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Reconnaissance Assessment Of Energy Alternatives-Chilkat River Basin Region 2-1980
ALASKA POWER AUTHORITY LIBRARY COPY DO NOT REMOVE FROM OFFICE 1 : i 1 ea ee ee Sa ETO TT ORIE TE ET | CH2M SSHILL engineers planners economists scientists February 22, 1980 K13070.00 Alaska Power Authority 333 West 4th Avenue, Suite 31 Anchorage, Alaska 99501 Attention: Eric Yould Dear Mr. Yould: Attached is the report titled, Reconnaissance Assessment of Energy Alternatives, Chilkat River Basin Region. The report evaluates alternatives for supplying electric energy to Haines and Skagway. The report focuses mainly on hydropower, although other alternatives were also considered. Thirteen hydropower sites were originally identified. Technical, economic and environmental evaluations of the sites resulted in selection of six sites for inclusion in area power plans to serve Haines and Skagway. Two plans were developed for serving Haines, two plans for serving Skagway, and three plans for serving both communities through an intertie. A comparison of plans for separate generation for each community and the intertie plans favored separate plans. The six sites included in the area power plans are Upper Chilkoot Lake, Dayebas Creek, Upper Dewey Lake, Reid Falls Creek, West Creek, and Goat Lake. Based on our evaluations and the January 31, 1980, meeting with the utilities serving Haines and Skagway, we recommend that the utility serving Haines (Alaska Electric Light and Power) consider developing the Nayebas Creek project now and the Upper Chilkoot Lake project in the future as loads grow. We recommend that the utility serving Skagway (Alaska Power and Telephone Company) defer construction of the Reid Falls Creek or Upper Dewey Lake projects in favor of the proposed expansion of existing hydro- power facilities. If loads in Skagway grow more rapidly than projected, the utility should consider developing the Reid Falls Creek project. Anchorage Office 310 K Street, Suite 602, Anchorage, Alaska 99501 907/279-6491 Mr. Yould Page 2 February 22, 1980 K12070.00 The West Creek and Goat Lake projects should only be considered with an intertie between the communities, which is not economically feasible at this time. We would like to thank Robert Mohn of Alaska Power Authority for his cooperation in preparing this report. We would also like to thank William Corbis, Alaska Electric Light and Power and Robert Grimm, Alaska Power and Telephone Company, for providing information on the present electric systems in the two communities. It has been a pleasure working with APA on this report and we look forward to working with you again. Sincerely, Chalu.€ nthe Charles E. Torkko Regional Manager CET/GD:11 CHILKAT RIVER BASIN REGION RECONNAISSANCE ASSESSMENT OF ENERGY ALTERNATIVES For: STATE OF ALASKA ALASKA POWER AUTHORITY 333 West 4th Avenue, Suite 31 Anchorage, Alaska 99501 Prepared By: CH2M HILL ENGINEERING OF ALASKA, INC. 310 "K" Street, Suite 602 Anchorage, Alaska 99501 February 1980 K13070.00 CONTENTS Summary (5/5) 6 eo) 6) o |e lo! le! fa le 1 INELOAUCEION. sie « « «1 6) 6 «© 1 2 Community Power Needs ..... . Economic Development of Haines . Electric Load Growth and Forecast--Haines. Economic Development of Skagway. Electric Load Growth and Forecast--Skagway 3 Hydroelectric Power Site Assessment Field Reconnaissance .... Hydrology. =. « :« « «6 s © /s Site Development ...... Power and Energy ..... . Economic Evaluation. .... Environmental Evaluation .. 4 Alternative Energy Sources. ... Wood-Waste Thermal ..... Pidale- «<6 sw ews 6S Wind 2s s\ 6s 6 . 5 « = @ 1s Geothermal . ........ Energy Conservation. ... . 5 Transmission Intertie Assessment. Haines Transmission System . Skagway Transmission System. Haines-Skagway Intertie. .. Whitehorse-Skagway Intertie. Haines-Klukwan Intertie. .. 6 Area Power Plane . «.s+« «ess Haines Power Plans ..... Skagway Power Plans .... Haines-Skagway Intertie Power Plans. References: s.s 3 « «s/s 6 ss =). Exhibits (Bound at end of text) Exhibit A Hydrology Exhibit B Geologic Data Exhibit C Economic Analysis 5 Percent Interest Rate Exhibit D Economic Analysis 7 Percent Interest Rate NNNNN ' WNHRNE CON Re ee eT AU EPENRE NNUI PPE EP tt UO PkWRP eR 1 1 PROURR wR Se eee 1 o> Dan 1 PRWE bat ' b Contents, continued Exhibit E Economic Analysis 9 Percent Interest Rate Exhibit F Investment and Annual Costs for Area Power Plans Exhibit G Energy Costs for Area Power Plans, 5 Percent Interest Rate Exhibit H Energy Costs for Area Power Plans, 7 Percent Interest Rate Exhibit I Energy Costs for Area Power Plans, 9 Percent Interest Rate iv 10 11 12 13 14 L5 TABLES Historical Population--Haines ..... Employment in Haines by Industrial Classi fication — «6-6 esses High and Low Population Projections-- Haines Electric System Service ... Haines Electric System Energy Use Data Energy and Peakload Forecast Assumptions--Haines. ........ Number of Customers (By Class) High and Low Projections. ........ High, Medium, and Low Projections (1978-1990) Energy Sales by Customer Class--Haines ..........-. Historical Population--Skagway .... Estimated Employment--Skagway .... Low and High Population Projections-- Alaska Power and Telephone/Skagway Service Area. ........2.24.6-. Energy Use Data, 1973-1979, Alaska Power and Telephone Campany-- skag Ways. ee «16; 6 11s is 2 6 6 61: le Energy Use by Customer Class for 1978, Alaska Power and Telephone-- Skagway. « « » «© © » 0 © « © «© » « « Number of Customers, By Class, Low and High Projections Alaska Power and Telephone-- Skagway. « «© « «= =e w@ 8s ew ee ew Summary of High and Low Projections, 1978-1990 Energy and Peakload, Alaska Power and Telephone--Skagway. Low and High Projections, 1978-1990 Energy Peakload, Alaska Power and Telephone-- Skagway «._s: «_ «16 0. 10.6.6). #. «1-6. 2-15 2-16 2-18 2-19 2-28 2-31 2-33 2-35 2-36 16 ay 18 HLS 20 21 22 23 24 2D 26 27 28 29 Mean Annual and Mean Monthly Flows .... Site Features’ Summary. 5 3 «sss 3 6 3 5 3 6 Estimated Construction Costs ......... Estimated Project Schedule for Alternative Hydroelectric Facilities Near Haines and Skagway, Alaska. ...... Estimated Investment and Annual Cost for Alternative Hydroelectric Projects . . Projected Diesel Costs Per kWh ........ Benefit/Cost Ratios for Alternative Hydroelectric Sites at Haines and Skagway, at Interest Rates OL) 55) 7, and! 9 percent. |. | <|)slellaie is © - Haines Projects Transmission Costs ...... Skagway Projects Transmission Costs. ..... Transmission Intertie) Costs, = s)s|)s 4) «=| «| / Present Value of Alternative Haines Area Power Plan Costs, 1980-2005. ........ Present Value of Alternative Skagway Area Power Plan Costs, 1980-2005 ...... Present Value of Alternative Haines- Skagway Intertied Power Plan Costs, LO BO—Z2O0O5i5 |e) 3 |e) is fells 6) a) lie) 3 =| 3 |e) «| fo Comparison of Least-Cost Area Power Plans for Haines and Skagway, Separate versus Intertied Pillans. ls ie. 4 « a) |ae|s =| aie) =| ts EXHIBITS TABLES (Bound at end of text) Al A2 cL Comparison of Average Flows from Gage Analysis and Regional Analysis Comparison of Runoff Per Square Mile of Drainage Area Estimated Investment and Annual Cost for Alternative Hydroelectric Projects--Haines and Skagway, 5 Percent Interest Rate vi 3=5 3-9 3=13 3-58 3-60 3-63 3-66 5=5 5-10 6-9 6-16 6-23 6-25 C2=5 c6-10 D1 D2-5 D6-10 El E2-5 E6-10 F1-3 G1-2 G3-4 G5-7 G8 G9 H1-2 Projected Annual Costs--Haines Projects-- 5 Percent Interest Rate Projected Annual Costs--Skagway Projects--5 Percent Interest Rate Estimated Investment and Annual Cost for Alternative Hydroelectric Projects--Haines and Skagway--7 Percent Interest Rate Projected Annual Costs--Haines Projects-- 7 Percent Interest Rate Projected Annual Costs--Skagway Projects--7 Percent Interest Rates Estimated Investment and Annual Cost for Alternative Hydroelectric Projects--Haines and Skagway--9 Percent Interest Rate Projected Annual Costs--Haines Projects-- 9 Percent Interest Rate Projected Annual Costs--Skagway Projects--9 Percent Interest Rate Investment and Annual Cost for Area Power Plans--5, 7, and 9 Percent Interest Rates Energy Production Mix and Costs, Haines Power Plans--5 Percent Interest Rate Energy Production Mix and Costs, Skagway Power Plans--5 Percent Interest Rate Energy Production Mix and Costs, Haines-- Skagway Intertied Power Plan--5 Percent Interest Rate Energy Production Mix, Average Cost Per kWh, and Annual Cost for Electric Energy Produced for Haines Assuming No Additional Hydro 1980 to 2005 ‘Energy Production Mix, Average Cost per kWh, and Annual Cost for Electric Energy Produced for Skagway Assuming No Additional Hydro 1980 to 2005 Energy Production Mix and Costs, Haines Power Plans--7 Percent Interest Rate vii H8 H9 H10 aL I1-2 13-4 I5-7 I8 19 Energy Production Mix and Costs, Skagway Power Plans--7 Percent Interest Rate Energy Production Mix and Costs, Haines-- Skagway Intertied Power Plan--7 Percent Interest Rate Energy Production Mix, Average Cost Per kWh, and Annual Cost For Electric Energy Produced for Haines Assuming No Additional Hydro 1980 to 2005 Energy Production Mix, Average Cost Per kWh, and Annual Cost for Electric Energy Produced for Skagway Assuming No Additional Hydro 1980 to 2005 Average Energy Cost for Skagway Using Existing Hydropower and Diesel Facilities plus Proposed Expansion of Hydropower Facilities, 1980 to 2005 Weighted Average Energy Costs for Haines and Skagway Using Existing Power Facilities, Plus New Diesel, 1980 to 2005 Energy Production Mix and Costs, Haines Power Plans--9 percent Interest Rate Energy Production Mix and Costs, Skagway Power Plans--9 Percent Interest Rate Energy Production Mix and Costs, Haines - Skagway Intertied Power Plan--9 Percent Interest Rate Energy Production Mix, Average Cost Per kWh, and Annual Cost for Electric Energy Produced for Haines Assuming No Additional Hydro 1980 to 2005 Energy Production Mix, Average Cost Per kWh, and Annual Cost for Electric Energy Produced for Skagway Assuming No Additional Hydro 1980 to 2005 viii 10 id 12 13 14 15 16 17 18 19 20 2a 22 FIGURES Study Area Map ....... Projected Energy and Capacity Needs Compared . to Present Firm Energy and Capacity. ..... Chilkoot Lake Alternatives. Chilkoot Lake Diversion .. Chilkoot Lake Dam ..... Upper Chilkoot Lake... . . Upper Chilkoot Lake Powerhouse. Dayebas Creek ....... Dayebas Creek Powerhouse. . Ferebee River ....... Haska Creek ........ Upper Dewey Lake and Reid Falls Creek Upper Dewey Lake Powerhouse Reid Falls Creek Powerhouse West Creek. . . 2. 2. 2. «© « « West Creek Dam Site .... West Creek Powerhouse ... Skagway River ....... Goat Lake . . . « «© © «© « « Goat Lake Powerhouse. ... Skagway Tributary ..... Kasidaya Creek. ..... . ix . 2-39 3-15 3-17 3-20 3-23 3-25 3-27 3-28 3-30 3=32 3-34 3-36 3-37 3-39 3-40 3-43 3-45 3-47 3-49 3-51 23 24 25 26 27 28 29 30 3. 32 33 34 35 36 37 38 39 Figures, continued Cost of Energy--Haines. . ......-+-+-«-e-e Cost of Energy--Skagway. . . . . « « « « «© « « Haines and Skagway Systems .......e.e.-. Haines and Skagway Transmission Intertie. .. Haines, Comparison of Projected Energy Consumption to Monthly Production ...... Haines, Comparison of Projected Peak Loads 0) Capacities = % sis <\|e\s = s)miei\ le 5 «| « Haines, Comparison of Projected Energy Consumption to Annual Marketable Energy. . . System Energy Cost--Haines Power Plan Alternatives; 2 « © «| « i « i 6 8 « 0 © = « @ Skagway, Comparison of Projected Energy Consumption to Monthly Production ...... Skagway Comparision of Projected Peak Loads to Capacities. 5 2 «isis. © 2\6 3% |e Skagway Comparison of Projected Energy Consumption to Annual Marketable Energy. . . System Energy Cost--Skagway Power Plan Alternatives. |.|\2\6 | 5 3 \6\6\\s|\ |. «| «|| «| |e Haines-Skagway Intertied, Comparison of Project Energy Consumption to Monthly Production. . Haines-Skagway Intertied, Comparison of Projected Peak Loads to Capacities. .... Haines-Skagway Intertied, Comparison of Projected Energy Consumption to Annual Marketable Energy . ... +. +++ ++ ee « « System Energy Cost--Haines and Skagway Intertied Power Plan Alternatives. ......-+-+«s-s. System Energy Cost--Least Cost Alternative. .. 3-64 3-65 6-5 6-6 6-10 6=10 6-12 6-13 6-17 6-18 6-19 6-20 6-24 6-26 Ee BM summary This reconnaissance-level study provides evaluations of alternatives for supplying electric energy to the communities of Haines and Skagway in southeast Alaska. The report's main focus is on hydropower, but it also includes area power plans that incorporate hydroelectric, diesel-electric, and wood-waste thermal generation. Other alternatives, such as wind, geothermal, and tidal generation, were investigated but found infeasible at this time. Estimates of future electric energy demands in the two communities were made based on population and economic growth projections. The projections and load forecast were made through 1990. Energy loads were then extrapolated beyond 1990 to 2040, at the rate of 5 percent per year. At Haines the load growth is directly affected by the primary industry, Schnabel Mill. Expected growth in mill production will add jobs, increase population, and provide economic stability to the community. At Skagway the rate of load growth is dependent on the continued operation of the White Pass & Yukon Route railroad. If the railroad ceases to operate, population and energy needs will temporarily decline. Under the most probable economic and population trends, the energy load in Haines will increase from a present level of 6,890 MWh per year to 13,700 in 1990. At Skagway, the energy load is projected to drop from the present level of 5,990 MWh per year to 4,290 MWh per year if the railroad stops operating. If the railroad continues, loads will increase to 9,360 MWh per year in 1990. poe The power needs of Haines could be partially met by the wood-waste thermal generation plant proposed by Schnabel Mill. This interruptible source is not a long-term solution to the community's needs, but it could displace a significant amount of diesel generation in the near future. Hydropower is the most attractive source of electric energy for the two communities. Thirteen sites are identified and evaluated in this report. Each evaluation determined the technical, environmental, and economic constraints at each site. The technical evaluations included a field visit to collect geologic, hydrologic, and other data that are the basis for the conceptual site development plans in this report. The development plans include the proposed location and size of all project features, the proposed project operation, and the annual energy production. Construction and operation cost estimates are also presented for each site. The technical evaluation eliminated four sites from further environmental and economic consideration. The environmental conditions and probable environmental impacts associated with hydropower development at each site were determined based on data from published reports. Development of some sites would have minimal environmental impact while development of others could have significant impact. The two main concerns are increased suspended sediment during construction and impacts on anadromous fishery. Other concerns involve wildlife, scenic values, historic sites, and recreation facilities. An economic evaluation of each hydropower site was made to compare the cost of energy produced at the site with the xii cost of energy produced by diesel power. The analysis was made using interest rates of 5, 7, and 9 percent, inflation rates of 4 percent for construction and 6 percent for oil products, and an amortization period of 35 years. The analysis showed that several of the nine sites could be developed to produce energy at a cost less than diesel-electric generation. Seven alternative area power plans were developed. They are aimed at meeting the overall energy needs of the Haines-Skagway area to the year 2005. Existing power plants, new hydropower plants, and the proposed wood-waste thermal plant at Schnabel Mill are included in the plans. Two types of plans have been developed: (a) plans that provide completely separate generation and distribution systems for each community, and (b) plans that provide common generation facilities and a transmission intertie between the two communities. An economic evaluation of each plan was made to determine the least-cost plan to meet the area's energy needs through the year 2005. CONCLUSIONS Technical constraints do not prevent developing any of the thirteen sites identified. However, four of the sites (Ferebee River, Skagway River, Skagway Tributary, and Kasidaya Creek) have technical constraints that make development very expensive. Therefore, the four sites were dropped from further economic evaluation. The environmental evaluation of the nine remaining sites did not reveal any potential impacts that could not be avoided or mitigated at a reasonable cost to the projects. xiii The economic evaluation of the nine remaining sites (Chilkoot Lake Dam, Chilkoot Lake Diversion, Upper Chilkoot Lake, Dayebas Creek, Upper Dewey Lake, Reid Falls Creek, Goat Lake, Skagway River, and West Creek) showed that several sites have economic advantages over diesel generation. Four sites have benefit/cost ratios greater than 1.0 at all three interest rates: Upper Chilkoot Lake and Dayebas Creek near Haines and Upper Dewey Lake and Reid Falls near Skagway. Benefits are valued at the diesel-electric generation costs displaced by the hydropower facility. Two sites in the Haines area (Chilkoot Lake Dam and Chilkoot Lake Diversion) have benefit/cost ratios greater than 1.0 at low interest rates but their cost, per installed kilowatt, is nearly five times the cost at other sites. Two sites in the Skagway area (West Creek and Goat Lake) also have benefit/cost ratios greater than 1.0 at low interest rates. If more output from the Skagway sites was marketable through an intertie to Haines, then the projects will become more economically attractive. Two alternative area power plans for serving Haines were evaluated; both plans include existing facilities (diesel), a proposed wood-waste thermal plant, and additional diesel power, as needed. The first alternative includes the Dayebas Creek project and the second includes the Upper Chilkoot Y Lake project. Over the 1980-2005 planning period, the first alternative plan has a present value 33 percent less than the second plan, at 7 percent interest. Two alternative area power plans for serving Skagway were evaluated; both plans include existing facilities and addi- tional diesel power development, as needed. The first alternative includes the Reid Falls Creek project and the second includes the Upper Dewey Lake project. The first xiv alternative has a present value 24 percent less than the second, at 7 percent interest. Three alternative area power plans for serving both Haines and Skagway through an intertie were evaluated. The first plan includes the West Creek project, the second includes the Goat Lake project and the third includes the Upper Chilkoot Lake project; the least-cost plan was the second alternative. Its present value is 47 percent less than the first alternative and 9 percent less than the third, at 7 percent interest. A comparison of the least-cost power plan providing separate generation for each community and the plan providing an intertie between the communities favored separate plans. The separate plans have a present value of 17 percent less than the least-cost intertie plan, at 7 percent interest. RECOMMENDATIONS The utilities serving Haines and Skagway should proceed to develop hydropower projects to displace the diesel power currently used and to provide for future load growth. The Dayebas Creek project or the Upper Chilkoot Lake project should be considered for Haines and the Reid Falls Creek project should be considered for Skagway. An intertie between the communities should not be constructed at this time. At Haines, The Dayebas Creek project best matches the short- term load forecast, has a slightly higher benefit/cost ratio, and requires less capital investment than the Upper Chilkoot Lake project. However, the Upper Chilkoot Lake project displaces more diesel and provides more capacity and xV energy toward the long-term load forecast for Haines. Environmental constraints, economic evaluation, availability of capital and time required to license and construct are the factors that should be considered in selecting the project to develop. If the load increases faster than projected or if the cost of diesel fuel escalates faster than assumed, the economics of either project will be more favorable than shown in this report. At Skagway, the present generation facilities are sufficient to meet projected peakloads and annual energy requirements (assuming the railroad stops operating) well beyond the year 2005. Alaska Power and Telephone Company has proposed additions to the existing hydropower facilities over the next 3 years that will result in less use of diesel-electric generation. Because of the unstable economic future of Skagway and the uncertain load growth, it is recommended that development of the Reid Falls Creek project be delayed in favor of the proposed expansion of existing hydropower facilities. This will have the least impact on system energy costs in the near future. If the railroad continues to operate, causing the electric load to increase above projections in this report, or if the cost of diesel fuel increases faster than assumed, the economics of the Reid Falls Creek project will become more favorable. The project should then be considered for development. xvi MB ochapter 1 8 P INTRODUCTION This report presents the results of a reconnaissance-level study to assess alternative electric energy qeneration systems for the communities of Haines and Skaqway in south- east Alaska. Hydroelectric generation is the main focus of the report, but such other systems as wood-waste thermal, geothermal, wind, and tidal energy sources also are evaluated. The current and expected future enercy needs of the two communities are identified and plans are developed for meeting those needs. The technical, economic, and envir- onmental constraints of each alternative have been assessed. Fydropower development is well suited to this area because of the mountainous terrain and the larce annual precipita- tion and runoff. Fiaure 1 shows the study area and identi- fies the sites evaluated in this report. The study concen- trates on sites near Haines and Skaqway so that transmission costs are minimizec. Other large hydropower sites could be developed farther from the communities, but access and transmission costs make them uneconomical. Faines and Skaqway currently rely on two types of electrical ceneration: Haines uses diesel-electric generation and Skagway uses both diesel-electric and hydroelectric qeneration. Alaska Flectric Light and Power provides Haines with 4,400 kW of diesel-electric generation. Alaska Power and Telephone provides Skaqway with °75 kW of diesel-electric qeneration and 468 kW of hydroelectric generation. Two 1,250-kW diesel generators are being added to existing facilities at Skaqway, and an application has been filed with the Federal Fnergy Requlatory Aqency to add a 200-kW hydroelectric generator at Skaqway. The Haines and Skacway electric distribution systems are not intertied. \ ALASKA {CANADA \ MAP \ AREA ANCHORAGE | JUNEAU GULF OF ALASKA KEY TO SITES FIGURE 1 1. CHILKOOT LAKE 6. UPPER DEWEY LAKE A. DIVERSION 7. REID FALLS CREEK MAP OF STUDY AREA B. DAM 8. WEST CREEK 2. UPPER CHILKOOT LAKE 9. SKAGWAY RIVER 0 2 4 3. DAYEBAS CREEK 10. GOAT LAKE ee 4. FEREBEE RIVER 11. SKAGWAY TRIBUTARY SCALE IN MILES 5. HASKA CREEK 12. KASIDAYA CREEK MM chapter 2 ae 7 COMMUNITY POWER NEEDS Peakload and energy forecasting are planning tools useful in evaluating alternative energy generation systems for the Haines and Skagway areas. Changes in energy demand are directly related to the economic growth of the community. Two economic scenarios have been evaluated in this chapter and were used in preparing the peakload and energy forecast. This gives decision makers low and high growth projections to use in evaluating proposed energy development. For Haines, the low and high energy projections differ in their assumptions regarding major industrial developments. Although Haines recently experienced a decrease in employ- ment and population caused by a timber industry decline, this trend seems to have stopped. Both projections assume that employment in the timber industry will increase. For Skagway, the high and low projections differ in their main assumption about the future of the White Pass & Yukon Route railroad, the only major employer in the Skagway area. Because of the uncertain future of the railroad, it is advisable to base the feasibility of any major investments in the Skagway area on the low projection. The railroad has been experiencing financial difficulties over the last few years and has indicated that it will petition to cease operations if it does not receive financial aid. The Canadian government is considering the appeal for financial assistance and, until a decision is made, the future of the railroad is uncertain. The low-load projection reflects the very real possibility that the railroad will shut down in the early a=. 1980's. The peakload projections in this report were calculated using the current average load factors of 43 percent in Haines and 50 percent in Skagway. ECONOMIC DEVELOPMENT OF HAINES Historical Development Population As shown in Table 1, the population of Haines increased from 875 in 1960 to a high of 2,009 in 1975, but since then it has decreased again to the 1970 level of 1,500. The average annual growth rate for the Haines census division for the period 1960-1978 was 3.3 percent. The average annual decrease between 1970 and 1978 of .03 percent reflects an average annual growth rate of 6.6 percent from 1970 to 1975, and an average annual decrease of 14.9 percent from 1975 to 1977. Table 1 HISTORICAL POPULATION--HAINES Avg Annual % Change 1960 1970 1960 1970 1975 1976 1977 1978 1970 1978 Haines Census Division 875 1,504 2,069 1,850 1,500 1,500 5.6 0.0 Haines Greater Area 512 683 965 974 -- -- 209 -- Source: 1960, 1970, Bureau of the Census, U.S. Department of Commerce. 1975, 1977, Department of Labor, State of Alaska. 2-2 The number of residents in Haines is highly seasonal. In the summer months, the population peaks because of an influx of visitors and workers seeking seasonal employment opportu- nities. With the onset of winter, the population descreases-- and some of the resident population migrate out for winter employment. Economic Base Over the years, the Haines economy has been highly changeable, responding to a number of events: construction of Haines Highway, wartime closure of Ft. William H. Seward, commercial fishing, marine highway operation, pipeline construction, shifts in tourism, and changes in timber harvest. In the 1960's tourism, transportation, trade, and commercial fishing began to flourish. Recent history shows a greater dependence on the development of the southeast Alaska timber industry. Employment in Haines increased between 1960 and 1975, but the area has been losing employment since then. However, because data before 1975 are inconsistent, employment trends cannot be analyzed for those years. Table 2 summarizes 1975 and 1977 employment in Haines. This table shows that the primary sources of employment are manufacturing (timber) and government. These two sectors accounted for 60 percent of total employment in 1975 and 40 percent of total employment in 1977. The employment decrease was caused primarily by a permanent closure of one sawmill and temporary closure of another. Table 2 EMPLOYMENT IN HAINES BY INDUSTRIAL CLASSIFICATION Avg Annual Industrial Classification 1975 1977 % Change Mining 0 0. -- Construction 23, min -- Manufacturing 7a 47 (47.6) Transportation Communication & utilities 69 75 4.3 Retail trade nS 86 Wad, Finance-insurance Real estate 7 12 22.9 Federal, state, and local government BLS 6) 130 (2.2) Total 540 475 (6.2) anot reported to avoid disclosure of data for individual firms. Data withheld for a quarter or more of the year. Employment estimate not an accurate annual average. Source: Alaska Department of Labor, Bureau of Labor Statistics. The Bureau of Labor Statistics, U.S. Department of Labor, reports an unemployment rate of 5.2 percent for September 1979. This rate is below the rate reported in August, although the rate usually increases in September. The September 1979 rate is also well below the high of 29.4 percent reached in February 1977. Generally, all the monthly unemployment rates for 1979 have been at or below normal levels. These facts indicate that the decline in employment and population has leveled off and that new employment opportunities will cause an increase in population rather than provide jobs to unemployed residents. The timber industry in Haines consists of one major company, Schnabel Lumber, and several one-man operations. For many 2-4 years, there were two lumber companies operating in Haines (Schnabel Lumber Company and Alaska Forest Products); during the 1976 peak production year, the two provided employment to 300 employees and contract workers. State timber sales were restricted after 1971 and only salvage sales were available in the Haines area. Good-quality logs were bought from private companies who charged higher prices and would not guarantee supply. In 1975, Alaska Forest Products ceased production because of rising costs, poor location, and the inability to handle chips. The Schnabel mill closed in December 1977 because there was no dependable supply of logs. The mill reopened in September 1979, when it appeared that a contract might be negotiated with the Department of Natural Resources. The mill currently employs 48 workers. Fishing has been a primary economic activity in Haines, although there is no fish processing in the area. An esti- mated 75 to g5t residents of Haines actively fish commer- cially each year. However, with more boats from outside the Haines area fishing Lynn Canal, the local catch is decreasing. Since the inception of the Marine Highway System, tourism has provided seasonal and annual jobs for about 35 people. Local tourist attractions are the native Chilkat Dancers, sport fishing, the ferry and cruise-ship disembarkment points, Glacier Bay Monument, and Chilkoot Lake Wayside campground. Vehicle counts at the compground have increased from 9,200 in 1970 to 30,000 in 1978.+ At least two companies : City of Haines, Coastal Management Plan, prepared by Environmental Services Limited, October 26, 1979. offering tour packages have indicated they will add Haines to the cities their tours visit. Government is the largest single employer in the city, employing 130 people. While the number of employees decreased slightly between 1975 and 1977 because of a loss of special funding and expiration of temporary funding, it has decreased less than total employment and has been a stabilizing factor in the economy. The school system currently employs 55 persons and accounts for the greatest percentage of government employment. Projected Economic Development The economic future of Haines depends primarily on the future of tourism, the timber industry, and the potential development of the mining industry. Developments in these sectors, as well as other activities affecting the economic development, are discussed below. Timber The future of Haines's largest private employer, Schnabel Lumber Company, depends highly on state timber sales. Ina contract recently signed with the State of Alaska Department of Natural Resources (DNR), Schnabel was guaranteed a 25-year wood supply. This provides 54,000 acres that will be harvested on a sustained yield basis. Although Schnabel Lumber has negotiated this contract with the DNR, financing for the timber supply has not been obtained. According to company plans, when the timber sale is final- ized, Schnabel will hire an additional 35 employees. There are also plans to expand the sawmill in about 3 years, providing employment for 25 additional people. Rising diesel costs (used for power generation) have been one of the factors negatively affecting sawmill operations. Schnabel has applied to the Department of Renewable Resources for funding to construct a 4,000-kW, waste-wood-fired, electric generating plant. If funding is approved and the project is completed, it would be a step toward ensuring profitability and continued operations of the lumber company. Fishing Fish catches for local commercial fishermen have been de- creasing in recent years. For this reason and because construction of a fish processing plant is unlikely at this time, employment in the fishing industry is not expected to increase. However, because fishing represents a lifestyle to many Haines residents, it is unlikely employment in fishing will decrease much more. Recreation and Tourism Sport fishing is a popular activity in Haines. On Canadian holidays the influx of fishermen from Whitehorse is signifi- cant and will likely increase with the paving of the Haines Cutoff and the Alcan Highway. River rafting on the Chilkat, Tsirku, and Takhin has increased and the Sobek Company, a rafting outfitter, has announced plans to locate in Haines. These recreational activities have low-level service require- ments, and employment opportunities would be greater if the tourism were actively promoted and accommodations were expanded. Mining Two mining development operations are currently under con- sideration. Alyu Mining Corporation plans to develop a barite mine site at Glacier Creek and is beginning a 5-year test drilling program. During this exploration period, 15 persons will be seasonally employed at the site. If the ore body proves to be as large as expected, production could be as much as 5,000 tons per day (tpd). Potential employment is estimated to be between 200 and 250 workers in mining, milling, trans- portation, and terminal operations. Longshoring would also be needed. If the ore body is less than expected, the company's low production plan of 200 tpd would require employing approximately 40 to 50 persons.* General Enterprises is planning to develop a gypsum deposit located in British Columbia 60 to 70 miles northwest of Haines. The firm is considering two possible development options. According to Homan-McDowell Associates, the first involves constructing a gypsum plant in Haines to produce wallboard and bagged gypsum; the second option would be to crush the mineral at the mine site and truck it into Haines for subsequent bulk ore shipment. This option would require bulk storage at a waterfront site, and barging the ore to another location for processing. 1 Information regarding the Alyu mine was obtained in inter- views with a company representative and reported in the "Economic Adjustment Plan for Haines, Alaska," prepared by Homan-McDowell Associates in association with R. W. Pavitt and Associates, Craig Lindh Associates, and Environaid. 2-8 If a processing plant is established in Haines, an estimated 50 persons would be employed at the plant. In either devel- opment option there would be a need for 25 to 40 truckdrivers and additional longshoremen. No mine employment estimates are available. There is also a large iron ore deposit, estimated to contain 13 billion tons, near Klukwan, 24 miles northwest of Haines. Development of the deposit would involve construction of a large concentrating plant at Klukwan, and a pipeline to Haines. The substantial investment required, the unavailability of power, the high cost of diesel-electric power generation, and the environmental concerns associated with development of the site are contributing to the present infeasibility of the project. Other Developments Construction of the Alcan pipeline would also affect the Haines economy because Haines would serve as a transshipment point for materials and supplies. The local impact would be similar to construction of the Trans-Alaska pipeline, affecting all sectors, and especially transportation. Financing is currently being sought for the project, and if obtained it would be several years before additional activity in the Haines economy would result. Population Projection High and low population projections were developed for the Haines electric system service area, as shown in Table 3. The average of the two constitutes a medium projection, which is considered most probable. 2=9 Table 3 HIGH AND LOW POPULATION PROJECTIONS - HAINES ELECTRIC SYSTEM SERVICE Base Adjusted Total Population Changes in Employment Changes in, Population Percent Projection Direct Indirect Total Population Projection Change Low Projection 1978 1,428 - - - - 1,428 - 1979 1,442 - - - - 1,442 1.0 1980 1,457 35 35 70 126 1,583 9.8 1981 1,471 35 85: 70 126 1,597 9 1982 1,486 35 35 70 126 1,612 9 1983 1,501 35 35 70 126 1,627 9 1984 1,516 35 35) 70 126 1,642 9 1985 1,531 35 35 70 126 1,657 9 1986 1,546 35 95) 70 126 1,672 9 1987 1,562 35 35 70 126 1,688 9 1988 1,577 35 35 70 126 1,703 9 1989 1,593) 35 35 70 126 1,719 9 1990 1,609 35 35 70 126 1,735 9 High Projection 1978 1,428 - - - - 1,428 - 1979 1,471 - - - - 1,471 3.0 1980 1,515 35 35 70 126 1,641 11.6 1981 1,560 35 35 70 126 1,686 2.7 1982 1,607 60 60 120 216 1,823 8-1 1983 1,655 60 60 120 216 1,871 2.6 1984 1,705 210 210 420 756 2,461 31.5 1985 1,756 210 210 420 756 2,512 2.1 1986 1,809 250 250 500 900 2,709 78 1987 1,863 250 250 500 900 2,763 2.0 1988 1,919 250 250 500 900 2,819 2.0 1989 1,976 250 250 500 900 2,876 2.0 1990 2,035 250 250 500 900 2,935 2.0 Flow projection assumes Schnabel Lumber will hire 35 people in 1980 High projection assumes Schnabel Lumber will hire 35 people in 1980, another 25 people in 1982 and that Alyu Mining and General Enterprises will hire 150 and 40 people, respectively, from 1984 to 1986, One indirect employee for every direct employee. “Based on a 1.8. residents per employee. Estimates indicate that 1,482 residents made up the service area in 1978. This base population is projected to grow at different rates, based on expectations for the local economy. The low and high base population projections were adjusted for major industrial developments that would significantly impact population growth. The low population growth rate of 1 percent assumes that there will be a growth in the tourism and service sectors of the economy that is less than the historical growth rate. The high population growth rate of 3 percent assumes that Haines will actively pursue development of tourism and recreation, producing a rate of population growth near historical levels. The rate of growth in the Haines greater area between 1960 and 1970 was 2.9 percent. The 1960 to 1970 growth rate is used because since 1970 the city has seen both a dramatic increase and a decrease in population. Growth rates portraying these shifts would not be indicative of the long-term population trends. Both the low and high projections were adjusted to include 35 employees that Schnabel Lumber Company will hire when the state timber sale is finalized. The low projection assumes no other major developments affecting the population base. The high projection assumes that Schnabel Lumber Company will expand the sawmill in 1982 and will hire another 25 people; that the Alyu Mining Corporation will begin mining the Barite mine site in 1984 and employ 150 new workers; and that General Enterprises will develop its gypsum deposit and hire 40 people. Both the low and high projections were adjusted for indirect employment changes that result from the direct employment changes. An analysis of employment in 1975 showed that for 2-11 every employee in an exporting industry or service, there was one local service employee, resulting in an employment multiplier of 2. In 1979, there were 965 residents in the greater Haines area and 940 employees (see Tables 1 and 2), resulting in a population multiplier of 1.8. The population estimates and employment adjustments are shown in Table 3. ELECTRIC LOAD GROWTH AND FORECAST--HAINES Historical Peakload and Energy Characteristics Energy usage in Haines has been extremely variable since 1971, reflecting changes in the economy and population levels (see Table 4). Total usage grew at an average annual rate of 16 percent from 6,725 MWh in 1971 to 12,186 MWh in 1975. Usage has since decreased to 6,891 MWh in 1978. Residential sales decreased from 35 percent of total sales in 1971 to 28 percent in 1975, and have since increased to 41 percent in 1978. During the same period, average resi- dential use increased from 5.5 MWh in 1971 to 7.1 MWh in 1975 and then decreased to 6.3 MWh in 1978, resulting in an overall average annual growth rate of 2.1 percent. The number of residential customers has been only slightly more stable, increasing a total of 1 percent from 404 to 408 for the 1971 to 1978 period. The highest number of customers, 454, was attained in 1975. The commercial class sales increased from 25 percent of total sales in 1971 to 47 percent in 1978. Average annual use per commercial customer increased 86 percent while the number of customers increased 1.4 percent during the same period. Total commercial sales have increased at an average annual rate of 9.5 percent between 1971 and 1978. 1971 Average Number of Customers Residential Commercial Industrial Street Boat Harbor 404 146 4 1 Average Energy Use/Customer (kWh) Residential ae Commercial 10, Industrial 614, Street Lighting 14, Boat Harbor Total Energy Use (MWh) Residential Zs Commercial 1, Industrial 2, Street Lighting Boat Harbor TOTAL 6, System Losses (MWh) Total Requirements (MWh) 6. System Losses (%) 5 Annual Peak Demand (kW) a Month of Peak System Load Factor (%) 480 753 000 085 214 570 456 14 254 471 725 7 850 DEC 41.5 Table 4 HAINES ELECTRIC SYSTEM ENERGY USE DATA 1972 1973 1974 407 386 437 148 140 159 6 6 6 1 1 1 6,177 6,948 6,551 10,581 U7 14,893 495,833 881,000 979,500 5 16,096 114,745 115,311 1 2,514 2,193 2,863 1,566 1,348 2,368 297.5 4,322 5,877 16 94 LS) 7,071 7,957 LL 213 p33 599 844 9,603 8,557 12,062 7 Gj 7 1,950 1,950 1,950 DEC DEC DEC 44.5 50.1 70.6 7,101 16,376 370333 09,683 3,224 2,702 5,297 110 LS tS3 853 12,186 u 1,950 DEC 71.3 7,102 19,396 528,000 129,603 2,912 2,890 1,584 129 V1 566 8,080 7 1,300 DEC 47.3 6,106 18,039 519,000 168, 483 2,595 2,778 1,038 168 6,579 495 7,074 7 1,300 DEC 41.4 1978 408 148 26 6, 336 20,034 279,000 164,401 5,615 2,585 2,965 558 164 146 6,418 473 6,891 1,300 DEC 40.3 Percentage Change 1971-1978 a uw oorr coro 2commercial customers 1971-1977 estimated prorata ratio of 1978 actual commercial customers to residential customers. Estimated. Average Annual % Change 1971-1978 owoo Orne LS Industrial customers accounted for 39 percent of total sales in 1971, 52 percent in 1974, and 9 percent in 1978. The number of industrial customers was four in 1971, six in 1974, and two in 1978. Average use per industrial customer increased from 614 MWh to 980 MWh in 1974 and then decreased to 279 MWh in 1978. Total industrial sales followed the same pattern of growth and recession from the 1971 level of 2,456 MWh to 5,877 MWh in 1974 to 558 MWh in 1978. Energy use for street lighting has increased dramatically from a 1971 level of 14 MWh to 164 MWh in 1978. The seasonal variation in energy requirements is illustrated by the 1979 monthly energy sales shown below. Mwh Mwh January 607 July 411 February 652 August 456 March 530 September 492 April 519 October 492 May 501 November 588 June 456 December 588 Forecast Methodology and Assumptions The energy and peakload forecasts are based on the foregoing population forecast and economic projections; major energy forecast assumptions are presented in Table 5. Table 6 shows the projected number of residential, commercial, industrial, street light, and boat harbor customers. Calculations for commercial customers are based on their ratio to the number of residential customers in 1978 (2.8 residential customers per commercial customer). Industrial customers were projected primarily according to known devel- opments in that sector. However, in the high projection, 2-14 unidentified industrial customers were added under the assumption that the increase in economic activity could induce one industrial customer to locate in Haines. The number of street light and boat harbor customers is expected to remain the same. Table 5 ENERGY AND PEAKLOAD FORECAST ASSUMPTIONS--HAINES Forecast Parameters Persons per household (residential customer) 325 Residential customers per commercial customer 2.8 Street light customres 2 Boat harbor customers 26 Annual increase in average energy use per customer Residential 2% Commercial 2% Industrial 1% Street light 1% Boat harbor 0.5% Average load factor 43% The average energy usage for residential and commercial customers is expected to increase 2 percent per year. This is slightly below the past average annual increase (2.2 percent) for residential consumption. The reason for selecting a lower-than-historical rate is the anticipated small increase in conservation. This rate was used to project the con- sumption for both classes because the most reliable data for average annual consumption were obtained for the residential class. The average usage for industrial customers has decreased over the 1971-1978 period. However, because wood supplies are expected to increase, causing an increase in the industrial load, and because new industrial customers probably 2-15 Table 6 NUMBER OF CUSTOMERS (BY CLASS) HIGH AND LOW PROJECTIONS a Number of” Number of© Number of Number of Number of Adjusted Residential Commercial Industrial Street Light Boat Harbor Population Customers Customers Customers Customers Customers Projections 1978 1,428 408 148 2 1 26 1979 1,442 412 148 2 1 26 1980 1,583 452 161 2 1 26 1981 1,597 456 163 2 1 26 1982 1,612 461 165 2 1 26 1983 1,627 465 166 2 1 26 1984 1,642 469 168 2 1 26 1985 1,657 473 169 2 1 26 1986 1,672 478 171 2 1 26 1987 1,688 482 172 z dL. 26 1988 1,703 487 174 Z 1 26 1989 1,719 491 175 2 1 26 1990 L735) 496 177 2 L 26 High Projections 1978 1,428 408 148 2 iL 26 1979 1,471 420 150 2 1 26 1980 1,641 469 168 2 iL 26 1981 1,686 482 172 2 1 26 1982 1,823 521 186 3 1 26 1983 1,871 535 191 3 1 26 1984 2,461 703 Z51 3 1 26 1985 2,512 718 256 3 L 26 1986 2,709 774 276 4 1 26 1987 2.103 789 281 4 1 26 1988 2,819 805 288 4 1 26 1989 2,876 822 294 4 1 26 1990 2,935 839 300 4 i 26 pFrom Table 3. (Colum 1 divided by 3.5 persons per household. Column 3 divided by 2.8 except 1978 figures - actual. will not generate their own power like Schnabel Mill, usage is projected to increase at an assumed rate of 1 percent. The average annual rate of increase for street lights has been quite high because of a construction program by the city, which is nearly complete. Therefore, street light usage was also projected at the nominal rate of 1 percent. Because the price of electricity is comparatively high to boat harbor customers, it is unlikely average usage will increase substantially. Thus, average annual usage for boat harbor customers was projected at 0.5 percent. The increases in average consumption are the same for both the low and high projections. Peakload_ and Energy Forecast Low and high peak and energy projections were calculated to reflect the low and high economic and population forecasts discussed above. A composite projection which averages the high and low projections was also calculated and is con- sidered to be most representative of what will occur in the future. Table 7 shows peakload and energy forecasts. Total system energy requirements increase from 6,891 MWh to 10,165 MWh in the low projection and to 17,165 MWh in the high projection during the forecast period 1978 to 1990. In both projections, energy requirements grow more quickly in the early years with the growth rate leveling off in later years. The average annual rates of change in the first 6 years are 3.9 percent and 10.9 percent for the low and high projections, respectively. For the next 6 years those rates are 2.7 percent and 5.0 percent, respectively. The contribution of each class to total system energy requirements remains roughly the same. Beyond 1990 energy requirements were projected at an annual increase of 5.5 percent. This corresponds to the overall growth rate between 1980 and 1990. 