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Bristol Bay Energy & Electric Power Potential Phase I 1979
170,06.0/ FILE COPY Bristol Bay Energy and Electric Power Potential Phase | December 1979 Prepared For: U.S. Department of Energy Alaska Power Administration Under Contract No. 85-79AP10002.000 NOTICE This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States or any agency thereof, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for any third party's use or the results of such use of any information, apparatus, product, or process disclosed in this report, or represents that its use by such third party would not infringe privately owned rights. JAY S. HAMMOND, GOVERNOR STATE Ok ALASKA, DEPART MENT OF FISH AND.GA ME 333 RASPBERRY ROAD ANCHORAGE 99502 October 24, 1979 Department of Energy Alaska Power Administration P., 0. *Box 50 Juneau, Alaska 99802 Attention: Mr. Robert J. Cross, Administrator Gentlemen: Re: Bristol Bay Energy and Electric Power Potential - Phase I (Draft Report) On 4 October 1979, we responded to the subject document and stated that we had no specific comments to offer. Subsequent review brought us to the attention of Section IV, page 166, which addresses hydroelectric development on Tazimina River. It should be pointed out that the Tazimina River is an important fish stream. The document, specifically page B- 438, is correct that the falls on this river is a migrational barrier. However, there is a large population of sockeye salmon which spawn below the falls. Escapements have ranged as high as 500,000 fish. Last year there were more than 150,000 sockeye in the river and although this year's figures have not yet been published, they are expected to show an even higher number. Aside from sockeye salmon, Tazimina River supports a notable population of rainbow trout, grayling and char. Anyway, we foresee rather serious fisheries problems with power plant development on Tazimina River. Areas of potential conflict include: A. Nitrogen saturation B. Flow level manipulation - altering temperature, benethic (invertebrate) production, channel configuration, and flushing rates Should a decision be made to pursue development, indepth field investigations will need to be conducted to fully address project impacts and potential mitigation measures. 4k. Power Administration -2- Thank you for the opportunity to comment. are any questions (telephone 344-0541). Sincerely, Ronald 0. ee ae SE FRa eRe rtp BY: Bruce M. Barrett Projects Review Coordinator Habitat Protection Section cc: J. Madden, DPDP October 24, 1979 Please contact us if there B STATE OF ALASKA / +. — OFFICE. OF THE GOVERNOR pratt POUCH AD DIVISION OF POLICY DEVELOPMENT AND PLANNING JUNEAU, ALASKA 99811 PHONE: 465-3512 November 1, 1979 Mr. Robert J. Cross, Administrator Department of Energy Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 Subject: Bristol Bay Energy & Electric Power Potential State I.D. No. FE210-79100201S Dear Mr. Cross: Since this is the close of the review period, the Alaska State Clearinghouse is forwarding a copy of a letter from Commissioner Ronald Skoog of the Alaska Department of Fish and Game, and the following comment from Mr. Eric Yould, Executive Director of the Alaska Power Authority. Mr. Yould stated: "We find the study is a very important contribution to rural energy planning. The Power Authority is presently implementing the report's primary recommendation for the Dillingham, Naknek/King Salmon and Iliamna areas. Specifically, feasibility studies and field investigations are underway to assess the timing and cost of various hydroelectric development scenarios incorporating the hydropower potential of Lake Elva, Grant Lake and Tazimina." If additional comments are received, the Clearinghouse will forward them to you. Sincerely, _ Rib) (Co fo dace L. Madden State-Federal Coordinator Enclosure cc: Richard Logan, ADF&G Eric Yould, APA David Allison, DPDP FILE COPY > Bristol Bay Energy and Electric Power Potential Phase | December 1979 Prepared By: Robert W. Retherford Associates Arctic District of International Engineering Co. Inc. Anchorage, Alaska For The: U.S. Department of Energy Alaska Power Administration P06 Biex 5:0 Juneau, Alaska 99802 Under Contract No. 85-79AP10002.000 This report has been prepared by: Robert W. Retherford Associates Arctic Division of International Engineering Company, Inc. R. W. Retherford, P.E. Dy. .L. ‘Gropp; P.E. G: Hs Steeby, 7P.iE. C.) Thompson, Ets: Information on certain Energy Resources has been provided by: Geothermal, Fossil, Mineral Cc. C. Hawley Associates Wind Dr. Tunis Wentink, Jr., University of Alaska ACKNOWLEDGEMENTS Many sections in this report would have been not only incomplete but almost impossible to do without the information and knowledge made available to us by numerous organizations, companies, agencies, and individual people. We would like to express our thanks for the help received from everybody involved. Only a few can be mentioned here in somewhat of a chronological order: Andy Golia from the Bristol Bay Native Association who helped to or- ganize and advertise the public meetings in Dillingham and Naknek. Dave Bouker, .Manager of Nushagak Electric Corporation, who showed us the Lake Elva and Grant Lake hydro sites. Mike Nelson, Richard Russell and Chris Smith from the Alaska Department of Fish and Game who provided valuable comments on the impact of resource development on the Bristol Bay fisheries and wildlife. Laura Schroeder, City Manager of Dillingham, who gave us an understanding of the overall economic development picture of the area. For the preparation of the energy balance and power requirements forecast, local utilities Nushagak Electric Corporation, Naknek Electric Association, Alaska Village Electric Cooperative, Iliamna-Newhalen Electric Cooperative, the City of Manokotak, Glen Alsworth, Sr. of Port Alsworth, The Southwestern and the Lake and Peninsula School District, The Federal Aviation Agency, The Alaska Air Command, local and regional Chevron fuel distributors in Dillingham and Naknek, Moody's Sea Lighterage in Aleknagik, and the Bureau of Indian .Affairs opened their books and assisted us in gathering the required data. The following agencies and offices helped us to learn about existing facilities and planned future developments in the individual communities: The Alaska Department of Energy and Power Development, the Alaska Department of Community and Regional Affairs and the Division of Commercial Fisheries of the Alaska Department of Fish & Game. Without the effort put forward by all the above and others who are not listed here, this report could not have been prepared with the in depth information it now contains. BRISTOL BAY ENERGY AND ELECTRIC POWER POTENTIAL PHASE | TABLE OF CONTENTS EXECUTIVE SUMMARY A. Introduction B. Energy Balance C. Electric Energy Demand Projections D. Potential Energy Resources E. Potential Electric Power Resources Ps Recommendations ENERGY BALANCE 1977 AND EXISTING SYSTEMS A. Introduction and Summary B. Dillingham Cc. Naknek - King Salmon D. Iliamna - Newhalen - Nondalton Es Rural Bristol Bay le Nushagak Bay 2 Peninsula - Bristol Bay 3: Peninsula - Pacific 4. Togiak Bay 5 Iliamna Lake 6 Inland B ibliography XS=11 XS-19 XS-26 11-29 Waast 11-37 11-40 11-45 11-49 [1=50 I-S5 11-61 11-67 Dana 11-76 11-82 TABLE OF; CONTENTS (Continued) Page ELECTRIC ENERGY DEMAND PROJECTIONS 11-85 A. Introduction and Summary 111-87 B.. Projection Parameters 111-88 Cc. Dillingham 111-93 D. Naknek - King Salmon 111-98 E. Iliamna - Newhalen - Nondalton i 111-103 F. Rural Bristol Bay 111-106 Ax Nushagak Bay 111-108 2. Peninsula - Bristol Bay 111-116 Ss Peninsula - Pacific 1-125 4. Togiak Bay 111-136 35 lliamna Lake 111-140 6s Inland 111-148 G. Bibliography 111-156 POTENTIAL ENERGY AND ELECTRIC POWER RESOURCES 1V-159 A. — Introduction 1V-161 B. Bristol Bay Energy Resources 1V-161 ds Hydroelectric Energy 1V-162 2s Geothermal Energy 1V-167 3 Coal IV-174 4. Oil and Gas Resource .- 1V-178 5. Uranium 1V-186 6. Wind Potential 1V-190 7. Tidal Energy 1V-205 8. Other Energy Resources 1V-209 C. Electricity Generating Technology and Cost Review iV215 1 Diesel Electric Generating Units IV-215 oe Gas Turbine Generating Units 1V-220 a. Steam Turbine Generating Units 1V-221 4. Hydroelectric Generating Units IV-222 Cy Wind-electric Generating Units 1V-225 6. Other Generating Technologies IVe227 Ds Analysis of Power Supply Alternatives 1V-229 - iii - TABLE OF CONTENTS (Continued) Page D. Electric Energy Resources 1V-233 a Dillingham/Naknek - King Salmon 1V-237 a. Energy Resources 1V-237 b. Electric Power Demand and Resources 1V-237 a Analysis of Electric Power Resource Alternatives 1V-246 a Ten Villages in the Nushagak/Kvichak Bay Area 1V-255 a. Energy Resources [V=255 & Electric Power Demand and Resources 1V-255 Gs Analysis of Electric Power Resource Alternatives 1Vie255 3h lliamna, Newhalen, Nondalton |V-259 a. Energy Resources 1V-259 b. Electric Power Demand and Resources 1V-259 Cs Analysis of Electric Power Resource Alternatives 1V-261 4. | Chignik Bay Communities ; 1V-262 cals Energy Resources 1V-262 bE Electric Power Demand and Resources 1V-262 Gy Analysis of Electric Power Resource Alternatives 1V-269 a Rural Bristol Bay - Energy and Power Resources 1V-270 Ts Peninsula - Bristol Bay iV=270 Be Peninsula - Pacific Coast (IV=273 es Togiak Bay 1V-274 4. Iliamna Lake Area 1V-275 V. RECOMMENDATIONS ; V-277 A. Introduction V=279 B. Diesel Electric Energy V-279 -iv- TABLE OF CONTENTS (Continued ) Hydro Energy Geothermal Energy Energy Energy Development Plans Energy Balance Data and Conversion Factors Residential Small Schools Medium School Large School Village Stores Public Buildings Technical Performance Data and Descriptions G: Dp. By Coal FE Wind G. APPENDICES A. Th 2. Se 4. 52 6; Bis is 2s 3: 4. Si 6. iG... Gost Ths 2. 3. 4. 53 Single Wire Ground Return Transmission Distribution and Transmission Line Load Limitations Economizing Diesel Generator Plants Phase and Frequency Conversion in Power Transmission Wind Energy Conversion Potential Hydro-Sites Estimates Distribution Transmission Diesel Generating Equipment Wind Generating Equipment Coal/Steam Generating Equipment Ve279 V-281 V-281 V-282 V-283 A-287 A-291 A-296 A-298 A-300 A-302 A-304 B-307 B-309 B-321 B-327 B-335 B-341 B-363 C-443 C-445 C-447 c-449 c-450 c-450 TABLE OF CONTENTS (Continued) D. Economic Evaluations he Parameters zi Small Diesel Generating Plant 3. Wind Electric Generating System 4, Small Diesel/Wind Generating System Combination Su Lake Elva and Diesel - Dillingham 6. Transmission Intertie for Communities in the Nushagak/Kvichak Bay Area 7.° Lakes Tazimina, Elva and Grant for Dillingham/Naknek plus 13 Villages 8. Chignik Bay Hydro and Intertie 9. Lake Kukaklek 0 lliamna Variable Speed Diesel Generation ] =H Appendix - Comments and Other Reports E-1 Review Comments on Draft Report E-2 Chignik Coal Field Cost Study E-3 Tazimina Hydro Project Impact on Fisheries ees Page D-453 D-455 D-458 0-460 D-462 D-463 D-465 D-468 D-474 D-483 D-484 E-489 E-491 E-499 E-535 LIST OF FIGURES EXECUTIVE SUMMARY ENERGY Li=a 1-2 11-3 11-4 11-5 11-6 Bristol Bay Region Vicinity Map Bristol Bay - Energy Use in 1977 Bristol Bay - Power Requirements Hydro Developments for Dillingham/Nakinek ° BALANCE AND EXISTING SYSTEMS Dillingham - 1977 System Electric Energy Use Naknek - 1977 System Electric Energy Use King Salmon - 1977 System Electric Energy Use Egegik - 1977 System Electric Energy Use Togiak - 1977 System Electric Energy Use New Stuyahok - 1977 System Electric Energy Use ELECTRIC ENERGY DEMAND PROJECTIONS 11-1 I1-2 11-3 11-4 W-5 111-6 1-7 11-8 11-9 111-10 Bristol Bay Population - Historical and Future Trends Bristol Bay - Power Requirements Dillingham - Power Requirements Dillingham - Seasonal Electric Energy Use Naknek - King Salmon - Seasonal Electric Energy Use Naknek - Power Requirements 1977 - 2000 lliamna - Power Requirements 1977 - 2000 Rural Bristol Bay - Seasonal Electric Energy Use Clarks Point - Power Requirements 1977 - 2000 Ekuk - Power Requirements 1977 - 2000 - vii - xore XS-3 XS-8 XS-24 11-39 11-43 11-44 11-57 11-69 11-81 111-88 111-91 111-95 111-97 111-99 111-100 111-104 111-107 111-108 111-110 IV. 1-11 tl=12 111-13 11-14 11-15 111-16 111-17 111-18 111-19 111-20 11-21 111-22 111-23 11-24 111-25 111-26 111-27 111-28 111-29 111-30 11-31 111-32 ENERGY al | IV-2 IV-3 IV-4 LIST OF FIGURES (Continued ) Manokotak - Power Requirements 1977 - 2000 Portage Creek - Power Requirements 1977 - 2000 Egegik - Power Requirements 1977 - 2000 Pilot Point - Power Requirements 1977 - 2000 Port Heiden - Power Requirements 1977 - 2000 Port Moller - Power Requirements 1977 - 2000 Pacific Coast Communities Seasonal Energy Use Chignik - Power Requirements 1977 - 2000 Chignik Lagoon - Power Requirements 1977 - 2000 Chignik Lake - Power Requirements 1977 - 2000 Ivanoff Bay - Power Requirements 1977 - 2000 Perryville - Power Requirements 1977 - 2000 Togiak - Power Requirements 1977 - 2000 Twin Hills - Power Requirements 1977 - 2000 Igiugig - Power Requirements 1977 - 2000 Kokhanok - Power Requirements 1977 - 2000 Pedro Bay - Power Requirements 1977 - 2000 Port Alsworth - Power Requirements 1977 - 2000 Ekwok - Power Requirements 1977 - 2000 Koliganek - Power Requirements 1977 - 2000 Levelock - Power Requirements 1977 - 2000 New Stuyahok - Power Requirements 1977 - 2000 AND ELECTRICAL POWER RESOURCES Tazimina Hydro Site Projected Cost of Diesel Generation Typical Bulb Turbine Installation Dillingham - Naknek plus 10 Villages Intertie (Map) - viii - Page 111-112 11-114 111-116 111-118 111-120 111-122 11-125 111-126 11-128. 111-130 111-132 111-134 111-136 111-138 111-140 111-142 111-144 111-146 111-148 111-150 111-152 11-154 1V-166 1V-216 1V-225 1V-241 EISTOE; ENGURES (Continued ) Page Iv-5 Hydro Developments for Dillingham/Naknek 1V-243 IV-6 Dillingham/Naknek - Cost of Power - Low Load Projections ‘rari v-2ol IVT Dillingham/Naknek - Cost of Power - High Load Projections : 1V-253 IV-8 Nushagak/Kvichak Villages - Cost of Power ‘ 1V-257 Iv-9 Chignik Bay Intertie 1V-265 APPENDICES Bossi Fuel Rates B-332 G-3.2 Relative Engine Wear Bodso) B-5.1 Wind Speed Duration and WECS Power Characteristics B-345 8-5.2 Power Output Versus Wind Velocity B-348 O-1 Projected Cost of Diesel Generation D-456 D-10.1 Fuel Efficiency Ranges for 230 kW Generators D-486 - ix - ING LIST OF TABLES EXECUTIVE SUMMARY ENERGY 11-1 2 ENERGY \V-1 IV-2 IV-3 1V-4-6 IV-7 lvV-8 1977 Energy Balance 1977 Energy Use Bristol Bay Communities - Future Electric Energy Requirements Potential Hydrosites in the Bristol Bay Area Wind Generator Energy and Power Output Bristol Bay Communities - Potential Electric Energy Resources 1990 Power Requirements and Energy Cost Estimates for Various Resources BALANCE AND EXISTING SYSTEMS 1977 Energy Use Use of Information Sources AND ELECTRIC POWER RESOURCES Potential Hydro Sites Measured Average Windspeeds Expected Average Windspeeds WECS Mean Power Output Average Power Output of Two Typical WECS Wind Generator Power & Energy Output XS-4 XS=5-6 *S=9-10 XS-12-13 XS-17 XS-20 XS-21-22 11-34-35 11-36 1V-163-164 IV=195 1V-196 1V-198-200 1V-201 1V-203 ~ 1Vz9 1V-10 IV-11 nV Vets IV-14 [Ve15 1V-16 APPENDICES A-1 Bee Booed Dota D-6.1 D=1051 LiSd OF GABLES (Continued) Bristol Bay - Solar Energy Allowable Electric Energy Cost for Comfort Heating Diesel Fuel Cost in 1977 Allowable Hydro Investment Allowable Investment for Wind Energy Systems Electrical Energy Cost for Various Generating Systems Bristol Bay Potential Electric Energy Resources i 1990 Power Requirements and Energy Cost Estimates Energy Usage of Appliances Line Loading Limits Average Power Output - Polynominal Coefficients for Contemporary WECS Parameters for Cost Benefit Evaluations Transmission Tie Lines Fuel Rates for Varying Speeds and Load Ranges - xi - Page 1V-210 bVieen2 IV=217 - IV-223 1V-227 1V-230 1V-233 1V-234-236 A-294 B-s25 B-347 D-457 D-466 D-485 EXECUTIVE SUMMARY Page XS-1 |. EXECUTIVE SUMMARY A. INTRODUCTION This study has been conducted under contract 85-79 AP 10002.000 for the U.S. Department of Energy, Alaska Power Administration. Part | - this part of the study - consists of establishing the Energy Balance for 1977 Electric Power Requirements to the year 2000 Potential Energy and Electric Power Resources Evaluation of the Electric Power Resources Recommendations for developments or future studies for the Bristol Bay Area. Fossil fuels are presently used to satisfy almost all energy demands. Emphasis in this study has therefore been placed on possible resources that can replace or at least supplement the use of increasingly costly fuel oil. The report is based on information available from existing reports, publications, maps and verbal communications with people who are familiar with the area. The study area is shown on Figure I-1 and the communities addressed are listed on the map. auasea COMMUNITIES CLARK'S POINT CHIGNIK CHIGNIK LAGOON CHIGNIK LAKE DILLINGHAM EGEGIK EKUK EKWOK IGIUGIG IVANOFF BAY ILIAMNA KOKHANOK KOLIGANEK LEVELOCK MANOKOTAK NAKNEK / KING SALMON NEWHALEN NEW STUYAHOK NONDALTON PEDRO BAY PERRYVILLE PILOT POINT / UGASHIK PORT ALSWORTH PORT HEIDEN PORT MOLLER TOGIAK TWIN HILLS Page SX-2 ivr Anenor 4 Chintes pr He 49, Mey. 0 Kakhonsic 2p Chenik * \ MT covatas 4A Unni Quzinkic? Kooian/? KOD ¥ >" >" +4000) roo ISLAN, Ren Larsen Bay 2 ¥ ew Bases Ro Avakulik® 20id Harbor Akio on Sitkalidak 1 Black Point ae © Rasuyak Tugidak reas, Sithinak | Ty 1S qainitY 1S Chirikot 1 SEGUGEEOGEOREe BOUNDARY OF STUDY AREA BRISTOL BAY REGION VICINITY MAP FIGURE I -1 932 Page XS-3 } B. ENERGY BALANCE To establish a base and understanding of energy use in the Bristol Bay Region an energy balance has been compiled for the year 1977. Although a great amount of data used in this balance had to be based on estimates and interpolations, the results are judged to be representative for the area. Energy forms used are diesel fuel, gasoline, aviation gas, jet fuel and propane. It is recognized that coal, wood and wind constitute energy sources which have been used on a small scale. Utilization data has not been available, however. The following graph summarizes the total energy use in the Bristol Bay area by energy form and end-use category while the subsequent table lists the use by energy form and end-user category. Energy use in the individual communities has been listed by end use category on the following table. The industrial use addressess energy use in the fish processing industry exclusively. This table also includes the total amount of diesel fuel, gasoline and electric energy used with their respective unit cost where available. The cost for energy listed does not include jet fuel, aviation gasoline and propane, for which cost could not be obtained. BIGU RE=-2 WASTE HEAT GASOLINE AV GAS 24% vET FUEL, PROPANE & DIESEL | FUEL 76% FUEL 7.0 x10 GAL. ENERGY IN BTU-100% =1260 x 10 BTU P ALL PERCENTAGES BASED ON TOTAL “INPUT EFFICIENCIES ASSUMED: TRANSPORTATION 0% ELECTRIC GENERATION 30% INDUSTRY 8 HEATING = 70% BRISTOL BAY - ENERGY USE IN 1977 FIGURE I -2 BRIS4/A1 TABLE I-1 ENERGY BALANCE - 1977 BRISTOL BAY AREA TOTALS a CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10%8TU 10%8Tu/—— 10% Tu/-—2 10°a Tu/—® 10°BTus-—8 1oeeTu/—t— Ave—Kuh ave. 4 of 10°BTU 10°BTU 10°BTU 10°BTU EBT age kWh Total TYPE No. 1,566,557 692,572 46,511 hc 1,131_/ 3,954 308.4 RESIDENTIAL = 1,134 ARTE aa ghee Tokens -0- 0 sagt ets Te hepa Sere 1,231,525 524,909 oe 225,175 978,007 233 / 4,342 391.9 COMMERCIAL 235 165.956/na 66.664/na 0 31.074/na 724,207/na 1,553 Layee sia 1,939,934 125, 459 ard =o — 28 / 4,421 283.6 cn 300 -26T-7657na_— 15.9337 o s o 73, 156 Waa 22.5 FISHING 598,005 . aaa on = Nea na 4 na 82.5 VESSELS os 82.505/na =) 0 3 9 na na y PUBLIC 323,395 98 / 1,175 44.6 BUILDINGS es 44.629/na ei0z -0- SAS = OF eee «|S 1,074,679 1 6,660 148.3 MILITARY 1 -0- -0- -0- -0- sso “148-3667 “ na =e 6,734,095 1,342,940 46.511 225,175 978,007 1,491_/ 20,552 1,259.4 TOTAL 1,498 926°374.73"* = 770.676. 327% 4.2/na 31. 1/na 124.2/na 1.149 7-17.9% = 100.0 % of Total BTU 73.8 185: 0.3 2.5 9.9 incl in Diesel 100.0 CANNERY incl in large incl in large 13 2,800 (self generating) users users Ur na ne 100,000 na REMARKS: Na ~ not available * - 5 communities reporting ** - average of available data TASEE [se 1977 ENERGY USE ELECTRIC TOTAL DIESEL GASOLINE ENERGY _—_Energy* Energy Use 10° BTU MWh 10° BTU's J of Total Energy Gal. X 10% BTU's X 10° Gal. X 103 BTU'sx10® = ¢7kWh Primary ELEC- “Ga. «$§/7i0' BTU ~ $/Ga. $710" BTU Energy* HEATING & INDUSTRY TRANSPOR- TRICITY LOCATION (Average) _1000-$_ HOME USE PROCESSING TATION GENERAT. TOTAL Dillingham 1764.8 243548 485.1 61608 4769 305156 115.40 10.48 175.64 58.79 360.31 "a 4.36 ia oA W3.7 1,413.6 Ben 1 49 ae 100 Naknek - King Salmon 3042.2 419818 516.2 65551 11691 485369 175.36 99.02 173.39 139.84 587.61 7 4.71 = 5.83%e* Ts 235.5 30 aD ee, 24 100 Niamna 172 23739 6.6 838 666.2** 24577 8.00 0 838 15.81 24.62 -69 5.0 os io “Ts” 123-6 33 6. oc “be” "700" Newhalen 63.47 8759 9 1143 205** 9902 4.84 0 1.14 3.98 9.96 69 7) 315 a) == 50.5 “a9 0 i) 40 “700 Nondalton 65.6 9051 21 2667 129** 11718 5.23 0 2.67 3.96 11.85 15 a4 T.47 70.62 = 113.4 44 6 23 33 100 Nushagak Bay Clark's Point*** 58.1 8016 ag 1143 152.7** 9159 4.92 0 1.14 2.16 9.22 resi aie = “Shree =. ear 3 2 7 “00 Ekuk*** 12.6 1745 4.8 610 21.3** 2355 142 0 61 65 2.38 65 1 755.9 == 71.8 4 “oC 26 2 “a7 100 Manokotak. 104.2 14386 25.2 3200 197.8 17,586 9.84 0 3:2 4.7 17.74 -58 , 68 5.35 Sracrls G7tS “56 6 “6 6 “100- Portage Creek*** 37.3 5150 6.6 838 83.3** 5988 3.39 0 84 1.8 6.03 Ss 3.o78+* = 7. 08+** ose 26.7 6 6 4 30 “700 Peninsula ~ Bristol Bay Egegik 307.3 42414 1 1408 101.9 43822 4.01 23.49 1.41 14.91 43.90 Pri 5.21 | 7.87 “18.4 232.7 “a0 “34 ao raat 100 Pliot Point*** - 46.4 6398 11.4 1448 101** 7846 4.12 0 1.45 2.35 7.92 Ugashik aa 521 Cie 5.3 = 4.5 “S2- 6 Te “30 “700 Port Heiden*** 45.2 6242 9.6 1219 90.6** 7461 4.27 0 1.22 2.03 7.52 er 4.42 “38 6.25 = 3.2 “oT 6 16 et 100 Port Moller*** 1g 1805 4.8 610 23.2** © 2415 1.12 0 -61 7 2.44 we 7 aaee* -- 525+ == 7.8 “ae 6 a. oe 7 Peninsula - Pacific Side Chignik*** 54.6 7536 9 1143 152.6 8679 4.42 0 1.14 3.18 8.74 oF 3.62 TO TT Roger 9, S600) oe 6 aS e “700 Chignik Lagoon*** 43.6 6023 9 1143 98.8** 7166 3.80 0 1.14 2.28 7.22 a 3.62 TO 78) == 30.6 Be 6 Te a “7100 oG-SX 39Wd 1977 ENERGY USE (CONTINUED) en ELECTRIC TOTAL DIESEL GASOLINE ENERGY Energy* Ener; Use 10® BTU MWh 10° BTU's ¥ of Total Energy Gal: X 103 BTU's X 108 Gal. X_ 10% BTU'sx10® = ¢7kWh Primary ELEC- $/Gal. $/108 BTU $7Gal. $710" BTU Energy* HEATING & INDUSTRY TRANSPOR- TRICITY LOCATION (Average) _1000-$ HOME USE PROCESSING TATION GENERAT. TOTAL Pacific Side (Cont.) Chignik Lake*** 71.8 9906 15 1905 167.4** 11811 6.39 0 1.91 3.6 11.9 5 3.62 a 55° = 48.1 “34” 0 “Te 30 “700 Ivanoff Bay*** 17.4 2399 6.6 838 25.7** 3237 1.65 0 84 279 3.28 -61 4.42 = 6.29++* = 15.5 50 0 26 24 “100 Perryville*** $3.7 7416 15 1905 109.7** 9321 4.88 0 1.91 2.61 9.40 7 5.07 1 8.66 = 54.1 52 0 20 “28 “100 Togiak Togiak 213.9 29514 56.4 7163 512.1 36677 20.11 227 7.15 9.50 37.03 -85 6.15 9 7.08 22.8 232.2 “34 1 “79 26° “100 Twin Hills*** 59.7 8234 9.6 1219 144.5% 9453 5.39 0 1.22 2.9 9.51 -85 6.15 9 7.08 == 59.3 7 0 “a 30 “700 Igiugig 34.8 4812 1.2 914 79.1** $726 3.18 0 91 1.68 5.77 “ea 5.07 94 TA “= a1 55 0 “16 cs "100 Kokhanok 59.7 8234 9.6 1219 144.5** 9453 5.39 0 1.22 2.9 9.51 we 5.07 76 5.98 = 49 37 6 3° “30 “100 Pedro Bay*** 51.1 7053 13.2 1676 105.3** 8729 4.65 0 1.68 2.48 8.81 7a 5.21 “T.0 7.87 wes 49.9 33 0 13° “28 “700 Port Alsworth 25 3446 3. 381 68.9** 3827 2.18 0 238 1.27 3.85 =- 5.2144 == T.B1*** == 20.9 7 0 10 33 “700 Inland Ekwok*** 23.9 10197 15 1905 167.4** — 12100 6.68 0 1.91 3.6 12.19 754 3.91 3 7.08 == 53.3 5 0 1S “30 100 Levelock*** 78.6 10852 16.8 2133 qer* 12982 7.21 0 2.13 3.74 13.08 243 3.11 -53 4.17 == 42.6 35 a Te ri 700 New Stuyahok 97.8 13507 25.2 3200 203.2 16700 8.83 0 3.2 4.83 16.86 a) “5.79 T.71 8266 23 105.9 52 0 “79 “2” “700 Koliganek*** 66 9106 12 1524 160.1** 30629 5.80 0 1.52 3.38 10.70 = 5.79++* = B66 ++* == 65.9 “$a” 0 a4 “32° 100 TOTAL 6734 929306 1343 170552 20544 1099858 433 133 392 302 1260 -65 4.73 “80 6.32 17.9 5,471.8 34 7 3 24 700 Total® in 1000$ (Approx. ) 4,394.2 1,077.6 1,860.4 601.9 1,696.3 1,313.2 5,471.8 - Jet Fuel, Propane and AV Gas & Electricity not included. ** Private Generators only. No Central power plant. *** Estimated data. 9-SX JdVd Page XS-7 The following communities had reporting central electric utilities -in 1977: Dillingham, Naknek/King Salmon, Egegik, New Stuyahok, and Togiak. In other villages school generators and fish processors supplied several residences part of the year. Operating data for these communities is not available. C. ELECTRIC ENERGY DEMAND PROJECTIONS The electric power requirements to the year 2000 have been projected for the individual communities with high and low load growth scenarios. It is anticipated that the realization of either will depend partly on the real! cost at which electric power is available to the consumer. Development of the fishing industry has been taken into account by assuming the local processing to continue at the present level but with increased use of utility power for the low load cases, and increasing the capacity of local processing facilities and their energy . use for the high load growth scenarios. The change to fresh freezing of fish by many processors is expected to replace some of the canning and therefore not change the energy balance substantially. Residential and commercial consumers are expected to observe reasonable energy conservation measures but an increase in electric energy use is anticipated due to the still low level of electrification in the entire region. Possible oil - and gas exploration activities are not expected to impact the present communities to a great extent, except for a moderate population increase and the development of staging areas. Actual development of a reservoir is difficult to predict at this time and would probably change the entire aspect of this study. Figure !-3 "Bristol Bay - Power Requirements" shows the anticipated population and consumer growth as well as electric energy use increase to the year 2000 for the entire area. The table following the graph lists the projected power and energy demand for the individual communities. It has been assumed that eventually all communities will have central power plants and that fish processors will be supplied by the central plant rather than continue to generate their own electricity. The meaning of real as used here means cost after adjusting for inflation in the general economy. BRISTOL BAY POWER REQUIREMENTS FIGURE I-3 ' ~ —+ — 4 1970 1977 1980 198665 1390 1995 2000 JUNE 1979 LOCATION 1977 Clark's Point Chignik Chignik Lagoon Chignik Lake Dillingham Egegik Ekuk Ekwok Igiugig Ivanoff Bay Hliamna Kokhanok Koliganek Levelock TABLE I-3 BRISTOL BAY COMMUNITIES FUTURE ELECTRIC ENERGY REQUIREMENTS kwW_- Power Demand MWH - Energy Demand 45 143 ao) 153 30 39 _50 167 1200 4769 =| Oo AID NIO ae da & aaa ul nN | fez) | ele 3 ls alg o Ao a “I nN 1990 600 (55) 1574 (191) 570 (370) 2495 (1631) 405 (55) 17753 (191) 115 (63) 403 (220) 3960 (2580) 19080 (11070) 1360 (690) S591 CIS) 308 (233) 269 (203) 130 (62) 457 (218) 85 (48) 292 (166) 392 (150) 1715 (524) 660 (400) 2887 (1761) 91 (50) 320 (176 150 (58) 523 (206) 180_ (65) 629 (228) Page xXS-9 (low load growth) 2000 850 (250) 2215 (883) 1120 (390) 4928 (1703) 1120 (260) 4928 (1183) 175 (69) 764 (300) 8660 (3650) 45516 (15972) 1400 (770) 3692 (1683) 930 (287) 1628 (378) 345 (68) 1507 (297) 120 (53) 528 (232) 1100 (260) 4788 (1149) 1720 (490) 8270 (2149) 140 (56) 612 (246) 345 (88) 1505 (386) 290 (105) 1267 (458) LOCATION Manokotak Naknek/King Salmon Newhalen , New Stuyahok Nondalton Pedro Bay Perryville Pilot Point/Ugashik Port Alsworth Portage Creek ‘Port Heiden Port Moller Togiak Twin Hills TOTAL *Noncoincidental Peak. TABLE I!-3 (Continued) kW_- Power Demand MWH - Energy Demand 1977 rh = L ox So Co} Co oO = =i - OD nN oO = ny oO} rN} a3 Wo ov w NX ro le ae § ul ao oO —s wo = o oO = oO =i g|8 wolo Sle WL dle sls —_ un oO uo pp» = a wn =j B Bl 1990 290 (80) 1018 (271) 6120 (3830) 30002 (18770) See Iliamna 186 (100) 53 (2 See Iliamna 104 (60) 457 (210) 430 (165) 1902 (580 680 (370) 1492 (651 68 (41) 236 (144) 80 (45) 275 (156) 92 (74) 400 (256) 460 (214) 2478 (749) 1100 (560) 3857 (1227) 95 _(S0) 3317)\C176) 18711* (10468 )* 79051 (41772) Page XS-10 Clow load growth) 2000 560 (120) 2439 (523) 9740 (4700) 51180 (23076) See Iliamna 390 (110) 7713 (488) See Iliamna 240 (66) 7055 (289) 1200 (400) 5339 (1740) 900 (415) 3047 (725) 88 (50) 384 (204) 107 (50) 468 (224) 400 (75) 1772 (326) 500 (233) 2604 (818) 1700 (790): 7402 (2076) 270 (56) 1172 (246) 34410* (13861)* 160723 (577/54) Page XS-11 D. POTENTIAL ENERGY RESOURCES Energy and power resources are abundant in the Bristol Bay Region. In hydro potential alone this study identifies a total capacity of more than 230 MW (>2000 million kWh annually) in the region. This compares to total estimated requirements of 35 MW (160 million kWh annually) projected in the year 2000 if high load growth is assumed. Geothermal potential is roughly estimated at more than 400 MW for just four possible sites on the Alaska Peninsula. Recoverable coal resources could produce approximately 50 million kWh annually for 100 years. Wind and other solar energy resources are of course present but are not assigned a specific value because of insufficient credible data. The resources which have been identified in this study are listed with their possible potential and restraints in respect, to development. Tis Hydroelectric Resources The following table lists the resources identified from U.S.G.S. Maps (Scale 1:63360), their estimated capacity and cost of installment. The most promising sites for further investigations have been found to be: Prime Number Capacity Site On Table (MW) Lake Elva 11 96 Grant Lake 5 T.38) Lake Tazimina 36 15* Chignik #1 27 “4 Chignik #2 27 wit *First stage. TAB WE |) ea POTENTIAL HYDROSITES tn THE BRISTOL BAY AREA Firm Cost-Total* Installed Drainage Aver. Flow Energy Installed 1979-$x 1000, Cost/kW USGS M Areay || MEH (CFS) Annual Capacity (MW)_ Annual Cost Prime jap rea ¢ 1, = SITE 1:63360 (Sq. Mi.) (Ft.) Regulation (MWH) Plant Factor 1000-$ *#** (1979-$) — Restraints*** ww NUSHAGAK BAY/WOOD RIVER - TIKCHIK LAKES 1 Algnak River Mliamna A-8 480.0 170 1250 45,552 as 23.900 5,750 18 35 : 2 Agulowak River Dillingham B-8 BULB TURBINE SITE 3 3 American Creek Mt. Katmai D-4, 98.2 800 200 99,513 2x12 35,850 3,156 1 0-3, C-4, C-3 700 47 2,606 4 Chikuminuk Lake Taylor Mtns A-8 290.0 100 850 52,560 2x6 34.30 5,233 2,4 100 5 ’ 5 Grant Lake Dillingham D-7 37.2 215 92 12,132 1,5** 6,691 4,831 2 ? 700 92 “486 6 Idavain Lake Mt. Katmal C-6, 0-6 26.6 685 41.5 17,520 2x2 15,065 7,532 1 Naknek C-1 “100 “50 1,095 7 Kontrashibuna Lake Lake Clark A-4 200.0 220 880 120,450 2x14 46,940 3,414 1 700 49 3,413 8 Kukaklet Lake #1 Niamna A-7 480.0 330 20 122,640 ext 29.818 1,057 1,3 5 115 Kukaklet Lake #2 Mliamna A-7 140 oe 52,560 ee 12,665 1,055 1,3 7 5 $21 9 Kvichak River Dillingham A-2 BULB TURBINE SITE 3,5 10 Lake Brooks Mt. Katmai C-6 N/A 20 300 3,591 .4 1,710 4,171 1 100 100 124 n Lake Elva Goodnews C-1 10.0 275 + 8, 409 a 8,730 7,010 2 12 Lake Grosvenor Mt. Katmai C-4, 630.0 85 950 49,494 2x6 21,025 3,721 1 c-5 700 47 1,52 13/14 Naknek Lake/River Naknek C-2 2720.0 90 5400 297,840 2x34 37,580 1,105 3 “100 “50 2,732 15 Nayakuk - Tikchik Dillingham D-8 1486.0 180 3340 367,920 2x45 134,435 3,200 2,3 Lake “706 ‘ a7 3,773 16 South Fork Mt. Katmai B-2, 29.9 400 85 12,702 2x2.5 13,460 9,283 1,4 Savanoski River B-3, C-2, C-3 60 a ~o- 7 Upnuk Lake Taylor Mtns B-8 100.0 150 oe 27,594 2x3 23,730 7,533 2,4 1 5. 1,725 ALASKA PENINSULA - BRISTOL BAY SIDE 18 Creek Port Moller D-2 14.5 300 22 4,029 2x.45 5,390 8,370 3 Chignik A-8 700 Psi “392 é 19 Becharof Lake Naknek A-3 BULB TURBINE SITE 1,3 20 Hot Springs Creek Ugashik C-2 5.9 800 aio 14,454 2x1.65 9,750 5,909 4 1 50 709 , 21 King Salmon River Chignik A-7, A-8 388.0 100 58 3,504 2x.4 5,030 12,575 3 Port Moller D-1, D-2 700 “30 “366 22 Landlocked Creek Chignik C-1, C-2 15.5 200 fe 7,358 ae 4,615 5,494 5,4 ZL-SX abe ‘ POTENTIAL HYUROSITES iN ' HE BRISTOL BAY AREA (CONTINUED) Firm Cost-Total* Installed ‘ Drainage Aver. Flow Energy Installed (4979-$x1000) — Cost/kw USGS Map Area MEH fers) Annual Capacity (Mw) Annual Cost Prime * SITE 1:63360 (Sq. Mi.) (Ft.) Regulation (MWH) Plant Factor 1000-$ **** (1979-$) — Restraints*** Reindeer Creek Chignik D-1, D-2 27.6 100 55 1,752 2x.2 5,120 25,600 © 50 ‘ 50 S72 : ALASKA PENINSULA - PACIFIC COAST Unnamed Lake Mt. Katmal A-2 1.7 730 70 28,601 2x3.5 9,335 2,859 1,4 near Hidden Harbor 90 47 679 Dakavak Lake Mt. Katmai A-2 28.0 240 168 25,053 2x3 7,900 2,762 1,4 A-3 700 “4B $74 Kirschner Lake Iliamna B-3 13.8 100 83 5,081 58 1,456 4,853 4 700 100 106 Chignik #1 Chignik B-2 2.8 460 22.4 6,219 2x.7 3,475 2,482 5 700 sO 253 : Chignik #2 Chignik B-2 4.3 170 34.5 3,591 2x.4 3,015 3,768 5 “700 7 219 Two Lake #1 Ugashik C-1 2.6 180 13 1,435 3x.3 4,995 11,352 1 700 49 363 Two Lake #2 Ugashik C-1 4.4 180 22 2,409 3x.3 4,995 11,352 1 700 49 363 Lake near Devils Mt. Katmai B-1 14.4 80 120 5,913 2x.7 2,770 4,104 1,4 Cove 100 ‘ 8 ann ILIAMNA/LAKE CLARK Copper River - Hliamna C-3 26.6 100 130 7,971 2x.75 4,935 5,423 5 Meadow Lake c-4 700 359 Kokhanok River ijamna B-4 + 145.0 45 400 5,519 2x75 §,350 8,492 5 i B-5 “50 42 389 Koksetna River Lake Clark B-6 160.0 155 465 17,520 3x3 19,880 3,898 4,5 “39 pee 1,445 Lachbuna Lak« Lake Clark B-3 168.0 1100 495 205,000 3x25 103,000 2,664 4,5 achbun. ake “a 31 “7,488 ° Summit Lake #1 liamna C-2, C-3 11.4 390 68.5 16,644 2x2 8,395 4,418 5 D-2, D-3 100 “48 “610 Summit Lake #2 18.5 390 im 26,280 2x3 16,350 5,450 5 Hiamna 706 “50 1, 185 Lake Tazimina lliamna D-5 320.0 300 1,440 131, 400 2x15** 34,445 2,296 s (ist Stage) 50 50 2,504 Newhalen River Hliamna D-6 3,300.0 35 9,303 192,720 2x20 79,939 3,634 3 “T00- : s or ¥ Exclusive of R-O-W, Substation, Transmission. mg Partial Development. +** Restraints: 1. Located in National Monument 2. Located in State Park. 3. Important fish spawning or migration area. 4. Remote location, distance to loadcenters. 5. Located in wilderness study area. **** Based on: 35 years Loan with 5% interest, quarterly payments. - 1979 Base 1% O&M, .2% insurance (7.27% total). €l-sx abeg Geothermal Resources With almost no field data available, assessment of this resource is Occurrences in presently sparsely populated areas and difficult. Page XS-14 great distances from potential load centers in combination with high cost are severe restraints for development in the near future. Location Development CUS. GySi Cost, 1,000-$ 1:250,000 Map) Potential (approximately) Restraints Mt. Katmai 100 MW 50,000 - 200,000 1, 3, * (Mt. Katmai) Mt. Peulik 100 MW 50,000 - 200,000 ly oe (Ugashik) : Mother Goose Lake not determined - Cys fed (Ugashik) Aniakchak not determined - Apes a (Chignik) Black Peak 100 MW 50,000 - 200,000 2, 4 (Chignik) Mt. Veniaminof 100 MW 50,000 - 200,000 ius (Chignik) Staniukovich not determined 2,4 (Pt. Moller) Port Moller 80 gallons/minutes not determined 5 (Pt. Moller) 60°C : Port Heiden warm spring not determined 5 (Chignik) Iniskin Peninsula 5 MW not determined 27 4 Clliamna) Restraints: located in National Monument located in Wilderness Study Area distance to load center(s) cost of development only marginal utilization UPWNe iouu wou Page XS-15 i Coal Resources Aside from occurrences noted in petroleum exploration wells along the north shore of the Alaska Peninsula the following coal fields have been identified. Location ¢ Development (U.S.G.S.-Map Potential - Recoverable Cost 1,000-$ 1:250,000) & Rank 3 (approximately) Restraints Chignik ~ 100x108 tons 25 $ 14 - 58/ton 1,°3 (Chignik) bituminous : Herendeen Bay 10 - 100x10® tons 25 not determined 17c2p 8 (Pt. Moller) bituminous Unga Island not determined - ~ QS (Pt. Moller) Lignite Restraints 1 = located in Wilderness Study Area 2 = distance to load centers 3 = cost of development & operation 4. Oil & Gas Resource Estimates and exploratory data indicate the following potential: ; Oil (10° Barrels) __Gas (1012 Cu. Ft.) Province Onshore Offshore Onshore Offshore Bristol Bay Tertiary 0 to .94 Oto 255 0 to 6.8 0 to 5.4 Alaska Peninsula 0 to 1.1 - Oto: 12-0 - Zhemchug - St. George - ORtovoe1 - 0 to 13.0 Cook Inlet Onto. 93 0 to 2.3 0 to 6.67 0 to 11.68 Kodiak & Shumagin 0 to 2.4 = 0 to 17.5 Development of the resource and its impact cannot be assessed at this time due to lack of firm data on their occurrences and the anticipated adverse impact on fisheries. - Page XS-16 Uranium Anomalies have been reported near Lake Nunavaugaluk (U.S.G.S. - Map 1:250,000 - Dillingham) and Lake Kontrashibuna (U.S.G.S. - Map 1:250,000 - Lake Clark). The available data does not allow a more detailed assessment of this resource. Wind Energy Resource The following average wind speeds have been recorded for various locations in the Bristol Bay area: Expected Average Recorded Average Annual Windspeed Annual Windspeed at 60 Ft. Height Location Height (Ft.)/Speed (MPH) (MPH) Dillingham 30 / 10.7* 12.5 Hiamna 33 / 10.4 11.7 King Salmon 38 / 11.4 12:5 King Salmon 26 / 10.5 12.4 Port Heiden 29 / 14.8 TZ 2 Port Moller 25 / 10.2 12.2 Ocean Area 33 / 14.8 - The listed averages are based on data recorded for 5 years or more. * 6 months in 1978 only. The following table shows the possible power output for various sizes of wind energy conversion systems (WECS) and the associated cost. This energy is secondary in nature since it does not include any provision for firming the variable output of the wind units. Page XS-17 TABLES. =.5 WIND GENERATOR ENERGY AND POWER OUTPUT FOR SELECTED LOCATIONS, IN THE BRISTOL BAY AREA Installed? Cost $ Output Se 3 Secondary Av. Annual aS ee Energy Cost Location Wind Speed? ¢/kWh 1.5 KW RATED GENERATOR King Salmon/ 12.5 0.4-0.6 9,440 79 Dillingham 4.32 3,403 lliamna 11.7 0.3-0.7 9,440 86 3.96 3,403 Port Heiden 7.2 02575) 9,440 55 6.24 3,403 15 KW RATED GENERATOR King Salmon/ 1255 2.7-4.0 35,220 23)" Dillingham 28.91 6,550 lliamna AIEa7: 1.7-5.7 35,220 26 2534 6,550 Port Heiden 17.2 a erse 35,220 12 52.56 6,550 100 KW RATED GENERATOR King Salmon/ 125 31-42.2 226 ,000 10 Dillingham 321.49 32/505 Hliamna ed 21.8-54.3 226,000 11 288.2 32,595: Port Heiden Wise 43.5-62.6 226,000 7 490.50 32,595 Notes: Investment cost and maintenance cost are based on manufacturer's in- formation with very little field data from Alaska available to verify these assumptions. 1 At 60' mounting height. 2 From Appendix C.4. Assumes cogeneration (no energy storage). 3 15 year loan, 9% interest (.1221 cap. recovery factor) plus maintenance $2250 per year for 1.5 kW and 15 kW; $5000 per year for 100 kW. Page XS-18 Other Resources This section addresses possible replacement or suplementation of diesel fuel utilized for heating purposes. This use-category represented 34% of the total energy used in 1977 in the Bristol Bay Area. fae Solar Energy: Insolation data for the Bristol Bay area has not been compiled yet. Data-compiled for the Bethel area indicates that with proper design considerations passive solar heating can provide 40% of the heat required by an average residence (900 sq. ft.) even in November/December. Active Solar heating by utilization of collectors and heat storage facilities installed into a newly built home has been found to be competitive with a fuel oil furnace only if the cost for diesel oil would be more than $2.50/gal at present equipment cost. Solar Voltaic energy conversion is still uneconomical at an estimated $1/kWh at the present state of the art. Wind Energy for Waterheating: It is conceivable that wind energy could be more efficiently utilized by heating water than by generating electricity, where storage and conversion require special investments. However, a comparison of the energy requirements for a residential hot water supply with the cost for a wind energy system - utilizing equipment designed for electric energy generation - and an oil-fired heater shows that fuel oil would have to rise to more than $5/gal before a wind heating system would become economically viable. If the wind/electric energy conversion technique is utilized without consideration of speed and frequency it is anticipated that a wind energy system can compete economically with an oil fired heater. Tidal Power: With tidal ranges as high as 31' and currents up to 5 knots in Nushagak Bay a potential for tidal power is conceivable. Severe icing conditions during the winter- months preclude development with presently known technology, however. Biomass: The only resource of significance in this category is wood. The southern and western limit of wooded country leaves most of the area south of Dillingham and Naknek treeless. Resource information available for the wooded areas in the Tikchik/Wood River Lakes, the Iliamna area, and Nushagak River drainage is not sufficient to allow assessment of possible utilization. Page XS-19 Bs POTENTIAL ELECTRIC POWER RESOURCES Utilization of any one of the previously listed resources depends on economic feasibility, land status of the site, and environmental considerations. Location of several resources within national monuments precludes development in the foreseeable future as does possible disturbance of the fisheries if mitigation cannot be achieved. Economic feasibility is mostly determined by the cost of construction for the necessary facilities, the cost of operation, and the intensity of use in relation to capacity of the project - e.g. it will not be economically © feasible to build a 30 MW facility to supply a .4 MW damand. The above considerations eliminate most hydro and geothermal sites. Wind and solar energy conversion devices presently on the market still prove too expensive and unreliable to allow utilization as a "stand alone" and reliable electric energy supply. At the present state-of-the- art it appears that these two resources should best be used to supple- ment conventional heating and electric energy supply systems. A brief investigation of the cost for a transmission tie to the South- central Alaska systems in the Anchorage area shows that the energy cost in 1980 would be approximately 14¢/kWh at the distribution bus in Dillingham. This compares to approximately 8-9¢/kWh for local diesel generation. The following table 1-6 "Potential Energy Resources" lists the Bristol Bay Communities and the electric energy resources economically available to them. Economic evaluations have been based on comparisons with diesel generating cost. To show the approximate cost for electric energy in the communities, estimates of annual and per unit cost for the various resources for the year 1990 are listed on table |-7 "1990 Power Requirements and. Energy Cost Estimates". It should be noted that by choosing a specific year to show this type of data, imbalances are unavoidable. The data listed constitutes a comparison in magnitude of cost only. TABLE 1-6 BRISTOL BAY COMMUNITIES POTENTIAL ELECTRIC ENERGY RESOURCES Page XS-20 POTENTIAL ECONOMIC ENERGY RESOURCE LOCATION HYDRO GEOTHERMAL Clark's Point Yes* No Chignik Yes ss Chignik Lagoon Yes* re Chignik Lake Yes* ae Dillingham Yes No Egegik Yes* No Ekuk Yes* No Ekwok Yes* No Igiugig Yes* No Ivanoff Bay No | am lliamna Yes* No Kokhanok No No Koliganek Yes* No Levelock Yes* No Manokotak Yes* No Naknek/King Salmon Yes* No Newhalen Yes* No New Stuyahok Yes* No Nondalton Yes* No Pedro ‘Bay No No Perryville No ee Pilot Point/Ugashik No No Port Alsworth No No Portage Creek Yes* No Port Heiden No bail Port Moller Marginal aad Togiak No No Twin Hills No No - With transmission-intertie. a Insufficient data available to assess. COAL No Yes Yes Yes* No No No No No ** No No No No No No No No No No OK No No No No No No No WIND Yes 2K aK aK Yes Yes x KK 2K 2K Yes *”K *K 2K x Yes *K *K ** 2K aK Yes Yes KK Yes Yes Yes 7K wwewwewewwewewewr-e- - - ~ - BRIS4/J1 TABLE |-7 1990 POWER REQUIREMENTS AND ENERGY COST ESTIMATES Location ———— Dillingham Naknek-King Saimon iamna Newhalen Nondaiton Nushagak Bay Clark's Point Ekuk Manokotak Portage Creek Peninsula-Bristo! Bay Egegik Pilot Point - Ugashik Port Heiden Port Moller Peninsula-?: Side Chignik Chignik Lagoon Chignik Lake 1990 Energy - Cost? FOR VARIOUS RESOURCES Page XS-21 4900 MwH Annual —1000-§ necuiroments Diesel® with High Transmission Low Diesel® intertie Hydro? Coal wind* 19080 1472 n.d.7 1432_- 2175 N/A n.d), 8.80 T1070 13.3 17.4 - 18.8 10-23 30002 2496 n.d.7 2459 - 3529 N/A nares” 18770 13.3 17.4 - 18.8 10-23 2887 493 N/A 389 N/A ncdit.2 2° 1761 “SB 73.5 - 22.1 11-26 1574 74 6&7 74 = 225 N/A n.d. 19T 38.5 35¢ 74.3 - 269 78 val 38 - 78 N/A n.d. 203 38.5 35 74.3 - 1018 104 95 105 - 146 N/A n.d. 27 38.5 358 74.3 - 275 60 55 39 - 60 N/A n.d. 156 38.5 35° 74.3 - 38.6 3591 584 531 $13 - 586 N/A n.d.7 § 10 1517 35 bie 74.3 - 38. 10-23 1492 731 N/A N/A N/A n.d.? & 10 651 i) 2 400 125 N/A n.d.7 N/A nid.? © 2° 256 “49 T2 2478 367 N/A 773 dates recat ete 743 “ss 32 - 103.2 T2 2495 457_- 799 473 1631 28 - & Rie 1778 53 - 94 55 565 - 599 998 n.d? 191 = 4 23° 2.8 - 7.7 2.4 403 62 - 108 64 220 28 - 45 299 Page XS-22 BRIS4/J3 TABLE 1-7 1990 POWER REQUIREMENTS AND ENERGY COST ESTIMATES FOR VARIOUS RESOURCES (CONTINUED) 5 1 = 1000- 1990 MWH 1990 Energy - Cost Annual 000-$ Requirements <r a a @"_— With High Transmission Location Low Diesei® Intertie Hydro? Coal? wind* Ivanoff Bay : 1715 147_- 257 N/A N/A n.d. n.d? 324 28 - 49 Perryville 1902 162 - 284 N/A N/A n.d.? n.d.? “380 28 - 49 Togiak Togiak 3857 344 - 601 n.d.7 N/A N/A n.d? 1227 28 - 49 Twin Hills 31 49 _- 89 n.d.? N/A N/A aids! 176 a 45 Niamna Lake Igiugig 292 64 58 42 _- 64 N/A insds® 166 385 358 14.3 - 38.6 Khokanok 320 86 N/A 700 N/A n.d.7 176 8 219 Pedro Bay 487 103 N/A n.d? N/A n.d.? 210 48 Port Alsworth 236 nm N/A n.d.7 N/A n.d.? 144 3 inland Ekwok 457 84 76 65 - 84 N/A n.d.? 218 38.5 if 74.3 - 38.6 Koliganek 523 79 72 75_- 80 N/A n.d.7 206 38.5 an 14.3 - 38.8 Levelock 629 88 80 88 - 90 N/A n.d.7 228 38.5 sae 74.3 - 38.6 New Stuyanok 653 108 98 93 - 108 N/A n.d.? 280 38.5 358 14.3 - 38.6 Notes: This table shows the results of cost evaluations utilizing the parameters shown below. The data should not be used in any decision making process without consulting the detailed report. + At local distribution bus - not at’ end users meter. 2 Operational in 1985, 5% interest on 35 years loan, 1% OSM, 0.2% insurance - range applies to various scenarios - lowest unit cost for "high" load growth only. 3 Operational in 1985, 5% interest on 35 year loan, 2% O&M, - "high" load growth only. 4 Operational in 1980, 9% interest on 15 year loan, 15 - 100 kW system in cogeneration only. s For “low” power requirements only; fuel cost escalation at 7% per year. ® Single wire Ground Return Trai ion, 40 kV - 9% interest on 35 year loan, .5% O&M - operational in 1980. 7 Not determined. i. Supply of up to 30% of system energy requirements. °, 24:9/14.4 kV Transmission - 5% interest on 35 year loan, losses neglected, operational in 1980. 1 Secondary energy only - this price cannot be directly compared to other systems. If sufficient energy storage (batteries) were added to make the wind energy truly a firm power supply, it is estimated that this price would gore than double. nna aa aoe Se Page XS-23 The following paragraphs will address the potential electric power resources and possible development plans for the regional areas. is Nushagak and Kvichak Bay Area The Elva, Grant and Tazimina hydro sites have the potential to supply 15 communities or approximately 65% of the entire regions demand with electrical and possibly heating energy for more than 20 years. The energy from Elva and Grant can be absorbed by an interconnected Dillingham/Naknek/King Salmon system as soon as it is built. Tazimina, although less costly on a per unit basis, cannot deliver energy at competitive cost into the load centers until the late 1980's or early 1990's. This is mostly due to the combination of low demand in the early years and the required long transmission lines to transport the energy to the Dillingham/Naknek systems. The future. cost of diesel fuel bs influences this analysis very much. If 10% per year escalation of fuel cost is assumed instead of the 7% used, immediate development of the Tazimina site is most prudent. If, however, conservative fuel escalation, high interest rates and low load growth are anticipated, the Elva and Grant installations should be pursued first. Only a more detailed study, which carefully weighs the influence of the various parameters, can determine the most beneficial development. The following graph shows the cost per kWh for the possible hydro developments. Page XS-24 GRANT LAKE 71.34W (TO ILLINGHA LY) — - = AT DILLINGHAM / WA! TAZIMINA FIRST DISTRIBUTION BUS STAGE |ISMW dhe TAZIMINA + BLVA|+ GR. beat LH cost|oF Die GEMER, \ 7% ANNUAL INCRE, Ww FUEL C (208 LAKE] ELvA|-IMW (ro DILLINGHAM ONLY ). i390 PROJECT ™~ _ os ——+—— AREA US HIGH) 980 T_ | 1990 2000 ~ 1 2 Shs en Tegeso 20 30-40 «5060 MB 3) 1 MWH ° 5 YR BRISTOL BAY HYDRO - DEVELOPMENTS — DILLINGHAM/ NAKNEK — 1985 - BASE FIGURE I-4 JUNE 1979 Page XS-25 The developments evaluated in this report have been assumed as follows: . Installed Transmission Length Project Capacity Voltage/# of Phases mi. OH/mi. Lake Elva 1x1.5 MW 24.9 kV/30 9/201 Grant Lake 1x1.5 Mw? 66 kV/193 654/ - Tazimina 2x15 MW 138 kV/3@ 1815/ - Submarine cable to Aleknagik. Low frequency, single phase generation. Single Wire Ground Return - Low Frequency. To Dillingham only. To Dillingham and Naknek/King Salmon. ar WN EH To extend the length over which transmission lines of a particular design can deliver energy at acceptable voltage levels, reduced frequency, single phase transmission has been examined briefly in regard to the technical aspects. This technique can increase the possible load or line length of Single Wire Ground Return transmission by almost 1/3 without a change in design and would make it possible to interconnect more remote communities, or develop hydro potentials which require long transmission lines to load centers. The Grant Lake development has been assumed with this technique. For 10 villages! in the Nushagak/Kvichak Bay area investigations have considered whether transmission interties to the Dillingham/ Naknek systems can supply these communities with less costly electric energy than locally operated small diesel plants. If the single wire ground return scheme is used, this solution appears to be viable even if diesel generation only is assumed for the supplying systems. Possibly available hydroelectric energy makes this solution even more attractive. The Tazimina hydro project can serve the communities of Iliamna, Newhalen and Nondalton via distribution lines and replace the use of diesel generation in these villages. Apparent wind energy potential in the bay area and in Iliamna can be utilized to supple- ment other generating means. Clark's Point, Egegik, Ekuk, Ekwok, Igiugig, Koliganek, Levelock, Manokotak, New Stuyahok, Portage Creek. Page XS-26 2. Peninsula - Bristol Bay Side Wind energy conversion appears to be the most promising alternative to diesel generation for the communities of Port Moller, Port Heiden, and Pilot Point/Ugashik. Hydro potential ("Unnamed Creek" with 460 kW prime) in the vicinity of Port Moller could be developed economically if the higher energy use load growth scenario materializes. 35 Peninsula - Pacific Side The Chignik Bay area is expected to experience accelerated development based on a year round fishing industry. Electric energy supply by full development of the hydro sites or the coal field with distribution interties from Chignik to Chignik Lagoon & Lake appear to be more economic than the continued use of diesel generation. A more detailed evaluation of the coal field and its mining is considered necessary to allow a better assessment of this resource in regard to the total energy picture in the area. lvanoff Bay and Perryville might have wind or small scale hyc-o potential, but assessment has not been possible due to lac data. Ay Togiak Bay Area Potential resources that could be developed economically within the foreseeable future have not been found. Wind energy potential is considered good, but specific data is not available. 2. Inland Low load levels and limited load growth make the development of hydropotentials Copper River, Kokhanok River, and Summit Lake for the communities of Kokhanok, Pedro Bay, and Port Alsworth uneconomical. Wind energy is expected to be available, aithough site specific evaluations will be necessary due to mountainous terrain. Fs RECOMMENDATIONS The most viable alternate energy source to supplement or replace the use of diesel fuel has been found to be hydroelectric energy. The necessary steps towards possible development area: Page XS-27 Tes Field investigations to determine geology, access, etc. 25 Feasibility studies to assess timing and cost for various development scenarios. The coal fields at Chignik Bay will have to be field assessed in regard to mining and market area. Only a more detailed cost study can compare the benefits of hydro or coal development in this area. The lack of firm data on the vast geothermal resources requires detailed mapping and geophysical tests, before development feasibility can be assessed more accurately. To assess the wind energy potential with more accuracy, measurements of wind speed and frequency in the various communities will have to be recorded for at least 1 or 2 annual cycles. Results of these measurements will allow people in remote locations, where diesel generation is the only other alternative, to evaluate the possible performance of wind generation systems in comparison to conventional energy generating systems. Operating data should be obtained from a demonstration project located in a more accessible area (Dillingham, Naknek, King Salmon), where maintenance and repairs are not made as troublesome as in a remote location. It is recognized that for several communities petroleum fuels appears to be the only viable energy resource. Here the efficient use of this resource cannot be over emphasized if costs for energy are to be kept as low as possible. Efficiency can be improved at the individual home level (weatherization, insulation, use of passive solar heat, etc.) and in diesel generating plants where waste heat utilization and variable speed generation can reduce fuel use and energy cost. As existing energy technologies are being improved and further developed and new technologies are introduced results of resource evaluations in this report may become obsolete and inadequate. Periodic review is therefore advised in order to maintain the usefulness of this study. ENERGY BALANCE AND EXISTING SYSTEMS 0608 O08 OOS CD COOH HHOEHOE YH OVE EOEOCOEOHOHOCHOEO Page 11-31 Il. ENERGY BALANCE AND EXISTING SYSTEMS A. INTRODUCTION AND SUMMARY To obtain a comprehensive understanding of future energy require- ments for the Bristol Bay area, a control year - 1977 - was established from which all projections have been made. For this year village surveys as well as inventories of fuel delivered have been used to establish general and electric energy use in the Bristol Bay area. Almost all energy needs in the region are supplied by gasoline and diesel fuel, with the following ratios established from the total deliv- ered Btu's: Gasoline 14% Diesel Fuel 74% Aviation Gas 3} Jet Fuel } 12% Propane 3 It is recognized that coal, wood and wind were also energy sources which could have contributed to total energy usage. However, no data on wood utilization could be located, no examples of coal utiliza- tion were found and only two working windmills were found. These windmills are located in Port Alsworth and Portage Creek. No per- formance data was available on the windmill in Port Alsworth and the windmill in Portage Creek was being utilized to charge batteries for a television translator. Electric energy in the area was almost exclusively generated with diesel or gasoline engine generators with the exception of the above mentioned wind systems. The approximate use of diesel fuel for the major categories has been established as follows: Heating 453 Electric Generation 31% Fishing Industry 24% The fishing industry percentage includes some transportation and generation fuel, but no actual allocation data was available from the canneries. With fuel oil being the predominant energy source and only one bulk supplier serving the entire region in addition to the BIA1°8, reasonably accurate data for the total amount of fuel delivered could be obtained without difficulty. This total does not account for fuel flown or shipped into communities by private individuals. Allocation of this total amount of fuel to user categories and the various end uses has been more difficult. Again, for the larger communities with bulk fuel suppliers and central electric utilities a fairiy accurate base could be Page 11-32 established. But for more than 2/3 of the 30+ communities in the area most of the energy usage had to be estimated (see Appendix A). To obtain an accuracy check the following approaches were used: a. establish energy and electric power use with the estimates from Appendix A; b. compare the results from a) with the 1978 Community Energy Survey!°° which is a compilation of fuel use, existing generating facilities and population for Alaskan communities. The informa- tion is taken from questionaires that have been answered by the communities. Where large discrepancies between the estimated and reported!°° fuel use could not be reconciled, the estimates have been used. A comparison of the total energy use (obtained from actual data, where available, plus estimates) with the total energy delivered is shown in the following: BTU's Delivered* BTU's Used** Gasoline 202.4 x 109 170.5 x 102 Diesel 898.6 x 109 929.6 x 109 Total 1101 ~x +109 7100.1 x 109 (without jet fuel, AV gas + Propane) This comparison indicates that a fairly accurate data base has been established. Electric energy use has been tabulated for communities with and without central plants to establish a base for future requirements. The energy costs are quite varied depending greatly on location and ease of access to the communities. The following cost ranges have been found: $/Unit $/10® BTU Gasoline (Gal. ) .53 to 1.47 4.17 to 10.62 Diesel (Gal.) .43 to 1.3 3.62 to 9.42 Electric Energy (kWh) -12 to .24: 35.16 to 73.25 Table Il-1 "1977 Energy Use" lists gasoline, diesel fuel and electric energy use for the individual communities. * Summation of deliveries into the area. ** Summation of community totals. ® sea ® OS 01} 0G GVO OHHSEBOOSCSHOOLSOHSELEHR GOOCH OCSCOHOORSOCD Page 11-33 Sources of information used to establish the energy balance data are listed in the bibliography of this section. Table 11-2 "Use of Information Sources" shows for which particular energy use category the various information sources have been utilized. It should be noted that in some instances several sources had to be used to establish the most likely conditions for the base year, if conflicting information was found. The energy used in the individual communities is listed in tabular form in subsequent parts of this section. Electrical energy is included in the diesel fuel use and the approximate quantity of fuel used for generation has been listed with the electrical energy balance. The energy use in the individual communities has then been summarized and is shown as "Total Bristol Bay Area Totals" on table "Energy Balance - 1977". Page 11-34 TABLE eo- 4 1977 ENERGY US ELECTRIC TOTAL DIESEL GASOLINE ENERGY _—_Energy* Energy Use 10° BTU MWh 10® BTU's of Total Energy Gal. X 103 BTU's X 10° Gal. X 10% BTU'sx10® = ¢7kWh Primary ELEC- $7Gal. $/10® BTU $7Gal. $/1 © BTU Energy* HEATING & INDUSTRY TRANSPOR- TRICITY LOCATION (Average) _1000-$_ HOME USE PROCESSING _ TATION GENERAT. TOTAL Dillingham 1764.8 243548 485.1 61608 305156 118.40 10.48 175.64 58.79 360.31 6 4.36 73 5.71 1,413.6 32 3 49 16 100 Naknek - King Salmon 3042.2, 419818 65551 11691485369 175.36 99.02 173.39 139.84 587.61 65 a7 5 O3t** 72.3 2,359.5 30 7 30 24 100 Uiamna _172 23739 6.6 838 666.2** 24577 8.00 0 838 15.81 65” 5.0 <7) Ft] - 123.6 33 6 3 64 Newhalen 63.47 8759 9 1143 205** 9902 4.84 0 1.14 3.98 9.96 :65 5.6 wt 5.5 = 50.5 45 o 71 40 100 Nondalton 9051 21 _ 2667 129" 11718 5.23 0 2.67 3.96 11.85 a4 47 70.62 -- 13.4 44 0 23 33 0 Nushagak Bay Clark's Point*** 58.1 8016 1143 152.7** 9159 4.92 0 1.14 3.16 9.22 = Tie “S.9ee* == 44.6 54 5 12 34 100 Ekuk*** 12.6 1745 4.8 610 2355 1.12 0 61 -65 2.38 65 an a 5.5 71.8 47 5 26 27 100 Manokotak 104.2 14386 25.2. 3200 197.8 17,586 9.84 0 3.2 4.7 17.74 -58 4.2 -68 5.35 == 77.5 56 0 “18 “26 “700 Portage Creek*** 37.3 5150 6.6 838 83.3** 5988 3.39 0 84 1.8 6.03 == 3.978%" == 7.08*** == 26.1 56 0 4 “30 “100 Peninsula - _Bristol Bay Egegik 307.3. 42414 N41 1408 101.9 43822 4.01 23.49 1.41 14.91 43.90 oae 5.21 1 7.87 18.4 232.1 9 54 ai ji <a “100 Pilot Point*** - 46.4_ 6398 11.4, 1448 101** 7846 4.12 0 2.35 7.92 Ugashik we 5.21 5 5.9 => 41.9 "$2" 0 "30" “100 Port Heiden*** 45.2 6242 9.6 1219 90.6** 7461 4.27 0 1.22 2.03 7.52 6i 4.42 8 6.25 -- 35.2 57 6 “Te "LT 100 Port Moller*** 1805 4.8 610 23.2** 2415 a2 0 -61 oat 2.44 4.42** == 6. 25+9* = 77.8 “46- 6 oS “3 “100 Peninsula - Pacific Side Chignik*** 54.6 7536 9 1143 152.6 8679 4.42 0 1.14 3.18 8.74 15 5-62 TO TT = 36.0 oa 5 aes % 100 Chignik Lagoon*** 43.6 6023 9 1143 98.8** 7166 3.80 0 1.14 2.28 7.22 5 3.62 TO 7.87 == 30.8 “52 6 Te “3 “700 ©0200 OHO HOOOHOSSOOHSHOKHOOOEES C006 OOHOHOCHSOOD BRIS4/E3 ©CO2SBOO00O306HOSOOOS8OE OEE OD TABLE a“ - 1 1977 ENERGY USE (CONTINUED) ELECTRIC TOTAL 00 00608 00008 SOC DIESEL GASOLINE ENERGY Energy* Energy Use 10° BTU MWh 10° BTU's % of Total Energy Gal. X 103 BTU's X 10° Gal. X 108 BTU'sx10® = ¢/kWh Primary ELEC- $/Gai. $7i0® BTU $7Gal. $710© BTU Energy* HEATING & INDUSTRY TRANSPOR- TRICITY LOCATION (Average) _1000-$ HOME USE PROCESSING TATION GENERAT. TOTAL Pacific Side (Cont. Chignik Lake*** 71.8 9906 15 1905 167.4** 11811 6.39 0 1.91 3.6 1.9 5 3.62 75 5.9 == 48.7 54 6 16 30 100 Ivanoff Bay*** 17.4 2399 6.6 838 25.7** 3237 1.65 0 -84 79 3.28 -6T 742 == 5.25* = b.5 30° u a :) 24 100 Perryville*** 53.7 7416 15 1905 109.7** 9321 4.88 0 1.91 2.61 9.40 ot 5.07 a B66 54.7 52 0 20 “OB 100 Togiak Togiak 213.9 29514 56.4 7163 512.1 36677 20.11 227 7.15 9.50 37.03 85 “STS a 7.08 22.8 232.2 3a ti waar 26 TOO Twin Hills*** 59.7 8234 9.6 1219 144.5** 9453 5.39 0 1.22 2.9 9.51 85 6.15 os TB =- 55.3 ST 5 3 “30 100 iliamna Lake Igiugig 34.8 4812 12) 914 79.1** 5726 0 91 5.77 ins 5.07 94 TA = 3. 5 16 100 Kokhanok 59.7 8234 9.6 1219 144.5** 9453 0 1.22 9.51 a 5.07 -76 5.98 = 4a 6 13 100 Pedro Bay*** $1.1. 7053 13.2 1676 105.3** 8729 4.65 0 1.68 8.81 ta 5.21 7.0 7.87 = 49.5 53 6 19 100 Port Alsworth 25 3446 Si 381 68.9** 3827 2.18 0 .38 1.27 3.85 = 5.21*8* = 7.87*** = 20.5 7 6 “16 33 100 Ekwok*** 3.9. 10197 18 1905 12100 6.68 o 19 3,6 12.19 ~54 3.51 39 7.08 3.3 55 5 15 30 100 Levelock*** 78.6_ 10852 16.8 2133 die** 12982 7.21 9 2.13 3.74 13.08 43 3.11 53 4.17 = 42.6 55 0 io 29 100 New Stuyahok 97.8 13507 25.2 3200 203.2 16700 8.83 o 3.2 4.83 16.86 5 5.75 1.1 5.66 23 105.9 52 0 15 2 100 Koliganek*** 66 9106 12 1524 160.1** 30629 5.80 0 1.52 3.38 10.70 == 5. 