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HomeMy WebLinkAboutRegional Inventory and Reconnaissance Study for Small Hydropower Projects, Northeast Alaska 1982 Part 2FOREWORD This report consists of two parts. Part I is an overview of the study, including study results in summary format. Part II contains site-specific data for each of the conmunities studied. The Table of Contents provides an itemized list of the tables, ~aps, and data contained within each corrrnunity section of Part II. The report al so contains appendices which provide reference data and detailed explanations of study methodologies. i PART I -OVERVIEW 1.0 SUMMARY ... 2.0 INTRODUCTION TABLE OF CONTENTS 2.1 STUDY OBJECTIVES. 2.2 DESCRIPTION OF THE STUDY AREA 2.3 STUDY AUTHORITY ..... 2.4 STUDY PROCESS 2.5 DATA SOURCES .. 3.0 EXISTING CONDITIONS 3.1 CO~lMUNITY CHARACTERISTICS 3.1.1 Historical Develo~~ent 3.1.2 Existing Characteristics 3.2 EXISTING ELECTRICAL GENERATING SYSTEl·1S . 3.2.1 Longevity of Diesel Generators 3.2.2 Cost of Power ........ . 3.2 CURRENT ELECTRICAL ENERGY REQUIREMENTS . 4.0 PROJECTED ELECTRICAL ENERGY REQUIREr'lEtHS 4.1 FORECAST tl0DELS AtW ASSUr·1PTIONS . . 4.1.1 Introduction ........ . 4.1.2 Variables Used in EstiMating Demand 4.1.3 Forecasting riethodology . 4.2 PROJECTED DH1AtJDS 5.0 SCREENWG OF CmlHUNITY HYDROELECTRIC POTEtJTIAL 5.1 SCREENING CONCEPT ..........•... 5.2 PRELHlINARY SCREENING .......... . 5.2.1 Drainage Basin Inventory and Engineering Page 1-1 · 2-1 · 2-1 · 2-1 · 2-1 2-3 2-3 3-1 · 3-1 · 3-1 3-2 · 3-3 3-8 · 3-8 · 3-9 · . 4-1 · 4-1 · 4-1 · • 1t-1 · . 4-1 4-5 · 5-1 · . 5-1 · . 5-1 Ana lys; s ... . . . . . . . . ..... 5-1 5.2.2 fiydrologic Analysis. . ..•....• 5-2 5.2.3 Economic Analysis. • . • . • • • . .. 5-2 5.2.4 Screening Results. . .... 5-3 i i TABLE OF CONTENTS (Continued) 6.0 DETAILED INVESTIGATIONS .. 6.1 FIELD RECONNAISSANCE. 6.2 HYDROLOGIC ANALYSIS ..•. 6.3 PLAtH FACTORS AND INSTALLED CAPACITY. 6.4 CONCEPTUAL ENGINEERING 6.4.1 6.4.2 6.4.3 6.4.4 6.4.5 6.4.6 6.4.7 6.4.8 Genera 1 • . . • . • . Diversion Dams ••••. Soils and Foundations. Waterways • . . • • . . • Turbines and Generators Site Access .•.•.. Transmission ..••.•. Operation and Maintenance 6.5 PROJECT COSTS 6.5.1 Dar.1s • • 6.5.2 Penstocks. 6.5.3 Powerhouse and Equipment 6.5.4 Swi tchya rd 6.5.5 Access .••.•.••• 6.5.6 Transmission •••••••• 6.5.7 Mobilization •.•••. 6.5.8 Geographic Cost Adjustment 6.5.9 Operati on and ~1ai ntenance • 6.6 ECONOMIC ANALYSIS .••. 6.7 ENVIRONt4ENTAL CONSTRAINTS 7.0 LIST OF REFERENCES .•.•.•. iii · . . . . . . Page · 6-1 6-1 · 6-2 6-26 • 6-31 · 6-31 · 6-33 6-38 · . 6-39 • • . . . 6-40 . . • •. . 6-43 · • 6-43 • • • • • . 6-45 • • 6-46 6-46 · • 6-49 · " 6-50 . • • . 6-52 • • •. 6-52 . . . . . . . 6-52 · . 6-53 6-54 · 6-54 · 6-56 · . . . · 6-56 · . 7-1 LIST OF TABLES -PART I No. Title Page 1-1 SUMMARY TABLE, HYDROPOWER POTENTIAL 1-4 3-1 CLASSIFICATION OF COMMUNITIES BY EXISTING GENERATING SYSTOfS, SOUTHCENTRAL ALASKA 3-4 3-2 EXISTIt~G POWER SYST81 DATA SUMf.1ARY, SOUTHCENTRAL ALASKA COMMUNITIES 3-5 4-1 FORECAST PARAMETERS -LIGHTING AND APPLIANCES -TYPE A COMMUNITIES (NO CENTRAL GENERATION PLANT) AND TYPE C COMt1UNITIES (NO ELECTRICITY TO RESIDENCES) 4-3 4-2 FORECAST PARAMETERS -LIGHTING AND APPLIANCES -TYPE B COMMUNITIES (CENTRAL GENERATION PLA~T) 4-4 4-3 ELECTRIC SPACE HEATING REQUIREMENTS 4-5 4-4 SU~1~1ARY OF PROJECTED ELECTRICAL ENERGY ANNUAL PEAK DEr~AND 4-6 5-1 6-1 6-2 6-3 6-4 6-5 6-6 6-7 SUMMARY OF COMMUNITY HYDROPOWER POTENTIAL, SOUTHCENTRAL REGION POTEtJTIAL STORAGE SITES, SOUTHCENTRAL REGION GAGED STREAMS USED FOR BASIN PAIRING FLOW ADJUSTMENT FACTORS FOR GAGED STREAMS USED IN BASIN PAIRING BASIN PAIRINGS AND HYDROLOGIC CHARACTERISTICS OF POTENTIAL HYDROPOWER SITES TYPICAL PLANT FACTOR ANALYSIS FOR ISOLATED COMMUNITES AND SMALL UTILITIES, DESIGN YEAR 1997 ALASKA SI-lALL HYDROPOWER PROJECTS -COST ESCALATImJ FACTORS ALASKA GEOGRAPHIC COST ADJUSTMENT FACTORS iv 5-5 6-3 ti-4 6-7 6-11 6-29 6-47 6-55 LIST OF FIGURES -PART I No. Title Page 2-1 STUDY COMMUNITIES LOCATION MAP 2-2 6-1 MEAN ANNUAL PRECIPITATION AND MEAN MINIMUM JANUARY 6-8 TEMPERATURES IN COOK INLET 6-2 MEAN ANNUAL PRECIPITATION AND MEAN MINIMUM JANUARY 6-9 TEMPERATURES IN GULF OF ALASKA AREA AREA 6-3 FLOW DURATION CURVE FOR SQUIRREL CREEK AT TONSINA 6-14 6-4 FLOW DURATION CURVE FOR WEST FORK OLSEN BAY CREEK NEAR CORDOVA . 6-15 6-5 FLOW DURATION CURVE FOR BARBARA CREEK NEAR SELDOVIA 6-16 6-6 FLOW DURATION CURVE FOR TWITTER CREEK ~JEAR HOMER 6-17 6-7 FLOW DURATION CURVE FOR CRESCENT CREEK NEAR COOPER LANDING 6-18 6-8 FLOW DURATION CURVE FOR GLACIER CREEK AT GIRDWOOD 6-19 6-9 FLOW DURATION CURVE FOR SOUTH FORK CAMPBELL CREEK NEAR ANCHORAGE 6-20 6-10 FLOW DURATION CURVE FOR LITTLE SUSITNA RIVER NEAR PAL~1ER 6-21 6-11 FLOW DURATIOU CURVE FOR WI LLOW CREEK NEAR WILLOW 6-22 6-12 FLOW DURA TON CURVE FOR CHUITNA RIVER NEAR TYONEK 6-23 6-13 FLOW DURATION CURVE FOR BERRY CREEK NEAR DOT LAKE 6-24 6-14 FLOW DURATION CURVE FOR SEATTLE CREEK NEAR CANTWELL 6-25 6-15 FLOW DURATION CURVE FOR PLANT FACTOR ANALYSIS UTILITY-SERVED COMMUNITIES 6-27 6-16 LOAD DURATION CURVE FOR PLANT FACTOR ANALYSIS ISOLATED COMMUNITIES AND SMALL UTILITIES 6-30 6-17 ROCKFILL/SHEETPILE DAM AND INTAKE STRUCTURE -TYPICAL LAYOUT 6-34 6-18 LOW CONCRETE D~1 AND INTAKE STRUCTURE -TYPICAL LAYOUT 6-36 6-19 LARGE CONCRETE DAM AND INTAKE STRUCTURE -TYPICAL LAYOUT 6-37 v No. 6-20 6-21 6-22 LIST OF FIGURES -PART I (Continued) Titl e POWERHOUSE -TYPICAL LAYOUT TRANSMISSION LINE LOAD VS. DISTANCE FOR 5 PERCENT LOSS TURBINE GENERATOR COSTS APPENDICES APPEIWIX A: UTILITY RATE SCHEDULES APPENDIX B: METHODOLOGY FOR DRAINAGE BASIN INVENTORY AND PRELIMINARY SCREENING APPENDIX C: ECONOMIC ANALYSIS METHODOLOGY APPENDIX D: SOUTHCENTRAL ALASKA INTERTIED COMMUNITIES SUMMARY TABLE vi Page 6-42 6-44 6-51 TABLE OF CONTENTS (Continued) PART II -COMMUNITY AND SITE DATA Note: For each community listed below, data sheets are provided in the fo 11 owi ng order: Hydropower Sites Identified in Preliminary Screening Summary Data Sheet Load Fo reca st Significant Data (Detailed Investigation) Conceptual Layout (Detailed Investigation) Plant Factor Program Output (Detailed Investigation) ~dropower Cost Data (Detailed Investigation) Benefit-Cost Ratio (Detailed Investigation) Photographs Community Descriptions and Site Selection discussions are also provided for communities which were visited in the field. Part II communities are provided in the following order: Cantwell-Broad Pass Chickaloon Halibut Cove Kachemak Mentasta Lake New Chenega Northway Port Graham-English Bay Sel dovi a Tazlina Tetlin-Last Tetlin Village Whittier Hope Rainbow Tyonek Copper Center Gakona-Gul kana Kenney Lake Meakerville-Eyak Eska-Jonesville-Sutton Knik r~ontana Tal keetna Ellamar-Tatitlek Ferry-Suntrana Cape Yakataga Chi stochi na Chitina Nabesna Paxson Skwentna Slana Susitna vi i PART I -OVERVIEW 1. 0 S Ur~MAR y Currently, most Alaskan communities consume electricity that is generated by burning non-renewable fossil fuels. The costs of this fonn of power generation have been increasing rapidly and it is expected that the costs of fossil fuels will continue to rise. An important alternative to burning fossil fuels for electricity is the hYdroelectric potential of Alaska's surface water resoun:es. In 1976, the Corps of Eng"j neers was authori zed by Congress to assess small hydropower developments (5 megawatts or less) that might serve communities throughout Alaska. This study of Southcentral Alaska is focused on one of six subregions identified by the Corps for further study of hYdroelectric potential. The purpose of this reconnaissance-level study is to identify, at each of 42 Southcentral Alaska communities, nearby hYdroelectric resoun:es worthy of further evaluation. The study was accomplished through a three-stage process: 1) prel imi na ry inventory and screeni ng of drai n- age basins; 2) limited field reconnaissance; and 3) reconnaissance- level engineering and economic evaluation of the more promising sites. As a result, small hydroelectric projects at 15 sites appear to be worthy of feasibility-level evaluations: -----. Cantwell-Broad Pass Site 5, Carlo Creek Halibut Cove Site 4, Halibut Creek Kachemak Site 3, Swift Creek Port Graham-English Bay, Site 5, Dangerous Cape Creek Seldovia Site 4, Windy River Whittier Site 3, Placer River Hope Site 1, Bear Creek Copper Center Site 16, Klawasi River Gakona-Gulkana Site 3, Copper River Tributary Kenney Lake Site 1, Tonsina River Tributary Meakerville-Eyak Site 6, Robinson Falls Creek Eska-Jonesville-Sutton Site 6, Wolverine Creek Montana Site 1, North Fork Kaswitna River Ta"lkeetna Site 4, Middle Fork Montana Creek Ferry-Suntrana Site 5, Moody Creek In addition, three sites with potential installed capacities exceeding the 5~egawatt limit, \-Ihich generally defines small hYdropower projects, were identified: Chickaloon Site 12, Kings River Rainbow Site 5, Ship Creek Knik Site 3, Willow Creek Further study of the Chickaloon and Rainbow sites could be done under the small hydropower authority if additional hydrologic data indicate that the optimum site capacity is less than 5 megawatts. The Knik site with a potential capacity well in excess of the 5 megawatt limit could be considered under a different Corps general investigation authority. 1-1 Each of the communities that could be served by one of the potential sites listed above is tied to an existing transmission line, with one exception. The site that would serve the communities of Broad Pass and Cantwell was evaluated with the assumption that it would be tied to the proposed Anchorage-Fairbanks Intertie. In general, the development potential of the sites listed above may be attributed to the fact that all of the small hYdropower projects would serve existing utility systems. It was assumed that all power generated by such projects would be consumed by the utility system as a whole. Greater system demand (in comparison with an isolated community) provides for higher plant factors and makes sites economically attractive. Also, these projects provide higher installed capacities (greater than 300 kW) than those for which further studies are not warranted. However, exi sti ng service to all of these communities is subject to interruption, and all are without an alternative tie-in to regional power systems. Table 1-1 summarizes significant information pertaining to each site included in the third and final stage of this reconnaissance study. The resul ts are stated in terms of benefit-cost rati os. In thi s study, this ratio is defined as the costs of the most likely alternative method of power generation (diesel, combustion turbine) divided by the costs of hYdroelectric generation. Thus, the more expensive the alternative in comparison to hYdropower, the higher the benefit-cost rati 0 deri ved for the hYdropower site. The prel imi nary screeni ng was intended to highlight the more promising sites among all identified sites. Sites with benefit-cost ratios less than 1.0 in the preliminarY screening stage were not considered further. The field visits and more detailed studies of the sites which "survived" the preliminary screening resulted in the calculation of benefit-cost ratios. These ratios indicate whether these studies would be worthY of feasibility-level investigations. The last column of Table 1-1 indicates where feasibil ity studies would be best appl ied. Some of the communities suggested for further study will be reviewed during future Corps of Engineers studies to identify which of these communities might be more effectively served by future power projects such as the proposed Bradley Lake and Susitna developments. Consideration of such future projects could change the benefit-cost relationships for some of the suggested sites. 1-2 TABLE 1-1 SOUTHCENTRAL ALASKA HYDROPOWER SUMMARY TABLE RESULTS OF DETAILED RECONNAISSANCE INVESTIGATIONS Draf nage Transmf ssi on Net Desfgn Mfnfmum Installed Plant Energy Benefft Sfte Stream Area Dfstance Head Flow Flow Capacfty Factor Cost Cost Connunfty No. Name (mf 2) (mil (ft) (cfs) (cfs) (kW) ( Percent) (~/kWh).Y Ratfo'll Cantwell-Broad Pass 5 carlo Creek 14.9 23.0 485 52.0 5.2 1,710 41 0.26 1. 91 Chfckaloon 12 Kf ngs River 99.0 7.4 191 598 119.6 7,744 37 0.065 5.96 Halfbut Cove 4 Hal f but Creek 18.9 2.2 349 174 17.4 4,117 52 0.094 4.12 Kachemak 3 Swift Creek 6.9 2.6 625 15.9 1.6 674 46 0.21 1.80 Mentasta Lake 1 Rf ght Trf buta r,y to Slana River 3.3 4.0 650 1.9 0.38 84 39 1.06 ...... 0.44 I W New Chenega 5 Sectfon 22 Lake 0.5 2.2 604 2.4 0.48 98 47 0.72 0.65 Northway 3A Gardf ner Creek 28.9 H.O 85 37.0 3.7 213 31 1.55 0.29 Port Grahal8 -5 Dangerous 5.8 6.1 407 35.7 3.6 985 52 0.16 2.43 Engl fsh Bay Cape Creek Seldovia 4 Wfncty Rfver 6.4 2.5 191 59.0 5.9 ,764 52 0.14 2.78 Tazlfna 4 cache Creek 21.3 2.0 183 H.6 2.3 144 48 0.44 0.82 Tetlfn-Last Tetlfn Vf 11 age 14 Mfce Creek 27.6 18.8 239 7.2 1.4 H7 36 1.94 0.27 Whittfer 3 Pl acer River ZO.8 H.3 265 218 43.6 3,917 45 0.12 3.21 Hope 1 Bear Creek 4.0 0.4 1,086 8.5 0.85 626 52 0.16 2.36 Rainbow 5 Shfp Creek 75.0 0.5 489 204 40.8 6,763 48 0.071 5.46 Tyonek 4 Chuitna Rfver 108 4.7 93 426 42.6 2,686 44 0.40 0.97 1/ 1981 ~ 2/ Condition~: Ii DPrr.pnt fllPl r.o~t. escalation; canit.itl r.o~t~ of .'lltprn.'ltivp nnwpr npnpri1tinn p.rl"rlprl TABLE 1-1 (Continued) SOUTHCENTRAL ALASKA HYDROPOWER SU~tMARY TABLE RESULTS OF DETAILED RECONNAISSANCE INVESTIGATIONS Drai nage Transmi ss ion Net Design Minimum Installed Plant Energy Benefit Site Stream Area Di stance Head Flow Flow Capacity Factor Cost Cost COOlllunity No. Name (mi 2) (mil 1ft) (cfs) (cfs) (kW) ( Percent) ( $/kWh).!/ Ratio~/ Copper Center 16 Klawasi River 149.0 0.8 152 270 27.0 2,782 48 0.22 1. 67 Gakona-Gulkana 3 Copper Ri ver 35.9 6.9 244 65 6.5 1,075 48 0.26 1. 39 Tri butary Kenn~y Lake 1 Tonsina River 7.8 2.7 937 6.2 0.62 394 48 0.28 1.28 Tributary Meakerville-~ak 6 Robi nson 1.7 13.1 674 19.8 2.0 905 64 0.10 3.95 ........ Fall s Creek I ~ Eska-Jonesville-6 Wol veri ne 45.4 1.5 533 91.5 9.15 3,306 39 0.13 3.04 Sutton Creek Knik 3 Willow Creek 146.0 0.1 374 572 114.4 14,504 38 0.066 5.88 Montana 1 North Fork 39.0 3.7 483 153 15.3 5,010 43 0.14 2.78 Kaswitna River Talkeetna 4 Middle Fork 35.0 0.2 155 96 9.6 1,009 43 0.20 1. 97 Montana Creek Ellamar-Tatitlek 6 Indi an Creek 1.7 9.3 897 2.1 0.42 128 55 0.59 0.8? Ferry-Suntrana 5 Mooc\y Creek 87.0 2.0 235 304 60.8 4,843 36 0.17 1. 95 2.0 INTRODUCTION 2.1 STUDY OBJECTIVES Electric power provided to Southcentral Alaska villages is presently generated by diesel generators for isolated communities and by combustion turbines to those co~nunities served by some of the utilities. The costs of fuel, including transportation and handling costs, have been increasing rapidly and present a financial burden to electricity consumers. Diesel generators break down frequently and are expensive to operate and maintain. Among the wide range of power generation alternatives, the potential hYdroelectric resources of Southcentral Alaska merit consideration due to the availability of potentially suitable surface water resources in the region. Development of small local hydropower facilities would relieve v'illage consumers of paying for the rising cost of fuel and ensure a source of power not subject to inflation. The purpose of this study is to evaluate potential hYdropower developments to serve local needs at each of 42 Southcentral Alaska communities. As a reconnaissance study, the objective was to identify and evaluate streams that might serve each community's power needs. The report provides, for each community, a summary of the existing power system, future power needs, an identification of potential sites, and an economic review that indicates benefits of hYdropower relative to existing power. For those sites with economic hydropower potential, information is provided on the hYdrologic characteristics, suitable equipment, preliminary size of project components, conceptual cost estimates, and identification of any environmental constraints. 2.2 DESCRIPTION OF THE STUDY AREA The forty-two communities that comprise the Southcentral study region (Figure 2-1) are located primarily on the Kenai Peninsula, along the Alaskan and Glenn Highways, in the Copper River Valley, and on the shoreline of Prince William Sound. Despite the size of the study area, the comli1unities support similar lifestyles and share many common social and economic problems and needs. All of the communities have a population of less than 500 persons. Most of the communities are accessible by road and only a few communities are accessible only by air transport. Approximately 25 percent of the study area communities are native villages. The economies are a mixture of subsistence/cash. Few employment opportunities exist outside the fishing industry which provides jobs to residents of communities on the Kenai Peninsula. 2.3 STUDY AUTHORITY The Alaskan Small HYdropower Study authorized the Corps of Engineers to assess the potential for installing small hydropower prepackaged units 5 megawatts or less to serve isolated communities throughout Alaska. This study of the hYdroelectric potential of Southcentral Alaska is focused on one of six identified subregions. To date studies of the 2-1 ( PACIFIC OCEAN KEY MAP .' ;;. "i)'~i' ~~ .. :..~ .f ., ~ .. .,."".... = .... >4~ -.. ,...' .. ?-? )" .. ~ "\' ";1 .--:-<, -~ i,,~ '''~.l~, ~ ·~v·.~~""IIfIIi.·:S 100 50 0 100 I I ..... iiiiiiiiiiiiiii~ SCALE I N MILES REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA STUDY COMMUNITIES LOCATION MAP FIGURE 2 - 1 DEPARTMENT OF THE ARMY ALASKA CORPS DISTRICT OF ENGINEERS Southeast, Southwest, Northwest, and Kodiak Island/Alaska Peninsula/Aleutian Islands have been completed. This study was conducted simultaneously with the hydropower study of Northeast Alaska. 2.4 STUDY PROCESS The study was accomplished in three stages during the period April to December 1981. The first stage involved a literature and information review, a projection of community electrical energy requirements, and review of USGS 1:250,000-scale topographic maps to inventory drainage basins and identify potential hydroelectric sites. Stream flows \'Iere estimated by applying the concept of "basin pairing," in \>lhich drainage basi n characteri stics for ungauged streams are matched to the most appropriate gauged stream basin within the region. For those streams that were estimated to have sufficient hydroelectric development potential to meet a substantial part of community needs, preliminary cost estimates were prepared. The cost of hYdropower was then compared to the cost of alternative power. Six sets of benefit/cost ratios were calculated based on scenarios of 0, 2 and 5 percent fuel escalation, both with and without the cost of capital investment in generating equipment for alternative power sources. The second stage involved a field reconnaissance to sites that indicated development potential. During the site visits, community 1 eaders were contacted rega rdi ng 1 oca 1 interest in hYdropower, power needs, future plans for the community, and any environmental constraints to development. Cross-sectional profiles of streams and streamflow observations were made. The most promising sites identified in the preliminary screening \>lere included in the third stage of analysis. A list of sites to be studied in greater detail was developed on the basis of field observations and review of USGS 1:63,360-scale maps. Data obtained in the field were evaluated, and load projections were revised based on community survey results. More detailed development concepts and cost estimates were prepared for the most promising sites. Benefit/cost ratios were recomputed for each hYdropower project by compari ng hYdropower costs to the value of electricity produced by the least costly alternative, which in all cases was assumed to be existing generating plants. 2.5 DATA SOURCES A list of reports that were used as background to this reconnaissance study can be found in the reference section. Several reports were available on the energy requirements of remote villages and were used to support the load projections. Current population figures were obtained from the U.S. Bureau of the Census. In addition to recent Alaska literature, persons in various state agencies and utilities were contacted regarding electrical energy demand. Fuel, equipment. and transportation companies were contacted to obtain the most current prices and costs. 2-3 3.0 EXISTING CONDITIONS This section includes a description of community characteristics which provides a context for understanding both the present and future electric energy requirements of the study area communities. Thi s description of social and economic conditions provides a rationale for the specific assumptions used in forecasting electric energy demand. 3.1 COMMUNITY CHARACTERISTICS The communities of Southcentral Alaska that comprise the study area can be classified as either small regional centers or rural villages. Small regional centers are communities ranging in size from approximately 200-500 persons, provide sources of employment, but do not present the economic opportunities of the larger cities. Communities that fall withi n thi s category are Copper Center, Kachemak, Meakerville (Cordova), and Seldovia. These small economic centers provide for the delivery of goods and social services to the surroundi ng a rea. Small busi nesses and government agenc i es locate in these centers and provide local jobs. These communities are characterized by the presence of commercial air service, air charter services, and accomodations for tourists. The majority of communities in the study area can be classified as rural villages with populations of less than 200 persons. In the more remote vi 11 ages, the unemployment rate is chronically high and jobs usually must be sought outside of the village on a temporary basis. Jobs are often found primarily in construction, firefighting, the fishing industry, and with the native corporations. Many of the communities of Southcentral Alaska have a mixed cash/subsistence economy. Some of the coastal communities have evolved in response to the expandi ng fi shi ng industry. In those communities, jobs are more available than in many of the land-locked villages. The results are a more stable source of income and a relatively higher per capita income. In addition, tourism and second-home development are contributing to modest growth in selected areas such as coastal communities on the Kenai Peninsula. 3.1.1 Historical Development The economy of the typical rural village is small, unstable, and rapidly changing. Since 1940 population has declined in many of these vi 11 ages. In other vi 11 ages, popul ati on 1 evel shave fl uctuated greatly, raising the question of future growth or decline (Alonso and Rust 1976). Some remote villages have been abandoned in the past and new co~nunities have evolved in response to the changing economic structure. In general, a net movement towards the larger cities has been occurri ng, particul arly among the nati ve popul ation. Thi s trend has been reversed in some areas due, in part, to the provisions of the Alaska Native Claims Settlement Act and more recently to the Alaska Lands Bi 11. 3-1 3.1.2 Existing Characteristics The socioeconomic characteristics and physical setting of a community tell a great deal about existing and future electrical energy requirements and the feasibility of continuing to produce power from diesel generators. For remote communities, the expense of transporting fuel and repairing the generators is a substantial economic burden. The following discussion provides an overview of village demographics, economic climate, and infrastructure. Demographic s Long term population growth in Alaska has ranged from less than 1 percent to 3 percent per year (Retherford 198!). Population growth in small rural villages has been lower on the average than in the larger communities. Each community is unique with respect to population trends, however; some villages have for years experienced little or no change in population while other communities are growing rapi dly. In native villages the availability of housing and jobs, and proximity to family relatives are three major factors that influence a person to relocate to a village. Privately financed housing construction is uncommon and most new homes are obtained through the HUD housing program. Communities that suddenly receive a large number of new homes may experience a spurt in population growth. The availability of jobs, such as for an airport construction project, may be an additional inducement for an outsider to relocate. The reasons whY people move to non-native villages are not so appa rent. Some persons relocate to a remote cOllll1uni ty to escape the city without considering fully job or housing opportunities. Average household size in Alaska was 3.26 in 1976 (Goldsmith and Huskey 1980) but historically has been larger in non-urbanized communities. The 44 villages served by the Alaska Village Electric Cooperative (AVEC) have a reported household size of 5.5 persons (Galliet 1980). Following the national trend toward fewer persons per household, household size in Alaska will probably decrease over time. The household size used in the load forecasting model was 4.5 persons for isolated communities and 3.5 persons for intertied communities. Employment and Income In a mixed subsistence/cash economy, income is derived from either wages or transfer payments. Subsi stence acti vities reduce the need for cash and typically consist of mining (e.g. gold panning), trapping, fishing, and gathering wood for fuel. Most jobs in rural villages are seasonal, cyclical, and temporary. Traditionally, seasonal employment has been provided by jobs in fishing, construction, and firefighting. Temporary employment may be found outside the village with resource 3-2 exploration companies. A few local jobs have been created by the CETA program, whi ch is a government subsi di zed employment program. The funding has recently received drastic cuts, however, and the program may eventually be phased out. Transfer payments are another form of income and include food stamps, welfare, social security, and unemployment benefits as well as other government subsi di zed programs. These payments often do not respond to inflation and may be subject to cutbacks in the near future. Infrastructure Infrastructure in a small rural village typically includes housing, community center, elementary school, laundry, and possibly a water and sewer system. The i ntroducti on of infrastructure into a community can change radically the electricity requirements. While many of the rural villages have limited infrastructure, water and sewer systems, schools, airports, and HUD housing may be introduced over the next ten years and would, consequently, increase the demand for electricity. Under federa 1 1 aw, every vi 11 age has a ri ght to an adequate water and sewer system, and housing for low income people. Every village with eight or more secondary students has a right to have a high school under state law. Airport development projects are occurring throughout the study area, and may increase in the future. 3.2 EXISTING ELECTRICAL GENERATING SYSTEMS Communities in the study area range from having no electricity to purchasing electricity from a utility. Communities that are intertied to Golden Valley Electric Association (GVEA), Homer Electric Association (HEA), Matanuska Electric Association (MEA), or Chugach Electric Association (CEA) rely primarily on combustion turbines for electricity. Eighteen of the communities purchase electricity from one of these four utilities. Communities intertied to Copper Valley Electric Association (CVEA) or Cordova Public Utilities (CPU) as well as isolated communities purchase electricity generated from diesel generators. In some communi ti es, generators of 2-5 kW ins i ze provi de individual residential electricity but their use is restricted by the high operating and maintenance costs. Some communities have small diesel generators owned, operated, and maintained by the BIA that are limited to school and council use. Ten communities fall within the category of havi n9 no resi denti a 1 el ectricity. Last Tetl in Vi 11 age, which has no resiaents, also has no electricity. A classification of the communities by existing generating systems is presented in Table 3-1. Several utilities were contacted to determine the expected useful life of their existing diesel generators. Because each utility system consists of a mix of generators of varying sizes and ages, and because the utilities generally plan to extend the useful life of their eqUipment through periodic overhauls, no speciic data on expected useful life of the generators can be provided in Table 3-2. However, for purposes of the present study, certain assumptions were developed. These are discussed in the following section. 3-3 TABLE 3-1 CLASSIFICATION OF COMMUNITIES BY EXISTING GENERATING SYSTEMS SOUTHCENTRAL ALASKA Type A Individual or Small Village Generators Broad Pass Cantwell Chitina Paxson Tatitlek Type B Central Generati on Pl ant Chickaloon Copper Center Engl i sh Bay Eska Eyak Ferry Gakona Gul kana Halibut Cove Hope Jonesvi 11 e Kachemak Kenney Lake Knik Meakerville ~lontana North\'1ay Port Graham Rainbow Sel dovi a Suntrana Sutton Tal keetna Tazl i na Tyonek Whitti er 3-4 Cape Yakataga Chi stochi na Ell amar Last Tetlin Village Mentasta Lake Nabesna New Chenega Slana Skwentna Susitna Tetl i n -,. TABLE 3-2 EXISTING POWER SYSTEM DATA SUMMARY SOUTHCENTRAL ALASKA COMMUNITIES Page 1 of 3 1/ !I !/ 1981 Energy Cost of Cost of Connunfty Longitude 1981 Method of-Util fty Installed Use 2/ Diesel Fuel Residential 3/ Name and Latitude Po~ulation Generation Name Ownershi~ Ca~acit~ (kW) (kWh/~earl-(i/gallon) Power (i/kWh)- Broad Pass 149· 16'W 63· 14'N 12 Diese 1 None Individual generators 41,673 1.421 Cantwell 148· 57'W 63· 24'N 95 Diesel None Private Individual generators 395,893 1. 421 Cape Yakataga 142· 25'W 60· 05'N 48 Unknown 22,282 1.324 Chickaloon 148· 23'W 61· 42'N 43 ~dro, Gas Matanuska REA None 190,764 .09 El ectri c Association Chistochina 144· 4O'W 62· 34'N 55 Diesel None Private 55 (lodge/general 25,532 1. 305 store) Chitina 144· 26'W 61· 31'N 25 Diesel None Private 60 104,182 1.315 Copper Center 145· 17'W 61· 58'N 213 Diesel Copper Va 11 ey REA 3700 944,945 1.028 .23 Electric Association ~ Ellamar 146· 43'W 60· 56'N 46 Unknown 21,354 1.324 U1 English Bay 151· 55'W 59· 21'N 125 Diesel Homer Electric REA 1500~/ 554,545 .08 Association Eska 148· 55'W 61· 44'N 53 ~dro, Gas Matanuska REA None 235,127 .09 Electric Association Eyak.!/ 145· 35'W 60° 31'N 3 Diesel Cordova Muncipal 8500 13, :ll9 1.131 .32 Electric Coope ra t i ve Ferry 149· 07'W 64· 01'N 32 Coal, Golden Valley REA 225,000 137,527 .12 Diesel, Electric 011 Association Gakona 145· 19'W 62-18'N 25 Diesel Copper Valley REA 3700 110,909 1.028 .23 Electric Association 1/ Alaska Department of Commerce and Economic Development. 1979. 2/ Derived from the load forecasts. 'I/ Based on consumption of 438 kWh/month. 4/ Community has been annexed by Cordova. !/ Most of the power sold is purchased from Chugach Electric Assoc i ati on. TABLE 3-2 EXISTING POWER SYSTEM DATA SUMMARY SOUTHCENTRAL ALASKA COMMUNITIES Page 2 of 3 11 11 11 1981 Energy Cost of Cost of Community Longitude 1981 Method of Uti lity Installed Use 2/ Diesel Fuel Residential 3/ Name and Latitude Po~ulation Generation Name Ownershi ~ Ca~acit~ (kW) (kWh/~earl-(g/gallon) Power (g/kWh)- Gul kana 145° 23'W 62° 16'N 111 Diesel Coppe r Va 11 ey REA 3700 492,436 1.028 .23 Electric Association Ha 1 i but Cove 151· 14'W 59· 36'N 60 Diesel Homer Electric REA 1500E.I 266,182 .08 Association Hope 149° 40'W 60° 55'N 51 I1Ydro, Gas Chugach REA 423,000 226,254 .06 Electri c Association Jonesvi 11 e 148° 58'W 61° 44'N 97 I1Ydro, Gas Matanuska REA None 430,327 .09 Electric Associati on Kachemak 151° 24'W 59° 41'N 403 Diesel Homer Electric REA 1500 1,787,855 .07 Association w Kenney Lake 144° 56'W 61° 44'N 100 Diesel Copper Valley REA 3700 443,636 1.028 .23 I 0"1 Electric Association Knik 149· 44'W 61· 27'H 10 I1Ydro, Gas Matanuska REA None 44,364 .09 Electric Association Last Tetlin 142° 36'W 63° 02'N 0 None None None Vi 11 age Meakervi 11 ei/ 145° 45'W 60° 32'H 300 Diesel Cordova Municipal 8500 1,330,909 1.131 .32 Electric Cooperative Mentasta Lake 143° 48'W 62° 56'N 75 Diesel None 45 1. 330 Montana 150° 04'W 62° 05'N 39 I1Ydro, Gas Matanuska REA None 173,018 .09 Electric Association Nabesna 143° OO'W 62° 22'H 40 None None None 1.345 New Chenega 147° 56'W 60° 04'N oY None None None 1.324 Northw~ 141° 56'W 62° 58'N 375 Di esel No rthw~ Powe r Private 480 1,663,637 1.259 .25 and Light Y Popul' 10f 94 expected by autumm of 1982. ) TABLE 3-2 EXISTING POWER SYSTEM DATA SUMMARY SOUTHCENTRAL ALASKA COMMUNITIES Y Page 3 of 3 1/ Y 1981 Energy Cost of Cost of COIIIllU ni ty Longitude 1981 Method of-Utility Installed Use 2/ Diesel Fuel Residential 3/ Name and Latf tude POl!ulatfon Generation Name Ownershil! Caeac i tl: (kW) (kWh/l:ea r)-(j/gallon) Power (S/kWh)- Paxson 145· 24'W 63· 4O'N 24 Diesel None Private Unknown 1.305 Port Graham 151· 5O'W 59· 21'N 162 Dfesel Homer Electric REA 1500i/ 718,691 .08 Associatfon Rafnbow 149· 38'W 61° OO'N 20 I1Ydro, Gas Chugach REA 423,000 88,727 .06 Electric Assocfatfon Seldovfa 151· 43'W 59· 26'N 479 Dfesel Homer Electrfc REA 1500i/ 2,125,018 .08 Associatfon Skwentna 151· 11'W 61° 58'N 16 None None None 1.456 Slana 143· 58'W 62· 43'N 12 Unknown 1.325 Suntrana 148· 51'W 63· 51'N 81 Coal, Golden Valley REA 225,000 359,346 .12 Dfesel, Electrfc 011 w Assocfatfon I -....,J Susftna 150· 3O'W 61· 33'N 42 Unknown 1.456 Sutton 148· 52'W 61· 43'N 76 I1Ydro, Gas Matanuska REA None 337,163 .09 Electric Associatfon Talkeetna 150· 08'W 62· 19'N 182 fiydro, Gas Matanuska REA None 807,418 .09 Electrfc Assocfatfon Tatftlek 146· 42' W 60· 52'N 68. Dfesel None BIA 170 31,567 1.324 Tazlina 146° 27'W 62· 04'N 27 Diesel Copper Valley REA 3700 119,7B2 1.028 .23 Electric Association Tetlin 142· 32'W 63· 08'N 107 Diesel None BIA 90 1.349 Tyonek 151· 08'W 61· 04'N 239 I1Ydro, Gas Chugach REA 423,000 1,061,291 .06 Electric Association Whfttier 148° 41'W 60° 46'N 198 fiydro, Gas Chugach REA 423,000 878,400 .06 Electric Association Thirty-four communities, primarily in the Southcentral region, purchase electricity from utilities. These communities were not included in the hydropower reconnaissance, but a summary of these communities listing the population, electric utility, and cost of power is provided in Appendix D. 3.2.1 Longevity of Diesel Generators The life expectancy of a diesel generator is influenced by a number of factors including size, number of total operating hours, daily and seasonal operating patterns, and frequency and quality of maintenance. Generators in size of up to 500 KW usually have a limit of 20,000 hours of conti nuous operati on before a major overhaul is requi red. The larger diesel generators (500-850 KW) have a longer operating period of 30,000 -40,000 hours before an overhaul is requi red. A generator can be overhauled three to four times. Given these values, a small diesel generator has a life expectancy of approximately 9 years, if operated continuously. Under these same maximum operating conditions, the larger generators that would be used in a utility power system have an expected life of about 18 years. Operating the generators only during the day and keeping one small generator on-line for summer use inc reases the expected 1 i fe of the system. For the pre 1 imi na ry screening, an investment cycle of 20 years was used to calculate the cost of diesel power. While the 1 ife expectancy of a diesel generator in isolated communities can be considerably less, a 20 year life expectancy represents a conservative estimate of diesel power costs. In Southcentral Alaska, diesel generators are not always maintained on a regular basis and conditions for maximizing the life of the machine are not optimal. The requirements of a diesel system are complicated further by the absence of local people to maintain the generators. In cases, where sending for a person from Anchorage to repair a generator is required, the time and expense involved may be a disincentive to properly maintaining a generator. 3. 2. 2 Co s t 0 f Po\ie r The cost of power varies greatly among the 42 communities in the study area. The disparity in electricity prices can be attributed to the size of the generating system, price of fuel, and size of fuel storage facilities. In general, communities that buy electricity from utilities have lower power rates than isolated communities. The small util ities that serve only one community charge higher rates than large utilities that serve multiple communitites since they are not able to achieve the economies of scale found in large power generating systems. In communities served by utilities, the price of electricity is not always simply the charge per kilowatt-hour. Utilities have up to three components in the price of electricity. The residential electricity rate schedule typically consists of a service charge (flat rate per month), an energy charge for the amount of electricity consumed (fixed rate per kilowatt-hour), and a fuel surcharge (fixed rate per kilowatt-hour) which is usually a fraction of the energy charge. Individual utility rate schedules are presented in Appendix A. 3-8 In isolated communities where diesel generators are owned and operated by private individuals, the price of electricity usually has just an energy charge, which covers the capital, operating, and maintenance costs and very little profit, if a/1Y. In native villages, the BIA owns, operates, and maintains the diesel generators that provide electricity to the schools and village council buildings. In some native villages, the BIA provides electricity to residences as well. In this case, the residential electricity price does not reflect the real cost of generating power since the government is subsidizing the power system. 3.3 CURRENT ELECTRICAL ENERGY REQUIREMENTS In the study area communities, electricity is used for lighting, small househol d appl i ances, and 1 a rge appl i ances such as refri gerators, freezers, televisions, and car heaters. The number and type of large appl iances are key variables affecting energy demand. Some households have washers, dryers and, in a few cases, electric hot water heaters, which are large electricity consumers. In addition to residences, buildings in rural villages that use electricity include the washeteria, school, and community building. In the larger communities, bui 1 di ngs that are el ectricity consumers i ncl ude stores, motel s, and restaurants. 3-9 4.0 PROJECTED ELECTRICAL ENERGY REQUIREME~JTS 4.1 FORECAST MODELS AND ASSUMPTIONS 4.1.1 Introduction Electric energy forecasting is a planning tool useful in evaluating the needs of a community in relation to the generating capability of a proposed hydroelectric project. In a centrali zed system without interties, electric energy demand is an important economic factor in assessing the appropriate size of project. The approach taken in this study toward forecasting demand is to use different scenarios of electric energy growth based on the current electric generating system and projected end use consumption. Villages that presently are supplied electricity from a central generation plant consume on the average more electricity per capita than do villages that have individual diesel generators. The villages not served by a uti 1 ity a re generally cha racteri zed by small er popul ati ons and fewer job opportunities. The models represent two load growth scenarios, in which consumption patterns of villages with decentralized or no electric generation lag behind those villages served by utilities. 4.1.2 Variables Used in Estimating Demand Va ri abl es that i nfl uence current and future e 1 ectri c energy demand are population, income, and infrastructure. These variables affect end uses of electricity, such as the number and type of household appliances, as well as consumption patterns over time. The historical fluctuations in population and economic activity of many of the remote villages in Southcentral Alaska make forecasting demand highly speculative. Electricity requirements can change radically through the introduction of new school or housing construction, which result from state and federal programs. In villages with unreliable or no diesel generators, electrification may affect locational preferences of residents (Alonso and Rust 1976). It is difficult to predict to what extent electrification will cause population growth, however, since source of income rather than the availability of electricity is probably the most critical variable affecting location decisions. A change in employment opportunities will affect the size of disposable income and, therefore, consumption patterns, as well as locational preferences of residents. 4.1.3 Forecasting Methodology Low and high electric energy projections have been calculated to reflect different levels of use of electricity. The low projection is based on the assumption that electricity would be used only for lighting and household appliances. The high projection represents the application of electricity to space heating in 3/4 of all residences as well as to lighting and appliances and domestic hot water. The low and 4-1 high projections delineate the bounds of electric energy consumption throughout the 1980-2030 period. In addition. a composite projection that averages the high and low projections has been calculated. The low growth projection is considered to be most representative of electric energy consumption patterns in the future. The present pattern of energy consumption is low. and is not expected to undergo substantial change in the future. The medium and high growth projections indicate possible futures in the event growth is induced by development. The availability of revenues from a project. local jobs with relatively high incomes. and the introduction of lifestyles at variance with the existing culture may lead to higher energy consumption. All three load forecasts are i ncl uded for each convnunity in Part I I of this report. Application of Electricity to Lighting and Appliances Most rural Alaskan villages have low per capita electric energy usage stemming from low incomes. Typically. the largest individual consumer is the school. Consumption in the residential sector accounts for approximately 10 percent of the total in rural villages and approximately 35 percent of the total in sub-regional centers. \Hth the introduction of lower priced electricity a potential exists for increased resi denti al consumpti on. Cu rrent end uses of el ectri c energy include lighting, small appliances, and large appliances such as refrigerators, washers, and televisions. If the price of electricity decreases substantially, more appliances such as dryers. freezers. and electric water heaters would be acquired. Acquisition of space heaters is unlikely, as explained in the following section. Assumptions used to forecast demand for lighting and appliances are presented in Tables 4-1 and 4-2. The assumptions were derived from a review of recent energy studies conducted for Alaskan communities and personal communication with Alaskan utilities. Documents of particular use were Alaska Power Administration 1979; Goldsmith 1980; Retherford 1981; Holden and Associates 1981; ISER 1976; CH2M Hill 1980; and Galliet 1980. The growth of electric energy consumption in the residential sector wi 11 va ry accordi ng to the current generati ng system. Residences served currently by a util ity consume approximately 5,250 kWh/year. Thi s val ue represents an average rate for consumers served by Al aska Village Electric Cooperative (AVEC) and Copper Valley Electric Cooperative (CVEA) for the year 1980. In comparison, residences served by individual small diesel generators consume approximately one-third of that amount, or 1,800 kWh/year. Rates of growth in the residential sector as well as the institutional and commercial sectors are presented in Tables 4-1 and 4-2. Using this methodology residential consumption in rural villages 'jn the year 2000 approaches present consumption of residences served by utilities. Communities that currently have no electricity will require several years to match the consumption patterns of communities that have <'f' ..• e 1 ec t ri city. 4-2 TABLE 4-1 FORECAST PARAMETERS -LIGHTING AND APPLIANCES TYPE A COMMUNITIES (NO CENTRAL GENERATION PLANT) AND TYPE C COMMUNITIES (NO ELECTRICITY TO RESIDENCES) Population Parameters (Common to Types A and C) Annual Increase in Population Persons per Household 1. 5 percent 4.5 Growth in Electricity Consumption (Common to Types A and C) Annual Increase in Energy in Residential Sector Growth Scenario: 1980 -19~ 1990 -2000 2000 -2020 2020 -2030 7 percent 5 percent 1 percent o percent Growth in Electricity Consumption per Household: Year 1980 19~ 2000 2010 2020 2030 Annual Increase in Growth Scenario: 1980 -19~ 1990 -2000 2000 -2030 Energy Use in Electric Energ,l Consumption b,l Sector Present Sector Type A T:Ype c Residential Institutional Commerci al Public Facilities Percentage 1980 ll9O" 10 percent 79 percent 6 percent 5 percent 4-3 ~ kWh ,lear) ~ kWh ,lear) 1800 0 3541 1800 5768 3541 6371 5768 7038 6371 7038 7038 Instituti ona 1 Sector (School s) Expected Change 1990-2030 2000-2030 2 percent 1 percent 0.5 percent Increase 84 percent Decrease 6 percent 10 percent TABLE 4-2 FORECAST PARAMETERS -LIGHTING AND APPLIANCES TYPE B COMMUNITIES (CENTRAL GENERATION PLANT) Popul ati on Parameters Annual Increase in Population Persons per Household Gro~/th in El ectri c ity Co nsumpti on Annual Increase in Energy in Residential Sector Growth Scenario: 1900 -19~ 1990 -2000 2000 -2020 2020 -2030 Growth in Electricity Consumption per Household: Year 1980 19~ 2000 2010 2020 2030 Annual consum~tion ( kWh/year 5,250 7,056 8,601 9,982 11,584 11,584 1.5 percent 3.5 3 percent 2 percent 1.5 percent o percent Annual Increase in Energy Use in Institutional Sector (Schools) Growth Scenario: 1900 -1990 1990 -2000 2000 -2030 El ectri c Energy Consumpti on by Sector Sector Residential Insti tuti onal / Public Facilities Commerci al 1980 35 percent 55 percent 10 percent 4-4 1990-2030 Increase Decrease 10 percent 2 percent 1 percent .5 percent 90 percent Application of Electricity to Space Heating The use of electricity for residential space heating in Alaska is unlikely due to the significant heating requirements and the higher cost of electricity than alternate sources such as fuel oil, wood, coal, and peat. Wood and coal are available in varying quantities throughout Southcentral Alaska and their use will depend on long term supply. The substitutabil ity of electricity for other sources of heat has therefore been assessed separate from other applications of electricity. The use of electric space heating in the study area is very unlikely but will depend on the price of electricity, income of household, and the price of substitutes. The electric energy requirements for space heating in Alaska are substanti a 1. In compa ri son to Seattl e, el ectri c energy requi rements for space heating are approximately twice as great in Alaska. Annual el ectri c energy requi rements for si ngl e fami ly residences are presented in Table 4-3. These values may exceed space heating requirements of residences in the study area since houses in the remote communities have on the average less area to heat than houses in urbanized areas, from which these values were derived. The end use of electricity for space heating in the high scenario has been assumed to remain constant throughout the study period. 4.2 PROJECTED DEMANDS The low energy demand was used as a basis for slzlng the hYdropower projects and comparing the costs of hYdropower to alternative power, for the reasons given in Section 4.1.3. The projected energy demands for each community were calculated on the basis of the assumptions presented above and 1980 census data, and are presented in Table 4-4. For the purpose of sizing projects to serve intertied communities, the aggregate demand of study area communities was used as a basis. In such situations, since the transmission lines are already in place, one project could serve the entire system. For isolated communities with village or individual generators, projects were sized according to the community demand. TABLE 4-3 ELECTRIC SPACE HEATING REQUIREMENTs!/ Location Anchorage -Kenai Peninsula Glenallen -Valdez Y Goldsmith and Huskey 1980. 4-5 kWh/single family residence/year 28,700 31,700 TABLE 4-4 SUMMARY OF PROJECTED ELECTRICAL ENERGY ANNUAL PEAK DEMANoll (kW) Sbeet ] cf 2 Cormnuni t,l: 1990 1997 2000 2010 2020 2030 Broad Pass 19-19 23-35 24-42 27-68 31-78 34-89 Cantwell 185-185 218-335 232-399 259-648 292-743 319-843 Cape Yakataga 76-76 99-140 108-167 136-272 152-309 171-354 Chickaloon 85-85 100-143 106-167 128-269 156-320 174-365 Chistochina 87-87 113-160 124-191 156-311 174-355 196-406 Chitina 49-49 57-79 61-91 68-139 77-159 84-179 Copper Center 423-423 495-728 526-859 632-1406 771-1670 864-1907 Ell ama r 73-73 95-134 104-160 130-260 146-296 164-339 Eng1 i sh Bay 248-248 290-414 308-486 371-782 452-930 507-1061 Eska 105-105 123-176 131-206 157-332 192-394 215-450 Eyak 6-6 7-10 7-12 9-20 11-24 12-27 Ferry 61-61 72-121 76-147 92-255 112-302 126-346 Gakona 50-50 58-85 62-101 74-165 90-196 101-224 Gu1kana 220-220 258-379 274-448 329-733 402-870 450-994 Ha 1 i but Cove 119-119 139-199 148-233 178-375 217-446 243-509 Hope 101-101 118-169 126-198 151-319 185-379 207-433 Jonesvil1 e 192-192 225-322 239-377 288-607 351-722 393-823 Kachemak 799-799 936-1336 994-1566 1195-2522 1458-2998 1634-3421 Kenney Lake 198-198 232-331 247-389 297-626 362-744 405-849 Knik 20-20 23-23 25-39 30-63 36-74 41-85 Meakerville 595-595 697-1026 740-1210 890-1981 1086-2352 1216-2685 Mentasta Lake 119-119 154-247 169-301 212-519 237-594 268-681 Montana 77-77 91-129 96-152 116-244 141-290 158-331 Nabesna 64-64 82-116 90-139 113-226 127-258 143-295 New Chenega 146-146 189-260 207-309 260-496 291-564 328-645 Northway 744-744 871-1466 925-1776 1112-3087 1357-3648 1520-4179 Paxson 47-47 55-75 59-88 65-133 74-153 81-172 Port Graham 321-321 376-537 400-629 480-1014 586-1205 657-1375 Rainbow 40-40 46-66 49-78 59-125 72-149 81-170 11 The range of peak demands given for each community correspond to low and high growth scenarios. 4-6 TABLE 4-4 S~~ARY OF PROJECTED ELECTRICAL ENERGY ANNUAL PEAK DEMANol1 (kW) Sheet 2 of 2 Conwnuni t~ 1990 1997 2000 2010 2020 2030 Seldovia 950-950 1112-1588 1182-1861 1421-2998 1734-3564 1942-4066 Skwentna 25-25 33-45 36-54 45-86 51-98 57-112 Sl ana 19-19 25-35 27-42 34-68 38-77 43-89 Suntrana 161-161 188-317 200-384 240-667 293-788 328-903 Susitna 67-67 86-119 95-141 119-226 133-258 150-295 Sutton 151-151 176-252 188-295 225-476 275-565 308-645 Talkeetna 361-361 423-603 449-707 540-1139 659-1354 738-1545 Tatitlek 108-108 140-198 153-236 192-385 215-438 243-502 Taz1ina 54-54 63-92 67-109 80-178 98-212 109-242 Tetlin 170-170 220-352 241-430 303-741 338-847 382-972 Tyonek 474-474 555-792 590-929 709-1496 865-1778 969-2029 Whittier 393-393 460-656 489-769 587-1239 717-1473 803-1681 4-7 5.0 SCREENING OF COMMUNITY HYDROELECTRIC POTENTIAL 5.1 SCREENING CONCEPT The objectives of applying a preliminary screening process were Uto select from a large number of identified hydroelectric sites those that demonstrated potential, and 2)to identify communities with potential sites that warranted a field visit. The procedure used to screen sites was based on a set of engineering, hydrologic, and economic criteria. The preliminary screening procedure resulted in narrowing the number of Southcentral communities with potential hydroelectric sites from 42 to 33. Each of these thirty-three communities could be served by at least one hydro site with a preliminary benefit/cost ratio greater than one, which indicated the economic merit of hydroelectric power compared to the existing method of power generation over a 50-year period. Fourteen communities were visited by the study team. 5.2 PRELIMINARY SCREENING 5.2.1 Drainage Basin Inventory and Engineering Analysis The initial selection of potential hydroelectric sites involved an inventory of drainage basins using u.S. Geological Survey topographic maps at a scale of 1:250,000. A 15-iT1ile radius around each community generally defined the outer limits for identifying a site. This distance was generally used to limit the study area for each community principally because of the economics of transmission lines and access requi rements for small hydro developments. However, potenti ally attractive sites as far as 25 miles from a community were included in the screening where no suitable sites were found within the 15-iT1ile radius. For each community, approximately six sites located within the radius were selected for further investigation. The most promising sites were selected in a logical manner, beginning with the principal river or stream and then examining the smaller tributaries~ Each site was sized to meet the following criteria: o 80 percent of the low demand scenario in year 2030, approximately equal to average day peak demand; o Sites which could serve intertied communities were sized based on the aggregate demand of the communities; For each site selected, the following features were identified on the maps: o Site identification number o Drainage basin boundaries and area above damsite o Dam and powerhouse location 5-1 o Penstock route o Transmission line route A more detailed discussion of the preliminary screening methodology is presented in Appendix B. 5.2.2 Hydrologic Analysis Because r,lQst of the streams i dentifi ed as potenti al hydropower sites are ungaged, a method of estimating flows in these streams was necessary. For i niti al power potenti al and si te screeni ng purposes, estimates of streamflow were made by assuming that flow is proportional to drainage basin area and by using values of average runoff per unit area (given in cfs/mi2) derived by Balding (1976). Drainage basin areas were estimated from 1:250,000 USGS topographic maps using pl animetric techni ques, and these values were multipl ied by the runoff per unit area values obtained from Balding (1976), which are given in the form of isoline maps, to obtain mean annual streamflow. Only the single value of mean annual streamflow was used in the initial sc reeni ng phase. 5.2.3 Economic Analysis The economic analysis methodology used in this study is presented, along with a site-specific example, in Appendix C. The following paragraphs provide a more general summary of the economic analysis used in the preliminary screening phase. 8enefit/cost ratios were calculated for each potential site identified in the drainage basin inventory and preliminary screening. The objective of the analysis was to compare the economic viability of hydroelectric sites based on conceptual costs to the cost of alternative power. Plant sizes were based on low electric energy growth projections. Fuel costs of alternative power were escalated at rates of 0, 2. and 5 percent. A discount rate of 7-5/8 percent was applied to the costs of both hYdroelectric and alternative power. Cost of Hydroelectric Power For each of the sites identified in the map reconnaissance, costs were estimated for the major components and then summed to provide a total estimated capital cost. The project components for which separate cost estimates were developed include generation equipment (including the powerhouse structure), penstocks, dams and mobilization, and transmission facilities. Annual costs for each site were developed using an interest rate of 7-5/8 percent for project financing over a 50-yea r peri od, i ncl udi ng an allowance for operati on and mai ntenance costs. The average annual cost of energy for each site was then based on the annual cost of the project and the estimated annual energy output. 5-2 Oiesel Alternative A stream of diesel costs in $/kWh were calculated for all isolated and potentially intertied communities based on annualized capital, operating and maintenance costs and, in the case of potential interties, annualized transmission costs. Two investment streams were calculated employing an average cost methodology and based on an interest rate of 7-5/8 percent. The capital costs were multiplied by a capital recovery factor of .0991 for the 20-year investment cycle. Replacement of the diesel generator after each 20 year increment was assumed. The assumption of a 20-year investment cycle and a 5 percent fuel escalation rate were used to calculate diesel costs for the first screening. For the potential intertied communities, transmission costs were annualized based on a capital recovery factor of .07823 for a 50-year investment cycle. Other assumptions were used in calculating diesel generation costs. Diesel generators were sized for peak hour of the final year of their useful life (20th year), assuming the demand at that time would be 1.5 times greater than average demand. The factor of 1.5 was derived from load curves suplied by Alaska Village Electric Cooperative (AVEC). A diesel heat rate of 12.4 kWh/ gallon was used to calculate fuel requirements.l/ Operating time was assumed to be 4380 hours per year, or half time on the average. Capital costs varied with size ($225/kW-$525/kW) and maintenance costs were assumed to be 6 percent of installed capital costs. Combustion Turbine Alternative The alternative to hydropower was assumed to be combustion turbines for those cOlllTlunities served by Golden Valley Electric Association. The assumptions used in the economic analysis of combustion turbine power generation were the following: 25 year investment cycl e heat rate of 10,800 Btu/kWh capital cost of $720/kW for turbines 5-50 MW in size o and M cost of $0.005/kWh 5.2.4 Screening Results Benefit/cost ratios which use average cost values were developed for screening purposes. The benefit-cost ratio is defined as the costs of the most l'ikely alternative method of power generation (diesel, 1/ A heat rate of 12.7 kWh/gallon was derived from data provided by Caterpillar Products and Sales Services. A value of 12.4 kWh/ gallon was used as a conservative estimate of the diesel heat rate. 5-3 The average ratio was taken for the cost of power generated during the 1981-2030 period. A B/C ratio greater than 1.0 indicates that the hydro site is worthy of further consideration. Six sets of benefit/cost ratios were examined, including 0, 2 and 5 percent fuel escalation, with and without the capital costs of alternative power included. Benefit/cost ratios based on fuel escalation but excluding the capital costs of the diesel generators were included as part of the analysis since it can be assumed that hydropoHer can suppl ement the ex i sti ng generati ng system but not replace it. Since hYdropower would be unlikely to meet 100 percent of the demand throughout the year, diesel generators would be used as standby power. Based on a 5 percent fuel escalation, and including the capital cost of alternative power, the results of the preliminary screenin~ indicate that 4 communities have no alternative hYdroelectric sites whlle 38 communities survived the screening. When the capital costs of alternative power were excluded from the analysis, 33 cor.ullunities survived the screening. This is because the capital costs of diesel generators are a relatively important component of total costs; hydroelectric development is less attractive in comparison to diesel alternatives when it is assumed that diesel generators would be needed for standby power. Thirteen of the 33 communities that have sites with B/C ratios greater than 1.0 were further investigated during a field reconnaissance. In addition, New Chenega which has sites with B/C ratios less than 1.0 was visited due to its unique situation as a new town. A list of study area communities grouped into these three categories is presented in Table 5-1. As explained in the following chapter, communities which had at least one site with a benefit-cost ratio greater than 1.0 were included in the detailed study phase, the results of which are presented in Tab 1 e 1-1. 5-4 Si tes Wi th No Potential Cape Yakataga Chistochina Chitina Nabesna Paxson Skwentna Vi 11 age Slana Susitna TABLE 5-1 SUMMARY OF COMMUNITY HYDROPOWER POTENTIAL SOUTHCENTRAL REGION Potential Sites/ Not Visited Copper Center E11amar English Bay Eska Eyak Ferry Gakona Gu1kana Hope Jonesvi 11 e Kenney Lake Knik Meakervi11e Montana Rainbow Sutton Suntrana Talkeetna Tatitlek Tyonek Potential Sites/ Field Reconnaissance Broad Pass Cantwell Chickaloon Ha 1 i but Cove Kachemak Last Tetlin r4entasta Lake New Che neg a..!/ Northway Port Graham Seldovia Taz1ina Tetlin \~hittier 1/ Sites for New Chenega did not survive the preliminary screening, but the community was added to the site reconnaissance list by the Alaska District. 5-5 6.0 DETAILED INVESTIGATIONS Communities which had at least one site with a benefit-cost ratio greater than 1.0 were included in the detailed study phase. Each site to be studied was selected on the basis of field observations or study of more detailed (1:63,560-scale) maps. In a few instances, detailed map study indicated unfavorable conditions which could not be seen in the preliminary screening, and such sites were not included in the detailed investigations. This chapter provides information regarding the procedures employed in conducting the detailed investigations. 6.1 FIELD RECONNAISSANCE At each community visited, as many of the candidate sites were observed as possible. Use of helicopters allowed inspections from the air and on the ground. Initially, the intent had been to inspect only the sites at each community ranked highest during the preliminary screening, with the dam sites inspected from the ground and stream and valley section measurement made at one or both sites. However, the field inspection revealed several anomalies, including occasionally pronounced differences in the runoff observed on north versus south-facing basins, the disappearance of stream flow into floodplain gravels or complete absence of flow in some basins. In addition, community leaders consistently expressed a desire for a supply of hYdropower during the winter season. This led to reconsideration of and visits to larger streams with potential for more adequate winter flow. The field reconnaissance revealed significant differences in stream cross-sections, bed material, and sediment type and ~ovement. In or adjacent to the Kenai Peninsula, say on Evans Island, and in the high-elevation Nenana tributaries, the flow generally was over exposed bedrock and/or had relatively dense vegetated banks that contribute very little sediment to the flow. None of the streams in the study area flow over loose volcanic ash, particularly suited to use of sheet pil e dams. In the foothills of the Alaska Range, alpine streams fed by glaciers are common. These streams can be grouped into two sub-types, here called "braided" and "torrential". Both types require speCial considerations in the type of diversion dam and intake selected. The libra i ded" streams typically consi st of several narrow acti ve channel s within a broad channel, up to 300 foot wide, composed of 2 to 12 inch sized gravel and small boulders. Typically a gravel terrace, two or three feet higher than the channel, extends for 100 to 200 feet on one or both sides. This gravel terrace floodplain in most cases is covered with vegetation. A diversion structure for this type of stream would have to extend the entire valley width. An important consideration is the danger of potential undennining of a surface type dam versus the probably greater expense of excavating and constructing the structure down to bedrock. 