2-17 Table 7 HIGH, MEDIUM, AND LOW PROJECTIONS (1978-1990) ENERGY SALES BY CUSTOMER CLASS - HAINES Actual 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Low Projection (MWh) Residential 2,585 2,663 2,980 3,066 3,162 3,253 3,346 3,442 3,549 3,650 3,762 3,868 3,986 Commercial 2,965 3,025 3,356 3,465 3,579 3,672 3,791 3,890 4,014 4,119 4,250 4,360 4,498 Industrial 558 564 569 Sh 581 586 592 598 604 610 616 622 629 Street lights 164 166 168 169 7 173 175 176 178 180 182 183 185 Boat harbor 146 147 147 148 149 150 150 151 152 153) 153, 154 155 Total 6,418 6,565 7,220 7,423 7,642 7,834 8,054 8,257 8, 497 8,712 8, 963 9,187 9,453 System losses (7%) 473 494 543 559 575 590 606 621 640 656 675 691 712 Total system requirements 6,891 7,059 7,763 7,982 8,217 8,424 8,660 8,878 9,137 9, 368 9,638 9,878 10,165 Peakload (kW) 1,950 1,870 2,060 2,120 2,180 2,240 2,300 2,360 2,430 2,490 2,560 2,620 2,700 High Projection (MWh) Residential 2,585 2,714 3,092 3,241 ss ow BS 3,742 5,016 5,226 5,746 5,974 6,218 6,476 6,742 Commercial 2,965 3,066 3,502 3,657 4,034 4,225 5,664 5,892 6,479 6,729 7,034 fae: “7,623 Industrial 558 564 569 575 871 880 888 897 1,208 1,221 15253 1,245 1,258 Street lights 164 166 168 169 U1 173 175 176 178 180 182 183 185 Boat harbor 146 147 147 148 149 150 150 151 152 rz LSD: 154 155 Total 6,418 6,657 7,478 7,790 8,798 9,170 11,893 12,342 13,763 14,256 14,820 15,382 15,963 System losses (7%) 473 501 563 586 662 690 895 929 1,036 1,073 Li 15 1,158 1,202 Total system requirements 6,891 7,158 8,041 8,376 9,460 9,860 12,788 S272 14,799 15,329 15,935 16,540 17,165 Peakload kW 1,950 1,900 2,130 2,220 2,510 2,620 3,390 3,520 3,930 4,070 4,230 4,390 4,560 Medium Projection® (MWh) Residential 2,585 2,689 3,036 3,154 3,368 3,498 4,181 4,334 4,648 4,812 4,990 5,172 5,364 Commercial 2,965 3,046 3,429 3,561 3,807 3,949 4,728 4,891 5,247 5,424 5,642 5,842 6,060 Industrial 558 564 569 575 726 733 740 748 906 916 925 934 944 Street lights 164 166 168 169 171 173 175 176 178 180 182 183 185 Boat harbor 146 147 147 148 149 150 150 151 152 152 153 154 155, Total 6,418 6,612 7,349 7,607 8,221 8,503 9,974 10, 300 Lisi 11,484 11,892 12,285 12,708 System losses (7%) 473 498 325, 573 619 640 wou 775 838 864 895 925 957 Total system requirements 6,891 7,110 7,902 8,180 8,840 9,143 10,725 11,075 11,969 12,348 12,787 13,210 13,665 Peakload (kW) 1,950 1,890 2,100 2,170 2,350 2,430 2,850 2,940 3,180 3,280 3,400 3,510 3,630 ®average of low and high projections. Table 8 HISTORICAL POPULATION--SKAGWAY Census Division Skagway/Yakutat City Greater Area 1960 2,070 659 = 1970 2pLon 675 708 1975 2,638 834 - 1976 2,853 954 - 1977 2,700 = - 1978 = 877 914 Average annual % change 1960-1970 0.4 0.2 - 1970-1978 3.3° 3.3 3.2 21970-1977. Source: 1960-1970 actual, 1970-1977 estimates, Bureau of Census 1978 Community and Regional Affairs, State of Alaska. The increase in peakload from 1978 to 1990 varies from 750 MW to 2,610 MW. Since the peakload was derived from the energy requirement projections using a constant load factor, the largest increases occur in the first half of the projec- tion period. Likewise, peakload projections beyond 1990 increase at the same rate as energy projections. ECONOMIC DEVELOPMENT OF SKAGWAY Historical Development Population The Skagway area population increased steadily from 1960 to 1976 but census estimates have shown a decrease since that year. Historical population trends for the Skagway/Yakutat Census Division, the City of Skagway and the greater Skagway area are shown on Table 8. The greater Skagway area accounts for approximately one third of the Skagway/Yakutat census division population, and the City of Skagway accounts for 95 percent of the greater Skagway area population. Although data for the greater Skagway area are incomplete, both the city and the greater city area seem to be following the same general population trends as the census division area. From 1960 to 1970 the average annual growth rate for the city and the census division was 0.2 percent and 0.4 percent, respec- tively; the annual growth rate over the last 8 years was approximately 3.3 percent for all three areas. Since 1976 population has decreased 5 percent in the census division and 8 percent in the City of Skagway. This recent population trend is assumed to be the same for the greater Skagway area. The population in Skagway is more seasonally stable than most cities in southeastern Alaska because of its relatively 2-20 heavy dependence on the transportation industry, which operates year-round. There is some seasonal population shift caused by the local tourist industry. Economic Base Unlike most Alaska communities, Skagway's economic hase is not heavily dependent on the timber and fishing industries. Instead, the Skagway economy centers primarily on trans- portation and tourism because of its location and history. The city was founded as a "gateway" city, a transportation corridor to interior Alaska and Canada during the Klondike Gold Rush. Its strategic position has given the city a virtual monopoly on transportation services to the Yukon Territory. Skagway's historical setting, the Klondike Gold Rush National Historical Park, and the spectacular surrounding scenery have made the city one of the most popular vacation areas in southeast Alaska. Over 60 percent of total employment in Skagway is generated by the transportation/commerce industry, as shown in Table 9. The bulk of year-around employment is generated in railroad and shipping terminals. The area's principal employer, the White Pass & Yukon Route railroad hauls lead-zinc concentrate, silver-lead-zinc concentrate and copper ore from the Yukon to Skagway for shipment by waterborne carriers. The railroad also operates a daily passenger service between Whitehorse and Skagway; during the summer passenger service also is provided between Skagway and Bennett. Each train has a capacity of 300 persons and transports roughly 750,000 tons of cargo per year; 500,000 tons of ore are moved south and 250,000 tons of general cargo are moved north. Over the last few years railroad traffic has declined after losing all asbestos cargo and other cargo to competitors; this has caused a corresponding decrease in railroad equipment. 2-21 Table 9 ESTIMATED EMPLOYMENT--SKAGWAY Occupations Number Employed Agriculture (fishing) 0-10 Construction 10 Finance, Insurance, and Real Estate 10 Government 40 Mining 0 Manufacturing/Processing 5 Service 30 Trade 45 Transportation, Commerce 190 Other 0 Total (Average) 310 Source: State of Alaska, Division of Economic Enterprise, Skagway, An Alaskan Community Profile, May 1979. Services and trade account for the next largest employment sector, which is almost 25 percent of total employment. High employment in this sector reflects the substantial tourist trade in Skagway. Since 1969 Skagway has benefited from the boom in cruise ships; at the peak of cruise ship activity, over 100 ships visited during the summer months. Skagway is also the northern terminus of the Alaska Marine Highway System, receiving three to five ships a week year- round. Westours, Inc., a local tour guide company, offers tours over the White Pass & Yukon Route. In 1979 the Klondike International Highway (Carcross Road), opened connecting Skagway with Whitehorse and the Alaska Highway. A local official estimated that 45,000 visitors traveled the highway during the summer of 1979; peak weekend traffic was estimated at 500 vehicles. The one setback in an otherwise progressing tourist industry has been the initiation by some cruise ship companies of a 7-day cruise which returns from Juneau rather than the traditional 8-day cruise which returns from Skagway. The decrease in the number of cruise ships to Skagway has re- sulted in depressed tourist-related activity since 1977. Projected Economic Developments The economic future of Skagway will depend primarily on the future of the primary employer in the area, the White Pass & Yukon Route railroad. Developments in the transportation industry, as well as tourism, and other potential development activities are discussed below. Transportation Railroad operations have decreased over the last few years, resulting in decreased employment in the Skagway area. Federal Industries, the owner of the White Pass & Yukon Route railroad, has indicated that the railway division is not providing sufficient return to continue operations. The company has applied to the Canadian government for financial assistance. A special task force appointed by the Minister of Indian and Northern Affairs investigating the railroad's operations recommended that the request for financial assis- tance be rejected. A second request for assistance is 2-23 currently being investigated by the Canadian Railway Trans- portation Commission. A spokesman for the Commission stated that the investigative report was not due for three to four months and then it is uncertain when a decision would be made. A representative for the company indicated that the railroad would definitely operate through 1980, but without financial assistance it would request permission from the Canadian Transport Commission to abandon the railroad. Opinions vary as to the possible outcome of the railroad dilemma. Other factors which may influence the decision to continue or discontinue the White Pass & Yukon Route are listed below. e Although it is old and out of date, the narrow gauge railroad is a popular tourist attraction. e There is a high potential for mineral development in the Yukon Territory beginning in the mid-1980's. As mines become productive it will increase the demand for bulk movement by rail. @ The White Pass & Yukon Route provides the only railroad service from inland to tidewater in southeast Alaska. e If the Alcan pipeline is constructed, Skagway would be a major entry point for construction materials, placing a heavy demand on all transpor- tation facilities. e There has been some discussion about lengthening the railroad, which would provide service to a greater area in the Yukon Territory. CY The Klondike International Highway offers alterna- tive overland transportation between Skagway and Whitehorse but the highway currently is not main- tained in the wintertime. e Federal Industries owns trucks that carry ore from the Yukon Territory to the railroad. It may be economically feasible for them to transport the ore entirely by truck, thus eliminating the need for railroad transportation. ” Westours has threatened to discontinue use of the railroad passenger service and may use buses instead. If the railroad follows its plans to cut back operations over at least the next three to five years, employment in the railroad industry will continue to decrease. It is possible that this may be offset, at least partially, by an increase in containerized cargo through the port. Port facilities are being upgraded and a new barge loading unloading dock is being constructed. Tourism The tourism industry is expected to rebound from several weak seasons and remain a steady contributor to the Skagway economy. New access through the Klondike International Highway should offset the slight decline in cruise ship traffic. The city is currently expanding their small boat harbor to accommodate an additional 100 boats. Residents of Whitehorse, the Yukon Territory, and Southeast Alaskan fisherman are expected to use the boat harbor, contributing to an increase in marine and tourist support services. The city is continuing restoration of its Historic District and 2-25 improvement of camping facilities. Over the last several years the city has appealed to the state and Federal govern- ment to fund an additional campground, although there has been no action on the request to date. Other Developments Developments in oil and gas pipeline projects under consid- eration in the United States and Canada could lead to a major expansion in the Skagway economy in the early and mid-1980's. As mentioned above, Skagway could serve as a major entry point for materials if the Alcan gas pipeline is constructed. Heavy demands would be placed on all trans- portation facilities and local services during the construction period. The pipeline project has been subject to continuous delays and financing is currently being sought. Once financing is obtained it still may be several years before any impact is felt at Skagway. The Canadian Government has asked the Foothills Oil Pipeline Company to resubmit its application for pipeline route approval. The Foothills proposal, which calls for an oil port at Skagway, had been withdrawn from the Canadian National Energy Board (NEB) hearings. A decision to build an oil port would obviously have a tremendous impact on the local economy. At this time it is not possible to determine the probability of the Foothill proposal being approved or to quantify the probable employment and population impacts. It is safe to conclude that, given NEB and U.S. approval, there would be no major construction activity until 1983-1985. Population Projection High and low population forecasts for the Skagway area reflect two possible economic scenarios that differ mainly 2-26 in their assumptions about the future of the White Pass & Yukon Route railroad. Although the railroad is certain to operate through 1980, there is a very real possibility that it will discontinue operations after 1980. The low projection assumes local economic conditions will remain stable through 1980 but forecasts a decline in population in 1981, 1982 and 1983 due to closure of the railroad. The high projection assumes that the railroad will continue to operate and local economic conditions will remain stable for the next five years, after which improvements in the economy will produce a steady population increase. Low Population Projection The low projection, shown on Table 10, shows no change in population from 1978 (the latest population estimate avail- able) through 1980. The impact of the railroad closure after 1980 on employment and population is shown below. Cumulative Changes in Employment Changes in Direct Indirect Total Population 1980 -- -- -= 1981 (30) (12) ( 42) (126) 1982 (60) (24) ( 84) (252) 1983 (90) (36) (126) (378) It is estimated that 90 people, or 60 percent of the 150 people employed by the railroad, would leave the Skagway area over a 3-year period. The remaining 60 people are assumed to be able to locate other jobs in the community. In addition to the employment change caused directly by the railroad, there are indirect employment changes that result from the direct change. An analysis of employment showed that for every two employees in a major industry (tourism, transportation/commerce) in Skagway, there is approximately 2-27 one local, service-oriented employee, resulting in an employ- ment multiplier of 1.4. Analysis of employment to population showed there were approximately three residents for every employee in the Skagway region, yielding a population multi- plier of 3.0. It is unlikely that the population would continue to decrease after 1983. The mid-80's look promising for development in the Yukon Territory, and there are several potential pipeline projects that would have a positive impact on the Skagway economy. Also, it is probable that the state government would aid the City of Skagway in attracting new industry, as they have done for the neighboring City of Haines. (The state funded an "Economic Adjustment Plan" for Haines when the city's major employers shut down). Table 10 shows the low population estimate increasing from 1983 to 1990 at an average annual rate of 3.0 percent. Table 10 LOW AND HIGH POPULATION PROJECTIONS ALASKA POWER AND TELEPHONE/SKAGWAY SERVICE AREA Low High Population Projection” Population Projection® 1978" 914° 914° 1979 914 914 1980 914 914 1981 788 914 1982 662 914 1983 536 914 1984 552 951 1985 569 989 1986 586 1,028 1987 603 1,069 1988 621 1,112 1989 640 1 Loi) 1990 659 1,203 @estimate from Department of Community and Regional Affairs, State of Alaska. Projected to decrease in 1981 through 1983 due to railroad closure, increase after 1983 at annual rate of 3%. “projected to increase after 1984 at an annual rate of 4%. 2-28 67-c Average number of customers Average use per customer (MWh) Energy sales (MWh) System losses (MWh) Total requirements (MWh) Percent system losses (%) Annual peak demand (Kw) System load factor (%) 43 months data annualized. 11.0 3, 492 200 3,692 900 46.8 Table 11 ENERGY USE DATA 1973-1979 ALASKA POWER AND TELEPHONE COMPANY--SKAGWAY 51.2 1975 359 12. 4,313 1976 369 12.5 4,601 661 5,262 12.6 1,100 54.6 1977 413 1232) 5,057 800 5,857 14.0 1,300 51.4 1978 422 12.4 5,254 732 5,987 12.2 1,400 48.8 19797 400 15.0 5,387 High Population Projection The high projection assumes that the local population will stabilize at the 1978 level and remain constant until the early to mid 1980's. Continuation of the railroad and a steady tourism industry will contribute to the stability of the local economy until 1983, when development in the Yukon Territory and potential pipeline projects may produce an increase in population. The high population projection forecasts this increase at an annual rate of 4 percent beginning in 1984. ELECTRIC LOAD GROWTH AND FORECAST--SKAGWAY Historical Peakload and Energy Characteristics Historical load data for the Skagway service area of Alaska Power and Telephone are incomplete; pre-1973 data and com- plete data for 1975 are unavailable. Table 11 presents energy sales, losses and annual peak demand since 1973. Total energy requirements increased by over 60 percent between 1973 and 1978 from 3,700 MWh to 6,000 MWh, producing an average annual increase of 9.7 percent. This increased load was the result of a 5.9 percent average annual increase in the number of customers and a 2.4 percent annual growth in average use per customer. Losses averaged 11.7 percent of total system requirements for the period and utility officials estimate the annual system load factor at approxi- mately 50 percent. Preliminary data for 1979 are shown with all percentages calculated on 1978 data. Preliminary data for 1979, based on 8-months data annualized, show a decrease in the number of customers, and an increase in average use per customer, producing an increase in total energy sales of 2.5 percent over 1978. Energy use data by customer class (shown in Table 12) were only available for 1978. The residential class accounts for the highest use, consuming 35 percent of total energy in 1978, followed by commercial use (34 percent) and the railroad (20 percent). The government class is the lowest user, account- ing for 10 percent in 1978. Table 12 ENERGY USE BY CUSTOMER CLASS FOR 1978 ALASKA POWER AND TELEPHONE--SKAGWAY Annual Energy Number of Average Annual Use Customer Class Use Customers Per Customer (MWh ) (MWh ) Residential 1,861 261° 7.1 Commercial 1,790 #156 14.9> Government 539 -- -- Railroad 1,064 5 213.0 Total 5,254 422 liestimated by dividing 1978 population by 3.5 persons per household. Includes government customer class. Source: Alaska Power and Telephone FPC from December 1. A breakdown of average number of customers by class is not available. The number of residential customers was estimated by dividing the 1978 population by 3.5 persons per household. The railroad receives power through 5 different meters. The remaining 156 customers are classified commercial and government since there are no industrial customers. Annual usage per customer averaged 7.1 MWh for the residential class, 14.9 MWh for the commercial class and 213 MWh for the railroad in 1978. The seasonal variation in energy requirements is illustrated by the 1978 monthly energy sales shown below. Mh Miwh January 409 July 428 February 449 August 445 March 425 September 452 April 419 October 514 May 404 November 430 June 429 December 451 Peak usage occurred in October 1978, although the utility source indicated that the peak usually occurs in January or February. There is a 21 percent variation between the lowest monthly use of 404 MWh in May and the October peak of 514 MWh. There is no residential heating load in Skagway. Forecast Methodology and Assumptions The energy and peakload forecasts are based on the foregoing population and economic projections. Table 13 shows the projected number of residential and commercial/government customers. Residential customers are calculated by dividing the population by the estimated persons per household. Calculations for commercial/government customers are based on their historical ratio to the number of residential custom- ers. The ratio of 1.7 residential customers per commercial/ government customer was derived from the breakdown of customers on Table 12. The average increase in energy use per customer was projected at 2 percent annually, slightly below the average annual growth rate of 2.4 percent from 1973 to 1978. The reason Z=)3'2 €€-Z Table 13 NUMBER OF CUSTOMERS (BY CLASS), LOW AND HIGH PROJECTIONS ALASKA POWER AND TELEPHONE--SKAGWAY Low Projection High Projection Number of Number of Number of Number of Households/ Commercial/ Households/ Commercial/ Population, Residential Governmen Population, Residential Governmen Projection Customers Customers Projection Customers Customers 1978 914 261° 1569 914 261 156 1979 914 261 156 914 261 156 1980 914 261 156 914 261 156 1981 788 225 32 914 261 156 1982 662 189 pha bak 914 261 156 1983 536 153) 90 914 261 156 1984 552 158 93 951 272 160 1985 569 163 96 989 283 166 1986 586 167 98 1,028 294 173 1987 603 2 101 1,069 305 179 1988 621 D7 104 Ppil2 318 187 1989 640 183 108 17157 son 195 1990 659 188 ay 17203 344 202 From Table 10. cPopulation divided by 3.5 persons per household. ©1978 ratio of 1.7 residential customers per commercial/government customer assumed to remain the same through 1990. 1978 actual. b d for selecting a lower-than-historical rate is the anticipated increase in conservation. The low projection assumed railroai use would be discontinued in 1981. Peakload and Energy Forecast High and low peakload and energy projections were calculated to reflect high and low economic and population forecasts discussed above. As shown in Table 14, the low forecasts project total system energy requirements will increase to a high of 6,179 MWh in 1980, then decrease to a low of 3,023 MWh in 1983, and increase steadily after 1983 to 4,292 in 1990. From 1978 to 1980 the average annual rate of increase in total energy requirements was 1.6 percent. After the sharp decreases in 1981 through 1983, averaging -21.2 percent annually, total energy requirements increase at an average annual rate of 5.1 percent. Projections beyond 1990 were made using an annual increase of 5.1 percent. The high projection forecasts that total energy requirements will increase from 5,987 MWh in 1978 to 9,358 MWh in 1990, resulting in an average annual growth rate of 3.8 percent for the period. A lower annual increase of 2 percent is forecast from 1978 to 1983, increasing to 5.3 percent for the period 1984 through 1990. Table 15 presents moce detailed calculations for the high and low energy projections. Peakload estimates were derived from the energy requirement projections using a constant load factor and therefore follow the same patterns. The low projection forecasts that the peakload will increase from 1,400 kW in 1978 to a high of 1,411 kW in 1980 and then will decrease to 690 kW in Table 14 SUMMARY OF HIGH AND LOW PROJECTIONS, 1978-1990 ENERGY AND PEAKLOAD ALASKA POWER AND TELEPHONE--SKAGWAY 1978° 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 High Projection Residential (MWh) 1,861 1,879 L931 1,958 2,010 2,035 ZyldG 220 2,440 2,593 2,767 2,912 3,096 Commercial/ government (MWh ) 2,329 2,371 2,418 2,465 2,512 2,558 2,688 2,839 3,028 3,186 3,403 3,608 3,818 Railroad (MWh) 1,064 1,085 1,107 1,129 1,152 1,175 1,198 1,222 1,247 1,272 1,297 1,323 1,349 Total (MWh) 5,254 5,335 5,456 5,552 5,674 5,768 6,062 6,382 6,715 7,051 7,467 7,843 8,263 System losses (Mwh)* 733 707 723 736 752 764 803 846 890 934 989 1,039 1,095 Total energy requirements (MWh ) 5,987 6,042 6,179 6,288 6,426 6,532 6,865 7,228 7,605 7,985 8,456 8,882 9,358 Peakload cw)” Low Projection 1,400 1,379 1,411 1,436 1,467 1,491 1,567 1,650 1,736 1,823 1,931 2,028 2,137 Residential (MWh) 1,861 1,879 1,931 1,688 1,455 1,193 1,264 1,337 1,386 1,462 1,540 1,610 1,692 Commercial/ government (MWh) 2,329 2,371 2,418 2,086 1,787 1,476 1,562 1,642 1,715 1,798 1,893 1,998 2,098 Railroad (MWh) 1,064 1,085 1,107 - - - - - - - - - - Total (MWh) 5,254 5,335 5,456 3,774 3,242 2,669 2,826 2,979 3,101 3,260 3,433 3,608 3,790 System losses (MWh) * 133 707 723 500 430 354 374 395 411 432 455 478 502 Total energy requirements (MWh) 5,987 6,042 6,179 4,274 3,672 3,023 3,200 3,374 3,512 3,692 3,888 4,086 4,292 b Peakload (kW) 1,400 1,379 1,411 976 838 690 731 770 802 843 888 933 980 asystem losses estimated at 11.7% of total energy requirements. Assumes load factor of 50%. “1978 actual. Source: Table 15. High Projection Residential A Number of customers Average use Per cus- tomer (MWh) Energy use (MWh) Commercial/ government , Number of customers Average use pgr cus- tomer (MWh) Energy, use (MWh) Railroad Total Low Projection Residential A Number of customers Average use per cus- tomer (MWh) Energy use (MWh) Comme rcial/ government a Number of customers Average use Per cus- tomer (MWh) Energy use (MWh) Railroad Total pFrom Table .13. 1978 261 7.1 1,861 156 14.9 2,329 1,064 5,254 261 7.1 1,861 156 14.9 2,329 1,064 5,254 Table 15 HIGH AND LOW PROJECTIONS 1978-1990 ENERGY AND PEAKLOAD ALASKA POWER AND TELEPHONE/ SKAGWAY 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 261 7.2 1,879 156 15.2 2h. 1,085 De335) 261 7.2 1,879 156 15.2 2,371 1,085 5,335 261 7.4 1,931 156 15.5 2,418 1,107 5,456 261 7.4 1,931 156 15%5 2,418 1,107 5,456 Projected to increase at an annual rate of 2%. ilroad use discounted. Actual. 261 7.5 1,958 156 15.8 2,465 1,129 DIZ 225 7.5 1,688 132 15.8 2,086 261 7.7 2,010 156 16.1 2,512 1,152 5,674 189 7.7 1,455 lll 16.1 261 7.8 2,035 156 16.4 2,558 1,175 5,768 153 7.8 1,193) 90 16.4 1,476 272 8.0 2,176 160 16.8 2,688 1,198 6,062 158 8.0 1,264 93 16.8 1,562 283 8.2 2,321 166 17.1 2,839 1,222 6, 382 163 8.2 1,337 294 8.3 2,440 173 17.5 3,028 1,247 65715 167 8.3 1, 386 98 17.5 15715 305 8.5 2,593 179 17.8 3,186 1,272 7,051 V2; 8.5 1,462 101 17.8 1,798 318 8.7 2,767 187 18.2 3,403 1,297 7, 467 177 8.7 1,540 104 18.2 1,893 331 8.8 2,912 195 18.5 3,608 1,323 7,843 183 8.8 1,610 108 18.5 1,998 344 9.0 3,096 202 18.9 3,818 1,349 8,263 188 9.0 1,692 111 18.9 2,098 2,669 2, 826 3,10 3,260 3,43 3, 608 3,790 1983. After 1983 the peakload will begin to increase again, reaching 980 kW in 1990. Beyond 1990 the peakload increase was projected at an annual rate of 5.1 percent. The high projection forecasts an increase in peakload of 737 kW between 1978 and 1990, an increase of 53 percent over 1978 levels. The average annual rate of increase over the entire period is 3.6 percent; again, the annual growth rate is lower from 1978 to 1983 (1.3 percent) than from 1983 to 1990 (5.3 percent). As mentioned above, the economic future of the Skagway area depends primarily on the future of the White Pass & Yukon Route railroad. Because of the uncertainty of the future of the railroad, it is advisable to base the feasibility of any major investments in the Skagway area on the low-load projection. Comparison of Projected Load and Present Generating Capacity Haines currently uses diesel-powered generators to supply all their electricity. The number of units and their capacities are: - 2,070 kw = 850 kw - 600 kW - 300 kw = 300 kW = 200 kw = 150 kw 4,320 kw PRPRPRPP BRB The firm capacity for Haines is 2,250 kW (4,320 kW total capacity, minus the capacity of the largest unit). The firm annual energy is 8,500 MWh using a load factor of 43 percent. 2-37 Figure 2 shows that this present capability is insufficient to meet projected peakloads after 1981 and insufficient to meet annual energy requirements after 1980. Skagway currently relies on both diesel-powered generators and hydropower for their electricity needs. The number of units and their capacity are as follows: - 315 kW Diesel - 300 kW Diesel 200 kW Pelton Hydropower - 135 kW Pelton Hydropower - 1,250 kW Diesel (presently being installed) - +70 kW Diesel standby unit PNPRPRP NPB ' Plans have been made by Alaska Power and Telephone Company to increase the hydropower capacity during the next 3 years. In 1980 the existing 200-kW machine will be upgraded to 300 kW. In 1981 a new 100-kW machine will be added. In 1982 rehabilitation of the headworks diversion will increase available flow; the expected capacity increase is 100 kw. The firm capacity for Skagway is 2,500 kW, not including the proposed hydropower additions and 70 kW diesel standby. The firm annual energy is 11,500 MWh using a load factor of 50 percent. Figure 2 shows that this present capability is sufficient to meet peakload and annual energy requirements well beyond the year 2005. The proposed hydropower additions will increase the firm capacity and firm annual energy; therefore, any new generation capability in Skagway must be justified on the basis of displacing higher-cost, diesel- generated energy. Potential for Development of an Electric Heat Market. The load forecasts developed for this report assume that an electric heat market will not develop in the Haines and 2-38 PEAKLOAD (1000 KW) ANNUAL ENERGY (1000 MWH) 10 40 TCAPACITY PROJECTED PEAKLOAD ,——— PRESENT FIRM CAPACITY 1988 COMBINED 1980 1985 1990 1995 2000 2005 YEAR ENERGY | PROJECTED ANNUAL ENERGY 30 —— — PRESENT FIRM ANNUAL ENERGY COMBINED YEAR FIGURE 2 PROJECTED ENERGY AND CAPACITY NEEDS COMPARED TO PRESENT FIRM ENERGY AND CAPACITY Skagway communities. Of course, this assumption is highly dependent on the costs of electric generation versus alternative energy sources for heating. Currently, the price of fuel oil for home heating in Southeast Alaska towns is about 90 cents per gallon. At a 60 percent heating efficiency for oil, this price is equivalent to about 3.9 cents per kWh at a 100 percent efficiency for electric heat. At current price levels, this cost is below the development cost for alternative hydropower sites in the Haines and Skagway area and is significantly below the overall cost of delivering the hydropower through the distribution system to the household market. Since surplus electricity associated with the hydropower sites has, for all practical purposes, no marginal costs, schemes to use this surplus for electric heat could have some merit. However, for Haines and Skagway, the energy requirements and hydropower resource characteristics for the area appear to diminish the possibilities. The lack of substantial storage means that most surplus energy is available only in the April-October period when stream flows are relatively high. Of course, most of the heating load would occur during the other half of the year. Over the long term, it is likely that southeast Alaska residents will have to ultimately move away from oil heat, if oil prices increase faster than general inflation, as assumed in this report. Again, economics and changes in energy technology will be determining factors in the resident's selection of alternative heating forms. Hydroelectric power and wood heat appear to be the most likely possibilities at present. ne WM Chapter 3 HYDROELECTRIC POWER SITE ASSESSMENTS Thirteen possible sites for hydroelectric development were identified during the study (see Figure 1). Each site was evaluated by considering: (a) the cost of development and operation compared to diesel-electric generation, (b) annual and monthly energy production compared to projected energy requirements, and (c) environmental constraints. The basis for these evaluations was a field reconnaissance, a hydrologic study, and proposed site developments. FIELD RECONNAISSANCE A field reconnaissance of the Haines-Skagway region was per- formed to collect data about each potential hydroelectric power site. CH2M HILL staff visited as many sites as possible; several sites (Upper Chilkoot Lake, Ferebee River, Goat Lake, Haska Creek, and Skagway Tributary) were inaccessible by land and poor weather prevented aerial reconnaissance. The Upper Chilkoot Lake and Goat Lake sites have good hydro- electric development potential and will be visited when weather allows. The results of the site inspection will be reported in an addendum to this report. The headworks of the existing Skagway hydropower facility was also visited. Information about the Reid Falls and Upper Dewey sites was obtained from the FERC license drawings of the present hydropower system and from discussions with the system operators. During the reconnaissance, data were collected on the physi- cal constraints of developing each site. The following information was collected: e The available head and streamflow e Feasibility and special design problems associated with siting the embankment, penstock, spillway, powerhouse and fish ladder e Potential for a reservoir and the storage it would provide e Geologic constraints such as foundation strength, foundation and abutment permeability, and stream sedimentation characteristics e Environmental constraints e Alternative transmission line routes and the con- struction problems associated with each e Access to the site for construction workers and materials e Availability of soils suitable for embankment construction This information formed the basis for preparing a development scheme at each site. HY DROLOGY A hydrologic evaluation was made at each site to determine the average annual and the average monthly streamflow avail- able for energy production. Flows for a typical wet year and dry year were also determined. The maritime climate of southeast Alaska is characterized by cool summers and mild winters. Precipitation is heavy and frequent throughout the year and temperatures vary little, both seasonally and daily. The orographic features of southeast Alaska cause mean annual precipitation to vary widely; Haines and Skagway receive 50 inches and 30 inches per year, respectively, while nearby areas receive over 100 inches. Daily streamflow and total annual runoff are influenced by drainage basin elevation, melt from glaciers, natural storage in lakes, forest cover, stream slope, and basin orientation. Mean annual runoff is about 7 cfs per square mile in the Haines-Skagway area. Surface water records are available for three streams in the study area which include: Skagway River (gage No. 15056100), West Creek (gage No. 15056200) and Taiya River (gage No. 15056210). The period of record is short for all gages: Skagway River, 16 years; West Creek, 15 years; Taiya River, 8 years. The USGS has classified the records as either fair or poor, depending on the time of year. Exhibit A contains the analysis of the gage records and the results. Because reliable surface water records are lacking in the study area and because most potential hydroelectric sites are located on ungaged streams, regional methods were inves- tigated for possible use to calculate average monthly stream flow. The regional method contained in the Water Resources Atlas (Reference 1) was compared to the results of the gage analyses to determine its acceptability. The comparisons and analyses made are shown in Exhibit A. The regional method gives values that compare favorably with flows measured at the gages. For a reconnaissance-level study the regional method yields satisfactory results and was, therefore, used to compute mean annual and mean monthly flows (see Table 16) at each site. Other values that were determined using equations from the regional analysis included: 7-day, 2-year recurrence, low flow; five points on the daily flow duration curve; and peak flow, 100-year recurrence interval. The average annual and monthly flows were used to compute power and energy production at potential reservoir sites. The flow duration curves were used to compute power and energy at sites where run-of-river hydroelectric generation is possible. Spillway design flows for sizing spillways were estimated from the 100-year peak flow. The sites evaluated in this study will require a spillway capable of carrying the Probable Maximum Flood (PMF), which is estimated to be about four times the 100-year peak flow. SITE DEVELOPMENT The development concept for each site is based on the following data: e Available mapping: --Quadrangle maps 1:63,360 with 100" contour intervals for all sites, plus USGS site maps for Chilkoot Lake and West Creek --USGS Preliminary Geologic Map of southeastern Alaska compiled by Helen M. Beikman, 1975, in cooperation with the State of Alaska Depart- ment of Natural Resources 3-4 Site Chilkoot Lake Upper Chilkoot Lake Dayebas Creek Ferebee River Haska Creek Upper Dewey Lake Reid Falls West Creek Goat Lake Skagway Tributary Kasidaya Creek Mean Annual Flow (cfs) Jan 943 216 34 3 62 ll 265 137 9 1 10 1 17 2 280 43 29 3 135) 15 129 17 MEAN ANNUAL AND MEAN MONTHLY FLOWS Feb 213 4 ll 142 56 18 2 March 191 6 16 124 66 21 28 Table 16 365 8 26 237 99 31 43 1,253 68 111 816 25 24 36 448 55 222 219 April May June Mean Monthly Flow (cfs) July _Aug_ _Sept_ _Oct_ Nov 2,060 1,640 1,480 1,836 180 216 1,245 36 58 67 684 162 552 401 234 170 977 30 69 70 722 226 556 384 114 118 909 18 37 46 603 105 385 311 91 142 1,142 20 29 42 596 80 335 300 1,390 44 90 869 12 13 23 375 37 183 181 702 22 47 472 12 198 20 89 96 Dec 377 9 21 236 122 41 47 e Existing geologic reports (see Exhibit B) e Site visits where possible. (Upper Chilkoot Lake and Goat Lake sites will be visited when weather permits and the results of the site inspection will be reported in an addendum to this report.) e Discussions with local people familiar with: --Potential sites --Present generation systems --Limitations of existing hydropower installations, especially regarding winter operation e Hydrologic data developed as explained in this chapter e Need for fish passage The intent of the site selection process was to identify all potential sites within a reasonable transmission distance that could make a significant contribution toward meeting present and future energy needs. For this initial study phase, each site was given optimum consideration based on a limited knowledge of the sites, engineering judgment, and previous experience in developing and evaluating hydroelectric sites. Storage Sites Only the West Creek site has identified limitations on the maximum available storage. Limitations on the remaining sites have not been established. Some sites will be limited by foundation conditions and some by the geometry of the dam sites that are not distinguishable on 100-foot contour maps. Our estimates of available storage are based on maps with 100-foot contour intervals and are intended to be conservative. Except for West Creek, feasibility studies may show that additional storage (and consequently additional winter power) is available. Earthfill and rockfill dams have been proposed where the needed materials appear to be available (Chilkoot Lake Dam, Ferebee River, and West Creek). Concrete dams have been proposed for all other sites. The hydroelectric sites that provide storage also provide the added benefit of flood control. The storage reservoirs can be operated during the spring runoff to provide flood storage for reducing peak flood flows downstream. Run-of-River Sites For all run-of-river sites concrete diversions have been proposed. The conceptual diversion design includes: e A concrete gravity overflow section e A penstock headworks with trashrack (and fish screen where applicable) e Sluiceway for flushing stream deposited materials e Provisions for ice protection including deicing equipment where winter operation is anticipated All Sites The penstock is assumed to be welded steel pipe except where tunnels are anticipated. Steel penstocks would be buried where soil conditions allow and would be supported on concrete pedestals anchored to rock where burial is impractical. Detailed conceptual designs of the powerhouses have not been formulated. The estimated cost of the powerhouse is based on Corps of Engineers cost curves (Reference 2) for the particular head, the conceptual selection of unit size, and type chosen for each site. Actual selection of equipment and siting of the powerhouse would be accomplished in the feasibility and preliminary design phases. Elements of the powerhouse construction (such as difficult foundation condi- tions) that could be identified to significantly affect the project cost have been included in the estimated cost. These elements are discussed, where applicable, under the discussion of each site. Following is a discussion of each site accompanied by figures that show the conceptual development used for estimating construction costs. Table 17 summarizes project features for each site. Table 18 summarizes construction costs for each site. Table 17 SITE FEATURES SUMMARY J & Yv Chilkoot Lake Site Name Chilkoot Lake Dam Diversion Upper Chilkoot Lake Dayebas Creek Ferebee River Latitude and Longitude 59°=20' 135°-34" 59°-20" 135°-34' 59°=25" 135°-40' 59°-17' 135-22" 59°-21" 135°-27' Hydrology Drainage Area (sq miles) 128.9 128.9 4.6 11.4 82.4 Mean Annual Flow (cfs) 943 943 34 62 625 Low Flow (cfs) (Note: a) 72 72 2 Ss 44 High Flow (cfs) (Note: b) 22,100 22,100 930 1,470 16,000 Site Development Dam Type Earth Concrete Gravity Concrete Gravity Concrete Diversion Earth Height (ft) 60 35 30 15 70 Operation Storage (66,000 Storage (16,400 Storage (3,500 Run of River Storage (35,000 ac-ft) ac-ft) ac-ft) ac-ft) Spillway Type Concrete Chute Concrete Ogee Concrete Ogee Note: c Concrete Chute Capacity (cfs) 80,000 (PMF) 80,000 (PMF) 3,600 (PMF) 45,000 (PMF) Penstock Length (ft) 4,000 500 6,500 1,600 400 Diameter (ft) 10 12 2.5 2.5 6.5 Concrete Canal Length (miles) None 1 None None None Powerhouse Type of Machine Kaplan Kaplan Pelton 1-Francis 3540kW Kaplan (Note: 4) Number of Units 1 1 1 1-Pelton __950kW 1 (Note: e) Installed Capacity (kW) 3,300 3,500 12, 400 4, 490kW 2,740 Transmission Facilities Length 8.5 8.5 16.5 45 13.0 Voltage 25 kV-3 phase 25kV-3 phase 34.5 kV-3 phase 25 kV-3 phase 25 kV-3 phase Fish Ladder Vertical Height (ft) 70 45 None None 55 Energy Production Static Head (ft) 60 35 2,100 500 55 Net Effective Head (ft) (Note: f) 50 33 1,825 345 46 Full Gate Flow (cfs) 1,000 1,500 100 150 900 Installed Capacity (kW) 3,300 3,460 12,400 4,490 2,740 Annual Energy-Low Flow Year (MWh) 19,352 16,778 57,422 15,032 -_ Annual Energy-High Flow Year (MWh) 25,228 20,124 66,800 22,548 _ Average Annual 22,476 19,165 61,186 18,190 13,172 Energy (MWh) Dependable Capacity (kW) 1,010 500 2,490 410 180 (Note: g) Economics Capital Cost ($1,000) 35,378 35,708 24,254 5,043 _-- O&M Cost ($1,000/yr) 160 160 240 192 _— Environmental Concerns Important spawning and Important spawning and Erosion could occur due A submarine transmis- Not rearing areas for pink rearing areas for pink to steep slopes. High sion cable would be identified ao op and chum salmon immedi- ately below the diver- sion structure could be impacted by in- creased sedimentation. ‘Average 7-day, 2-year winter low flow. Peak flow, 100-year recurrence interval. Concrete Diversions for the run-of-river projects serve as overflow structures to pass all streamflows not diverted for power. and chum salmon immedi- ately below the diver- sion structure could could be impacted by increased sedimentation. Definition of Turbine Units as presented in this report. Pelton - an impulse turbine with one, two, or four needle-valve nozzles. Francis - a reaction turine with fixed blade runners and wicket gates. Kaplan - a reaction turbine with variable pitch propellers mounted in a tube, a bulb or vertically. ‘The number of turbine-generator units was determined by considering operating heads, flow range, present and future power loads, standby diesel capacity and unit efficency. more detailed analysis of these factors. one or more of the Upper Chilkoot, West Creek, Skagway River, Goat Lake, the ranking of the sites based on the conceptual construction estimate. Net effective head is the head on the turbine, at installed capacity, after hydraulic losses in the delivery system. SEstimated dependable capacity is defined as the capacity available during the lowest flow month based on the estimated average year monthly flows. or Kasidaya Creek sites. silt load could adver- sely impact downstream (Chilkoot River) spawing. Th: subject to underwater seismic and current activity. Future feasibility and design at selected sites will include a much It is possible the analysis will show that multiple units are preferable at is would not change Site Name Latitude and Longitude Hydrology Drainage Area (sq miles) Mean Annual Flow (cfs) Low Flow (cfs) (Note: a) High Flow (cfs) (Note: b Site Development Dam Type Height (ft) Operation Spillway Type Capacity (cfs) Penstock Length (£t) Diameter (ft) Concrete Canal Length (miles) Powerhouse Type of Machine (Note: d) Number of Units (Note: e) Installed Capacity (kW) Transmission Facilities Length Voltage Fish Ladder Vertical Height (ft) Energy Production Static Head (ft) Net Effective Head (ft) (Note: f) Full Gate Flow (cfs) Installed Capacity (kW) Annual Energy-Low Flow Year (MWh) Annual Energy-High Flow Year (MWh) Average Annual Energy (MWh) Dependable Capacity (kW) (Note: g) Economics Capital Cost ($1,000: O&M Cost ($1,000/yr) Environmental Concerns ‘Average 7-day, 2-year wint ao op Haska Creek 59°=13" 135°=32" 2.1 10 ) 350 Concrete Diversion 15 Run of River Note: c 885 0.5 25 kV-3 phase None 1,000 620 20 885 4,028 6,042 5,035 20 Not identified er low flow. Peak flow, 100-year recurrence interval. Concrete Diversions for the run-of-river projects serve as overflow structures to pass all streamflows not diverted for power. Table 17 Cont. Upper Dewey Lake 59°27" 135°=16" 1.6 7 300 Concrete Diversion 23 Run of River Note: c 10,000 16-inch None Pelton 1 3,920 None 25 kV-3 phase None 3,010 1,920 30 3,920 16,477 24,708 20,590 8,689 80 Seismically induced- structure failure could cause risk to life and property in Skayway. Definition of Turbine Units as presented in this report. Pelton - an impulse turbine with one, two, or four needle-valve nozzles. Francis - a reaction turine with fixed blade runners and wicket gates. Kaplan ~ a reaction turbine with variable pitch propellers mounted in a tube, a bulb or vertically. The number of turbine-generator units was determined by considering operating heads, flow range, present and future power loads, standby diesel capacity and unit efficency. more detailed analysis of these factors. the ranking of the sites based on the conceptual construction estimate. Net effective head is the head on the turbine, at installed capacity, after hydraulic losses in the delivery system. ®Estimated dependable capacity is defined as the capacity available during the lowest flow month based on the estimated average year mon thly flows. J Reid Falls 59°=28" 135°=17" 2.8 280 1 600 Concrete Diversion 20 Run of River Unlined Rock 26,000 2,700 20-inch None 1-Pelton 2,690kW l-Pelton __350kW 3,040 0.5 34.5 kV-3 phase None 1,020 600 60 3,040 8,410 12,614 11,335 4,013 80 Lower Skagway River salmon spawning could be adversely affected by siltation. Siesmically induced structure failure could cause risk to life and property in Skayway. West Creek 59°32" 135-25" 39.6 565 18 6,780 Earth 40 Storage (65,000 ac-ft) Unlined Rock 35,000 10,600 8' tunnel None Francis 1 13,400 6.5 25 kV-3 phase None 610-730 645 300 13,200 111,438 127,592 117,124 11,400 66,538 272 Coho salmon below the damsite could be ad- versely affected by siltation and dam operation. Future feasibility and design at selected sites will include a mich It is possible the analysis will show that multiple units are preferable at one or more of the Upper Chilkoot, West Creek, Skagway River, Goat Lake, or Kasidaya Creek sites. This would not change Skagway River sge-31' —135%15! 