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Home My WebLink AboutLarsen Bay Feasibility Study Final VolD Aug 1982... LARSEN BAY ,. CONTENTS -Section Page FOREWORD iv ... I • SUMMARY .. A. General 1-1 B. Area Description 1-2 .-C. Power Planning 1-2 D. Description of Recommended .. Hydroelectric Project 1-3 E. Base Case Plan 1-4 F. Economic Analysis 1-5 tiIIII G. Environmental and Social Impacts 1-6 H. Conclusions and Recommendations 1-6 - II. INTRODUCTION A. General 11-1 B. Purpose 11-2 C. Project Area Description 11-2 D. Authority 11-3 E. Scope of Study 11-4 F. Study Participants 11-7 G. Report Format 11-8 H. Acknowledgments 11-9 -I I I . STUDY METHODOLOGY A. General 111-1 B. Prereconnaissance Phase 111-1 C. Field Study Phase 111-2 D. Office Study Phase 111-2 -NBI-426-9523-tc i IV. BASIC DATA A. General B. Hydrology C. Geology and Geotechnics D. Surveys and Mapping E. Land Status F. Previous Reports V. ALTERNATIVES CONSIDERED A. General B. Alternative Projects C. Description and Evaluation VI. RECOMMENDED HYDROELECTRIC PROJECT VII. A. B. C. D. E. F. General Recommended Project Description Turbine-Generator Selection Field Constructibility Project Energy Production Project Operation Scheme and Controls PROJECT ENERGY PLANNING A. General B. C. D. E. Projection Considerations Energy Demand Projections Base Case Plan Recommended Project Plan VIII. PROJECT COSTS A. B. C. D. General Cost Estimating Basis Base Case Plan Recommended Project Costs NBI-426-9523-tc ii IV-l IV-l IV-3 IV-5 IV-6 IV-7 V-l V-l V-2 VI-l VI-l VI-4 VI-ll VI-12 VI-13 VII-l VII-l VII-5 VII-9 VII-16 VIII-l VIII-l VIII-2 VIII-2 ------ • • • - • --• • • • • • • • .. • -• -• - • • • • • - • • • • - - - .. - ..... - all - - - IX. ECONOMIC ANALYSIS A. B. C. D. E. F. General Project Analysis Parameters Base Case Economic Analysis Recommended Hydroelectric Project Economic Analysis Economic Comparison of Projects Unit Costs and Project Timing X. ENVIRONMENTAL AND SOCIAL EFFECTS XI. A. B. C. General Environmental Effects Socioeconomic Effects PROJECT IMPLEMENTATION A. B. C. General Project Licenses, Permits and Institutional Considerations Project Development Schedule XII. CONCLUSIONS AND RECOMMENDATIONS A • B. Conclusions Recommendations BIBLIOGRAPHY APPENDIX A. Project Drawings B. Hydrology C. Geology and Geotechnics D. Detailed Cost Estimate E. Environmental Report F. Letters and Minutes G. Space Heating Installation and Cost NBI-426-9523-tc iii IX-l IX-l IX-3 IX-8 IX-ll IX-12 X-l X-2 X-7 XI-l XI-l XI-3 XII-l XII-l This vol ume, recommendations of FOREWORD Volume D, presents a study intended to the findings fully assess and the economic, technical, environmental, and social viability of a hydropower project for the village of Larsen Bay. Volumes B, C and E present feasibility studies for hydropower projects for the villages of King Cove and Old Harbor and a reconnaissance study for Togiak, respectively. Volume A is a summary report incorporating the findings, conclusions, and recommendations of • ---- • • • • II • the other four volumes. - NBI-411-9523-FO iv • • • • .. • • -.. -• • ----- • • • • - • • - - - .. -... A. GENERAL SECTION I SUMMARY Several prior studies of alternative means of supplying Larsen Bay with electrical energy had recommended a hydro- electric project as the best available source. As a direct resul t of these prior studies and recommendations, the Alaska Power Authori ty has authorized a feasibili ty study to investigate in detail the hydropower potential in the vicinity of Larsen Bay. This report summarizes the act i vi ties conducted for the feasibili ty study. These activi ties included projections of energy needs, formulation of a hydroelectric project and an alternative base case to meet the electrical energy needs of Larsen Bay, detailed analyses of economic feasibility, and preparation of an environmental assessment of the effects of the project. The results of the study indicate that a 270 kilowatt (kW) hydroelectric project can be constructed at Larsen Bay, that the project is considerably more economical than the base case alternative, and that the environmental effects of the project are minor. The total cost of the proposed Larsen Bay hydroelectric project is $2,821,400 in January 1982 dollars. The project could be implemented and on-line by January 1, 1985, if a decision to proceed with the project is made by December 1982. During an average water year, the proposed project would be capable of supplying more than 85 percent of the electrical needs and about 14 percen t of the space heat ing needs in the project area. The equi valent savings in diesel fuel in the year 2001 would be about 69,000 gallons for direct electrical demand and 16,000 gallons for space heating. NBI-426-9523-I 1-1 B. AREA DESCRIPTION The village of Larsen Bay is located near the junction of two fjords, Larsen Bay and Uyak Bay, on the northwest coast of Kodiak Island. Shelikof Strait, separating Kodiak Island from the mainland, lies 14 miles to the northwest and the ci ty of Kodiak lies 60 miles to the east. The selected hydroelectric power site is on Humpy Creek, a small tributary of Larsen Bay fjord about one mile south of town. The general project area and the proposed project site are shown on Plate I of Appendix A. C. POWER PLANNING Power planning for the Larsen Bay project was conducted using standards set forth by the Alaska Power Authority. Previously recommended potential hydroelectric sites were investigated and the project area was surveyed to evaluate potential new sites. After detailed study, a project was selected and then compared with a base case plan. Present energy demands for Larsen Bay for direct electrical uses and space heating were estimated and future uses in these categories were projected. The projections were based on fore- casts of increases in the number of customers and increased usage rates. Population growth and employment, legislation and other political influences, life style changes, and other factors can influence future energy demands but they were not explicitly treated. The period of economic evaluation used was 53 years, which starts in January 1982 and extends for the 50-year life of the hydroelectric project after the estimated on-line date of January 1985. The energy demands for Larsen Bay were increased for 20 years starting in January 1982 and extending through NBI-426-9523-I 1-2 • ----- • • • • • • • .. • • • .II .. • • • • .. -- • • -• • -• • - December 2001. The demands were then held level over the remainder of the economic evaluation period. For the proposed hydroelectric project, it was assumed that the first priority of use for the energy produced would be the direct electrical needs of Larsen Bay, and any remaining energy would be used for space heating. D. DESCRIPTION OF RECOMMENDED HYDROELECTRIC PROJECT Hydroelectric power plants transform the energy of falling water (head) into electrical energy. Generally, a hydroelec- tric power project consists of a dam to produce the head or to divert stream flows so that they can be passed through a turbine-generator system to produce electric power. In the case of the recommended Larsen Bay Hydroelectric Project, a low weir will act as a dam to divert water from Humpy Creek through an inlet structure and into a penstock (conveyance pipe). The ~enstock will be 27 inches in diameter and will carry the water about 2700 feet to the powerhouse, where it will be passed through the turbine-generator system to produce electric energy. The powerhouse will have the capacity to produce 270 kW of electrical power. A transmission line will be constructed to transmit the power generated at the plant to Larsen Bay. Access to the powerhouse facilities will be provided by building a short length of new road to link up with an existing road that extends to an existing and abandoned dam near the site of the new powerhouse. The transmission line will follow the alignment of the new access road and the existing road to Larsen Bay. The general plan and features of the proposed project are presented on Plates I through VI I of Appendix A. Photographs of the project area are presented in Exhibits VI-1 through VI-4 at the end of Section VI and in the Environmental Report, Appendix E. NBI-426-9523-I 1-3 Under the recommended plan, energy generated by the hydro- electric plant will have to be supplemented by diesel genera- tion. Larsen Bay does not currently have a central diesel generating plant and the plan will therefore require the construction of diesel facilities for standby and backup power. The hydroelectric generation will be adequate to meet the direct electrical needs of Larsen Bay during most of the year; however, from December through March diesel will be needed to supplement the hydroelectric generation. A new electrical distribution system will also be required since none currently exists. During an average wa ter year the proposed hydroelectric project will be capable of supplying more than 90 percent of the electrical needs of Larsen Bay and approximately 20 percent of the space heating over the life of the project. Average annual energy production from the hydroelectric plant will be 1.09 million kilowatt-hours (kWh) and the average annual plant factor will be about 46 percent, which means that the plant is expected to generate about 46 percent of the energy that it could produce if the turbine-generator unit was operated continuously at full capacity. E. BASE CASE PLAN The base case plan formulated to meet the projected energy demands of Larsen Bay assumed that the use of individual existing diesel generating plants would be discontinued and a new centralized diesel generating plant would be constructed. Because of apparent economic benefits, it was assumed that the proposed system would also incorporate waste heat recovery that would be used for space heating. The possibility of installing wind generation equipment was also considered, and was found to be economically viable. NB1-426-9523-1 1-4 ------• - • • • .. • • • • • ---- • -.. .. -.. • • -- • • • • .. .., ". - - - - - It was assumed that the diesel system for the 1982 base case would require about 51,500 gallons of fuel oil per year; this amount was expected to increase over the next 20 years to more than 80,000 gallons per year. Waste heat recovery was expected to displace the use of 17,000 gallons of fuel oil per year by the year 2001. The wind generators are expected to displace about 12,000 gallons of oil by 2001. F. ECONOMIC ANALYSIS The economic analysis was based on the Alaska Power Authority criteria that compare the net present worth of the proposed base case costs to the net present worth of the pro- posed hydroelectric project costs using specified real price escalation and discount rates. Net present worth is the present value of the costs that would be incurred over a comparable economic evaluation period of 53 years for both projects. The present worth of the base case only, that is, diesel generation, is $7,532,100. If this cost is reduced by the savings that could be realized from the installation of waste heat recovery, the present worth is $6,725,100; further reducing this cost by· the benefit obtainable from wind generation yields a present worth of $6,432,000. All costs except the cost of the hydroelectric project and its diesel supplement were considered as adjustments to the base case. The cost of the space heating credit was added to the base case because it represents a benefit that would not be realized if the base case plan was implemented. The next present worth of the base case after all adjustments is $7,348,600. For the proposed hydroelectric project, the present worth of the costs, is $5,941,700. A comparison of this net present cost with the base case net present costs indicates that the NBI-426-9523-I 1-5 recommended hydroelectric project is considerably more economical than the alternative base case. An additional measure of project feasibility is the bene- f i t/ cost ( B/C) ratio. The B/C ratio is the present worth of the project benefi ts divided by the· net present worth of the project costs. For this project, the B/C ratio for the base case only is 1.268. The B/C ratio after adjustment for waste heat recovery is 1.132; after additional adjustment for wind generation, the B/C ratio is 1.067; and after all adjustments, the B / C rat i 0 is 1. 23 7 • Th e s e B / C rat i 0 sin d i cat e t hat the proposed hydroelectric project is highly feasible. G. ENVIRONMENTAL AND SOCIAL EFFECTS The environmental study results indicate that the effects of the project will be minor due to the limited scope of the project activities, the inability of salmon to spawn above the old diversion dam on Humpy Creek, the abundance of alternative areas available for trapping, hunting, and general recreation, and the availability of measures to mitigate potential effects from the construction and operation of the facilities. Minor socioeconomic benefits will occur as a result of project construction and maintenance and cbeaper electric rates made possible by the project. Additional environmental studies do. not appear to be warranted unless regulatory agencies or local residents express additional concerns. H. CONCLUSIONS AND RECOMMENDATIONS The studies conducted for this report ind ica te that the proposed 270 kW hydroelectric project is feasible and that the energy demands of Larsen Bay are suff icient to ut il ize the hydroelectric plant's planned capaci ty. The proposed project is a more economic means of meeting the area's future electric needs than the base case diesel alternative. Environmental effects of the proposed project are minor. NBI-426-9523-I 1-6 • ----- • - • • • - • • • • • • • • • - • • • .. • - • • • • .. • • • II - - - -- - In view of these findings, it is recommended that actions be initiated to implement the project. NB1-426-9523-1 1-7 -- - - - - - - - SECTION II INTRODUCTION A. GENERAL The village of Larsen Bay is located near the junction of two fjords, Larsen Bay and Uyak Bay, on the northwest coast of Kodiak Island 60 miles west of the city of Kodiak. Larsen Bay does not now have a central generation or electrical distribu- tion system. About one-half of the residents get electrical power from small, privately owned generators and the remainder do wi thout. It has been assumed that wi thout a hydroelectric project the local community will develop a central generation and distribution system based on ci ty-owned diesel generators in the same way that other similar villages have done. How- ever, diesel systems for electrical generation have several serious drawbacks, especially in remote locations --availabil- ity and cost of diesel fuel, expected shortages and increased expense of fuel in the future, potential maintenance problems, and the cost and availability of parts or even whole systems. The installation of hydroelectric generating capacity would potentially alleviate the major problems inherent in the diesel systems and provide dependable generating capacity over a long time span. This section describes the purpose and scope of the study, the physical and economic characteristics of the project area, and the organizational makeup of the participants in the study. B. PURPOSE The primary purposes of this feasibili ty study were to prepare a recommendation on the best configuration for develop- NBI-388-9523-II 11-1 ing a dependable source of hydroelectric energy supply for Larsen Bay and to determine the engineering, environmental, and economic feasibility of the project. The recommended hydroelectric project was compared wi th a base case plan that consisted of diesel generating units sup- plemented by wind generation and a central distribution system that would be augmented with additional units as necessary to accommodate growth. Earlier studies had determined that these alternatives were the most promising sources of electrical energy for Larsen Bay. C. PROJECT AREA DESCRIPTION Larsen Bay is located on the west side of Kodiak Island. The village site lies along a beach with a gradual incline. The background is covered wi th low alder, brush and grass. Away from the water side, the village is surrounded by moun- tains that rise to more than 2000 feet and treeless terrain. The local sea coast is marked by deep, narrow scoured straits and fjords and by steep, rocky sea bluffs. Larsen Bay is only accessible by air and by water. No roads connect the town wi th any other town on Kodiak Island. Uyak Air Service, based in Larsen Bay, serves area villages on an on-call basis. Kodiak Western Airlines makes one flight daily, Monday through Friday. Other companies are also avail- able to provide chartered flights. The economy of Larsen Bay has traditionally been based on fishing and cannery work. A large salmon cannery was operated in the town until recently when it ceased operations. However, the fishing industry will remain the primary commercial acti- vi ty and the fishermen will use other means to market their catch. The Larsen Bay Tribal council has appl ied for funds from U.S. Housing and Urban Development (HUD) to develop a fish NBI-388-9523-II 11-2 • -- - • - • .. • -• • .. • • • • • • .. • • • - • --• • • • • • -• • - - - ,- - - - - - smoking operation using some of the facilities of the old cannery. Electrical power is provided by individual generators at the residences. Approximately 20 five kW generators provide electricity to 25 or 30 households. Generally, electricity is used only during the evening hours. The school has two 60 kW generators. Humpy Creek to the south of the vi llage is the proposed location for hydropower development. The creek originates in a hanging valley above Larsen Bay fjord. It passes through the village of Larsen Bay and discharges into Larsen Bay. The pro- posed diversion site is about one mile south of Larsen Bay. The general plan and drawings of Appendix A show the location and features of the proposed project. The climate of Kodiak Island is dominated by a strong marine influence. The area is characterized by moderately heavy precipitation and cool temperatures. High clouds and fog occur frequently but the area has Ii ttle or no freezing wea- ther. The humidity is generally high and temperature variation is small. The mean maximum temperature varies from 320 F to 620 F. Average rainfall is 23 inches per year. Winds of 50 to 75 knots are frequent, with 120 mph winds estimated for a 100- year storm. Icing is primarily a problem for ships. D. AUTHORITY The Alaska Power Authority (APA) has authorized studies to prepare the "Detailed Feasibili ty Analyses of Hydroelectric Projects at King Cove, Larsen Bay, Old Harbor and Togiak." This particular report, Volume D, summarizes the studies con- ducted for Larsen Bay. APA is a public corporation of the Department of Commerce and Economic Development, State of Alaska. NBI-388-9523-II 11-3 - - E. SCOPE OF STUDY - In general the scope of the study consists of an aaalysis -of the the costs and benefits of a hydroelectric project, a _ comparison of these costs and benefits with those for the base case plan for the village, and an environmental assessment of the effects of the project. To accomplish these goals, the following activities were necessary. 1 . Data Accumulation Data collected included existing flow records, topographi- cal mapping, present and future demands for power, applicable laws and regulations, existing reports, and other applicable information that was available. 2. Site Reconnaissance The purposes of the site reconnaissance were to supplement and verify the data gathered, to collect topographical, hydro- logical, environmental, and geotechnical data, and to determine the accessibility of the site. The conceptual design of pro- ject features was established in the field. 3. Site Surveys A topographic survey was conducted at the site of the diversion, penstock, powerhouse, and transmission line in sufficient detail for use in final design. 4. Hydrology , Hydrologic data were developed from the limited available data. A suitable method was established to prepare a streamflow table, a flow duration curve, and the seasonal NBI-388-9523-11 11-4 • .. • - • ., • • • • • --.. • .. • - • • • • • • • • .. --• -- - - - .... distribution of the flow duration curve. flooding problems were also considered. Diversion and 5. Geotechnical Investigations Geotechnical investigations were conducted to determine material sources, slope stabili ties, and load-bearing charac- teristics of the foundations for all structures in the project. 6. Base Case Plan A base case plan was analyzed that assumed the establish- ment of a diesel generation and distribution system, supple- mented by wind generation, and least-cost additions for future generators. Included in this analysis was an assessment of current energy usage and a forecast for the life of the pro- ject. The cost of establishing and continuing the use of the diesel generators assumed for the base case plan provided a basis for determining the value of power at the site. Data regarding the energy potential and cost of wind generation at Larsen Bay were provided by another contractor to APA. 7. Power Studies Several different types of turbines and installed capacities were evaluated to determine configuration. 8. Environmental Overview a range of the optimal The environmental investigation was conducted to identify any environmental constraints that might prohibit project development. NBI-388-9523-II 11-5 9. Design A layout of tbe project was designed and sizes and capaci- ties of water-carrying, structural, and control components were determined. All features of tbe project were designed in sufficient detail for use in preparing a cost estimate. 10. Cost Estimates Cost estimates, including direct and indirect costs, were prepared using a present cost base escalated to the anticipated time of construction. 11. Economic Analysis The project was analyzed using tbe economic criteria of tbe Alaska Power Autbori ty. The general metbodology employed was to compute the present net worth of tbe costs of tbe proposed bydroelectric project over a 50-year project life and to compare this value to the present net worth of the costs of the base case plan over tbe same 50-year project life. 12. Environmental Assessment A detailed environmental analysis was conducted based upon tbe final design and layout of the project. 13. Conclusions and Recommendations Tbe report presents findings on tbe feasibility of tbe project and recommends a future course of action to be followed. NB1-388-9523-11 11-6 • ---.. -.. • • • -• • -• • • • ---.. -• --• • -• -• • • -• .. 14. Public Meetings Public meetings were conducted in Larsen Bay at the begin- ning of the project studies to obtain comments from local citi- zens. Another public meeting was held in Larsen Bay to present the findings and conclusions of the study and to solicit public comments. All letters and comments received from federal and state agencies were answered by APA with changes incorporated in the text of the final report as required. A copy of the comments and replies is contained in Appendix F. 15. Report A draft report was submitted to the APA in February 1982, and the final report incorporating all comments was submitted in August, 1982. F. STUDY PARTICIPANTS DOWL Engineers, of Anchorage, Alaska, was the primary contractor for the study. DOWL was assisted by two subcon- tractors--Tudor Engineering Company of San Francisco, Cali- fornia, and Dryden & LaRue of Anchorage, Alaska. The primary role played by each of the participants is covered below. 1. DOWL Engineers DOWL Engineers, an Alaskan partnership, performed the project management function and provided the primary contact wi th the Al aska Power Author i ty. DOWL collected basic data, participated in the hydrology studies, and had the prime responsibility for the local coordination activities, geology and geotechnics, and the environmental, ground survey, stream gaging, and wind velocity aspects of the investigation. NBI-388-9523-II 11-7 2. Tudor Engineering Company Tudor, as principal subcontractor, supplied all hydro- electric expertise for the project.· They directed data collec- tion and conceptual design of facilities; assisted with public meetings; assisted and provided direction in evaluating the base case plan and power values, formulating cost estimates, and making the financial and economic evaluation; and furnished advice on the aspects of the envi ronmental problems that are unique to hydroelectric projects. Tudor prepared the initial draft of the project report. 3. Dryden &. LaRue (D&L) The partners in D&L are electrical engineers registered in Alaska. Much of the electrical work was accomplished in close cooperation with this firm. Transmission lines and backup diesel generation facilities were involved as well as questions related to reliability and integrated operation of the proposed system with existing village systems. D&L and Tudor estab- lished the value of power and the present and projected power demands. D&L provided the feasibili ty designs and cost esti- mates for the transmission lines and appurtenant electric features. G. REPORT FORMAT Pages, tables, figures, and exhibi ts in this report are numbered within the sections in which they appear. Within sec- tions, the tables, figures, and exhibits are placed at the end of the text. References noted in the text are listed in the Bibliography. NBI-388-9523-11 11-8 - -- --.. - • - • .. • • • • • -----• --- -- • -• -• .. -- - H. ACKNOWLEDGMENTS The cooperation of the many federal, state, and local agen- cies and local residents contacted during the course of the study is gratefully acknowledged. This list includes, but is not limited to, the Alaska Power Administration, the Alaska Department of Fish and Game, the Alaska Department of Trans- portation, the Alaska Department of Natural Resources, the U.S. Army Corps of Engineers, the U. S. Geological Survey, and the U.S. Fish and Wildlife Service. The assistance of the Rockford Corporation and the Locher Construction Company, a subsidiary of Anglo Energy Company, is also acknowledged. Individuals who were especially helpful include Don Baxter of APA, Roger Smith of ADF&G, and Dora Aga and Frank Peterson of Larsen Bay. NBI-388-9523-II 11-9 - ,. - .. - - .. .. - SECTION III STUDY METHODOLOGY A. GENERAL This section describes the general methodologies employed and steps taken to complete the project studies and analyses. In general, the study proceeded in three phases-- pre-reconnaissance, field studies, and office studies. Each project phase is described briefly below and the resul ts are covered in detail in the following sections of the report and the appendices. B. PRE-RECONNAISSANCE PHASE This phase consisted of initial data collection and analyses, obtaining access permits, coordination with resource agencies, and evaluation of the existing material and reports. A brief one-day visi t was made to Larsen Bay by the project team to conduct the initial field investigation. Later a member of the project team returned to hold the initial public meeting and inform the residents of project investigation activities. During the initial field evaluation, available alternative hydroelectric sites were inspected and preliminary environmental evaluations of all sites were made. Office studies of alternative sites and environmental conditions had preceded the initial field work. The project team on this initial visit consisted of individuals with geologic, geotech- nical, hydroelectric, hydrological, environmental, and electrical expertise. All individuals participated in evaluat- ing the alternatives and conducting the field investigations • NB1-426-9523-111 111-1 C. FIELD STUDY PHASE The field studies were conducted several weeks after initial pre-reconnaissance activities, mobilization, and field planning were completed. Detailed site investigations spanning several days were made by the hydroelectric engineers to define the location of the project features. They were aided in this work by the geology and geotechnic team, which also made a detailed investigation of geology and soil conditions following final selection of the feature locations. Field environmental and hydrologic investigations were also conducted in parallel as the field conceptual design work was completed. The field survey team immediately followed the hydro- electric and geotechnical teams to the field to conduct detailed surveys. A stream gage was also established by the hydrology group. Data were gathered from Larsen Bay regarding the present and planned generating conditions of the city system. D. OFFICE STUDY PHASE The final and most extensive phase of the study was the office study phase where all data gathered from the field and all accumulated data and information were analyzed and addi- tional investigations were conducted to complete the project activities. Separate reports were produced for the hydrology, geology and geotechnical, and environmental activities. They are included with this report as Appendices B, C and E, respec- tively. The environmental appendix also includes information on permitting requirements, social impacts, and land status. NBI-426-9523-III 111-2 ------• -- • -• • • • • • • --- • • • -• --- • -• • • • • • ,- - Project energy planning studies were conducted to define tbe year-by-year electrical and beating demands of Larsen Bay. To meet tbe were analyzed to requirements, various determine tbe opt imal installed capacities project size and tbe conceptual design of tbe bydroelectric project. Tbese tasks were completed with tbe aid of tbe maps prepared from tbe field activities. Detailed cost estimates were tben prepared based on tbe final size of 270 kW and tbe completed project layouts. Tbe economic analysis was tben conducted to complete tbe project analysis activities, and a draft report was prepared. Following a preliminary review of tbe report by tbe Alaska Power Autbority, an additional meeting was beld in Larsen Bay to solici t public comments. Tbe draft was circulated to all concerned state and federal agencies. After receipt and con- sideration of comments, tbe final report was compiled. Appen- dix F contains a copy of all tbe comments received and tbe replies prepared by APA and tbe contractor. NB1-426-9523-111 111-3 - ,1IIiIf - SECTION IV BASIC DATA A. GENERAL This section describes in general the basic data used in the preparation of the Larsen Bay report. Included are hydrologic, geologic and geotechnical data, surveys and mapping, land ownership status and previous reports. B. HYDROLOGY The primary thrust of the hydrologic studies for the Larsen Bay hydroelectric project concerned the development of a flow duration curve, an annual hydrograph, and a flood frequency curve for Humpy Creek. A complete report of the steps taken to achieve those items is covered in the hydrology report included with this report as Appendix B. One year of streamflow data was available for Humpy Creek (USGS Gage No. 15296480). The general methodology employed to develop the Humpy Creek flow duration and hydrograph was to first develop an estimated value for the Humpy Creek mean annual flow. Dimensionless flow duration curves and hydro- graphs were then developed from the records of a long-term stream gaging station, Myrtle Creek on Kodiak Island. Applying the Humpy Creek mean annual flow to the dimensionless curves then yielded a specific flow duration and hydrograph for Humpy Creek. 1. Mean Annual Flow The long-term mean annual flow was developed using three different estimating techniques--conversion of the 1981 measured flow, the modified rational formula, and regional NBI-388-9523-IV IV-1 analysis. The three methods yielded similar values and the Humpy Creek mean annual flow was taken as 13.0 cfs. 2. Flow Duration Curve The closest gaged stream with an adequate length of record ---.. -- • • is Myrtle Creek on Kodiak Island (No. 15297200), 70 miles to • the east of Larsen Bay. A comparison of dimensionless curves from three basins on Kodiak Island showed considerable similari ty. On this basis the Myrtle Creek curve developed from 17 years of daily record was adopted as the type of curve for small, mountainous maritime basins in southwest and south- central Alaska. The Humpy Creek flow duration curve presented as Figure IV-1 is based on Myrtle Creek scaled to the ratio of its respective mean annual flows. 3. Annual Hydr9graph Based on the same data and reasoning that went into determining the mean annual flow and the flow duration curve, an annual hydrograph was developed based on monthly flows at Humpy Creek. The resul ting annual hydrograph is presented in Figure IV-2. 4. Flood Frequency Curve Estimates of flood discharges are based entirely on regional analyses. Regression equations obtained through regional analyses were first applied to the gaged stream to test their applicability. The basin and climatological characteristics of Humpy Creek were then entered to obtain the following flood frequency values. NBI-388-9523-IV IV-2 - • - • .. • • .. • • --- • • • --• ----• .. • • • • - - Q10 = 250 cfs Q25 = 325 cfs Q50 = 400 cfs Q100= 485 cfs These data are plotted on a frequency curve and presented as Figure IV-3. C. GEOLOGY AND GEOTECHNICS The purpose of the geologic and geotechnical studies con- ducted for this report was to assess the geologic hazards, establish appropriate design criteria, explore material borrow sites, and provide background information for environmental studies. A complete Geology and Geotechnics Report covering these items in detail is included as Appendix C. A summary of the report is included below. 1. Site Topography Larsen Bay is a communi ty located on Larsen Bay on Kod iak Island, Alaska. Kodiak Island is essentially an isolated extension of the Kenai Peninsula in the Gulf of Alaska. Larsen Bay is an arm of the larger Uyak Bay, which is a major north- south trending bay opening to Shelikof Strai t between Kodiak Island and the Alaska Peninsula. Larsen Bay is now a fjord; however, during glacial times it was filled with ice and was a tributary to the major ice mass occupying Uyak Bay. Because mul tiple glacial advances have brought ice to this entire area, the hills are generally smooth and rounded, hanging valleys are common, and valleys tend to have a parabolic cross section . Elevations in the immediate area range to approximately 3000 feet. Stagnant ice topography and abandoned outwash channels are common. NBI-388-9523-IV IV-3 The proposed dam site is on Humpy Creek, which drains the hills to the south of Larsen Bay and flows through town into the bay. The stream is relatively straight and is incised into bedrock in the project area. 2. Regional Geology The Kodiak Formation that constitutes the bedrock underly- ing the Larsen Bay si te has been interpreted as a deep-sea trench deposit of Late Cretaceous age that has been accreted to the continent. These rocks are for the most part marine turbidi ties and range from well-Ii thified sil tstones to fine sandstones. ------ • - • ---• • • Glaciation on Kodiak Island has probably extended from - Miocene time to the present. The glacial deposi ts at Larsen Bay date from Late Pleistocene time. Both till and glacial outwash are present. 3. Site Geology The geology of this area consists of glacial till, outwash, and alluvial fan deposits that mantle bedrock belonging to the Late Cretaceous Kodiak formation. The bedrock is a slate with poor to moderate fissility. The proposed diversion site is in a very narrow gorge within the bedrock. The walls of the gorge are nearly vertical in many areas along the stream and at the diversion si te. Other than removing minor amounts of loose rock at the surface, no special problems are anticipated for the abutments. The rock is not highly weathered or fractured and appears competent for this use. There are two options for the si te of the road and pen- stock, one on each side of Humpy Creek. Each option could NBI-388-9523-IV IV-4 • • • --- • • .. ---------• • • • - - follow the existing road up to the present dam across Humpy Creek. This road ends near the west abutment of that dam. Option A, considered the better option, could also follow the west side of Humpy Creek to the existing dam. Most of the Option A route is inexpensi ve. Upon reaching the stream, Option A would need about 125 feet of blasted road and one stream crossing to reach the staging area or three stream crossings and no blasting to reach the staging area. There are few geologic hazards and little likelihood of future major maintenance problems. 4. Construction Materials Gravelly sand is present in both the outwash deposi t and the alluvial fan deposit. The fan deposits are probably superior for construction because there is an existing gravel pit that can be used. If higher quality materials are required, beach materials are a possibility. 5. Seismic Hazards The Larsen Bay proposed dam site is in a seismically active area. Strong ground motion is the principal seismic hazard. Recommended design criteria should be based upon a 50-year life of the structure and a base acceleration of 40 to 50 percent of the acceleration due to gravi ty. Surface faul ting or major ground failure is not expected at the dam site. D. SURVEY AND MAPPING A detailed ground survey, based on the project configura- tion marked in the field by the hydropower engineering, was made of the Humpy Creek Site between November 6 and 10, 1981. The survey and the drawings produced from them included ground control; traverse, profile (1 inch = 50 feet horizontal, 10 NBI-388-9523-IV IV-5 feet vertical) and valley cross sections of two al ternative penstock routes on the east and west sides of the canyon; and topographic mapping (1 inch = 20 feet, 2-foot contour interval) and cross sections of the diversion dam and alternative -.. - powerhouse sites in the vicinity of the abandoned cannery - diversion dam. Elevation datum was assumed. --Prior high altitude stereo aerial photography of the area _ was available. This was used to produce a general topography map (1 inch = 700 feet, 20-foot contour interval, assumed control) of the lower portion of the Humpy Creek Basin. The locations of the airstrip and other recent developments within Larsen Bay were obtained from the Larsen Bay Community Map. The project is located on the USGS Kodiak C-6, 15 minute Quadrangle Map (1:63,360; 100-foot contour interval, 1952). E. LAND STATUS A map showing land status in Larsen Bay and the project area is presented in Figure IV-4. The diversion weir to be constructed across Humpy Creek, the borrow site location near the diversion weir and a portion of the proposed trail from the diversion weir to the powerhouse are within lands for which the surface estate has been interim conveyed to Koniag, Incorporated, as part of their entitlements under the Alaska Native Claims Settlement Act of 1971 (ANCSA), Public Law 92- 203. Interim conveyance is used in this case to convey unsurveyed lands. Patent will follow interim conveyance once the lands are identified by survey. The powerhouse, and an al terna ti ve borrow si te near the city solid waste disposal area are located on lands which are interim conveyed or patented for surface and subsurface estates to the ci ty of Larsen Bay. The proposed transmission route al ternatives from the powerhouse to Larsen Bay traverse both NBI-388-9523-IV IV-6 .. - • • • • • • --- • -• • ----- • • • .. .. • .. - - patented private, city of Larsen Bay, Townsite Trustee, and patented Koniag Corporation property. An airport lease, Serial Number AA 9087, is near the powerhouse and the final transmis- sion route alternative should take this into account. Larsen Bay has a federal townsi te, U. S. S. 4872, wi th the patent issued to the Bureau of Land Management Townsite Trus- tee. The Trustee has deeded occupied parcels to the residents and some vacant lots to the ci ty. Other subdi vlded property remains with the Trustee. A permit would be required for the transmission line to cross Trustee lands and it can be issued by the U.S. Department of Interior after an affirmative reso- lution by the City Council. All of the interim conveyed lands identified above are also part of the Kodiak National Wildlife Refuge as classified and withdrawn by Public Land Orders 1634, 5183, and 5184. All lands that were part of a national wildlife refuge before the passage of ANCSA and have since been selected and conveyed to a Native corporation will remain subject to the laws and regulations governing use and development of such refuges as outlined in Section 22(g) of P.L. 92-203. F. PREVIOUS REPORTS Studies of power potential projects for the Larsen bay area are described below: 1. "Hydroelectric Power Potential for Larsen Bay and Old Harbor, Kodiak Island, Alaska Appraisal Evaluation, May 1978, " by Uni ted States Department of Energy, Alaska Power Administration. This report presents rough appraisals of potential hydroelectric projects to serve the villages of Larsen Bay and Old Harbor on Kodiak Island. NBI-388-9523-IV IV-7 The potential hydroelectric generation plan consists of utilizing water from the stream that flows north through the village. The plan assumes a 1000 kW generating plant operating under 300 feet of net head, with a design hydraulic capacity of 50 cfs. The average power potential is 2,704,000 kWh. The total investment cost of the project was estimated to be $2,300,000 or $2,300 per kW. The average cost of power would be 13 cents per kWh. The study concluded that the project at Larsen Bay has potential as a run-of-stream plant. The plant cannot meet power demands during the winter or during dry periods in the summer. It would have to be operated in conjunction wi th a diesel plant, and the value of the hydro would be based on the fuel oil saved. The approximate value of diesel generated power using $1.00 per gallon oil at 11 kWh per gallon is 9.1 cents per kWh. With a demand of 2 million kWh/year, the cost of hydro power would be 13 cents/kWh. With a larger demand, it would be 7 cents per kWh. It was concluded that the Larsen Bay project appears to have a chance of feasibility. 2. "Report of Geologic Investigation--Old Harbor, Larsen Bay and Port Lions--Kodiak Island, Alaska," 1978, by Robert M. Retherford. At the request of the Alaska Power Administration, this geologic study was made of the hydropower site proposed in the Alaska Power Administration report listed as report number 1 above. The report covered general geology of the Larsen Bay area and site geology for the powerhouse, penstock route, and dam si te. It also made recommenda tions for future geologic explorations. NBI-388-9523-IV IV-8 ------• ---- • • • III .. • • .. -- • --• -------• • • • • - - - .. .. - 3. "Preliminary Feasibili ty Designs and Cost Estimates for Hydroelectric Project Near Larsen Bay, Alaska," prepared for the U.S. Department of Energy, Alaska Power Administration, Juneau, Alaska, by Robert W. Retherford Associates of Anchorage, Alaska, January 1980. This report presents a preliminary feasibility study of the site proposed in the Alaska Power Authority (APA) report of 1978 . On are con n a iss a n c e bas is, the rep 0 r t co n sid e r s all 0 f the components involved in a feasibility study. It was concluded that the project would cost $3,232,200 for an installed capacity of 1120 kW. The total annual cost would be $293,440. The average cost of hydro power in 1981 was estimated to be 9.41 cents/kWh based upon the sale of 3,115,800 kWh. The 1981 benefit/cost ratio would be 1.08. 4. Regional Inventory and Reconnaissance Study for Small Hydropower Projects--Aleutian Islands, Alaska Peninsula, Kodiak Island, Alaska, by Department of the Army, Alaska District, Corps of Engineers. Prepared under contract by Ebasco Services Incorporated, July 1980 draft--October 1980 final. The purpose of this study was to provide a reconnaissance- grade report outlining the potential for hydropower development at each of 36 isolated communities stretched over 1500 miles in the Aleutian Islands, the Alaska Peninsula, and Kodiak Island. At Larsen Bay, three potential power si tes were analyzed. Site 1 was located about three miles southwest of Larsen Bay. Si te 2 was located about three-quarters of a mile south of Larsen Bay, and Site 3 was located about two miles west- northwest of Larsen Bay. All three streams were unnamed in this report. Si te 2 corresponds to the si te analyzed in the 1978 APA report. NBI-388-9523-IV IV-9 The report lists the existing energy source, demographic characteristics, economic characteristics, land ownership, and environmental concerns. Conclusions reached were shown in the following table: Site Power Factor No. Percent 1 67 2 67 3 67 1 43 2 43 3 43 5. "Reconnaissance Al terna ti ves for Akhiok, Ouzinkie and Sand Poin t , " by CH2M HILL, May 1981. Annual Cost Benefit/Cost per kWh Ratio $ .032 5.25 .033 5.09 .054 3.11 .050 3.36 .051 3.29 .084 2.00 Study of Energy Requirements and King Cove, Larsen Bay, Old Harbor, prepared for Alaska Power Authori ty The purpose of the study was to identify and assess the present and future power needs of each community and to assess the power project alternatives available to that community. It served as a basis for recommending more detailed data collection activities, resource assessmen ts, or detailed • --- • - • ----- • • • • • • • --- • • -feasibility studies of one or more specific power project - alternatives. The report concluded that the Humpy Creek Hydroelectric Project plan is the lowest-cost power alternative to Larsen Bay and the centralized diesel generation plan is the second- lowest-cost al terna ti ve. The base case plan of decentralized diesel generation is the highest-cost plan. Waste heat -- • • -- recovery would be an attractive addition to the school _ generator. _ NBI-388-9523-IV IV-10 • • • • - •• 6. "Summary-Reconnaissance Study of Energy Requirements and Al terna ti ves for Larsen Bay," prepared for Alaska Power Authority by CH2M HILL, July 1978. This study presents the resul ts of the study listed as No. 5 evaluating energy requirements and alternative electrici ty sources for the communi ty of Larsen Bay on Kodiak Island. The preferred al ternative electrici ty supply system would consist of a standby central diesel generator, serving the entire village and a hydropower plant on Humpy Creek. This would require the installation of a central electrical distribution system for the village. The recommended standby plant would consist of one 120 kW diesel engine generator. The recommended project would have a rated capacity of 300 kW and would require an initial investment of $3.3 million. A more detailed feasibility investigation is recommended for the Humpy Creek project • NBI-388-9523-IV IV-11 - - - -,. 70 60 50 40 \ 30 \ ~ \ " 20 ,~ MEAN ~,NNUAL FLOW 13 cfs _ 10 UJ ... o· -~ o i 0 o 20 " " "--.......... 40 60 PERCENT (0/0 ) OF TIME FLOW EXCEEDED HUMPY CREEK FLOW DURATION CURVE ............... ............... 80 ~ 100 FIGURE N-I - - - - - - - .