6-1 The "torrential" alpine streams mayor may not exhibit the slightly raised floodplain terrace. The main stream channel might typically be only 30 to 80 feet wi de, with a bed of 1 a rge gra ve 1 and up to 2 foot size boulders. This material can be readily visualized as quickly piling up against and overflowing any low to medium height diversion dam. Spring floods deposit this material in their runout plains, miles further downstream, and in the process build up continuous windrows on either side, thus confining their own course. It was decided that the intake on a torrential stream should be located 50 to 100 feet upstream of the dam, thus avoiding the deposited sediment wedge at the dam. Scour pipes through the dam would be provided, but it is doubtful that much gravel would be flushed on either the "braided" or "torrential" st reams. Although storage type hydro projects were not considered to be economically feasible for isolated communities or for small intertied systems, note was made of site suitability for storage projects in general. The same approach was followed for the handful of communities already forming part of a larger system, limiting the present study to projects not exceeding in design capacity the 1997 community load demand. The attractive potential storage sites identified are summarized in Table 6-1. 6.2 HYDROLOGIC ANALYSIS The detailed analysis of the most promlslng potential hydropower sites required more accurate estimation and more complete description of streamflm'l than was done for the initial screening phase (Section 5.2.2). The basis of the procedure was the assumption that runoff per unit area in an ungaged stream \</as equal to runoff per unit area in a nearby representative gaged stream, scaled by the ratio of mean annual precipitation for the ungaged and gaged basins. That is, Q2/A2 = (Q1/A1}(P2/P1) where the subscr'ipts 1 and 2 refer to gaged and ungaged basins, respectively, and Q = overall mean monthly or annual streamflow A = drainage basin area P = mean annual precipitation for basin The factor P2/P1 adjusts for differing water inputs to the gaged and ungaged basins and includes any effects due to elevation differences between the basins. (1) The complete records of mean daily flows for all current and discontinued gaged streams in Southcentral Alaska were obtained from the U.S. Geological Survey on magnetic tape. From these, stations were selected for pairing with ungaged basins, based on geographical proximity and correspondence of characteristics such as basin area, percent of area glaciated, and general topography. These stations are listed in Table 6-2. For each of these stations, mean flow for each 6-2 CoIIITI unity Halibut Cove Whittier Tyonek Kenney Lake Knik Mentasta Lake TABLE 6-1 POTENTIAL STORAGE SITES SOUTH CENTRAL REGION Site Number Stream 4 Ha 1 i but Creek 3 Placer River 4 Chuitna Ri ver 1 Tonsina River Tributary 3 Wi 11 ow Creek 1 Right Tributary to Slana River 6-3 Potential Dam Height (feet) 30 50 40 100 100 100 TABLE 6-2 GAGED STREAMS USED FOR BASIN PAIRING Sheet 1 of '- Station Station Drainage Mean Mean Length of Number Name Area Annual Annual RecordQ/ (mi 2) Preci pitati on Flow (i nche s) (cfs}2/ 15208100 Squi rrel Creek 70.5 12 34.0 1O(66-75) at Tonsina 15219000 West Fork 01 sen 4.78 140 32.5 15( 65-79} Bay Creek nea r Cordova 15238820 Ba rba ra Creek 20.7 40~./ 84.8 7(73-79} near Sel dovi a 15239880 Twi tter Creek 16.1 30 24.8 2( 72-73} near Homer 15254000 Crescent Creek 31. 7 50 79.6 17( 50-66} near Cooper Landi ng 15272550 Glacier Creek 62.0 80 289 13( 66-78} at Gi rdwood 15274000 South Fork 30.4 22 37.9 24( 48-71} Campbell Creek near Anchorage 15276000 Shi P Creek 90.5 34 1592./ 33(47-79} near Anchorage 15290000 Little Susitna 61. 9 50 208 17( 63-79} River near Palmer 15294005 Wi 11 O~I Creek 166 45 390 l( 79} near Willow 15294450 Chuitna Ri ver 131 28 333 4(76-79} near Tyonek 15476~0 Berry Creek 65.1 18 50.0 8(72-79} nea r Dot Lake 15515000 Seattle Creek 36.2 20 42.2 10(66-75} near Cantwell . .e' 6-4 TABLE 6-2 GAGED STREAMS USED FOR BASIN PAIRING Sheet 2 of 2 a/ Mean annual flow during gaging period multiplied by flow adjustment factors presented in Table 6-3. E./ Complete water years only. Number of years is given with the years of record in parentheses. c/ The isohYets in Lamke (1979) for the part of the Kenai Peninsula south of Kachemak Bay appear to be somewhat erroneous. The mean annual flow that would result from 100 percent runoff of the 40 in/yr of precipitation estimated for Barbara Creek from the map in Lamke (1979) would be less than the gaged mean annual flow. The most likely explanation is that the precipitation value is too low. The iso~etal map could very likely be in error in this area, as a high precipitation gradient is present due to strong orographic effects. Barbara Creek was paired with three streams in this area of the Kenai Peninsula (see Table 6-4), and a similar underestimation of mean annual precipitation was assumed to occur for the ungaged streams as occurred for Barbara Creek. The flo\'IS estimated for the ungaged streams are still valid, however, because the flow estimates are dependent only on the ratio of the precipitation for the two basins, not the actual magnitudes. A consistent underestimate of precipitation for gaged and ungaged basins does not, therefore, produce erroneous flow estimates for the ungaged streams. ~ A diversion exists just upstream of the gage. Value given is adjusted to include diversion. 6-5 month and year of record, overall mean monthly and annual flows for the entire period of record, and a flow duration curve were calculated from the dai ly data. Only data for complete \'/ater years were used in the computations. Due to the relatively short period of record for many of the gaged streams and the fact that many recorded years could not be considered "normal" but rather high or low flow years, the development of flow adjustment factors \'ias necessary to define Q1 in Equation 1 properly. The factors were developed using long-term precipitation data. Each gaged stream was paired with a nearby representative long-term precipitation station, which was used as an index to average basin precipitation. The long-term mean annual rainfall from this station was divided by the mean annual rainfall that occurred during the stream gaging period. This factor was multiplied by the overall mean monthly and annual flows calculated from the streamflow data to obtain "nonnal" mean flows. That is, Q1 = (Q1*)(AP/GP) where Q1 = "nonnal" mean monthly or annual flow Q1* = mean monthly or annual flow calculated from streamflow records AP = long-term mean annual precipitation at index station GP = mean annual precipitation at index station during stream gagi ng peri od (2) The flow adjustment factors for the gaged streams used for basin pairing are listed in Table 6-3, and the adjusted mean annual flows are given in Table 6-2. After each ungaged stream identified as a potential hydroelectric site was paired with a gaging station, the precipitation scaling factor was derived and applied to the streamflow data for the gaged stream to obtai n mean flows for the ungaged stream. The precipitation factor (P /P 1 in Equation 1) required knowledge of basin-wide mean annual precipitation for gaged and ungaged basins. This information is available in Lamke (1979). In this regression study of regional flood characteristics, mean annual precipitation was determined for many Al askan gaged streams. Al so i ncl uded in thi s report are i sohyetal maps covering the entire state, which were used by Lamke in determining mean annual precipitation. For the present study, these maps were used to obtain mean annual preCipitation for all ungaged basins as well as for any gaged basi ns used for pai ri ng that di d not have a mean annual precipitation val ue al ready reported by Lamke. Mean annual precipitation for gaged streams used for basin pairing are given in Table 6-2, and values for potential hydropower sites are given in Table 6-4 and on the significant data sheets accompanying each community's detailed description. The isonyetal maps from Lamke (1979) used in this study are given in Figures 6-1 and 6-2. 6-6 -~- ,.. ~. TABLE 6-3 FLOW ADJUSTMENT FACTORS FOR GAGED STREAMS USED IN BASIN PAIRING Stream Index Precipijation FactorE/ Stati on! SqU"j rrel Creek Gul kana 1.10 West Fork Cordova 1.01 01 sen Bay Creek Ba rba ra Creek Homer 0.87 Twi tter Creek Homer 1.17 Crescent Creek Seward 1.05 Gl ac i er Creek Anchorage 1.09 South Fork Anchorage 0.99 Campbell Creek Shi p Creek --s./ 1.00 Little Susitna Matanuska Agricul tu ral 1.03 River Experiment Station Wi 11 ow Creek MatanlJska AgriclJl tlJral 0.90 Experiment Station Chuitna River Anchorage 0.89 Berry Creek Big Delta, Northway£/ 1.12 Seattl e Creek McKinley Park, Talkeetn~/ 1.00 ~/ National Weather Service stations as given in U.S. Environmental Data Service (NOAA) Climatoligical Data. ~/ Factor = AP/GP in Equation 2 in text. c/ Gaging station has more than 30 years of record and can be considered to be a long-term station (same definition as for precipitation stations). No flow adjustment is, therefore, necessary. d/ Factors obtained from two representative stations were averaged. 6-7 en I CD .' '. ':) ..... ,"~ ,---''------''----''-'-'--''-'-'----'-":-:.:~----r--.--.. -.-.4 .. - "'''''.!:, .'.1." •.... ';. Fi gure 6-1. 1';1; 1.;1 Mean annual (Source: precipitation Lamke 1979) and mean minimum January temperatures in Cook 1', :Jet, COOK INLET AREA '; J "1 LE S L ___ l I ._ i. ____ -.:J 14tl' Inlet area. en I <D G U I.F OF ALASKA GULF OF ALASKA AREA (; ~UI!ILES r' __ ,1cc,=cl',_, ,T'c'o'-i __ :,~ The drainage areas of the ungaged streams (A2 in Equation 1) were determined by locating the dam sites on 1:63,360 USGS topographic maps, outlining the drainage basins contributing runoff to those points, and pl animeteri ng the resul ti ng areas. Orai nage areas for gaged streams were given in the station descriptions accompanying the USGS flow data. Drainage area data are given in Tables 6-2 and 6-4 and the comr,lunity significant data sheets. Tile procedures described above were used to derive values for 01, AI, A2, PI, and P2 in Equation 1. The solution to Equation 1 was labeled 02, the mean flow for the ungaged stream. This was done for all ungaged streams to obtain overall mean flows for each month of the year and to obtain the overall mean annual flow of the stream. Further descri pti on of streamflow in the ungaged streams was obtai ned using dimensionless annual flow duration curves calculated from the USGS daily streamflow data for the gaged streams. Since the curves were dimensionless (the ordinate was flow divided by mean annual flow), they could be applied to the paired ungaged streams. Once the mean annual streamflow for an ungaged stream was detennined as outlined in the procedure given above, the ordinate of the flow duration curve was multiplied by this value to obtain a flow duration curve for the ungaged stream. Flow duration curves for the gaged streams used for pairing are given Figures 6-3 through 6-14. The flow duration curves were used to detennine plant factors for hydropower projects for util ity-served cOlllT1unities. For these communities, it could be assumed that any energy in excess of community demand could be routed into the utility grid and sold. Therefore, a standard flow duration curve analysi s to detenni ne percent of total flow that is usable was appropriate. This percent was only dependent on powerplant machine limitations. On the other hand, a flow duration cu rve ana ly sis wa s i napp rop ri ate fo r p raj ects servi ng i so 1 ated communities not within a utility grid because the energy available for which there was no demand could not be sold elsewhere. This reduced the percent of total flow that is usable below the value due strictly to powerplant machine limitations. For these communities, mean monthly streamflows were used instead of the flow duration curve to estimate flow availability. These flows were used in a computer program that calculated a plant factor by comparing energy availability to demand. The procedures for determining plant factors are described in more detail in Section 6.3. The methodology descri bed above can be expected to gi ve reasonabl e estimates of mean annual flow and the flow duration curve but less accurate estimates of mean monthly flows for ungaged streams. This is because a number of variables have a significantly greater effect on monthly flows than on annual flow. Factors such as orientation of slopes (i.e., north or south-facing) and percent of drainage area glaCiated have a large effect on the monthly distribution of flow. For example, streams draining primarily north-facing slopes or glaCiated basins have their peak runoff period a month or two later in the year than do streams draining south-facing slopes or unglaciated basins. These factors have a much smaller effect on annual flow. In a basin 6-10 TABLE 6-4 BASIN PAIRINGS AND HYDROLOGIC CHARACTERISTICS OF POTENTIAL HYDROPOWER SITES Sheet 1 of , Estimated Drai nage Mean Mean Pai red Site Are~ Annual al Annual Gaged (mi ) Precipitation-Flow Stream (i nc hes) (cfs) Ca ntwe 11 IB road Pass 14.9 40 34.7 Seattle Creek Site 5 Chickaloon 99.0 60 399 Little Susitna Site 12 River Ha 1 i but Cove 18.9 6o.e.I 116 Barbara Creek Site 4 Kachemak 6.9 30 10.6 Twitter Creek Site 3 Mentasta Lake 3.3 30 4.2 Berry Creek Site 1 New Chenega 0.5 160 4.0 Crescent Creek Site 5 Northway 28.9 20 24.7 Berry Creek Site 3A Po rt Gra haml 5.8 4QbL 23.8 Barbara Creek Engl i sh Bay Site 5 Seldovia 6.4 6o.e.I 39.3 Ba rba ra Creek Site 4 Tazlina 21.3 9 7.7 Squirrel Creek Site 4 Tetl i n/Last 27.6 10 11.8 Berry Creek Tetlin Village Site 14 6-11 TABLE 6-4 BASIN PAIRINGS AND HYDROLOGIC CHARACTERISTICS OF POTENTIAL HYDROPOWER SITES Sheet 2 of 3 Estimated Drai nage Mean Mean Pa ired Site Are~ Annual a/ Annual Gaged (mi ) Precipitation-Flow Stream (i nc hes) (cfs) Whitti er 20.8 120 145 Glacier Creek Site 3 Hope 4.0 25 5.7 South Fork Site 1 Campbell Creek Rainbow 75.0 35 136 Shi P Creek, Site 5 South Fork Campbell Creek~./ Tyonek 108 29 284 Chuitna River Site 4 Copper Center 149 30 Site 16 180 Squi rrel Creek Gakona/Gul kana 35.9 30 ·43.3 Squi rrel Creek Site 3 Kenney Lake 7.8 13 4.1 Squirrel Creek Site 1 Meakervi 11 e/ 1.7 160 13.2 West Fork Eyak Site 6 01 sen Bay Creek Eska/Jonesville/Sutton 45.4 20 61.0 Little Susitna Site 6 River Knik 146 50 381 Wi" ow Creek Site 3 Montana 39.0 50 102 Wi" ow Creek Site 1 6-12 TABLE 6-4 BASIN PAIRINGS AND HYDROLOGIC CHARACTERISTICS OF Site Talkeetna Site 4 Ellamar/Tatitlek Site 2 Ferry /Suntrana Site 5 POTENTIAL HYDROPOWER SITES Estimated Drai nage Mean Mean Are~ Annual a/ Annual (mi ) Precipitation-Flow (i nc hes) (cfs) 35.0 35 64.0 1.7 100 8.3 87.0 40 203 Sheet 3 of Pa ired Gaged Stream Wi 11 ow Creek West Fork 01 sen Bay Cree Seattle Creek a/ The mean annual precipitation values presented are for the cited drainage basin, estimated from ishoyetals in Lamke (1979) • .Q./ The isohYets in Lamke (1979) for the part of the Kenai Peninsula south of Kachemak Bay appear to be somewhat erroneous. The mean annual flow that would result from 100 percent runoff of the 40 in/yr of precipitation estimated for Barbara Creek from the map in Lamke (1979) would be less than the gaged mean annual flow. The most likely explanation is that the precipitation value is too low. The isohYetal map could very likely be in error in this area, as a high precipitation gradient is present due to strong orographic effects. Barbara Creek was paired with three streams in this area of the Kenai Peninsula, and a similar underestimation of mean annual precipitation was assumed to occur for the ungaged streams as occurred for Barbara Creek. The flows estimated for the ungaged streams are still valid, however, because the flow estimates are dependent only on the ratio of the precipitation for the two basins, not the actual magnitudes. A consistent underestimate of precipitation for gaged and ungaged basins does not, therefore, produce erroneous flow estimates for the ungaged streams. EI Ship Creek has a diversion just upstream of the gage. Values of mean monthly and annual flow adjusted to include the diversion are given in the yearly volumes of USGS Water Resources Data for Alaska. Adjusted daily values, however, are not given. Ship Creek data could therefore be used to estimate mean annual flow at the dam site, but they could not be used to determine a flow duration curve. The flow duration curve for South Fork Campbell Creek was used. 6-13 ~ 0 ...J ~ Z 4: ~ ~ ...... ~ 0 ...J ~ 4.0 :3.5 :3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW: 34.0cfs DRAINAGE AREA = 70.5 mi 2 O~----~------~------~------~-----+-o 20 40 60 80 100 PERCENT CE TIME F-1.OW IS EQUALED OR EXCEEDED REGIONAL INVENTORY & RECONNAISSANCE STUOY SMAU ~YOROPOWER PIlOJECTS SOUTH CENTRAL ALASKA FIGURE 6-3 FLOW DURATION CURVE FOR SQUIRREL CREEK AT TONSINA ~----------------------------~ 6-14 DEPARTMENT OF THE ARM"f ALASKA DISTRICT CORPS OF ENGINEERS ~ 0 ..J IJ.. ~ IAJ :! ..... ~ 0 ..J IJ.. 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW = 32.5cfs DRAINAGE AREA = 4.78 mi 2 O~----~------~------~------~----~ o 20 40 60 80 100 PERCENT CF TIME FLOW 15 EQUALED OR EXCEEDED REGIONAL INVENTORY &. RECONNAISSANCE STUOY SMALL HYOROPOWER PROJECTS sOUTHCENTRAL ALASKA FIGURE 6-4 FLOW DURATION CURVE FOR WEST FORK OLSEN BAY CREEK NEAR CORDOVA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ~ 9 ~ z ~ La.! :I ........ ~ 0 -oJ ~ 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW : 84.8 cfs DRAINAGE MEA : 20.7mi 2 O+-----~------~----_r------~----~ o 20 40 60 80 100 PERCENT ~ TIME FLOW IS EQUALED OR EXCEEDED REGIONAL INVENTORY & RECONNAISSANCE STUOY SMALL HYOROPOWER PflOJECTS SOUTHCENTRAL ALASKA FIGURE 6-5 FLOW DURATION CURVE FOR BARBARA CREEK NEAR SELDOVIA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS 3: 0 ~ LI. ~ "'-I ::2 ...... 3: 0 ~ LI. 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW =24.8 cfs DRAINAGE AREA = 16.lmi 2 0~ ____ ----~--__ ----__ --~1 o 20 40 60 80 100 PERCENT CF TIME FLOW IS EQUALED OR EXCEEDED REGIONAL INVENTORY &. RECONNAISSANCE STUOY SMALL HYQAOPOweR PROJECTS SOUTH CENTRAL ALASKA FIGURE 6-6 FLOW DURATION CURVE FOR TWITTER CREEK NEAR HOMER DEPARTMENT OF THE ARM'f ALASKA DISTRICT CORPS OF ENGINEERS ~ 0 ..J Ll- Z « LLI :2 ....... ~ 0 ..J LI- 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW = 79.6 cfs DRAINAGE AREA = 31.7 mi 2 O~----~------~------~------~-----+-o 20 40 60 80 100 PERCENT CE TIME FLOW IS EQUALED OR EXCEEDED ~-IA REGIONAL INVENTORY & RECONNAISSANCE STUDY SMAU ~YDROPOWER PROJECTS SOUTH CENTRAL ALASKA FIGURE 6-7 FLOW DURATION CURVE FOR CRESCENT CREEK NEAR COOPER LANDING DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ~ 0 ...J "'- ~ LIJ ~ ...... ~ 0 ...J "'- 4.0 :3.5 :3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW = 289cfs DRAINAGE AREA =62.0mi 2 O?-----~------~------T_------~----_+_ o 20 40 60 80 100 PERCENT CF TIME FLCJN IS EQUALED OR EXCEEDED REGIONAL INVENTORY &. RECONNAISSANCE STUDY SMAU HYOROPOWER PROJECTS SOUTHCENTRAL ALASKA FIGURE 6-8 FLOW DURATION CURVE FOR GLACIER CREEK AT GIRDWOOD DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ~ 9 LI.. ~ IJJ ::E ........ ~ 0 ..J LI.. 4.0 3.5 3.0 2.5 2. 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW = 37. 9cfs DRAINAGE AREA = 30.4 mi2 O~----~------~----~------~------~ o 20 40 60 80 100 PERCENT OF TIME FLC1N IS EQUALED OR EXCEEDED REGIONAL INVENTORY & RECONNAISSAMCE STUDY SMAll HYOROPOWER ""OJECTS SOUTH CENTRAL ALASKA FIGURE 6-9 FLOW DURATION CURVE FOR SOUTH FORK CAMPBELL CREEK NEAR ANCHORAGE DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS ~ 9 ~ i L&.I :2 ...... ~ ..J ~ 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED Pw£AN ANNUAL FLOW :: 208 cfs DRAINAGE M£A :: 61.9 mi 2 O~----~------~------~----~-------+-o 20 40 60 80 100 PERCENT ~ TIME Fl...aN IS EQUALED OR EXCEEDED REGIONAl. INVENTORY & RECONNAISSANCE STUDY SMAll HYOAOPOWER PROJECTS SOUTHCENTRAL ALASKA FIGURE 6-10 FLOW DURATION CURVE FOR LITTLE SUSITNA RIVER NEAR PALMER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ~ 9 ~ ~ l'-' 2 "- ~ 0 ...J ~ 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW: 390 cfs DRAINAGE AREA = 166 mi 2 O~----~------------~~----~------+-o 20 40 60 80 100 PERCENT ~ TIME Fl!JN IS EQUALED OR EXCEEDED REGIONAL INVENTORY &. RECONNAISSANCE STUOY SMAll HYDROPOWER PROJECTS SOUTH CENTRAL ALASKA FIGURE 6-11 FLOW DURATION CURVE FOR WILLOW CREEK NEAR WILLOW DEPARTMENT OF THE ARM'f ALASKA DISTRICT CORPS OF ENGINEERS 1 I 4.0 3.5 3.0 ADJUSTED MEAN ANNUAL FLOW = 333 cfs DRAINAGE AREA = 131 mi 2 2.5 2.0 :J 9 ~ ~ 1.5 ~ 2 ..... :J 0 ..J ~ 1.0 0.5 0 :J 0 20 40 60 80 100 PERCENT CF TIME FLOW IS EQUALED OR EXCEEDED REGIONAL INVENTORY & RECONNAISSANCE STUDY SMAU HYDROPOWER P!!OJECTS SOUTH CENTRAL ALASKA FIGURE 6-12 FLOW DURATION CURVE FOR CHUITNA RIVER NEAR TYONEK DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS ~ 0 ..J ~ ~ L£.I 2 ...... ~ 0 ..J ~ 4.0 3.5 3.0 2.5 2.0 1.5 1.0 O~ ADJUSTED MEAN ANNUAL FLOW = 50.0 cfs DRAINAGE AREA = 65.1 mi 2 O~----~------~-----r------~--~~ o 20 40 60 80 100 PERCENT rR TIME FLOW IS EQUALED OR EXCEEDED REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PlmJECTS SOUTHCENTRAL ALASKA FIGURE 6-13 FLOW DURATION CURVE FOR BERRY CREEK NEAR DOT LAKE DEPARTMENT OF THE ARMY ALASKA OISTRICT CORPS OF ENGINEERS 4.0 3.5 3.0 2.5 2.0 ~ 9 ~ ~ 1.5 ~ 2 ....... ~ 0 ~ ~ 1.0 0.5 ADJUSTED MEAN ANNUAL FLOW = 42.2 cfs DRAINAGE AREA = 36.2 mi 2 20 40 60 80 100 PERCENT CF TIME FLOW IS EQUALED OR EXCEEDED REGIONAL INVENTORY &. RECONNAISSANCE STUDY SMAU HYOAOPOWER PROJECTS SOUTHCENTRAL ALASKA FIGURE 6-14 FLOW DURATION CURVE FOR SEATTLE CREEK NEAR CANTWELL DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS pairing procedure, it is often difficult to find nearby gaged streams with all drainage basin characteristics similar to the ungaged streams, especially in remote areas such as portions of Southcentral Alaska, where gaged streams are very sparse. Good estimates of mean annual flow can still be obtained under such conditions, but mean monthly flows can be in error, especially during the spring and summer snowmelt period. The mean annual flows estimated by this methodology, therefore, can be considered to be more accurate than the estimated mean monthly flows. While the accuracy limitations of the mean monthly flow estimates are recognized, the monthly estimates were developed in order to derive plant factors for sites serving isolated villages, as discussed in the following section. This procedure was determined to be appropriate in a reconnaissance-level study, but a more rigorous approach supported by better data would be required at the feasibility level of study. 6.3 PLANT FACTORS AND INSTALLED CAPACITY Two methods of plant factor analysis were used in the more detailed studies. The first method was used in systems where the installed capacity of the hYdroelectric plant was substantially below the average system uti 1 ity demand (annual energy di vi ded by 8,760 hours). It was assumed that the utility can sell any power produced, and the only limitation to the amount of energy produced would be availability of streamflow to operate the turbines. The installed capacity was sized to capture up to 1. 5 times the mean annual flow. Any fl O~I occuri ng in excess of that amount was assumed to be spilled without producing power. In additi on, turbi nes cannot operate below a certai n mi nimum flow, which is determined by machine limitations. When the flow drops below that amount, the turbine cannot operate and must be shut down. The flow duration curve in Figure 6-15 illustrates the principles involved. The area beneath the curve represents the total flow in the stream, and the shaded area beneath the curve represents the fraction of the total flow that can be used to generate power. This fraction is multiplied by the annual average flow and termed the usable annual average flow qu (in cfs). The annual energy (E) resulting from this flow is calculated by the following equation: E = quHn e 8760 11.8 where: Hn is the net head in feet, e is the system efficiency, based on a tyical turbine efficiency of 0.85, generator efficiency of 0.96 and transformer efficiency of 0.98, which results in e = 0.80, and 8760 is the number of hours per year. The factor 11.8 is a conversion factor used to make all units dimensionally consistent. Di vi di ng the above annual energy actually generated by the energy that could be generated by the plant operating at the design flow for the entire year, yields the plant factor. 6-26 4.0 3.5 3.0 2.5 2.0 PLANT FACTOR = FRACTION OF TOTAL FLOW THAT IS USABLE X MEAN FLOW of DESIGN FLOW ~ 1.&.1 1.5~......--......-\ 2 ...... ~ u.. 0/ 0,5 USABLE j~ o /// M// /MINIMUM USABLE FLOW o 20 40 60 eo 100 PERCENT CF TIME FLOW IS EQUALED OR EXCEEDED REGIONAllNYENTORY & R£CONNAISSANCI: STUDY SMAll HYIlfIOPOWER PfIOJECTS SOUTHCENTRAL ALASKA FIGURE 6-15 FLOW DURATION CURVE FOR PLANT FACTOR ANALYSIS-UTILITY -SERVED COMMUNITIES DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Isolated corranunities and smaller utilities required a different approach to estimate the plant factor, since not all power that can be groduced during periods of low demand can be sold. This approach is illustrated in Table 6-5, a typical summary table for 1997, the design yea r. The computations i nvol ved were perfonned on a computer for each year in the 50 year period of analysis, although only the design year results were output. This infonnation was included in the significant data section for each site analyzed. In order to implement this second, approach, average monthly flows were derived as detailed in Section 6.2, Hydrologic Analysis. The potential hydroelectric energy generation was calculated based on the net head, average monthly flow, and number of hours per given month. When average monthly flows exceeded the design flow, the design flow replaced the average monthly flow in the computations. When average monthly flow fell below the minimum operating flow for the turbine unit, it was assumed that no hydroelectric energy was generated. The installed capacity was selected as the lesser of the capacity required to meet the 1997 annual energy forecast in kilowatt-hours, divided by 8,760 hours per year and multiplied by 1.6 (see discussion below on load utilization curve) and by the capacity resulting from utl i zati on of 1. 5 times the average streamflow. The percent of average annual energy used in each month was based on five villages in the Alaska Village Electric Cooperative.l/ These values were multiplied by the yearly annual energy forecast to obtain monthly energy demand in kilowatt hours. The usable hydro energy was calculated from the potential hydroelectric energy generation (PHEG) and the energy demand. The method is illustrated graphically in Figure 6-16. The figure represents a load duration curve for a given month and year (in this case the month of October and the design year, 1997). The curve shape was developed from several references (USDI 1980; Creagher and Justin 1950; and Linsley and Franzini 1975) and actual field observations. Actual utility data were used to define the load duration curve for the Cordova Electric Cooperative. The ordinate is the non-dimensional ratio of hourly demand to average daily demand (by definition 1.00 represents the average daily demand). The abscissa is the time (hours) over which that ratio prevails. The factors defining the curve are referred to as load shape and hour factors. The daily peak was assumed to occur during lunch and/or dinner time. It was estimated to be twice the average daily demand and have a duration of 3 hours. This corresponds to a load shape factor of 2.00 and an hour factor of 3.00. The bulk of the demand was estimated to be greater than or equal to 1.6 times the average daily load and anticipated to occur over 13 hours. Therefore, it was selected as an installed capacity guideline. During the eight hour night-time period, demand nonnally is minimal and was therefore assumed to be zero for this analysis. l/ Small ~droelectric Inventory of Villages served by Alaska Village Electric Cooperative, United States Department of Energy. Alaska Power Administration, December 1979. 6-28 TABLE 6-5 TYPICAL PLANT FACTOR ANALYSIS FOR ISOLATED COMMUNITIES AND SMALL UTILITIES, DESIGN YEAR 1997 NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY PLANT FACTOR PROGRAM CONMUNITY: MENTASTA LAKE SITE NUMBER: 1 NET HEAD (FT): 650. DESIGN CAPACITY (KW): 84. MINIMUM OPERATING FLOW (1 UNIT) (CFS) : 0.38 LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00 HOUR FACTORS: 16.00 15.00 13.00 3.00 110 NTH (#DAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY MONTHL Y HYDROELECTRIC OF AVERAGE DEMAND FLOW ENERG Y ANNUAL ENERGY (CFS) GENERATION (KWH) (KWH) JANUARY 0.66 21677. 10.00 45009. FEBRUARY 0.57 16910. 9.50 42758. MARCH 0.55 18064. 9.00 40508. APRIL 0.95 30196. 9.00 40508. ~1A Y 8.70 62496. 8.00 36007. JUNE 13.40 60480. 5.50 24755. JULY 8.96 62496. 5.50 24755. AUGUST 7.86 62496. 6.00 27005. SEPTEMllER 4.63 60480. 8.00 36007. OCTOBER 2.19 62496. 9.00 40508. NOVEMoER 1.07 34010. 10.00 45009. DECHIBER 0.85 27918. 10.50 47259. TOTAL 519719. 450089. PLANT FACTOR(1997): 0.38 PLANT FACTOR(LIFE CYCLE): 0.39 6-29 USABL E HYDRO ENERGY 14452. 11273. 12043. 1 9 716. 34817. 2475!:J. 24755. 27DO~ . 34565. 37228. 22173. 18433. 281215. 2.0+---........, o 4: 9 1.5 w (!) 1.0 <t a:: w > 4: ........ o 4: o ...J 0.5 LEGEND 6 EXAMPLE: MENTASTA LAKE MONTH OF OCTOBER DESIGN HYDROELECTRIC ENERGY (62,496 kWh) (PLANT LIMITED) 7/ (20NTHLY DEMAND / ( 40,508 kWh) ----------- 12 HOURS 18 24 I77"l POTENTIAL HYDROELECTRIC ENERGY LL-LJ (62,496 kWh) (FLOW LIMITED) ~ USABLE HYDROELECTRIC ENERGY ~(37,228 kWh) II£GIONAL INYBIT~V & ~ STlJ)V SMAU HYOIIOPOW9I PIIOJECTS SOUTHCENTRAL ALASKA FIGURE 6-16 LOAD DURATION CURVE FOR PLANT FACTOR ANALYSIS -ISOLATED COMMUNITIES AND SMALL UTILITIES DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS The resulting PHEG value was converted to a non-dimensional ratio by dividing it by the monthly energy demand. Values of the ratio were then plotted as a line on the load duration curve. The shaded area beneath the line represents the usable hydroelectric energy. It was calculated by the computer from the defined load shape and hour factors. The plant factor is equal to the sum of the usable hydro energy, divided by the energy that would have resulted from operating the plant at its installed capacity for the period under consideration. The plant factors output included the 1997 design year plant factor as well as the plant factor resulting over the 50 year period of analysis. 6.4 CONCEPTUAL ENGINEERING 6.4.1 General From previous experience on similar studies and from a brief economic sensitivity analysis, the type of hYdro development adopted was limited to run-of-the-river plants. Accordingly, at the few topographically very favorable sites where a minor amount of storage was provided behind forty foot high dams, no credit was given to this storage in operational studies because increasing dam height proved simply the most economic means for providing sufficient spillway capacity and sediment storage, as well as providing additional head in confined si tes. Reconnaissance level studies were conducted of the type of diversion dams, waterways, mechanical and electrical equipment, powerhouses, transmission lines, access, and mobilization and demobilization. The studies included review and evaluation of: 1. Published climatologic, geotechnical and other relevant data on the study a rea; 2. State of art of small hydro engineering in cold regions, i ncl udi ng previously compl eted reports; 3. Equipment manufacturers data; 4. Transmission line options; 5. kcess techni ques; and 6. Contractor mobilization/demobilization requirements including need for construction camps. For the optimum site for each community the selected damsite and project layout are described on its Significant Data sheet included in this report. 6-31 Except for the Kenai Peninsula and a narrow coastal band along the south shore of Alaska, and some river valleys and south-facing slopes, the entire study area is generally underlain by permafrost. The main aspects in which the presence of pennafrost often may potentially affect engineering projects are evaluated in considerable detail in the 1900 USCOE report on Northwest Alaska. Several of the restrictive conclusions reached in that report are, however, applicable to a much larger degree, to storage type projects in the flatland and muskeg country of Northwest and Southwest Alaska, where only a handful of sites could develop more than a hundred foot of head. These conclusions are not felt to be fully applicable to the foothill and mountain country of this study area where practically all the sites evaluated in this study would be located. There can be no doubt that extensive geotechnical exploration would be required on any project in order to establish, by drilling, electromagnetic surveys, jacking in holes and by other methods, the extent, temperature, and other characteristics of the permafrost areas and zones. It should, however, be remembered that permafrost is not continuous in the present study regions and that the types of areas where the extent of permafrost is at a minimum and/or where its presence has the least effect on construction are typically those in which any small run-of-the-river type hYdro developments would be located. Such modifying factors, as they might lessen the negative impact of permafrost on the main project elements, are summarized below: o Diversion Dams In almost every case these would be located on tha\i-stable gravelly materi al s or on bedrock. In quite a few cases the stream might also already have created a thaw-bulb strip all along its course, thus having actually entirely removed any pennafrost. Low concrete dams are therefore not 1 i kely to settle significantly, nor would their safety be likely to be endangered by any nominal increase in leakage flow underneath them. Nor would minor temperature cracking within the concrete blocks endanger these small structures. o Penstocks In most cases penstock routes would skirt a stream bank, and be located either on gravel terraces or on shallow bedrock, their gradient normally dipping quite steeply. This would avoid the need for any deep excavation or use of arctic type piles to reach the bedrock. Settlement upon melting of any ice lenses in the bedrock could readily be absorbed by the penstock by means of incorporation of slight bends in plan and by use of expansion joints. 6-32 o Powerhouse Most likely, powerhouses would be seated within a gravel terrace or on a bedrock bluff and therefore not be affected adversely by pennafrost, if present. In the few cases where it might be located on banks of finer material, drilled piles would readily ensure its safety. o Transmission Lines For most of thei r 1 ength the routes wou1 d probably run in terrain similar to that followed by the penstock routes. Crossing of any 1 imited local adverse pennafrost areas of frozen wet silty ground, in the flat country at the foot of the hills, would be readily achieved by use of double po1yethe1ene film wrapped around the embedded part of the poles. o Access Roads Because of the relatively favorable topographic and foundation factors discussed above, need for limiting access to winter only would not be an automatic conclusion. The heavy construction materials and equipment, as well as the pennanent project equipment, might well, however, be moved during wintertime, simply because of the greater ease of winter transpo rtat ion. 6.4.2 Diversion Dams The type of dam selected depends upon soils and foundations conditions found at the project site. Soils and foundations infonnation was obtained from soil classification data in nExp10ratory Soils Survey of Alaskan of the u.S. Department of Agriculture Soil Conservation Service (1979). The classification data describe soil types, terrain slope, erodibility and stability for roads, and other types of foundations. Three types of diversion dams, consisting of concrete, sheet pile, and embankment structures, were considered for the South Central Region. Sheetp'ile and rockfill diversion structures as shown in Figure 6-17 were considered appropriate in most cases wherever the soil s conditions were such that driving of sheetpi1es was feasible. The sheetpi1e dam scheme incorporates an intake structu re with a central overflow spillway section, serving also as a fish ladder, a coarse gravel or riprap rock backfill behind the downstream wingwa11s, and riprap protection to the creek channel immediately downstream of the diversion dam. Diversion into the penstock pipe will occur from an intake box, sl i ght1y recessed into one stream abutment and nonnally located just upstream of the dam face. Flow enters this intake box through a sloping heavy grating-type trashrack, located on an incline along the top of the box. This arrangement allows for easy maintenance removal of any accumulated trash and the closed vertical \'iall s of the box 6-33 ( :: . 'Il' SLIDE GATE -'-:'I'!IoI~' ::., 0 .. '.,'.~ ::::::::::::::::::: :::: ::: ::: :::::::::: ::::::: ::::: F[OW ::: : :::::: :;:::: : :::::::: . ~ .Ytrt~Q~ -:I~ 'M ';,~ -~ ~f II~ L I I I I 110 L.8 VARI ES (26.5'-66) I .~ OVERFLOW WE I R '\ I SCOUR PIPE: -r- GRATI NG TYPE TRASHRACK \ 1 c .~. ~~ "~~~~Y~ ~ i\) ~l..~~ l~~ 4> q\,\VfI SECTION A - A ,,/+~~ DRIVE SHEET PILE 2 ~/ : ~. 2 =-~ ~1 ~~ , I I I I I I .... I I I I I I I I I I I I I I I I I I I , I I I I I I I I I I I I I I I ,_.L_1_..L_L..l._7....l_L-_L.U_l_L. _L~_L..J ASSUMED BEDROCK SECTION B - B 10 o 10 ~DRIVE SHEET PILE I : I SCALE IN FEET W:'[IIII I I.j " u :::: 20 --..l.-ll I I ... fa 10 -.I..._L I 2'.5 I I I .l..j.....>- .:7 ~ ~-:. "-'~n\~~ I I.J-~_.~ ~ t~ ~1' I I L.-~ .. ~ .. ~ 11"':: ~~ I I J,-- REGIONAL INVENTORY & RECONNAISSANCE STUOY SMAU HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA c;l-~ -l_1111 I 'I\~ ..... ~.~ , -l.. I 1-...... t -l_J... I I f- ...,J_ I I I I §/i DW //~ i'// I I I I I -.lJ..1 ,II I I r ,... r-L-I , I I I I I I I I I I ~-~r~ L I L~ ~ Li '"ASSUMED BEDROC K ELEVATION C -C .-~.-~ I .'-... -. I I I I· II I 1 1 1 I I I I I I I I I I I I I I I I -..J_~-r-t _1 __ ROCKFILL/SHEETPILE DAM AND INTAKE STRUCTURE TYPICAL LAYOUT FIGURE 6-17 For: DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS exclude bottom sediment from the vicinity of the pipe intake. A scour valve has been incorporated on each side of the stream for periodic fl ushi ng of bottom sediment accumul ated. An overflow wei r woul d be located centrally over the stream bed, with its crest elevation several feet above the top of the intake box. This will allow winter flow to enter the penstock even after up to a four foot thick ice cover has formed. The multi-step fish ladder off the downstream face of the weir also serves as an energy dissipator during high stream flow. A concrete diversion dam has been proposed for sites where bedrock is exposed or where 1 arge boulders and gravel, or possible presence of permafrost, preclude driving of sheetpiles. Two versions of this concrete diversion dam were developed. The first, minimum height, version shown on Figure 6-18 would be very similar in configuration and size to the sheetpile dam. For most of the sites, however, the size of the spillway design flood, the likely presence of a more than 3 foot thick ice sheet and the need for provision for a certain amount of sediment storage, especially on the braided and/or torrential streams, led to the development of a second version of concrete dam. As shown in Figure 6-19, this up to 40 foot high dam would have a central standard ogee spillway section with a bucket dissipator. No fish ladder has been indicated or costed out for this concrete dam because the cost of this item could become quite considerable for this higher dam and should therefore only be studied where feasibility studies showed an actual need for such provisions. The ogee spillway was sized for a SO-year flood, in accordance with the approach in USCOE "Feasi bil i ty Studi es for Small Scal e Hydropower Additions" (1979) for low hazard dams, with storage not exceeding 1000 acre feet and heights less than 40 feet. These 50 year floods were determined using the method detailed in "Flood Characteristics of Alaskan Streams" (1975), taking no allowance for lake and pond storage or forests. Mean minimum Janua~ temperatures of O°F for the South Central coastal areas and -20°F for the South Central Interior were assumed. Various combinations of spillway height and width were utilized in order to confine this flood to the main stream channel. No freeboard was provided to the top of the non-overflow section which was assumed to be safely overtopped during larger floods. This dam type will also provide a considerable amount of sediment storage, as well as ample room for an ice sheet to form. However, because only the sand size fraction of sediment would probably be subsequently removed through flushing, the large gravel, cobble, and boulder size particles would continue to accumulate against the dam. For most of the sites, the need for provision for a certain amount of sediment storage, especially on the braided and/or torrential streams, caused the intake structure for the penstock to be an independent structure, located 50 to 100 feet further upstream. From field observation and literature study it was assumed that all concrete dams would reach relatively impervious alluvial materials -or bedrock - after excavating down four feet. This assumption also infers that foundation treatment requirements would not become excessive. 6-35 FLOW ~ OVERFLOW SECTI ON ~m W WITH I iC;r BACKFI LL PLAN ~B VARIES ELEVATION C -C 6-36 SLIDE GATE AIR VENT SECTION A - A SECTION B - B 10 o J , 18" HIGH FISH LADDER (TYP) 10 , SCALE IN F REGiONAl INVENTORY & RECONNAISSANCE STUDY SMAll HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA 20 , LOW CONCRETE DAM AND IN T A K EST R U C T U R E -T Y PIC ALL A YOU FIGURE 6-18 For: DEPARTMENT OF THE ARMY ALASKA DISTRICT ~PS OF ENGINEERS INTAKE STRUCTURE • •• 0 • 0'. lB . · · · o· • 0 L--C=~=======U~~~ .r- eno l1J 0 0:1 ~ -~ - TO POWERHOUSE EXISTING GRADE MAX. 50 YEAR W. L. NORMAL W.L. SECTION A-A SCALE: 1"= 101 VARIES SCOUR PIPE AND VALVE -I- l=} 1==1 :::::::t==lI~l~' PLAN VARIES (16 1 -2601 ) OGEE SPILLWAY SCOUR PIPE AND VALVE HANDRAIL TO BE DESIGNED TO OSHA STANDARDS (TYPICAL) -----------""'------------------ DEPTH OF EXCAVATION '---_-J' (VARIES) ELEVATION SCALE:)"= 20' SLIDE GATE BACKFILL BETWEEN CONCRETE WALLS ""'---~-L......-------_:_T-+______. ...... , ....... .............. ....... ....... ....... ....... ....... ....... ....... ....... HEAVY GRATI NG ........... ..IT~==±1-~ 4-- TO ER POW HOUSE SECTION 8-8 I -I I ~---- SECTION C-C SCALE: 1"= 10 1 SCALE: 1"= 10 1 REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALl HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA LARGE CONCRETE DAM AND INTAKE STRUCTURE, TYPICAL LAYOUT FIGURE 6-19 For: DEPARTMENT OF THE ARMY AlASKA DISTRICT CORPS OF ENGINEERS At several sites an earthfill type of dam was evaluated in wide stream valleys on creeks requiring "'~latively large spillways. A standard, "non-frozen" earth and rockfi 11 dam section with 2.5 to 1 slopes -as costed out by USCOE and given as Figure 4-2 in Tudor (1981) Report - was utilized on these creeks, with a freeboard of ten feet provided for the 50 year flood. The spillway was assumed to be an ungated concrete chute in an abutment. Details of the core, filter, and rockfill zones would depend on the local availabilty of materials. The intake would be as for the larger concrete dams but the penstock Hould be concrete-encased through the dam and provided with a downstream control gate and an adjacent smaller diameter pipe for stream releases. Largely because of the great cost for the concrete chute spillway, this type of dam did not prove to be economical and was not further considered for South Central Region sites. Normal constructi on practice requi res the contractor to be responsi bl e for cofferdam construction and diversion of water around the dam site. This item is highly variable in cost and, as such, is included in the contigency amount. 6.4.3 Soils and Foundations u.S. Department of Agriculture soils maps were utilized in identificaton of rocky and steep mountainous areas where access, penstock, and transmission line construction might prove to be difficult and more costly. The type of bedrock is of relatively minor significance for the very small size hYdraulic structures that would be required at the sites evaluated in this report. Both bedrock and permafrost profiles should, however, be established at both the intake and the powerhouse sites. Diversion dam and powerhouse structures do not necessarily have to be seated on bedrock, but could be supported on dense, pervious gravel. For both the dam and powerhouse structures, the need for a cutoff to bedrock would have to be evaluated in order to avoid seepage and subsequent potential piping failure at the intake weir and undermining by eddying currents at the powerhouse. It is possible that pile foundations for the powerhouse may be required at those few sites where bedrock, clean gravel, or other foundation material not subject to frost heave, does not exist at a shallow depth. Pi 1 e foundati ons, i ncorporati ng appropri ate measures for dealing with permafrost, such as use of non-frost-susceptible backfill slurries, proper anchoring, etc., would then be utilized. Because of the 1 ack of subsurface information, both \'1ith regard to extent of permafrost and especially on the type and thickness of foundation material, the increase in cost due to the need for such foundations was not included in the present study. 6-38 6.4.4 Waterway s The use of open canals as waterways was evaluated and rejected for those projects, partly because of the negative environmental aspects, but mainly because of the likely thawing of the underlying permafrost and resulting permanent erosion, unless extensive gravel surround was to be p rovi ded. All water conveyance structures woul d be enclosed pipelines. The hYdraulic head at each site was generally maximized in order to maximize power operations. The unit cost of penstocks was kept to a minimum, both by 1 imiting the design pressure and by reducing roughness of pipe which allowed the penstock diameter to be reduced. Diameters were selected to limit head losses to 10 percent of gross head, using the Hazen Williams equation with CHW = 140. The alignment selected attempts to maximize the low pressure pipeline sections of the penstocks. The use of a low-head penstock section is possible along the upper reaches of many sites. However, for the manufactured steel penstock pipe assumed in thi s study, mi nimal, normally accepted handling thicknesses proved to govern the pipe thickness and hence the cost up to a static head of 280 feet for large diameter (54" and greater) pipes, increasing up to 560 feet for small 12" diameter pipes. An allowance of 35 percent of static head for surge was included. Extra pipe wall thickness was required when the combination of static head and surge allowance exceeded the heads withstandable by the mi nimum handl i ng thi ckness. Except for a very short section immediately downstream of each intake wei r, where buri al and/or concrete encasement appear to be practically a requirement in order to provide protection against undermining and other damage from high flood flows, the penstock line can be left exposed. (Burial of up to 2-mile long penstocks would, in most cases, prove to be very expensive and the long-term environmental impact from potentially extensive excavation and soil erosion could be significant, although not posing as high a likelihood as erosion from canals.) A brief state-of-the-art survey was carried out for the smoothest type of readily available, long-lasting, and economic internal lining for both factory manufactured steel pipes and field-assembled small diameter (5 feet and below) steel penstocks. The optimum lining proved to be either polyurethane vinyl, hand coated in 3 to 5 mil thickness, or mechanical extruded vinyl lining (30 mil). For the outside coating, zinc rich exterior primer with 2 protective coats of polyurethane vinyl would be suitable for the Alaska locations. Tar, tar enamel, tar epoxy, or asphalt exterior coating is not recommended as these proective coatings become brittle and spall at the sub-zero Al askan wi nter temperature s. 6-39 Pl astic pipe!.! has been installed both above ground and underground for water supply and sewerage service in the Alaska environment, and has perfonned sati sfactori ly. Because of the remoteness of the sites in this study, use of plastic pipe was, however, not deemed advisable without further detailed investigations. No insulation was specified for the penstocks because maintenance of continued flow within full pipes was assumed to basically provide sufficient protection against freezing. To further guard against any freezing and to enable rapid restarts to be made if freezing still were to happen, the penstocks were finally assumed to be of steel. Small diameter drain pipes would be specified at frequent dips in the penstock profile to ensure speedy drainage of the system during any lengthy shutdowns. At certain sites, low flow or no flow conditions will prevent hYdroelectric operation during the winter months. Detailed investigations of the pipeline thennodynamics as well as insulation, flo\'i bypass systems and pipe burial should be conducted during feasibility studies. No line items for these components have been provided for in this study other than the general contingency. Also, as discussed in Section 6.4.1, no special support provisions were desi gned or costed in thi s reconnai ssance study for copi ng with permafrost, since the extent of this foundation aspect would first have to be detennined by detailed field studies. 6.4.5 Turbines and Generators The project sites evaluated have a potential unit output range of from 80 to 7,250 kilowatts, with heads from 90 up to 1100 feet. Impulse turbines are utilized for most sites in this S~~dy because their ability to operate over a wide range of flows. Typically, these turbines operate safely at 20 percent of maximum output. Accordingly, with two turbines per site, hYdroelectric generation can thus be maintained with stream flows as low as 15 percent of the average flow. At Tazlina, Mentasta Lake, New Chenega, Tetlin or Ellamar however, only single units are proposed, both because of the low plant capacity «150 kW) and because of average winter flows greater than minimum operati ng flows. 11 Either FRP (glass fiber reinforced isopthalic resin) or high density polyethYlene. ~I Discussions were held with the manufacturers of small-size, but basically medium-to high-head turbines. The two major U.S. turbine manufacturers do not include small impulse turbines of the size required for these installations in their product line. There are, however, domestic small specialty turbine manufacturers and foreign suppliers who do supply this equipment. Price information covering the full project range was obtained from a domestic manufacturer for this class of equipment. 6-40 For the small size generating units involved in this study, ready means are available to limit the potential pressure changes upon sudden flow changes in the penstock, without resorting to relatively expensive hydrau1 ic structures, such as construction of surge tanks. Moderation or elimination of potential pressure rise from sudden loss or decrease in load in the case of impulse-type turbines is built into the machine in that the jet deflector first deflects the jet from the turbine without changing the rate of flow in the penstock. Thereafter, the needle valve controlling the flow can be slowly moved to a position corresponding to the new output. The rate of closure of the valve can be controlled to protect the penstock from unacceptable pressure rise. The nozzle needle can be designed to maintain some flow in the penstocks to avoid freezing. If it is anticipated than any of the plants might be shut down for long periods, the intake valves provided at the head of the penstock can be closed to drain the penstock. The intake valves will generally be manually operated. On most project sites the diverted flow through the penstock is assumed to be divided at the powerhouse into two equally sized impulse-type units. The typical arrangement, using two packaged units, is shown on Figure 6-20. The penstock would bifurcate just upstream of the powerhouse into two pipes, each supplying a skid~ounted unit package, seated on a concrete base slab. Each unit would discharge into a tailrace slot cut into this concrete base slab. Because impulse turbi nes ha ve to di scha rge into atmospheri c pressure above the maximum tailrace elevation, about 3 to 6 feet of ~drau1ic head is lost. This loss is negligible when considering the flexibility of the machine and its ability to operate without expensive surge tanks. The package unit enclosures are supp1 ied by the manufacturer and are included in the total cost of the unit. If these package enclosures prove to be not sufficiently insulated, a prefabricated wooden building could be readily placed over the two unit packages. The additional costs would be negligible in comparison with each project cost. The preferred orientation of the powerhouse, directing the tailrace flows to meet the stream at approximately 45 degrees, is shown in Figure 6-20. It should also be noted that the location of "impulse-type turbines above the tailrace water surface effectively precludes any fish from entering the generating units. The small Pelton-type impulse turbines described above were considered to be below their optimum range at four sites because of the low (85 to 150 feet) head available. Crossflow or Ossberger turbines which have a relatively broad flow range were therefore utilized. On plants larger than 1500 kW, either 2 Peltons or 2 horizontal Francis units, with fully enclosed powerhouses, were used. 6-41 A A j C TROL PAC KAGE PLAN SCALE : 1" • 10 1 -a" PENSTOCK SECTION B - B SCALE: 1" = 6 1 -0" ft-42 GENERATOR CONCRETE FlOOR. i~~~ir--SUBSTRUCTURE SECTION A - A IMPULSE TURBINE RUNNER SCALE : 1" • 6' -0" REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA For: POWERHOUSE TYPICAL LAYOUT FIGURE 6-20 DEPARTMENT OF THE ARMY AlASKA DISTRICT CORPS OF ENGINE ERS Whil e generators may be either synchronous or i nducti on type, most sites will require that synchronous generators be provided. The only appl icati on for an i nducti on generator is for those instances where the power from the project is fed into a much larger system that has the capability at the point of connection of providing the reactive power necessary fo. the operation of the inductive machine. The speed of a synchronous generator must be controlled in order to ensure proper operation of electric motors and timing devices. A governor will therefore be provided to control the flow of water to the turbine in accordance with the load on the generator to maintain a constant speed. An induction generator would be controlled by the electrical system to which it was connected and would have required control devices only to protect the machine in case of malfunction. As stated above, however, this less expensive type of generator could only be consi dered for the few proposed pl ants where connecti on to a 1 arge system such as the Golden Valley system is possible. 6.4.6 Site Access The impulse turbines selected as the generating units are packaged in a container which can be readily transported to the sites during wintertime on a sled. Remote control projects have been assumed for the majority of the sites. Therefore, no pennanent roads have been assumed to be needed to powerhouse locations or other project features. Access tracks to powerhouse and intake areas would be required as well as to parts of the transmission lines where the conditions appear to be particularly difficult. 6.4.7 Transmission Transmission line capabilities under relatively small loading and short distances have been evaluated to assess transmission capabilities up to several megawatts at voltages of 7.2 kV, 14.4 kV, and 38 kV. The economies involved do not warrant consideration of higher voltages for the range of loads and distances considered. The voltages are intended as an estimate only and a more detailed study of selected corona effects, long distance stability, and thennal conditions as well as other eng; neeri ng cons i derat ions shoul d be perfonned at the next stage of study. The transmission line capabilities for voltages and distances consi dered are dependent prima ri ly upon si ze and number of conductors, voltage, distance, power factor, and, to a lesser degree, phase spacing. This study assumed a minimum power factor of 0.9 and typical phase spacing for 3-phase lines. The transmission line system was selected to limit linepower losses to approximately 5 percent and voltage drops at 7.75 to 10 percent. As shown on the load versus distance curves in Figure 6-21, for a given line power loss and voltage drop, the maximum product of the installed capacity in kilowatts and the transmission distance in miles remains a constant. Specific limiting kilowatt-miles for various transmission alternatives are summa ri zed in the Transmi ssi on Costs section. 6-43 20~------+-+---------~--------+- 15~--------~--------4---------~- 38 kV (Maximum MW -MILES = 167) --IO~--------+---~~--4---------~--- 5~--~----+---------4---------~-- 14.4 kV (Maximum MW -MILES = 24) 6 10 20 30 DISTANCE (MILES) 266.8-26/7 7.75 °/0 VOLTAGE DROP 5°10 LOSS 3 PHASE REGIONAl. INVENTORY & RECONNAISSANCE STUDY SMAll HYDROPOWER PRO.ECTS SOUTHCENTRAL ALASKA FIGURE 6-21 TRANSMISSION LINE LOAD VI. DISTANCE FOR 5 LOSS 6-44 DEPARTMENT OF THE ARMY ALASKA DlSTRICT CORPS OF ENGINEERS The basic, most economic transmission system, the single~ire ground return (SWGR), was evaluated for all the small developments investigated. The SWGR transmission system is well-suited for the part of south central Alaska south of the Alaska Range since ground moisture is requi red for conducti vi ty. For communiti es in non-pennafrost areas having economic development potential, the SWGR support system recommended in the Bristol Bay Energy and Electric Power Potential Study (Retherford 1979 and 1980) was modified to a single wood pole type that would be suitable in non-pennafrost areas. This system is appropriate for small loads and short transmission distances, until the combined effect of increased generating unit capacity and/or increased distance of transmission from powerhouse to load center cause the line power losses to exceed 5 percent. In perT,lafrost areas, single wire ground return systems are often not feasible because of too low ground conductivity values. An alternative Single phase transmission concept was utilized, therefore, with a second wire provided for the return current. Such systems are in common usage in the Alaska Village Electric Cooperative Service areas and other interior and northern utilities. Embedded wood poles would be used because no major cost increases result from incorporation of a double folded polyethelene film sleeve around the embedded part of the pole which serves to break the bond to the active zone of pennafrost and thus prevent heave from occurring. A 14.4 kV or 38 kV four-wire transmission line was selected for larger and/or more remote powerhouses. Selection of the minimum voltage in this four-wire line alternate was subject to the same 5 percent loss consideration. Long spans were used at a few sites, where transmission lines would traverse expanses of water. This approach has been proved to be more economical than alternate routings, which follow steep and circuitous shorelines and/or involve submarine cable crossing. 6.4.8 Operations and Maintenance Little data are available on operations and maintenance of small hYdroelectric projects. Most infonnation that is available has been compiled for operation of such projects as part of a larger system, within ready reach of skilled personnel and maintenance facilities. An attempt was made to arrive at conservative minimum 0 and M costs for single Alaskan communities, not in the immediate viCinity of a large population center. The plant was assumed to be equipped with sufficient redundant components to facilitiate remote control with a minimum of plant outage and provide sufficient time for maintenance personnel to arrive when needed. Remote control and intelligence transmission would be by microwave carriers and the remote operating center would include a computer facility, as well as all functions required to start, operate, monitor, and shut down the plant. 6-45 Local recording of basic data and important functions would take place at the plant and all equipment would be designed for fail safe operation. ~10nthly inspection of the plant would be required for: Cleaning of debris (intakes, sumps, filters, racks, etc.); Replacement of recorder paper, relays, and adjustments; Checking of condition of electrical equipment, batteries, transfonners, microwave equipment, motors, etc; Comparison of data collected at the remote control center with that recorded locally, for precise calibration; Replacement of printed circuit cards as necessary; i.e., excitation, microwave, etc. Prescheduled maintenance outages would occur once a year. 6.5 PROJECT COSTS The reconnaissance level cost estimates were derived from the prel imi na ry project 1 ayouts by fi rst estimati ng the cost for simil ar work in the Pacific Uorthwest. The cost 1 evel for each item was based on the construction cost indices of the Bureau of Reclamation for July 1981. Table 6-6 gives specific escalation factors applied to the various cost components. Construction costs were totaled and multiplied by a geographic factor developed for each community reflecting the particular conditions in that part of Alaska, including higher labor and transportation costs, mobilization and demobilization, and other factors related to remoteness and adverse climate. These factors are presented in Section 6.5.8. Conti ngenci es of 25 percent and engi neeri ng and owner admi ni strati on of 15 percent were then added to give the Total Construction Cost. Interest Duri ng Constructi on (IDC) was estimated by assumi ng a 2.5-year construction schedule and using an interest rate of 7-5/8 percent, as defined in the scope of work for this study. The IDC factor was computed following the uniform annual cost approach, as recommended by the USCOE "Hydropower Cost Estimating Manual II (1979). The IDC factor was then added to the Total Construction Cost to give the Total Project Cost, which is provided on the Cost Summary sheet for each project. Costs not estimated are land, diversion and care of water during construction, reservoir, relocations, and environmental controls and mitigation. 6.5.1 Dams As discussed in Section 6.4.2, two slightly different versions of concrete gravity dams, both with a central ungated ogee section, were used at most sites. Costs were based on quantity takeoff from the typical drawings (Figures 6-17 and 6-18). 6-46 TABLE 6-6 ALASKA SMALL HYDROPOWER PROdECTS COST ESCALATION FACTORS USBR Date of Cost Indexes Escalation K, 1/ Original Original July Over Origina Item Source-Estimate Estimate 1981 Estimate Comments 1. DAMS Concrete Small New Large New Earth and Rockfi 11 1 4/79 2.37 3.00 1. 27 Fig. 4-2 Spi 11 way 1 4/79 2.47 3.21 1. 30 Fig. 4-3 Sheetpi 1 e 2 7/80 2.83 3.08 1.09 2. PENSTOCKS 1 4/79 2.61 3.27 1. 25 Fi g. 4-5 3. POWERHOUSE AND EQUIPMENT T u rb i ne sand Generators Pe lton 2 7/80 2.95 3.29 1.12 Crossflow 3 7/78 2.38 3.29 1.38 Fig. 5-7 Franci s 1 4/79 2.48 3.29 1.33 Fig. B-3 Mi sc. Power Pl ant and Auxil iary Equipment 1 4/79 2.37 2.95 1.24 Fig. B-8 Powerhouse Structure Pel ton New Crossflow 3 7/78 2.28 3.03 1.33 Fig. 5-20 Francis 4 7/78 2.28 3.03 1. 33 Fig. 4-7 Excavati on 3 7/78 2.33 3.14 1.35 Fig. 5-21 Valves and Bifur- cations 1 4/79 2.61 3.27 1. 25 Fig. 4-6 4. SwitchYard (E1 ectri cal and Ci vi 1 ) 1 4/79 2.37 3.08 1.32 Fig. B-9 or Fig. 4-17 5. Pccess 2 7/80 3.16 3.32 1.05 6. Trans- mission New 7. Mobili- zation New • . !.I Sources: 1. EPRI (1981). 2. Ebasco (1980). (Note Alaska cost factors were taken out to be consistent with geographic factor applied to totals.) 3. USBR (fonnerly WPRS) (1980). 4. ACOE (1979). 