79*** = 5. 66*** = 65.9 54 6 14 32 100 TOTAL 6734 929306 1343 170552 20544 1099858 433 133 392 302 1260 -65 4.73 -80 6.32 17.9 5,471.8 34 1 31 24 100 No Central power plant. Jet Fuel, Propane and AV Gas & Electricity not included. Private Generators only *** Estimated data Page 11-36 TABLE II-2 USE OF INFORMATION SOURCES END USER OF ENERGY ‘Population rie and Electric Electric ____ SCHOOLS 7 FISH PROCESSING | Bibliography # of Energy Energy Systems Energy Install- Energy Install- __Ref. # ~~ Source of Information Consumers Use Use (Installed) Use ation Use _ation _ ~ 100 1978, Community Energy Survey xX xX xX xX 101 1977, Inventory of Sanitation Services xX 102 1978, Community Profiles X 103 1974, Alaska Regional Profiles X 104 1978, School Generation Survey xX xX 105 1979, Military Energy Use xX X X 106 1979, School Energy Use X X xX xX 107 1979, Port Alsworth Energy Use X xX 108 1979, BIA Fuel Deliveries xX X 109 1979, Manokotak Elec. Energy Use xX X 110 1979, Fuel Deliveries by Moody Lighterage xX xX a 1979, Canneries in Operation X 112+116 1979, Dillingham & Naknek Fuel Use & Distribution xX x X 113-115 1977, Utility Reports xX xX X 117 1978, System Study, Tliamna xX xX 118 1978, Workplan - Kodiak Electric xX xX ©690SSFOOOFHOHOSOOOOHOKOCS ODE OOOH COD 608 8HSOECO Page |1!-37 B. DILLINGHAM 1. TOTAL ENERGY BALANCE 1977 Energy balance information for Dillingham includes the energy usage for the smaller villages connected to Dillingham by road. These villages, namely Kanakanak, Aleknagik, and Olsenville, have both an electrical and a fuel umbilical to Dillingham. Although it has the highest ‘civilian population, the Dillingham area is second in energy consumption to the Naknek area. This is in part due to the military base in King Salmon, but is mostly due to the number of canneries in Naknek. There are nine canneries in Naknek and only one in Dillingham. Chevron USA, Inc. has stationed a permanent sales representative in Dillingham making it one of the two fuel distribution points in the Bristol Bay area. From that sales representative a good accounting was obtained for both the total fuel quantities remaining in the Dillingham area, and a consumer usage breakdown of those quantities. 112 2. ELECTRICAL ENERGY BALANCE Nushagak Electric Cooperative, the Dillingham local electrical utility, supplied historical usage data for the electrical energy balance section.113. During the calendar year 1977, the utility generated electricity at an average heat rate of 12.20 kWh/gallon of fuel. The cannery is not connected to the central utility and its electrical consumption was estimated. Waste heat from the powerplant is utilized to heat Nushagak Electric's office and warehouse space. 3. EXISTING ELECTRICAL SYSTEM Nushagak Electric Cooperative (N.E.C.) supplies electrical power to the Dillingham area. It is a federally financed (REA) utility which had 2900 kW of generating capacity in 1977. Nushagak distributes power over a dual voltage distribution system. The in-town distribu- tion feeder is in the process of being converted from a 2400 voit three-phase delta system to a 7.2/12.5 kV three phase wye system. When this conversion is complete Nushagak will be distributing power at a single voltage. APAOOSC3 ENERGY BALANCE - 1977 DILLINGHAM AREA TOTALS Page i425 CONSUMER iL ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gat No. Cons/Annual MWH 10°B TU 108atu/—2— 10%stu/—S— 108atu/—*%— 10*aTu-—S— 10° Tu/-_$_ % of 10°BTU 10°BTU 10°BTU 10°BTU 10°BTU Total TYPE NO. 5 480,376 160, 400 15,000 V dal 88,028 RESIDENTIAL 35956, 29874.36 20, 37175. 7 7,365/na is ° 24.4 234,977. _ 324,700 eet Ad 423,538 80 / 1,175 127,453 COMMERCIAL 80 32,42174.36- 47,239/5.71 o 0 53, 783/na 7224 13.2 35.4 372,825 __ 205 = ios Eg) = Aoi a he ofS Sot $1,450 LARGE USERS 2 Bib 74-36 0 0 0 o 40,306 711.8 = 143 FISHING 436,537 ed he Lee an] na_/ na 60,242 VESSELS ne $0, 24274.36 o 0 9 0 na na 16.7 PUBLIC 240, 126 Lad rt Low | ie 59 / 1,031 33,137 BUILDINGS 59 33, 139/4.36 0 0 9 0 7,450 7 12.9 3.2 MILITARY 0 -0- -O- -0- -0- -0- -@- 0 1,764,841 485,100 _ 15,000 Sn __ 423,538 500 / 4,769 360,310 Su 500 243,548/4.36 61,608/5.71 T,365/na 2 53, 789/na 794 713.1 100.6 % of Total BTU 67.6 71 0.4 -0- 14.9 incl in Diesel 100.0 CANNERY 1 _ incl in large incl in large Lae Sloe te 200 (self generating) users users na REMARKS: Central Electric Utility used 426,000 gal of diesel fuel Ma - not available @ oO Page 11-39 it-18 0 DILLINGHAM @ 1977 SYSTEM ELECTRIC ENERGY USE 0 @ : 1500} | 4 : 1400 | ; 1300 — @ 120 0 e 1100 0 Oo 0 1000 T T o o 900 | @ Oo 800 SY 4. @ SEAR 5 e @® @ 600 1 o oO 500 . a x 10° 400 = MON XS . ae : 300 ; 200 + + 2 100 = @ @ JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC e # OF CONSUMERS: 500 e@ FIGURE ID-1 e JUNE 1979 ® Page 11-40 C. NAKNEK - KING SALMON 1. TOTAL ENERGY BALANCE 1977 The Naknek area, which includes Naknek, South Naknek and King Salmon, uses the largest amount of energy in the Bristol Bay area. The U.S. Air Force installation at King Salmon has its own centralized heating and electrical generation plant. They supplied fuel data? used in the energy balance. The Chevron U.S.A., Inc. sales representative in Naknek made avail- able comprehensive records!!® regarding fuel utilization in the Naknek area. These records were used in completing the energy balance. The residential total diesel fuel and the fishing vessels total diesel fuel were approximated from the total diesel "cash sales" account. This was done by subtracting the total approximated home heating fuel (see Appendix A for this approximation) from the total quantity of diesel fuel sold in the "cash sales" account. 2. ELECTRICAL ENERGY BALANCE Electrical usage information for the Electrical Energy Balance was supplied by Naknek Electric Associationt!*+ (NEA) and by the U.S. Air Force?95, N.E.A. is a federally financed (REA) utility which serves Naknek, South Naknek, portions of King Salmon and Egegik. Although Egegik is officially part of the N.E.A. system it has its own generation and distribution facilities. While the majority of the canneries in the Naknek area are connected to the electric utility, they use their own generation facilities when fish processing begins. During the calendar year 1977, Naknek Electric Association generated electricity at a heat rate of 11.86 kWh/gallon of fuel. During the same period of time the military generated at 13.22 kWh/gallon. Waste heat from the NEA generating plant is utilized to heat the Naknek High School. 3. EXISTING ELECTRICAL SYSTEM Naknek Electric Association distributes electrical energy to the Naknek area over two 7.2/12.5 kV 3 phase wye feeders. It is currently in the process of converting one of these feeders to a 14.4/24.9 kV 3 phase wye system and with it will eventually supply power for the U.S. Air Force Base in King Salmon. Page |1-41 The Air Force is presently operating a 2400 Volt delta system. Naknek Electric Association had 1400 kW of installed power in 1977. Installation of an additional 2320 kW was planned for 1978. The Air Force has an installed generating capacity of 1950 kW. APAOOSCS ENERGY BALANCE - 1977 NAKNEK - KING SALMON AREA TOTALS MER a ____ ENERGY FORM CONSUMED | __ OIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal __ Gal _ Gal No. Cons/Annual MWH 10®BTU 10°aTu/—— 10%aTu/—* 10° Tu/—* 10°aTu/—* 1osatu/—t— “Ave—KWn ave. ¢ Yof 10°BTU 10°BTU 10°BTU 10°BTU 10°BTU el kwh Total TYPE NO == . < a __ 323,922 190,484 253 a 6 —203_/ 1,302. 69,643 RESIDENAIAL 203 4, 10174. 71 24, 181/na 7na S ° 5347 12.8 1.8 o 225,175 _ 554,469 18 __/ 2,444 228,126 COMMERCIAL 76 Oi 31,074/na 70, 418/na 2,680 7 12.3 38.8 S . =e Of = O= 20 a 8 116,250 LARGE USERS 4 26,404 7 11.7 19.8 FISHING na_/_na__—S__22, 283 VESSELS = a =O “ee == na 7 na “3.8 PUBLIC 21,770 8 / 18.0 3,004 BUILDINGS . 7004/4. 71 =oe =O ao cad 87 716-6 0.5 1,074,679 7 _1__/ 6,660 148, 306 MILITARY 1 748, 30674 71 -0- -0- -0- -0 54,960 7 ha Ce 3,041, 155 516, 152 8,253 225,175. 555,890 587,612 TOTAL 92 ak ates ae — eae —$, oo) eet ae wr ele : 419,818/4.71 65,551/na 751/na 31,074/na 70,418/na 100.0 % of Total BTU 71.4 11.2 0.1 $.3 12.0 incl! in Diesel 100.0 CANNERY 1 incl in large incl in large -0- =o = __ 9 / 1,800 (self generating) users users / ~ 100,000 7 na 0 REMARKS: Central Electric Utility used 508,000 gal of diesel fuel L Military used 500,000 gal diesel fuel for electricity generation re ———— inane e > na - not available Y Page 11-43 11-23 NAKNEK-SOUTH NAKNEK 1977 SYSTEM ELECTRIC ENERGY USE # OF CONSUMERS: 300 FIGURE IL-2 JUNE 1979 * e @ @ ® e@ e 1500 @ @ e 1400 @ @ 1300 @ e 1200 @ 1100) @ e e 1000) e e 900 @ @ 800 e e 700) @ ® 600 e : 500: ; 400 . 300 e 200 @ ®@ e 100 @ e JAN FEB MAR APR MAY JUN JUL AUG SEP oct NOV DEC e e e @ Page 11-44 KING SALMON AIR FORCE BASE 1977 SYSTEM ELECTRIC ENERGY USE 11-24 1500 1400 1300 1200 = fh 100 1000 r 900 SYSTEM | PEA, 800 700 a a | 600 SYSTEM KWH /MGNTH x10> 500 400 300 7 im 200 T 100 JAN FEB MAR APR MAY JUN JUL AUG SEP ocT NOV DEC FIGURE IL-3 JUNE 1979 Page 11-45 D. ILIAMNA - NEWHALEN - NONDALTON Total Energy Balance 1977 The lIliamna - Newhalen - Nondalton area was evaluated separately, because a system planning study was available1”. The study addressed electrical consumers, electrical consumer growth projections and several energy development scenarios. The energy balance information for this area was estimated using electrical use information from the system planning study combined with heating fuel estimates. The heating fuel estimates for various consumers groups can be found in Appendix A. Because there were no centralized utilities in Iliamna - Newhalen or Nondalton, a conver- sion rate of 4.5 kWh/gallon was used for residential and small com- mercial consumers. This was based on manufacturers data for small (less than 6 kW) diesel generators. A conversion rate of 8.5 kWh/gallon was used for large commercial consumers. This was verified by several of the large commercial consumers in the area, namely: The Federal Aviation Administration (FAA) in Iliamna; RCA Alascom in lliamna, and the school in Newhalen. EXISTING ELECTRICAL SYSTEM There are no existing central electrical systems in Iliamna, Newhalen or Nondalton. There are however, private individuals and several organizations in the area that maintained private generation facilities. The schools in Newhalen and Nondalton each have an installed capacity of 150 kW. The Federal Aviation Administration facility in Iliamna has an installed capacity of 125 kW and generated an average of 23,000 kWh/month. The FAA distribution system operates at 2400V. APAOO9C7 ENERGY BALANCE - 1977 ILIAMNA AREA TOTALS CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal_ Gal Gal Gal No. Cons/Annual MWH 10°BTU 10°a Tu/—* 10% Tu/—* 10¢aTuA—* 10°a Tus—* 1088 Tu/—* Ave. kWh ave. ¢ of 10°8TU 10°BTU 10°BTU 108s TU 18aTu —menth _/ wh Total TYPE NO. bree 26,478 6,600 _ 447 ane ne Th) acy Biya 4,533 RESIDENTIAL " has —sih75.9 A jnar 0 0 0h sa __ 89,978 Dae ao aie Lae 221 ji ats 12,417 COMMERCIAL 22 1, 417750 0 0 0 0 7 ss ‘5s 55,565 ia A = ere 320 7,668 LARGE USERS 2 1 ghS OT 0 0 0 0 + —ti FISHING Dic re earl Lois Lee na_/__na 0 VESSELS - ° ° 0 ° . na na PUBLIC ce ae a Sa Dan na / na 0 BUILDINGS 2 ° . ° ° o na 7 na MILITARY 0 -0- . 70- -0- -0- -0- -0- 0 TOTAL 35 172,021 6,600 447 =a -0- 35/666 24,618 23, 7T3875.0 83875. — Tjna_ “15867 na 160.0 % of Total BTU 96.4 F 3.4 0.2 -0- -0- incl in diesel 100.0 CANNERY on — ste iis a ae na_/__na na 7 na (self generating) REMARKS: Qp-1| a5ed Ma - not available * - including public buildings BRIS4/A9 ENERGY BALANCE - 1977 NEWHALEN AREA TOTALS CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10®8TU 10°8TU/—2— 10*aTu/—*® 10°aTu/—2 10%eTu/—* weetu-—$— AvetWn) ave. ¢ tof 10°BTU 10°BTU 10°BTU 10°BTU 10°BTU cons kWh Total TYPE NO 22,115, 9,000 610 15 36 4,251 REAIDenT iat 1 —308275-0 1143/5." —s6/na oP re SS a 42.7 COMMERCIAL 2 — 82 - -0- -0- -0- -0- ~~ ee i 1 160 _5,064 LARGE USERS 1 -0- -0- -0- -0- 73,333 / na $0.8 FISHING na na 0 VESSELS os Te = 0! =O) == ahi na na PUBLIC na na 0 BUILDINGS ¢ Oe =O rhe a0 = a8 na na MILITARY 0 =O- -0- -0- <= -0- 3s0- 0 63,471 9,000 _ 610 - ah 18/205 9,958 ROLAL 18 75, 75875.0 7, 143/5.9 56/na » : 949 7—na 700.0 % of Total BTU 87.9 11.5 0.6 -0- -0- incl in diesel 100.0 CANNERY na na (self generating) ee es 7s =e ere na na REMARKS: 15 families, 1 school no post office, no community hall na - not available -TT e6ed l BRIS4/A11 ENERGY BALANCE - 1977 NONDALTON AREA TOTALS CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 108atTu/—&— 10° Tu/--* 10¢aTu/—* 1083 Tu/—* woeatus—S— Ave—KwD) ave. ¢ bof 10°BTU 10°B TU 108BTU 10°BTU 10°aTU —2 kWh Total TYPE NO. eons 54,402 21,000 1,423 fa lle | 56 7 10, 303 CE i ais 7 7, 5017/5. 42 2, 661710.62 “1287na : ° 230 na $7.0 11,189 CNT, tae ia el 3/32 1,544 COMMERCIAE 3 77784479.42 7 ° . S 300-7 —na 13.0 LARGE USERS 0 -0- -0- -0- =O <0 na_/ na 8 na / na FISHING alta lm nl Tia las als na_/__na 0 VESSELS = ° , : ° o na na PUBLIC lla Jas iat leat Tale na_/__na 0 BUILDINGS . ° . 7 7 o na na MILITARY 0 -0- 10% -0- -0- -0- -0- 0 65,591 21,000 1,423 ee Tae 38/129 “11,847 TOTAL a8 5, 05179. 42 2,667710.62 “2h7na 0 0 2837 na 700.5 4 of Total BTU 76.4 22.5 1 -0- -0- incl in diesel 100.0 CANNERY 265 aos -0- Loe os na_/ na (self generating) REMARKS: na 7 na na - not available 8P-TT ebed Page 11-49 E. RURAL BRISTOL BAY Rural Bristol Bay was divided into the following subgroups: ‘As Nushagak Bay = Clarks Point Ekuk Manokotak Portage Creek (e Peninsula - Bristol Bay - Egegik Pilot Point - Ugashik Port Heiden Port Moller Ss Peninsula - Pacific = Chignik Chignik Lagoon Chignik Lake Ivanhoff Bay Perryville 4. Togiak Bay we Togiak Twin Hills. Bi lliamna Lake > Igiugig Kokhanok Pedro Bay Port Alsworth 6. Inland - Ekwok Levelock New Stuyahok Koliganek The rural villages were divided into the various subgroups on the basis of geographic, economic and climatological similarity. Grouping the villages aided in understanding area electrical requirements from which energy scenarios were developed. Most of the base data for these rural communities had to be estimated. Parameters for these estimates are stated in Appendix A. Depending on population, one or more stores, a school and one or more public buildings were assumed to be located in the individual villages. If canneries were in operation during the base year, their energy use has been noted. According to information obtained from the State Department of Fish and Game!!! several existing canneries apparently did not operate in 1977. Page 11-50 1. NUSHAGAK BAY Although one of the villages in the Nushagak Bay area, Manokotat, does have a central utility, the available data regarding that village was limited. The available data for Manokotak was used in its total energy balance and the remainder of the data for Manokotak was estimated. Data for the other villages in this subregion was estimated and all estimates were made in accordance with the parameters set forth in Appendix A. As with all villages where electrical and fuel - usage was estimated, the number of stores was set directly propor- tional to the number of families. The number of public buildings was obtained from either the State of Alaska, Regional Profiles!°? or from first hand knowledge. Information regarding the size of village schools in this area was estimated from data received from the South- west Region School District!°?. EXISTING ELECTRICAL SYSTEM The only village in the Nushagak Bay subregion that had a central power generation facility was the village of Manokotak which operated part of 1977. The only information obtained regarding this facility was that the installed generation capacity was 75 kW. The installed generation capacity in the schools in each of the various villages is shown in the following table: VILLAGE INSTALLED CAPACITY Clarks Point 100 kw ic eee Manokotak 60 kW Portage Creek 100 kW In addition to the above generation there are also numerous small generators in each village operated by private individuals. BRIS4/A13 ENERGY BALANCE - 1977 RURAL BRISTOL BAY NUSHAGAK BAY - CLARK'S POINT CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 10¢aTu/—2— 10°aTu/—4 10°aTu/—* 10*sTu/—2 1oeaTus—s— Ave kWh ave ¢ = Yo 10°B TU 108BTU 10°BTU 10°BTU weaTy —moath_/ wh Total TYPE No. cons 18,975 9,000 610 15 22 3,818 RESIDENTIAL % 2,619/na 7, 143/na na a0 210k 721 na 41.4 4,734 a oe Bas one S07 749 653 COMMERCIAL 2 $53/na 0 0 0 0 305.7 na SA 30,344 be abt. As a 1_/ 106 4,187 PARCENUSERS ' 4, 187/na e 8 c 2 6,833 7 na 45.4 FISHING “ aa oe ne na 0 VESSELS ps ° o 9 so 0.5 na na PUBLIC 4,037 . . 7 a " . s . aN Bag fst Be. —__557 BUILDINGS 2 557/na o 2 ° ° 233 7 na 6.1 MILITARY 0 -0- -0- -0- -0- -0- -0- 0 58,090 9,000 610 one ne 20/153 9,215 TOTAE eo 8,016/na 7, 1437na 56/na c ° 6367 na “700.0 % of Total BTU 87.0 12.4 0.6 -0- -0- incl in diesel 100.0 CANNERY ge “id= Te ion a-< na / na (selt generating) REMARKS: na / na na - not available IS-TT ebed APAOOSCI1S ENERGY BALANCE - 1977 RURAL BRISTOL BAY NUSHAGAK BAY - EKUK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gat Gal No. Cons/Annual MWH 10®8TU 10%aTu/—2&— 10% Tu-—* 10°aTu/—* 1088 Tu/—* wteTus—s— Ave KWh Avene tof 10°BTU 10°BTU 10°BTU 1oeaTu 10° TU month / kWh Total TYPE No. 10, 120 4,800 325 Petal i - Bhl7 2,037 RES OE EAL : 1801/40 ||| 0/510 30/na c ° Tey —ts.4 2,525 Las 1 10 348 COMMERCIAL 1 Pr -0- e- 0 o 803 na ace LARGE USERS o -0- Zio )= “0 -0- -0- na f na o na na ' FISHING na na o VESSELS ™ molt aon inhealil an oli na na PUBLIC na na oO BUILDINGS ° ao ACh mihi nT Tacit na na MILITARY 0 Oriol -0- -0- =10) =| -0- ° 12,645, 4,800 325 I I oo tian ae 2,385 Yo a T, 74574. 71 Telos Si 307na— ait c 733 na 100-0 % of Total BTU 73.1 25.6 1.3 -0- -0- incl in diesel 100.0 CANNERY ly DL aa I We nat fine (self generating) me o o 0 0 na 7. ne REMARKS: no school, community hall or post office na ~ not available zs-1| a6eq APAOOSC17 ENERGY BALANCE - 1977 RURAL BRISTOL BAY NUSHAGAK BAY - MANOKOTAK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 108aTus-—*— 10%atTu-—S— 10% TUE 10%aTuA—% woeaTus—s— Avetwh ave. g of 10°BTU “1088 TU 10°BTU 10°BTU 10°BTU sana kWh Total TYPE NO. 61,036 25,200 1,708 twat ae 39/67 11,778 ae <2 ea237a-z 3, 20075.35- 857na S LM a7 na——“ié‘“(S:*«SC 9,361 ; 2 19 1,292 COMMERCIAL 4 Tae -0O- -O0- °0- -O- a na —75 30,344 in na ee oh 1_/__106 4,187 CARGE USERS, Va o ¢ o “Oe/— a8 FISHING na na 0 VESSELS os be ams =F =K0)= SOE na na PUBLIC 3,507 sine sae eae 2 6 484 BUILDINGS 2 7 s0S co e 2 z na meat MILITARY 0 -0- " 20- =16.= 6 = =iQ~ 26s 0 104,248 25,200 1,708 44 198 17,741 PSTAL 490 abe 3, 20075.35- 55/na aos oe 3 na 760.0 % of Total BTU 81.1 18.0 0.9 -0- -0- incl in diesel 100.0 CANNERY Pye: ones es ‘ y na na (self generating) 0 o a =e a na na REMARKS: 42 families Cental Electric Utility used approx. 39,200 gal diesel fuel na - not available €S-1| e6eq APAOOSC19 ENERGY BALANCE - 1977 RURAL BRISTOL BAY NUSHAGAK BAY - PORTAGE CREEK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10®BTU $ 6 p— $ 6 $ 6 $ Ave. kWh 1o8eTU/— wee TU/— 1o8aTU/— 10% TU/— 108BTU/— a ee 10°BTU 108BTU 10%BTU 108BTU ioeTu —Beath_/ kwh Total TYPE No. me 13,915, 6,600 447 a Gide u/s 6 2,799 RESIDENTIAL No —ls7na Ss 8am ane 0 9 7217 na 6.5 3,472 he ae 7s 1/10 479 COMMERCIAL 1 —age— 0 ° 0 0 a -Ct—C HBB 15,900 ike Pe oe aa 1/82 2,194 LARGE USERS 1 = 0 o 0 0 3 44 FISHING Sane laid bt iT na_/__na 0 VESSELS oa = o ® , . na 7 na PUBLIC 4,037 We nae) Lak Lele ‘7 557 BUILDINGS 2 —377na ° ° ° ° B27 ha 9.2 MILITARY 0 -0- "soe -0- -0- -0- a 0 37,324 6,600 447 et one 15, 84 6,029 TOTAL 5s 3, 150/na $36/na 41/na 0 0 2 na 7160.0 4 of Total BTU 85.4 13.9 0.7 -0- -0- incl in diesel 100.0 CANNERY 20's -0- a0 =0'- -0- na_/__na (self generating) na / na REMARKS: na - not available yS-I| e6ed Page 11-55 2. PENINSULA - BRISTOL BAY The five villages in the Peninsula - Bristol Bay subregion were grouped because of their geographic and economic similarities. All are coastal villages dependent on a fishing economy. Port Heiden and Port Moller both have inactive military installations and RCA Alascom maintains a communication station at Port Moller. Fuel usage data for the village of Egegik was obtained ‘from the Chevron representative in Naknek?!!§. Note that, because the cannery diesel fuel usage was known, they were classified as large energy consumers on the total energy balance sheet. Also, note that there are no large electrical consumers listed in the electrical energy balance. This difference occurs because the electrical utility in Egegik does not serve the canneries. This differ- ence in number ‘of total large consumers also occurs on the overall total sheets. : Data for the remaining communities has been estimated in accordance with Appendix A. EXISTING ELECTRICAL SYSTEMS Two of the four villages in the Peninsula - Bristol Bay subregion have a central power system. These two villages are Egegik and Port Heiden. The only information available on the Port Heiden system was the installed capacity of 75 kW. Informaton regarding electrical generation and utility fuel usage for the village of Egegik was obtained from Naknek Electric Association (NEA). The total installed generation capacity in Egegik is 135 kW and power is supplied via a generation facility in the village itself. There is no transmission line linking Naknek to Egegik. In addition to the above generation, there are also numerous small generators in each village operated by private individuals. BRIS4/A21 ENERGY BALANCE - 1977 RURAL BRISTOL B AY PENINSULA - BRISTOL BAY - EGEGIK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS. ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU wosatu/—S— w%etu/—— otatu-—2— w%stu-—$— r0aTur—S_— AVE—KN ave. Gof 10°B TU 10%BTU 10%BTU 1088TU vosaTu Benth / kwh Total TYPE NO. 36,813 11,088 853 21 46 6,566 RESIDENTIAL 2 =sSetear || aera & -0- -0- a= SO 29,724 1 56 4,102 COMMERCIAL 7 yee a -0- 10) were waa ate LARGE USERS 2p eae Slee wy Be mors “Oi na na 33,232 33,232/5.21 ne ne 78.7 FISHING pute ee ie ait ie NIE na na 0 VESSELS na 0 ° o o o na na PUBLIC ites ane Do a unt Laws na na 0 BUILDINGS o 0 0 0 0 0 na na MILITARY 0 -0- -0- -0- “0% aa aor 0 307,349 11,088 853 28 102 43,900 SO SO ead yala/ore lant; a08/7c0 Th ina o C 303 na 7160-0 4 of Total BTU 96.6 3.2 0.2 -0- -0- incl in diesel 100.0 CANNERY 2 incl in large incl in large ae Bae ae 2 600 (self generating) users users 150,000 / na REMARKS: Central Electric Utility used 37,500 gal diesel fuel na - not available 9S-IT e6eg TOTAL SYSTEM KWH/MONTH x 10° Page 11-57 11-49 EGEGIK 1977 SYSTEM ELECTRIC ENERGY USE 10 o N JAN FEB MAR APR MAY JUN JUL AUG SEP ocT NOV DEC ESTIMATED PEAK: 40KW # OF CONSUMERS'28 FIGURE IL-4 JUNE 1979 APAO0SC23 ENERGY BALANCE - 1977 RURAL BRISTOL BAY PENINSULA - BRISTOL BAY - PILOT POINT - UGASHIK CONSUMER ENERGY FORM CONSUMED : DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU $ $ $ @ $ Ave. kWh 10°BTU/ a 10°BTU/ 10°BTU/- 2 10°BTU/ a 10%BTU/— month / —Ave.¢ % of 10°BTU 1088 TU 10°BTU 10°BTU rosatu —menth _/ kwh Total TYPE NO. 24,035 11, 400 772 7 141 19 28 4,835 RESIDENTIAL 190 ats “Tab 75-90 a7 =o . vai 7— na 6 5,996 — A est 2_/ 19 827 eee ee 2 TRIS rier Phe 9 o 3037 —na 10.4 15,900 tue ie 1 52 2,194 LARGE USERS 1 a -0- -0- 9 0 4,334 /_na er FISHING a na na 0 VESSELS. ns poke oe ae ee -o na na PUBLIC ji 432 oe stays Foe eae 1 2 60 BUILDINGS 6075.21 162 na TT MILITARY oO -0- “ -0- -0- -0- 0 = -0- 0 46,363 11, 400 772 ee Lek, 23 101 7,916 TOTAL 3 '" wat 7, 44875. 50 70/na ® ® 3 na 760.0 % of Total BTU 80.8 18.3 0.9 p= (0- =0 A incl in diesel 100.0 CANNERY na_/__na (self generating) 7 a1 Obs UE oar “m= na / na REMARKS: no community center na ~ not available gS-1| a6eq APAO0SC2S ENERGY BALANCE - 1977 RURAL BRISTOL BAY PENINSULA - BRISTOL BAY - PORT HEIDEN CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 108TU 108aTu/—S— 10%aTu/-—* 1088 Tu/—* 1088 Tu/—*® wosaTus—S— Ave kWh pve ¢ of 108BTU 10*a TU 10°BTU 10%BTU roeaTu — month _/ wh Total TYPE NO. Se 20,240 9,600 651 i ae 16 23 4,071 Ee OEE as 2, 79374.42 721876. —397na ae e 721 na ees 5,049 see ats ae ses ean) 698 COMMERCIAL Ride ar COR ATRE g Y ° i/eme . aoe 15,900 a ae Hah tees 17 82 2,194 LARGE USERS 1 S474. 0 0 0 0 a = ee FISHING na na ° VESSELS pa = Oe oo als igs ae na na PUBLIC 4,037 be Wel ail Pe 2 6 557 BUILDINGS 2 551/442 ic o o e 22 na 3.4 MILITARY ° -0- -0- -0- -0- -0- -0- 0 45,226 9,600 651 UN Te 2/7 9 7,520 TOUAR 20 0 aReTa aE AGB TS/O OS 337na e ° SeS7 Tear iomnnrt ag tOost % of Total BTU | 83.0 16.2 0.8 -0- -0- incl in diesel 100.0 CANNERY peat ay, a a intiach na na (self generating) o 8 os i ® na na REMARKS: na ~ not available 6S-I| eed APAOOSC27 ENERGY BALANCE - 1977 RURAL BRISTOL BAY PENINSULA - BRISTOL BAY - PORT MOLLER CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°8TU 10°aTu/—S— 10%atu/—%— 10% Tu/—$ 10¢aTu-—2 wotstu;—S— Avekwh ave. ¢ Roof 10°BTU 10°B TU 10°aTU 10°aTU rosaTy —Zenth_/ "kwh Total TYPE NO. 10,120 4,800 325 E 8 12 2,037 ee eS 8 7,397/na 610/na 30/na -o ao 12 na 83.3 . 2,525 ante se his Jn 1 10 348 COMMERCIAL 1 ee 0 0 o 0 3 na 74.2 LARGE USERS 0 =0e -0- =e -0- -o- na fa —= 3 na / na FISHING na na oO VESSELS ba pea Oke For 75 Or na na aa PUBLIC 4 432 mae oe sion oe 1 2 BUILDINGS 60/ni 162 na MILITARY o -0- -0- -0- -0- -0- -0- 0 13,077 4,800 325 . las 10 24 2,445 TOTAL ue 7,805/na 610/na ina o 0) 1 na 700.0 % of Total BTU 73.9 24.9 2 -0- -0- incl in diesel 100.0 CANNERY na na (self generating) "as i “G* aes “es na na REMARKS: no school and no community center na ~ not available 09-1) a5ed Page 11-61 3. PENINSULA - PACIFIC The villages in this subregion were grouped due to similar geographic and economic conditions. All the villages are located at or near the Alaska Peninsula and receive fuel via Chevron USA, Inc. Chevron delivers fuel to these communities on a monthly or bi-monthly basis, using a small tanker as the delivery vessel. Although the cannery in Chignik supplies electric power to part of the town, no data was available on fuel or kWh usage. Fuel and electrical usage were estimated for the five villages in the area in accordance with the figures in Appendix A. School size was determined from information obtained from the Lake and Peninsula School District. 1° The number and type of public buildings was taken from the State of Alaska Regional Profiles. 1% EXISTING ELECTRICAL SYSTEM The village of Chignik in the Peninsula - Pacific Side subregion is the only village in this subregion that has a central power system. The local cannery, which has an installed capacity of 400 kW, supplies power to 24 homes. No fuel use data or electrical use data was avail- able from the cannery. The installed generation capacity in the schools in each of the various villages is shown in the following table: VILLAGE INSTALLED CAPACITY Chignik 2 - 50 kw Chignik Lagoon 2-15 kW Chignik Lake 2 - 30 kw ivanhont: Baye cee ocean Perryville Not Available ENERGY BALANCE - 1977 RURAL BRISTOL BAY CHIGNIK AREA TOTALS CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 108atTu/—— 10%arus—* 10a tus—® 08a Tu/—* woes Tu/—S— Ave—KWn) ave. % of 1088 TU 10° TU 1088 TU 10%BTU roeatu Seon _/ kwh Total Type NO. ore 16,677 9,000 610 Sak ns 15 22 3,500 RESIDENTIAL i —y3047e6F || 8477-87 na 9 o) sa 0.1 4,081 oe ie Sos oe 2 19 563 COMMERCIAL 2 seh 0 0 0 ° 5 12 — 8 30,344 =< orate a 1 106 4,187 LARGE USERS V “H8773.62 =e $ : ° ase TS FISHING age wn & opt ee ae na /__na 0 VESSELS na c 5 o UG e na / na PUBLIC 7 3,512 ae mor Lipo mae 2 6 485 BUILDINGS 78573. 62 233 na = 5.6 MILITARY 0 -0- -0- -0- -0- -0- -0- ° 54,614 9,000 610 a lad 20 153 8,735 See cy 7, 536/3.62 7143/7. na 8 e 7 na 160.0 % of Total BTU 86.3 13.1 0.6 , ee -0- incl in diesel 100.0 CANNERY s0= S10 sore =O) ofc ‘na / na (self generating) REMARKS: na na Na - not available z9-1| a6eq APAQ09C31 ENERGY BALANCE - 1977 RURAL BRISTOL BAY PENINSULA - PACIFIC CHIGNIK LAGOON CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gat Gal Gal Gal Gat No. Cons/Annual MWH 10°BTU 08a Tu/—S— 10%aTu/-—$ 10®a Tu/—* totatus—$— 10%sTu/—S— Ave—Kuh ave. ¢ — Lof 108BTU 10%BTU 108aTU 10%BTU roeaTu Benth _/ kwh Total TYPE No. 18,975 9,000 610 15 22 3,818 REE OETA 1S —ee7s6e 1148/7. —S6/na dae =2'S 721 na 32.5 4,735 2 19 653 COMMERCIAL 20 aepPR- -0- -0- -0- -0- 3 3 15,900 1 s2 2,194 LARGE USERS 1 = Bae -0- 74> =i0ic eT a na —i.4 \ FISHING na na oO VESSELS ~ es -O- gr ele ss na na PUBLIC a 4,037 os wae oe 2A 2 6 557 BUILDINGS 557/3.62 233 na fe MILITARY o -0- so- -0- -0- -0- -0- 0 43,647 9,000 610 Sins mre 20 99 1,222 Tote 2000 502878-62 1 148/7.8T- 67m 2 : ant na 160.0 % of Total BTU 83.4 15.8 0.8 -0- -0- incl in diesel 100.0 CANNERY na na (self generating) “F* es =o - -@- “er na na REMARKS: na ~ not available €9-TT ebed ENERGY BALANCE RURAL BRISTOL - 1977 BAY PENINSULA - PACIFIC CHIGNIK LAKE CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 10a Tu/—— 10°eTu/—L 10% Tu/—* 10%atus/—$ rosatu/—t— Ave—KWh ave. % of : 108BTU 10%aTU 108BTU 108 TU roeaty —menth _/ kwh Total TYPE No. 31,625 15,000 1,017 os it 3 2/37 6,362 RESIDENTIAL 25 eT 730875.9— “S37na— e e “TW 7 na “yeaa COMMERCIAL 2 9838 — = 0°< -0- -0- -0- e 18 738 . 13 na . 30,344 eat ae che in. 1_/ 106 4,187 LARGE USERS 1 ese 0 0 0 0 E97 ne 8 FISHING Cin na__/__na 0 VESSELS oS 109 Bue =i05 oe a na na PUBLIC 4,037 ~ aie 7 2 6 $57 BUILDINGS 2 oo SA ao =40 o ° 233 na at MILITARY 0 -0- -0- -0- -0- -0- -0- 0 71,792 15,000 1,017 . ae 30 168 11,904 TOTAL 30 95067362 -1,80875.5— “Sina ae 8 na 7760.0 % of Total BTU 83.2 16.0 0.8 -0- -0- incl in diesel 100.0 CANNERY na na (self generating) 7O- = Os nm? “0 Ole na na, REMARKS: na - not available ™_ BRIS4/A35 ENERGY BALANCE - 1977 RURAL BRISTOL BAY PENINSULA - PACIFIC IVANHOFF BAY CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 1088 TU 1otatus—S— otetu-—2— 10%atu-—*— 10s Tu-—$— _ t0*w Tu-—_$— AVE —MN ave. ¢ Bot 1088 TU 10°8TU 1088 TU 10°BTU rosary — month _/ why Total TYPE NO. sons 13,915 6,600 447 or, el no f46 2,799 een pl 7, 520/4.42 838/na ai/na S e 7217 na @5.4 3,472 Sag reed Ae in ee 1 10 479 COMMERCIAL 1 eta 0 0 0 0 3 na 4.6 an. tae aes i tay oH na na oO LARGE USERS 0 0 0 0 0 0 ua ua FISHING na na o VESSELS pa Ole i aor ole oe na na PUBLIC na na 0 BUILDINGS G “er shag ola a Oa = 0) na na MILITARY 0 -0- -0- -0- -0- -0- -0- 0 17,387 6,600 447 sige a 12) fe 8 3,278 Tore 0 39874.4e B38/na ai/na 9 P 19/7 na 700.0 4 of Total BTU 3.1 25.6 3 -0- -0- incl in diesel 100.0 CANNERY rie are ae bg: 2g ee na / na (self generating) REMARKS: nd school, no community center, no post office na / ona na - not available SO-TT ebeg BRIS4/A37 ENERGY BALANCE - 1977 RURAL BRISTOL BAY PENINSULA - PACIFIC PERRYVILLE CONSUMER ENERGY FORM CONSUMED. DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 10° TU/-—2— 10° Tru/-—_* 108s Tu/—&— — 10*°a Tu/_4. voseTus—S— Ave. tWh ave. & of 10°BTU 10°BTU 10°BTU 10°BTU weaTU —as kWh Total TYPE NO. 31,625 15,000 1,017 _— 25 37 6,362 RESIDENTIAL 3 RUE OT | Tee a -0- 0 RS 5,786 2 19 798 COMMERCIAL 2 7 18875-07— “oe = 03 os ee “aa 15,900 1 52 2,194 CORGE USERS y 2, 19475.07 me que ae GAGs 4,334 7 na 23.3 FISHING 5 Fh ie ax Nl - Bre «iz aii na_/ na 0 VESSELS na S ° e o o na / na PUBLIC 5 432 sore a2 Bors Lio 1 2 60 BUILDINGS 6075.07 1 na 0.6 MILITARY 0 -0- -0- -0- -0- -0- -0- 0 53,743 15,000 1,017 ee Lp 29 110 9,414 BOTAS ee 7,416/5.07 T, 30578. 66 987na o o 315 na 700.6 % of Total BTU 78.8 20.2 : 1.0 -0- -60- incl in diesel 100.0 CANNERY na na (self generating) S0le On -0- -0- -0- at ne REMARKS: no community center Ma - not available ~ 99-IT ebed Page ||-67 4. TOGIAK BAY Togiak and Twin Hills, the two villages in this subgroup, are coastal villages separated from the Nushagak area by a low range of mountains. The two villages are located across the Togiak river from one another and are the northern most coastal villages in the study area. For Twin Hills, the fuel and electrical data were estimated. For Togiak the information supplied by the electrical utility!!5 (AVEC) was used and combined with the estimated heating fuel usage to calculate the total fuel usage. All estimates were made in accordance with the parameters set forth in Appendix A. The number of residential consumers, small commercial consumers, large commercial consumers and public buildings in Togiak were taken from electrical utility records. The number of residential consumers in Twin Hills was obtained from a survey entitled Community Energy Survey made by State of Alaska. 190 The number of small commercial consumers in Twin Hills was estimated as described in Appendix A. The size of the large commercial consumer (the school) in both Twin Hills and Togiak was estimated from data received from the Southwest Region School District. 1°4 The number of public buildings in Twin Hills was taken from the State of Alaska, Regional Profiles. 1°% EXISTING ELECTRICAL SUPPLY. SYSTEM Togiak is the only village in this subregion that has a central power system. Togiak is part of the Alaska Village Electric Cooperative (AVEC) which is a Rural Electrification Association (REA) funded utility. AVEC which has a total generation capacity in Togiak of 481 kW, generated at a average rate of 7.37 kWh/gallon. The school in Togiak has an installed standby generation capacity of 75 kW. Besides the privately owned and operated small generators in Twin Hills, the school has generation capacity of 150 kw. ENERGY BALANCE - 1977 RURAL BRISTOL BAY TOGIAK BAY - TOGIAK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10®BTU 1088 Tu/—S— 10% Tu/—* 10% Tu/—S 10% Tu-—® wosatu/—t— Ave-Kwh ave. % of 10°BTU 10°BTU 10°BTU 10°BTU 1ofaTu ——— kWh Total TYPE NO. cone 114,441 56, 400 3,822 or 9a /_192 23,304 ES 94 75, 79376.15— 7, 163/7.08 348/na ola o AS 5/7 26g. > 680 19,763 oe Ave ave we 48 10 2,727 SORIA 10 RES o 9 : o “—e-a—. 70,689 o oe 1 231 9,755 Teen 1 Sy75576.15- “ae 2 ® sete BS FISHING na_/ na oO VESSELS oe anes Ros 02 ie poe na na PUBLIC 8,978 2 42 1,239 BUILDINGS 2 7723976.15- = 0% Sle a oe =e 7,766 722 3.3 MILITARY 0 -0- -0- -0- -0- -0- -0- ° 213,871 56,400 3,822 ae Sa 107 513 37,025 core 1075147615 7, 1637708 3487na o s 22. 160.0 % of Total BTU 79.8 b 18.3. 0.9 -0-- -0- incl in diesel 100.0 CANNERY 1 inc in large incl in large =a io ee 1 200 (self generating) users users ees as 700, na REMARKS: Central Electric Utility used 69,500 gal diesel fuel na - not available 89-1) aBeg ~~ —S—- wT W—- | ~ewreowewer ~S~eweweerewewewyrwwee - = ~ wee weer w~—~e wee ere wow w~ TOTAL SYSTEM KWH/MONTH x 10° Page i1-69 "1-72 TOGIAK 1977 SYSTEM ELECTRIC ENERGY USE 60 40 LH 20 JAN FEB MAR APR MAY JUN JUL AUG SEP ocT NOV DEC ESTIMATED PEAK °15iKW # OF CONSUMERS : 107 FIGURE IL-5 JUNE 1979 ENERGY BALANCE - 1977 RURAL BRISTOL BAY TOKIAK BAY - TWIN HILLS CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal * No. Cons/Annual MWH 10®BTU 108aTu/—*— 10%stu/—*— 10°aTu/—% 08a Tu-— woeatu-—S— Ave—KWR ave. % of 10¢aTU 10%aTU 10°BTU 108aTu rotatu —Beath_/ kwh Total TYPE No. ae 20,240 9,600 651 ar = 16 23 4,071 RESIDENTIAL 1%. Sees | Cater aL 0 0 asf 23 34 5,049 oe a ai =e 1 10 697 COMMERCIAL 1 —35776-05— 0 o 0 0 03 na aiapaes 30,344 : Sats at 1 106 4,187 LARGE USERS 1 ae -0- -0 0 o 7832 7 na 44.0 FISHING na_/__na 0 VESSELS na Ole 20k Ole or naOie na / na PUBLIC 4,037 2 6 557 BUILDINGS 1 —38976.05- one pon pos Ors 223 na 5.9 MILITARY 0 -0- -0- =(0 =O =e SO ° 59,670 9,600 651 i 20 145 9,512 TOTAL 200 R76.0S 12187708 na OS S 2 7 na 160.6 4 of Total BTU 86.6 12.8 0.6 -0- -0- incl in diesel 100.0 CANNERY Non! tae -s ae ss pat /t nal (self generating) REMARKS: “na 7 na Na - not available OL-11| a6ed ©0220 808080O8HHOOHOHOHHO8OCHHHO88OOHEECOEOSCEOES eee Page II-71 5. ILIAMNA LAKE Four villages in the Iliamna Lake area were made part of a subgroup because of their inland status and because of their centralized grouping around Lake Iliamna and Lake Clark. All of the energy use data for these villages was estimated. The estimates were made in accordance with the parameters set forth in Appendix A. Because it is a relatively new community, no data was available on Port Alsworth. For this reason the number of consumers was estimated from discussions with individuals having knowledge of this community . 197 EXISTING ELECTRICAL SUPPLY SYSTEM There are no central utilities in the Iliamna Lake subregion. Besides the numerous small generators in each village operated by private individuals, the schools have their own generation facilities. The in- stalled generating capacity in each of the villages is listed in the table below: VILLAGE INSTALLED CAPACITY Igiugig 2 - 20 kw Kokhanok 2 - 50 kw Pedro Bay 50 kW Port Alsworth 2-75 kW BRIS4/A43 ENERGY BALANCE - 1977 RURAL BRISTOL BAY ILIAMNA LAKE - IGIUGIG CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 1oSatu-—*— 10%aTu-—2 10%aTu/-—t 108s Tu/—_* wotatus-—t$— Ave—KWn) ave. ¢ bof 10%sTU 10%aTU 10°BTU 10°8TU voraTu —Meath_/ kwh Total TYPE NO. . 15,180 7,200 488 ae a 12 18 3,053 EEE UUs ag 2,095/5.07 914/7.4 44/na e o 721 na $2.9 3,787 1 10 523 COMMERCIAL 1 8s - -0- -0- -0- -0- 2 4 15,900 1 52 2,194 LARGE USERS 1 —18,800_ -0- -0- -0- == es 2,194/5.07 Cree ne E FISHING na na 0 VESSELS on oS ae Oe aC ss na na PUBLIC na na cP 0 BUILDINGS ° ={0i= = Ol oe anole Oe na na MILITARY 0 -0- -0- -0- -0- ae -0- 0 34,867 7,200 488 7 14 80 5,770 POTAL 4 H81275.07 —H477.— ‘ana : ° aa 4% of Total BTU 83.4 15.8 0.8 -0- -0- incl in diesel 100.0 CANNERY wipe -0O- aT nee it ha na na (self generating) o o 9 9 a) na na REMARKS: no post office, no community center na - not available ZL-TT e6ea APAOOSC4S ENERGY BALANCE - 1977 RURAL BRISTOL BAY ILIAMNA LAKE - KOKHANOK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gat No. Cons/Annual MWH 108 TU 108atTu/—S— 10*atu-—* 10% Tu/—* 108aTuz-—% oSatus—S— Ave-KWh pve. Lor 10°BTU 10°BTU 10°BTU 10°aTU 10°BTU ee kWh Total TYPE No. 20,240 9,600 651 aa Rte 16 23 4,071 RESIDENTIAL 16 ae Seior || 7s L ° ° “t+ S.-C COMMERCIAL 1 ag Ee oe Ole ‘a or 1 10 697 . na . 30,344 fi a el Ae 1_/ 106 4,187 LARGE USERS 1 Gee or -0 0 o ° ji ma —n.8 FISHING na na 0 VESSELS rs nia ae F eo ele = na na PUBLIC 4,037 hr NS aL giLi/neng 57 BUILDINGS 2) 9) pete Ota rou me 2 ° 337 a : MILITARY 0 -0- -0- -0- -0- -0- -0- oO 59,670 9,600 651 Lee Il 20/145 9,512 TOTAL 20 OT | aS oe 1 o 0 43 sé of Total BTU | 86.6 12.8 0.6 -0- -0- inet in diesel 100.0 CANNERY Cae ary a Sate rie na na (self generating) REMARKS: na na ~ not available €L-|| ebeg ENERGY BALANCE - 1977 RURAL BRISTOL BAY ILIAMNA LAKE - PEDRO BAY ENERGY FORM CONSUMED CONSUMER DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal No. Cons/Annual MWH 1088 TU 1oatus—S— 108atu-—2— 108 ru-_£ 10° Tu/-—* rotatu/—S$— Ave—kuh) ave. % of 10BTU 1088 TU 1oeaTU 108BTU yo’atu Benth _/ kwh Total TYPE NO. Ss 27,830 13,200 895 sa alas 22 32 5,598 Ree eA ee 3,841/5.21 © 1,676/7.87 iin a 9 721 ma 656 6,943 aie aly ee fils! | 2 19 958 COMMERCIAL 2 —yeRe ar 0 ° 0 5 2 ie 15,900 a Pat as sas 1 52 2,194 Ce 1 373475-27- 9 i. ° 4,334 7 na a3 FISHING na na oO VESSELS na aie Shr wale racks =O na na PUBLIC 7 432 ad ae gt ae 1 2 60 BUILDINGS 8075.27 762 na 0.7 MILITARY 0 -0- -0- -0- -0- -0- -0- 0 51,105 13,200 895 Sind ae 26 105 8,810 TOTAL 26 -7,08575.21 67677 .87- Bi/na o @ 33 na 100-0 % of Total BTU 80.1 19.0 0.9 -0- -0- incl in diesel 100.0 CANNERY ius =a oh na na (self generating) 270) = a 0 ° 0 na na REMARKS: no community center na - not available pl-1| e6eq APAOOSC 49 ENERGY BALANCE - 1977 RURAL BRISTOL BAY PORT ALSWORTH CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 10°sTus—&— 1088 Tu/—* 10¢aTus-—$ 10°aTus-—$ tosatus—s— Ave—kwh) ave. ¢ Yor 1088 TU 10°BTU 10°BTU 10°BTU 18BtU Sa kWh Total TYPE NO. 6,325 3,000 203 Ss re 1,272 Ree eNAL 5 873/na 381/na 18/na ao or Tat na 33.0 2,746 1 10 379 COMMERCIAL 1 Hina *0- -0- -0- -0- 3 ia ToS 15,900 a s2 2,194 LARGE USERS 1 — -0- -0O- -0- -O0- 2,194/na 4,334 na 7.1 FISHING na na o VESSELS na aes aos ele ey as na na PUBLIC na na 0 BUILDINGS a 2 o Ds a a na na MILITARY oO -0- =0- -0- #6 -O- -0- oO 24,971 3,000 203 i. 69 3,845 TOTAL Z 3, 446/na 381/na 18/na eo ae 820 f na 760.0 % of Total BTU 89.6 9.9 0.5 Pale =O inct in diesel 100.0 CANNERY i a fa yar tae na na (self generating) eo 9 ® e ° na na REMARKS: population $25, assume 5 families na - not available SL-1| aBed Page 11-76 6. INLAND There are four villages that were categorized as inland villages. They were placed in that subregion, as opposed to the Iliamna Lake subregion, because they are all located on a major river. Whereas the villages in the lIliamna Lake subgroup are centered around Lake lliamna and Lake Clark. Because New Stuyahok has a central utility the actual electrical fuel and electrical energy usage was combined with estimated heating fuel and heating energy. Information concerning energy and fuel consumption in the remaining villages in this subregion was estimated. All estimates were made in accordance with the parameters set forth in Appendix A. EXISTING ELECTRICAL SUPPLY SYSTEM Only one of the villages in the inland subregion, New Stuyahok, has a centralized power system. New Stuyahok is part of the Alaska Village Electric Cooperative (AVEC). The number of consumers, the electrical fuel usage and the electrical usage data for New Stuyahok was obtained from AVEC.115 The total installed generation capacity in this village system was 120 kW and AVEC generated at an average rate of 5.81 kWh/gallon. In addition to the private generators in each village the installed generating capacity in each of the village schools is listed in the table below: Sti VILLAGE INSTALLED CAPACITY Ekwok 75 kW Koliganek Unknown Levelock 50 kW New Stuyahok 75 kW Standby APAQOSCS1 ENERGY BALANCE - 1977 RURAL BRISTOL BAY EKWOK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°BTU 1otatu/—S— 10%atu-—S— 0*stu-—S— 10s Tu-—_$— _ 10®s Tu/_$— AXE—BAD pve. ¢ = Dol 1088 TU 10%aTU 10°BTU 10%aTU rotatu —B28th_/ kwh Total TYPE No. 31,625 15,000 1,017 cas ee Bt 6,362 RESIDENTIAL 2% eer || 7490877.08 ana 0 ° 1217 na —~ $2.2 7,890 2 19 1,089 COMMERCIAL 20 =paeee 0 -0- -0- -0 aS 30,344 1 106 4,187 Sheen Maen rr CE 7o.7 rar a se iat FISHING na na 0 VESSELS Be de eos a ea aes na na PUBLIC 4,037 2/ 6 557 BUILDINGS 2 35973. mols =0)= Oe Oe z na 4.6 MILITARY ° -0- -0- -0- -0- -0- -0- ° 73,896 15,000 1,017 30 / 168 12,195 TOTAL 300 1877318057708 jn =o 70s na —T60.0 % of Total BTU 83.6 15.6 0.8 -0- -0- incl in diesel 100.0 CANNERY na na (self generating) = ie re 78° ~8- = 0. na na REMARKS: na - not available LL-\| e6ed ENERGY BALANCE - 1977 RURAL BRISTOL BAY LEVELOCK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10®BTU 108aTu/—*— 10% Tu/-—3 10°aTu/—* woeatu/—$— 108 Tus—$— Ave—Kuh ave. ¢ = of 08a TU 10°BTU 10°BTU 10°BTU rosary —Bonk _/ kwh Total TYPE NO. 35,420 16,800 1,138 28/4 1,126 RESIDENTIAL a 4, 88673.17 2347417 “647na 20'S e a7 na 8,837 ies xe =e ae 2 19 1,220 COMMERCIAL 2 Tea ° 0 o 0 7 2 Ae 30,344 = ae ne are 1_/_106 4,187 PEARCE UEERS V0 a8773.17 ¢ e . o “wey nas «8 FISHING na_/__na oO VESSELS ne Oe +0 eon =0= == Re vaina== PUBLIC 2 4,037 oe Boe =o oe 2 6 557 BUILDINGS 73.1 232 na a5 MILITARY 0 -0- -0- -0- -0- -0- -0- o 78,638 16,800 1,138 Sa oF ee 33 172 13,090 TTA 33 70, 85273.11 2, 134/4.1 i047na c 2 a na 760.6 a of Total BTU 82.9 16.3 0.8 -0- -0- inct in diesel 100.0 CANNERY ae ie Soe —0~ ae na_/__na (self generating) REMARKS: na / na na - not available 8L-1| aBed ~ 9 APAOOSCS7 7 ENERGY BALANCE - 1977 RURAL BRISTOL BAY KOLIGANEK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gal Gal No. Cons/Annual MWH 10°8TU 10%atu/—2— 108atu-—S— 10° Tu/—_£ 10% Tu/—* rotatu-—S— Ave—Kuh ave. ¢ Bot 10°BTU 10°BTU 10°BTU 10°BTU 10850) (awe kWh Total TYPE NO. 25,300 12,000 813 20 29 5,089 RESIDENTIAL 20 aes hina aa =10\5 =o- 721 na a7 6,312 2 19 871 COMMERCIAL 2 —e— -0- = 05 =o cee 3 na Fat 30,344 e Bll a 1 106 4,187 LARGE USERS 1 Hittin -0- ao 0 0 E na eet FISHING na na oO VESSELS id = Oe ial als ia 05 na na PUBLIC 4,037 os th as ibe ol de 2 6 57 BUILDINGS 2. 357/na o co) 2 a na 5.2 MILITARY o -0- -0- -0- -0- -0- -0- o 65,993 12,000 813 x, 25 160 10,704 Touee 6 3, 106/na T,584/na na OS ene) 4 na 700.0 % of Total BTU 85.1 14.2 0.7 70> a inci in diesel 100.0 ‘ CANNERY ee es ie aia na_/__na (self generating) o 0 e ls 7 0'< na na REMARKS: na ~ not available we 6L-1| 25ed APAOOSCSS ENERGY BALANCE - 1977 RURAL BRISTOL BAY NEW STUYAHOK CONSUMER ENERGY FORM CONSUMED DIESEL GASOLINE PROPANE JET FUEL AV. GAS ELECTRICITY TOTAL Gal Gal Gal Gat Gal No. Cons/Annual MWH 1088TU 108aTu/-—S— 108s Tu-_* 10¢aTu/—* 108atu/—* wosatu-—— AvekwR) ave. ¢ Yof 1088 TU 10¢8TU 10a TU 10°BTU rotatu —menth_/ wh Total TYPE No. 54,592 25,200 1,708 Laid ee 42_/ 88 10,899 Se eA ae 7,534/5.73 _~3,200/8.66- 155/na 0 o 173 24 ay O48 3,716 sae an Lat ee 2 6 519 COMMERCIAL 2 ss 75 0 0 0 o 256 4 sui 36,118 ue Al 1 106 4,98: LARGE USERS 1 a -0- 0 0 ° as 3 Ages FISHING na__/ na oO VESSELS ne ah la aos rae pele Wor na na — PUBLIC 3,404 1 4 470 BUILDINGS 1 —a7675-15 ors OF mole rely 254 z Paes MILITARY ° -0- -0- -0- =0- Ole Ole ° 97,830 25,200 1,708 we ET 46/204 16,862 ve 46 755077573 3, 20078.65- “557na e e SB fs a: 000 % of Total BTU 80.1 19.0 0.9 -0- == incl in diesel 100.0 TAY -0- =0= -0- 05 =10)= na_/__na (self generating) REMARKS: Central Electric Utility used 35,000 gal diesel fuel na / na Ma - not available 08-11 e6eq TOTAL SYSTEM KWH/ MONTH x10> 20 a 10 JAN FEB MAR APR NEW STUYAHOK |977 Page 11-81 SYSTEM ELECTRIC ENERGY USE MAY JUN FIGURE IL-6 \/ V JUL AUG SEP oct ESTIMATED PEAK:IOOKW # OF CONSUMERS: 46 NOV 11-93 DEC JUNE 1979 100 101 102 103 104 105 106 107 108 109 110 da Page 11-82 F. BIBLIOGRAPHY AND REFERENCES "Community Energy Survey, 1978". Department of Commerce and Economic Development, Division of Energy and Power Development, State of Alaska. "Inventory of Rural Sanitation Services", March 1977. State of Alaska, Department of Environmental Conservation. "Community Profiles", 1978. State of Alaska, Department of Community and Regional Affairs. "Alaska Regional Profiles, Southcentral Region and Southwest Region", June 1974, published by the State of Alaska in cooperation with the Joint Federal State Land Use Planning Commission for Alaska. "School Generation Survey", December 1978. Performed by Industrial Services for the Southwest Regional School District. Letter regarding energy use by military installations in the Bristol Bay area, March 1979. By Mr. Bodnar, Department of the Air Force. Letter regarding fuel use and generation installations, April 26, 1979. By Don Anderson, The Lake and Peninsula School District. Letter regarding population, fuel use and generation facilities, April 10, 1979. By Glen R. Alsworth, Sr., Port Alsworth, Alaska. Letter regarding fuel deliveries made by the Bureau of Indian Affairs to villages in the Bristol Bay area. January 19, 1979 by G. W. Taylor, United States Department of the Interior, Bureau of Indian Affairs. Letter regarding fuel use and generation installations, April 23, 1979. By Gust S. Bartman, City of Manokotak, Manokotak, Alaska. Letter regarding fuel deliveries made to villages in the Bristol Bay area, March 8, 1979. Moody Sea Lighterage, Aleknagik, Alaska. Letter regarding cannery installations, March 19, 1979. By Don Wanie, State of Alaska, Department of Fish and Game. ec. 112 113 114 115 116 117 118 Page 11-83 Letter regarding fuel distribution from Dillingham and fuel usage in Dillingham, March 1979, Mr. Tom Ward. Chevron distributer, Dillingham, Alaska. Year end REA Form 12F and monthly REA Form 7 for 1977, Nushagak Electric Cooperative, Dillingham, Alaska. Year end REA for 12F and monthly REA Form 7 for 1977, Naknek Electric Association, Naknek, Alaska. Written communication regarding electrical use in New Stuyahok and Togiak, March 1979, from Alaska Village Electric Cooperative. Interview with Naknek Chevron Fuel distributer. April 1979. "Iliamna Newhalen Electric Cooperative 1978 - System Planning Study" by R. W. Retherford Associates. "1978-1980 Construction Work Plan" for Kodiak Electric Association by R. W. Retherford Associates. ELECTRIC ENERGY DEMAND PROJECTIONS ©8000 00S OHHH O8 66 OD OOS SOLS OTE HHOHOHOHEHOTO COO OOSS OOO OSEOHOEH2OHOOHHOHOHOOOSD OOOOH OSO Page 111-87 Ill. ELECTRIC ENERGY DEMAND PROJECTIONS A. INTRODUCTION AND SUMMARY Use of electric energy in the Bristol Bay Region is low compared to other areas in Alaska. This is mostly attributed to a low "hook-up saturation" level, low population growth, and low economic development. Historical increase in use of electricity supplied by the two major utilities in the region has been 11% per year since 1970. This implies that once electric energy becomes available on a reliable basis the usage will increase not only with new consumer connections but also with increased use by the individual consumers. The rapid increase in cost of electricity in the last few years has not caused a reduction in consumption, mostly because the users in the area are still in the process of applying electric energy to more and more tasks. Generally it can be assumed that the use of electricity will increase with the increase in family. income if the annual bill remains within a certain percentage range. A recently completed study for a southcentral utility!?9 in Alaska showed that over a 35 year period the average energy use by the individual residential consumers has increased by 2700%, but that the monthly bill has remained constant between 2.4 and 3.9% of the family income. The lowest expected increase of electric energy use has therefore been assumed to be at 4.5%/year (average) with a higher growth during the first 10 years of the study period and a lower growth during the second half from an estimated 20,900 MWh annually in 1977 to 57,800 MWh in 2000. This growth can be expected if the continued use of diesel generation increases the cost for electric energy at the presently prevailing rate of escalation. ; The high growth rate has been assumed at twice the low growth rate. This rate implies that more cost stable energy sources - e.g., hydro - are utilized and encourage private and industrial use. If the fishing industry expands and oil or gas development takes place the high growth rate is considered to be conservative. Separate power requirement forecasts prepared for the individual communities will allow evaluation of smaller areas in regard to potential resource developments. A bibliography at the end of this section lists studies and publications used to establish the electric power requirements. Section ||| - Demand Projections Page 111-88 BRIS1/H B. PROJECTION PARAMETERS The historical growth pattern for the population of the Bristol Bay Area is shown on figure Il|l-1. ‘Possible extrapolations for future growth assume the rate for 1960-1977 as the low growth rate. The higher rates shown represent the predicted growth of 2% per year and more from the Alaskan portion of the U.S. Department of Commerce Study "Preliminary Forecast of Likely Use of Electric Energy to the Year 2000" (11/1/78) and from the "Man in the Arctic" Model used for the Southwestern Region in the University of Alaska, Institute of Social and Economic Research Publication "Alaska Electric Power Requirements" (6/77). The growth beyond 1990 to the year 2000, from the ISER publication has been extrapolated at the rate of growth from 1980 to 1990. Although the ISER study assumes an overall higher growth rate caused by oil and gas development, it is anticipated that small villages will not particularly benefit from the capital intensive petroleum developments. 7000: 6000: e 3 POPULATION MISTORIEAL DATA Is UR CENSUS imFORMATION FOR 1960 & 1970 FWTT DATA FROM OEPARTMENT OF ENVIRONMENTAL INFORMATION 4000 FORECAST FoR ALASKA BRISTOL BAY POPULATION HISTORICAL & FUTURE TRENDS FIGURE IT -1 Page II1-89 Extension and development: of the fishing industry, agriculture etc., will tend to further the population growth in rural areas. The population increase shown for the individual locations (parts C to | of this section) takes this differentiation into account and addresses it in greater detail. It is further assumed that the number of members per household will follow the overall Alaska tendency and decrease from the average 1977 ratio of 5199 in the Bristol Bay Area at a rate of 1% per year to an average of 4 by the year 2000. Therefore the number of residential electric energy users will increase at a higher rate than the population. The number of small commercial energy users, e.g. stores or shop facilities, is assumed to increase in direct proportion to that of residential consumers. Electrical energy use has been historically low compared to other areas in Alaska, but if a central power supply becomes available for the individual villages it is expected that the demand will gradually increase to levels that are comparable to the projected use in the Kodiak area. The intensity in the individual use of electrical energy (kWh per month per consumer) has been escalated under two different assumptions: Th If electricity continues to be generated by small diesel engines and the cost of fuel is escalated at a rate of 2% above the general inflation rate, the individual increases in usage will be less than the historical growth rates for the various locations until 1990. After 1990 further decreases in growth rates will be experienced, reflecting increased use of energy conservation measures. 2s If a more "cost" stable source of power (hydro) becomes available, the higher intensity of use will reflect the increased utilization of electricity for appliances and some electric heating. The economic backbone of the Bristol Bay area at this time is the salmon fisheries. Large Power Consumers (LPs) are therefore mostly fish processors. A total of 20 fish processing facilities are operable and processing an average of 60-70,000,000 Ibs. of salmon per year. 1°3 At this time all canneries generate their own electricity at peak season with diesel generator sets up to 600 kW in size. The addition of freezing and cold storage facilities will increase the demand by an average of 150 to 300 kW per cannery. The present processing season (June/July) is expected to be extended by an increase of herring catches. Bottom fishing will have an impact on the communities with ice-free ports on the Pacific Ocean side of the peninsula. It is expected that electric energy for all canneries will be supplied by central plants within the next 20 years. A dramatic increase in number of facilities and electric energy use for the Page 111-90 individual canneries beyond the above addressed parameters is not anticipated. Therefore the following energy use will be assumed for an average processing facility: a. In the Bristol Bay Area Peak Demand: Canning only 200 - 400 kw With additional freezing facilities 300 - 600 kw Monthly energy use during peak season (June/July): Canning only 80 - 150,000 kWh/mo. With additional freezing facilities 150 - 250,000 kWh/mo. Year round average use: 3 - 10,000 kWh/mo. b. Pacific Coast Peak Demand: Canning only 100 - 300 kw With additional freezing facilities 200 - 500 kw Monthly energy use (year round): Canning only 80 - 120,000 kWh With additional freezing facilities 150 - 180,000 kWh Development of Bristol Bay oil and gas reserves will begin with a lease sale in the Southwest Bristol Bay uplands in 19811. Offshore exploration and development is still very controversial and not expected until the late 1980's or early 1990's. Exploration in itself is not expected to have a major impact on the electric power requirements. Development and operation of a reservoir will have power requirements in the magnitude of 50 - 200 MW and depend greatly on location (offshore/land) and size of the reservoir. Therefore attempts to assess these possibilities at this time are virtually impossible. The following table and figure II!-2 show the anticipated electric power requirements for 1977 to 2000 in the entire Bristol Bay area. 10il and Gas Journal 2/26/79 Page 111-91 1000 == 900 800 700: 600: por! 500: + 400 300 HIGH Low 200 = HIGH 100: ~~ 5 LF =.468 4 3 1 | BRISTOL BAY POWER REQUIREMENTS ° | FIGURE ID -2 t | 1970 1977 1980 1985 1990 1995 2000 JUNE 1979 Page 111-92 e@ BRISTOL BAY e@ ELECTRIC POWER REQUIREMENTS 1977-2000 e 1977 1980 1990 2000 e@ POPULATION 4327 (high) 4572 5535 6548 e (low) 4431 4808 5225 e (1) # of residential 1131 Chigh) 1315 1938 2440 @ consumers Clow) 1296 1828 2246 e (2) average kWh/mo/ 291 (high) 385 660 1364 e consumers Clow) 324 424 473 (3)+(1)+12x1000 @ (3) MWh/year residential 3951 (high) 6081 15338 39934 r ) consumers Clow) 5043 9298 12752 e (4) # of small commercial 233 (high) 275 419 532 e@ consumers (low) 274 389 490 e (5) average kWh/mo/ 1553 (high) 1913 3034 6047 e consumer (low) 1534 2155 2312 e (6)+(4)+12x1000 (6) MWh/year 4342 (high) 6313 15256 38604 e sm. com. cons. (low) 5045 10059 13597 e (7) # of large 127. (high) —'156 176 198 6 cons. + public buildings (low) 156 170 177 e (8) average kWh/mo/cons 8039 (high) 9800 22944 34590 @ (9)+(7)+12x1000 (low) 8640 10988 14786 e (9) MWh/year 12251 (high) 18345 48457 82185 @ LP's (low) 16175 22415 31405 e (10) System MWh/year 20544 (high) 30739 79051 160723 @ (3)+(6)+(9) (low) 26263 41772 57754 e (11) System .45 (high) 46 .48 .53 e Load Factor (low) -45 .46 .48 e (12) System Demand 5400 (high) 7600 18700 34500 @ kW Clow) 6600 10300 13500 e (10)+8760+(11)x1000 e Note: Totals and subtotals have been rounded off. Total and Subtotal MWH @ listed here represent the summation of usage by various consumer @ classifications from similar tables prepared for the individual communities. @ Page 111-93 C. DILLINGHAM (INCLUDES ALEKNAGIK, KANAKANAK AND NELSONVILLE Dillingham serves as a major transportation hub for the surrounding villages. The economy is based on the fishing industry; government and native corporation expenditures; and trapping. Development potential exists for oil exploration with the first lease sale anticipated in 19814. The exploration activities are expected to cause only a temporary increase of the population in the Dillingham area by SO to 100. If commercial amounts of natural gas or oil are found a permanent increase in population to 4 to 6 times the present is conceivable. This development would start after 1986 and not culminate until after the year 2000. For this study the impact of oil and gas development on population has been assumed as follows: 1977 1980 1990 2000 Population 1025 1200 2400 6200 The historic growth for. Nushagak Electric since 1970 has been as follows: Number of Consumers 5% increase per year Energy Use 12% increase per year Peak Demand 13% increase per year It is anticipated that with or without oil development the population, and with it the number of consumers in the Dillingham area, will continue to grow at a rate above the growth rate for the overall Bristol Bay Region. The latest power requirements study for the co-op was prepared in 1977 and used the following growth rates for the next 10 years: Number of Consumers % increase per year Energy Use 11% increase per year Peak Demand 11% increase per year 1The Oil and Gas Journal - February 26, 1979 Page 111-94 The above rates follow the historical pattern with a slight emphasis on a faster increase in the number of people using electricity compared to the increase in intensity of use. The study does not anticipate drastic changes in the development of the Dillingham area. Agricultural potential has been investigated and preliminary findings indicate relatively good potential!®? for certain grains in the Nushagak valley, although further tests will have to be conducted. It is anticipated that major agricultural developments will mostly influence the villages in the valley and Dillingham only by the influx of small commercial enterprises. The fishing industry is expected to expand but year round operation is precluded due to pack ice conditions during the winter months. The two possible development scenarios shown on "Dillingham - Power and Energy Requirement 1977 - 2000" and in the table "Dillingham - Electric Power Requirements 1977 - 2000" are based on the following parameters: qe Low Growth Scenario The number of residential consumers increases in relation to the population growth with a 1% per year reduction in family size. Overall energy use is anticipated to reflect the rapidly increas- ing cost of diesel-generated electric power. Use by residential consumers is expected to grow in accordance with the previously mentioned power requirements study until 1990 (7% per year)-and then reduce to 4%/year reflecting energy conservation measures. Consumption by small commercial con- sumers will generally follow the trend established for residential users. Industrial use and other large power consumers use has been evaluated as follows: a. Schools and Public Buildings - To increase at population growth rate. b. Fish Processing Industry - The existing cannery and cold storage facility are expected to be supplied by the central utility; no further additions are anticipated. Page I11-95 Accelerated Growth Scenario This scenario would fit two possible developments: a. The individual energy usage grows as assumed under the "low growth" scenario but the population growth is accel- erated due to oil and gas or other industrial development. Ds If a cost stable source of power becomes available - such as hydro - it is conceivable that the individual use will increase by 25-30%. This increase would account for some utilization of electric heat. In this case the number of consumers is assumed to grow as described under the "low growth" scenario. : While the system projections on Figure I11-3 "Dillingham Power Requirements" can be used for either development, the "cost stable" source has been used for the residential and small commercial consumer category in the table. Again the small commercial consumers and their usage follow the trend of the residential consumers. For large power users the base established in the "low growth" scenario has been utilized and one additional processing facility has been added. DILLINGHAM POWER REQUIREMENTS 1977-2000 mien Low mien Low arr 1980 es mo mes 2000 FIGURE IE - 3 FIGURE 111-3 Page 111-96 e @ DILLINGHAM, ALEKNAGIK, KANAKANAK, OLSENVILLE @ (NUSHAGAK ELECTRIC ASSOCIATION) e ELECTRIC POWER REQUIREMENTS 1977-2000 @ 1977 1980 1990 2000 @ POPULATION 1025 (high) 1078 1276 1510 e (low) 1059S‘ 1317 @ (1) # of residential 359- Chigh) 404 590 750 e consumers Clow) 404 590 750 e (2) average kWh/mo/ 370 (high) 478 799 1690 e consumers (low) 413 558 630 @ - @ (3) MWh/year 1596 Chigh) 2317 5655 15210 @ residential cons. Clow) 2000 3950 5670 (1)x(2)x12=1000 e@ @ (4) # of small commercial 80 Chigh) 90 133 170 e consumers (low) 90 133 170 @ (5) average kWh/mo/ 1224 (high) 1581 2633 5542 consumer Clow) 1278 1911 2158 ® (6) MWh/year 1175 (high) 1707 4202 11306 @ sm. com. cons. (low) 1380 3050 4402 (4)x(5)x12+1000 e (7) # of large 61 Chigh) 62 66 72 e cons. + public buildings (low) 62 66 71 e (8) average kWh/mo/cons 2730 (high) 3427 11645 21991 e Clow) 3427 5139 6925 e (9) MWh/year 1998 (high) 2550 9223 19000 @ LP's (low) 2550 4070 5900 e (7)x(8)x12+1000 e (10) System MWh/year 4769 (high) 6574 19080 45516 eo (3)+(6)+(9) +200 (low) 5930 11070 15972 e + cannery in 1977 @ (11) System 45 (high) 25 255: .6 e Load Factor wd (low) .45 .49 aa e (12) System Demand 1200 Chigh) 1500 3960 8660 @ kW 1200 (low) 1500 2580 3650 e@ (10)+8760+(11)}x1000 e % OF ammua roTaL Page 111-97 If the fish processors are supplied by a central utility it is expected that the systems load factor will improve slightly by introducing a load in summer at a time of normal low demand in the system. It is, however, not anticipated that the system peak will occur in summer. The following figure !1!