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Home My WebLink AboutElectric Power Generation Alternatives Assessment for Nome Alaska 1980ELECTRIC POWER GENERATION ALTERNATIVES ASSESSMENT | FOR NOME, ALASKA PREPARED FOR THE ALASKA POWER AUTHORITY APRIL, 1980 PROPERTY OF: © 7° Alaska Power Authority ‘ 334 W. 5th Ave. : Anchorage, Alaska 99501 ADVANCED ENERGY SYSTEMS PROJECTS ENGINEERING OPERATION INSTALLATION and SERVICE ENGINEERING DIVISION 1 RIVER ROAD SCHENECTADY, NEW YORK, 12345 GENERAL @@ ELECTRIC GENERAL € ELECTRIC EXECUTIVE SUMMARY Within the last five years, oil resource costs have more than doubled, resulting in a general increase in prices. Particularly affected are diesel-electrical power generaticn systems. To offset these cost escalations and to limit continued use of oil related fuels, the Alaska Power Authority selected the General Electric Company to perform an investigation of non-petroleum electric power alternatives such as hydroelectric development, coal resources, wind generation, photovoltaic application, geothermal development, biomass conversion, and use of regional oil and gas resources for the Nome, Alaska region. Presently, Nome's municipal water sources are Moonlight Springs. In the Springs' vicinity, an underground drain field collects water and feeds it into a buried pipe. Collected water then travels down a pipe approximately 2.5 miles to the City via gravity due to a pipe "entrance-exit" elevation difference of over 100 feet. Once at the treatment plant, transported water is deposited, under atmospheric conditions, into a cistern for treatment and then distributed. Water flows year round and is not heated during the winter months. Moonlight Springs drain field utilizes only a portion of the formation where water is collected. General Electric conducted field investigations to assess water yield characteristics of the formation including an evaluation of potential hydrogeneration capabilities. Surface water flows were estimated for the Anvil Creek and Cooper Gulch drainage basins based on assumed rainfall-runoff relationships. Potential groundwater recharge estimates were made for the Moonlight Springs area. Four test holes were drilled to help define the source of water for the springs and to perform an aquifer test. Insufficient groundwater was found, therefore, a pumping test was not performed. It is estimated that the Anvil Creek and Cooper Gulch drainage basins would produce a total average annual flow of slightly less than 7 cfs. Actual streamflow hydrographs are not available, but the GENERAL €@ ELECTRIC flows would not be uniform and are expected to be very high in the late spring and early summer and low in winter. Results indicate that Moonlight Springs water resources are insufficient for hydroelectric development. Maximum average annual generator output would be less than 50 kilowatts. Furthermore, ex- tensive civil works would be required including drain field redevelop- ment, penstock construction and turbine foundations installation. Following the Moonlight Springs Reconnaissance Water Resources Study, three resources were identified as potential alternatives to the present power generation system - hydroelectric, coal and wind. Photovoltaic, biomass conversion, geothermal, and use of regional- ly obtained oil and gas alternatives were not addressed. Photovoltaic and biomass options were not considered applicable to the Nome region. Environmental characteristics of the region preclude the use of pre- sent day photovoltaic and biomass systems. Concerning regional geo- thermal development, the State of Alaska Department of Commerce and Economic Development, Division of Energy and Power Development is pre- sently conducting a geotechnical investigation program to assess the Pilgrim Spring's geothermal potential. Their studies will be completed in mid-1980 when a 500 foot depth exploratory well will be bored. Results will be published by that agency. To avoid duplication of efforts, particularly with the incomplete nature of data, geothermal potential of Pilgrim Springs was not evaluated. Presently, the United States Geological Survey estimates large hydrocarbon resources offshore of Nome, Alaska. Their availability, however, is undefined. Since a description of such resources has not been developed, their application to Nome was not considered. Of the three potential non-oil resources (hydro, coal and wind) that could be utilized to generate electric power in the vicinity of Nome, Alaska, only wind generation systems were found to have an application. ii GENERAL @ ELECTRIC Hydroelectric systems examined were generally found to be tech- nically feasible. Their costs per kilowatt hour, however, were greater than those associated with a diesel generation system. Unless the economic parameters used in compiling this report are altered (through geological information refinement), hydroelectric generation of electricity does not appear to be an alternative to the present diesel generation system. Preliminary investigations reveal no coal fired electric gener- ating system exist that approaches the small size are required by Nome. It is recognized that technology and equipment definition presently exist for design and installation of coal fired systems for Nome. The design, however, would be a "first of its kind"; furthermore, its personnel operating requirements would be nearly the same as that of 20 to 80 megawatt systems. The most likely use of Nome region coal resources appears to be for home heating. Conventional generation planning computer simulation methods were used to evaluate the performance of several wind turbine gener- ators on. the city of Nome utility system. Actual wind data collected at the Nome weather station was used for the hour-by-hour simulations. The results of the evaluations indicate economic viability of wind turbine generators in Nome, if recent cost and performance estimates for large (200 kW rated output) wind machines in quantity production can be achieved. Sensitivity analyses, performed as part of the evaluation, indicate that wind plant value exceeds wind plant cost under a wide range of wind regimes, diesel fuel costs and wind plant cost. The wind turbine generators selected for consideration in this study are representative of machines currently operational as part of federal and private efforts. The DOE-NASA MOD-OA wind turbines cur- rently operating in Clayton, New Mexico; Culebra, Puerto Rico; and Block Island, Rhode Island are examples of 200 kW class machines evaluated in this study. A fourth MOD-OA machine is scheduled for ade GENERAL €@ ELECTRIC 1980 installation in Hawaii. The next 200 kW class machine planned as part of NASA's evaluation in hardware design is the MOD-6 WTG, with the first machine scheduled for 1983. Based on the results of this wind turbine generator evaluation, a wind turbine field test on the Nome Joint Utility System appears justified. Successful demonstration of a 200 kW class machine, for example, would answer questions concerning WTG operations in an environment significantly different than present installations, including the operational impacts of severe wind storms and blade icing in the Nome environment. A successful demonstration could lead to additional WTG installations which reduce both oil consumption and the cost of electricity in Nome. iv GENERAL €@ ELECTRIC TABLE OF CONTENTS Section Title 0 EN ETOAUCT 1 ONieierelsiensielele eerie ele eielel cle lalelolereleleleherelerelele 2.0 Nome Electric Power Generation Characteristics . S30 Hydroelectric Potential of the Nome Region ..... 4.0 Nome Region Coal Reserves ..........cccccccccces Sy0 Wind Turbine Generation Evaluation ....... ORO OICEG 6.0 Conclusions iermreriersieiel ieeieieiel leas afetiole! ole! slielele oe) 2) slleielielle GENERAL @@ ELECTRIC Exhibit No. Title 2.1-1 Average Daily Kilowatt-Hours Production ..eseaaceever rl 2| Powerplant Loads for Summer and Winter .....-.ceeeeees SeO— Inventory of Potential Hydroelectric Sites in Alaska 3.0-2 Location Map of Hydroelectric Dam Sites ......6.. 3-1-1 Bluestone River Dam Site Location Map ...eseseees 3.1-2 Bluestone) River Dam\(ST te) rele ieee eleleliala)a\sie)ialierele se) ¢)a)ehele 3.2-1 Fish River) Dam iSite) Location) Map) je celelsieisisiels eel aieiele 3.2-2 Fish River Dam and Powerhouse Site... ..cacvceneeee 3.3-1 Kuzitrin Dame Site Location Map..............6. eels 3.3-2 Kuzitrin) Dam jand |/Powerhouse) Site 57s ssc 2\c/</<) sisi elo 0) otcire 3.3-3 KUZSLEIN Dam RASCTVOL oes clleietelenelelersielieieleleyelel el oieiarslielei sisi els 3.4-1 Nome River Dam Site Location Map ............. Ooo 3.4-2 View of Ridge, Looking Towards Nome ............-ee00. 3.4=3 Nome River Dam Drainage Basin Area .............--20. 3.5-1 Salmon gbakeqLocation |Map)| <\slaienere) she) sucieiclicl aie) aiieieis eile slensiolelo 3.5=-2 Salmon Lake Aerial View ...... Mallelelielielevehortehe elelerellelleetaretele 3-5-3 Salmon Lake - Nome River Scheme ..............2.-02- 3.6-1 tuksuic iChanne!) Dam) Site) Location) Map) e's siekele is o/c)! elielreliello 3.6-2 Tuksuk Channel Dam & Powerhouse Site ................ 3.6-3 Tuksukj TRCSCHVO1 ECA Callens io ctote erent a) stevere aye: claviotle tonerst ofeliolienel eters 3.7=1 Cross Sections Through Typical Earth Dams Built ONMESTMALLOS Calpeieilclelleieiebensloiel aveliererel ol ielenelodencnonehenononcte sie 3.7=-2 Valivay SDamiifaeorereketelercteleyoncieiele}erehenele isicheleleieisnereieetenctoleltele reise 3.8-1 Salmon) LakeVvAlLternatawyeierccieleleielielel lel aleliciiaelelfele)ictie) sence 359—2 Salmon Lake Monthly Discharges) |< cclslslcie cle voce o sisi 3) b=) Cost (Compars's3.ons|) —))7/%) Enterest) Race) [ee lels) scevele lols ec) oilelle JL l=2) Cost Comparisions|/—/\9%) Interest) Rate: |52).) <1 sreicisles el <1 3.11-3 Cost Comparisions - 10% Interest Rate ........ce.ceoee 4.1-1 Nome Area Coal Field .............. eee eevee ece secs LIST OF EXHIBITS 3-10 3-13 3-14 3-5 S17, 3-18 39) 3-22 3=25 3-24 3-26 3-27 3-28 3-3 3-32 3-36 3-37 3-43 3-44 3-45 4-2 GENERAL €@ ELECTRIC LIST OF APPENDICES Section Page 310 Moonlight Springs Reconnaissance Water Resource Study, Nome Alaska ....ee-eseeceeaere 3-48 5.0A Total Utility System Cost Methodology ........:- 5-33 5.0B Present Worth Factor for an Inflation Series .. 5-39 5.0C Sample WTG Cost/Value Calculation .isecsececener 5-41 5.0D Einancia lyAnallivs PSiiara miclela aig c)iehelarcialierelerehe rel siser oleic ler alte 5-44 vii GENERAL GB ELECTRIC ESO INTRODUCTION Within the last five years, oil resource costs have more than doubled, resulting in a general increase in prices. Particularly affected are diesel-electrical power generation systems. To offset these cost escalations and to limit continued use of oil related fuels, the Alaska Power Authority selected the General Electric Company to perform an investigation of non-petroleum electric power alternatives such as hydroelectric development, coal resources, wind generation, photovoltaic application, geothermal development, biomass conversion, and use of regional oil and gas resources for the Nome, Alaska region. Presently, Nome's municipal water sources are Moonlight Springs. In the Springs' vicinity, an underground drain field collects water and feeds it into a buried pipe. Collected water then travels down a pipe approximately 2.5 miles to the City via gravity due to a pipe "entrance-exit" elevation difference of over 100 feet. Once at the treatment plant, transported water is deposited, under atmospheric conditions, into a cistern for treatment and then distributed. Water flows year round and is not heated during the winter months. Moonlight Springs drain field utilizes only a portion of the formation where water is collected. General Electric conducted field investigations to assess water yield characteristics of the formation including an evaluation of potential hydrogeneration capabilities. Inclusive in the field investigation were the drilling of four test holes. Description of these investigations and their results are presented as Appendix 3.0 "Moonlight Springs Reconnaissance Water Resources Study, Nome, Alaska". Following the Moonlight Springs Reconnaissance Water Resources Study, three resources were identified as potential alternatives to the present power generation system - hydroelectric, coal and wind. L=1 GENERAL GQ ELECTRIC Photovoltaic, biomass conversion, geothermal, and use of regional- ly obtained oil and gas alternatives were not addressed. Photovoltaic and biomass options were not considered applicable to the Nome region. Environmental characteristics of the region preclude the use of pre- sent day photovoltaic and biomass systems. Concerning regional geo- thermal development, the State of Alaska Department of Commerce and Economic Development, Division of Energy and Power Development is pre- sently conducting a geotechnical investigation program to assess the Pilgrim Spring's geothermal potential. Their studies will be completed in mid-1980 when a 500 foot depth exploratory well will be bored. Results will be published by that agency. To avoid duplication of efforts, particularly with the incomplete nature of data, geothermal potential of Pilgrim Springs was not evaluated. Presently, the United States Geological Survey estimates large hydrocarbon resources offshore of Nome, Alaska. Their availability, however, is undefined. Since a description of such resources has not been developed, their application to Nome was not considered. In subsequent potions of this document, each potential resource - hydroelectric, coal, and wind - was examined for its potential as an adjunct to Nome's conventional diesel generation systems. Assisting the Advanced Energy Systems group of Project Engineering Operation on diesel-wind trubine applications was General Electric's Electric Utilities Energy Systems Department. 1-2 Big Diomede 1 / Little Diomede Ig Nudyagmo Prince of Wales ¢ Mugisitohwb oj MNopp Cape Qvates tine on Cc K\ Goodhope ah > \Bay Garn Ochamis CHAMISSO. WILDLIFE REF sono t Cape Rodney’ 2" Sledge |) 3970 Glacial \eeesens re ~ [BR Serpentine | t i? Hot Springs { i CON 40 Ne pian 870%) Black Dome; \! fiver st 4g MOUNTAIN \GLUPSS, SMT OSBORN Salmoo Lake Lake ‘amp ~O. Fort_ Davis Cape Nome — Port Satety . lopptain Tonok’ ».. 67 9 Splut © & IKNUTAK MTN 1688" Re Exhibit 1.0-1 doen ' o¢tim Walla Wall chortage Bis Cape , nbigh Project Location 91419313 GB 1veINa9 GENERAL €@ ELECTRIC 2.0 NOME ELECTRIC POWER GENERATION CHARACTERISTICS 2.1 POWER GENERATION The City of Nome generates approximately 14,000,000 kilowatt- hours annually. Power production characteristics are shown in Ex- hibit 2.1-1, “Average Daily Kilowatt Hours Production by Month", and Exhibit 2.1-2, “Typical Powerplant Loads for Summer and Winter." All power was produced by seven (7) diesel generators: 3, Cooper Bessemers @ 600 kilowatts each 1, Cooper Bessemer @ 1050 kilowatts Colt-Fairbanks-Morse @ 1250 kilowatts 1, Colt-Fairbanks-Morse @ 1550 kilowatts 1, General Motors @ 300 kilowatts @eeeee b . In October of 1979, the City of Nome added a single General Motors 2500 kilowatt diesel unit to its power plant. 2.2 FUTURE POWER REQUIREMENTS Excluding the impact of possible offshore oil and gas development, the population of Nome is expected to increase from 2,500 (1980) to 5,000 residents by the year 2000. The year 2000 estimate of Nome residents was based upon a report prepared for the City of Nome discussing Nome's future water supply and sewage disposal needs (exact name and author of report is not avail- able). The increase in population was stated to be the result of con- solidation of local villages. Present grid load demand is principally for residential and small store use (lighting, appliances, televisions, etc.). Power load demand characteristics are not expected to differ from those of the present. For an estimate of year 2000 electric power load demand, values pre- sented in Exhibits 2.1-1 and 2.1-2 should be doubled. 2-1 GENERAL @Q ELECTRIC NOME JOINT OTILITY SYSTEMS P.0.BOX70 © NOME, ALASKA 99762 TELEPHONE (907) 443-5242 AVERAGE DAILY KW-H PRODUCTION BY MONTH MONTH & YEAR November 1978 December 1978 January 1979 February 1979 March 1979 April 1979 May 1979 June 1979 July 1979 August 1979 September 1979 October 1979 Exhibit 2.1-1 Average Daily Kilowatt-Hours Production GENERAL @@ ELECTRIC P.O.BOX70 * NOME, ALASKA 99762 TELEPHONE (907) 443-5242 TYPICAL POWERPLANT LOADS FOR SUMMER & WINTER WINTER SUMMER Exhibit 2.1-2 Powerplant Loads for Summer and Winter GENERAL Q ELECTRIC 2.3 POWER COST In August of 1979, the City of Nome was purchasing diesel fuel at $.81 per gallon. During the same period, the City was billing their customers at a rate cf $.17 per kilowatt-hour. Of the $.17, $.025 was for capital cost amortization and $.062 was for fuel charges. GENERAL @@ ELECTRIC 3.0 HYDROELECTRIC POTENTIAL OF THE NOME REGION The objective of this section is to review past hydroelectric potential studies, assess potential new sites and compare hydroelectric generated power cost to that generated by diesel units. Hydroelectric work, except for Moonlight Springs, presented in subsequent portions of this document are "overview" in nature. Moonlight Springs Site, at the request of Nome's City Manager, was investigated extensively as described in Appendix 3.0. Hydroelectric power development for the Nome region has been investigated periodically since the early 1900's. The latest study was conducted by the Alaska Power Administration (APA) in the mid-1960's with results summarized in Exhibit 3.0-1, "Inventory of Potential Hydroelectric Sites in Alaska." Sites proposed by the Alaska Power Administration along with those recommended by the Nome residents are identified in Exhibit 3.0-2, "Location Map of Hydroelectric Dam Sites." Sites shown are: Bluestone River Dam Site Fish River Kuzitrin Dam Site Nome River Dam Site Salmon Lake Dam Site Tuksuk Channel Dam Site Moonlight Springs Site Description of these sites and assessment of their ability to supply electrical power to the City of Nome comprise the following sections. cae 1 KA1Lik Bend 2 Duna Haver 3 Kucher Creek noKnMesT KECON ou Upper Kobuh hives 10 Buckland Kiver n Taksuk Gorge n Kurieeun River (wunker MANE si » Salen Lake Me Fish River YUKON (IWTERIOR) REGION 4 Upper Chul teak kaver (thay Crow waite Bute Fey Leland Alatna bavi Alatoa River, Upper Jie Kiver 27 (10) melositne 2e nn paloettne Adv 23 a aby 300 movitns Rive 3o__testens tive 22-2) Junction Leland 3 anttene River 34 Neklaley Kiver 3 ___Chatantha Adv ~~ Feklantka Rive Srowe 3o Walker Creek 38 tanert Bor? (us) teat Sri carte 420) bruskanene 40 tetatlanthe Aver (itele belt 47 Ge) Bt bette 48 (17) Geratie 49 (16) Jona 9) Cau ST Wabeona 32 Chisana River sa hock Lake 3420) Kawpart : 38 Fork Qhandalar Biver, 7 Ease Fork Chandale River, Litele Rock se East Fork Chandale 59 (21) Porcupine 60.02 ae rot Mo. Fork Fortymt o So. fork Fortyaile 64 (24) Yukon-Tatye Exhibit 3.0-1 colvitie & Moatad i. Nowak Kotak Kogoluktuk Kobuk Buckland Tukeuk Channel Yukou ® Yakon hoy royuku Hoy wha oy sk Matne Matos oak Hoya “Tohe ke. eloeitna nelost Yukon Tanane ALASKA POMEK ALMIMISTRATION ory of Potential Hydroslectric Sites tn Alaska size ceiterie is generally 2500 KM (continuous power) and hegutated Surtace Head (ey te Kenan &. lookout Kidge cilik Woatah AZ Batra Mtn. Dd 7,000 Bared mtu. AL 7,840 Shungnak 0-2 a agra 2,970 Landi vo 2,410 Teller Anz 4215 Bendteben a6 1190 Solomon 0-6 107 Noman 0-3 4.20 Woly Crows 0-9 sez Woly Crows A-Te2 320,000 mutate 296,000 Kantosl ® wel 25,660 Melozitne 19/980 Mayhew 9-3 aw, 700 tees Hughes 2,960 Survey vans ais ber tes 0-2 0 Beet ten 4.350 iTseman a4 2.695 39 2/020 256,200, 2,570 44500 350 ® Kane 42,490 400 Kantiahna &. Rantiahna slaao S00 neKinley &. Chacanihe i “Teklanika Webeena f. Chiewane Pearmigan Crook Yukon ELF. Qhandalar EF. Giandalar EP. Chanda K.P. Chandatar Porcupine B. me. McKinley no 1,795 Livengood A-4 770 "$00 Wealy 0-6 $201,006 Fairbanks 2,450 1,000 Fairbanks 2/330 1,200 11190 2/200 1700 1,900 20130 : 1,600 Big delta 900 Big voles a7. Big Delta 300 bay velea 1,100 Mayen 10,700 11790 Mayes 1ol430 1,470 Tanacrosa 1550 Les Pas 2.025 Mebewne A-) ma aes mecarthy O-L 934,600, Tanana 8-3 200,000 “46s Chandatar ‘ woo. Guandalar 1,100 arctic 2,025 Coles a 975. 