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Home My WebLink AboutAngoon Hydroelectric Project HDR Study 2000ANGOON HYDROELECTRIC PROJECT 10. W/A 414 4 ( J; 4 -4 A' WIAll I'll 110 t - -IL I ljoj FOR !4 ' I� ItOOTZNOOWOO INCORPORATED MARC"* 2000 SECTION TITLE PAGE EXECUTIVE SUMMARY .-.-..------.----.-----.----.--.-.-.-. ES-1 I-.--..-----.-..---..---.---.--.----.-.---.--.-..l IL ANGO[)N LOADS AND RESOURCES ........................................................................... 3 ID. GENERAL DESCRIPTION OFTHE LOCALE ................................................................ 6 IV HYDROLOGY --.------.------..--.-----------.---------.7 V. ALTERNATIVE PROJECT ARRANGEMENTS........................................................... lO \/I SELECTED PROJECT ARRANGEMENT ..------------.--..---.---...2l VIIPOWER OUTPUT ............................................................................................................ 28 VIIISCHEDULE ....................................................................................... 3l DX. COST ESTIMATE ............................................................................................................ 34 X. ECONOMIC ANALYSIS ................................................................................................. 4l XI. CONCLUSIONS AND RECOMMENDATIONS ---..-.--.---.-.--..-.---..47 ANGN HYDROELECTRIC PROJECT FEASIBILITY EVALUATION REPORT FIGURE TITLE 1. Location Map and Vicinity Map 2. Annual Flow Duration Curve 3. Flood Frequency Curve 4. Alternative 1 General Plan 5. Alternative 2 General Plan 6. Alternative 3 General Plan 7. Selected Arrangement General Plan 8. Diversion Dam and Intake Structure 9. Pipeline, Surge Tank, and Penstock - - Sections 10. Powerhouse - - Site Plan 11. Powerhouse - - Interior Plan 12. Powerhouse - - Elevation and Section 13. Transmission Line - - Sections 14. One -Line Diagram - - Sheet 1 15. One -Line Diagram - - Sheet 2 16. Development Schedule 17. Grant Funding Requirements with Continued Service by T-HREA 18. Cost of Power Projection with Continued Service by T-HREA 19. Grant Funding Requirements with Stand -Alone Angoon Utility 20. Cost of Power Projection with Stand -Alone Angoon Utility A. ANILCA Section 506 (Relevant Paragraphs) B. Monthly Flow Duration Curves C. Power Duration Curves (Selected Arrangement) D. Economic Analysis Spreadsheets HDR Alaska, Inc. March 2000 ANGOON HYDROELECTRIC PROJECT FEASIBILITY EVALUATION REPORT U Kootznoowoo Incorporated (Kootznoowoo) is the village corporation for the city of Angoon, which is located on the west side of Admiralty Island approximately 60 miles southwest of Juneau, Alaska. Kootznoowoo is considering the development of the Angoon Hydroelectric Project (Project) as a means to lower the cost of power generation in Angoon, directly benefiting the residents with lower electric bills and indirectly stimulating the local economy. The Alaska National Interest Lands Conservation Act of 1980 (ANILCA) specifically provides to Kootznoowoo the right to develop the Project subject to conditioning authority by the U.S. Forest Service. Electricity is currently supplied to residents and businesses in Angoon by the Tlingit-Haida Regional Electric Authority (T-HREA) at rates that are some of the highest in Alaska (about 32.5 0/kWh). The average load in Angoon is currently about 230 kW, and the peak load is about 425 kW. To meet the existing loads, T-HREA has a single power plant in Angoon with two diesel generators with an aggregate generating capacity of 1,115 kW. Potential new electric loads are possible in Angoon due to the recent distribution of over 600 homesites to Kootznoowoo shareholders and the proposed siting of a Alaska Marine Highway System near Angoon by the Alaska Department of Transportation and Public Facilities. Practical alternatives for supplying the existing and new loads are: 1) continuation of diesel generation, and 2) development of the Project if sufficient funding assistance can be obtained (as is relatively common for small hydro developments in Alaska). C. PROJECT SETTING The Project would be located on Thayer Creek approximately 6 miles north of Angoon, as shown in Figure 1. Thayer Creek flows out of Thayer Lake for about 6 miles at a gentle grade through a broad forested valley, then steepens for 6,800 feet through a narrow forested canyon, and finally flattens again for 2,000 feet before flowing into Chatham Straight. The Project will develop the energy potential in the steep section of the stream. The lower section supports anadromous runs of pink, chum, and coho salmon, and the upper section supports cutthroat trout. It is unknown if the steep section of stream supports any resident fish. The average flow in Thayer Creek is about 370 cfs, and can vary from 25 cfs during cold periods in the winter to over 2000 cfs during storms in the fall and winter. The Project area is in the Kootznoowoo Wilderness on Admiralty Island, an area with no roads and few trails. The lack of access will have a significant influence on the ability to develop the Project economically, both from the direct cost of providing access during construction and operation and from possible opposition to the Project's development. HDR Alaska, Inc. ES-1 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated D. ALTERNATIVE ARRANGEMENTS The initial phase of the work documented by this report was to evaluate several alternative arrangements for the Project so that a preferred alternative could be selected. Three primary alternative arrangements were evaluated, as follows: e Alternative 1 - - Pipeline and Penstock e Alternative 2 - - Directional -Drilled Tunnel e Alternative 3 - - Conventional Tunnel A comparison of some of the primary costs and benefits of these three alternatives is shown in Table ES-1. Additional alternatives looked at the cost and benefits of decreasing the installed capacity to 500 kW, using overhead or buried transmission instead of submarine, and adding a water supply pipeline along the submarine transmission line. At a review meeting on April 26, 1999, Kootznoowoo selected Alternative 1 - - Pipeline and Penstock as the preferred alternative. In the second phase of work, this preferred alternative was refined to develop the selected arrangement, as described below. E. SELECTED ARRANGEMENT 1. Project Features Figure 7 provides a general plan of the selected arrangement for the Project. The major features are as follows: Port facilities will include a temporary barge landing, mooring buoys, and a garage for housing operation and maintenance vehicles. The port facilities will be located approximately 1.8 miles south of the outlet of Thayer Creek where an existing peninsula provides secure anchorage and protection from storms. There will be three access roads for the selected arrangement. The first will lead from the port facilities to the power plant, and will be approximately 1.9 miles long. The second access road will lead from the powerhouse access road near the powerhouse to the diversion dam/intake structure, and will be approximately 7,200 feet long. A 1,000-feet long spur from this road will provide access to the top of the surge tank during construction. The third access road will be from the port facilities to Kootznoowoo Inlet, and will be a minimum -construction road primarily for installation of the transmission line; it will also provide emergency access to the Angoon facilities by all -terrain vehicles. The diversion darn will be located approximately 8500 feet above tidewater at the head of a very steep section of rapids about 250 feet above sea level. The dam will be primarily a concrete wall approximately 10 feet high, with grouted rockfill on each side for stability. The intake structure will be located on the north abutment of the diversion dam, and will be primarily a concrete structure housing a trashrack, transition section, shutoff valve, sluiceway, and control facilities. Modified shipping containers will be incorporated in the construction of the intake structure, and will initially function as diversion flumes to bypass water around the damsite during construction. HDR Alaska, Inc. ES-1 March 2000 I i Me" gg- mg W-1 Cd xe- 0 WIN oWd"URM 'M '52 Cd 79b 00 0 4-4 0 OU Cd 0 cd 0 4- C4 C.) rn + C4 o -15 7� .2 b) 0 0 z alT NP 0 C-) 0 vi Go!) 'Q 2 4 > cd 7:3 7:$ to CN Goa 0 4-4 4-4 +C4 ct cd cz 'o 0 0 cz 0 C,3 cl Cd cn co Q) 03 C�, -t:� = rn 0 0 0 0 cd 0 0 In. 0 0 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated The pipeline will be a 42-inch diameter HDPE pipeline about 6,100 feet long from the intake structure to just above the powerhouse. The pipeline will be laid on grade through the forest for its entire length, with minimal clearing. It will be at a gentle grade to minimize the pipe thickness requirement. The penstock will be aboveground 36-inch diameter steel pipe about 510 feet long. It will convey water from the downstream end of the pipeline down the hillside to the powerhouse. Just upstream of the powerhouse, the penstock will branch into two 24-inch pipes leading to the turbines. The surge tank will be a 240 feet long section of 6 feet diameter concrete pipe laid on grade above the junction of the pipeline and penstock. The surge tank will provide passive protection against pressure surges in the pipeline. It will also assure good frequency control by the Project. The power plant will be located about 300 feet downstream of a waterfall that serves as a natural barrier to upstream migration of anadromous fish. The power plant structure will be a pre-engineered metal building set on a concrete foundation, and will be about 30-feet by 68-feet in plan dimension, and about 25 feet high. It will house two generating units, each consisting of a 700-HP horizontal -shaft Francis turbine, 500-kW synchronous generator, and flywheel. The power plant will also contain standard utility controls and metering to provide remote unattended operation. The power plant will discharge through a pipe as far upstream as practical to minimize the impact to anadromous fish habitat. The transmission line will include three distinct sections. The initial section will be an overhead 12.5-kV line from the powerhouse to the port facilities, and will be placed adjacent to the powerhouse access road (a length of 1.9 miles). The second section will be from the port facilities to Kootznoowoo Inlet (4.2 miles). It will also be an overhead line, but it will be constructed through the forest from the minimum -construction access road described above, with a clearing width of approximately 25-30 feet. The third section will be a submarine crossing of Kootznoowoo Inlet to vicinity of the existing float plane dock (4,600 feet). During construction, there will be two staging areas. One will be located at a large flat area between the port facilities and the power plant. A construction camp could also be located at that site if necessary. The second staging area would be located at a flat area about midway between the power plant and the diversion dam. This staging area will be used primarily for construction of the diversion dam and pipeline. f 2. Generation The Project will be able to supply all of Angoon's power needs at current load levels over 99% of the time; generation would need to be supplemented on an average of about 2 days per year. This percentage would decrease to slightly less than 99% (4 days/year) if loads increase by 50% and to 97% (10 days/year) if loads increase by 100%. The Project has the potential to generate about 8.5 million kWh/year, which is over 4 times the current Angoon annual energy requirement (2.0 million kWh/year). The generation amounts indicated above are based on an assumed instream flow requirement of 20 cfs. If resident fish are found in the bypassed reach of Thayer Creek, it is probable that the state and federal fisheries agencies would want a significantly greater instream flow, which would decrease the Project generation. HDR Alaska, Inc. ES-3 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 3. Estimated Construction Cost The estimated total cost for the selected arrangement is $8,100,000, as summarized in Table ES- r 2. The cost includes about $6,900,000 for direct construction costs and about $1,200,000 for indirect costs for licensing, design, and construction management. This estimate is based on a conventional design/bid/build method of Project development. Other methods of development x; are possible which could reduce the cost total cost, although at some greater risk or loss of management control by Kootznoowoo. The estimated cost of $8,100,000 compares to $9,300,000 previously estimated for Alternative 1, and $8,500,000 estimated in 1996 by the GH Group for a somewhat similar Project arrangement and assumptions. A preliminary development schedule is shown in Figure 16. The development of the Project will occur in three phases, assuming the development proceeds on a "normal" track. The first phase is preliminary design and permitting, which includes the current effort as well as future work to obtain the necessary construction approvals from state and federal authorities. The second phase is design and contract bidding, and the final phase is the actual construction. As can be seen from Figure 16, the schedule results in the Project generating power in mid-2005, which is considered the earliest that the Project could be completed. A significantly longer schedule can be expected if there is a lack of consensus regarding the desirability of development of the Project. In the near term, Project development should focus the following activities: e Determination of the regulatory framework for Project development. ® Pursuit of grant funding and/or low -interest loans to make the Project economical. ® Resolution of utility structure issues associated with Project development. G. ECONOMIC ANALYSIS The economic analysis contained in the 1998 Angoon Power Supply Study was updated to reflect the estimated cost of the Project as determined by the current studies. The economic analysis is z' basically a comparison of the future cost of power to Angoon citizens with and without the Project under two different utility structures. For the first utility structure, it was assumed that power from the Project would be sold to T- HREA, who would continue to supply electricity to Angoon. With this utility structure, there is only a small benefit to T-HREA customers from Project construction if nearly all of the construction cost is grant -funded (i.e., a 2-3% reduction in power costs). Although the benefit is small, obtaining grant -funding could be easier with this utility structure since the grant would help more citizens. For the second utility structure, it was assumed that T-HREA ceases supplying electricity to Angoon, and Angoon sets up a municipal utility. With this utility structure, there is a substantial benefit to the community if nearly all of the construction cost is grant -funded. The cost of power to Angoon citizens initially would be slightly less than the current cost, and would stay relatively constant. HDR Alaska, Inc. ES-4 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated COST SUMMARY .fit SELECTED PROJECT ARRANGEMENT Feasibility Evaluation Report 330 Land and Land Rights $ - 330.5 Mobilization and Logistics $ 741,000 331 Sturctures and Improvements $ 543,000 332 Reservoirs, Dams, and Waterways $ 1,587,000 333 Turbines and Generators $ 715,000 334 Accessory Electrical Equipment $ 366,000 335 Miscellaneous Mechanical Equipment $ 110,000 336 Roads and Bridges $ 789,000 353 Substation Equipment and Structures $ 48,000 355 Transmission Line $ 1,173,000 CONTINGENCIES: Equipment Contingency (Accts. 333,334,335) $ 120,000 Transmission Line Contingency (Accts 353,355) $ 240,000 General Contingency (Accts 330,330.5,331,332,336,350) $ 440,000 PERMITTING AND ENGINEERING: Licensing/Permitting $ 578,000 Design Engineering $ 400,000 Construction Management $ 250,000 TO'I' PREJECT ' OST (1999 Cost Level} $ �;100 000 j HDR Alaska, Inc. ES-5 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report The analyses confirm that substantial grant funding is necessary for the Project to have a direct net positive economic benefit. With either assumed utility structure, about 75% of the cost must be grant -funded for the Project to demonstrate economic feasibility over a 30-year time frame. This does not consider indirect economic benefits that could accrue due to the electric rate stability provided by the Project. Sensitivity analyses were conducted for varying assumptions regarding load growth rates in Angoon and varying diesel fuel prices. The Project's viability is enhanced by higher load growth rates and diesel fuel prices with either assumed utility structure. HDR Alaska, Inc. ES-6 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated . INTRODUCTION A. LOCATION The Angoon Hydroelectric Project ("Project") is a potential hydroelectric development on Thayer Creek approximately 6 miles north of Angoon, Alaska. Thayer Creek and Angoon are on Admiralty Island in southeast Alaska approximately 60 miles southwest of Juneau. Kootznoowoo Incorporated ("Kootznoowoo") is the native corporation for Angoon incorporated pursuant to the Alaska Native Claims Settlement Act. Most of the lands on Admiralty Island, including the lands to be occupied by the Project, are reserved as the Admiralty Island National Monument and Kootznoowoo Wilderness ("Monument"), which was created by the Alaska National Interest Lands Conservation Act of 1980 ("ANILCA"). ANILCA reserved to Kootznoowoo the rights to develop the hydroelectric potential of the Thayer Creek area, including lands for an overland transmission line to Angoon (see Appendix A). Angoon is the only permanent settlement on Admiralty Island, and has a population of approximately 600. It is accessible only by air or water, and there is regular floatplane service from Juneau. Angoon is electrically isolated, and power is supplied by the Tlingit-Haida Regional Electric Authority ("T-HREA"). The T-HREA electric rates are some of the highest in Alaska (about 32.5 0/kWh). Angoon's proximity to the Monument provides a small but growing tourism business. In addition, the Alaska Department of Transportation and Public Facilities ("ADOTPF") is proposing development of a Alaska Marine Highway System terminal near Angoon. Decreasing the cost of electric power in Angoon could facilitate the development of both tourism and the ferry terminal. [.4 114 Z�7`7 Although ANILCA provided the right to develop the Project in 1980, there has been only intermittent development activity as Kootznoowoo focused on other activities. With the decline of its timber resources, in the mid-1990's Kootznoowoo started to consider its other assets, including the hydroelectric development rights granted by ANILCA. The current study was authorized on January 26, 1999 to provide Kootznoowoo with a basis for deciding whether the Project's feasibility warrants proceeding with permitting and design efforts. The main tasks authorized for the present study were: a Evaluation of alternative project arrangements to determine the most feasible. t ® Evaluation of Project hydrology, including installation of a stream gage on Thayer Creek. ® Estimation of the potential power generation by the Project. ® Estimation of construction and operating costs for the Project. ® Determination of the permits that will be necessary for Project development. HDR Alaska, Inc. 1 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report Preparation of a schedule for Project development, including a list of the major milestones. ® Analysis of the economic feasibility of the Project, considering the alternatives available for supplying power to Angoon and the possibility of obtaining financial assistance. HDR Alaska, Inc. 2 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated I. ANGOON LOADS AND RESOURCES A. INTRODUCTION The following discussion of Angoon loads and resources primarily summarizes information from the Angoon Power Supply Study (HDR, 1998), with some updating. The reader is referred to that report for details. D. EXISTING ANGOON LOADS For the period 1992-97, energy sales in Angoon increased each year until 1997, when sales decreased 10%. For the last few years, peak loads in Angoon have been relatively stable at approximately 425 kW, and the average loads have been about 230 kW. These loads are somewhat seasonal, with peak loads in the winter months. Table II-1 provides a typical monthly distribution of peak and average loads. Note that the loads shown in Table 11-1 are average values for five years of data. In any one year, there may be much greater variability in the loads. January 407 265 February 411 290 March 394 223 April 371 247 May 340 215 June 326 196 July 293 180 August 304 195 September 327 211 October 349 219 November 404 256 December 425 254 Annual '425 230 C. FUTURE LOADS The Angoon Power Supply Study did not include a detailed projection of future loads and resources. Instead, it assumed that Angoon loads would increase by approximately 1 % per year. Further, it noted the possibility of three future economic developments in Angoon that could HDR Alaska, Inc. 3 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated increase the loads more than the base 1 % per year. The following is an update of the status of those potential future loads Aircraft maintenance facility: Kootznoowoo is no longer considering the development of an aircraft maintenance facility in Angoon. State marine ferry facility: At the present time, it appears that ADOTPF will proceed with the development of a Alaska Marine Highway System terminal near Angoon. However, rather than being located deep in Hood Bay and therefore isolated from Angoon, ADOTPF is considering a location at the southern limit of the Angoon road system. The increase in energy sales directly associated with the ferry terminal may be relatively small, but it could stimulate increased tourism and support service industries in Angoon, with resulting increases in energy sales. Dome site allocation: Kootznoowoo recently allocated over 600 homesites in the Angoon area to corporation shareholders. It is not yet clear how the homesite allocation will affect growth in Angoon. However, it does provide an opportunity for population growth (and the attendant electrical load growth) if other developments provide an economic incentive. D. EXISTING RESOURCES In order to provide for the power requirements in Angoon, T-HREA currently owns and operates two diesel -fueled internal combustion generators with a combined capacity of 1,115 kilowatts (one at 565 kW and one at 550 kW). Diesel generators of this size should last, if properly maintained, for 150,000 or more operating hours. The existing diesel generator capacity is sufficient to meet load through 2027 if peak requirements increase at 1 percent annually. However, if the resources are retired prior to then or loads increase at a greater rate, then capacity shortfalls would occur prior to 2027. A 2 percent load growth would result in capacity shortfalls after 2014. Even though the existing diesel generator capacity is sufficient for several years of growth, there is considerable incentive for the development of alternate resources, including: 1. T-HREA's rates are currently some of the highest in Alaska (32.5 0/kWh). In addition, T-HREA no longer provides electricity to Klawock, which will result in T-HREA's fixed costs being paid by fewer customers. T-HREA has indicated that because of the loss of Klawock, they will have to maintain their rates at the current level rather than institute a rate decrease as they had expected. 