-4 "Dillingham - Seasonal Electric Energy Use" attempts a correlation between demand and energy use on a monthly basis if fish processors are centrally supplied. It should be noted that this graph is only valid if the assumed ratio between normal system load and processing load remains constant (1977 base plus 2 processors with cold storage). DILLINGHAM SEASONAL ELECTRIC ENERGY USE — — wae re. wan are way one war ave wrt or now oa FIGURE II1-4 Page 111-98 D. NAKNEK/KING SALMON General economic and population patterns are considered similar to the Dillingham area, therefore the general system growth has been assumed at the same rates as the Dillingham system. The military installations at King Salmon are expected to remain constant in their electric energy use for the time considered in this study. With 9 fish processing facilities presently located in the Naknek/South Naknek area it is assumed that eventually all the electric energy used by these facilities will be supplied by a central utility. It is further expected that most processors that presently exclusively can fish will add fresh-freezing equipment! and cold storage facilities. A gradual extension of the fishing season from 2 to about 4 months is expected when other fish than salmon will increasingly be utilized. Herring appear to have good potential when the harvesting techniques are adapted. The energy use for the large power consumers reflects the above parameters by assuming 9 processors operating canning and freezing equipment for 4 months in the year 2000 in the accelerated development scenario. The low growth parameters have been established with the following fish processing facilities in 2000: 4 processors canning 2 months 4 processors canning and freezing 2 months 1 processor canning and freezing 4 months lf all canneries are centrally supplied it is anticipated that the system will be a summer peaking system with load characteristics approximately as shown on Figure |1I-5 "Naknek - Seasonal Electric Energy Use". The forecast of power use for Naknek is shown on Figure II!-6 "Naknek Power Requirements 1977-2000". Istate of Alaska, Department of Fish and Game, Letter of 3/19/79 Page 111-99 NAKNEK - KING SALMON SEASOWAL ELECTRIC ENERGY USE “% 1% # ‘% OF aumval EAE Ocuane % OF annua. rota. % om FiguRE I-68 Load and consumer projections have been based on a 1978 REA power requirements study for Naknek Electric Association. ©9SSOOOOOOOOOHOOOOOOHOOOHOOOOOOOOOOOCOCOOE® 2 Page 111-100 FIGURE III-6 NAKNEK POWER REQUIREMENTS 1977-2000 100,000 90,000 + + al a 80,000|_ 70,000 60,000 + 1 50,000 4 HIGH 40,000 30,000) Low 20,000] on 10,000 + 9000 [= | = HIGH 8000! 7000 | a 6000) ao 4000 oe TERE 3000! ee Sn — KW 2000 1977 1980 1965 1990 1998 2000 FIGURE IT -6 Page 111-101 NAKNEK - SOUTH NAKNEK - KING SALMON ELECTRIC POWER REQUIREMENTS 1977-2000 (10)+8760+(11)x1000 e e @ @. @ e e@ 1977 1980 1990 2000 @ POPULATION 500 Chigh) 526 623 437. e@ Clow) 517 577 644 @ (1) # of residential 203. (high) ~—258 410 525 consumers low) 258 410 525 e ¢ @ (2) average kWh/mo/ 534 (high) 618 888 1690 @ consumers (low) 528 620 643 @ (3) MWh/year 1302 (high) 1918 4367 10647 e@ residential cons. Clow) 1635 3050 4050 e@ (1)x(2)x12+1000 e (4) # of small commercial 76 (high) 104 165 211 e consumers (low) 104 165 211 @ (5) average kWh/mo/ 2680 (high) 2847 4090 7740 @ consumer (low) 2300 2960 3003 e (6) MWh/year 2444 (high) 3553 8098 19600 ® sm. com. cons. (low) 2871 5860 7603 @ (4)x(5)x12+1000 e (7) # of large 13 (high) 18 20 21 ® cons. + public buildings (low) 18 19 19 ® (8) average kWh/mo/cons 50929 (high) 39907 73071 83068 @ (low) 37130» 43248.-~=— 50101 @ (9) MWh/year 7945 (high) 8620 17537 20933 e LP's Clow) 8020 9860 11423 e (7)x(8)x12+1000 ® e (10) System MWh/year 11691 (high) 14086 30002 51180 (3)+(6)+(9) 1440 Clow) 12526 18770 23076 e + cannery in 1977 e (11) System .56 (high) 56 .56 6 e@ Load Factor .56 (low) .56 .56 .56 @ e (12) System Demand 2400 (high) 2870 6120 9740 e kw 2700 (low) 2550 3830 4700 e @ e ® Page 1I11-103 ES ILLIAMNA - NEWHALEN - NONDALTON \liamna is rapidly developing into the center of activities in the entire Lake Iliamna area. The economy is based on fishing and tourism during the summer and in Iliamna itself, on employment in government and state offices as well as lodges. A system planning study!18 for a forming electric co-op has been used as a base for the power requirements in this area. The growth projections in the system study are considered very conservative and have therefore been used as the "low growth" scenario. For the "accelerated growth" scenario it has again been assumed that the availability of less cost intensive hydro-power will encourage the use of electricity by residential and small commercial consumers to an extent where the individual use will reflect the utilization of some electric heat, ranges, clothes dryers, water heaters, etc. and larger residences. In the large consumer category the addition of a third school between 1980 and 1990 and cold storage facilities or a similar consumer between 1990 and 2000 have been assumed. Since this area did not have a central utility in the past no history or seasonal electricity use is available. The system is expected to be winter peaking with an annual load factor of .5 to .55. The following figure !I|-7 "Iliamna - Power Requirements 1977 - 2000" and Table "Iliamna - Electric Power Requirements 1977 - 2000" show the anticipated use for the area. ® @ e ® « PAGE 111-104 : ‘ @ @ @ « @ e e @ @ @ e@ e * ILIAMNA /NEWHALEN/NONDALTON e inoco POWER REQUIREMENTS 1977-2000 9000 T e 7oea a e #000 ® 5000 eh e oo @ pa00 @ sc00) Low ® HIGH ; e "300 e 700 e ne | ee 4 Low : 400 =] ees eel o_o e 2 ew pe 7 @ 200 : e 100 4 ® 1977 1980 1988 1990 1998 2000 @ FIGURE IL-7 e @ e@ @ Page 111-105 e |LIAMNA/NEWHALEN/NONDALTON e@ ELECTRIC POWER REQUIREMENTS 1977-2000 ® @ 1977 1980 1990 2000 @ POPULATION 389 (high) 409 484 573 e (low) 402 448 500 e (1) # of residential 61 (high) 97 165 210 e consumers Clow) 97 165 210 @ (2) average kWh/mo/ 280 Chigh) 438 597 1200 @ consumers Clow) 360 360 360 ® (3) MWh/year 206 (high) 510: -. 1181 3024 e residential cons. Clow) 419 713 907 e (1)x(2)x12+1000 ® (4) # of small commercial a Chigh) 26 44 56 e consumers Clow) 26 28 38 e (5) average kWh/mo/ 969 (high) 1260 1716 3461 @ consumer (low) 1035 1214 1300 @ (6) MWh/year 314 Chigh) 393 906 2326 @ sm. com. cons. (low) 323 408 602 @ (4)x(5)x12+1000 e (7) # of large 3 (high) 4 4 6 e cons. + public buildings (low) 4 4 4 e (8) average kWh/mo/cons 13344 (high) 13333 16666 40556 e (low) --13333" -. 13333 =. 794333 e e (9) MWh/year 480 (high) 640 800 2920 LP's (low) 640 640 640 e (7)x(8)x12+1000 @ e (10) System MWh/year 1000 Chigh) 1543 2887 8270 e (3)+(6)+(9) (low) 1382 1761 2149 @ (11) System 4 (high) 5 5 .55 Load Factor Clow) 5 5 5 6 @ (12) System Demand 285 (high) 352 660 1720 @ kw (low) 315 400 490 (10)+8760+(11)x1000 6 e Page 1I1!1-106 F, RURAL BRISTOL BAY The grouping of the villages into geographical areas has been established in the "Energy Balance" section of this report. Historical population growth for the villages has been varied and will be addressed individually. To determine future power requirements it has generally been assumed that a central station will supply electric energy. The effect of improved electric service is anticipated to be an increase in the intensity of use as compared to individually operated generators. 195 Further more, with the subsistence economy changing in many communities into a cash economy and subsequent improvements in the quality of life, new electric loads will require service.112 The HUD houses planned for various villages will be larger than existing older housing and be equipped with more appliances using electricity (see Appendix A for distribution and usage of electrical appliances). Water and sewage treatment plants, new and larger schools, and cold storage facilities are expected to be installed in all villages during the time covered by this study. The scenarios of low or accelerated growth will again greatly depend on the cost of power and the economy in the individual community. By assessing the villages individually or within the geographic setting it has been attempted to arrive at projections that are most likely to be realized. Power requirement studies prepared for the REA - Co-op supplied communities Togiak, New Stuyahok and Egegik have been used as guidelines for other villages with similar conditions. The seasonal energy use pattern will reflect greatly whether fish processing facilities are operating in a community or not. The following figure I11-8 "Rural Bristol Bay - Seasonal Energy Use" has been compiled by utilizing the 1977 data for Togiak, New Stuyahok, and Egegik for the curve representing "Energy Use Without Fish Processing Facilities". One cannery or freezing plant operating with a usage of 100 - 150 MWh/month during June and July but without any winter use has been added to arrive at the curve representing "Energy Use With Fish Processing Facilities". RURAL BRISTOL BAY SEASONAL ELECTRIC ENERGY USE (TYPICAL ) 10 % 2 9% m7 oe xX 3 —-—T \ 8 % Pace u ae . coe TOTAL a x 7 6 % mT ° ENERGY USE WITHOUT \ ‘ FISH PROCESSING FACILITIES %}+-—— ann % OF ANNUAL a 3% | - 4 ENERGY USE WITH FISH 'SSING FACI —aeepneee +... 2% ee ee ss — ZOL-LLL ebed 1% 7 T JAN FEB MAR APR MAY JUNE JULY AUG SEPT oct NOV DEC FIGURE I -8 Page 111-108 These energy usage patterns can be used for all communities except for those located on the Pacific coast of the Alaska Peninsula. A separate graph will illustrate energy use in these villages. 1. Nushagak Bay Area | Lifestyle in these communities is determined by fishing. 1.1. Clark's Point Similar to Ekuk this village has experienced flooding and relocation has been planned. The population has declined from 130 in 1960 to approximately 70 in 1977. With new housing units planned by HUD and increased incomes in the fishing industry the growth potential is considered good and has been assumed at 5% per year (high) to 1990, dropping to 2.5% per year after that year for this study. Low growth has been set at 1% per year. School, community buildings and eventually fish processing facilities are anticipated in the large consumer section between 1980 and 1990. The electric power use is forecast on Figure I11-9 "Clark's Point - Power Requirements 1977-2000" below: CLARK'S POINT POWER REQUIREMENTS I977—2000 Low wien mewn /YEAY wr? 1980 i908 1980 ro88 2000 FIGURE IL -9 FIGURE [11-9 Page 111-109 CLARK'S POINT ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 62 (high) 72 117 150 Clow) 62 64 65 (1) # of residential 15 Chigh) 18 32 43 consumers Clow) 15 17 19 (2) average kWh/mo/ 121 Chigh) 179, 468 1000 consumers Clow) 135 205 234 (3) MWh/year 21.8 (high) 39 180 516 residential cons. Clow) 24 42 53 (1)x(2)x12+1000 (4) # of small commercial 2 (high) & 4 5 consumers Clow) 2 2 2 (5) average kWh/mo/ 805 Chigh) 1208 3111 6646 consumer (low) 833 1375 1667 (6) MWh/year 19.3 (high) 29 149 399 sm. com. cons. (low) 20 33 60 (4)x(5)x12=1000 (7) # of large ~ 3. (high): - 3 4 4 cons. + public buildings Clow) 3 4 4 (8) average kWh/mo/cons 3099 (high) 3222 25938 27083 Clow) 3222 3222 16042 (9) MWh/year 111.6 Chigh) 116 1245 1300 LP's (low) 116 116 770 (7)x(8)x12=1000 (10) System MWh/year 152.7. (high) 184 1574 2215 (3)+(6)+(9) (low) 160 191 883 (11) System .4 (high) .4 as 3 Load Factor (low) “4 .4 4 (12) System Demand 45 (high) 52 600 850 kW (low) 46 55 250 (10)+8760+(11)x1000 960060 OOHOHOOHHHHCOOHHOOOOOOECOOHCHHOCOCHOSSOCES Section I!| - Demand Projections Page !11-110 BRIS1/H 1.2 Ekuk The population has grown very slowly since 1960 to approx- imately 50 people in 1977. The summer population, however, is up to 10 times as high due to commercial and subsistence fishing. Relocation of the village site is planned to prevent seasonal flooding. The relocation would probably halt decline in the population and provide employment. Growth has therefore been assumed at 2% per year (high) and at 1% per year (low). Community buildings, ‘a school, and addition of freezing equipment in the cannery are the expected increases in the large consumer section. The projected demand in 1980 includes the cannery which did not operate in the base year. See Figure 1I11-10 below: EKUK POWER REQUIREMENTS 1977-2000 miem Low 100) ‘s00} 200 09} 200] 00} 300} Low 3 wir 1980 res 1990 188 2000 FIGURE II -10 FIGURE 111-10 @ e Page 111-111 @ @ e EKUK @ ELECTRIC POWER REQUIREMENTS 1977-2000 e e 1977 1980 1990 2000 @ POPULATION 57 (high) 60 74 90 e Clow) 59 65 72 @ (1) # of residential 8 (high) 9 12 14 e consumers (low) 8 9 10 e (2) average. kWh/mo/ 121. (high) 179 468 1000 e@ consumers Clow) 135 205 234 e (3) MWh/year Wed (high) 19 67 168 @ residential cons. Clow) 13 22 28 e (1)x(2)x12+1000 e (4) # of small commercial i! (high) 1 1 2 @ consumers Clow) 1 1 1 @ (5) average kWh/mo/ 803. (high) 1208 3111 6646 6 consumer (low) 833 1375 1667 @ (6) MWh/ i year 9.6 (high) 14 37 160 @ sm. com. cons. Clow) 10 16 20 @ (4)x(5)x12+1000 ® (7) # of large 0 (high) 2 4 4 @ cons. + public buildings (low) 2 2 3 e (8) average kWh/mo/cons 0 (high) 6875 6875 27083 @ (low) 6875 6875 9167 ® : e (9) MWh/year 0 (high) 165 165 1300 LP's (low) 165 165 330 e (7)x(8)x12=1000 @ (10) System MWh/year 21.63 (high) 198 269 1628 e (3)+(6)+(9) (low) 188 203 378 @ + cannery in 1977 +200 e (11) System 4 (high) eal at be @ Load Factor 1 (low) A 4 115 @ @ (12) System Demand 6 (high) 226 308 930 kw +252 (low) 214 233 287 @ (10)+8760+(11)x1000 e @ e Section {11 - Demand Projections Page 11-112 BRIS1/H 1 “3 Manokotak The population has grown from just over 100 in 1950 to approximately 300 in 1977. The number of families is approximately 40. The economy is mostly based on fishing and trapping. Potential for reindeer herding has been pointed out. 1°° The population growth has been assumed to continue above . average with 5% per year for the "accelerated development" - scenario and with .5% per year for the "low growth"senario. Expansions of schools and public buildings are the only increases that are anticipated in the .arge consumer section. See Figure I11-11 below: MANOKOTAK POWER REQUIREMENTS 1977-2000 38 mien Low 8 3838 wr? 1980 vee 1900 1998 ‘2000 FIGURE IL-1 FIGURE I11-11 Page 111-113 MANOKOTAK ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 300 (high) 347 565 723 (low) 304 320 336 (1) +# of residential 39 (high) 50 89 120 consumers Clow) 43 47 51 (2) average kWh/mo/ 143. (high) —.265 468 1000 consumers (low) 202 204 234 (3) MWh/year 67 (high) 159 500 1440 residential cons. (low) 104 15 143 (1)x(2)x12+1000 j (4) # of small commercial Z (high) 5 9 12 consumers (low) 4 4 5 (5) average kWh/mo/ 803 (high) 1050 1880 4021 consumer (low) 771 833 1000 (6) MWh/year 19.3 (high) 63 203 579 sm. com. cons. Clow) 37 40 60 (4)x(5)x12=1000 (7) # of large 3 (high) 3 4 4 cons. + public buildings (low) 3 4 4 (8) average kWh/mo/cons 3099 (high) 3222 6563 8750 Clow) 3222 3222 6667 (9) MWh/year 191.5 (high) 116 315 420 LP's (low) 116 116 320 (7)x(8)x12+1000 (10) System MWh/year 197.8 (high) 338 1018 2439 (3)+(6)+(9) Clow) 257 271 523 (11) System “4 (high) 4 4 a, Load Factor (low) 4 4 5 (12) System Demand 58 (high) 97 290 560 kW (low) 73 80 120 (10)+8760+(11)x1000 ~_ Section II| - Demand Projections Page 111-114 BRIS1/H 1.4 Portage Creek Historical population information is not available. Moderate to low growth (+ 1%/year to + .2%/year) have been assumed for the purpose of this study. The geographic proximity to Dillingham (approximately 30 miles) has influenced the population and economy in the village in the Past and it is expected that this trend will continue. Major new develop- ments are not anticipated. See Figure ||!-12 below: PORTAGE CREEK POWER REQUIREMENTS I977~2000 1000 900 B00 700 600 500 400 300 200 100 30 60 40 30 20 10 1977 1980 1985 1990 1995 2000 FIGURE II - 12 FIGURE 111-12 a ~ EES @ e P 111-115 age - @ g ® e PORTAGE CREEK ® ELECTRIC POWER REQUIREMENTS 1977-2000 e e@ 1977 1980 1990 2000 @ POPULATION 25. (high) 26 29 32 e (low) 25 aT. 29 @ (1) # of residential 11 (high) 11 13 14 consumers Clow) 11 12 12 @ ; a (2) average kWh/mo/ 121 (high) = 179 468 1000 e@ consumers (low) 135 205 - 234 e (3) MWh/year 16.1 (high) 24 T3 168 @ residential cons. (low) 18 29 34 e (1)x(2)x12+1000 e (4) # of small commercial 1 (high) 1 1 1 e consumers Clow) 1 1 1 @ (5) average kWh/mo/ 803 (high) 1208 3111 6646 @ consumer (low) 833 1375 1667 ® (6) MWh/year 9.6 (high) 14 37 80 @ sm. com. cons. (low) 10 16 20 @ (4)x(5)x12+1000 ® : (7) # of large 3 (high) 3 3 3 @ cons. + public buildings (low) 3 3 3 . (8) average kWh/mo/cons 1600 (high) 2500 4583 9167 (low) 1944 3083 7083 @ (9) MWh/year 57.6 (high) 90 165 220 @ LP's (low) 70 111 170 @ (7)x(8)x12+1000 : (10) System MWh/year 83.3 (high) 120 275 468 e (3)+(6)+(9) (low) 110 156 224 @ (11) System 4 (high) -4 4 .5 e Load Factor Clow) 4 4 5 @ (12) System Demand 24 ~— (high) 34 80 107 e kW (low) 31 45 50 e (10)+8760+(11)x1000 @ @ e » Section II! - Demand Projections Page I11-116 BRIS1/H 2 Peninsula - Bristol Bay These communites have a stable population, rely greatly on fishing for income and will potentially be influenced by oil and gas development. 2.1 Egegik The population has been stable at around 100 people for the last 17 years. The existing two canneries have only operated during high cycle sockeye runs in the past. It can be expected that the canneries will diversify in the future?% and also add freezing equipment. This would influence the village economy favorably and a moderate growth of 1% per year (high) or .2% per year (low) is anticipated. The demand shown for 1980 includes 2 operating fish processors. See Figure I|I-13 below: EGEGIK POWER REQUIREMENTS 1977-2000 § 583338 $3338 3 vr 1900 88 1990 1998 2000 FIGURE ID - 13 FIGURE 111-13 i €@680080000800VO880C8OCEC8OESEOO898GCONSCECOCOBEOSECES Page 111-117 EGEGIK ELECTRIC POWER REQUIREMENTS 1977-2000 (10)+8760+(11)x1000 ® e @ @ ® ° 1977 1980 1990 2000 o @ POPULATION 148 (high) 152 168 186 o (low) 149 152 155 e (1) # of residential 21. ~~ (high) 22 40 44 e consumers (low) 22 30 31 0 (2) average kWh/mo/ 183 (high) 193 212 230 e consumers (low) 183 190 195 e (3) MWh/year 46.4 (high) 51 101 121 @ residential cons. Clow) 48 68 73 e (1)x(2)x12+1000 e@ (4) # of small commercial 7 (high) 7 8 9 e consumers (low) 7 7 7 @ (5) average kWh/mo/ 661 (nigh) 702 888 1028 low 661 7 1 @ consumer ¢ sg (6) MWh/year 55.5 Aaa 59 Hs os sm. com. cons. (low 55: 5 @ (4)x(5)x12=1000 ® (7) # of large (high) 3 6 6 @ cons. + public buildings (low) 3 6 6 e (8) average kWh/mo/cons (high) 25833 47292 48056 e@ (low) 8611 19306 21528 e (9) MWh/year (high) 930 3405 3460 e LP's (low) 310 1390 1550 @ (7)x(8)x12=1000 e (10) System MWh/year 101.9 Chigh) 1040 3591 3692 @ (3)+(6)+(9) +400 (low) 413-1817 1683 e + cannery in 1977 e (11) System (high) 2 3 3 6 Load Factor .29 Clow) 1 .25 25 @ e (12) System Demand 40 (high) 600 1360 1400 kW +600 (low) 600 690 770 @ e @ e e 2.2 Page 111-118 Pilot Point/Ugashik The population has been stable at approximately 60 - 70 for the last 20 years. Economic development has been dictated by salmon fishing. Potential exists for an extended fishing season, cold storage, fresh water fishing and oil/gas develop- ment. HUD plans approximately 10 new homes!99. Moderate population growth of 1.5% per year (high) and .5% per year (low) has therefore been assumed for this study. The accelerated growth scenario also assumes expansion of the fish processing facilities. The demand shown for 1980 includes 2 fish processors, which were not operating in the base year. See Figure |11-14 below: PILOT POINT POWER REQUIREMENTS 1977-2000 Low Low w7T 1980 r88 1990 1998 2000 Figure OL -14 FIGURE 111-14 COCO HOHOOOHOOSHOHOOEHHHSHOOSHECOTDOCECHOHSHOEOOO Page 111-119 PILOT POINT - UGASHIK ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 40 (high) 42 49 5/ (low) 41 43 45 (1) # of residential 19 (high) 20 24 29 consumers (low) 20 21 23 (2) average kWh/mo/ 121 Chigh) 179 468 1000 consumers (low) 135 205 - 234 (3) MWh/year 27.6 (high) 43 135 348 residential cons. (low) 32 52 65 (1)x(2)x12+1000 (4) # of small commercial 2 (high) 2 3 4 consumers (low) 2 2 2 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer (low) 833 1375 1667 (6) MWh/year 19.3 (high) 29 112 319 sm. com. cons. (low) 20 33 40 (4)x(5)x12=1000 (7) # of large ; 2 (high) 4 4 5 cons. + public buildings (low) 4 4 3 (8) average kWh/mo/cons 2248 (high) 5750 25938 39667 (low) 5750 11792 17222 (9) MWh/year 52 Chigh) 276 1245 2380 LP's (low) 276 566 620 (7)x(8)x12=1000 (10) System MWh/year 100.9 (high) 348 1492 3047 (3)+(6)+(9) (low) 328 651 725 (11) System .38 Chigh) 2 «25 4 Load Factor (low) 2 ue 2 (12) System Demand 30 (high) 200 680 900 kW (low) 200 370 415 (10)+8760+(11)x1000 SSCHOHSHSSSSHSSHSSHSSCHNSHSHSSHSHSCSHSCHHOHSHSECLE Page 111-120 2.3 Port Heiden The population has been stable with approximately 70 people for the last 20 years. FAA facilities, community maintenance, and fishing provide employment. Potential exists for oil and gas development, expansion of fisheries and tourism (Aniakchak Monument.)?°° Population growth has therefore been assumed at 1.5% per year (high) or .5% per year (low). 020008 OO0SOSHS8CHHSOHSHSTSHHOHOOHOEHOHOHSESEOOS The demand projected for 1980 includes a fish processor not operating during the base-year 1977. See Figure I!1-15 below: PORT HEIDEN POWER REQUIREMENTS 1977-2000 mien wien $583588 Low Low $3338 wer? 1900 mes 1990 1908 2000 FIGURE IIT - 15 FIGURE 111-15 e @ Page 111-121 ® PORT HEIDEN 6 ELECTRIC POWER REQUIREMENTS 1977-2000 e 1977 1980 1990 2000 @ POPULATION 75 (high) 78 91 106 e (low) 76 80 84 e (1) # of residential 16 (high) 17 21 26 oe consumers (low) 16 18 20 a (2) average kWh/mo/ 121. (high) —'179 468 1000 @ consumers (low) 135 205 234 ® (3) MWh/year 23.3 (high) S72 118 312 @ residential cons. Clow) 26 44 56 @ (1)x(2)x12+1000 e (4) # of small commercial 1 (high) 1 1 1 Oo consumers Clow) 1 1 1 6 (5) average kWh/mo/ 803 (high) 1208 3111 6646 @ consumer (low) 833 1375 1667 ® (6) MWh/year 9.6 (high) 14 Bz. 80 e sm. com. cons. (low) 10 16 20 @ (4)x(5)x12+1000 ® (7) # of large 3 (high) 4 4 5 Ge cons. + public buildings (low) 4 4 4 e (8) average kWh/mo/cons 1600 (high) 4083 5104 23000 o (low) 4083.» 4083 5208 @ o (9) MWh/year 57.6 (high) 196 245 1380 LP's (low) 196 196 250 e (7)x(8)x12+1000 » a (10) System MWh/year 90.5 (high) 247 400 1772 e (3)+(6)+(9) Clow) zoe 256 326 @ (11) System 34 (high) 4 5 5 a Load Factor (low) .4 4 5 @ (12) System Demand 30 (high) 70 92 400 o kW (low) 66 74 75 (10)+8760+(11)x1000 @ eo e e Page 111-122 2.4 Port Moller No historical population data is available for this community. The U.S. military facilities have been closed, but the communication site is being operated by RCA. A new cold storage facility is being built in 1979.11° A moderate increase in population (+1.5% per year high, + .5% per year low) is expected with developing fishing industry activities. It is expected that the cold storage facility will allow an extended processing time. Further expansion of the fishing industry is anticipated for the "accelerated development" scenario for 1990-2000. Oil and gas development potential is there but has not been taken into account as a major factor for this study. See Figure I|I!-16 below: PORT MOLLER POWER REQUIREMENTS 1977-2000 wn YEAR Low mien Low wt? 1900 08 1980 1908 2000 FiguRE IT-16 FIGURE I11-16 02000 GOH OOOOH HOHHOOHHHOHHOHOHOONOOHOOH8HHEO8D Page 111-123 PORT MOLLER ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 37 (high) 39 45 52 (low) 36 38 40 (1) # of residential 8 (high) 8 10 12 consumers (low) 8 9 10 (2) average kWh/mo/ 121 Chigh) 179 468 1000 consumers (low) 135 205 234 (3) MWh/year 11-7 (high) 17 56 144 residential cons. (low) 13 22 28 (1)x(2)x12=1000 (4) # of small commercial 1 (high) i 1 a consumers (low) 1 1 1 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer Clow) 833 1375 1667 (6) MWh/year 9.6 (high) 14 37 80 sm. com. cons. (low) 10 16 20 (4)x(5)x12=1000 (7) # of large 1 (high) 3 5 5 cons. + public buildings (low) 3 4 4 (8) average kWh/mo/cons 162 (high) 14194 38750 39667 (low) 8639 14813 16042 (9) MWh/year 1.9 (high) 514 2325 2380 LP's (low) 314 711 770 (7)x(8)x12+1000 (10) System MWh/year 23.2 (high) 542 2478 2604 (3)+(6)+(9) (low) 334 749 818 (11) System 26 (high) 5) 6 6 Load Factor (low) =o 4 4 (12) System Demand 10 (high) 123 460 500 kW Clow) 123 214 233 (10)+8760+(11)x1000 CO OOBOOHSOHEOHOEOHSCOHEHOEEHOHOOHHOHOOHHOTVECOHOO 00069 OOOO OEOSHOOGOOOHEHOHHOOHOHOOSOHOOHHEEO8O Page 111-125 3. Peninsula - Pacific Side Due to weather conditions and topography these villages are among the least accessible communities in the area. A year round working fishing industry does appear possible especially with the 200 mile limit bottom fishing and shrimp fishing development under way. The following graph illustrates the anticipated seasonal energy use with these developments taken into consideration. PACIFIC COAST COMMUNITIES SEASONAL ELECTRIC ENERGY USE (TYPICAL) (BASED ON KODIAK ELECTRIC ASSOC. DATA 1974-1976) % OF ANNUAL TOTAL van Fes WAR apr may JUNE suur aus sep oct nov vec FIGURE I11-17 SOSSHOSHKEOHOHSHSHHOHOHHEHOSHOSCHHOHOSOHSOHOSHHSCOCEO Section II! - Demand Projections Page 111-126 BRIS1/H 3.1 Chignik, Chignik Lagoon and Chignik Lake The total population of these three communities is approximately 250 people and has been stable since 1960. With the new shrimp processing facilities,tt4 year round employment in the area appears to be assured. Moderate population growth of 1% per year (high) or .2% per year (low) is expected. Expansion of the fish processing facilities is anticipated when bottom fishing will influence the area. The 1980 demand includes the shrimp processing facility which was not in operation in 1977. See Figure 111-18, I11-19, and 111-20 following: CHIGNIK POWER REQUIREMENTS 1977-2000 nie $583588 3 $3338 20 10) wr 1980 1988 1980 188 2000 FIGURE It -18 FIGURE 111-18 00009 OOHKHOOOOHHOOOOHOHOHOHOHOHSESHHOHOOH8EOO8D Page 111-127 CHIGNIK ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 78 (high) 80 89 98 (low) 78 80 82 (1) # of residential 15 (high) 15 TH 19 consumers (low) 15 17 19 (2) average kWh/mo/ 121 (high) 179 468 1000 consumers Clow) 135 205 234 (3) MWh/year 21.8 (high) 32 95 228 residential cons. Clow) 24 42 ° 53 (1)x(2)x12+1000 (4) # of small commercial 2 Chigh) 2 2 2 consumers Clow) 2 2 2 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer (low) 833 1375 1667 (6) MWh/year 19.3 (high) 29 75 160 sm. com. cons. Clow) 20 33 40 (4)x(5)x12+1000 (7) # of large 3 (high) 4 4 5 cons. + public buildings Clow) 4 4 4 (8) average kWh/mo/cons 3099 (high) 32417 48438 75667 Clow) 27417 32417 33542 (9) MWh/year ; 1115 (high) 1556 2325 4540 LP's (low) 1316 1556 1610 (7)x(8)x12=1000 (10) System MWh/year 152.6 (high) 1617 2495 4928 (3)+(6)+(9) (low) 1360 1631 1703 (11) System .39 (high) 5 5 5 Load Factor (low) “3 5 9 (12) System Demand 45 Chigh) 370 570 1120 kW (low) 310 370 390 (10)+8760+(11)x1000 SHPHSHHOHSHOSHHSHSHSHSHOSCHSHSOSASCHCSSOLAEOOHOCOHSECOED CHIGNIK LAGOON POWER REQUIREMENTS 1977-2000 Page 111-128 10,000 a 3000| 7000 soon + | HIGH 4000}_ 3000 2000) | Low 1000) | HIGH 900) tT woo t a 1 600 Pty ee alk | 400 } ye | 300 ~~ ; yi Low _ 7: MWH/YEAR 7 MWH a ‘30 co = 2 ze 80 | ez. 70} a 60 ae — | so! ae kw PEAK EAR —— SUA 40 sol__ 20 | 10 1977 1980 1988 1990 FIGURE IT - 19 2000 020009 OOOOOOOOHHOGDOOOEHHHTHHOHOHSEOHHOEOHEEOOD GOHSCHHHSCHSHOOTSSCHOHHOHHSCHAOCHAHHHEHOHESESCOHTPCOC®S CHIGNIK LAGOON ELECTRIC POWER REQUIREMENTS 1977-2000 Page 111-129 1977 1980 1990 2000 POPULATION 57 (high) 59 65 72 (low) 57 58 59 (1) # of residential 15 (high) 15 17 19 consumers (low) es 17 19 (2) average kWh/mo/ 121 Chigh) 179 468 1000 consumers (low) 135 205 234 (3) MWh/year 21.9 (high) 32 95 228 residential cons. (low) 24 42 53 (1)x(2)x12+1000 (4) # of small commercial 2 (high) 2 2 2 consumers (low) 2 2 2 (5) average kWh/mo/ 803 Chigh) 1208 3111 6646 consumer Clow) 833 1375 1667 (6) MWh/year 19.3 (high) 29 75 160 sm. com. cons. (low) 20 83 40 (4)x(5)x12+1000 (7) # of large 3 (high) 3 4 5 cons. + public buildings (low) 3 4 4 (8) average kWh/mo/cons 1600 (high) 3222 33438 75667 (low) 3222 3222 22708 (9) MWh/year 57.6 (high) 116 1605 4540 LP's (low) 116 116 1090 (7)x(8)x12=1000 (10) System MWh/year 98.8 Chigh) 177 1775 4928 (3)+(6)+(9) (low) 160 191 1183 (11) System .38 (high) 4 ‘3 sis} Load Factor (low) 4 4 a (12) System Demand 30 (high) 50 405 1120 kW (low) 45 55 260 (10)+8760+(11)x1000 1000 CHIGNIK LAKE POWER REQUIREMENTS 1977-2000 Page 111-130 900 es 800 HIGH 700 500 400 300 Low 200 ry MWH eer} HIGH 11 Low 8 § 83888 KW O-} ow ° 10 1977 19860 9865 1990 FIGURE II - 20 1995 2000 200 89HOHTHOOHZHEGOOHOHOHOOOHOOSHOOOOCOOREOOES e @ Page 111-131 oe e CHIGNIK LAKE e ELECTRIC POWER REQUIREMENTS 1977-2000 ® 1977 1980 1990 2000 e POPULATION 117 (high) 121 134 148 e (low) 118 120 122 e (1) # of residential 25 (high) 26 29 32 e consumers Clow) 26 29 32 : (2) average kWh/mo/ 121 ae 179 oe — consumers f low 135 205 4 e (3) MWh/year 36.5 (high) 56 163 384 © residential cons. (low) 42 71 90 e (1)x(2)x12=1000 rs (4) # of small commercial 2 (high) 2 Z 2 ® consumers Clow) 2 2 2 6 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer (low) 833 1375 1667 @ e@ (6) MWh/year 19.3 (high) 29 15) 160 sm. com. cons. (low) 20 33 40 e (4)x(5)x12=1000 @ e@ (7) # of large 3 (high) 3 3 3 e cons. + public buildings (low) 3 3 3 @ (8) average kWh/mo/cons 3099 (high) 3222 4583 6111 e (low) 3222 3222 4722 e (9) MWh/year 111.6 (high) 116 165 ° 220 Ss LP's (low) 116 116 170 ° (7)x(8)x12+1000 @ (10) System MWh/year 167.4 Chigh) 201 403 764 @ (3)+(6)+(9) Clow) 178 220 300 ® (11) System 38 (high) -4 4 5 @ Load Factor (low) 4 4 5 @ (12) System Demand 50 (high) 57 115 175 @a kW (low) 50 63 69 @ (10)+8760+(11)x1000 e e e e 322 Page 111-132 Ivanoff Bay A very small community with a declining population; a potential for development is nevertheless seen in the rapidly growing year round fishing industry in the area. Several housing units are planned by HUD;1°° as are airport and road improvements. It is anticipated that the school can be opened again and that eventually a fish processing facility will be built. Moderate population growth (1% per year high, .2% per year low) is expected. See Figure !!I-21 below: IVANOFF BAY a POWER REQUIREMENTS 1977-2000 ‘3000 [7 T = T 1 #000) t t 1 i 1B new net $3 389888 3 wr 1980 908 1990 88 FIGURE IT-2t FIGURE [11-21 SNSOOCHNHSHVOSSHSOHSHSOOSSHOOSHOHOSHEEOHOHHHHHHSOOESD Page 111-133 IVANOFF BAY ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 36 (high) 37 41 45 (low) 36 37 38 (1) # of residential 11 (high) 1 13 14 consumers s (low) 11 13 14 (2) average kWh/mo/ 121 (high) 179 468 - 1000 consumers Clow) 135 205 234 (3) MWh/year 16.1 (high) 24 73 168 residential cons. Clow) 18 32 39 (1)x(2)x12+1000 (4) # of small commercial 1 (high) 1 1 1 consumers (low) 1 1 1 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer (low) 833 1375 1667 (6) MWh/year 9.6 (high) 14 37 80 sm. com. cons. (low) 10 16 20 (4)x(5)x12+1000 (7) # of large 0 (high) 3 4 5 cons. + public buildings (low) 3 4 4 (8) average kWh/mo/cons 0 (high) 3222 33438 75667 (low) 3222 9917 22708 (9) MWh/year 0 high) 116 1605 4540 LP's Clow) 116 476 1090 (7)x(8)x12=1000 (10) System MWh/year 25.7 (high) 154 1715 4788 (3)+(6)+(9) (low) 144 524 1149 (11) System .29. (high) 4 5 5 Load Factor (low) .4 4 5 (12) System Demand 10 (high) 45 392 1100 kW (low) 41 150 260 (10)+8760+(11)x1000 SPCHHOHNDPHOHSNSHSSHOHAHHSOCHOSNSHOSAOHGOHSSSHSSCCOCOCHECCOEES 3.3 Page I11-134 Perryville The population has remained relatively stable during the last 17 years. Fifteen new housing units were planned by HUD in 1977;19°9 and fish processing and/or cold storage facilities are considered in the long range planning. 1° Following the trend between 1970 and 1977 the future population growth has been assumed to be 1.5% per year for the accelerated development and .5% per year for a low growth scenario. See Figure ||1-22 below: PERRYVILLE POWER REQUIREMENTS 1977-2000 Low mien cow vr 1980 08 1980 88 2000 FIGURE I - 22 FIGURE I11-22 02000898000 OOOOECHOOOHEHOHOHOH8OHSOOFOO888OCO8S @ @ e@ Page 111-135 e PERRYVILLE e@ ELECTRIC POWER REQUIREMENTS 1977-2000 e 6 1977 1980 1990 2000 e POPULATION 101 (high) 106 123 143 @ (low) 103 108 114 e (1) # of residential 25 (high) 27 33 40 @ consumers (low) 26 29 32 @ (2) average kWh/mo/ | 121 Chigh) 179 468 1000 @ consumers (low) 135 205 234 ® (3) MWh/year 36.5 Chigh) 58 185 480 e residential cons. (low) 42 71 90 @ (1)x(2)x12+1000 @ (4) # of small commercial 2 (high) 2 3 4 e consumers Clow) 2 2 2 6 (5) average kWh/mo/ 803 Chigh) 1208 3111 6646 @ consumer (low) 833 1375 1667 e e (6) MWh/year 19.3 (high) 29 112 319 sm. com. cons. (low) 20 33 40 @ (4)x(5)x12=1000 e (7) # of large 3 (high) 4 4 5 ® cons. + public buildings (low) 4 4 4 e (8) average kWh/mo/cons 1499 (high) 9917 33437 75667 @ (low) 2417 9917 33542 S (9) MWh/year 53.9 (high) 476 1605 4540 9 LP's Clow) 116 476 1610 ® (7)x(8)x12+1000 @ (10) System MWh/year 109.7 Chigh) 563 1902 5339 e e (3)+(6)+(9) (low) 178 580 1740 @ (11) System .36 (high) 4 5 5 e Load Factor Clow) 4 -4 5 @ (12) System Demand 35 Chigh) 160 430 1220 Se kW (low) 50 165 400 (10)+8760+(11)x1000 @ e e Page 111-136 Togiak Bay The two communities in this area are growing rapidly. The economy is largely based on the fishing and processing industry. With the anticipated expansion of this industry the growth trend is expected to remain approximately the same. 4.1 Togiak The population has grown from approximately 100 people in 1950 to over 400 people in 1977. A 1977 power requirement study!12 covering 10 years to 1986 has been used as a base for the projections in this study. Besides possible expansion in the fishing and processing industry, a reindeer industry with meat processing appears viable.!°° Plans for a new high school are being made.!°° The consumer growth is assumed at 4.5% per. year until 1990 and at 2.5% per year beyond. Individual energy use is expected to be greatly determined by the cost of power and earning power in the community. Two possible scenarios are shown in the following Graph (Figure I11-23) and Table. TOGIAK POWER REQUIREMENTS 1977-2000 Low Low wr ne 1908 1980 1908 2000 FIGURE I - 23 FIGURE 111-23 2008880090 OHOOEHOOHOEHOHODOOHSHHSOHOOHEOSCCES ELECTRIC POWER REQUIREMENTS 1977-2000 TOGIAK Page 111-137 ©8300 OOOH OOHEHOOOHHHOEHHOHHHDOODOOSBEOHOCOHE 1977 1980 1990 2000 POPULATION 419 (high) 441 522 618 (low) 433 483 539 (1) # of résidential 94 (high) 109 180 230 - consumers Clow) 109 180 230 (2) average kWh/mo/ 169 (high) 225 426 1000 consumers (low) 173 186 235 (3) MWh/year 191.5 (high) 294 920 2760 residential cons. (low) 226 402 648 (1)x(2)x12=1000 (4) # of small commercial 10 (high) 12 20 26 consumers (low) 12 20 26 (5) average kWh/mo/ 397 (high) 667 1258 2955 consumer (low) 479 563 731 (6) MWh/year 47.6 (high) 96 302 922 sm. com. cons. Clow) 69 135 228 (4)x(5)x12+1000 (7) # of large 3 (high) 4 6 7 cons. + public buildings (low) 4 4 4 (8) average kWh/mo/cons 7583 (high) 14375 36597 44286 (low) 11250 14375 25000 (9) MWh/year 273 (high) 690 2635 3720 LP's (low) 540 690 1200 (7)x(8)x12=1000 (10) System MWh/year 512.1 (high) 1080 3857 7402 (3)+(6)+(9) (low) 835 1227 2076 (11) System .39 (high) Zo 4 2 Load Factor (low) 4 .25 3 (12) System Demand 150 (high) 500 1100 1700 kW (low) 240 560 790 (10)+8760+(11)x1000 Page 111-138 4.2 Twin Hills This is a very young community (founded in 1964 after a flood in Togiak) with similar characteristics as Togiak itself. The population has grown from 65 in 1970 to 83 in 1977. The economy is ruled by the fishing industry in Togiak, and Togiak Bay, but the possibility of reindeer herding has been pointed out.1°° The population growth has been assumed at the same rate as Togiak's, 3% per year for the "accelerated growth" scenario and 1% for the "low growth" alternate. See Figure I11-24 below: TWIN HILLS POWER REQUIREMENTS 1977-2000 T T t zi i ees it ARE wien 58 883538 we Ee ® Tt eS a "Sec ——— : sol t t t t Fob { ia t L «| : | = | ce reams ream! ne OW “oF SSS ees | x ro 0 err 80 wee v80 ve 7000 FIGURE I-24 FIGURE 111-24 0200090009008 8OHOOOHOHOHEHHOH8H9OOGOOEHSOCO8SO COSCO OHHH OHHHHOHOHOOHHOHHHOHEHOOO8BOO8EOEOEES Page 111-139 TWIN HILLS ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 POPULATION 67 (high) 71 87 106 (low) 68 71 75 (1) # of residential 16 (high) AZ 23 31 consumers (low) 16 18 20 (2) average kWh/mo/ 12] (high) 179 468 1000 consumers (low) 135 205 234 (3) MWh/year 2353 (high) 36 129 372 residential cons. (low) 26 44 56 (1)x(2)x12+1000 (4) # of small commercial 1 (high) 1 1 1 consumers (low) 1 n 1 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer (low) 833 1375 1667 (6) MWh/year 9.6 (high) 14 37 80 sm. com. cons. (low) 10 16 20 (4)x(5)x12+1000 (7) # of large 3 (high) 3 3 4 cons. + public buildings (low) 3 3 3 (8) average kWh/mo/cons 3099 (high) 3222 4583 15000 (low) 3222 3222 4722 (9) MWh/year ATA (high) 116 165 720 LP's (low) 116 116 170 (7)x(8)x12+1000 (10) System MWh/year 144.5 (high) 166 331 1172 (3)+(6)+(9) (low) 152 176 246 (11) System AKT) (high) -4 4 nS Load Factor (low) .4 .4 15 (12) System Demand 45 (high) 47 95 270 kW (low) 45 50 56 (10)+8760+(11)x1000 ul Page 111-140 lliamna Lake Area (without Iliamna, Nondalton, Newhalen’ see section II,E for these communities ) Most communities in this area have had moderate population increases during the past 27 years. Income is mostly derived from the Bristol Bay fisheries and supplemented by subsistence hunting. Growth potential in this area is considered moderate. 5.1. Igiugi The population has been stable for the last 17. years and the growth is expected at 1% per year (high) or .2% per year (low). Community improvements such as water and sewer systems, community building, etc. are the additions expected. See Figure 111-25 below: IGIUGIG IGIUGIG POWER REQUIREMENTS 1977-2000 $$ 3895388 Low 3 Low = Ke vex ER | sel 8383338 arr reo 108 1990 1998 2000 FIGURE I-25 FIGURE 111-25 LMR RR ERERE RTE REE A EIT e @ e Page 111-141 e@ IGIUGIG e@ ELECTRIC POWER REQUIREMENTS 1977-2000 1977 1980 1990 2000 e @ POPULATION 40 (high) 41 45 50 6 (low) 40 41 42 e (1) # of residential 12 (high) 3) 16 19 @ consumers (low) 12 14 15 @ (2) average kWh/mo/ 121 (high) 179 468 1000 @ consumers (low) 135 205 234 e (3) MWh/year 17.5. (high) 28 90 228 @ residential cons. (low) 19 34 42 e (1)x(2)x12+1000 @ (4) # of small commercial 1 (high) 1 1 1 @ consumers (low) 1 1 fl @ (5) average kWh/mo/ 803 (high) 1208 3111 6646 e@ consumer (low) 833 1875 1667 e (6) MWh/year 9.6 (high) 14 37 80 $ sm. com. cons. (low) 10 16 20 @ (4)x(5)x12+1000 © (7) # of large 1 (high) 3 3 3 e@ cons. + public buildings (low) 3 3 3 e (8) average kWh/mo/cons 4334 (high) 3222 4583 6111 @ Clow) 3222 3222 4722 s : : e (9) MWh/year $2 (high) 116 165 220 LP's (low) 116 116 170 e (7)x(8)x12+1000 @ (10) System MWh/year 79.1 (high) 158 292 528 e (3)+(6)+(9) (low) 145 166 232 @ @ (11) System 235 (high) “4 .4 35 e Load Factor (low) .4 4 = @ (12) System Demand 25. (high) 45 85 120 e kW (low) 41 48 53 6 (10)+8760+(11)x1000 e @ e Page 111-142 5.2 Kokhanok The population here has grown from under 50 in 1950 to almost 90 in 1977. Ten new housing units were planned in 1977 by HUD1°9 and the community intends to pursue development of fresh fish marketing as well as tourism. 1°° Population growth has been assumed at 2% per year for the “accelerated growth" scenario and at .5% per year for "low" growth. Besides community improvements no major system additions are expected. See Figure I11-26 below: KOKHANOK POWER REQUIREMENTS 1977-2000 $3538 300 Low 200) § § 83883 Low 8 i998 2000 rr 00 es 90 FIGURE HX - 26 FIGURE 111-26 SPOOSOO OS CHOCO HEDOOOOOOOHOOOO6O0O64OOCOOSOOS e ® e e @ KOKHANOK @ e : ELEC TRIC PO eS | WE r | | - ge 111-1 ULAT é | f MEN 3 : TS: 1977 Li 7 = S 2000 elena : e (2) a ai = Vi cacti kV = : e@ ume wf 3 (3 rs mo/ : : ; : 3 7 coe @ aaicaeeh - : , (1) ential . 3 | : 3 = : ; igh) 1 ® ) #0 z i | co f small : : @ (5) eigen a a : a rcial | a age k : : nsum oF | | @ (6) ote dobre , 7 (I gh) : e@ sm h/yea i Z | ae vars : ® x(5)x12#1001 = , @ (7) # of = i | : ot @ cons eit / ( . + ) | | | e 8) publi : ) : avera ae : e ge kWh/ ee | | 3 | 16 e (9) MWh @ = 2 @ Pe in : | , | 3 3 = hie | ( x12+ = ) : # = 111.6 = , | st : : @ Cpecey4(3), 7 , : z (lo ) 2 611 (11) § ) : : 3 — 144.5 : : Fac : 7 . (12) tor ona : & ao D . | = e (10)+8 emand | si +8760+(11 a | )x100 i | st ‘4 a 3 Ay : . -9 ' .5 = 91 = 140 56 5.3 Page 111-144 Pedro Bay This community has been depending on the Bristol Bay fisheries in the past. Good potential exists for fresh water fish marketing and lumber industry.1°° The. population has been stable in the past and moderate growth is expected (1% per year high and .2% per year low). Community improvements such as a health clinic, freezer units etc. are the major system additions that are expected. See Figure 111-27 below: PEDRO BAY POWER REQUIREMENTS 1977-2000 Low mien wr7 1980 1908 1980 r988 2000 FIGURE I-27 FIGURE 111-27 COC OOOO OOOO OHHOHOHOOHOHOHOLYSHHOS SOY OCEHHOSOOS Page 111-145 PEDRO BAY ELECTRIC POWER REQUIREMENTS 1977-2000 SCwOOOCeSEOO 1977 1980 1990 2000 POPULATION 65 (high) 69 84 102 (low) 66 69 73 (1) # of residential 22 (high) 24 32 43 consumers (low) 23 25 28 > (2) average kWh/mo/ 121 (high) 179 468 1000 e consumers (low) 135 205 234 ® (3) MWh/year ; 32.1. (high) 52 180 516 e@ residential cons. (low) 37 61 79 4 (1)x(2)x12+1000 (4) # of small commercial 2 (high) 2 3 4 consumers (low) 2 2 2 @ (5) average kWh/mo/ 803 (high) 1208 3111 6646 * consumer (low) 833 1375 1667 e (6) MWh/year 19.3 (high) 29 112 319 é sm. com. cons. Clow) 20 33 40 e (4)x(5)x12+1000 @ (7) # of large 2. (high) 3 3 3 e cons. + public buildings (low) 3 3 2 @ (8) average kWh/mo/cons 2248 (high) 3222 4583 6111 e (low) 3222 3222 4722 ® (9) MWh/year 53.9 (high) 116 165 220 e LP's (low) 116 116 170 e (7)x(8)x12=1000 ® (10) System MWh/year 105.3 (high) 197 457 1055 @ (3)+(6)+(9) (low) 173 210 289 @ (11) System 4 (high) 4 5 5 @ Load Factor (low) 4 4 ' @ e (12) System Demand 30 (high) 56 104 240 kW (low) 50 60 66 * (10)+8760+(11)x1000 ® @ © * Page 111-146 5.4 Port Alsworth Historical population information for this community is not available, but is assumed to be stable around 2025 people. 103 A moderate growth of 1% per year (high) or .2% per year (low) is expected. See Figure II1-28 below: PORT ALSWORTH POWER REQUIREMENTS 1977-2000 1000 — 900 - 800 700 | T 600 500 nite HIGH 300 200 Low wwe / YEAR 100 ron + ae HIGH 80 a To a -_ _ 60 4 Leet 50 _— Low so prose a 40 eal ww PEAK / YEAR —_-— es 30 kw 20 >)- 10 1977 980 985 1990 i995 2000 FIGURE II - 28 FIGURE I11-28 ©FO8OO SOD SOFHHSOOOO OSS OS GOL 972OFOENOOHOETOBOOO ©0O SOOO CHE HBO 8 OOO EOOS OES OE OOOH O CH 200004908 PORT ALSWORTH ELECTRIC POWER REQUIREMENTS 1977-2000 Page 111-147 1977 1980 1990 2000 POPULATION 25 Chigh) 27 32 39 (low) 26 28 31 (1) # of residential 5 (high) 5 6 7 consumers (low) 5 5 5 (2) average kWh/mo/ 121 (high) 179 468 1000 consumers Clow) 135 205 234 (3) MWh/year 7.3 (high) 11 34 84 residential cons. Clow) 8 12 14 (1)x(2)x12+1000 (4) # of small commercial 1 (high) 1 1 1 consumers (low) 1 1 1 (5) average kWh/mo/ 803 (high) 1208 3111 6646 consumer (low) 833 1375 1667 (6) MWh/year 9.6 (high) 14 37 80 sm. com. cons. (low) 10 16 20 (4)x(5)x12=1000 (7) # of large 1 (high) 3 3 3 cons. + public buildings Clow) 3 3 3 (8) average kWh/mo/cons 4334 (high) 3222 4583 6111 (low) 3222 3222 4722 (9) MWh/year 52 (high) 116 165 220 LP's Clow) 116 116 170 (7)x(8)x12=1000 (10) System MWh/year 68.9 (high) 141 236 384 (3)+(6)+(9) (low) 134 144 204 (11) System .39 (high) 4 “5 uo Load Factor (low) 4 .4 oO (12) System Demand 20 (high) 40 68 88 kW (low) 38 41 50 (10)+8760+(11)x1000 Page 111-148 Inland Area The communities in this area are located on the Nushagak or Kvichak Rivers. The economy is ruled by the salmon fisheries in Bristol Bay to varying degrees and supplemented by subsistence hunting and trapping. Historical population growth has varied and might be influenced by people relocating from Bay communities to river communities and back.1°3 The electrical power in the village of New Stuyahok is supplied by the REA co-op, AVEC. The 1976 power requirements study prepared for this system has been used as a base to project demands for the other communities as well. 6.1 Ekwok This community has experienced a slight decline in population from 130 in 1950 to approximately 109 in 1977. A new school is planned to be built in 1979/80 and other community improvements are anticipated. The population growth has been assumed at 1% per year for the high development and .2% per year for the low development alternate. See Figure 111-29 below: EKWOK POWER REQUIREMENTS 1977~2000 mien Low 177 1900 res 1990 1908 2000 FiGURE TIL - 29 FIGURE 111-29 1O © OO’ S OHS OH OHL GOCE HCH HHHODTOOO ©008000680€9 908 @ 6 Page 111-149 e e EKWOK @ ELECTRIC POWER REQUIREMENTS 1977-2000 @ e 1977 1980 1990 2000 e@ POPULATION 109 (high) 112 124 137 @ (low) 110 111 113 @ (1) # of residential 25 (high) 27 32 39 e consumers Clow) 26 28 31 e@ (2) average kWh/mo/ 121 (high) 179 468 1000 e consumers Clow) 135 . 205 234 e (3) MWh/year 36.5 (high) 58 180 468 e residential cons. (low) 42 69 87 (1)x(2)x12+1000 @ e (4) # of small commercial 2 (high) 2 3 4 e consumers Clow) 2 2 2 @ (5) average kWh/mo/ 803 (high) 1208 3111 6646 e consumer (low) 833 1375 1667 ®@ (6) MWh/year 19.3. (high) 29 112 319 @ sm. com. cons. (low) 20 33 40 4 (4)x(5)x12=1000 @ 9 (7) # of large 3. (high) 3 3 4 e cons. + public buildings (low) 3 3 3 @ (8) average kWh/mo/cons 3099 (high) 3222 4583 15000 e Clow) 3222 3222 4722 @ (9) MWh/year 171.6 Chigh) 116 165 720 4 LP's (low) 116 116 170 e (7)x(8)x12+1000 a (10) System MWh/year 167.4 (high) 203 457 1507 @ (3)+(6)+(9) (low) 178 218 297 e (11) System .38 (high) 4 4 5 @ Load Factor (low) 4 .4 5 e e (12) System Demand 50 (high) 58 130 345 kW Clow) 51 62 68 @ (10)+8760+(11)x1000 6 @ @ ® 6.2 Page 111-150 Koliganek This community has grown from 90 people in 1950 to approximately 140 in 1977. Fifteen new housing units are planned by HUD.!°° A local freshwater fishing industry is considered possible and desirable.1°° Presently, however, income is mostly derived from salmon fishing during the summer and-fur trapping in winter. Accelerated or low growth will depend on whether the freshwater fishing industry can be established and whether the fur prices will stabilize. See Figure 111-30 below: KOLIGANEK POWER REQUIREMENTS 1977-2000 Low niew vor 1980 wes 1900 t908 r00e FiGURE IIT- 30 FIGURE 111-30 CO OSOO OOOO COTO DP OOO8OSSOOHEEHHGEHOHHOHOCOHSOEOCO @ e Page 111-151 e é KOLIGANEK e ELECTRIC POWER REQUIREMENTS 1977-2000 @ @ 1977 1980 1990 2000 e POPULATION 142 (high) 146 161 178 @ (low) 143 146 149 @ (1) # of residential 20 (high) 21 25 30 e consumers (low) 21 23 25 e (2) average kWh/mo/ 121 Chigh) 179 468 1000 e@ consumers Clow) 135 205 234 e . e (3) MWh/year 29.2. (high) 45 140 360 . residential cons. (low) 34 57 70 ® (1)x(2)x12+1000 e 6 (4) # of small commercial 2 (high) 2 3 4 é 4 consumers (low) 2 2 2 cf (5) average kWh/mo/ 803 (high) 1208 3111 6646 e consumer Clow) 833 1375 1667 e@ (6) MWh/year 19.3 (high) 29 112 319 sm. com. cons. (low) 20 3S 40 @ (4)x(5)x12+1000 @ * (7) # of large 3 (high) 3 4 5 a cons. + public buildings low 3 4 6 il Clow) 3 6 (8) average kWh/mo/cons 3099 (high) 3222 5646 13767 e (low) 3222 3222 5750 e@ (9) MWh/year 111.6 (high) 116 271 *826 ° LP's Clow) 116 116 276 7 (7)x(8)x12+1000 @ @ (10) System MWh/year 160.1 (high) 190 523 1505 ® (3)+(6)+(9) (low) 170 206 386 @ (11) System 37. (high) .4 4 5 ® Load Factor (low) .4 .4 5 e (12) System Demand 50 (high) 54 150 345 e kW (low) 50 58 88 e@ (10)+8760+(11)x1000 @ © @ @ Page 1|11-152 6.3 Levelock The population has increased slightly from 75 in 1950 to approximately 95 in 1977. Extension of the school and other community facilities are anticipated within the next 10 years. The population growth has been assumed at 1% per year for the “accelerated growth" scenario and at . % per year for the "low growth" alternate. See Figure I!1-31 below: LEVELOCK POWER REQUIREMENTS 1977-2000 Low Low wr? 1980 res 1980 08 000 FIGURE IZ-3! FIGURE II1-31 COC OOOO SOOO OO1DOC OHO OD OOK GHD SOOO HOHOBHSCOHEOOO @ @ Page 111-153 e @ e LEVELOCK © ELECTRIC POWER REQUIREMENTS 1977-2000 : 1977 1980 1990 2000 e POPULATION 95 (high) 98 108 119 (low) 96 101 106 : (1) # of residential 28 (high) 30 36 a4 consumers (low) 29 32 35 @ e (2) average kWh/mo/ 121 (high) 179 468 1000 consumers Clow) 135 205 234 S e (3) MWh/year 40.8 (high) 64 202 528 residential cons. (low) 47 79 98 @ (1)x(2)x12+1000 @ e (4) # of small commercial 2 (high) 2 3 4 é consumers (low) 2 2 2 @ (5) average kWh/mo/ 803 (high) 1208 3111 6646 e consumer (low) 833 1375 1667 @ (6) MWh/year 19.3 (high) 29 112 319 sm. com. cons. (low) 20 33 40 @ (4)x(5)x12=1000 @ @ (7) # of large 3 (high) 3 4 4 cons. + public buildings Clow) 3 4 4 ® 6} (8) average kWh/mo/cons 3099 (high) 3222 6563 8750 e (low) 3222 3222 6667 ® (9) MWh/year 111.6 (high) ‘116 315 420 LP's Clow) 116 116 320 (7)x(8)x12+1000 @ @ (10) System MWh/year 17157 (high) 209 629 1267 @ (3)+(6)+(9) (low) 183 228 458 @ (11) System .39 Chigh) 4 4 & @ Load Factor (low) 4 .4 5 e (12) System Demand 50 (high) - 60 180 290 kW Clow) 52 65 105 e (10)+87602(11)x1000 e @ e @ 6.4 Page I11-154 New Stuyahok Historical population growth has been high from 95 in 1950 to approximately 240 in 1977. With a recent (1976) REA power requirement study available for this community, consumer growth has been based on that study, with approximately 1.5% increase per year. The individual energy use will depend greatly on the overall economic development and the cost at which power will be available. The two development scenarios assume continuation of diesel generation for the low growth alternate and a transmission tie to a less expensive source for the "accelerated growth" scenario. Community improvements, school expansions and cold storage facilities have been assumed to contribute to a moderate system growth. See Figure 111-32 below: NEW STUYAHOK POWER REQUIREMENTS 1977-2000 Low wen/vean_| ee Kw PEAK /YEAR wT? 1900 1988 1990 oy F000 FiguRE ID - 32 FIGURE 111-32 ©9000 OOOO SOOO GEO OCOES OOOOH OOCCHOHOOECNHHEOOHEOOO @ @ e Page 111-155 @ @ NEW STUYAHOK @ ELECTRIC POWER REQUIREMENTS 1977-2000 @ e 1977 1980 1990 2000 e@ POPULATION 230 (high) 242 286 339 e (low) 238 266 297 @ (1) # of residential i 42 high e consumers ben : im = * e (2) average kWh/mo/ . i 174 h e consumers foes i 4 e @ 7 (3) MWh/year 87.5 hi h ‘i h @ residential cons. ote "3 i i e (1)x(2)x12+1000 e (4) # of small commercial 2 (high) 2 3 3 e consumers (low) 2 3 3 @ (5) aver age kWh/mo/ 256 (high) 1083 2250 4639 @ consumer Clow) 833 917 1167 @ e (6) MWh/year 6.1 (high) 26 81 167 sm. com. cons. (low) 20 33 4 ) (4)x(5)x12+1000 . @ (7) # of large 2 Chi h) 3 e@ cons. + public buildings ibid} 3 3 : . 3 4 e (8) average kWh/mo/cons 4564 fae 3222 5646 13767 ow 3222 3222 5750 e e (9) eee 109.5 (high) 116 271 826 s Clow) 116 116 276 ® (7)x(8)x12+1000 @ 10) Syst i e (10) ae 203.1 (high) 267 653 1713 e . Clow) 232 280 488 (11) System i e 7 a ne8 (high) 53 .4 5 e (low) .23 oa 25 = (12) System Demand 100 chigh) 100 186 390 ow 1 e (10)+8760+(11)x1000 * ee me @ @ e@ e 100 101 102 103 104 105 106 107 108 109 110 111 112 Page I11-156 G. BIBLIOGRAPHY AND REFERENCES Bristol Bay - The Fishery and the People, 1975. Bristol Bay Area Development Corporation. Bristol Bay - Its Potential and Development, 1976. Bristol Bay Regional Development Council and Bristol Bay Native Association. ’ Bristol Bay - An Overall Economic Development Plan, Nov. 1976. by Andrew Golia, Economic Plans Bristol Bay Area Planning Grant. Bristol Bay - A Socioeconomic Study, 1974. Institute of Social, Economic and Government Research - University of Alaska. Electric Power in Alaska 1976 - 1995, August 1976. Institute of Social, Economic and Government Research - University of Alaska. 5 A Regional Electric Power System for the Lower Kuskokwim Vicinity, July 1975. United States Department of the Interior - Alaska Power Administration prepared by R. W. Retherford Associates. Waste Heat Capture Study - June 1978. State of Alaska - Department of Commerce and Economic Development, Division of Energy and Power Development, prepared by R. W. Retherford Associates. Alaskan Electric Power - An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region, Volumes | and ||, March 1978. State of Alaska, Department of Commerce and Economic Development, prepared by Battelle. State of Alaska, Department of Fish and Game. Letter of March 19, 1979. 1978 - Community Energy Survey by State of Alaska, Department of Commerce and Economic Development, Division of Energy and Power Development. Alaska Industry and Oil, April 1979. Alaskana, Volume VII, No. 1, 1979. State of Alaska - Public Utilities Commission. "Alaska Village Electric Cooperative Cost of Service Study", November, 1877. 113 114 115 116 117 118 119 Page 111-157 United States - Department of the Interior. Alaska Power Administration. “Alaska Electric Power Statistics 1960 - 1976", July 1977. "The 1976 Alaska Power Survey". Volumes 1 and 2 by The Federal Power Commission. "Alaska Regional Energy Resources Planning Project - Phase 1", Volume 1, October 1977. By Alaska Division of Energy and Power Development. The Alaska Economy. Year-End Performance Report 1977. By State of Alaska, Department of Commerce and Economic Development. Overall Economic Development Program. Bristol Bay Borough, Alaska by Arne G. Erickson, Administrative Assistant, Bristol Bay Borough, August 1976. System Planning Study, Iliamna - Newhalen Electric Cooperative, by R. W. Retherford Associates, September 1978. System Planning Study, Matanuska Electric Association, by R. W. Retherford Associates, December 1978. POTENTIAL ENERGY AND ELECTRIC POWER RESOURCES > Page |V-161 IV. POTENTIAL ENERGY AND ELECTRIC POWER RESOURCES A. INTRODUCTION This section presents an analysis of energy resources in the Bristol Bay Area based on available information. Published reports, USGS maps and other literature as listed in the bibliographies with each part, as well as communication with people in the area which have been utilized to compile the available Knowledge on resources that can be developed with known technology within the next twenty years. No field work has been involved in this part of the study. Resources that appear most promising to develop are pointed out and have been analyzed to a greater extent in regard to economical and environmental feasibility in subsequent parts of this section. Except for the oil and gas potential, which would require a very large scale development and is still considered a controversial issue in regard to impact on the fisheries, development of several potential hydroelectric sites appears to be the best prospect to provide the required electrical energy in the future. Small communities without economic access to hydroelectric or geothermal energy will have to rely on diesel electric energy generation or implement wind and solar power on a small scale basis, although neither one of these solutions appears to be economically advantageous at this time. Severe restraints on development of most potential resources are caused by the present land status -- less than .1% of the land in the area is in private hands. These resources are mentioned however, and economically evaluated on an approximate basis in this study. The energy requirements established in Section II!, “Electric Energy Demand Projections" have been used for the more detailed evaluation of several resources. It should be noted that substantially different developments (either higher or lower compared to the projections in Section I!| "Future Power Requirements") in any given area will require a re-evaluation of the potential resource. B. ENERGY RESOURCES The following potential energy resources are discussed: Hydroelectric Resources Geothermal Resources Oil and Gas Resources Coal Resources Uranium Resources Wind Energy Resources, and Solar and Tidal Energy Resources NOULRWN — Page 1V-162 The available energy resources are evaluated in regard to their potential to replace or supplement the present use of petroleum fuels. It is not expected that any of the above named resources will replace petroleum fuel for transportation purposes within the next 10-20 years. Possible use in comfort heating, electricity generation and industrial uses are therefore investigated to a greater extent. The present state of the art in wind and solar energy conversions are considered to be not economically feasible on a “utility" scale for the Bristol Bay Area due to either high cost or questionable reliability. It is expected that both these energy conversion technologies will be pursued on a demonstration - or private individual level in the near future. Overall energy needs, however, will have to be filled by means of proven technology and economically feasible developments. Emphasis has been placed on renewable resources. This does not imply that other resources have been overlooked but rather attempts to put them in perspective in regard to possible development and cost. 1. Hydroelectric Energy The investigation of potential hydroelectric sites has been based on the utilization of USGS maps of the 1:63360 scale series (1" = 1 mile). Contour intervals on these maps are 50' or 100'. This implies that elevation differences of less than 50' are not shown on these maps. Therefore it is possible that sites suitable for a small scale (5 to 200 kW) development exist and have not been listed in this study. This applies also to possible bulb-turbine application where elevation differences of 10' - 30' would mean a + 100% estimate of the power potential. An aerial survey at low altitude or on site survey could evaluate these sites with more accuracy. The potential sites are listed in the following geographical areas: 1.1. Nushagak Bay/Wood River - Tikchik Lakes 1.2 Alaska Peninsula - Bristol Bay 1.3. Alaska Peninsula - Pacific Coast 1.4 Iliamna/Lake Clark Within these areas the sites are listed alphabetically. The number as listed with each location refers to locations on Map |. More detailed data and environmental impact information on the individual sites is listed in Appendix B-6. O©O0OOOOOHOOHOHOCHOOOHOOOCHOOOSCO * L B POTENTIAL HYDROSITES IN THE BRISTO AY AREA Firm Cost-Total* Installed Drainage Aver. Flow Energy Installed (1979-$x1000) Cost/kW USGS Map Area MEH enti Annual _Capacity (MW) = Annual Cost Prime # SITE 1:63360 (Sq. Mi.) (Ft.) Regulation (MWH) Plant Factor (%) 1000-$ **** (1979-$) Restraints*** 1.1 NUSHAGAK BAY/WOOD RIVER - TIKCHIK LAKES 1 Algnak River Hiamna A-8 480.0 170 1250 45,552 2x8 29,900 5,750 1,3 35 2 2,174 2 Agulowak River Dillingham B-8 BULB TURBINE SITE 3 3 American Creek Mt. Katmal D-4, 98.2 800 200 99,513 2x12 35,850 3,156 1 D-3, C-4, C-3 700 a7 2,606 4 Chikuminuk Lake Taylor Mtns A-8 290.0 100 850 52,560 2x6 31,400 5,233 2,4 100 50 2,283 5 Grant Lake Dillingham D-7 37.2 215 92 12,132 1.5** 6,691 4,831 2 700 92 486 6 Idavain Lake Mt. Katmai C-6, D-6 26.6 685 41.5 17,520 2x2 7,532 1 Naknek C-1 100 5 7 Kontrashibuna Lake Lake Clark A-4 200.0 220 880 120,450 2x14 3,414 1 700 49 8 Kukaklet Lake #1 Illamna A-7 480.0 330 1200 122,640 2x14 1,057 4,3 50 50 . Kukaklet Lake #2 iamna A-7 140 620 52,560 2x6 12,665 1,055 1:3 + 100 50 921 9 Kvichak River Dillingham A-2 BULB TURBINE SITE 3,5 10 Lake Brooks Mt. Katmal C-6 N/A 20 300 3,591 4 1,710 4,171 1 700 700 124 nN Lake Elva Goodnews C-1 10.0 275 _50 8,409 1.5 6,730 7,010 2 - 700 64 469 12 Lake Grosvenor Mt. Katmai C-4, 630.0 85 950 49,494 2x6 21,025 3,721 1 c-5 700 7 1,529 13/14 Naknek Lake/River Naknek C-2 2720.0 90 5400 297,840 2x34 37,580 1,105 3 700 “50 2,732 15 Nayakuk - Tikchik Dillingham D-8 1486.0 180 3340 367,920 2x45 134, 435 3,200 2,3 Lake 100 47 “9,773 16 South Fork Mt. Katmai B-2, 29.9 400 85 12,702 2x2.5 13, 460 9,283 1,4 Savanoski River B-3, C-2, C-3 66 29 “$79 7 Upnuk Lake Taylor Mtns B-8 100.0 150 295 27,594 2x3 23,730 7,533 2,4 700 53 1,725 ALASKA PENINSULA - BRISTOL BAY SIDE 18 Creek Port Moller D-2 14.5 300 _22 4,029 2x.45 5,390 8,370 3 Chignik A-8 700 51 392 19 Becharof Lake Naknek A-3 BULB TURBINE SITE 1,3 20 Hot Springs Creek Ugashik C-2 5.9 800 _30 14,454 2x1.65 9,750 5,909 4 700 50 709 21 King Salmon River Chignik A-7, A-8 388.0 100 _58 3,504 2x.4 5,030 12,575 3 Port Moller D-1, D-2 100 50 366 22 Landlocked Creek Chignik C-1, C-2 15.5 200 _60 7,358 2x.85 4,615 5,494 5,4 700 49 366 E9L-AI beg TABLE iv 1 POTENTIAL HYDROSITES iN THE BRISTOL BA AREA (CONTINUED) . Firm Cost-Total* Installed Drainage Aver. Flow Energy Installed (1979-$x1000) — Cost/kw USGS Map Area MEH crs Annual Capacity (MW) Annual Cost Prime SITE 1:63360 (Sq. Mi.) (Ft.) { Regulation (MwH) Plant Factor (4) 1000-$ **** (1979-$) — Restraints*** 23 Reindeer Creek Chignik D-1, D-2 27.6 100 55 1,752 2x.2 5,120 25,600 - 50 50 372 ALASKA PENINSULA - PACIFIC COAST 24 Unnamed Lake Mt. Katmai A-2 11.7 730 70 28,601 2x3.5 9,335 2,859 1,4 near Hidden Harbor 30 a7 “Gs 25 Dakavak Lake Mt. Katmai A-2 28.0 240 168 25,053 2x3 7,900 2,762 1,4 A-3 100 48 $74 26 Kirschner Lake Niamna B-3 13.8 100 83 5,081 58 1,456 4,853 4 700 700 106" 27 Chignik #1 Chignik B-2 2.8 460 22.4 6,219 2x.7 3,475 2,482 5 100 50 253 Chignik #2 Chignik B-2 4.3 170 34.5 3,591 2x.4 3,015 3,768 5 100 50 219 28 Two Lakes #1 Ugashik C-1 2.6 180 _13 1,435 3x.3 4,995 11,352 1 700 9 363 Two Lakes #2 Ugashik C-1 4.4 180 22 2,409 3x.3 4,995 11,352 1 700 49 363" 29 Lake near Devils Mt. Katmai B-1 14.4 80 120 5,913 2x.7 2,770 4,104 1,4 Cove 100 48 201 ILIAMNA/LAKE CLARK 30 Copper River - Iliamna C-3 26.6 100 130 7,971 2x.75 4,935 5,423 5 Meadow Lake c-4 700 61 359) 31 Kokhanok River lliamna B-4 145.0 45 400 5,519 2x.75 5,350 8,492 5 B-5 50 42 389 32 Koksetna River Lake Clark B-6 160.0 155 465 17,520 3x3 19,880 3,898 4,5 39 22 1,445 33 Lachbuna Lake Lake Clark B-3 168.0 1100 495 205 , 000 3x25 103, 000 2,664 4,5 61 31 7, 488 2 a 34 Summit Lake #1 liamna C-2, C-3 11.4 390 68.5 16,644 2x2 8,395 4,418 5 ms D-2, D-3 100 48 610 a 35 Summit Lake #2 18.5 390 mw 26,280 2x3 16,350 5,450 s — Hiamna 700 50 T, 189 ti ‘ a 36 Lake Tazimina Hiamna 0-5 320.0 300 1,440 131,400 2x15** 34,445 2,296 5 > (ist Stage) 50 50 2,504 37 Newhalen River Niamna D-6 3,300.0 35 9,303 192,720 2x20 79,939 3,634 3 100 55 * Exclusive of R-O-W, Substation, Transmission. * Partial Development. *** Restraints: Located in National Monument Located in State Park. Important fish spawning or migration area. Remote location, distance to loadcenters. nnwno Located in wilderness study area. Page IV-165 The cost estimates include engineering, design, construction of dams, tunnels, etc., powerhouse and equipment and access. Not included are costs for rights-of-way, substations and transmission; or distribution lines. Annual cost and economic feasibility have been established for the following sites: (5) Grant Lake. (8) Kukaklek Lake. (11) Lake Elva. (18) Creek near Port Moller. (21) King Salmon River. (27) Chignik #1 and 2. (36) Lake Tazimina. Part D of this section and Appendix D list the details of the feasibility evaluations. ; The following figure I1V-1 shows the conceptual layout for Lake Tazimina. RESERVOIR DAM CREST El. 700 ay U/ 5 FOREBAY DAM SITE |. CREST Ej. 660 a \ First Stage Pevelo vats i, ancorkouse yard Hivo Peat, Vaifs 99L-Al 26ed a eee ee ates POWERHOUSE 1.925 Foro Le Baie BOE fou HOUSE El . 