6-47 For the smaller creeks the lower, nominally 10 foot high, version with a combined step-type spillway/fish ladder was assumed. As shown in the tabulation below, the abutment sections were first costed out, together with a standard 30-foot overflow section. Additional costs per 10 feet of widening of dam overflow section were then developed as a separate subitem. The width of the horizontal stream bed part was estimated for each creek from site and/or map inspection. Concrete Dam -Low -Base Structure (for 30-foot wide creek) Item Qua nt i t,l Unit Concrete 150 cy Excavation 8 cy Backf i 11 130 cy Val ves and Grati ng L.S Cost 300 25 10 (~) Total ~45,000 200 1,300 5,000 say ~50,000 -Incremental cost for each 10-foot wideni ng or narrowi ng of overflow section Concrete Excavation Conc rete Dam -La rge 20 cy 4 cy 250 25 say 5,000 100 ~5,000 TIle concrete costs util i zed a basic concrete cost of $250 per cubic yard. The cost of constructing the spillway bucket was estimated at $375 per cubic yard. The intake structure was estimated at $500 per cubic yard since it includes considerable framework. Valves and grating added an additional $10,000. Excavation, foundation treatment, and backfill were estimated as 10 percent of the total concrete costs. The concrete vol urnes were estimated separately for each of the primary geometric sol ids apparent in Figure 6-18. The side slopes were detenl1ined from Abney level readings taken in the field, and estimated from the USGS maps for unvisited sites. The spillway volumes were calculated by integrating the area under the ogee curve and additional allowance was made for the spillway bucket and wall s. Intake structure costs were estimated based on penstock diameter and the height of the concrete ogee section which directly governs the height of the intake. Sheetp 1'1 eDam Where grolJnd conditions appeared to be favorable a sheetpile structure was assumed for the intake structure (see Fig. 6-19). It was costed out similarly to the approach used for the low concrete dams: 6-48 -Base Structure (for 30-foot wide creek) Item Sheetpiling PZ-27 BacHi 11 Valves and Grating Quantity 2,435 s.f. 320 c.y. Unit Cost (~) 15 10 Total ($) ~36,520 3,200 5,000 $44,725 say ~45,000 -Incremental cost for each 10-foot widening of overflow section Sheetpi 1 i ng 340 s.f. 15 ~ 5,100 Backfill 320 c.y. 10 500 $ 5,600 say ~ 6,000 Arch Dam For the proposed Whittier site on the Placer River on the Kenai Peninsula, arch dam costs were estimated at ~400 per c.y. of concrete (unescalated for geographic factor). This value was taken to also include excavation, structural materials, and appurtenances. These somewhat lower costs than other recent Alaskan arch dam estimates were based on the proximity to Anchorage and on the existence of direct railroad access to the site. The arch dam volume was estimated using R. S. Yarshey's "Pre-design Estimates for Arch Dams", publ ished in "Water Power and Dam Constructi on" of February, 1975. 6.5.2 Penstocks Penstock costs were estimated based on the diameter and length, and utilized Figure 4-5 from the 1981 EPRI study "Simplified Methodology for Economic Screening of Potential Low-Head Capacity Hydroelectric Sites". Included in the costs are the supply and erection of the penstock with supports, concrete footings, minimal excavation, and surface treatment. Special foundation treatments, thrust blocks, and bifurcations are not included. Since EPRI Figure 4-5 is based on low pressure penstocks, a high head adjustment factor (Fn) was developed. Fn equals 1 for net heads less -than or equal to those calculated based on the USSR formula and adjusted for surge. When net heads exceed this, a cost adjustment was made to cover the extra thickness requi red for the internal pressure desi gn. Install ed penstocks average approximately S2.25 per pound of steel pipe based on the EPRI Figure escalated to July 1981 costs. Manufacturers quoted the cost of extra steel at S.45 per pound. The extra shipping weight and increased handling costs would raise this increase in cost to S.75 per pound or 6-49 to approximately 1/3 of the cost per unit given by EPR! Figure 4-5. Since thickness varies linearly with head, the following formula was adopted for the high pressure head adjustment: Fn ' 1 + (H n -Hmin~Hm1n where Hn is the net head, and Hmin is the equivalent internal pressure design head for the USSR minimum handling thickness. This factor was multiplied by the cost per foot, times the length of the high head penstock. An analysis of penstock parameters showed that freight, supports, and installation accounted for approximately 50 percent of the total cost. The product cost of the finished penstock plant was not escalated by the geographic factor. Therefore, weighted value of only 75 percent of the total penstock cost was entered on the cost data summary table for each site. 6.5.3 Powerhouse and Equipment 6.5.3.1 Turbines and Generators Pelton type impulse turbines were selected for most projects except for heads below 150 feet. Estimates of the cost of powerplant generating equipment (including turbine, governor, generator, and control equipment) were obtained from manufacturers. Costs for a skid-mounted, fully weather proofed, steel panel enclosed turbine generator package are given by the curve in Figure 6-22. For heads below 150 feet crossflow units were assumed. The equipment costs were escalated from the USSR 1978 reference curve specified in Table 6-6. Under moderate heads (190-370 feet) and high flows (over 100 cfs) horizontal Francis units were selected. The equipment costs were escalated from the EPRI 1981 reference curve specified in Table 6-6. 6.5.3.2 Miscellaneous Power Plant and Auxiliary Equipment For Pelton, Crossflow, and Francis units, the costs of miscellaneous equipment were obtained from EPRI Figure B-8, which also details the equipment included in this item. 6.5.3.3 Powerhouse Structure The Pelton unit skid-mounted packages would be placed on a concrete based slab, assumed to be seated on bedrock. Cost of this concrete substructure, including erection of skid, was estimated at $350 per cubic yard for structural concrete and $250 for mass concrete, with rock excavation at $15 and common at $3 per cubic yard. Large Pelton 6-50 (J) I <JI o o o 700 600 500 ;::: 400 z: :::> ...... .". 300 200 100 o , I I I I I i ~ : : , i I , , i I I i I i , ! :7 , , I i I I : I I I I I I I I , I I I , A"! i ! ! I I I I I I I I i I I I I I ~ /' j i I ! I I , ! I 1 I I i I 0' I ! I I I i I , ; I ! , i i , I I I I , I I xi I I i I i , I i ! I I I I i I ! , I 1 1 I !~ 1 I I I I ! i i I I : I , I I i !yl j I I I I ! : I i I I 1 /' I I I : I i i ! ! I , i I : , ; I I V-I I i I I i I I I ! , ! I .. : / I I I I ! I I I I i I I I I I , ! I i i : / , ""-; {: T o I i I I I I ! i I I I I I I I I , I i I I , I I I I I I I I I i I I , I ! I I I , I I ! I i : : I I I I ! I I i I i i I , I I I 500 1000 UN ITS I ZE KW 1500 IMPULSE TURBO-GENERATORS COST-FOB FACTORY-COMPLETE INTEGRATED UNITS NOTE: COST BASE FOR CURVE IS JULY 1980. ESCALATE BY A FACTOR OF 1.12 TO JULY 1981. I I I ! i I I I I I I : I I I I I I i I , ,I I i , I I I I I i I , I I I . I I I 2000 I i I I ! I , j I \ I I I , I ! I i I I I ; I ! i I : 2500 REGIONAL INVENTORy &. RECONN!'ISS~.'ICE STUDY SMALL HYDROPOWER PnUJECTS SOUTH CENTRAL ALASKA FIGURE 6-22 TURB I NE GErlERATOR COSTS Note: Includes Cost of Turbine Cenerator, Valves. and Switchgear DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS unit powerhouses were estimated using manufacturer's dimensional data to obtain an area and applying the USBR cost curve for crossflow units which are also impulse turbines. The horizontal Francis units had powerhouse costs estimated from ACOE Figure 4-7. For the crossflow units the cost of the powerhouse and the attendant excavation was based on USBR 1978 cost curves. In both cases the cost of excavation for the transition into the existing stream downstream of the drafttube Has included. No specific tail race was required, however, because the flow in the stream would never be increased above the present flow. 6.5.3.4 Valves and Bifurcations Costs of the penstock bifurcation, and the turbine intake valve were obtained from EPRI Figure 4-9, except for the crossflow unit intake valve which had already been included as part of the turbine cost. 6.5.4 Swi tc hYa rd Swi tchyard costs with generator voltage ci rcuit breakers were estimated from EPRI Figure 4-17 or B-9 of EPRI of "Simpl ified Methodology for Economic Screening of Potential Low-Head Small Capacity Hydroelectric Sites." The figures yield both civil and equipment costs which were totaled and entered as a single line item on the cost summary sheets. 6.5.5 kcess Access tracks were estimated to be ~15,OOO per mile. Typically, they extend from the powerhouse to the intake structure. This assumed that construction access to nearby communities would generally follow transmission line routes. Nonnal access to transmission lines was included in the transmission line cost and the extra cost of detouring from the transmission route was not included. 6.5.6 Transmission Transmission line costs were developed from several sources, including previous Ebasco reconnaissance studies, discussions with Alaska utility engineers, and cost manuals by the Corps of Engineers, EPRI and USBR. Conductors were sized to limit line losses to 5 percent. Losses are related to the product of installed capacity (kw) and distance transmitted (miles). Because cost variation between 7.2 kV and 14.4 kV systems was not significant, all costs were based on 14.4 kV and 38 kV systems. This also provides the added advantage of reduced line losses and potential for expansion for the smaller systems. Listed below are the ranges in kW-miles over which the various transmission systems are applicable. These costs include wood poles, conductor line hardware and insulators, surveying, and clearing. No allowance has been made for land and right-of-way acquisition nor for special access roads. 6-52 Va 1 tage High Low Cost Base (kV) Phase (MW mi 1 es) (Ml~ mil es) ($ ~er mile) Cost Comments 38 3 167 24 50,000 0 Conventional 14.4 3 24 12 40,000 0 Co n ve nt i a na 1 14.4 1 12 0 25,000 0 Conventi ana 1 14.4 1 15 0 20,000 25,000 Si ngl e Wi re Ground Return 14.4 1 12 0 30,000 5,000 Conventional, Long Span 14.4 3 24 12 60 ,000 10 ,000 Long Span The above costs per mile were subsequently multiplied by the terrai n factors listed below. Terrai n Flat Ro 11 i ng ~lountai nous Swam~y Terrai n Factor 1.0 1. 25 1. 50 1. 50 The followi ng costs for step-up transfonners have been added to the transmission line costs for connection to existing lines: Transfonnation Capacity Cost 14.4 kV/115 kV 833 kVA $ 50,000 14.4 kV /115 kV 2,000 kVA $ 80 ,000 14.4 kV/115 kV 5,000 kVA $100,000 14.4 kV /115 kV 7,500 kVA $150,000 For 34.5 kV/115 kV, 80 percent of the above costs was assumed. For the 14.4 kV/138 kV or 34.5/138 kV, 110 percent of the 115 kV cost and for 14.4 kV/69 kV or 34.5 kV/69 kV, 70 percent of the 115 kV cost was assumed. No allowance has been made for step-down transfonners at the distribution end. 6.5.7 Mobilization Mobilization costs in Alaska are typically a sizable percentage of direct costs. In recent bids on hydro projects in Southeast Alaska, mobilization costs ranged from 4 to 20 percent of the direct cost, the successful bidder havi ng allocated the 20 percent figure. From investigation of recent estimates and construction bids for Alaska, a figure of 10 percent of the direct costs has been adopted for mobilization and demobilization at readily accessible sites, increasing to 20 percent when an extensive construction camp is required at a remote site. Minimum costs of ~100,000 for the fanner and ~200,000 for the 1 atter case have been assumed. 6-53 6.5.8 Geographic Cost Adjustment For preliminary screening studies, no generalized geographic cost multiplier ~,as used in the South Central region. Construction costs had al ready been escalated to southern Alaska costs from the lower 48 states' costs, generally by a factor of 2. A r;"Iore rigorous approach \."as applied in the more detailed studies, in which the geographic cost adjustment was calculated for each community studied. The Department of the Army recommends 1.7 as an empirical factor for converti ng Washi ngton State costs to Anchorage costs. The Alaska Department of Transportation and Public Facilities publishes location indices across the State of Alaska with Anchorage as a base equal to 1.0. These indices were combined to convert the lower 48 states' construction costs to those of the communities selected for detailed studies. The geographic cost adjustment factors are shown in Table 6-7. 6.5.9 Operations and Maintenance With the realization that the degree of sophistication affordable \."ill vary considerably from 0.05 MW to 3 r~w, the following are estimated to be reasonable expenditures of mandays required for maintenance as an average in a reasonably accessible fair-size community such as Tok: r~onthly routi ne checks and mi nor repai rs Annual inspection and major overhaul Peripheral facilities, communications, controls, etc. Contigency Total Man-days/Yea r 35 45 10 15 1U5" For more remote, isolated communities, the following minmum yearly costs have been estimated: -Electrical operator -Monthly transportation -Annual maintenance (additional imported personnel) -Outside repairs Insurance and general costs Total $30,000 5,000 15,000 10,000 10,000 $70,000 For larger plants the only collated data have been presented by EPRI (1981). Although it seems reasonable to expect that 0 and M costs would be proportional to installed plant capacity rather than to total project costs, the latter is the only relationship published. kcordi"gly, a value of 1.2 percent of the total project costs has been assumed for the intertied plants, and increased to 1.5 percent for the isolated communities. 6-54 TABLE 6-7 ALASKA GEOGRAPHIC COST ADJUSTMENT FACTORsl/ WhittierlV 1.9 Taz1ina 2.1 Eng1 i sh Bay-Port Graham 2.0 Halibut Cove 2.0 Kachemak 1.9 Seldovia 2.0 Chickaloon 1.9 Northway 2.3 Mentasta Lake 2.2 New Chenega~/ 2.2 Tetlin 2.4 Cantwell 2.3 Hope 1.9 Rainbow 1.7 Tyoneld/ 2.2 Copper Center 2.2 Gakona/Gulkana 2.3 Kenney Lake 2.3 Meakerville/Eyak 2.1 Eska/Jonesvi1 le/Sutton 1.8 Knik 2.0 Montana 2.1 Talkeetna 2.1 Ellamar-Tatitlek 2.1 Ferry-Suntrana 2.3 1/ Washington State costs escalated to Anchorage costs based on the Department of the Anny's "Empirical cost Estimtes for Military Construction and Cost Adjustment Factors". The applicable factor is 1.7. Cost adjustments between Anchorage and other Alaskan communities were further escalated based on actual locations or a reasonable proximity to actual locations as indicated on the State of Alaska Department of Transportation and Public Facilities "Location indices of 08/06/81". ~/ Estimates based on similar proximity to population centers and transportati on routes. 6-55 6.6 ECONOMIC ANALYSIS The economic analysis procedures used for the ~ore detailed investigations were essentially identical to those used in the preli~inary screening, as discussed in Section 5.2.3 and Appendix C. One refinement was built into the detailed studies, however. The benefit-cost analysis was modified to reflect a 2-1/2 year lead time for constructi on of the tlydroel ectric project. Constructi on is assumed to begin July I, 1981 and benefits from the project will begin to accrue when power is produced on Janua ry 1, 1984. In order to mai ntai n consistency in comparing the economic benefits of hydroelectric and diesel generation, benefit-cost ratios were calculated for the period 1984 through 2030. 6.7 EINIRONMENTAL CONSTRAINTS Major potential environmental constraints to hYdroelectric project development were identified principally through discussions with corrnnuni ty 1 eaders duri ng the fi el d reconnai ssance. The major environmental concerns were either land ownership status or the use of streams by migrating or spawning salmon. These concerns were included in the selection of sites for detailed study, and in several cases, were pivotal in selection of one site over another. Environmental factors, where important, are highlighted in the individual cOll1l1unity/ site descriptions and data sheets included in this report. Reference was also made to the National Register of Historic Places (U.S. Department of the Interior, 1981); no historic or archaeological sites listed appear to be located in ~roximity of the potential hYdroelectric sites identified in this study. 6-56 7.0 LIST OF REFERENCES Alaska Dept. of Transportation and Public Facilities. 1981. Location i ndi ces of 8/06/81. Personal correspondence. Al aska Energy Assoc i ati on. Undated. New Chenega a 1 ternati ve energy plan. Prepared for the New Chenega loR.A. Village Council, Anchorage, Alaska. Al aska Power Admi ni stati on. 1979. Small hydroel ectri c inventory of villages served by Alaska Village Electric Cooperative. U.S. Depa rtment of Energy. Anchorage. Alaska Power Authority. 1980. Reconnaissance study of the Kisaralik River hydroelectric pO\,/er potential and alternate electric energy resources in the Bethel area. Alonso, W. and E. Rust. 1976. The evolving pattern of village Alaska. Joint Federal-State Land Use Planning Commission for Alaska. Anchorage. 8alding, G.O. 1976. Water availability quality, and use in Alaska. U.S. Geol. Survey Open File Rept. 76-513. CH2M Hill. 1978. Review of southcentral Alaska hydropo\'ier potential- Fairbanks area. U.S. Army Corps of Engineers, Alaska District. CH2r·l Hill. 1978. Review of southcentral Alaska hydropower potential - Anchorage area. U.S. Army Corps of Engineers, Alaska District. CH2M Hill. 1979. Regi onal inventory and reconnai ssance study for small hydropower sites in southeast Alaska. U.S. Army Corps of Engineers, Alaska District. CH2M Hill. 1980. Reconnaissance assessment of energy alternatives. Chilkat River basin region. Prepared for the State of Alaska, Al aska Power Authori ty. Anchorage. Creagher, W.P. and J.D. Justin. 1950. Hydroelectric handbook. John Wi 1 ey and Sons, Inc., New York. Ebasco Services Incorporated. 1980. Regional inventory and reconnaissance study for small hydropower projects -Aleutian Islands, Alaska Peninsula, Kodiak Island, Alaska. U.S. Army Corps of Engineers, Alaska District. Ebasco Services Incorporated. 1981. Terror Lake Hydro Project independent feasibility-level cost estimate. Alaska Power Authority, Anchorage. Federal Energy Regulatory Co~ission. 1981. Alaska river basins planning status report. FERC-0068. Federal Power COlTlf:lission. 1976. The 1976 Alaska power survey, vol. 1. 7-1 Gall iet, Harol d H., Joe A. Marks, and Dan Rensha\'I. 1980. Wood to gas to power - a feasibility report on conversion of village power generation and heating to fuels other than oil. Vols. I, II, and III. Prepared for the Alaska Village Electric Cooperative. Goldsmith, Scott, and Lee Huskey. 1980. Electric power consumption for the Railbelt: a projection of requirements. Prepared jointly for State of Alaska House Power Alternatives Study Committee and Alaska Power Authority by the Institute of Social and Economic Research. Anchorage, Alaska. (June), Technical Appendices (May). Golze, Alfred R. (ed.). 1977. Handbook of dam engineering. Van Nostrand Reinhold Co., New York. Gordon, J.L. and A.C. Penman. 1979. Quick estimating techniques for small hYdro potential. Water Power and Dam Construction (Oct.) Holden and Associates, Fryer Pressley Elliot Associates, and Jack West Associates. 1981. Reconnaissance study of energy requirements and alternatives for Kaltag, Savoonga, White Mountain and Elim. Draft report, prepared for the Al aska Power Authority. Institute of Social and Economic Research, University of Alaska. 1976. Electric power in Alaska, 1976-1995. Prepared for the House Fi nance Commi ttee, Second Sessi on, Ni nth Legi sl ature State of Alaska. Prepared by ISER in cooperation with Kent Miller, Robert Retherford Associates, Stefano-Mesplay and Associates, and National Economi c Resea rch Associ ates. Anchorage. Kilday, G.D. 1974. filean monthly and annual precipitation -Alaska. NOAA Tech. Memo. NWS AR-10. Lamke R.D. 1979. Flood characteristics of Alaskan streams. U.S. Geol. Survey Water Res. Invest. 78-129. Linsley, R.K. and J.B. Franzini. 1964. Water resources engineering. McGraw-Hill Book Co., Inc. Linsley, R.K. et ale 1975. HYdrology for engineers. 2nd ed. McGraw- Hi 11, Inc. Ott Water Engineers, Inc. reconnai ssance study. Di stri ct. 1981. Northwest Alaska hydropower U.S. Army Corps of Engineers, Alaska R.W. Retherford Associates. 1980. Reconnaissance study of the Lake Elva and other hYdroelectric power potentials in the Dillingham area. Alaska Power Authority, Anchorage. R.W. Retherford Associ ates. 1981. Draft report: reconai ssance study of energy resource alternatives for thirteen western Alaska vi 11 ages. Prepa red for State of Al aska, Al aska Power Authority. Anchorage, Alaska. 7-2 Rutledge, G. et al. 1980. Alaska regional energy resources planning project. Vol. II -Hydroelectric development. Alaska Div. of Energy and Power Development. Scott, Kevi n I'I. 1978. Effects of permafrost on stream channel behavior in arctic Alaska. U.S. Geol. Survey. Prof. Paper 1068. U.S. Govt. Prtg. Off., Washington, D.C. Tudor Engi neeri ng Company. 1981. Simpl ifi ed methodology for economic screening of potential low-head small-capacity hydroelectric sites. Electric Power Research Inst. (EPRJ) EM-1679. Tudor Engineering Company. 1980. Reconnaissance evaluation of small, low-head hYdroelectric installations. U.S. Dept. of the Interior, Water and Power Resources Service. U.S. Army Corps of Engineers. 1979. Feasibility studies for small scale hydropower additions. tHIS. U.S. Army Corps of Enyineers, Alaska District. Undated. Electrical power for Va 1 dez and the Copper Ri ver Basi n. Interim Feas·r bi 1 i ty Report and Fi na 1 Envi ronmental Impact Statement. U.S. Army Corps of Engineers, Alaska District. 1981. Small-scale hYdropower reconnaissance study, Southwest Alaska. U.S. Army Corps of Engineers, Portland District. 1979. Hydropower cost estimating manual. U.S. Department of Agriculture, Soil Conservation Service. 1979. Exploratory soil survey of Alaska. U.S. Department of the Artily. 1978. Construction empirical cost estimates for mil itary construction and cost adjustment factors. Army Regulation 415-17. U. S. Depa rtment of Energy, Al aska Power Admi nstrati on. 1976. Inventory of potential hYdroelectric sites in Alaska. U.S. Department of Energy, Alaska Power Administration. 1979. Small hYdroelectric inventory of villages served by Alaska Village El ectri c Corporati on. U. S. Department of Energy, Al aska Power Admi ni strati on. 1981. Preliminary evaluation of hYdropower alternatives for Chitina, Al aska. U.S. Department of Interior, Bureau of Reclamation. 1974. Design of small dams. U.S. Govt. Prtg. Off.,Washington, D.C. U.S. Department of Interior, Heritage Conservation and Recreation Service. 1981. National Register of Historic Places; Annual Listing of Historic Properties. Federal Register 46(22): 10623-10624. U.S. Environmental Data Service. climatological data, Alaska. Admi ni strati on. 1949-1979. Annual summaries- National Oceanic and Atmospheric 7-3 PART II -COMMUNITY AND SITE DATA INTRODUCTION Part II of this report provides information specific to each community studied. The communities are grouped as follows: 1) The first twelve sections (numbered 1.0 through 12.0) contain information for the Southcentral Region communities which were visited in the field. A brief text is included to provide insights gained during the field visits. Summary data for the detailed studies are included. 2) The next 13 sections (Hope through Ferry-Suntrana) contain detailed study data, but no summary text because these communities were not visited in the field. 3) The remaining communities (Cape Yakataga through Susitna) were not studi ed beyond the prel imi na ry screeni ng, and therefore those sections contai n only prel imi nary screeni ng resul ts. Listed below are explanations of the terms and abbreviations used on the computer output contained in Part II. Term/Abbreviation Nondiscounted/Nondisc Oi scounted/Oi sc Operation and Maintenance/O and M Explanation The nondiscounted cost of power at a given point in time is equal to the cost of delivery in 1981 dollars. The disco~nted cost of power at a given point in time is equal to its present value in 1981 dollars calculated at a discount rate of 7-5/8 percent per year. Operating costs were assumed to vary with plant size while maintenance costs were assumed to be fixed at 6 percent of the installed cost of the plant. 1.0 BROAD PASS -C~~TWELL 1.1 COHMUN lTV DESCRI PTION The communities of Broad Pass and Cantwell are located on the George Parks Highway south of Denal i National Park and are approximately 20 miles apart. They have been evaluated as one unit since Carlo Creek potentially could serve both com~unities. Broad Pass Broad Pass is not a typical community in the sense that there are no schools and community hall that serve as a community center. Unlike the settlement patterns of many bush villages, Broad Pass is populated by 12 persons dispersed over a 25 square mile area. The dispersement of potential consumers is a constraint on the economic feasibility of installing electric distribution lines. Residences in Broad Pass either have no electricity or use small household generators. The current price of diesel fuel is between $1.40 and $1.50 per gallon. Potential consumers of electricity include the Igloo Lodge and the Coronado Mine. Residences are proposed to be built at Colorado Lake 6 miles south of Broad Pass but they would most likely be second homes and not use electricity. Cantwell The center of Cantwell is located 2 miles off the highway and includes several residences, cafe, garage, and railroad depot. Gas stations, grocery stores, and a lodge/restaurant are located at the junction of the George Parks and Denali highways. The current population is 95. Similar to the conditions in Broad Pass, there is no central diesel generator. Nearly every household has an individual generator which costs between $1.40 and $1.50 per gallon to operate. Electrical applicances found in most households include radios, lights, toasters, coffeemakers, televisions, and car heaters. Propane is used to substitute for or supplement electricity since the diesel generators are expensive to operate and are often unreliable. r·10st homes use coal or oil for space heating. Twel ve new HUD houses are planned to replace some of the older hOlJsing stock and these \lould be equipped with electrical wiring. The economic outlook for Cantwell is not encouraging. Current local sources of employment are few and include the Usibelli Coal Mine and Jack River Inn. Prior to the federal job cutbacks, the Denali National Park fonned the economic backbone of Cantwell. The rail road was a former employer as well. Residents could then earn enough money during the summer to carry them economically through the year. 1-1 Electric energy demand is not anticipated to increase signficantly. The major factor constraining electricity consumption is lack of jobs. No new projects are planned for Cantwell in the near future that would affect the economic base. 1.2 SITE SELECTION The two most attractive sites near this community are located in the Denal i National Park, and were therefore not considered further. T~'IO other sites were overflown and one site north and one south of Cantwell were vi sited. Observations made at Carlo Creek (Site 05) confirmed this basin to have the most potential for development. Ample stream flow in a narrow valley in sedimentary bedrock, and a powerhouse site located on the Nenana floodplain, only half a mile from the Anchorage-Fairbanks Highway, combine to make this an attractive potential site. Although fifteen miles of transmission line to Cantwell, and eighteen miles of line to Broad Pass would have to be erected if this project were to be built today, the proposed high voltage Anchorage-Fairbanks transmission line was assumed to have already been erected in the evaluations for this site. Slime Creek (Site 04) drains the adjacent basin, five miles further south. The hYdro potential of this site closely resembles Carlo Creek without quite equalling its attractiveness. There might, however, be future interest for consideration of this potential development, especially if construction of the Anchorage-Fairbanks intertie proceeds. Site 11, on a northern tributary to Cantwell Creek north of the CAA station near Summit, is located in a 100 foot wide valley with no evidence of excessive bed material transportation and with its abutment sloping steeply at 30 to 40 degrees. Although potentially attractive and located only seven miles from Broad Pass, the site was not judged to be able to compete with the more distant Carlo Creek site. Because of its proximity (within seven miles) to Cantwell, Site 01 was also overflown. It is located on a southern tributary to the Jack River, 1/4 mile upstream of its emergence into the Uenana plain. Although the dam site geometry is attractive, access to all elements of this development would be prohibitive because of the steep rocky cliff faces forming the creek abutments. Topographically, the Jack River here itself appears to provide an excellent site for a 300 foot high dam. 1-2 NOTE: TOPOGRAPHY FROM U. S. G. S. -HEALY ALASKA, 1:250,000 5 0 5 SCALE IN MILES LEGEND 'Y DAM SITE • POWERHOUSE o SITE NO. - --' -PENSTOCK ---TRANSMISSION LINE' ------WATERSHED y'> / M 0 n i!,li'a n -J ~ >-,..-~-~-. ---~E~'?l:_,~---~ REGIONAL INVENTORY a RECONNAISSANCE STUD'( SMALL HYDROPOWER PROJECTS SOUTHOENTRAL AlASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING BROAD PASS -CANTWELL DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS H,ldro~or/er Potenti al Installed Capacity Site No. (kW) 11~/ 1710 Demographic Characteristics 1981 Population: 12 SUMMARY DATA SHEET DETAILED INVESTIGATIONS BROAD PASS, ALASKA Cost of Installed Cost Al ternaji ve Po\'Ier_/ ($1000 ) (mi 11 s/kWh) 17,706 500 1981 Number of Households: 3 Economic Base Tou ri sm Subsistence 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of I1Ydropower Benefit/Cost (mi 11 s/kWh) Ratio 260 1. 91 See Appendix C (Table 6-8) for example of method of computation of cost of alternative power. 2/ Site could also serve Cantwell. Hydropower Potential Si te I~o. 11~/ Install ed Capaci ty (kW) 1710 Demographic Characteristics 1981 Population: 95 SUMMARY DATA SHEET DETAILED INVESTIGATIONS CANTWELL, ALASKA Installed Cost ($1000 ) 17,706 Cost of Al ternatl/" ve Power'! (mi 11 s/kWh) 500 1981 Number of Households: 21 Economic Base Touri sm Mi ni n9 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower (mills/kWh) 260 Benefi t/Cost Ratio 1. 91 See Appendix C (Table 6-8) for example of method of computation of cost of alternative power. 2/ Site could serve also Broad Pass. ~EGIO~AL INVE~TORY i RECONNAISANCE STUDY -SMALL HiDROPOWER PROJECTS lEAF' 1 .:;.: ;~~ I.) 1 .::;.; 1 1.:';8~5 !. '~;34 L ':;'85 198,::- 1~};7 1':;;8:3 19:39 1. .:;.:;, ,) 1 q (i 1 L ';'9 ,:~ J.Q Q 4 l '?9!:::i 1 ':';96 1997 19'::-:3 1 .:;..:;. ':; 2(nj2 2 1.)(J:3 .2 t) I.) 4 2(.,,)5 2 1)')6 :: I.~J~) 7 2'')('8 21) l') 2(11 1 21,)12 2'} 13 2') 14 :2') I, '5 :>j J. ,:; :: ,) 1 -;; :2'} Ul 2(11 .:;. 2(':~ 2 . ~ I.:':~ 3 2',)25 ALAS~A DISTRICT -CORPS OF ENGI~EERS LOAD FOREC~ST -BROAD F'ASS ~ILOWATT-HOURS PER YEAR LmJ ·<.h) l) l) I) • 41673. A3346. <4::;CI1'~ • 4,~69:: , 48364. 50',)37. 5171 I}. 53383. 55t.'j5,~ • 5672'''. 58177. 59625. ,SlC'72. ,S3968. ~i5416. ,-;:.68.~4 • 68311. ,::'9759. 712!)7. 7 2!)45. 72884. ---'-1) ./ . .!J ./ .... ..:.. • 7 456!) • 75398. 76237. 77tj75 ~ 77913. ?8752. 7959!) • 8C,~,!j5 • 81.621. 82C::,36. 83652 .. 84667. 85682. :3.5698. 87713. 88729. 8':;;744. 90572. . ? 2229 ~ 93')58. 93886. 94714. 95543. 96371. ~720tj ~ 9:3!)28. MEDIUM 4 •. } • .) !j I) • 41,~,73. 4334,S. 45·jl9. 46692. 48364. 5!)I,)37. 5171':'. 533834 5S(j56. 56729. ,~t)753 • 64776. 68800. 72824. 7,S848. 8()871. 848·?5. 88919. 92942. 9,S966. IIH207. 105448. 109690. 113931. 118172. 122413. 12·S654. 130896. 135137. 139378. 141353. 143328. 145304. 147279. 149254. 151229. 153204. 15518!} • 157155. 159130. 161072. 163015. 164957. 16691)':' • 168842. .17')784. 172727. 174669. 176612. 178554. HIGH 4!}lj00. 4l6T:5. 43346. 45!)1 9. 46692. 48364. 5!)'.)37. :j1'710. 53383. 55056. 56729. 63329. 69928. 7,-)5,28. 83127. 89727. 9632t:, "' 102926. 10952':; • 116125. 122724. 130368. 138012. 145657. 1533C'1. 160945. 168589. 176233. 183878. 191522. 199166. 2!)2101. 2!)5!)36. 2!)7971. :2 U)'''··)6. 213841. 216776. 219711. 222646. 225581. 228516. 231572. 234'~129 .. 237685 • 24!)741. 243797. 246854. 2499 l\). 252966. 259 !) 7':;' • LOW 14. 14. 15. 15. 17. 17. 18. 18. 19. 19. 2'.) .. 2t) .. 21. 21. 24. jC' ~.J .. 25. 26. 26. 26. ,,,"; .:.. I ... 27. . 27 ... 28. 29. 29. 3,,) • 3',) • 3!) • 31. 31. 31. 32. 32. 32. 32. 33. 33. 33. 34. riE 'c, I Un 14. 14. 15. 15. 1·~ • 17. 17. 18. 113. P. 1 ,~ • ;.~ 1 • , , ...:.....:... 25. 2,~ • 3lj ... ::5:: "' 3~~ 39. 4'.} • 42. 43. 45 • 46 • 48. 48. 49. 5!} . 5() ... 51. 5:3. 54+ 54. C' ::' .J.J • 56 • 5,S ., C'''"; . .-J l • 58 • 58. 59. 6(i. 6\} • 61. HI':iH L'f , 14. 1 ~~ .. 1 .-;:, • 1.': , 1 -, , 1 ;~, , L :=5. 1 .-; . 1 .-;. 2·~· .. j'., ...... ' . 3 L , .~.~ .. ~~= . .<.\7. 51.) • ::I:j ... :.~ ;'j .~ 6 1.; • ,~,~ ... ,~8 • 6~. 7 L • ..' ,,;.. ... 74. "";C:- l .J .. ./ I~ • 77. 8'·", • ;3 1 + 82. 83. 8~. 8,~ .• 87. 8~~ • ;;'EG I DNi4L INVENTORY & RECONNi4 ISArKE STUDY -SMALL H'1'DROPQWER PF\:O.JEC 75 ALASKA [IISTf;:ICT -CORPS OF ENGINEERS LIJA[I FOF:ECA5T -CAiHWELL t< I LOWAT T-HOIjf\~S PER YEAR ArWUAL F'EAr;: [lFMArW- '(EAF: LOW MEDIUM HIGH LOW ME[I I Uri HIGh 19:31) 3:301}')") • 380')01) • 380000. 130. 131) • 131} • 1':';:31 395893. 395893. 395893. 136. 136. 136. 1'::;0:;.-) : ._ .... :.. 411785. 411785. 411785. 141. 141. 141. 1':;;83 427678. 427678. 427678. 146. 146. 146. 1984 443571} • 443571) • 443570. 152. 152. 152. l'7'85 459463. 459463. 459463. 157. L57. 157. t ~'86 475356. 475356. 475356. 163. 163. 163. 1987 491248. 491248. 491248. 168. 168. 168. l,,.88 507141. 50714L. 51)7141. 174. 174. 174. 1989 523033. 523033. 523033. 179. 17'1' • 179. 1991) 538926. 538926. 538926. 185. 185. 185. 1-1'91 552680. 577151. 601621. 189. 198. 2')6. 1992 566434. 615376. 664317. 194. 211. 22:3. 1993 580188. 653600. 727012. 199. 224, 249. 1994 593943. 691825. 789708. 21)3. ~~/. 270. 1995 607697. 730050. 852403. 21)8. 250. 292. 1996 621451. 768275. 915098. 213. 263. 3l3. 1997 635205. 806500. 977794. 218. ,-. ~ /.~. 335. 19'''8 648959. 844725. 1040489. '"j"i"i .:...:...:... . 28'1' • 356. 1999 662713. 882949. 1103184. ..,--.:.L/. 302. 378. 20-.)'.) 676467. 921174. 1165881). 232. 315. 3'1'9. 2001 684431. 961466. 1238500. 234. 32 lt. 424. 2002 692396. 1001758. 1311119. ,--.... .,) / . 343. 449. 2003 700360. 1042050. 1383739. 240. 357. 47 2')04 708324. 1082342. 1456359. 243. 371. 4'?- 2',}1)5 716289. 1122633. 1528978. 245. 384. ;:..:.:4. 21)1)6 724253. 1162925. 1601598. 248. 3-7'8. 548. 2',j(> 7 732217. 1203217. 1674217. 251. 412. C"----1.1 . .!l • 2(,v8 740182. 1243509. 1746837. 253. 426. 598. 2009 748146. 12838\) 1. 1819457. 256. 440. 623. 2010 756111) • 1324093. 1892076. 259. 453. 648. 2011 765756. 1342857. 1919959. 262. 460. 658. 2012 775401. 1361621. 1947841. , ... ... 00. 466. 667. 2013 785047. 1380385. 1975724. 269. 473. 677. 2014 794693. 1399151) • 2003607. 272. 479. 686. 2015 804338. 1417914. 2031489. 275. 486. 696. 2016 813984. 1436678. 2059372. 279. 492. -~C" / V-.J • 2017 823629. 1455442. 2087254. 282. 498. 715. 2')18 833275. 1474206. 2115137. 285. 51)5. 724. 2019 842921. 1492970. 2143020. 289. 511. 734. 2020 -"',C"" . 1j,.J ... ;:I00. 1511734. 2170902. 292. 5i8. 743. 2()21 860436. 1530187. 2199937. 295. 524. -.,.-/ . .J.~ • 2 t.)22 868307. 1548639. 2228972. 297. 530. 763. 2023 876t77. 1567092. 2258007. 300. 537. 773. 2024 884047. 1585545. 2287042. 303. 543. 783. 2025 891918. 1603997. 2316077. 305. 549. 791. -~,' .::. v ... 0 899788. 1622451) • 2345112. 308. 556. 8\)1. 2027 907658. 164091j2. 2374147. 311. 562. 813. 21)28 915529. 1659355. 2403182. 314. C'.-·-101j • 82~· 2029 923399. 1677808. 2432217. 316. --C" ;:'/;:1. 83 2')30 931269. 169626,) • 2461252. 319. 581. 84:j. CANTWELL/BROAD PASS SITE 5 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Carlo Creek Section 32, Township 155, Range &/, Fairbanks Meridian Community Served: Cantwell, Broad Pass, Anchorage-Fairbanks Transmission Intertie Distance: 13.5 mi (from Cantwell) Direction (community to site): Northeast Map: USGS, Healy (C-4), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SP ILLWA Y Type: Openi ng Hei ght: Width: Crest El evati on: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbine Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINEl:/ Voltage/Phase: Terrai n:!/ Fl at (1.0) Ro 11 i ng (1. 25) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 14.9 34.7 40 sq mi cfs in Large Concrete Gravity 15 ft 2715 fmsl 570 cu yd Concrete Ogee 5 ft 66 ft 2710 fmsl Steel Penstock 30 in 6300 ft 2 Pelton 2170 fmsl 485 ft 1710 kW 52.0 cfs 5.2 cfs 1.2 14.4 18.0 5.0 23.0 mi kV/1 phase mi mi mi 41 percent 6142 MWh Flow Duration Curve 1/ Includes: 5.0 mi from powerhouse to proposed Anchorage-Fairbanks Intertie, 9.0 mi from Intertie to Cantwell, and 9.0 mi from Intertie to Broad Pass. 2/ Terrain Cost Factors Shown in Parentheses. .... ..... : : = ...... REGIONAL INVENTORY & F\ECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA CANTWELL-BROADPASS SITE 06 CONCEPTUAL LAYOUT CARLO CREEK DEPARTMENT OF TH E ARMY ALASKA DISTRICT CORPS OF ENGINEERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Site: Stream: Cantwell/Broad Pass 5 Carlo Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. kcess 6 T .. 1/ • ransmlSSlon- TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (A/P = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST ~ 176,000 ~ 546,000 ~ 1,904,000 ~ 419,000 ~ 557,000 ~ 21,000 ~ 199,000 ~ 18,000 ~ 606,000 ~ 4,446,000 ~ 445,000 ~ 4,891,000 2.3 ~ 11,248,000 ~ 2,812,000 S14,060,000 ~ 2,109,000 ~16, 170,000 ~ 1,536,000 S17, 706,000 S 10,350 ~ 1,385,100 ~ 212,500 S 1,597,600 0.26 1. 91 1/ Includes ~156,000 from powerhouse to proposed Anchorage-Fairbanks Intertie, S225,000 from Intertie to Cantwell, and S225,000 from Intertie to Broad Pass. ,t ! . I UN(H., I ~'NI::~~TOF:Y ~.,: RECONN?~:r :A4r\\I,~E :::; I Ul.tY-:::;MALL H't D~:Uf'-'WE.F( F'RI),Jt:::I: '~. ALASKA DISTRICT -CORPS OF ENGINEERS DETn I l._ED RECONNA I ::;:::;{4NCE I N've:; r I GPII II)N:::; (O:::;;T OF HYDF.:OF'Ot,..)[H --8[':::I\jE:~F': 1 'r C.O::::T RPd'1 U C{:)NTI-JEl_L :::; I TE NO. ':::' '([;:41( 1 '::'::::4 1 0':"-.' • 1 •• ' ' •. '! 1 ':::' ::~:::: 1 ':~' ::::: ',"! :l ')'::!(I t -:;) ':j .l 1 ':j':':',~, 1'::'97 1 '~!':':=; l'~.J ':) '~) 20()(; :=::001. 200::::: 2UU:~: 2004 2 o v:; :Z(\()(:· :~::uo/ :::UO:=: :?(HY' /OlU ,>.)11 201.2 :>i1.:·~: :::() 1 ·!i· 2Ul':; :::~ 01 (:, :? (t 1 ~:' 201:::: ?O 1 ':'i f::~'jH/ YEAF: ,~;.14·?UOO • (:.,14'::000. 6142()OO. 6142')0(1, i,llj·:20U(I. ,0, 142(rOO. 6l"'120(1i) • 614200() • 61'12(1)0. 614::(11)(1. ,/:,14:2000. 61 l j.2000. b 1. t+2')OO. (,14:.2000. {:.,142000. ,~,142000. 1.':0 1 42.)00. ,::,~, 4 :2000. 614:?OOO. (,14200 ') • 1;..142000. ,'~, 14~~:OO(l. (~, 14·2000. 6142UOO. i;" l'l:?OOO. ,~:, 14~::OOO. i.:" 14:2000. 611.1;'::000. {:' 1420(10. /:' l l ].?()OO. .':,142000. ''::' [':j.?OOO. 6142000. 6142000. 61 I L2r)(lU. /:' [42000. ,~,142000. ,0, 1 42U(,I) • ,1-, 1420()(l. /.::, l4:'::-000. .:?O~-::/j. 1:.,142000. 20Z:; ,::'14~'()()(). :;~: ():2 .. ~:, (~, 1 4 '2 (~() () \0 . :>,'/.,i ,~, 142000. ;::.', " ::: (. 1 'f ;;:'YH) • ,," i.:-:, t.1.42000., : . .>'::;;) !:' 1..11-2(100. AVERAGE COST CAP I T(..~L 1394171. 1 :~:'~i41 7 1 • 1 :394171 • 1. :~:941 -71 • 1 :;:94l71 " 1.':94171 • 1. ::;::':''41 71 " 1 ::::';!·41 ? 1 " 1 :.::941 71 " 1. ::::':::'4l 71. • 1 ::::':'i 4 171 " 1 J':~"·41 71 • 1::':::'.<.11 '11 • 13';'4171 • 13'~!41l1. 1:394171. 1 '::941 71. 1. :::::94171 • 13';'4171 • 1:::941 71 • 13':;'4l71. 1 ::::941 71, • 1:394171. 1394171. 1 ::::94171 • 1 ::::';/41 71. 1394171. 1394171. 1 :~:9lll 71 • 1:;::94171. 1394171. 1 ::::':'-'4171 • 1 3':;!·<]·171 • 1 :3':::'41 71 • 1394171. 13';/4171 • 1 ::::';!41 71 • 1 3':')~·1 71 . 13'"'4171 • :I. :::::941 71 • (I ~~ M 212'=:;00. ~~ 12~;OO. 212':iOO. ,:~ 1 2~5UO. 212500. 21 :?'500. 21250(1" :21 ':25 (H) • 21 ~~:~;O(l. 212500. 212'500. 212~:~OO • ::~ 1250u. 2L2500. 212500. 21.2500. :212500. 212500. :21 ~:'50(1. .::: 12500. :212~,OO • 212~~OO . 21 ::2500" 212500. 21 ;::~~OO. ',212500. 212500. 212500. ::::: 1.2500. 212500. ~~ 125()(). :21 '25()(). 2:1. :::~;OO. ~~ 12500. :212500. ? 12~'OO. 212":;00. :::-'1 2~50(). ::21250(1. 1.:;::941.71" 21 ~?":iOO" 1 394171 • ::: 1. ::'~'i(j(I, 1 :;:941 71 • :::: 1 ?~~l)(). 1394171. 212~;OO • 1:;:94171.)12500, 1394171.. 212<'500. 1 J9,<l1. 71 • ::: 12':;00. TClTAl_$ 1606671. 16U6/~,71. 1.606671. 1,601..:,('71. • 1.606/:.71, 16(11':,,1:,71 • 1,·::;,06671. 1 (~,O,I:,(:,71, 11::.UI..~,(~,71. • 1606671. 1/:,06671. U:,061..:..71. 1.606671. 1606671. 1606671. 1606671. 1606671. 1606671. 1606/:,71. 160I::.t,71. 1/:,066'71 " 1 ,1~,06(:' 71. • l(~,06671 • 1,1::,06671. 1606671. 1601':,671 • 1.606671. 1601..~,(,71 • 1 (:,Ob/~,71 • U:,Ot,t,71. 160/-,671. 1601:',671" 1606671" 1606671. 1 (~,O(·,I:',71 • 1 t.(16671 • 1606671. 1606671. 1606(:,71, 1601:,(-, 7l • 1;/ l<l,~H $,.. f:.WH NUND:r :::;I~: 1.1] '.:C o. ~::62 o. 1 '::!~:; (>" 262 (). H~: 1 o . 2 «: o. it, ::::: O. 262 O. 1 ~,,~, f, I" ::::: {,:. (). 1 Ll '5 0.:>,::: O. I. ?:i o ... .::: i:., -;:: (l" j J /' f) ,,? (:,2 0., 1 u :::: f).;:~6? (1.101 O. ~::62 (>. 'Y'4 o .?,«: ()" 0::::7 0.26:2 0.0:::1 <). 2,1:,2 (>. 07':; 0.262 0.070 0.262 0,,()65 0.2(:',2 0.060 O. :262 I)" 05{~, () II 2/~,::: (1. (j~:~~~ o . 2 (:..:::: (>. (i Li e o . ::><:: (l .' ('I 4 ~:~ 0,,2\:" 11,,04,:::: () ,. ~~:: I::., ? () " ():3 ':~) () .. '::' /.:-? ()" (I ::~: /:. O. ;::6:2 0.0::::::;:: O.2/:'2 0.0::':1 O. :?(:,2 (>.02':' o. ::J:.2 (l • U:':7 ()" ~'2 ,,~, .~~: ()" () 2 ~3 0.21..:,;:: 0.02:: (1.262 (). ')22 0" '2'6'2 0.0:::::0 (>. .? (,:2 0 , () 1 9 0.2(,,' O. OJ. 7 0,,;'::/:,':: 0.016 0.262 O"Ol':':~ 0.262 0.014 ().26'2 0.013 I). '<~:b:? (I. 012 (). :2 (~. ? (>. 0 j t 1. f:.()61..:·71 • 0 .. /1:, .. :: U" (> 1 0 1606671. O.2~2 0.010 1 t, 0 I:, /:'::' 1 • () " ;: (~, ::': (i" (lfY) 1606/:,71. 0.262 0.008 1606671. 0.262 0.008 1606671. 0.262 0,,007 1.1:',01::,671 .. 0 ":::6::' O. 007 Cantwell, Al aska Carlo Creek Drainage Basin View of Cantwell Community 2.0 CHICKALOON 2.1 COMMLIN lTY DESCRI PTION Chickaloon is located on the Glenn Highway 76 miles northwest of Anchorage wi thi n the Matanuska-Susitna Borough. The popu1 ati on of the village itself is 43, and many residents are located in outlying areas. The Victory Bible Camp in the vicinity has a population of approximately 300. For the purpose of projecting electrical energy demand, the population of the village has been used. Chickaloon is served by the Matanuska Electric Association (MEA), which buys power wholesale from Chugach Electric Association. In addition to the residences, a lodge and gas station are located in the village and use electricity. r~ost households have freezers and car heaters as well as the usual small appliances. The average household electricity consumption falls within a range of 400 to 600 kWh per month. Average monthly bills range from S36 to S55. Consumption increases slightly in the winter due to the use of car heaters. Wood or oil is used for space heating and propane is used for cooking. The rate of unemployment is high. The lodge and gas station are the only local sources of employment and together employ five workers full time and one part time. The remaining employable residents work seasonally either as guides or in the construction business. The demand for electricity may be expected to increase if industry is attracted to Chickaloon. Otherwise, growth would be constrained by the lack of jobs. Chickaloon has experienced some population growth with households re10cat"ing there, in part due to people moving away from Anchorage. A new subdivision on Fish Lake has 5 houses but no power yet. The Village Council has an interest in developing agriculture in the form of hYdroponics, which is dependent on the availability of less costly power. The project would provide year-round jobs to some of the residents. Another factor that may stimulate growth is the potential to reopen mines in the area or to develop local lime deposits. 2.2 SITE SELECTION Three sites were investigated in the field for the community of Chickaloon. Site No.5, Boulder Creek, had previously been id~ntified as a potential hYdropower site in another study and presently) sunder consideration for development as a major hYdroelectric development. The site has a very narrow gorge which is ideally suited for a 25 foot concrete dam. The penstock route is somewhat difficult, especially through the gorge itself. The pipe would have to be anchored into the gorge wall, or possibly a shelf would have to be blasted along the wall. The powerhouse site presents no major difficulties. There is no existing access to this site, however. 2-1 Carpenter Creek (Site 10) had a very attractive benefit cost ratio in the preliminary screening. However, a major drawback appeared to be site access. The terrain leading to the dam site is rather steep and the access road would follow a very circuitous route. In addition, either a bridge across the Matanuska River connecting the site with the Glenn Highway would have to be built, or a proposed road on the south bank of the Matanuska River would have to be in place. The most promising feature of the site is the presence of very narrow rock gorges which may be well suited to large dam construction provided the material proves structurally sound. An upper and a lower gorge were identified during field reconnaissance. A potential difficulty would be the penstock route since it would have to be located within the gorge and placed either by blasting a shelf or anchoring it into the rock wall. The geology of the site is primarily sedimentary rock, including some coal seams. The Kings River site, No. 12, was the fourth most desirable site based on the preliminary screening. However, visual inspection indicated the site had perhaps greater potential than earlier anticipated. An access road, which was not shown on the USGS map, is located relatively close to the site and would require only minor upgrading for construction purposes. The dam site is located in a relatively narrow reach of the river, and a concrete dam would be appropriate. In addition, the penstock length would be much shorter than typically was encountered at other sites. The 2500 foot penstock would drop about 200 feet over its length. This site therefore was chosen as the primary site for further consideration, especially since Boulder Creek is already under investigation. 2-2 NOTE: TOPOGRAPHY FROM U. S. G. S. -ANCHORAGE ALASKA, 1:250,000 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO. PENSTOCK ---TRANSMISSION LINE ---WATER SHED 5 o 5 E3 F=4 E3 SCALE I N MILES REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED I N PREll MINARY SCREEN I NG CHICKALOON DEPARTMENT OF THE ARM'!' ALASKA DISTRICT CORPS OF ENGINEERS H.tdro~ower Potenti al Installed Capacity Site No. (kW) 12 7,744 Demographic Characteristics 1981 Population: 43 SUMMARY DATA SHEET DETAILED INVESTIGATIONS CHICKALOON, ALASKA Cost of Installed Alternative Cost Power .. !.! ( SIOOO) (mills/kWh) 17,956 387 1981 Number of Houeho 1 ds: 12 Economi c Base Touri Slil Subsi stence 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mi 11 s/kWh) Ratio 65 5.96 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. I.~. E;:2 1 o:~3 L '?84 1 <:~'8'::. 1'::';8 -:' 1988 1989 i .? 9 I.) l'~94 l':; 9 :,; 19 '7'.::, 199 7 1998 l099 21)(11 20()2 2()\)3 21}1)4 2·)\)5 2 1.)0.-':- .21.:,.) 7 2(11)8 2009 2(.11 I) 2') 11 21) 12 2\)13 2',)14 2(!l5 2 IJU) 2017 2')18 2 1)19 21)22 "j" "")-,,"I).:...~ 2t)24 "j .. ,,,--.:..V.;..~ 2,)26 2('::7 2 1j2!3 2tj29 REGIONAL INUE~TORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALAS~A DiSTRfCT -CORPS OF ENGINEERS LOAD FORECAST -CHIC~ALOON t, ILCjWATT -HOURS L Ol-J riEll I Uri 184286. 184286. 190764. 190764. 197242. 2\j37:». 211)1~:3+ 216676. 2231~53·. 229631. 2361\)9. 242~'S87 • 249\)65. 25513.!lt 27335 L • 279422. 2854'i3. 291565. 291',~36 • 3037')8. 309779. 3161:)4 1). 322301. 328562. 334823. 341(184. 347344. 353605 • 35.:;1866. 366127. 372388. 38059(). 388791. 39.~.:;193 • 405194. 413396. 4215.:;17. 4.29799. 438t)(II) • 446202. 454403. 459865. 465:327. 470.)789. 47.!)251. 481713. 487.175. 492637. 498 1)99. 5(13~5o 1. 50)9\)23. 21.j3 7 :~~j • 21',)198. 21667.~. 223153. 229631. 23.~ 1 (j9 • 242587. 249',)65. 2641)41. 279('17. 293992. 3t)8968. 323944. 33892'J. 353896. 368872. 383847. 398823. 416;347. 434872. 452896. 47t)92(). 488945. 51)6969. 524993. 543018. 561042. 579066. 590586. .~02105 . .:::013625. 625144. 636664. 648183. 65'~703 • ,~71222 .. 682742. 694261. 7\)3574. 712886. 722199. 731512. (41)824. 75()137. '759451) • 768763. 7781)75. 787388. F'ER '(EHF: HIGH 184286. 191)7t.4. 197242. 2\)3721; • 21':'198. 216676. 223153. 229631. 2361 I)':t. 242587. 249(j65. 272945. 29.~825 • 3207,)6. 34458.~ • 368466. 392346. 4l6226. 44\H07. 463987. 487867. 517655. 547442. 577231) • . ::'07018. 636805. .:::066593. 69638.1. 726169. 755956. 785744. 800582. 815419. 830257. 845094. 859932. 874769. 889607. 904444. 919282. 934119. 947282. 960446. 973609. 986772. 999936. It)1309<;.. 1026263. 1')39426. 1052589. 11)65753. ANNUAL ~EA( DEriAND-ni LOW MEDiUM HiGH ·!l3. 65. 1~8 ~ it) • 74. 76. 79. 8 l • 83. 135. a7. 89. 94. .:;1 . ..:, • 98. 10('., 1 t) 2. 1 t)4. l06. 1')8. 111.) • 113. 115. 117. 119. 121. 123. 125. 128. 130. 133. 136. 13'; • 142. 144. 147. 15t) • 153. 156. L57. 159. 161. 163. 165. 1.S 7. 169. 171. 174. 63. 74. 7.-j • 9:) • 9.,,:, • 1',) i + 1'),":' • 111 • 116. 121. 131. 137. 143. 14'; • l~::o. 1·:;1 • 1.:;7. 174. 113\). 113·..:. • 192. 1';;~ • 2,):2 + 21.)6. 2 1(' • 214. 218. 222. 226 .~ 23(.1. 234. 238. 24 i. 244. 247. 25!. 254. 2·":",) • 263. 21=>6. 271) . .' .,,:. ,~ , I.J . .j 1'·) 2 1 l'~1 1 ~;:: 12,~, 134 1·<.13 1 =,; L 1 =,j-:; i·":' : 1:/ 1;~ "7 1':;-8 -, I .::. ~ ... ,_, 2·4';- 25 0 2,~';' 28':' .. 3('1) 3t)'5 3 l'.) 3i.5 320 324 32'; 333 338 342 3~7 351 3 '5.:::0 3·~(· CHICKALOON SITE 12 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Kings River Section 31, Township 21N, Range 5E, Seward Meridian Community Served: Chickaloon, Matanuska Electric Association Distance: 7.0 mi Direction (community to site): Northwest Map: USGS, Anchorage (D-5), Alaska 2. HYDROLOGY Drainage Area: Estimated ~~ean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei g ht: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: I~i dth : Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo ltage/Phase: T e r ra i n :.!.I Fl at (1. 0 ) Mou nta ins (1. 5 ) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrain Cost Factors Shown in Parentheses. 99.0 399 60 sq mi cfs in Large Concrete Gravity 25 ft 1825 fmsl 1430 cu yd Concrete Ogee 15 ft 80 ft 1810 fmsl Steel Penstock 78 in 2500 ft 2 Horizontal Francis 1600 fmsl 191 ft 7744 kW 598 cfs 119.6 cfs 0.5 38 6.0 1.4 7.4 mi kV/3 phase mi mi mi 37 percent 25100 MWh Flow Duration Curve DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE BAS IN REGIONAL INVENTORY &. RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA CHICKALOON SITE 12 CONCEPTUAL LAYOUT KINGS RIVER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS I . ~ HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Communi ty: Chi cka loon Si te: 12 Stream: Kings River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equ"ipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val ves and BHu rcati ons 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST ~ 431,000 ~ 853,000 ~ 2,540,000 ~ 676,000 $ 188,000 ~ 11,000 $ 346,000 ~ 8,000 ~ 405,000 $ 5,458,000 $ 546,000 $ 6,004,000 1.9 $11,407,000 $ 2,852,000 $14,259,000 ~ 2,139,000 $16,398,000 $ 1,558,000 $17,956,000 $ 2,320 $1,404,700 ~ 215,500 $ 1,620 ,200 $ 0.065 5.96 i,! I., i l\r·jPd_ [ r'~\iE NTUF(Y' ~:( FFCUNNA I ::·;ANCE ::nUDY -:::;MALL HYm~UF'UWER F'F:O,JEI.T~:; ALASKA DISTRICT -COFPS OF ENGINEERS DETAIL.ED RECONNAISSANCE INVESTIGATIONS cu::n (JF~' Hf miClf"ilA.IFR --BEN[F I T c:o:~n RA r J: U Y[f:'ir;: 1 ':/:::;4 1 ') :::: ,:~, :I. 9::::7 1 '::-1::>::: 19::::') 1 ')';)(J :1.991 1,)92 1 -::)'::<:: 19'~il.j. 1 '::) ';.., ",,; 1 ';19/:. 199) 19')::: 1 ';.1'::;":,-1 2000 ::::001 '::~ClO::: 200:;:: 2004 ::::00':':; 200(~, :2007 2()Or: ::: eli) ':,) 2010 2U11 2012 2013 201·4 201 ~; 2016 201-.7 201 ::: 201') 2020 2021 202::: 2024 20:27 2():2:3 CH I U:::A U)OI\t :::' I TE NI)" L' ~:I,.JH / YEAF\: 2':-:; 1. 00000. 2'':'; 1 00000 • 251,)0000. 2:-:; 10(1)('0. 25100000. :::'5100000. 2'5100000. 25100000. 2~; 100000. 25100000. 2'::~1 00000. 2~51 00000. 2:=; 100000. ~~51 ()OOOO. '2~31 00000. 2:;100000. 2~31 00000. 25100000. 2~5100000. 2':; 100000. 25100000. 2':i 100000. 2':; 1 00000. 25100000. ::2~51 00000. 25100000. 251 O()OOO. ::::; 100000. 2::; 1 oooon. 2~; 1 00000. 2'51 OUOOO. 2':i 1 00000. 25100000. 25100000. :25100000. 2~:51 00000. :25100000. :2~; 1 00000. :2'::; 1 00000. 25100000. 25100000. 25100000. 25100000. 25100000. 25100000. CAP I TAl_ 1413:::56. 141 ::;::::::56" 141'~::='::5(:' • 1413::::56. 1413:::5,1: .• 1 41:~:::::5(:'. 1413:::56. 1413:::56 " 1413::::56. 141 :~:::::56. 1 41 :~::::~~'-::' • 141 :~::::5f:,. 1413:::':01:, • 141 :~::=:56. 141 :3::::56. 1413:::'56. 141 ::::::::56. 1413:::0::;6. 141 ::::::;:56. 141 ::::::::":';'~" 1 41 :::::::56. 1413::;56. 1.41 :::::::::'56 . 141 :::::::~36. 141 ::::::::56. 141 ::::::::5('-,. 141 ::::::::56. 1. 41 :3:;::56. 1413::::56. 1 41 :::::::'5 (:' • 141 :~::::5(::,. 141 :~::::t::;6 • 1413:::5(.:0 • 141 :::::::':,6 • 141 :::::::56. 141 :;:::::56 • 1 41 ::::356 • 141 ::::::::56. 141 .::::::':i,~,. 1413:::56. 141 :::::::56. 141 :;::::56. 141 :::::::~i(:. • 141 :;::::56. 1 41 :~::::56 • o ~( M 21 ':i500. :215500. 215500. 215':,00. 210:=;0:=;00. ~7: 1 ':i500" '215500. 21 ':'i::;OO. :::: 1 ::;500. 215':;00. 215500. 215500. 215':;00. 21.5500. 215500. 215500. 215500. 215500. 21 ':i500. 215~;UO. 21 '::i~~OO. 21 ':,500. ~: 15':iOO. 215500. 215~:;()() • :215500. 215500. 215500. 21550U. '215':;00. 21 :=;500. 215500. 215500. 215500. 215500. '21 "5500. 215500. 2l55()O. 215500. 215500. 215500. 215500. 215500. 215500. 215500. 2029 25100000. 141 :::::::'56. 215500. 2030 25100000. 1413856. 215500. AVERAGE COST TUTAL$ 16:29::::~i6 . 1629:::0:;6. 1 (:,29356. 1";;,:2";"3':i6. 1629356. 1 (~,:29:::::~;6 • 1629:::':;6. 1";;,29356. 16:;29356. 16:::'<:"::;1;:. • 1629::::~:;6 . 1629:~:~-,(~, • 162':!.:::~;6 • 1629:::"36. 16293':;6. :[ (~,2'~1::::56. 162'::<::~:i6 • 1";;,293':i6. 16293'::,6. :t 62')3~:i6. 1629::-::':i6. 1629:3:=;6. 162930::;6. 16293~,6 " 1629::::':;,~:o • 1 6 ~:: ';<:::i (-, • 16293':i6. 1629::::":~6 • 1629'3'5,~, • 1 (.<:::9:.::";';6. t 62':;13~i6. 1629::::':i6. 1629:::::56. 1629:_:::5(:, • 1629::::':;6. 1629::':~~~6 • 1629:;:5(:, • 11.:,2'~}::::5e, • 1(:,29356. 1(:,29::::':;6. 1629::::5(:, • t, /I<t..JH $ / ~::WH ()" O~.~:i 0" 06~~; (I. O(~,~"i O. 06~~! O. 0/:,'::; 0, 06:c~ 0"n6",,; I). i)6':i O. ,)(:,"3 () .. () (, ~:;.; U. (16~' I). O(,,:"-i (). () r::-~··; () a t)I~I~; (l. O/:o:~~ () . () /:.' ~~;; (I. (),~~, ~"i O. 06''5 0.06:, O. 06':; 0" 06'::', 0.0(:<', O. U6:i () II (;(-,~i O. (l//:"; () a () ~-, ~~I i). 06~" () II I )'~I ~:';i (I. 06~S o " 'J ,/:' ~'~; (I. 06~:, O. (I";;,:'; <)" 06~~; O.OU', 0.065 O. O(:,~, O.06':i n. (j,';:,,,C; o " 06~'-! O. 06~::; O. 06~, O.OU5 O. 06::; O.OU::i O. ')(:,~~i or '=;( (). (14:: o. ()4'-::i 0" 04:? (I. o::::,~~, O. 0:::(:, 0" 0':::4 O,U31 0.029 0 .. ;r?7 i). 02",,; (l" 02:;:: o . (i :::'? ()., ():?() (I. () 19 0.017 (l. () J I::, 0.01 "::' O.(i14 O. () 1 :::: O.Ol:,:~ O. (111 O. ('10 0.01 () U.n09 (I. o ():::: O.O(l) 0.007 O. (lOr:, O.()06 o. nO:i 0.005 O. OO"'~ O. ')()4 0.004 0.004 0.00:::: 0.003 O. ()():3 0.003 O. (len 0.00;' 0.002 0.002 0.002 1629356. 0.065 0.002 1629356. O. U6 t :; o. O()':~ O.06:i 0.014 BENEF I T-·CO::-::r F(AT 10 (51. FUEl ... (:O::;T E::;;C(-iL.AT I CIN) : 5.96 Chickaloon, Alaska Aerial View of Chickaloon Kings River Damsite 3.0 HALIBUT COVE 3.1 COMMUNITY DESCRIPTION Hal i but Cove is located on the southern shores of Kachemak Bay on the Kenai Peninsula. The community has a permanent population of 60; the population doubles during the summer. The average household size is 2. The Homer Electric Association (HEA) provides electricity to the residents of Halibut Cove. Most residences have a small diesel generator or some fonn of auxil iary power and these are used during power outages. Average monthly electrical consumption is 350 kWh. The demand peaks in the winter when boats are moored in the harbor. Most households have the usual variety of appliances, including freezers and power tools. The fish rearing facility at the head of Halibut Cove is a principal electricity consumer. If electricity was available at the public boat float, power use would approximately double. Homes are heated by wood, oil, and coal. The ready availability of local coal makes it an attractive fuel for heating. Fishing and tourism are the major sources of income for the residents. Few jobs are provided by local businesses but opportunities to develop a source of income based either on fishing or tourism exist. The Halibut Cove area has been growing steadily but one-half of the growth can be attri buted to summer resi dences. Some of the 1 atest residents to move to Halibut Cove have been retired people. While there is some local opposition to new projects that would stimulate growth, its accessibilty and attraction as a place to live is expected to result in some degree of growth. 3.2 SITE SELECTION Halibut Cove Site No.4 on Halibut Creek appears to be an excellent dam site. It is located in a relatively narrow gorge and a 20 foot high concrete dam could be constructed. The primary drawback of the site appears to be the penstock route as neither side of the creek appears to be promising. Two options exist. One would be to blast through the north abutment and along the north bank of the stream at the 400 foot elevation until the penstock approaches the powerhouse site near Halibut Cove, at which point it would turn to the southwest and proceed down and into the powerhouse. The problem with this route appears to be that the quantity of rock excavation and blasting required may prove this route uneconomical. The less expensive alternative used in this study is a route which would roughly parallel the stream from the dam to the powerhouse along the north bank. The powerhouse site is situated in a forested area at 20 to 25 feet above sea level and appears suitable for the purpose. The transmission line route would include a long span across Halibut Cove and would then proceed along the coast to the community itself, tying into the existing HEA line. 3-1 Proj ect 1 and requi rements and constrai nts imposed by the bou ndari es of an existing state park should be investigated further. prior to any feasibility-level studies. Halibut Cove Site No.2 is located on an unnamed tributary of a stream draining the Wosnesenski Glacier. The primary feature of this site is a dramatic waterfall which could potentially provide 800 feet of head in less than 2000 feet. The primary drawback to this site appeared to be the environmental impact of dewatering the waterfall. The penstock would also be located on a very steep slope and require special anchoring. The drainage basin above the falls is a classic u-shaped glacial valley and appears to provide adequate flows. However. it lacks the glaciers present in the Halibut Creek drainage basin, and thus may have a lower degree of flow reliability. Another difficulty would be the steep access necessary to the dam site. The powerhouse site would not pose any access difficulty and the transmission route is relatively flat and easy except for some swampy areas. This site is definitely suitable as an alternative site to the Halibut Creek development and may merit further study provided the environmental impacts can be adequately addressed. 3-2 ;1 /' //-- I] NOTE: TOPOGRAPHY FROM U. S. G. S. -SELDOVIA ALASKA, I: 250,000 LEGEND ... DAM SITE • POWERHOUSE o SITE NO PENSTOCK - - -TRANSMtSSION LINE --WATERSHED 5 o 5 E3 E3 !=-=:I SCALE IN MILES REGIONAL INVENTORY Ii RECONNAISSANCE STUor SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED A" IN PRELIMINARY SCREENING HALIBUT COVE DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ~dro~ower Potenti al Installed Capacity Si te No. (kW) 4 4,117 Demogra~hic Characteristics 1981 Population: 60 SUMMARY DATA SHEET DETAILED INVESTIGATIONS HALIBUT COVE, ALASKA Cost of Installed Alternaj}ve Cost Power_ (S1000 ) (mill s/kWh) 19,403 387 1981 Number of Households: 9 Economic Base Fi sheri es 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mill s/kWh) Ratio 94 4.12 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. h'E(j IOrJAL I r~;'..iErHORY ,. REcomJA I SAi'JCE STUD'" -SMALL H 'r'D~:GF'GW E R F'Ril...JEC IS ALASI<A DISTF\'1CT -CORF'S OF Ei'!G T NEEF\'S LOAll FORECAST -HALIBUT CiWF K: I LOWATT -HOURS F'E~: YEAR AWJUAL F'EAt< [IEMAtHl-i"< 'T'EAR LOW MEDIUM HIGH LOW MEDIUM HIGH 198,:, 2'57143. 257143. 257143. 88. 8j~ • 8:3. 1981 266182. 266182. 266182. 91. 91. 9 i • 1'?8 :-: 275221. 275221. 275221. 94. 94. 9 I."} + L;;83 284260. 28426') • 284260. 97. 97. 97. 1984 29329"~ . 293299. 29~299. 100. 1 \)0. 10\} • 1985 3\)2338. 3\)2338. 302338. 104. 104. j 1)'+ • 1 0 86 311377. 311377. 311377. 107. 107. 1\)7. 1987 320416. 320416. 320416. 110. 110. 110. 1988 329455. 329455. 329455. 113. 113. i.l >; • J.989 338494. 338494. 338494. 116. 116. 11·:). 1990 347533. 3A7C;33. 347533. 119. 119. 119. 1991 356005. 368430. 380854. 122. 12.~ • 130. 1 00 :. 36447.~. 38932.:) • 414175. 125. 133. 1~2+ 1993 372'~48 • 4i0223. 447497. 128. 14\) • 153. 1 0 94 381420. 431119. 480818. 131. 148. 165. 1995 389891. 452016. 514139. 134. 155. 17.~ • 1996 398363. 472912. 547460. 136. 162. 187. 1997 406835. 493809. 580781. 139. 169. 199. 1 '1'98 415307. 514705. 614103. 142. 176. 21') • 1999 423778. 535602. 647424. 145. 183. ..,,,,Jj ..:... •• 0 ,.:. • 2 (j t) I) 432250. 556498. 680745. 148. 191. 233. . 2001 440986 • 581648. 722309. 151. 199. 247. 2002 449722. 606798. 763873. 154. 208. 262. 2,j03 458459. 631949. 805438. 157. 216. ..,-, ... /0 2':)04 -l67t95. 657099. 847002. 16\) • 225. 290. 2()O5 475931. 682249. 888566. 163. 23'+ • 3\)4. 2006 484667. 707399. 930 13(). 166. 242. 319. 2007 493403. 732549. 971694. 169. 251. 333. 2008 51)2140. 757701) • 1013259. 172. 259. 347. 2')09 510876. 782850. 1054823. 175. 268. 361. 2010 519612. 8(8001) • 1096387. 178. 277. --.,. ~ / .. 1. 2\)11 531056. 824074. 1117091. 182. 282. 3;33. 2(112 542500. 841)147. 1.i 37794. 186. 288. 39\) • 2013 553944. 856221. 1158498. 190. 293. 0:9 '/ • 2014 565388. 872295. 1179202. 194. 299. 4\)4. 2015 576831. 888368. 1199905. 198. 304. 411. 2016 588275. 904442. 1220609. 201. 310. -l1B. 2017 599719. 920516. 1241312. 205. 315. 425. 2018 611163. 9::\6590. 1262016. 209. 321. 432. 2019 622607. 952663. 1282720. 213. 326. 439. 2020 634051. 968737. 1303423. 217. 332. 446. 2021 641672. 981731. 1321790. 220. 336. 453. 2l)22 649294. 994726. 1340158. 222. 341. 459. 2023 656915. 1007720. 135K525. 225. 345. 465. 2024 664537. 1020715. 1376893. 228. 350. '+ '/ ;:; • 2')25 672158. 1033709. 1395260. 23,) • 354. 478. 2l)26 679779. 1046703. 1'+13627. 233. 358. 484. 2027 68741)1 • 1059698. 1431995. 235. 363. 49\) • 2028 695022. 1072692. 1450362. ,.,--... ~~. 367. 497 ..... .: 1).2 9 702643. 108568f.. 1468729. 241. 372. C'~-. .J I).:J 2C'3 1j 710265. 1098681. 1487097. 243. 37.~ • 51)9. HALIBUT COVE -SITE 04 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Halibut Creek Section 10/15. Township 75. Range 11W. Seward Meridian Community Served: Halibut Cove Distance: 4 mi Direction (community to site): East Map: USGS. Seldovia (C-3). Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo ltage/Pha se: Terrain:.!.! Flat (1.0) Rolling (1.25) Long Span Total Length: 9. ENERGY 18.9 116 60 sq mi cfs in Large Concrete Gravity 20 ft 425 fmsl 380 CIJ yd Conc rete Ogee 10 ft 30 ft 415 fmsl Steel Penstock 54 in 9400 ft 2 Pel ton 22 349 4117 174 17.4 2.0 14.4 1.0 1.0 0.2 2.2 fmsl ft kW cfs cfs m; kV/3 phase mi mi mi mi Plant Factor: 52 percent Average Annual Energy Producti on: 18754 ~1Wh Method of Energy Computation: Flow Duration Curve 10. ENVIRONMENTAL CONSTRAINTS: No fish spawning in Halibut Creek. Portions of project may be within State Park lands. 1/ Terrain Cost Factors Shown in Parentheses. DAM PENSTOCK u.~ ......... TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA • ----------------------.