2. Prices for diesel fuel have been quite variable recently, but may increase at a faster rate in the future. 3. The existing diesel plant is a source of both air and noise pollution in the community. Air quality requirements may become more restrictive in the future. The Angoon Power Supply Study (1998) investigated the merits of several alternative generating technologies, including combustion turbines, coal, fuel cells, wind, tidal, and hydropower. Of these technologies, only hydropower was found to have economic benefits, and then only if the capital cost could be reduced to approximately $4-5 million. It noted that even with a reduced HDR Alaska, Inc. 4 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated capital cost, the hydroelectric power could be more expensive than diesel generation in the early years of operation. The studies documented by this report are intended to supplement the Angoon Power Supply Study by determining the expected cost of the Project and the amount of economic support necessary for it to be economical. The Angoon Power Supply Study also looked at whether modifications to the utility structure in Angoon could reduce costs to the ratepayers. Three options were considered: 1. Continued membership in T-HREA (i.e., current utility structure). 2. Transfer of the service to another existing utility (such as Alaska Power & Telephone). 3. Establishment of a new, stand-alone utility. Kootznoowoo could develop the Project under any of these utility structure options. However, under the current utility structure, the Project costs and benefits would accrue to all T-HREA ratepayers, not just those in Angoon. HDR Alaska, Inc. 5 March 2000 E_ Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated III. GENERAL DESCRIPTION OF THE LOCALE The climate of the Project area is largely maritime, typified by cool summers, relatively mild winters, long periods of almost continuous cloudy or foggy conditions, and abundant year-round precipitation. Average annual temperature is about 41°F with lows ranging from -10°F in the winter to highs of about 85°F in the summer. Temperature extremes occur in both winter and summer due to occasional continental air mass incursions from Canada. Precipitation varies greatly with elevation and location. At Angoon, the mean annual precipitation is about 47 inches. Land in the Project area is included in the Admiralty Island National Monument and Kootznoowoo Wilderness. As such, the area is largely uninhabited, roadless and unlogged, with few if any trails. A small lodge is located nearby on Thayer Lake at the start of Thayer Creek. C. FISH, WILDLIFE, AND BOTANICAL RESOURCES Below Thayer Lake, Thayer Creek flows for approximately 6 miles in a broad forested valley at a mild grade (<%2%). This stream reach reportedly supports a large population of cutthroat trout. Then, for approximately 6,800 feet, Thayer Creek flows in a series of rapids and cascades through a narrow forested canyon at a steep grade (up to 12%). It is unknown if there are any resident fish in this steep section. Approximately 2,000 feet from tidewater, the gradient becomes milder (—l%), and the stream supports anadromous runs of pink, chum, and coho salmon. At the upper end of this lowest reach, there is a cascade approximately 8-10 feet high, which reportedly is a barrier to anadromous fish. Wildlife surveys have not been conducted specifically for the Project area. However, wildlife resources would be expected to be representative of Admiralty Island fauna, including brown bear, Sitka black -tailed deer, beaver, marten, otter, bald eagle, great blue heron, and a variety of F ducks, geese, and songbirds. Most of the Project area is characterized by old -growth climax forest, which consists of an overstory of coniferous trees (primarily western hemlock, Sitka spruce, and western red cedar) and a dense understory of shrubs and herbs. There are a few patches of muskeg interspersed -- throughout the climax forest. HDR Alaska, Inc. 6 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report A. THAYER CREEK DRAINAGE Thayer Creek at tidewater has a drainage area of 64 square miles. Thayer Creek flows out of Thayer Lake, a large natural lake with a surface elevation at approximately 365 feet mean sea level (MSL). Thayer Lake provides some natural regulation of the flows in Thayer Creek, decreasing peak flows and increasing low flows. Below Thayer Lake, Thayer Creek flows for approximately 6 miles in a broad forested valley at a mild grade (<%2%). Then, for approximately 6,800 feet, Thayer Creek flows in a series of rapids and cascades through a narrow forested canyon at a steep grade (up to 12%). Approximately 2,000 feet from tidewater, the gradient becomes milder (-1%), and there is a cascade approximately 8 feet high, which reportedly is a barrier to anadromous fish. B. ESTIMATION OF THAYER CREEK FLOWS Thayer Creek has never been gaged. However, the USGS operated a stream gage on Hasselborg Creek approximately 14 miles from the Project site. The Hasselborg Creek gage operated from July 1951 through September 1968, providing 17 years of flow data. Hasselborg Creek and Thayer Creek are quite similar, as shown by the following statistics: Drainage Area 64 mi2 56.2 mil Maximum Channel Length 16.5 miles 12.5 miles Mean Basin Elevation 1500 feet 1200 feet Gage Elevation 260 feet 295 feet Lakes and Ponds, Percent of Basin 7 % 11 % Forests, Percent of Basin 82 % 68 % Glaciers, Percent of Basin 0 % 1 % Mean Annual Precipitation 100 inches 100 inches Mean Minimum Air Temperature 24 OF 24 OF Basin Exposure SSW SSE Because of the similarities between the two basins, it is reasonable for purposes of investigating Project feasibility to estimate the Thayer Creek flows as a direct proportion of the Hasselborg Creek flows. The Hasselborg Creek data is rated as excellent by the USGS. However, inspection HDR Alaska, Inc. 7 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated of the data indicates that there were a few brief periods during which the flows are merely estimates, probably because of gage malfunctions. The data record provided by the Hasselborg Creek gage is somewhat less than ideal because of its limited duration (17 years) and some data inconsistencies, but it is nevertheless considered to provide an adequate basis for assessing Project feasibility. However, state and federal resource agencies can be expected to focus their attention on the adequacy of flows for supporting existing populations of fish in the anadromous and bypassed stream reaches, and it will be valuable for Kootznoowoo to be able to strongly support its estimation of flows. Therefore, on August 20, 1999 Kootznoowoo installed a stream gage on Thayer Creek as part of the current Project investigations to obtain detailed flow information. Based on the ratio of the respective drainage areas, Thayer Creek streamflows at the diversion site have been estimated as 114% of the Hasselborg Creek gage flows. Table IV-2 provides a summary of the average monthly flows for the 17 years of estimated flows. The average annual flow of Thayer Creek is estimated to be 369 cfs. Figure 2 is an annual flow duration curve for Thayer Creek at the diversion site; monthly flow duration curves are provided in Appendix A. The pattern of flows in Thayer Creek is typical of southeast Alaska, with high flows in the late spring and early summer due to snowmelt runoff, and again in fall due to high rainfall. Flows are generally the lowest in winter and late summer. During occasional brief periods of intense cold, flows in the winter can become very low. Floods can occur at any time due to storms, but flood peaks are significantly attenuated by Thayer Lake. '� 1T" Thayer Creek peak streamflows have been estimated as 114% of the Hasselborg Creek gage flows, based on the ratio of the respective drainage areas. Figure 3 shows the estimated flood frequency curve for Thayer Creek. Based on the assumed flood frequency distribution, the 10, 100, and 1000-year frequency floods are as follows: D HDR Alaska, Inc. 8 March 2000 EL ?N W N N N "o m — m to 0 00 O in C) rn ORS "o rn CV c> kn — c" 00 "t F- � C-4 C) tn 0V r-- O tn m �o O "o m C) C'4 It m 00 1�0 C) c) CN � to tn 00 0� N Cl, 00 CZ �o 't N � r- C14 C14 m W) It kn to N — kn rl- w Qv C) CN to Cn C-4 W) I'D cq CN r- W) m C) M t-- to m r- m m r- CD "t C) �t N Cn "o to 00 W) ON C� It N00 It 'It "T m �o C) t-- W) 1.0 W I It kf) C14 It M C-% kf) 00 00 r- M O-T-411i O 00 W) oo n cN CN m c) C', N w N V-) to kn It to a ggam", IM C14 N r-- rn m C) m 01 N C,4 � c 4 W) m 00 110 W) tn W') It m pgm gmg '-0 to C) CN kn C") dt rn C-- C\ m r- C> m d 00 M 00 r- C> m C*N ce) 00 C-- C) Tt 00 wtolvi 'IT N C14 CIF) Cfl d It en 0 Cf) 00 C) W kn I'D \.O "qt to m C) cn A` C> � 110 'It C) C% r- C) 00 cn C'n a,, 00 O RM ON aA g 'SM21"MA, �M, r'- C) "o cn 00 0V \,o "t C,4 00 in C-- 00 ,,,�gw ",& ON kn c) m It kn M 51 Cf) Y '00;N 771 r'- m kn N tn \,o W) kn It CN tn N C� m w tn W) 0 C� C14 00 -,zt r- 'n O t �t r a, r- 00 r- 'n 00 It 00 00 N �0 C4,) M — M C) W N m kn tf) NCe) lr �t kn M N N t-- C14 r'- r- \,o \,c r- CN to 01 O rn m CIN 110 01 M It 'Itt "IT ON W) r- V) 00 00 m It 110 \10 V, c") to to W-1 d d m to cn It N C> r- CN m C) m � 0 N c-, O'\ C> CD V-) m N 00 cr) 0N 00 00 It In if) Cn \0 dt r- m W) w \0 \10 r.- I:t M �t Lr) \,o r- 00 aN C) N Cf) et kn �O r- 00 kn In tn kn to (n in cv ON Cl C\ CV 01\ CN Cv cl\ 01 C) CV CN CN 0\ M Z- 1% Angoon Hydroelectric Proyect Feasibility Evaluation Report Kootznoowoo, Incorporated V. ALTERNATIVE PROJECT ARRANGEMENTS A. GENERAL Alternative arrangements of the Project were studied in the first phase of the current work to provide a basis for Kootznoowoo to select a preferred alternative arrangement for the Project. The alternatives analysis was documented in a draft letter report dated April 19, 1999, and a meeting was held on April 26, 1999 to discuss the report and other Project issues. The letter report was never issued in final form, and therefore the text of the letter report has been updated and incorporated herein. Six alternatives were evaluated. The first three vary primarily in their means of conveying water from the diversion to the powerhouse, and are therefore identified by the conveyance systems as follows: Alternative 1 - - Pipeline and Penstock Alternative 2 - - Directional -Drilled Tunnel Alternative 3 - - Conventional Tunnel (note that Alternative 3 uses more flow at lower pressure to generate the same capacity as Alternatives 1 and 2) These first three alternatives have been arbitrarily sized at 1,000 kW (2 — 500 kW generating units). That capacity is substantially greater than the current Angoon peak load. It was selected to provide for future load growth in Angoon as well as reserve capacity during routine turbine maintenance. Alternative 4 is the same as Alternative 1, but sized at 500 kW (one 500 kW generating unit), and therefore comparison of Alternatives 1 and 4 illustrates the cost of providing for future load growth and maintenance reserves. Alternatives 1, 2, and 3 include a submarine cable to transmit the power generated by the Project to Angoon. Use of a submarine cable will decrease the environmental impacts of the Project substantially, and will be quite reliable if the cable is routed away from the swift currents near Turn Point. However, submarine cables can be very expensive, and therefore Alternative 5 includes an overhead transmission line rather than a submarine cable. Providing good quality water reliably to Angoon is a major problem. Thayer Creek could provide a water supply, and therefore Alternative 6 has been evaluated. It includes the construction of a water supply pipeline from Thayer Creek to Angoon in conjunction with the submarine cable transmission line. 1. Project Features Figure 4 provides a general plan of Alternative 1. The major Project features areas follows: The diversion dam would be located approximately 8500 feet above tidewater at the head of a very steep suction of rapids about 250 feet above sea level. The dam would be primarily a concrete wall approximately 10 feet high, with grouted rockfill on each side for stability. HDR Alaska, Inc. 10 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated The intake structure would be located on the north abutment of the diversion dam, andwould be primarily a pre -cast concrete structure housing a trashrack, transition section, shutoff valve, and control facilities. Part of the intake structure would initially function as a diversion flume to bypass water around the damsite during construction. The pipeline would be a 48-inch diameter HDPE pipeline about 6,000 feet long from the intake structure to just above the powerhouse. The pipeline would be buried in the access road to the intake structure and diversion dam, and would be at a nearly flat grade to minimize the thickness requirement. The penstock would be an aboveground 36-inch diameter steel pipe about 320 feet long. It would convey water from the downstream end of the pipeline down the hillside to the powerhouse. Just upstream of the powerhouse, the penstock would branch into two 24-inch steel pipes leading to the turbines. The power plant would be located immediately downstream of the waterfall that prevents upstream migration of anadromous fish. At this location, there would be a substantial amount of excavation because of the steep slopes on both sides of the stream. The power plant structure would be a pre-engineered metal building set on a concrete foundation, and would be about 30- feet by 60-feet in plan dimension, and about 25 feet high. It would house two generating units, each consisting of a 700-HP horizontal -shaft Francis turbine, synchronous bypass valve, 500-kW generator, and flywheel. The power plant would also contain standard utility controls and metering to provide remote unattended operation. The transmission line would be a submarine cable approximately 7 miles long. The initial 1,800 feet would be buried in the access road to the power plant, and the remainder would be in Chatham Straight at depths up to 600 feet. The cable would pass on the outside of Danger Point and would connect to the Angoon distribution system at the existing diesel power plant. Port facilities would include a bulkhead -type barge landing, a small boat dock, and a garage for housing operation and maintenance vehicles (assumed to be on pickup and a small backhoe). The port facilities would be located approximately 1,800 feet north of the outlet of Thayer Creek to avoid that important wildlife habitat and to eliminate any switchbacks in the access road to the diversion dam. There would be two access roads for Alternative 1. The first would lead from the port facilities to the power plant, and would be approximately 1,800 feet long. The second access road would lead from the port facilities to the diversion dam/intake structure, and would include three distinct sections. The first section would be about 1,500 feet long and would ascend to the end of the pipeline at a very steep grade (15%). The second section of the intake access road would be approximately 6,000 feet long at a mild grade (<1 %). This section would be almost entirely a full bench in the side of the canyon. The third section would be 3,000 feet long, and would be a temporary road during construction. It would ascend from the end of the pipeline over a flat section of land to a spoils disposal area 2,000 feet south of the diversion dam. This temporary road is proposed so that spoils from the excavation for the mild grade section can be put in the spoils area rather than the brought down to sea level. Note that most of the sidehill slopes are too steep to allow cut -and -fill construction. HDR Alaska, Inc. 11 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 2. Generation Based on the Project arrangement, hydrology, operations model, and instream flow assumptions described above, Alternative 1 would be able to supply all of Angoon's power needs at current load levels over 99% of the time; generation would need to be supplemented on an average of 2 days per year. This percentage would decrease to slightly less than 99% (4 days/year) if loads increase by 50%, and to 97% (10 days/year) if loads increase by 100%. 3. Estimated. Construction Cost The construction costs estimate for Alternative 1 - - Pipeline and Penstock is shown in Table V- 1. The costs are generally grouped according to FERC's standard system of accounts. The sum of the FERC account values is termed the total direct construction cost, and is approximately the amount that may be bid by a construction contractor. However, additional contingency amounts must be added to account for minor items not included in the cost estimate and unexpected conditions that may be incurred during construction. The sum of the total direct construction cost and the contingency allowance is termed the total construction cost. The total project cost is the sum of the total construction cost and indirect costs for permitting, design engineering, and construction management. The estimated total project cost for Alternative 1 is $9,300,000. This compares to $8,500,000 estimated in 1996 by the GH Group for a somewhat similar Project arrangement and assumptions. C. ALTERNATIVE 2 1. Project Features { Figure 5 provides a general plan of Alternative 2 — Directional Drilled Tunnel. The major Project features of Alternative 2 are as follows: The diversion dam would be located approximately 8,900 feet above tidewater at the very head of the high -gradient section of stream about 255 feet above sea level. The dam would be a concrete wall across the river with grouted rockfill on both sides for stability. The spillway section of the dam would be 80 feet long with the crest at elevation 260 feet MSL. The north and south abutments would be 30 and 50 feet long, respectively, with the crest at elevation 265 feet MSL. The intake structure would be located approximately 500 feet south of the diversion dam, and would be connected to the pond behind the dam by an excavated channel. The intake structure would be a cast -in -place concrete structure housing a trashrack, transition section, shutoff valve, and control facilities. There would be no access road to the diversion dam or intake structure; therefore helicopters would need to transport materials and personnel to the site during construction and operation. The directional -drilled tunnel would be a 42-inch diameter tunnel approximately 4,200 feet long from the intake structure to the power plant. The tunnel would be lined with 36-inch steel pipe. Drilling and reaming the tunnel would be from an excavated staging area behind the power HDR Alaska, Inc. 12 March 2000 E9 C) C) 0 C) 0 C) 0 0 0 -0- C) C) C) C) C) C) C) C) C) C) C) C) C) C) (: c C� C:) C) C) CD C) C) C) C) tr) 00 C) 110 0 000 It C'n 00 N Cn Ncn N 00 ,t Cn C> tn 00 m N "zr .rn dt C14 - I - I10q-1 1 -4 eol� E9 C) C> C) C) C) C) CD 0 0 C) CD C) C> C) C) C) C) C) C) C) C> C) C) C> C) C) C) C) C� C> C) C) C) C) CI 0 Cl C� C5 kr) C14 m �o C) O 06 ,Zt' 4 00 to r- C-4 cq kn c> ON O to �t r-- r- 00 m C14 C,4 C� cn N 6011 69 W-73 WWI I Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated plant. Note that this is somewhat experimental technology for this application. Directional drilling is advancing in its capabilities, and it is theoretically possible to use it as proposed. However, to our knowledge, it has not been successfully used for a hydroelectric project. Alaska K _ Power & Telephone has investigated directional drilling for construction of the tunnel at the proposed Mahoney Lake Project near Ketchikan, and has concluded that it is feasible. AP&T's research is the basis for our estimate for this alternative. The penstock would be a buried 36-inch diameter steel pipe about 100 feet long. It would convey water from the downstream end of the directional -drilled tunnel to the power plant. Just upstream of the power plant, the penstock would branch into two 24-inch pipes leading to the turbines. The power plant for Alternative 2 would be identical to that of Alternative 1. The transmission line for Alternative 2 would be identical to that of Alternative 1. Port facilities for Alternative 2 would be identical to that of Alternative 1. The only access road for Alternative 1 would be the powerhouse access road as described in Alternative 1. 2. Generation Same as for Alternative 1. 3. Estimated Construction Cost The construction costs estimate for Alternative 2 - - Directional -Drilled Tunnel is also shown in Table V-1. The estimated total project cost for Alternative 2 is $10,600,000, which is $1,300,000 more than Alternative 1. D. ALTERNATIVE 3 1. Project Features Figure 6 provides a general plan of Alternative 3 —Conventional Tunnel. The major Project features of Alternative 3 are as follows: The diversion dam would be located approximately 5,000 feet above tidewater midway through the high -gradient section of stream, about 135 feet above sea level. The dam would be similar to that for Alternative 1, except the spillway length would be only 45 feet due to the narrowness of the stream in the canyon. The intake structure would be similar to that for Alternative 1. The pipeline would include two 36-inch diameter steel pipes about 300 feet long from the intake structure to the upstream tunnel portal, continuing for an additional 2,650 feet through the tunnel. The pipeline would be buried in the access road between the tunnel portal and intake structure, and would be at a mild grade as necessary to provide freeboard for the tunnel. The tunnel would be a 11-foot diameter horseshoe tunnel approximately 2,650 feet long. The two 36-inch diameter steel pipes would be stacked on the north side of the tunnel. The remainder of the tunnel would be open to provide narrow -wheelbase access to the diversion dam and intake structure. HDR Alaska, Inc. 14 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated The penstock would be two buried 24-inch diameter steel pipes about 100 feet long. They would convey water from the downstream end of the tunnel to the power plant, one to each turbine. The power plant for Alternative 2 would be similar to that of Alternatives 1 and 2, except the generating equipment would be somewhat larger and slower due to the lower head. The transmission line for Alternative 3 would be identical to that of Alternatives 1 and 2. Port facilities for Alternative 3 would be identical to that of Alternatives 1 and 2. The only access road for Alternative 3 would be the powerhouse access road as described in Alternative 1. 