87.1 29 55 8,960 Concrete Gravity 15 Run of River Unlined Rock 1,200 1,200 7 None Kaplan 1 8,600 4.5 25 kV-3 phase None 150 130 985 8,600 20,184 30,276 25,230 35 29,569 192 The lower Skagway River fishery and salmon spawning area could be adversely affected by silta~ tion and dam opera- tion. Seismically- induced dam failure could cause risk to life and property in Skagway. Site Name Latitude and Longitude Hydrology Drainage Area (sq miles) Mean Annual Flow (cfs) Low Flow (cfs) (Note: a) High Flow (cfs) (Note: b) Site Development Dam Type Height (ft) Operation Spillway Type Capacity (cfs) Penstock Length (£t) Diameter (ft) Concrete Canal Length (miles) Powerhouse Type of Machine (Note: d) Number of Units (Note: e) Installed Capacity (kW) Transmission Facilities Length Voltage Fish Ladder Vertical Height (ft) Energy Production Static Head (ft) Net Effective Head (ft) (Note: £) Full Gate Flow (cfs) Rated Capacity (kW) Annual Energy-Low Flow Year (MWh) Annual Energy-High Flow Year (MWh) Average Annual Energy (MWh) Dependable Capacity (kW) (Note: g) Economics Capital Cost ($1,000) O&M Cost ($1,000/yr) Environmental Concerns ao op J Goat Lake 59°-32" 135°=11" 4.4 29 350 Concrete Gravity 15 Storage (5,000 ac-ft) Concrete Ogee 1,200 6,200 2.5 None Pelton 1 12,700 34.5 kV-3 phse None 2,090-2, 130 1,870 100 12,700 57,440 68,283 62,934 2,960 23,219 224 Erosion could occur due to steep slopes. ‘Average 7-day, 2-year winter low flow. Peak flow, 100-year recurrence interval. ‘Concrete Diversions for the run-of-river projects serve as overflow structures to Table 17, Cont. Skagway Tributary 59°34" 135°=12" 16.3 135 3,370 Concrete Diversion 15 Run of River Note: c 2,900 5 None 1-Francis 20,000kW 4, 200kW * 24,200 1-Pelton 34.5 kV-3 phase None 700 530 560 24,200 48,984 73,476 61,230 720 Not identified Definition of Turbine Units as presented in this report. Pelton - an impulse turbine with one, two, or four needle-valve nozzles. Francis - a reaction turine with fixed blade runners and wicket gates. Kaplan - a reaction turbine with variable pitch propellers mounted in a tube, a bulb or vertically. ‘The number of turbine-generator units was determined by considering operating heads, flow range, present and future power Future feasibility and design at selected sites will include a mch It is possible the analysis will show that multiple units are preferable at loads, standby diesel capacity and unit efficency. more detailed analysis of these factors. Kasidaya Creek 59°24" 135°-20' 19.7 129 3,420 Concrete Diversion 15 Run of River Note: c 2,500 4 None Francis 1 9,820 25 kV-3 phase None 500 360 400 9820 31,536 47,304 39,420 200 Not identified one or more of the Upper Chilkoot, West Creek, Skagway River, Goat Lake, or Kasidaya Creek sites. the ranking of the sites based on the conceptual construction estimate Net effective head is the head on the turbine, at installed capacity, after hydraulic losses in the delivery system. Estimated dependable capacity is defined as the capacity available during the lowest flow month based on the estimated average year monthly flows. pass all streamflows not diverted for power. This would not change Item Project Headworks (1) Difficulty Factor (2) Special Contingency (3) SUBTOTAL (1x2x3) Waterway Special Mobilization SUBTOTAL Fish Facilities Powerhouse Foundation Contingency SUBTOTAL Transmission Roads Mobilization, Bonds, Ins., Care of Wtr, etc. SUBTOTAL CONTINGENCY 25% FACTOR TO ALASKA 1.6 TOTAL CONSTRUCTION ENGINEERING & OVERHEAD TOTAL INVESTMENT 0 & M ($1,000/yr) Replacement (Powerhouse equip.) ($1,000/ yr) UNIT COST ($/installed kW) Chilkoot Lake Diversion 1,865 1.10 1.10 2,256 2,388 2,388 5,049 3,250 650 3,900 280 10, 200 ‘rapie 18 ESTIMATED CONSTRUCTION COSTS (Thousands Dollars @ 1979 Price Level) Chilkoot Lake Upper Chilkoot Dayebas Dam Lake Creek 2,877 463 63 T.15 1.05 1.00 1.12 1.20 1.08 3,706 583 68 1,982 1,870 256 --- 440 20 1,982 2,310 276 3,596 -- --- 3,440 5,000 1,010 650 --- 350 4,090 5,000 1,360 280 680 425 91 850 —_ 1,374 942 196 15,119 10,365 2,325 3,880 2,591 581 11,339 7,774 1,744 30, 238 20,730 4,650 5,140 3,524 791 35,378 24,254 5,441 160.0 240.0 192.0 77.4 112.5 22.7 10,700 1,960 1,210 Upper Dewey Reid Falls West Skagway Goat Lake Creek Creek River Lake 108 60 7,287 560 530 1.05 1.02 1.05 1.03 1.10 1.08 1.05 1.15 1.08 1.20 122 64 8,799 623 700 1,820 297 12,190 567 2,411 580 288 --- ess 428 2,400 585 12,190 567 2,839 800 840 5,400 10,000 5,000 50 50 50 100 100 850 890 5,450 10,100 5,100 -_- 20 270 160 270 ao --- 175 38 114 337 156 2,688 1,149 899 3,709 1,715 29,572 12,637 9,992 927 429 74393 3,159 2,481 2,783 1,286 22, 179: 9,477 7,442 7,418 343 59,144 25,273 19,845 1,261 583 7,393 4,296 3,374 8,689 4,013 66,538 29,569 23,219 80.0 80.0 272.0 192.0 224.0 18.0 18.9 121.5 225.0 112.5 2,220 1,320 5,040 3,440 1,830 Chilkoot Lake (Figure 3) Chilkoot Lake is about 11 miles north/northwest of Haines and has a surface area of 1,680 acres at a water surface elevation of about 29 feet Mean Sea Level (MSL). The lake is formed by a terminal moraine that is between 130 and 170 feet higher than the lake, except where cut by the Chilkoot River. This site has been identified by the Federal government (J.S. Geological Survey) as a potential power site. The maximum power development of the site is limited by topography to a 150-foot dam with about 550,000 acre feet of storage. However, the permeable nature of the terminal moraine forming the foundation and abutment will probably limit the development of the site to a project somewhat like the two concepts presented in this report. The spillway at this site would be designed for a probable maximum flood of about 80,000 cfs. Two alternative development schemes are proposed for Chilkoot Lake; the first uses a low diversion dam with a canal leading to a short penstock and the powerhouse; the second uses a high dam with a long penstock leading to the powerhouse. The diversion dam alternative, because it has a short penstock, can be designed to use nearly all the natural stream flow. The high dam alternative requires a long penstock which, for economic reasons, cannot be sized large enough to use all the natural streamflow; the available storage is not enough to compensate for the lower penstock capacity and, therefore, this alternative spills more water than the diversion alternative. MS \§ ANZ UNS ! \ LEGEND FIGURE 3 DIVERSION POWERHOUSE —P— TRANSMISSION ae om CHILKOOT LAKE ALTERNATIVES SCALE IN FEET Chilkoot Lake Diversion (Figure 4) A low diversion near the mouth of the lake provides some storage for winter regulation and allows the use of a canal to deliver water to the penstock, providing more flexibility in the flows released for power production. The low diver- sion also minimizes the potential for seepage problems through the foundation and abutments. PRESENT LAKE NORMAL PENSTOCK HEADWORKS AND FISH SCREENS EXISTING CNA GROUND HEADWORKS 12' $ PENSTOCK ACTIVE f STORAGE = } \ _ 16,400 AC FT POWERHOUSE 3.5 MW KAPLAN CONCRETE S — DIVERSION WITH San, OGEE CREST = PROJECTION OF ~S LO SHILKooT RIVER LADDER STREAMBED ae ay APPROXIMATE NORMAL TIDE RANGE = TAILWATER SCALES IN FEET CHILKOOT LAKE DIVERSION PROFILE This concept consists of a concrete ogee crest overflow section that raises the normal water surface of the lake about 6 feet. Releases for power production are made through a canal headworks in the left abutment. The concrete-lined canal is 5,500 feet long with an invert elevation at the diversion of 25 feet MSL and a slope of .0025 of a foot per foot. The crest of the canal dike is 37 feet MSL. The capacity of the canai varies with the elevation of the lake from a maximum of 1,500 cfs at the normal water surface, down to 200 cfs at a lake elevation of 29. The canal terminates at the penstock headworks. The penstock is a 12-foot-diameter steel pipe, 500 feet long, leading to the powerhouse constructed in the tide zone of Lutak Inlet. S=L6 EMBANKMENT CREST EL 55 CHANNEL EXC TO EL 25 DIVERSION l LUTAK \ NLET 0 1000 2000 SCALE IN FEET TRAINING WALL CONCRETE OGEE SHEET Euise RIPRAP. PILE CONCEPTUAL SECTION NTS FIGURE 4 CHILKOOT LAKE DIVERSION 0 200 400 ——— SCALE IN FEET Fish passage is accomplished by a fish ladder from near the powerhouse to the downstream end of the canal. The fish then swim the canal to the lake. Fish screens at the pen- stock headworks prevent downstream migrants from entering the penstock. Since the total head at this site is only 35 feet between Mean Sea Level and the normal water surface of the lake, full advantage of this head can only be realized by construc-— ting the powerhouse in the tide zone. Because of the difficulties of construction dewatering with a tide range of about 20 feet, a special contingency has been allowed for the foundation work on the powerhouse. The powerhouse will house a Kaplan turbine with a 3.5-MW generator. Construction of this facility requires relocation of the present access road at the mouth of the lake to a position above the maximum flood level created by the diversion works. Access to the canal headworks will be by a road con- structed as part of the canal berm. The monthly reservoir level variation and energy production for an average flow year are shown below. The amount of water that is spilled from the reservoir and not used for power production is also given. 40 RESERVOIR RESERVOIR EL (MSL) kWH/mo (x 108) SPILL = Lowyr 4,000 Ac Ft Avagyr 69,000 Ac Ft CHILKOOT LAKE High yr 181,000 Ac Ft DIVERSION 3-18 NORMAL ws. Chilkoot Lake Dam (Figure 5) The actual limitations on the height of a dam at this site can be determined only by a detailed site investigation. Based on our site visit and preliminary evaluation of the site conditions, we believe the lake could be raised to about 60 feet MSL with a dam section incorporating measures to control the seepage that would occur through the foundation and abutments of the structure. A conceptual section of the earth dam is shown in Figure 5. It consists of upstream and downstream shells constructed from the terminal moraine materials, that are protected by rock from the talus slopes along the base of the valley walls. Construction of the impervious central core will require processing of local and imported materials. The transition zones and filters needed to protect the core and control seepage will be processed from local materials. Flood flows will be passed through a concrete-lined spillway in the right abutment of the dam. ¢ oF bam PENSTOCK INTAKE STRUCTURE 6 FREEBOARD — active Sfonace - $5,800 AC FY oN So = aa re STREAM BED" 7 EXISTING GROUND. POWERHOUSE RANGE = TAILWATER [|-—— CHILKOOT LAKE DAM PROFILE APPROXIMATE NORMAL TIDE 0 1000 SCALE IN FEET 2000 Su Se le c= (¢ we 7) RESERVOIR ACCESS CONCRETE SPILLWAY CHUTE OUTLET AND PENSTOCK CONTROL STRUCTURE access _, / ROAD 0’ DIA I PENSTOCK, 4 ONC TRANSITION AND FILTERS TRENCH EPTUAL SECTION NTS 0 200 400 > SCALE IN FEET FIGURE 5. CHILKOOT LAKE DAM The location of the dam was selected as the best compromise between an increasing dam height as it approaches Lutak Inlet and an increasing penstock length as the dam approaches Chilkoot Lake. Also, spillway discharges at this site are lined up with the natural channel alignment. The spillway grade allows the fish ladder to be incorporated in one wall of the spillway. As with the low diversion, the reservoir access road will be relocated above the reservoir level created by the dam. The penstock headworks is located at the upstream toe of the dam and incorporates fish screens to prevent the entrance of downstream migrants. The embankment slopes selected for this conceptual design are 3.5:1 upstream and 2.5:1 downstream, which are relatively conservative but allow some margin for the anticipated foundation conditions and the potential seismic loadings. The 10-foot-diameter steel penstock is 4,000 feet long, terminating at the powerhouse in the tide zone of Lutak Inlet, similar to the low diversion scheme. The powerhouse will house a Kaplan turbine with a 3.3-MW generator. Access to the dam and penstock headworks will be by access road con- structed along the left bank of the Chilkoot River. The monthly level variation and energy production for an average flow year are shown below. The amount of water that is spilled from the reservoir and not used for power production is also given. RESERVOIR LEVEL RESERVOIR EL (MSL) kWH/mo (x 108) SPILL = Lowyr 32,000 Ac Ft Avg yr 146,000 Ac Ft CHILKOOT LAKE High Yr 273,000 Ac Ft DAM 3-21 Upper Chilkoot Lake (Figure 6) This is an unnamed lake about 4 miles upstream from the head of Chilkoot Lake in the Chilkoot basin. The lake has a surface area of about 90 acres at elevation 2270 MSL. The site was not visited because of weather conditions; however, aerial photographs taken in May 1961 were reviewed. A snow cover limits the photographs" usefulness for determining geologic detail, but the geometry of the lake outlet suggests that a 30-foot dam is feasible. A 30-foot dam would provide 3,500 acre feet of active storage. The possibility of obtaining impermeable materials for an earth dam are very remote; therefore, a concrete dam was selected for conceptual design. The rugged terrain and remoteness of the site will make delivery of equipment and materials for construction very expensive. For this reason, future feasibility consid- erations should include a rockfill dam with an impermeable upstream membrane or a concrete core to reduce the amount of imported materials. UPPER CHILKOOT LAKE EXISTING ACTIVE STORAGE = \ gxising GROUND « i ig PENSTOCK aearrene I \ Borie | possiate© TUNNEL \ ALTERNATIVES a |] sor estinateoy \ | \ 500 | ie ScATEBINFEET obi \ 4 tt TUNNEL IN 3001 1000 = \ — =. aa \ ~ POWERHOUSE Ma \ CHILKOOT ie =_ RIVER UPPER CHILKOOT LAKE PROFILE SY Cece The proposed concrete dam would have a spillway overflow section capable of passing an estimated probable maximum flood of 3,600 cfs A 6,500-foot-long, 30-inch-diameter 3-22 UCL CaaS Se LEGEND PENSTOCK FIGURE 6 POWERHOUSE o — P= TRANSMISSION UPPER CHILKOOT LAKE ACCESS ROAD SCALE IN FEET steel penstock will be required. The powerhouse tailwater elevation would be 200 feet MSL, resulting in a static head of 2,100 feet. The penstock will be supported on concrete piers anchored to rock. The powerhouse will house a Pelton turbine driving a 12.4-MW generator (see Figure 7). This conceptual design allows for a minimum power generation in the winter of about 2.5 MW. Future investigation should include soundings of the existing lake to determine whether a lake tap could be made to increase the active storage. The possibility of a tunnel delivery system should also be investigated. An access road to the powerhouse will be required along Chilkoot Lake. Transmission lines will parallel the access road. Access to the dam, penstock, and penstock headworks will be by way of a tramway built for construction, The monthly reservoir level variation and energy production for an average flow year are shown below. The amount of water that is spilled from the reservoir and not used for power production is also given. Pei 10 ! { RESERVOIR ! 230047 EVEL 2 p kWH/MO, | = ! es oe © x 2290 aT 2 | 52 c | FY 9 8 Z & 2280 ! z a i w J 2270 N D UPPER SPILL = Lowyr 4,000 Ac Ft A 11,000 Ac F ae, High yr 17,000 Ac Ft ELEC PANEL U] GOVERNOR ENERATOR (Controls Deflector) = SHROUD OVER PELTON WHEEL DISCHARGE PIT PREFABRICATED BUILDING NEEDLE VALVE OPERATOR SHROUD PELTON WHEEL EFLE DEFL CTOR DISCHARGE PIT FIGURE 7 UPPER CHILKOOT LAKE POWERHOUSE Dayebas Creek (Figure 8) Dayebas Creek, located across Taiya Inlet from Haines, drops very steeply in its last 500 feet. The conceptual design of this site includes a concrete diversion structure at eleva- tion 500, with a 30-inch-diameter steel penstock 1,600 feet long, to a powerhouse located near the high tide line of Taiya Inlet. This stream was used in the past to power a sawmill with a Pelton wheel and belt drive. Soil cover along the penstock profile is variable. Some of the penstock would be buried, and other parts would be supported on concrete supports anchored to the rock. EXISTING GROUND = 30° @ PENSTOCK PROFILE prosection \ OF STREAM BED ae ~ SCALES IN FEET APPROXIMATE TIDAL RANGE TAIYA INLET ° 500 DAYEBAS CREEK PROFILE This site requires two turbine-generator units to fully use seasonal flow variations. The conceptual design includes a Pelton turbine with a 1-MW generator and a Francis turbine with a 3.5-MW generator (see Figure 9). The Francis turbine results in higher efficiencies than multiple Pelton units, but a feasibility study may show that multiple Pelton units are preferable because they simplify powerhouse construction and surge protection. 3-26 ToAWd YA phorage Cove eS 2 CRAB OUI, as Deshu eet LEGEND GM ODIVERSION FIGURE 8 —— PENSTOCK @ POWERHOUSE DAYEBAS CREEK —P— TRANSMISSION —S— sUBMARINE CABLE 0 2 4 SCALE IN FEET OUTLINE OF DISCHARGE PIT BELOW PELTON TURBINE FRANCIS ___ ___ TURBINE PENSTOCK Pea PREFABRICATED SUPERSTRUCTURE CRANE ELECTRIC PANEL CRANE SUPPORTS GENERATOR. FIGURE 9 DAYEBAS CREEK POWERHOUSE 8 Access to this site will be by boat. Transmission from the site will be overhead, and will run south about 2 miles to Low Point Light (see Figure 8) and then west by submarine cable across Chilkoot Inlet to Haines. This route avoids a trench 1,000 feet deep offshore from the powerhouse site. There is a possibility that additional investigation of this site may find limited storage sites upstream, increasing the winter power potential of the site. Ferebee River (Figure 10) The Ferebee River dam site is located about 8 miles north of Haines. The site is a glaciated valley about 1/2-mile wide with an unknown depth of colluvial materials. This is not a desirable dam site because of the permeable foundation conditions, extensive talus abutment slopes, and lack of a suitable spillway site. Potential generation was determined for a medium-sized dam located at this site. TRANSITIONS: AND FILTERS NORMAL RESERVOIR TOP OF DAM EL 90 SHELL 6.5 > PENSTOCK LOCATED NEAR ONE ABUTMENT ON ROCK. INTAKE AND GUARD oe POWERHOUSE ALLUVIUM 50, (UNKNOWN DEPTH) CONCEPTUAL EMBANKMENT SECTION SCALES IN FEET (COMPOSITE OF MAXIMUM SECTION AND PENSTOCK) + eo FEREBEE RIVER 3=29 LEGEND Gm pay PENSTOCK © POWERHOUSE TRANSMISSION = ACCESS ROAD RESERVOIR NWS_EL = 70 ACTIVE-STORAGE = 35,000 AG. FT, BETWEEN ELEVATIONS 152AND\70 0 2 4 — SCALE IN FEET FIGURE 10 FEREBEE RIVER v, In our judgment, the generation potential does aot justify the probable cost of site development. For this reason, the site was eliminated from further consideration and an estimate was not made for the site development. The monthly reservoir level variation and energy production for an average flow year are shown below. The amount of water that is spilled from the reservoir and not used for power production is also given. RESERVOIR LEVEL a a = ioe o a - a x & ° 8 £ = = P| z a io c FEREBEE SPILL = Lowyr OAc Ft RIVER Avayr 2,000 Ac Ft High yr 30,000 Ac Ft Haska Creek (Figure 11) Haska Creek is about 3 miles west/southwest of Haines, across the mouth of the Chilkat River. This stream has been identified as a future water supply source for the City of Haines. The hydropower potential of the stream is small; however, because this site probably will be developed in the EXISTING GROUND 18" @ PENSTOCK PROFILE KASKULM POINT 6" +o McCLELLAN FLATS WATER LINE POWERHOUSE. TO CITY va rae SCALES IN FEET HASKA CREEK PROFILE o ° 1000 2000 ep al LS he | 2) Cy ‘as IA LEGEND GMM ODIVERSION FIGURE 11 PENSTOCK © POWERHOUSE HASKA CREEK —P— TRANSMISSION SCALE IN FEET —— Enea future for potable water, it may be economical to oversize the delivery pipeline to carry water for both hydropower and potable water supply. With a concrete diversion at elevation 1000 and an 18-inch-diameter penstock, the power potential for a powerhouse located at Kaskulu Point is about 5,000,000 kWh annually. The powerhouse would house a Pelton turbine with a .88-MW generator. With the turbine operating at the rated capacity, a flow of 1.5 cfs (less than 20% of total flow) at 85 psi could be delivered to the City through a valve located ahead of the turbine. No construction cost estimate was made for this project because there is insufficient generating potential as a power project only; the site should be considered only in conjunction with development for a city water supply. Upper Dewey Lake (Figure 12) Upper Dewey Lake is currently a major water source for Lower Dewey Lake, which is now used for hydropower in Skagway. By constructing a penstock from the present powerhouse to Upper Dewey Lake, at elevation 3100 feet, the summer generation can be increased to about 10 times the present generation. UPPER DEWEY LAKE EL 3070 RECONSTRUCT EXISTING DAM EXISTING GROUND 16" @ PENSTOCK PROFILE 1000 SCALES IN FEET =~ POWERHOUSE ol ° 1000-2000 UPPER DEWEY LAKE PROFILE 3-33 wu 5 —s* ie Hien 4 3 bs Xt 34 z Lame a “Bong Dyea Pt — (Ca Yakutania Pt snap Sf ® swayX S »\ Y Ferry Teginat fey LEGEND ME Diversion FIGURE 12 oe | PENSTOCK UPPER DEWEY LAKE a POWERHOUSE —P— TRANSMISSION AND ° z 4 REID FALLS CREEK SCALE IN FEET The conceptual design includes replacement of the existing log-crib dam at the present lake outlet, construction of a 16-inch-diameter steel penstock, 10,000 feet long, supported on concrete piers anchored to rock. A tramway for access for construction and maintenance is included in the estimate. A new powerhouse located near the existing powerhouse would house a Pelton turbine with a 3.9-MW generator (see Figure 13). Experience with minimal winter flows available for the present hydropower system suggest that winter power would not be possible from Upper Dewey Lake. Winterizing would include shutdown and dewatering of the penstock, at which time the existing system could be reactivated to operate from Lower Dewey Lake. Reid Falls Creek (Figure 12) At present, a diversion at elevation 1080 on Reid Falls Creek is licensed as a part of the hydropower development currently serving Skagway. A 6-inch pipeline carries a portion of the flows in this stream to a point near Icey Lake, which then flows to Lower Dewey Lake and the headworks of the present penstock. RECONSTRUCT EXISTING DIVERSION EL 1080 EXISTING GROUND = 20" @ PENSTOCK PROFILE POWERHOUSE SCALES IN FEET TW EL 60 REID FALLS CREEK PROFILE 3=30) PENSTOCK. ELEC PANEL ( LI GOVERNOR ENERATOR (Controls Deflector) DISCHARGE PI NEEDLE VALVE OPERATOR SHROUD OVER PELTON WHEEL T SHROUD PELTON PREFABRICATED BUILDING. FIGURE 13 UPPER DEWEY LAKE POWERHOUSE The existing diversion dam will require reconstruction to improve its operation. It will serve as the headworks for a 20-inch-diameter steel penstock, 2,700 feet long. This results in a potential for more than 11 million kWh annually. The powerhouse would be constructed near the base of the hill below the diversion. The powerhouse will house a Francis and a Pelton turbine (see Figure 14). The Francis will drive a 2.6-MW generator for normal summer flows and the Pelton will drive a .4-MW generator for efficient use of low winter flows. The present diversion is reported to have problems flushing stream deposits. The reconstructed diversion would improve this situation and also provide a deeper pool to minimize winter icing problems at the penstock entrance. West Creek (Figure 15) The USGS made a geologic reconnaissance of a dam site on West Creek in 1965. A topographic map of the dam site was developed and surficial geologic features were mapped. Our conceptual development is shown on this map in Figure 16. This site has the potential for storing a sufficient volume of the stream runoff to allow uniform power releases year-round. The dam site is about 6 miles northwest of Skagway. Logging has progressed to within 1 mile of the site; however, approxi- mately 2 miles of new access road would be required to serve the project. Bedrock at the dam site consists of a strong, massive grano- diorite. This rock is suitable for supporting a dam at the site and also providing construction materials for the shells of an earth dam. The USGS reconnaissance effort did 39/1 OUTLINE OF DISCHARGE PIT BELOW PELTON TURBINE GUARD VALvesq PENSTOCK PREFABRICATED SUPERSTRUCTURE CRANE ELECTRIC PANEL CRANE SUPPORTS GENERATOR FIGURE 14 REID FALLS CREEK POWERHOUSE ———— SNS a. ch ‘( an ny / i V ; \ ‘ Dy) SS TAS SY F Hi LEGEND = = AS FIGURE 15 o POWERHOUSE — P= TRANSMISSION WEST CREEK ===== ACCESS ROAD 0 2) 4 SCALE IN FEET TRANSITIONS 3 CREST EL 800 T NWS EL 780 ¢ ROCK SHELL ROCK CUT SPILLWAY FOUNDATION GROUTING CONCEPTUAL SECTION NTS DIVERSION AND OUTLET CHANNEL TUNNEL VALVE INTAKE CHAMBER LEGEND (pe INTRUSIVE ROCKS CNY FIGURE 16 PREDOMINANTLY GRANODIORITE WEST CREEK DAM SITE 0 200 400 Se SCALE IN FEET not identify core material borrow areas but suggested that they would probably be found upstream of the dam site. Much of the rock required for construction of the shells would come from required foundation and spillway excavations. Transition and filter materials could come from processed gravel deposits upstream of the dam site. If suitable materials for an impervious core cannot be identified in the feasibility investigation, a rockfill dam with an impermeable upstream membrane should be considered. EXISTING GROUND ALONG TUNNEL ALIGNMENT RESERVOIR NWS SURGE CHAMBER VALVE CHAMBER ——== TUNNELS PROJECTION OF Ss WEST CREEK STREAM BED ACTIVE STORAGE = 65,000 AC FT POWERHOUSE TW EL 50 WEST CREEK PROFILE SCALES IN FEET 0 ° 1000 2000 For maximum site development, the dam would be about 190 feet high and contain about 1.7 million cubic yards of embankment. The conceptual embankment section used to compute quantities uses fairly conservative slopes to ensure that a sufficient contingency has been allowed for a seis- mically suitable design. A 190-foot dam will result in an active storage volume of 65,000 acre feet plus 20 feet of flood storage to pass an estimated probable maximum flood of 26,000 cfs. The outlet for the dam will be a tunnel in 3-41 the left abutment, which will also serve as diversion during construction. The spillway will be an open rock cut ina saddle located just upstream of the left abutment. Flows released to the powerhouse will pass through an unlined, 8-foot-diameter tunnel. The tunnel intake and valve struc- ture will be located in the right abutment of the dam. The penstock will daylight at the powerhouse in the Taiya River valley. The powerhouse will house a Francis turbine with a 13.2-MW generator (see Figure 17). The conceptual design does not provide for fish passage because fish are not currently able to negotiate the lowest cascades of West Creek (adjacent to the proposed powerhouse). The monthly reservoir level variation and energy production for an average flow year are shown below. The amount of water that is spilled from the reservoir and not used for power production is also given. 20 RESERVOIR 800 LEVEL al a s & 4 750 kWH/MO S w \ x « . 10> 3 ----- E > = & 700 = oa =x w c 650 AIM 0 WEST CREEK SP/LL = Lowyr 500 Ac Ft Avg yr 16,000 Ac Ft High yr 20,000 Ac Ft 3-42 PENSTOCK PREFABRICATED BUILDING TUNNEL, STEEL LINED NEAR PORTA TAILRACE SECTION NTS FIGURE 17 WEST CREEK POWERHOUSE Skagway River (Figure 18) The Skagway River site is located about 4 miles upstream of the City of Skagway. This site was previously licensed by the FPC in 1927 for an installed capacity of about 200 kW. The site was never developed and the license was surrendered in 1944, NORMAL RESERVOIR WS EL 540 NO SIGNIFICANT STORAGE EXISTING GROUND ALONG 7’ PENSTOCK ROUTE POWERHOUSE 100, Ni SCALES IN FEET sip ° 500 SKAGWAY RIVER PROFILE The conceptual design of this site includes a concrete gravity dam with an overflow section capable of passing an estimated probable maximum flood of 35,000 cfs. A 7-foot- diameter, 1,200-foot-long steel penstock takes advantage of the gradient through the river cascades, resulting in a static head of 150 feet at the powerhouse. The powerhouse, located at the base of the cascades, houses a Kaplan turbine with an 8.6-MW generator. No fish facilities are provided with this development because the river cascades at the proposed powerhouse are a natural barrier. A short access road to the site will be required 3-44 LEGEND Ply DAM ——— PENSTOCK AS FIGURE 18 © POWERHOUSE — Pm TRANSMISSION SKAGWAY RIVER = ACCESS ROAD 0 2 4 SCALE IN FEET from the present highway on the right bank of the Skagway River. Although a 40-foot dam is used to maximize the head at this site, the dam provides very little storage. The site is basically a run-of-river development. Goat Lake (Figure 19) Goat Lake is about 7 miles northeast of Skagway in the Skagway River basin. The lake elevation is 2915. The water flowing from the lake cascades down Pitchfork Falls to the Skagway River at an elevation of 800 feet, for a static head of about 2,100 feet. The Goat Lake site was not visited because of weather conditions; however, May 1961 aerial photographs obtained from the State show the lake outlet, penstock, and powerhouse sites. GOAT Lake ACTIVE STORAGE ~ 5000 ac FY XN N 20° 7 ype emer it I \ | POSSIBLE N TUNNEL ALTERNATIVES X I] wor estimareo) oy Sa TUNNEL oe awe SCALES IN FEET Poe AR ° o 800 7000 GOAT LAKE PROFILE A 15-foot dam, coupled with a 25-foot-deep lake tap, results in an active storage of 5,000 acre feet. The quadrangle Maps suggest that a low dike may be required at the north end of the lake in addition to the dam at the outlet. The aerial photograph coverage is not adequate to confirm this. 3-46 LEGEND Cm pau moe TUNNEL PENSTOCK © POWERHOUSE —P— TRANSMISSION =222= ACCESS ROAD AAS WEAN SS LAKE EL. 2915 ACTIVE STORAGE = 5000 AC. FT. BETWEEN ELEVATIONS nly Ws 4 2890 AND 2930 FIGURE 19 eu als GOAT LAKE SCALE IN FEET A 6,200-foot-long, 30-inch-diameter steel penstock connects the lake tap to the powerhouse. The penstock will be sup- ported by concrete piers anchored to the rock. The power- house will house a Pelton turbine with a 12.7-MW generator (see Figure 20). An access road to the powerhouse will be constructed from the existing highway on the right bank of the Skagway River. Access to the penstock and dams will be by way of a tramway provided for construction and maintenance. Feasibility work on this site should include consideration of a tunnel in lieu of the steel penstock. A properly constructed tunnel would result in simpler winter operation and would almost eliminate maintenance of the water conveyance facilities. The monthly reservoir level variation and energy production for an average flow year are shown below. The amount of water that is spilled from the reservoir and not used for power production is also given. 2930 10 RESERVOIR LEVEL 2920 2910 RESERVOIR EL (MSL) kWH/mo (x 108) GOAT LAKE SPILL = Lowyr 2,000 Ac Ft Avg yr 7,000 Ac Ft High yr 12,000 Ac Ft ELEC PANEL [aart) U GOVERNOR ENERATOR (Controls Deflector) SHROUD OVER PELTON WHEEL | | | ! | DISCHARGE PIT PREFABRICATED BUILDING NEEDLE VALVE OPERATOR SUROUD PENSTOCK. NEEDLE VALVE FIGURE 20 GOAT LAKE POWERHOUSE Skagway Tributary (Figure 21) A tributary of the Skagway River, about 9 miles northeast of Skagway, flows into the river from the north. A concrete diversion at elevation 1800 on this tributary and a powerhouse at elevation 1100 on the bank of the Skagway River provide a static head of 700 feet. DIVERSION EL 1800 EXISTING GROUND = 45° DIA PENSTOCK PROFILE PROTECTED STREAM PROFILE SKAGWAY RIVER POWERHOUSE TW EL 1100 400 300 200 1001 scaLe IN FEET 7 SKAGWAY TRIBUTARY PROFILE 0 300 600 Our conceptual design includes a 2,900-foot-long, 4.5-foot-diameter, steel penstock supported on piers anchored to the rock. The powerhouse houses a Francis turbine with a 20-MW generator and a Pelton turbine with a 4.2-MW turbine. The Pelton generator would be used to make efficient use of the low winter flows. This site has potential for adding to the power grid in the future. But, considering the limited potential for winter generation and the closeness to Skagway of other sites, which are already capable of meeting all or part of the study period projected load, the cost estimate to develop this site was not made. iy We Ht LEGEND MMM OCDIVERSION PENSTOCK © POWERHOUSE — P— TRANSMISSION =s===2= ACCESS ROAD SCALE IN FEET FIGURE 21 SKAGWAY TRIBUTARY Kasidaya Creek (Figure 22) Kasidaya Creek is located 3-1/2 miles south of Skagway on the east shore of Taiya Inlet. The crest of a Kasidaya Creek falls at about elevation 500 begins a steep cascade to the Taiya Inlet. The crest of the falls is the site of a diversion in our conceptual development. A 2,500-foot-long by 4-foot-diameter steel penstock connects the diversion with the powerhouse constructed at the high tide line on the beach. The powerhouse houses a Francis turbine with a 9.8-MW generator. EXISTING GROUND = 4° PENSTOCK, PROFILE PROJECTION oF KASIDAYA CREEK PROFILE SCALES IN FEET ° = KASIDAYA CREEK PROFILE Although the power potential for this site is fairly significant, the site is too remote and the transmission alignment is too rugged to justify development of this site before other sites already identified in the Skagway area. The estimated construction cost would be about 1.9 times the Dayebas Creek site or +$10 million. 3-52 LEGEND GMM ODIVERSION —— PENSTOCK QO POWERHOUSE — P= TRANSMISSION SCALE IN FEET FIGURE 22 KASIDAYA CREEK Additional Sites Studied By Others Several additional hydropower sites have been studied by the U.S. Bureau of Reclamation (now Water and Power Resources Service), and others. Endicott River Site A potential hydropower site about 30 miles south of Haines on the west side of Lynn Canal. As most recently described by the U.S. Bureau of Reclamation (Reference 4): A 50-foot dam; 540-foot crest length; 50,000 acre feet; 18,000-foot conveyance to powerhouse; tailwater elevation equals the water surface in a second reservoir formed by a 250-foot dam; 250-foot crest length; no active storage; 2,000-foot conveyance to powerhouse. The estimated firm annual energy equals 70,000,000 kWh. Taiya River Site This site was studied by the U.S. Bureau of Reclamation and an International Commission and includes a transmountain diversion from the Lewes River in Canada at Lake Linderman. Lake Linderman would be interconnected with other lakes in the basin for a total storage of approximately 6,000,000 acre feet. Two alternatives have been suggested: e Diversion of about 2,300,000 acre feet annually to Taiya River via 15 miles of tunnel for 3,500,000 MWh of firm annual energy, plus small generation on the Lewes River to serve Whitehorse. 3-54 e Similar but larger scale development than Alternative A, subordinating normal navigational use of the water to power generation that would result in a potential of 8,800,000 MWh firm annual energy. Chilkat River About 5 Miles Inside the United States Border A large dam just above the confluence of the Tahini River would back water into Canada. The site was apparently considered as a power source for development of mineral resources in the vicinity of Klukwan. As reported by residents of Haines, the site has the potential for developing considerably more power than the industry would use. No written documentation on this site was found in the literature review. Development of the site to serve the Haines-Skagway area would require a 40-mile transmission line to Haines plus a Haines-Skagway intertie. These sites have not been considered further by this study. The Endicott and Chilkat sites are too far from the study area to economically provide power to Haines and Skagway. All three sites are several orders of magnitude larger than the loads in the study area. POWER AND ENERGY Each hydroelectric site was evaluated to determine the power that could be produced and the annual energy that could be produced during years with average, high and low streamflow. 3-55 The installed capacity proposed for each site resulted from consideration of operating heads, flow range, machine efficiency, present and future power loads, and standby diesel capacity. Past experience in hydropower development and engineering judgement were used to evaluate these factors and determine the installed capacity. No detailed analyses were made to optimize the installed capacity. The power that could be produced at each site was calculated using typical turbine efficiency curves, a generator effi- ciency of 98 percent and calculated penstock headlosses. Transformer and transmission line losses were not considered. Annual energy production at each site was calculated in one of two ways. First, for run-of-river plants, the average annual flow duration curves were used to calculate a power duration curve. The area under the power duration curve between the maximum and minimum machine capacity is the annual energy produced by the project. Energy during low flow and high flow years was based on the ratio of total runoff during the low and high flow years and average annual runoff. Low flows and ice make winter power generation a problem for run-of-river plants. For this study, it was assumed that the diversion dam would be high enough to provide a pool of water at the penstock intake so that winter diversions are possible. Secondly, the energy production at sites with storage was calculated based on a simple reservoir operation study using average monthly inflows and storage capacity curves from existing maps. Average monthly outflows were determined from the study and used to calculate monthly energy production. The reservoir sites have the ability to generate much larger amounts of energy in the winter than the run-of-river sites. 3-56 ECONOMIC EVALUATION This section contains an evaluation of the costs and benefits associated with the potential hydroelectric developments in the Haines and Skagway areas. This analysis is limited to the determination of attractive developments assuming that Haines and Skagway continue to operate separately. Detailed analyses of these attractive separate developments versus alternatives for combined, interconnected operations for the two areas are included in Chapter 6. The analysis includes the following methods and assumptions: e The marketable kWh benefits for the alternative projects were valued at the estimated cost for diesel generation. e Project cost estimates (construction costs plus engineering and overhead), were adjusted for inflation, which is assumed to average 4 percent per year throughout the study period. e The project schedule for each hydroelectric project is shown in Table 19. + Interest during construction was calculated as part of investment cost based on the "end-of-year convention." That is, yearly project costs during the construction period were assumed to be paid at the end of each year. e Operation, maintenance, and replacement cost estimates were assumed to increase at 4 percent per year throughout the study period; inflation to fuel prices was assumed to average 6 percent per year. Table 19 ESTIMATED PROJECT SCHEDULE FOR ALTERNATIVE HYDROELECTRIC FACILITIES NEAR HAINES AND SKAGWAY, ALASKA Initial Licensing Construction Year of Project Period Years Period Years Operation Chilkoot Diversion 1980-84 4 1984-87 3 1987 Chilkoot Dam 1980-84 4 1984-87 a 1987 Upper Chilkoot Lake 1980-83 x) 1983-86 3 1986 Dayebas Creek 1980-83 3 1983-85 2 1985 Upper Dewey Lake 1980-83 a 1983-86 = 1986 Reid Falls Creek 1980-83 a 1983-85 2 1985 West Creek 1980-84 4 1984-88 4 1988 Skagway River 1980-84 4 1984-87 3 1987 Goat Lake 1980-83 3 1983-86 a 1986 3-58 e Project life for hydroelectric facilities was estimated to be 50 years. e Amortization of new hydroelectric investment was assumed to occur over a 35-year period. e Diesel units were assumed to produce 13.5 kWhs per gallon. At 80¢ per gallon plus 5 percent for lube oil, total oil costs per kWh were estimated at 6.2¢/kWh in 1980. e@ Costs associated with diesel equipment depreciation, interest, and operation and maintenance was estimated to be 1.6¢/kWh in 1980. This estimate was based on an installed cost of $350/kW, a 50 percent average capacity factor and major maintenance every 30,000 hours. * Separate analyses were performed under assumed interest rates of 5, 7 and 9 percent. The estimated investment and the first-year annual cost associated with each potential hydroelectric project, assuming a 7 percent interest rate, is shown in Table 20. Line 1 shows the project cost in 1979 dollars. As mentioned above, these costs include construction, engineering, and overhead expenditures. In Line 3, these costs are escalated to their price levels at the year construction begins. Assuming project costs occur in a more or less uniform manner over the construction period, the project cost per year during the construction period is shown in line 5. Line item 6 shows the effect of continued inflation during the construction period. Interest during construction is calculated as shown in line 7. As mentioned above, this calculation assumes an 3-59 TABLE 29 ESTIMATED INVESTMENT AND ANNUAL COST FOR ALTERNATIVE HYDROELECTRIC CHILKOOT LAKE TAM UPFER CHILKOOT LAKE LAYERAS CREEK SACO IOI ICO IO IOI IK XASSUMF TIONS * * GENERAL. INFLATION 4%% * FUEL INFLATION 62K * INTEREST RATE SAK SOOO OOOO OOK FROJECTS NEAR HAINES ANI! SKAGWAYs ALASKA (DOLLAR AMOUNTS IN THOUSANIIS) CHILKOOT LAKE DESCRIF TION TNIVERSION 1. FROJECT COST (FC)»1979 DOLLARS 35708.0 2+ YEAR CONSTRUCTION BEGINS 1984 3. PROJECT COST @ FRICE LEVELS OF YEAR CONSTRUCTION REGINS 43444.2 4, CONSTRUCTION FERIOL (YEARS) 3 S. AVG. FROJECT COST FER YEAR @ FRICE LEVELS OF BEGINNING CONSTRUCTION YR. 14481.4 6. PROJECT COST PER YEAR @ CURRENT YEAR FRICE LEVELS (X) YEAR 1 14481.4 YEAR 2 15060.7 YEAR 3 15663.1 YEAR 4 0.0 YEAR 5S 0.0 YEAR 6 0.0 TOTAL 45205.2 7. INTEREST DURING CONSTRUCTION (N=LAST CONSTRUCTION YEARS X=FC 8. IN CONST YR YEAR N 3 X TIMES YEAK N-13 X TIMES YEAK N-2! X TIMES YEAR N-33 X TIMES YEAR N-43 X TIMES YEAR N-S3 X TIMES TOTAL ILc TOTAL INVESTMENT? FLUS IDC @ CURRENT FRICE LEVELS +000 +050 +102 158 +216 +276 FROJECT COSTS 9. ANNUAL AMORTIZATION COST (35 YEARS) 10. ides 12. 13. 14. ANNUAL OPERATION AND! MAINTENANCE (O&M) COST, 1979 DOLLARS ANNUAL REPLACEMENT COST» TOTAL ANNUAL O&M AND YEAR OFERATION BEGINS ANNUAL COST IN FIRST YEAR AMORTIZATION O&M AND REPLACEMENTS TOTAL 1979 DOLLARS REPLACEMENT COSTS OF OPERATION coouce 0 3 4 ° 0 0 47442.6 2897.4 160.0 7361 233.1 1987 2897.4 319.0 43042.7 3 14347.6 2216.7 4700441 2870.6 160.0 77.4 237.44 1987 2870.6 324.9 3195.65 30782.5 3 10260.8 10260.8 10671.3 11098.1 1585.3 33615.5 2053.0 240.0 112.5 352.5 1986 2053.0 463.9 2516.8 UPPER REID DEWEY FALLS WEST SKAGWAY GOAT LAKE CREEK CREEK RIVER LAKE 8689.0 4013.0 66538.0 2956940 23634.0 1983 1983 1984 1984 1983 10164.9 4694.6 80953.7 35975.2 27648.4 3 2 4 3 3 3388.3 “2347.3 20238.4 11991.7 921661 3388.3 2347.3 20238.4 11991.7 921661 3523.8 2441.2 21047.9 12471.4 9584.8 3664.8 0.0 21889,.9 12970.3 9968.2 0.0 0.0 22765.5 0.0 0.0 0.0 0.0 0.0 0.0 9.0 0.0 0.0 0.0 0.0 0. 10576.9 4788.5 85941.7 37433.4 287691 0.0 0.0 0.0 0.0 0.0 176.2 117.4 1094.5 623.6 479.2 347.3 0.0 2157.4 1229.2 944.7 0.0 0.0 3190.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 523.5 117.4 6442.0 11100.4 4905.9 92383.7 3928661 30193.0 677.9 299.6 5642.0 2399.3 1843.9 80.0 80.0 272.0 192.0 224.0 18.0 18.9 121.5 225.0 112.5 98.0 98.9 393.5 417.0 336.5 1986 1985 1988 1987 1986 677.9 299.6 5642.0 2399.3 1843.9 129.0 560.1 370.7 442.8 806.9 O21 2970.0 2286.8 end-of-year convention. Total investment, defined as total project cost adjusted for inflation, plus interest during construction, is shown in line 8. Line 9 shows the annual amortization costs for the investment over a 35-year period at the given interest rate. Annual operation, maintenance, and replacement costs are shown in lines 10 through 12 and at 1979 price levels. Total annual costs during the first year of project operation are shown in item 14. Amortization is fixed at the level shown from line 9, while the amount shown for operation, maintenance and replacement (OMAR) expense is for the first year of operation. In subsequent years, these OMAR costs are assumed to increase annually at the general inflation rate of 4 percent per year. Detailed analysis of costs associated with each hydroelectric project and the diesel alternative to each project are included in the exhibits with this report. The analyses are divided among three exhibits according to the assumed interest rates as follows: Exhibit C 5% Interest Rate Exhibit D 7% Interest Rate Exhibit E 9% Interest Rate Within each of those exhibits, the first table has the same format as Table 20, presenting the estimated investment and annual costs for the hydroelectric projects at the assumed interest rate. This table is followed by a series of tables, one for each hydroelectric project. Each of these tables presents a 50-year series of the given hydroelectric project annual costs, marketable energy production and the resulting average cost per marketable kWh. The tables also present a comparable 50-year series showing the annual cost associated 3-61 with diesel generation identical to that produced by the given hydroelectric project. The projected diesel cost per kWh is shown in Table 21 and is assumed to be the same alternative cost to each of the hydro projects. A comparison of the long-term average cost per kWh for diesel generation and the various hydroelectric projects near Haines is shown in Figure 23. Figure 24 shows a similar analysis for Skagway. The benefit/cost ratio for each of the alternative sites is shown in Table 22. As noted above, the benefits shown for each facility are valued at the cost of diesel generation (including equipment, O&M and fuel) that would be displaced by the given hydroelectric facility. The present valve calculations are detailed in Exhibits C, D, and E. Only four of the nine sites are attractive with benefit/cost ratios greater than 1.0 at all three given interests rates. These include Upper Chilkoot Lake and Dayebas Creek for the Haines area, and Upper Newey Lake and Reid Falls Creek for the Skagway area. In both of the two areas, the smaller of the two attractive hydropower sites had the higher benefit/ cost ratio. At Haines, Dayebas Creek has benefit/cost ratios of 2.5 to 4.7, depending on the interest rate, and annual energy production of 18,200 MWh. Upper Chilkoot Lake has lower benefit/cost ratios, (ranging from 1.7 to 4.4) but produces 61,200 MWh annually, three times the output of Dayebas Creek. Reid Falls Creek has higher benefit/cost ratios than Upper Dewey Lake (1.6 to 4.9 for Reid Falls vs. 1.2 to 3.5 for Upper Dewey) but Upper Dewey produces nearly twice as much energy. Since the larger projects would displace more diesel generation than the smaller projects, 3-62 TABLE 21] FROJECTED DIESEL COST PER KWH (CENTS) CAPITAL CAF ITAL cost PLUS Cost PLUS YEAR O&M OIL TOTAL YEAR O8H OIL TOTAL 1980 1.60 6.20 7.80 7699 67.60 75.59 1981 1.66 6.57 8.24 2022 8.31 71.65 79.96 1982 1.73 5.97 8.70 2023 8.64 75.95 84.59 1983 1.80 7.38 9.18 2024 8.99 80.51 89.50 1984 1.87 7.83 9.70 2025 9.35 85.34 94.69 1985 1.95 8.30 10.24 2026 9.72 90.46 100.18 1986 2.02 8.79 10.82 2027 10.11 95.89 106.00 1987 2.11 9.32 11.43 2028 10.51 101.64 112.15 1988 2.19 9.88 12.07 2029 10.93 107.74 118.67 1989 2.28 10.47 12.75 2030 11.37 114.20 125.58 1990 2.37 11.10 13.47 2031 11.83 121.06 132.88 1991 2.46 11.77 14,23 2032 12.30 128.32 140.62 1992 2.56 12.48 15.04 2033 12.79 136.02 148.81 1993 2466 13,22 15.89 2034 13.30 144.18 157.48 1994 2.77 14,02 16.79 2035 13.83 152.83 166.67 1995 2.88 14.86 17.74 1996 3.00 15.75 18.75 1997 3.12 16.70 19.81 1998 3.24 17.70 20.94 1999 3.37 18.76 22.13 2000 3.51 19.88 23.39 2001 3.65 21.08 24.72 2002 3.79 22.34 26.13 2003 3.94 23.68 27.63 2004 4.10 25.10 29.20 2005 4.27 26.61 30.87 2006 4.44 28.21 32.64 2007 4.61 29.90 34,51 2008 4.80 31.69 36.49 2009 4.99 33.59 38.58 2010 5.19 35.61 40.80 2011 5.40 37.75 43.14 2012 5.61 40.01 45.62 2013 5.84 42.41 48.25 2014 6.07 44.96 51.03 2015 6.31 47.65 53.97 2016 6.57 50.51 57.08 2017 6.83 53.54 60.37 2018 7410 56.76 63.86 2019 7439 60.16 67.55 2020 7+68 63.77 71.45 INTEREST RATE= 7% GENERAL INFLATION= 4% OIL PRODUCTS INFLATION= 6% =z = =x a e 2 wi 2 > o c w 2 w uw ° 3 o CHILKOOT LAKE DIVERSIO! CHILKOOT LAKE DAM DAYEBAS CREEK FIGURE 23 COST OF ENERGY—HAINES COST OF ENERGY (CENTS/KWH) 80 60 INTEREST RATE= 7% S 100 }——GENERAL INFLATION= 4% oy OIL PRODUCTS INFLATION= 6% ay Y 4, > Oe Cy ~, % 4 NV & > ——S “| 40 20 1980 1990 2000 YEAR 2010 2020 FIGURE 24 COST OF ENERGY—SKAGWAY Table 22 BENEFIT/COST RATIOS FOR ALTERNATIVE HYDROELECTRIC SITES AT HAINES AND SKAGWAY, AT INTEREST RATES OF 5, 7, AND 9 PERCENT (DOLLAR AMOUNTS IN MILLIONS) 5% Interest Rate 7% Interest Rate 9% Interest Rate Benefit/ Benefit/ Benefit Cost Cost Cost Project Benefits Costs Ratio Benefits Costs Ratio Benefits Costs Ratio Haines Area: Chilkoot Lake Diversion $111.8 $59.6 1.9 $66.8 $56.4 ee $43.0 955.1 0.8 Chilkoot Lake Dam 132.3) 59.4 Drie, 7923 56.1 1.4 Sly 2 54.7 0.9 Upper Chilkoot Lake 227 0) S13 4.4 L25i51 46.0 2G 74.0 43.3 Deed Dayebas Creek 93.8 19.8 G7 55.8 16.3 3.4 35.8 14.3 Ze5) Skagway Area: Upper Dewey Lake 56.5 16.0 Be) 29.4 14.6 2.0 16.5 13.9 2) Reid Falls Creek 38.7 Sri 4.0 20.8 8.1 2/16 12.20 Uo) 1.6 West Creek 116.2) 11327 1.0 59.4 109.2 0.5 32.55 108.0 0.3 Skagway River 52.1, 61.0 0.9 27.1 54.5 0.5 1551 Slay (Ol Goat Lake 87.1 47.0 19) 45.0 42.0 Loud; 24.9 39.4 0.6 Notes: 'Renefits are valued at the cost of diesel generation (equipment, O&M and fuel) that would be displaced by the given hydroelectric pracility. Present value calculations are in terms of the initial year of cooperation shown for each hydro site. General inflation is assumed to be 4 percent per year; fuel inflation is assumed to be 6 percent per year. 3-66 it was decided that they should also be evaluated as hydro- power alternatives in the separated area power plans discussed in Chapter 6. For the area power plan with combined Haines/Skagway operations, three relatively large hydropower alternatives are evaluated in Chapter 6: Upper Chilkoot, West Creek and Goat Lake. Benefit/cost ratios presented in Table 22 do not pertain to evaluation of combined operations since they do not include the full benefits or costs associated with combined operations. ENVIRONMENTAL EVALUATION This section provides a reconnaissance-level review of the environmental conditions and probable environmental impacts associated with the nine alternative projects determined to be feasible from an engineering perspective. The review is based entirely on secondary source information and general knowledge of the kinds of impacts likely to result from a hydroelectric project. No site-specific information was avalable for any of the eight sites, with the exception of the gross topographic and physical feature information presented on USGS 15-minute topographic quadrangles. Existing, large area land-use plans? provided most of the existing conditions information and nearly all the criteria for determining when and gener- ally what kind(s) of adverse impact mitigation would probably be required. lyaines Coastal Management Plan (Environmental Services Limited, 1979). 3-67 The environmental evaluations listed below present concerns only about probable adverse impacts on important biotic, recreational and cultural resources; and about situations where seismically-induced dam failure could be a hazard to human life and property. Other impacts commonly associated with construction and operation of hydroelectric dam projects are listed after the environmental evaluations. Also included is a list of public agencies with which implementation of any of these project alternatives or similar projects elsewhere in Alaska must be coordinated. Environmental Conditions and Concerns Chilkoot Lake Diversion--Alternative 1 The 15-foot-high structure, located at the upper end of the Chilkoot River connection between Chilkoot Lake and Lutak Inlet, would block the river until the lake level rises high enough (15 feet) to spill over the diversion structure. A canal along the north bank of the stream would connect the diversion structure to a powerhouse proposed for a site at the mouth of the river. Existing Conditions Geophysical. The project site is located in a deep, northwest to southeast valley. A 3,000-foot-high ridge bounds the valley on the north and the 3,000- to 5,000-foot-high Takshanuk Mountains form the southern boundary. 3-68 The Haines area lies within a tectonically active area, where large-scale faulting has been common. Several major and numerous minor faults transect the general area of Haines; one is the Chilkoot fault, extending longitudinally under the valley floor. These faults are, for the most part, concealed by water or by valley-floor deposits; thus their exact location and character can only be inferred. There are no known earthquake epicenters within the study area, but over 100 earthquakes have been recorded for the Haines area. Seismic records indicate that the largest earthquakes expected at Haines would have magnitudes between 6 and 7. Earthquakes of this magnitude could be expected to occur on the order of once or twice per century. The greatest potential earthquake effects include (a) damage due to displacement of facilities along faults, (b) damage due to compaction, settlement, liquefaction, subsidence, and ground fracturing of poorly consolidated, water-saturated deposits, (c) damage due to sliding on steep slopes or in fine-grained plastic sediments, and (d) damage from waves induced by submarine landsliding. Geologic hazards that are not caused by earthquakes are less severe but more common. Landslides and mixed snow and debris avalanches are most likely to occur during or after periods of heavy precipitation. Small landslide and snow avalanche debris accumulations occur along the steep mountain front north and northwest of Haines and along the fiord walls of Chilkoot and Lutak Inlets. A few landslides of considerable extent have occurred in the Haines area, including one on the east side of Taiyasanka Harbor and one on the northeast side of Lutak Inlet. Breaks in underwater cables can be caused by submarine landsliding. 