Loading...
HomeMy WebLinkAboutThomas Bay Hydro Project Appraisal Report 1975LIBRARY PET L 006 * 018 THOMAS BAY PROJECT APPRAISAL REPORT ( THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA R. W. BECK and ASSOCIATES Engineers and Consultants Seattle, Washington Orlando, Florida Denver, Colorado Columbus, Nebraska Wellesley, Massachusetts Phoenix, Arizona Indianapolis, Indiana NOVEMBER 1975 A ependent mt and in- intended surances ’ THOMAS BAY PROJECT APPRAISAL REPORT THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA R. W. BECK and ASSOCIATES Engineers and Consultants Seattle, Washington Orlando, Florida Denver, Colorado Columbus, Nebraska Wellesley, Massachusetts Phoenix, Arizona Indianapolis, Indiana NOVEMBER 1975 R. W. Beck AND ASSOCIATES ENGINEERS AND CONSULTANTS PLANNING SEATTLE, WASHINGTON DESIGN DENVER, COLORADO IN, RATES 200 TOWER BUILDING PHOENIX, ARIZONA ANALYSES ORLANDO, FLORIDA T Ni IN 981 EVALUATIONS SEATTLE, WASHINGTON 96101 COLUMBUS, NEBRASKA MANAGEMENT TELEPHONE 206-622-5000 WELLESLEY, MASSACHUSETTS INDIANAPOLIS, INDIANA rite No. WW-1523-HG1-MX November 13, 1975 3110 Thomas Bay Power Commission Post Office Box 758 Wrangell, Alaska 99929 Gentlemen: Subject: Thomas Bay Project - Appraisal Report Pursuant to your authorization, we herewith submit the Appraisal Re- port on the Thomas Bay Project, a staged hydroelectric development to meet the projected power requirements of the Petersburg-Wrangell area. Our principal findings, conclusions and recommendations are set forth in the Summary of the report. Significant details of site investiga- tions, power studies, project development and cost of power of the proposed hydroelectric development, are described in subsequent sections of the report. Respectfully submitted, R. W. BECK AND ASSOCIATES, INC. James V. Williamson Assistant Manager Western Design Office CERTIFICATE OF ENGINEER THOMAS BAY POWER COMMISSION APPRAISAL REPORT THOMAS BAY PROJECT The technical material and data contained in this report were pre- pared under the supervision and direction of the undersigned whose seals, as registered professional engineers licensed to practice, are affixed below. Principal Engineer R. W. Beck and Associates, Inc. Dorebol € (Souea Donald E. Bowes Executive Engineer R. W. Beck and Associates, Inc. ee eeesee binox xo ee tg sarceeny James V. Williamson upervising Executive Engineer R. W. Beck and Associates, Inc. OUTLINE OF REPORT Section Page Number Section and Subsection Title Number Letter of Transmittal Certificate of Engineer Outline of Report List of Tables List of Figures Summary I INTRODUCTION 1. Authorization I-1 2: Scope of Services I-1 3. Background to Present Study I-1 4 General Project Description I-2 II SITE CONDITIONS 1. General TII-1 2. Geology II-1 3. Site Investigations rr-2 III HYDROLOGY III-1 1. Precipitation EII-1 ae Runoff Itt-1 3. Project Yield III-2 4. Probable Maximum Flood III-2 IV POWER STUDIES Iv-1 Es General IV-1 2. Historical Load Growth IV-1 3. Power Markets IvV-1 4. Projected Loads IV-2 bs Present and Future Resources IV-3 6. Forced Outage Reserve IV-4 Vv PROJECT DEVELOPMENT V-1 1. General V-1 = Alternative A v-1 3. Alternative B v-2 4. Alternative C ¥=2 5. Selected Arrangement v-2 6. Comparison of Alternatives v-3 OUTLINE OF REPORT (continued) Section Page Number Section and Subsection Title Number VI ESTIMATED CONSTRUCTION COSTS AND CONSTRUCTION SCHEDULE VI-1 1. General VI-1 2. Basis of Costs VI-1 Se Construction Cost Estimate VI-2 VIL COST OF POWER VII-1 I. General VII-1 2. Annual Costs VII-1 36 Comparison of Diesels and Thomas Bay Project VII-2 VIII CONCLUSIONS AND RECOMMENDATIONS VIII-1 1. Conclusions VIII-1 2. Recommendations VITI-1 Ix References XI-1 THOMAS BAY PROJECT APPRAISAL REPORT LIST OF TABLES Table Number Title III-1 Streamflow Data - Cascade Creek VI-1I Phase 1 - Cost Estimate Summary VII-1 Fixed Cost for New Diesel Installations VII-2 Estimated Cost of Fuel for Diesel Generation VII-3 Annual Cost of Power - Diesel Units VII-4 Phase 1 - Annual Cost of Power Figure Number THOMAS BAY PROJECT APPRAISAL REPORT LIST OF FIGURES Title Location Map Swan Lake - Storage-Yield Mass Diagram Historical Energy Load Growth Curves Projected Energy Load Growth Curve Projected Peak Load Growth Curve Alternative A Arrangement - Plan Altermative B Arrangement - Plan Alternative C Arrangement - Plan Selected Arrangement - Plan Selected Arrangement - Profile Comparison of Annual Costs with Diesel SUMMARY To develop plans to meet the projected power requirements of the Petersburg-Wrangell area, the Thomas Bay Power Commission authorized the pre- paration of this Appraisal Report on the Thomas Bay Project, a hydroelectric generating facility to develop the waters of Cascade Creek. This Report presents the results of our studies which include: a description of the project site conditions, analysis of the hydrology of the Cascade Creek drainage basin, forecast of power loads and resources in the Petersburg-Wrangell area, description of the selected project with staged de- velopment and alternative project arrangements that were considered, construc- tion cost estimate of the selected project arrangement, and an economic com- parison with an alternative diesel power development. The Project site, about 16 miles northeast of Petersburg on the south arm of Thomas Bay, is located in a heavily forested, very rugged area within the Tongass National Forest. Access to the upper portion of the proj- ect area for construction will in all probability be by air or cableway due to the inaccessability of the area. Geologically the area is mostly composed of hard granitics which are excellent for the contemplated project development. The average annual runoff available for regulation was determined to be 226 cubic feet per second. The regulated average annual flow available for power production was determined to be 192 cubic feet per second, with al- lowances for losses and stream releases. A probable maximum flood for the Project was determined to have a peak inflow of 25,862 cubic feet and a vol- ume of 30,000 acre-feet. Projected load growth of the Petersburg-Wrangell area based on historical load growth between 1968 and 1974 was established at 7-1/2% which is lower than that estimated by the Alaska Power Administration. Four alternative conceptual arrangements were considered for Project development. The Selected Arrangement alternative is a staged project with initial development of 20,200-kW and ultimate capacity of 39,100-kW. It was chosen since it would initially develop the largest output that could be utilized in the system within a reasonable period, at a lower cost per kW of installed capacity than other alternatives. Phase 1 of the Project would de- liver 19,100-kW, and 68,700,000-kWh annually, to the load centers. The Total Construction Cost for the Phase 1 development, for a current cost level corresponding to a bid date of January 1975, is $46,307,000, and the corresponding Total Construction Cost for the earliest possible in- service date of January 1983 (bid date January 1980), is $70,542,000. The estimated Capital Investment for an in-service date of January 1983, is $75,833,000, corresponding to $3,754/installed kW. The annual cost of power from the Thomas Bay, Phase 1 installation, was compared with the alternative of installing additional diesel generation. Based on the assumed rates of escalation for capital costs and diesel fuel, and 5%, 40-year, terms for Project financing, the comparisons show that the Page 2 annual cost of power from the Project would be more than that from the alterna- tive of additional diesel generation, until about 1989. However, the economic feasibility is significantly affected by the terms of financing and if 40-year term financing with an interest rate in the range of 4% to 4-1/2% can be secur- ed, the Project is more economic than additional diesel generation, and should be. constructed as soon as possible. Efforts should be directed toward obtaining low interest financing for the Project. Studies should be initiated as soon as possible, of alterna- tive smaller hydroelectric projects in the area such as Thoms Lake, Virginia Lake and Kunk Lake. These studies would form the basis for re-evaluation of the Thomas Bay Project, once the terms of available financing are established. SECTION I INTRODUCTION 1. AUTHORIZATION The work described in this report was authorized by the Thomas Bay Power Commission, Wrangell, Alaska, by an Agreement for Engineering Consulting Services dated March 27, 1975 and signed by Richard L. Ballard, Chairman. 