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Home My WebLink AboutAPA3485IS / 0 FPC P-37 HD 9685 .U6 A4729 1969 2 FEDERAL POWER COMMISSION 1969 - .'. I I) l; ALASKA POWER SURVEY A Report by THE FEDERAL POWER COMMISSION 1969 PROPERTY OF Washington, ~.C. ,o ' ,_.,_ . ARLIS For sale by the Snperlntendent.orDocwnents, u.s.'tioverDinent-P~~ & lnformatloD Set V tees w.,.hmgton, n.c. 20<11>-P<ioa$_'_;"'. ': Anchorage, Alaska . :· .. · . . . . . Alaska Resources COMMISSIONERS LEE C. WHITE, Chairman CARL E. BAGGE LAWRENCE J. O'CoNNOR, Jr. JoHN A. CARVER, Jr. ALBERT B. BROOKE, Jr. MuRRAY CoMAROW, Executive Director GoRDON M. GRANT, Secretary Prepared by the Federal Power Commission, Bureau of Power F. STEWART BROWN, Chief T ALASKA POWER SURVEY CONTENTS Preface ............................................................................. . lntroduction~Background and Highlights of the Survey .................................. . CHAPTER I GEOGRAPHY, RESOURCES, AND ECONOMY Geography ........................................................................... . Climate and Agricultural Production ..................................................... . Mineral Resources ..................................................................... . Other Resources ....................................................................... . Income, Population, and the Economy ................................................... . Present and Future Development. ........... : ........................................... . CHAPTER II THE ELECTRIC POWER INDUSTRY TODAY +t't> '5Gt&"" r()IO 1\4'=1-'2'3 t\ <!)10 ~ Page VIII I 5 8 8 10 10 11 Ownership of Utilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Utility Electric Power Supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 CHAPTER Ill PROSPECTS FOR LOAD GROWTH Population Patterns. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Projection of Power Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Electric Power Markets ................................................... , . . . . . . . . . . . . . 27 Utility Load Shapes and Diversity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Nonutility Growth Prospects. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Consumer Power Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 CHAPTER IV FUELS AND THERMAL-ELECTRIC GENERATING PLANTS Present and Projected Fuel Requirements and Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Other Uses of Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Inter-fuel Competition ... :. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Fuel Production, Reserves and Prices .............. .". . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Natural Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Coal............................................................................. 39 00............................................................................... ~ Other Fuels ... :. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Transportation of Fuels.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Transportation of Fuels Versus Electric Transmission of Fuel Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . 42 m Page Steam-Electric Generating Plants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Nuclear and Other Non-Fossil Fuel Generating Plants ........................... : . . . . . . . . . . . 43 Gas-Turbine Electric Generating Plants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Internal-Combustion Engine Generating Plants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Siting Considerations for Large Electric Generating Stations... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Trends in Fuel-Electric Plant Actual Power Production Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Comparison of Costs for Large and Small Plants .............. · ...... · . · · · · · · · · · · · · · . . . . . . . . 45 Summary and Conclusions ................................................... · . . . . . . . . . . . 47 CHAPTER V HYDROELECTRIC POWER RESOURCES History of Hydroelectric Power in Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Hydroelectric Projects, Developed, Under Construction, and Authorized........................ 49 Hydroelectric Developments Under License. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Hydroelectric Development by Federal Agencies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Hydroelectric Surveys by Federal Agencies.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Trends in Ownership of Hydroelectric Plants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Evaluation and Use of Hydroelectric Capacity.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Projected Hydroelectric Developments.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Summary and Conclusions............................................................... 61 CHAPTER VI PRESENT AND PROSPECTIVE PROGRAM FOR COORDINATED DEVELOPMENT Planning by Regions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Southcentral Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Load Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Existing Interconnected Operations and Power Pools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Present Generating and Transmission Facilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Possible Programs of Development by 1975 and 1985.......................... . . . . . . . . . . 72 Summary of Southcentral Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Interior Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Load Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Operating Utilities.................................................................. 73 Existing Interconnected Operation and Power Pools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Present Generating and Transmission Facilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Possible Programs for Development by 1975 and 1985. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Summary for the Interior Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Southeast Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Load Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Existing Interconnected Operation and Power Pools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Present Generation and Transmission Facilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Possible Programs for Development by 1975 and 1985.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Summary of Southeast Region.. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Northwest and Southwest Regions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Load Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Operating Utilities.................................................................. 79 Present Transmission Facilities .................................................. : . . . . . 79 Possible Programs for Development. . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Summary of Northwest and Southwest Regions. . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 IV CHAPTER VII TRANSMISSION AND INTERCONNECTION STUDIES BETWEEN INTERIOR AND SOUTHCENTRAL REGIONS Page General Considerations and Assumptions for Study Cases..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 Bases of Cost Estimates.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 Descriptions of Models Used for Planning Studies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 Plan I -Beluga & Devil Canyon Generation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 Plan Il-Beluga Generation..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 Plan III -Kenai and Beluga Generation. c. . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 Plan IV-Kenai, Beluga, and Bradley Lake Generation.................................. 86 Plan V-Kenai, Beluga, De\·il Canyon and Bradley Lake Generation...................... 86 Plan VI-Nuclear Generation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Plan VII-Isolated System (No Transmission Interconnection Between Interior and South- central Regions). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Plan VIII-Isolated Systems-Individual Utilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Plan VIII-A-City of Anchorage.. . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Plan VIII-B-Chugach Electric Association.......................................... 87 Plan VIII-C:---City of Fairbanks.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 Plan VIII-D-Go!den Valley Electric Association..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 Conclusions from Interconnection Studies.................................................. 88 CHAPTER VIII OUTLOOK FOR COST REDUCTION Suggested Target for 1985. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 Projected Power Costs-1985............................................................. 93 Evaluation of Cost Reductions.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 Cost Estimating Assumptions.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 Conclusions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 ACKNOWLEDGMENTS Committee Members ............................................................. - . . . . . 99 APPENDICES Appendix A Generating Plant Capacity, Ownership, and Location.................................. 101 B Annual Electric Power Requirements-Number of Customers, and Use Per Customer....... 107 FIGURES Figure I General Area Features ........................................................... . 2 Location of Electric Utllities and Installed Generating Capacity 1965 ................... . 3 Total Electric Energy Production by Alaska Electric Utility Systems ............... · ..... . 4 Population and Electric Power Load Center Areas ................................... . 5 Annual Peak Demands and Energy Requirements 1945-65 ............................ . 6 Fossil Fuel Resources ............................................................. . 7 Hydroelectric Projects-Existing and Potential. ...................................... . 8 Interconnected Electric Utility Syst~ms and Transntission Tie Lines-1965 .............. . 9 Proposed 79-Kilovolt Single Phase Service to Remote Villages ......................... . 10 Plan II-1975 ............................................................... · · · · v 6-7 16-17 18 22-23 25 36-37 62-63 66 75 84 Figure Page II 197 5 Power Flow Diagram ............................................. , . . . . . . . . . . . 84 12 Plan II-1985. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 13 1985 Power Flow Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 14 Plan III-1975................................................................... 85 15 197 5 Power Flow Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 16 Plan III-1985................................................................... 85 I 7 1985 Power Flow Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 18 Projected Trends in Regional Power Costs-1965-85.................................. 94 TABLES Table I Total Generating Capacity by Type of Prime Mover. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 2 Electric Utility Systems, Principle Operations and Retail Customers. . . . . . . . . . . . . . . . . . . . . 15 3 Ownership of Utilities by Size of Total Energy Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . 15 4 Alaska Resident Population........................................................ 21 5 Projection of Electric Power Requirements, 1965--75--85................................ 24 6 Rates of Increase in Alaska Electric Energy Requirements.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 7 Projected Increase in Electric Energy Requirements by Categories of Use... . . . . . . . . . . . . . . 27 8 Total Delivered Cost of Power-Composition in Percent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 9 Typical Monthly Electric Bills-Residential Service, January I, 1968.................... 30 10 Typical Monthly Electric Bills-Commercial Service, January I, 1968. . . . . . . . . . . . . . . . . . . 31 II Typical Monthly Electric Bills-Industrial Service, January I, 1968..................... 32 12 Fuel Requirements and Costs by Energy Sources...................................... 35 13 Fossil-Fuel Resources..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 14 Estimated Power Production Expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 15 Estimated Power Production Costs.................................................. 46 16 Hydroelectric Developments-Existing, Under Construction, Authorized. . . . . . . . . . . . . . . . . 50 17 Summary of Evaluation of Hydroelectric Potential. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 18 Interconnections Between Utilities and Major Nonutility Installations.................... 67 19 Estimated Capital and Annual Costs (Composite Financing)............................ 89 20 Estimated Capital and Annual Costs (Federal Financing). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90 21 Cost of Electric Power---1965 and 1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94 22 Cost Differences in Delivered Power-Anchorage and Fairbanks Load Centers by 1985. . . . 95 23 Reduction in Costs of Electric Power by I 985. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96 24 Composite Annual Fixed Charge Rates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 PHOTOGRAPHS Alaska Relative Size Map. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Anchorage Airport.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Harvest Time in Matanuska Valley. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Dredge Seeks Gold. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Oil Rig in Cook Inlet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Tidewater Logging in Southeast Alaska.................................................... 10 Log Raft at Ketchikan Pulp Mill. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Alaska King Crab at Kodiak.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II Pulp Mill Near Sitka.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Native Craftsman....................................................................... 18 Aerial View of Metropolitan Anchorage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Visitors and the Juneau Fishing Fleet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 University of Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Alaska-Made Chemicals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 VI --- Page Anchorage Manufactured Airplane Skis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Refinery on Kenai Peninsula. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Kenai Oil Well in Winter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Hurricane Gulch Railroad Bridge. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Fairbanks 8;500-Kilowatt Municipal Generating Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Barrow, America's Most Northern Community. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Knik Arm Power Plant ................................................. :. . . . . . . . . . . . . . . . 42 International (Gas-Turbine) Station....................................................... 43 City of Anchorage Municipal Generating Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Eklutna Hydroelectric Plant ................ ~. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Generators at Eklutna Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Cooper Lake Hydroelectric Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Line Erection by Helicopter ..................... ' . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 Bernice Lake Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Healy-Fairbanks 138-Kilovolt Line. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Oil Storage Tanks at Kotzebue... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Transmission Tower on Turnagain Arm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 VII I J PREFACE On April 15, 1965, the Federal Power Commission announced its plan to under- take an electric power survey of Alaska to determine how best to meet the State's load growth during the years to 1985. The Alaska Power Survey has examined both early and long-range opportunities for supplying Alaska's electric power needs in the most economical manner, including the opportunities for interconnection and coordination of existing systems to reduce the present high cost of electricity. It has also appraised and sununarized various opportunities for major developments which could serve the long-range needs of the State. The Survey Report was prepared largely by the Staff of the Federal Power Com- mission. The staff work was carried out under the direction of F. Stewart Brown, Chief Engineer and Chief of the Bureau of Power. The Survey was conducted with the assistance and cooperation of appointed representatives of all segments of the electric power industry and of State and Federal agencies concerned with Alaska's econQWic and electric power development and growth. The names of those who served on the Commission's Advisory Committee and Subcommittees are listed in the acknowledgments at the end of the report. The Commission wishes to express its appreciation to the Committees and to the many individuals who contributed to the work of the Survey and the preparation of this report. V1II INTRODUCTION BACKGROUND AND HIGHLIGHTS OF THE SURVEY Stimulated by statehood and an accelerated <;x- ploration and development of its many potential resources, Alaska is faced with an expansion in its supply of electric power in the next 15 to 20 years at a rate that is likely to exceed the rate of power growth in any other State. The Alaska Power Survey explores both the im- mediate and the long-range electric power needs of the State, and alternative ways of improving the economy and reliability of its bulk power supplies. Numerous opportunities have been examined for improvement of utility operation through the in- terconnection and coordination of the many elec- tric facilities which comprise Alaska's power in- dustry. One of the more encouraging indications for successful achievement of these goals is the manner in which representatives from Federal, State, and local agencies and the electric power industry have earnestly cooperated in the study to achieve meaningful and positive results. A major goal of the Survey has been to suggest possible patterns of power system expansion which could result in lower costs and increased service reliability. The Survey visualizes patterns of possi- ble development which, by 1985, could reduce the statewide average cost of electricity by about 65 percent, assuming a continuation of today's value of the dollar. The Survey encourages broader local and regional planning among Alaska's electric power utilities to the end that utilities of all seg- ments will work together to meet their combined needs to the mutual advantage of themselves and their consumers. The Survey was conducted by the Federal Power Commission as a means of carrying out the pro- visions of section 202(a) of the Federal Power Act which directs the Commission ". . . to promote and encourage . . . interconnection and coordi- nation" of electric utility systems for " . . . the purpose of assuring an abundant supply of electric energy throughout the United States with the great- est possible economy and with regard to proper utilization and -conservation of natural resources." 1 The future patterns for Alaska's electric power systems depicted in the Survey report are not sug- gested as firm patterns for any system or systems of electric powerplants or transmission lines. No one can adequately foresee all of the many changes in technology, operating conditions, or market po- tential that will occur in the years ahead. Therefore, the report does not set forth plans but only possible patterns for providing an economic and reliable system to supply future electric loads. The goal is to excite interest in the many opportunities for sav- ings and increased service reliability that should be continually explored. Growth in power consumption and closer co- ordination of power systems, particularly in the more populated sections, are twin ingredients in the formula for reducing future power costs. Power costs over the years have shown a downward trend. The goals of the Survey are to help continue and to accelerate the lowering of costs to the consumer, and to increase the reliability of electric service. The achievement of lower costs is in itself a stimulus to wider use of electricity. The key to the future growth of Alaska's electric power industry lies largely in the willingness of its members to embark vigorously-on a course of plan- ning together for new power sources and system interties. Economies of scale in large gerterating units, coupled with low-cost energy transportation, suggest that many of Alaska's individual power sys- tems could profitably join together in constructing new capacity, either through joint projects or by staggering their construction _programs. In areas where communities are of significant size, substantial reductions in the future cost of power appear possible. The total cost of generating, transmitting, and distributing power to customers of Alaska electric utiliiies in 1965 averaged about 2.69 cents per kilowatt-hour of power produced. No estimates of the equivalent costs are available for power produced by non utility installations. The Survey is concerned primarily with genera- tion and transmission of power to the distribution substations, and projects that this bulk power supply part of the cost can be reduced by 65 percent. Guided by our previous studies of distribution costs in other parts of the United States, it appears that some reduction in the distribution costs should also be possible during the Survey period. The Survey projects that by 1985 not only will population have increased and more customers will be using more electricity individually than in 1965, but the cost of electric power before distribution to the ultimate customer could be reduced from the present average of about 1.98 cents to about 0. 71 cents per kilowatt- hour. The study recognizes that the unit invest- ments in production, transmission, and distribution facilities, as well as operating costs, are not the same in every location, and consequently, the pos- sible reductions are greater in some areas than in others. As mentioned earlier, no direct comparison of possible cost differences for nonutility electric services is available. If comparable reductions are assumed, however, and the suggested reduction of 1.27 cents per kilowatt-hour is applied to the 5.3 billion kilowatt-hours considered for coordinated central utility service in 1985, it indicates that total savings could amount to as much as $67 million a year to Alaska's consumers. If the potential savings are calculated for utility served loads alone, the annual total is $45 million. These savings will result from a greater number of custo_mers using larger amounts of electricity for which unit costs will continue to decrease. Thus, the challenge facing Alaska's electric power industry is to continue the long-term trend of selling elec- tricity to the consumer at steadily lower prices. To compute the average cost of power, a com- posite fixed charge rate 1 was used to deteirnine costs of power for all segments of Alaska's power industry. The use of such rates permits a reasonable economic comparison of alternative plans. It is re- cognized, of course, that actual fixed charges will vary, depending upon taxes or tax equivalents and the cost of money applicable to the constructing agency. Analysis of the opportunities for lowering Alaska's power cost in the years . ahead must begin with a knowledge of the State's geography and economy, and the present development of the electric pqwer 1 A percentage applied to the net investment in facilities to cover the annual cost of interest on the investment, depreciation or amortization, taxes, and insurance. 