3-69 Biotic. Lutak Inlet, to the southeast, is among the northern- most extensions of Lynn Canal, the north-south inlet off the Gulf of Alaska. Lutak Inlet is classified as an estuary in the Haines Coastal Management Plant (Environmental Services Limited. 1979). An estuary is defined as a "semi-closed, coastal body of water which has a free connection with the sea and within which seawater is measurably diluted with fresh- water derived from land drainage." Tide flats at the Chilkoot River mouth link the freshwater- associated upland habitat areas to the saltwater estuary. The tide flats are mostly unvegetated and alternately exposed and inundated by rising and falling tide waters. The tide- flats provide feeding grounds for birds and mammals during low tides. The Chilkoot River system (including Chilkoot Lake, islands, sandbars, and sloughs) is a combination of moving and quiet water bodies. Aquatic, riparian, and floodplain forest vegetation types provide very productive habitat for water- fowl, other birds, big game, and other upland mammals. The water bodies provide spawning and rearing areas for migratory fish species. Surrounding the Chilkoot River/Lake system is extensive upland habitat. Upland habitat is defined in the Haines Coastal Management Plan? to include: liaines Coastal Management Plan, Environmental Services Limited. 1979. 3-70 "1) Wildlife concentration areas (does not include areas where only wildlife presence is noted) as defined by the Alaska Department of Fish and Game in their revisions to Alaska's Wildlife and Habitat, 2) an area on either side of all anadromous fish streams, 3) coastal forest fringe from shorelines of estuaries and tideflats or around municipal water supplies, and 4) primary viewsheds. . . (They) protect anadromous streams, marine waters and downslope developments from excessive runoff, erosion, winds and avalanches, and help maintain the visual continuity of shorelines." The diversion structure would be situated in the river system and upland habitat. The canal would pass through upland habitat. The powerhouse would be located on upland habitat at the edge of the tideflats. Hemlock-spruce forest is the principal vegetational community of the project area. Proper growing conditions (i.e., streamsides, gentle to moderate slopes, uplifted beaches, and well-drained valley bottoms) make the forests in the project area of commercial quality. Although no site-specific information is available, the Haines Coastal Management Plan indicates that the lower Chilkoot River area is not a terrestrial mammal habitat of significance. The area probably does provide habitat for mink, martin, otter, muskrat, coyote, wolf, fox, lynx, wolverine, marmot, porcupine, and numerous small mammals; a few black or brown bears, particularly in the spring among salmon streams such as the Chilkoot River; an occasional moose moving between summer and winter ranges in November and back to summer ranges in June. 3-71 The Chilkoot River area, including the tideflats, is fre- quented by a variety of waterfowl, including Barrow's goldeneye, bufflehead, surf and white-wing scooters, common merganser, harlequins, and oldsquaw. lLoons, grebes, cormorants, gulls, terns, murres, and murrelets are seabirds commonly observed along the Lutak Inlet shoreline. Bald eagles commonly nest along the inlets of upper Lynn Canal and the major river valleys. Four known nest sites are within 1 mile of the project site, 1 less than 1/2-mile north/northwest. Nesting usually occurs April through August. Upland birds include the willow ptarmigan, blue grouse, ruffed grouse, ravens, magpies, jays, crossbills, chickadees, juncos, and numerous other songbirds that either nest here or migrate through the area. Marine life in Lutak Inlet includes: phytoplankton and zooplankton; algae and kelp; clams, cockles and severally commercially important species of crab and shrimp; five species of Pacific salmon, the Pacific Halibut, and Pacific herring, char, trout, true cod, rockfish, and sablefish; and marine mammals such as seals, sea lions, whales, and propoises. Pink and chum salmon spawn in the Chilkoot River segment between Chilkoot Lake and Lutak Inlet. Coho and sockeye salmon spawn in the upper end of Chilkoot Lake and tributary streams. Chilkoot Lake is one of the two most important sockeye spawning and juvenile-rearing areas in southeast Alaska, with from 60,000 to 100,000 escapements each year (Haines Coastal Management Plan, Environmental Services Limited. 1979). 3-72 Cultural. No sites listed on the National Historic Register are located at or near the project site. However, the diversion structure location is at or adjacent to the Chilkoot River Village site, which is believed to have prehistoric significance and is worthy of further consideration for possible inclusion in the National Register (Environmental Services Limited. 1979). Land Use, Ownership Status and Institutional Considerations. The proposed diversion structure site is partially within a private land holding. The canal would pass through both private and state lands. The powerhouse would be sited on state land and the transmission lines on state and private lands. There are no residences or businesses on the sites proposed for these facilities. An existing road along the south shore of Lutak Inlet connects the Chilkoot River Village area to the City of Haines. The project area is within the coastal zone defined in the Haines Coastal Management Plan. However, no coastal zone use policies are in effect here since the area, being unin- corporated, does not have the planning authority to draft and adopt a management plan. Use of state-owned portions of the project site would also be affected by the Haines--Skagway Area Land Use Plan (Alaska Department of Natural Resources. 1979). The Plan, adopted by the Commissioner of the Alaska Department of Natural Resources in June of 1979, designates land use classifications, which prescribe allowable land use activities that can be conducted while mantaining or enhancing the land's intrinsic 3=73 natural resource value. The land use classifications can be altered by decision of the Commissioner, if changing conditions warrant. The project site is partially on land designated "Public Recreation," where maintenance of scenic quality and develop- ment of public access and use potential commensurate with maintaining the fishery resources are the primary management policies. A Plan guideline prescribes no development at the "Kloot" (Chilkoot River Village) historic site until the State Office of History and Archeology has conducted a field survey to ensure compatibility with and protection of historic and archeological values. The canal would cross an area designated "Resource Management" where land use must be compatible with maintaining the adjacent fishery resource. Near the powerhouse site, the canal would pass through a small area classified "Reserved Use" where timber harvesting, mineral extraction, and mineral sales may occur with proper leasehold arrangements. The powerhouse and part of the diversion structure may be located on private land. Such areas are exempt from the Land Use Plan policies. The transmission lines would cross an area designated "Forest," where timber management for commercial productivity is the primary objective. 3-74 Environmental Concerns and Mitigation Measures Concern. Construction activity in the river bank and bed would cause a significant siltation problem disruptive to and possibly destroying pink and chum salmon spawning beds in the Chilkoot River. Mitigation. Construction work is most feasible during warmer weather and during the periods of lowest river flow, which is March, April, and May or October and November. The spring period corresponds with emergence of pink and chum salmon fry. The silt load could bury their initial food supply. Construction employing sedimentation ponds and diversion of lake water around the construction site to flush the spawning beds, or other techniques to (a) divert the major silt load away from the spawning beds and (b) maintain "clear" water flow over the beds to ensure a semblance of normal spawning bed conditions, can ensure survival of a portion of the fry. The cost of mitigation must be weighed against the value of perpetuating only a partial run of pink and chum salmon every third year thereafter. Concern. The diversion structure, at about 15 feet tall, would present a virtually impassable barrier to coho and sockeye salmon returning to spawn in Chilkoot Lake and tributary streams above the lake. Mitigation. A fish ladder should be provided around the diversion structure. The ladder should be in place prior to mid-July so that upstream migration will not be interrupted. The ladder could be incorporated into the proposed canal. 3-75 Concern. Raising the surface level of Chilkoot Lake by something less than 15 feet could result in flooding of the existing state wayside (recreation area) about 1/2-mile west of the diversion structure site. Mitigation. Relocate the wayside facilities. Concern. Construction of the proposed diversion structure could adversely impact the Chilkoot River Village prehistoric site. Mitigation. Submit diversion structure site plans and precise description of location to the Alaska State Office of History and Archeology for comment and recommendations. Concern. The diversion structure would be subject to the relative seismic instability of the southeast Alaska area. Mitigation. Engineering solutions for foundation and struc- tural characteristics can compensate for certain, predictable kinds and strengths of seismic activities. No manmade structures, except the powerhouse, would be affected by failure of the diversion structure. Chilkoot Lake Dam--Alternative 2 A 30-foot dam would be constructed near the upper end of the Chilkoot River connection between Chilkoot Lake and Lutak Inlet. A penstock following the river would connect the dam to a powerhouse at the river mouth. 3-76 Existing Conditions Geophysical. Same as described for Alternative 1. Biotic. Same as described for Alternative 1. Cultural. Same as described for Alternative 1. Land Use, Ownership Status, and Institutional Considerations. Same as described for Alternative 1. Environmental Concerns and Mitigation Measures. Concerns and mitigations are the same as for Alternative 1. However, the higher resulting lake surface elevation could adversely affect the utility of spawning beds in the upper lake and tributary mouths. No mitigation would be possible. Upper Chilkoot Lake--Alternative 3 A dam more than 15 feet high would be constructed on a small tributary to the Chilkoot River. A powerhouse would be located at the confluence, approximately 4 river miles above Chilkoot Lake. A penstock would connect the powerhouse to the dam, about 1 mile northeast. Overhead transmission lines down the south side of the Chilkoot River Valley and Lutak Inlet would connect the powerhouse to the City of Haines. Existing Conditions Geophysical. Similar to Alternative 1. Biotic. The project site is above important habitat or spawning areas in the Chilkoot River system. Downstream conditions are as described for Alternative 1. 3=77: Cultural. Available information shows no nearby sites of historic or anthropological importance. Land Use, Ownership, and Institutional Considerations. The project site is state land, although the transmission line route could cross private holdings. Land use is governed by the Haines--Skagway Area Lane Use Plan. The Plan designates the dam and impoundment site as "Resource Assessment." This is a temporary classification pending further area study and subsequent, permanent reclassification. The powerhouse site has a "Forest" designation, wherein management of timber resources for commercial harvest is the primary objective. An existing road from Haines passes near the powerhouse site. A bridge across the Chilkoot River would be required. Access to the damsite would require a new road over steep, forested terrain. Environmental Concerns and Mitigation Measures Available data indicates little need for concern about adverse wildlife or fish impacts. However, conducting construction work during dry weather periods should minimize the potential for excessive sediment loads in the stream and Chilkoot River which could adversely affect spawning areas downstream. Seismic concerns and mitigation would be similar to the Alternative 1 case. Dayebas Creek--Alternative 4 A diversion structure about 15 feet high would be built across Dayebas Creek about 1/2-mile above Taiya Inlet. The powerhouse proposed at the river mouth would be connected to 3-738 the diversion structure by a penstock along the north river bank. Existing Conditions Geophysical. Taiya Inlet, into which Dayebas Creek flows, is part of the intricate system of fiords off Chatham Strait and Lynn Canal dissecting southeast Alaska. The terrain in the project area rises steeply from Taiya Inlet to 5,000 feet at Mt. Villard in less than 3 miles. Seismic conditions are similar to those described for Alter- native 1. Biotic. Barrier falls near the mouth of Dayebas Creek probably preclude anadromous fish use. Although no site- specific information is available, marine species in Taiya Inlet and upland habitat plant and animal species in the area are probably similar to those mentioned for the Alterna- tive 1 project area. There is no indication in available information that the project area is considered to be critical habitat. Cultural. Available information shows no indication of historically or anthropologically important sites in the area. Land Use, Ownership Status, and Institutional Considerations. The project site is within the Tongass National Forest, and subject to the policies of the Tongass Land Management Plan. (U.S. Department of Agriculture, Forest Service, Alaska Region. 1979). The Tongass Plan designates the project area to be managed “in a roadless state to maintain its wildland character." Roads for specific uses may be authorized, however. 3-79 There are currently no roads, manmade structures, or private ownerships in the area. Environmental Concerns and Mitigation Measures Available data indicates little need for concern about adverse wildlife or fish impacts. Concern. The proposed project could violate the wildland character maintenance objective of the Tongass Land Management Plan. Mitigation. Project planning should be closely coordinated with the U.S. Forest Service, Alaska Region. Upper Dewey Lake--Alternative 5 A diversion structure about 15 feet high would be built across an outlet stream from Upper Dewey Lake. A two-mile-long penstock paralleling the stream would connect it to a power- house in Skagway. Existing Conditions Geophysical. Geophysical conditions are similar to those described for Alternative 4. Seismic conditions are similar to those described for Alter- native 1. Biotic. Available information shows no indication of anadro- movs fish usage, although Dolly Varden and brook trout are present. Wildlife presence should be similar to that described for upland habitat in Alternative 1. 3-80 There is no critical habitat here. Cultural. Available information shows no historically or anthropologically important sites in the area. Land Use, Ownership Status, and Institutional Considerations. The project site is within the Tongass National Forest, in an area to be managed to maintain wildland character, as described for Alternative 3. The project site is also in the jurisdiction of the Haines--Skagway Area Land Use Plan. A "Watershed" designation has been given the area, which has historically been the City of Skagway's water source and has the potential for future usage as such. The Dewey Lake Watershed is to be managed for its recreation potential while water supply quality and quantity are maintained. Water from Upper and Lower Dewey Lakes is currently used to supplement Skagway's power supply. Environmental Concerns and Mitigation Measures Concern. The risk to life and property caused by seismic activity is greater in this more populated location. Mitigation. As described for Alternative 1. There appears to be no other significant environmental concerns regarding this alternative. Reid Falls Creek--Alternative 6 A diversion structure about 15 feet high would be built across Reid Falls Creek about 1/2-mile above its conflu- ence with the Skagway River. A powerhouse would be built at the confluence and a penstock paralleling the creek would connect the two structures. 3-81 Existing Conditions Geophysical. Geophysical conditions would be similar to those described for Alternative 4. Biotic. The mouth of Reid Falls Creek appears to be located near the upper limit of the Skagway River salmon fishery. Other wildlife presences should be similar to that described for the upland areas near the Alternative 1 site. There is no critical habitat here. Cultural. Available information shows no historically or anthropologically important sites in the area. Land Use, Ownership Status, and Institutional Considerations. Land use designations and objectives of the Tongass Land Management Plan and the Haines--Skagway Area Land Use Plan are as described for Alternative 5. Environmental Concerns and Mitigation Measures Concern. Construction caused siltation could adversely affect salmon spawning in the Skagway River. Mitigation. Construction should occur during low creek flow conditions. Vegetation removal should be minimized, especially on stream banks. Revegetation or other methods to stabilize soil must be implemented as soon as possible to minimize a potentially excessive erosion and siltation problem. Concern. The risk to life and property caused by seismic activity is greater in this more populated location. Mitigation. As described for Alternative 1. 3582 West Creek--Alternative 7 A dam more than 15 feet high would be built across West Creek about 2-1/2 miles above its confluence with the Taiya River. A tunnel in the south valley wall, paralleling the creek would connect the dam to a powerhouse, also south of the creek, just above the confluence. Power transmission lines generally would parallel the east side of the Taiya River to Skagway. Existing Conditions Geophysical. Geophysical and seismic conditions are the same as described for Alternative 1. Biotic. The lower ten miles of the Taiya River are reported to provide important anadromous fish (chum, pink and coho salmon) spawning and rearing areas. From the West Creek confluence to its mouth, the Taiya River provides an important sport and subsistence fishing area (Alaska Department of Natural Resources, 1979). The lower reaches of West Creek, possibly above the dam site, provide similar fish habitat. Fish species include coho salmon, Dolly Varden/Arctic char and eulachon. The lower reaches of West Creek also provide important waterfront habitat (Alaska Department of Natural Resources, 1979). Upland area wildlife species and vegetation are probably similar to those mentioned for Alternative 1. None of the Taiya River/West Creek habitat is designated as “critical” 3-83 Cultural. Available information indicates no specific historic or archeological sites in the project area. The project area is, however, just outside the Klondike Gold Rush National Historic Park. Land Use, Ownership Status and Institutional Considerations. The Haines--Skagway Area Land Use Plan designates the project site as "Public Recreation." Land here will be managed in a manner that permits existing recreational uses (e.g., hunting, hiking, firewood gathering and berry picking) to continue and is compatible with adjacent Klondike River objectives. The land use plan recognizes the hydroelectric development potential. Secondary development priorities identified for the West Creek Valley area are solid waste disposal and remote cabin sites. Environmental Concerns and Mitigation Measures There appears to be no significant environmental concerns, although plans for this project should be coordinated with the Alaska Department of Natural Resources. Skagway River--Alternative 8 A dam exceeding 15 feet in height would be built across the Skagway River about five miles above its mouth at Taiya Inlet. A penstock would extend 1/2-mile downstream to the proposed powerhouse. Overhead transmission lines would parallel the west side of the river to Skagway. Existing Conditions Geophysical. The project site is in a deep river valley, making geophysical conditions similar to those described for 3-84 Alternative 1. Seismic conditions are also similar to Alternative 1. Biotic. According to the Haines--Skagway Area Land Use Plan, the lower 1 or 2 miles of the Skagway River provide coho and chum salmon and eulachon spawning areas. Barrier falls about 1 mile above Skagway prohibit upstream passage of anadromous fish. The lower Skagway River is also an important sport and subsistence fishing area. Joland vegetation and wildlife species are probably similar to those mentioned for Alternative 1. Wo major wildlife habitats are located here, however. Cultural. No important historic or archeological sites in the project area are identified in available information, although the Skagway River generally is the location of numerous old gold mining claims. The Klondike Gold Rush National Historic Site is about three miles farther upriver. Land Use, Ownership Status and Institutional Considerations. The Haines--Skagway Area Land Use Plan has temporarily designated this area as "Resource Assessment" until further evaluation determines the most appropriate permanent designation. The Tongass Land Management Plan prescribes management practices that maintain the area's wilderness character. Environmental Concerns and Mitigation Measures Concern. Construction caused siltation and/or radical Fluctuations in the river flow caused by dam operation for hydropower production could damage the lower Skagway River fisheries. 3-85 Mitigation. Construction should occur during the lowest flow period (spring) and vegetation removal should be mini- mized. The release of large quantities of sediment will probably be unavoidable because of the expense and lack of siting possibilities for sedimentation ponds. The flow contributions of tributaries entering the Skagway below the project site may be enough to flush the spawning beds. Some fry loss must be anticipated. Project design and operating characteristics (i.e., storage release) must be coordinated with the Alaska Department of Fish and Game. Concern. The dam would be subject to the relative seismic instability of the southeast Alaska area. With Skagway directly downstream, the risks to life and property become a significant issue. Mitigation. Mitigation would be as described for Alternative 1. Goat Lake - Alternative 9 Two dams, each exceeding 15 feet in height, would be built across the natural northern and southern outlets of Goat Lake. A short tunnel located just north of the south end dam would become the new outlet. The tunnel would empty into a mile-long penstock ending at a powerhouse on the bank of the Skagway River, about seven miles above the City of Skagway. Overhead transmission lines would deliver the power to Skagway along the west side of the river. Existing Conditions Geophysical. The dam site is 2,000 feet up the east side of the Skagway River valley. Geophysical and seismic conditions in the area are similar to those described for Alternative 1. Biotic. Biotic conditions are the same as described for Alternative 9. In addition, Goat Lake supports brook trout. Cultural. Cultural conditions are the same as described for Alternative 9. Land Use, Ownership Status and Institutional Considerations. The dam sites and penstock are within the area affected by the Tongass Land Management Plan. The "LUD II" use descrip- tion applied to the general project area prescribes manage- ment practices that maintain the area's wilderness character. The powerhouse lccation is also in the planning area of the Haines--Skagway Land Use Plan. The temporary designation of "Resource Assessment" applied here implies redesignation in the future to an appropriate, permanent use designation. Environmental Concerns and Mitigation Measures Concern. The steep slopes pose a very high erosion pro- bability, with a potentially heavy silt load reaching the Skagway River. Mitigation. Construction should occur during dry weather (spring), vegetation removal minimized, and revegetation or other soil stabilization techniques employed as soon as possible. 3-87 Concern. The dams would be subject to the area's relative seismic instability. Mitigation. Mitigation would be as described for Alternative 1. Common Impacts The following types of impacts are commonly associated with constructing and operating a hydroelectric dam project. Construction Phase e Mostly permanent aquatic and terrestrial habitat disruption for site access e Mostly permanent visual scars for accessways, project sites and transmission right-of-way where fill may be necessary; and at borrow sites, if not existing operations e Short-term noise in pristine environment e Short-term air quality degradation in pristine area e During short-term construction and until revegetation or final soil stabilization measures are completed, there is high probability of erosion from cleared areas (slides are possible at steep-sloped sites) and high probability of heavy stream sedimentation e Short-term and long-term (operational) probable stream bank erosion from altered stream flow regime caused by construction-related diversion and trail race characteristics of completed project 3-88 e Short-term construction labor force, if imported, will be added burden on city services and create a short term demand for housing e Short-term traffic increase on routes serving project site, equipment and supply sources and labor housing. Status of existing roads needs to be known. There will be some O & M traffic over the long term e Short-term construction labor force will spend payroll locally e Mostly permanent disruption of existing land use e Effect of required permits on project design and implementability Operational Phase e Inundation of impoundment area will permanently eliminate any existing wildlife, geological, cultural and aesthetic resources, possibly creating new resources e Permanent minor traffic and noise impacts in pristine environment for 0 & M e Permanent replacement of free flow stream with slack water e Permanent altered recreational-use opportunities. Need to know amount and type of existing recreational use e Permanent reservoir drawdown would expose unsightly lakebed e Pristine natural environment character would be encroached upon by structures, roads, borrow pits and transmission line corridors, etc.--permanently e Effects of increased electrical energy availability on the local communities, including: --Potential increased population capacity --Potential increased commercial/industrial develop- ment and employment --Reduced need for less environmentally compatible energy production e O & M staff will add to local payroll and consumer spending. e Operation life limited to sediment entrapment which gradually reduces reservoir capacity. e Land uses will be altered. Alterations must be compatible with existing land use plans, etc. Agency Coordination/Permit Requirements The following Federal or state agency coordination, as evidenced by a permit of approval, will probably be required in varying combinations for each alternative: 1 environmental Services Limited, 1979. Haines General Management Plan. Prepared for the City of Haines, Alaska. 3-90 Agency U.S. Army Corps of Engineers Council on Environmental Quality U.S. Fish and Wildlife Service Environmental Protection Agency U.S. Forest Service Alaska Department of Fish and Game Alaska Department of Environmental Conservation Alaska Coastal Management Program Alaska Department Natural Resources Permit of Approval Permit for ocean dumping of dredged materials in territorial waters Permit for discharge of dredged or fill materials in or adjacent to tidelands, submerged lands, rivers and wetlands Permit for structures or work affecting navigable waters Approved EIS for Federal action affecting the quality of the environment Approved EIS for Federal action affect- ing the quality of the environment Approved measures to protect affected endangered species NPDES permit for discharges to the waters of the U.S. Approval of measures to coordinate with national forest management plans Critical habitat area permit Protection of anadromous fish permit State game refuge permits Solid waste disposal permit Approval of measures to coordinate with with coastal management program Tideland permit (for temporary use of state-owned tide and submerged lands -- less than five years Tideland lease (for use of state-owned tide and submerged lands more than five years) 3-91 Alaska Department Natural Resoures (continued) Miscellaneous land-use permit (for installation of roads and utilities on state-owned lands) Permit to appropriate water from source reserved for public use Mining lease (for extraction of minerals from state-owned lands, tidelands and submerged lands) 3-92 an WMH chapter 4 ALTERNATIVE ENERGY SOURCES WOOD-WASTE THERMAL Schnabel Mill is presently the only source of wood waste for thermal generation of electricity in the Haines-Skagway area. The mill has proposed constructing a plant to supply the electric needs of the mill and provide some surplus energy to Haines. A detailed analysis of the technical and economic feasibility of the project is contained in a report prepared for Schnabel mili. The assumptions in the report relating to wood-waste (primarily wood bark) conversion to electricity are: e Moisture content of wood waste--55 percent e Heating value of wood waste--3,960 btu's/1b average for 70 percent hemlock and 30 percent spruce bark e Boiler efficiency--63 percent e Steam/fuel ratio--2.19 1b stm/1b waste e Steam/kWh production ratio--11.2 1b stm/kWh with boiler at 750°F/600 psi and condensate at 109° F These assumptions are reaonable and consistent with industry standard values. 1 Northwest Pacific Corporation: "1979 Updating of Feasibility Study and Report on Generation of Electrical Power from Wood Refuse at the Haines, Alaska Sawmill for Schnabel Lumber Company." 4-1 Additional data provided in a November 7, 1979 letter from Northwest-Pacific Corporation to Schnabel indicates that Schnabel would provide Haines with about 6261 mWh per year at a cost of about 8 cents per kWh. Given the fact that fuel costs are now about 6.2 cents per kWh (80 cents per gallon and 13.5 kWh per gallon), it is likely that Schnabel would not be able to immediately charge 8 cents per kWh. As an incentive to the utility, Schnabel would probably need to offer Haines Lighting and Power a rate somewhat lower than the diesel cost per kWh--that is, 6.0 cents per kWh if the power were available in 1980. Such a rate could then increase at about the same rate as diesel prices. At a savings of 2 mills per kWh, Haines electricity costs would be reduced by about $12,500 per year, assuming an annual Schnabel supply of 6,261 MWh. The letter also suggests that wholesale power cost to the community could be reduced in the future by ammortizing the capital investment on an accelerated schedule. This may enhance the wood-waste thermal alternative but an evaluation cannot be made without a specific long-term plan showing energy cost each year. It is apparent that while the wood-waste thermal potential contribution to future Haines annual energy requirements appears to be significant in initial years, it might also have an extremely wide range of contribution, depending on the operating mode of the mill. Conversely, contribution to demand requirements by the mill is relatively insignificant from the start and diminishes each year. Demand contribution is, of course, less valuable than annual energy contribution, and diesel peaking capacity could be economically added to the Haines power system to improve the "firm" power reliability. 4-2 Conclusions The installation of wood-waste generation at the Schnabel mill has economic merit and attractiveness in the Haines market area if the price allows the displacement of diesel- electric generation. However, Haines could not afford to become long-range energy dependent on the economic future of the wood mill. The long-range state timber contracts (20 years with options) do not guarantee the mill continued operation or economically attractive energy from the mill. Until hydroelectric power comes on-line, displacement of some portion of Haines's present diesel-electric generation is possible by the proposed wood-waste generation at Schnabel mill. The economic merit to the community, by wood-waste displacement of diesel fuel, depends on average diesel fuel prices, the selling price of Schnabel power, the on-line date of the wood-waste generation plant, and the reliable annual energy produced. When adequate hydropower is available, it will displace the wood-waste generation from the mill. However, the mill could still provide peaking and emergency power to the community on a standby basis and displace diesel-electric generation during winter low-flow months if the cost was less than diesel. TIDAL One site in the Haines-Skagway area was identified as having development potential to produce electric energy from the daily tide variation. Taiyansanka Harbor, located 4-1/2 miles north of Haines, at the mouth of the Ferebee River, could be developed for tidal power, but appears difficult and expensive. The mouth of the harbor, where a dam would be built, is 1,000 feet wide and 60 feet deep. The right abutment is solid rock and the left abutment is a terminal morraine of sands and gravels. Construction would pose very difficult foundation and dewatering problems. The harbor currently serves as a rough water refuge for small boats. The harbor and river support anadromous fisheries. A resolution of these present uses and the technical construction problems would be needed before development could be considered. WIND The feasibility of developing wind powered electric genera- tion facilities for Haines and Skagway cannot be evaluated at this time because of the lack of wind intensity/duration data. The area may be suitable for this type of development, but the economic feasibility depends on the solution to several technical difficulties: e The rugged mountainous terrain makes access to suitable sites very difficult and expensive. e The power output of most wind units in operation today is small. Several of the largest experimental units would be required to serve Haines and Skagway. The cost per installed kilowatt currently makes these units uneconomical. e Wind generation is not a dependable source, there- fore backup systems (diesel or hydropower) would still be required. e Winter operation would be difficult and may be impossible because of problems caused by ice formation. r) Wind generation technology is in the development stage. Demonstration projects currently under construction will probably point out additional technical and economic problems and solutions. GEOTHERMAL A literature search to find previously identified potential geothermal sources in the study area was not successful. The nearest identified evidence of geothermal activity is 60 to 70 miles south. The regional geology of the study area is a Jurassic or Cretaceous age batholith ranging in composition from gabbro to granite, and minor inclusions of metamorphic rock, have been identified by various geologic studies of the area. There is very little possibility for finding a geothermal resource close enough to Haines or Skagway to be included in a power plan. ENERGY CONSERVATION Peak loads and energy requirements can be reduced through load management and conservation. The success of these measures is related to the current levels of energy use. In 1977 the average energy consumption for residential customers in Alaska was 9,975 kWh per year. In Haines the average consumption was 6,106 kWh per year in 1977, and in Skagway the average consumption was 7,100 kWh per year in 1978. The current high cost of energy from diesel sources in Haines and Skagway has limited energy use and measures to conserve more energy would probably have little success. 4-5 CHAPTER V Transmission Intertie Assessment a Chapter 5 TRANSMISSION INTERTIE ASSESSMENT New hydroelectric or alternative electric generation facilities will require construction of transmission lines to carry the power to load centers in Haines and Skagway. There are two ways to serve the energy needs of the communities (a) construct two generation facilities, one serving Haines and the other serving Skagway and (b) construct one or more facilities and serve both communities through an intertie. _ Power systems in the two communities are not interconnected at present. Details of the two ways to serve the communities are discussed more fully in Chapter 6. HAINES TRANSMISSION SYSTEM The components required for a transmission system to connect either the Upper Chilkoot Lake project or the Dayebas Creek project to the City of Haines are listed below. Figure 25 shows the location of the system. e Upper Chilkoot Lake Powerhouse One 12.4 MW Pelton type turbine with generator voltage at 13.8 kV. Average annual energy for Upper Chilkoot is 61,186 (MWh) for 6.98 (MW) average capacity. e Upper Chilkoot Substation Step-up substation (15 MVA) from turbine generator, 13.8 kV, to overhead line, 69 kV, with associated switchgear and remote (microwave or carrier) controls. GOAT LAKE POWERHOUSE AND SUBSTATION WEST CREEK POWERHOUSE AND 24.9kV SUBSTATION OVERHEAD @ REID FALLS POWERHOUSE UPPER DEWEY POWERHOUSE UPPER CHILKOOT LAKE POWERHOUSE AND SUBSTATION 69 kV OVERHEAD DAYEBAS POWERHOUSE AND SUBSTATION 24.9 kV OVERHEAD - a Cin \aberanine HAINES CABLE SUBSTATION AND f TERMINAL INTERTIE WITH EXISTING HAINES DISTRIBUTION SYSTEM FIGURE 25 HAINES AND SKAGWAY TRANSMISSION SYSTEMS SCALE IN MILES 69 kV Overhead Transmission Line 16.5 miles of overhead, 69 kV line, with (15 MVA) transmission capacity, routed along west shore of Lower Chilkoot Lake basin to Haines Substation. Routing through scenic area requires timber screening from lake side and nonreflective conductors. (This adds to costs/mile). Haines Substation 15 MVA, 69/24.9 kV step-down for Upper Chilkoot transmission tie to Haines, 24.9 kV distribution, with associated switchgear, controls, enclosures and fencing. Submarine cable terminal (from Dayebas Creek) and 25 kV tie with associated switchgear. Dayebas Creek Powerhouse One Francis type 3.54 MW and one Pelton type 0.95 MW turbine generators. Average annual energy from Dayebas project is 18,190 MWh for 2.08 MW average capacity. Turbine generator at 4.16 kV requires step-up to 25 kV tie to Haines Substation. Dayebas Substation 3 MVA, 4.16 kV/24.9 substation to supply 24.9 kV overhead line to east shore cable terminal, with line interrupters and remote (microwave or carrier) controls. ® Dayebas Overhead Line 2.8 miles overhead 24.9 kv distribution line from Dayebas powerhouse to east shore cable terminal. e Dayebas Cable Terminal (East Shore) Four single conductor 25 kV cable terminals to provide one, three-phase (3 MVA) rated submarine circuit and one spare single-phase circuit. e Submarine Circuit--Dayebas to Haines 3.0 circuit miles of four each, single conductor, 24 kV submarine cables. This configuration provides one, three-phase (3 MVA) rated submarine circuit and one spare single-phase circuit for reliability. Cable to be purchased with 10 percent spare for repairs requires a total of 13.2 miles, single conductor, 25 kV cable. This route avoids deep (1,000 feet) submarine canyon crossing near the mouth of Dayebas Creek. e Haines Distribution System The existing system in Haines will require expansion or conversion to 24.9 kV to match load growth. These costs have not been included in this study. The costs to provide the transmission facilities are shown in Table 23. 5-4 Table 23 HAINES PROJECTS TRANSMISSION COSTS Upper Chilkoot Substation; 15 MVA @ $40/kVA 69 kV O/H transmission lines; 16.5 mi. @ $200,000/mile (environmental constraints add to cost/mile) Haines Substation; 15 MVA @ $35/kVA Dayebas Substation; 3 MVA @ $35/kVA Dayebas O/H line; 2.8 mi. @ $80,000/mile Dayebas Cable Terminal; 4 ea. 25 kV terminals Submarine circuit, Dayebas-Haines; (4 ea., l-phase cables, 13.2 mile @ $80,000/mile SKAGWAY TRANSMISSION SYSTEM ($1,000) 600 3,300 525 105 224 40 1,056 The components required for a transmission system to connect the Goat Lake, Reid Falls, or Upper Dewey Lake projects to Skagway are listed below. Figure 26 shows the location of the system. 1, Goat Lake Powerhouse One 12.7 MW Pelton turbine. Average annual energy from Goat Lake project 62,934 MWh for 7.18 MW average capacity. 1.A Goat Lake Substation 15 MVA, 13.8 kV/24.9 kV step-up with associated switchgear and controls. 5-5 HAINES SUBSTATION AND INTERIE WITH EXISTING HAINES DISTRIBUTION SYSTEM SCHNABEL geese WOOD-WASTE GENERATOR GENERATOR 0 2 4 _—— SCALE IN MILES WEST CREEK POWERHOUSE AND SUBSTATION 29.4 kV-OVERHEAD TO INTERTIE: POINT WITH EXISTING SKAGWAY DISTRIBUTION 34.5 kV OVERHEAD HAINES—SKAGWAY INTERTIE SUBMARINE CABLE TERMINAL FIGURE 26 HAINES AND SKAGWAY INTERTIE Overhead Line, Goat Lake to Skagway 24.9 kV, 6.5 miles to intertie with existing Skagway distribution system. Reid Falls Powerhouse One 2.69 MW and one 0.35 MW Pelton turbine. Average annual energy 11,335 MWh for 1.29 MW average capacity. Minimum 0.5 mile 25 kV tie required to existing Skagway distribution system. Upper Dewey Lake Powerhouse One 3.92 MW Pelton turbine. Average annual energy from project 20,590 MWh for 2.35 MW average capacity. No new overhead line construction required because powerhouse is adjacent to existing Skagway distribution system. The costs to provide transmission facilities are shown in Table 24. Table 24 SKAGWAY PROJECTS TRANSMISSION COSTS (1000's $) Goat Lake Project (12.7 MW) Goat Lake Substation: 13.8/24.9 kv, 15 MVA @ $40/kVA 600 O/H 24.9 kv line; Goat Lake to Skagway: 6.5 mi. @ $80,000/mile 520 Reid Falls Project: (3.0 MW) (0.5 mi. 24.9 KV distribution @ $80,000/mile) 40 Upper Dewey Project: (3.9 MW) (No distribution required, because project is adjacent to existing plant) 0 5-7 HAINES-SKAGWAY INTERTIE An alternative to developing separate projects for each community is to construct an intertie between the communities and a large hydropower project such as West Creek. Developing West Creek requires an 8 MW capacity intertie to Haines and a 5 MW capacity intertie to Skagway. This is based on projected loads in the two communities. The components of an intertie system are listed below. Figure 26 shows the location of the facilities. is West Creek Powerhouse One 13.2 MW Francis type turbine. Average annual energy available 117,124 MWh. Generator requires short 13.8kV circuit to West Creek Substation. is West Creek Substation Two each (7.5 MVA) three-phase tertiary type transformers, each 13.8/34.5/24.9 kV, with associated switchgear, protective relaying, and remote (microwave or carrier) controls, enclosures, and fencing. Je Skagway Overhead Line 4.0 miles of 24.9 kV overhead distribution line to intertie point with existing Skagway distribution system. 4, Skagway Distribution Existing or expanded, not included in intertie costs. 5=8 Haines Overhead Line 16.0 miles of 34.5 kV overhead line routed along west shore of Taiya Inlet. Difficult route is reflected in cost estimates. Option in difficult places to substi- tute short segments of submarine cable. Submarine Cable Terminal The 34.5 overhead line to 35 kV submarine cable transition requires fenced area, protective interrupters on cable, and cable terminals. Submarine Cable 2.0 miles of 35 kV, three-phase submarine circuit. Four single-phase cables provide for single-phase failure. Purchase of 10 percent spare cable (to be stored for future emergency repairs) results in total initial purchase of 8.8 miles of single-phase cable. Haines Substation Two each 5.0 MVA three-phase transformers, each 34.5/24.9 kV with associated switchgear, protective relaying and instrumentation, enclosures and fencing. Schnabel Wood-Waste Generator Intertie Intertie at Haines substation. One 1.0 MVA three-phase transformer 2.4/24.9 kV required to include wood-waste generation into the distribution system. Minimum disconnect switches and ancillary equipment. 5-9 Item 9 above is required only if the wood-waste thermal generation system at Schnabel Mill is interconnected to Haines. The cost for each of these components is shown in Table 25. Table 25 TRANSMISSION INTERTIE COSTS West Creek Hydropower project West Creek Substation, 15 MVA @ $40/kVA (3 winding transformers, 13.8/34.9/24.9 kv) Skagway O/H line, 24.9 kV, 4.0 miles @ $80,000/mile Skagway Distribution System (not part of this study) Haines O/H Line; 34.5 kV, 16 miles @ $150,000/mile Submarine Cable Terminal, 4 each, 35 kV cables and switchgear Submarine Cables, 4 each, 1 phase, 8.8 miles total @ $100,000/mile (2 miles of 3-phase circuit plus 10% spare cable) Haines Substation, 10 MVA @ $35/kVA (34.5/24.9 kV transformers) Transformer & minimum switchgear for, 2.4 kV wood-waste intertie addition, 2.4/24.9 kV, 1 MVA @ $30/kVA (1000's Dollars) 600 320 2,400 50 880 350 30 The economic comparison of the intertie versus developing separate projects for the two communities is discussed in Chapter 6. 5-10 WHITEHOUSE-SKAGWAY INTERTIE A minimal evaluation of a possible electric intertie from Whitehorse, Yukon Territory, to the Skagway, Alaska, communities is made in a report by the Northern Canada Power Commission. The capital cost estimate for the intertie is based on a 33 kV or 69 kV (the report is unclear) transmission line routed approximately 65 miles through the rugged terrain of the international boundary, at an assumed $75,000 per mile. The report acknowledges that the nearly $5 million cost of the line could double if extensive helicopter construction techniques were required. The NCPC report also presents an estimate of at least $11,000 per year for annual line maintenance following construction. There are many facets of the report open to question, but the critical areas are: 6 Unrealistic projections of Skagway electric energy and demand impacting the Whitehorse-Aishihik system; the NCPC report projects no load increase for Skagway to the year 1985, using a constant 6,700 MHW per year 1978 energy level. (The report acknowledges this shortcoming). e Indeterminate construction cost (and amortization penalty for delivered energy) for the Carcross-Skagway intertie. > Northern Canada Power Commission (NCPC), "A Preliminary Feasibility Study on the Carcross-Skagway Extension Between Carcross, Y.T., and Skagway, Alaska." 5-11 e Preliminary economic assessment is based on diesel- electric generation at Whitehorse as the primary energy source, rather than lower cost energy which future NCPC hydroelectric and transmission projects might deliver in the next two decades. e Inadequate determination of the jurisdictional and political complexity of the inter-Canada-Alaska transmission intertie, its authorization and establishment of the wholesale energy cost. Currently, there is a precedent for inter-Alaska-Canada power purchase in the southeast region. The community of Hyder, Alaska, at the head of the Portland Canal, receives diesel-generated wholesale power from Stewart, British Columbia. However, the communities are within sight of each other, connected by a short all-season road, and the energy transmission is technically simple and constitutes a relatively small-scale addition to Stewart's requirements. Also, the communities are economically related with a long history of friendly cooperation and intercommunication. Our evaluation of the NCPC report concludes that an adequate analysis of costs for a Whitehorse-Carcross-Skagway intertie have not been provided. Without a lower cost alternative energy source than present diesel-electric generation at Whitehorse, the intertie to Skagway has no justifying economic potential for further evaluation. The community of Skagway should pursue development of local alternative hydroelectric energy projects (outlined in this study) that will require FERC licensing during the 1980-82 period. Should alternative hydroelectric or major transmis- sion projects on the Canadian side of the border develop during 1980-83, Skagway can reevaluate an intertie to Whitehorse in lieu of local hydroelectric development, prior to commencing local project(s) construction. 5-12 HAINES-KLUKWAN INTERTIE A report! prepared for the Alaska Power Authority by Robert W. Retherford Associates, shows projected energy requirements for Klukwan. In 1995, loads are projected to be 951,000 kWh per year with a peak demand of 246 kW. An intertie between Haines and Klukwan would require 20 miles of transmission line at an estimated cost of $1,200,000 ($60,000 per mile). If the construction cost is amortized over 35 years at 7 percent interest, the cost for transmis- sion varies from 19.7 cents per kWh in 1980 to 9.7 cents per kWh in 1995 (based on load forecasts in the above report). At this time, it is more economical for Klukwan to continue using diesel-electric generation. If loads grow faster than projected, or if diesel costs escalate faster than expected, an intertie should be reconsidered. lrobert W. Retherford Associates for Alaska Power Authority, Preliminary Appraisal Report, Hydroelectric Potential for Amgoon, Craig, Hoonah, Hydaburg, Kake, Kasaan, Klawock, Klukwan, Pelican, Yakutat. Anchorage, Alaska, September, 1977. 