2. Generation Based on the Project arrangement, hydrology, operations model, and instream flow assumptions described above, Alternative 3 would be able to supply all of Angoon's power needs at current load levels 97% of the time; generation would need to be supplemented on a average of 10 days a year. This percentage would decrease to 95% (19 days) if loads increase by 50% and to 91% (34 days) if loads increase by 100%. 3. Estimated Construction Cost The construction costs estimate for Alternative 3 - - Conventional Tunnel is shown in Table V-1. The estimated total project cost for Alternative 3 is $9,700,000, which is $400,000 more than Alternative 1 but $900,000 less than Alternative 2. E. ALTERNATIVE 4 - - 500 KW INS'TAALLED CAPACITY 1. Project Features Because of the estimated lesser cost of Alternative 1, it has been used as the basis for determining the savings that might be possible by reducing the capacity to 500 kW, which would be sufficient to supply only existing loads and a minor amount of load growth. Alternative 4 would include the following changes to the features of Alternative 1: ® The pipeline diameter would be reduced from 48-inches to 36-inches. ® The penstock diameter would be reduced from 36-inches to 30-inches. The power plant would contain a single 500-kW generating unit. ® The accessory electrical, control, and transmission systems would be modified as appropriate for the smaller capacity. 2. Generation With existing loads, Alternative 4 - - 500 KW would have approximately the same generation as Alternative 1, as shown previously. However, Alternative 4 would not provide all of the required generation if the Angoon loads grow significantly. Also, the generation would be less reliable, since an outage of the one unit would require that the diesel power plant be operated. HDR Alaska, Inc. 15 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 3. Estimated Construction Cost The construction cost estimate for Alternative 4 - - 500 KW is shown in Table V-1. The estimated Total Project Cost for Alternative 4 is $7,900,000, which is $1,400,000 less than Alternative 1. r 1. Project Features The evaluation of Alternatives 1, 2, 3, and 4 assumed power from the project would be transmitted by submarine cable. The use of a submarine cable would minimize the visual impact of the project that would be associated with clearing for an overhead or buried transmission line. By routing the submarine cable outside of Turn Point, it would also be possible to avoid the swift currents in Kootznoowoo Inlet. However, submarine cables can be very expensive, and so three other transmission line arrangements were considered, as follows: ® T2 — Overhead: An overhead 12.5 kV transmission line proceeding south from the powerhouse to a point on the north shore of Kootznoowoo Inlet, a distance of nearly 6 miles. From that point, a submarine cable about 4,600 feet long would cross Kootznoowoo Inlet to an interconnection with the existing distribution system in the vicinity of the floatplane dock. ® T3 — Buried: A buried 12.5 kV power cable along approximately the same alignment as the overhead line described above. There would also be the submarine crossing of Kootznoowoo Inlet. ® T4 — Overhead and Submarine: An overhead 12.5 kV transmission line proceeding south from the powerhouse to a peninsula approximately 1.8 miles south of the mouth of Thayer Creek. From there, a submarine cable about 4.8 miles long would interconnect at the existing diesel plant. This arrangement was evaluated because it would obtain some of the cost benefits of the overhead line and avoid the most rugged terrain. Note that it would be possible to cross Kootznoowoo Inlet with an overhead span, but that span would be directly in the .route of landing and departing float plane traffic. It would also be possible to cross Kootznoowoo Inlet with a shorter length of submarine cable, but at the risk of putting it in the very swift tidal currents. The longer route to the floatplane dock was assumed for this analysis to provide reliability. 2. Generation Generation for all of the transmission alternatives would be comparable to that for Alternative 1 as presented earlier, although the generation may be somewhat less for overhead line options because of the potential for large trees falling on the line and causing extended outages. MDR Alaska, Inc. 16 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 3. Estimated Construction Cost The estimated construction costs for the four transmission line options are presented in Table V- 2. Note that these costs are only for the transmission portion of the project. As can be seen, the least cost option is T2 - - Overhead, which is about $125,000 less than T3 - - Buried, $200,000 less than T4 - - Overhead and Submarine, and $300,000 less than Tl - - Submarine. TABLE V-2 TRANSMISSION LINE OPTIONS £ � � 4 Mt Ou h d er e r - x Section 1: Type Buried cable Overhead Buried cable Overhead (mild terrain) (mild terrain) (mild terrain) (mild terrain) Length 0.34 miles 2.07 miles 2.07 miles 2.07 miles Cost $62,000 $284,000 $335,000 $284,000 Section 2: Type Submarine cable Overhead Buried cable Submarine cable (rugged terrain) (rugged terrain) Length 6.57 miles 3.67 miles 3.67 miles 4.80 miles Cost $1,350,000 $632,000 $649,000 $1,040,000 Section 3: Type Submarine cable Submarine cable Length 0.86 miles 0.86 miles Cost $269,000 $269,000 Interconnection $50,000 $50,000 $50,000 $50,000 Oil f1"9N,L ngtf i 6 3, miles 6 6Q m1leS f 6 60 mxleS 6 7m21e S s $1;462Q0{} $,3o3;ooa r .1235,00 . Y ,; K,374000 1. Project Features Alternative 6 - - Water Supply would include a 7-mile long 8-inch diameter HDPE water supply pipeline installed in conjunction with the submarine transmission line. This water supply pipeline could provide up to several million gallons per day of Thayer Creek water for use in Angoon. The waterline would be bundled with the submarine cable, which would provide additional strength. The key technical problem with the pipeline is the depth at which it would be laid (up to 600 feet deep). Under normal operating circumstances, a waterline would have a positive net pressure, and thus the depth would not be an issue. However, if the waterline were ever to become evacuated, the external water pressure at that depth would completely crush the pipe. Nevertheless, it is difficult to imagine a circumstance under which the waterline could become HDR Alaska, Inc. 17 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated accidentally dewatered. By carefully inflating the waterline, it might even be possible to use the waterline to raise the electrical cable in case a fault in the cable requires maintenance. Laying the waterline and submarine cable at a shallower depth might be possible. However, from the limited depth soundings available, it appears that shallower depths would require placement on steep side slopes, requiring expensive underwater anchorages. 2. Estimated Construction Cost The estimated construction cost for the water supply pipeline is $500,000. This includes $300,000 for the materials, $150,000 for laying the line in conjunction with the transmission cable, and $50,000 for permitting, design, and construction management. H. COMPARISON OF ALTERNATIVES 1. Alternative Conveyance Systems The comparative advantages and disadvantages of Alternatives 1, 2, and 3 are summarized in Table V-3. At the review meeting on April 26, 1999, Kootznoowoo indicated its preference for Alternative 1, but recommended further evaluation in an effort to reduce the cost as much as possible. 2. Alternative Capacities Decreasing the Project capacity from 1000 kW to 500 kW to more closely match the existing Angoon loads would save approximately $1,400,000. Project reliability would be decreased if only one 500-kW generating unit is installed, and the Project would not be able to provide for much more than a 10% increase in peak load. The reliability could be maintained if two 250-kW generating units were installed, although this would reduce the cost savings to only about $1,000,000. Because of the limited cost savings associated with a reduction in installed capacity, and because of the significant potential for economic development and increasing loads in Angoon, Kootznoowoo concluded at the April 26, 1999 review meeting that reducing the installed capacity to less than 1,000 kW was not appropriate. 3. Alternative Transmission Options The comparative advantages and disadvantages of the four transmission options are shown in Table V-4 below. There is a clear cost advantage to using an overhead line (Option T1), but the potential visual impact issue could be very difficult to resolve. The submarine cable option (Option T2) avoids the visual impact difficulties, but the cost is high and since little is known about the subsurface route, the cost could increase substantially. The buried cable option (Option T3) could be a good compromise between cost and visual impact, however, there is also a great risk that its cost could increase substantially if rock is found near the surface. There does not appear to be any real advantage to the part overhead — part submarine transmission line option (Option T4). HDR Alaska, Inc. 18 March 2000 0 801 CO c) a =0 .;89 p U 0 U _0 o tb w ) �= C,3 0 >, b�O 0 0 0 "Cl o o os C) in, 0 C� U) r. 0 79b .— C/I 0 u 0 u rn o 0 co C> C> 0 t4o C13 a) 0 al (4-4 0 0 0 0 6q 0 o0 0 Nr� CN 4- 0 OW cl u) 0 o co tD .12 24� C) (=, 0 0 U Q bO 0 0 6 C) M cd F 4--, �j x �: C) En — = U) 0 0 I:$ 0 0 0 )4 ^CjC's rn —14 cn 0 0 (D 0 cd 7:1 0 0 0 C,3 0 z= o 0 0 O Cd Q) cd p Cd > —03 cd Q) 0 C,3 to cd u M Q) 0 Q) cn uZI in. PClq w 0-4 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated TABLE V-4 COMPARISON OF TRANSMISSION LINE OPTIONS OptionAdvantages F D gegm ..._ ., <,,. s.. A.. .,. .. ', .. ..., .;',, tk. 'fl,+s?Ri.r ..1 cx rni R,c.�. v`t'�. RM T1 — Submarine Cable Least visual impact. Most expensive ($1,462,000). High risk of extra costs. Difficult to maintain. T2 — Overhead Least expensive ($1,235,000). Most visual impact. Low risk of extra costs. Prone to weather -caused damage. Relatively easy to maintain. T3 — Buried Cable Relatively low visual impact. Moderate cost ($1,303,000). High risk of extra costs. Relatively easy to maintain. T4 — Overhead & Submarine Relatively low visual impact. High cost ($1,374,000). High risk of extra costs. Difficult to maintain. Prone to weather -caused damage. Selection of the preferred transmission line option was not completed in the first phase of the work because of the lack of a definitive advantage for any option. However, during evaluation of project access in the second phase of work, the cost advantage of an overhead transmission line became more significant. See Section VI for further discussion of this process. 4. Water Supply Addition Angoon is currently pursuing the development of a water supply from a source south of the town. It probably would be preferable to the pipeline from Thayer Creek because the route would be accessible by road for its entire length, whereas the pipeline from Thayer Creek would be inaccessible and would be more risky to design and install. Therefore, Kootznoowoo concluded at the April 26, 1999 review meeting that adding a water supply function to the Project was not appropriate. However, during evaluation of the overland transmission line route, an.alternative water source was found. See Section VI for further discussion of this process. - HDR Alaska, Inc. 20 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report VL SELECTED PROJECT ARRANGEMENT At a review meeting on April 26, 1999, Kootznoowoo indicated their preference for Alternative 1 - - Pipeline and Penstock to be the Project arrangement for further refinement. In particular, it was desired to reduce the cost of the Project as much as possible from the estimated cost of $9,300,000. The proposed site for the port facilities was viewed from the air at low tide on August 17, 1999, and it was clear that access to those proposed facilities would be restricted during low tide conditions. Also, in the course of installing a stream gage on Thayer Creek on August 20, 1999, an Angoon citizen hired to provide boat transportation to the site indicated that the port facilities as proposed for Alternative 1 would not be routinely usable during stormy weather, but that a site approximately 2 miles closer to Angoon would be. Also, the topography on the south side of Thayer Creek was observed to be more suitable for powerhouse construction. As a result of this information, the access roads, port facilities, and power plant for the selected arrangement have been extensively modified from Alternative 1, as described in the following subsections. B. PORT FACILITIES For the preliminary assessment of Project alternatives, it was assumed that a permanent barge landing and boat dock would be constructed approximately 1200 feet north of the mouth of Thayer Creek to provide access during construction and operation (See Figures 4, 5, or 6). For the selected Project arrangement, those facilities have been replaced by a temporary barge landing and boat mooring and haulout facilities located at a peninsula about 1.8 miles south of Thayer Creek (see Figure 7). The permanent barge landing was eliminated because: ® A permanent barge landing would be exposed to waves and rough weather in Chatham Strait, and would likely require considerable effort and expense to maintain it in usable condition. ® Once the Project is operating, there is little likelihood of needing to mobilize large equipment to the site. ® It would eliminate one of the most visible elements of the Project. The temporary barge landing would be a timber crib/rockfill structure constructed from materials 'i from the access road clearing and excavation. The barge landing would be removed at the end of construction. Initial delivery of construction equipment and materials to the site (before construction of the temporary barge landing) would be by grounding a barge on the beach at high tide. The same procedure could be used during operation if it was necessary to - bring large J equipment to or from the site. Two mooring buoys would be placed offshore to provide secure anchorage for small workboats that would transport personnel and small tools to the site during both construction and operation. In addition, a cable would be run from an on -shore anchor to one of the mooring buoys, so that HDR Alaska, Inc. 21 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated workboats could haul themselves on and off the beach during inclement weather when it might not be safe to operate a lighter or dinghy from the mooring buoy. Locating the port facilities at the peninsula where now proposed will provide more reliable access during storms and low tide periods. Also, the "hammerhead" topography of the peninsula provides two secure anchorages and shelter from winds from any direction. C. ACCESS ROADS For the preliminary assessment, it was proposed to construct two permanent access roads and one temporary access road. The two permanent access roads would be 1) from the port facilities to the powerhouse, and 2) from the port facilities to the intake diversion structure. The latter would also serve as the route for the proposed pipeline, and would be on a bench cut along the steep wall of the Thayer Creek canyon. The temporary access road was proposed to take off from the intake access road above the powerhouse and cross a relatively flat area above the Thayer Creek canyon, joining the intake access road again about 2,500 feet below the diversion/intake structure. For the selected Project arrangement, both the powerhouse access road and the intake access road have been modified substantially. See Figure 7 for the alignments now proposed for these roads. The powerhouse access road has been lengthened from 1800 feet to 2.0 miles due to the relocation of the port facilities and powerhouse. The route topography is favorable, with relatively gentle slopes and a maximum elevation of about 160 feet MSL. The intake access road modification is tied closely to proposed changes for the pipeline (as described in Subsection E below). In general, the temporary access road has been eliminated and the permanent road has been routed out of the steepest part of the canyon. Also, the road includes a bridge across Thayer Creek about 300 feet downstream from the powerhouse to tie into the powerhouse access road. The total length of the intake access road is 7,200 feet. A spur road about 1,000 feet long would provide access to the top of the surge tank during construction. The selected Project arrangement also now provides restricted access from Kootznoowoo Inlet to the port facilities. This access would be by the construction grade for the transmission line (as described in Subsection F below), but would also be suitable for small all -terrain vehicle access to the generating facilities. The proposed route is shown in Figure 8. The route includes some relatively steep sections, and the maximum elevation is about 500 feet MSL. This route could also provide access to a potential water supply reservoir for Angoon that could be developed at two small lakes approximately two miles north of Kootznoowoo Inlet (see Subsection H below). D. IDI`TERSION DAM AND INTAKE STRUCTURE 1. Modifications from Alternative 1 The conceptual design for the diversion dam and intake structure has been modified by the addition of a sluicing facility and the use of modified shipping containers for 1) bypassing of flows during construction of the diversion dam, and 2) as the basic structures for the sluice and intake facilities. For the analysis of alternatives, precast concrete conduit segments were assumed for these functions. Use of modified shipping containers reduces the construction cost and reduces the size of equipment needed to build the intake. The sluiceway has been added to HDR Alaska, Inc. 22 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report provide a means for passing accumulated sediment from behind the dam. It also provides greater bypassing capacity during construction. 2. Construction Sequence The following is a summary of the construction sequence proposed for the diversion dam and intake structure. Construction should occur from about March 1 through June to allow temporary diversion of Thayer Creek during its lowest flow period. 1. Excavate right abutment (looking downstream) to just above the normal water surface (about El 251). 2. Place a cofferdam of large sandbags to isolate the right abutment area. For planning purposes, we have assumed that these sandbags could be filled with material from the beach near the mouth of Thayer Creek. 3. Place a slab of foundation shaping concrete on the right abutment to about El 252. 4. Set modified shipping containers in place and anchor to bedrock through the foundation shaping concrete. During diversion there would be two pairs of containers, with each pair consisting of an upstream 20' container and a downstream 40' container. - 5. Construct concrete wall between outermost (intake) 40' container and the right abutment, and between the two container sets. 6. Move and extend the initial sandbag cofferdam across Thayer Creek from the innermost (sluiceway) 20' container to the opposite bank. This will divert the flow through the containers and allow construction of the diversion dam. 7. Excavate loose material from beneath the core wall of the diversion dam. 8. Grout rock beneath core wail if necessary. 9. Construct reinforced concrete core wall and abutment wall against sluiceway 40' container. 10. Encapsulate the intake 40' container in concrete. 11. Place rockfill on both sides of core wall; fill voids in outer 3 feet with concrete to prevent erosion of rockfill during high flows. 12. Place bulkheads over ends of 20' containers to close diversion and cause flow to pass over the cofferdam and completed diversion dam. 13. Install intake transition section, intake butterfly valve, and sluiceway sluice gate. 14. Remove bulkheads and 20' containers. 15. Place one 20' container on top of the intake 40' container to serve as a control room. 16. Place precast concrete trashrack structure in front of the intake 40' container. 17. Encapsulate the control room container in concrete. 18. Place fill around control room container. 19. Install handrails, ladders, hatches, valve and gate operators, etc. HDR Alaska, Inc. 23 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated E. PIPELINE AND PENSTOCK The conceptual design for the pipeline and penstock has been modified substantially in the development of the selected arrangement. It will still be primarily a long section of HDPE pipeline and a shorter section of steel penstock. The following modifications have been made to reduce the cost of the Project while maintaining an acceptable level of reliability: 1. Reduced Pipeline Diameter The HDPE pipeline diameter has been reduced from 48 inches to 42 inches. This will increase the maximum velocity in the pipeline from 6.5 to 9.1 feet per second, and will increase the maximum head loss from 21 feet to 39 feet. A head loss of 39 feet is approximately 17% of the available head, which is a higher percentage than is typical for new hydroelectric projects, but it is justified for the Project because of the surplus of streamflow available for generation. The primary advantage of the smaller pipeline diameter is the lesser cost, both from the amount of material required and somewhat easier installation. The primary disadvantages are associated with the higher velocity. With the higher velocity, pressure surges from unplanned shutdowns are a serious problem, and control of the system frequency within acceptable limits is much more difficult. The surge tank discussed below has been added to compensate for these disadvantages. HENNUMMUM The HDPE pipeline is no longer proposed to be buried for its entire length. Instead, the pipeline will be simply laid on the ground and secured against sliding downhill by a system of nylon straps and galvanized steel cable. This pipe will be installed by first fusing together approximately 300 feet of pipe at a staging area above Thayer Creek (see Figure 7), and then dragging the fused sections into position by cables and winches. These pipe sections will then be joined with mechanical couplings. It is expected that few trees will need to be cut along this section of the pipeline. Instead, the pipeline will snake between the trees. The advantages to this method are several: ® Decreases the time required for constructing the pipeline. ® Allows a reduction in the length of access road. ® Allows the access road to be located in less steep terrain. The major disadvantage of having an exposed section of pipe is vulnerability to damage, particularly from tree falls. HDPE is a flexible, tough, and durable material, and it is expected that a tree falling on the pipe would only depress it, and not break it. Once the tree was removed, the pipe would return to its original shape. Another disadvantage would be the tendency for the pipeline to collect debris on the uphill side, which might need to be periodically removed for inspection. Thermal expansion of the pipe will be manageable. Another possible disadvantage is with an exposed pipeline is the greater potential for freezing. There will nearly always be at least some water flowing through the pipeline, and it will take very little flow to prevent freezing. On extremely rare occasions, intense cold weather may to decrease flows below the minimum operating conditions of the turbines, and it could be necessary to drain the penstock to prevent bursting. HDR Alaska, Inc. 24 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 3. Surge Tank As noted above, a surge tank has been added to the pipeline and penstock system to provide for r acceptable frequency control and protection against pressure surges. The surge tank will include 240 feet of 6 feet diameter precast concrete pipe laid on concrete saddles on the ground slope at the downstream end of the pipeline. It will be vented and capped at the upper end, and anchored by a large concrete block at the lower end. The transition from HDPE pipeline to steel penstock will also occur in the concrete block. The surge tank will act as a short-term reservoir, providing water to the penstock during load acceptance by the generator and storing water during generator unloading. There are other methods of providing these functions, such as 1) pressure regulating valves on the turbines and operating in a "water -wasting" mode, and 2) use of impulse (Turgo) turbines and operating in a "water -wasting" mode. The surge tank is proposed because it is a completely passive system, whereas the others rely on mechanical devices that require periodic maintenance to be effective. The surge tank as proposed is believed to be similar in cost to the other alternatives. The surge tank has been sized for 100% load acceptance and rejection. It is unlikely that those conditions will occur in the near future (due to the small load in Angoon), and it may be possible to reduce the diameter of the surge tank somewhat as a cost -saving measure. 