41,020 01,580 1,400 uns 2/200 rer Aonual Magula- theryy Capacity 1/7 Laden fanoft thon (ea tthon Wwlant Cost (000 ary uty (1000 WOH) factor W 3/ 140 1 160,000 12,306 137,000 13,100 19,200 100 1,070 14,000 100 2a 12,300 100 02 11,900 1661, 613 zioov 100 ms 920 100 rrr) 120 100 a 2,000 === as 1,300 90 ie a” 202 100 aw 6,400 100. 260 “96 2,080" 2590 9 90 66 18 a w Mould be nundated by 4 Tuksuk Gorge prod} Tukeuk to elevation $0 and 77 million awh. An alternative to Holy Crows Alternative to Dulbi, cost was wot calculated: Yukon-Talya would reduce downatream potential Inventory of Potential Hydroelectric Sites in Alaska 91419313 GB 1vwana9 GENERAL @@ ELECTRIC UZITRIN DAM SITE 3X&=" Ri et get ke r.. regress rap Wig eS : : Se a > ce " Le aah) ‘AIK MOUNTAIN: Of Bb \ . Ss ONY ee peat Ml pe ean gq cs NGLOPG7 16 “MT OSBORN ; Bas we ge ee Seed ee erent Aaliks ? AE te = SALMON LAKE DAM SITE Set accep ORs I LL ER ee es WEES “Reid a | A ge z S ISH RIVER SITE Location Map of Hydroelectric Dam Sites Exhibit 3.0-2 GENERAL @ ELECTRIC 3.1 BLUESTONE RIVER DAM SITE Bluestone River Dam Site, shown in Exhibit 3.1-1 "Bluestone River Dam Site Location Map" is located along the Nome-Teller Road approxi- mately 55 miles northwest of Nome and i7 miles southeast of Teller. The reservoir area formed by dam installation would be relatively small as shown in Exhibit 3.1-2 "Bluestone River Dam Site". The reservoir would require relocation of the Nome-Teller Road. The dam site has a tributary area of 75.83 square miles. Based on hydrologic estimates made from the Tuksuk Gorge region of about 1/2 cubic feet per second per square mile, the average flow for the Bluestone site would be about 38 cubic feet per second (APA). The installation of a dam 180 feet in height and having a crest length of about 850 feet would form a reservoir with a water surface elevation of 300 feet. The facility could be expected to produce approximately 300 kilowatts of power for 55 percent of the year or 1.3 million kilowatt hours annually (APA). Considering the relatively small amount of power produced, the market for power produced would be Teller. Teller's population ranges from 200 to 300 people which converts to a power load demand of roughly 150 to 250 kilowatts. Teller's need for power would be even less dur- ing the summer due to days with long periods of sunlight. It appears that the development of the hydroelectric facility along the Bluestone Creek is not feasible due to: e small load demand e@ construction requirements (dam, roads relocation transmission lines, sub-stations) e mismatch between power production and demand BLUESTONE RIVER . ee eT FRR Ve Gel a LISS Ck be ayPrar in BLUESTONE DAM & POWER re , TL = HLEVATIONS IM FEET Exhibit 3.1-1 Bluestone River Dam Site Location Map HOUSE SITE 91419313 GB 1vuanas GENERAL & ELECTRIC \ To TELLER \ Vy (P55 ta SONAL NK 2 .. em BLUESTONE DAM & POWERHOUSE SITE \ a SGN TING 7 Tre \ SVi/ ASS Lo Y —\Y { RN \) ‘ , BBY ESD UY Peg Zt ("~~ BLUESTO tT tte / THI/1 | xs | { “ . yy a m RESERVOIR AREA <> | \\\\ a4 / \ if \| \\ \ \ WY 7 /}}) \ ‘ cs \\ WW SS) My a ei CC ey \ MS TO NOME ELEVATIONS IN FEET Exhibit 3.1-2 Bluestone River Dam Site 3-6 GENERAL @ ELECTRIC 3.2 FISH RIVER - CONCRETE GRAVITY TYPE DAM Fish River, located approximately 75 miles northeast of Nome, Exhibit 3.2-1 "Fish River Dam Site Location Map", is one of the largest streams in southern Seward Peninsula. It drains a large area south of the Bendeleben Mountains and discharges into Golofin Sound. Its drainage area comprises 2,110 square miles and is composed of two large basins of about equal size, that of the Fish River to the east, and that of Nuckluk River to the west. The Fish River rises in the heart of the Bendeleben Mountains and flows in a general southward direction. A hydroelectric facility has been proposed on the Fish River through a U-shape mountain pass as displayed on Exhibit 3.2-2 "Fish River Dam and Powerhouse Site". The proposed hydroelectric facility - a concrete gravity type dam - would be 100 percent regulated and oper- ate under a 103 foot head (APA data). The maximum regulated water surface elevation would be approximately 150 feet above mean sea level and encompass an area of about 250 square miles - an area known gen- erally as McCarthy's Marsh within the Bendeleben Drainage Basin. The proposed hydroelectric facility installed capacity is esti- mated as 13,000 kilowatts with a plant factor of 55 percent - an annual firm energy production of approximately 60,000,000 kilowatt hours (6.8 megawatts of mean annual continuous power) (APA data). Based upon map reconnaissance, no major village or dwelling clusters were located within the proposed reservoir area. Assuming: e 13,000 Kilowatts Powerhouse Output e 100 Miles Transmission Length e 3 Phase, 397,000 Circular Mils, Aluminum Steel Core Rein- forced Conductors e 69 Kilovolt Nominal System Rating @ Power Factor of 1, B=, GENERAL &B ELECTRIC transmission line losses were estimated to be 1 megawatt. Assuming transmission line cost of $80,000 per mile (from Electric Power Research Institute publication "Transmission Line Reference Book", basic line cost was estimated to be $40,000 excluding land costs. Adding 1.5 for Alaska region, 1.1 for site remoteness, and 1.2 for engineering and con- struction supervision, transmission line installation cost is assumed to be $80,000), the 1980 transmission line costs are estimated to be $8,000,000. When the Fish River Dam Site was first investigated in 1965, the construction cost (excluding land right purchases) was estimated at $67,000,000. Assuming 7 percent annual inflation rate (from 1965 to 1979, Historical Construction Cost Index increased from 49.1 to 125.7 for an average annual compound rate of approximately 7%), 1980 costs for the same work would be about 188 million dollars. As indicated in Exhibit 3.2-1, a roadway presently exists from Nome to within 15 miles of the site. This roadway would provide reasonably good access to the site as well as a corridor for trans- mission line installation. Generally, site development appears to be technically feasible. 3-8 GENERAL GB ELECTRIC Def EZ ee SU: FISH RIVER DAM & POWE | i es ten iN ey &: % + e y ~ TRANSMISS zo Fish River Dam Site Location Map Exhibit 3.2-1 GENERAL QQ ELECTRIC 0 Y/ : wr le MI \ °930~ aa ee ot wN } ZN i\15, CODE: 400) I } Wer pe ul NV) yy, wares esl FIS RIVER DAM & POWERHOUSE SIT AN renter oan 988 COLA CAS Beal aD) oer ant Exhibit 3.2-2 Fish River Dam and Powerhouse Site GENERAL & ELECTRIC 3.3 KUZITRIN DAM SITE - CONCRETE GRAVITY TYPE DAM Kuzitrin River and its tributaries drain an area aggregating about 1,890 square miles, in the central portion of Seward Peninsula. The two forks of the main stream rise in the lava beds just north of the Bendeleben Mountains and flow west to Imuruk Basin. Kuzitrin River has a number of large tributaries, including Noxapaga River, Garfield Creek, and Kougarok River from the north; and Minnie, Ella, Bonanza, Birch, and Belt creeks from the south, The drainage basin is diversified, both topographically and geologically. At the south lie the Bendeleben Mountains, a rugged range with many sharp peaks and glaciated valleys. South of the Bendeleben Mountains is a large lowland basin di- vided into two parts; one the lower river between Bunker Hill and the Imuruk Basin; and above Bunker Hill the other, which merges toward the east into a plateau formed of lava flows. A hydroelectric facility has been proposed on the Kuzitrin River at Bunker Hill located approximately 75 miles from Nome as depicted on Exhibit 3.3-1 "Kuzitrin Dam Site Location Map" and Exhibit 3.3-2 "Kuzitrin Dam and Powerhouse Site". The proposed hydroelectric facility would operate 100 percent regulated under a 95 foot head of water (APA data). The maximum regu- lated water surface elevation would be approximately 150 feet above mean sea level and encompass an area of about 225 square miles as shown on Exhibit 3.3-3 "Kuzitrin Dam Reservoir". The proposed hydroelectric facility installed capacity is esti- mated as 14,000 kilowatts with a plant factor of 55 percent or an annual firm energy production of approximately 67,000,000 kilowatt hours or 7.6 megawatts of mean annual continuous power (APA data). 3-11 GENERAL €@ ELECTRIC Dwellings at Bunker Hill would need relocation should a dam be constructed. The Alaska Power Administration estimated this expense in their economic evaluation of the site. Assuming: @ 14,000 Kilowatts Powerhouse Output e 75 Miles Transmission Length e 3 Phase, 397,000 Circular Mils, Aluminum Steel Cord Rein- forced Conductors e 69 Kilovolt Nominal System Rating e@ Power Factor of l, transmission line losses were estimated to be .9 megawatt. Assuming 1980 transmission line costs of $80,000 per mile, the transmission line cost is about $6,000,000. The 1965 costs for the facility described were estimated to be $78,000,000 (not including land purchase rights). Updating cost to 1980 dollars (7% annual inflation rate), this same installation can be expected to cost $218,000,000. As indicated on Exhibit 3.3-2, a roadway presently exists from Nome to within 6 miles of the site. The roadway would provide reason- ably good access to the site as well as a corridor for transmission line installation. Additionally, the Kuzitrin River is navigable by shallow draft boat to Bunker Hill. Generally, site development appears to be technically feasible. tLe ELEVATIONS IN FEET «1 W SCALE Exhibit 3.3-1 Wht? pe eb Ber Oe ye oe Peel ‘S42 e™ KUZITRIN DAM & POWERHOUSE SITE | /& 1 . “Se p too Eee \o" Eo SRA 55 RIVER FLOW Da Lk KUZTITRIN RIVER “59 0 ANG Kuzitrin Dam Site Location Map : AVIS) el 600° ~ /& 8 SS) —_J® SALMON LAKE Bee SC isslen LINE q Mikes yh = Di) 91419373 GB 1vuana9 GENERAL @@ ELECTRIC 893TS esnoyreMog pue weq uTARTZNyY z7-E°E 3IqQTYXT N “a /<= io z oO _ 3-14 ST-€ RESERVOIR AREA 5 ELEVATIONS IN FEET Exhibit 3.3-3 =. =) U ote SS —— NOME TRANSMISSION LIN Ae, 1388) “6 se — EH Kuzitrin Dam Reservoir 91419373 GB 1vu3Nna9 GENERAL €@ ELECTRIC 3.4 NOME RIVER DAM SITE Located approximately 22 miles north of Nome along the Nome- Salmon Lake Road is a ridge about 15 to 20 feet high composed of stable rock, Exhibit 3.4-l1 "Nome River Dam Site Location Map" and Exhibit 3.4-2 "View of Ridge, Looking Towards Nome". Some area residents are of the opinion this is an ideal small head hydroelectric site. Examination of Exhibit 3.4-3 " Nome River Dam Drainage Basin Area", reveals that the drainage basin for that sec- tion of the Nome River is very small - 28 square miles. The power output from a facility with an operating head of 17 feet was estimated to range from 60 to 100 kilowatts. This small site is not considered suitable for hydroelectric development. 3-16 GENERAL €@ ELECTRIC 422 TRANSMISSION LINE 2 ELEVATIONS IN FEET Nome River Dam Site Location Map Exhibit 3.4-1 3-17 8T-€ Exhibit 3.4-2 RIVER FLOW NOME-SALMON LAKE ROAD View of Ridge, Looking Towards Nome 91419313 GP 1vuINgas GENERAL @ ELECTRIC am ui) ae 3| << WAR %, \ v N \ ee en NOME RIVER DAM“ POWERHOUSE SITE sep torts WORE REL y RS tN 1 | me ELEVATIONS IN FEET ' Exhibit GENERAL €@ ELECTRIC 3.5 SALMON LAKE DAM SITE - CONCRETE GRAVITY TYPE DAM Salmon Lake is located approximately 30 miles north of Nome - Exhibit 3.5-1 "Salmon Lake Location Map". Salmon Lake has been formed by the damming of the Pilgrim River by morainic materials brought down by glaciers which occupied the valleys of the Kigluaik Mountains and extended some distance beyond their flanks. The outlet of the lake, Exhibit 3.5-2 " Salmon Lake Aerial View", has been cut through this moraine, and a dam site has been formed, about 150 feet long at the bottom and 600 feet long at an elevation of 50 feet above the present lake surface of 442 feet above mean sea level. The morainic material is composed largely of gravel and angular frag- ments of no great size and was in part laid down in water, as it shows a certain degree of stratification and is interbedded with clays and silts. Salmon Lake hydroelectric development as proposed in the Alaska Power Administration inventory, is depicted in Exhibit 3.5-3 "Salmon Lake-Nome River Scheme", and consists of: e Construction of concrete gravity base dam across the outlet of Salmon Lake to a crest height of about 500 feet above mean sea level. e Intake Structure and Tunnel to transport water from the Pil- grim Power Basin to the Nome River Basin. e Buried Conduit to a point above the Nome River, where water is then fed into a Penstock. Water then flows down the Penstock into Powerhouse with the Powerhouse tail race at elevation 200 feet above mean sea level. Due to numerous water interchange points and relatively long water conveyance lengths, the hydroelectric arrangement proposed is compli- cated and costly. The 1965 cost for the facility was estimated to be $70,000,000 (excluding land use purchase rights). Updating costs to 1980 dollars (7% annual inflation), the same installation can be expected to cost $196,000,000. 3-20 GENERAL €@ ELECTRIC Transmission line power loss and cost were not calculated due to its nearness to Nome (25 miles) and relatively large power plant cost as compared to transmission line installation costs. a From a technical perspective, the "Salmon Lake - Nome River Scheme" would be difficult but feasible, 3-21 gent ELEVATIONS IN FEET Exhibit 3.5-1l > Sh 1718, % HS. WS SALMON LAKE QS ADO) US TOY I ‘7 foo / ©) ar Sa ee a ee ZT " . WwW a poe Salmon Lake Location Map ATER FLOW Sr J ¥ 91u19373 GB 1vuana9 ECae SALMON LAKE Exhibit 3.5-2 PILGRIM RIVER — WATER FLOW SALMON LAKE DAM SITE Salmon Lake Aerial View 91419313 GP 1vwanas VE=E | a eee Cb fet - ‘) TUNN 0 aes es NOME - PILGRIM RIVER BASIN DIVIDE , ‘e { used : t PILGRIM RIVER SALMON LAKE DAM SITE RESERVOIR AREA Ag = me ge 4 Ml fe gn) lS he dy. Nee WA t aa} Ole TA Lp ja : 2 a aa EL INT | { ¢ NOME RIVER DAM & BURIED CONDUIT INTAKE STRUCTURE BURIED CONDUIT NOME RIVER CONDUIT TERMINUS FLEVATIONS IN FEET Exhibit 3.5-3 PENSTOCK POWERHOUSE Salmon Lake - Nome River Scheme AY. ) ¢ WN us (VY (« \\WV(/ ( e ) SALMON LAKE 91419373 GB 1vuanas GENERAL &@ ELECTRIC 3.6 TUKSUK CHANNEL DAM SITE Tuksuk Channel Dam Site, Exhibit 3.6-1 "Tuksuk Channel Dam Site Location Map" and Exhibit 3.6-2 "Tuksuk Channel Dam & Powerhouse Site", is located approximately 75 miles northwest of Nome. Water depths in the vicinity of the proposed dam are about 42 feet - precluding small dam construction. The proposed hydroelectric facility for this site would have an installed capacity of 66 megawatts with a plant factor of 55 percent or 289,000,000 kilowatt hours of energy annually. The area that would be inundated by construction of the dam is out- lined in Exhibit 3.6-3 "Tuksuk Dam Reservoir Area". Major portions of the Imurik Basin, including Pilgrim Springs, and the Kuzitrin River Basin would be impacted. This site is not considered feasible for development due to the: e@ depth of water in the channel, @ power produced is an order of magnitude greater than needed, e environmental impact of reservoir area formation. 3-25 got y TELLER TRANSMISSION LINE { Sy», (23\/ a Pes 7 TUKSUK CHANNEL 73 a fs NIWA SAK a) a eer) (aA s TUKSUK CHANNEL DAM & POWERHOUSE ~~! 