2s SCOPE OF SERVICES The Scope of Services involves preparation of an Appraisal Report on the Thomas Bay Project, a proposed staged hydroelectric generating faci- lity that will meet the projected loads and power requirements of the Peters- burg-Wrangell area. The specific engineering services performed included: as Review of available previous studies and reports on the Project. Dis Compilation of existing available engineering and environmental data on the Project. on Analysis of hydrology for determination of Project power output. d. Determination of historical and projected power loads for the cities of Petersburg and Wrangell and the surrounding service areas. e. Preparation of preliminary conceptual layouts of Project features, and a schedule for completion, in sufficient detail to provide a basis for a preliminary cost estimate of the Project considering staged development to meet the projected power loads. £5 Field reconnaissance of the Project site. g. Preparation of an Appraisal Report on the results of our investi- gations and studies. 3. BACKGROUND TO PRESENT STUDY The first known investigation of hydroelectric development of the waters of Cascade Creek was an application for a license to the Federal Power Commission in 1922. The license was issued but later terminated. The Bureau of Reclamation completed an Interim Report on the poten- tial of the Thomas Bay Project, dated June 1965. The hydroelectric project was to meet the urgent power needs at that time of the Petersburg, Wrangell, Kake, Ketchikan and Metlakatla areas. A geology report on the project develop- ment had been earlier completed in January 1962. The City of Petersburg retained R. W. Beck and Associates, Inc. to analyze the electrical power requirements for the City which culminated in a report, Analysis of Electric System Requirements, dated March 1974, which con- sidered the Thomas Bay Project as a potential power resource. In recent years the cost of fuel oil for diesel generation has been escalating rapidly, and this is expected to continue. At the same time, the nation has been caught with shortages of fuel oil which has given rise to con- cern about the reliability of fuel deliveries. As a result of a need for low- er cost energy for the Petersburg-Wrangell area, the Thomas Bay Power Commis- sion authorized R. W. Beck and Associates, Inc. to investigate the hydroelec- tric potential of the Thomas Bay Project to meet these needs. 4. GENERAL PROJECT DESCRIPTION The Thomas Bay Project, a single-purpose hydroelectric development, is located in southeastern Alaska near Cascade Creek on the south arm of Thomas Bay. The runoff from the Cascade Creek watershed with its headwaters near the Canadian border could be combined with the hydraulic head between Swan Lake at El 1515 and Thomas Bay at tidewater, to ultimately develop electrical energy for the future power demand requirements of the communities of Petersburg and Wrangell. Petersburg is located on Mitkof Island across Frederick Sound about 16 air miles southwest of the Project area. Wrangell is located at the north end of Wrangell Island about 40 air miles southeast of the Project area. The Project will be connected to the load centers of Petersburg and Wrangell by ap- proximately 56 miles of a combined overhead and submarine cable transmission line crossing Frederick Sound to Kupreanof Island and across Wrangell Narrows to Mitkof Island, and then crossing the Stikine River delta to Wrangell Island. The Project area and transmission line route are shown in Fig. 2. SECTION II SITE CONDITIONS 1. GENERAL The Project drainage basin is approximately 23 square miles. It lies within the North Tongass National Forest which is extremely mountainous and is marked by comb ridges and narrow gorges. The mountains rise abruptly to 3,000 feet or more from sea level with peaks obtaining heights of 5,000 feet or more. The drainage area is heavily forested with western hemlock, Sitka spruce, and muskeg cover from tidewater to approximately El 1500. A- bove El 1500, the vegetation thins to brush-covered slopes and subsequently to barren rock at higher elevations. Cascade Creek, the only major tributary of the watershed, flows westward through Swan Lake at about El 1515 and Falls Lake at El 1160 des- cending the 1,500 feet to sea level within two miles below Swan Lake. The creek falls 350 feet in one half mile, with 80 foot high falls at the head of Falls Lake. The narrow stream gorge with right-angle turns caused by joint systems in the bedrock, and the steep stream gradient make the stream channel and other access routes from tidewater to Swan Lake extremely diffi- cult. Small streams entering Swan Lake are building small fans and deltas with Cascade Creek forming a large outwash delta at the head of the lake. South of the mouth of Cascade Creek near tidewater is a natural bench of al- luvial material that could serve as an initial construction staging area and construction camp location. 2. “Geondey The following section on geology is based on U.S. Geological Survey bulletins, USBR publication on the Thomas Bay Project dated January 1962, drill hole logs by the USBR on exploration holes at the Swan Lake outlet and at tidewater north of the mouth of Cascade Creek, and as a re- sult of a reconnaissance made by helicopter of the Project site. The Project area is located in the Wrangell-Revillagigedo belt of metamorphic rocks, and the "granites" of the Coast Range batholith under- lying the mainland and nearby islands. The metamorphics consist of inter- bedded cherts, slates, phyllites, limestone (marble), greenstone and schist grading easterly into gneisses in the broad contact zone bordering the batho- lith. The granitic rocks, intruded in late Mesozoic time, are of quartz dio- rite composition in the western part of the batholith while its core is of granodiorite. The quartz diorite has a distinct gneissoid (banded) structure. The banding in the quartz diorite, the gneissic foliation and schistosity, all have a general trend and dip parallel to attitudes of the formations and the belt of metamorphics. They form the "grain of the country" with a northwest- erly trend and steep northeasterly dip. II-2 The Project is located in an area of hard crystalline rock, mainly quartz diorite with some gneiss. The surrounding high mountains have been deep- ly scored by glaciation as has Swan Lake and its outlet gorge. The outlet channel with quartz diorite abutments has been filled with talus to a possible depth in excess of 100 feet. The quartz diorite, gneiss, schist and marble should provide excellent conditions for tunneling. 3. SITE INVESTIGATIONS A field reconnaissance of the proposed Project area and transmission route was conducted by helicopter during September 1975. An earlier air recon- naissance by float plane was also made during August 1975. The reconnaissance of Cascade Creek from tidewater to Swan Lake at El 1515 revealed that accessibility to the upper project area will constitute a major construction problem. Construction access to either Falls Lake or Swan Lake would in all probability be restricted to helicopter, float plane or cable- way. The outlet of Swan Lake, a narrow steeply sided granite gorge has been filled to an estimated depth of over 100 feet with boulders, cobbles and glacial sands and gravels. Although it is possible to build a dam at the site, cofferdams, dewatering and foundation excavation costs would be very high. In addition, spillway construction for an embankment dam would be difficult in the steeply sided gorge which would require consideration of a tunnel spillway. In all probability the most economical dam at the site would be an arch dam that would incorporate the spillway over the dam. However, a lake tap utilizing the available storage in the natural lake is considered feasible and could be more economical if the additional head developed by the dam is not a consideration. The deeply incised outlet of Falls Lake has been choked with bould- ers, cobbles and glacial sands and gravels. A semi-pervious to pervious condi- tion in all probability exists and would require partial sealing, and possibly blanketing, if Falls Lake is to be