2 industry. Chapters I and II discuss the State's his-. tory, geography, economy, and resources, together with the makeup of its electric power industry and enough of its history to give some insight into the evolution of today's power industry structure. The Survey, in chapter III, outlines the prospects for electric load growth, postulates that the predom- inant growth will occur in the areas of civilian use, and projects that civilian power demands in 1985 will require the production of 4,800 million kilowatt- hours of electricity, 6% times the 1965 production of 707 million kilowatt-hours. It is this large increase in energy use that enables the prediction of large reductions in costs of electricity suggested in this report. Conceivably, the very recent expansion in the discoveries of petroleum in the Arctic Region could result in even more rapid industrial and economic expansion than forecasted in the report. Chapter IV discusses the availability and pro- jected costs of Alaska's solid, liquid, and gaseous fuels for the generation of electric power. Also in- cluded is a projection of Alaska's future power gen- erating plants, including possible types, locations, and costs, to mee{ both base load and peak power generating needs. A summary of Alaska's developed and potential hydroelectric resources is presented in chapter V. The heart of the report is in chapters VI and VII which include suggestions for improved economy and reliability through concepts of interconnection, coordination, the use of diversities in load patterns, and reductions in reserve requirements. Chapter VI discusses the transmission of electric power in Alru;ka today, and developments which are im- portant to the expansion of power networks. It also presents illustrations of possible patterns of power generation and transmission, and suggests alternative ways in which system developments might occur. Chapter VII summarizes studies of various generation patterns and interconnections of the Anchorage and Fairbanks areas. Estimates are included of the savings which may be achieved with coordinated planning as opposed to unco- ordinated individual system planning. Chapter VIII attempts to bring into focus the economic significance of the patterns of growth visualized by the Survey. It projects the potential savings to consumers which will result from the growth and technological improvements projected in the report. The greatest savings are expected to take place in the Interior and Southcentral Regions I I I where low cost fuels, growth in loads, and the favorable geography offer many possibilities for improvement. It is our sincere hope that the Alaska Power Survey wip set a standard and serve as an en- couraging guide for planning the future of Alaska's 3 electric power industry. The goal proposed is an abundant supply of low cost electric power which will promote economic growth, add to the well- being of Alaska's population, and stimulate develop- ment which is not likely to be achieved without the ready availability of this resource. CHAPTER I GEOGRAPHY, RESOURCES, AND ECONOMY Any study of Alaska's electric power resources and needs over the years ahead must take into ac- count the State's economy, geography, climate, and resources, all of which will help to shape its power needs and determine· its potential for development. Geography Alaska is the largest peninsula of the North Amer- ican Continent, approximately 586,400 square miles in area. It is a State of many long rivers-the long- est, the Yukon, rises in Canada, flows through the State, and empties into the Bering Sea. Alaska's topography is marked by two great mountain sys- tems; the Brooks Range above the Arctic Circle and the Pacific Mountain system, which sweeps in a great arc through the southern part. Because of vast distances, climate, and rugged topography which hamper the building of roads and railways, air travel is a way of life. The general area map, figure 1, shows the many, widely distributed airports in contrast to the relatively limited highway and railway systems. In addition, there are 18 major and more than 50 smaller seaports in Alaska. Alaska's land area is 365,481,600 acres, of which about 80 percent is composed of unreserved public domain and slightly more than 2 percent of land re- served by the Federal Government for the manage- ment and conservation of the State's major natural This superimposed print of Alaska shows the relatively large size of the 49th State in comparison to the lower 48. 5 B E R N G 5 f A ;'RrSl.,Of ;']~h.- 't>~!~_,r<J ' I S A R C T I C CHUKCHI S E: A Figure 1 6 NORTON r o L a R J s ,.... P A C F c 0 C E A N SEA GULF OF ALASKA 0 C E A N FEDERAL POWER COMMJSSJON ALASKA POWER SURVEY GENERAL AREA FEATURES SCALE 11'1 Mll.£5 LEGEND ---RtGIQN/.l BOUNDARY HIGHWAYS AHO ROADS ~ STAlE HIGHWAYS RAilROAD US AIR fORCE BASE AIRPORTS ( " ( 7 resources. Under the provisions of statehood, Alaska can select 104,582,745 acres from the unreserved and unappropriated acreages for State purposes. The selection must be completed "by 1984. As of 1967, Alaska had selected only 17,606,803 acres, of which working title had been secured for some 13 million acres. Anchorage I nternational Airport has become an important intermediate point for international air traffic using the polar routes between the Orient and other parts of the world. Climate and Agricultural Production The climate of Alaska is influenced by its north- erly latitude, its peninsular character, the proximity of the warm Japan current, the mountain ranges running east and west and prevailing southerly winds. Within innumerable variations of weather, A laska experiences mi ld periods of many days duration. Agricultural production is aimed largely at local consumption. Relatively little of the State's vast land area has soil and climate conditions suitable for agricultural development. These disadvantages, in addition to la nd clearing problems and hig h labor and machinery costs, make the price of local farm products relatively high. Farming centers around the raising of chickens, cattle, and vegetables, and the production of milk, eggs, and field crops. Home gardening of vegetables and flowers is carried on throughout Alaska, espe- cially in the river valleys and southern and eastern coastal areas. Most of the developed agricultural lands are located in the Matanuska, Susitna, and Tanana Valleys. 8 Harvest time in Alaska-These farmers in the Matanuska Valley are looking over the potato crop with an eye /or choosing entries in the annual Matanuska Fair. Average annual precipitation varies from less than 5 inches at Barrow in the Arctic Circle and about 12 inches around Fairbanks in the interior to 150 inches per year at Ketchikan in the southernmost part of Alaska. Vegetation varies with the climate, ranging from dense r ain f orests and heavy undergrowth in the central and southeast coastal zo ne to smaller forests and sparse undergrowth extending from the coastal mountains of the interior to the tundra of the Arctic slope. Vast expanses of grassland exist throughout the Alaskan Peninsula and the Aleutian Islands. Mineral Resources Mineral resources have been the mainstay of Alaska's economy a lmost since the purchase of the territory from Russia. Most of the recorded mineral production of about $1.5 billion came initially from gold and copper. Production has reflected the ups and downs of prices of these metals. Within the past year, gold output has decreased to less than 1 percent of the total because most mining operations have become uneconomic. With the discovery of oil on the Kenai Peninsula in 1957, petroleum and natural gas jumped dramatically into prominence and in 1965 accounted for approximately $36 mil- lion of the $83 million total mineral production. Production of crude oil which doubled in volume in 1967 over the previous year doubled again in 1968. The State's total 1968 mineral production of $212.1 million included $178.7 million of crude oil and almost $3 m illion of natural gas. The recent .... discovery of a large oil province on the North Slope, roughly estimated to exceed 10 billion barrels, augurs well for the future of oil and gas as a prin- cipal element in the State's economy. Alaska monster devours whole river beds in search of gold. These dredges, though dwindling in number through- out the North, hav e played an important role in the economy of Alaska. Truck at far right of picture gives an idea of size. Deposits of all the strategic minerals are known to exist in some quantity in Alaska's 586,000 square miles. These can be expected to provide a n impor- tant basis for industry as the discovery and verifica- tion of resources which can be mined economically proceeds. Oil and coal reserves are very large. At present, coal production has stabilized in the area of 800,000 to 900,000 tons per year of which 70 percent is used in power production. The natural gas production, which has risen along with oil, is now starting to reach commercial markets in Anchorage and is also being used for power gen- eration on the Kenai Peninsula. The conversion of the Anchorage area m ilitary bases from coal to natural gas will be an important market for gas. These considerations are discussed in more detail in chapter IV. It has been estimated that Alaska's m ineral pro- duct;on could increase from 10 to 100 fold as de- velopment acti vity accelerates. Copper deposits are known to be quite extensive and exp loration is active. The Ruby Creek deposit near Kobuk is being reappraised to determine the potential for year-round mining and milling opera- tions. A target of 5 years for the start of production has been mentioned. 9 In a very recent report, the Department of the Interior announced the discovery of lead, zinc, and silver in the remote Bowser Creek area about 150 miles northwest of Anchorage. Preliminary ex- aminations are reported to indicate locally rich mineral deposi ts which, however, may be tedious to explore because they are small, terminate abruptly, and are irregularly distributed. No iron ores have been mined in Alaska, but titaniferous magnetite deposits have been discovered in the C h enik Mountain a rea. One deposit is esti- mated to contain 1 billion tons of ore, with 15 per- cen t recoverable iron, and represents a good possibility for future development. Petroleum production from beneath the sea is a major part of Alaska's booming post-statehood economy. This is one of several units producing oil from under the waters of Cook Inlet near Anchorage. A laska has an abundance of construction mm- erals, such as sand and gravel. During 1965, abo ut 30 million tons of these two minerals, with a value of about $34 m illi on, were extracted. Production in 1966 amounted to $22 million, and in 1967, an estimated $28 million. The only known tin deposit in North America is located in the western part of the Seward Penin- sula and may become o f economic and strategic im- portance in the future. Some prospecting a nd min- ing is carried on for other minerals, precious and semiprecious. Other Resources The most attractive and most active commercial lumber areas in Alaska are the forest regions in the southeastern Panhandle, south-central coastal area, and the eastern half of the Kenai Peninsula. Al- though the interior forests occupy about 34 percent of the land surface, commercial development has been limited to supplying local needs. Forest sur- veys indicate that 119 million acres sustain forest growth and, of this total, 28 million acres are classed as commercial forest land. The major prod- uct of the timber harvest is wo od pulp. Construction timber and green veneer are also important mar- ketable products. Expansion of timber harvesting can be expected, and wi ll have considerable in- fluence on the economy of the State. Two of Alaska's major resources are its rivers and its adjacent oceans. They support a substantial com- mercial seafood industry and are a basic asset to A laska's fast growing tourist industry. Expansions o{ the fishery and tourist industries are likely to be important f actors in the growth and development of the St ate. The potential for hydroelectric power development is discussed in chapter IV. Income, Population, and the Economy A steady increase in personal income is an indica- tor of the health of the economy. Although the popu- lation includes many native Alaskans who exist on marginal incomes, the average per capita personal income of all Alaskans rose from $2 ,842 in 1956 to $3,187 in 1965, $3,346 in 1966, and $3,430 in 1967, exceeding the average for the United States by more than 15 percent. The rate of increase in both employment a nd income supports an increasing rate of power consumption. This, in turn, suggests an ever-expanding market for electric appliances and equipment for farms, homes, businesses, and industries. From 1880 to the start of World War II, the population of Alaska rarely exceeded 70,000. It reached a peak of about 225,000 in 1943. With the cessation of hostilities and withdrawal of many of the defense oriented personnel, the population de- creased to about 100,000 in 1946. In 1950, the resi - dent population stood at 138,000, of which approxi- mately 20,500 were .defense personnel. There has been no let-up in population growth since then. In 1960, 226,000 person s were in residence in Alaska, of whom about 47,500 were military personnel and their dependents. In a September 1968 news re- 10 Tidewater logging in southeast Alaska. L og rafts await processing in the Pacific Ocean waters of Ketchikan, Alaska's pulp mill. Southeast Alaska's great- est natural resource-timber-surrounds this industrial site. lease, the Census Bureau reported that Alaska's resi- dent population had reached 277,000-a 22 percent increase over 1960 a nd the greatest percent increase of any State. Average employment in nonagricultural activities was 77,200 in 1967, approximately 35 percent above 1960. Farmworkers have remained for some time at a level of about 650 persons. The Federal, State, and local governments are t h e largest employers (32,200 persons ), and wholesale and retail trade establish- ments are the next largest (I I, 700). Construction and manufacturing employed a total of 12 ,800 while transportation employment was 7,400. Mining em- p loyment has risen from about 1,000 in I965 to 2,000 in 1967. ps Loans and investments increased more than 31 percent from around $175 million in 1963 to over $230 million in 1966. Public construction increased in the same period from a n average of $100 million to $110 million. Federal contributions to .1\laska's construction program have been substantial, rang- ing from 30 percent to over 60 percent of the total. Although fisheries provide seasonal employment for more than I 0,000 residents and 5,500 nonresident fishermen, in addition to over 8,700 cannery and wholesale workers, the average number employed fulltime is very low. Most of the approximately 24,000 seasonal fishery workers are not counted in computing average employment. This is true also for other seasonal activities. Expansion of the fish- ery industry to include harvesting and processing presently W1exploited stocks in the Gulf of Alaska on a year-roW1d basis would provide employment for a large number of these seasonal workers. Present and Future Development The activities which have and are lik ely to con- tinue to shape Alaska's development are those concerned with national defense and with the development and exploitation of natural resources. Expansion in the use of the State's timber re- sources, which are now only partially utilized, is expected to continue. Production of oil and gas is economically attractive and can be expected to in- crease; with it, certain manufacturing industries will develop, such as urea processing, ammonia, and compressed gas for shipment to fore ign as well as domestic markets. With salmon runs returning to their form er size , and development of a substantial king crab market, a healthy expansion of the fishing industry is oc- curring in southeast Alaska and in the Gulf of Alaska as far as the Aleutians. Finally, in terms of input to the civilian economy and the number of persons which will be affected, the tourist business promises to become the largest single industry. Extensive exploration for many of Alaska's solid minerals and significant expansion of mining opera- tions appear to be some time off. However, the 11 Alaska king crab is unloaded for processing at island community of Kodiak. The giant crustacean is taken from Alaska's gulf durin g the winter months, an other- wise-quieted season for northern fi shermen. development of Alaska's large natural gas and pe- troleum resources and related petrochemical in- dustries is expect ed to have the greatest impact on the economy. Improvement is needed in trans- portation faci lities to gain access to large mineral deposits. Federal assistance in the development of adequate transportation is a necessity. Major improvements in price structure are needed to make economic activity in Alaska more competi- tive. The costs of basic services and facilities (trans- portation, electric power, and communications ) must be reduced to make Alaska's economy strongly competitive nationally and internationally. Long- range economic development depends on establish- ing new trade patterns, such as trade with Japan and Canada. CHAPTER II THE ELECTRIC POWER INDUSTRY TODAY Alaska's electric power industry was oriented, originally, to mining and refining operations, fish canneries, lumber mills, trading posts, and the like. For many communities, industrial and commercial power installations were the only sources of elec- tricity. Some of Alaska's present utility systems are derivatives of these earlier industrial and commer- cial enterprises. This report considers the needs for both utility and nonutility electric power. Utilities are defined as those who generate, transmit, distribute, and sell electric energy. Nonutilities generate electric energy for their own use, such as for lumber and pulp mill operations, hospitals, schools, railroads, communica- tion centers, and defense installations. A detailed tabulation showing generating-plant capacities for both utilities and nonutilities by types of prime mover, location, and ownership of r ecord in 1965 forms appendix A of the report. Water was first used to produce substantial amounts of power for a mining operation in 1882. For many years thereafter, no appreciable use was made of Alaska's hydropower potential. The first hydroelectric project of significant size began op- eration in 1901, and supplied e lectricity to the city of Ketchikan. Many of the original hydroelectric plants are still in operation, as are a number of steam-electric and internal-combustion engine generating units which were installed in the early 1900's. During the t wen ties and thirties, electric gener- ating capacity additions continued to be of modest size in keeping with the slow growth in utility and industrial power requirements. Power for Alaska's defense installations marked the beginning of a new demand for power in Alaska. D u ring a subse- quent 20-year period ending in 1965, electric utili- ties added capacity at an average rate of about 11,000 kilowatts per year, and total utility capacity at the end of the period was about 249,000 kilowatts. 13 Making a giant roll of paper-like pulp is the final stage of production for pulp mill processing at this plant near Sitka, Alaska. It was 257 ,000 kilowatts in 1967. Approximately 60 percent of the capacity is lo cated in the south-cen- tral region around Anchorage, and on the Kenai Peninsula. The maximum buildup in generating capacity at defense installations occurred between 1955 and 1960. Since then, it has leveled off, standing now a t about 207,000 kilowatts. Nonutility and nonde- fense capacity is approximately 61 ,400 kilowatts, the largest part of which is located in lumber and pulp mills in the southeast region. As of 1967, n on- utility capacity (including defense) totaled 275,000 kilowatts. The general composition of capacity in- stalled throughout Alaska from 1945 through 1967 is shown in table 1. The electric generating capacity installed by Alaska utilities is shown on the map, figure 2, which locates the electric utilities and shows the extent of their dispersion. The major communities served by the various systems are listed in appendix A; how- ever, there are a number of small communities and trading posts of fewer than 100 persons, such as Chitina ( 15 kw.), Hughes, Teller ( 30 kw.), Dot L ake (60 kw.), Lake Minchumina, Manley Hot Springs ( 48 kw.), Northway ( 480 kw.), and Ram- part which have electric service. Complete data on these small sources of power are not a vailable. The ele ctric power industry includes more than 50 separate utility systems. Their installed capacities range from less than 100 kilowatts to approximately 100,000 kilowatts . Non utility electric facilities are widely distri buted. Capacity installations range from a few kilowatts to 54,000 kilowatts. Although total capacity is now abou t evenly divided betwee n utility and nonutility segments, t his balance is n ot expected to continue. Electric utility capacity is advancing, while capacity installed in nonutility establishments appears to have leveled off and could d ecrease as utility central station power b ecomes available at more attractive rates. The opportunities for coordination between utility and nonutility systems, and possibilities for serving eventually some portion of the nonutility loads from utility sources are discussed in chapter V I. Ownership of Utilities Alaska's electric power industry comprises four distinct ownership segments-private (investor owned ), municipal, cooperative, and Federal. T h e largest segment is the cooperative group and more than half of t he 58,82 1 retail customers in Alaska are served by Alaska's 15 cooperatively owned systems (table 2 ) . As shown in table 3, 12 coopera- tives owned generating plant in 1965 which ac- counted for 41 percent of the State's total electric TABLE 1 Total Generating Capacity by Prime Mover Alaska Electric Power Industry 1945 19 50 1955 1960 1965 Percent 196 7 Percent Items caoacity capacity capacity capacity capacity of total, cap acity of total kw ) (kw ) (kw) (kw ) (kw ) • 1965 (kw) • 1967 Utility capacity: Steam-electric 1 ............... 10,300 13,800 27,500 32,500 32,500 6 32,500 6 I nternal-combustion ........... 3,600 12,080 25 , 110 33,550 59,219 12 73,335 14 Gas-turbine .................. 