4. Reseryorr Dam sok}. 675 Aperor, 4 Miles Frei Road ; . 5. Open Cay or Tunn ef" Figure 1V-1 | TAZIMINA LAKE PROJECT Seale: /EImile Page |V-167 26 Geothermal Resources For the purposes of this report, geothermal energy is simply defined as any naturally occurring heat source at the surface or within 10,000 feet (3500 m) of the surface. The Bristol Bay subregion encompasses one of the most favorable geothermal terrains in Alaska. The U.S. Geological Survey has defined seven areas of Prospective Geothermal Resource (PGRA's) within the area. a). Possible Large-Scale Development According to the Geothermal Steam Act of 1970, a PGRA is: "\..an area in which higher than normal temperatures are likely to occur with depth and in which there is a reasonable possibility of finding reservoir rocks that will yield steam or heated fluids to wells." These seven PGRA's within the Bristol Bay subregion cover an area of almost 1.5 million acres (Map |). From north to south, these areas are: Katmai Peulik Mother Goose Lake Aniakchak Black Peak Veniaminof Staniukovich Four of these areas include igneous systems which the U.S. Geological Survey has recently (Muffler '78) identified and rated in terms of thermal energy. These four are Katmai, Peulik, Black Peak and Veniaminof. Veniaminof and Black Peak are located close to the communities of Chignik, Chignik Lagoon, Chignik Lake, Perryville, Ivanoff Bay, Port Moller and Port Heiden. They theoretically contain a combined potential thermal energy of 652 X 1018 joules in their magmatic systems down to 10 kilometers. (Note: 1 joule = 9.48 X 10-* Btu.) This can represent more than 70,000 MW (50% load factor) per year for 50 years for each site. The energy is there, but is it possible to develop it? Lack of any energy demand from nearby areas now or in the near future (ten years) severely restricts scenarios of large-scale devel- opment of geothermal resource. Research and development for a site would require large initial capital expenditures. Page 1V-168 The estimated costs for particular sites are approximately as follows: Initial assessment (geological and geophysic mapping) $ 50,000 - 100,000 Test well $ ~ 1,000,000 Development of 25 MW plant $50,000,000 - 80,000,000 (See Rosenbruch, 75.) With an annual generation of 109,500 MWH this amounts to 6-9¢/kWh at the plant bus with a 35 year loan at 5% interest, 5% O&M, and 1% insurance. It has to be noted that the power requirements are not of this magnitude in the communities in the vicinity of any of the listed resources, even if electric space heating were included. A plant at Mt. Veniaminof supplying the previously listed communities for example would only need to produce 30,000 MWH (include space heating) annually in the year 2000. Further complications in development could stem from requirement for about 150 miles of transmission line, the overlap of national monuments, and their new additions with the PGRA's (see Map |). Kirkwood (1979) gives a good summary of the impact of federal land actions on geothermal development. Rapid resolution of Alaska's land status, followed by economic favor- ability to development of mineral resources and/or to large seafood processing centers, are somewhat unlikely conditions that might allow geothermal usage in the next few years. b). Favorable Small-Scale Geothermal Sites When judged against other sources of energy, the following geothermal sites may not warrant further evaluation; however, they represent two of the most favorable areas to utilize hot surface waters on a small scale. (i) Port Moller Hot springs are located approximately 9 miles (14 km) from the town of Port Moller at the north end of Mud Bay. The springs, issuing from Paleocene volcanic sandstones, discharge at 80 gpm and have a temperature of 60° C (Baker, 1977). There are no year-round residents at the site and the acreage immediately surrounding the site is held privately by Arthur H. Johnson of S. Naknek. c. Page |V-169 It is possible that a small low-temperature Rankine-cycle generator (Abbin, '78) such as the Israeli Ormat (see '79 proposal by Leonard to DOE) could be used to supply 3-5 kilowatts of energy to a greenhouse primarily heated by the hot spring water. This two stage geothermal system might allow the development of a small vegetable business. There are two principal drawbacks to the situation. A suitable market may not exist for such produce and sufficient research has yet to be carried out on Rankine-cycle generators to firmly establish how much energy they can be expected to produce, and how reliable they are. (ii) Port Heiden Less is known about the hot springs near Port Heiden. They are located across the bay from the village of Meshik on the southwest shore. Initial assessment would include temperature, discharge, chemistry and construction feasibility at the site. If the character of the springs was favorable, a similar small-scale development such as that proposed for Port Moller might be considered. The other known hot springs in the Bristol Bay region are either far removed from population centers or within National Monument boundaries. Favorable Geothermal Sites Adjacent to the Bristol Bay Region Two potentially large-scale geothermal sites near the Bristol Bay subregion are worth considering: the Iniskin Peninsula area and the KGRA (Known Geothermal Resource Area) at Geyser Bight on Umnak Island. (i) The Iniskin Peninsula area has a long history of oil and gas exploration; nine wells have been drilled there between 1902 and 1961 (see Blaska, 1976). All the wells encountered gas at shallow depths and often hot flowing salt water. Zappa #1, drilled in 1961, encountered hot salt water and steam at 9700 feet. The hot brine and steam flowed at 400 psi for several hours before it was "shut-in". Bottom hole temperatures at Zappa #1 were approximately 220°F. Blaska ('76) estimated the power potential of such a well at about 5000 kw. Since large deposits of copper are known in the Kasna Creek area (refer to Map |) and several large iron deposits exist between Lake Iliamna and the Iniskin Peninsula, it is possible that energy could be used to process ore before shipment. Further, transmission of this power could serve the communities of Old Iliamna, Pile Bay and Pedro Bay. Page |V-170 (ii) The U.S. Geological Survey has designated a 2 km long zone near Geyser Bight on Umnak Island as a Known Geothermal Resource. By definition, "...an area in which the geology, nearby discoveries, competitive interest, or other indications would, in the opinion of the Secretary (of the Interior), engender a belief in.men who are experienced in the subject matter that the prospects for ex- traction of geothermal resources are good enough to warrant expenditures of money for that purpose." In other words, the area will probably develop as soon as there is a market for its energy. While the Umnak KGRA is 600 miles further west than Dillingham and Kodiak, the comparative size of its resource and relative ease of development may give it an economic advantage should a large-scale energy need arise. Geothermal development, then, may occur here first. The size of this potential resource is estimated by U.S.G.S. as 136 megawatts for a thirty year period. Page !V-171 SELECTED BIBLIOGRAPHY GEOTHERMAL Baker, R.O., Lebida, R.C., Pyle, W.D., and Britch, R.P., 1977, An_ investigation of selected Alaska geothermal spring sources as_ possible salmon hatching sites: 151 p. Biggar, N.E., A geological and geophysical study of Chena Hot Springs, Alaska (M.S. thesis): Univ. Alaska. Byers, F.M., Jr., Geology of Umnak and Bogoslof Islands, Aleutian Islands, Alaska: U.S. Geol. Survey Bulletin 1028-1. Coats, R.R., 1956, Geology of Northern Adak Island, Alaska: U.S. Geol. Survey Bulletin 1028-C, p. 67. Drews, Harald, Fraser, G.D., Snyder, G.L., Barnett, H.F., Jr., 1961, Geology of Unalaska Island and adjacent insular shelf, Aleutian Islands, Alaska: U.S. Geol. Survey Bulletin 1028-S. Forbes, R.B., and Biggar, N.E., 1973, Alaska's geothermal resource potential: The Northern Engineer, v.5, #1, p. 6-10. Forbes, R.B., Leonard, L., and Dinkel, D.G., 1974, Utilization of geothermal energy resources in rural Alaskan communities: U.S. Atomic Energy Comm. Rept., p. 82. Forbes, R.B., 1975, The energy crunch...Alaska style: transcript of proceedings, U.S. Energy Research and Develop. Adm., Wash., D.C. Forbes, R.B., Gedney, L., VanWormer, D., and Hook, J., 1975, A_geophysical reconnaissance of Pilgrim Springs, Alaska: Rept. for U.S. Atomic Energy Comm., p. 26. Forbes, R.B., 1976, Geothermal energy and wind power, alternate energy sources for Alaska: Alaska Energy Office and Geo- physical Inst., Univ. Alaska, p. 144. Godwin, L.H., 1971, Classification of public lands valuable for geo- thermal steam and associated geothermal resources: U.S. Geol. Survey Circ. 647, p. 18. Hickel, W.J., 1972, Geothermal energy: a national proposal for geo- thermal resources research: final report of the Geothermal Resources Research Conf., Seattle, Wash. 1972. Univ. Alaska, 95 p. Page IV-172 Johnson, G.R., Sainsbury, C.L., 1974, Aeromagnetic and generalized map of the West-Central part of the Seward Peninsula, Alaska: U.S. Geol. Survey Map GP-881. Kirkwood, P., 1979, The impact of federal land actions on geothermal resource development in Alaska: Rept. to U.S. Dept. of Energy. Kruger, P., 1975, Development of the nation's geothermal energy resources: manuscript, Second Energy Tech. Conf., Washington, DG. 1975: Leonard, L., 1975, What's old in geothermal energy: The Northern Engineer, v. 6, #4. McConkey, W., Quinlan, C., Rutledge, G., Lane, D., and Rahm, M., 1977, Alaska's energy resources: findings and analysis: Alaska Div. of Energy and Power Develop., p. 244. McFadden, W.A., Jr., Wanek, A.A., and Callahan, J.E., 1971, Alaska geothermal resources minutes #1: minutes of Mineral Land Classification Bd. McFadden, W.A., Jr., Wanek, A.A., and Callahan, J.E., 1971, Alaska geothermal resources minutes #2: minutes of Mineral Land Classification Bd. Miller, T.P., 1973, Distribution and chemical analyses of thermal springs in Alaska: U.S. Geol. Survey Open-File Rept. Miller, T.P., Barnes, F., and Patton, W.W.,.Jr., 1973, Geologic setting and chemcial characteristics of hot springs in central and western Alaska: U.S. Geol. Survey Open-File Rept. Miller, T.P., Barnes, Ivan, 1976, Potential for geothermal energy development in Alaska-summary: Circum-Pacific Energy and Mineral Resources Mem. 25, A.A.P.G. Ogle, W.E., 1974, Geothermal energy possibilities in Alaska: Consultant, Anchorage, Alaska. Ogle, W.E., 1976, Report of a visit to Bell Island Hot Springs. Ogle, W.E., 1976, Geothermal energy applications to aquaculture: Pacific Alaska Research. Ogle, W.E., 1976, Baranof, an example of hot springs-originated geo- thermal spaceheating in Alaska: Consultant, Anchorage, Alaska. Ogle, W.E., 1976, Considerations on the possible application of geo- thermal, wind, and solar energy to minimize consumption of exhaustible energy resources at certain select sites in the Alaskan raiibeit: Consultant, Anchorage, Alaska. Page 1V-173 Ogle, W.E., 1976, Report of a visit to_a number of Alaskan hot springs to_ aid in the selection of a site for the possible installation of a small binary geothermal electric generating plant. Ogle, W.E., Geothermal possibilities in Alaska, p. 6. Ogle, W.E., 1976, Report of a visit to Ophir Hot Springs , Alaska. Rosenbruch, J.C., Bottge, R.E., 1975, Geothermal energy: economic potential of three sites in Alaska: U.S. Bur. of Mines Inform. Circ. 8692, p. 40. Sacrato, D.M., 1975, State policies for geothermal development: National Conf. of State Legislature, p. 94. Selkregg, L.L., et. al., 1976, Alaska regional profiles: prepared for Federal-State Land Use Planning Comm., published by Arctic Environmental Information and Data Center, Univ. Alaska. Stefano, Ralph R., and Associates, 1974, Geothermal resources, Pilgrim Hot Springs, Alaska: Consultants' Report. U.S. Code of Federal Regulations, title 43, public lands, Sect. 3200, Geothermal leasing, Part 2310, Withdrawals. U.S. Congress Geothermal Steam Act, Public Law 91-581, 1970, 84 Stat. 1566. Wanek, A., 1973, Geothermal areas by meridians and acreages: U.S. Geol. Survey for Alaska Land Use Planning Commission, 28 p. Wapona, Inc., 1976, Study of environmental regulations applying to geothermal exploration, development and use: prepared for E.P.A. Waring, G.A., 1965, Thermal springs of the United States and other countries of the world, a summary: U.S. Geol. Survey Prof. Paper 492, p. 381. Waring, G.A., 1917, Mineral springs of Alaska: U.S. Geol. Survey Water Supply Paper 492. White, D.F., and Williams, D.L., 1975, Assessment of geothermal resources of the United States: U.S. Geol. Survey Circ. 726, p. 155: Page |V-174 3h Coal Resource The Chignik, Herendeen Bay and Unga Island coal fields have been known for some time. During the early 1900's small quantities of coal were mined from each of the fields. Since then only minor development work has been done at Herendeen and Chignik. As fuel prices rise, it may become economic to utilize some of this coal locally. Of less importance, occurrences of coal have been noted in several petroleum exploration wells throughout the Tertiary section along the north shore of the Alaska Peninsula. This Tertiary province is shown as KTcb on Map |. Most of these observations made no reference to thickness or rank of coal, and often the beds were deeply buried. However, as new information is gathered in the coming years, the Tertiary province may prove more valuable. a). Chignik Coal Field The Chignik coal field lies on the western shore of Chignik Bay about 250 miles shoutwest of Kodiak. The settlements of Chignik, Chignik Lagoon and Chignik Lake are close by. About fifty miles south by sea are the towns of Perryville and |vanoff Bay. The Chignik coals are hosted in Late Cretaceous aged rocks of the Chignik formation, which trends northeastward for about 25 miles. The formation is exposed at the margins of a broad anticline giving the shape of a horseshoe (see Map |). The coal field covers an area of about 50 square miles (Holloway, '77). Quality and quantity of the field are assessed as follows: Rank: bituminous (Barnes, '67) Heat contents: 9.640 - 11,240 Btu/Ib. (Barnes, '67) Amount in site: ~ 100 x 10® tons (Don McGee, U.S.G.S.) (up to 300 x 10® tons) Recoverable: 253 Mining: Open Pit Approx. cost at mine mouth: $14-$58/ton - 20-100 tons/day Access: 6 miles of road to Chignik and Kviukta Bay Land status: Wilderness Study Area Page IV-175 b). Herendeen Bay Coal Field The Herendeen Bay coal field lies on the peninsula between Herendeen Bay and Port Moller. It lies within about ten miles of the towns of Port Moller and Nelson Lagoon. The coals are hosted by the same Late Cretaceous rocks that occur at Chignik. The field covers roughly 40 square miles and the coal beds are moderately folded and broken by several faults. The coal is primarily of bituminous ranking, with a heating value between 11,260 and 11,790 Btu's. McGee estimates the indicated resource is between 10 and 100 million tons with a hypothetical resource of about 300 million tons. 25% of the 10 to 100 million tons should be recoverable. Mining here would probably have to be underground. A further complication is that Herendeen Bay freezes over for several months so that a more suitable port would have to be found on the Pacific shore with a connecting road or railroad link. Herendeen Bay is within a Federal Land Policy and Management Act of 1976, 94th Congress Public Law #94579, Title ||, Section 204e withdrawal c). Unga Island Coal Field and Tertiary Lignite-Bearing Beds South and east of Herendeen Bay there are several hundred square miles of Tertiary lignite-bearing beds. These beds are similar to those on Unga Island. The lignites of Unga have a heating value of only 5,800 Btu's and have a high ash content. Basically, the lignites on the mainland are unevaluated, and the Unga lignites are too low grade and too thin to be economic for some time. The mainland area is under a Federal Land Policy and Management Act of 1976, 94th Congress Public Law #94579, Title 11, Section 204e withdrawal and Unga Island appears to be open. Page |V-176 SELECTED BIBLIOGRAPHY COAL Averitt, Paul, 1974, Coal Resources of the United States: U.S. Geol. Survey Bull. 1412. Barnes, Farrell F., 1967, Coal Resources of Alaska: U.S. Geol. Survey Bull. 1242-B. Burk, C.A., 1965, Geology of the Alaska Peninsula - Island Arc and Continental Margin: GSA Memoir 99. Cobb, Edward N., 1975, The United States Geological Survey in Alaska: Accomplishments during 1975: U.S. Geol. Survey Circ. 733. Conwell, C.N., 1972a, Alaskan Coals: AIME Annual Meeting paper, San Francisco, Calif. Conwell, C.N., 1977, Cook Inlet-Susitna Coal Fields: presented at the annual meeting of Canadian Association of Geologists. Conwell, C.N., 1977, Energy Resource Map of Alaska: State of Alaska, Dept. of Natural Resources, Div. of Geological & Geo-physical Surveys. Crane, W.R., 1915, Chignik Bay, Alaska, Coal Fields: Colliery Eng., v. 35, p. 457-461. Holloway, C.D., 1977, Map showing Coal Fields and Distribution of Coal-bearing rocks in the Western Part of Southern Alaska: U.S.G.S. Open-File Map 77-169-1. McGee, D.L., and O'Connor, K.M., 1975, Cook Inlet Basin Sub- surface Coal Reserve Study: State of Alaska, Dept. of Natural Resources, Div. of Geological & Geophysical Surveys, Open-File Rept. 74. McGee, D.L., and O'Connor, K.M., 1976, Mineral Resources of Alaska and the Impact of Federal Land Policies on their Availability - Coal: State of Alaska, Dept. of Natural Resources, Div. of Geological & Geophysical Surveys, Open-File Rept. 51. Rao, P. Dharma, and Wolff, Ernest N., eds., 1975, Focus on Alaska's Coal '75: proceedings of conference. Fairbanks, Ak. MIRL Rept. 37. Page |V-177 Schaff, Ross G., 1975, Biennial Report 1974-75: State of Alaska, us. Dept. of Natural Resources, Div. of Geological & Geophysical Surveys. Department of Interior. Bureau of Mines. Analyses of Alaskan Coals, George Gates, technical paper 682. 1946. Department of Interior. Bureau of Mines. Resume of Information on Alaskan Bituminous Coals with Particular Emphasis on Coking Characteristics, by Robert S. Warfield. Open-File Report 11-67. 1967. Department of Interior. Bureau of Mines. Strippable Reserve of Bituminous Coal and Lignite in the United States, by Bureau of Mines Staff. Information Circ. 8531. 1971. Department of Interior. Geological Survey. Coal Resources of Southwestern Alaska, by R.W. Stone. Survey Bulletin 259, p. 1-1/1. T9053 Department of Interior. Geological Survey. Geology and Mini- eral Resources of Parts of Alaska Peninsula, by W.W. Atwood. Survey Bulletin 467, 137 p. 1911. Department of Interior. Geological Survey. The Herendeen Bay Coal Field, by Sidney Paige. Survey Bulletin 284, p. 101-108. 1906. Department of Interior. Geological Survey. Mineral Resources of Southwestern Alaska, by W.W. Atwood. Survey Bulletin 279, p. 108-152. 1909. Department of Interior. Geological survey. Part of Herendeen Bay Coal Field Alaska, by G.O. Gates. Survey Open-File Report No. 2, p. 5, 1944. Department of Interior. Geological survey. Report on Coal and Lignite of Alaska, by W.H. Dahl. 7th Ann. Rept. Pt. 1, Sec. E, 1896. Page IV-178 4. Oil and Gas Resource This section includes consideration of all liquid petroleum fuels and natural gases. A discussion of areas favorable to both will be fol- lowed by a few additional areas that are favorable for gas only. a). Oil and Gas Basins The. Lower Cook Inlet basin, the St. George basin (southeast of the Pribilofs), and the Kodiak and Shumagin Shelves, the general Bristol Bay post-Miocene section including the onshore Nushagak district are the areas of best favorability in their approximate order of importance. The southern Alaska Peninsula Mesozoic province is less favorable. The approximate limits of these basins are shown on Map |. Exploratory petroleum well locations are shown also. To date, approximately seven wells have been drilled in the Mesozoic province and nine holes in the Tertiary Bristol Bay section. The results of these holes have been discouraging thus far. During the last few years both the State of Alaska and the U.S. Geological Survey have attempted to assess the resource potential of gas and oil in Alaska's basin. The following tables were compiled from U.S.G.S. tables published in McConkey (1977) and DGGS tables published in Klein (1974). ONSHORE OIL ESTIMATES BY PROVINCE (in Billion Barrels) UNDISCOVERED PROVINCE AGENCY RECOVERABLE Bristol Bay Tertiary USGS 0-0.7 Bristol Bay Tertiary DGGS +94 Alaska Peninsula USGS O-1.1 Alaska Peninsula DGGS “<= Cook Inlet USGS 0.2-0.8 Cook Inlet : DGGS 93 Kodiak USGS Negligible Kodiak DGGS = rr @ @ @ Page |V-179 @ e ® e OFFSHORE OIL ESTIMATES BY PROVINCE @ (in Billion Barrels) @ Bristol Bay USGS 0-2.5 @ Bristol Bay DGGS ot e Zhemchug-St. George USGS 0=5..1 Zhemchug-St. George DGGS Spe @ Cook Inlet USGS O75+2-3 Cook Inlet DGGS 1.6 e Kodiak and Shumagin USGS 0-1.4 } Kodiak and Shumagin DGGS 2.4 ® @ @ e ONSHORE GAS ESTIMATES BY PROVINCE e (in Trillion Cubic Feet) @ Bristol Bay USGS 0-2.4 Bristol Bay DGGS 6.8 @ Alaska Peninsula USGS 0.-2.0 e@ Alaska Peninsula DGGS = sm Cook Inlet USGS 0..7-Z2.58 @ Cook Inlet DGGS 6.67 e Kodiak USGS Negligible Kodiak DGGS a @ @ e @ OFFSHORE GAS ESTIMATES BY PROVINCE e (in Trillion Cubic Feet) @ UNDISCOVERED e PROVINCE AGENCY RECOVERABLE @ Bristol Bay USGS 0-5.4 e Bristol Bay DGGS - += Zhemchug-St. George USGS 0-13.0 @ Zhemchug-St. George DGGS --- e Cook Inlet USGS 1.0-4.5 Cook Inlet DGGS 11.68 eo Kodiak and Shumagin Shelves USGS 0-4.0 e Kodiak and Shumagin Shelves DGGS 17.5 e s @ @ e e Page !1V-180 (i) Lower Cook Inlet This basin is perhaps most important because it has produced oil in the upper inlet and it is the most likely candidate to be explored in the near future. Discoveries offshore of Kamishak Bay could impact the Bristol Bay subregion by (1) promoting development of onshore facilities for refining and shipping, (2) supplying a nearby source of petroleum and natural gas products that could be transported via road or pipeline to the larger population centers, and (3) indirect stimulus of socio-economic growth. (ii) The Bristol Bay Basin Exploration to date includes about nine test wells, some of which were over 15,000 feet in depth. Private industry sources feel that petroleum prospects for Bristol Bay do not look good at this time. The wells indicate that below the Miocene unconformity, there are very few satisfactory reservoir rocks. This fact alone narrows the potential favorable areas considerably. Furthermore, seismic surveys indicate that there is little structural relief in the basin to form traps. Onshore the prospects are little better; in fact, the Tertiary section thins and many of the rocks tend to be immature north of Naknek (personal communication, Bill Lyle, DGGS; paper with Irv Palmer in press on Oil and Gas Potential of Alaska Peninsula). Finally, the fisheries of Bristol Bay and outer Bristol Bay will probably discourage federal leasing until alternative areas have been more fully evaluated. (iii) The St. George Basin Information to date would indicate that this basin contains adequate thickness, correct age and reasonable structure to allow petroleum accumulation. Most of the hard data is, of course, proprietary in nature. The basin is large and is connected with the Zhemchug basin to the north. Exploration and development of these basins is probably a decade away, however, and the large distance from the Bristol Bay area would soften its economic impact should discoveries be made there. (iv) The Kodiak and Shumagin Shelves The Kodiak area is currently being explored geophysically and may have a stratigraphic test well in the near future. Both the USGS and DGGS have given it moderate potential for oil and quite good marks for gas. Discoveries on the Shumagin Sheif could affect the Chignik-Stepovak Bay areas of the peninsula. Discoveries south of Kodiak Island would be less influential. ©0000 0COOOOHOOOHHOOHHOHOHOOO8HHOOHHO8HO8EOHO Page 1V-181 b). Additional Favorable Gas Areas Three additional areas show some potential for natural gas; the on- shore Nushagak district of the Bristol Bay basin, the Iniskin Penin- sula and the Gas Rocks. (i) Nushagak District The potential for petroleum in this area is considered low by some, but others apparently disagree as exploration wells are already planned for this year. Since the basin thins onshore and many of the Miocene rocks appear immature, the wells are given a better chance of striking gas than oil. (ii) Iniskin Peninsula Over the years, several wells on the Iniskin Peninsula have produced gas, however, none commercially to date. The gas has been low volume and intermittent in all cases. Even so, the fact that it is there is quite important. Breakthroughs in the technology of developing wells could make the Iniskin a new target. Ciii) Gas Rocks There is little published information on this area of natural occurring gas vents on the southern shore of Lake Becharof. It is the opinion of Bill Bishop of BBNC that there is little potential for gas reserves here. SPOSCOSSOHHSSSSHSOHOHSSCHOSHSCSEOSOSSCOCCOHOCECESECE®E Page 1V-182 SELECTED BIBLIOGRAPHY OIL AND GAS American Petroleum Institute, 1969, Reserves of Crude Oil, Natural Gas Liquids and Natural Gas in the United States and Canada as of December 31, 1968: American Gas Association and Canadian Petroleum Assoc.,' v. 23, p. 31. Blasko, D.P., 1971, Effect of Petroleum and Natural Gas Industry Activities on Public Land Use in Selected Areas of Alaska: prepared for Environ. Qual. Conf. for the Extraction Industries of the Amer. Inst. of Mining, Metall., and Petr. Engin. (SPE-AIME), Washington, D.C., June 1971, p. 217-221. Blasko, D.P., 1975, A History of Bureau of Mines Oil and Gas Resource Investigations in Alaska with an_Index_of Published and Unpublished Reports, Containing Information on Alaska's Oil and Gas Resources: 19201974: U.S. Dept. of Interior, Bureau of Mines, informational handout. Blasko, Donald P., 1976, Occurrences of Oil and Gas Seeps: Alaska Peninsula, Alaska, Western Gulf of Alaska: U.S. Dept. of Interior, Bureau of Mines Rept. 8122. Bottge, Robert, 1975, Alaska's Energy and Mineral Potential, 1975: U.S. Dept. of Interior, Bureau of Mines, Alaska Field Operations Center, Situation Report. Bottge, R.G., 1975, Alaska's Energy and Mineral Potential: U.S. Dept. of Interior, Bureau of Mines, Situation Report. Map folio. Scale 1/250,000. Bybee, R.W., 1970, Petroleum Exploration and Production on the Nation's Continental Shelves: Economic Potential and Risk: Annual Conference, Marketing Tech. Soc., v. 2, No. 6, p. 733-739. Gates, G.O., Grantz, Arthur and Patton, W.W., Jr., 1968, Geology and Natural Gas and Oil Resources in Alaska in Natural Gases of North America, edited by B.W. Beebe and F. Curtis: Amer. Assoc. Petrol. Geologists Memoir 9, v. 1, p. 3-48. Grantz, Arthur, 1964, Petroleum and Natural Gas - Southern Alaska in Mineral and Water Resources of Alaska: U.S. Congress, Senate Committee on Interior and Insular Affairs, 88th Congress, 2nd Session, Committee Prit., p. 44-62. SOCOSHSOHOHOSHSSSHSSOHOHSOHOKSHOSCSECOCSOSSOCOOHSCSOSESEE®S Page |V-183 Gryc, George, 1971, Summary of Potential Petroleum Resources of Region | (Alaska and Hawaii) - Alaska in Future Petroleum Provinces of the United States - Their Geology and Potential, ed. by |.H. Cram: Amer. Assoc. Petrol. Geol. Memoir 15, v. 1, p. 55-67. Hatten, C.W., 1971, Petroleum Potential of Bristol Bay Basin, Alaska in Future Petroleum Provinces of the United States - Their Geology and Potential, ed. by |.H. Cram: Amer. Assoc. Petrol. Geol. Memoir 15, v. 1, p. 105-108. Keller, A.S., and Cass, J.T., 1956, Petroliferous Sand of the Chignik Formation at Chignik Lagoon, Alaska: U.S. Dept. of Interior, Geological Survey, Open-File Report. Kellum, L.B., Daviess, S.N., and Swinney, C.M., 1945, Geology and Oil Possibilities of the Southwestern Part of the Wide Bay Anticline, Alaska: U.S. Dept. of Interior, Geological Survey, Open-File Rept. Klein, R.M., Lyle, W.M., Dobey, P.L., and O'Connor, K.M., 1974, Energy and Mineral Resources of Alaska and the Impact of Federal Land Policies on their Availability: State of Alaska, Dept. of Natural Resources, Div. of Geological and Geophysical Surveys, Energy Res. Sect., Open-File Report 50. Knappen, R.S., 1929, Geology and Mineral Resources of the Aniakchak District in Mineral Resources of Alaska, Report on Progress of Investigations in 1926, Part F: U.S. Dept. of Interior, Geol. Survey Bull. No. 797, p. 161-227. LeMay, W.J., 1969, A Perspective on Alaska's Oil Potentials in Oil and Gas Journal, v. 67, No. 8., p. 114-120. Lyle, W.M., and Dobey, P.L., 1974, Geologic Evaluations of the Herendeen Bay Area, Alaska Peninsula: State of Alaska, Dept. of Natural Resources, Div. of Geological and Geophysical Surveys, Open-File Report No. AOF-48. Martin, G.C., 1925, Petroleum on Alaska Peninsula: The Outlook for Petroleum near Chignik in Mineral Resources of Alaska, Report on Progress of Investigations in 1923, Part D: U.S. Dept. of Interior, Geol. Survey Bull. No. 733, p. 209-219. McConkey, W., Lane, D., Quinlan, C., Rahm, M., and Rutledge, G., 1977, Alaska's Energy Resources: Inventory of Oil, Gas, Coal, Hydroelectric and Uranium Resources, Vol. II. Page 1V-184 Miller, D.J., Payne, T.G., and Gryc, George, 1959, Geology of Pos- sible Petroleum Provinces in Alaska with annotated bibliography by E.H. Cobb: U.S. Dept. of Interior, Geol. Survey Bull. 1094. Moore, Billy J., 1975, Tables on Alaskan Gases in Analyses of Natural Gases: U.S. Dept. of Interior, Bureau of Mines, p. 4-8. School, D.W., and Hopkins, D.M., 1969, Newly Discovered Cenozoic Basin, Bering Sea Shelf, Alaska: Am. Assoc. Petrol. Geol. Bull. v. 53, p. 2067-1078. Smith, W.R., and Baker, A.A., 1924, The Cold Bay*Chignik District, Alaska in Mineral Resources of Alaska, Report on Progress of Investigations in 1922, Part D: U.S. Dept. of Interior, Geol. Survey Bull. 755, p. 151-218. Smith, W.R., 1925, Petroleum on Alaska Peninsula: The Cold Bay-Katmai District in Mineral Resources of Alaska, Report on Progress of Investigations in 1923, Part D: U.S. Dept. of Interior, Geol. Survey Bull. 733, p. 183-207. Spurr, J.E., 1898, A Reconnaissance in Southwestern Alaska in 1898 in Twentieth Annual Report: U.S. Dept. of Interior, Geol. Survey, P. 263-264. State of Alaska, Div. of Oil and Gas Conservation, no date, Alaska - Peninsula Well Location Map, Cold Bay to King Salmon, R13S-R59S, T39W-T84W, S.M., scale 1:250. State of Alaska, Dept. of Natural Resources, Div. of Geological and Geophysical Surveys, 1974, Estimated Speculative Recoverable Resources of Oil and Natural Gas in Alaska: Open-File Report 44. U.S. Dept. of Interior, Bureau of Mines, 1973, Alaska 1/250,000 Scale Quadrangle Map Overlays Showing Exploratory Oil and Gas Well Drilling Locations and Productive Oil and Gasfield Locations, by staff, Open-File Report 69-73. (updated yearly). U.S. Dept. of Interior, Bureau of Mines, no date given, The Mineral Industry of Alaska in Minerals Yearbook - Vol. | & Il, Metals, Minerals and Fuels; Vol. I!|, Area Reports: Domestic. U.S. Gov. Printing Off. 1932 to present. SOSCSCHOSHOSSSSHOHOHOHOHOSHOHHEHSCOEHOOOCOHOHOOEEOCO® Page |V-185 U.S. Dept. of Interior, Bureau of Mines, 1974, Minerals, Fuels, Geology - Resources Analyses for Joint Federal-State Land Use Planning Commission for Alaska: Volume 1: Inventory Report - Arctic Region. 1974. Volume 2: Inventory Report - Northwest Region. 1974. Volume 3: Inventory Report - Yukon Region. 1974. Volume 4: Inventory Report - Southcentral Region. 1974. Volume 5: Inventory Report - Southwest Region. 1974. Volume 6: Inventory Report - Southeastern Region. 1974. Edited and assembled by Arctic Environmental Information and Data Center. U.S. Dept. of Interior, Geol. Survey, 1974, Oil and Gas Regions and Provinces, State of Alaska USA: Resource Appraisal Group, Branch of Oil and Gas Resources for G.S. Cir. 725, Scale 1" = approximately 75 miles. Weeks, L.G., 1969, Offshore Petroleum Developments and Resources, in Journal of Petroleum Technology, v. 21, p. 377-385. SOCCHHSOHSSSESHSSOSHOSOSHSCHOSESSSOSCSOSCOCOCEOOESES®O Page |V-186 Se Uranium Uranium occurs in two main geologic environments: (1) in ancient sedimentary basins, and (2) with granitic or other alkalic igneous rocks. In sedimentary basins, uranium minerals have a common association with organic materials which apparently acted as a reductant to uranium-bearing aqueous solutions, thus fixing the uranium. The Bristol Bay subregion has environments which have some of the characteristics favorable for the occurrence of uranium. Other characteristics are, however, less favorable, and there are very few reported occurrences. Overall, the existing evidence suggests that the region is not as favorable for uranium deposits as other regions in Alaska; the better parts of the region are inferred to be in the north and northwest parts of the Nushagak or Bristol Bay Tertiary sedimentary Basin. Specific studies for uranium in the region have been few. Texas Instruments, Inc., of Dallas, Texas (1978A and B) has investigated the Dillingham and Lake Clark quadrangle by air radiation methods. MacKevett and Holloway (1977) of the U.S. Geological Survey indicated one possible uranium occurrence in the region. a). Sedimentary Basins Three sedimentary basins are generally recognized in the Bristol Bay subregion: The Alaska Peninsula Mesozoic Basin, the Bristol Bay Tertiary Basin, and a small part of the Cook Inlet Tertiary basin. In the Mesozoic basin, the coal-bearing beds of Cretaceous age include feldspathic sandstones of continental origin which could act as uranium-bearing hosts. The distribution of these rocks, such as those near Chignik, is shown on Map 1. These sandstones have organic materials and are possible hosts for uranium deposits. The Tertiary units of the Bristol Bay or Nushagak basin are poorly exposed, but are known from a few drill holes and geophysical evidence to be extensive. A major unconformity exists in the Tertiary section below the Miocene, and the rocks below the unconformity are highly deformed. Possible uranium environments include sandstone beds in the Miocene and pre-Miocene sections, and the unconformity itself. The Cook Inlet Tertiary basin also contains some favorable units for uranium deposition. This basin lies mainly offshore, but possibly extends into the northeastern part of the Bristol Bay region. SG0COH8OOOCHOEOOHOCHOOOSOEHEHHO8BHOSEOHO8O8E8ECO®S ©0098 08OOOCOHOOHOCEOOHOEEHOOESOESEO3ES8SCEOESESO b). Page 1V-187 Specific Data One preferred uranium anomaly was reported by Texas Instruments, Inc. near Lake Nunavaugaluk in the southwest part of the Dillingham quadrangle (1978A). The anomaly is not over one of the major recognized basins, but apparently over marine sedimentary rocks of Cretaceous age. The anomaly has a rather low total count, and is not likely as a uranium prospect. A second preferred anomaly is shown, east of Lake Kontrashibuna over a rock unit mapped as Jurassic quartz diorite (Texas Instruments, Inc., 1978). This anomaly has much higher total apparent uranium content than the Dillingham quadrangle anomaly (48 counts/ second vs. about 13 counts/second). The U.S. Geological Survey reported an occurrence in T. 29 S., R. 42 W. on the Ugashik quadrangle (MacKevett and Hollowway, 1977). It is a placer deposit with molybdenum and uranium reported. The validity of the occurrence is questionable. Overall Favorability The main mountain axis of the Alaska Peninsula is characterized by quartz diorite-granodiorite igneous rocks and andesitic volcanics. These rocks characteristically have a lower uranium content than more acidic igneous rocks. It is mainly because of this that the region is considered to have relatively low uranium potential. The sedimentary basins are derived partly by the erosion and transport of these igneous materials, and they have less favorability than if they were derived from more acidic igneous rocks. The Bristol Bay region is poorly evaluated for uranium by actual prospecting, and deposits of presently unsuspected type could occur. Inasmuch as uranium deposits are known to occur with titaniferous rocks, and the entire Alaska range Jurassic batholity has numerous associated titaniferous iron deposits, uranium deposits could occur in this environment. Of the recognized basins, the northern and northwestern parts of the Bristol Bay or Nushagak basin are considered most favorable, because potential igneous source rocks near the Tikchik Lakes are more acidic and probably more uraniferous than the granodiorite-quartz diorite which characterizes the bulk of the Mesozoic-Tertiary basin source areas. Page IV-188 REFERENCES MacKevett, E.M., Jr., and Holloway, C.D., 1977, Table describing metalliferous mineral deposits in the western part of Southern Alaska: U.S. Geol. Survey Open-File 77-169F. Texas Instruments, Inc., 1978A, Aerial radiometric and magnetic reconnaissance survey of the Eagle-Dillingham area, Alaska, Dillingham quadrangle-Vol. 2-M Bendix Field Engineering Cor- poration, Subcontract No. 7/7-060-L. ‘U.S. Dept. of Energy. Texas Instruments, Inc., 1978B, Aerial radiometric and magnetic reconnaissance survey of the Eagle-Dillingham area, Alaska, Lake Clark quadrangle-Vol. 2-L: Bendix Field Engineering Corporation, Subcontract No. 77-060-L. U.S. Dept. of Energy. ; 000080000 HOCOOOOOHOOOSEOHOHOHOHHHOSEODOHEO8EEO8®O “ @oe ee O24 220 42e5° Page |V-189 SELECTED BIBLIOGRAPHY URANIUM Alaska. Joint Federal-State Land Use Planning Commission. Minerals Secton. Resource Planning Team. May, 1974. Minerals, Energy and Geology - Southwest Region: Inventory Report. Bendix Field Engineering Corp., 1976, National Uranium Resource Evaluation, Preliminary Report (GJO-111(76): Under contract to U.S. Energy Research and Develop. Administration. Bottge, Robert, 1975, Alaska's Energy and Mineral Potential: U.S. Dept. of Interior, Bureau of Mines. Cobb, Edward H., 1970, Uranium, Thorium, and Rare-Earth Elements in Alaska: Mineral Investigations Resources Map MR-56. U.S. Dept. of Interior, Div. of Geol. Survey. Eakins, Gilbert R., 1969, Uranium in Alaska: State of Alaska, Dept. of Natural Resources, Div. of Mines and Geol. Rept. No. 38. Eakins, Gilbert R., and Forbes, Robert B., 1976, Geological and Geo- physical Surveys. Investigation of Alaska's Uranium Potential: State of Alaska, Dept. of Natural Resources, Special Rept. No. 12 (Open-File Report, U.S. ERDA, 11/25/75, GJO-1627). Eakins, G.R., Jones, B.K., and Forbes, R.B., 1977, Investigations of Alaska's Uranium Potential: State of Alaska, Dept. of Natural Resources, Div. of Geological and Geophysical Surveys, Open-file Rept. 109. Klein, Robert M., 1975, Energy and Minerals Resources of Alaska - and the impact _of Federal land policies on their availability - "Sedimentary Uranium": State of Alaska, Dept. of Natural Resources, Div. of Geol. Surveys Open-File Report No. 52. Texas Instruments, Inc., 1978, Aerial Radiometric and Magnetic Reconnaissance Survey of the Eagle-Dillingham Area, Alaska: vol. 1, 2-M, and 2-L; prepared for the U.S. Dept. of Energy under subcontract to the Bendix Field Engineering Corporation. Wedow, Helmuth, White, Max G., and Moxham, Robert M., 1951, Interim Report on_an Appraisal of the Uranium Possibilities of Alaska: U.S. Dept. of Interior, Div. of Geol. Survey, Trace Elements Memorandum Rept. 235. by). Page IV-190 Wind Potential General Remarks This is a preliminary survey of the wind energy potential of communities within the boundaries of the Bristol Bay Regional Corporation (BBRC). This potential relates to practical application of this wind energy extracted by contemporary wind energy conversion systems (WECS). For at least the coastal communities of the BBRC this potential is high, and should be exploited soon. There is a spasmodic history of wind power use in the Bristol Bay Area (BBA), continuing on a small scale today. According to verbal communications Dillingham had WECS in the 1930's and there is one small machine operational today at Portage Creek. The Geophysical Institute of the University of Alaska operated a WECS at Ugashik in 1975. A small unit at Port Alsworth is also providing significant power to a private residence. However, the central question addressed here is the magnitude of the wind resource applicable to electrification or supplemental supply of energy to communities. The basic approach used to determine feasibility of WECS is explained to a greater detail in Appendix B-5. Wind Data for the Bristol Bay Area Sites: Here and later the data and analyses are categorized according to region areas, namely near Dillingham (Dil), near King Salmon-Naknek and remaining villages. The latter have been subdivided into the areas south of Naknek and inland and northeast of Dillingham. Some open ocean (Bristol Bay) data and coastal sites outside the BBRC are included here as a guide to estimation, when required. Data deficiencies are noted when pertinent, and also summarized in the conclusions. (i) Dillingham_and_ surrounding area Dillingham wind data have been recorded for many years (about 20), mostly for aviation purposes. The raw data are available in Alaskan climatic archives, but have not been summarized. The cost of the necessary processing is far outside the scope of this study and even a single year summary was not attempted. However, the data for January and July of 1978 has been summarized. The resulting Gi) Page 1V-191 average wind speed (V) are given later in Table 1V-7. These were then compared to the corresponding known V for Cape Newenham, King Salmon and the Bristol Bay ocean area. Such extrapolations are fraught with uncertainty, especially since local obstructions and channeling effects can strongly influence the winds. Villages East and Northeast of Dillingham Early in this study the use of wind power well inland from Dillingham did not appear promising. This premature conclusion was based on the usual marked attenuation of wind speed observed when inland. For instance, outside the BBA Bethel is a good candidate for WECS but 65 miles upriver Aniak is a poor one; similarly, winds at Unalakleet are usable but at Kaltag they are marginal. However, the relatively flat and open terrain between Dillingham and lliamna and the wind statistics from both indicate that the wind potential of villages along the Nushagak and Kvichak Rivers cannot be ignored. In any subsequent study, a village-by-village survey of residents should be made to assess the worth of wind measurements at their recom- mended sites. \liamna: There are reliable and adequate wind data (5. year summary) from the Iliamna airport. These indicate that the potential for useful wind power for most months is good. There is a gap in the Aleutian Range between Kamishak Bay to lliamna Lake. that apparently provides a path for winds over lIliamna and possibly further inland. The winds are predominantly from the ESE or NNE. Port Alsworth: At the extreme NE border of the BBA wind power is being used for a resident at Port Alsworth. Local topography maps indicate severe shielding and an expected low potential, but in this case a slope exposed to a long wind run over Lake Clark apparently produces favorable winds. There are archived wind data from Tanalian Point, which have not yet been analyzed. Togiak and Twin Hills: These should have a reasonable wind power potential, in view of the coastal location and usually flat surrounding topography. (iii) (iv) Page IV-192 King Salmon-Naknek Area The wind data for King Salmon (KS) are extensive and reliable, due to the long-term operation of a first class National Weather Service station there. There are less data for Naknek, but these were not pursued; the terrain for the area indicates that the KS data apply for our purposes also. to Naknek. Since Naknek is closer to Bristol Bay, wind speeds there probably are slightly higher than at KS. In the tables separate sets of KS data are given, to indicate the variations observed for different heights and data periods. Villages Southwest of King Salmon (See also (v) of this section. ) The only known wind data for BBA villages on the Alaskan Peninsula SW of King Salmon (KS) are for Port Heiden (PH), Pilot Point (PP) and Ugashik (Ug). Also considered here are data for the Peninsula sites of Nelson Lagoon (NL) and Port Moller (PM). Port Heiden: The several years of PH data seem to be reliable, and typical of the NW side of the Aleutian Range on the Alaskan Peninsula. There is a general decrease in windspeed going northeastward from Cold Bay to King Salmon, but the wind power potential is generally good. Part of the trend is an increased frequency of low windspeed and calm periods going toward King Salmon. Nelson Lagoon and Port Moller: The village of Nelson Lagoon (NL) and the Air Force Station at Port Moller (PM) Present auxiliary information and a contrast. These in comparison give an example of the need for careful measure- ments with proper exposure in making judgments as to wind power feasibility. At Nelson Lagoon a currently experimental 20 kW-rated windmill apparently has yielded very satis- factory power outputs, when operational. It has been plagued by operational "bugs", (largely those associated with designer inexperience with Alaskan soil conditions and wind-driven moisture). While the associated windspeed at Nelson Lagoon is not known, the wind power potential there seems to be good to excellent. However, about 20 miles to the east across a bay the measured site of Port Moller gives relatively low windspeed and indicates little promise for WECS use. This can be explained to a large extent by local 20068000000 OOOOOHOOO8HOHOOHOHOOO8OD OOH HOOSES G©OHSHOHHOHHOHHHHAOSHOEHOCHOOHCHOHOOHOHOEHOGECOOS (v) Page !1V-193 shielding of, and also low height of, the anemometer. (A verbal communication indicates that the winds at the landing strip at PM are much stronger than at the radar site.) Ugashik, Pilot Point and Egegik: Sporadic wind measurements have been made by the Geophysical Institute at Ugashik in 1974-1977, and a 6 kW-rated WECS was operated there in 1975. The wind data did not yield a statistically valid windspeed, but usually showed extended good wind power periods (several days at a time) spaced by calm periods of a day or two. The incomplete speed data was consistent with averages of the data for Port Heiden and King Salmon for which good statistical data is available. The WECS performed well for the last four months of 1975; then it was destroyed during a modest gale (65 knot peak gusts) due to the failure of a defective "safety" feature. There are fragmentary wind data from Pilot Point which support the even less complete measurements at Ugashik, 8 miles inland. The annual windspeed at Pilot Point in the December 1938 April 1941 period was 12.6 MPH at 34 ft. Usually only three observations were taken daily, and there was some topographic shielding from north winds. Maximum winds reported were only 45 MPH (curiously low), but there were many periods of 7 to 17 hours with windspeed of 35 to 45 mph. Calms amounted to 12% of the time. There seems to be little question about the wind power potential of this area. The long runs of high winds point out a special design consideration of WECS for the Alaska Peninsula; the WECS should have a cut-out windspeed above that of most contemporary WECS, say 50 MPH or more instead of 30 to 40 MPH. These long runs are one reason we favor for Alaska, and especially the Alaska Peninsula a complex of smaller machines rather than a few large units. There are no known wind data for Egegik. The location and topography should favor usable wind power. A conser- vative estimate for V at Egegik is that measured for King Salmon. Chignik Area The villages of Chignik, Chignik Lake, Chignik Lagoon, Perryville and Ivanoff Bay experience wind regimes different from those like Port Heiden, being south of the Aleutian Range. There are no known wind data for the Chignik area. The wind power potential of the first three villages is estimated to be poor. All five are subject to severe Page |V-194 topographic shielding, but perhaps some channeling effects may yield usable winds during some months. The effect of nearby Mt. Veniaminof (volcanic) to the north or northwest is probably the dominant adverse shielding factor. From topographic maps the following is estimated: Perryville: There is a path so that katabatic winds off the slopes of Mt. Veniaminof, if they occur, can flow across the village to the sea. This path also provides good exposure to winds from the south, unless nearby off-shore islands also produce shielding. lvanoff Bay: The shielding is pronounced, excepting the possible passage for winds from southwest Stepovak Bay across the Stepanof Flats. Chignik is heavily shielded. Chignik Lake and Chignik Lagoon are similarly shielded, but channeling effects could be marked. The winds across the tops of the numerous steep hills probably have a good potential, but the transmission line and WECS maintenance problems would be severe and costly. Wind surveys at Perryville and/or |Ivanoff Bay should be made, subject to the advice of their residents. Wind Data The following tables give the measured windspeed, the height of measurement and the windspeed estimated at a standard height of 60 feet. This standard height was selected as a practical compromise between tower cost, WECS erection problems and the increased power expected from increased heights. Standardization of height here is to compare the wind power in various parts of the BBA. Other considerations covered later show that lesser or greater heights might be worthwhile for given machines at specific sites. Computations of power flux for several sections are given in the next section after a discussion of expected WECS power outputs. ©2008 8008OOO8HHOHHOHOHEHOHTOHOHCHOOOCOHDOCCECOCECO8E Page IV-195 TABLE 1!V-2 MEASURED AVERAGE WIND SPEEDS (MPH) IN THE BRISTOL BAY AREA BB Ocean Area PH PM KS(1) KS(2) Dil (CN) Wi h, Tt. 33. 29. 25. 38. 26. 30. 20. 33. J 15.8 16:5 9.8 1.6 11.2 12:2. 12.58 14.8 F Ea.7 16.1 10.0 11.9 11.7 13.0 pe M 17.7 15.9 10.6 12.4 11.4 12.3 9.2 A 17.6 14.0 10.6 11.1 10.6 12.6 9.0 M 14.4 12.8 Oca 11.8 10.8 9.9 9.8 J 12.0 12.7 8.1 10.8 10.0 8.6 10.2 J 11.6 at 9.0 10.3 8.9 9.3)% 778.6 8.3 A 15:5 14.2 10.0 10.6 10.0 10.2 9.6 S$ 18.2 15.7 10.6 1116 10.0 1160 10.5 Oo 22.1 15.8 12.2 11.2 10.6 11.7 11.1 N 19.0 1552 V2:3 12.6 10.9 12.5 11.4 D 20.0 16.8 10.9 1125 10.5 12.0 10.6 Annual 14.8 14.8 AOr2 11.4 10.5 Tihs 10.4 (CN) not within BB Regional Corporation Boundaries KS(1) for 5 years at 38 ft. KS(2) for 25 years at mean height of 26 ft. *Necessarily assumed; from ships between coast and 165°W, 55-59° latitude. + 1978 only; all other from 5 or more years of data. BB = Bristol Bay PH = Port Heiden PM = Port Moller KS = King Salmon Dil = Dillingham CN = Cape Newenham ili = Iliamna Page |V-196 TABLE IV-3 EXPECTED AVERAGE WIND SPEEDS (MPH) AT 60 FT. IN THE BRISTOL BAY AREA PH PM KS(1) KS(2) Dil (CN) i J 19.0 11.7 12.7 13.2 14.0 15.9 16.7 F 18.6 11.9 13.0 13.9 16.2 12.5 M 18.4 12.6 13.6 13.5 15.3 10.4 A 16.2 13.0 12.1 12.5 15.6 10.7 M 14.8 10.8 13.0 12.8 12:3 We J 14.6 9.6 11.9 11.8 10.8 11.5 J 14.0 10.7 11.3 10.5 10.7 10.8 9.4 A 16.4 11.9 11.6 11.8 12.8 10.8 S 18.1 12.6 12.7 11.8 13.8 11.8 Oo 18.2 14.5 12.2 12.5 14.6 12.5 N 17.6 14.7 13.7 12.9 15.6 12.9 D 19.4 13.0 12.6 12.4 14.9 11.9 Annual V7.2 12.8 12.5 12.4 14.0 11.7 PH = Port Heiden PM = Port Moller KS = King Salmon Dil = Dillingham CN = Cape Newenham Hi = lliamna d). Page |V-197 WECS Average Power Production Average Powers: Detailed calculations of the average machine power output (P,,) were made for two contemporary WECS with locations assumed at Port Heiden, King Salmon and Iliamna. The results are given in Tables 1V-4 through |IV-8. These data represent magnitudes to be expected, but do not indicate optimum performance. Gi) 15 kW-rated WECS This machine (25 ft. disc) .is not optimized; the rotor and controls evidently are designed to limit (at 15 kW) before the 20 kW generator capability. It is inherently a high V machine. It is a prototype of the WECS being tested at Nelson Lagoon, which may be rated near 20 kW. ii) 100 kW-rated WECS This machine (125 ft. disc) as used in our calculations involves a rotor capable of over 200 kW mechanical drive to the generator. The prototype used a 100 kW-rated generator, but a new version with a 200 kW generator is now operational at Clayton, NM. Thus, one can estimate that a WECS with an 88 ft. disc and 100 kW generator would produce Pu similar to our tabulated values. The wind data in the tables are for the heights of wind measurement and sites designated. There is an incompatibility in the tables, in that for the 100 kW machines naturally one can not place the hub height at less than the blade length. However, the tables are useful in that the machine power output does correspond to the mean windspeed given if that speed occurs at hub height. Duration of Wind Power: The power output (Puy) quoted take into account the wind variability, including calm periods. Thus, the instantaneous P will range from zero to the rated P; hence power conditioning and distribution equipment must be rated at the maximum WECS power. Energy storage is not considered here, since, for municipal systems a better and well-developed approach is the synchronous inverter or an induction generator. A windspeed of about 12 MPH has been used in USDOE wind power work as a practical criterion for economically viable use of WECS. This criterion can be changed, depending on the other energy sources at a location and the fossil fuel Page 1V-198 TABLE !V-4 WECS MEAN OUTPUT POWER, WECS OUTPUT FLUX AND MEAN POWER FLUX OF THE WIND ILIAMNA 15 AND 100 KW-RATED WECS AT H=60 FT FP IN TABLE ARE MEAN POWERS V v P¢15) P¢100) P/AC15S) P/AC100) P/ACWIND) (KT) (MPH) (KW) CRW) CW/M2) (W/M2) CW/M2) J 14.51 1647 3+67 54.28 124.35 47.57 545-39 F 10.86 12,45 3430 36470 72-24 32-17 228,71 Mm 9.04 10.4 2.21 26.66 48.36 23-36 131.72 A 9.30 10-7 2.36 28.12 31.62 24.65 143.45 M 9.65 11.1 2.56 30.06 56.05 26-34 160-15 J 9.99 11.5 2+76 31.98 60.57 28.03 178.09 J 8.17 94 1.73 21.75 37695 19-06 97-26 A 9.39 10.8 - 2.41 28.61 52.72 25-07 147.51 S 10.25 11.8 2.92 33.41 64.02 29-28 192.40 © 10.86 12.5 3.30 34+70 72-24 32.17 228.71 N 11.2 12. 3-51 38.55 77.03 ~~ 33-78 251.38 p 10.34 11.9 20697 33-89 65.18 2970 197.33 Anna) 10.17 11.7 2.87 32694 62.87 28-87 187.55 Columns 1 and 2 are average windspeed for the months and annually in knots (kt) and miles per hour (MPH). Columns 3 and 4 are average power output, from equation (5)* and Table 1 in kW. Column 5 and 6 are output flux in watts per square meter; the discrepancies are due largely to the mismatch in rotor and generator size of the 100 kW WECS; see text. Column 7 gives power flux in watts per square meter, from equation (4)*. In Appendix B. 000 COOOOOOOOHHOOHOOHOHOHOHHOHOOCOCHOEOOO8S Page |V-199 TABLE IV-5 WECS MEAN OUTPUT POWER, WECS OUTPUT FLUX AND MEAN POWER FLUX OF THE WIND FORT HEIDEN. 15. AND 100 KW-RATED WECS AT H= 60 FT FP IN TABLE ARE MEAN POWERS v Vv PCLS) P(100) P/ACLS) P/AC100) P/ACWINI) (KT) (MPH) CRW) (KW) CW/M2) CW/M2) (W/M2) 16.51 19.0 6+97 61.55 152.81 53-94 803.19 16-16 18.6 6.75 60.44 147.96 52-97 733-52 15.99 18.4 6.64 59.86 145.51 92-46 729 +47 14.08 14.2 339 52.44 118.06 45-96 497.85 12.86 14.8 4.58 46.88 100.44 41.09 379-61 12.469 14.6 4.47 46.04 97.94 40.35 364443 12.17 14.0 4.13 43.47 90.47 38,10 321.32 14.25 14.4 3-50 53.18 120,58 46.61 916.52 15.73 18-1 +47 58.95 141.82 31-67 694.37 15.82 18.2 6-53 59.25 143,06 91.93 705695 15.29 17.6 6.19 57 +37 135.62 30,28 638.40 16.86 19.4 7eae 62-59 157-61 54.85 854.99 14095 . 172 3+96 34-03 130.43 49,11 595.86 FORT HEIDEN 15 AND 100 KW-RATED WECS AT H=29 FT F IN TABLE ARE MEAN POWERS v U PC(15) P¢100) P/ACLS) P/AC100) P/ACWIND > (KT) (MPH) (KRW) (RW) (W/M2) (W/M2) (W/M2) 14.34 16.5 5056 - 53.55 121,84 © 46493 5326.03 13.99 1661 5-33 52.046 116.80 45.43 A488 +49 13.82 15.9 Se2i 51-30 114.27 44.96 470.70 12.17 14.0 4.13 43.47 90+47 38.10 321.32 11.12 12.8 3-46 38.09 75.82 33-38 245.58 11,04 12.7 3.41 37-63 74.62 32.99 239,87 L0.St:" 12.4 3.08 34.83 67-52 30.53 207-45 12.34 14.2 4.24 44.34 92.95 38-86 335+29 13.64 15,7 510 50.52 114,75 44.28 453.16 13.73 15.8 5-16 50.91 113.01 44.62 461.88 13421 .15.2 4,81 48.52 105.46 42,53 411.23 14-60 16,8 3+73 54-463 125.61 47.88 555.25 12.86 14,8 4.58 46.88 100.44 41.09 379 +61 The remarks at the bottom of Table |1V-4 apply here. ©99OEOHOOHHHHOOHOHHOOHOOHOHHEOHHO8OCHSOSE8O Page !V-200 TABLE IV-6 WECS MEAN OUTPUT POWER, WECS OUTPUT FLUX AND MEAN POWER FLUX OF THE WIND KING SALMON 15 AND 100 KW-RATED WECS AT 60 FT* F IN TABLE ARE MEAN POWERS V Vv PC1S) FC100) P/AC15) P/AC100) P/ACWININD CRT) (MPH) (KW) CRW) (W/M2) (W/M2) (W/M2) 11.04 12.7 3-41 37-463 74+62 32.98 239-87 11.30 13.0 3-57 39.00 78.23 34.18 257.27 11.82 13.6 3-990 41.71 85.54 36.55 294-456 10551 (12.2... 3-08 34.83 67.52 30-53 207.45 11.30 13,0 3.57 39.00 78-23 34,18 257.27 10.34 11.9 2077 33.89 65.18 29.70 197-33 9.82 1163 2.66 31,02 58,30 27.19 168.96 10.08 11.6 2-82 32.46 61.72 28.45 182.78 11.04 12,7 3-41 37.63 74462 32.98 239.87 10.40 2.2 3.13 35-430 68.49 30-94 212.64 Dido PD!) LS eZ, 3-96 42.15 86.77 36-94 301.411 10.95 12.6 3-35 37-16 73443 32.657 234.24 10.86 12.5 3-30 346.70 202 32.17 228.71 NING SALMON 15 AND 100 KW-RATED WECS AT 38 FT* F IN TABLE ARE MEAN POWERS Vv Vv P¢15) P(100) P/ACLS) P/A(100) P/ACWIND) (KT) (MPH) (KW) CRW) (W/M2) (W/M2) CW/M2) 10.08 11.6 2.82 32-46 61.72 28,45 182.78 10.34 11.9 2097 7 33.89 65.18 29.70 197.33 10.78 12.4 024 36.24 71.05 31.76 223427 9.65 11.21 2.56 30.06 36-05 26.34 260.15 10.25 11.8 2292 33.41 64.02 29-2 192.40 9.39 10.8 2.41 28.61 52-72 25-07 147.51 8.95 10.3 216 26-17 47.29 22-94 127.96 9-21 10.6 2-31 27+63 50.53 24.22 139,47 10,08 11.6 2,82 32-446 61-72 28-45 182.78 ¥s7a Tisk 2-61 30.54 57.17 26+77 164.52 10.95 12.46 3,435 37.16 73443 32.57 234.2 Pe9?) Lies 2.76 31.98 60.57 28.03 178.09 9.F71i 14+4 2071 31.50 59-44 27,61 173.49 *Use these results for Dillingham as a probably conservative approximation. The remarks at the bottom of Table IV-4 apply here. C900 ECOOOOCHHOCHOOOOOHOOHOHOHOOHOO8OHHHOOCO8S ©0003 OHOOHOH9DOOHOOOOHOOHOOHKEIENDNOOCOCOECOROCOD Page |V-201 TABLE IV-7 AVERAGE POWER OUTPUT (KW) OF TWO TYPICAL WECS IF OPERATED AT 60 FT HUB HEIGHT IN THE BRISTOL BAY AREA 15 kW-rated 100 ‘kW-rated Pu Pu range Pa Py range Location (Annuai) (12 months) (Annual) (12 months) Dillingham Use King Salmon results as conservative estimates. King Salmon 3.3 2.7-4.0 36.7 31.0-42.2 Iiamna 2.9 1,7-5.7 32.9 21 .8-54.3 Port Heiden 6.0 4.1-7.2 56.0 43.5-62.6 (4.6)* (3.1-5.7)* *If at 29 ft. height. e). Page 1V-202 costs there. The tables show that this windspeed is available at Port Heiden all months, at 29 ft.; at King Salmon there is adequate wind at 60 ft. for about 10 months and at lliamna at 60 ft. for six months. King Salmon estimates are expected to be conservative if applied to Dillingham. Wind prospecting at any site may locate more favorable locations. Economic Analyses There are various ways to deduce the economic worth of a WECS. Only one method is given here. We deal with the payoff time, the period a WECS operates to pay off through oil savings, a loan for the machine. The input variables and equations are summarized on the next page. The important result is that under the conditions of high annual V, high fuel costs and poor diesel generating efficiency the payoff time can be of the order of five years. Those conditions already exist in many Alaskan villages. The payoff times for Dillingham and King Salmon would be less attractive now, especially because of high diesel efficiencies and relatively low fuel costs. However, 1985 could present a different picture. WECS costs are in a state of flux now. USDOE contracts are aiming for about $800/kW (f.o.b. outside Alaska) in 1978 dollars. This: rate is for WECS in the 1 to 25 kW-rated range. For estimation purposes, a rate of $1100/kW installed in Alaska should be used; this assumes barge transportation. Synchronous inverters currently are priced around $300/kW. An expanding market probably will reduce this figure. Of course, inflation must be considered in all the above. Application of WECS is investigated in subsequent sections of this study. The following table shows the energy output for characteristic locations in the Bristol Bay area, derived from the available wind data. Estimated annual and per kWh cost are also listed. 09089000000 O9GOOOOOHOOHOOOOOBOTBENOOOOOCEROO8 Page !V-203 TABLE IV-8 WIND GENERATOR ENERGY AND. POWER OUTPUT FOR SELECTED LOCATION BRISTOL BAY AREA Installed? Output _Cost $_ kw_Range Annual? Av. Annual Annual MWH Cost $ Energy Cost (Secondary Location Wind Speed? non firm) ¢/kWh 1.5 KW RATED GENERATOR King Salmon/ 1225 0.4-0.6 9,440 79 Dillingham 4.32 3,403 lliamna thd 0.3-0.7 9,440 86 3.96 3,403 Port Heiden 17.2 "19 9,440 55 6.24 3,403 15 KW RATED GENERATOR King Salmon/ 1235 2.7-4.0 35,220 23 Dillingham 28.91 6,550 lliamna A OvA iev=Sig/, 35,220 26 25.4 6,550 Port Heiden 1i2 4.1-7.2 35,220 a2 52.56 6,550 100 KW RATED GENERATOR King Salmon/ 12.5 31-42.2 226 , 000 10 Dillingham 321.49 Ja, 990 lliamna 11.7 21.8-54.3 226 ,000 11 288.2 827595 Port Heiden W762 43.5-62.6 226 ,000 7 490.50 32,595 Notes: Investment cost. and maintenance cost are based on manufacturer's information with very little field data from Alaska available to verify these assumptions. At 60' mounting height. 2 From Appendix C.4. Assumes cogeneration (no energy storage). 3 15 year loan, 9% interest (.1221 cap. recovery factor) plus maintenance $2250 per year for 1.5 kW and 15 kW; $5000 per year for 100 kW. ©0086 COHOHOOHOGSOHOOOOHOCOHHOSCOHHODOCBOCO f ™ x SS = x WECS PAYOFF THROUGH OIL SAVINGS. 1V-274 tit (ii) 8760 P, t F Gf, = ‘ (1+i)°-1 t or CC, = Cq =» 12) a s3 Fe . [(1+i)°-1] © (14r) 0 C, = 8760 E. (KWh/yr) Cy = UF, $/ga1)(G gal /Kith) fy went S) 4 = LOAN INTEREST RATE F = AVERAGE OIL COST OVER PERIOD t ($/gal) r= OIL (INFLATION) RATE INCREASE F,= FIRST OIL COST ($/9a1) t t = PAYOFF TIME OF L (YEARS) Bw Fes y car)t to L = WECS COST (INSTALLED) 1/G= ELECTRICAL ENERGY YIELD OF DIESEL GENERATOR (KWh/ga1) B= AVERAGE POWER FOR GIVEN WECS AND _ f= USE FACTOR (WECS ENERGY); UNITY OR LESS SITE AVERAGE WIND SPEED vU ® a © Ss ' nM So > ©0000 OOSOO OC COGO OOOOH OOSESOOOHOOOOHOOSTOCOHOCO Page 1V-205 Tidal Energy With extreme tidal ranges as high as 31' and extreme tidal currents up to 5 knots in Bristol Bay a potential for tidal power is conceivable. However, to provide perspective consider the following factors relating to these tides: (i) According to the Tide tables published by the National Oceanic and Atmospheric Administration (NOAA) of the U.S. Department of Commerce, the mean range (difference in height between mean high water and mean low water) for Bristol Bay is as follows: Egegik River Entrance 13.8 feet Egegik River - Egegik 10.8 feet Naknek River Entrance 18.5 feet Naknek River - Morakas Pt. 15.1 feet Naknek River - King Salmon 2.1 feet Kvichak River - Naknek 15.4 feet Kvichak River - Kvichak . 