5-13 CHAPTER VI Area Power Plans ma Chapter 6 an 7 AREA POWER PLANS The purpose of this chapter is to develop and evaluate alternative plans for meeting the electric energy needs of the Haines-Skagway area through the year 2005. The evalu- ation shows the least-cost alternative plan for providing the area energy needs. The most feasible generating alter- natives discussed in this report have been included in the various plans presented in this chapter. The alternatives include diesel-electric power, hydropower, and wood-waste thermal power at the Schnabel Mill. Generally, there are two ways to supply electricity to Haines and Skagway. The first way provides completely separate generation and distribution systems for each community. The second provides common generation facilities and a transmission intertie between the two communities. Seven alternative area power plans have been developed based on the technical, economic, and environmental analysis in Chapters 3, 4, and 5. All plans include the present generating facilities at each community, one new hydroelectric development, and additional diesel-electric generation, if needed, to meet projected loads. The new hydroelectric sites included in the plans are those with the best benefit/cost ratio when compared to the diesel alternative and those with the least technical and environmental constraints. Plans for Haines also include the proposed wood-waste thermal plant at Schnabel Mill. The seven alternative plans are: e Haines Alternative 1--Upper Chilkoot Lake Alternative 2--Dayebas Creek 6-1 e Skagway Alternative 3--Upper Dewey Lake Alternative 4--Reid Falls Creek e Haines and Skagway Intertied Alternative 5--West Creek Alternative 6--Goat Lake Alternative 7--Upper Chilkoot Lake Investment, operation, maintenance and replacement cost data for alternatives 1 through 4 are shown in the first table in Exhibits C, D, and E for interest rates of 5, 7, and 9 percent, respectively. Similar cost data for alternatives 5, 6, and 7 are presented in Exhibit F for each of the three interest rates. The data for Alternatives 5, 6, and 7 also include the $4.6 million (1979 prices) investment required for a transmission intertie between Haines and Skagway. Each of the alternative plans were evaluated over the planning period 1980 to 2005. The evaluation determined (a) the energy cost throughout the planning period (b) and the present value of the plan costs throughout the planning period. The evaluation also compared the energy cost for each alternative plan with the energy cost of the "no action" alternative. The "no action" alternative is defined as a plan that uses the existing generation facilities at each community and new diesel-electric generation facilities necessary to meet projected loads. This comparison is shown in Figures 30, 34, and 38. 6-2 HAINES POWER PLANS Alternative 1, Plan Description The Upper Chilkoot Lake hydropower project has several advantages over the Dayebas Creek Project (Alternative 1). Upper Chilkoot Lake can be developed as a storage project, thereby providing capacity and energy during the winter when natural stream flows are low. The project could provide nearly 100 percent of the projected energy needs to the year 1998 (see Figure 27). The capacity needs of Haines could be met by the project during most of the year. How- ever, existing diesel generation facilities would be needed to meet peak loads during low flow months and to cover energy deficits after 1998. Overall, this project contributes most to the long-range energy needs of Haines. The ability of the Upper Chilkoot Lake project to meet projected annual energy and capacity requirements throughout the planning period is shown in Figures 28 and 29. Alternative 2, Plan Description The Dayebas Creek hydropower project, although smaller than the Upper Chilkoot project (Alternative 1) has several advantages. The site has been developed in the past to serve the hydroelectric needs of a now abandoned sawmill. It is less expensive than Upper Chilkoot Lake to develop and could be constructed and operational in less time, thereby displacing the diesel-electric alternative at an earlier date. The disadvantage of Dayebas Creek is the lack of storage to provide for energy needs during low streamflow periods. Figure 27 shows that the project would never provide all of Haines's projected annual energy requirements IN 2030 (GOIH3ad YV3A OL AS HLNOW/YMW) NOILdWNSNOD ATHLNOW 39VYH3AV G3193r0Oud IN 2020 3322 IN 2010 4 1945 IN 2000 1139 IN 1990 658 MWh/MONTH IN 1980 T T T T ~ o wo vt (HLNOW/YMW 000L) NOILONGOYd ATHLNOW JDVYHSAV --—-- UPPER CHILKOOT LAKE —-—CHILKOOT LAKE DAM -—CHILKOOT LAKE DIVERSION + DAYEBAS CREEK FIGURE 27 ENERGY CONSUMPTION TO MONTHLY PRODUCTION HAINES COMPARISON OF PROJECTED LOAD FORECAST MEDIUM PROJECTION a INSTALLED CAPACITY 12,400 kW = = Qa 4 ° 4 x ¢ wi a 4 <x 2 2 2 ¢ INSTALLED CAPACITY UPPER CHILKOOT LAKE RANGE OF AVERAGE MONTHLY CAPACITY DAYEBAS CREEK RANGE OF AVERAGE MONTHLY CAPACITY 0 Oo] TTTtTt TTT TTT TTT tT le 1980's H 2000's 2010's I-| FIGURE 28 HAINES COMPARISON OF PROJECTED PEAK LOADS TO CAPACITIES = = = So So S = > Oo oc w 2 Ww - < = 2 2 < a 3° w 3 LOAD FORECAST MEDIUM PROJECTION MARKETABLE ENERGY FROM UPPER CHILKOOT LAKE (ALTERNATIVE 2) MARKETABLE ENERGY FROM DAYEBAS CREEK (ALTERNATIVE 1) \ 2010's Tova ey Talal ee lan [xcs | YEAR 2020's 2030's FIGURE 29 HAINES COMPARISON OF PROJECTED ENERGY CONSUMPTION TO ANNUAL MARKETABLE ENERGY during the winter months. Operation of existing diesel- electric generation facilities would have to continue, although at a reduced level, to provide both peak capacity and energy. Figures 28 and 29 show the projected annual energy and capacity requirements for Haines throughout the planning period and the ability of the Dayebas Creek hydropower project to meet those requirements. Schnabel Mill Wood-Waste Thermal Electric Generation Alternative plans 1, 2, 5, 6, and 7 serve the City of Haines and include power available from the wood-waste thermal electric plant described in Chapter 4. Schnabel Lumber, in Haines, is considering a plan that would make 6,260 MWh per year available to the city. Preliminary analysis indicates that initially energy would be sold at 8 cents per kWh; rates possibly will decline after that due to accelerated equipment ammoritization by the mill owners. The data presented to date indicate that wood-waste generation would be attractive in the Haines market area as a substitute for diesel-electric generation. However, since the wood-waste power production is dependent on the economic viability of the lumber mill, it should be considered an interruptible supply. The long-range state timber contracts (20 years with options) do not guarantee continued mill operation. Until hydroelectric generation can come on-line, displace- ment of some Haines diesel-electric generation by wood-waste thermal generation is likely to be economically attractive at 6.0 cents per kWh (based on 1980 diesel costs). Once hydropower becomes available, the market for the wood-waste generation will be limited to periods when the area's load exceeds the available hydropower, such as winter low-flow periods. 6-7 For the purposes of the area power plan, we have assumed the Schnabel mill will provide Haines with about 6,260 MWh per year until the area is served with hydropower; after that, all energy will be provided by hydroelectric or diesel generators. Economic Evaluation of Haines Plans Projections of the generation mix (diesel, hydropower and thermal), annual power costs and average cost per kWh for 1980-2005 are presented in three exhibits: Assumed Interest Exhibit Rate G 5% H 7% I 9% Table 1 in each Exhibit assumes that Upper Chilkoot is built and begins providing power to Haines in 1986; Table 2 assumes that Dayebas Creek is constructed and supplies power to the area starting in 1985. The analysis assumes that Haines will be served by diesel-electric generation and by the Schnabel wood-waste generation until the hydroplant is operating. The power from Schnabel Mill, identified as "other" in the fifth column of data, is assumed to be 6,261 MWh per year. Once the hydropower plant begins operation, it is assumed that loads not met with the new hydropower resource will be supplied through diesel-electric generation. In reality, some of this load may be met with Schnabel generation. However, given the uncertainty of future load dispatch and Schnabel operating levels in the late 1980's, the simplifying assumption was made that diesel- electric generation would be dispatched after hydropower. 6-8 During the planning period Upper Chilkoot Lake provides 25 to 50 percent more marketable power and thereby displaces more diesel than Dayebas Creek; however, its construction cost is about 3.75 times higher. As a result, development of the Dayebas Creek site is the least-cost alternative. As shown in Table 26, the present value of Haines 1980-2005 power costs, including all forms of generation, is 31 to 65 percent higher (depending on the interest rate) with inclusion of Upper Chilkoot Lake (Alternative 1) than it is with Dayebas Creek (Alternative 2). Table 26 PRESENT VALUE OF ALTERNATIVE HAINES AREA POWER PLAN COSTS, 1980-2005 Present Value at Given Interest Rate (1,000 dollars) 5% 7% 9% Alternative 1--Upper Chilkoot Lake New Hydropower $25,396 $23,745 $21,961 Diesel-Electric 2,441 1,976 1,654 Other 2,198 2,058 2,932 TOTAL $30,035 $27,779 $25,546 Alternative 2--Dayebas Creek New Hydropower $ 9,612 $ 8,594 & 7,703 Diesel-Electric 11,483 8,283 6,123 Other 1,823 1,723 1,631 TOTAL $22,918 $18,600 $15,457 Ratio: Upper Chilkoot Lake to Dayebas Creek be3 1.49 1.65 Note: Present values calculated from annual costs shown in Tables G1, G2, H1, H2, I1, and I2. 6-9 INTEREST RATE = 7% GENERAL INFLATION = 4% OIL PRODUCTS INFLATION = 6% UPPER CHILKOOT LAKE ALTERNATIVE 1 EXISTING SYSTEMS PLUS NEW DIESEL AND WOOD WASTE THERMAL DAYEBAS CREEK ALTERNATIVE 2 i E ; + NOTE: DATA FOR THIS FIGURE IS SHOWN IN EXHIBIT H AS FOLLOWS: ALTERNATIVE 1 —TABLE H1 ALTERNATIVE 2 —TABLE H2 EXISTING SYSTEMS —TABLE H8 FIGURE 30 SYSTEM ENERGY COST HAINES POWER PLAN ALTERNATIVES N (1000 MWh/MONTH) 4363 IN 2040 b (MWh/MONTH BY 10 YEAR PERIOD) r= 2 - o > a ° c a > a x = 2 So = w Oo < c Ww > < PROJECTED AVERAGE MONTHLY CONSUMPTION 2646 IN 2030 1604 IN 2020 973 IN 2010 590 IN 2000 515 IN 1980 358 MWh/MONTH IN 1990 ——-—- WEST CREEK —-— GOAT LAKE — SKAGWAY RIVER os - UPPER DEWEY REID FALLS FIGURE 31 SKAGWAY COMPARISON OF PROJECTED ENERGY CONSUMPTION TO MONTHLY PRODUCTION SKAGWAY HIGH PROJECTION WITH RAILROAD a < ° a = < w a - < 2 2 2 < SKAGWAY LOW PROJECTION 8-—4 REID FALLS WITHOUT CREEK RAILROAD RANGE OF AVERAGE 6-| MONTHLY INSTSLLBD CAPACITY CAPACITY 3,040 kW UPPER DEWEY LAKE RANGE OF DEPENDABLE AVERAGE MONTHLY CAPACITY 0 kW CAPACITY FIGURE 32 SKAGWAY COMPARISON OF PROJECTED PEAK LOADS TO CAPACITIES w o 1 —F N 3 1 a At eee au LOAD FORECAST ENERGY FROM LOW PROJECTION EEE DEWEY KE (ALTERNATIVE 3) ANNUAL ENERGY (1,000 MWh) MARKETABLE ENERGY FROM REID FALLS (ALTERNATIVE 4) Le a ‘al TTTTITT TTTTTT. 1980's s 1990's 2000's 2010's 2020's 2030's R YE FIGURE 33 SKAGWAY COMPARISON OF PROJECTED ENERGY CONSUMPTION TO ANNUAL MARKETABLE ENERGY Figure 30 shows the average system energy costs throughout the planning period. During most of the planning period, the Dayebas Creek alternative provides energy at less cost than the Upper Chilkoot Lake alternative. SKAGWAY POWER PLANS Alternative 3, Plan Description The Upper Dewey Lake hydropower project has very little storage and cannot provide all of Skagway's projected energy needs. Figure 31 shows that the project cannot meet energy requirements during the winter months. However, the project is very close to Skagway, which minimizes construction and operation difficulties. It is also close to existing trans- mission facilities. The project is located at an existing hydroelectric powerhouse; this minimizes the construction period and makes energy available to Skagway sooner than other projects. Existing diesel-electric generation facilities and facilities now under construction would be needed to meet projected annual peak loads and energy requirements of Skagway {see Figures 32 and 33). Alternative 4, Plan Description The Reid Falls Creek hydropower project is very similar to the Upper Dewey Lake project; they are similar in size, peak capacity, energy, construction and operation. Figures 31, 32, and 33 show the capability of the project to meet peak loads and energy requirements of Skagway. Economic Evaluation of Skagway Plans Projections of the generation mix and costs for Alternative 3 (Upper Dewey) and Alternative 4 (Reid Falls) are shown as the 6-14 third and fourth tables, respectively, of Exhibits G, H, and I. The generation mix shown in the tables includes the existing hydropower at Skagway. Alaska Power and Telephone Company operates two units at Dewey Lake which generate about 1.5 million kWh per year. During the planning period the Upper Dewey Lake alternative provides 10 to 20 percent more marketable energy output than Reid Falls Creek, but costs associated with the project more than offset the added energy benefits. Table 27 shows that the present value of system costs for Alternative 3 (Upper Dewey Lake) is 34 to 47 percent higher (depending on the interest rate) than the present value for Alterantive 4 (Reid Falls Creek). Figure 34 shows the sytem energy costs throughout the planning period. During this period, the Reid Falls Creek alternative provides energy at less cost than the Upper Dewey Lake alternative. HAINES-SKAGWAY INTERTIE POWER PLANS Alternative 5, Plan Description The West Creek hydropower project is much larger than Goat Lake or Upper Chilkoot (Alternative 7). The project has enough storage capacity to meet 100 percent of the communities' projected energy needs to the year 2024 (see Figures 35 and 37), and could also meet projected capacity requirements to the year 2008 (see Figure 36). Table 27 PRESENT VALUE OF ALTERNATIVE SKAGWAY AREA POWER PLAN COSTS, 1980-2005 Present Value at Given Interest Rate (1,000 dollars) 5% 7% 9% Alternative 3--Upper Dewey Lake Existing Hydropower $ 554 $ 436 $ 352 New Hydropower 8,076 7,611 7,077 Diesel-Electric 3,009 2,372 1,931 TOTAL $11,636 $10,419 $ 9,360 Alternative 4--Reid Falls Creek Existing Hydropower $ 551 $ 436 $ 352 New Hydropower 4,820 4,372 3,963 Diesel-Electric 3,334 2,583 2,068 TOTAL $ 8,705 $ 7,391 $ 6,388 Ratio: Upper Dewey Lake to Reid Falls Creek 1.34 1.41 1.47 Note: Present values calculated from annual costs shown in Tables G3, G4, H3, H4, 13, and I4. INTEREST RATE = 7% GENERAL INFLATION = 4% OIL PRODUCTS INFLATION = 6% UPPER DEWEY LAKE ALTERNATIVE 3 REID FALLS CREEK ALTERNATIVE 4 = = 2 z wi 2 > o « w 2 wi uw ° EXISTING SYSTEMS PLUS NEW DIESEL EXISTING SYSTEMS PLUS PLANNED EXPANSION OF PRESENT HYDROPOWER PLUS NEW DIESEL ————— ! 1980 1986 1995 NOTE: DATA FOR THIS FIGURE IS SHOWN IN EXHIBIT H AS FOLLOWS: ALTERNATIVE 3 —-TABLE H3 ALTERNATIVE 4 —TABLE H4 EXISTING SYSTEMS —TABLE H9 Pee + neni SYSTEM ENERGY COST SKAGWAY POWER PLAN ALTERNATIVES 7301 IN 2020 4 4926 IN 2010 (MWh/MONTH BY 10 YEAR PERIOD) 2 ° = oO > Qs ce a2 —@ z€ ES z= |S ue we < c w > < PROJECTED AVERAGE MONTHLY CONSUMPTION 2535 IN 2000 1497 IN 1990 1173 MWh/MONTH Jin 1980 WEST CREEK —-—— GOAT LAKE —--— UPPER CHILKOOT FIGURE 35 HAINES-SKAGWAY INTERTIED COMPARISON OF PROJECTED ENERGY CONSUMPTION TO MONTHLY PRODUCTION = = a < ° a =x < wi a a <x = 2 2 < GOAT LAKE RANGE OF AVERAGE MONTHLY CAPACITY UPPER CHILKOOT LAKE RANGE OF AVERAGE MONTHLY CAPACITY 2, LOAD FORECAST COMBINED HAINES AND SKAGWAY INSTALLED INSTALLED CAPACITY CAPACITY 12,700 kW INSTALLED CAPACITY 13,400 kW DEPENDABLE CAPACITY 11,400 kW DEPENDABLE CAPACITY WEST CREEK ll RANGE OF AVERAGE MONTHLY CAPACITY DEPENDABLE CAPACITY FIGURE 36 HAINES—SKAGWAY INTERTIED COMPARISON OF PROJECTED PEAK LOADS TO CAPACITIES MARKETABLE ENERGY FROM WEST CREEK (ALTERNATIVE 8). i a LOAD FORECAST COMBINED HAINES AND SKAGWAY MARKETABLE ENERGY FROM GOAT LAKE (ALTERNATIVE 7) — —— ——— porn = = = ° S 6 = > oO c w v= w el =< 2 2 = < =a a MARKETABLE ENERGY FROM UPPER CHILKOOT LAKE (ALTERNATIVE 6) FIGURE 37 HAINES—SKAGWAY INTERTIED COMPARISON OF PROJECTED ENERGY CONSUMPTION TO ANNUAL MARKETABLE ENERGY Alternative 6, Plan Description The Goat Lake hydropower project would be developed, as previously described, to serve both communities. Figures 35, 36, and 37 show the capability of the project to meet projected monthly and annual peak loads and energy. Alternative 7, Plan Description The Upper Chilkoot Lake hydropower project would be developed, as previously described, to serve both Haines and Skagway. The advantage of serving both communities is that with the combined load more of the plant output is marketable during the early years of the planning period. Figures 35, 36 and 37 show the capability of the project to meet projected annual peak loads and monthly and annual energy for both communities. Economic Evaluation of Haines-Skagway Intertie Plans Investment and annual cost data for Haines-Skagway intertie alternatives are shown in Exhibit F, under the three different interest rate assumptions. Projections of generation mix, annual cost and energy cost are presented in Exhibits G, H, and I, (5, 7, and 9 percent interest rates). Alternative 5 (West Creek) is shown in the fifth table, Alternative 6 (Goat Lake) is shown in the sixth table, and Alternative 7 (Upper Chilkoot Lake), is shown in the seventh table. The intertied power plan includes the existing hydropower at Skagway and the Schnabel wood-waste generation at Haines. Like the separate Haines alternative, the simplifying assumption was made that the 6,261 MWh annual output from Schnabel would be purchased only until new hydropower generation is available. 6-21 Alternative 6 (Goat Lake) has the least cost of the three intertied power plan alternatives. As shown in Table 28, the present value of system costs is about 10 percent more with Alternative 7 (Upper Chilkoot Lake) and 80 to 90 percent more with Alternative 5 (West Creek). Figure 38 shows the system energy costs throughout the planning period. The Goat Lake alternative provides energy at about 39 to 59 percent less cost than the West Creek alternative and about 10 to 13 percent less cost than the Upper Chilkoot Lake alternative. Economic Evaluation of Separate Versus Intertied Power Plans Comparison of separate versus intertied power plan alternatives shows that separate operations, with development of Dayebas Creek at Haines and Reid Falls Creek at Skagway, are the least expensive way to meet projected loads during the 1980-2005 power planning period. As shown in Table 29, the least-cost intertie alternative is 8 to 31 percent more expensive, on a present value basis, than the separate operation alternative. Figure 39 compares the system energy costs for the least-cost separate and intertie alternatives. Separate plans provide energy with an average cost about 0 to 35 percent less than the intertie plan during the intial years of the planning period. At the end of the planning period, the intertie plan would provide energy at an average cost about 18 percent less than separate plans. Table 28 PRESENT VALUE OF ALTERNATIVE HAINES-SKAGWAY INTERTIED POWER PLAN COSTS, 1980-2005 Present Value at Given Interest Rate (1,000 dollars) 5% 7% 9% Alternative 5--West Creek Existing Hydropower $ 551: $ 436 $ 353 New Hydropower 55,136 52,383 48,650 Diesel-Electric 3,724 3,398 Spii2 Other CPERE) 2,718 2,506 TOTAL $62,370 $58,935 $54,621 Alternative 6--Goat Lake Existing Hydropower $ 551 $ 436 $ 353 New Hydropower 26,665 25,048 23,244 Diesel-Electric 4,152 3,714 3,078 Other 2,198 2,058 wos TOTAL $34,066 $31,256 $28,606 Alternative 7--Upper Chilkoot Lake Existing Hydropower $ 55a $ 436 $ 353 New Hydropower 28,914 27,215 25,290 Diesel-Electric 5,976 4,609 3,691 Other 2,198 2,058 1,931 TOTAL $37,639 $34,318 $31,265 Ratios: West Creek to Goat Lake 1.83 1.89 L.91 Upper Chilkoot Lake to Goat Lake 0 LO Lj09 Note: Present values calculated from annual costs shown in Tables G5, G6, G7, H5, H6, H7, 15, I6, and 17. 6-23 INTEREST RATE = 7% GENERAL INFLATION = 4% OIL PRODUCTS INFLATION = 6% & WEST CREEK ALTERNATIVE § UPPER CHILKOOT LAKE ALTERNATIVE 6 i e 2 8 > g Fe 3 GOAT LAKE ALTERNATIVE 7 \ pasting SYSTEMS PLUS NEW DIESEL NOTE: DATA FOR THIS FIGURE IS SHOWN IN EXHIBIT H AS FOLLOWS: ALTERNATIVE 5 —TABLE H5 ALTERNATIVE 6 —TABLE H6 ALTERNATIVE 7 —TABLE H7 EXISTING SYSTEMS —TABLE H11 FIGURE 38 SYSTEM ENERGY COST HAINES AND SKAGWAY INTERTIED POWER PLAN ALTERNATIVES COMPARISON OF LEAST-COST AREA POWER PLANS Table 29 FOR HAINES AND SKAGWAY, SEPARATE VERSUS INTERTIED PLANS Least-Cost Power Plans Separate Operations: Haines: Alternative 2, Dayebas Creek Skagway: Alternative 4, Reid Falls Creek TOTAL Intertied Operations: Alternative 6, Goat Lake Ratio: Intertied to Separate Operations 1980-2005 Present Value at Given Interest Rate (1,000 dollars) 5% 7% 9% $22,918 $18,600 $15,457 8,705 7,391 6,383 $31,623 $25,991 $21,840 $34,066 $31,256 $28,606 1.08 1.20 1.32 6-25 = g ef ai 2 > °o « w Zz ui u ° é INTEREST RATE = 7% GENERAL INFLATION = 4% OIL PRODUCTS INFLATION = 6% GOAT LAKE ALTERNATIVE 5 RE! ALTERNATIVE 4 DAYEBAS CREEK ALTERNATIVE 2 D FALLS CREE FIGURE 39 SYSTEM ENERGY COST LEAST COST ALTERNATIVE 10. 11. a2! REFERENCES U.S. Department of Agriculture, Forest Service, Region 10, Water Resources Atlas, Ott Water Engineers, Redding, California. April 1979. U.S. Army Corps of Engineers, Hydropower Cost Estimating Manual, North Pacific Division, Portland District, Portland, Oregon. May 1979. Manual for the Determination of the Feasibility of Adding Small Hydroelectric Power to Existing Impoundments, Draft Copy, Hydrologic Engineering Center, Davis, California. March 1979. Alaska, "Reconnaissance Report on the Potential Develop- ment of Water Resources in the Territory of Alaska," Jan. 1952, USDI Bureau of Reclamation, 82nd Congress, 1st Session, House Document 197. “Water Powers Southeast Alaska" by the Federal Power Commisision and the Forest Service. 1947. "Report to the Federal Power Commission on the Water Powers of Southeastern Alaska." Joseph Cummings Dort, Hydroelectrical Engineer, U.S. Forest Service, Government Printing Office. 1924. Yehle, Lynn A., and Lemke, Richard W., U.S. Department of the Interior, Geological Survey, "Reconnaissance Engineering Geology Of The Skagway Area, Alaska, With Emphasis On Evaluation Of Earthquake And Other Geologic Hazards" Open File Report: OF 550, 1972. 1972. Yehle, Lynn A., and Lemke, Richard W., U.S. Department Of The Interior, Geological Survey, "Reconnaissance Engineering Geology Of The Haines Area, Alaska, With Emphasis On Evaluation Of Earthquake And Other Geologic Hazards" Open File Report: OF 515, 1972. 1972. Haines Coastal Management Plan, Environmental Services Limited. 1979. Haines--Skagway Area Land Use Plan, Department of Natural Resources. 1979. Tongass Land Management Plan, U.S. Department of Agricul- ture, Forest Service, Alaska Region. 1979. Northwest Pacific Corporation, "1979 Updating of Feasibility Study and Report on Generation of Electrical Power from Wood Refuse at the Haines, Alaska Sawmill for Schnabel Lumber Company." 1979. x-1 MM exhibit A ae HYDROLOGY A hydrologic analysis of the study area was completed to determine the quantity of water that is available for hydropower at each potential site. Normally, the best method is an analysis of streamflow records from recording gages. However, in this case, most of the hydropower sites are on streams without recording gages. Therefore, for this study, a regional method was applied, but not before its applicability was tested against the available streamflow records in the area. Three USGS streamflow gages, located in the study area, were analyzed using standard statistical methods: e Skagway River near Skagway (No. 15056100), 16 years of record e West Creek near Skagway (No. 15056200), 15 years of record e Taiya River near Skagway (No. 15056210), 8 years of record Data from each gage were analyzed to determine mean annual flow, mean monthly flow, annual flow duration values, and peak flow frequency values. Mean flows and flow duration values were calculated from mean daily flow measured at each gage. The peak flow frequency values were calculated from the annual measured peak flows using the log Pearson type III method. The regional method described in Reference 1 was applied to the gaged watersheds to determine values for mean annual flow, mean monthly flow, flow duration and peak flow frequency. The independent variables needed to apply the regional method were obtained from 15-1/2 minute USGS quadrangles, and from Reference 1. The results of the gage analyses and the regional analysis at the gage sites were compared to evaluate the applicability of the regional method to the study area. Table Al shows a comparison of the mean annual and mean monthly flows from each analysis. For West Creek and Taiya River, there is general agreement between the mean annual flows from the two methods. Mean annual flows for the Skagway River do not agree well. The comparison of flow per square mile of drainage area shown in Table A2 indicates that West Creek and Taiya River are hydrologically similar while the Skagway River is very different. The cause of this difference in watershed response is not readily apparent from characteristics of the watersheds. Precipitation variation is probably the main reason. Oro- graphic effects in southeast Alaska can cause variations in annual precipitation of 200-300 percent in very short dis- tances. Since there are few rain gages in the area, the published isoheytal maps do not accurately show all the rainfall variations. Any regional analysis is, therefore, limited by the accuracy of such maps. The variation between the gage measurements and results of the regional method may be partly due to errors in the gage measurements. The USGS classifies the records for the three gages as fair to poor, depending on the time of year. This is because of problems in measuring winter flows when the rivers are frozen. Because the regional method showed good agreement with two of the three gages in the area, the method was judged ade- quate for a reconnaissance level hydropower study. Future studies at the feasibility level should attempt to improve the hydrology data. Some suggested ways to do this include: e Collect rainfall data at various points in the project watershed to determine variations due to orographic effects. e Corelate rainfall data collected at the project site to nearby long-term gages to refine estimates of average annual precipitation. e Measure streamflows at the site; correlate data to the long-term gages in the area and to precipitation data. e Refine regional analysis methods through studies covering a smaller area around the project site. Existing studies cover a large part of southeast Alaska and may not adequately consider all varia- tions in weather patterns and watershed response throughout that area. Table Al COMPARISON OF AVERAGE FLOWS FROM GAGE ANALYSIS AND REGIONAL ANALYSIS West Creek Skagway River Taiya River Month Gage Regional Gage Regional Gage Regional Jan 26 47 32) 236 83 209 Feb 27 60 36 57 96 205 Mar 30 70 33 158 d3 248 Apr 53) 106 76 327 128 411 May 212 477 418 1,201 692 1,794 June 625 730 17395) 2 DIe2 2,041 4,000 July 990 769 1,641 2,248 37532 3,879 Aug 955 644 1,247 1,600 3,483 2,836 Sep 666 637 830 1,898 2,055 2,927 Oct 253 403 367 1,395 771 1,884 Nov 120 213) 163 TAS 407 970 Dec 46 132 56 285 145 506 Annual 335 300 527, 956 27136 1,322 Table A2 COMPARISON OF RUNOFF PER SQUARE MILE OF DRAINAGE AREA Month West Creek Taiya River Skagway River (cf£s/sq mi) (cfs/sq mi) (cfs/sq mi) Jan 0.60 0.46 O22 Feb 0.63 0.53 0.25 Mar 0.69 0.41 0.23 Apr Ae 28 0.71 0.52 May 4.91 3.86 2.88 June 14.47 11.40 9.62 July 22.92 1973 ala kas }74 Aug 2264 19.46 8.60 Sep 15 637 11.48 Bene Oct 5.86 4.31 2e53 Nov 2.78 2.27 dros. Dec 1.06 0.81 0.39 Annual eh 65.35 3 eGs West Creek drainage area = 43.2 square miles. Taiya River drainage area = 179 square miles. Skagway River drainage area = 145 square miles. MH rxhibit B ae GEOLOGIC DATA RECONNAISSANCE ENGINEERING GEOLOGY OF THE HAINES AREA, ALASKA, WITH EMPHASIS ON EVALUATION OF EARTHQUAKE AND OTHER GEOLOGIC HAZARDS By Richard W. Lemke and Lynn A. Yehle ABSTRACT The Alaska earthquake of March 27, 1964, brought into sharp focus the need for engineering geologic studies in urban areas. Study of the Haines area constitutes an integral part of an overall program to evalu- ate earthquake and other geologic hazards in most of the larger Alaska coastal communities. The evaluations of geologic hazards that follow, although based only upon reconnaissance studies and, therefore, subject to revision, will provide broad guidelines useful in city and land-use planning. It is hoped that the knowledge gained will result in new fa- cilities being built in the best possible geologic environments and being designed so as to minimize future loss of life and property damage. Haines, which is in the northern part of southeastern Alaska approx- imately 75 miles northwest of Juneau, had a population of about 700 people in 1970. It is built at the northern end of the Chilkat Peninsula and lies within the Coast Mountains of the Pacific Mountain system. The climate is predominantly marine and is characterized by mild winters and” cool summers. The mapped area described in this report comprises about 17 square miles of land; deep fiords constitute most of the remaining mapped area that is evaluated in this study. The Haines area was covered by glacier ice at least once and prob- ably several times during the Pleistocene Epoch. The presence of emer- gent marine deposits, several hundred feet above sea level, demonstrates that the land has been uplifted relative to sea level since the last ma- jor deglaciation of the region about 10,000 years ago. The rate of rela- tive uplift of the land at Haines during the past 39 years is 2.26 cm per year. Most or all of this uplift appears to be due to rebound as a result of deglaciation. Both bedrock and surficial deposits are present in the area. Meta- morphic and igneous rocks constitute the exposed bedrock. The metamorphic rocks consist of metabasalt of Mesozoic age and pyroxenite of probable early middle Cretaceous age. The igneous rocks consist of diorite and quartz diorite (tonalite) of Cretaceous age. Sedimentary rocks of Terti- ary age may be present in the mapped area but are not exposed. The surfi- cial deposits, of Quaternary age, have been divided into the following map units on the basis of time of deposition, mode of origin, and grain size: (1) undifferentiated drift deposits, (2) outwash and ice-contact deposits, (3) elevated fine-grained marine deposits, (4) elevated shore and delta deposits, (5) alluvial fan deposits, (6) colluvial deposits, (7) modern beach deposits, (8) Chilkat River flood-plain and delta deposits, and (9) manmade fill. Offshore deposits are described but are not mapped. Southeastern Alaska lies within the tectonically active belt t rims the northern Pacific Basin and has been active since at least Paleozoic time. The outcrop pattern is the result of late Mesozoic and Tertiary deformational, metamorphic, and intrusive events. Large-scale faulting has been common. The two most prominent inferred fault systens in southeastern Alaska and surrounding regions are: (1) The Denali fault system and (2) the Fairweather-Queen Charlotte Islands fault system. hat early In the general area of Haines, rocks of Mesozoic age northeast of Chilkat River have a simple monoclinal structure. Paleozoic-Mesozoic rocks southwest of Chilkat River are gently to rather complexly folded. Several major and numerous minor faults probably transect the general area of Haines but their exact location and character can only be inferred because their traces are coincident to the long axes of fiords and river valleys, where they are concealed by water or by valley-floor deposits. Inferred faults in or near the Haines mapped area are: (1) Chilkat River fault, (2) Chilkoot fault, (3) Takhin fault, and (4) faults in the saddle area at Haines. Southeastern Alaska lies in one of the two most seismically active zones in Alaska, a State where 6 percent of the world's shallow earth- quakes have been recorded. Between 1899 and 1970, five earthquakes of magnitude 8 or greater have occurred in or near southeastern Alaska or in adjacent offshore areas, three have occurred having magnitudes between 7 and 8, at least eight with magnitudes between 6 and 7, 15 with magnitudes between 5 and 6, and about 140 have been recorded with magnitudes less than 5 or of unassigned magnitudes. All of the earthquakes with magni- tudes greater than 8, and a large proportion of the others, appear to be related to the Fairweather-Queen Charlotte Islands fault system or to the Chugach-St. Elias fault. — Although there are no known epicenters of earthquakes in the Haines mapped area, more than 100 earthquakes having epicenters elsewhere have been felt or were possibly felt at Haines. Microearthquake studies along a segment of the Denali fault system between Mount McKinley and Haines (about 400 miles) indicate that during the period of investigations the Haines area had one of the highest rates of microearthquake activity any- where along that segment. On the basis of the seismic record alone, the largest expectable earthquakes in the Haines area would be of only moder- ate size (between magnitudes 6 and 7) and at only infrequent intervals. However, because of the high activity of the Fairweather-Queen Charlotte Islands fault system as well as the presence of other nearby faults of large size and of unknown activity, the possibility of an earthquake as great as magnitude 8 cannot be ruled out. Inferred effects from future earthquakes are based on this assumption. Possible earthquake effects include: (1) surface displacement along faults and other tectonic land-level changes, (2) ground shaking, (3) com- paction, (4) liquefaction in cohesionless materials, (5) reaction of sen- sitive and quick clays, (6) water-sediment ejection and associated suosidence and ground fracturing, (7) subaerial slides and slumps, ($) subaqueous slides, (9) effects on glaciers and related features, (10) effects on ground water and surface water, and (11) tsunamis, seiches, and other abnormal waves. Facilities that probably would be affected most by surface displace- ment of faults would be those along inferred faults in the saddle area at Haines. These might include roads and streets, buildings, port facil- ities, waterlines, sewerlines, a petroleum pipeline, and an aircraft landing strip. About the only facilities that might be affected by move- ment on the Chilkat River fault are shcrt segments of the Haines Highway, a petroleum pipeline, and a segment of a proposed highway across the Chilkat River. The Chilkoot fault probably is too far offshore to affect facilities other than, possibly, underwater communication cables. Sudden regional tectonic uplift or subsidence could produce a number of adverse effects, particularly along the shorelines of the inlets. Although the amount of shaking (intensity) associated with an earth- quake is dependent upon a great many variables, the variable most respon- sible at any epicentral distance is the type of ground. Generally the shaking is considerably greater in poorly consolidated deposits than in hard bedrock, particularly if the deposits are water saturated. In the Haines area, the geologic units are divided tentatively into three gen- eral categories on the basis of comparative degrees of expectable shak- ing: (1) strongest shaking, (2) intermediate shaking, and (3) least shaking. Compaction and resulting settlement could cause some damage in the Haines area. Roads and streets, the aircraft landing strip, buildings, and other facilities built of or founded wholly or partly on manmade fill might be damaged. Piers, docks, and other harbor works may be af- fected by compaction of loose sandy beach deposits. Any appreciable settlement of the Chilkat River flood-plain and delta deposits or of the low-lying parts of the elevated fine-grained deposits would result in these areas being inundated by the sea. Liquefaction in conesionless materials resulted in catastrophic flow slides, heavy loss of life, and great property damage during some past earthquakes in Alaska and in other parts of the world. Other factors being equal, fine sands and coarse silts are most subject to liquefaction. In the Haines area, the Chilkat River flood-plain and delta deposits prob- ably would bé most affected. Sensitive and quick clays, which lose a considerable part of their strength when shaken, commonly fail during an earthquake and become rapid earthflows. In the Haines area, preliminary data indicate that the ele- vated fine-grained marine deposits are most likely to contain sensitive clays, but more information is needed. Water-sediment ejection and associated subsidence and ground fractur- ing are common effects during major earthquakes. The ejections are associated with surface or near-surface unconsolidated deposits where there is a high water table and a confinec-water condition. In the Haines area, the Chilkat River flooc-plain and delta ceposits Probably are the most likely to be subject to these effects. Earthquake-triggered slides on land are confined most commonly to steep slopes and may involve either bedrock or surficial deposits. On moderately to nearly flat slopes, sliding is generally confined to fine- grained plastic surficial deposits or to materials that are subject to liquefaction. In the Haines area, an earthquake could trigger new rock- slides or accelerate the movement of presently active to semiactive talus deposits on steep slopes. Facilities that might be affected include roads northwest and north of Haines, the water facilities for Haines, a segment of a petroleum pipeline, and dwellings close to steep slopes. Surficial deposits that might slide on moderate to nearly flat surfaces are: (1) Cnilkat River flood-plain and delta deposits, (2) elevated fine-grained marine deposits, (3) elevated shore and delta deposits, (4) modern beach deposits, and (5) manmade fill. Facilities affected would depend upon which deposits slide. In assessing the potential for earthquake-induced submarine sliding in the Haines mapped area, it is concluded that the deltaic deposits at the mouth cf the Chilkat River probably have the greatest pctentiality. There seems little likelihood of major submarine sliding in Portage Cove because no steep underwater slopes are indicated. However, if the off- shore deposits are subject to liquefaction, slides can be generated on gentle slopes and the resulting slurrylike mess can move a considerable distance offshore. There are no glaciers in the Haines mapped area. Adverse effects from nearby glaciers probably would be minimal. Snow and debris ava- lanching on steep slopes might constitute a hazard within the Haines area during winter months. It seems unlikely that long-term supplies of ground water would be greatly affected although there might be temporary changes in flow and the water might be turbid for a period of time. Short-term effects on surface water may include increased flow of Chilkat River unless trib- utary stream channels are blocked by snow or rockslides and debris slides. If a slide dam is breached suddenly, the flow of water that was impounded can be large and heavy damage can ensue downstream. Abnormal water waves associated with large earthquakes elsewhere have caused vast property damage and heavy loss of life. Maximum height of tsunami waves and of runup on land cannot be predicted for the Haines area. Whether seiche waves can be generated in the inlets near Haines also cannot be ascertained. Local waves generated by earthquake-induced submarine sliding or by subaerial landsliding into water probably have the greatest destructive potential of any type of abnormal wave because of possible high local runup and because they can hit the shore almost without warning during or immediately after an earthquake. Geologic hazards in the area that are not caused by earthquakes are pelieved to be relatively minor. However, effects from hazards of this type may occur so much more frequently than effects from very infrequent large earthquakes that their aggregate effects could be significant. They include: (1) effects of ,landsliding and subequeous sliding, (2) effects of flocding, and (3) effects of relative uplift of land. Because of the reconnaissance nature of the study, the evaluations of geologic hazards described in this report must be regarded as tenta- tive and subject to revision. In order that more rigorous interpretations can be made in the future, several recommendations are made for additional studies. RECONNAISSANCE ENGINEERING GEOLOGY OF THE SKAGWAY AREA, ALASKA, WITH EMPHASIS ON EVALUATION OF EARTHQUAKE AND OTHER GEOLOGIC HAZARDS By Lynn A. Yehle and Richard W. Lemke ABSTRACT A program to study the engineering geology of most of the larger Alaska coastal communities and to evaluate their earthquake and other geologic hazards was started promptly after the 1964 Alaska earth- quake; this report is a product of that program. Field-study methods were largely reconnaissance, and thus the interpretations in the report are subject to revision as further information becomes avail- able. The report provides broad guidelines for planners and engineers when considering geologic factors during preparation of land-use plans. The use of this information should lead to minimizing future loss of life and property, especially during major earthquakes. Skagway was established in 1897 as a seaport near the head of Taiya Inlet fiord in the northern part of southeastern Alaska. Rugged mountains, steep-walled valleys, fiords, and numerous glaciers and icefields characterize the landscape of the area. Valley floors are Narrow and most carry large streams, which end in tidewater deltas. Skagway is situated on the delta and lower valley floor of the Skagway River. Glaciers became vastly enlarged during the Pleistocene Epoch and presumably covered the area at least several times. The last major deglaciation probably occurred about 10,000 years ago. Subsequently, there was minor expansion and then partial retreat of glaciers; land rebound because of glacial melting is still going on today. Bedrock is composed predominantly of plutonic intrusive rocks, chiefly quartz diorite and granodiorite; some metamorphic rocks and a few dikes are present. Most bedrock is of Jurassic and Cretaceous age. An assortment of surficial deposits of Quaternary age form the valley bottoms and locally part of the valley walls. Thick deposits of sand and gravel have accumulated as deltas at the heads of fiords and as alluvium in the main stream valleys; deposits may be as much as 585 feet thick at Skagway. Locally, thin deposits mantle some of the steep bedrock slopes and also form some moderately to gently sloping ground. Manmade fill covers much of the top of the delta and floor of the Skagway valley. The fill is composed chiefly of gravel and sand. Quarried blocks of granodiorite are used as riprap to face 1 river dikes and on fill areas exposed to waves of Taiya Inlet. The geologic structure of the area is imperfectly known. However, it appears that plutonic rocks intruded metamorphic rocks in Jurassic and Cretaceous time. Extensive faulting is strongly indicated by the strikingly linear or curvilinear pattern of fiords and many large and small valleys, but no major faults have been positively identified because of concealment by water or surficial deposits. Inferred faults include those coincident with the lower Skagway valley, Taiya Inlet-Taiya valley, and the Katzehin River delta-Upper Dewey Lake. Principal fault movements probably occurred in middle Tertiary time but some movement might have been in late Tertiary or possibly early Quaternary time. Local faults appear to join the Chilkat River fault, a segment of the important Denali fault system, one of the major tec- tonic elements of southeastern Alaska. One fault segment of this sys- tem shows evidence of movement within the last several hundred years. Southeastern Alaska's other major fault system is the active Fairweather-Queen Charlotte Islands fault system near the coast of the Pacific Ocean. This fault system passes to within about 100 miles of Skagway. At its northwest end the fault system merges with the Chugach-St. Elias fault. One hundred twenty-two earthquakes, some of them strong, have been felt or possibly felt at Skagway during the years 1898 through 1969. The closest large earthquake (magnitude about 8) causing some damage at Skagway occurred July 10, 1958. Its epicenter was about 100 miles to the southwest. Other earthquakes, as much as 150 miles away, also have caused slight to moderate damage. The closest instru- mentally recorded earthquake (magnitude 6) had its epicenter about 30 miles to the west of Skagway. Most earthquakes in southeastern Alaska have occurred southwest, west, or northwest of Skagway, near the coast of the Pacific Ocean. They appear to be related to movement along the Fairweather-Queen Charlotte Islands fault system or the Chugach-St. Elias fault. Most have had their epicenters offshore. Some earthquakes may be related to movement at depth along the Denali fault system. The probability of destructive earthquakes at Skagway is unknown because the tectonics of the region have not been studied in detail. However, on the basis of the seismic record and limited tectonic evi- dence, we suggest that sometime in the future an earthquake of at least magnitude 6 probably will occur very close to the city, a magni- tude 7 earthquake might occur in the general area, and an earthquake of magnitude 8 probably will occur at some distance to the southwest, west, or northwest. Effects from nearby large earthquakes could cause extensive damage at Skagway. Nine principal effects are considered. 1. Surface displacement. Displacement of ground caused by fault movement would affect only structures built athwart the fault. How- ever, a sudden tectonic uplift of land of as much as a few feet might affect a wide area and necessitate extensive dredging and wharf rebuilding. On the other hand, a subsidence of several feet would allow tidewater to reach inland and flood part of the harbor facili- ties and the business district. 2. Ground shaking. Because intensity of ground shaking during earthquakes largely depends on type and water content of the geologic material being shaken, the geologic materials are separated into three categories. Those considered susceptible to strongest shaking are grouped into category 1 (containing materials that are saturated, loose, and of medium- to fine-grain sizes); those of intermediate susceptibility in category 2; and those least susceptible to shaking in category 3. 3. Compaction of some medium-grained sediments during strong earthquake shaking could cause local settling of alluvial and deltaic surfaces. Also, some manmade fills near the harbor might undergo marked differential settling. 4. Liquefaction of saturated beds of uniform, fine sand commonly occurs during strong earthquakes. Few such beds, however, are posi- tively identified at Skagway; some may occur within deltaic and allu- vial deposits. If present, these beds might liquefy and cause local settling or trigger landslides. S. Ejection of water-sediment mixtures from earthquake-induced fractures or from point sources, plus some associated ground subsid- ence, is common during major earthquakes where saturated sand and fine gravel deposits are confined beneath generally impermeable beds. Some alluvial and deltaic deposits at Skagway probably are susceptible to these processes. Locally, ejecta might cover roads and areas between buildings and fill low-lying areas. Associated ground fracturing might damage roadways, foundations of buildings, and other facilities. 6. Subaerial and subaqueous slides occur frequently during earthquakes. Saturated loose sediments on steep slopes are especially susceptible to sliding. During a major earthquake, surficial deposits forming such slopes along the southeast side of the Skagway valley probably would be subject to sliding or earthflowing on an extensive scale. Some sliding might extend onto the valley floor and damage or destroy buildings and part of the railroad. Rockfalls would be numer- ous and locally very. large rockslides might occur. Subaqueous sliding of the Skagway delta is potentially the most damaging of earthquake effects. Sliding may have occurred there dur- ing the earthquake of September 16, 1899; any future major earthquake close to the city would cause extensive sliding, possibly triggered 3 in part by liquefaction. If shaking continued for several minutes successive slides might progressively remove large portions of the’ delta and allow extensive land spreading and fracturing of Skagway River alluvium as much as several thousand feet landward from the shoreline. 7. Glacier surfaces commonly receive extensive snow avalanches and rockslides during seismic shaking. In the Skagway area, glaciers may be disrupted at their margins, and resulting blocked streams might form lakes in a few places. If these lakes drained suddenly, down- stream areas would be flooded. No long-term effects, such as glacier expansion, are expected. 8. Ground- and surface-water levels often are affected during and after strong earthquake shaking. At Skagway, ground-water levels prob- ably would be lowered, but there would be no permanent change in water quality. Earthquake-triggered landslides could dam the Skagway River; the sudden failure of the dams might cause severe flooding. 