2 $3 RS ILIV 8 we so o tz itp SEE SS) NOME - TELLE Exhibit 3.6-1 Tuksuk Channel Dam Site Location Map 91419313 GB 1vuanas GENERAL @@ ELECTRIC “TUKSUK CHAN 1145 ~ Exhibit 3.6-2 Tuksuk Channel Dam & Powerhouse ELEVATIONS IN FEET 3-27 GENERAL @@ ELECTRIC TUKSUK CHANNEL KUZITRIN FLATS ee ee BUNKER HILL KUZITRIN DAM & POWERHOUSE SITE NOME-SALMON LAKE ROAD Tuksuk Reservior Area Exhibit 3.6-3 GENERAL @@ ELECTRIC 3.7 DAMS BUILT FROM LOCAL MATERIALS UNDER PERMAFROST CONDITIONS In estimating cost for dams listed in the Alaska Power Adminis- tration's "Inventory of Potential Hydroelectric Sites in Alaska" for the Nome region, only concrete gravity type dams were considered. Due to the remoteness of the region, building of dams (chiefly rock-filled types) from local materials should be investigated. Primary consider- ation would focus on the thermal stability of soils, since most perma- frost soils lose their load-bearing capability and become highly permeable to water as they thaw. Two fundamental types of dams can be built on permafrost from local materials: e nonfiltering dams that use the permafrost as an extremely strong and water-impermeable material, Exhibit 3.7-1 "Cross Sections Through Typical Earth Dams Built on Permafrost" e filtering dams, which are designed with consideration for permafrost thaw in their bases, Exhibit 3.7-l "Cross Sections Through Typical Earth Dams Built on Permafrost". In the first case ("frozen variant"), the dam can be built with practically any type of soil, provided that the frozen state is pre- served, and with it the strength and water impermeability of the ice- saturated frozen ground. In the second case ("thawed version"), earth and rock-filled and concrete dams can be built only on strong bedrock or on coarse-skeleton ground with low compressibility and a mandatory impermeable core. Dams built from local materials have been constructed as high as 246 feet. An example cf one such dam is the Vilyuy Dam in Russia. Vilyuy Dam shown in Exhibit 3.7-2 "Vilyuy Dam" measures 207 feet in height and is on incompressible bedrock. For locations where incom- pressible bedrock is not found, artificial freezing of soils by means of cooling systems that are continuously or periodically used have been GENERAL €B ELECTRIC installed. Some of these system simply circulate winter air to main- tain soil-ice stability. Rock filled dams appear to have an application in the Nome re- gion. This assumes that competent geotechnical conditions exist at a site, especially for providing sources of construction materials. GENERAL B ELECTRIC Co; a2 Ms —~4—~ 5 6 Cross sections through typical earth dams built on permafrost: (a2) dam using frozen ground as material for strength and impermeability to water (nonfiltering dam); (5) filtering dam; (1) zone of per- manently thawed soil; (2) zone of perma- nently frozen soil; (3) zone of alternating thawing and freezing; (4) zone in which natural talik must be frozen; (5) zone in which preliminary thawing is desirable; (6) frost-heave zone with water influx. Exhibit 3.7-l1 Cross Sections Through Typical Earth Dams Built on Permafrost (isota Vilyuy dam: (1) rock fill; (2) filtering layer; (3) clay core; (4) rock ballast; (5) grout screen. Exhibit 3.7-2 Vilyuy Dam 91819313 GB 1veanag GENERAL ELECTRIC 3.8 SALMON LAKE DAM SITE - ROCK FILLED TYPE DAM Of sites considered in Sections 3.1 through 3.6 "Region Poten- tial Hydroelectric Sites", several site development costs could be substantially reduced if rock filled type dams were considered rather than concrete gravity type. Of particular interest is the Salmon Lake Site. Salmon Lake is formed by morainic material brought down by gla- ciers. The morainic material is composed largely of gravel and angular fragments. It is not unlikely that there may be, at a reasonable distance below the surface, a stratum of boulder clay or other imper- vious material on which a cut-off wall could be founded, but such a stratum has not been demonstrated to exist. It is proposed that the dam be constructed utilizing a concrete core or concrete slurry wall supported on either side by locally obtained materials. The crest elevation would be set at 525 feet above mean sea level creating a reservoir with a maximum pool elevation of about 500 feet above mean sea level. The reservoir would be 1 mile wide and 8 miles long as shown on Exhibit 3.5-3 "Salmon Lake Reservoir Area". The dam and powerhouse would be separated by a 10 mile long penstock as shown in Exhibit 3.8-1 "Salmon Lake Alternative. This arrangement would provide an operating head of approximately 225 feet. Exhibit 3.8-2 "Salmon Lake Monthly Discharges", indicate water flow is continuous all year with a mean winter flow (October-April) of about 50 cubic feet per second (CFS) and a mean summer flow of approx- imately 489 CFS. Assuming regulation could supply dependable annual mean flow of about 243 CFS, or about 90 percent of the mean flow, the potential power is estimated as 4000 kilowatts (refer to Appendix 3.0, page 4-1, for power calculation formula). To account for penstock head losses, 4000 kilowatts is reduced 75% to 3000 kilowatts. Assuming: 3-535) GENERAL €@ ELECTRIC e 3 Megawatt Powerhouse Output e 35 Mile Transmission Length e 3 Phase, 397,000 Circular Mils, Aluminum Steel Reinforced Conductors e 34.5 Kilovolt Nominal System Rating e@ Power Factor of l, transmission line losses were estimated to be about .3 megawatts or 10% line loss. Costing of a rock-filled type dam at the Salmon Lake site was performed in Section 3.8.1 that follows. The estimate was prepared without benefit of detailed hydrologic and geotechnical information. GENERAL GQ ELECTRIC 3.8.1 225 FOOT GROSS HEAD ARRANGEMENT 1980 COST ESTIMATE Slurry Wall/Concrete Core 3000 linear feet @ $4,000 per linear foot $12,000,000 Rock Fill Placement 200,000 cubic yards @ $25 per cubic yard 5,000,000 Powerhouse 6,000 kilowatts installed @ $2,000 per kilowatt 12,000,000 (Power Factor - 55%) Power Production Equipment 3,000 kilowatts installed @ $2000 per kilowatt 12,000,000 (Power Factor - 55%) Relocation of Road 3 miles @ $500,000 per mile 1,500,000 Purchase of Property Not Assessed Substations Not Assessed Transmission Line 45 miles @ $80,000 per mile 3,600,000 Penstock 10 miles @ $3,000,000 per mile 30,800,000 SUB-TOTAL $76,100,000 Miscellaneous @ 15% $11,400,000 SUB-TOTAL $87,500,000 Engineering (Site, Design, Construction, Start-Up, and Check-Out) @ 203 $17,200,000 TOTAL ESTIMATED CONSTRUCTION COST $105,000,000 3-35 9E-€ ELEVATIONS IN FEET Exhibit 3.8-1 v \ mr 92080 \ ol oy Nowe E rer Oo %, \2 x jl s\ a) Be) 1388: ) nk y XS NS PENSTOCK (7% PILGRIM RIVER =": Be AFT SALMON LAKE DAM SITE < Mao {CRASH LY Fateh S xX WRA Bn TRANSMISSION LINE » *!<! FP EAN Sry Salmon Lake Alternative Aisne 91419313 GB 1vwanag GENERAL €@ ELECTRIC Runoff, tsebes on | Total tn aneeeeesnasa SRERSESS5988 4 8] 382888889828 889888888898 sdeit igi gaged drainage | acre-feet. ares. SRIBABIR REBRKBILSSAT Pade” SSBSSRBIALR pooteodaaaee SIRsreesyeaa | | Per square mile. BRBBOMATRIES So Sededdelit BASIS oSIBRSB Td aided” RBBISKASSASE St todededed ot RSIIS+SERBKB gad @S45483E5389 et tbefet BSIIAS HOARSE elabefdrjetd * PRSIERATIRSE saasnpagesée oo BBIsgrgeRegs | saree SISSRRRIERS 'SBSQsrs | Maximum. | Minimum.| Mean. gganera aE Salmon Lake Monthly Discharges Exhibit 3.8-2 3-37 GENERAL €@ ELECTRIC 3.9 FISH RIVER SITE - ROCK FILLED TYPE DAM Assuming the geology permits installation of a Rock filled type dam, costs presented in Section 3.2 "Fish River Site - Concrete Gravity Type Dam" could be reduced by approximately 15 percent, 3-38 GENERAL €@ ELECTRIC 3.10 KUZITRIN RIVER SITE - ROCK FILLED TYPE DAM Assuming the geology permits installation of a rock filled type dam, costs presented in Section 3.3 "Kuzitrin River Site - Concrete 4 Gravity Type Dam" could be reduced approximately by 25 percent. (Kuzitrin River Dam Construction is less expensive than for a similar facility on the Fish River since the site has good road and waterway access.) 3-39) = => =— => a =e = wa GENERAL €Q ELECTRIC 3.11 HYDRO-DIESEL COST COMPARISONS The Alaska Power Authority (APA) has established guidelines for performing economic analysis. APA directed that an inflation rate of 7 percent be used with an additional 2 percent applied to oil products. Interest rates of 7, 9, and 10 percent were also recommended. Project life of 35 years was to be assumed. These guidelines are applied to data developed in the preceding portions of this document. Results are presented in Exhibits 3.11-1 "Cost Comparisons - 7% Interest Rate", Exhibit 3.11-2 "Cost Compari- sons - 9% Interest Rate", and Exhibit 3.11-3 "Cost Comparisons - 10% Interest Rate". These exhibits compare only diesel capital and fuel cost to hydro- electric plant cost. For this effort, diesel operating (less fuel) and Maintenance costs are considered equal to that of hydro generated power (most hydroelectric plants are operated automatically or from remote locations). Hydro dollars per kilowatt displayed in Exhibits 3,.11-1, 3.11-2, and 3.11-3 are based upon 100 percent power use. Hydroelectric system capital charges were considered fixed so that as the annual power consumed deviates from the 100% usage factor, capital charges per kilo- watt hour increase. Generally 4 to 6 years are required for complete hydroelectric construction and installation. Preceding these years, additional time is necessary to obtain environmental approval, make final geo- technical assessments, etc. 1990 was assumed as a representative date when hydroelectric power would be available in the Nome region. From Section 2.0 "Nome Electric Power Generation Characteristics", Nome's total power production is approximately 8450 kilowatts. Of the 8450 kilowatts, 5950 kilowatts are produced from 7 relatively small diesel power units. It was assumed that by 1990 Nome would replace 3-40 GENERAL €Q ELECTRIC these 7 units with larger units - such as the existing General Motors. This assumption is based upon the projected Nome population increase and the need to retire outdated equipment. Thus, 1980 Nome Diesel Capital Changes were increased from $.025 to $.05 per kilowatt hour ($.025/kWH x [1.07]1°) and 1980 Nome Diesel Fuel Charges from $.062 to $.15 per kilowatt hour ($.062/kWH x [1.09]?°) to reflect 1990 charges. Diesel Capital Charges were assumed fixed for the next 35 years while Fuel Charges were escalated at 9 percent annually. For 1990, total Capital and Fuel Charges were estimated as $.20 per kilowatt hour. Hydroelectric power outputs and costs developed in previous sec- tions are summarized in the first 3 columns of Exhibits 3.11-1, 3.11-2, and 3.11-3. 1980 costs were then projected to 1990 using a factor of ee of 35 years, annual capital recovery charges were determined. Corres- ). Using interest rates of 7, 9, and 10 percent over a period ponding costs per kilowatt hour were calculated by dividing the Annual Capital Recovery Charges by the Net Annual Firm Energy Produced. Of the hydroelectric schemes considered, a rock-filled type dam arrange- ment at the Kuzitrin Site appears to have the lowest 1990 development cost - $.44 per kilowatt hour. As stated in Section 2.2, Future Power Requirements, Nome's popu- lation can be expected to double by the year 2000 (excluding possible offshore oil development impacts). The corresponding power load demand is assumed to be linearly proportioned to the population in- creasing from 14,000,000 to 28,000,000 kilowatts annually. The Kuzitrin Site Annual Firm Energy Production is estimated to be about 59,000,000 kilowatt hours, 31,000,000 kilowatt hours more than Nome would need. This excess power can be expected to be utilized in resistance heating systems or an hydro/hydrogen.generation and storage system. If this is not the case, kilowatt hour cost would increase by a factor of 2.1 (59728). 3-41 GENERAL 3 ELECTRIC Results indicate that in 1990, a diesel electric power system "cost per kilowatt hour" would be less that the hydroelectric alterna- q tives considered. Diesel and hydro generating system costs would be similar in Year 2000 provided that dams were put in operation in 1990. i Year 1980 construction expenditures would need to be multiplied by a factor or 4 CLuGe to convert to year 2000 cost - increasing capital charges by the same factor, 3-42 Cp-€ DIESEL VS. HYDRO ELECTRIC GENERATION COST COMPARISONS YEAR 1990 DAM COMPLETION 7S INTEREST RATE —r ———— ner ANNUAL YEAR 1990 FIRM TRANSMISSION ANNUAL, YEAR 1980 YEAR 1990 YEAR 1990 Gaae cost VEAR 2035 SYSTEM ENERGY LOSSES, FIRM INSTALLATIONS. COST PER INSTALLATION arenueay PER COST PER (MILLIONS (MILLIONS ENERGY cost Kwit cost Kets CHARGES, Kot mic Ket) Kut) aLLions (8 MILLION) (Katt) (smicuion, | GuAnces ‘aan (sikh CaPiTac CHARGES 025 05 -05 NOME DIESEL .062 .15 3.1 FUEL CHARGES | DIESEL TOTAL - 087 BLUESTONE RIVER SITE CAPITAL CHARGES T-TT°€ FFATUxXa ASIBLE Conchete GRAVITY DAM 196 392 Carat cuanots Concne re Ghavity DAM 214 428 | Carita cnanots Q O n a Q O 3 oS om K B n ° 5 n NOME RIVER SITE SITE NOT CONSIDERED FEASIBLE |) cacmoarcaneneee perme 196 392 CONCRETE GRAVITY DAM CAPITAL CHARGES TUKSUK CHANNEL SITE CAPITAL CHARGES SITE NOT CONSIDERED FE SALMON LAKE SITE ROCK FILLED OAM 225 FOOT HEAD OPTION 105 CAPITAL CHARGES sages 60 168 ROCK FILLED DAM CAPITAL CHARGES aqzey FSOTSQUI BL KUZiTAUN nuven site hock FitueD oam 67 CAPITAL CHANGES “TRANSMISSION LOSSES AND COSTS WERE NOT ASSESSED 91u19313 GB 1vuaNna9 vP-€ DIESEL VS. HYDRO ELECTRIC GENERATION COST COMPARISONS YEAR 1990 DAM COMPLETION Qg Intenest nate ner ANNUA YEAR 1990 rin TRANSMISSION | ANNUAL YEAR 1900 YEAR 1990 YEAR 1990 CAPTAL cost YEAR 7025 ENERGY LOSSES FRM INSTALLATIONS | COSTER | INSTALLATION | CAPITAL rer COST PER (MIL Lions (MIL LIONS. ENERGY cost Kot cost Katt CHARGES Kot ae eae Ket) tar. Lions (e MILLION) (8/Kwttd (8 MILLION) (snatclouaT tenet) (skit NOME DIESEL .025 .05 05 CAPITAL CHARGES. Putt cuanacs - 062 15 — | .087 BLUESTONE RIVER SITE CAPITAL CHARGES SITE NOT CONSIDERED FEASIBLE Z-TT°€ FtATUxXa Concnete GRAVITY DAM 196 392 cabivat chancte Poe 214 2 aQ oO a ct aQ O 3 'O @ K B. a oO 5 a NOME RIVER SITE SITE NOT CONSIDERED FEASIBLE Conenere GRAVITY DAM 196 392 Carivat cHanGes TUKSUK CHANNEL SITE CAPITAL CHARGES SITE NOT CONSIDERED FEASIBLE SALMON LAKE SITE 225 FOOT HEAD OPTION 105 210 CAPITAL CHARGES Fis RIVER SITE 60 168 336 ROCK FILLED DAM CAPITAL CHARGES aeY YSSTSERUI 6 moet 67 340 | “TRANSMISSION LOSSES AND COSTS WERE NOT ASSESSED 91419313 GB 1vuang9 SP-E DIESEL VS. HYDRO ELECTRIC GENERATION COST COMPARISONS YEAR 1990 DAM COMPLETION LOG Interest rate NET ANNUAL ANNUAL YEAR 1900 FIRM TRANSMISSION ANNUAL YEAR 1980 YEAR 1900 YEAR 1990 CAPITAL cost LOSSES FIRM INSTALLATIONS COST PER INSTALLATION dnency, | toes | entnay tas me a necoveny ren Katt) Kot) (ane re (8 MILLION) (8/Kott) (6 MILLION) nal CHARGES Kot (8 MILLIONS) (Kt NOME DIESEL .025 ~05 CAPITAL CHARGES NOME DIESEL .062 15 FUEL CHARGES €-TT°€ FtqTUxE NONE DIESEL TOTAL -087 BLUESTONE RIVER SITE CAPITAL CHARGES: ASIBLE Fish aiven site 392 CONCRETE GRAVITY DAM CAPITAL CHARGES. kuziTam fuven site Concht te Gavity DAM 428 CAPITAL CHARGES NOME RIVER SITE SITE NOT CONSIDERED FEASIBLE SALMON LAKE NOME RIVER SITE* 196 CONCRETE GRAVITY DAM CAPITAL CHARGES 392 TUKSUK CHANNEL SITE CAPITAL CHARGES SITE NOT CONSIDERED FEASIBLE SALMON LAKE SITE ocx Ficeb oam 225 FOOT HEAD OPTION 105 210 caoTTAU cHances FISH RIVER SITE 60 168 336 ROCK FILLED DAM CAPITAL CHARGES Qa ° a co Q ° a we} © K H- a O° s a ! hb oO oe H 5 ct oO K 0) n ct w » ct @ SITE oc Fitteo baie 67 340 CAPITAL CHARGES “TRANSMISSION LOSSES AND COSTS WERE NOT ASSESSED 1u19313 GB 1yuaNng9 GENERAL ELECTRIC 3.12 ADDITIONAL HYDROELECTRIC POWER COMMENTS As stated earlier, the hydroelectric assessment performed is an overview in nature. With additional development of geotechnical and construction information, cost of hydroelectric facilities at Kuzitrin and Salmon Lake Sites may be reduced. In the case of Salmon Lake, soil sampling studies would establish the need for a slurry cutoff wall and quantity of rock fill required. For the Kuzitrin Site, the water- way to Bunker Hill is navigable to shallow draft vessels allowing for shipment of equipment and materials. Of the two, the Kuzitrin Site appears to have the highest poten- tial for development based upon: e Lowest development cost as shown in Exhibits 3.11-1, 3.11-2, and 3.11-3 e Largest drainage basin and reservoir @ Site accessibility to construction materials and equipment. Finally, lake ice thickness in the Nome region probably would not exceed 9 feet in thickness. Large rivers, such as Pilgrim River at the outlet of Salmon Lake, Exhibit 3.8-3, have a year-round flow. As shown in Exhibit 3.8-3, average winter flow is almost an order of magnitude less than that of typical mean summer flows. Dams proposed are sized so that some summer acquired water could be stored to aug- ment natural winter flows. Should additional hydroelectric studies follow, reservoir storage characteristics to levelize annual power production schedules would need to be considered. GENERAL @ ELECTRIC 3.13 CONCLUSIONS Unless the economic parameters used in compiling this report are altered, hydroelectric generation of electricity is not an alternative § to the present diesel generation system. MOONLIGHT SPRINGS RECONNAISSANCE WATER RESOURCE STUDY NOME, ALASKA PREPARED FOR THE ALASKA POWER AUTHORITY JANUARY, 1980 ADVANCED ENERGY SYSTEMS PROJECTS ENGINEERING OPERATION INSTALLATION and SERVICE ENGINEERING DIVISION 1 RIVER ROAD SCHENECTADY, NEW YORK, 12345 GENERAL @® ELECTRIC 3-48 APPENDIX 3.0 GENERAL @@ ELECTRIC CONTENTS APPENDIX 3.0 GENERAL QD ELECTRIC TABLE OP CONTENTS Section Page 10) TNTRODUCTION Soe te aw eee tg elo eo to sos 1-1 220 MUNICIPAL WATER SYSTEM .....-.+.-+-.-.+e.. 2-1 320 NOME ELECTRIC POWER GENERATION CHARACTERISTICS . 3-1 4.0 HYDROELECTRIC POWER POTENTIAL . ......... 4-1 au FIELD INVESTIGATIONS ........4..+24646-. 5-1 6.0 SUMMARY AND CONCLUSIONS ..........4+446.-. 6-1 120) ACKNOWLEDGEMENTS ...... 2. + © © © © © © @ J-1 8.0 REP ERENCE S Ssepetg tec teoiafa te anteater no tone ns 8-1 i APPENDIX 3.0 GENERAL €@ ELECTRIC LIST OF EXHIBITS Exhibit Title Page 1-1 Location Map....... sVokenslell okeWolololel oleleliohelelaLehelaloleveienerer oie 1-2 2-1 DE AWA eLmeeiererole aielercliarelel araialiereiaiclcheieleloieiele elelelicteleieterore 2-3 2-2 Drawing 2 ....<-; oieialeveie lial eiroliotioneta of cilajieice elev eVa) halicieiielonsiens 2-4 2-3 DrAwang) 3) iererels) «cre eicielelalslelishelelererchohersisickerlalelelelclonel ster 2-5 2-4 Drawing 4 .......... etre tence eecessarerececes 2-6 2-5 DE AWENG MOM en Rodel eielelereke rer shelled eloker akeleleKa lately creche elerstcrcls 2-7 2-6 Drawing (6) ai SiolioletaloneNeholoislclarstol lciclelokckeholeielokenolelen neta 2-8 2-7 Drawing 6-A ....... erale eiielieiieie/1 es! eifelielielionens sveKelielorelener elena 29 2-8 DEAWANG! O=B) ee creiciaicle = oo SheleloNaleraiehalarelorcie cisiclonncketeloncl= 2-10 2-9 DAWN Gia melelorelerel ciahale oiclaielolelalelolsralaicielelersrarsie aiereliele stare 2-11 2-10 Drawing 8 ..... ceeene CoA PRET OP Eee we 2-12 2-11 D2 W119 roterrenet elralioellerareneieieliaiellehepaiereteielelerenarieleiieiioleRaner sien 2-13 2-12 Drain Field OVS yew) Malelelienalelehoisinisialstalchovelelieierenclersielen 2-14 2-13 Ovexrtllow | SERPUGEUTE! fis areca is elo aicie ales © 6) 4) elaite alelele sles 2-15 2-14 Spring #1 Above Drain Pield afelielslioliolel lel elsiieielelololel<eie 2-16 2-15 Spring #2 Above Drain Freld | cc ceccavce eo evoncions 2-17 2-16 Collector=Terminus=.-rerejere ce alcrsisle sles ele siete we = se 2-18 3-1 Average Daily KW/H Production by Month ......... 3=2 4-1 Generator Output oes seeccceeccs plcketenotelelolelekenohoreneielte 4-3 5-1 ENV.SSET Jat TON ANC alaaenatetenetevarerelel ale crererehehonevienene onan er sieve 5-13 5-2 Geologic Cross Section A-A ......-sesceeee ascace 5-14 5-3 Location of Test Holes ....... slcleneloherelotienelere a) slleiieiells 5-15 5-4 Lithologite Logs) of Test: | Holley (ys << arcrielelercs e)oialicile 5-16 ii APPENDIX 3.0 GENERAL @@ ELECTRIC SECTION 1.0 Introduction APPENDIX 3.0 GENERAL GB ELECTRIC 1.0 INTRODUCTION During the fall of 1979, field investigations on the water re- sources of the City of Nome, Alaska, which lies on the western half of the Seward Peninsula and fronts Norton Sound (EXHIBIT 1-1 "Lo- cation Map"), were conducted by two branches of the General Electric Company - Advanced Energy Systems of Projects Engineering Operation and TEMPO, Center for Advanced Studies. Inclusive in the field in- vestigations were the drilling of four test holes. The primary ob- jective of these efforts were the evaluation of ground water re- sources which supply the City's municipal water system to determine if adequate flows exist to generate hydroelectric power. Presently, the municipal water sources are Moonlight Springs. In the Springs' vicinity, an underground drain field collects water and feeds it into a buried pipe. Collected water then travels down a pipe approximately 2.5 miles to the City via gravity due to a pipe "entrance-exit" elevation difference of over 100 feet. Once at the treatment plant, transported water is deposited, under atmospheric conditions, into a cistern for treatment and then distributed. Water flows year round and is not heated during the winter months. Moonlight Springs drain field utilizes only a portion of the formation where water is collected. Field investigations were ini- tiated to assess water yield characteristics of the formation in- cluding an evaluation of optimum drain field placement. Description of these investigations and their results form sub- sequent portions of this document. 