13.9 feet Kvichak River - Levelock 8.2 feet Nushagak Bay - Clarks Pt. 15.3 feet Nushagak Bay - Snag Pt. 15.9 feet (ii) According to the Tidal Current Tables published by NOAA the average velocity at maximum current for Flood and Ebb tides in the Bristol Bay are as follows: Flood Ebb Kvichak Bay (off Naknek River Entrance) 2.5 knots 2.5 knots Morakas Pt. 1.1 knots 2.1 knots Kvichak 1.7 knots 3.0 knots Nushagak Bay - Clarks Pt. 3.2 knots 3.4 knots Dillingham 3.4 knots 3.2 knots Giii) The semidiurnal tides of Bristol Bay have a period of about 12.42 solar hours. For a prime power installation using these tides, two storage pools (one maintained at high water levels by replenishment from the high tides and one maintained at low level by draining during low tides) are required. The power turbines are driven by water flowing through them from the higher pool to the lowest pool. A tidal power project of this nature should then include the two pools close together with a power plant between and with gates to provide quick filling and emptying of the high and low pools during slack water periods. The storage require- ment for such pools with a 12.42 hour tidal period is about as follows: Mean Useful Page 1V-206 ACRE-FT. OF PONDAGE REQUIRED - EACH POOL (Two-Pool Tidal Power Development - 12.42 Hr. Tide Period) Mean Useful* Tide Range-Ft. Power Plant Capacit 7,000 2,000 5 10 15 20 25 30 2,933 5,865 1,466 2,933 978 - 1,955 733 1,466 587 1,173 489 978 - Kilowatts 5,000 10,000 14,664 29,327 ypaoe 14,664 4,888 9,776 3,666 a,a0e 2,933 5,865 2,444 4,888 The mean range of the tide is useful only if the two pools are large enough to provide a mean effective head equal to this mean range. lesser effective head. Smaller pools will result in Gates to provide quick filling and emptying of pools during slack water will need to provide for movement of the acre-ft. of pondage shown in the table above during the time of slack water. Using times of 30 and 60 minutes (See Table 4 of NOAA Tidal Current Tables for more accurate data) gate length requirements may be roughly estimated as follows: 1000 cfs per 100 ft. of 2 ft. depth of water flow thru gate) ate length (based on about APPROXIMATELY GATE LENGTH (FT.) REQUIREMENTS - EACH POOL (30/60 Minutes Slack Water) (Two-Pool Tidal Power Development - 12.42 Hr. Tide Period) Tide Range-Ft. 1,000 2,000 5,000 5 7,100/3,550 14,200/7,100 35,500/17,750 10 3,550/1,775 7,100/3,500 17,750/8,875 15 2,370/1,185 4,740/2,370 11,850/5,925 20 1,775/887 3,550/1,775 8,875/4, 440 25 1,420/710 2,840/1,420 7,100/3,550 30 1,185/592 2,370/1,185 5,925/2,962 Power Plant Capacity - Kilowatts 10,000 71,000/35,500 35,500/17,750 23,700/11,850 17,750/8,875 14,200/7,100 11,850/5,925 Page |V-207 (iv) Tidal currents can produce electric power by turning a Propeller Horsepower* 1400 140 14 1400 140 14 propeller placed in the current. Power produced in this manner is dependent on the kinetic energy of the moving water. This can be estimated approximately by calculating the velocity head and using this head to calculate power output as follows: 2 = @ 2.5 knots of current, a 0.28 ft. of head 2 @ 5.0 knots of current, Vv" = 1.11 ft. of head 2g Power can be produced by efficient propeller type turbines in amounts calculated by Power (kW) head x c.f.s. x 0.07 0.020 kW per c.f.s. @ 2.5 knots 0.078 kW per c.f.s. @5.0 knots An estimate of characteristics of propeller turbines for use in tidal currents can be made by referring to design factors for screw propellers for ship drives (see Baumeister and Marks, Standard Handbook for Mechanical Engineers). Utilizing the Taylor design diagrams, a formula for propeller projected area A (sq.in.) = 326 P/V X thrust (p.s.i.), and using the velocity head of the current and the weight of salt water (64.4 Ibs./cu.ft.) to determine thrust, the following table was developed: Projected Thrust Propeller Efficiency Propeller Pitch/ Area sq. ft. p.s.i. r.p.m. % Diam. (ft.) Diam. FOR 2.5 KNOT CURRENT 9,752 0.13 : 2 68.0 194 0.9 975 0.13 6 68.0 61 0.9 98 0.13 20 68.0 20 1.05 FOR 5.0 KNOT CURRENT 1,268 0.50 10 69.5 71 1.0 127 0.50 30 69.5 23 10 13 0.50 100 69.5 7 1.0 These sizes will deliver about 1,000 kW, 100 kW and 10 kW respectively. Page !V-208 Inspection of the factors listed above shows the important effect that range of tides and tidal current velocity have on the physical size of facilities needed to produce tidal power "Tidal Power Study for the United States Energy Research and Development Administration", March 1977 - prepared by Stone and Webster Engineering Corporation of Boston, Mass. indicates that it is generally found that tidal ranges of less than 18 feet are not likely to prove feasible. Bristol Bay has an additional factor of severe icing during winter conditions that would add a substantial burden for such tidal power efforts. It must be concluded that there is no tidal power potential of probable feasibility in Bristol Bay. Page |V-209 8. Other Energy Resources Section |! (Energy Balance) has shown that approximately 34% of the energy used in the base year has been utilized for home heating purposes. This part will investigate possible alternatives to replace or supplement fuel oil in the comfort and hot water heating process. a). Solar Heating The Bristol Bay area is located roughly between 55° and 61° latitude. The possible insolation shown on Table |V-9 for Annette and Bethel are considered to approximate conditions in Bristol Bay. The Annette and Bethel data has been developed with the F-Chart computer program and takes climate and typical weather conditions into account. The annual amount of solar energy available can satisfy all heating needs of an average home if enough collecting surface area and adequate storage could be installed. Heat storage or supplemental heating by other means would be necessary for about 6 - 7 months where the available insolation cannot satisfy the needs. If passive solar heating is considered, where the solar energy is used by energy efficient design (increased insulation, south facing windows with shutters, etc.) it is conceivable that even in November/December 40% of the required heat can be supplied by the sun if 350 sq. ft. of south facing windows can collect energy for an average size (900 sq. ft.) residence in the Bristol Bay area. Active solar energy collection requires collectors, a heat transfer agent (usually water or other fluids) and heat storage facilities. At the cost of $15 to $20 per Ft? of collectors with an efficiency of 40-70%, $1 to $2 per gallon storage capacity (1500+ gal at 180°F needed*) plus piping and controls it becomes obvious that the installed cost of a new solar system ($15,000+) cannot compete with a conventional oil-fired heating system (approximately $4000) at present fuel cost. With a 10 year system life expectancy and 12% interest the fuel cost would have to be $2.50+/gal. to allow installation of a solar heating system into a new house at this time. It should, however, be noted that the above calculations are only approximations and more precise evaluations of individual cases should be done especially with steadily increasing fuel costs expected to reach the $2/gal. mark by 1990 at some locations of the Bristol Bay Region. Stored capacity required = 1400 x 10° BTU (from Table IV-1 at 50% system efficiency using Annette); 8.36 BTU/gal./°F capacity of water at AT = 180°F-65°F = 115°F then requires 1456 gal. Does not account for heat loss during storage period. Page IV-210 TABLE IV-9 BRISTOL BAY - SOLAR ENERGY Available passive heat Average irisolation/day/Fet BTU/day through BTU/day? a_ Vertical South Facing Surface 350 Ft.* South Facing Windows Heating Degree? Days required for average Annette (55°02') Bethel (60°47') Annette Bethel Dillingham/King Salmon Residence Bristol Bay JAN 719 832 251.6 x 108 291.2 x 103 1528 396.7 x 103 FEB 837 1224 292.9 x 103 428.4 x 208 1288 378.6 x 103 MAR 1126 1892 . 394.1 x 108 662.2 x 108 1386 341.9 x 103 APR 1119 1689 391.6 x 108 591.1 x 103 1023 263.3 x 103 MAY 1001 1176 350.5 x 103 411.6 x 10 693 did, | x05 JUN 901 1021 315.3 x 103 357.3 x 10° 409 116.7 x 108 JUL 936 886 327.6 x 108 310.1 x 10° 307 74.2 x 103 AUG S15) Tits 320.2 x 10% 250.2 x 103 341 74.2 x 108 SEPT 992 874 347.2 x 108 305.9 x 103 ~ 525 146.7 x 108 OcT 627 823 219.4 x 103 288. x 10% 939 225.8 x 10% NOV 397 518 138.9 x 108 181.3 x 10° 1230 323.3 x 103 DEC 470 502 164.5 x 103 175.7 x 103 1562 396.7 x 103 ANNUAL 304.6 x 105 368.9 x 105 106.6 x 10° 129.7 x 105 11212 88.2 x 10% 1 "Solar Energy Resource Potential in Alaska" by J. P. Earling, R. D. Seifort for U of A Institute of Water Resources, 1978. 2 Alaska Regional Profiles, Southwest Region, State of Alaska. 3 Energy Balance, Appendix A: 97.4 x 10® BTU for 12410 degree days. Page IV-211 The report of V. P. Zarling and R. D. Seifert "Solar Energy Resource Potential in Alaska'' shows that hot water heating utilizing active solar energy collection is economical if it supplements electricity that has to be generated by burning fuel oil, but still cannot compete with gas or oil fired waterheaters. b). Electric Heat (Resistance and Heat pump) Electric resistance heating is almost 100% efficient if only the conversion from eléctricity to heat is taken into account. The installation costs of a resistance heating system are low compared to hot water elements, etc. and operation is clean and easy. Since electricity in the Bristol Bay area is generated in diesel electric generating plants where the conversion efficiency reaches 30% at best, electric heat cannot compete with a 70% efficient home furnace. Heat pumps - working according to the same principle a refrigerator does - can have coefficients of performance (C.O.P.) up to 3, which apparently leads to a "breakeven" situation with diesel plants. Efficiency of a heat pump, however, depends on the "media" temperature and will approach that of resistance heating at temperatures below 0°F. The following table is an excerpt from "The Role of Electric Power in the Southeast Alaska Energy Economy" Phase |, March 197919 and shows the capacity of the Janitrol, heating only heat pump, in relation to outside dry bulb temperature: Temperature cE 62 52 42 32 22 12 2 -8 Heat Pump Capacity 44000 39000 34000 29000 24000 19500 15500 12500 (BTU/Hr.) \f Compressor and fan run continuously the pump uses approximately 2.5 kW. Cost of installation for heat pumps are approximately 1.5 times 109 higher than for a hydronic oil fired furnace of equal capacity. Installation is therefore justified only when a low cost source of electric power is available. Electricity, generated in a hydroelectric power plant or by other means that use renewable or "free fuel" sources, can make electric heat or a combination of an electric with a fossil fuel fired heating system economical. Page IV-212 TABLE 1V-10 ALLOWABLE ELECTRIC ENERGY COST FOR COMFORT HEATING Cost! $/kWh_ to # Residential Annual? MWh) Annual MWh Other Total System Total System YEAR $/Gal. Offset Fuel Consumers? w/o Heat w/Heat Use MWh w/o heat MWh w/Heat 1980 8 .027 990 4499 33506 17035 21534 50541 1981 . 86 .029 1032 4884 35122 18034 22918 53156 1982 -92 .031 1074 5269 36737 19033 24302 55770 1983 -98 .033 1116 5654 38353 20032 25686 58385 1984 1.05 .036 1158 6039 39968 21031 27070 60999 1985 A AZ - 038 1198 6426 41527 22029 28455 63556 1986 1.20 -041 1242 6807 43198 22964 29771 66162 1987 1.28 .044 1286 7188 44888 23899 31087 68767 1988 1.37, .047 1330 7569 46538 24834 32403 71372 1989 1.47 .05 1374 7950 48208 25769 33719 73977 1990 1.57 .054 1417 8331 49849 26706 35037 76555 1991 1.68 .057 1452 8640 51184 27568 36208 78752 1992 1.80 -061 1487 8949 52518 28430 37379 80948 1993 1.93 - 066 1522 9258 53853 29292 38550 83145 1994 2.06 .07 1557 9567 55187 30154 39721 85341 1995 2.01 .075 1594 9876 56580 31017 40893 87597 1996 2.36 .081 1630 10185 57944 31879 42064 89823 1997 2.53 . 086 1666 10494 59308 32741 43235 92049 1998 2.70 .092 1702 10803 60672 33603 44406 *94275 1999 2.89 .099 1738 11112 62035 34465 45577 96500 2000 3o0 . 106 quae 11421 63340 35328 46749 98668 1 Dillingham/Naknek area for residential use, escalated 7%/year from 1980 on. 2 "Low" Growth Projections for Dillingham/Naknek plus 13 villages. Assumptions: Average house with appr.100 x 10® BTU required per year: 1000 gal. of fuel at 70% furnace efficiency or 29300 kWh for electric Page IV-213 The following Table 1V-10 shows the maximum cost for electric energy if fuel costs only have to be replaced. Also shown is the possible increase in electric energy consumption if only residential consumers would convert to electric heat in the Dillingham/Naknek area. These projections can assist in the process of establishing feasibility of a hydro project. The performance of a heat pump cannot be evaluated in this table because detailed data for required "on-line" time have not been compiled for this study. The maximum cost for electricity, however, can be 0 to 2 or more times higher than those for resistance heating and still break even with a fuel fired furnace. It should be noted, that cost of installation has not been evaluated in this simplified comparison. c). Wind Energy for Waterheating Only If a wind generating system would be used only to heat the hot water supply for a residential home, the economic aspects can be evaluated as follows: Wind Generating System: 1.5 kW, installed cost $5,000*. Monthly payments at 12% interest for 5 year loan $111 or $1332/year. Average Windspeed: 15 mph Energy Output: 460 kWh/month = 1,570 x 102 Btu/month, based on manufacturer's data, relates to cut-in speed of 10 mph min. Energy Requirements: for 52 gallon waterheater, 5 kW estimated load factor .5, then 430 kWh/month = 1,468 x 10° Btu/month. Fuel Oil fired waterheater at 80% efficiency uses approximately 13 gallon/month or 156 gallon/year. System Life Expectancy: 20 years Maintenance: Assumed equal for both systems and therefore omitted. 20 Year total cost wind generating system $6660. 20 Year total cost fuel oil system (i) at $.8/gallon with 7% escalation per year $5,091. (ii) at $.8/gallon with 10% escalation per year $7,213: *Assumes Owner-Installed. d). Page IV-214 This comparison shows that the wind generation system will only payoff within 20 years when fuel oil cost increase to more than $5/gallon within this time span. It is however anticipated that a wind energy system which can utilize all the energy available from the wind (no minimum "cut-in" windspeed and/or frequency required) can be economically more competitive than the system evaluated in the above calculations. Biomass The only resource of significance in this category is wood. The southern and western limit of wooded country, however, precludes utilization of wood as a continuous resource in all but the following communities: Dillingham Aleknagik Ekwok New Stuyahok Koliganek Igiugig lliamna Newhalen Nondalton Driftwood is occasionally available in the coastal communities and is used for home heating. The available information on quantity, heat content, age, and required time for regrowth for the wood in the forested areas does not allow a detailed assessment of the resource. Page IV-215 C. ELECTRIC ENERGY GENERATING TECHNOLOGY AND COST REVIEW This section will evaluate efficiencies and cost of various generating technologies and attempt to put their applications into perspective for the Bristol Bay area. Power cost evaluations have been carried to the distribution bus to insure properly weighted evaluation. 1. Diesel Electric Generating Units A prime mover consisting of an internal combustion engine utilizing fuel oil is connected to a synchronous generator forming a diesel electric generating unit. The units are usually completely assembled in the factory and can be easily installed close to load centers. They will supply single phase or three phase AC equipment. Efficiency ranges from 35% for large, relatively slow running engines (<1200 RPM) at proper loading (.5 to .9 of nominal load) down to less than 20% for small, high speed units (21800 RPM) at low loads. Very small units -- used in single family residences for example -- will use 138,000 Btu's (one gallon of diesel fuel) per hour to produce 16,000 Btu's (4.7 kWh) in electric energy at % nominal load. This represents an efficiency of only 12%. Waste heat recovery equipment will improve this performance and is available in various forms. Fuel efficiencies for power plants in the Bristol Bay Area have been listed in Section || of this study. An unorthodox method of improving the efficiency and life expectancy of diesel engines has been investigated for a typical load case in the Iliamna area (see Appendix D-10 of this study). Two different size prime movers drive one generator via gearbox connections. Appendix B-3 describes this method to a greater detail. Advantages Units are “on the shelf" items up to almost 1000 kW and can be installed quickly. They carry their design load reliably if properly maintained and operated. They can be placed close to load centers and thereby make long distribution or transmission lines unnecessary. In spite of relatively high cost, a diesel plant with an installed cost of $600 to $1300/kW installed capacity compares favorably with other generating means. Page I1V-216 Disadvantages The cost of energy generated by a diesel engine is greatly dependent on the cost of fuel. Table 1V-11 lists the 1977 cost for fuel in various Bristol Bay communities. With the expected escalation of 7% per year the cost at the plant bus in the year 2000, if generated in a conventional diesel generator, will be between $.23/kWh and $.79/kWh. The trend for cost of power between 1980 and 2,000 for the Bristol Bay Area is illustrated on Figure !V-2 where the total cost is the sum of fixed cost/kWh and variable cost/kWh in a given year. ASSUMPTIONS: 79| INTEREST 5% | FUEL COST ESCALATION 7% PER YEAR | FUEL EFFICIENCY 7 LIZ KWH/GAL FOR PLANT 31000 Kw 9 KWH /GAL FOR PLANT & SOOKW LOAD FACTORS +.4-.56 BARS INDICATE RANGE OF FUEL COST OMY. COST OF POWER (aT BUS) © FIXED COST + VARIABLE COST. 404. s ha VARIRBLE COST/KWH SMALL” PLANTS (100-500 Kw VARIABLE COST/KWwH ANTS WITH DEMANO 3 1000 Kw ¢/ kw 5 FIXED COST/KwH ALL PLANTS (100-500 Kw) FIXED COST/KWH PLANTS WITH DEMAND 1 1000 Kw vere 1900 wean 1990 lone 1000 PROJECTED COST OF DIESEL GENERATION FiguRE IX -2 DIESEL FUEL COST IN 1977 Table iV-11 from "Energy Balance" COMMUNITY . DILLINGHAM NAKNEK - KING SALMON ILIAMNA - Iliamna Newhalen Nondalton NUSHAGAK BAY Manokotak Portage Creek Ekuk Clark's Point FwWwnNre PENINSULA - BRISTOL BAY 1. Egegik 2. Pilot Pt. - Ugashik 3. Port Heiden 4. Port Moller PENINSULA - PACIFIC SIDE 1. Chignik 2. Chignik Lagoon 3. Chignik Lake 4. Ivanhoff Bay 5. Perryville TOGIAK . Togiak 2. Twin Hills ILIAMNA LAKE 1. Igiugig 2. Kakhonak 3. Pedro Bay 4. Port Alsworth INLAND 1. Ekwok 2. Levelock 3. New Stuyahok 4. Koliganek Page 1V-217 COST/GALLON $ -61 .651 -69 -69 1.30 -58 not available -65 not available .74 12 -61 not available -50 -50 -50 -61 -70 -85 -83 -70 .70 -72 not available «54 -43 .80 not available Page 1V-218 The graphs on Figure I1V-2 have been prepared by analyzing recent power cost studies for five southcentral Alaska utilities operating diesel generators exclusively (Dillingham, Naknek, Kodiak, Glennallen, Valdez), and three planning studies for communities in the Bristol Bay Region (lliamna, Chignik, Pilot Point). The general assumptions for all studies were: Interest 53 Depreciation 3 - 7% ("slow" - "fast" engines) Cost of fuel + 7% per year The "bands" reflect the ranges of installation and fuel cost in relatively more or less accessible areas. The variable costs include fuel, operating and maintenance expenses which are substantial since continuously running diesel generating equipment needs frequent observation, lubrication, filter changes, etc. by trained and qualified operators. An economic analysis evaluating the installation and operation of a small diesel plant at a remote location in rural Bristol Bay for the next twenty years has been investigated in Appendix D.1 of this section. The use of private diesel or gasoline generators is widely spread in the Bristol Bay area and partially dictated by the absence of a central power plant. The following brief analysis will show the estimated power cost for this type of generation: Load Characteristics Estimated Demand 2 kw Estimated Energy Use (average) 4 kWh/day = 1460 kWh/year Operating time 8 hrs/day Equipment Data Diesel Engine 2 kW Investment: $2,000.00 Efficiency at 1/4 load 4.7 kWh/gallon 1/2 load 7.5 kWh/gallon full load 9 kWh/gallon Life Expectancy 5 years Gasoline Engine 2 kW Investment $500.00 Efficiency at 1/4 load 1.6 kWh/gallon 1/2 load ~ 3 kWh/gallon fuil load 4 kWh/gallon Life Expectancy 3 years Page IV-219 Annual Cost Diesel Engine Gasoline Engine Amortization (12% interest) $ 538.00 $ 201.00 Maintenance (.6%) 12.00 4.00 Insurance (.2%) 4.00 1.00 Fixed Cost $ 554.00 $ 206.00 Fuel (1/2 load) 195 gal. @ $.8 487 Gal @ $1. = $ 156.00 = $ 487.00 Lube Oil (10% of fuel) 16.00 . 49.00 Variable Cost $ 172.00 $ 536.00 Total Cost $ 726.00 $ 742.00 with 1460 kWh use 50¢/kWh 51¢/kWh This compares to 37.2¢/kWh (or $543/year for 1460 kWh) presently being charged for residential service supplied by AVEC. A direct comparison with the cost/kWh at the distribution bus for a central power plant as shown on graph IV-C "Projected Cost of Diesel Generation is not possible since cost for home generation represents the cost at the consumer's service entrance. Further cost reductions are possible if the available waste heat can be utilized to offset other heating cost. With the previously stated operating assumptions the following heat is available for 8 hours every day: Diesel Engine Gasoline Engine Fuel Use 2.1 gal/day 4 gal/day Total Energy 289.8 x 10° Btu/day 512 x 10° Btu/day Electric Energy at 90% efficiency 4.44 kWh = 15.17 4.44 kWh = 15.17 x 108 Btu/day x 108 Btu/day Waste Heat 274.63 x 10° Btu/day 496.83 x 10° Btu/day or 34.33 x 108 Btu/hour or 62.10 x 10% Btu/hour Page |V-220 Diesel Engine Gasoline Engine Recoverable ] Waste Heat (70%) 24 x 10% Btu/Hr. 43 x 10% Btu/Hr. Heat required for residences (average): 100 x 10® Btu/year or 11.4 x 10% Btu/hour or .12 gal/hour of fuel at 70% furnace Efficiency Possible annual savings at $.8/gallon: 350 gallon or $280.00 The amount that can be used annually to pay for heat recovery equipment is then: Fuel savings $ 280.00 Adjusted for cost/kWh difference between $.5. and $:372 (priv. generator versus AVEC) (183.00) $ 97.00 At 12% interest and 10 year amortization (quarterly payments) this allows an investment of $2,242. The estimated installed!°7 cost for heat exchanger, heat recovery silencer, radiator and controls are approximately $3,000 - $4,000 if a conventional hot water. baseboard heating system is used. The result shows then that under the assumed operating conditions, even with waste heat recovery, a home generator cannot provide elec- tric energy as cheaply as a central plant. Zs Gas Turbine Generating Units Gas or oil fired in a turbine drives a generator. Exhaust heat is either directly released or utilized in a regenerative cycle through heat exchangers to raise the temperature of the inlet combustion air and increase the overall efficiency of the unit. Simple cycle gas turbines will require 12-16,000 Btu/kWh, while regenerative cycle gas turbines will generate at 10-13,000 Btu/kWh. Page IV-221 A gas turbine's output is, to a certain degree, inversely dependent on the inlet air temperature. This means that a low ambient temperature will increase output and efficiency of a gas turbine from 100% at +60°F to approximately 118% at -20°F. Inlet air icing problems might, however, require preheating of the inlet air and diminish this -- for Alaska -- advantageous performance characteristic. If waste heat is fully utilized the overall efficiency of a gas turbine can be very competitive with diesel engines. Advantages Cost of installation are usually less (between 10% and 30%) than for a diesel unit of equivalent size. The gas turbine generators usually serve as peaking units and are quickly brought on line. In this capacity they are very reliable. If waste heat is usable, the exhaust heat of a gas turbine is easily recoverable. Disadvantages The lower efficiency usually prohibits use as base-load units, especially since gas turbines are designed to operate at full load (a unit "idling" would still use approximately 30% of the fuel used at full load). Steam Turbine Generating Units In a steam plant a fuel fired boiler (usually coal, gas, or oil) generates steam which drives a turbo-generator. This method has proven to be one of the most efficient means of generating electric energy from fossil fuels. The more complex equipment, however, also increases the cost of installation, and transportation cost for the combustion material, especially if coal is involved, adds further to the cost of operation. If waste heat of the generating cycle can be used in industrial or heating processes, the efficiency can be as high as 4500 Btu/kWh, which is 3.5 times more efficient than a simple cycle gas turbine. Not many small plants (<10 MW) are being built due to the high cost of installation. The possibilty of a steam plant has therefore only been approximately evaluated for the Chignik Bay area where coal reserves exist. Page |V-222 Hydroelectric Generating Units Falling water turns a turbine to which a generator is coupled. Utilizing a renewable resource, hydroelectric generating units are about 88% efficient and the "fuel" is free if a negative impact on fish does not have to be accounted for. This makes hydroelectric power one of the most desirable generating facilities. Promising hydro sites, however, are usually not located close to load centers and therefore make construction of transmission lines necessary. Capital cost of a hydroelectric plant and its - power line connections to population centers are therefore the most significant factor in determining power cost. The following table will help to determine an approximate amount that may be invested in a hydro plant compared with diesel fuel replacement. A comparison with diesel fuel is made as most small Alaska utilities generate their electrical needs with diesel-electric units. Table 1V-12 shows the allowable hydro investment per kW for fuel cost and has been derived using the following assumptions: (i) A 20-year amortization period with quarterly payments at 5, 8, and 10% interest. (ii) Diesel fuel escalation at 7% per year during the 20-year period. (iii) Diesel engine-generator sets producing 13 kWh per gallon of fuel. (iv) Hydro installed capacity for 50% load factor. The 20-year amortization period was selected as the best probable financing period for a private utility and the range of interest rates chosen were those that may be expected from State loans or private financing. When considering other diesel costs such as lube oil, glycol, maintenance, and higher depreciation, the hydro may be installed under this criteria with little or no rate increase during the first few years, unless the size is substantially larger than the thermal plant it replaces. An escalation rate of 7% per year for diesel fuel is considered conservative. A fuel rate of 13 kWh per gallon of fuel is much better than most Alaska diesel plants achieve. This figure was used to be on the conservative side. Page |V-223 If any potential hydro site investment readily appears to fall below the break even point as determined from Table !V-5 for a present fuel rate and probable interest, the hydro should definitely be investigated if a better alternative does not exist. It should, however, be noted that costs for a possibly required transmission line are not included. Depending on the distance of a potential hydro site from an existing distribution system, this can increase the cost of investment substantially. TABLE !V-12 ALLOWABLE HYDRO INVESTMENT 20-Year 20-Year Ave. Annual Fuel Fuel Cost Maximum Hydro Investment Diesel Cost/Gal For 8760 kWh Per kW* - 20 Year Amortization Fuel (7% Assuming 5% 8% 10% Cost/Gal Escalation) 13 kWh/Gal Interest Interest Interest $0.40 $0.877 $591.17 $3,723 $2,937 $2,546 0.50 1.097 738.96 4,654 3,671 35,182 0.60 1.316 886.75 5,585 4,405 3,819 0.70 1.935 1,034.54 6,516 5,140 4,455 0.80 1.755 1,182.34 7,447 5,874 5,097 0.90 1.974 1,330.13 8,378 6,608 5,728 * Based on a 50% load factor Example: If a utility is paying $0.50 a gallon for diesel fuel in 1979 and can borrow money at 8% interest on a 20-year loan (quarterly payments), the annual saving of $738.96 would allow for an investment of $3,671 in 1979 per kW installed capacity for an installation with a 50% load factor. Hydro plants are very reliable and require little maintenance. Automation, remote control, and unattended operation are easily feasible. Page |V-224 Relatively long planning periods in which geology, water availability, etc. of a potential site are evaluated, as well as regulatory requirements are satisfied, precede the actual design and construction of a hydro- electric facility. It is not anticipated that any of the potential sites located in the Bristol Bay area can be developed in less than five years. The environmental impact of a hydroplant has to be carefully assessed: dams and reservoirs may disturb the balance of aquatic life and block the migration of fish. On the other hand a regulated flow in a stream can enhance the downstream fisheries. Bulb turbines (a type of axial turbine) -- widely used in Europe and Japan -- is a turbine suitable for low head application. Water level control structures are necessary in most cases. Several rivers in the Bristol Bay area appear to be suitable for this type of hydro installation. No negative impact on fisheries by the turbine unit is known at this time, but it is recommended that this item be investigated more thoroughly. Figure |V-3 illustrates a typical bulb turbine installation. wrwowowwoeow ww Page 1V-225 FIGURE IV-3 Typical Bulb Turbine Installation Utilization in a channel carrying some diverted flow of a major river appear to be feasible. Shutdowns could be planned during the peak fish migration season. 5) Wind Generating Units The extraction of energy from wind has been accomplished from . the earliest days of interest and applications in technoloy. Its greatest disadvantage is the certainty that it will not be available at all times. Other energy forms gradually displaced most windpower uses because of this fact. The history. of use of wind generating units is very limited is Alaska. But with the steadily increasing cost of fossil fuel and its major influence on the costs of fuel generated electricity, the interest in utilizing wind generators is increasing. Windmills are connected to an electric generator (either direct or via a gear arrangement). The energy generated is either AC or DC. Most wind generating systems built in the past employ an energy storage system (batteries) and an inverter to make the stored DC energy compatible with 60 cycle AC equipment. The equipment required for these conversions is costly and reduces the efficiency of the plant. Therefore recently small wind generators employing induction generators have become available. Induction generators can only be used as part of a system where voltage and frequency are maintained and reactive power is Page 1V-226 supplied by other generating means (synchronous generator). Conversion equipment can then be eliminated. Approximately 1/3 of a system's basic demand can be supplied by induction generators without causing instability or requiring additional reactive power supplies. If these conditions can be met, the use of induction generators can lower the cost of a wind generator installation considerably. The life expectancy is generally assumed to be fifteen years. Cost estimates for several arrangements are given ‘in Appendix C.4 and an economic evaluation for a "Rural Bristol Bay Community" in Appendix D.3 and D.4 of this section shows performance of a wind generator in a basically diesel supplied system. Table 1V-8 in the "“Energy-Resource" section shows estimated power output and cost for various locations and wind energy systems. Advantages The "fuel" is virtually free. With induction generators a minimum of control will lead to satisfactory performance. Operating costs are then limited to maintenance (oiling of bearings, brake adjust- ments, etc.) and replacements (brake shoes, etc.) Disadvantages The cost of investment is still relatively high. Reliability is questionable at best (of three installations in the Bristol Bay Area / Aleutian Islands, none is operating at this time). Power is not available at all times and requires that other generating capacity be installed. Similar to the "allowable investment for a hydro installation" the following Table 1V-13 shows the allowable investment for a wind generator (in 1979) that would produce power at the fuel cost of a diesel generator. Assumed are fifteen year amortization, 5% interest, 50% load factor, installed capacity equal to peak demand (up to 1/3 of system continuous load), fuel cost increase 7% per year. Additional distribution lines as well as maintenance costs are not included. Maintenance is estimated to be, up to 1979, $2,000 per year for one to three machines at remote locations where skilled personnel have to fly in from Anchorage or Seattle. wwewewvwvrwewewewewewewewww Page |V-227 TABLE 1IV-13 ALLOWABLE INVESTMENT FOR WIND ENERGY SYSTEMS 15-Year 15-Year Ave. Annual Diesel Avg. Fuel Fuel Cost Maximum Investment (1979) Fuel Cost/Gal For 8760 kWh Per kW* - 15 Year Amortization Cost/Gal Gy ‘Assuming 5% 8% 10% 1979 Escalation) 13 kWh/Gal Interest Interest Interest S424 S .72 § 483.16 S 2.538 $§ 2,099 $ 1,866 25) 9 603.95 3,173 2,624 2,333 -6 1.08 724.74 3,808 3,149 2,800 od 1.25 : 845.53 4,442 3,674 3,267 -8 1.43 966.32 5,077 4,199 3,f33 9 1.61 1,087.10 5,712 4,723 4,200 *Installed cost for small machines, 1.5 - 10kW are estimated to be approximately $9,500 - $26,000 in 1979. Other Generating Technologies Fuel Cells The fuel cell is a device for directly converting fuel into electrical energy, heat, and water. Like a normal storage battery, they function by virtue of electro-chemical reaction. The Energy Resource and Development Administration (ERDA) is actively engaged in building, testing, and reducing costs of fuel cells of such size to provide or supplement central station service. A 4.8 MW installation is presently being constructed. A typical fuel cell will convert 40% of fuel input into electrical energy and 60% to heat. With proper configuration beneficial use of 85-90 percent of the fuel input can be obtained. This makes the actual fuel cell one of the most efficient energy converting devices available. However, the fuel cell requires pure gaseous hydrogen for operation and the overall system efficiency must take into account the energy expended in converting any fuel into a form usable by the fuel cell. The present short-term goal is to produce a fuel reformer with a thermal efficiency of 87%. The installed cost for a fuel cell generating plant are estimated to be approximately 30% higher than a gas turbine plant of equivalent capacity when they become available (early 1980's). The efficiency of these "first generation" plants is not expected to be higher than approximately 38% (at full load) and operating Page |V-228 and maintenance could be as much as 5 times as high as for a gas turbine installation. The "second generation" plants (anticipated in the early 1990's) will be approximately 48% efficient. Solar Photo Voltaic Cells These cells convert light directly into electricity via semiconductors. Since no moving parts, nor high pressures or temperatures are involved, this would be the ideal way of generating electricity. The cells operate quietly and easily and can be located wherever power is needed. In addition to the cell array, however, storage equipment (batteries) and inverters will be required if a "stand alone" system is desired to supply the equipment and devices presently in use with electric energy. The cost of installation at this time is estimated to be more than $11/peak Watt (output of a cell that is exposed to the sun at the zenith on a clear day) which calculates to electrical energy cost of more than $1./kWh if an output of 1000 kWh per year per installed kW is assumed together with 10% interest and 20 year amortization. It is obvious that the cost of photo voltaic cells has to be reduced before they can economically compete with conventional generation of electric energy. Wholesale Power Supply from Anchorage The price of wholesale power in the Anchorage area at 19 to 20 mills per kWh in 1979 is an attractive price when compared to the price of wholesale power in Dillingham and Naknek. However, the distance from the nearest possible supply point of the Anchorage Area power system (Beluga) to Dillingham is about 280 miles (See key map). A transmission line traversing this route would probably go through Lake Clark Pass (elevation approx. 1100 ft.) and then follow Lake Clark, Iliamna to Dillingham and Naknek. If such a power delivery system were compared to local generation, the value of the energy delivered would normally be considered equivalent to the fuel cost of local energy unless a second line or other standby capacity were provided. To estimate what "prudent investment" might be made for such a power delivery system, the value of kWh delivered to Dillingham/Naknek will be set as the estimated average fuel cost/kWh in 1985 and the remaining calculations be made in the following manner: Estimated Energy to be delivered to Dillingham/Naknek 28,000 MWH Cost of Fuel displaced @$0.086/kWh (See Figure IV-2) $2,408 ,000/year Cost of Energy purchased ($0.03/kWh @ Beluga) 29,400 MWH $ 882,000/year Estimated annual 0 & M costs for transmission system $§ 196,000/year Remainder for Investment Costs $1,330,000/year Page |V-229 If a municipal corporation were to sponsor the project, the estimated fixed charges related to this investment might be: Cost of Money 0.080 (8%) Depreciation (sinking fund, 35 yrs) 0.0058 Interim Replacements 0.002 Insurance 0.001 0.0888 say 9% Maximum Prudent Investment in 1985 becomes: sees = about $14,777,800. This figure represents about $ 52,800/mile (in 1985) or, (considering 7% discount of cost to today's equivalent cost (1979) $ 35,183/mile Estimated cost of 138 kV line $ 125 ,000/mile A conventional transmission system from Anchorage does not offer an attractive alternative wholesale power source for this situation. We Analysis of Power Supply Alternatives Electric power in the Bristol Bay area is presently almost entirely diesel generated (Chignik operates a 60 kW hydro plant). As shown in part 1 (Diesel Generation) of this section a vast difference in cost per kWh exists between communities with private generators or small central plants (<500 kW installed capacity) and larger communities with more efficient larger (>1000 kW installed capacity) plants. The following Table 1V-14 provides a brief synopsis of cost for eiectricity for various supply methods and locations: Page 1V-230 TABLE !1V-14 ELECTRICAL ENERGY COST FOR VARIOUS GENERATING SYSTEMS 1980 $ Fixed Cost Variable Cost Total ¢/kWh at Supply Method ¢/kWh ¢/kWh Power Plant Bus Diesel >1000 kW! 1.4 - 1.7 6- 7.2 7.4 - 8.9 Diesel <500 kw! 6-9 12.4 - 23.5 18.4 - 32.5 Priv. Generator! 2-4 kW 14 - 38 37 - 12 51% - 503 Small Windplant? 1.5 kW 20 - 44 10 - 15 324 - 974 1 From Section IV-C,1 2 From Section IV-B.6 Cost at Service Location Consists of the non-firm secondary energy cost, to which must be added the cost of firming. If the wind plant is added to a > 1000 kW diesel system, the fixed cost of that system should be added, for example: Wind Plant Total 30 8 ¢/kWh Large Diesel Fixed 1.7 ¢/kWh Wind firm power cost 31.7 ¢/kWh or, if the wind plant is added to a private (very small) diesel system, the firm power cost should be Wind Plant Total 59 ¢/kWh Private Diesel fixed 38 ¢/kWh Wind firm power cost 97 ¢/kWh 100 101 102 103 104 105 106 107 108 109 Page 1V-231 BIBLIOGRAPHY “Low Head Power Generation with Bulb Turbines", by J.L. Carson and R.S. Samuelson, International Engineering Company, ine. "Development of Small Hydroelectric Plants", by A.E. Allen, Harza Engineering Company, September 1977. "System Planning Study" for Iliamna Newhalen Electric Cooperative, Inc., by R. W. Retherford Associates, September 1978. "Power Cost Study 1979-1993" for Copper Valley Electric Association, Inc., by R. W. Retherford Associates, March 1979. "Power Cost Study" for Nushagak Electric Cooperative, Inc., Dillingham, by R. W. Retherford Associates, February 1979. "Ten Year Power Cost Study 1977-1986" for Naknek Electric Association, Inc., by R. W. Retherford Associates, November 1977. "Fifteen Year Power Cost Study" for Kodiak Electric Association, Inc., By R.W. Retherford Associates, August 1978. "Waste Heat Capture Study" for the State of Alaska, Division of Energy and Power Development, by R.W. Retherford Associates, June 1978. "Electric Power in Alaska 1976-1995" by the University of Alaska, Institute of Social and Economic Research, August 1976. "A Regional Electric Power System for the Lower Kuskokwim Vicinity" for the U.S. Department of the Interior, Alaska Power Administration, by R.W. Retherford Associates, July 1975. 110 111 112 113 114 115 116 Page IV-232 "The Solar Component" by Richard Seifert and Lee Leonard in The Northern Engineer, Vol. 9, No. 4, Winter 1977. “Energy Primer" edited by Richard Merrill and Thomas Gage, published by Dell Publishing Co., Inc., Copyright 1978. "Fuel Cells for Public Utility and Industrial Power", edited by Robert Noyes, Noyes Data Corporation, Park Ridge, New Jersey, 07656 published 1977. "A Giant Step Planned in Fuel-Cell Plant Test", Edward P. Barry of Northeast Utilities Service Company, Roosevelt L.A. Fernandes of Niagara Mohawk Power Corporation, and William A. Messner of Consolidated Edison Company of New York, pubis in November 1978 issue of the IEEE Spectrum. "Fuel Cell Power Plants", Arnold P. Fickett of Electric Power Research Institute (EPRI) published in December 1978 issue of Scientific American. "Application of Solar Technology to Today's Energy Need" Volume |, by Congress of the United States, Office of Technology Assessment, June 1978. "Solar Energy Resource Potential in Alaska" by J. P. Zarling and R.D. Scifert, University of Alaska, Institute of Water Resources, IWR-89, 1978. Page |V-233 D. ELECTRIC ENERGY RESOURCES This section investigates the economic feasibility of potential electric power resources listed among the energy resources. It will concentrate on development of hydroelectric and coal resources at well as possible transmission interties. Other available electric energy resources are addressed and assessed approximately in relation to diesel fuel generated electricity. The following table gives a brief overview of the potentially feasible electric energy resources developments for the Bristol Bay communities. More detailed evaluations will be found in subsequent parts of this section. TABLE 1V-15 - BRISTOL BAY COMMUNITIES POTENTIAL ELECTRIC ENERGY RESOURCES POTENTIAL ECONOMIC ENERGY RESOURCE LOCATION HYDRO GEOTHERMAL COAL WIND Clark's Point Yes* No No - Yes Chignik Yes ia Yes #e Chignik Lagoon Yes* aX Yes aa Chignik Lake Yes* *% Yes* nm Dillingham Yes No No Yes Egegik Yes* No No Yes Ekuk Yes* No No ** Ekwok Yes* No No ** Igiugig Yes* No No aN Ivanoff Bay No ae = om lliamna Yes* No No Yes Kokhanok No No No — Koliganek Yes* No No et Levelock Yes* No No ** Manokotak Yes* No No oe Naknek/King Salmon Yes* No No Yes Newhalen Yes* No No ee New Stuyahok Yes* No No +e Nondalton Yes* No No or Pedro Bay No No No bd Perryville No oe ek =. Pilot Point/Ugashik No No No Yes Port Alsworth No No No Yes Portage Creek Yes* No No a Port Heiden No = No Yes Port Moller Marginal ne No Yes Togiak No No No Yes Twin Hills No No No * ns With transmission-intertie. -™ Insufficient data available to assess. Page |V-234 A "mid-term" synopsis of energy requirements and the estimated cost of various resources has been summarized for 1990 in the following table. Energy cost are determined by using a multitude of parameters listed on the table and are only magnitude-type approximation. Construction of facilities in different years then assumed for example can change the per unit. cost considerably. Data listed in this table should not be used without consulting the more detailed evaluations in this section or Appendix D). Page IV-235 BRIS4/K1 TABLE IV - 16 1990 POWER REQUIREMENTS AND ENERGY COST ESTIMATES FOR VARIOUS RESOURCES 1990 MWH 1990 Energy - Cost! Annual _-_1000-$ ; ¢/ kWh Requirements Diesel with High Transmission wind* Location Low Diesel® Intertie Hydro? Coal? (non-firm) Dillingham 19080 1472 n.d.? 1432_- 2175 N/A n.d.7 # 11070 73.3 11.4 - 18.8 T10-79) Naknek-King Salmon 30002 2496 n.d? 2459 - 3529 N/A n.d.? ® 18770 13.3 11.4 - 18.8 (10-79) WWiamna Newhalen 2887 493, N/A 389 N/A 1761 28 13.5 - 22.1 Nondaiton Nushagak Bay Clark's Point 1874 74 67 74 = 225 N/A n.d. 191 8.5 358 74.3 - 38.6 Ekuk 269 78 71 38 - 78 N/A n.d. 203 38.5 358 14.3 - 38.6 Manokotak 1018 104 95 105 - 146 N/A n.d. 27 38.5 358 74.3 - 38.6 Portage Creek 275 60 55 39 - 60 N/A n.d. 156 38.5 358 74.3 - 38.6 Peninsula-Bristol Bay Egegik 3591 584 531 513 - 586 N/A n.d.7 § 1S1 38.5 358 74.3 - 38.6 Ti0-75) Pilot Point - Ugashik 1492 731 N/A N/A N/A a.d.t# 651 es T12-85 Port Heiden 400 125 N/A n.d.7 N/A n.d.7 ® 256 49 12-55) Port Moller 2478 367 N/A 773 n.d.? n.d.7® “743 “ag 3.2 - 103.2 12-55) Peninsula-Pacific Side Chignik 2495 457_- 799 473 1631 28 - 49 29° Chignik Lagoon 178 $3. - 94 38 565 - $99 238 n.d? 191 28 - 49 29° 72.8 - 27.7 21.4 Chignik Lake 403 62 - 108 64 220 28 - 49 29° Page IV-236 BRIS4/K3 TABLE IV - 16 1990 POWER REQUIREMENTS AND ENERGY COST ESTIMATES FOR VARIOUS RESOURCES (CONTINUED) 1990 MwH 1990 Energy - Cost! Annual - 1000-$ ¢/kWh Requirements Diesel™ with ; High Transmission Location Low Diesel® Intertie Hydro? Coal? wind* Ivanoff Bay 1715 147 _- 257 N/A N/A n.d.? n.d.7 524 | Perryville 1902 162 - 284 N/A N/A n.d.7 n.d.7 “S80 = 4 Togiak Togiak 3857 344 - 601 n.d.? N/A N/A n.d.? Tea? 28 - 49 Twin Hills 331 49 - 89 nd. N/A N/A. n.d.7 176 = Niamna Lake Igiugig 292 64 58 42 - 64 N/A n.d.7 766 38.5 35¢ 74.3 - 38. Khokanok 320 86 N/A 700 N/A fia? 176 49 219 Pedro Bay 457 103 N/A n.d.” N/A n.d.7 210 49 Port Alsworth 236 n N/A n.d.7 N/A n.d.? 144 43 Iniand Ekwok 457 84 76 65 - 84 N/A na:” 218 38.5 35¢ 74.3 - 38.6 Koliganek $23 79 72 75 _- 80 N/A n.d.? 206 38.5 358 14.3 - 38.6 Levelock 629 88 80 88 - 90 N/A (i 228 38.5 35° 14.3 - 38.6 New Stuyahok 653 108 98 93 - 108 N/A nsds* 280 38.5 35¢ 14.3 - 38.6 Notes: we euse This table shows the results of cost evaluations utilizing the parameters shown below. The data should not be used in any decision making process without consulting the detailed report. At local distribution bus - not at end users meter. Operational in 1985, 5% interest on 35 ye scenarios - lowest unit cost for "high" load growth only. Operational in 1985, 5% interest on 35 year loan, 2% O&M, - "high" load growth only. Operational in 1980, 9% interest on 15 year loan, 15 - 100 kW system in cogeneration only. For "low" power requirements only; fuel cost escalation at 7% per year. Single wire Ground Return Transmission, 40 kV - 9% interest on 35 year loan, .5% O&M - operational in 1980. Not determined. Supply of up to 30% of system energy requirements. 24.9/14.4 kV Transmission - 5% interest on 35 year loan, los: s loan, 1% OSM, 0.2% insurance - range applies to various neglected, operational in 1980. Page |V-237 The following parts of this section will give a more detailed evaluation and description of the electric energy resources investigated within specific areas. Combined load requirements are listed where applicable to illustrate the magnitude of demand and potential supply. "High" or "low" projected power requirements have been used to evaluate various resources to show possible "worst" cases as necessary: a large hydro or coal mining developments - for example - will be economically more feasible with "high" energy use where fixed annual cost can be divided by more kWhs than with "low" use. Small hydro developments on the other hand can only take the place of fuel replace- ment for a short time if "high" energy requirements are applied. It has been attempted to weigh these possible developments and show the consequences in form of cost per kWh for five year intervals to the year 2000. Diesel generated electricity has been used as a yardstick against which to measure potential benefits of other resources. ie Dillingham _- Naknek - King Salmon Approximate locations and distances as well as possible transmission lines for interties are shown on Figure IV-4. a. Energy Resources The development of hydro, solar, and wind potential can be alternatives to the present almost exclusive use of fuel oil for heating, processing, and electricity generation as shown in the energy resource section of this study. While utilization of wind and solar energy do not appear to be economically feasible at this. time, development of hydroelectric resources is investigated further in subsequent sections. Presently available data on geothermal, oil and gas occurrences in this area do not allow an adequate assessment of these resources to determine development feasibility during the next 10 to 20 years. b. Electric Power Demand and Resources The projected future electric power demand for the three communities as established in Section II! of this study is as follows: Page !V-238 Power Requirements 1980 1985 1990 1995 2000 Dillingham Annual MWh (High) 6574 12827 19080 32298 45516 Peak Demand MW (High) 1.50 2:13 3.96 6.31 8.66 Annual MWh (Low) 5930 8500 11070 13521 15972 Peak Demand MW (Low) 1.50 2.00 2.58 3.10 3.65 Naknek/King Salmon Annual MWh (High) 14086 22044 30002 40591 51180 Peak Demand MW (High) 2.87 4.495 6.12 7.93 9.74 Annual MWh (Low) 12526 15648 18770 20923 23076 Peak Demand MW (Low) 205 3.18 3:83 4.265 4.7 Total Annual MWh (High) 20660 34871 49082 72889 96696 Peak Demand* MW (High) 4.37 Ta225 10.08 14.24 18.4 Annual MWh (Low) 18456 24248 29840 34444 39048 Peak Demand* MW (Low) 4.05 5.19.- - 6.41 7.365 8.35 * Noncoincident Electric Power Resources (i) Continuous Use of Diesel Generation As shown in the "Generating Technology and Cost Review" section, it can be anticipated that the cost for diesel generation for the three communities will develop approximately as follows (if a moderate increase in fuel cost of 7% per year is assumed): 1980 1985 1990 1995 2000 ¢/kWh at distribution bus 8.3 10.5 13.3 Ti 22.1 Page |V-239 (ii). Transmission Intertie Dillingham - Naknek Two possibilities are considered: 7 Transmission via 138 kV, three phase, with 10 MVA substations on either end. 2. Transmission via "Single Wire Ground Return Line" at 40 kV with conversion equipment on either end. With the distance of 92 miles the following costs are estimated: a. 138 kV, 3@ with substations’ 1979-$ 12,400,000 Annual cost with 35 year loan at 5% interest and 130 & M a 877,000 2. Single Wire Ground Return 40 kV, 266.8 ACSR with terminals (1 MW load limit) 1979-$ 2,900,000 Annual cost with 35 year loan at 5% interest and 130 & M 206,000 The intertie would allow the two systems to share peaking capacity and spinning reserve. If the value of peaking capacity is assumed at $100/kW per year and the cost for transmission losses are neglected, the annual benefits are estimated to be: at 1 MW $ 100,000 at 2 MW $ 200,000 at 4 MW $ 400,000 The above estimates show that with the stated parameters a transmission intertie does not appear to be economically feasible at this time, if both systems rely on diesel generation exclusively. Page |1V-240 (iii) Hydroelectric Resources The following potential hydroelectric sites have been considered for further evaluation in this area: Prime Installed Plant Transmission Capacity Capacity Cost Cost Site (Mw) (MW) 1000-$ 1000-$ Lake Elva .96 1.4 7803 2340 Grant Lake 1.385 a5 7391 4539 Lake Tazimina First Stage 15 2x16 34445 23975 Final 30 4x15 #22000 wwe Possible bulb turbine applications in the Agulowak, Kvichak and Naknek River are not considered here, because an evaluation of capacity and cost cannot be performed with the limited available site-data. The impact of bulb turbines on fisheries is also not well enough known to allow a prudent judgment. Other potential hydro sites, which are not addressed in greater detail are either located within state parks, national monuments, or the impact ‘on the fisheries has been judged too severe to allow development, are: Lake Kukaklek 14 MW prime, 1st stage Lake Naknek 34 MW prime Alagnak River 5.2 MW prime American Creek 11.36 MW prime Chikuminuk Lake 6 MW prime Idavain Lake 2 MW prime Kontrashibuna Lake 13.75 MW prime Lake Brooks -4 MW prime Lake Grosvenor 5.6 MW prime Nuyakuk - Tikchik Lakes 42 MW prime South Fork Savanoski River 1.45 MW prime Upnuk Lake 7.53 MW prime With development cost for Tazimina, Elva and Grant as shown in Appendix D, the energy cost for various annual usages are shown on the following Figure |1V-5 "Hydro Developments". Installation for all sites has been assumed in 1985. Comparable cost without considering fisheries impact or land status for the Kukaklek development have been added to show its potential. ww - Page 1V-241 \ K S ew i" oO 10: ox) 0 o & 4 ° 9 0 eo A > st Qo S¢6 <S o 0 O_Nhobhallbsees - Oy 20% a ° . is a I/o a (Re Ne = ; oboe yrede i Dp Qo. 3 300 _ vig VTi = if c ikghik Loxe ° 0 Sy C 3 J 108 . Fil ‘ ot loke a ol ty rm 5 CHINI yataay wits %. io Ip Cae Pos Kokid S SR: CF aM je : Se hic Pern 5 a SI) (1 es : 2 5 to ‘fo Ky fo% SP Ay ebet7 ZF 6 baron be rsyrrccs 5 \ A “ 25 © : 3 > 7, B, Hee rt 1 axe KC y CI o * ‘Oil Point > 22, s e ° ak > Zi 9 . ’ wh hag, REINORER Ve o ot STATION 0 AW? b wo” at ot roo e BSS Tignogvi Point Burr Point ° oS LEGEND ; OE ai 2 ofa ¢ Ae a ae ee & HYDROELECTRIC GENERATING PLANT WITH = = St z INSTALLED CAPACITY. = be) s fe 5 3 5 % o T ——————= _-—»« TRANSMISSION LINE, I38KV 39 ' 6 Se, Z kof UW | —_____ EXISTING DISTRIBUTION LINES ( UP TO 24kKV) *e Sy. \ 19 OR 39 e Dd < ———— SINGLE WIRE GROUND RETURN ; neg ° Se 2 TRANSMISSION, 40KV °K, —-—-— DISTRIBUTION LINE (UP TO 24KV) Hargtfe} fonvi., zZ js ork bg S seeeeeeesseeees SINGLE WIRE GROUND RETURN TRANSMISSION, a % °° Ls, h REDUCED FREQUENCY x =< oe ge a wy S) és > wor g 4 Ss) GAKY 3s / S Cape Dougles as = S eo e o Hammers! light Hand Point 7. : eae x . \ 7, 3 ‘ 30 2 S Oy i SS ° : * a RY ) tekctial ron BAY OF iStANDS— @ SCX! PeBZHP > Kiukpalik Islond S66 Pek g coax 0 3 RIN SELES 2 fs 3D 2 SA sSegscsls @Shokun Islands ACS Scat Bos Protection Point Ao 782 Fe00K8 10K a ‘, 2 Brooks 0 F <9) Boer. OLX Ts “g fj a Bloc 3 . 2 SREY ¥ DILLINGHAM / NAKNEK . Cope Constantine ea Cr< ERS SQ PLUS 10 VILLAGES INTERTIE e \ - i, SCALE: I: 1000 000 at SKY é SH CG; : FIGURE Iv -4 vet ° (An Yor c = 14 e ° > 0 .. a 4 Va “Wy, : > <. 'o} 1 @ hom } x ly, $5 ey? ) WW Se Cope Kulik q 5 \ Tok Soe <A Ss Se oo Mays os 3 Fe pe Atushagvik S Raspberry-Cape, veeg ? > \ 3 7m y Dc ¥ e y g : X a ‘Cape Fok ONTON 8A . ) y 3 - a Cabin \0<750, ¥: = ae = I oy Cy 2 £ ‘ , Page |V-243 The indicated "area use" includes the projected use for 13 villages in the Nushagak/Kvichak/Tazimina area. ~ The following describes the assumed generation and transmission installations for the three evaluated sites. Approximate transmission line routings are shown on Figure 1V-4 "Dillingham - Naknek Plus 10 Villages Intertie". 7 wale fee | sbe] ‘| (TO DiLuinenae = Teste tty ok od M oper uw sTase jisuw s +t44 me + | | seeaet ae \ mil ci \ \ Terme ¢ Gums TT @vasenawn | | + 1 (1D Ounimenaat bet \ HDA 1 v \ $/KwH x \ a . ¥ Ht \ +14 , CosTloF ore! “oe \ my — bem) | cad eal ere OLLINGHAM Cas \ jpiseo hives) \ a ~ pRosecT ~ rea Use Hen) | ro) T9980 2000 r sa eTte sO were MWwH aa 5 YR BRISTOL BAY HYORO ~ DEVELOPMENTS. — DILLINGHAM/ NAKNEK — 1985 - BASE ) FiGURE Iy-5 JUNE 1979 e— Page !1V-245 Lake Elva To reduce cost and permit requirements, this site is assumed to be developed as a "minor project with up to 1500 kW installed Capacity. The connection to the existing Nushagak Electric System will be made in Alegnagik (the existing 7.2 kV, 1@ line would have to be upgraded to 24.9 kV, 3%). The transmission is assumed to consist of approximately 9 miles overhead line following Pick and Lillie Creek, and approximately 20 miles submarine cable in Lake Aleknagik or 9 miles of submarine cable in Lake Nerka, 2 miles overhead line to cross the valley west of Bumyok Ridge and 18 miles submarine cable in Lake Aleknagik. Although located in the Wood River Lakes State Park, hydro development has been listed as a compatible project in the park statutes. Grant Lake The. development as a "minor" project here too will save cost and have the least possible influence on fisheries since no diversion is being: planned. Since approximately 65 miles of transmission line are required the cost evaluation has been done utilizing single phase, low frequency generation. (1500 kW) and Single Wire Ground Return transmission at 66 kV with phase and frequency conversion at the connecting substation into the Dillingham System. Compared to three-phase 69 kV transmission, the total cost for the development as described before is estimated to be approximately 8-10% lower. Higher savings are conceivable when the single phase/low frequency scheme can be utilized on an "off. the shelf" basis. For this study conservative cost estimates have been used. The project is located in the Wood River Lakes State Park but hydro development has been listed as a compatible project in the park statutes. Lake Tazimina The first stage of this site would be the installation of 2 x 15 MW generating capacity, 181 miles of 138 kV transmission line with substations at Dillingham and Naknek/King Salmon. A 24.9 kV distribution line will supply the communities of Iliamna, Newhalen and Nondalton direct. Ten villages are connected into the Dillingham/ Naknek system via Single Wire Ground Return transmission (see also Part 2 of this section "10 Villages in the Nushagak/Kvichak Bay Area"). Page 1V-246 The project is located in a wilderness study area (Iliamna National Resource Range Alaska) and development has been addressed in the Environmental Impact Statement prepared by the U.S. Department of Interior in 1974, but has not clearly been judged compatible or incompatible. Analysis of Electric Power Resource Alternatives Closer examination (see figures 1V-6 and IV-7) of the Elva, Grant and Tazimina hydro potential shows that only Tazimina can supply the demand of both systems to the year 2000. Elva and Grant's potential energy is almost completely committed in a combined system if it is assumed that the earliest operational date is 1985. Supplemental diesel generation in times of peak demand is necessary almost immediately even if both plants are in operation in 1985. a Page |V-247 The total load compares as follows to the available hydro capacity: 1985 1990 1995 2000 Dillingham + Naknek Annual MWh (High) 34871 49082 72889 96696 Peak Demand* MW (High) 7.225 10.080 14.240 18.400 Annual MWh (Low) 24148 29840 34444 39048 Peak Demand* MW (Low) 5.190 6.410 7.365 8.350 10 _ Villages Annual MWh (High) 6094 9281 13121 16962 Peak Demand* MW (High) 2.35) 3.37: 4.36 5.34 Annual MWh (Low) 2736 3436 4494 5552 Peak Demand* MW (Low) 1.36 1.44 1.67 1.9 Hiamna/Newhalen/Nondalton Annual MWh (High) 2215 2887 5578 8270 Peak Demand* MW (High) -506 .66 1.19 1m Annual MWh (Low) 1571 1761 1955 2149 Peak Demand* MW (Low) aod 4 445 .49 Total Load Annual MWh (High) 43180 61250 91588 121928 Peak Demand* MW (High) 10.08 14.11 19.79 25.46 Annual MWh (Low) 28455 35037 40893 46749 Peak Demand* MW (Low) 6.91 8.31 9.48 10.74 Hydro Capacity Lake Elva Annual MWh 8409 8409 8409 8409 Peak MW 1.5 1.5 1.8 139 Grant Lake Annual MWh 12130 12130 12130 12130 Peak MW 1.5 1.5 1.5 135 Lake Tazimina (1st Stage) Annual MWh 131400 131400 131400 131400 Peak MW 30 30 30 30 Total Capacity Annual MWh 151939 151939 151939 151939 Peak MW 33 33 33 33 *Noncoincident Page 1V-248 Preliminary feasibility for Elva and Grant has been investigated with low load growth projections for the Dillingham system alone. The power cost at the distribution bus are then estimated as follows (see Appendix C and D-5,7 for details): DILLINGHAM/LAKE ELVA/GRANT LAKE - LOW LOAD GROWTH (Power Cost at Distribution Bus) Peak kW required “ Hydro Capacity, Elva - kW Hydro Capacity, Grant - kW Annual MWh, required Hydro Capacity, Elva - MWH Hydro Capacity, Grant - MWH Cost for Diesel only ¢/kWh 1000$/Year 15 Year Average ¢/kWh Cost for Hydro, Elva ¢/kWh 1000$/Year 15 Year Average ¢/kWh Cost for Hydro, Grant ¢/kWh 1000$/Year 15 Year Average ¢/kWh Cost for Elva & Diesel ¢/kWh 1000$/Year 15 Year Average ¢/kWh Cost for Grant & Diesel ¢/kWh 1000$/Year 15 Year Average ¢/kWh 1985 2000 960 1380 8500 8409 12130 10.5 893 1258: 1078 1126 1405 12.8 1088 16.6 1405 1990 2580 960 1380 11070 8409 12130 1353) 1472 12.8 1078 11.6 1405 eno 1432 12.8 1405 15.6 12.8 11.6 14.1 13.4 1995 3100 * 960 1380 13521 8409 12130 Vet 2312 12.8 1078 11.6 1405 14.4 1952 1222. 1643 2000 3650 960 1380 15972 8409 12130 22.1 3530 12.8; 1078 11.6 1405 17.2 2749 14.1 2254 Page |V-249 An analysis for high load growth would emphasize the increase in power cost when more and more diesel generation has to be added. Over the 15 year time frame it appears to be most economical to develop both sites to offset fuel cost. It should be noted though that the Grant Lake development with a conventional transmission line would increase the power cost and favor a later construction date for this facility. Dillingham-Naknek/Elva/Grant/Tazimina Comparative power cost in the Naknek and Dillingham system for development of Tazimina; Elva and Grant; and Tazimina, Elva and Grant are shown on the following tables and graphs. The cost allocations assume a single wire transmission intertie between Dillingham and Naknek for Elva and Grant installation only. For the Tazimina evaluation supply to 10 intertied villages in addition to Dillingham/Naknek has been assumed. The parameters used to calculate the power cost are listed in Appendix D-5 and D-7. The cost curves applying to Tazimina include transmission to Dillingham and Naknek, but no subtransmission to interconnect the 10 villages. It has been assumed that the village interties will be in existence when the Tazimina hydro project is operational. Depending on load growth the power cost analysis shows the following breakeven points for the hydro projects if compared to continuous use of diesel: ‘ High i Low Load Growth Load Growth Elva + Grant 1988 1988 Tazimina 1988 1994 Tazimina + Elva + Grant 1992 1999 Page |1V-250 DILLINGHAM/NAKNEK - LOW LOAD GROWTH (Power Cost at Distribution Bus) 1985 1990 1995 2000 Peak kW (noncoincident) 5230 6410 7380 8350 Annual MWh 24148 29840 34444 39048 Elva + Grant kW (installed) - 3000 3000 3000 3000 Elva + Grant annual MWh 20539 20539 20539 20539 Tazimina kW (installed) 30000 30000 30000 30000 Tazimina Annual MWh 131400 131400 131400 131400 Annual Cost (1000$) Tazimina 5616 5616 5616 5616 ¢/kWh 23.43 18.8 16.3 14.4 15 Year Average ¢/kWh 18 Elva 1078 1078 1078 1078 + Grant 1405 1405 1405 1405 + Intertie 177 177 177 177 + Diesel 379 1237 2378 4090 Total 3039 3897 5038 6750 ¢/kWh 12.6 131 14.6 iss 15 Year Average ¢/kWh 14.2 Three Hydros 8099 8099 8099 8099 ¢/kWh 33:5 27 23/45 20.7 15 Year Average ¢/kWh 73.9 Diesel Only 2535 3969 5890 8630 ¢/kWh 10.5 13:3. Wea oat 15 Year Average ¢/kWh 15.6 Page IV-251 90 90: —. + ot ; 1 60+ —<—$—_— T 50+— T 40 —+— 1 DIESEL W. FUEL AT 10% / YEAR 30. $$ — —__—_-_—--- 3 HYDROS 20- ELVA + GRANT TO DILLINGH. onLY ———_____| RY TAZIMINA ONLY} : _ W. VILLAGES a4 Poa ¢ /xw ne RE 10 — 9+ DIESEL ONLY W. INTERTIE 8 7 | TT 1 6} 5+ rit 3+ 2 BRISTOL BAY DILLINGHAM / NAKNEK cosT POWER — (AT DISTRIBUTION BUS) LOAD} PROJECTIONS FIGURE IZ-6 JUNE 1979 __| 1980 1985 1990 1995 2000 YEAR DILLINGHAM/NAKNEK - HIGH LOAD GROWTH (Power Cost at Distribution Bus) Page !V-252 1985 1990 1995 2000 Peak kW (noncoincident) 7225 10080 14240 18400 Annual MWh 34871 49082 72889 96696 Elva + Grant kW (installed) 3000 3000 3000 3000 Elva + Grant Annual MWh 20539 20539 20539 20539 Tazimina kW (installed) 30000 30000 30000 30000 Tazimina Annual MWh 131400 131400 131400 131400 Annual Cost (1000$) Tazimina 5616 5616 5616 5616 ¢/kWh 16.1 11.4 Tal 5.8 15 Year Average ¢/kWh 9.9 Elva 1078 1078 1078 1078 + Grant 1405 1405 1405 1405 + Intertie 177 177 177 177 + Diesel 1505 3796 8952 16831 Total 4165 6456 11612 19491 ¢/kWh 11.9 13.2 15.9 20.2 15 Year Average ¢/kW 15 Three hydros 8099 8099 8099 8099 ¢/kWh 23.2 16.5 111 8.4 15 Year Average ¢/kWh 14.3 Diesel Only 3162 6528 12464 21370 ¢/kWh 10.5 13.3 17.1 22) 15 Year Average ¢/kWh 15.6 100: 8 T Page IV-253 DIESEL \. FUEL AT 10%|/ YEAR 3 HYDROS ELVA + GRANT + DIESEL W.O.