-----------------~ HALIBUT COVE SITE 04 CONCEPTUAL LAYOUT H;"LlBUT CREEK ----______ ---____ ----------------------1 :;EPARTME~H OF THE ARMY '\c_.i<SKA DISTRICT ~C);:;:PS elF ENGINEERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Halibut Cove Site: 4 Stream: Halibut Creek IT EN 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchya rd 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facil ities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 123,000 $ 1,838,000 $ 1,581,000 $ 533,000 $ 1,092,000 $ 63,000 $ 231,000 $ 30,000 ~ 112,000 $ 5,603,000 ~ 560,000 $ 6,163,000 2.0 $12,327,000 $ 3,082,000 U5,408,OOO $ 2,311,000 U7,719,OOO $ 1,683,000 $19,403,000 $ 4,710 $ 1,517,900 $ 232,800 $ 1,750,700 $ 0.094 4.12 1:-,'1:: : , [ IHlt~I., [ r,~t,)FJ'1 f CIF:Y~, F'F.~ I, C)~·~t\~':::1 1 ::,f:1NCE :::; T! 'II Y .-:::;r'1f·d .. L. H'f'Df·;:III':>I,,(...JER f:'RU,.1 E:::CT':, l '):;::,":' 1 'j : .. ;: / 1. ':':::::::' l':':~:'::" 1. 0::, ,."(': 1 '0 ":j 1 1 ':,o:::::~. 1 .::, ',:' .:::: 1 9':j.~ 1 ,),;,,~:; 1. ':!'~) (:' I '~"':) / 1 ')')r.:; .:~ ()i) () :::001 ,2(>():2 . ?')03 2 i )(lil· 200 7 ',:~O()::=:: 2i)O'~' .:::',)10 ::~C' 1 1 201:? 2(11 ::: :~>::"14 ·~::U 1 ::; 201/:, . ~~() 1 '7 :,:» 1 :::: 201'::" 2020 .:::021 '~:02:? :?():? ::; :':::0:24 202~~, :::029 ~~03(l ~LASKA DISTRICT -CORPS OF FNGINEERS D[T':::) T LED F'EI~UI'.lNt-\ 1 :::;'::;A~~C:[ 1 NVE:::n I CdYT I UW:; COST UF HYORuPOWER -8~NEFIl cosr RATIO HAL. 181,n ClJI/E :::;JTE t··KI. 4 f: t.JH / YE:J~R 1 :::7'54UOO. 1 :::: '7 ':; 4-(. i()(> • J. f:7'::;4·(>0(' '. 1 :~:T:;4000. 1 :::?,,:;400U. J :::;:7'::';4(1)0. :I. :::::7~::;40()O" 1 ::;:: 7:AuOO . 1 ::;:754(lOO. :I. :::7~:;4UUO. 1 :::;:7":';4000. 1 :::::7 L:';4()(ii). 1 :;:::7:=; .t~ 0 I) 0 " 1 :::7~:;4C'OO. 1 :::7'::~4000. 1 :::7~54000. 1 :=:T5400U. 1 :=:7':;4(h)O. :I. ::;:754000. 1 ::~T::;4000 • 1 :::754000. 1 ::::754000. 1 :::::754000. 1 ::::7'::~4000. 1 :=:T54000. 1 :::7~:;4000. 1 ::::7~A(lOO. 1 :;:::7':';4000. 1. :::: 7"540(1). 1 ::::T:,'lOOO" 1 :=:)·~:;4(1(i(). 1 ::: 7~';40UO. 1 :;::7",,;-4000. 1 ::;::754000 • 1 :=:754000. 1 :::7540(>0. 1 ::::754000. 1 ::::T::';4000. l :::: T':A t) (H) • 1 :::7~:AO(lO. 1 ::::7540UU. 1 ::::7~:AOOO. 1 :::754000. 1. :::7'54000. :L ::=::754000. 1 ::::7~;4000. 1 :::7~i4000. 1 5 :2~' '71~):;~ • 1 '::;:2 7 7'?2. 1 '5~"7792. 1. ~':;,2 7 /')'2 n 15277';;2. 1 ~:~:~ '7? '~/2 • 1 5 ~;:~ ':.? i7 I~~I 2 • 1 :;~~7'71~1:::: If 152779:'2. 152T792. 1. ':i2T79:::::. 15:::~)''7'~/2 II 1521'7';'2. 152'7'7'~i:? • 1 ::; :::~ ~l'll~) 2 a 15277';:'2. 152'/79:2. 1527792. 1. 52T/'~:'2. 1 ~i::27?':;':;;::. 152~77'~J2 • 15:27792. 1527792. 1527792. 1527792. 1527792. 1 !52T?92. o ~,: M 2:::: ,'2:=:00. :.::: ::::: :~~: U (i • 232:::::(J() • 2:~::2::::00. ·,2J2:;::OO. :2:::::?:::::uO. ~::~: ',;>~: 0 0 • ::2';::?::::UU. ~:: ::;: ',;~: :~: () () . :?:~::?:::()() a ,~:::2::::U(l • ~::32:=-:OO • ~'::':~:::::::OO. :;~: :~::2 ::~: () () • :2:3;~:=:()() • 2::::2::::00. :2:~:2::::00 • 2::::2::::00. :.2::::~2:::()(j • ::.::: :::::~: ::: () () . ;~ :;: ~~:: :::: () () . '2::;:::;:::3()() • ~::~:2:::()() • 2:::::2::::00. ::.:'::32:300. ~:~3:2:=:OO • :~:~:2:::()() • ::;:::32::::()() • 2::::2::::()() • :~~ ::.: ::: ::: () () . :2 ::;::2 ::~: () I.) .. :2:~:2:::()(j • 2:32:3()() • 2:~:2:3()() • 2:::: 2::: () () • 2:::: 2:=: () () • 1:3:;::~:()C) • 2:::::::::::()() • TOTf~L..$ 1760~,92 .. 176059:? 1 760~:;92" 176(6';12. 1. 7 6()~:'')2" 1. 7 (:,0,,:;'<:: • 1 7,1:,n~:;'·):2. 1 ?,~,(J":';9:2. 1760~92. 17bO':S92. 1.7 f:.O'S':;r~~: • 1 7 60~~i'):? • '1 ? /:,O~59:? • 17.':.0~:"::;'2 , 1760592. :1. '7 I~:' 0 ::i'~1 ::2 II 1760592. 17,:':,0:=;92. 176059:2. t 7 (:.()51~)2 .. 1760!59:2 • 1760592. 176059::2. 1 760O:::i9:2 n 11 (;,0592. :I. 7 60~,9:? 1760~:;9:2. 1760592. 17(:'0':i9:2 • 1760592. 17605'::'2 n 1 7(:'05'~'2. 1. 7/:,0':;9::':::. 17 605':;;.~::. 1 7 60~)9::~. 1760592. 1760592. 1760592. 17('::,059:;;:'. 1760592. 17605';:'2. $/r::'WH 0.0'::"4 0.0';'4 () • O':;-!.i.j. O. (Y"j. On0 9 4 O. (l';i4 () " ,y::,,'+ (;.O·~'4 U. O'~'4 0, ()':~'4 U" U'-ilj. 0.094 I)" n')'~· 0.094 O. U';i.:j. O. ')'~)iJ. i)" (i'ft.l· (':I. U':'4 O"O':'/'t O.O··:hj. 0.094 0.094 (). ()94 0.094 O. ')'?'4 0.1)94- C,. ')94 O.O'.::'·l O. i),)4 O. ')9L~ 0.094 0.094 0.094 C,. O'~'4 U. ()'~i4 0.094 0.0';'4 0.094 O. (Y;i4 O. (yU.j. 0.094 0.094 0.094 0.094 0.094 0.094 0 .. 094 $/I<WH [I 1::;;:( 0.0](:' (>.O(:.L::; 0.0(:,0 o. U':',f::, U. U5::~ 0 .. 04:::: <). ()42 () • (I"::: '~.J () .. () '::(, (). j):>l o. '')::::1 n"f)?-; O. U~::~~; t). U2.:: ( ) . ( ):~:::;:' (I. ():::J", u. ;) 1. ':i U.01l 0.016 0.01':; 0.014 O.OlJ 0,01.2 O. () 11 0.010 0.010 C'.009 0 .. no::::: 0.00::: 0.007 0.007 O. ()()/:. O. t:'O(-, O. OO~'i 0.005 0.005 0.004 O.()04 O. ()()4 0.00:::: o. ()():.:;: 0.00::;: O. O():~:: (). O(r;·: 0.00:2 AVERAGF. COST O. (194 0.020 8ENEFIT-COST RATIO (5% FUEC COST ESCALATION): 4.12 Hal ibut Cove, Alaska Damsite at Halibut Creek Aerial Vi ew of Halibut Cove 4.0 KACHEMAK 4.1 COMMUNITY DESCRIPTION Kachemak is a community of 403 people located approximately 5 miles east of Homer and accessible by road. The average household size is approximately 4 persons. The population expands in the summer as a response to the fi shi ng industry and touri sm. The pennanent popul ati on has been growi ng as well in recent years. Homer Electric Association provides electricity to Kachemak consumers. In addition to approximately 100 residences, other consumers of electricity include the new community building, a lodge, four businesses inside the city limits, and three commercial shops. Nearly all households have a full variety of small appliances, refrigerators, and freezers. The usage of power tools is common. The average household pays on the average $38 per month for electricity and consumes in the range of 500 to 650 kWh. If the price of e 1 ectri c ity was reduced, the number and types of appl i ances woul d probably stay about the same. Homes are heated with oil, propane, wood, and coal and a small segment of the population has electric resistance heating. Coal is gathered on the beach after storms from exposed veins but demand for this "free" fuel is increasing. The economic base is fishing and the area attracts a large number of commerci a 1 fi shermen. Incomes are suppl emented by seasonal constructi on work elsewhere, such as on the North Slope. The demand for electricity will probably increase due to the increase in number of consumers. Kachemak is a growing community with new homes being developed between Homer and mile 21 of Strand Road. Growth would be more rapid if it were not for the shortage of a fresh water supply. The development of a new local water supply has become the highest priority as a result. Planned new construction includes a fish processing dock and a beef stockyard and butcher shop, the latter being dependent on water availability. A segment of the local community is interested in developing the tourist trade and some of these tourists may choose to resi de in Kachemak permanently. 4.2 SITE SELECTION The community of Kachemak has been interested in developing a t\Ydroelectric site in conjunction with their proposed Fritz Creek water supply development. From the hydroelectric standpoint, the available head and long penstock required to develop this stream as well as diversions from Beaver and Horse Creeks does not appear to be very promising. However, the overall project feasibility might be established through an analysis which takes into account both electric and water supply benefits. 4-1 A preferable alternative to this site appears to be the Swift Creek site located 14 miles northeast of the community. A concrete or possibly a sheetpile dam would be appropriate. Access to the site vicinity would be provided by an existing road which terminates approximately one mile to the southwest. The penstock route would follow the northeast bank of the stream on a contour until dropping 250 feet down a spur to near sea level where the powerhouse would be located. However. the steep side slopes on both sides of the creek will make the penstock difficult to construct. The powerhouse would be located near an existing Russian village. The powerhouse site is in an area characterized by sedimentary deposits and the foundation may prevent some problems. The transmission line would follow the penstock upstream back to the dam site \~here an existing HEA line crosses near the dam site. A third alternative. Twitter Creek (Site Uo. 2). has easy access and ;s ;n an area al ready somewhat developed. The creek. however. is al ready developed as a water supply for the city of Homer and a potential use conflict exists. Should these conflicts be resolvable. a sheetpile dam could be located downstream of the confluence of three branches of the creek. The penstock route could follow either side of the stream. The powerhouse site probably lies in soft ground and no exposed bedrock was apparent. The powerhouse is located downstream of an existing gauging station and potentially might have to be relocated upstream of the station depending on its importance. The existing transmission lines in the area could serve this project. The site may be a viable alternative to Swift Creek provided the water use conflicts could be resolved. However. it should be noted that substantially less head and consequently greater penstock diameter also render this site unattractive in comparison to Swift Creek. 4-2 Bluff Point A c NOTE: TOPOGRAPHY FROM U. S. G. S. -SELDOVIA ALASKA, I: 250,000 LEGEND ... DAM SITE • POWERHOUSE o SITE NO PENSTOCK - - -TRANSMISSION LINE ---WATERSHED 5 o E3 E3 t==; SCALE IN MILES , ·--....-ir-::- 5 REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING KACHEMAK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS H,ldro~ower Potential Installed Capacity Site No. (kW) 3 674 Demographic Characteristics 1981 Population: 403 SUMMARY DATA SHEET DETAILED INVESTIGATIONS KACHEt1AK, ALASKA Cost of Installed Alternaii ve Cost Power_/ (~1000 ) (mills/kWh) 5,862 387 1981 Number of I-huseholds: 115 Economic Base Fi sheri es 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mills/kWh) Ratio 214 1.80 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. 1981 1982 i 98:3 t984 1985 .198,:) 1987 1988 1989 199') 1 '7"" 1 t992 1993 1'194 t995 1 '7'96 1997 1998 1999 2000 2')01 2002 2')03 2004 2005 2\)1)6 2007 2008 2009 2010 2011 2012 2013 2014 2015 201,-) 2017 2018 2019 2020 2021 2(j22 2023 2024 2025 2')26 2027 2028 REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS LO~D FORECAST -~ACHEHAK KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 1727143. 1787855. 1848567. 1909279. 1969991. 2030702. 2091414. 2152126. 2212838. 2273550. 2334262. 2391164. 2448066. 2504968. 2561870. 2618772. 2675674. 2732576. 2789478. 2846380. 291)3282. 2961961) • 3020637. 3079315. 3137992. 3196671). 3255347. 3314025. 3372702. 3431380. 349(1)58. 3566923. 3643788. 3720653. 3797518. 3874383. 3951248. 4028113. 4104978. 4181843. 425871)9. 4309899. 4361089. 4412279. 4463469. 4514659. 4565849. 4617039. 4668229. 4719419. 4770,-)0.:;0. 1727143. 1787855. 1848567. 1909279. 1969991. 2030702. 21)91414. 2152126. 2212838. 227355',) • 2334262. 2474617. 2614972. 2755326. 2895681. 3036036. 3176391. 3316745. 345710(1. 3597455. 3737809. 3906735. 4075660. 4244586. 4413511. 4582437. 4751362. 4920288. 5089213. 5258139. 54270"';3. 5535025. 5642'i-87. 5750949. 5858911. 5966873. 6074835. 6182797. 6290759. 6398721. 6506682. 6593961. 6681240. 6768519. 6855798. 6943077. 7030356. 7117635. 72049L4. 7292193. 7379472. 1727143. 1787855. 1848567. 1909279. 1969991. 2030702. 2091414. 2152126. 2212838. 2273550. 2334262. 2558070. 2781877. 3005685. 3229492. 3453300. 3677107. 390~)915 • 4124722. 4348530. 4572337. 4851510. 5130683. 5409856. 5689029. 5968202. 6247375. 6526548. 6805721. 7084894. 7364069. 7503128. 7642186. 7781245. 7920303. 8059362. 8198420. 8337479. 8476537. 8615596. 8754654. 88781)22. 901) 139,). 9124758. .:;0248126. 9371494. 9494862. 9618230. 9741598. 9864966. 9988334. ANNUAL PEAK DEriAND-~W LOW 591. 612. 633. 654. 675. 695. 716 • 737. 758. 779. 799. 819. 8:38. 858. 877. 897. 916. 93,~ • 955. 975. 994. 1014. 1034. 1055. 1075. 1095. 1115. 1135. 1155. 1175. 1195. 1222. 1248. 1274. 1301. 1327. 1353. 1379. 1406. 1432. 1458. 1476. 1494. 1511. 1529. 1546. 1564. 1581. 1599. 1616. 1634. dE i:rI Uh 591. 612. 633. 654. 675. 6·:t5. 71,~ • 737. 758. 779. 799. 847. 8'~6 • 944. 992. 11)40. 11)88. 1136. 1184. t232~ 12~3() • 1338. 1396. 1454. 15il. 1569. 1627. 168::;. 1743. 1801. 1859. 1896. 1933. 1970. 21-)1)6. 21)43. 21)80. 2t17. 2154. 2191. 2228. 2258. 2288. 2318. 2348. 2378. 2408. 2438. 24.~ 7. 2497. 2527. HiGH 6334 6::;4. 675. 695. ,l .!r / t 758. 779. 953. 11)29. 1 U)6. 1183. 1259. 1336. 1413. 1489. 156,-). 1661. 1757, 1853. 1948. 2'·)44. 214(' • 2235. 2331. 2426. -,e" -, 'j ... . ..J~..:.. ~ 257(j. 2617. 21~65 • 2712. 2761) • 281)8. 2855. 2903. -<:ie"' .:. , . .J 1 • 2998. 31)4(, • 3('83. 3125. 3167. 3209. 3252. 3294. 3336. 3378. 3421. KACHEMAK SITE 3 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Swift Creek Section 23, Township 4S, Range 11W, Seward Meridian Community Served: Kachamek, Homer Electric Association Distance: 12.5 mi Direction (community to site): Northeast Map: USGS, Seldovia (D-3), Alaska 2. HYDROLOGY Drainage Area: 3. Estimated Mean Streamflow: Estimated Mean Annual Precipitation: DI VERS ION DAM Type: Hei ght: Crest Elevation: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: 6. Diameter: Length: POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. 9. TRANSMISSION LINE Vo 1 tage/Phase: Terrain:ll Mountains (1.5) Tota 1 Le ngth : ENERGY 6.9 10.6 30 sq mi cfs in Sheetpi 1 e 10 ft 700 fmsl Stairstep Fish Ladder 5 ft 29 ft 695 fmsl Steel Penstock 22 in 13500 ft 2 Pelton 10 625 674 15.9 1.6 3.0 14.4 2.6 2.6 fmsl ft kW cfs cfs m; kV/3 phase mi mi Pl ant Factor: 46 percent Average Annual Energy Production: 2716 MWh Method of Energy Computati on: Flow Durati on Curve 10. ENVIRONMENTAL CONSTRAINTS: No salmon spawning in local creeks • .!I Terra; n Cost Factors Shown in Parentheses. LEGEND : DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA KACHEMAK SITE 03 CONCEPTUAL LAYOUT SWIFT CREEK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF EN INEERS ,II, ... ,I, "I,. ,.. . .,\ .1 , -: ..... ~ SCALE: HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Kachemak Si te: 3 Stream: Swi ft Creek 1- 2. 3. 4. 5. 6. ITEM Dam (including intake and spillway) Penstock Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations Switchyard Access Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Constructi on at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Cost of Hydro: Benefit-Cost Ratio COST $ 45,000 $ 780,000 $ 415,000 $ 294,000 $ 30 ,000 $ 19,000 $ 167,000 $ 45,000 $ 156,000 $ 1,951,000 $ 195,000 $ 2,146,000 1.9 $ 4,078,000 $ 1,019,000 $ 5,097,000 $ 765,000 $ 5,862,000 $ 557,000 $ 6,418,000 $ 9,520 $ 502,100 $ 77,000 $ 579,100 $ 0.21 1.80 f~L I j lUr\I,:.\t J l'j \}FN TORY ~~ Fi:E:CUNNA I :::;ANCE :~:;TIJDY -:;:;MALL HYDROPOWER PRO,JEer :::; 'I. ':::' ::,:4 1 ':':::::~i " ':~':::':6 1 ',/:,,:7 1. ''';::::;::: 1. '::'::::') 1 ':"::'0 :l '~)'::/3 1 "::"~)4 1 ':) ':')~~j 1. 0::;':')6 j '~/ '~" '! 2U OO :.:.:UOI .::: ()02 .200:;:: ,:~U0 4 ;:'OO~:i 2(1():S 20U7 2()()::: 2009 ::2 010 2011 2 012 2013 2 014 ?01~j 2016 ~~017 201::: :,2(119 2021 2024 :2~()25 2026 ~::()2~7 ALASKA DISTRICT -CURPS OF ENGINEERS DETAILED RECONNAISSANCE INVESTIGATIONS COST UF HYDROPOWER -BENEFIT CO S T RATIO ~:ACHEi'lAI< ::;;ITE NO. :;:: $/~:::WH $/kWH ~:J..jH/YEAR 27 t6000" :~:71 (,oon. 27 1 (~,OOO. 2716000. 271.6000. :27 16000. 27 16000. 2 7 1 6 000. 2 716000. 2716000. 2716000. 2.71 ~~,OOO. 2 71 (",0(10. 2716000. 2"7 1 ,~,OOO. 271 (:,C)O() " 27 16000. :27 16000. 271/,;:,000. 2716000 . 2716000. 2716000. 2716000. 2716000. 2716000. 2716000. 2716000. 271/:.000. 2716000. 2716000. 2716000. 2716000. 2716000. 271/:.000. 2716()OO. 2716000. 2716000. :2716000. 2716000. 271 (:,000. 2716000. :2716000. 2716000. 2716000. :271/:.000. 2716000. CAPITAL 5 () ~i :~:!:i :~: • ~i ()~; ::.: 5 :::: . ~:t () ~5 :~: ~i :;: • ~i ()!:; :~: ~i :~: • ~i()~5:;:5:~: • ~:~; () 5 :~: 5 :;: . ~5()5:3~i:~:: II !:;()~j ::::5 :::: • ':j()5::::~5:::: • 5()~i:~:5 :3 I I 5 ():; :::: ~~i :~:: • 5()5::::~5:;: • ~5()5::::~:i:3 II ~;()~i :::~:~: • 5()'5::::5 :~: If ~i()~i:35::: If ~i()~:;::::~:':~: • 5 c)5::;: 5:::: • 5()5::::~i:~: • ~i()5 :35:~: • ~5c)5 :~:5:3 • ~i()5::::~5 :;: • 5()5::;:5:3. ~S()5::::5:::: • 5()5:35:::: :I 5()5:;:~i:::: • 5()5::::5:::: • 5()5 :~:5:::: • TOTAL$ 5:::2 ::::5 :::: • ~5:=:2.::::5:~: • 5:=:'~~::::5 :~: • ~i !:::2 :::: 5 :::: • Co" .-', ,'M, .~'. 1:.:' •• ', ._1';:.0£ .. ; •. _1.:, • 5::::~::3 5:::: • a::.-.. ··1·-'·· .. ,1::",' I " 11:'.a:: .. ·: •. ~I .:o • 5:::2::::~i :;: • 5::::2 :~:5 :::: " 5:::2:~:5:::: • ~5:::2 :35:3 • ~i ::::2 :?: 5 :::: • ~i:::2::;:~5:;: • 5:~:2 :~:~;:::: • 5:=:2:~:!5 :~: • ~i;::2::::5::;: • !5:::~::3 5 :~~: • 5:::2:~:5 :;: II ~i ::: ~:: :;: 5 :~: • 5:::2::::5 :::: • 5:32::::5:;: • 0.214 0.2 14 0.214 O. ~~ 14 0.214 0.2 14 0, ::-::1 4 0.2 1.4 O. ::~: 1 i.J. O. ~::.1 4 0.214 0.:2.1.4 0.214 0.:214 (;. ~'14 ('l. ~::' .1 4 (l.:;:~14 0.214 O.:;::li~ 0.2 1.4 0,,~;~14 O. ::::'1.4 0.214 0.214 0.214 (I. ~:: 1L~ O.~'.l.4 0.214 0.214- 0.21'l 0.214 O. >:14 0.214 0.214 0.214 0.214 0.214 0.::214 0.2.14 0.214 0.214 0.214 0.214 (I. ~~ 14 0.:?14 O. 21'~ D I :~;f ::: 0.1(:,0 o. 14:,,:: (I. 1 :~::::: (). 1 ':;::::: 0.119 (I. 111. ()" 1 0:: 0 .09/-, O. (l:~:'~:' O. UT7 0.0'11 0.066 0.1)61. C . O~i ')' (). ()~i :::: O.U49 0.046 fl. 04~: 0.(41) O. 0 ::';:/ 0.034 0.032 0.029 0.027 (). ()::::~i 0.024 0.022 0.020 0.019 0.018 0.016 O.Ol~~j 0.014 0.(113 0.01 '::" 0.011 0.011 0.010 O. OO'~I O. (11)::: i). 00::';: (1,,(107 (1.007 f). ()()(~, 0.006 :::0 3 0 2716000. 5()5:35:3. 5()5:35:~: • 5()5 :~:5:3 • 5()S :35:::: • 5(>5 ::;:5:3. 5()5 :;:~j :::: • 5()'5::::5:::: • ::'C)5::::5:;: • 5()5:~:~5:::: • 5()5::':5:~: • ::~('5:::'5:311 5()~i :~:5 :;: • 5()~i :35 :::: • 5()5::::5:3. ~5()5 :35:M:: " 5()5::::5:::: • ~~()~i::::5:::: • 5(}5:35 :~: • 5()~i ::::~i :::: • (I ~~ M 77000. 77000. '77000. 7"7000. 77(100 . 77000. T 7000. 7"7000. 7700u. 7l00t). 77000. 77000. 77000. T10(lO. 1'7000. 770(ll) . 77(luO. 1'7000. 77000 . 77000. ]7000. 77000. 77000. 77000. 77000. 77000. 77000. 7"7000. 77000. 77000. 77000. 77000. 77000. 77000. 77000. 77000. .77000. 7700(1. 77(100. 770(>0. 77000. 77000. 77000. "1"700(1, 77000. 77000. T70UO. 582353. O .~14 0.005 0.214 0.046 AVERAGE COST BENEFIT-COST RATIO (5% FUEL COST ESCALATION): 1.80 Kache ln ak , Al aska Swift Creek Damsite (at confluence) Aerial View of Kachemak Area 5.0 MENTASTA LAKE 5.1 COMMUtJITY DESCPIPTION Mentasta Lake is a native village situated 6 miles off the section of the Glenn Highway between Slana and Tok at the base of the Alaska Range. With approximately 15 households, the population of Mentasta Lake is 75 and has been stable for several years. The housing stock consists of log frame dwellings and is generally in poor condition. The village plans to replace many of the older homes with new HUD housing. In addition to the 15 houses, Mentasta Lake has an elementary school, community hall, and clinic. t4entasta Lake has no electricity. The village 35 kW diesel generator, which was generating power 2 years ago, is no longer operating due to prohibitive fuel costs. Diesel fuel in that area costs about $1.35/gallon. A small horsepower engine is used to run lights and power tools as needed. The houses are heated by wood. The village is a subsistence economy with no jobs provided within the village. Residents work in Tok, Fairbanks, and the North Slope at temporary jobs. If electricity was introduced to Mentasta Lake, the number and types of appl i ances acqui red woul d be 1 imited by income. 5.2 SITE SELECTION The two sites for which the preliminary screening had indicated the lowest costs per kWh (sites 01 and 04) were visited in the field. In addition, Site 02 near the landing strip was overflown, without, however, disclosing any noticeably attractive features. Sites 01 and 04 have equally-sized drainage basins of approximately four square miles, equal predicted runoff, and are both located at approximately the same elevation of 3000 feet. Nevertheless, striking differences in actual runoff and in stream type were observed. Observations of the south-facing basin of Site 04 on Jake Creek closely confi nned both the predicted runoff and tye type of c reek expected. What appeared to be grey phyllite bedrock was exposed in places. On the other hand, runoff at Site 01, on a north-facing tributary to the Slana River, was measured as twelve times the predicted average annual runoff. (No credit was, however, taken for this measurement in subsequent site capacity analyses because of it being a single isolated reading.) The creek itself was of the "alpine" type, with up to 2 foot rounded boulders piled into windrows and piles up to 4 foot high, within an about 30-foot wide stream channel. This site, proposed for development, would require a separate intake 50 to 100 feet upstream of the concrete diversion dam, with substantial storage space for transported bed material. 5-1 I , . '. ,i>----- -r '. i' 02566" NOTE: TOPOGRAPHY FROM U. S. G. S. -NABESNA ALASKA, I : 250,000 LEGEND ... DAM SITE • POWERHOUSE o SITE NO - - - --PENSTOCK - - -TRANSMISSION LINE ---WATERSHED , , , jl "'c:.\=~'y:-· , '\ 5 0 5 E3 H H SCALE IN MILES ~GIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING MENTASTA LAKE DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS H,l d ro~ owe r Potenti a 1 Install ed Capaci ty Site No. (kW) 1 84 Demographic Characteristics 1981 Population: 75 SUMMARY DATA SHEET DETAILED INVESTIGATIONS MENTASTA LAKE, ALASKA Cost of Installed Alternative Cost Power"!! ($1000) (mi 11 s/kWh) 2,859 468 1981 Number of Households: 15 Economic Base Subsistence ..!! 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of J1ydropower Benefi t/Cost (mi 11 s/kWh) Ratio 1,060 0.44 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY i RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALAS~A DISTRICT -CORPS OF ENGINEERS 'r"EAF: 1 'i81) l -;'81 1982 1983 l'i84 l'i85 19:36 1;:;'87 l':;'88 l'i89 1 S;' 'i .:. l'?:;' L L992 1993 L994 19.:;05 19'iS 1997 1998 19<:;9 2')1)'.) ."N,:'l 21~j'.j2 2''-)~)3 2')04 :005 21.) () I~ 2(}v7 21)08 2')(19 21.) 11.) 2014 2')15 201,~ 2017 2'.) L 8 2') 1 9 2021 . 2(j22 21)24 :( .. 25 ::(126 2i):: 8 ::"::"29 LOAD FORECAST -MENTASTA LAKE KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 0. 34816. ,~9632 • 11)4449. 139265. 174081. 2')8897. 243713. 278530. 313346. 348162. 377284. 3'" 1845. 4'.:'640,~ • 4209,~ 7. 435528. 45'.)089. 464650. 479211. 493772. 506374. 518976. 531577. 544179. 556781. 569383. 581985. 594587. 6(17188. 619790. 627087. 634384. 641681. 648978. 656275. 663572. ,~70869 • 678166. 685463. 692761) • 71)1598. 7104~55 • 719273. 728110. 736948. 745785. 754623. 772298. 781135. o. 34816. 69632. 104449. 13.:;0265. 1741)81. 208897. 243713. 278530. 313346. 348162. 382042. 415922. 4498('2. 483682. 517562. 551442. 585322. 619202. 653(:'82. 686962. 7251)86 • 763209. 801333. 839457. 877580. 915704. 953827. 991951. 1030075. 1068198. 1082694. 1097L90. 1111685. 1126181. 1141)677. 1155173. 1169668. 1184164. 1198660. 1213155. 1231)347. 1247539. 12647:31. 1281923. 1299115. 1316307. 1333499. 1351)69 L • 1367883. 1385\)75. O. 34816. 69632. 1,)4449. 139265. 174081. 208897. 243713. 27853') • 313346. 348162. 401361. 45456(1. 51)775.:;0 • 560958. 614157. 667355. 720554. 773753. 826952. 881} 151. 943797. 1()07442. 1071088. 1134733. 1198379. 1262024. 1325670. 1389315. 1452961. 1516606. 153831)1. 1559995. 1581690. 1603384. 1625079. 1646773. 1668468. 1691) 16::. 1711857. 1733551. 1759097. 1784644. 1810190. 1835737. 1861283. 1886829. 1912376. 1937922. 1963468. 198.:;0015. ANNUAL PEAK DEriAND-~W LOW MEDIUM HIGH 0. 12. 24. 3.S. 48. 6t) • 72. :33. 95. 11)7. L19. 124. 129. 134. 139. 144. L49. 154. 159. 164. 169. 173. 178. 182. 186. 19 L • 195. 199. 204. 21)8. 212. 215. 217. 220. 225. 227. 231) • 232. 235. 237. 240. 243. 246. 249. 252. 255. L::':Its. 2,~ 1. 264. 268. O. 12. 24. 36. 48. ,~I) • 72. 83. 95. 1')7. 119. 13 l • 142. 154. 16,~ • 189. 21.2. 224. -,-1:" ..;....!-J .. 248. 261. 287. 31) 1. 3!.4. .~,:, / .. 340. 353. 36.~ • 371. 376. 381. 386. 391. 396. 41j L • 41)6. 410. 415. 421. 427. 433. 439. 445. 451. 457. 4.S3. 4,~8 • . .} , J : • 24. ;::: ...... 1 ';'7. 119. 137. 1'56. 174. 192. 21'} • . ..:..:.!)::, .. ::,51.) L • 3.23. 345. ..,. .-. ..!r.,!j.l • 4 i.1}. 432. 454. 476. 4~':~ .. 534. 542. 54'~ • 557. 571. 579. 58,,:) ~ 594. 61)2. 6il. 1~21J • 629. 637. 64.~ • 655. 6,~4 • 681. MENTASTA LAKE SITE 1 SIGN IFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Right Tributary to Slana River Section 21, Township 13N, Range 8E, Copper River Meridian Community Served: Mentasta Lake Distance: 4.5 mi Direction (community to site): Southwest Map: USGS, Nabesna (D-6), Alaska 2. HYDROLOGY Ora i nage Area: Estimated Mean Streamflow: sq mi cfs Estimated Mean Annual Precipitation: 3.3 4.2 30 in 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Volume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow: Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vol tage/Phase: T e r ra i n :1/ Fl at (1. 0 ) Tota 1 Length: 9. ENERGY P1 ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Local Fi sh Creek and lower Sl ana Ri ver. Large Concrete Gravi ty 15 ft 3395 fmsl 340 cu yd Concrete Ogee 5 ft 16 ft 3390 fmsl Steel Penstock 12 in 5800 ft 1 Pelton 2730 fmsl 650 ft 84 kW 1. 9 cfs 0.38 cfs 1.1 14.4 4.0 4.0 mi kV/1 phase mi mi 39 percent 287 MWh Plant Factor Program salmon spawning restricted to 1/ Terrain Cost Factors Shown in Parentheses. NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY PLANT FACTOR PROGRAM COMMUfHTY: MENTASTA LAKE S ITt NUMBE R: 1 NET HEAD (FT): 650. DESIGN CAPACITY (KW): 84. MINIMUM OPERATING FLOW (1 UNIT) (CFS): 0.38 LOAU SHAPE FACTORS: 0.50 0.75 1.60 2.00 HOUR FACTORS: 16.00 15.00 13.00 3.00 r~UNTH (HDAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USAi3LE MONTHLY HYDROELECTRIC OF AVERAGE DEMANO HYURO FLOW ENERGY ANNUAL ENERGY ENERGY (CFS) GENERATION (KWH) (KWH) JANUARY 0.66 21677 • 10.00 45009. 14452. FEBRUARY 0.57 16910. 9.50 42758. 11273. MARCH 0.55 18064. 9.00 40508. 12043. APRIL 0.95 30196. 9.00 40508. 19716. MAY 8.70 62496. 8.00 36007. 34817. JUNE 13.40 60480. 5.50 24755. 24755. JULY 8.9b 62496. 5.50 24755. 24755. AUGUST 7.86 62496. 6.00 27005. 27005. SEPTEMGER 4.63 60480. 8.00 36007. 34565. OCTOBER 2.19 62496. 9.00 40508. 37228. NOVEI"IBER 1.07 34010. 10.00 45009. 22173. DECE~IBER 0.85 27918. 10.50 47259. 18433. TOTAL 519719. 450089. 281215. PLANT FACTUR(1997): 0.38 PLA~T FACTOR(LIFE CYCLE): 0.39 ( 12. DAM PENSTOCK TRANSMISSION UHf POWERHOUSE DRAINAGE BASIN REGIONAllHVENTORY & RECONNAISSANCE STUDY SMAll HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA MENTASTA LAKE SITE 01 CONCEPTUAL LAYOUT R. TRIBUTARY TO SLANA RIVER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Mentasta Lake Si te: 1 Stream: Right Tributa~ to Slana River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 15 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operati ons and Mai ntenance Cost at 1. 5 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 106,000 $ 156,000 $ 56,000 $ 148,000 $ 30 ,000 $ 6,000 $ 99,000 $ 17,000 $ 100,000 ~ 718,000 $ 108,000 $ 826,000 2.2 $ 1,817,000 $ 454,000 $ 2,271,000 $ 341,000 $ 2,611,000 $ 248,000 $ 2,859,000 $ 34,040 $ 223,700 $ 70,000 $ 293,700 $ 1.06 0.44 :-,': ._1 'l l=I~~~:d ___ I ~IVENTI)RY ~( RECONNA I ::;;ANCE ::;TUl.IY --::;;MALL HY[lF':OF-'OWER Pfi O,JE -C--, ':., ALASKA DISTRICT -CORPS OF ENGINEER S Y i.:fW 19::::4 "I. '~n:;;6 1 '):::;:-' 1 9:::;::::: 1 9::::~' :I. ',":;1 (l l'~1 9 1 1 ':I'~i :2 t ,::,,:;::;:: 1 (;I ';'/t 1995 1. ';)') ~:­ l-=j -:n 199:3 1 '::i ::i';:' -;:::r)OO 2 001 2 (;:,)2 :::UO --? 2 0 0 4 20 0~i 200(, 2 00 7 200::::; 2009 2 01(1 2 ():I. 1 2 (1:1.2 :201::': 2014- 2015 :2016 :~:O1. 7 201:3 :2019 2(l :?0 2021 :2 0::::~: 2024 :;~:(i :25 ::(i~::(~, DETAILlD RECONNAISSANCE INVESTIGATIONS COSl OF HYDROPOWER -BENEFIT COST RATIO t'IENTA::;T (~ l _('i~:::F :::; I TE t -IO. 1 KWH/YEAR 1 :::::::':40 ~::. 1 ~i 7 412. .L 7::;: L2::::. _226476. 24;: 1_ 40. ::~: -4 :::: :::: I) 5 • 2 54413. 271234. ;:7 ,~-,b::':7 • ;~:=!'~~1 7 :21 • ~~'~J :=:()72 • ~~~'~)5~i54 " :::::04/93. :~:():=:7:3:=: " 310707. :::14545. ::;;: 1 !'.:i~-:-56. :~:: 1 -':;, ~7 /::.. ::;: • 317::;:7':" • ::: 1 :3 '~'~i(). :;: 1 ':.1 !::! I~I () • 320710. :;:2152'~1 • .-....... -•• '-, .-. C" .~I";;"~":"':I._' • ::;:2:31 :-;:(). :::::~':4::::5:3 • :::::249T7. :3252::::/': .• :3 :25'~J()5 • :::: :~: c. :::: :~: 2 • :;::~7142. C:AF' I TAL :~~:2~i 11 :~:. ~;::~~511 :::. ::;:':2511:3 .. :?·~:!,:::i 1 1 ::::. :;2 :;~ ~':i 1 1 :::: • 22511 :::. 2:2511 :~: .. :2:';251 1. :~:: • 22511:~:. ':22511 :::. 2:2511 :~:. :~::2511 :~~:. 2 :;':-::; 11:3. :22":i1 u:::. ::;:::?~;.1. 1::::. :22511:=:. 22511 ::::. ;~:2511 :::!. :22511:3 . :;~~2~i 118. 22511:-::. ::?:25118 " 22511:::. 2::?511:3. 225118. 225118. 22511 :::!. :;:'-2511:=:. 2~:511:3. (I :~._ M 7(1<)00. 70000. 70000. 7 0()(lO. 70'')()() • 70000. 70')00. 7 0000. 7 i) 0 ()() . 7')000. 70000. 70(10(1. 7 0000. 70000. 70000. 7 0000. 70000. ?O()()i) • 70000. 70000. 70000. 70000. 70000. 70000. 7 0000. 7 0000. 70(l()(1" 70000. 70000. 70000. 70000. 700no. 70000. 70000. 70000. 70000. 70(100. 70000. 70000. 70000. 70000. 700(>0 . 70000. 1'0000. 70(>00. 70000. 70000. $/I-:'-l"H $ / ~;JAH T01ALS NONDI S C DI SC :~'9511 ::;:. :::. :: 12 1 • b W ~ .. 2951 H::. 1 • :::: I r:; 1 . -;:;':) (~: 295118. 1 .657 1.0 A ~ 2':":i 11:3. 1 • ~'; 16 (>. ':'0 1;- 2':"':; 11:?'.. 1 • 400 0 " 77 ::, :2'~I':i 11:::. 1.:;::Cn (1 .;(-.7 ::: 29"'=; 11 ::;:. J • 1 :~:9 (, • '::;:-::(> :"::9511 ::::. 1. • 1 60 ( ,_ 4 :3 0 :"~9~:; 1 t :::. :I • 1 -::':4 C'" 4-:-_::(, 29':i 11 ::;::. 1 .. 111 C'. :~;:':i 7 ~?-:;-'511 :::. 1 .. 0::::::;:: l)" ::;1-:,1 ·~:9~,11:3. 1 .0(:,7 ('. :::-~:'9 :2':;i511:::. 1.049 '_'.30 1 :2 ':;/511:::. 1 • 0 :;::3 (0 _. :;~'7 ':;i :2':;'51. 1 :::. 1 . 019 0 .. 252 29:;11:::. 1.007 0.2 ::::;:: 295118. 0.990 0.1 07 295 t 1 :3. U. 9::::::: (i .. t :~: 1 2'~JI:5118 .. () M '~"'75 C· r: 'I (:,7 ~::9':il1 ::::. (1.9(,:::: O. 1~"5 4 29511.8. 0.962 0.142 29~i11:?. ().9~56 ('.1-:::1. 2 0 5118. 0.950 0.1 2 1 29511::;:. 0.0:)44 0.11-:: 2 95118. 0 -9 3 8 0.1.0 8 ::::'~i51 J :~. ( ) .. '~i ::::!:, (>" CJ'·~' {:. :~~';:/51 1. ::! II ~) .. '~J :~:'2 (J. ():::I~J 2':;'~i 1 .L :::" ~). ':~/~I:::: (' .. (>:::::2 29'311.::::. n. ':)-:::; 0.076 295118. 0.923 0.0 7 0 2'~i511 :::. ('j" .,,:~::() (I If ()I.:.~i 295118. 0.918 0 .061 295118. 0.916 0.056 295118. 0-918 0.052 295118. 0.91 2 0,048 295118. 0.910 0.045 :29511:3. (>. '~iO:::: (-0.041 )95118. 0.907 O.03Y 295118. 0.906 0.036 :;29':; 11 e. (). 906 (>. 0:::::::: 2 0 5118. 0.905 0.031 295118. 0.904 0 .029 :~:'::i51 ) :::::. i). '~'O ::: (I. 0 2 7 2 9 5118. 0.902 0.02 5 295118. 0.901 0.023 AVERAGE COST :1.063 O. ~_:'7''::i BENEFIT-COST RATIO (~% FUEL _ COST ESCALATION): 0.44 Menta sta Lake , Alaska Da msite-Ri ght Tributary to Slana River Aerial View of Mentasta Lake ,. j' . . ~. - Oamsite -Right Tributary to Slana River 6.0 NEW CHENEGA 6.1 COMMUNITY DESCRIPTION New Chenega woul d be a new community (now in the pl anni ng stage) located on Evans Island in the Prince William Sound. The village, to be built by the Chugach Native Corporation, is intended to replace the original Chenega Village located on Chenega Island, which was destroyed in the 1964 earthquake. Many of the prospective residents are second generation Chenega survivors relocating primarily from Anchorage and Valdez. Plans for the community include 21 families by the fall of 1982, an elementary school, village store, floating dock to accomodate 300 boats, and community hall. The houses would be provided by HUD and wood stoves are incorporated into the home plans. The population is expected to grow and plans exist for 10 additional lots. Families will support themselves economically from fishing, a fuel depot that would be constructed on the floating dock, and the existing fish hatchery, which will employ approximately three persons. There are three abandoned canneries but there are no plans to revitalize them by the New Chenega IRA Villge Council due to limited funds. The Village Council is interested in developing a reliable source of el ectrica 1 energy, preferably a renewabl e resou rce. The Council is pl anni ng to purchase 2 -75 kW diesel generators but intends to IJse them for backup power. The San Juan Aquacul ture Corporation has a 60 kW hydropower facility behind the hatchery. The plant is operating at full capacity, however, and would not be able to meet the community needs except, possi bly, at i rregul ar interval s of time. A study of futu re energy reqlJ i rements of New Chenega was conducted through the Alternative Energy Technical Assistance Program (AETAP)l/. Pm'ler projections were made based on a review of existing data sources and original calculations by AETAP. Total electrical energy requirements were projected to be 154,075 kWh/year for the residential, commercial, and institutional sectors, and 217,671 kWh/year to include the additional requirements from the community center, which would contain a laundromat. These calculations correspond with Ebasco's electrical energy projections for years 1983-1986. 6.2 SITE SELECTION Several potential hydro development sites appear to be located close to the proposed New Chenega village on Evans Island. The four most likely sites all possess small headwater lakes and were all overflown during the field inspection. Site 04, located a quarter mile west of and some 200 feet above the San Juan Aquaculture facilities appears, however, to be already fully developed, judging both from conversations with personnel and from field observations. 1/ New Chenega Alternative Energy Plan, undated. 6-1 The site located one quarter mile south of Guguak Bay (on the west side of the island) \'Ias previously identified by others, but was not included in this screening. It seems to be the least attractive of the remaining sites because the head avi1ab1e is only about 100 feet. Site 03, three miles northeast from Crab Bay, offers about 600 feet of gross head, connecting a small lake to the seashore in somewhat less than a mile. A small, triangular-shaped, 20 foot high dam with a 30 foot crest length could plug the gully, cut in sedimentary rock. By cutting a trench through a narrow rock ledge downstream of the lake, six to eight feet of storage within the lake would be utilized by this small dam. This project also possesses an attractive site for its powerhouse, on rock ledges near the water's edge. Site OS, on "Section 22 Lake", appears, however, to be sl ight1y more attractive because its penstock and transmission line are one third shorter than for Site 03, while the head is the same. A 100-foot long and IS-foot high concrete dam would be seated directly on bedrock at the outlet of the lake and would raise its storage elevation by approximately five feet. This site appears to be that preferred by the Corps of Engineers on page 12 of its 1976 Trip Report. The bedrock, accordi ng to USGS Map T -1150, is greenstones and sedimentary rocks. The likelihood that a basalt sill forms the rock barrier at the outlet of the lake could not be confirmed. 6-2 NOTE: TOPOGRAPHY FROM U. S. G. S. -SEWARD ALASKA, 1:250,000 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO - - - --PENSTOCK - - -TRANSMtSSION LINE --WATERSHED __ -----'---_-'-.... -d 5 o 5 E3 SCALE IN MILES REGIONAL INVENTORY a RECONNAISSANCE STUD'( SMALL HYDROPOWER PROJECTS SOUTHCENTRAL AlASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING NEW CHENEGA DEPARTMENT OF THE ARM'f ALASKA DISTRICT CORPS OF ENGINEERS Hydropower Potential Site No. 5 Installed Capaci ty (kW) 98 Oemographic Characteristics SUt1MARY DATA SHEET DETAILED INVESTIGATIONS NEW CHENEGA, ALASKA Install ed Cost ($1000 ) 2,597 Cost of Al ternati ve Power'!! (mills/kWh) 466 1981 Population: 94 (by autumn of 1982) Cost of ~dropower (mill s/kWh) 720 1981 NUlilber of Households: 21 (by autumn of 1982) Economic Base Fisheries (planned) .!! 5 Percent Fuel Escalation, Capital Cost Excluded. Benefi t/Cost Ratio 0.65 See Appendix C (Table C-8)) for example of method of computation of cost of alternative power. REGIONAL INVENTORY , RECONNAISANCE STUDY -SMALL HYDRO~OWER PROJECTS ALAS~A DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -NEW CHENEGA I'\ILOWATT-HOURS PER YEAR AWWAL PEAi< DEiiANi)-r fEAR LOW MEDIUM HIGH LOW MEllIUM HIGh 1'7'8(' O. O. O. O. O. I) • 1',,81 42708. 42708. 42708. le-...J. 15. 15. .1982 85416. 85416. 85416 • 29. 29. 2-9. 1983 128124. 128124. 128124. 44. 44. 4':', 1984 170832. 170832. 170832. 59. 59. 59. 1985 213540. 21354~j • 213540. 73. 73. ~"7 3 • 19:36 256247. 256247. 256247. 88. 88. 8:-1. 1'7';37 298955. 298955. 298955. 102. 102. L 0.:12. 1988 341663. 341663. 341663. 117. 117. 1l7. 1'?89 384371. 384371. 384371. 132. 132. 132. 1991) 427079. 427079. 427079. 146. 146. 1 4,-:' • 1991 444941. 459758. 474576. 152. 157. 163. 1992 462802. 492437. 522073. 158. 169. 179. 1'?'?3 480664. 52511.!). 569569. 165. 181) • 1'~"5 • 1994 498525. 557795. 617066. 171. 191. 211. 1995 516387. 590475. 664563. 177. ""'1" j ...'J ...... "·-.C ..:.. ~'.J • 1996 534248. 623154. 7121)60. 18:3. 213. 244. 1997 552110. 655833. 759557. 189. -'-Ie" ... ..:...-:;J • '") .. ..:...!: I.} • 1998 569971. 688512. 807054. 195. 236. 2"7,-:' .. 1'?99 587833. 721191. 854550. 201. 247 • 2-?3. 2 G.IIj I) 6'.)5694. 753870. 902047. 207. .,e--..:,.._1;:' • 31:.9 • 20() 1 621152. 788904. 956656. 213. 27,} .. 328. 2(1)2 636611). 823937. 1011265. 218. 282. 3 ... 6. 2003 652069. 858971. 1065873. -,,--..:....:!~. 294 • 3IS~' 2004 . . -C"--oO/.:,.,J.:!./. 8941)04. 1120482. 229. 306 • 38~ 2\},:'5 . :;82985. 929038. 11751)91. 234 • 318. 41)2. 2 (.11) 6 698443. 964071. 1229701) • 239. 331) • 421. 2CJ07 71391)1. 999105. 1284308. 24 .... 342. 441) • 21)08 729360. 1034138. 1338917. 251) • 354. 459. 2009 744818. 1069172. 1393526. 255. 366. 4'--' " ./ . 2'.) 11) 76(1276. 1104205. 1448135. 261) • 378. 4';'6. 21) 11 7.~9227. 1118677. 1468129. 263. :383. .,.. -.~'.).~ . 2012 77817:3. 1133150. 1488123. 266. 388. 5 L I). 2013 787129. 1147622. 1508116. .,-.". .a:.. /~I. 393 • 5i6. 2014 796080. 1162095. 1528110. .,--..:.. ;' . .,!. .. 398 • e---...J~~ • 2015 81)5030. 1176567. L548104. .,-. .:../0. 41)3 • 5:3'.) • 2016 81398l. 1191039. 1568098. 279. 408. 5:37. 2017 822932. 1205512. 1588091. 282. 413. 544. 2018 831883. 1219984. 1608085. 285. 418. 55 L. 2019 841)834. 1234456. 1628079. 288. 423. 558. 2(1,2(.. 849785. 1248929. 1648073. 291. 428. 5.~4 • 2021 8.!)0626. 1266178. 1671729. 295. 434. e---;;.J ,o.~. 2022 871466. 1283426. 1695386. 298. 440. 581. 2(123 882307. 1300675. 1719042. 31)2. 445. 589. 2',)24 893148. 1317924. 1742699. 306. 451. e---...J""I I • 2C)25 903988. 1335172. 1766355. 310. 457. . "e-(1) . ..) • 2 1j26 914829. 1352421. 17900l1. 313. 463. 613. 2( .. 27 925670. 1369669. 1813668. 317. 469. 621. 2028 936511. 1386918. 1837324. 32l. 475. 629,"~ 2029 947351. 141)4167. 1860980. 324. 481. 63" ,21)3 1.) 958192. 1421415. 1884637. 328. 487. 64~. NEW CHENEGA SITE 5 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Unnamed (Section 22 Lake) Section 22, Township 15, Range 8E, Seward Meridian Community Served: Crab Bay (New Chenega) Distance: 1.7 mi Direction (community to site): Map: USGS, Seward (A-3), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow: Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/Phase: Terrain:.!/ Rolling (1.25) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Cornputati on: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrain Cost Factors Shown in Parentheses. 0.5 4.0 160 sq mi cfs in Northwest Large Concrete Gravity 15 ft 625 fmsl 340 cu yd Concrete Ogee 2.5 ft 18 ft 622.5 fmsl Steel Penstock 12 in 3300 ft 1 Pelton 10 604 98 2.4 0.48 0.6 14.4 2.2 2.2 fmsl ft kW cfs cfs mi kV /1 phase mi mi 47 percent 403 MWh Plant Factor Program ( ( NEW CHENEGA TOWNSITE SGwmill Bay DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMAll HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA NEW CHENEGA SITE 05 CONCEPTUAL LAYOUT SECTION 22 LAKE DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY PLAin FACTOR PROGRAM CUM~~NITY: NEW CHENEGA SI n NU~mER: 5 NET HEAU (FT): 604. DESIGN CAPACITY (KW): 98. MINIMUM OPERATING FLOW (1 UNIT) (CFS): 0.48 LUAU SHAPE FACTORS: 0.50 0.75 1.60 2.00 HOUR FACTURS: 16.00 15.00 13.00 3.UO MONTH (HDAYS/MO.) AVERAGE POHNTIAL PERCENT ENERGY USAl:>LE MONTHL Y HYDROELECTRIC OF AVERAGE DEMAND HYL.lHO FLO~~ ENERGY ANNUAL ENERGY ENEkGY (CFS) GENERATION (KWH) (KWH) JANlJAkY 1.44 43949. 10.00 5!:J211. 21:5407. FEBftUARY 1.10 30323. 9.50 52450. 20U4tl. MAKCH 0.95 28994. 9.00 49690. 19157. APRIL 1.30 38396. 9.00 49690. 24939. MAY 4.57 72912. 8.00 44169. 42241. JUNE 10.20 70560. 5.50 30366. 30366. JULY 8.33 72912. 5.50 30366. 30366. AUGUST 5.55 72912. 6.00 33127. 33127 • SEP TE f'o'l BE R 5.30 70560. 8.00 44169. 419U1. UCTOBER 4.07 72912. 9.00 49690. 43635. NOVEMGER 3.32 70560. 10.00 55211. 42821. lJECErVlbER 1.94 59209. 10.50 57971. 36903. TOTAL 704200. 5!:J2109. 393905. PLANT FACTUR( 1997): 0.46 PLANT FACTOR(LIFE CYCLE): 0.47 HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Cornmu n i ty : Site: Stream: New Chenega 5 Unnamed (Section 22 Lake) ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 20 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.5 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST S 107,000 S 89,000 S 67,000 S 149,000 S 30 ,000 S 6,000 S 99,000 S 9,000 S 69,000 S 625,000 S 125,000 S 750 ,000 2.2 S 1,650,000 S 413,000 S 2,063,000 S 309,000 S 2,372,000 S 225,000 S 2,597,000 S 26,500 S 203,200 S 70,000 S 273,200 S 0.72 0.65 ;"~~ • :' , f I,iff; ,l r i\II.)F 1\ITllf~:Y t. F:F!=:I)NNA r ::;?)NCE ':::H.ID'{ --::::t1ALL H T i!o:.;:ClF'OJrIlH r:'HII,Jf ALASKA DISTRICT -CORPS OF ~NGINF~RS DETAILED RECONNAISSANCE INvESTIOA1JONS COST OF HYDROPOWER NEW CHENECiA ::: IT E NO. ':i YE:(if'i 1 '::':"::4 1 ':'::::6 19::::7 1. ':::1:::::::: J 9::::9 1990 1 ';":.' 1 1''':'·'? 1'?9:::: :[ ('!'.:j':' '::000 2001 ~~:()():2 :::::00::;:: 2004 :::00&, :2007 2/)0::;: 2010 :2011 2012 :201':;: 2014 2015 :2016 :?O 17 201::: 201':':' 2020 )021 2022 ~:l,JH/YEAR 1}034~i. 24:~:044 • 2724Tl. :3'7~;~:;7f() " :3:::2<) 1 (; I. ·4 ()I~) ::: :~: 1:. •• 4·12 1;J:;!';! • 415::::54. Ll,21 426475. 42'~/094 • 4::;::1712. 4::;::4244. 4::::5:34:::: • 4::;::7542. 43::::t..41. 440::;::93. 4411t.5, 441t.::1::::. 442256. 44:~:22;:: • 44:3~7:3::: • 444·247. 444740. ll..45234. :;~i)2t. 44~i7 27. ':'V,::!' Ll46:;;::21 • 2C':~:::: 44<:,714. ~::C}:?':~J ~,i~,:71 (:,)(" ::~ 'J :.::: () ~~ 4 '/ !,::~t .;~:~ • AVERAGE COST CAF'ITAL 2044:::::: . :2 (I Ll, iI· :::: !::: • 2044::::::: • 2044::::3. 2044::::::: • 2044:::;:::. 2044::::::::. :~'044::::::: • 2044::::;':: " ~:()44:=:::: • :2c)44:::::: . 2044::::::: . 2044:::::3. 2044::::::;: • 20448:::. 20·4488. 2044:::::: . 20448::: . 2044:::::=': . ~2(l4 4 ::: ::::! • 2044:::::::::: • '~:'O4-4:::::: • 2044:::::::;: • 20448::;:. 2044:38. ~'2C)44~:::=: • L~()44:=::=! • 2044:::::: • 2044::::=: • 2044::~::::: • 20448:::;:. ~::-U448::: , 2044:;'::::: • 2044::;:::::: • 2044:::::::: • 2()44::::?' • 2044::::::::: • ,;;:044:3:::: • 20448::: " 204 '1.::::::~:. (I g, M 70000. 70000. 70000. 70000. 70000. 70000. ]1)000. 700()O. 700(/) • 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 700\,)0. 70000. 70000. 70000. 70000. 70000. 70000. 70(lOO. 700i)O. 70000. 7(H}(H). 70000. 7(HI!)O. 70000. 70000. 70000. '7(1(100. /0000. 7()O(lO. ~; (,,)uO. ?U()OO. $/~::WH $/KWH lOTAL$ NU~DISC DISC :27i~4::::::. ,1,(~,11 1 .. 1 2744:':;::::;:. :t .. :::: 1 I i) .. ')0:::: 274488. 1. 12 q 0.7~7 2744::::::::. 1 .00 l (I. i:,I) .:: [! 44::::::::. (). 91 7 (I .. ~;i(.':' 274488. 0.849 0"4J~ ::2? 44::::::::. \)" 7',11+ (i .. :~:::31 :,.~ ''/ .Ll L~ C::::: II () II '7 4 ~5 (l .. ::;:~ :::< ':.l 274488. 0.731 0.261 27448:::. 0.719 0.239 27,tl4::;:::::. 0.707 0.21:::: 274488. 0697 0.200 2744::::::::. O. (;.::::::;;: O. :t:::::~: 274488. 0.681 0.lb9 274488. 0.675 0.155 274488. 0.670 0.143 27448:::. 0.665 0.132 274488. 0.660 0.122 274488. 0.656 0.112 274488. 0.652 0 .. 104 274488. 0.648 0.096 274488. 0.644 0.080 274488. 0,636 0.075 274488. 0.632 0.070 274488. 0.A31 0.065 274488. 0.629 0.060 274488. 0.62J 0.056 274488. 0.626 0.051 2744::='::::. O. ,0:..24 O. ()4:~: 274488. 0.623 0.044 ;~744::::::. ().b~:';) 0.041 274488. 0.621 0.038 274488. 0.h21 0.085 7744:::8. 0.620 0.033 274488. 0.619 0.080 ~74488. 0.619 O.O~k 274488. 0.618 0.026 274488. 0.617 0.024 274488. 0.617 0.023 274488. 0.616 0.021 274488. 0.615 0.019 274488. 0.614 0.018 274488. 0.614 0.017 274488. 0.613 0 .. 016 (I .. 717 0 .. 1 ::::::::: BENEFIT-cosr RATIO (~% FUEL COST ESCALATION): 0.65 New Chenega, Alaska Aerial View of New Chenega Townsite Section 22 Lake 7.0 NORTHWAY 7.1 COMMUNITY DESCRIPTION North\~ay is located 40 miles northwest of the Canada border off the Alaska Highway and consists of three distinct districts: Northway Junction; Northway Indian Village; and Northway, where the FAA installation, state trooper headquarters, and lodge are located. Within this widely defined area. approximately 375 persons reside. Approximately one-third of the population lives in Northway Indian Village. Northway Power and Light is a privately operated utility that provides electricity to 67 residences, school, lodge, airport, state trooper headquarters, and FAA facilities. The airport lights remain on throughout the night and add considerably to the load. The installed capacity of the system includes 2 -250 kW diesel generators and a 420 kW generator is waiting to be installed. Once the 420 kW generator is on-line. one of the 250 kW generators would be used as a back-up to the system. The load during the summer is 160 kW and it increases to 320 kW during the winter. The planned construction of 20 homes and 2 commercial buildings will increase the summer load by 20 kW and the winter load by 30 to 40 kW. Transmission lines feed electricity to the Indian Village which is 2 miles from Northway, to Northway Junction, and 1 mile east along the Alaska Highway. The cost of diesel fuel is $1.25/gallon. All residences served by Northway Power and Light are metered. Customers pay 23.2 cents/kWh with an increase of 2 cents/kWh anticipated soon. The FAA, which is the largest single consumer, pays a rate of 21.2 cents/kWh. Consumers can be divided into two categories according to the amount of electricity used in the home. Residences in r~orthway have appliances such as electric dryers and domestic hot water heaters that consume significantly more electricity than small appl iances, which are the primary end uses of electricity in Northway Indian Village. Car heaters are a necessity since temperatures drop below -50°F during the winter. Wood is used for space heating in the native village while oil and propane are used in the Northway houses. The FAA, Northway Power and Light, school, lodge, and firefighting provide local employment to some of the residents. Some of these jobs are seasonal rather than permanent. Pl ans are underway to doubl e the size of the school, which may provide temporary employment. No other factors that would stimulate growth were identified. 7.2 SITE SELECTION The optimum site identified in the preliminary screening, Site 02 on Beaver Creek, was removed from further consideration because discussions with community leaders indicated that land ownership of this site was in dispute between the native corporation and the U.S. Ai r Force. 7-1 At the next best site on a western tributary of Gardiner Creek (Site 03) approximately ten miles east of Northway Junction, the measured flow varied from zero to only about 0.5 cfs. Site 03A. approximately eleven miles northeast from Northway Junction and further upstream on the main branch on Gardiner Creek, was then inspected. This site, in a flat V-shaped thinly forested valley, appeared to be the optimum site although here, too, the flow measured was only about 1 cfs. None of the schist bedrock was outcropping at the damsite. Local road construction to the top of Cheneathda Hill is planned. Access from this point over the remaining seven miles to the project site, especially in wintertime, would be relatively easily along the contour. The transmission line would follow the same route because alternate routes would probably involve access along the rugged terrain of the Beaver Creek Basin. 7-2 \ .' . m~xtSaida ~. 'I NOTE: TOPOGRAPHY FROM U.S.G.S.-TANACROSS,NA ESNA 5 0 5 ALASKA, I: 2~, 000 r-H-.,.---,Hr--...--""TH-r----------I LEGEND .. DAM SITE • POWERHOOSE o SITE NO -----PENSTOCK - --TRANS MtSSION LINE -WATERSHED SCALE IN MILES REGIONAL INVENTORY 8 RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING NORTHWAY DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS HLdro~ower Potential Installed Capacity Si te No. (kW) 3A 213 Demographic Characteristics 1981 Population: 375 SUMMARY DATA SHEET DETAILED INVESTIGATIONS NORTHWAY, ALASKA Cost of Installed Alternaj}ve Cost Power_ (SlOOO) (mill s/kWh) 9,402 443 1981 Number of Houeholds: 107 Economic Base Government Subsi stence 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benef it/Co st (mill s/kWh) Ratio 1,550 0.29 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. rEAr;: l?:3·) 1 ::(81 11'83 1·:;:-:34 t::;'85 L '::;';36 L ·1'8::' l':;';3'? 1 ';' 9·) 1991 1 :,,93 L ·?94 1995 199·S 199 7 1998 19':;'9 2tJ,)"j 20»1 2(),)7 2',)~)~3 2(,' 1 J.) 201 1 21,)12 ~~ » 13 21)14 2;)15 20 I·!;) 2(J ,J.:3 2''} 19 .2 1,)24 2() 25 2')-2-" 2.)3 '.) HYDROPOWER ~ROjECTS AlAS~A DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -NORTH~AY KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 1607143. 1607143. 1607143. 1663637. 1663637. 1663637. 1720131. 1720131. 1720131. 1776624. 1776624. 1776624. 1833118. 1833118. 1833118. 1889612. 1889612. 1889612. !546106. 2,)59(193 ~ 2115587. 21721)80. 2225t)28. 2277977.) 2330926. 2436823. 2489771. 2542720. }C':'-~ •. -.:..·:.;'-/·;.)ct.)tj • 2648·S 17. 27~).1565. 2756166. 2810767. 2865367. 2919968. 2974569. 3029170. 308377i) • 3138371. 3192972. 3247572. 33191)97. :3391)621. 3462146. 3533.S71) • 3605195. 3676719. 3748244. 3819768. 3891293. 39.S2818. 41)10452. 4058085. 41')5719. 4153352 • 420098.~ • 4248619. 4296253. 434388.~ • 439152·) • 443 0 153. 19461',)6. 2·.)·)2599. 2C)59093. 2115587. 2172')80. 2349222. 252,~363 <+ 271)35 .. )5. 28:30646. 3057788. 3234929. 3412071. 3589212. 3766354. 394349.:) • 4162166. 4381j836. 4599506. 481:3176. 5036846. 5255516. 5474186. 5692856. 5911526. 6131)195. 6247998. 6365800. 6483603. 660141)5. 6719208. 683(1) 10. 6954813. 7072615. 7 19~)417 • 73 .. )8218. 74\)9559. 7511)899. 7612240. 7713580. 7:314921. 7916261. :31)176\)2. 8118942. 8321623. 194611)6. 21)02599. 2\)59093. 2l15587. 2L72081). 2473415. 2774750. 30761)84. 3377419. 3678754. 398')089. 4281424. 4582759. 48841)94. 5185428. 55.:)8167. 5951)906 + 6333645. 6716384. 71)99123. 7481862. 7864.:)01. 8247341) • 8630079. 9012818. 9176898. ':;-341)978. ·?505058. 9669138. 9833218. 99972Y8. bH61378. 11)325458. 10489538. 10653618. 10808666. 10963714. 11118762. 11273810. 11428858. 11583906. 1173:3954. 118941)02. L 2'.)49('50. 122041)9i3. ANNUAL PEAK DEhAND-l k LOW MEDIUM ~IGH 551) • 570. 58'? • 61)8. 628. .~66 • 686. 705. 725 .. 744. 762. 781) • 79i3. 816. 835. 853. 871. 8:39. 9 (, i' • 944. 9.~3 • 98.1. 1 !jOt) • 1019. 11).37. 1 1)5·~. 1075. 1093. 1112. 1137. 11,:)1. 118.:) • .1210. 1235. 1259. 1284. 13(}8. 1333. 1357. 1373. 13';'0. 1406. 1422. .1·439. 1455. 147.1. 1488. 15\)4. 1520. 55l) • 57() • 589. 6()i; • ,~66. 6;31!:. • _ ... c:o / \} .~J ,) 744. 81)5. \3t'!)~ 4> 926* 9:"17. .1047, Ulj8. 11 ,~9 • 1229. 1290. 1351. 1425. 15')0. 1·":'50. 1725. li3',)O. 1875. 1950. 2\)24. 2\)99. 214·.). 231) 1. 234.1. 2382. 2462. 2538. 257'2. 2.~\)7 + 2642+ 2.~ 7 ,.; + 2711. 2746. 278t) • 2tj15. 2~-3r::~) ,. 5~t) ~ 57(J ~ 5;:;$'--';-• 647. 74·4. 95~) • i (''::=: .. L157. l2,~\j .. 13·~·~5 • i 4 .S6 • L 5.S:? . 1·:;7.":' . 1?·)7. 2169, 23(11.) • ,~"431 • 2562+ 26';;3. 3'·)87 , 3143. .} 1 ..,,'~~ .. 3::55. 3311. 3368. 3.<42·<4. 348() • 3536. :35';;:': • 3648. 386.1. 3?14. 3·~.~ 7. 41)2'.j, 4179. NORTHWAY SITE 3A SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Gardiner Creek Section 1, Township 15N, Range 20E, Copper River Meridian Community Served: Northway Distance: 16.3 mi Direction (community to site): Northeast Map: USGS, Tanacross (A-2), Alaska 2. HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Height: Crest E1 evation: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tai1water Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Voltage/Phase: Terrain:l/ Flat (1.0) Ro 11 i ng (1.25) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: 28.9 24.7 20 sq mi cfs in Sheetpi1e 15 ft 2415 fmsl Stairstep Fish Ladder 5 ft 66 ft 2410 fms1 Steel Penstock 45 in 7000 ft 2 Crossflow 2320 fms1 85 ft 213 kW 37.0 cfs 3.7 cfs 1.3 14.4 6.0 5.0 11.0 mi kV /1 phase mi mi mi 31 percent 578 MWh Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: local Plant Factor Program fishe~ mostly grayling and pike. Y Terrain Cost Factors Shown in Parentheses. ----~ -........--....... .. , ..........................................•....... , ... --'---.. ------, \'._--r--- DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ~") ( ( NE/SC ALASKA SMALL HYDRO RECUNNAISANCE STUUY PLANT FACTOR PRUGRAM COMt1UNITY: NORTHWAY SITE NUMl:1EI<: 3A NET HE AD (FT): 85. UESIGN CAPACITY (KW): 213. MINIMUM OPERATING FLOW (1 UNIT) (CFS) : 3.70 LOAU SHAPE FACTORS: 0.50 0.75 1.60 2.00 HOUR FACTORS: 16.00 15.00 13.00 3.00 t<10 NTH (#OAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USAl>LE MUNTHL Y HYDROELECTRIC OF AVERAGE OEr~AND HYURO FLOW ENERGY ANNUAL ENERGY ENEKGY (CFS) GENERATION (KWH) (KWH) JANUARY 3.87 16622. 10.00 254272. 11081. FEURUARY 3.30 O. 9.50 241558. U. MARCH 3.21 O. 9.00 228845. O. APRIL 5.57 23152. 9.00 228845. 15434. MAY 50.80 158472 • 8.00 203418. 102790. JUNE 78.40 153360. 5.50 139850. 94724. JULY 52.30 158472. 5.50 139850. 97493. AUGUST 45.90 158472. 6.00 152563. 98553. SEPTEI~BER 27.00 112226. 8.00 203418. 74379. OCTOBER 12.80 54977 • 9.00 228845. 36651. NOVEMBER 6.26 26020. 10.00 254272 • 17346. OECEM8ER 4.98 21389. 10.50 266986. 14260. TUTAL 883161. 2542720. 562712. PLANT FACTOR(1997): 0.30 PLANT FACTOR(LIFE CYCLE): 0.31 HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Site: Stream: t40rthway 3A Gardi ner Creek ITEM 1. Dam (including intake and spillway) 2. Pe nstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri n9 Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANN UAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.5 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST S 100,000 S 919,000 S 331,000 S 188,000 S 341,000 S 6,000 S 181,000 S 20,000 S 275,000 S 2,361,000 S 236,000 S 2,597,000 2.3 S 5,973,000 S 1,493,000 S 7,466,000 S 1,120,000 S 8,586,000 S 816,000 S 9,402,000 S 44,100 S 735,500 S 141,000 S 876,500 S 1.55 0.29 1111',l rn"')[hITOF{'t~, F':ECCINNAI::;f.'~NCE :::;TU[I'y' -::A1ALL HY\iF,:IIF'III,JL',' f'h'I.:I.II-·!. 1-< "FP,F' ':, ::~: iJ. I':»~:, I. ';'::::7 I <j<'4 1 ,.:"~j rc:; I ':"":i,<:, I':)'::·') . ,:"(H)(', :.. '(>('11. :::'(H) .. ,::, 2')07 '?(I()!:! :::'()()9 2"') 1 (. ::011 .... CI.1 ) ::::,. 1 .::: ;:014 ::::".1':.; ::'01(:, ".>':'1 t7 '(i 1 :::: 2019 ,:>:<:,) ::: i) ~:. 1. ,:(':i:~: .:·::()?4 ALASkA DISTRICT -CORPS OF ~NGINErRS [IE Tr::', I LED f;:ECOW,IA I :::;':;A!',IC:E 1 Nl..,"F:::;T I CIr:::,T I Cif'I':::; () I:::T OF HY[l~~I)F:'(H.JEF': j'II .. Ij;:THWAY ::; In: 1\10. :;:A 5"5::::: 1 02 • ~~~54J7:::: " 5 ~~ ~::i ~~i 1~.lJ. If ~:;~S/~,~7'"-5~i II c.; L~;.:3 .-:) () :::: " ":1/'04::::0. '::;71. ::45. ~57:::::07 4. ~:;~7 .q.!::()":::. ~:~"? 51~i :~:5 .. :::; '7 :::::? 0 (> • 5 7 9:2::::7. ~5::~:1) t 5:2:. ":.:::: 1 016. ~~:::2:::::94 . ::-;;::':::::::342. ~5:=::::::21 ::.-: " &::" ~'I"',· ", I "r ,"', _, :-:' •. ::' '.:' (: .. l~ •.. ~-:;::':4 731 . ''::;:::4\'00. C::r~F' I T~il." 740J14. 7 L~r):~: 14" T4UJ14. 740:~: 14. 740:;:1.4. '/ 40~:: 14. 7iJ.uJ:i4. 74'').:::14. 740::::14. 740::: 1,.,+. :7 40::~: 1 'l. '7.4(1::::: 1 '+ .. ;' .itO:.~: 'l 4., :;' 4 0:·-:1 'l. 74n:~: 14. 7'+0314 .. '! 4 1Y::: 14 • :7 J+(l:~:: 14. 740:;:: 14. /41)Jl.:J.. 740::::: t if. 740::'::: I ,:~. '/' LI()::::: I 4 .. 740314. 7 4 ():':: 1 4 • 740314. '74'')3.14 .. 7403.1.4. '740::;::14. ?40'~:14 • 740:314. 74n:~:14 • 740314. 74«:: 14. 741):;: 14 .. 7 /+i )31.<'+ , 740314. ~;'4CI:;: 1 't. ! Il'Y=': 1 4,. 740:::: 14" 74():::;: 14. 741):::: 14. 740:::04. 740314. ? 41):::: 14. 740314" l j~·U·:: 14 .. (I ~, 1"1 1 ·41 (>00 .. 141000. 141.()OO. 141000. 141.00(>. 1,41000. 141 OO(). 1. L~ 1 O()(). 141000. 141000. t :1· 1. (I()() " 1410, )1). 141,)()O. 141,)00. 141 ('!Oi). 141. OOi). l·q·, (l(it). 141(1no. 141. (>:)0. 141 ()t)O .. 1 410(10. 1410,)0. 1. ,.~ 1. (11)( ) . 1.410')0. .1.41.000. 141000. 141000. 14 j .)()(). 1 ·41. Coo.)(>. 141000. 1410()(,. 141000. 141000. .1.410,·1(). i 41 (l(ll). j 4 j ()Oi). :14·1:)0:>0. 1 .ell :')~)('. 1. 41.:'O(). 1 ,+ 1(0)(1 .. 1 ·~·1. ()():: )" j41 (100. 14.1.(;,:\(.) .. 141000. 141000. 141UOO. t LI·1. ('nu . TOTP"._~' ::::::::: t :::: 14. :::::::: 1 .~:: t 4-" :::::::: 1. :~: 14. ;::::::::1:::14. ::::::: 1 31 4 n :::::::: 1 :::: 14. ::.:::::: 1 ::::: t 4. C:::: 1 :::: 14. :::::'::: j:::: 14. ::.::::: 1 J', 4. C:::: 1 .:: t L~ • ::::~: 1. :':: 1. 4 • :::::::: 1 :;:: j 4. :::::::: 1 .:.=: 14 • :~~::::: 1 :':: 1. 4 . :~:::: j.:: 1 '+ • :::::::: 1.:: t ,:j. • :::::::: t:::: 14. ::.: :::: t .~: 1 4 , :;:::::: j ::.=: 14. :::::::: 1. ::: 14 • ::;::::1314. :~::::: 1 314 • ;::'::::: 1 J l/~·. :~::::: 1 ::: 1 4 " :::::=.: 1 :~: 14 " :::::~: 1 :~: 14" ::::::::i :::::.1 .I·f, ;:::::~: 1.::::: 14. ::,::::: 1 ::: 1 Ll , I;:::::: 1:::: 14. :::::::: 1:::: 14. :::::::: 1314. ::~: :::: 1 :::: 1 4 • ::::::::1::':14. :::::::: 1 ::.::: 14 • I:::::; 1 :.=: 14. f,:::: 1::: 14. :~.::::: 1 .:~: 14. ::::;.: 1 :3 14. :::::::::!. :)14, ::::;::: j :::: 1. L! u :::::;:: 1 ::' j ,:) .. :::::::: 1 J 1 -4. ::: :;:: 1 ::: 1. Ll " :::::::;:1314. ::::::::131.4. 1-/ ~I,)H "10 Nfl r ::::C: 1 • I:, 1 ::::: 1. (,i)::: 'j .' ,«)4 :I. ,. l·,(ll ., • ~:;'~,? 1 • ~:, ';::, .::: '1 .' :~,'~'O 1. , ~'::'(, I. " 0::':;:=:0 I • ":,'7(, 1. • ~":; '/ ::::: '1 • '~; /(, I. • ~:"I (::.f:, 1. " "I/~,J .I " ":;/:,(') 1. , t:,"'~7 " I' ~:~; •• :; '" ' :[ .. L.::o:;;(, I .. '::;47 '1 " ':, 4 ~'~ .! • ~:i:1 :~:: 1. , ~'::;40 .1 • ":,.:::::: '1., ':::;-:::I~. 1. <::.-:<:: 1. • ~'::, .:: () 1. " ":':;::7 .L. ':<>l 1 . 0::'::' 1 1. ., "'",1..:) 1. " r::. 1 7 1 • <:, 1. L=, 1 • '51::::: 1. ~d2 1 " ~::I:I 1 1. 511 1. • ~) 1 0) 1 " '51 I) 1 , ~::;r:)::: 1 n ~:1()7 1. • 5(' '7 :;, / VI.I!--I D J ':;C: 1 u :,~ U:? 1. I 14 (,' " (-, C:f~~ (J .. (:,l):.::: ( '_ it::'·:4- f), <'[49 C,. il·1 /:, (I" :-.::'~:(-" () • .,~: ~:;'I:~ : ':'" :;':-1.:? (".1.':>:-, (i" 1 :':::'2 '., ,.1 (:,':;, I.,'" 1 ~:;/ ,'),,14"', O. 1 ::::':i i). :l16 (, , 1. i):::: 0 .. oj I')() ():I ()':)'::: (1 .. (>::::(-:' 0.0::::(> O. (174 () /1 (':t ,~-,I~I ' .. '" i"I,I,' (l, 0'5.t (I. ,)LL:::: ( '" ()!~ '1- (I" (If.~ 1 AVERAGE COST 1.,r::,i,~~, (1.,":41 !f:-.NF-_FIT-·":·I)':n I~ATIO (":'% ~:'U1::L C'CI:~;"r E:::;CAL.f-1TI(II·'.j): 1).)'::; Nor t hway , Alaska Aerial View of Northway Indian Village Northway -Airfield Vicinity Aerial View of Northway Junction Gardiner Creek Site Area 8.0 PORT GRAHAM 8.1 COMIv1UNITY DESCRIPTION Port Graham ;s a native village with a population of 162 persons. Located near the southern end of the Kenai Peninsula, Port Graham is primarily a fishing community. In addition to 53 houses, structures that have electricity include a cannery, fire station. church, school, community hall, and Village Corporation building. The community is served by Homer Electric Association (HEA) at a residential rate of ~.05/kWh.1! Electricity consumption for a househol d may be as much as 1500 kWh per month with a correspondi ng bill of ~85 to ~100. Households have a \tide variety of power tools and appliances including refrigerators, freezers, televisions, and microwave ovens. lv1any residents have electric hot water heaters, which use a large amount of electricity. Per capita consumption in the residential sector would not be expected to increase if the price of electricity was reduced since the market is fairly well saturated with household appliances. The consequences of a drop in electricity prices may rather be the stimulation of new businesses. ~10st homes are heated with wood stoves although some residences have oil burners. The annuql cost of heating a home with oil is approximately ~2,150._?/ It is likely that a conversion from 011 to wood will take place as oil prices continue to rise. The economic base of Port Graham is fishing and several job opportunities exist both within and outside the industry. In addition to commercial fishing boats and a canner-Y. jobs have been available at the school and through the CETA program. No projects that might stimulate community growth were identifed. An influx of permanent population would likely be dependent on the growth of more jobs. 8.2 SITE SELECTION Port Graham Site No.1, Mount Bede Creek, is located on the western tip of the Kenai Peninsula. The damsite would probably be a low concrete dam, located where the stream narrows adjacent to a point which is covered by trees. The penstock route appears moderately difficult and probably would follow the north stream bank. The powerhouse would be located in a wooded area near the outlet of the creek into the Cook 1/ Price does not include service charge or fuel surcharge. 2/ 2 bbl/month (April -September); 3 bbl/month (October -March) at S71.62/bbl (55 gallons) 8-1 Inlet. The transmission line, which would follow the shore line to English Bay, would be difficult to construct on the steep slopes, and would be exposed to severe storms. The site offers lower installed capacity. This factor, coupled with the access problems, render this site relatively unattractive. The preferred site, Port Graham Site 5, is located on Dangerous Cape Creek. The site would be located at the confluence of two smaller streams located at elevation 460. Streambed material appeared fine enough that a sheetpile dam would not present major difficulties. The penstock route would follow the north bank of the stream, and the powerhouse site would be located near sea level. The transmission route would follow the coastline at an approximate elevation of 100 to 400 feet to connect with the HEA transmission line 6 miles to the southeast. 8-2 288 '" NOTE: TOPOGRAPHY FROM U. S. G. S. -SELDOVIA ALASKA, 1:250,000 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO -- ---PENSTOCK -- -TRANSMtSSION LINE --WATERSHED " 5 0 5 E3 E3 t===! SCALE IN MILES REGIONAL INVENTORY Ii RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PREUMINARY SCREENING ENGLISH BAY-PORT GRAHAM DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS H,z: d ro~ owe r Potential SUMMARY DATA SHEET DETAILED INVESTIGATIONS ENGLISH BAY-PORT GRAHAM, ALASKA Cost of Insta 11 ed Installed Al ternai}ve Cost of Capacity Cost Power_ Hydropower Site No. (kW) ( S1000) (mills/kWh) (mill s/kWh) 5 985 7,882 387 160 Demographic Characteristics 1981 Population: English Bay -125; Port Graham -162 Benef; t/Cost Ratio 2.43 1981 Number of Households: English Bay -36; Port Graham -46 Economic Base Fi sheri es 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. See Appendix C (Table C-8) for example of method of computation of cost of alternative power. ~£I;[ONAL INVENTORY i RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS '~E:,~ r;: t :1':3(' L ::;';3 1 L ':;;33 l. '~:J4 t :;t;3r;:,; 19'?3 i=-':;-4 i ';·:j:5 lltl;l~ t997 1998 1 '::;''::';9 : 1.)\) 1 ~2"jl.)2 21) r.j 3 21)('4 2l)~)7 ;::'1,j8 2')09 2·:' 13 2',) 14 2':'15 2 I)! 7 2') 1 :~, . ~O 1 ':;' 2 1,)2(r 20 2~:~ 2!')2l6 ALAS~A DiSTRiCT -CORPS OF ENGINEERS LOAD FORECAST -PORT GRAHAM KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH ,:;94286. 718.S91. 7 43~}97 • ?.s7502~ 7919.)7. 816313. 84,)718. :3.:;'5123. 8;39529. ·~13934. 'i38339. 9,S1213. 9:3408·~ .• 10,}696'} • 1,: .. 29:334 , UY?'5581. 1 t.)9:?455. 112132·~. 11442')3. 1167076. 11 '?0664. l214251. 1237839. 1261426. 1285014. 13')86\H. L332189. 1-1:'"---. I. ,:'",,:':J / 10. 1379363. 14.)2951. 1 .. r33850. 14.:)4748. l49'5.S47. 1526546. 1557444. 1588343. 1619241. 165,) 141}. 1681 !)3-1' • 1711937. 1732515. 17531)93. 1773.:;. 7',). 1T14248. 1814826. 1835404. 18559~3 L • U37.:;559. L897137. 1.9L7715. 694286. 718691. 7 43t)97 • 7.j 75~)2. 7919(17. 816313. 84·,)718. 865123. 88952'~ • -:;-13934. '?3813'::( • 9·~47.:)0 • l()51181) • 11,) 7 .S ,) 1 • 11,":'4,)21 • 1221)442. U7 6:3.S2. 1333283. 138~703. L44.:;'124. 15,)2544. 157()4"50. 1638355. 1 /,1)6261. 1774166. 1842072. 1909977. 1 ~778l33. 2 ',)45788. 2113694. 2181599. 2224998. 2268397. 2311796. 2355L95. 2398594. 24419-:;;3. 2485392. 252879 L + 25721'?1} • 2615589, 2,~5\}6 74. 268'5759. 2720844. 2791,)14. 2826\)99. 2861184. 2896269. 2'1'31354. 29.:>6439. 694286. 718691 • 743097. 7675()2. 7';'19\)7. 816313. 84\)718. 865i23. 889529. 913'734. 938339. 1,)283,)6. 