used for regulation as an afterbay or fore- bay arrangement especially if a dam is to be constructed which would raise the hydraulic head. The lake would have to be dewatered and Cascade Creek divert- ed to allow sealing and blanketing as well as for the dam construction. Difficult access and steeply sided slopes at the proposed power- house site next to the falls at the head of Falls Lake would involve high construction costs for both plant site development and general construction. The best site within Falls Lake for a power tunnel intake portal would be at the upper end of the narrows along the left bank. The narrows could be uti- lized for a cofferdam site and the flow diverted through the excavated power tunnel during construction of the Falls Lake dam and overflow spillway. The best powerhouse location for the initial phase of a two-stage development in regard to ease of construction access and permanent access is in the depression south of Falls Lake. This would also allow for the second stage development to proceed without interruption of the power from the ini- tial development during construction. II-3 An existing alluvial bench at tidewater just south of the mouth of Cascade Creek would provide an excellent area for staging and construction camp location. Access to tidewater and to an initial stage powerhouse would be relatively easy from this point. The transmission line from the plant would cross the Patterson and Muddy River alluvial deltas to the shore of Frederick Sound. The allu- vial delta area just 4 to 5 miles from the project area, is a potential borrow area for sands, gravels and fines for use as filter materials and concrete ag- gregates. The delta at the head of Swan Lake potentially could be a similar source of materials, but costs of development and transportation in all proba- bility would be higher from this source. The proposed overhead and submarine cable transmission line route was flown during the reconnaissances. The route adopted is based on the eco- nomics of construction with due regard to ease of access for maintenance. SECTION III HYDROLOGY 1. PRECIPITATION The climate of the Petersburg-Wrangell area, at sea level, is characterized by heavy precipitation, relatively mild temperatures, and much cloudiness. Precipitation results when warm, moist winds off the Pacific Ocean rise over the mountain barriers of the islands and the mainland. This produces a warming effect on the area, and keeps the air temperature much higher than would be expected at such a northerly latitude. Orographic effects of the area greatly influence precipitation, cloudiness, fog and temperature, which result in extreme variations within a few miles distance. Therefore, precipitation in the mountains is much heavier than at sea level and temperatures are considerably lower. The greater part of the annual precipitation falls during the months of September through December, mostly as snowfall especially in the Project drainage area. The historical average monthly and mean annual pre- cipitation recorded at Petersburg, Alaska over 24 years, is tabulated below: Petersburg Precipitation Month (inches) November 10.6 December 10.6 January 9.4 February 7.6 March 7.0 April 7.0 May 6.2 June 4.8 July 5.2 August 7.6 September 11.6 October LEL3 Mean Annual 105.8 The mean annual precipitation on the Cascade Creek drainage basin, based on the historical runoff records from the stream gaging station, is esti- mated to be in excess of 150 inches. 2. RUNOFF The U. S. Geological Survey has maintained a stream gaging station near the mouth of Cascade Creek for 38 years from 1918 to 1928, and from 1947 to 1973. The drainage area upstream of the gage location is 23 square miles. The monthly and annual discharges in acre-feet during this period are listed on Table III-1. PREZ Project runoff regulation will be accomplished at Swan Lake, which has a drainage area of 18.9 square miles. Taking into account the 82% ratio of the drainage area above Swan Lake to that of the gaging station location and the orographic effects of the two areas, the runoff at Swan Lake is estimated to be 89.9% of that recorded at the gaging station. The average annual runoff at Swan Lake was found to be 164,000 acre-feet or 226 cubic feet per second. The highest recorded peak flow at the Cascade Creek gage is 3,280 cubic feet per second. Flood frequency analysis using the Gumbel Method and the Pearson Log Type III Method showed that the flood of record has a return frequency of one in 153 years and one in 93 years, respectively. 3. PROJECT YIELD Swan Lake will be utilized as a storage reservoir to regulate and develop a firm runoff yield for all alternatives investigated for the Thomas Bay Project. The Project firm yield of Swan Lake was determined based on average monthly flows determined from historical recorded flows at the gaging station modified to the Swan Lake drainage area as explained previously. The firm yield for a 3-year critical period was found to be 204 cfs with a requir- ed usable storage of approximately 80,000 acre-feet. The firm yield for a 10- year critical period was found to be 210 cfs with a required usable storage of approximately 92,000 acre-feet. The storage-yield mass diagram for Swan Lake is shown in Fig. 2. For power study purposes, the calculated average annual runoff at Swan Lake was reduced by a 15% allowance to account for minimum stream flow releases and other losses. Therefore, the average annual power release will be 192 cfs (139,000 acre-feet per year) which is 94% of the firm annual yield for a 3-year critical period utilizing 80,000 feet of Swan Lake storage. The area-capacity of Swan Lake, from an assumed normal water maxi- mum surface at El 1515 to El 1300, was determined from underwater soundings performed by the U.S. Geological Survey. The total volume of the lake be- tween these elevations is 97,500 acre-feet. The area of the lake at El 1515 is 572 acres. The area at El 1300 is 365 acres. 4. PROBABLE MAXIMUM FLOOD A Probable Maximum Flood (PMF) hydrograph was developed for the Swan Lake drainage area for use in flood routing through potential reservoirs of the Project for several alternative layouts. In developing a basin unit hydrograph for these studies, Clarks Method for unit hydrograph determination was used. The Probable Maximum Precipitation (PMP) used for these studies was obtained from the Weather Bureau Technical Paper No. 47 for this area which was adjusted upwards by 50% to reflect basin orographic effects. In addition, a snowmelt contribution of 5.41 inches was added to the PMP. Tit-3 The peak inflow of the developed PMF was found to be 25,862 cubic feet per second and the volume of the PMF is 30,000 acre-feet. CASCADE CREEK NEAR PETERSBURG Gage Number 15026000 MONTHLY AND ANNUAL DISCHARGE IN ACRE-FEET Drainage Area - 23 Mi. Year October November December January February March April May June July August September Annual 1918 35,200 39,100 4,540 4,050 1,520 1,250 3,000 12,000 28,700 32,700 40,300 23,800 227,000 1919 23,100 11,000 5,580 9,900 1,500 1,680 4,440 9,530 19,200 29,300 35,100 29,000 179,000 1920 20,500 6,070 4,460 4,790 3,450 2,010 2,030 6,110 26,200 33,800 41,600 19,800 171,000 1921 9,720 7,620 2,140 2,040 2,290 2,480 2,050 12,300 30,300 26,600 22,700 24,000 144,000 1922 34,800 7,380 9,040 3,070 "1,390 1,230 3,870 11,100 18,400 29,100 30,900 23,500 174,000 1923 15,500 15,100 3,950 1,700 2,280 3,370 5,360 15,200 30,400 27,700 31,200 33,000 185,000 1924 23,7 14,200 4,800 2,249 1,440 2,750 3,870 18,000 35,300 32,500 31,800 40,700 211,000 1925 22,00 12,100 5,240 1,140 1,110 1,530 1,980 20,500 29,000 38,300 27,700 18,700 179,000 1926 12,900 10,900 21,300 24,900 4,120 8,550 16,200 17,700 24,400 25,300 20,0u0 13,700 200,000 1927 23,900 9,640 8,300 3,320 1,110 : 1,920 1,930 10,100 32,800 29,600 25,800 31,500 180,000 1928 18.400 5,030 1,990 8,670 2,800 4,060 4,270 22,400 34,000 36,200 27,200 25,200 190,000 1947 11,590 13,530 2,340 2,640 2,280 11,480 9,730 20,100 30,330 23,930 22,670 31,340 182,000 1948 11,570 9,520 4,440 5,280 2,319 1,640 1,510 21,440 29,530 24,810 21,970 28,800 162,800 1949 13,340 8,690 2,960 2,790 1,380 2,140 3,610 17,850 26,500 30,450 28,300 27,100 165,100 1950 23,130 22,169 3,780 1,540 1,110 1,400 1,590 10,090 30,850 30,970 23,860 25,480 176,000 1951 8,590 5,090 3,000 2,570 1,420 1,790 2,670 17,870 34,720 29,930 20,420 16,960 