1-1 APPENDIX 3.0 GENERAL QQ ELECTRIC Mpa Moonlight p RA 0) Cty Sea, 4 |= N Ss ¢ a SNS prings ' Project Area EXHIBIT 1-1 Location Map 1-2 APPENDIX 3.0 GENERAL @@ ELECTRIC SECTION 2.0 Municipal Water System APPENDIX 3.0 GENERAL GB ELECTRIC 2.0 MUNICIPAL WATER SYSTEM As indicated in Section 1.0 "Introduction", Moonlight Springs are the sources of water for the City of Nome. Engineering drawings of water transmission and source development (provided by Clark & Groff Engineers of Salem, Oregon) are presented as EXHIBITS 2-1 through 2-ll. EXHIBIT 2-11 "Source Development and Intake Works" shows dJe- tails of the underground drain field. Essentially, the system mea- sures 1000 feet in length along the base of Anvil Mountain at an elevation of 105 feet above mean sea level. Water is collected along lengths of perforated pipe sections with pipe extensions (Section A-A, EXHIBIT 2-11) placed in known spring areas found during construction. Collected water then flows to a "Collector Terminus and Overflow Structure" for transmission to the city. Nome utility personnel stated that at the time of our initial visit in August, pipeline flow rate was 400 gallons per minute and that the pressure near the ter- minus of the pipeline just before water drops into the city cistern was approximately 35 pounds per square inch. Photographs of the drain field are presented in EXHIBITS 2-12 through 2-16. EXHIBIT 2-12 "Drain Field Overview" shows the basic components of the drain field, local topography and the presence of excess water from springs located above the drain field. During the August visit, the estimated total yield of the formation was 10 to 15 cubic feet per second. It was also noted that many of the springs were releasing water at elevations considerably higher than elevation 105 - one in excess of 50 feet above the collector terminus at a flow rate of 1 to 2 cubic feet per second. Based upon the August visit, the following observations were made: o The City of Nome does not utilize the pressure or velocity head at the Moonlight Springs water transmission terminus. 2-1 APPENDIX 3.0 GENERAL @ ELECTRIC o Only a small portion of Moonlight Springs water resources are used by the City. o It is possible that a new drain field could be installed ata higher elevation than that of the existing collection system. Subsequent portions of this document will address the hydroelec- tric potential of these observations. APPENDIX 3.0 GENERAL @@ ELECTRIC pons MOONLIGHT NCH NO 321 Ey BENCH NO 608 FRACTION 405 Test wove TEST MOLE TEST MOLE Nez nes 18. FL00R fév"eeae L ranean s/f oo TUNDRA fe assoc Wl 9 8 oS vnc ow cn na cal moan CROSSING A oe SSR SoS” Eee aS Se LILLIAN Assoc PLACER aaa J geaesr'se”w 333.64 PROPOSED WATER TRANSMISSION LINE \. BENCH NO 4S mete PLACER 1373\ TUNDRA LAKE assoc 7 vier i208 SAIH. NET MAYFLOWER PLACER ANVIL TUNDRA assoc. i ALLE BENOK <0 PLACER 1373, SKOOKUM Mz SNAKE PLACER FAA HOUSING \ Aah Uae CITY OF NOME - WATER TREATMENT PLANT Navayo 1154 SITE reac geo 494 3 2 i 4. 7, ®. [wa yee] as ae [EVision | Date | APPROVED EDA PROJECT NO. 07-1-00489 nevseo sr CITY OF NOME, ALASKA APPROXIMATE LOCATION | PROPOSED WATER TRANSMISSION LINE CLARK & GROFF ENGINEERS ENGINEERING ARTS BUILDING 3276 Commercial $ & 968 By 26 ows. EXHIBIT 2-1 Drawing 1 APPENDIX 3.0 GENERAL QQ ELECTRIC EQUATION STONON O00 = -1s2 q& CURVE DATA WOBTOROU © 1N4.55" AUT. ROUTE TOBRIOGE. KiNG (FIELD otek [> Locate) see sueeT No whg oe eaniereN - Best oy 26 E T68.08" be IN8.8 oN Bh BNYKG VEUts © CURVE DATA As 24240 30" Rs 640.08 T+ \40.00' Le U5 ee" Be asst or wre & Cove opTe a: 53°80" tT 5A0.8y auanl * 30060 meal + SBR. 20 + eke & CURVE DSTA x Re Wer ae) & Ls 420.26! . T 100.00" Le 80 38 De v3.33 BURIED POWER COMES “ES ‘AAW [BLE | awe ‘yo Mung Ai SPECIAL ITEM NO 2 STA 28+00 4° DIA SERVICE STUB FAA HOUSING SEE SHEET 7 S47 ee see PINVUIN GS 7 © cusve pata 7 TAVLING 57 eC Re arg.10 \20.00 NEE RORY Ds 2.0045 BORLCOW «AKER ee, ay TA moot bate | aeevo | ecReTION CITY OF NOME, ALASKA WATER TRANSMISSION LINE STA. 0+00 TO STA. 50+00 CLARK & GROFF ENGINEERS baseas 2 ENOINEERING ARTS BUMDING ont 3276 Commercial, 5. — SALA ORSON 10679 4 1" EXHIBIT 2-2. Drawing 2 2-4 APPENDIX 3.0 GENERAL QB ELECTRIC © Curve nate S Curve Pate ; asset Rs @a8..0 T+ 100.00 Le v8 te Be eas er og 110-72 Pe eseu.a SPECIAL ITEM NS 3 CREEK CROSSING SEE SHEET 7 Soros t wseros se7E 99-26 TRUNGS iene fuer ave _ SF cove "or 4 PPE. eri} eae cu. ve © Core pera Raise ©: 018.08 300.00 Sas 12 Sosika WATER TRANSMISSION LINE PLAN - PROFILE STA 50+00 TD STA 100 +00 " , T . She? CLARK & GROFF ENGINEERS ue BERh cgucTmucTIgN TYPE t ay uk a a j 2 ENGINEERING ARTS BURDING 3276 Commercial $f EXHIBIT 2-3 Drawing 3 2; APPENDIX 3.0 GENERAL Q ELECTRIC & CURVE DaTR as eRy Renter Y00.00) TUN RO TUNDRA Bas.) TUNG S TuNben asc Tenias TRVUNas M+ 00 chee pate 10.14 REDUCER © “oS & NOME TELER RO . & cueve pata ‘90 60 bre 0 \ Beers TaNLiNas FASB Lt 188 8o. De B.2SS26 Aum BLECOER {AO NO. OF POWER POLe To Le Ny NSUST SC ea ey Teonas | ! ABANDONES tasoea ARAMDONED APE Avg BLEEDER, oD ate TRUNGS 20 SO. OF REDUCER 2 Lovenutan Powte, Stow. mow Borto~ oeea ec (aay 38.48 \38s00. CiTY OF NOME , ALASKA WATER TRANSMISSION LINE LAN- PROFILE STA 100+00 TO STA CLARK & GROFF ENGINEERS ENGINEERING ARTS BUILDING 3276 Commarea 5 & SALEM, O8EGON te eee sau Tee? L EXHIBIT 2-4 Drawing 4 2-6 APPENDIX 3.0 GENERAL @@ ELECTRIC = CURVE DATE asatas ts ya8.8y 1+ 60.00 Le Teese Pears tey LABANIONED AR Sj CURVE Dara Gump CONTROL ; rat tbe eee a sett the ee Ty Eee service 10 o BELT? scnoo. SEE SHEET TO te e RUGNNENT BET a! Pr 10+ 88.5 wv. haz} NL GRATE OF CULTRES Reco FRELNE INCTRLLSTION ADJUST UNE 4 GRADE OF CONVERTS AL NEC ESS ORY FOU PIPEGRE JSTALLAT_ON Ravithy Cuveer FIL Ovi ow & MO. OT =i City CF NOME, ALASKA WATER TRANSMISSION LINE |, PLAN: PROFILE STA. 148+00 TO STA 183+4 CLARK & GR ENGINEERING af EXHIBIT 2-5 Drawing 5 APPENDIX 3.0 2-7 GENERA wOTES \ EATEN TO GIST. (OW F OW PAUELS Comteor WW TREATHENT ALANT, PROVIDE 2 OR, WE Mad STEEL FFE wore DLDUPMENT # WR < ¢ wo et seme AUR PUMP Came aleewome Gers seeuee care Te Sises, —_— 2—— APE Te FPR ENT ROTAT ON, Sorte RTL Pant SCALE womIZ 17s 10) eat ise CONTROL MANHOLE WIRING SCHEMATIC No scace BEGIN CONC, ENCOSEMENT ULAED 1O'4 PIPE 2.48 Buen SOW WATER PLANT eRe TO DANTE TAN 3. * FE come. amr avin iNew ND NON NSLME? O77 PPE view scat 2 Me _ETE aRING FOR we For pump 3602 site VOLT SINGLE PHASE FoR WEAT CABLE mo “a case IN SECTION VIEW 2) CONDUIT ENTRANCE DETAIL yo scace SPECIA ram ho / | | FROM STA D+ seeonfemel + ieee — : p f EC VitW TR ? La } 7 “ é . a . | as : : = por . a : : SHEET REPLAL qareo Ww2sed ve | ERA roves HO. p7-1-004¢9 ile I t t CITY OF NOME, ALASKA SPECIAL “ITEM Nt I SNAKE RIVER CROSSING 6 CLARK & GROFF ENGINEERS ENGINEERING ARTS BUNOING 2276 Commercial $ € SAU OREGON EXHIBIT 2-6 Drawing 6 = APPENDIX 3.0 GENERAL GB ELECTRIC com cuw TRANSMISSION LIME ayes we 1G NORTH 16°46'E (DEC 1965) | awe savor WELo To GusseT AT eneuse 1/2 NEOPRENE PAO SNAKE RIVER anaces a 20 centens nam gf ESSER copPLNG KR smic@ 10° BUTTERY VALVES (PLAIN STEM) feermneinaten im talons 2) ane ve ANG ~ s/e'poutsim) > — (existing eninge struoture ——=7 _ es PIPE HANGER DETAIL 10" ey Pass To CITY : . - SCALE 3/4": 1.0) CONNECT TO EXISTING MAIN” SEE OET SHEET 68 wee Lie is THiS VICINITY : c o_O YL . MEW 10" TRANSMISSION LINE INSULATED ena SUPPORTED at 20° CENTERS SEE PIPE MANGER / eRIOGE DECK ' THIS SHEET 6A Ley eZ IO" TRANSMISSION UNE - ———_—_— ase fecin cROssiNg cone vaver ( PLAN VIEW SEE DET SHEET 6B ‘er purterny vaive BRIDGE CROSSING SCALE ("= 10° exists 10 SECTION VIEW | NOTE: THIS SHEE meine SHEET fo {| | [ i fi | CITY OF NOME, ALAS! A RIVER CROSSING DETAILS ot_ BRIDGE CLARK & GROFF ENGINEERS Gm 6 A —— ENGINEERING ARTS BUADING ae 3276 Commercial, 5. SALEM OREGON 1 9 [ome ame [ems [kat _noreo Jose v2vee Re PM LP EXHIBIT 2-7 Drawing 6-A_ 2-5 APPENDIX 3.0 GENERAL Gp ELECTRIC © AY VE ee Ries wer sar? 2, CITY OF NOME, ALASKA VAULT~ DETAILS CLARK & GROFF ENGINEERS GR MOWIEERING ARTS BURDIONG 3276 Commercial, $8 SALEM, ORROON [oer Tore see fone _ [uaraorec [= Ae mam EXHIBIT 2-8 Drawing 6-B 5_,, APPENDIX 3.0 GENERAL @ ELECTRIC SPECIAL ITEM ONE 3 CREEK CROSSING - STA. 54+48 SPECIAL ITEM N°2 SERVICE TO FAA HOUSING STA. 156 + 26.26 SPECIAL ITEM NO. 3 SECTION A-A resto wer € PE ZONE MBTERIAL - REDUCER @ THRUST BLOCK STA. 143450 EDA PROJECT NO. 07-1-00489 CITY OF NOME, ALASKA SPECIAL ITEMS N22 @ NES CLARK & GROFF ENGINEERS _ ENGINEERING ARTS BUKDING * 3276 Commercial. $ 7 aa oassn STs ST ae ee ea EXHIBIT 2-9 Drawing 7 APPENDIX 3.0 > 2-11 GENERAL @ ELECTRIC BERM - TYPE I ROAD CROSSING “ITH TYPICAL TRENCH SECTION ROAD CROSSING WITH PAVEMENT REPLACEMENT GRAVEL REPLACEMENT BERM - TYPE I “ORESSERLOY" BOLTS REQUIRED Tn i coat a wrap. | COAT @ WRAP SARA | Foss ais "Saas a 7a 7 va va CAULK W/BITUMINUS MASTIC 4" WIDE STAINLESS STE: Saeeolnean ri PRIOR TO BANDING EA. SIDE DRESSER COUPLING - STYLE 38 FOR STEEL PIPE 2 am a TYPICAL FIELD weSULATION en I 24GA SLEEVE RIGIO PREFORMED OR FOAMED | GHOOVE FOR eit caster taintace noocaron | ' | a | WALL THICKNESS, SPECIFIED EDA PROJECT WO. 07-!-00489 CITY OF NOME, ALASKA | \ RUBBER GASKET c E Pipe 00 PIPE 1D PIPE 10 SPECIFIED CARNEGIE SHAPE - Nore O-RING JOINT STANDARDS (DIMENSIONS IN INCHES ’ TRENCH, PIPE.@ BERM DETAILS were e O-RING RUBBER GASKET OF MANUFACTURERS D E r 6 wes a Design 10 INSURE EFFECTIVE WATER SEAL, ee GASKETS | SHALL MEET MATERUL. REQUINE MENT, aan Sica ios OF AWWA C-ill-64. SPECIFICATIONS erss 3623032 ‘ - 2274 Conmerval, 3 tain" Sascon eiveriis) TYPICAL FIELD INSULATED JOINT O-RING PIPE JOINT FOR STEEL PIPE © 8 [owe & Jom was [ony sammy ove Ta CLARK & GROFF ENGINEERS — 8 ENGINEERING ARTS BUILDING ae) EXHIBIT 2-10 Drawing 8 ae APPENDIX 3.0 KNOWN SPRING AREAS SHOWN - (@ INDICATES SPRING) DEVELOPMENT OF OTHER SPRINGS FOUND DURING CONSTRUCTION TO BE AT DISCRETION OF ENGINEER SCALE woRIZ "+ vert © BH Ce 19 OF COW. FRE este Fg? wre WY CE we MRICT UCL WYE CONNECTION we EDA PROJECT NO. 07-1-00489 CITY OF NOME, ALASKA aeenien & SOURCE DEVELOPMENT AND SECTION BB i i INTAKE WORKS ) ave comecron —/ . COLLECTOR TERMINUS & SEE ceTan Tas seeer ? F sagen 1K & GROFF ENGINEER . re 0 3 séte OVERFLOW STRUCTURE . eae . 9 PIPE PERFORATION DETAIL SECTION A-A ho Seace lo ee cay JANUARY (968 1 oP EXHIBIT 2-11 Drawing 9 APPENDIX 3.0 2-13 SPRINGS SHARP GROUND CONTOUR CHANGE ANVIL MOUNTAIN 91419313 GB 1vwanay OVERFLOW STRUCTURE COLLECTOR TERMINUS o°¢ XIGNaddv¥ EXHIBIT 2-12 Drain Field Overview @INJ2NYS MO1}Z9BAO E1-Z LIGIHXI GENERAL QQ ELECTRIC WN APPENDIX 3.0 GENERAL Qi ELECTRIC i o is - 5 a a o > ° a < % D ec ‘= a rn + 7 “ = 7 <= x< ta 2-16 APPENDIX 3.0 GENERAL @® ELECTRIC EXHIBIT 2-15 Spring #2 Above Drain Field APPENDIX 3.0 GENERAL Qi ELECTRIC EXHIBIT 2-16 Collector Terminus APPENDIX 3.0 GENERAL @ ELECTRIC SECTION 3.0 Nome Electric Power Generation APPENDIX 3.0 — GENERAL €B ELECTRIC 3.0 NOME ELECTRIC POWER GENERATION CHARACTERISTICS 3.1 POWER GENERATION As displayed in EXHIBIT 3-l "Average Daily KW/H Production by Month", the City of Nome generates approximately 14,000,000 kilo- watt-hours annually. All power was produced by seven (7) diesel generators: 3, Cooper Bessemers at 600 kilowatts each 1, Cooper Bessemer @ 1050 kilowatts Colt-Fairbanks-Morse @ 1250 kilowatts 1, Colt-Fairbanks-Morse @ 1550 kilowatts 1, General Motors @ 300 kilowatts eeeee b si In October of 1979, the City of Nome added a single General Motors 2500 kilowatt diesel unit to its power plant. 3.2 POWER COST In August of 1979, the City of Nome was purchasing diesel fuel at $.8l1 per gallon. During the same period, the City was billing their customers at a rate of $.17 per kilowatt-hour. Of the $.17, $.025 was for capital cost amortization and $.062 was for fuel charges. 3-1 APPENDIX 3.0 GENERAL @ ELECTRIC NOME JOLNTY OTILITY SvsSsTEeEmMs P.O.BOX70 * NOME, ALASKA 99762 TELEPHONE (907) 443-5242 AVERAGE DAILY KW/H PRODUCTION BY MONTH MONTH & YEAR November 1978 December 1978 January 1979 February 1979 March 1979 April 1979 May 1979 June 1979 July 1979 August 1979 September 1979 October 1979 KW/H 44,322 32,560 44,018 45,232 42,415 40,860 37,589 32,338 32,560 34,184 36,005 39,821 EXHIBIT 3-1 Average Daily KW-H Production By Month APPENDIX 3.0 GENERAL @@ ELECTRIC SECTION 4.0 Hydroelectric Power Potential APPENDIX 3.0 GENERAL QQ ELECTRIC 4.0 HYDROELECTRIC POWER POTENTIAL For a volume of water passing through turbines under a constant head, the energy delivered is: Kilowatts = gq (H-h)e Equation (4.1) aS where q = Water flow in cubic feet per second H = Gross head, in feet h = System head losses e = Station efficiency, expressed as a fraction Assuming efficiencies of 91% for turbines, and 95% for genera- tors (including excitation and station use), the cumulative overall plant efficiency can be taken as e = .86. In addition, let it be assumed that system head losses are 15% of the gross head. (During our August Nome visit, Mr. A. Edge (Nome Utility Manager), stated that the cost associated with the design and installation of a new penstock was not to be considered since such cost would be assessed to expanding municipal water supply capabilities. Hence, for this level of effort, system conduit losses can only be assumed). Sub- stituting efficiencies, equation (4.1) can be re-written as follows: Generator Output in Kilowatts q_ (.85H) (.386) Equation (4.2) 11.3 qH(.06) In the application of Equation (4.2), tailrace water elevations were assumed to be the same as that of Nome's Harbour - "0" feet at APPENDIX 3.0 GENERAL QQ ELECTRIC elevation. Further, a reaction turbine was viewed as the most likely turbine application type. Using Equation (4.2), EXHIBIT 4-1 "Generator Output" was con- structed. These values serve aS a guide to determine power potential of the Moonlight Springs area under various hydrologic and topo- graphic conditions. It should be noted that to achieve values shown in EXHIBIT 4-1, a new drain must be developed, a penstock installed and turbine foundations constructed. ae APPENDIX 3.0 o°€ XIGNAddv GENERATOR OUTPUT IN KILOWATTS ELEVATION IN FEET 130 39 78 EXHIBIT 4-1 Generator Output 91419313 GB 1vuaNad GENERAL €@ ELECTRIC SECTION 5.0 Field Investigations we APPENDIX 3.0 GENERAL @@ ELECTRIC 5.0 FIELD INVESTIGATIONS In the fall of 1979, four (4) bore holes were placed to evaluate water resources of the formation that encompasses Moonlight Springs. Bore holes were located above Moonlight Springs on the side-of Anvil Mountain at an approximate elevation of 170 feet above mean sea level. Discussion of the geotechnical aspects of the region, drilling pro- gram and results are presented in the following portions of this sec- tion. Del GEOLOGY the coastal plain at Nome is covered with glacial and marine sand and gravel of Pliocene and Pleistocene age. Geologic studies by Hopkins (1967) have defined four main marine units which appear as linaments inland from Norton Sound and parallel to the shoreline which are locally referred to as Submarine Beach, Second Beach, Third Beach, and Fourth Beach. Subsequent exploratory drilling by United States Smelting, Refining, and Mining Co., the U.S. Bureau of Mines, and Shell Oil Co., and offshore seismic-reflection profiles by A.R. Tagg and A.G. Greene (1970) have defined other onshore and offshore beach deposits as displayed in EXHIBIT 5-1 "Investigation Area" and EXHIBIT 5-2 "Geologic Cross Section A-A." Pliocene Beach and Submarine Beach are covered by glacial drift of the Iron Creek (pre-Illinoian) glaciation; Intermediate Beach, Monroeville Beach, Third Beach, and Fourth Beach were deposited during the Iron Creek glaciation and subsequently covered by the Nome River (Illinoian) glaciation. The Modern Beach and Second Beach overlie the Illinoian glacial and, in turn, are overlain by alluvium, colluvium, outwash, and aerolian silt that accumulated during Wis- consin and Holocene time. Beneath the coastal plain sediments and cropping out at Anvil Mountain is Paleozoic limestone and schist bedrock first described by Collier et al. (1908). APPENDIX 3.0 GENERAL Q ELECTRIC Alluvial deposits, primarily gravels, are found along Anvil Creek where it cut its present channel into the Paleozoic schist and limestone valley floor west of Anvil Peak. These gravels also form a low bench, not over 15 to 20 feet high in most places, along the east side of the valley and extend upward into Specimen Gulch. Anvil Creek gravels consist chiefly of material like the rocks of the sur- rounding hills, and are probably derived to a large extent from sources within the drainage basin. However, rounded granite boulders are interspersed in these surficial deposits and are not entirely of local origin. This bench does not appear at the west side of the valley where the creek flows close to the rather steeply rising west- ern slope. Cooper Gulch, a very small valley east of Anvil Peak, is cut in the Paleozoic bedrock with very little surficial deposits. A small alluvial fan has formed at the mouth of the canyon where it opens on- to the tundra. De) PREVIOUS INVESTIGATIONS Following the gold rush at Nome between 1898 and 1900, the U.S. Geological Survey conducted early geological investigations of the area (Brooks et al., 1901; Collier et al., 1908; Moffit, 1913). More recent studies of the Nome coastal plain were undertaken by the United States Smelting, Refining, and Mining Co.; the U.S. Geological Survey-MacNeil et al. (1943); Hopkins et al (1960); Hummel (1962); Greene (1970); and Nelson and Hopkins (1972). a3 GEOLOGICAL RECONNAISSANCE A geological reconnaissance of the Moonlight Springs area was conducted prior to initiating the drilling. Bedrock outcrops ex- posed north of the springs on Anvil Mountain have been described in previous reports and can be divided into two metamorphic rock types: limestone (marble?) and schist. The limestone is principally platy with some slabby and massive exposures. Blue-gray to gray on a 372 APPENDIX 3.0 GENERAL €@ ELECTRIC freshly exposed surface, the limestone weathers to a buff color. The contact between the limestone and the schist meanders in a north- easterly direction across Anvil Mountain and the drilling program suggests that this trend continues beneath the unconsolidated mate- rial to the southeast. The contact itself is gradational with a gray schistose marble being an intermediate rock type. The schist is pre- dominantly gray weathering to a light gray. Slightly graphitic in the study area, the calcareous quartz schist contains minor units, including blue-gray, gray, and black marble, and black quartz schist. Both the marble and schist are early to middle Paleozoic in age. Unconsolidated deposits overlie the bedrock along Anvil Creek and at the mouth of Cooper Gulch. These alluvial ceposits consis of weathered bedrock, primarily limestone and schist. The low ter- race north and northwest of Moonlight Springs on which the four test holes were drilled is composed of elluvium (atmospheric accumulations of rocks in situ as opposed to alluvium which requires the action of the water for deposition). South of Moonlight Springs, unconsoli- dated deposits have been reworked by gold dreding operations. 