9. Waves generated by earthquakes include tsunamis, seiche waves, and waves caused by subaerial and submarine sliding and tectonic dis- placement of land. Damage in the Skagway area would depend on wave height, tidal stage, and warning time. Some waves triggered by subaer- ial and subaqueous slides have a strong possibility of reaching heights of as much as 60 feet--or possibly even higher. Tstmamis from the open ocean must travel 160 miles of fiords before reaching Skagway, which allows sufficient time for appraisal of expectable wave height and, if necessary, evacuation of the harbor area and other low-lying ground. Geologic hazards other than those hazards associated with earth- quakes include nonearthquake-induced subaerial and subaqueous slides, floods, and slow uplift (rebound) of land. Landslides of moderate size are known to have occurred from time to time during heavy rains such as those of September 1967. Subaqueous slides happen intermit- tently during the normal growth of deltas. Submarine cables on the floor of northern Taiya Inlet presumably were broken by such slides on September 10, 1927. Flooding by the Skagway River has inundated parts of the city many times, usually during heavy rains in the fall. Two floods were reported to have been caused by the sudden draining of glacier-dammed lakes. Dikes protect the city from many smaller floods, but heightening and broadening is needed to give full protection. Slow land uplift at Skagway, because of regional glacioisostatic rebound, averages 0.059 foot per year. On this basis, the shoreline theoretically shifted seaward 500 feet and the harbor shoaled 4.4 feet between 1897 and 1972. It is recommended that future geologic study of the Skagway area include: detailed geologic mapping and collection of data on geologic materials, joints, faults, and slope stability; complete evaluation of earthquake probability and response of materials to shaking; and col- lection and evaluation of periodic soundings and sediment data from Skagway and Taiya deltas to assist in forecasting the stability of the delta front. MM Exhibit c MM ECONOMIC ANALYSIS 5 Percent Interest Rate TABLE Ci ESTIMATED PROJECTS NEAR HAINES AND SKAGWAY»s ALASKA (DOLLAR AMOUNTS IN THOUSANDS) CHILKOOT LAKE DESCRIPTION DIVERSION 1. PROJECT COST (PC)»1979 DOLLARS 35708.0 2+ YEAR CONSTRUCTION BEGINS 1984 3. PROJECT COST @ PRICE LEVELS OF YEAR CONSTRUCTION BEGINS 43444.2 4. CONSTRUCTION PERIOD (YEARS) 3 5S. AVG. PROJECT COST PER YEAR @ PRICE LEVELS OF BEGINNING CONSTRUCTION YR. 14481.4 6. PROJECT COST PER YEAR @ CURRENT YEAR PRICE LEVELS (X) YEAR 1 14481.4 YEAR 2 15060.7 YEAR 3 15663.1 YEAR 4 0.0 YEAR 5 0.0 YEAR 6 0.0 TOTAL 45205.2 7. INTEREST DURING CONSTRUCTION (N=LAST CONSTRUCTION YEAR# X=PC IN CONST YR @ CURRENT PRICE LEVELS YEAR N ¢ X TIMES .000 0.0 YEAR N-1: X TIMES .050 753.0 YEAR N-23 X TIMES .102 1484.3 YEAR N-3i X TIMES .158 0.0 YEAR N-4% X TIMES .216 0.0 YEAR N-Si X TIMES .276 0.0 TOTAL IDC 2237.4 8. TOTAL INVESTMENT! PROJECT COSTS PLUS IDC 47442.6 9. ANNUAL AMORTIZATION COST (35 YEARS) 2897.4 10. ANNUAL OPERATION AND MAINTENANCE (O&M) COST» 1979 DOLLARS 160.0 11. ANNUAL REPLACEMENT COST» 1979 DOLLARS 7361 12. TOTAL ANNUAL O&M AND REPLACEMENT COSTS 233.1 13. YEAR OPERATION BEGINS 1987 14. ANNUAL COST IN FIRST YEAR OF OPERATION AMORTIZATION 2897.4 O&M AND REPLACEMENTS 319.0 TOTAL 3216.4 CHILKOOT LAKE DAM 35378.0 1984 43042.7 3 14347.6 14347.6 14921.5 15518.3 0.0 0.0 0.0 44787.4 0.0 74661 1470.6 0.0 0.0 0.0 2216.7 47004.1 2870.6 160.0 77.4 237.4 1987 2870.6 324.9 UPFER CHILKOOT LAKE 26313.0 1983 30782.5 3 10260.8 10260.8 10671.3 11098.1 0.0 0.0 0.0 32030.2 0.0 533.6 1051.7 0.0 0.0 0.0 1585.3 33615.5 2053.0 240.0 112.5 352.5 1986 2053.0 463.9 INVESTMENT AND ANNUAL COST FOR ALTERNATIVE HYDROELECTRIC DAYEBAS CREEK 10164.9 3 3388.3 3388.3 3523.8 3664.8 0.0 0.0 0.0 10576.9 0.0 176.2 347.3 0.0 0.0 0.0 523.5 11100.4 677.9 80.0 18.0 98.0 1986 677.9 129.0 SEO IO IO IK X*XASSUMPT IONS %* GENERAL INFLATION 4% x * FUEL INFLATION INTEREST RATE 62% Sx* SOOO OI IOK WEST CREEK 66538.0 1984 80953.7 4 20238.4 20238.4 21047.9 21889.9 22765.5 0.0 0.0 85941.7 0.0 1094.5 2157.4 3190.1 0.0 0.0 6442.0 92383.7 5642.0 272.0 121.5 393.5 1988 5642.0 560.1 SKAGWAY RIVER 29569.0 1984 3597542 3 11991.7 11991.7 12471.4 12970.3 0.0 0.0 0.0 3743364 0.0 623.6 1229.2 0.0 0.0 0.0 1852.7 39286.1 2399.3 192.0 225.0 417.0 1987 2399.3 570.7 GOAT LAKE 23634.0 1983 27648.4 3 921661 9216.61 9584.8 9968.2 0.0 0.0 0.0 2876961 0.0 479.62 944.7 0.0 0.0 0.0 1423.9 30193.0 1843.9 224.0 112.5 336.5 1986 1843.9 442.8 TABLE C2 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT ANI! COST PER KWH FOR CHILKOOT LAKE DIVERSION HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 5% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cosT OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 0.0 0.0 0.000 0.0 0.0 0.000 1987. 3216.4 9520.0 0.338 1087.9 9520.0 0.114 1988. 3229.2 9880.0 0.327 1192.7 9880.0 0.121 1989. 3242.4 10240.0 0.317 1305.8 10240.0 0.128 1990. 3256.2 10600.0 0.307 1428.0 10600.0 0.135 1991. 3270-6 11080.0 0.295 1577.0 11080.0 0.142 1992. 3285.5 11560.0 0.284 1738.3 11560.0 0.150 1993. 3301.1 12040.0 0.274 1912.9 12040.0 0.159 1994. 3317.2 12520.0 0.265 2101.9 12520.0 0.168 1995. 3334.0 13000,.0 0.256 2306.2 13000.0 0.177 1996. 3351.5 13480.0 0.249 2527.1 13480.0 0.187 1997. 3369.6 13960.0 0.241 2765.7 13960.0 0.198 1998. 3388.5 14440.0 0.235 3023.5 14440.0 0.209 1999. 3408.1 14920.0 0.228 3301.7 14920.0 0.221 2000. 3428.6 15400.0 0.223 3602.1 15400.0 0.234 2001. 3449.8 16027.5 0.215 3962.5 16027.5 0.247 2002. 3471.9 16655.0 0.208 4352.6 16655.0 0.261 2003. 3494.9 17282.5 0.202 4774.5 17282.5 0.276 2004. 3518.8 17910.0 0.196 5230.6 17910.0 0.292 2005. 3543.7 18537.5 0.191 5723.4 18537.5 0.309 2006, 3569.5 19165.0 0.186 6255.9 19165.0 0.326 2007. 3596.4 19165.0 0.188 6614.2 19165.0 0.345 2008. 3624.4 19165.0 0.189 6993.4 19165.0 0.365 2009. 3653.4 19165.0 0.191 7394.6 19165.0 0.386 2010, 3683.7 19165.0 0.192 7819.1 19165.0 0.408 2011. 3715.1 19165.0 0.194 8268.4 19165.0 0.431 2012. 3747.8 19165.0 0.196 8743.8 19165.0 0.456 2013. 3781.9 19165.0 0.197 9246.9 19165.0 0.482 2014. 3817.2 19165.0 0.199 9779.4 19165.0 0.510 2015. 3854.0 19165.0 0.201 10342.9 19165.0 0.540 2016. 3892.3 19165.0 0.203 10939.2 19165.0 0.571 2017. 3932.1 19165.0 0.205 11570.4 19165.0 0.604 2018. 3973.5 19165.0 0.207 12238.5 19165.0 0.639 2019. 4016.5 19165.0 0.210 12945.6 19165.0 0.675 2020. 4061.3 19165.0 0.212 13694.0 19165.0 0.715 2021. 4107.8 19165.0 0.214 14486.2 19165.0 0.756 2022. 1258.9 19165.0 0.066 15324.7 19165.0 0.800 2023. 1309.2 19165.0 0.068 16212.4 19165.0 0.846 2024, 1361.6 19165.0 0.071 17152.0 19165.0 0.895 2025. 1416.0 19165.0 0.074 18146.7 19165.0 0.947 2026. 1472.7 19165.0 0.077 19199.6 19165.0 1,002 2027. 1531.6 19165.0 0.080 20314.4 19165.0 1.060 2028. 1592.9 19165.0 0.083 21494.5 19165.0 1.122 2029. 1656.6 19165.0 0.086 22743.8 19165.0 1.187 2030. 1722.8 19165.0 0.090 24066.6 19165.0 1.256 2031. 1791.7 19165.0 0.093 25467.0 19165.0 1.329 2032. 1863.4 19165.0 0.097 2694947 19165.0 1.406 2033. 1938.0 19165.0 0.101 28519.5 19165.0 1.488 2034. 2015.5 19165.0 .0.105 30181.7 19165.0 1.575 2035. 2096.1 19165.0 0.109 31941.6 19165.0 1.667 2036. 2179.9 19165.0 0.114 33805.0 19165.0 1.764 PRESENT VAL " INITIAL YEAR OF OPERATION = --------— 0 59573.7 111771.9 TABLE C3 PROJECTED ANNUAL COSTS, MARKETABLE OUTPUT AND COST PER KWH FOR CHILKOOT LAKE DAM HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT SX INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986, 0.0 0.0 0.000 0.0 0.0 0.000 1987. 3195.5 11468.8 0.279 1310.7 11468.8 0.114 1988, 3208.5 11979.2 0.268 1446.1 11979.2 0.121 1989. 3222.0 12489.6 0.258 1592.7 12489.6 0.128 1990. 3236.1 13000.0 0.249 1751.3 13000.0 0.135 1991. 3250.7 13580.0 0.239 1932.8 13580.0 0.142 1992. 3265.9 14160.0 0.231 2129.3 +14160.0 0.150 1993. 3281.7 14740.0 0.223 2341.9 14740.0 0.159 1994, 3298.2 15320.0 0.215 2572.0 15320.0 0.168 1995. 3315.3 15900.0 0.209 2820.7 15900.0 0.177 1996. 3333.1 16480.0 0.202 3089.5 16480.0 0.187 1997. 3351.6 17060.0 0.196 3379.9 17060.0 0.198 1998. 3370.8 17640.0 0.191 3693.5 17640.0 0.209 1999. 3390.8 18220.0 0.186 4032.0 18220.0 0.221 2000. 3411.6 18800.0 0.181 4397.3 18800.0 0.234 2001. 3433.2 19412.7 0.177 4799.65 19412.7 0.247 2002. 3455.7 20025.3 0.173 5233.4 20025.3 0.261 2003. 3479.2 20638.0 0.169 5701.5 20638.0 0.276 2004. 3503.5 21250.7 0.165 6206.2 21250.7 0-292 2005. 3528.8 21863.3 0.161 6750.3 21863.3 0.309 2006. 3555.1 22476.0 0.158 733666 22476.0 0.326 2007. 3582.5 22476.0 0.159 775669 22476.0 0.345 2008. 3611.0 22476.0 0.161 8201.6 22476.0 0.365 2009. 3640.6 22476.0 0.162 8672.1 22476.0 0.386 2010. 3671.4 22476.0 0.163 9170.0 22476.0 0.408 2011. 3703.4 22476.0 0.165 9696.9 22476.0 0.431 2012. 3736.7 22476.0 0.166 10254.4 22476.0 0.456 2013. 3771.4 22476.0 0.168 10844.5 22476.0 0.482 2014. 3807.4 22476.0 0.169 11468.9 22476.0 0.510 2015. 3844.9 22476.0 0.171 12129.7 22476.0 0.540 2016. 3883.9 22476.0 0.173 12829.1 22476.0 0.571 2017. 3924.4 22476.0 0.175 13569.4 22476.0 0.604 2018, 3966.5 22476.0 0.176 14352.8 22476.0 0.639 2019, 4010.4 22476.0 0.178 15182.1 22476.0 0.675 2020. 4056.0 22476.0 0.180 16059.8 22476.0 0.715 2021. 4103.4 22476.0 0.183 16988.8 22476.0 0.756 2022. 1282.1 22476.0 0.057 17972.3 22476.0 0.800 2023. 1333.4 22476.0 0.059 19013.3 22476.0 0.846 2024, 1386.7 22476.0 0.062 20115.2 22476.0 0.895 2025. 1442.2 22476.0 0.064 21281.7 22476.0 0.947 2026. 1499.8 22476.0 0.067 22516.6 22476.0 1,002 2027. 1559.8 22476.0 0.069 23823.9 22476.0 1.060 2028. 1622.2 22476.0 0.072 25207.9 22476.0 1.122 2029. 1687.1 22476.0 0.075 26673.1 22476.0 1.187 2030. 1754.6 22476.0 0.078 28224.4 22476.0 1.256 2031. 1824.8 22476.0 0.081 29866.7 22476.0 1.329 2032. 1897.8 22476.0 0.084 31605.6 22476.0 1.406 2033. 1973.7 22476.0 0.088 33446.6 22476.0 1.488 2034. 2052.6 22476.0 0.091 35395.9 22476.0 1.575 2035. 2134.8 22476.0 0.095 37459 .9 22476.0 1.667 2036. 2220.1 22476.0 0.099 39645.3 22476.0 1.764 PRESENT VAL INITIAL YEAR OF OPERATION 132257.2 TABLE C4 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR UPFER CHILKOOT LAKE HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT S% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTFUT COST FER cosT OUTFUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 2516.8 11359.2 0.222 1229.0 11359.2 0.108 1987. 2535.4 11936.4 0.212 1364.1 11936.4 0.114 1988. 2554.7 12513.6 0.204 1510.6 12513.6 0.121 1989, 2574.7 13090.8 0.197 1669.3 13090.8 0.128 1990. 2595.6 13668.0 0.190 1841.3 13668.0 0.135 1991. 2617.3 14561.2 : 0.180 2072.4 14561.2 0.142 1992. 2639.9 15454.4 0.171 2323.9 15454.4 0.150 1993. 2663.4 16347.6 0.163 2597.4 16347.6 0.159 1994, 2687.8 17240.8 0.156 2894.4 17240.8 0.168 1995, 2713.2 18134.0 0.150 3217.0 18134.0 0.177 1996. 2739.6 19027.2 0.144 3567.0 19027.2 0.187 1997. 2767.1 19920.4 0.139 3946.6 19920.4 0.198 1998. 279566 20813.6 0.134 4358.0 20813.6 0.209 1999, 2825.3 21706.8 0.130 4803.6 21706.8 0.221 2000. 2856.2 22600.0 0.126 5286.1 22600.0 0.234 2001. 2888.4 23580.0 0.122 5829.8 23580.0 0.247 2002. 2921.8 24560.0 0.119 6418.5 24560.0 0.261 2003. 2956.5 25540.0 0.116 7055.7 25540.0 0+276 2004. 2992.7 26520.0 0.113 774561 26520.0 0.292 2005. 3030.3 27500.0 0.110 8490.6 27500.0 0.309 2006. 3069.3 28480.0 0.108 929665 28480.0 0.326 2007. 3110.0 29460.0 0.106 10167.2 29460.0 0.345 2008. 3152.3 30440.0 0.104 11107.7 30440.0 0.365 2009, 3196.3 31420.0 0.102 12123.0 31420.0 0.386 2010. 3242.0 32400.0 0.100 13218.9 32400.0 0.408 2011. 3289.5 33810.0 0.097 14586.7 33810.0 0.431 2012. 3339.0 35220.0 0.095 16068.7 35220.0 0.456 2013. 3390.5 36630.0 0.093 17673.6 36630.0 0.482 2014. 3444.0 38040.0 0.091 19410.8 38040.0 0.510 2015. 3499.66 39450.0 0.089 21290.2 39450.0 0.540 2016. 3557.5 40860.0 0.087 23322.6 40860,.0 0.571 2017. 3617.6 42270.0 0.086 25519.5 42270.0 0.604 2018. 3680.2 43680.0 0.084 27893.4 43680.0 0.639 2019, 3745.3 45090.0 0.083 30457.4 45090.0 0.675 2020. 3813.0 46500.0 0.082 33225.7 46500.0 0.715 2021. 1830.5 4796940 0.038 36258.1 4796940 0.756 2022, 1903.7 49438.0 0.039 3953146 49438.0 0.800 2023. 1979.8 50907.0 0.039 4306461 50907.0 0.846 2024, 2059.0 52376.0 0.039 46874.6 52376.0 0.895 2025. 2141.4 53845.0 0.040 50983.9 53845.0 0.947 2026. 2227.0 55314.0 0.040 55414.0 55314.0 1.002 2027. 2316.1 56783.0 0.041 60188.4 56783.0 1.060 2028. 2408.8 58252.0 0.041 65332.4 58252.0 1.122 2029, 2505.1 59721.0 0.042 70873.2 59721.0 1.187 2030. 2605.3 61190.0 0.043 7683947 61190.0 1.256 2031. 2709.5 61190.0 0.044 81310.9 61190.0 1.329 2032. 2817.9 61190.0 0.046 86044.9 61190.0 1.406 2033. 2930.6 61190.0 0.048 91057.1 61190.0 1.488 2034, 3047.8 61190.0 0.050 96364.0 61190.0 1.575 2035. 3169.8 61190.0 0.052 101983.0 61190.0 1.667 PRESENT VAL INITIAL YEAR OF OPERATION = -------- 0 51255.0 227712.1 TABLE CS PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR DAYEBAS CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT SX INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cosT OUTPUT COST FER cost OUTPUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 833.0 8625.0 0.097 883.5 8625.0 0.102 1986. 844.4 8980.0 0.094 971.6 8980.0 0.108 1987. 856.3 9335.0 0.092 1066.8 9335.0 0.114 1988. 868.7 9690.0 0.090 1169.7 9690.0 0.121 1989. 881.6 10045.0 0.088 1280.9 10045.0 0.128 1990. 895.0 10400.0 0.086 1401.1 10400.0 0.135 1991. 908.9 10892.5 0.083 1550.3 10892.5 0.142 1992. 923.3 11385.0 0.081 1712.0 11385.0 0.150 1993. 938.4 11877.5 0.079 1887.1 11877.5 0.159 1994, 954.0 12370.0 0.077 2076.7 12370.0 0.168 1995. 970.3 12862.5 0.075 2281.8 12862.5 0.177 1996. 987.3 13355.0 0.074 2503.7 13355.0 0.187 1997. 1004.9 13847.5 0.073 2743.4 13847.5 0.198 1998. 1023.2 14340.0 0.071 3002.5 14340.0 0.209 1999. 1042.2 14832.5 0.070 3282.4 14832.5 0.221 2000. 1062.0 15325.0 0.069 3584.5 15325.0 0.234 2001. 1082.6 15802.5 0.069 3906.9 15802.5 0.247 2002. 1104.1 16280.0 0.068 4254.6 16280.0 0.261 2003. 1126.3 16757.5 0.067 4629.4 16757.5 0.276 2004. 1149.5 17235.0 0.067 5033.4 17235.0 0.292 2005. 1173.6 17712.5 0.066 5468.7 17712.5 0.309 2006. 1198.7 18190.0 0.066 5937.6 18190.0 0.326 2007. 1224.7 18190.0 0.067 6277.7 18190.0 0.345 2008. 1251.9 18190.0 0.069 6637.6 18190.0 0.365 2009. 1280.0 18190.0 0.070 7018.4 18190.0 0.386 2010. 1309.4 18190.0 0.072 7421.4 18190.0 0.408 2011. 1339.9 18190.0 0.074 7847.8 18190.0 0.431 2012. 1371.6 18190.0 0.075 8299.0 18190.0 0.456 2013. 1404.6 18190.0 0.077 8776.5 18190.0 0.482 2014. 1438.9 18190.0 0.079 9281.9 18190.0 0.510 2015. 1474.5 18190.0 0.081 9816.7 18190.0 0.540 2016. 1511.6 18190.0 0.083 10382.7 18190.0 0.571 2017. 1550.2 18190.0 0.085 10981.8 18190,.0 0.604 2018. 1590.3 18190.0 0.087 11615.9 18190.0 0.639 2019. 1632.1 18190.0 0.090 12287.0 18190.0 0.675 2020. 1128.4 18190.0 0.062 12997.3 18190.0 0.715 2021. 1173.6 18190.0 0.065 13749.2 18190.0 0.756 2022. 1220.5 18190.0 0.067 14545.1 18190.0 0.800 2023. 1269.3 18190.0 0.070 15387.6 18190.0 0.846 2024, 1320.1 18190.0 0.073 16279.4 18190.0 0.895 2025. 1372.9 18190.0 0.075 17223.5 18190.0 0.947 2026. 1427.8 18190.0 0.078 18222.9 18190.0 1.002 2027. 1484.9 18190.0 0.082 19280.9 18190.0 1.060 2028. 1544.3 18190.0 0.085 20401.0 18190.0 1.122 2029. 1606.1 18190.0 0.088 21586.8 18190.0 1.187 2030. 1670.4 18190.0 0.092 22842.2 18190.0 1.256 2031. 1737.2 18190.0 0.096 24171.4 18190.0 1.329 2032. 1806.7 18190.0 0.099 25578.6 18190.0 1.406 2033. 1878.9 18190.0 0.103 27068.6 18190.0 1.488 2034, 1954.1 18190.0 0.107 28646.2 18190.0 1.575 PRESENT VAL INITIAL YEAR OF OPERATION = ----mee 19831.6 93776.4 TABLE Cé PROJECTED ANNUAL COSTS, MARKETABLE OUTPUT AND COST PER KWH FOR UPPER DEWEY LAKE HYDROELECTRIC FROJECT ANI! ITS LIIESEL ALTERNATIVE AT 5% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 806.9 1647.9 0.490 178.3 1647.9 0.108 1987. 812.0 1767.1 0.460 201.9 1767.1 0.114 1988. 817.4 1886.4 0.433 227.7 1886.4 0.121 1989. 823.0 2005.7 0.410 255.8 2005.7 0.128 1990. 828.8 2125.0 0.390 286.3 2125.0 0.135 1991. 834.8 2310.0 0.361 328.8 2310.0 0.142 1992. 841.1 2495.0 0.337 375.2 2495.0 0.150 1993. 847.6 2680.0 0.316 425.8 2680.0 0.159 1994, 854.4 2865.0 0.298 481.0 2865.0 0.168 1995. 861.5 3050.0 0.282 541.1 3050.0 0.177 1996. 868.8 3235.0 0.269 606.5 3235.0 0.187 Las 876.5 3420.0 0.256 677.46 3420.0 0.198 1998. 884.4 3605.0 0.245 ' 754.8 3605.0 0.209 1999, 892.7 3790.0 0.236 838.7 3790.0 0.221 2000. 901.2 3975.0 0.227 929.8 3975.0 0.234 2001. 910.2 4252.5 0.214 1051.4 4252.5 0.247 2002. 919.5 4530.0 0.203 1183.9 4530.0 0.261 2003. 929.1 4807.5 0.193 1328.1 4807.5 0.276 2004. 939.2 5085.0 0.185 1485.1 5085.0 0.292 2005. 949.6 5362.5 0.177 1655.7 5362.5 0.309 2006. 960.5 5640.0 0.170 1841.0 5640.0 0.326 2007. 971.8 5917.5 0.164 2042.2 5917.5 0.345 2008. 983.5 6195.0 0.159 2260.6 6195.0 0.365 2009, 995.8 6472.5 0.154 2497.3 6472.5 0.386 2010. 1008.5 6750.0 0.149 2753.9 6750.0 0.408 2011. 1021.7 7210.0 0.142 3110.6 7210.0 0.431 2012. 1035.5 7670.0 0.135 3499.44 7670.0 0.456 2013. 1049.8 8130.0 0.129 3922.6 8130.0 0.482 2014. 1064.6 8590.0 0.124 4383.2 8590.0 0.510 2015. 1080.1 9050.0 0.119 4884.1 9050.0 0.540 2016. 1096.2 9510.0 0.115 5428.2 9510.0 0.571 2017. 1112.9 9970.0 0.112 6019.2 9970.0 0.604 2018. 1130.3 10430.0 0.108 6660.4 10430.0 0.639 2019. 1148.4 10890.0 0.105 7356.0 10890.0 0.675 2020. 1167.2 11350.0 0.103 8109.9 11350.0 0.715 2021. 508.9 11980.0 0.042 9055.3 11980.0 0.756 2022. 529.2 12610.0 0.042 10083.2 12610.0 0.800 2023. 550.4 13240.0 0.042 11200.2 13240.0 0.846 2024. 572.4 13870.0 0.041 12413.1 13870.0 0.895 2025. 595.3 14500,.0 0.041 13729.5 14500.0 0.947 2026. 619.1 15130.0 0.041 15157.3 15130.0 1.002 2027. 643.9 15760.0 0.041 16705.2 15760.0 1.060 2028. 669.7 16390.0 0.041 18382.2 16390.0 1.122 2029. 69665 17020.0 0.041 20198.3 17020.0 1.187 2030. 724.3 17650,.0 0.041 22164.1 17650.0 1.256 2031. 753.3 18140,0 0.042 24104.9 18140.0 1.329 2032. 783.4 18630.0 0.042 26197.4 18630.0 1.406 2033. 814.8 19120.0 0.043 28452.5 19120.0 1.488 2034. 847.3 19610.0 0.043 30882.5 19610.0 1.575 2035. 881.2 20100.0 0.044 3349969 20100.0 1.667 PRESENT VAL INITIAL YEAR OF OPERATION. ===-= = eee 16004.4 56289.8 TABLE C7 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR REID FALLS CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT S% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost OUTPUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 424.8 1353.6 0.314 138.7 1353.6 0.102 1986, 429.8 1472.9 0.292 159.4 1472.9 0.108 1987. 435.0 1592.1 0.273 182.0 1592.1 0.114 1988. 440.4 1711.4 0.257 206.6 1711.4 0.121 1989. 446.0 1830.7 0.244 233.5 1830.7 0.128 1990. 451.9 1950.0 0.232 262.7 1950.0 0.135 1991. 458.0 2125.0 0.216 302.4 2125.0 0.142 1992. 464.3 2300.0 0.202 345.9 2300.0 0.150 1993. 470.9 2475.0 0.190 393.2 2475.0 0.159 1994, 477.7 2650.0 0.180 444.9 2650.0 0.168 1995. 484.8 2825.0 0.172 501.2 2825.0 0.177 1996. 492.3 3000.0 0.164 562.4 3000.0 0.187 1997. 500.0 3175.0 0.157 629.0 3175.0 0.198 1998, 508.0 3350.0 0.152 701.4 3350.0 0.209 1999, 516.3 3525.0 0.146 780.1 3525.0 0.221 2000. 525.0 3700.0 0.142 865.4 3700.0 0.234 2001. 534.0 3935.0 0.136 972.9 3935.0 0.247 2002. 543.4 4170.0 0.130 1089.8 4170.0 0.261 2003. 553.1 4405.0 0.126 1216.9 4405.0 0.276 2004. 563.3 4640.0 0.121 1355.1 4640.0 0.292 2005. 573.8 4875.0 0.118 1505.2 4875.0 0.309 2006. 584.8 5110.0 0.114 1668.0 5110.0 0.326 2007, 596.2 5345.0 0.112 1844.7 5345.0 0.345 2008. 608.0 5580.0 0.109 2036.2 5580.0 0.365 2009. 620.4 5815.0 0.107 2243.7 5815.0 0.386 2010. 633.2 6050.0 0.105 2468.3 6050.0 0.408 2011. 646.6 6385.0 0.101 2754.7 6385.0 0.431 2012. 660.4 6720.0 0.098 3065.9 6720.0 0.456 2013. 674.9 7055.0 0.096 3404.0 7055.0 0.482 2014. 689.9 7390.0 0.093 3770.9 7390.0 0.510 2015. 705.5 7725.0 0.091 4169.0 7725.0 0.540 2016. 721.7 8060.0 0.090 4600.6 8060.0 0.571 2017. 738.6 8395.0 0.088 5068.3 8395.0 0.604 2018. 75662 8730.0 0.087 5574.8 8730.0 0.639 2019, 774.4 9065.0 0.085 6123.2 9065.0 0.675 2020. 493.8 9400.0 0.053 6716.6 9400.0 0.715 2021. 513.6 9593.5 0.054 7251.4 959365 0.756 2022. 534.1 9787.0 0.055 7825.9 9787.0 0.800 2023. 555.5 9980.5 0.056 8442.9 9980.5 0.846 2024, 577.7 10174.0 0.057 9105.4 10174.0 0.895 2025. 600.8 10367.5 0.058 9816.6 10367.5 0.947 2026. 624.8 10561.0 0.059 10580.1 10561.0 1.002 2027. 649.8 10754.5 0.060 11399.5 10754.5 1.060 2028. 675.8 10948.0 0.062 12278.7 10948.0 1.122 2029. 702.9 11141.5 0.063 13222.0 11141.5 1.187 2030. 731.0 11335.0 0.064 14234,.0 11335.0 1.256 2031. 760.2 11335.0 0.067 15062.3 11335.0 1.329 2032. 79066 11335.0 0.070 15939.2 11335.0 1.406 2033. 822.2 11335.0 0.073 16867.7 11335.0 1.488 2034, 855.1 11335.0 0.075 17850.7 11335.0 1.575 PRESENT VAL INITIAL YEAR OF OPERATION -------- asererencrcrecey 9664.6 38670.1 TABLE C8 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR WEST CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT S% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost _ OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986, 0.0 0.0 0.000 0.0 0.0 0.000 1987, 0.0 0.0 0.000 0.0 0.0 0.000 1988. 6202.1 2432.3 2.550 293.6 2432.3 0.121 1989, 6224.5 2614.1 2.381 333.4 2614.1 0.128 1990, 6247.8 2796.0 2.235 376.7 2796.0 0.135 1991. 6272.0 3074.4 2.040 437.6 3074.4 0.142 1992, 6297.2 3352.8 1.878 504.2 3352.8 0.150 1993, 6323.4 3631.2 1.741 576.9 3631.2 0.159 1994, 635047 3909.66 1.624- 656.4 3909.6 0.168 1995. 6379.0 4188.0 1.523 743.0 4188.0 0.177 1996, 6408.5 4466.4 1.435 837.3 4466.4 0.187 1997. 6439.2 4744.8 1.357 940.0 4744.8 0.198 1998. 6471.1 5023.2 1.288 1051.8 5023.2 0.209 1999, 6504.2 5301.6 1.227 1173.2 5301.6 0.221 2000. 6538.7 5580.0 1.172 1305.2 5580.0 0.234 2001. 6574.6 6039.46 1.089 1493.2 6039.6 0.247 2002. 6611.9 6499.62 1.017 1698.5 6499.2 0.261 2003. 6650.7 6958.8 0.956 1922.4 6958.8 0.276 2004. 6691.0 7418.4 0.902 2166.5 7418.4 0.292 2005. 6733.0 7878.0 0.855 2432.3 7878.0 0.309 2006. 6776466 8337.6 0.813 2721.6 8337.6 0.326 2007. 6822.0 8797.2 0.775 3036.1 8797.2 0.345 2008. 6869.2 9256.8 0.742 3377.8 9256.8 0.365 2009. 6918.3 9716.4 0.712 3749.0 9716.4 0.386 2010. 696964 10176.0 0.685 4151.7 10176.0 0.408 2011. 7022.5 10933.2 0.642 4716.9 10933.2 0.431 2012. 7077.7 11690.4 0.605 5333.6 11690.4 0.456 2013. 7135.1 12447.6 0.573 6005.8 12447.6 0.482 2014. 7194.8 13204.8 0.545 6738.0 13204.8 0.510 2015. 7256.9 13962.0 0.520 753469 13962.0 0.540 2016. 7321.5 14719.2 0.497 8401.6 14719.2 0.571 2017. 7388.7 15476.4 0.477 9343.5 15476.4 0.604 2018. 7458.6 16233.6 0.459 10366.5 16233.6 0.639 2019. 7531.2 16990.8 0.443 11476.9 16990.8 0.675 2020. 7606.8 17748.0 0.429 12681.5 17748.0 0.715 2021. 7685.4 18998.4 0.405 14360.2 18998.4 0.756 2022. 776761 20248.8 0.384 16191.4 20248.8 0.800 2023. 2210.1 21499.2 0.103 18186.9 21499.2 0.846 2024, 2298.5 22749.6 0.101 20360.1 22749.6 0.895 2025. 2390.4 24000.0 0.100 22724.7 24000.0 0.947 2026. 2486.1 25250.4 0.098 25296.0 25250.4 1.002 2027. 2585.5 26500.8 0.098 28090.1 26500.8 1.060 2028. 2688.9 27751.2 0.097 31124.3 27751.2 1.122 2029. 2796.65 29001.6 0.096 34417.3 2900146 1.187 2030. 2908.3 30252.0 0.096 379891 30252.0 14256 2031. 3024.7 32312.4 0.094 4293746 32312.4 1.329 2032. 3145.7 34372.8 0.092 48334.8 34372.8 1.496 2033. 3271.5 36433.2 0.090 54216.4 36433.2 1.488 2034, 3402.3 38493.6 0.088 60620.9 38493.6 1.575 2035. 3538.4 40554.0 0.087 67589.8 40554.0 1.667 2036. 3680.0 42614.4 0.086 75167.3 42614.4 1.764 2037. 3827.2 44674.8 0.086 83401.2 44674.8 1.867 PRESENT VAL INITIAL YEAR OF OPERATION = -=------= nnn 113681.6 116200.8 TABLE C9 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR SKAGWAY RIVER HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT S% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 0.0 0.0 0.000 0.0 0.0 0.000 1987. 2970.0 1242.1 2-391 142.0 1242.1 0.114 1988. 2992.8 1361.4 2.198 164.3 1361.4 0.121 1989, 3016.5 1480.7 2.037 188.8 1480.7 0.128 1990. 3041.2 1600.0 1.901 215.5 1600.0 0.135 1991. 3066.9 1765.0 1.738 251.2 1765.0 0.142 1992, 3093.6 1930.0 1.603 290.2 1930.0 0.150 1993. 3121.4 2095.0 1.490 332.9 2095.0 0.159 1994, 3150.3 2260.0 1.394 379.4 2260.0 0.168 1995. 3180.3 2425.0 1.311 430.2 2425.0 0.177 1996, 3211.5 2590.0 1.240 485.5 2590.0 0.187 1997. 3244.0 2755.0 1.178 545.8 2755.0 0.198 1998, 3277.8 2920.0 1.123 611.4 2920.0 0.209 1999, 3313.0 3085.0 1.074 682.7 3085.0 0.221 2000. 3349.5 3250.0 1.031 760.2 3250.0 0.234 2001. 3387.5 3490.0 0.971 862.8 3490.0 0.247 2002. 3427.1 3730.0 0.919 974.8 3730.0 0.261 2003. 3468.2 3970.0 0.874 1096.8 3970.0 0.276 2004. 3510.9 4210.0 0.834 1229.5 4210.0 0.292 2005. 3555.4 4450.0 0.799 1373.9 4450.0 0.309 2006. 3601.6 4690.0 0.768 1530.9 4690.0 0.326 2007. 3649.7 4930.0 0.740 1701.4 4930.0 0.345 2008. 3699.67 5170.0 0.716 1886.6 5170.0 0.365 2009. 3751.8 5410.0 0.693 2087.4 5410.0 0.386 2010. 3805.9 5650.0 0.674 2305.1 5650.0 0.408 2011. 3862.1 6030.0 0.640 2601.5 6030.0 0.431 2012. 3920.6 6410.0 0.612 2924.5 6410.0 0.456 2013. 3981.5 6790.0 0.586 3276.1 6790.0 0.482 2014. 4044.8 7170.0 0.564 3658.7 7170.0 0.510 2015. 4110.6 7550.0 0.544 4074.5 7550.0 0.540 2016. 4179.1 7930.0 0.527 4526.4 7930.0 0.571 2017. 4250.3 8310.0 0.511 5017.0 8310.0 0.604 2018. 4324.3 8690.0 0.498 5549.3 8690.0 0.639 2019. 4401.3 9070.0 0.485 6126.6 9070.0 0.675 2020. 4481.4 9450.0 0.474 6752.3 9450.0 0.715 2021. 4564.7 9955.0 0.459 752466 9955.0 0.756 2022. 2252.0 10460.0 0.215 8364.0 10460.0 0.800 2023. 2342.1 10965.0 0.214 9275.7 10965.0 0.846 2024. 2435.8 11470.0 0.212 10265.2 11470.0 0.895 2025. 2533.2 11975.0 0.212 11338.7 11975.0 0.947 2026. 2634.5 12480.0 0.211 12502.6 12480.0 1,002 2027. 2739.9 12985.0 0.211 13763.7 12985.0 1.060 2028. 2849.5 13490.0 0.211 15129.7 13490.0 1.122 2029. 2963.5 13995.0 0.212 16608.4 13995.0 1.187 2030. 3082.0 14500.0 0.213 18208.5 14500.0 1.256 2031. 3205.3 15200.0 0.211 20198.2 15200.0 1.329 2032. 3333.5 15900.0 0.210 22358.5 15900.0 1.406 2033. 3466.9 16600.0 0.209 24702.5 16600.0 1.488 2034. 3605.5 17300.0 0.208 27244.6 17300.0 1.575 2035. 3749.8 18000.0 0.208 29999 9 18000.0 1.667 2036. 3899.7 18700.0 0.209 32984.8 18700.0 1.764 PRESENT VAL INITIAL YEAR OF OPERATION = --------— 0 nnn 60987.9 52092.4 TABLE C1iO PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR GOAT LAKE HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT SX INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 2286.8 2068.6 1.105 223.8 2068.6 0.108 1987. 2304.5 2250.4 1.024 257.2 2250.4 0.114 1988. 2322.9 2432.3 0.955 293.6 2432.3 0.121 1989. 2342.0 2614.1 0.896 333.4 2614.1 0.128 1990, 2362.0 2796.0 0.845 37667 2796.0 0.135 1991. 2382.7 3074.4 0.775 437.6 3074.4 0.142 1992. 2404.2 3352.8 0.717 504.2 3352.8 0.150 1993, 2426.6 3631.2 0.668 576.9 3631.2 0.159 1994, 2450.0 3909.66 0.627 656.4 3909.6 0.168 1995. 2474.2 4188.0 0.591 743.0 4188.0 0.177 1996, 2499.4 4466.4 0.560 837.3 4466.4 0.187 1997, 2525.6 4744.8 0.532 940.0 4744.8 0.198 1998, 2552.9 5023.2 0.508 1051.8 5023.2 0.209 1999, 2581.3 5301.6 0.487 1173.2 5301.6 0.221 2000, 2610.7 5580.0 0.468 1305.2 5580.0 0.234 2001. 2641.4 6039.46 0.437 1493.2 6039.6 0.247 2002. 2673.3 6499.2 0.411 1698.5 6499.2 0.261 2003, 2706.5 6958.8 0.389 1922.4 6958.8 0.276 2004. 2741.0 7418.4 0.369 2166.5 7418.4 0.292 2005. 2776.9 7878.0 0.352 2432.3 7878.0 0.309 2006, 2814.2 8337.6 0.338 2721.6 8337.6 0.326 2007, 2853.0 8797.2 0.324 3036.1 8797.2 0.345 2008. 2893.4 9256.8 0.313 3377.8 9256.8 0.365 2009. 2935.3 971564 0.302 3749.0 9716.4 0.386 2010, 2979.0 10176.0 0.293 4151.7 10176.0 0.408 2011. 3024.4 10933.2 0.277 4716.9 10933.2 0.431 2012. 3071.6 11690.4 0.263 5333.6 11690.4 0.456 2013, 3120.7 12447.6 0.251 6005.8 12447.6 0.482 2014. 3171.8 13204.8 0.240 6738.0 13204.8 0.510 2015. 3224.9 13962.0 0.231 7534.9 13962.0 0.540 2016. 3280.2 14719.2 0.223 8401.6 14719.2 0.571 2017, 3337.6 15476.4 0.216 9343.5 15476.4 0.604 2018, 3397.3 16233.6 0.209 10366.5 16233.6 0.639 2019, 3459.5 16990.8 0.204 11476.9 16990.8 6.675 2020. 3524.1 17748.0 0.199 12681.5 17748.0 0.715 2021. 1747.4 18748.2 0.093 14171.1 18748.2 0.756 2022. 1817.3 19748.4 0.092 15791.2 19748.4 0.800 2023. 1890.0 20748.6 0.091 17552.0 20748.6 0.846 2024. 1965.6 21748.8 0.090 19464.4 21748.8 0.895 2025. 2044.2 22749.0 0.090 21540.2 22749.0 0.947 2026. 2125.9 23749.2 0.090 23792.1 23749.2 1.002 2027. 2211.0 2474944 0.089 26233.7 24749.4 1.060 2028. 2299.4 25749.6 0.089 28879.4 2574946 1.122 2029. 2391.4 26749.8 0.089 31745.0 26749.8 1.187 2030. 2487.1 27750.0 0.090 34847.2 27750.0 1.256 2031. 2586.5 28790.0 0.090 38256.9 28790.0 1.329 2032. 2690.0 29830.0 0.090 41946.7 29830.0 1.406 2033. 279746 30870.0 0.091 45937.8 30870.0 1.488 2034, 2909.5 31910.0 0.091 50252.9 31910.0 1.575 2035. 3025.9 32950.0 0.092 54916.5 32950.0 1.667 PRESENT VAL INITIAL YEAR OF OPERATION = ----99-- 0 ee 47031.8 87133.3 MM exhibit D az 7 Percent Interest Rate TABLE D1 ESTIMATED INVESTMENT AND ANNUAL PROJECTS NEAR HAINES ANT SKAGWAY> “TOLLAR AMOUNTS IN THOUSANTS) ALASKA CHILKOOT LAKE PROJECT COST (FC) +1979 DOLLARS 2. YEAR CONSTRUCTION BEGINS 3. PROJECT COST @ PRICE LEVELS OF YEAR CONSTFUCTION BEGINS 4, CONSTRUCTION FERIOL (YEARS) S. AVG. PROJECT COST PER YEAR @ FRICE LEVELS OF BEGINNING CONSTRUCTION YR. &. PROJECT COST FER YEAR @ CURRENT YEAR PRICE LEVELS (xX) YEAR YEAR YEAR YEAR YEAR YEAR OOD oto TOTAL ?. INTEREST DURING CONSTRUCTION CN=LAST CONSTRUCTION YEARS IN CONST YR Ni PRICE ie) YEAR N 3 X TIMES .000 YEAR N-12 X TIMES .070 YEAR N-2! X TIMES .145 YEAR N-3$ X TIMES .225 YEAR N-4: X TIMES .311 YEAR N-Si X TIMES .403 TOTAL IDC 8. TOTAL INVESTMENT? FROJECT COSTS FEUS LUG 9.4 ANNUAL AMORTIZATION COST (35 YEARS) 10, ANNUAL OPERATION AND MAINTENANCE (O&M) C > 1979 DOLLARS 1. ANNUAL Ff ACEMENT COST: 1979 DOLLARS TOTAL ANNUAL O&M ANDI REPLACEMENT COSTS YEAK OPERATION BEGINS 4, ANNUAL COST IN FIRST YEAR OF OPERATION AMORTIZATION O&M AND REPLACEMENTS TOTAL 14481.4 14481.4 15060.7 15663.1 48357.8 3734.9 160.90 7301 233.1 1987 S734.7 319.0 4053.9 CHILKOOT LAKE 14347.64 14347.6 14921.5 15S518.3 0.0 0.0 0.0 44787.4 47910.9 3700.3 169.0 74 23764 1987 3700.3 324.9 4025.2 COST POR ALTERNATIVE HYDROELECTRIC UPPER CHILKOOT LAR 313.0 1983 307832.5 2 10260.8 19260.% 16471.3 11098.1 0.0 0.0 0,0 32030.2 1486.8 0.0 9.0 0.0 2233.8 34264,0 2646.3 1986 2646.3 463.9 3110.2 *xASSUMFPT TONS * * * TAYE BAS hk 0 8689.0 1983 101464.9 2 > 2 4 3388.2 20238.4 20238.4 21047,9 21889,9 22765.5 0.0 0.0 7043.0 11314.6 698.4 873.9 192.0 80.0 80.0 272.0 34,0 18.0 18.9 121.5 225.0 93.0 98.9 $93.5 1985 19846 1985 198% 698.4 873.9 7343.3 286.0 129.0 540.1 984.4 7903;4 FUEL INTEREST RATE 7 ect eet tee tees tee terse se) GENERAL INFLATION 4%x INFLATION Leos? 2471.4 3743324 2610.46 40044,0 3092.8 225.0 225 417.0 1987 3092.8 570.7 FOO OOK AOR AGI K * GOAT LAKE 4.0 1983 27648.4 3 P21661 9216.1 0.0 670.9 2335.4 0.0 Ue.) 0.0 2006.4 $0775 .5 237609 224.0 112.5 33, 330.5 LIBS 237609 442.u 2819.7 TABLE D2 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR CHILKOOT LAKE DIVERSION HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTFUT COST PER cost OUTPUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 0.0 0.0 0.000 0.0 0.0 0.000 1987, 4053.9 9520.0 0-426 1087.9 9520.0 0.114 1988, 4066.6 9880.0 0.412 1192.7 9880.0 0.121 1989. 4079.9 10240.0 0.398 1305.8 10240.0 0.128 1990, 4093.7 10600.0 0.386 1428.0 10600.0 0.135 1991, 4108.1 11080.0 0.371 1577.0 11080.0 0.142 1992, 4123.0 11560.0 0.357 1738.3 11560.0 0.150 1993, 4138.5 12040.0 0.344 912.9 12040.0 0.159 1994, 4154.7 12520.0 0.332 2101.9 12520.0 0.168 1995. 4171.5 13000.0 0.321 2306.2 13000.0 0.177 1996, 4188.9 13480.0 0.311 2527.1 13480.0 0.187 1997, 4207.1 13960.0 0.301 2765.7 13960.0 0.198 1998, 4226.0 14440.0 0.293 3023.5 14440.0 0.209 1999. 4245.6 14920.0 0.285 3301.7 14920.0 0.221 2000. 4266.0 15400.0 0.277 3602.1 15400.0 0.234 2001. 4287.3 16027.5 0.267 3962.5 16027.5 0.247 2002. 4309.4 16655.0 0.259 4352.6 16655.0 0.261 2003. 4332.4 17282.5 0.251 4774.5 17282.5 0.276 2004, 4356.3 17910.0 0.243 5230.6 17910.0 0.292 2005. 4381.1 18537.5 0.236 5723.4 18537.5 0.309 2006. 4407.0 19165.0 0.230 6255.9 19165.0 0.326 2007. 4433.9 19165.0 0.231 6614.2 19165.0 0.345 2008. 4461.8 19165.0 0.233 6993.4 19165.0 0.365 2009. 4490.9 19165.0 0.234 739466 19165.0 0.386 2010. 4521.1 19165.0 0.236 7819.1 19165.0 0.408 2011. 455246 19165.0 0.238 8268.4 19165.0 0.431 2012. 4585.3 19165.0 0.239 8743.8 19165.0 0.456 2013. 4619.3 19165.0 0.241 9246.9 19165.0 0.482 2014, 4654.7 19165.0 0.243 97794 19165.0 0.510 2015. 4691.5 19165.0 0.245 10342.9 19165.0 0.540 2016. 4729.8 19165.0 0.247 10939.2 19165.0 0.571 2017. 4769.66 19165.0 0.249 11570.4 19165.0 0.604 2018, 4810.9 19165.0 0.251 12238.5 19165.0 0.639 2019. 4854.0 19165.0 0.253 12945.6 19165.0 0.675 2020, 4898.7 19165.0 0.256 13694.0 19165.0 0.715 2021. 4945.3 19165.0 0.258 14486.2 19165.0 0.756 2022. 1258.9 19165.0 0-066 15324.7 19165.0 0.800 2023. 1309.2 19165.0 0.068 16212.4 19165.0 0.846 2024, 1361.6 19165.0 0.071 17152.0 19165.0 0.895 2025. 1416.0 19165.0 0.074 18146.7 19165.0 0.947 2026. 1472.7 19165.0 0.077 19199.6 19165.0 1.002 2027, 1531.6 19165.0 0.080 20314.4 19165.0 1.060 2028. 1592.9 19165.0 0.083 21494,5 19165.0 1.122 2029. 1656.6 19165.0 0.086 22743.8 19165.0 1.187 2030. 1722.8 19165.0 0.090 24066.6 19165.0 1,256 2031. LAL 67 19165.0 0.093 25467.0 19165.0 1.329 2032. 1863.4 19165.0 0.097 26949.7 19165.0 1.406 2033. 1938.0 19165.0 0.101 28519.5 19165.0 1.488 2034, 2015.5 19165.0 0.105 30181.7 19165.0 1.575 2035. 2096.1 19165.0 0.109 31941.6 19165.0 1.667 2036. 2179.9 19165.0 0.114 33805.0 19165.0 1.764 PRESENT VAL INITIAL YEAR OF OPERATION = -------— 0 ene 56426.1 66765.2 TABLE D3 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR CHILKOOT LAKE DAM HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH COST OUTPUT COST PER COST OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH | 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 0.0 0.0 0.000 0.0 0.0 0.000 1987. 4025.2 11468.8 0.351 1310.7 11468.8 0.114 1988. 4038.2 11979.2 0.337 1446.1 11979.2 0.121 1989, 4051.8 12489.6 0.324 1592.7 12489.6 0.128 1990. 4065.8 13000.0 0.313 1751.3 13000.0 0.135 1991. 4080.4 13580.0 0.300 1932.8 13580.0 0.142 1992. 4095.6 14160.0 0.289 2129.3 14160.0 0.150 1993. 4111.4 14740.0 0.279 2341.9 14740.0 0.159 1994, 4127.9 15320.0 0.269 2572.0 15320.0 0.168 1995. 4145.0 15900.0 0.261 2820.7 15900.0 0.177 1996, 4162.8 16480.0 0.253 3089.5 16480.0 0.187 1997. 4181.3 17060.0 0.245 3379.9 17060.0 0.198 1998. 4200.5 17640.0 0.238 3693.5 17640.0 0.209 1999. 4220.5 18220.0 0.232 4032.0 18220.0 0.221 2000. 4241.3 18800.0 0.226 4397.3 18800.0 0.234 2001. 4263.0 19412.7 0.220 4799.5 1941247 0.247 ; 2002. 4285.5 20025.3 0.214 5233.4 20025.3 0.261 2003. 4308.9 20638.0 0.209 5701.5 20638.0 0.276 2004, 4333.2 21250.7 0.204 6206.2 21250.7 0.292 2005. 4358.5 21863.3 0.199 6750.3 21863.3 0.309 2006. 4384.9 22476.0 0.195 7336.6 22476.0 0.326 2007. 4412.2 22476.0 0.196 7756.9 22476.0 0.345 2008. 4440.7 22476.0 0.198 8201.6 22476.0 0.365 2009. 4470.3 22476.0 0.199 8672.1 22476.0 0.386 2010. 4501.1 22476.0 0.200 9170.0 22476.0 0.408 2011. 4533.2 22476.0 0.202 9696.9 22476.0 0.431 2012. 4566.5 22476.0 0.203 10254.4 22476.0 0.456 2013. 4601.1 22476.0 0.205 10844.5 22476.0 0.482 2014. 4637.1 22476.0 0.206 11468.9 22476.0 0.510 2015. 4674.6 22476.0 0.208 12129.7 22476.0 0.540 2016. 4713.6 22476.0 0.210 12829.1 22476.0 0.571 2017. 4754.1 22476.0 0.212 13569.4 22476.0 0.604 2018, 4796.3 22476.0 0.213 14352.8 22476.0 0.639 2019, 4840.1 22476.0 0.215 15182.1 22476.0 0.675 2020. 4885.7 22476.0 0.217 16059.8 22476.0 0.715 2021. 4933.1 22476.0 0.219 16988.8 22476.0 0.756 2022. 1282.1 22476.0 0.057 17972.3 22476.0 0.800 2023, 1333.4 22476.0 0.059 19013.3 22476.0 0.846 2024, 1386.7 22476.0 0.062 20115.2 22476.0 0.895 2025. 1442.2 22476.0 0.064 21281.7 22476.0 0.947 2026. 1499.8 22476.0 0.067 22516.6 22476.0 1.002 2027. 1559.8 22476.0 0.069 23823.9 22476.0 1.060 2028. 1622.2 22476.0 0.072 25207.9 22476.0 1.122 2029, 1687.1 22476.0 0.075 26673.1 22476.0 1.187 2030. 1754.6 22476.0 0.078 28224.4 22476.0 1.256 2031. 1824.8 22476.0 0.081 29866.7 22476.0 1.329 2032. 1897.8 22476.0 0.084 31605.6 22476.0 1.406 2033. 1973.7 22476.0 0.088 33446.6 22476.0 1.488 2034, 2052.6 22476.0 0.091 35395.9 22476.0 1.575 2035. 2134.8 22476.0 0.095 37459.9 22476.0 1.667 2036. 2220.1 = 22476.0 0.099 39645.3 22476.0 1.764 PRESENT VAL INITIAL YEAR OF | GRERATION| eee esrecesee ee 56128.0 7927943 TABLE [14 PROJECTED ANNUAL COSTS» MARKETABLE OUTFUT AND COST FER KWH FOR UPPER CHILKOOT LAKE HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985, 0.0 0.0 0.000 0.0 0.0 0.000 1986. 3110.2 11359.2 0.274 1229.0 11359.2 0.108 1987. 3128.8 11936.4 0.262 1364.1 11936.4 0.114 1988. 3148.1 12513.6 0.252 1510.6 12513.6 0.121 1989, 3168.1 13090.8 0.242 1669.3 13090.8 0.128 1990, 3189.0 13668.0 0.233 1841.3 13668.0 0.135 1991. 3210.7 14561.2 0.220 2072.4 14561.2 0.142 1992. 3233.3 15454.4 0.209 2323.9 15454.4 0.150 1993, 3256.8 16347.6 0.199 2597.4 16347.6 0.159 1994, 3281.2 17240.8 0.190 2894.4 17240.8 0.168 1995. 3306.6 18134.0 0.182 3217.0 18134.0 0.177 1996. 3333.0 19027.2 0.175 3567.0 19027.2 0.187 1997. 3360.4 19920.4 0.169 3946.66 19920.4 0.198 1998. 3389.0 20813.6 0.163 4358.0 20813.6 0.209 59976 3418.7 21706.8 0.157 4803.6 21706.8 0.221 2000. 344966 22600.0 0.153 5286.1 22600.0 0.234 2001. 3481.7 23580.0 0.148 5829.8 23580.0 0.247 2002. 3515.2 24560.0 0.143 6418.5 24560.0 0.261 2003. 3549.9 25540.0 0.139 7055.7 25540.0 0.276 2004, 3586.1 26520.0 0.135 774561 26520.0 0.292 2005. 3623.6 27500.0 0.132 8490.6 27500.0 0.309 2006. 3662.7 28480.0 0.129 9296.5 28480.0 0.326 2007. 3703.4 29460.0 0.126 10167.2 29460.0 0.345 2008. 3745.7 30440.0 0.123 11107.7 30440.0 0.365 2009, 3789.6 31420.0 0.121 12123.0 31420.0 0.386 2010. 3835.4 32400.0 0.118 13218.9 32400.0 0.408 2011. 3882.9 33810.0 0.115 14586.7 33810.0 0.431 2012. 3932.4 35220.0 0.112 16068.7 35220.0 0.456 2013. 3983.8 36630.0 0.109 17673.6 36630.0 0.482 2014. 4037.3 38040.0 0.106 19410.8 38040.0 0.510 2015. 4093.0 39450.0 0.104 21290.2 39450.0 0.540 2016. 4150.8 40860.0 0.102 23322.6 40860.0 0.571 2017. 4211.0 42270.0 0.100 25519.5 42270.0 0.604 2018. 4273.6 43680.0 0.098 27893.4 43680.0 0.639 2019. 4338.7 45090.0 0.096 30457.4 45090.0 0.675 2020. 4406.4 46500.0 0.095 33225.7 46500.0 0.715 2021. 1830.5 479690 0.038 36258.1 4796940 0.756 2022. 1903.7 49438.0 0.039 3953146 49438.0 0.800 2023. 1979.8 50907.0 0.039 43064.1 50907.0 0.846 2024. 2059.0 52376.0 0.039 46874.6 52376.0 0.895 2025. 2141.4 53845.0 0.040 50983.9 53845.0 0.947 2026. 2227.0 55314.0 0.040 55414.0 55314,.0 1,002 2027. 2316.1 56783.0 0.041 60188.4 56783.0 1.060 2028. 2408.8 $8252.0 0.041 65332.4 58252.0 1.122 2029. 2505.1 59721.0 0.042 70873.2 59721.0 1.187 2030. 2605.3 61190.0 0.043 76839.7 61190.0 1.256 2031. 2709.5 61190.0 0.044 81310.9 61190.0 1.329 2032. 2817.9 61190.0 0.046 86044.9 61190.0 1.406 2033. 2930.6 61190.0 0.048 91057.1 61190.0 1.488 2034. 3047.8 61190.0 0.050 96364.0 61190.0 1.575 2035. 3169.8 61190.0 0.052 101983.0 61190.0 1.667 PRESENT VAL INITIAL YEAR OF OPERATION mmm ea a a a 45995.8 125063.0 v TABLE DS PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR DAYEBAS CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST PRESENT VAL INITIAL YEAR OF OPERATION ANNUAL cost ($000) 1007.7 1020.1 1033.0 1046.3 1060.3 1074.7 1089.8 1105.4 1121.7 1138.7 1156.3 1174.6 1193.6 1213.4 1234.0 1255.5 1277.7 1300.9 1325.0 1350.1 1376.1 1403.2 1431.4 1460.8 1491.2 1523.0 1555.9 1590.2 1625.9 1663.0 1701.6 1741.7 1783.5 1128.4 1173.6 1220.5 1269.3 1320.1 1372.9 1427.8 1484.9 1544.3 1606.1 1670.4 1737.2 1806.7 1878.9 1954.1 16275.4 MWH OUTPUT FOR MARKET 9335.0 9690.0 10045.0 10400.0 10892.5 11385.0 11877.5 12370.0 12862.5 13355.0 13847.5 14340.0 14832.5 15325.0 15802.5 16280.0 16757.5 17235.0 17712.5 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 COST FER KWH DIESEL AL TERNATIVE ANNUAL cost ($000) 1401.1 1550.3 1712.0 1887.1 2076.7 2281.8 2503.7 2743.4 3002.5 3282.4 3584.5 3906.9 4254.6 4629.4 5033.4 5468.7 5937.6 6277.7 6637.6 7018.4 7421.4 7847.8 8299.0 8776.5 9281.9 9816.7 10382.7 10981.8 11615.9 12287.0 12997.3 13749.2 14545.1 15387.6 16279.4 17223.5 18222.9 19280.9 20401.0 21586.8 22842.2 24171.4 25578.6 2706846 28646.2 55814.3 MWH OUTPUT FOR MARKET 8980.0 9335.0 9690.0 10045.0 10400.0 10892.5 11385.0 11877.5 12370.0 12862.5 13355.0 13847.5 14340.0 14832.5 15325.0 15802.5 16280.0 16757.5 17235.0 17712.5 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 18190.0 COST PER KWH TABLE [16 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR UPPER DEWEY LAKE HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost OUTFUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 1002.8 1647.9 0.609 178.3 1647.9 0.108 1987. 1008.0 1767.1 0.570 201.9 1767.1 0.114 1988. 1013.4 1886.4 0.537 227.7 1886.4 0.121 1989. 1018.9 2005.7 0.508 255.8 2005.7 0.128 1990. 1024.7 2125.0 0.482 286.3 2125.0 0.135 1991. 1030.8 2310.0 0.446 328.8 2310.0 0.142 1992. 1037.0 2495.0 0.416 375.2 2495.0 0.150 1993. 1043.6 2680.0 0.389 425.8 2680.0 0.159 1994, 1050.4 2865.0 0.367 481.0 2865.0 0.168 1995. 1057.4 3050.0 0.347 541.1 3050.0 0.177 1996, 1064.8 3235.0 0.329 606.5 3235.0 0.187 1997. 1072.4 3420.0 0.314 677.6 3420.0 0.198 1998, 1080.3 3605.0 0-300 754.8 3605.0 0.209 1999. 1088.6 3790.0 0.287 838.7 3790.0 0.221 2000. 1097.2 3975.0 0.276 929.8 3975.0 0.234 2001. 1106.1 4252.5 0.260 1051.4 4252.5 0.247 2002. 1115.4 4530.0 0.246 1183.9 4530.0 0.261 2003. 1125.1 4807.5 0.234 1328.1 4807.5 04276 2004. 1135.1 5085.0 0.223 1485.1 5085.0 0.292 2005. 1145.6 5362.5 0.214 1655.7 5362.5 0.309 2006. 1156.4 5640.0 0.205 1841.0 5640.0 0.326 2007. 1167.7 5917.5 0.197 2042.2 5917.5 0.345 2008. 1179.5 6195.0 0.190 2260.6 6195.0 0.365 2009. 1191.7 6472.5 0.184 2497.3 6472.5 0.386 2010. 1204.4 6750.0 0.178 2753.9 6750.0 0.408 2011. 1217.7 7210.0 0.169 3110.6 7210.0 0.431 2012, 1231.4 7670.0 0.161 3499.4 7670.0 0.456 2013. 1245.7 8130.0 0.153 3922.6 8130.0 0.482 2014. 1260.6 8590.0 0.147 4383.2 8590.0 0.510 2015. 1276.1 9050.0 0.141 4884.1 9050.0 0.540 2016. 1292.1 9510.0 0.136 5428.2 9510.0 0.571 2017. 1308.9 9970.0 0.131 6019.2 9970.0 0.604 2018. 1326.3 10430.0 0.127 6660.4 10430.0 0.639 2019. 1344.4 10890.0 0.123 7356.0 10890.0 0.675 2020. 1363.2 11350.0 0.120 8109.9 11350.0 0.715 2021. 508.9 11980.0 0.042 9055.3 11980.0 0.756 2022. 529.2 12610.0 0.042 10083.2 12610.0 0.800 2023. 550.4 13240.0 0.042 11200.2 13240.0 0.846 2024. 572.4 13870.0 0.041 12413.1 13870.0 0.895 2025. 595.3 14500.0 0.041 13729.5 14500.0 0.947 2026. 619.1 15130.0 0.041 15157.3 15130.0 1.002 2027. 643.9 15760.0 0.041 16705.2 15760.0 1.060 2028. 669.7 16390.0 0.041 18382.2 16390.0 1.122 2029, 696.5 17020.0 0.041 20198.3 17020.0 1.187 2030, 724.3 17650.0 0.041 22164.1 17650.0 1.256 2031. 753.3 18140.0 0.042 24104.9 18140.0 1.329 2032. 783.4 18630.0 0.042 26197.4 18630.0 1.406 2033, 814.8 19120.0 0.043 28452.5 19120.0 1.488 2034, 847.3 19610.0 0.043 30882.5 19610.0 1.575 2035. 881.2 20100.0 0.044 33499 .9 20100.0 1.667 PRESENT VAL INITIAL YEAR OF CEE RAT LGN ||| mmc mee |||)!!! 1100) 111111111) 0 00011) 411))) 0 0 |||) eae 14576.2 29400.5 TABLE D7 PROJECTED ANNUAL COSTS: MARKETABLE OUTPUT AND COST PER KWH FOR REID FALLS CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE i ANNUAL MWH ANNUAL MUH COST OUTPUT COST PER COST OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 507.7 1353.6 0.375 138.7 1353.6 0.102 1986. 512.7. 1472.9 0.348 159.4 1472.9 0.108 1987. 517.9 1592.4 0.325 182.0 1592.1 0.114 1988. 523.3 1711.4 0.306 206.6 1711.4 0.121 1989, 528.9 1830.7 0.289 233.5 1830.7 0.128 1990. 534.8 1950.0 0.274 262.7 1950.0 0.135 1991. 540.9 2125.0 0.255 302.4 2125.0 0.142 1992. 547.2 2300.0 0.238 345.9 2300.0 0.150 1993, 553.8 2475.0 0.224 393.2 2475.0 0.159 1994, 560.6 2650.0 0.212 444.9 2650.0 0.168 1995. 567.8 2825.0 0.201 501.2 2825.0 0.177 1996. 575.2 3000.0 0.192 562.4 3000.0 0.187 a 1997. 582.9 3175.0 0.184 629.0 3175.0 0.198 1998. 590.9 3350.0 0.176 701.4 3350.0 0.209 1999, 599.2 3525.0 0.170 780.1 3525.0 0.221 2000. 607.9 3700.0 0.164 865.4 3700.0 0.234 2001. 616.9 3935.0 0.157 972.9 3935.0 0.247 2002. 626.3 4170.0 0.150 1089.8 4170.0 0.261 2003. 636.0 4405.0 0.144 1216.9 4405.0 0.276 2004, 646.2 4640.0 0.139 1355.1 4640.0 0.292 2005. 656.7 4875.0 0.135 1505.2 4875.0 0.309 2006. 667.7 5110.0 0.131 1668.0 5110.0 0.326 2007. 679.1 5345.0 0.127 1844.7. 5345.0 0.345 2008. 691.0 5580.0 0.124 2036.2 5580.0 0.365 2009, 703.3 5815.0 0.121 2243.7 5815.0 0.386 2010. 716.1 6050.0 0.118 2468.3 6050.0 0.408 2011. 729.5 6385.0 0.114 2754.7 6385.0 0.431 2012. 743.4 6720.0 0.111 3065.9 6720.0 0.456 2013. 757.8 7055.0 0.107 3404.0 7055.0 0.482 2014. 772.8 7390.0 0.105 3770.9 7390.0 0.510 2015. 788.4 7725.0 0.102 4169.0 7725.0 0.540 2016. 804.6 8060.0 0.100 4600.6 8060.0 0.571 2017. 821.5 8395.0 0.098 5068.3 8395.0 0.604 2018, 839.1 8730.0 0.096 5574.8 8730.0 0.639 2019, 857.3 9065.0 0.095 6123.2 9065.0 0.675 2020. 493.8 9400.0 0.053 6716.6 9400.0 0.715 2021. 513.6 9593.5 0.054 7251.4 9593.5 0.756 2022. 534.1 9787.0 0.055 7825.9 9787.0 0.800 2023. 555.5 9980.5 0.056 8442.9 9980.5 0.846 2024, 577.7 10174.0 0.057 9105.4 10174.0 0.895 2025. 600.8 10367.5 0.058 9816.6 10367.5 0.947 2026. 624.8 10561.0 0.059 10580.1 10561.0 1.002 2027. 649.8 10754.5 0.060 11399.5 10754.5 1.060 2028. 675.8 10948.0 0.062 12278.7 10948.0 1.122 2029. 702.9 11141.5 0.063 13222.0 11141.5 1.187 2030. 731.0 11335.0 0.064 14234.0 11335.0 1.256 oa 2031. 760.2 11335.0 0.067 15062.3 11335.0 1.329 2032. 790.6 11335.0 0.070 15939.2 11335.0 1.406 2033. 822.2 11335.0 0.073 16867.7 11335.0 1.488 2034. 855.1 11335.0 0.075 17850.7 11335.0 1.575 PRESENT VAL INITIAL YEAR OF OPERATION) GQ -<<2s->2¢«~C*=“‘OCOC*‘«A@ese=e=ce i 8117.8 20817.8 TABLE D8 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST PER KWH FOR WEST CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH COST OUTFUT COST PER COST OUTFUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986, 0.0 0.0 0.000 0.0 0.0 0.000 1987. 0.0 0.0 0.000 0.0 0.0 0.000 1988. 7903.4 2432.3 3.249 293.6 2432.3 0.121 1989, 7925.8 2614.1 3.032 333.4 2614.1 0.128 1990. 79491 2796.0 2.843 376.7 2796.0 0.135 1991. 7973.3 3074.4 2.593 43766 3074.4 0.142 1992. 7998.5 3352.8 2.386 504.2 3352.8 0.150 1993, 8024.7 3631.2 2.210 576.9 3631.2 0.159 1994, 8051.9 3909.6 2.060 656.4 3909.6 0.168 1995, 8080.3 4188.0 1.929 743.0 4188.0 0.177 1996, 8109.8 4466.4 1.816 837.3 4466.4 0.187 1997. 8140.4 4744.8 1.716 940.0 4744.8 0.198 1998. 8172.3 5023.2 1.627 1051.8 5023.2 0.209 1999, 8205.5 5301.6 1.548 1173.2 5301.6 0.221 2000. 8240.0 5580.0 1.477 1305.2 5580.0 0.234 2001. 8275.8 6039.6 1.370 1493.2 6039.6 0.247 2002. 8313.1 6499.2 1.279 1698.5 6499.2 0.261 2003. 8351.9 6958.8 1.200 1922.4 6958.8 0.276 2004, 8392.3 7418.4 1.131 2166.5 7418.4 0.292 2005. 8434.2 7878.0 1,071 2432.3 7878.0 0.309 2006. 8477.9 8337.6 1.017 2721.6 8337.6 0.326 2007. 8523.3 8797.2 0.969 3036.1 8797.2 0.345 2008. 8570.5 9256.8 0.926 3377.8 9256.8 0.365 2009, 8619.6 9716.4 0.887 3749.0 9716.4 0.386 2010. 8670.6 10176.0 0.852 4151.7 10176.0 0.408 2011. 8723.7 10933.2 0.798 4716.9 10933.2 0.431 2012. 8778.9 11690.4 0.751 5333.6 11690.4 0.456 2013, 8836.3 12447.6 0.710 6005.8 1244746 0.482 2014, 8896.1 13204.8 0.674 6738.0 13204.8 0.510 2015. 8958.2 13962.0 0.642 7534.9 13962.0 0.540 2016. 9022.8 14719.2 0.613 8401.6 14719.2 0.571 2017. 9090.0 15476.4 0.587 9343.5 15476.4 0.604 2018. 9159.8 16233.6 0.564 10366.5 16233.6 0.639 2019. 9232.5 16990.8 0.543 11476.9 16990.8 0.675 2020. 9308.0 17748.0 0.524 12681.5 17748.0 0.715 2021. 9386.6 18998.4 0.494 14360.2 18998.4 0.756 2022. 9468.4 20248.8 0.468 16191.4 20248.8 0.800 2023. 2210.1 21499.2 0.103 18186.9 21499.2 0.846 2024. 2298.5 22749.6 0.101 20360.1 22749.6 0.895 2025. 2390.4 24000.0 0.100 22724.7 24000.0 0.947 2026. 2486.1 25250.4 0.098 25296.0 25250.4 1.002 2027. 2585.5 26500.8 0.098 28090.1 26500.8 1.060 2028, 2688.9 27751.2 0.097 31124.3 27751.2 1.122) 2029. 2796.5 29001.6 0.096 34417.3 29001.6 1.187 2030, 2908.3 30252.0 0.096 37989.1 30252.0 1.256 2031. 3024.7 32312.4 0.094 42937.6 32312.4 1.329 2032. 3145.7 34372.8 0.092 48334.8 34372.8 1.406 2033. 3271.5 36433.2 0.090 54216.4 36433.2 1.488 2034, 3402.3 38493.6 0.088 60620.9 38493.6 1.575 2035. 3538.4 40554.0 0.087 67589.8 40554.0 1.667 2036. 3680.0 42614.4 0.086 75167.3 42614.4 1.764 2037. 3827.2 44674.8 0.086 83401.2 44674.8 1.867 PRESENT VAL INITIAL YEAR OF OPERATION = -<-9--9— 0 109243.4 59402.4 TABLE [119 PROJECTED ANNUAL COSTS, MARKETABLE OUTPUT AND COST PER KWH FOR SKAGWAY RIVER HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986, 0.0 0.0 0.000 0.0 0.0 0.000 1987. 3663.5 1242.1 2.949 142.0 1242.1 0.114 1988. 3686.3 1361.4 2.708 164.3 1361.4 0.121 1989. 3710.0 1480.7 2.506 188.8 1480.7 0.128 1990. 3734.7 1600.0 2.334 215.5 1600.0 0.135 1991. 3760.4 1765.0 2.131 251.2 1765.0 0.142 1992. 3787.1 1930.0 1.962 290.2 1930.0 0.150 1993. 3814.9 2095.0 1.821 332.9 2095.0 0.159 1994, 3843.8 2260.0 1.701 379.4 2260.0 0.168 1995. 3873.8 2425.0 1.597 430.2 2425.0 0.177 1996. 3905.0 2590.0 1.508 485.5 2590.0 0.187 1997, 3937.5 2755.0 1.429 545.8 2755.0 0.198 1998. 3971.3 2920.0 1.360 611.4 2920.0 0.209 1999. 4006.5 3085.0 1.299 682.7 3085.0 0.221 2000. 4043.0 3250.0 1.244 760.2 3250.0 04234 2001. 4081.0 3490.0 1.169 862.8 3490.0 0.247 2002. 4120.5 3730.0 1.105 974.8 3730.0 0.261 2003. 4161.7 3970.0 1.048 1096.8 3970.0 0.276 2004. 4204.4 4210.0 0.999 1229.5 4210.0 0.292 2005. 4248.9 4450.0 0.955 1373.9 4450.0 0.309 2006. 4295.1 4690.0 0.916 1530.9 4690.0 0.326 2007. 4343.2 4930.0 0.881 1701.4 4930.0 0.345 2008. 4393.2 5170.0 0.850 1886.6 5170.0 0.365 2009. 4445.3 5410.0 0.822 2087.4 5410.0 0.386 2010. 4499.4 5650.0 0.796 2305-1 5650.0 0.408 2011. 4555.6 6030.0 0.755 2601.5 6030.0 0.431 2012. 4614.1 6410.0 0.720 2924.5 6410.0 0.456 2013. 4675.0 6790.0 0.689 3276.1 6790.0 0.482 2014. 4738.3 7170.0 0.661 3658.7 7170.0 0.510 2015. 4804.1 7550.0 0.636 4074.5 7550.0 0.540 2016. 4872.6 7930.0 0.614 4526.4 7930.0 0.571 2017. 4943.7 8310.0 0.595 5017.0 8310.0 0.604 2018, 5017.8 8690.0 0.577 5549.3 8690.0 0.639 2019. 5094.8 9070.0 0.562 6126.6 9070.0 0.675 2020. 5174.9 9450.0 0.548 6752.3 9450.0 0.715 2021. 5258.1 9955.0 0.528 752466 9955.0 0.756 2022. 2252.0 10460.0 0.215 8364.0 10460.0 0.800 2023. 2342.1 10965.0 0.214 9275.7 10965.0 0.846 2024. 2435.8 11470.0 0.212 10265.2 11470.0 0.895 2025. 2533.2 11975.0 0.212 11338.7 11975.0 0.947 2026. 2634.5 12480.0 0.211 12502.6 12480.0 1.002 2027. 2739.9 12985.0 0.211 13763.7 12985.0 1,060 2028. 2849.5 13490.0 0.211 15129.7 13490.0 1.122 2029. 2963.5 13995.0 0.212 16608.4 13995.0 1.187 2030. 3082.0 14500.0 0.213 18208.5 14500.0 1.256 2031. 3205.3 15200.0 0.211 20198.2 15200.0 1.329 2032. 3333.5 15900.0 0.210 22358.5 15900.0 1.406 2033. 3466.9 16600.0 0.209 24702.5 16600.0 1.488 2034. 3605.5 17300.0 0.208 27244.6 17300.0 1.575 2035. 3749.8 18000.0 0.208 29999 69 18000.0 1.667 2036. 3899.7 18700.0 0.209 32984.8 18700.0 1.764 PRESENT VAL INITIAL YEAR OF OPERATION ---me— ee ee 54477.7 27112.8 TABLE [10 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR GOAT LAKE HYDROELECTRIC FROJECT AND ITS DIESEL ALTERNATIVE AT 7% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER COST OUTPUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 2819.7 2068.6 1.363 223.8 2068.6 0.108 1987. 2837.4 2250.4 1.261 257.2 2250.4 0.114 1988. 2855.9 2432.3 1.174 293.6 2432.3 0.121 1989. 