145,000 1952 15,020 6,660 4,110 2,040 1,870 1,850 2,780 15,860 26,050 37,840 28,610 31,040 173,700 1953 29,070 9,140 3,880 2,030 1,680 1,830 2,550 21,520 27,260 23,910 25,330 22,920 171,100 1954 24,190 7,890 4,740 3,120 11,030 2,110 1,780 12,060 27,110 24,010 17,310 19,690 155,000 1955 15,870 13,260 9,190 4,120 2,530 2,220 2,960 8,360 25,230 34,090 33,740 26,090 177,600 1956 13,210 8,170 2,460 1,400 1,160 958 2,090 22,120 25,180 33,310 40,680 17,910 168,600 1957 14,320 12,220 11,920 4,250 2,310 2,090 3,070 18,570 29,200 27,310 21,680 28,640 175,600 1958 16,610 15,060 5,360 6,240 2,190 2,660 5,340 18,520 28,870 25,860 26,710 12,380 165,800 1959 28,670 8,420 6,470 2,960 3,130 2,560 3,570 16,320 30,650 40,580 29,260 16,220 188 ,900 1960 25,030 8,710 12,320 4,250 2,930 3,110 7,650 19,120 26,060 34,710 30,940 25,160 200,000 1961 37,700 11,650 10,810 4,920 4,850 2,170 6,610 18,400 34,380 32,950 39,340 23,970 227,800 1962 34,550 9,680 3,390 8,550 6,960 2,590 3,460 12,470 31,290 37,870 29,480 30,570 210,900 1963 17,740 14,500 17,890 10,950 10,830 4,750 3,710 16,040 23,820 27,330 21,580 37,650 206 ,800 1964 20,490 5,110 7,400 5,340 3,720 2,530 3,480 8,850 35,250 37,830 28,470 15,390 173,860 1965 21,010 9,119 6,350 9,480 3,260 3,840 4,170 9,730 25,150 25,030 20,110 15,190 152,400 1966 29,150 54740 3,940 3,350 2,350 3,220 5,260 13,950 29,860 29,820 29,230 27,500 183,400 1967 20,270 9,950 4,040 3,400 1,840 1,960 2,840 18,410 42,940 29,320 31,190 35,650 201,800 1968 17,890 12,780 4,690 5,910 5,520 8,490 4,280 17,840 21,870 31,870 19,670 36,360 187,200 1969 14,440 8,910 3,790 1,250 901 1,170 ° 2,330 17,650 35,060 31,230 27,660 18,850 163,200 1970 13,440 23,390 14,400 4,410 4,580 3,470 3,050 14,090 32,960 28,490 29,040 31,3830 203,100 1971 20,050 10,510 2,770 3,270 1,910 1,900 2,540 13,330 31,430 30,890 33,250 20,340 172,200 1972 14,740 6,380 3,430 2,330 3,440 5,840 2,350 15,370 30,030 40,030 38,480 28,040 190,500 1973 26,640 9,080 3,340 3,020 2,910 2,560 4,200 14,600 29,030 34,620 37,620 42,550 210,200 Mean 20,500 11,140 6,172 4,664 2,986 2,986 3,899 15,410 29,190 31,060 28,710 25,700 182,400 T-III eTqeL SECTION IV POWER STUDIES 1. GENERAL The Thomas Bay Project, with a possible ultimate development in the range of 40,000 to 50,000 kW of installed capacity, would supply residen- tial, commercial and industrial power to the Petersburg-Wrangell area. The Petersburg power needs are currently served by the City of Petersburg Muni- cipal Power and Light Department while the Wrangell power needs are served by the City of Wrangell. The purpose of the Thomas Bay Project would be to provide lower cost generation of electrical energy than diesel. It would serve the Peters- burg-Wrangell area as the projected load growth of the area develops and an- ticipated higher costs for diesel fuel are realized. 2. HISTORICAL LOAD GROWTH Historical records of energy generation for Petersburg and Wrangell are not available on which to establish long-term patterns for predicting future growth trends. Records of energy and peak loads from 1968 to 1974 for both Petersburg and Wrangell and the historical energy load growth curves during this seven-year period for both Petersburg and Wrangell are shown in Fig. 3. This recent historical energy load growth for both communities is approximately 7-1/2%. The total energy generation and system peaks during 1974 for the communities are: Petersburg - 18,735,270 kWh -- 3,500 kW Wrangell - 10,304,800 kWh -- 2,250 kW The energy generation of Wrangell is only approximately 55% of Petersburg mainly because the lumber industry in Wrangell generates its own needs. 3. POWER MARKETS A survey of existing power markets in the load areas was conducted during August 1975 for analyses of future potential load growth. The power markets included residential, commercial establishments, fisheries, canneries, cold-storages and lumber mills. The results of the survey of the main users of energy in Petersburg and Wrangell is as follows: a. Petersburg (1) Petersburg Processers (Cannery) - Possible expansion if fish runs of the 1960's return, otherwise no expansion contemplated. €2) Whitney-Fidalgo (Cannery and Cold-Storage) - No expansion for- seen unless possible expansion for cold-storage. Iv-2 (3) Alaska Glacier Seafoods (Cannery) - Possible expansion within the next 5 years due to addition of refrigeration. (4) Petersburg Fisheries Inc. (Cannery and Cold-Storage) - Growth trend now at 10% per year. If bottom fishing returns in the near future, pos- sible 20% expansion in the next 2 to 10 years. (5) Mitkof Lumber Company (Mill) - Possible expansion of 500 horse- power in the next 3 years and to 1,200 horsepower in 5 to 10 years. Presently on mill diesel of 1,000 horsepower. b. Wrangell (1) Stikine Inn (Hotel) - Possible expansion in the next 2 years. Expect to double capacity. (2) Alaska Wood Products, Inc. (2 Mills) - Presently 70% of the City of Wrangell's employment is related to the mills. The mills have increased loads approximately 10% per year and have self-supplied steam power with average loads of 1,200 kW and 1,600 kW. Possible future expansion within the next 2 years of 1,000 kW to 1,200 kW. At the end of this year, the mills plan purchase of 200 kW of capacity from the City of Wrangell. (3) Harbor Seafoods Company, Inc. (Cannery) - Expansion planned within the next 3 years within cold-storage and canning. Present consumption approximately 500,000 kWh of energy annually. 4. PROJECTED LOADS The 1974 Alaska Power Survey by the Alaska Power Administration (APA), states that the likely mid-range growth rate for southeast Alaska would be as follows: Years Rate 1972-1980 13.1% 1980-1990 7.8% 1990-2000 6.7% The historical load growth for Petersburg and Wrangell from 1968 to 1974 is approximately 7-1/2% as shown in Fig. 3. These projections do not reflect possible large block load increases that might result from conversion to municipal power by the wood products mills in Wrangell or development of other new industry in the area. The projected rates by APA are higher than this value, and if the power markets develop as discussed above, the actual future growth could be higher. On the other hand growth rates are down this year as a result of a slowdown in the area. It is therefore considered reason- able for projecting loads to determine a schedule of future generation to con- tinue to use the historic growth of 7-1/2%. The projected energy load growth curve on this basis is shown in Fig. 4 and the projected peak load in Fig. 5. IV-3 5. PRESENT AND FUTURE RESOURCES a. Petersburg The present power supply system for Petersburg consists of the following: Nameplate Rating Type (Kilowatts) Diesel 1 2,100 Diesel 2 350 Diesel 3 1,250 Blind Slough Hydro Unit 2 500 Blind Slough Hydro Unit 3 1,900 TOTAL cee ceeeceeeeceseceeesees 6,100 Kilowatts Future power resources include: (1) Expansion of the Blind Slough Project as described in the report, Analysis of Electric System Requirements, for the City of Petersburg, dated March 1974, by R. W. Beck and Associates, Inc. This is in the planning and design stage by the City. (2) Installation of new diesel units. (3) Participation in development of regional hydroelectric pro- jects such as Thomas Bay, Goat Creek, and Virginia Lake. b. Wrangell The present power supply system for Wrangell is all diesel gen- eration and consists of the following: Nameplate Rating Type (Kilowatts) Diesel 1 1,250 Diesel 2 1,250 Diesel 3 1,250 Diesel 4 1,250 Diesel 5 500 Diesel 6 500 Diesel 7 500 Diesel 8 1,250 TOTAL 056-0 veelsie eos wee weiss ects . 7,750 Kilowatts Iv-4 Future power resources include: (1) Installation of new diesel units. (2) Development of local hydroelectric projects such as Virginia Lake, Thoms Lake or Kunk Lake. (3) Participation in development of regional hydroelectric pro- jects such as Thomas Bay, Goat Creek, and Virginia Lake. c. Petersburg-Wrangell Potentially the best long-range power resource for the combined Petersburg-Wrangell area is the Thomas Bay Project. Phase 1 of the Thomas Bay Project has been assumed to come on-line as soon as possible, which is con- sidered to be January 1983. Up to this time the loads will be met by operat— ing the existing hydro (including the Blind Slough Expansion), and increased operation of existing diesels at both communities. This will provide the needs of the system, without shortage, except that some reduction in reserve would result during 1982. (See Fig. 5) As can be seen from Figs. 4 and 5, Thomas Bay will have capacity and energy well in excess of the needs of the system at that time. In the determination of the annual costs for the Project, these costs have been in- creased to reflect that there is no market for all of the energy until the load grows sufficiently (in about 7 years) so that all of the Phase 1 Project output is absorbed. 