5.4 DRILLING PROGRAM Four test holes were drilled and logged as part of the Nome groundwater resource investigation. A local drilling contractor, Mr. Jim Thrasher, was awarded the drilling subcontract by the City of Nome. A track-mounted Chicago-Pneumatic air-rotary rig owned by the Alaskan Gold Company drilled all four test holes. The drill crew consisted of a driller and one to two helpers. Test hole completion material (i.e., steel or PVC casing) and pump test equipment (i.e., submersible pump with wire and control box, flow meters, pressure gage, shut-off valve, etc.) was supplied by Mr. Leo Schachle with Western States Associates, Inc., located in Anchorage, Alaska. Pump test equipment was returned to Mr. Schachle unused because a groundwater body large enough to test was not loca- ted by the test holes. 5-3 APPENDIX 3.0 GENERAL €@ ELECTRIC Lithologic logs of the four test holes were constructed by ex- amining the bore hole cuttings. The locations of these holes are shown in EXHIBIT 5-3 "Locations of Test Holes" while the logs are displayed graphically in EXHIBIT 5-4 "Lithologic Logs of Test Holes," and are as follows: TEST HOLE #1 Start date: Finish date: Total depth: Bedrock depth: Barey (Gs) ss Surface elevation: Depth to water: Depth (feet) OS HOr.0 Sie Oreo 10 2) Oy eel Aree Saturday, October 20, 1979, 2:00 PM Saturday, October 20, 1979, 5:30 PM 35.0 feet 27.0 feet 4 3/4-inch insert approximately +170 feet MSL 14.5 feet or +155.5 feet MSL Lithologic description and drilling notes Yellow-gray-brown calcareous clay with some weathered, platy, limestone fragments; num- erous plant roots and organic material in cChemcoprZureec yt rastvaral) ings Dark gray to black calcareous quartz schist; highly weathered, friable, platy fragments in a brown clay matrix; harder than overlying clay; moderately fast drilling. Dark gray to black micaceous schist fragments with red-brown hematite staining, brown clay; minor amount of coarse, subangular quartz grains embedded in the clay matrix; soft rocks; fast drilling with the exception of a harder layer from 13.5 to 14.0 feet. Water was first detected at 14.5 feet. 5-4 APPENDIX 3.0 GENERAL QQ ELECTRIC Depth (feet) are IIe Bteo) AL StS M27 aa) 27/10) =| 3 5)e1O TEST HOLE #2 Start date: Finish date: Total depth: Bedrock depth: Bit(s): Surface elevation: Depth to water: Lithologic description and drilling notes Yellow=-brown limestone; subrounded to suban- gular fragments coming up with yellow-brown muddy groundwater. Yellow-brown calcareous mud; subrounded yel- low-brown limestone fragments; subrounded dary-gray schist fragments (schist fragments collected at depths of 24 and 26 feet appear to be part of an ancient beach deposit, pos- sibly Fourth Beach (see Figure 1-2); marked increase in groundwater circulated to the surface was noted at 20.3 feet. Subangular dark gray calcareous schist with some red-brown hematite staining; marked in- crease in hardness; drilling rate reduced to 3 feet/hour; drilling characteristics suggest test hole terminated in a fractured schist. Sunday, October 21, 1979, 1:55 PM Sunday, October 21, 1979, 5:40 PM 29.0 feet 22.0 feet 4 3/4-inch insert with extensions welded to bit to cut 6-inch hole, 4 3/4-inch tricone rock||bie approximately +164 feet MSL 20.0 feet or +144 feet MSL 5-5 APPENDIX 3.0 GENERAL GB ELECTRIC Depth (feet) 0 - 4.2 a2 -— 0.5 Go 5=S=)5) O=0S—= 10-0 L050 ===14 5) 14.5 - 22.0 Lithologic description and drilling notes Yellow-brown calcareous clay; soft, fast drilling with some roots and organic material near the surface. Gray-brown, highly weathered schist frag- ments; brown clay with some fine gravel-sized subangular rock fragments. Gray to dark gray platy calcareous schist fragments; weathered with red-brown hematite staining; fine-grained cuttings; gray-brown clay matrix. Very fine-grained cuttings; gray-brown weath- ered schist, light metallic gray graphic schist fragments. Yellow-brown medium- to fine-grained cuttings consisting of approximately 20 percent fine, multicolored black, brown, and white sand grains; 80 percent yellow-brown clay. Medium- to fine-grained quartz sand ina yellow-brown clay matrix; color change to light gray-brown with some coarse sand grains at 18 feet; cuttings are dry to 20.0 feet where they became damp (drilling rate slow at 22.0 feet, lost three inserts on bit, changed to tricone rock bit). 5-6 APPENDIX 3.0 GENERAL €@ ELECTRIC Depth (feet) 22h5 0) 1929710) TEST HOLE #3 Start date: Finish date: Total depth: Bedrock depth: Bit(s): Surface elevation: Depth to water: Depth (feet) 0 =) E20 Op Leds TUS (OSH abifcr} Lithologic description and drilling notes Light yellow-brown, medium- to fine-grained sandy limestone (marble?); medium hard; slow drilling; no water circulated up with cut- tings; next day water was standing in hole at 20-foot level. from 28- to 29-foot section. Drilling rate 2 feet/hour 11:15 AM 11:40 AM Monday, October 22, Monday, October 22, 17.5 feet ll feet 4 3/4-inch insert; HOOT, 1979, 4 3/4-inch tricone rock bit approximately + 160 feet MSL dry test hole Lithologic description and drilling notes Yellow-brown calcareous clay with roots and organic material. calcareous weathered Light gray, platy, schist fragment; some subangular schist frag- ments encountered at 4.5 feet; soft, yellow-brown clay matrix; fast drilling rate. Light gray-white limestone (marble?); suban- gular, medium hard drilling. Change from in- sert bit to tricone rock bit at 14 feet. Cutting dry to 17.5 feet. nated at 17.5 feet because prospects of Drilling termi- finding water appeared to be slight. APPENDIX 3.0 GENERAL GB ELECTRIC TEST HOLE #4 Start date: Tuesday, October 23, 1979, 12:30 PM Finish date: Tuesday, October 23, 1979, 2:10 PM Total depth: 15.0 feet Bedrock depth: 7.5 feet Bit(s): 4 3/4-inch insert Surface elevation: approximately +158 feet MSL Depth to water: dry test hole Depth (feet) Lithologic description and drilling notes 0-1.7 Dark brown, moist clay with roots and organic material. Lat = 7.5 Light brown to gray-brown calcareous schist fragments; dry, minor amount of clay. 7.5 ~- 15.0 Gray, calcareous schist fragments, platy to subangular dry cutting. Drilling terminated at 15.0 feet because prospect of finding water was considered slight. ur . ow PRECIPITATION DATA Total precipitation in the form of rain and snow is a vital part of the hydrologic cycle and determines the amount of surface flows and groundwater recharge for a given drainage basin. Total precipi- tation measurements are compiled on a monthly basis at the Nome, Alaska airport under the direction of the National Oceanic and Atmo- spheric Administration. Normal precipitation for Nome is 16.44 inches per year with snowfall accounting for about 4.5 inches of moisture or 54.5 inches of snow. The last 6 years on record for the City are presented as follows: 5-8 APPENDIX 3.0 GENERAL @ ELECTRIC PRECIPITATION DATA FOR NOME, ALASKA Precipitation period Total precipitation (inches) October 1973 to September 1974 aA o 5) October 1974 to September 1975 12.64 October 1975 to September 1976 8.53 October 1976 to September 1977 L3.a October 1977 to September 1978 16.88 October 1978 to September 1979 19.82 5-16 ANVIL CREEK DRAINAGE BASIN Anvil Creek drainage basin includes approximately 5.3 square miles extending northeast between Banner Peak and Anvil Mountain to King mountain above Moonlight Springs. Nekula, Specimen, Little Specimen, and New Year Gulches are part of the basin and provide water to Anvil Creek after precipitation events. Anvil Creek is reported to be a perennial stream flowing southwest into the Snake River and from there into Norton Sound. During the winter when mois- ture is locked up in snow, the creek flow decreases and is channeled under a layer of sheet ice which forms across the creek bed. Streamflow measurements are not available for Anvil Creek. Very rough approximations of streamflow can be made by estimating the amount of rainfall or snow fall that becomes surface runoff. Over the United States as a whole, about 33 percent of the rainfall be- comes runoff, although this figure varies in different parts of the country. In the Nome area, surface runoff is expected to be higher than the national average for the following reasons: 1. permeability of the ground would be reduced by freezing much of the year =O APPENDIX 3.0 GENERAL GQ ELECTRIC 2. tundra vegetation is low and relatively sparse, reducing interception of rainfall and evapotransipiration 3. concentration of rainfall during the summer months would keep the ground saturated and increase runoff 4. approximately one-third of the annual precipitation is locked up in the winter snow which is thawed by spring rains and becomes runoff. If we assume that 65 percent of the rainfall becomes surface runoff, then approximately 10.7 inches of water will flow from the drainage basin into Anvil Creek for the average precipitation year. This is equivalent to about 3,000 acre-feet of water per year (an acre-foot of water equals the amount of water required to cover 1 acre to a depth of 1 foot) or a flow rate of about 4.1 cubic feet per second (cfs) for 1 year. The actual discharge of Anvil Creek would be considerably higher during the spring and early summer and less during the fall and winter months. The other 35 percent of the rain- fall would supply plant needs and infiltrate into the groundwater system. This would be approximately equal to a flow rate of 2.2 cfs annually. The actual groundwater flow would again to a function of the seasonal temperature and precipitation with the variation in flows (high to low) smaller in relationship to the surface water. Using the above assumptions to define rainfall to runoff relation- ships and the precipitation data for the last 6 years, we could expect a minimum annual flow rate of about 2.4 cfs for the period of October 1975 to September, 1976, and a maximum annual flow rate of about 5.0 cfs for the period October, 1978 to September, 1979 in Anvil Creek. As indicated above, these flow rates are very rough approximations but are useful in pre-feasibility analysis of the water resources available in Anvil Creek. Moonlight Springs is located in the Anvil Creek drainage basin near the base of Anvil Mountain. It has been the source of potable water for the City of Nome since the turn of the century. Controlled 5-10 APPENDIX 3.0 GENERAL @B ELECTRIC by the Alaskan Gold Company, then the Welsh brothers, it is now owned by the City. In 1968 a drain field was developed below the major springs to collect water which is fed by gravity through a 10-inch pipe to the City's water treatment plant. Here the water is pumped to about 60 percent of the homes in the City. The drain field is con- structed with a 2l-inch overflow pipe which empties into a nearby pond. One large spring (estimated discharge in October 1979 of about 2 cfs) and several small seeps which are part of the series of water sources which make up Moonlight Springs, are not being captured by the drain field and flow down onto a floodplain and eventually into Little Creek. Periodically, these waters are captured in a small dam and pumped to a gold mining operation run by Mr. Carl Glavinovich. Records of the flow of water through the drain field have not been kept. During the October 1979 field study, the flow from Moon- light Springs was estimated as follows: 1 cfs was being used by the City, 5 cfs was being discharged through the overflow pipe, and about 2.5 cfs was flowing from nearby springs and seeps, for a total of 8.5 cfs. Observations of total discharge from the springs during mid- summer 1979 are somewhat higher, in the order of 10 to 15 cfs, mainly occurring as increased discharge from nearby springs and seeps. The primary source of water for Moonlight Springs is unknown. Mr. C.H. Hummel, USGS Alaskan Branch Geologist, has speculated a pos- sible structural connection between the Nome River and the springs based on the surface geology (oral communication, October 1979). How- ever, discussions with several residents of Nome regarding the histor- ic discharge from the springs (particularly the short potable water supply during 1975-1976) suggests a smaller, more localized source. Test Hole #1, drilled north of the principal spring discharge, iden- tified a highly permeable beach-type channel deposit that is trans- mitting water to the springs. The channel was very narrow for a second test hole 100 feet to the northwest had low permeability and no beach-type deposits. Test holes #3 and #4 were drilled north and northwest of a spring flowing about 2 cfs in order to determine the location of the source supplying water to that area. Both holes went 5-11 APPENDIX 3.0 GENERAL QB ELECTRIC into bedrock at a shallow depth and were completely dry. These data suggest that the sources of water to Moonlight Springs are narrow, sinuous, permeable channels lying on bedrock that are recharged in the local Anvil Creek drainage basin. This is consistent with the rough recharge estimates and does not require additional quantities of groundwater supplied from outside sources to meet the Nome resi- dents' recollection of the historic flow from Moonlight Springs. Sut COOPER GULCH DRAINAGE BASIN Cooper Gulch is a small drainage basin (360 acres) east of Moon- light Springs. An ephemeral stream (a stream or portion of a stream which flows only in direct response to precipitation) flows to the southwest over a small alluvial fan deposit which has formed at the mouth of the gulch. Utilizing the same assumptions as for Anvil Creek drainage basin, the surface water flows and groundwater recharge pot- ential from the gulch would be about 0.44 cfs and 0.20 cfs annually for the average precipitation year respectively. The natural runoff is supplemented by water from the remains of Miocene Ditch, which cir- cles around Anvil Mountain collecting runoff from the south- and west- facing slopes. If a permeable channel provided communication between the mouth of the gulch and the springs, some of the recharged ground- water would appear as discharge at the springs. 5-12 APPENDIX 3.0 GENERAL QB ELECTRIC Rea Moonlight Spri “yer sesy Ss ae - e Geologic Cross Section A-Al EXHIBIT 5-1 Investigation Area 5-13 APPENDIX 3.0 o°€ XIGNaddv Tet=sS TEST HOLE NO. e ES ANVIL MOU! aa 4 4 INTAIN 134", 2 eee TEST HOLE NO.3 e @ TEST HOLE NO. 2 > Secu HOLE NO.1 \ \YA MOONLIGHT SPRINGS i I 0 01 02 O03 O4 a eo ROAD CLASSIFICATION wes MEDIUM DUTY -- LIGHT DUTY <== = UNIMPROVED DIRT O.5 MILES NORTH EXHIBIT 5-3 Location of Test Holes 91419313 GB 1vuaNg9 O°€ XIGNAddv Ref.: EXHIBIT 5-1 Investigation oy) 7-65 to —72 ft beach Modern Beach Ye Second Beach ag} beach le [' Vv Alluvium of Wisconsin age il [e} fel Drift of Mlinoian ; Glactation Beach Marine silt | sediments and clay DEPTH IN METERS DEPTH IN FEET ST-S 25 mites , 2 SRNOMETERS Older glacial a drift HORIZONTAL SCALE [=] Stratified sedimentary rocks of unknown character (1474 Schist EXHIBIT 5-2 Geologic Cross Section QUATERNARY TERTIARY WE PALEOZOIC C Anvil Peak CENOZOIC 91H19313 GB 1VuaNad GENERAL QB ELECTRIC +170 MSL 169 168 167 166 165 164 163 162 161 160 159 158 157 156 155 154 153 152 151 150 149 148 147 146 145 144 143 142 141 140 139 138 137 136 135 MSL TEST HOLE NUMBER 4 dark brown moist clay with small roots a XS ae 2 3 4 5 6 7 8 9 3 KJ iN rh UV light gray-brown calcareous schist fragments with minor amounts of clay gray calcareous schist uy 26 a pp wo TEST HOLE NUMBER 3 yellow-brown calcareous A ’« cla EN ‘ SS light gray, platy calcareous weathered schist fragments light gray-white limestone (marble?) 1 ©onvNOanr wh NOOO BON = 0 TEST HOLE NUMBER 2 yellow-brown calcareous clay, t™ h 7 soft, organic material near surface gray-brown weathered schist in clay matrix with small angular gravel fragments grey schist with small red- brown hematite staining fine-grained schist multi- colored medium- to fine- grained sand in yellow-brown clay matrix medium-fine grained quartz sand light gray-brown clay matrix to 22 feet. —WATER LEVEL— yellow-brown medium- to fine-grained sandy lime- stone (marble?) © orn An FAWN TEST HOLE NUMBER 1 yellow brown, calcareous clay with small platy lime- stone fragments organic material in top 2 feet dark gray calcareous quartz schist in brown clay matrix —WATER LEVEL— yellow brown limestone (marble?) in clay matrix mixed limestone, and schist fragments subrounded; may be ancient beach deposit dark gray calcareous schist, bedrock weathered and fractured from 27 to 30 feet ©M7 NOOO BWwHN wo wo w | 25) 9) NNRYNNNNKR ZEA 2 ee eese SS SS SRSSRBVSRBRSENVRRGGAYTFAARGA 3 +170 MSL 169 168 167 166 165 164 163 162 161 160 159 158 157 156 155 154 153 152 151 150 149 148 147 146 145 144 143 142 141 140 139 138 137 136 135 MSL EXHIBIT 5-4 Lithologic Logs of Test Holes APPENDIX 3.0 5- 16 GENERAL @@ ELECTRIC SECTION 6.0 Summary and Conclusion APPENDIX 3.0 GENERAL @@ ELECTRIC 6.0 SUMMARY AND CONCLUSIONS A reconnaissance study of water resources from the Moonlight Springs area was performed in October 1979 by General Electric Com- pany's Projects Engineering Operation with assistance from General Electric-TEMPO. Surface water flows were estimated for the Anvil Creek and Cooper Gulch drainage basins based on assumed rainfall- runoff relationships. Potential groundwater recharge estimates were made for the Moonlight Springs area. Four test holes were drilled to help define the source of water for the springs and to perform an aquifer test. Insufficient groundwater was found;therefore, a pumping test was not performed. It is estimated that the Anvil Creek and Cooper Gulch drainage basins would produce a total average annual flow of slightly less than 7 cfs. Actual streamflow hydrographs are not available, but the flow would not be uniform and are expected to be very high in the late spring and early summer and low in winter, Results indicate that Moonlight Springs water resources are insufficient for hydroelectric development. Maximum average annual generator output would be less than 50 kilowatts. Purthermore, extensive civil works would be required such as a drain field re- development, penstock construction and turbine foundations installation. 