2875.0 2614.1 1.100 333.4 2614.1 0.128 1990. 2894.9 2796.0 1.035 376.7 2796.0 0.135 1991. 2915.7 3074.4 0.948 437.6 3074.4 0.142 1992. 2937.2 3352.8 0.876 504.2 3352.8 0.150 1993, 29596 3631.2 0.815 576.9 3631.2 0.159 1994, 2982.9 3909.66 0.763 656.4 3909.6 0.168 1995. 3007.2 4188.0 0.718 743.0 4188.0 0.177 1996, 3032.4 4466.4 0.679 . 837.3 4466.64 0.187 1997. 3058.6 4744.8 0.645 940.0 4744.8 0.198 1998. 3085.9 5023.2 0.614 1051.8 5023.2 0.209 1999, 3114.2 5301.6 0.587 1173.2 5301.6 0.221 2000. 3143.7 5580.0 0.563 1305.2 5580.0 0.234 2001. 3174.4 6039.6 0.526 1493.2 603946 0.247 2002. 3206.3 6499.62 0.493 1698.5 6499.2 0.261 2003. 3239.5 6958.8 0.466 1922.4 6958.8 0.276 2004. 3274.0 7418.4 0.441 2166.5 7418.4 0.292 2005. 3309.8 7878.0 0.420 2432.3 7878.0 0.309 2006. 3347.2 8337.6 0.401 2721.6 8337.6 0.326 2007. 3386.0 8797.2 0.385 3036.1 8797.2 0.345 2008. 3426.3 9256.8 0+370 3377.8 9256.8 0.365 2009. 3468.3 9716.4 0.357 3749.0 971664 0.386 2010. 3512.0 10176.0 0.345 4151.7 10176.0 0.408 2011. 3557.4 10933.2 0.325 4716.9 10933.2 0.431 2012. 3604.6 11690.4 0.308 5333.6 11690.4 0.456 2013. 3653.7 12447.6 0.294 6005.8 12447.6 0.482 2014. 3704.8 13204.8 0.281 6738.0 13204.8 0.510 2015. 3757.9 13962.0 0.269 7534.9 13962.0 0.540 2016. 3813.1 14719.2 0.259 8401.6 14719.2 0.571 2017. 3870.6 15476.4 0.250 9343.5 15476.4 0.604 2018. 3930.3 16233.6 0.242 10366.5 16233.6 0.639 2019. 3992.5 16990.8 0.235 11476.9 16990.8 0.675 2020. 4057.1 17748.0 0.229 12681.5 17748.0 0.715 2021. 1747.4 18748.2 0.093 14171.1 18748.2 0.756 2022. 1817.3 19748.4 0.092 15791.2 19748.4 0.800 2023. 1890.0 20748.6 0.091 17552.0 20748.6 0.846 2024. 1965.6 21748.8 0.090 19464.4 21748.8 0.895 2025. 2044.2 22749.0 0.090 21540.2 22749.0 0.947 2026. 2125.9 23749.2 0.090 23792.1 23749.2 1.002 2027. 2211.0 24749.4 0.089 26233.7 24749.4 1.060 2028, 2299.4 2574946 0.089 28879.4 2574946 1.122 2029. 2391.4 26749.8 0.089 31745.0 26749.8 1.187 2030. 2487.1 27750.0 0.090 34847.2 27750.0 1.256 2031. 2586.5 28790.0 0.090 38256.9 28790.0 1.329 2032. 2690.0 29830.0 0.090 41946.7 29830.0 1.406 2033. 2797.46 30870.0 0,091 45937.8 30870.0 1.488 2034. 2909.5 31910.0 0.091 50252.9 31910.0 1.575 2035. 3025.9 32950.0 0.092 54916.5 32950.0 1.667 PRESENT VAL INITIAL YEAR OF OPERATION = -----mm 41974.8 45006.6 MM exhibit E ana 9 Percent Interest Rate TABLE E1 ESTIMATED INVESTMENT AND ANNUAL COST FOR ALTERNATIVE HYDROELECTRIC PROJECTS NEAR HAINES ANI SKAGWAYs ALASKA (DOLLAR AMOUNTS IN THOUSANTS) CHILKOOT LAKE DAM UPPER CHILKOOT DAYEBAS LAKE CREEK UPPER DEWEY LAKE WES CREE SOOO *XASSUMF TIONS x * GENERAL INFLATION 4% * FUEL INFLATION 6% * INTEREST RATE 9K JEOOOOOOIOOIOIOI OIC III OK CHILKOOT LAKE DESCRIPTION DIVERSION 1. PROJECT COST (PC)»1979 DOLLARS 35708.0 2. YEAR CONSTRUCTION BEGINS 1984 3. PROJECT COST @ PRICE LEVELS OF YEAR CONSTRUCTION BEGINS 43444.2 4. CONSTRUCTION FERIOD (YEARS) 3 S. AVG. PROJECT COST FER YEAR @ PRICE LEVELS OF BEGINNING CONSTRUCTION YR. 14481.4 6» FROJECT COST FER YEAR @ CURRENT YEAR PRICE LEVELS (xX) YEAR 1 14481.4 YEAR 2 15060.7 YEAR 3 15663.1 YEAR 4 0.0 YEAR 5 0.0 YEAR 6 0.0 TOTAL 45205.2 7. INTEREST DURING CONSTRUCTION (N=LAST CONSTRUCTION YEAR$ X=FC IN CONST YR @ CURRENT FRICE LEVELS YEAR N ¢ X TIMES .000 0.0 YEAR N~-13 X TIMES .090 1355.5 YEAR N-23 X TIMES .188 2724.0 YEAR N-33 X TIMES .295 0.0 YEAR N-43 X TIMES .412 0.0 YEAR N-Si X TIMES .539 0.0 TOTAL IDC 4079.4 8. TOTAL INVESTMENT: PROJECT COSTS PLUS IDC 49284.6 9. ANNUAL AMORTIZATION COST (35 YEARS) 4664.1 10. ANNUAL OPERATION AND MAINTENANCE (O&M) COST, 1979 DOLLARS 160.0 11. ANNUAL REPLACEMENT COST» 1979 DOLLARS 7361 12. TOTAL ANNUAL O&M AND REPLACEMENT COSTS 233.1 13. YEAR OPERATION BEGINS 1987 14. ANNUAL COST IN FIRST YEAR OF OPERATION AMORTIZATION 4664.1 O&M AND REPLACEMENTS 319.0 TOTAL 4983.1 35378.0 1984 43042.7 3 14347.6 14347.6 14921.5 15518.3 0.0 0.0 0.0 48829.1 4621.0 160.0 77.4 237.4 1987 4621.0 324.9 26313.0 7327.0 1983 1983 30782.5 8571.6 3 2 10260.8 4285.8 10260.8 4285.8 10671.3 4457.2 11098.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 960.4 385.7 1930.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2890.5 385.7 34920.7 9128.7 3304.7 863.9 240.0 192.0 112.5 34.0 352.5 226.0 1986 1985 3304.7 863.9 463.9 286.0 3768.6 1149.9 10164.9 3 3388.3 3388.3 3523.8 3664.8 0.0 0.0 0.0 11531.4 1091.3 80.0 18.0 98.0 1986 1091.3 129.0 4999.8 473.2 80.0 18.9 98.9 1985 66538 1984 80953 4 2023) 20238 21047 21889 22765 ° ° 85941 ° 1970 3959 5970 ° ° 11900 97841 9259 272 121 393 1988 9259 560 T SKAGWAY GOAT K RIVER LAKE +0 29569 .0 23634.0 1984 1983 7 35975.2 27648.4 3 3 B44 11991.7 9216.1 4 11991.7 921661 oo 12471.4 9584.8 oo 12970.3 9968.2 Ss 0.0 0.0 +0 0.0 0.0 +0 0.0 0.0 +7 37433.4 2876961 +0 0.0 0.0 ol 1122.4 862.6 ol 2255.6 1733.6 9 0.0 0.0 +0 0.0 0.0 +0 0.0 0.0 ol 3378.1 2596.2 8 40811.5 31365.3 3 3862.2 2968.3 +0 192.0 224.0 S 225.0 112.5 Ss 417.0 336.5 1987 1986 3 3862.2 2968.3 ol 570.7 442.8 4 4432.9 3411.1 TABLE £2 FROJECTEL HY LIROE ANNUAL CO LECTRIC PROJEC HY tf ANNUAL cost ($000) 0.0 0.0 498So1 3420.1 5450.4 3481.8 $514.5 5548.5 S583.9 5620.7 5657.0 5698.8 5740.2 5783.2 5828.0 5874.5 1258.9 1309.2 1361.4 1416.0 1472.7 1541.46 1592.9 1656.4 72258 DAZ ee 1863.4 1738.0 2015.5 2096.41 2179.9 PRESENT VAL INITIAL YEAR OF OF ERATION ae STS» MARKETABLE T AND ITS RO MWH QUTPUT FOR MARKET 0.0 0.0 9520.0 9880.0 10240.6 10600.0 11080.0 11540.0 12040.0 12520.0 13000.0 13480.0 13960.0 14440.0 14920.0 15400.0 146027.5 16655,.0 17282.5 17910.0 8537.5 19165.0 19165.0 19165,.0 19165.0 19165.0 19165.0 19165,.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19145.0 19165.0 19165.90 19165.0 19165.0 19165.0 19165.0 19145.0 19165.0 19165.0 19165.6 19165.0 19165.0 19165.0 19165.0 COST FER KWH 9.000 ©.006 Gs ns 0.506 0.489 OVa7e 0,455 0.437 0.421 0.406 0.392 0.380 0.368 0.357 0.547 0.837 0.325 0.315 0.304 1295 26286 0.278 0.280 0.290 2291 0.293 06297 6,300 0.302 0,404 0,307 0.066 0.068 0.071 0.074 0.077 0.080 G.083 0,086 0.090 0.093 0.097 O.101 0.105 0.109 0.114 ur AL. ANNUAL cost ($900) 0.0 0.0 1087.9 1192.7 1305.8 1428.0 1577.06 1738.3 08.2 2527.1 2765.7 $023.5 3301.7 5723.4 6255.9 6614.2 E993.4 FSI4aG 7BLIA B268.4 8743.8 9246.9 9779.4 10342.% 10939,.2 11570.4 12238.5 12945 .6 13694.0 14486.2 15324.7 16212.4 17152.0 18146.7 19199.6 20314.4 21494.% 3194164 33805,.0 429 oa RNATIVE MWH OUTPUT FOR MARKE 6.9 0.0 9520.0 20 11%400.0 12046.0 12520.0 13000.0 13480.0 13960.0 14440.0 14920.0 15400.0 [6027.5 16655.0 17282.5 17910.0 18537.5 19165.0 191465.0 19365.0 19165.0 19145.0 191465.0 191¢65.0 19165.0 19165.0 19165.0 19165.0 (7165.0 19165.0 19165.0 1S145.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 19165.0 191465.0 19165.9 19145.0 19165.0 OUTPUT AND COST FER KWH FOR CHILKOOT LAKE DIVERSION DIESEL ALTERNATIVE AT INTEREST COST PER KWH 0.006 0,690 O.114 0.135 0.142 0.150 Cals? 0.168 O.L77 0.187 O.198 0.209 0.221 TABLE E3 PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR CHILKOOT LAKE DAM HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 9% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost OUTPUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0.000 1986. 0.0 0.0 0.000 0.0 0.0 0.000 1987. 4945.9 11468.8 0.431 1310.7 11468.8 0.114 1988. 4958.9 11979.2 0.414 1446.1 11979.2 0.121 1989, 4972.4 12489.6 0.398 1592.7 12489.6 0.128 1990. 4986.5 13000.0 0.384 1751.3 13000.0 0.135 1991. 5001.1 13580.0 0.368 1932.8 13580.0 0.142 1992. 5016.3 14160.0 ' 0.354 2129.3 14160.0 0.150 1993. 5032.1 14740.0 0.341 2341.9 14740.0 0.159 1994, 5048.5 15320.0 0.330 2572.0 15320.0 0.168 1995. 5065.6 15900.0 0.319 2820.7 15900.0 0.177 1996. 5083.4 16480.0 0.308 3089.5 16480.0 0.187 1997, 5101.9 17060.0 0.299 3379.9 17060.0 0.198 1998, $121.2 17640.0 0.290 3693.5 17640.0 0.209 1999. 5141.2 18220.0 0.282 4032.0 18220.0 0.221 2000. 5162.0 18800.0 0.275 4397.3 18800.0 0.234 2001. 5183.6 19412.7 0.267 4799.5 19412.7 0.247 2002. 5206.1 20025.3 0.260 5233.4 20025.3 0.261 2003. 5229.5 20638.0 0.253 $701.5 20638.0 0.276 2004. 5253.9 21250.7 0.247 6206.2 21250.7 0.292 2005. 5279.2 21863.3 0.241 6750.3 21863.3 0.309 2006. 5305.5 22476.0 0.236 7336.6 22476.0 0.326 2007. 5332.9 22476.0 0.237 775669 22476.0 0.345 2008. 5361.4 22476.0 0.239 8201.6 22476.0 0.365 2009. 5391.0 22476.0 0.240 8672.1 22476.0 0.386 2010. 5421.8 22476.0 0.241 9170.0 22476.0 0.408 2011. 5453.8 22476.0 0.243 9b9b69 22476.0 0.431 2012. 5487.1 22476.0 0.244 10254.4 22476.0 0.456 2013. 5521.8 22476.0 0.246 10844.5 22476.0 0.482 2014. 5557.8 22476.0 0.247 11468.9 22476.0 0.510 2015. 5595.3 22476.0 0.249 12129.7 22476.0 0.540 2016. 5634.2 22476.0 0.251 12829.1 22476.0 0.571 2017. 5674.8 22476.0 0.252 13569.4 22476.0 0.604 2018. 5716.9 22476.0 0.254 14352.8 22476.0 0.639 2019. 5760.7 22476.0 0.256 15182.1 22476.0 0.675 2020. 5806.3 22476.0 0.258 16059.8 22476.0 0.715 2021. 5853.8 22476.0 0.260 16988.8 22476.0 0.756 2022. 1282.1 22476.0 0.057 17972.3 22476.0 0.800 2023. 1333.4 22476.0 0.059 19013.3 22476.0 0.846 2024. 1386.7 22476.0 0.062 20115.2 22476.0 0.895 2025. 1442.2 22476.0 0.064 21281.7 22476.0 0.947 2026. 1499.8 22476.0 0.067 22516.6 22476.0 1,002 2027. 1559.8 22476.0 0.069 23823.9 22476.0 1.060 2028. 1622.2 22476.0 0.072 25207.9 22476.0 1.122 2029. 1687.1 22476.0 0.075 26673.1 22476.0 1.187 2030. 1754.6 22476.0 0.078 28224.4 22476.0 1.256 2031. 1824.8 22476.0 0.081 29866.7 22476.0 1.329 2032. 1897.8 22476.0 0.084 31605.6 22476.0 1.406 2033. 1973.7 22476.0 0.088 33446.6 22476.0 1.488 2034. 2052.6 ° 22476.0 0.091 35395.9 22476.0 1.575 2035. 2134.8 22476.0 0.095 3745969 22476.0 1.667 2036. 2220.1 22476.0 0.099 39645.3 22476.0 1.764 PRESENT VAL INITIAL YEAR OF OPERATION ==----—- tees 54706.1 51198.6 TABLE E4 FROJECTED ANNUAL COSTS» MAK HYDROELECTRIC PROJECT ANID ITs HYORG ANNUAL cost ($000) 0.0 3768.6 3787.2 3806.5 3826.5 3847.4 3869.1 3891.7 3915.2 393964 3965.0 3991.4 4016.38 4047.4 4077.1 4168.0 4140.1 4173.6 4208.3 4244.5 9° 4404.1 4448.0 4493.8 4541.3 4590.8 4642.2 ABI? 4751.4 4809.2 4869.4 4932.0 A997 A 5064.8 1830.5 1903.7 7S 2059.0 2141.4 2227.0 2316.1 2408.8 2505.1 2605.3 2709S 2817.9 2930.6 3047.8 3169.8 PRESENT VAL INITIAL YEAR OF OPERATION 9 ====-==- 43314.3 ou FOR MWH TFUT MARKET 0.0 11359.2 11936.4 12513.6 13090.8 13668.0 14561,.2 15454 14347.6 17240.8 18134.0 19027.2 19920.4 20813.6 21706.8 22600.0 23580,.0 245460.0 25540.0 26520.0 27500.0 28480.0 29460.0 30440.0 31420.0 32400.0 33810.0 35220.0 36630.0 389040.0 39450.0 46860.0 42270.0 43480.0 45090.0 46500.0 4796960 49438.0 50907.0 52376.0 S3845.0 55314.0 54783.0 $8252.0 39721.0 €1190,0 61190.0 1190.0 61190.0 61190.0 1190.0 TABLE OUTPUT AND COST FER KWH FOR UPPER Y 9% TNTEREST MIESEL ALTERNATIVE @ ANNUAL COST FER cost KWH ($000) 0.0 1229.0 1364.1 1510.6 1669.3 1841.3 S946 .6 4358.0 4803.6 5286.1 5829.6 6418.5 7055.7 7745.1 8490.4 9296.5 10167.2 a0 67 12123.0 13218.9 14586,7 16048.7 17673.6 19410.8 S9S31.¢ 43064.1 46874.6 0983.9 55414.0 60188.4 $5332.64 70873.2 7683967 81310.9 86044,9 91057.1 96364.0 0,052 101983.0 739891 NATIVE MWH QUTPUT FOR MAKET 11359 .2 11936.4 12513.4 13099.8 136468.0 1.2 4.4 16347,6 1 0,8 1P134.0 19027.2 19920.4 3.0313.5 21706.8 28486.0 29440.0 30440.0 31420.0 22400.0 33810,0 3S220.0 36630,0 38040.0 BI450.0 40860.0 42270.0 43480.0 45090.0 46500.0 479690 49438 .9 £0907,0 76.0 845.0 55314.0 54783,0 S8252.0 $9721.0 61190,0 1199.0 61170.0 61190,.0 1190.0 61190.0 0.0 COST FER SWE 0.406 0.431 ASE 0.482 0.510 0.540 0.571 9.604 0.639 0.675 0.715 0.754 0.800 O.F4e 0.898 O94? 1.002 1.060 1.122 1.187 1.256 1.329 1.404 1.488 1.575 1.667 CHILKOOT LAKE TABLE ES PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR DAYEBAS CREEK HYDROELECTRIC PROJECT AND ITS DIESEL ALTERNATIVE AT 9X INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST PER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 1149.9 8625.0 0.133 883.5 8625.0 0.102 1986. 1161.3 8980.0 0.129 971.6 8980.0 0.108 1987. 1173.2 9335.0 0.126 1066.8 9335.0 0.114 1988. 1185.6 9690.0 0.122 1169.7 9690.0 0.121 1989, 1198.4 10045.0 0.119 1280.9 10045.0 0.128 1990. 1211.8 10400.0 0.117 1401.1 10400.0 0.135 1991. 1225.7 10892.5 0.113 1550.3 10892.5 0.142 1992. 1240.2 11385.0 0.109 1712.0 11385.0 0.150 1993. 1255.3 11877.5 0.106 1887.1 11877.5 0.159 1994, 1270.9 12370.0 0.103 2076.7 12370.0 0.168 1995. 1287.2 12862.5 0.100 2281.8 12862.5 0.177 1996. 1304.1 13355.0 0.098 2503.7 13355.0 0.187 1997. 1321.7 13847.5 0.095 2743.4 13847.5 0.198 1998. 1340.1 14340.0 0.093 3002.5 14340.0 0.209 1999. 1359.1 14832.5 0.092 3282.4 14832.5 0.221 2000. 1378.9 15325.0 0.090 3584.5 15325.0 0.234 2001. 1399.5 15802.5 0.089 3906.9 15802.5 0.247 2002. 1420.9 16280.0 0.087 4254.6 16280.0 0.261 2003. 1443.2 16757.5 0.086 4629.4 16757.5 0.276 2004. 1466.4 17235.0 0.085 5033.4 17235.0 0.292 2005. 1490.5 17712.5 0-084 5468.7 17712.5 0.309 2006. 1515.5 18190.0 0.083 5937.6 18190.0 0-326 2007. 1541.6 18190.0 0.085 6277.7 18190.0 0.345 2008. 1568.7 18190.0 0.086 6637.6 18190.0 0.365 2009. 1596.9 18190.0 0.088 7018.4 18190.0 0.386 2010. 1626.2 18190.0 0.089 7421.4 18190.0 0.408 2011. 1656.7 18190.0 0.091 7847.8 18190.0 0.431 2012. 1688.4 18190.0 0.093 8299.0 18190.0 0.456 2013. 1721.4 18190.0 0.095 8776.5 18190.0 0.482 2014. 1755.7 18190.0 0.097 9281.9 18190.0 0.510 2015. 1791.4 18190.0 0.098 9816.7 18190.0 0.540 2016. 1828.5 18190.0 0.101 10382.7 18190.0 0.571 2017. 1867.1 18190.0 0.103 10981.8 18190.0 0.604 2018. 1907.2 18190.0 0.105 11615.9 18190.0 0.639 2019, 1948.9 18190.0 0.107 12287.0 18190.0 0.675 2020. 1128.4 18190.0 0.062 12997.3 18190.0 0.715 2021. 1173.6 18190.0 0.065 13749.2 18190.0 0.756 2022. 1220.5 18190.0 0.067 14545.1 18190.0 0.800 2023. 1269.3 18190.0 0.070 15387.6 18190.0 0.846 2024, 1320.1 18190.0 0.073 16279.4 18190.0 0.895 2025. 1372.9 18190.0 0.075 17223.5 18190.0 0.947 2026. 1427.8 18190.0 0.078 18222.9 18190.0 1.002 2027. 1484.9 18190.0 0.082 19280.9 18190.0 1.060 2028. 1544.3 18190.0 0.085 20401.0 18190.0 1.122 2029. 1606.1 18190.0 0.088 21586.8 18190.0 1.187 2030. 1670.4 18190.0 0.092 22842.2 18190.0 1.256 2031. 1737.2 18190.0 0.096 24171.4 18190.0 1.329 2032. 1806.7 18190.0 0.099 25578.6 18190.0 1.406 2033. 1878.9 18190.0 0.103 27068.6 18190.0 1.488 2034. 1954.1 18190.0 0.107 28646.2 18190.0 1.575 PRESENT VAL INITIAL YEAR OF ORPERARIJON =ee—=—SS 0 SSS 14301.3 35771.0 TABLE E6 PROJECTED ANNUAL COSTS» MARKETABLE QUTFLUT AND COST FER KWH FOR UPPER DEWEY LAKE HYDROELECTRIC PROJECT AND TTS WIESEL ALTERNATIVE aT o% INTEREST HYDRO DTESEL ALTERNATIVE ANNUAL. MWH ANNUAL. MWH COST OUTFIT COST FER cost OUTPUT COST PER ¢$000) FOR MARKET KWH ($0090) FOR MARKET KWH 0.0 9.000 0.0 0.0 0.060 1647.9 0.741 178.3 1647.9 9,108 1767.1 0.693 201.9 1767.61 0.114 1988, 1886.4 0,652 7 1886.4 0.121 1989, 2005.7 0.616 2005.7 0.128 1990. 0.585 286.3 25:0 Isis 0.540 328.8 10.0 725 0.503 ? 2495.0 1993, 2 9.471 2680.0 1994, 1267.8 2865.0 QO.443 2865.0 1995. 1274.8 3050.0 0.418 541.1 3050.0 1996, 1282.2 3235.0 0.396 606.5 3235.0 Lae ® 1289.8 3420.0 0.377 677.6 3420.0 1998, 1297.8 3605.0 0.360 754.8 3605.0 1999, 1306.0 3790.0 0.345 838.7 2790.0 2000, 1314.6 3975.0 0.331 929.8 3975.0 2001, 1323.5 4252.5 Q.311 1051.4 4252.5 2002, 1332.8 4530.0 294 1183.9 4530.0 2003, 1342.5 4807.5 0.279 1328.1 4807.5 2004, 1352.5 5085.0 0.266 1485.1 5085,0 2005. 1363.0 5362.5 0.254 ‘ 5362.5 2006. 1373.9 5640.0 0.244 5640.0 2007. 1385.2 5917.5 0.234 $917.5 2008, 1396.9 6195.0 0.225 2009, 1409.1 6472.5 0.218 2010. 1421.9 6750.0 0.211 2011. 1435.1 7210.0 0.199 2012. 1448.8 7670.0 0.189 2013, 1463.1 8130.0 0.180 2014, 1478.0 8590.0 O.172 "4 2015. 1493.5 9050.0 0.1465 4884.1 » 9050.0 2016. 1509.6 9510.0 0.159 5428.2 9510.0 2017, 1526.3 9970.0 0.153 6019.2 9970.0 2018, 1543.7 10430.0 0.148 6640.4 19430.0 2019, 1561.8 10890,.0 0.143 7356.0 10890.0 2020. 1580.6 11350.0 0.139 8109.9 11350.0 2021, 508.9 11980.0 0.042 9055.3 11980.0 2022. $29.2 12610.0 0,042 10083.2 12610.0 2023. 550.4 13240.0 0.042 11200.2 13240,0 2024. 572.4 13870.0 0.041 12413.1 13870.0 2025. 595.3 14500.0 0.041 13729.5 14500.0 2026. 619.1 15130.0 0.041 15157.3 15130.0 2027. 643.9 15760.0 0,041 16705.2 15760.0 2 ’ 669.7 16396,.0 0.041 18382.2 14390,0 2029. 49665 17020.0 0,041 20198.3 17020.0 2030. 724.3 17450.0 0.041 221641 17650.0 2031. 753.3 18140.0 0.042 104.9 18140,0 2032. 783.4 18630.0 0.042 26197.4 18430,0 2033, 814.8 19120.0 0.043 28452 19120,0 2034, 847.3 19610.0 0.043 3088: 19610.0 O35. 881.2 ?0100.0 0,044 33A99.9 29100,0 PRESENT VA INITIAL YEAR OF OPERATION (0 -=2-eo- went nees 13864.1 1445841 TABLE E7 PROJECTED ANNUAL COSTS: MARKETABLE OUTFUT ANI! COST PER KWH FOR REIL FALLS CREEK HYDROELECTRIC PROJECT ANI ITS DIESEL ALTERNATIVE AT 9% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost OUTPUT COST PER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 598.3 1353.6 0.442 138.7 1353.6 0.102 1986. 603.3 1472.9 0.410 159.4 1472.9 0.108 1987. 608.5 1592.1 0.382 182.0 1592.1 0.114 1988, 613.9 1711.4 0.359 206.6 1711.4 0.121 1989. 619.6 1830.7 0.338 233.5 1830.7 0.128 1990. 625.4 1950.0 0.321 262.7 1950.0 0.135 1991. 631.5 2125.0 0.297 302.4 | 2125.0 0.142 1992, 637.8 2300.0 0.277 345.9 2300.0 0.150 1993, 644.4 2475.0 0.260 393.2 2475.0 0.159 1994, 651.3 2650.0 0.246 444.9 2650.0 0.168 1995. 658.4 2825.0 0.233 501.2 2825.0 0.177 1996, 665.8 3000.0 0.222 562.4 3000.0 0.187 1997. 673.5 3175.0 0.212 629.0 3175.0 0.198 1998. 681.5 3350.0 0.203 701.4 3350.0 0.209 1999. 689.9 3525.0 0.196 780.1 3525.0 0.221 2000. 698.5 3700.0 0.189 865.4 3700.0 0.234 2001. 707.5 3935.0 0.180 972.9 3935.0 0.247 2002. 716.9 4170.0 0.172 1089.8 4170.0 0.261 2003. 726.7 4405.0 0.165 1216.9 4405.0 0.276 2004, 736.8 4640.0 0.159 1355.1 4640.0 0.292 2005. 747.4 4875.0 0.153 1505.2 4875.0 0.309 2006. 758.3 5110.0 0.148 1668.0 5110.0 0.326 2007. 76967 5345.0 0.144 1844.7 5345.0 0.345 2008. 781.6 5580.0 0.140 2036-2 5580.0 0.365 2009. 79309 5815.0 0.137 2243.7 5815.0 0.386 2010. 806.8 6050.0 0.133 2468.3 6050.0 0.408 2011. 820.1 6385.0 0.128 2754.7 6385.0 0.431 2012, 834.0 6720.0 0.124 3065.9 6720.0 0.456 2013. 848.4 7055.0 0.120 3404.0 7055.0 0.482 2014. 863.4 7390.0 0.117 3770.69 7390.0 0.510 2015. 879.0 7725.0 0.114 4169.0 7725.0 0.540 2016. 895.3 8060.0 0.111 460046 8060.0 0.571 2017. 912.2 8395.0 0.109 5068.3 8395.0 0.604 2018. 929.7 8730.0 0.106 5574.8 8730.0 0.639 2019. 948.0 9065.0 0.105 6123.2 9065.0 0.675 2020. 493.8 9400.0 0.053 6716.6 9400.0 0.715 2021. 513.6 959365 0.054 7251.4 9593.65 0.756 2022. 534.1 9787.0 0.055 7825.9 9787.0 0.800 2023. 555.5 9980.5 0.056 8442.9 9980.5 0.846 2024. 577.7 10174,.0 0.057 9105.4 10174.0 0.895 2025. 600.8 10367.5 0.058 9816.6 10367.5 0.947 2026. 624.8 10561,.0 0.059 10580.1 10561.0 1.002 2027. 649.8 10754.5 0.060 11399.5 10754.5 1.060 2028. 675.8 10948.0 0.062 12278.7 10948.0 1.122 2029. 702.9 11141.5 0.063 13222.0 11141.5 1.187 2030. 731.0 11335.0 0.064 14234.0 11335.0 1.256 2031. 760.2 11335.0 0.067 15062.3 11335.0 1.329 2032. 79066 11335.0 0.070 15939.2 11335.0 1.406 2033. 822.2 11335.0 0.073 16867.7 11335.0 1.488 2034. 855.1 11335.0 0.075 17850.7 11335.0 1.575 PRESENT VAL INITIAL YEAR OF OPERATION = e-em R 7263.4 12006.8 TABLE ES PROJECTED ANNUAL COSTS» MARKETABLE OUTPUT AND COST FER KWH FOR WEST CREEK HYDROELECTRIC PROJECT AND ITS MIESEL ALTERMATIVE AT 9% INTEREST HYDRO DIESEL ALTERNATIVE ANNUAL MWH ANNUAL MWH cost OUTPUT COST FER cost OUTFUT COST FER YEAR ($000) FOR MARKET KWH ($000) FOR MARKET KWH 1985. 0.0 0.0 0.000 0.0 0.0 0,000 1986, 0.0 0.0 0.000 0.0 0.0 0.060 1987. 0.0 0.0 9.000 0.0 G.0 0.000 1988. 9819.4 2432.3 4,037 293.6 2432.3 0.121 1989. 7841.8 2614.1 3.765 333.4 2614.1 6.128 1990. 9B65 61 2796.0 3.528 37667 2796.0 0.135 1991, 9889.3 3074.4 3217 437.6 3074.4 0.142 1992. 9914.5 3352.8 2.957 504.2 3352. 0.150 1993, 9940.8 3631.2 2 S76s9 3631.2 0.159 1994, 9968.0 3909.6 656.4 3909.6 0.168 1995. P999GA 4188.0 743.0 4188.0 O.177 1996. 10025.8 4466.4 837.3 4466.4 0.187 1997. 10056.5 4744.8 940.0 4744.8 0.198 1998. 10088.4 3023.2 2.008 1051.8 $023.2 0.209 Teo 10121.5 5301.6 1,909 1173.2 S301L.6 0.221 2000. 10156.0 5580.0 1.820 1305.2 80.0 0.234 2001. 10191.9 $039.6 1.688 1493.2 6039 +247 2002 10229.2 6499.2 1.574 1698.5 6499.2 2003. 102468.0 6958.8 1.476 1922.4 6956.8 2004, 10308.3 7418.4 1.390 2166.5 7418.4 2005. 10350,.3 7878.0 1.314 2432.3 7878.0 2006, 10393.9 8337.4 1.247 2721.6 8337.6 2007. 104329.3 8797.2 1.187 3036.1 8797.2 2008. 10486.5 9256.8 1.133 3377.8 9256.8 2009. 10535.6 9716.4 1,084 3749.0 9716.4 2010. 10586.7 10176.0 1.040 4151.7 10176.0 2011. 10639.8 10933.2 0.973 4716.9 10933.2 2012. 10695.0 11690.4 0.915 5333.6 11690.4 2013. 10752.4 A766 0.864 6005.8 12447.6 2014, 10812.1 04.8 0.819 6738.0 13204.8 2015. 10874.2 12962, 0.779 7534.9 13962.0 2016. 10938.8 14719.2 0.743 8401.6 | 14719,2 2017. 11006.0 15476.4 0.711 9343.5 15476.4 2018. 11075.9 162353.6 0.482 10346.5 16233,.6 2019. 11148.5 16990.8 0.656 11474.9 16990.8 2020, 11224.1 17748.0 0.632 12681.5 17748.0 2021. 11302.7 18998.4 0.595 14360.2 18998.4 2022. 11384.4 20248.8 0.562 L6191.4 20248.8 2023. 2210.1 21499.2 0.103 18186.9 21499.2 2024. 2298.5 2274946 0.101 20360.1 227496 2025, 2390.4 24000.0 0.106 724.7 24000.0 2026. 2486.1 25250.4 0.098 25296.0 25250.4 2027. 2585.5 26500.8 0.098 28090.1 26500,.8 2028. 2688.9 7751.2 0.097 31124.3 27751. 2029. 2796.5 7001.4 0.096 34417.3 297001.6 2030, 2908.3 30252.0 0.096 379891 30252 2031. 3024.7 32312.4 0.094 4293746 32312.4 2032. 3145.7 34372.8 0.092 48334.8 34372. 2033. 3271.5 36433.2 0.090 54216.4 36433.2 2034 3402.3 38493.6 0.088 60620.9 38493.6 2 3538.4 40554.0 0.087 67589 8 40554.0 2036, 3680.0 42614.4 0.086 75167.3 42614.4 2037. 3827.2 44674.8 0.086 83401.2 44674.8 PRESENT VAL INITIAL YEAR OF OPERATION TABLE EY PROJECTED ANNUAL COSTS: MARKETABLE GUTPUT AND COST FER KWH FOR SKAGWAY RIVER HYDROELECTRIC FROJECT AND ITS UTESEL ALTERNATIVE AT 9% INTEREST HYDRO NIESEL ALTER ANNUAL MWH ANNUAL MWh cosT OUTPUT COST FER cost OUTPUT COST FER ($000) FOR MARKET KWH $0 >) FOR MARKET KWH 0.0 0.0 9.000 Oo. 0.000 0.0 0.0 0.000 0.0 0.000 4432.9 1242.1 3.569 142.0 0.114 4455.7 1361.4 3.273 164.3 0.121 44795 1480.7 3.025 188.8 0.128 4504.2 1600.0 2.815 215.5 0.135 4529.9 1765.0 251.2 0.142 4556.6 1939.0 290.2 0.150 4584.3 2095.0 332.9 0.159 4613.2 2260.0 S794 9.168 4643.3 2425.0 430.2 0.177 4674.5 2590.0 485.5 4707.0 275540 545.8 4740.8 2920.0 o11.4 4775.9 3085.0 682.7 4812.5 3250.0 760.2 3250.6 4850.5 3490.0 862.8 3490.0 4890.0 3 +O c 974.8 3730.0 4931.1 oO 1.242 1094.98 3970.0 4973.9 4210.0 1.181 1229.5 4210.0 5018.3 4450.0 1,128 1373.9 4450.0 5064.6 4690,0 1.080 1530.9 4590.0 Sil2s7 4930.0 1.037 1701.4 5162.7 5170.0 0.999 1886.6 5214.7 5419.0 0.964 2087.4 5268.8 5650.0 0.933 2305.1 S325.1 6030.0 0.883 2601.5 S383.6 6410.0 6.840 2924.5 5444.5 6790.0 O.RO2 3276-1 5507.7 7170.0 9.768 4658.7 SS73.6 7350.0 0.738 4074.5 5642.0 7930.0 O.v11 4526.4 B410.0 9.498 5017.0 8690.0 3 9070.0 4 9450.0 3 9955.0 104460.0 10965.0 11470.9 11975.0 12480.0 273949 12985.0 2849.5 13490.0 2763.5 13995.0 3082.0 14500,0 3208.3 9 $333.5 15709.0 3466.9 16600,0 7405.5 17 7749.8 899.7 99ISS.0 16440.0 109465.% 13490.6 13995 0 14500.0 PRESENT VAL TNITIAL YEAR OF OPERATION on in TABLE £10 FROJECTED HYDROELECTRIC PROJEC HYD ANNUAL cost ($000) 0.0 3411.1 3428.8 3447.2 3466.4 3486.3 3507.0 3528.6 3551.0 3574.3 3598.5 3623.8 3650.0 3677.2 3705.6 373561 3765.8 3797.7 3830.8 3865.3 3901.2 3938.5 3977.3 4017.7 4059.7 4103.3 4148.7 4196.0 4245.1 429661 4349.3 4404.5 4461.69 4521.7 4593.8 4648.4 1747.4 1817.3 1890.0 1965.6 2044.2 2125.9 2211.0 2299.4 2391.4 2487.1 2586.5 2690.0 2797.6 2909.5 3025.9 INITIAL YEAR OF ERAT ION OF ANNUAL COSTS» MARNE TABLE ITS DIESEL ALTERNATIVE AT T ANT RO MWH OQUTFUT COST FER FOR MARKET KWH 0.000 1.649 1.524 1.417 1,326 1.247 1.141 1,052 0.978 0.914 0.859 0.811 0.769 5023.2 0.732 5301.66 0.499 5580.0 04669 6039.4 0.624 6499.2 0.584 6958.8 0.551 7418.4 0.521 7878.0 0.495 8337.6 0.472 8797.2 0.452 9256.8 0.434 9716.4 0.418 10176,.0 0.403 10933.2 9.379 11690,.4 0.359 12447.6 13204.8 139 ° 14719.2 15474.4 Src 6 16990.8 17748.0 18748,2 19748.4 20748.46 21748.8 22749.0 23749.2 24749.4 25749.6 26749.8 27750.0 28790.0 29830.0 30870.0 31910.0 32950.0 OUTPUT ANIL uIE ANNUAL . AL cost 1305.2 1493.2 1698.5 1922.4 2166.5 2432. 2721.6 3036.1 3377.8 3749.9 4151.7 A714.9 5333.4 4005.8 6738.0 7534.9 B401.6 9343.5 10364.5 11476.9., 12681.§ 14171.1 15791.2 17552.0 19464.4 21540.2 z 2el1 33.7 28879.4 31745.0 34847.2 38256.9 41946,7 45937.8 502 o §4916.5 24853.6 COST PER KWH FOR % INTEREST NATIVE MWH OUTFUT ($000) FOR 0.0 2068.6 0.4 432.3 4u4 2794.0 O74 .4 2352. Oot se 3909.6 4183.0 9466.4 4744.8 $023.2 S301.6 5580.0 6039.4 6499.2 6958.8 7418.4 7878.0 8337.46 8797.2 9256.8 9716.4 10176.0 10933.2 11490,4 12447.4 13204,2 13942.0 14719.2 15476.4 16233.4 16990.8 17748.0 18748.2 19748.4 20748.6 21748.8 22749,0 23749.? 24749.4 2574946 26749.8 27750.0 28790.0 29830.0 30870.0 aL Ose 32959.0 2 GOAT COST FER HWH 0.000 0.108 0.114 0.121 9.128 0.145 9.142 9.150 0.15? 9.168 GA?77 0.187 9.198 9.209 0.221 0.234 0.247 0.261 0.276 0.292 0.309 0.326 GO, 345 0.365 9.386 0,408 0.431 0.458 6.482 9.519 0.540 O.S71 9.604 0.639 0,675 0.715 0.756 9,800 0,845 0.895 0.947 1,002 1.960 dee 1.187 1 2S6 1.329 1,406 1,488 1.575 1.447 LAKE Exhibit F Investment and Annual Costs for Area Power Plans TABLE FL ESTIMATED INVESTMENT ANID ANNUAL COST FOR ALTERNATIVE HYDROELECTRIC SOOO OK PROJECTS NEAR HAINES ANI SKAGWAYs ALASKA *XASSUMP TIONS * (DOLLAR AMOUNTS IN THOUSANDS) * GENERAL INFLATION 4%% * FUEL INFLATION OUK * INTEREST RATE Sux SOOO OOK COMBINED UPPER UFFER REID COMBINED COMBINED UPPER CHILKOOT TAYERAS DEWEY FALLS WEST GOAT GOAT TESCRIF TION CHILKOOT LAKE CREEK LAKE cE CREEK LAKE LAKE Pl [OST CFCI21979 DOLLARS 30943.0 26313.0 7327.0 8489. ° 4013.0 71168.0 23634.0 YEAR “CONSTRUCT LON BEGINS 1983 1983 1983 1983 1983 1984 1983 3, PROJECT COST @ PRICE LEVELS OF YEAR CONSTRUCTION BEGINS 36198,.9 3078 8571.4 10164.9 4B9466 86586,.8 27648.4 4. CONSTRUCTION FERLOD (YEARS) 3 : 2 & 2 4 3 5. AVG. PROJECT COST PER YEAR @ PRICE LEVELS OF BEGINNING CONSTRUCTION YR. 12066.3 10260.8 4285.8 3388.3 2347.3 21646.7 11021.6 9216.1 6. PROJECT COST FER YEAR @ CURRENT YEAR PRICE LEVELS (XxX) YEAR 1 12066.3 10260.8 4285.8 3388.3 2347.3 21646.7 11021.6 921661 YEAR 2 12549.0 10671.3 4457.2 3523.8 2441.2 S12+66 11462.5 9584.8 YEAR 3 13050.9 11098.1 0.0 3664.8 0.0 23413.1 11921.0 9968.2 YEAR 4 0.0 0.0 0.0 0.0 0.0 24349.6 0.0 0.0 YEAR S 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 YEAR & 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 ' 1 ! 1! TOTAL 8743.0 10576.9 91921.9 34405.1 2876901 7. INTEREST DURING CONSTRUCTION (N=LAST CONSTRUCTION YEARS X=FC TIN CONST YR @ CURRENT PRICE LEVELS YEAR N $ X TIMES .000 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 YEAR N-13 X TIMES .050 627.4 533.6 214.3 176.2 117.4 1170.7 573.1 479.2 YEAR N-23 X TIMES .102 1236.8 1051.7 0.0 347.3 0.0 2307.5 1129.7 944.7 YEAR N-33 X TIMES .158 0.0 0.0 0.0 0.0 0.0 3412. 0.0 0.0 YEAR N-43 X TIMES .216 0.0 0.0 0.0 0.0 0.0 0.90 0.0 0.0 YEAR N-Si X TIMES .276 0.0 0.0 0.0 0.0 0.90 0.0 0.0 0.0 TOTAL Inc 1864.2 214.3 $23.5 117.4 6890.2 1702.8 1423.9 8. TOTAL INVESTMENT? FROJECT COSTS FLUS TDC 39530.4 33615.5 8957.3 11100.4 4905.9 98812.1 36108.0 30193.0 9. ANNUAL AMORTIZATION COST (35 YEARS) 2414.2 2053.0 547.0 677.69 299.6 6034.6 2205.2 1843.9 10. ANNUAL OPERATION ANT! MAINTENANCE (O&M) COST, 1979 NOLLARS 243.0 192.0 80.0 80.0 275.0 227.0 224.0 11. ANNUAL REPLACEMENT COST, 1979 DOLLARS 115.0 34.0 18.0 Aiea? 124.0 115.0 12. TOTAL ANNUAL O&M AND REPLACEMENT COSTS 358.0 226.0 98.0 98.9 399.0 342.0 13. YEAK OPERATION BEGINS 1986 1984 1985 1986 1985 1988 1986 1986 14, ANNUAL COST IN FIFST YEAR OF OPERATION AMORTIZATION 2414.2 2053.0 547.0 677.9 2 6034.6 2205.2 O&M AND REPLACEMENTS 471.1 463.9 286.0 129.0 125.1 567.9 450.0 TOTAL 2885.3 2516, 8 833.0 806.9 424.8 6602.5 2655.2 TABLE F2 ESTIMATED INVESTMENT ANI! PROJECTS NEAR HATNES AND SKAGWAY» CMOLLAR AMOUNTS IN THOUSANTIS > - 3T CPC} 61979 DOLLARS 2s YEAR TRUCTION BEGINS "OIECT 37 @ PRIC (E Ss OF YEAR CONSTRUCTION BEGINS 4. WUNSTRUCTION PERIOD CrEARS» » AVG. PROJECT COST PER TAR CON CE PON YR, LEVELS OF BEGINNING CONS 6. PROJECT COST PER YEAR @ CURRENT YEAR PRICE LEYELS (X) YEAR 4 oe YEAR 3 YEAR 4 YEAR Si YEAR TOTAL 7. INT T TURING CONSTRUCTION CN=LAST CONSTRUCT YEARS IN CONST YR @ CURR RICE LE YEAR YIMES 009 YEAR . TIM 1070 YEAR TIM 145 TEAR TIN 1225 YEAR TIM re YEAR TIM 14 TOTAL Enc 8. TOTAL INVESTMENT! PROJECT COSTS PLUS Se ANNUAL Tne AMORTIZATION COST C35 TEARS } 10. ANNLAL OF CUE) Ld ANNUAL FE 12. YOTAL ATION ANU MAINTENANCE 9 1979 COLLARS SCEMENT COST? ANNUAL C&M ANT 197° TOLLARS "LACEMENT COSTS 13. 14. YEAR OPERATION BEGINS ANNUAL COST IN FIRST YEAR AMORTIZATION Sah ANG REPLACEMENTS OF OPERATION TOTAL ANNUAL COST FOR ALASKA 0.9 ALTERNATIVE COMBINED nar 30943.0 1983 198.9 x 12066.3 12066.3 L2549.60 13050.9 0.0 0.90 9.0 37666.2 9.0 878.4 1748.4 0.0 0.0 0.0 Go 1986 3112.0 471-1 HYDROELECTRIC UPPER CHILKOOT TAYEBAS LAK CRE K 26313.0 1983 19260.8 10260.8 10671.3 11098.1 0.0 0.0 0.0 32030.2 0.90 0-0 PAZ 300.0 1486.8 0.0 0.0 0.0 0.0 0.0 O,0 $4244,0 9043.0 2646,3 693.4 192.0 34,0 226.0 1984 1985 2646.3 SOOO XASSUMFT TONS * * GENERAL INFLATION 42% * FUEL INFLATION on x INTEREST RATE PAE SOOO OOK OK UPPER: COMBINED COMBINEL EWE Y WEST GOAT Boat LAKE LAKE 8489.0 4013.0 23434.0 1983 1983 1983 10164.9 4694.6 86586,8 33064,9 3 2 4 3 3388.3 2347 11021.6 921661 3388.5 2347.3 2646.7 1403166 = PB1S A 3523.8 12 11462.5 9584.8 3664.8 11921.0 9968.2 0.0 0.0 24349.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1057449 PLF2169 2876941 0.0 0.0 0.0 0.0 246.7 164.3 1638.9 670.9 491.0 0.0 = 326241 1235.4 9.0 0.90 4874.4 0.0 940 0.0 0.0 0.0 9.9 0 0.0 0.0 9772.4 11314.6 4952.8 101694.3 36804.5 30775.5 B73.9 382.5 7854.3 2842.6 2374.9 80.0 80.0 275.0 227.0 224,0 18,0 18.9 115.0 112.5 98,0 9849 342, S26 05 1986 1985 988 1986 1986 873.9 2842.6 2376.9 129.0 442.8 450.0 1002.8 TABLE F3 ESTIMATED INVESTMENT ANI PROJECTS NEAR HAINES ANI SKAGWAY» (DOLLAR AMOUNTS IN THOUSANIIS) ALASKA DESCRIPTION 1. PROJECT COST (PC)»1979 DOLLARS 2+ YEAR CONSTRUCTION BEGINS 3. PROJECT COST @ FRICE LEVELS OF YEAR CONSTRUCTION BEGINS 4. CONSTRUCTION FERIOL (YEARS) S. AVG. PROJECT COST FER YEAR @ PRICE LEVELS OF BEGINNING CONSTRUCTION YR. 6. PROJECT COST FER YEAR @ CURRENT YEAR PRICE LEVELS (X) YEAR YEAR YEAR YEAR YEAR YEAR AnNrunNe TOTAL 7+ INTEREST DURING CONSTRUCTION (N=LAST CONSTRUCTION YEAR# X=FC IN CONST YR @ CURRENT FRICE LEVELS YEAR N % X TIMES .000 YEAR N-1: X TIMES .090 YEAR N-2: X TIMES .188 YEAR N-33 X TIMES .295 YEAR N-43 X TIMES .412 YEAR N-Si X TIMES .539 TOTAL IDC 8. TOTAL INVESTMENT: PLUS IDC 9. ANNUAL AMORTIZATION COST (35 YEARS) PROJECT COSTS 10. ANNUAL OPERATION AND MAINTENANCE (O&M) COST, 1979 DOLLARS 11. ANNUAL REPLACEMENT COST, 1979 DOLLARS 12, TOTAL ANNUAL O&M ANID REPLACEMENT COSTS 13. YEAR OPERATION BEGINS 14. ANNUAL COST IN FIRST YEAR OF OFERATION AMORTIZATION O&M AND) REPLACEMENTS TOTAL COMBINED UPPER CHILKOOT UPPER CHILKOOT LAKE ANNUAL COST FOR ALTERNATIVE HYDROELECTRIC LAYERAS CREEK UPPER TEWEY LAKE REID FALLS CREEK SOOO IOI *ASSUMF'TIONS * x x GENERAL INFLATION 4%*% FUEL INFLATION INTEREST RATE oxe Ox SOOO OOO OOOO IE COMBINED COMBINED WEST CREEK GOAT LAKE GOAT LAKE 30943.0 1983 361989 3 12066.3 12066.3 12549.0 13050 ooonw ° ° ° Arh ooowuvo ne ne 4357.4 26313.0 1983 30782.5 3 10260.8 10260.8 10671.3 11098.1 ° ° ° ooo 32030.2 0.0 96064 1930.1 34920.7 3304.7 240.0 112.5 352.5 1986 3304.7 463.9 10164.9 3 3388.3 3388.3 71168.0 1984 86586.8 4 21646.7 21646.7 22512.6 23413.1 2434966 0.0 0.0 91921.9 0.0 2107.2 4234.6 6386.4 0.0 0.0 12728.2 104650.1 990366 275.0 124.0 399.0 1988 990366 567.9 10471.5 33064.9 3 11021.6 11021.6 11462.5 11921.0 oO. oO. Oo. eoo 37509.9 3549.8 227.0 115.0 342.0 1986 3549.8 450.0 23634.0 1983 27648.4 3 9216.1 31365.3 2968.3 224.0 112.5 336.5 1986 2968.3 442.8 MM exhibit G B Energy Costs for Area Power Plans 5 Percent Interest Rate TABLE Gi ENERGY FRODUCTION MIX» ANID ANNUAL COST FOR ELECTRIC ENERGY FRODUCED YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 AVERAGE COST PER HAINES WITH ALLITION OF UFFER CHILKOOT 1980 TO 2005 Loan FORECAST EXIST (MWH) HYDRO 7902.0 8180.0 8840.0 9143.0 10725.0 11075.0 11969.0 12348.0 12787.0 13210.0 13665.0 14416.6 15209.5 16046.0 16928.5 17859.6 18841.9 19878.2 20971.5 22124.9 23341.8 2462546 25980.0 27408.9 28916.4 30506.8 ecocoocoooooooooooooooooooco ecooocecece\|coocooooooooocoso ENERGY FPRODUCTION(MWH) 11936.4 12513.6 13090,.8 13665.0 14416.6 15209.5 16046.0 16928.5 17859.6 18841.9 19878.2 20813.6 21706.8 22600.0 23580.0 24560.0 25540.0 26520.0 27500.0 ecocoooocoo wewocoooocoooo s » ¢ N > - ao » N > » ao . 1045.6 1420.0 1868.9 2396.4 3006.8 6261.0 6261.0 6261.0 6261.0 6261.0 . an Nn an = ecocoococece|c|coeocoeoo$o eccooocoocoooocoooooooco$o 7902.0 8180.0 8840.0 9143.0 10725.0 11075.0 11969.0 12348.0 12787.0 13210.0 13665,.0 14416.6 15209.5 16046.0 16928.5 17859.6 18841.9 19878,.2 20971.5 22124.9 23341.8 2462546 25980.0 27408.9 28916.4 30506.8 KWH» FOR EXIST HYDRO 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 PRODUCTION COST FER KWH(CENTS) 0.00 7.80 6.00 0.00 8.24 6+36 0.00 8.70 6674 0.00 9.18 7AS 0.00 9.70 7.57 0.00 10.24 8.03 22.16 10,82 8.51 21.24 11.43 9.02 20.42 12.07 9.656 19.67 12.75 10.14 18.99 13.47 10.75 17.97 14.23 11.39 17,08 15.04 12.07 16.29 15.89 12.80 15.59 16.79 13.57 14.96 17.74 14.38 14,40 18.75 15.24 13.89 19.81 16.16 13.43 20.94 17.13 13.02 22.13 18.15 12.64 23.39 19.24 12.25 24.72 20.40 11.90 26.13 21.62 11.58 27.63 22.92 11.28 29.20 24.29 11.02 30.88 25.75 WEIGHT AVERAGE 6.37 6.80 7.31 Zia? 8.46 8699 21.58 20.91 20.24 19.61 18.99 18.15 17.36 16.60 15.88 15.19 14.54 13.92 13.49 13.19 12.98 12.78 12.67 12.67 12.77 12.98 EXIST HYDRO ecooocoo0ooooooocoocscoocooCOCOCCSCS ecoooooooocooocoocoooocoooos OOOO OOOO IK ANNUA' NEW HYDRO 2921.8 2956.5 2992.7 3030.3 xASSUMF'T IONS x * GENERAL INFLATION 4% * FUEL INFLATION * INTEREST RATE 62% Sik SOOO OK OK L. COSTS($1000) 66.0 0.0 esoooosoogoogooogo°o°oc oso ecooooocoooooocoooooccoso 9IS6D 2582.8 2582.4 2587.7 2589.9 2595.6 2617.3 2639.9 2663.4 2687.8 2713.2 2739.6 276761 2828.7 2917.9 3029.7 3146.9 3292.9 3472.8 3692.5 3958.6 TABLE G2 ENERGY FROLDIUCTION MIX» AVERAGE COST FER KWH» JOOS OKOK AND ANNUAL COST FOR ELECTRIC ENERGY FROLDIUCED FOR XASSUMPTIONS x HAINES WITH ADDITION OF DAYERAS CREEK %* GENERAL INFLATION 4% 1980 TO 2005 . * FUEL INFLATION 62% * INTEREST RATE Sx SIO IOI IO ORK FRODUCTION ENERGY FRODUCTION(MWH) COST FER KWH(CENTS) ANNUAL COSTS($1000) LOAD x MKT FORECAST EXIST NEW EXIST WEIGHT EXIST NEW YEAR (MWH) HYDRO HYDRO DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HYDRO DIESEL OTHER TOTAL 1980 7902.0 0.0 0.0 1641.0 6261.0 7902.0 0.00 0.00 7.80 6.00 6+37 0.0 0.0 128.0 375.7 503.7 1981 8180.0 0.0 0.0 1919.0 6261.0 8180.0 0.00 0.00 8.24 6.36 6.80 0.0 0.0 158.0 398.2 556.2 1982 8840.0 0.0 0.0 2579.0 6261.0 8840.0 0.00 0.00 8.70 6674 7-31 0.0 0.0 224.3 422.1 646.4 1983 9143.0 0.0 0.0 2882.0 6261.0 9143.0 0.00 0.00 9.18 7AS Ti7D 0.0 0.0 264.7 447.4 71261 1984 10725.0 0.0 0.0 4464.0 6261.0 10725.0 0.00 0.00 9.70 7.57 B.46 0.0 0.0 433.0 474.3 907.2 1985 11075.0 0.0 8625.0 2450.0 0.0 11075.0 0.00 9.66 10.24 8.03 La7e, 0.0 833.0 251.0 0.0 1084.0 1986 11969.0 0.0 8980.0 2989.0 0.0 11969.0 0.00 9.40 10.82 8.51 9676 0.0 844.4 323.4 0.0 1167.8 1987 12348.0 0.0 9335.0 3013.0 0.0 12348.0 0.00 9.17 11.43 9.02 972 0.0 856.3 344.3 0.0 1200.7 1988 12787.0 0.0 9690.0 3097.0 0.0 12787.0 0.00 8.96 12.07 9.656 9.72 0.0 868.7 373.9 0.0 1242.6 1989 13210.0 0.0 10045.0 3165.0 0.0 13210.0 0.00 8.78 12.75 10.14 9.73 0.0 881.6 403.6 0.0 1285.2 1990 13665.0 0.0 10400.0 3265.0 0.0 13665.0 0.00 8.61 13.47 10.75 Pa7e 0.0 895.0 439.69 0.0 1334.8 1991 14416.6 0.0 10892.5 352441 0.0 14416.6 0.00 8.34 14.23 11.39 9.78 0.0 908.9 501.6 0.0 1410.5 1992 15209.5 0.0 11385.0 3824.5 0.0 15209.5 0.00 8.11 15.04 12.07 9.85 0.0 923.3 575.1 0.0 1498.4 1993 16046.0 0.0 11877.5 4168.5 0.0 16046.0 0.00 7.90 15.89 12.80 9.98 0.0 938.4 662.3 0.0 1600.7 1994 16928.5 0.0 12370.0 4558-5 0.0 16928.5 0.00 7.71 16679 13.57 10.16 0.0 954.0 765.3 0.9 1719.3 1995 17859.6 0.0 12862.5 4997.1 0.0 17859.6 0.00 7.54 17.74 14.38 10.40 0.0 970.3 886.5 0.0 1856.8 1996 18841.9 0.0 13355.0 5486.9 0.0 18841.9 0.00 7.39 18.75 15.24 10.70 0.0 987.3 1028.6 0.0 2015.9 1997 19878.2 0.0 13847.5 6030.7 0.0 19878.2 0.00 7-26 19.81 16.16 11.07 0.0 1004.9 1194.8 0.0 2199.7 1998 20971.5 0.0 14340.0 6631.5 0.0 20971.5 0.00 17.13 11.50 0.0 1023.2 1388.5 0.0 2411.7 1999 22124.9 0.0 14832.5 7292.4 0.0 22124.9 0.00 18.15 Aste 0.0 1042.2 1613.8 0.0 2656.0 2000 23341.8 0.0 15325.0 8016.8 0.0 23341.8 0.00 6.93 23. 39 19.24 +58 0.0 1062.0 1875.1 0.0 2937.2 2001 24625.6 0.0 15802.5 8823.1 0.0 24625.6 0.00 6.85 24.72 20.40 i325 0.0 1082.6 2181.3 0.0 3264.0 2002 25980.0 0.0 16280.0 9700.0 0.0 25980.0 0.00 6.78 26.13 21.62 14.01 0.0 1104.1 2535.0 0.0 3639.1 2003 27408.9 0.0 16757.5 10651.4 0.0 27408.9 0.00 6672 27.63 22.92 14.85 0.0 1126.3 2942.6 0.0 4068.9 2004 28916.4 0.0 17235.0 11681.4 0.0 28916.4 0.00 6667 29.20 24.29 15.77 0.0 1149.5 3411.6 0.0 4561.1 2005 30506.8 0.0 17712.5 12794.3 0.0 30506.8 0.00 6.63 30.88 25.75 16.80 0.0 1173.6 3950.2 0.0 5123.9 TABLE G3 ENERGY FRODUCTION MIX» AVERAGE COST FER KWH» SOOOOOOOOIOIOKOKOCKOKKRK ANI' ANNUAL COST FOR ELECTRIC ENERGY FRODUCEL FOR *XASSUMF TIONS x SKAGWAY WITH ADDITION OF UPPER DEWEY %* GENERAL INFLATION 4% 1980 TO 2005 * FUEL INFLATION 6% * INTEREST RATE Sx SOOO CIO OKCCOK PRODUCTION ENERGY FRODUCTION(MWH) COST PER KWH(CENTS) ANNUAL COSTS($1000) LOAD MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST DIESEL OTHER TOTAL YEAR (MWH) HYDRO HYDRO [DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYIIRO 1980 6179.0 1500.0 0.0 4679.0 0.0 6179.0 1.67 0.00 7.80 0.00 6.31 25.0 365.0 0.0 390.0 1981 4274.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 0.00 8.24 0.00 5.95 26.0 228.5 0.0 254.5 1982 3672.0 1500.0 0.0 2172.0 0.0 3672.0 1.80 0.00 8.70 0.00 5.88 27.0 188.9 0.0 215.9 1983 3023.0 1500.0 0.0 1523.0 0.0 3023.0 1.87 0.00 9.18 0.00 5.56 28.1 139.9 0.0 168.0 1984 3200.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 0.00 9.70 0.00 6.07 29.2 164.9 0.0 194.1 1985 3374.0 1500.0 0.0 1874.0 0.0 3374.0 2.03 0.00 10.24 0.00 6.59 30.4 192.0 0.0 222.4 1986 3512.0 1500.0 1647.9 364.1 0.0 3512.0 2.11 48.97 10.82 0.00 25.00 31.6 39.4 0.0 877.9 1987 3692.0 1500.0 1767.1 424.9 0.0 3692.0 2.19 45.95 11.43 0.00 24.20 32.9 48.6 0.0 893.5 1988 3888.0 1500.0 1886.4 501.6 0.0 3888.0 2.28 43.33 12.07 0.00 23.46 34.2 60.5 0.0 912.2 1989 4086.0 1500.0 2005.7 580.3 0.0 4086.0 2.37 41.03 12.75 0.00 22.82 35.6 74.0 0.0 93266 1990 4292.0 1500.0 2125.0 667.0 0.0 4292.0 2.47 39.00 13.47 0.00 22.27 37.0 89.9 0.0 955.7 1991 4512.2 1500.0 2310.0 702.2 0.0 4512.2 2.57 36.14 14.23 0.00 21.57 38.5 99D 0.0 973.3 1992 4743.7 1500.0 2495.0 748.7 0.0 4743.7 2.67 33.71 15.04 0.00 20.95 40.0 112.6 0.0 99367 1993 4987.0 1500.0 2680.0 807.0 0.0 4987.0 2.78 31.63 15.89 0.00 20.40 41.6 128.2 0.0 1017.5 1994 5242.8 1500.0 2865.0 877.8 0.0 5242.8 2.89 29.82 16.79 0.00 19.93 43.3 147.4 0.0 1045.1 1995 5511.8 1500.0 3050.0 961.8 0.0 5511.8 3.00 28.25 17.74 0.00 19.54 45.0 170.6 0.0 1077.1 1996 5794.5 1500.0 3235.0 1059.5 0.0 5794.5 3.12 26.86 18.75 0.00 19,23 46.8 198.6 0.0 1114.3 1997 6091.8 1500.0 3420.0 1171.8 0.0 6091.8 3.25 25.63 19.81 0.00 19,00 48.7 876.5 232.2 0.0 1157.3 1998 6404.3 1500.0 3605.0 1299.3 0.0 6404.3 3-38 24.53 20.94 0.00 18.85 50.6 884.4 272.0 0.0 1207.1 1999 6732.9 1500.0 3790.0 1442.9 0.0 6732.9 3.51 23.55 22.13 0.00 18.78 52.7 892.7 319.3 0.0 1264.6 2000 7078.3 1500.0 3975.0 1603.3 0.0 7078.3 3.65 22.67 23.39 0.00 18.80 54.8 901.2 375.0 0.0 1331.0 2001 7441.4 1500.0 4252.5 1688.9 0.0 7441.4 3.80 21.40 24,72 0.00 18.61 57.0 910.2 417.5 0.0 1384.7 2002 7823.1 1500.0 4530.0 1793.1 0.0 7823.1 3.95 20.30 26.13 0.00 18.50 59.2 919.5 468.6 0.0 1447.3 2003 8224.4 1500.0 4807.5 1916.9 0.0 8224.4 4.11 19.33 27.63 0.00 18.49 61.6 929.1 529.6 0.0 1520.3 2004 8646.4 1500.0 S085.0 2061.4 0.0 8646.4 4.27 18.47 29.20 0.00 18.57 6461 939.62 602.0 0.0 1605.3 2005 9089.9 1500.0 5362.5 2227.4 0.0 9089.9 4.44 17.71 30.88 0.00 18.75 6646 GAP LG 687.7 0.0 1704.0 TABLE G4 ENERGY PRODUCTION MIX» AVERAGE COST FER KWH» JOO OOOO ACK ANI) ANNUAL COST FOR ELECTRIC ENERGY FROLDIUCED FOR XASSUMF' TIONS x SKAGWAY WITH ADDITION OF REIL FALLS %* GENERAL INFLATION 4% 1980 TO 2005 . * FUEL INFLATION 6% * INTEREST RATE Sx JAI CIO IK PRODUCTION ENERGY FRODUCTION(MWH) COST FER KWH(CENTS) ANNUAL COSTS($1000) LOAL FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR (MWH) HYDRO HYDRO DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HYDRO DIESEL OTHER TOTAL 1980 6179.0 1500.0 0.0 4679.0 0.0 6179.0 1.67 0.00 7.80 0.00 6-31 25.0 0.0 365.0 0.0 390.0 1981 4274.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 0.00 8.24 0.00 S695 26.0 0.0 228.5 0.0 254.5 1982 3672.0 1500.0 0.0 2172.0 0.0 3672.0 1.80 0.00 8.70 0.00 5.88 27.0 0.0 188.9 0.0 215.9 1983 3023.0 1500.0 0.0 1523.0 0.0 3023.0 1.87 0.00 9.18 0.00 5-56 28.1 0.0 139.9 0.0 168.0 1984 3200.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 0.00 9.70 0.00 6.07 29.2 0.0 164.9 0.0 194.1 1985 3374.0 1500.0 1353.6 520.4 0.0 3374.0 2.03 31.38 10.24 0.00 15.07 30.4 424.8 53.3 0.0 508.5 1986 3512.0 1500.0 1472.9 S39.1 0.0 3512.0 2.11 29,18 10.82 0.00 14.80 31.6 429.8 58.3 0.0 519.7 1987 3692.0 1500.0 1592.1 S999 0.0 3692.0 2.19 27.32 11.43 0.00 14.53 32.9 435.0 68.6 0.0 536.4 1988 3888.0 1500.0 1711.4 676.6 0.0 3888.0 2.28 25.73 12.07 0.00 14.31 34.2 440.4 81.7 0.0 556.3 1989 4086.0 1500.0 1830.7 755.3 0.0 4086.0 2637 24.36 12.75 0.00 14.14 35.6 446.0 96.3 0.0 577.9 1990 4292.0 1500.0 1950.0 842.0 0.0 4292.0 2-47 23.17 13.47 0-00 14.03 37.0 451.9 113.4 0.0 602.3 1991 4512.2 1500.0 2125.0 887.2 0.0 4512.2 2.57 21.55 14.23 0.00 13.80 38.5 458.0 126.3 0.0 622.7 1992 4743.7 1500.0 2300.0 94367 0.0 4743.7 2+67 20.19 15.04 0.00 13.62 40.0 464.3 141.9 0.0 646.2 1993 4987.0 1500.0 2475.0 1012.0 0.0 4987.0 2.78 19.03 15.89 0.00 13.50 41.6 470.9 160.8 0.0 673.3 1994 5242.8 1500.0 2650.0 1092.8 0.0 5242.8 2.89 18.03 16.79 0.00 13.44 43.3 477.7 183.5 0.0 704.5 1995 5511.8 1500.0 2825.0 1186.8 0.0 5511.8 3.00 17.16 17.74 0.00 13.43 45.0 484.8 210.5 0.0 740.4 1996 5794.5 1500.0 3000.0 1294.5 0.0 5794.5 3.12 16.41 18.75 0.00 13.49 46.8 492.3 242.7 0.0 781.8 1997 6091.8 1500.0 3175.0 1416.8 0.0 6091.8 3.25 15.75 19.81 0.00 13.61 48.7 500.0 280.7 0.0 829.4 1998 6404.3 1500.0 3350.0 1554.3 0.0 6404.3 3-38 15.16 20.94 0.00 13.80 50.6 508.0 325.4 0.0 884.1 1999 6732.9 1500.0 3525.0 1707.9 0.0 6732.9 3.51 14.65 22.13 0.00 14.06 52.7 516.3 378.0 0.0 P4669 2000 7078.3 1500.0 3700.0 1878.3 0.0 7078.3 3465 14.19 23.39 0.00 14.40 54.8 525.0 439.3 0.0 1019.1 2001 7441.4 1500.0 3935.0 2006.4 0.0 7441.4 3.80 13.57 24,72 0.00 14.61 57.0 534.0 496.0 0.0 1087.0 2002 7823.1 1500.0 4170.0 2153.1 0.0 7823.1 3.95 13.03 26.13 0.00 14.90 59.2 543.4 562.7 0.0 1165.3 2003 8224.4 1500.0 4405.0 2319.4 0.0 8224.4 4.11 12.56 27.63 0.00 15.27 61.6 SS3.1 640.8 0.0 1255.5 2004 8646.4 1500.0 4640.0 2506.4 0.0 8646.4 4.27 12.14 29.20 0.00 15.72 64.1 563.3 732.0 0.0 1359.3 2005 9089.9 1500.0 4875.0 2714.9 0.0 9089.9 4.44 11.77 30.88 0.00 16.27 6666 573.8 838.2 0.0 1478.7 TABLE GS YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 19792 1992 1993 1994 1995 1996 1997 1998 L999 2000 2001 2002 2003 2004 2005 ANT ENERGY PRODUCTION MIX» AVERAGE COST FER KWH» ANNUAL COST FOR ELECTRIC ENERGY FRODUCEL FOR COMBINED WITH ADDITION OF WEST CREEK 1980 TO 2005 LOAL FORECAST EXIST (MWH) 14081.0 12454.0 12512.0 12166.0 13925.0 14449.0 15481.0 16040.0 16675.0 17296.0 17957.0 18928.8 19953.2 21033.0 22171.3 23371.4 24636.4 25970.0 27375.8 28857.8 30420.1 32067.0 33803.1 35633.3 37562.8 39596+7 HYDRO 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 "1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 ENERGY PRODUCTION(MWH) ecooocoo°o ecocooooooco 5 15796.0 16457.0 17428.8 18453.2 19533.0 20671.3 21871.4 23136.4 24470.0 25875.8 27357.8 28920.1 30567.0 32303.1 34133.3 36062.8 38096.7 GY pony N an ~ 6320.0 4693.0 4751.0 4405.0 eccooooooooooocoocoo eccoocoooooooooooo OTHER 6261.0 6261.0 6261.0 6261.0 6261.0 0 14449.0 6261.0 6261 6261 o oo o ° eccoooooooocoocoooo ecooooooocoooocooco TOTAL 14081.0 12454.0 12512.0 12166.0 13925.0 15481.0 16040.0 16675.0 17296.0 17957.0 18928.8 19953.2 21033.0 22171.3 23371.4 24636.4 25970.0 27375.8 28857.8 30420.1 320670 33803.1 35633.3 37562.8 3959667 PRODUCTION COST PER KWH(CENTS) MKT NEW HYDRO 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 43.51 41.94 40.40 38.29 36.30 34.43 32.67 31.01 29.44 27.96 26.57 25.25 24.01 22.84 21.73 20.68 19.68 18.74 7.80 8.24 8.70 9.18 9.70 10.24 10,82 11.43 12.07 12.75 13.47 14.23 15.04 15.89 16.79 17.74 18.75 19.81 20.94 22.13 23.39 24.72 26.13 27.63 29.20 30.88 6.00 6+36 6474 71S 7.57 8.03 8.51 9.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 WEIGHT ANNUAI OOOO IOK *XASSUMPTIONS * x GENERAL INFLATION 4% %* FUEL INFLATION 6% * INTEREST RATE Sx SOOO II IOK LL COSTS($1000) EXIST AVERAGE HYDRO 6.35 6.51 6.89 7.23 7691 8.43 9.04 9.63 39.80 38,51 37.23 35.46 33.77 32.17 30.65 29.21 27.84 26.54 25.30 24.12 23.01 21.95 20.94 19.98 19.07 18.20 ecocoooooco nNnuwocooooocoo aa aa no an 6648.9 6673.4 6699.0 6725.6 6753.2 6781.9 6811.8 6842.9 6875.3 6908.9 6943.9 6980.2 7018.0 7057.4 7098.3 7140.8 493.0 375.7 893.6 386.5 398.2 810.7 413.2 422.1 862.3 404.6 447.4 880.1 597.8 474.3 1101.4 685.1 502.7 1218.3 835.2 532.9 1399.7 94661 564.9 1543.9 6711.9 6739.0 6767.2 679665 6827.0 6858.7 6891.46 6925.9 696146 699866 7037.2 7077.3 7119.0 7162.4 7207.5 ecooooooooooocoooocoe ecocooocoooooooocoooo ecocoocoooooooocooocoo ecooocooocoooooooo TABLE G6 ENERGY FRODUCTION MIX» AVERAGE COST FER KWH» YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Lee. 1992 1993 1994 1995 1996 L297: 1998 Leos. 2000 2001 2002 2003 2004 2005 AND ANNUAL COST FOR ELECTRIC ENERGY FRODUCELD FOR COMBINED WITH ADDITION OF GOAT LAKE 1980 TO 2005 PRODUCTION ENERGY FRODIUCTION(MWH) COST PER KWH(CENTS) LOAD MKT MKT FORECAST EXIST NEW EXIST NEW (MWH) HYDRO HYDRO DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER 6320.0 6261.0 14081.0 1.67 0.00 7.80 6.00 4693.0 6261.0 12454.0 1.73 0.00 8.24 6.36 14081.0 1500.0 ° ° O 4751.0 6261.0 12512.0 1.80 0.00 8.70 6474 ° ° ° ° 12454.0 1500.0 ° 12512.0 1500.0 ° ° 4405.0 6261.0 12166.0 1.87 0.00 9.18 7.15 ° 6164.0 6261.0 13925.0 1.95 0.00 9.70 7.57 ° 6688.0 6261.0 14449,0 2.03 0.00 10.24 8.03 12166.0 1500.0 13925.0 1500.0 14449.0 1500.0 15481.0 1500.0 13981.0 0.0 0.0 15481.0 2.11 18.99 10.82 0.00 16040,0 1500.0 14540.0 0.0 0.0 16040.0 2.19 18.39 11,43 0.00 16675.0 1500.0 15175.0 0.0 0.0 16675.0 2.28 17.74 12.07 0.00 17296.0 1500.0 15796.0 0.0 0.0 17296.0 2637 17.17 12.75 0.00 17957.0 1500.0 16457.0 0.0 0.0 17957.0 2.47 16.60 13.47 0.00 18928.8 1500.0 17428.8 0.0 0.0 18928.8 2.57 15.79 14.23 0.00 19953.2 1500.0 18453.0 0.2 0.0 19953.2 2+67 15.04 15.04 0.00 21033.0 1500.0 19533.0 0.0 0.0 21033.0 2.78 14.32 15.89 0.00 22171.3 1500.0 20671.0 0.3 0.0 22171.3 2.89 13.65 16.79 0.00 23371.4 1500.0 21871.0 0.4 0.0 23371.4 3.00 13.01 17.474 0.00 24636.4 1500.0 23136.0 0.4 0.0 2463644 3.12 12.41 18.75 0.00 25970.0 1500.0 24071.0 399.0 0.0 25970.0 3.25 12.04 19.81 0.00 27375.8 1500.0 25006.0 869.8 0.0 27375.8 3-38 11.70 20.94 0.00 28857.8 1500.0 25904,.0 1453.8 0.0 28857.8 3.51 11.41 22.13 0.00 30420.1 1500.0 26875.0 2045.1 0.0 30420.1 3.65 11.11 23.39 0.00 32067.0 1500.0 27958.0 2609.0 0.0 32067.0 3.80 10.79 24.72 0.00 33803.1 1500.0 29040.0 3263.1 0.0 33803.1 3.95 10.50 26.13 0.00 35633.3 1500.0 30123.0 4010.3 0.0 35633.3 4.11 10.23 27.63 0.00 37562.8 1500.0 31205.0 4857.8 0.0 37562.8 4.27 9.99 29.20 0.00 39596.7 1500.0 32288.0 5808.7 0-0 3959647 4.44 9.77 30.88 0.00 WEIGHT ANNUAI FAO OOOO II K *ASSUMP TIONS x %* GENERAL INFLATION 4% %* FUEL INFLATION 6%% %* INTEREST RATE Sx SOOO IOI OK IOI OK iL COSTS($1000) EXIST AVERAGE HYDRO 6.35 6.51 6.89 7.23 7691 8.43 17.36 16.87 16.35 15.88 15.42 14.75 14.11 13.50 12.92 12.37 11.85 11.65 11.54 11.54 11.56 11.59 11.72 11.93 12.25 12.66 25.0 26.0 27.0 28.1 29.2 30.4 31.6 32.9 34.2 35.66 37.0 38.5 40.0 41.6 43.3 45.0 46.8 48.7 50.6 52.7 54.8 57.0 59.2 61.6 64.1 66.6 ececoocoo noocoooceo h an a a 2673.2 2691.9 2711.4 2731.7 2752.7 2774.6 2797.4 2821.1 2845.7 2871.4 2898.0 2925.7 2954.5 2984.5 3015.7 3048.1 3081.8 3116.9 3153.4 493.0 375.7 893.6 386.5 398.2 810.7 413.2 422.1 862.3 404.6 447.4 880.1 597.8 474.3 1101.4 685.1 502.7 1218.3 0.0 0.0 2686.9 0.0 0-0 2706-41 0.0 0.0 2726.2 0.0 0.0 2747.0 0.0 0.0 2768.7 0.0 0.0 2791.2 0.0 0.0 2814.7 0.0 0.0 2839.0 O.1 0.0 2864.4 O.1 0.0 2890.8 O.1 0.0 2918.3 790 0.0 3025.8 182.1 0.0 3158.5 321.7 0.0 3328.9 478.3 0.0 3517.6 645.0 0.0 3717.7 852.8 0.0 3960.1 1107.9 0.0 4251.3 1418.7 0.9 4599.7 1793.4 0.0 5013.4 TABLE G7 YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 ENERGY PRODUCTION MIX» AVERAGE COST FER KWH» AND ANNUAL COST FOR ELECTRIC ENERGY FRODUCED FOR COMBINED WITH ADDITION OF UPPER CHILKOOT 1980 TO 2005 ENERGY LOAD MKT FORECAST EXIST NEW (MWH) HYDRO HYDRO 14081.0 1500.0 ° 12454.0 1500.0 ° 12512.0 1500.0 ° 12166.0 1500.0 ° 13925.0 1500.0 ° 14449.0 1500.0 ° 15481.0 1500.0 13981.0 16040.0 1500.0 14540.0 16675.0 1500.0 15175.0 17296.0 1500.0 15796.0 17957.0 1500.0 16457.0 18928.8 1500.0 17428.8 19953.2 1500.0 18453.0 21033.0 1500.0 19318.0 22171.3 1500.0 20183.0 23371.4 1500.0 21049.0 24636.4 1500.0 21914.0 25970.0 1500.0 22779.0 27375.8 1500.0 22644.0 28857.8 1500.0 24510.0 30420.1 1500.0 25375.0 32067.0 1500.0 26525.0 33803.1 1500.0 27675.0 35633.3 1500.0 28825.0 37562.8 1500.0 29975.0 39596.7 1500.0 31125.0 PRODUCTION(MWH) 3231.8 2847.8 3545.1 4042.0 4628.1 5308.3 6087.8 6971.7 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 ecoooocooooocooocococo ecocoocoooooooooooocooeocoo EXIST TOTAL HYDRO 14081.0 1.67 12454.0 1.73 12512.0 1.80 12166.0 1.87 13925.0 1.95 14449.0 2.03 15481.0 Sead 16040.0 2.19 16675.0 2.28 17296.0 2.37 17957.0 2.47 18928.8 2.57 19953.2 2.67 21033.0 2.78 22171.3 2.89 23371.4 3.00 2463664 3.12 25970.0 3.25 27375.8 3.38 28857.8 3.51 30420.1 3.65 32067.0 3.80 33803.1 3.95 3563343 4.11 37562.8 4.27 3959667 4.44 PRODUCTION COST FER KWH(CENTS) NEW HYDRO DIESEL OTHER AVERAGE 0.00 0.00 0.00 0.00 0.00 0.00 20.64 19.97 19.27 18.64 18.02 17.14 16.31 15.71 15.16 14.65 14.20 13.78 13.99 13.05 12.73 12,30 Tie Ft 11.56 11.24 10.95 7.80 8.24 8.70 9.18 9.70 10.24 10.82 11.43 12.07 12.75 13.47 14.23 15.04 15.89 16.79 17.74 18.75 19.81 20.94 22.13 23.39 24.72 26.13 27.63 29.20 30.88 6.00 6.36 6.74 7.AS 7.57 8.