- - - - - - - SECTION V ALTERNATIVES CONSIDERED A. GENERAL The request for proposals for the Larsen Bay Hydroelectric Project indicated that past studies had identified Humpy Creek as the most attractive site for development. Locating a physi- cally and economically viable hydroelectric power project in the vicinity of Larsen Bay presents certain difficulties. Adequate head is readily available in several streams near the town, but the drainage areas are small and thus provide only limited water supplies. The superiority of Humpy Creek on this count has long been recognized. This section summarizes the alternatives considered during this phase of the work and presents the reasoning that led to the conclusion that Humpy Creek did indeed provide the best available site. B. ALTERNATIVE PROJECTS Four sites were proposed in previous studies and all of these sites were considered. Two sites were subject to detailed ground reconnaissance before selecting a site on lower Humpy Creek. Power output estimates are based on the average annual flow developed in this study, which corresponds to the 30 percent flow duration or avai labi I i ty, and on gross head minus penstock losses. Transmission lines are assumed to terminate at the Town Hall because no electrical distribution lines now exist in Larsen Bay. The values ci ted therefore differ from those previously reported. NBI-388-9523-V V-l B. DESCRIPTION AND EVALUATION Before field activities were undertaken, a preliminary evaluation of the sites was made on the basis of prior reports and map and stereo air photo interpretation. Final evaluation and the selection of the lower Humpy Creek site were made by the field team while they were in Larsen Bay. The locations of the sites studied are shown in Figure V-1. Selection of a site was based on information similar to the data presented in Table V-1. Head, flow, and penstock length were measured in the field at both Sites 1 and 2 before Site 1 was selected. Primary consideration was given to the ability of the alterna- ti ve projects to meet Larsen Bay I s projected power needs as weighed against the relative constructibility and cost of the requi red st ructures. ReI iabi I i ty of the water supply, length of penstocks, geotechnical problems, access roads and transmis- .. -.. -.. - • -• • • • • • .. • • iii sion lines, and environmental effects were major considera-• tions. The following discussions highlight that evaluation. • Site 1 was described in the request for proposals for this feasibili ty study and was recommended in the July 1981 CH2M HILL reconnaissance study (1981) and the Ebasco study (1980). The superiority of Humpy Creek at either Site 1 or 2 is evident. The powerhouse would be located near an existing road at the edge of the village and the water supply is the largest available within a wide radius. Site 1 was selected over Site 2 on the basis of a better match of power production to esti- mated future demand and a considerably shorter penstock. It shares with Site 2 the potential problem of being immediately below the badly deteriorated cannery diversion dam; however, direct delivery of water from the plant tailrace to the cannery pipeline may prove to be an asset should the cannery reopen. The primary disadvantage of the site is the difficult construc- tion access to the diversion weir and upper penstock. NBI-388-9523-V V-2 • • • -• - • - • • • • • • .. • .. .. - --- - ... - - - - - - ..... - Si te 2 would locate its powerhouse on the opposite bank from Site 1. A 16-inch-diameter penstock would be laid along the west side of the valley to a long diversion dam in the upper basin, 1500 feet beyond the USGS stream gage. Construc- tion conditions through an open series of terraces would be generally excellent. The high-head configuration of the Humpy Creek development is inherently attractive because it shifts the power equation toward the stable head component and away from the widely fluctuating flow component. However, the site was finally rejected on the basis of its excessively long penstock. A 1500-foot shorter configuration was considered but it would require suspending about 500 feet of penstock from the unstable cl i ff face above the falls. This approach was not considered prudent. Site 3 is located on the north shore of Larsen Bay north- west of the 01 d cannery. I ts power is inadequate and its transmission line extending under the bay would entail exces- sive costs. Site 4 is located 2.5 miles west of the village on the south shore of the bay. While the site is superior to Site 3, it is not competitive with Humpy Creek. NBI-388-9523-V V-3 i No. Steam 1 Humpy Creek, Lower 2 Humpy Creek, Upper 3 Unnamed Creek No. 1 4 Unnamed Creek No. 2 NBI-388-9523-V-1 TABLE V-1 ALTERNATIVE PROJECTS LARSEN BA Y Dr ainage Average Gross Penstock Area Flow Head Length (sq mi) (cfs) (ft) (ft) 6.28 13 200 2700 3.22 6.7 740 7000 (North) 1.5 3.1 370 2900 (West) 1.9 3.9 600 4800 i Transmission Power Line Remarks (mi) (kW) 0.7 270 Selected 0.7 320 2.5 75 2.9 150 -+ - - ':~=-~-=-=~L-A~R~S~EN;~B~A~y~r:~:S~~!.l..!!:::~~~--~FV~IG~:~RElf----ALTERNATIVE PROJECTS - - - .. - - - - SECTION VI RECOMMENDED HYDROELECTRIC PROJECT A. GENERAL Hydroelectric power plants transform the energy of falling water (head) into electrical energy. In general, a hydro- electric power project consists of a dam to produce the head or to divert stream flows; an intake and penstock or flume to con- vey the water to the hydraulic turbine; the turbine itself, which is coupled to a generator to produce electrical energy; accessory electrical equipment; and a transmission system to transmit the energy to a distribution system or user. This section describes these features as they are specifically adapted for the Larsen Bay Hydroelectric Project and the methodologies used in selecting the type of turbine and generator, the size and number of units and the configuration of the penstock and power plant. Field constructibility, project energy production, and project operations are also discussed. B. RECOMMENDED PROJECT DESCRIPTION In general, the features of the recommended project consist of diversion facilities that include a low weir and an inlet structure that will be located on Humpy Creek about one mile south of Larsen Bay at the confluence with the first tributary that joins the creek from the southeast. The diverion weir will divert water into a 27-inch-diameter penstock that will transport it 2700 feet along the right bank of Humpy Creek to a powerhouse wi th an install ed capac i ty of 270 kW. From the powerhouse, a transmission I ine will extend to the town of Larsen Bay along the alignment of the existing road. This road NBI-411-9523-VI VI-l will provide access to the project facilities. A concrete mat will be constructed where the short access road needed to link up the powerhouse with the existing road crosses Humpy Creek. A staging area will be provided in the flood plain near to the proposed diversion facilities. Access from the staging area to the diversion dam will be by a trail along the pipeline. These features and are through are presented on Plates II through VI in Appendix A described more specifically below. Exhibits VI-l VI-4 show photographs of the project area and the proposed locations of project features. The diversion weir will consist of a prefabricated steel module that wi 11 be bolted to a concrete apron. The at t i tude of the upstream face of the gate will be about 45 degrees from vert ical and the gate will be fitted with back supports. The steel weir module will be connected by a pin at the base and the upper sect ion wi 11 be supported by steel st ruts. A neo- prene flap wi 11 provi de the necessary water tigh tness at the connection of the weir diaphram to the apron. A prefabricated steel inlet structure will be located at the right of the weir. The 27-inch-diameter penstock will be about 2700 feet in length and will consist of both steel and fiberglass sections constructed along the right bank from the diversion weir to the powerhouse. The penstock will consist of buried fiberglass pipe whenever possible to eliminate the need for anchor blocks. Steel pipe will be used where rock foundation material is encountered or where other reasons dictate above-ground installa tion. Typical pens tock access road sect ions are shown on Plate III of Appendix A. The power plant at the terminus of the penstock will have an installed capacity of 270 kW and it will utilize an impulse- type turbine and a synchronous-type generator. NBI-411-9523-VI VI-2 ---- • • .. -• • .. • .. .. • • • • .. .. • " • -- • .. • .. • • • • • • • • The operating head will be 180 feet, wi th a design dis- charge of 23.8 cubic feet per second (cfs). The 270 kW rating is based on assuming a nominal turbine efficiency of 83 percent. It is possible that a turbine manufacturer may guarantee a higher turbine efficiency; if so, this will increase the turbine-generator rating proportionally. With reasonable turbine efficiency the turbine-generator will perform satisfactorily on turbine discharges as low as 10 percent of rating. Turbine discharges as high as 48 cfs will not cause a problem or create excessive maintenance costs for the turbine-generator unit. (A detailed "explanation of the turbine-generator selection following subsection.) process is incl uded in the The turbine-generator and all other equipment except the power transformer will be placed indoors at the powerhouse site. The turbine, speed increaser, flywheel, and generator will be shipped preinstalled on fabricated skids and no field assembly or alignment of those components will be necessary. The powerhouse construction will utilize a reinforced- concrete floor slab and a prefabricated metal building about 32 feet by 34 feet to house the equipment. Permanent lifting fac il i ties will not be prov ided; however, an oversi zed equip- ment door will permit portable lifting facilities to be used if they are required for a major overhaul. Since equipment of the type being used is very rugged, the normal annual overhaul functions should not require the lifting of heavy equipment sections. The three-phase power transformer will be mounted on a pad and placed outdoors adjacent to the powerhouse structure. A chain link fence with a barbed guard at the top will encompass the transformer and form the switchyard enclosure. The generator breaker will be inside the powerhouse. NBI-411-9523-VI VI-3 A transmission line from the powerhouse switchyard to the town of Larsen Bay will utilize a transmission voltage of 12.47 --- kV. The configuration of the line will be single pole with single cross arms. Poles will be located at 350-foot intervals with the lines running along the centers of the cross arms. A sketch showing the detailed configuration is included in Appendix A as Plate VI. As previousl y noted, no d ist r ibut ion system and cen tral genera tion fac il i ties curren tl y exist in Larsen Bay. They would have to be constructed to implement a hydroelectric proj- ect but they are not considered here as a project feature since they would also be necessary for a base case relying primarily on diesel generation. The diesel generation base case was used as an alternative for comparison with the proposed hydro- electric project. This point is discussed more extensively in Section VII, Project Energy Planning. C. TURBINE-GENERATOR SELECTION In the selection process, the type of turbine and type of generator were first selected from the available al terna- ti ves and the install ed capac i ty was t hen determined by an incremental cost/benefit economic analysis. This selection process is described below. 1. Description of Available Turbines Conventional turbine equipment that is commercially availa- ble is classified either as impulse or reaction turbine equip- ment. An impulse turbine is one having one or more free jets discharging into an aerated space and impinging on the buckets of the runner. The jet size increases as the head on the turbine decreases. For low-head applications the cost of the NBI-411-9523-VI VI-4 • -.. • --.. .. • .. • • • • • --• • • • • • • • • • • • • - - "'<.i - - - - - impulse turbines is generally not competitive with the reaction type. The impulse turbine can, however, be operated economi- cally on heads as low as 150 feet. For the 180-foot operating head of this development, there are two suitable types of impulse turbines, Pelton and Turgo. In the Pelton type the jet impinges the runner near its extrem- i ty and in the plane of the runner. In the Turgo type the jet impinges the runner from the side about mid-runner. For the same hydraulic conditions, the Turgo type will operate at about twice the speed of the Pel ton type. There is very Ii ttle difference between the two types in either efficiency or methods of control. A Francis turbine is one having a runner wi th a large n umber of fixed bl ades attached to a crown (top) and a band (bottom) • The d imensional configuration of the runner is designed to suit the head conditions of the application. Designs are commercially available to suit head conditions ranging from 15 to 1500 feet. In general the Francis turbine is not competi tive wi th the propeller type below a head of about 60 feet. A propeller turbine is one having a runner resembl ing a propeller with a small number of blades, usually four, five or six, to which water is suppl ied in an axial direction. The blades are attached to the hub of the runner. The blade angle is adjusted to sui t the head cond i tions of the appl ication. Runners are available in either fixed-blade or adjustable-blade designs. The suitable head range of propeller turbines is from 15 to 110 feet. The 180-foot head of the Larsen Bay Project is beyond the head range of the propell er turb ine. Accord ingl y, this type of turbine was not included in the study. In addition to the impulse and reaction turbine, a proprie- tary design called the Ossberger turbine is available for head NBI-411-9523-VI VI-5 ranges from 15 to 500 feet. The runner design is classified as a cross flow that derives energy from both impulse and reaction turbine principles. Water is forced through a rectangular cross section and guide vane system and then through the hori- zontal runner blades. This flow pattern has the unique advantage of working out refuse such as grass and leaves and melting snow and ice that may be forced between the blades of the runner as the water enters. Any quantity of water from 16 percent to 100 percent of the design flow is usable wi th optimum efficiency. 2. Description of Available Generators Generators can be of the synchronous or induction type. Induction generators are often considered more practical for the smaller turbine-generator installations because they cost less and require less maintenance. They require no excitation and need only a squirrel-cage rotor that uses no wire windings or brushes. Furthermore, they do not run at exact synchronous speed and complex equipment is not needed to bring them on line. They cannot be used to establish frequency, however, and must be connected to a system with synchronous generators because they take their exci ta tion from system current. The generators produce electric energy with a high degree of efficiency. Synchronous generators are usually three-phase star or Y-connected machines with one end of each winding connected together in common and the other ends used as line terminals. The al terna ting-current synchronous genera tor, or al terna tor, delivers its induced alternating current directly to the exter- nal circui t. It is used where transmission is to be sent over long lines. The alternating current can be transformed to the desired transmission voltage. NBI-411-9523-VI VI-6 • --- • .. • • .. - • - • • • .. • .. .. -• .. -- • --- • --• • -• • • • - ""'" - - For this development the synchronous-type generator is used because it is necessary to establish frequency. 3. Selection of Turbine Type As previously discussed, the 180 feet of head available for the Larsen Bay Hydroelectric Project is suitable for operating either a reaction turbine (Francis) or impulse turbine (Pelton or Turgo). For the size of this unit, the costs of equipment delivered at the job si te are about equal. Installation costs are generally lower for the impulse types since few imbedded parts are necessary. _ Any change in the rate of penstock flow will set up a pres- - - ..,." - - sure wave that increases the penstock pressure when the flow rate is decreased and lowers the penstock pressure when the flow rate is increased. Destructive pressure risks, known as water hammer, are possible if the flow is suddenly stopped. This water problem can be limited by building a surge chamber near the power plant, by installing a bypass valve (known as a pressure-relief valve) at the power plant, or by a combination of both methods. A surge chamber, to be effective, would have to be so high tba tit would no t be pr act ical. A bypass valve would have to be capable of discharging the same amount of water as the tur- bine and in addi tion would have to be able to dissipate the same hydraulic power as the turbine. A valve of this type can be constructed for a modest cost, 10 percent of the turbine cost. On a Francis turbine, the penstock flow is controlled by the opening and closing of the turbine wicket gates. An electrical load rejection will cause the wicket gates to close as fast as is permi tted by the turbine governor. Too slow a closing allows the turbine-generator speed to rise to destruc- NBI-411-9523-VI VI-7 tive velocities. Too fast a closing resul ts in high penstock water hammer pressures. The use of a turbine bypass valve and proper governor setting can hold the rise in both the speed and water hammer pressure within reasonable limits. A sudden decrease in electrical load initiates signals from the turbine governor that cause the bypass valve to open enough to maintain a near-constant penstock flow. The bypass valve then slowly closes under controlled conditions and the rise in water hammer pressure is negligible. Impulse turbines are equipped with a jet deflector. The jet deflector intercepts and deflects a portion of the jet or, in the case of a load rejection, the entire jet away from the runner. Under this condition, the rate of flow in the penstock is constant until the needle valve closes, under control of the governor, at a rate slow enough to keep the water hammer pres- sure from materially increasing the penstock pressure. The guide vanes of an Ossberger turbine serve the same f unc tion as t he wicket gates in the Fr anc is t urb ine. Both turb ines have h ydraul icall y simil ar relationships to t he pen- stock. The previous discussion for the Francis turbine is applicable to the Ossberger turbine. Using a Francis (reaction) turbine would require the use of a bypass valve. on this development The bypass valve and its controls increase the overall power plant costs more than installing an impulse turbine. On this basis, the impulse turbine was selected. 4. Selection of Number of Units Every turbine is most efficient wi thin a range of flows, with decreasing efficiency occurring beyond this range. Consequently, more power can usually be generated if two or more small turbines are selected rather than one large unit. NBI-411-9523-VI VI-8 • .. • ------ • • • • • • • .. • .. • • • .. • -• --.. • • • -• • • • , ... For example, two turbines, each rated at 50 percent of design flow, will produce more energy over the flow range than one turbine rated at 100 percent of design flow. However, the two turbines will generally cost 30 percent to 70 percent more than the single turbine. The extra value of the energy produced by the two units must therefore make up for the extra cost of using two units. In the specific case of Larsen Bay, the impulse unit to be used is very efficient over the anticipated range of flows; the relatively small extra energy that would result from the use of two units would not justify the extra expense. was therefore indicated. 5. Selection of Size of Unit A single unit The selection of turbine-generator size is primarily a matter of economics. The larger the turbine size, the larger the flow that can be accommodated and the more energy that can be generated; however, the cost is higher. Comparisons were therefore made of the incremental costs and benefits associated wi th increments in size. As long as the incremental benefits exceeded the incremental costs, it was economically justified to install the larger capacity. Five turbine sizes in all were investigated for the Larsen Bay Project. The sizing was based on turbine-generator capacities based on flows corresponding to the 35 percent to 15 percen t range of exceedance val ues on the Humpy Creek flow duration curve, Figure IV-1. A value of 180 feet of hydraulic head (gross head minus losses) was used in all cases. The average annual energy production for each size was calculated using the Humpy Creek flow duration curve. For a given hyd raul ic head, t he area und er such a curve wi thin the generation limits of the particular size and type of turbine NBI-411-9523-VI VI-9 under analysis represents the available energy. The result of the analysis is presented in Table VI-1. As shown, the range of flows investigated is from 11.9 cfs (at 35 percent exceedance) to 23.8 cfs (at 15 percent exceed- ance) with installed capacities of 145 kW to 270 kW and corre- sponding average annual energy values of 0.82 million kWh to 1.09 million kWh. The incremental benefits for the sizes analyzed were com- puted using the differences between the 50-year present worth of the energy for each addi tional increment and the data and assumptions presented in Section VII, Project Energy Planning, and Section IX, Economic Analysis. The incremental costs were based on the differential costs of the installed unit. The results of the analysis are presented in Table VI-2. The incremental benefits far exceeded the incremental costs for all size increases up to and including the largest size reviewed, 270 kW at the 15 percent exceedance poin t, which indicates that this is the optimal size studied. Judgment was the deciding factor not to size the unit for flows in excess of the 15 percent exceedance value. Increasing the turbine dis- charge somewhat beyond this point would probably be economical but it would decrease the energy available on the low-flow portion of the flow duration curve and would not materially increase the annual energy generation. The recommended 270 kW selection would make available all the energy represented by the flow duration curve between the 15 and 87 percent time exceeded. This is graphically illustrated in Figure VI-2, included at the end of this section. NBI-411-9523-VI VI-10 • .. ., - • • a. --.. .. • • lit! • .., • .. • • • • • ., -- • • • • .. • • • • D. FIELD CONSTRUCTIBILITY For the recommended project, various prefabrication opera- tions and field procedures would be utilized that would mini- mize field construction time and also minimize the use of highly specialized construction skills. The diversion weir module and the inlet structure would be shop-fabricated welded-steel structures with shop-applied protective coatings. After fabrication in Anchorage or Seattle, they would be shipped wholly assembled to the field. The field installation of these structures would consist of simply bolting the weir and inlet structure into place on the concrete apron. The 27-inch-diameter penstock would consist of either steel or fiberglass, depending on the geologic and topographic condi- tions encountered. The penstock would be steel where rock was encountered and where the penstock would be elevated. All other sections would utilize fiberglass pipe. The steel portions would be placed above ground with steel collars steel. resting on The steel either concrete pads or prefabricated collars would be shop-welded to the pipe during the fabricating process. The pipe sections would be connected wi tb flexible bolted couplings and no field welded connections would be required. The fiberglass sections of the penstock would be buried to eliminate the need for anchor blocks at vertical and horizontal bends. Bell and spigot joints wi th rubber gaskets woul d be utilized to permi t rapid field installation and the use of relatively unskilled labor. NBI-411-9523-VI VI-ll The powerhouse would consist of a prefabricated metal building erected on a concrete base slab. A standardized unit approximately 32 feet by 34 feet would be utilized. Field assembly of the building would be rapid and unskilled labor could be utilized. The turbine-generator, the speed increaser, and the flywheel will be shipped skid mounted, fully assembled and interconnected to the field. The entire assembly will be bolted in place on the powerhouse slab, the penstock will be connected, the electrical wiring will be finished, and the installation will be completed. In summary, the maximum use of prefabricated and preas- sembled components is envisioned. The use of concrete in general and formed concrete in particular has been minimized and all major features can be constructed expeditiously using relatively unskilled labor. E. PROJECT ENERGY PRODUCTION As mentioned in subsection C-5 above and as shown in Table VI-2, the average annual energy production for the recommended 270 kW installation at Larsen Bay is 1. 09 mill ion kWh. Th is value was derived using the flow duration curve rather than the average monthly hydrograph since the data used in deriving the flow duration curve were daily values rather than monthly averages as shown on the hydrograph. values have been used to compute However, the hydrograph the available peak power generation that could be expected per month. graph values exceeded the maximum turbine Where the hydro- design flow, the turbine flow was used for the calculation. The "available peak power" values were then used on a monthly percentage basis to distribute the average annual energy value of 1.09 million kWh to monthly energy values. The results of these compi la t ions are presented on Table VI-3. The monthly power and energy production values are shown on Figure VI-1. These monthly hydroelectic energy values will be used in Section VII, Project NBI-411-9523-VI VI-12 • ----.. • .. • - • • • .. • .. • .. .. • • .. • • • .. • • • .. • • • • • • ..... Energy Planning, to meet the projected present and future energy demands of Larsen Bay. The plant factor, the rat io of energy that coul d be pro- duced by the turbine-generator if continuously operated at its rating to the annual energy actually produced, is 46 percent for Larsen Bay. F. PROJECT OPERATION SCHEME AND CONTROLS 1. Turbine-Generator Controls for the turbine-generator unit will load the unit in response to the connected system demand. A turbine governor will control the turbine needle valve setting that controls the turbine discharge and thus matches the turbine-generator elec- trical output with the connected system load. A small decrease in the system load will cause the governor to actuate the jet deflector and a quantity of water will be deflected from the runner to maintain a constant runner speed. If the lower load continues, the turbine governor will cause the needle valve to move to a position where the turbine discharge is of the correct value and the jet deflector will move out of the jet stream to allow the full jet to impinge on the runner. As long as the connected load does not exceed the capacity of the turbine-generator, the electrical frequency can be held within approximately plus or minus one-tenth of a cycle. The turbine-generator is being operated on an isolated system; that is it is not elect rically connected into a gr id wi th other operating generating uni ts. Any overload in the unit will gradually decrease the unit's speed and result in a corresponding lowering of both line voltage and frequency. Minor overloadi ng, probably up to about ten percen t, can be tolerated. But an excessive overload can, if continued, cause protective devices to trip the unit • NBI-411-9523-VI VI-13 It is feasible to have a hydraulic turbine-generator unit operate in parallel with diesel generating units that would be constructed as a backup and supplemental electrical system. The hydraulic turbine can be operated as a base load unit and regulate the system frequency. By proper setting of the diesel uni t governors, the diesel units can be brought on line and operated during unusual system demands. The cost of this inte- grated system was included in the economic analysis. The turbine-generator will be manually started. A manual start implies that operating personnel are present during start up. The operating personnel shoul d physically check the unit. This check will include opening the turbine shut-off valve (if closed) and seeing that water is against the needle valve and all supporting systems are operable. Operating personnel will then actuate a single control swi tch and the turbine-generator will automatically start up. When the unit reaches synchronous speed, it automatically goes on line. The provision of enough sophisticated equipment and controls to allow the unit to be started up from a remote location is not proposed. Protective devices on the equipment will be capable of shutting the generating unit down automatically, which would require a manual startup. The automatic protective devices on the equipment will sense the internal temperature of the gen- erator, most bearing temperatures, and critical oil levels. High temperatures and low oil levels can trip the turbine- genera tor of f the 1 ine. An alarm wi 11 be given before any control device shuts down the generating unit. A pressure sensor will be installed at the penstock intake to function in concert with the turbine governor to protect the turbine during periods when there is not meet the turbine discharge requirements. sequences will be followed to protect the NBI-411-9523-VI VI-14 sufficient water to One of two control equipment: .. - • .. • .. -- • .. • .. • • • .. .. .. • .. • -• • • .. • .. • • .. .. • • • • 1. The lowering water level at the intake will bring the governor control into a mode where it will match the available wa ter quantity wi th the turbine discharge. If this reduced turbine discharge will not permit the turbine-generator to produce sufficient power to meet the load demand, then the turbine-generator wi 11 be operating in an overloaded condition as discussed above. 2. If the water level falls to a level where the penstock will not be running full, then the control will take the turbine-generator off the line. Based on the flow dura t ion curve for Humpy Creek, it is expected that about 13 percent of the time water levels will be too low for the turbine to run efficiently. In both cases an alarm will be given prior to shutdown. maintenance will be performed on a weekly Routine schedule. The power generated by the turbine-generator need not be reduced during this maintenance period. The maintenance will include routine checks to verify that (1) all equipment is operating in a normal condi tion, (2) none of the equipment is being operated at a temperature above normal limi ts, (3) all lubrication requirements are being met, and (4) no discontin- uity exists in electrical wiring, relays, or controls. Overhaul maintenance will be performed on an annual basis and it will be scheduled during the minimum average river flow, usually in March. The turbine-generator will have to be removed from the line and electrical power required by the City System will be provided by diesel generating units. This annual maintenance period will not normally exceed a week. This type of maintenance will include the following items: NBI-411-9523-VI VI-15 1. Areas of wear on the turbine-generator unit will be reviewed and corrective measures will be initiated in cases where wear beyond the allowable limi ts set by the manufacturer has occurred. 2. Electrical insulation checks will be made. 3. Relubrication will be required under the manu- facturer's recommendations. 4. 2. Verification will be made that all relays and controls are properly set. Diversion Facilities The design of the steel diversion weir provides a hinge at the base of the weir at the connection with the concrete apron. This design allows for periodic lowering of the weir to remove accumulated sediment. The frequency of such a maintenance procedure woul d depend on the rate of sediment deposition and the interference of the deposi ts wi th the diverted flows. If cleaning is necessary at all, the frequency is not expected to be more than once a year. NBI-411-9523-VI VI-16 - - • • .. • .. .. .. • .. • .. .. .. • • • .. -.. • .. • -.. III! .. • • .. • • • • - Percent Times Exceedance .... (Percent) 15 20 25 30 .,.. 35 NBI-388-9523-VI-1 TABLE VI-1 TURBINE-GENERATOR SIZING LARSEN BAY Turbine Unit Penstock Discharge Head Size 1.0. (cfs) (feet) (kW) (Inches) 23.8 180 270 27 18.9 177 210 24 16.2 183 190 24 14.0 188 165 24 11.9 191 145 24 Annual Energy Generated (million kWh) 1.09 0.99 0.94 0.88 0.82 Plant Rating (kW) 145 165 190 210 270 TABLE VI-2 PLANT SIZE AND INCREMENTAL COST AND BENEFIT LARSEN BAY Incremental Jan. 1, 1982 Material Net Benefit Incremental Cost with Heating Benefit -----------dollars in thousands---------- 4,661 2.1 148 4,809 19.0 106 4,915 24.4 128 5,043 52.3 170 5,213 Incremental BiC Ratio 70.5 5.6 5.2 3.3 NBI-388-9523-VI-2 • - • ., • • • • • • • .. • • • .. • .. • .. • .. • ... • .. • .. • .. • ... • .. • • • lilt ,.0,4 ",. ~'''~ - - - Average Month Flow (cfs) Jan 7.9 Feb 6.7 Mar 4.8 Apr 9.8 May 27.1 June 23.7 July 9.4 Aug 10.6 Sept 18.2 Oct 16.8 Nov 12.6 Dec 7.5 TABLE VI-3 AVERAGE MONTHLY PEAK POWER OUTPUT AND ENERGY GENERATION -270 kW UNIT LARSEN BAY Flow Utilized for Available Energy Head Design Peak Monthly Generation Loss Head Power Energy (thousand (cfs) (feet) (feet) (kW) kWh) 7.9 2.04 196 98 56.8 6.7 1.47 197 83 48.2 4.8 0.75 198 60 34.4 9.8 3.14 195 120 70.3 23.8 18.5 180 270 170.8 23.7 18.4 180 269 170.2 9.4 2.89 196 116 67.5 10.6 3.67 195 130 76.2 18.2 10.83 188 216 130.7 16.8 9.23 189 200 120.6 12.6 5.19 193 153 90.5 7.5 1.84 197 93 53.8 Total 1090 NBI-388-9523-VI-3 Percent of Total Annual Energy 5.2 4.4 3.2 6.4 15.7 15.6 6.2 7.0 12.0 11.1 8.3 4.9 100.0 .. - - SECTION VII PROJECT ENERGY PLANNING A. GENERAL This section presents the projected energy usage for Larsen Bay over the study period and two alternative means of meeting this projected demand: the base case plan and the recommended hydroelectric project. The potential future demand for power and energy at Larsen Bay was estimated during this study in order to establish the electrical requirements that the alter- natives could meet. This information was used to size both alternatives and was also used for the overall economic analysis of the project, which is presented in Section IX. , B. PROJECTION CONSIDERATIONS The future demand for power and energy at Larsen Bay is a function of a number of variables that are difficult to fore- cast and quantify. These factors include the appliance satura- tion rate; the effects of cultural factors and traditional life styles on energy consumption; the rate of modernization of the Native life style; the amount of employment in the fish processing industry; the natural variability of the fishery; the amount of new housing buil t in the area; and numerous political factors such as the 1981 legislation relating to energy projects and programs of the APA. Electrical energy at Larsen Bay is currently supplied by individually owned diesel generators. Because of this, no base data on power use within a power grid are available. Electrical use patterns will almost certainly be altered by the establishment of a central power system, and the historical data currently available for Larsen Bay are not necessarily relevant. This situation makes the quantification of future electrical demand more difficult NBISF-426-9523-VII VII-1 and uncertain than it would be in the case of an existing power supply system. The installation of the much cheaper hydroelec- tric alternative will almost certainly al ter the pattern of energy and power demand; therefore the forecast presented here is probably conservative. 1. Appliance Saturation Rate The number and type of appliances owned by each household, as well as the extent to which these appliances are used, may have a significant effect on the amount of power used in the village. A definite relationship between appliances within a household and electrical use characteristics is very elusive. The actual use of energy is more dependent on the number of people wi thin a given res idence, and their age, habits, and financial condition. For example, one could predict the annual electrical use of a refrigerator or freezer because this is almost independent of activity and habits. Energy use for electric lights, small appliances, and television is very susceptible to habits. Energy used for water heaters, washers, dryers, and dishwashers varies primarily subject to the number and age of the users. For example, hot water use among families with small children or babies is very high. One method of measuring potential future growth and use of appliances is through a concept known as the appliance saturation rate. The estimated present percentages of homes having various types of appliances in Anchorage, the Kenai-Cook Inlet area, and Larsen Bay are presented in Table VII-l. This information for Larsen Bay is very approximate and was obtained through several inter- views with village residents. The number of appliances in any given household in Larsen Bay depends on the desire and ability to obtain the appliances, the cost of electricity, and the available room for the appli- ances. Larsen Bay does not currently have any form of central genera t ion or elect rical d istri but ion system. Approximately NBISF-426-9523-VII VII-2 --- • • • • • - • • • .. • .. .. • .. .. • • -... .. --- • .. • .. ... .. • .. .. .. - - - - one-half of the homes in the village receive electrical power from small, pri va tely owned generators; the remainder of the homes do not have any form of electrical supply. When cheap electricity becomes available, all of the homes in the village will probably begin to acquire appliances. The purpose of presenting the Anchorage and Kenai-Cook Inlet data in Table VII-1 is to provide a compar ison with largely urbanized areas that have much greater unit consumption of electrical energy. Appliance saturation rates (and sizes of appliances) for rural Alaskan villages such as Larsen Bay can be expected to increase in the future. The base year 1980 energy use rate per residential ~ustomer was about 4400 kWh, as discussed subsequently. This indicates a fairly high per customer use of electrici ty in this area. The homes in Larsen Bay are small and those homes that do have electricity have all of the appliances that they are likely to acquire. At present no change in the quali ty of housing at Larsen Bay is anticipated. Any significant increase in per customer consumption of electricity at Larsen Bay would proba- bly be the result of a change in the type of housing common in the village. The Kodiak Island Housing Authori ty is currently preparing an application for HUD funding to construct 13 single family housing uni ts. The available data are insufficient to make predictions of this nature. Therefore, the rate of consumption of energy was assumed to increase slowly. For purposes of this study, it was assumed that the use rate would increase to about 5,270 kWh annually by 2001. The Ebasco ( 1980) regional inventory assumed that households would increase energy consumption to 6,000 kWh per year by the year 1995, exclusive of electric space heating. The CH2M HILL report pred icted that the increase in energy use would be 12 percent annually from 1981 through 1985, and four percent annually thereafter. The new policies permitting opportunities for reductions in price, discussed in the next section, NBISF-426-9523-VII VII-3 ---indicate that this projected 5,270 kWh annual residential rate • is on the conservative side. 2. The Influence of Price on the Demand for Power The 1981 legislation relating to the projects and programs of the APA may result in some reduction in the cost of power at Larsen Bay. This possible decrease in power cost could be expected to be accompanied by an increase in per customer use. Data from the Alaska Power Administration have been developed to show the 1980 individual customer use of electric- i ty versus cost for all towns, ci ties, and villages for which information was available in Alaska. This information is summarized in tabular form in Table VII-2 and graphically in Figure VII-l. While the data on Figure VII-1 are somewhat -• • .. • • • ., • • .. ., scattered, the trend is evident that low power costs result in • higher usage and high power costs result in lower usage. In economic terminology, this relationship of price to quantity consumed is referred to as "elasticity" of demand. As indicated by Table VII-2, unit energy costs of less than 100 mills per kilowatt-hour are generally accompanied by high use rates, in excess of 7000 ki Iowa t t-bours per customer per year. As the unit price of power increases, the per customer use tends to decrease, with the 48 AVEC Villages having energy costs in excess of 400 mills per kilowatt-hour and annual per customer demands of about 2000 kilowatt-hours. The two different utilities listed for Fairbanks provide an even clearer example of the elasticity of the demand for electrical energy; in this case where the cost of energy was 75.1 mills/kWh the annual demand was 10,519 kWh per customer and where the cost of energy was 122.2 mi lIs/kWh the demand was 5501 kWh per customer. NBISF-426-9523-VII VII-4 • ... • .. • • • ., .. ., -., • • -• • ., .. >I'" - - - - The general conclusion is that in the higher ranges of price there is significant elasticity in demand. Lower energy costs result in higher energy usage and this can also be expected to occur in Larsen Bay with the advent of lower prices. The actual amount of higher usage, however, is very difficul t to quantify. For purposes of this study no attempt has been made to predict the higher usage other than to incorpora te a moderate increase in the energy in the projections covered below. probably on the low side. C. ENERGY DEMAND PROJECTIONS per customer use of These projections are For the economic evaluation, a period of 50 years after the proposed date for the hydroelectric project to come on-line was considered. As requested by APA, the period of study was started in January 1982. The demand for power was assumed to increase for 20 years from the beginning of the period of study and was then held at a constant value for the remainder of the study. The planning period is the 20-year period during which increased demand for energy was recognized, from January 1982 to December 2001. The economic evaluation period extends past the planning period to 2034, 50 years after the on-line date for the hydroelectric alternative. The overall energy demand for Larsen Bay for purposes of energy planning has been broken into two primary categories: direct electrical demand, which includes residential, small commercial, and school; and space heat ing demand. A cannery formerly operated at Larsen Bay; however, it has been dismantled and was not considered for purposes of this study. Projections for each of these categories and the combined requirements are presented below. NBISF-426-9523-VII VII-5 1. Direct Electrical Demand The general approach followed in estimating direct elec- trical demand was to break down the direct city system demand ---- into general types of customers normally identified by util-.. ities in projecting electrical users in small villages. These include the number of residential, small commercial, and school customers. Residential use represents the largest proportion of usage, and for Larsen Bay it amounted to about 60 percent. The base year of 1980 demand was taken from available data on popula t ion, average number of individuals per customer unit, and per customer usage estimates. From the CH2M HILL (1981) report, a village electrical demand of 132,000 kWh per year and 30 residences were used to derive the per customer use rate of 4,400 kWh per customer per year. The R. W. Retherford and Associates study (1980) indicates an annual per customer use rate of 4960 kWh. Projections beyond 1980 were not directly tied to estimated growth in population. Because of significant changes that could occur in the number of residential customers as a result of existing housing that are not currently supplied with power being electrified, it was found that residential demand was more closely correlated to the number of housing units than to population growth. This was substantiated by AVEC records of similar communities. Growth in demand from 1980 to 1985 may be heavily influenced by the electrification of the entire vi llage. The increase in residential use for this period was assumed to be nine percent; after 1985, the annual growth rate was assumed to be two percent. The CH2M HILL report predicted that the increase in energy use would be 12 percent annually from 1981 to 1985, and four percent annually thereafter. Peak demands were calculated by applying typical load factors for each type of consumer group. Load factor data were derived from AVEC historical data as well as data from other NBISF-426-9523-VII VII-6 • .. • .. -.. III> .. ... • ... • III> • • • • • ... .. • .. .. .. .. • .. .. .. - - - - - - - - - - - - - - typical utilities. Historically, the load factor tends to improve as the load increases. This improvement is explained by added street lighting, refrigeration, and other loads that tend to level the power demand. Projected total annual direct electrical demands over the planning period to 2001 are shown in Table VII-3. An annualized table showing these demands is included as Table VII-10. No data were available on the monthly energy demands for Larsen Bay. The only source of data found during the course of the study for monthly demands for small rural villages such as Larsen Bay was the 1979 AVEC records for Togiak. Using these data, the monthly percentages of the total annual energy demand were computed. These values are presented in Table VII-4 and are used in Tables VII-9A to VII-9D to compute the projected monthly energy demands from 1980 to 2001. While the total amount of energy used in a given village will vary consider- ably, it was assumed that the monthly use pattern would be fairly similar for rural villages throughout the state; the Togiak values were therefore assumed to be applicable to Larsen Bay. At any rate, any error resulting from this assumption is expected to be small. 2. Space Heating Demand The fuel oil use rate for Larsen Bay for 1980 was obtained from the CH2M HILL report (1981) on energy alternatives. This report also gave estimated values for 1990 and 2000. These values were used with interpolated and extrapolated values for 1985 and 2001 to compute the annual heating requirements for Larsen Bay in terms of equivalent kilowatt-hours of electrical energy. These values are presented in Table VII-5. Note that the total potential demand is far greater than the expected output of the hydroelectric project; thus it does not con- stitute a constraint on the economic analysis. NBISF-426-9523-VII VII-7 The monthly heating demands over the study period were computed using the number of heating degree days per month from the Larsen Bay Communi ty Profile and applying the calculated monthly percentages to the annual heat demand values from Table VII-5. The resulting projected monthly heating demands for 1980 to 2001 are presented in Table VII-6. • - • • • .. • • • The actual daily variation in heat demand is not necessar-.. i ly represented by the monthly demand for heat; however, for ease of computation, differences between monthly totals and actual usable amounts of heat were ignored. The estimates of heat demand presented herein are conservative. 3. Total Energy Demands The projected annual energy values for direct electrical and heating demands are presented in Table VII-7. The projected monthly energy demands for these same categories are presented in Table VII-8. Also shown in the tables are the total direct electrical demand and the total combined demand (direct electrical and heating demand). The annual energy projections from Table VII-7 are pre- sented in graphical form in Figure VII-2, where the energy demands are plotted for each year of the study period. Also shown is the annual hydroelectric energy production for the sizes stud ied (145 kW to 270 kW). Figure VII-2 presents two separate graphs of the same information: overall data and detailed data. The overall data graph illustrates that a very large proportion of the combined energy demand is heating demand. The detai led data graph presents in more detai 1 the relative values of the various demands and available generation values. The distribution of hydroelectric generation used to meet direct electrical demand, and the use of excess hydroelectric NBISF-426-9523-VII VII-8 • • • • .. .. .. iii .. .. • .. • .. .. • • III III .. .. .. • .. .. Ia • .. - - -- ", .. ""," ... - - - - - energy for space heating, is presented as Tables VII-9A through VII-90. These tables are discussed in detial on pages VII-16 and VII-17. The monthly energy projections from Tables VII-9A to VII-90 are presented in Figure VII-3, again as an overall data graph and a detailed data graph. These graphs show the relationship on a monthly basis between the energy demands and the hydro- electric energy available over the study period. The graphs illustrate the general periods where the hydroelectric energy would have to be supplemented by diesel generation to meet the village needs and when excess energy would be available for space heating. As shown, during an average water year the hydroelectric· plant would generate energy sufficient to meet more than 90 percent of the village's direct electrical demand. The annual values of direct electrical demand, and the generation mix that would be met by the hydro project and the supplemental diesel, are presented as Table VII-10. O. BASE CASE PLAN The base case plan as originally formulated for Larsen Bay included diesel generation supplemented by waste heat recovery. This plan was mod ified to include wind generation. The plan as originally formulated is presented below, and is followed by the wind generation plan . 