4. Pipeline and Penstock Alignment The alignment for the pipeline and penstock is similar to that for Alternative Arrangement 1, but with the following modifications: ® The pipeline grade is increased to maintain positive pressure under all static conditions (required by the smaller diameter and increased head loss). ® The transition from HDPE pipeline to steel penstock has been moved downstream as required for the new powerhouse location. ® The penstock is longer due to the new powerhouse location, and includes an elevated F crossing of Thayer Creek at the powerhouse. The crossing will be accomplished by using thicker pipe and possibly increasing the diameter F. POWERHOUSE The powerhouse location and arrangement for the selected Project arrangement is similar to that considered in the analysis of alternatives, but located on the south side of Thayer Creek and about 300 feet downstream of the anadromous fish barrier. This location has been selected because it will require much less excavation than the previously proposed north side location. The powerhouse will be a 30' by 68' pre-engineered steel structure set on a reinforced concrete foundation. The powerhouse will be insulated, heated, and ventilated to provide comfortable temperatures during operation and maintenance. A separate control room will be included in the powerhouse, with a restroom and minimal housing facilities in case someone should be stranded at the site. A site plan, interior plan, and transverse section of the powerhouse are shown in Figures 10, 11, and 12, respectively. The powerhouse will contain two horizontal generating units, each consisting of a Francis turbine, flywheel, and 500 kW synchronous generator, for a total installed capacity of 1,000 kW. HDR Alaska, Inc. 25 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated The turbines will each be rated at 700 HP, 198 feet net head, and 41 cfs. The generators will be 480V, 3-phase, 0.8 power factor. A 50 kW generator will also be installed in the powerhouse to provide auxiliary power during outages. Additional mechanical equipment will include butterfly valves at the inlet to each turbine, a single hydraulic power unit (HPU), a 10-ton bridge crane, and miscellaneous plumbing and HVAC systems. The control system will include 480V switchgear, a 125 VDC battery system for supplying reliable power to the HPU and microprocessors, unit and plant control panels, and a load bank. The load bank is sized at 100 kW, and is necessary to provide additional electric load when the town loads are too small to run a single generating unit; it is in essence a large water heater. Additional electric systems include lighting and 480/277 V and 120/208 VAC power systems. As proposed, the powerhouse does not include "flow continuation" facilities. If installed, these would provide an automatic means to maintain discharge from the powerhouse during outages, and are commonly required by the fisheries agencies to prevent a sudden decrease in flow from the powerhouse that could strand fish and/or de -water redds downstream of the powerhouse. They have not been proposed for the Project because their use could be expected to be extremely rare. However, it is likely to be an issue with the resource agencies. Providing flow continuation facilities could be expected to cost an additional $100,000. The power plant will discharge directly back into the creek. This will routinely reduce the flow in approximately 300 feet of anadromous fish habitat, which may also be an issue with the resource agencies. The power plant does include a discharge structure designed to prevent harm to anadromous fish that may be attracted to the turbine discharge. G. TRANSMISSION LINE For the evaluation of alternatives, a 6.5-mile long submarine cable was the assumed choice for the transmission line primarily because it would minimize the visual impact of the Project, even though it would be more expensive. However, the relocation of the port facilities as described above changes the balance between submarine cable and overland transmission. The transmission line arrangement now proposed as part of the selected Project arrangement includes the following: ® 5.8 miles of overhead line between the powerhouse and Kootznoowoo Inlet. This transmission line will be similar to a typical distribution line, as shown in Figure 13. Where the line parallels the access road between the port facilities and powerhouse, the additional clearing width for the transmission line will be about 15 feet. Between the port facilities and Kootznoowoo Inlet, the clearing width will be 30-40 feet. 4,600 feet of submarine cable through Kootznoowoo Inlet connecting to the existing distribution system near the float plane dock south of Angoon. This is not the shortest route, but should keep the cable in manageable currents. ® Two 12-pair filled T-screen control cables will be included with the transmission line to allow remote control and monitoring of the power plant from Angoon. The route for the proposed transmission line is shown in Figure 7. HDR Alaska, Inc. 26 March 2000 t Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated H. POTENTIAL WATER SUPPLY For the evaluation of alternatives, Thayer Creek was considered as a water supply for Angoon, but was dropped from consideration because Angoon was looking at another source and there were technical concerns with submarine piping from Thayer Creek. However, the change to an overland transmission system opens up other water supply possibilities. The proposed route for the transmission line will pass two existing lakes approximately 2 miles north of Kootznoowoo Inlet (see Figure 7). A small dam could be constructed to increase the storage in the lakes by as much as 200 million gallons. The yield from the lakes is preliminarily estimated at about 1.5-2.0 million gallons per day. An adjacent creek could easily be diverted to provide an additional 10 million gallons per day. An energy recovery station on the system could generate approximately 100-200 kW. A cost estimate has not been prepared for this potential water supply, but if the access was already provided by the hydroelectric Project, then it could be very competitive with other sources under consideration. One potential difficulty is that the existing lakes extend just beyond the boundary of area reserved to Kootznoowoo for hydroelectric development by ANILCA. Quality of the water is also unknown at this time. I. POTENTIAL STORAGE The Project as proposed herein does not include any reservoir storage because the unregulated streamflows are nearly always sufficient to meet all generation requirements. However, three circumstances could make storage more desirable: Loads grow more than expected so that the amount of time when unregulated streamflows are not sufficient becomes significant. ® Instream flow requirements are significantly more than the 20 cfs assumed for this study. ® Angoon becomes electrically interconnected with another utility or load so that additional generation can be marketed. Should one of these situations occur in the future, Kootznoowoo may want to consider the feasibility of constructing a higher dam to provide storage. The canyon where the diversion dam is now proposed could allow a 50 foot high dam which would provide approximately 900 acre- feet of storage, and the reservoir would be within the area reserved for hydroelectric development. That amount of storage would be sufficient to operate the Project at maximum capacity for about 5-6 days. HDR Alaska, Inc. 27 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated VII. POWER OUTPUT A. OPERATIONS MODEL Operations studies have been conducted to determine the potential power generation of the alternative Project arrangements and refinements of the selected Project arrangement. The operations studies were conducted using a numerical simulation model developed specifically for the Project. The simulation model is a Microsoft Excel® spreadsheet, and calculates the generation for each day of the 17 years of streamflow data. It includes the following features: ® Daily time step e Run -of -river operation with load -following capability a Variable or constant headwater level ® Variable of constant tailwater level ® Variable generating and transmission efficiencies w ® Instream flow requirements variable by month Generally, the flow in Thayer Creek is much greater than necessary to generate all of Angoon's power requirements. However, under some conditions, the flows drop low enough that the hydro generation will need to be supplemented from other sources (e.g. the existing diesel generators). Based on the Project arrangement, hydrology, operations model, and instream flow assumptions described above, the Project will be able to supply all of Angoon's power needs at current load levels over 99% of the time; generation would need to be supplemented on about 2 days per year. This percentage would decrease to slightly less than 99% (4 days per year) if loads increase by 50%, and to 97% (10 days per year) if loads increase by 100%. Monthly generation amounts are shown in Table VII-1 both as absolute amounts of generation (MWh) and as the number of days per year that project generation would need to be supplemented. Monthly power duration curves are provided in Appendix B. Also shown in Table VII-1 is the maximum potential generation by the Project, which is the amount that could be generated if not limited by the size of the Angoon load. This would be the generation that a 1,000 kW project as proposed herein could sell if it was interconnected to other loads. As noted above, the operations model includes consideration of instream flow- requirements. These arP minimum flow levels that would need to be released from the diversion dam, primarily to preserve fish habitat in the bypassed reach of stream between the diversion dam and the powerhouse. Instream flows are almost always required at new hydro projects, and are determined through scientific studies and negotiations with regulatory agencies (primarily HDR Alaska, Inc. 28 March 2000 Li `r' r r ry rt o Oo M Oo c� O 06 M O O MAN 00 ' N C r1 M O M tiO M M 01 CT kn N Vn C� d N d M d O O � v��o r r r r r r r r N O O O O O O O C M N M -� M O M M M M M N N M M M M M 00 6 _4 6 C14 00 O O O O O O O O c5. C) . Q] CT"o N (-4 -G �D N d N T N N O N , N N N M N "O �Dr N in N v 00 NN ` 4a, O O O O O O O O O O 2 "O CO tV 0 CO) O x , p O M r" O dt - V') US kn r r d 00 CN O N M o CCS cz U �r cz Q. O U O z Q I m Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated ADF&G and the U.S. Fish and Wildlife Service). Instream flow requirements will decrease the Project's generation during low flow periods. At the present time, there have been no discussions with the regulatory agencies to provide a basis for determining instream flows. Because of the steep gradient in the bypassed reach, it is not at all clear if there are any fish that will be of concern to the agencies. It is likely that the agencies will first want Kootznoowoo to determine if fish are present in the bypassed reach, and if fish are found, it is likely that the agencies will want a substantial release to support the population, regardless of its socioeconomic value. For purposes of this initial evaluation, the operations modeling has assumed a constant instream release of 20 cfs, which is approximately the historical minimum flow in the stream. The agencies can be expected to initially request more than 20 cfs. Table VII-2 shows how instream flows of 0 cfs, 20 cfs, and 50 cfs affect the estimated Project generation for two load conditions: 1) generation to meet existing Angoon loads and 2) maximum potential generation. 1 Existg Lc1unurrc�teiia } tgiz e�' � 2✓fr�'/y '��,s / ' ?p �?j-.{.� ai'S 2. 3 .2's''r' f' F 1VrGi61^.Lr. }+ f ^� �/yr�`".,e�ya�..py�� `��*.s 4 �`�4At�'F CG�6 �Fl.� 7 '(�}' :.;Instram�lcrw s`+'�y 0 cfs 2,009 0 8,630 26.9 20 cfs 2,000 2.2 8,446 47.1 50 cfs 1,931 16.9 7,950 75.6 HDR Alaska, Inc. 30 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated II. DEVELOPMENT SCHEDULE A. GENERAL Subsequent development of the Project will occur in three phases, assuming the development proceeds on a "normal" track. The first phase is Preliminary Design and Permitting, which includes the current effort as well as future work to obtain the necessary construction approvals from state and federal authorities. The second phase is design and contract bidding, and the final phase is the actual construction. A preliminary development schedule is shown in Figure 16. As can be seen, the assumed schedule results in the Project generating power in mid-2006. The activities that cause this schedule are discussed below. The preliminary design contained in this document defines the Project arrangement that Kootznoowoo can use to begin the process of obtaining the necessary permits and approvals. However, the regulatory framework for the permits and approvals is not yet established. The biggest questions is whether Kootznoowoo needs to apply for a license from the Federal Energy Regulatory Commission (FERC). FERC has previously indicated that their informal opinion is that ANILCA divests them of regulatory authority and transfers it to the U.S. Forest Service. However, FERC also has recommended that Kootznoowoo obtain a legislative clarification of that position. Such legislation could also be a vehicle for funding authorization and possibly a land boundary adjustment. The Forest Service has indicated they want FERC to have authority, and FERC authority could provide for more disciplined agency consultation. The development schedule shown in Figure 16 shows establishment of the regulatory framework to be the major Project activity through most of 2000. It is expected that the lead agency (either FERC or the Forest Service) will need to prepare an Environmental Assessment for the Project, based on an applicant -prepared preliminary environmental document. Prior to preparation of the EA, Kootznoowoo will need to conduct a number of field studies to obtain the information on which the EA will be based. Prior to conducting those studies, Kootznoowoo will need to conduct scoping meetings with the regulatory agencies and the public, and prepare study plans to address the environmental issues surfaced during the scoping. At this time, we cannot predict completely what environmental issues will arise. The following is a preliminary list of issues and studies that can be reasonably expected to occur: ® Stream surveys and habitat mapping of the anadromous reach and bypassed reach of Thayer Creek. Minnow trapping and/or electrofishing in the bypassed reach to determine fish utilization (if any). ® Subsurface habitat mapping in the vicinity of the port facilities. ® Wildlife surveys to determine wildlife usage of the Project area. ® Photographic renderings to demonstrate the Project's visual impact. HDR Alaska, Inc. 31 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated ® Cultural resources survey of the Project area. ® Wetlands inventory Because of the complexity of these issues and the likelihood of an organized opposition to the Project, we expect that it will take over a full year of field studies to adequately address all of the environmental issues, and that all of the permit applications will be submitted by January, 2004. The following is a preliminary list of permits that will be required: ® FERC license (tentative) ® U.S. Forest Service Special Use Permit ® U.S. Army Corps of Engineers Dredge and Fill Permit/Alaska Department of Environmental Conservation Water Quality Certification ® Alaska Coastal Zone Consistency Determination ® Alaska Department of Fish and Game Habitat Permit ® Alaska Department of Natural Resources Water Right Assuming that Kootznoowoo can obtain local and congressional support for the Project, we expect that the necessary permits can be issued by the end of 2005 (a 24-month processing period). That is typical for a small hydro Project in Alaska if regulated by FERC. If the Forest Service has the primary authority rather than FERC, then additional time could be required because of the Forest Service's unfamiliarity with hydroelectric projects and a possible bias against the Project. While the pern fitting process is proceeding, Kootznoowoo will also need to be actively obtaining grants to defray the cost of the Project. That activity should begin as soon as possible so that the degree of congressional support can be gauged prior to conducting any expensive field studies. C. DESIGN AND CONTRACT BIDDING Once it appears that the necessary permits can be obtained without fatal conditions attached, Kootznoowoo can proceed with design of the Project. However, considering the issues surrounding the Project, the schedule shown in Figure 16 assumes that only those field studies critical to the maintenance of the schedule will be authorized prior to receipt of the permits. Those critical activities include a geotechnical evaluation of the Project site, detailed topographic mapping of the diversion and powerhouse areas, and a bathymetric survey of the transmission line route. The schedule further assumes that the development will proceed under four separate construction contracts as a traditional design/bid/build development. The four assumed contracts are: ® Port facilities and access roads ® Generating equipment ® General construction a Transmission line Other contract arrangements are certainly possible, depending on how much control Kootznoowoo wants over the final development and how much risk it is willing to take to reduce the overall cost. HDR Alaska, Inc. 32 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated D. CONSTRUCTION For the purposes of this feasibility study, it has been assumed that construction would begin in the late spring of 2005 and continue for 18 months until the end of the summer of 2006. This would provide two full summer seasons when construction is most easily accomplished in an inclement weather location such as Angoon. Key assumptions and/or dependencies of the construction schedule are: ® The contract for construction of the port facilities and access roads is awarded by the end of March, 2005, and the contractor is finished with the port facilities and powerhouse access road by the end of June, 2005. ® The supply contract for the major generating equipment is awarded by the end of March, 2005, and the equipment is delivered to the site 13 months later. ® The powerhouse structure is complete by the end of November, 2005 so that installation of the interior mechanical and electrical systems can proceed during the winter. i Construction of the diversion/intake structure begins in late winter, 2005 when streamflows are normally at their lowest level. See Section VIII for a more detailed discussion of the assumed construction sequence for the diversion/intake structure. HDR Alaska, Inc. 33 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated A construction cost estimate for the selected Project arrangement as described in Section VI is shown in Table IX-1. This construction cost estimate includes both direct construction costs (i.e. costs for work by construction contractors) and indirect construction costs, which includes pre - construction costs for permitting, design, and legal services, as well as management and administrative costs during construction. The cost of the current study is not included, as it is being funded by a grant. The cost of feasibility work prior to the current study is also not included. Costs for civil and structural aspects of the Project have been estimated by calculating quantities of construction and then applying unit costs. The unit costs are for 1999 construction, and have been developed from several sources, including costs from similar recent construction and from standard estimating guides with adjustments for the remote Project location. For road construction, we have relied heavily on Kootznoowoo's actual history with logging road construction in the area. Costs for the generating equipment have been based on preliminary estimates provided by equipment suppliers, including Gilkes, Sulzer, and Alstom. Gilkes provided the most favorable s estimate, and based their estimate on existing turbine designs. The construction cost estimate includes additional amounts for contingencies, with a 10% contingency applied to the cost of the generating equipment, a 20% contingency applied to the transmission line, and a 15% contingency applied to the remainder of the construction. The contingency allowance is to provide for items that may have been overlooked or underestimated as well as costs for unforeseen conditions that might occur during construction. Indirect construction costs have been estimated primarily from recent experience with similar projects. The indirect cost that is most difficult to estimate is the cost for permitting and licensing. The amount estimated for this item ($578,000) is considered to be reasonable if opposition to the Project does not result in protracted delays or legal/regulatory conflicts. '_. Other costs will occur that will increase the amount required to be funded, including interest during construction and financing costs, which would include administrative costs associated with obtaining any grants as well as fees to lenders or bond underwriters for any portion of the Project not funded by grants. The assumptions regarding these costs are discussed in more detail in Section X. HDR Alaska, Inc. 34 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report u . AG 01 tit des ii 6tion 330 LAND AND LAND RIGHTS 1 U.S. Forest Service I L.S.