6-1 APPENDIX 3.0 GENERAL @® ELECTRIC SECTION 7.0 Acknowledgments APPENDIX 3.0 GENERAL @@ ELECTRIC 7.0 ACKNOWLEDGEMENTS Several individuals have assisted in the data gathering for this report. In particular, Mr. C.L. Hummel of the U.S. Geological Survey has been especially helpful in providing aerial photographs, maps, and his personal knowledge of the local geology. Mr. Carl Glavinovich, retired manager of the Alaskan Gold Company, generously offered an account of mining activities in the study area and comments on the local groundwater system and historic flow characteristics from Moon- light Springs. Sincere thanks is extended to Mr. Andy Edge, Nome City Manager, for his extensive support of the field work. 7-1 APPENDIX 3.0 GENERAL @@ ELECTRIC SECTION 8.0 References APPENDIX 3.0 GENERAL QD ELECTRIC 8.0 REFERENCES Brooks, A.H., G.B. Richardson, and A.J. Collier, Reconnaissance in the Cape Nome and Norton Bay Regions, Alaska, in 1900, U.S. Geolo- gical Survey (special publication), 1901. Brown, Luther P. and Whippen, Warren E., Hydraulic Turbines, Inter- national Textbook Company, Scranton, Pennsylvania, 1972. Chow, Vera T., Handbook of Hydrology, McGraw-Hill, New York, WY, 1969. Collier, A.J., F.L. Hess, P.S. Smith, and A.H. Brooks, The Gold Placers of Parts of Sewara Peninsula, Alaska, Including the Nome, Council, Kougarok, Port Clarence, and Goodhope Precincts, U.S. Geological Survey Bulletin 328, 1908. Davis, Calvin V. and Sonensen K.E., Handbook of Hydraulics, McGraw- Hill, New York, NY, 1969. Gancharov, A.N., Hydropower Stations Generating Equipment and Its In- Stallation, National Technical Information Service, Springfield, Vir- ginia, 1975. Greene, H.G., A Portable Refraction Seismograph Survey of Gold Placer Areas near Nome, Alaska, U.S. Geological Survey Bulletin 1312-B, 1970. Henshaw, F.F. and Parker, G.L., Surface Water Supply of Seward Penin- sula, Alaska, U.S. Geological Survey Water Supply Paper 314, 1913. Hopkins, D.M., F.S. MacNeil, and E.B. Leopold, "The Coastal Plain at Nome, Alaska-A Late Cenzoic Type Section for the Bering Strait Region," International Geological Congress, Copenhagen, pp 46-57, 1960. 8-1 APPENDIX 3.0 i GENERAL &B ELECTRIC Hammel, C.H., Preliminary Geologic Map of the Nome D-l Quadrangle, Seward Peninsula, Alaska, U.S. Geological Survey Mineral Investiga- tions Field Studies Map MF-248, scale 1:63,360, 1962. MacNeil, F.S., J.B. Mertie, Jr., and H.A. Philsby, "Marine Inverte- brate Faunas of the Buried Beaches near Nome, Alaska", Journal of Paleontology, 1943. Moffit, F.H., Geology of the Nome and Grand Central Quadrangles, Alaska, U.S. Geological Survey Bulletin 533, 1913. Nelson, C.H., and D.M. Hopkins, Concentration of Particulate Gold in Sediments of the Northern Bering Sea, U.S. Geological Survey Paper 689, 1972. 8-2 APPENDIX 3.0 GENERAL @ ELECTRIC 4.0 NOME REGION COAL RESERVES 4.1 COAL AND IRON ORE DEPOSITS About 25 miles northwest of Nome, a region containing surface coal outcrops is located. The field shown in Exhibit 4.1-1, "Nome Area Coal Field", is bisected by the Sinuk River and is accessible via the Nome-Teller Road. Several coal outcrops are visible and at least two of them shows signs of being mined. The quality of coal as well as its quantity (subsurface configuration) is unknown. In the same general vicinity of the coal field shown in Exhibit 4.1-1, are iron ore deposits known as the Monarch Iron Ore Deposit. The deposit is composed of various grades of iron ore with the main ore body high grade Hematite of Iron (Fe,03) whose quantity is esti- mated at approximately thirty million tons with the detrimentals almost nil. To the south of - and joining - this main ore body is a much larger deposit of ore with a lime content which makes it almost a self fluxing ore. To the north of and joining the high grade ore is a deposit of ore composed of Black Oxide of Manganese, Calcite and a small amount of Iron, almost the proper combination to pro- duce Ferromanganese. Ore deposits have not been developed, 4-1 COAL FIELD SURFACE BOUNDARY i } Ke y, AO i eg84 if SINUK RIVER W e < D2 Cape mech Ove Le Sue Cripple S Creek 205 e i “Sec ae cat (glans 2 a Be zt ELEVATIONS IN FEET Exhibit 4.1-1 Nome Area Coal Field 91819313 GB 1vuaNas GENERAL @@ ELECTRIC 4.2 COAL FIRED ELECTRIC GENERATING SYSTEMS The smallest coal fired electric generating system that this office is aware of is a 20 megawatt unit located in Wellington, Kan- sas. It is recognized that technology and equipment definition pre- sently exist for design and installation of coal fired systems for Nome. The design, however, would be a "first of its kind". Further- more, its personnel operating requirements would be nearly the same as that of 20 to 80 megawatt systems. To estimate coal requirements for a small coal fired electric generating system, system efficiency and coal quality are needed. This information has not been developed. However, as a "rule of thumb", one pound of coal will produce approximately 1 kilowatt hour of electric power. GENERAL G@ ELECTRIC 4.3 COAL UTILIZATION COMMENTS The Alaska Power Authority is presently investigating means of converting coal and wood into a gas for use in small electric power generation systems suitable for Nome. Until these activities mature into, or pass, prototype stages - there does not appear to be a system to produce electric power outputs of 3 to 5 megawatts. The most likely use of Nome region coal resources is for home heating. The Nome-Teller Road was installed within the last ten years. Until its construction, there was no dependable transportation route from the coal fields to Nome or Teller. The road, however, is closed during the winter. Therefore, the coal could be mined and transported only during the summer. To access coal production cost at the Sinuk River Site, let it be assumed that such cost would be similar to those of the Usibelli Coal Mines, Inc., located in Healy, Alaska. Usibelli cost averages $15 per ton. The $15 per ton value includes all production costs including railroad car loading. Transporation and delivery expenses are not included in the $15 figure. GENERAL @ ELECTRIC 5.0 WIND TURBINE GENERATOR EVALUATION 5.1 INTRODUCTION The objective of this work was to consider wind power from the perspective of the Nome Joint Utility System and to evaluate its potential for becoming a viable adjunct to conventional diesel generators. Utility ownership and control of WIG facilities was assumed in the economic evalu- ation. The evaluation approach used in this work was re- cently developed by General Electric's Electric Utility Systems Engineering Department as part of Electric Power Research Institute (EPRI) Research Project 740-1, "Require- ments Assessment of Wind Power Plants in Electric Utility Systems" (Reference 1). The primary objective of EPRI Research Project - 740 was to develop a methodology suitable for use by individual electric utilities to assess prospects for wind generation in their respective service areas. As part of the RP-740 analysis, the methodology was exercised in several real utility systems to estimate energy and capacity values of wind generation. The utility specific results, demonstrated that the energy value of wind power plants is greatest in utilities having both favorable winds and substantial amounts of oil-fired generation. Wind turbine generator applications in the Nome region satisfy the above criteria. 5.2 APPROACH The evaluation approach is based on established utility planning methods using analytic tools accessible to the utility industry. A wind plant performance model utilizes actual wind data and WIG performance characteristics to simulate hour-by-hour WTG operations over a one year time GENERAL GB ELECTRIC period. The wind plant performance model output is WTG net electric output which is subsequently used in an hour-by- hour utility simulation. By making two utility simulation runs (the first with some wind capacity and the second with no wind capacity) and comparing results, it is possible to determine annual operating cost savings brought about by the WTG power output. The wind turbine generator evaluation approach used in this study is the same as that used in EPRI Research Pro- ject - 740 with the exception that WIG economic viability in Nome was evaluated only in terms of energy value (fuel savings). Throughout the Nome analysis, we have assumed that the WTG's have no capacity value; i.e., they are used solely as fuel savers. The addition of wind capacity to the Nome Joint Utility System is assumed to have no impact on installed diesel generating capacity. Practical acceptance of some capacity credit, in the future, will require actual operating experience on the Nome utility system. The six tasks which comprise the wind turbine generator evaluation approach are identified below and described in more detail in the remainder of this subsection. Selection of Hourly Wind Data Selection of Candidate Wind Turbine Generators WIG Performance Simulation o 0 0 0 Nome Utility System Operation Simulation - Without Wind Turbine Generators - With Wind Turbine Generators Economic Evaluation Sensitivity Analysis Selection of Hourly Wind Data The first task in the WIG evaluation is selection of one or more years of wind data to be used in Task 2 to 5-2 GENERAL GB ELECTRIC determine hour-by-hour electric output of the wind plant. Hourly wind data for a 15 year time period (1951-1964) was obtained from the National Climatic Center (NCC) in Ashe- ville, North Carolina. The data was collected at the Nome weather station located at Nome Field, approximately one mile northwest of the city. The reason for selecting wind data for the 1951-64 time period is that the more recent, post-1964 data is based on observations at three-hour inter- vals. The 15 years of hourly wind data which was used is assumed sufficient to achieve a reliable evaluation of wind power generation for the Nome Field site. How representa- tive this wind data is for other sites near Nome should be investigated in the future. The average annual wind speeds (mph) for the 15 year time period are shown in Exhibit 5.2-1. Note that the average wind speeds are shown both at wind instrument eleva- tion and corrected to the present elevation of 21 feet. The source data obtained from Bud Krepky at the Nome weather station was collected by wind instruments located at eleva- tions which varied from 32' to 70' during the 1951-64 time period. As shown in Exhibit 5.2-1, the average wind speed over the 1951-64 time period is 9.4 mph (at 21 feet). This is less than the 10.8 mph average for the 1941-1970 time period; however, the 10.8 mph average does not reflect adjustments for wind instrumentation elevation changes during the time period. Since August, 1966, wind instru- ments have been located at an elevation of 21 feet. The average annual wind speeds for the 1967-78 time period are also shown in Exhibit 5.2-1. As shown, the average wind speed over the 1967-78 time period is 10.2 mph, slightly greater than the 9.4 mph value for the 1951-64 time period. Based on the wind data in Exhibit 5.2-1, the year 1958 was selected as a typical wind year. The average wind speed for 1958 is close to the average for the 1951-64 time peri- GENERAL @@ ELECTRIC Average Annual Ave. Annual Wind Speed (mph) Wind Speed, @ See Note 1 @ 21' Year mph @ 21' le re 8. on 10. oF aKole 10. et als aa 2 2 2% 1967 10. 68 8. 69 LOR 70 10% 71 LON. 72 LOR a3 OF 74 75 76 77 78 VIN DOWNIYRPWUOIDOe OWDWNWODWVHBICYHO UANOUBRUORPRPOADWA DUBDUAHOPUMUUE Average Wind instrument elevation: 53 feet 12/4/50 to 7/26/57, 32 feet 7/26/57 to 8/13/58, 70 feet 8/13/58 to 8/13/66, 21 feet 8/13/66 to present. 1951-1964 wind speeds at wind instrument elevation corrected to 21 feet elevation using an assumed 1/7 wind shear exponent. Exhibit 5.2-1 Average Annual Wind Speeds at the Nome Weather Station GENERAL @@ ELECTRIC od. To assess the impact of annual variations in wind energy, years 1953 and 1963 were selected as low and high wind years, respectively. Most of the WIG evaluation work will be performed using the 1958 hourly wind data. During the sensitivity analysis, the 1953 and 1963 wind data will be used to assess the impact on WTG value. Selection of Candidate Wind Turbine Generators As part of previous and ongoing wind power research projects funded by EPRI and DOE, EUSED has evaluated the performance of numerous wind turbine generator designs, ranging in size from 2 kW to 2000 kW. The larger machines, 1500-2000 kW, appear to be the most cost effective for many utility applications; however, it was decided to select smaller (200 kW and less) wind turbine generators for the Nome study. The smaller WIG's seem appropriate in light of anticipated installed diesel capacity and operational con- siderations. With minimum loads in 1990 of 2000 kW, more than one 2000 kW WIG could result in significant amounts of non-marketable output power. Future analyses should assess the impact of wind machines on dynamic stability to deter- mine potential limits on WTG size and penetration in the Nome Joint Utility system. It is anticipated that voltage fluctuation associated with wind gusting would be less severe with multiple 200 kW units compared to a single 2000 kW unit. Two wind turbine generators were selected for consider- ation in this study: a 200 kW horizontal axis/two blade machine and a 2 kW horizontal axis/three blade machine. Both wind turbine generators are representative of machines currently operational as part of ongoing federal and private efforts (Reference 3). The federal wind energy program under Department of Energy (DOE) direction is a broadly based program which concerns both large (greater than 100 GENERAL B ELECTRIC kw) and small wind turbine generators. The portion of the DOE program concentrating on large horizontal-axis wind turbine generators is under the direction of NASA. NASA wind turbine generator models so far have logged over 7000 hours of operational experience, supplying power to utili- ties. This testing began with a 100 kW MOD-O machine in September 1975 at NASA's Plumbrook station near Sandusky, Ohio. The DOE-NASA MOD-OA wind turbines currently operating in Clayton, New Mexico; Culebra, Puerto Rico; and Block Island, Rhode Island are examples of 200 kW class machines considered in this study. As described in Reference 3, the first rotation dates for the Clayton, Culebra, and Block Island units were 1977, 1978, and 1979, respectively. A fourth MOD-OA machine is scheduled for 1980 installation in Hawaii. The next 200 kW class machine planned as part of NASA's evolution in hardware design is the MOD-6 WTG, with the first machine scheduled for 1983. WIG Performance Simulation The wind power plant performance model provides an hourly simulation of the plant operation. Performance model inputs include an hourly weather tape and WTG performance characteristics necessary to calculate power output. In the process of calculating net power output, the model deter- mines aerodynamic losses, cut-in, cut-out and regulation losses, mechanical losses and electrical losses. Operating efficiencies are input to the performance model as a func- tion of load to assure a realistic representation of WTG operations at different wind speeds. Nome Utility System Operation Simulation The Monthly Production Simulation Model (MPS), a com- puter program authored by General Electric's Electric Util- ity Systems Engineering Department, was used to simulate the GENERAL €3 ELECTRIC operation of the Nome utility system on a chronological hourly basis for one year time periods. Wind electric power generation was modeled as a load modifier which reduces the load to be served by diesel generating units. The hourly wind power information comes from the wind power plant performance model described previously. The production simulation includes maintenance schedul- ing and a deterministic or probabilistic representation of unit forced outages. The MPS model commits and dispatches economically the thermal generating units each hour. The unit commitment process establishes which diesel generating units are on-line and synchronized (committed) to meet the hourly system demand plus a spinning reserve margin. The unit dispatch process schedules the output of the committed units such that the system fuel cost is minimized. As it does this, the fuel costs are directly calculated for each diesel generating unit and the entire system. By making two simulation runs, one with wind turbine generators and a second with no WTIG's, it is possible to determine WIG energy displacement effects in terms of util- ity system operating costs. These operating cost savings associated with WTG output utilization are termed WTG energy value. The future escalation of diesel fuel costs will cause this energy value to increase through time. Present worth analysis is used in the economic evaluation to account for annual variations of energy value. Economic Evaluation The economic evaluation approach used in this study was developed as part of EPRI Research Project - 740 (Reference aD) In evaluating electric generating facilities, it is necessary to consider total system costs over the plant's entire life. In the absence of multi-year production cost studies, it is possible to simulate operations for one year GENERAL €@ ELECTRIC and include the effect of future cost inflation by using a present worth levelized equivalent cost. The process is illustrated in Exhibit 5.2-2. The present worth levelized equivalent is that uniform annual series of expenditures whose present worth equals that of the actual cost expendi- ture pattern. Capitalization of annual costs determines what single initial capital investment would produce an equivalent series of levelized annual fixed charges. Thus a uniform series can be converted to an equivalent capital cost simply by dividing the levelized annual expenditures by the levelized fixed charge rate. For the Nome Joint Utility System, the levelized fixed charge rate was equal to the capital recovery factor since property taxes, federal income taxes, insurance, investment tax credit, and payments in lieu of taxes were assumed to be zero. The economic evaluation of a wind turbine generator is made by comparing a wind addition case to a base case with no additions of WIG capacity. Throughout this analysis the base case was the 1990 Nome Joint Utility System with a 6 MW peak load and 10 MW of installed diesel capacity (four General Motors diesels @ 2500 kW). One wind addition case considered in the analysis included 600 kw of WTG's (three units @ 200 kW) in addition to the diesel capacity. The energy value was determined from the results of the utility system simulation for 1990 both before and after the addi- tion of wind capacity. The annual operating cost saving is levelized over a 30 year period using 9% diesel fuel cost escalation and a 10% discount rate. The result is then capitalized using the capital recovery factor for a 30 year WTG life and 10% interest rate. The assumed 30 year life is consistent with baseline design requirements for MOD-OA machines, but, as described earlier, operating experience to date is less than five years. The WTG capital cost and the annual O&M (levelized and capitalized) comprise the two GENERAL GB ELECTRIC Actual Costs ‘\ Present Worth Levelized Equivalent Exhibit 5.2-2 Capitalization of Annual Cost GENERAL GQ ELECTRIC components of WIG cost. The cost/value comparisons provide a measure of the economic viability of the WIG application under consideration. Sensitivity Analysis In addition to a baseline economic evaluation, sensi- tivity analyses were performed as part of this study. The purpose of the sensitivity analyses is to quantify the impact of baseline parameter changes on WTG value. The parameter changes considered in the economic evaluation include the following: ° Changes in diesel fuel costs and future escala- tion; Changes in baseline economic parameters. High and low wind years. Amount of installed WTG capacity. o Oo 0 0 Changes in WTG performance characteristics. 