1. Original Plan The base case plan to meet the projected energy demands presented above was developed assuming that a central diesel generation plant and distribution system would be built at Larsen Bay during the summer of 1982. This plant would consist of three diesel generating units with 100 kW of capacity each, NBISF-426-9523-VII VII-9 • - • resulting in a firm capacity of 200 kilowattsll. This capacity a should be adequate to meet peak demands on the system through- out the period of study based on previously stated assumptions about projected demands for power. The diesel engines would be replaced every 15 years, and the entire structure would be replaced every 30 years. The lives of the engines were shortened from 20 to 15 years because the small machines selected for this site run at a higher speed than the larger systems, and would therefore wear diesel engines operate at 1200 rpm. this site would operate at 1800 rpm. out faster. Commonly used The machines selected for In order to implement the diesel system, it would also be necessary to install fuel storage facilities. For purposes of this study, it was assumed that the fuel storage facilities at Larsen Bay would consist of two 50,000-gallon tanks surrounded by a protective dike. The city has applied for a grant to purchase four 10,000 gallon fuel tanks from the cannery. The base case would also utilize heat recovered from the diesel generators to the maximum extent feasible. The fuel that the engines use represents energy injected into the system, which is about 138,000 BTUs for every gallon of fuel oil consumed. About one-third of this thermal energy is con- verted into electrical energy, about one-third is rejected in the form of heat from jacket water and oil cool ing, and the remaining one-third is rejected, also in the form of heat, in the hot exhaust gases. The heat energy from the jacket and oil cooling water is the easiest portion of the waste heat to recover. This can be accomplished by installing a simple heat exchanger and heating 11 In figuring firm capacity, the largest unit is omitted. NBISF-426-9523-VII VII-l0 • - • .. • • • .. • .. • • • • • .. • • • .. • .. III .. • • !II • .. • • • - ,- - - -- - - - .. - .. - - - water to be used for space heating. The temperature available is about 180 to 1900 F, which is quite usable for hydronic heating or air plenum radiators. The exhaust heat is of much higher quality, 600 to 10000 F, but it is much more expensive and complicated to capture. The exhaust is forced through what looks like a standard fire tube or water tube boiler, either heating the water to just below boiling or producing steam. The hot water is much easier to deal with, so most systems control the flows to prevent the formation of steam. The jacket water heat is almost entirely usable, while the -typical recovery efficiency of the exhaust heat system is between 30 and 40 percent at full load. For purposes of this study, it was assumed that only jacket heat would be recovered and that exhaust heat recovery would not be feasible from a first cost or maintenance standpoint. One real problem in waste heat utilization is that the heat available is directly dependent upon the electrical generation requirements at any particular time. The requirements for heating the buildings are, however, dependent upon the weather. There is no viable method at present to store this heat over long periods. Therefore, much available heat energy cannot be utilized simply because there is no need for it at the time it is avai lable. This is called coincidence between supply and demand . For this study it was assumed that about 60 percent of the available jacket heat could be utilized each year. As the generation increases over time, the heat is available more of the time and therefore somewhat greater usage could be expected. It was assumed that public buildings in the area would be connected ini tially and that this would not change substantially over time. Their utilization was assumed to NBISF-426-9523-VII VII-11 increase by 1.5 percent per year. The amount of usable heat and growth rate were based on experience with similar projects. Data on installations of this type are scarce; however, these projections are felt to be conservative. The community hall, clinic, old school, and new school at Larsen Bay would use the heat recovered from the diesel system. The existence of these heating loads was verified from the community profile and from interviews with local reidents. The items associated with waste heat recovery include the installation of equipment in the powerhouse and the use of radiators and insulated pipes to convey the water to and from the point of use. The equipment in the powerhouse would consist of heat exchangers, piping, a circulating pump, and fan controls. Insulated pipes would be laid from the powerhouse to the point of heat demand. Hot water radiation would be installed in the public buildings. Waste heat could be recovered and used for heating build ings up to 2000 feet from the powerhouse. The equipment in the powerhouse would have to be replaced when the diesels are replaced. The equipment for waste heat recovery from the water jackets and oil cooling is essentially 8n extension of the diesel engine cooling system, has no moving parts, and should last at least 20 years. The hot water distribution lines and radiators should last for the entire economic life of the project. The diesel generation system at Larsen Bay would consume about 51,530 gallons of fuel oil in 1983, and this amount could be expected to increase to more than 80,000 gallons annually by 2001. The fuel oil savings from waste heat recovery would be about 17,000 gallons annually in 2001. NBISF-426-9523-VII VII-12 • --- • • .. III .. • .. III • III .. • •• .. • .. .. • • • • .. • • • -.. It .. • II • • • - - - - - - - - - - 2. Wind Generation Plan The possibility of supplementing the existing diesel system with wind generation was investigated as part of the base case analysis. At the direction of the Alaska Power Authority, all wind data and wind system costs were obtained from a report entitled "Bristol Bay Regional Power Plan, Detailed Feasibility Analysis, Interim Feasibility Assessment Report", 1982, by Stone and Webster. Unpublished data and information developed by Stone and Webster in conjunction with this report was also utilized. Wind energy is an emerging technology, but has, to date, proved to be economically feasible only under certain condi- tions. The investment cost associated with wind generation is very high, and the cost of other energy sources must be greater than at least 15 cents per kWh to justify the investment. Standard equipment uses induction generators, and system stabili ty becomes a problem if more than about 20 percent of the total system power is from wind. For some limited applica- tions, such as remote cabins and communications installations, direct current generators and banks of storage batteries may be practical. Some configurations that use excess wind energy for space heating show good overall economics. The only proven wind generators that are currently avail- able have capacities of 10 kW or less. However, units up to 100 kW are currently becoming commercially available and are expected to be dependable. The application of this equipment is subject to some limiting restrictions. In order to be efficient the wind turbine must operate at low wind speeds and yet be rugged enough to withstand high gust ing and wind. The gear boxes, towers, and blades must operate under these adverse conditions almost continuously. At this time few manufacturers are able to demonstrate the required reliability under Alaska conditions. NBISF-426-9523-VII VII-13 The electrical interface to the utili ty system is also fairly complex wi th some reliabili ty problems. The simplest and most reliable systems use induction generators, but these units introduce another limiting factor, stability problems. The wind varies widely in available energy. This variation can be over seconds, days or months. Energy must be stored to bridge the periods of low wind. There are many ideas about possible storage mediums including compressed hydrogen generation, pumped hydro storage, thermal. air, batteries, flywheels, and All of these methods have a reasonable theoretical basis but are not commercially mature. The efficiency, availability, reliability and operational requirements of these schemes are many years from application to present electric power systems. Storage of heat using water or eutechtic sal ts is a good system if the energy is to be used ultimately for space heat. Under rapidly varying wind conditions the energy output of wind units varies widely. Since utility system loads are quite stable, the other generation must absorb these wide varia- tions. The induction generators . also introduce a frequency stability problem, since they do not operate at a "synchronous" speed, deriving their excitation from the power system. These conditions limit the amount of wind driven induction generation to about 20% at any given moment. This is a very rough number and will vary with the inherent stability of the existing system, but will probably never exceed 30%. Synchronous machines which could carry much more of the load are prohibitively expensive and not well developed, reliable systems. NBISF-426-9523-VII VII-14 • -.. .. • - • .. • .. • .. • • .. .. • .. .. .. .. .. • .. III' .. II .. III' .. .. .. .. .. .. • III • -- - - -- - - - ..... - - ..., - Since storage is a major problem, the electrical energy generally is generated and consumed in the same instant. At periods of high wind the loads may be low, while at times of high load there may be low wind condi tions. This coincidence factor greatly limits the final percentage of energy which can be generated with wind equipment. To an electric utility the wind generation represents only a savings in fuel and some slight reduction in engine mainte- nance. A full-sized diesel plant must be maintained because the wind source may not be available during the system peak. This benefit is often overestimated by individual consumers who have their own wind systems because they save the full billing rate for the electrical power. Actually, they are not paying for the standby generation, utility equipment and per- sonnel available to them when the wind doesn't blow. They are being subsidized by their neighbors. The communi ties we have studied fall outside of the wind class map provided. We have assumed Class 5 winds for all communities. square meter. This provides an average energy of 390 Watts per For this study, two types of wind machines were consid- ered. Both types are mounted on 60 foot towers and use induc- tion generators. One unit has seven-foot-diameter blades and a maximum output of 10 kW, and the other has 20-foot-diameter blades, with a maximum output of 25 kW. A maximum power pene- tration of 20 percent was assumed; this means that at any given moment, not more than 20 percent of the total system load can be met by wind driven generators. Significant data on the machines investigated are presented as Table VlI-11. NBISF-426-9523-VII VII-15 For this study, it was assumed that three ten kilowatt wind generators would be installed at Larsen Bay during 1982, and that these plants would be operational during 1983 and would require replacement every 15 years. A fourth uni t woul d be brought on line during 1991 and would increase the total installed capaci ty to 40 kW. The usable wind generation is presented as Table V II-12. Inspection of Table V 11-12 shows that the amount of usable wind generation has been assumed to be constant as long as the installed capacity remains the same. The amount of usable wind generation would probably actually increase sl ight ly wi th time; however, th is increase would probably be minor, and the accuracy of the energy use and economic analyses would not be enhanced by this refinement. The estimates presented here are probably high. E. RECOMMENDED PROJECT PLAN The recommended project plan for Larsen Bay would consist of a 270 kW hydroelectric power plant supplemented by diesel generation. The diesel and fuel storage facili ties would be installed during 1982 according to the plan outlined above. The hydroelectric power plant would become functional in late 1984. An on-line date of January 1, 1985, has been assumed for this study. The annual average energy generation is shown on Figure VII-2. The entire diesel capacity (300 kW installed capacity) would be required as standby and backup power. The hydroelec- tric generation would be adequate to meet the direct electrical demand during most of the year; however, during periods between the end of November and the first of April it would be neces- sary to supplement the hydroelectric generation with diesel in order to meet the direct electrical demand. The full capacity of diesel generation required to meet the direct electrical demand would still be necessary for emergency use. Since the diesel engines would not operate as much under this plan as NBISF-426-9523-VII VII-16 .. • • • .. .. .. • .. .. • .. IIIi .. • .. .. • .. .. .. • • .. .. • .. • .. • .. .. .. .. • .. .. - - .... .... - - - they would under the base case plan, it was assumed that they would not need to be replaced for at least 30 years. This would give the engines and structure the same useful life. Waste heat recovery would not be included as part of this plan because the diesels would not operate often enough to justify the installation of the waste heat equipment. The average annual energy production for the hydroelectric power plant would be 1.09 million kWh, compared to a projected direct electrical demand for electricity of 0.464 million kWh in 1985 and 0.723 million kWh for the year 2000. The average annual plant factor would be about 46 percent. Diesel genera- tion would be required to meet the direct electrical demand for a small part of the time due to the lack of coincidence between electrical demand and hydroelectric generation. Hydroelectric energy not needed to meet the direct electrical demand would be used for space heating. Appendix G describes space heating installation and costs for Larsen Bay. Using the above criteria, the amount of hydroelectric energy that is available over the study period to meet the direct electrical demands and the heating demands has been com- puted on a monthly basis. The results are presented in Tables VII-9A through VI 1-90. The direct electrical demand and the mix of demand that could be met by hydro and required supple- mental diesel generation are presented as Table VlI-10. The resulting net values of hydroelectric energy used for the direct electrical demand and the heating demands will be used in Section IX, Economic Analysis. Note that the "energy accounting" described above and presented in Tables VII-9A through 90 assumes that 100 percent usage can be made of the available hydroelectric energy. This usage level may not be wholly attainable in practice because of the unavailability or breakdown of end-use equipment and NBISF-426-9523-VII VII-17 d istr i but ion lines. Al so, a system making use of all of the excess hydroelectric energy for heat would not be 100 percent efficient. However, any error resulting from the assumption of a 100 percent usage rate would likely be small and would be counterbalanced because both the projected demand and the hydroelectric energy output estimates are conservative. NBISF-426-9523-VII VII-1S • .. • - • .. • • II' • It • • .. .. .. • • • • • .. • .. • • • .. • .. • .. • .. • .. • • - - - ... - - - - - TABLE VII-1 ELECTRICAL APPLIANCE SATURATION RATES LARSEN BAY Consumption Kenai- per House-Cook Larsen Appliance Household 1.1 Anchorage 1/ Inlet 1.1 ~~/ (kWh) -------percentage of total households------- Lights 1,000 100 100 Small Appliances 1,010 100 100 Refrigerator 1,250 100 100 Freezer 1,350 42 56 Water Heater 3,475 100 94 Television 400 156 100+ Video Tape Recorder 3/ Y 1./ Washer 70 50 85 (Water) (1,050) Dryer 1,000 71 76 Dishwasher 230 50 31 (Water) (700) 1.1 Values are for 1978 from "Electric Power Consumption for the Railbelt: A Projection of Requirements," Technical Appendices, Institute of Social and Economic Resources, May 23, 1980. ~/ The percentage of residences having the listed appliances is based on estimates from several Larsen Bay residents usage rate data are not available nor is the mode split between electrical and other sources of energy known. 1./ Not available. NBISF-426-9523-7-1 52 52 52 52 52 52 8 52 20 2 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. TABLE VII-2 UNIT COST AND ENERGY DEMANo..!i ALASKA Cost Location (mills/kWh) 5 Villages (Southeast) 298.7 Haines 2 / 144.3 Juneall2/ 45.7 Juneau-92.2 Ketchikan 58.4 Metlakatla 31.5 Petersburg 123.5 Sitka 49.8 Skagway 133.9 Wrangell 156.3 Yakutat 152.7 AnChOrag~~ 37.5 Anchorag~/ 33.6 Anchorag~ 45.8 Glenallen, Valdez 131. 5 Homer 35.9 Kodiak 149.3 Seward 54.0 Fairbank4j 122.2 Fairbank~ 75.1 Fort Yukon 245.3 Tanana 269.9 48 Villages (AVEC) 422.1 Barrow 129.8 Kotzebue 199.7 Bethel 177.4 Dillingham 151.9 McGrath 233.5 Naknek 174.5 Data obtained from "Alaska Electric Power 1980," Sixth Edition, August 1981, United of Energy, Alaska Power Administration. table on page 40, "Energy Sales, Revenue, were used to develop this table. Demand (kWh/Customer) 3,996 5,680 7,775 7,775 8,528 17,981 6,355 8,483 5,879 4,689 7,170 9,124 11,982 14,800 5,890 12,644 5,871 6,694 5,501 10,519 1,669 5,992 2,044 4,395 5,290 4,590 5,000 1,735 5,524 Statistics, 1960- States Department Val ues from the Customers--1980," ~/ Juneau, Anchorage and Fairbanks are served by more than one utility. Each listing is for a separate utility. NBISF-426-9523-7-2 • - • ... • -.. .. • • • -.. .. .. .. • ... • • • .. • • .. .. .. ... .. • • .. .. • • .. • .. - - .... - +- - .... - - - - TABLE VII-3 PROJECTED ANNUAL ENERGY DEMAND LARSEN BAY Annual Energy Peak Type of Number of Demand Demand Year Consumer Customers (1000 kWh) 1./ (kW) -- 1980 Residential 48 211 2:..1 70 Small Commercial 5 30 11 School 1 131 55 ~ Total City System 54 372 136 1985 Residential,i./ 75 330 94 Small Commercial 5 36 12 School 1 159 60 Total City System 81 525 166 1990 Residential 83 364 95 Small Commercial 6 40 12 School 1 176 67 Total City System 90 580 174 2000 Total System 92 707 180 2001 Total System 93 723 183 CH2M Hill Study, June 1981. 1/ 2/ 3/ 4/ CH2M Hill study of June 1981 indicates an annual demand of 4400 kWh per consumer. The R. W. Retherford study indicates 4960 kWh per consumer, annually. Retherford Associates estimate. 15 to 20 HUD houses are to be built according to the Community Profile. NBI-388-9523-VII-3 Month January February March April May June July August September October November December Totals TABLE VII-4 MONTHLY LOAD CHARACTERISTICsli Monthly Power Demand (kW) 165 ~/ 151 127 139 127 115 131 144 137 163 163 163 Monthly Percentage of Annual Peak Power DemancJ/ 100.0 91.5 77.0 84.2 77.0 69.7 79.4 87.3 83.0 98.8 98.8 98.8 Monthly Energy Demand (kWh) 56,400 50,600 74,400 52,500 50,100 21,000 35,200 44,900 55,500 47,800 52,500 61,600 602,500 Based on 1979 AVEC data for Togiak. Monthly Percentage of Annual Energy DemancIl./ , 9.4 8.4 12.4 8.7 8.3 3.5 5.8 7.5 9.2 7.9 8.7 10.2 100.0 1./ ~/ This value was changed from 192 kW to 165 kW because it seemed abnormally high compared to other years. This gives a 41.7 percent annual load factor. :l/ Percentages calculated from demand. NBISF-426-9523-7-4 • --- • • .. • .. ., ... .. .. • • ... • .. .. .. • .. • ... • lilt • • lilt • .. • .. - - hltlJ - - - - Year - Annual Fuel Oil..!./ (BBL) Annual Requiremen~ (1000 kWh) TABLE VII-5 ANNUAL HEATING DEMAND LARSEN BAY 1980 1985 1990 -~ 900 1,200 1,500 1,400 1,870 2,340 2000 2001 2,040 2,090 3,180 3,250 1J 1980, 1990, and 2000 values from CH2M Hill report (1981), Tables 4-6. Other values interpolated or extrapolated. ~/ Based on 55 gal/BBL, 138,000 BTU/gal, 70% efficiency, and 3413 BTU/kWh. Values rounded to nearest 10 gallons. NBISF-426-9523-7-5 Heating Month Degre~/ Days - TABLE VII-6 MONTHLY HEATING DEMANDsl/ LARSEN BAY Percentage of Annual Heating Degree Days 1980 1985 -1990 2000 2001 • .. • • .. • • .. ---------------1000'kWh ---------------.. January 850 10.9 February 1,070 13.7 March 850 10.9 April 635 8.1 May 595 7.6 June 360 4.6 July 200 2.6 August 235 3.0 September 365 4.7 October 650 8.3 November 800 10.2 December 1,200 15.4 Totals 7,810 100.00 153 204 192 256 153 204 113 151 106 142 64 86 36 49 42 56 66 88 116 155 143 191 216 288 1,400 1,870 255 321 255 189 178 108 61 70 110 194 239 360 2,340 347 436 347 257 242 146 83 95 149 264 324 490 3,180 1/ Based on the number of heating degree days indicated in the Larsen Bay Community Profile multiplied by the Annual Heating Demands from Table VII-5. ~/ From the Larsen Bay Community Profile. NBISF-426-9523-7-6 354 445 354 263 247 149 84 98 153 270 332 501 3,250 ,. .. • .. • .. • .. .. ., ., .. .. .. • .. • .. • • • .. • • • • - .,.. TABLE VII-7 -ANNUAL ENERGY DEMAND LARSEN BAY - Directll f'''' Electrical Heatin g 2 / Total Year Demand Demand -Demand . -------------1000 kWh ------------- .-1980 372 1400 1772 1985 525 1870 2395 1990 580 2340 2920 2000 707 3180 3887 2001 723 3250 3973 ..... - - - 1./ From Table VII-3 . ..... ~/ From Table VII-5. - NBISF-426-9523-7-7 - TAlIL~; VII-8 MONTHLY ENERGY DEMAND LARSEN BAY 1980 985 1990 2000 2001 Percentagel/ Direct Direct Direct Direct Direct Month of Annual ElectriC~} Heat / Total ElectriC~} Heat Total Electr\c~} Heat Total ElectriC~} Heat Total ElectriC~} Heat Total ~ ~ _ ~ 1. Demand Demand _ Demand 1.1 Demand Demand _ Demand 1.1 Demand Demand _ ~ 1.1 ~ Demand _ Demand 1.1 Demand -----------------------------------------------------------------1 ~kWh ---------------------------------------------------------------- January 9.4 February 8.4 March 12.4 April 8.7 May 8.3 June 3.5 July 5.B August 7.5 September 9.2 October 7.9 Novembe r 8.7 December 10.2 Totals 100.0 Jj From Table VII-4. ~/ From Table VlI-3. 1./ From Table VII-6. NBISF-426-9523-7-8 I • I 1 I • 35 31 46 33 31 13 22 28 34 29 32 38 372 • • 153 192 153 113 106 64 36 42 66 116 143 ~ 1400 • 1 188 223 199 146 137 77 58 70 100 145 175 254 1772 , I 49 44 65 46 44 18 31 39 48 41 46 54 525 I • 204 256 204 151 142 86 49 56 88 155 191 288 1870 I I 253 300 269 197 186 104 80 95 136 196 237 ~ 2395 , . 55 49 72 50 48 20 34 44 53 46 50 59 580 , 1 255 321 255 189 178 108 61 70 110 194 239 360 2340 I • 310 370 327 239 226 128 95 114 163 240 289 419 2920 , , 66 59 88 61 59 25 41 53 65 56 62 72 707 I I 347 436 347 257 242 146 83 95 149 264 324 490 3180 I • 413 495 435 318 301 171 124 148 214 320 386 562 3887 , , 68 61 90 63 60 25 42 54 66 57 63 74 723 , I 354 445 354 263 247 149 84 98 153 270 332 501 3250 , I I I 422 506 444 326 307 174 126 152 219 321 395 575 3973 I • I i Month I I TABLE VII-9A 1980 ENERGY GENERATION, DEMAND, AND USAGE LARSEN BAY Directl! Electrical Hydr~ Direct Use Remaining Heat!! Hydro Used l Demand Energy Hydro Energy Hydro Energy Demand For Heat ------------------------------------1000 kWh--------------------------- January February March April May June July August September October November December TOTAL 35 31 46 33 31 13 22 28 34 29 32 38 372 ~/ From Table VII-8 o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o o 153 192 153 113 106 64 36 42 66 116 143 216 1,400 o o o o o o o o o o o o o ~/ The proposed hydroelectric project will not go on-line until late 1984 or early 1985. For the projections, an on-line date of January 1985 has been assumed. NBISF-426-9523-7-9A i TABLE VII-9B 1985 ENERGY GENERATION, DEMAND, AND USAGE LARSEN BAY Direcd/ HYdr(}:./ Us~ Hea t.!./ Elect rical Direct Remaining Hydro Used Month Demand Energ~ H~dro Energ~ H~dro Energ~ Demand For Heat " ------------------------------------1000 kWh------------------------- January 49 February 44 March 65 April 46 May 44 June 18 July 31 August 39 September 48 October 41 November 46 December 54 TOTAL 525 1./ From Table VII-8. ~/ From Table VI-3. 57 48' 34 70 171 170 68 76 131 121 90 54 1,090 49 8 204 44 4 256 34 0 204 46 24 151 44 127 142 18 152 86 31 37 49, 39 37 56 48 83 88 41 80 155 46 44 191 54 0 288 494 596 1,870 ~/ Hydro energy that will be used to meet demand currently met by diesel generation. NBISF-426-9523-7-9B 8 4 0 24 127 86 37 37 83 80 44 0 530 I. I I I. f I I. f I I. I. f. •• " " " 'I " , I ,. I I I I Month January February March April May June July August September October November December TOTAL 1/ From ~ From TABLE VII-9C 1990 ENERGY GENERATION, DEMAND, AND USAGE LARSEN BAY I I Direct JJ Electrical Hydr~/ Direct Us~/ Remaining Hea~/ Hydro Used Demand Energy Hydro Energy Hydro Energy Demand For Heat ------------------------------------1000 kWh------------------------- 55 57 55 2 255 2 49 48 48 0 321 0 72 34 34 0 255 0 50 70 50 20 189 20 48 171 48 123 178 123 20 170 20 150 108 108 34 68 34 34 61 34 44 76 44 32 70 32 53 131 53 78 110 78 46 121 46 75 194 75 50 90 50 40 239 40 59 54 54 0 360 0 580 1,090 536 554 2,340 512 Table VII-8. Table VI-3. 3/ Hydro energy that will be used to meet energy demand currently met by diesel generation. NBISF-426-9523-7-9C I i Month January February March April May June July August September October November December TOTAL Jj From TABLE VII-9D 2001 ENERGY GENERATION, DEMAND, AND USAGE LARSEN BAY DirectJ} Electrical Hydro~/ Direct Use~/ Remaining He a t.l/ Hydro Used Demand Energy Hydro Energy Hydro Energy Demand For Heat ------------------------------------1000 kWh------------------------ 68 57 57 0 354 0 61 48 48 0 445 0 90 34 34 0 354 0 63 70 63 7 263 7 60 171 60 111 247 111 25 170 25 145 149 145 42 68 42 26 84 26 54 76 54 22 98 22 66 131 66 65 153 65 57 121 57 64 270 64 63 90 63 27 332 27 74 54 54 0 501 0 -- 723 1,090 623 467 3,250 467 Table VII-8. 2/ .-... See Table VI-3 . 1/ Hydro energy that will be used to meet electrical demand currently met by diesel generation. NBISF-426-9523-7-9D I I f I I I I I ,. '1 I I 'I ,. '1 ,. J' " 'I •• •• I I • I I I - .... .... '!lfjIII " ... .... ," .. y" .... .... .w. .... .... .... YEAR TABLE VII-10 ENERGY DEMAND, GENERATION, AND USAGE ANNUAL SUMMARY LARSEN BAY Total Demand Met Required Supplement Demand by Hydro Diesel Generat~on (1000 kWh) 1.1 (1000 kWh) 2/ (1000 kWh) 1... -- 1980 372 0 372 1981 403 0 403 1982 433 0 433 1983 464 0 464 1984 494 0 494 1985 525 494 31 1986 536 502 34 1987 547 511 36 1988 558 519 39 1989 569 528 41 1990 580 536 44 1991 593 544 49 1992 605 552 53 1993 618 560 58 1994 631 568 63 1995 644 576 68 1996 656 583 73 1997 669 591 78 1998 682 599 83 1999 694 607 87 2000 707 615 92 2001-34 723 623 100 3/ From Table VII-3. Intermediate values not shown on VII-3 obtained through interpolation . From Tables VII-9A through VII-9D. Intermediate values not shown on those tables obtianed through interpolation. Difference between total demand and demand met by hydro . NBISF-426-9523-7-10 TABLE VII-11 WIND ENERGY EQUIPMENT DATA LARSEN BAY 10 kW Machine Tower Height (ft) 60 Efficiency (%) 20 Mean Power Output (kW) JJ 3.75 Availability (%) .Y Annual Usable Energy Capital Cost ($) 1/ Mean Power Output 90 Generation (kWh) 1.1 27,900 34,000 = (Watts/Meters 2 ) X (0.7854) X (Diameter 2 ) X (efficiency)/1000 25 kW Machine 60 20 7.66 90 60,400 50,000 1./ The availabili ty is the time that the uni t can actually operate and is limited by breakdowns, maintenance, and repair. 3/ -Energy = Mean Power Output X Availability. NBISF-426-9523-7-11 • ---• .. .. • • II • .. • .. • .. • .. • .. • .. • .. .. .. • .. .. .. .. .. .. .. • .. • ... .... ',"j! .... .... ... .... ,.., YEAR - 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001- 2034 TABLE VII-12 WIND ENERGY USAGE LARSEN BAY Peak System Installed Wind Demand 1./ Ca p acit 2/ (kW) (kW) - 148 0 154 30 160 30 166 30 168 30 169 30 171 30 172 30 174 30 175 40 175 40 176 40 176 40 177 40 178 40 178 40 179 40 179 40 180 40 183 40 Usable Wind Generatio~/ (MWh) - 0 84 84 84 84 84 84 84 84 112 112 112 112 112 112 112 112 112 112 112 lJ From Table VII-3. Intermediate values obtained by interpolation. ~/ 10 kW generators. The maximum penetration of asynchronous wind generators into the system is 20%; therefore, not more than 20% of the total peak demand can be met by wind at any time . ~/ From Stone and Webster Report . NBISF-426-9523-7-12 .... .... "' .. .... - iii. ililil .... - .... .... SECTION VIII PROJECT COSTS A. GENERAL The basic assumptions and methodology used to analyze the total project cost of the Larsen Bay Hydroelectric Project and a summarized cost estimate are presented in this section. A more detailed breakdown of the cost estimate methodology is contained in Appendix D, Detailed Cost Estimate. The appendix con tains the backup data, incl ud ing the proj ec t construction schedule and manpower projection. B. COST ESTIMATING BASIS Several alternative methods of preparing cost estimates were considered. The heavy construction estimating method was determined to be more realistic in this case because of the nature and location of the project. The approach taken to prepare the construction cost estimate was to determine the cost of the required permanent materials and equipment, construction equipment, and labor. Due to the location of the project site, it was determined that all material and equipment would be transported by barge. For the purposes of this estimate, the material prices at Seattle, Washington, were determined. Shipping costs by barge from Seattle to Larsen Bay were used. Material prices were based on estimating quotes by various manufacturers; commercial harge transportation companies, based at Seattle, provided shipping rate quotations for the appropriate commodity classifications. The skilled labor force was assumed to be brought in by the contractor . Current wages, based on union scale, incl uding NBI-411-9523-VIII VlII-l benefi ts and premium rates for overtime were used. The con- struction personnel will be housed in a construction camp set up specifically for this project. Commercial firms that pro- vide these services in Alaska were contacted for quotes on the cost of this service. The costs used are based on a cost per person-day. They are January 1982 pr ices t ha t include set up and demobilization. Alaskan contractors were contacted for construction equip- ment costs, which are current costs based on ownership, opera- tion, and main tenance. Th is estimate al so assumes that the equipment will be barged in from Seattle. As support to the project, commercial air charter fi rms provided current costs for various sized airplanes suitable for transporting personnel and supplies. A construction schedule was prepared to allocate manpower, material, and equipment costs to each major construction cate- gory. Allowances were made for associated miscellaneous acti v i ties requi red for completion of each item. The d irec t construction cost was determined from the various costs men- tioned above. Along with the various backup information, these costs are presented in the Summary of Costs, Table D-6 of Appendix D. C. BASE CASE PLAN Detailed costs were not estimated for the base case plan because that degree of refinement was not necessary. Costs of major items are presented in Section IX, Economic Analysis. D. RECOMMENDED PROJECT COSTS A rigorous method of cost estimating, known as the heavy- construction estimating method, was employed to define all NBI-411-9523-VIII VIII-2 • - • .. • - • • • • .. .. .. • • • • • • • • .. • -.. .. .. • • .. .. • • • • • • • iIiIl ... ..... ..... - .. '" .... to. ..... .... " ... project tasks and then determine the time, materials, quanti- ties, equipment, and skilled personnel required for each task. Using up-to-date Alaskan data for skilled craft wages, equipment ownership and use rates, and material and machinery costs FOB Seattle, the major direct costs for the project -- project mobilization and transportation of materials, equipment and labor, permanent material, and construction camp costs -- were determined . The remote nature of the site will require that construc- t ion mater ial sand equi pmen t be barged from Seattle at the outset and be returned to Seattle by the same means after project completion. Barge costs are based on weight and type of c ommod i ty. Personnel and suppl ies wi 11 be tr ansported by air. It was assumed that the crew will be housed in a catered construct ion camp for the duration of the project. Camp costs were based on a fixed unit cost per man-day of accommodation. The camp will be large enough to accommodate necessary fluctua- tions in the size of the work force . Subcontracted items included in the estimate are for const ruc tion of the tr ansmission 1 ine, mov ing the turbine/generator assembly into place in the powerhouse, and erection of the prefabricated powerhouse superstructure. A 15 percen t con t ingency fac tor was appl ied to d irec t construct ion costs, including the subcontracts, except for the transmission line subcontract, which includes a 10 percent contingency. A 10 percent markup by the prime contractor for handling and overhead was applied to the transmission line subcontract. The prime contractor's profit was assumed to be 15 percent and was applied to all construction costs except the transmission line subcontract. Engineers' fees for surveying, right-of-way, geolo~y, design, and construction management were included . The legal and administrative costs borne by APA were set at three percent of the direct plus indirect costs . NBI-411-9523-VIII VII 1-3 Total capital cost of the Larsen Bay Hydroelectric Project is estimated to be $2,821,400 at January 1982 prices. Prices for the major components of the construction work and the indirect costs are presented in Table VIII-I. NBI-411-9523-VIII VI I 1-4 • .. • .. • -• .. • • • .. • • .. .. • .. • • .. .. • .. • .. • .. .. .. • • • .. • • .. • ~.~ TABLE VI II-1 >"",,~ LARSEN BAY CONSTRUCTION COST .... Unit Item Quantit~ Unit Price Amount .... Mobilizaton and Demobilization LS $321,600 Diversion Dam '.,~~ Steel Structures 1,100 LB 3.98 4,380 Concrete 10 CY 1113 11,130 Reinforcement 1,150 LB 1. 73 1,980 ... $ 17,490 Intake Offtake Structure 3,500 LB 3.98 13,930 ..... Sediment Structure 8,000 LB 3.98 31,830 Concrete 10 CY 1113 11,130 Reinforcement 1,150 LB 1. 73 1,980 ",\!!II-$ 58,870 Penstock Steel 27 inch dia. 1,425 LF 121 171,840 Fiberglass 27 inch ~ dia. 1,275 LF 76 96,800 Concrete 54 CY 1312 70,850 Excavation 3,030 CY 17 52,270 Backfill 2,730 CY 9 25,120 $416,880 Powerhouse Prefab Building LS 49,650 Turbine and Generator LS 467,670 Auxiliary Systems LS 123,440 idi. Concrete 111 CY 1113 123,690 Reinforcing Steel 11,370 LB 1. 72 19,610 $784,060 .... Access Road Excavation and Backfill 600 CY 35 20,720 Gravel fill 630 CY 25 15,940 Culvert 50 LF 70 3,500 Excavation, Rock 4,671 CY 54 254,210 $294,370 .. '" 'oM NBI-411-9523-8-1 Transmission Line (Subcontract) Contingencies -15% TABLE VlII-1 (Concluded) (Excluding Subcontract Portion of Transmission Line) Contract Cost Engineering Right-of-Way and Geology Design Construction Management Owner's Legal and Administrative TOTAL PROJECT COST * January 1982. NBI-411-9523-8-1 Amount $ 208,980 286 z950 $2,389,200 $ 50,000 175,000 125,000 82 z20Q $2,821,400* • • • - • .. • ... • • • • .. .. II' • • • • .. -.. • • • ... • • ., .. • .. • • • .. II .. ..... ..... ... .... .... ".l!iilil "'. SECTION IX ECONOMIC ANALYSIS A. GENERAL The economic parameters and methodology used to analyze the economic feasibility of the Larsen Bay Power Project and the resul ts of the analysis are presented in this section. The methodology and criteria used for this analysis are in accord- ance with the standards set forth by APA. The present worth of the total costs of the base case as developed in Section VII is compared to the present worth of the total costs of the proposed hydroelectric project in order to determine the more advantageous scheme for development. Based on this analysis, the proposed hydroelectric project is the more favorable alternative and it appears to be feasible. B. PROJECT ANALYSIS PARAMETERS The assumptions that form the basis for this analysis are founded to as great an extent as possible on the APA standard criteria. Wherever necessary, additional assumptions were based on the best available information and on experience • The data previously developed in Section VII, Project Energy Planning, and Section VIII, Project Costs, are exten- sively utilized in this analysis. The planning period and the economic evaluation period both begin with January 1982. The hydroelectric project is assumed to be on-line by January 1985, and the analysis extends 50 years beyond that time. The last year of the analysis is 2034 and the length of the evaluation period is 53 years. The NBI-388-9523-IX IX-1 planning period for meeting future demands assumes a leveling of growth in 20 years, and it includes the year 2001. For purposes of this analysis, no inflation was assumed. The values of diesel fuel and lubricating oil were escalated at 2.6 percent annually to account for the escalation of oil prices at a rate greater than inflation. The values were escalated for the duration of the planning period, wi th the last escalation occurring in the year 2001. The costs were held constant at the 2001 value for the remainder of the period of economic evaluation through 2034. All annual cash flows were discounted to January 1982 at three percent interest. The interest rate for all amortization and sinking funds was assumed to be three percent. This and the above assump- tions are in accordance with the APA criteria. The economic life of the hydroelectric project was assumed to be 50 years. The economic project life for diesels was assumed to be 15 years for the engines and 30 years for the structure for the base case and 30 years for both the engines and structure for the hydroelectric al terna ti ve; the diesels were given a longer life for the hydroelectric al ternative because they would operate significantly less often than they would for the base case. The diesel engine life for the base case was reduced to 15 years from the 20 year period that is APA standard criteria because the machines that would be installed here would be small, high speed machines that would wear out faster than large uni ts. The installation proposed for Larsen Bay would use diesel engines that operate at 1800 rpm, as apposed to somewhat larger machines common at similar installations that operate at 1200 rpm. The 15 year economic life is the standard criteria used by the Rural Electrification Agency. NBI-388-9523-IX IX-2 • - • - • -.. • • .. • -• • II • • .. • .. • • • -• .. • -• • .. • .. • • • • ill. .... ..... ... ... .... ..... .... .... .... .... .... Operation and maintenance costs were assigned to the year during which they would occur. Capital costs were assigned to the year in which they would occur. They were assumed to be equal to the total investment cost because the construction periods for all items included in the analysis were less than one year. struction was included. The first No interest during con- amortization payment was shown in the year following the capital cost . Amortization costs, operation and maintenance costs, and benefits were assumed to occur at the end of the year and were shown in the year that they actually occurred . Replacement costs were handled by the use of a sinking fund. Replacement sinking funds were assumed to occur in per- petuity. All costs that were common to both plans, such as local distribution costs, were excluded. It will be necessary to bui ld a distribution system for either al terna t i ve. The cost of installing the transmission system would probably be about $80,000 plus $1500 per residential service and $5000 per commercial service • The effects of installing waste heat recovery were con- sidered separately and applied as a reduction in cost where appropriate. The benefit for space heating for the hydroelec- tric alternative case also was treated separately . C. BASE CASE ECONOMIC ANALYSIS The base case plan was originally formulated as diesel generation supplemented by waste heat recovery. This plan was modified to include wind generation. The original base case NBI-388-9523-IX IX-3 • • • analysis is presented below, and it is followed by the wind - generation analysis. 1. Original Plan The base case plan was analyzed to determine the present worth of the total cost of the base case plan over the entire period of analysis. The cost of the base case plan would be the sum of the costs of building and replacing the diesel gen- eration system, insurance, operation and maintenance, lubrica- tion oil, and fuel oil. These costs were all assigned to the year of their occurrence, and the total annual cost of the existing system was calculated for each year of the period of economic evaluation. These annual costs were then discounted at three percent interest to January 1982. They were then summed to find the total present worth of the base case alter- native. The costs of replacing and expanding the plant were assumed to be the cost of replacing the diesel engines every 15 years at a cost of $150,000 and replacing the entire plant every 30 years at a cost of $400,000. These costs are consistent with the current market. The cost of insuring the power plant was assumed to be $0.83 per $100 of replacement value. This rate represents current insurance rates for Alaska. The plant was assumed to have a replacement value of $400,000. The costs of operation and maintenance reflect experience and they were assumed to be the sum of the maintenance cost, calculated as $17 per megawatt-hour of energy produced, and the cost of an operator, which was taken as $60,000 per year. The total cost of lubrication oil was calculated from the unit cost of lubrication oil and the amount of lubrication oil NBI-388-9523-IX IX-4 ---• • • • • • • • • • • • • .. • • • • ---• .. - • • • • • • ., .... - ..... .... ..... , ... required. The lubrication oil rate of use was assumed to be 0.60 gallons per megawatt-hour and the cost of lubrication oil was assumed to be $3.95 per gallon for January 1982. The costs of operation and maintenance are based on experience with similar projects in Alaska. The cost of lubrication oil was also escalated at 2.6 percent for the duration of the planning period to be consistent wi th treatment of all petroleum pro- ducts. The total cost of fuel oil was calculated from the cost per gallon of fuel oil and the anticipated rate of fuel oil con- sumption. The average energy value of fuel oil was taken as 138,000 Btu/gallon and the average overall efficiency of the diesel genera tors was assumed to be 22 percent; using these criteria, one gallon of oil will produce 9.0 kilowatt-hours of electrici ty. The fuel oil cost for King Cove was established at $1.78 per gallon for January 1982 and escalated according to the previously mentioned criteria for real price changes. The annual costs over the project economic study period of the base case diesel generation for operations and maintenance, lubrication oil, and fuel oil, and replacement are presented in Tables IX-1, IX-2, IX-3, and IX-4, respectively, and combined in Table IX-5 to show the annual cost for the base case for each year of economic evaluation. These annual costs were dis- counted to January 1982 at three percent interest . After the annual cost of the base case plan was calculated, the savings possible from waste heat recovery were estimated. The total amount of heat available annually for recovery would be approximately equivalent in heat output to the amount of electricity generated annually by the plant. Waste heat recovery at Larsen Bay would be from the cooling water jackets and from the oil cooling system. Waste heat recovery from the exhaust would not be practical at this site. Al though waste heat recovery from the diesel cooling systems is highly NBI-388-9523-IX IX-5 efficient, only about 60 percent of the total waste heat avail- able would have an end use in 1982 as marketable heat because of heat generated during the summer when it is not needed for institutional users such as the school. The increase in total generation and total demand over the planning period was assumed to result in an annual growth rate for the amount of usable waste heat of about 1.5 percent. The amount of waste heat that would be usable, and the growth rate for usable waste • • • --- • • • • heat, are based on experience with similar projects in _ Alaska . Data on installations of this type are not avai lable and projections of usable waste heat are difficult to quantify; however, the projections presented herein are probably conserv- ative. The costs associated with waste heat recovery are the cost of installation and the cost of operation and maintenance. The -• • • .. • installa t ion cost includes the cost of the equipment in the - powerhouse, the cost of insulated, buried pipes from the power- house to the point of use, and the cost of installing radiators at the points of use. The equipment used for waste heat recovery from the water jackets and cooling oil do not have any moving parts and should last for the entire period of economic evaluation. The only required replacement costs would occur when the diesel power plants are replaced; at that time, it • • .. • • • would be necessary to replace the heat recovery equipment • located in the powerhouse. The heat would be available for use _ up to 2000 feet from the power plant. The initial cost of the waste heat recovery system would be $143,000, and the replacement cost would be about $60,000 every 15 years. The operation and maintenance of the system would be very minimal and probably would not exceed $1,000 per year. Using these data, the annual waste heat recovery costs are pre- sented in Table IX-6. NBI-388-9523-IX IX-6 • • • • • • • • • • • • "'.,,' .~ .. " .. The annual savings from waste heat recovery for each year of operation were calculated as a credit for the oil displaced by waste heat recovery. The result was reduced by the annual costs from Table IX-6 to yield an annual savings stream for the project, as presented in Table IX-7. The annual base case diesel generation costs and present worth of these costs are presented in Table IX-8 along with the waste heat recovery savings and the present worth of the savings. As shown, the total January 1982 present worth of the costs of the base case would be $7,532,100 and the present worth of the waste heat recovery savings would be $807,000, yielding a net present worth of the base case of $6,725,100. 2. Wind Generation Plan The possibility of installing wind-powered generators as part of the base case was also considered. Wind powered generation is discussed in detail in Section VII, including installed capacities and energy generation. (This data is from the 1982 Stone and Webster Report -See Section VII.) The benefi ts attributable to wind generation would be a reduction in the amount of fuel consumed by the diesel genera- tors, and a slight decrease in the lubrication and maintenance costs associated wi th the diesel generation. These costs are summarized in Tables IX-lA, IX-2A and IX-3A which are included behind Table IX-21. These tables are combined in Table IX-4A. The costs of installing, replacing, and maintaining the diesels would not be affected by the addition of wind generation because the full standby diesel capacity would always be required, the diesels would not have enough reduction in operation to would receive increase thei r useful lives, and the opera tor the same salary regardless of how often the diesels operate. NBI-388-9523-IX IX-7 The cost of 10 kW wind turbines and generators was assumed to be $34,000 each, installed. The operation and maintenance cost for the wind turbines was assumed as five percent of the capital cost. The wind turbines were assumed to have a useful life of 15 years. A summary of costs associated wi th this installation is presented as Table IX-5A. The credi ts for reduction in diesel generation were then adjusted by the cost of wind generation to yield the annual credit attainable from wind generation. This credit was discounted to January 1982 at three percent interest. The present worth of the wind generation credit is $330,400. This present worth is summarized in Table IX-6A. D. RECOMMENDED HYDROELECTRIC PROJECT ECONOMIC ANALYSIS • .. • .. • - • • • • • • • .. .. • The recommended hydroelectric project plan was analyzed to • determine the present worth of the total cost of the recom- mended project over the period of economic evaluation. The cost of the recommended project would include the costs of building, replacing, operating and maintaining the new hydro- electric development and the costs associated with building and replacing the diesel system, insurance, operation and mainten- ance, lubrication oil, and fuel oil for the diesel system. It would be necessary to maintain sufficient diesel capaci ty to meet projected power demands in the event of an outage of the hydroelectric plant. This has been previously discussed in Sec t ion VI I and it is ill ust rated in Table IX-14. The diesel capacity would also be required at times when the demand on the • .. • .. --• • .. system is greater than can be met by the hydroelectric genera-• tion. - The cost of the diesel supplement to hydroelectric genera- t ion was calculated in the same manner as for the base case, with the following differences: the diesels supplied only the demand that could not be met by the hydroelectric plant; the NBI-388-9523-IX IX-8 • .. • - • - • .. 