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 WEIGHT 6.35 6.51 6.89 723 7.91 8.43 18.84 18.31 17.74 1723 16.72 15.99 15.29 14.79 14.36 14,02 13.75 13557 14,23 13.45 13.52 13.47 13.51 13.64 13.87 14.21 EXIST HYDRO 25.0 26.0 27.0 28.1 29.2 30.4 31.6 32.9 34.2 35.46 37.0 38.5 40.0 41.6 43.3 45.0 46.8 48.7 50.6 52.7 54.8 57.0 59.2 61.46 64.1 6666 SOOO IK XASSUMP TIONS * GENERAL INFLATION 4% * FUEL INFLATION * INTEREST RATE SOOO OO OOO ORK ANNUAL COSTS($1000) 3084.7 3111.5 3139.4 3168.4 3198.6 3230.0 3262.6 3296.6 3331.9 3368.6 3406.7 w 0 0 0 ° 0 0 ° 4 2 onoooocoo ao 145.9 229.2 335.0 67667 630.2 829.2 999.3 1209.5 1466.5 1777.9 2152.5 37567 398.2 422.1 447.4 > N > 5 ° ececcoooooooooooooooooon cecocoooooooo ooo ooooCOoOoOONW x 6% S%* 3387.5 3523.2 3895.8 3881.5 4114.0 4318.9 4565.3 4859.9 5210.6 5625.9 TABLE G8 ENERGY FRONUCTION MIX» AVERAGE COST FER KWH» YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 L989 1990 L991 1992 1993 1994 1995; 1996 L997 1998 1999, 2000 oo1 002 2003 2004 2005 ANI) ANNUAL COST FOR ELECTRIC ENERGY FRODUCED FOR HAINES ASSUMING NO ALDLITIONAL HYDRO 1980 TO 2005 ENERGY PRODUCTION (MWH) LOAD MKT FORECAST EXIST NEW (MWH) HYDRO HYDRO DIESEL OTHER 7902.0 0.0 0.0 1641.0 6261.0 8180.0 0.0 0.0 1919.0 6261.0 8840.0 0.0 0.0 2579.0 6261.0 9143.0 0.0 0.0 2882.0 6261.0 10725.0 0.0 0.0 4464.0 6261.0 11075.0 0.0 0.0 4814.0 6261.0 11969.0 0.0 0.0 S708.0 6261.0 12348.0 0.0 0.0 6087.0 6261.0 12787.0 0.0 0-0 6526.0 6261.0 13210.0 0.0 0.0 6949.0 6261.0 13665.0 0.0 0.0 7404.0 6261.0 1441646 0.0 0.0 8155.6 6261.0 15209.5 0.0 0.0 8948.5 6261.0 16046.0 0.0 0.0 9785.0 6261.0 16928,.5 0.0 0.0 10667.5 6261.0 1785946 0.0 0-0 115986 6261.0 18841.9 0.0 0.0 12580.9 6261.0 19878.2 0.0 0.0 13617.2 6261.0 20971.5 0.0 0.0 14710.5 6261.0 22124.9 0.0 0.0 15863.9 6261.0 23341.8 0.0 0.0 23341.8 0.0 2462546 0.0 0.0 24625.6 0.0 25980.0 0.0 0.0 25980.0 0.0 27408.9 0.0 0.0 27408.9 0.0 2891664 0.0 0.0 28916.4 0.0 30506.8 0.0 0.0 30506.8 0.0 TOTAL 7902.0 8180.0 8840.0 9143.0 10725.0 11075.0 11969.0 12348.0 12787.0 13210,.0 13665.0 14416.6 15209.5 16046.0 16928.5 1785946 18841.9 19878.2 20971.5 22124.9 23341.8 24625.6 25980.0 27408.9 28916.4 30506.8 EXIST HYDRO 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0-00 0.00 0.00 PRODUCTION COST PER KWH(CENTS) HYDRO 0.00 0.00 0.00 0.00 0.00 0.00 0-00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 DIESEL 7.80 8.24 8.70 9.18 9.70 10.24 10,82 11.43 12.07 12.75 13.47 14.23 15.04 15.89 16.79 17.74 18.75 19.81 20.94 22.13 23.39 24.72 26.13 29.20 30.88 OTHER 6.00 6436 6474 7.15 7.57 8.03 8.51 9.02 9.56 10.14 10.75 11.39 12.07 12.80 13.57 14.38 15.24 16.16 17.13 18.15 0.00 0.00 0.00 0.00 0.00 0.00 WEIGHT AVERAGE 64637 6-80 731 7+79 B46 8.99 961 10.21 10.84 11,51 i 2 13.00 13.82 14.68 15.60 16.56 17.58 18.64 19.80 21.00 23.39 24.72 26.13 27.63 29.20 30,88 EXIST HYDRO HYDRO ecoccoooococoococece|ceceooc“eoceceof] ecoooocoooooococoeocoooccooso cooocoooooocococococoooocoo oeocoooooocooocooocoocooococococe SRO OOO OOK K *XASSUMF TIONS x * GENERAL INFLATION 42% * FUEL INFLATION EL * INTEREST RATE Sak AAO OOK ANNUAL COSTS($1000) DIESEL OTHER TOTAL 128.0 375.7 503.7 158.0 398.2 556.2 224.3 422.1 646.4 264.47 447.4 712.1 433.0 474.3 907.2 A931 502.7 99569 617.5 $32.9 1150.4 69566 564.9 1260.5 787.8 598.7 1386.6 886.1 634.7 1520.8 99765 672+7 1670-2 1160.8 713.1 1873.9 1345.6 755.9 2101.5 1554.6 801.3 2355.9 1790.9 849.3 2640.2 2057.6 900.3 2957.9 2358.5 954.3 3312.8 2697.8 1011.6 3709.4 3080.1 1072.3 4152.3 3510.7 1136.6 4647.3 545966 0.0 5459.6 6088.2 0.0 6088.2 6789.6 0.0 6789.6 7572.0 0.0 7572.0 8445.0 0.0 8445.0 9419.0 0.0 9419.0 TABLE Ge ENERGY PRODUCTION MIXs AVERAGE COST FER KWH» SOOO OOK ANDI ANNUAL COST FOR ELECTRIC ENERGY FRODIUCED FOR XASSUMF'T IONS x SKAGWAY ASSUMING NO ADDITIONAL HYLIRO * GENERAL INFLATION 4% 1980 TO 2005 * FUEL INFLATION 62% * INTEREST RATE S%x* SOOO OOK OK FRODUCTION ENERGY FRODUCTION(MWH) COST PER KWH(CENTS) ANNUAL COSTS($1000) LOAD MKT MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR (MWH) HYDRO HYDRO DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HYDRO DIESEL OTHER TOTAL 1980 6179.0 1500.0 0.0 4679.0 0.0 6179.0 1.67 0.00 7.80 0.00 6.31 25.0 0.0 365.0 0.0 390.0 1981 4274.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 0.00 8.24 0.00 5.95 26.0 0.0 228.5 0.0 254.5 1982 3672.0 1500.0 0.0 2172.0 0.0 3672.0 1.80 0.00 8.70 0.00 5.88 27.0 0.0 188.9 0.0 215.9 1983 3023.0 1500.0 0.0 1523.0 0.0 3023.0 1.87 0.00 9.18 0.00 S656 28.1 0.0 139.9 0.0 168.0 1984 3200.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 0.00 9.70 0.00 6.07 29.2 0.0 164.9 0.0 194.1 1985 3374.0 1500.0 0.0 1874.0 0.0 3374.0 2.03 0.00 10.24 0.00 6659 30.4 0.0 192.0 0.0 222.4 1986 3512.0 1500.0 0.0 2012.0 0.0 3512.0 2.11 0.00 10.82 0.00 710 31.66 0.0 217.7 0.0 249.3 1987 3692.0 1500.0 0.0 2192.0 0.0 3692.0 2.19 0.00 11.43 0.00 7+68 32.9 0.0 250.5 0.0 283.4 1988 3888.0 1500.0 0.0 2388.0 0.0 3888.0 2.28 0.00 12.07 0.00 8.29 34.2 0.0 288.3 9.0 322.5 1989 4086.0 1500.0 0.0 2586.0 0.0 4086.0 2.37 0.00 12.75 0.00 B.94 35.6 0.0 329.8 0.0 365.3 1990 4292.0 1500.0 0.0 2792.0 0.0 4292.0 2.47 0.00 13.47 0.00 9.63 37.0 0.0 376.1 0.0 413.1 1991. 4512.2 1500.0 0.0 3012.2 0.0 4512.2 2457 0.00 14,23 0.00 10.35 38.5 0.0 428.7 0.0 467.2 1992 4743.7 1500.0 0.0 3243.7 0.0 4743.7 2467 0.00 15.04 0.00 11.13 40.0 0.0 487.8 0.0 527.8 1993 4987.0 1500.0 0.0 3487.0 0.0 4987.0 2.78 0.00 15.89 0.00 11.94 41.6 0.0 554.0 0.0 59566 1994 5242.8 1500.0 0.0 3742.8 0.0 5242.8 2.89 0.00 16.79 0.00 12,81 43.3 0.0 628.3 0.0 671.6 1995 5511.8 1500.0 0.0 4011.8 0.0 5511.8 3.00 0.00 17.74 0.00 13.73 45.0 0.0 7idieZ 0.0 756.7 1996 5794.5 1500.0 0.0 4294.5 0.0 5794.5 3.12 0.00 18.75 0.00 14.70 46.8 0.0 805.1 0.0 851.9 1997 6091.8 1500.0 0.0 4591.8 0.0 6091.8 3.25 0.00 19.81 0.00 15.73 48.7 0.0 909.7 0.0 958.4 1998 6404.3 1500.0 0-0 4904.3 0-0 6404.3 3.38 0.00 20,94 0.00 16.82 50.6 0.0 1026.9 0.0 1077.5 1999 6732.9 1500.0 0.0 5232.9 0.0 6732.9 3.51 0.00 22.13 0.00 17.98 52.7 0.0 1158.0 0.0 1210.7 2000 7078.3 1500.0 0.0 5578.3 0.0 7078.3 3.65 0.00 23.39 0.00 19,21 54.8 0.0 1304.8 0.0 1359.5 2001 7441.4 1500.0 0-0 S941.4 0.0 7441.4 3.80 0.00 24.72 0.00 20.51 57.0 0.0 1468.9 0.0 1525.9 2002 7823.1 1500.0 0.0. 6323.1 0.0 7823.1 3695 0.00 26.13 0.00 21.88 S962 0.0 1652.5 0.0 1711.7 2003 8224.4 1500.0 0.0 6724.4 0.0 8224.4 4.11 0.00 27.63 0.00 23.34 6146 0.0 1857.7 0.0 1919.3 2004 8646.4 1500.0 0.0 7146.4 0.0 8646.4 4.27 0.00 29.20 0.00 24.88 64.1 0.0 2087.1 0.0 2151.2 2005 7089.7 1500.0 0-0 7589.9 0.0 9089.9 4.44 0.00 30.88 0.00 26.51 6646 0.0 2343.4 0.0 2410.0 Exhibit H Energy Costs for Area Power Plans 7 Percent Interest Rate TABLE Hil ENERGY FRODUCTION MIX, AVERAGE COST PER Filiiy SOR OOO E AND ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR ASSUMPTIONS HAINES WITH ADDITION OF UPPER CHILKCOT * GENERAL INFLATION 1980 TO 2005 * FUEL INFLATIGN * INTEREST RATE SOOO FORK PRODUCTION COST FER KWH(CENTS) ANNUAL COSTS($1000) ENERGY PRODUCTION (MWH) LOA MKT MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR (MWH) HYDRO HYDRO DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HYDRO DIESEL OTHER TOTAL 1980 7902.0 0.0 0.0 1641.0 6261.0 7902.0 0.00 7.80 1981 8180.0 0.0 0.0 1919.0 6261.0 8180.0 0.00 8.24 1982 8840.0 0.0 0.0 2579.0 6261,0 8840.0 0.90 8.70 1983 9143.0 0.0 0.0 2882.0 6261.0 9143.0 0,00 9.18 1984 10725.0 0.0 0.0 4464.0 6261,0 10725.0 9.00 9.70 3985 11075.0 0.0 O.0 4814.0 6261.0 11075.0 0.00 10.24 1986 11969.0 0.0 11359.2 609.8 0.0 11969.0 0.00 10.82 1987 12348,0 0.0 11936.4 411.6 340 48.0 9.09 11.43 $988 12787.0 0.0 12513.6 273.4 0.0 12787.0 0.00 12.07 3181. 1989 13210.0 0.0 13090.8 Uo 2 0.0 13210.0 9.00 12.75 $284.3 1990 13665.0 0.0 13665.0 9.0 0.0 13665.0 0.00 13.47 3139,0 L991 14416.6 0,0 14416.6 0.0 0.0 144146.6 0.00 14.23 10.7 1992 15209.5 0.0 15209.5 0.0 0.0 15209.5 0.00 15.04 BS od 1993 16046.0 0.0 16046.0 0.0 0.0 16046.0 0,00 15.89 4.8 1994 16928.5 0.0 16928.5 0.0 0.0 16928.5 0.00 16.79 81.2 1995 17859.6 0.0 17859.6 0.0 0.0 17859.4 0.00 17.74 0664 1996 18841.9 0.0 18841.9 0.0 0.0 18841.9 0,00 18.75 0.9 1997 19878.2 0.0 19878.2 0.90 0.0 19878.2 0.00 19.81 9.0 1998 20971.5 0.0 20813.6 157.9 0.0 20971.5 0.00 20.94 0.0 LOOD 2212459 0.0 21706.8 418.1 0.0 22124.9 0.00 22.13 0.0 2000 23341.8 0.0 600.0 741.8 6.0 41.8 0.00 23.39 0.0 2001 24625.6 0.0 23580.0 1045.6 0.0 24625.4 0.00 24.72 0.0 2002 25980.0 0.0 24560.0 1420.0 0.0 25980.0 0.00 26.13 0.0 2003 27408.9 0.0 25540.0 1848.9 0.0 27408.9 0.00 27.63 0.0 2004 28916.4 0.0 26520.0 2396.4 0.0 28915.4 0.00 29.20 0,0 2005 30506.8 0.0 27500.0 3006.8 0.0 30506.8 0,90 30.88 9.0 ANT ANNUAL COST FOR ELE IC ENERGY PRODUCED HAINES WITH ADDITION OF DAYEBAS CREEK 1980 TO 2005 LOAT ORECAST EXIST HY DIR CMWH) 1980 7902.0 1981 8180.0 L982 8840.0 1983 9143.0 1984 10725.0 1985 11075,0 1986 117469,0 1987 12348,0 1988 12787.0 1989 13210.0 1990 13665.0 1991 14416.6 15209.8 14046.0 16 Ss 17859.6 18841.9 ENERGY PRODUCTION MIX» AVERAGE COST PER KWH» TION CMWH > TOTAL 0.0 0.0 1641,0 790250 9.0 0.0 1919.0 8180.0 0.0 0.0 2579.0 Bea, Qo 0.0 0.0 2882.0 ) 0.0 0.0 4464.0 + S60 2450.0 298940 0.0 9335.0 3013.0 0.0 9690.0 3097.0 12787, 0.0 19045.0 3165.0 13210 1346 0.90 oe 9 144146.6 15209.5 0.0 16044,.6 0,0 12370.0 0.0 12862.5 0.0 13355.0 18841,9 0.0 123847.5 19876.2 0.0 ae 2 Oo 0 10651, 4 11681.4 ‘ 12794,3 0.0 30506.8 FOR PRODUCTION MKT EXIST NEW HYDRA HYDRO OTHER 6.00 6436 6.74 FAS Dea? B03 8.51 9,02 9656 10.14 16475 11.39 2.07 2.80 13.57 14,38 15.24 16.16 17413 18.15 19,24 3440 662 Ee PER RW CEEN DS) HY Leo FOO OOK AR OK AC *ASSUMP TIONS * * GENERAL INFLATION 4%% * FUEL INFLATION En * INTEREST RATE Tak SOIR RAKE ANNUAL ay Teme0e2) HAT ST NEW Hert NIESEL omer 9.0 0.0 0.0 0.0 0.90 0.0 984.4 0.0 1007.7 C,0 1020.1 1033.9 1046.3 TABLE H3 ENERGY PRODUCTION MIX» AVERAGE COST FER KWH» SOI III OOK AND ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR ASSUMPTIONS * SKAGWAY WITH ADDITION OF UPPER DEWEY * GENERAL INFLATION 4%x% 1980 TO 2005 * FU INFLATION 6k * INTEREST RATE 72k SOO AOK PRODUCTION ENERGY FRODUCTION(MWH) COST PER KWH(CENTS) ANNUAL COSTS($1000) LOAD MKT MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR CMWH > HYDRO HYDRO DTESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HY TRG DIESEL OTHER TOTAL 1980 6179.0 1500.0 0.0 4679.0 0.0 6179.0 1.67 0.00 7.80 0.00 6.31 25.0 0.0 365.0 0.0 390.0 1981 4274.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 0.00 8.24 0.00 5.95 26.0 0.0 228.5 0.0 254.5 1982 3672.0 1500.0 0.0 2172.0 0.0 3672.0 1.80 0.00 8.70 0.00 5.88 27.0 0.0 188.9 0.0 215.9 1983 3023.0 1500.0 0.0 1523.0 0.0 3023.0 1.87 0.00 9.18 G.00 S656 2861 0.0 139.9 0.0 168.0 1984 3200.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 0.00 9.70 0.00 6.07 ey ia 0.0 164.9 0.0 194.1 1985 3374.0 1500.0 0.0 1874.0 0.0 3374.0 2.03 0.00 2 0.00 6659 30.4 0.0 192.9 0.0 222.4 1986 3512.0 1500.0 1647.9 36461 0.0 3512.0 2-11 60.86 0.00 30.58 31.6 1002.8 39.4 6.0 1073.9 1987 3692.0 1500.0 1767.1 424.9 0.0 3692.90 19 57.04 0.00 29.51 32.9 1608.0 48.6 0.9 1089.4 1988 3888.0 1500.0 1886.4 501.6 0.0 3888.0 2.2 53.72 0.00 28,50 34.2 1013.4 60.5 0.0 1108.1 1989 4086.0 1500.0 2005.7 580.3 0.0 4086.0 2.37 50.80 6.00 27.62 35.6 1018.9 74.9 0.0 1128.5 1990 4292.0 1500.0 2125.0 667.0 0.0 4292.0 2.47 48.22 0.00 26.83 37.0 1024.7 89.9 0.0 1151.6 1991 4512.2 1500.0 2310.0 702.2 0.0 4512.2 2.57 44.62 9.00 25.91 38.5 1030.8 9967 0.0 1169.2 1992 4743.7 1500.0 2495.0 748.7. 0.0 4743.7 2-667 41.56 0.00 25.08 40.0 1047.0 112.6 0.0 1189.7 1993 4987.0 1500.0 2680.0 807.0 0.0 4987.0 2.78 38.94 0.00 24.33 41.6 1043.6 128.2 0.0 1213.4 1994 5242.8 1500.0 2865.0 877.8 0.0 5242.8 2.89 36.66 0.00 23.67 43.3 1050.4 147.4 0.0 1241.0 1995 5511.8 1500.0 3050.0 961.8 0.0 5511.8 3.00 34,67 0.00 23.10 45.0 1057.4 170.6 0.0 1273.1 1996 5794.5 1500.0 3235.0 1059.5 0.0 5794.5 3.12 32,91 0.00 22.61 46.8 1064.8 0.0 1310.2 1997 6091.8 1500.0 3420.0 1171.8 0.0 6091.8 3.25 31.36 0.00 22.21 48.7 1072.4 0.0 1353.3 1998 6404.3 1500.0 3605.0 1299.3 0.0 6404.3 3.38 29.97 9.00 21.91 50.6 1080.3 0.0 1403.0 1999 6732.9 1500.0 3790.0 1442.9 0.0 6732.9 3.51 28.72 0.00 21.69 52.7 1088.4 0.0 1460.6 2000 7078.3 1500.0 3975.0 1603.3 0.0 7078.3 3.65 27.60 0.00 21.57 54.8 1097.2 0.0 1527.0 2 7441.4 1500.0 4252.5 1688.9 0.0 7441.4 3.80 26.01 0.00 21.24 57.0 1106.1 0.0 1580.4 2002 7823.1 1500.0 4530.0 1793.1 0.0 7823.1 3.95 24.62 0.00 21,01 $9.2 1115.4 46846 0.0 1643.3 2003 8224.4 1500.0 4807.5 1916.9 0.0 8224.4 4.11 23.40 0.00 20.87 61.6 1125.1 529.6 0.0 1716.3 2004 8646.4 1500.0 S085.0 2061.4 0.0 8646.4 4.27 22.32 90.00 20,83 64.1 1135.1 602.0 0.0 1801.2 2005 9089.9 1500.0 5362.5 2227.4 0.0 9089.9 4.44 21.36 0.00 20.90 66.6 1145.6 687.7 0.0 1899.9 TABLE H4 ENERGY PRODUCTION MIX», AVERAGE COST FER KWH» SOOO OOOO OE ANDI ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR *XASSUMP TIONS * SNAGWAY WITH ADDITION OF REID FALLS * GENERAL INFLATION 4%* 1980 TO 2005 * FUEL INFLATION OU * INTEREST RATE 74% SOOO OO IK FPROLUCTION ENERGY PRODUCTION (CMWH) COST FER KWH(CENTS) ANNUAL COSTS( #1000) LOALD MKT AKT HKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR sunt HYDRO BUGRG DIESEL OTHER TOTAL DG CARO) DIESEL OTHER AVERAGE HYDRO HYDRO DIESEL OTHER TOTAL 1980 6179.0 1500.0 0.0 4679.0 0.0 6179.0 1.67 0.00 7.80 0.00 6.31 25.0 365.0 0.0 1981 4274.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 0.09 8.24 0.00 59S 26.0 228.5 0.0 1982 3672.0 1500.0 0.0 2172.0 0.0 3672.0 1,80 0.00 8.70 0.00 5.88 27.0 188.9 0.0 1983 3023.0 1500.0 0.0 1523.0 0.0 3023.0 1.87 6.00 9.18 0.00 3.56 2661 139.9 9.0 L984 3200.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 0.00 9.70 0.00 6.07 29.2 144.9 0.0 1985 3374.0 1500.0 1353.6 520.4 0.0 3374.0 2.03 37.51 10.24 0.00 17,53 30.4 53.3 9.0 1986 3512.0 1500.0 1472.9 S39.d 0.0 3512.0 11 34.81 10,82 0.00 17.16 3 58.3 9.0 1987 3692.0 1500.0 1592.1 599.9 0.9 3692.0 2019 32.53 11.43 0.00 16.77 2 68.46 0.0 1988 3888.0 1500.0 1711.4 67666 0.0 3888.0 30.58 12.07 0.00 16.44 81,7 0.0 1989 4086.0 1500.0 1830.7 755.3 0.0 4086.0 28.89 12.75 0.00 16.17 96.3 0.0 1990 4292.0 1500.0 1950.0 842.0 0.9 4292.0 2.47 27.42 13.47 0.00 15.97 334.8 113.4 0.0 1991 4512.2 1500.0 2125.0 887.2 0.0 4512.2 2.57 14.23 9.00 15.64 240.9 126.3 0.0 1992 4743.7 1500.0 2300.0 943.7 O.0 4743.7 2-67 23.79 15.04 0,00 18.37 £47.2 14159 0.0 1993 4987.0 1500,0 2475.0 1012.0 0.0 4987.0 2.78 22.38 15.89 0,00 15.16 33, 160.8 0.0 1994 5242.8 1500.0 2650.0 1092.8 0.0 5242.8 2.89 21.16 16.79 0.00 15,02 560.6 183.5 0.0 1995 S511,8 1500.0 2825.0 1186.8 0.0 S511.8 3.00 20.10 17.74 0.00 14.94 567. 8 210.5 6.0 1996 5794.5 1500.0 3000.0 1294.5 0.0 5794.5 3.12 19.17 18.75 0.00 14.92 73.2 242.7 0.0 1997 6091.8 1500,0 3175.0 1416.8 0.0 6091.8 3.25 18.36 19.81 0.00 14,98 2 280.7 9.0 1998 6404.3 1500.0 3350.0 1554.3 0.0 6404.3 3.38 17.64 20.94 0.00 15.10 590.9 1999 6732, 1500.0 3525.0 1707.9 0.0 6732.9 3.51 17.00 22.13 0.00 15.30 599.2 1029.9 2000 7078.3 1500.0 3700.0 1878.3 9.0 7078.3 3.65 16.43 23.39 0.90 15.57 607.9 1102 001 7441.4 1500.0 3935.0 2006.4 0.0 7441.4 3.80 15.68 24.72 9,00 15.72 616.9 1149.9 002 7823.1 1500.0 4170.0 2153.1 0.0 7823.1 3.95 15.02 26.13 0.00 15.96 62664 1248.2 2003 8224.4 1500,0 4405.0 2319.4 0.0 8224.4 4.1L 14.44 27.63 0.00 16.27 1$.38,4 2004 8646.4 1500,0 4640,0 2506.4 0.0 8646.4 4.27 13.93 29.20 O.v0 16.68 1442.3 2005 9089.9 1500.0 4878.0 2714.9 0.0 F0OB9.9 4.44 13.47 39,88 0.00 17.18 ISG166 TABLE HS ENERGY FRODUCTION MIX» AVERAGE COST FER KWH» SOOO OOK AND ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR *ASSUMPT IONS x COMBINED WITH ADDITION OF WEST CREEK * GENERAL INFLATION 4%% 1980 TO 2005 * FUEL INFLATION On * INTEREST RATE 7K* SOIR ROK RK PRODUCTION ENERGY PRODUCTION (MWH) COST FER KWH(CENTS) LOAD MKT MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR CMWH) HYDRO HYDRO [DTESEL OTHER TOTAL HYDRO CIESEL OTHER AVERAGE HYDRO HYDRO TOTAL 1980 14081,.0 1500.0 0.0 6320.0 6261.0 14081.0 1.67 9.00 7+80 6.00 +0 0.0 BPS. 1981 12454.0 1500.0 0.0 4673.0 6261.0 12454.0 1.73 9.600 64636 oO G.0 810.7 1982 12512.0 1500.0 0.0 4751.0 6261.0 12512.0 1.80 0.00 6674 0.9 842.3 1983 12166.0 1500.0 0.0 4405.0 6261.0 12166.0 1.87 0.00 71S 0.0 BE0. 1984 13925.0 1500.0 0.0 6164.0 6261.0 13925.0 0.00 7.57 G.0 1101.4 1985 14449.0 1500.0 0.0 6688.0 6261.0 14449,0 0.00 8.03 9.0 1218.3 1986 15481.0 1500.0 0.0 7720.0 6261.0 15481.0 0.00 8.51 0.0 139967 1987 16040.0 1500.0 0.0 8279.6 6261.0 16040.0 0.06 7.02 0.0 1543.9 1988 16675.0 1500.0 15175.0 0.0 0.0 16675.0 55.50 0.00 8422.2 B456.4 1989 17296.0 1500.0 15796.0 0.0 0.0 17296.9 53.46 0.00 8444,9 8480.5 1990 17957.0 1500.0 16457.0 0.0 0.0 17957,0 51.46 9,06 84468,5 8505.5 1991 18928, 1500.0 17428.8 0.0 0.9 18928.8 48.73 0.00 8493.1 B5S1.46 1992 19953. 1500.0 18453.2 0.0 02 46616 0.00 558.6 1993 21033.0 1500.0 19533.0 0.0 2 +0 4AS.°S 9,00 40,383 85 1994 22171.3 1500.0 20671.3 0.0 22171.3 2 41.47 0.00 39.86 BG 1995 23371.4 1500.0 21871.4 0.9 23371.4 ai 39.33 0.00 37,00 c R546.6 1996 24636.4 1500.0 23136.4 0.0 0.0 24636.4 3 37.31 6.90 35.23 B6SL.5 8475.3 1997 25970.0 1500.0 24470.0 0.0 0.0 25970.0 3 35.40 0.00 33.54 8662.4 2d = &: 1998 27375.8 1500.0 25875.8 0.0 0.0 27375.3 3 33.40 0.00 31,95 8694.7 8745.5 1999 857.8 1500.0 27357.8 0.0 0.0 28857,.8 3 31071 0.00 30.43 3 5 es: 2000 30420,1 1500.0 28920.1 0.0 0.0 30 3.45 a 0.00 28.99 8765.5 2001 32067.0 1500.0 30567.0 0.0 Oo 3.80 0.00 27, 8799.9 2002 33803.1 1500.0 32303.1 0.0 0.0 33803.1 3595 0.00 24,32 2003 35633.3 1500.0 34133.3 0.0 0.0 35633.3 Avil 0.00 25.09 ; 2004 37562.8 1500.0 36062, 0.0 0.0 275462 4.27 290 23691 8917.9 2008 39596.7 1500.0 38096.7 0.0 0.0 39596.7 4.44 0.00 22.80 8960.5 TABLE Hé ENERGY PRODUCTION MIX, AVERAGE COST FER KWH» SAO OK OR IORI IOK ANT ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR *X ASSUMPTIONS * COMBINED WITH ADDITION OF GOAT LAKE ¥ GENERAL INFLATION 42% 1980 TO 2005 * FUEL INFLATION On * INTEREST RATE TAK SOOO AK OK PRODUCTION ENERGY FRODUCTION(CMWH) COST FER KWH(CENTS) ANNUAL COSTS($1000) LOAL MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST CMWH > HYDRO HYDRO TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO 14081,0 1500.0 0.0 6320.0 6261.0 14081.0 1,67 0.00 7+80 6100 6.35 493.0 375.7 893.6 12454.0 1500.0 0.0 4693.0 6261.0 12454,0 1.73 0.00 8.24 6536 S51 386.5 398.2 810.7 12512.0 1500.0 0.0 4751.0 6261.0 12512. 1.80 0,00 2.70 G74 6.89 413.2 422.1 Bé2. 12146.0 1500.0 0.0 4405.0 6261.0 12146.0 1.87 0.09 9.18 71S 7.23 464.6 447.4 880.1 13925.0 1500.0 0.0 6164.9 6261,0 13925,0 1.695 0.00 9.760 7457 Tat i 474.3 1101.4 14449.0 1500.0 0.0 6688.0 6261.0 14449,0 2.403 6.00 10,24 8.03 8.43 685.1 S02. 1218.3 15481.0 1500.0 13981.0 0.0 0.0 15481.0 2-11 23.55 10.82 9.00 21,47 0.0 0.0 3324.2 16040.0 1500.0 14546,0 0.0 0.0 16040,.0 3 11.43 0.00 20,84 O60 0.0 3243.5 146675.0 1500.0 15175,0 0.0 0.0 16675.0 12.07 0.00 20.17 0.0 0.0 3363.5 172946.0 1500.0 15796.0 0.0 0.0 17296.0 12.75 0.00 19.57 0.0 4.0 3384.4 17957.0 1500.0 16457.0 0.0 0.0 17957. 13.47 9.00 18.97 0.0 0.0 3406.1 18928.8 1500.0 17428.8 0.0 0.0 18928.8 14.23 0.00 18.11 0.0 0.0 3428.4 19953,.2 1500.0 18453.0 0.2 0.0 19953,2 15.04 0.00 17.30 0.0 0.0 3452.1 21033.0 1500.0 19533.0 0.0 0.0 21033.0 15.89 0.00 16.53 0.0 0.0 3476.4 22171.3 1500.0 20671.0 0.3 0.0 22171.3 16.79 0.00 15.79 O.1 0.0 3501.8 3371.4 1500.0 21871.0 O.4 0.0 23371.4 17.74 6.00 15.10 Ol 0.0 3528.2 24636.4 1500.0 23136.0 0.4 0.0 24636.4 18.75 0.00 14.43 3508.7 O.1 0.0 3555.6 25970.0 1500.0 24071.0 399.0 0.9 25970.0 19,81 0,00 14.11 3535.4 7940 0.0 3663.1 27375.8 1500.0 25006.0 869.8 0.0 27375.8 20,94 0.06 13,87 3543.1 182.1 0.0 3795.9 28857.8 1500.0 25904.0 1453.8 0.0 238857.8 2. 3 0.00 13.74 P 3591.9 32107 0.0 3966.3 30420.1 1500.0 26875.0 2045.1 0.0 30420.1 23.39 9.00 13.46 54.8 3621.9 478.3 0,0 4155.0 32067.0 1500.0 27958.0 2609.0 0.0 32067.0 24.72 0.00 13.58 57.0 3653.1 a 9.0 4355.1 27803.1 1500.0 29040.0 3263.1 0.0 33803.1 26.13 0,00 13.60 59.2 3685.5 0.0 4597.5 2 35633,.3 1500.0 36123,.0 4010.3 0.9 35633.3 27.63 0,00 13.72 61-6 2719.2 0.0 4888.7 2004 37562.8 1500.0 31205.0 4857.8 0.9 2 29.29 0.00 13.94 64.1 3754.3 0.0 $237.1 2005 39596.7 1500.0 32288.0 5808.7 0.0 39596.7 30,88 0.00 14.27 66.4 3790,7 0.0 5650.8 TABLE H? ENERGY PRODUCTION MIX: AVERAGE COST OOOO KK AK ANDI ANNUAL COST FOR ELECTRI NERGY F XASSUMF'T IONS * COMBINED WITH ADDITION OF UPPER CHILKOOT * GENERAL INFLATION 4% 1980 TO 2005 * FUEL INFLATION On * INTEREST RATE PL SOCIO OK ACK PRODUCTION ENERGY ROBUET ION Lriuhi) egSt FER ANWHCEENTS? ANNUAL -EGSTSes 2000) - LOAL MKT MKT . MK FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR CMWH) HYDRO HYDRO “SEL OTHER TOTAL oon HYfMRO [DTESEL OTHER AVERAGE HYTRO HY DRG OTHER TOTAL 1980 14081.0 1500.0 0.0 6320.0 6261.0 14081.0 1.47 0.00 7,80 E400 6.35 O10 375.7 B93.5 1981 12454,.0 1500.0 0.0 4693.0 6261.0 12454.0 1,73 0.00 8.24 5 6551 9.0 398.2 810.7 1982 12512, 1500.0 0.0 4751.0 6261.0 12512.0 1.80 0.00 8.70 6.74 6689 0.0 422.1 862.3 1983 12166.0 1500.0 0.0 4405.0 6261.0 12166,.0 1.87 0.00 9.18 75S 7423 0.0 447.4 880.1 1984 13925.0 1500.0 0.0 6164.0 6261,0 13925,.0 1.95 9.00 9,70 7657 709d 9.0 474.3 1101.4 1985 14449.0 1500.0 0.0 6688.0 6261.0 14449,0 2,02 9.00 10.24 8.02 8,43 0.0 502.7 1218.3 1986 15481.0 1500,0 13981.0 0.0 0.0 15481.0 a 25.63 10.82 0.00 23.35 3583.) 0.0 3614.7 1987 16040,0 1500.0 14540,0 0.0 0.0 14040.0 11.43 0.00 22.66 3601.9 0.0 3634.8 1988 16675,.0 1500.0 15175.0 0.0 0.0 16675.0 2.07 0.900 21,92 3621.5 0.0 3655.8 1989 17296,.0 1500.0 15796.0 0.0 0.0 17296.0 12.75 0.00 21,26 3641.69 0.0 3677;5 1990 17957.0 1500.0 16457.06 0.0 0.0 17957.6 13.47 0.00 20,61 366361 0.0 370041 1991 18928,.8 1500.0 17428.8 0.0 0.0 18928,.8 14.22 0,00 19,67 3685.2 0.0 3723.6 1992 19953.2 1500.0 18453.0 2 0.0 19953.2 15.04 0.00 18.78 3708.1 0.0 3748.1 1993 21033.0 1500.0 19318.0 215.0 0,0 21033.0 15 0,00 18.10 3731.9 0.0 BSO02: 7 1994 22171.3 1500.0 20183.0 oad 0.0 22171,.3 16.79 9,00 17,51 375667 G.0 1993 23371.4 1500.0 21049.0 822 0.0 23371.4 17.74 9.00 17.00 3782.5 0.0 1996 24636,.4 1500.0 21914,0 ioe 0.0 24636.4 18.75 0.00 14.58 3809.3 0.0 1997 25970.0 1500.0 22779.0 1691.0 0.0 25970.0 19,81 0.00 16.25 3837.2 0.0 1998 27375.8 1500.0 22644,.0 3231.8 0.0 27375.8 20.94 0.00 14.78 oe 0.0 1999 28857,8 1500.0 pare 2847.8 0.0 28857.8 22.13 0.00 15.87 0.6 2000 30420.1 1500.0 25375.0 3545.1 0.0 39420.1 23.39 0,00 15.82 3 7,3 0,0 O1 32067.0 1500.0 265 25.0 4042.0 0.9 32067.0 24.72 6,00 15.64 3960.4 0.0 O02 33803.1 1500.6 27675.0 4628.1 0.0 33803.1 26.13 0.00 15.57 3994,4 1209.5 0.0 03 35633.3 1500,0 28825,0 5308.3 0.0 354633.3 27 62 O.00 15.60 4029.7 1466.5 0.0 04 37562.8 1500.0 29975.0 6087.8 0.0 37562.8 9.20 0.00 15.73 4066.4 1777.9 0.0 2005 39596.7 1500.0 31125.0 4971.7 0.0 39596.7 30, ge 0.00 15.97 4104.5 21 Ss 0.0 TABLE H8 ENERGY FROLIUCTION MIX AVERAGE COST PER KWH» AND ANNUAL COST FOR ELECTRIC ENERGY FRODUCEDL FOR HAINES ASSUMING NO ADDITIONAL HYDRO 1980 TO 2005 PRODUCTION ENERGY FRODUCTION(MWH) COST FER KWH(CENTS) LOAD MKT MKT FORECAST EXIST NEW EXIST NEW YEAR (MWH) HYDRO HYDRO DIESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER 1641.0 6261.0 7902.0 0.00 0.00 7.80 6.00 1919.0 6261.0 8180.0 0.00 0.00 8.24 +36 2579.0 6261.0 8840.0 0.00 0.00 8.70 6474 2882.0 6261.0 9143.0 0.00 0.00 9.18 7.15 4464.0 6261.0 10725,.0 0.00 0.00 9.70 7.57 4814.0 6261.0 11075.0 0.00 0.00 10.24 8.03 5708.0 6261.0 11969.0 0.00 0.00 10.82 8.51 6087.0 6261.0 12348.0 0.00 0.00 11.43 9.02 6526.0 6261.0 12787.0 0.00 0.00 12.07 9.56 6949.0 6261.0 13210.0 0.00 0.00 12.75 10.14 7404.0 6261.0 13665.0 0.00 0.00 13.47 10.75 8155.6 6261.0 14416.6 0.00 0.00 14.23 11.39 8948.5 6261.0 15209.5 0.00 0.00 15.04 12.07 9785.0 6261.0 16046.0 0.00 0.00 15.89 12.80 10667.5 6261.0 16928.5 0.00 0.00 16.79 13.57 11598.6 6261.0 17859.6 0.00 0.00 17.74 14.38 12580.9 6261.0 18841.9 0.00 0.00 18.75 15.24 13617.2 6261.0 19878.2 0.00 0.00 19.81 16.16 14710.5 6261.0 20971.5 0.00 0.00 20.94 17.13 15863.9 6261.0 22124.9 0.00 0.00 22.13 18.15 1980 7902.0 1981 8180.0 1982 8840.0 1983 9143.0 1984 10725.0 1985 11075.0 1986 11969.0 1987 12348.0 1988 12787.0 1989 13210.0 1990 13665.0 1991 14416.6 1992 15209.5 1993 16046.0 1994 16928.5 1995 17859.6 1996 18841,.9 1997 19878.2 1998 20971.5 1999 22124.9 eocococecocoocecece|coecoc]e|e|]o eccooocoocoooococooocoooocsooooocge ecoooocoooocoooocooocecocoeocso$g ecocoococeceNce|cece\|cece|coocoocoo 2000 23341.8 23341.8 0.0 23341.8 0.00 0.00 23.39 0.00 O01 24625.6 24625.6 0.0 24625.6 0.00 0.00 24.72 0.00 2002 25980.0 25980.0 0.0 25980.0 0.00 0.00 26.13 0.00 2003 27408.9 27408.9 0.0 27408.9 0.00 0.00 27.63 0.00 2004 28916.4 28916.4 0.0 28916.4 0.00 0.00 29.20 0.00 2005 30506.8 30506.8 0.0 30506.8 0.00 0.00 30.88 0.00 WEIGHT AVERAGE 6.37 6-80 7.31 7479 B46 B69? 9.61 10.21 10.84 11,51 12.22 13.00 13.82 14.68 15.60 16.56 17.58 18.66 19.80 21.00 23.39 24.72 26.13 27.63 29.2 30.88 EXIST HYDRO eoooocooocoocoocoeocoecoocoocoso ocooooocoooooocoocoooocoococeo ecoooooooooococooocooocococseceo cecoocooooocoooocoooooococooooooooosg 2A OOOO OOOO OK *XASSUMP TIONS x * GENERAL INFLATION 4%xk * FUEL INFLATION 6% * INTEREST RATE TEx SOO OOO OOO OK ANNUAL COSTS($1000) DIESEL OTHER TOTAL 128.0 375.7 503.7 158.0 398.2 556.2 224.3 422.1 646.4 264.7 447.4 71261 433.0 474.3 907.2 493.1 502.7 995.9 617.5 532.9 1150.4 695.6 564.9 1260.5 787.8 S98.7 1386.6 886.1 634.7 1520.8 997.5 672.7 1670.2 1160.8 713.1 1873.9 1345.6 755.9 2101.5 1554.6 801.3 2355.9 1790.9 849.3 2640.2 2057.6 900.3 2957.9 2358.5 954.3 3312.8 2697.8 1011.6 3709.4 3080.1 1072.3 4152.3 3510.7 1136.6 4647.3 5459.6 0.0 5459.6 6088.2 0.0 6088.2 6789.6 0.0 6789.6 7572.0 0.0 7572.0 8445.0 0.0 8445.0 9419.0 0.0 9419.0 FOO OOOO OK XASSUMFT IONS * * GENERAL INFLATION 4% * FUEL INFLATION 62% x INTEREST RATE 7h SOOO OOOO OK PRODUCTION COST FER KWH(CENTS) ANNUAL COSTS($1000) TABLE qo ENERGY FRODUCTION MIX» AVERAGE COST FER KWH» AND ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR SKAGWAY ASSUMING NO ADDITIONAL HYLIRO 1980 TO 2005 ENERGY FPRODUCTION(MWH) LOAD MKT FORECAST EXIST NEW EXIST YEAR (MWH > HYDRO HYDRO DIESEL OTHER TOTAL HYDRO 1980 6179.0 1500.0 0.0 4479.0 0.0 6179.0 1.67 1981 4274.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 1982 3672.0 1500.0 0.0 2172.0 0.0 3672.0 1.80 1983 3023.0 1500.0 0.0 1523.0 0.0 3023.0 1.87 1984 3200.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 1985 3374.0 1500.0 0.0 1874.0 0.0 3374.0 2.03 1986 3512.0 1500.0 0.0 2012.0 0.0 3512.0 2.11 1987 3692.0 1500.0 0.0 2192.0 0.0 3692.0 2.19 1988 3888.0 1500.0 0.0 2338.0 0.0 3888.0 2-28 1989 4086.0 1500.0 0.0 2586.0 0.0 4086.0 2.37 1990 4292.0 1500.0 0.0 2792.0 0.0 4292.0 2-47 1991 4512.2 1500.0 0.0 3012.2 0.0 4512.2 2.57 1992 4743.7 1500.0 0.0 3243.7 0.0 4743.7 2+67 1993 4987.0 1500.0 0.0 3487.0 0.0 4987.0 2.78 1994 5242.8 1500.0 0.0 3742.8 0.0 5242.8 2.89 1995 5511.8 1500.0 0.0 4011.8 0.0 5511.8 3.00 1996 5794.5 1500.0 0.0 4294.5 9.0 5794.5 3.12 1997 6091.8 1500.0 0.0 4591.8 9.0 6091.8 3.25 1998 6404.3 1500.0 0.0 4904.3 0.0 6404.3 3.38 1999 6732.9 1500.0 0.0 5232.9 0.0 6732.9 3.51 2000 7078.3 1500.0 0.0 5578.3 0.0 7078.3 3.65 2001 7441.4 1500.0 0.0 5941.4 0.0 7441.4 3.80 2002 7823.1 1500.0 0.0 6323.1 0.0 782361 3.95 2003 8224.4 1500.0 0.9 6724.4 0.0 8224.4 4.11 2004 8646.4 1500.0 0.0 7146.4 0-0 8646-4 4.27 2005 9089.9 1500.0 0.0 7589.9 0.0 9089.9 4.44 MKT MKT NEW WEIGHT EXIST NEW HYDRO DIESEL OTHER HYDRO DIESEL OTHER TOTAL 0.00 7.80 0.00 6.31 25.0 0.0 365.0 0.0 370.0 0.00 8.24 0.00 5.95 26.0 0.0 228.5 0.0 254.5 0.00 8.70 0.00 5.88 27.0 0.0 188.9 0.0 215.9 0.00 9.18 0.00 5.56 28.1 0.0 139.9 0.0 168.0 0.00 9.70 0.00 6.07 29.2 0.0 164.9 0.0 194.1 0.00 10.24 0.00 6659 30.4 0.0 192.0 0.0 222.4 0.00 10.82 0.00 710 31.66 0.0 217.7 0.0 249.3 0.00 11.43 0.00 7+68 32.9 0.0 250.5 0.0 283.4 0.00 12.07 0.00 9.29 34.2 0.0 288.3 0.0 322.5 0.00 12.75 0.00 B.94 3546 0.0 329.8 0.0 365.3 0.00 13.47 0.00 9663 37.0 0.0 37661 0.0 413.1 0.00 14,23 0.00 10.35 38.5 0.0 428.7 oO.” 467.2 0.00 15.04 0.00 11.13 40.0 0.0 487.8 0.0 527.8 0.00 15.89 0.00 11.94 41.6 0.0 554.0 0.0 S9S+6 0.00 16.79 0.00 12,81 43.3 0.0 628.3 0.0 671.46 0.00 17.74 0.00 13.73 45.0 0.0 7AL 7 0.0 735667 0.00 18.75 0.00 14.70 46.8 0.0 805.1 0.0 851.9 0.00 19.81 0.00 15.73 48.7 0.0 909.7 0.0 958.4 0.00 20.94 0.00 16.82 50.66 0.0 1026.9 0.0 1077.5 0.00 22.13 0.00 17.98 52.7 0.0 1158.0 0.0 1210.7 0.00 23.39 0.00 19.21 54.8 0.0 1304.8 0.0 1359.5 0.00 24.72 Q.00 20.51 57.0 0.0 1468.9 0.0 1525.9 0.00 26.13 0.00 21.88 59.2 0.0 1652.5 0.0 1711.7 0.00 27.63 0.00 23.34 61.6 0.0 1857.7 0.0 1919.3 0.00 297.20 0.00 24.88 64.1 0.0 2087.1 0.0 2151.2 0.00 30.88 0.00 26.51 66.66 0.0 2343.4 0.0 2410.0 Table H-10 AVERAGE ENERGY COST FOR SKAGWAY USING EXISTING HYDROPOWER AND DIESEL FACILITIES PLUS PROPOSED EXPANSION OF HYDROPOWER FACILITIES 1980 to 2005 Weighted Load eae Diesel Cost Year Forecast (MWh ) (¢/7kWh) (MWh ) (¢/kWh ) (¢/kWh ) 1980 6,179 MWh 1,500 S67 4,679 7.80 (sil 1981 4,274 MWh 1,748 2604 2,526 8.24 5162: 1982 3,672 MWh 2,243 2.49 1,429 8.70 4.91 1983 3,023 MWh 2,986 2.38 37 9.18 2.46 1984 3,200 MWh 2,986 2.44 214 9.70 2.93 1985 3,374 MWh 2,986 2.50 388 10.24 3.39 1990 4,292 MWh 2,986 2.80 1,306 13°47 6.05 1995 5,512 MWh 2,986 3219 2,526 17.74 9.86 2000 7,078 MWh 2,986 3.65 4,092 233539 15.06 2005 9,090 MWh 2,986 4.22 6,104 30.88 22L2 Assumptions: General Inflation 4% Fuel Inflation 6% Interest Rate 7% Table H-11 WEIGHTED AVERAGE ENERGY COSTS FOR HAINES AND SKAGWAY USING EXISTING POWER FACILITIES, PLUS NEW DIESEL, 1980 to 2005 Haines Skagway Combined mM Energy Cost Energy Cost Ener Cost Year (MWh_) (¢/kWh (MWh_) (¢/kWh) (MWh_) (¢/kWh) 1980 7,902 6.37 6,179 6.31 14,081 6.34 1981 8,180 6.80 4,274 5)95 12,454 62511 1982 8,840 Heo 3,672 5.88 127,522 6.89 1983 9,143 TietD 3,023 5.56 12,166 7.24 1984 10,725 8.46 3,200 6.07 13,925 Tj91- 1985 11,075 8.99 3,374 6.59 14,449 8.43 1990 13,665 L222 4,292 9.63 Li, 957 11.60 L995) 17,859 16.56 Soe eS ord 23,371 15.89 2000 23,342 2139 7,078 19.21 30,420 22.42 2005 30,507 30.88 9,090 26.51 B95 917, 29.88 aWeighted by MWh used each year by each community. Assumptions: General Inflation 4% Fuel Inflation 6% Interest Rate 71% MM exhibit I =e Energy Costs for Area Power Plans 9 Percent Interest Rate TABLE Ti) ENERGY PROUWUCTION MIXs AVERAGE LOST PRR KWHe SOOO KACO OF AND ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR XASSUMPT LONS * HAINES WITH ADDITION OF UPPER CHILKOOT * GENERAL TNFLATLON 4% 1980 TO 2005 ¥ FUEL INFLATION GUk * INTEREST RATE GU SOOO ICR FOR AOR OK AK PRODUCTION ER KWHCCENTS) ANNUAL COSTS($1000) LOAD FORECAST EXIST YEAR CMUH HYDRO EXIST NEW WEIGHT EXIST NEW OTHER TOTAL HYDRO HYORO DIESEL OTHER AVERAGE HYDRO HYDRO TTESEL OTHER TOTAL 1980 7902.0 0.0 0.0 1641.0 6261.0 7702.0 0.00 0.00 4.00 4637 0.0 375.7 503.7 1981 8180,0 0.0 0.0 1919.0 6261.0 8180.0 0.00 0,00 6636 6.80 0.0 398.2 556.2 1982 8840.0 0.0 0.0 2579.0 4261.0 8840.0 0.90 0.00 6474 7.31 0.0 422, 646.4 1983 9143.0 0.0 0.0 2882.9 6261.0 9143.0 0.00 0.00 7.15 7.79 0.0 447.4 712. 1984 10725.90 0.0 9.0 4464.0 6261.0 10725.0 0.00 0.00 7.57 Beas 0.0 474.3 907.2 1985 11075.0 0,0 0.0 4814.0 6261.0 11075.0 9.00 0.00 8.03 8.99 0.0 SC 7 99S 69 1986 11949.0 0.0 11359.2 609.8 0.0 11969,.0 0.00 33,18 8.51 32.04 0.0 O 3834.4 1987 12348.0 0.0 11936.4 411.6 0.0 12348.0 0.00 31.73 9.02 31.05 0.0 0 3834.2 1983 12787.0 0.0 12513.6 273.4 0,9 12787.0 0.00 30.42 9.%6 30,03 0.9 0 3839.5 1989 13210.0 0.0 13090.8 119.2 0.0 13210.0 0.00 29.23 19,14 ok o.0 9 3841.7 1990 13665.0 0.0 13665.0 0.0 0.0 123645,.0 ¢.00 28,15 0.0 O 3847.4 1991 14416.6 0.0 14416.4 0.0 O10 1441646 0.00 26.57 0.9 O FB465.4 1992 15209.5 0.0 15209.5 0.0 0.0 19209.5 0.00 25.18 0.9 3891.7 QO 3891." 1993 160446.0 0.0 16046.0 0.0 0.0 16046.0 0.09 23.95 0.0 S915.2 Oo 3915.3 1994 16928.5 0.0 16923.5 0.0 0.0 16928.5 9.00 22.85 9.0 3959.6 9.0 3939.46 1995 1785946 0.0 17859.6 0.0 0.0 17859.6 0.00 9.0 3955. 0.0 3965.0 1996 18841.9 0,0 18841.9 0.0 0.0 18841.9 0.00 20.98 9.0 3991.4 0.0 3991.4 1997 19878.2 0.0 19878.2 0.0 0.0 19878.2 0,00 29.17 9.0 4018.8 9.0 4618,8 1998 20971.5 0.0 20813.6 157.9 0.0 20971.5 0.00 19.45 0.9 4047.4 9.0 4080.5 22124.9 0.0 21706.8 418.1 0.0 22124.9 9.00 18.78 0.0 4077.1 0.0 4167.4 23341.8 0.0 22600,.0 741.8 0.0 23341.8 9.00 18.18 o.0 4198.0 0,0 4281.5 24625.6 0.0 23580.0 1045.6 0.0 24625.6 9.00 17.56 0.0 4149.4 0.0 4398.46 0.0 24560.0 1420.0 0.0 25980.0 0.00 16.99 O,0 4173.6 9,0 4544,7 0.0 25540.0 1868.9 0.0 27408.9 O.00 16.48 40 4208.3 9.0 4724.6 2B91G.4 0.0 26520.0 2396.4 0.0 78916.4 9.00 16.00 0.0 4244.5 0.0 4944.5 © 30506.€ 0.0 27500.0 3006.8 0.9 39506.8 6.00 15.57 0.0 $272.0 0.6 $210.4 MUCTION Mix» AVERAGE PER KWH» SOC E K ANT) ANNUAL COST FOR ELECTRIU & SODUCED FOR ASSUMP T TONS * HAINES WITH ADDITION OF DAYERAS * GENER@L TNFLATION 4%% 1980 TO 2005 *¥ FUEL INFLATION 42K * TATEREST RATE 9Le SAO CORK TABLE IT2 ENERGY PRO FRORUCT LON ¢ KWHCCENTS) ANNUAL COSTS (#1000) eben ope oan LOATI MKT FORECAST EXIST NEW EXIST YEAR CMWH} HYDRO HYDRO DTESEL OTHER TOTAL HYDRO ART WETGHT EXIST HEU DIESEL OTHER AVERAGE HY CF HYDRO Oe SEL | OTHER TOTAL 1980 7902.0 0.0 0.0 1641.0 1.0 0.00 6.37 9.0 0.0 L981 8180.0 0.0 O90 19TS 0 1.0 9.00 &.80 On 0.0 1982 Baa, Qo 0.0 0.0 2579.0 6261.0 9840, Go 0.00 731 0.9 9.0 1983 0.0 0.0 2882.0 6261.0 0.00 Lito) 0.0 0.90 I O.0 0.0 4464.0 6261.0 09.00 8.46 6.0 0.0 0.9 O 2450.0 0.0 0.00 12,65 0.0 1149.9 1986 0,0 +0 2989.0 0.0 9,00 12.40 0.0 1161.3 L987 0.0 140 301340 0.0 L2 0 0.00 12.29 O50 107302 1988 0.0 +9 309 0.0 12787.0 0.00 12.20 0-0 1185.6 1989 9.9 10045.0 6.0 0.00 12.13) O.0 1198.4 L99O 13665.0 0.0 10400.0 0.0 o,00 12,09 6.0 2 1991 1441 z 0,0 10892 0.0 14416.4 0.00 11,98 9,0 1992 15209.5 0.0 11385.0 0.0 15209,5 0,00 O.G L993 16046.0 0.0 11 o 4168.5 9.0 16046.0 0.00 O.0 1994 16928.5 0.0 12370.0 48 5 0.0 16928.5 0400 0.0 1995 17859.6 0,0 128 S 4997.1 0.0 17859.6 0.00 12.437 0.0 1994 18841.9 0.0 13355.0 486.9 O.0 18841.9 0.00 2.38 0.0 1997 1987 0.0 13847.8 6030.7 0.0 19878.2 0.00 12.66 0.0 1998 7 0.0 14340,.0 4631.5 0.0 20971.5 0.00 e308 0.0 0.0 14832.5 7292.4 0.0 22124.9 0.00 +44 0.0 41.8 0.0 8016.8 0.0 23741.8 0.00 +74 0.90 625.6 0.0 BB24.1 0.0 24625.4 0,00 0.0 1399.5 2181, x 0.0 3580. 8 25980,.0 0.0 9700.0 0.0 25980.0 0.00 ; bs: 28) 0.G 1420.9 C 0.0 3955.9 27408.9 0.0 10651.4 0.0 27408.9 0.00 16,00 0.0 1443.2 0,0 4385.8 2891664 0.0 11681.4 0.0 28916.4 0.00 16.87 0.0 1466.4 0.0 4877.9 $0506.8 o.0 12794.3 0.0 36506.8 0.00 17,83 0.0 1490.5 O.0 $440.7 TABLE IX ENERGY FRODUCTION MIX» AVERAGE COST FER KWH» ORO OK OOO IO AND ANNUAL COST FOR ELECTRIC ERGY PRODUCED FOR KASSUMFP TIONS * SKAGWAY WITH ADDTTION OF LIF ¢ TEWEY A GENERAL INFLATIGN 4%% 1980 TO 2005 * FUEL INFLATION OnK ® INTEREST RATE PUK SOOO OO AO AOOK PRODUCTION COST FER KWH ENERGY PRODUCTION (MWH) NTS) ANNUAL COSTS( $1000) LOAL MKT MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW HY ORO HYDRO DIE YEAR (MWH) HYDRO HYDRO DT BE OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAG Lo OTHER 1980 6179.0 1500.0 0.0 4679.0 0.0 1.67 0.00 7.80 0,00 3631 0.0 390.0 1981 4274.0 1500.0 0.0 2774.0 0.0 1,73 0.00 8.24 0.00 59S 0.0 254.5 1982 3672.0 1500.0 0.0 2172.0 0.0 1.80 9,00 8.70 0.90 5,88 0.9 215,9 1983 3023.0 1500.0 0.0 1523.0 0.0 1.87 0.00 9.18 O.00 5.546 . 209 148.0 1984 3200.0 1500.0 0.0 1700.0 0.9 1.95 0.00 9670 9.00 6.07 0.0 194, 1985 3374.0 1500.0 0.0 1874.0 0.0 2.03 0.00 10.24 9.00 bao 9.0 1986 3512.0 1500.0 1647.9 3646). 0.0 2-11 74.05 10.82 0.00 0.6 1291.3 1987 3692.0 1500.0 1767.1 424.9 0.0 2619 69.34 11.43 0.00 0.0 14046,5 1988 3888.0 1500,0 1886.4 501.6 0.0 3888.0 2628 65.24 12.07 0.00 0.0 1325.5 1989 4086.0 1500.0 2005.7 580.3 0.0 4086.0 2.637 61.64 12.75 0,00 0.0 1545.9 1990 4292.0 1500.0 2125.0 667.0 0.0 4292.0 2.47 58.45 13.47 0,00 0.9 1369.0 1991 4512.2 1500.0 2310.0 702.2 0.0 4512.2 2.57 54.03 14.23 9.00 0.0 1386,6 1992 4743.7 1500.0 2495.0 748.7 0.0 4743.7 2.67 50.28 15.04 0.006 0.0 1407.1 1993 4987.0 1500.0 2680.0 807.0 0.0 4987.0 2.78 47.05 15.89 0.00 0.0 1430.8 1994 242.8 1500.0 2865.0 877.8 0.0 5242.8 2689 44.25 14,79 0.00 0.0 1995 5511.8 1500.0 3050.0 961.8 0.0 5511.8 3.00 41.80 17.74 0.00 O.0 1996 5794.5 1500.0 3235.0 1059.5 0.0 5794.5 3.12 39.43 18.75 0.09 9.0 1997 6091.8 1500.0 3420.0 1171.8 9.0 6091.8 $3.25 37.7% 19.81 0,00 9.0 1998 6404.3 1500.0 3605.0 1299.3 0.0 6404.3 3.38 36.00 20,94 0.00 0,0 1999 6732.9 1500.0 3790.0 1442.9 0.0 6732.9 3.51 34.46 2413 9.00 9.0 1678.0 2000 7078.3 1500.0 3975.0 1603.3 0.0 7078.3 3.65 33.07 23.49 0.00 0.0 1744.4 2001 7441.4 1500.0 4252.5 1688.9 0.0 7441.4 3.80 31.12 24,72 0.00 0.0 1798.1 2002 7823.1 1500.0 4530.0 1793.1 0.0 7823.1 3.95 29.42 0.00 0.0 1860.7 2003 8224.4 1500.0 4807.5 1916.9 0.0 8224.4 4.11 27.92 0,00 0.0 1933.7 2004 8646.4 1500.0 S085.9 2061.4 0.0 8646.4 4627 24.60 0.00 i 0.0 2018.7 2005 9089.9 1500.0 5362.5 2227.4 0.0 9089.9 4.44 25,42 0.00 66.6 1343.0 687.7 0.0 2117.3 TABLE T4 ENERGY PRODUCTION MIX» ANT ANNUAL COST FOR SKAGWAY WITH anti Tian 1980 TO 2005 FER KWH» SOOO AIC EE CODUCEOD FOR ¥ASSUMPTIONS x AL INFLATION 4%% INFLAT Toe aK oT RATE On SII IOK PRODUCT TOW IMUC TION (MWH D> COST PER KWH ANNUAL COS KT MKT LOAL FORECAST EXIST NEW EXIST NEW WET GHT EXIST NEW YEAR CMWH HY TRG HYDRO DTESEL OTHER TOTAL HYDRO HYDRG TIESEL OTHER AVERAGE HYTRO HYDRO ToTA 1500.0 0.0 4679.0 0.9 6179.0 1.67 0,00 7.80 0.00 oe Sl 25.0 O6G 0.0 1500.0 0.0 2774.0 0.0 4274.0 1.73 0.00 8.24 0.00 5.95 26.90 0.0 0.0 1500.0 0.0 2172.0 0.0 8672.0 1.80 0.00 8.70 9.00 5.88 27.0 0.0 0.0 1500.0 0.0 1523.0 9.0 3023.0 1.87 0.00 7.18 e.00 5.5 28.1 0.0 2.0 1500.0 0.0 1700.0 0.0 3200.0 1.95 0.00 9.70 0.00 29.2 0.0 0.0 1500.0 1353.6 520.4 0.0 3374.0 44.20 10,24 0.00 30.4 598.3 0.0 1500.0 1472.9 S391 0.0 3512.0 40.96 10,82 0.06 31.6 603,23 0.0 G2 1500.0 1592.1 599.9 0.0 3692.0 38.22 0.00 32.9 608.5 0.0 3888.0 1500.0 1711.4 676.6 0.0 2888.0 35.87 0.06 34.2 413.9 0.0 4086.0 1500.0 1830.7 755.3 0,0 4086.0 33.84 . 9.00 35.6 G19.6 0.0 4292.0 1500.0 1950.0 842.0 0.0 4292.0 32.07 13.47 0.00 37.0 625.4 0.0 4512.2 1500.0 2125.0 887.2 0.0 4512.2 29.72 14.23 0.05 38.5 621.5 126.3 0.0 4743.7 1500.0 2300.0 943.7 0.0 4743.7 73 9,00 40.0 6378 141.7 0,0 4987.0 1500.0 2475.0 1012.0 0.0 4987.0 +04 0.00 41.6 b44.4 140.8 6.0 $242.8 1500.0 50.0 1092.8 0.0 5242.8 2.89 24.58 0.00 43.3 651.3 183.5 0.0 511.8 1500.0 2825.0 1186.8 0.0 5511.8 3.00 9.00 45.0 658.4 210.5 0.0 5794.5 1500.0 3000.0 1294.5 0.0 5794.5 3.12 0.06 46.8 665.8 242.7 0.0 6091.8 1500.0 3175.0 1416.8 0.0 6091.8 3.25 Le 20 0.60 48.7 673.5 280.7 0.0 1002.9 6404.3 1500.0 3350.0 1554.3 0.0 6404.3 3.38 20.34 0.06 50.6 681.5 325.4 0.0 1957.6 6732.9 1500.0 3525.0 1707.9 0.0 3.51 19.57 0.00 689.9 378.0 0.0 1120.5 7078.3 1500.0 3700.0 0.0 3.65 18.88 E 0,00 $4.8 S985 439.3 0.0 1192.6 7441.4 1500.0 3935.0 0.0 3.80 17.98 24.72 0.00 57.0 707.5 494.0 0.0 1260.6 7823.1 1500.0 4170.0 0,0 3095 17.19 26.13 0.00 59.2 FIELD 362.7 0.0 1338.9 8224.4 1500.0 4405.0 0.0 4.11 16,50 27.63 0.90 61.6 726.7 640.8 0.0 1429.0 8646.4 1500.0 4640.0 0.0 4.27 15.88 29,20 0,00 64.1 73668 732.0 0.0 1532.9 9089.9 1500.0 4875.0 0.0 4.44 18.33 30,38 0.00 6646 PA7A4 838,2 0.0 1652.2 TABLE IS ENERGY PRODUCTION MIX» AVERAGE COST FER KWH» SOOO OO OOK AND) ANNUAL COST FOR ELECTRIC ENERGY FRODUCED FOR *ASSUMP TIONS * COMBINED WITH ADDITION OF WEST CREEK * GENERAL INFLATION 4%% * FUEL INFLATION 64% 1980 TO 2005 * INTEREST RATE 9nx SOOO OOO RIOR EK PRODUCT ION ENERGY FRODUCTION(MWH) COST PER KWH(CENTS) ANNUAL COSTS($1000) LOAD MKT MKT FORECAST EXIST NEW EXIST NFW WEIGHT EXIST NEW YEAR (MWH) HYDRO HYDRO DTESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HYDRO DIESEL OTHER TOTAL 1980 14081.0 1500.0 0.0 6320.0 6261.0 14081,0 1.647 0.00 7.80 6.00 6-35 25.0 9.0 375 B93, 1981 12454,0 1500.0 0.0 4693.0 6261.0 12454,0 L673 0.00 8.24 6.36 6.51 26.0 0.0 398.2 810.7 1982 12512.,0 1500.0 0.0 4751.0 6261.0 12512.0 1.80 0.00 8.70 674 4.89 2700 0.0 422.1 862.3 1983 12166.0 1500.0 0.0 4405.0 6261,0 12166.0 1,87 0.00 9.18 7AS 7.2 28.1 0.0 447.4 880.1 1984 13925,0 1500.0 0-0 6164.0 6261.0 13925.0 1.95 0.00 9.70 7.57 791 29.2 0.0 474.3 1101.4 1985 14449,0 1500.0 0.0 6688.0 6261.0 14449,0 2.03 0.00 10.24 8.03 8.43 30.4 0.0 502.7 1218.3 1986 15481.0 1500.0 0.0 7720.0 6261,0 15481,0 2.11 9,00 10.82 8.51 9.04 31.6 0.0 5] 9 1399.7 1987 16040.0 1500.0 0.0 279.0 6261.0 16040.0 2.19 9.00 11.43 9.02 9463 32.9 0.0 564.7 1544.9 1988 16675.0 1500.0 15175.0 0.0 0.0 16675.0 69,01 12.07 0.00 43,00 34,2 10471 o.0 10505.8 1989 172946.0 1500.0 15796.0 0.0 0.0 17296.0 66.44 12,75 0,00 460,88 35.6 10494,3 0.0 10529.8 1990 17957.0 1500.0 16457.0 0.0 0.0 17957.0 63.91 13.47 0,00 58.78 37.0 10517.9 0.0 10554.9 1991 18928.8 1500.0 17428.8 0.0 6.0 18928.8 60.49 14,23 0.00 55.90 38.5 10542.5 +2 10580.9 1992 19953,.2 1500.0 18453.2 0.0 0.0 19953.2 S7.27 15.04 0.00 53.16 40,0 10568,0 0.0 10608,9 1993 21033,0 1500.0 19533.0 0.0 0.0 21033.0 54,24 15.89 0.00 50.57 41,6 10594,6 0,0 10636.2 1994 22171.3 1500.0 20671.3 0.0 0.0 22171.3 51.39 16.79 0.00 48.114 43.3 10622,2 0.0 10665.5 1995 23371.4 1500.0 21871.4 0.0 0.0 23371.4 42.70 17,74 0.00 45.7? 5.0 10651.0 0.0 10696.0 1996 24636.4 1500.0 23136.4 0.0 0.0 24636.4 46.16 18,75 9.00 43.54 46.8 10680.9 0.0 10727.7 1997 25970.0 1500.0 24470,0 0.0 0.0 25970.0 3.78 19.81 0.00 41.43 48.7 10711.9 0.0 10760.4 1998 27375.8 1500.0 25875.8 0.0 0.0 27375.8 41,52 20.94 0.00 29,43 50.8 10744,3 0.0 10794.9 28857.8 1500.0 27357. 0.0 0.0 28857.8 39.40 22.13 0.00 37,53 3 10777.9 0.9 10830.6 30420.1 1500.0 28920.1 0.0 0.0 30420.1 37.39 23,39 0.00 35.73 54.8 16812.9 0.0 10867 32067.0 1500.0 30567,0 0.0 0.0 32067.0 35.49 24.72 0.00 34,01 57.9 10849.2 0.0 10906.2 33803.1 1500.0 32303.1 0.0 0,0 33803.1 33.70 26.13 0,00 32,38 59,2 10887.1 0.0 10946.3 35633.3 1500.0 34133.3 0.0 0.0 35633.3 32.01 27,63 0.00 30.84 61.6 10926.4 0,0 10988,0 37562,.8 1500.0 36062.8 0.0 0.0 37562.8 30.41 29.20 0.00 29,37 64.1 10967,3 0.0 11031.4 39596.7 1500.0 38096.7 0.0 0.0 39596.7 28.90 30,88 0.00 27.97 66.6 11009.9 0.0 11076.5 o°sse9 0°O v°ZéZT O°86bb 9°99 90°9T 00°0 BB°OL L4'°et 0°G £°808S O'°88ccr 0'°00S L£°96SEE GOO0E L£*vvsS 0°O 4° Stor S*iore Tvs cs°st 00°O Of°6E OF'HT oro 8°24S8e O'SOETS O'OOST B'E9GZE bOGT 6°S6SS 0°O 6°ZOoTT 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O'TB80b¥T O86T WLOL MBHLO = (“TaS3at OMTAH OMJAH SOYMSAY MSHLO IASSIN OMTAH OMWAH WILOL M3HLO VaS3IN OMWAH OMMAH CHMW) MVaA MAN LSIX3 LHOTaM MAN 4SIX3 MAN iSIx3 LSVOSM04 LNW LNW LNW 1907 (O00T$)S1S09 TWANNY (SLN3D)HMN Yad 1909 CHMWONOTLONIONd ASYANA NOTLINION SOOO OOK K2Z6 3L¥N LS3MSLNI x KX NOTAYVANI TANd * $00E OL O86T *%b | NOTLY TANT WMSNA9 * ANYT L909 JO NOTLIUIY HLIM WAaNTSWOO x SNOTLAWNSSY* 404 (1S39NT0YNd AOYSNS JIMLISZTZ YOs LSOD TWWANNY HINY 2 OOOO KAR RRA K ‘HMM 43d LS09 39V¥SN9 “XIW NOTLOINIONS AOMSNA FI AW¥L YARBLE [7 ENERGY PRODUCTION MIX» AVERAGE COST FER KWHy SOI TOCCOA IK AND ANNUAL COST FOR ELECTRIC ENERGY PRODUCED FOR XASSUMP TIONS * COMBINED WITH ADDITION OF UPPER CHILKOOT * GENERAL INFLATION 4%% 1980 TO 2005 * FUEL INFLATION 64 * INTEREST RATE DUK FIO ORO KK PRODUCTION ENERGY FRODUCTION(MWH) COST PER KWH(CENTS) ANNUAL COSTS($1000) Loan MKT MKT MKT FORECAST EXIST NEW EXIST NEW WEIGHT EXIST NEW YEAR CMWH > HYDRO HYLRO DTESEL OTHER TOTAL HYDRO HYDRO DIESEL OTHER AVERAGE HYDRO HYDRO NIESEL OTHER 1980 14081.0 1500.0 0.0 6320.9 6261.0 14081.0 1.67 0.00 7.80 6.00 6.35 25.0 0.0 493.0 375.7 893.6 1961 12454.0 1500.0 0.0 4693.0 $261.0 12454.0 1.73 9.00 $.24 6436 6.51 26.0 0.0 386.5 398.2 810.7 1982 12512. 1500.0 0,0 4751.0 6261,0 12512.0 1,80 c.00 8.70 6.74 6.89 27.0 0.0 413.2 422.1 862.3 1983 12166.0 1500.0 0.0 4405.0 6261.0 12166.0 1.87 0.00 9.18 7AS 023 28.1 0.0 404.6 447. 880.1 1984 13925.0 1500.0 0.0 6164.0 6261,0 13925.0 1.95 0,00 9.70 7657 791 29.2 0.90 597.8 474.3 1101.4 1985 14449.0 1500.0 9.0 6688.0 6261.0 14449,0 2.03 0.00 10.24 8.03 8.423 30.4 0.0 685.1 502.7, 1218.3 1966 19481.0 1500.0 13981.0 0.0 9.0 15481.0 2eiL 31.17 10,82 0.00 28.35 31.6 4357.4 0.0 0.0 4389.0 1987 16040.0 1500.0 14540.0 0.0 0.0 16040.0 2.19 30,10 11.43 0.00 27.49 3269 4376.2 0.0 0.0 4409.1 1988 16675.0 1500.0 15175.0 0.0 0.0 16675.0 2.28 28.97 12.07 0.00 26.57 34.2 4395.8 0.0 0.0 4430.0 1989 17296.0 1500.0 15796.0 9.9 0.0 17296.0 2637 27.96 12.75 0.90 25.74 35.6 4416.2 0.0 0.0 4451.8 1990 17957.0 1500.0 16457.0 G.0 0.0 17957.0 2.47 26,96 13,47 9.00 24.92 37.0 4437.4 0.0 0.0 4474.4 1991 18928.8 1500.0 17428.3 0.0 0.0 18928.8 2.57 25.59 14.23 0.90 23.76 38.5 4459.4 0.0 0.0 4497.9 1992 19954.2 1500.0 18453.0 0.2 0.0 19953.2 2.67 24.29 15.04 0.00 22.67 40.0 4482.3 0.0 0.0 4522.4 1993 21033.0 1500.0 19318.0 215.0 9.0 21033.0 2.78 23.33 15.89 0.00 21.78 41.6 4506.2 34.2 0.0 4582.0 1994 22171.3 1500.0 20183,0 488.3 9.9 22171.3 2.89 22.45 16.79 0.00 21.00 43.3 4531.0 82.0 0.0 4656.3 1995 23371.4 1500.0 21049.0 822.4 0.0 23371.4 3.00 21.65 17.74 9.00 20.31 45.0 4556.8 145.9 0.0 4747.7 1996 24636.4 1500.9 21914.9 1222.4 0.0 24625.4 3.12 92 18.75 0.00 19.73 46.8 4583.6 229.2 0.0 4859.6 1997 25970.0 1500.0 22779.0 1691.0 0.0 25970.0 3.25 20.24 19,81 9.00 19.23 48.7 4611.5 335.0 0.0 4995.2 1998 27375.8 1500.0 22644.0 3231.8 0.0 27375.8 3.38 20.49 20.94 0.00 19.61 50.6 4640.5 676.7 0.0 5367.8 1999 28857.8 1500.0 24510.0 2847.8 0.0 28857.8 3.51 19.06 22.13 0.060 18.55 S2.7 4670.7 630.2 0.0 $353.6 2000 30420.1 1500.0 25375.0 3545.1 0.0 30420.1 3.65 18.53 23.39 0.00 18.36 54.8 4702.0 829.2 0.0 S586.0 2001 32067.0 1500.0 26525.0 4042.0 0,0 32067.0 3.80 17.85 24.72 0.00 18.06 57.0 4734.7 999.63 0.0 5791.0 2002 33803.1 1500.0 27675.9 4628.1 0.0 33803.1 3.95 17.23 26.12 04:00 17,86 S9.2 4768.6 1209.5 0.0 6037.4 2002 35633.3 1500.0 28825.0 S308.3 0.0 35633.3 4,11 16.67 27.63 0.00 17.77 61.4 4803.9 1466.5 0.0 6332.0 2004 37562.8 1500.0 29975.0 6087.8 9.0 37562.8 4.27 14.15 29.20 0.06 17.7 64.1 4840.6 1777.9 0.0 6682.6 2005 39596.7 1500.0 31125.0 6971.7 0.0 0.0 7097.9 3959647 4,44 15,67 30,88 0.00 17.93 66.6 4878.8 2152.5 TABLE 1g YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 a 1992 1993 1994 1995 1996 1997 1998 Lear 2000 2001 2002 2003 2004 2008 AND LOAD FORECAST EXIST HYDRO CMWH) 7902.0 8180.0 8840.0 9143.0 10725.0 11075.0 11969.0 12348.0 12787.0 13210.0 13665.0 14416.6 15209.5 16046.0 16928.5 17859.6 18841.9 19878.2 20971.5 22124.9 23341.8 24625.6 25980.0 27408.9 28916.4 30506.8 ENERGY PRODUCTION MIX» ENERGY ecoooooooococococoooccoooooco eccoceoceceoce|ecocoeocoooooooocs eoooocoooocoocooooocoocoosooS eccooooooooocecococoooooocoso PRODUCTION (MWH) DIESEL 1641.0 1919.0 2579.0 2882.0 4464.0 4814.0 5708.0 6087.0 6526.0 6949.0 7404.0 8155.6 8948.5 9785.0 10667.5 11598.6 12580.9 13617.2 14710.5 15863.9 23341.8 2462546 25980.0 27408.9 28916.4 30506.8 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 6261.0 0.0 0.0 eoooo ° oO. oO. oO. AVERAGE COST FER KWH» ANNUAL COST FOR ELECTRIC ENERGY PRODUCED HAINES ASSUMING NO ADDITIONAL HYDRO 1980 TO 7902.0 8180.0 8840.0 9143.0 10725.0 11075.0 11969.0 12348.0 12787.0 13210.0 13665.0 14416.6 15209.5 16046.0 16928.5 17859.6 18841.9 19878.2 20971.5 22124.9 23341.8 2462546 25980.0 27408.9 28916.4 30506.8 6.00 6436 6474 7AS 7057 8.03 8.51 9.02 9.56 10.14 10.75 11.39 12.07 12.80 13.57 14.38 15.24 16.16 17.13 18.15 0.00 0.00 0.00 0.00 0.00 0.00 PRODUCTION COST FER KWH(CENTS) MKT NEW HYDRO DIESEL 0.00 7.80 0.00 8.24 0.00 8.70 0.00 9.18 0.00 9.70 0.00 10.24 0.00 10.82 0.00 11.43 0.00 12.07 0.00 12.75 0.00 13.47 0.00 14.23 0.00 15.04 0.00 15.89 0.00 16.79 0-00 17474 0.00 18.75 0.00 19.81 0.00 20.94 0.00 22.13 0.00 23.39 0.00 24.72 0.00 26.13 0.00 27.63 0.00 29.20 0.00 30.88 WEIGHT AVERAGE HYDRO 64637 6.80 7.31 7.79 8.46 8.99 9.61 10.21 10.84 11.51 12.22 13.00 13.82 14.68 15.60 16.56 17.58 18.66 19.80 21.00 23.39 24.72 26.13 27.63 29.20 30.88 EXIST occoooooooooooooooooooooooso ececoooooooocoooooooooococoecsfo ecocoooocoococoococececoeooocoo ecocooooooocoooococoooocoocooooceo SAO IOK *XASSUMPTIONS x %* GENERAL INFLATION 4% %* FUEL INFLATION * INTEREST RATE 62% Gn SOOO O I OIOOIIOIO I IOK ANNUAL COSTS($1000) 128.0 158.0 224.3 264.7 433.0 493.1 617.5 695.6 787.8 886.1 9976S 1160.8 1345.6 1554.6 1790.9 2057.6 2358.5 2697.8 3080.1 3510.7 5459.6 6088.2 6789.6 7572.0 8445.0 9419.0 503.7 556.2 646.4 712.1 907.2 995.9 1150.4 1260.5 1386.6 1520.8 1670.2 1873.9 2101.5 2355.9 2640.2 295769 3312.8 3709.4 4152.3 4647.3 S4S9+6 6088.2 6789.6 7572.0 8445.0 9419.0 TABLE 19 Loan YEAR — (MWH) 1980 6179.0 1981 4274.0 1982 3672.0 1983 3023.0 1984 3200.0 1985 3374.0 1986 3512.0 1987 3692.0 1988 3888.0 1989 4086.0 1990 4292.0 1991 4512.2 1992 4743.7 1993 4987.0 1994 5242.8 1995 5511.8 1996 5794.5 1997 6091.8 1998 6404.3 1999 6732.9 2000 7078.3 2001 7441.4 2002 7823.1 2003 8224.4 2004 8646.4 2005 9089.9 ENERGY PRODUCTION MIX» AND ANNUAL COST FOR ELECTRIC ENERGY FRODUCED FOR SKAGWAY ASSUMING NO ADDITIONAL HYDRO 1980 TO 2005 ENERGY FRODUCTION(MWH) AVERAGE COST FER KWH» FORECAST EXIST HYDRO 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 1500.0 oocoocoooooooooocecoeococooocyoe ecoooocoeoocoeocooooocooocooooo DIESEL 4679.0 2774.0 2172.0 1523.0 1700.0 1874.0 2012.0 2192.0 2388.0 2586.0 2792.0 3012.2 3243.7 3487.0 3742.8 4011.8 429465 4591.8 4904.3 5232.9 5578.3 5941.4 6323.1 6724.64 7146.4 7589.9 ecoococeooocooocoooocoooocoooococy“e ecoccooooocococoece|ce|ececocoocecéo 3374.0 3512.0 3692.0 3888.0 4086.0 4292.0 4512.2 4743.7 4987.0 5242.8 $511.8 5794.5 6091.8 6404.3 6732.9 7078.3 7441.4 7823.1 8224.4 8646.4 9089.9 EXIST HYDRO PRODUCTION COST FER KWH(CENTS) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 HYDRO DIESEL 7.80 8.24 8.70 9.18 9.70 10.24 10.82 11.43 12.07 12.75 13.47 14.23 15.04 15.89 16.79 17.74 18.75 19.81 20.94 22.13 23.39 24.72 26.13 27.63 29.20 30,88 OTHER 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 WEIGHT AVERAGE 6-31 5.95 5.88 5.56 6.07 6.59 7.10 7+68 8.29 B.94 9.63 10.35 11.13 11.94 12.81 13.73 14.70 15.73 16.82 17.98 19.21 20.51 21.88 23.34 24.88 26.51 EXIST HYDRO 25.0 26.0 27.0 28.1 29.2 30.4 31.6 32.9 34.2 35.6 37.0 38.5 40.0 41.6 43.3 45.0 46.8 48.7 50.6 52.7 54.8 57.0 59.2 61.6 6461 6666 HYDRO ecoooocoococococococooooooce ooooooocoooocooccoooCSoOOSCOOCOCSOSD SOOO ORK KOK XASSUMF'TIONS x %* GENERAL INFLATION 4% * FUEL INFLATION * INTEREST RATE 62% OU SOOO OOK KK ANNUAL COSTS( $1000) DIESEL 365.0 228.5 188.9 139.9 164.9 192.0 217.7 250-5 288.3 329.8 37661 428.7 487.8 554.0 628.3 711.7 805.1 90967 1026.9 1158.0 1304.8 1468.9 1652.5 1857.7 2087.1 2343.4 OTHER ecocooooocoocoocoooecooocoooooso eooccoooococoeoocooCooOSC OOO OCOCOS TOTAL 390.0 254.5 215.9 168.0 194.1 222.4 249.3 283.4 322.5 365.3 413.1 467.2 527.8 595.6 671.46 75667 851.9 938.4 1077.5 1210.7 1359.5 1525.9 1711.7 1919.3 2151.2 2410.0