5.3 WIG PERFORMANCE IN NOME The wind plant performance model provides an hourly simulation of the WIG operation. Each hour the weather tape gives wind speed and information necessary to determine the air density, p. The input WIG performance data includes rotor swept area, A, hub height, and the curve of coeffi- cient of performance, Cy: for the particular WTG being studied. Wind shear data is also input to calculate wind speed at hub height. From these data, the performance model calculates the rotor shaft power using the expression P = Sy p A v?/2, where V is the wind velocity at hub height. To obtain net electric power output, specified losses in the mechanical transmission and the generator are subtracted from the rotor shaft power. GENERAL €@ ELECTRIC The wind plant performance model was used to investi- gate the performance of the two wind turbine generators shown in Exhibit 5.3-1, a 200 kW WIG and a 2 kW WTG. The performance model results are summarized in Exhibit 5.3-2. Note that performance of the 200 kW WIG was investigated using wind data for three years: a typical year (1958) and high and low wind years (1963 and 1953, respectively). As has been the case in previous wind analyses performed by EUSED, the WTG output and associated capacity factor vary significantly over extended time periods. As pointed out in Section 5.2, however, the winds for the 1951-64 time period appear to be less than the more recent 1967-78 time period (Exhabait 1S) ) 2 The WTG designs evaluated in this study are not opti- mized for the Nome wind regime. Future work effort should consider optimized designs which should demonstrate improved performance. As indicated in Exhibit 5.3-2, the small 2 kw WIG does not perform as well as the 200 kW WTG (24% capacity factor versus 35% for 1958). This relative behavior has been observed in other wind studies performed by EUSED. One of the reasons for this difference in capacity factor is the high rated wind speed for the 2 kW machine (28 mph at hub height). 5.4 NOME UTILITY SYSTEM OPERATION SIMULATION For purposes of this study, the year 1990 was chosen for the baseline analysis because it was believed that wind generation, if it is to be developed, will have reached a degree of maturity by that time. Based on data provided by the Nome Joint Utility System and the Alaska Power Author- ity, a 1990 base case utility system was defined. The Nome utility characteristics for 1990 are shown in Exhibit 5.4-1. The 1990 generating system consists of four generating units GENERAL QQ ELECTRIC Rotor Diameter (ft) Rotor Speed (RPM) Hub Height (ft) 62 Rated Wind Speed (mph) 7s 28 Cut-In Wind Speed (mph) 9.6 10 Cut-Out Wind Speed (mph) 36.8 40 Generator Type Synchronous Induction Note: Rated wind speed, cut-in and cut-out wind speed all at hub height. Exhibit 5.3-1 Wind Turbine Generator Characteristics GENERAL @@ ELECTRIC Annual Annual WTG Output Capacity Year (MWH ) Factor (%) 200 kW WTG 1953 1958 1963 WIG 1958 : 24 WTG output and annual capacity factor based on an annual availability of 90%. Exhibit 5.3-2 Wind Turbine Generator Performance vi". Annual Peak Load 6,000 kw Installed Capacity 10,000 kW (4 Diesels @ 2500 kW) Diesel Heat Rate @ 9300 Btu/kwh. Rated Power 1990 Diesel Fuel Cost §2.1/gallon $15.1/MBtu Hourly utility loads for each month were determined based on data provided by the Nome Joint Utility System. The $2.1/gallon fuel cost is based on 1979 fuel cost of $.81/gallon and a 9% fuel esca- lation (2% + 7% inflation) as requested by the Alaska Power Authority. Exhibit 5.4-1 Nome Utility Characteristics, 1990 31819313 GP 1vuINa9 GENERAL ED ELECTRIC similar to the General Motors 2500 kW unit installed in October, 1979. The Nome utility system simulation was performed using EUSED's Monthly Production Simulation (MPS) model. The MPS model simulates the operation of the Nome generation system based on a chronological load model which includes four 24 hour typical days (Sunday, Peak Weekday, Average Weekday, Saturday) for each month. The detailed representation of diesel generating units includes part load heat rates, forced outages, planned maintenance outages and spinning reserve requirements. MPS model outputs include monthly and annual summaries of generator production costs, hours on line, capacity factors, average operating heat rates, energy produced and fuel used. Summaries by generation type and plant are also available. The MPS model has been used by many utilities since the early 1960's and is currently accessible by telephone via General Electric's MARK III telecommunication network. Exhibit 5.4-2 is presented to illustrate the MPS re- sults for three of the utility simulations performed as part of the evaluation. The utilization of these results to calculate WIG energy value will be discussed in Section 5.5 - Economic Analysis Results. Results for other simula- tion runs performed in this study will also be presented in Section 5.5. 5.5 ECONOMIC ANALYSIS RESULTS The economic analysis approach was briefly described in Section 5.2. The major emphasis of the economic analysis was on measuring the value of wind power plants in the Nome Joint Utility System. Comparison of WTG value to WTG cost provides a measure of WIG economic viability in Nome. a Total Operating Total Diesel Case Description Cost (million $) Generation (MWH) Base Case 503) 35,500 (10 MW Diesel Cap.) Wind Case #1 4.78 33,700 (10 MW Diesel plus 600 kW WIG) Wind Case #2 (10 MW Diesel plus 1800 kW WTG) Wind case results are based on the performance of 200 kW wind turbine generators and the 1958 wind data. Exhibit 5.4-2 Nome 1990 Utility Simulation Results 91H19313 G} 1vuaNag GENERAL €@ ELECTRIC In evaluating electric generating facilities, it is necessary to consider the total system costs over the plant's entire life. In preliminary studies such as this, it is possible to perform a detailed analysis of utility operations for one year (e.g., 1990) and to include the effect of future cost inflation by using a present worth levelized equivalent cost. This approach, which was used in EPRI Research Project - 740 (Reference 1), is described in more detail in Appendix A. For this study, the year 1990 was selected as the reference year. Assuming a 30 year life for a wind turbine generator (Reference 2), the study time period is 1990-2020. The year 1990 was selected because it was believed that wind generation, if it is to be developed, will have reached a degree of maturity by that time. The results presented in this section fall into two categories: (1) baseline economic analysis results and (2) sensitivity analysis results. The baseline economic analy- sis results were developed using economic parameters recom- mended by the Alaska Power Authority. The baseline economic parameters are described below. The sensitivity analysis was conducted to evaluate the impact of key parameter changes on WTG value. Baseline Economic Parameters The following economic parameters, recommended by the Alaska Power Authority, were used in the baseline economic analysis: Inflation Rate - Wye Discount Rate = 10% Oil Products Cost Escalation = 9% GENERAL @@ ELECTRIC Based on information provided by the Nome Joint Utility System, the city of Nome was purchasing diesel fuel at $0.81/gallon in August, 1979. Using the above 9% escalation for diesel fuel, the 1990 diesel fuel cost is: 1990 Diesel Fuel Cost = $2.1/gallon Throughout the economic analysis, the assumed WTG plant life is assumed to be 30 years (Reference 2). WIG Plant Costs The major emphasis of the WIG economic analysis was on measuring the value of wind power plants operating as part of the Nome Joint Utility System. It was not a part of this study to make detailed estimates of costs of wind power plants. Nevertheless, it was considered desirable to estab- lish some baseline cost estimates to compare to WTG value. Based on information available in the literature, installed plant costs for 200 kW wind plants fall in the range of $225,000 to $370,000 (1980 $). The corresponding dollar per kilowatt cost range is $1125/kw - $1850/kw. There are a number of factors which contribute to the varia- tion in plant cost estimates. Some plant cost estimates available in the literature reflect mature design and manu- th facturing practices appropriate for the 100 unit produced. First and second-unit costs can be significantly higher than 100th unit costs. Some estimates are based on WTG designs for low wind regimes, while others are based on designs for high wind regimes. Low wind regime designs tend to be more costly because of larger rotor size, etc. As pointed out in a recent EPRI Journal article (Refer- ence 3), several companies are now marketing large machines. The first on the market with a utility size machine is said to have been WIG Energy Systems, Inc., based in Angola, New GENERAL @ ELECTRIC York. The company has had a 200 kW unit operating on Cutty- hunk Island, Massachusetts since June 1977. As pointed out in the same EPRI Journal article, WIG Energy Systems, Inc. recently sold a second 200 kW turbine of the same design to Nova Scotia Power Corporation for $226,000. This turbine is expected to be up and operating in September, 1980. Other wind turbine generators in the 200 kW class currently on- line are the DOE-NASA MOD-OA plants in Clayton, New Mexico; Culebra, Puerto Rico; and Block Island, Rhode Island (Refer- ence 3). Baseline Economic Analysis Results The comparison of WIG value and cost for 600 kW (three wind plants @ 200 kW) of installed wind capacity on the 1990 Nome Joint Utility System is presented in Exhibit 5.5-1. For the wind case, the total installed generating capacity was 10,600 kW (10,000 kW diesel and 600 kW wind). The value result shown in Exhibit 5.5-1 is based on hourly wind data for 1958 which is typical for the time period, 1951-64. The WIG plant cost shown in Exhibit 5.5-1 is at the high end of the $225,000 - $370,000 range, where plant costs were in- creased from 1980 to 1990 at 7% inflation. The capitalized O&M costs shown are based on O&M cost data in Reference 2. A sample calculation of WIG cost and value is presented in Appendix C. Variations in WIG value over the 1951-64 time period are presented in Exhibit 5.5-2. The years 1953 and 1963 were selected as low and high wind years on the basis of average annual wind speeds. Addition analysis would be required to determine if they are high and low wind years on the basis of WIG energy output. The distribution of wind speeds with respect to the cut-in, cut-out, and rated wind speed affects the actual WTG output. Although WIG value varies significantly, it is interesting to note that WTG GENERAL €@ ELECTRIC Installed Wind Capacity = 600 kw (3 units @ 200 kw) 9% Fuel Cost Escalation 10% Discount Rate 30 Year WTG Life 1958 Wind Data <— Energy Value vv vo N 4 = © 2 on Qu © vo ove < ° 4 4 4 eal = 2 a a 4 Exhibit 5.5-l1 WTG Value and Cost GENERAL @@ ELECTRIC installed Wind Capacity = 600 kw (3 units @ 200 kw) 9% Fuel Cost Escalation 10% Discount Rate 30 Year WTG Life <— WTG VALUE N oe 4 © v oa Q % oO we s ° A a + ot = So a a 4 Exhibit 5.5-2 WTG Value vs Wind Year GENERAL @ ELECTRIC value for the low wind year exceeds cost, shown in Exhibit 5.5-1, by more than 35%. The results in Exhibits 5.5-1 and 5.5-2 indicate the 200 kW WIG is economically viable in the Nome utility system even at plant costs significantly higher than the baseline values. To determine if diesel unit part loading had a signifi- cant operating cost impact at higher WTG penetration levels, a second penetration level was investigated (1800 kW total wind capacity). WTG value and cost versus WTG installed capacity are presented in Exhibit 5.5-3 which shows a linear relationship. As part of the sensitivity analysis, the impact of spinning reserve requirements on WTG value was also investigated. Spinning reserves from 300 kW to as much as 2500 kw (largest unit capacity) were considered in the analysis which demonstrated little variation of WIG value with spinning reserve requirements. Limits to WIG installed capacity which could be introduced by operational consider- ations including stability and voltage and frequency control were not addressed in this study. Future efforts should address some of these operational issues. Sensitivity Analysis Results WTG analyses performed by EUSED in previous projects indicated that utility fuel costs are a principal determi- nant of WIG value. As a result, a sensitivity analysis was performed considering a wide range of diesel fuel costs for the Nome Joint Utility System. The results are presented in Exhibit 5.5-4. As shown, the range of 1990 fuel costs considered was 1 to 4 S$/gallon. The baseline value was $2.1/gallon, as previously indicated. During the 1990-2020 time period, three fuel cost inflation scenarios were con- sidered: 0, 9, and 12%. Throughout the fuel cost sensitiv- ity analysis, general inflation was assumed to be 7% and the discount rate 10%. GENERAL €@ ELECTRIC 9% Fuel Cost Escalation 10% Discount Rate 30 Year WTG Life 1958 Wind Data WTG VALUE | - WTG COST 8 4 - eed enemas 600 1200 1800 3 a N a 4 6 ze) “d a % o wo < ° a 4 = a = ° a a - WTG Installed Capacity (kw) Exhibit 5.5-3 WTG value & Cost vs Installed Capacity 972-SG Installed Wind Capacity = 600 kw (3 units @ 200 kw) 1958 Wind Data Discount Rate WTG Value % oO N dd d © yp “A a, © 0 wo S oO 4 a 4 “dl = ° oO °) a 10% Diesel Fuel Escalation Rate, 1990-2020 allt WTG Cost a < O&M Cost <— <«— Plant Cost 1990 Diesel Fuel Cost » $/gallon Exhibit 5.5-4 WTG Value vs Diesel Fuel Cost 91419313 GB 1vuaN39 GENERAL @@ ELECTRIC The results in Exhibit 5.5-4 indicate that if diesel fuel costs are S$2/gallon in 1990, WTG value exceeds the baseline WTG cost, even when fuel escalation is nearly zero. It should be noted that the diesel fuel escalation rates shown are total escalation not fuel escalation in addition to the general 7% inflation. For example, the 9% fuel escalation (the value used in the baseline analysis) repre- sents a fuel escalation of 2% in addition to the general 7% inflation. The WIG cost/value results are based on the performance of a particular 200 kW WIG design with a rated wind velocity of 17.6 mph hub height. As part of the sensitivity analy- sis, EUSED assessed the performance of another 200 kW de- sign. The second WIG has a smaller rotor diameter (130 ft. versus 161 ft.) and it is rated at a higher wind velocity (19.9 mph versus 17.6 mph). As shown in Exhibit 5.5-5, the smaller, lighter design results in significant plant cost savings, but at the expense of an even larger reduction in WIG value. In other words, the first design is better matched to the Nome wind regime. One of the conclusions which can be drawn based on the Exhibit 5.5-5 results is the WIG value is sensitive to WTG design and operation. The value results presented in this section are appropriate for the WTG plants considered and are not necessarily appropri- ate for other machines. The comparative performance of large and small machines is shown in Exhibit 5.5-6. The large machine is the 200 kw WIG discussed throughout this section while the small ma- chine is a 2 kW WIG. The characteristics of these two machines are presented in Section 5.3, Exhibit 5.3-1. As would be expected based on the WIG output (Annual MW#H) results presented in Exhibit 5.3-2, the value for 600 kw of small units is substantially less than 600 kW of large units. The improved performance of the 200 kW WTG is ex- GENERAL €@ ELECTRIC 200 kw WTG 1958 Wind Data 9% Fuel Inflation 10% Discount Rate oD oO N oa 4 o v oat Q % ov ur s ° ol St sa “4 = o a a q Design #1 Design #2 Rated Wind Velocity v. HL 7/10 = 19.9 mph Rated Vrated Rotor Diameter D = 161 ft. Diino Ont tr. Exhibit 5.5-5 Cost Value Comparison for Alternative WTG Designs GENERAL GB ELECTRIC 1958 Wind Data 600 kw Installed Wind Capacity 9% Fuel Escalation 10% Discount Rate COST VALUE 3 oO N 4 so za) oa a o oO wD S ° ol 4 ZI d = ° a a a 600 kw Total Capacity 2 kw Single Plant Capacity Exhibit 5.5-6 Comparative Performance of 200 KW and 2 KW WTG GENERAL €@ ELECTRIC plained by a higher rotor efficiency (c,) compared to the 2 kw wWTG. The total plant cost for the 2 kW WTG case in Exhibit 5.5-6 is representative of commercially available machines in the 2 kW class. In addition to the cost/value analysis, a financial analysis was performed. The objective of the financial analysis was to calculate potential reductions in total utility system power costs which could be achieved with the installation of 600 kW of wind power by 1990. Power costs in Nome are approximately 20 ¢/kWh at the present time. The cents per kilowatt hour cost reduction over a 15 year time period is shown in Exhibit 5.5-7. The net cost reduction is the difference between the value and cost also presented in Exhibit 5.5-7. The results in Exhibit 5.5-7 are based ona total system generation of 35.5 million kWh per year. The WIG cost is based on a levelized fixed charge rate of 10.6% (capital recovery factor