| VILLAGES DIESEL| ONLY ae W. INTERTIE 8 SJ 7 TAZIMINA ONLY W. VILLAGES 6 S at _ ———————— pe BRISTOL BAY 1960 1990 YEAR DILLINGHAM / NAKNEK COST QF POWER (AT DISTRIBUTION BUS) [HIGH] - Loko PRovEcTIONS FIGURE IZ+7 JUNE 1979 2000 Page |V-254 To show sensitivity of future power cost to fuel oil prices, diesel generation costs have been calculated at 10% increase per year and are shown as a separate line. It is then apparent that the Tazimina Project is very attractive - even at low load growth. If electric heat as calculated in part B.6 of this section (Table IV-10) is added to the low load growth projections the breakeven curves as shown for the "high" load can be applied. The busbar cost for electric energy can then be calculated as follows: TAZIMINA POWER COST WITH ELECTRIC HEAT At_Dillingham/Naknek Distribution Bus Dillingham/Naknek - Iliamna + 10 Villages - Low Load Growth 1985 1990 1995 2000 (1) Annual MWh w/o heat 28455 35037 40893 46749 (2) Annual MWh heat 35101 41518 46704 51919 (3) Annual MWh with heat (1) + (2) 63556 76555 87507 98668 (4) Annual Cost Tazimina 6840 6840 6840 6840 1000-$/¢/kWh (w/o heat) 24.0 19.5 16.7 14.6 (5) Allowable Cost for heat* ¢/kWh 3.8 5.4 15 10.6 (6) Annual Allowable Cost for Heat (2) x (5) 1000-$ 1,334 2,242 3,503 5,503 (7) Annual Cost for Remaining Energy (4) - (6) 1000$ 5,506 4,598 3,337 1,337 (8) ¢/kWh for Remaining Energy (7) + (1) 19.3 13.1 8.2 2.9 (9) ¢/kWh Diesel Only 10.5 1353 diva 22.1 *See Table IV-10. Note: Distribution losses and other cost not accounted for. It has to be considered that with further increasing load more hydro generation has to be installed, increasing the power cost again. The investigation shows that electric heat - if only the replaced fuel is accounted for - can lower the power cost for the entire system if the installed hydro capacity is large compared to other system demands in the early years. 2. b. Page !V-255 Ten Villages in the Nushagak/Kvichak Bay Area Energy Resources and Electric Power Resources The resources for these villages are as described under the Dillingham/Naknek portion of this study. The application of solar and wind energy can be more advantageous in these villages due to higher fuel cost. The larger hydro developments obviously cannot be developed by any one of these communities, but could supply several or all villages if the individual systems were intertied by transmission or distribution lines. To investigate the feasibility of such an intertie the energy requirements for the communities have been compiled from Section II] “Future Power Requirements". The interties with the existing Dillingham/Naknek systems have been assumed to be single phase lines utilizing the single wire ground return scheme (see Appendix B-1). This type of transmission system will allow relatively low cost installation com- pared to three phase transmission. Most of the connected loads are single phase loads and phase conversion equipment can readily produce three phase power where needed. Two demonstration projects - utilizing single wire ground return lines - are expected to be built in the Bethel and Kobuk area in the near future. It is anticipated that this scheme can eventually replace small, inefficient diesel plants and make less costly power available to remote communities. To assure adequate voltage levels in the communities under consideration, the interties have been chosen at 40 kV with conductors 7#8 Alumoweld or 226.8 ACSR respectively. The approximate routing has been shown on Figure 1|V-4. Analysis of Electric Power Resources Alternatives In the preliminary evaluation of the feasibility of a transmission intertie the fact has been ignored that power supply systems exist at this time in several communities and electric energy can be purchased for between 20¢ and 37¢ per kWh. Power costs at the distribution bus have been uniformly assumed at an intermediate value from Figure |V-2 "Cost of Diesel Generation". The feasibility calculations in Appendix D-6 "Transmission Interties in the Dillingham/Naknek Area" utilize the low load growth projections and relatively high value for wholesale power to show the least favorable case for a capital investment. Breakeven under these assumptions is not achieved until 1986 if the ties TEN VILLAGES LOAD PROJECTIONS Page |V-256 1980 1985 1990 1995 2000 Clark's Point Mwh/Year High 184 879 1874 1894 2215 Peak MW High 052 -326 6 +725 -85 Mwh/Year Low 160 175 191 537 883 Peak MW Low 046 -051 055 153 +25 Egegik Mwh/VYear High 1040 2316 3591 3642 3692 Peak Mw High 6 -98 1.36 1.38 1.4 Mwn/Year Low 413 966 1817 1600 1683 Peak MW Low 6 645 -69 73 ave Ekuk Mwn/Year High 198 233 269 948 1628 Peak MW High +226 267 -308 +619 +930 Mwh/Year Low 188 195 203 290 378 Peak MW Low 214 224 +233 +26 287 Ekwok MWh/Year High 203 330 457 982 1507 Peak MW High -058 +094 13 238 +345 MWh/Year Low 178 198 218 2s7 297 Peak MW Low 051 057 062 065 068 Igiugiq MwWh/Year High 188 225 292 410 $28 Peak MW High 045 -065 085 +103 12 MWh/Year Low 145 155 166 199 232 Peak MW Low 041 045 048 051 -053 Koliganek Mwn/Year High 190 356 $23 1014 1505 Peak MW High 054 +102 18 248 345 MWh/Year Low 170 188 206 296 386 Peak MW Low +05 +054 -058 -073 -088 Levelock MWh7Year High 209 419 629 948 1267 Peak MW High 06 -12 18 +235 29 MWh/Year Low 183 20S 228 343 458 Peak MW Low 052 058 065 085 105 Manokotak Mwn/Year High 338 678 1018 1728 2439 Peak MW High -097 +194 +290 425 +56 MWh/Year Low 257 264 271 398 $23 Peak MW Low 073 .077 +08 12 New Stuyahok Mwh7Year High 267 460 653 1183 1713 Peak MW High -1 +143 +186 288 ag Mwh/Year Low 232 256 280 384 488 Peak MW Low 5 1 1 1 71 Portage Creek Mwh7Year High 120 198 275 372 468 Peak MW High 034 -057 08 +094 -107 Mwh/Year Low 110 134 156 190 224 Peak MW Low -031 038 045 048 05 Total MWn/Year High 2907 6094 9281 13121 16962 Peak MW* High 1.33 2.35 3.37 4.36 5.34 MWh/Year Low 2036 -2736 3436 4494 $552 Peak MW* Low 1.27 1.36 1.44 1.67 1.9 *Noncoincident Page |V-257 were built in 1980. The influence of hydro development is shown on Figure IV-8 "Nushagak/Kvichak Villages - Cost of Power". These curves are based on the assumption that the cost for the interties plus allocated cost for the Tazimina development as established in Appendix D-7 are the annual total power cost. If only Lake Elva and Grant Lake are developed, a wholesale price has been used as the "diesel only" evaluation. The investigation shows that a transmission intertie between Dillingham/ Naknek and the 10 villages should be approached on an individual basis at the present time. Close attention has to be paid to existing systems and operating efficiencies. If the Tazimina project is taken into account, however, these transmission ties will eventually lower the electric energy cost in these villages dramatically. 100: 907 + ——<t 80+ 70+ LOCAL DIESEL W.O. INTERTIE | |— INTERTIE TO DILLINGHAM / NAKNEK ( DIESEL ) -— INTERTIE TO DILLINGHAM/ x NAKNEK —_— ( ELVA + GRANT + DIESEL) 30: INTERTIE TO DILLINGHAM / NAKNEK (TAZIMINA ONLY ) BRISTOL BAY : NUSHAGAK / KVICHAK — VILLAGES » / KWH COST OF POWER (AT VILLAGE BUS) FIGURE IZ-8 a | JUNE _1979_| 1980 1985 1990 1995 2000 YEAR : Page IV-258 Transmission Tie Lines - Low Load Growth (Power Cost at Local Distribution Bus) 1980 1985 1990 1995 2000 Annual MWh : 2036 2736 3436 4494 5552 Cost for Local Generation ¢/kWh 257.5) 31 38.5 48.5 61.5 Annual Cost (1000-$) 519 848 1323 2179 3415 20 Year Average ¢/kWh 40.3 Purchased Power* 260 442 707 1175 1854 (+5% Transmission Loss) Tie Lines 494 494 494 494 494 Annual Cost (1000$) 754 936 1201 1669 2348 Cost for Central Generation ¢/kWh 37 34.2 35 3721 42.3 20 Year Average ¢/kWh 37.1 Tazimina 834 834 834 834 + Intertie Annual Cost (1000$) Total 1328 1328 1328 1328 ¢/kWh 48.5 38.6 29.6 23:39) 15 Year Average ¢/kWh 35m * Wholesale = Dillingham/Naknek Distribution bus cost + 45%. Page |V-259 Sis \liamna_- Newhalen - Nondaiton a. Energy Resources Most of the energy in this area is presently derived from fuel oil, which has to be brought by barge from Naknek or flown in if the water level in the Kvichak River is too low to allow barge traffic. Alternate resources are solar, wind and hydro energy. Again, solar/wind energy potentials are considered as viable alternatives - especially with the promising wind data of 11.7 mph at Iliamna. The nearby hydro potential of Tazimina Lake - although with too high a capacity and investment cost to be feasible for these three communities alone - is a viable resource if developed for the Dillingham and Naknek area. bE Electric Power Demand and Resources The future electric power demand for the three communities as established in Section II! of this study is as follows: Power Requirements 1980 1985 1990 1995 2000 Annual MWh (High) 1543 e215 2887 5578 8270 Peak Demand MW (High) .352 -506 -66 1.19 Tle; Annual MWh (Low) 1382 1571 1761 1955 2149 Peak Demand MW (Low) _ .315 .357 -4 j -445 .49 Page |V-260 Electric Power Resources Gi) Diesel Generation A central power plant does not exist in the area at this time, although the Iliamna/Newhalen Electric Cooperative has attempted to obtain loan funds from REA to construct power supply and distribution facilities. System studies, prepared in 1978, assume a central plant in Iliamna with 14.4/24.9 kV overhead distribution to Newhalen and Nondalton. The link to Nondalton could later be connected to the Tazimina hydro project and supply the entire system. An alternate scheme for generation proposed the "gearbox" diesel generator (see Appendix B-3 and D-10) to achieve greater fuel economy than with conventional small diesel generators. The bus bar power cost for these proposed installations compare as follows Clow load growth): 1980 1985 1990 1995 2000 Conventional ¢/kWh 18. 2285) 2i.5 34.5 44.5 Diesel (Appendix D-7) Gearbox Diesel ¢/kWh de ZALS 26.4 33.3: 43.5 (Appendix D-10) Priv. Generators* ¢/kWh] 50. -- -- -- -- (Section 1V-C.1) *not at distribution bus, but at service drop; power available approx. 4-8 hrs/day. It does appear that a central system could provide cheaper power than private generators if the required distribution system is low cost. The benefits of having power available at a turn of a switch have not been considered. Gi) Hydroelectric Resources Development of the Tazimina hydro project is described under the "Dillingham/Naknek" part of this section. Cost for this project (earliest year of operation is 1985) has been allocated to the various communities in Appendix D-7. The resulting bus bar power cost for Iliamna/Newhalen/Nondalton would then be: Page |V-261 ILIAMNA/NEWHALEN/NONDALTON - LOW GROWTH (Power Cost at Distribution Bus) 1985 1990 1995 2000 Annual MWh 1571 1761 1955 2149 Annual Cost (1000$) , Tazimina (allocated) 390 390 390 390 ¢/kWh / . 24.8 22.1 19.9 18.1 15 Year Average ¢/kWh 21 Diesel only* 353 484 674 956 ¢/kWh 22.5 2735 34.5 44.5 15 Year Average ¢/kWh 82:5 *From System Planning Study, 1978. Other hydropotentials in the general area that have not been evaluated in greater detail due to their location in national monuments, parks, impact on population and fisheries or. high cost of development are the following: Koksetna River 2 MW prime Lachbuna Lake ‘23.4 MW prime Newhalen River 22 MW prime Cs Analysis of Electric Power Resource Alternatives With the recognized alternatives of solar, wind, diesel and hydroelectric energy, a central diesel generating plant appears to be the most economic solution at this time. With improving technology it is possible that wind energy becomes a very attractive supplemental power source. The cost evaluations in Appendix D-2 to D-4 can be used as a guideline to establish feasibility for individual systems. Development of the Tazimina hydro potential will provide the least costly source of electric energy and can potentially replace fuel for home heating, if Dillingham/Naknek can utilize this source. Page !1V-262 4. Chignik Bay Communities a. Energy Resources Various resources have been identified in this area: Coal Chignik Bay 100 x 10® tons at 9640 to 11240 Btu/Ib. Hydro Lake #1 700 kW prime Lake #2 400 kW prime Landlocked Creek 840 kW prime Wind potential is expected to be good although there is at present no data available to assess this resource in greater detail. Br Electric Power Demand and Power Resources The three communities of Chignik, Chignik Lagoon, and Chignik Lake have the following projected energy demands (from Section Ht): Electric Power Demand 1980 1985 1990 1995 2000 Chignik Annual MWh (High) 1617 2055 2495 3711 4928 Peak MW (High) wal, w47. md -845 1.12 Annual MWh (Low) 1360 1495 1631 1667 1703 Peak MW (Low) al iO. san -_ 39 Chignik Lagoon - Annual MWh (High) Nida 976 1775 3351 4928 Peak MW (High) .05 .228 -405 . 762 tal2, Annual MWh (Low) 160 176 191 687 1183 Peak MW (Low) -045 305 .055 .158 -26 Chignik Lake Annual MWh (High) 201 303 403 584 764 Peak MW (High) .057 . 086 at te -145 aifo Annual MWh (Low) 178 199 220 260 300 Peak MW (Low) .05 .057 . 063 . 066 .069 Total Annual MWh (High) 1995 3334 4673 7646 10620 Peak MW (High) -477 . 784 1.09 1,752 2.415 Annual MWh (Low) 1698 1870 2042 2614 3187 Peak MW (Low) .405 447 - 488 604 shld *Noncoincident Page IV-263 Electric Power Resources (i) Diesel Generation General parameters for the evaluation of the cost of diesel generation either on an individual or community basis have been established in Part C.1 of this section (Generating Technologies). The bus bar costs with 7% fuel cost increase per year are expected to be approximately as follows (from Figure IV-2.) 1980 1985 1990 1995 2000 Chignik and Chignik * Lagoon ¢/kWh 20 25 31 36 46 Chignik Lake ¢/kW 27 34 44 54 64 The low range of the "cost bands" has been used for Chignik and Chignik Lagoon with the lowest relative fuel cost in the area. Chignik Lake, being smaller and with more difficult access, has been assigned cost in the middle to upper range. Cii) Distribution Intertie and Diesel Generation If a central generating plant is assumed to be built in Chignik and: Chignik Lagoon as well as Chignik Lake are being supplied from this plant via a three phase 24.9 kV distribution line to Chignik Lagoon and a single phase 14.4 kV continuation to Chignik Lake (see Figure |V-9 for routing) the following approximate cost at the distribution bus in all three communities have been calculated (see Appendix D-8a for details). ros os = = 8 ¢ cr. OT | NAc -LEGEND Anguvik I " Scale (UP TO 25 (UP TO 14.4 Ob dihk s we = n no eae J 2 ob DISTRIBUTION LINE 39 kv) DISTRIBUTION LINE 1@ Kv) HYDRO ELECTRIC GENERATING BAY jack Pt : <9 Tuliumnit P Nikolai Cove §: 250,000 ra & lara ~~) Chankth x ts g b . CHIGNIK BAY INTERTIE 0 & ‘ FIGURE IZ -9 L bee S9Z-Al ebed Page |V-266 CHIGNIK BAY POWER COST - LOW LOAD GROWTH - DISTRIBUTION INTERTIE AT DISTRIBUTION BUS (Diesel Only) 1980 1985 1990 1995 2000 Peak kW : 405 447 488 604 719 Annual MWh 1698 1870 2042 2614 3187 Installed Generation Capacity kW 700* 1050 1050 1050 1050 Annual Cost (1000$) Total Cost 304.1 435.5 592.9 939.4 1406.1 ¢/kWh 17.9 23.3 29 35.9 44.1 20 Year Average ¢/kWh 30.1 *Firm capacity is assumed by maintaining existing cannery engine generators on standby. If the interties are assumed with "Single Wire Ground Return" transmission, even lower energy costs are conceivable. (iii) Hydroelectric Resources Lake #1 with a potential of 700 kW prime power, has previously been utilized to supply water to the Chignik cannery. A 60 kW hydro generating unit is presently being operated with the existing wooden stave pipe that supplies the cannery water. Full development (with 2 x 700 kW installed by 1984) of this potential has been assumed with low load growth projections for the three communities (with distribution intertie) and supplemental diesel generation for the cost evaluation in Appendix D-8b). Power costs are then calculated approximately as follows: Page |V-267 CHIGNIK BAY POWER COST - LOW LOAD GROWTH AT DISTRIBUTION BUS (Diesel plus Hydro #1) 1980 1985 1990 1995 2000 Peak kW 405 447 488 604 ego Annual MWh 1698 1870 2042 “2614 3187 Installed Capacity kW 700* 2100 2100 2100 2100 Annual Cost (1000$) Total Cost 304.1 538 564.9 585.8 634 ¢/kWh 17.9 28.8 RFF 22.4 19.9 20 Year Average : ¢/kWh CaS) *Firm capacity is assumed by maintaining existing cannery engine generators on standby. Lake #2 with a potential of 400 kW prime power, will be more costly to develop and is not necessary if low load growth is assumed. For the high load growth case and Lake #1 operational in 1983, this potential is required by 1994. The cost evaluation in Appendix D-8c follows this scheme utilizing diesel generation a supplemental energy source. The power costs are then calculated approximately as follows: CHIGNIK BAY POWER COST - HIGH LOAD GROWTH AT DISTRIBUTION BUS (Diesel Plus Hydro #1 & 2) 1980 1985 1990 1995 2000 Peak kW 477 784 1090 752) 2415 Annual MWh 1995 3334 4673 7646 10620 Installed Capacity kW 900 2300 2300 3100 3600 Diesel MWh* | 1995 29.8 320 623 2229 Annual Cost (1000$) Total Cost 323.5 517.4 598.5 15511.2 2394.2 ¢/kWh 16.2 18.5 12.8 20;/3 (ass: 20 Year Average ¢/kWh 17-5, *Applying typical load duration curve and assuming prime power for hydros only. (iv) Page |V-268 The higher capacity diesel plant and full utilization of the hydro potentials lead to the lowest per unit cost. Increased use of diesel in the later years leads to gradually increased cost per kWh. Another potential hydro site in this area that has not been evaluated in regard to energy cost for the Chignik Bay communities is: Landlocked Creek with .84 MW prime. This site is located in a wilderness study area and would have to be environ- mentally assessed and declared "non-objectionable". Coal An analysis was performed to determine whether the coal deposits in the Chignik Bay area can be economically utilized for. power generation. A 4 MW coal fired steam plant is assumed to be built in Chignik with an approximately 6 mile road connection to the mine. With parameters as stated in Appendix D-8d power cost are estimated as follows: CHIGNIK BAY POWER COST - HIGH LOAD GROWTH AT DISTRIBUTION BUS (Diesel Plus Coal) 1980 1985 1990 1995 2000 Peak kW 477 784 1090 * 1752 2415 Annual MWh 1995 3344 4673 7646 10620 Installed Capacity kW 900 4900 4900 4900 4900 Diesel MWh 1995 aoe ---- o--- ---- Annual Cost (1000$) Total Cost 323.3 909.2 998.2 1135.8 1340.2 ¢/kWh 16.2 27.2 21.4 14.9 12.6 20 Year Average ¢/kWh 18.5 Waste heat utilization has not been taken into account. It has been assumed, however, that the coal or steam are utilized for comfort heating and in the fish processing industry, leading to a production of approximately 40 tons of coal/day. Page 1V-269 Analysis of Electric Power Resource Alternatives With the coal development for electricity generation being slightly more expensive than the other alternatives, the most viable solution appears to be installation of a central diesel plant with village interties and gradual development of the nearby hydro- potentials. The use of coal for heating and fish processing in connection with power generation does appear to have potential but has not been evaluated here. Page IV-270 E. RURAL BRISTOL BAY - ENERGY AND POWER RESOURCES Communities not addressed in Part D of this section have been found not to have viable alternatives to diesel generation at this time. They are listed with their projected energy requirements and potential resources in the general area which will give a valid enough perspective to allow determination of further investigations. ils Peninsula - Bristol Bay Side a. Power Requirements (from Section 111) The anticipated costs of diesel generation have been added for comparison with possible alternate sources. 1980 1990 2000 Pilot Point/Ugashik Annual MWh (High) 348 1492 3047 Peak MW (High) ee .68 9 Annual MWh (Low) 328 651 725 Peak MW (Low) a .37 -415 Port Heiden Annual MWh (High) 247 400 1772 Peak MW (High) .07 .092 .4 Annual MWh (Low) 232 256 326 Peak MW (Low) . 066 .074 .075 Port Moller Annual MWh (High) 542 2478 2604 Peak MW (High) -123 .46 a Annual MWh (Low) 334 749 818 Peak MW (Low) ales .214 .233 Cost for diesel generated energy (average) at distribution bus 27 38.5 61.5 Page |V-271 b. Potential Energy and Power Resources Hydro Energy Unnamed Creek Distance: approximately 5 miles east of Port Moller. Capacity: 460 kW prime. Estimated annual cost (including transmission): if installed in 1985 at 35 year, 5% interest capital + O & M and insurance - $773,000 at high use (1510 MWh) = 51.2 ¢/kWh Becharof Lake Distance: approximately 20 miles from Egegik. (Bulb turbine application. ) Hot Springs Creek Distance: more than 50 miles from Pilot Point/Ugashik. Capacity: 1.65 MW prime Estimated construction cost: 1979 - $5,909/kw. King Salmon River Distance: approximately 10 miles from Port Moller. Capacity: 400 kW prime. Estimated annual cost (including transmission): if installed in 1985 at 35 years, 5% interest capital - O & M and insur- ance - $780,000 at high use (1510 MWh) = 51.7 ¢/kWh. Reindeer Creek Distance: approximately 6 - 7 miles to Port Heiden. Capacity: 400 kW prime. Estimated construction cost: in 1979 - $12,800/kW. Page |V-272 Geothermal Energy Mt. Veniaminof A large scale development with a potential of more than 70,000 MW equal distance from Port Moller and Port Heiden. Port Moller Hot Springs Distance: approximately 9 miles. Flow: 80 gpm. Temperature: 60°C (140°F). Port Heiden Hot Springs No data available. Coal Energy Herendeen Bay Distance: approximately 10 miles to Port Moller. Recoverable Amount: 2.5 - 25 x 10® tons. Heat Value: 11,260 - 11,790 Btu/Ib. With expected average wind speeds of 12.2 to 17.2 MPH, wind potential is considered excellent throughout the. area. Page |V-273 Peninsula - Pacific Coast Power Requirements (from Section 111) 1980 1990 2000 Ivanoff Bay Annual MWh (High) 154 1715 4788 Peak MW (High) -045 .392 Tet Annual MWh (Low) 144 524 1149 Peak MW (Low) .041 «15 -26 Perryville Annual MWh (High) 563 1902 5339 Peak MW (High) -16 -43 1.22 Annual MWh (Low) 178 580 1740 Peak MW (Low) .05 -165 .4 Potential Energy and Power Resources Hydro Energy No potential has been found in the vicinity of these communities. This does not preclude the existence of small scale potential that cannot be judged from available maps. A 75 feet waterfall has been pointed out by local residents. Potential has not been assessed yet. A transmission tie to the Chignik Bay area appears possible but has not been investigated. Geothermal Energy Mt. Veniaminof A large scale development. Coal Energy The Chignik and Herendeen Bay fields are located within 100 miles of the communities (via sea). Wind Energy Although no actual measurements are available, the potential is conceivably good. Page 1V-274 Togiak Bay Area Power Requirements (from Section ||!) 1980 1990 2000 Togiak Annual MWh (High) 1080 3857 7402 Peak MW (High) 5 ‘1. Ve Annual MWh (Low) 835 1227 2076 Peak MW (Low) .24 56) ~19 Twin Hills Annual MWh (High) 166 331 1172 Peak MW (High) .047 .095 .27 Annual MWh (Low) 152 176 246 Peak MW (Low) .045 .05 056 Potential Energy and Power Resources No potential resources that could be developed within the next 20 years have been found. Wind energy potential is considered good, but has not been assessed since specific data is not available. A transmission intertie with the Dillingham system could be economically feasible, if hydropower becomes available there, but has not been evaluated within this study. Page 1V-275 Ah. lliamna Lake/Lake Clark a. Power Requirements (from Section II!) 1980 1990 2000 Kokhanok Annual MWh (High) 167 320 612 Peak MW (High) -05 .091 .14 Annual MWh (Low) 152 176 246 Peak MW (Low) * .045 .05 .056 Pedro Bay Annual MWh (High) 197 457 1055 Peak MW (High) -056 -104 .24 Annual MWh (Low) 173 210 289 Peak MW (Low) .05 .06 . 066 Port Alsworth Annual MWh (High) 141 236 384 Peak MW (High) .04 .068 . 088 Annual MWh (Low) 134 144 204 Peak MW (Low) .038 -041 .05 b. Potential Energy and Power Resources Hydro Energy Copper River - Meadow Lake Distance: ~ 25 miles to Kokhanok ~ 25 miles to Pile Bay Capacity: 910 kW prime (install 2 x 750 kw). Estimated cost 1979: $5423/kWh. Development would produce power cost of > $2/kWh in 1985 and not drop below $1/kWh by 2000 since one community's (Kokhanok) requirements cannot utilize all the available energy. Page |1V-276 Kokhanok River Distance: ~ 12 miles to Kokhanok. Capacity: 630 kW prime (install 2 x 750 kW). Estimated cost: 1979: $8492/kwW. Economic development does not appear feasible with the pro- jected load levels. Summit Lake - Chinkelyes Creek Distance: ~ 6 miles to Pike Bay ~ 18 miles to Pedro Bay Capacity: 3 MW prime. Estimated cost 1979: $5450/kw. Economic development does not appear feasible with the pro- jected load levels. Geothermal Energy Iniskin Bay Distance: ~ 40 - 50 miles east of Pedro Bay. Temperature: approximately 220°F. Depth: 9700 Ft. Pressure: 400 psi. Capacity: approximately 5 MW. Cost estimate: Not done due to insufficient data. Wind Energy Measured wind velocities in Iliamna indicate a good potential there, although generally a site specific evaluation will be necessary due to the mountainous terrain. A wind generator being operated in Port Alsworth appears to work satisfactorily. V. RECOMMENDATIONS Page V-279 A. INTRODUCTION The rapidly increasing cost of fuel dictates the investigation of other energy resources. The previous chapters in this study have listed and addressed various possible resources, projected possible load growth and compared load size with resource capacity where practical. The general findings have indicated that most power or energy re- sources have a much higher capacity than required within the geo- graphical area of their location. Transportation of energy is costly and the economic determination to develop an energy potential will depend greatly on these costs. With the preliminary evaluations of several resources as a base, sections B to F will briefly outline steps that are necessary to allow more detailed or accurate feasibility analyses of thé energy resources. Section G addresses possible development plans for regions and communities. Oil and natural gas resources will not be addressed here, since large scale development cannot be undertaken on a regional base. B. DIESEL ELECTRIC ENERGY Where no other alternate energy sources have been found, a more efficient use of fossil fuel can reduce the impact of rapidly increasing fuel costs to some extent. The possibilities are: or Larger central power plants with SWGR transmission interties. Z- Gearbox engines for small plants to reduce speed at low load periods. Possible transmission interties have been preliminarily evaluated. A more detailed evaluation will have to be done on a case by case basis. This analysis would take presently operating plants and their costs into account. C. HYDRO ENERGY The survey for this study has been performed utilizing U.S.G.S. maps with a scale of 1 inch = 1 mile. This scale does not allow evaluation of bulb turbine applications or smaller than 400 kW capacity potentials. During the preparation of this study several possible small hydro sites have been mentioned by local residents which could not be verified. These sites are in the general vicinity of: Page V-280 Togiak New Stuyahok Perryville Preliminary assessments can be made by a brief on site investigation. The bulb turbine sites are: Agulowak River Naknek River Becharof River Kvichak River These sites require stream and flow measurements as well as on site investigations in regard to terrain. Since very little is known about the impact of bulb turbines on fisheries, this aspect should be investigated in greater depth to determine whether these applications are viable at all. Hydro potentials located in national monuments or parks have been addressed but generally not been evaluated since park statutes usually will not allow development of these resources unless a status of compatibility has been granted to the project. Several sites are located in "Wilderness Study" areas, where this status can still be obtained. These sites are: Kvichak River Naknek Lake Becharof Lake Landlocked Creek Reindeer Creek Chignik Lakes #1 and #2 Copper River - Meadow Lake Kokhanok River Koksetna River Lackbuna Lake Summit Lakes Tazimina Lake The hydro potentials for which the preliminary evaluations indicate that development could be economically feasible will require flow measurements and geologic on site evaluations. These sites are: Lake Elva Grant Lake Lake Tazimina Chignik Lakes #1 and #2 Individual feasibility studies addressing availability and cost of capital, timing of construction, and load projections for the above projects should be performed to allow a better evaluation of the possible choices. Page V-281 D. GEOTHERMAL ENERGY Ts Hot or Warm Springs’ Although the potentials listed are too small for even community scale development, discharge and temperature measurements at the Port Heiden site are recommended. 2. Prospective Geothermal Resource Area (PGRA) The Alaska Peninsula is known to have geothermal potential. Research and investigations have been limited to approximate assessments of the energy contents of possible magma chambers. In order to determine whether the potential is actually within the stated boundaries and depth, field investigations are necessary. The cited potentials at Mt. Veniaminof and Black Peak are considered to be close enough to the communities of: Port Moller Port Heiden Perryville Ivanoff Bay Chignik Chignik Lagoon Chignik Lake to warrant further studies in regard to: a. geological mapping b. geophysical tests The results of these investigations will then allow a more definite evaluation of the possibilities for development. E. COAL ENERGY a Of the identified resources the Chignik Bay field is located close to potential load centers and appears to have easier access. The prelim- inary evaluation indicates that development might be economically feasible. A more extensive feasibility study, including: Fs Page V-282 Field investigations of geology and possible mining techniques Determination of possible uses for: heating industry power generation oom Cost estimates for: a mine installation and operation Dis roadways c. transportation over land and by sea d power plant installation at the mine or within the load centers e. transmission of electric energy or steam Determination of annual cash flowsfor the coal mining and transport is necessary to assess the possible utilization of this resource. WIND ENERGY Wind energy is abundant in almost the entire region and utilization by individuals or communities to supplement other energy resources can be economic depending on location. To realize this potential the following steps are recommended: U Collect _and publish wind data on a steady basis for most of a year from Perryville, Egegik or Ugashik and some village(s) on the Nushagak River (e.g. New Stuyahok and/or Koliganek). Interviews of residents might be followed by wind measurements at schools, with teacher and student participation. This can be part of a needed region-wide educational program on alternate energy sources. Properly summarize five years of wind data from Dillingham; the raw data are in Alaskan archives. Design and operate a WECS system, involving no energy storage but using an induction generator for wind/oil sharing. Install, test and gather operating and performance data at King Salmon and then move to some more energy deficient candidate village. Page V-283 G. DEVELOPMENT PLANS Energy conservation and energy conscious building design are assumed to be observed throughout the area. This section will address the options in resource development - other than the more efficient use of diesel-generation - found in the course of this study for the individual communities and regions. 1. Dillingham/Naknek - King Salmon Development of hydro-power appears economically feasible for these population centers. The sites are Lake Elva with 1.5 MW prime Grant Lake with 1.5 MW prime Tazimina with 15 MW prime (1st stage) If the Dillingham and Naknek systems are not interconnected, Lake Elva and subsequent Grant Lake development are the best options for Dillingham. Tazimina - due to its size - is only feasible if both systems are supplied. To allow a better evaluation of the available choices, flow measurements, geological and engineering site reconnaissance, and studies in regard to timing of construction as. well as cost of capital have to be performed for these projects. With wind energy potential judged as very good in King Salmon, a demonstration project is recommended to be pursued at this location. The ready accessibility would facilitate operation, maintenance and recordkeeping. 2s Uliamna, Newhalen, Nondalton A co-op has been formed is this area to build a centralized power plant. So far the Iliamna-Newhalen-Electric-Cooperative (INEC) has not been able to obtain financing for these facilities. The Tazimina hydro project could supply cost stable power to this area if development proves feasible. 35 Page V-284 Nushagak/Kvichak Bay Communities Transmission interties between the larger utilities in Dillingham and Naknek and the following villages Clark's Point Egegik Ekuk Igiugig Koliganek Levelock Monokotak New Stuyahok Portage Creek could provide reliable electric power where a centralized system does not yet exist and reduce cost at locations with inefficiently operating small plants. More accurate investigations into the existing systems and power cost in the above communities should be performed to determine feasibility on a case by case basis. Development of the Tazimina Hydro project would make these interties almost mandatory. Peninsula-Bristol Bay Side Hydro potential in the Port Moller area is of marginal economic value at this time. Wind energy is the most abundant resource for communities in this area. If reliable equipment with a good operating record can be found, supplemental use of wind generators to a diesel electric generating plant is considered economically feasible. Peninsula-Pacific Side Hydro- and coal resources in the Chignik Bay area appear to have good potential for economic development. Field investigations are necessary for both resources to allow a more accurate assessment. Distribution interties between the three communities of Chignik, Chignik Lagoon and Chignik Lake, however, are considered to lead to lower power cost as soon as they can be installed. 1 eo — Page V-285 Togiak Bay Although wind energy potential is expected to be good in this area, no data is available at this time. With no other major economic energy resources found in the vicinity of Togiak and Twin Hills, this potential should be more closely evaluated. An intertie to the Dillingham system should be investigated in connection with the Tazimina hydro project. Inland Investigations into possible wind energy are recommended. Hydropotential does exist but is considered to be too costly to develop for the load requirements in the communities of Kokhanok, Pedro Bay and Port Alsworth. APPENDIX A ENERGY BALANCE DATA Page A-289 APPENDIX A ENERGY BALANCE DATA Where energy usage had to be estimated for the 1977 base year the following data has been used: Annual Use in Gallons Residential Gasoline Propane Heating (97.4 x 10° Btu, 75% Efficiency) Diesel Electric (363 kWh/mo.) - if supplied by central plant Diesel (122 kWh/mo.) - if supplied by private generator Diesel Schools a. Small Heating (1010 x 10® Btu, 75% Efficiency) Diesel Electric (52,000 kWh/year) Diesel b. Medium Heating (1850 x 10® Btu, 75% Efficiency) Diesel Electric (105,995 kWh/year) Diesel c. Large Heating (4082 x 10® Btu, 75% Efficiency) Diesel Electric (230,000 kWh/year) Diesel Stores Heating (137.5 x 10® Btu, 75% Efficiency) Diesel Electric (803 kWh/mo.) - if supplied by central plant Diesel (803 kWh/mo.) - if supplied by private generator Diesel 2 stores for every 22 families Public Buildings Heating (289.3 x 10® Btu, 75% Efficiency) Diesel Electric (5588 kWh/Year) if supplied by central plant Diesel if supplied by private generator Diesel 600 40. 941 512 324 9800 6100 17874 12470 39400 27129 1329% 1134 3471 2795 og. 1242 66 Page A-290 The derivation of the above usages is explained in detail in the following sections of this appendix. Fuel uses for electric generation have been assumed at different generating efficiencies for central plant generation and private generators.’ Central Plant efficiencies are assumed at 8.5 kWh/Gal. (based on AVEC Cost of Service Study, 1977) for plants larger than 20 kW._ Private Generators efficiencies are assumed at 4.5 kWh/Gal. (based on manufacturer's data) for engines in the 3 - 8 kW range. The energy conversion factors used in this study were as follows: 138,000 BTU/gallon for diesel fuel 127,000 BTU/gallon for gasoline. 91,000 BTU/gallon for propane. 138,000 BTU/gallon for jet fuel. 127,000 BTU/gallon for AV gas. ubnWh— Page A-291 1. FAMILY RESIDENCE Assumptions Made in Approximating Fuel and Electrical Consumption Building Size 30' x 20' x 12.5! 600 Sq. Ft. A. Heat loss calculations and fuel use Area of Windows = 1/10 total wall area = 1252Sq:eFt. Area of Walls = 1125. Sq.Ft. Area of Roof = 600Sq..Ft. Area of Floor = 600 Sq. Ft. Assume walls of 2" x 4" construction on 16" centers R-12 insulation U Factor .08. Roof and floor 2" x 8" or 2" x 12" on 16" centers. Unheated attic 6" of insulation U Factor .09, .5 air changes per hour. U = .45 for windows. Heat Loss = 2 Area x U Factor BTU/Hr.AT Heat Loss Walls = 1125 Sq. Ft. (.08) = 95.28 BTU/Hr.AT Heat Loss Windows = 125:..Sq.. Ft. ¢.45)-= 56.25 BTU/Hr.AT Heat Loss Roof = 600 Sq. Ft. (.09) = 54.00 BTU/Hr.AT Heat Loss Floor = 600 Sq. Ft. (.09) = 54.00 BTU/Hr.6T Subtotal Heat Loss , 259.53 BTU/Hr.AT Heat loss due to air change of .5 air changes/hour = 5 3) ,.075 Lb, ,.14 BTU Fp (7500 ft.%) (asap) Cc Tb. aT ) = 67.5 BTU/Hr.AT Total Heat Loss = 327.03 BTU/Hr.AT Fuel Calculations Average Temperature S12 ss 24 Hr. 365 da BTU/Year = 327.03 BTU/Hr.AT x Day Xe Vear x (65° - 31°) = 97.4 x 106 BTU/year _ 97.4 x 10° BTU 1 1 gallon used Push a Year * 738000 * .75 gallon effective 941 gallons/year/family B. Page A-292 Electrical Energy Use For villages with centralized power system Assume 4357 _kWh/Family/Year This is based on the attached (Table A-1) survey information published by Alaska Village Electric Cooperative in the "Light Lines" newsletter (April and May 1977) Fuel Used for electric energy for villages with centralized power system: Assume 8.5 kWh/gallon generating efficiency including losses 4357 kWh 7 1 gallon _ 512 allons Family/Year 8.5 kWh Family/Year Family Residence Electrical Use for villages with non-centralized power system: Assume 1460 kWh/year/family 8 hr. Based on .5 kW x day x 365 days = 1460 kWh (based on village survey data in "A Regional Electric Power System for the Lower Kuskokwim Vicinity" by RWRA for U.S. Department of the Interior, Alaska Power Administration, 1975.) Fuel use for electric energy for villages with non-centralized power system: Assume 4.5 kWh/gallon 1500 kWh 8 1_gallon _ 324 gallon Year/family 4.5 kWh Year/Family CG. Page A-293 Propane Usage Assumptions made in approximating fuel consumption: Assume propane is used only for the range in a residence by 93% of the families in a village. This is based on the survey information (Table A-1) published by Alaska Village Electric Cooperative in “Light Lines" Newsletter (April and May 1977). Average range estimated annual kWh = 1175 kWh. Conversion into heat units yields: 3413 BTU kWh x (.93) = 3.73 x 10© BTU/year/family 1175 kWh = 1175 kWh x Fuel Usage is then: 3.73 x_10® BTU . iat Ho x 1Gallon Year/Family 21670 BTU 4.23 Lb. 40.66 gallons Year/Family TABLE A-1 ENERGY USAGE OF APPLIANCES Rep. Wattage Representative Est. kWh APPLIANCE % OWNED of Appliance kWh* Ann/App. Ann/Village Blender 11% 300 1 1 Clothes Dryer 11% 4856 993 109 Electric Frying Pan 40% 1196 100 40 Electric Blanket 2% 177 147 3 Hand Mixer 39% 127 2 1 Oven/Broiler 63 1333 60 4 Radio 91% 71 86 78 Television 51% 45 100 51 Broiler 1% 1140 85 8 Microwave Oven 23 1450 170 4 Popcorn Popper 283 1200 2 fl Coffee Maker 613 894 106 65 Can Opener 283 1 1 1 Electric Drill 523 =~ 2 1 Freezer 813 =: 1320 1069 Electric Hot Water Heater 83 2475 4219 337 Electric Range 7% 12200 1175 82 Sewing Machine 42% ZB 11 5 Washing Machine - regular 663 286 76 50 Toaster 633 1146 39 25 Surface Hot Plate 35% 1200 90 31 Cooker/Fryer 27% 1196 100 27 Cassette Player 76% 100 100 76 Electric Saw 44% -- 2 A Grill/Waffle lron 9% 1200 20 2 fron 54% 1100 60 32 Refrigerator 41% -- 700 287 Soldering Iron 24% -- 2 1 Washing Machine - Auto 15% 512 103 15 Blow Dryer (Hair) 22% 1500 20 4 Hair Dryer 16% 381 14 2 Lighting 100% 1944 Total kWh/fam/year 4357 Total kKWh/fam/month 363 From "Alaska Village Electric Cooperative Cost of Service Study". Nov. 1977. Prepared for State of Alaska - Public Utilities Commission. : *Source: Eectric Energy Association, 1975. Page A-295 Gasoline Usage Assumptions Made in Approximating Fuel Consumption: 600 gallons Assume Family/Year This is an average approximated from the Department of Commerce and Economic Development. Division of Energy and Power Development. Community Energy Survey. 1978. Assumptions Made in Approximating 2. SMALL SCHOOL Fuel and Electrical Consumptoin Page A-296 Several buildings constitute the school, including the school itself, teacher housing, a storage shed and a generator shed. the generator shed and storage shed are not heated. Building size: School - 32,000 cu. ft. - 12,500 cu. ft. Teacher Housing A. Heat Loss Calculations Area of windows in school 200 Area of walls in school 2050 Area of roof in school 3000 Area of floor in school 2500 Area of windows in teacher housing 132 Area of walls in teacher housing 1353 Area of roof in teacher housing 1400 Area of floor in teacher housing 1000 Assume V of windows = .45, V of Walls = .07 V of roof and floor Subtotal Heat Loss Subtotal Heat Loss Heat Loss Due to Air Change of 1.5 times per hour = .23 = Area x V Factor BTU/Hr. AT 2205 BTU/Hr.AT 1.5 Air Changes xX 44500 ft.3 X .075 Ib. Hour = 1201.50 BTU/Hr. AT Total Heat Loss = 3406.5 BTU/Hr. AT sq. sq. sq. sq. sq. sq. sq. sq. It is assumed The generator size for a small school is also assumed to be less than 20 kw. ft. ft. tt. ft. ft. ft. ft. Tt. x .24 BTU Ft.3 Ib. AT Fuel Use Calculation: Average Temperature 31°F. BTU _ 3406.5 BTU x 24 Hr. x 365 day Year Hr. AE day Year X (65°F - 31°F) = 1.01 X 10° BTU/Year _ 1.01 X 109 BTU 1 gallon — Year X 738000 BTU 1_gallon_used a x .75 gallons effective — 9800 gallons Electrical Use kWh earl ec 52,000 (~ 4 of data for medium school) Fuel Use: Assume 8.5 kWh/gallon 52000 kWh ,, 1 gallon ~ Vaan x 3.5 kWh = 6100 gallons diesel Page A-297 Page A-298 3. MEDIUM SCHOOL Assumptions Made in Approximating Fuel and Electrical Consumption Several buildings constitute school including the school itself, teacher housing, storage shed and generator shed. Building Size: School 40000 cu.ft. Teacher Housing 20000 cu.ft. Storage Shed 7500 cu.ft. Generator Shed 9000 cu.ft. A. Heat loss calculation Area of windows in school = 280 sq. ft. Area of walls in school = 2120 sq. ft. Area of roof in school = 4200 sq. ft. Area of floor in school = 3750 sq. ft. Area of windows in teacher housing = 260 sq. ft. Area of walls in teacher housing = 1540 sq. ft. Area of roof in teacher housing = 1950 sq. ft. Area of floor in teacher housing = 1500 sq. ft. Area of windows in storage shed = 60 sq. ft. Area of walls in storage shed = 1040 sq. ft. Area of roof in storage shed = 900 sq. ft. Area of floor in storage shed = 750 sq. ft. Area of windows in generation shed = 60 sq. ft. Area of walls in generation shed = 1140 sq. ft. Area of roof in generation shed = 1050 sq. ft. Area of floor in generation shed = 900 sq. ft. Assume U of windows = .45, U of walls = .07, U of roof and floor = .23 Subtotal heat loss = 2 Area x U Factor BTU/Hr.AT Subtotal Heat loss 4155.3 BTU/Hr.AT Heat loss due to air change of 1.5 times per hour 1.5 air changes 3 «Jo LD). .24 BTU , Hour Me HERG, ee es v4 tis) OC Lb. AT = 2065.5 BTU Hr. AT Total Heat Loss = 6220.80 BTU/Hr. AT Page A-299 Fuel Use Calculations: Average Temperature at*F _ 6220 BTU 24 Hr. 365 days BTU/ year §. erat x “day a Year BTU ° i ° = 9 x (65°F -"31°F):= 1.85 x 10% a _ 1.85 x 109 BTU 1 gallon es Year * 738000 BTU 7 1_gallon_ used = 17874 gallons .75 gallon effective Year Electrical Use kWh Year estimate is actual use of small school in New Stuyahok -_ 105995_kWh Waar (AVEC 1977) Fuel use for electric energy generation: 8.5 kWh Assume ———— gallon 105995 kWh 1_gallon — 12470 gallons Year * 8.5 kWh: Year ‘ = 30344 gallons Medium School Total Fuel Use Year Page A-300 4. LARGE SCHOOL Assumptions Made in Approximating Fuel and Electrical Consumption School: One Large Building Building size: School 95,200 cu.ft. Gym 170,100 cu.ft. A. Heat Loss calculation Area of windows in school = 0 sq. ft. Area of walls in school = 4500 sq. ft. Area of roof in school = 6000 sq. ft. Area of floor in school = 5600 sq. ft. Area of windows in gym = 0 sq. ft. Area of walls in gym = 8000 sq. ft. Area of roof in gym = 6750 sq. ft. Area of floor in gym = 6300 sq. ft. Assume U of windows = .45, U of walls = .07, U of roof and floor = .23. Subtotal heat loss = = Area x U Factor BTU/Hr.AT Subtotal heat loss = 6544 BTU/Hr.AT Heat loss due to air change of 1.5 times per hour = 1.5 air changes 3 -075 Lb. .24 BTU Hour Aor FES ~Ft.3 LBAT = 7163.1 BTU/Hr.AT Total Heat loss = 13707.1 BTU/Hr.AT Fuel Use Calculations: Average temperature 31°F 13707 BTU 24 Hr. 365 days ae Hr. AT ~* day * Year BTU 7 =a 9 x (65°F 31°F) 4.08249 x 10 Year Page A-301 _ 10° BTU 1_gallon Fuel use = 4.08249 x Year * 738000 BTU - 1_ gallon used mito! 4 5c 103 gallons .75 gallon effective ‘ Year Electrical Use kWh kwh estimate is actual use of large school in Togiak = 230060 Vea Year Fuel Use for electricity generation: Assume 8.5 kWh/gallon kWh 1gallon _ 230060 Wear a Schwan 27129 gallons = 62212 gallons Large School Total Fuel Use Vear Page A-302 5. VILLAGE STORES Assumptions Made In Approximating Fuel and Electrical Consumption Village Store: Store size the same as an average village house. A. Heat Loss Calculations Heat loss neglecting air changes are the same as for a house = 259.53 BTU Hr. AT Heat loss due to assumed 1% air changes/hour = 1.5 Air Changes 3), .075 Lb. .24 BTU _ 202.50 BTU Hour (7500 Ft.*)€ “Es “That Hr.AT Total Heat Loss = 462.03 BTU/Hr.AT Fuel Calculation: Average Temperature 31°F BTU/Year = see BTL x ene x O82 les x (65°F - 31°F) = 137.5 x 108 an Fuel Use = 182.6» 10° BTU x mes TS aT atectiva = 1329.5 gallons/Store Electrical Use Assume store electrical use is the same as an average residential home plus additional refrigerators, freezers and lights. Average residential = 4357 kWh/year 2 additional freezers i 2640 kWh/year 1 addition refrigerator - 700 kWh/year Additional Lighting - 1944 kWh/year Total Page A-303 Electrical Fuel Use for electric energy generation: (i) Gi) if generated with private generator: Assume 4.5 kWh/gallon . 9641 kWh 1_gallon . 2142 gallons Year * 45 kWh 7 Year/Store Total Store Fuel Usage for Villages with noncentral power: 3471_gallons Year Store if generated in central plant: Assume 8.5 kWh/gallon 9641 kWh x 1gallon _ 1134 gallons Year 8.5 kWh Year/Store Total store fuel usage for villages with central power: 2463 gallons Year/Store Assume 2 stores/22 families This is an average approximated from the Department of Commerce and Economic Development Division of Energy and Power Development -Community Energy Survey. 1978. Store Use/Family for villages with noncentral power = 3471 gallons x: 2_ stores - 315 gallons Year/Store 22 Families Family/Year Store Use/Family for villages with central power = 2463 gallons 2_ stores f 223 gallons Year/Store 22 Families Year/Family Page A-304 6. PUBLIC BUILDINGS Assumptions Made In Approximating Fuel and Electrical Consumption Community Center, Health Clinic, etc. are all contained in one building. Building Size - 40' x 40' x 12%4' = 1600 sq. ft. A. Heat Area Area Area Area Loss Calculation of Windows = 1/10 total wall area = 200 sq. ft. of Walls = [(40 + 40) x 124]2 - 200 = 1800 sq. ft. of Roof = 40 x 40 = 1600 sq. ft. of Floor = 40 x 40 = 1600 sq. ft. Assume walls of 2" x 4" construction on 16" centers with R-10 insulation U Factor .1. Roof and floors 2" x 8" or 2" x 12" on 16" centers. _Unheated attic 6 inches of insulation U Factor .13, .75 air changes pwer hour. U = .45 for windows. Heat Loss = = Area x U Factor BTU/Hr. AT Heat Loss Walls = 1800 ‘sq. ft. x .1 = 180 BTU/Hr.AT Heat Loss Windows = 200 sq. ft. x .45 = 90 BTU/Hr.AT Heat Loss Roof = 1600-sq: ft. x -.13 = 215.67 BTU/Hr.AT Heat Loss Floor = 1600 sq. ft. x .13 = 215.67 BTU/Hr.AT Subtotal Heat Loss Heat 701.33 BTU/Hr.aT loss due to airchange of .75/hour = .75 air changes (20000 cu.ft.) (.075 Ib) .24 BTU _ 270 BTU/Hr.AT Hour Ft.> Lb.AT Total Heat Loss = 971.33 BTU/Hr.AT Fuel Use Calculation: Average Temperature 31°F BTU/Year = 971.33 BTU/Hr.AT x ‘24 hr. day x 365 cays x (65°-31°) = 289.3 x 10° BTU/year = 6 BTU 1_gallon Fuel Use = 289.3 x 10 —“Vear i 30600 STU 000 BTU _1 gallons used = * 75 gallons effective ~ 2735.17 gallons Electrical Use Assumptions Page A-305 Lighting - 1944 kWh/year Refrigeration - 700 kWh/year Outlets - 2000 kWh/year Total 3644 _kWh/year Electrical Fuel Use for electric energy generation: (i) if supplied by private generators Assume 4.5 kWh/gallon 1_gallon 3644 kWh/year x ae kwh 810 gallons Community Center Total Approximated Yearly Fuel Use for village with noncentralized power: (ii) if supplied by a central plant Assume 8.5 kWh/gallon 1_ gallon 8.5 kWh Community Center total approximated fuel use for village with centralized power 3644 kWh/Year X = 428 gallons Post Office 3605.17 gallons 3223.17 gallons Assuming the post office is located in a residence it has the same heating and electrical load plus additional lighting. See average home electrical use. Average home - Included in Residential Use Additional Lighting - 1944 kWh/year Total Additional Electrical Use - 1944 kWh/year Page A-306 Electrical Fuel Use for village with noncentralized power: Assume 4.5 kWh/gallon 1944 kWh 1_gallon year. ° 4.5 kwh = 432 gallons Post Office approximated yearly fuel use for village with noncentralized power 432_gallons Electrical fuel use for village with centralized power: Assume 8.5 kWh/gallon 1944 kWh 1_ gallon Venn x 8 kwh 229 gallons Post Office approximated yearly fuel use for village with centralized power 289 gallons Then the total for public buildings are as follows: Approximated yearly fuel use for villages with noncentralized power 4037 _ gallons Approximated yearly fuel use for villages with centralized power 3512 gallons APPENDIX B TECHNICAL PERFORMANCE DATA AND DESCRIPTIONS Page B-309 B-1 SINGLE WIRE GROUND RETURN TRANSMISSION Page B-311 GENERAL CONCEPT MINIMUM COST TRANSMISSION SYSTEM Single Wire Ground Return Transmission of Electricity The Single Wire Ground Return (SWGR) transmission concept described in this proposal has evolved from a recognition of certain basic facts- of-life concerning electric energy in remote western and interior Alaska, which facts are: 1. Small electric loads and the geographic distribution of villages presently limit electric energy supply to small, inefficient fossil- fueled generating plants. oa Fuel prices in the western and interior regions, already uniquely high, face the probability of continued escalation. 3. Conventional three-phase electric transmission/distribution systems to intertie the outlying communities to more efficient generating plants are mostly impractical because high initial costs penalize the transmitted energy rates. 4. A transmission system using a Single Wire Ground Return (SWGR) line promises good electrical performance [1] [4] [7] [8] [10] and a substantially lower initial capital cost and therefore a lower transmitted energy cost than conventional transmission. 5 The SWGR line can be constructed using a high percentage of local labor and local resources in areas that need gainful employment as well as lower cost electricity. 6. The incentive to develop new, alternative energy sources (such as appropriate scale hydroelectric power in.the area) is dependent on an economically viable electric transmission scheme that can feasibly deliver such energy to the villages. The SWGR transmission concept is one which proposes to deal with these realities. While the use of a single energized wire and earth return circuit is unconventional in the sense that applications are not common, it is an accepted system of proven use in several areas of the world [7] [8] [9] [10[ [11]. Three phase equipment can also be successfully operated from this system by using phase converters [6]. The fifth edition of the National Electrical Safety Code (NESC) allowed the use of the ground as a conductor for a power circuit in rural areas; however, the most recent edition does not. It is the opinion of this writer that the SWGR system proposed here would in no way Page B-312 create an operating system with a lesser safety than the "conventional" system now in use throughout Alaska. Robert W. Retherford Associates has applied to the State of Alaska for an exception to the NESC to allow construction of a SWGR system. Verbal approval has been received, with final approval to be on a case by case basis, to construct demonstration projects using this principle. A project to supply central station electricity to isolated villages using the SWGR system is proposed. Such a project would provide a demonstration of the technical and cost feasibility of the system. The following pages provide a listing of objectives and a description of three alternate projects of increasing size and cost that will contribute valuable data for use in considering further extensions of such systems, Page B-313 PHYSICAL DESIGN AND CONSTRUCTION CONSIDERATIONS Lack of a road system, permafrost, and limited or no accommodations for construction crews throughout most of the region being studied establish some limitations that must be dealt with to find appropriate solutions. Conventional construction techniques and line designs might be used - but at premium costs. A design believed most adaptable to these limitations is based on the use of an A-frame structure shown in the following sketch labeled Figure 1. The arrangement is well suited to the SWGR design. It is believed that the design has certain features that will provide unique opportunities for its use over the terrain of this region, as follows: 1. The structure can be built using maximum local products and manpower. The legs of the A-frame can be made from local spruce that grows along the major river systems of the region and can be transported by these rivers. With this being done, 75% of the total line construction dollars could stay within the region. 2. The structure has transverse stability from gravity and need not penetrate the earth (permafrost in this region). Longitudinal stability is obtained through the strength and normal tension of the line conductor. This allows for use of the shortest lengths for legs to provide the ground clearances needed for safety. Additional longitudinal stability would be provided by fore and aft guying at suitable intervals. 3. The Single Wire configuration can be designed for minimum cost by utilizing high-strength conductors that require a minimum number of structures and still retain the standards for high reliability. For example: A single wire line constructed using 7#8 Alumoweld High Strength (approx. 16,000 Ib. breaking strength) wire, electrically equivalent to a #4 ACSR conductor will require one half as many structures per mile as the #4 ACSR under the same Heavy Loading Design Conditions. (The line could also be converted to 3@ at a future date by adding another structure in each span, and adding the new conductors. ) SPRUCE A-FRAME POWER LINE STRUCTURE PRELIMINARY DESIGN SKETCH age eel ALUMINUM TUBE SLRS FUTURE ADDED WIRE & INSULATOR SPRUCE POLE SPRUCE POLE. NOTES 1. Structures may be guyed fore and aft at intervals to limit the fall of structures should the line break. (Sometimes called "storm guys") 2s It is estimated that this structure using 30 ft. long local spruce poles would weigh a total of about 650 lbs., could be delivered and erected by men and snow machines. The heaviest piece is the 30 ft. spruce at about 280 lbs. A line constructed in this manner using one high strength wire could supply the electrical requirements as forecast for the villages of the proposed project. it¢ wW dlessear WwW. PETHERFORD ASSOCIATES z LT bf onsen FIGURE | Page B-315 4. The A-frame, gravity stabilized design form allows the use of a unique, engineering/construction technique that will substantially reduce both engineering and construction effort as follows: The high strength conductor is laid out on the ground between anchor points (at typical intervals of 1 to 2 miles) and tensioned while on the ground to the approximate stringing tension. An engineer and assistant locate structure points by using the tensioned conductor as a template (lifting it above the ground to observe clearances from the natural contour). This could be done in winter time by using snow machines rigged with a small "jig" to underrun the conductor and lift it to predetermined heights for observation. At points selected by the engineer, a crew assembles a structure completely and fastens it permanently to the conductor (all lying on the ground). The crew lifts the structure at the point of attachment while the stress in the conductor is being maintained at the appropriate stringing tension. (A typical structure with conductors in an 800 foot span might weigh 900 Ibs. complete. ). C4 Long -river crossings (typically 2000 feet or less in length) can be accomplished using the same high strength conductor. Several such crossings have been in successful operation in Alaska using this same 7#8 Alumoweld wire as follows: Naknek River (S. Naknek to Naknek) 2000 ft. Talkeetna River (near Sunshine) 1894 ft. Along Kachemak Bay, Tutka Bay 1835 ft. Sadie Cove 4135 ft. Halibut Cove 2070 ft. 6. Costs for an SWGR line constructed using the A-frame design and high strength conductor is estimated to be about one-third (1/3) the cost of an equivalent 3%, 4 wire line of similar capacity. Page B-316 The gravity stabilized A-frame line design using long span construction will provide excellent flexibility to adapt to the freezing - thawing cycles of the tundra and shallow lakes of the region. Experience in this kind of terrain has clearly demonstrated the need to "live with" these seasonal cycles and avoid designs that cannot tolerate movement of the structure footings. Gravel backfill around and under poles that are set in the earth using more conventional line designs has proven seccessful but usually expensive and in many areas of this region highly impractical because of lack of gravel. Hinged structures supporting large transmission line conductors (Drake, 795 MCM, ACSR, 31,700 Ib. strength, 1.094 Ibs. weight/ft. ) across shallow and deep muskeg swamps and permafrost have been performing excellent service on the lines from Beluga across the Susitna River and its adjacent flat lands. Some of this route has severe freeze - thaw action that has dramatically demonstrated the need for flexibility. These flexible systems have performed as intended during severe differential frost action. The basic structural philosophy and performance of this transmission line is reflected in the proposed A-frame arrangement described here. The experience with such existing lines provides the strong basis for confidence in the structural performance of this new design. Page B-317 ELECTRICAL CHARACTERISTICS Series impedances and shunt capacitive reactance for selected conductor sizes have been calculated using the following formulas [12]: Series Impedance 2 2160 J f Zg =r. + 0.00158 f + j0.004657F log,y GMR ele resistance of conductor per mile f = frequence in Hz p = earth resistivity in ohm meters GMR = geometric mean radius of conductor Shunt Capacitive Reactance a iy , Xe = oe 41/3 a in Megohms per mile ol = .0683 2 logio ¢ (Capacitive Reactance at 1 ft. spacing) tlds ees ae x il aT login 2h (Zero Sequence Shunt Capacitive Reactance Factor) h = height above ground in ft. it = frequency in Hz r = conductor radius in ft. The line data have been calculated with the following assumptions: Frequency: Height above ground: Earth Resistivity: © Ground Electrode Resistance: 60 Hz, 25 Hz 30 ft. 100 Ohm-m (swamp), 1000 Ohm-m (dry earth) R Ohms of each end Page B-318 60 Hz _ IMPEDANCES AND SHUNT CAPACITIVE REACTANCES Z_ (ohm per mile) R GMR(Ft) xX (om Diam. p = 100 p = 1000 (MegSohm Conductor Size Per Mile) Cinch) Ohm-m Ohm-m Per Mile) 7#8 Alumoweld 2.654 0116 2.449 + 2.449 + -244 385. ~j 1.504 j 1.643 266.8 MCM 735 5 OZ -445 + -445 + .229 ACSR 642 j 1.428 j 1.567 397.5 MCM .235 .0278 339.4 -33 + seer ACSR - 806 j 1.397 j 1.537 556.5 MCM -168 .0313 -263 + -263 + -218 ACSR -927 j 1.383 Jj) 1eS23 795 MCM BiiliZh .0375 sole * eile aes) 1.108 j 1.361 j 1.501 25 Hz IMPEDANCES AND SHUNT CAPACITIVE REACTANCES R GMR(Ft) Z_ (ohm per mile) xX, (Ofim Diam. p= 100 p = 1000 (Meg “ohm Conductor Size Per Mile) (inch) Ohm-m Ohm-m Per Mile) 7#8 Alumoweld 2.354 .0116 2.394 + 2.394 + -586 385 j .649 j .707 266.8 MCM 730 .0217 .390 + .390 + .549 ACSR -642 j .617 j .675 397.5 MCM 2235 .0278 .275 + sel + O83 ACSR 806 j .604 j .663 556.5 MCM - 168 .0313 -207 + .207 + 920 ACSR :927 j .598 j .657 795 MCM -117 -0375 2157 + .157 .511 1.108 j .589 j .647 [1] [2] {3] [4] [5] (6] Page B-319 LIST OF REFERENCES "A Regional Electric Power System for the Lower Kuskokwim Vicinity, A Preliminary Feasibility Assessment" prepared for the United States Department of the Interior - Alaska Power Administration, by Robert W. Retherford Associates, Anchorage, Alaska, July 1975. Alaska Electric Power Statistics 1960-1975, published by the United States Department of the Interior - Alaska Power Administration, Fourth Edition, July 1976. "Grounding Electric Circuits in Permafrost", a paper by J. R. Eaton, P.E., West Lafayette, Indiana (formerly Professor of Electrical Engineering, Purdue University and visiting Professor of Electrical Engineering, University of Alaska) consultant to Alyeska Pipeline Service Co.; P.O. Klueber, P.E., Senior Opera- tions Engineer, Alyeska Pipeline Service Co., Anchorage, Alaska and Robert W. Retherford, P.E. of Robert W. Retherford Associates, Anchorage, Alaska. January 1976. "Single-Wire Ground-Return Transmission Line Electrical Performance", a paper prepared for Robert W. Retherford Assocites by J. R. Eaton, visiting Professor of Electrical Engineering, University of Alaska, Fairbanks, Alaska, April 1974. "Ground Electrode Systems", by J. R. Eaton, Professor of Electrical Engineering, Purdue University, Lafayette, Indiana, sponsored by Commonwealth Edison Company, Chicago, Illinois, June 1969. "Performance Characteristics of Motors Operating from Rotary-Phase Converters", prepared by Leon Charity, Professor Agricultural Engineering, lowa State University, Ames, lowa, and Leo Soderhoim, Agricultural Engineer, Farm Electrification Res. Br. AERD, ARS, USDA, Ames, lowa. This paper was presented at the IEEE Rural Electrification Conference held at Cedar Rapids, lowa May 1-2, 1967. Paper No. 34CP, 67-268. [7] [8] [9] [10] [11] [12] Page B-320 "Rural Electrification by Means of High Voltage Earth Return Power Lines", by My E. Robertson, Paper No. 1933 presented before a General Meeting of the Electrical and Communication Engineering Branch of the Sydney Division on 27 August 1964. The author is the Design Engineer for the Electricity Authority of New South Wales, Australia. "Wire Shielding 230 kV Line Carries Power to Isolated Area" - an article which appeared in the July 15, 1960 issue of Electric Light and Power, written by D. L. Andrews, Distribution Studies Engineer and P.A. Oakes, System Analysis Engineer, Idaho Power Company. This article describes a 40 kV single-phase transmission line using earth return. "Single-Phase, Single-Wire Transmission for Rural Electrification", Conference Paper No. CP 60-883, presented at the AIEE Summer General Meeting, Atlantic City, New Jersey, June 19-24, 1960 by R. W. Atkinson, Fellow AIEE and R.K. Garg, Associate Member AIEE, both of Bihar Institute of Technology, P.O. Sindri Institute, Dhanbad (Bihar) - India. "Single Wire Earth Return High Voltage Distribution for Victorian Rural Areas", by J.L.W. Harvey, B.C.E., B.E.E., H.K. Richardson, B.E.E., B. Com., and |.B. Montgomery, B.E., B.E£.E., Messrs. Harvey and Richardson are with the Electricity Supply Department, State Electricity Commission of Victoria, Australia and Mr. Montgomery is Director and General Manager, Warburton Franki (Melbourne) Ltd. This paper No. 1373 was presented at the Engineering Conference in Hobart, Australia, 6 to 21 March, 1959. The paper recalls that "...... the system was first developed by Lloyd Mandeno of Aukland, New Zealand, who introduced it in the Bay of Islands area in the North Island of New Zealand in 1941. Since that time ....... thousands of consumers are connected to hundreds of miles of single-wire lines ...... In September 1951, the State Electricity Commission of Victoria erected a small experimental system at Stanley . following the success of the experimental installations the single-wire earth-return system has been very extensively used in Victoria... ." "Using Ground Return for Power Lines", by R.K. Garg (see [9] above) of the Bihar Institute of Technology - an article published in the Indian Construction News, June 1957. Electrical Transmission Distribution Reference Book, 4th Edition, 1950, copyrighted and published by the Westinghouse Electric Corporation, East Pittsburg, Pa. Page B-321 B-2 DISTRIBUTION AND TRANSMISSION LINE LOAD LIMITATIONS Page B-323 DISTRIBUTION AND TRANSMISSION LINE LOAD LIMITATIONS The amount of power that can be transmitted over a distribution or transmission line is limited by: e current carrying capacity of the conductor e tolerable voltage drop e electrical system stability. System stability considerations have to be determined for individual cases and current carrying capacity depends strictly on conductor material and size. Voltage drop, however, is a limiting factor dictated by line length, operating voltage, load, and conductor size and configuration. - Moltage sent - Voltage received Voltage Drop (%) = Voltage received x 100 Maximum tolerable voltage drops are for: Distribution Lines (up to 24.9 kv)? 