- m .. Suipf Acc to 33E1. "i;ind_�ridnd Itf htsa 330.5 MOBILIZATION AND LOGISTICS .1 Mobilization of Crew and Equipment 1 L.S. $ 400,000 .2 Temporary Facilities On Site 1 L.S. S 50,000 $ 50,000 .3 Housing and Subsistence 8,850 Man -Days $ 25.00 $ 221,000 .4 Daily Crew Transportation To/From Site 400 Days S 100.00 $ 40,000 .5 Light Helicopter 40 Hrs $ 750 $ 30,000 _...,..n .. „talatotal ice-1do:330:5-14�Ioliiliztiati end:.... - itics 331 STRUCTURES AND IMPROVEMENTS .1 Powerhouse .1 Clearing (Powerhouse/Switchyard) 0.30 AC $ 5,000 $ 2,000 .2 Unclassified Excavation 930 C.Y. S 40.00 $ 37,000 .3 Backfill 1,490 C.Y. S 20.00 $ 30,000 .4 Slope Stabilization 34 EA $ 150 $ 5,000 .5 Cast -In -Place Concrete - Structural 134 EA $ 1,000 $ 134,000 .6 Cast -In -Place Concrete - Slabs 150 C.Y. $ 800.00 $ 120,000 .7 Pre-engineered Metal Building 2,040 S.F. $ 25.00 $ 51,000 .8 Insulation 6000 S.F. $ 4.00 $ 24,000 .9 Metal Fabrications 5,000 LB. $ 5 $ 25,000 .10 Doors and Windows 1 L.S. S 6,000 $ 6,000 .11 Interior Finish 1 L.S. $ 14,000 $ 14,000 .12 Heating and Ventilation 1 L.S. S 10,000 $ 10,000 .13 Plumbing 1 L.S. $ 25,000 $ 25,000 .14 Grounding Grid I L.S. $ 15,000 $ 15,000 Subtotal - Acc No. 331.1 - Powerhouse $ 498,000 .2 Garage .1 Unclassified Excavation 40 C.Y. $ 25.00 $ 1,000 .2 Concrete Foundation (incl. reinforcing) 20 C.Y. $ 800.00 $ 16,000 .3 Pre-engineered Metal Building 500 S.F. $ 20.00 $ 10,000 .4 Insulation 1,900 S.F. S 4.00 $ 8,000 .5 Doors and Windows I L.S. S 3,000 $ 3,000 .6 Heating and Ventilation 1 L.S. S 2,000 $ 2,000 .7 Plumbing I L.S. S 5,000 $ 5,000 Subtotal - Acc No. 331.2 - Garage $ 45,000 "' "Subtotal -A& No.331 =- SWeturei acid lmrovements HDR Alaska, Inc. 35 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated 332 RESERVOIRS, DAMS, AND WATERWAYS .1 Diversion Dam .1 Cofferdam .2 Unclassified Excavation .3 Foundation Grouting .4 Leveling Concrete .5 Cast -In -Place Concrete .6 Rockfill .7 Grouted Rockfill (Concrete Cost Only) .8 Shipping Containers (for temp. diversion) .9 Modify Container for Sluiceway .10 Sluice Gate Subtotal - Acc No. 332.1 - Diversion Dam .2 Intake Structure .1 Modify Containers for Intake .2 Rockfill .3 Cast -In -Place Concrete .4 Metal Fabrications .5 Butterfly Valve .6 Roof Hatch Subtotal - Acc No. 332.2 - Intake Structure .3 HDPE Pipe .1 HDPE Pipe - Supply .2 HDPE Pipe Installation Subtotal - Acc No. 332.3 - HDPE Pipe .4 Surge Tank .1 Clearing .2 Unclassified Excavation .3 Precast Concrete Cylinder Pipe .4 Cast -In -Place Concrete .5 Miscellaneous Metal Subtotal - Acc No. 332.4 - Surge Tank 300 C.Y 120 C.Y 1 L.S. 90 C.Y 92 EA 1,120 C.Y 77 C.Y 1 L.S. 1 L.S. 1 L.S. 1 L.S. 1,300 C.Y. 60 C.Y. 7,000 LB. I EA 1 EA 6,070 L.F. 6,070 L.F. 0.17 400 240 54 400 AC C.Y. L.F. C.Y. LBS Feasibility Evaluation Report $ 50.00 $ $ 75.00 $ $ 35,000 $ $ 500 $ $ 1,000 $ $ 20.00 $ $ 500 $ $ 31,000 $ $ 5,000 $ $ 30,000 $ $ 10,000 $ $ 10.00 $ $ 1,000 $ $ 5.00 $ $ 50,000 $ $ 5,000 $ $ 56.00 $ $ 50.00 $ $ 10,000 $ $ 25.00 $ $ 320 $ $ 800 $ $ 5.00 $ 15,000 9,000 35,000 45,000 92,000 22,000 38,000 31,000 5,000 30.000 322,000 10,000 13,000 60,000 35,000 50,000 5.000 173,000 340,000 304 000 644,000 2,000 10,000 77,000 43,000 HDR Alaska, Inc. 36 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated TABLE IX-1 Feasibility Evaluation Report EiTnit .5 Penstock (Steel Pipe) .1 Clearing 0.60 AC $ 15,000 9,000 .2 Unclassified Excavation 390 C.Y. $ 40.00 16,000 .3 Cast -In -Place Concrete 30 C.Y. $ 1,000 30,000 .4 Steel Pipe 520 FT $ 120.00 $ 62,000 .5 Special Pipe Fabrications I L.S. $ 16,000 $ 16,000 .6 Pipe Supports 13 EA. $ 2,500 $ 33,000 Subtotal - Ace No. 332.5 - Penstock (Steel Pipe) $ 166,000 .6 Tailrace and Outfall .1 Clearing 0.2 AC $ 10,000 $ 2,000 .2 Unclassified Excavation 700 C.Y. $ 25.00 $ 18,000 .3 Backfill 1100 C.Y. $ 20.00 $ 22,000 .4 Precast Concrete Cylinder Pipe 300 L.F. $ 240.00 $ 72,000 .5 Cast -In -Place Concrete 28 C.Y. $ 1,200 $ 34,000 Subtotal - Acc No. 332.5 - Tailrace and Outfall $ 148,000 U "And W 333 TURBINES AND GENERATORS .1 500 kW Turbine, Generator, and Shutoff Valve 2 EA $ 320,000 $ 640,000 .2 T/G/V Installation 2 EA $ 25,000 $ 50,000 .3 50 kW Auxiliary Diesel Generator I EA $ 25,000 $ 25,000 es and or. kc, :G6ueiiit6n" "711 QW, 10 334 ACCESSORY ELECTRICAL EQUIPMENT . I Switchgear I L.S. $ 75,000 $ 75,000 .2 Control System I L.S. $ 148,000 $ 148,000 .3 AC Power and Lighting I L.S. $ 125,000 $ 125,000 .4 DC System I L.S. $ 18,000 $ 18,000 --''Subtotal ''Acc, 6�434-�-'Wic i& Electrical,Euiptneut 366-000, 335 MISCELLANEOUS MECHANICAL EQUIPMENT .I Bridge Crane I L.S. $ 40,000 $ 40,000 .2 Miscellaneous Vehicles and Equipment I L.S. $ 70,000 $ 70,000 -S U oil - '6. `bt t "Ai6iN "335% sc.- Mechanical Equipment 116,000, 336 ROADS AND BRIDGES .1 Port Facilities . I Fill 1,700 C.Y. $ 5.00 $ 9,000 .2 Timber Crib (Temporary) I L.S. $ 25,000 $ 25,000 .3 Permanent Moorings I L.S. $ 10,000 $ 10,000 Subtotal - Ace No. 336.1 - Port Facilities $ 44,000 HDR Alaska, Inc. 37 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated .. ,, CONSTRUCTIONOST ESTIMATE FOR SELECTED PROJECT Feasibility Evaluation Report FERC �� >i%a►t �A�nonn� .2 Powerhouse Access Road .I Clearing 5 AC $ 10,000 $ 52,000 .2 Unclassified Cut and Fill 14,100 C.Y. $ 10.00 $ 141,000 .3 Slope Protection 1 L.S. $ 11,000 $ 11,000 .4 Surfacing 2,700 C.Y. $ 30.00 $ 81000 Subtotal - Acc No. 336.2 - Powerhouse Access Road $ 285,000 .3 Diversion Access Road .1 Clearing 5 AC $ 10,000 $ 49,000 .2 Unclassified Cut and Fill 17,600 C.Y. $ 10.00 $ 176,000 .3 Slope Protection I L.S. $ 30,000 $ 30,000 .4 Surfacing 2,000 C.Y. $ 30.00 $ 60,000 .5 Bridge 1 L.S. $ 145,000 $ 145,000 Subtotal - Ace No. 336.3 - Diversion Access Road $ 460,000 Subtotal "A--' 353 SUBSTATION EQUIPMENT AND STRUCTURES .1 Transformer, 750 WA (4.16kV/12.47kV) 1 EA $ 34,000 $ 34,000 .2 Switches 1 EA $ 8,500 $ 9,000 .3 Foundations 5 C.Y. $ 1,000 $ 5,000 000. 355 TRANSMISSION LINE .1 Overhead Line, Powerhouse to Port Facilities 2.00 MILES $ 110,000 $ 220,000 .2 Overhead Line, Port Facilities to Kootz. Inlet 3.84 MILES $ 165,000 $ 634,000 .3 Submarine Crossing to Angoon 0.86 MILES $ 225,000 $ 194,000 .4 Mobilization for Submarine Crossing 1 LS $ 75,000 $ 75,000 .5 Interconnection at Angoon 1 LS $ 50,000 $ 50,000 Siibttital = Ace No::355 = Transnission`Llue = $ '. 1 173'000 HDR Alaska, Inc. 38 March 2000 Angoon Hydroelectric Project Kootznoowoo, Incorporated TABLE IX-1 ,�. . . t SUMMARY 330 LAND AND LAND RIGHTS 330.5 MOBILIZATION AND LOGISTICS 331 STRUCTURES AND IMPROVEMENTS 332 RESERVOIRS, DAMS, AND WATERWAYS 333 TURBINES AND GENERATORS 334 ACCESSORY ELECTRICAL EQUIPMENT 335 MISCELLANEOUS MECHANICAL EQUIPMENT 336 ROADS AND BRIDGES 353 SUBSTATION EQUIPMENT AND STRUCTURES 355 TRANSMISSION LINE TOTAL DIRECT CONSTRUCTION COST CONTINGENCIES Equipment Contingency (Accts. 333,334,335) Transmission Line Contingency (Accts 353,355) General Contingency (Accts 330,330.5,331,332,3: CONTINGENCY ALLOWANCE TOTAL CONSTRUCTION COST PERMITTING AND ENGINEERING Licensing/Permitting Design Engineering Construction Management TOTAL PERMITTING AND ENGINEERING COST TOTAL PROJECT COST 10% 20% 15% 13.2% Average Feasibility Evaluation Report $ 741,000 $ 543,000 $ 1,587,000 $ 715,000 $ 366,000 $ 110,000 $ 789,000 $ 48,000 $ 1,173,000 $ 6,072,000 $ 120,000 $ 240,000 $ 440.000 $ 800,000 $ 6,872,000 $ 578:000 $ 400000 $ 250,000 $ 1,228,000 $ 8,100,000 HDR Alaska, Inc. 39 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated B. OPERATING COSTS Operating costs for the Project will include: labor for the operations and maintenance personnel; ® expenses for transportation of the O&M personnel to the site; a routine expenses for parts, tools, and supplies; ® administrative costs; ® insurance; and 0 interim replacements (i.e., annualized cost for future major maintenance or upgrade). To some degree, these costs will depend on who operates the Project and who receives the power (see also Section X). For purposes of this feasibility study, it has been assumed that Project O&M can be coordinated with the O&M for the existing diesel plant so that only a single new half-time position is required. The total O&M cost for the Project is estimated to be $85,000 (in 1999 dollars), as shown in Table IX-2. TABLE IX-2 ESTIMATED OPERATION AND MAINTENANCE COSTS Misc. Expenses Administrative Insurance Replacements $15,000 35% of O&M $15,000 0.1% of Total $8,000 Construction Cost 0.2% of Total $17,000 Construction Cost Total $85,000 HDR Alaska, Inc. m March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated A. GENERAL The Angoon Power Supply Study (HDRlFEC, 1998) concluded that diesel generation is the only technology (other than hydroelectric) which is currently viable for Angoon. It also concluded that the total project cost for the Project could be no more than about $4-5 million for it to compare favorably with continued use of diesel generation, assuming financing at a 6% interest rate and then -current costs for diesel fuel. These conclusions of the Angoon Power Supply Study are still generally valid. However, some circumstances have changed since issuance of that report, most notably being the development of the Project arrangement and cost estimate discussed in previous sections of this report. Therefore, the economic analysis of the Angoon Power Supply Study has been revised and expanded, as described below. Diesel generators currently provide all of the electricity for Angoon, and diesel generation is considered to be the only viable technology (other than hydroelectric) for Angoon for the foreseeable future. Accordingly, the economic analysis is basically an evaluation of diesel vs. hydroelectric generation under a couple of possible utility structures. The following subsections describe the assumptions made for the economic analysis. In addition, we have provided a few comments regarding three power supply options other than diesel generation that may be of interest. 1. General Assumptions The following are assumptions and parameters that apply to all of the power supply options considered in the economic analysis: ® The analysis period is through the end of the expected 50-year term of the license (2054). Because of the uncertainties associated with projecting that far into the future, we also consider the economic feasibility after 10 years and 30 years. ® All variable costs except diesel fuel are assumed to escalate at 2.5% per year. ® To provide a reasonable basis for decision, all future costs are discounted to a present worth by 6% per year. ® Peak and energy loads in Angoon are assumed to escalate at 1% per year from the 1997 load levels. ® Station use and distribution losses are assumed to be 10% of the total energy requirements. ® Generating resources are assumed to be maintained such that there is sufficient capacity to meet the expected annual peak if the largest unit is unavailable. HDR Alaska, Inc. 41 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 2. Diesel Generation In 1998, T-HREA installed a new 550-kW diesel generator in the Angoon power plant. That installation has generally been used as the basis for many of the parameters for diesel generation used in the economic analysis. The primary parameters and assumptions are as follows: ® New generating units are added when required in 550-kW increments at a cost of $280,000 (1998 cost level). ® Existing generating units are replaced when they have accumulated 200,000 hours of service, and each of the two existing units are run approximately 5,000 hours per year. ® New generating units are financed at a 6% interest rate with a term of 15 years. ® The 1999 cost of diesel fuel delivered to Angoon is $1.00/gallon. ® Diesel fuel is assumed to escalate at a rate of 3.0% per year, slightly higher than the general inflation rate. ® Variable operating costs other than overhauls are assumed to be 0.5 0/kWh (1998 cost level). ® Overhaul costs are assumed to be equivalent to $5.00 per operating hour (1998 cost level). ® Fuel efficiency is assumed to be 13.2 kWh/gallon, equal to the average efficiency achieved by T-HREA in 1997. 3. Angoon Hydroelectric Project The following assumptions are derived from the studies documented herein as well as from actual operating history for similar small hydroelectric projects: ® The total investment cost of the Project (excluding any grant funding) is $8,100,000 (1999 cost level). ® The Project is financed at a 6% interest rate with a term of 30 years. ® Financing costs amount to 2% of the total Project cost less any grant funding. ® Interest during construction amounts to 7.5% of the total Project cost less any grant funding. ® To recoup its investment in the Project through 1997, Kootznoowoo will earn an annual premium of $50,000 once the Project becomes operational (1999 cost level). ® Ordinary operating costs for the Project are $85,000 per year (1999 cost level). That amount assumes that the operator for the diesel power plant will be available for routine operation of the hydro Project. ® The Project will generate 95% of the Angoon power requirements. The remaining 5% would be supplied by the existing diesel generation, and accounts for the few days per year when streamflows may be insufficient to meet all requirements and for unplanned outages due to mechanical problems with the Project. ® No credit is taken for disposal of one of the two existing generators, even though one would be surplus to Angoon's needs. HDR Alaska, Inc. 42 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated C. ANALYSIS RESULTS FOR ALTERNATIVE UTILITY STRUCTURES The Angoon Power Supply Study considered several utility structures for supplying power to Angoon. Two utility structures are considered to be reasonable, and have been considered for this economic analysis: 1) continued service by T-HREA, and 2) establishment of a new utility specifically for Angoon. The following subsections describe the assumptions and results of the economic analysis for these two utility structures. The economic analysis calculations are provided in Appendix C. 1. Continued Service by T-H A T-HREA recently lost a court decision over the right to provide power to Klawock, which was one of its largest and most economical load centers. In the future, Klawock will be provided power by Alaska Power & Telephone. The loss of the Klawock load will mean the fixed costs of the T-HREA operation will be borne by fewer customers, including the citizens of Angoon. However, T-HREA has recently indicated that it will be able to maintain the existing retail rates, whereas if it had not lost the Klawock load it would have been able to reduce rates by 10-15%. There is substantial uncertainty regarding T-HREA's future viability. Also, T-HREA's use of a "postage stamp" rate (i.e. the same rate for all communities regardless of individual power supply costs) make it difficult to consider development of the Project under that utility scenario, since the benefits would flow to all T-HREA customers, not just to Angoon citizens. It is considered 4 for this economic analysis because there are some possible political benefits that could make obtaining 100% grant funding of the Project easier to obtain, as follows: : ® Grant funding of the Project would be seen as helping a larger group of citizens. ® Grant funding of the Project could be seen as helping T-HREA overcome loss of I customers to a non -Alaska corporation. ® Grant funding of the Project could make T-HREA a proponent of project development rather than a neutral or antagonistic party, thus clearing away some significant hurdles. In evaluating the economics of Project development under this existing utility structure, we have made the following assumptions: f ® All T-HREA loads will increase at the same rate at Angoon loads. 4 ® T-HREA's annual costs for items other than fuel and O&M amount to $2,800,000 (1999 cost level). This assumption results in a cost of power equal to the current retail rate. e 25% of the T-HREA costs for items other than fuel and O&M are fixed (i.e. amortization). a Power from the Project is sold at cost to T-HREA for the life of the Project, except that Kootznoowoo receives a return on its investment in the Project prior to 1997 as described earlier. Assuming 100% grant funding of the Project development, the cost of power to Angoon citizens with continued service by T-HREA would be as shown in Table X-1 below: HDR Alaska, Inc. 43 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated 2. Stand -Alone Angoon Utility If T-HREA ceases to provide power to Angoon, one option would be for the City to set up a new municipal utility. Under this scenario, the Project could be developed by Kootznoowoo and sold to the new utility at cost so that all of the Project costs and benefits would accrue to Angoon citizens. The assumptions made for evaluating the Project feasibility under this scenario are as follows: ® The cost to acquire T-HREA's generation and distribution assets would be $1,700,000, which is approximately the estimated net book value (1998 value). The cost is financed at an interest rate of 6% over 20 years. o The cost for legal or other fees necessary for the new utility to begin operation is $300,000 (1998 value). ® The new utility begins operation in 2005. ® Operating costs for the new utility other than for fuel, parts, and overhauls is $220,000 (1998 value). This assumes that the existing city administration can perform the utility administration functions economically. Assuming 100% grant funding of the Project development, the cost of power to Angoon citizens if a new municipal utility is set up would be as shown in Table X-3 below: AVERAGE COST OF POWER WITH STAND-ALONE ANGOON UTILITY Average Cost of P6wer; ¢/kWh First 10 ; First 30 First 50 Years Years Years Without Project Development 34.5 38.4 45.2 With Project Development 31.1 30.9 33.0 The rates shown in Table X-3 with Project development are substantially less than those shown in Table X-1 for continued electric service by T-HREA. Furthermore, the rates with Project development are very stable over the life of the Project. Rate stability is one the greatest benefit of hydroelectric development. On a discounted cost basis, the average cost of power would be as shown in Table X-4. It must be recognized that the cost of power values shown in Table X-4 are much lower than actual power costs, and are intended to be used only for evaluating the relative economics of the Project. HDR Alaska, Inc. 45 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated TABLE X-4 _ AVERAGE DISCOUNTED COST OF POWER WITH STAND-ALONE ANGOON UTILITY Average,Cat,6 Power, ¢/kWh. First 10 First 30' First 50=` Years Years Z r Years Without Project Development 21.6 _]7�12.7 14.7 11.0 With Project Development 19.9 9.2 These results indicate that Angoon ratepayers would see a substantial decrease in power rates if the Project were constructed and the power distributed by a local municipal utility. The cost advantage for the Project is about 15-25%, and is dependent on 100% grant funding of the construction. As shown in Figure 17, the economic advantage of the hydroelectric Project disappears if the grant funding is less than about 70%. Figure 18 shows how the cost of power would vary over time. It should be noted that the cost of power with the Project could actually be higher than diesel generation in the first few years of operation if a significant portion of the project cost is financed by loans rather than grants. 1. Load Growth Load growth in Angoon could have a significant impact on the Project's economic viability. To demonstrate this impact, cost of power calculations have been made for growth rates of 0% and 2% (in addition to the 1% growth rate assumed for the base studies). Table X-5 shows the average cost of power for the first 30 years of Project operation at these varying load growth rates, assuming 100% grant funding of the construction. TABLE X-5 AVERAGE COST OF POWER WITH VARYING LOAD GROWTH RATES 30-Year Average Cost of Power, 0/kWh 0% Load 1 % Load 2%`Load Growth Growth Growth CASE 1 - - Continued Service by T-HREA Without Project Development 50.6 44.0 38.9 With Project Development- 49.6 42.7 37.4 CASE 2 - - Stand -Alone Angoon Utility Without Project Development 43.4 38.4 34.5 With Project Development 37.3 30.9 25.9 HDR Alaska, Inc. 46 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated As Table X-5 shows, the Project's viability increases with higher load growth, particularly for the stand-alone utility case. Load growth will also influence how much of the Project must be funded by grants to make it economical to develop. With 0% load growth, 80-85% grant funding would be required, whereas with a 2% load growth, the required grant funding amount decreases to about 60-65%. 2. Diesel Fuel Escalation The price of diesel fuel also has a significant impact on the Project's viability. The base studies described above assume that diesel fuel prices increase 0.5% faster per year than the general inflation rate. In the last several years, diesel fuel prices have fluctuated drastically, and it is difficult to predict the future price. Because petroleum is a finite resource, the price should in the long term increase at a faster rate than general inflation. Table X-6 shows the average cost of power for the first 30 years of Project operation for diesel fuel escalation rates that are 0.0%, 0.5% and 1.0% higher than general inflation (i.e., 2.5%, 3.0%, and 3.5%), assuming 100% grant funding of the construction. 10LI 0.3 a�:a� AVERAGE COST OF POWER WITH VARYING DIESEL FUEL ESCALATION RATES 30-YearAyerage Costof�Power,; ea , OW11 2:5Q10 Fuel Fuel: _ 3,.Fuel, Escalation � :Escalation Escalation CASE 1 - - Continued Service by T-HREA Without Project Development 42.9 44.0 45.2 With Project Development 41.8 42.7 43.8 CASE 2 - - Stand -Alone Angoon Utility Without Project Development 37.3 38.4 39.6 With Project Development 30.8 30.9 30.9 Table X-6 demonstrates that the Project's viability is enhanced by higher diesel fuel prices, but the affect is not overwhelming. 