0 0 0 0 74,810 15 74,810 14 Nuclear ..................... 0 0 0 0 0 0 0 0 Hydroelectric 2 ..........••... 16,880 20,450 54,400 59,030 82,300 16 76,675 14 Total utility ................ 30, 780 46,330 107,010 125,080 248,829 48 257,320 48 Nonutility capacity: 3 Steam-electric ....................... 21,500 4 1,500 157,350 140, 785 29 156,660 29 Internal-combustion ..................... 8, 170 8, 170 59,590 121,739 22 115,336 22 Gas-turbine ............................ 0 0 0 0 0 0 0 Nuclear ............................•.. 0 0 0 2,000 2,000 Hydroelectric ........................... 2,980 2, 110 I, 190 I, 197 I, 19 7 Total non utility capacity ............... 32,650 51 , 780 218, 130 265, 721 52 275, 193 52 Summary-Utility and nonutility capacity: Steam-electric ......................... , 35, 300 69,000 189,850 173,285 35 189, 160 36 Internal-combustion ..................... 20,250 33, 280 93, 140 180,958 34 188,671 35 Gas-turbine ............................ 0 0 0 74,810 15 74,810 14 Nuclear ............................... 0 0 0 2,000 2,000 Hydroelectric .......................... 23 ,4 30 56, 510 60, 220 83,497 16 77,872 15 T otal installed capacity ................ 78,980 158,790 343,2i0 514, 550 100 532,5 13 100 1 Includes capacity of U.S. Smelting, Refining & ~lining (industrial ) included; of late years output sold to utilities. Co. which sold power to city of Fairbanks. 3 Data incomplete for nonutilities for 1945. 2 Hydroelectric capacit y installed in A. J. Industries 4 Coverage almost 100 percent compared with prior years. 14 ~----------------------------------- installation. I n contrast to the 48 States, where more than 75 percent of all generating capacity is privately own ed, only 9.5 percent of reta il customers in Alaska are served by private utilities. As shown in table 3, only two utilities-one mu- n icipal an d one cooperative-had energy require- ments in 1965 of over 100 m illion kilowatt-hours and neither of these exceeded 200 million kilowatt- hours. The requirements of seven others ranged between 25 and 99 mill ion ki lowatt-hours. Utility Electric Power Supply By 1965, Alaska's electric uti lities had developed 82,300 kilowatts of hydroelectric and 166,529 kilo- watts of steam-elect ric, diesel, and gas-turbine capacity amounting to a total capacity in electric utility plants of 248,829 kilowatts. Between 1965 and 1967, 14,116 kilowatts of diesel capaci ty were added, but 5,625 ki lowatts of hyd roelectric capacity were destroyed in 1967 by the Fairbanks area fl ood. At the end of 1967, capacity in utility generating plants was 257,320 kilowatts, as shown in t able 1. The relative sh ares of en ergy produced by u ti li ty hydroelectric and thermal-electric generating sources for the years 1960 and 1965 are shown in figure 3. Hydroelectric pla n ts produced al most two - thirds of the 381 million kilowatt-hours of total production in 1960. In 1965, all utility plants gen- erated a bout 694 million kil owatt-hours, a p p r oxi- mately 1.8 times the energy produced in 1960, but hydroelectric plants produced less th an 47 percent of the t otal. Alaska's sing le Federal hydroelectric plant of 30,000 kilowatts accounted for more than 73 percent TABLE 2 Electric Utility Systems, Principal Operations and Retail Customers By Ownership Segment Owne r sh i p Privat e .......................... Municipal ....................... Cooperative ...................... Federal. ......................... Total ..................... T o tal number syst e ms 15 13 15 44 (Systems of Record-1965) N umbe r N umber e n gaged in e ngaged in generation, gene r ation, tra n smission tra nsmission a nd a nd d istribution w h ol esaling II 3 12 0 12 0 0 35 4 G enera ting capacity perc ent of total 12 35 41 12 100 Number e ngage d i n distributio n only 1 3 0 5 1 Project camp and interdep artment (proj ect use) customers totaled 10, but not included as retail. TABLE 3 R e ta il customer s s er v ed Number P erc e nt 5,56 1 9.5 23,4 7 1 40. 0 29, 789 50. 5 10 0 58,821 100.0 Ownershi p of Util ity Systems by Size of Total Energy Requirements (Systems of Recor d-1965) Ownership Privat e. . ..................•.............................. Pub lic .................................................. . Cooperative ............................................... . Federal ................................................... . Total number ....................................... . 15 Number o f sy stems-Annual e n e r g y r e quire ments- Million s o f Kilo w a tt-hours Ove r 100 25-99 0 I 0 2 I 3 3 0 7 1-24 6 7 8 22 Unde r 1 T ota l 8 15 2 13 3 15 0 I 13 44 B E R N ' (! \~~~~~~~.,,. ·~-~, s E A A R C T I C CHUKCHI SEA G ;·~-, ____ \ \~{ ISLANC ' ,, Nushagah Figure 2 16 I. 0 1-~ P A C F I E A N c SEA FEDERAL POWER COMMISSION ALASKA POWER SURVEY LOCATION OF ELECTRIC UTILITIES AND IN S TALLED GENERATING CAP A CITY 1965 SCALI:: IJ'i M.ILt.:5 ::.;; LEGEND ---REGIONAL BOUNDARY HIGHWAYS AND ROADS =~ S!All HIGHWAYS )t. (H) (S) (0) (G T.) RAILROAD US. AIR FORCE BASE HYDROELECTRIC STEA M DIESEl GAS TURBIN E f ( ( -' ' < (,/~-~l Alaska Power & Telephone Co.-210KW (D) --"-X'------, Alaska Power & Telephone Co .. 7">KW (D)--c-,---;: Ketchikan Public Utilities- 9,flfXJr\W (H),873KW (D) Metlakatla Indian Community-3,~W (H) 0 C E A N 17 of the total hydroelectric energy produced in 1960 . In 1965, its share reduced to 41 percent, because the plant was out of service for part of the year for repair of earthquake damage and also because the total energy produced by other hydroplants had increased. The largest addition was from a 15,000 kilowatt cooperatively owned plant that be- gan generating in 1961. Sixty-three percent of all the energy produced by Alaska's utilities in 1960 and 1965 was generated by plants located in the south-central area. oc oc oc oc ,oc oc 00 0 I TOTAL ELECTRIC ENERGY PRODUCTION BY ALASKA ELECTRIC UTILITY SYSTEMS MILLION KILOWATT -HOURS 1960 AND 1965 ~ THERMAL-ELECTRIC HYDROELECTRIC ~ ill fiTil mn ~ n 960 l 96!:i 1960 196!S 19 60 196!S 19 6 0 196!5 19 6 0 196!5 1960 1965 NORTHWEST SOUTHWEST SOUTH INTERIOR SOUTHEAST STATE CENTRAL OF ALASKA REGION Figure 3 Utility plant generation, supplemented in some areas by generation from industrial installations ' supplied about 62 percent of Alaska's population. 18 Nonutility generating plants, mainly those of the defense installations, furnished the needs of about 19 percent of Alaska's resident population. Much of the remaining population is composed of migrat- ing Eskimo and Indian families who live in villages with no electric service. Where electric power is available, service for the most part is seasonal and is supplied by small diesel and gasoline engine- driven generators. Generating capacity additions have usually been tailored to the needs of the individual utility sys- tem. For several systems, however, opportunities exist for interconnection and coordination of opera- tions and the construction of larger and more efficient generating units. This could result in substantial economies for all of the cooperating systems. Native worker busily engaged in handcraft work. CHAPTER Ill PROSPECTS FOR LOAD GROWTH The Survey's projection of the electric power in- dustry's future foresees electricity as a prime energy source in the daily life of almost every Alaskan. By 1985 the State's economy is expected to require over 6.1 billion kilowatt-hours of electricity annually. The civilian sector of the economy will probably need in excess of 4 .8 billion kilowatt-hours-6 % times the amount provided in 1965. To produce this energy dependably and provide a reasonable re- serve margin, Alaska's electric utilities will need about 1.3 million kilowatts of installed capacity com- pared with approximately 249,000 kilowatts in- stalled in 1965. Underlying the market projection for electric power is the assumption that the utilities will under- take in a thoroughly coordinated manner, the devel- opment of the most economical and reliable supplies of power, and will pursue the advantages of selling electric power at the lowest possible price. Doing so will open the way for an expanded application and use of electricity. Alaska has the resources and mechanisms for sup- plying power to its more populated areas at costs which could be on a par with the lower levels of cost in the 48 States. By contrast with Alaska's higher average cost of living, its electric power will be an even greater bargain. Such possibilities are fundamental to appraising the opportunities for a greatly expanded powe r eco nomy in the State. This chapter presents estimates of electric power requirements through 1985 of the total electric power industry. Projections include both the loads now served by Alaska's privately and publicly owned utility systems, and those currently supplied by de- fense and industrial generating plants. By 1985, a large proportion of Alaska's present ge nerating capacity will have become obsolete. Thus, there is an opportunity to seek the economies of scale and generating system optimization made possible by the expected load growth and the replacement or pro- vision of substitute capacity for old generators in many existing plants. Utilit y central station service 19 could become an attractive alternative to some exist- ing sources. The estimates of future power requirements are based on a careful study of past trends of power usage, economic growth and opportunities for the future inherent in Alaska's economy, and an as- sessment of prospects for changes in the nonutility loads. The estimates are not a precise forecast, but are presented as a guide to aid in the comprehen- sive and imaginative long-range planning needed now to insure the best development of Alaska's elec- tric power systems. The attainment of this goal will be determined largely by the electric industry's own course of action. No one factor can be singled out as the reason for a sixfold growth in energy requirements of Alaska's electric utilities between 1950 and 1965. Statehood, discoveries of mineral fuels justifying commercial production, expansion and improvement in trans- portation facilities with resulting lower costs, better educational and health services, increased incomes, better housing, better utility services, higher living standards, and population increases all contributed. In addition to the load s supplied by Alaska's e lec- tric utilities, nonutility generating capacity supplies defense lo ads, and the industrial loads of the lum- ber and pulp mills, fish processing and cold storage establishments, and the like. Total load supplied from the larger industry-owned generating p lant s in 1965 has been estimated in the order of 240 mil- lion kilowatt-hours. It has remained at about this level for a number of years, and only a small in- crease is expected. The power requirements for most defense establishments were estimated to be over 302 million kilowatt-hours i n 1960 and 360 million kilowatt-hours in 1965. Annual requirements of the many small and scattered industrial establishments, aircraft landing fie lds, military and communication cent ers, and sim ilar loads are estimated to be about 320 million kilowatt-hours. The projected increase in total electricity con- sumption by customers of the electric utilities from 1965 to 1975 is about 156 percent; from 1975 to 1985, approximately 162 percent. Over the 20-year span from 1965, the projected increase represents an average growth rate of approximately 10 per- cent. This corresponds quite closely with the 15- year actual rate of growth from 1950 to 1965, and provides a sound basis for the industry's long-range planning, but will require continued updating to keep it in line with the ever-changing circumstances of the industry's and Alaska's growth. The above projections reflect growth from 1965 rather than some later date because reports are obtained from many of the Alaska utilities only at 5-year intervals. Population Patterns The size of the population to be served at any location is an important factor in planning and developing a reliable and economic electric power supply. Population data and a description of popula- tion fluctuations during the World War II period have been given in chapter I. Over one-fifth of the population is composed of the three-principal native groups-Eskimos, Aleuts, and Indians. The civilian population of Alaska grew at an annual average rate of about 5.2 percent from 1950 to 1960 period, compared with a growth rate of about 1. 7 percent in the rest of the United States. Before World War II, the largest population con- centration, approximately 30 percent of the State's total, was in southeastern Alaska. By 1950, the population had sh ifted and was concentrated around Anchorage and on the Kenai Peninsula in south-central Alaska. During the next decade, this trend continu ed so that by 1960 over 43 percent of all persons resided in that area. Population projections for geographic regions and for the State have been developed using the growth rate experienced since 1950, tempered by anticipated development in the durable and non- durable goods sector and expansion in tourist- oriented services. The projected 1985 total popula- tion of 550,000 reflects an annual growth of 3.9 percent, or almost 2y2 times the anticipated growth rate of the remainder of the United States. It is , however, substantially lower than the 1950-60 growth rate of 5.2 percent. The total population estimate of 550,000 is con- siderably higher than a projection of 400,000 made by the Bureau of the Census in October 1967. The estimate used here, however, was adopted by the 20 Alaska Advisory Committee after detail ed studies of specific situations in Alaska, and is believed by the Committee to represent a realistic view of prob- able population growth b y 1985. Estimates of the 1965, 1975, and 1985 popula- tion for the State and for each of the five regions are given in table 4. The locations of the areas of significant population concentration are keyed to numbere d circles on the population and load center map, figure 4. By far, the largest concentration is in the south-ce ntral region. Most of the region's population is in and around the city of Anchorage, fanning southward through the Kenai Peninsula and northward into the Matanuska Valley area. The population in the south-central region was about 107,730 in 1965 and is estimated to be 270,540 in 1985. The population of the southwest region is the smallest. In 1965, it was about 3,630 and in 1985 will be about 6,670. The numbers residing on defense bases and in small scattered villages are given in the table as a total, not identified with specific areas and not shown on the map. Metropolitan Anchorage, largest of Alaska's cities, boasts an increasing number of many-storied office, apartment, and hotel buildings. Projection of Power Requirements Electric power requirement projections for geo- graphic regions and for the State were developed using guidelines established by the Federal Power Commission's Alaska Power Survey Advisory Com- mittee. The Committee, in establishing guidel.ines, considered the growing petrochemical industry on the Kenai Peninsula, the rapidly growing tourist travel and recreational potential, the general pop- -------=-- TABLE 4 Alaska Resident Population-1965, 1975, 1985 Estimated Geographic study region Population and load center number 1965 1975 1985 Northwest. ............................................ 1,2,3 ................. . 5,600 3, 630 7, 010 8,400 Southwest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4, 5, 6 ................. . 5, 100 6,670 Southcentral ................................................................. · · 107,730 187, 260 270, 540 (a) Anchorage-Kenai ......................... :-..... 9, 10, II, 12, 13 ........ . 101,840 5,890 178,890 258,690 (b) Otherareas .................................... 7,8, 14, 15 ............ . 8, 370 11 ,850 Interior. . . . . . . . . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 ................... . 25,000 35, 730 37,500 56,250 Southeast .............................................. 17 through 24 .......... . 51,500 72 ,380 Total population of centers I ...........................•...........•....... 177, 690 108, 810 288,370 414, 240 Other civilian and on-base military population ..........................•.......... 121 ,630 135,760 Total resident population ................................................ . 286,500 410,000 550,000 I Excludes military and civilian population located on military bases. ulation support services, the potential for developing a year-round fisheri es industry in the Gulf of Alaska, the possible growth of mining and processing of mineral resources, and expansion of forest products industries, including manufacture of finished goods for domestic consumption. Historic power requirement data assembled over the years by the Federal Power Commission were used to obtain guideli ne-related trends to set the course of the projections of the energy and peak demands for the future . The growth trend of Alaska electric uti li ty loads from 1945 through 1965 is shown in figure 5. During this period, the growth rate was such that loads about doubled every 5~ years. Projections were correlated with the popula- tion estimates. Actual 1965 total annual energy re- quirements and peak demands and estimates for the years 1975 and 1985 are shown in the electric power requirements table 5. No estimates of power requirements were attempted for those utilities in small -scattered villages and in trade, communica- t ion, and airfield centers, the operations of which are, for the most part, seasonal or part time. The small est annual increase in power require- ments-between 6 and 7 percent-is projected for the Southwest Region. This region is spa rsel y settled and its econ omy is presently dependent on fishing, wi th defense and communications offering some employmen t. Some minerals in the region have been exploited, such as those of the platinum group, but the overall mineral resources are of undetermined 21 potential. Tourism is of minor, but growing impor- tance, mainly for hunters and fishermen . There is n o indication at the present time of any dramatic surge in the economy of the area, and load growth is expected to be relatively slow. Until very recently, the Northwest Region seemed to be faced with conditions somewhat simi lar to thos e in t he southwest. The principal differences were exploration and development of copper de- posits at the Ruby Creek site, and oil and gas ex- ploration on the Arctic Slope. Recent discoveries have led to sp eculation that the region may be one of the richest in petroleum reserves in the world. There is some thought that very rapid industrial and commercia l expansion co uld accompany these developments and result in a similar expansion of the economy of the reg ion. Under the most pes- simistic outlook, these activities should provide some expansion of the economy along with the service- orie nted tourism industry, and power needs may be expected to increase at a somewhat faster rate than in the southwest. There are enormous coal deposits in northwest Alaska which m ight be readily mar- ketable in Japan if other developments should revo lutionize the transportation facilities out of the Arctic region . The Southeast Region's economy is expected to undergo a relatively steady rate of growth. The region already has well-d eveloped and thriving fishery and forest product industries, wh ich are expected to continue, and in the case of forest prod- B E R I N ;, \~~:~~~~~ s E A ARCTIC G CHUKCHI S£A \."·:~;~~::'? \!5L At;D I '-~~--~~ ... } Figure 4 22 NORTON P A C F c lltJLF OF S£A ALASKA FEDERAL POWER COMMJSSION ALASKA POWER SURVEY POPULATION AND ELECTRIC POWER LOAD CENTER AREAS SCAt£ IN Mllf.S :..-:• ... l LEGEND ---REGIONAL BOUNDARY HIGHWAYS AND ROADS =~~ STATE HIGHWAYS RAILROAD )\ U.S. AIR FORCE BASE • EXI STING HYDROELE CTRIC POWER PLANT S 0 • POTENTIAL HYDROELECTRIC POWER PLANTS FUEL PLANT S 0 POPULATION AND ELECTRIC POWER LOAD CENTER AREA + 0 C £ A N 23 -- TABLE 5 ' Projection of Alaska's Electric Power Requirements, Electric Utility Systems, and Nol)utility lnstallati'ons 1965 1975 1985 Region and type of load Load center number Energy Peak de-Energy Peak de-Energy Peak de- (fig. 4) mwh. mand mwh. mand mwh. mand (mw.) (mw.) (mw.) Northwest. ................................... 52,927 12.09 72,, 690 I6.52 IIO, 680 25. 19 Utility ................... 1, 2, 3 .......... 8, 219 1. 86 18, 100 4. 12 44,790 10.24 Do .................. (') 468 . 18 700 .30 1, 100 . 35 Nonutility ................ (') 44,240 10.05 53,890 12. 10 64, 790 14.60 Southwest. ................................... 154,293 35. 11 189,800 43.15 237,990 51. 06 Utility ................... 4, 5, 6 .......... 7, 038 1. 55 12, 800 2.85 24, 790 5.51 Do .................. (') 1,255 . 26 2,000 .40 3,200 . 55 Nonutility ................ (') 146,000 33.30 175,000 39.90 210,000 45.00 Southcentral .................................. 643,473 144.07 1,484,240 324.48 3,647,890 784.94 Anchorage-Kenai .......... 9 to 13 ......... 563,749 126.51 I, 364,720 297.79 3,442,090 739.49 Utility ............................... 406,604 92.66 1, 137, 840 249. 79 3, 201, 190 689.49 Nonutility (military) ................... I57, 145 33.85 226,880 48.00 240,900 50.00 Other areas ............... 7, 8, 14, I5 ...... 56,030 II. 76 88,620 I9.29 165,000 35.85 Utility ............................... 22, 917 5.06 50,660 II. 09 II8, 690 25.95 Nonutility ............................ 33, ll3 6. 70 37,960 8.20 46,310 9.90 Utility ............... (1) 7,494 2.10 11,600 3.00 IB, 900 4.60 Nonutility ............ (') I6, 200 3. 70 19,300 4.40 2I, 900 5.00 Interior .............. ' ........................ 368,860 81. 89 654, I30 144. 71 1, I45,68o 256.29 Fairbanks ................. I6 ............. 239,669 52.23 500, I10 109.26 967,980 215.89 Utility ............................... 106,867 25. I6 275,850 64.26 721,350 I64.69 Non utility (military) ................... 132,802 27.07 224,260 45.00 246,630 51.20 Utility ............... (') ............. 2, 191 . 55 4,020 . 95 6, 700 I.40 Nonutility ............ (') ............. I27, 000 29. 1I I50, 000 34.50 171,000 39.00 Southeast ..................................... 4I9,942 69.84 609,050 li I. 04 959, 730 I83.24 Utility ................... I7 to 24 ........ I 55, 023 33. 76 323,370 70. 79 668,630 141. 94 Nonutility (industrial) ...... 20 and 23 ...... 246, 62I 31. 60 263,000 35.00 263,000 35.00 Utility ................... (') ............. 2,298 . 78 3,680 . 85 6, IOO I. 30 Nonutility ................ (') ............. I6, 000 3. 70 19,000 4.40 22,000 5.00 Total utility requirement ................. 720,374 163. 92 I, 840,620 408.40 4, 8I5, 440 I,046.02 Total nonutility require- ment ................................. 9I9, I21 179.08 1, I69, 290 231.50 1, 286, 530 254. 70 Total Alaska ........................... · .... · · 1, 639,495 343.00 3, 009, 910 639.90 6, 101, 970 1, 300. 72 I Scattered nonload center loads. NoTE.