6. FORCED OUTAGE RESERVE The Petersburg-Wrangell system reliability necessitates an adequate capacity for reserve purposes. The scheduling of generation resources is based on providing a forced outage reserve over and above the estimated peak load, equal to the largest individual generating unit in the system. Therefore, the system can operate to meet the peak load even with forced outage of the largest unit. When diesel unit generation is being replaced by hydroelectric wits, the older diesel units would be retired and the newest diesel units would be used to furnish all or part of the system reserve capacity. SECTION V PROJECT DEVELOPMENT 1. GENERAL Studies of the development of the Thomas Bay Project involved com parison of several alternatives. Four alternative arrangements were formulated considering staged development and total development of the hydroelectric poten- tial of Cascade Creek. Preliminary civil and hydraulic designs were made involv- ing layouts and construction feasibilities. The 69 kV single circuit transmission facilities from the Project to the load centers at Petersburg and Wrangell are common for all alternatives and are as follows: a. Overhead transmission from the Project to Frederick Sound. b. Submarine cable across Frederick Sound to Kupreanof Island. c. Overhead transmission along Kupreanof Island to Wrangell Narrows. d. Submarine cable across Wrangell Narrows. e. Overhead transmission to substation at Petersburg. £ Overhead transmission along Mitkof Highway to south end of Mitkof Island. ge Submarine cable across the Stikine River delta to Wrangell. h. Overhead transmission to substation at Wrangell. The transmission line route is shown in Fig. 1. The four alternative project layouts considered during project formulation are described in the following subsections. Alternatives A, B and C were compared to the alternative which is now termed the Selected Arrangement. 2. ALTERNATIVE A This arrangement is composed of a two-staged development and is shown in Fig. 6. The initial stage, Phase 1, includes a 125 foot high concrete arch dam at the outlet of Swan Lake to raise the reservoir to El 1620, a 7-foot diameter power tunnel, and an underground powerhouse at the head of Falls Lake. The Phase 1 development, with Swan Lake inflow regula- tion producing 192 cfs average annual discharge and with a net head of 380 feet, would produce approximately 47,000,000 kWh of annual energy. With a plant factor of 40%, 13,400 kW could be installed. v-2 The second stage, Phase 2, includes a 30 foot high concrete faced control dam at the Falls Lake outlet, 7-foot diameter power tunnel, 6-foot dia- meter penstock and a powerhouse at tidewater. The total development with an average annual discharge of 192 cfs and a net head of 1,140 feet, would produce approximately 141,000,000 kWh of annual energy. With a plant factor of 40Z, 40,200 kW could be installed. 3. ALTERNATIVE B This arrangement is composed of a two-staged development and is shown in Fig. 7. The initial stage, Phase 1 includes a lake tap intake at Swan Lake with 7-foot diameter power tunnel and underground powerhouse at the head of Falls Lake. The Phase 1 development, with 192 cfs average annual discharge and a net head of 215 feet, would produce approximately 27,000,000 kWh of annual energy. With a plant factor of 40%, 7,600 kW of capacity could be installed. The second stage, Phase 2, would be the same as the second stage development of Alternative A. 141,000,000 kWh of annual energy would be pro- duced with 40,200 kW of installed capacity operating at a 40% plant factor. 4. ALTERNATIVE C This arrangement is composed of a single stage development from Swan Lake to tidewater and is similar to that Proposed by the USBR. A lake tap intake at Swan Lake would connect to a 7-foot diameter power tunnel, surge tank and a powerhouse at tidewater. Alternative C arrangement is shown in Fig. 8. The power development with 192 cfs average annual discharge and a net head of 1,375 feet would produce approximately 170,000,000 kWh of an- nual energy. With a 40% plant factor, 48,500 kW could be installed. 5. SELECTED ARRANGEMENT The selected alternative arrangement for development of the Thomas Bay Project is a two-staged development. It is shown in plan in Fig. 9 and in profile in Fig. 10. Swan Lake is used for regulation only and would have an outlet tunnel discharging into Cascade Creek. The initial Phase 1 development would consist of a lake tap at Swan Lake and an outlet tunnel with a valve house at the downstream end to regulate releases for power. Falls Lake will require a low dam consisting essentially of a spillway weir at its outlet, to control reservoir leakage and to maintain head on the plant. A gated power intake at Falls Lake for the 7-foot diameter concrete-lined power conduit would convey power releases to the Falls Lake Powerhouse located at the head of the depressed area south- west of Falls Lake. With an average annual discharge of 192 cfs and a gross head of 590 feet, 70,800,000 kWh of annual energy would be produced which re- sults in 68,700,000 kWh delivered to the load centers. Utilizing a 40% plant factor, 20,200 kW of capacity could be installed which would deliver 19,200 kW to the load center. Four units would be installed to minimize required forced outage reserves. The second stage, Phase 2, would involve construction of the Thomas Bay Forebay downstream of the Falls Lake Powerhouse, and an intake structure for a 7-foot diameter power conduit consisting of steel penstock and concrete-lined tunnel which would connect to the Thomas Bay Powerhouse at tidewater. Utilizing the 192 cfs average annual discharge and a gross head of 550 feet, 66,100,000 kWh of annual energy would be realized. With a plant factor of 40%, 18,900 kW of capacity could be installed. The Phase 1 and Phase 2 development would produce a total of 136,900,000 kWh of annual energy with an installed capacity of 39,100 kW. It is recognized that additional power could be developed by utilization of the head between Swan Lake and Falls Lake. However, the incremental cost of development would be more expensive than other alternatives. 6. COMPARISON OF ALTERNATIVES Preliminary conceptual layouts of alternatives A, B and C and the Selected Arrangement alternative were compared on the basis of prelimi- nary construction cost estimates, the power developed and the power needs of the Petersburg-Wrangell area. It was determined that the initial stage, Phase 1, of the Selected Arrangement alternative would develop the largest capacity (19,200 kW delivered), that could be utilized in the system in a reasonable period, at a significantly lower cost per installed kW of capacity than other alternatives. Alternative C which completely develops 48,500 kW, while it re- sults in the lowest cost per installed kW is much too large a project for the system power needs. Further it would require a significant increase in capi- tal investment. SECTION VI ESTIMATED CONSTRUCTION COSTS AND CONSTRUCTION SCHEDULE 1. GENERAL Cost estimates for the Thomas Bay Project Phase 1 Selected Arrange- ment were based on the conceptual layouts shown in this report. Approximate quantities were established for major civil features and unit costs were ap- plied. Mechanical and electrical item costs were based on experience cost data. 2. BASIS OF COSTS a. Direct Construction Costs This includes the total of all costs directly chargeable to the construction of the Project and in essence represents a contractor's bid. The Direct Construction Costs are based on contractor bid prices, adjusted to a January 1975 bid price level. Indirect Costs are defined as those which are added to the Direct Construction Cost to result in the Total Construction Cost. Indirect Costs include an allowance for contingencies, engineering and escalation where nec- essary. b. Contingencies To allow for unforeseen difficulties during construction and to