1. Southeast Intertie The Southeast Intertie is a proposed transmission grid linking the major communities of Southeast Alaska. The idea has been around for many years, but no portion of it has ever been developed, due primarily to high costs. The first link likely to be developed is a line between the Tyee Lake Project near Petersburg to the Swan Lake Project near Ketchikan, which would allow HDR Alaska, Inc. 47 March 2000 Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated use of excess Tyee Lake energy to meet growing loads in Ketchikan. Other links could connect Petersburg/Wrangell with Sitka, Juneau, and other southeast communities. If the Southeast Intertie were developed, Angoon might be interconnected at a fairly nominal cost, and the small Angoon load could be supplied by power from existing or new large hydro projects rather than the Thayer Lake Project. Conversely, Angoon could use the intertie to sell excess power from an expanded Thayer Lake Project. Although some communities and organizations are actively pursuing development of the Southeast Intertie, it will require a substantial amount of financial assistance from the state or federal governments. Also, it probably would be many, many years before it could supply Angoon with power. 2. Tidal The Angoon Power Supply Study noted the potential for developing the energy potential of the tides in Kootznoowoo Inlet, either by a conventional scheme involving water impoundments or by direct use of the tidal currents near Turn Point. That report concluded that tidal development would be risky and expensive. In addition, the generation would vary substantially from hour to hour and day to day, thus requiring the development of some type of energy storage system or continued use of diesel generation for a large portion of Angoon's energy needs. We understand Alaska Power & Telephone has recently expressed some interest in the tidal potential of the Turn Point currents. Our primary reservations about that type of development are 1) the expected high cost and 2) reliability issues associated with logs, marine mammals, or other masses in the tidal stream. 3. Fuel Cells Fuel cells generate electricity through an electro-chemical reaction similar to a battery. They provide very clean and reliable power, but need a hydrogen or hydrocarbon (e.g. propane) fuel supply. It is a promising technology, but it is currently only economical for backup power situations such as emergency generators. The cost of supplying hydrogen or propane to Angoon in the quantities needed for routine generation will make fuels cells uneconomical for many years. HDR Alaska, Inc. 48 March 2000 Y Angoon Hydroelectric Project Feasibility Evaluation Report Kootznoowoo, Incorporated XI. CONCLUSIONS AND RECOMMENDATIONS Based on this study of the Angoon Hydroelectric Project, it is concluded that: 1. Development of the hydroelectric potential is technologically feasible. 2. With an installed capacity of 1,000 kW, the Project would be able to meet virtually all of Angoon's existing loads as well as most future loads if load growth is moderate. 3. The assumed instream flow requirement (IFR) of 20 cfs continuously does not present a serious problem to the Project feasibility. However, a greater IFR as may be requested by the regulatory agencies could be detrimental. 4. The Project will have little impact on anadromous fish if the powerhouse discharges back to Thayer Creek near the base on the barrier falls approximately 2,000 feet upstream from the mouth. 5. The most economical project arrangement includes a low diversion/intake facility, an HDPE pipeline approximately 6,100 feet long, a steel penstock approximately 500 feet long, a powerhouse on the south side of Thayer Creek containing two Francis -type generating units, approximately 3.5 miles of access road, port facilities approximately 2 miles south of Thayer Creek, an overhead transmission line to the north side of Kootznoowoo Inlet, and a submarine crossing of Kootznoowoo Inlet to interconnect near the float plane dock. 6. The estimated Total Project Cost is $8,100,000, which includes approximately $6,900,000 for direct construction costs and about $1,200,000 for licensing and permitting, design engineering, and construction management. 7. Decreasing the capacity to 500 kW would reduce the Project cost by approximately $1,400,000. A 500 kW Project would be able to meet existing loads, but would not provide for significant load growth. 8. Transmission alternatives that could reduce the visual impact of the project are significantly more expensive. 9. The proposed transmission route would provide real opportunity to develop a water supply for Angoon at two small lakes approximately 2 miles north of town. 10. The earliest reasonable date for the Project to begin operation is toward the end of 2005. Licensing and permitting issues will have a great impact on the schedule. 11. The Project is economically feasible only if a large portion of the construction cost is funded by grants. 12. If the Project is developed and the power sold to T-HREA, the benefit to Angoon citizens is small; however, sale to T-HREA may enhance the chances of obtaining grant funding. HDR Alaska, Inca 49 March- 2000 r Angoon Hydroelectric Project Kootznoowoo, Incorporated Feasibility Evaluation Report FIGURE TITLE 1. Location Map and Vicinity Map 2. Annual Flow Duration Curve 3. Flood Frequency Curve 4. Alternative 1 General Plan 5. Alternative 2 General Plan 6. Alternative 3 General Plan 7. Selected Arrangement General Plan 8. Diversion Dam and Intake Structure 9. Pipeline, Surge Tank, and Penstock - - Sections 10. Powerhouse - - Site Plan 11. Powerhouse - - Interior Plan 12. Powerhouse - - Elevation and Section 13. Transmission Line - - Sections 14. One -Line Diagram - - Sheet 1 15. One -Line Diagram - - Sheet 2 16. Development Schedule 17. Grant Funding Requirements with Continued Service by T-HREA 18. Cost of Power Projection with Continued Service by T-HREA 19. Grant Funding Requirements with Stand -Alone Angoon Utility 20. Cost of Power Projection with Stand -Alone Angoon Utility HDR Alaska, Inc. March 2000 A R C TI C BARROW O C E A N P NDME I5 b ' PROJECT V I LOCATION � b u2OMORALE a i _ RIREAB GB 01F A 5 K A o�yA e EfLHIKAN P A C I F I C O C E A N LOCATION MAP FmKOOTZNOO ,NCOMOI—DORATED Alaska, Inc. 1*41 PROPOSED OVERLAND. TRla[SSION . LINES F i � V i f'Nfi,1R1_ � • -._ _. _. � (Y 7 � I! ''Yv �f'� y C t - ✓di, A i ^tA k 0 IN ANGOQN K00TZN00W00 INC. MARCH 2O00 ANGOON HYDROELECTRIC PROJECT Figure LOCATION AND LAND OWNERSHIP MAP 1 1 2000 1750 1500 1250 0) LL V 3 1000 O U. Aloska, Inc. 750 500 250 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% PERCENT TIME EXCEEDED KOOTZNOOW00 INC. ANGOON HYDROELECTRIC PROJECT ANNUAL FLOW DURATION CURVE 1OIK]U TMAYER CREEK LL LL LLI uj 100 1.001 1.02 1.11 1.25 2 5 10 20 100 1000 RETURN PERIOD, YEARS FMKOOTZNOOWOO Alaska, Inc. xOOTZwouWOO INC ANGOON HYDROELECTRIC PROJECT I . . . .. . . . . .. . .. . . IVE ... . ...... X "9009-- 500 0 500 1000 FEET 1 500' , d , J44, Fm K00TZN00W00@W4 Alaska, Inc. INCORPORATED ......... . . .... ...... .. .. ... . .. . ..... ... -1`6M URR, 4 AU U. E \X1 -PENST .... ...... CCE S R RAD DISP SA ........... 'M KOOTZNOOWOO INC. ANGOON HYDROELECTRIC PROJECT GENERAL PLAN — ALTERNATIVE 1 PIPELINE AND PENSTOCK Figure \ \ \ \ c , - it 5-77 iiiijil"I MENEM r w •• FMK00TZN00W00 Alaska, Inc. INCORPORATED , �v CTIO(dAL N.. E o / / / y rr /o i� o. / r" , \ r KOOTZNOOW00 INC. ANGOON HYDROELECTRIC PROJECT GENERAL PLAN — ALTERNATIVE 2 DIRECTIONAL DRILLED TUNNEL I 0 . . ......... O . . . . . . . . ....... IDP . . . . . . . . . . . . . ......... . .. . .... .... 0 6 , lKOOTZNOOWOO INCORPOPATED Alaska, Inc. 10� .. ........ 200 .... .. .... ....................... UN-N .. ............ < J -B U R'l E D,", Yi . . . ................ .. .............. KOOTZNOOWOO INC, ANGOON HYDROELECTRIC PROJECT GENERAL PLAN - ALTERNATIVE 3 CONVENTIONAL TUNNEL li M-1 NOTES: TOPOGRAPHY SOUTH OF KOOTZNOOW00 INLETBYR&M ENGINEERING AND LAMERTON & ASSOCIATES BASED ON AERIAL PHOTOGRAPHS TAKEN JULY 17, 1996. TOPOGRAPHY NORTH OF KOOTZNOOWOO INLET AND ORTHOPHOTO IMAGES BY CRAZY MOUNTAIN JV, NOVEMBER, 1997. KOOTZNOOW00 INC. ANGOON HYDROELECTRIC PROJECT SELECTED ARRANGEMENT GENERAL PLAN z a I AIR VENT !m MAX. SURGE W.S. El 275 CONCRETE SADDLE (TYP.) ___'X c CLEAR TREE" LY IN (®— DIRECT PATH —PIP IN \ \ 4WOOD POST 3TREATED" NYLON STRAP GALV. STL CABLE I ANCHORED TO ROCK OR LARGE STABLE TREES ADJUSTING CABLE FmAlaska, s EXPOSED PIPELINE SCALE 1/4"=1'0" (for 22x34) 42" DIA. HDPE PIPELINE STATIC W.S. El 260 5'0 CONCRETE CYLINDER PIPE 24010'=240' TOTAL LENGTH SURGE TANK SCALE 1/8"=1'0" (for 22x34) ORIGINAL GROUND LINE ASSUMED \ ROCK LINE CONCRETE SADDLE N-A STEADY—STATE W.S. El 218 (1000 kW) MAX. DRAFT W.S. El 213 0 PENSTOCK SCALE 1/2"=1'0" (for 22x34) ANCHOR STRAP 36"0 STL. PIPE CONCRETE THRUST BLOCK HDPE PIPELINE PENSTOCK KOOTZNOOW00 INC. MAR 2000 ANGOON HYDROELECTRIC PROJECT Figure PIPELINE, SURGE TANK AND PENSTOCK 9 SECTIONS PARTS & TOOLS 12' ROLL -UP wonxoswcx FLOOR DRAIN (T,p) LAYDOWN AREA HOSE RACK Tcnw|w»L oAmwcT (T,p.) N", LDESK AND po B U TTI�,R:_Y_V`A�LV�EW/ HYDRAULIC OPERATOR (TYP.) DRAFT \ / | Toes(np) GENERATOR U 500KW, ^80v uuo pr (T,p)rnAwo/s Tunmws -------' 700 yp, ruo npw (TYP.) R w lsan. Z E TRENCH BUNK CONTROL PANELS EYE WASH STATION (T,p) GENERATOR #1 BREAKER GENERATOR #2 BREAKER LOAD BANK REST LOAD BANK BREAKER ROOM STORAGE RBINE 12nvno BATTERY BANK BATTERY CHARGERS xooTZwU0w0O|wC. ANGOON HYDROELECTRIC PROJECT OWERHOUSE INTERIOR PLAN FRANCIS TURBINE 700 HP, 720 RPM YARD EL 30± 9w rt F DRAFT TUBE 48" STL PIPE DISCHARGE STRUCTURE PERCHED LEDGE MIGRATION BARRIER DESIGN FLOOD LEVEL EL 20± NORMAL WATER LEVEL EL 15± rC DISCHARGE SECTION 10 SCALE 1/8"=1'—O" (for 22x34) TRANSMISSION LINE DEAD END STRUCTURE o PRE—ENGINEERED METAL BUILDING MAIN POWER TRANSFORMER E r DIESEL GENERATOR EXHAUST O KOOTZNOOWOO Alaska, Inc. 4. mm=mmmm=mmmmmmmmmmm=mmmmmmmmmmmmmmmmmmmmmm=mmmmmmmmmmm= INCORPORKFED DESIGN FLOOD 36" STLPENSTOCK LEVEL EL 20± NORMAL WATER LEVEL EL 15± PRE—ENGINEERED METAL BUILDING CONCRETE THRUST BLOCK _\ EXPANSION JOINT YARD EL 30± RING GIRDER (TYP.) ---, Z 11 1�7--/l 11 IV ROIKFILL b ) Z>UUIH tLtVAIIUN 10 SCALE 1/4-=1'—O" (for 22x34) BUTTERFLY VALVE FRANCIS 'TURBINE 700 HP, 720 RPM SECOND STAGE CONCRETE STRUCTURAL BACKFILL a) TRANSVERSE SECTION � 10 SCALE 1/4"=1'-0" (for 22x34) 10T BRIDGE CRANE CONTROL ROOM CONTROL PANEL ORIGINAL GROUND LINE OIL/WATER SEPARATOR KOOTZNOOWOO INC. MAR 2000 ANGOON HYDROELECTRIC PROJECT Figure POWERHOUSE ELEVATION AND SECTION 12 15'± CLEARING LIMIT KOOTZNOOWOO Alaska, Inc. 55" MIN. CONDUCTOR SPACING TREATED WOOD �— POLE `- �i/r��71 CL ACCESS ROAD F 10' —15' / w I NK �� 10'-15' KOOTZNOOW00 INC. ANGOON HYDROELECTRIC PROJECT OVERHEAD TRANSMISSION LINE TYPICAL SECTION CLEARING LIMIT 480 V STATION BUS 480Y/277V, 3 PHASE 4W, 2000A BUS ------------------- TO w In PLANT PLC I + a T M STATION BUS CTS _ 480Y/277V, 3 PHASE, 4W, 2000A BUS -------------------- D m Q O N --------------------------------------------------I r a EXCITATION TRIP i i SHUT -DOWN SOLENOID BUS VG V1D TRIP 65SD PM METERING I l � 480:120 � 1 I I I Y PTS-3 I I PT3 (2) I I I 1600AF I I 900AT52G2 \----------------------------------------------J I 43 I G1 1 I PM SURGE I I I (I ARRESTORS IIi1I1II \\ ----------------------------------- ------- I /I1II -- ARRESTORS / VB VTD LOAD I EXCITATION 650 VOLT (3) BANK I TRIP 480:120 vs 400/5 400AF SHUT -DOWN SOLENOID 27 59 \81400AT TRIP 65SD —PTS-2 PT2 (2) 1600A�900AT 52G7 ----------------------------------- ----------WHM, VAR _II - - - - t />/} THD, WM PF, V SURGE IIIIIII1 PM 51V .32 J IIIIIII ( I I I II ARRESTORS VG VTD I CT2 51 B - - - - - � - I 650 VOLT 1 1 800:5 CTS-2 I i l I I I I 480:120 S —0' 27 59 81 I 800:5 SLC PTS-1 i I REGULATOR VOLTAGE 77 PLC i IF-- ------ I \ \ \ (- - - 1 I PT1 (2) PU CONTROL WHM. VAR I ---� -� _T I THD, WM I I I PU I 1 PF, V, A I I CT1 1 I I PM 51V S7N 32 I I 800:5 I I 1 - I I I 1 SHUTDOWN \ \\ \ 41E i SOLENOID CT2 516---- - 1 I 65SD TRIP I I --___ 1 I I 135 KW 135 KW I 800:5 CTS-2 - �_------- I I I I I I I I STEPPED CONTINUOUSLY I _1 I I I GENERATOR 2 LOAD ADJUSTABLE I 500 KW, 0.80 EXC I 1 I I I CONTROL LOAD I 480V, 3¢, 60HZ I I CONTROL 800:5 I 750 FLA \ I I 86M2 VOLTAGE _ _ 77 _ _ _ _ _ - PLC \ A ATD LOAD BANK REGULATOR F PU CONTROL I CT3 \ I I I I - - - - I I 77 I (3) Cam. I I L-� CONTROL SIGNAL I PU - 1 1 800:5 AS TO PLC CT1 I I \ CTS-1 1 I 800:5 1 1 1 ILJ\ I 1 1 I I I 41E I I SHUTDOWN 1 I \�------------------/-- 38 �49 39 Q21SOLENOID 1 TM G 65SD TRIP I I I I I 1 r 59N \ \ \ \ I I I GENERATOR 1 500 KW, 0.80 PF EXC 0V, 30, 60HZ 75 750fLA \ I 1 S6M1 i I L-------------------------------------------------------J ---� \ A ATD ABBREVIATIONS (CONTINUED) I I I SC SYNCHRONISM CHECK i 1 D CT3 \ 1 1 I 1 I SLC STEPPED LOAD CONTROLLER (3) CTY \ I \ I 1 I I I A AMMETER SS SYNCH SCOPE OR SELECTOR SWITCH 800:5 AS I I AS AMMETER SWITCH THD TOTAL HARMONIC DISTORTION \ CTS-1 j I i i ATD AMP TRANSDUCER TL TIE LINE B BUS V VOLTMETER - - - - - - - - - - - - - - - - - - - - 38 -_ 38 49 39 2.1 1 I 1 CT CURRENT TRANSFORMER VAR VOLT AMPERES REACTIVE METER TM TM G 14 1 1 1 CTS CURRENT TEST SWITCH VARTD VAR TRANSDUCER r 59N �\ �\ �\ �\ I j EXC EXCITER VFI VACUUM FAULT INTERRUPTER II-� F FREQUENCY METER VS VOLTMETER SWITCH G GENERATOR VTD VOLT TRANSDUCER I j I H3 SYNCH SELECTOR SWITCH WM WATT METER L--------------------------------------------------------� --- PF POWER FACTOR METER WH WATTHOUR METER PM POWER LOGIC MONITOR WTD WATT TRANSDUCER PT POTENTIAL TRANSFORMER VB BUS VOLTAGE PTS POTENTIAL TEST SWITCH VG GENERATOR 'VOLTAGE A4td41h4'w m •• •i •• Alaska, Inc. INCORPORATED W SS 43 G2 12 GENERATOR OVERSPEED 13, 14 GENERATOR SPEED SENSING 25 SYNCHRONISM CHECK DEVICE 25A AUTOMATIC SYNCHRONIZER 25VTX SYNCHRONIZING VOLTAGE TRANSDUCER 27 UNDERVOLTAGE RELAY 32 DIRECTIONAL POWER RELAY 38 BEARING TEMPERATURE RELAY 39 VIBRATION MONITORING DEVICE 40 FIELD RELAY 41 FIELD CIRCUIT BREAKER 43 MANUAL TRANSFER OR SELECTOR DEVICE 46 REVERSE -PHASE OR PHASE -BALANCE CURRENT RELAY 49 TEMPERATURE RELAY (G=GENERATOR, T=TRANSFORMER) 51B AC TIME OVERCURRENT RELAY (B=BACKUP) 51TN AC TIME OVERCURRENT RELAY (TN=TRANSFORMER NEUTRAL) 51V AC TIME OVERCURRENT RELAY (V=VOLTAGE RESTRAINT) 52 AC CIRCUIT BREAKER 59 OVERVOLTAGE RELAY 59N/27 100% STATOR GROUND RELAY 60 VOLTAGE BALANCE 63 PRESSURE SWITCH 64F FIELD GROUND PROTECTIVE RELAY 65SD SHUTDOWN SOLENOID 71 OIL LEVEL SWITCH LOW 77 TACHOMETER PICKUP AND TRANSMITTER 81 FREQUENCY RELAY (0/U=OVER/UNDER) 86 LOCK -OUT RELAY (E=ELECTRICAL, M=MECHANICAL) K00TZNC0W00 INC. ANGOON HYDROELECTRIC PROJECT ONE LINE DIAGRAM - - SHEET 1 14 - MCC-XXX I 480V, 30, 4W, 600A, CU BUS ELECTRONIC MCP j MCP MCP ) MCP 20/3 20/3 6C i I 1 200/3 ) / 120/208V 4f FVNR 1 FVNR 1 FVNR 1 FVNR 1 PNLBD PPB I w H Q W W w N N L m m W W W W Q Q Q Q Q Q N EL N a- a a XFMR-XXX -- (n � 48V I GENERATOR CONTROI. PANEL 1 b MAIN POWER TRANSFORMER 50 KW I I 12.47/7.2 KV I STANDBY GENERATOR I GROUNDED Y- 0 480V DELTA - - - - 1500 KVA - CTS-3 225AF 200AT If 2 TO BUS METERING i o LEGEND: 0 MCC-XXX ONE LINE DIAGRAM I I I 1 L - - 12.47/7.2 KV SUBMARINE CABLE TO ANGOON ft EXISTING 6.5 MILE DISTRIBUTIONLINE DISTRIBUTION SYSTEM i POWER CIRCUIT, 12.47KV POWER CIRCUIT BREAKER Q 52G2 480 VOLTS OR MORE o (3 POLES OR AS INDICATED) POWER CIRCUIT, 460V POWER CIRCUIT, 120V GENERATOR a '-------- OPERATIONAL LINE e6 - - — EQUIPMENT ENCLOSURE —III SURGE ARRESTOR POWER TRANSFORMER RECTIFIER --I�— CURRENT TRANSFORMER - HEATING ELEMENT M � t-1 —ts RESISTOR POTENTIAL TRANSFORMER MOTOR OR GENERATOR FIELD CONTACT, NORMALLY OPEN — POWER CIRCUIT RRFAKFR CONTACT, NORMALLY CLOSED SYSTEM ONE LINE DIAGRAM FUSE, BASIC -0- 0- SWITCH CURRENT TEST SWITCH —0 r BYPASS SNITCH THREE PHASE WYE CONNECTION WITH NEUTRAL EXTENDED NUMBER IN HEX REFERENCES CONDUIT SCHEDULE D 0 - 208Y/120V 30, 4W, > > uj 30 KVA uj I INVERTER I w m V m U BYPASS SWITCH 1 F I 125V DC BATTERY 125V DC BANK LPNLBD - L 1 CONTROL SYSTEM 27 LOADS g �I 86E1 AND 86E2 COMBINATION MAGNETIC STARTER WITH MOTOR CIRCUIT PROTECTOR (MCP) TYPE CIRCUIT BREAKER DISCONNECT. RATING OF THE MCP SHALL BE DETERMINED BY THE MANUFACTURER OF THE STARTER AND MCP THEREFORE IS NOT SHOWN ON THE DWGS. C A - STARTER TYPE: FVNR - FULL VOLTAGE NON -REVERSING B - NEMA SIZE A B C - REFERENCES CONTROL DIAGRAM NUMBER OINDICATING METER AS SWITCH KOOTZNOOW00 INC. ANGOON HYDROELECTRIC PROJECT ONE LINE DIAGRAM - - SHEET2 me PRELIMINARY DESIGN AND PERMITTING Prepare Preliminary Design Establish Regulatory Framework Environmental Studies ...................... ... .._._.__........ ...................... ..... _.......... _...... _....._.:._..v...... Study Scoping and Planning Field Studies ._.................... _..._._._.._........... _._..._.......... _.................. ........ _... .._.,............. Prepare Permit Applications Permit Application Processing DESIGN AND BIDDING Field Investigations ......... _....................................._......_.................._...._._.......__,._.._........ Port Facilities and Access Roads Prepare Bid Documents ..................... ............. ...... ..... ..... ................ _........ .... ........... __.._._........._.<......._.... Bid Solicitation and Award Generating Equipment Prepare Bid Documents Bid Solicitation and Award ............ .................... __.... ............ ......................... _ ..... I. .......... ............. . . General Construction Prepare Bid Documents .... _.... ............. .............. ..... .......... _...... _....... _._.............. .............. .._.............:._...;..._. Bid Solicitation and Award Transmission Line ..... . ............... _................._._..... _.... _............... ._...... _................... :._...;.._.._. Prep_are Bid Documents Bid Solicitation and Award CONSTRUCTION Port Facilities Powerhouse Access Road ............... ._...... ._....._.......................... ............... ........ ................... __......_.:...._;....... . Intake Access Road General Contractor Mobilization .. ...................... ............ ____..... .... __...... ._._.................. ........ _...............:_. Diversion Dam and Intake Powerhouse Structure . ................ ................ ... __....... _.... _...... _............................. _...... ..._.........__ .. Pipeline and Penstock Generating Equipment Manufacture Generating Equipment Installation Miscellaneous Mach. & Elec. Equip. .......... _...... _...... ___._.... _......... _... _..__.... _... _...._....._._............. ..._.:..._-;__... Transmission Line Startup and Testing 41 K00TZN00W00Alaska, Inc. INCORPORATED ' KOOTZNOOW00 INC. ANGOON HYDROELECTRIC PROJECT PRELIMINARY DEVELOPMENT SCHEDULE MR '51.0 : 471) ' 45.0 ! 43.0 ^ 41]3 ' 39.0 Fm Alaska, Inc. 2596 50% 75% 100% GRANT FUNDING AMOUNT xooTZNoownO INC. ANG0ON HYDROELECTRIC PROJECT GRANT FUNDING REQUIREMENTS YNTH CONTINUED SERNCE BYT—HREA I KEY ASSUMPTIONS: Annual energy growth rate -196. Grant funding ofProject '10O%. First full year ofoperation '-200O. Diesel fuel cost --$1.UU/oa|in1QS9. General inflation rate -2.596. Diesel fuel escalation rate -3.0Y6. KOOTZNOOWOO INC. ANGOON HYDROELECTRIC PROJECT Mal KOOTZNOOWOO Alaska, Inc. COST OF POWER PROJECTION WITH CONTINUED SERMCE BY T—HREA 70.0- HYDRO & 0% LOAD GR OWTH HYDRI 65.0 - ---------------- ----------- ----- ................ ------------------------------- I --------------------------------- I -------------------------------- 60.0 - ------------------------------- .... ......... ---- ------------- ----------- ------------------------------- -------------------------------- HYD RO & I% LOAD Z55.0 - ------ ---------------- ---- -------- --------------- ----- -------- ----------------------- ------------------------------- % LOAD GROWTH 3: 50.0 - -------------------------------- --------------- --------------- --- ------------------------------- ------------ --------------- 0 0. U. 0 45.0 --------- ------------------- I ------------------------- ---- ----------------------- -------------------------------------- 0 0 uj 40.0 - -------------------- - --------- ------- --------------------- ------------------ ----------- -------------------- ------ --- UJI 35.0 - ------------ ---- ------ ---------------- ------------- ------ ---------------------- ---------- ------------------- w �D�IE§EL & 1% LOAD GROWT 30.0 - ---------- -------------- VDIESELL ------------------------------- I --------------------------------- ------- -------------- >GROWT & 2% LOAD GROWTH 25.0 - --------------------------- --------- HYDRO & 2% LOAD -------------------------------- 20.0- 0% 25% 50% 75% 100% GRANT FUNDING AMOUNT KOOTZNOOWOO INC. MAR 2000 KOOTZNOOWOO ANGOON HYDROELECTRIC PROJECT Figure Alaska, Inc. GRANT FUNDING REQUIREMENTS NTH STAND—ALONE ANGOON UTILITY A- 19 Now -III 70 1111111111111111013 10 O 2000 2010 2020 2830 YEAR KEY ASSUMPTIONS: Annual energy growth rate -196 Grant funding ofProject -10O96. First full year ofoperation - - 2006. Diesel fuel cost -'$1.00/oa|in10g9` General inflation rate -2.596. KOOTZNOOWOO INC. MAR 2000 KOO'rZNOO ANGOON HYDROELECTRIC PROJECT Figure Alaska, Inc. I-. w1low COST OF POWER PROJECT WITH STAND—ALONE ANGOON UTILITY 20 LIST OF APPENDICES A. ANELCA Section 506 (Relevant Paragraphs) B. Monthly Flow Duration Curves C. Power Duration Curves (Selected Arrangement) D. Economic Analysis Spreadsheets APPENDIX A ADMIRALTY ISLAND LAND EXCHANGES Sec. 506. (a)(1) Congress hereby recognizes the necessity to reconcile the national need to preserve the natural and recreational values of the Admiralty Island National Monument with the economic and cultural needs and expectations of Kootznoowoo, Incorporated, and Sealaska, Incorporated, as provided by the Alaska Native Claims Settlement Act and this Act. (3) Subject to valid existing rights, there is hereby granted to Kootznoowoo, Incorporated (B) The right to develop hydroelectric resources on Admiralty Island within township 49 south, range 67 east, and township 50 south, range 67 east, Copper River Base and Meridian, subject to such conditions as the Secretary of Agriculture shall prescribe for the protection of water, fishery, wildlife, recreational, and scenic values of Admiralty Island. (D) Any right or interest in land granted or reserved in paragraphs (3) (A, B, and C) shall not be subject to the provisions of the Wilderness Act. (6) Nothing in this Act shall restrict the authority of the Secretary of Agriculture to exchange lands or interests therein with Kootznoowoo, Incorporated, pursuant to section 22(f) of the Alaska Native Claims Settlement Act, or other land acquisition or exchange authority applicable to the National Forest System. APPENDIX B MONTHLY FLOW DURATION CURVES NOTE: FLOWS SHOWN ARE ESTIMATED NATURAL FLOWS AT THE POWERHOUSE. FLOWS AT THE DIVERSION WILL BE SLIGHTLY LESS. 