-1965 utility actual, nonutility partly estimated; 1975 and I985 estimated. ucts to expand. Tourism is expected to become increasingly significant. None of these activities, however, is expected to result in marked upsurges in the region's economy, and thus a steady rate of growth in power requirements is predicted. A somewhat higher rate of growth is expected in the Interior Region caused by a lowering of power costs through an interconnection "with the South- central Region, where the development of large, low-cost, gas-fired, steam-electric plants is antici- pated. Electric space heating is being promoted 24 vigorously. This will help eliminate the smog and reduce ice fog in and around Fairbanks.1ll-electric home customers with installed heat now use an average of 34,000 kilowatt-hours annually. Fair- banks is a service center for the villages of the in- terior and for the University of Alaska. It will profit from a growing tourist industry and serve as a center for oil and gas exploration on the Arctic Slope and for the defense establishments of the interior. The Southcentral Region, which includes the greater Anchorag-e borough, the growing com- -------~--------~-------~---~----- ALASKA ELECTRIC UTILITY LOADS (ANN UAL PEAK DEMANDS AND ENERGY REQUIREMENTS ) 1945 . 1965 Figure 5 munities on the Kenai Peninsula and offshore Kodiak Island, is expected to show the most rapid growth both in population and in power use. An- chorage is the service center for the State, and the Kenai Peninsula is the site of a growing petro- chemical industry. Kodiak Island is a center for the fisheries industry, for naval and coast guard in- stallations, for ranching, and for tourism . These will tend to bring in population and enhance the economy. Anchorage is also a center for tourism and will benefit from this growing industry. The region also has forest resources that have not been fully developed and there are unexploited fish stocks in the Gulf of Alaska which could be harvested to supply year-round employment. Load growth is expected to follow population growth. While elec- tric space heating will face strong competition from natural gas, it is expected to increase in the home and commercial heating fields . There may also be limited ·applications for cooling and humidity con- trol in the summer. 25 Over the stern of Alaska State ferry, visitors peer down on a portion of the Juneau, Alaska, fishing fleet and beyond it the capital city itself. Southeastern ferries also call at Skagway, Haines, Sitka, Petersburg, Wrangell, and Ketchikan-all in Alaska-and Prince Rupert, B.C. The Uni versity of Alaska-farthest north university in America-provides accredited educational facilities and faculty. The university museum is one of the most popular tourist attractions in the State . The rates of growth of projected power require- ments for each of the five regions are presented in table 6. i TABLE 6 Rates of Increase in Alaska Electric Energy Requirements Geographic Region Increase in AverafC: annual generation rate o mcrease (percent) (perc ent) 1965-75 1975-85 1965-75 1975-85 Northwest .......................................................... . 37 52 3.2 4.3 Utility ......................................................... . 117 144 8. I 9.3 Nonutility ...................................................... . 22 20 2.0 1.9 Southwest .......................................................... . 23 25 2. I 2.3 Utility ......................................................... . 79 89 6.0 6.6 Nonutility ...................................................... . 20 20 1.8 1.8 Southcentral. ....................................................... . 131 146 8.8 9.4 Utility ......................................................... . 175 178 10.5 10.6 Nonutility .......... : ........................................... . 38 9 3. 3 .9 Interior ............................................................ . 77 75 5.9 5.8 Utility ......................................................... . !56 160 9 .9 10. I Nonutility ...................................................... . 44 12 3. 7 1.2 Southeast ..................................... , ..................... . 45 58 3. 8 4. 7 Utility ......................................................... . 108 116 7.6 8.0 Nonutility ...................................................... . 7 I .9 .I Total utility ......................................................... . !56 162 9.9 10. I Total nonutility ................................................. . 27 10 2.4 .9 Total Alaska ........................................................ . 84 103 6. 3 7.4 Alaska-made chemicals are manufactured by this Anchor- age producer. Most of the se v eral products made here are sold and utiliz ed within the State. 26 Many factors and forces in Alaska's economy account for the variation in regional load projec- tions. The prospects for increases in population support services and industrial employment are unique to each region. Where opportunities exist, the broadening of the manufacturing base to supply a greater share of goods for domestic use, and possi- bilities for the development of forest, fishery, water, and mineral resources were additional factors considered . In projecting an almost sevenfold growth in electric power consumption between 1965 and 1985, the Alaska Power Survey is not simply charting the electric utility industry's growth potential. Implicit in this growth projection is a rise in the total civilian per capita consumption of electricity from about 1,060 kilowatt-hours in 1950 to 3,100 kilowatt-hours in 1965 and 9, 700 kilowatt-hours in 1985 . Expressed in relation to personal income the in~rease is from 0.37 kilowatt-hour of electricity per dollar of income in 1950 to 0 .64 in 1965. In 1985, assuming that total personal income will increase at the 1950-65 rate of about 6.5 percent per annum, the kilowatt-hour consumed per dollar of income will be 1.34. During the 1945-65 period, the annual average growth rate of electricity use was nearly 1 o/3 that in the 48 States. Electric Power Markets A breakdown of t he energy requirement proj ec- tion into major use categories, as shown in table 7, suggests the industrial energy usage doubling every 4 . 7 years. A more detailed tabulation of the annual electric power requirements by major use categories at 5-year intervals from 1950 to 1985 is shown in appendix B of the report. The largest energy use is expected to lie in the residential category, doubling about every 8 years. Much of this is expected to come from increased use of electricity for space heating. TABLE 7 Projected Increase in Electric Energy Require- ments, by Categories of Use, Electric Utilities 1985 Millions of 20-year Number kilowatt-average of years Category of use hours annual to double increase rate usage over 1965 percent Residential (nonfarm) ........ 1, 428 9.4 7. 9 Farm 1 •..... 20 8.4 8.8 Commercial ........ 656 6. 9 10. 7 Industrial. .......... 1, 285 15.6 4. 7 Other uses 2 •••••.••• 291 10 . 2 7.2 Losses and unac- counted for ....... 415 9.9 7. 5 Total ........ 4,095 10.0 7.4 1 Includes relatively small percentage of irrigation and drainage pumping usage. 2 Includes uses fo r municipal water pumping, oil and gas pipeline pumping, street and highway lighting, heating and power usage in public buildings, transportation, and all ultimate consumption usages not elsewhere classified. Although commercial power usage in 1965 was second to residential, about 33 perce~t of the total, commercial requirements by 1985 will be in third place. Street and highway lighting and other usages are small, but are growing. In long-range projections of electric power usage, it is difficult to predict the effect of new product developments. New uses have come into being and have created levels of consumption far higher than were thought possible only a few years ago. Today, household uses of electricity are manifold . In the next 20 years, technological advances can be ex- 27 pected to create new applications and bring about improvements in techniques which will provide methods of using electricity in ways not generally known or available today. The projections for residential nonfarm electric utility customers assume a rise in average annual consumption of electricity from about 5,670 kilowatt-hours in 1965 to 14,000 in 1985. In many areas of other States, the present usage is already well over 10,000 kilowatt-hours. Alaska's industrial electric-load growth IS projected at 15.6 percent per year. The industrial market for power is expected to capture approxi- mately 28 percent of total generation by electric utility systems in 1985, compared with about 10 per- cent in 1965. Whether this rate of growth is attained will depend on the success with which extraction and processing of Alaska's mineral resources are pursued, and on increases in manufacturing capac- ity to produce finished products which heretofore have been imported. The projection is not unreason- able, however, considering that manufacturing now requires over 40 percent of the power sold in the 48 States. For the "flyingest State" in the United States, this Anchorage manufacturer produces airplane skis for use on the winter snow. I j il I . I The commercial category of total electricity use has historically covered a multitude of services, some of which could be classed as small industrial func- tions. Load growth in the commercial market for power is projected at 7 percent per year. The esti- mates allow for an accelerated expansion of lighting and electric space heating, much more electric office equipment of all kinds, the growth of electric cook- ing in restaurants and institutions, greater use of outdoor signs, display lighting, lighting of recrea- tional areas, and snow removal from business areas. Coupled with these uses is the anticipated con- struction of large numbers of all-electric hotels and motels. Low-electric rates will also be an incentive to modernize existing accommodations for use on year-round basis which should do much to improve the annual load factor of the Alaska power industry. The power requirements of Alaska's growing goods and services industry have always been com- paratively large, and comprise a substantial per- centage of the utilities' total loads. The projections foresee for 1985 an increase of some 656 million kilowatt-hours over 1965 in this category. Although its projected share of the total Alaska market will be less than it was in 1965, the expectation that it will amount to almost 19 percent of total electrical requirements compares favorably with present com- mercial usage in t~e 48 States. Utility Load Sha·pes and Diversity A plot of the annual loads of Alaska's major electric utility systems resembles a hammock swung between January and December, maximum loads being experienced in the latter month. Because of load growth, January peaks have usually been about 10 percent less than those oc- curring in the following December. From January, loads gradually fall off to minimum levels in June through August, about 65 percent of the December peaks. After August they climb sharply to their December maximums. Load diversity occurs when loads on two or more .power systems occur at different times. Diversity can be shared by interconnecting the systems and co- ordinating planning and operations. Thus, total capacity needed in the interconnected supply can be minimized by each system supplying a part of the peak load of the other. Although no observable seasonal diversity exists in Alaska, two other kinds of diversity do exist- time zone and random. Since there are four time 28 zones in Alaska, Panhandle loads peak one hour before the Yakutat area load, 2 hours ahead of loads in the vast central area, and 3 hours ahead of loads in the westernmost areas bordering the Bering Sea. Due to lack of zone-to-zone interconnections, how- ever, there is no way at present to utilize time-zone diversity, nor does it appear that time-zone interties will be established during the survey period. The random diversity category includes all differences in timing and magnitude of loads, other than those attributable to seasonal or time-zone characteristics. It results from hour-to-hour and day-to-day load changes as affected by daylight, temperature cycles, living habits, kinds of industry, work schedules, and the like. Some degree of random diversity exists within time zones. For example, in the Alaska standard time zone, there is evidence that the winter evening loads on the two largest systems serving the Anchorage- Kenai area peak 1 or 2 hours apart. Peak loads of the two systems in the Fairbanks area differ by an hour or more from the Anchorage peaks. During summer months, peak loads on the Anchorage Municipal System have been experi- enced at noon or earlier, whereas the Chugach Elec- tric Association, whose geographical service area is more extensive, experienced 6 o'clock evening peaks. In the Fairbanks area, the municipal system sum- mer loads have consistently peaked from around 4 p.m. to 6 p.m. The Golden Valley Electric Associa- tion system has peaked rather erratically-some- times before noon, at other times in the early after- noon and evening hours. Available evidence indicates that random diver- sity exists. A detailed study of load pattern varia- tions over an extended period of time would be required to establish the magnitude of load diversity and determine with some assurance whether it would continue to exist in future years. Where significant diversity exists, sizable benefits can be achieved through coordinated planning for new capacity, local interties, and systems inter- connections. Opportunities for bridging the Anchor- age and Fairbanks areas are discussed in subse- quent chapters. Nonutility Growth Prospects Projections of the future power requirements for nonutility establishments are more speculative than those in the utility category. Alaska's large non- utility power industry has found it advantageous to operate its own plants, particularly at some isolated locations or where there were opportunities to utilize low-temperature steam from a power tur- bine for heating or processing purposes. At many locations, no central station utility electric service is presently available. Therefore, no appreciable per- centage of nonutility load could be transferred to utility power sources in the near future. Where util- ity service is available at attractive rates, however, or will be as system expansions progress, it is reason-- able to expect that some of these nonutility loads will be transferred to central station sources of sup- ply as an alternative to replacing old and obsolete installations. As shown in table 5, growth rates for nonutility loads are expected to be significantly lower than those of the utilities. By 1985, the non- utility power requirements are expected to be only about 20 percent of the total. Consumer Power Costs Any discussion of the prospects for growth in Alaska's electric utility industry would be incom- plete without an appraisal of the costs to supply power to the ultimate consumer. Consumer rates for electricity are usually based on generation, trans- mission, and distribution costs-fixed and variable or operating components. The fixed cost component is made up of constant annual charges essentially un- affected by the number of kilowatt-hours generated. The variable expense component consists largely of the costs of fuel, operation and maintenance labor, material, and administrative and general expenses. The percentage relationships between the cost components for Alaska systems are noticeably dif- ferent from their counterparts in most of the United States, reflecting in part the predominance of pub- licly-owned utilities. Operating expenses are higher, and the generation function bears a much greater share of the total cost. The relative percentages of cost assignable to each function, based on currently available costs, are given in table 8. Many factors operate to produce differences in electric power costs and consumer bills. Differences lie in production and distribution costs, and are affected by the proximity of the generating station to low-cost fuel, water, and loads served; type and sizes of generating units; customer density; utility ownership and management practices; effectiveness of regulatory bodies, and the like. It is important to note that where retail rates are substantially below average in the United States, the power supply sources are all hydroelectric or are a part of an inte- grated system with large thermal-electric generating sources. Major reasons for high electric rates in many parts of Alaska, and in other States as well, are high labor costs and fuel prices, relatively small and inefficient generating units, low load densities owing to small population concentrations, the absence of developed hydroelectric power, and lack of a strong regulatory system. The long-term trend in rates for residential serv- ice has been downward in most Alaska communities as well as in other parts of the United States. For the Anchorage-Spenard area, for example, with its relatively large population served by municipal and a cooperative system, the average cost for 100 kilo-. watt-hours per month was $6.93 in 1948; $4.75 in 1958; $4.30 in 1966; and $4.28 in 1968. The bill for a monthly usage of 500 kilowatt-hours--energy for lighting, refrigeration, cooking, other household ap- pliances, and water heating-was $17.08 in 1948; $14.50 in 1958; $12.95 in 1966; and $12.35 in 1968. In less populated areas and those remote from low-cost fuel or water power, and where transporta- tion and labor prices are highest, rates are higher. TABLE 8 Total Delivered Cost of Power-Composition in Percent Function Generation ..................................... . Transmission. . . ................................ . Distribution. . . . ................................ . Total .................................... . Alaska Fixed Operating Total cost expense cost 17 3 12 32 29 51 1 16 68 68 4 28 100 Contiguous States Fixed Operating Total cost expense cost 28 8 23 59 23 2 16 41 51 10 39 100 But as in the Anchorage area, rate reductions have been made by many systems over the years. At Fair- banks, an area served by municipal and cooperative systems, the 1968 bills for 100 kilowatt-hours and 500 kilowatt-hours were $7.50 and $25 (in 1948 the bills were $9 and $33) . At some locations, there have been rate increases. For example, at Kodiak City, the 1968 typical bills for 100 and 500 kilowatt- hours were $9.15 and $24.65 (in 1948 the bills were $8 and $24.10), respectively. Until recently, electric bills for residential service in Ketchikan, served by Ketchikan Public Utilities, were Alaska's lowest. The 1968 bill for 100 kilowatt-hours was $4.60; for 500 kilowatt-hours, $12.03 (in 1948 they were $4.50 and $9.50). In southeastern Alaska communities where hydroelectric generation exists and fuel prices are less, bills have been consistently 25 to 60 percent lower. Decreases in bills have usually reflected changes in fuel costs, taxes, surcharges, amortization charges, or rate brackets. The geographic pattern of spread in retail rates in effect January 1, 1968, is indicated by the bills for residential, commercial, and industrial service computed for Alaska communities of 2,500 popula- tion or more. These are shown in table 9 ( residen- tial), table 10 (commercial), and table 11 (indus- trial). It is noted that each increment of increased use involves a lower unit cost which is possible be- cause the kilowatt-hour cost becomes less as more electricity is used. As energy usage increases, use of lower rate blocks reduces average costs per kilowatt-hour. For ex- ample, the average cost per kilowatt-hour for Anchorage and Spenard for a 100 kilowatt-hour per month residential usage is 4.275 cents; for a usage of 500 kilowatt-hours per month, the cost per kilo- watt-hour is 2.47 cents. For Ketchikan, the average TABLE 9 Typical Monthly Electric Bills, Residentia·l Service-Jan. 1, 1968 Community Popula-Minimum bill 100 250 tion Amount kwh.! kwh.2 500 750 1,000 kwh.a kwh.a kwh.a Utility Serving Community Anchorage ........... 44, 237 $2.00 36 $4.25 $8. 75 $11. 75 $14. 75 $17.75 Anchorage Municipal Light & Power De- partment. Do ...................... 2.00 36 4.30 8.95 12.95 16.95 20.95 Chugach Electric Associa- tion Inc. Chugiak Eagle River .. 2,500 5.00 72 6.25 13.00 19.25 25.50 31. 75 .Matanuska Electric Associa- tion Inc. Fairbanks ............ 13, 311 1. 80 22 7.50 15.00 22.50 30.00 37.50 Fairbanks Municipal Utilities System. Do ...................... 5.00 50 7.50 15.00 25.00 32. 50 40.00 Golden Valley Electric Association Inc. Juneau .............. 6,797 3.00 60 5.00 10.00 14.40 20. 15 25.90 Alaska Electric Light & Power Company Ketchikan ........... 6,483 3. 00 20 4.60 7.60 12.03 15.50 18.63 Ketchikan Public Utilities. Kodiak ... .......... 2,628 3.00 27 9. 15 15.25 24.65 34.00 43.40 Kodiak Electric Associa- tion Inc. Sitka ... ............ 3, 237 5.00 100 5.00 11.00 19.00 24.40 28.40 Sitka Public Utilities. Spenard ........ · ..... 9,074 2.00 36 4.25 8. 75 11. 75 14. 75 17. 75 Anchorage Municipal Light & Power De- partment. Do ...................... 2.00 36 4.30 8.95 12.95 16.95 20.95 Chugach Electric AsSocia- tion, Inc. 1 Lighting, small appliances and refrigeration. 2 Lighting, appliances, refrigeration, and cooking. 3 Lighting, appliances, refrigeration, cooking, and water heating. 30 TABLE 10 Typical Monthly Electric Bills, Commercial Service-Jan . 1, 1968 Billing Demands (kilowatts) and Monthly Consumptions (kilowatt-hours) Community 3.0 kw. 6.0 kw. 12.0 kw. 375kwh. 750kwh. 1,500 kwh . 30.0 kw. 6,000 kwh. 40 .0 kw. 10,000 kwh. Utility Serving Community Anchorage I ..•...•........ $12. 16 $21. 16 ..................... . Anchorage Municipal Light & Power Department Do 2 ••••••••.••••.••••.....•••.•.•...••••• $44. 64 Anchorage ................ . 13 .00 24. 00 23. 50 44.00 47.00 Fairbanks 3 ....•..•.•.•.•.. 76 . 50 Do' .............................. . 81. 60 Fairbanks. . . . . . . . . . . . . . . . . 30. 00 49. 50 82 .00 Spenard I .....•....•... 12. 16 21. 16 Do 2 ••••..••...•••.•••• Spenard .................. . 13 .00 23 . 50 44. 64 47.00 I Rate schedule 21. 2 Rate schedule 23. cost per kilowatt-hour for a 100 kilowatt-hour per month usage is 4.6 cents; for 500 kilowatt-hours, it is 2.41 cents . Trends in rate reductions for commercial service have been generally the same as residential. Large usage customers classified as industrial and billed accordingly are not numerous in Alaska. Only in a few cases is electric power sold wholesale for resale, and special terms and conditions usually apply in such instances. While further reductions in rates can be expected as operational improvements are instituted, the promise for significant reductions throughout the whole rate spectrum is brightest for utilities serving the Railbelt area. It is here that the largest load growth is projected and where the greatest benefits of an interconnection between the Anchorage and Fairbanks load centers would be expected. 31 $138. 60 $21 I. 05 176.00 268.00 ............. 294.00 252.00 138.60 176.00 452.00 372. 00 21 I. 05 268.00 3 Rate schedule Bl. ' Rate schedule B2. Chugach Electric Association, Inc. Fairbanks Municipal Utilities System Golden Valley Electric Association, Inc. Anchorage Municipal Light & Power Department Chugach Electric Association, Inc. Alaska's first oil refinery at Kenai on the Kenai Peninsula processes oil produced from 49th State wells. Most of the final product is sold for u;e in Alaska. j TABLE 11 Typical Monthly Electric Bills, Industrial Service-Jan. 1, 1968 Billing demands (kilowatts) and monthly consumption (kilowatt-hours) Community 75 kw. 150 kw. 300 kw. 500 kw. 1,000 kw. Utility Serving Community 15,000 30,000 30,000 60,000 60,000 120,000 100,000 200,000 200,000 400,000 kwh. kwh. kwh. kwh. kwh. kwh. kwh. kwh. kwh. kwh. Anchorage 1, . . . . .. . . . . . $338 $523 $662 $1,033 $1, 310 $2, 052 $2, 174 $3,411 $4, 334 $6, 809 }Anchorage Municipal Light & ~ Do 2,.............................................. 