'M' ... .... .... .... ,. ... diesel engines would only need to be replaced every 30 years instead of every 15 years; only one-half of the operator's salary would be assigned to the cost of the diesel, the other half being assigned to the hydroelectric project; and the diesels would not operate often enough to justify waste heat recovery. The annual costs over the project economic study period of the supplemental diesel system for the recommended hydroelec- tric project for operation and maintenance, lubrication oil and fuel oil are presented in Tables IX-9, IX-10, IX-11, respectively. Those costs are combined in Table IX-12 to present the annual cost for the supplemental diesel generation for each year of the economic evaluation . The capital cost of $2,821,400 for the hydroelectric power plant was amortized at three percent over a period of 50 years from the on-line date of the power project. The cost of the operation and maintenance was taken as 1.5 percent of the con- tract cost; this is based on U.S. Bureau of Reclamation practice. Two replacement costs were considered for the hydroelectric power plant: the cost of replacing the turbine runner after 25 years of operation, and the cost of replacing the transmission line that would tie the plant to the village distribution system every 30 years. The economic lives used for both the runner and transmission lines are based on experience and are conserva t i ve. The cost of replacing the runner was estimated as $80,000, and the cost of replacing the lines was estimated as $208,980. Sinking funds were established to meet these costs . The annual costs of the hydroelectric portion of the recom- mended hydroelectric project are presented in Table IX-13. This table includes the amortization, operation and maintenance, and NBI-388-9523-IX IX-9 replacement costs. These costs are then combined with the annual costs for the supplemental diesel system from Table IX- 12 and presented as the combined diesel and hydroelectric costs in Table IX-14. The proposed hydroelectric power plant would also generate power in excess of the village's direct demand during certain times of the year. The hydroelectric energy that would be available in excess of the village's direct electrical demand could be used for space heating in the village. The distribu- tion of hydroelectric generation is addressed in Chapter VII. The space heating energy available from hydroelectric gen- eration would be equivalent to one gallon of oil for every 28.3 kilowatt-hours of available electricity. This conversion factor is based on an assumed average energy value for oil of 138,000 Btu/gallon and 70 percent ef f iciency. The values for displaced energy used are from Tables VII-9A to VII-9D. The use of electricity for space heating would be controlled automatically in order to take advantage of as much excess electricity as possible. The system design and cost estimate are included as Appendix G. The Kodiak Island Authority should be informed of space heating plans. The annual savings for the hydroelectric energy used for space heating are presented in Table IX-15. This table indi- cates the annual hydroelectric energy available for the heat demand, the equivalent amount and cost of the fuel oil dis- placed, annual cost of the electric space heating, and the resulting net annual savings. The present worth of the recommended hydroelectric project cost is presented in the Table IX-16 summary as $5,941,700. This table also shows that the present worth of the fuel oil savings in using excess hydroelectric energy to meet space heating demand would be $1,006,100. NBI-388-9523-IX IX-10 • ----- • • • -• • • • • .. • • • • • lit • • • .. • • • .. • • • • • .. • • E. ECONOMIC COMPARISON OF PROJECTS The base case plan and the recommended hydroelectric proj- ect plan can be compared on the basis of the present worth of the total cost of each plan. Both plans were formulated to satisfy the same energy demand and the plan having the lower present worth of costs would be the more advantageous plan for development. In addition to the cost of diesel generation and the cost of the hydroelectric project, economic benefi ts are available from waste heat recovery, wind generation and from use of excess hydroelectric power for space heating. The actual plans as presented herein consider the waste heat recovery and wind generation as part of the base case plan, and the space heating credi t as part of the recommended hydroelectric project. For purposes of determining the relative economic merit of the projects, with emphasis on the hydroelectric project, the costs associated with the hydroelectric project can be considered as costs and the costs of the present system, that would be avoided by installation of the hydroelectric project, can be considered to be benefits. The cred i ts avai lable from waste heat recovery and wind generation were considered as reductions in the cost of the base case and the space heating credit was considered to be an increase in the cost of the base case. A summary of the present worth of the costs and benefits outlined above is presented as Table IX-17. The benefits associated wi th the project are the cost of the base case, minus the credits from waste heat recovery and wind generation, plus the space heating credit. The cost associated wi th the project is the cost of the recommended hydroelectric project, including the cost of supplemental diesel generation. NBI-388-9523-IX IX-ll Benefit/cost ratios for the project are presented as Table IX-18. The benefit/cost ratio for the base case only is 1.268. The benefit/cost ratio, considering the base case diesel costs, including waste heat recovery as a benefit, is 1.132. If the benefi t is adjusted by the wind generation credit, the benefit/cost ratio is 1.067. If the benefit is adjusted for the wind energy credit and the space heating credit, the benefit/cost ratio is 1.237. F. UNIT COSTS AND PROJECT TIMING As requested by the Alaska Power Authority, the unit energy cost of the base case and recommended hydroelectric project plans were calculated on an annual basis. These values are presented in Tables IX-19 and IX-20, and are shown graphically on Figure IX-I. The optimum timing for project development would occur when the unit costs of the diesel generation system exceeds the unit cost of the proposed hydroelectric power project. Because actual costs are important for this comparison, the space heating credi t is shown as an adjustment to the recommended hydroelectric project cost. The annual unit costs for the two schemes are shown with and without the adjustment for this credit. Inspection of Figure IX-1 reveals a number of discontinuities. These discontinuities are due to large changes in the net annual cash flow of each configuration that are caused by capital expenses or increases in generating capacity. A discontinuity showing an increase in the unit cost of energy indicates that the annual cost of a capital expenditure exceeds the annual value of the increase in generation, if any, resul ting from that cost. This type of discontinuity normally accompanies a major investment, such as installation of a hydroelectric facility or expansion of diesel NBI-388-9523-IX IX-12 • • • -• .. • • • • • .. • • • • • • -• .. • • -• • • .. • • • • • • • • • • "o,!' ..... ... ..... .1 plant capacity; this type of discontinuity would also accompany expenses associated with the power system that do not result in increased generation, such as construction of fuel storage facilities. Downward discontinuities on Figure IX-1 indicate expenditures that result from an annual increase in generation having greater value than the annual cost of the increase. This si tua t ion resul ts from the installation of conservation methods, such as waste heat recovery. The general downward sloping trend of the unit cost of the various levels of the hydroelectric project are the result of a gradual increase, over time, of the amount of hydroelectric energy that can be used. These lines indicate an advantage associated with hydroelectric projects; although the initial cost of a project of this nature is high, the variable annual costs are low. The general upward trend of the base case unit annual cost is the result of the increase in total demand for electricity and the increase in the cost of oil. For the base case plan, increasing demand must be met primarily by diesel generation, giving this plan a high variable annual cost . For the Larsen Bay Project, no cost of electricity is shown prior to 1983. This is because the village does not have an existing system. The costs of the five different levels of the project are shown as parallel lines for 1983 and 1984; the cost of both hydroelectric cases is the same but is less than the base case without space heating or wind credits because the newly installed diesels have been given a longer life than they were for the base case plan. The cost of the hydroelectric project jumps upward at the start of 1985 due to the cost of the hydroelectric project; this cost is also shown adjusted downward for the inclusion of the space heating credit. NBI-388-9523-IX IX-13 The base case alternative including the wind energy credit shows a decrease in 1991 due to increased capacity. The decrease in the cost of the base shown for 1998 is due to the fact that the sinking fund for the first interim engine replacement was only for 15 years and would be for 30 years after 1998; see Table IX-4. The decrease in the cost of all plans, shown for 2001, results from the retirement of the debt from the construction of fuel storage facilities. As shown on Figure IX-I, the base case cost would exceed the recommended hydroelectric project cost by the time the recommended hydroelectric project could be brought on line. NBI-388-9523-IX IX-14 • • • --.. • • • .. • • • • • • • -• -• .. • • • • • -• • • • • • • .. • • .... ' "", .... -. riO·" "....,fI ... ""w .. " ..... "'''' , .... ... ., TABLE IX-1 BASE CASE DIESEL OPERATION AND MAINTENANCE COSTS LARSEN BAY Annual Energy..!..! Annual Production Maintenancedi Operation.l! Cost Year (1000 kWh) ($) ($) ($) 1982 1983 464 7,900 60,000 67,900 1984 494 8,400 60,000 68,400 1985 525 8,900 60,000 68,900 1986 536 9,100 60,000 69,100 1987 547 9,300 60,000 69,300 1988 558 9,500 60,000 69,500 1989 569 9,700 60,000 69,700 1990 580 9,900 60,000 69,900 1991 593 10,100 60,000 70,100 1992 605 10,300 60,000 70,300 1993 618 10,500 60,000 70,500 1994 631 10,700 60,000 70,700 1995 644 10,900 60,000 70,900 1996 656 11,200 60,000 71,200 1997 669 11,400 60,000 71,400 1998 682 11,600 60,000 71,600 1999 694 11,800 60,000 71,800 2000 707 12,000 60,000 72,000 2001 723 12,300 60,000 72,300 2002-34 723 12,300 60,000 7 2,300 ~/ From Table VII-10. ~/ $17 per megawatt-hour. Values rounded to nearest $100. ~ $60,000 for operators salary . NBI-411-9523-IX-3 AnnuallJ Energy Production Year (1000 kWh) 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002-34 464 494 525 536 547 558 569 580 593 605 618 631 644 656 669 682 694 707 723 723 TABLE IX-2 BASE CASE DIESEL LUBRICATION OIL COSTS LARSEN BAY Lubrication~/ Oil (gallons) 278 296 315 322 328 335 341 348 356 363 371 379 386 394 401 409 416 424 434 434 Lubricatiord/ Oil Cost ($/gallon) 4.05 4.16 4.27 4.38 4.49 4.61 4.73 4.85 4.98 5.11 5.24 5.37 5.51 5.66 5.81 5.96 6.11 6.27 6.43 6.43 lJ From Table VlI-10. ~/ 0.6 gallons per megawatt-bour. 1/ Escalated at 2.6 percent annually. ~/ Values rounded to nearest $100. NBI-411-9523-IX-4 Lubrication~./ Oil Cost ($) 1,100 1,200 1,300 1,400 1,500 1,500 1,600 1,700 1,800 1,900 1,900 2,000 2,100 2,200 2,300 2,400 2,500 2,700 2,800 2,800 • • • - • ---• -• -• • • • • • • .. .. • • • • • • -• • • • • • • • • • -...... .... .... "'/'# "''at;'' ..... .... .... TABLE IX-3 BASE CASE DIESEL FUEL OIL COSTS LARSEN BAY Annual..!! Equivalent.~/ Energy Fuel Fuel Production Oil Oil Cost Oil Cost~/ Year (1000 kWh) (gallons) -) ($/gallon) ($) 1982 1983 464 51,600 1.82 93,900 1984 494 54,900 1.87 102,700 1985 525 58,300 1.92 111,900 1986 536 59,500 1.97 117,200 1987 547 60,800 2.02 122,800 1988 558 62,000 2.07 128,300 1989 569 63,200 2.12 134,000 1990 580 64,400 2.18 140,400 1991 593 65,900 2.23 147,000 1992 605 67,200 2.29 153,900 1993 618 68,700 2.35 161,400 1994 631 70,100 2.41 168,900 1995 643 71,500 2.48 177,300 1996 656 72,900 2.54 185,200 1997 669 74,300 2.61 193,900 1998 682 75,800 2.67 202,400 1999 694 77,100 2.74 211,300 2000 707 78,500 2.82 221,400 2001 723 80,300 2.89 232,100 2002-34 723 80,300 2.89 232,100 ..!! From Table VlI-10. ~/ 111.1 gallons per megawatt-hour. Based on 138,000 Btu/gallon, 3,413 Btu/kWh, and 22 percent efficiency. Values rounded to nearest 100 gallons. 1/ Values rounded to nearest $100. NBI-411-9523-IX-5 New Plantl/ Schedule of Amortization~/ Investment Year ( $) ($) 1982 400,000 1983 20,400 1984 20,400 1985 20,400 1986 20,400 1987 20,400 1988 20,400 1989 20,400 1990 20,400 1991 20,400 1992 20,400 1993 20,400 1994 20,400 1995 20,400 1996 20,400 1997 20,400 1998 20,400 1999 20,400 2000 20,400 2001 20,400 2002 20,400 TABLE IX-4 BASE CASE DIESEL SCHEDULE OF INVESTMENT LARSEN BAY Fue 1 Tank-~/ Schedule of Investment ( $) 150,000 Amortization~/ ( $) 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 10,100 Replace.~/ Engines Schedule of Investment ($) 150,000 2003-34 400,000 20,400 150,000 Jj 21 Replace entire plant every 30 years at a cost of $400,000. $400,000 amortized for 30 years at 3 percent in perpetuity. New plants in Annuall/ Sinkin~1 Fund Investment Cost ( $) $ 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 8,100 38,600 3,200 33,700 3,200 33,700 3,200 33,700 3,200 33,700 3,200 33,700 3,200 23,600 1982 and 2012. ~I 41 One-time cost for two 50,000 gallon fuel storage tanks and protective dike. $150,000 amortized for 20 years a 3 percent. • • • - • --.. • .. • • • • .. III • .. • -• • • .. • - • - • - • • ~I Interim engine replacement. Replace engines in 1997 and 2027. Engine life is 15 years instead of 20 years because they are small high speed engines. II ~I $150,000, 15 years at 3 percent, then $150,000 for 30 years at 3 percent in perpetuity. II Values rounded to nearest $100. NBI-411-9523-IX-4a .. • .. • • £ • • I " I t • i f i t .. II; II; " • , .. • TABLE IX-5 BASE CASE DIESEL COSTS LARSEN BAY Firm!/ Schedule.Y AnnuaJ21 Operation.!! Insuranc~ and Capacity of Investments Cost Maintenance Year (kW) ($) ($) ($) ($) -- 1982 300 550,000 1983 300 38,600 3,300 67,900 1984 300 38,600 3,300 68,400 1985 300 38,600 3,300 68,900 1986 300 38,600 3,300 69,100 1987 300 38,600 3,300 69,300 1988 300 38,600 3,300 69,500 1989 300 38,600 3,300 69,700 1990 300 38,600 3,300 69,900 1991 300 38,600 3,300 70,100 1992 300 38,600 3,300 70,300 1993 300 38,600 3,300 70,500 1994 300 38,600 3,300 70,700 1995 300 38,600 3,300 70,900 1996 300 38,600 3,300 71,200 1997 300 150,000 38,600 3,300 71,400 1998 300 33,700 3,300 71,600 1999 300 33,700 3,300 71,800 2000 300 33,700 3,300 72,000 2001 300 33,700 3,300 72,300 2002 300 33,700 3,300 72,300 2003-34 300 550,000 23,600 3,300 72,300 The largest unit is omitted when calculating firm capacity. From Table IX-4. i t 1 .. , .. Lubr icat ion..i/ Oil ($) 1,100 1,200 1,300 1,400 1,500 1,500 1,600 1,700 1,800 1,900 1,900 2,000 2,100 2,200 2,300 2,400 2,500 2,700 2,800 2,800 2,800 1/ 2/ 3/ 4/ 5/ 6/ Replacement cost is $400,000. Insurance cost is $0.83 per $100 replacement value. Table IX-1. Table IX-2. Table IX-3. NBI-411-9523-IX-2 l t FueI§l Annual Oil Cost ($) ($) 93,900 204,800 102,700 214,200 111,900 224,000 117,200 229,600 122,800 235,500 128,300 241,200 134,000 247,200 140,400 253,900 147,000 260,800 153,900 268,000 161,400 275,700 168,900 283,500 177,300 292,200 185,200 300,500 193,900 309,500 202,400 313,400 211,300 322,600 221,400 333,100 232,100 344,200 232,100 344,200 232,100 334,100 Year Schedule of Capital Investment ($) 1982 143,000 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001-34 TABLE IX-6 BASE CASE WASTE HEAT RECOVERY ANNUAL COSTS LARSEN BAY Schedule o~1 Replacement Sinkin~ Amortizationll Investment Fund ($) ($) ($) 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 60,000 120,000 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 II 52 years at 3 percent. Rounded to nearest $100. Operation and Maintenance ($) 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 Annual Cost ($) 0 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 9,600 1/ Replace diesel engines every 15 years. Replace equipment in plant in 1997, 2012, and 2027. See Table IX-4. • - • - • .. • .. • • • .. .. • .. • • .. • .. • • .. .. • --- • .. .. • • 1V Sinking fund $60,000, 15 years at 3 percent, in perpetuity. Rounded to • nearest $100. NBI-411-9523-IX-5a • • • • :...,./ "" \"-~ .. .... .... ... " "'~¥ _ .. ... " ""4 "''' .... ." ...... ..... TABLE IX-7 BASE CASE WASTE HEAT RECOVERY SAVINGS LARSEN BAY Oil"!! Oi :t..Y Annua0 Net Cred i t..~./ Annual Equivalent Cost Cost Savings Year (~allons) ($/~allon) ($) ($) ($) 1982 0 0 0 0 1983 13,200 1.82 24,000 9,600 14,400 1984 13,400 1.87 25,100 9,600 15,500 1985 13,600 1.92 26,100 9,600 16,500 1986 13,800 1.97 27,200 9,600 17,600 1987 14,000 2.02 28,300 9,600 18,700 1988 14,200 2.07 29,400 9,600 19,800 1989 14,400 2.12 30,500 9,600 20,900 1990 14,600 2.18 31,800 9,600 22,200 1991 14,900 2.23 33,200 9,600 23,600 1992 15,100 2.29 34,600 9,600 25,000 1993 15,300 2.35 36,000 9,600 26,400 1994 15,500 2.41 37,400 9,600 27,800 1995 15,800 2.48 39,200 9,600 29,600 1996 16,000 2.54 40,600 9,600 31,000 1997 16,300 2.61 42,500 9,600 32,900 1998 16,500 2.67 44,100 9,600 34,500 1999 16,700 2.74 45,800 9,600 36,200 2000 17,000 2.82 47,900 9,600 38,300 2001 17,300 2.89 50,000 9,600 40,400 2002-34 17,300 2.89 50,000 9,600 40,400 l/ Escalated at 1.5% annually. See page IX-5. 2/ Escalated at 2.6% annually. ~/ Rounded to nearest $100. ~/ Includes Replacement Sinking Fund, Amortization, and Operation and Maintenance from Table IX-6 . NBI-411-9523-IX-6 • • -TABLE IX-8 - BASE CASE • SUMMARY -LARSEN BAY -Annual..!..! AnnuaL~./ Presen0 Waste Heat..i/ Presen0 • Energy Diesel Recovery Demand Cost Worth Savings Worth .. Year (1000 kWh) ($) ($) ($) ($) • 1982 1983 464 204,800 193,000 14,400 13,600 • 1984 494 214,200 196,000 15,500 14,200 • 1985 525 224,000 199,000 16,500 14,700 1986 536 229,600 198,100 17,600 15,200 .. 1987 547 235,500 197,200 18,700 15,700 • 1988 558 241,200 196,100 19,800 16,100 1989 569 247,200 195,100 20,900 16,500 .. 1990 580 253,900 194,600 22,200 17,000 • 1991 593 260,800 194,100 23,600 17,600 1992 605 268,000 193,600 25,000 18,100 • 1993 618 275,700 193,400 26,400 18,500 • 1994 631 283,500 193,100 27,800 18,900 1995 644 292,200 193,200 29,600 19,600 .. 1996 656 300,500 192,900 31,000 19,900 .. 1997 669 309,500 192,900 32,900 20,500 1998 682 313,400 189,600 34,500 20,900 .. 1999 694 322,600 189,500 36,200 21,300 • 2000 707 333,100 190,000 38,300 21,800 2001 723 344,200 193,600 40,400 22,400 .. 2002 723 334,200 185,000 40,400 21,700 -2003-34 723 334,100 3,662,100 40,400 442,800 • TOTALS 7,532,100 807,000 • .. • • 1/ • From Table VII-10. 2/ • From Table IX-5. • 3/ January 1982. Discounted at 3%. Present worth factors accurate to four decimal places. Rounded to nearest $100. • -4/ Table IX-7. • NBI-411-9523-IX-1 • • • {,lIf/Il \1:;\' '.," "". -,..<~ "-It*' TABLE IX-9 RECOMMENDED HYDROELECTRIC PROJECT DIESEL OPERATION AND MAINTENANCE COSTS LARSEN BAY Annual.!! Energy Maintenanc~ Operation1! Annual Production Cost Year (1000 kWh) ($) ($) ($) - 1982 1983 464 7,900 60,000 67,900 1984 494 8,400 60,000 68,400 1985 31 500 30,000 30,500 1986 34 600 30,000 30,600 1987 36 600 30,000 30,600 1988 39 700 30,000 30,700 1989 41 700 30,000 30,700 1990 44 700 30,000 30,700 1991 49 800 30,000 30,800 1992 53 900 30,000 30,900 1993 58 1000 30,000 31,000 1994 63 1,100 30,000 31,100 1995 68 1,200 30,000 31,200 1996 73 1,200 30,000 31,200 1997 78 1,300 30,000 31,300 1998 83 1,400 30,000 31,400 1999 87 1,500 30,000 31,500 2000 92 1,600 30,000 31,600 2001 100 1,700 30,000 31,700 2002-34 100 1,700 30,000 31,700 ~/ Required supplemental diesel generation from Table VII-10. ~ $17 per megawatt hour. Rounded to nearest $100. ~/ One-half of operator's salary after hydro plant goes on- line in 1985. NBI-411-9523-IX-10 TABLE IX-10 RECOMMENDED HYDROELECTRIC PROJECT DIESEL LUBRICATION OIL COSTS LARSEN BAY Annual..!! Lubrication~/ Lubricatiord! Lubrication!! Energy Production Oil Oil Cost Oil Cost Year (1000 kWh) (gallons) ($/~allon) ($) 1982 1983 464 278 4.05 1,100 1984 494 296 4.16 1,200 1985 31 19 4.27 100 1986 34 20 4.38 100 1987 36 22 4.49 100 1988 39 23 4.61 100 1989 41 25 4.73 100 1990 44 26 4.85 100 1991 49 29 4.98 100 1992 53 32 5.11 200 1993 58 35 5.24 200 1994 63 38 5.37 200 1995 68 41 5.51 200 1996 73 44 5.66 200 1997 78 47 5.81 300 1998 83 50 5.96 300 1999 87 52 6.11 300 2000 92 55 6.27 300 2001 100 60 6.43 400 2002- 2034 100 60 6.43 400 l/ Required supplemental diesel generation from TableVlI-10. ~ 0.6 gallons per megawatt-hour. 1/ Escalated at 2.6 percent annually. jj Rounded to nearest $100. NBI-411-9523-IX-11 • --- • - • -• - • • • .. • • .. • -• -• • • • • • • • • .. • • • • , .. , "y" ..... 011 " ... 11 _ .. #JB,~II 'l'...<'fi d>l ..... TABLE IX-11 RECOMMENDED HYDROELECTRIC PROJECT DIESEL FUEL OIL COSTS LARSEN BAY Annual..!.! Equivalene/ Fuel Oil~/ Fuel Oil~.! Energy Production Oil Cost Cost Year (1000 kWh) (~allons) ($/~allon) ($) 1982 1983 464 51,600 1.82 93,900 1984 494 54,900 1.87 102,700 1985 31 3,400 1.92 6,500 1986 34 3,800 1.97 7,500 1987 36 4,000 2.02 8,100 1998 39 4,300 2.07 8,900 1989 41 4,600 2.12 9,800 1990 44 4,900 2.18 10,700 1991 49 5,400 2.23 12,000 1992 53 5,900 2.29 13,500 1993 58 6,400 2.35 15,000 1994 63 7,000 2.41 16,900 1995 68 7,600 2.48 18,800 1996 73 8,100 2.54 20,600 1997 78 8,700 2.61 22,700 1998 83 9,200 2.67 24,600 1999 87 9,700 2.74 26,600 2000 92 10,200 2.82 28,800 2001 100 11,100 2.89 32,100 2002- 2034 100 11,100 2.89 32,100 ~/ Required supplemental diesel generation from Table VlI-10. ~ 111.1 gallons per megawatt-hour. Rounded to nearest 100 gallons. 3/ ~/ Escalated at 2.6 percent annually. Rounded to nearest $100. NBI-411-9523-IX-12 • I I I I • TABLE IX-12 RECOMMENDED HYDROELECTRIC PROJECT DIESEL COSTS LARSEN BAY Fi rill .. !.! Schedule Of~/ Annual..!!/ ~ Operatio~/ Lubricatio~/ Fuel!....! Insurancei/~ and Annual Capacity Investment Cost Maintenance Oil Oil Cost Year (KW) ( $) ( $) ( $) ($) ($) ($) ($) 1982 300 550,000 1983 300 30,500 3,300 67,900 1,100 93,900 196,700 1984 300 30,500 3,300 68,400 1,200 102,700 206,100 1985 300 30,500 3,300 30,500 100 6,500 70,900 1986 300 30,500 3,300 30,600 100 7,500 72,000 1987 300 30,500 3,300 30,600 100 8,100 72,600 1988 300 30,500 3,300 30,700 100 8,900 73,500 1989 300 30,500 3,300 30,700 100 9,800 74,400 1990 300 30,500 3,300 30,700 100 10,700 75,300 1991 300 30,500 3,300 30,800 100 12,000 76,700 1992 300 30,500 3,300 30,900 200 13,500 78,400 1993 300 30,500 3,300 31,000 200 15,000 80,000 1994 300 30,500 6,300 31,100 200 16,900 82,000 1995 300 30,500 3,300 31,200 200 18,800 84,000 1996 300 30,500 3,300 31,200 200 20,600 85,800 1997 300 30,500 3,300 31,300 300 22,700 88,100 1998 300 30,500 3,300 31,400 300 24,600 90,100 1999 300 30,500 3,300 31,500 300 26,600 92,200 2000 300 30,500 3,300 31,600 300 28,800 94,500 2001 300 30,500 3,300 31,700 400 32,100 98,000 2002 300 30,500 3,300 31,700 400 32,100 98,000 2003 300 20,400 3,300 31,700 400 32,100 87,900 2004 300 20,400 3,300 31,700 400 32,100 87,900 2005 300 20,400 3,300 31,700 400 32,100 87,900 2006 300 20,400 3,300 31,700 400 32,100 87,900 2007 300 20,400 3,300 31,700 400 32,100 87,900 2008 300 20,400 3,300 31,700 400 32,100 87,900 2009 300 20,400 3,300 31,700 400 32,100 87,900 2010 300 20,400 3,300 31,700 400 32,100 87,900 2010 300 20,400 3,300 31,700 400 32,100 87,900 2011 300 400,000 20,400 3,300 31,700 400 32,100 87,900 2012-34 300 20,400 3,300 31,700 400 32,100 87,900 The largest unit is omitted when calculating firm capacity. 1/ 2/ 3/ 4/ 5/ 6/ 7/ 8/ Build fuel storage facility in 1982 for $150,000. Replace plant every 30 years for $400,000. Tank cost amortized over 20 years at 3 percent. Plant cost amortized over 30 years at 3 percent. Plant replacement value is $400,000. Insurance cost is $0.83 per $100 replacement value. From Table IX-9. From Table IX-10. From Table IX-II. Nearest $100. NBI-411-9523-IX-9 , . I • , I , . I • I , I • , . I I , I , I • • I I I • I • I • ., ..., ... , ., .. , ... ~ tIto~ ..... -" "",if '. .... ,,,,II .;,o,,J<l .... .... TABLE IX-13 RECOMMENDED HYDROELECTRIC PROJECT HYDROELECTRIC COSTS LARSEN BAY Capi tal.!! Operation~/ ii/ Replacementl/ Rep1acement2./ ii/ and Schedule of Sinking Cost Amortizatioo1/ 2../ Maintenance Investment Fund Year ($) ($) ($) ($) ($) 1982 0 1983 0 1984 2,821,400 0 1985 109,700 35,800 6,600 1986 109,700 35,800 6,600 1987 109,700 35,800 6,600 1988 109,700 35,800 6,600 1989 109,700 35,800 6,600 1990 109,700 35,800 6,600 1991 109,700 35,800 6,600 1992 109,700 35,800 6,600 1993 109,700 35,800 6,600 1994 109,700 35,800 6,600 1995 109,700 35,800 6,600 1996 109,700 35,800 6,600 1997 109,700 35,800 6,600 1998 109,700 35,800 6,600 1999 109,700 35,800 6,600 2000 109,700 35,800 6,600 2001 109,700 35,800 6,600 2002 109,700 35,800 6,600 2003 109,700 35,800 6,600 2004 109,700 35,800 6,600 2005 109,700 35,800 6,600 2006 109,700 35,800 6,600 2007 109,700 35,800 6,600 2008 109,700 35,800 6,600 2009 109,700 35,800 80,000 6,600 2010 109,700 35,800 6,600 2011 109,700 35,800 6,600 2012-34 109,700 35,800 208,980 6,600 1/ 2/ 3/ 4/ 11 !!..I From Table VIII-I. 50 years at 3~. 1.5~ of contract cost. Replace turbine runner in 2009; replace transmission lines in 2014. Runner fund 25 years at 3~. Transmission Lines fund 30 years at 3~. Funds are superimposed and in perpetuity. Values rounded to nearest $100. NBI-411-9523-IX-8 Annual Cost ($) 0 0 0 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 152,100 • - TABLE IX-14 • SUMMARY -RECOMMENDED PROJECT DEVELOPMENT COSTS LARSEN BAY - AnnuaL!! Annual~/ -AnnuaI1! Total -----Ge~7ration Mix-----Hydro Diesel Annual Demand Hydr= Dieseill Cost Cost Cost -Year (1000 kWh) (1000 kWh) (1000 kWh) ($) ($) ($) -1982 1983 464 0 464 0 196,700 196,700 .. 1984 494 0 494 0 206,100 206,100 .. 1985 525 494 31 152,100 70,900 223,000 1986 536 502 34 152,100 72,000 224,100 • 1987 547 511 36 152,100 72,600 224,700 .. 1988 558 519 39 152,100 73,500 225,600 1989 569 528 41 152,100 74,400 226,500 .. 1990 580 536 44 152,100 75,300 227,400 • 1991 593 544 49 152,100 76,700 228,800 1992 605 552 53 152,100 78,400 230,500 .. 1993 618 560 58 152,100 80,000 232,100 • 1994 631 568 63 152,100 82,000 234,100 1995 644 576 68 152,100 84,000 236,100 • 1996 656 583 73 152,100 85,800 237,900 .. 1997 669 591 78 152,100 88,100 240,200 1998 682 599 83 152,100 90,100 242,200 • 1999 694 607 87 152,100 92,200 244,300 -2000 707 615 92 152,100 94,500 246,600 2001 723 623 100 152,100 98,000 250,100 .. 2002 723 623 100 152,100 98,000 250,100 .. 2003 723 623 100 152,100 87,900 240,000 2004 723 623 100 152,100 87,900 240,000 .. 2005 723 623 100 152,100 87,900 240,000 -2006 723 623 100 152,100 87,900 240,000 2004 723 623 100 152,100 87,900 240,000 • 2008 723 623 100 152,100 87,900 240,000 .. 2009 723 623 100 152,100 87,900 240,000 2010 723 623 100 152,100 87,900 240,000 .. 2011 723 623 100 152,100 87,900 240,000 .. 2012-34 723 623 100 152,100 87,900 240,000 .. • • 1/ From Tables VII-9A through VII-9D. Intermediate values by interpolation. • 2/ 3/ From Tables VII-9A through VII-9D. Intermediate values by interpolation. 4/ Difference between annual demand and demand met by hydro. .. From Table IX-13. ~/ From Table IX-12. .. NBI-411-9523-IX-13 • • • • ..... .... ""'. "~'t!iIII "'W idilill' ..... """ -k"" iii_ ~'1;. "oj .. "" TABLE IX-15 RECOMMENDED HYDROELECTRIC PROJECT SPACE HEATING CREDIT LARSEN BAY Oil~/ Oi I Uni 0./ Schedule of~./ Net Energy-!/ Annual Equivalent Cost Creditil Investment Amortizato~/ Savings Year (1000 kWh) (gal) ($/ gal) ($) ($) ($) ($) 1982 0 0 1.78 0 1983 0 0 1.82 0 1984 0 0 1.87 0 $40,000 1985 530 18,700 1.92 35,900 1,600 34,300 1986 526 18,600 1.97 36,600 1,600 35,000 1987 523 18,500 2.02 37,400 1,600 35,800 1988 519 18,300 2.07 37,900 1,600 36,300 1989 516 18,200 2.12 38,600 1,600 37,000 1990 512 18,100 2.18 39,500 1,600 37,900 1991 508 17,900 2.23 39,900 1,600 38,300 1992 504 17,800 2.29 40,800 1,600 39,200 1993 500 17,700 2.35 41,600 1,600 40,000 1994 496 17,500 2.41 42,200 1,600 40,600 1995 492 17,400 2.48 43,200 1,600 41,600 1996 487 17,200 2.54 43,700 1,600 42,100 1997 483 17 , 100 2.61 44,600 1,600 43,000 1998 479 16,900 2.67 45,100 1,600 43,500 1999 475 16,800 2.74 46,000 1,600 44,400 2000 471 16,600 2.82 46,800 1,600 45,200 2001-34 467 16,500 2.89 47,700 1,600 46,100 1/ 2/ 3/ 4/ 5/ 6/ From Tables VII-9A through VII-9D. 138,000 BTU/gal, 3,413 BTU/kWh, 70% gallons. Escalated at 2.6% annually. Rounded to nearest $100 . See Appendix G for cost estimate. 50 years at 3%. Intermediate values by interpolation. efficiency. Rounded to nearest 100 -NBI-411-9523-IX_14 .. 1f TABLE IX-16 RECOMMENDED HYDROELECTRIC PROJECT SUMMARY LARSEN BAY Project..!..! Present Worth.~/ Space~/ Present Wort~/ Heating Cost Project Cost Credit Heating Credit Year ($) ($) ($) ($) 1982 0 0 0 0 1983 196,700 185,400 0 0 1984 206,100 186,600 0 0 1985 223,000 198,100 34,300 30,500 1986 224,100 193,300 35,000 30,200 1987 224,700 188,200 35,800 30,000 1988 225,600 183,400 36,300 29,600 1989 226,500 178,800 37,000 29,200 1990 227,400 174,300 37,900 29,000 1991 228,800 170,300 38,300 28,500 1992 230,500 166,500 39,200 28,300 1993 232,100 162,800 40,000 28,100 1994 234,100 159,400 40,600 27,600 1995 236,100 156,100 41,600 27,500 1996 237,900 152,700 42,100 27,000 1997 240,200 149,700 43,000 26,800 1998 242,200 146,500 43,500 26,300 1999 244,300 143,500 44,400 26,100 2000 246,600 140,600 45,200 25,800 2001 250,100 138,500 46,100 25,500 2002 250,100 134,400 46,100 24,800 2003-34 240,000 2,630,600 46,100 505,300 TOTALS 5,941,700 1,006,100 From Table IX-14. 1/ 2/ Discounted to January 1982 at 3% interest. Present worth factors accurate to four decimal places. Values rounded to nearest $100. 3/ From Table IX-15. NBI-411-9523-IX-15 • --- • ---. • • • • • • • • • .. • .. • lit • • • • • • • .. • • .. .. • lit • • ... , , ... "'" ..... M",;f ..... ';\kIW .... ,~" '''''' •• .. II .... . ~ .. .... ... A. B. 1J 2/ 11 TABLE IX-17 PRESENT WORTH SUMMARY LARSEN BAY BASE CASE (Benefits) Gross Present Worth Costs .l! Waste Heat Recovery Credit .l! Subtotal Wind Credit Y Subtotal Space Heating Credit 11 Total RECOMMENDED HYDROELECTRIC PROJECT (Costs) Gross Present Worth Costs 11 From Table IX-8. From Table IX-6A . From Table IX-16. NBI-411-9523-IX-18 7,532,100 807,000 6,725,100 382,600 6,342,500 1,006,100 7,348,600 5,941,700 A. BASE CASE B. BASE CASE ONLY B/C = TABLE IX-18 BENEFIT/COST RATIOS LARSEN BAY 7,532,100 5,941,700 = 1.268 INCLUDING WASTE HEAT RECOVERY B/C = 6,725,100 _ 1.132 5,941,700 - CREDIT • .. • • ---- • • • • • .. • • C. BASE CASE INCLUDING WASTE HEAT RECOVERY CREDIT AND WIND • CREDIT .. • B/C = 6,342,500 = 5,941,700 1.067 • • D. BASE CASE INCLUDING WASTE HEAT RECOVERY CREDIT, WIND .. CREDIT, AND SPACE HEATING CREDIT. B/C 7,348,600 = = 5,941,700 1. 237 NBI-411-9523-IX-19 • • • .. • • • .. • • .. / .. .. .. • • i Energy Year Production 1 / (1000 kWh) - 1982 1983 464 1984 494 1985 525 1986 536 1987 547 1988 558 1989 569 1990 580 1991 593 1992 605 1993 618 1994 631 1995 644 1996 656 1997 669 1998 682 1999 694 2000 707 2001-34 723 1.1 From Table VII-IO. y From Table IX-8. r , Base Case Annual Cos~ ($) 204,800 214,200 224,000 229,600 235,500 241,200 247,200 253,900 260,800 268,000 275,700 283,500 292,200 300,500 309,500 313,400 322,600 333,100 343,100 Unit En§~gy Cos~ (Mills/kWh) 441 434 427 428 431 432 434 438 440 443 446 449 454 458 463 460 465 471 462 .Y Base case without waste heat recovery credit. jj From Table IX-8. ~ Base case including waste heat recovery. 2.! From Table IX-6A. 1.1 Base case including waste heat recovery credit SFNBI-426-9523-IX-20 • • t. TABLE IX-19 ANNUAL UNIT COSTS BASE CASE LARSEN BAY Waste Heat Annu~} Credi0.J Cos~ ($) ($) 14,400 190,400 15,500 198,700 16,500 207,500 17,600 212,000 18,700 216,800 19,800 221,400 20,900 226,300 22,200 231,700 23,600 237,200 25,000 243,000 26,400 249,300 27,800 255,700 29,600 262,600 31,000 269,500 32,900 276,600 34,500 278,900 36,200 286,400 38,300 294,800 40,400 293,700 Unit Ener~y Cos~ (Mills/kWh) 410 402 395 396 396 397 398 399 400 402 403 405 408 411 413 409 413 417 406 and wind generation credit. ~ . . Wind Generat~?n Credi~ AnnuH Cos~ Enern Cos~ ($) ($) (Mills/kWh) 4,900 185,500 400 5,400 193,300 391 5,900 201,600 384 6,300 205,700 384 6,800 210,000 384 7,300 214,100 384 7,700 218,600 384 8,300 223,400 385 11,700 225,500 380 12,400 230,600 381 13,200 236,100 382 14 ,000 241,700 383 14,900 247,700 385 15,600 253,900 387 16,500 260,100 389 17,200 261,700 384 18,100 268,300 387 19,100 275,700 390 19,900 273,800 379 • - • TABLE IX-20 • ANNUAL UNIT COSTS • RECOMMENDED HYDROELECTRIC PROJECT - LARSEN BAY • Hydro • Project Unit Space Unit • Energy Annual Energy Heating Annual Energy Year Productionl! Cost Cost Credit Cost Cost ... (1000 kWh) ( $) (Mills/kWh) . ( $) ( $) (Mills/kWh) • 1982 .. 1983 464 196,100 423 0 196,100 423 1984 494 206,100 417 0 206,100 417 • 1985 525 223,000 425 34,300 188,700 359 • 1986 536 224,100 418 35,000 189,100 353 1987 547 224,700 411 35,800 188,900 345 .. 1988 558 225,600 404 36,300 189,300 339 .. 1989 569 226,500 398 37,000 189,500 333 1990 580 227,400 392 37,900 189,500 327 • 1991 593 228,800 386 38,300 190,500 321 ., 1992 605 230,500 381 39,200 191,300 316 1993 618 232,100 376 40,000 192,100 311 • 1994 631 234,100 371 40,600 193,500 307 1995 644 236,100 367 41,600 194,500 302 • 1996 656 237,900 363 42,100 195,800 298 • 1997 669 240,200 359 43,000 197,200 295 1998 682 242,200 355 43,500 198,700 291 • 1999 694 244,300 352 44,400 199,900 288 • 2000 707 246,600 349 45,200 201,400 285 2001 723 250,100 346 46,100 204,000 282 ., 2002 723 250,100 346 46,100 204,000 282 • 2003-34 723 240,000 332 46,100 193,900 268 .. • - • • • ... • .Y From Table VII-10. ... 2/ From Table IX-14. • .. SFNBI-426-9523-IX-21 • ... .... .... ..... ..... .... .... .... .... Year 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002-34 TABLE IX-1A BASE CASE WIND ENERGY CREDIT DIESEL OPERATION AND MAINTENANCE COSTS LARSEN BAY Annual Energy..!! Production (1000 kWh) 84 84 84 84 84 84 84 84 112 112 112 112 112 112 112 112 112 112 112 112 Maintenance.Y ($) 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 Operation1! ($) o o o o o o o o o o o o o o o o o o o o ~/ From Table VII-12. Annual Cost ($) 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 ~/ $17 per megawatt-hour. Values rounded to nearest $100. ~ Salary for operator, included in base case costs. SFNBI-411-9523-IX-1A TABLE IX-2A BASE CASE WIND ENERGY CREDIT DIESEL LUBRICATION OIL COSTS LARSEN BAY Annual.lJ Lubrication~./ Lu br ica t iord! Energy Production Oil Oil Cost Year (1000 kWh) (gallons) ($!~allon) 1982 1983 84 50 4.05 1984 84 50 4.16 1985 84 50 4.27 1986 84 50 4.38 1987 84 50 4.49 1988 84 50 4.61 1989 84 50 4.73 1990 84 50 4.85 1991 112 67 4.98 1992 112 67 5.11 1993 112 67 5.24 1994 112 67 5.37 1995 112 67 5.51 1996 112 67 5.66 1997 112 67 5.81 1998 112 67 5.96 1999 112 67 6.11 2000 112 67 6.27 2001 112 67 6.43 2002-34 112 67 6.43 ~! From Table VII-12. ~! 0.6 gallons per megawatt-hour. 1! Escalated at 2.6 percent annually. ±! Values rounded to nearest $100. SFNBI-411-9523-IX-2A Lubricationi.l Oil Cost ($) 200 200 200 200 200 200 200 200 300 300 400 400 400 400 400 400 400 400 400 400 • .. -.. ---.. • - • .. • • .. .. • .. • • • .. .. .. .. .. --.. .. .. • .. .. • .. • • "", .... .... "". "",./ii! ,-1'"...1 ,..,.11 ' .... ~"1!,~ ". "" '1- 4 _ .... .... TABLE IX-3A BASE CASE DIESEL FUEL OIL COSTS WIND ENERGY CREDIT LARSEN BAY Annuall./ Energy Equivalen~ Fuel Fuel Production Oil Oil Cost Oil Cost Year (1000 kWh) (gallons) ($/gallon) ($) 1982 1983 84 9,300 1.82 16,900 1984 84 9,300 1.87 17,400 1985 84 9,300 1.92 17,900 1986 84 9,300 1.97 18,300 1987 84 9,300 2.02 18,800 1988 84 9,300 2.07 19,300 1989 84 9,300 2.12 19,700 1990 84 9,300 2.18 20,300 1991 112 12,400 2.23 27,700 1992 112 12,400 2.29 28,400 1993 112 12,400 2.35 29,100 1994 112 12,400 2.41 29,900 1995 112 12,400 2.48 30,800 1996 112 12,400 2.54 31,500 1997 112 12,400 2.61 32,400 1998 112 12,400 2.67 33,100 1999 112 12,400 2.74 34,000 2000 112 12,400 2.82 35,000 2001 112 12,400 2.89 35,800 2002-34 112 12,400 2.89 35,800 1/ 2/ From Table VII-12. 111.1 gallons per megawatt-hour. Based on 138,000 Btu/gallon, 3,413 Btu/kWh, and 22 percent efficiency. Values rounded to nearest 100 gallons. SFNBI-411-9523-IX-3A • • • -TABLE IX-4A • BASE CASE -WIND ENERGY GENERATION CREDIT LARSEN BAY SUMMARY • • InstalledlJ Operation~/ Lubr ica t iord/ FueLi./ Total • Year Capacity Maintenance Oil Oil Credit -(kW) ($) ($) ($) ($) • 1982 1983 30 1,400 200 16,900 18,500 • 1984 30 1,400 200 17,400 1985 30 1,400 200 17,900 19,000 • 19,500 1986 30 1,400 200 18,300 19,900 • 1987 30 1,400 200 18,800 1988 30 1,400 200 19,300 20,400 • 20,900 1989 30 1,400 200 19,700 21,300 • 1990 30 1,400 200 20,300 1991 40 1,900 300 27,700 21,900 • 29,900 1992 40 1,900 300 28,400 30,600 .. 1993 40 1,900 400 29,100 1994 40 1,900 400 29,900 31,400 • 32,200 1995 40 1,900 400 30,800 33,100 • 1996 40 1,900 400 31,500 33,800 1997 40 1,900 400 32,400 34,700 • 1998 40 1,900 400 33,100 35,400 • 1999 40 1,900 400 34,000 36,300 2000 40 1,900 400 35,000 37,300 • 2001 40 1,900 400 35,800 38,100 • 2002 40 1,900 400 35,800 38,100 2034 40 1,900 400 35,800 38,100 • - • • • iii .. • 1/ From Table VII-12. ~/ From Table IX-1A. 3/ From Table IX-2A. It • 4/ From Table IX-3A. • SFNBI-411-9523-IX_4A • • • "". 'OIl' ,-, , ... .. '.,. ,~"," '-"""4 "oil ' .... ... .... ' .... Year 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2005 2034 1/ 2/ 3/ 4/ TABLE IX-5A BASE CASE WIND GENERATION COSTS LARSEN BAY InstallectlJ Schedule o~ Amort iza tion .. ~/ Operator Annual Capacity Investmen~/ Maintenance~/ Cost (kW) ($) ($) ($) ($) 102,000 30 8,500 5,100 13,600 30 8,500 5,100 13,600 30 8,500 5,100 13,600 30 8,500 5,100 13,600 30 8,500 5,100 13,600 30 8,500 5,100 13,600 30 8,500 5,100 13,600 30 34,000 8,500 5,100 13,600 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 102,000 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 11,400 6,800 18,200 40 34,000 11,400 6,800 18,200 40 11,400 6,800 18,200 From Table VII-12. Replace equipment every 15 years. Build first plant in 1982 and bring on line in 1983. Expand capacity in 1990. Table 111-12. 15 years at 3% in perpetuity rounded to the nearest $100. 5% of capital cost rounded to the nearest $100. SFNBI-411-9523-IX-5A • - • • TABLE IX-6A • BASE CASE .. WIND ENERGY CREDIT LARSEN BAY • PRESENT WORTH • InstallecJ} Annual~ Annual~/ Net Annual Presenti./ • Year Capacity Credit Cost Credit Worth • (kW) ($) ($) ($) ($) • 1982 1983 30 18,500 13,600 4,900 4,600 .. 1984 30 19,000 13,600 5,400 4,900 .. 1985 30 19,500 13,600 5,900 5,200 1986 30 19,900 13,600 6,300 5,400 .. 1987 30 20,400 13,600 6,800 5,700 1988 30 20,900 13,600 7,300 5,900 .. 1989 30 21,300 13,600 7,700 6,100 .. 1990 30 21,900 13,600 8,300 6,400 1991 40 29,900 18,200 11,700 8,700 • 1992 40 30,600 18,200 12,400 9,000 .. 1993 40 31,400 18,200 13,200 9,300 1994 40 32,200 18,200 14,000 9,500 • 1995 40 33,100 18,200 14,900 9,900 .. 1996 40 33,800 18,200 15,600 10,000 1997 40 34,700 18,200 16,500 10,300 • 1998 40 35,400 18,200 17,200 10,400 .. 1999 40 36,300 18,200 18,100 10,600 2000 40 37,300 18,200 19,100 10,900 • 2001 $239,800 • 2034 40 38,100 18,200 -TOTAL $382,600 - • .. • .. • • 1/ From Table VII-12. .. 2/ From Table IX-4A. 3/ From Table IX-5A. • 4/ Discounted at 3% to January 1982. Present worth factors accurate to 4 decimal places. • • SFNBI-411-9523-IX-6A • • .... ... .... .... ..... ... Iii .. .. '" .. '" .. '" .... .M .... SECTION X ENVIRONMENTAL AND SOCIAL EFFECTS A. GENERAL An environmental study of the Larsen Bay Hydroelectric Project vicinity was conducted to survey the resources in the area, evaluate potential effects of the project, and formulate measures to avoid or ameliorate adverse effects. Two field investigations were made, relevant literature was reviewed, and representatives of the Alaska Departments of Natural Resources and of Fish and Game, the U.S. Fish and Wildlife Service, and the Kodiak National Wildlife Refuge were consul ted. Local residents were contacted through a community meeting and through discussions with individuals. The Larsen Bay Hydroelectric Project will offer a signifi- cant advantage to the local community--a central power source. It will also bring modest socioeconomic benefits. While some potential for adverse environmental and social effects exists, adequate project planning should be able to avoid these consequences • The study results indicate that most of the adverse environmental effects of the project will be minor due to the limited scope of the project activities, the inability of salmon to spawn above the old diversion dam on Humpy Creek, the abundance of alternative areas available for trapping, hunting, and general recreation, and the availability of measures to mitigate potential effects from the construction and operation of the facilities . The project access road could lead to the serious disturbance of wildlife if it opened the higher ridge country NBI-388-9523-X X-l to recreational vehicles; however, project plans call for this road to end at a point where further travel by vehicle would require road-blasting activities and the removal of large trees. If implemented, the project will make a centralized power source available to a community that now depends on individual generators. That community, however, will have to be protected against possible disturbances that could be introduced by importing a project construction work force into what is essentially a small, isolated village. Establishment of a trailer work camp is recommended to accommodate the workers. The areas considered in the study included fisheries, wild- life, vegetation, archaeological and historic sites, visual resources, recreation, air quality, and socioeconomic impacts. Land status, hydrology, and geology are addressed in Section IV, Basic Data. The detailed report on the environmen- tal studies conducted is contained in Appendix E and a summary of the study is presented in this section. B. ENVIRONMENTAL EFFECTS 1. Fisheries The Alaska Fisheries Atlas published by the Alaska Depart- ment of Fish and Game (ADF&G) lists pink salmon and Dolly Varden char as the only fish species present in Humpy Creek. Local residents confirmed this in general, but they added that some rainbow trout are present as well. Fish surveys were taken only twice on Humpy Creek in recent years. In 1977, 12,075 pinks were counted in a foot survey, and in 1981 600 pinks were counted in an aerial survey. NBI-388-9523-X X-2 • - • .. • • • • • .. • ... III .. ., .. .. II1II .. .. .. .. • .. • '" • .. .. II .. • • • .. • • .... ... , .... ... ... .... .... ... In Humpy Creek most of the spawning occurs intertidally and wi thin the firs t 100 yards above the cuI vert of the exist ing road. Only in years with large runs, do a few pink salmon get upstream as far as the old diversion dam. This dam, builtin 1923, has a 1 O-f oot fall, and it prevents f ish passage. Thus the proposed facili ties will not affect the salmon spawning. Some Dolly Varden, however, do exist above the old dam. Fish from the sea traditionally have formed a large portion of the diet of Larsen Bay residents. Subsistence harvesting of the Humpy Creek pink salmon run is still common but no figures are available on the total catch. The portion of Humpy Creek between the diversion weir and the powerhouse may be dewatered during low flows, and a major reduction in flow will occur during plant operations. These project-related effects may prevent fish from utilizing this st ream sect ion. However, on ly small numbers of Dolly Varden char were found in this section of the stream. No significant effect on water quanti ty or quali ty is anticipated downstream from the powerhouse outflow. Construction activity will cause minor increases in erosion and sedimentation during the short period of construction. These impacts can be minimized through the use of proper con- struction practices. Also, the design of the diversion weir will allow it to be collapsed temporarily should it prove necessary to flush sediment out of spawning gravels below the weir . 2. Wildlife Wildlife existing in the project area were identified by consul ting existing Ii terature and by contacts with personnel of ADF&G, the Kodiak National Wildlife Refuge, the U.S. Fish and Wildlife Service, and local residents . Bear, otter, fox, NBI-388-9523-X X-3 and weasel all commonly use the Humpy Creek drainage. Brown bear are constant visi tors in Larsen Bay during the summer, fishing tbe lower reacbes of the creek for salmon and visiting tbe creek and village dump. About 10 to 15 bears frequent the hydro project si teo Denning probably occurs on the mountain being considered for the diversion weir, but the facility is below tbe 400-foot level and most dens are probably above 700 feet. Si tka black-tailed deer are abundant in tbe Larsen Bay area. The Humpy Creek drainage supports deer all year but is probably not a major wintering area. Eigbt bald eagle nests have been recorded in the Larsen bay drainage. although No nests have been identified along Humpy Creek eagles do feed at the mouth of the creek. Rough- legged bawks probably nest in the upper project area. Lists of mammals and birds found on Kodiak Island Archipelago are presented in Appendix E. Most of the local hunting efforts do not occur near the proposed projec t site. Local bunters general 1 y hunt across Larsen Bay and Uyak Bay. Most of tbe red fox and land otter trapping and hunting occurs away from the project area, but local residents occasionally trap in or near the area. No endangered species occur on Kodiak Island, according to the U.S. Fish and Wildlife Service, although the Peales peregrine falcon, the nonendangered subspecies, does nest on tbe island. Project construction will result in permanent habitat loss in the diversion weir site, the powerhouse location, and the access route to the dam si teo Due to the small size of the project, this loss is expected to be minimal. Temporary habi- tat disturbance will occur at equipment staging areas and in NBI-388-9523-X • - • • • • • • • • • • • • .. • • .. • .. • .. • - • -• .. • • .. III • .. • • • • .,., .." "'" iIfII. .... ... ..... ..... ..... ..... - the transmission anticipated from line right-of-way. Few adverse effects are gravel removal for project construction because an existing borrow site will be used. Operation of heavy equipment and other construction acti- vities will create considerable noise that will disturb wild- life and cause some species to abandon traditionally used areas. However, all construction activity should occur within a six-month period or less. Also the proximi ty of the town acts to limit wildlife numbers in the project area. During project operation, alterations in the flow regime between the diversion weir and the powerhouse may force water- dependent animals such as the water ouzel to relocate. A major potential impact from construction of a hydropower facility would occur if the route to the diversion dam allowed vehicle access above the alder zone. The use of three-wheeled vehicles and snow machines is a popular sport in Larsen Bay. Once above the alder zone, these recreational vechicles could probably be taken the entire length of the ridge between Karluk Lake and Uyak Bay. This area is good deer habi tat and an important denning area for brown bear. Wildlife officials fear that the use of recreational vehicles on this ridge could crea te serious disturbances to wi ld life. To discourage th is potential abuse, project plans call for the road to terminate in a very narrow portion of Humpy Creek drainage where exten- sion of the road would require blasting and tree removal . For the most part, the proposed project is on such a small scale that construction impacts will be minor and short term. The use of prudent construction practices can further minimize impacts. The transmission line to the town of Larsen Bay will follow the alignment of the existing road, so habi tat losses will be limited • A construction buffer zone should be estab- lished around any active eagle nests in the project area . NBI-388-9523-X X-5 • • 3. Vegetation • - Birch is the dominant tree throughout most of the Humpy - Creek drainage except in outwash plains where it is replaced by cot tonwood. The understory varles with the density of canopy cover, with the following species predominant: elderberry, highbush cranberry, rose, lady and fiddlehead fern, and scattered alder and willow. 4. Archaeologic and Historic Sites An archaeological site has been located at the mouth of Humpy Creek, but the extent of the site is unknown. The Division of Parks has recommended that an archaeological survey be done in this area before construction begins and the U. S. Fish and Wildlife Service also requires an on-site survey. Archaeological artifacts are common throughout the Larsen Bay area. Workers associated with the project must be caut ioned about the unauthorized removal of artifacts. 5. Visual Resources The transmission line is the only project feature that may be visible from town. 6. Recreation Project construction and operation should have little impact on recreational values since little or no fishing occurs above the old dam and other areas for trapping, hunting, and picnicking exist in abundance. The route to the diversion weir may open up additional areas for the use of three-wheeled vehicles. This possible use should be prohibited due to the potential disturbance to wildlife in the upper ridge country. NBI-388-9523-X X-6 - • .. • .. • -• .. II • • • -.. .. .. • • • .. • - II • • • .. • • • • 1* .... .... .... .. III til" ... .... Wii/l:!ii1 , ... 7. Air Quality During project construction, exhaust fumes from diesel equipment and dust generated by construction activity may diminish air quality. Winds are common in this area, however, and they should rapidly disperse air pollutants. Electrical power for Larsen Bay is currently provided with diesel generators. To the extent that hydro power replaces the diesel generating facilities, the discharge of hydrocarbon pollutants should be lowered. C. SOCIOECONOMIC EFFECTS The economic analysis for the Larsen Bay Hydroelectric Project assumed that a central distribution system, which does not now exist, was already in place. Thus, the distribution system must be installed before the project can produce any benef i ts. I f implemented, however, the project wi 11 br ing a significant socioeconomic benefit to the local community--a central power source--and it will offer modest benefits from project-related payrolls and employment. The potential exists for social disturbances, but adequate project planning can avoid these possible sources of friction. The project will expand the payroll in the local area during construction and it should provide some local jobs if workers with suitable skills can be found. In fact, the Kodiak Area Native Association has expressed a willingness to provide training to local residents so that they will be qualified to work on this project. It will be important to use as many local residents as possible because employment opportuni ties are 1 imi ted in the area. Otherwise, the local resi den ts may resent the importation of workers to construct , operate, and maintain the project facilities. The project construction force, though, is not expected to exceed 21 and it will average NBI-388-9523-X X-7 about 16. If accommodations for the imported construction workers are not available, which is likely, trailers can be brought in to set up a temporary work camp. The manager of the project construction team should take precautions to ensure that the imported workers cause as little disruption of the traditional life style of Larsen Bay as possible. This is a small, isolated community and the tempo- rary intrusion of the project work force must be handled with consideration for the needs and wishes of the local popula- tion. The use of a trailer camp to accommodate the imported work force would simplify this task. The intensive work schedule will also limi t the time available to the imported work force for recreation. NBI-388-9523-X X-8 • - • - • lit .. • • • • • • • ., ... • • • .. • • • • • • ., .. II • • till lit • • • • .. -. .. , ... ,. ..... .... .... .... .... .. "" ... SECTION XI PROJECT IMPLEMENTATION A. GENERAL This chapter presents comments regarding the various licenses, permits, and inst i tutional considerations that will be encountered during the implementation phase of the Larsen Bay project. A project development schedule is also presented and discussed. B. PROJECT LICENSES, PERMITS, AND INSTITUTIONAL CONSIDERATIONS The following permits may be required for construction of the Humpy Creek facility: 1. Under the authority of Sect ion 404 of the Federal Water Pollution Control Act Amendments of 1972, the Army Corps of Engineers (COE) must authorize the discharge of dredged or fill materials into navigable waters, which includes adjacent wetlands, by all individuals, organizations, commercial enterprises, and federal, state and local agencies. A COE Section 404 Permit will therefore be required for the diversion weir on Delta Creek • 2. A Water Quality Certificate from the State of Alaska, Department of Environmental Conservation (DEC), is also required for any acti vi ty that may resul t in a discharge into the navigable waters of Alaska. Application for the certificate is made by submitting to DEC a letter requesting the certificate, accom- panied by a copy of the permit application being submitted to the Corps of Engineers • NBI-411-9523-XI XI-l 3. 