1118273. 12(j8241. 1298:::08. 1388175. 1478142. 1 "5.,;)8111) • 16581.}'?7. 1748044. 1838 0;:' 11 • 1';;5,)235. 2')6245~3 • 2174681. 2286905. 239'" 129. .25113'5.2. 262357,:) • 2735799. 2848023. 2961)246. 3016146. 31)72045. 31:::7945. 3183844. 3239744. 3295643. 33515-+3. 3407442. 3463342. 35t':;'241. 35·:)8833. 3·!) 18425. 3.-:'68(117. 3717609. 37.:) 7 2 I} 1 • 38167-:;-3. 38.';6385. 3915977. 3,';'65569. 4~)15161. ArH~UAL FEAr,' L,EriAr;;::-r. i, LOW MEDIUM HIG~ 238. 246. 254. 2,~3 • 271. 28t'; + 31.)5. ~H3. 3:::1. 329. ~337 .. 345. 3'51. 3 . ..:, 1. 376. 384. 3~'2 + 4,)0. 41)8. 416. 424. 432. 44,) • 448. 456. 464. 472. 480. 4-i'1. 5t)2. 512. 533. 544. 555. 565. ";j/I!). 586. 593. 6\}\) • .:),j 7 + 614. 622. 629. .~4:3 • 65\) • 657. 246. 254. 27 L. :3 f'}5. 3l3. 321. '3":' t • 41;3. 4:37 • 457. 4 i.'; • 4':;''5. 515. 561. ::';:: 4 • 631. 654. 677. 7t)! • 724. 747. 7.~2 4 792. 81)7. 821. 83.'" • :351, :3·":'6. 881. 8';'6. 9\)8. 92 ',) • ~;32 .. 944. 95,-:) + 968. 981) • '~92 + 1 \)(14. ll) l·S. :::~ ,~, ::::4 ,~ . ,... ' .. ' ._' '3 L5 ~::: J 414 4..1::- 4 '7":,: ::.,"':' ;'j 5'-;"~ 62':; 8.22 86',:' ';;37 :;-75 FJ14 1,1)33 1';:: ~,: . 1\j7 L • 1'}'::( t), 111'J " 1 1.2·~ 114;3 1 L~.--;; 118,~ 12.2: L239 1256 1 . ..:. ,/.~ 1.2'i') 13,)7 13:4 1341. 1358 ~EGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALAS~A DISTRICT -CORPS OF ENGINEERS 1'Ei-~IR lS'8(1 l'i8L L982 L '7'83 1984 19B5 1'186 1987 lq88 1989 L ':t90 1991 1992 1993 1994 1995 199,::- L997 19'1'8 1999 2000 .2001 2002 2('03 2004 ::005 20()6 2008 2009 2(}10 2~) 11 2\)12 2013 2014 2':j15 2~) 16 2017 :C'18 2()19 2021 2022 2023 2\)24 2(j25 2026 2 1)28 2!)29 2030 LOAD FORECAST -ENGLISH BAY KILOWATT-HOURS PER YEAR LOW HEDIUM HIGH 535714. 554545. 573377. 5922,)8. 611~)39. 62987 t. 648702. ':S1:)7533. 686365. 7')5196. 724()27. 741677. 759326. 776976. 794625. 812275. 829924. 847::';74. 865223. 882873. 9t)~)522 • 918722. 936922. 955123. 973323. 991523. 1009723. 1027923. 1046124. 1064324. 1082524. 1106366. 1130207. 1154049. 1177890. 1201732. 1225573. 1249415. 1273256. 1297098. 1320939. 1336817. 1352695. 1368573. 1384451. 1400328. 1416206. 1432084. 1447962. 1463840. 1479718. 535714. 554545. 573377. 592208. 611039. 629871. 648702. 667533. 686365. 705196. 724,)27. 767561. 811096. 854630. 898164. 941699. 985233. 1028767. 1072302. l115836. 1159370. 1211766. 1264163. 1316559. 1368955. 1421351. 1473748. 1526144. 1578540. 163\)936. 1683332. L716819. 175\)306. 1783793. 1817280. 1850766. 1884253. 1917740. 1951227. 1984714. 2018201. 2045273. 2072345. 2099416. 2126488. 2153560. 2180632. 2207703. 2234775. 2261847. 2288919. 535714. 554545. 573377. 592208. 611039. 629871. 648702. 667533. 686365. 705196. 724027. 793446. 862865. 932285. 1\)01704. 1071123. 1140542. 1209962. 1279381. 1348800. 1418219. 1504811. 1591403. 1677995. 1764588. 185118\). 1937772. 2024364. 2110956. 2197548. 2284140. 2327272. 2370405. 2413537. 2456669. 2499801. 2542934. 2586066. 2629198. 2672330. 2715463. 2753729. 2791995. 2830260. 2868526. 2906792. 2945058. 2983323. 3\)21589. 3059855. 3098121. ANNUAL PEA~ DEMAND-K LOW MEDIUM HIGH 183. 190. 196. 203. 209. 216. 222. 229. 235. 242. 248. 254. 260. 266. 272. 278. 284. 290. 296. 302. 308. 315 • 321. 327. 333. 340. 346. 352. 358. 364. 371. 379. 387. 395. 403. 412. 420. 428. 436. 444. 452. 458. 463. 469. 474. 480. 485. 490. 496. 501. 507. 183. 190. 196. 203. 2\)9. 216. 222. 229. 235. 242. 248. 2·::'3. 278. 293. 308. 337. 352. 367. 382. 397. 415. 433. 451. 469. 487. 505. 523. 541. 559. 576. 588. 599. 611. 634. 645. 657. 668. 680. 691. 700. 710. 719. 728. 738. 747. 756. 765. --.,. / / ,.J • 784. 18~. 19\) • 1';'6. 203& 2\)9. 216. 222. 22'~ .. 235. 242. 24:3. 27? 296. 3 1';' • 343. 3.~ 7. 3'; 1. 414. 438. 462. 486. 5L5. 545. 575 604. 634. 664. 693. 723. 753. 782. 797. 812. 827. 841. 856. 871. 866. 900. 9.15. 930. 943. 956. 969. 982. 995. 10\)9. 1022. 1035. 1048 1061. PORT GRAHAM/ENGLISH BAY SITE 5 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Dangerous Cape Creek Section 17, Township 9S, Range 15W, Seward Meridian Community Served: Port Graham, English Bay, Homer Electric Association Distance: 3.5 mi (from Port Graham) Direction (community to site): North Map: USGS, Seldovia (8-5), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Height: Crest Elevation: 4. SPILLWAY Type: Openi ng l-lei ght: Width: Crest El evati on: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vol tage/Phase: Terrain:.!! Flat (l.0) Ro 11 i ng (1. 25) Total Length: 9. ENERGY 5.8 23.8 40 sq mi cfs in Sheetpile 10 ft 470 fmsl Stairstep Fish Ladder 5 ft 26.5 ft 465 fmsl Steel Penstock 30 in 11000 ft 2 Pel ton 10 fmsl 407 ft 985 kW 35.7 cfs 3.6 cfs 2.1 14.4 4.1 2.0 6.1 mi kV/1 phase mi mi mi Pl ant Factor: 52 percent Average Annual Energy Production: 4488 MWh Method of Energy Computation: Flow Duration Curve 10. ENVIRONMENTAL CONSTRAINTS: Humpback salmon spawn near mouth of this stream. Powerhouse siting should take this into consideration. 1/ Terrain Cost Factors Shown in Parentheses. ,-------. '-. I ' . .-/ C:~~~ P DAM PENSTOCK TRANSMISSION UHf POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA ENGLISH BAY-PORT GRAHAM SITE 05 CONCEPTUAL LAYOUT DANGEROUS CAPE CREEK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGI NEERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Si te: Stream: Port Graham/English Bay 5 Dangerous Cape Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bi furcati ons 4. Swi tchy a rd 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (A/P = 0.07823) Operations and Mai ntenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 43,000 $ 914,000 $ 583,000 ~ 321,000 $ 30 ,000 $ 19,000 ~ 169,000 $ 32,000 $ 165,000 $ 2,276,000 $ 228,000 $ 2,504,000 2.0 $ 5,007,000 $ 1,252,000 $ 6,259,000 $ 939,000 $ 7,198,000 $ 684,000 $ 7,882,000 $ 8,000 $ 616,600 ~ 94 2 600 $ 711,200 $ 0.16 2.43 F'I-'! ; J 1"iI ',Jril. I NVE N T()f;:"( ~, REC ONNA I ::;AN CE :::nUDY -::;;MALL HYllh:I,IP OWEF, F'h u,J ECl':: ALAS KA DISTRI CT -CORPS OF ENG I NEERS DETA ILE D RE CO NNAI SS ANCE INVESTIGATIONS e(I(:; T (IF HYDF'" :IF'(I (·JER -B ENE r::-I T C:(I ::;T I'~AT I () F'Cl F~ r CiR?)HAi"i :::; I TE N(I. ~·i lE'N :;' I '::;::::Lf i. 9::::f::, 19 ::=':7 I. 9';1 (; 1. '~/') 1 1 ':,;"::r:: l.o:J9 3 19 ')4 1 9 96 l':i 97 1 9 9 ::::: 1.9 99 ,::~O(),) '2 001 :::-00 :2 2 00 :~:: 2 0 04 ::O U '':; ~:O (>/~, ::::007 ::2 0(1 :::: ::~00 9 ,:W1 0 :?,) 11 2 01::: :2 013 2014 2 015 2 011:.:. 2 017 2 01 f: 2 019 .2 ()~2 () :20 23 2024 2026 ~-:-:O:::7 f<WH l YEA I:;' 44 f ::='::O(l ') . 4 4::::::;:U OO . 44:::::::::0 ('0. 44:~:::::(l(l0 • 44:::::::(l i)O . 44f:::::OO O . 4 I.f:,::::=':OOO. 44::::::000. 44:::::::000. 44::::::::000. 44:::::::0 (lI) • 44::::::000. 44:;::::::000. 44::::::(>0 0 . 44:;:::::::000 . 44::::::::000. 44:::::::000. 44:3:3000. 44::::::000. 44:3::::000. 44:::::::0(,'0 . 44::::::;:000. 44:3::::000 . 44:3 ::::(H)0 • 44::::::000. 44:::;::::000. 44:3:::::000. 448::::000. 44:;:::=':(100. 44 ::: ::: (II) 0 • 44:::::3000. 44::::::000. 44:3:3 000. 44:3:::000. 44:::::::;:000 . 44::::::: (H)(l • 44:::::3000 • 44::::::()()() • 44::;:::::000. 44 ::::3000. 44:::;::::000. 44:~::::;:000 • 44;:::;:::0 0 0. 44::::=:<:.00. 2 02::: 44::::::000. 20:29 44 :::::;::000. :";:0 :.::0 44::::::;:000. AVERAGE COST CAPITAL ·~)L~()I.:..·2 1;' • c .. 2 (~f;.:2 ,~, .. l;.2()t.2 ';:J " 1;:·:2 () /;. 2 '~1 II (-:.:2()/:.·:2'"i' • 1~,~'2(j',:,2') • 6:2 0 1;:,::;:';:' • 6 201;:,'2 9. 6 ::;::06:29. 620(:,2 9. ,S2(l/;,:2 '"i' • (:.20629. 620/:,29. t,2()(:,2~) • ,~,2()I:.,:21~j • 1;,2()/:'2'~1 • ,=-:2 () (:. :2~' • 1:.,.~~()cI2·~1 • /:..:2 () ;~-:I:2~ ';1 • 620629. (:12()(;,2'~ II is :2~ () I~-:' :;;~ I~ • t,2()1:..21~J • 6206:2'~J • 6 :20t:~,:::·::,. 62 0 6::::9. '--..:2:()!.:.,2''i! • ,~,2(),~:,:2~1 • ,S2(>/;. '2'~1 • ~,2()1.:..2-:'J • (S2()I:.,;~r~J • 1.:.,~2()t;:, ~~ ';1 • {:1 ::~()1:.,2'"i' • 1:.,2()I;,L:'~ II /;.2 (>/:.. :2 1~) • t,.:2()/:.·2';) • 1:.~2(}I,,,,,,2'~i • IS2()I-:,,:2'~) • C.2(l/.:..:2''i' • (S~:()tl~:I~1 • I':. 2 ()/.:.. 29 • (I ~( M ';'4/:,00. ?4600. 9 4600. ';'4600. 9 46 0(1. 94/~,()() .. 94600. 94/~,()1 ·1 . 94600. 94600. 94600. 9 46uO. 94600 . 94600. 946(XI. 9460(). 94600. 94600. 94600. 9460 0. 94'::.00. 94600. 94~,OO. 94600. '::'4600. 94600. 9 4600. '~'46(lO • 94600. 94600. 94600. 946(10. 941::.00. 94600. 94600. 9 4600 . 94600. 94600, 946(>1). 94(1)0. 94600. 9 46u O . 9 460(1. 9460u. ';:1 4600. 9460U. 94600. $1t:::WH $/K WH TOTALS NONDI SC DIS C 7152 29 . 0 .1 59 O.11 ~ 7 15229. ('). 1. ~i'::' ,). 1 1 (> 715229. 0 .1 59 0 .103 7152 29. O. j 5':;:' O. 1,i 9':;i 71522 9. O . 1~9 0 .089 7 1 5229 . O . t~~ 0.082 715229. 0.159 0.076 71 ::;iZ:9. (). 1 r::i9 (j " ')71 715229. 0.159 0 .0 6 6 715229. 0.1 ~9 0 .061 715229. 0.159 0.057 7 152:29. 0.159 0.053 715229 . 0.1 5 9 0.04 9 7152 2 9. 0.15 9 0.046 715229. 0 .159 0.042 715229. 0.1 59 0.039 7152 2 9. 0.1 5 9 0 .037 7152 2 9. 0.159 0.034 715229. 0.1~9 0.032 715229. 0.159 0 .029 715229. 0.159 0.027 7152 29. 0.159 0.025 7152 2 Q • 0.1~9 0 .024 715229. 0.\59 0.0 2 2 7152 2 9. 0.1 59 0.02u 715 22 9. 0 .1 ~9 0,,019 7 15229. 0.1 59 , 0.018 715 22 9. 0.1 5 9 0 .016 715229. 0.159 0.01~ 715229. 0.!~9 0.014 71 ~i2':~9. O . 1 ~i9 i>. (11:::: 715229. 0.15 9 0.012 715229 . 0 .159 0.011 715:229. 0.1 5 9 0.011 715 229. O. t~9 0.010 715229. 0 .1 5 9 0.0 0 0 715229. 0.159 0.008 715229. 0.159 0.00::: 715229. 0.159 0.007 715229. 0.159 0.00 7 715 229. 0.159 0.006 7152 29. O.l~Q 0.006 715:229. 0.1~9 0.00~ 71 :i2 ::::~';'. (I. J 5 9 1).005 715 ~'~~. 0 .1~9 0.005 7 15229 . 0.1 59 0.004 71 5229. 0.159 0.004 O. 159 (>. 0 :;:5 HENEFIT-(:O :::;T F,'AlIO (~i l. FUEL (:O::;T E::;CALATION): 2.4::::: Enqlish Bay -P ort Graham , Alaska Aerial Vi ew of Port Graham Aerial View of Engl ish Bay View Upstream Toward Dangerous Cape Creek Da msite 9.0 SELDOVIA 9.1 COMMUNITY DESCRIPTION Seldovia is a native village located on the southern tip of the Kenai Peninsula on Kachemak Bay. The village of 480 persons can be reached by boat or plane. Several commercial establisllnents, two schools, and a Vi 11 age Corporation office compri se the vi 11 age center. Electricity consumers in Seldovia purchase power from Homer Electric Association (HEA). Backup diesel generators are located 1n the village to be used in the event of outages. Households have a fairly complete range of appliances and power tools. Since the power rate is t"elatively low, the consumer market probably has a1 ready been saturated with appliances. If the price of electricity was reduced, it could be expected that per capita consumption may remain unchanged. Homes are heated by wood stove or oil burners. A typical annual heating bill based on oil burners is ~1,000. Fishing is the prinCipal source of income and the mainstay of village economic activity. Unemployment is chronic since fishing is a seasonal activity and does not employ all the residents in the labor force. Seldovia has a slow growth pattern at present with 1 to 2 households being added to the population each year. One factor that may influence growth is the reopeni ng of chromi um mi nes at Red t10untai n. Thi s renewed activity would provide jobs locally as well as increase the electrical load of the HEA system. 9.2 SITE SELECTION Site 2, a Barbara Creek tributary, is located northeast of Barbara Creek, approximately 100 feet downstream of the confl uence where the northeast abutment is clearly exposed bedrock. The site could either be a low concrete or a sheetpile dam. The principal drawbacks to this site in comparison to the preferred site are somewhat lower flows and lower generating capacity. Site 4, Windy River, is located just east of the Kenai Chrome Nine access road. A small sheetpile dam spanning approximately SO feet and located in alluvial deposits appears to be the best diversion option for the site. The penstock would follow the northwest bank of the Windy River for a distance of only 2400 feet. Close to 200 feet of net head can be developed over this distance. The transmission line would traverse approximately 2.S miles of flat terrain to the existing HEA Li nes northwest of the powerhouse site. The advantages of thi s site over site 2 include a greater degree of accesssibility, higher flows, and a slightly greater installed capacity. 9-1 H~droEower Potential Insta 11 ed Capacity Site No. (kW) 4 764 Demographic Characteristics 1981 Population: 479 SUMMARY DATA SHEET DETAILED INVESTIGATIONS SELDOVIA, ALASKA Cost of Install ed Alternal}ve Cost Power_ (UOOO) (mi 11 s/kWh) 5,274 387 1981 Number of Households: 137 Economic Base Fi sheri es Touri sm 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mill s/kWh) Ratio 140 2.78 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. NOTE: TOPOGRAPHY FROM U. S. G. S. -SELDOVIA ALASKA, 1:250,000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO. - - ---PENSTOCK ---TRANSMISSION LINE --WATER SHED 5 0 5 E3 E3 1--1 SCALE I N MILES REGIONAL INVENTORY Ii RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIEI IN PRELIMINARY SCREENING SELDOVIA DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PRO·jEeTS ALASKA DISTRICT -CORPS OF ENGINEERS fEAR 1981) 1981 1982 1983 1"7'84 1":7'85 1986 1':;'87 1':;'88 1989 19':;'~) 1"7'91 1992 19"7'3 1994 1·:;-95 19':;'6 L :;-"7' 7 1998 1999 2001 20()2 2003 2(1)4 2005 2006 2007 2008 2 ()',)9 2010 2011 .2013 21)14 2()15 2016 2 I)! 7 2018 2019 2020 2021 2~122 2023 2()24 2025 2(t,26 2()28 2\)29 2030 LOAD FORECAST -SELDOVIA KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 2052857. 2125018. 2197180. 2269341. 2341502. 2413.563. 2485825. 2557986. 263'.} 147. 2702308. 2774470. 2842103. 29\)9736. 2-;;77369 + 3045002. 3112635. :H 80268. 3247901. 3315534. 3383167. 3450799. 3520542. 3590286. 3660029. 3:.;'29772. 3799515. 3869259. 39390,)2. 41)08745. 41)78488. 4148232. 42395':;'3. 4330954. 4422315. 4513676. A·~·.)5037 • 4696398. 478775':;'. 4879120. 4970481. 51)61840. 5122684. 5183528. 5244372. 5305216. 5366060. 5426904. 5487748. 5548592. 5.~09436 • 5670281} • 2052857. 2125018. 21"7'7180. 226·:t341. 2341502. 2413663. 2485825. 25579;~6 + 2630147. 2;()'2308. 27'74470. 2941294. 311)8117. 3274941. 3441764. 361)8588. 3775411. 3942235. 410':;'1)58. 4275881. 44427i)6. 4643489. 4844271. 5,)45054. 5245836. 5446619. 56474(jl. 5848184. 6048966. 6249749. 6450529. 6578851. 6707173. 6835495 • 6963817. 7092139. 7220461. 7348783. 7477105. 7605427. 7733748. 7837487. 7941226. 8044965. 8148704. 8252443. 8356182. 8459921. 8563660. 8667399. 8771138. 2()52857. 2125()!8. 219718\) • 2269341. 2341502. 2413663. 2485825. 2557986. 2630147. 2702308. 2774470. 3041}484. 3:"306499. 3572513. 3838527. 4104541. 4370556. 4636570. . ,.91)2585. 51685':;'9. 5434613. 5766434. 6098255. 6430076. 6761897. 71)937 t 8. 7425539. 7757360. 81)89181. 8421 \)!) 2 • 8752825. 89L8108. 91}83391. 9248674. 9413957. 9579240. 9744523. 9909806. 11}075\)89. 10240372. 1 ',)405655. 10552289. F'698923. 10845557. 10992191. 11138825. 11285459. 11432093. 11578727. 11725361. 11871995. ANNUAL PEA~ DEriAND-~W LOW MEDIUM HIGH 703. 728. -.,.-/ .",1"::" .. ./ ! ,'/ • S02. 827. S",!i. 876. 9\} 1. ~'25. 95') • 973. 9"7' .:: .• 1 ~)2J"j + J.043. U).~6 • 11)8'~ • 1112. 1135. 1159. liS::. l206. 1231) • 1253. 1277. 1301. 1325. 1349. 131"3. 1397. l421. 1452. 1483. 1514. 1546. 1577. 161)8. 1640. 1671. 1702. 1734. 1754. 1775. 1796. 1817. 1838. l859. 1879. 19(.!} • 1921. 1942. 703. " ./ 1/ • ,827. 851. 876. 9'.)1. '7·5 i) , 1\)\)7 .. 1179. t236. 12':;-3. 1351) • 140.:·7. 1464. 1521. 15Y(J ... .1.:;59. 1728. t "-::97 ... ! 8.~5. 1934. 2003. 2141) . 2209. 2253. 7. 2341. 2385. 2429. ~473+ 2517. 2561. 26i)5. 264·" • 2684. 27 2tj. 2755. 2791. 2820. 281;)2 + 2897. 293:3. 2<1'·.sS. 3004. 777+ 8-,)2. 851, 87,~ , ~I.-.l i ,. ·:i'5') , 1·}41 , 1132. 1::23., L-5t5. 14ij"; .• 1 :+ <1' -;: ., 1679 • 177( •. U361. L ·~75. 2543. 2770. 2i'384 .. 2';'98. 3'.)54. 311 l • :'5i67. 3224. 3281. 3394. 34~5\) • 351)7. 3564. 3·.s 14. 3664. T~ 14. 3764. 3815. 3;~65 • 3·:;-L 5. 3965. 401.6. 41)66. SELDOVIA SITE 4 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Windy River Section lOt Township 9S, Range l3W, Seward ~'eridian Community Served: Seldovia, Homer Electric Association Distance: 9.0 mi Direction (community to site): Southeast Map: USGS, Seldovia (8-4), Alaska 2. HYDROLOGY Ora i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tagel Pha se: Terrain:l1 Flat (1.0) Tota 1 Length: 9. ENERGY 6.4 39.3 60 sq mi cfs in Sheetpile 10 ft 810 fmsl Stairstep Fish Ladder 5 ft 46 ft 805 fmsl Steel Penstock 51 in 2400 ft 2 Pelton 595 191 764 59.0 5.9 0.5 14.4 2.5 2.5 fmsl ft kW cfs cfs mi kV 11 phase mi mi Plant Factor: 52 percent Average Annual Energy Producti on: 3400 MWh Method of Energy Computation: Flow Duration Curve 10. ENVIRONMENTAL CONSTRAINTS: Significance for salmon spawning unknown, but local interest in this aspect is strong. 11 Terrain Cost Factors Shown in Parentheses. DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTH CENTRAL ALASKA SELDOVIA SITE 04 CONCEPTUAL LAYOUT WINDY RIVER DEPARTMENT OF TH E ARMY ALASKA 01 ICT CORPS OF IN EERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Seldovia Site: 4 Stream: Windy River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbi nes and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operati ons and Mai ntenance Cost at 1. 2 percent TOT AL ANtWAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 55,000 $ 405,000 $ 471,000 $ 303,000 $ 30,000 $ 21,000 $ 167,000 $ 8,000 $ 63,000 $ 1,523,000 $ 152,000 $ 1,675,000 2.0 $ 3,351,000 $ 838,000 $ 4,188,000 $ 628,000 $ 4,816,000 $ 458,000 $ 5,274,000 $ 6,900 $ 412,600 $ 70,000 $ 482,600 $ 0.14 2.78 F':EU I IJNP,L r t"~')ENT(lF:Y ~< RECOr~NA I '::,ANLE ':n'IJ[lY --::;;;r'1A U .. HYDROpm·JER F'RCkIF r: T ::: I 34 l~': ;:::'::, i ':"0 i "~I';! 1. .1:'94 1. 9')~~ ,.'{H)(, :~ ,)() 1 . :")02 :)tKl4 . (}()~:; '?()()I~:I -~?(~() 7 ;:00::;, ',;:~ ()() t~i ?()10 :::i) 11 :~:i) .1:>' 2013 201,4 201 :'i 2016 :2017 ::::01 :?, 2019 2020 20::;:1 .2024 :~~():~:5 ALA:=;~'A DI::::TRICT --1.::ORl-::':::: (IF ENG I NEFF<:::: DET (.i I LED F'EI:(INNA I :~::':=;Al\lCE l NVF::::;T r GAT I Or~::, (O::;T OF HYDF .... 'IF'C!\.-IER -BJ-:j\.jE~·.rr CI.Y;::T r:':ATII) ::ELDOVIA :::ITE NO. -4 1<.WH/y'EAR :::4::::0000. 34f:(h)OO. :34:::;: ()()(H) • :=:4:::0000. :::4:;::(l(H)') • :-;:4:::0000. ,'::4:::::0000. 34::::000r) • ~:4::::(lOOO • :;:4:::i)(iO(l. ::::4:::::0000 • 34HOO')O. 3I.t::;::()()OO. ·::;:4::::(h)00. ::::4·80000. 34:::::n(lOO. 34:;:;:0000. :34:::0nno. . :;:4::::0000, 34f::()Of)U. :;:4:::0000. ::4:::::0000. 34:::::0000. 34:::00(1,) • 34::::(1000. :34::::()()()(, • :;::4::;:0000. 34::::0000. 3480000. :;:4:::(1000. :~A::':OOOO • :34800(l(J • :34::::0000. 34:30000. :34:::::0000. 34:::0000. 34::::0000,. 34::::0(100. 34:::0000. 34:::0000. 34::::0000. :::4:::=0000. ::::4::::0000. CAPITAL 41 ~:;275« -'l·1 ~:;2~J5 .. 4·1 ~;~;~~l~;. ~t 1 ~i27~5 .. 41 ':.2?~5. 415275. 415275. 4l5275. 415.2 7~5. 4.15:2:7 5 u 41 :=;::;;: 75. 415:275. 41"':.275. 415:27'3. 41 ~~i:::75 .. 41527'5 • 4152T;':;, 41 ~5):75. 415Z7~i .. 415275. 415275. 415275, 41 r:::'27!:i. 41 ~i?'l~i. 41 !:i275. 41.5:275. 415275. 415275. 41 !:,j:~::/~i. 41S;'::T5. 4152'75 .. o ~< M 70000. ,/'0000. 70000. 70000. 7 o (H) r) • 70000. 70000. 70000. JO()!:)(l. 4i::~i:~~7~~ • 4 :=!~~ ~~~ 7 ~I • 4:::~5~~~ri7!5 • 4·:=:~j~?7~t • 4:~:~~i2~75 • 4~~~~~;~':7~i II 4:::!5:;~~ 7 15. 4 ':..00:::'·-·",)',,, '_I.,.).;t.' i ,.~I .. 4~3~52 'l!5. 4:::5275. 4:::5275. 4:::~,:?7~; • 4 :::!!:i ~~~ 7~; u 4:=:~i2"'7~f • 4:::527~5. 4:::~!:i:::7~; ~ 4::~52'7~t • 4:::~5~~7~i .. 4:::~5:?'7~~ If 4:::~i:~~'75 to 4:=:::i:2'7~i .. 4:3!:i2':?~i " <f' / I<.(..IH ~*; / t':WH NOr~I11 ';:;( Lt I ~~:I~ ('. l ::~:':) O. 10,t ().13'~1 O.!)':!'!' (I. 1 :"::(,i (>. (l''::'(l (>. J~~:9 O. u::!::·: (). :I. ';::':' o. OT7 0, 1 :~:;:':! O. 072 (I. 1. :::,:,:, O. 06 o. 1::: .~! (I • O(: .. ~: (I. 1 ::::';:! (>. n,:,;:=: (>. 'j .:::', 0.0:,4 O. j ,:::.;-, O. if:i(l (I. 1 :;:'-' (I, ('4(- (I .. .I 3': () " 04':;' 0, 1.:·::~1 (I .. 04' .. ' () n 1 :::::'~> i) .. (J::·::·:~t O. 1 ';::':/ O. 0::::::;':' (). 1'3 1 ) ()" C)··~:t.~ (;. t :3 1 -) () II (~:~:~ ::-~ (). j ::=:':) i), 0::::'.::- (J, 1 ::::':' O. ()24 O. 1 3" n. O~::";:· (>. 1 ::::'~) (>. 021 O. 1 ':::';' o. () 1 '~I O. 1:::';" (:-• 01 :::: 0.13';! 0.017 (I. 1 :::::9 O. 01':, I). 1 :::9 O. 01 4 0.1:'::9 0.01:::: 0.1:39 0.012 (I. 1 :?o'::i (I. 01 t O. :t ::::';1 I) • () 11 O. 1 ::::O::j O. n 1. () O. 1 ::::9 (>. 0(1':' O. 139 n n O()'~i (I. 1 '::9 O. (1):::: 0.13'" 0.007 0.1:3':/ 0.007 O. t ::::: ':' (I • (i() (:' 0.139 fl.006 O. 1::9 o. (l05 O. 1:'~:9 0.005 O. t ::::':;1 0 .. UO~::; :::029 34:30000. 415:27::; • 41 !'.::iX75. 415275. 4152-/5. 41':i275. 415275. 415275 • 415275. 41~·275. 4152?!::;, 41 :i2P:::;. 415275. 70000. 700no. 7000U" /r)OOO .. lonon, 7noo·). 70000, 70000. 70000. 70000 • 7000')" 7000'). 10000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 7(lOOO" /(lOOO. 70000. 700(1). 70000. 700()(). 70(l(h). 70000. 70000. 700(10. 70000. 70000. 7(1)00 70000. 70000. 4f:5'2:7~; .. 4:::5;::)f~; • (>. 1~:':1 (>. ()04 O. t :;:9 0 .. 004 O. 1~-:9 (I. 004 O. 1 :'~:9 o. i)OL!-,:( l, ':U :::4:::::0000. AVERAGE COST 415275. O. 1 ::::9 O. 0::::0 RENEFIT-Cu~r RATIO (5% FUEL COST ESCALATION): 2.78 Seldovia, Alaska Damsite at Windy River Aerial View of Seldovia 10.0 TAZLINA 10.1 CO~1MUNITY DESCRIPTION Taz1ina is a small native village of 27 people located on the Glenn Highway 30 miles west of Glennallen. Ten residences and a lodge comprise the village. Copper Valley Electric Association is the utility that sells electricity to the residents. Households pay on the average about S60 per month for approx imately 275 kWh. The lodge is a 1 arge power consumer and uses on the average 4000 kWh per month. All of the households have the usual range of small appliances and freezers. Wood or propane is used for cooking. The primary fuel for space heating ;s wood although a few homes heat with oil. The lodge is the center of economic activity and some local residents work as guides. Occasional work turns up with construction crews. The population has been stable and no permanent population growth is expected. The lack of available land is the major constraint to future growth. 10.2 SITE SELECTION Two sites near Taz1ina were investigated in the field. Site 2A is considerably more remote than Site 04 and access would be a major problem. Site 04, located on Cache Creek, is well suited to a sheetpi1e dam and is the perferred site. The depth of rock at the dam site is unknown and would have to be determined in the feasibility studies. A 15 foot-high dam with a 5 foot spillway opening would provide a 10 foot-deep pool to avoid complete wintertime freezing. The penstock route, which meanders to some extent, could occupy either side of the stream. Access to the site is good since the dam site is only 7000 feet from the A1 aska Hi ghway and the powerhouse site is two mil es from the highway. The site is generally underlain by glacial till. The runoff from the small tributary just upstream of the damsite was noticeably turbid with glacial flour. Few large boulders were present in the stream bed, the average size being 4 to 12 inches in diameter. Signs of frostheave were present including slumping of the side slopes. Permafrost was suspected as some areas of the ground were still frozen during the September field reconnaissance. 10-1 LEGEND • DAM SITE • POWERHWSE o SITE NO - ----PEN STOCK - - -TRANSMtSSION LINE --WATERSHED 5 H o H H O,=> \, !-Cariboll L ~ ¢ -;_ f~rellchrnll~i L Rill SCALE IN MILES 5 REGIONAL INVENTORY a RECONNAISSANCE STUOV SMALL HYDROPOWER PROJECTS SOUTHCENTRAL AlASKA ... fII':> HYDROPOWER SITES IDENTIFIEr . I N PREll MINARY SCREEN I NG TAZLlNA DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS Htdro~ower Potential Installed S; te t~o. Capacity (kW) 4 144 Demographic Charactersists 1981 Population: 27 SUMMARY DATA SHEET DETAILED INVESTIGATIONS TAZLINA, ALASKA Cost of Installed Alterna1jve Cost Power_ (SlOOO) (mi 11 s/kWh) 2,520 362 1981 Number of Households: 8 Economic Base Tour; sm Subs; stence 11 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (m; 11 s/kWh) Ratio 440 0.82 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY & RECQNNAISANCE STUDY -SMALL HYDROPOWER PRQ·jECTS ALASKA DISTRICT -CORPS OF ENGINEERS 'd::AE L '.:;.~t") L;'::;; 1 1:18 ~: 19~j:~ I.Q2:4 t98:=.i F-tk. t~;':3 7 L '::;'8:3 t·:,; 2: ':i 199.) 1';' 9 1 L992 1993 1994 t Y';;5 1996 1997 1:?98 t i;;'~;'9 2,)t)J~) 2(11) 1 2',)~)2 :01.')4 2')05 20'.)6 21} •. )7 2008 2()09 :~010 2011 2 .. } 13 2 .. )14 2015 20 t.!i, 2') 17 2CJ1,~ 2'.)1'i 2(}20 ~.:O 21 2023 '4 2~)26 LOAD FORECAST -TAZLINA KILOWATT-HOURS PER YEAR LOW J.1::i714. 119782. 12384'? • 1.27';;17, 131984. 136052. 14(112''}, 144187, 148255. 152322. 15.£39\) , 160202, 164015. 16'7827. J.71639. 175451. 179264. 183076. 186888. 19071)1 • 194513. 198444. 2',)2375. 206307. 210238. 21416Y. 218100. 222\)31. 225963. 229894. 233825. 238975. 244125. 249274. 254424. 259574. 269874. 2751)23. 280173. 2;35323. 288753. 292182. 2'~516l2 + 29YI)41. 302471. 3\)5901. 3\)9330. 312761) • 316189. 319.::.19. iiED I Uri 115714. 119782. 123849. 127917. 131984. 136052. 140120. 144187. 148255. 152322. 156390. L66378. 176366. 186.353. 196341. 206329. 216317. 22631)5. 236292. 24,S28() • 256268. 268358. 280447. 292537. 304627. 316716. 328806. 340896. 352986. 365075. 377165. 38461.:) • 392067. 399518. 406-?69. 414420. 421871. 429322. 436773. 444224~ 451675. 457775. 463875. 469976. 476076. 482176. 488276. 494376. 500477. 5'.)6577. 512677. HIGH 115714. 119782. 123849. 127917. 131984. 136052. 140120. 144187. 148255. 152322. 156390. 172553. 188717. 21)4880. 221044. 237207. 25337fj + 269534. 285697. 3()1861. 318024. 338272. 358520. 378768. 399016. 419264. 439513. 459761. 480009. 500257. 5205t)5. 530257. 54QOO'':f • 549761. 559514. 569266. 579018. 588770. 598522. 608274. 618026. 635568. 644339. 653110. 661880. 671)651. 679422. 688193. 696964. 7t)5735. ANNUAL PEAK DfMAND-Kl LOW MEDIUM HIGH 41) • 41. 42. 44. 45. 47. 48. 49. 51. 52. 54. 55. 5,~ + 57. 59. 6t) • 61. 63. 64. 65. 67. 68. 69. 71. 72. 73. 75-, 76. 77. 79. 80. 82. 84. 85. 87. By. 91. 94. 96. 9R. 99. 100. 101. 102. 104. 105. 106. 107. 11)8. 109. 40. 41. 42. 44. 45. 47. 48. 49. I:" • .;;J J. • 52. 54. 57. 60. 64. 67. 71. 74. 78. 81. 84. 88. 92. 96. 1 .. )0. 104. 1 t)8. 113. 117. 121. 1 129. 132. 134. 137. 139. 142. 144. 147. 150. 152. 155. 157. 159. 1.S 1 • 1.~3 • 165. 167. 169. 17l. 173. 176. 4(' • 4l. 4:. 44. 4:5. 47. 4;:;;. 49. 5L. C" .-# ...J .,,; + 54. 5'i. 65. 7\], 76. 81. 87. 9'~' • 9;3 • 103. It)9. 1 L,~ • 123. 13;') • 137. 144. 151. 157. 1.~4 • 171. 178. 182. 185. 188. 19'2. 195. 198. 202. 2t)?) • 2·)8. 212. 215. 2i8. 221. 224. 227. 231) • 233. 236. 23';. 242. TAZLINA SITE 4 SIGN InCANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Cache Creek Section 29, Township 3N, Range aw, Copper River Meridian Community Served: Tazlina, Copper Valley Electric Association Distance: 9.5 mi Direction (community to site): Southeast Map: USGS, Gulkana (A-6), Alaska 2. HYDROLOGY Ora i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow: Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/Phase: Terrain:l/ Flat (1.0) Total Length: 9. ENERGY 21. 3 7.7 9 sq mi cfs in Sheetpi 1 e 10 ft 2215 fmsl Stairstep Fish Ladder 5 ft 28 ft 2210 fmsl Steel Penstock 18 in 4100 ft 1 Pelton 2000 fmsl 183 ft 144 kW 11.6 cfs 2.3 cfs 0.8 14.4 2.0 2.0 mi kV/l phase mi mi Pl ant Factor: 48 percent Average Annual Energy Production: 605 MWh Method of Energy Computation: Flow Duration Curve 10. ENVIRONMENTAL CONSTRAINTS: Most local creeks provide spawning habitat for salmon which migrate up to the Tazlina River. Y Terrai n Cost Factors Shown in Parentheses. ................. ,,"'''. . ~ . '. ~G?11 .......... . ......... -~ . . Q: .................. ; *. .. ... .. . 1~ 2000FT DAM PENSTOCK POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSNn STUDY SMAll HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA TAZLINA SITE 0 .. CONCEPTUAL LA YOUT CACHE CREEK DEPARTMENT OF THE ARMY ALASKA DISTRICT HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Tazl i na Si te: 4 Stream: Cache Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Mi sc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST ~ 45,000 ~ 185,000 ~ 101,000 ~ 165,000 ~ 30 ,000 ~ 6,000 ~ 99,000 ~ 12,000 ~ SO,OOO ~ 693,000 ~ 69,000 ~ 762,000 . 2.1 ~ 1,601,000 S 400 2 000 S 2,001,000 S 300,000 S 2,301,000 S 219 2 000 S 2,520,000 S 17,500 S 197,100 S 70,000 S 267,100 J 0.44 0.82 REU [C!t'HiL. I N'..j E f\n OF:;:Y ~< F'ECljNNA I :::ANCE :;::TUDY -::;::MALL. HYD~:OF'C)WER r 'h.I..I,J FC T :~; ALA S KA DISTRICT -CORPS OF ENGINEERS DETAI~E D RE CONNAISSANCE INVESTIGATION S CO::::T (IF H Y ORUPC:WEF: .-BENEF I T co:::n RAT I 1'1 TAZL I N(~ ::::1 TE NO. 4 YE("R 1 '~)::::4 1 '::J:~:S 1 9:::;:6 1 q';'(l .1991 1 ')';.:'::: 1. 9(:/4 J 9 '::):5 1 ,:)')'7 :1":.1':):::: :[ .;;,0:)9 :2000 2001 20C'2 ;~()~).::: 2 004 '~::()05 200t. ~:007 ~~OO::;: :::009 :2 01 ('; 2011 2012 201:3 ~~014 20 1~:; ·201·~. 2017 '201:::: :::019 :?020 2021 ::~():~~:2 '2~()~':::: 2024 :2():L~5 20:::::6 2027 ~:J,.jH/YEAR (.O~:;OOO • 6(l~:;OOO • 60~iOUO. 605(1uO. 60~~i()OO • 605000. 60~5000. (,05000. 605000. 6()5000. 60~~,OO(i • 6(Y5000. 60~i()()f) . .':.05000. 6tY5000. 6 05000. 60:,(100. i:..O ~5000. 605000. 60!:iOOO. 605000. 605000. (:.05000. 605000. 605000. 60!:i(JOO. 60~iOOO. 605(')00. 60~SOOO. 605000. 1:.05000. 1:·05000. 60~iOOO. 605000. 605000. 605000. 60:iOOO. 60~i(l00. (-.05000. (:.050(11) • 605000. (,05000. 605()()O. 6050('0. 605000. 2029 605('00. ;::0::::0 605000. AVERAGE COST CAPITAL 19:::42:i . 19::;:425. 1 ·~/:=:425. l'~J:=:42~; • l'~/:342~i .. 1·::1!::425. 1'~J:::42~i • 1'~1:=:4 :~:5 • 1·;:1!=:425. 19:::;:425. 11~J:::425 • 1'~):::42~5 .. 1 ':;/:3425. l';i::::·425 .. 1'~/:::425 .. 1 '~/::34:2'~;. 1 ':;:=:425. 19:::425. 1 f~i:::4 '25 .. 1'~:3425 • 1'~!3425. 1 '~JE:425. 19:=.:425. 19:::425. l'~J!::425 • 1 t~:3425. 1'?84 :?5. 19:3425. 1 '~/:::425. 1';/::::4:2'5 .. 1 r~:=:425. o ~~ 1'1 70000. 70000. 70000. 7 0000. 70000. 70000. 70000. 70000. 70000, 70(J(10. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 70000. 700(Ji) . 70000. 70000. 70000. TOTAUf; 2t.:34 :25. 2(:.::::425. L~t:,:::42~i • 2(:.:::425 I. 2e.:=:425 .. 21:..:::4 :25. ~~1:.,:::4:25 • :2(:,:::4 :25 It 2~'):::4 :2~5 • 2,~,:::4L:5 .. 2/:;,:::4~::~; .. $/f:::t.·lH NCiN l l ( .. ::C,: 0.444 0.444 0.444 0.444 (>.4 Lllj. O. <1.44 0.444 0.444 0 .,4'1 q. 0.444 O . ·'+·4.'t O. il-fl .. :I· (). I.~LJA 0.444 (;.44 /:j. 0.444 (I. il44 0.44 ,:,;, 0.444· 0.4 44 0.444. O .4·j<1 U. 4 .c.'j.4 O. ,4'H 0.444 $/K!,JH Dr :::.C ('" .~!::: 1 0.307 0.265 O. 24·(:. 0.21 3 (I .. 19:::: O. l :~:4 O. 171 O. l.~:i·~' (>. 14'7 I:'. 1 J 7 0.127 (l •. 1 1 ::.:: O. 110 (J. 102 O. (J')~.; 0.0:::::::: 0.0:3.2 0 .07 1.:. 0.0'71 . O . (V :.!::. C. O~-.·j 1),05'/ 268425. 0.444 O.05 ~ 268425. 0.44~· 0.04~ 268425. 0.444 0.045 268425. 0.444 0.042 21:.,:34:2~i It 2(:.8425. ;~l:,:342~; • 2t.:::42!:; . 26:34::;~; • 2t·E:4~~!:i • 26:3425. 21:..::::4 '~:~i • :;~t,:::4 '25. :2 I~:I :::: 4 ::? 5 • 2/~r:::4 ~::':j .. 0.44A 0.444 0.444 0.444 0.444 0.444 0.444 0.444 0.444 0.444 0.444 0.444 O. VIA 0.444- 0.444 0.444 0.0:39 0.0::::6 O. 0:::4 0.0:31 0.029 0.027 O. O :2~i (). ()2 :~: 0.0:22 0 .. 020 U.019 0 .0l.7 0 ,.016 0 .015 O.Ol/:j. O.Ot:::: 2684?5. 0.444 0.012 268425. 0.444 0.011 0.444 0.096 8 ~N~~TT-~nST RATTO (5% FUEL COST ESCALATION): 0.8 2 Tazlina Lod~e, Alaska Cache Creek Oamsite Aerial View of Tazlina Lodge 11.0 TETLIN -LAST TETLIN VILLAGE 11.1 COMMUNITY DESCRIPTION Tetlin is a native village located 20 miles southeast of Tok and is accessible only by air or foot. The village population is 107 distributed among 28 households. Tetlin;s the permanent settlement while Last Tetlin Village is used for a fishing and hunting camp on a temporary basis. A 35 kW diesel generator maintained by the BIA provides electricity to the school, community hall, and community laundry. Electricity is not available to any of the residences but plans are underway to transport 1 -35 kW and 1 -50 kW diesel generator once a haul road from the Alaska Highway freezes in the fall of 1981. While the housing stock is 01 d, the houses are al ready wi red for electricity. An appl ication for new HUD houses has been submitted to the state and is pending approval. Planned end uses of electricity include lights, refrigerators, televisions, and small household appliances. Use of electricity needs to be limited to certain types of appliances so as not to exceed the load. Once the generators are in operation, Tetlin would be paying in the range of $1.35 -$1.50/gallon of diesel fuel. The current method of heating homes is by wood, and propane is used for cooking. Tetlin has a subsistence economy based on trapping and fishing, and has a high rate of unemployment. Residents often find employment during the summer outside the village. Construction of a clinic and expansion of the community hall are planned for the near future. The effect on local employment would be temporary; no long-term effect on community growth is expected. 11.2 SITE SELECTION The comparatively large area surrounding Tetlin is not served by any roads or electric systems, thus preventi ng any ready interconnection with the AP and T utility system. The nearest road is approximately 10 miles distant while the distance to the nearest point on the AP and T transmission system is about 20 miles. Several potential hYdroelectric site were evaluated and in some cases explored in further detail in the field. The area close to Tetlin and Last Tetlin Village has an abundance of surface water in the form of numerous small ponds and lakes, but unfortunately has only negligible relief and hence shows no hYdro potential. Site 012 near the southwest corner of Lake Tetlin was overflown but found to be dry. Site 08, six miles further northwest, appeared to be more promising, but not to the same degree as site 014. 11-1 The most attractive site proved to be Site 014 on Mice Creek. some three miles upstream of its junction with Bear Creek. but more than twenty miles from Tetlin Village. The site is located on a meandering creek in a broad-bottomed. wide, densely wooded valley. Optimization of dam siting would, therefore. have to await feasibility-level studies. The penstock would follow a low pressure route along the right bank, dropping more steeply to the powerhouse over the last half a mile. Both the damsite and penstock route would be located in massive greenstones, in places surface-covered by alluvium. The almost twenty mile long transmission line \iould follow level ground, but the last eight miles to Tetlin Village would traverse numerous ponds and lakes on marshy ground. 11-2 NOTE: TOPOGRAPHY FROM U. S. G. S. -TANACROSS ALASKA, 1:250,000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO. - - - . -PENSTOCK ---TRANSMISSION LINE ---WATERSHED 5 0 5 SCALE IN MILES STUDY HYDROPOWER SITES IDENTIFIED IN PREU MINARY SCREEN I NG TETLI N ,LAST TETLIN VILLAGE DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET DETAILED INVESTIGATIONS TETLIN-LAST TETLIN VILLAGE, ALASKA H~dro~ower Potent; a 1 Cost of Installed Installed Al terna1fjve Cost of Capac; ty Cost Power_ Hydropower Si te No. (kW) ($1000 ) (mi 11 s/kWh) (mills/kWh) 14 117 7,267 515 1,940 Demographic Characteristics 1981 Population: 107 1981 Number of Households: 24 Economic Base 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Benefit/Cost Ratio 0.27 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY i RECONNAISANCE STUDY -SHALL HYDROPOWER PRO.jEerS ALAS~A DISTRICT -cnRPS OF ENGINEERS (EAF-: 1980 F.i81 1982 1983 1984 1986 19:37 l':;'8,3 1'=,)8.:;1 1':;'9(1 1<'(91 li?92 L993 19'?4 1995 199~. 1997 l'?:;i :3 199';' 2000 2()01 2,)()2 2{j·)3 2()')4 2'.)05 2t)06 2007 2(,(\8 2l)09 2\} l,} 2(} 1. 1 2(; 1':::: 2.)13 2')14 2015 2,) 16 2\)1/ 2018 2019 '::020 2021 2~)22 2()23 2l)24 2025 . 2,)26 2\j27 2·)28 2029 LOAD FORECAST -T~TLIN ~ILOWATT-HOURS PER YEAR LOW MEDIUM HIGH '.) . 49671. '7'9342. 149013. 1986;34. 248356. 2·i8027. 3471~98. 447,)4":1. 496711. 517485. 559',)32. 579806. 600579. 62135:3. 683674. 704448. /'224:27. 74(;4l):5 • 758384. 776363. 79434L. 81.232'.) • 830298. 848277. 866256. 884234. 894644. 9("5055. 915465. 9'2587~~ • 93628.~ • 946.:) 'i ,:; • 957106. 967517. 977927. 988337. 1000945. L013553. 1,)26162. 1038770. 1')51378. 1063986. 1076595. L 0892(1.3. 1 U)18.l1. 11144 L .=-• ,) . 49.:;71. 99342. 149l)13. 19868-'+. 248356. 298027. 347698. 397369. 44704.), 4'i67.l1. 54504.:) • 593382. 641717. 690,)53. 738388. 7:3.:)723. ~335l)54~ ~ 8833'1'-'+ • 931729. 981)065. L0344'55. 1,;8:3845. 1143234. 1197624. 1252014. 13064,)4. 13.!)0793. 14L5183. 1469573. 1523963. 1544644. l565324. 1586vt')5. 1·S06685. 1.~27365. 1.!l48046. 1 ,!l.:;87 27. 16i394,)7. 171()1)88. 173076.3. 1755295. 17"79823. 180435\) • 1828877. 1853404. 1877932 • 19,)2459, 1926986. 1951513. l'?7,S041. O. 49671. 99342. 149013. 198.:)84. 248356. 347698. 397369. 4-,+7\)4,', • 496711. 572608. 6-'+8505. 724402. 8003,)·.) • 87";197. 952094. 1()27991. 111}3888. 1179785. 1255.::'82. 134.:)483. 1437284. 1528085. 161888.!). 1709687. 1800488. 1891289. 198209,) • 2\)72891. 2163692. 2194643. 22255';'4. 2256544. 2287495. 2318446. 2349397. 238\)347. 2411298. 2442249. 2473199. 2509645. 2546092. 2582538. 2618';i84. 2655430. 2691877. 2728323. 27647.£9. 2801215. 2837662. ANNUAL PEAK DEMAND-~~ LOW MEDIUM HIGH I) • 17. 34. 51. 68. 85. 102. 119. 136. 153. 170. 177. 184. 191. 1 'i9 • 20";. 213. 227. 234. 241. 24i. 254. 26t) • 266. 278. 284. 291. 297. 303. 3\)6. 3 U). 314. 317. 321. 324. 328. 33 t • 335. 338. 343. 347. 351. 356. 360. 364. 369. 373. 377. 3;32. '} . 17. 34. 5l. 6;3. 8'5. 1 I) 2. 119. 136. 153. 17,} • 187. 220. 23.!) .. 253. 269. 281~ • 303. 319. 336. 354. 373. 3;~ 2. 41 I) • 429. 447. 4·'::'6. 4;35. 5')3. 529. 53.~ • 5-'+3. 55\} • 557. 564. 57·~ .. 58,~ • 593. 6\) i • 610. 618. 626. 635. 643. 660. 668. 677. 17. ~ .~ f,_' f .. ' • 1 1):2. 1 l'~. 136. 1 ~! •• ... ~...;...,.; ... "~ 404, 4:)'~' • 4"; 1 • 4;'2 •. 58.!) • 617, 6-'+8. 679. 7tO. 741. 773~ 7:33. 79" • 8,)5. 815. 82,"; . 836. 847. 859. 872. 884. 8'~7 + 9·)9. 934. 947. 9~~. 972. TETLIN/LAST TETLIN VILLAGE SITE 14 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Mice Creek Secti on 30, Township 14N, Range 14E, Copper Ri ver ~1eri di an Community Served: Tetlin, Last Tetlin Village Distance: 15.2 mi (from Tetlin) Direction (community to site): Southwest Map: USGS, Nabesna (0-4), Alaska 2. HYDROLOGY Dra i nage Are a: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SP ILLWAY Type: Open; ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Max imum F1 ow: Minimum Flow (single unit): 7. ACCESS Length: 8. TRANS~lISSION LINE ~~~;:l~~r~a~i~t (1.0) Swamp (1. 5) Total Length: 9. ENERGY 27.6 11.8 10 sq mi cfs in Large Concrete Gravity 15 ft 2275 fmsl 540 cu yd Concrete Ogee 5 ft 37 ft 2270 fmsl Steel Penstock 18 in 11350 ft 1 Pel ton 2000 fmsl 239 ft 117 kW 7.2 cfs 1. 4 cfs 2.1 14.4 14.6 4.2 18.8 mi kV/1 phase mi mi mi Plant Factor: 36 percent Average Annual Energy Production: 369 MWh Method of Energy Computation: Plant Factor Program 10. ENVIRONMENTAL CONSTRAINTS: Generally no significant salmon runs ; n the Tetl i n River or its tri butari es. 11 Terrai n Cost Factors Shown in Parentheses. / t I -------,- \ \ ') j \ \ \ .. , I , \ , I \ I l-----~ , \ \ \ , , \ 2000----· -'-, • • • • • • • · .. -' . -. .' ~3 ,', .:. ") -: • -~r/ , ...-· '.' · ,.;...) • <,;: ~ -, • : ',_-J iI ,.----...-.' .' • / \ '--\:' ,-\, \', ....., \ , :,-". \ 8.CALE 1" 2000 \ \ ,k \'--','': ", \ \ I", : I', ------,-~-- DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA TETLIN SITE 14 CONCEPTUAL LAYOUT MICE CREEK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS ---~-- NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY PLANT FACTOR PROGRAM COMMUNITY: TETLIN/LAST TETLIN VILLAGE 51 TE NUMBER: 14 NET HEAU (FT): 239. DESIGN CAPACITY (KW): 117. MINIMUM OPERATING FLOW (1 UNIT) (C FS) : 1.40 LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00 HOUR FACTORS: 16.00 15.00 13.00 3.00 MUNTH (,DAYS/MU.) AVERAGE PUTENTIAL PERCENT ENERGY USABLE MONTHLY HYDfWELECTRI C OF AVERAGE DEF-'IAND HYDRU FLOW ENERGY ANNUAL ENERGY ENERGY (CFS) GENERAT ION (KWH) (KWH) JANUARY 1.85 22342. 1U.OU 64213. 14895. FEBRUARY 1.58 17235. 9.50 61002. 11490. MARCH 1.53 18477 • 9.00 57791. 12318. APRIL 2.66 31088. 9.00 5779l. 20b34. MAY 24.30 87048. 8.00 51370. 49409. JUNE 37.50 84240. 5.50 35317. 35317. JULY 25.00 87048. 5.50 35317 • 35317. AUGUST 21.90 87048. 6.00 38528. 38528. SEPHNBER 12.90 84240. 8.00 51370. 49058. OCTUBER 6.10 73668. 9.00 57791. 44719. NUVEtvtBER 2.99 34944. 10.00 64213. 23178. DECEMBER 2.38 28742. 10.50 67423. 19162. TOTAL 656120. 642127. 354023. PLANT FACTUR(1997): 0.35 PLANT FACTOR(LIFE CYCLE): 0.36 HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Tetlin/Last Tetlin Village Site: 14 Stream: Mice Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equ'ipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. kcess 6. Tra nsmi ss i on TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 20 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Du ri ng Construct; on at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent {AlP = 0.07823} Operations and Maintenance Cost at 1.5 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 163,000 $ 511,000 $ 84,000 $ 155,000 $ 30,000 $ 6,000 $ 99,000 $ 32,000 $ 523,000 $ 1,603,000 S 321,000 $ 1,924,000 2.4 $ 4,617,000 $ 1.154.000 $ 5,771,000 $ 866,000 $ 6,636,000 $ 630,000 $ 7,267,000 $ 62,110 $ 568,500 $ 109,000 $ 677,500 S 1.94 0.27 ;il'.ifUh~~\L 1I',I\!EJ"rOI~:Y 8, H[CDI'-.jNf::'.!,:·;rH'JCF;~ ,. 'II.'I,!f '" ·~;t·l(d"L H'{(II"!IPIJ~JFh' F"':~:!L+I. r';. ~1LH::;f<A D I :~; 1 RIC r CUhP:~; (IF [hll:: J "IEEP::. DFHUL.E:TI PFCI)NNA 1::':;:::{.lI'lCI": HNE::; rIl;ir.:,-r ((11\1'::. C:O:::::1 (IF H'r'lJl~UF'IIWf:::R ." BFNFF I T C fi::; T ~:~{:\ f [1..1 TETLIN/LJt:::l IT::!'I, IN "III.,I.AI~: 1 ,):=:::: L ';i :~:;',,~! 1. ')9() I .... :'! 1 1. (;''';:::::~: :L ':"ii':) 2()·)() >'01 . :~:CH) :~~ ,~:007 ,2(!')::: 0:'010 ?fi.i 1 '?() 12 ~.~O 1 ::::: 201.4 2(11 ~5 . ~.' (i 1 f.~, 2(iJ 7 2018 :,;:0 1 ':' :2 i J)O ~::021 ';:::ITE NO, 1,4 ~;:\.JH/ YEAR 1734:=::6. :.2 ::,;-1 ::;:: ::.::] • :,:;ij.42(':'S. ::::07.1:.40. 31 ~,671 . :::4 149:::;: • :347!Sl. '~:60(!::::: 1 • ::::649-::)3. :::;:::1:::16. 3:::46:::9. :3:::7::::51:., • 401112. 40::::435. 404~:~i:,:::: • 405(:81 . 40/:,::;:: 18. 41>7571. 40:::317. 4090.~~.:::: • 4()t~5::::~; • 409';/7/:. • 41041::::. 410:::::59. 411300. 4.11741- 4 1 ':;;: 1 :=,:::: • CAF'ITf'4L !:i72::(IL~ " "57:2:204. ~i'722()4 Ia ~57 2204. ::;7:~:;2()4 f1 ~j7:2204. ~p ::: :~:: (i 4 . ':"i72::204. 57'2:~:f)4 , ~i'7~~:~',()4 • 572:21:)i" • ~::'7:2204 • 57:2'204. 572:204. ~i7;::2(l4 • ~j72204. 5722()4. 5722()4. !:17:?:2()4. :;,72:204. :572:':::04. ~i'72;~()4 • 572204. 572204. ~~72:~~()L1· • '57:2:204. ::,72204. ~~, 7'~:204 • ~i722()4 " 572:i~(~·4 • II ;;'i M 109000. 1 (l9(lr)O" 109000. l')'~i (I (it) • 1 (J'i(jt)O • 109000. 1 (i'i/()no • 1 i)900i ). 109000. 1 i)·,:iOl'l(). j ()9(H)(). 1 09(1I)o. 1 O',)nOCl. 1 09(H)O. 1 09()(l!)" 1 i)9CH)O. 109(1)0. 1 09(Y',(J. 109000. 109('00. 1 O':;/(ii)0 • 1 f)9000. 109000. 109000. 1 (y:-, ()() 0 • l090UO. 1U9(1i)O. l rY,OOO. 10';:'000. 1 O·:"()()O. 1090(>0. 1 09(H)(). 1090(l(). 10';/0(11) • t ()':;·ooo. 1090':)0) • 1 ')':'000. 109000. 1 090()i). ,:; 7:2204 . 109000. 572204. 1 U·:;/()!)(l. 572204. 1(19(100. ~17:2·204. 1')9(100. 57:::204. 109000. 'I 1~1 r {"::'L ~~ /:.::: 1204. I:"::: 1204. 6:::: 1 '~~04. ~:.;:';: 1 :204. 6:::::1204. 6:::: 1:»4. i'.F: 1 204. I::.:~: 1 :204. t,::: 1 '/04. 1',.:::: 1204. !;.:::: 1 :,2()4 • (t.:::: 1 ::'04" ,I:. ;~::1 '2 (I 4 • /:,f:1.204. 6 ::::: 1 ::,:: () f.l. I;:,:':: 1 :204. (.:::: 1 '204" ~:l:::: 1 :~()4 II 6:31 ';;:04. 6::::: j 204. is :::: 1~:: () iJ. • i;.::: t 204. 681204. 6:::: 1204. 6::::: 1 :?04. 6 •. :::: 1. ~:-:04. .:,:;.:;:! 1204. 681204. t,::~: 1 :2:<)4 It .';;.:=.: 1 :2/)4. ,1~.::: 12()4. 6::: 1 ~:(l4. .:':081204. ":,:::: 1204. (-.::;:: 1. :;:on 4. /:.::: 1 :?04. b:::: t ::'04. 6:::: 1 ?04. 6::::1204. 6:?12()4. f',::: 1204. .:~.81204 . 2028 412624. 572204. 109000. 681204. 2029 413007. 572~04. 109000. 681204. ,.;:0-):30 41 :~::::T7 • 572204. 1 (j'il()!)r). ,:~,::::: 1 :204. AVERAGE COST BENEFIT-COST RATIO (5% FUEL COST ESCALA1ION): $;' ::lrJH $ / Kt·Jj'1 ~' ,01; ,:: .. ,,: 14 ? .. 1,12 2 .. 0,/'1 'I • ,,!':~: 4 1 .. ;",9'.,: 1 .. :~: ';' ~;. j • ;::',,>9 1 • :::: 1. '':: J ,,':~~:4 L 71 1.759 :1..747 :l • 73':; :t.693 1 • 1.~.74 :l .. (,:71 t " ,:~,/.'" 5 I • (',62 l. {:.6'/ 1 .. 421 1 • ~i'2'~: () fl '~J(,,2 (', r ~:"I(J '4 U.4;",;: i). ,cf ',::'':'j (' ... : ,;, 1 )"1'1' ::(\i) (). L~ '::' () i). ~:"4(i (), ""?:2 (I" ~ :=:t~) (ll! :~ 7 ~~ (I. 1 (\2 0.1'.:;0 O. 1 :~.:.) (I. 1 1. 'i) O. 11 (> 1 • (.:. (:' <) I ) ~ (j ",!' (J 1 • 6~i;:::: O. ()/~.~, 1 . (. <=;(:, (j .. 06 1. t , 6':";4 i)" O~5/~. j • {:·~5:3 {). ()~;? 1 .. (:,'=; 1 ':'. 04'·i 1 • (~..49 o. ('4",,; 1..64:3 0.042 1.942 0 .. t::ir'l:::: Tetlin-La~t Tetlin VillaljP. Alaska View Downstream Toward Mice Creek ite i a 1 View 0 f T e t 1 i n 12.0 WH ITTI ER 12.1 CDr1MUNITY OESCRIPTION Whittier is located at the southern terminus of the Alaska Railroad on Prince William Sound. A few high-rise concrete buildings enclose apartments, businesses, and government offices. The Begich Tower contains 198 apartments and the majority of the 198 residents. The tower is only 30 percent occupied on a permanent basis but some people reside there on weekends. Other Whittier residents 1 ive on boats in the harbor. Chugach Electric Association (CEA) provides electricity to the community. Outages occur frequently in the winter and service is generally considered poor by the residents. Standby diesel generators are located in every major building and are used during the outages. An average monthly bill for an apartment is $18 and the corresponding electricity consumption is approximately 300 kWh. The buildi ngs are heated by oil burners. The economic base of Whittier is fishing and tourism, and many jobs are associated with the ferry service, charter boats, and shops. No planned projects were identified that would stimulate growth of Whittier. Electrical energy demand may increase if the tourist and fishing activities increase and, as a result, draw more permanent residents to the area. 12.2 SITE SELECTION Two attractive sites were identified and overflown during the field inspection. Both of these sites are glacier-fed to a greater or lesser degree. a factor that normally tends to even out the peak spring-summer stream flows and make a larger proportion available for energy product; on. Site 01 is located just north of the Portage-Whittier railroad grade, approximately four miles from Portage. The overfl ight appeared to confirm the feasibility of intercepting the two branches of this northern tributary to Portage Creek by individual intake dams at approximately 800 foot elevation, and then running a single penstock to the railroad level. Access to the dams in the steep rocKy terrain (in sedimentary rocks of the Valdez Group) would be costly. The site studied in greater detail is Site 03 on the Placer River, immediately downstream of the junction with a westerly tributary, 3/4 of a mile below Deadman Glacier and 1/8 mile south of the "Tunnel" siding of the Seward railroad. It is proposed that, because of the narrowness of the river gorge in what appeared to be conti nuous exposures of blocks of sound sedimentary rock of the Valdez Group, a low (approximately 50 feet high) arch dam to be considered for the diversion intake dam. The downstream half of the two mile-long 12-1 penstock along the left bank of the river might, however, involve considerable expense along the narrow gorge above the railroad tunnel. Transmission would probably initially follow the same route and then basically follow the railroad, which probably would substantially reduce the cost of traversing the northern seven miles of the marshY Placer River delta to the Seward Highway. The proposed damsite would be located about two miles east of the Placer River Fault. 12-2 NOTE; TOPOGRAPHY FROM U. S. G. S. -SEWARD ALASKA, I: 250,000 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO - - ---PENSTOCK - - -TRANS MtSSION LINE --WATERSHED HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING WHITTIER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Hldro~ower Potential Installed Capacity Site No. (kW) 3 3,917 Demogra~hic Characteristics 1981 Population: 198 SUMMARY DATA SHEET DETAILED INVESTIGATIONS WHITTIER, ALASKA Cost of Insta 11 ed Alternailve Cost Power_ (UOOO) (mi 11 s/kWh) 20,509 387 1981 Number of Households: 57 Ec onomi c Ba se Fi sheri es Touri sm Government 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mi 11 s/kWh) Ratio 120 3.21 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALAS~A DISTRICT -CORPS OF ENGINEERS (EAF:~ 198(! I. 9:3 I. 1:;-82 19:::::4 1985 i ':;;':3~) 1. ,:~ :3 ~," 1';'::;:03 1 ~/;3 c;. 19':;'\:' 1':;';:;' J. !. ~::;;: l,;·q:~: L 9':;'4 1:;''::;''':'; 1'79.~ 1:;';:;7 t 99 ;:~ i99':t 21·j~)J.) 2(1\:' I. :l.j(J2 21.)1.) ::5 20(j4 2'.)1:.15 2t,')(r6 2(j(17 2(il)8 2(t10 21) 11 2012 2('13 :::;")14 :2') 15 2',) 1 "7 ::.>j 18 2(' 1':;i 2t}21 ::()2,q. ,2·'):: .~ 2(j27 2029 . :,: ' .. '.~~) LOAD FORECAST -WHITTIER ~ILOWATT-HOURS PFR YEAR LOW MEDIUM HIGH ::;48571. ;37841)0. t?38t)57 + 96/'886. 997714. 1027543. 1'):'57372, J. \);?, 'l '2 I} 1 • 1l17('29. J.14.S858. 11':';4815. l 2 ~) '.:: ~:., -:": ::2 t l23(.t7:8~ L342:::=';5 + 137,)512. 1. 3';t:34.~.9 • 14.264::6" I. 484'};35. .I.512~14. 1541743. 157~)5 7 '2 .. t591~4I.)2 .. 1.628231. J.657C)61). 16858:3 9 • 11'1471:3. 1752483. L 7-:f0248. 1828 .. ) 13. L86::;7"~8 • 1'7",)3543. lC;'41308. l':;'7''1(i'73. ;2.,) 1.6838. 2 1)54,:;(j3. 2(,92368 .. 21·?2970. 2218121. 2243271. 848'5'7 L • 87:34')0. Q38ij57. ¥h7886. 9-;'7714. 11)27543. l')57372. Uj:3"72(d. ll17'}29. L J.4,~858 • 12L'581.~. 12:34775· 13"S3T53. 14';'1,:';)5''). 156()6')8. 1629:S67+ .l6·~:3525 • 17674:33. L83644:;;. 191-:;'438. 2\)(.12433. 21,S8425. 225142'} , 23344L6, 241741L. 25 1.)\) 4~)7 .. 258341)2. 26~~,~39~3 " 271':;;441. 27';;24~35 .. 2825528. 28785 7 1. 2931,~14. 2984658. 3.,377(' L • 3·)9«744. 3L9.»831. 323'?713. 32825-?4. 3325476. 33.S8357 i 3411239. 3454121). 3·497 t.j')2,\ ,3539:3i33. 35827.S5 .. 848571. 8784(11) • 9381)57. 96788,:;' • 997714. 1 ~)27543 + 1\j57372 + ll)872('1. li17029. 114,!)858. 1256818. l36.::. 778. i47.-S738. 158669::3. lSI)6.::'18. 19 1.~578. 2(j21~538 • 213·~498 • 224~·458 " 238362') • 252,)782. 2657944 • 2795106. 29322·~8 • 306943":' • 3206592t 3343754. 3480916. 3618078. 36864()O). 3754721. 3823(,43. 3i=191364. 395968,:l. ,rh) 28('ij7 • 41)9.~ 329. 416465(1. 4232-;'/2+ 4301294. 436191)6. 44225.i9. 4483132. 4543744. 46043~7> 46.~4969 + 4725582. 478.~194 • 484.':;'81)7. 4907419 • ANNUAL P~AK DFMAND-~i LOW MEDIUM HiGH 291. 31)1. 311. 321. 331. 342. -c--, ,~~...J...:.. ~ ~,'5,~2 • 383. 393. 41)2. 412. 421. 431. 441. 45'} • 4.::'(, " 4,-S9. 479. 48'; • 4':;;:3. 5i)8, 518. 52:3. 538. 548. It .~.I)I) • 613., 62,~ • 639. -!) 78. 6';'1. 71)4. 7l7. 734. 742. 7<=;.i. 7.50. 7.:;8. ---, , , I' ... " ... 7':;'4. 81)3. 29l. 3\) L • 3d. '321. 331. ";"--;.-. -' .' ...... ~ :;. ...... ~ .. '_I '_' '" 4 l·S. 44( •. 4.~4, :'3 i.l , 5:3.4" :.~8 2" f:, I.):S ' .~57 ,. 714. 743. ::..,. 1 • 818.\ . ;. "5 L , 949, 9·~8 . 1022. 1:)4\). L (15ij • It}77. 1·)95 + i.109. 11.24. 113',. -, 1154. 11 ·!)8 • 1183. 11'~8 . 1212. 1227. 2'~ 1. ,,j I.l • ! • ..: 1 , 1 ',}t)4 • 10'51, 1. \)9~~ • 1145. 11 r';2. 1.23=-. 12.S2 • 13(!9. 1333. 1379. 141)3 • L "i 2 ,~ .• 14 51) • 1473. 1494. 15i5. 1535. 1556. 10//+ i::;':;':';, 1.£H~. 1639 t. i.~.:S t) 1. .:).3 i • WHITTIER SITE 3 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Pl acer Ri ver Section 26, Township 7N, Range 2E, Seward Meridian Community Served: Whittier, Chuguch Electric Association Distance: 14.0 mi Direction (community to site): Southwest Map: USGS, Seward (C-6), Alaska 2. HYDROLOGY Drainage Area: Estimated r~ean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERS ION DAt4 Type: Height: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi n9 Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: 6. Diameter: Length: POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/Phase: Terrain:l/ Flat (1.0) Swamp (1. 5) Total Length: 9. ENERGY 20.8 145 120 sq mi cfs in Concrete Arch 50 ft 495 fmsl 400 cu yd Concrete Ogee 13 ft 38 ft 482 fmsl Steel Penstock 66 in 10200 ft 2 Ho ri zo nta 1 F ra nc i s 190 fmsl 265 ft 3917 kW 218 cfs 43.6 cfs 1.9 38 5.4 5.9 11.3 mi kV /3 phase mi mi mi Pl ant Factor: 45 percent Average Annual Energy Producti on: 15441 MWh ~1ethod of Energy Computation: Flow Duration Curve 10. Ei~VIRONMENTAL CONSTRAINTS: None i dentifi ed. 11 Terrai n Cost Factors Shown in Parentheses. " ," o tJ# • \ , " . / .' I ./ I / 19 / / ~ DAM PENSTOCK TRANSMtSSlON LINE POWERHOUSE DRAINAGE BASIN ) \) 0 " ~ I I I \ "\ ) REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDR0P9WER PROJECTS SOUTHCENTRAL ALASKA WHITTIER SITE 03 CONCEPTUAL LA YOUT PLACER RIVER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS .--'"'-- HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Whittier Site: 3 Stream: ~acer River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Swi tchy a rd 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTIOtJ COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST S 160,000 S 2,754,000 S 1,482,000 S 531,000 S 136,000 S 59,000 S 290 ,000 S 29,000 S 793,000 S 6,234,000 S 623,000 S 6,857,000 1.9 Z13,029,000 S 3,257,000 Sl6,286,OOO S 2,443,000 Sl8,729,000 S 1,779,000 $20,509,000 S 5,236 S 1,604,400 $ 246,100 S 1,850,500 $ 0.12 3.21 REGIONAL INVENTORY & RFCONNAISANCE STUDY -SMALL HYDROPOWER PROJEfTS ALASKA DISTRICT -CORPS OF ENGINEERS DFTf~ I LED RECONNf4 I :::;:::;ANCE 1 NVE::H J OAT IIJW:; COST OF HYDROPOWER BENEFIT COST RATIO ,-EfC.fi' 1984 19'3h) 19';;' 1 19','4 199'5 19')/:. 1. '~'?7 ::~:ooo ..2001 200:':': 20(r3 2004 ~:UO:; 2006 2007 200::: 2009 2010 201.t 2012 20 1-:~: :::014 2015 2016 2017 ~:() 1 ::;: 201.':;1 :;':'i)20 2021. :?024 :2:()25 ~::(':::~I::.I 2:027 WHITTlER ~:; I TE NO. I«(..)H/YEAR 1 ':i441 000" 154-41000. 1. <:i441 000. 15441000. 15441000. 15441000. 1.5441000. 154410(lO. 15441000. 1.5441000. 1 '5441 000. 1 ::A41.000, 1 !:i441 000. 1 ~'441 0(10. 1'5441000. 15441000. 15441.(100. 15441000. 15441000. 1 ':::;441 000. 15441000. 1544:1000. 15441000. 15441000. 15441000. 1'5441000. 1 ~3441 000. 15441.000. 15441000. 15441000. 15441000. 1 :;i441 (1\)0. 15441000. 15441000. 15441000. 15441000. 15441000. 15441 (H)O. 15441000. 15441000. 15441000. 1 ~544:1. 000. 1 ~5(j-4 1 000 • 1 '5441000. 15441000. CAPITAL 1614::::79. 1/;:.14:::: 7 1;1 II 1614::::7':;1 d 1614::::79. 1614::::79. 1614:::79. 1614::::79. 1614:::79. .11:.,14:379. 1614:::79. ! i:, 14:=:7'~'. 1 (-, 14:::::7':;1. 1614::::7'::-J. 1l:., 14::::79 . 1/;:.14::;:79. 1614:::: 7':-1. 16l4:::7':;I. 1614:::79. 161 (j-::::79 • 1614::::7':;) . 1.614:=:79. 1614:::7":', 1614::::7':" • 1614879. 1614:::79. 1614:37':;J • 1614879. 1614::::7':;1. 1614:::]';") • 161. 4::::79. 1614879. 161 4:::7':;1. 1614:::7';J. 1614:::79. 1614879. 1614::::79. 1614::::7';' . 161. 4:::;:79. 1614:::79. 1614::::7':;' . 1614:37':;' • 1614:=:79. 161 4:::7':;"J • 1614::::-79. 1614:::-7';-' • (I ~( M 246100. :::£1-6100. 246100. 246100. :246100. 246100. 241':,100. 2461 ()(). 246100. 246100. 241.-,100. :;;::46100. 246100. 24(;,100. ::46100. 2461 (lI). 2461 ell). 24/:.100, 246100. :;?4I:.,10(l. -246100. 24[':,100. 246100. 246100. 246100. 241:.,100. 246100. 246100. 246100. 2461.00. 246100. 24/':'100. 246100. ~::46100. 241.:,100. 246100. 241:..100. 246100. 241;.100. 24(:,100. 246100. -:?461(lO. 241.:,1 no. 246100. 241.:,100. 20:;;::',) 154410(:,0. 1614:::7'':;'. 24(:,100. LU~U 1544tOOO. 1614879. 246100. AVERAGE COST T(nAV~ 1 ::~:(~,(l979 . 1 :::6097';' • 1 :3 f:.O?7 ':;-1 • 1 :::: (:. un '::J • 1 :::(:,0979. 1:360979. 1 :::: (:' (I ')7':.'1 • 1 ::;::(:,0';'79 • 1 :::::60979. 1 :360'~i79. 1 i::60979. 1 :::60'~}79 • 1 :::6097':;' • 1 :~:/:.,()~J7'~1 • 1::::60979. 1 ::::(:;.() ') 7 ,";-, • 1 ::: /:. () "~)"7 '~') • 1 ::::60979. 1 :360979. 1 :::I:..()t~j7''iJ. 18~~,0979 • 1 E:60979. 1::::60979. 1 :=:!.:.,()1;'7''i'. 1 :360'~179. 1 :360979. 1860979. 1 ::: /.:. () t~) ~7 ';1 • 1. :::(:,0979. 1 ::::60979. 18(~,O':;J79 . 1:360979. 18/.::.0979. 18(-'097';:J. 1. r::6097"'. 1 :::~")0979 • 1860979. 1860979. 1 :?-60':;';';'. 1 t: I~t () '~) 7 '~i • 1 :=:I;,(')I~)'lt~J • NOND 1 :~;c 0.1:21 O. 121 O. 121 0.121 0.121 0.121 O.1:~:1 0.121 <). 121 O. 121 O. 121 O.]:~'l O. 121 O. 121 O. 121 (I. 121 0.1"21 0.1:-::1 O. 121 O. 121 O • .L::? 1 O. 1~~1 o. :121 O. 12] o. L:1 0.121 0" 121 0.121 O. 121 0,121 O. 121 O. 121 O. 1 :21 O. 121 n.1:21 0.121 0.121 O. 121 0.121 O. 121 0.121 O.l:?1 O. L::1 O,1:~:1 O. 121. )J I: ::,::(: (;" 0\11) 0.0:::::::: 0 .. 0]::::: 0.072 0.067 0 .. 06:2 () .. ()5::: 0.054 () .. O~;iO 0.046 0.043 0 .. 040 0.0:37 0.0:35 () II ():3::~ 0.030 ()" ()2::: 0.02(:, 0.024 0.0:,(:::: O. O~:::l ()"Ol'?:i 0.01::: 0.01? 0.015 0.014 0.01 ::;: 0.012 0.011 O. (11.1 0.010 O. OO,~, 0.00':;1 (j.OO::: O. (H)7 0.007 0.006 O.OOt, 0.006 0.005 0.005 0.004 0.0(14 0.004 0.004 1860979. 0.121 0.003 1860979. 0.121 0.003 O. 1~:-I l" i)26 HEI\IEFIT--CO~:::r RATIO (51. FUEL. CO~::;T E:::;CALATION): :-:::.21 Whittier , Alaska Placer River Damsite (downstream of confluence) Aerial View of Whittier CHICKALOON BA Y Nud 10IudI / J NOTE: TO POGRAPHY FROM U. S. G. S. -SEWARD ALASKA I I: 250,000 LEGEND .., DAM SITE • POWERHOUSE o SITE NO. ---' -PENSTOCK --TRANSMISSION LINE ---WATERSHED 5 o 5 E3 I--l E3 SCALE IN MILES REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING HOPE DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Hxdro2ower Potenti a 1 Install ed Capacity Site No. (kW) 1 626 Demographic Characteristics 1981 Population: 51 SUMMARY DATA SHEET DETAILED INVESTIGATIONS HOPE, ALASKA Cost of Installed Alternai}ve Cost Power_ ($1000) (mi 11 s/kWh) 5,053 387 1981 Number of Households: 15 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mills/kWh) Ratio 164 2.36 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVEi'HORY & F:ECONNAISANCE STtlTty -SMALL H'TtIROPOWER PROJECTS ALASKf) DISTRICT -CORPS OF Ew~tNEERS LOAD FOf\'ECAST -HOPE KILowHTT-HOURS PER YEAR ANi'WAL PEAi\ DE:MAND-r, YEAR LOW MEDIUM HIGH LOW MfItIUM HIGH 198·) 218571. 218571. 218~7 J • -.,. I..J. -c-I . .) • -.,. /. I. Lt81 i'i''i~~ ..:...:.O..:...J .... 226254i 226254. 77. 77. 77. 1982 233937. 233937. 233937. 80. 8C). 81} • 1983 :41621. 241621. 2A16;'1. 83. 81. 83. 1984 249304. 249304. 249304. 85. 85. -1;,. lj .. ! • 1985 256987. 256987. 256987. 88. 8:3. 8:3. 1986 264670. 264670. 264670. 91. 91. 'it. 1987 272353. 'i-'i-~-..:./ .... ~_.~ . 272353. 93. 91. 9-: • 1988 280037. 280037. 280037. 96. 9,~ • ¥I~. 1989 287720. 2877:70. 287720. 99. 99. ':;;9. 1990 295403. 295403. 295403. 101. It1i. 1''} 1 • 1991 302604. 313165. 323726. 104. 107. l1L 1992 309805. 3::\0927. 352049. 106. 113. 121. 1993 317006. 348689. 38,)372. 109. 11'? • 13'} • 1994 324207. 366451. 4,)869~ • 111. 125. 141) • 1995 331408. 384213. 437 .. )18. 113. 132. iSO. 1996 338609. 4(j1 97~. 465341. 116. 138. 159. 1997 345810. 419737. '19::\664. 118. 144. 169. 1998 353011. 437499. 521987. 121. 150. i -: .. ~ . / ; .. 1999 360212. 455261. 55,)310. 123. 156. 188. 2000 367413. 473023. 578633. 126. 162. 198. 2001 374839. 494401. 613963. 128. 169. 210. 2002 382264. 515778. 649292. 131. 177. 222. 2003 389690. 5::\7.15<", • 684622. 133. 184. 234 2004 397116. 558534. 719952. 136. 19 i .• 247 2005 404541. 579911 • 755281. 139. 199. -c--L·-:J,-/ t 2006 411967. 6\)1289. 790611. 141. 206. 271. 2007 419393. ~'j'i.,.-0..:...:.00/. 825940. 1.<;.«{ • 213. 283. 2 .. )08 426819. 644045. 86i270. 146. 221. 29~. 2009 434244. 665422. 89660,) • 149. 228. 3 .. -)7. 21)10 441670. 68·S800. 931929. 15.i • 235. 319. 2011 451397. 700463. 9'}9~27 • 155. 24iJ. --z:::-~':'..J. 2012 461125. 714125. 967125. 158. 245. :-;~.i • 2013 470852. 727788. 984723. 161. 249. 337. 2014 481)579. 74145j. 1002321. 165. 254. 343. 2015 490307. 755113. 1019919. 168. 259. ;\49. 2016 500034. 768776. 1037517. 171. -.'-..:.O~. -=-~'J::J • 2017 509761. 782'i38. 1055115. 175. 268. 361. 2018 519489. 796101. 1072713. 178. ;717::\ • 367. 2019 529216. 809764. 10903.i .i • 181. 277. 373. 2020 538943. 823426. 1107909. 185. 282. 379. 2021 545421. 834471. 1123521. 187. 286. 385. 2(,'22 551899. 845517. li3913'~, 189. 290. 391) • 2023 558378. 856562. 1154746. 191. 293. 39~. 2024 564856. 867607. 1170359. j9~. 297. 401. 2025 571334. 878653. jI8~971. 196. 30i. 41)6. 2026 577812. 889698. 1201583. 198. 305. A,i? • 2027 584290. 900743. 1217196. 200. 30th 417. 2028 590769. 911789. 1232808. 202. 312. 422 2029 597247. 922834. 1248420. 205. 3j6. 42f~ 2030 603725. 933879. 1264033. 207. --.~ ,~..:.I) • 433. HOPE SITE 01 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Bear Creek Section 1, Township 9N, Range 2W, Seward Meridian Community Served: Hope, Chugach Electric Association Distance: 1.0 mi Direction (community to site): Map: USGS, Seward (D-7), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Uni ts: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Voltage/Phase: Terrain:1! Flat (1.0) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 11 Terrain Cost Factors Shown in Parentheses. 4.0 5.7 25 sq mi cfs in East Low Co nc re te Gra vi ty 10 ft 1340 fmsl 140 cu yd Stairstep Fish Ladder 5 ft 16 ft 1365 fmsl Steel Penstock 16 in 12100 ft 2 Pelton 200 fmsl 1086 ft 626 kW 8.5 cfs 0.85 cfs 2.3 14.4 0.4 0.4 mi kV /3 phase mi mi 52 percent 2852 MWh Flow Duration Curve ( ............. DRAINAGE BASIN REGIONAl INVENTORY & RECOttWSSANCE STOOY SMALL HYDROPOWER PAOJECTS SOUTHCENTRAl AlASkA HOPE SITE 01 CONCEPTUAL LAYOUT BEAR CREEK DEPARTMENT OF THE ARMY AlASKA DISTRICT HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Colllfiunity: Hope Si te: 1 Stream: Bear Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Swi tchy a rd 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Du ri n9 Constructi on at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 43,000 $ 530 ,000 $ 403,000 $ 293,000 S 30 ,000 $ 19,000 S 167,000 $ 35,000 S 16,000 S 1,536,000 S 154,000 S 1,690,000 1.9 S 3,210,000 $ 803.000 S 4.013,000 $ 602,000 $ 4,615,000 S 438,000 $ 5,053,000 S 8,070 $ 395,300 J 70,000 S 465,300 $ 0.16 2.36 f,;L(,! (IN?.! IN\/ENTOfU ~, HFCO~H\I{-iI':;ANCE ~:;Ttl[lY -:-:,Mr~LL HYUFiOPOWE:f~; F'FCI . .ii::' ! ; ALJ~':~;f::A U l':·TR I I,:r .. · COFF':::; Uf D\/U 1 NI:EF::: [1FT t'l [L.ED r:(f::ONNr-:~ 1 ~:<'~;m+ E J r,r/[:, r] I.ii~ T T (lr::~; COST UF HYDROPOWER -B~NEFrr C,I ;1' RAllO HOPE :;:: I TE NfJ. 1 YE(~P 1 .::! :::: Lf 1'):::"; 19:::6 l';::':~:';::' 1 ')9(l 1 ':,;, ':J J 1 ':.:,.::.::: 19':'4 '?()()-;? ::?i)():~: ,20U4 ~:~()():; 2006 :2()(J::::~ ~~~009 2010 2011 2012 :2() 1 :~: :2014 2015 :2016 :::017 201:::: 201';:-' 2020 2021 :2():2~~~ :2:():2::~: 2024 2025 :?027 ~2()2:::: I<.I,)H / Y E{'~I::;' 2::~:':;:?OOO " ::::::::;~~:(l\)U • :2 ::~ ~5 ~,~ () () () '" :?:~::~::;,,;::(}()f) " 2:~:'5201.)(\ • :2:::~' '?(l () () " 2::::'5:::000. ,~::3~:;:='OOO • '2~=: ':i ~~~ ()()(j .. '.,;.;:::::5:2(~)()(~ If ~::::::~i:2()()() If 2 :::: ~::; :,:~ 0 0 (> • ?:::~:;)O(l() • :~!:::5:~::()(){) ., ;:::.::~~;~~()()() . ~~~ :::::::; ::::: () { ) () 01 ~~:::~:;'2(1()() II ·:~;:3~5.~~()()() " 2 :::: ':i :?()(H) • '2 ::: ~:i ;~: C't () () " ~~: ~:~: ~5:? () ().:.) Il 2f~~i:~()()() II ~:::=:52()OO • :;2::::~;:~()()() If ~~:::5:~::i)()f.) II :2::35:?()()() .. :2:::5~~()()() ., :2852000. 2:::5200'') • 2:=:5::::~t)()() • 2::::5,2() {)() II 2:::52()()() .. 2:::::~520(lO • ?:::::5200(l. 2!::!'::;:2~()()() • :2::~5:2~)()() .. 2:=:5:~:~()l)() .. 2::::5:~;:()()() " 2:;::!!S:2()()() .. 2::::52000. :2():~::() ~~::::!52()()(). AVERAGE COST Cl~F' I TAL :::i '~.I 7 ~:: '7 :::: .. :3"~17::::7:3 .. (I ~, M 70000. 70000. 70000. 7'<)()()(:1 .. "lUOt":) • l()()(l{; • "? ()I'~i(~(~" /t)1 )( /1) • 10000. 70000. !(H)(H) • ':7 (lOO'; • 70000. 7 ')U'.I t )" / (JI)()() • 70i )(i(i. '7 (H)()(" II )',)(J()(", II 700(·t:" 700!)O. '/1)000. 7()(l(JO. '7 f)()()() " 70000. 70CH if I • 7 ()()(IC:I '1 7')()()," • )~("()(H) II 7(lO(l(' • 7(H)(l(' • 7000,.1 " 70U(H,'. '/r)O(lO. 70000. 700(l\·I. "'/OOO(J. 70000. 70000, 70000. 70(1)0. 700(H) • 70()()(l. 70nOn. 7000(l. 7 i )(;()(i. 70()()O. 70000. I'CIH;t.:t. 1\l1!',:ITC>,: "II '::;1 467:-{l3. ('. 1 (",1.1, I) " 1 X,.:: .l~67:~:73" ()" U~A !), 1 1. ,,' 4(:,7::::73. 1!.1{.:1 (:, l':'r:~, Lj i:;./:=::?:,::" O. 11::.4 (l, ,)9:::: 46j873. 0,164 0.0Q l iV:,j::i3. f'" ,! 4 0.' /, 46 )'::: i:::' I)" 1. ,~,:I ( • 0 i;'::: 467::::73. 0.16<1· n, Il./~,? i}.~.)-:::7:3. ('. l·~:,l+ (). ()~jl~.' 46 878. 0.J6~ 0,054 L},/. /~'3'?-~:" {",. 1 ~~j'q. (i,. (?~~:; 1 4· ':::' / :::{? :::: .. (;., :i (.I.l .• i) -l ~t· C, /,,';-:.::/:: , i" .U',CJ (J. () ",').1 46/873. o. 161 0.08~ A"~(~f'/:,;;'/:::; If (J .. 1.~-_,i.~ (, /I cr:::'~" 46}::-' T-; , (;" 1 (, <~ i: " .):: .:: L'k:,7::::73. 