977 1, 436 1, 598 2, 363 3, 150 4, 680 Power Department Do: ...... ·........ 380 642 740 1, 243 l, 447 2• 436 .............. " ...... " ........ " .. ""}Chugach Electric Association Inc; Do . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 723 2, 548 3, 397 5, 046 Fairbanks.............. 735 1, 185 1, 470 2, 370 2, 940 4, 740 4, 900 7, 900 9, 800 15, 800 Fairbanks Municipal Utilities system. Spenard 1, . . . . . . . . . . . . 338 523 662 1, 033 1, 310 2, 052 2, 174 3, 411 4, 334 6, 809 }Anchorage Municipal Light & Do 2,.............................................. 977 1, 436 1, 598 2, 363 3, 150 4, 680 Power Department. Do: ...... ·· ...... · 380 642 740 1, 243 1, 447 2• 436 .................................... ""}Chugach Electric Association Inc; Do .. ·............................................................... 1, 723 2, 548 3, 397 5, 046 1 Rate schedule 23. 2 Rate schedule 22. a Large power schedule. 4 Large power 42. CHAPTER IV FUELS AND THERMAL-ELECTRIC GENERATING PLANTS Alaska is not lacking in raw fuel resources, but natural gas and coal are the only ones produced in quantity and processed locally for use in Alaska. Thus far, the major exploitation of mineral fields has been in the Interior and Southcentral Regions. Alaska's oil and gas industry has been through cyclic stages of development since about 1902. The Swan- son River field on the Kenai Peninsula, south of Anchorage, came into production in 1957, and the first refinery was built in 1963. Production from its 20,000 barrel per day crude oil capacity is limited to supplying heating oil for Alaskan homes, diesel distillates for the trucking industry, and jet fuel for transport planes. Most of Alaska's crude, naph- thas, and residual oils are exported to west coast refineries in the lower 48 States. Consequently, diesel and other liquid fuel products needed to supply the bulk of the requirements of Alaska's transportation and electric power industries must be imported. Another refinery is planned, and will constitute another step toward self-sufficiency of the Alaska fuel economy. Recent discoveries in the Prudhoe Bay area indicate the presence of large oil reserves on the Arctic slope. The discovery of natural gas on the Kenai Penin- sula and the spread in exploration through the Cook Inlet and the rich Beluga fields has placed natural gas in the foremost position in the Southcentral Region's fuel economy. Natural gas transmission and distribution facilities now serve the greater Anchorage, Soldotna, and North Kenai areas. Greater utilization of natural gas is hindered by long distances and sparse, scattered population. The total demand for energy so far has not been suffi- cient to justify the extension of gas pipelines beyond the Anchorage-Kenai Peninsula area. Conversion to natural gas has been relatively rapid in the civilian, domestic, and electric utility markets in the Anchorage area, and similar conver- sions are now under way in defense installation steam plants. The conversion of the Fort Richard- son and Elmendorf Air Force Base steamplants 33 from coal to natural gas and the conversion of family quarters at Elmendorf to natural gas was accom- plished during 1968. Some natural gas is used for heating and power generation at Barrow on the Arctic Ocean. The gas is moved by a 5-mile Federally-owned pipeline from U.S. Navy wells on the north slope. Refuse wood in conjunction with fuel oil and concentrated wood pulp liquor serves as fuel for pulp and paper mill operations and for byproduct generation of electric energy in southeast Alaska. There are scattered uranium deposits in Alaska, but there has been no large commercial production to date and the deposits are of unspecified commer- cial value. The Kendrick Bay-Bokan Mountain de- posit, west of Ketchikan, has supplied a considerable tonnage of commercial uranium ore to outside mills. Contracts to continue mining the ore body have been signed recently. Present and Projected Fuel Requirements and Costs Alaska's electric power industry is fossil-fuel oriented--coal and oil accounted for 73 percent and natural gas 8 percent of electricity production in 1965. Projections of fuel use show that by 1985 natural gas will produce 74 percent, coal4 percent, and oil 17 percent of the total fuel-produced elec- tricity. The remaining 5 percent will be from non- fossil fuels almost wholly in lumber-based industrial plants. These estimates ar~ predicated on the pro- duction of electric power from Beluga natural gas at a cost of 15¢/million British thermal units. The Beluga coal field contains billions of tons of known reserves, including presently known strippable coals of several hundred million tons. It has been sug- gested that the coal could be produced at a cost low enough to have an important bearing on an onsite generating plant. The average cost of fuel for Alaska's electric powerplants during 1965 was approximately 72 cents per million British thermal units, almost three times the average cost in the other States. By 1985, the average price of all fuel delivered to Alaska's sources of generation is projected to drop to about 34 cents per million British thermal units. This projected price reflects possible decreases in ex- ploration, production, processing, and transporta- tion costs coupled with sizable increases in demands for most of the conventional fuels, led by an eighteen to twentyfold increase in the requirement for natural gas. Two different assumptions were used in project- ing Alaska's fuel requirements for generation of elec- tric power. The first was that there would be no change in the present number of interties between electric utilities and nonutilities. The second was that loads and power sources in the Anchorage and Fairbanks areas would be interconnected, operations coordinated, and the bulk of the total load require- ment supplied from natural gas-fired electric gen- erating plants located largely in gas fields near Anchorage. Coal use would be confined to fueling a relatively small plant in the Healy area coal field near Fairbanks and a small steam-electric military plant near Anchorage at Whittier. Furthermore, it was assumed that some diesel and gas-turbine equip- ment would be converted to less costly fuels, some capacity would be retired or used as standby, and conversions from coal to gas-firing would be made in all south-central stations but one. With the An- chorage and Fairbanks power production sources interconnected, it was assumed that almost all of the load which had been supplied by coal-fired defense base plants would be served by large scale modem and more efficient sources in the south- central gas fields. Fuel requirements for electric power generation, which totaled 23,500 billion British thermal units in 1965, are expected to exceed 63,000 billion British thermal units by 1985 if the Anchorage and Fair- banks area utility and defense suppliers become in- terconnected. Should present intersystem relations not change, total British thermal units requirements would increase by 8 to 9 percent. Interconnection of the Anchorage and Fairbanks areas would, by 1985, produce an annual saving in the cost of fuel alone of $2.6 million. Higher thermal efficiencies of new generating units will also reduce the average amount of fuel needed to produce a kilowatt-hour of electric energy. The average heat rate of Alaska's steam- electric and internal-combustion engine generating 34 plants during 1965 was about 18,200 British thermal units/kilowatt-hour. Under the premise of more interconnections and larger units as suggested, the system heat rates could be reduced to approxi- mately 11,000 British thermal units/kilowatt-hour in 1985. During 1965, the average cost of all fuel used in Alaska was about 13.1 mills per kilowatt-hour. The comparable cost by 1985 is projected to be ap- proximately 4 mills per kilowatt-hour, representing a cost reduction of about 70 percent below 1965 levels. Fuel requirements-and costs for Alaska's electric power industry in 1965 and 1985 are shown in table 12. Other Uses of Natural Gas Natural gas is a highly desirable petro-chemical used not only for space, industrial process and power plant boiler heating but also in the manu- facture of other products, such as plastics, deter- gents, and fertilizers. A $50 million fertilizer manufacturing complex 11sing Kenai field natural gas as the chemical raw material for synthesis of anhydrous ammonia is being completed at Nikiski on the Cook Inlet. Production, beginning near the end of 1968, will be about 1,500 tons per day of ammonia and 1,000 tons per day of prilled urea. The urea fertilizer is for export to Southeast Asia, and the remaining ammonia pro- duction will be marketed in the lower 48 States. A $57 million liquefaction plant is being con- structed on the Kenai Peninsula by Japanese and American interests to liquefy natural gas for export to Japan. Deliveries by huge refrigerated tankers are expected to begin in mid-1969. The abundance of natural gas in Alaska will probably encourage the development of. additional industries to compete with electric power generation for the gas. lnterfuel Competition It appears that the most active competition be- tween fuels can be expected in the Interior and Southcentral Regions. In the Northwest, South- west, and Southeast regions, oil is expected to con- tinue to be the only practical fuel for electric power generation, although butane and propane gases may become available as products of the liquefaction plant at prices which would be competitive in these areas. Oil presently used in these regions is imported, -rrrr r and this Will continue until more refinery operations are available in Alaska. Liquefied natural gas may also compete if transportation and storage facilities can be developed at sufficiently low costs. Natural gas reserves largely in the Anchorage- Kenai fields and coal reserves in the Matanuska and Healy fields ample to meet Southcentral and In- terior Region generating plant requirements during the period of the survey. Other gas, oil, and coal reserves could be produced commercially if needed. The refining of sufficient quantities of crude oil in Alaska to supply most of the State's internal-com- bustion generating plants can now be considered a future economic certainty. TABLE 1'2 Alaska Electric Power Industry, Utilities and Nonutilities Combined Fuel energy sources Electric energy (Gigawatt- hours) Fuel require- ment (billion British thermal units) Unit cost (cents per million British thermal units) Total cost (dollars) Energy fuel cost (mills/ per kilowatt- hour) Cost reduction (percent) FUEL REQUIREMENTS AND COSTS BY ENERGY SOURCES, 1965 Coal. ............................... 454 8, 750 51 4,460,000 ........................ Natural gas .......................... 105 2,037 40 815,000 0 •••••••••••• 0. 0 •••••••• Oil. 0 •• 0. 0 ••••••••••• 0 •••• 0. 0 •• 0 •••• 485 6, 663 130 8, 660,000 • •••••••••••• 0 •••••••••• Nuclear. 0 •••••••••• 0 ••• 0 0 ••••••••••• 11 181 30 54,300 • •••••• 0 •••••••••••••••• Other fuels .......................... 235 5, 865 50 2,930,000 •••••••••••••••• 0. 0 ••••• Total ......................... 1, 290 23,495 '72 16,919, 300 13. 12 ••••••• 0 •••• Total coal, gas, and oil .......... 1, 044 17,450 180 13,935,000 13.35 ............ NO INTERREGION SYSTEM INTERCONNECTION, 1985 Coal ................................ I, 005 13, 890 31 4, 310,000 ••••••• 0. 0 •• 0 ••••••••••• Natural gas .......................... 3, 126 36, 718 15 5, 510,000 ........................ Oil. ................................ 903 11,523 100 II, 523,000 ......................... Nuclear ............................. 12 192 30 56,600 ........................ Other fuels ........................... 256 6,400 40 2,560,000 • 0 ••••••••••• 0 ••••• 0 •••• Total ......................... 5, 302 68, 723 1 35 25,939,600 4.52 66 Total coal, gas, and oil. ......... 5,034 62, 131 134 21,343,000 4.24 68 ANCHORAGE AND FAIRBANKS AREA SYSTEMS INTERCONNECTED, 1985 Coal ............................... . Natural gas ......................... . Oil ................................ . Nuclear ....................... ··· .. · Other fuels ......................... . Total ........................ . Total coal, gas, and oil ......... . I Average. 215 3, 916 903 12 256 5,302 5,034 2,670 42,644 11,523 192 6,400 63,424 56,837 35 30 15 100 30 40 1 33 801,000 6,400,000 11,523,000 56,600 2,560,000 21,340,000 18,724,000 4.03 69 3. 72 72 B E R N ' (I \~~\\~~~~ .. 5 E A A R C T I CHUKCHI S £A G \' ......... ~ ... ·\N:J~I ... .'l.!t ) ~-LA"'C { ~r·'-' v, ' Figure 6 36 NORTON s r o L 8 R I 8 • y 0 C E A N e£AUFORT S £A s 1 GULF OF ALASKA P A C F c 0 C E A N FEDERAL POWER COMMISSION ALASKA POWER SURVEY FOSSIL-FUEL RESOURCES LEGEND ---REGIONAL BOUNDARY HIGHWAYS AND ROADS ===0-STATE HIGHWAYS .,. + RAilROAD US AIR fORCE BASE f UH RESERV ES PRESE NT & POTENTIAL PRODU CTI ON AREA S SEE TABLE 13 FOR f iEL DS ./' .,. ( 37 Fuel Production, Reserves and Prices The locations of Alaska's fossil-fuel resources are shown in figure 6. Estimates of fuel reserves and price ranges in present and potential production areas are summarized in table 13. is well situated to supply domestic and foreign markets. Some production will soon be liquefied for export. Natural Gas Natural gas production in Alaska, now in relative infancy, is destined to grow in importance. Alaska Several major gas structures have been found in the Cook Inlet basin relatively near large popula- tion centers. Its availability, plus the relatively high percentage of methane and lack of impurities, such as sulfides, make it easily adaptable for a variety of uses. Discoveries of lesser importance have also been made on the Arctic slope in the Umiat-Gubik TABLE 13 Fossil-Fuel Resources Field Map symbol (fig. 6) Natural gas (unprocessed): Anchorage-Kenai Peninsula area: Swanson River .......... : ................................... . West Fork .................................................. . Sterling .................................................... . Kenai. .................................................... . Falls Creek. . . . ............................................ . 1 2 3 4 5 West Foreland.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Beluga River. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Middleground Shoal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Cook Inlet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Total gas ............................................................. . North slope area: Umiat...................................................... 10 Barrow...................................................... 11 Gubik....................................................... 14 Prudhoe.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Total gas ............................................................. . Crude petroleum: Anchorage-Kenai Peninsula area: Swanson River ............................. :. . . . . . . . . . . . . . . . . 1 Middleground Shoal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Total oil ............................................................ . North slope area: Umiat...................................................... 10 Simpson.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Fishcreek. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Prudhoe....... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Quantity (estimated) Millions cubic feet 10,000,000 Estimated price ¢/million B.t.u. 15-18 0 ••• • •••••••••••••••••••••••• 500 Millions barrels 200 200 ............. . Total oil.... . ......................................................... 5, OOQ-10, 000 Coal: Nenana (Healy) I............................................. 15 Matanuska 2................................................. 16 Susitna a . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Scattered Total coal ........................................................... . 1 1946 base, 861.6 measured million tons included. 2 1946 base, 6.6 measured million tons included. Millions short tons 6,938 137 2, 394 458 9, 927 23--45 30-53 3 Indicated and inferred only (base 1964). Includes 260 million tons in Beluga area, 402 million tons in Capps Glacier District, and 1,540 million tons in the Chuitna River field-a total of 2,394 million tons in an area adjacent to the Beluga gas generation site. 38 1' ' ' " • ' I -:1~ area. The resources of the Cook Inlet, Kenai Penin- sula and Beluga gas fields are conservatively esti- mated to be as high as 10 trillion cubic feet in terms of economically producible gas stocks. Estimates have been revised upward each year and, deposits appear adequate to supply competing petro-chemi- cal requirements as well as fuel needs of the electric utilities for many years. Yearend reports for 1967 put Alaska's "proved" natural gas reserves at 3.635 trillion cubic feet, eighth highest of State reserv«;:s. Eleven gas fields in the Anchorage-Kenai area are now in production. The average price delivered by pipelines to the Anchorage market was 40 cents per million British thermal units in 1965. The cur- rent price as a fuel for utility generating plant use is 38 cents. Gas field prices are expected to range around 15 cents per million British thermal units throughout the survey period. Thus, Alaska's natural gas assumes great significance as a competitive fuel. In 1965, Alaska produced a total of some 11,373 million cubic feet of natural gas, a considerable portion of which was returned to the ground as a pressure maintenance media for producing oil sands in the Kenai Peninsula. Some 5,000 million cubic feet were marketed in the Greater Anchorage area of which about 18 percent was used by Anchorage utilities to operate gas-turbine generating units. The use of natural gas by gas-turbine units will increase substantially, but, by far, its greatest use is projected to be by steam-electric plants. Coal Coal reserves in producing areas of Alaska have barely been disturbed, and are estimated to be about 10 billion tons. As shown in table 13, most of this is located in the Nenana field and a small percent in the Matanuska field, which are the only producing fields in Alaska at this time. They are located ad- vantageously with respect to large markets in the Interior and Southcentral Regions. Significant coal deposits are located in the Susitna field west of Cook Inlet and could possibly compete with gas as a fuel for electric power generation in the Beluga area. Coal deposits in northwest Alaska are estimated to contain billions of tons, but here and in other re- gions production for utility use during the Survey period is not expected. Alaska coals are predominantly sub-bituminous as in tlie Nenana field. Although operations have been discontinued in the Matanuska field, the coal in that area is high volatile bituminous in rank. 39 Both underground and strip mining is used in the Healy Creek beds of the Nenana field. The Wish- bone Hill District on the north side of the Mata- nuska Valley has a large number of bituminous beds ranging from a few inches to about 23 feet in thickness. In 1965, Alaska mined 860,000 tons of coal, an increase of 17 percent over 1964. Electric utilities used only 150,000 tons or 17 percent of the total. About 25,000 tons were used for steam heating by the utilities. The defense bases used 638,000 tons or 74 percent during 1964, but this amount will be reduced in the future due to the conversion of the military steam-electric plants from coal to natural gas. The prices of coal to the two Fairbanks electric utilities have remained relatively constant for the past few years and in 1965, f.o.b. the Healy mining area, ranged from about 34 to 45 cents per million British thermal units. Delivered to Fairbanks, the price is in the order of 52 to 64 cents. In the past, coal delivered to utilities in the Anchorage area from the Matanuska mines averaged about 50 to 60 cents per million British thermal units. Defense agency contracts have averaged about 27 cents per million British thermal units at the Healy mines and 29 cents for Jonesville-Matanuska area coal at the mine. Delivered costs have been about 42 cen~s per million British thermal units at Fairbanks de- fense plants and 39 cents at Anchorage defense plants. Coal for the Golden Valley Electric Associa- tion's new steam-electric generating plant in the Healy coal field area is about 29 cents per million British thermal units. At present, the cost of coal burned in Alaska's plants is about double the price paid by utilities in the contiguous 48 States, but any material increases in tonnage would be ex- pected to significantly reduce this difference. Mine costs vary, of course, with geological conditions, labor costs, degree of quality control, mining meth- ods and volumes mined. It is anticipated that com- petition from gas and oil fuels might cause some reduction in coal prices during the period of the Survey. Oil The petroleum industry has, since statehood, in- vested over $850 million in its search for and de- velopment of productive oil and natural gas areas in Alaska. The value of the oil produced in 1967 alone was more than $88 million. In 1967, year end ranking by states placed Alaska eighth in crude oil reserves with a proved reserve of 380 million barrels. Since the initial discovery of the Swanson River field on the Kenai peninsula in 1957, several addi- tional oil structures have been discovered and are being developed in the offshore area of Upper Cook Inlet. Oil production during 1965 amounted to around 11,100,000 barrels. In 1967, total production was 39,927,000 barrels and the prospects are that production in this and other fields will greatly increase. In an effort to aid and stimulate exploration in Naval Petroleum Reserve No. 4 (NPR-4), U.S. legislation now permits production and sale of crude oil to exploration companies operating on the North Slope, at a price not to exceed twice that of the monthly average of daily posted prices of marine diesel fuel in Seattle. Kenai Peninsula oil well in winter. This well produces crude oil, most of which is processed at the Kenai refin- ery. Some is transported south by ship (as in lower photo). Alaska has numerous large sedimentary basins as well as extensive Continental Shelf lands. Conse- quently the State is regarded as a likely area for the discovery of more oil and gas deposits. Recent successes by oil companies drilling in the Prudhoe 40 Bay area indicate highly significant oil reserves on the Arctic Slope. Some geologists feel that this area has the greatest petroleum potential of any geologi- cal province within the United States, possibly from 5 to 1 0 billion barrels. Until recently, crude oil was not refined in Alaska. Diesel and internal combustion engine fuels were shipped to Alaska ports from refineries in California or Washington and for inland use were transshipped by railway and truck. The cost of all grades of fuel oil used in electric