at 10% interest and 30 year life) and O&M costs escalating at 7%. Power cost reductions for lower interest rates would fall between the WIG value and net cost reduction curves shown in Exhibit 5.5-7. The net cost reduction of up to 1.75 ¢/kWh shown in Exhibit 5.5-7 are less than 10% of the 20 ¢/kWh current power costs in Nome. The results in Exhibit 5.5-7 are based on 1958 wind data and the baseline economic parameters, as indicated. Sample calculations of the cost results presented in Exhibit 5.5-7 are presented in Appendix D. 5.6 SUMMARY AND CONCLUSIONS Conventional generation planning computer simulation methods were used together with a wind turbine generator (WIG) performance model to study wind generation on the Nome Joint Utility System. Hourly wind speed data collected at the Nome Weather Station were used to evaluate the perform- GENERAL GQ ELECTRIC 1958 Wind Data 200 kw Wind Plants 7% Inflation 9% Fuel Escalation 10% Discount Rate 1990 Diesel Fuel, $2/gallon Net Cost Reduction (Value - Cost) Power Cost Reduction v ¢/kwh WTG Cost ee (Plant & O&M) Exhibit 5.5-7 Impact of 600 KW WTG Addition on ¢/KWH Power Cost GENERAL G@ ELECTRIC ance of several WIG designs. Evaluations were based on comparison of total utility generation system costs with and without wind plant additions. Economic analysis results were expressed in terms of wind power plant value and cost. Value is measured by the value of reduced diesel fuel con- sumption resulting from WIG energy output. In this study, wind plants were assumed to have no capacity value; i.e., they function solely as fuel savers. The results of this study demonstrate that the value of wind plants is highly variable. Value depends upon the wind regime, WIG design, and economic factors (principally the cost of diesel fuel). The baseline economic analysis re- sults indicate that energy value is sufficient for WIG economic viability if recent cost and performance estimates for large wind machines in quantity production can be achieved. As part of the sensitivity analysis a wide range of wind conditions, WTG designs, and diesel fuel costs were considered. In the sensitivity analyses the calculated WTG value ranged from 4,000-14,000 $/kW (1990S) while the total costs ranged from 3000-7500 $/kW (1990S). In most cases, wind value exceeded wind cost indicating economic viability. The utility simulation results also show 1990 oil savings which range from 5.5% to 16% for the 600 kW and 1800 kW WIG additions, respectively. The wind turbine generators selected for consideration in this study are representative of machines currently operational as part of federal and private efforts. The DOE-NASA MOD-OA wind turbines currently operating in Clay- ton, New Mexico; Culebra, Puerto Rico; and Block Island, Rhode Island are examples of 200 kW class machines evaluated in this study. A fourth MOD-OA machine is scheduled for 1980 installation in Hawaii. The next 200 kW class machine planned as part of NASA's evaluation in hardware design is the MOD-6 WTG, with the first machine scheduled for 1983. GENERAL GS ELECTRIC Short time (less than an hour) fluctuations of wind power plant output were not studied because neither wind nor load data were available. It is estimated, however, that for small penetrations, wind plant output variations plus normal load fluctuations will not impose duty on diesel generating units any more stringent than present load fluc- tuations alone. Experience with wind turbines in the 200 kw class has demonstrated that large wind machines can operate successfully in a small utility environment. However, future analyses should assess the importance of stability and dynamic considerations as potential limits to WTG pene- tration into small systems. Additional wind resource data is required for the Nome area to fully assess wind power's potential for becoming a viable adjunct to diesel generators. Results based on the Nome Weather Station wind data indicate significant poten- tial even though the average annual windspeed is 10 mph (@ 21 feet). A question remains concerning the wind resource at other potential sites and how it compares to the weather station site. Based on the results of this wind turbine generator evaluation, a wind turbine field test on the Nome Joint Utility System appears justified. Successful demonstration of a 200 kW class machine, for example, would answer ques- tions concerning WTG operations in an environment signifi- cantly different than present installations. For example, what are the operational impacts of severe wind storms and blade icing in the Nome environment. A successful demon- stration could conceivably lead to additional WTG installa- tions which reduce both oil consumption and the cost of electricity in Nome. GENERAL @@ ELECTRIC REFERENCES ale "Requirements Assessment of Wind Power Plants in Elec- tric Utility Systems", EPRI ER-978 (Volumes 1 and 2), Prepared by General Electric, Electric Utility Systems Engineering Department, January, 1979. me "Technical Assessment Guide", EPRI PS-1201-SR, Prepared by The Technical Assessment Group of the EPRI Planning Staff, July, 1979. Sr "Going With the Wind", EPRI Journal, March, 1980, pp. =I 2 GENERAL €@ ELECTRIC APPENDIX A Total Utility System Cost Methodology The total utility system cost methodology described in this appendix is the same methodology used in EPRI Research Project - 740, "Requirements Assessment of Wind Power Plants in Electric Utility Systems" (Reference 1). One way to evaluate and compare the economic performance of wind plants is to compare annual revenue requirements for the base case and the wind addition case. This comparison is illustrated in Figure A-1l which shows fixed charges associated with generation equipment along with fuel and O&M costs which escalate through time. The basic quantities illustrated in Figure A-1 are: Cy = Levelized fixed charges associated with existing diesel equipment ($/yr). Annual O&M cost for diesel plant ($/yr). o Fp = System annual fuel cost for all diesel base case (S$/yr). Cy = Levelized fixed charges associated with wind plant (S$/yr). Annual O&M cost for wind plant (S/yr). # F = System annual fuel cost for the wind addition case ($/yr). Since the total utility system costs illustrated in Figure A-1l vary through time, it is common and convenient to use present worth levelized equivalent costs. The present worth GENERAL GQ ELECTRIC Base Case: All Diesel System Wind Addition Case: Diesel + Wind Exhibit A-l Annual Revenue Requirements GENERAL €@ ELECTRIC levelized equivalent is that uniform series of costs whose present worth equals that of the actual cost expenditure pattern. The levelized total utility system cost for the base (all diesel) case is given by: Ty = PpR, + MK,R, + FLK,R, (A-1) where: Pp = Diesel plant cost ($). Ry = Levelized fixed charge rate. Cy = PpR, = Levelized fixed charges for diesel plant (S/yr). K = Present worth factor for an infla- tion series. R5 = Capital recovery factor. The present worth factor for an inflation series is oy K = eal (A-2) where: a = Inflation rate/100. 1 = Interest rate/100. n = Wind plant life (years). The above expression for K is derived in Appendix B. The levelized total utility system cost for the wind addition case is given by Tw = PpRy + PyRy + MpKoRo + MyKoRo + Fy KR, (A-3) where: Wind plant cost ($). Annual O&M cost for wind plant (S$/yr). # = GENERAL €@ ELECTRIC F = System annual fuel costs for the wind case (S$/yr). One way to evaluate and compare the economic perform- ance of wind plants is to calculate the ratio of total utility system costs, Ty/Tp- A ratio less than or equal to unity indicates economic viability. One of the problems with the use of the Ty/Tp changes in input quantities such as wind plant costs have ratio is that relatively large little impact on the value of the ratio. Another way to evaluate and compare the economic per- formance of wind plants is to calculate breakeven wind plant costs. The breakeven cost is the wind plant cost required to make the total utility system cost for the wind case equal to that of the base case (i.e., Ty = Tp): By setting the equations for Ty and Tp equal and solving for Pw (Wind Plant Cost), the following equation for breakeven cost is determined. Bs BS (P,.) = (F, - F,) K, s*- K, =*, ® Breakeven D to 4 el MW : Ry in capitalized $ (A-4) A third method of comparison which was used in EPRI RP-740 and in this Nome wind energy study is to calculate total value of the wind plant additions. In the Nome study, total value is equal to energy value since wind plants are assumed to have no capacity value. GENERAL €@ ELECTRIC In equation form, WIG Energy Value = (F, - F K 2 . ( D w> is Ry’ in capitalized $ (A-5) Total cost associated with a wind plant is simply the wind plant capital cost plus capitalized O&M costs. WTG Total Cost = Py +t My Ky an (A-6) Note that the difference between wind plant energy value and breakeven cost is the capitalized O&M costs; i.e., compare equations A-4 and A-5. For the Nome Joint Utility System, it is assumed that property taxes, income taxes, insurance, payments in lieu of taxes and investment tax credit are zero, as a result, the fixed charge rate equals the capital recovery factor (Ry = R,)- In this case, the equations for energy value and total cost are: WTG Energy Value = (Fp - Fy) Ky (A-7) WIG Total Cost = Py + My K, (A-8) where: Fp = System annual fuel cost for the all diesel base case (S$/yr). F, = System annual fuel cost for the wind case (S/yr). GENERAL ELECTRIC Py = Wind plant cost (S$). My = Annual O&M cost for wind plant (S$/yr). K = Present worth factor for inflation series, see equation A-2. GENERAL € ELECTRIC APPENDIX B Present Worth Factor for an Inflation Series In many economic comparisons, it is useful to calculate the present worth of an inflation series, such as fuel costs. where: x is: Assume the inflation series is: PP [iceman (1 + a) (B-1) F = Fuel cost in first year. Inflation rate/100. Number of years considered. 3 " The present worth, PW, of this series at discount rate PW = Pip + “35+ (tay oe} + tay (B-2) (+i)? (iti)? (1+i)™ Multiplying Equation B-2 by (1+i): 2 n-1 7 pat l+a ita, papa rebate! a EOC) BL Facer fC) | Ges, } (B-3) Multiplying Equation B-2 by (l+a): lta are l+a 1+a,™ PW(l+ta) = F[ ess lla ta)” ail (yz) ] (B-4) GENERAL @@ ELECTRIC Subtracting Equation B-4 from Equation B-3 yields: n ' Pw(i - a) = F [1 - (72%) ] (B-5) lta aD Bs = eee i ee Be eigen cit (Bre) The present worth factor, K, for an inflation series is, therefore, n 1+ [1- Gy 1 Sl ainaeel ey where: a = Inflation rate/100. al = Discount rate/100. GENERAL €@ ELECTRIC APPENDIX C Sample WIG Cost/Value Calculation The following equations for WTG value and WTG cost were derived in Appendix A. WTG Value = (Fp - Fy) Ky WIG Cost = Py + My K, n lta. mn (ee — {1 (GT ) ] l- as. ‘i j where: Fp = 1990 Utility Fuel Cost for all Diesel Base Case (S/yr). Fy = 1990 Utility Fuel Cost for Wind Case. Py = 1990 WTG Plant Cost ($). My = WIG Annual O&M Cost ($/yr). ay = Diesel Fuel Escalation/100 a5 = WIG O&M Cost Escalation/100 1 = Discount Rate/100 Using the results presented in Section 5.4, F. = 5.03 x 10° F. = 4.78 x 10° GENERAL @ ELECTRIC The 1990 total plant cost for three wind plants rated at 200 kw is assumed to be $2.16 million. Annual O&M costs for the 600 kW of wind capacity is assumed to be $12,900/year based on WIG O&M cost data in Reference 2. As previously indi- cated, baseline values for fuel escalation and discount rate are 9% and 10%, respectively. In summary, Py = $2.16 million = $12,900 a, = -09 as = .07 i = .10 n = 30 years Using equations (1), (2), and (3) and the above input parameters, 4.00.29 i (—_) K, = —— er = «23-96 WIG Value = (5.03 - 4.78) 10° (23.96) = $5.99 x 10° 1_o7.* 1: Ga Ko = r= 07 = «18-79 GENERAL €@ ELECTRIC WTG Cost Py + My Ko $2.16 x 10° + $12,900 (18.79) $2.4 x 10° GENERAL GB ELECTRIC APPENDIX D Financial Analysis The objective of the following analysis is to assess the impact of 600 kw of wind power on total system power costs. The following sample calculations illustrate the determination of system power cost reductions through time as presented in Exhibit 5.5-7. As was the case in the Appendix C sample calculation, the following data are used: Fb = 5.03 x 10° S/year Fy = 4.78 x 10° S/year Py = $2.16 x 10° My = $12,900 a, = 09 ay Sys Oi. where: Fp = 1990 Utility Fuel Cost for all Diesel Base Case ($/year) Ew = 1990 Utility Fuel Cost for Wind Case ($/year ) P = 1990 WTG Plant Cost (S$) = 1990 WTG Annual O&M Cost ($/year) Diesel Fuel Cost Escalation/100 WTG O&M Cost Escalation/100 om vu a a) » In the following example, the levelized annual revenue requirements for plant costs are based on a levelized fixed charge rate of 10.6% (capital recovery factor at 10% inter- est and 30 year life). The levelized annual revenue requirements for WTG plant costs are: GENERAL €@ ELECTRIC (ARR ) rg Py, X FCR Plant e $2.16 x 10° (.106) $230,000/year The annual revenue requirements for WIG O&M costs are $12,900 in 1990, escalating at 7% per year. The additional annual revenue requirements through time are summarized in Exhibit D-1. The total is shown in million dollars per year and in ¢/kWh based on total annual kWh generation of 35.5 x 10°. The ¢/kWh results shown in Exhibit D-1l represent the additional power costs associated with WTG plant and O&M expenses. To determine the net impact of wind plants on power costs, it is necessary to calculate WTG value year- by-year. Yearly WTG value is the fuel cost saving which result from the reduced consumption of diesel fuel. The diesel fuel cost savings achieved with 600 MW of WIG in 1990 are 1990 Fuel Cost Savings = Fy - Fw D 5.03 x 10° - 4.78 x 10° $250,000 The fuel cost savings are assumed to escalate at 9% through the 1990-2005 time period. The reduced annual revenue requirements associated with reduced diesel fuel consumption are shown in Exhibit D-2. The net impact of a 600 kW WTG addition on annual revenue requirements (ARR) and system power costs is shown in Exhibit D-3. Note that the ARR and ¢/kWh results are incremental savings and not total system ARR and ¢/kWh, respectively. For example, in the year 2000, wind power in the Nome Joint Utility could reduce power costs approxi- mately 1 ¢/kWh. GENERAL i ELECTRIC WIG Cost Total WTG Plant WIG O&M Additional Added ARR ARR ARR Power Cost Year (million $/yr) (million $/yr) (million $/yr) $/kWh 1990 -230 013) 243 -69 91 we30) -014 -244 92 7230 BOLO) -245 93 -230 -016 246 94 72350 honky eed 1995 250) -018 248 -70 96 +230) -020 250) 97 A230) Ogi seo 98 -230 -022 oy 99 -230 024 254 2000 2230) -026 ~250 mee, 1 -230 -027 a aod, 2 sO) -029 S209 3 230) a oejal -261 4 20) -034 -264 2005 -230 -036 -266 aS) Note: Total system power generation = 35.5 x ie kWh/year. Exhibit D-1 Incremental Impact of WTG Plant and O&M Costs on Annual Revenue Requirements and Power Cost GENERAL QQ ELECTRIC WIG Value Reduced Reduced ARR Power Costs Year (million $/yr) (¢/kWh ) 1990 25.0) oO) 1 Zire 2 297 3 ~324 4 SDS 1995 oD) 1.09 6 419 a -457 8 -498 9 543 2000 s992 167 1 645 2 703 3 - 766 4 835 2005 OL: oN, Exhibit D-2 Impact of Reduced Fuel Costs on Annual Revenue Requirements and Power Costs GENERAL QQ ELECTRIC WIG WIG Neen Reduced Annual Costs Annual Value Power Costs Year (million $/yr) (million $/yr) (aetinicnt S/yr) (¢/kWh ) 1990 .243 +250 .007 402 1 244 yee) 028 2. 245 Zo 0.512) 3 246 a324 -078 4 ~247 1353 106 -39 1995 -248 -385 esi) 6 250 -419 -169 7 25 3457; 206 8 e252 -498 246 9 254 543 289 2000 W250) -592 330 95 as 2 ou: -645 -388 2 ~259) 7703 444 3 -261 766 -505 4 264 4335 OAs 2005 -266 -911 -645 82 Exhibit D-3 Net Impact of 600 kW WIG Addition on System Power Costs GENERAL €B ELECTRIC 6.0 CONCLUSIONS Of the three potential non-oil resources (hydro, coal and wind) that could be utilized to generate electric power in the vicinity of Nome, Alaska, only wind generation systems were found to have an application. Hydroelectric systems examined were generally found to be tech- nically feasible. Their costs per kilowatt hour, however, were greater than those associated with a diesel generation system. Unless the economic parameters used in compiling this report are altered (through geological information refinement), hydroelectric generation of electricity does not appear to be an alternative to the present diesel generation system. Preliminary investigations reveal no coal fired electric gener- ating system exist that approaches the small size as required by Nome. It is recognized that technology and equipment definition presently exist for design and installation of coal fired systems for Nome. The design, however, would be a "first of its kind"; furthermore, its personnel operating requirements would be nearly the same as that of 20 to 80 megawatt systems. The most likely use of Nome region coal resources appears to be for home heating. Conventional generation planning computer simulation methods were used to evaluate the performance of several wind turbine gener- ators on the city of Nome utility system. Actual wind data collected at the Nome weather station was used for the hour-by-hour simulations. The results of the evaluations indicate economic viability of wind turbine generators in Nome, if recent cost and performance estimates for large (200 kW rated output) wind machines in quantity production can be achieved. Sensitivity analyses, performed as part of the evaluation, indicate that wind plant value exceeds wind plant cost under a wide range of wind regimes, diesel fuel costs and wind plant cost. GENERAL GB ELECTRIC The wind turbine generators selected for consideration in this study are representative of machines currently operational as part of federal and private efforts. The DOE-NASA MOD-OA wind turbines cur- rently operating in Clayton, New Mexico; Culebra, Puerto Rico; and Block Island, Rhode Island are examples of 200 kW class machines evaluated in this study. A fourth MOD-OA machine is scheduled for 1980 installation in Hawaii. The next 200 kW class machine planned as part of NASA's evaluation in hardware design is the MOD-6 WTG, with the first machine scheduled for 1983. Based on the results of this wind turbine generator evaluation, a wind turbine field test on the Nome Joint Utility System appears justified. Successful demonstration of a 200 kW class machine, for example, would answer questions concerning WTG operations in an environment significantly different than present installations, including the operational impacts of severe wind storms and blade icing in the Nome environment. A successful demonstration could conceivably lead to additional WTG installations which reduce both 0il consumption and the cost of electricity in Nome. 6-2 Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 GENERAL @@ ELECTRIC