0 .. 164 (l, ( :',:(! Lj.(~,7:::::7,::::. ().1.,~:,·4 O«>:~ 467873, 0.104 0.024 l). /~I i :::,:7:::: lr () >, 1 /~14 I) '" ()~)":: 46 '; ::.:7~:. O. 1(>+ '). I) U::: 46!87~. 0.164 0.017 41:. /:~:I::" (i, 164 ('. 01 i::, ..j./;;, 7::-:'7:.:.. (o.l {,4 ':)>> ;) 1 ~:':i 4(:. 7;:,:7,::" n" :I. (~,4 (). (> 1:: 4/;'·h'/ ,< n. 1-:' . .q 0. (J 1. :.: 46:h:/:;:. 1) .. 164 .i)l~' 4/~, 7 I:: :;' :;: , I)>> 1 (" ,4 (\ r {, 1 1 467873. 0.164 0.01u 4,f::.j:::/:~~:" 0» :: 64 ". <)09 467873. 0.164 0.009 467873. 0" 164 0.008 46 7 873. 0.164 C.007 467:::: 73. O. 164 (\. 007 467873. 0.164 0.006 4678 7 3. 0.164 0.006 467873. 0.164 0.006 4A78?3. 0.164 0.005 467873. 0.164 0.005 467:::: 7:::. (). 1. (A () " 1)()4 467::::7 ::;:: 0 . .1:.4 0.1),)4 0" 11:.4 ;"). '):::6 "~t '-:rL ,J;... ...... 11 ..... NOT E: TO POGRAPHY FROM U. S. G. S. -ANCHORAGE ALASKA, 1:250,000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO -----PENSTOCK ---TRANSMtSSION LINE -WATERSHED 5 o 5 E3 E3 H SCALE IN MILES REGIONAl INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING RAINBOW DEPARTMENT OF THE ARM'f ALASKA DISTRICT CORPS OF ENGINEERS ~dro~ower Potential Installed Capacity Site No. (kW) 5 5,552 Demographic Characteristics 1981 Population: 20 SUMMARY DATA SHEET DETAILED INVESTIGATIONS RAINBOW, ALASKA Cost of Installed Alternative Cost Power1/ ($1000 ) (mi 11 s/kWh) 1,272 387 1981 Number of Households: 6 Economic Base UnknO\"n 1/ 5 Percent Fuel Escalation, Capital Cost Excl uded. Cost of Hydropower Benefi t/Cost (mills/kWh) Ratio 77 5.46 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. ~EGION~L INVENTORj i RECONN~I5ANCE STUDY -SM~LL H~D~OPO~E~ P~O.JECTS fEi4~: 198(1 1981 l·:;e 2 L ';;'83 1':;84 L985 1q88 L989 199(. 1991 1992 1991 L '7'94 19;;'5 1'7'9.~ L'?97 1 ;;'98 1-7'99 2tj\)~) 20(jl 2(,02 2(j03 20(j4 2()t)7 2~j(18 2013 2'.) 14 2015 1016 1018 21)19 :~ I.) 2~j 2(j21 2023 -, ,--/C· .,;...}.,;.. . ..} ,2026 21)27 2')28 ALA5K~ DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -RAINBOW KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 85714. :38727. 91 74\}. ·i4753. 97'7.~,,~ .. 1 t)(j779 + L 1)3792. 1 ·,)6805, 1·)981:3. 11283 L. L L5:~44. 118.:).:)8. 12L492. 12431-~,. 127L4,). 1327:37+ 135611. 1.3;3435. 141259. L 44('8:3; 146.:;i95, 1499·)7. 1::52:319. 155731. 158.~43 • 1644.:)8. 16738.). 1732.)4. 177\)19. L 80e:n. 18464;3. 188462. 192277+ 1':;;-·5092. L ;il99().';'. 2.)7535. 211351). 213891. 216431. 224053. 226593. 229134. 231674. 23421:;. 85714. -; L '741) • 94753. 97766. 1 (H)779. 1('3792. l,).S81)'S • 1',)9818., lL2:331. 115844. 12 U). 129775. 13.S 7 41 • J.43706. U,4.-';'C'3. 171.568. 178534, 1 ;3549':;'. 193:382. 21,)649. 227416. 2441:33. 25.2566. 2t~I')'?5~) + 26y333+ 27469l. 28~)04'" • 28541)7. 301481) • 3(,,~e38 , 3L219,~. -'-C'"r:::' ·~L .I ',) ,.14 • 322912. 327244. 33l57:S. 33591)7. 341)238. 14457() • 3489(-1 + 353233. 357564. 3t~ L i39~~ • 366227. 857l4. 88727. 9L741). '14753. 977{~6. 11)0779. i(;'3792. l')\-';';~1)5. 11)9::118. 11283l. 115844. 12.£95 L. 138058. L49L65. 17l379. 1::$:2487. 1935'7>4. :: '} ".\I'} 1 • 21581)i~ ~ 22t~915 + 2·(',; 77t) + 254624. 268479. 282334. 296L88. 3101)43. 323898. 337753. 35L607. 365462. 372363. 379264. 386166. 3931)67. 399968. 41)6869. 41377',), 420672. 427573. 434474. 440597. 446719. 458964. 465,)87. 47l2ij9. 477332. 4;33454. 489577. 49:;,~99 • Ar~i-il.jAL FEAt,: i)ErlArJD "r. L Ol.,j ME i)1 :'H~ i'lI I,) f-i 2<'7', 3 l.j ., 32~ 33, 35. 37. 4,) • 4 L " 42. ·,n. 44. 45, 4:;. 4::: " 4';:' • 5''} .. 51. 54. ::-::' -' . .) ,~ 56. 57~ 58. 59, 61. 62. 63. . ~5 • 66. 73. 74. 75. 76. 77. 78. 78. ~5:: . 33~ 4.0: • 4·:.\. 47. 54. 6:=-·. , ' .,' .;..'+ /~+ 8 t • 8"::\ , 8·:S • 11)( ... 1 \} 1. 103, 11)5. 1'·)7. 1 \)9. ILL. 112. 114. 115, 117. 118. 119. 121. 12: • l24. L25. . ---"" ; ,~, ,.' ~ .:.;~ . ·4,.), <~:3 • 4::' • ~5 L • ::: -:-:; ) ~::;, ~ 1 \) 1 + 1") ,.:., • 1 L 1 • 11·:;' • l. ::() • I -.::- "'" ..;. ,.1 .. 1 ~5'.~J ., 1:3::. 13:::'; • 13 7 • 139. 1,'12, 14.<1, 146. 149. 15i. 1:;3. J.55. 1 :) ? • 1.S6. l6:3 . RAINBOW SITE 05 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (di vers ion) Stream: Ship Creek Section 13, Township 13N, Range 2W, Seward Meridian Community Served: Rainbow, CEA Di stance: 15.8 mi Di rection (community to site): North Map: USGS, Anchorage (A-7), Alaska 2. HYDROLOGY Ora i nage Area: Estimated Mean Streamflow: Estimated Mean Annual PreCipitation: 3. DIVERSION D~1 Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo ltage/Pllase: T e r ra i n : .. !/ Fl at (1. 0 ) Total Length: 9. ENERGY Plant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrain Cost Factors Shown in Parentheses. 75 136 35 sq mi cfs in Large Concrete Gravity 15 ft 1045 fmsl 1600 cu yd Concrete Ogee 10 ft 78 ft 1035 fmsl Steel Penstock 63 in 15500 ft 2 Horizontal Francis SOO fmsl 489 ft 6763 kW 204 cfs 40.8 cfs 3 34.5 0.5 0.5 mi kV/3 phase mi mi 48 percent 28437 MWh Flow Duration Curve I / \) DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE 8ASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA RAINBOW SITE 05 CONCEPTUAL LAYOUT SHIP CREEK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Rainbow Site: 5 Stream: Ship Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. .Access 6 • T ran sm iss ion TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Adm"inistration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and r·lai ntenance Cost at 1. 2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST !l 524,000 !l 4,076,000 !l 1,746,000 !l 639,000 !l 144,000 !l 7,000 !l 344,000 !l 45,000 !l 25,000 !l 7,550 ,000 !l 755,000 !l 8,305,000 1.7 !l14, 119, 000 !l 3,530,000 !l17,648,OOO !l 2,647,000 !l20,295,OOO !l 1,928,000 !l22,223,OOO !l 3,290 !l 1,738,500 ~ 266,700 !l 2,005,200 !l 0.071 5.46 FF'O (It,U:1L T !'!')Ei'~ rUHY ~, f'ce Or,:rl{i : JlNCF ::' fill, '{ .... :,t1P,! L. fir Df-;>":'I)WFf.' F'F'O.JE tT ALASKA DISfRICT -CORP~ OF ~NGINEERS DETAILED RECONNAISSANCE INVESTIGATIONS ClY::;T OF HVDf::OPOW~::J;: --BENEFIT [(I(;T RATIO V E ,"1 F<: 1';'::::4 1':;:':::6 1 ':;,':::;:7 19::::':::' 199(1 1.991 19':"2 1 Q';:J4 1995 1 ';19f:. 19':'i7 1 1>:;9':;' 2000 2001 :2()():2 2003 2004 :::00"5 :;2 () t:) ,~. ~2(}()'7 :2: (;()::: ;~~O(yl 2010 2011 :;;:~() 12 2014 :2() 1 r:; 2016 2017 2() 1 ::: 2019 2020 ~:::O.? 1 ;::022 ::"()2:~:; ~-:;:():2~ 1:., :2<):2"7 RAINBOW ;::: I T E: 1\1t::). ~f KWH/YEAR 2::::437000. 2:::4:~:7000 . '':;:'::::437000. 2::::437000. 2:34 ':::7(JO(I. 2:::;:4:::7000. 2:::437000. 2:=.:437000. 2:::::4 :;:7 000. :2::::4:;:: 7000. :2:::4:;::7000. :;;::::::437000. 2:3437000. 2::;::4:'::7000. 2:::4:::7000. :::;::437000. ':;:::::4::::7000. 2:::437000. :~::=:437000 • 2::;:4::700') . 2::~4::::7()()1) • 2:':::4::;:70004 2:::437000. 2:::4:~:7000. :2::::4:::::7000. :2:::4 '::7 0(1). 2:::4:370(11) • 2:34.;:7()()() • 2:::4:37000. 2::;::4:;:7000. :2:::4:37000. 2::::4::::7000. :2::;::4::::7000. 2:34:37000. 2::::4:37000. ~::::4,~:700(J • 2::::437000. :284':::7000. 2:::437000. 2::::4'~::7000 • 2::;::4:-~:7000 • 2:::4:::7000. 2:::437000. 2:::4:~:70(lO • 2:::4:::7000. CAPITAL 174'?S39. 174'~i::;::::·~/. 1749:'::::::'9. 17 4':I!::3'i' • 1749:::::3':;/. 1 7 L'J.9:::';:'39. 1749;:::39. 1 } 49::;:::::;:9 . 1"74 ';'::=::;:9. 1 '7 4·~I:::J';·I. 1 749::::::::'7' • 174'):::::::9. 17 49::::::':'i'. 174'):::39. 1 -,7 4'~'::<::9. 1 749::;::::;:9. 1749:::::39. 1749:::39. 1749::::::::9. 174':;;:::::39. 1749:::::3';1. 1749::::.39. 174'::'839. 17 49::::3'~' • 1749:'::39. 1 '7 4 '~') !:: '3 .~/ • 1749:::39. (I 8~ 1'1 :;;::6(~,700 • 2667(10. 2(:.6700. 2bf:.700. 26670(1. 2667()O. :?~,670(l. 21.:06700. 21':.(:.700. 26(:.700. 266700. 266700. 266700. 266700. :?b(:.7()O. .261;·700. :26/:.]00. 266700. 2667()o. 2·1.:.67()1) • 2/:,6700. :266700. 261:.-'; 00. 26670u. ::::,~,670(l. 26(:,70() • 2667(1(). 21.:·{:.700. 266700. 26...:.700. 266700. 2l:: .. ~. 7 (li) • :2667()() • 266700. ~:~/:.6700 , 2(:.6/00. 2~·(:.700. 2/':.(:,700. 26670ll. 2·':·6700. 21:: .. 1::,700. 266700. 2029 28437000. 1749839. )66700. 2030 28437000. 1740 839. 2A6700. AVERAGE COST TOTAL. $ :?() 1,~,5:~:'~J. :~() 1 (.:,~~:~:'~:1. 2(l16~~:::::9 • 20 j ::·r:~;:'::9 • :,:::0 1 t':'~j:'::9 " L:(> 1 (-:' ~5 3'~) ~ 2 () l/:·I~i :3'7' .. .;:~ l) 11:.1 ~i :.:: '::,1 • 2016'3.:;:9. 201 e.':i:3'? • :2016,:,::::9. ~2(} t (-:I~:,:::J~I .. ~~ () l ~::,~:;:3 '~:J .. .::0 t 1;;."::i::9. ·.2U .16''5:::9. 20 l6::,:~:9 . ~::(i 1 :2() 1·~·~3:.::l;; .. ~?() 1 t'::i·3t~J .. 201 (::. '::i-::-:;; • 20 1.~/::j:::9. 2(l16~:,:.::·:J , ::: () 1 (:·~;:3 ·~I ., ~?~) 11:..:5 ::'~' .. :~:: () 1 f. !:=; : :: ';1 II 20 1 f:.~:i:.::9 • 20'l65:Y'. 20 1(:'5:~:·~i. 2011.:.5:39. 2016539. :201 es:::::'::' • 20 1 (~,':'-~:~:9 • 2 () 1 ,~:,~; :~:: '~i • :?() t /;' ~I::: I~' « 20 1 (-,~5:·::9. ',:;:() 1 ~~,~;.34~} If :2() '1 '~1~:3'~) p :;;~() 1 i::,5:3'~1 • O.(l?1 0.071 0.071 (l.n71 ().U;1. (I. (i! 1 O. ');.! (I. ,) i' I i).C)?! i). ()"7 'I 0.0 J O. (j"71. (I.O?1 0.(1/1 {)" () ? 1. 1).0'/1 (I. t):; 1 O. (":;-1 .). (1":'1 ~)" t~) / I O. ()71 O.O·"t 0.0 i' 1 O. (I'.:" 1 U.071 0.0/1 I). o? t 0.,)71,' 0. (111 0.071 .). \.111. 0.071 0.071 0.071 0.07l 0.071 O.O"!l O. (01 0.071 0.011 (I. {Ill 0.0',' 1. 0.0'/1 0.071 1;.049 (I. ()4(:. '"J. ,'142 O. n::~:9 ,). U:~;:7 !'l. i)::?-4 t ,}. t) ~~.2 ()" ()2'~:' ..) II (J:2'7 I,. U:~~~ i,. i 1 .. :~4 I .. >., (i.?::~: (\. (\20 0 .. 019 0.01 ::::: 0.01 f: .. (\. () 1 ::i 0.014 (',ill':: () It (. 1 '~:: (I" () 11 0.01.0 i). (I:l (i () .. ()CII::) (). (l(le (1.00:::: 0.00/ I). ()07 I,i" 1)0t. (1. (lO/:, (I,n05 0.005 I). ()()~;~ 0.004 0.004 0.004 0.00::': 0.00:::: O. (lClI'::: f), n(n 0.0(r3 O. OO::-~ (1.002 0.002 :2016539. 0.071 0.002 20l. 65:~:9 • (I. c,/ 1 (I. 00';- 0.071 0 .. 015 BENEFIT-COST RATIO (5% FUEL COST ESCAL.,A1ION): 5.~6 · .......... -.............. ------~ .' " L z~--- 5 o E3 E3 E3 SCALE I N MILES NOTE: TOPOGRAPHY FROM U.S.G.S.-TYONEK ALASKA, 1:250,000 5 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO. PENSTOCK ---TRANSMISSION LINE' --...-WATERSHED t." REGIONAL INVENTORY a REOONNAISSAN.CE STUD'I" SMALL HYDROPOWER PROJECTS SOUTHCENTRAL Al..ASKA HYDROPOWER SITES IDENTIFIED IN PREUMINARY SCREENING TYONEK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Hydropower Potential S1 te No. 4 Install ed Capaci ty (kW) 2,686 SUMMARY DATA SHEET DETAILED INVESGTIGATIONS TYON EK, ALASKA Installed Cost (~1000 ) 45,168 Cost of Al ternaii/ve Power_ (mills/kWh) 387 Demographic Characteristics 1981 Population: 239 1981 Number of Households: 68 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower ( mi 11 s/kW h) 400 Benefi t/Cost Ratio 0.97 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. t ,~:, ,::' t •. ' .. ' J. I.:. ' .. ' .. 1. ,: .. ;:; '.': .. ',' '·1 1 .::. :::: ":; ~ .;;,: ::: ,~:, i ':.:. :'~, .":: t :'", :-, "', j.. 'f,,),') :, .:;. ,~;, I. 1 :;-·~·:S I. :~, ::; "':' t '7":;':~ 1 ";' ,~.;:; ,.~I)I) ....: 2 :)1.) .J. 2(})) :': ~~ r.)C:I;~ :.:' 11 .~')11 ,2(' I. 5 :1) J.-4 2':' 17 :('1.::5 :., I ) ..:.~ " ~. HYDROPOWER P~G·jECTS ALAS~A DISTRICT -CORPS OF ENGINEERS LOAD FQRECAS7 -r~ONE~ ~ILOWAT7-~OURS PER 'TT I~t:; HIGH U.HJ hE:.! i: Uri ).,':'::4:86. L ) ,~:, ,,):7' 1. 1 1. .~;, :::;"5 '} -;; • 1. ~': (,,~ ::. 1. :2 , t24('::::18 , 14::18~;l1 , I. 485".:;-... ..; .. 15·5:~(,i68 • L =.:.;~j.s814. L .!) .2 C' :5 :) 9 " 16543,')5. L6:38.}5l. 1721797. 1. 7'S.-S59.~ , t 7? 13'?5. l. 8 :,,~d ':;:'4. 1 ::; .~.l) q .-;. ::~ + 18':;'57'=1 I. • 193,.:,5;;<') + 211537t. 23432-?6 " 238:3881. 2434466. 248')051. ~::~52:';636 + 2555995. ;~586353 " 26l.~712. 264? \; 7.) • 2,67742:;;. . 2707787 + ... . _ ....... -,- ~! / ~7";::$::j ~~ ,!, • (')24 I':) .~. (, :.: 'i l • 1 f. 1~;j31.')7 ,~ 12('4312. L::4l)31.;:: , 127,~37:3 .~ 13 l ::3.2:3 ~ 134i33T3, 13843T:; • 1 :55Cd3 l5. 1!~34~)52. 1 ~,!l71.)i,)3 ~ 2\)5',)24 L 4 2133479. 2311~.;398 .. 261?44.2. 2·.717,~24+ 26178(.·50) 2917987. 3tH81.::';:S • 3118351.). 32J.::s531. 3 213 2~558. 3346585. 341'),0;:.12. 3474r.;.39. 353866.',) • 36.)2693 .. 373.)747 - 3794T7 4. 38588!) 1. 3910562. 4() 14('85. 4,).!)5846. 4117607. 4169369. .:. 1 l:};.) • 4272891. 102428,::'. 106')291. 10':;'·':,297. 11323')2. 1168307. 1204312. 124t')3lt;. 127,~~:23 • L31232~3. 1348333. 1384339. 1517l)69. 1649798. 17f3'2528 ... 1915.257. 2·,)4 798·S. 2313446. 244.~175 • 2711634. 2:377198. 3'.)42763. 32,)8327. 3373891 + 3539455. 370502'} • 3870584. 40.)36148. 42',)1713. 4:3.-')7277 + 4449746. 4532215. 4614684. 4697153. 4779622. 4:362091. 4;;'4456,) • 5('27029. 51()9498. 5191966. 526513.} • 5338294. 5411458. 54;34622. 555778.~ • 5.53095(, • 5704114. 5777278. ---_._. ::,y L~ot.}.!) '" ANNUAL P~A~ DF~AND-~W LOW MEDIUM HIi:'H 35 i. ·!',O"~· + :375 .. 388. 4'.jf) • 412. 449. 462. 474. 48·::, • 4'i? • 51)9. 520. ~.~ I ... 59l) . 602. 613. 625. 637. 685. 697. 7if9. 724+ 740. 756. 771. 787. 802. 8i8. 834. 84-:;; . 8.55. 8 886. 8'::;,5. 907. 917. 927,. .j:' 1 • 363. ~375 • 4'}') • "n:2 . -4...::: .• 4.;-.' • 4.4':;' • 4,:;2. "P4. .~. L7. 1~45 ~ 7';3 ;; 8::;3. 8t~: + 931. '?1~5 + 9 s;u;' ... 1',)34. 1068. 11 0)2. 1124. 114.~ • 1168. l1-:;;O. 1::1.2. t234. 1256. l339. 1357. 1375. 141,), 1428 • 1446. i,4.:;3. l·,li31 • 14:~9 + .. :' ': .. ~ .. 375 -} 4l2. 4"5 7 • 44':;' • 4.~2 . .1:4, 7\:, 1 • 747. 1'.:'42, l\)99. 11'55, 1212+ 1::,~9, 13::,~ • 143':;' • 14::;6. 15;::5(1. 16');;' • l.S37. 1·~ 65. 1.:;:.9::' • L7 2::. 175·) • 17'::";3 ; 182(-3 I l8'53. 1878. t 9.-)3. 1-:;'2:3 • 197':;' • 2'-)1.)4. TYONEK -SITE 4 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Chuitna River Section 24, Township 12N, Range 12W, Seward Meridian Community Served: Tyonek, Chugach Electric Association Oi stance: 7.2 mi Di rection (corrmunity to si te): Northwest Map: USGS, Tyonek (A-4), Alaska 2. HYDROLOGY Ora i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: He; ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng He; ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Steel Penstock 84 in 2000 ft Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/ Pha se: Terra; n:11 Fl at (1. 0) Tota 1 Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown Jj Terrai n Cost Factors Shown in Pa rentheses. 108 284 29 sq mi cfs in Large Concrete Gravity 15 ft 275 fmsl 830 cu yd Concrete Ogee 5 ft 254 ft 270 fmsl Steel Penstock 120 in 12100 ft 2 Crossflow 165 fmsl 93 ft 2686 kW 426 cfs 42.6 cfs 2.7 38 4.7 4.7 mi kV/3 phase mi mi 44 percent 10353 MWh Flow Duration Curve ,'- ,I SCALE: 1\ 2000FT LEGEND: DAM PENSTOCK ............. TRANSMISSION LINE • POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA TYONEK SITE 04 CONCEPTUAL LAYOUT CHUITNA RIVER DEPARTMENT OF THE ARMY ALASKA DISTRICT HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Site: Stream: Tyonek 4 Chuitna River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 15 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngeney at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANN UAL COSTS Annuity at 7-5/8 percent (A/P = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 269,000 $ 8,522,000 $ 1,214,000 $ 366,000 $ 573,000 $ 10,000 $ 159,000 $ 4·1,000 $ 188,000 $11,342,000 $ 1,701,000 $13,043,000 2.2 $28,695,000 $ 7.174,000 $35,869,000 $ 5,380,000 $41,249,000 $ 3,919,000 $45,168,000 $ 16,800 $ 3,533,500 $ 542,000 $ 4,075,500 $ 0.40 0.97 :<ECi I ClNr.4L I hlVEHT OF;~Y ~< F:ECUI',II\1A I :::Ar'.jCE ::;;:TUDY (;:;1'1ALL HYl!r,:1 IF'I~I{, .. H.::H PFTJ . .JFCT'::, ALASKA DISTRICT -CORPS UF ENGINEERS DETAILED RECONNAISSANCE INVFSTIGATInN~ CO::::T OF I-IYDI(I)PUWFJ:: 8E:,NEF:I r 1:(1:;;: r Rf'4T I I. I TYOr>JEf< :::: I TE Nt). 4 YEAR KWH/YEAR CAPITAL 0 & M 1984 10306000. 3556528. 542000. 1985 10306000. 3556528. 542000. 1986 10306000. 3556~28. 542000. 1987 10306000. 3556528. 542000. 1988 10306000. 3556578. 542000. 1989 10306000. 3556528. 542000. 1990 10306000. 3556528. 542000. 1991 10306000. 3556528. 542000. 1992 10306000. 3556528. 542000. 1993 10306000. 3556528. 542000. 19~4 10306000. 3556528. 542000. 1. 99:i 10::;::(16000. :::::~:i':;I:.':;:;:::::;;:. C::i4:?()()I)" 19';//:. 10306000.. J''5~:"i6':i~:::::. !54::;:-rl(Ji)" 1 .:).=.0 1 0:~::06000 .:::"',~:;6~:!;=':0:. t::i4:::UOI) .. 1998 10306000. 3556528. 54JOQO. 1999 10306000. 3556528. 542000. 2000 10306000. 3556528. 542000. :;::001 1 O::::();~.(iOO. 2003 10306000. 35~0~28. ~42000. 2004 10306000. 35~~528. 542000. 2005 10806000. ~556528. 542000. ~:~()().~:;. t (;:3() !:.() (H) " :::~i~f(-:.~i~?::::. ~14:~~(j()I) t. 2007 10306000. 3556528. 542000. 200::::: 1. (no/~.Oi)CI. :~:'=:'56!::'~:?:::. '~)4:20uU. :::~OO':;:I 1 (no/::.('II)O. ::;:556'5:2:,::. 5420(1(l. 2010 10306000. 3556528. 542000. 2011 10806000. 3556528. 5420UO. ':~O 1:2 1 0306(ji')() .~':':;,:;(-.~";~;:'::::. "";42000,, 201.:::': 1 (l::::()(:-'OOO. 3~::?:i.I:·52C, ~~i42()()(). 2014 10::06000. ::::!"'i':;I:.::;~~·:::. 542000. :2() 1.5 1 ():~!().::,{)(l().. :::~~~~/~"t~I:?::::. ~14:~.'(H)(; It 2016 10306000. 35~6528. 542000. 2017 10306000. 355A528. ~4:2000. 2018 10306000. 3556~28. 542000. 2019 10306000. 542000. 2020 1 O:::(l(:.OOU. :35~:1652G. ",:.42000. 20:.? 1 1 O:::06()(H). 355 U":; ?:::: • !':';42c·n() . 2022 10306000. 3556528. 542000. 2023 10306000. 3556528. 542000. 2024 10306000. 3556528. 542000. 2025 10306000. ::':!:;~i(:.~i:~::~:. 542()(H). 2026 10306000. 8556~28. 542000. 2027 10306000. 3556528. 542000. 2028 10306000. 3556528. 542000. 202 0 10306000. 3556528. 542000. :?():::~() 1. ()::::(){:.(){)f!., ::::~~~:;(~,~:'i,?::::,. ~i4:2i)()CI1. AVERAGE COST TOTAl_~) NClhIDI~~:I.: )IJ~:;': 4()'~Jf:5:2:=: a () to :::;:':);::: (i" :~~ } I::) 4·()·~!::::~:;:2:::. {) 10 '3·~1::;: () .. '?~d~t 4098528. 0.398 0.221 4098528. 0.398 0.205 4098528. 0.398 0.191 LI·(t'~/;::~~;~?~:::. () ;[ '.~:'~~I::::~ () ot 1 f.:.,r,':i .4( )t;!::::~:';:~:I::~: ., ()., :,~:'~~' ;:::: () .. 1 ~::; .::: 4n';):::::~,~:·:~:. "" ::.,'!:': (1.142 4008~28. 0.398 0.114 4,()'~/!~':~~;:2::': II I') I' ·31~):.:: ()" I )~ ... !l::'1 4(j·:;J;·:::~5~~:,:~~., (i~. J'.::':.:': ()., l,Y' .. ·'·,., 4·()·';!:"::";1·;:"~:~:., I~l u :.:::;:.I~:: () .. ("~-:i 1 4098B?8. C.~08 0.041 4()':·)r~::::i'2::!. ':) ... ::'''}':'': () II ~ ),.~!:~: 41' )t;:):~::~:~~~~:: II (). :~!'~.i:;~: f),. 1)'::,:1:-', iJ.()·~!::~f:::<;;:':;! II () t. ,:~:";!:;:~ (i h ((~:::::: 4·(:I·):·':~f:;·::~:. C· ,. ::':;:I:~: (, II ('»::i) 4(}'~~':~:::':·I:::~:~:. () .. :~~'~i!::! (j .. (),?:~,~ .1q.( 11~,.':~.~I:;':~:~:.. ()" ::::':'):::': ()" (r .. ··~., i.~':)'):::;~:::i:?:~: II () •. :?,~w':7: () ~ (',:?4 .(~.( )·~):~':l'::i~~~::-:. <') .. ~:::'~:'::~~ (i. t~) /:::: il. () .:;, :::.: c5 '(' :~: II (l" .. :: I;:} : ::: (J " (', ') 1 4.)'?'J!~:!~:-.i.=~:~:: It () .. ~:t':i:,·:: (). (1'?() 4()'~':~::~S2:::" C)" :'::(:~);:~: (} .. (I t :~:: 4()1~-,::-::t:'~".2:::~~ n ()" ·::!·::l~:.: () '! () 1 )' 4098~28. O. ~98 0.016 4t·)')f~r:;:~~.:~::. () .. :~~:I~/:~: () .. () 1 ~:I 4098~28. 0.398 0.014 4098528. 0.398 0.012 4098528. 0.398 0.011 o o NOTE: LEGEND ~ DAM SITE • POWERHOUSE o SITE NO. -----PENSTOCK TRANSMISSION LINE -----WATERSHED HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING COPPER CENTER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS H~dro~ower Potential Installed Capacity Site No. (kW) 16 2,782 Demographic Characteristics 1981 Population: 213 SUMMARY DATA SHEET DETAILED INVESTIGATIONS COPPER CENTER, ALASKA Cost of Installed Alterna~i ve Cost Power_/ (UOOO) (mill s/kWh) 27,922 362 1981 Number of Households: 61 Economi c Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mills/kWh) Ratio 217 1.67 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. l-i::rs l ';i 8<l L ? :~: ,:; 1.::i;3:; :, ;;:i8 1-~8'1 1:;--i ,) L -=i9 i 1 '7".(:;:: 1993 1'?94 1?9~: 1';;>96 1.':;;'97 1 ,~,::;, ::l L 99'? 2,:,\)0,) 2',)(' J. 2 t.:lt) 2 2(n.j3 :~~)(p~ ,:.:')(.'5 :::';)')6 ;::\)1)7 2')~:'8 21jl.)~ :2(,' J. ,) 2'jll 2()12 :2(, l4 2') 1:'i 20.16 :').17 ~~I) H:i :(. 1.9 ';;\} ~:~~ 2t.j.~23 2 1,)24 ~EGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALAS~A DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -COPPER CENTER ~ILOWATT-HOURS PER YEAR LOW MEDIUM HIGH <:;128'5"7. ~i44945 • -:;077034. L 1)1.)9122. l(j41211. 1,:·73299. 1 1',)5387. l13747,S. 11695.S4. L2') 1 ·:):52. L2:33741. 1.2630316. 12';i3891. 13 23-~65. 1354')4\} • 13841.15. 14 I. 419\}. 1444264. 1.4-,'4339. 15\)4414. 1534489. 1565:'!)2. 159651.~. 1627529. 1.'!>58542. 1.,!>89S55, 172056.:;0. 1751582. 1782595. J.813·SI)8. 1844621. 18:35247. 1925873+ .1966499. 2\)1)7125. 2\)47751. 2\)88377. 21 :~91}1:j3. 216·?629. 221,),255. 225(1881. ~2277937 • 2304993. :n32(j49. 23591,}5. 2~586.16t. 2413217. 2441)273. 2494385. 2521441. ~12857. 944945. 977034. 100'~ 122. 1041211. 1(03299. 1105387. 1137476. 1169564. 1.201652. 1233741. 1312534. 1391327. 147(121) • 1548914. 162771)7. 170.6500. 1785293. 18641)86. 1942879. 2021672. 2117046. 2307794. 2403168. 2498542. 2593916. 2·68'7' 291} • 2784664. 2880038. 2975413. 3034193. 31)92973. 3151752. 3210532. 3269312. 33281)92. 3386871. 3445651. 351)4431. 3563211. 3611335. 3659459. 37()7583. 3755707. 3803831. :3851955. 391)1)079. 3948203. 3996327. 912857. 944945. 977')34. 1009122. 1041211. 1073299. 1105387. 1137476. 1169564. 121)1652. 123374L. 13·:)1253. 1488764. 161.6276. 1743787. 187129i.f. 199881 1:) • 2126322~ 2253833. 2381345. 2508856. 2668591. 2928326. 2988061. 3147796. 3307531. 3467266. 362701) 1. 3786736. 3946471. 4106205. 4L83139. 4260072. 4337006 • 4413939. 4490873. 45678',)6. 4644740. 4721673. 479861)7. 4875541) • 4944733. 5013925. 5083118. 5152310. 5221503. 5290695. 5359888. 5429(81) • 5498273. 5567465. ANNUAL PEA~ DEriAND-;0 LOW riEDIUM HIG~ 313. 313. 313. 324. 335. 346. 357. 368. 3 7 9. 3':;O~ 401. 412. 423. 433. 443. 453. 464. 474. 484. 495. 5~)5 • 515. 526. 536. 547. 557. 568. 579. 589. 601} • 610. 621. 632. 646. 6·~0 • 673. 687. 7i) 1. 7i5. 729. 771. 780. 789. 799. 81)8. 817. :326. 836. 845. 854. 8.~4 • 324. 335. 346. 357. 3,68. 37i.f. 3':;;",} • 41) 1 • 412. 423. 449. 476. 5t)3. 530, 584. 611. 638. 6"::5. 692. 725. 758. 79\) • 823. ;35·6. 8i~8 • 921. 954. 0-' ,~O. li)19. 11)39. l059. 1079. 1 ()'~.~. 112',). 1141} • 116"-) • 118',) • 12i)0. 1237. 1253. 127t) • 1286. 131)3. 1319. 1336. 1352. 1369. 13;35. :".~J " 3<46. .':',::1 ..' ... 3:~1) • 4,) 1 • 412. 423. 4,S.~ • 51') • 5:=;4. 5':;'7, ·S41. 8 1.:) • 1 , .. ,-:--,_· '*.~' 11)7 1133. 11;:57. 1242. 1297. 1352. 14~)6 • L433, 14')·~. 14:35. lSi2. 1538 .. 1564. 15-i1. 16i7. 1643. 1670. 16'~3+ L7 L7. 1741. 17,64. 1788. 1812. 1836. l859. i;38/ 19(1, COPPER CENTER SITE 16 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Klawasi River Section 5, Township IN, Range IE, Copper River Meridian Community Served: Copper Center, CVEA Distance: 2.7 mi Direction (community to site): Northeast Map: USGS, Valdez (D-4), Alaska 2. HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vo 1 ume: 4. SP ILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Uni ts: Turbine Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/Pha se: Terrain:Y Flat (1.0) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown Y Terrain Cost Factors Shown in Parentheses. 149 180 30 sq mi cfs in Large Concrete Gravity 20 ft 1200 fmsl 2620 cu yd Concrete Ogee 10 ft 120 ft 1190 fmsl Steel Penstock 90 in 9200 ft 2 Crossflow 1030 fmsl 152 ft 2782 kW 270 cfs 27.0 cfs 1.7 24.9 0.8 0.8 m; kV /3 phase mi mi 48 percent 11698 MWh Flow Duration Curve --~ • 7 •• I .. ) ' ... ". . ~ ". ~ \ \ ( ! 1/ \ c o o .../ -~ o o \ .... - 0'· '" LEGEND: seA L r: 1 -; 200 (i, ! :, : /--..:: --+-........ -" :. '-.. . , DAM PENSTOCK ~+ •••• #..-~ • .. """"""'~""" / ~". ~.~ ............... . ,"-, .~ .,-.,.... .. ....... ,.\ ------- • r , r t I TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY &. RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA COPPER CENTER SITE 16 CONCEPTUAL LAYOUT KLAWASI RIVER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS :1 I HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Communi ty: Site: Stream: Copper Center 16 Klawasi River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. SwitchYard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Our; ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 755,000 $ 3,968,000 $ 1,435,000 $ 471,000 $ 367,000 $ 8,000 $ 264,000 $ 26,000 $ 36,000 $ 7,330,000 $ 733,000 $ 8,063,000 2.2 n 7,739,000 $ 4,435,000 $22,173,000 $ 3,326,000 $25,499,000 $ 2,422,000 $27,922,000 $ 10,040 $ 2,184,300 $ 335,100 $ 2,519,400 $ 0.22 1. 67 r~:FC; I CI~.J(·\L J rNEI'HORY :;:c RECurH·Jt·:\ I:,ANCE :::TI.lDY :::r1{:d L H't Dr:UF'OWC.R F'F·,'U,.IEI ... i ': ALASKA DISTRICT -CORPS OF ENGINEERS DETAILED RECONNAISSANCE INVLSTIGATIONS CO:::::1 ()F HYDf~:OPOWEF~ -EI[]\It:F I T (:II:::T RAT I I.. C:OF'F'ER CENTEr.::: ::; I TE 1\10. J. (:. YEAR KWH/YEAR CAPITAL 0 & M 1984 11698000. 2198578. 335100. 1985 11698000. 2198578. 335100. 1986 11698000. 2198578. 3351UO. 1987 11698000. 2198578. 335100. 19:~::::: 1 169::::000. 219::::':::;1:2:" :~~:::::!,,:~ 1 00. 19::::9 11 (:,';'::::')(H). ::219:::~:57::'~: ,,:.::::':,1 ()o. 1':'/90 116';";:::(1)1). 219::;::57:?:.. :::::3510(). 1991 116980uO. 2198578. 83~100. t 99:;:' 11 t;.9f:OOO. 219:·::~::'?:::::. :;:.:''': 1. u(J" 1993 11698000. 2198578. 335100. 1994 11.':.':;'::::000" ~:: 1':;-':::~;78.. 3::::~; 1.1 )()., 1995 11.':.98000. 2198578. 335100. 19':)(:, 11 /:"~):=:OO(l. ? 1 '::):::::57:=::" :':::::") 1 ue,. 1997 1169 8000. 2198578. 835100. 1':)';;':::: 1 1 (:,'~!:::()()O. :2:l 9:':::~~; 7:;:::. :::::::::"; I ')0" 1)')9 111':',9:::::(H)O. 21(;':=:~57:::~. 3::~51'.J(i, 2000 11 ,1:,9:::(H)0 " :219:~:~;7::::" ::::::;~; 1 CHI. 2001 1169:::000" 219::::~;7:~::. 3::<:,1. OCo. 2002 1169::~:OOO. 21 9:::~:;7:;:::.. J3~; 1 ()(), 2003 11.':.9800n. 2198578. 3j~]OO. 2004 11698000. 2198~78. 33~100. 2005 11698000. 2198578. 33~100. :2: (H)(:, 11,:,';:':;:::(\00. 219::;::<:;7::::" :::::::'5 'l (H). 2007 11698000. 2198578. 335100. 2008 11698000. 2198578. 335100, 2009 11.':.98000. 2198578. 335100. 2010 11698000. 2198578. 335100. 201 1 1 1. /:. 9::::000. :::; 1 '~j8'57:~::" 335100. 2012 11698000. 2198578. 3~~100. 2013 11 t:,9::::000. 21 '~n:::~;7B. :~::~::~, 1 0(1. 2014 1169:~:(JOO. 21·~')::::57:::. 3351 O(). 2015 11698000. 2198578. 335100. 2016 11698000. 2198578. 3?~100. 2017 11698000. 2198578. 335100. 201.::: 1169:=':000. 21 ':;'::::';7:·:: .:::'::~ 1 (\(1" 2019 11698000. 2198578. 835100, :::::020 116',:):::000. :2 j 9:::57::;:: .;:::::5100:' r 2021 11.':.98000. 2198578. 335100. 2022 11698000. 2198578. 335100. 2023 11698000. 2198578. 335100. 2024 11698000. 2198578. 885100. 2025 11698000. 2198578. 335100. 2026 11698000. 2198578. 2027 11.':.98000. 2198578. 2028 116 9 8000. 2198578. 2029 11698000. 2198578. 2030 1i698000. 2198578. AVERAGE COST :3351 (Hi, ::::::::!::51 00. lUO. 3::'::~, 1 00 " :::::~::~; 100. TOT(K,$· NONDI::;C DI::::;I: ~::~:;:::::::67:::. 0.:.1/ n. l'~;1) 2533678. 0.217 O. '~0 ~2~5::::::::(;.·7:;:::. () ~ :? 1. ':7 (I" 1 ~"':;l :::::~'; :::~::67::::. \ i. ~.'.1 ! (l, ,} ...• ( j '~:j ~::I :~'::'~: /) -;-f: u (r >I ':;:: 1. :: (I" (; ? .:::: ::;:.~~~ 3"::;(:. '7::::: <l (')., • .': " ~7 () .. t' )/-" ,/ ./~"" -!::3l-.. ~7!~:" \,> If ~::,' 1 / (, .. (I,:::." ~::~:;f:~'::~:':(:,7::: II () j' ',:' .i. ':? ,:'1" (iL.I ::: .~:::I:"';'':!:·':~\~'':~: It 1):11 ," 1 / (} .. 1 }:-'4 i :::,:~j:::::::':(~.7:~:.. t.,)" ,,:~l), 1') .. (:ll·":-, :2~j:::::'~::,~, l:~': ~ ()" '? ,1 "."I 1,1,. ( ll'l ::" .,:::~";::':::':(·78. O ... '.1 7 O.nlj.Cl ';::::-";':':::~:/:<7f: JI f) ,. :;:t 1 ";.1 () •. (>.:;.; *~:I~J:':: ~::;IS:I :~:: II i) I, .:' 1 "7 0 " ():3 >:~~ :~2~; ~:~::3 I:> "7 :~: « ( ) .t 0''': 'I. '/ () .. I J -:~,) ;:~1:~;:::·.!::!\1::.7:::::. t) .. :=~1 7 \)" (r~::i) :~:~C~I:~~::~:l) 7f:,. ~ I .. ':.:~ 17 ("} h (}'2::::~ :? ~5 :3 :~:; ,f;", '7 ::::~ ,f (' ... -:~. l ';' () " (j .,-:: /.~. ~?~-3'3'~1 '7::!,. I I ' .• :~ t >' () to ("'L~4 ::2~5:"':::',:/",'7~J ft () .. ',,' 1 l (I .. I ~'''''>I ~~:~~::::: .'~:/) '7 :::: " t') '1 ? 1 7 () If () 1 :;,.; ~:·'~.:::;·~:67::::. ').,'::'1/ O.Ot 7 2533A78. G.?17 0.015 2~83678. 0.217 0.014 ,;·:'j:!:'·:h7:::;:. ()" .: 1. 7 O. () J .,:: ~;:: ~=t "'~.' ::~: (M. *7 ::! It ( ) A ~:I 1. 7 () .. () J ~~., 2~·i::<:":,7::::. (o.;:'j7 (:0.011 2533678. 0.217 O.Otl 2533678. 0.217 0.010 ~":"::::::67::::. I) .... 1'1 (). Oil',', 2~83678. 0.217 0.009 ~?~i::~::~~~::, 7:;::" ()" ~;t 1 7 () n (i()~~:: O. '';::17 ().OO'/ 0.21 7 0.007 0,,217 0.006 o. ?:: '7 0. no('· n.217 0.00') BENEFIT-CO::n RATIO (~;:I,. FIIEL CO:::;1" E::::;('::~U\TJI)~~): .;::17 0.047 1" '';'/ .4 .' . . 'Q' . " z~---- 5 o 5 E3 E3 E3 SCALE I N MILES NOTE: TOPOGRAPHY FROM U.S.G.S,-GULKANA ALASKA, 1:250,000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO. -----PENSTOCK -- -TRANSMISSION LlNEI --WATER SHED REGIONAL INVENTORY a REQ)NNAISSANCE S'fU1( SMALL H't1)ROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PREU MINARY SCREEN I NG GAKONA-GULKANA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS .. ~ :I rtYdroQower Potenti al Insta 11 ed Capacity Si te No. ( kW) 3 1,075 Demographic Characteristics SUMMARY DATA SHEET DETAILED INVESTIGATIONS GAKONA-GULKANA, ALASKA Cost of Installed AlternaHve Cost Power_ ($1000 ) (mi 11 s/kWh) 12,939 362 1981 Population: Gakona -25; Gulkana -111 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mill s/kWh) Ratio 260 1. 39 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY & RECONNAISANCE STUDY -SHALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -GULKANA ~ILOWATT-HOURS PER YEAR 'lEAf': LOW MEDIUM HIGH LOW 163. 169. 174. 1St) • 186. 192. 197. 21)3. 209. 214. HIGH L '~8(t 1'?:31 1 ',:'82 19E.~4 19:35 19:3·~ l'1' 8:3 19B9 19 0 <;' 1=i91 1'::;'92 1.99:3 1';'94 1995 1':;';;06 1'?97 1998 199'9 21)(.10 2C,.,) 1 2·j(j2 20')3 2('04 2r:)(,~j 2')06 2',)07 21)08 200'::t 2010 2011 2012 2014 2015 2',)16 21,)17 2')18 2( .. 19 ::':)20 2(,21 2023 2024 21)25 2026 2027 475714. 492436. 5(19158. 525881. 54261)3. 559325. 576047. 5'i2769. 609492. 626214. 642936. 65861)9. 6'74281. 689954. 71)5627. 721299. 736972. 752645. 768318. 7E:3990. 799.663. 815825. 831'1'87. 848148. 864311). 880472. 8,';f6634. 912796. 928958. 945119. 961281. 982452. 1003624. 11)24795. 1045966. 1067138. 1088309. 110948,) • 1130651. 1151823. 1172994. 11871)94. 1201193. 1215293. 1229393. 1243492. 1257592. 1271691. 1285791. 1299891. 1313990. 47~71/.: • 492436. 51)9158. 525881. 542603. 559325. 576047. 592769. 609492. 626214. 642936. 6:33997. 725058. 7.:)6119. 807181. 848242. 889303. 930364. 971425. 11)12486. 1053547. 1103249. 1152951. 1202653. 1252356. 1302058. 1351760. 1401462. 1451164. 1500866. t 551)568. 1581200. 1611831. 1642463. 1673095. 1703726. 1734358. L764989. 1795621. 182625::i. 1856884. 1881963. 1907042. 1932120. 1957199. 1982278. 2007357. 2032435. 2057514. 21)82593. 2107A7.1. 475714. 492436. 509158. 525881. 542603. 559325. 576047. 592769. 6,)9492. 626214. 642936. 709386. 775835. 842285. 908735. 975184. 1041634. 1108t)83. 1174533. 1240983. 1307432. 1390674. 1';73916. 1557158. 1640401. 1723643. 1806885. 189tH27. 1973369. 2056611. 2139853. 2179945. 2220037. 2260129. 2300221. 2340313. 2380405. 2421)497. 2460589. 2500681. 2540774. 2576832. 2612890. 2648948. 2685006. 2721064. 2757122. ?793180. 2829238. 2865296. 2901354. 22') + 226. 231. 236. 242. 247. 252. 258. 2~3. 268. 274. 279. 285. 29i) • 296. 302. 307. 313. 318. 324. 329. 336. 344. 351. 358. 365. 373. 380. 387. 394. 402. 407. 411. 416. 421. 426. /:31 + 436. 441) • 445. 451). 163. 169. 174. 18'.} • 186. 192. 197. 203. 2 I)";' + 214. 234. 248. 262. 276. 29,) • 3,)5. 319. 333. 347. 361. 378. 395. 4i2. 429. 446. 463. 48\} • 497. 514. 531. 542. 552. 5.~2 • 573. 583. 594. .~1)4 • 615. 625. 636. 645. 653. 662. 670. 679. 687. 69'6. 705. 713. 722. 1·:;3. 1·S9. 174. 180. 186. 19::. i ::or;; • 2l)3. 2(19. 22t.) .. 243. 21~1S; • 311. 334. 379. 4,)2. 425. 'i t.'l P. • 476. 5\)5. ~~::-;;+ 5,~2 t 5~\j • 619. 647. 676. 7 1)4. Tn. 760. 774. 788. 81)1. 815. 829. 843. 85.:) • 871). 882. 895. 907. 920. 9:0.2. 944. -.,.-"t.J / • 969. 981. 994. ?EGIONAL I~VENTORY & REC0NNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALAS~A DISTRICT -CORPS OF ENGINEERS r'E.4t-: l '"';'8') l .~~. i~: 1. 1'~;3:: L q::j~3 1':;; f:54 1'::;;::;::5 L ~:~·S 198? 1 <i :38 l'i8,? 1·:;.·::tO 1 ':;9 1 1 ';';'2 t?93 1994 1995 199.:::- 19';-7 199:;i 1999 2:'}')'} 20(11 20 1)2 2')03 2')04 2 (H) 5 :: l.)().~ 2'')()7 2008 21)09 2CJ!l) 2011 2,)13 2014 2016 2')17 :» 18 2·.) 19 2025 .2026 2(;27 2'')28 • ~·j29 LOAD FORECAST -GAKONA KILOWATT-HOURS PFR YEAR LOW MEDIUM HIGH 107143. 107143. 107143. 110909. 11()90<;. 110909. L14675. 114675. 114675. 118442. 118442. 118442. 125974. 12974!). 133506. 137273. 141039. 144:305. 148335. 151865. 155395. 158925. 162455. 165984. 169514. 173044. 176574. 18CJ104. 183744. 1;37384. J.91024. 194664. 19831)4. 20 1·?l45. 205585. 209225. 212865. 216505. 221273. 226042. 230810. 235578. 240346. 245115. 249883. 254651. 259420. 264188. 267364. r:0539. 273715. 276890. 280!)66. 283242. 2:36417. 289593. 292768. 295944. 122208. 125974. 129740. 133506. 137273. 141039. 1448l)5. 154053. 16330l. L72549. 181797. 191')45. 200293. 209541. 218789. 228037. 237285. 248479. 259673. 27!)868. 282062. 29:3256. 31)445() • 315644. 326839. 338033. 349227. 356126. 363025. 369924. 37.~823 • 383722. 390621. 397520. 404419. 411318. 418217. 423865. 429514. 435162. 440811. 446459. 452107. 457756. 46341)4. 469053. 474701. 122208. 125974. 129740. 133506. 137273. 1411)39. 144805. 159771. l74737. 189704. 2(4671) • 219636. 234602. 249568. 264535. 279501. 29·i467. 313215. 331963. 350712. 369461) • 388208. *)6956. 425704. 444453. 463201. 481949. 490979. 5001)08. 509038. 518068. 527097. 536127. 545157. 554187. 563216. 572246. 580367. 588488. 596610. 60473 t. 612852. 620973 • 629094. 637216 • 645337. 653458. ,<Y ANNUAL P~A~ DEriAND-~ LOW MEDIUM H~GH 37. 38. 37. 38. 3Y. 3"~. 41. 42. 43. 44. 46. 48. 50. 5i- C'~ ;:J~. 53. 54. 56. 57. 58. 59. 6!) . 62. 63. 64. 65. 67. 68. 69. 70. 73. 74. 76. 77. 79. 81. 82. 84. 86. 87. 89. 90. 92. 93. 94. 9~. 96. 97. 98. 99. 100. 101. 4 L • 42. 43. 44. 46. 47. 48. 50. 53. 56. 59. 62. 65. 69. /~. 75. 78. 8 L • 85. 89. 93. 97. 100. 11)4. 108. 112. 116. 120. 122. 124. 127. 129. 13l. 134. 136. 138. 141. 143. lil5. 147. 149. 151. 153. 155. 157. 159. 161. 163. 4 i • 47. 4:3. C'" ...,1 f.' .. ;:J:). 6t) t l~5 " l::". 8(t + :3~ .. 9 i .• U) i • 1!)7. 114. i27 133. 139. 14.!). 1:).::. 159. 165. 168. 17.! • 174. 177. 18 i • 184. 187. 190. 193. 196. 199. 21}4. 2l)7 + 210. 213. 215. 218 ... 2~J .i 224~ GAKONA/GULKANA SITE 03 SIGN IFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Copper River Tributary Section 35, Township 5N, Range IE, Copper River Meridian Community Served: Gakona, Gulkana, GVEA Distance: 8.7 mi Direction (community to site): Map: USGS, Gulkana (A-3), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 35.9 43.3 30 sq mi cfs in Southeast 3. DIVERSION DAM Type: Large Concrete Gravity Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Voltage/Phase: Terrain:l/ Flat (1.0) Rolling (1.25) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1.1 Terrain Cost Factors Shown in Parentheses. 15 ft 2065 fmsl 1570 cu yd Concrete Ogee 5 ft 108 ft 2060 fmsl Steel Penstock 42 in 10100 ft 2 Pelton 1790 fmsl 244 ft 1075 kW 65.0 cfs 6.5 cfs 1.9 24.9 5.9 1.0 6.9 48 4520 mi kV/3 phase mi mi mi percent MWh Flow Duration Curve 29 ........ ~ ... : ......... . 32 5· I 8 28 4 . .:" ·9 a a 0) - \9 o o 3 (\ \ ' , . ~ V'l I l/ / i SCALE 1":2000 , I () -_ ... _- 26 ( \ 1/ \ , ~; , I \ \ "'-V7 '/ ~ 11 Il , " " , I \ I , \ I I \ '0 LEGEND: ~ DAM PENSTOCK ............. TRANSMISSION LINE • POWERHOUSE [ DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTH CENTRAL ALASKA GAKONA/GULKANA SITE 03 CONCEPTUAL LAYOUT COPPER RIVER TRIBUTARY DEPARTMENT OF THE ARMY ALASKA DISTRICT ~PS OF ENGINEERS i ,1 ,I :1 i HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS CoI1l11U n i ty : Si te: Stream: Gakona/Gul kana 03 Copper River Tributary ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val ves and Bifurcations 4. SWitchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Ouri ng Constructi on at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annui ty at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 476,000 $ 1,250,000 $ 605,000 $ 329,000 $ 30 ,000 $ 21,000 $ 187,000 $ 29,000 $ 322,000 $ 3,249,000 $ 325,000 $ 3,574,000 2.3 $ 8,220,000 $ 2.055,000 $10,275,000 $ 1,541,000 $11,816,000 $ 1,123.000 $12,939,000 $ 12,040 $ 1,012,200 ~ 155,300 $ 1,167,500 $ 0.26 1.39 REO I IIN?'iL. I N!E NTCIRY ~( FECUNr~?H :::ANCE :;:fII[lY .... :::MAl.L HY Llh'I:1POWEF F'{;.:;'I"LJEI.=: r::: AL.A:::;hA DI:::TI,: leT -COF'F':~: I.lF ENOTI\JE:F.::·F:':~: DFT{:i T L.EO F:E::CU"~N':~ I ::::::,ANIE 1f\.IV~::::: r H~i{H I Of\l:~: co::;;! OF HYDROPOWER BENEF I T co::n F:A r I (I {E{:~F: 19::::4 19::;:'::; 1 '?:;::t, 19::::7 19::::9 'I ')90 1991 1'7'92 1 ';1';:1;:: t 9'~14 1,995 1 9'~16 19'="7 1 ':;1'):::: 1999 2000 ::::001 :;::00:2 200:::: 2004 ::;:'oo~; 200.';. 2007 200':- 2010 :::011 2(! 1:2 2013 :::014 201 '::i 2016 2017 201:::: :20 1 '~I 2020 2021 20:2:2 2024 :::O~)6 2027 :2():2~:=: OA~::DNA/GUL.J:::ANf-\ ::::ITE NO. :::: KWH/YEAR CAPITAL 0 & M 4520000. 101 ::::::: 17. 1 ~j5300. 4 :=;20000. 1 (I 1 ::::::: 1 7 • 15~5300. 4'520000. 101 :::::::: 1"' • 155:300" 4520000. 1 0 t::;:!:~H '7 • 1. ':;::;::::00. 4520000. 101 ::::::;! 1 7. 15"Y::OO. 45:20000. 1 (I 1 :::::: 17. 155::':('(). 4520()OO. 101 :;::::::: 17 • 1 ~i::;:~:(I(,. ",V5:?OOOO. 1 U 1 :::::::: 1. 7 • 1. ~i::i::::O(l. 4520000. 101 :::::: 17. 155::::00. 4520000. 1018817. 155300. 4520000. 101 ::::;:: 1 7. 155300. 4 :i:~:OO(lO. 10 H:f: 17. 155::::00. 45:20000. 101 ::;;::::: 1 7 • 155::::00. 4520000. 1018817. 1.55300. 4520000. 1 (I 1 :::::: 1 7 " 155::':00. 4520000. 1018817. 155300. 4520000. 1018817. 155300. 4",i20000. 1 (II :3:::: 17 • 155300« 4520000. 1018817. 155300. 4520uOO. 10]8817. 155300. 4520000. 101 :=:::::: 1 7. 1 ~i:i::':OO. 4520000. 101 :=.:::;: 17 . 155300. 4520000. 1018817. 155300. 4~)20000. 101 ::::::: 1 7. 1 ~;530' :' . 4520000. 45~'i )000. 4520000. 45:;;::0000. 45?(jOOO. 4~5:20000 . 4'::;20000. 452;)000. 4'520000. 4520000. 45:20000. 4520000. 452(lOOO. 4520(100. 4520000. 4520000. 452(i()(lO. 4''5:20(100 « 4520000. 4520000. 4520000. 10 1 :~::::: 17 • 1 ~j'5JOO. 101 :::~7.: 1 :7 • 1 :i~i3()(I. 1 (l U::::: 1 '7. 1. ':;~5::::(h) " 101 ::::::;:: J. 7. 1 :;i5:::0n. 10]8817. 155300. 1') 1 :~:81 7 • :I '5 ':i'3 0 (I " 1 (I 1. f:::: ] 7. 1 '5 1:;300 . 1 (I 1 :::;:;: 1 7 • 155300. 1018817. 155300. 1 (I 1. :3:::: 1 7 . 155';::!)(!" 1. 0 1 ::;::::: 1. 7. 1 55:300 • 10U:::317. 155:300. 1018817. 155300. 1018::: 1 7 • :l 5~5:300. 101 :::::: 17" 155::::00. 1 01881 7 • 155:300 . 1 (I 1 :::::31 7 • 1. r55:::00. 1018817. 155300. 1018:::: 1 ? . 1 :'i!:i·:::no. 101 :;:::::; 1 7 • 15~)::::OO • 101 ::::::: 1 7 • 1 55:~:no. 2029 4520000. 1018817. 155300. 20:::0 45:;;::0000. 101::::G17. l5~;::::OO. AVERAGE COST $/r::WH $ ll<I,.JH TOTALS NONDISC DISC 1 1 :; 4 1 1 7 . 0 • 2 :~. (I O. 1 '~14 1174117. 0.260 O. 1::::0 1174117. 0.2AO O,~67 1174117. U,2.:,u ('.15:. 1174117. 0.260 0.144 11741 17 . C. '2 (:,() O. 134 1174117. (). ;o/:,() o. 12~", 1 1 / 4 1 1 7 • U • ~:-(-, U (). 1 1 r;:. 117411.1. O':/'~"() 0.10:: 11 /'4117. (I, .. ~/,(l (i. "I. no 1174117. 0.260 0.093 1174117. 0.260 0.086 1174117. 0.260 0.080 1174117. 0.260 0.074 1174117. O.~AO 0.069 1174117. (I.2~O 0.064 1174117. () .. :::"1:.0 o. (1(;,0 1174117. O. ~:'hO O. (i~::il:, 11'4117. 0 .. ::.~;\() O. U5:? 1174117. 0.260 0.048 117411'7. (;. :2 (-,(I O. 04 ~:"i 1114117. ().:/t·,(j O.'i~l 117,:;'11', O.:~6l) O.():::::';: 117411/. ')./i~.(1 O,U:3/~, 11.7 ':1117. 117 ,+117. 117'-+11.7. 1174117. .1]74117, 1174117. 117q.l1'1. 117,1-117. 1174117, 1174j17. 1174117. 117'll17. 11:/·H17. 1174117. 1174117. 117·4117. 1174117. 1174117. 1174117. 11}411.7. 1174117. 1174117. 1174117 o , .. 'i·,() ,") -/.(: .. () (I.? I,(i O.?bO O. ::;':60 O. ?r:,O o .,)f-.n o. '::'/~,n ,"). :?/·,t) 1)" :?I"() o ,;:'-~;(l I). '~>,(l (i, .? t:,() I.)" ',;,~ I'~'I ( :; o. !.<=.::::: o. O'~: l O. (),?,) (l. (,"! o. v:::::.:: C'. 021 0.02(1 0.01 ::! 0.01'/ O.Olh () • I.) 1. ~~~ <), {'14 0.01:::: (I. (i 1 ::::: 0.011. 0.010 0.010 0.009 0.00:=: (I.OOH 0.007 0.007 0.05(::, BENEFIT-COST RATIO (5% FUEL COST ESCALATION): n., 260 <). ':;:0;.,1) O. :;'6() (I •. :y~,(l O.2(:.() O. 'i'60 ;.l. 2~~,O O. '?bO 1.::9 J FROM U. S. G. S. -VALDEZ 1:250,000 o E3 H SCALE IN MILES LEGEND • DAM SITE • POWERHOUSE o SrTE NO. -----PENSTOCK ---TRANSMISSION LINE' ---WATERSHED HYDROF'OWI:::R PRO.IECTS ALASKA HYtR>POWER SITES IDENTIFIED IN PREUMINARY SCREENING KENNEY LAKE DEPARTMENT OF THE ARMY AlASKA DISTRICT CORPS OF ENGINEERS l! 1 " Hydropower Potential Si te No. 1 Installed Capacity (kW) 394 Demographic Characteristics 1981 Population: 100 SUMMARY DATA SHEET DETAILED INVESTIGATIONS KENNEY LAKE, ALASKA Install ed Cost ($1000 ) 5,042 Cost of Al ternal'/" ve Power_ (mills/kWh) 362 1981 Number of Households: 29 Economic Base Unknown 11 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower (mill s/kWh) 282 Benefit/Cost Ratio 1. 28 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL HJVEi'HQRi & RECOtWA ISAi'JCE STUDY -SMALL H Y [I RO POW E t:: F'F':O.JEC T S ALASt<A DISTRICT -CORPS OF Er~GH~EERS LOAD FORECAST -i\Ei'Ji'JE Y LAi<E KILOWATT-HOURS PER YEAf\: Ai'HJUAL PEAr': [lEMAi'HI-t~W ·{EAF: LOW MEIIIUH HIGH LOW MEDIUM HIGH 1980 428571. 428571. 428571. 147. 147. 147. 1981 443636. 443636. 443636. 152. 152. 1::;.:;:. 1982 458701. 458701. 458701. 157. 157. 157. 1983 473766. 473766. 473766. 162. 162. 162. 1984 488831. 488831. 488831. 167. 167. 167. 1985 51)3896. 503896. 503896. 173. 173. 173. 1986 518961. 518961. 518961. 178. 178. 178. 1987 534026. 534026. 534026. 183. 183. 183. L988 549()91. 549091. 549091. 188. 188. 188. 1989 564156. 564156. 564156. 193. 193. 193. 1990 579221-579221. 579221. 198. 198. 198. 1991 593341. 614049. 634756. 203. 210. 217. 1992 607460. 648876. 690292. 208. 222. ,-. .;.·..)0. 1993 621580. 683704. 745827. 213. 234. 255. 1994 635700. 718531. 801363. 218. 246. 274. 1995 649819. 753359. 856898. 223. 258. 293. 1996 663939. 788186. 912433. 227. 27(j. 312. 1997 678058. 823014. 967969. 232. 282. 33i. 1998 692178. 857841. 1023504. 237. 294. 351. 1999 706298. 892669. 1079039. 242. 3()6. 37\) • 21)00 720417. 927496. 1134575. 247. 318. --,-:: ~i:; l' .. 2001 734977. 969413. 1203849. 252. 332. 412. 2002 749537. 1011330. 1273123. 257. 346. 436. 2003 764098. 1053247. 1342396. 262. 361. 4.!)'') • 2004 778658. 1095164. 1411670. 267. 375. 483. 2005 793218. 1137081. 1480944. 272. 389. 5!)7. 2006 807778. 1178998. 1550218. 277. 404. 531. 2007 822338. 1220915. 1619491. 282. 418. C"c-= ...J.J...J • 2008 836899. 1262832. 1688765. 287. 432. 578. 2009 851459. 1304749. 1758039. 292. 447. 61)2. 2010 866019. 1346666. 18.27312. 297. 461. 626. 21)11 885092. 1373456. 1861818. 3,j3. 470. 6.38. 2(j 12 9(.'4165. 1400245. 1896324. 310. 480. 649. 2013 923239. 1427035. 1930830. 316. 489. 661. 2014 942312. 1453824. 1965336. 323. 498. 673. 2015 961385. 1480613. 1999841. 329. 51)7. • -c-clj·J. 2016 980458. 1507403. 2034347. 336. 516. 697. 2017 999531. 1534193. 2068853. 342. 525. 709. 2018 1018605. 1560982. 2103359. 349. 535. 7;211. 2019 1037678. 1587772. 2137865. 355. 544. 732. 2020 1056751. 1614561. 2172371. 362. 553. 744. 2021 1069453. 1636218. 2202984. 366. 560. 754. 21)22 1082156. 1657876. 2233596. 371. 568. -."" /O..J+ 2':)23 1094858. 1679533. 226421)9. 375. 575. --c-/ /.J. 2(j24 1107561. 1701191. 2294821. 379. 583. 786. 2025 1120263. 1722848. 2325434. 384. 590. 796. 2026 1132965. 1744505. 2356046. 388. 597. 8\)7. 2027 1145668. 1766163. 2386659. 392. 605. 817. 2028 1158370. 17878.20. 2417271. 397. 612. 828. 2029 1171072. 1809477. 2447884. 401. 620. 838. 203() 1183775. 1831135. 2478496. 405. 627. 849. KENNEY LAKE SITE 01 SIGN IFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Tonsina River Tributary Section 12, Township 3S, Range 3E, Copper River Meridian Community Served: Kenney Lake, CVEA Distance: 9.4 mi Direction (community to site): Southeast Map: USGS, Valdez (C-3), Alaska 2. HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: 6. Diameter: Length: POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSM ISS ION LI N E Voltage/Phase: Terrain:Y Flat (1.0) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown Y Terrai n Cost Factors Shown in Parentheses. 7.8 4.1 13 sq mi cfs in Large Concrete Gravity 15 ft 2405 fmsl 600 cu yd Concrete Ogee 5 ft 17 ft 2400 fmsl Steel Penstock 12 in 6300 ft 2 Pel ton 1370 937 394 6.2 0.6 4.3 14.4 2.7 2.7 48 1657 fmsl ft kW cfs cfs mi kV /1 phase mi mi percent MWh Flow Duration Curve PENSTOCK ............. TRANSMISSION LINE • POWERHOUSE : ~ ~* ...... -;~ ~"< '~<'>"" DRAINAGE BASIN " , _ 4 .' ~ ~~, ,... REGIONAL INVENTORY & RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA KENNEY LAKE SITE 01 CONCEPTUAL LA YOUT TONSINA RIVER tRIBUTARY DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF GINEERS HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Kenney Lake Site: 01 Stream: Tonsina River Tributary ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 15 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 181,000 $ 179,000 $ 200,000 $ 221,000 $ 30,000 $ 19,000 $ 168,000 $ 65,000 $ 68,000 $ 1,211,000 $ 182,000 $ 1,393,000 2.3 $ 3,203,000 $ 801,000 $ 4,004,000 $ 601,000 $ 4,604,000 $ 437,000 $ 5,042,000 $ 12,800 $ 394,400 $ 70,000 $ 464,400 $ 0.28 1.28 REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS {EAR 19::;;:4 1 '~t:::(:. 19::::7 19::::9 1990 1991 1 '~J'::'3 1994 1~J'~I~i 1991;;. 1997 1 ';' .":,'::, 2000 2001 2002 200:;: 2004 2005 2006 2007 2 ()c)::! 2 ()(}';J 2010 2011 2012 201J 2014 :2015 2016 2017 2()1 ::: 201<::' 2020 2021 2022 :2 c) 2:::: 20::'4 2()2~; 2()2,~, 2030 DETAILED RECONNAISSANCE INVESTIGATIONS COST OF HYDROPOWER -BENEFIT CO~T RAllO KENNEY LAf<E ~=;ITE NO. 1 VWH/YEAR 1657000. 1(:.57000. 1657000. 1657000. 1657000. 1657000. 1,:':;.57000. 1657 000. 1657000. 1657000. 1657000. 1657000. 1657000. 1657000. 16570i )l) • 1657000. 1657(>00. 1657000. 1657000. 1657000. 1657000. 1(:,57000. 1657(100. 1657000. 1657000. 1657000. 1657000. 1657(>00. 16~,7000. 1657(>00. 1657(>00. 1(:.57000. 1657000. 1657000. 1l~/5700i). 11.:,57(i(H) • 1657000. 1657000. 1657000. 16::',7000. 16':i70')0. 1 (:.57000. 1657000. 16':;7000. 1657000. 16'57000. 1657000. CAPITAL :;:'~'7007 • ::::';'7007. :397007. 397007. ::::97007. :;:','700"/ . :.::':;']007. 397007. 397007. 397007. ::::'::'J7007. 397007. :3';'7007. 397007. 397(H)7. 397007. ::::<::17007. :3970(0. ::::97007. 397007. 397007. ::::97007. 3';'7007. ::::97007. 397007. '3'~)7()()7 • 397007. ::::97007. ::::97007. :397007. ::::9700 7 • 397(>07. :::97007. ::::';'70('7. ::::'~'7007 • :;:970()7. ::::97007. 3970(>7. 397007. 397007. :;: .;:.? 00 " . ),'~'7001 • :::970()' . :31~)7()()·/ l\ Y:7007. :397007. (I a( M 70000. 70000. 70000. 70000. 70000. 70000. }OOOO. 70000. 70000. 70000. 70000. 70000. /0000. 70000. 7iXH)O. 70000. lOO!)!). 70000. 70000. 70000. 70000. 70000. 70000. 70000, 70000. 70000. 70000. 70000. 70000. 70000. 70000. 7 o ()() 0 • 7 (l(H)(' • 70000. 70000. 7000'). "lO(H)n. 70000. 70000, 70000. 70000. "70000. 10000. 70000. 70000. 70000. 70000. TOTAL ;. 467007. 467007. 467007. 467007. 46}O(l7. 467(H)l. 4670(;',7, 4/;.7007. 4/:.700"7. 4670(0. 4670('7. 4670(,7. 4/:.700"7. 4·/::/(J07. 46'J007. 4670n ,7 • 4(-.7007. 4670(>7. 467001. 4(:.7007. 467007. 467()07. 467007. 467007. 46700}. 467007. 467007. 467007. 46700 7 , 467007. 467007. 467007. 4/:·?OY7. 4/:::00;> • 4670(,~7 , 4 (-:h)n7 « 4.1:.7007. 4/:,7007. 4!~.7')07 • 46700"7. 467007. 467007. 4670(f? . 4,::."7,)·)" • 4(:, 7()()) • 4670( 7. $n::wy $/rWH ~·jl)N[t I ':;C It I::'C O. :::::::2 O. 1 ':'/~i (i. 2:::2 O. 1 ':: 1 (;. 2:::\2 i) II 12(:, (J. ~::::2 ('.~. 1 "I O. ?::::;:: ,)" 1 (l:~: () •. 2:-::.,2 () It 1 () 1 (). ::;'::: ,~: < ~ I}:::; 1 (). :::'!::2 ':) r ()75 () II _2::;:2 ()" t)/() (1 t, 2:~:~.' i j .. ,~)t,5 (J. ·~:::2 (). ()I::'C) i). 2:::~:: n. u5.::· () II 2:::;~ I) ~)4~~ (). 2::::2 I). ~)42 (l. ·:'::!2 (). ~):3'~J () 11 2;:;:::2 () • ():3(:t (). 2::;'2 (} ()::;::3 0.2:::2 0.0::::1 ().282 (). ()21~) O. 2:::::' O. 027 0.2:::2 0.025 c) • .2:::::' I). ()2(> (>" ,:~::; ~'2 c~ " ,) 1 '~I I). 2:::::2 (, • l) 1 7 0.2:::2 0.011:. () It 2f::2 n " ~.) 1 ~; O.2B',2 i),014 O. :;:'::::2 0.01:3 0.282 0.012 0.28"2 0.011 o . :,,::=: 2 I) • 010 (). 2~~~:2 ' .. t) 1 () 0.2:::2 (;. r)()7 0.2::::2 O. -)6·1 NOTE: TOPOGRAPHY FROM U. S. G. S. -CORDOVA ALASKA, I: 250,000 LEGEND .. DAM SITE • POWERHOOSE o SITE NO - - - --PENSTOCK - - -TRANSMtSSION LINE --WI4TERSHED "~ (';:~ 5 0 5 E3 1--1 E3 SCALE IN MILES REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING MEAKERVILLE -EYAK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET DETAILED INVESTIGATIONS MEAKERVILlE-EYAK,!/ ALASKA H~dro~ower Potent; a 1 Installed Insta 11 ed Capacity Cost Si te No. (kW) ( $1000) 6 905 5,556 Demographic Characteristics 1981 Population: Meakerville -300 1981 Number of Households: 86 Economic Base Economic activities tied to Cordova Cost of Al ternati ve Power.£/ (mi 11 s/kWh) 398 11 Communities have been annexed by Cordova. 21 5 Percent Fuel Escalation, Capital Cost Excluded. Cc st of l1Y dropower Benefi t/Cost (lili 11 s/kWh) Ratio 101 3.95 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY & RECONNAtSANCE STUDY -SMALL HYDROFOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS ·'I'EAR 198(' 1981 1982 1983 1984 L985 1986 1987 1988 1989 1990 1991 1'192 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 20~)9 2010 2011 2012 2013 2014 2015 2')16 2017 2018 2019 2020 2(j21 2()22 2023 2024 2,)25 2026 2\)28 2029 2030 LOAD FORECAST -MEAKERVILLE KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 1285714. 1330909. 1376104. 1421299. 1466494. 1511689. 1556884. 16~j2079 • L647274. 1692469. 1737664. 1780023. 1822382. 1864740. 1907099. 1949458. 1991817. 2034175. 2076534. 2118893. 2161252. 2204933. 2248613. 2292294. 2335974. 2379655. 2423335. 2467016. 2510696. 2554377. 2598058. 2655278. 2712498. 2769717. 2826'?37. 2884157. 2941377. 2998596. 3055816. 3113036. 3170255. 3208362. 3246469. 3284575. 3322682. 3360789. 3398896. 3437002. 3475109. 3513216. 1285714. 1330909. 1376104. 1421299. 1466494. 1511689. 1556884. 1602079. 1647274. 1692469. 1737664. 1848640. 1959617. 2070593. 2181569. 2292545. 2403522. 2514498. 2625474. 273645~) • 2847426. 2981756. 3116085. 32504L5. 3384744. 3519074. 3.:)53403. 3787733. 3922062. 4056392. 4190722. 4273511. 4356299. 4439088. 4521876. 4604665. 4687453. 4770242. 4853030. 49358L9. 501861)7. 5086388. 5154168. 5221949. 5289729. 535751\) • 5425290. 5493071. 556085 L • 5628632. 5696412. 1285714. 1330909. 1376104. 1421299. 1466494. 1511689. 1556884. 1602079. 1647274. 1692469. 1737664. 1917258. 2096851. 2276445. 2456038. 2635632. 2815225. 2994819. 31744L2. 3354006. 3533599. 3758578. 3983557. 4208536. 4433515. 4658494. 4883473. 5108452. 5333431. 5558410. 5783387. 5891744. 6000101. 6108458. 6216815. 6325172. 6433529. 6541886. 6650243. 6758600. 6866958. 61'64412. 7061866. 7159320. 7256774. 7354228. 7451682. 7549136. 7646590. 7744044. 7841498. ANNUAL PEA~ DEMAND-Ki LOW MEDIUM HIGH 440. 456. 471. 487. 518. 533. 549. 564. 580. 595. 61(j. 624. 639. 653. 668. 682. 697. 711. 726. 74\) • 755. 770. 785. 800. 815. 83\) • 845. 860. 875. 89\} • 909. 929. ';49. 968. 988. 1007. 1 \)27. 1')47. 1066. 1086. 1099. 1112. 1125. l138. 1151. 1164. 1177. 1190. 1203. 1216. 44~) • 456. 47 L. 487. 5'.)2. 5i8. 533. 549 .. 5·~4 . 58l) • 595. .!>33. 67l. 709. 747. 785. s:n. 861. 8';9. 937. 975~ 1021. 1067. 1 L L 3. 1159, 1205. L 25 L • 1297. 1343. 13i~'i • 1-435. 14.';)4 • 1492. 152\} • 1549. 1577. 1605. 1634. 1662. t690. 17L9. 1742. 1765. 1788. 1812. 1835. 1858. 1881. 1904. 1928. 195 L. 4-'4\; + 456. 471. 487. 5tj2 ~ 5i8. 533. 549. 564. 58\} + 5'~~~ ~ .0::' ./ • 7i8. 78() . 84 L • 9\)3 • 964. 1087. 114·? • 121 .. ), 1287. 1364. 1441 .~. .L5i8 L,~72. 174';. 1827. 1·il)4. l q:31 • :;~") 1 ~3 .. 2()55. 212.;. 2 1.:S6 • 221)3. 2240. 2315. .2352. 2385. 2418. 2452. 2485. 25l9. 2552. -.• -C' ,,:,olj·J. h E (j I ()i"~ A L INIJnJTORY &. ~:ECONNA I SArJCE STUDY -SMALL H'y'[lROF'OWER F'ROJECTS ALASt,:A DISTRICT -CORPS OF ENGH~EERS LOAD FORECAST -EYM, r;: I LOWATT -HOURS PER ''(EAR ANNUAL F'EAr< DF.MAND-KW 'lEAF: LOW MEDIUM HIGH LOW MEIIIUM HIGH 1981j 12857. 12857. 12857. 4. 4. 4. 1':t81 13309. 13309. 13309. 5. 5. 5. 19E$2 13761. 13761. 13761. 5. 5. .,. ...J • L Ci:;::3 l4213. 14213. 14213. 5. 5. :,.. 19:34 14665. 14665. 14665. 5. 5. c:" ,_f. 1985 15117. 15117. 15117. 5. 5. c:" ...J. 1986 15569. 15569. 15569. 5. 5. .,. ..) . [987 16021. 16021. 16021. t:' ...J. 5. .,. . ..J • J.988 16473. 16473. 16473. 6. 6. 6. 1989 16925. 16925. 16925. 6. 6. 6. 1':;'91} 17377. 17377. 17377. 6. 6. 6. t ,,.9 t 178\)1. 18487. 19173. 6. 6. 7. L992 18224. 19596. 20969. 6. 7. / . 1993 18648. 20706. 22765. 6. 7 .. 8. 1994 19071. 21816. 24561. 7. / . 8. L'7'95 19495. 22925. 26357. 7. Eh 9. 1996 19919. 24035. 28152. 7. 8. 1 \) • 1997 20342. 25145. 29948. 7. 9. 1'·) • l'i98 20766. 2.!>255. 31744. -/ . 9. 1!. 1999 21189. 27364. 33540. 7. 9. li. 20(iO 21.~13 • 28474. 35336. 7. 10. 12. 2001 22\)51). 29817. 37586. 8. 10. 13. 2\)02 22487. 31161-39836. 8. 11. 14. 2':)\)3 22923. 32504. 42085. 8. 11. 1,j • 2004 23360. 33847. 44335. 8. 1 -, ,;.., 15. 2',)05 23797. 35191. 46585. 8. 1 ~, ,;.., 16. 200e. 24234. 36534. 48835. 8. 13. 17. 2\}07 24671. 37877. 51085. 8. 13. 17. 2008 25107. 39220. 53334. 9. 13. 18. 2009 25544. 40564. 55584. 9. 14. 19. 2010 25981. 41907. 57834. 9. 14. 2') • 2011 26553. 42735. 58918. 9. 15. .....-...1) • 2\) 12 27125. 43563. 60001. 9. 15. 21. 21} 13 27698. 44391.. 61085. 9. 15. 21. 2(114 28270. 45219. 62168. 10. 15. 21. 2'il5 28842. 46046. 63252. 1~) • 16. -, -; ...:....:.... :;-:1)16 29414. 46974. 64336. 10. 16. .r:.:..:. 2017 29986. 47702. 65419. 10. 16. 2/+ 201.8 3Q559. 48530. 66503. 10. 17. ..,-,;...:, . 2',)19 31131. 49358. 67586. 11. 17. ..,-,;...:, . 21j20 31703. 50186. 68670. 11. 17. 2l} • 2()2t 32l)84. 50864. 69645. 11. 17. " ..,:.."4. 2()22 32465. 51542. 70619. 11. 18. 24. 2(,23 32846. 52219. 71594. 11. 18. 25. 2')24 ~33227 • 52897. 72568. 11. 18. -,t:' ,.,;.;;".:}. 2025 33608. 53575. 73543. 12. 19. 25. 2~)26 33989. 54253. 74517. 12. 19. 26. 2027 34370. 54931-75492. 12. 19. ". ...0. 21)28 34751. 55608. 76466. 12. 19. 26. ~()29 35132. 56286. 77441. 12. 19. -,-: • ...' 21:'3~j 35513. 56964. 784L5. 12. 20. ' , .:... J .. MEAKERVILLE/EYAK SITE 6 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Robinson Falls Creek Secti on 7, Townshi p 14S, Range 2W, Copper Ri ver Meri di an Community Served: Meakerville, Eyak Distance: 9.5 mi Direction (community to site): South 2. 3. Map: USGS, Cordova (C-5), Alaska HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: DI VERS ION DAf~ Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Opening Height: \Ji dth: Crest Elevation: 5. WATERCONDUCTOR Type: 6. Diameter: Length: POWER STATION Number of Units: Turbine Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow: Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vol tage/Phase: Terrain:.!! Rolling (1.25) Tota 1 Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. Et~V IRONMENTAL CONSTRAINTS: Unknown !/ Terrain Cost Factors Shown in Parentheses. 1.7 13.2 160 sq mi cfs in Low Concrete Gravity 10 ft 810 fmsl 160 cu yd Stairstep Fish Ladder 5 ft 17 ft 805 fmsl Steel Penstock 16 in 2600 ft 2 Pel ton 50 674 905 19.8 2.0 0.5 fmsl ft kW cfs cfs mi 14.4 kV/ SWGR 13.1 mi 13.1 mi 64 percent 5074 MWh Plant Factor Program /'"'""". DAM PENSTOCK TRANSMISSION LINE POWIRHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAtSSANCE STUDY SMAU HYDROPOWER PROJECTS SOUTHCENTRAl ALASKA MeA~ERVILLE/IYAK SITE O. ·CONC&9-TUAL ·LAVOUT ROBINSON FALLS . CREEK · DEPARTMENT OF THE ARtK'f ALASKA DISTRICT CORPS OF ENGINEERS NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY PLANT FACTOI< PROGKAI-1 cor'1~IUNITY: MEAKERVILLE-CORDOVA ELECTRIC SITE NUMOER: 6 NET HEAD (FT): 674. OESIGN CAPACITY (KW): 905. MINIMUM UPERATING FLOW (1 UNIT) (C FS) : 2.00 LOAD SI,f,P E FACTORS: 0.75 0.94 1.10 1.21 HOUR fACTORS: 24.00 18.00 12.00 6.00 MONTH (#DAYS/MO.) AVERAGE POTENTIAL PERCENT ENEI<GY USAblE MONTHLY HYUROELECHIC OF AVERAliE DEMAND HYDRO FLOW ENERGY ANNUAL ENEKGY ENERGY (CFS) GENEKATION (KWH) (KWH) JANUARY 4.67 159047. 8.48 2221760. 159047. rEBKUARY 5.65 173802. 8.30 2174600. 173802. MARCH 4.06 138272. 8.63 2261060. 138272. APRIL 7.36 242575. 8.60 2253200. 242575. MAY 2U.20 673320. 8.33 2182460. 673320. JUNE 25.00 651600. 7.55 1978100. 651600. JULY 18.00 613030. 9.35 2449700. 613030. AUGUST 14.70 500641. 9.62 2520440. 500641. SEPTEMBER 21.9U 651600. 7.58 1985960. 651600. OCTOeER 19.40 660710. 7.49 1962380. 660710. I'IOVEI"lBER 11.80 388911. 7.55 1978100. 388911. DECEMI:lER 5.41 184250. 8.52 2232240. 184250. TOTAL 503775H. 26200000. 503775H. PLANT FACTUR(1997): 0.64 PLANT FACTOR(LIFE CYCLE): 0.64 HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Site: Stream: Meakervi 11 elEyak 6 Robinson Falls Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operati ons and Mai ntenance Cost at 1. 2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 48,000 $ 106,000 S 549,000 $ 312,000 S 30 ,000 S 19,000 S 169,000 S 8,000 S 287,000 S 1,528,000 $ 153,000 S 1,681,000 2.1 S 3,530,000 S 882,000 S 4,412,000 ~ 662,000 S 5,074,000 S 482,000 S 5,556,000 S 6,140 S 434,600 S 70,000 S 504,600 S 0.10 3.95 ~:';t-' .. :' J !Jt\l~jL. [i I'/EN ropy t( RECONNA I ~::;ANCE ::;TUDY -:::::MALL HYDROPOWER F'RO,JEC I '=. nU4:::;~:::A D I :::::TR I CT -CORP::; OF ENO I NEER:::; [':::':36 i .;:! .. :: .... ;- • 1. .<'.': 19:::9 l .;>:/{) '!. 'i .~, i 1 ':.1 ,~.1 ,:' 1. '-:"::.1 .. :: i ':::'9.':j. I '·/(:"::i 1 '::}'::! i:. '1 .~)-::}-/ :I .::!,::,:::: k:l(i(l? :::: i) I.) '.:.: . ..:·j,i)t) .. :{. ~:~l)() :::; ?(,1 U ,>, J 1 ;>i l.~· 2:(11:: ::?( ij 4 201(:· :> .• 1"7 II "1 ::;::(l>~ ,;::() ,~::: DErAIL~D RECONNAISSANCE INVESTIGATIONS COST OF HYDkOPUW~R-BENEFIT COST RATIO MEAKERVILLE-CORDOVA ELECTRIC ::::1 TE ~~O" 1.::. ~;; () :~,: 7 .,/ ~r !~/ • ~;():3 7 M75 1;) • ~5():3 7 75:::: If ':;0:::::775::: • 50:::;:7759. ~=~ () :~: 7 ~7 ~51:) • ~~ (),:j-/~7~~~'~1 0 ~51):~i '7 ?~5::::. ~; (J .:~:"/ '/ ~5';) • r:·'~).:::·?7~i~=: .. ~,():~:7'7~;':) • r~)()'3-?'75::: It ~~~I.):,'~ ? 75::! u ~;(),:~: '7~?~,'~" 1/ ':i():3'7'7~,::: ~ ':·():~:·7·75:~! 11 ~t():;~:.7 7~;:::" ~::,():~:'?'75:~: • ~~~():':::7'75:~: • ~5() :~~:;: ~i'~t~:: <t ~5(t',~:"7 '75'~J • !,:;{),~:7 ?~~.~)" ~5()::::'?'75j'iJ • 5()::::~7'75:;~: • ~5(),~~:~i'7~)::: It ~::i(},-:~~7-75:::~: II ~;J:)::::'? /~)t~) I'i ~:;():::::~/'/~i'~) • ~51:):3:7 /':Il~) <I :-;():'::~?-75::: It ~:i(/'~~: 7' 75'~) II ~i () :~: '/"? ~) :::~ • ':5 i )'? '}' 7::5~:::. ~l(!: ~~77::;t~) .. ~!t.')·~::·l'?~:5(;' M ~:~ () .~~ "/ 7 ~:i'} -'~ :::~) :,::! '/. ,/ ~~i !:: • 1::~(),3? ~7~;:::. ~1():~::'/'7~:i:::: ., ~:i().'"::7 7:i:;::: • CAPIT{4L 437479. 437479. 43747'). 43747';'1. 43747'!. 437479. 4::::7479. 4'37479. 4:~:7479 • .It:::: 7 479. 4:'::7479. 4:3747'::1. 4:::7479" 43747';'. 4:::P479. 437479, 4_~:/4 79. 4:::;:74]':) • 4':::7479 " 4:314l? 4::::7 479. 4:::7479. 437479. 437479. 4:::047';1 " 4:~:7479 • L~::'=:7 47':' • 4:37479. 437479. 4:3747-;1 " 4:~:7479 • 4-::~i479 . 4:T747\'. 4:3?4 7':'. 4:;: '14 l'i' • 4:374·79. "I·:::; /4 ?'~i. 4:3747':':', 4«7 4 "/ ':J • LV:! I 4-7':" • L~;::/47q • 1./ :~:"/ -4 7'~i. 4:'7479. 4:.::/4/'/ • 437479. o ~( M 70000. 70000. 70000. 70000 . 70000. 7000u. 70<)00. 7()OO(I, 70n!).) • /0000. iOOOO. 70000. '7 i)i)'')!). 70000. 7()(>OO. 70000. } (H)t)O • }")()(l() • 7'CHilli) , ~'(I(H)r) • 10(11)(1 • 7(10(10. looun. 70000, /0000. 'lO(liH). loon'l. 'JOr)(H) • 7(1000. 7(H)O(i. /(1)00. 70(1)1). 7(1()OO. ?'i)()()() • l()()OO. lO(HH). lO()(l(l. -/0000. 70(1(11) • /()(}uo. ". ,(li )f). 70(l1)(l. )O(l(lO. /O'i()O. 700')u. /' ('(H.li) • 70000. '$ II<WH $/~J,.IH TOTALS NONDISC DISC 507479. u. 101 0.07~ ~i07479. 0.101 (1,070 507 if 7';:-1. ;'j. 101 '.). O(:,~c'i 507479. 0.101 0.060 507479. O.10l 0.056 507479. 0.,o1 0.052 507479. 0.101 0.048 50741':':'. (),lOl o. ('4~; 507't/9. O. :1 (II U. i)4::? '::-i(l] 4 79. (l, 1 i) 1 i). (J':::9 ::iO 147'::-'. n. :I 0 1 !~;. 0:;:··;:, ~,O:1 479 • (l" J(l 1 ' )" '1:;: ::: 'jl)?479. O.10i. 0. u·::t 507479. 0.101 0.029 ~j()747'il. u.l.U1 (i. 0;(/ 507479. 0.101 0.025 507479. 0.101 0.023 507479. 0.1 01 O. 507479. 0.10] O.02~ ::. '.1 ~I 47-:;1 • ' '. ~ p 1. U. (I 1 .:, 5074/9. u,.lfll O.U1./ ~5 (I 1479 • (l, 1 ':/ t u. ' 1 1 i:-, '5 1 )7479. n. lui (I" ()1 '5 ::;O? 4 '/9. 0, Hl'I (I" (;.1 '-/. "':i07479. (1,,1!)1 (;, (11:;: ~:i()i'4 7';;'. 0.', (I 1 0" (j 1 ~~() l4'/ I:;:' " (-IT J () 1 () It () J 1. ')0 7 479. 1).1',)1 O. (.'ItO ::;0747'). '.'.lOl (l.Ule) <5(' llV/9 • ()" Hn (I. 0"'.::" ~Ot{\747'i1. ,), :I ut n. :.)()::: '~j()74l9. 0.1(11 (' .. (I(,!:-: ':i(;,:;'l/ ,~, , '.)" t ()., (, . ('('~i "",u7 479. (i .. 1 (H (). Oil} ~j, ;/4-7..;i .. ' j. 1 () 1 fl " n (j ./) 50/·4/9. n,.l(I:: 1).i)(I/·, 507479. 0.101 0.005 507479. O.lul o.oo~ 5u747~. 0.101 0.005 !::i074 79. U. 101 i). 004 ~i)7479. 0.101 0.004 ::,Ci <'t /9. O. 1. ( ) 1 (i. 00·" ::' '. ,7479 " ' i. I i) 1 U" (l( .;::: "'i l »'4 79. I}. 101 ! .• ry)::: ':i r)l 4 /9. ,j. 1. (I 1 (J. 00::;: ~=,014]'i'. (1.,l(lj 0.(10::: 507479. 0.101 0.003 . AVER.ZI,.GE COST • j (I 1 U. 022 BENEF If _.( I)ST RAT I (I (~5% FUEL co::::;r ESCALAT ION) : . ,)-:; NOTE: TOPOGRAPHY FROM U. S. G. S. -ANCHORAGE ALASKA, I: 2~,OOO LEGEND • DAM SITE • POWERHWSE o SITE NO -- ---PENSTOCK ---TRANSMISSION LINE --WATERSHED 505 E3 H H SCALE IN MILES REGIONAL INVENTORY I.i RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING ES KA -JONESVILLE -SUTTON DEPARTMENT OF THE ARM,,( ALASKA DISTRICT CORPS OF ENGINEERS H~dro~ower Potential Installed Capacity Site No. (kW) 6 3,306 SUMMARY DATA SHEET DETAILED INVESTIGATIONS ESKA-JONESVILLE-SUTTON, ALASKA Cost of Installed Al ternaI1ve Cost of Cost Power_ Hydropower (Z1000 ) (mill s/kWh) (mill s/kWh) 15,823 387 127 Demographic Characteristics 1981 Population: Eska -53; Jonesville -97; Sutton-76 Benefit/Cost Ratio 3.04 1981 Number of Households: Eska -15; Jonesville -28; Sutton -22 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. See Appendix C (Table C-8) for example of method of computation of cost of alternative power. ~EGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER P~OjECTS ~LASKA DISTRICT -CORPS OF ENGINEERS TEM,' 1:>:3 ,':" !. ':;:31 19(,:3: 19;34 19;35 l'?8tj 1 .:;' ;3:::; l >:j ~~';' l.:j<:/(;· 1'·?91 199~5 1·:;;f.t4 l'iq~; J.i7·96 1:?9 7 l':~98 1'?-?9 20(J! 21)02 20\j~.' 2')04 2lj~j!7J ":"',,}\) / 20~)a 20·.)9 2(11 .. } 201.1 2012 2014 . 2(t15 2':1 f..~ 2') 1·7 20J.8 2')19 2021 2(,22 2',)23 2024 2,)25 2026 202::i .2 ',)::3 (. LOAD FORECAST -ESKA ~ILOWATT-HOURS PFR YEAR LOW MEDIUM HIGH 22?143. 235127. 243112. 251096. 259',)81 • 267tj65. 275049. 283034. .291')18. 29'~')03 • 3';)6987. 314470. 321·?54~ 329437. 336l':f21. 344404. 351887. 3"':':9371. 36·:'854. 374338. 381821. 369538. 397255. 404972. 412689. 420406. 428122. 4.35839. 443556. 451273. 45899\) • 469099. 479208. 4;39316. 499425. 50Q 534. 5L9643. 529752. 539861. 549969. 5601)78. 5668LO. :573542. 580275. 587007. 59373', • 600471. 607203. 613936. 620668. 627400. 227143. 235L27. 243112. 25109.~. 259c)81. 267065. 275049. 283034. 2911.)18. 299003. 31.).S987. 325446. 3439\)4. 362363. :38\)821. 399280. 417739. 436197. 454656. 473114. 49L573. 513789. 536005. 558221. 580437. 602653. 624869. 647085. . S6930 1. 691517. 713733. 72793.1. 742130. 756328. 770527. 784725. 798923. 813122. 827320. 841518. 855717. 867196. 878674. 89015:<:. 901631. 91311\). 924588. 936067. 947545. 959024. 970502 • 227143. 235127. 243112. 25109.',) • 259081. 2670.55. 275()49. 283034. 291018. 299\)03. 306987. 336421. 365855. 395288. 424722. 454156. 48359\) , 5131)24. 542458. 571891. 601325. 638040. 674755. 711470. 748186. 784901. 821616. 858331. 895046. 931761. 968476. 986764. 1005052. L023340. 1041628. 11)59916. 11)78204. 1096492. 1114780. 1133068. 115L356. 1167581. 1183806. 1200030. 1216255. 1232480. 1248705. 1264929. 1281154. 1297379. L313604. ANNUAL PEAK DEMAND- LOW 78. 8 L • 83. 8·!) • 89. .~ 1. 94. 97. 1 O~') • 102. 1')5. 108. 110. 113. 115. 118. 121. 123. 126. 128. 131. 133. 136. 139. 141. 144. 147. 149. l52. 155. 157. 16.1. 164. 168. 171. 174. 178. 181. 185. 188. 192. 194. 196. 199. 2\) 1. 203. 206. 2\)8. 210. 213. 215. 78. 8 i • 8~. 86. 89. 91. 94. 97. 1 I)l). 11)2. 105. 111 • 118. 124. 13\) • 137. 143. 149. 156. 162. 168. 17.S. 184. 191. 199. 2 r)6 + 214. 222. 229 • 237. 244. 249. ::54. 259. 264. 269. 274. 278. 283. 28;3. 293. 297. 3l)1. 305. 31')9. 313. 317. 321. 325. 328. 332. HIij, 7;~ • 8 i • 83. ;3':;; • 91. 9/, + 1 I)'} • 1'):: • 1\)5. lLS. 125~ L:3=:. 145. 15.:) • 17.";' • L ;'3.~ • 1·~·~ • 2(tt) .. .:: L 9,~ 23 t + 24 -,c .... 1 • 29/~ .. 31)7. 3L9. 33;:s • 344. 351} • 357. 3.S3 • -,-,,!. ,!)'-y ." 37.':) • 38:3. 394. 41;\-) • 405. 4l1. 417. 422. 428. 433. 43;~ • 4~_. i ';,:':3') L ';'::;: L l. ':;;'13 ::: 1 :~:, ;:::::, 1 :;;. (;!.4 L:: ::" ~:' 1t ;;,~. 1 ';;-:;::':" ':;:3;:! 1 ;. ~:j ':,: 1 ;;,:;. :'5 L;;':;4 L,':;' ':,: 1?::i '~i 11"97 1'::;' ':;;;~: 1':;'9':;: 2')',] l ~:cJO '2 21-Jt:)~ .2 I.:, I.) ·4 :'.)I)~; 21.)(1.':) 20.)7 2(n)9 ,~I.) 1 \) 201 L 2 .. )J .2 ::';1) 1 :'5 :.».L :.l :;,) L '5 ::,-) L·~ 2C'1l :: ':.' 1. 