utility plants in 1965 averaged $1.30 per million British thermal units. Further development of oil refineries will un- doubtedly reduce the future price of all grades of fuel oil. Tht; future use of diesel and gas turbine fuel is expected to increase throughout Alaska excent where there are lower cost natural gas sources. Other Fuels A small nuclear unit generates heat and power to supply part of the requirements for a military in- stallation in the Interior. The cost of the nuckar fuel for this installation has been estimated to be about one-fourth the price of fuel oil. However, the high-capital cost of small nuclear plants is expected to preclude their application during the Survey period, except possibly in special situations. Some lumber and pulp mills in the southeast Panhandle area use oil mixed with wood refuse for fuel, but mainly woodpulp liquor resulting from the breakdown of the wood into pulp materials. This has been estimated to cost about 40 P.ercent of the local fuel oil price. Compared with available fossil fuels, these other fuels are expected to play only a minor role in the development of Alaska's power resources by 1985. Transportation of Fuels Transportation cost is a significant component of the present price of most fuels in Alaska. The price of oil in some areas is doubled by the cost of trans- portation. The transportation costs account for about 30 percent of the average price of coal for steam-electric plants in the Southcentral and In- tenor Regions and 60 percent of the price of the natural gas piped into thermal plants in the Anchor- age area. Coal is transported by rail from the Healy fields to Fairbanks and Anchorage. It was also moved from the Matanuska fields to Anchorage by rail when the Matanuska fields were in operation. Coal is trucked to the Fairbanks area at about the same cost as by rail. For the past several years, the cost for moving coal from the Healy field to Fairbanks' utilities has been about $3.30 per ton (about 19 cents per million B.t.u.) and the cost from the Mata- nuska field to Anchorage, $2.54 per ton (about 10 cents per million B.t.u.). Alaska Railroad bridge, high above Hurricane Gulch, near the Chulitna Valley, north of Anchorage. Prior to the destruction of the Seward and Whit- tier commercial oil storage facilities in the 1964 earthquake, the Alaska Railroad was used to trans- port fuel oil from Kenai Peninsula ports to Anchor- age, Fairbanks, and way stations. The rail freight cost of transporting fuel oil by tank car to Fairbanks was $2.80 per barrel (about 47 cents per million B.t.u .). The Alaska Railroad is still used to ship oil from Anchorage to Fairbanks. It is anticipated that movements of coal will not increase sufficiently during the Survey period to bring about a significant reduction in coal trans- portation costs . The delivered coal price for the Healy steam-electric generating station is lower than elsewhere because of its location near the mine. Although coal slurry transmission by pipeline has been undertaken in other parts of the Nation, it would encounter obstacles in Alaska because of ter- rain, water availability, and adverse weather con- ditions. Coal for use by the electric power industry is not presently shipped by water transportation, and it is not expected to be during the Survey period . More and probably larger pipelines from the petroleum fields will be needed to supply the future fuel requirements of the Anchorage-Kenai area. The average price of natural gas delivered to An- 41 chorage by pipeline for gas-turbine use in 1965 was about 40 cents per million B.t.u . Major future gen- erating capacity in this area is expected to be constructed near the gas fields where little trans- portation of fuel will be required. It is not economically feasible to transport gas by pipeline to Fairbanks for demands foreseen by 1985. Transmission would add an estimated 44~ cents per million B.t.u . to the field price, resulting in a delivered cost some two to three times the de- livered cost of coal from the Healy fields. Two Department of the Defense petroleum pipe- lines serve military facilities in the Interior and Southcentral Regions. One 8-inch line extends 626 miles from tanker unloading facilities at Haines in the Southeast Region to Fairbanks. A second 8-inch line extends 60 miles from the port of Whittier on the Southcentral coast to Anchorage bases. Both receiving ports are open the year around. Fuel oil transportation and storage facilities can serve as a backup source of fuel if coal deliveries and stocks should be impaired for any reason . Under the pres- ent arrangements, these two pipelines are not avail- able for other than military use. This generating plant of Fairbanks Municipal Utilities System includes three coal-fired steam units with a total capacity of 8,500 kilowatts and a 7,000-kilowatt gas turbine. A Federally owned and operated 5-mile pipeline on the Arctic Slope supplies gas for heat and power at Barrow. A small commercial pipeline extends from Skag- way in southeast Alaska to Whitehorse in Yukon Territory. This 110-mile line, the majority of which is in Canada, can provide fuel for convoys traveling the Alaska Highway or for aircraft operating out of Whitehorse. It is not used to supply fuel for generation of power. Although the cost of water transportation is high, it is still the least expensive and in many instances the only method available to move fuel oil in large quantities. Transportation by open water to north- ern ports of the State is usually limited to 3 or 4 months. Fuel is distributed inland by tank truck, rail or barge and to some remote interior locations by aircraft or dog sled. In 1965 , the price of diesel fuel at Ketchikan (delivered from San Francisco) was as much as 70 percent more than the price in San Francisco. With quantity production by Alaska refineries, the price of diesel and fuel oil in Alaska markets should become substantially less. Barrow, Alaska, is America's most northern community, braving severe arctic winters and short suTnJmers. Prod- ucts from the sea and wild game provide staples for the town's Eskimo residents. Transportation of Fuels Versus Electric Transmission of Fuel Energy The lowest kilowatt-hour electric energy cost to the customer often depends on whether it is cheaper to ship the fuel to genera:ting plants in the vicinity of the load or transmit electric energy from generat- ing plants near the source of the fuel. This may be the determinant for location of an electric generat- ing station when there is a choice among locations that satisfy other requirements, such as cooling water or atmospheric criteria. Comparative studies in two areas of Alaska dis- close that energy can be moved at lower cost by electrical transmission than by shipment of fuel. Construction of wellhead and mine-mouth plants and transmission facilities is under way in these areas which will enable electricity generated in the 42 Beluga ·natural gas field to be brought to Anchorage, and electricity produced in the Healy coal field to be transmitted to Fairbanks. The benefits to be gained by these developments should provide the incentive to undertake further expansions in system facilities . The Survey program also included numerous studies to determine the savings which could be achieved through the interconnection of systems, and the comparative benefits of utilizing various combinations of thermal and hydroelectric power sources and fuel supplies. One study indicated that the annual cost to pipe natural gas from the Cook Inlet field to Fairbanks for local powerplants would be about double the cost of transmitting the energy as electricity. I \ Knik Arm powerplant on the Chugach Electric Associa- tion's system is a coal-fired plant with five units having a .combined generating capacity of 14,500 kilowatts. Steam-Electric Generating Plants Historically, many of Alaska's utility and non- utility electric generating plants have also produced steam for space heating, the processing of lumber products, and for mining operations. Combined production can result in modest economies in the supply of both heat and power. Generating units in utility steam-electric plants range in size from 500 to 5,000 kilowatts, in pressures from 400 to 850 pounds per square inch, and in temperatures from 700 to 900 ° F . This low range in pressures and temperatures, results in high heat rates (the number of British thermal units required to generate 1 kilowatt-hour ). Average heat rates of utility steam-electric plants in Alaska have dropped from about 22,600 British thermal units in 1945 to 17 ,5 00 British thermal units in 1965. By comparison, the average 1965 heat rate in the contiguous United States was 10,453 British thermal units. Generating units in defense base plants vary in size from 500 to 7,500 kilowatts and in pulp mills from 7,500 to 10,000 kilowatts. During operation, turbine throttle pressures and temperatures are typ- ically quite variable, 100 pounds per square inch to 850 pounds per square inch and 325° to 825° F., providing for balancing steam production and electric generation requirements. Plant heat rates are estimated to be around 22,000 British thermal units j killowatt-hour. Assuming that the cours.e of future development will employ units of larger size and higher steam pressures and temperatures, the average heat rate of steam-electric plants in Alaska should be reduced to about 11,000 British thermal units /kilowatt-hour by 1985. Nuclear and Other Non-Fossil Fuel Generating Plants Only one nuclear-fueled plant is in operation in Alaska. It is located at a military base and its rated electrical output is 2,000 kilowatts. Because nuclear plants of a size adapted to Alaska's needs are not competitive wi th alternative types, the development of any significant amount of nuclear power within the period of the projection is not foreseen . Steam-electric plants using byproduct fuels such as wood waste and pulp byproducts may expand their capacity to a degree, but the power produced is not expected to reach the domestic market. Gas-Turbine Electric Generating Plants Gas-turbine electric units were first installed by Alaska utilities in 1962 for base load operation as well as for peaking. Plants are presently operating in the Anchorage and Fairbanks areas, varying in size from 8,850 to 16,000 kilowatts. Natural gas or oil are used as fuels. Gas turbines are not as efficient as internal-combustion engines; in 1965, utilities experienced an average heat rate of 20,300 British thermal units /kilowatt-hour for gas-turbine operation. Improved units are available with a heat rate of 13 ,500 British thermal units for operation at 30° F. ambient temperature and 50 feet above mean sea level. A reduction in operating costs can be effected by "waste heat recovery" in which the exhaust from the gas turbine is used to make steam for a second generator driven by a steam turbine. Prepackaged gas-turbine units which can be shipped preassembled, are on the market with rat- ings up to 30 megawatts. In the larger sizes, which 43 must be field assembled, unit capacities up to 132 megawatts are available. These are powered by multiple aircraft-type jet engines. The capability of a gas turbine is higher at lower air temperatures. Accordingly gas turbines in Alaska are able to pro- duce their greatest power during the predominant winter peak demands. International Station of the Chugach Electric Association, Inc. is located near Anchorage. The photograph shows two gas-turbine generating units and a third was added in 1968. During 1968, a 32,000-kilowatt two-unit gas turbine plant went into service in the Beluga gas field on the west side of Cook Inlet. The use of gas turbines will continue to grow where the increments of load are relatively small and fuel costs are not a major consideration. The largest single generating station in Alaska, lo cated in Anchorage, has three gas turbines with a combined rating of 48,000 kilowatts and six diesels of 1,000 kilowatts each. A 22,000-kilowatt steam turbine will be added in 1971, the steam to be generated by waste heat from the gas turbines. Internal-Combustion Engine Generating Plants Internal-combustion engine generating plants will continue to supply power needs in many small communities. Plants vary widely in the size and number of units. Individual units of 2,500 kilowatts are in operation, but the more average size is in the range of several hundred kilowatts. Package-type units minimize many of the ship- ping and installation problems and are available in a sound-suppressed weatherproof housing. These units can be brought to full load from cold start within 60 to 90 seconds and are well suited to meet- ing many of Alaska's widely dispersed smaller load demands. Heat rates vary from 13,000 to 10,000 British thermal units /kilowatt-hour for most diesel plants, depending on kinds of fuels, unit sizes, and operating conditions . The Alaska Village Electric Cooperative Associa- tion, formed in 1967 as a statewide REA borrower, will use a $5.2 million loan from the Rural Electri- fication Administration to install 9,650 kilowatt of diesel capacity in 5,9 villages to serve primarily some 20,000 Eskimos, Aleuts, and Indians. The program may ultimately provide package-type diesel plants and underground distribution systems in some 206 presently unserved villages. These vi llages have pop- ulations ranging from 7 5 to 400 and have power requirements in the range of about 25 to 75 kilo- watts. They are generally separated by many miles of unfavorable terrain, and fuel costs are between 4~ and 6 cents per kilowatt-hour. Delivered power costs would range from 9 to 16 cents per kilowatt- hour. The recent REA loan will permit starting a program which, under present plans, would provide power to about two-thirds of these communities by the end of 1980. Siting Considerations for Large Electric Generating Stations Many factors must be considered m deciding where to locate a large generating station. The choice is usually based on a series of engineering and economic studies for a number of alternative sites. Important considerations include relation of plant to load, system and intersystem configuration and reliability of bulk power supply, transmission line losses, land, foundation conditions, fuels and fuel transportation costs, cooling water, air quality ef- fects, and esthetics. Municipal generating plant of the cit y of Anchorage, with three gas turbine and six diesel units, was the largest single generating station in Alaska at the end of 1968. 44 Not all of Alaska's principal electric power needs are located where the .State's abundant fuel resources are readily accessible but fortunately the Anchorage and Fairbanks areas are within reasonable proximity of abundant economic fuel supplies. The Anchorage area has the greatest opportunity for accommodat- ing large plants of the future. These are expected to be natural gas-fired, steam-electric installations in the Cook Inlet gas fields where ample supplies of fuel and cooling water are readily available. A large supply of cooling water is required to condense steam leaving the turbines for re-use in the boilers of large conventional fossil-fuel fired steam-electric generation stations. For this reason, plants are located near sizeable rivers and lakes and at tidewater. Plant size, heat rate, and temperature rise determine magnitude of required water flow. For a cooling water temperature rise of 13° F. from condenser inlet to outlet, a flow of about 650 gallons of water per minute is required per megawatt of generating capacity. Apart from icing problems, Alaska poses no difficulty in finding adequate water supplies. With the increase in population, however, and the growing concern with esthetic consideration, each proposed new plant should be judged in terms of its probable effect on the environment, biologi- cally and esthetically. While it is understandable that Alaska has had less reason to be concerned about such problems in the past, regard for preserving natural habitats for fish and wildlife and for the prevention of air pollution will warrant careful con- sideration of potential impacts in the location and design of new generating facilites. Geography and weather conditions may combine to produce temperature inversions with resulting concentrations of pollutants and formation of ice fog. The Fairbanks area has long experienced smog and ice-fog problems and such conditions could be aggravated b y operation of cooling towers or ponds. The sulphur content of fuel burned and the effi- ciency of combustion and of a plant's air-cleaning equipment play important roles in reducing air pollution to an acceptable level. Trends in Fuel-Electric Plant Actual Power Production Costs The average total production costs of power generated by Alaska's coal, gas, and oil-burning elec- tric utility plants are shown in table 14. Similar costs for the nonutility segment of Alaska's power TABLE 14 Eledric ·Power Production Expenses 1 (MillsjK.ilowatt hour) Type 1960 1961 1962 1963 1964 1965 Steam-electric: 2 Fuel ....................... ·· ... ························ 9.3 10.7 II. 9 8.2 10.5 6. 7 12.6 7.5 10.9 8.8 10. I 9.0 Operation and maintenance ............................... . Total steam-electric .................................... . 20.0 20. I 17. 2 20. I 19. 7 19. I Gas-turbine: 3 Fuel............................................................................ 8. 5 8.9 2.2 9. I 2.2 Operation and maintenance........................................................ 3. I Total gas-turbine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II. 6 II. I I I. 3 Internal-combustion: Fuel ....................... ··.·························· 16.2 24.8 16. 7 19. I 17. 3 16.8 15.0 12. 7 16.2 II. 6 14.3 12.4 Operation and maintenance ............................... . Total internal-combustion ............................... . 41.0 35.8 34. I 27.7 27.8 26. 7 1 Data include information from reports filed with the Federal Power Commission and ·additional information submitted by the utilities for this report. Fixed charge costs are not included. industry are not available but would be expected to be somewhat higher. Fuel costs, however, have tended to be lower and because a large percentage of plant capacity is on military bases, operation and maintenance costs could be less. As indicated, costs per kilowatt-hour for steam-electric generation have remained fairly constant over a 6-year period. Dur- ing this time, the size and efficiency of steam plant facilities changed very little, and operation and fuel costs remained fairly constant. Production costs for utility gas-turbine genera- tion were 41 percent lower than steam-e1ectric costs and 58 percent lower than internal-combustion costs in 1965. The greatest difference is in the opera- tion and maintenance costs. The low operating costs of gas-turbine units and the proximity of the large load areas to natural gas sources explain why gas- turbine capacity in 1965 amounted to 45 percent of the total capacity in utility fuel plants. The many small plants have kept average genera- tion costs at higher levels than those in other States. Larger units and plants, lower cost fuels, and inter- connection and coordination among utilities should affect substantial reductions in production costs. 45 2 Excludes cost of coal used for steam heat production. 3 1963 first full year of operation. Data include both oil and gas-fired turbines. Comparison of Costs for Large and Small Plants Lower investment cost per kilowatt of generating capacity can be achieved by increasing the unit size. Further savings can be achieved through improved heat rates obtainable from large thermal units and through optimization of steam conditions. For a steam-electric plant designed to bum only natural gas or oil, the absence of coal and ash-handling facilities results in substantial savings. Unitization has also brought down the costs of internal-com- bustion installations. Cost estimates of the components of electric power production for four types and a range in sizes of generating plants, are shown in table 15. Particularly notable is the effect of size on the pro- duction costs of coal and gas fired steam-electric plants. Capital investment costs used in developing the component costs of table 15 are indicated in the table. Some new diesel unit designs now coming into use for combination peak and base load service are available at about one-half the costs of heavy duty units. 1TABLE 15 Estimated Power Prod'uction Costs Items 2-unit 400-mw. plant Dollars per Mills per kilowatt kilowatt- Single unit 40-mw. plant Dollars per Mills per kilowatt kilowatt- Coal-fired steamplant: I Assumed capital investment. . . . . . . . . . . . . . . . . . . . 195 Fixed charges ........................................... . Fuel. .................................................. . Operation and maintenance ............................... . Total ................................................ . Gas-fired steamplant: 2 Assumed capital investment. . . . . . . . . . . . . . . . . . . . 155 Fixed charges ........................................... . Fuel ..................... · ... ··· ... ····················· Operation and maintenance ............................... . Total. ............................................... . hour 3.2 2.5 0.8 6.5 2.6 1.4 0.5 4.5 350 275 hour 5.9 3.4 2. 7 12.0 4.6 1.7 2.5 8. 7 Single unit 25-mw. plant Single unit 10-mw. plant Dollars per Mills per Dollars per kilowatt kilowatt-kilowatt Peaking service: 2 Gas-turbine plant: Assumed capital investment. . . . . . . . . . . . . . . . . . . . 115 Fixed charges ........................................... . Fuel .................................................. ·· Operation and maintenance ............................... . Total ................................................ . hour 2.0 2.6 1.4 6.0 130 Mills per kilowatt- hour 2.2 3.0 1.9 7. 1 Single unit 10-mw. plant Single unit 2-mw. plant Dollars per Mills per Dollars per kilowatt kilowatt-kilowatt hour Base load: Internal-combustion engine plant: 3 Assumed capital investment. . . . . . . . . . . . . . . . . . . . 280 . . ......... 350 Fixed charges ........................................... . 4. 7 •••••••• 0. Fuel ............................... ··· ... ··············· 1 I. 3 . . . . . ....... Operation and maintenance ............................... . 5.0 • • • 0 .. 0 •••• Total ................................................ . 21.0 ........ . . Mills per kilowatt- hour . ..... . . . . 5.8 13.5 12.5 31. 8 Savings (mills per kilowatt- hour 2.7 0.9 1.9 5.5 2.0 0.3 1.9 4.2 Savings (mills per kilowatt- hour 0.2 0.4 0.5 I. 1 Savings (mills per kilowatt- hour) .. . . . . . . . . I. 1 2.2 7.5 10.8 I Fuel at 28¢ per million B.t.u. 2 Fuel at 15¢ per million B.t.u. 3 Fuel at 110¢ per million B.t.u. Assumption: Estimates are based on a composite fixed charge rate of 7.3 percent (table 24, ch. VIII) and a 50-percent capacity factor. 46 ----.