reflect possible omissions of estimate items, an allowance of 15% was applied to the Direct Construction Cost estimate. c. Engineering and Client Administration These costs for the Project were based on actual experience with costs for similar work. The item includes all preliminary engineering work; project feasibility studies; field investigations; final design and prepara- tion of construction contract documents; inspection of construction; and client administration. An allowance of 13% of the Direct Construction Cost plus Con- tingencies is considered a reasonable estimate and was included for this item. d. Escalation All costs were derived for a base January 1975 construction con- tract bid price level. Estimated costs were developed to correspond to bid- ding in accordance with an assumed Project schedule to bring the Phase 1 de- velopment on line as soon as possible, considered to be January 1983. The schedule is based on 4 years for investigations, FPC licensing and design, and 3 years for construction. The costs were escalated from the base Janu- ary 1975 bid level to other bid dates with assumed escalation rates of 12% for calendar year 1975, 10% for 1976, 8% for 1977 and 7% for 1978 and beyond. VI-2 Since the individual Project stages only require three years for construction, the bid prices used are assumed to reflect in-built escalation during the construction period and no additional escalation adjustment was nec- essary. e. Sales Tax No sales tax allowance is applicable. £. Total Construction Cost This includes the total of Direct Construction Cost, Contingencies, Engineering and Client Administration, and Escalation where appropriate. g. Interest During Construction For this purpose financing is assumed to be available, either from State or Federal sources, on a 5%, 40-year term basis. As discussed in Section VII, lower interest rate financing may be available, particularly through the State Water Resources Revolving Loan Fund. Interest during the construction period was thus assumed to be 5% per year based on a straight line cash flow, during the construction period which is estimated to be three years for the Phase 1 Project. h. Capital Investment The Capital Investment is the sum of the Total Construction Cost plus Interest During Construction. 3. CONSTRUCTION COST ESTIMATE A cost estimate summary for the initial stage Phase 1 development of the selected Thomas Bay Project is shown in Table VI-1l. The estimated Total Construction Cost for the development, bid date January 1975 is $46,307,000, and the corresponding Total Construction Cost for the proposed in-service date of January 1983 (bid date January 1980), is $70,542,000. The estimated Capital Investment for the in-service date of January 1983, is $75,833,000, corresponding to $3,754/installed kW. THOMAS BAY PROJECT COST ES Item Mobilization Swan Lake Outlet Tunnel Falls Lake Dam & Reservoir Falls Lake Power Tunnel Falls Lake Power Plant Transmission Subtotal Sales Tax DIRECT CONSTRUCTION COST Contingencies Subtotal Engineering & Client Administration Escalation TOTAL CONSTRUCTION COST Interest During Construction CAPITAL INVESTMENT CAPITAL INVESTMENT , $/INSTALLED kW PHASE 1 TIMATE SUMMARY Bid Date January 1975 $ 3,050,000 6,865,000 1,626,000 7,512,000 5,225,000 11,357,000 $35,635,000 $35,635,000 5,345,000 $40,980,000 5,327,000 $46,307 ,000 3,473 ,000 $49,780,000 $2 5464 TABLE VI-1 Bid Date January 1980 On-Line January 1983 $24,235,000 $70,542,000 5,291,000 : $75 ,833,000 $3,754 ——= SECTION VII COST OF POWER 1. GENERAL The only practical alternatives available for future development of the Petersburg-Wrangell electric generation system in the foreseeable fu- ture, are installation of additional diesel units or development of new hydro- electric sites. Gas turbines, and coal or oil-fired, steam generating units are not considered economic for the magnitude of loads expected. In this study only the alternative of diesel generation was compared with the develop- ment of the Thomas Bay Project - Phase 1 to determine the economic feasibi- lity of the Project. Comparison of the Project, and diesel generation, with other potential hydroelectric projects in the area should be undertaken, be- fore a final decision is made on the project resources scheduling, but is beyond the scope of this study. 2. ANNUAL COSTS a. Diesels New diesel units were considered as having fixed annual costs es- tablished on a capitalized basis and are determined as a percentage of the total bond issue for financing such an installation. Fixed costs established in this manner include debt service, operation and maintenance, administration, replacements, insurance and taxes and represent a levelized annual cost through- out the life of the units. An appropriate increase, determined to be 14%, was made to the to- tal construction cost to reflect interest during construction, the necessary reserves and other financing costs to arrive at the bond issue amount. The annual fixed cost for new diesel units were estimated to be 13.8% of the bond issue, based on a 25-year unit life, 7% interest rate, and a 1-1/2-year con- struction period. A summary of the fixed annual costs for the installation of new diesel units is shown in Table VII-1. Variable annual costs are those associated with the generation of energy and vary directly as the amount of energy generated. The only variable annual cost considered in this study is the cost of fuel oil. An estimate of the anticipated costs of fuel oil during the period of time considered in this study is shown in Table VII-2. Although very high increases in fuel oil costs have been recently experienced it is believed that the high rate of increase will not continue. Therefore, for purposes of this study, it has been assum- ed that fuel oil cost will increase at 10% per year through mid-1979 and at 7% per year thereafter, from a base cost of $16.00 a barrel in mid-1975. The annual cost of power for installing new diesel capacity with the capability of power output to the level which will result from Phase 1 and coming on-line in January 1983, is shown in Table VII-3. This diesel installation, is 14,000 kW producing 68,700,000 kWh annually by 1989, and a lesser amount to meet the load shown in Fig. 4, from 1983 to 1989. This is based on retiring about one-third of the existing diesels in 1983 and placing the others on capacity reserve. VII-2 b. Thomas Bay Project ~- Phase 1 The estimated annual cost of Thomas Bay, Phase 1 with on-line January 1983 construction costs, has been determined on the basis that State or Federal loans at a 5% interest rate and 40-year repayment period, will be available for financing hydroelectric projects. Under the provisions of the State Water Resources Revolving Loan Fund a lower interest rate loan, con- ceivably 3% or 4%, might be obtained. For this study, however, it was consi- dered prudent to assume the higher 5% rate. Annual fixed costs include debt service, and financing costs which have been estimated to be 0.7% of the Capital Investment. Variable costs for the Project include operation and maintenance, administrative and general, in- surance and interim replacements, and have been estimated to be 1.0% of the capital investment cost. Annual costs for the Thomas Bay Project, Phase 1, for an on-line date of January 1983, are shown in Table VII-4. The total energy output of the project will not be marketable im- mediately in the Petersburg-Wrangell system. The amount of deficient revenues needed to meet bond repayments during the initial period of operation through 1989 was capitalized, and spread over the 40-year repayment period which added 8.0 mills per kWh to the cost of power which would result if all power were marketable. The final cost of power in mills/kWh annually, through 1990, is shown in Table VII-4. It should be noted that the cost of power is based on the long-term average energy from the project, which can be considered firm by infrequent and short-term operation of the existing diesels to make up the small energy deficiency in the adverse water periods. 