8 2() 19 :I)~:~) ~EG[O~AL I~0E~TO~i i RECONNAISA~JCE S7UDY -SHALL HYDRQFOWER ~RQjECTS ALA5~A DISTRICT -CORPS OF ENGINEERS i_'JW ::':::2571.:1. ~ ... " '-.,:",~, I.) I.)i~ .:. • ---1-1" .~/ :) .~ .. 428759. 44'')20:3. 4'5(''::;':'59. 4t~t 1,~~, 7~) .. 4724')1 + 4:?'~3132 + 4938.~3 • ~31}4'59:'5 • :51.5324 + 5~5.-:) 78·-S, 547517. 5585:33 + 5.:;.9.-:)49 + 5:31.)714. 59178(1, 60284,~ • 613912. ~,24::;l78 • 63.5\)44. 6471\)9. 658175. 672671. ,;::,i37166. 716158. 73 1:",:)53 + 745149. 759.S44. 774140, 788636. 8 1,)313 1 • 812785. 822439. 84174.';', 85141)(j. ;361054. LOAD FORECAST -SUTTON M~I) I Uri ,~':'::;j/.L4. 337163. 348613. 3~~',)()"';'2 • 37L512. 382961. 39441~). 4'')5861) • 4173('9. 428759. ;14')2:(;8. 4.S6677. 49:'5146. 5L9.~15. !54.~08.t.j. • 572553. 5'~f:;'I')21 + . ::)2:5491} • 651959. 6 7:~428. 7\)4897. 736754. 7.b8611. 800468. 832325. 864t:31. 80;603.3. 927895. 959752:. 991609. 11)23466. 1 ('43826 + U}64186. 11)84546. 110491)7. 1125267. 1145627. 1165;;087. 1186347. 1206 7l)7 • t 227t),-S 7 .. 1243527. 12590;86. 1276446. 12929 1.)6. 1309:'5.';)5. 1325825. 1342284. 1358744, 13752\)4. ITt1663, HIGH 325714. 337163. 348.~13. 3.::)1)062. 371512. 382961. 3';4411) • 405860. 417309. 42875'::(. 441)208. 482415. 524622. 5.S6829. 6\)9036. 651242. 693449 • --r:::-'C'" " ',!)'J.!l,.J'~' 777863. 820070. 914925. 967573. 1\)2()221. 1072869. 1125517. 1178165. L230813. 1283461. 1336100;. 1388757. 1.414982. L4412\)6. L4674:'51. 1493655. L5 1';88('. 1546104. 1572329. 1598553. 1·';)24778. 1.S 5 1 I) I} 2 • 1674268. 1697533. 1720798. 1744064. 17.';)7330. 179')595. 1813861. 1:337126. 186('3';'2. 1 ~j83/S57 • ANNUAL ~EA( DEriAND-~W LOW MEDIUM HiGH 112. 112. it2. 115. 119. 1.:;::3. L::7. t::5 1 • L35. 1:'5':;:' • 143. 147. 15i. 154. 15;3. I. ,:,)2. 1.S5. 169. 176. 18',; , 184. 18;3. 10;:1. 195. 199. 203. 206. 21 ( ... 214. 218. 222. 23t) + 235. 24\} • 245. 250. 260. 27\) • 275. 278., 282. 285. 288. ,.. --.1.'fL.., 295. 298. 3':'1. 305. 3\)8. it5· lL ':;:.. 1:: '!: • 1..::;, " 131. IT5. 13:(, l,<l3, 147, 15t. 16(: . I. ,~':; • 1.78. 1 :37. 1 '1.';' • 214. , , . ...:. • ..;.. • ...1 ... 241. 285. 29,~'\ 3\;7. 318. 329, 34C; + 35i.. 3·:S l 1. 3 7 1. T:;':;:.. 4Ij.::, • 413. 42·,) , 4 2·!, • 432:, 437, 443. 448. 454. 47t. 477, 1l "5, 1 L:( , 123, 1:'7. 1:'5::- 13':;:' .. 1.<1',5. 1:.4; , 151, L ,S:: • ..:... ... -' '" 3l3, 331. 349. 3.";7 ... 441) • 4:58. 4 7.,;) • 4;35. 494. 5l):'5, t::' • -, . ..J l .:.. • ::...:1. 52':;:., 5:'58. 5·{~,7 .\ 5~~6 • 1 • 5';7. 6')5 .. 6l::E. .~:::: 1 • .*",J. ~ l + REGIONAL INVE~TORY i RECG~NAISA~CE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS LOAD FGF.:ECAST -JONESVILLE KILOWATT-HOURS PER YEAR ANi'WAL PEAi'; DEMAf.JlI-KI,.I"" rEAR LOW MErlIUH HIGH LOW MErlIUM HIGH 198·) 415714. 415714. 415714. 142. 142. 142. 1981 430327. 430327. 430327. 147. 147. 147. 1982 444940. 44494\) • 444940. 1~-' \:J~. 152. 152. 1983 459553. 459553. 459553. 157. 157. 157. 1984 474166. 47416.~ • 474166. 162. 162. 162. 1985 488779. 488779. 488779. 167. 167. 1.S 7. 1986 503393. 503393. 51)3393. 172. 172. 172. 198; 5180(,6. 518006. 518006. 177. 177. 177. 19fs8 532619. 532619. 532619. 182. 182. 182. L989 547232. 547232. 547232. 187. 187. 187. 1990 561845. 561845. 561845. 192. 192. 192. 1991 575541. 595628. 615714. 197. 204. 211 • 1992 589237. 629410. 669584. 202. 216. 229. 1993 ,~02933 • 663193. 723453. 206. 227. 248. 1994 616629. 696976. 777322. 211. 239. 26.~ • 1995 630325. 730758. 831192. 216. 25'.) • 285. 1996 644021. 764541. 885061. 221. 262. 3\)3. 1997 657717. 798323. 938930. 225. 273. -.--) ..)L.-:.. .. 1998 671413. 8321('6. 992800. 230. .:.:8::J. 340. t999 685109. 865889. 1046669. 235. 297. 358. 2\)00 698805. 899671. 1100538. 239. 3\)8. ..!' .. l .. 2001 712928. 940331. 1167734. 244. 322. 41)1) • 2002 727052. 980990. 1234929. 249. 336. 423. 2003 741175. 102165,). 1302125. 254. -~-.':',,JI) • 446,· 2004 755299. 1062309. 1369320. 259. 3.~4 • 46:~ 2005 769422. 1102969. 1436516. 264. 378. 4'?2. 2006 783545. 1143628. 1503711. 268. 392. SiS. 20',)7 797669. 1184288. 1570907. 273. 41)6. .,.--~l,)lj • 2008 811792. 1224947. 1638102. 278. 420. 561, 2009 825915. 1265607. 1705298. 283. 433. 584. 201 f,j 840039. 131)6266. 1772493. 288. 447. 6\)7. 2(111 85854() • 1332252. 18059.';)4. 294. 456. .~H$ • 2()12 877041. 1358238. 1839435. 3t")\) • 465. 6:3\) • 2013 895542. 1384223. 1872905. 307. 474. 641. 2014 914043. 1410209. 1906376. 313. 483. 653. 2015 932544. 1436195. 1939847. 319. 492. 6.~4 . 2016 951045. 1462181. 1973318. --" ~.:..o. 5r.) 1 • 676. 2017 969546. 1488166. 2,)06788. 332. 511) • 687. 2018 988047. 1514152. 2040259. 338. 5i'? 699. 2019 1006548. 1540138. 207373,) • 345. 527. 7l0. 2 tj20 1025049. 1566124. 2107200. 351. ~-. ,.J ·~o • 722. .2 'j21 1037371) • 1587132. 2136894 • -~-• ':';;;1:') • 544. ---, / .~.:. . 2 1.)22 104969l. 1608140. 2166588. 359. 551. 742. 2023 1062013. 1629147. 2196282. 3.';4. 558. -1:'-I ,J'::' • 2(}24 1074334. 1650155. 2225976. 368. I:"~ ,.JO·:! • 762. 2t)25 1086655. 1671163. 2255670. 372. ~"'"";.-, .,JI":;"+ 772. 2026 1098976. 1692171. 2285364. 376. 5i30. 783. 2027 1111298. 1713178. 2315058. 381. 587. 793. 2028 1123619. 1734186. 2344752. 385. 594. 81)3. 2029 1135940. 1755194. 237444,~ • 389. 6\)1. 813· ... ' 2030 1148261. 1776202. 2404140. 393. .!)08. 823 ESKA/JONESVILLE/SUTTON SITE 06 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Wolverine Creek Section 20, Township laN, Range 3E, Seward Meridian Community Served: Eska, Jonesville, Sutton, MEA Distance: 6.7 mi Direction (community to site): Map: USGS, Anchorage (C-6), Alaska 2. HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM 45.4 61.0 20 sq mi cfs in South Type: Large Concrete Grav; ty Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Voltage/Phase: Terrain:1! Flat (1.0) Ro 11 i ng (1. 25 ) Total Length: 9. ENERGY Plant Factor: Average Annual Energy Producti on: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrai n Cost Factors Shown; n Parentheses. 15 ft 1215 fmsl lOBO cu yd Conc rete Ogee 5 ft 95 ft 1210 fmsl Steel Penstock 42 ;n 11800 ft 2 Pe 1 ton 620 533 3306 91.5 9.15 2.3 38 1.0 0.5 1.5 fmsl ft kW cfs cfs m; kV /3 phase m; mi mi 39 percent 11295 MWh Flow Duration Curve " ROAD 14 I I I I I I I -.;.....----+--- I I I I I I I I I I REGIONAL INVENTORY & RECONNAISSANCE STUDY SMAll HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA ESKA/JONESVILLE/SUTTON SITE 06 CONCEPTUAL LA YOUT WOLVERINE CREEK DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS DAM PENSTOCK TRANSMISSION LINE POWERHOUSE DRAINAGE BASIN HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Site: Stream: Eska/Jonesville/Sutton 6 Wo 1 veri ne Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val ves and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Mai ntenance Cost at 1. 2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST ~ 319,000 ~ 1,623,000 ~ 1,378,000 ~ 506,000 ~ 812,000 ~ 33,000 ~ 290,000 ~ 35,000 ~ 81,000 ~ 5,077,000 S 508,000 ~ 5,585,000 1.8 S10,052,000 ~ 2,513,000 $12,566,000 ~ 1,885,000 ~14,450,000 ~ 1,373,000 $15,823,000 ~ 4,790 ~ 1,237,800 ~ 189,900 ~ 1,427,700 ~ 0.13 3.04 RE:Ci I UNAL_ I r I )EI'HORY ~, F<ETC)r·lr~A I ':;ANCE ':.TU[ly' -~:;M{:iU HY nf~I:IF'OWE Fe f~'f~'I=I,-'EI-T::, ALASKA DISTRICr -CORPS UF ENGINEERS DETAILED RECONNAISSANCE INVESTIGATIONS COST OF HYDRUPOWER -BENEFIT COST RATIO ESKA/JONESVILLE/SUTTON !::;ITE NO. I;. YEAR KWH/YEAR CAPITAL 1 ';;::::4 112'~'5000. 124590::::. 19:::'5 112":)5000. 124590::':. 1 9:::;(:, 112":~!':iOOO. 1245':;'0::::. 19:::7 1129~5000. l. 24':i90J. 1')::::3 1129'::iOOO. 124:i':;'03. 19::::9 112';'5000. 124590:'::. 1990 1129S00l). 124590::':. 1 ';"91 112'::!~:;000. 1 :245903. 19';'2 11295(100. 124':i90:::: • 19'::'3 11295000. 1 :;::4~,'~'O::::. 1 994 1129~:5000. 124':803. 1 ':;/';'':i 11295000. 1245903. l'::"::'I~, 112950r)0. 124~:i90::::. 1997 1129':iOOO. 124~~i'::'(l::;::. 1 ?9::: 112':'5000. 124':i9r)~:. 19';";' 1129':iOOO. 1 :24:i90:~:. 2000 112Q 5000. 124590::::. 2001 11295000. 124':i'::)(L3. 2002 11295000. 1245903. 200::;:: 1129':iOOO. 124590::':. 2004 11295000. 1245903. 2005 11295000. 1245903. 2006 11295000. 124590::':. 2007 11295000. 124590::':. ~~OO::: 11295000. 1245903. 2009 11295000. 124'::i';'0::::. :2010 11295000. 1245903. 2011 11295000. 124590:::. 2012 11295000. 124590::::. 201:;: 11295000. 2014 11295000. 2015 11295000. 2011;. 11295000. 2017 11295000. 201::: 1129':iOOO. 2019 11295000. 2020 11295000. 2021 1129':iOOO. 2022 1129':iOOO. 202:3 112':;'5000. 2024 11295000. 202':i 112':;'50(>0. 2026 11295000. 2027 11295000. 202:;::: 11295000. 20:29 11295000. 20::;::0 11295000. AV:SRAGE COST 124590:3. 1 :24::80::::. 1245903. 1 245'~/O:::: • 124~5':;/O:::: • 124590:~: • 124~?:'0:3 • 124~i90:3 • 1245903. 124590:3. 124~5903 • 124590:3. 124~i90:::: • 124:~1~"():~: • 124590:::;. 124':i90:::: • o 8( M 1 :::::9900. 1 f:9';'00. 1 :::9900. 1 :::::9900. 1::::9900. 1 ::::9900. 1:39900. 1 :::::9900. 1:::::9900. 1 :::':;'900. 1 ;::':)900. 1 ::::9900. 1 :::::9900. 1 :::::9900. 1::::99uO. 1 ::::9900. 1 ::::9'~'O(l. 1 ::::9900. 1 :::99(>0 1::::9900. 1 :::9';'00. 1:::9900. 1::::9900. 1 ::::9900. 1 :::':;"'900 • 1:::990U. 1:;::9900. 1 ::::9900. 1 :::'~'~/()(). 1 :::9';'00. 1:::::9900. 1:::::9900. 1 ::;:9900. 1::::9900. 1 ::::9900. 1:::::9900. 1:::9900. 1 ::::99()(>. 1:39900. 1 :::')900. 1:::9900. 1::::9900. 1:;:::9900. 1 :::::9900. j :::9900. 1 :::9900. 1 :::9900. $/KWH $/f:::WH TOTALS NONDISC DISC 143580J. 0.127 0.095 1435:::03. O. l27 (>. O:::::~: 14J5:::0J. 0.127 0.082 14:35:::0::':. 0.127 0.076 1435:::(>3. 0.127 0.071 1435803. 0. 127 0.06~ 14::':5803. 0.127 0.061 1435803. 0.127 0.057 1435803. 0.127 0.053 14:::':;:::(;:;:. 0.121 'J. ()LIS' 1435:::0::;:" (I. 127 (j .. Oil",:i 14J580J. 0.127 0.042 143580::':. O. l27 0.03 0 1435803. 0.127 0 .. 036 143<=;::'::0::::. (1. 127 (i. U::::4 1435803. 0.121 0.031 1435803. 0.127 0.079 143~i:':::O:;:. ('. 121 f). \Y?;; 1 'j";::~'i::::()::::. (I .. 1.:."7 U. (1·;":=· 14::::580~. O. ]27 0.023 14J580J. 0.127 0.022 143~i:::::O::::. O. t 2·7 (). 020 1435803. 0 .. 127 O.Ol0 14:::~:i:::::()::::. U. 1=::7 n, 01 7 14J5:::03. 0.127 0.016 1435803. n.127 0.015 l4::::~i:::O:~::. i;" 1 :~: l '.1.014 14:::::'j::::03" i). 1 )7· o. n 1 ::: 14 ·:::~i:::():: " (),' 1 ::.:? u. (> 1 ':~ 14::::':i::::cn. 14:::5::::i):::: • 14J:i::::() ~~:. 14:35::;:0:::: • 1435:::0:::: • 1435:::X>3. 143':i::::03. 1435:::0:::: • 14::::5:=:03. 14:3!,:;:::():~: • 1 '~::::5:::0:;:. 1 4 ::: ':i:X> :::: • 14:35::!():3. 14::::5:::03. 14::;::5:::0:;:: • 14:::5::::0:::: • 0 • .127').U:l.l O.T:?i (I.OlO O. l2? i).010 0.121 0.009 (I. 1. ::;::7 (>. OOf: O. l2? (1. no::: f).127 0.007 0.127 0.007 O.L::7 0.00(:, O. 12)' (>. O()6 (). i 27 U , OO~:; U.l::2/ U.I)r)5 U.1:.27 O.OO:i O. l :/1 U. 0(>4 (>. 127 (I. 004 0.127 0.004 O. J 27 O. (10:::: 0.127 0"003 (). 127 (). 0:::::: SENEF I T-CCI':;T RAT I 0 (:i~1.. FUEL CO!:;T E!:;CAU~:·l UN) : :::. (iLl / z.~--- 5 0 H t=1 E3 SCALE I N MILES NOTE: TOPOGRAPHY FROM U. S. G. S. -ANCHORAGE ALASKA, 1:250,000 5 ,,,'A," ,.,. ~ 1'1 " ' •• I~' 0 , •• 't '., ·:t l'· LEGEND ~ DAM SITE • POWERHOUSE o SITE NO. - - ---PENSTOCK - - -TRANSMISSION LINE ----WATERSHED REGIONAL INVENTORY &' REawNAlSSANCE STlD( SMALL HYDROPOWER PROJECTS SOUTHCENTRAl ALASKA tMR>POWER SITES IDENTIFIED IN PREUMlNARY SCREENING KNIK DEPARTMENT OF THE ARMY ALASkA DISTRICT CORPS OF ENGINEERS ttYdropower Potential Installed Capacity Site No. (kW) 3 14,504 Demographic Characteristics 1981 Population: 10 SUMMARY DATA SHEET DETAILED INVESTIGATIONS KNIK, ALASKA Installed Cost (nOaa) 35,045 Cost of Al ternaji ve PowerJ (mi 11 s/kWh) 387 1981 Number of Households: 3 Economic Base Unknown II 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of ttY d ropowe r (mill s/kWh) 66 Benefi tlCo st Ratio 5.88 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -~NIK i<ILOWATT-HOURS f'ER 'y'EAR ArmUAl f·EAr .. IIEHArHi -KW '(EAR lOW MEDIUM HIGH LOW iiEIIIUii HIGH I9::h) 42857. 42857. 42857. 15. 15. 15. i '?81 44364. 44364. 44364. 15. IS. l5. Ii:=] :: 45870. 45870. 45870. 16. 16. L .:) • 1'?83 47377. 47377. 47377. 16. 1,~ • 1 '~I . Fi:34 48883. 48883. 48883. 17. 17. 17. i'i85 50390. 5t)390. 50390. 17. 17. 1 "7 • I. 9:36 51896. 51896. 51896. 18. 18. 1:3. l'i87 53403. 53403. 53403. 18. 18. 18. 1988 54909. 54909. 54909. 19. 19. 1 <;'. 19:39 56416. 56416. 56416. 19. 1<;'. 1<;'. 199(' 57922. 57922. 57922. i" ... v. 2 .. ) • .:.~} .. 1 0 91 59334. 61405. 63476. 20. 21. ' , .......... i'::/92 60746. 64888. 69029. 21. -j~' 24+ """~. 1993 62158. 6837,) • 74583. 21. 23. 2·~ .. 1994 63570. 71853. 80136. -I"-J ~.;.. 25" 27 .. L995 64982. -C"'--' • I'J,~~O • 85690. 22. 2~~ • 199.:; 66394. 78819. 91243. 23" ...,-: .:... I • :3 i • l'i97 6780.:) • 82302. 96797. 23. 28. 1998 69218. 85784. 102350. 24. "')-... 'i t .j::1 • 1999 70630. 89267. 107904. 24. 31. 37. lO'iO 72042. 9275,). 113457. I::' .... .,J. 32 . 21)(·1 73498. 96942. 120384. ie:" ..... .J. 33. 41 • 2'),)2 74954. 101133. 127312. 20+ 35. 44. 2\)03 76410. 105325. 134239. " .:..0. 36 • 4.:) • 2('04 77866. 11')9517. 141167. i"'; 38. 4;~ • .... ' • 2 1.:t \)5 79322. 113709. 148094. 27. 39. e:" . ,,J I. • 2(,11)6 80778. 117900. 155021. 28. 4·). 53. 21.ji)7 82234. 122092. 161949. 28. 42. :::-::.J.j • 2008 8369\) • 126284. 168876. 29. 43. 5H. 20')9 85146. 130475. 175804. 29. 45. 6t} • 2') 1',) 86602. 134667. 182731. 31) • 46. 61. 2011 88509. 137346. 186182. 30. 47. 64. 2t:J12 <;'0417. 140025. 189632. 31. 48. 2')13 92324. 142704. 193083. 32. 49. 6.~ • 2.)14 94231. 145383. 196533. -, 5',) • 6'7 ~ .... . 2015 96138. 148062. 199984. 33. c:" ...J1. 6:"3 • 20L~ 98046. 150740. 203435. 34. c:"-, '-J..:.... 7i) • 2(j 17 99953. 153419. 206885. 34. c:"-...J'~ • 7 L • 2(}1:3 101860. 156098. 210336. -e:" ~...J. 53. 72. 2('19 103768. 158777. 213786. 36. 54. 71. 2')20 105675. 161456. 217237. 36. r:::::: ...J.J. 74. 2021 106945. 163622. 220298. 37. r::: ' .,jl';,. 2 t)22 108215. 165787. 223360. 37. c:"-,J I. 76. 2()23 109486. 167953. 226421. 37. 1:"-...Jl:j. -r /1":$ • 2ti24 110756. 170119. 229482. 38. r:::-.,j~. 79. 2()25 112026. 172285. 232543. 38. 5'~ • 8t} • 2 .. )26 113296. 174450. 235605. 39. 6t) • 8 i • 2\127 114566. 176616. 238666. 39. 6() • 8'2+ 2(128 115837. 178782. 241727. 40. 61. 83. 2·j29 117107. 180947. 244789. 40. 62. 84. 2(130 118377. 183113. 247850. 41. 63. KN IK SITE 03 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Willow Creek Section 34, Township 20N, Range 3W, Seward Meridian Community Served: Knik, MEA Distance: 22.5 mi Direction (community to site): North Map: USGS, Anchorage (0-8), Alaska 2. HYDROLOGY Drai nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: He; ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Uni ts: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/ Pha se: Terrain:1! Flat (1.0) Tota 1 Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: r~ethod of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrain Cost Factors Shown in Parentheses. 146 381 50 Large 17.5 9275 1300 sq m; cfs in Concrete Grav; ty ft fmsl cu yd Cone rete Ogee 12.5 ft 125 ft 915 fmsl Steel Penstock 90 in 11600 ft 2 Horizontal Francis 500 fmsl 374 ft 14504 kW 572 cfs 114.4 cfs 1.5 38 0.1 0.1 mi kV /3 phase mi mi 38 percent 48281 MWh Flow Duration Curve . , \./ ."" .... ..l.6' \ \:$'0 .,",' ' .. ", ""'~ ······29 .7 '. 32· '.. . .. • ) \ J -----------i- b I· o· ~L: I I I \ r \ I I I 6 I ~ . o. \"1 ) ,I \ ...... ~.::.:. ( I fi · \ I I f'-.. ~~ //. .. . 1 • ~ \ " "'1 () ---------- -------:-: --\~--.-.. ---~-. -~'.~--+ : I-yl' I \ ~ /;. '. I a · / I ("'~ '\ . ~.~"""'. '. "l" a I . \' / ~:. I' .. & /i '~~d. \~ru··· . i··· / : j' a \ .. '" \ I \ /0 .'. ", I . , 0\ 'JI Va' . J \ n t I ~ J:'r,1I I' I~ • I ! ~:" ..... - l~ 2 ... ,". " . . "". : :,.: .: : .. ~ •• # :./ : .. . .. ~ ." ........... : .' DRAINAGE BAStN . .. . ........ l.r r---REGIOHAl--~-INV9fTOR-'t-H-~-Y-NT-& RA-ReCMIAI-L-~-LSS:-K-A-S-TOO-Y-- J r----" -:11'1 r' J,..--C;--'~ KNIK IITI O' COMC.PTUAL LAYOUT . I I ! . ··rJ . : i ~ -----------r-----~- \ ····f--l /-;;0 i: DEPARTMENT OF THE ARMY o! .! AlASKA DISTRICT i I'l CORPS Of ENGINEERS ----=----------~!~.~~---------- WILLOW CfltllK HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Knik Site: 03 Stream: Willow Creek ITEM 1. Darn (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Switchyard 5. kcess 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 396,000 $ 5,039,000 $ 3,127,000 $ 849,000 $ 210,000 $ 11,000 $ 460,000 23,000 $ 5,000 $10, 120 t 000 $ 1,012,000 $11,132,000 2.0 $22,264,000 $ 5,566,000 $27,830,000 $ 4,175,000 $32,005,000 $ 3,040,000 $35,045,000 $ 2,420 $ 2,741,600 $ 420, SOO $ 3,162,110 $ 0.07 5.88 REJ~'InNALl',i\'E.IJlI'IPY ~, ;::;:ECulilJ:d'.,{~Ni~E ::.11,1.,'\ :'·"1,.1.1 II,CIII,F'CII,.Ji , IF,·O.IF, I ALASkA DISTRICT -CORPS OF ENGINEERS DET A I LETI HE CONNA I ~::~::;ANCE I NVE::;;;-r I GAT TOW:; CO~:;T OF f--!y[II:';:CIF'OWEF: --m:NET IT CCI::;;'T f;:f-~ TIl'l YEAR 1':)1::::4 1 ")::::!5 1 ':):~:6 1 '~i:::7 19:::::~: 19:~:9 19'::;'(> 1<:j91 1992 1 ')93 1 '~!'::)4 19';'5 1996 1997 1 9'~"~' 2000 2001 ::200:2 200:~:: 2004 2()()~:; :2()()i~-:. 2007 200::: 200';} 2010 2011 2012 201:3 2014 2015 :::» 16 2017 :::::01:::: 2019 2020 2()21 :2()22 2024 :2C>:27 VNI~::: ::nTE NO. KWH/YEAR CAPITAL 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 4:::2:;::: 1000" ::2 r:;'?44::. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 27594~3. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 4:::::2:::: 1 000. 27!::':i944:~::. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. ~759443. 48281000. 2759443. 48281000. 275 9 443. 48281000. 2759443. 482::: 1 000. 275944:::. 48281000. 2759443. 48281000. 2759443. 48281000. 27S9443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443, 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. 48281000. 2759443. o ~1. 1'1 420500. 420500. 420':;00. 4205(10. 420!:iO(l. 420':,00. 420':;00. 42050(). 420~jOO, 4:205(H), 42o~iUU. 420500. 4:::-0~50(l. 4 :::( lc;:i(HI • 420~iOO. 420500. 420~iOO. 42()!'500. 4'::::0500. 4::0~jOO. 4205qO. .i.~20500 . 4:.;:05UO. 420!500. 420500. 420500. 420500. 420500. 420500. 420500. 4'::-0500. 4~~n~iOO . 4::.::0~'OO, 42()r:500. 420500. 420500. 4~:IY:500 . 4:::V:i,")(l. 420~;OO. 4:»500. 420500. 42()~iOO . 420500. 420!":,OO. 420500. 2029 48281000. 2759443. 420500. 2030 48281000. 2759443. 420500. AVERAGE COST $/~::J..JH $/I-:'t,.jH TOTAL$ NONDISC DISC 317994::;::. (I. ()66 (). (1,'1'::> 3179943. 0.066 0.046 3179943. 0.066 0.042 ~: 1 79943. O. 06/::. 0,0::::':' 3179943. 0.066 0.037 3179'~'4:::':. (). 066 O. 0:::;:4 3179943. 0.066 0.032 3179943. 0.066 0.029 3179943. 0.066 0.027 3179943. 0.066 0.()2~ 3179943. 0.066 0.024 317';)943. 0.1)66 i). (11':;' 31 79'~i4::::. O. UI~,b (). (l U:: ::~: 179':;'4:.::. (1« 0(:./:. U ' (-11., 3179943. 0.066 0.015 3179943. 0.066 0.014 :;: 179943. O. (;/::..(, (1. (11 ::;: 31 -r'94:'::. (). (1/:./:, () '. () 1 j : ... :] ]'?94,'.:" (). 0(;-,(, (i. () J (, 31 ;';194:3. (j, 06/;. (). I) 1 0 :::: 1 7q94:~::. O. U{:J, (i. (I(i'~i :::11';:-'943. ll. (i,l~,.I:. (I, O(j:~,: ::':::1 79943. U. 066 I). -.)0:::: 3179943. 0.066 0.00/ 317994:3. 0.06(, 0.(l0? 3179943. 0.066 O.OOb 3179~43. 0.066 0.006 :::::179943. O.U'::.b O.(i()5 31J~943. 0.066 0.005 ':: 1 /9·::1,:~:~;. 0.066 0.004 :::: 1 7'~',:;'4:::. O. (i/:.!:, 0. 004 :~:: l 70:;943. O. (l(:./.::. !). (l04 3179943. 0.066 0.003 ,-::170:::";:43. (I. (l66 1).1.11)3 31./9943. \). u66 (I. 00::-: ,::.1 r:'':;-'L~3. 0.1:"/-.(-' (1.I,H):.:: 3179';/4:;:. 0. u(:·6 ').003 317 9 943. 0.066 0.002 :"179943. O. ()f:,l, O. Ill):::" 3179Q 43. 0.066 0.u02 3179943. 0.066 0.002 3179943. 0.066 0.002 :::;: 17';'94:;:. n. O<~,f::. ('1« n02 NOTE: TO POGRAPHY FROM U. S. G. S. -TALKE E TNA ALASKA, I: 250,000 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO -----PENSTOCK ---TRANS MfSS I ON LINE ---WATERSHED 5 o 5 E3 t==; E3 SCALE IN MILES REGIONAL INVENTORY Eli REOONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING MONTANA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Hydropower Potential Si te No. 1 Installed Capacity ( kW) 5,010 Demographic Characteristics 1981 Population: 39 SUMMARY DATA SHEET DETAILED INVESTIGATIONS MONTANA, ALASKA Installed Cost ($1000 ) 28,951 Cost of Al ternaj11" ve Power_ (mill s/kWh) 387 1981 Number of Households: 11 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower (mill s/kWh) 139 Benefit/Cost Ratio 2.78 See Appendix C (Table C-8) for example of method of computation of cost of a 1 ternati ve power. REGIONAL Ii'JVEi'HORY & RECONtJA I SAi'KE STUDY -SMALL H 'j' [I R 0 F' 0 W E R F'~:ijjEC TS ALASI<A DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -MurHAi"JA KILOWATT-HOURS PER YEAR AtHWAL PEAr~ DEMArH' '-i':W #,>J"t<. YEAF.: LOW MEDIUM HIGH LOW MEDIUM H 1:'3H 1980 1.:)7143. 167143. 167143. 57. 5~: + 1 ':';'81 173\)18. 173C)18. 173018. 59. 59. s·:.:· • 1982 178894. 178894. 178894. 61. 6i. c.L. 1983 184769. 18476':r • 184769. 63. 63. ·';'3. 1984 190644. 191)644. 190644. 65. . = 1!:t . ..J + ,.;,:::; . 1985 196519. 196519. 19.:)519. 67. 6'! · 1'7"86 2023'i5. 202395. 202395. 69. 69. 6~ .. 19:37 21)8270. 208270. 208270. 71. 71. ..; . .. 1.." 1988 214145. 214145. 214145. 73. 73. .,';'~ .. 1989 220-.)21 .. 220021. 22\j021. 75. -"" ;' .J .. 7~. 1990 22589~~ .. 225896. 225896. 77. 77 • 77 • 1991 23141)3. 239479. 2·47555. 79. 82. -I:" ;-j. I • 1992 23691)9. 2531}61. 269214. 8t. 87. 92. 1993 242416. 266644. 291)872. 83. 9i • 1 I} (1 • 1994 247923. 280227. 312531. 85. 96. 107. 1995 253430. 293809. 334190. 87. 1 C, 1 • lL4. 1996 25893.:) • 307392. 355849. 89. 1\)5. 122. 1997 264443. 320975. 377508. 91. 11 I}. 12'f. 1998 269951) • 334558. 399166. 9.2. 115. 137. 1·:r99 275456. 348140. 420825. 94. il9. 144. 21)00 280963. 361723. 442484. 96. 124. !::"L. 2001 286642. 378071. 469501. 98. 129. 1 ,S L • 2002 292320. 394418. 496518. 11)0. 115. 17'.) • 21)03 297999. 411)766. 3534. 102. 141. 179. 2004 303677. 427114. 550551. 104. 146. 1 :3;;' • 2005 309356. 443461. 57756:3. 106. 152. 198. 201)6 315034. 459809. 61)4585. 1t.)8 .. 157. ":'1.) / .. 20()7 320713. 476157. 631602. 110. 1.:)1. 21,S. 2008 326391. 492505. 658619. 112. 1':'9. L~·~ .. 2009 332070. 508852. 685635. 114. 174. -.-=:-.....:> ...... 2010 337748. 525200. 712652. 116. 1.81} • 244. 2011 345167. 535648. 726109. 118. 183. 24-;' • 2012 .... e./ . !'jJ:" ..!I.;).:....!)~...J + 546096. 739567. 121. 187. -1:"-L '_'"~ • 2013 360064. 556544. 753024. 123. 191 • ....=-"""_'CS .. 2014 36750.2. 566992. 766481. 126. 194. 262. 21)15 374941. 577439. 779939. 126. 198. 267 .. 2016 382379. 587887. 793396. 131. 2\) 1. 272. 2017 389818. 598335. 806853. 133. -,--.:..v::". 276. 2018 397256. 608783. 820311. 136. 208. 2,3 L • 2019 404695. 619231. 833768. 139. 212. 28.~ • 2020 412133. 629679. 847225. 141. 216. 290. 2021 417087. 636125. 859164. 143. 219. 2;~'4 • 2022 422041. 646572. 871103. 145. 221. 2·?8. 2023 42.:;995. 655018. 883041. 146. 224. 3i)2. 2024 431949. 663465. 894980. 148. -,--~~/. 31)7. 2025 436903. 671911. 906919. 150. 23c) • 311. 2026 441856. 680357. 918858. 151. 233. • ..) .I. ::.. • 2027 446810. 688804. 930797. 153. 236. 3i9. 2028 451764. 697250. 942736. 155. 239. 323. 2029 456718. 705696. 954674. 156. 24,2. .j~/ .. • .rP>"'1"'- 2030 461672. 714143. 9.:;.:).=> 13. 158. 245. 33i, MONTANA SITE 1 SIGN IFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: North Fork Kaswitna River Section 25, Township 23N, Range 3W, Seward Meridian Community Served: Montan, Matanuska Electric Association Distance: 11.1 mi Direction (community to site): East Map: USGS, Talkeetna Mts. (A-6), Alaska 2. HYDROLOGY 3. Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Opening Height: Width: Crest El evati on: 5. WATERCONDUCTOR Type: 6. Diameter: Length: POWER STATION Number of Units: Tu rbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Voltage/Phase: Te r ra i n :.Y Fl at (1. 0 ) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrain Cost Factors Shown in Parentheses. 39.0 102 50 sq mi cfs in Large Conc rete Gravi ty 15 ft 1515 fmsl 1760 cu yd Conc rete Ogee 10 ft 61 ft 1510 fms 1 Steel Penstock 54 in 15300 ft 2 Pel ton 970 483 5010 153 15.3 2.9 fmsl ft kW cfs cfs mi 138 kV/3 phase 3.7 mi 3.7 mi 43 percent 18872 MWh Flow Duration Curve I \ / a a o 21 ) / 28 N"O{l T H'~ -----" --- ) , I.Jj o o ~.~"" ~)": 35 b o ( '----. 36 '-~-----1500 __ ~ , " DAM PENSTOCK ............. TRANSMISSION LINE • POWERHOUSE DRAINAGE BASIN REGIONAL INVENTORY & RECONNAISSANCE STUOY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA MONTANA SITE 01 CONCEPTUAL LAYOUT N. FORK KASWITNA RIVER DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS II HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Montana Site: 1 Stream: North Fork Kaswitna River ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val ves and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANN UAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 534,000 $ 3,228,000 $ 1,764,000 $ 560,000 $ 1,092,000 $ 43,000 $ 352,000 $ 44,000 $ 345,000 $ 7,962,000 $ 796,000 $ 8,758,000 2.1 $18,392,000 $ 4,598,000 $22,990,000 $ 3,449,000 $26,439,000 $ 2,512,000 $28,951,000 $ 5,780 $ 2,265,800 $ 347,400 $ 2,612,200 $ 0.14 2.78 REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS DETAILED RECONNAISSANCE INVESTIGATIONS COST OF HYDROPOWER BENEFIT COST RATIO MONTANA ~::; I TE NO. 1 $/KWH $/kWH Y'EAR 19::::4 1';/:::;:5 1';1:36 1 'il::? . l9::::9 19'~lO 1991 19':;r;:: 19":./';: 19';:-14 l':;:19~3 199'-::, 19';'7 19'::":::: 19':"9 2000 :2001 2002 2003 2004 2005 2006 2007 200::: 2009 2010 2011 2012 201:~: 2014 201::; 2016 2017 2() 1 ::: :2019 2(120 :;:::021 2024 ~?()25 :2~() ~2(~, 2();~<l KWH/YEAR 1 :;::::;:72000. 1 ::::::::72000. 1 ::::::::72000. 1 ::::::::72000. 1 :::::::72000. 1 :3:377~OOO • 1 ::::872000. 1 ::::372000. 1 ::::::72000. 1 ::::::72000. 1 :::::::72000. 1 ::::::7:2000. 1 ::::::7~:()()(). 1 :::::::72000. 1 ::::::72()()() It 18872000. 1 :::::::72000. 1 ::::::72000. 1 :=::::7~'20(l0. 1 ::::::72000. 1 :::::::72000. 1 :::::::72000. 1 :3::::72000. 1 ::::372000. 1 :::872000. 1 :3:::72000. 18::::72000. 18872000. 1 ::::872000. 1 ::::372000. 1 ::::::72000. 1 ::;:::;:72000. 1 ;3:::72<)()(). 1 :;::::=:72000. 1 :::872000 . 1 :::::::72000. 1 :3:::72000. 1 ::=::::7200(i. 1 ::::372()()(). 1 :3:::72000. 1:::872000. 1 ::::::::72000. 1 :::::!~l'~~()()() • 1 ::::=:7:;:()()(i" t ::~:::72()()(). 1 :::::::72000. 1 ::;:::::72000. CAPITAL 2279602. 227960:2. 2279602. L~27':'I,~,();~ • ~22-/'~)(:,()2 • 22 W7 'i'(:.():? • ;:27·:'11::.1()~:~ • 227''i'/;,():2. 227960:2. 227960;::. 227''5J~j()~~ • :2~~~'7'~)6(}L' • 2 :l~ ~/I:'II:.I ():;~ • 227'~/1:..()2 • 2279(:,02. ~:27'~)l:..t():2 • :;:~ 2 '7 I~' ( .. ~, () :::: . 2:2~7f'ilt,()2 • 227':;/602. 2279602. 227'~ll:.t()2 • 227t~II:.,()2 • 227'"iJ,~,()2 • 227':"(:,1:)2. 227'~1t.,()2 .. 2:27f~J(:,()2 • 2271;/':.();~ • 227';1602. 22:11~)1::.,()2 • ~~2:71;JI:.,()~2 • 2;:7';II;'()2. 2279(::.02. 2279602. ~~2-l'~il:.,().2 • 2;~'71~il;,():2 • 2:;;'717IS():::~ • ~:~:2: 7 '~J /:.. () ~~~ a :2:2~7*~JI:.,()2 • 2:2: 7 l~) (:.(> 2 • 227';:'11::'0':: • 2279602. I) ~I, M ::::47400. 347400. J4740(). :347400. :~:47400. 347400. :347400. 347400. 347400. :;:47400. ::::47400. :34"140\) .. :347400. ::':47400. 347400. :3474()O. 347400. 347400. 347400. 347400. 34740C). :347400. ::'~4740(l. 347400. :347400. :347400. :347400. :347400. ::;::47400. ::;:47400. :347400. :347400. :347400. :347400. :347400. :347400. :347400. J4740(). ::::47400. :347400. :~:47400 • :;:47400. 347400. ::':47400. ':::47400. :347400. 347400. TOTAL$ 26.27(j()2 II 2(:'.:~:7('()2 • 2(':,270():;:~ . 2t,27002. 2c.27()()2. 2627002. 2627002. 2O::<:?7002. :~:627(H)2 • 2627002. :;:f:.,~::'70i)2 . ~>I.::,:27(j()·~: If :~~627002 , 262:7002. 2627(1( 12. :2'~1.2-'()():~ • :?,~:,2 7()():;.:~. :~~:/:"27002 • 2627002. 2627002. 2627002. :2627002. :'::'/:..:;::7002. ::~6270(l2 • 2627002. 26:::7 (1\):2 • 2627002. 2627002. 2627002. 2627002. 2627002. 2c,27()()2. 2627002. 2627002. 2{:,27()()2. :2e,27002. '~~62700L: . 262'1002. ·2{:,27002. 2627002. 262700;2:. 262l002. ~:: /:. 2 7 ()(.r~~ • 2t,21 1)O:l. 2627002. NUNDI~:::;C O. 1 ::::':;J O. 1 ::::9 O. 1::::9 O. 1 :~:9 O. 1 :3'~1 0.1::::9 (1. 1 :::';:! O. 1. :_::9 I). 139 0.1::::9 0.139 0 .. 139 O. 1::;::9 O. 1 :.::9 ,). :l :::: '~J O. 1 :;':'~I 0.139 O. 1::;::9 (). 1 :~:I~'" 0.139 (). 1 :::;:'y <'). 1. ::;:'~I O. 1,::;::9 O. 1 :::'71 0.1:.:::9 (I. 1:;: ':::' O. 139 (). 1 ::;:'::) O. 1 :39 0.139 (I. 1 :3':;1 (I. 13':;1 0.1:39 O. 1.:;::':=' 0.1::':9 0.139 (). 1 :39 0.139 0.139 0.1:-:;:9 (i. 1 :~y:,/ (). 139 O. 1 :::::9 (1.1:39 (I. 1 ::::';:l OJ::';(: O. lOll· 0.096 0.090 0.01"7 O. 07:,~ (I. (le,? 0.062 (; .. ('):,::! o. O~;4 n.o!':";o ,) .. (j4~· 0.04:;:: (I" Uil·O 0" (i::::-/ () to (":~:·~t (I" n:;:::2: 0., (nO () 1I ()2::: 0.026 0.024 (1.022 O. o:? 1 (). (; l'~1 0.01 :~: 0.U1.7 o . () j ~:-, (1.014 0.013 G.01·,:: 0.011 0.011 0.010 0.0(>9 0.009 0.00::::: 0.007 0.007 0.006 0.0(16 0.005 O. O(J"'~ (). O(l!:; 0.004 0.004 0.004 0.004 AVERAGE COST 1).139 U.O.';;:O BENEFTT-COST RATIO (5% FUEL COST ESCALATION): 2.7::: NOTE: TOPOGRAPHY FROM U. S. G. S. -TAL.KEETNA ALASKA, 1:250,000 LEGEND Y DAM SITE • POWERHOUSE o SITE NO. ---. -PENSTOCK -.. -TRANSMISSION LINE ---WATERSHED 5 0 5 E3 I--t E3 SCALE I N MILES REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING TALKEETNA DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS ~dro~ower Potential Installed Capacity Si te t~o. (kW) 4 1,009 Demographic Characteristics 1981 Population: 182 SUMMARY DATA SHEET DETAILED INVESTIGATIONS TALKEETNA, ALASKA Cost of Insta 11 ed Alternai}ve Cost Power_ ( SlOOO) (mi 11 s/kWh) 8,237 387 1981 Number of Houeholds: 40 Economic Base Touri sm Subsi stence 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of ~dropower Benefit/Cost (mill s/kWh) Ratio 197 1.97 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. REGIONAL IN0E~TO~Y ~ RECONNAISANCE STUDY -SHALL HYDROPOWER P~OjECTS AlAS~A DISTRICT -CORPS OF ENGINEERS -{E~lf\- 1':;8(1 1 .::;. ,:; 1 1982 1983 L;,'!]4 1 -?i3!7j 1 '::';;:.17 1::;'8:'3 198';' 19';-(1 t ,::;,'i 1 1'7";;-:: 1=-94 19'i::i 199.-:) 1997 1.':;'.:;i8 19<;'9 2 '.} I.) 0 2, (/I,) 1 .2 t) I) ~5 21)(14 2()1)5 ::(J(lt~ 2(101" 2.1)')8 2'') 1!') 2\) 1. 1 2') 12 :;.,) 14 2\) 15 2 1.;16 2(117 2')18 . 2019 2()24 2 t )25 2«26 20:28 LOAD FORECAST -TAL~EETNA ~IlOWATT-HOURS PER YEAR LOW MEDIUM HIGH 8(,7418. 8.34:;37. a:~9,~T5 • :) 1 70·?.2 • ':i44:5 II}. '?71?2;3 .. 9':;;934'7. l\)541:33. 1,)79;3;3 L. I. l \) 5:'; I' 8 . Ll~St27,~ .• 11 ;:';.:)-i7 4. L U32.~.71 • 121)836':;; • l.234066. 12597.-:)4. 12:35462. J.31115';'. 13.3765-:;; • 1364158. 13'1'1)6:58. L4.171513. 1443.~57 • 14701.57. 14';;,:).:)56. L549656. 1576155. J.61')868. 1..~4558:;': • 1680295. 17t5,}()8. L749721. 178443:5. L81914:3. t;?'538.~ 1. 1888574. 1 ';;2328:3. 194.::'41)6. L 9.~9524. 1992642. 201576L. 2\)3887'" • 2CI,~ 19'~7 ~ ;::',)85 l. 15 • ;::131351. .2 L544,::,9. 834:337. 862255. 889,::' 73. 917092. 944511). -:;;71928. ':;";'9347. h) 2.:)765 • 1!)54183, 1117569. L li~'')955. 1244341. 1307727. 137L113. 1434499. 1497885. 156127!. 1624657. 1688!}43. 1764332. l840621. 19L.:)91!}, 19931'1"::;; . 2'-)69487. 214577.6. 2222C·65. 2298354~ 2374643. 245(1932. 249';06;39. 2548446. 25·~7.2(j3 • 26459,~O • 2.::,94717. 2743474. 2792231. 284\)988. .2889745. 293851) 1. 29779L8. 3 .. ) 17334. 3,)56751. 3('96167. 3135584. 3175.)'.),) • 3214417. 3253833. 32'?3250 .. ----... . .!l.l~~':'::f~*:'JI~ .. 7 :31)(n) I) • Bi)74H~. 8:34837. 862255. 889673. 9 17i)'t2. 944511). -::;;71928. 999347. L')26765. 1',)54181. 1155257. 125~,332. 1357406. 145848\) • 1559554. 166062';< • 17617()3. 1862777. 1'~63851 • 2064926. 2191,)04. 2317083. 2443161 • 2569239. 2695317. 2821396. 2947474. 3()73552 .. 3199630. 33257'')8. 338850-; • 34.51310. 351411\). 3576911. 36397L2. -----1-".~ II .. )..:!~ .!> .. 3765313. 3828114. 38909L5. 39537L5. 4,}.)9430. 4065145. 4120859. 417.~574. 4232289. 428801)3. 4343718. 43-;;'?432. 4455147. 451 ',)8.~ L • ANNUAL PEA~ DFMAND-~W LOW MEDIUM ~IGH 267. 28,::' • 295. 3'.)5. 314. . .. -oJ"':'" '...J .. 333. _;.40:.: • :379. .,!J;:; / 0\ 3-;'6. 41·)5 .. 414. 423. 431. 44(1. 449. 45;3. 467. 476. 485. 494. 5·}3. 513. 522. 531. 54\} • ~;37 :5 -:;-9 • 011. 1~23 ~ 635 • 647. 65-; • 667. 674. 682. 69·.). ,~98 .. 7\}6. 714. 2.;:; 7 .. :~ 14 • 4')4. 4 2.~· .. 44,? • 47,<). 4';'1. 513. ~::'o .. 5"78. .::'.)4 .• ,S·3~) .. 656. .:i:B. 7'·}9. 735. 7,S 1 • 7;37. 8l3. 839. 85.:) • :3:3'; • -t')6. .;i23. 94 • .} • YCj6. 99\) • 1',)0.:) • 1'.)2(). 1')33. 11)47. 1('6~} • 11)74. 11)87. 11 \)1 • 11 L4. 1141. "':'.,,~ ... 3'.)5 .. 3~:.; 3~.::~ 361. 3-::;.::', 43(1, 465. 4 .;.-;; • :--~L:'4 .. 51~·:t + ,SI.)::) ) 673. 7'.)7 _ 75',) + .~ 23. I - -, '" .,)·...,1!t .. 113-;' , 1 L ,S(' • 1182. 124.:) • 1268, 1311 • 13.33. 1354, 1373. 1411. 1430. 1449. 14,':;';3. 14;38. l 51) 7 • 1'545. TALKEETNA SITE 4 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Middle Fork Montana Creek Section 5, Township 24N, Range 3W, Seward Meridian Community Served: Talkeetna, MEA Distance: 11. 7 mi Direction (community to site): Map: USGS, Talkeetna r~ts (A-6), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 35.0 64.0 35 sq mi cfs in Southeast 3. DIVERSION DAM Type: Large Concrete Gravity Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng He; ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/Phase: Terrai n:Y Fl at (1. 0) Tota 1 Length: 9. ENERGY Plant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown Y Terrain Cost Factors Shown in Parentheses. 15 ft 1065 fmsl 1450 cu yd Concrete Ogee 5 ft 119 ft 1060 fmsl Steel Penstock 36 in 1300 ft 2 Crossflow 890 fmsl 155 ft 1009 kW 96 cfs 9.6 cfs 0.3 138 0.2 0.2 43 3801 mi kV/3 phase mi mi percent MWh Flow Duration Curve 1 .... " . 12 . ~ ... o o -- TO l>ROPOSED ANCHORAGE- FAIRBANKS INTERTIE ) ( 4 .I i I ! LeGEND: I ~I I ~2 ( , i '"' ~::STOCK l ,/ ( \,..// \,~ uN......... TRANSMISSION LINE I // ( \ \ I /<'"'~ .'--------PO-W€-R-HO-U-SE------~~ ( I ~) ._- ( SCALE 1·: 20 10 , ) i, /~---.07" // !r--==-,.-,~_--' r' / -L/'/--~ , / '--------"""""'----------"---------------ti!! 8 / 9 / //~Zj/~ 1 ~ r REGIONAL INVENTORY & RECONNAISSANCE STUDY ",' DRAINAGE BASIN G J / * / I /~ \ II SMALL HYDROPOWER PROJECTS " ~ I C-, 1:\1\,' ;{ ~/ ·1 ~ , SOUTHCENTRAL ALASKA f; ----L----; I, ~// / / I ';j I I' --===::::=;::.:-:---. '~~~ ;--c>-/:J TALKEETNA SITE 04 I ('\;" CONCEPTUAL LAYOUT ;j / /'\ ' 1 , ~ ~(' ... ;'t-_· ~( --7\,--" _______ M_I_DDLE_F_O_R_K ______ ._J I . I , i \) : .;'!~ 'I DEPARTMENT OF THE ARMY o ._ -.," AlASKA DISTRICT .9 '" CORPS OF ENGINEERS • ..::... ... ___ ", •• __ ----___________ -i,'1I HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Taol keetna Site: 4 Stream: Middle Fork Montana Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations 4. Switchy a rd 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Eq~ipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 428,000 ~ 132,000 $ 676,000 $ 353,000 $ 341,000 $ 7,000 $ 305,000 $ 5,000 $ 18,000 $ 2,265,000 S 227,000 $ 2,492,000 2.1 S 5,233,000 S 1,308,000 S 6,541,000 $ 981,000 S 7,522,000 S 715,000 S 8,237,000 S 8,160 S 644,400 i 98,800 S 743,200 S 0.20 1.97 REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS DETAILED RECONNAISSANCE INVESTIGATIONS CO:::T OF HYDROPOWER -FlENEF I T COST f;:AT I U TAU:::EETNA ::HTE NO. 4 $/VWH $/KWH YEAR 19::;:4 19:::5 1986 1 ':;/:::::7 1 'i/:::::! 1 SJ:=:'~I 1990 1991 1 {~)'~'2 1. 'iJ'~):3 19';/4 1995 199/::.. 1997 1 '::",)C, 2000 .2001 2002 200:3 2004 2005 2006 2007 2008 2009 :2010 2011 2012 201:3 2014 2015 2016 :2017 2019 2020 2021 202:~: 2024 2()25 2()2(:, 2()27 2()2:::: KWH/YEAR :3:;::01000. 3:::01000. ::::::;:01000. :3::::01000. :3801000. 3::::01000. :::::301 (JOO. :;:::::01000. :3:::01000. :::;::::01000. :;::;::01 (100. ::;::::0.1 000. ::::;:::01000. :3:::01000. ·3:::() 1 000. :::::30:l 000. :3801000. ::::::::01000. ::::::;:01(1)0. :3801000. :::::301000. :::::::01000. :3801000. 3801000. :3:::01000. :::::::01. 000. 3801000. ::::801000. 3::;:01000. 3801000. :;::::01000. :::::::::01000. :~::30 1 000. :::::::(11 ()OO • 3801000. :::::::01000. 3801000. ::::801UOO. :3801000. ::::801000. ::::::;:01000. :::::::01000. :3801 (H)O. :;:;::01000. ::;::::() 1 000. ::::::::0 1 000. CAPITAL 648581. (':t4:::~i::: 1 • (S4:::~5::: 1 • 648':i::: 1 • 6485:::1. cJ4:::5:=~ 1. • t;14!35:::: 1 • (:.4 :::~{!=: 1 • l~l4::!~5!31 • 6485:;:: 1 • (:.485::::111 /:'48~i::: 1 • 64::::5:::: 1 .. (:,4:35:31 • l:14:=:581 II 64::::581. f~J:=!::: () () • j:;:=::::~()() .. '~::::::~() () . '~J ~::: ::: i) () " '~I :::: !::: () () • '~8!=!()() • '~I ::: ::: () () .. ''i/8:=:()() • I;J::~:::(}() • t'f)::::::()() _ ~I ::: :=: () () • '~Jr::::;()() • l~/E:8()() .. f_:)E~:::: {) () • I:} ::: :~~ () () • ''iJ :3::;!(){) ., '~)~3::::()() • '~) :::! :::: () () • ':"E:i::t)() • 98:::(1), J~8!::()() • I'i' :=: ::: () () • t~) ::; !:: () () • ''i' :::: ::: () () • '~)~::::()l) • I;,::-:::::()() • ~I ::: :=~ ()() ~ '~J !:: ::: () () • '~:=~8{)() ft '?" !=~ :=~ () () • ''i':3 :::: () () • 1~:38(H) • '~:=:8()() • ·~I E: E: () () • t~:3:::()() • '~'::::8()() • J~' ::: :=: (H) • ';)8:=:()() " 9:3~3()() . '~J8:::()() • '~::: ::: () () . ';, :::: ::! () () • ·rOlAL$ 747:;::::: 1 • 747::::::::1 • 74 7::::f:: 1 " 747::::::::1 .• 747:::::::::1 • 747:3:31. 747::::::::1 . 747::::::': 1 • 747::::::H , 7 4 7::~:::n • 7473:::1. '7 47':'::~: 1 • 747::::81. 747:381. 7473EH. 747381. 747::::::: 1 • 747:.~::::t • 747:381. 747:;:::: 1 • 747:::::;:1. 7473;::1. 747:;::::::1 • 747:::::!1. 7473::: 1 • 7473:::1. '7473::: 1 • 747:::::1. 747::::::H • 747:::;::::H. 747::::81. 747::::81. 747:3:::1 • 747:381. 747::::::::1 • 747::::81. 7473:31. ·747381. 747:=.::::: 1 • 747:3:::1. 747:381. 7473:31. 747::::f:l. 2030 :3:::01000. 648581. 98800. 747381. AVERAGE COST BENEFIT-COST RATIO (5% FUEL COSl ESCALATION): 0.1,97 0.1,97 0.197 (l" 197 0. 197 O. 197 I). t ';17 0.197 0 .. 197 O.1';!7 O. 197 0.197 0.197 O. 1'::.17 0.197 0.,197 0.19/ O. 197 0, 1. '::)] n, 197 O. 1 (,? 0.197 0.1'-;'7 0.197 O. 1';)7 fi.t97 0 .. 197 0.1 -:n 0.197 0 .. 197 0" I',' 7 0.197 0.1.97 0.197 0.197 0.197 (J. 1':;'7 0.197 0.197 0.197 0.197 0.197 0.197 0.397 0.197 0.1';'7 O. 1'-:.17 0. 197 1.97 [r I :::;C 0.147 0.13f:. (I. 1 :: .. '7 0.11:3 0.109 I). 101 0.094 o ,. ('::.':~:: O. (I:::: 1 O. (O{-, O.07(l O. 06~; (l" (V:' 1 0.056 () u <) ~i::;:~ 0.04 9 0.04':; 0.042 (I. O::~:9 0.0;:4 0.0:':;: 1 0.027 0.025 0,. n~)::: II. ()"?::' 0, 02() C). CliO) 0.017 O.Ol/.:. 0.01::; 0.014 0.01:3 0.01:;;:; 0.011 0.0.10 0.010 0.009 0.00:3 O. (10::::: 0.007 0.007 0.006 O.OO/.:. O. O(l~i O.OO!:i O. 04.~: Freemantle ,,0 ;-Bligh Reef - lightS PRINCE WILLIAM SOUND NOTE: TO POGRAPHY FROM U. S. G. S. -CORDOVA ALASKA, 1:250,000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO. -- - --PENSTOCK ---TRANSMISSION LINE ---WATERSHED { , , ":P Gravina I·· Gravina' i POlO! t::.u ORCA 5 0 E3 t==; E3 SCALE I N MILES 5 REGIONAL INVENTORY a REOONNAISSANCE S'I"I.I1I' SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING ELLAMAR-TATITLEK DEPARTMENT OF THE ARM'f ALASKA DISTRICT CORPS OF ENGINEERS Hydro~ower Potent; al Insta 11 ed Capacity Site No. (kW) 6 128 Demographic Characteristics SUMMARY DATA SHEET DETAILED INVESTIGATIONS ELLAMAR-TATITLEK, ALASKA Cost of Installed Alternai}ve Cost Power_ (UOOO) (mill s/k:Wh) 3,427 485 1981 Population: Ellamar -46; Tatitlek: -68 Cost of Hydropower (mills/k:Wh) 590 1981 Number of Households: -Ellamar -13; Tatitlek: -19 Economic Base Unk:nown 11 5 Percent Fuel Escalation, Capital Cost Excluded. Benefit/Cost Ratio 0.82 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. ~EGIONAL I~VENTORY i RECONNAISANCE STUDY -SHALL HYDROPOWER PROJECTS iE~.t;: l ':; :~~: \~, 198:: 1:;'i33 1';, )::: <.\ 1":;;8~:'; 1 '=i ~j ,..:' 1 ':;8::: 19::::3 195':' 1 ':;";:;.(. 1;:;'91 1~;":;' :; 1. (;'93 1 ,:j':; ,4 19Qt~, 1997 1'';'9:3 19 Q ';; 2(,(11) 2'.:·'02 '::',)('4 2~)'.)7 '::')',)8 2\)1<) 2()11 ~,~(, 12 2013 ~~,) 14 2':115 '::l)l~· :018 2,,)19 :',)21 2'j::: ,2')24 :-:1·)26 ALAS~A DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -ELLAMAR KILOWATT-HOURS PER YEAR LOW MEDIUM HIGH l) • 21354. 427Cd3. 64~j,~:2 ~ 8:'i4U;,. 1·j6 77\). 1..28123. 149477. 192185. 2224/\). 2314()1. 2,4\)331. 2J~92.~:: . 258193. 276()55. 2849i35. 293916. ~502i34 7. 310576. 3183\)5. 326\)34. 3337.~3 . 341492. 349222. 356951. 3.S4680. 3724\')9. 38',) 138. :384.:) 14. 3891)89. 3",)3565. 3'~:3l)4',) • 4('25L6. 4(!6991. 411467. JH5942. 4::~0418. 424893. 430313. 435734. 441154. 446574. 451995. 457415. 462~j35 • 41~t8256 • ll73.S 7~, ~ 479,')96. 21354. 6-'+ ().,;) 2 • 854L6. 106771). 128123. 149477. 17083L. 1921:35. 213539. 23',j653. 2477676p 264881. 28199"). ::9911)9. 316224. 333338. 351)452. 3675.:)6. 384681) • 4\)3220. 421761) • 44029'~ • 458839. 477379. 495919. 514459. 532999. 551538. 570078. 577,~,lj3 • 585128. 592652. 61)0177. "~1)77(,2 • 615227. 622752. 630277, 637801. 645326. 654285. ·:)6324-'+ • . :) 7 221)4. 681163. 690122. 699i)8 L • 7'')8041} • 7 17(1)1}. 725959. 734~18. O. 21354. 42708. 64')62. 85416. 106770. 128123. 149477. 170831. 192185. 213539. 238836. 26413-'+. 289431. 314728. 341)i)26. 3·:)5323. ---',-,~""\JO ... V • 415917. 441215. 466512. 4Q5863. 525213. 554564. 583914. 613265. 642616. 671966. 7\) 1317. 731)668. 7.61)018. 770592. 781166. 791741) • 8')2315. 812889. 823463. 8341)37. 844611. 855185. 8.!)5759. 878257. 890755. 'j·,j3253 • 915751. 928249. 941)747. 953245. 'i65743. 978241. 99C,739. ANNUAL PEAK DFMAND- LOW MEDIUM HIGH O. 7. 15. 29. 37. J:' ' ,.J ,L • 5~. 66. 73. 76. 79 .. 82. 85. 88. 91. 95. 98. 1',) 1. 104. 11)6. 1 \)9. 112. 114. 117. L 2',}. 122. 125. 128. 130. 132. 133. 135. 136. 138. 139. 141. 144. 146. 147. 149. 151. 153. 155. 157. 159. 161} • L62. 164. o. 44. 5 i • 5';. .,;).:) . ,'.~ .. 85 .. 91. 97. 1 \)2. 108. 114. 12"-} • 12·:) • 132. 13::j • L44. 151. 157. 163. 1 7e}. 176. 183. 1 ;39. 1';5. 198. 2l)') • 21)3. 21)6. 2\)8. 2 L 1. 213. 21.:) . 218. 221. ,,--.;...:: ! .. 23(1. 233. 236. 242. 241~ • 24';'. I) .:. iI.<.i, SL "5'-:' • ,~,,;:, . J·oJ • 1 \:':3 + 1 i ,S • 12'5. L34+ 142. 15 L + 1 '~":" 17.,) • 1 :3\-) • .' ' 2'·:1 .. ./ • 211) • 23(} . 24.) + 25(.l4o 2,~(' .. ,'-.:..~':l • 27 l • 275. 27;3. 282. 2:3'~ • 2'~3 • 3 ')5. 3(''; • 3i4. 318. 326. REGIONAL [NUENTORY & RECONN~IS~NCE STUDY -SMALL HYDRopnWER PROJECTS ALAS~A Dl RICT -CORPS OF ENGINEERS 'y'E At;: 1 'i:3 ,.} 1':;<81 19:32 1;;; i3"~ L 985 !'=i86 L ':;';37 Lq;3::; 1989 L ,::; ';iI) 1991 I .... ·:;;:: 1'=t.:;.~S 1.':;'94 1995 1':;''::;6 L'1'98 19 Q ", -........ -LI .... ')~ 2·)·,)3 2(,,')4 2 1,)')5 20t).!) 2·')1') I' .200i3 2l.)(;·~ 2011 2012 :2(J 13 2')1.4 ::,) l:;'j 2(' L .. S 2()18 2,)19 2(':~O .2 1,) .21 2('25 20 2,~ 2',)](; LOAD FORECAST -TATITLEK ~ILOWATT-HOURS PER YEAR LOW MEDIUM HIGH 0 .• 31567. ·S31 ':;'47')(, • 1.26267. 157834. 1 ;3941)C', ::,2'.)967. 2525:!:4 + 2;7$41 O(j • :5 L56.:;;7. 328:369 + 3·;.\2',)71. -C"C" -~-;-. .:).J.J"," / ...:> • -'-4--. ~i::·ts /:,. 381677. 41)8081. "Ld283. 4 -.54485, 447.~8'7 , 4591.13. 47053i3. 4;'31964. 493389. 5'.)4815. 516241. 5.27.~.,;).S • 5391)Q2 • 5:;,.')517. 5·S 1943. 5'~l85~~;'=i + 575175. 5i31791. 5~384()7 ~ 5'~5()22 + 6(' 16313. . :S(J~325"~ 4 . ::'14871) • 621486. 628102. . - . 11-·~,jO '. ~:..: + . ~.44 1 27. .::'52141] • . ~6·j153 • . "'.'.)8 L65. 676178. . ~841·;; 1. ~;\-) •. j 216. 7')8::':.2::;' • o. 31567. 63133· ':(4/.)0. 12,S267 + 157834. 18':;-4(1) • 220967. 252534. 284 L (.1\)., 315667. ~54tj9.~,~ 4 36,~265 + 391564. 416863. 442.162. 467461. .4 .;-':;"0 6') • 5 L81)59. 543358. 568 7. 59.~1).~4 • 623471} • 65t)877. 678284. 7f_)56~1) .. 733097. 760504. 787';-11 • 8L5317, 842724, ;35384;3 • ;;.-'>4':(7 L , 876095, 8;3721-:;-t 89834.2. 9·.)0466. 92'.)589. 931713. 942837. 953961;· • 96721)4. 9;~t)44;3 • 99369:: • 1·.j(jt·93.:;; • 1(21)181) • 1033424, 1'·)4·!l668., 11):H912. 1(j73 l5.:', o. 31567. 63133. 94700. 126267+ 1·'57834. 18941)0. 220967. 252534. 284101j. 315667. 353063. 390459. 427855. 465251 + 502,-:)47. 540043. 57743'; • 614835. 652231 " 689627, 733015. 7764(·3. 81979'.) • 863178. 91)6566. 949954. 993342. L03673(1. 1080117. 112351)5, 113913.:), 1154768. 1170399. 1186030, 1201661. 1217293. 1232924. 1248555, 126418·'.) • 12798L7. 1298292. 13L6768. L335243. 1353718. 1372193. L3.'i(I669. 1409144. 1427619. 144.:)0'1'4. 1464570. ANNUAL PEA~ D~MAND-~W LOW MEDIUM HIGH 11. ,:.. ..:... + . , ... ' ......... .' ~ OJ • 1'·);3. 113. 117. 1:::. 14(' + 1<.1"~ • 14':;:' • 153. 15-:: , 1.~· L • 1.~:: . 1'7,) • 1 7 :, 1:31. LiS. 1'?!. 1':;'9, 2Ll. 213. 215. 218 • 221 • 2_::3 + 221~ • 229. 234. --~ ,,;!..j / • 11. L34. 143 . 151. 11:;~) .. t ,S'? .. 1'r5, 2·j4. 214, 25l + 260. 27\) + 3\)\) • 304, 3(,8. 3 L 1 , 315 • 319. 323. 33.1. 33.~ • 34·) • 345. 34'? • 354. 358 • 363. 3.~8 • ';"' : " L ':';';1 + 1:: 1, 2 L L 2"St~ • 2i3 i ~ 2\;(,S + ,j.~:j • 3~C! + 41) 1 , 4,).::). 417+ .{~ 28 • 43.3 + 43;3., 4~'S, 45 L. 457. 464. 471). 47.-S • 4;33. 4;3 0 + 4vC;. ELLAMAR/TATILEK SITE 6 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: Indi an Creek Section 26, Township lOS, Range 8W, Copper River Meridian Community Served: Ellamar, Tatitlek Distance: 6.7 mi (from Ellamar) Direction (community to site): Northeast Map: USGS, Cordova (0-7), Alaska 2. HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Hei ght: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest El evati on: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow: Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE ~~~~:i~~I,a~i!t (1.0) Roll; ng (1. 25) Mountains (1.5) Long Span Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: t1ethod of Energy Computati on: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terrai n Cost Factors Shown in Parentheses. 1.7 8.3 100 sq mi cfs in Low Concrete Gravity 10 ft 1110 fmsl 140 cu yd Stairstep Fish Ladder 5 ft 14 ft 1105 fmsl Steel Penstock 12 in 4200 ft 1 Pelton 200 fmsl 897 ft 128 kW 2.1 cfs 0.42 cfs 0.8 14.4 2.5 4.4 2.0 0.4 9.3 mi kV/1 phase mi m; mi mi m; 55 percent 617 MWh Plant Factor Program 'J" r X993 / ., I / .32 __ I (0" / // .: eJ,$39 / j' , /' : ~{_~ ~ __ ·~ ____ ·_,,·_'_'1+-i_~"--J-~""""~ 5 * * B .A y ~ ", ~ /f, I~ " • \ ../... ' II 13( LEGEND: . DAM ............. • I --. . DRAftAGE BASIN REGIONAlINVEMTORY .. RECONNAISSANCE STOOY SMAU. HYDROPOWER PROJECTS SOUTH CENTRAL ALASKA ELLAMAR-TATITLEK 81TE 08 OO.C .... TUALLAYOUT INDIAN C"IIK DEPARTMENT OF THE ARtI'f ALASKA DISTRICT COR OF ENGINEERS NE/SC ALASKA SMALL HYDRU RECONNAISANCE STUDY PLAIn FACTUR PROGRAM C0I1!·IUN I TV: ELLAf1AI</TAT I TLEK SITE Nur'tI.lER: 2 NET HEAD (FT): 897. DESIGN CAPACITY (KW): 128. MINIMUM OPERATING FLOW (I UNIT) (CFS): 0.42 LOi~D SHAPE FACTORS: 0.50 0.75 1.60 2.00 HOUI< FACTORS: 16.0U 15.00 13.00 3.00 MONTH (#DAYS/MO.) AVERAGE POTENTIAL' PERCENT ENERGY USABLE MONTHL Y HYDROELECTRIC OF AVERAGE DEI-lAND HYDRO FLOW ENERGY ANNUAL ENERGY ENEHGY (CFS) GENERATIUN (KWH) (KWH) JANUARY 2.n 95232. 10.00 68414. 57285. FLtiRUAHY 3.53 86016. 9.50 64993. 52008. rvlARCH 2.54 95232. 9.00 61572. 56715. APRIL 4.60 92160. 9.00 61572. 55051. I'Y\t\ Y 12.60 95232. 8.00 54731. 52952. JUNE 15.60 92160. 5.50 37627. 37627. JULY 11.30 95232. 5.50 37627. 37627. AUGUST 9.20 95232. 6.00 41048. 41048. SEPTEIVloER 13.70 92160. 8.00 54731. 52568. OCTUBER 12.10 95232. 9.00 61572. 56715. NOVEMBER 7.37 92160. 10.00 68414. 55621. UECEMl:>ER 3.38 95232. 10.50 71<334. 57'070. TOTAL 1121280. 684136. 612789. PLAHT FACTOR(1997): 0.55 PLANT FACTUR{LIFt CYCLE): 0.55 HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Site: Stream: Ellamar/Tatitlek 6 Indi an Creek ITEr4 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val ves and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 20 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest Duri ng Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Mai ntenance Cost at 1. 2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 42,000 $ 129,000 $ 90,000 $ 164,000 $ 30,000 $ 6,000 $ 99,000 $ 12,000 $ 292,000 $ 864,000 $ 173,000 $ 1,037,000 2.1 $ 2,177,000 $ 544,000 $ 2,722,000 $ 408,000 $ 3,130,000 $ 297,000 $ 3,427,000 $ 26,770 $ 268,100 $ 70,000 $ 338,100 $ 0.59 0.82 1-':1:-1, i [ Of\IAL. INVENTORY ~,: F~E(:ONNA I ~::ANCF STUD\(-::=':MAL l HYDP(lPCIWER pr;:(I.IU T':. ALASKA DISTRICT -CORPS OF ENGINEERS DEW", I LED 1:~I:Cnf\jJ\lA '[ ":;;~=;ANCE I NVE:::r1 I Gr .. H I 111\1::::: CO:::.T Of'": H"r'DF,'CH'::'UWf::R , .. PENEF I T 1.(1:::,'1 ~A r I II ELLAMAR/TATlrL~K )' Ef~l~ l q ::::4 1 o:J:::::, 19;:::(, t';::':::: 7 1 ':/::::') 1. ':1':'0 1 '~/'" 1 199:::: 1';:":;:>4 1 <;/99 2000 2001 :~003 2004, :~;~ () i) ':t 20(lI.:;. ~~~oo '? :;~: ()():? :;?r,H)9 2010 :::::011 :;;;:012 2013 :':::014 :';::015 ::::01.':" ,;;::01"7 2Ul::;;: ::::U19 :~:: () ::' () 20:,::1 f:::l-.IH/ YEAR Z 1 1/':,:::::2. 264603. ,:::1 r524. :370444. 42:::::365. 474737. ~5 4 () ::.:: ';1 ::: • 557::::::::() • 5711:..21. 6127:::9. 620443. 627/:,49. 6429:37. ~:.4 730:2. 1:..51596. ~;.'5~577:3. 6~8:=:04. 1:.1~:1:~:575 • t~. i~1 7 :::: 4 2: • 67110';:'. 674::::76. .~.·7·?(j~57 • 1b ~l'~/2 :~: ';1 • 6:::1420. 683601. 6:?7299. (~,89036. 690774,. • ~~ •• ~) "-1-() :.:: .;) .. ( . .';:) ~i ,,:;. 5 1 • 700707. 20:27 702946. 20?::: 704065. 2()L:'~! 7()51 :::4. 2030 7(l6::~:04. AVERAGE COST CAPITAL ~: {, ':) !:! 4:2~ • ~2·~,'~)::::42 • 2(::..~):::4~;:: It 2(:.'~1:342 • :2~.'~J:::4 2. :2t:,·~/:34:2 • 21:., '~j:::4:;: • 2(:/;i~::42 • 2(:,t;J:342. 2(:t':;;~342 « :2:("'..t~J842~ A 2(:1·~):::4~~ • 2I:.J·~J:::42. 2(:,'~:::42 • 2(:1'~~:::42 " :21:..t~"'!::4~2 • ~~ I:.~ t~i ::: 4;;~ • ~~ /;' '~/:::4 *;;;: tl :21:.. '~J :~:: 4 :;~ . :21:.1 r~~:3 i~ ~~: • L~ ~";' ::: 4 :;.~ :t 26Si~=:4::~~ • ~~(:.'~/::34 2. ~~(:f~I:::42 ,. o ~I, 11 70000. 70000. 70000. 7(l(i(iO. 70000. 70000. 70(;00. 70000. 70000. 7(H)OO. 7(ii')()() • 70000. 70000. 70000. 7 o (HX, • '70000. ?(lOOO. 70000. 70000. 70000. 70000. 70(100. 70000. 70000. "/()(lOO. "/r)oOO. 70000. 7(1000. 70000. 70000. l()I)OO. 70000. 700(10. 7(H)OO. 70000. 70000. 70000 • 70000. 7000(1. 'j"(l(I()() • 70000. 70(lOU. 70000. 70(1)0. 70(100. 7 1)(H)(l. 70000. 339842. 1.284 0.889 ::;::3984:2" 1 • 070 O. (,:::':::. 339842. 0.917 0.548 339842. 0.803 0.446 339842. 0.6St 0.817 :3::::·~':=:42~" ,::/. 1~:;:2l~i () ... 2:~::t) 339842. 0.571 0.!90 339842. 0.562 0.1 7 3 :::!::::'~):::4~:~. (). 5~;~; () .. 1 ~;'~l 339842. 0.541 0,134 33984:2. 0.536 0.123 339842. 0.532 O.11~ 339842. 0.529 0.105 :~::~:'~}E:42 , (I., ~3:2:5 c) ..•. )'~:';7 :~~:3~~J:::42. ()" ~~;,~2':;:' i) "I {);:.:,;-, 339842. 0.518 0.083 :'::':::'";1:34:2:. (). ~515 () <. I'; 7 / .... ' :3:~:t~}:34:2~ w (s .. 51 :2 (J .. f) "I' () :::::~:1~)::::42. {)II~~()I:'I (ltt('(-,5 :::,:::~:'~)E!4;;~. i) It ~~()(~~ () Zf ().~~.() :~:'~~I~t:~4~:~" () Ii :-~()4 (t. ()~~.;(-:, :::::·~:I~':::.t.l·:~.. ()" 5(,~~~ () If (j~51 339842. 0.500 0.048 :'::::;:,):::4~,:. I)" 4'~i9 0.044 339842. 0.497 0.041 339842. 0.496 0.038 339842. 0.494 0.085 339842. u.493 0.033 339842. 0.492 0.030 339842. 0.491 0.028 339842. 0.490 0.026 339842. 0.489 0.024 339842. O.48~ 0.022 :,:::':::~~J:::4 *:2. (.1" 4:::7 (). (' ;:21 339842. 0.486 0.01 Q 339842. 0.485 0.018 339842. 0.484 0.016 :;:~~:f1::::4:2~.. (1. 4:::::::: (). l) 1 ~5 :~~::::f;):::4:~2" t.~ .. 4:~~3 ()~ (;1 l l :;:::;:9:::42. (I. 4::;Q O. (11 :;:: 339842. 0.481 0.012 (;. 590 0.:1 i.:./.l. BENEFIT-COST RATIO (5% FUEL COSl ESCALATION): 0.82 NOTE: TOPOGRAPHY FROM U.S.G.S.-FAIRBANKS a H ':( ALASKA. 1:250,000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO. - - - --PENSTOCK - - -TRANSMISSION LINE --WATERSHED 5 0 5 E3 F=4 E3 SCALE I N MILES REGIONAL INVENTORY a RECONNAISSANCE STUI)'( SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFfED IN PRELIMINARY SCREENING FERRY DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Hydro2ower Potenti al Installed Capacity Si te No. e kW) s?:./ 4.843 Demographic Characteri stics 1981 Population: 32 SUMMARY DATA SHEET DETAILED INVESTIGATIONS FERRY. ALASKA Cost of Installed Alternai}ve Cost Power_ e ~1000) (mill s/kWh) 27,920 324 1981 Number of Households: 9 Economi c Base Mining 1/ 5 Percent Fuel Escalation. Capital Cost Excluded. Cost of Hydr()power Benefi t/Cost (mi 11 s/kWh) Ratio 166 1. 95 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. ~ Site could also serve Suntrana. REGIONAL I r~lJENTOR'( & RECONNAISAi'KE STUDY -SMAll H'r'DRljF'OWER PF\:oJECT:; ALASt~A DISTRICT -CORPS OF ENGINEERS UJArl F'ORECAST -FERF.:Y r< I LOWATT -HOljF.:S PER YEAR ANi"WAL F'EAr.: DEMANI)-I<W _.,)i-~'~" 'rEAR LOW MEDIUM HIGH LOW MEDIUM HIGH 1980 132857. 132857. 132857. 45. 45. ' I:" 4J. 1981 137527. L37527. 137527. 47. 47. 47. 1982 142197. 142197. 142197. 49. 49. 49. 1983 146868. 146868. 146868. r::" '..)1) • 5\) • 51) • 1984 151538. 151538. 151538. 52. I:" -, '::J..:.... 52. 1985 156208. 156208. 156208. 53. 53. 53 • .1986 160878. 160878. 160878. r::= ....J , .. I • 55. 1:"::-...J • ..1 • 1987 165548. 165548. 165548. 57. 57. r::~ .J., " 1988 170219. 17\)219. 170219. 58. 58. 1:"" ._'M + 1989 174889. 174889. 174889. 6\}. 61j. .~ I.} • 1990 179559. 179559. 179559. 61. 61. 61. 1991 183936. 194203. 204469. 63. 67. 71) • 1992 188313. 208846. 229380. 64. 72. 79. 19'1'3 192690. 223490. 254290. 66. 77. 87. 1994 197067. 238134. 279200. 67. e::'} • 9.~. ~ 1995 201444. 252778. 304111. 69. 87. b)4. 1996 205821. 267.421. 329021. 71) • 92. 113. 1997 210198. 282065. 353931. -~ I'::'. 97 .. 121. 1998 214575. 296709. 378841. 73. 102. 13,) • 1999 218952. 311352. 403752. 75. 107. 138. 2',)00 223329. 325996. 428662. 76. 112. 147. 2001 227843. 344073. 460302. 78. 118. 158. 2002 232356. 362149. 491942. 80. 124. 168. 2003 236870. 38()226. 523581. 81. 130. 179. ,4Il1i4;'111;_' 2004 241384. 398303. 555221. 83. 13·6. 1':;'0. 2005 245898. 416379. 586861. 84. 143. 2(j i , 2006 250411. 434456. 618501. 86. 149. 212. 2007 254925. 452533. 650141. 87. 155. 213. 2008 259439. 470610. 681781. 89. 16 j • 233. 2009 263952. 488686. 713420. 90. 167. 244. 2010 2.oS8466. 506763. 7451)60. 9'") .:... 174. -,t::'C' ..:;.. • ...J...J .. 2011 274379. 516501. 758624. 94. 177 .. 2.~0 • 2012 280291. 526240. 772188. 96. 180. 264. 2013 286204. 535978. 785752. 98. 184. 269. 2014 292117. 545716. 799316. 100. 187. 274. 2015 298029. 555455. 812879. 102. 190. 278. 2016 303942. 565193. 826443. 104. 194. 28A+ 2017 309855. 57493l. 84(1)07. 106. 197. 288. 2018 315768. 584670. 853571. 108. 20ij. 292. 2019 321680. 594408. 867135. 110. 2(}4. 297. 20.20 327593. 604146. 880699. 112. '"'j'-.:....V/. 3C)2 • 2021 331531. 612524. 893516. 114. 210. 306. 2022 335468. 620901. 906334. 115. 213. 310. 2023 339406. 629279. 9L915.L. 116. 216. 315. 2024 343344. 637656. 931968. 118. 218. 319. 2025 347281. 646034. 944786. l.L9. 221-3.24. 2026 351219. 654411. 957603. 120. 224. 328. 2027 355157. 662789. 970420. 122. 227. 332. 2028 359095. 671166. 983238. 123. 230. 337. 2029 363(,32. 679544. 996055. 124. 233. 341. ~ 2030 366970. 687921. 1008872. 126. 236. 3 t iA. NOTE: TO POGRAPHY FROM U. S. G. S. -HEALY ALASKA, 1:250,000 LEGEND Y DAM SITE • POWERHOUSE o SITE NO. ---• -PENSTOCK -- -TRANSMISSION LINE -----WATERSHED 5 0 5 E3 E"3 I----i SCALE I N MILES REGIONAL INVENTORY a REOONNAISSANCE STUD'( SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING SUNTRANA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS Hydropower Potential S1 te t~o. sY Insta 11 ed Capacity (kW) 4,843 Demographic Characteristics 1981 Population: 81 SUMMARY DATA SHEET DETAILED INVESTIGATIONS SUNTRANA, ALASKA Installed Cost ( S1000) 27,920 Cost of Alternative Powerll emi 11 s/kWh) 324 1981 Number of Households: 23 Economic Base Mining 1/ 5 Percent Fuel Escalation. Capital Cost Excluded. Cost of Hydropower (mills/kWh) 166 Benefit/Cost Ratio 1. 95 See Appendix C (Table C-8) for example of method of computation of cost of alternative power. 2/ Site could also serve Ferry. ~EGtONAL I~VENTORj & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS ALASKA DISTRICT -CORPS OF ENGINEERS LOAD FORECAST -SUNTRAr4A KILOWATT-HOURS F'ER YEAR AWWAL PEAr: i)EMAi'W-i\:W 'rEAP LOW MEDIUM HIGH LOW MEDIUM i-iIGi-i 1':;'-'80 34"7143. 347143. 347143. 119. L19. 11':;' • 19:31 . 359346. 359346. 359346 • 123. 123. L23. l O ·:;j -; ' ,-/..:... 371548. 371548. 371548. 127. 127. L27. 1983 3:33751. 383751. 383751. 13i. 131. 13 L. 198,4 395953. 395953. 395953. 136. 136. 136. 1985 40815.~. 408156. 4~)8156 • 140. 140. l·,j i) • 1986 420359. 421)359. 420359. 144. 144. 144. 1'?87 432561. 432561. 432561. 148. 148. 148. 1988 444764. 444764. 444764. 152. 152. 152. 1'?89 456966. 456966. 456966. 156. 156. 156. 1990 469169. 469169. 469169. 161. 161. 1·::' 1 • 1'7'91 48(.1606. 507432. 534257. 165. 174. 183. 1992 4'7'2043. 545694. 599346. 169. 187. 2\)::;. 1993 503480. 583957. 664434. 172. 21)1) • 2 1994 514917. 622219. 729522. 176. 213. .,=-... ,:,}I) • 1';-95 526354. 660482. 794611. 180. 226. 27'2. 1'7'96 537790. 6'~8745. 859699. 184. 239. 294. 1997 549227. 7371)07. 924787. 188. i~-1 ,,:;,>.J~ .. 3l7. L998 561)664. 77527-.) • 989876. 192. 266. 33':;' • 1999 572101. 813533. 1054964. 196. 279. 3"; i.. 200'.} 583538. 851795. 1120052. 200. 292. 3:34. 21)01 595332. 899028. 1202724. 204. 31;8. 4l2. 2(q) 2 607126. 946260. 1285396. .,--.",VI.:S. 324. 44(1, 2003 6189l9. 993493. 1368067. 212. 341) • 4,~.9 . 21)1)4 630713. 1040726. 1450739. 216. -C' ' ,~·JO • 497. 2 I.}'') 5 642507. 1087959. 1533411. 22(} .. 373. 525~ 20(1 1:) 654301. 1135191. 1616083. 224. 389. C"--..J ::1.;) • 2')07 6~.60q5. 1182424. 1698754. 2223. 41)5. 2008 677889. 1229657. 1781426. 232. 4;21. 6l0. 21.)09 689682. 1276890. 1864098. .,-, .:..~O. 437. 638 • 201\) 7\) 1476. 1324122. 1946769. 240. 453. .!)67. 201l 716925. 1349567. 1982210. 246. 4·'!!.2. 6 7 '; • 2012 732375. 1375013. 2017652. 251. 471. 6;1. 2(,\13 747824. 1400458. 2053093. -C". L...JO. 480. 71)3. 2014 763.273. 1425903. 2088534. 261. 488. 715. 2015 778723. 1451348. 2123975. .,'~ ,,".~ I. 497. 727~ 2016 794172. 1476794. 2159417. 272. 51)6. 74\) • 2('17 81)96.2 1. 1502239. 2194858. .,--.:..11. 5l4. -C"-l ' .... .:.! • 2018 825071. 1527684. 2230299. 283. r::::-,-• ...J.:...~ • 764. 201'i 841)520. 1553129. 2265740. 288. 532. 77.:) + 2()2-j 855969. 1578575. 2301181. 293. 541. 78;~ • . 2021 -"")1:'-::I.~O.:....JI.:S • 1600465 • 2334672. 297. 548. 8 ell) + 2022 876547. 1622354. 2368162. 300. C"-. ,:,}':;)o • 811. 2023 886835. 1644244. 2401653. 304. 563. t$~L. 2024 :397124. 1666134. 2435143. 307. 571 + 834. 2()25 907413. 1688023. 2468634. 311. 578. :345. 2026 9L7702. 1709913. 2502124. 314. 586. ;357. 2()27 927991. 1731802. 2535615. 318. 593. 868. 2028 93828t) • 1753692. 2569105. 321. 61) L • -,.,. ::I,~I) • 2029 948568. 11'75582. ., " "'" }'IOO C" -~ .:..oVL.:.J'fO. 325. 6'.)8 • 891. 2'')3') 958857. 1797471. 2636086. 328. 61.:;. 9\;3. SUNTRANA SITE 05 SIGNIFICANT DATA DETAILED RECONNAISSANCE INVESTIGATIONS 1. LOCATION (diversion) Stream: t~oody Creek Section 36, Township 12S, Range ]W, Fairbanks Meridian Community Served: Suntrana, Ferry, and GVEA Distance: 2 mi Direction (community to site): South Map: USGS, Healy (0-4), Alaska 2. HYDROLOGY Drainage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: Height: Crest Elevation: Vol ume: 4. SPILLWAY Type: Openi ng Hei ght: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type: Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/ Pha se: Terrai n:1/ Fl at (1.0) Total Length: (approximate distance to Anchorage-Fairbanks intertie) 9. ENERGY Plant Factor: Average Annual Energy Production: Method of Energy Computation: 10. ENVIRONMENTAL CONSTRAINTS: Unknown 1/ Terra; n Cost Factors Shown in Parentheses. 87 203 40 sq mi cfs in La rge Cone rete Gra vi ty 20 ft 1670 fmsl 1040 cu yd Concrete Ogee 10 ft 97 ft 1660 fmsl Steel Penstock 70 in 11300 ft 2 Horizontal Francis 1400 fmsl 235 ft 4843 kW 304 cfs 60.8 efs 2.2 138 2.0 2.0 mi kV/ phase mi mi 36 percent 15273 MWh Flow Duration Curve DRAt4AGE 1AS1N AEGIOtW. tNYEHTORY & ~ SMALL HYDROPOWER PROJECTS STUDY SOUTHCENTJltAL ALASKA , ..... V-.UNT .. ANA .IT ••• CONC.PTUAL \'A VOUT MOODY CREEK DEPARTMENT OF T ALASKA DISTRICT HE ARMY HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS Community: Suntrana Si te: 5 Stream: Moody Creek ITEM 1. Dam (including intake and spillway) 2. Penstock 3. Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Valves and Bifurcations 4. Switchyard 5. Access 6. Transmission TOTAL DIRECT CONSTRUCTION COSTS 7. Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Contingency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TOTAL ANNUAL COSTS Cost per kWh Benefit-Cost Rati 0 COST $ 317,000 $ 3,856,000 $ 1,659.000 $ 543,000 $ 144,000 $ 8,000 $ 245,000 $ 33,000 $ 206.000 $ 7,011,000 $ 701,000 $ 7,712,000 2.3 S17, 738,000 $ 4.434,000 $22,172,000 $ 3,326,000 $25,498,000 $ 2,422,000 $27,920,000 $ 5,770 $ 2,184,200 $ 335,000 $ 2,519,200 $ 0.17 1.95 REI..:, 1 or~AL 1 NVENTORY ~,: RECONNi~ I :::;ANCE ~:; nlflY -::::MAL L HYDRClF'O(..!t~F F'RO,JI~ C T' ALA:::;VA D I ::;TR T CT CORP::; I)F ENG J t'J'-F k:,: DETAILED RECuNNAIS8ANCE INVESTIG01 rONS COST OF HYDROPOWER -BENEFIT COST RATIO ::;:;UNTRANA YEAR 1 '~!:~:4 19:::::5 1 '?J::;::(~. 19:~r7 1 9:~~:::: 1990 1991 1992 19':;'::;: 1 ':'1';/4 199~) 199(:. 1997 19')::: 2000 2001 :::002 2003 2004 200':; 2006 2007 ,200:::: 2(l(l'~' 2010 2011 2012 2013 2014 2015 2016 2017 20i::: ::::1 TE NO. VWH/YEAR CAPITAL 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 21 0 8421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. 15273000. 2198421. :::::3~i()()() • 3::::5000. 3:::;:5000. ::::::::5000. :::::35000. ::;:::::5000. ::::::;:5000. :;1::;:5000. ~:::::::5000 • 335000. :::::~:5000. 335000. :::::~:":;ooo • ::::::~:~,OO(l. 3:3'5000. :;::3~;(l()(l • ::::::35000. :335000. :3:3~,()(J(J • 335000. 3:::50,00. 3::::5000. :3::::5000. :~::3500(l. :;:::;:5000. ~:::35(lOO . 335000. ::;:::::5000. :::::350(l0. ::::;:5000. :33~i(lOO . ::::3~;000 . ::::::~;OO(l. ::::::;:5000. ::::35000. 2019 15273000. 2198421. 835000. 2020 15273000. 2198421. 335000. 2021 15273000. 2198421. 335000. 2022 15273000. 2198421. 335000. 2023 15273000. 2198421. 335000. 2024 15273000. 2198421. 335000. 2025 15273000. 2198421. 335000. 2026 1 :;27~:000. 219:::421. 3:;':5000. 2027 15273000. 2198421. 335000. 2028 15273000. 2198421. 335000. 2029 15273000. 2198421. 335000. 2030 15273000. 2198421. 335000. AVERAGE COST sn:::WH $/!{WH TOTALS NONDISC OISC 2533421. 0.166 0,124 2533421. 0.166 0.115 2538421. 0.166 0.107 253:3421. 0.166 0.099 2533421. 0.166 0.092 2533421. 0.166 0.086 2533421. 0.166 0.080 2533421. 0.166 0.074 2533421. 0.166 0.069 2533421. 0.lA6 0,064 2533421. 0.166 0.059 2533421. 0.166 0.055 2533421. 0.166 0.051 2533421. 0.166 0.048 2533421. 0.166 C.044 2533421. 0.16A 0.041 2533421. 0.166 0.038 2533421. 0.166 0.03~ ~'.~i:3:~~:421 • (I. 1 h/:. O. O:L: 2533421. 0.16/:. 0.031 2533421. 0.16~ O.0~8 2!:i;3::;:421. I)" Ibl:. ('. 1)~26 2533421. 0.]66 0.025 2538421. O.16~ 0.023 2533421. 0.166 0.021 2533421. 0.166 0.020 2533421. 0.166 u.018 2533421. 0.166 0.017 2533421. 0.166 0.016 2533421. 0.166 0.015 2588421. 0.166 0.014 2533421. 0.166 0.013 2533421. 0.166 0.012 2533421. 0.166 0.011 2533421. 0.166 0.010 2533421. 0.166 0.009 2533421. 0.166 0.009 2533421. 0.166 0.008 2533421. 0.166 0.008 2533421. 0.166 0.007 2533421. 0.166 0.007 2533421. 0.166 0.006 2533421. 0.166 0.006 2533421. 0.166 0.005 2538421. 0.166 0.005 2533421. 0.166 0.005 2533421. 0.166 0.004 0.166 0.0:::::6 BENEFlf-·CIY:;T RATIO (5':-: FUEL CO~:;T C::a::ALATION): 1.95 0:: 0:: AnchOr '. ",*J ~~).;'_~):i ~.J:"""" ,tosh F o A L A 8 NOTE: TOPOGRAPHY FROM U. S. G. S. -BERING GLACIER ALASKA, 1:250,000 LEGEND ... DAM SITE • POWERHOUSE o SITE NO. --_. -PENSTOCK ---TRANSMISSION LINE --WATERSHED Umbrella Reei 5 o 5 E3 t==1 E3 SCALE I N MILES fEGIONAL INVENTORY a RECONNAISSANCE STUO'f SMALL HYDROPOWER PRO.£CTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PREUMINARY SCREENING CAPE YAKATAGA DEPARTMENT OF THE ARM ... ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING CAPE YAKATAGA, ALASKA ~dro~ower Potential Cost of Installed Installed Alternaj}ve Cost of Capacity Cost Power_ ~dropower Benefit/Cost Si te t~o. (kW) ($1000) (mills/kWh) (mill s/kWh) Ratio 7 137 1,102 466 608 0.77 5 137 1,473 466 748 0.62 4 137 1,678 466 825 0.56 1 137 1,726 466 844 0.55 6 137 1,884 466 903 0.52 2 137 1,962 466 932 0.50 3 137 2,298 466 1,088 0.43 9 137 2,380 466 1,126 0.41 8 137 2,785 466 1,318 0.35 10 137 3,359 466 1,590 0.29 Demogra~hic Characteri stics 1981 Population: 48 1981 Number of Households: 11 Economic Base Unknown 11 5 Percent Fuel Escalation, Capital Cost Excluded. REGIONAL INVErHORY & RECONtJAISA;JCE STUDY -SMALL HYDROPOWER F·RO.JECTS ALASt~A IIISTRICT -CORPS OF ENGINEERS LOAII FORECAST -CAF'E YAKATAGA KILOWATT-HOURS F'ER YEAR ANNUAL PEA,< I'EMAi'm-r~~· '{EAR LOW MEDIUM HIGH LOW MEI'IUM HIGH 1980 O. O. O. O. O. \) . 1981 22282. 22282. 22282. 8. 8. 8. 1982 44565. 44565. 44565. 15. 15. 15. 1983 66847. 66847. 66847. 23. 23. 23. 1984 89130. 89130. 89130. 31. 3L. 3 i. • 1985 111412. 111412. 111412. 38. 38. 3:1. 1986 133694. 133694. 133694. 46. 46. 46. 1987 155977. 155977. 155977. ~-~,~ . .::--...J ,,) • ~-~.) . ~988 178259. 178259. 178259. 6.1. 61. .~ i. • 1989 200542. 20,')542. 200542. 69. 69. 6';-• 1990 222824. 222824, 222824. 76. 7.!, • 76. 1991 232143. 240682. 249221 .• 81) • -~, 1;:1,. 8~. 1992 241462. 258541) • 275618. 83. 8v. 94. 1993 250781. 276398. 302015. 8,~ • 95. 1ij3. 1994 260101). 