6.67% Transmission Lines (from 34.5 kV up to 138 kV)? 5-7% The following tables show load limitations in form of Megawatt Miles for various distribution and transmission lines. For distribution lines calculations were performed in accordance with REA Bulletin 45-1 where: apa HH VD) (kV?) (cos 0) P Megawatt Miles =~. Uk cose ean ©) 100 Where VD = Allowable voltage drop in % kV = Line to ground voltage 8 = Phase angle between voltage and current P = # of phases R = Resistance in ohms per phase per mile of line x = Reactance in ohms per phase per mile of line 1 REA Bulletin 169-27, January 1973 2 Standard Handbook for Electrical Engineers. Fink & Carroll. 10th Edition. ’ Page B-324 For transmission lines tables published in REA Bulletin 65-2 have been utilized and for Single Wire Ground Return Lines the following formula? is considered to render adequate results for preliminary investigations: we a X 1 Vy I? - ( ) (R2+X2) Receiving End Voltage = Vi TX cos 6 + R sin 5 Where Vi = Sending end voitage in kV R = Resistance in ohms per phase per mile xX = Reactance in ohms per phase per mile 6 = Phase Angle between the two bus voltages 8 =isin =? [ ¢ Paz ¢ eae 4 4 IViIIVel 4 Where Pio = total real power (MW) The reactive power Qio = Q? + Q Loss - Ye V,2 hers Qe = Receiving end reactive power (MVAr) Q loss = Line loss reactive power (MVAr) Ye = Shunt capacitive admittance in Meg mhos per mile It should be understood that this formula can only be used for "short" line models (up to 50 miles) and that the following assumptions have been made: 1. RS1/5X 2. 6 and Vz are calculated by solving for each alternatively, assuming 6 $ 10° 3. V4 and V2 differ less than 10% 4. Line Length 1 mile The load limitation given in Table B-2 can be used for preliminary feasibility investigations. For actual line design more accurate calculations are mandatory. 1 From: Electric Energy Systems Theory by Olle I. Elgerd. Published by McGraw-Hill, Inc. Appendix B - Technical Data BRIS4/11 DISTRIBUTION LINES (6.67% Voltage Drop) TABLE B-2 LINE LOADING LIMITS IN MEGAWATT MILES. IN REGARD TO ALLOWABLE VOLTAGE DROP FOR SELECTED CONDUCTOR SIZES Conductor 7.2kV-1g 7.2kV- 14. 4kV-18 14. 4kV-39 Size - AWG F. P.F. PF. PF. PF. Pie PF. Pets Bis PF. P.F. PF (ACSR/AAC) 9 +95 1.0 9 95 1.0 9 95 1.0 9 +95 1.0 a. ist ie2 1.4 3.9 4.1 4.6 4.3 4.7 5.6 15.5 * 16.7 18.9 1/0 1.9 2.2 3.1 8.3 8.9 11.7 7.4 8.4 12 33.3 36.7 46.7 4/0 2.8 33 5.4 13.3 15.5 23.3 FY 13 21 51 60 2 397.5 - - - 19 23 44 - - - 14 Ey 173 Based on lines of Standard REA Desiga Transmission Lines (5% Voltage Drop) Conductor 69 kV (8.54' equiv. spacin, 116 kV (13.48" equiv. spacing) 138 kV (19.53' equiv. spacing) Size - AWG P.F. PF. (giz P.F. Pe: Bat; PF. PF. Pe. (acsr) 73 -95 1.0 9 95 1.0 i) -95 1.0 Partridge 266.8 307 362 573 819 973 1571 - - : IBIS 397.5 370 450 788 980 1197 2142 1359 1668 3030 Dove 556.5 423 526 997 112 1389 2685 1535, 1924 3770 Drake ss 795 476 * 603 1228 1243 1581 3271 1706 2178 4556 Single Wire Ground Return Lines (5% Voltage Drop) Conductor Size - AWG 40 kV 66 kV 80 kV 133 ay (ACSR unless P.F. P.F. v2. Er otherwise noted) s Ss 3 A 708 Alumoweld 2s* 65* 9s* - Partridge 266.8 70 180 : 265 720 IBIS. 397.5 75 200 290 800 Dove 556.5 80 215 31s 860 Drake 795 85 225 335 910 Ground resistivity = 100 ohm-m (characterizes swampy wetlands). account. *Calculated using A,B,C,D constants for 50 mile line model. Voltage drop at the ground electrodes has not been taken into §ze-g abe Page B-327 B-3 ECONOMIZING DIESEL GENERATOR PLANTS Page B-329 ECONOMIZING DIESEL GENERATOR PLANTS IMPROVING THE LONGEVITY, FUEL ECONOMY AND LOWERING INSTALLATION COSTS OF DIESEL ENGINE GENERATING PLANTS FOR BUSH VILLAGES The diesel engine has no equal when it comes to squeezing useful energy out of a pound of fuel. Big steam and nuclear plants can run cheaper only because they use cheaper fuel. The efficiency of the diesel engine reigns supreme. At part power the diesel's efficiency advantage is even greater over all others. For this reason the diesel engine generating set is the popular choice for bush village power. It is possible to improve these installations. Life gains of a factor of almost two are possible, and fuel economy can be improved by equally impressive amounts. Total installed power can be reduced, and reliability can be almost doubled. The "conventional" diesel engine generator set runs continuously at its A.C. synchronous speed. At full load this is the diesel's best operating point. As the load is decreased at this synchronous speed, the diesel moves into operating conditions that go from ideal, to wasteful, to harmful. A diesel engine running full speed but producing only a fraction of its rated power may be using twice as much fuel as necessary, may be wearing out three times as fast as necessary, and may be "slobbering", "wetstacking", "sooting", "diluting", "sludging" and corroding. If we run the engine at the speed where it produces small amounts of power ideally, none of these problems need exist. A 300 HP, 1800 RPM engine is a very poor 30 HP, 1800 RPM engine, but may be a very good 30 HP engine at 600 RPM. Engines have "Power Curves". There are several of these. One curve is the "Maximum Power Curve", which is the power the engine can produce at various speeds for a short time under laboratory conditions. A second curve, the "Intermittent Power Curve" is the power the engine can produce at various speeds for a short time, usually one hour. A third, the "Continuous Power Curve" is the power at various speeds the engine can produce continuously day in and day out. These are the usual curves. A fourth curve is the "Minimum Fuel Rate Curve". This is the power the engine can produce at various speeds at highest efficiency. Page B-330 A fifth and seldom precisely known curve is the "Minimum Wear Power Curve". This is the power the engine will produce at various speeds with minimum wear. There is such a curve but it is very hard to establish as it is dependent on so many variables. It would be near the minimum fuel rate curve because retained heat is what really damages engines. At minimum fuel rate the least heat is retained in the engine for its cooling system to handle. Unfortunately, most engines are sold on the basis of the "Intermittent" or "Continuous" ratings. No thought is given as to where the engine could be at its best at some lower power. Some engine companies’ have complete performance data. Some do not. All engines have these performance characteristics even if the maker does not know them or publish them. Figure B-3-1 shows the relative fuel rates. The solid curve is setting the engine at its best fuel rate speed for each power. The dashed curve is for an engine as conventionally used at constant 1800 RPM for all powers. Figure B-3-2 shows relative wear rates. The solid curve is when the engine is set at its best speed for each power. The dashed curve is for a conventional installation running at 1800 RPM constantly. A power plant which has varying load thus should ideally be equipped with a device which would allow the engine to run at its "best fuel economy" speed for each power demanded. This curve is quite easily determined. This device would be an "infinitely variable ratio trans- mission". These are quite available and at all power levels from multi-thousand horsepower to fractional horsepower. Unfortunately, these devices are not very efficient and are very expensive. They would enable us to hold the engine at its best speed while the alter- nator ran at a constant 1800 RPM. The inefficiency and cost of these infinitely variable speed transmissions would from the beginning eat up any possible saving they enabled. Another great feature of the diesel comes to our rescue. The diesel is quite flexible; it does not exhibit peak inefficiency at a sharp point, but more of a plateau of good efficiencies. This means that if several fixed speeds are available using multi-speed geared transmissions of good efficiency and cheap price, the economies of matching speed to power at best fuel rate can be obtained. _ Page B-331 The following table shows performance rates which have been calculated from available data on Cummins Diesel Generators in conjunction with a transmission having a ratio of: anogks Teds 1.00%: .81 a ee The best fuel rate for a Cummins C-220 Engine (110 kw at 1800 RPM) (kWh/Gal or Ibs/BHPH) can be maintained in the following ranges: Load Range % of Rated % of Nominal Load RPM at Rated RPM 100 100 - 68 81 82 - 45 63 64 - 27 At 123% of rated speed 123% of the rated load can be supplied at a fuel rate that is 10% below the best possible rate. The preceding table shows how much saving might be obtained by wise application of a four-speed gear box. The savings are: Less wear simply by "revolutions not turned"; Less wear and damage by operation in near ideal load ranges; Less wear because of lower speed giving less dynamic ioading; Better fuel economy; Less installed power required because of more ideal load and power matching. ubwn- These savings have been habitual in most diesel engine applications except generation of 60 cycle AC power. The concept is used in every truck, locomotive, tractor, and crane. The controllable pitch reversible propeller has been giving these same savings for years in boats. All of these applications could get along without variable ratio gear boxes if powered like we conventionally do in generation, i.e. use engines bigger than any conceivable load and run them mostly at low load. No one could afford this. We need not afford this in generation. The method above can do the trick. LBS FUEL’/ BHP HR. MINIMUM FUEL RATE RPM 50% PERCENT ENGINE POWER FUEL RATES wef a B-3,1 100% zee-g e6eg Page B-333 1800 RPM CONTINUOUS POWER SPEED RELATIVE WEAR PER KWH ~ Se ~ ~— Tr aay —" w te ine 50% 100% PERCENT ENGINE POWER RELATIVE ENGINE WEAR B-3.2 Page B~-335 B-4 PHASE AND FREQUENCY CONVERSION IN POWER TRANSMISSION Page B-337 PHASE AND FREQUENCY CONVERSION IN POWER TRANSMISSION Power transmission lines are limited in their capacity to transport energy by conductor sizes and voltage levels. Theoretically higher operating voltages and larger conductors will allow transmission of higher loads over greater distances. Load and distance of transmission will cause the voltage to drop. If this drop exceeds 5-7% of the nominal voltage either load or distance have to be decreased or a higher voltage level and/or larger conductor have to be chosen. Construction and operating cost will limit operating voltages and conductor sizes however to the most economical level for any particular case. In Alaska, where small communities with low energy demands are separated by great distances, conventional transmission lines will - in many cases - have to be designed for voltage levels that are too high to allow economical installation. The Single Wire Ground Return transmission scheme is an attempt to make tie lines possible where conventional 3-phase lines would be too expensive to be built (see Appendix B-1). If this scheme is utilized at a lower operating frequency the load or transmission distance could be increased by an amount that is proportional to the new value for the frequency. Railroad electrification in the U.S. as well as in Europe has utilized reduced frequencies (25 and 16 2/3 Hz respectively) to maintain adequate voltage levels over great distances. Generating plants, transmission lines and substations have been built exclusively to supply the railroad distribution network with single phase, low frequency power. : Interconnections between three phase, 50 or 60 Hz systems and single phase, 16 2/3 or 25 Hz systems have been made via rotating converter sets up to 45 MVA1!°°. Static frequency/phase conversion equipment is available, but presently not an "off the shelf" item for small (1-2 MW) applications. It is, however, conceivable that this type of power transmission and conversion can be economically feasible where conventional transmission lines would be too expensive. In case of a remote hydroelectric plant for example the power can be generated single phase at low frequency, the voltage stepped up to transmission level and transported to the point of utilization where, after voltage step down, phase and frequency can be converted to the required system levels. Since accurate cost estimates for conversion equipment could not be obtained in time to be used for this study, the potential benefits are shown for a hypothetical case. Page B-338 Transmission line capacity is shown here in terms of Megawatt miles at 5% voltage drop, .9 power factor for: MEGAWATT MILES CAPACITY THREE PHASE TRANSMISSION, 60 Hz SINGLE WIRE GROUND RETURN, 60 Hz and 25 Hz CONDUCTOR THREE PHASE SIZE 60 Hz (AWG) . 34.5 kV 69 kV 138 _kV 266.8 ACSR 78 295 -- 397.5 ACSR 94 353 1359 556.5 ACSR 108 401 1535 SWGR 60 Hz 40 kV 66 kV 80 kV 133_kV 266.8 ACSR 70 180 265 720 397.5 ACSR 75 200 290 800 556.5 ACSR 80 215 315 860 SWGR 25 Hz 40 kV 66 kV 80 kV 133_kV 266.8 ACSR 110 300 440 1200 397.5 ACSR 135 360 540 1440 556.5 ACSR 150 410 600 1640 See Appendix B-1 and B-2 for method of calculation. The construction cost of SWGR transmission are estimated at approximately 30-40% of a three phase transmission line. For a rough comparison the following cost can be used: 34.5 kV 39 $ 80,000/mile (conductor to 556.5 ACSR) 69 kV 39 $100,000/mile (conductor to 556.5 ACSR) 138 kV 39 $125,000/mile (conductor to 556.5 ACSR) Page B-339 Transmission line cost for the following assumptions are then: Power to be transmitted 6 MW Distance 50 Miles 36 - 69 kV, 397.5 ACSR $5,000,000 SWGR (60 Hz) - 80 kV, 266.8 ACSR $2,500,000 SWGR (25 Hz) - 66 kV, 266.8 ACSR $2,000,000 The achievable cost savings if SWGR transmission is employed are: $2,500,00 to $3,000,000 which would allow an expenditure of $416 to $500 per kW for phase and frequency conversion equipment. A rotating converter set of this size (6 MW) with controls is estimated to cost approximately $300/kW. Preliminary cost estimates for static converters received from a manufacturer indicate $200/kW per terminal. Conversion losses are estimated at 6% at each terminal. Generating equipment for single phase, reduced frequency operation are anticipated to be between 10 and 20% more expensive for an equivalent power output than for three phase equipment. To demonstrate the benefits of reduced frequency operation for power transmission systems more clearly, investigations in regard to the availability of conversion equipment as well as the capacity and cost are necessary. The evaluation of a particular project installed with conventional and low frequency, single phase equipment will then show the possible savings. 100 101 102 103 Page B-340 BIBLIOGRAPHY "The Largest Rotating Converters for Interconnecting the Railway Power Supply with the Public Electricity System in Kerzers and Seebach, Switzerland" Brown Boveri Review, November 1978. "Electrical Transmission and Distribution Reference Book", Westinghouse, 1964. "Standard Handbook for Electrical Engineers", Fink and Carroll, 10th Edition. "Electrical Engineers' Handbook", Pender, Delmar, 4th Edition Electric Power. Page B-341 APPENDIX B-5 WIND ENERGY CONVERSION & WIND ENERGY CONVERSION SYSTEMS ECONOMIC PAYOFF TIME Page B-343 BASIC DEFINITIONS AND METHODOLOGY The following explains the basic approach used: The primary criterion for determining the feasibility of WECS use is the average wind speed V at the rotor hub height h of a WECS. An annual V of 12 MPH is desirable, but lower V may still be useful in energy-deficient areas. The principal equations below will be used, always leading toward the calculation of the average power P,, produced by a wind machine. Thus, monthly and annual V for each community are sought. Ap Power in the Wind (no WECS involved here) A wind with instantaneous speed V will have an instantaneous power density or flux P/A (for a vertical or "sheet of wind" area A) of = 3 : PY/A Bice Ve (1) Cy depends on the units of A and V, and the air density. The average power flux PLA in a wind regime (the collection of V values over a long period, say a month or year) is not a 3 PY/A eo Vie (2) but is P/A = f(k) C, v¥. (3) The value of f(k) depends on the speed distribution of the winds, i.e., the shape of the so-called frequency distribution curve. For Alaskan winds f(k) = 2.14 is a good value for estimation purposes, and it is used herein when actual f(k) are not known. Then, for A in square meters, V in miles per hour (MPH), C_ is 0.05472 if P. is in watts (w) and equation (3) becomes o ha P./A (w/m?) = 2.14(0.05472) v3 (MPH®) or P./A = 0.1171 V3, (4) So, a rough "rule-of-thumb" is that the average power flux of a wind regime is 1/8 of the cube of the average wind speed, for the units given above. However, see the caution under "Power Output of a WECS" regarding use of equation (4). It is important to remember that the above refers to the power (or energy content) of the wind. Now the question of the energy ex- traction by a WECS must be considered. In the following this is done, in terms of average power delivered at the output of the wind-driven turbine (generator), with no further losses such as those due to transmission lines, inverters, etc., being considered. Page B-344 23 Power Output of a WECS The average power produced by a specific (model, size, etc.) WECS is defined as Pu: One can define an analog to the wind flux Pasa by Py/As where in the windmill case A is the disc area swept out by the blades. There is no theoretical simple relationship between ea and Pur except that, of course, the larger the ee the larger the expected Pu: Detailed calculations of the coupling of a windmill with a given power characteristic (Pry vs. V) and the actual full wind distribution curve for_a given location lead to a set of values Pur V. This is displayed in Figure B-5.1 with the associated computational procedure given later. One must be careful.in applying equation (4) to engineering situations. While the mean wind power flux is useful as a guide to determining the wind power potential of a site, the P/A is appreciably greater than Py/A- First, only 59.3% of PY/A at most can be extracted by an ideal single unshrouded disc WECS, and then only if the WECS operates at all V in the wind spectrum. This is a fundamental limita- tion (like the Carnot Law). In practice cut-in and cut-out V of a WECS make some of the wind spectrum unusable. Second, for a rotor the efficiency or power coefficient at various V is variable, ranging from zero to some maximum value (0.3 to 0.45 at best) and then back to zero, for increasing V. This power coefficient depends on the ratio of the wind V/rotational speed of the blade tips. There are additional inefficiencies, as in any geared rotating system. Thus, in practice the Pruy/A of contemporary wind machines will be of the order of 1/5 to 1/10 of PA. Tables illustrate this variation. Page B-345 furling~, WECS CHARACTERISTIC | | 1 | hel Le 1 | a Lat | | ro} | %tV2V 100 oavee ft oO | | | 1 y Y 1 ty | } {00 1} | | 1 | a ee i ie Lr | I | { ri %ot, ! V2V al 1 Prated—! [a ee Ee 0 ~=— P 0 Figure B-5.1 COMBINATION OF A WIND SPEED DURATION CURVE AND WECS POWER CHARACTERISTIC TO OBTAIN THE WECS TOTAL ENERGY PRODUCTION For the WECS, Y= limiting V; v.= cut-out or furling V Tne average power P is obtained from the total energy produced . (shaded area): divided by the total absolute time of the measurement period of the duration curve (taking into account that the curves above express time. as a percentage of the period involved). Page B-346 3. Computation Method Given the assumption of a specific WECS installed at a hub height h; (above ground) where the average wind speed is Vie the mean average power Pu from the WECS can be predicted from simple empirical equations. These are of the polynomial form 2 Ve + a v3 (5) Pry (kW) =a, ta 3 V, +a 1 2 The a; depend, of course, on the machine selected. Table B-5.1 gives the a for two contemporary machines; one is rated (maximum power) at 15 kW, the other at 100 kw. For most locations the h; of installation will be different from the he of anemometers yielding the measured Va The key relationship here is c p V,/V, = (h,/h,)P, (6) where a good approximation is p = 0.2. Equations (5) and (6) are the most important equations used herein. Justification of these, especially in determination of the ay is outlined here. The first step in getting the a of equation (5) requires that the frequency statistics (% of the time the wind blows at a specific V) are summed in a way to yield the V and also the so-called wind speed V duration curve. The latter gives the fraction or percentage of the time of the measurement period that the wind blew at V or greater than V. The duration curve is then coupled with the WECS power characteristic Pu vs. V to provide a third curve giving the percentage of time the WECS delivers a given P. See Figure B-5.1. The area under this last curve is then the total energy extracted by the WECS, since the product of power and time is energy. Thus this total Page B-347 energy divided by the absolute time (e.g. in hours) of the V measure- ment period gives the average power Pu for the period involved. In this way a large number of V statistics from the wind regime are boiled down to a single Pur V point characterizing the behavior of a given WECS at a specific location for a selected period. Then a large number of such points can be used to obtain plots like Figure B-5.2, and curve fitting computer routines yield fits (give the a;) corresponding to the plotted points. For example, several hundred duration curves from 50 Alaskan sites have been treated to arrive at the constants of Table B-5.1. TABLE B-5.1 AVERAGE POWER OUTPUT POLYNOMIAL COEFFICIENTS FOR CONTEMPORARY WECS Plkw) = a, + ay Via V + a, v; V in MPH Max. P a ay ay a, (Rated P) - 15 kW -0.247 -0.1169 4.333 E-2 -9.041 E-4 100 kW -19.59 3.222 0.1935 -7.280 E-3 P, EW (V, = 40 weH) 10 v FIGURE B-5.2. P VS. V FOR NASA 100 KW MOD O WECS (PROTOTYPE) NASA 100 KH MOD O (F1) 30 KPH 13 w/s 8re-g eBeg Page R-350 WECS ECONOMIC PAYOFF TIME by Tunis Wentink, Jr. Geophysical Institute University of Alaska Fairbanks, Alaska 99701 November 1976 (Reissued April 1979) This is a working paper first issued in 1976 as part of an unpublished report to the U.S. Energy Research and Development Administration. An abbreviated version was published in 1977, but there were unexplained serious omissions. Because of continued interest of others in this work we issue it again, with only minor changes in the introductory paragraphs. The cost-effectiveness of a WECS can be judged in various ways some quantitatively and some only qualitatively. In the latter case, for instance, if wind is the only energy source the main judgment is what is the energy worth to the user. Then WECS costs must be related to convenience, life style and other difficult-to-measure considerations. In the former case, the main criterion is usually how well the WECS will compete economically with other energy systems (e.g., diesel- driven generators) already in place. Page B-351 In gauging this economic competition one can either use the payback period method or the cost per kWh method; Marshall (1978), for instance, used both and compared them. His analysis used discounted loan rates, present worth refinements and a fixed loan (for the WECS) period equal to the assumed WECS life time of 20 years. Wentink (1976) used a somewhat different approach, in that the loan period was computed to be that in which the loan for the WECS would be paid off through the cost savings in fuel for the competing oil-fueled electricity. generator. A use factor for the WECS-derived energy was also introduced, since non-use of the wind energy naturally increases the payoff time. Wentink's abbreviated analysis was published incompletely; the necessary equations and figures were inexplicably omitted! The full analysis follows. Some Alaskan examples used now obsolete fuel costs but have not been updated. New fossil fuel rates will only reinforce the conclusion that (especially for many remote villages) the capital costs of an installed WECS can be paid off by fuel savings in about five years or less. For the oil-fueled (diesel) generators we used energy conversion efficiencies (1/G) 7.4 to 12.5 kWh/gal. The former value is the average for the spasmodically loaded Alaska Village Electrical Cooperative usually high speed medium (100-300 kW) machines. The latter value is near the limit of more efficient large Stesul=drtven giqiextors operated mostly at full load. An actual example is for the small utility at Cold Bay; at about Page B-352 225 MWh sold monthly the average 1/G is 11 KWh (sold)/gal. In actual cases one must de-rate 1/G considerably if load variations cause the diesel to idle or run at low efficiencies for appreciable periods of time. We use a first cost of oi] (Fo). taken as the price per gallon of oil at the time the WECS is installed (and begins operation). The oil cost is assumed to escalate at a constant percentage rate (R) or con- stant fractional rate (r) yearly over the life (t) of the loan for the WECS. While we have used r = 0.07 (7%) in some calculations, in Alaska and many other locations r over the past few years has been about 0.34 (34%), and even more for remote arees. For instance, at Cold Bay, readily served by tankers, oil for the utility went from 25¢/gal in November 1973 to 45¢/gal 2 years later. The 7% escalation rate thus is more of an anticipated inflation rate, and does not take into account any future untoward OPEC price actions. We are probably optimistic. For a wind regime characterized by v, (annual), and for a WECS power productivity of ¥, (annual, in KW) the total value (dollars) of wind- derived energy (KWh) for t years, compared to oj] doilars saved, is equivalent to 8760 t P GF Fy (26) where F is the average cost of the oil (per gallon) over t years. We assume that the oi] saved would otherwise be paid for yearly, by cash, with no loan involved. The wind energy use factor (fy) is unity or less, and is treated later. Page B-353 F is calculated on the assumption that the same number of gallons n of oi] would be used or saved each year, so that nt is the total oil volume saved. Then the total cost of the oil for t years is nF C1 + (Ter)! + (ter)? + 2. + (Ter)® + a(tery® 71], ar) where A is the fraction of a year when t is not integral. Thus, for t = 7.6 years, 7.6 7 x (1#r)7-6 = (ler)? + 0.6(14r)®, (28) 0 0 For convenience, let t t £ (ltr) = rf(r,t). 0 Then, Fe : F 3 =e rf(r,t). (29) The loan (principal L, in dollars) taken to purchase and install the WECS is to be paid back in yearly payments for t years, at fixed yearly rate I or fractional interest rate i. Hence, the total of the payments (T) (k + interest) is, from the usual formula for paying off a loan in equal payments, TetLa Gye (30) (141) e1 Then, if t is the number of loan years so that the installed cost and interest of the WECS are balanced by the cost of the fuel oil savings, ¢ 30 ; from equating Ef) and (3) and rearranging, with the use of (29) Page B-354 8760 Ps G fo ty eaaenit s ti(iti) r (31) (141) ®-1]s#(r,t) We found it easiest to solve for t by successive approximations, when equation (31) was expressed in the logrithmic form. A small programable desk computer (Tektronix 31) was adequate for this purpose. The Use Factor, f In the ideal situation fy = 1. This assumes that all the energy produced by the WECS is used, and so represents an equivalent oi] savings. If any of the wind energy is wasted for any reason, the rate of pay-off of the loan is effectively reduced (payoff t is increased), and also oi] must be consumed to compensate for the wind energy expected but wasted; then ta is less than unity. An fe below one can be inter- preted in various ways. One way means that the WECS effectively is competing with oil less expensive (as far as the diesel is concerned) than the actual cost of oil otherwise being paid by the WECS owner. Thus, for f, = 0.6 and oil costing 75¢/gal, the WECS is replacing 34¢/gal oil. The effects of calm and wind periods with V below cut-in do not enter into our f,, being included in the P calculated for a given V. However, unless specified otherwise, these P are those from the WECS system before the addition of additional conversion devices like rec- tifiers, batteries, or DC-AC inverters. Even if there are always available some use or storage capability for the wind-derived energy, there are inherent losses. For instance, lead-acid batteries are at most 85% energy efficient in charging. The best DC-AC inverters we know Page B-355 oF are 90% efficient when operating at full load, and much less at below full load. Thus, fractional efficiencies of 0.77-or less, or losses (other than in ikea? loads) of 0.23 or more can be expected when bat- teries plus inverters are employed. Additionally, field tests by others have shown that, unless care is taken in matching and switching of loads during varying wind conditions losses of the order of 40% of the wind energy can be readily encountered. For example; say the WECS is operating at P = 2.1 KW (V = 15 mph). For 50¢/gal oil converted to electricity at 7.4 KWh/gal, the idealized (fy = 1) payoff period would be 7.3 years. However, if there were 37% waste of the WECS energy, so that the effective P were 1.3 KW, the pay- off period would be 11.8 years. This difference in loan periods in- volves an appreciable amount of interest on a $10,000-7% loan, being about $1900 when paid back in yearly installments. Figure 6 shows the payoff time for a windmill having a power characteristic like the Elektro WVG-50G (6 KW rated), presumed to be installed at a cost of $10,000 (=L). The effect of first oil costs of 0.50, 1, and 2 $/gal and oil-to-electricity conversions of diesel generator of 7.4 and 12.5 KWh/gal are shown, for various V of Alaskan wind regimes. Steady annual interest rates and yearly escalation of oi] costs of 7% each are assumed for Figure 6. Figure 7, for the Grumman Windstream 25, 15 Kw rated, is based on 10% for I and R. The latter figure seems pessimistic. However, as shown on the next page, a set of relatively small changes in costs and circumstances can change the pay- off time from 15 years to 8 or even 5 years. Page B-356 Figure 6 WECS PAYOFF TIME VS. MEAN WIND SPEED FOR DIFFERENT FUEL COSTS AND DIESEL EFFICIENCIES. (for Elektro 6 KW WECS) & wasaWINiw MIdved HAVN NINTIBIA W-OVvVE ‘ON ‘vy "3 "NN BQWW tA NAAT ANAAND 4 4 2 2] Se Be oe ee ee lll Figure 7. WECS PAYOFF TIME VS. MEAN WIND SPEED FOR DIFFERENT USE FACTORS AND GENERATOR EFFICIENCIES (for Grumman 15 KW prototype) Page B-358 Similar curves for these rates but for other combinations of first oil costs, diesel generator efficiencies, and use factors can be deduced For instance, one can prepare plots of the loan payoff time vs. the dimensionless factor Fy G q for given V and the machine specified. We found convenient in considering vardous situations (different machines, different wind regimes, etc) a generalized version of equation (31), which is 7 jvt Cc Se ee: 32 3 casi)" ryeF(r,t) i where C3 = C, Cos calculated from C, = 8760 Pa/t and Cy = FS G fy3 Cy is a measure of the WECS installation at a given site, while Cy isa Measure of the competing oil-fed generator. Figure 8 shows: curves from equation (32), for I = 10% and R ranging from 7 to 20%. We considered various smal] WECS operating in the range V = 10 to 25 mph, of sizes so that E is from 0.5 to 10 KW, with installed costs of $6,000 to $25,000 and ‘ = 1.0 to 0.5. O11 costing in the range of 40¢/gal to $2.5/gal and used in the generators yielding 7.4 to 12.5 KWh/gal lead to C, from about 0.006 to 1.5. For our well-worn Elektro example, if L = $10,000., in the V range cited above C3 varies from 0.011 to 1.18. While the wide C3 spread depends on all the variables for a location and user system, it is most sensitive to Ls (i.e., V). In this spread of C3 the payoff time can be between 33 years and 1 year, for i = 10% and r = 7%. It is equally sensitive on a percentage basis to the delivered cost of oil, the use factor, and the loan cost, the latter a reflection of the cost per installed KW. The greatest chance a WECS PAYOFF THROUGH OIL SAVINGS. sae) t e7co P tar = tit Ou : uo (asi) it ae ee ee t 1G 152 3 t t t C(1+4)*1] 9 (tr) 6 C, = 8760 P, (KWh/yr) Cy = (Fy $/ga1)(6 gal/Kuh) Ff, “OC Wlar. | i= LOAN INTEREST RATE F = AVERAGE OIL COST OVER PERIOD t ($/ga1) } r= OTL (INFLATION) RATE INCREASE F = FIRST OIL COST ($/ga1) t = PAYOFF TIME OF L (YEARS) pip F, x cary? ‘0 L = WECS COST (INSTALLED) 1/G= ELECTRICAL ENERGY YIELD OF DIESEL GENERATOR (KWh/ga1) P_= AVERAGE POWER FOR GIVEN WECS ANO ; ra = USE FACTOR (WECS ENERGY); UNITY OR LESS SITE AVERAGE WIND SPEED 6SE- g abeg 5 r o | ~ ! 1 : sey p eer amend ' ' ~ | Page B-360 a { ao Ses pe a ween fee ene pw emcee en enh cwcmmnm 9s ee 10 f. eee. ~- 2. x: pees is — ee ee pid crdreeics: tema lon 4p ae tS Be ed eae nabemreren een = OTe Tas —2=—a-— Ec. iS a Se S ees =f re <7 ee ey eee TQ QW S=- _ Ey £ $3 as en - 5 ee x a ee Sees ~F-n Wy - pees ee Bins B-8- Ye Gait ths sen "is Suse 8 Wyk: Dim 35 sF I> Gt Sec enieseon 2 | rece ; x 2) co YU wb + Figure 8 WECS PAYOFF TIMES VS, C3 FOR VARIOUS INTEREST AND INFLATION RATES. = Paae B-361 for reduction in the payoff time and actual costs seems to be through WECS cost reduction through mass production. In practice, time will increase the cost of oi], decreasing payoff time. Another example is that of a Grumman Windstream 25 (15 KW rated) assumed to be installed at Cold Bay, for $25,000. There V = 17.4 mph, so Fe = 6.1 KW. We assume that f, = 0.7, F, = 50¢/gal, and the alter- native diesel-powered generators yield 11 KWh/gal (1/G). Then Cy = 2.10°and C, = 0.032, hence C3 = 0.068. For 10% loan interest and oi] escalation at 7%, t for pay-off is then 15.6 years, not satisfactory. Now suppose that we could reduce purchase costs (so L = $22,000), get a 6% REA loan, FS has reached 60¢/gal by the time the WECS is installed (but still rises at 7% annually), and refine the use of the wind energy so that f, = 0.8. Then C, = 2.42 and C, = 0.044; then C, = 0.106 and the pay-off t = 8.1 years. If the cost of oi] were the only change in the last situation, at 75¢ or $1/gal, the pay-off would be 6.4 or 5.3 years, respectively. Page B-363 B-6 POTENTIAL HYDRO SITES Page B-365 14 Nushagak Bay/Wood River - Tikchik Lakes Page B-366 Location [1] Alagnak River with a dam site in NE of Section 15 in R39W, T13S on USGS-Map Iliamna A-8. Capacity (Est. ): Drainage area: 480 sq. mi. Average flow: 1250 cfs Mean effective head: 170 feet Regulated flow: 437 cfs Dam: 150' high to Elev. 750 Tunnel: 5900 feet, 15' dia. Penstock: 2800 feet, 102" dia. 5200 kw Install 2x5000 kW 45552 MWH/Year Cost of Installation (Est. ) Load Center(s) and Distance $29,900,000 Dillingham approx. 100 miles $/kw 5750 Naknek approx. 65 miles Access Land Status Air or overland vehicle Located in Mt. Katmai National Monument Wild and Scenic River Environmental Considerations Not determined. Impact on Fisheries Important sockeye salmon spawning system, dam would prevent access to Kukaklek Lake system. Recommendations Land status and impact on fisheries preclude development at this time. Page B-367 ALAGNAK RIVER MAP PORTION FROM USGS : ILIAMNA A-8 Page B-368 Location [2] Agulowak River with a dam site in Section 9, R57W, T9S as shown on Dillingham B-8. Capacity (Est.) kW - Not determined. MWH/Year - Not determined. Bulb turbine application. Cost of Installation (Est. ) Load Center(s) and Distance $ ; Not determined. Dillingham approximately 30 miles. $/kKW ; Access Land Status Lake Aleknagik Open. Environmental Considerations Not determined. Impact On Fisheries Very important salmon stream, any interference is considered objectionable. Recommendations Impact on fisheries precludes development in near future. Due to the proximity of this site to the Dillingham area, flow rates and elevation differences should be determined however. This would allow making a judgment of the available energy. Page B-369 Ss SA 0 Ves) of JF ai ~ cS. ye (Gace CABG AS I x a = ss a $732) Xv - oi. a abins: * | Waa SSS WW JaseZ as Oy >4 | A \ SN ° ! 2 3 AGULOWAK RIVER MAP PORTION FROM USGS DILLINGHAM B-8 Location [3] Page B-370 American Creek with a dam site in section 3, R36W, T15S, with diversion north approximately 1 mile and a second dam in section 27. R36W, T14S and a powerhouse on Nonvianuk Lake as shown on Mt. Katmai D-4, D-3, C-4 and C-3. Capacity (Est. Drainage area: 98.2 sq. mi. Average flow: 200 cfs MEH: 800 feet Regulated flow: 200 cfs Dam: 150 ' high to Elev. 1650 Open ditch: 2000 feet to 50' deep Penstock: 8900 feet, 66" dia. kW - 11360 Install 2x12,000 kW MWH/Year - 99513 Cost of Installation (Est. ) $35,850,000 $/kW 3156 Access Air or tracked vehicle only. Environmental Considerations Not determined. Impact On Fisheries Important sockeye spawning system. Recommendations Land status precludes development. Load Center(s) and Distance Naknek approx. 60 miles Dillingham 120 miles Land Status Located in Mt. Katmai National Monument Interference judged severe. oul Page B C-3 ’ c-4 D=-3 MI. KATMAI > MAP PORTION FROM USGS D-4 Page B-372 Location [4] Chikuminuk Lake as shown on Taylor Mts. A-8. Capacit Est. Drainage area: 290 sq. mi. Average flow: 850 cfs_ MEH: 100 feet Regulated flow: 850 cfs Dam: 35 ' high to Elev. 633 Tunnel: 5800 feet to 20' deep Penstock: 1050 feet, 11.5' dia. kw - 6000 MWH/Year - 52560 Cost of Installation (Est. ) Load Center(s) and Distance $31, 400,000 Dillingham > 100 miles $/kW 5233 Access Land Status Air. Located in State Park. Environmental Considerations Not determined. Impact _on Fisheries Sport fishing only. Recommendations Land status, development cost and distance to load center preclude development in the near future. ) Page B-373 MAP PORTION FROM USGS TAYLOR MINS. A-8 CHIKUMINUK LAKE Page B-374 Location [5] Grant Lake with a dam site in section 28, R54W, T4S as shown on Dillingham D-7. Capacity (Est. ) Drainage area: 37.2 sq. miles Average flow: 92 cfs (from USGS records) MEH: 215 feet Regulated flow: 92: cfs Dam: to Elev. 510 CMP: 6600 feet to 60" dia. Penstock: 1300 feet, 48" dia. kW - 1385 (Partial development) MWH/Year - 12,132 Cost of Installation (Est. ) Load Center(s) and Distance $6,691,000 Dillingham approx. 65 miles. $/kW 4831 Access Air or overland vehicle only. Land Status Located in State Park, but judged as nonobjectionable in statutes. Environmental Considerations Not Determined. Impact on Fisheries Partial development should not have negative impact on salmon spawning. The lake itself has pike population. Recommendations Further evaluation to determine economic feasibility. Page B-375 LJP War BAM C i LZ — MAP PORTION FROM USGS DILLINGHAM D-7 : Page B-376 Location [6] Idavain Lake with a dam site in section 25, R40W, T16S as shown on Mt. Katmai D-6, C-6, and Naknek C-1. Capacity (Est.) Drainage area: 26.6 sq. mi. Average flow: 41.5 cfs MEH: - 685 feet Regulated flow: 41.5 cfs Dam: 20 ' high to Elev. 752 Tunnel: 10550 feet, 10! dia. Penstock: 8000 feet, 30" dia. kw - 2000 MWH/Year - 17520 Cost of Installation (Est.) Load Center(s) and Distance $15,065,000 Naknek > 50 miles $/kW 7532 Access Land Status Air or Naknek Lake. Located in Mt. Katmai National Monument. Environmental Considerations Undetermined. Impact on Fisheries Population of char in lake. No spawning salmon. Recommendations Land status precludes development in near future. wwowew Page B-377 Sala Cae ee MAP PORTION FROM USGS MT. KATMAI C-6, D-6 NAKNEK C-1 IDAVAIN LAKE Location [7] Page B-378 Kontrashibuna Lake with a dam site in section 14, R29W, T1N as shown on Lake Clark A-4. Capacity (Est.) Drainage area: Average flow: MEH: Regulated flow: Dam: Tunnel: Penstock: kw - 13750 MWH/year - 120,450 Cost of Installation (Est. ) $46,940,000 $/kW 3414 Access Air or via lliamna Lake. Environmental Considerations Recreational use. Impact on Fisheries Sport fishing only. Recommendations sq. mi. ' high to Elev. 535 feet, 17' dia. feet, 12' dia. Load Center(s) and Distance Port Alsworth / 4-6 miles lliamna, Nondalton 20-25 miles Land Status Located in Lake Clark National Monument. Land status precludes development in near future. Page B-379 Tanalian Point = MAP PORTION FROM USGS KONTRASHIBUNA LAKE LAKE CLARK A-4 Location [8] Page. B-380 Kukaklek Lake with a dam site in section 26, R38W, T12S with diversion to Iliamna Lake, USGS Map Iliamna A-7. Capacity (Est.) Drainage area: Kukaklek #1: Average flow: MEH: Diverted flow: Dam: Penstock: 14,000 kw 122,640 MWH/Year Kukaklek #2 Average flow: MEH: Regulated flow: Dam: Penstock: 6,000 kw 52,560 MWH/Year Cost of Installation (Est. ) $29,616,000 + $12,665,000 $/kW 1057 resp. 1055 Access Iliamna Lake and tracked vehicles. Environmental Considerations Not determined. Impact on Fisheries 480 sq. mi. 1200 cfs 330 feet 600 cfs to Elev. 825 14780 feet 620 cfs 140 feet 620 cfs 45 ' high to Elev. 210 4750 feet, 9' dia. Load Center(s) and Distance Dillingham / 100 miles Naknek / 65 miles Land Status Located in Mt. Katmai National Monument. Important salmon spawning system. Questionable whether permanent rise in lake level can be tolerated. Recommendations Although land status and impact on fisheries preclude development in the near future, an approximate economic evaluation should be performed. =381 Page B MAP PORTION FROM USGS ILIAMNA A-7 Page B-382 Location [9] Kvichak River with a dam site at Latitude 59°14'N, Longitude 156°25'30"W as shown on Dillingham A-2. Capacity (Est. ) Cost of Installation (Est. ) kW - Not determined. $ Not determined MWH/Year - $/kW Bulb turbine application. Load Center(s) and Distance . Access Naknek approx. 60 miles River Dillingham approx. 90 miles Land Status Located in wilderness study area and native selection. Environmental Considerations Rise in lake level, river level (will enhance boat and barge travel). Impact_on Fisheries Important salmon spawning system. Questionable whether rise in lake level can be tolerated. Recommendations Due to the impact on fisheries development does not appear feasible in the near future. Determination of flow and contours are recommended to allow capacity determination. Page B-383 MAP PORTION FROM USGS DILLINGHAM A-2 KVICHAK RIVER Location [10] Page B-384 Lake Brooks with a diversion in section 7, R39W, T19S as shown on Mt. Katmai C-6. Capacity (Est. ) Diversion ditch - 3700 ' long to divert 300 cfs. MEH - 20 feet kw - 410 MWH/Year - Summer only (camp) Cost of Installation (Est. ) $1,710,000 $/kW 4171 Access Naknek Lake Environmental Considerations Recreational use. Impact_on Fisheries Presently has fish ladder. Recommendations Land status precludes development. Load Center(s) and Distance Brooks Camp. Land Status Located in Mt. Katmai National Monument Page B-385 MAP PORTION FROM USGS MI. KATMAI C-6 Page B-386 Location [11] Lake Elva as shown on preliminary U.S.G.S. quad sheet Goodnews Ceair Capacit Est. Drainage area: 10 sq. mi. Average flow: 50 cfs MEH: 275 feet Regulated flow: 50 cfs Dam: : 80 ' high to Elev. 350 CMP: 6400 feet, 48" dia. Penstock: 1200 feet, 36" dia. kw - 960 MWH/Year - 8409 Cost of Installation (Est.) Load Center(s) and Distance $6,730,000 Dillingham approx. 49 miles $/kW 7010 Access Via Lake Aleknagik and Lake Nerka. Land Status Located in State Park, but judged nonobjectionable in park statutes. Environmental Considerations Access roads probably cannot be tolerated. Impact on Fisheries Salmon spawning (very few) only near the mouth of Elva Creek. No negative impact expected. Recommendation Economic evaluation to determine feasibility. Page B-387 MAP PORTION FROM USGS 0 D; f GOODNEWS C-1 SSO IMIA Pests LL) co TD NHS Rte oe VT | ney) 4 Y FG i . N9 / ee LS Location [12] Page B-388 Lake Grosvenor with a dam site in section 28, R35W, T19S and diversion in section 21, R37W, T17S as shown on Mt. Katmai C-4 and Cc-5. Capacit Est.) Drainage area: 630 Average flow: 950 MEH: 85 Regulated flow: 950 Dam: a5 Tunnel: 2550 Penstock: 1400 kw - 5650 MWH/Year - 49494 Cost of Installation (Est. ) $21,025,000 $/kW 3721 Access Air and Naknek Lake. Environmental Considerations Recreational use (canoe trail). Impact on Fisheries Salmon spawning area. Recommendations sq. mi. cfs feet cfs ‘ ' high to Elev. 142 feet, 20' dia. feet, 12' dia. Load Center(s) and Distance Naknek > 50 miles Land Status Located in Mt. Katmai National Monument. Land status precludes development. Page B-389 MAP PORTION FROM USGS MI. KATMAI LAKE GROSVENOR Scale 1:250,000 Page B-390 Location [13] [14] Naknek Lake with a dam site in section 14, R44W, T18S as shown on Naknek C-2 [13] or Naknek River with a dam site in section 12, R43W, T18S as shown on Naknek C-2 [14]. Capacity (Est. ) Drainage area: 2720 sq. mi. Average flow: 5400 cfs MEH: 90 feet Regulated flow: 5400 cfs Dam: 125 ' high to Elev. 150 Tunnel: none : Penstock: none kw - 34,000 MWH/Year - 297,840 Cost of Installation (Est. ) Load Center(s) and Distance $37,580,000 Naknek - 20 miles $/kW 1105 Dillingham - 97 miles Access Land Status River barge. : Border of Mt. Katmai monument on native land selection. Environmental Considerations None known. Impact _on Fisheries Up to 3,000,000 sockeye salmon spawn beyond the potential site. Recommendations Impact on fisheries are judged too severe to consider development. Page B-391 MAP PORTION FROM USGS NAKNEK C-2 NAKNEK LAKE/RIVER Page B-392 Location [15] Nuyakuk-Tikchik Lakes with a dam site in section 10, R52W, T3S as shown on Dillingham. D-6 and diversion to Kulik Lake in section 27, RS6W, T3S as shown on Dillingham D-8. Capacity (Est.) Cost of Installation (Est. ) Drainage area: 1486 sq. mi. $134, 435,000 Average flow: 3340 cfs $/kw 3200 MEH: 180 feet Regulated flow: 3340 cfs Dam: 35 ' high to Elev. 340 Penstock: 2 = 2100 feet, 16' dia. each kw - 42,000 MWH/Year - 367,920 Load Center(s) and Distance Dillingham Nushagak River Villages Naknek/King Salmon Approximately 90 miles from powerhouse to Dillingham AA Access No existing roads. Shallow passages between lakes makes barging difficult. Land Status Located in State Park. Environmental Considerations Project implies diversion of Tikchik Lakes into Wood River Lakes. Impact on Fisheries Disturbance of salmon spawning in Tikchik Lakes due to dam. Recommendations Planned diversion and impact on fisheries are judged to preciude development in near future. aa aaa Page B-393 nana MAP PORTION FROM USGS : : : DILLINGHAM D-8 Location [16] Page B-394 South Fork Savanoski River with a dam site in section 10, R33W, T19S, as shown on Mt. Katmai C-3, C-2, B-3 and B-2. Capacity (Est. ) Drainage area: 29.9 Average flow: 85 MEH: 400 Regulated flow: 51 Dam: 90 Low pressure pipe: 6340 Penstock: 1700 kw - 1450 MWH/Year - 12702 Cost of Installation (Est. ) $13,460,000 $/kW 9283 Access Air or overland vehicle only. Environmental Considerations Not determined. Impact on Fisheries Not determined. Recommendations sq. mi. cfs feet cfs ' high to Elev. 700 feet feet Load Center(s) and Distance Naknek > 80 miles Land Status Located in Mt. Katmai National Monument. Land status and remote location preclude development in near future. Page B-395 MAP PORTION FROM USGS SOUTH FORK SAVANOSKI RIVER Location [17] Page B-396 Upnuk Lake as shown on Taylor Mts. B-8. Capacit' Est. Drainage area: 100 Average flow: 295 MEH: . 150 Regulated flow: 295 Dam: 35 Tunnel: 11088 Penstock: 1850 kw - 3150 MWH/Year - 27594 Cost of Installation (Est. ) $23,730,000 $/kW 7533 Access Air anly or overland vehicle. Land Status Located in State Park. Environmental Considerations Recreational use. Impact on Fisheries No salmon spawning. Sport fishing. Recommendations sq. mi. ' high to Elev. 820 feet, 12' dia. feet, 7' dia. Load Center(s) and Distance Dillingham > 100 miles Cost and distance from load centers preclude development in near future. Page B-397 B-8 MAP PORTION FROM USGS TAYLOR MINS. _ ie a a Wi ' mR ; { Ses ae es Page B-399 1.2 -Alaska Peninsula - Bristol Bay Side Page B-400 Location [18] An unnamed creek with a dam site in section 23, R72W, T48S, as shown on Port Moller D-2 and Chignik A-8. Capacity (Est. ) Drainage area: 14.5 sq. mi. Average flow: 22 cfs MEH: 300 feet Regulated flow: 22 cfs Dam: 100' high to Elev. 500 Penstock: 4200 feet, 30" dia. kw - 460 MWH/Year - 4029 Cost of Installation (Est. Load Center(s) and Distance $5,389,500 Port Moller Approx. 5 miles. $/kW 8370 Access Air or tracked vehicle. Land Status Open. Environmental Considerations Undetermined. Impact on Fisheries Undetermined. Salmon spawning expected. Recommendations Economic evaluation to determine feasibility. Page B-401 uowDg - yy NO DRS ere . Whe MAP PORTION FROM USGS KING SALMON RIVER & UNNAMED CREEK PT. MOLLER D-1, D-2 CHIGNIK A-7, A-8 Page B-402 Location [19] Becharof Lake with a dam site in section 5, R46W, T25S as shown on Naknek A-3. : Capacity (Est.) kW - MWH/Year - Not determined. Bulb turbine application. Cost of Installation (Est. ) $ Not determined. $/kW Load Center(s) and Distance Egegik approximately 20 miles. Access Becharof River. Land Status Located on border of Becharof National Monument. Environmental Considerations Rise in lake level. Impact _on Fisheries Important salmon spawning system. Recommendation Impact on fisheries precludes development in near future. Page B-403 BEC*HAROF MAP PORTION FROM USGS NAKNEK A-3 BECHAROF LAKE Page B-404 Location [20] Hot Springs Creek with a dam site in section 2, R44W, T29S as shown on Ugashik C-2. Capacit Est.) Drainage area: 5.9 sq.. mi. Average flow: 30 cfs MEH: 800 feet Regulated flow: 30 cfs Dam: 100 ' high to Elev. 1300 Low pressure pipe: 400 feet Penstock: 3300 feet, 24" dia. kw - 1650 MWH/Year - 14454 Cost of Installation (Est. ) $9,750,000 $/kw 5,909 Load Center(s) and Distance Pilot Point/Ugashik > 50 miles Egegik > 50 miles Access Air or overland vehicle only. Located on flanks of Mt. Pevlik Volcano. Land Status Located on border of Becharof National Monument. Environmental Considerations Impact on Fisheries Not determined. Not determined. Recommendations Location and distance from sizable load centers preclude development in near future. Page B-405 “sss Mt Peulik | MAP PORTION FROM USGS M | a Oo n Oo a A od n 8 a UGASHIK C-2 Page B-406 Location [21] King Salmon River with a dam site in section 8, R71W, T48S, as shown on sheets Chignik A-8, A-7, Port Moller D-2 and D-1. Capacity (Est. ) Drainage area: 388 sq. mi. Average flow: 58 cfs MEH: 100 feet Regulated flow: 58 cfs Dam: 70 ' high to Elev. 150 Open cut: 1100 feet Penstock: 3700 feet, 3' dia. kw - 400 MWH/Year - 3504 Cost of Installation (Est. ) $5,030,000 $/kW 12,575 Load Center(s) and Distance Port Moller approx. 10 miles. Access Air or tracked vehicle. Bristol Bay coast. Land Status Environmental Considerations Open. Undetermined. Impact_on_ Fisheries Salmon spawning stream. Recommendations Economic evaluation to determine feasibility. Page B-407 MAP PORTION FROM USGS KING SALMON RIVER & UNNAMED CREEK PT. MOLLER D-1, D-2 CHIGNIK A-7, A-8 Page B-408 Location [22] Landlocked creek with a dam site in section 28, R58W, T41S as shown on Chignik C-2 and C-1. Capacity (Est. ) Drainage area: 25. Oe.” Ml. Average flow: 60 cfs MEH: 200 feet Regulated flow: 60 cfs Dam: 50 ' high to Elev. 300 Open cut: 500 feet Penstock: 1600 feet kw - 840 MWH/Year 7358 Cost of Installation (Est. ) $4,615,000 $/kw 5494 Load Center(s) and Distance Port Heiden approx. 25-30 miles Chignik Bay approx. 25-30 miles Access ; Air or tracked vehicle. Land Status Located in wilderness study area. Environmental Considerations Impact on Fisheries Not determined. Not determined. Recommendations Cost of installation and distance from load centers preciude development in near future. 409 Page B C-2 elt MAP PORTION FROM USGS CHIGNIK C Sabi gh ot ‘Landlicked ee LANDLOCKED CREEK Location [23] Page B-410 Reindeer Creek with a dam site in section 13, R58W, T37S as shown on Chignik D-2 and D-1. Capacity (Est.) Drainage area: 27.6. Average flow: 55 MEH: 100 Regulated flow: 27:5 Dam: 80 Tunnel: Penstock: 3650 kw - 200 MWH/Year - 1752 Cost of Installation (Est. ) $5,120,000 $/kW 12,800 Load Center(s) and Distance Port Heiden approx. 6-7 miles. Access Air or tracked vehicle. Land Status Located on selected native land. Environmental Considerations Not determined. Recommendations Development judged too costly to be feasible in near future. sq. mi. cfs feet cfs ' high to Elev. 400 none feet, 42" dia. Impact on Fisheries Not determined. Page B-411 Dele {i ; j i MAP PORTION FROM USGS CHIGNIK D-1, D-2 REINDEER CREEK Page B-413 1.3. Alaska Peninsula - Pacific Coast ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( { ( ( ( ( ( ( ( ( ( ( naan Page B-414 Location [24] An unnamed lake with a dam site in section 9, R32W, T23S, as shown on Mt. Katmai A-2. Capacit Est.) Drainage area: Ii. isq. mis Average flow: 70 cfs MEH: 730° feet Regulated flow: 63 cfs Dam: 50 ' high to Elev. 800 Low pressure pipe: 3700 feet, 6' dia. Penstock: 1900 feet, 42" dia. kW - 3265 MWH/Year - 28,601 Cost of Installation (Est. $9,335,000 $/kW 2859 Load Center(s) and Distance None. Access For construction via Shelikof Strait. Transmission line crosses Alaska Range. Land Status Located in Mt. Katmai National Monument. Environmental Considerations Impact on Fisheries Undetermined. Undetermined. Recommendations Remote location precludes development in near future. -415 Page B MAP PORTION FROM USGS KATMAI A-2 3 a UNNAMED LAKE NEAR HIDDEN HARBOR Page B-416 Location [25] Dakavak Lake with a dam site at the lake outlet as shown on Mt. Katmai A-3 and A-2. Capacity (Est.) Drainage area: 28 sq. mi. Average flow: 168 cfs MEH: 240 feet Regulated flow: 168 cfs Dam: 2 to elevation 300' Open cut: 1000 feet Penstock: 1000 feet, 5' dia. kw - 2860 MWH/Year - 25,053 Cost of Installation (Est.) $7,900,000 $/kKW 2762 Load Center(s) and Distance None. Access Shelikof Strait. Land Status Located in Mt. Katmai National Monument. Environmental Considerations Impact on Fisheries Undetermined. Undetermined. Recommendations Land status and remote location preclude development in near future. Page B-417 MAP PORTION FROM USGS MI. KATMAI A-2, A-3 Page B-418 Location [26] Kirschner Lake, section 1, R28W, T9S as shown on Iliamna B-3. Capacity (Est.) Drainage area: 13.8 sq. mi. Average flow: 83 cfs MEH: 100 feet Regulated flow: 83 cfs Dam: 30 ' high to Elev. 110 Penstock: ; 600 feet, 40" dia. kw - 580 MWH/Year - 5081 Cost of Installation (Est. ) $1,456,000 $/kW 4853 Load Center(s) and Distance Kokhanok approx. 40 miles Pedro Bay approx. 50 miles Pile Bay approx. 40 miles Access Kamishak Bay. Land Status Open. Environmental Considerations Impact_on Fisheries Not determined. Not determined. Recommendations Location of load centers across the Alaska Range precludes development in near future. Page B-419 als MAP PORTION FROM USGS ILIAMNA B-3 KIRSCHNER LAKE Location [27] Page B-420 Two unnamed creeks with dam sites in section 18, R58W, T45S and section 14, R59W, T45S as shown on Chignik B-2. Capacity (Est.) Chignik #1: Drainage area: Average flow: MEH: Regulated flow: Dam: Flume: Penstock: kw - 710 MWH/Year - Chignik #2: Drainage area: Average flow: MEH: Regulated flow: Dam: Penstock: kw o- 410 MWH/Year - Cost of Installation (Est. ) $3,475,000 + $3,015,000 $/kW 2,482 resp. 3,768 Access Air or tracked vehicle. Environmental Considerations Not determined. Recommendation 6219 3591 2.8 sq. mi. 22.4 cfs 460 feet 22.4 cfs 55 ' high 3600 feet 2200 feet 4.3 sq. mi. 34.5 cfs 170 feet 34.5 cfs 70 ' high 2600 feet Load Center(s) and Distance Chignik Bay Chignik Lagoon, approx. 6-8 miles Chignik Lake, approx. 12-15 miles Land Status Native land selection and Wilderness Study Area. Impact on Fisheries Not determined. Judged low. Economic evaluation to determine feasibility. Page B-421 Negro Head MAP PORTION FROM USGS CHIGNIK # 1 & 2 CHIGNIK B-2 Location [28] Two unnamed lakes with dam sites in shown on Ugashik C-1. Capacity (Est.) Upper Lake: Lower Lake Drainage area: Average flow: MEH: Regulated flow: Dam: Penstock: kW = 165 MWH/Year - 1435 Drainage area: Average flow: MEH: Regulated flow: Dam: Penstock: kw - 275 MWH/Year - 2409 Cost of Installation (Est. ) $4,995 ,000 $/kW 11,352 Access Shelikof Strait. Environmental Considerations Not determined. Impact on Fisheries Not determined. Recommendations Page B-422 section 23, R43W, T30S as 2.6 sq. mi. 13 cfsé 180 feet 1Sicts 75 ' high to Elev. 500 1300 feet, 20" dia. 4.4 sq. mi. 22 icfs 180 feet 22 cfs 20 ' high to Elev. 300 2600 feet, 24" dia. Load Center(s) and Distance Pilot Point/Ugashik > 60 miles Land Status Located in Becharof National Monument. Cost of installation precludes development in near future. Page B-423 MAP PORTION FROM USGS TWO LAKES #1 & 2 UGASHIK C-1 Location [29] Unnamed Lake (Mt. Katmai B-1). Elevation 1750'. Capacity (Est. ) Drainage area: 14.7 sq. mi. Average flow: 120 cfs MEH: 80 feet Regulated flow: 120 cfs Dam: 20 ' high to Elev. Penstock: 1200 feet, 4' dia. kW 675 MWH/Year 5913 Cost of Installation (Est. ) $2,770,000 $/kWw 4104 Load Center(s) and Distance None. Access Shelikof Strait. Land Status Located in Mt. Katmai National Monument. Environmental Considerations Undetermined. Impact_on Fisheries None known at this time. Recommendation 100 Page B-424 Land status and remote location preciude development in near future. -425 Page B MAP PORTION FROM USGS 2 a 5 3 z 3 Page B-427 1.4 Iliamna/Lake Clark Page B-428 Location [30] Copper River - Meadow Lake (Iliamna), U.S.G.S. Iliamna C-3 & C-4. Capacit Est. Drainage area: 26.6 sq. mi. Average flow: 130 cfs MEH: 100 ‘feet Regulated flow: 130 cfs Dam: 40 ' high to Elev. 60 kw - 910 (prime and average) - install 2 x 750 kw MWH/Year - 7971 Cost of Installation (Est. ) $ 4,935,000 $/kW 5,423 Load Center(s) and Distance Kokhanok - approx. 25 miles Pile Bay - approx. 25 miles Access Tracked vehicle or air. Land Status Environmental Considerations Located in Wilderness Study Area. Not determined. Impact on Fisheries Limited salmon spawning below 32' waterfalls near lower Copper Lake. Recommendation Economic evaluation to determine feasibility. Page B-429 MAP PORTION FROM USGS ILIAMNA C-4, C-3 COPPER RIVER - MEADOW LAKE Location [31] Kokhanok River (lliamna) with a U.S.G.S. Iliamna B-4 and B-5. Capacity (Est. ) Drainage area: 145 Average flow: 400 MEH: 45 Regulated flow: 200 Dam: 35 ' high to Elev. 100 kw - 630 (prime) MWH/Year - 5519 Cost of Installation (Est. ) $ 5,350,000 $/kW 8,492 Load Center(s) and Distance Kokhanok - approx. 12 miles Access Lake Iliamna. Land Status Located in Wilderness Study Area. Environmental Considerations Not determined. Impact_on Fisheries sq. mi. feet: Page B-430 dam at the mouth of the river. Fish passage planned; presently 25' waterfalls into Lake Iliamna. Recommendation Economic evaluation to determine feasibility. Page B-431 MAP PORTION FROM USGS KAKHONAK RIVER ILIAMNA B-4, B-5 Location [32] Koksetna River (Lake Clark) with shown on Lake Clark B-6. Capacity (Est.) © Drainage area: Average flow: MEH: Regulated flow: Dam: Tunnel: Penstock: 160 465 155 180 155 1600 2700 Page B-432 a dam in Section 13 T3NR32W as sq. mi. ' high to Elev. 1400 feet, 15! dia.. feet, 8' dia. kw - 5100 (average), 2000 (prime) MWH/Year - 17520 Cost of Installation (Est.) $ 19,880,000 $/kW 3,898 Load Center(s) and Distance Nondalton - approx. 