3. COMPARISON OF DIESELS AND THOMAS BAY PROJECT A comparison of Tables VII-4 and VII-3 shows that the annual cost of power from the Thomas Bay Project, Phase 1, is more expensive than the diesel alternative until about 1989. The comparison of annual costs is shown graphi- cally in Fig. 11. This is of course based on the assumptions utilized in this study for load growth, escalation of costs for hydroelectric and diesel instal- lations, and future increases in diesel fuel costs. Although the studies here- in show that Thomas Bay is not economically feasible on an annual cost of power basis until about 1989, this situation could change if the load growth and or diesel fuel escalation rates increased above those assumed. In addition if lo- wer interest rate financing is made available for the Project, as discussed above, the economic feasibility as compared to diesel generation would occur earlier. The significant effect of lower financing terms is demonstrated in Fig. 11, where the cost of power for 3% and 4% interest rate, 40-year term, financing is com- pared with the 5% interest rate. As can be seen with 4% to 4-1/2% financing, the Project becomes economic as soon as it can be constructed. The Project with 3% financing is considerably more economical than the alternative of diesel gen- eration. The real problem with the initial stage of the Thomas Bay Project is that significant costs for the ultimate project are incurred during the first phase. Costs such as those for access roads, Swan Lake outlet tunnel and lake tap and a large portion of the transmission lines and substations, are very large, and are incurred as sunk costs at the beginning. The second phase VII-3 of Thomas Bay would be constructed at a much reduced cost per kilowatt of in- stalled capacity. Unless lower interest rate financing is made available, the analysis with the diesel alternative shows that the Project would not be economical until about 1989, and that some other source of hydroelectric generation should be con- sidered for development to serve the needs of Wrangell and Petersburg, either collectively, or individually in the intervening period. The Blind Slough expan- sion will serve the needs of Petersburg for part of this period; Wrangell's needs can be met by increased diesel generation, or by developing a smaller hydroelectric project than Thomas Bay such as Thoms Lake, Virginia Lake or Kunk Lake. Such a project might serve Wrangell alone initially, and later on might be connected to Petersburg if the latter's needs develop. Even if low interest financing can be obtained for the Thomas Bay Project, a comparison should be made of the relative economics and scheduling, with these smaller hydroelectric projects, to determine the best generation resources development program for the Petersburg-Wrangell area. On-Line Date Direct Construction THOMAS BAY PROJECT FIXED COST FOR NEW DIESEL INSTALLATIONS Contingency Total and Engineering (3) $ 48. 51. 55. 58. 63. +52 72. 77. +71 88. 94. 101. 108. 116. 124. 132. 67 82 14 51 12 97 10 25 30 50 70 33 42 01 13 82 $ 338.14 361.81 387.14 414.23 443.23 474.26 507.45 542.98 580.98 621.65 665.17 711.74 761.56 814.87 971.90 932.94 Construction Cost — $/kW_ IDC, Reserve and Bond Cost (4) $ 47. 50. 54. 57. 62. 66 71 76 114 122 130 34 65 20 99 05 +40 +04 +02 81. 87. 93. 99. 106. +08 -07 +61 34 03 12 64 62 Bond Issue $/kW $ 385. 412. 441. 472. 505. 540. 578. 619. +32 662 708. 758 811. 868. 928. 993. 1,063. 48 46 34 22 28 66 49 00 68 +29 38 18 95 97 55 Annual Fixed Cost $/kW_(5) $ 53.20 56.92 60.90 65.17 69.73 74.61 79.83 85.42 91.40 97.80 104.65 111.97 119.81 128.19 137.17 146.77 Years shown are calendar years with the units shown coming on-line at the beginning of that year. If a unit is completed, for example, late in 1987 to meet the calendar year 1988 loads (on-line in January 1988), debt service and other annual costs will be payable for the entire year (1988). Contingency estimated at 10%, and engineering estimated at 6%. Estimated at 14% of Total Construction Cost. (1) Cost - $/kW (2) Jan. 1975 $ 290.00 Jan. 1976 310.30 Jan. 1977 332.02 Jan. 1978 355.26 Jan. 1979 380.13 Jan. 1980 406.74 Jan. 1981 435.21 Jan. 1982 465 .68 Jan. 1983 498.27 Jan. 1984 539.45 Jan. 1985 570.47 Jan. 1986 610.41 Jan. 1987 653.14 Jan. 1988 698.86 Jan. 1989 747.77 Jan. 1990 800.12 (1) (2) Escalated at 7% per year. (3) (4) (5) Estimated at 13.8% of Bond Issue. T-IIA ®T9?L Assumptions: ESTIMATED COST OF FUEL FOR DIESEL GENERATION THOMAS BAY PROJECT Cost per Cost Cost of Barrel per Power Year (42 Gallon) Gallon Mills/kWh 1975 16.00 $0 .381 27.2 1976 17.60 0.419 29.9 1977 19.36 0.461 32.9 1978 21.30 0.507 36.2 1979 23.43 0.558 39.8 1980 25.06 0.597 42.6 1981 26.82 0.639 45.6 1982 28.70 0.683 48.8 1983 30.71 0.731 52.2 1984 32.86 0.792 55.9 1985 35.16 0.837 59.8 1986 37.62 0.896 63.9 1987 40.25 0.958 68.4 1988 43.07 1.025 73.2 1989 46.08 1.097 78.3 1990 49.31 1.174 83.8 (1) - Cost of fuel escalated at 10% per year from base price in mid-1975 to mid-1979 and 7% per year thereafter. (2) Average heat rate of diesel units assumed at 10,000 Btu/kWh. (3) - Heat content of diesel fuel assumed at 140,000 Btu/gallon. (4) Cost of power in mid-year is assumed for generation during that calendar year. Table VII-2 TABLE VII-3 THOMAS BAY PROJECT ANNUAL COST OF POWER DIESEL UNITS Variable Total Annual Cost Cost of Power Year Fixed Costs (1) Costs (2) of Generation Mills/kWh 1983 $1,280,000 $1,931,000 $3,211,000 86.78 1984 1,280,000 2 5292 ,000 3,572 ,000 ‘ 87.12 1985 1,280,000 2,691,000 3,971,000 88.24 1986 1,280,000 3,195 ,000 4,475 ,000 89.50 1987 1,280,000 3,762,000 5,042 ,000 91.67 1988 1,280,000 4,392,000 5,672 ,000 94.53 1989 1,280,000 5,168,000 6,448 ,000 97.70 1990 1,280,000 5,757,000 7,037 ,000 102.43 NOTES: (1) - Based on installation of 14,000 kW of diesel capacity, on-line January 1983, at the unit cost shown in Table VII-1 (2) - Based on generation of energy necessary to meet the load shown in Fig. 4 at fuel oil costs as shown in Table VII-2. THOMAS BAY PROJECT PHASE 1 ANNUAL COST OF POWER TABLE VII-4 Fixed Variable Total Cost of Power (3 Year Costs (1) Costs(2) Annual Cost Mills/kWh 1983 $4,951,000 $ 758,000 $5,709,000 91.13 1984 4,951,000 811,000 5,762,000 91.90 1985 4,951,000 868,000 5,819,000 92.73 1986 4,951,000 929,000 5,880,000 93.62 1987 4,951,000 994,000 5,945,000 94.57 1988 4,951,000 1,063,000 6,014,000 95.57 1989 4,951,000 1,138,000 6,089,000 96.66 1990 4,951,000 1,217,000 6,168,000 97.81 NOTES: (1) - Debt Service based on 5%, 40-year term loan, plus financing costs estimated at 0.7% of Capital Investment. (2) - Estimated at 1.0% of Capital Investment. (3) - Based on total average energy of 68,700,000 kWh with adjustment of cost to allow for inability to market Project output in initial years of Project operation. SECTION VIII CONCLUSIONS AND RECOMMENDATIONS 1. CONCLUSIONS The following conclusions are made as a result of these studies: a. Development of hydroelectric power at the Thomas Bay site is tech- nically feasible. Development would have to be staged to match load require- ments of Petersburg and Wrangell and to reduce the capital investment required. b. The Selected Arrangement would allow staged development of Thomas Bay Project at a significantly lower cost per installed kW of capacity than other alternatives. Phase 1 of the Selected Arrangement would have an installed capacity of 20,200 kW and would produce 70,800,000 kWh of average annual energy. The ultimate development of Phase 1 and Phase 2 would have a total installed capacity of about 39,100 kW and an average energy output of 136,900,000 kWh. c. Phase 1 of the Selected Arrangement is estimated to require a capi- tal investment of $49,780,000 ($2,464/installed kW) based on bidding of con- struction contracts in January 1975, and $75,833,000 ($3,754/installed kW) bas- ed on bidding in January 1980 so that the Project would enter into service in January 1983, which is the earliest practical schedule. The relatively high cost for Phase 1 results from large sunk costs in the initial stage, and Phase 2 would have a much lower cost of installed kW. d. With 5%, 40-year term, financing the annual cost of power from the Thomas Bay Project is more than that from alternative additional diesel genera- tion until about 1989. However, with 40-year term financing and an interest rate in the range of 4% to 4-1/2%, the Project will produce power at less cost than the diesel generation alternative. Since it is not possible to market all of the Project output in its early years, the cost of power has been adjusted to reflect this condition. e. Other smaller hydroelectric sites, such as Thoms Lake, Virginia Lake and Kunk Lake, offer the potential for economic power development. Studies should be made of these projects to compare the resulting cost of power with that from the Thomas Bay Project as well as additional diesel generation. 