294256. 328412. 89. 1 I) i.. 112. 1995 269419. 312114. 354809. 92. 107. 122. 1996 2,'8738. 329973. 381207. 95. 113. 131. 1997 288057. 347831. 407604. 99. I1v. 14tj. 1998 297376. 365689. 4341}01. 102. 125. 14v. 1999 306695. 383547. 460398. 11)5. 131. 158. 2001} 316014. 401405. 486795. 108. 137. 167. 2001 324079. 420751. 517422. 111. 144. 177. 2002 332144. 440097. 548048. 114. 151. 1:38. 2003 34(211) • 459443. 578675. 117. 1:::,./. 1:~8 2004 348275. 478789. 609302. 119. 1,:'4. 2\)~ , 2005 356340. 498135. 639928. 122. 171. 21·~ • 2006 364405. 517480. 670555. 125. 177. 231) • 2007 372470. 536826. 7(H182. 128. 184. 241j. 2008 380536. 556172. 731809. 130. 1 :?f). -.::-' ':'...J l • 2009 388601. 5755L8. 762435. 133. 197. ' , , ,01. 2,)10 396666. 594864. 793062. L36. 2\j4. 272. 2011 401336. 602716. 81)41)96. 137. 21)6. 275. 2012 406006. 610568. 815130. 139. 209. 27~+ 2013 410676. 61842(,. 826163. 141. 212. 283. 2014 415346. 626272. 837197. 142. 214. 287. 2015 420016. 634123. 848231. 144. 217. 2 ";. l) • 2016 424686. 641975. 859265. 145. 2.2lj + 294. 2017 429356. 649827. 870299. 147. 223. 2q8. 2018 434026. 657679. 881333. 149. --c:-LL...J+ 302. 2019 438696. 665531. 892366. 150. 228. 3\)6. 2020 443366. 673383. 903400. 152. 231. 3~)9 • 2021 449022. 682732. 916442. 154. 234. 314. 2022 454678. 69208t) • 929483. 156. 237. 318. 2023 460334. 701429. 942525. 158. 240. 323. 2024 46599(j. 71\)778. 955566. 160. 243. 327. 2025 471646. 720126. 968608. 162. 247. 332. 2026 477302. 729475. 981649. 163. ,J::~ .:.,:JV. 336. 2027 482958. 738824. 994691. 165. 253. 341. 2028 488614. 748173. 1007732. 167. ")J:: ' ,·"JO. 345. 2029 49427,) • 757521. 11)20774. 169. 259. 350 21)3\) 499926. 766870. 1033815. 171. ,.-,O~. 354 ") /0 "\ \) I I .,~ \ \ NOTE; TOPOGRAPHY FROM U. S. G. S. -GULKANA ALASKA, I : 2!SO, 000 LEGEND .. DAM SITE • POWERHClISE o SITE NO ••••• PENSTOCK - - -TRANSMtSSION LINE -WATERSHED _Ie. dI I 5 0 H t=; H .\. c SCALE IN MILES 5 REGIONAl INVENTORY a RECONNAISSANCE ST1JD't SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PREU MINARY SCREEN I NG CHISTOCHINA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING CHISTOCHINA, ALASKA Hldro~ower Potential Cost of Installed Installed Alternaj}ve Cost of Capacity Cost Power_ Hydropower Benefit/Cost Site No. ( kW) (JI000) (mills/kWh) (mill s/kWh) Ratio 5 157 2,016 459 833 0.55 9 157 2,081 459 860 0.53 10 157 2,125 459 878 0.52 6 157 2,185 459 903 0.51 7 157 2,340 459 967 0.47 8 157 2,370 459 979 0.47 Demographic Characteri stics 1981 Population: 55 1981 Number of Households: 12 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. n.r:CIONAL INVENTOPY & RECONNAISANCE STUDY -S"lALL HYDROPOWER PROJECTS ALASKA DISTRIC'r -CORPS OF ENGINEERS LOAD FOHECAST -CHISTOCIIINA KILO\iAT'r-l!OURS PER YEAR ANNUAL PEAK DEMAND-KW YEAR LOH t-IEDIUM HIGH LOW MEDIU~l HIGH 1980 O. O. O. O. O. O. 1981 25532. 25532. 25532. 9. 9. 9. 19f~2 51064. 51064. 51064. 17. 17. 17. 19b3 76596. 76596. 76596. 26. 26. 26. 19t14 102128. 102128. 102128. 35. 35. 35. 1985 127660. 127660. 127660 • 44. 44. 44. 193(, 153191. 153191. 153191. 52. 52. 52. 1087 178723. 178723. 178723. 61. 61. 61. 1988 204255. 204255. 204255. 70. 70. 70. 19H9 229787. 229787. 229787. 79. 79. 79. 1990 255319. 255319. 255319. 87. 87. 87. 1') 9 1 265')97. 275781. 285566. 91. 94. 98. 1992 276675. 296244. 315812. 95. 101. 108. 1993 287353. 316706. 346059. 98. 108. 119. 1994 298031. 337169. 376306. 102. 1 15. 129. 1995 308709. 357631. 406552. 106. 122. 139. 1996 319388. 378093. 436799. 109. 129. 150. 1997 330066. 398556. 467046. 113. 136. 160. 1998 340744. 419018. 497292. 1 17. 143. 170. 1999 351,122. 439481. 527539. 120. 151. 181. 2000 362100. 459943. 557786. 124. 158. 191. 2001 371341. 482110. 592879. 127. 165. 203. 2002 380583. 504277. 627972. 130. 173. 215. 2003 389824. 526445. 663065. 134. 180. 227. 2004 399065. 548612. 698159. 137. 188. 239. 2005 408307. 570779. 733252. 140. 195. 251. 2006 417548. 592946. 768345. 143. 203. 263. 2007 426789. 615113. 803438. 146. 211. 275. 2008 436031. 637281. 838531. 149. 218. 287. 2009 445272. 659448. 873624. 152. 226. 299. 2010 454513. 681615. 908717 • 156. 233. 311. 2011 459864. 690612. 921360. 157. 237. 316. 2012 465215. 699609. 934003. 159. 240. 320. 2013 470566. 708606. 946646. 161. 243. 324. 2014 475917 • 717603. 959289. 163. 246. 329. 2015 481268. 726600. 971931. 165. 249. 333. 2016 486620. 735597. 984574. 167. 252. 337. 2017 491971. 744594. 997217 • 168. 255. 342. 2018 497322. 753591. 1009860. 170. 258. 346. 2019 502673. 762588. 1022503. 172 • 261. 350. 2020 508024. 771585. 1035146. 174. 264. 355. 2021 514505. 782297. 1050089. 176. 268. 360. 2022 520986. 793009. 1065033. 178. 272. 365. 2023 527466. 803721. 1079976. 181. 275. 370. 2024 533947. 814434. 1094919. 183. 279. 375. 2025 540428. 825146. 1109862. 185. 283. 380. 2026 546909. 835856. 1124806. 187. 286. 385. 2027 553390. 846570. 1139749. 190. 290. 390. 2028 559871. 857282. 1154692. 192. 294. 395. 2029 566351. 867994. 1169635. 194. 297. 401. 2030 572832. 878706. 1184579. 196. 301. 406. NOTE: TO POGRAPHY FROM U. S. G. S. -VALDEZ ALASKA, 1:250.000 LEGEND .. DAM SITE • POWERHOUSE o SITE NO. -----PENSTOCK - - -TRANSMISSION LINE -WATERSHED 5 0 5 E3 F=4 E3 SCALE 1 N MILES REGIONAL INVENTORY a REQ)NNAISSAHCE SfI.l7f SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYlR>POWER SITES IDENTIFIED IN PRELIMINARY SCREENING CHITINA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING CHITINA, ALASKA ~dro~ower Potential Cost of Installed Installed Al ternai}ve Cost of Capacity Cost Power_ ~dropower Benefit/Cost Site No. ( kW) ( $1000) (mi 11 s/kWh) (mi 11 s/kWh) Ratio 6 67 7,276 462 555 0.83 7 67 8,119 462 593 0.78 7A 67 8,105 462 592 0.78 8 67 8,185 462 596 0.78 19 67 1,008 462 681 0.68 10 67 1,011 462 682 0.68 17 67 1,110 462 727 0.64 9 67 1,130 462 735 0.63 20 67 1,159 462 749 0.62 18 67 1,281 462 803 0.58 Demographic Characteristics 1981 Population: 25 1981 Number of Households: 6 Economic Base Unknown 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. REGIONAL I?~VENTOFY & RECONNAISANCr: STUDY -SMALL HYDROPOWER PkOJECTS ALASKA DISTRICT -COKPS OF ENGINEERS LOAO FORECAST -CHITINA A'fli~< KILOWA'fT-/lOURS PER YE1\R ANNUAL PEAK Dl::HAND-K~v 'iEl.:' LO\J Hl.:DIm4 HIGH LOW MEDIU~l HIGH 1980 100000. 100000. 100000. 34. 34. 34. 19~1l 104182. 104182. 104182. 36. 36. 36. 19i32 108365. 108365. 108365. 37. 37. 37. 10 )13 112547. 112547. 112547. 39. 39. 39. 1q:-:<4 llfi729. 116729. 116729. 40. 40. 40. 1985 120911. 120911. 120911. 41. 41. 41. 19f.)~ 125094. 125094. 125094. 43. 43. 43. 19~7 129276. 129276. 129276. 44. 44. 44. 19B8 133458. 133458. 133458. 46. 46. 46. 1 <J~~9 137641. 137641. 137641. 47. 47. 47. 19')0 141823. 141823. 141823. 49. 49. 49. 1')')1 145443. 149890. 154337. 50. 51. 53. 1992 149062. 157957. 166852. 51. 54. 57. 1~)93 152682. 166024. 179366. 52. 57. 61. 1994 156301. 174091. 191880. 54. 60. 66. 1995 159921. 182158. 204394. 55. 62. 70. 1996 163540. 190224. 216909. 56. 65. 74. 1997 167160. 198291. 229423. 57. 68. 79. 199:3 170779. 206358. 241937. 58. 71. 83. 1999 174399. 214425. 254452. 60. 73. 87. 2000 17eo 18. 222492. 266966. 61. 76. 91. 2001 180114. 230463. 200813. 62. 79. 96. 200:.! 182210. 238435. 294659. 62. 82. 101. 2003 184305. 246406. 308506. 63. 84. 106. 2004 186401. 254377. 322353. 64. 87. 110. 2005 180497. 262349. 336199. 65. 90. 115. 2006 190593. 270320. 350046. 65. 93. 120. 2007 192689. 278291. 363893. 66. 95. 125. 2008 194784. 286262. 377740. 67. 98. 129. 2009 196080. 294234. 391586. 67. 101. 134. 2010 198976. 302205. 405433. 68. 103. 139. 2011 201514. 306401. 411286. 69. 105. 141. 2012 204053. 310596. 417139. 70. 106. 143. 2013 206591. 314792. 422991. 71. 108. 145. 2014 209130. 318987. 428844. 72. 109. 147. 2015 211668. 323183. 434697. 72. 111. 149. 2016 214206. 327378. 440550. 73. 112. 151. 2017 216745. 331574. 446403. 74. 114. 153. 2018 219283. 335769. 452256. 75. 115. 155. 2019 221822. 339965. 458100. 76. 116. 157. 2020 224360. 344160. 463961. 77. 118. 159. 2021 226431. 348154. 469879. 78. 119. 161. 2022 228502. 352149. 475796. 78. 121. 163. 2023 230573. 356143. 481714. 79. 122. 165. 2024 232644. 360138. 487632. 80. 123. 167. 2025 234715. 364132. 493549. 80. 125. 169. 2026 236787. 368126. 499467. 81 • 126. 171. 2027 238858. 372121. 505385. 82. 127. 173. 2028 240929. 376115. 511303. 83. 129. 175. 2029 243000. 380110. 517220. 83. 130. 177. 2030 245071. 384104. 523138. 84. 132. 179. 5 ° 5 E3 1---1 E3 SCALE IN MILES NOTE: TOPOGRAPHY FROM u. S. G. S. -NABESNA ALASKA, 1:250,000 LEGEND 'Y DAM SITE • POWERHOUSE o SITE NO. -----PENSTOCK - - -TRANSMISSION LINE I ---WATERSHED AEGIONAL INVENTORY a AEQ)NNAJSSANCE ST\.D'f SMALL HYDROPOWER PRO.ECTS SOUTHCENTRAL ALASKA HYtIIDPOWER SITES IDENTIFIED IN PREUMINARY SCREENING NABESNA DEPARTMENT OF THE ARMV ALASKA DISTRICT CORPS OF ENGINEERS Hydropower Potential Si te No. 3 2 6 1 5 7 4 8 Installed Capacity ( kW) 114 114 114 114 114 114 114 114 Demographic Characteristics 1981 Population: 40 SUMMARY DATA SHEET PRELIMINARY SCREENING NABESNA, ALASKA Installed Cost (31000) 9,423 1,124 1,180 1,355 1,766 1,841 2,117 2,211 Cost of Al terna\i1ve Power_ (mills/kWh) 473 473 473 473 473 473 473 473 1981 Number of Households: 9 Economi c Base Unknown 11 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of ~dropower (mi 11 s/kWh) 658 740 765 844 1,030 1,064 1,203 1,256 Benefit/Cost Ratio 0.72 0.64 0.62 0.56 0.46 0.44 0.39 0.38 Rl:£IONAL I NVEi"TORY & H ECONNA I SANC E STUDY -S~1ALL HY D~OPO\Oit:: R PhQJr.;CTS ALASKA DISTRICT -CORPS OF ENGINE£RS LOAD FORSCAST -NABESt~A KILOWA'fT-IIOURS PER YEAR Al~NUAL PEAK DEHANU-K\\ YEAr< LOW MEDIUM HIGH LOW MEDIlJr-1 HIGH 1980 O. O. o. o. o. O. 1981 18569. 18569. 18569. 6. E.. 6. 1982 37137. 37137. 37137. 13. 13. 13. 1983 55706. 55706. 55706. 19. 19. 19. 19114 74274. 74274. 74274. 25. 25. 25. 1985 92843. 92843. 92843. 32. 32. 32. 198(; 111412. 111412. 111412. 3R. 38. 38. 1987 129980. 129980. 129980. 45. 45. 45. 1998 148549. 143549. 148549. 51. 51. 51. 1909 161117. 167117. 167117. 57. 57. 57. 19C)O 1B5686. 185686. 10 56B0. "[;1'1. 64. f)4. 1991 193452. 200'if.B. 207684. 6(>. 69. 71- 1992 201212. 21545(). 229681. ,-,., t.:~. 74. 79. 1903 208984. 230331. 251679. 72. 79. B6. 1994 216750. 245213. 273(;77 • ;·1. 8~. ~)4 • 19~5 ~2451(;. 260095. 295(',7'). 77. S9. 101. 1996 232281. 274q77 • 317672. 80. 94. 109. 1997 240047. 289859. 339670. 82. 99. 116. 1.998 247813. 304740. 3F.1668. 85. 104. 124. 1999 255579. 319622. 383665. 8~. 109. 131. 2000 263345. 334504. 405663. 90. 115. 139. 2001 270066. 350626. 431185. 92. 120. 148. 2002 276787. 366747. 456707. 95. 126. 156. 2003 283508. 382869. 482230. 97. 131. 165. 2004 290229. 398990. 507752. 99. 137. 174. 2005 296950. 415112. 533274. 102. 142. 183. 2006 303671. 431234. 558796. 104. 148. 191. 2007 310392. 447355. 584318. 106. 153. 200. 2008 317113. 463477. 609841. 109. 159. 209. 2009 323834. 479598. 635363. 11 1 • 164. 218. 2010 330555. 495720. 660885. 113. 170. 226. 201 1 334447. 502263. 670080. 115. 172. 229. 2012 338338. 508807. 679275. 116. 174. 233. 2013 342230. 515350. 688470. 117 • 176. 236. 2014 346122. 521893. 697665. 119. 179. 239. 2015 350013. 528437. 706859. 120. 181. 242. 2016 353905. 534980. 716054. 121. 183. 245. 2017 357797. 541523. 725249. 123. 185. 248. 2018 361689. 548067. 734444. 124. W8. 252. 20"19 365580. 554611"1. 743639. 125. 190. 255. 2020 369472 • 561153. 752R34. 127. 192. 258. 2021 374135. 568944. 763702. 128. 195. 262. 2022 37tl899. 576734. 774570. 130. 198. 265. 2023 383612. 584525. 785437. 131. 200. 269. 2024 3f38325. 592316. 796305. 133. 203. 273. 2025 393039. 600106. 807173. 135. 206. 276. 2026 397752. 607897. 818041. 136. 208. .280. 2027 402465. 615687. 828909. 138. 211. 284. 2028 407179. 623·178. 839777. 139. 2~4. 288. 2029 411892. 631269. 850644. 141. 216. 291. 2030 416605. 639059. 861512. 143. 219. 295. -,Creek + ,-' flrk-Cap) (. , " ~ ,1;Omg -." I , 'l.4.e g. ';,$1 £~. . '\A~':'I., ~ . 't"., '. " Cryll141 --': _-Lake3 Two Bit . ' J • NOTE; TOPOGRAPHY FROM U. S. G. S. -MT. HAYES, GULK A ALASKA J I : 250,000 lEGEND • DAM SITE • POWERHOOSE o SITE NO • -_.-PENSTOCK -- -TRANSMtSSION LINE -WATERSHED 5 o 5 E3 H H SCAl E IN MilES REGIONAL INVENTORY a RECX)NNAlSSANCE ST'UO"I' SMAU HYDROPOWER PRO.ECTS SOUTHCENTRAl AlASKA HYDROPOWER SITES IDENTIFIED IN PREU MINARY SCREEN I NG PAXSON DEPARTMENT OF THE ARM'f ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING PAXSON, ALASKA H,ldroeower Potenti al Cost of Installed Installed Alterna I7 ve Capacity Cost Power_ Site No. (kW) (~1000 ) (mill s/kWh) 1 65 7,176 459 2 65 8,916 459 6 65 1,156 459 5 65 1,336 459 4 65 1,378 459 3 65 1,529 459 Demographic Characteri stics 1981 Population: 24 1981 Number of Households: 7 Economic Base Touri sm Subsi stence 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. Cost of Hydropower Benefit/Cost (mi 11 s/kWh) Ratio 574 0.80 655 0.70 778 0.59 863 0.53 882 0.52 952 0.48 F.i:GIOl~M" HlVSti1.'GRY & RECONNAISANCE ~TU[)Y -SHALL flYDROPOYiER PHOJECTS ALASKA DISTRICT -CORPS OF SNGINEEHS o : 1 19ti2 19n3 1 '124 1985 1986 1987 1C'(::3 1'.,lfl9 1') (JO 1 () 01 1 '.1'.32 1W~3 1994 1995 199G 1997 1998 1999 2000 2001 2002 2003 ;'004 2005 2006 2007 2008 20(19 2010 2011 2012 2013 201,1 2015 2016 2017 201R 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 KI LUIJAT'l'-llOCRS PEn YEAR Lm~ 11r:DIllf.1 HIGH 96000. 96000. 96000. 100015. 100015. 100015. 104030. 103045. 112060. 116075. 120090. 124105. 1281 20. 132135. 136150. 139625. 143099. 146574. 150049. 153524. 156998. 160473. 16394B. 167422. 170897. 172909. 174921. 176933. 178945. 180957. 182969. 184981. 186993. 189005. 191017. 193454. 195891. 198327. 200764. 203201. 205638. 208075. 210511. 21294H. 215385. 217373. 219362. 221350. 223338. 225326. 227315. 229303. 231291. 23J280. 235268. 104030. 108045. 112060. 116075. 120090. 124105. 128120. 132135. 136150. 143894. 151638. 159383. 167127. 174871. 182615. 190359. 198104. 205848. 213592. 221244. 22P897. 236549. 244202. 251854. 259506. 267159. 274811. 282464. 290116. 294144. 298172. 302199. 306227. 310255. 314283. 318311. 322339. 326366. 330394. 334229. 338063. 341898. 345732. 349567. 353402. 357236. 361071. 364905. 368740. 104030. 108045. 112060. 116075. 120090. 124105. 128120. 132135. 136150. 148164. 160178. 172191. 184205. 196219. 208233. 220247. 232260. 244274. 256288. 269581. 282873. 296166. 309459. 322751. 336044. 349337. 362630. 375922. 389215. 3941134. 400452. 406071. 411690. 417308. 422927. 428546. 434165. 439783. 445402. 4510R3. 456764. 462445. 468126. 473807. 47948P. 485169. 490850. 496531. 502212. A1JNUM, PEAK DJ..:i1AND-K\,' LOW ~'1CDI1Jr-l HIGH 33. 33. 33. 34. 34. 34. 36. 36. 36. 37. 38. 40. 41- 43. 44. 45. 47. 48. 49. 50. 51- 53. 54. 55. 56. 57. 59. 59. 60. 61. 61. 62. 63. 63. 64. 65. 65. 66. 67. 68. 69. 70. 70. 71. 72 • 73. 74. 74. 75. 76. 76. 77. 78. 79. 79. 80. 81. 37. 38. 40. 41. 43. 44. 45. 47. 49. 52. 55. 57. 60. 63. 65. 68. 70. 73. 76. 78. Bl • 84. 86. 89. 91. 94. 97. 99. 101. 11':) 2 • 103. 105. 106. lOU. 109. 110. 112. 113. 114. 116. 117. 1 18. 120. 121. 122. 124. 125. 126. 37. 3H. 40. 41- 43. 44. <15. 47. 51- 55. 59. t3 • 67. 71. 75. 80. 92. 97. 101. 106. 111. 115. 120. 124. 129. 133. 135. 137. 139. 141. 143. 145. 147. 149. 151- 153. 154. 156. 158. 160. 162. 164. 166. 168. 170. 172 • NOTE: TOPOGRAPHY FROM U. S. G. S. -TALKEETNA t TV NEK ALASKA, I: 250,000 LEGEND ~ DAM SITE • POWERH()JSE o SITE NO -----PENSTOCK ---TRANS MtSSION LINE -WATERSHED 5 E3 o H H ·/."h, ·Cab,;:", Me Doug':\ ISitt) SCALE IN MILES 5 REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING SKWENTNA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING SKWENTNA, ALASKA ~dropower Potential Cost of Installed Installed Al terna'Hve Cost of Capaci ty Cost Power_ Hydropower Benefi t/Cost S; te No. ( kW) ( nOOO) (mill s/kWh) (mill s/kWh) Ratio 4 46 1,082 512 1,802 0.28 2 46 1,257 512 2,000 0.26 3 46 1,250 512 1,992 0.26 1 46 1,037 512 2,057 0.25 Demographic Characteristics 1981 Population: 16 1981 Number of Households: 5 Economic Base Unknown 11 5 Percent Fuel Escalation, Capital Cost Excluded. F).3(1 1 ,)~, 1 1':'32 1(')J3 1 'j ;,1 it 1',l:J5 1'.li.;(, 19 ;17 , 9~~) 1 f) lJO 1':H1 1 ') ,)2 1'-1"3 1'j)4 l'~q5 1996 .1'197 1998 199'1 2000 .2001 2002 2003 2004 .2005 20C6 2n07 2008 2 n09 201U .2 0 11 2012 2013 2u14 2015 2011; 2017 2n1F 2019 202() 2 fi2 2 20n 2024 202fi 2026 2fJ27 202l] 2029 2030 ':'C I' ):.h!. I"V:::i'ITUHY & R 1 :CONNAI SANCC S':;:'UIJY -S~ll\LL tlY~ROPOViER PEOJ ECTS ALASYJI DI;~TRICT -CO~::' OF ~;NGINEERS KILO\il\TT-1HoiJRS PER YEAR Lo\; O. 7422. ~lLUlml o. LOW MEDIv":~ llIGli 14855. 22283. 2':1710. 37138. 44565. 51993. 59420. 66134<3. 7 :~2 75. 77 381. H04B8. 83594. 86700. B9H06. 92913. 96019. 99125. 102232. 105338. 10['026 • llU715. 113403. 116092. 1187[lO. 121468. 124157. 126845. 129534. 132222. 133779 • 135335. 130892. 13£14,19. 140006. 1415('2. 143119. 14467fi. 14(, 2 32. H7789. 14')674. 151S60. 153445. 155330. 157215. 159101. 16098(, • 162871. 161;757. 16GG42. 7428. 14;355. 22283. 29710. 37138. 44565. 51993. 59420. 66848. 74275. 79958. 856,12. 91325. 97008. 102691. 1013375. 114058. 119741. 125425. 131108. 137201. 143294. 149386. 155479. 161572. 167665. 173758. 179850. 185943. 192036. 194553. 197070. 199587. 202104. 204621. 207137. 209654. 212171. 214688. 217205. 220205. 223205. 226204. 229204. 232204. 235204. 238204. 241203. 244203. 247203. O. 7428. lMl55. 22283. 29710. 37138. 44565. 51993. 59420. 66842. 74275. t2535. 90796. 99056. 107316. 115576. 123l:l37. 132097. 14u357. 148618. 156P78. lG6375. 175872 • 185369. 194866. 204363. 213861. 223358. 232855. 242352. 251849. 255326. 2'18803. 262281. 265758. 269235. 272712. 276189. 279667. 2U3144. 286621. 290735. 294849. 298964. 303078. 307192. 311306. 315420. 319535. 323649. 3.71763. O. O. 3. 5. H. 10. 13. 15. lB. 20. 23. 25. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41 • 42. 43. 43. 44. 45. 46. 46. 47. 47. 48. 4A. 49. 50. 50. 51. 51. 52. 53. 53. 54. 54. 55. 56. 56. 57. 3. 5. 8. 10. 13. 15. 18. 20. 23. 25. 27. 29. 31. 33. 35. 37. 39. 41. 4 J. 45. 47. 49. 51. 53. 55 • 57. 60. 62. 54. 66. 67. 67. 68. 69. 70. 71. 72. 73. 74. 74. 75. 76. 77. 7B. BO. Pl. 82. 83. 85. o. 3. 5. P. 10. 13. 15. 18. 20. 23. 25. 2e. 31. 34. 37. 40. 42 • 45. 4B. 51. 54. 57. (')0. 63. 67. 70. 73. 76. 80. 83. 86. 87. 89. 90. 91. 92. 93. 95. 96. 97. 98. 100. 101 • 102. 104. 105. 107. 108. 109. 111 • 112. .. 'it {lo i 'r , ( , ___ ._ca __ .::.,!" NOTE: TOPOGRAPHY FROM US.G.S.-NABESNA, GUL NA ALASKA, 1:250,000 LEGEND ~ DAM SITE • POWERHOUSE o SITE NO. -----PENSTOCK ---TRANSMISSION LINE ---WATERSHED 5 0 5 E3 E3 I---l SCALE IN MILES REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED I N PREll MINARY SCREEN I NG SLANA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING SLANA, ALASKA Hldro~ower Potential Cost of Installed Install ed Alternaj}ve Cost of Capacity Cost Power_ Hydropower Benefit/Cost Site No. (kW) (~1000 ) (mill s/kWh) (mills/kWh) Ratio 6 34 8,374 466 2,034 0.23 5 34 1,009 466 2,292 0.20 8 34 1,077 466 2,395 0.19 7 34 1,159 466 2,519 0.18 9 34 1,167 466 2,531 0.18 Demogra~hic Characteristics 1981 Population: 12 1981 Number of Households: 3 Economic Base Unknown 11 5 Percent Fuel Escalation, Capital Cost Excluded. fif.GIOhAL P';VEi','lORY " RECONNAlbANCL STUDY -St-lALL HYI)ROpm~E,H PHOJEC'i'~ hLi\SY.A DISTRICT -CO,,!'S 01:" EtlGHlEl::RS 1" 1 1'182 i .1.n 1 '"1" 5 19 ;~f. 1<';37 1 ~[) 1 C) 1 1 n (:] 1 n ." 1 q ~')7 19 (Xl 1999 .;;(\UO 2UCl1 2(;02 ;:; fl()3 :' (,04 :2 DO 5 2(;(;0 ;:;n07 ;:;008 200c) 2010 2011 2fJ12 2013 2014 2015 20H; 2(;17 201f3 2U19 2020 ;,:n21 2022 2023 2024 2025 20:!6 2027 2028 2029 2030 KILC\v,\TT-HOlJl<; PER YEAR LO(; MCDIUt1 HIGH O. 5571. 11141. 16712. 222B2. 27853. 3 3L!24. 3?994. ·H565. 50135. 55706. 5H03l •• 6036E. 62695. G5025. 07355. 74344. 76674. 79004 • 81020. 83036. 85053. 87069. 890[15. 91101. 93117 • 95134. 97150. 9916(;. 100334. 101501. 102669. 1 fJ3,:n6. 105004. 106172. 107339. 1013507. 10')674. 110842. 112256. 113670. 115084. 116498. 117<)12. 119326. 120740. 122154. 1235GB. 124982. O. 5571. 111<11. 16712. 22282. 27B53. 33424. 3fl<)94. 44565. 50135. 55706. 60171 • 64635. uCl100. 73564. 7(l029. 82493. [:G95B. 91422. 95887. 100351. 105WP. 110024. 1141::61. 1191S97. 124534. 129370. 134207. 139043. 143880. 148716. 150679. 152642. 154605. 156568. 15fl531. 160494. 162457. 16-1420. 16631:33. 16B346. 170683. 173020. 175358. 177695. 180032. 182369. 184706. 1870/14. 1893A1. 191718. O. 5571. 11141. 16712. 22282. 27853. 33424. 389')4. 44565. 50135. 55706. 62305. 68905. 75504. Q2103. '::'702. 05302. 101901- 108500. 115100. 121699. 129356. 137012. 144G69. 152326. 1599B3. 1[,7639. 17 5296. 182953. 190609. 198266. 201024. 203783. 206541. 209300. 212058. 214816. 217575. 220333. 223092. 225B50. 229110. 232371. 235631. 238892. 242152. 245412. 248673. 251933. 255194. 258454. AKt:UAL PEAK lIcr·iN:' D-K\.v LO\'! r'ELIur·' HIGll o. O. O. 2. 4. 6. 8. 10. 1 1 • 13. 15. 17. 19. 20. 21. 21. "'"1 L ..... 23. 25. 26. 27. 28. 28. ~9. 30. 31. 31. 32. 33. 33. 34. 34. 35. 35. 36. 36. 36. 37. 37. 38. 38. 3R. 39. 39. 40. 40. 41. 41. 42. 42. 43. 2. 4. 10. 1 1 • 13. 15. 17. 19. 21 • 22. 24. 27 • 3G. 31- 33. 34. 36. 41- 43. 44. 40. 48. 49. 51- 52. 52. 53. 5il. 54. 55. 56. 56. 57. 58. 5B. 59. GO. 61. 62. t2. 63. 64. 65. 66. ~ . 10. 11 • 13. 15. 17. 19. 21. 24. 2 • 30. 33. 37. 39. 42. 44. ';'7. 50. 52. 55. 57. 60. 63. 65. 68. 69. 70. 71. 72. 73. 74. 75. 75. 76. 77. 78. 80. 81. 1:32. 83. 84. 85. 86. 1:37. 89. 1--' --.. ~~-- SI/(,ket' 205 fAt!.',. NOTE: TOPOGRAPHY FROM U.S.G.S.-TYONEK ALASKA, I: 250,000 LEGEND • DAM SITE • POWERHOUSE o SITE NO PENSTOCK - - -TRANSM'SSION LINE ---WATERSHED 5 WI,il, .. ! L<lkr o r' I, Creek , ,Hock , Lake ;..... 5 E3 H I=-=i SCALE IN MILES REGIONAL INVENTORY a RECONNAISSANCE STUDY SMALL HYDROPOWER PROJECTS SOUTHCENTRAL ALASKA HYDROPOWER SITES IDENTIFIED IN PRELIMINARY SCREENING SUSITNA DEPARTMENT OF THE ARMY ALASKA DISTRICT CORPS OF ENGINEERS SUMMARY DATA SHEET PRELIMINARY SCREENING SUSITNA, ALASKA Hydropower Potenti a1 Cost of Insta 11 ed Installed Al ternai}ve Cost of Capaci ty Cost Power_ Hydropower Benefit/Cost Si te No. (kW) ($1000 ) (mills/kWh) (mi 11 s/kWh) Ratio 3 110 1,370 512 811 0.63 4 91 1,368 512 823 0.62 2 120 2,773 512 1,500 0.34 1 120 3,413 512 1,846 0.28 Demographic Characteri stics 1981 Population: 42 1981 Number of Hoseho1ds: 9 Economi c Base 11 5 Percent Fuel Escalation, Capital Cost Excluded. r~X:lnt!I\L I:'lVE;n'ORY & RECOtmAI~;ANCL f/rlH)':{ -SHALL HYOROPO\.LR PROJr.::CTS ALi-IS:'::'A DISTPICT -COHPS 01" r:t,GI;~EERS 1'.no Flf!1 1') :12 19;13 19.'::14 pes 19.'36 19f:7 1" 1 'l ') 1 1 ',0:> 1 C" j 1 1 ;, 1':195 19 <)(, 1997 1908 1999 2000 2001 2 003 2004 2005 2006 2007 21)03 2009 2010 2011 2G12 2013 2014 ~Q15 2016 ::017 201::-' 2019 2020 2021 2022 '::023 2 (\:) 4 2025 2(126 2027 2028 2029 2030 LOAD FORl::ChST -SUSrrNA KILO\~ArrT-!lOURS prR YEAH LOi-i NEDIUM HIGlI O. 19497. 38994. 52491. 77988. 9748G. 116983. 1364BO. 155977. 17 5474. 1%971. 203125. 2 1 1 27 C). 2 F)433. 2275t'7. 235741. 24389(,. 252050. 2(;U204. 268358. 276512. 283569. 290626. 2976t'.3. 304740. 311797. 31RH54. 325911. 332%8. 340025. 347082. 351168. 355255. 359341. 363427. 367514. 371600. 375686. 379773. 383859. 3B7945. 392B94. 397d43. 402792. 407741. 412690. 41764(). 42258'). 427538. 4324n7. 437436. O. 19497. 38994. :'8491. 77988. 97486. l1G9B3. 136480. 155977. 175<174. 194971. .209890. 2 2'1!3Cd. 2 ]')727. 25,::;646. 2Ci9565. 2844B3. 299402. 314321. 329239. 344158. 360152~ 376145. 392139. 408132. 42412(). 440120. 456113. 472107. 488100. 504094. 510701. !S17308. 523q 15. 53()S22. 537129. 543735. 550342. 556949. 563556. 570163. 578037. 585912. 593786. 601661. 609535. 617409. 625284. G33158. 641032. M8907. O. 19497. 38994. 58491. 7798fJ. 97486. 116983. 13(,480. 1S5~J77. 175<174. 19<4971. 216654. 2 .:H~\ 338. 2(,U021. 281704. 303386. 325071. 346754. 368437. 390121. 411804. 436734. 461(-64. 486594. 511524. 536455. 561385. 586315. 611245. 636175. 661105. 670233. 679360. 688488. 697616. 706743. 715871. 7249%. 7341?6. 743254. 752381. 763181. 77398U. 7U4780. 795580. 806379. 817179. 827979. e38779. 849578. 860378. A~NUAL Pr:AK DGIAND-1<'W LOU MEDIlJr'i HIGtt O. 0. O. 7. 7. 7. 13. 20. 27. 33. 40. 47. 53. 60. 67. 70. 72. 75. 78. 81. 84. 86. 89. 92. 95. 97. 100. 102. 104. 107. 109. 112. 114. 116. 119. 120. 122. 123. 124. 126. 127. 12<) • 130. 131. 133. 135. 136. 138. 140. 14,. 143. 145. 146. 148. 150. 13. 20. 27. 33. 40. 47. 53. bO. G7. 72. 77. S7. 92. 97. 103. 10f'. 113. 118. 123. 129. 134. 1·10. 145. 151. 156. 162. 167. 173. 175. 177. 179. lB2. 1B4. 1136. 188. 191. 193. 195. 19~. 201. 203. 206. 209. 211. 214. 217 • 220. 222. 13. 20. 27. 33. 40. 47. 53. GO. (7. 74. 39. 104. 1 11 • 119. 126. 134. 141. 150. 158. 167. 175. 184. 192. 201. 209. 218. 226. 230. 233. 236. 239. 242. 245. 248. 25,. 255. 258. 261. 265. 269. 272. 276. 280. 284. 287. 291. 295. APPENDIX A UTILITY RATE SCHEDULES Table A-I Homer Electric Association Residential Electricity Rate Schedule ~ant; ty Consumed per Month (kWh) Schedule 1 -North of Kachemak Bay Fi rst 1000 kWh Over 1000 KWh Schedule 2 -South of Kachemak Bay All kWh Additional Charges Service Charge Fuel Surcharge Table A-2 Matanuska Electric Association Residential Electricity Rate Schedule ~anti ty Consumed per Month (kWh) 1st 100 kWh next 150 kWh next 250 kWh next 700 kWh over 1200 kWh A-I Cost ($ /kWh) .0415 .0315 .0500 ~12.50/month .001317 Cost (S /kWh) .135 .090 .068 .037 .030 Table A-3 Copper Valley Electric Association Residential Electricity Rate Schedule Quantity Consumed per Month ( kWh) Fi rst 100 kWh next 100 kWh next 400 kWh over 600 kWh Additional Charges Ni nimum charge Fuel Surcharge Credi ts Power Production Cost Assistance Program (100 percent participation rate among households) Table A-4 Chugach Electric Association Residential Electricity Rate Schedule Suburban Schedule Quantity Consumed per Month ( kWh) First 50 kWh next 200 kWh next 500 kWh next 750 kWh over 1500 kWh Mi nimum Cha rge A-2 Cost ($ IkWh) .24 .205 .170 .130 S20.00 .0258 .0389 Cost (S /kWh) .105 .062 .044 .027 .023 S4.68 Table A-5 Cordova Electric Cooperative Residential Electricity Rate Schedule ~antity Consumed per Month (kWh) Fi rst 1000 kWh over 1000 kWh Additional Charges Service charge Fue 1 Su rcha rge Table A-6 Cost ($ /kWh) .18 .16 $18.00 (per month) .0973 Golden Valley Electric Association Interim Residential Electricity Rate Schedule ~anti ty Consumed per Month ( kWh) 1 st 100 next 1,400 over 1, SOO Mi nimum charge A-3 Cost ( !/kWh) .186 .105 .0847 $11.35 APPENDIX B METHODOLOGY FOR DRAINAGE BASIN INVENTORY AND PRELIMINARY SCREENING APPENDIX B METHODOLOGY FOR DRAINAGE BASIN INVENTORY AND PRELIMINARY SCREENING This Appendix contains the assumptions and methodology used in the drainage basin inventory and preliminary screening phase for the reconnaissance study of small hydropower projects in Southcentral Alaska. The purpose of the first screening is to identify those potentially viable hydroelectric sites which, based on a preliminary comparison with costs of alternative thermal generation, warrant more detailed investigations. Outline of Proposed Methodology for Basin Inventory and Preliminary Site Screening A. Basin Selection 1. Using USGS 1:250,000 maps locate each community and draw a 15 mile radius c'ircle around the community center. 2. Visually reconnoiter all drainage basins. Select approxi- mately the six (6) best sites, preferably located within the circle, for investigation. Sites should be sized to meet the following criteria: Provide 80 percent of the year 2030 low demand scenario. This is approximately equal to average day peak demand. Intertied communities are sized based on the intertied average peak day demands for the communities in this study. Sites that exceed the demand are costed to identify above average potential for industrial or "new town" expansion. These sites are to be scaled down to meet the above criteria in the second loop of the evaluation process. The sites for the list are to be selected in a logical manner, beginning with the principal river or stream and moving thence into the smaller tributaries. The best sites meeting the above load criteria shall then be entered into the summary table. No sites in Canada are considered. 3. Indicate the sites selected on the USGS map, including the following features: 1) Drainage basin boundaries above damsite 2) Dam and powerhouse location 3) Penstock route 4) Transmission line route 5) Site identification number B-1 B. Compilation of Summary Table 1. For each site selected for the Summary Table proceed to measure and/or calculate the following parameters and enter the values in the table: a. Pl animeter basi n areas (A b) usi ng a zero setti ng planimeter, calibrated to yield a value in square miles in 2 passes; b. Using maps obtained from Joint Federal State Land Use Planning Commission estimate isolines for mean annual runoff (R,n) in cfs per square mile; c. Determine average flow: (Q) = Ab X Rm in cfs; d. Measure transmission distance (Ot) in miles and penstock length (Op) in feet and record penstock elevation range; e. Estimate gross head (H g ), the elevation difference between damsite and powerhouse site, and add a 5 foot diversion dam height allowance; f. Calculate net head (Hn) as 90 percent x Hg; g. Calculate installed capacity (Pi) in kilowatts as: h. Pi = (1.5 x Q x Hn x 0.85}/11.8; Calculate individual machine capacity (Mc) as Pi/N (where N is the number of units, assumed to be , in this study) ; Calculate annual energy production eE) as: E = Pi x P.F. x 8760 hr/yr, where P.F. is the plant factor, equal to 0.45 for plant sites where installed capacity exceeds 25 percent of the 2030 average day peak demand and 0.55 for sites with less than or equal to 25 percent. j. Using the modified Gordon-Penman equation estimate the capital cost of generating equipment and powerhouse: Ce = 13639.5 S KeKa (NM c )0.7 (H n )-0.35 where S is the Siting factor relating project cost to powerhouse and equipment cost and is taken to be 3.7 for plants less than 500 kW and 2.6 for plants greater than or equal to 500 kW. Ke is the escalation factor to B-2 October 1981 from January 1978, based on the composite index from WPRS, and is equal to 1.35 for this study. K is an Alaska cost adjustment which was assumed to be 2.00 for this study. k. Calculate October 1981 transmission costs (C t ) in dollars as follows: 1) Pi x Dt = kW -lid 2) If kW -mi > 133,909, Ct (cost of transmission) = 300,000 Dt (115 kV, 3 phase) 3) If 24,000 < kW -mi ~ 133,909 (38 kV, 3 phase) Ct = 150,000 Dt 4) If 12,000 < kW -mi.< 24,000 (14.4 kV 3 phase) Ct = 120,000 Dt - 5) If kW -mi < 12,000 Ct = 50,000-+ 50,000 Dt (14.4 single phase) 6) If single wire ground return transmission systems (single phase) are allowable and kW -mi ~ 15,000 use Ct = 50,000 Dt + 50,000 7) Submarine cable 550,000 x length of cable in miles Li ne Losses are 1 imited to 5 percent. 1. Calculate penstock costs (C p ) in dollars: Cp = Ks [37.21 C1.5Q)1/2 -15] Dp Hn/600 where a minimum Hn is computed based on the USBR minimum handling thickness design and used where the net head is less than the resultant pressure for handling thickness, Q min is 0.5 cfs, and K = 1.14, the escalation factor to October 1981 ~rom June 1980. m. Mobilization and Dam costs (Cd) as follows: 10/81 Installed Capacity N(M c ) 0-100 kW 101-500 kW 501-1000 kW >1000 kW B-3 Cost of Mobilization plUS Dam U50,OOO 250,000 400,000 600,000 Dam costs are based on 30 foot wide sheetpile dam, 5 feet high and are estimated at $50,000. n. Calculate sum of costs (C s ) in dollars Cs = (C e + Ct + Cp + Cd) Kr Where Kr is a remoteness factor, equal to 1.0 ; n the Southcentral region. o. Operation and maintenance costs are calculated as the greater of 2 percent of capital costs or $40,000. p. Calculate cost of energy (Ck) in mills per ki10wat hour Ck = 0.09823 Kr Cs 1000 mi1ls/$ Where 0.09823 is the sum of the 0 and M factor, 0.02 and 0.07823, the amortization factor at 7-5/8 percent interest over 50 years. q. For sites with potential installed capacity greater than 80 percent of 2030 10\'1 demand scenario divide 80 percent of the year 2030 low demand by the installed capacity computed in step "g." This quotient (Y) then is multipled by the flow computed in step c and reentered. All computations are then repeated based on this fraction of average flow. In such cases when the installed capacity is reduced to accommodate project demand, the only further adJustment required is to increase the plant factor in step i." Proceed as follows: 0.25 ~ Y < 1; PF = 0.5067 y2 -1.18 Y + 1.123 o < Y < 0.25; PF = 0.6944 y2 -0.5764 Y + 0.9607 Typical values for plant factor follow: Y 0.10 0.20 0.25 0.40 0.5 0.75 1.00 8-4 PF Q.9T 0.87 0.86 0.73 0.66 0.52 0.45 APPENDIX C ECONOMIC ANALYSIS METHODOLOGY Southcentra 1 APPENDIX C ECONOMIC ANALYSIS METHODOLOGY 1.0 INTRODUCTION The methodology used to perform the economic analysis of hydropower sites is presented in this Appendix. The preliminary screening methodology is discussed in Section 2.0, which includes the generic assumptions that were applied to all sites investigated. The economic analysis applied at the more detailed stage is discussed in Section 3.0. In Section 4.0 of this Appendix, the community of Kachemak serves as an example to illustrate the progression of analysis from the preliminary screening through the detailed screening. Data tables for Kachemak, the same as those presented in Part II of the report, are included with an explanation of how the results from the preliminary and detailed screenings were derived. 2.0 PRELIMINARY SCREENING METHODOLOGY 2.1 Surrrnary Benefit/cost ratios were calculated for each site identified in the drainage basin inventory. The objective of the economic analysis in the preliminarY screening was to compare the cost of hydroelectric sites to the cost of the most likely alternative form of power generation, which in all cases was assumed to be diesel generators or combustion turbines. Plant sizes were based on low electric energy growth projections. Fuel costs of alternative power were escalated at rates of 0, 2, and 5 percent. For the purposes of estimating the cost of alternative power, the cornmunities were classified into three categories: 1) isolated communities; 2) communities that could utilize hYdropower more economically through interties than from independent systems, and 3) communities that are intertied currently and rely on electrical power generated by diesel or other fossil fuel based systems. Diesel generators were assumed to be the most likely alternative for isolated communities, proposed intertied communities, and communities served by Copper Valley Electric Association (CVEA) and Cordova Public Utilities (CPU). Combustion turbines were assumed as the most likely alternative for the communities served by Chugach Electric Association (CEA), Matanuska Electric Association (MEA), and Homer Electric Association (HEA) • Six sets of benefit-cost ratios were calculated based on 0, 2, and 5 percent fuel escalation, both including and excluding the capital costs of alternative power. The criterion used for preliminary screening of all identified sites was the set of benefit-cost ratios based on 5 percent fuel cost escalation, excluding the capital costs of alternative power. The methodology for computing the costs of C-l alternative power, both including and excluding capital costs, is presented in this Appendix. The benefit-cost ratios provided the basis for identifying cOrnQunities and sites which would be visited in the fi el d and subj ect to more deta'il ed reconnai ssance-l eve 1 i nvesti gati ons. 2.2 Cost of Hydroelectric Power For each of the sites identified in the map reconnaissance, costs were estimated for the major project components and then summed to provide a total estimated capital cost. The project components for which separate cost estimates were developed include generation equipment (including the powerhouse structure), penstocks, dams, mobilization, and transmission facilities. The basis for estimating the costs of these components is described in Chapter 6.0. A plant factor of 0.55 for communities served by large utilities and 0.45 for other communities was used in establishing the cost of hydropower si nce it was assumed that not all power produced woul d be consumed. The plant factor was assumed to reach these levels when demand for power equaled or exceeded the supply. Annual costs for each site were developed using a capital recovery factor based on an interest rate of 7-5/8 percent for project fi nanci ng over a 50-year project life, with the additional costs included for operation and maintenance. The average cost of electricity for each site was then based on the annual dollar expenditure for capital, operating and maintenance costs of the project divided by the estimated average annual electricity output. Specifically, the average cost was computed for each year; then the averages were summed and divided by SO. The average cost of hydroelectric power was calculated by the following formula: Hydro Costs in year t (HP t ) = Where C = capital costs for year t CHF = capital recovery factor a = operati ng costs for yea r t HP t = hydropo\'1er cost in year t kWh t = power consumed in year t (C x CRF) + 0 and M kWh t The eRF is taken for 50 years and kWh t is defined as the kilowatt hours produced by the project and consumed by the community inyear t. The kWht tenl1 adj usts for sites where the power output exceeds the corrununity (or intertied area) requirements. The term kWht is taken C-2 fom the load forecasts for the communi ty or in the case of a uti 1 i ty, the summation of demand for all study area communities served by that utility. The value used in the preliminary screening was 80 percent of comsurnption year 2030.1.1 In the detailed investigations, the term kWh was based on the demand in year 1997. The factor of 1.6, used in both the preliminary and detailed investigations, accounts for peak demand. Hydro costs were calculated using this term because revenues from the hydroelectric plant should be calculated from power sold to the community rather than power produced. The average annual cost of hydropower then was developed by the following fonnula: HPave = (~O HP t\ 50 t = 1981 J All costs are in 1981 dollars in that no general inflation or escalation term has been built into the price forecasts. The annualized capital cost of the hydroelectric development ;s calculated such that the net present value of the investment is $0 in year 1981. 2.3 Cost of Diesel Alternative 2.3.1 Capital Costs Included A stream of diesel costs in ~/kwh were calculated for all isolated and potentially intertied communities, and communities served by utilities that use diesel generators. This cost stream was based on annualized capital, operating and maintenance costs and, in the case of potential interties, annualized transmission costs. Cost of fuel was calculated 11 This was based on the assumption that the plant operates for 4380 hours per year. C-3 using r~ay 1,1981 fuel prices. The fonnula used to calculate these costs in any given year was the following: Diesel Cost in year (DPt) = (C x CRF) + 0 and M + F kWh t where C = capital costs for year t CRF = capital recovery factor o = operati ng costs for yea r t N = mai ntenance costs for year t F = total fuel costs for year t (including lubricants) DP t = d i ese 1 power cost in year t kWh t = power produced and consumed in year t An investment stream was calculated employing an average cost calculation and based on an interest rate of 7-5/8 percent. The present value of the capital investment was calculated using a capital recovery factor. The capital costs were multiplied by a capital recovery factor of .0991 based on a 20-year investment cycle. The assumption of a 5 percent fuel escalation rate was used to calculate diesel costs for the preliminary screening. For the potential intertied communities, transmission costs were annualized based on a capital recovery factor of .07823 for a 50-year investment cycle. Other assumptions were used in calculating diesel generation costs. Diesel generators were sized for peak hour of the final year of their useful life (20th year), assuming the demand at that time would be 1.5 times greater than average demand. A diesel her} rate of 12.5 kWh/ gallon was used to calculate fuel requirements.-Operating time was assumed to be 4380 hours per year, or half time on the average. Assumptions regarding diesel costs are listed in Table C-1. Average costs were then calculated as follows: DP = COPt /SO ( 2030 ~ ave L-- t = 1981 All costs are in 1981 dollars, in that no general inflation or escalation term has been built into the price forecasts. The CRF tenn annualizes the capital or investment cost such that the net present value of the investment in the year 1981 is ~O. 11 A heat rate of 12.7 kWh/gallon was derived from data provided by Caterpillar Products and Sales Service. A value of 12.5 kWh/gallon ~vas used as a slightly more conservative estimate of the diesel heat rate. C-4 Cost Parameters Installed Capital Hai ntenance Operation Fuel Lub ricant TABLE C-l DIESEL COST FACTORS Factors Derived from diesel cost curves provided by Caterpillar Products and Sales Service 6 percent of installed capital improvements 1 worker per yea r for systems <1 ~'W 2 workers per year for systems >1 MW Average annual salary of worker -$33,000 Varies with location -based on contacts with utilities, fuel distributors, and trucking, barge, and air carrier companies 10 percent of fuel costs 2.3.2 Capital Costs Excluded A stream of diesel costs in $/kWh were calculated based on five percent fuel cost escalation and excluding the costs of the diesel generators. For each year, fuel costs were escalated at 5 percent from May 1, 1981 fuel prices and divided by the heat rate of diesel generators. The arithmetic average of the cost of diesel power over the life of the project was calculated by summing the values for each year and dividing by the number of years (50). 2.4 Cost of COlllbustion Turbine Alternative The alternative to hydropower was assumed to be combustion turbines for those communities that purchase electricity from Chugach Electric Assocation. Matanuska Electric Association, and Homer Electric Association. The assumptions used in the economic analysis of combustion turbine power generation were the following: 25 year investment cycle heat rate of 10,500 Btu/kWh capital cost of S720/kW for turbines 5-50 MW in size o and M cost of $0.005/kWh The equations for calculating the average cost of the combustion turbine alternative were identical to the equations used to calculate the average cost of diesel power, for both inclusion and exclusion of capital costs. C-5 2.5 Benefit Cost Ratios for Preliminary Screening Benefit/cost ratios were developed for screening purposes. Present ~lOrth values were applied with respect to the capital investment of the hydroelectric project. The generic formula employed was: B/C = Ave. Cost Diesel Power (Z/kWh) Ave. Cost Hydro Power (Z/kWh) The dverage was taken for power generated over the 1981-2030 period. A B/C ratio greater than 1.0 indicates that the hYdro site is worthy of further consi derati on. Substituting the averaging equations into the generic equation yields the following formula: B/C = ( 2030 t ~981 = DP --",.,--a_v_e rag e HP average C ~981 Because the OPt and HPt values are developed to yield an average cost for a given system, where DP ave exceeds HP ave , and B/C is greater than 1, the site should be retained for futher analysis. Where DPaverage is greater than HPq.verage, hydropower benefits represent a cost savings over alternatlve sOurces of power. 3.0 DETAILED INVESTIGATIONS METHODOLOGY The detailed phase of economic analysis was performed for 25 sites selected from the list of sites investigated in the preliminary screening. At the conclusion of the preliminary screening, it was decided that a community with sites having a benefit-cost ratio greater than 1, based on 5 percent fuel cost escalation and excluding the capital costs of alternative power, would be retained for more detailed investigation. The capital cost of alternative power was excluded because a hYdroelectric facility would not be capable of meeting 100 percent of the power demand, thus necessitating alternative generating methods to supplement hydropower. Input to the detailed phase of economic analysis involved the development of a plant factor program, revisions to the load forecasts, and more detailed hYdroelectric cost estimates. It was assumed that the hydroelectric plant would not begin to generate power until 1984. This phase of analysis resulted in a new set of benefit-cost ratios which is presented in Table 1-1 of the Overview. C-6 4.0 SITE SPECIFIC EXAMPLE -KACHEMAK This section uses Kachemak as an example to illustrate how the economic ana 1ysi s was perfonned for sites located in the study a rea communities. Kachemak is served by Homer Electric Association (HEA), which in addition to Matanuska Electric Association (r1EA), purchases power from Chugach Electric Association (CEA). This section addresses the sequential process of applying the economic analysis methodology through the preliminary and detailed phases of investigation. All tables included in Part II of the report are referenced in this section. The methodology used to evaluate site feasibility involved the com~arison of benefit-cost ratios based on the arithmetic average of nondiscounted hydropower and alternative power costs. All values are in 1981 dollars since inflation was accounted for. The present value of capital investment was discounted over the period of analysis using a capital recovery factor. 4.1 Preliminary Screening 4.1.1 Introduction Five sites were identified in the map reconnaissance of Kachemak. Conceptual costs of hYdroelectric development for all five sites were estimated. Alternative combustion turbines were sized to meet the projected el ectri c energy requi rements of the community. For both hYdroelectric development and combustion turbine operation, the average nondi scounted costs were ca1cul ated. The load forecasts for Kachemak are presented in Table C-2. Forecasts were calculated for three growth scenarios (low, medium, high) as explained in Chapter 3.0 of the Overview. It was decided that the low growth scenario was most representative of the future of southcentra1 communities. The values for electric energy demand, expressed as kilowatt hours per year, were pooled with values for all other communities in the study area served by CEA, MEA, and HEA, and served as input data to calculate both the cost of alternative power and hydroelectric power. 4.1.2 Diesel Cost Calculation 4.1.2.1 Capital Cost Included Alternative power costs were calculated by sizing the combustion turbines. Values for the total investment and annual capital costs are presented in Table C-3. C-7 Table C-~ h;::GIO;;,\L r:V:::!'l.'ORY & RCCO!.Ui\ISANCl STUIJY -St:hLL IiYl'HOPO\!Ei, PROJI.:C·,:,~ y;::r,n 1980 1981 1982 19B3 19A4 1985 19nc, 19u7 19'38 1')89 1990 1991 1992 1993 1994 1995 1 Cl ~C, 1997 1 St 9:3 19,)) 2000 20(11 2002 2003 2004 2005 200(, 2007 2008 2fl()9 2010 2011 2012 2013 2014 2015 201" 2017 ;> () h~ 2019 2020 2021 2022 2023 2024 2025 2fJ26 2027 202,' 2029 2(;30 ALASKA DISTRIC'r -CORPS OF ENGW[U~S LOl,D FORECAST -KACHEFi\K KILOI:l,TT-HOURS PETZ n;AF LQ}-: !-1EDIUI·l HIGH 1727143. 1727143. 1727143. 1787055. 1787855. 1787855. 184E5G7. lC?09279. 196<)9<)1. 203n702. 20914 H. 2152126. 2212838. 2273550. 2334262. 2391164. 244G06G. 2504963. 25(,,113"70. 2618772 • 205674. 2732576. 278947H. 2846380. 290 32fl2. 2961950. 3020(;37. 3079315. 3137992. 319(,670. 3255347. 3314025. 3372702. 34313RO. 3490058. 356(5')23. 3G437!;>P. 3720(;53. 379751R. 3b7 ·1383. 3951248. 4028113. 410497~. • ; 181[;43. 425,1709. 4309699. 43610~<9. 4412279. 4 .. 634W. 4514659. 45(;5849. 4(,17039. 46682 /.9. 4719419. 4770609. 184tl567. 19C9279. 1%9~91 • 20307U2. 209H 14. 2152126. 2212[;3H. 2273550. 2334262. 2 .. 74617. 2614972 • 2755326. 2895681. 3036036. 3176391. 3316745. 3457100. 3597455. 3737809. 3906735. 4075660. ,1244586 • 4413511. 45B2437. 4751362. 4920288. 5089213. 5258139. 5427%3. 5535025. 5642<)87. 575094'1. 5858911. 59f,6[-:73. 6074835. 6182797. 0290759. 6398721. 65066"12. 6593961. 66D 12·10. 6 7()8519. 6855798. 6943077 • 7030356. 7117635. 72(14914. 72921":13. 7379472. 18485(;7. 1909279. 1969991. 2030702. 2091414. 2152126. 22121:138. 2273550. 2334262. 255b070. 2791E77. 3005685. 3229492 • 3453300. 3677107. 3900915. 4124722. 43413 530. 4572337. 4R51510. 5130(,J3. 5409'156. 5G89029. 5968202. 6247375. 6S26546. 6805721. 7084394. 73640('9. 75031 2R. 76421%. 7781245. 792(130). n059362. S198420. 8337479. 847<=>537. 8G15596. 875.-1654. 9R7~022 • 9001390. 912475B. 92 4e 12\J. 9371494. 9494D62. 9618230. 9741598. 9864966. 99E8334. C-8 LOvi 59,. (,12. 633. 65·~ • 675. 695. 71(. 737. 758. 779. 799. ell). 831::'. 853. 877. B97. 91(,. 936. 955. 975. 994. 1014. 1034. 1 0~·5. 1075. 1095. 1 115. 1135. 1 155. 1175. 1195. 122.2. 1248. 1274. 1301. 1327. 1353. 1379. 1406. 1432. 1452. 1476. 1494. 1511 • 1529. 1546. 1 5\::4. 15q 1 • 159,). 1616. 163..1. m:UIUM 591. 612. 633. 654. 675. 69:; • 716. 737. 750. 779. 799. 847. 8%. 944. 992. 1040. 10B8. 1131i • 1184. 1232. 1280. 133H. 1396. 1454. 1511. 1569. 1(;27. HiSS. 1743. 1801. 1859. 18%. 1933. 1970. 2006. 2043. 2 OPt) • 2117. 2154. 2 1 ,) 1 • 2221;. 225B. 22SB. 2318. 2348. 237S. 2408. 2438. 24';7. 2497. 2527 • HIe!! 591- 612. 633. 654. t75. 7 1!~ • 737. 75<.:,. 77':j. 799. d76. 953. 1(;29. 1106. 1 1E 3. 1259. 1336. 1413. 1489. 1566. 1f.61. 1757. 1853. 1943. 2044. 2140. 2235. 2331. 2426. 292. 257n. 2617. 2005. 2712. 2760. 2t! Of.). 2855. 29('1. 2951. 299i-1. 3 O.j 0 • 3083. 3125. 3167. 3209. 3252. 3204. 333G. 337 c' • 3421. Investment Year Tabl e C-3 Cost of Combustion Turbines Kachemak, Homer Electric Association Total Capital System Cost/kW Investment Recovery Size (kW) ( S) (S) Factor Annual Capital Cost (S) 1981 2006 5995 X 720 = 4,316,400 X .0907 = 391,500 8947 X 720 = 6,441,840 X .0907 = 584,300 Annual costs for operation and maintenance, fuel, and lubricant were calculated and added to the cost of the capital "investment. As an example, the costs for year 2006 are presented in Table C-4. Capital 584,300 TABLE C-4 Annual Cost of Combustion Turbines, Year 2006 Kachemak, Homer Electric Association (0011 ars) Operati on and Mai ntenance.!! 89,137 FuelY 5,578,180 Total 6,251,617 1/ $0.005kWh x 17,827,432 kWh/year = S89,137/year ~ gal/kWh x kWh/yr x $/gal = Annual fuel cost .0Bgal/kWh x 17,827,432 kWh/yr x $3.91/gallon = $5,578,180/year The nondiscounted cost of electricity ($.351/kWh) was obtained by dividing the total annual cost (S6,251,617) by the quantity of electricity produced (17,827,432 kWh/year). C-9 4.1.2.2 Capital Costs Excluded The alternative annual power costs were calculated by escalating the 1981 fuel price (Sl.15/gallon) at a 5 percent rate throughout the planning period (50 years) and dividing that value by the heat rate of the combustion turbines (12.5 kWh/gallon).ll As shown in Table C-5 the nondiscounted cost of alternative power in year 1981 SO.092/kWh, was obtained by dividing Sl.15/gallon by the heat rate of 12.5 kWh/gallon. This calculation was made for each year. The average cost of alternative power ($.387/kWh) was calculated by taking the summation of values for each year (19.341) and dividing that value by 50 years. 4.1.3 ~droelectric Cost Calculation Hydroelectric costs were calculated by slzlng the plant for one investment year -1981. Values for the total investment and the annual costs are presented in Table C-6. Table C-6 Total Annual Costs of Hydropower Swift Creek, Kachemak Investment System Year Size (kW) 1981 941 Cost/kW ($) Capital Recovery Factor Annual Capital Cost ($) o and M ($) Total Annual Costs ($) 3,112,686 .07823 243,505 + 62,254 = 305,759 The nondiscounted electricity costs were calculated for each year by dividing the total annual cost by the amount of electricity produced. An example of this procedure is shown in Table C-7. Year 1981 2001 Tota 1 Annual Cost ($) 305,759 305,759 Table C-7 Cost of Hydroe 1 ectri c Energy Swift Creek, Kachemak Discounted Cost E1 ectri city Produced (kWh/yr) of Electricity ($/kWh) 4,533,738 4,533,738 = = .067 .067 1/ Sl.15/gallon = $8.56/Btu x 10 6 x 0.135 x 10 6 Btu/gallon. C-10 R£X.;ICNAL IlNEN'IOH.":{ & RE(l)Nl.JAISSANCl:: S'IUDY -SMALL HYDroPCW::R PRaJECI'S N...ASKA DISTRICl' -O)NPS OF fl'!GINEERS 5% FUEL OJ~"T E..SCALATI~; CAPI'l'AL OOS'fS l:J{U,UDIID Table c-5 PRB.<)ENT VALUE OF NA'IURAL GAS Q)~rs : I.lJiJ DEMAND SO~NARIO UTILITY 2 -Hl::A,CBA,MEA YI.:;AR S/KWH 19tH 0.092 19B2 0.097 1963 0.102 1Yl:S4 U.I07 B8~ 0.112 1986 0.118 lY87 0.124 19tH:l 0.130 b89 0.137 1990 0.143 1991 0.151 1992 0.150 1993 0.166 1994 U.174 1995 U.183 1996 0.192 1997 0.202 1998 0.212 1999 0.222 2000 0.233 2001 0.245 2002 0.257 2003 0.270 2004 0.284 2005 0.298 2006 0.313 2007 0.329 2008 0.345 2009 0.362 2010 0.380 2011 0.399 2012 0.419 2013 0.440 2014 0.462 2015 0.4H5 2016 0.510 2017 0.535 2018 0.562 2019 0.590 2020 0.620 2021 0.650 2022 0.683 2023 0.717 2024 0.753 2025 0.791 2026 0.830 2027 0.872 2028 0.915 2029 0.961 2030 1.009 AVERAGE cx)ST 0.387 c-ll 4.1.4 Results The results of the preliminary screening indicated that site number 3, Swift Creek, ranked highest among all the Kachemak sites investigated. Kachemak was included in the communities visited in the field. Observations in the field confirmed that this site was the most favorable and, therefore, warranted a more detailed analysis. Results for communities with no sites "surviving" the preliminary screening are presented in tabl es entitl ed IISummary Data Sheet, Prelim; nary Screeni ng ll of Part I I of the report. 4.2 Detailed Investigations The secondary phase of economic analysis was performed after the site visits and involved considerably more detail. Information gathered in the field resulted in the refinement of some of the population and fuel cost data. These revisions affected the load forecasts and the cost of alternative power. Results of the detailed investigations are presented for site number 3 in Table C-8 entitled "Summary Data Sheet, Detailed Investigations." Similar tables are provided in Part II of the report for each community with sites evaluated in the detailed investigations phase of the study. The results of the detailed investigations represent the cost of alternative power based on a 5 percent fuel cost escalation and exclude capital costs. The effect of excluding capital costs was to lower the average cost of alternative power. The value of S.387/kWh, as shown in Table C-8, represents an arithmetic average of the nondiscounted costs of alternative power. It was calculated by taking the summation of values for each year (19.341) and dividing that value by 50 years. Hydropower costs were estimated in more detail. Layouts were developed to reflect actual site conditions. In the case of unvisited sites, more detailed mapping was utilized to develop conceptual costs. Site specific data for each of the parameters presented in Table C-9 were used to develop the cost data presented in Table C-IO. Further, indirect costs were added to the direct construction costs, resulting in si gni ficantly lower benefi t-cost rat; os than those resul ti ng from the preliminary screening. Methods used to derive project costs are presented in Chapter 6.0 of the Overview. A plant factor was calculated for Kachemak based on the assumption that all energy produced and distributed by Homer Electric Association would be sold. In 1984, when the hYdroelectric plant is expected to begin operation, the plant would generate a constant amount of electricity throughout its life. A flow-duration curve was developed from hydrologic information. A plant factor of 46 percent was derived from the flow-duration curve and turbine limitations. Utilities were assumed to use the available energy supply except when flows fell below minimum turbine flow requirements or that portion of flow which exceeded the design capacity flow. C-12 Hydropower Potential Site No. 3 Installed Capacity ( kW) 674 TABLE C-8 SUMMARY DATA SHEET DETAILED INVESTIGATIONS KACHEMAK, ALASKA Insta 11 ed Cost (S1000) 5,862 Cost of Al ternat,i ve Power1 emi 11 s/kWh) 387 Demographic characteristics 1981 Population: 403 1981 Number of Households: 115 Economic Base Fi sheri es Cost of Hydropower (mill s/kWh) 214 1/ 5 Percent Fuel Escalation, Capital Cost Excluded. C-13 Benefit/Cost Ratio 1.80 1. LOCATION (diversion) Stream: Swift Creek TABLE C-9 KACHEMAK SITE 3 SIGNIFICANT DATA Section 23, Township 4S, Range 11W, Seward Meridian Community Served: Kachamek, Homer Electric Association Distance: 12.5 mi Direction (community to site): i~ap: USGS, Seldovia (D-3), Alaska 2. HYDROLOGY Dra i nage Area: Estimated Mean Streamflow: Estimated Mean Annual Precipitation: 3. DIVERSION DAM Type: lJeight: Crest Elevation: 4. SPILLWAY Type: Opening Height: Width: Crest Elevation: 5. WATERCONDUCTOR Type: Diameter: Length: 6. POWER STATION Number of Units: Turbi ne Type! Tailwater Elevation: Rated Net Head: Installed Capacity: Maximum Flow (both units combined): Minimum Flow (single unit): 7. ACCESS Length: 8. TRANSMISSION LINE Vo 1 tage/Phase: Terrain:li Mountains (1.5) Total Length: 9. ENERGY Pl ant Factor: Average Annual Energy Production: Method of Energy Computation: 10. EtNIRONMENTAL CONSTRAINTS: None noted. 1/ Terrai n Cost Factors Shown in Parentheses. C-14 6.9 10.6 30 sq mi cfs in Sheetpi 1 e 10 ft 700 fmsl Northeast Stairstep Fish Ladder 5 ft 29 ft 695 fmsl Steel Penstock 22 in 13500 ft 2 Pel ton 10 fmsl 625 ft 674 kW 15.9 cfs 1.6 cfs 3.0 14.4 2.6 2.6 mi kV/3 phase mi mi 46 percent 2716 MWh Flow Duration Curve TABLE C-lO HYDROPOWER COST DATA Community: Kachemak Si te: 3 Stream: Swift Creek 1. 2. 3. 4. 5. 6. 7. ITEM Dam (including intake and spi 11 way) Penstock Powerhouse and Equipment -Turbines and Generators -Misc. Mechanical and Electrical -Structure -Val yes and Bifurcations Switchyard h::cess Transmission TOTAL DIRECT CONSTRUCTION COSTS Construction Facilities and Equipment, Camp, Mobilization, and Demobilization TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT SUBTOTAL Geographic Factor = SUBTOTAL Conti ngency at 25 percent SUBTOTAL Engineering and Administration at 15 percent TOTAL CONSTRUCTION COST Interest During Construction at 9.5 percent TOTAL PROJECT COST Cost per kW Installed Capacity ANNUAL COSTS Annuity at 7-5/8 percent (AlP = 0.07823) Operations and Maintenance Cost at 1.2 percent TuTAl ANNUAL COSTS Cost per kWh Benefit-Cost Ratio COST $ 45,000 $ 780,000 $ 415,000 $ 294,000 $ 30,000 $ 19,000 $ 167,000 $ 45,000 $ 156,000 $ 1,951,000 $ 195,000 $ 2,146,000 1.9 $ 4,078,000 $ 1,019,000 S 5,097,000 $ 765,000 S 5,862,000 S 557,000 $ 6,418,000 9,520 $ 502,100 $ 77,000 $ 579,100 S 0.21 1.80 The hydropower cost data and the benefit-cost ratio for the detailed investigation are presented in Table C-11. The value of $.214/kWh represents an arithmetic average of nondiscounted hydropower costs. This value was obtained by calculating the summation of costs for each year (10.058) and dividing it by the number of years (47). For Kachemak, the average cost of alternative power (387 mills/kWh) was divided by the average cost of hydropower (214 mills/kWh) to obtain a revised benefit-cost ratio of 1.80. C-16 Table C-l1 REG ICNAL Il\TVEN'lORY & REOJNNAISANCE S'IUDY -SMALL IIYUfUP(k,iEH PRClJr.:Cl'S ALASKA DIS'l'HICT -C1JkPS Of' EN.,;INI:.t:RS DE'rAI 1£0 RECON'NAI SS/\NCE INVESTIGATIONS cosrr OF HYDROPOIJEH -BE::NEf'IT OJST RATIO KAQlf.ll.iAK SITE NO. 3 S/KWi S/KWH YEAR KI\H/YEAR CAPITAL o & M 'lUI'Ar..$ t-XJNDISC DISC 1984 2716000. 505353. 77000. 582353. 0.214 0.160 1985 2716000. 505353. 77000. 582353. 0.214 0.148 1986 2716000. 505353. 77000. 582353. 0.214 O.13t; 1987 2716000. 505353. 77000. 582353. 0.214 0.128 191:i8 2716000. 505353. 77000. 582353. 0.214 0.119 1989 2716000. 505353. 77000. 582353. 0.214 0.111 1990 2716000. 505353. 77000. 5f12353. 0.214 0.103 1991 2716000. 505353. 77000. 582353. 0.214 0.096 1992 2716000. 505353. 77000. 5H2353. 0.214 0.089 1993 2716000. 505353. 77000. 582353. 0.214 0.082 1994 2716000. 505353. 77000. 582353. 0.214 0.077 1995 2716000. 505353. 77000. 5H2353. 0.214 0.071 1996 2716000. 505353. 77000. 582353. 0.214 0.066 1997 2716000. 505353. 77000. 582353. 0.214 0.061 1991:i 2716000. 505353. 77000. 5t32353. 0.214 0.057 1999 2716000. 505353. 77000. 582353. 0.214 0.053 2000 2716000. 505353. 77000. 582353. 0.214 0.049 2001 2716000. 505353. 77000. 582353. 0.214 0.046 2002 2716000. 505353. 77000. 582353. 0.214 0.043 2003 2716000. 505353. 77000. 582353. 0.214 0.040 2004 2716000. 505353. 77000. 582353. 0.214 0.037 2005 2716000. 505353. 77000. 582353. 0.214 0.034 2006 2716000. 505353. 77000. 582353. 0.214 0.032 2007 2716000. 505353. 77000. 582353. 0.214 0.029 2008 2716000. 505353. 77000. 582353. 0.214 0.027 2009 2716000. 505353. 77000. 582353. 0.214 0.025 2010 2716000. 505353. 77000. 582353. 0.214 0.024 2011 2716UOO. 505353. 77000. 5t;2353. 0.214 0.022 2012 2716000. 505353. 77000. 582353. 0.214 0.020 2013 2716000. 505353. 77000. 582353. 0.214 0.019 2014 2716000. 505353. 77000. 51:i2353. 0.214 0.018 2015 2716000. 505353. 77000. 582353. 0.214 0.016 2016 ~716000. 505353. 77000. 582353. 0.214 0.01'5 2017 2716000. 505353. 77000. 582353. 0.214 0.014 2018 2716000. 505353. 77000. 5B2353. 0.214 0.013 2019 2716000. 505353. 77000. 582353. 0.214 0.012 2020 2716000. 505353. 77000. 582353. 0.214 0.011 2021 2716000. 505353. 77000. 582353. 0.214 0.01l 2022 271600U. 505353. 77000. 5ti2353. 0.214 0.010 2023 2716000. 505353. 77000. 582353. 0.214 0.009 2024 27160UO. 505353. 77000. 582353. 0.214 0.008 2025 2716000. 505353. 77000. 582353. 0.214 0.008 2026 2716000. 505353. 77000. 582353. 0.214 0.007 2027 2716000. 505353. 77000. 582353. 0.214 0.007 2028 2716000. 505353. 77000. 582353. 0.214 0.006 2029 2716000. 505353. 77000. 582353. 0.214 0.006 2030 2716000. 505353. 77000. 582353. 0.214 0.005 AVr:HJ'lGf; COST 0.214 0.046 BEM':r'I'r-mST AATIO (5% I:lJt.:L CUS'l' EOCALATIUI) : 1.80 r'_17 APPENDIX D SOUTHCENTRAL ALASKA INTERTIED COMMUNITIES SUMMARY TABLE APPENDIX D The summa~ table presented in Appendix 0 contains, for reference purposes, data for Southcentral Alaska communities served by intertied electric utility systems, but which were not included in this reconnaissance study. The residential cost of power data were obtained from the listed utilities. 0-1 APPENDIX D SOUTHCENTRAL ALASKA INTERTIED COMMUNITIES SUMMARY TABLE Sheet 1 of 2 1980 Uti 11 1;)' Residential Cost?/ COr.mJl1uni ty Populati on FJame Type of OWners~ip Anchorage 173,017 Anchorage Municipal Municipal Light and Power Co. Anchor Poi nt 171 Homer Electric Association REA Bi rChwood 3,040 Matanuska Electric REA Associati on Chugiak 3,224 Matanuska Electric REA Association Clam Gulch 47 Homer Electric Association REA Cohoe 122 Homer Electric Association REA Cooper Landing 31 Chugach E1 ectri c REA Association Cordova 2,241 Cordova E1 ectri c Municipal Cooperati ve Eagle River 5,400 Matanuska Electric REA Association Ek1utna 65 Matanuska Electric REA Association Fairbanks.!.! 53,259 Fairbanks Municipal Municipal Utilities System Girdwood 144 Chugach El ectri c REA Association Glennallen 363 Copper. Valley Electric REA Associati on Homer 2,209 Homer Electric Association REA Houston 370 ·Matanuska Electric REA Association 1/ Includes all communities·within the North Star Borough except for North Pole. ~/ Based on consumption of 438 kWh/month. 0-1 (J/kWh) .06 .07 .09 .09 .07 .07 .06 .32 .09 .09 .09 .06 .23 .07 .09 SOUTHCENTRAlAlA$KA tNTERTlED COMMUN In ES SUMMARY TABLE Sheet 2 of 2 1980 Utilit,l .. . .... Residential CostY COr.1l11l1uni ty Population Rame Typ.e of Ownership. (J/kWh) Kasilof Village 71 Homer E1 ectric Association REA .07 Kenai 4,324 Homer Electrfc Assocfatfon REA .08 Matanuska 50 r~atanuska El ectric REA .09 Association Moose Creek 240 Golden Valley Electric REA Association Moose Pass 53 Chugach Electric REA .06 Association Nenana 470 Golden Valley:Electric REA Association· Ninilchik 336 Homer Electric Assocfation REA .07 North Pole 724 Golden Valley Electric REA Association Pa 1 mer 2,141 Matanuska Electric REA .09 Association Portage 71 Chugach El ectri c REA .06 Associatton Potter 14 Chugach Electric REA .06 Association Salamatof 2,560 Homer Electric Association REA .07 Seward 1,843 Seward Electric System· Municipal .07 Soldotna 2,320 Homer Electric Association REA .07 Starl ing 115 Homer Electric Association REA .07 Usibelli 100 Golden Valley Electric REA .12 Association Valdez 3,079 Copper Valley Electric REA .23 Associ ati on Wasi 11 a 1,559 Matanuska Electric REA .09 Association Willow 108 Matanuska Electric REA .09 Association 0-2