4. The Alaska Department of Fish and Game, Habitat Divi- sion, under authority of AS 16.05.870, the Anadromous Fish Act, requires a Habitat Protection Permit if a person or governmental agency desires to construct a hydraulic project or affect the natural flow or bed of a specified anadromous river, lake, or stream, or use equipment in such waters. A Habitat Protection Permit will be required for the diversion weir, and for any bridging, instream or stream bank work on Delta Creek. Under authority of AS 16.05.840, the Alaska Department of Fish and Game can require, if the Commissioner feels it necessary, that every dam or other obstruc- tion built by any person across a stream frequented by salmon or other fish be provided with a durable and efficient fishway and a device for a efficient passage of fish. A Habi tat Protect ion Permi t, wi 11 therefore be required. 5. All publ ic or pri va te entities (except Federal agen- cies) proposing to construct or operate a hydroelec- tric power project must have a license from the Federal Energy Regulatory Commission (FERC) if the proposed site is located on a navigable stream, or on U.S. lands, or if the project affects a U.S. govern- ment dam or interstate commerce. For the Larsen Bay project, a minor license may be required. The ques- tion of whether or not this project is jurisdictional under the FERC regulations is currently being studied. 6. A Permit to Construct or Modify a Dam is required from the Forest, Land and Water Management Division of the Alaska Department of Natural Resources for the con- struct ion, enlargement, al tera t ion or repair of any dam in the State of Alaska that is ten feet or more in NBI-411-9523-XI XI-2 III • III • • .. • • • • • • .. .. .. .. • • • • .. • • .. .. .. • • .. .. • • • • • • •• ", .... ... 7 . height or stores 50 acre-feet or more of water. Since the weir is less than ten feet high and has only mini- mal storage, this permit is not likely to be required. A Water Rights Permit is required from the Director of the Division of Forest, Land and Water Management, Alaska Department of Natural Resources, for any person who desires to appropriate waters of the State of Alaska. However, this does not secure rights to the water. When the permit holder has commenced to use the appropriated water, he should notify the director, who will issue a Certificate of Appropriation that secures the holder's rights to the water. 8. The proposed project area is located within the coastal zone. Under the Alaska Coastal Management Act of 1977, a determination of consistency with Alaska Coastal Management Standards must be obtained from the Di vision of Policy Development and Planning in the office of the governor. Th is determination woul d be made during the COE 404 Permit review. 9. Any party wishing to use land or facilities of any National Wildlife Refuge for purposes other than those designated by the manager-i n-charge and publ ished in the Federal Register must obtain a Special Use Permit from the U.S. Fish and Wildlife Service. This permit may authorize such activities as rights-of-way; ease- ments for pipelines, roads, utilities, structures, and research projects; and entry for geologic reconnais- sance or similar projects, filming and so forth. Note that all lands that were part of a National Wild- life Refuge before the passage of the Alaska Native Claims Settlement Act and have since been selected and conveyed to a Native corporation will remain under the rules and regulations of the refuge. NBI-411-9523-XI XI-3 C. PROJECT DEVELOPMENT SCHEDULE • .. • - A proposed project development schedule starting at the _ time the initial draft is submitted is XI-l. presented in Figure The schedule is based on the assumption that two separate contracts would be awarded for the project construction. The first would be for fabrication and delivery of the turbine- generator equipment to the Port of Seattle and later installation and the second would be for civil work construction and installation in cooperation with the manufacturer of the turbine-generator equipment. The controlling activities on the proposed schedule are the turbine-generator procurement and the construction period. 1. Turbine-Generator Procurement According to manufacturers' estimates, approximately one year fabrication is (and necessary delivery for turbine-generator to the Port of Seat t Ie) starting from the time of contract award. In addi- tion, prior to the award a two-month period must be allowed for advertising, bid preparation, and bid evaluation. This in turn would be preceded by a three-month period to prepare specifications. 2. Construction Period The field construction period would require two to three summer months of on-site activities, preceded by one to two months of shipping and mobilization time. Other critical tasks such as preparation of the civil plans and specifications, award of the civil contract, procurement of NBI-411-9523-XI XI-4 • • • • .. • • • III • • • • • lilt III .. • -• • • • • • • • II .. • • • .. .. ", .... the necessary permits and license, and coordination of project- related activities with other affected agencies would be accomplished during the turbine-generator procurement phase; thus they are not directly controlling activities. As shown, the project construction would be completed about October 1, 1984. Following three months of commissioning and debugging time, the project would come on-line about January 1, 1985 • NBI-411-9523-XI XI-5 • i • " Activity 1. State of Alaska DecisioD .. "' 2. Secure Necessary Permits, Licenses 3. Turbine/Generator Contract a. Prepare Turbine/Generator Spec. b. Advertise k Evaluate Bids c. Fabricate Turbine/Generator d. Deliver Turbine/Generator to Seattle 4. Civil Contract a. Prepare Civil Plans k Specs. b. Advertise k Evaluate Bids 5. Construction Activities a. Yobilization Period b. Barge Shipment c. Site Yobllization d. Site Construction 6. Power Plant Co~nissionlng, Debugging Period 7. Plant On-Line NHI-410-9521-PDS • , FIGURE XI-l PROJECT DEVELOPYENT SCHEDULE 1982 J F Y A Y J J A S o N D J F Y - -----_ .. -,----- • . ! 1983 1984 A Y J J A S o N D J F Y A Y J J A S o N D '-- • -'---• ___ L-______ J " \10", .... .... SECTION XII CONCLUSIONS AND RECOMMENDATIONS A. CONCLUSIONS On the basis of the studies completed for this report, the following conclusions can be drawn: 1. The energy demands of Larsen Bay are sufficient to utilize the energy hydroelectric project. produced by the proposed 2. The Larsen Bay Hydroelectric Project at the recommended capacity of 270 kW is a feasible project. 3. The proposed project is a more economic means of meeting the future electric needs of Larsen Bay than the base case, or diesel, alternative. 4. The environmental effects from the construction and operation of the proposed project are minor and will have no major temporary or long-term impacts. The project will, however, offer a significant advantage to the community--a central power source. B. RECOMMENDATION In view recommended of by the conclusions the consultant that enumerated actions above, it be ini t ia ted is to implement the project. along the general lines Implementation. NBI-426-9522-XII Implementation can be indicated in Section accomplished XI, Project ·i.fIt" ~,,, -" '1I'ilo"'( " .. ; BIBLIOGRAPHY LARSEN BAY Alaska Department of Fish & Game. Alaska's Fisheries Atlas, Volumes I and II, 1978. Alaska Department of Fish & Game. Alaska's Wildlife and Habitat, Volumes I and II, 1973. CH2M HILL. Reconnaissance Study of Energy Requirements & Alternatives for Akhiok-King Cove-Larsen Bay-Old Harbor-Ouzinkie-Sand Point. For Alaska Power Authority, June 1981. Department of Commerce. ESSA -Environmental Data Service, Climatological Data Summary, Alaska. Ebasco Services, Inc., Regional Inventory and Reconnais- sance Study for Small Hydropower Projects: Aleutian Islands, Alaska Peninsula, Kodiak Island, Alaska. Vols. 1 and 2, October 1980. Ott Water Engineers. Water Resources Atlas for USDA Forest Service Region X, Juneau, Alaska. April 1979. P~w~, T.L. Quatenary Geology of Alaska: U.S. Geological Survey Professional Paper 835, 1975. Robert W. Retherford Associates. "Preliminary Feasibility Designs and Cost Estimates for a Hydroelectric Project Near Larsen Bay, Alaska." January 1980. U.S. Department of Energy, Alaska Power Administration. "Hydroelectric Power Potential for Larsen Bay and Old Harbor, Kodiak Island, Alaska." May 1978. NBI-419-9523-B u.s. Geological Survey. "Flood Characteristics of Alaskan Streams," Water Resources Investigation 78-129, R. D. Lamke. 1979. u.S. Geological Survey. "The Hydraulic Geometry of Some Alaskan Streams South of the Yukon River (Open File Report), II William E. Emmett, July 1972. u.S. Geological Survey. "Water-Resources Data for Alaska Water Year 1963 through Water Year 1980-1981." u.S. Geological Survey. "Water Resources of Alaska (Open File Report)"; A. J. Feulner, J. M. Childers, V. W. Norman; 1971. u.S. Geological Survey. "Water Resources of the Kodiak- Shilikof Subregion, South-Central Alaska," Atlas HA-612, Jones, et al., 1978. Woodward-Clyde Consultants. Valdez Flood Investigation Technical Report. February 1981. NBI-419-9523-B S. H. • • • .. • -• .. • .. • .. • .. • .. • .. • .. • • .. • .. • .. • .. • • • .. • .. • • .... ••• LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX A PROJECT DRAWINGS filii' PLATE I PLATE II PLATE III PLATE IV PLATE V PLATE VI I". TABLE OF CONTENTS GENERAL PLAN INLET STRUCTURE AND ONE-LINE DIAGRAM PENSTOCK AND ACCESS ROAD--PLAN, PROFILE AND SECTIONS DIVERSION FACILITIES--PLAN, ELEVATION AND SECTIONS POWERHOUSE--PLANS AND SECTIONS TYPICAL CROSSARM CONSTRUCTION ASSEMBLY ...... - - -- - - LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX B HYDROLOGY '. TABLE OF CONTENTS ,... PAGE iIIIif A. GENERAL 1 -J B. AREA DESCRIPTION 1 .. C . DATA UTILIZED 4 D. PROJECT STREAM FLOWS 5 .. E . DIVERSION WEIR FLOOD FREQUENCY 11 .- F. CONSIDERATION OF POTENTIAL RIVER ICE PROBLEMS 14 - NBI-426-9523-TC - - - .. - .. - .... - A. GENERAL The following report provides the estimates, the method- ology, and the background data on stream flows near the village of Larsen Bay, located on Kodiak Island in south-central Alaska. Also included is a generalized wri teup of potential ice problems in the vicinity of Larsen Bay and elsewhere. Since the streamflows dictate the amount of energy that can be produced by a particular dam and power plant configuration, their accuracy critically affects the feasibility of the proj- ect. Better than average estimates can now be made for the proposed Humpy Creek si te because more than a year of flow records is now available from a stream gage installed by the U.S. Geological Survey in anticipation of this project. These measurements should be continued for some addi tional time to assess the variability of flow. In the meantime, information from other areas of Kodiak Island bas been used to place this single year of record in context wi th the expected long-term flows. This report describes the general characteristics of the Larsen Bay region and the basin that feeds Humpy Creek. The data used in the hydrologic analysis and streamflow and flood frequency data from Humpy Creek are also presented. A list of the references ci ted in the text is presented at the end of this report . B. AREA DESCRIPTION 1. Regional Setting The village of Larsen Bay is located near the junction of two fjords, Larsen Bay and Uyak Bay, on the northwest coast of Kodiak Island. Shelikof Strait, separating Kodiak Island from the mainland, lies 14 miles to the northwest. The city of Kodiak lies 60 miles east and the village of Old Harbor, the NBI-388-9523-B* 1 site of another hydroelectric feasibility study, lies 35 miles to the southeast. Larsen Bay shares wi th other regions of south Alaska the comparatively mild maritime climate controlled by the Japan Current that sweeps through the Gulf of Alaska. This current produces cool summers, mild winters, and moderate amounts of precipi tation that are well distributed throughout the year. Most of the precipitation occurs when moist air from the ocean precipitates as rain or snow as it is uplifted along the southern slopes of a 2000-to 4000-foot-high mountain range that extends southwest through the length of the island. Its primary crest is located 28 miles upwind (south) from Larsen Bay. Strong continuous winds blow from the south as eastward- moving Aleutian lows pass through this region from December through March. No lakes or glaciers remain. Mean annual precipitation ranges from 20 inches in the most sheltered coastal locations like Larsen Bay to an estimated 180 inches on some mountain crests (Ott Water Engineers, 1979). The mean annual temperature of 410F at Kodiak ranges from a normal daily minimum of 25 0 F in December and January to a normal daily maximum of 60 0 F in August (Department of Commerce Environmental Data Service). Mean annual runoff is typically four cfs per square mile (54 inches) along this leeward portion of the island. The mean annual low month produces only about one cfs per square mile of runoff (USGS, 1971). 2. Basin Description All the previous studies that have considered energy alternatives at Larsen Bay have chosen Humpy Creek as the preferred site for potential hydro power development (CH2M HILL, 1981; Ebasco, 1980; Retherford Associates, 1980; USGS, 1978). The creek is also known as Dora Creek, Trout Creek, or Larsen Bay Creek, but the local name of Humpy Creek will be used in this report. NBI-388-9523-B* 2 • - • • • • • • • • • -• • • • • • • -• • • • .. • • • • • • ,. • • • • _1If •• .. II1II .iiII ,,"" , ... Humpy Creek originates at the north end of a long glacial trough that forms a hanging valley above Larsen Bay fjord. The stream flows north for about 4.5 miles. It passes through the communi ty of Larsen Bay and discbarges into Larsen Bay. The si te of the proposed power diversion dam (elevation 285 feet MSL) is one mile south of Larsen Bay at the confluence of the first tributary that joins Humpy Creek from the southeast. The drainage area above this si te is 6.28 square miles. Mountain ridges that flank the drainage basin to the east and west rise to 2500 feet. The basin divide to the south is an indistinct rise in the floor of the glacial valley. No lakes or glaciers remain. Humpy Creek is a comparatively short, steep stream with characteristics similar to other Kodiak streams. An old diversion dam, reportedly built in the early 1900s, is located one-half mile upstream from the town. Until it recently closed, the Kodiak Island Seafoods cannery obtained its water from this dam through a wood-stave aqueduct. The small pond behind the dam is completely filled with 10 to 12 feet of sediment. The stream between the old dam and the proposed diversion is in a narrow, deep canyon with bed material consisting of gravels, cobbles and some boulders. Only a narrow discontinuous floodplain has developed within the canyon. The floodplain and slopes are covered with alders and brush. A considerable period of climatological data exists for Larsen Bay. These data are collected by the Department of Commerce's Environmental Data Service. A summary of monthly precipitation is given in Table B-1. Precipitation in the basin is considerably lower than the southeast coast basins of the island receive. The mean annual precipitation for Larsen Bay is 23.01 inches, in contrast to the 56.71 inches in Kodiak. Precipitation is lower because Humpy Creek basin is located far down wind from the crest of NBI-388-9523-B* 3 the primary mountain range. This range causes most of the precipi tation to fallon its windward slope or wi thin a few miles downwind of the crest. However, the precipitation within the drainage basin is expected to be significantly higher than the 23 inches recorded at the sheltered village site. Based on National Weather Service and U.S. Geological Service precipita- tion mapping of the area, the mean annual precipi tation is about 40 inches. The USGS used existing streamflow data to determine precipitation isolines; hence, the selected mean annual precipitation value should approximate precipitation to be expected in the project basin. C. DATA UTILIZED The primary data utilized consisted of the one year of daily stream flows recorded by the USGS in upper Humpy Creek, 0.7 miles upstream of the proposed power diversion. This gage, established August 22, 1980, is designated "Larsen Bay Creek near Larsen Bay, No. 15296480." It is located at an elevation of 800 feet and measures a drainage area of 3.92 square miles. In addi tion, the USGS took a number of spot measure- ments on Humpy Creek near the bay between 1978 and 1980. • • • • • • • - • -• • • • • • • • .. • • -USGS streamflow records from numerous gages on Kodiak _ Island were used to establish flow characteristics of streams similar to Humpy Creek. Much of the data is summarized in the USGS Hydrologic Atlas for the Kodiak-Shelikof subregion (USGS, 1978) . The 1963 to 1980 dai ly flow records of Myrt le Creek gage (No. 15297200), located nine miles south of Kodiak, were used extensively (USGS, 1981). Precipitation records from Larsen Bay and Kodiak were used indirectly by making appropri- ate adjustments. A report by Ebasco (1980) presented flow durat ion curves from other basins, regional estimating methods, and initial estimates of basin yield. The CB2M HILL report (1981) depended NBI-388-9523-B* 4 • -• • • • • • • .. • .. • • principally on the U.S. Geological Survey statewide report (1971) for flow estimates. D. PROJECT STREAMFLOWS w. Humpy Creek is a perennial stream at the site of the diver- .Mliil ... sion dam, according to local residents. The flow regime is seasonal. Higher flows normally occur in May and June from spring snowmelt and from September into November from rainfall. A comparison of precipi tation records from Larsen Bay and Kodiak (Table B-1) indicates that the time distribution of precipitation is generally similar at both stations. Larsen Bay has a proportionately drier spring and a somewhat wetter late summer and autumn than Kodiak. The most recent preliminary discharge values for Humpy Creek obtained from USGS and monthly average flows are presented in Figure B-2. Note that the winter discharge values are affected by ice when the float of the stage recorder is frozen. For such periods, the daily discharges were estimated on the basis of the recorded range in stage or comparison with the station records from nearby basins . An examination of the hydrograph for the water year 1980-81 shows two peak runoff periods, May and October. As the snowpack starts mel ting in April, a slow increase in direct runoff follows. Peak flows occur in mid May. At the conclusion of the snowmel t, following a period of low precipitation (see Table B-1, Kodiak, 1981) in July and August, the discharge drops to its lowest values. These values reflect little, if any, contribution from surface runoff. The base flow, which is the groundwater contribution to the streamflow, attains a value of four cubic feet per second during this period. The second peak flow occurs in October as a result of heavy rainfall that contributes to a rapid increase in direct NBI-388-9523-B* 5 runoff. The annual peak discharge is typically caused by rainstorms rather than snowmelt in a small drainage basin with Ii ttle storage capaci ty such as Humpy Creek. Note that to estimate the flow at the proposed diversion dam the given discharges recorded at the gaging station should be multiplied by 1.60 to correct for the difference in drainage area between the gage and the dam site. 1. Mean Annual Flow The mean annual flow for the water year 1980-1981 as determined from the Humpy Creek gage records is 10.6 cfs for a drainage area of 3.92 square mi les. For the drainage area above the proposed dam si te, this value becomes 16.9 cfs. A check has been made to ascertain whether the observed mean annual flow is due to a normal, wet, or dry year. The only long-term precipi tat ion records near the project area are for the city of Kodiak. Precipitation at the Kodiak station for the water year 1980-1981 was 75.61, the long-term average annual precipitation is 56.71 inches. Taking the ratio of these precipitations (56.71/75.61) provides a flow adjustment factor of 0.75. If the 1981 mean annual flow of 16.9 cfs at the dam site is multiplied by 0.75, an estimated long-term mean annual flow of 12.7 cfs is obtained. Al though at least a year of discharge record for Humpy Creek was available for use in obtaining a measured value of mean annual flow, three procedures for estimating mean annual flow were applied to help to establish the relationship of the 1981 record to anticipated long-term flows. NBI-388-9523-B* 6 • ---.. • • -• -• • • • • ... • • • -• • -- • • • • • • • • .. • - • • .... ..... .... . ..., ,- These procedures can be categorized into the following groups: • modified rational formula • regional analysis • channel geomorphology a. Modified Rational Formula Application of the modified rational formula is explained in detail in the Ebasco report (1980). Only the salient features of the method are provided below. The method requires that a gaged stream within the study area having similar weather patterns and groundcover to the ungaged stream be selected. A proportion is then set up, so that = Ag Aug where Qg and Qug refer respectively to gaged and ungaged streamflow in cubic feet per second and A is the drainage area. Factors to adjust precipi tation and elevation data are incorporated into this equation as follows: ~ug Qg (P) + (~H)E Aug Ag where P is the precipitation adjustment factor between the two watersheds, ~H refers to the elevation differential, and E is the elevation adjustment factor. I n applying this procedure, the stream gage records from Myrtle Creek near Kodiak were paired with Humpy Creek on the basis of the period of record and of basin and climato- logical similarity. Mean discharge records of the Myrtle Creek NBI-388-9523-B* 7 area were analyzed in conjunction with long-term weather records at Kodiak to determine whether the observed values are normal or due to runoff from wet or dry series of years. A flow adjustment factor was derived by taking the ratio of the average annual rainfalls during a 16-year gaging record to the long-term average rainfall during the period of weather records. The resul t ing factor of 0.86 was appl ied to the shorter-term measured flow of 46 cfs. This analysis yields an adjusted mean annual runoff of 39.4 cfs or a unit runoff of 8.3 (Qg/Ag in the above equation) for Myrtle cfs per square mile Creek. The precipi tation adjustment factor (P) accounts for the precipitation difference between the area of gaged and ungaged stream. It is a ratio of long-term average precipi- tations between the two basins. The precipitation adjustment factor between Humpy and Myrtle Creek basins is similarly based on estimates of mean annual basin precipitations. The values used are 40 inches of precipi tation for Humpy Creek and 140 inches of precipitation (Ott Water Engineers, 1979) for Myrtle Creek. This resul ts in a precipi tation adjustment factor of 0.285 between the two basins. Using this factor, the adjusted unit runoff for Myrtle Creek yields a unit mean annual runoff of 2.37 cfs per square mile for Humpy Creek. The mean annual flow for the project stream is thus estimated to be 14.9 cfs. The Ebasco report (1980) estimate of 4.1 cfs per square mile is much higher. That estimate was based on a pairing with the gage records from upper Thumb River, which cover a much shorter, but wetter, period. b. Regional Analysis The regional method described by Ott Engineers (1979) was first applied to the gaged stream Myrtle Creek to test its applicability. The maritime climate in the Larsen Bay area is similar to the Chugach National Forest area at the nortbeast NBI-388-9523-B* 8 • -• - • • • -• • • • • • • • • • • -• -• -• -• -• • • • .. • • • • end of Kodiak Island where the method was in part developed; therefore, the regional method should provide reasonable estimates. This method yielded a mean annual flow of 43 cfs with 90 percent confidence limits of 35 and 52 cfs. This predicted value is within seven percent of the measured flow of 46 cfs. The same method applied to the Humpy Creek si te with a mean annual precipitation of 40 inches gives a flow of 13.3 cfs. The 90 percent confidence limits are 11 ana 16 cfs. c. Channel Morphology Channel geomorphology can be used to estimate both the mean annual flow and the mean annual flood by measuring channel dimensions that have been shaped by these streamflows. The method is considered to give reliable estimates for parts of the United States where estimating relations have already been defined. Despite the success of this method at other hydro feasibility sites and a calibration based in part on streams located only 15 miles south of Larsen Bay, the estimates for Humpy Creek were unrealisticly low and therefore they were discarded. d. Estimated Flow A mean annual flow of 13.0 cfs for the Humpy Creek site is considered to be the best estimate based on available information and the confidence interval of the various estimates. The close agreement of the adjusted observed flow wi th the two estimating methods lends considerable confidence to the value. NBI-388-9523-B* 9 2. Flow Duration The flow duration curve for a potential hydroelectric site is the initial tool used in sizing the turbine and estimating annual energy production. Where no continuous record is avail- able at the si te, the information must be transferred from gaged sites on the basis of their hydrogeological characteristics. The flow duration curve can be viewed as the time dis- tribution of flows about the mean annual flow; thus a dimen- sionless flow duration curve (the ratio of flow to the mean annual flow versus the percentage of time the flow is exceeded) can be developed for any gaged basin and be directly compared with any other dimensionless curve. Within certain hydro- geologic regions these curves often have remarkable similarity, particularly within the 15 to 80 percent exceedance interval. Thus, regional curves can be developed. Curves from small, steep basins with bedrock near the surface and little ground- water contribution are typically steeper than those from larger basins that include swamps or lakes and a good aquifer. The Humpy Creek basin belongs to the former group. A comparison of dimensionless curves from three basins on Kodiak Island 25 to 40 miles distant and one from Amchitka Island 1200 miles to the southwest showed considerable similari ty. On this basis the Myrtle Creek curve developed from 17 years of daily record was adopted as the type of curve to use for small, mountainous maritime basins in southwest and south-central Alaska. The Humpy Creek flow duration curve presented in Figure B-1 is based on Myrtle Creek, wi th the flows scaled to the ratio of their respective mean annual flows in cfs (13/46). 3. Annual Hydrograph Based on the same data and reasoning that went into determining the mean annual flow and the flow duration curve, NBI-388-9523-B* 10 • • • - • • • -• .. • • • • • • • • -• - • - • - • - • • • .. • • • • • • ...... ."", .... '" an annual hydrograph can be developed based on monthly flows at Myrtle Creek. The Humpy Creek annual hydrograph presented in Figure B-2 and Table B-2 is based primarily on the mean and standard deviations of the logs of the mean monthly flows recorded at Myrtle Creek during the 17 years of record. The data are scaled to-the Humpy Creek si te by the rat io of mean annual flows. The 1980-81 measured mean monthly flows, adjusted for the difference in drainage area, were superimposed and showed good agreement. The range of monthly means shown in gray on Figure B-2 corresponds to roughly seven out of ten years. Thus the average monthly flow should lie below the indicated flow range at least one year in ten and above the indicated flow range at least one year in ten. E. DIVERSION WEIR FLOOD FREQUENCY Estimates of the magnitude and frequency of floods at remote sites such as the Humpy Creek site must depend primarily on regional studies. These studies relate the calculated flood frequency of measured peak flows at gaging stations to drainage basin characteristics such as area and precipi ta tion by means of multiple regression analysis. Estimates of flood discharge at the site were made on the basis of three previous regional hydrology reports: USGS (1979), Ott Water Engineers (1979), and Woodward-Clyde Consultants (1981). The USGS report employs the log-Pearson Type III distri- bution to determine flood magnitude and frequency relations on the basis of data collected at 260 stations throughout Alaska. Tbe details of the analysis are provided in the report. The Ott ~ngineers report was developed for the Chugach and Tongass National Forests on the Gulf of Alaska. The NBI-388-9523-B* 11 Chugach National Forest includes the east end of Kodiak Island and the prediction equations developed are considered applic- able to the Larsen Bay area. The Woodward-Clyde Consul tants report, written for the City of Valdez, covers much of the same area of south-central Alaska as the Chugach National Forest equations developed by Ott Engineers. The three sets of flood prediction equations were applied to both the Humpy Creek si te and Myrt Ie Creek, the latter providing an approximate test for this region. BASIN PARAMETERS Site Area Precipe Temperature Percent of Area (sq.mi.) (in.) (Jan. mean min.) lake store. -forest Humpy Cr. 6.28 Myrtle Cr. 4.74 40 140 o o PREDICTED FLOOD FREQUENCY AT HUMPY CREEK Method Peak Discharge for Hecurrence (years) 2 10 25 50 USGS (cfs) 590 890 950 1150 (Standard errors,%) 50 45 48 42 Ott (cfs) 120 250 325 400 Woodward-Clyde (cfs) 250 420 NBI-388-9523-B* 12 o o Interval 100 1270 485 520 • .. • - • • • -• - • .. • • • .. • • • -• -• -• • • -• • • -• .. • -• • ~, .. ,"·4 ''''''''' .... PREDICTED FLOOD FREQUENCY AT MYRTLE CREEK Method Peak Discharge for Recurrence Interval (years) 2 10 25 50 100 USGS (cfs) 930 1400 1510 1810 2000 Ott (cfs) 665 1110 1300 1480 1670 Woodward-Clyde (cfs) 1130 1470 1620 Based on Lamke I s analysis of 14 years of measured flood peaks on Myrtle Creek, the 2-year and 10-year floods are 765 and 1020 cfs respect i vely. The maximum flood in that period, 1110 cfs on September 14, 1969, has approximately a 10-year average recurrence interval. The mean annual precipitation used at Myrtle Creek is derived from the isohyetal map produced by Ott. It accounts for significant increases in precipi tation wi th elevation and it is similar to the basin precipi tation derived for Humpy Creek. The USGS method produces much higher estimates wi th this precipitation value. However, if the mean annual precipitation of 80 inches derived from the earlier isohyetal map actually used by Lamke is substituted, the estimated 10- year flood is 1040 cfs. This appears to be a case where each method must be confined to the data on which the original regression analyses were based. With this limitation on precipitation estimates, there is good agreement among the three methods. The adopted flood frequency curve at the Humpy Creek si te based on the Ott Engineers equations is presented in Figure B-3. The 90 percent confidence limi ts adapted from the Ott analysis are also shown. The lines indicate that the true flood frequency would lie within these limits with a 90 percent level of confidence. NBI-388-9523-B* 13 It should be recognized that in this environment the greatest depth and extent of flooding may not be due to peak discharges. Ice sheet and ice jam flooding are common. During the normal winter freeze-thaw cycles, many layers of ice may accumulate and create temporary ponds that may release suddenly to inundate and jam the diversion weir. F. CONSIDERATION OF POT£NTIAL RIVER ICE PROBLEMS 1. Formations of River Ice The occurrence and condition of the ice on rivers and reservoirs may require protection of water intake points from blockage. Several types of ice can form in natural ri vers. One is called "sheet ice" and it occurs mostly on stagnant bodies of water and slowly flowing streams. This ice usually originates wi th plate or border ice and gradually propagates across the water surface until a continuous sheet is produced. Another type of river ice is called "frazil ice." by nucleation of slightly supercooled turbulent It is formed water. Two forms of frazil ice are distinguished: active and passive forms. Passive frazil ice is not considered as detrimental as active, which sticks to any solid object at or below freezing temperature in the river. If the active frazil ice adheres to the river bottom, it may contribute to the formation of anchor ice. One other form of river icing refers to a mass of surface ice formed by successive freezing of sheets of water that seep from a ri ver. A river icing (to which the term aufeis is commonly restricted) is more particularly the mass of ice superimposed on the existing river ice cover. 2. Estimates of Ice Thickness The thickness a natural ice sheet can attain depends upon the cooling potential of the atmosphere. In winter this is NBI-388-9523-B* 14 • .. • .. • • • ---• • .. • • • • • -• -• - • .. • • • • • -• • • - • • often expressed in freezing degree days, and the thickness reached at any time is expressed in terms of the square root of the degree days. Although several relationships have been developed to estimate ice thickness as a function of the cooling potential of the atmosphere, Stefan's simple equation ( 1889) is ·presented here to provide rough est ima tes of ice thickness. The Stefan equation in its original idealized form does not include the effects of snow cover, wind, surface roughness, and other physical parameters. expression of Stefan's formula H=ar-FT The following incorporates a coefficient a that presumably accounts for local effects such as snow cover and snow conditions. Values of a are given in the following tabulation. FI is the freezing index and refers to the number of degree days below freezing for one year. Freezing degree days or freezing index values are obtained from NOAA climatological records. For the four small hydropower locations studied for this contract of which the Larsen Bay Hydroelectric Project is a part, the following values of a and FI have been chosen and the resulting river ice thicknesses are indicated. Site a FI (OF-day) H (inches) --- Togiak 0.65 2225 30 King Cove 0.40 1400 15 Old Harbor 0.40 1500 16 Larsen Bay 0.40 1400 15 Estimates of river ice thickness are provided to aid the design of proper hydraulic structures and protect them from ice problems such as ice jams, icing, and improper placement of the NBI-388-9523-B* 15 intake. Note that these ice thicknesses are theoretical values and do not include the effects of wind, flowing water, and currents and snow cover. 3. Frazil Ice More severe problems could potentially be experienced from frazil ice formation at the water intake point. Since very little is known about frazil ice formation, evolution, and subsequent disposition, rational design methods to avoid frazil-ice problems are lacking. Frazil ice formation has been observed at Midway Creek, Old Harbor, and Humpy Creek dam site in Larsen Bay. Particularly, Humpy Creek dam site appears to produce considerable frazil ice under natural flow condi tions. Del ta Creek dam si te at King Cove may also experience simi lar ice problems. The Togiak Quigmy River project site has been observed to have floating ice blocks and ice jams that develop at naturally constricted channel locations. During the installation of a stream gage in December 1981, release of water from an ice-jammed reservoir upstream caused the stage to rise approximately three feet. Considerable quantities of floating ice blocks have been observed following the rise in stage. While little data are presently available, it is clear that the potential ice problem ci ted above must be considered in depth during the design phase of project implementation. These in-depth considerations should include an evaluation of condi- tions that cause ice problems, the extent of the problems to be encountered, and potential measures to alleviate or mi tigate the problems. About 18 percent of the project energy would be produced during the coldest winter months from December through March. If a portion of this energy were lost because of ice problems, the economic feasibili ty of the project might be affected. Mitigation measures would be implemented, of course, NBI-388-9523-B* 16 • • • ... • - • -• .. • - • -• • • • • .. • - • - • - • - • • • - • • • • • • . " .. .... to control the problem, but the chance remains that some energy might be lost. As mentioned, this will be studied in detail during the design phase of the project • NBI-388-9523-B* 17 TABLE B-1 AVERAGE MONTHLY PRECIPITATION (inches) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual La rsen Bay..!./ 2.05 1.92 1.38 1.07 0.76 1.19 1.29 2.82 2.90 3.03 2.37 2.23 23.01 Kodiak, long term 5.01 4.89 3.85 3.61 4.35 4.12 3.54 4.30 6.11 6.29 5.41 5.03 56.71 Kodiak, 1980-81 Water Year1./ 13.65 6.43 8.05 2.86 7.26 1.87 2.53 4.35 7.47 (9.38) (7.12) (4.64) 75.61 1/ 8 to 15 years of data through 1967. 2/ (October through December) from 1980. TABLE B-2 ESTIMATED AVERAGE MONTHLY FLOWS AND DEVIATIONS HUMPY CREEK (cfs) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Average 7.9 6.8 4.8 9.9 27.4 23.9 9.5 10.6 18.3 17.0 12.8 7.5 13.0 High 24.2 22.5 14.8 20.7 38.6 42.2 20.4 24.2 30.9 28.1 22.8 19.7 Low 2.5 2.1 1.4 4.6 19.3 13.4 4.6 4.6 10.9 10.2 7.0 2.8 NBI-388-9523-Bl 70 60 50 40 30 20 _ 10 f/I .. o -~ 9 ~ 0 \ \ \ \ '" ' ... MEAN ~,NNUAL FLOW 13 cfs " ~ , ............... r---... r-----~ o 20 40 60 80 100 PERCENT (%) OF TIME FLOW EXCEEDED ~I~_-----------------------------------------------------------HUMPY CREEK FIGURE FLOW DURATION CURVE 8-1 LARSEN BAY APPENDIX B References CH2M HILL. Reconnaissance Study of Energy Requirements & Alternatives for Akhiok-King Cove-Larsen Bay-Old Harbor-Ouzinkie-Sand Point. For Alaska Power Authority, June 1981. Department of Commerce. ESSA -Environmental Data Service, Climatological Data Summary, Alaska. Ebasco Services, Inc., Regional Inventory and Reconnais- sance Study for Small Hydropower Projects: Aleutian Islands, Alaska Peninsula, Kodiak Island, Alaska. Vols. 1 and 2, October 1980. Grey, B.J. and D.K. MacKay, "Aufeis (overflow ice) in Rivers", Canadian Hydrology Symposium Proceedings: 79, Glaciology Division, Water Resources Branch, Inland Waters Directorate, Environment Canada, 1979. Michel, B., "Winter Regime of Rivers and Lakes", CRREL Monograph III-BIA, CRREL, Hanover, New Hampshire, 1971. Osterkamp, T. and Gosink, J.P., 'Letter written to Dept. of Commerce and Economic Development', January 1982. Ott Water Engineers. Water Resources Atlas for USDA Forest Service Region X, Juneau, Alaska. April 1979. Rhoads, E.M., "Ice Crossings", The Northern Engineer, Vol. 5, No.1, pp. 19-24, 1974. NBI-388-9523-BR Robert W. Retherford Associates. "Preliminary Feasibility Designs and Cost Estimates for a Hydroelectric Project Near Larsen Bay, Alaska." January 1980. Stefan, J. "Uber Die Tbeorien Des Eisbildung in Polarmere tl , Wien Sitzunsber, Adad. Wiss., Sere A, Vol. 42, Pt. 2, pp. 965- 983, 1889. u.S. Department of Energy, Alaska Power Administration. "Hydroelectric Power Potential for Larsen Bay and Old Harbor, Kodiak Island, Alaska." May 1978. u.S. Geological Survey. tlFlood Characteristics of Alaskan Streams," Water Resources Investigation 78-129, R. D. Lamke. 1979. u.S. Geological Survey. "The Hydraulic Geometry of Some Alaskan Streams South of the Yukon River (Open File Report) ,11 William E. Emmett, July 1972. u.S. Geological Survey. "Water-Resources Data for Alaska Water Year 1963 through Water Year 1980-1981.11 u.S. Geological Survey. "Water Resources of Alaska (Open File Report)"; A. J. Feulner, J. M. Childers, V. W. Norman; 1971. u.S. Geological Survey. "Water Resources of the Kodiak- Shelikof Subregion, South-Central Alaska," Atlas HA-612, S. H. Jones, et al., 1978. Wabanik, R.J., "Influence of Ice Formations in the Design of Intakes", Applied Techniques in Cold Environments, Vol 1, pp. 582-597 . 1978. Woodward-Clyde Consultants. Valdez Flood Investigation Technical Report. February 1981. NBI-388-9523-BR • --- • - • -• • • .- • • • • .. • • -- • -• --- • - • .. • -• • • • Yould, P.E., and T. Osterkamp, "Cold Region Considerations Relative to Development of the Susitna Hydroelectric Project", Applied Techniques in Cold Environments, Vol. 2, pp. 887-895, 1978. NBI-388-9523-BR LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX C GEOLOGY AND GEOTECHNICS A. B. C. D. E. F. G. - TABLE OF CONTENTS INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOPOGRAPHY ••• . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REGIONAL GEOLOGY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ENGINEERING GEOLOGY. 1. 2. 3. Dam Site Geology ••••••••••••••••••••••••• Construction Materials ••••••••••••• Road/penstock/Powerhouse Location •• SEISMIC HAZARDS ••••• . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MECHANICAL ANALYSES. REFERENCES CITED •••• i 1 2 3 6 6 6 7 10 13 16 Figure 1 2 3 4 5 6 LIST OF FIGURES Geologic Time Scale •.••••••••.••••••••••••••••• Reconnaissance Geologic Map •••••••••••••••••••• Road Location Map •••••.•••••••••••••.•••••••••• Seismic Risk Map ••••••••••••••••••••••••••••••• Gradation Outwash Deposit ••••• ~ •••••.•••••••• Gradation -Alluvial Fan Deposit .•.•••••••••••. ii page 4 5 8 11 14 15 • -• • • • • -• • • • • • • III • • • .. • .. • -• - • • • - • .. • • • • • • - - ........ APPENDIX C Geology and Geotechnics for the Proposed Larsen Bay Hydropower pro~ect A. INTRODUCTION In siting a hydropower facility, it is important to under- stand the regional as well as the site-specific geology and geo- technics. Regional information is necessary to: (1) assess the geologic hazards, (2) assure that appropriate design criteria are utilized, (3) discover construction materials borrow sites, (4) provide background information for environmental studies. This report discusses regional geology and seismicity and the specific dam site, penstock/road routes, and the powerhouse location. In accordance with the Scope of Work for this project, the informa- tion is intended for use at the detailed feasibility study stage. Geologic and geotechnical field studies were conducted September 18, October 23-25, and November 6-7, 1981, by Dr. R.L. Burk, project Geologist and Team Coordinator, and J. Finley, Project Geotechnical Engineer. -1- B. TOPOGRAPHY Larsen Bay is a community located along a bay with the same name on Kodiak Island, Alaska. Kodiak Island is essentially an isolated extension of the Kenai Peninsula in the Gulf of Alaska. Larsen Bay is an arm of the larger Uyak Bay which is a major north-south trending bay opening to Shelikof Strait between Kodiak Island and the Alaska Peninsula. Larsen Bay is now a fjord; however, during glacial times it was filled wi th ice and was a tributary to the major ice mass occupying Uyak Bay. Because of the mul tiple glacial advances that have brought ice to this entire area, the hills are gener- ally smooth and rounded, hanging valleys are common and valleys tend to have a parabolic cross section. Elevations in the immediate area range to approximately 3000 feet. Stagnant ice topography and abandoned outwash channels are common. The proposed dam si te is on Humpy Creek, which drains the hills to the south of Larsen Bay and flows through town into the bay. The stream is relatively straight and is incised into bed- rock in the project area. -2- • .. • • • • • .. • • • .. • .. • .. • .. • lilt -- • • - • • • • • • • .. • • • • - C. REGIONAL GEOLOGY Plate-tectonic theory provides the basic ideas necessary to synthesize and understand the geology of continental margins and plate boundaries. Ocean trenches are viewed as si tes of large- scale underthrusting of oceanic crustal materials. The sediments that fill these trenches are scraped from the downgoing plate and accreted to the overlying plate as this underthrusting con- tinues. Southwestern Alaska has a long history of being a zone of accretion for deep-sea deposits. The Kodiak Formation which consti tutes the bedrock under- lying the Larsen Bay si te has been interpreted as a deep-sea trench deposi t of Late Cretaceous age (see Figure 1) which has been accreted to the continent (Connelly, 1978). These rocks are for the most part marine turbidites and range from well-lithified siltstones to fine sandstones. Glaciation on Kodiak Island has probably extended from Miocene time (Pewe , 1974) to the presen t. The g lac i al depos its at Larsen Bay date from Late Pleistocene time (Coulter, et al., 1965). Both till and glacial outwash deposits are present (see Geologic Map, Figure 2). -3- GEOLOGIC TIME SCALE Subd Ivlslons of GeologIc TIme Eras PerIods Epochs (Recent) Quaternary PleIstocene u Pliocene - 0 N MIocene 0 z LU U TertIary OlIgocene Eocene Paleocene u Cretaceous -0 N JurassIc 0 en I.lJ :::E TrIassIc PermIan PennsylvanIan u MIssIssIppian - 0 N DevonIan 0 LU ~ < Silurian a.. OrdovIcIan CambrIan PRECAMBRIAN (No worldwide subdIvIsIons) BIrth of Planet Earth Figure 1. Geologic Time Scale. -4- RadiometrIc Ages (ml II Ions of years before the present) 1.8 6 22 36 58 63 145 _. 210 255 280 320 360 _. - 415 465 520 580 4,650 - • - • - • - • -• .. • • • • • • III • -• --- • • -• -.. • .. • • • • ..... - - - - - - - ..... - - - D. ENGINEERING GEOLOGY 1. Dam Site Geology The geology of this area consists of glacial till, out- wash, and alluvial fan deposits that mantle bedrock belonging to the Late Cretaceous Kodiak Formation (see Geologic Map, Figure 2). The bedrock is a slate with poor to moderate fissil- ity. There appears to be some gradation in size of the original sediment, which is consistent with the turbidite classifica.tion of these rocks by Connelly (1978). The proposed diversion weir is in a very narrow gorge within the bedrock. The walls of the gorge are near vertical in many areas along the stream and at the dam site. Other than removing minor amounts of loose rock at the surface, no special problems are anticipated for dam abutments. The rock is not highly weathered or fractured and appears competent for this use. Stream gravels at the proposed dam site are virtually non- existent. Permafrost is not present in this area. No springs or unusual groundwater condi tions were observed at the si te during field work • 2. Construction Materials Gravelly sand is present both in the outwash deposi t (see Geologic Map, Figure 2) and the alluvial fan deposit. Gradations are shown in the Mechanical Analyses Section, Figures 5 and 6. rrhe fan deposi ts are probably superior for -6- construction because there is an existing gravel pit (also the city dump) which can be used. If higher quali ty materials are required, beach materials should be investigated. The rock that is blasted away for road construction • • • • • • .. • • • should provide adequate riprap for weir construction and stream _ crossings, if they are necessary. - 3. Road/Penstock/Powerhouse Locations There are two potential locations for the penstock and road: one on each side of Humpy Creek (see Road Location Map, Figure 3). Both of these locations involve a number of geotech- nical problems in terms of slope stability, river channel cross- ings and bedrock excavation. An adequate road currently exists up to the present dam across Humpy Creek. This road ends near the west abutment of that dam. option A could ei ther cross the creek at the wei rand connect with the existing road or extend down the east side of the creek to town. option Bb would connect with the existing road and stay on the west s ide all of the way to the proposed diversion site. From the staging area (see Figure 3), both op- tions are identical and require a roadbed to be blasted into the bedrock. Up to the point where the road would drop down to the stream, option A is very inexpensive to build, with few geologic • • • .. III III .. • - • • • .. .. • .. • hazards and little likelihood of future major maintenance • problems. Once the road reaches the stream, either one (Alterna- tive Aa) or three (Alternative Ab) stream crossings, depending on the amount of blasting, are necessary to reach the staging area. -7-• • • II1II Option Aa would need approximately 125 feet of blasted road and one stream crossing to reach the staging area and Option Aa would require three stream crossings and no blasting. Option Bb extends from the dam up a gentle slope de- veloped on glacial till. From there it crosses a 60 percent side slope composed of outwash, which would be difficult to cut back because of its height. After approximately 500 feet on the side slope, the route crosses landslide deposits with springs issuing from them and then follows a low terrace until just before the staging area. To go from the terrace down to the staging area, it will be necessary to cut into the bedrock along a section approximately 200 feet long. Of the two options, cutting back into the slopes. better option. It also does Option A requires a minimum of From that standpoint, it is the not cross any areas of major hillslope failure. The proposed powerhouse is located on inactive alluvial" fan deposits with good bearing capacity. No special geotechnical problems are anticipated at that site. -9- • .. • .. • • • .. • .. .. -• .. • .. • .. • • • .. • .. • .. • III • .. • II • .. .. .. • .. - - - - - - - - - - - -- - E. SEISMIC HAZARDS Southwestern Alaska is part of an intense seismic zone which circumscribes the Pacific Ocean. Most of the more than 150,000 earthquakes that occur worldwide each year occur in this Circum- Pacific belt and in a somewhat smaller belt which extends through southern Asia and the Mediterranean. Past earthquake damage in the study area has been princi- pally manifested in five separate forms which can act independ- ently or in combination. o o o Surface faulting -faults are present in the Lar- sen Bay area: however, the rock at the proposed dam sites does not appear to have been subject to fault slip. There is no evidence of faulting along the penstock/access route or at the power- house site. Strong ground motion over a 50-year design period, the maximum rock acceleration is expected (probability of exceedance = 10%) to be between 40 and 50%g (see Figure 4). This figure was pre- pared using actual earthquake epicenter and magnitude data for Alaska. Ground failure -minor landslides have occurred in this area in the past; however, no major slides that would affect the integrity of a dam or powerhouse are expected. The site is in -10- - ,·WIII - -o -o - - ..... bedrock. The access road and penstock is in part on glacial drift, however no special ground failure problems are expected. Seiches -these are long-period oscillations of enclosed water bodies. Because no reservoir is proposed, no destructive seiches are expected. Tsunami -seismic sea waves could affect coastal areas, including the town of Larsen Bay but not the diversion site. -12- - - - .... - - - - F. MECHANICAL ANALYSES ..... .... .... - - - -13- - - ® Alaska Testlab 4040 "B" Street Anchorage, Alaska 9950] Phone (907) 278-1551 Textural Class~ ____ Grav~)}·X_?