2. RECOMMENDATIONS The following recommendations are submitted: a. Efforts should be made to secure low interest financing for develop- ment of the Thomas Bay Project. If this financing can be obtained a re-evalua- tion of the Project economics should again be made against alternative diesel generation, and by comparison with alternative smaller hydroelectric projects. b. Studies should be initiated as soon as possible to investigate the feasibility of alternative smaller hydroelectric projects such as Thoms Lake, Virginia Lake and Kunk Lake. These studies would form the basis for a re-evaluation of the economics and scheduling of the Thomas Bay Project. SECTION IX REFERENCES Alaska Power Survey, Federal Power Commission, 5 Volumes, dated 1969-1973. USBR; Thomas Bay Project, Alaska, Geology on Project Development, dated January 1962. USBR; Thomas Bay Project, Alaska, Interim Report dated June 1965. USBR; Thomas Bay Project, Alaska: a. DC-1 Estimate Sheets - Initial of Second Stage of (3 sheets). b. DC-1, Estimate Sheets - Single Stage Development (11 sheets), dated June 27, 1962. USBR; Thomas Bay Project, Alaska: a. Penstock Profile, Plate 5, dated February 13, 1962. b.. Power Tunnel Surface Profile, Plate 10, dated February 16, 1962. Cs Penstock Profile with Plan of Development, Plate 11, dated February 13, 1962. d. Waterways, Feasibility, Design Drawing No. 945-D-1, June 15, 1962. Analysis of Electric System Requirements for City of Petersburg, Alaska by R. W. Beck and Associates, Inc., dated March 1974. Paper, "Southeastern Power Needs," by J. V. Williamson, R. W. Beck and Associates, Inc. Presented at Southeastern Conference, October 1974. ; Geological Survey Bulletin Nos. 1631-E dated 1962 and water supply paper 1529, dated 1962. House Bill 171, Creation of a water resources revolving loan fund. Act Signed July 2, 1975. Thomas THOMAS BAY PROJECT MITKOF HIGHWAY MITKOF ISLAND BLIND SLOUGH PROJECT ~ Sumner Strai ZAREMBO ISLAND ORONKAFSK ISLAND +—ZIMOVIA HIGHWAY WRANGELL ISLAND ALASKA Yakon rive’ ANCHORAGE pes be ng e ae Thomas Bay Mh Qa! LEGEND Proposed transmission line —e\/h-e RW. BECK and ASSOCIATES, INC. Engineers and Consultants Seattle, Washington Columbus,Nebraska Denver, Colorado Orlondo , Florida Indicnapolis, Indiana Phoenix ,Arizono Wellesley , Massochusetts THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA THOMAS BAY PROJECT LOCATION MAP IDATE: IDRAWN: APPROVED: NOV.1975 | GT. | O¢@B 7 fo} ° + Critical period 2.91 a i WwW Wi w ' re) a Oo <z °o ° i ' = °o - wu a ay E = a > = 2 oO Oo _ 1951 NOTES: |. Flow is 89.9% of recorded flow at Cascade Creek gage. 2. Average annual flow is 226 cfs. RW. BECK and ASSOCIATES, INC. Engineers and Consultonts Seottle, Washington Columbus, Nebraska Denver , Colorado Oriando ,Florida Indionapolis, Indione Phoenix,Arizona Wellesley ,Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA THOMAS BAY PROJECT SWAN LAKE STORAGE -YIELD MASS DIAGRAM DATE: DRAWN | APPROVED: NOV, 1975 6.7. | MER tg a ul < <= = =< o oO ' > 9° a Wd 2a Ww t97I CALENDAR YEAR LEGEND QO Petersburg - Wrangell & Petersburg O- Wrangell NOTE |. Historical date taken from FPC Form (2 generation data. 2.75% growth rate superimposed RW. BECK and ASSOCIATES, INC. Engineers and Consultants Seattle , Woshington Columbus, Nebraska Denver , Colorado Oriondo, Florida Indianapolis, Indiana Phoenix ,Arizono Wellesley , Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA THOMAS BAY PROJECT HISTORICAL ENERGY LOAD GROWTH CURVES IDATE: IDRAWN: APPROVED: NOV. 1975 | LEE DER Orlando, Florida Phoenix ,Arizona = Wellesley, Massachusetts Engineers and Consultants Seattle , Washington Denver , Colorado THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA THOMAS BAY PROJECT PROJECTED ENERGY LOAD GROWTH CURVE RW. BECK and ASSOCIATES, INC. Columbus , Nebraske Indianapolis, Indiana Falls Lake Units 1-4 Average Delivered gh_Unit | lind _Slou CALENDAR YEARS aE! fo] °o @ o HM™ 000‘000'! - ADY3N3 Cc. Orlando, Florida Wellesley ,Mossochusetts Engineers and Consultants Seattle , Woshington Denver , Colorado Phoenix , Arizono THOMAS BAY POWER COMMISSION THOMAS BAY PROJECT PROJECTED PEAK LOAD GROWTH CURVE R.W. BECK and ASSOCIATES, IN PETERSBURG- WRANGELL, ALASKA Columbus, Nebraska Indianapolis, Indiana Falls Lake Peak Load Thomas Bay, Phase | CALENDAR YEARS Blind Slough Unit | Peak Load Plus Reserves SX N a } y V//// Existing Di Wy UZ VZ U, y ~ Y UL - ° N 8 MW ~ ALIDVdV9 ACCESS ROAD- AY; : 7 nf re J rc vy 4 ee Ss \ coo > es “POWER TUNNEL ao - A - a * Flt oad 7X sa ow ae rN {| ‘(ie i fat = SC PHASE 1 ce Ne All| ecu ) “POWERHOUSE SW es. “Normal WS. El. 80s a) \i . moo et 4 a ae . sau ao oa re 6 x ee ale l FALLS: LAKE pee eH eae / “(Power | TUNNEL —-~ aa, \ RANSMISSION LINE \\/ Ik 1A : ; mA d i lh il R.W. BECK and ASSOCIATES, INC. i Engineers and Consultants Seattle, Washington THOMAS BAY i : 1 ii y i / } u / s i Columbus, Nebrosko Denver, Colorado Orlando, Florida Indianapolis , Indiana Phoenix, Arizona Wellesley, Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA ‘POWERHOUSE - —* THOMAS BAY PROJECT / Me i \ , ; I ‘ sea ae ~ TLET T~. Tapo graphy trom USGS Quadrangle ALTERNATIVE A ARRANGEMENT yaelt } ; 7 : Wii / ~~ ~~-Sumdum(A-3) Alaska PLAN ate 4+:63,360 ; DATE lee APPROVED FIG: Nov.1975 | nem | O6@ 6 - PHASE / ~ . POWERHOUSEX : foe a A NN met Se goN 2 FALLS LAKE weer _— - ~ Se ~ Cortour ieee 200. feet RW. BECK and ASSOCIATES, INC. Engineers and Consultants Seattle, Washington -] Columbus , Nebraska Denver , Colorado Orlando, Florida Indianapolis , Indiana Phoenix, Arizona Wellesley, Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA THOMAS BAY PROJECT THOMAS BAY |. Topography from USGS Quadrangle ALTERNATIVE B ARRANGEMENT Pa - yr ~---Sumdum pg eas PLAN : > (> 3000~—— ~Scate 1:63, ~ Loe [pare DRAWN. | APPROVED FIG oo if , ; nov.i975 | ncm | OER iC SPRAY ISLAND VL u POWER TUNNEL ~ / Vase: } ~ Pee ; A) es oa \ vw / f \ \ AU Ae ~~ “TL ACCESS ROAD i +f J ks RW. BECK and ASSOCIATES, INC, Engineers and Consultants Seattle, Washington Columbus , Nebraska Denver , Colorado Orlando, Florida _] Indianapolis , indiana Phoenix, Arizona Wellesley, Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG- WRANGELL, ALASKA THOMAS BAY PROJECT THOMAS BAY —Topography’ from USGS Quadrangle ALTERNATIVE C ARRANGEMENT SPRAY ISLAND >. -Gumdum ‘(A-3) Alaska PLAN cate 4+:63,360 DATE DRAWN APPROVED FIG. ; Nov. 1975 | ncm | O€@ 8 ( ( p< SWAN LAKE \ / OUTLET TUNNEL FALLS LAKE FOREBAY™ FALLS LAKE DAM Normal Water Surface El. 1170 , Z fa a 4 woo F°——FALLS LAKE POWER CONDUITS C \ > . \ 1000 Oo ~~ 1000' ~ 4095 Scale ~— Contour interval 200 feet R.W.BECK and ASSOCIATES, INC. Engineers and Consultants Seattle, Washington Columbus , Nebraska Denver , Colorado Orlando, Florida Indianapolis , Indiana Phoenix , Arizona —_ Wellesley , Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG-WR ANGELL, ALASKA THOMAS BAY PROJECT THOMAS BAY POWER CONDUIT SELECTED ARRANGEMENT TRANSMISSION LINE 4 Topography from USGS Quadrangle SPRAY. ISLAND TO PETERSBURG AND Sumdum (A-3) Alaska PLAN WRANGELL ~30090 —* ~~ Seale 1:63,360 DATE: DRAWN: APPROVED. FIG NOV. 1975 | GT. | O€B 9 ELEVATION - FEET 2200 + T —— — 2000 1800 Swan Lake Normal Max. Original ground El. 1515) 1600 = i Minimum ] 1400 [BSE ie LISS iA \ er ik Swan Lake 1200 Outlet Tunnel 1000 800 600 i 400 200 fo) da oO 10 20 40 50 60 70 90 120 130 140 180 STATIONS R.W.BECK and ASSOCIATES, INC. Engineers and Consultants Seattle, Washington Columbus , Nebraska Denver , Colorado Orlando, Florida Indianapolis , indiana Phoenix, Arizona Wellesley , Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG -WRANGELL, ALASKA THOMAS BAY PROJECT SELECTED ARRANGEMENT PROFILE DATE: DRAWN. | APPROVED: NOV. 1975 GT. OEB Mills/KWh ' a ud = oO a A °o be n o o d a —] = 2 < Alternative :. 3% - 40 Year Financing —+— 1986 1988 1990 CALENDAR YEAR R.W.BECK and ASSOCIATES Engineers and Consultents Seottle , Washington Columbus, Nebrosko Denver , Colorado Oriando Florida Indionopolis,Indiona Phoenix,Arizona Wellesley ,Massachusetts THOMAS BAY POWER COMMISSION PETERSBURG - WRANGELL, ALASKA THOMAS BAY PROJECT COMPARISON OF ANNUAL COSTS WITH DIESEL DATE: DRAWN. APPROVED: nov.1975 | GT. | OCB