'u--------------------------- 4- o-----'------~----------r','----'---'--~ ---------------------------- ----------- 1--..f----------. |-----'-'--'i-/---'--'- o o o C) C) 0 _ (SIo)S88O-14 O O r m O rl- cl O Lu co Lu U x w LL! O � L LJ_ O z Ljt U O � d W I. O M O N O O O O O O O O �- O O � O �- (SID) smo-i-A R / / / o a 0 (sp)SmO]] / / 2 / Q 2 � LU x LLJ LU o § o w U. 0 R 2 @ o � # W w a / \ 0 m / / / (Sp)Sm0]] / / / / O 2 a w w Q x w w 2 w b w 2 uj ? UJ UJ a / \ 0 m I 8 0 ti O M O N 9 O O O O O O O O �- O � I 0 M. / \ 9 � o o (Sp)SmO]] ---------------------------------------------- *----.---------------------- /---------------------------- 1� --.-.-_--_-- t-',----.-----,---- / 12 9 N O S LLI x w LLI o � m R b w 2 w o � # a w IL / & 0 0 0 0 0 0 / 0 0 0 (Sp)SMO]] 0 0 r 8 a ti a 11J m o LLI U x w W o L LL O I- z u,J U o � UJ 0- 8 O N O r O O O O O O O �- O O r � r r (SIO) SMOi4 RE E a w CD a w to 0 X w w o L U. O z uJ C� o � w a. 0 ch 0 9 0 0 0 0 0 0 0 - 0 0 <- o •= (SIO) SMO-14 0 ti a LU C.0 o LU LU U x LU ui o LL O z w o c� v W a. O CM e 9 0 0 0 0 0 0 0 0 0 0 - o (SID) SMO14 APPENDIX C POWER DURATION CURVES (SELECTED ARRANGEMENT) 1 NOTE: CURVES SHOW MAXIMUM POTENTIAL GENERATION ASSUMING AN INSTREAM FLOW REQUIREMENT OF 20 CFS. ACTUAL GENERATION WILL BE LIMITED BY THE ANGOON LOADS. A 0 0 0 0 0 N O CO CO �P P P I 0 0 P M. 0 Q I- 0 w uj w 0 x w w o � L LL O z w o U ,It w to 0. 0 m k k / (M)I}Q]1"]N]e N3MOd I / d N @ O w 2 2 LU Q x ui w o E n w LL 0 w 2 w o � # � w CL @ 0 0 0 ? / / / O CD 0 LU LU x LU w o m ¥ b w 2 w o � ® w M / \ 0 0 / / / / / / q o c c It a 0 0 P C) 0) C C C L O � 00 C L a c O F C L Id1 u L W U W W L o C U C U a 0 F Z ui L o V It � uJ F «C) L L L O N c C] P O N O 000 C00 'T CVO 0 CD 0 C\L O 00 co 'IT (M)I) Cl:;J-VN3N3E) N3MOd i 0 CD 0) a 00 a O LU CD a uj LU 0 x ui LU C, U. 0 z ui ui 0- 0 p & y�� ■ : *_ ©:: � «�■ » I 0 @ 2 w S u Q x w w o § r w b R z uj o ,It � u CL $ $ 0 0 0 I 0 0 r 0 rn O 0 0 w co a w w U X w w o w O z w o U w a. 0 O N O r O o O O O N O 00 CO d r r z O w z w CD 0 0 0 0 0 q o / 2 ? Mi)031"]N]O 113MOd / / / / O LU 2 LU / LU S o § e 0 � 2 ui o # � LLI a. R \ 0 WO 2 2 / u 2 2 0 � 2 5 / 3 O O O 0 O r- 0 W W W v x W W o � W O z W o C.) ,Itui W C. O O O O O N O 00 CD 't (M)) 03.1 VN3N3J 293MOd N O 00 CO d P P (M)1) 03-L"3N3J M3MOd 0 O N 0 0 P N Q 0 W C.0 in Lu /LU V x ul LU c us.. U- O z 'W 0 V W 0. M. 0 Ri C� C> 0 0 C) 0 0 0 0 C) C\L :::i OD (D "t (M)I) (33.L"=IN3!D IGMOd 9 0 0 N O C:> .-, ------------------ ------------------- C� 04 -------------------- -- CD 0 CD 0 cli \ <# » *: ©., : y■� / M. 0 / / p.q 0 0 0 2 / O LU S LU Q x w w o £ o R b w 2 w o � # ui IL / \ 0 0 / R 0 0 / / cl� o = o # a {MA}O]1"]N]O Z13MOd APPENDIX D ECONOMIC ANALYSIS SPREADSHEETS THAYER CREEK HYDRO PROJECT ECONOMIC ANALYSIS All costs in $1000 GENERAL ASSUMPTIONS: GENERAL INFLATION RATE 2.5% DISCOUNT RATE 6.0% T-HREA NON -O&M COSTS: OTHER T-HREA COSTS $ 2,800 IN 1998 PERCENT FIXED 25% VALUATION OF T-HREA ANGOON FACILITIES: Net book value of generating assets 662 Net book value of distribution assets 1,046 Net book value of existing assets 1,708 Other capital costs (legal fees, etc.) 300 Total capital cost for acquisition 2,008 Date of acquisition 2005 Finance term for acquistion 20 YEARS Finance rate for acquisition 6.0% Estimated annual general costs 220 IN 1998 LOAD GROWTH: 1998 LOADS BASIC GROWTH LOSS COMMUNITY ENG.. MWH PEAK, KW RATE RATE #1 UNTIL THEN ANGOON 2,000 450 1.0% 2020 1.0% 1 OF. OTHER T-HREA COMMUNITIES 10,200 2,500 1.0% 2020 1.0% 10% DIESEL ALTERNATIVE: DIESEL FUEL COST 1.00 $/GAL IN 1999 FUEL COST ESC. RATE 3.5% UNTIL 2020 THEN 2.5% ANGOON POWER PLANT OTHER T-HREA —UNIT 1 UNIT COMBINED YEAR POWER PLANTS CAPACITY, KW 565 550 1115.0 YEAR INSTALLEq 1990 1998 CUMULATIVE HOURS THRU 1999 60,000 5,000 MAXIMUM CUMULATIVE HOURS 200,000 200,000 FUEL USE RATE, kWh/GAL 13.5 13.2 OVERHAUL COST, $/HR 5.00 1998 5.00 1998 VARIABLE O&M COST, cJkWh 0.5 1998 0.5 1998 NEW CAPACITY COST, $1Kw 550 1998 FINANCE INTEREST RATE 6.0% FINANCE TERM 15 YEARS HYDRO ALTERNATIVE: TOTAL CONSTRUCTION COST: $ 8,100 IN 1999 ESTIMATED ON-LINE DATE 2006 FINANCIAL ASSISTANCE 100% FINANCING COST 2.0% FINANCE INTEREST RATE 6.0% IDC FACTOR 1.25 FINANCE TERM 30 YEARS OUTAGE RATE 5.0% O&M COST $ 85 IN 1999 KOOTZNOOWOO SURCHARGE $ 50 IN 1999 F LOADS: THAYER CREEK HYDROELECTRIC ECONOMIC ANALYSIS CONTINUED t' ,I All Costs in 000 Page i of 6 ANGOON ENERGY LOAD, MWH 2000 2,040 2001 2,061 2002 2,081 2003 2,102 2004 2,123 2005 2,144 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 ANGOON LOSSES, MWH 204 206 208 210 212 214 2,166 217 2,187 219 2,209 2,231 2,254 2,276 2,299 2,322 2,345 2,369 2,392 2,416 2018 2,440 ANGOON GENERATION, MWH 2,244 2,267 2,289 2,312 2,335 2,359 2,382 221 223 225 228 230 232 235 237 239 242 244 2,406 2,430 2,454 2,479 2,504 2,529 2,554 2,580 2,605 2,632 2,658 2,684 OTHER T-HREA ENERGY LOAD 10,405 10,509 10,614 10,720 10,828 10,936 11,045 11,156 OTHER T-HREA LOSSES, MWH 1,041 1,051 1,061 1,072 1,083 1,094 1,105 1,116 11,267 11,380 11,494 11,609 11,725 11,842 11,960 12,080 12,201 12,323 12,446 OTHER T-HREA GENERATION, MWH 11,446 11,560 11,676 11,792 11,910 12,029 12,150 1,127 1.138 1,149 1,161 1,172 1,184 1,196 1,208 1,220 1,232 1,245 12,271 12,394 12,518 12,643 12,769 12,897 13,026 13,156 13,288 13,421 13,555 13,691 TOTAL ENERGY LOAD, MWH 12,445 12,570 12,695 12,822 12,951 13,080 13,211 13,343 13,476 LOSSES 1,690 1,827 1,965 1,105 1,295 1,308 1,321 1,334 1,348 13,611 13,747 13,885 14,024 14,164 14,305 14,449 14,593 14,739 14,886 TOTAL GENERATION, MWH 13,690 13,827 13,965 14,105 14,246 14,388 14,532 1,361 1,375 1,388 1,402 1,416 1,431 1,445 1,459 1,474 i,489 14,677 14,824 14,972 15,122 15,273 15,426 15,580 15,736 15,893 16,052 16,213 16,489 375 ANGOON PEAK LOAD, KW 459 464 468 473 478 482 F ANGOON AVERAGE GENERATION, KW 256 259 261 264 267 269 487 272 492 497 502 507 512 517 522 528 533 538 544 549 ANGOON CAPACITY FACTOR 56% 56% 56% 56% 56% 56% 56% 275 277 280 283 286 289 292 295 297 300 303 306 56% 56% 56% 56% 56% 56% 56% 56% 56°% 56% 56% 56% DIESEL ALTERNATIVE: DIESEL FUEL COST 2000 1.04 2001 1.07 2002 1.11 2003 1.15 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1.19 1.23 1.27 1.32 1.36 1.41 1.46 1.51 1.56 1.62 1.68 2015 2016 2017 2018 UNIT 1 HOURS 5,000 5,000 5,000 5,000 5,000 6,000 5,000 1.73 1.79 1.86 1.92 UNIT 1 CUMULATIVE HOURS 65,000 70,000 75,000 80,000 85,000 90,000 95,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 UNIT 2 HOURS 5,000 5,000 5,000 5,000 5,000 5,000 5,000 100,000 5,000 105,000 110,000 115,000 120,000 125,000 130,000 135,000 35 140,000 145,000 150,000 155,000 UNIT 2 CUMULATIVE HOURS 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 REPLACEMENT CAPACITY ADDITION, KW 0 0 0 0 0 50,000 55,000 60,000 65 ,000 70,000 75,000 85,000 90,000 95,000 0 0 0 0 0 0 0 ,000 0 100,0000 ' ANGOON DIESEL CAPACITY 1,115 1,115 1,115 1,115 1,115 1,115 0 0 0 p ANGOON RESERVE CAPACITY 656 651 647 642 637 633 1,115 628 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 RESERVE CAPACITY ADDITION, KW _ _ 623 618 613 608 603 598 593 587 582 _ 577 571 566 ANGOON FUEL USE, 1000 GAL. 166.2 167.9 169.6 171.3 173.0 174.7 �... ANGOON FUEL COST 172.0 179.9 188.0 196.5 205.4 214.8 176.4 224.5 178.2 180.0 181.8 183.6 185.5 187.3 189.2 191.1 193.0 195.0 196.9 198.8 ANGOON VARIABLE O&M 11.8 12.2• 12.6 13.1 13.5 14.0 14.5 234.7 245.3 256.4 268.1 280.3 293.0 306.2 320.2 334.6 349.9 365.7 382.2 ANGOON OVERHAUL COST 32.1 32.9 33.7 34.6 35.4 36.3 37.2 15.0 15.6 16.1 16.7 17.3 17.9 18.5 19.2 19.8 20.5 21.2 22.2 CAPITAL COST OF NEW CAPACITY 38.2 39.1 40.1 41.1 42.1 43.2 44.3 45.4 46.5 47.7 48.9 50.1 DEPRECIATION OF NEW CAPACITY #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 DEPRECIATI 0.0 0.0 0.0 0.0 0.0 0.0 ON OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 TOTAL ANGOON GENERATION COST 215.9 225.0 OTHER T-HREA FUEL USE, kGAL 867.1 875.8 OTHER T-HREA FUEL COST OTHER T-HREA 897.5 938.1 VARIABLE O&M 60.1 62.2 OTHER T-HREA OVERHAUL COST NOT INCLUDED IN ANALYSIS OTHER T-HREA NEW CAPACITY NOT INCLUDED IN ANALYSIS a L TOTAL OTHER T-HREA GEN. COST 957.6 1000.4 T-HREA NON-FUEL/O&M COSTS 2,906 2,961 TOTAL T-HREA COSTS 4079.8 4186.9 TOTAL T-HREA COSTS, C/KWH 32.8 33.3 DISCOUNTED T-HREA COST, C/KWH 30.9 29.6 AVERAGE COST OF POWER: ACTUAL DISCOUNTED 10-YEAR (OF PROJECT LIFE) 37.3 23.1 30-YEAR (OF PROJECT LIFE) 45.2 �54.7 16.5 50-YEAR (OF PROJECT LIFE) 12.6 z zs4.3 244.2 254.4 265.1 276.2 287.9 300.0 312.6 325.9 339.7 354.0 369.0 384.7 400.9 418.1 435.8 454.3 884.5 980.7 64.4 893.3 1025.1 66.7 902.3 1071.6 69.1 911.3 1120.2 71.5 920.5 1171.1 74.0 929.6 1224A" 76.6 938.9 1279.7 79.3 948.3 1337.7 82.1 957.8 1398.4 85.0 967.3 1461.7 88.0 977.0 1528.1 91.1 986.8 1597.4 94.3 996.7 1669.8 97.7 1006.7 1745.5 101.1 1016.7 1824.7 104.7 1026.9 1907.4 108.3 1037.2 1994.0 112.2 1 U45.2 1091.8 1140.7 1191.7 1245.1 1300.8 1359.0 1419.8 1483.4 1549.7 1619.2 1691.7 1767.4 1846.6 1929.4 2015.8 3,018 3,076 3,135 3,196 3,259 3,323 3,388 3,455 3,524 3,595 3,667 3,741 3,817 3,895 3,975 4,057 4297.5 33.9 28.4 4412.0 34.4 27.3 4530.4 35.0 26.1 4653.1 35.6 25.1 4780.0 36.2 24.1 4911.2 36.8 23.1 5047.2 37.5 22.2 5187.8 38.1 21.3 5333.5 38.8 20.4 5484.3 39.5 1A R 5640.4 40.2 iR o 5802.1 41.0 5969.6 41.7 6142.9 42.5 6322.8 43.3 . 6508.8 44.2 _ 4,141 6701.6 45.0 -. i 1a.D 14.`J f _ LOADS: ANGOON ENERGY LOAD, MWH ANGOON LOSSES, MWH ANGOON GENERATION, MWH OTHER T-HREA ENERGY LOAD OTHER T-HREA LOSSES, MWH OTHER T-HREA GENERATION, MWH TOTAL ENERGY LOAD, MWH LOSSES TOTAL GENERATION, MWH ANGOON PEAK LOAD, KW ANGOON AVERAGE GENERATION, KW ANGOON CAPACITY FACTOR f DIESEL ALTERNATIVE: DIESEL FUEL COST UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL. ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY#1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 TOTAL ANGOON GENERATION COST OTHER T-HREA FUEL USE, kGAL OTHER T-HREA FUEL COST OTHER T-HREA VARIABLE O&M OTHER T-HREA OVERHAUL COST OTHER T-HREA NEW CAPACITY TOTAL OTHER T-HREA GEN. COST T-HREA NOWFUEUO&M COSTS TOTAL T-HREA COSTS TOTAL T-HREA COSTS, C/KWH DISCOUNTED T-HREA COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) { 50-YEAR (OF PROJECT LIFE) 2019 202( 2,465 2,489 246 249 2,711 2,738 12,570 12,696 1,257 1,270 13,827 13,966 15,035 15,186 1,504 1,519 16,539 16,704 555 560 309 313 56% 56% r ►' � 7 ECONOMIC71 ANALYSIS All Costs in /// 2021 2022 2023 2024 2025 2026 2027 2,514 2,539 2,565 2,591 2,616 2,643 2,669 251 254 256 259 262 264 267 2,766 2,793 2,821 2,850 2,878 2,907 2,936 12,823 12,951 13,081 13,212 13,344 13,477 13,612 1,282 1,295 1, 308 1,321 1,334 1,348 1,361 14,105 14,246 14,389 14,533 14,678 14,825 44,973 15,337 15,491 15,646 15,802 15,960 16,120 16,281 1,534 1,549 1,565 1,580 1,596 1,612 1,628 16,871 17,040 17,210 17,382 17,556 17,732 17,909 566 571 577 583 589 595 601 316 319 322 325 329 332 335 56% 56% 56% 56% 56% 56% 56% 2028 2029 2030 2031 2032 2033 z,696 2,723 270 272 2,965 2,995 13,748 13,886 1,375 1,389 15,123 15,274 16,444 16,608 1,644 1,661 18,088 18,269 607 613 338 342 56% 56°! z,750 275 3,025 14,024 1,402 15,427 16,774 1,677 18,452 619 2,777 2,805 2,833 278 281 283 3,055 3,086 3,117 14,165 14,306 14,449 1,416 1,431 1,445 15.581 15,737 15,894 16,942 17,111 17,283 1,694 1,711 1,728 18,636 18,823 19,011 625 631 637 349 352 356 56% 56% 56% 2034 2035 2,862 2,890 286 289 3,148 3,179 14,594 14,740 1,459 1,474 16,053 16,214 17,455 17,630 1,746 1,763 19,201 19,393 644 650 359 363 56% 56% 2036 2,919 292 3,211 14,887 1,489 16,376 17,806 1,781 19,587 657 367 Page 2 of 6 2037 2,948 295 3,243 15,036 17,984 1,798 19,783 663 370 56% 2019 1.99 2020 2.04 2021 2.09 2022 2.14 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2.20 2.25 2.31 2.37 2.42 2.48 2.55 2.61 2.68 2.74 2.81 2.88 2.95 3.03 3.10 5,000 160,000 5,000 165,000 5,000 170,000 5,000 175,000 5,000 180,000 5,000 185,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 190,000 5,000 195,000 5,000 200,000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 105,000 110,000 115,000 120,000 125,000 130,000 135,000 140,000 5,000 145,000 5,000 150,000 5,000 155,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 0 0 0 0 0 0 0 160,000 165,000 170,000 175,000 180,000 185,000 190,000 195,000 0 0 550 0 0 0 0 0 0 0 0 0 1,115 560 1,115 555 1,665 1,099 1,665 1,094 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 - - 550 - 1,088 - 1,082 - 1,076 - 1,070 1,064 - 1,058 - 1',052 1,046 - 1,040 1,034 - 1,028 - 1,021 - 1,015 1,008 1,002- 200.8 399.6 202.8 413.6 204.9 428.3 206.9 443.3 209.0 211.1 213.2 215.3 217.5 219.6 221.9 224.1 226.3 228.6 230.9 233.2 - 235.5 - 237.9 240.2 22.8 23.6 24.4 25.3 459.0 26.1 475.3 27.1 491.9 509.3 527.3 545.8 565.1 585.0 605.6 627.0 - 649.1 672.0 695.6 720.1 745.5 51.3 52.6 53.9 55.3 56.6 58.1 28.0 59.5 29.0 30.0 31.1 32.2 33.3 34.5 35.7 37.0 38.3 39.6 41.0 42.5 61.0 62.5 64.1 65.7 67.3 69.0 70.8 72.5 74.3 76.2 78.1 80.0 0.0 0.0 533.8 0.0 0.0 0.0 0.0 0.0 0.0 634.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 65.3 65.3 65.3 65.3 65.3 65.3 65.3 65.3 65.3 65.3 473.7 489.8 506.7 523.8 541.7 560.4 579.5 599.3 619.8 706.3 728.3 751.0 774.4 798.8 824.0 849.9 876.7 904.6 933.4 1047.5 20B4.3 1058.0 2157.9 1068.6 2233.8 1079.2 1090.1 1101.0 1112.0 1123.1 1134.3 1145.7 1157.1 1168.7 1180.4 1192.2 1204.1 1216.1 1228.3 1240.6 1253.0 116.1 120.2 124.4 2312.6 128.8 2394.2 133.4 2478.6 2565.9 2656.4 ` 2750.0 2847.0 2947.3 3051.2 3158.7 3270.1 3385.3 3504.7 3628.3 3756.2 3888.6 138.1 142.9 148.0 153.2 158.6 164.2 170.0 176.0 182.2 188.6 195.2 202.1 209.3 216.6 4zuu.v zzf8.1 2358.3 2441.4 2527.6 2616.7 2708.9 2804.4 2903.2 3005.6 3111.5 3221.2 3334.7 3452.3 3573.9 3699.9 3830.5 3965.4 4105.3 4,227 4,315 4,406 4,498 4,593 4,691 4,790 4,893 4,997 5,105 5,215 5,328 5,444 5,562 5,684 5,808 5,936 6,067 6,201 i901.2 45.9 14.3 7083.2 46.6 13.7 7270.6 47.4 13.2 7463.6 48.2 12.6 7662.6 49.0 12.1 7867.7 49.8 11.6 8078.7 50.6 11.1 8296.4 51.5 10.7 8520.5 52.3 10.2 8816.8 53.6 9.9 9054.8 54.5 9.5 9300.1 55.4 9.1 9552.7 56.4 8.7 9813.3 57.3 8.4 10081.6 58.3 8.0 10358.2 59.3 7.7 10643.2 60.4 7.4 10937.0 61.4 7.1 11239.7 62.5 6.8 Page 3 of 6 All Costs in 000 LOADS: ANGOON ENERGY LOAD, MWH 2038 2,978 2039 3,008 2040 3,038 2041 3,068 2042 3,099 2043 3,130 2044 3,161 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 ANGOON LOSSES, MWH 298 301 304 307 310 313 316 3,193 319 3,224 3,257 3,289 3,322 3,355 3,389 3,423 3,457 3,492 ANGOON GENERATION, MWH 3,276 3,308 3,341 3,375 3,408 3,443 3,477 3,512 322 3,547 326 3,582 329 332 336 339 342 346 349 3,618 3,654 3,691 3,728 3,765 3,803 3,841 OTHER T-HREA ENERGY LOAD OTHER T-HREA LOSSES, MWH 15,186 1,519 15,338 1,534 15,492 1,549 15,647 1,565 15,803 15,961 16,121 16,282 16,445 16,609 16,775 16,943 17,112 17,284 17,456 17,631 17,807 OTHER T-HREA GENERATION, MWH 16,705 16,872 17,041 17,211 1,580 17,383 1,596 17,557 1,612 17,733 1,628 1,644 1,661 1,678 1,694 1,711 1,728 1,746 1,763 1,781 17,910 18,089 18,270 18,453 18,637 18,824 19,012 19,202 19,394 19,588 TOTAL ENERGY LOAD, MWH LOSSES 18,164 18,346 18,529 18,715 18,902 19,091 19,282 19,474 19,669 19,866 20,065 20,265 20,468 20,672 20,879 21,088 21,299 TOTAL GENERATION, MWH 1,816 19,981 1,835 20,180 1,853 20,382 1,871 20,586 1,890 1,909 1,928 1,947 1,967 1,987 2,006 2,027 2,047 2,067 2,088 2,109 2,130 20,792 21,000 21,210 21,422 21,636 21,852 22,071 22,292 22,515 22,740 22,967 23,197 23,429 ANGOON PEAK LOAD, KW 670 677 683 690 697 704 711 718 726 733 740 747 755 763 ANGOON AVERAGE GENERATION, KW 374 378 381 385 389 393 397 401 405 409 770 778 786 ANGOON CAPACITY FACTOR 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 413 56% 417 421 426 430 434 438 56% 56% 56% 56% 56% 56% DIESEL ALTERNATIVE: F DIESEL FUEL COST UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL. ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 TOTAL ANGOON GENERATION COST OTHER T-HREA FUEL USE, kGAL OTHER T-HREA FUEL COST OTHER T-HREA VARIABLE O&M OTHER T-HREA OVERHAUL COST OTHER T-HREA NEW CAPACITY TOTAL OTHER T-HREA GEN. COST T-HREA NON-FUEL/O&M COSTS TOTAL T-HREA COSTS TOTAL T-HREA COSTS, C/KWH DISCOUNTED T-HREA COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 3.18 3.26 3.34 3.43 3.51 3.60 3.69 3.78 3.88 3.97 4.07 4.17 4.28 4.39 4.49 4.61 4.72 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 55,000 60,000 65,000 70,000 75,000 80,000 85,000 90,000 95,000 100,000 105,000 110,000 115,000 120,000 125,000 130,000 135,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 200,000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 75,000 80,000 0 550 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 995 988 982 975 968 961 954 947 939 932 925 918 910 902 895 887 879 242.7 245.0 247.5 250.0 252.4 255.0 257.6 260.1 262.7 265.3 268.0 270.7 273.4 276.1 278.9 281.7 284.5 771.9 798.9 827.1 856.4 886.4 917.9 950.1 983.7 1018.3 1054.1 1091.3 1129.7 1169.7 1210.9 1253.5 1297.8 1343.5 44.0 45.5 47.1 48.8 50.5 52.3 54.1 56.0 58.0 60.1 62.2 64.4 66.6 69.0 71.4 73.9 76.6 82.1 84.1 86.2 88.4 90.5 92.8 95.1 97.5 100.0 102.5 105.0 107.6 110.3 113.1 115.9 118.8 121.8 0.0 832.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 65.3 65.3 65.3 65.3 65.3 65.3 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 963.3 1079.6 1111.5 1144.6 1178.5 1214.1 1185.1 1223.0 1262.0 1302.3 1344.2 1387.4 1432.4 1478.7 1526.6 1576.3 1627.6 1265.5 1278.2 1291.0 1303.9 1316.9 1330.1 1343.4 1356.8 1370.4 1384.1 1398.0 1411.9 1426.1 1440.3 1454.7 1469.2 1483.9 4025.6 4167.5 4314.5 4466.5 4623.9 4786.9 4955.8 5130.4 5311.2 5498.4 5692.4 5892.8 6100.8 6315.7 6538.3 6768.8 7007.4 224.3 232.2 240.4 248.8 257.6 266.7 276.1 285.8 295.9 306.3 317.1 328.3 339.9 351.9 364.3 377.1 390.4 4Z49.9 4399.7 4554.9 4715.3 4881.5 5053.6 5231.9 5416.2 5607.1 5804.8 6009.5 6221.1 6440.7 6667.6 6902.6 7145.9 7397.E 6,339 6,480 6,624 6,772 6,924 7,080 7,239 7,403 7,570 7,742 7.918 8,098 8,283 8,473 8,667 8,866 9,071 11551.8 11958.9 12290.4 12632.1 12984.0 13347.3 13656.1 14041.7 14439.2 14848.9 15271.6 15706.9 16156.3 16619.2 17096A 17588.6 18096.( 63.6 65.2 66.3 67.5 68.7 69.9 70.8 72.1 - 73.4 74.7 76.1 77.5 78.9 80.4 81.9 83.4 85.0 6.6 6.3 6.1 5.8 5.6 5.4 5.1 4.9 4.7 4.6 4.4 4.2 4.0 3.9 3.7 3.6 3.4 THAYER CREEK HYDROELECTRIC PROJECT Page 4 of 6 ECONOMIC ANALYSIS CASE I CONTINUED SERVICE BY T-HREA All Costs in $1000 HYDRO ALTERNATIVE: F ANGOON DIESEL GENERATION 2000 2244 2001 2267 2002 2289 2003 2312 2004 2335 2005 2359 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 ANGOON HYDRO GENERATION - - - - - 119 2,263 120 122 123 124 125 126 128 129 130 132 133 134 2,286 2,309 2,331 2,355 2,379 2,403 2,426 2,451 2,475 2,500 2,525 2,550 UNIT I HOURS 5,000 5,000 5,000 5,000 5,000 5'000 250 250 250 250 250 UNIT 1 CUMULATIVE HOURS 5,000 10,000 15,000 20,000 25,000 30,000 30,250 30,500 30,750 31,000 31,250 250 250 250 250 250 250 250 250 UNIT 2 HOURS 5,000 5,000 5,000 5,000 5,000 5,000 250 250 250 31,500 31,750 32,000 32,250 32,500 32,750 33,000 33,250 UNIT 2 CUMULATIVE HOURS 5,000 10,000 15,000 20,000 25,000 30,000 30,250 30,500 30,750 250 31,000 250 31,250 250 250 250 250 250 250 250 250 REPLACEMENT CAPACITY ADDITION, KIN 0 0 0 0 0 0 31,500 31,750 32,000 32,250 32,500 32,750 33,000 33,250 0 0 0 ANGOON DIESEL CAPACITY 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 ANGOON RESERVE CAPACITY 1,070 1,098 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 RESERVE CAPACITY ADDITION, KW - - - - 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 ANGOON FUEL USE, 1000 GAL. 166.2 167.9 169.6 171.3 173.0 174.7 8.8 8.9 9.0 9.1 ANGOON FUEL COST 172.0 179.9 188.0 196.5 205.4 214.8 11.2 11.7 12.3 9.2 9.3 9.4 9.6 9.6 9.6 9.7 9.8 9.9 ANGOON VARIABLE O&M 11.8 12.2 12.6 13.1 13.5 14.0 0.7 0.8 12.8 13.4 14.0 14.6 15.3 16.0 16.7 17.5 18.3 19.1 ANGOON OVERHAUL COST 32.1 32.9 33.7 34.6 35.4 36.3 1.9 0.8 1.9 0.8 0.8 0.9 0.9 0.9 1.0 1.0 1.0 1.1 1.1 2.0 2.0 2.1 2.1 2.2 2.2 2.3 2.3 2.4 2.4 2.5 t CAPITAL COST OF NEW CAPACITY 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 DEPRECIATION OF NEW CAPACITY #1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 f DEPRECIATION OF NEW CAPACITY #2 1 DEPRECIATION OF NEW CAPACITY#3 HYDRO DEBT SERVICE 0 HYDRO O&M 0 0 0 0 0 0 PAYMENT SURCHARGE 101 104 106 109 112 114 117 120 123 126 129 133 136 TOTAL ANGOON GENERATION COST - 215.9- 225.0 234.3 244.2 254.4 265.1 59 174.3 61 62 178.9 - 64 66 67 69 71 72 74 76 78 80 183.6 188.4 193.4 198.5 203.8 209.2 214.8 220.5 226.3 232.3 238.-5 -OTHER T-HREA FUEL USE, kGAL 867.1 875.8 884.5 893.3 902.3 911.3 920.5 929.6 938.9 948.3 957.8 967.3 OTHER T-HREA FUEL COST 897.5 938.1 980.7 1025.1 1071.6 1120.2 1171.1 1224.1 1279.7 1337.7 977.0 986.8 996.7 1006.7 10161 1026.9 1037.2 OTHER T-HREA VARIABLE O&M 60.1 62.2 64.4 66.7 69.1 71.5 74.0 1398.4 1461.7 1528.1 1597.4 1669.8 1745.5 1824.7 1907.4 1994.0 OTHER T-HREA OVERHAUL COST NOT INCLUDED IN ANALYSIS 76.6 79.3 82.1 85.0 88.0 91.1 94�3 97.7 101.1 104.7 108.3 112.2 OTHER T-HREA NEW CAPACITY INOT INCLUDED IN ANALYSIS TOTAL OTHER T-HREA GEN. COST 957.6 1000.4 1045.2 1091.8 1140.7 1191.7 1245.1 1300.8 1359.0 1419.8 1483.4 1549.7 1619.2 1691.7 1767.4 1846.6 1929.4 2015.8 2106-.2 T-HREA NON-FUELfO&M COSTS 2,906 2,961 3,018 3,076 3,135 3,196 3,259 3,323 3,388 3,455 3,524 3,595 3,667 3,741 3,817 3,895 3,975 4,057 4,141 TOTAL T-HREA COSTS TOTAL T-HREA COSTS, C1KVvjj 4079.8 32.8 41869 33.3 4297.5 4412.0 4530.4 4653.1 4678.0 4802.2 4930.8 5063.7 5201.1 5343.2 5490.2 5642.3 5799.6 5962.5 6131.0 6305.3 6485.8 DISCOUNTED T-HREA COST, C/KWH 30.9 29.6 33.9 28.4 34.4 27.3 35.0 26.1 35.6 35.4 36.0 36.6 37.2 37.8 38.5 39.1 39.8 40.5 41.3 42.0 42.8 43.6 25.1 23.5 22.6 21.7 20.8 19.9 19.1 18.4 17.6 16.9 16.2 15.6 15.0 14.4 AVERAGE COST OF POWER: ACTUAL DISCOUNTED I 10-YEAR (OF PROJECT LIFE) 36.7 22.8 30-YEAR (OF PROJECT LIFE) 43.8 16.1 50-YEAR (OF PROJECT LIFE) _-52�A 12.21 ECONOMIC All Costs in$ 1000 Page 5 of 6 HYDRO ALTERNATIVE: ANGOON DIESEL GENERATION ANGOON HYDRO GENERATION 2019 136 2,575 2020 137 2,601 2021 138 2,628 2022 140 2,653 2023 141 2,680 2024 143 2,708 2025 144 2,734 2026 145 2,762 2027 147 2,789 2028 148 2,817 2029 150 2,845 2030 151 2,874 2031 153 2,902 2032 154 2,932 2033 156 2,961 2034 157 2,991 2035 159 3,020 2036 161 3,050 2037 162 3,081 UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW 250 33,500 250 33,500 0 250 33,750 250 33,750 0 250 34,000 250 34,000 0 250 34,250 250 34,250 0 250 34,500 250 34,500 0 250 34,750 250 34,750 0 250 35,000 250 35,000 0 250 35,250 250 35,250 0 250 35,500 250 35,500 0 250 35,750 250 35,750 0 250 36,000 250 36,000 0 250 36,250 250 36,250 0 250 36,500 250 36,500 0 250 36,750 250 36,750 0 250 37,000 250 37,000 0 250 37,250 250 37,250 0 250 37,500 250 37,500 0 250 37,750 250 37,750 0 250 38,000 250 38,000 0 ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW 1,115 1,115 - 1,115 1,115 _ 1,115 1,115 - 1,115 1,115 _ 1,115 1,115 _ 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 - 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 - 1,115 1,115 1,115 1,115 1,115 1,115 ANGOON FUEL USE, 1000 GAL, ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST 10.0 20.0 1.1 2.6 10.1 20.7 1.2 2.6 10.2 21.4 1.2 2.7 10.3 22.2 1.3 2.8 10.4 22.9 1.3 2.8 10.6 23.8 1A 2.9 10.7 24.6 1.4 3.0 10.8 25.5 1.5 3.1 10.9 26.4 1.5 3.1 11.0 27.3 1.6 3.2 11.1 28.3 1.6 3.3 11.2 29.3 1.7 3.4 11.3 30.3 1.7 3.5 11.4 31.4 1.8 3.5 11.5 32.5 1.8 3.6 11.7 33.6 1.9 3.7 11.8 34.8 2.0 3.8 11.9 36.0 2.1 3.9 - 12.0 37.3 2.1 4.0 CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 . 