_a~<!~~~ __ ~_~_~ _____ ~ Client ________ ~A:.laska_~ower Frost Class _~ ____ ~ _________ Unified Class SW ______ ~ Plastic Properties _________________ ~ ______ ~_~ ___ ~ _________ ~ Project _____ ~~~s~Jl ___ Bay Sample Number ___ ,3985 __ Date Received 11 !9/8l~ ________ ~ ________ _ Location ______ ~ ____ ..Bl~_RB.:_a _ Sample Taken By Cl j ent Sheet 2 of 2 W.O. No. D134~ Date _~~11/9/81 T~chni~ian §M_~~ Autnor~ty -- ----~~~--~------------------~------~---~--------~--~ ~~~~~~-~~ _____ S~IE~V~E~ _ _r~A~N~A~L~Y~S~I~S~~-~~~-~----~-~~-~H~Y~O=ROMETER ANALYSIS US STO CUM 0/0 ~--L-__ -~51~Z~[-~O~f~O~~~M~I~~~I~"~IM~C~H~[~S--~-~NUN~.~[~R~~~M~fSH ~R:~IM~C~H~U~S~ST~A~N~~~R~D~ __ ~------~O~R~AI~N~S~ll~[~1~M~M~M~ _________ _L~~ .. • ... -:£ N ~ _,;1 ~; ~. • 9 !! ~ ~8 ~ ~ ~ 8 &88 § 8 ~ 8 § go 0 0 i~ 08 ... • .- 100 -__ --,-----_:' -T-----l--rT--TT----.---_, _1t _ I r---_ -_ 1-_------= __ _ f--. j -----~ -I • -_ f-----~-f- 90 ---_t +-j+-I--i--I--t-i--I-+ ~-+---t-~-__ -__ -_+~f_+--_------i-+_ -_-+--t---t---++~-+-----tl++-+-+-~~-+-----+~+-+-+-+-I---....jtf.-_ ----_-_------loo ~~:-~ . ~~ ~ i __ ~_ f--__ r--~ .0~----~~t-~;--+--~--+--+-4--+----++----~+--+--+--++-~---~~~~~---+----~+++-~~-~~--------l t-tL:.::_:~~J---=_ -----f-------::---:---__=. f------t~-= ,---~--~_-t--f-f-_ ~-~f-_--_=_=--__ -_~-_== lO -t +-----t t---t-----i i I t- ~! J---!---t-_ ~ !-~-H -±t-~f::::':'-r-:!t -=-1_-~:..:-t-=-=--=--=30 j ii- ! LT t- l .... ! lC -1-j~------I--~ ------:::+-~ --~ 1------~ ---. r-. --l--+-+---~.. t --I--. ---- : 60~~~ .. ~--~-i-.-T~.-i~· --it-_-----i~~--+--t--4--t---.-.·.-_+~-----~--~~---t-----+i----+--+1--~j4~------~+-~~~-~-.~~-.---------++++~.~~-+~---~-~I-------~.-~--~-----:==~40 ~ _ . ~ "~----t-- ---+----+---+------_ .. - L ~0~----~~--~_t--~_i--t_~--t_----~r_--_r_+--+__+--~~-r+_----~+_~~~--~----++~~+_+_~--~---.-------~~ ~ . -1 it + ---t·j -:.. -t I-..--f .. -l ··r ...:.:1-1 ---~ ~ 40 ~+-~~---+-t~'r-+-----+ -.---1---+-+--+-+---------.--+-~+-~-~--------jl-~---__+--+_-+--~-+_+__<~_++ f._:-1=-= ~--~ f-~ ... ----::::: ~-:t-~.. L£ ---.. -----. r: ·r--+r-----IH-+-+--II--+------4f+tr-++-!-++-+_--___ -_--I. f-f--_-_==----1ao ., ... ... L ---t--..:= :--... -.-~---~--- 101-_-_~+--_-jl-.~-t--r-+---+-~--+--t--~-+-----+4---~~~-+--+--+~~~~.----~~~~~--~----_+~~~-+---L--~=-~-~-~-=-=.-]10 --t-~ -_ _ f--------= 20 ~i-:~--.... ------~ f--f-------.-= _.~ f __ 1-__ _ __ _ __ eo ~ ~--,.. ---I---,. ..--- I 0 r--------. ---I - -~-----~ ---=== ·f-·· ----f_----~-~ --- H+jf._+ ----~I----- __ ~!~.l ~._!.. ! ",L-~N'-----~44_.1-~.-:..l .. ~_~"':!----'---J--~~_.JTu; l'--'rUL-'----,~L.---L..--L.----.LJ --100 ~ ~ N -~~8~e ~ o§§a~8 § g ---:::-f-~. -6-~ o ~ -.:..j ulL1L ~ ,,--Lf_~ ~_ o 8~~~~i Ii: N - ."AIII Sllf •• MILLIME TEllt .. l< !! ... • ~ • II: ... .. II: 4 0 u .... z .. u Ii: .. IL I I I • II I I , . • • • I I I I • ,. I I • I I • I • • I I • SIEVE PASS ------- ------ 3 2 ~----------- 1 1/2 ----- ]OQ_ 3/4 95 112 92 3/8 85 . ------- 4 69 10 46 20 31 40 22 100 9 200 4.4 0.02 MM Figure 6. Alluvial Fan Deposit I • I • I • - - - - - - - - - G. REFERENCES CITED Connelly, W. 1978, Uyak Complex, Kodiak Islands, Alaska: A Cretaceous subduction complex: Geological Society of America Bulletin, v. 89, p. 755-769. Coulter, H.W., and the Alaska Glacial Map Committee, 1962, Map showing the extent of glaciations in Alaska: u.S. Geologi- cal Survey Map 1-415. Pewe, T.L., 1975, Quaternary Geology of Alaska: u.S. Geological Survey Professional Paper 835, 145 p. -16- .... - .... - - ... LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX D DETAILED COST ESTIMATE ,.,. -TABLE OF CONTENTS -PAGE -A. GENERAL 1 -B. METHODOLOGY 2 -C. MOBILIZATION AND SUPPORT COSTS 3 D. UNIT PRICES 4 ~ .... ,,,,,,,otf' NBI-426-9523-TC .... - ..... .... APPENDIX D DETAILED COST ESTIMATE A. GENERAL This appendix presents the method, backup data, and assumptions used to estimate the cost of the recommended hydroelectric project. Following the presentation of the methodology are tables showing a breakdown of major cost items such as mobilization, labor and transportation. At the outset of the cost estimating procedure for the Larsen Bay Power Project, it was determined that the unit-cost estimating method for material placement and other construction activities confidence . would not provide sufficient accuracy and Development of construction cost estimates with this method uses unit prices developed from estimates and bid tabulations on similar projects under similar conditions, in terms of geo- graphic location, weather, accessibility and other factors that may affect the cost. When available unit prices are not similar in these respects, they must be adjusted to reflect the actual cost of the construction items under the specific conditions. For this project, it was felt that the available data base of unit prices was not sui tabl e. Typically, un i t prices on remote Alaskan construction projects vary widely and seem to depend heavily on a contractor's approach in scheduling crews, transportation, shipping, and work schedules. NBI-426-9523-AD 1 The cost estimate herein was prepared by using the heavy- construction estimating method and January 1982 costs. This method treats the project as a separate entity. The construc- tion cost computations are based on the use of construction equipment units, labor rates, labor productivity, working conditions, work schedule and sequence, subcontract prices, permanent material and equipment prices, and special con- straints and requirements. B. METHODOLOGY The preliminary design and layout of facilities was used to establish estimated quantities of permanent and consumable materials and other measurable items of work such as excavation and embankment quanti ties. A construction schedule was pre- pared for each major item of work, based on assumed production rates normally attainable under similar conditions. Considera- tion was given to the remote location, 60-hour work week, and short construction season. Construction equipment of appropriate size and type for each operation was selected with a view toward minimizing the number of pieces of equipment and using each piece to its optimum capacity. The manpower from the standpoint of crafts and the numbers of persons; hours of equipment operation; Quantities of consumable supplies and spare parts; subcontracted work; and the required permanent materials and equipment were estimated for each work i tern. The appl icabl e rates and pr ices were applied to produce direct costs of labor, equipment, and materials. It was assumed that all skilled construction personnel will be brought to the site by the contractors since it is not known whether local I abor will be avai I abl e. Tabl e 0-1 I ists the skilled personnel that will work on the project, and tabulates NBI-426-9523-AD 2 • .. • .. • .. • • • - • - • • lilt • .. • .. • .. • .. • • • • • • • .. • .. • • • • - .... - the number of man-weeks required for each craft. Also ind ica ted is the weekly wage for each craft. The wages are based on union scale, including benefits, current as of January 1982. A work week (man-week) consisting of six ten-hour days is assumed. If the contractor chooses to increase the number of working hours per man-week, the weekly wage will increase, but the overall labor cost will not, since the duration of the construction period will decrease accordingly. Also included in the work force are subcontracted person- nel. A heavy equipment moving crew will transport the turbine/generator assembly from the barge unloading site to the project site and install it in the final position. An erection crew will assemble and install the prefabricated metal powerhouse building on the concrete foundation. The transmission line subcontract labor force is not included in Table 0-1 and is excluded from the labor cost; however, the required camp cost to support this crew of eight is shown. A detailed breakdown of the transmission line subcontract is presented in Table 0-8. The subcontract amount is based on January 1982 costs for power lines connecting the potential hydroelectric si te to existing village power plants. Loads and distances can easily be handled with distribution vol tages (12.47 kV). Therefore, popular REA-type assemblies and conductors were assumed. A typical crossarm construction assembly is shown on Plate VI, Appendix A. Equipment costs presented in Table 0-2 are based on an hourly ownership rental for 21 weeks plus an hourly use rate for the actual hours used. The rates used are from actual costs of operating, include fuel costs owning, and maintaining equipment. They at Alaskan rates. Material costs are current costs for the items delivered to Seattle, Washington, at a barge departure point. They are shown in Table 0-3. NBI-426-9523-AO 3 C. MOBILIZATION AND SUPPORT COSTS Due to the remote location of the site, essentially all of the equipment, vehicles, and supplies required to construct the project will be transported to and from the si te by barge. Barges can operate from several points, including Seattle and Anchorage. The actual departure point would depend on the contractor's particular situation. This cost estimate is based on a barge departing Seattle in late April or early May, using material prices FOB Seattle and barge rates from Seattle to Larsen Bay (see Table D-4.) Barge time to the project site is approximately two weeks. Table D-4 summarizes barge shipping costs both to and from Larsen Bay. The construction workers and supervisory personnel will be housed in a construction camp set up specifically for this project. Table D-5 shows the overall cost, based on a uni t cost per person-day assuming that each man-week of labor will require support for one person for seven days. The cost includes mobilization and demobilization of the camp and all other supportive costs. Ai r t ransporta tion support costs are shown in Table D-5. These costs cover the trips that would be required for a project of this nature and an anticipated personnel turnover rate of about 20 percent. Table D-6 is a summary of all direct costs associated with the construction of the Larsen Bay project. A contingency of 15 percent and a markup of 15 percent for contracor overhead and profit are included. The cost of the transmission line is based on a subcontract cost that incl udes a cont ingency. As ind ica ted, it is marked up by 10 percent to cover the prime contractor's indirect expenses associated wi th scheduling and NB I -426-9523 -AD 4 • • • .. • • .. lilt .. .. • .. • • iii • .. .. • .. • ... • iii • • • • • • • • • • ... ..... - .... .... ..... responsible supervision. administrative costs are cost. ,D. UNIT PRICES Engineering and owner's legal and added to produce a total project Figure D-l is a construction schedule for the Larsen Bay Power Project. Based on a detailed analysis of the construc- tion activities and the information presented in Tables D-l through D-5, all of the direct costs were assigned to an appropr ia te category that represents a major item of work. Unit prices were calculated and these are presented in Table D-7. They take into account the assumptions previously used for production rates, support equipment, and supervisory effort. Page 2 of Table D-7 details the content of the various cost headings and item descriptions. Finally, a detailed breakdown of uni t prices, quanti ties, and total cost is presented in Table VI I I -1. These are based on the average unit costs for major categories presented in Table D-7 and modified to take into account the quantities, scheduling, and location within the project area of the specific item of work. Therefore some unit prices may vary for the same items used on different phases of the work. Note that the cost estimate prepared for this project was not based on the unit-cost method. The unit prices presented in this report are intended for use in presenting the general relationship and magnitude of the major construction items for this particular project. They should not be used out of context because they may not accurately represent the cost of performing similar work at other sites or under different circumstances. NBI-426-9523-AD 5 .... - ..... ,- - "' .. - ,- - .... TABLE 0-1 LARSEN BAY LABOR BASED ON 60 HR. WEEK Labor Cost/ (Man-Weeks) Week Total Cost General Superintendent 17 $1,986 $33,762 Superintendent (Cr ew A) 10 1,758 17,580 Operators (Crew A) 25 1,730 43,250 Oilers 10 1,575 15,750 Mechanics 10 1,730 17,300 Laborers (Crew A) 38 1,571 59,698 Dr i 11 e r / Po wd e r Man 3 1,603 4,809 Superintendent (Crew B) 10 1,986 19,860 Electrician 5 1,850 9,250 Ironworkers 5 1,840 9,200 Carpenters 9 1,637 14,733 Apprentice Carpenter 9 1,571 14,139 Operators (Crew B) 18 1,730 31,140 Millwrights 3 1,800 5,400 Finishers 4 1,571 6,284 Welders, Fitters 2 1,897 3,794 Laborers (Crew B) 31 1,571 48,701 Manufacturer's Rep 3 10,000 Line Crew (8) 16 Subcontract K. D. Bldg. Crew (3 ) 3 Subcontract 10,000 Heavy Equipmen t Moving Crew 3 Subcontract 25,000 TOTALS 234 Man Weeks $399,600 NB 1-411-9523 -0-1 CAT-D8K Front End Loader 966D Flatbed Truck Dump Truck (10 yd) Service/Fuel Truck Airtrack/Compressor Pickup Truck (2 ea) Backhoe -CAT 225 Welder Generator Generator Spare Hand Compactors (5 ea) Conc. Mixer Trailer Small Mixer (3 ea) Screening Plant 3" Water Pumps (3 ea) Fuel Tank, Bladder Cutting Torch, Set Misc. Equipment Pole Setting Truck Line Truck Office Trailer TABLE D-2 LARSEN BAY EOUIPMENT COST Ownership Total Hourly Expense Operating Operating Operating (23 wks) Hours Cost Cost $67,600 340 $103.22 $35, 100 18,800 240 30.06 7,210 4,100 240 14.57 3,500 8,350 240 16.87 4,050 10,850 360 17.20 6,200 23,350 180 27.00 4,860 3,250 ea 300 ea 12.69 ea 3,800 ea 24,900 300 20.37 6,110 1,100 80 5.51 440 510 540 .94 500 510 100 .94 100 1,800 ea 75 ea 1.00 ea 75 ea 2,000 125 2.50 310 250 ea 50 ea 1.00 ea 50 ea 9,300 220 23.75 5,225 500 ea 240 ea 1. 00 ea 240 5,000 300 2,000 Costs contained in transmission subcontract 3,000 600 1. 68 1,000 TOTAL Total Cost This Project $102,700 26,010 7,600 12,400 17,050 28,200 21,170 31,010 1,540 1,010 600 5,625 2,310 900 14,525 2,220 5,000 300 2,000 4 2 °00 $286,510 NBI-411-9523-D-2 I. I I I I ,. I. , I I I 'I I I I I ,. 'I • I I I 'I I I I. I. I I .... TABLE 0-3 LARSEN BAY -MATERIAL FOB SEATTLE - Uni t Item Quantity Uni t Price Amount --- 1. Cement Type I 1,840 Bags $ 4.73 $8,703 -2. Reinforcing Steel 21,160 Lb 0.35 7,406 3. Fiberglass Pipe -27" 2,475 Ft 44.30 56,483 ' .... 4. Steel Pipe -27" 1,425 Ft 45 64,125 5. 27" Dresser Coupl ings 36 Ea 300 10,800 .... 6. Welded Ring Girder 66 Ea 75 4,950 . ~4'i 7 • Prefabricated Steel Uni ts Steel Dam, 1,100 Lb 1. 50 1,650 Offtake Structure 3,500 Lb 1. 50 5,250 Sed imen t Basin 8,000 Lb 1. 50 12,000 .... 8 . Turbine Generator Assy. Includes Switchgear 1 Ea 320,000 9. Electrical & Mechanical Accessory Equipment and Materials 1 Lot $46,000 $46,000 .... 10 . Culvert Materials -50' 780 Lb 1.00 780 11. Blasting Powder 4,405 Lb 1. 00 4,405 , .. it 12. Steel B u i 1 din g Ki t 1 Ea 25,000 25,000 13. Forming Materials 1 Lot 7,500 7,500 -14. Misc. Structural Steel 1,300 Lbs 0.30 390 -MATERIALS FOB SEATTLE DOCK $575,500 - .... NBI -411-9523 -0-3 Haul Class A B C 0 E F G H I J I J Commodity Structural Palletized Lumber Poles TABLE 0-4 LARSEN BAY BARGE SHIPPING COST Seattle To Larsen Bay (Typical) Weight (lb) Steel 42,140 Cement 172,960 7,500 7,700 KO Metal Bldg 15,000 Steel Pipe, Cuvert 101,080 Misc. Wire, Hardware, etc. 24,105 Fiberglass Pipe 30,850 Large Equipment, M~chinery 390,500 Trailer 12~000 TOTAL ($/cwt) 8.24 6.93 8.00 8.00 12.50 8.24 24.32 16.48 12.00 25.00 Larsen Bay to Seattle (Return) Large Equipment, Machinery 301,000 12.00 Office Trailer 12~000 25.00 TOTAL NBI-411-9523-0-4 Cost ($) 3,472 11,986 600 616 1,875 8,329 5,860 5,084 46,860 3~000 $87,690 36,120 3~000 $39,120 • • • • • - • .. • -• ... • • • .. ., • • .. • .. • ... • ., • • • • • .. • .. • • • • - - - .... ..... "' ... ESTIMATE OF CAMP COSTS 226 Man-Weeks TABLE 0-5 LARSEN BAY Each week the men are supported for seven days 226 x 7 or 1582 days @ $135 per day CAMP COSTS TOTAL ESTIMATE OF AIR TRANSPORTATION COSTS Bring in crew and small tools -assume 6 men per flight and 24 men with a Beech King Air. 4 Trips Anchorage to King Cove and back @6 hrs/round trip 4 Trips @ $2500 Approximately 1500 lbs of freight via Reeve Aleutian and Air Taxi twice a week 3000 lbs @ $0.75/lb or $2250 per week 10 Weeks @ $2250 40 One Way Trips during construction for per- sonnel changes & supervisor visits 32 Trips @ $282 Misc. Supply Trips 4 Trips Queen Air Cargo Remove crews at job close AIR TRANSPORTATION TOTAL NB I -411-9523 -0-5 $213,570 $10,000 22,500 9,024 10,000 10,000 $61,520 Material FOB Seattle Labor TABLE D-6 LARSEN BAY SUMMARY SHEET Transportation -Barge to Site Transportation -Barge to Seattle Transportation -Air Camp Costs -Catered Equipment Cost Prime Contractor 15% Profit Contingency 15% Transmission Line -Electrical Labor & Materials Subcontract Prime Contractor 10% Markup Surveying, Right-of-Way & Geology Engineering Design Construction Management Owner's Legal & Admin. Costs 3% Subtotal Subtotal Subtotal Subtotal GRAND TOTAL NBI-411-9523-D-6 $ 575,500 399,600 87,690 39,120 61,520 213,570 286 2 510 1,663,500 249 2 520 1,913,020 286,950 172,000 17,200 2,389,200 50,000 175,000 125 2 000 350,000 82 2 200 $2,821,400 • • .. • • -.. • .. .. .. .. .. • • .. .. .. .. .. • .. .. .. • • • .. • .. • • • .. • .. • • I TABLE D-7 LARSEN BAY ( I DEVELOPMENT OF AVERAGE UNIT PRICES FOR MAJOR ITEMS OF WORK 1/ Material Labor Equipment Contractor Total Item Cost Cost Cost Profit (15% ) Amount Quantity 1-Mobil/Demob. $151,90oY $ 73,600 $ 54,090 41,950 $321,600 2. Penstock -Steel 88,730 46,720 13,980 22,410 171,840 1,425 3. Penstock -Fiberglass 61,560 42,660 47,240 22,720 174,180 1,275 4. Rock Exc. 4,410 62,620 154,020 33,160 254,210 4,671 5. Road Exc. , Conunon 0 4,600 13,410 2,700 20,710 600 6. Culvert Pipe 840 1,200 1,000 460 3,500 50 7. Gravel Fill -Road 0 8,200 5,700 2,090 15,990 630 8. Concrete 37,470 158,660 14,880 31,650 242,660 185 9. Transmission LineY 2,080 15,120 0 2,580 19,780 10. Prefab Steel Bldg. 26,880 12,840 1,420 6,170 47,310 11. Turbine & Generator 369,990 135,990 8,030 77,100 59,110 12. Prefab Steel Structures 19,950 17,850 5,800 6,540 50,140 12,600 TOTALS $249,520 $ 1 , 91 3 , 02 o.!! 1/ These items are described on page 2 of this table. 2/ Includes Barge and Air Support Costs only. 3/ Includes costs over and above subcontract amount only. 4/ Amount corresponds with second subtotal on Table D-6. NBI-411-9523-D-7 Unit Unit Price LS $ LF 121 LF 137 CY 54 CY 35 LF 70 CY 25 CY 1,312 LS LS LS LB 3.98 ITEM 1. Mobilization/Oemob 2. Penstock, Steel 3. Penstock, Fiberglass 4. Rock Excavation 5. Road Exc. , Common 6. Culverts 7. Gravel, Road 8. Concrete 9. Transmission Line TABLE 0-7 (Cont'd) Includes general supervIsIon, barge and air support costs, staging equipment, miscellaneous standby equipment, etc. Installed, including couplings, ring girders, excavation & back- fill (unclassified). Installed, including bedding, excavation & backfill (unclass- ified) . All, including road, penstock route and structural. Unclassified road excavation, including placement as fill where used. Installed. Road fill, borrow, including haul. All, including equipment, material, cement, forming, miscellaneous structural excavation (unclassified) & reinforcing steel. Installed -Subcontract plus shipping, and camp costs. 10. Prefab Steel Bldg. Installed. 11. Turbine & Generator Installed, including mechanical, electrical, and startup. 12. Prefab Steel Structures Installed, including structural excavation for diversion dam. COLUMNS Material Cost Material cost FOB Seattle plus shipping. Labor Cost Salary at 60 Hrs/week plus subsistence costs. Equipment Cost Ownership rental plus use rental, based on six months. NBI-411-9523-~7 I. I. f. I I I I I 1 I. •• • I I I 'I 'I r I I. ,. I I I I 'I I I .- - - .... - - ..... - ...... TABLE D-8 LARSEN BAY BREAKDOWN OF TRANSMISSION LINE SUBCONTRACT Item Poles Crossarms, Insulators & Guys Wire Subtotal, Overhead Transformers, Pads & Sectionalizing Equipment Subtotal Contingency: 25% Labor 10% Materials Subtotal Equipment Mobilization Misc. Crew Transportation & Supervision Total Say Material Cost 2,800 2,285 2,218 7,303 39,800 47,103 Laborl.! Cost 11,900 6,450 11,880 30,230 22,100 52,330 Total Cost 14,700 8,735 14,098 37,533 61,900 99,433 13,083 4,710 117,226 50,000 4,800 172,026 $172,000 1/ Based on 75 $/man hour and 425 $/crew hour for a 5 man crew, including: 1 backhoe, 1 line truck with digger, 1 crew cab pickup, and wire stringing equipment. NBI-411-9523-D-8 i Activity I. Barge T rave I 2. Mobllization/Demobi Ilzatlon a. Set Up Camp/Demobilize b. Stage Material 3. Road Construction & Penstock Route 4. Penstock Construction a. Underground b. Steel c. Testing 5. Powerhouse a. Concrete Work b. Set Turblne-Generator c. Erect Building d. Mechanical & Electrical e. Startup 6. Diversion Site a. Concrete Work b. Set Prefab Steel 7. Cleanup 8. Transmission Line I I FIGURE 0-1 LARSEN BAY CONSTRUCTION SCHEDULE Week 2 3 4 5 6 7 8 9 10 11 12 13 ... - - .... ... - ..... .... "",. LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX E ENVIRONMENTAL REPORT _. - ..... - - ... .... - ,... - A. B. C. D • E. F. G. H. I. J. K • L. M. N. O. P. Q. R • S. T. U. V. W. x. PROJECT DESCRIPTION SCOPE OF WORK HYDROLOGY FISHERIES TABLE OF CONTENTS CURRENT UTILIZATION OF FISHERY RESOURCES PHYSICAL STREAM DESCRIPTION FISHERY H1PACTS FISHERY MITIGATION WILDLIFE CURRENT UTILIZATION OF WILDLIFE RESOURCES ENDANGERED SPECIES WILDLIFE IMPACTS WILDLIFE MITIGATIO~ VEGETATION ARCHAEOLOGIC AND HISTORIC SITES POTENTIAL VISUAL IMPACTS IMPACT ON RECREATIONAL VALUES AIR QUALITY SOCIOECONOMIC IMPACTS LAND STATUS PERMITTING REQUIREMENTS RECOMMENDATIONS REFERENCES CITED PERSONAL COMMUNICATIONS i • ••• e. Page 1 1 3 5 6 7 7 9 10 11 20 20 22 23 24 24 24 24 25 26 27 30 31 31 Figure 1 Tables 1 2 3 4 LIST OF FIGURES Project Location Map LIST OF TABLES Water Quality Data, 1981 3 Species and Number of Fish Caught in Humpy Creek 5 Terrestrial Mammals of the Kodiak Island Archipelago ••••••.••••.••••.••••..•••.• 12 Birds of the Kodiak Island Archipelago 13 LIST OF PHOTOGRAPHS Photographs 1 Proposed Dam Site 2 3 4 Cannery Dam, Built in 1923 .................... Stream Section Between the Proposed Powerhouse Site and the Existing Dam ...••.••••.••••.••• Intertidal Zone, Humpy Creek .................. ii 2 2 8 8 • • • III --.. • • ... .. • • • • • .. • • -.. • • .. .. • • III .. • .. • • .. • .. - .... - - - - - - .. - - - - - .... - .... A. PROJECT DESCRIPTION A diversion weir is proposed at an elevation of 325 feet (MSL) on Humpy Creek for a run-of-the-river hydroelectric proj- ect with a power output of 270 kilowatts. Water would be diverted into a penstock, leading to the powerhouse located just below the old cannery dam. A trail, passable by three- wheeled vehicles, will be constructed from the powerhouse to the diversion weir. A transmission line will lead from the powerhouse to Larsen Bay. B. SCOPE OF WORK As contracted with the Alaska Power Authority, environ- mental studies were to include an initial two-day reconnais- sance visit, followed by a three-to four-day trip for more de- tailed studies. Li terature review and discussion with local residents and agency members were to be combined with field studies to obtain information on fish and wildlife resources in the area and effects of the project on these resources • Hydrology, land status, archaeologic and/or historic sites, and permitting requirements were to be briefly dis- cussed, as well as impacts on recreational values, air quality, socioeconomics and scenic viewpoints. The reconnaissance visit occurred on September 18, 1981, and a more detailed site investigation occurred October 23-24, 1981. Humpy Creek was walked for most of its length and minnow were traps placed in selected locations. Numbers and locations of wildlife and wildlife sign were noted. Local residents were contacted through a community meeting on September 20, 1981, and through discussions with individual s during both visits. Photos 1 and 2 show the proposed dam site on Humpy Creek and the abandoned cannery dam. -1- ... - ....... - .... - - .... - ..... .... .- The Alaska Power Authority held an informational meeting to discuss four potential hydropower sites, including Larsen Bay, with interested federal, state and local organizations in Anchorage on October 21, 1981. Additional contacts were made by DOWL with state and federal agencies on an individual basis during September, october and November. C. HYDROLOGY Humpy Creek originates from the mountainous terrain south of Larsen Bay and flows in a northerly direction through the communi ty of Larsen Bay. The creek is about 4.5 miles long. It discharges into Larsen Bay after draining an area of 6.28 square miles at the proposed dam site. A year of streamflow data exists for Humpy Creek. The long-term mean annual flow is estimated to be 12.7 cubic feet per second at the dam site. Based on the discharge records, May and October appear to be peak runoff periods: the former is due to snowmelt and the latter is due to rainstorms. The base- flow, which is the groundwater contribution to the streamflow, ranges from cubic feet per second and occurs in winter and dry summers (July and August). The mean annual flood can exceed 60 cubic feet per second. Additional information on hydrology can be found in Appendix B. Water quality information for Humpy Creek is given in Table 1, and sampling locations are shown in Figure 1. Date 10/24 10/24 TABLE 1 WATER QUALITY DATA, 1981 Location Temp. D.O. (oC) ~ (mg/l) Cannery Dam 4.1 7.2 12.8 Above the Culvert 4.8 6.7 12.2 -3- Conductivity Micromhos/Cm 56 55 ..... - - Hfit ..... .- - -- D. FISHERIES Alaska's Fisheries Atlas, Volumes I & II (ADF&G, 1978a), lists pink salmon and Dolly Varden char as the only fish spe- cies present in Humpy Creek. Local residents confirmed this information. Ken Manthey, Kodiak Area Management Biologist (personal communiciation, 1981), stated that runs of pink sal- mon occur each year, but that the strongest run occurs during odd years. Escapement counts for Humpy Creek have been sporad- ically taken by ADF&G. In 1977, 12,075 pinks were counted during a foot survey, and in 1981 600 pinks were counted in an aerial survey. Approximately 25 adult pink salmon were observed in Humpy Creek above the culvert on September 18, 1981. Dolly Varden char were caught in minnow traps throughout the stream, and juvenile silver salmon were caught in two locations (Table 2). TABLE 2 SPECIES AND NUMBER OF FISH CAUGHT IN HUMPY CREEK October 23-24, 1981 Location Juveniles Caught 30 yards above the road 4 Dolly Varden 10 silver Salmon 230 yards above the road 11 Dolly Varden 400 yards below existing dam 20 Dolly Varden 23 Silver Salmon 200 yards below existing dam 5 Dolly Varden 100 yards above existing dam 1 Dolly Varden Pink salmon normally spawn intertidally or in the lower reaches of short coastal streams. Medium-sized gravel -5- (0.6 to 0.3 inch) is preferred, with an optimum stream flow velocity for spawning of 0.1 ft./sec. or greater (ADF&G, 1978a). In Humpy Creek, it appears that most of the spawning .occurs intertidally and within the first 100 yards above the culvert of the road. Local residents stated that only in years with large runs do a few pink salmon get upstream as far as the diversion dam. This dam, built in 1923, has a 10 foot fall that prevents upstream fish passage. Pink salmon migrate to saltwater immediately upon emergence. Silver salmon generally spawn at the head of riffles in shallow, swift flowing streams or tributaries. flow velocity during spawning is 3.4 ft./sec. Optimum stream (ADF&G, 1978a). When first emerged, juvenile silvers frequent near-shore areas wi th gravel substrates. Older juveni les prefer deeper pool s and avoid riffle areas. In Humpy Creek, juvenile silvers occur predominately in still or slow-moving water. Dolly Vardens spawn in medium to large gravel (1.3 to 0.3 inches) in a fairly strong current, usually near the center of the stream in at least a foot of water (ADF&G, 197 8a) . Juvenile Dolly Vardens are relatively inactive, often remaining on the stream bottom in pools or eddies under rocks and logs or undercut banks. Dolly Varden occur in both anadromous and non- anadromous populations. If anadromous, juveniles spend three to four years in their natal stream before entering saltwater. E. CURRENT UTILIZATION OF FISHERY RESOURCES Larsen Bay residents have traditionally gathered a large portion of their diet from the sea and they continue to do so today, al though to a lesser extent. Al though no figures are available for the total annual catch, local residents indicated that a subsistence harvest for pink salmon occurs in Humpy Creek. -6- • .. • - • ... • .. • • • ... • • • ... • • • -• .. • .. • .. • • • .. • • • ... • .. • • - ..... - ..... - F. PHYSICAL STREAM DESCRIPTION Humpy Creek can be divided into two sections based on the type of fishery habitat. Section 1 extends from the headwaters to about 100 yards below the existing dam. Section 2 includes all portions of the stream below this point. Photos 3 and 4 show Humpy Creek in the proposed project area and in an inter- tidal zone. In Section 1, the stream flows through a lOa-foot wide gorge with steep gradients. The streambed is primarily com- posed of boulders and bedrock shelves, with intermittent pockets of gravel. Behind the dam, deposited gravel and sand extend 150 feet upstream. The deposits have built up to within three feet of the top of the dam. The lower stream (Section 2) has a slower flow velocity and a gravel substrate of slate fragments. Substrate size ranges from sand to cobbles six inches in diameter, with a median size of one to two inches. Above the cuI vert, the frequently undercut banks are lined with grass and willow. The stream width varies from 6 to 10 feet and the maximum depth is approximately 18 inches. Below the bridge, the stream is tid- ally influenced, and forms a broad channel with a maximum depth of approximately eight inches. Humpy Creek has no established use as navigable or public waters. G. FISHERY IMPACTS Construction activity may temporarily increase erosion and sedimentation in Humpy Creek. Sedimentation could affect fish by interfering with or preventing respiration of incubating eggs, through loss of spawning gravel, and through physical -7- ..... - disturbance to both adult anadromous fish and resident species. These effects could lead to a decrease in returning salmon runs to Humpy Creek. However, proper construction techniques and timing can minimize these impacts. The portion of Humpy Creek between the diversion weir and the powerhouse may be dewatered during low flows, and a major reduction in flow will occur during plant operations. This reduced flow may seasonally prevent fish from util izing this stream section. The diversion weir will also prevent passage of resident fish. However, impacts are considered to be minor since onl y small numbers of Dolly Vardens were found in this section of the stream. No changes in water quality are anticipated due to opera- tion and maintenance of this power project. H. FISHERY MITIGATION The following measures should be followed to reduce ero- sion and sedimentation of area streams: Construction should be done during a single sum- mer. This should reduce the opportunity for ero- sion of exposed soil. Instream work should be scheduled during low flow periods to reduce the amount of stream bed disturbance. To avoid the introduction of suspended solids by road traffic, the access road should cross as few tributary streams as possible, and culverts should not be allowed to flow directly into streams. Streams should be crossed with small -9- I. log bridges or culverts, whichever would provide the best protection to streamside vegetation. A vegetated buffer zone should be left between all access roads and the streambank. All areas disturbed during construction activ- ities should be stabilized to reduce erosion. Any organic soils excavated during construction should be stockpiled and spread over disturbed sites to encourage revegetation. Waste petroleum and wastewater should be dis- posed of in an environmentally sound manner and a plan for safe storage, use, and clean-up of oil and gas used in project construction and operation should be prepared following state and federal oil spill contingency plans (40 CFR 112.38, December 11, 1973). WILDLIFE Local residents stated that brown bear, river otter, fox, and weasel all commonly use the Humpy Creek drainage. Si tka black-tailed deer are abundant in the Larsen Bay area. The Humpy Creek drainage supports deer all year, but because of the generally northerly exposure, it is probably not a major wintering area (Smith, 1981). The north-south ridge between Karluk Lake and Uyak Bay from which Humpy Creek drains is good deer habitat (stratton, 1981). This same ridge is also an important brown bear denning area (Stratton, R. Smith, 1981). -10- • • • - • ... • -• -• -• .. • • • -• • - • • -• • • • • -• - • .. - - , .... - - The following is excerpted from a letter from Roger Smith, ADF&G Area Managment Biologist, Division of Game: Brown bear are constant visitors in Larsen Bay during the summer. They fish for salmon in the lower reaches of the creek mainly in July and August. Re- ports received from villagers during the summer of 1980 indicated that 15 or more bears were frequenting the creek and the village dump. My estimate is that 10-15 bears frequent the hydro project location. Denning occurs in all the higher mountains in the Larsen Bay area. Usually dens are located at eleva- tions above 300-400 feet with a preference for north facing slopes. The mountain under consideration for a diversion dam probably is used for denning, but most dens are probably above 700 feet. During DOWL field studies, numerous bear trails were ob- served on the west bluff above the creek, along the creek, and leading from the bluff down to the stream. The east bluff had considerably fewer trails. Eight bald eagle nests have been recorded in the Larsen Bay drainage (Zwiefelhofer, 1981). Although no nests have been identified along Humpy Creek, the mouth has been documented as a feeding area for bald eagles. Rough-legged hawks probably nest in the upper project area (Zwiefelhofer, 1981). An unnamed seabird colony containing glaucous-winged gulls, black-legged kittiwakes and tufted puffin is located on Amook Island within five miles of the project (ADF&G, 1978b). A list of mammals found for Kodiak Island Archipelago is given in Table 3 and a list of birds is given in Table 4. J. CURRENT UTILIZATION OF WILDLIFE RESOURCES Roger Smith, Area Management Biologist for the Alaska Department of Fish & Game, Game Division, on Kodiak Island, had -11- TABLE 3 TERRESTRIAL MAMMALS OF THE KODIAK ISLAND ARCHIPELAGO INDIGENOOS SPECIES Little Brown Bat Tundra Vole Red Fox Brown Bear Short-tailed Weasel Land Otter INTRODUCED SPECIES Snowshoe Hare Arctic Ground Squirrel Norway Rat House Mouse Northern Red Squirrel* Marten* Beaver Muskrat Roosevelt Elk* Sitka Black-tailed Deer Mountain Goat Dall Sheep * Introduced to Afognak Island -12- SCIENTIFIC NAME Myotis luncifugus Microtus oeconomus Vulpes vulpes Ursus arctos Mustela erminea Lutra canadensis SCIENTIFIC NAME Lepus americanus Citellus parryi Rattus norvegicus r1us musculus Tamiasciurus hudsonicus Martes americana Castor canadensis Ondatra zibethicus Cervus canadensis Odocoileus hemionus Oreamnos americanus Ovis dalli • ---- • -. • - • -• • • -• • -• ., • • • • -• • • • • ... • -• • ''"¢". TABLE 4 ''M?i BIRDS OF THE KODIAK ISLAND ARCHIPELAGO - A -Abundant ~ ... ,.,. S -Spring, March-May C -Common S -Summer, June-August U -Uncommon F -Fall, September-November R -Rare W -Winter, December-February ..... + -Casual * -Nesting ..... SPECIES SCIENTIFIC NAME S S F W Common Loon Gavia immer U U U U Yellow-billed Loon Gavia adamsii R R U Arctic Loon Gavia arctic a U U U Red-throated Loon Gavia stellata U U U U Red-necked Grebe Podiceps grisegena U + U U Horned Grebe Podiceps auritus U U U Short-tailed Albatross Diomedea albatrus + + Black-footed Albatross Diomedea nigripes C C C Laysan Albatross Diomedea immutabilis U U U Northern Fulmar Fulmaris glacialis C C C C Pink-footed Shearwater Puffinus creatopus + Flesh-footed Shearwater Puffinus carneipes + + New Zealand Shearwater Puffinus bulleri + + Sooty Shearwater Puffinus griseus A A A U .','1i Short-tailed Shearwater Puffinus tenuirostris A A A U Manx Shearwater Puffinus puffinus + Scaled Petrel pterodroma inexpectata U U U .. ~"I/I Fort-tailed Storm-petrel Oceanodroma furcata C C C C Leach's Storm-petrel Oceanodroma leucorhoa U U U f~ Double-crested Cormorant Phalacrocorax auritus U U U C Pelagic Cormorant Phalacrocorax pelagicus C C C C Red-faced Cormorant Phalacrocorax urile C C C U --- Great Blue Heron Ardea herodias + + + + --- #~ -13- .. • • - TABLE 4 • Continued - • -SPECIES SCIENTIFIC NAME S S F W • Whistling Swan Olor columbianus C C C R -Canada Goose Branta canadensis U U + Brant Branta bernicla A + + + • Emperor Goose Philacte canagica C U C - White-fronted Goose Anser albifrons U U • Snow Goose Chen caerulescens + -Mallard Anas platyrhynchos A A A A • Spotbill Duck Anas poecilorhyncha + -Gadwall ~ strepera U U U U Pintail Anas acuta A C C U • ----- Green-winged Teal C C C U .. Anas crecca Blue-winged Teal Anas discors R • Northern Shoveler Anas clypeata C R R + -European Wigeon Anas penelope U R R • American Wigeon Anas americana C C C U -Canvasback Aythya valisineria + + + • Redhead AXthX a americana + + + .. Ring-necked Duck Aythya collaris R R R Greater Scaup Ayth;ta marila A C A A • Lesser Scaup AythXa affinis R R R - Tufted Duck Axthya americana + + -Common Goldeneye Bacephala clangula C U C C .. Barrow's Goldeneye Bucephala islandica C U C C • Bufflehead Bucephala albeola C + C C • Oldsquaw Clangula hyemalis A + A A Harlequin Duck Histrionicus histrionicus A C A A • Steller's Eider Polysticta stelleri C + U C .. Common Eider Somarteria mollissima U U U U • King Eider Somateria spectabilis C R U C -Spectacled Eider Somateria fischeri + • White-winged Scoter Melanitta deglandi A U A A • -14-• • TABLE 4 Continued SPECIES Greater Yellowlegs Lesser Yellowlegs Solitary Sandpiper Spotted Sandpiper Wandering Tattler Ruddy Turnstone Black Turnstone Northern Phalarope Red Phalarope Common Snipe Short-billed Dowitcher Long-billed Dowitcher Surfbird Red Knot Sanderling Semi-palmated Sandpiper Western Sandpiper Least sandpiper Baird's Sandpiper Pectoral Sandpiper Sharp-tailed Sandpiper Rock Sandpiper Dunlin stil t Sandpiper Buff-breasted Sandpiper Ruff Pomarine Jaeger Parasitic Jaeger Long-tailed Jaeger South Polar Skua Glaucous Gull TABLE 4 Continued SCIENTIFIC NAME Tringa melanoleuca Tringa flavipes Tringa solitaria Actitis macularia Heteroscelus incanus Arenaria interpres Arenaria melanocephala Phalaropus lobatus Phalaropus fulicarius Gallinago gallinago Limnodromus griseus Limnodromus scolopaceus Aphriza virgata Calidris canutus Calidris alba Calidris pusilla Calidris mauri Calidris minutilla Calidris bairdii Calidris melanotos Calidris acuminata Calidris ptilocnemis Calidris alpina Micropalama himantopus Tryngites subruficollis Philomachus pugnax Stercorarius pomarinus Stercorarius parasiticus Stercorarius longicaudus Catharacta maccormicki Larus hyperboreus -16- S C + R C R C C U C C + C + R R A R C C C C U R S C C + u C R C C U C C + u + R A A U U u R + + C C U + + F C C R u R U C U C U R u R U R R C C C U + + C C U R W u R u R + C U R • .. • -----.. • -.. • .. • .. -• • • • • --- • .. • • • -• -• • ..... SPECIES Glaucous-winged Gull .. " Slaty-backed Gull Herring Gull -Thayer's Gull Ring-billed Gull , .... Mew Gull Bonaparte's Gull Black-legged Kittiwake Red-legged Kittiwake Sabine's Gull ... ,.1/ Arctic Tern Aleutian Tern ,*,,-,"; Common Murre Thick-billed Murre Pigeon Guillemot Marbled Murrelet Kittlitz's Murrelet ,0'.1lf Ancient Murrelet Cassin's Auklet Parakeet Auklet Crested Auklet Least Auklet Rhinoceros Auklet Horned Puffin ml>'" Tufted Puffin Morning Dove '>110.811 Snowy Owl Hawk Owl .~.,. Short-eared Owl Boreal Owl Belted Kingfisher _lii:!l TABLE 4 Continued SCIENTIFIC NAME Larus glaucescens Larus schistisagus --- Larus argentatus Larus thayeri Larus delawarens is Larus canus Larus philadelphia Rissa tridactyla Rissa brevirostris Xema sabini Sterna paradisaea Sterna aleutica Uria aalge Uria lomvia Cepphus columba Brachyramphus marmoratus Brachyramphus brevirostris Synthliboramphus antiguus Ptychoramphus aleuticus Cyclorrhynchus psittacula Aethia cristatella Aethia pusilla Cerorhinca monoccrata Fratercula corniculata Lunda cirrhata Zenaida macrovra Nyctea scandia Surnia ulula Asio flammeus Aegolius funereus Megaceryle alcyon -17- S S F W A A A A + + R R R R R R R + C C A A U U U A A A U + + + + U U U C C R U U C C A A R R R R C C C C C C C C R R R R U U R R U U U R R R + + C A + + + + R R R R C C C R A A A R + + + + U U U U U U U R C C C C C C C C SPECIES Common Flicker Yellow-bellied Sapsucker Hairy Woodpecker Downy Woodpecker Northern Three-toed Woodpecker Eastern Kingbird Horned Lark Violet-green Swallow Tree Swallow Bank Swallow Barn Swallow Cliff Swallow Black-billed Magpie Common Raven Northwestern Crow Black-capped Chickadee Red-breasted Nuthatch Brown Creeper Dipper Winter Wren American Robin varied Thrush He:rmit Thrush Gray-cheeked Thrush Golden-crowned Kinglet Ruby-crowned Kinglet Water Pipit Bohemian Waxwing Northern Shrike starling Orange-crowned Warbler TABLE 4 Continued SCIENTIFIC NAME Colaptes auratus Sphyrapicus varius Picoides villosus Picoides pubescens Tyrannus tyrannus Eremophila alpestris Tachycineta thalassina Iridoprocne bicolor Riparia riparia Hirundo rustica Petrochelidon pyrrhonota Pica pica Corvus corax Corvus caurinus Parus atricapillus Sitta canadensis Certhia familiaris Cinclus mexicanus Troglodytes troglodytes TUrdus migratorius Ixoreus naevius Catharus guttatus Catharus minimus Regulus satrapa Regulus canendula Anthus spinoletta Bombycilla garrulus Lanius excubitor Sturnus vulgaris Vermivora celata -18- S S F W + + + + + C C C C Picoides tridactylus + C C U C C C C U C C C R C A R A C C + C C C A R + C C C C U C C C R C A C A + C C C + R R U C C C C U C C C R C C A + C R C + R C C C C U C C C R U A + + R C + • • • .. -- • .. .. - • .. -• .... • • --- • ., • --.. • • • • • -• -• • ..... -SPECIES Yellow Warbler -Yellow-rumped Warbler Blackpoll Warbler -Wilson's Warbler Red-winged Blackbird • .,.:16 Rusty Blackbird Brambling Pine Grosbeak ..... Gray-crowned Rosy Finch Hoary Redpoll "'."'; Common Redpoll Pine Siskin "'*'~# Red Crossbill White-winged Crossbill Savannah Sparrow Dark-eyed Junco Tree Sparrow Harris' Sparrow White-crowned Sparrow Golden-crowned Sparrow White-throated Sparrow Fox Sparrow Lincoln's Sparrow Song Sparrow <>i1l'9111 Lapland Longspur Snow Bunting " .. McKay's Bunting TABLE 4 Continued SCIENTIFIC NAME Dendroica petechia Dendroica coronata Dendroica striata Wilsonia pusilla Agelaius phoeniceus Euphagus corolinus Fringilla montifringilla Pinicola enucleator Leucosticte tephrocotis Carduelis hornemanni Carduelis flammea Carduelis pinus Loxia curvirostra Loxia leucoptera --- Passerculus sandwhichensis Junco hyemalis Spizella arborea Zonotrichia querula Zonotrichia levcoEhrys zonotrichia atricapilla zonotrichia albicollis Passerella iliaca Melospiza albicollis Melospiza melodia Calcarius lapponicus Plectrophenax nivalis Plectrophenax hyperboreus -19- S S F W R C R R U R + U A U + R R R + C C C C U U U U + C C C C C C C C R R R R C C C C A A A + R + U U U U U + + + R + R R A A C R + A A C R + + C C C C A A C + C C C C + the following comments (personal communication, 1981). Most of the local hunting effort does not occur near the proposed proj- ect site. Hunters generally use skiffs to hunt across Larsen Bay and Uyak Bay. Some hunters from Kodiak and other Alaskan loca tions al so hunt from Larsen Bay. Because Larsen Bay is incl uded in a much larger area for harvest compilations, no exact figures are available. Based on local estimates, an annual harvest of 50 deer occurs in the Larsen Bay drainage, and at least another 50 to 100 deer are probably taken by local residents from Uyak, Zachar and Spiridon Bays. Both red fox and land otter are hunted and trapped near Larsen Bay, but most of the trapping occurs in Uyak Bay. Occasionally locals trap, but most of the harvest is taken by Kodiak residents. Larsen Bay falls within two river otter har- vest areas. The village is included with Karluk Lake, where 35 otters were reported in 1981. Sixty-five otters were taken from Zachar Bay to the south side of the entrance of Larsen Bay. The take of otters only from Larsen Bay drainages prob- ably is less than 15 otters per year. K. ENDANGERED SPECIES No endangered species or subspecies are known to occur on Kodiak Island (Money, 1981). Peales peregrine falcon, the non- endangered subspecies, does nest on Kodiak Island. Both endan- gered subspecies of peregrine falcon have been reported to winter on Kodiak Island, but this has not been verified. Peregrine falcons were trapped and observed by U. S. Fish and ~Vildlife Service biologists during the winter of 1980-81, but they were all the nonendangered subspecies (Amaral, 1982). L. WILDLIFE IMPACTS Project construction will result in permanent habitat loss in the dam site vicinity, powerhouse location, and along the -20- • -• .. -- • --.. • -• .. • .. • -• - • .. • • • ----.. • • • -• - • • - - - ...... .... "' ... access route to the dam site. Due to the small size of the project, this loss is expected to be minimal. Temporary habi- tat alteration will occur at equipment staging areas, the camp si te, and in the transmission 1 ine right-of-way. Few adverse impacts are anticipated from gravel removal for project con- struction because an existing borrow site will be used. Operation of heavy equipment and other construction activ- ities will create considerable noise and may also result in disturbance of wildlife and temporary abandonment of tradi- tionally used areas. Since all construction activity should occur within a six-month period and the project area is close to town, project construction should not have a major impact • During project operation, alternations in the flow regime between the diversion weir and the powerhouse may force water- dependent animal s such as the water ouzel to relocate. Some minor mortality to birds may result from colI is ions with the transmission line. A major potential impact from construction of a hydropower facility would be disturbance to wildlife if the route to the diversion dam allowed access above the alder zone. The use of three-wheeled vehicles and snowmachines is a popular sport in Larsen Bay. Once above the alder zone, these recreational vehicles could probably be taken the entire length of the ridge between Karluk Lake and Uyak Bay. This area is good deer habitat and an important denning area for brown bear. Both Roger Smith, Game Biologist with the Alaska Department of Fish and Game, and Bob Stratton, Refuge Manager for Kodiak National wildlife Refuge, felt that the use of recreational vehicles on this ridge would create serious disturbances to wildlife which could result in the desertion of -21- dens by bears and foxes and might al ter the distribution or movements of deer and other animals. Current plans have the road terminating in a very narrow portion of the Humpy Creek drainage where it appears that ex- tension of the road would require blasting and tree removal. M. WILDLIFE MITIGATION The proposed project is on such a small scale that most impacts such as disturbance of wildlife during construction