40 miles Iliamna Newhalen $ approx. 54 miles Access Air or tracked vehicle only. Environmental Considerations Land Status Located in Wilderness Study Area. Moose habitat; improved access potentially harmful. Impact_on Fisheries Sport fishing only. Recommendations Remote location precludes development in near future. Page B-433 ( NC HA | | | \ iZ - } \ - ee : 3 ~— 2A Ai aN 5) wile \ Wa ny Nn j ft 1 \ ) , SS “8 i MAP PORTIO N mee n Wad e ites LAKE CLARK B-6 Location [33] Page B-434 Lachbuna Lake (Lake Clark) with a dam in Section T4N;R28W as shown on Lake Clark B-3. Capacity (Est. ) Drainage area: Average flow: MEH: Regulated flow: Dam: Tunnel: Penstock: sq. mi. cfs feet cfs ' high to Elev. 1400 feet, 14' dia. feet, 8' dia. kW - 38,660 (average annual), 23,400 (prime) MWH/Year - 205,000 Cost of Installation (Est. ) $ 103,000,000 $/kW 2,664 Load Center(s) and Distance Nondalton - Iliamna > 40 miles Access Air or tracked vehicle only. Environmental Considerations Not determined. Impact on Fisheries Land Status Located in Wilderness Study Area. Not determined. No salmon spawning area. Recommendations Remote location precludes development in near future. Page B-435 MAP PORTION FROM USGS LACHBUNA LAKE Page B-436 Location [34] & [35] Summit Lakes, Chinkelyes Creek (Iliamna). Located on road between Pile Bay and Williamsport. Two possible schemes: #1, Powerhouse on Pacific side at Williams Creek; #2, Powerhouse on Iliamna Lake side... U.S.G.S. Iliamna ‘C-2;: C-3, D-2, D-3. Capacity (Est. ) #1 (Williams Creek) Drainage area: 11.4 sq. mi. : Average flow: 685 cfs MEH: 390 feet Regulated flow: + 68.5 cfs Dam: 25 ' high to Elev. Summit Lake 530! Low pressure pipe: 1600 feet Penstock: 900 feet kw - 1900 (prime) MWH/Year - 16,644 #2 (Iliamna) Drainage area: 18.5 sq. mi. Average flow: Tieicts MEH: 390 feet Regulated flow: 111 (cfs Dam: 25 - 40 ' high to Elev. Low pressure pipe: 33250 feet, 6' dia. kW - 3,000 (prime) MWH - 26,280 Cost of Installation (Est.) #1: #2: $ 8,395,000 $ 16,350,000 $/kW 4,418 $/kW 5,450 Load Center(s) and Distance Pile Bay - approx. 14 miles to #1; 6 miles to #2 Pedro Bay - approx. 26 miles to #1; 18 miles to #2 Williamsport - approx. 2 miles to #1; 10 miles to #2 Access Land Status Existing road. , Wilderness Study Area. Environmental Considerations Impact _on Fisheries Not determined. Sportfishing only. Recommendations Size of loads in vicinity precludes development in near future. Page B-437 BOROUGH | MAP PORTION FROM USGS SUMMIT LAKES #1 - WILLIAMS CREEK ILIAMNA C-2, C-3, SUMMIT LAKES #2 - ILIAMNA D-2, D-3 Page B-438 Location [36] Tazimina Lake with a dam site* in section 24, R32W, T3S as shown on lliamna D-5. [ Capacity (Est.) - First Stage Drainage area: 320 sq. mi. Average flow: 1440 cfs MEH: 300 feet Regulated flow: 720 cfs Forebay dam: 100 ' high to Elev. 660 Reservoir dam: 20 ' high to Elev. 675 Open cut: 1200 feet, 20' dia. Penstock: 10030 feet, 11' dia. See also map next page (and Figure IV-1) kw - 15,000 MWH/Year - 131,400 Cost of Installation (Est. ) $34,445 ,000 $/kW 2296 Load Center(s) and Distance Dillingham approx. 149 miles Naknek approx. 121 miles |liamna/Nondalton/Newhalen 14 miles Access State road planned from Iliamna.to Nondalton. Land Status Located in Wilderness Study area and native selection land. Environmental Considerations Impact _on Fisheries Not determined. No salmon spawning beyond falls Recommendations Economic evaluation to determine feasibility. *Preliminary geologic reconnaissance (U.S.G.S. 1967) indicates that this site could present problems due to loose surface deposits. Site specific investigations are therefore strongly recommended. Page B-439 MAP PORTION FROM USGS ILIAMNA D-5 LAKE TAZIMINA (1st stage) Page B-440 Location [37] Newhalen River with a dam site in section 23, R33W, T4S as shown on lliamna D-6. Capacit Est.) Drainage area: 3,300 sq. mi. Average flow: 9,303 cfs MEH: 35 ft Regulated flow: 9,303 cfs with 2,000,000 Ac Ft Storage Dam: 47' high to Elev. 275 Tunnel: ” Penstock: = kW - 22,000 MWH/year - 192,720 Cost of Installation (Est. ) Load Center(s) and Distance $79,939,500 \liamna, Nondalton ~ 10 miles $/kW 3634 Dillingham/Naknek ~ 135 miles Access Land Status Road from Iliamna Village withdrawals Environmental Considerations Lake Clark level rise to 275' would flood village sites. Impact _on Fisheries Important salmon migrating and spawning system. Dam would require fish passages. Lake level rise could destroy spawning beds. Recommendations Impact on existing communities and fisheries too severe to consider development in the near future. to -441 Page B MAP PORTION FROM USGS NEWHALEN RIVER APPENDIX C COST ESTIMATES Page C-445 APPENDIX C COST ESTIMATES AND ECONOMIC PARAMETERS The estimates have been based on the cost of recent construction projects in Alaska, information obtained from local suppliers and contractors and the engineers experience. 15 Distribution Systems Line costs are calculated using local labor where possible and contract labor for extensive projects. a. 14.4 or 7.2 kV Single Phase Overhead Line REA - Standard design, average span 300' 1979 $/mile Poles 40' high, 17 @ $500 $ 8,500.00 Conductor 1/0 ACSR, 12000' @ $100/1000' 1,200.00 Line hardware $50/pole 850.00 Survey 2,500.00 Clearing 30%/mile, $600/1000 ft. 950.00 Freight 1,500.00 Contract Labor 400 manhours @ $50 (includes supervision and inspection) 20,000.00 . $35,500.00 Engineering 10% 3,550.00 ($47, 050.00) Use $42,000.00 If local labor can be used at an estimated rate of $25/hour the cost/mile can be reduced as follows: $35,500.00 (20,000.00) + 400 hours @ $25.00 10,000.00 + additional supervision 2,500.00 $28,000.00 Engineering 3,500.00 ($31,500.00) Use 32,000.00 n Page C-446 24.9 or 12.5 kV Three Phase Overhead Line REA Standard design, average span 300' 1979 $/mile Poles 40' high, 17 @ $500 $ 8,500.00 Conductor 4/0 ACSR, 24000' @ $120/1000' 2,880.00 Line hardware $250/pole 4,250.00 Survey 2,500.00 Clearing 30%/mile, $700/1000 ft. 1,102.00 Freight 2,500.00 Contract Labor 550 man hours @ $50 * 27,500.00 Supervision & Inspection 5 days @ $500 2,500.00 4 $51,732.00 Engineering 10 5,200.00 ($56,932.00) Use $60,000.00 - If local labor can be used at an estimated rate of $25/manhour the cost/mile can be reduced as follows: $51,732.00 (27,500.00) + 550 hours @ $25.00 13,750.00 + additional supervision 1,250.00 $39,232.00 Engineering 5,200.00 ($44,432.00) Use $47,000.00 25 kV Cable 1979 $/mile 4/0 Cu, 1%, armored @ $5,000/1000' $79,200.00 (including terminators, etc.) Labor 110 man hours @ $50 5,500.00 Freight 26000 Ibs. @ $.14/Ib. 3,640.00 $88 ,340.00 Engineering 1,000.00 $89,340.00 Use 10,000.00 2 Transmission Systems 138 kV Three Phase Overhead Line REA Standard design, average span 1000! Structures, 5 @ $5000 Conductor 556 MCM ACSR, 17000' @ $500/1000' Line Hardware & Anchors $1000/Structure Survey Clearing 30% @ $1500/1000' Freight Labor 900 manhours @ $50 Engineering 123 Use NOTE: Right-of-Way is not included. Transmission/Distribution Substation Transformer 12/16/20 MVA Switchgear Bus Structure & Hardware Freight Labor 1500 manhours @ $50 Engineering 10% Real Estate Use For 40 MVA Transformer Add Page C-447 1979 $/mile $ 25,000.00 8,500.00 5,000.00 8,000.00 2,376.00 5,000.00 45,000.00 $ 98,876.00 12,000.00 ($110,876.00) $125,000.00 1979 - $ __ $180,000.00" 60,000.00 40,000.00 15,000.00 75,000.00 $370,000.00 37,000.00 $407,000.00 _ 25,000.00 ($432,000.00) $450,000.00 $150,000.00 Single Wire Ground Return Up To 40 kv 2 Pole Structures, 800' Spans Structures, 7 @ $180 (local timber) Conductor 7#8 Alumoweld 5300', $500/1000'! Line Hardware Survey Clearing 20%/mile @ $700/1000! Freight Local Labor 250 manhours @ $20 Engineering Use For Conductor 266.8 ACSR add: Structures and Hardware Conductor $250/1000' Use For river crossings, bog shoes and additional labor in difficult terrain add NOTE: Right-of-Way is not included. Terminal for Single Wire Ground Return Transmission Up To 40 kV Ground Grid 20, 20' deep rods interconnected with about 1000' of wire Labor 50 manhours @ $20 Transformer, 1%, up to 1 MVA including shipping and installation Switchgear and Protection Engineering Use Page C-448 Per Mile 1979 $ $ 1,260.00 2,650.00 1,600.00 2,000.00 739.00 600.00 5,000.00 $13,849.00 1,000.00 ($14,849.00) $15,000.00 $ 250.00 1,320.00 ($ 1,570.00) $1,600.00 $4,000.00 1979 $ $ 1,500.00 1,000.00 22,000.00 5,000.00 $29,500.00 5,000.00 ($34,500.00) $35,000.00 mw Page C-449 e. Single Wire Ground Return Low Frequency Transmission Up To 80 kV © 2 Pole Structures, 500' Spans Per Mile 1979 $ Structures, 11 @ $300 (imported timber) $ 3,300.00 Conductor 266.8 ACSR, 5,300' @ $750/1000' 3,975.00 Line Hardware 5,500.00 Survey 2,000.00 Clearing 20%/mile $700/1000' 739.00 Freight 1,500.00 Labor 250 manhours @ $50(contract labor) 12,500.00 $29,514.00 Engineering 10% 2,951.00 to account for river crossings, bog shoes etc. ($32,465.00) Use 40,000.00 ft. Phase and Frequency Conversion Equipment 1979 $ Per kW (i) Low frequency (25 Hz) to high frequency (60 Hz) and 19% to 3% for 1 to 2 MW per terminal (manufacturer's data: ASEA, Sweden) $ 200.00 Plus freight & engineering, contingencies 100.00 $ 300.00 (ii) Phase conversion equipment 19 to 30 estimate $ 150.00 ie Diesel Generating Equipment a. Central Plant (installed) $1979 $ Buildings & Structures $90 to $120/Sq. Ft. Fuel Tanks $1 to $1.50/Gal. Engine Generator (up to 500 kW) $200 to $400/kW Switchgear (2 Generators, 2 Feeders) Approx. $30,000 Freight $15 to $20/100 Ibs. bs Home Generators 1979 $ Diesel 4 kW $ 4,000.00 Diesel 2 kW 2,000.00 Gasoline 4 kW 1,000.00 Gasoline 2 kW 500.00 NOTE: Owner installation is assumed. Wind Generating Equipment a. Coal 1.5 kW windplant with induction generator and control (Enertech 1500) Tower including 60-3 pole, pole top adaptor guy wires and anchors (4) Control anemometer wire, 400! Freight 4000 Ibs. @ $17/100 Ibs. Installation 100 manhours @ $50 15 kw windplant with DC-generator Conversion equipment and controls Tower 60-3 pole (as under a) Control Anemometer wire 400! Freight 8,000 Ibs at $17/100 Ibs Installatin 150 man hours @ $50.00 100 kW windplant with DC-generator Conversion equipment and controls Tower 120 ft. high, steel Cable and wiring Freight 50,000 Ibs @ $17.00/100 Ibs. Installation 400 man hours @ $50.00 and Steam Generating Equipment Power Plant 4 MW Power Boilers $500/kW Turbo Generators (packaged units) 4 @ 1000 kW $250/kW Mechanical Systems Electrical Systems Building & Site Preparation 7000 Ft? @ $50 Installation Freight 10% of Material Engineering 14% Contingencies Or $1500/kW Page C-450 1979 $ $ 2,900.00 800.00 60.00 680.00 5,000.00 $9,440.00 $ 16,500.00 9,000.00 800.00 60.00 1,360.00 7,500.00 $ 35,220.00 $110,000.00 60,000.00 25,000.00 2,500.00 8,500.00 __ 20,000.00 $226,000.00 1979 $ $ 2,000,000 1,000,000 250,000 150,000 350,000 1,000,000 __ 375,000 $ 5,125,000 718,000 $ 5,843,000 157,000 $ 6,000,000 Roads and Transportation Road mine to plant 6 miles @ $100,000 Transportation Coal Mining Assumption: (i) Gi) graded to uniform size. Investment 1 D9/D6 Ripper & Blade 1 966C Front End Loader 110 Cu. Yd. Dump Truck 1 Crusher, Grader, Washer Tools, Hardware 1 36x50 Warehouse, office 2 Mobile Home Feight Initial Exploration & Dev. Total Investment Annual Cost Investment (8 years life expectancy, 9% interest, 3% insurance - .2107) Continued Investigation Fixed Cost - Subtotal Operation: 3 operators Room & Board Parts & Maintenance Fuel Variable Cost - Subtotal Total Annual Cost Cost/Ton 100 tons/day Operation (1979-$) $ 310,000 115,000 35,000 150,000 80,000 100,000 100,000 $ 890,000 40,000 150,000 $1,080,000 $:5 187,523 50,000 $237,523 100,000 55,000 15,000 92,000 $ 262,000 499,523 13.70 Page C-451 $ 600,000 $ 3.50/ton Open pit operation, 5% rock & dirt, 20 tons/day Operation (1979-$) $ 90,000 115,000 35,000 150,000 50,000 100,000 $540,000 30,000 150,000 $720,000 $151,704 50,000 $201, 704 100,000 55,000 11,000 55,000 $221,000 422,704 57.90 APPENDIX D ECONOMIC EVALUATIONS Page D-455 APPENDIX D ECONOMIC EVALUATIONS Parameters for Cost Benefit Evaluations Diesel generating costs for various locations have been determined by plotting fixed and variable cost on Figure IV-2. This figure is included here with its source data listed. Estimates for investments have been made on a 1979 cost basis. Future investments have been escalated at 10% per year, except for wind generation systems, where improvements in technology are expected to reduce this escalation rate to 5% per year. Fuel and lube oil costs have been escalated at 7% per year beyond the 1977 rates listed in Table 1V-3. Interest rates, insurance, and operations and maintenance cost are listed on the following Table D-1.1 "Parameters for Cost Benefit Evaluations". We have been attempted to reflect realistic conditions for the various evaluations. Interest rates of 5% have been used only where REA loan funding is considered possible. Where it had to be assumed that a private individual had to obtain the loan, a rate of 12% interest has been used. Other commercial loans or bond issues have been assumed at 9%. Labor and maintenance costs have been escalated at 7%/year. For hydro plants a representative average has been used throughout. 100 MLM ae 90 - +— BLE COST/KWH TS (100-500 KW) ¢ / KWH 1975 1980 1985 1990 1995 Pee ae COST OF DIESEL GENERATION FIGURE D-| 2000 Page D-456 ASSUMPTIONS: INTEREST 5% FUEL COST ESCALATION 7% PER YEAR FUEL EFFICIENCY \ 12 KWH/GAL FOR PLANT 1 1000 KW L9KWH/GAL FOR PLANT £500 KW LOAD FACTORS =.4-.56 BARS INDICATE RANGE OF FUEL COST ONLY. COST OF POWER (AT BUS) = FIXED COST + VARIABLE COST. VARIABLE COST/KWH PLANTS WITH DEMAND 1000 KW FIXED COST/ KWH SMALL PLANTS (100-500 KW) —< VARIABLE COST —e— FIXED COST —C— CHIGNIK —D— DILLINGHAM —G— GLENNALLEN —I— ILLIAMNA —K— KODIAK —N— NAKNEK —P— PILOT POINT —V— VALDEZ FIXED COST/ KWH PLANTS WITH DEMAND \ i000 KW Page D-457 BRISTOL BAY PARAMETERS FOR COST BENEFIT EVALUATIONS TABLE D-1.1 Annual Annual Insurance Operation/ O&M Interest Depreciation Amortization Insurance Escalation Maintenance Escalation Rate Period (Quarterly (% of Rate (% of Rate (%) (YRS) Payments) (%) Investment) (% per year) investment) (% per year) Hydro Plant 5 35 6.07 oi) 7 i 7 Central Diesel Plant REA Loan 5 5 9.52 2 7 6-10 7 Commercial Loan 9 15 a2 20 2) 7 6-10 7 Home Generator Gasoline‘ 12 3 40.18 2, 7 6% 7 Diesel 2} 5 26.89 a 7 .6%* 7 Wind Generating Plant 9 15 12,21 oS = 7-20 7 Transmission & Distribution Lines REA Standard 5 85 6.07 1 7 SWGR etc. 9 35 9.42 1 7 *Parts only Page D-458 Small Diesel Generating Plant A small community without a central power plant has been chosen to evaluate the power cost for continuous diesel generation. With load data for a "low" load growth case the following installations have been assumed to maintain firm and adequate service: 1980 2 x 60 kW generators (1980 - $50,000) Building 30! x 40! 15,000 gal. fuel tank 4 switchgear cubicles 1980 - $290,000 1984 Add 1 x 60 kW generator + 1 switchgear cubicle 1984 - $ 50,000 1989 Add 15,000 gal. fuel storage. 1989 - $ 52,000 1995 Add 2 x 100 kW generators. (1995 - $150,000) Retire 2 x 60 kW generators. Add 15,000 gal. fuel storage. 1995 - $208,000 1999 Add 1 x 100 kW generator. Retire 1 x 60 kW generator 1999 - $102,000 Distribution system cost have not been included but are estimated to be approximately $132,000 in 1980 for approximately 3 miles of overhead line. Small Diesel Plant (typical) Power Cost at Distribution Bus Page D-459 1980 1985 1990 1995 2000 Peak kW 55 62 70 85 100 Annual MWh 191 218 245 335 438 Gen. Capacity (kW) 2x60 3x60 3x60 200 300 Investment 1000$ 290 340 392 600 702 Fixed Cost (1000$) Amortization 28.8 34.5 39.6 57.6 65.2 Insurance 6 1.0 1.6 3.4 5.6 Total Fixed Cost 29.4 35.5 41.2 61.0 70.8 Variable Cost (1000$) Maintenance Tee 2.5 3.5) Pe 11.6 Fuel 23.4 40.3 63.7 116.4 203.7 Operating 30 42.1 59 82.8 116.1 Lube Pott 4.0 6.4 11.6 20.4 Total Variable Cost 56.9 84.9 132.6 218 351.8 Total Cost (1000$) 86.3 120.4 173.8 279.0 422.6 ¢/kWh 45.2 55.2 70.9 83.3 96.5 Assumptions: Generating Efficiency: Lube Oil: 10% of fuel oil 8 kWh/gal. (incl. losses) Operations Maintenance: 1 Operator $10/kW in 1979 escalated at 7% Loans: Interest: 15 years for engine generators} quarterly 35 years for other systems} 9% per year payments Page D-460 Wind Electric Generating System (Small Community) At the present "state of the art" and with operating records from the Bristol Bay area in mind, only the supplemental use of wind power has been investigated. For this purpose choosing a system with a small existing diesel generating plant and load characteristics as described in Appendix D-2 - increments of 1.75 kW Enertech 1500 wind power units with induction generators have been chosen to supplement diesel generation. This will eliminate storage batteries, inverters and other control equipment. Since the induction generator, however, requires a source of reactive power and frequency the generating mix has been kept in a relationship of 1:3 of base load to avoid system stability problems. If an average windspeed of 15 mph is assumed the Enertech 1500 will have an output of 467 kWh/month. This energy contribution has been assumed for each installed generator for the chosen load case. Other parameters for the evaluation are: Installation Schedule 1980 4 units @ $9900. 1980 - $ 39,600 1984 1 unit 1984 - $ 12,000 1989 1 unit 1989 - $ 15,300 1994 1 unit 1994 - $ 19,600 1999 2 units 1999 - $ 47,600 Life expectancy: 20 years Loan: 9% interest, 15 years, quarterly payments Maintenance: 1 specialist once per year for up to 10 units escalated 7%/year Peak kW System MWh Load Factor Installed Wind Generator Capacity (kW) Wind MWh Fuel displaced at 8kWh/gal. efficiency (Gal. ) Wind System Cost Fixed Cost (1000$) Amortization Variable Cost (1000$) Maintenance Total Cost (1000 $) Value of Fuel displaced (1000 $) Difference (1000 $) ( ) penalty Note: Wind Generator Power Cost (at distribution bus) Page D-461 1980 1985 1990 1995 2000 55 62 70 85 100 191 218 245 335 438 4 .4 4 45 5 6.6 7.4 8.4 11.5 15 (4@1.75) (5@1.75) (6@1.75) (7@1.75) (9@1.75) 22.4 28 33.6 39.2 50.4 2800 3500 4200 4900 6300 4.8 6.3 8.2 5.8 10.1 2:3 353 4.8 6.8 9.5 7.1 9.6 13 12.6 19.6 2.7 5.2 8.7 13.6 23.4 (4.4) (4.4) (4.3) 1.0 3.8 source to an existing system. Non firm energy, only to be used as supplementary energy Page D-462 Small Diesel/Wind Generating System Combination 4. An investigation was performed of the economical feasibility of installing wind generation in addition to diesel generation in a small system as described and evaluated in Appendix D-2 and D-3. If the wind generators are only used as supplemental energy sources the only savings consist of not used fuel and lube oil. Installed ‘diesel capacity, operating personnel, etc. have to be maintained at 100%. To derive the maximum benefits from the wind generators no downtime and no redundant installed capacity has been assumed for them. Small Diesel/Wind Generating System Combination (Power Cost at Distribution Bus) ell 1980 1985 1990 1995 2000 Peak kW 55 62 70 85 100 Annual MWh required 191 218 245 335 438 Annual MWh Wind Syst. 22.4 28 33.6 39.2 50.4 Annual MWh Diesel Syst. 168.6 190 211.4 295.8 387.6 Fixed Cost (1000$) Diesel 29.4 35.5 41.2 61.0 70.8 Wind Gen. 4.8 6.3 8.2 5.8 10.1 Total Fixed Cost 34.2 41.8 49.4 66.8 80.9 Variable Cost (1000$) Diesel 31.2 44.6 62.5 90 127.7 + Fuel & Lube 22.7 38.6 60.5 113.1 198.3 Wind Gen. 2.3 3.3 4.8 6.8 9.5 Total Variable Cost 56.2 86.5 127.8 209.9 335.5 Total Cost 90.4 128.3 Wiad 276.7 416.4 - ¢/kWh (combined ) 47.3 58.9 72.3 82.6 95:1 ¢/kWh (Diesel : only) 45.2 55.2 70.9 83.3 96.5 Data based on Appendix D-2 and D-3. ~~,rTrwewwrewrTrT~- = Page D-463 Lake Elva and Diesel - Dillingham This evaluation uses the "low" load growth projections for the present Nushagak Electric Association system in Dillingham and assumes that a hydro plant at Lake Elva can be operational in 1985. Hydro Investment 1 x 1.5 MW 1979/$ Dam $ 2,920,000 Spillway 155,000 Intake 65,000 Waterways 1,120,000 Power Plant 520,000 Equipment 1,050,000 Substations 200,000 Transmission Line (24.9 kV), 29 miles 2,273,000 Engineering 900,000 9 000 Escalated at 10% to 1985 $14,821,524 Hydro Annual Cost Amortization 35 yrs. @ 5%/year $ 899,666 Insurance $2/$1000 29,643 Operations and Maintenance 1% 148,215 Total $ 1,077,524 Use $ 1,078,000 Diesel Cost Escalated cost per kWh as developed in section 1V-C.1 have been used. It should be noted that the following items are not taken into consideration by using the above base date: (i) Peak load supply by diesel generation. (ii) Escalation for cost of operations, maintenance and insurance -for hydro installations. Page D-464 (iii) Transmission losses for the hydro plant. (iv) Changes in diesel generating cost caused by reduced loads, varying losses, etc. The general trend is not expected to be influenced to a substan- tial extent by these simplifications. DILLINGHAM/LAKE ELVA - LOW LOAD GROWTH (Power Cost at Distribution Bus) 1985 1990 1995 2000 Peak kW 2000 2580 3100 3650 Hydro Capacity 960 960 960 960 Annual MWh 8500 11070 13521 15972 Hydro Capacity 8409 8409 8409 8409 Cost for Diesel ¢/kWh 10.5 3.3 7 Zen! 1000$/year 893 1472 2312 3530 15 year average ¢/kWh 15.6 Cost for Hydro ¢/kWh 12:8 12.8 12.8 12.8 1000$/Year 1078 1078 1078 1078 15 year average ¢/kWh 12.8 Cost for Hydro & Diesel ¢/kWh 12.8 12.9 14.4 gee 1000$/Y ear 1088 1432 1952 2749 15 Year Average ¢/kWh 14.1 Page D-465 Bay Area With the high cost of fuel oil, operations and the relatively low efficiency in operating small diesel plants, single wire ground return transmission line interties into the larger existing systems in Dillingham and Naknek are investigated for 10 villages. To simplify the evaluation, energy use, as well as the investment cost for all communities, have been added together and it has been assumed that the Dillingham and Naknek Systems are inter- connected. The following table lists the villages, line miles required, expected maximum load until the year 2000, and the required conductor size to insure service at the proper voltage level (see Appendix B-2 for line load limitations). TABLE D-6.1 TRANSMISSION TIE LINES Page D-466 Operating Conductor From To Distance ae Pay Voltage Size Location Location (Miles) ( KV) (AWG) Dillingham Manokotak 25 560 40 7#8 Alumoweld Dillingham Ekuk} 20 1780 40 7#8 Clark's Point} + Marine cable Dillingham Ekwok 49 345 40 . 266.8 ACSR New Stuyahok +10 390 40 266.8 ACSR Koliganek +20 345 40 7#8 Alumoweld Portage Creek +15 107 40 7#8 Alumoweld + river crossing Naknek Levelock 32 290 40 7#8 / Alumoweld Igiugig +40 120 40 7#8 Alumoweld Naknek Egegik 48 1400 40 266.8 ACSR TOTALS -- 284 5337 iso o— Installation cost 1979-$ 107 miles 266.8 ACSR @ $16,600 $1,776,200 177 miles 7#8 Alumoweld @ $15,000 2,655,000 River Crossings, 16,000 15 Terminals @ $35,000 525,000 Total ($4,972,200) Use $4,975,000 Annual cost Amortization 35 years, 9% interest, quarterly payments nl $ 468,645 Operations & Maintenance .5 24,875 Total $ 493,520 The following parameters have been used for the economic evaluation:. Low load growth projections. Cost for diesel generation from Figure |IV-2 a. For local generation. (units < 500 kw) b. For central generation in Dillingham/Naknek (units > 1000 kw) 5% line losses for transmission from Dillingham/Naknek bus. Tie lines operational in 1980 Page D-467 Transmission Intertie - Low Load Growth (Power Cost at Local Distribution Bus) Diesel Generation Only 1980 1985 Annual MWh 2036 2736 Cost for Local Generation Annual Cost (1000-$) 519 848 ¢/kWh 2D.5) 31 20 Year Average ¢/kWh (Local Generation Only) Cost for Central Generation Purchased Power* 260 442 Tie Lines 494 494 Annual Cost (1000$) 754 936 ¢/kWh 37 34.2 20 Year Average ¢/kWh (Intertie with Dillingham/Naknek) * Wholesale = Dillingham/Naknek Distribution bus cost + 45%. 1990 3436 1323 38.5 40.3 707 494 1201 35 37.1 1995 4494 2179 48.5 1175 494 1669 Bi.1 2000 5552 3415 61.5 1854 494 2348 42.3 Page D-468 Lake Tazimina, Elva and Grant for Dillingham/Naknek and 13 Villages This investigation evaluates the following scenarios for the high and _ low load projections: a. Dillingham/Naknek Power supply from Lake Elva, Lake Grant and Diesel (without use in 10 villages). b. Dillingham/Naknek and 13 villages. Power supply from Lake Tazimina only. e. Dillingham/Naknek and 13 villages. Power supply from three hydro plants. The following cost estimates and parameters have been used for the evaluations: Installation Cost 1979 $ Lake Tazimina 2x15 MW Forebay Dam $ 2,750,000 Reservoir Dam 230,000 Reservoir Control Valve 430,000 Spillway 1,200,000 Open Cut 160,000 Penstock 5,800,000 Powerhouse 2,000,000 Powerhouse Equipment 10,500,000 Controls 250,000 Project Roads 700,000 Operator Cottages 440 ,000 Transmission Lines (181 miles - 138 kV, 39) 17,900,000 Substations (3) 1,185,000 $43,545,000 Engineering 6,153,000 Contingencies 8,722,000 Total $58,420,000 Escalated at 10%/year to 1985 (earliest year on line) $94,085,994 Grant Lake 1 x 1.5 MW Dams Spillway Intake Waterways Equipment Powerhouse Substations & Terminals Transmission (65 miles - 66 kV,SWGR) Phase/Frequency Conversion Engineering Escalated at 10%/year to 1985 Total (earliest year on line) Lake Elva 1 x 1.5 MW See Appendix D-4 Dillingham/Naknek_Intertie Single Wire Ground Return to complete village loop, 67 miles, 40 kV, 266.8 ACSR Phase conversion equipment in Dillingham and Naknek 2x 1MW (earliest on line in 1980) Annual Cost Amortization 35 years, 5%/year Quarterly Payments Insurance ($2/$1000) Operations & Maintenance Total Tazimina $5,711,020 188,172 940 , 860 $6,840,052 Grant $1,166,252 28,427 200, 000 $1,404,679 Page D-469 1979 $ $ 540,000 300,000 135,000 1,925,000 1,805,000 675,000 1,000,000 2,600,000 450,000 2,500,000 $11,930,000 $19,213,384 1979 $ $ 1,498,000 1,000,000 $ 2,498,000 Intertie $ 151,600 25,000 $ 176,600 Page D-470 Cost Allocation for Tazimina (Total Cost $6,840,000/year) According to Use Ratio: Dillingham/Naknek 10 Villages lliamna Total MWh/Year MWh/Year MWh/Year MWh/Year 1980 High 20660 (82%) 3230 (12%) 1543 (6%) "25433 (100%) Low 18456 (84%) 2036 ( 9%) 1571 (6%) 21874 (100%) 1990 High 49082 (80%) 9281 (16%) 2887 (5%) 61250 (100%) Low 29840 (85%) 3436 (10%) 1761 (5%) 35037 (100%) 2000 High 96696 (79%) 16962 (14%) 8270 (7%) 121928 (100%) Low 39048 (83%) 5552 (12%) 2149 (5%) 46749 (100%) Average% 82.1% 12.23 5.7% 100% Allocated Cost $5,616,000 $834,000 $390 ,000 $6,840,000 Other Parameters Cost for diesel generation from figure 1V-2. Supply of peak demand, spinning reserve by diesel not taken into account. Transmission losses not taken into account. *~e2 _ Page D-471 DILLINGHAM/NAKNEK - LOW LOAD GROWTH Power Cost at Distribution Bus (Local Diesel only) 1985 1990 ° 1995 2000 Peak kW (noncoincident) 5230 6410 7380 8350 Annual MWh 24148 29840 34444 39048 Elva + Grant kW (installed) 3000 3000 3000 3000 Elva + Grant annual MWh 20539 20539 20539 20539 Tazimina kW (installed) 30000 30000 30000 30000 Tazimina Annual MWh 131400 131400 131400 131400 Annual Cost (1000$) Tazimina 5616 5616 5616 5616 ¢/kWh pau 18.8 Ges! 14.4 15 Year Average ¢/kWh 18 (Tazimina, Dillingham/Naknek intertied) Elva 1078 1078 1078 1078 + Grant 1405 1405 1405 1405 + Intertie 177 177 177 177 + Diesel 379 1237 2378 4090 Total 3039 3897 5038 6750 ¢/kWh 12.6 3.4 14.6 17.3 15 Year Average ¢/kWh 14.2 (Elva, Grant, Diesel Dillingham/Naknek intertied) Three Hydros 8099 8099 8099 8099 ¢/kWh 33.5 27.1 2oe5 20.7 15 Year Average ¢/kWh 25.9 (3 Hydros, Dillingham/Naknek intertied) Diesel Only 2535 3969 5890 8630 ¢/kWh 10.5 13.5 17.1 22.1 15 Year Average ¢/kWh 15.6 Page D-472 DILLINGHAM/NAKNEK - HIGH LOAD GROWTH Power Cost at Distribution Bus 1985 1990 1995 2000 Peak kW (noncoincident) 7225 10080 14240 18400 Annual MWh 34871 49082 72889 96696" Elva + Grant kW (installed) 3000 3000 3000 3000 Elva + Grant Annual MWh 20539 20539 20539 20539 Tazimina kW (installed) 30000 30000 30000 30000 Tazimina Annual MWh 131400 131400 131400 131400 Annual Cost (1000$) Tazimina 5616 5616 5616 5616 ¢/kWh AG 11.4 Tel’ 5.8 15 Year Average ¢/kWh 9.9 (Tazimina, Dillingham/Naknek intertied) Elva 1078 1078 1078 1078 + Grant 1405 1405 1405 1405 + Intertie 177 ‘ad 177 177 + Diesel 1505 3796 8952 16831 Total 4165 6456 11612 19491 ¢/kWh 11.9 13.2 15.9 20.2 15 Year Average ¢/kWh 5) (Elva, Grant, Diesel Dillingham/Naknek intertied) Three hydros 8099 8099 8099 8099 ¢/kWh 23.2 1625 11.1 8.4 15 Year Average ¢/kWh 14.3 (3 Hydros, Dillingham/Naknek intertied) Diesel Only 3162 6528 12464 21370 ¢/kWh 10:5: 13.3 Vial 22.1 15 Year Average ¢/kWh 15.6 (Local Diesel only) Page D-473 10 VILLAGES WITH INTERTIE - LOW LOAD GROWTH (Power Cost at Distribution Bus) 1985 1990 1995 2000 Annual MWh 2736 3436 4494 5552 + 5% Transmission losses Annual Cost (1000$) Tazimina : 834 834 834 834 + Intertie 494 494 494 494 Total 1328 1328 1328 1328 ¢/kWh 48.5 38.6 29.6 23.9 15 Year Average ¢/kWh 35.1 (Tazimina, Villages intertied) ILIAMNA/NEWHALEN/NONDALTON - LOW LOAD GROWTH (Power Cost at Distribution Bus) 1985 1990 1995 2000 Annual MWh 1571 1761 1955 2149 Annual Cost (1000$) Tazimina 390 390 390 390 ¢/kWh 24.8 22.1 19.9 18.1 15 Year Average ¢/kWh (Tazimina) 21 Diesel only* 353 ' 484 674 956 ¢/kWh 22.5 27.5" - 34.5 44.5 15 Year Average ¢/kWh (Diesel only) 32.5 *From System Planning Study, 1978. Page D-474 Chignik Bay Hydro, Coal and Intertie The following possible developments are investigated for the three communities in this area: a. Low Load Growth 7 Diesel Generation Only (Central Plant) plus Transmission/Distribution Intertie b. Low Load Growth ‘ Diesel Generation (Central Plant) plus 2 x 700 kW Hydro in 1984 plus Transmission/Distribution Intertie CG: High Load Growth Diesel Generation (Central Plant) 2 x 700 kW Hydro in 1983 plus 2 x 400 kW Hydro in 1994 plus Transmission/Distribution Intertie plus d. High Load Growth Diesel Generation (Central Plant) 4 x 1 MW Coal Fired Steam Generators in 1984 Transmission/Distribution Intertie Cost estimates and parameters used for the various scenarios: a. Low Load Growth - Diesel Only Installation Schedule and Cost 1980 Powerplant with: 30' x 40' Building 2 x 350 kW Engine Generators (Diesel) 80000 gallon Fuel Storage Electrical and Mechanical Equipment Substation 480/24900V - 350 kVA 1980-$ $ 457,000 1980 Distribution Plant With: 8 miles of 30 24.9/14.4 kV overhead line 15 miles of 19 14.4 kV overhead line 1980-$ $1,427,000 Page D-475 1985 Add 350 kW Engine Generator with Switchgear 1985-$ $ 132,600 1995 Replace 2 x 350 kW Engine Generators 1995-$ $ 516,000 Amortization Life expectancy engine generators - 15 years. Life expectancy buildings, distribution, etc. - 35 years. Loans: 5% interest/year, quarterly payments - 15 respectively 35 years Maintenance 2% of investment escalated 7% per year Operations 1 operator Insurance (generation only) $3/$1000 escalated at 7%. Fuel Rate 8 kWh/gal. (including losses) Lube oil is assumed at 10% of fuel oil. Distribution losses neglected. Page D-476 CHIGNIK BAY POWER COST - LOW LOAD GROWTH AT DISTRIBUTION BUS (Diesel Only) 1980 1985 1990 1995 2000 Peak kW 405 447 488 604 719 Annual MWh 1698 1870 2042 2614 3187 Installed Generation Capacity kW 700* 1050 1050 1050 1050 Annual Cost (1000$) Fixed Cost Amortization 121.9 133.4 133.1 168.2 168.2 Insurance 1.4 2.6 3.5 4.7 6.2 Total Fixed Cost 123.3 135.7 136.6 172.9 174.4 Variable Cost Fuel + Lube 158.8 264.8 407.1 697.5 1135.0 Operations/ Maintenance 22 35 49.2 69 96.7 Total Variable Cost 180.8 299.8 456.3 766.5 1231.7 Total Cost 304.1 435.5 592.9 939.4 1406.1 ¢/kWh 17.9 23.3 29 35.9 44.1 20 Year Average : ¢/kWh (Chignik Bay, 30.1 Diesel only) *Firm capacity is assumed by maintaining existing cannery engine generators on standby. b. Low Load Growth - Diesel + 700 kW Hydro Installation Schedule and Cost 1980 Power Plant with: 30' x 40! Building 2 x 350 kW Generators 80000 Gallon Fuel Storage Electric & Mechanical Equipment Substation 480/24900V - 500 kVA 1980-$ $459,000 Distribution Plant with: Page D-477 8 miles of 38 - 24.9/14.4 kV overhead line 15 miles of 19 - 14.4 kV overhead line 1980-$ 1984 Hydroelectric Plant with 2 x 700 kw (700 kW prime) 1979-$ Dam 840,000 Flume 210,000 Penstock 715,000 Powerhouse 142,000 Powerhouse Equipment 568 ,000 Substation 1500 kVA 50,000 $2,525,000 Engineering 600,000 Contingencies 400,000 Total 1979 $ $3,525,000 with 10% escalation per year 1984-$ Amortization Life cycle diesel engines - 15 years all other - 35 years Loans 15 respectively 35 years Maintenance 7%/year Operations 1 operator Insurance (Generation only) $3/$1000 - escalated at 7%/year Fuel Rate 8 kWh/gal. (including losses) Lube oil is assumed at 10% of fuel oil 5% interest/year, quarterly payments $1,427,000 $5,677,048 2% for diesel; 2% for hydro - escalated at Page D-478 CHIGNIK BAY POWER COST - LOW LOAD GROWTH AT DISTRIBUTION BUS (Diesel plus Hydro) 1980 1985 1990 1995 2000 Peak kW 405 447 488 604 719 Annual MWh 1698 1870 2042 | 2614 3187 Installed Capacity kW 700* 2100 2100 2100 2100 Annual Cost (1000$) Fixed Cost Amortization 721.9 474.1 474.1 460.1 460.1 Insurance 1.4 19 27.9 37.4 50.1 493.1 502 497.5 510.2 nm w& w Total Fixed Cost 1 Variable Cost Fuel + Lube 158.8 --- --- --- --- Operation + Maintenance 22 44.9 62.9 88.3 123.8 Total Variable Cost 180.8 44.9 62.9 88.3 123.8 Total Cost 304.1 538 564.9 585.8 634 ¢/kWh 17.9 28.8 27.7 22.4 19.9 20 Year Average ¢/kWh (Chignik Bay, 23.3 Diesel plus hydro) *Firm capacity is assumed by maintaining existing cannery engine generators on standby. c. High Load Growth - Diesel + 700 kW _+ 400 kW Hydro Installation Schedule and Cost 1980 Power Plant With: 30' x 40' Building 3 x 300 kW Engine Generators (diesel) 80000 gallon fuel storage Electrical + mechanical equipment Substation .48/24.9 kV, 1500 kVA 1980-$ $ 531,000 Page D-479 Distribution Plant With 8 miles of 30 - 24.9 kV Overhead Line 15 miles of 19 - 14.4 kV Overhead Line 1980-$ $1,427,000 1983 Hydroelectric Plant with 2 x 700 kW (700 kW Prime) as described under (b.) 1979-$ $3,525,000 with 10% escalation per year 1983-$ $5,160,952 1994 Hydroelectric Plant with 2 x 400 kW (400 kW prime) with: 1979-$ Dam $930,000 Penstock 780,000 Powerhouse 85,000 Powerhouse Equipment 360,000 Substation 1000 kVA 50,000 $2,205,000 Engineering 500,000 Contingencies 360,000 $3,065,000 With 10% escalation per year 1994-$ $12,803,265 1997 Add 500 kW Diesel Generator 1979-$ $300,000 with 10% escalation per year 1997-$ $1,668,000 Amortization, Maintenance, Operations, Insurance and Fuel Rate as listed under (b.) CHIGNIK BAY POWER COST - HIGH LOAD GROWTH Peak kW Annual MWh Installed Capacity kW Diesel MWh* Annual Cost (1000$) Fixed Cost Amortization Insurance Total Fixed Cost Variable Cost Fuel + Lube Operation + Maintenance Total Variable Cost Total cost ¢/kWh 20 Year Average ¢/kWh (Chignik Bay, AT DISTRIBUTION BUS (Diesel Plus Hydro) Page D-480 1980 1985 1990 1995 2000 477 784 1090 1752 2415 1995 3334 4673 7646 10620 900 2300 2300 3100 3600 1995 29.8 320 623 2229 126.5 446.7 446.7 1226 1384.7 1.6 195.2 26.9 53 77.1 128.1 465.9 473.6 1279 1461.8 169.6 3.8 58 151 721.6 25.6 47.7 66.9 121.2 210.8 195.2 51.5 124.9 272.2 932.4 323.3 517.4 598.5 1551.2 2394.2 16.2 15.5 12.8 20.3 22.5 17.5 Diesel plus hydro) *Applying typical load duration curve and assuming prime power for hydros only. ds Page D-481 High Load Growth - Coal This part investigates the utilization of a coal fired steam plant at Chignik with transmission interties to Chignik Lagoon and Chignik Lake. Waste heat utilization has not been taken into account in this evaluation. The cost for the mined coal, however, reflects an assumed production of approximately 40 tons/day. Investment cost and schedule 1980 Power plant as under c) 1980-$ 531,000 Distribution plant as under c)1980-$ 1,427,000 1983 4 MW coal fired steam plant 1983-$ 8,784,600 (from App. C-5) + Roads 1983-$ 882,000 Amortization 35 years at 5% per year, quarterly payments, diesel generators: 15 years. Maintenance 2% of investment escalated 7% per year Operations 1 operator for diesel plant (1979-$ 30,000/Year) 2 operators for coal plant Insurance $3/$1000 escalated at 7% Fuel Rate and Cost a. Diesel 8kWh/gallon (incl. losses) + Lube 10% of fuel b. Coal 10440 BTU/16 $25.00/ton at mine $ 3.50/ton transportation 1979 $28.50/ton escalated at 3% per year Plant efficiency 1.23 kWh/Ib. = 2450 kWh/ton Page D-482 CHIGNIK BAY POWER COST - HIGH LOAD GROWTH at distribution bus (Diesel Plus Coal) 1980 1985 1990 1995 2000 Peak kW 477 784 1090 1752 2415 Annual MWh 1995 3344 4673 7646 10620 Installed Capacity kW 900 4900 4900 4900 4900 Diesel MWh 1995 oore cece ooce cone Annual Cost (1000$) Fixed Cost Amortization 126.5 713.3 13.3 700 700 Insurance 1.6 41.9 58.7 81.6 114.2 Total Fixed Cost 128.1 1So6e 772 781.6 814.2 Variable Cost Fuel + Lube 169.6 coon ooo- eoa= ao Operation + Maintenance, Coal 25.6 107.6 150.9 211.6 296.3 Total Variable Cost 19572 154 226.2 354.2 526 Total cost 823753 909.2 998.2 1135.8 1340.2 ¢/kWh 16.2 27:2 2154 14.9 12.6 20 Year Average ¢/kWh (Chignik Bay, 18.5 Diesel and Coal) 0 Appendix D - Economic Evaluations Page D-483 BRIS3/F 9. Lake Kukaklek (First Stage - 2 x 14 MW) Investment cost and schedule . 1979-$ 1985 Hydroplant with: Overflow weir 500,000 Intake 800,000 Penstock 6,651,000 Powerhouse , 1,400,000 * Operators Cottage 700,000 Project Roads (15 mi.) 600,000 Powerhouse equipment 10,500,000 Substations (3) 1,350,000 Transmission | (122 miles, 138 kV, 39 12,065,000 34,566,000 Engineering 4,000,000 Contingencies 7,650,000 Total 1979 $ $46,216,000 cost in 1985 at 10% per year escalation $81,874, 463 Amortization 35 years, 5%/year, quarterly payments. Insurance $2/$1000 Operations and Maintenance 1% Annual Cost $5,952,000 Page D-484 10. jliamna - Variable Speed Generation For a low load growth case the influence of increased fuel economy is investigated. Performance data has only been available for Cummins engines. It is anticipated that engines of similar size from other manufacturers will perform similarly. Two engine generator sets as schematically ‘shown below are assumed to be installed: DIESEL ENGINE GEARBOX GENERATOR GEARBOX DIESEL ENGINE 2222 RPM/260 kW Bis) 1800 RPM 1800 RPM/225 kW “00: 1451 RPM ioe Ee, fee Ee OOED Ee ak | 400 kw 1.24; -81 2222 RPM/135 kW oof | 1800 RPH/129 kw 145) RPM/108 kw A: 131. 1:1.24 1132 RPM130 kw 1.59:1 1:51.59 1132 RPHY B3 kw To obtain comparable capacity with a conventional configuration, and use engines with similar characteristics, 4 engines @ 230 kw each are necessary. Installation cost for the two alternatives are estimated to be approximately equal. Utilizing the fuel consumption data for multiple speed arrangements as shown on Table D-10.1 leads to a continuous efficiency of 12 kWh/gallon. The constant speed engines (1800 RPM, 230 kW rated) will vary in their fuel economy throughout the low load years according to Figure D-10.1 which has been developed from the engine manufacturer's fuel consumption data and a load duration curve based on a .57 load factor. It is assumed that in both cases the engines are being operated in the most fuel efficient configuration. Lower maintenance cost, which can be expected for the gearbox arrangement due to the "less revolutions turned", are not being taken into account. The possible fuel savings for this load case from 1980 to 2000 are shown. RPM 2222 1800 1451 1132 * Fuel at 7.52 ** Continuous LOAD RANGE** 260 220 135 230 135 102 75 60 200 120 70 60 130 50 and below FUEL RATES FOR VARYING SPEEDS AND LOAD RANGES CUMMINS C-400 220 135 95 135 102 1S) 60 120 70 60 35 50 30 Ibs/gal. Duty, Base RATE kWwh/Gal 11.33 10.79 9.44 12 1133 10.79 9.44 6:5 12 11.33 10.79 9.44 10.79 9.44 TABLE D-10.1 Page D-485 RPM 2222 1800 1450 1132 LOAD RANGE** 135 90 110 15) 60 90 50 70 CUMMINS C-220 90 72 75 60 50 50 36 30 RATE kwh/Gal 10.79 9.44 12 11.33 10.79 12+ 11.33 12+ Page D-486 From this data the following graph has been developed: 3000 2560 MWH 2000 ; o i500 , 1000 «a8? 7 at . o © S B kWh/Gal FUEL EFFICIENCY RANGES FOR 230 kW GENERATORS LaF ut ILIAMNA - NEWHALEN - NONDALTON FIGURE D-10.1 This curve is valid for a multiple of 230 kW engines supplying energy according to a load duration curve based on a load factor of .57. Annual MWh AR Fuel Gal. (a) Fuel efficiency kWh (b) Fuel Gal. (b) $/Gal. Annual $ for Fuel (a) Annual $ for Fuel (b) Annual Savings $ (a) (12934) Accum. Savings m= oO VY wou ILLAMNA - LOW LOAD GROWTH FUEL COST COMPARISON (Variable Speed/Single Speed Engines) 1980 1382 On 115166 10.4 132884 s13 84071 97005 1980 to 2000 Gearbox Diesel Engines Conventional Diesel Engines © 1985 1571 cor 130916 10.7 146822 1.02 133534 149758 (16224) 1990 1761 ~OF 146750 11 160090 1.43 209822 228928 (19106) $392890 . Page D-487 1995 1955 sor 162916 Tse 174553 2.01 327461 350851 (23390) 2000 2149 oo. 179083 11.5 186869 2.81 503224 525101 (21877) APPENDIX E COMMENTS AND OTHER REPORTS Page E-491 E-] REVIEW COMMENTS ON DRAFT REPORT Department of Energy - Region X Department of the Interior - Fish and Wildlife Service Department of the Army - Alaska District, Corps of Engineers October 1979 Department of Energy Region X ml Date’ October 23, 1979/ _- ETFs Zi (ie Mee SAL q byer4 Reply to Jack B. Robertson, Regional Representative of the Secretary, Region X ~ Attn of. Subject’ Review of draft report "Bristol Bay Energy and Electric Power Potential - Phase I" To Robert Cross, Administrator, Alaska Power Administration Thank you for the opportunity to review the subject document. We found it to be comprehensive; it should be a valuable source document for those concerned with energy in the Bristol Bay area. Our only question concerns the lack of information on biomass as a potential energy resource for the area. If such a potential exists, we feel that it should be considered in concert with the other alternative energy sources. You may wish to have your designee contact Craig Chase of our staff to discuss the Department's biomass programs and objectives. He may be reached at 399-1842 (FTS). cc: Craig Chase Fred Chiei UNITED STATES DEPARTMENT, OFTHE INTERIOR FISH AND WILDLIFE SERVICE 1011.€, TUDOR RD»- ‘ IN REPLY REFER TO: ANCHORAGE, JAASKA. 99803 R7-1 (907) 276-3800 17 oct 979 Mr. Robert J. Cross, Administrator Alaskan Power Administration P.O. Box 50 Juneau, Alaska 99802 Dear Mr. Cross: We have reviewed the draft report "Bristol Bay Energy and Electric Power Potential Phase I." The report is an initial analysis of potential power resources and energy demands in the Bristol Bay region. We have no specific comments regarding fish and wildlife resources, However, various sections of the document reflect that associated environmental considerations have not been determined. It should be noted that such considerations would be required as part of the analysis of any specific project. The opportunity to review the report is appreciated and we look forward to your further coordination with our office. Masecehy ea . ? Ypcl-¥ e ls eirets fig Acting Assistaiié’ A me | wi ec: AOES, WAES DEPARTMENT OF THE ARMY ALASKA DISTRICT. CORPS OF ENGINEERS P.O. BOX 7002 ANCHORAGE, ALASKA 99510 REPLY TO ATTENTION OF: feo ay 18 Qcr. 1979 NPAEN-PL-R A PURER ACM, Mr. Robert J. Cross Administrator Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 Dear Mr. Cross: Thank you for the opportunity to review. the draft report "Bristol Bay Energy and Electric Power Potential - Phase I," by Robert W. Retherford Associates. We have no comments on the report at this time except that it should prove helpful in our evaluation of small hydroelectric power in Alaska. Sincerely, JAY K. SOPER Chief, Engineering Division Page E-499 E-2 CHIGNIK COAL FIELD COST STUDY U.S. Department of the Interior Bureau of Mines. Cost Study for the Development of the Chignik Coal Field. August 1979 United States Department of the Interior BUREAU OF MINES P. Q.. “Box 550 Juneau, Alaska August 24, 1979 Robert Retherford C. C. Hawley and Assoc. Star Rt. A, Box 78-D Anchorage, Alaska 99507 Dear Mr. Retherford: On August 2, 1979, you contacted Tom Pittman with regard to potential development of the Chignik Bay coal field. He referred you to Dave Carnes, who instructed me to prepare a cost study for two rates of production, 20 tons per day and 100 tons per day. I take pleasure in submitting to you the report on the results of my study: my findings which I believe will help you. In this report I present the summary of my analysis. The estimated capital and operating and owning costs are given and the parameters under which these were determined are listed. Mine and mill plans and their costs are included. Also enclosed are copies of the charts correlating rippability and seismic wave velocities as requested during our telephone conversation of the 17th of this month. If I can be of further assistance to you, please feel free to contact me. Sincerely, ' Abad. Base Op Susan B. Howell, Mining Engineer Enclosures INTERNAL REPORT U. S. BUREAU OF MINES COST STUDY CHIGNIK BAY COAL FIELD Susan B. Howell Mining Engineer TABLE OF CONTENTS Conclusion = seeveceeccsees 1 Introduction ..cccccccceeee 2 Parameters = eww eoccceee ee Geology tbs cle sbreisictoe oe Coal Seam — wa ween wigigverg sere. 140 Mining Plan seecceseeee ee = 0 Milling Plan ..ccocce sere eisai ne Cost Summary cecccsscece nee Bibliography ...... Jesecess,- Th Appendix vosccccneccees 12 CONCLUSION Capital cost for a 20 ton per day mine would be $1,048,458. Operating costs per week would be $3,039.57. Cost per ton being $21.71. The total capitol cost for a 100 ton per day mine would be $1,154,458 and operating costs per week would be $12,670.28. Cost per ton being $18.10. The purpose of this report is to determine the probable cost per ton of coal produced at a rate of 20 or 100 tons per day from the Chignik Bay coal field. The coal bed being considered is exposed at the mouth of the Chignik River. Certain basic parameters were assumed for the purposes of this report. INTRODUCTION PARAMETERS These were for both production amounts. 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 7 foot seam throughout 1:6 overburden (average) year-round stockpiling 5 day work week 8 hour day 1 nile road to put in 90% mine recovery advance stripping run of mine (ROM) 24 inch coal density = 82.64 1b/ft3 (ROM) overburden and coal drilled and blasted assume 20 ft. benches for overburden assume stripping on overburden blasting agent ANFO assume building for shop and mill 16) 17) 18) 19) 20) 21) 22) 23) 24) 1) whole operation movable except dock (including buildings) summer milling and shipment 1 1/2 inch minus product ship with tides charter barge cartonend purchased Seattle 10 year capital writeoff operation may be moved to Whalers Creek or Thompson Valley water from river used 70% mill recovery SPECIAL PARAMETERS 20 TPD one man Cost study based on: Average one day per week on each of the following activities: a) drilling and blasting overburden b) removing overburden c) drilling and blasting and loading coal d) milling and loading barges e) repairs, maintenance, tending stockpiles, etc. SPECIAL PARAMETERS 100 TPD 1) 5 men 2) basic same equipment as 20 TPD 3) more efficient operation GEOLOGY The Chignik coal field contains up to 17 separate seams. These high- volatile B bituminous high ash content (20%) coals appear to have distinct variations in character, thickness and ash content (Paige, 1906). The basal Coal Valley member, which contains the majority of the coal, is com- posed of siltstones, carbonaceous to lignitic shales and sandstones that are locally bentonitic. This member was probably deposited simultaneously in a continental, transitional and marine shelf complex between a volcanic island arc to the north and an oceanic trench to the south (Fairchild). In addition to deposition on an irregular surface, the formation was subjected to episodic differential vertical movement following periodic plutonic intrusions. The current structural configuration is a result of strong orogenic Pliocene deformation. This has lead in the area of Chignik Bay to adjacent synclines and anticlines which are further com- plicated by the presence of several faults. The inconsistancy of bed depo- sition and complexity of geological structure and gradational contact with the remainder of the Chignik Formation, makes exact location of coal and calculation of surface mineral reserves in any one area difficult. COAL_SEAM Figure 1 (see appendix) shows the area overlain by the Chignik Formation (light blue) and the darker blue represents the area exposure of the Coal Valley Member (it probably underlies most of this area too, and extends out under the Bay). Shown in figure 2, is a geologic section of the exposed rock at the proposed area. Figure 3 illustrates a measured coal section. Figures 4 and 5 show the washability characteristics of this coal. Figure 6 shows the proposed mine and mill sites. Results of the limited testing that has been done are shown in tables in the appendix, (Conwell and Triplehorn, 1978). As can be seen, the coal seam is steeply pitching to the southeast. MINING PLAN The natural surface is bulldozed of all loose materials. Then it is drilled with up to 22 ft. holes (3 inches in diameter) to aid in forming 20 ft. benches. Upon completion of the drilling, the holes are loaded and blasted. The overburden is then removed by the bulldozer and as mining advances, the overburden is dozed into the area from which the coal has been removed. The advanced stripping uncovers the coal down to the line of economic recovery. The exposed coal is then drilled and blasted and removed up dip. The coal is loaded on a truck using a front-end loader and is stockpiled by the mill. This mining method is shown in figure 7. MINING COST The equipment assumed used in this mining method, their capital cost and operating costs are listed below. Blast Hole Drill and Explosives: I-R LM 100 (YD 90) P 425. Capital Cost Hourly Owning and Operating Cost $111,676 Overburden $56.31 Coal $27.85 Crawler Tractor: Caterpillar Model D-8 Series "K" (FFV1 serial). Capital Cost Hourly Owning and Operating Cost $196 , 704 $81.94 Front-end Loader: Caterpillar Model 988 B Capital Cost Hourly Owning and Operating Cost $200,490 $85.15 Haulage Truck: Terex Model 33-09 (40 ton) Capital Cost Hourly Owning and Operating Cost $237,014 $100.59 MINING EQUIPMENT CAPITAL COST: 20 TPD $745,884 MILLING PLAN Run of mine coal (-24 x 0 inch) is loaded into the hopper of hammermill over bar grizzly and magnet. The coal which has been reduced to 1 1/2 inch minus product, is fed to the jig where a density separation is made. Refuse is sent to the refuse pile, while the clean coal is con- veyed to a centrifuge drier and is then fed into a pivoting coal loading chute to the barge for shipment. The effluent is sent to the settle- ment pond (see figure 8). MILLING COST Capital Cost Hourly Owning and Operating Cost $131,574 ' $60.07 COST SUMMARY TOTAL CAPITAL COST 20 TPD Mining $745,884 Milling | $131,574 Additional $171,000 TOTAL: $1,048,458 TOTAL CAPITAL COST 100 TPD Additional Capital Costs ; 106,000 TOTAL: $1,154,458 20 TPD 100 TPD Operation Drilling and Blasting D & B Coal Dozer Front-end Loader Truck Mill 20 TPD Operation Drilling and Blasting B & D Coal Dozer Front-end © Loader Truck Mill 100 TPD OPERATING COST PER WEEK 20 TPD Operating Cost $/hr hr /wk (56.31) (8) (27.85) (4) (81.94) (12) (85.15) (6) (100.59) (5) (60.07) (8) TOTAL: cost $21.71/ton 100 TPD Operating Cost $/hr hr /wk (56.31) (35) (27.85) (17.5) (81.94) (35) (85.15) (35) (100.59) (20) (60.07) (30) ADDITIONAL WAGES: TOTAL: Cost $18.10/ton $/wk 450.48 111.40 983.28 510.90 502.95 480.56 $3,039.57 $/wk 1,970.85 487.38 2,867.90 2,980.25 2,011.80 1,802.10 $12,120.28 550.00 $12,670.28 10 Li BIBLIOGRAPHY Atwood, W. W., 1909, Mineral resources of southwestern Alaska: U. S. Geol. Survey Bull. 379, p. 108-152, map. - 1911, Geology and mineral resources of parts of Alaska Peninsula: U.S. Geol. Survey Bull. 467, 137 p. Burk, C. A., 1965, Geology of the Alaska Peninsula -- Island arc and con- tinental margin: Geol. Soc. America Mem. 99, 250 p. Caterpillar, 1973, Caterpillar Performance Handbook, edition 3. Conwell, and Triplehorn, 1978, Herenden Bay -- Chignik Coal, Southern Alaska Peninsula. Alaska Geological and Geophysical Surveys; Special Report 8. Dahl, W. H., 1896, Report on coal and lignite of Alaska: U. S. Geol. Survey 17th Ann. Rept., pt. 1, p- 7613-908. Equipment Guide - Book Co., 1978, Green Guide, Equipment Guide -- Book Company. Fairchild, D. T., 1977, Paleoenvironments of the Chignik Formation, Alaska Peninsula: M.S. thesis, Fairbanks, Univ. of Alaska, 168 p. Gates, G. 0., 1944, Port of Herendeen Bay coal field, Alaska: U.S. Geol. Survey Open-File Rept. 2, 5 p. Knappen, R.S., 1929, Geology and mineral resources of the Aniakchak district, Alaska: U.S. Geol. Survey Bull. 797-F, p. 212-221. Lyle, W. M., and Dobey, P. L., 1974, Geologic evaluation of the Herendeen Bay area: Alaska Div. Geol. and Geophys. Surveys Open-File Rept. 48, 20 p. Moore, J. C., 1974, The ancient continental margin of Alaska, in The geology of continental margin (Burk, C.A., and Dorahe, C. L., eds.): New York, Springer-Verlag, p. 811-815. Mular, A. L., 1978, Mineral Processing Equipment Costs and Preliminary Capital Cost Estimation; The Canadian Institute of Mining and Metallurgy: Special Volume 18. Paige, Signey, 1906, The Herendeen Bay coal field: U.S. Geol. Survey Bull. 284, p. 101-108. Staff, Office of Director of Coal Research, 1967, Methods of analyzing and testing coal and coke: U.S. Bur. Mines Bull. 638, p. 25-36. Stone, R. W., 1905, Coal resources of southwestern Alaska: U.S. Geol. Survey Bull. 259, p. 151-171. Figure 1 Geology of Chignik Bay Area (Conwell and Triplehorn 1978) and sample location. Poorly exposed, interbedded, thin, lenticular sandstone and dark shale; some thin bony coal partinas. 0.5" coal-like material. 1.5° interbedded sandstone and shale. 3.0’ sandstone, fine-grained, exay but weathers brown. 4.2° siltstone, sandy with thin coaly partines, 0.8" coal. 2.0" platy, carbonaceous material. 1.1* coal grades to shaly coal na ebene Bbeia, 1S-ce-38 2 1.7" bright coal. 2.0" bone. Eo 1.5" bony coal. 4.7" coal (50! inside upper tunnel). 15-ce-39 2.7" bright coal. 0,3" sheared coal or clay. Part of section in lower tunnel, 3.7" bone and coal, platy. Figure 2 Geologic section of exposed rock, Chignik River (Note changes : : ip rie of coal and partings.) (Conwell and Triplehorn, 978. Figure 3 Senate, Wet Weed Ice T3<04 Te$ S206 Measured coal section in tunnel near Chignik River. (Conwell and Triplehorn, 1978.) Peseription, Baek clay Total Average Aah ro" oem rs ro ans) ns 724 us m7 43a 25 232 362 30.875 ne 634 na 12,040 14 w Specitic Grovity 20° AO 38) NTE RS AS: be US| o » - 90 ” + 2030 Seat Covi | Disiribution 20 + { + 80 Cumulative Sink Ash | 30 a | || zo “ 40 —— - 60 3 & 50 so : 60 4 40 2 é Bien [ie Specitie Gravity s 70 30 80 - 20 Cumulative Flost Ash 90 cal | 10 | + | wl yt 1 a 26 Ts T30T 45 60 75 sot ° ; eae ae Percent 2 oe ond Elementary Ash o 3° 6 9S 2 8 8 2 24. * Gumeiotive Ash Percent in Float Figur : gure 4 Washability characteristics of +20 mesh fraction of raw coal from Chignik River tunnel. (Conwell and Triplehorn, 1978.) _ Specific Grovity ozo ts enn S32 ie Dale) 10 = 90 ' 20 80 x 5 *% 40 60 § 3 2 | = 50 so é | = = i 60 40 8 i | 70 30 | | 80 20 | 90 10 ! wo ° ° 15 30 45 60 75 30 1 cee fa povcaet * id Fema, oar o.°3 6 9 2° 5 8 2 24 : a Cumsiotive Ash Percent in Float j Figure 5 wWashability characteristics of -20 by +65 mesh fraction of raw coal from Chignik River tunnel. Conwell and Triplehorn, 1978. ‘ Figure 6 A mining area M.S. mill site. 16 ws 17 @DOLACE Ovek eC i+ QELACH OVER ELIIsd 17 EICUT =F Wh OW L lem ase wine - a a oem | ce ay we al ¥ ee \ v we Figure 7 Mining plan. Ron oF MINE Coal We SN : ~ Qyv4eweT “7 BAR Y ! GOpPER SS ia E Te \ f \ : i | Ricans - i ' \ i ILS CLEAN ee a a ae — Coel _, REFUSE ord) lds - ea i. i RE Fucs Te . PILE \ 4 Ci UT RTIFUG: OPDei. et. i To a : re SENT UME > be -f : PEVOTING oo ; COAL , | Tr cuoTe is "it To BaRcé s Notes BARGE 1 Figure 8 Mill flow chart. 19 Table 1. Ash and chemical analyses on coal as received (in ppm except where noted). Sample 75-ce- Ash(%)? As? Ke Hg4 Sb® SeS Th? u7 37 32.3 5.0 45 0.12 0.2 0.4 <3 a2 38 12.8 3.0 40 0.07 0.3 0.4 <3 0.6 39 32.3 3.0 110 0.07 0.3 0.3 6.4 1.6 Table 2. Chemical analyses on coal ash, major oxides, and chlorine (%). Sample 75-cc- AlgO3® SOg® CI& CaO® SiOg® P2052 MnO® Fe03® Ky0® MgO® Nay08 Ti? ® 37 32 48 <0.2 38 460 <1.0 0.05 3.5 0.61 1.75 0.15 1.0 38-5 21 10.0 <0.2 61 37.0. <1.0 0.10 10.0 0.63 3.33 0.18 ia 39 35 3.0 <0.2 2.0 42.0 <1.0 0.07 3.2 0.36 1.39 0.15 0.9 Table 3. Chemical analyses on coal ash, trace clements (ppm). Sample 75-cc- Blo Ba!° Ca? Co? Cr10 Cus Ga? La}? Li? Mn? : 37 200 300 <1 15 50 72 30 N 202 - 295 38 700 500 <1 <10 100 79 30 N 125 720 39 300 300 <1 15 15 82 30 <100 ‘250 350 ; 10 Sample 75-cc- Mo19 Nil Pb& Sc? Sr? v9 ye Yb? Zn? Zr 37 T 20 35 20 150 150 56 5 79 200 38 a 30 <25 50 150 300 70 7 81 150 39 7 30 40 20 150 70 50 7 88 300 Determined gravimetrically (ashed at 525°C) by G.D. Shipley. 3 ~Determined by graphite furnace-atomic absorption method by G.O. Riddle and J.G. Crock. Determined by specific ion electrode method by J, Gardner, ~ Determined by wet oxidation - atomic absorption method by J.A. Thomas and G.O. Riddle. Deter: ined by Rhodamine-B method by G.T. Burrow. Determined by X-ray fluoresence by J.S. Walber. Determined by delayed neutron method by H.T. Millard. Determined by atomic absorption by V. Merritt. Determined by atomic absorption by G.D. Shipley. Determined by semiquantitative six-step spectrographic analysis by J.C. Hamilton, N - Not determined or below detection. **Elements searched for but not detected or below limit of determination include Ag, Au, Bi, Cd, Pd, Pt, Sb, Te, W, Ce, Ge, Hf, In, Li, te, Ta, Th, Ti, Eu, Pr, Nd, Sm, Gd, Tb, Dy, Ho, Er, Tm, and Lu. Financial support was in part provided by the USGS (contract 1 $-08-6001-G-207). Major-oxide and trace-element analyses were performed by the USGS. 20 Table 5. Fusibility of ash and sulfur forms and free-swelling index (FSI). Rs Fusibility(OF) Sulfur(%) Sample 75-cc- Condition LD.? Soft Fluid Sulfate Pyritic Organic FSI 37 2 2,575 2,685 2,770 0.02 0.57 0.49 a 3 0.02 0.58 0.50 4 . 0.03 0.83 0.71 38 and 39 2 2,800+ 0.2 0.57 0.76 0 Combined 1:1 3 0.2 0.58 0.78 4 0.3 0.76 2,01 lnitial deformation. Table 4. Proximate and ultimate analyses and calorific value. Proximate analyses(%) Ultimate analyses(%) Calorific Vol. value Sample 75-cc- Condition! Moist. mat.2 FC? Ash Hydrogen Carbon Nitrogen Oxygen Sulfur (Btu) 37 ZL 2.1 32.1 36.9 28.9 4.3 52.4 0.5 12.8 ad 9,140 2 2.3 32.1 36.8 28.8 4.3 52.3 0.5 13.0 it 9,130 3 38.8 37.7 29.5 4.2 53.5 0.5 11.2 AE 9,340 4 . 46.6 53.4 5.9 15.9 OF, 15.9 1.6 13,260 38 and 39 a 2.0 33.8 41.1 23.1 4.8 57.0 0.5 13.2 1.4 10,100 Jombined 1:1 2 2.2 33.7 41.1 23.0 4.8 66.9 0.5 13.5 1.3 10,090 3 34.5 42.0 23.5 4.6 58.2 0.5 11.8 a4 10,310 4 45.1 54.9 6.1 76.0 0.7 15.4 1.8 13,490 \eondition: 1 - air dried; 2 - as received: 3 - moisture free; 4 - moisture free and ash free. 2 Volatile matter. Fixed carbon, Table 6 Proximate analyses, Chignik River coal (in percent except where noted). | Calorific value Semple 75-cc- Moisture Ash Volatile matter Sulfur Fixed carbon (Btu) 1 1.16 11.53 37.25 2.75 47.30 12,486 2 1.67 69.40 16.40 - 8 13.53 - 3 1.65 18.10 35.35 ° 1.37 44.90 11,170 4 1.50 23.55 32.61 0.31 42.34 10,186 5 1.35 31.59~ 29.54 0.50 37.53 9,199 6 1.35 45.54 24.34 0.58 28.77 6,889 Table .7 Parr formula rank determination, Chignik River coal. Sample 75-ce- : Fixed carbon(%)!_ Volatile matter(%)1 Calorific value (Btu)? 1 55.07 44.93 13,848 3 58.03 41.97 13,970 4 58.47 41.53 13,753 5 58.77 ’ 41.23 14,109 6 ] 59.32 40.68 13,820 pry mineral, matter-free basis. 2ssoist mineral, matter-free basis, \ Table 8 Sink-float results of +20 mesh fraction of raw coal from Chignik River tunnel (91% of raw coal). Specific gravity Actual product Cumulative float Cumulative sink +0.10 Sp. Gr. Sink Float Wt.(%) Ash(%) Wt.(%) Ash(%) Wt.(%) Ash(%) Material (%) Ordinate D1 - 1.3 22.67 4.8 22.67 4.8 190.00 23.4 : 11.3 1.3 1.4 35.11 9.8 57.78 7.8 Tico 28.8 44.2 40.3 1.4 1.5 9.31 22:0 66.89 9.8 42.2 44.6 15.1 58.3 1.5 1.6 6.03 32.8 72.92 7 33.1 50.9 9.6 69.9 1.6 at 3.58 39.8 76.50 13.0 27.1 54.9 - 74.7 7 1.8 8.92 45.9 85.42 16.4 23.5 56.8 : 81.0 1.8 - 14.58 64.1 100.00 23.4 14.6 64.1 - 92.7 lordinate D, according to ASTM. Table 9 Sink-float results of -20. by +65 mesh fraction of raw coal from Chignik River tunnel (8% of raw coal).. Specific gravity _ Actual product Cumulative float Cumulative sink +0.10 Sp. Gr. Sink Float Wt.(%) Ash(%) Wt.(%) Ash(%) Wt. (%) Ash(%) _Material(%) Ordinate Dt : 1.3 1.48 4.9 1.48 4.9 100 24.4 - 0.7 1.3 1.4 54.20 5.1 55.68 5.1 98.6 24.7 62.0 28.6 1.4 1.5 7.80 18.4 63.48 6.7 44.4 48.6 12.9 59.6 1.5 1.6 5.09 28.1 68.57 8.4 36.6 55.0 9.3 66.0 1.6 LT 4.16 37.8 72.73 10.0 31.5 59.4 - 72,7 17 - 27-27 ' 62:8 100.00 24.4 27.3. 62.8 - 86.4 ordinate D, according to ASTM. Rippers-15 SO . 9 Series D Ripper BY SEISMIC WAVE VELOCITIES D9G RIPPER PERFORMANCE ESTIMATED Multi or Single Shank No Production ved 3¥0 NOW! wo? $3490 'F SIVaINIW 3v7S ISIHDS SNDOY DIHdYOWVLIW 3NOIS3WIT 3HDI1V) VIDD3NE 3LV43WOTDNOD 3NOISAV1D 3NOLSIUS 3NOISONVS 3IVHS SNDOY AYVINIWIGIS 9204 evar Dysve 31INVED $XDO¥ SNOINO! NL WIdvV1D AviD wWosdOL x pucres 0001 * pucres 104g joey UY Aj/D0)9, ooo1 ow uy Al saaddiy-91 Velocity in Meters cond x 1000 Velocity in Feet Per Second x 1000 0 é 12. 13° 14 a TOPSOIL CLAY GLACIAL TILL IGNEOUS ROCKS GRANITE BASALT TRAP ROCK SEDIMENTARY ROCKS SHALE SANDSTONE ‘SILTSTONE CLAYSTONE CONGLOMERATE BRECCIA CAUCHE LIMESTONE METAMORPHIC ROCKS; SCHIST SLATE MINERALS & ores COAL IRON ORE SAILIDOT3ZA JAVM OIWSISS Ad GALVWILSA JONVWYOS Yad YaddIY H8a dadd)y q saliag g “ON yUeYS ajBuls pue ninyy uonsnpoig RiPPAGLE ESSE MARGINAL __ NON-RIPPABLE ttn et Tec anenng Tp eee eos 0 1 3 Velocity in Meters Per Second x 1000 S rhligld Ragectllrege lots etltseillaal Velocity in Feet Per Secondx 10000 1 2 3 4 5S 6 7 8 9% 0 W 2 13 14 ~=15 TOPSOIL CLAY GLACIAL TILL IGNEOUS ROCKS GRANITE BASALT TRAP ROCK ISEDIMENTARY ROCKS SHALE SANOSTONE SILTSTONE CLAYSTONE CONGLOMERATE BRECCIA CAUICHE LIMESTONE METAMORPHIC ROCK - SCHIST QUARTZITE GNEISS ‘SLATE MINERALS & ORES COAL uononpoig SAILIDOTSA SAVM SIWSIAS AG G3LVWILSS JONVWYOd Yad Y3ddil 420 Li -saaddiy Page E-535 E-3 TAZIMINA HYDRO PROJECT IMPACT ON FISHERIES State of Alaska. Department of Fish and Game. Letter dated October 4, 1979 and October 24, 1979. Office of the Governor. Letter dated November 1, 1979. ) : | , | : i STATE OF ALASH / -—— October 4, 1979 Department of Energy Alaska Power Administration P. 0. Box 50 Juneau, Alaska 99802 Attention: Mr. Robert J. Cross, Administrator Gentlemen: Re: Bristol Bay Energy and Electric Power Potential - Phase I (Draft Report) The Alaska Department of Fish and Game has reviewed the subject draft document and has no specific comments or recommendations to offer at this time. Thank you for consulting us. Sincerely, Ronald 0. Skoog, Commissioner i. — Eo a aT fe NLL: eT US oe BY: Bruce M. Barrett Projects Review Coordinator Habitat Protection Section