00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 HYDRO DEBT SERVICE HYDRO O&M PAYMENT SURCHARGE TOTAL ANGOON GENERATION COST - 0 139 82 244.9 0 143 84 251.2 0 146 86 257.7 0 150 88 264.4 0 154 90 271.3 0 158 93 278.3 0 162 95 285.5 0 166 97 292.9 0 170 100 300.5 0 174 102 308.3 0 178 105 316.3 0 183 108 324.5 0 187 110 333.0 0 192 113 341.6 0 197 116 350.5 0 202 119 359.6 0 207 122 369.0 212 125 378.6 217 128 388.4 OTHER T-HREA FUEL USE, kGAL OTHER T-HREA FUEL COST OTHER T-HREA VARIABLE O&M OTHER T-HREA OVERHAUL COST 1047.5 2084.3 116.1 1058.0 2157.9 120.2 1068.6 2233.8 124.4 1079.2 2312.6 128.8 1090.1 2394.2 133.4 1101.0 2478.6 138.1 1112.0 2565.9 142.9 1123.1 2656.4 148.0 1134.3 2750.0 153.2 1145.7 2847.0 158.6 1157.1 2947.3 164.2 1168.7 3051.2 170.0 1180.4 3158.7 176.0 1192.2 3270.1 182.2 1204.1 3385.3 188.6 1216.1 3504.7 195.2 1228.3 3628.3 202.1 1240.6 3756.2 209.3 1253.0 3888.6 216.6 OTHER T-HREA NEW CAPACITY TOTAL OTHER T-HREA GEN. COST 2200.4 2278.1 2358.3 2441.4 2527.6 2616.7 2708.9 2804.4 2903.2 3005.6 3111.5 3221.2 3334.7 3452.3 3573.9 3699.9 3830.5 3965.4 4105.3 T-HREA NON-FUEUO&M COSTS 4,227 4,315 4,406 4,498 4,593 4,691 4,790 4,893 4,997 5,105 5,215 5,328 5,444 5,562 5,684 5,808 5,936 6,067 6,201 TOTAL T-HREA COSTS TOTAL T-HREA COSTS, CIKWH DISCOUNTED T-HREA COST, CIKWH 6672.4 44.4 13.8 6844.6 45.1 13.3 7021.7 45.8 12.7 7204.2 46.5 12.2 7392.1 47.2 11.7 7585.6 48.0 11.2 7784.8 48.8 107 7990.0 49.6 in a 8201.2 50.4 ca 0 8418.8 51.2 0 e 8642.8 52.0 n , 8873.7 52.9 . 9 9111.3 53.8 9356.1 54.7 9608.2 55.6 , _ 9867.9 56.5 _ . 10135.4 57.5 _ - 10410.9 58.5 10694.8 59.5 AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) HYDRO ALTERNATIVE: ANGOON DIESEL GENERATION ANGOON HYDRO GENERATION UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW t ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW a ANGOON FUEL USE, 1000 GAL. ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 HYDRO DEBT SERVICE HYDRO O&M PAYMENT SURCHARGE TOTAL ANGOON GENERATION COST OTHER T-HREA FUEL USE, kGAL OTHER T-HREA FUEL COST OTHER T-HREA VARIABLE O&M OTHER T-HREA OVERHAUL COST OTHER T-HREA NEW CAPACITY TOTAL OTHER T-HREA GEN. COST T-HREA NON-FUEL/O&M COSTS TOTAL T HREA COSTS TOTAL T-HREA COSTS, C/KWH DISCOUNTED T-HREA COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) ECONOMIC S D SERVICE All Costs in 000 2038 164 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 3,112 165 3,143 167 3,174 169 3,206 170 172 174 176 177 179 181 183 185 186 188 190 192 3,238 3,271 3,303 3,336 3,370 3,403 3,437 3,471 3,506 3,542 3,577 3,613 3,649 250 38,250 250 38,500 250 38,750 250 39,000 250 39,250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 39,500 39,750 40,000 40,250 40,500 40,750 41,000 41,250 41,500 41,750 42,000 42,250 38,250 38,500 38,750 39,000 250 39,250 250 39,500 250 39,750 250 40,000 250 40,250 250 250 250 250 250 250 250 250 0 0 0 0 40,500 40,750 41,000 41,250 41,500 41,750 42,000 42,250 0 0 0 0 0 0 0 0 0 0 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 12.1 38.6 12.3 39.9 12.4 12.5 12.6 12.8 12.9 13.0 13.1 13.3 13.4 13.5 13.7 13.8 13.9 14.1 14.2' 2.2 2.3 41.4 42.8 44.3 45.9 47.5 49.2 50.9 52.7 54.6 56.5 58.5 60.5 62.7 64.9 67.2' 4.1 4.2 2.4 4.3 2.4 2.5 2.6 2.7 2.8 2.9 3.0 3.1 3.2 3.3 3.4 3.6 3.7 3.8' 4.4 4.5 4.6 4.8 4.9 5.0 5.1 5.3 5.4 5.5 5.7 5.8 5.9 6.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 223 131 228 134 234 240 246 252 258 265 271 278 285 292 299 307 315 322 331 138 141 145 148 152 156 160 164 168 172 176 181 185 190 194 398.5 408.9 419.6 430.5 441.7 453.3 465.1 477.2 489.7 502.5 515.6 529.1 542.9 557.2 571.7 586.7 602.1 1265.5 1278.2 1291.0 1303.9 1316.9 1330.1 1343.4 1356.8 1370.4 1384.1 1398.0 1411.9 1426.1 1440.3 1454.7 1469.2 1483.9 4025.6 4167.5 4314.5 4466.5 4623.9 4786.9 4955.8 5130.4 5311.2 5498.4 5692.4 5892.8 6100.8 6315.7 6538.3 6768.8 7007.4 224.3 232.2 240.4 248.8 257.6 266.7 276A 285.8 295.9 306.3 317.1 328.3 339.9 351.9 364.3 377.1 390.4 4249.9 4399.7 4554.9 4715.3 4881.5 5053.6 5231.9 5416.2 5607.1 5804.8 6009.5 6221.1 6440.7 6667.6 6902.6 7145.9 7397.8 6,339 6,480 6,624 6,772 6,924 7,080 7,239 7,403 - 7,570 7,742 7,918 8,098 8,283 8,473 8,667 8,866 9,071 10987.1 60.5 11288.2 11598.5 11918.0 12247.2 12586.5 12936.0 13296.0 13666.9 14049.1 14443.0 14848.6 15266.9 15697.7 16141.6 16599.0 17070.5 61.5 62.6 63.7 64.8 65.9 67.1 68.3 69.5 70.7 72.0 73.3 74.6 75.9 77.3 78.7 80.1 6.2 6.0 5.7 5.5 5.3 5.1 4.9 4.7 4.5 4.3 4.1 4.0 3.8 3.7 3.5 3.4 3.3 Page 6 of 6 Page 1 of 6 LOADS: ANGOON ENERGY LOAD, MWH ANGOON LOSSES, MWH ANGOON GENERATION, MWH OTHER T-HREA ENERGY LOAD OTHER T-HREA LOSSES, MWH �I !. OTHER T-HREA GENERATION, MWH TOTAL ENERGY LOAD, MWH LOSSES TOTAL GENERATION, MWH ANGOON PEAK LOAD, KW ANGOON AVERAGE GENERATION, KW ANGOON CAPACITY FACTOR DIESEL ALTERNATIVE: DIESEL FUEL COST UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL. ANGOON FUEL COST ANGOON VARIABLE O&M "ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 DEPRECIATION OF T-HREA ASSETS UTILITY OPERATING COSTS b._ TOTAL ANGOON GENERATION COST TOTAL ANGOON COSTS, C/KWH DISCOUNTED ANGOON COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) k 50-YEAR (OF PROJECT LIFE) ECONOMIC AN; CASE STAND-ALONE UTILITY All Costs in 000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2,040 204 2,061 2,081 2,102 2,123 2,144 2,166 2,187 2,209 2,231 2,254 2,276 2,299 2,322 2,345 2,369 2,392 2,416 2,440 206 208 210 212 214 217 219 221 223 225 228 230 232 235 237 239 242 244 2,244 2,267 2,289 2,312 2,335 2,359 2,382 2,406 2,430 2,454 2,479 2,504 2,529 2,554 2,580 2,605 2,632 2,658 2,684 10,405 10,509 10,614 10,720 10,828 10,936 11,045 11,156 11,267 11,380 11,494 11,609 11,725 11,842 11,960 12,080 12,201 12,323 12,446 1,041 1,051 1,061 1,072 1,083 1,094 1,105 1,116 1,127 1,138 1,149 1,161 1,172 1,184 1,196 1,208 1,220 1,232 1,245 11,446 11,560 11,676 11,792 11,910 12,029 12,150 12,271 12,394 12,518 12.643 12,769 12,897 13,026 13,156 13,288 13,421 13,555 13,691 12,445 12,570 12,695 12,822 12,951 13,080 13,211 13,343 13,476 13,611 13,747 13,885 14,024 14,164 14,305 14,449 14,593 14,739 14,886 1,245 1,257 1,270 1,282 1,295 1,308 1,321 1,334 1,348 1,361 1,375 1,388 1,402 1,416 1,431 1,445 1,459 1,474 1,489 13,690 13,827 13,965 14,105 14,246 14,388 14,532 14,677 14,824 14,972 15,122 15,273 15,426 15,580 15,736 15,893 16,052 16,213 16,375 459 464 468 473 478 482 487 492 497 502 507 512 517 522 528 533 538 544 549 256 259 261 264 267 269 272 275 ' 277 280 283 286 289 292 295 297 300 303 306 56% 56°% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 1.04 1.07 1.11 1.15 1.19 1.23 1.27 1.32 1.36 1.41 1.46 1.51 1.56 1.62 1.68 1.73 1.79 1.86 1.92 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 65,000 70,000 75,000 80,000 85,000 90,000 95,000 100,000 105,000 110,000 115,000 120,000 125,000 130,000 135,000 140,000 145,000 150,000 155,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 75,000 80,000 85,000 90,000 95,000 100,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 656 651 647 642 637 633 628 623 618 613 608 603 598 593 587 582 577 571 566 166.2 167.9 169.6 171.3 173.0 174.7 176.4 178.2 180.0 181.8 183.6 185.5 187.3 189.2 191.1 193.0 195.0 196.9 198.8 172.0 179.9 188.0 196.5 205.4 214.8 224.5 234.7 245.3 256.4 268.1 280.3 293.0 306.2 320.2 334.6 349.9 365.7 382.2 11.8 12.2 12.6 13.1 13.5 14.0 14.5 15.0 15.6 16A 16.7 17.3 17.9 18.5 19.2 19.8 20.5 21.2 22.0 32.1 32.9 33.7 34.6 35.4 36.3 37.2 38.2 39.1 40.1 41.1 42.1 43.2 44.3 45.4 46.5 47.7 48.9 50.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 17p 262 701.7 32.8 33.3 33.9 34.4 35.0 32.7 30.9 29.6 28.4 27.3 26.1 23.1 TUAL DISCOUNTEC 35.01 21.8 39.61 15.0 47.0 1 11.3 175 175 175 175 175 175 175 175 175 175 175 175 175 268 275 282 289 296 303 311 319 327 335 343 352 360 719.3 737.7 756.7 776.3 796.8 818.0 839.9 862.7 886.4 910.7 936.3 962.6 989.E 33.2 33.7 34.3 34.8 35.4 35.9 36.5 37.2 37.8 38.4 39.1 39.8 40.6 22.1 21.2 20.3 19.4 18.6 17.9 17.1 16.4 15.8 15.1 145 14n 11d Page 2 of 6 .. LOADS: ANGOON ENERGY LOAD, MWH ANGOON LOSSES, MWH ANGOON GENERATION, MWH OTHER T-HREA ENERGY LOAD OTHER T-HREA LOSSES, MWH OTHER T-HREA GENERATION, MWH TOTAL ENERGY LOAD, MWH LOSSES TOTAL GENERATION, MWH ANGOON PEAK LOAD, KW ANGOON AVERAGE GENERATION, KW ANGOON CAPACITY FACTOR DIESEL ALTERNATIVE: DIESEL FUEL COST _ - UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL, ANGOON FUEL COST ANGOON VARIABLE O&M f ANGOON OVERHAUL COST - CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 DEPRECIATION OF T-HREA ASSETS t."tr UTILITY OPERATING COSTS TOTAL ANGOON GENERATION COST TOTAL ANGOON COSTS, C/KWH DISCOUNTED ANGOON COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) ECONOMIC '. A. STAND-ALONE .c All Costs in 000 2019 2,465 2020 2,489 2021 2,514 2022 2,539 2023 2,565 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 246 249 251 254 256 2,591 2,616 2,643 2,669 2,696 2,723 2,750 2,777 2,805 2,833 2,862 2,890 2,919 2,948 2,711 2,738 2,766 2,793 2,821 259 2,850 262 2,878 264 2,907 267 2,936 270 2,965 272 2,995 275 3,025 278 281 283 286 289 292 295 3,055 3,086 3,117 3,148 3,179 3,211 3,243 12,570 1,257 12,696 1,270 12,823 1,282 12,951 13,081 13,212 13,344 13,477 13,612 13,748 13,886 14,024 14,165 14,306 14,449 14,594 14,740 14,887 15,036 1,295 1,308 1,321 1,334 1,348 1,361 1,375 1,389 1,402 1,416 1,431 1,445 1,459 1,474 1,489 1,504 13,827 13,966 14,105 14,246 14,389 14,533 14,678 14,825 14,973 15,123 15,274 15,427 15,581 15,737 15,894 16,053 16,214 _ 16,376 16,540 15,035 1,504 15,186 1,519 15,337 15,491 15,646 15,802 15,960 16,120 16,281 16,444 16,608 16,774 16,942 17,111 17,283 17,455 17,630 17,806 17,984 1,534 1,549 1,565 1,580 1,596 1,612 - 1,628 1,644 1,661 1,677 1,694 1,711 1,728 1,746 1,763 1,781 1,798 16,539 16,704 16,871 17,040 17,210 17,382 17,556 17,732 17,909 18,088 18,269 18,452 18,636 18,823 19,011 19,201 19,393 19,587 19,783 555 560 566 571 577 583 589 595 601 607 613 619 625 631 637 644 650 657 663 309 56% 313 56% 316 56% 319 56% 322 325 329 332 335 338 342 345 349 352 356 359 363 367 370 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 56% 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 1.99 2.04 2.09 2.14 2.20 2.25 2.31 2.37 2.42 2.48 2.55 2.61 2.68 2.74 2.81 2.88 2.95 3.03 3.10 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 160,000 165,000 170,000 175,000 180,000 185,000 190,000 195,000 200,000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 105,000 110,000 115,000 120,000 125,000 130,000 135,000 140,000 145,000 150,000 155,000 160,000 165,000 170,000 175,000 180,000 185,000 190,000 195,000 0 0 0 0 0 0 0 0 0 550 0 0 0 0 0 0 0 0 0 1,115 1,115 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 560 555 1,099 1,094 1,088 1,082 1,076 1,070 1,064 1,058 1,052 1,046 1,040 1,034 1,028 1,021 1,015 1,008 1,002 - - 550 - - - - - - - - - - - - - - 200.8 202.8 204.9 206.9 209.0 211.1 213.2 215.3 217.5 219.6 221.9 224.1 226.3 228.6 230.9 233.2 235.5 237.9 240.2 399.6 413.6 428.3 443.3 459.0 475.3 491.9 509.3 527.3 545.8 565.1- 585.0 605.6 627.0 649.1- 672.0 695.6 720.1 745.5 22.8 23.6 24.4 25.3 26.1 27.1 28.0 29.0 30.0 31.1 32.2 33.3 34.5 35.7 37.0 38.3 39.6 41.0 42.5 51.3 52.6 53.9 55.3 56.6 58.1 59.5 61.0 62.5 64.1 65.7 67.3 69.0 70.8 72.5 74.3 76.2 78.1 80.0 0.0 0.0 533,8 0.0 0.0 0.0 0.0 0.0 0.0 634.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 65.3 65.3 65.3 65.3 65.3 65.3 65.3 65.3 65.3 65.3 175 175 175 175 175 175 370 379 388 398 408 418 429 439 450 461 473 485 497 509 522 535 549 562 576 1018.2 1043.6 1069.9 1096.8 1124.7 1153.6 1008.0 1038.6 1070.0 1167.8 1201.3 1235.8 1271.4 1308.2 1346.1 1385.1 1425.3 1466.8 1509.7 41.3 41.9 42.6 43.2 43.8 44.5 38.5 39.3 40.1 43.3 44.1 44.9 45.8 46.6 47.5 48.4 49.3 50.3 51.2 12.9 12.3 11.8 11.3 10.8 10.4 8.5 8.1 7.8 8.0 7.7 7.4 7.1 6.8 6.6 6.3 6.1 5.8 5.6 LOADS: ANGOON ENERGY LOAD, MWH ANGOON LOSSES, MWH ANGOON GENERATION, MWH OTHER T-HREA ENERGY LOAD OTHER T-HREA LOSSES, MWH OTHER T-HREA GENERATION, MWH TOTAL ENERGY LOAD, MWH LOSSES TOTAL GENERATION, MWH ANGOON PEAK LOAD, KW ANGOON AVERAGE GENERATION, KW JANGOON CAPACITY FACTOR DIESEL ALTERNATIVE: DIESEL FUEL COST UNIT I HOURS UNIT I CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL. ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 DEPRECIATION OF T-HREA ASSETS UTILITY OPERATING COSTS TOTAL ANGOON GENERATION COST TOTAL ANGOON COSTS, C/KWH DISCOUNTED ANGOON COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) THAYER CREEK HYDROELECTRIC PROJECT ECONOMIC ANALYSIS CASE 2 - - STAND-ALONE UTILITY All Costs in $1000 2038 2,978 2039 3,008 2040 3,038 2041 3,068 2042 3,099 2043 3,130 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 298 301 304 307 310 313 3,161 316 3,193 3,224 319 3,257 3,289 3,322 3.355 3,389 3,423 3,457 3,492 3,276 3,308 3,341 3,375 3408 1 3,443 3,471 322 3,512 3,547 326 3,582 329 332 336 - 339 - 342 346 349 3,618 3,654 31691 3,728 3,765 3,803 3,841 15,186 1,519 15,338 1,534 15,492 1,549 15,647 1,565 15,803 1,580 15,961 16,121 16,282 16,445 16,609 16,775 16,943 17,112 17,284 17,456 17,631 17,807 16,705 16,872 17,041 17,211 17,383 1,596 17,557 1,612 17,733 1.628 1,644 17,910 1,661 1,678 1,694 1,711 1,728 1,746 1,763 1,781 18,089 18,270 18,453 18,637 18,824 19,012 19,202 19,394 19,588 18,164 1,816 18,346 1,835 18,529 1,853 18,715 1,871 18,902 11890.. 19,091 19,282 19,474 19,669 19,866 20,065 20,265 20,468 20,672 20,879 21,088 21,299 19,981 20,180 20,382 20,586 20,192 1,909 21,000 1,928 21,210 1,947 1,967 21,422 1,987 2,006 2,027 - 2,047 2,067 2,088 2,109 2,130 21,636 21,852 22,071 22,292 22,515 22,740 22,967 23,197 23,429 670 374 677 378 683 381 690 385 697 389 704 711 718 726 733 740 747 755 763 770 778 786 56% 56% 56% 56% 56% 393 56% 397 56% 401 405 56% 409 413 417 421 426 430 434 438 56% 56% 56% 56% 56% 56% 56% 56% 56% 2038 3.18 2039 3.26 2040 3.34 2041 3.43 2042 3.51 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 3.60 3.69 3.78 3.88 3.97 4.07 4.17 4.28 4.39 4.49 4.61 4.72 5,000 55,000 5,000 60,000 5,000 65,000 5,000 70,000 5,000 75,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 80,000 5,000 85,000 5,000 90,000 95,000 100,000 105,000 110,000 115,000 120,000 125,000 130,000 135,000 200,000 5,000 10,000 15,000 20,000 25,000 30,000 5,000 5,000 35,000 40,000 5,000 45,000 5,000 50,000 5,000 55,000 5,000 5,000 5,000 5,000 5,000 0 550 9 0 0 0 0 60,000 65,000 70,000 75.000 80,000 0 0 1,665 995 1,665 988 1,665 982 1,665 975 1,665 968 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 - - - - 961 954 947 939 932 925 918 910 902 895 887 879 242.7 771.9 245.0 798.9 247.5 827.1 250.0 856.4 252.4 886.4 255.0 257.6 260.1 262.7 265.3 268.0 270.7 273.4 276.1 278.9 281.7 284.5 44.0 45.5 47.1 48.8 50.5 917.9 52.3 950.1 54.1 983.7 1018.3 1054.1 1091.3 1129.7 1169.7 1210.9 1253.5 1297.8 1343.5 82.1 84.1 86.2 88.4 90.5 92.8 95.1 56.0 58.0 97.5 60.1 62.2 64.4 66.6 69.0 71.4 73.9 76.6 100.0 102.5 1050 107.6 110.3 113A 115.9 118.8 121.8 0.0 0.0 832.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0�0 0.0 0.0 0.0 65.3 65.3 65.3 65.3 65.3 65.3 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 85.7 591 554 605 621 636 652 668 685 702 720 738 756 776 794 814 835 856 877 .0 52.2 1685.1 56.0 1732.1 57.0 1780.7 58.0 1830.5 1882.4 1870.2 1925.1 1981.7 2040.0 2100.4 2162.5 2226.8 2293.0 2361.2 2431.8 2504-1 5.4 5.4 5.2 5.0 59.1 4.8 60.1 59.2 60.3 61.5 62.6 63.9 65.1 66.4 67.7 69.0 70.3 71.7 4.6 4.3 4.1 4.0 3.8 3.7 3.5 3A 3.3 3.1 3.0 2.9 Page 3 of 6 HYDRO ALTERNATIVE: 2000 2001 E ANGOON DIESEL GENERATI N 2002 2003 O 2244 2267 2269 zs�z ANGOON HYDRO GENERATION - - - _ UNIT 1 HOURS 5,000 5,000 5,000 5,000 UNIT 1 CUMULATIVE HOURS 5.000 10,000 15,000 20,000 UNIT 2 HOURS 5,000 5,000 5,000 5,000 UNIT 2 CUMULATIVE HOURS 5,000 10,000 15,000 20,000 REPLACEMENT CAPACITY ADDITION, KW 0 0 0 ANGOON DIESEL CAPACITY 1,115 1,115 1,115 1,115 ANGOON RESERVE CAPACITY 1,075 1,100 1,115 1,115 RESERVE CAPACITY ADDITION, KW - - _ ANGOON FUEL USE, 1000 GAL, 166.2 167.9 169.6 171.3 ANGOON FUEL COST 172.0 179.9 188.0 196.5 ANGOON VARIABLE O&M 11.8 12.2 12.6 13.1 r ANGOON OVERHAUL COST 32.1 32.9 33.7 34.6 _t CAPITAL COST OF NEW CAPACITY 0.0 0.0 0.0 DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 DEPRECIATION OF T-HREA ASSETS UTILITY OPERATING COSTS L HYDRO DEBT SERVICE HYDRO O&M ._ PAYMENT SURCHARGE TOTAL ANGOON GENERATION COST TOTAL ANGOON COSTS, C/KWH 32.8 33.3 DISCOUNTED ANGOON COST, CJKWH 30.9 29.6 4 AVERAGE COST OF POWER: ACTUAL DISCOUNTED 10-YEAR (OF PROJECT LIFE) 31.1 19.9 30-YEAR (OF PROJECT LIFE) 30.91 12.7 50-YEAR (OF PROJECT LIFE) 33.1 1 9.2 SIZIL ECONOMIC ANALYSIS All Costs in 000 2004 2005 2006 2007 2008 2335 2359 119 120 122 - - 2,263 2,286 2,309 5,000 5,000 250 250 250 25,000 30,000 30,250 30,500 30,750 5,000 5,000 250 250 250 25,000 30,000 30,250 30,500 30,750 0 0 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 173.0 174.7 8.8 8.9 9.0 205A 214.8 11.2 11.7 12.3 13.5 14.0 0.7 0.8 0.8 35.4 36.3 1.9 1.9 2.0 0.0 0.0 0.0 0.0 0.0 175 262 ful.1 33.9 34.4 35.0 32.7 28.4 27.3 26.1 23.1 2009 2010 2011 123 124 125 2,331 2,355 2,379 250 250 250 31,000 31,250 31,500 250 250 250 31,000 31,250 31,500 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 9.1 9.2 9.3 12.8 13.4 14.0 0.8 0.8 0.9 2.0 2.1 2.1 0.0 0.0 0.0 Page 4 of 6 2012 2013 2014 2015 2016 2017 2018 126 128 129 130 132 133 134 2,403 2,426 2,451 2.475 2,500 2,525 2,550 250 250 250 250 250 250 250 31,750 32,000 32,250 32,500 32,750 33,000 33,250 250 250 250 250 250 250 250 31,750 32,000 32,250 32.500 32,750 33,000 33,250 0 0 0 0 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 9.4 9.5 9.6 9.6 9.7 9.8 9.9 14.6 15.3 16.0 16.7 17.5 18.3 19.1 0.9 0.9 1.0 1.0 1.0 1.1 1.1 2.2 2.2 2.3 2.3 2.4 2.4 2.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 175 175 175 175 175 175 175 175 175 175 175 175 175 268 275 282 289 296 303 311 319 327 335 343 352 360 0 0 0 0 0 0 0 0 0 0 0 0 0 101 104 106 109 112 114 117 120 123 126 129 133 136 59 61 62 64. 66 67 69 71 72 74 76 78 80 317.4 628.7 640.3 652.2 664.4 676.9 689.7 702.9 716.4 730.3 744.5 759.1 774.1 28.5 28.7 29.0 29.2 29.5 29.7 30.0 30.3 30.5 30.8 31.1 31.4- 31.7 19.0 18.0 172 ISIA 11; 1A n AA A -A - _ HYDRO ALTERNATIVE: ANGOON DIESEL GENERATION ANGOON HYDRO GENERATION UNIT 1 HOURS UNIT 1 CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL. a. ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY #1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 r DEPRECIATION OF T-HREA ASSETS UTILITY OPERATING COSTS III ~-~ HYDRO DEBT SERVICE HYDRO O&M PAYMENT SURCHARGE TOTAL ANGOON GENERATION COST TOTAL ANGOON COSTS, C/KWH DISCOUNTED ANGOON COST, C/KWH r AVERAGE COST OF POWER. 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) R '; � � ) _ is � �. • �• � ECONOMIC STAND-ALONE All Costs in �00 2019 2020 2021 2022 2023 2024 2025 2026 2027 136 137 138 140 141 143 144 145 147 2,575 2,601 2,628 2,653 2,680 2,708 2,734 2,762 2,789 250 250 250 250 250 250 250 250 250 33,500 33,750 34,000 34,250 34,500 34,750 35,000 35,250 35,500 250 250 250 250 250 250 250 250 250 33,500 33,750 34,000 34,250 34,500 34,750 35,000 35,250 35,500 0 0 0 0 0 0 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 "" 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 10.0 10.1 10.2 10.3 10.4 10.6 10.7 10.8 10.9 20.0 20.7 21.4 22.2 22.9 23.8 24.6 25.5 26.4 1.1 1.2 1.2 1.3 1.3 1.4 1.4 1.5 1.5 2.6 2.6 2.7 2.8 2.8 2.9 3.0 3.1 3.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 175 175 175 175 175 175 370 379 388 398 408 418 0 0 0 0 0 0 139 143 146 150 154 158 82 84 86 88 90 93 789.5 805.0 821.0 837.4 854.2 871.4 32.0 32.3 32.7 33.0 33.3 33.6 10.0 9.5 9.1 &6 8.2 7.8 2028 2029 2030 148 150 151 2,817 2,845 2,874 250 250 250 35,750 36,000 36,250 250 250 250 35,750 36,000 36,250 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 11.0 11.1 11.2 27.3 28.3 29.3 1.6 1.6 1.7 3.2 3.3 3.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Page 5 of 6 2031 2032 2033 2034 2035 2036 2037 153 154 156 157 159 161 162 2,902 2,932 2,961 2,991 3,020 3,050 3,081 250 250 250 250 250 250 250 36,500 36,750 37,000 37,250 37,500 37,750 38,000 250 250 250 250- 250 250 250 36,500 36,750 37,000 37,250 37,500 37,750 38,000 0 0 0 0 0 0 0 1,115 1,115 1,115 1.115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 11.3 11.4 11.5 11.7 11.8 11.9 12.0 30.3 31.4 32.5 33.6 34.8 36.0 37.3 1.7 1.8 1.8 1.9 2.0 2.1 2.1 3.5 3.5 3.6 3.7 3.8 3.9 4.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 429 439 450 461 473 485 497 509 522 535 549 0 0 0 0 0 0 0 0 0 0 0 162 166 170 174 178 183 187 192 197 202 207 95 97 100 102 105 108 110 113 116 119 122 714.0 732.1 750.7 769.8 789.3 809.4 829.9 851.0 872.6 894.8 917.5 27.3 27.7 28.1 28.6 29.0 29.4 29.9 30.3 30.8 31.3 31.7 6.0 5.7 5.5 5.3 Sn an A AA 562 212 125 940.8 576 217 128 964.7 32.7 3.6 HYDRO ALTERNATIVE: ANGOON DIESEL GENERATION j ANGOON HYDRO GENERATION UNIT 1 HOURS UNIT i CUMULATIVE HOURS UNIT 2 HOURS UNIT 2 CUMULATIVE HOURS REPLACEMENT CAPACITY ADDITION, KW ANGOON DIESEL CAPACITY ANGOON RESERVE CAPACITY RESERVE CAPACITY ADDITION, KW ANGOON FUEL USE, 1000 GAL. r ANGOON FUEL COST ANGOON VARIABLE O&M ANGOON OVERHAUL COST CAPITAL COST OF NEW CAPACITY DEPRECIATION OF NEW CAPACITY#1 DEPRECIATION OF NEW CAPACITY #2 DEPRECIATION OF NEW CAPACITY#3 DEPRECIATION OF T-HREA ASSETS UTILITY OPERATING COSTS HYDRO DEBT SERVICE HYDRO O&M PAYMENT SURCHARGE TOTAL ANGOON GENERATION COST TOTAL ANGOON COSTS, C/KWH DISCOUNTED ANGOON COST, C/KWH AVERAGE COST OF POWER: 10-YEAR (OF PROJECT LIFE) 30-YEAR (OF PROJECT LIFE) 50-YEAR (OF PROJECT LIFE) ECONOMIC i STAND-ALONE All Costs in 000 2038 164 2039 165 2040 167 2041 169 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 3,112 3,143 3,174 3,206 170 3,238 172 3,271 174 3,303 176 3,336 177 3,370 179 3,403 181 3,437 183 185 186 188 190 192 3,471 3,506 3,542 3,577 3,613 3,649 250 38,250 250 38,500 250 38,750 250 39,000 250 39,250 250 39,500 250 39,750 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 40,000 40,250 40,500 40,750 41,000 41,250 41,500 41,750 42,000 42,250 38,250 38,500 38,750 39,000 39,250 39,500 250 39,750 250 40,000 250 40,250 250 40,500 250 40,750 250 41,000 250 41,250 250 41,500 250 41,750 250 42,000 250 42,250 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 - 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 1,115 12.1 38.6 12.3 39.9 12.4 41.4 12.5 12.6 12.8 12.9 13.0 13.1 13.3 13.4 13.5 13.7 13.8 13.9 14.1 14.2 2.2 2.3 2.4 42.8 2.4 44.3 45.9 47.5 49.2 50.9 52.7 54.6 56.5 58.5 60.5 62.7 64.9 67.2 4.1 4.2 4.3 4.4 2.5 4.5 2.6 4.6 2.7 2.8 2.9 3.0 3.1 3.2 3.3 3.4 3.6 3.7 3.8 4.8 4.9 5.0 5.1 5.3 5.4 5.5 5.7 5.8 5.9 6.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 591 605 621- 636 652 668 685 702 720 738 756 775 794 814 835 856 877 223 131 228 134 234 240 246 _ 252 258 265 271 278 285 292 299 307 315 322 331 138 141 145 148 152 156 160 164 168 172 176 181 185 190 194 389.3 33.2 1014.4 33.7 1040.2 1066.6 1093.8 1121.6 1150.1 1179.4 1209.4 1240.2 1271.8 1304.2 1337.4 1371.5 1406.4 1442.2 1479.0 3.4 3.3 34.2 34.8 35.3 35.8 36.4 36.9 37.5 38.1 38.7 39.3 39.9 40.5 41.1 41.7 42.4 3.1 3.0 2.9 2.8 2.6 2.5 2.4 2.3 2.2 2.1 2.0 2.0 1.9 1.8 1.7 Page 6 of 6