will be minor and short term. To further minimize impacts, the following guidelines should be followed: If an on-site construction camp is required, all structures and equipment should be removed upon con- struction completion. The ground should be graded to its original contours and revegetated with natural vegetation. The material site should be operated in accordance with OSHA and the Mine Safety and Health Administra- tion standards. the side slopes stable condition When gravel extraction is complexed, should be returned to a long term (3: 1 or greater). Care should be taken to insure proper drainage at all times. No feeding of wildlife should occur. All refuse should be placed in metal containers with heavy lids, incinerated on site on a regular basis, and the nonburnable remains removed to an existing landfill. If problems \vi th bears or other wildlife do arise, the appropriate Alaska Department of Fish & Game officials should -22- • - --- • ------.. -,. .. • ---.. ... • • -----., • .. • - • - - .... .... be contacted and handling of the problem should follow their recommendations. Hunting or fishing in the project area should not be per- mitted by the contractor or construction workers during con- struction. A minimum 330-foot buffer of no construction activity should be established around active eagle nests and where pos- sible a seperation of 500 feet should be maintained. In addi- tion, the Alaska Department of Fish and Game strongly dis- courages siting of construction camps, material sites, and other high activity areas within one-quarter mile of an active eagle nest. Restrictions may include prohibiting fixed-wing aircraft from coming within a radius of 500 feet, and heli- copters from coming within a radius of 1,500 feet of the air- space surrounding active nests. The transmission line should be designed to minimize large raptor electrocution. Use of the project road by any vehicle other than main- tenance vehicles should be prohibited. N. VEGETATION Birch is the dominant tree throughout most of the Humpy Creek drainage except in outwash plains where it is replaced by cottonwood. The understory varies with the density of canopy cover, with the following species predominant: elderberry, highbush cranberry, rose, lady and fiddlehead fern, and scat- tered alder and willow • -23- O. ARCHAEOLOGIC AND HISTORIC SITES An archaeologic site has been identified at the mouth of Humpy Creek, and numerous sites are known to exist throughout Larsen Bay and the surrounding region (Dilliplane, 1981). The Division of Parks has recommended that an archaeological survey be done in this area before project construction begins. P. POTENTIAL VISUAL IMPACTS The transmission line is the only component of this proj- ect which may be visible from town. An existing road will provide access to the powerhouse, which should be screened from view by the surrounding vegetation. The diversion weir, pen- stock and route to the diversion weir should be concealed from view from the town by the narrow, meandering stream cut. Q. IMPACT ON RECREATIONAL VALUES Project construction and operation should have little effect on recreational values. The route to the diversion weir may provide additional area for the use of three-wheeled vehicles. R. AIR QUALITY During project construction, exhaust fumes from diesel equipment and dust generated by construction activity may im- pact air quality. Dispersion of air pollutants is expected to be adequate to prevent any significant impacts to air quality in the area. Electrical power for Larsen Bay is currently provided by diesel generators. Particulate emissions from the combustion of diesel fuel have a high proportion of particles with a very -24- - ---- • - • - • ---• ., • ---• -• • • ---• ., • • • • • • • • .... ~, .. ..... ..... small size fraction. These smaller particles penetrate deeper into the lungs and are therefore more hazardous to health than emissions from the combustion of other hydrocarbon products. Replacement of the diesel generating facilities by hydro- electric power should lower the discharge of hydrocarbon pollu- tants. S. SOCIOECONOMIC IMPACTS The construction force in Larsen Bay is not expected to exceed 25 people, and it will average less than 20. If accom- modations are not available locally, trailers would be brought in and a work camp set up. Mobilization would begin about April 1, with actual work beginning about April 15. The proj- ect shoul.d be completed by September 31 of the same year. Working hours would be 10 hours a day, six or seven days a week until project completion. The presence of 15 to 25 strangers in Larsen Bay for an extended period of time is bound to disrupt the traditional I ife style of the village. Skilled craft labor will be re- quired. Al though local hire will be considered, local resi- dents will not be hired unless they have appropriate skills. However, the Kodiak Area Native Association has expressed a willingness to provide training to local people so that they will be hired for this project. With the I imi ted employment opportunities available in Larsen Bay, local residents may re- sent any importation of laborers. However, construction will occur during the summer months, so residents may be busy with commercial fishing and not be available for hire. The potential does exist for confl icts with local resi- dents over alcohol use because alcohol is generally present in construction camps. Although Larsen Bay is not dry, there are -25- no liquor outlets in town. This proximity of alcohol may lead to the acquisition of alcohol by local residents through pur- chase or barter. Archaeological artifacts can easily be found in various parts of Larsen Bay, including the township. Therefore the potential exists for the unauthorized removal of the items by construction personnel. The availability of hydropower may provide economic bene- fits to the village and individual families. Cheaper electric bills should benefit for the householders. However, once centralized power is available, household generators will be outmoded and a local resale market will probably not exist. Residents may elect to switch from oil or wood heat to electric heat, which will require a large initial cash output for con- version. Maintenance of the power generation equipment will provide periodic employment for a skilled resident. T. LAND STATUS The diversion weir to be constructed across Humpy Creek, the borrow site location near the diversion weir, and a portion of the proposed trail from the diversion weir to the powerhouse are within lands for which the surface estate has been interim conveyed to Koniag, Incorporated, as part of their entitlements under the Alaska Native Claims Settlement Act of 1971 (ANCSA), Public Law 92-203. Interim conveyance is used in this case to convey unsurveyed lands. Patent will follow interim conveyance once the lands are identified by survey. The powerhouse, and an alternative borrow site near the city solid waste disposal area, are located on lands which are interim conveyed or patented for surface and subsurface estates to the City of Larsen Bay. The proposed transmission route -26- • ----- • .. • -• -• .. • .. • .. • -• - • .. • - • .. • • • - • • • -• • "''''' .... - .... .. - al ternatives from the powerhouse to Larsen Bay traverse both patented private, City of Larsen Bay, Townsite Trustee and patented Koniag Corporation property. An airport lease, Serial Number AA 9087, is near the powerhouse and the final transmis- sion route alternative should take this into account • Larsen Bay has a federal townsite, U.S.S. 4872, with the patent issued to the Bureau of Land Management Townsite Trust- ee. The Trustee has deeded occupied parcels to the residents and some vacant lots to the city. Other subdivided property remains with the Trustee. A permit would be required for the transmission line to cross Trustee lands and it may be issued by the u.s. Department of Interior after an affirmative resolu- tion by the city council. All of the interim conveyed lands identified above are also part of the Kodiak National Wildlife Refuge as classified and withdrawn by Public Land Orders 1634, 5183 and 5184. All lands that were part of a National Wildlife Refuge before the passage of ANCSA and have since been selected and conveyed to a Native corporation will remain subject to the laws and regula- tions governing the use and development of such refuges as out- lined in Section 22(g) of P.L. 92.203. U. PERMITTING REQUIREMENTS The following permits may be required for construction of the Larsen Bay hydropower project: Under the authority of Section 404 of the Fed- eral Water Pollution Control Act Amendments of 1972, the Army Corps of Engineers (COE) must authorize the discharge of dredged or fill mate- rials into navigable waters, which includes ad- jacent wetlands, by all individuals, organiza- -27- tions, commercial enterprises, and federal, state and local agencies. A COE Section 404 Permit will therefore be required for the diver- sion weir on Humpy Creek. A water Qual i ty Certificate from the State of Alaska, Department of Environmental Conservation (DEC), is also required for any activity which may result in a discharge into the navigable waters of Alaska. Application for the certifi- cate is made by submitting to DEC a letter re- questing the certificate, accompanied by a copy of the permit application being submitted to the Corps of Engineers. The Alaska Department of Fish and Game, Habitat Division, under authority of AS16. 05. 870, the Anadromous Fish Act, requires a Habitat Protec- tion Permit if a person or governmental agency desires to construct a hydraulic project or affect the natural flow or bed of a specified anadromous river, lake, or stream, or use equip- ment in such waters. A Habitat Protection Per- mit will be required for the diversion weir, and instream or streambank work on Humpy Creek. Under authority of AS16.05.840, the Alaska Department of Fish and Game can require, if the Commissioner feels it necessary, that every dam or other obstruction built by any person across a stream frequented by salmon or other fish be provided with a durable and efficient fishway and a device for efficient passage of fish. A Habitat Protection Permit will therefore be required. -28- • .. • .. • • • -• .. • .. • • • .. • .. • -• .. • • • .. • -• --• .. • • • • - ..... ..... .... " .. .... ..... ..... All public or private entities (except federal agencies) proposing to construct or operate a hydroelectric power project must have a license from the Federal Energy Regulatory Commission (FERC) if the proposed site is located on a navigable stream, or on U. S. lands, or if the project affects a u.s. government dam or inter- state commerce • A Permit to Construct or Modify a Dam is re- quired from the Forest, Land, and Water Manage- ment Division of the Alaska Department of Nat- ural Resources for the construction, enlarge- ment, alteration, or repair of any dam in the State of Alaska that is ten feet or more in height or stores 50 acre-feet or more of water. Since the weir is less than 10 feet high and has only minimal storage, this permit is not likely to be required. A Water Rights Permit is required from the Director of the Division of Forest, Land and Water Management, Alaska Department of Natural Resources for any person who desires to appro- priate waters of the State of Alaska. However, this does not secure rights to the water. When the permit holder has commenced to use the ap- propriated water, he may then notify the direc- tor who will issue a Certificate of Appropria- tion. The Certificate secures the holders' rights to the water . The proposed project area is located within the coastal zone. Under the Alaska Coastal Manage- ment Act of 1977, a determination of consistency -29- with Alaska Coastal Management Standards must be obtained form the Division of Policy Development and Planning in the Office of the Governor. This determination would be made during the COE 404 permit review. Any party wishing to use land or facil i ties of any National Wildlife Refuge for purposes other than those designated by the manager in charge and published in the Federal Register must ob- tain a Special Use Permit from the U. S. Fish & wildlife Service. This permit may authorize such activities as rights-of-ways; easements for pipelines, roads, utilities, structures, re- search projects; entry for geologic reconnais- sance or similar projects, filming and so forth. Note that all lands that were part of a National Wildlife Refuge before the passing of the Alaska Native Claims Settlement Act, and have since been selected and conveyed to a Native corpora- tion as part of their entitlement under ANCSA, will under remain under the rules and regula- tions of the refuge. v. RECOMMENDATIONS Although full-scale environmental field studies were not under- taken, the small scale of the project and the lack of major fishery or wildlife resources in the affected area indicate that these studies were considered sufficient to assess poten- tial impacts to the area. Therefore, unless substantial addi- tional concerns are expressed by local residents or regulatory -30- • • • .. • - • -• .. • • • • .. -• .. • • • -• .. • -• • • • • • • .. • -• • ..... - .... agencies, no additional environmental studies are considered necessary • W. REFERENCES CITED Alaska Department of Fish & Game, 1978a, Alaska's Fisheries Atlas, Volumes I and II. Alaska Department of Fish & Game, 1978b, Alaska's Wildlife and Habitat, volume II. x. PERSONAL COMMUNICATIONS Amaral, Michael. Wildlife Biologist, U. S. Fish and Wildlife Service, Endangered Species. 1982. Dilliplane, Ty. Alaska Department of Natural Resources, Divi- sion of Parks. 1981. Manthey, Ken. Fisheries Biologist, Commercial Fisheries Divi- sion, Alaska Department of Fish and Game, Kodiak, Alaska. 1981. Money, Dennis. Wildlife Biologist, U.S. Fish and wildlife Ser- vice, Endangered Species. 1981. Smith, Roger. Game Biologist, Game Division ADF&G, Kodiak, Alaska. 1981. Stratton, Bob. USFWS, Refuge Manager, Kodiak National Wildlife Refuge. 1981. Zwiefelhofer, Denny. u. S. Fish and Wildlife Service, Kodiak National Wildlife Refuge. 1981. -31- LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX F LETTERS AND MINUTES ... - ,.,. - '.liII' ..... ' ... ..... Public Meeting Questions and Answers A public meeting was held on March 26, 1982 in the community of Larsen Bay to discuss the results of this study. The following questions were asked and answers given during the meeting. 1. When would the project be built? construction could begin in the summer of 1984 • 2. What would the per kilowatt cost be? That type of financial analysis was not done. 3. How would the payback for the cost of the dam work? 4. 5. It is difficult to say at this point, however, the State is currently giving the money out as grants. Would generators be installed as a back-up? Yes. Hydroelectric power has brought high costs to the town of Kodiak -will it be the same for Larsen Bay? We would expect not because this is a much smaller project. However, the method of charging for power has not been determined and this study was not intended to evaluate charges to consumers • - . 1 .--.. • .. • ~~vr L c~· /C/6 <-- • - • • .. • - • -• .. .. • - • --.. • - • .. -• • .. • -• • .... •• - .... .... .... .- - ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE, ALASKA 99501 -~1r. Bob ~1artin Regional Supervisor State of Alaska Department of Environmental Conservation 437 E Street Second Floor Anchorage, Alaska 99501 July 28, 1982 Phone: (907) 277-7641 (907) 276-0001 Subject: Draft Feasibility Reports on Hydroelectric Projects at King Cove, Old Harbor, Larsen Bay; Draft Reconnaissance Report of a Hydroelectric Project at Togiak . Dear Mr. Martin: Thank you for your March 26, 1982, letter to Mr. Don Baxter of my staff regarding the above referenced reports. We appreciate your participation and timely input in reviewing the draft reports and are pleased to hear that you find no apparent major or permanent environmental impacts related to the projects, with the exception of Togiak. The project at Togiak appears to be marginally feasible from an economic standpoint and the likelihood of proceeding with additional studies is questionable. However, if the project is carried forward, appropriate mitigation measures will be taken to preserve Quigmy River water quality. An instream flow study program would become an integral part of any additional study programs. Thank you again for your consideration and timely input. Should you have further questions regarding these projects, please contact myself or Mr. Don Baxter of my staff. c\? J.\ Eric P. Yould '-\ Executive Director ~., - .... .... - ... - - - --- -.... 1M ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE, ALASKA 99501 r~s. Judy Ma rquez Director State of Alaska Department of Natural Resources Division of Parks 619 Warehouse Drive, Suite 210 Anchorage, AK 99501 July 28, 1982 Phone: (907) 277-7641 (907) 276-0001 SUBJECT: Draft Feasibility Reports on Hydroelectric Projects at King Cove, Old Harbor, Larsen Bay; Draft Reconnaissance Report of a Hydroelectric Project at Togiak. Dear Ms. Marquez: Thank you for your letters of April 12, March 30 and March 31, 1982, to Ms. Laurel Bennett of DOWL Engineers regarding the above referenced feasibility and reconnaissance reports. We appreciate your participation and timely input in reviewing the draft reports . In response to the concerns voiced in your letters, preconstruction cultural resource surveys would be accomplished prior to the initiation of construction activity on any of the projects. Any work associated with the scoping and implementation of such surveys would be fully coordinated with your office. Furthermore, the project at Togiak does not appear to be attractive at this point in time due to economics, and it is doubtful that it will be carried forward into developmental stages. Should you have further questions regarding these studies, please contact myself or Mr. Don Baxter of my staff. Sincerely, ~-;.y~~Jl Executive Director - _I .... - .... - - - - -.. -- -.- --- - - "'. :::'" . ," :,T;:~ -"';~ , . ' I . . ' ; .... ,,", .. • Letter March 31, 1982 Page 2 .. ' ....... :. . ,.' . ~ .. Page IX-8, fourth and fifth paragraphs: Please note that the KIHA will be informed of the project's availability of electricity to prdvide space heating. The plans for the new housing units could incorporate a combination of electrical and fuel heating appliances. Appendix E, page 24, third paragraph: K~NA will do everything in its pO\,/er to provide training to local people in order for the selected contractor to hire. KANA strongly urges the APA to provide the quali- fications necessary to construct the project, encourage contractors to hire locally, and to oversee that minimum social impacts occur • KANA feels that the APA has the responsibility to insure total involve- ment of the local community that is affected by project develo[1fllent. In final comments to the project for Larsen Bay, it should be pointed out to your Review Board that the BIC ratio is somewhat misleading based on the assumption of the comparable costs bet\-Jeen hydroelectric and a hypothetical cen- tralized diesel pm'/ered electrica1 distribution system. KANA does question the ,pay-back method to be used if the project is approved. Even though that method has not been resolved, the recent eaonomic condition prevailing in Larsen Bay may put the commlJnity in jeopardy from v/hatever pay-back scheme is condoned by the State. KAriA urges tile Revi e\'I Board to keep tha tin rni nd. ~ne more thing concerning Larsen Bay is the question of AP/\'s responsibility to develop a local utilit~ to handle the project's services. the KIHA is also the regional electrical authority and could act as the'utility if the Larsen Bay community could not develop one. Please keep this in mind as v/ell. The following comments relate to Old Harbor's Feasibility Study: Page 11-1, first paragraph: Correction. The ~ower plant is owned by AVEC and the city operates it through contract. KANA is dismayed that this information because Dowl Engineering had collected the correct information during their development of Old Harbor's Community Profile which Dm4L had contracted \'Iith the State. This unnecessary error ;s a derogatory example of Dowl's experience and reputation as a rural oriented consultant firm. Page VII-2, second paragraph: The KIHA has submitted a request for funds to construct seventeen (17) single family units in Old Harbor. HUD is the grant agency but the KIHA actually does the development. " . Page IX-7, second paragraph: Another example of Dowl 's demonstrative inability to keep things correct. What cannery -there is none,will electrical demand be used to replace industrial 0eneration? Page X-5, last pJragraph: KA~lA maintains the same pbsture on dcveloplllcnt of skills for 10Clll peoplc .)nd encou)·.)(Jcment of local hire as explained in the Larsen Gay conilllents. KJ\NA docs not shilre the assumption that 111,:)oY residents Me lHely to be busy \vith commercial fishing. The fisheries economy is such that a project development such .)s tile hydroelectric \lOuld dril\,l interest from the local labor force to talc part in. .: ... "' .. .... .... .... ... .. -... - .- ALASKA POWER AUTHORITY 334 WEST 5th AVENUE· ANCHORAGE, ALASKA 99501 Ms. lone M. Norton President Kodiak Area Native Association P.O. Box 172 Kodiak, Alaska 99615 July 28, 1982 Phone: (907) 277·7641 (907) 276·0001 SUBJECT: Draft Feasibility Reports on Hydroelectric Projects at Larsen Bay and Old Harbor. Dear Ms. Norton: The following letter addresses issues or answers questions contained in Mr. Tom Peterson's letter of March 13, 1982, regarding the draft reports referenced above. We appreciate you and your staffs' participation and timely input in reviewing the reports. Our responses to your comments relating to the projects are included below. Larsen Bay Hydroelectric Project: Page II-3 The text has been modified to incorporate this change. It has also been brought to our attention that the cannery has been purchased by an outside entity and is in the process of being reopened . Page VII-3 The text has been modified to incorporate this change. The application for funding does not affect our consumption estimates. Page VII-9 The text has been modified to incorporate this change. Page IX-8 The text has been modified to incorporate this change. Appendix E, page 24 If a decision is made to proceed with construction of the Larsen Bay Hydroelectric Project, attempts will be made by the Power Authority to provide local information on the qualifications necessary for construction and operation and maintenance of the facility, to encourage local hire, and to see that social impacts are minimized. Your final comments regarding the economic analysis, method of pay-back, and selection of a local utility to operate the project a re noted. Old Harbor Hydroelectric Project: Page II-I We have made the necessary correction. Page VII-2 The text has been modified to incorporate this change. Page IX-7 The text has been changed to more fully explain the cannery issue. Cannery boats frequently dock at Old Harbor and maintain operations for many weeks. These boats usually request power from the city, according to Mayor Haakanson. Page X-5; Appendix E, page 24 We fully support local hire and we did not simply assume that many residents would be busy fishing. This information came to light in a public meeting with the community and during interviews with the Tribal Council President. Our comments regarding Appendix E, page 24, of the .Larsen Bay Report apply here as well. • .. • • • • • -• - • -• • • -• • • --Again, your comments are noted on the economic analysis and on - the ability of the community to pay back any loans used for project development. .. Thank you again for your comments and timely input. Should you have further questions regarding these projects, please contact myself or Mr. Don Baxter of my staff. (e~e:? . .vM Eric P. Yould '-\ Executive Director cc: Frank Carlson, Mayor, Larsen Bay Frank R. Peterson, President, Larsen Bay Tribal Council Sven Haakanson, Mayor, Old Harbor Walter Erickson, President, Old Harbor Tribal Council Marlin Knight, Executive Director, KIHA • • • • --- • • • • • • • • • - ALASKA POWER AUTHORITY • • 334 WEST 5th AVENUE· ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 • The Honorable Frank M. Carlson Mayor . City of Larsen Bay Post Office Box 8 Larsen Bay, Alaska 99624 August 3, 1982 Subject: Larsen Bay Hydroelectric Project, Draft Feasibility Report. Dear Mayor.Carlson: Thank you for your letter of April 1, 1982 to Mr. Don Baxter of my staff regarding the above referenced report. The Power Authority is well aware of the rapidly escalating costs of electric energy in rural Alaska and of the benefits to the City of Larsen Bay if the hydroelectric project is developed. We will be making a decision on whether or not to proceed with final design of the Larsen Bay Project in the near future. We will notify you of the results of that decision once it is made. Thank you for your interest in the Larsen Bay Hydroelectric Project. Should you have any questions regarding the project, please contact myself or Mr. Baxter. Sincerely, S;~YO?' ~ ~ Executive Director cc: Senator Bob Mulcahy • • -.. -.. - • • • 'III • - • --.. .. .. • .. • - • - • • • • • .. • .. .... .... ... ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 July 28, 1982 -Mr. Jack W. Sedwick Director State of Alaska Dept. of Natural Resources Division of Forest, Land and Water Management 555 Cordova Street Pouch 7-005 Anchorage, AK 99501 SUBJECT: Draft Feasibility Reports on Hydroelectric Projects at King Cove, Larsen Bay and Old Harbor; Draft Reconnaissance Report of a Hydroelectric Project at Togiak. Dear Mr. Sedwick: Thank you for your letter of April 12th regarding the above referenced reports. The following letter addresses issues and answers questions contained in your letter. We appreciate the participation and timely input of you and your staff in reviewing the draft reports. Our responses to your comments are included below: a. Permit to Construct or Modify a Dam For King Cove, Old Harbor and Larsen Bay, plans will be submitted during the design phase of these projects, however, we understand that a permit will not be required because the proposed dams are less than 10 feet in height. The dam proposed for the Togiak site is greater than 10 feet in height, but the project does not appear to be economically attractive. It is therefore doubtful that the project would ever be developed. b. Water Rights Permit Except for the Quigmy River near Togiak, there are no established navigable uses for any of the streams or rivers under consideration. The text has been modified to reflect this comment. In a meeting with Paul Janke, some concern was expressed about mlnlmum flows. This issue is addressed in our letters to the u.S. Fish & Wildlife Service (USFWS), copies of which are attached. Mr. Jack W. Sedwick July 28, 1982 Page 2 Discussions of impacts during operations and maintenance, water quality issues, and loss of alternative uses have been incorporated into the final report text. Furthermore, ADEC concerns regarding fish and game resources have also been addressed in the final report text and in the attached letters to USFWS. Thank you again for your consideration and timely input. The Power Authority looks forward to a successful working relationship with the Department of Natural Resources in bringing these projects forward. Should you have further questions, please contact myself or ~1r. Don Baxter of my staff. ~~.~J) Executive Director Attachments as noted • • • .. • -• -.. --• • • .. • .. • - • .. • .. • • • • • - • -.. • • - • • ~~ KODIAK ISLAND BOROUGH - .... - - .... .- ' .... -- April 12, 1982 Mr. Eric P. You1d Executive Director Alaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 Telephones 486-5736 -486-5737 -Box 1246 KODIAK, ALASKA 99615 RE(;cIVt:O I'.?R 1 ~ 1982 \ AlAS'I.A PO'rVER '·.UTI!ORITY RE: Feasibility Studies of Hydroelectric Projects in Old Harbor and Larsen Bay Dear Mr. Yould: Thank you for the opportunity to review the draft feasibility studies of hydroelectric projects in Old Harbor and Larsen Bay. The reports appear to be comprehensive and well-prepared. I have two general co~ments to make regarding these studies. First, I expect the findings of these studies to be directly incorporated into the "electrification" study the APA is spon- soring in the Kodiak Island Borough. Secondly, I hope that the APA Board of Directors acts on these projects by promoting hydroelectric development in both Old Harbor and Larsen Bay. Thanks again for the opportunity to comment on this project. Sincerely, ~~ LindCl Freed CZ~1 Coordina tor Comnunity Development Department cc. Frank Carlson, Mayor Larsen Bay Sven Haak.:.1l1son, H.:1yor Old H.:lrbor LF/jda ALASKA POWER AUTHORITY 334 WEST 5th AVENUE· ANCHORAGE, ALASKA 99501 Ms. Linda Freed .CZM Coordinator Community Development Department Kodiak Island Borough Box 1246 Kodiak, AK 99615 July 28, 1982 Phone: (907) 277·7641 (907) 276·0001 SUBJECT: Draft Feasibility Reports on Hydroelectric Projects at Old Harbor and Larsen Bay. Dear Ms. Freed: Thank you for your April 12th letter regarding the above referenced reports. We appreciate your participation and timely input in reviewing the draft reports. The findings of these reports will be incorporated into the "electrificationll study we are sponsoring for the Kodiak Island Borough. Remy Williams of my staff will be managing that particular study. Furthermore, we also share your interest in wanting to bring these projects forward and hope that they receive a favorable response from our board of directors. Thank you again for your consideration and timely input. Should you have further questions regarding these projects, please contact myself or t"r. Don Baxter of my staff. Sincerely, ~;. yo? "\ ~ Executive Director cc: Frank Carlson, Mayor Larsen Bay Sven Haakanson, Mayor Old Harbor • • • • • • • -• • • • .. • .. • • • --- • • • • • -• -• - • • • • • • - - , ... . - United States Department of the Interior IN REPLY REFER TO: WAES Eric P. Yould Executive Director Alaska Power Authority 334 W. 5th Avenue Anchorage, Alaska 99501 Attn: Don Baxter Dear Mr. Yould: FISH AND WILDLIFE SER VICE 1011 E. TUDOR RD. ANCHORAGE, ALASKA 99503 (907) 276-3800 RE.CE\\JEO r ·-n 1 6 \~t'2 I \. ~. He: Larsen Bay Hydroelectric Project Feasibility Study The u.S. Fish and Wildlife Service (FWS) has reviewed the above referenced draft report submitted by DOWL Engineers. It is our intent in the following comments and recommendations to: 1) provide information which will enable you to avoid or minimize fish and wildlife losses associated with the project; 2) identify information needs which are necessary for objective project planning and decision-making; and 3) to identify those concerns which, if adequately addressed, would make the project acceptable to us, and determine our response to anticipated Federal permits and/or licenses associated with this project. General comments: In general, we find the conclusion of project feasibility based almost entirely on economic and engineering information. We feel the credibility of this conclusion could be greatly enhanced by comprehensively addressing the following issues: 1) Significantly expanding your data base regarding fish use (populations) and habitat. 2) The identification and incorporation of appropriate mitigation measures (clearly developed from the data base in #1). 3) Diversifying the types and scope of alternative electrical power production systems • Specific comments: Section I, page 5 -- Section X, page 1 -- Section X, page 3 -- Section X, page 4 -- Summary comments: The net cost figure of $4.9 million dollars does not include costs of additional environmental studies and mitigation measures. As mitigation, fish passage structures may be needed for the existing diversion dam as well as the project dam. Dolly Varden are char. Additional fisheries studies will be needed to ascertain the numbers of fish using the stream, and whether there is useable fish habitat above the existing dam. The possible upper limit of pink salmon spawning should be delineated. Spill projections between the dam and the tailrace should be made. Bear denning sites should be mapped and impacts of the project on year-round bear use should be discussed in detail. Habitat mapping should be done for Sitka black-tailed deer and eagles, too. According to the Fish and Wildlife Service mitigation policy, the fish and wildlife in the Larsen Bay vicinity fall into Resource Category 3, which means habitats are of high to medium value to the species there, and habitats are abundant. The corresponding mitigation planning goal for Resource Category 3 is no net loss of habitat value, while minimizing the loss of in-kind habitat value. Our future actions regarding various Federal permit and license applications will be to ensure that fish and wildlife resources in the project area are adequately described, that all significant impacts to those resources are identified, and that all adverse impacts are mitigated to reach our goal of no net loss. We look forward to continuing working with the Alaska Power Authority and providing technical assistance in the planning stages of this project. Thank you for the opportunity to comment on the report. ' .. ]:M/;,1.N ~ Regional Director cc: FWS-ROES, WAES ADF&G, NMFS, ADEC, OCM, Juneau ADF&G, NMFS, ADEC, EPA, Anchorage • • • • • - • • • .. • lit • • • .. • ., • - • .. • .. • • • .. • -• -• .. • .. • • ... ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE, ALASKA 99501 Mr. Keith Schreiner Regional Director U.S. Fish & Wildlife Service 1011 E. Tudor Road Anchorage, Alaska 99503 July 30, 1982 Phone: (907) 277-7641 (907) 276-0001 Subject: Draft Feasibility Reports on Hydroelectric Projects at King Cove, Old Harbor, Larsen Bay; Draft Reconnaissance Report of a Hydroelectric Project at Togiak. Dear Mr. Schreiner: This letter has been prepared in response to Mr. Gerald Reid's letters of April 14 and April 15, 1982, regarding the above referenced projects. We appreciate your timely input and your staff's participation in several agency meetings relating to these projects. GENERAL COMMENTS: At our request, DOWL Engineers (DOWL) has carefully reviewed the letters and has responded to your comments, many of which were quite constructive. However, the general comments and closing paragraphs of the letters appear to be in a format and of a nature that sets a generalized U.S. Fish and Wildlife Service (USFWS) policy for all hydroelectric projects, does not take into account the presence of existing data or local knowledge that is site specific, and assumes that all hydroelectric projects cause or have the potential to cause similar losses in fish and wildlife resources, habitat or both. It should also be noted that personal contact was made with refuge personnel and staff members of your Ecological Services several times over the course of the studies and that in addition to these contacts, two formal agency meetings were held to consider the implications of the projects. The draft reports were not prepared without the input of knowledgeable field personnel from both USFWS and the Alaska Department of Fish & Game (ADF&G). Additionally, the nature and size of the projects must be considered in any such evaluation, as well as consideration of the site specific determinants. Further, DOWL met on April 28, 1982, with representatives from your office and ADF&G to discuss the project on a site specific basis. In part, the specific comments provided below reflect the results of that meeting. Keith Schreiner July 28, 1982 Page 2 SPECIFIC COMMENTS: King Cove: Section I, Page 5. Based on other comments provided below, the possible cost of additional studies and mitigation measures is considered minor. The space heating credit is taken only for the dollar value of the heating oil being displaced. Deductions from this credit were taken as you have indicated they should have been. Section 1, page 6. Several additional field trips are planned to confirm the comment noted under Appendix E, page 5. Section IV, page 1. The hydrological data you noted is currently being collected. Preliminary winter streamflow data collected on Delta Creek appear to indicate that the measured flows utilized for energy generation are consistent with the estimates in the hydropower feasibility report. This conclusion is based on limited periodic discharge measurements, which will be used to develop rating curves for this creek as part of a one-year long stream gaging effort. Continuous streamflow data are being collected and will be made available as soon as the field study is completed. The range of estimated winter flows (December through April) utilized for energy generation and the observed flows are as follows: Estimated flow range: 8.8 to 14.5 cfs Observed flow range: 16 to 20 cfs It should be noted that that range of observed flows may change slightly as stream stage records are analyzed on the basis of completed rating curves. Spillage and projected discharges will be a function of final design. Section VI, page 12. This will be accomplished following the collection of the one year of actual discharge data. Section VI, rage 16. Schedules for cleaning and alternative methods of disposal wil be considered during final design and in determining operational procedures. The expected decrease in turbidity and sediment loads will in general enhance downstream conditions. Section VII, sage 4. The demand analysis presented has been standardizedy ApA for comparison of all hydroelectric projects and is thought to be realistic. The Power Authority's purview does not extend to denying rural Alaskans an improvement in their standard of living through the availability of reliable, stable-priced power. Appendix E, pale 5. Surveys of Delta Creek have been taken on a yearly basis for the ast 21 years by experienced ADF&G observers. Surveys are flown close to the normal time of peak spawning, so as to obtain maximum escapement counts. • • • -• - • - • - • - • • • -• • - • -• • • • • -• - • • • -• • • - .... .... - - .... .... Keith Schrei ner July 28, 1982 Page 3 The fisheries resources and upward extent of salmon spawning in Delta Creek were discussed with Arnie Shawl, the ADF&G fisheries biologist in Cold Bay, on three occasions and with several long time local residents. All were in agreement that pink salmon in the project area spawn in a tributary below the airport, and that chum salmon rarely reach the airport area, and have never been seen above it. No other species of salmon have been observed in or above the airport area. Little local information was available on silver salmon but ADF&G biologists did not believe that the run was very large or that spawning occurred very far above the extent of tidal influence. With the close proximity of the stream to the airport and the amount of recreational activity occurring at or near the airport, it seems unlikely that silvers would be present in any numbers (especially in a stream near a community of commercial fishermen), with the local residents not being aware of it. Appendix E, page 8. Field investigations will be conducted in 1982 to confirm the upper limits of chum, pink, and coho spawning, as noted above (Comment on Section I, page 5). Appendix E, page 14. The studies suggested appear to be unnecessary based on site specific knowledge of the potential for losses due to this project. If a significant number of coho salmon were to be found above the project site, then appropriate mitigation measures would be included in the final design. Through interviews and discussions with local residents, local city administrators, ADF&G biologists, staff members from Ecological Services and the input from several site visits, existing knowledge of wildlife and fisheries resources in the project area was incorporated into the report • With the exception of the confirmation of the upper limits of spawning and the completion of the collection of the hydrological data previously discussed, no additional environmental studies for this site are contemplated. Old Harbor: Section I, page 5. The Old Harbor Hydroelectric Project does not appear to warrant additional terrestrial habitat studies and/or mitigative measures that could not be accomplished within the estimated project cost. Section I, page 6. The road is one half mile long and will be built primarily through a sparse meadow community (with very little topsoil on mostly alluvial deposits). The transmission line is 3 miles long and crosses Big Creek. This crossing does present the potential for collision by waterfowl that utilize the area. Appendix E, Sections I through M, of the Feasibility Study, discussed wildlife utilization impacts and mitigation in an adequate level for this study. Keith Schrei ner July 28, 1982 Page 4 Section II, page 5. During the recent meeting with ADF&G and USF&WS personnel, it was generally agreed that consideration of mitigative and replacement measures were premature for the Old Harbor Project and that the fish and wildlife studies to date are sufficient for the present level of project evaluation. Section X, page 2. Good spawning gravel occurs only on the alluvial fan. The remainder of the stream is steep and rocky. Above the weir, the gradient flattens out and the gravel is potentially good for spawning. However, it is doubtful many fish, particularly pink salmon, would make it to this portion of the stream. Section X, pages 3 & 4; Section XII, page 1. The small size and limited potential impacts of this project do not warrant the extensive studies outlined. Enclosed with this letter is a reply to specific questions raised in a memorandum dated April 16, 1982 from the acting Refuge Manager, Kodiak NWR, to the staff of the Western Alaska Ecolooical Services, which provides further site specific information. - Through interviews and discussions with local residents, ADF&G biologists, Kodiak NWR personnel, staff members from Ecological Services and the input from numerous site visits, existing knowledge of wildlife in the project area was incorporated into the report. This level of information appears sufficient for project evaluation at this time. Larsen Bay: Section I, paae 5. The Larsen Bay Hydroelectric Project does not appear to warrant ad itional environmental studies and/or mitigative measures that could not be accomplished within the estimated project cost. Section X, ~a~e 1. Due to the location of the existing cannery dam and the marginaabitat existing between the proposed diversion weir and the dam, it appears that fish passage structures would not be required. • • • - • - • -• - • .. • • • .. • • - • - • .. • • • Section X, page 3. The typographical error concerning Dolly Varden Char .. has been corrected. As noted above, fish habitat above the existing cannery site dam is marginal with a bedrock and boulder substrate, no pools, and very little quiet water. At this time, the possible upper limit for pink salmon spawning is the face of the cannery dam. However, as can be seen from the photo provided on Page 8 of Appendix E, conditions for about 100 yards below the dam are marginal for spawning. The drainage area for Humpy Creek above the proposed diversion weir is 6.28 square miles. ~ean annual flow for this drainage area is estima 3ed to bZ 13.0 ft /sec, resulting in a unit runoff of some 2.1 ft /sec/mi . The drainage area for that reach of the creek between • - • .. • - • .. • • .... .... .... ... Keith Schrei ner July 28, 1982 Page 5 the diversion weir and powerhouse is computed to b~ 0.09 mi 2 The creek within this reach could potentially release 0.2 ft /sec on a mean annual basis; although, this estimate is conservative due to excess streamflows, which must be spilled over the diversion weir during periods of high flow. Sources of streamflow for the reach of creek between the diversion weir and powerhouse include: Ground-water seepage from the narrow valley slopes. Several rivulets and overland flow channels on the left valley banks. Runoff from the valley slopes during snowmelt and rainstorm events. Seepage fro~ the diversion weir itself. Al~o, the turbine generator is sized for a maxim~m design flow of 23.8 ft /sec. Stream flows in excess of this 23.8 ft /sec will spill over the diversion weir. This situation would obviously only occur during periods of high surface flows. Ultimately, spillage and projected discharges will be a function of final design. It is conceivable that short reaches of Humpy Creek below the diversion weir may go dry during periods of minimum flow-late winter and early spring. However, the streambed itself is expected to remain saturated throughout the year. Section X, ~age 4. The extent of wildlife habitat and its present use are outline in Appendix E, pages 10 through 20. With the project area being located in such close proximity to Larsen Bay itself, it would not have much additional impact relative to fish and wildlife resources, other than that which has already occurred. Enclosed with this letter is a reply to specific questions raised in a memorandum dated April 16, 1982 from the acting Refuge Manager, Kodiak NWR, to the staff of the Western Alaska Ecological Services, which provides further site specific information. Through interviews and discussions with local residents, ADF&G biologists, Kodiak NWR personnel, staff members from Ecological Services, and the input from numerous site visits, existing knowledge of wildlife in the project area was incorporated into the report. This level of information appears sufficient for project evaluation at this time. Keith Schrei ner July 28, 1982 Page 6 Togiak: Section 1, page 1. Mitigation measures such as a fish passage are included in this cost. If this project were to receive additional funding, further work would need to be accomplished in order to scope both impacts and possible mitigation measures. Section VI, page 5. A recommendation for additional studies on techniques to insure safe passage of outmigration smolt was included in the draft report in Appendix E, page 46. This recommendation has been clarified to show the potential need for changes in design. Section X, page 1 & 2. It should be pointed out that Togiak was intended to be only a reconnaissance study. It was understood that additional studies would be required should this project be funded. At that time, resource agencies would be invited to participate in scoping these additional studies. Due to the marginal feasibility of this project, we feel that any' discussion of additional studies at this time is premature. Section X, page 3. This change has been incorporated into the text. Section XI, page 3. A one year program to collect stream discharge data is presently being conducted. Apeendix E, page 21. The potential for changes in stream morphology was pOlnted out on this page. Due to the preliminary nature of this study, a detailed analysis of potential impacts was not necessary at this stage. Future or continued studies of this project would discuss these potential changes in more detail. Appendix E, pa*e 22. Mitigation measures will be discussed in more detail in any uture studies of this potential project. Because of the uncertain project status in regard to the Togiak Reconnaissance Study and because some consideration is being given to a different location on a different river, no further environmental activities are contemplated for Quigmy River. • • • .. • .. • .. .. -.. -.. • .. .. • .. .. .. .. • .. • .. .. .. • .. .. .. .. • .. • .. ... Keith Schreiner July 28, 1982 Page 7 Thank you again for your consideration and timely input. The Power Authority looks forward to a successful working relationship with the U.S. Fish and Wildlife Service in bringing this project forward. Enclosures: c? Eric P. Yould "-\ Executive Director USFWS memo of April 16, 1982 APA reply of July 28 to the above memo cc: FWS-ROES, WAES ADF&G, NMFS, ADEC, OCM, Juneau ADF&G, NMFS, ADEC, EPA, Anchorage m -\ r-;:.J ; 1 : '-, I :,..- 'U J)1~1·:\nl·'n:'TO!: "'~II :\~U (;:\:llt: April 14, 1982 hlaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 OFFICE 01lf~l{ft.1f~'t'd! SAN FRANCISCO lWR-MBH_ RNJ_N RR_ PEP_ CO DJC c:n -OCW_"'-OCR GVG_~ JWM= :.Ica _ cr. WFA_ RWM_Q.. OIC_ TTT _ c:r HMB_ Be _ RW£_ !-M~_ REI_ CTD_ CAL_ Attention: Eric P. Yould, Executive Director Gentlemen: JAY S. HAMMOND. GOYERNOR P.O. BOX 3·2000 JUNEAU. ALASKA 99802 PHONE: 465-4100 RECElVt:O !.?R 1 91322 po .. rt:~ A I ITU r"'t:: tTY P.iJ.SK.t.. J.~" r.~ •.. _, Re: Feasibility Studies for King Cove Hydroelectric Project, Old Harbor Hydroelectric Project, Larsen Bay Hydroelectric Project and Reconnaissance Study for Togiak Hydroelectric Project The Alaska Department of Fish and Game has reviewed the subject documents and generally concurs with the contents. There are, however, several informational needs and statutory requirements that need to be addressed. These are outlined within the enclosed specific comments. If you have any questions or comments, please do not hesitate to contact me. Sincerely, ~ Ronald O. Skoog Commissioner cc: C. Yanagawa R. Logan lit, I ; .. • .. • -• -• -• .. • -• ---• i • -, • • • • • I I , .. -, .. • '"III" .- Volume B -Feasibility Study for King Cove Hydroelectric Project -Draft Report SECTION X -ENVIRONMENTAL AND SOCIAL EFFECTS B. ENVIRONMENTAL EFFECTS 1. Fi sheries Page X-2, para. 3 Alaska Statute 16.05.840 requires that, if the Commissioner feels it necessary, dams be fitted with fishways and devices for passage of fish. This may necessitate a minimum f10w release thrQugh the stream reach below the diversion weir. SECTION XI -PROJECT IMPLEMENTATIONS B. PROJECT LICENSES, PERMITS, AND INSTITUTIONAL CONSIDERATIONS Page XI-l, general comment Absent from the list of permit requirements is that pertaining to AS 16.05.840 as follows: "Sec. 16.05.840. Fishway required. If the commissioner considers it necessary, every dam or other obstruction built by any person across a stream frequented by sa 1 mon or other fi sh sha 11 be provi ded by that person ..... We question the accuracy of some of the statements regarding substrate sizes and other optimum spawning conditions, including those obtained from the ADF&G 1978, Fisheries Atlas. Some work has already been conducted and other is ongoing regarding development of species suitability curves for several river systems in Alaska. While it should be recognized that curves developed for species in one system cannot be directly applied to those in another, they may be used in making qualified generalizations. G. FISHERIES IMPACTS Page 13, para. 3 Any habitat improvement accrued by retention of sediments will be negated by 'loss or absence of flow. H. FISHERY MITIGATION Page 14 & 15, general co~ments The fisheries mitigation section fails to address measures other than reduction of sedimentation. Other impacts such as loss of habitat in dewatered streams reaches and impediment to fish migration must also be addressed. M. WILDLIFE MITIGATION Page 24, para. 7 The 330 foot buffer cited here is a USFS reconmendation for minimum • .. • • separation for falling of trees. In instances where there is flexibility to .. locate camps, material sites, etc. at a distance greater than 330 feet, we recommend it be done. In addition, we suggest a minimum separation of 500 feet and strongly discourage siting within one-quarter mile. .. • • • - With respect to aircraft separation, we recommend 1500 feet separation .. for helicopters and 500 feet for fixed wing craft. Pages 24, general comments .. .. .. -• The wildlife mitigation section fails to address mitigation measures related_ to restoration of material sites, abandoned camp sites and utilization transmission lines designed to minimize large raptor electrocution. U. PERMITTING REQUIREMENTS Pages 28-29, general comments Absent from the list of permit requirements is that pertaining to AS 16.05.840 as follows: "Sec. 16.05.840. Fish\'I'ay required. If the commissioner considers it necessary, every dam or other obstruction built by any person across a of .. .. .. .. .. • -• .. • .. • .. .. .. stream frequented by salmon or other fish shall be provided by that person with a durable and efficient fishway and a device for efficie~t passage for • .. downstream migrants. The fishway or device or both shall be maintained in a .. .. • • ,,, .. .. - ..... practical and effective manner in the place, fonn and capacity the commissioner approves, for which plans and specifica- tions shall be approved by the department upon application to it. The fishway or device shall be kept open, unobstructed, and supplied with a sufficient quantity of water to admit freely the passage of fish through it. (Par. 30 pat 1 ch 94 SLA 1959)." A Habitat Protection Permit constitutes approval under AS 16.05.840. V. RECOMMENDATIONS Page 31, general comments We recommend that a determination of a minimum flow requirement to pass fish between the weir and powerhouse be made. Knowledge of this figure and its impact on power production will and in making the determination of necessity to provide fish passage. Volume C -Feasibility Study for Old Harbor Hydroelectric Project -Draft Rerort SECTION X -ENVIRONMENTAL AND SOCIAL EFFECTS B. ENVIRONMENTAL EFFECTS Page X-2, 1. Fisheries . Was any effort expended towards sampling for fish between the powerhouse and • • • iii • diversion weir site and above to ascertain use by fish? If not (as can be .. concluded from the report), there is no way to predict the consequences of habitat lost through dewatering or the impact of impeding fish migrations. Page X-2, Z. Wildlife Bear confrontations are likely to be the most serious wildlife consequence of the project. Confrontations would be most likely from August through • .. • .. • .. • .. October when bear are feeding on salmon in Big Creek. If construction were II • • executed other than in this time period, likelihood of this problem would be considerably reduced. Precautions with disposal of garbage and other food scraps (lunches, etc.) during construction will also reduce the potential for bear problems. Owing to the large number of bald eagles in the area, transmission line designs which minimize large raptor electrocution must be e~ployed. SECTION XI -PROJECT IMPLEMENTATION B. PROJECT LICENSES, PERMITS, AND INSTITUTIONAL CONSIDERATIONS Page XI-l, general comment Absent from the list of permit requirements is that pertaining to AS 16.05.840 as follows: • • • .. • • • .. • .. • .. • .. • .. • • • Iii • • '. .... "Sec. 16.05.840. Fishway required. If the commissioner considers it necessary, every dam or other obstruction built by any person across a stream frequented by salmon or other fish shall be provided by that person with a durable and efficient fishway and a device for efficient passage for downstream migrants. The fishway or device or both shall be-maintained in a practical and effective manner in the place, form and capacity the commissioner approves, for which plans and specifi- cations shall be approved by the department upon application to it. The fishway or device shall be kept open, unobstructed, and supplied with a sufficient quantity of water to admit freely the passage of fish through it. (Par. 30 pat 1 ch 94 SLA 1959)." A Habitat Protection Permit constitutes approval under AS 16.05.840. SECTION XII -CONCLUSIONS AND RECOMMENDATIONS B. RECOMMENDATIONS Page XII-l, general comments We recommend that it be determined whether fish utilize that portion of the stream that will be dewatered below the weir for either residence or as a migration route. If it is used for either or both, a fishway and/or minimum release may be required. APPENDIX E -ENVIRONMENTAL REPORT D. FISHERIES Page 4-6 general comments • • • • • .. • • We question the accuracy of some of the statements regarding substrate sizes .. and other optimum spawning conditions, including those obtained from the ADF&G 1978, Fisheries Atlas. Some work has already been conducted and other is ongoing regarding development of species suitability curves for several river systems in Alaska. While it should be recognized that curves developed for species in one system cannot be directly applied to those in another, they may be used in making qualified generalizations. H. FISHERY MITIGATION Page 9 & 10, general comments The fisheries mitigation section fails to address measures other than reduction of sedimentation. Other impacts such as loss of habitat in dewatered streams reaches and impediments to fish migration must also be addressed. M. WILDLIFE MITIGATION Page 22, para. 1 The 330 foot buffer cited here is a USFS recommendation for minimum separation for falling of trees. 1n instances where there is flexibility to • • • • • • • • • • -• • • • • • • • • -.. • • -• •• • • ."" locate camps. material site, etc. at a distance 9i'eater than 330 feet, we recommend it be done. In addition. we suggest a minimum separation of 500 feet and strongly discourage siting within one-quarter mile. With respect to aircraft separation, we recommend 1500 feet separation for helicopters and 500 feet for fixed wing craft. Pages 21 & 22, general comments The wildlife mitigation section fails to address mitigation measures related to restoration of material sites, abandoned camp sites and utilization of transmission lines designed to minimize large raptor electrocution. U. PERMITTING REQUIREMENTS Pages 26-28, general comment Absent from the list of permit requirements is that pertaining to AS 16.05.840 as follows: "Sec. 16.05.840. Fishway required. If the commissioner considers it necessary. every dam or other obstruction built by any person across a stream frequented by salmon or other fish shall be provided by that person with a durable and efficient fishway and a device for efficient passage for downstream migrants. The fishway or device or both shall be maintained in a practical and effective manner in the place, form and capacity the commissioner approves, for which plans and specifi- cations shall be approved by the department upon application to it. The fishway or device shall be kept open, unobstructed, and supplied with a sufficient quantity of water to admit freely the passage of fish through (Par. 30 pat 1 ch 94 SLA 1959)." A Habitat Protection Permit constitutes approval under AS 16.05.840. V. RECOMMENDATiONS Page 28, general comments it. We recommend that it be determined whether fish utilize that portion of the stream that will be dewatered below the weir for either residence or as a migration route. If it is used for either or both a fishway and/or minimum release may be required. Volume D -Feasibility Study for Larsen Bay Hydroelectric Project -Draft Report SECTION X -ENVIRONMENTAL AND SOCIAL EFFECTS B. ENVIRONM~NTAL EFFECTS 1. Fisheries • • • • • .. • .. • - • .. • .. • .. • .. • - • .. • .. • .. • .. • .. • .. • .. • • • • Page X-3, para. 3 Alaska Statute 16.05.840 requires that, if the Commissioner feels it necessary, dams be fitted with fishways and devices for passage of fish. This may necessitate a minimum flow release through the stream reach below the diversion weir. Dolly Varden are identified as being trout. They are chars. SECTION XI -PROJECT IMPLEMENTATION B. PROJECT LICE~SES, PER~'ITS, AND INSTITUTIONAL CONSIDERATIONS Page XI-l, general comment Absent from the list of permit requirements is that pertaining to AS 16.05.840 as follows: US ec . 16.05.840. Fishway required. If the commissioner considers it necessary, every dam or other obstruction built by any person across a stream frequented by salmon or other fish shall be provided by that person with a durable and efficient fishway and a device for efficient passage for downstream migrants. The fishway or device or both shall be maintained in a practical and effective manner in the place, form and capacity the con~issioner approves, for which plans and specifica- tions shall be approved by the department upon application to it. The fishway or device shall be kept open, unobstructed, and supplied with a sufficient quantity of water to admit freely the passage of fish through it. (Par. 30 pat 1 ch 94 SLA 1959)." A Habitat Protection Permit constitutes approval under AS 16.05.840. SECTION XII -CONCLUSION AND RECOMMENDATIONS B. RECOMMENDATION Page XII-l, general comments We recommend that a determination of a minimum flow requirement to pass fish between the weir and powerhouse be made. Knowledge of this figure and its impact on power production will aid in making the determination of necessity to provide fish passage relative to AS 16.05.840. APPENDIX E -ENVIRONMENTAL REPORT D. FISHERIES Page 5, general comments An assessment of the fisheries resources present between the weir and powerhouse should be made to determine the necessity of maintaining a minimum flow and the advisability of constructing fish passage structures. Page 6, para. 1-3 • • • .. • - • .. • - • • • • • • • • • .. • - • .. • - • • • - • - • -• . - • .. ·'.111 We question the accuracy of some of the statements regarding substrate sizes and other optimum spawning conditions, including those obtained from the ADF&G 1978, Fisheries Atlas. Some work has already been conducted and other is ongoing regarding development of species suitability curves for several river systems in Alaska. While it should be recognized that curves developed for species in one system cannot be directly applied to those in another, they may be used in making qualified generalizations. G. FISHERIES IMPACTS Page 7, general comments The presence of the weir and lack of flow will impede fish passage throughout the affected reach. H. FISHERY MITIGATION Page 9 & 10, general comments The fisheries mitigation section fails to address measures other than reduction of sedimentation. Other impacts such as loss of habitat in dewatered stream reaches and impediment to fish migration must also be addressed. M. WILDLIFE MITIGATION Page 22, para. 7 The 330 foot buffer cited here is a USFS recommendation for minimum separation for falling of trees. In instances where there is flexibility to locate camps, material sites, etc. at a distance greater than 330 feet, we .. .. • • • .. • recommend it be done. In addition, we suggest a minimum separation of 500 .. feet and strongly discourage siting within one-quarter mile. With respect to aircraft separation we recommend 1500 feet separation for helicopters and 500 feet for fixed wing craft. Pages 24, general comments • -• .. .. .. • III The wildlife mitigation section fails to address mitigation measures related .• to restoration of material sites, abandoned camp sites and utilization of transmission lines designed to minimize large raptor electrocution. U. PERMITTING REQUIREMENTS Pages 26-29. general comments Absent from the list of permit requirements is that pertaining to AS 16.05.840 as follows: "Sec. 16.05.840. Fish\'/ay required. If the commissioner considers it nece5sary, every dam or other obstruction built by any person across a stream frequented by salmon or other fish shall be provided by that person with a durable and efficient fishway and a device for efficien~ passage for downstream migrants. The fishway or device or both shall be maintained in a .. • - • .. • .. • -• - • .. • .. .. .. • • .. • .... - ,.., - , ... , ... - prrtctical and effective manner in the place. form and capacity the commissioner approves, for which plans and specifica- tions shall be approved by the department upon application to it. The fishway or device shall be kept open. unobstructed. and supplied with a sufficient quantity of water to admit freely the passage of fish through it. (Par. 30 pat 1 ch 94 SLA 1959)." A Habitat Protection Permit constitutes approval under AS 16.05.840. v. RECOMMENDATIONS Page 31, general comments We recommend that a determination of a minimum flow rec\uirement to pass fish between the weir and powerhouse be made. Knowledge of this figure and its impact on power production will aid in making the determination of necessity to provide fish passage relative to AS 16.05.840. Volume E Reconnaissance Study for Togiak Hydroelectric Project -Draft Report SECTION VI -ALTERNATIVE HYDROELECTRIC PROJECTS Page VI-5, 5. Fish Ladder • .. • • In addition to provisions to pass fish upstream consideration must be given _ to a means of providing passage of downstream migrants (fry, smolts and - resident fish) without incurring significant mortalities. In many instances, fish are unable to survive passage through turbines. In response to this problem, a number of devices such as traveling screens and baffled intakes have been developed. SECTION X -ENVIRONMENTAL AND SOCIAL EFFECTS A. GENERAL Page X-I, para. 2 B. With respect to recommendations for additional study, the upstream effects of the impoundment on salmon and resident spawning and rearing habitat need to be addressed. We also assume that downstream impacts to all salmon and resident species will be addressed. ENVIRONMENTAL EFFECTS Page X-3, para. I Dolly Varden are referred to as trout, they are char. Page X-4, para. I • - • • • .. • .. • • • • • .. • • • • • .. • • • II • • • .. • II .... .... - - - .... .... .... .... - - Although it is generally known that chum salmon spawning is heaviest in the lower one-half of the Quigmy River. distribution of all salmon species should be verified in subsequent studies. This is an important factor when determining requirements for minimum flows. In addition, it is recognized that chum salmon typically spawn in areas of groundwater upwelling. If this can be verified in the Quigmy River, it may have great significance respective to flow release for fisheries. SECTION XI -PROJECT IMPLEMENTATION B. DEFINITIVE PROJECT REPORT Page XI-3, 5. Hydrology Statement is made that estimates are based on data from areas 75 to 150 feet distant. Perhaps the distance is actually 75 to 150 miles . D. PROJECT LICENSES, PERMITS, AND INSTITUTIONAL CONSIDERATIONS Page XI-6, 3. ADF&G Permits Statement is made that a Habitat Protection Permit is required for Delta Creek. Should this refer to Quigmy River instead? Absent from the list of permit requirements is that pertaining to I AS 16.05.840 as follows: "Sec. 16.05.840. Fishway required. If the commissioner considers it necessary, every dam or other obstruction built by any person across a stream frequented by salmon or other fish shall be provided by that person II • • ... • • • with a durable and efficient fishway and a device for efficient passage for _ o· downstream migrants. The fishway or device or both shall be maintained in a .. practical and effective manner in the place, form and capacity the commissioner approves, for which plans and specifi- cations shall be approved by the department upon application to it. The fishway or device shall be kept open, unobstructed, and supplied with a sufficient quantity of water to admit freely the passage of fish through it . (Par. 30 pat 1 ch 94 SLA 1959)." A Habitat Protection Permit constitutes approval under AS 16.05.840. APPENDIX E -ENVIRONMENTAL REPORT 0.1. Spawning Page 11, para. 2 Optimum stream velocity for coho salmon is cited as being 3-4 cubic feet .second (cfs). This is a discharge quantity rather than one of velocity. Page 12, para. 1 Dolly Varden are properly referred to as char rather than trout. per • .. .. .. .. .. III .. .. • • .. .. .. .. • .. • • • • .. • • • • • • • - .... - - - ..... - .- - . - - Page 11 & 12, general comments 1. We question the accuracy of some of the statements regarding substrate sizes and other optimum spawning condition, including those obtained from the ADF&G 1978 Fisheries Atlas. Some work has already been conducted and other is ongoing regarding development of species suitability curves for several systems in Alaska. While it should be recognized that curves developed for a species in one system cannot be directly applied to those in another, they may be used in making qualified generalizations. FISHERIES IMPACTS Page 21, para. 3 There may be streambed morphology changes associated with the project due to attenuation of some flood events and lack of material recruitment from reaches above the dam. J. FISHERY MITIGATION Page 22, para. 2 Is the inference here that improving the road as little as possible will reduce the erosion potential? If so, we believe this to be an erroneous conclusion. A maintained gravel surface of adequate dimensions will produce far fewer fines than an unimproved surface • Page 22, general comments This discussion fails to address fisheries mitigation other than sedimentation and erosion control. There is no mention of flow maintenance, provision for safe passage of downstream migrants, provisions-for passage of upstream migrants, etc. Q. WILDLIFE MITIGATION Page 36 & 37, general comments of Discussion should also address mitigation measures related to restoration disturbed areas, prohibition of vehicular access to project roads, scheduling of construction events to minimize disturbance to wildlife, etc. • • • .. • • • • • • • • .. • • • .. • .. • • • .. • .. • • • • • • • l1li • • • II1II ". ... ... ..... .- ..... ALASKA POWER AUTHORITY 334 WEST 5th AVENUE· ANCHORAGE, ALASKA 99501 -Mr. Rona 1 d Skoog Commissioner Alaska Department of Fish & Game P.O. Box 3-2000 Juneau, AK 99802 July 28, 1982 Phone: (907) 277·7641 (907) 276·0001 Subject: Feasibility Studies for King Cove Hydroelectric project, Old Harbor Hydroelectric Project, Larsen Bay Hydroelectric Project and Reconnaissance Study for Togiak Hydroelectric Project Dear Commissioner Skoog: This letter is in response to your letter of April 14, 1982 and the subsequent meeting of April 28, 1982 discussing ADF&G's concerns about the above referenced projects. Note that this meeting included several representatives from the U.S. Fish & Wildlife Service as well as our consultant, DOWL Engineers. We appreciate the constructive nature of the comments and the time members of your staff spent in review and discussion of these projects. GENERAL COMMENTS APPLICABLE TO KING COVE, OLD HARBOR AND LARSEN BAY ARE: The Habitat Protection Permit required by Section 16.05.840, Fishway required, has been included in the list of permit requirements. (Volume B, XI-2 and page 29, Appendix E; Volume C, XI-2 and page 27, Appendix E; Volume D, XI-2 and page 27, Appendix E) • The ADF&G 1978, Fisheries Atlas was and is used at this time by DOWL biologists as a basic reference for fisheries spawning conditions. References provided by your staff and others relative to on-going work in the development of species suitability curves will be utilized for any future work at the project sites and certainly in future projects to augment the basic information currently available in the Fisheries Atlas for making qualified generalizations for each river system. o ADF&G's recommendations concerning minimum separation from active bald eagle nests have been incorporated into the text (Volume B, Appendix E, page 24; Volume C, Appendix E, page 22; and Volume D, Appendix E, page 22). o Restoration of material sites and abandoned camp sites has been addressed in the final report (Volume B, Appendix E, pages 16 and 24; Volume C, Appendix E, page 21; Volume D, Appendix E, page 22). Commissioner Ronald Skoog July 28, 1982 Page 2 o Utilization of transmission lines designed to mlnlmlze large raptor electrocution has been included as a mitigation measure (Volume B, Appendix E, page 24; Volume C, Appendix E, page 22; Volume D, Appendix E, page 22). COMMENTS SPECIFIC TO KING COVE: Page XII-I; Appendix E, p. 14, 15, & 31 Delta Creek ~1ean annual flow is 24 cfs for a dr~inage area of 3.63 square miles resulting in a unit runoff of 6.6 cfs/mi. Drainage area between the proposed dam site and powerhouse is 0.4 square miles. Sizing for turbine generator is set at the 15 percent exceedance point which corresponds to a flow of 44 cfs in the flow duration curve for Delta Creek. This is the maximum turbine design flow. Any flows in excess of design flow will be routed through the diversion weir spillway and will flow into the stream channel below the dam. Flows less than the maximum design flow will be completely diverted into the penstock. This may result in short reaches of Delta Creek devoid of any observable streamflow just below the dam although the tributaries and the groundwater seepage from the valley slopes will maintain some estimated minimum flows (less than 2 cfs) in most of that stream channel between the dam site and the powerhouse. A flow duration curve is provided to indicate the percent of time that streamflow in excess of maximum turbine design flow (44 cfs) will be let go through an unregulated spillway. See comments on Appendix E, page 13, below, for additional discussion. Appendix E, page 13, para. 3. Habitat improvement accrued by retention of sediments: DOWL feels that sufficient flow from groundwater and small tributaries will allow maintenance of resident populations and that the decreased velocity and sediment load will improve the available habitat. Additional field work to be performed by DOWL Engineers in 1982 will address the actual utilization of the upper portions of the system and minimal flow requirements between the weir and powerhouse locations, as well as potential hatitat loss. During our meeting of April 28, 1982 two concerns were stressed by ADF&G: (1) provision of sufficient flows between the diversion weir and the powerhouse to maintain the existing Dolly Varden population (addressed previously in this letter) and (2) insurance of some transport of sediment from above the diversion weir back into the stream channel below the weir to provide for recruitment of spawning gravels. DOWL feels that this would be possible but would require considerable investigation to assume compliance with DEC w~ter quality standards. • • • • • -• -• • • :II • • .. • • • --• .. • .. • .. • ... • • • • .. • ,. .. • • .... .... - - .... .... .... - Commissioner Ronald Skoog July 28, 1982 Page 3 COMMENTS SPECIFIC TO OLD HARBOR: Page X-2, I & XII-I. Fisheries: Location of trap sites. Two traps were set above the proposed powerhouse location. The report has been corrected to reflect this effort (Appendix E, page 6). Page X-2, 2. Wildlife: bear confrontations. Assuming no unexpected delays, it should be possible to avoid construction for most if not all of the time when bear concentrations will be present. Precautions will be taken with the handling of garbage to avoid attracting bears (Appendix E, page 21) . Appendix E, pages 9, 10, & 28. The drainage area for Midway Creek above the proposed diversion weir is 2.2 square mile~. Mean annual flow for this drainage are~ is estimated to be 10.5 ft /sec resulting in a unit runoff of 4.8 ft /sec/mi 2. The drainage area for that 'reach of the creek between the diversion weir and powerhouse is computed to be 0.08 square miles. From this small drainage basin, the creek could drain on an annual basis some 0.4 ft 3/sec of water. Sources of streamflow below the proposed diversion site will include: D a significant tributary draining a small area to the east and discharging 200-300 feet downstream of the proposed diversion weir . D ground-water seepage from the valley slopes into the creek. D seepage from the diversion weir . D runoff from the valley slopes during snowmelt and rainstorm events. !he turbine generator is sized for a maximum design flow of 19 ft /sec and any surplus will spillover the diversion weir during periods of high flows . It is conceivable that short reaches of Midway Creek just below the diversion weir may be devoid of surface flow certain periods during the year, (e.g. late winter low-flow periods). However, the streambed will most likely remain saturated even during low flow periods and may contain shallow ground water flow in the coarse bed materials. Some loss of habitat for resident Dolly Varden could occur during these periods. Commissioner Ronald Skoog July 28, 1982 Page 4 COMMENTS SPECIFIC TO LARSEN BAY: Page X-3, para. 3. Dolly Varden: corrected. Page 5, Appendix E. Fisheries resources above the powerhouse. The minnow trap set above the existing dam and proposed powerhouse captured one Dolly Varden. Additional trapping may be done in the future in connection with on-going hydrologic studies. As discussed in our meeting of April 28, 1982, consideration will be given to removal of the old dam as a possible mitigation for the current project impacts. Page XII-I, Recommendation, Page VII-I, Appendix E, page 7,9, 10, and 31. The drainage area for Humpy Creek above the proposed diversion weir is 6.28 square miles. ~ean annual flow for this drainage area is estimated to be 13.0 ft /sec resulting in a unit runoff of 2.1 ft 3/sec. The drainage area for that reach of the creek between the diversion weir and powerhouse is computed to be 0.09 squ~re miles. The creek within this reach could potentially drain 0.2 ft /sec on a mean annual basis although this estimate is considered conservative due to the excess streamflows which must be spilled over the diversion weir during periods of high flows. Sources of streamflow for that reach of the creek between the diversion weir and powerhouse include: o Considerable ground-water seepage from the narrow valley slopes. o Several rivulets and overland flow channels on the left valley banks. o Runoff from the valley slopes during snowmelt and rainstorm events. o Seepage from the diversion weir. Th3 turbine generator is sized for a maxim~m design flow of 23.8 ft /sec. Streamflows in excess of 23.8 ft /sec will spillover the diversion weir during periods of high surface flows. It is conceivable that short reaches of Humpy Creek below the diversion weir may go dry during periods of minimum flow-late winter and early spring. However, the streambed itself is expected to remain saturated throughout the year. Some loss of habitat for resident Dolly Varden could occur during these periods. • .. • • • -• -• • • .. • .. • .. • • • - • .. • • • -• • • • • • • • • '. • • • Department Of Energy Alaska Power Administration P.O. Box 50 Juneau. Alaska 99802 Mr. Eric P. You1d Executive Director Alaska Pm',er Authority 334 West 5th Avenue Anchorage, AK 99501 Dear ~1r. You1d: RECEIVt:O P,?R 1 91982 ~I.ASKA P01J1ER AUTHORITY April 15, 1982 These are our notes on the studies for King Cove, Old Harbor, Larsen Bay, and Togiak hydro projects. We found the studies to be very complete and well done. They certainly rank among the best we have recently reviewed. We agree with the conclusion and recommendations that actions be initiated to implement projects at King Cove, Old Harbor, and Larsen Bay. All of the projects except Larsen Bay are based on synthesized hydrology which should be carefully reviewed before a construction commitment is made. Even Larsen Bay data is very minimal with one year rtcord. As the studies acknowledge, significant local micro climates exist throughout the region, especially on Kodiak Island. We question whether or not energy could be sold for electric heat at the same price as electric energy for other purposes, especially when compared to the present and projected costs of oil. We also question tht space heating efficiency rates used from heating oil. The reports are using 70 percent efficiency. From our experience and other recent reports, 60 percent may be a more realistic figure for planning purposes. For Larsen Bay, will the high growth rate occur even with new HUD houses in light of the cannery being closed? A couple small items--pagc IV-9, the 22kWh/gal. should be 11 kWh/gal. and on line 5, page IV-9 of the Draft Report--"~1ay, 1978 11 shoul d be "Janua ry, 1980". Thanks for the opportunity to comment. ;g~/d ~Robert J. Cross TV --Adilli ni s trator I :--• • • -• '. • -• • • • -- • -• -• • • • • .. • • • • • .. • III • • - - ..... ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE, ALASKA 99501 -Mr. Robert J. Cross Administrator Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 July 28, 1982 SUBJECT: Draft Feasibility Reports of Hydroelectric Projects Phone: (907) 277-7641 (907) 276-0001 at King Cove, Larsen Bay and Old Harbor; Draft Reconnaissance Report of a Hydroelectric Project at Togiak. Dear Mr. Cross: Thank you for your letter of April 15th regarding the above referenced reports. The following letter addresses issues and answers questions contained in your letter. We appreciate the participation and timely input of you and your staff in reviewing the draft reports. Our responses to your comments are included below: Paragraph III Although we feel fairly comfortable with the synthesized hydrology which resulted in close correlations utilizing three independent methods, there is no substitute for actual field measurements over an extended period of time. A stream gaging program has been initiated, and will continue indefinitely on streams recommended for weir construction. Each project will be re-evaluated based upon updated hydrology resulting from stream gage recordings prior to making any construction commitment. Such a commitment could occur as earlly as spring, 1983. at which time over one full year of stream gage data would be available. Pa ragraph IV In this type of analysis. the dollars relate only to the value of the oil that is displaced. and not to the projected sales price of the energy. Paragraph V Since this analysis relates to the value of displaced oil. using 70% as a heating efficiency is a more conservative assumption than using 60%. 70% assumes that less oil is used and hence a lower quantity of oil would be displaced by hydropower. Pa ragraph VI Demand forecasts are difficult to make, however, we believe that have made a reasonable estimate. See text for the other suggested changes. Thank you again for your comments and timely input. Should you have further questions regarding these projects, please contact myself or Mr. Don Baxter of my staff. {:er~lY'_ Eric P. Yould Executive Director we • • • • • -• .. • • • -.. .. • .. • • • - • -• .. • • • .. • • • .. • • • • • • Weste~n Alaska Ecological Services April 16, 1982 Page 'I"wo F. A no-road alternative should be considered for both projects. A major cost in both projects is road construction. G. Both reconnaissance studies were conducted much too late in the season to evaluate any in-stream fisheries concerns. Stucies of the sort described cannot be used as a basis for evaluatio~ of potential damage to pink salmon. I realize neither stream is considered a major salmon stream, but evaluations during the pink salmon runs (June-July) should be made. H. Under fishery impacts, it is stated that proper construction tec~niques and timing can minimize fishery impacts. This is true, but on both of these projects timing of construction activ- ity will be impractical due to the short time window for the constructl.on. I. Under the wildlife mitigation section for both projects, it should be required that all refuse be incinerated on site, then rCEi'JVec. from the area -this is =ritical to reduce bear problems. J. Archeologic surveys of all former Refuge lands to be disturbed by project features are mandatory. 2. Specific Comments: A. Larsen Bay Hydro Project Section II A. -Potential maintenance problems, costs, and avail- ability of parts will likely be worse with hydropower than diesel systems, not the reverse as stated here. E. Land Status -See general COll\l'llent A. above. Figure IY-4 -Same as above -Land Status. Section Y -Alternatives -See our general comment C. above. Section VII E. -Installation of a large diesel generation plant in 1982 ensures the development of demand for cheaper power, i.e., hydro. Diesel plant should be installe~ concurrently with hydro project. Section X-2 Wildlife -page x-5 para. 3 -The potential abuse discussed here must be more than just discourage; it must be prevented. Before FWS can issue a permit to construct, we must have assurances that vehicle access into the upper ridges will not be aided or provided by this project. Such access must be physically impossible; not just prohibited or discouraged. This is an extremely critical issue. • .. • .. • -• -• • • • • • • • • • -• • -• -• • • • • • • • • .. • • - .- - Western Alaska Ecological Services P.lJril 16, 1982 Page Three Section X-4 -See general co~ment J. above. Section X-6 Recreation -Again, access· by 3-wheelers and other ORV"s must be prevented, not just discouraged. Section XI-B.B -Should note that subsurface estate remains with U. S. Appendix E -Environment31 Report: D. Fisheries -Studies should be done in June to properly evaluate pink salmon use in this stream. M. Wilclife Mitigation-para 2 -Refuse should be incinerated on site then removed from the area as soon as possible. Another mitigation factor should be added to ensure raptor- proof lines and poles. S. Socioeconomic Impacts -Why is a distribution system not inrll1r'1pr1? T. Land Status -Subsurface estate ...... i th u. S. as stated above. B. Old Harbor Hydro Project -Land status errors as described above. -From a wildlife, fisheries and the Refuges standpoint, alter- native site no. 1, Ohiouzuk Creek, would be a much more acceptable project. Reasons for selecting site no. 2 given here are not very definitive and should be clarified. Site number 1 would be our preference. Cost differences may not be sufficient to ~ffect wildlife concerns on this project. -Our previous comments on vehicle use apply to this project as well. Section B-1 Fisheries -Studies should be done in June, July to evaluate pink salmon use. Section B-4 -An archeologic reconnaissance would be required by FWS. Western Alaska Ecological Services F,pril 16, 1982 Fage Four Apendix D: D. Fisheries -Surveys must be done June, July ~s l'rc'Jiu'.:sly stated. I. Wildlife -~lountain goats were introduced to Ug2.k £3.1', n':.ot Uyak. Again, ORVis must be restricted. M. Mitigation -Refuse incinerated en site and rapter-proof transmission line. O. Archeologic survey of entire project is required by F~S. T. Subsurface estate remains in U. S. Government. • • • .. • -• - • • .. .. .. .. • .. • In sUITUTlary I both project reports appear extremely well don(' and very tht)rough. .. The few relatively minor (for the most part) changes suggested here sh::'>uld be considered. • l,pproval by FWS of either project should be withheld until F\'i"S Refuge a:lj \·:/"E5 personnel have comFleted an on-the-ground assessment (,f the proJect ilreas. I suggest we try to accomplish same this summer in June cr Jul,/. I t should be possible to complete such an assessment in one or t· .... o d .. .tys per project. Thank you for the opportunity to comment. ~~TV / jb cc: Larry Calvert, OMS .. • • • • -• -• -• -• • • • • .. . - ALASKA POWER AUTHORITY 334 WEST 5th AVENUE· ANCHORAGE, ALASKA 99501 -Ms. Mary Lynn Nation Western Alaska Ecological Services U. S. Fish and Wildlife Service 605 West 4th Avenue, Room G-81 Anchorage, Alaska 99501 Dear Ms. Nation: July 28, 1982 Phone: (907) 277·7641 (907) 276·0001 This letter is in response to the April 16, 1982 memorandum to your office from the Acting Refuge Manager, Kodiak Nt·JR. The comments contained in that memorandum were constructive in nature and we appreciate this opportunity to provide you with additional information and/or a response. GENERAL COMMENTS: 1A. An indepth search for land status information has affirmed, in part, the statement made by Mike Vivian in regard to the subsurface estate within the Kodiak National Wildlife Refuge. PLO 1634, Kodiak National Wildlife Refuge, excluded an area one mile square surrounding the village of Larsen Bay and it was not until PL 92-203, and later PLO 5183 and 5184, that the entire township of T. 30 S., R. 29 W., S.M. was included within the Kodiak National Wildlife Refuge. Subsurface estate has consequently been conveyed to Koniag, Inc. within the NWR boundary, as it exists today . I~ary Nation July 28, 1982 Page 2 The following is a BLM listing as of May 11, 1982, of subsurface interim conveyances and patents in Sections 31 and 32 of the above mentioned township: Serial Conve~ance Section Ali 9. Parts Lot Acres -CP 52780090 31 12 11. 370 CP 52780090 31 13 7.580 CP 52780090 31 14 8.361 1C 02000118 31 15 10.000 1C 02000118 31 16 5.000 CP 52780090 31 NENESE 10.000 CP 52780090 31 SWNESE 10.000 1C 02000118 31 S2SE 30.000 1C 02000118 32 3 2.000 CP 52780090 32 10 3.930 CP 52780090 32 9 8.530 CP 52780090 32 11 8.090 CP 52780090 32 10.000 CP 52780090 32 20.000 1C 02000118 32 8 10.940 1C 02000118 32 7 1.000 CP 52780090 32 SW 95.000 1C 02000118 32 2.370 1C 02000118 32 SENW 30.000 As a further note, the Secretary of the Interior may withdraw and convey lands out of the National Wildlife Refuge System to the appropriate Native Corporation for title. This applies to existing cemetery sites and historical places, which may be conveyed to a Native group that does not qualify as a Native village. Title to the surface estate in not more than 23,040 acres surrounding the Native groupsl locality may occur, with the subsurface estate being conveyed to the appropriate Regional Corporation. Furthermore, lands may be conveyed to an individual Native, however, the surface estate may not exceed 160 acres and must be occupied by the Native as a primary place of residence on August 31, 1971. The subsurface estate would again be conveyed to the appropriate Regional Corporation. This is pursuant to Section 14(h) of PL 92-203. The land status text and land status map for Larsen Bay has been changed to reflect the corrected land status based on this information. The land status text and land status map for Old Harbor has been changed to reflect your comment. lB. This stipulation has been incorporated into the mitigation section. • .. • .. • .. • .. • .. • .. • .. .. .. -.. • .. • • • • • -• -• -• .. • .. • • • • ..... ,- Mary Nation .July ~R, 1982 Page 3 1C. A previous study by CH2M Hill entitled "Reconnaissance Study of Energy Requirements and Alternatives for Akhiok, King Cove, Larsen Bay, Old Harbor, Ouzinkie and Sand Point" June, 1981, looked at a number of alternatives for the communities of Larsen Bay and Old Harbor, and hydropower was judged to be the most feasible. Also, the U. S. Amy Corps of Engineers had previously suggested hydropower alternatives for these communities. The current study focuses on the recommendations of these previous studies. The final report will contain an analysis of a wind power generation alternative for the communities. 10. The report states that frazil ice is a potential problem, but that there are a number of workable solutions that will not seriously affect the benefit/cost ratios for each of the projects. After careful review, if found to be necessary, one or more of the solutions suggested in the report will be incorporated during final design. IE. Use of off-the-road vehicles beyond the terminus of the maintenance road is not possible due to steep cliffs. Vehicles would be prohibited except for maintenance purposes. This comment has been incorporated into the text. IF. Because of requirements generated by dam construction and subsequent maintenance operations, a road is required. 1G. Neither the Larsen Bay Hydroelectric Project nor the Old Harbor Hydroelectric Project appear to warrant additional environmental studies. At Larsen Bay, the powerhouse discharge will be at the existing cannery dam, which presently blocks further upstream migration. At Old Harbor, suitable spawning habitat is subject to loss of flow during winter cold periods, so that survival of incubating eggs is not likely. In addition, Ken Manthey, AOF&G biologist in Kodiak, has indicated that he has flown over Midway Creek several times while doing aerial escapement counts on other streams in the area, and that he has never seen any salmon in Midway Cree k . 1H. Under the present schedule, construction would begin in June and it is possible that instream work could be completed before July 1, when returning adults may be present. In addition, this is only a general schedule subject to revision, and there is still room for some flexibility. II. This has been incorporated into the mitigation section. 1J. An archaeologic survey will be completed prior to project construction. Mary Nation July 28, 1982 Page 4 SPECIFIC COMMENTS: A. Larsen Bay Project. Section II A. E. Costs are greater and parts more difficult to obtain for hydropower systems; however, the probability of needing such maintenance for hydropower systems is substantially lower than for a diesel generation plant. Land Status. See lAo Figure IV-4. See lAo Section V. See lC. Section VII E. Concurrent installation of hydro and diesel power will be considered. Section X-2. Vehicle access into the upper ridges will not be aided by the project. Section X-4. An archaeologic survey will be done prior to initiation of construction. Section X-6 Recreation. Agreed. Section XI-B.8. See General Comment lAo Appendix E: D. See General Comment lG. M. Agreed; these comments have been incorporated into the mitigation plan. S. A distribution system is a very common installation. There would be no major socioeconomic impacts other than the minor inconvenience caused during construction of the system. T. Note General Comment lAo • • • • • -• .. • • • • • • • --- • - • .. • • • - • -• lit • • • • • • • • .... - j·j"ry Nation July 28, 1982 Page 5 B. Old Harbor Project. The land status comments have been incorporated. Midway Creek is preferable to Ohiouzuk Creek from both a geotechnical and hydrological perspective. Furthermore, the Midway Creek site satisfies the needs of the community. This is clearly indicated in Section V, Pages 1 through 4, of the report. Vehicle Usage, See Genera 1 Comment IE. Section B-1, See General Comment 1G. Section B-4, See Genera 1 Comment IJ. Appendix 0: D. , See General Comment IG. I. This typographical error has been corrected. Also, see Section X-2. M. This has been incorporated into the mitigation section. O. An archaeologic survey will be done prior to the initiation of project construction. T. See General Comment lA. Thank you agai!1 for the constructive comments. We certainly appreciate your timely input and look forward to a successful working relationship with the U. S. Fish and Wildlife Service in bringing this project forward. cc: Larry Calvert, OMS C~\~~ Eric P. Yould "\ Executive Director ..... .... ., ... .4 ALASKA POWER AUTHORITY 334 WEST 5th AVENUE· ANCHORAGE, ALASKA 99501 Mr. John E. Cook Regional Director, Alaska Region U.S. Department of the Interior National Park Service Alaska Regional Office 540 W. Fifth Avenue Anchorage, Alaska 99501 July 28, 1982 SUBJECT: Draft Feasibility Reports of Hydroelectric Projects Phone: (907) 277·7641 (907) 276·0001 at King Cove, Larsen Bay and Old Harbor; Draft Reconnaissance Report of a Hydroelectric Project at Togiak. Dear Mr. Cook: Thank you for your letter of April 19th regarding the above referenced reports. We appreciate your participation and timely input in reviewing the draft reports. In response to the question raised in your letter, the State Historic Preservation Office was contacted and has commented on the proposed projects. Copies of all relevant correspondence will be included in the final feasibility reports. Should you have further questions regarding these studies, please contact myself or Mr. Don Baxter of my staff. EPY:jls <Ee:e1S? \ \ JJ. Eric P. Yould '\ Executive Director --------------------------_.--- LARSEN BAY HYDROELECTRIC PROJECT FEASIBILITY STUDY APPENDIX G SPACE HEATING INSTALLATION AND COST .... ..... - - ..... ,- APPENDIX G UTILIZATION OF EXCESS ELECTRICAL ENERGY FOR SPACE HEAT During much of the year the hydro unit can provide all of the electrical needs for the community. In addition there could be excess water for electric power to be used in space heat ing. This excess could displace the use of substantial amounts of fuel oil. SYSTEM PARAMETERS 1. The system must use only hydro generated power which is excess. It must be deactivated whenever diesel generators are on the line. 2. The system must use as much of the excess as possible. 3. The system must not overload the hydro unit electrically or mechanically. 4. It must not force the hydro to draw more water than the stream can provide. 5. It must have remote capability to control the loads, adjusting the heating loads to the available energy. 6. It must be compatible with existing heating systems. 7. It must be reliable because service is not readily available . NBISF-426-9523-AG 1 IMPLEMENTATION A very simple method would be to install a separate meter at each user, connect heaters and limi ting thermostats, and then switch them off and on manually. This approach would work reasonably well at times of very high water flow, but would require a good deal of effort from the operator at periods of marginal flow. In all probabil i ty this would lead to great ly reduced use of the resource. A more automatic system is probably justified. This system • • • • • -• .. -• • .. is envisioned as follows: • The main control would be a control computer programmed in control basic language and capable of storing its programming in a non-volatile media, eliminating battery backup. Interface systems would allow the unit to interpret a water level signal from the dam, drive a keyboard and monitor, interpret dry contact closures, and run a line driver capable of communicating with the remote heating loads. At the user end would be a control which would respond to the computer command to turn on heaters. The user equipment could take several forms as described below. Operation • !It .. -- • - • • • • • • 1. The control would sense that only the hydro unit is on the _ line by checking the diesel unit circuit breakers. 2. The water level behind the dam would be checked to see that excess water was available and going over the spillway. 3. The hydro is checked to see that it has excess generation capacity. NBISF-426-9523-AG 2 • • .. • • • • • • -• "" ... , .... - "' ... .... - - - .... 4. The control begins sending signals to turn on heaters at the user locations rechecking items 1, 2, and 3 after each increment. This is a slow process, perhaps over 10 minutes. 5. If the water level drops or the generator approaches full load, the controller reduces the heating load. This can happen quickly. This same control computer could also be used to limit the hydro water flow by regulating the governor setting and to start the diesels if more generation was required. It could control up to 64 remote units in its basic form. COST ESTIMATE . The design of this system is qui te preliminary and highly dependent on final hydro design and nature of heating systems to be served. The system designs for small and large users are shown as Figures G-1 and G-2. It is assumed that the first priori ty heat loads would be the schools and other public buildings. This tends to spread the benefits evenly among the tax payers and are more cost effective to connect. Major components are estimated as follows: Dam Water Level Sensors, Cable, and Transducers Control Computer and Inter- face Installed Electric Heating Equipment, Boilers or Baseboard Heat Control Signal Wiring to Connect Computer to Users NBISF-426-9523-AG 3 This item is part of hydro estimate. $10,000 Installed cost - $40 per kW $ 5,000 Software Development and Fiel d Installation User Controls, kWh Meters, Cost for Entire System $ 5,000 Assumes $15,000 spread over three projects $12,000 The cost estimate for the Larsen Bay system is summarized on Table G-l. NBISF-426-9523-AG 4 • • • • • -• .. • • • • • .. • .. ---- • • • • • • .. .. • .. • .. • • III • • • llliiSl' - " .... '- ~" "'iIi .. " .... 1. 2. 3. 4. 5. TABLE G-1 SPACE HEATING INSTALLATION LARSEN BAY HYDROELECTRIC PROJECT Item Quantity Unit Unit Price Control Computer 1 LS $10,000 and Interface Electric Heating 200 KW 40 Equipment Control Signal Wiring 1 LS 5,000 Software Development 1 LS 5,000 and Installation User Controls and 1 LS 12,000 Meters TOTAL NBISF-426-9523-G-1 Amount $10,000 8,000 5,000 5,000 12,000 $40,000