-~-------- l Summary and Conclusions To keep pace with the projected growth in elec- tric loads, thermal and hydroelectric capacity pres- ently in service will need to be quadrupled by 1985. During this period of expansion, fossil-fuel prices are expected to decrease from an average of 80 cents per million British thermal units in 1965 to 33 cents in 1985. Reductions are anticipated in fixed charges and nonfuel related production expenses. The achievement of potential cost reductions hinges largely on the willingness of utilities to interconnect and coordinate the planning and operation of their systems. The use of large natural gas-fired steam-electric generating units holds the greatest promise for im- proved economic benefits within the study period. Lesser but still significant savings can be expected by the use of effective application and use of diesel and gas-turbine equipment in some of the future plant designs. Admittedly, power costs in many Alaska com- munities cannot be greatly reduced because gen- erating facilities are necessarily small and serve relatively isolated areas. Maintenance costs in some instances are increased by climatic conditions, and distribution costs are higher because of the small loads and fewer customers. Nevertheless, where large generating plants with improved thermal efficiencies and lower capital, operation, main- tenance and fuel costs can be used, the outlook is bright for reductions in electricity costs for over 75 percent of Alaska's population. 47 CHAPTER V HYDROELECTRIC POWER RESOURCES Alaska's rugged topography presents innumerable opportunities for the development of hydroelectric power, varying from small projects in steep valleys with high heads to broad valleys on large rivers with low to moderate heads. Many of the sites, however, which appear physi- cally attractive have limited utility because of low winter stream flows and lack of adequate storage for seasonal regulation. Others are remote from load centers and some of the broader valley sites would require extensive dams. Estimates of dependable energy yield are often hampered by an absence of long-term meteorological and hydrological records. Among .the resources which supplied power in 1950 for Alaska's utility, defense and industrial uses, hydroelectric installations supplied 30 percent of the total capacity, steam-electric plants 45 percent, and internal combustion engines the remaining 25 per- cent. In 1965, hydro supplied 17 percent, steam 35 percent, and internal-combustion and gas-tur- bines, almost 48 percent. Hydroelectric capacity in- creased from 23,400 kilowatts in 1950 to 83,500 kilowatts in 1965. History of Hydroelectric Power in Alaska Most of the early hydroelectric developments in Alaska provided power for mining or other indus- trial uses, such as fish processing. Developments were frequently associated with direct use of hy- draulic power. The first development for utility use was undertaken by the city of Ketchikan pub- lic utilities in 1901. Ketchikan is the only utility system with multiple hydroelectric developments and is still largely dependent on hydroelectric power to supply its requirements. A. J. Industries, suc- cessor to Alaska Juneau Gold Mine Co., also op- erates a multidevelopment hydroelectric system and sells energy to Alaska Electric Light and Power Co. in Juneau. The largest existing hydroelectric in- stallation in the State is the Alaska Power Adminis- tration's 30,000-kilowatt Eklutna plant, 32 miles north of Anchorage, and the second largest, located on the Kenai Peninsula, 60 miles southeast of 49 Anchorage, is the 15,000-kilowatt Cooper Lake plant of Chugach Electric Cooperative Association, Inc. Construction has been started by the Corps of Engineers on the first phase ( 46,700 kilowatts) of the 70,000-kilowatt Snettisham project on Long Lake, 28-miles southeast of Juneau. Many of the existing hydroelectric plants are small installations of less than 50 kilowatts, and generate power for fish canneries. Hydroelectric Projects, Developed, Under .Construction, and Authorized There are 41 hydroelectric developments in Alaska, existing, under construction, or authorized. These range in size from 1.5 kilowatts to 46,700 kilowatts, based on the initial capacity of the Snet- tisham project. Total capacity is 196,515 kilowatts. Several are not in operation; two are under con- struction; one is licensed by the Federal Power Commission, but not yet under construction; and one is authorized for Federal construction. The plants, ownership, and construction status are shown in table 16. Hydroelectric Developments Under License Under provisions of the Federal Power Act, the Federal Power Commission issues license!> for defi- nite terms not to exceed 50 years to non-Federal entities, authorizing the construction, operation, and maintenance of hydroelectric developments which affect public lands,. are located on streams over which Congress has jurisdiction, or where the power produced is used by a licensee operating in interstate or foreign commerce. The Act specifies that, in the judgment of the Commission, the project adopted shall be best adapted to a comprehensive plan for improving or developing a waterway or waterways for the use or benefit of interstate or foreign commerce, for the improvement and utilization of water-power devel- opment, and for other beneficial uses, includir.J recreational purposes. I i I == 2 = ?e TABLE 16 Hydroelectric Developments Existing-Under Construction-Authorized, December 31, 1968 System Southeast Region: Utilities- Plant Name or FPC Project No. Location Alaska Electric Light and Gold Creek ......... Juneau ................ . Power Co. Alaska Power and Telephone 1051 ............... Skagway .............. . Co. Pelican Utility Co ............................... Pelican ................ . Ketchikan Public Utilities. . . . 420. . . . . . . . . . . . . . . . Ketchikan ............. . Do .................... 1922 .................... do ................ . Do .................... 19l2 .................... do ................ . Metlak.atla Indian Com-Purple Lake ........ Metlakatla ............. . munity. City of Petersburg. . . . . . . . . . . 201. . . . . . . . . . . . . . . . Petersburg ............. . Sitka Public Utilities ......... 2230 ............... Sitka .................. . U.S. Army, Corps of Engineers Snettisham ......... Speel River (near Juneau). Subtotal. utilities .................................................... . Nonutilities- A. J. Industries ............. 2307 ............... Juneau ................ . Do . . . . . . . . . . . . . . . . . . . . 2307 .................... do ................ . Do . . . . . . . . . . . . . . . . . . . . 2307 .................... do ................. . Alaska Lumber and Pulp Co .. 2267 ............... Sitka .................. . Bahovec, Fred .............. 1185 ............... Baranoflsland ......... . Buchan and Heinen Packag-Skeckley Creek ...... Port Armstrong ......... . ing Co. Keku Canning .................................. Kupreanof Island ....... . Libby, McNeill and Libby Co. 206 ................ Ketchikan ............. . O'Neill, F. W. and Sarah ........................ Baranoflsland ......... . Capacity kilowatts 1, 600 338 500 4,200 5,600 2, 100 3,000 2,000 6,000 46, 700 72,038 2,800 2,800 2,800 900 3 14 30 67 3 Status Owner- ship p p p NF NF NF. NF NF NF F p p p p p p p p p Con- strue- tion E E E E E uc E E E uc E E E L E E E E E Remarks Plant is being operated under a Forest Service permit. Beaver Falls addition was completed in 1968. Capacity of 70,000 kilowatts is author- ized. 46,700 kilowatts represents first phase of construction. Licensed, but not yet under construction. Operating under Forest Service permit issued Sept. 4, 1959. Columbia Ward Fisheries, successor to Libby (1959). Applic11-tion has been made for a Forest Service permit. ··.~ (.J1 - ---~~----.,.-------~~~~-- Pacific American Fisheries . . . . . . . . . . . . . . . . . . . . . . . . Linkum Creek ......... . Stofold and Grondahl . . . . . . . . . . . . . . . . . . . . Kuiu Island ........... . Packaging Co. Sheldon-Jackson Jr. College ...................... Sitka .................. . Swanson, Ernest.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chicago£ Island ........ . 17 15 50 7 Subtotal nonutilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9, 506 Subtotal Southeast. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81, 544 Southcentral Region: Utilities- Chugach Electric Association . Alaska Power Administration. U.S. Army, Corps of Engineers. 2170. . . . . . . . . . . . . . . Cooper Landing ........ . Eklutna. . . . . . . . . . . . Eklutna ............... . Bradley Lake. . . . . . . . Bradley River .......... . Subtotal utilities .................................................... . Nonutilities- Alaska Packers Association. . . . 620. . . . . . . . . . . . . . . . Indian Creek ........... . Chatham Straits Fishing Co ....................... Crab Bay .............. . Intercoastal Packing Co ...... 2026 ............... Near Kodiak ........... . Kennecott Copper Co. . . . . . . . 1949. . . . . . . . . . . . . . . La touche Island ........ . Parks Canning Co.1 ••••.•..........••••......•... Kodiak Island .......... . San Juan Fishing and 2251 . . . . . . . . . . . . . . . La touche .............. . Packaging Co. Kodiak Fisheries ' . . . . . . . . . . . 1909. . . . . . . . . . . . . . . Kodiak Island .......... . Do 1 •••..••.•••••.•...• 1432 .................... do ................ . New England Fish Co ........ 1299 .................... do ................ . Estes Brothers, Inc ...... , . . . . 1196 . . . . . . . . . . . . . . . Moose Pass ............ . Subtotal nonutilities .................................................. . Subtotal Southcentral ................................................. . See fo<>tn<>te at end of table. 15,000 30,000 64,000 109,000 50 5 30 37 7.5 100 12.5 75 8 21 346 109,346 p p NF p NF F F p p p p p p p p p p -------------------------- E E E E E E A E E E E E E E E E E Operating under Forest Service permit issued Oct. 14, 1963. · Operating under Forest Service permit issued Feb. 15, 1961. Project is being re-evaluated for lower plant factor, higher capacity design. License transferred to James Sumpter, May 7, 1963. Project has been sold to CWC Fisheries. License renewal application pending. Project has been sold to CWC Fisheries. License renewal application pending. I I TABLE 16 Hydroelectric Developments Existing-Under Construction-Authorized, December 31, 1968-Continued Interior Region: Utilities- System Plant Name or FPC Project No. Location Capacity kilowatts Status Owner- ship Con- strue- tion Chatanika Power Co., Inc .... 2264 ............... Chatanika .......................... P E Subtotal utilities .................................................................. . Nonutilities- Subtotal Interior ................................................................. . Northwest and Southwest Regions: None ............................................................................... . Total-Alaska............................................................ 190,890 Remarks Plant destroyed by Fairbanks flood. Application has been filed for sur- render of license. I 1968 records of the State Department of Revenue and the State Department of Fish and Game indicate these are the only canneries presently operating in the Southcentral region. NoTEs.-Status designations: F=Federa1; NF=Nonfederal; P=Private; E=Existing; L=Licensed; A=Authorized, UC=Under Construction. At the end of December 1968, 17 licenses were in effect and two renewals were pending covering 22 developments. Of this total, 19 are existing proj- ects, one is under construction, one is yet to be constructed 1 and one has been destroyed.2 The total installed capacity in the 19 existing projects at the end of December 1968 was 41,942 kilowatts. The ownership, size, and status of all projects for which licenses are outstanding is summarized in Table 16 . The city of Ketchikan was authorized by amendment of license for project No. 1922, Beaver Falls, to add 2,100 kilowatts of capacity. Work on features covered by the amendment was completed in 1968. A license application is pending on one proposed development as follows: Project Owner Terror Lake ...... Kodiak Electric Assoc. FPC Installed project capacity No. kw . 2434 30,000 License applied for May 29, 1967, to con- struct and operate an initial installation of two 10,000-kw. generators. A preliminary permit is outstanding for one proposed project as follows: Project Owner Power Creek. . . . . . Cordova Public Utilities. FPC Installed project capacity No. kw. 2656 3,000 Many of the outstanding licenses are for projects classified as minor under present Commission rules and which could operate under permits issued by the Forest Service upon expiration of present FPC licenses. Hydroelectric Development by Federa·l Agencies At the present time, there is only one Federal power project in operation in Alaska, the 30,000- kilowatt Eklutna project of the Alaska Power Ad- ministration. The first phase, 46,700 kilowatts, of the 70,000-kilowatt Snettisham project is under construction by the Corps of Engineers. The 64,000- 1 The 900-kilowatt plant, project No. 2267, Alaska Lumber and Pulp Co., was licensed in 1960, but is not yet under construction. 2 The 5,625-kilowatt plant of the Chatanika Power Corp. was destroyed in the Fairbanks flood in 1967 and the corporation has applied for a surrender of license. 53 kilowatt Bradley Lake project has been authorized for construction by the Corps of Engineers, but construction funds have not been requested and the project is to be restudied to determine whether it should be redesigned for operation at about 25-per- cent load factor which would call for increasing the project capacity to about 187,000 kilowatts. The Alaska Power Administration's Eklutna powerplant near Anchorage has two 15,000-kilowatt hydroelectric units. Interior v ie w of Alaska Power Administration's 30,000- kilowatt Eklutna powerplant near Anchorage. The Corps of Engineers is completing a feasibilit y report on the 5,040,000-kilowatt Rampart project on the Yukon. It has appeared unlikely that power from the Rampart project could be made available to serve loads before 1985, the end of the projection -- period of this Survey. A further exploration during the early years of the Survey projection period of Alaska's natural resources and the opportunities for the economic development of these resources to serve U.S. and foreign markets should help to clarify the market for and the economic feasibility of a major hydroelectric power development in Alaska of the magnitude of the Rampart Canyon project. Hydroelectric Surveys by Federal Agencies Table 17 presents data concerning a large num- ber of hydroelectric developments in Alaska con- TABLE 17 Summary of Initial Evaluation of Alaska Hydroelectric Potentialities [Lowest priced projects with prime power capacities in excess of 2,500 kilowatts as evaluated on basis of Project Northwest: Stream Major features in addition to powerplant (dam is concrete unless noted) Agashashok (Igichuk) .......... Noatak River ......... Dam, Earth Dike ............... . Misheguk (Upper Canyon) ........... do ............... Dam, Earth Dikes .............. . Nimiuktuk ......................... do ............... Dam .......................... . Kobuk River. . . . . . . . . . . . . . . . . . Kobuk River. . . . . . . . . . Earth Dam .................... . Tuksuk (Imuruk Basin) ......... Tuksuk Channel ....... Dam .......................... . Interior: Holy Cross .................... Yukon River .......... Earth Dam .................... . Dulbi. ....................... Koyukuk River ............. do ........................ . Hughes ............................ do .............. Dam .......................... . Kanuti ............................. do .................... do ........................ . Melozitna .................... Melozitna River ............ do ........................ . Drainage area (slluare miles) 4 12,700 8, 750 7,000 7, 840 4,275 320,000 25,700 18,700 18,000 2,659 Ruby ........................ Yukon River ............... do ......................... 256, 000 Junction Island ................ Tanana River ......... Earth Dam..................... 42,500 Bruskasna. . . . . . . . . . . . . . . . . . . . Nenana River. . . . . . . . . Dam. . . . . . . . . . . . . . . . . . . . . . . . . . . 650 Carlo ............................. do .................... do......................... l, 190 Healy (Slagle) ...................... do .................... do......................... I, 900 Big Delta ..................... Tanana River ......... Earth Dam .................... . Gerstle ............................ do .................... do ........................ . Johnson ........................... do ............... Dam, Earth Dikes .............. . Cathedral Bluffs .................... do ............... Earth Dam .................... . Rampart ..................... Yukon River .......... Dam .......................... . 15,300 10, 700 10,450 8,550 200,000 Porcupine (Campbell River) . . . . Porcupine River ............ do. . . . . . . . . . . . . . . . . . . . . . . . . 23, 400 Woodchopper ................. Yukon River ............... do ......................... 122,000 Fortymile ..................... Fortymile River ............ do........................ 6, 060 Southwest: Crooked Creek. . . . . . . . . . . . . . . . Kuskokwim River .......... do ........................ . Nuyakuk (Nuyakuk-Tikchik) .... Nuyakuk River ........ Dam, Tunnel, Penstock .......... . Lake Iliamna. . . . . . . . . . . . . . . . . K vichak River. . . . . . . . Earth Dam .................... . Tazimina ..................... Tazimina River ....... Earth Dam, Tunnel Penstock .... . Ingersol (Lackbuna Lake) ...... Kijik River ................ do ........................ . Kukaklek ..................... Alagnak River ........ Dam, Tunnel, Penstock .......... . Naknek ................ · ...... Naknek River ......... Earth Dam .................... . See footnotes at end of table. 54 31, 100 I, 530 6,440 346 300 480 2, 720. Maximum regulated w.s. elevation (feet) 150 550 750 150 190 137 225 320 500 550 210 400 2,330 l, 900 I, 700 1, 100 1, 290 1,470 I, 650 665 975 1, 020 1, 550 500 342 150 725 1,460 825 150 sidered by the Subcommittee for Hydro Resources. Many of these have been reported on by the Corps of Engineers and the Department of the Interior. The Corps' findings are included in seven interim reports, bearing dates from 1950 through 1959, on Southeastern Alaska, Cook Inlet and Tributaries, Copper River and Gulf Coast, Tanana River Basin, Southwestern Alaska, Northwestern Alaska, and the Yukon and Kuskokwim River Basins. The most re- cent Department of the Interior findings are in- cluded in its January 1965 report entitled, "Field Report-Rampart Project, Alaska-Market for TABLE 17 t Summary of Initial Evaluation of Alaska Hydroelectric Potentialities );. ·~'i:: data available. Based upon data currently available to Bureau of Reclamation and Corps of Engineers] £:, Active storage (1,000 AF) 7,500 3,200 4,900 6,600 3,800 (6) 22,200 (6) 13,800 1,800 (6) 29,000 840 53 310 6,450 (6) 5,300 4,900 142,000 9,000 39,000 I, 610 30,000 2;200 11,700 420 Range in static head (feet) 140-118 240-120 200-100 120-90 190-184 (6) 78-51 (6) 180-141 325-160 (6) 125-95 250-140 200-100 350-175 120-60 (6) 180-100 160-120 457-436 315-312 360-190 390-200 355-349 202-172 120-115 455-385 472 1200-1080 710 365-350 4, 600 130-115 Aver- age head (feet) 132 199 166 114 187 Average annual runoff (1,000 AF) 3 7, 500 35,600 34,500 35,700 3 I, 880 94 1}60,000 68 2}9, 200 49 1}2;300 166 2 11, 900 270 1 1,400 72 1109,000 114 225,000 Percent regu- lation 100 83 100 100 100 100 100 91 100 212 1826 } 166 1 4 I, 670 291 142,675 83 99 1}2, 500 59 19,500 149 17,830 146 15,800 445 181,000 313 3 9, 100 300 157,600 324 3 3, 230 352 132,400 176 14,300 114 2}4, 600 393 2 724 I, 120 326 124 2695 3870 34,600 98 97 100 100 100 8 100 84 100 90 100 96 99 100 100 Contin- uous power (1,000 kw.) 93 87 70 60 33 1,400 122 55 184 32 730 266 96 113 50 105 79 3,904 265 I, 620 83 I, 070 63 156 26 72 27 54 55 Installation at 50% load factor Firm energy (kwh. X 106) 820 760 613 526 289 12,300 I, 070 482 I, 612 282 6,400 2,330 840 Installed capacity (1,000 kw.) 186 174 140 120 66 2,800 244 110 368 64 1,460 532 { IE} 987 226 438 100 920 210 693 158 34, 200 9 5, 040 2, 320 530 14,200 9 2, 160 723 166 9, 400 2, 140 555 127 I, 370 313 224 51 630 232 473 144 53 108 Construc- tion cost (dollars per installed kilowatt 16 ) 800 I, 000 I, 200 I, 500 1,800 800 I, 400 I, 000 1,200 I, 100 400 1,500 I, 000 1,600 I, 600 I, 600 I, 500 9 200 500 9 500 800 500 I, 500 I, 100 I, 500 I, 300 I, 000 1,200 Installation at 25% load factor Installed capacity (1,000 kw.) 372 348 280 240 132 488 220 736 129 I, 060 { 2~~ } 452 200 420 316 I, 060 332 253 626 102 288 106 216 Construc- tion cost (dollars per installed kilowatt 16 ) 600 700 800 900 1,000 800 700 700 700 200 800 600 900 I, 000 900 900 300 500 300 I, 200 600 I, 000 800 700 800 TABLE 17-Continued Summary of Initial Evaluation. of Alaska Hydroeledric Potentialities-Continued Project Southcentral: Stream Major features in addition to powerplant (dam is concrete unless noted) Crescent Lake ................. Lake Fork of Crescent 2 Diversion Dams, Canal, Tunnel, River. Penstock. Chakachamna. . . . . . . . . . . . . . . . . Chakachatna River . . . . Tunnel, Penstock ............... . Coffee ........................ Beluga River .......... Dam .......................... . Upper Beluga (Beluga River) ........ do .................... do ........................ . Y entna. . . . . . . . . . . . . . . . . . . . . . . Y entna River. . . . . . . . . Dam, Earth Dike •............... Talachulitna (Shell) ............ Skwentna River ....... Dam ........................... . Skwentna (Hayes) .................. do .................... do ........................ . Lower Chulitna ............... Chulitna River ............. do ........................ . Tokichitna ......................... do ............... Dam, Earth Dikes .............. . Keetna (Talkeetna) ............ Talkeetna River.... Dam .......................... . Whiskers ..................... Susitna River .............. do ........................ . Lane ................... : .......... do .................... do ........................ . Gold .............................. do .................... do ........................ . Devil Canyon ...................... do .................... do ........................ . Watana ........................... do .................... do ........................ . Vee ............................... do ............... Dam, Earth Dike ............... . Denali ............................ do. . . . . . . . . . . . . . . Dam Earth .................... . Snow. . . . . . . . . . . . . . . . . . . . . . . . Snow River. . . . . . . . . . . Dam, Earth Dike, Tunnel, Penstock Bradley Lake ................. Bradley Creek ......... Dam, Diversion Dams, Canals, Tunnel, Penstock. Lowe (Keystone Canyon) ...... Lowe River ........... Dam .......................... . Million Dollar. . . . . . . . . . . . . . . . . Copper River . . . . . . . . . Earth Dam .................... . Cleave (Peninsula) .................. do ............... Dam .......................... . Wood Canyon ...................... do ............... Dam, Saddle Spillway ........... . Southeast: . Chilkat. . . . . . . . . . . . . . . . . . . . . . . Chilkat River . . . . . . . . . Dam, Earth Dike, Tunnel, Penstock. Lake Dorothy. . . . . . . . . . . . . . . . . Dorothy Creek . . . . . . . . Tunnel, Penstock ............... . Speel Division, Snettisham. . . . . . Speel River. . . . . . . . . . . Dam, Earth Dike, Tunnel, Penstock. Tease Creek .................. Tease Creek .......... Dam, Tunnel, Penstock .......... . Sweetheart Falls Creek ......... Sweetheart Falls Creek ...... do ........................ . Houghton .................... Unnamed ................. do ........................ . Scenery Creek ................. Scenery Creek ......... Tunnel, Pen8tock ... , .......... ·: Thomas Bay (Cascade Creek) . . . Cascade Creek ............. do ........................ . Stikine River. . . . . . . . . . . . . . . . . . Stikine River. . . . . . . . . . Dam .......................... . Goat.. . . . . . . . . . . . . . . . . . . . . . . . Goat Creek ........... Dam, Tunnel, Penstock .......... . Tyee Creek. . . . . . . . . . . . . . . . . . . Tyee Creek. . . . . . . . . . . Tunnel, Penstock ............... . Spur ......................... Unnamed ................. do ........................ . Leduc ........................ Leduc River ............... do ........................ . Rudyerd ..................... Unnamed ................. do ........................ . Punchbow!'Creek .............. Punchbowl Creek ...... Dam, Tunnel, Penstock .......... . See footnotes at end of table. 56 ----------~ -·~-- Drainage area (sq_uare miles) 200 1, I20 860 840 6,400 2, 250 950 2,600 2,560 I, 250 6,320 6,280 6, I60 5, 810 5, I80 4, I40 I, 260 84.7 87.8 I90 24,200 2I,500 20,600 I90 11 I94 II. 4 35.2 39.2 21. I I8.9 20,000 I4.0 I4.6 IO. 2 7. I 7.9 I3. 6 Maximum regulated w.s. elevation (feet) 599 I, I27 210 375 '!50 350 I,OOO 500 725 950 490 660 850 I,450 I, 905 2,355 2, 552 I, 250 I, I95 800 200 420 I,400 600 2,422 325 I, IOO 684 550 957 I, 5I4 350 I, 298 I, 387 I, 889 I, 384 I, 775 650 TABLE 17-Continued Summary of lnitia.l Evaluation of Alaska Hydroelectric Potentialities-Continued Installation at 50% Installation at 25% load factor load factor Active Range in Aver-Average Con tin-Firm storage static age annual Percent uous energy Construe-Construe- (1,000 head head runoff regu-power (kwh. Installed tion cost Installed tion cost AF) (feet) (feet) (1,000 lation (1,000 X 106) capacity (dollars capacity (dollars AF) kw.) (1,000 per (1,000 per kw.) installed kw.) installed kilowatt 16 ) kilowatt 16 ) 306 599-500 5I7 3454 98 20 I79 4I 900 82 700 I, 700 942-820 793 1 2,460 100 I83 I, 600 366 600 732 500 (6) (6) 109 2 I, 800 I8 I60 37 I, 100 73 800 I,800 I63-97 I42 2 I, 800 100 24 210 48 I, 000 96 700 2,850 100-50 82 2 4 I2, 750 } I, 390 { I45 } I, 000 { 290} 575 I50-75 I24 . 14 4, 500 79 I 59 75 I 50 700 860 350-I75 29I 14 I, 900 98 I96 (6) (6) 89 1 6, 350 45 394 90 800 I80 600 2, 700 225-112 I86 1 6, 200 85 92 806 I84 800 368 600 675 345-I73 286 2 I, 740 82 37 324 74 I, IOO I48 700 (6) (6) 59 1 7, 500 42 368 84 I, IOO I68 700 (6) (6) I69 1 7, 500 I20 I, 052 240 800 480 500 (6) (6) I89 1 7, 327 I30 I, I39 260 I, 300 520 800 (6) (6) 575 "·.~} '·~J 738} "~ { 1,476} I, 960 435-330 425 14 6, 040 478 956 100 80I 300 I, 550 450-235 430 14 4, 730 386 772 5,000 14 2, 310 354 750-550 653 2 535 97 32 278 63 I, 000 I27 700 372 1195-I04I I, I55 1445 93 47 410 94 15 600 I87 400 420 402-201 334 3 I, 400 66 29 254 58 I, IOO II6 700 (6) (6) 89 2 38,000 220 I, 927 440 I,400 880 800 (6) (6) I65 2 28,000 410 3,600 820 I, 300 I, 640 700 2I,OOO 980-905 950 1 26, 700 100 2,500 21,900 10 3, 600 14 300 335 390-I90 320 2 870 80 21 I80 4I 950 82 680 I25 2406-225I . 2,248 1 81 IOO I7 I 50 34 600 68 500 330 325-223 273 3I 275 63 800 I26 500 33 I080-986 I, 034 3 I10 75 8 70 I6 I,400 32 900 250 684-543 6I2 1 250 IOO 14 I25 29 800· 57 600 333 550-36I 457 2 370 98 I5 I36 3I 1,000 62 700 60 697-564 620 2 I47 90 8 67 I5 800 3I 500 .72 1499-I350 I,442 1 I60 88 I9 I66 38 600 76 500 26,000 350-I75 29I 3 45,000 90 I, I30 9,900 2,260 900 4,520 500 .47 1098-I040 I, 056 3 II2 90 10 87 20 I, 200 40 800 66 I372-1185 I, 275 1 I23 93 I4 120 27 600 55 500 27 I859-I670 I, 766 3 83 87 I2 I05 24 900 48 600 6I I284-1184 I, 24I 3 6I 100 7 62 I4 I, 100 28 700 6I 1675-I525 I, 600 3 63 IOO 9 83 I9 800 38 600 IOO 650-596 622 1 I26 99 7 64 I5 800 29 500 57 TABLE 17-Continued Summary of Initial E.valuation of Alaska Hydroelectric Potentialities-Continued Project Stream Southeast-Continued Major features in addition to powerplant (dam is concrete unless noted) Drainage area (sCJ,uare miles) Maximum regnlated w.s. elevation (feet) Red ......................... Red River ............ Dam, Tunnel, Penstock .......... . 44.0 28.6 36.4 23.8 400 500 326 Lake Grace ................... Grace Creek ............... do ........................ . Swan Lake (Lower Swan Lake). Falls Creek ............ Dam, Penstock ................. . Maksoutof River .............. Maksoutof River ...... Dam, Earth Dike, Tunnel, Penstock. 17 630 18 800 Deer ......................... Unnamed ............ Tunnel, Penstock ............... . 7.4 10.6 29 25,700 374 1, 040 400 2,200 Takatz Creek ................. Takatz Creek ..... ." ... Dam, Tunnel, Penstock .......... . Green Lake ................... Vodopad River ........ Dam, Penstock ................. . Yukon-Taiya ................ · .. Yukon River .......... Dam, Channels, Tunnel, Penstocks. I Streamflow records at or near site. 2 Estimated from streamflow records for similar drainages. a Estimated from basin precipitation records and judgment. 4 Calculated from area maps. 5 Operating as a system. 6 Reservoir held essentially full for operation with upstream plants. 7 Estimated reservoir yield after allowing 1,500 cfs release from Hootalinqua Reservoir. 8 Operated in conjunction with downstream storage. 9 Based on 75 percent load factor. '0 Based on 69.4 percent load factor. 11 Exclusive of Fish and Wildlife mitigation costs, unless otherwise noted. Power and Effect of Project on Natural Resources," and its June 1967 report entitled, "Alaska Natural Resources and the Rampart Project." As presented in the latter report, the projects which appear to be more attractive, economically, include Wood Can- yon on Copper River; Yukon-Taiya near Skagway; Holy Cross, Woodchopper, and Ruby on the Yukon River; Crooked Creek on Kuskokwim, and Upper Susitna River. The list includes the Denali, Vee, Watna, and Devil Canyon units. Of these projects, the Yukon-Taiya project is currently receiving con- sideration by the United States and Canada for possible joint study as an international develop- ment. This project would involve regulation of the flows of the upper Yukon River in Canada and diversion of those flows to a powerplant in the United States near Skagway in Southeastern Alaska. The Alaska Power Administration has recently 58 completed feasibility studies and reports on the Lake Grace and Takatz Creek projects in the SoutheaSt- ern Region. The feasibility reports show the projects to be economically justified and financially feasible, but authorization of their construction was not re- quested because of the high per kilowatt investment costs of the projects and the possibility of develop- ment of diesel alternatives with somewhat. higher annual power costs. A proposal which would divert Alaska waters through British Columbia, eastward to the Great Lakes and Hudson Bay, and south through the arid western United States into Mexico, was advanced by the Ralph M. Parsons Co. in 1964 as the North American Water and Power Alliance. The NAWAPA plan includes major storage projects on the Tanana, Susitna, and Copper Rivers in Alaska. Considering all of the pertinent factors, it appears 12 Includes fish and wildlife mitigation measures. 13 DiversionofYukon-Taiya flow from Yukon River would reduce continuous power at downstream sites, by the following amounts: (I) Woodchopper 380,000 kw (2) Rampart 610,000 kw (3) Ruby 90,000 kw (4) Holy Cross 120,000 kw (5) Un- evaluated amounts in other reaches of the Yukon River. 14 Department of Interior Rampart Project January 1965 Field Report (table 59). 15 House Document No. 455, 87th Congress, 2d Session, cost estimate indexed to October 1965 prices plus additional powerplant and diversion costs for plan revisions. 16 Rounded to nearest $100. 17 Maksoutof. 18 Khvostof. that the NAWAPA, or any other similar alternative plan, lies in the more distant future, beyond the period covered by this Survey. Trends in Ownership of Hydroelectric Plants Many of the early hydroelectric developments in Alaska provided energy for mining or cannery op- erations and were constructed with private capital. The development of electric service for public use was usually the result of community action. Most of the utility distribution systems are municipally owned and thegenerating facilities were developed by the municipalities. New hydroelectric plants have been constructed mainly with public financing, Fed- eral or non-Federal. As a result, the percentage of privately financed hydroelectric generation has de- clined. Public ownership accounted for only 41 per- 59 cent of the installed capacity in 1950. In 1965, the public share had increased to 79 percent of which the Federal Eklutna project alone accounted for 46 percent. Evaluation and Use of Hydroelectric Capacity Hydroelectric power is unique in that it does not require fuel for the generation of energy, but de- pends on the renewable energy resource provided by the recurring hydrologic cycle of rainfall, runoff, evaporation, and transpiration. Since hydropower depends on the hydrologic cycle, the amount of generation varies from year to. year. Hydroelectric plants are also relatively expensive to build, since massive structures or long pipelines, or both, are required to create or utilize head and regulate the flow of water to the generating machinery. Since plant sites are frequently remote from load centers, expensive transmission facilities are often a major cost factor. In comparis on with thermal-electric plants, hy- droelectric projects have several distinct advantages. They do not consume or heat the water they use, and they do not contribute to air pollution. Main- tenance costs are relatively lo w, and it is possible to design the plants for virtuall y complete automatic or remote-control operation. Since they have long life, depreciation charges are low, and future costs are relatively predictable. Generating units are more reliable than steam-electric equivalents because they operate at relatively lo w speeds and are not sub- ject to severe temperature stresses . Outage rates for hydroelectric units are normally about one-fourth those of modern steam-electric machines. Hydroelectric development frequently provides opportunities for other related benefits, such as flood control, water supply, recreation, water-quality control, fish and wildlife enhancement, and cooling water for steam-electric and industrial plants. Multi- purpose uses make possible developments which would be uneconomic for single-purpose hydro- power development. The 15,000-kilowatt Cooper Lake hydroele.ctric plant of the Chugach Electric Association is located in the cen- tral section of the Kenai Peninsula. Capacity to be installed at hydroelectric projects is judged on the basis of head and streamflow. Mini- mum flows are estimated statistically from historical records. Installations are often increased by con- struction of storage reservoirs. From the standpoint 60 of power requirements, installations may also be sized on the basis of kilowatt-hours of energy to ac- company kilowatts of capacity. Most projects operating in Alaska have been de- veloped to serve specific loads. Some were planned to serve hydraulic mining loads and were intended to operate only during the summer months. Others were constructed to serve small cannery operations, while the A. J. Industries plants were built to pro- vide power for a very large underground mining and refining operation. Plants built to provide utility service were usually sized to operate at the annual load factor of the system to be served. In recent years, hydroelectric generation has been supplemer1ted, and in some instances replaced, by other types of generation, and the operation of the hydroelectric plant has been changed to conform to the needs of the owner. Thus, some plants with- out water storage now operate more or less con- tinuously using the available water so as to reduce the amount of fuel burned in other plants. Others with storage available to regulate flows are operated to supply system peakloads as well as to reduce fuel use. In Alaska, with an abundant supply of low-cost natural gas near the major load centers, the chief role of many hydroelectric plants may well be to serve peakloads. However, some of the larger hydro projects may be consi dered favorably in later years when greatly expanded loads must be served. Projected Hydroelectric Developments An appraisal of the undeveloped powersites in Alaska was made for purposes of this survey by a committee which included representatives of the Corps of Engineers, Alaska Power Administration, and Alaska Department of Natural Resources. From a list of some 700 sites which were screened by quick approximation of construction require- ments and power potential, some 245 locations were found to be worthy of further investigation. Water supply, power production, and cost estimates were made for each of the 245 sites to determine probable costs of firm energy. This further appraisal reduced the number of sites which appear to offer the best p~tential for development to the 76 sites listed by areas in table 1 7 and shown on the hydroelectric map, figure 7. This group of potential plants range widely in capacity from as little as 7,000 kilowatts to as much as 5,040,000 kilowatts; estimated costs range from $200 to $1,800 per kilowatt of installed capacity, assuming installations designed to operate at 50 per- cent annual plant factor or greater. Summary and Conclusions Hydroelectric projects have many favorable char- acteristics which warrant strong consideration of the many potential sites in Alaska. These plants have very long lives and low operation and mainte- nance costs, use a renewable resource, permit regulation of streamflows to enhance conditions :(pr fish and wildlife, offer possibilities for recreational development, and· provide flood control. They oper- ate at relatively slow speeds, respond quickly to changing power requirements, and have a high degree of reliability. Some sites are suitable for the development of pumped storage and for the production of low plant factor peaking power. Such service would ap- pear to be particularly appropriate for projects 61 located near the railbelt which could be connected to a transmission network serving the Anchorage load area or the interconnected load areas of An- chorage and Fairbanks, and supply relatively short- term daily and seasonal peak load demands in coordination with baseloaded thermal-electric plants. Investment costs for hydroelectric projects in Alaska are relatively high. It is reasonable to expect that most of the hydroelectric projects that may be developed in the future will be for multipurpose use and that the larger projects will be Federally financed. A few of the more favorably located smaller sites may be found attractive for develop- ment by private, cooperative, or municipal systems. Development of. more of the major sites may be economical when powerloads have expanded suffi- ciently to utilize the potential output of such installations. B E R S E A I'; A CHUKCHI SEA N G R C o' F i gure 7 62 T I C . . \ S ~ I s r o l.. 8 • r P A C F 0 c E A GULF c N SEA OF ALASKA 0 C E A N FEDERAL POWER COMMISSION ALASKA POWER SURVEY HYDROELECTRIC PROJECTS EXISTING AND POTENTIAL SCA.tf. I~ MILES !;___, ___ , __ ~-_:.._-----;'·<, LEGEND ---REGIONAL BOUNDI,RY HIGHWAYS AND ROADS ~-~ STATE HIGHWAYS RAilROAD )' US AiR fORCE BASE • EXISTING. HYDROELECTRIC POWER PLANTS o POTENTIAL HYDROELECTRICTRIC .. KEY GAGING STATION (4137) f.P .C. PROJECT NUMBERS POWER PLAN TS WITH LESS THAN !OOKW CAPACITY ARE HOT SHOWN 63 .f'·, LEGEND TRANSMISSION LINES• ...... ----11--- • STATION 9 115 KV 69 KV 34 KV 24.9 KV or Less (os Shown) CONNECTION BETWEEN UTILITIES CONNECTING LINES '" SUBSTATION OF ALASKA ANCHORAGE AREA SCALE IN MILES 0 25 50 INTERCONNECTED ELECTRIC UTILITY SYSTEMS AND TRANSMISSION TIE LINES 1965 ALASKA KEY MAP SCALE IN MILES 0 100 200 JUNEAU AREA SCALE IN MILES 9 2 10 Figure 8 66 0) ..... TABLE 18 Interconnections Between Utilities and Major Nonutility Installations, 1965 Principal generating utility Name Utilities and nonutilities which maintain direct connections: Consolidated Utilities, Ltd. Chugach Electric Association Inc. Do ............... Do ............... Do ............... Anchorage Municipal Light and Power Department. Eklutna, USBR ........ Utilities and nonutilities for which common terminals are available but direct connections are not maintained: Chugach Electric Association Inc. Do ............... Eklutna Project, USBR. Anchorage Municipal Light and Power Department. Do ............... Generat- ing ca- pacity (kw.) 2, 654 69,400 69,400 69,400 69,400 36,769 30,000 69,400 69,400 30,000 36,769 36, 769 Other utilities and nonutilities Name Generat- ing ca- pacity (kw.) Location of terminal SOUTHCENTRAL REGION Kenai City Light ............. 0 Consolidated Utility Plant Substation. Eklutna Project, USBR ....... 30,000 USBR Anchorage Sub- station. City of Seward .............. 3,000 C.L.A. Daves Creek Sub- station-Seward line at Lawing. Homer Electric Association 0 Kasilof Substation ......... Inc. Alaska Railroad ............. 4 Whittier near Portage Substation. Ek!utna Project, USBR ....... 30,000 USBR Anchorage Sub- station. Matanuska Electric Associa-0 {USBR Palmer substation ... tion Inc. M.E.A.fUSBR Reed sub- station. Anchorage Municipal Light 36, 796 USBR Anchorage Substation and Power Department. Elmendorf Air Force Base ..... 24, 100 . .... do ................... . ... do ..................... 24, 100 . . . . . do ................... ... . . . do ..................... 24, 100 ..... do ................... Chugach Electric Association 69,400 ..... do ................... Inc. Interconnection details Bus-tie line voltage (kw.) 2. 4/33.0 34.5 24.9 69.0 12.5 34.5 12.5 34.5/12. 5 34.5 34.5 34.5 34.5 34.5 Capacity ter- minal, line, or substation (kva.) (Sub) 3, 700 ..... (Lines) 40,000 ... (Sub) 3,000 ..... I (Sub) 3,750 ..... (Sub) 2,500 ..... (Line) 20,000 ... Purpose of installation Firm power delivery to Kenai City. Interchange firm and nonfirm. Firm power delivery to Seward. Firm power delivery to Homer. Nonfirm power receipt from Alaska Railroad. Firm power receipt from USBR. (Sub) 5,000 ..... tirm power deliver~ to (Sub) 1 500 ..... Mata?u~ka Electnc ' Assoc1at10n. Switching ....... Emergency. . .... do ......... Do. (Line) 20,000 ... Do . Switching ....... Do. ..... do ......... Do. TABLE 18-Continued Interconnections Between Utilities and Major Nonutility Installations, 1965-Continued Principal generating utility Other utilities and nonutilities .Name Utilities and nonutilities which maintain direct connections: Generat- ing ca- pacity (kw.) Name Generat- ing ca. pacity (kw) Location of terminal INTERIOR REGION Golden Valley Electric 21,245 Chatanika Power Co......... 5, 625 Cleary Summit Substation .. Association Inc. Do ............... 21,245 University of Alaska......... 3, 000 University Substation through Sheep Creek breaker. Do ............... 21,245 Fort Wainwright-Army ...... 22,000 Fort Wainwright Substation. Do ............... 21, 245 Fort Greely-Army. . . . . . . . . . 5, 000 Through Highway Park Do ............... 21,245 Murphy Dome-Air Force Base. Substation. I, 160 Near University Substation through Sheep Creek breaker. Do ............... 21, 245 Eielson-Air Force Base...... 9, 000 Eielson Substation ........ . Fairbanks Municipal 15,500 Fort Wainwright-Army ...... 22,000 Fairbanks 19th St. Sub- Utilities System. station. Utilities and nonutilities for which common terminals are available but direct connections are not maintained: None (Golden Valley and Fairbanks 'not directly intercon- nected). Interconnection details Bus-tie line voltage (kw.) 34.5 34.5 69.0 69.0 34.5 69.0 12.5 Capacity ter- minal, line, or substation (kva.) (Sub) 4,500 ..... (Sub) 7,500 ..... (Sub) 7,500 (Sub) 2,500 ..... (Sub) 1,000 ..... (Sub) 5,000 ..... (Sub) 7,500 ...... Purpose of installation Nonfirm wholesale receipt from Chatanika. Nonfirm wholesale receipt from University. Nonfirm transfers. Do. Do. Do. N onfirm emergency standby from fort. ------------------------------------------==---=~=~-~--~~-------------- Utilities and nonutilities which maintain direct connections: Alaska Electric Light and 8, 686 Glacier Highway Electric Power Co. Association. SOUTHEAST REGION 0 Juneau Mile 11 Glacier High- way and Upper Men- denhall River Bridge on Loop Road. Do............... 8, 686 Alaska-Juneau Industries ..... 8, 400 Various ................. . Sitka Public Utilities .... Ketchikan Public Utilities None 7,300 10, 673 HEW (Japonski Island Hos- pital) 3,000 kw. (S); Sitka Cold Storage, 250 kw. (D); Pioneer Nome, 50 kw. (D); Sheldon Jackson School, 75 kw. (H); Alaska Lumber and Pulp Mill, Inc., 15,000 kw. Ketchikan Spruce Mills, 900 kw.; Ketchikan Pulp Mill, 20,750 kw.; New England Fish Co., and miscellaneous other canneries and cold storage plants. NORTHWEST AND SOUTHWEST REGIONS 22.0 (Sub) 1,050 ..... Firm power delivery to Glacier Highway Electric Association. 22. 0 Line. . . . . . . . . . . Firm power receipt from Alaska-] uneau (6,700 kw.). Emergency interchange and dump power. Emergency interchange and dump power. ···-~ A typical corner structure element placed by helicopter on the Golden Valley Electric Association's 138-kilovolt transmission line between Healy and Fairbanks. There are many precedents elsewhere in the United States of coordination agreements, joint ventures, and other types of cooperative efforts among private, public, municipal, and industrial utility interest which operate to the mutual advan- tage of all concerned. Similar types of arrangements would seem to offer potential benefits for a number of the Alaska utilities. Some examples of joint ven- tures and coordinating arrangements now in opera- tion are listed below: A joint venture in which one State-owned and five investor-owned utilities have undivided in- terests in two 750-megawatt steam generating units in the Four Corners plant near Farmington, N. Mex. The ownership, by participants, is South- ern California Edison Co., 48 percent; Arizona Public Service Co., 15 percent; Public Service Co. of New Mexico, 13 percent; Salt River Project 70 (a publicly owned system), 10 percent; Tucson Gas & Electric Co., 7 percent; and El Paso Elec- tric Co., 7 percent. A similar joint venture in which two investor- owned utilities, two municipal-, and one State- owned system will have undivided interests in two 750-megawatt units now under construction at the Mohave plant in southern Nevada. Percent ownership will be: Southern California Edison Co., 50 percent; Los Angeles Department of Wa- ter and Power, 20 percent; Nevada Power Co., 16 percent; Salt River project, 10 percent; and Glendale Public Service Department, 4 percent. An agreement under which the Rushmore Electric Power Cooperative, Inc., owns a gen- erating unit in the Osage plant of the Black Hills Power & Light Co. The unit is leased to, and operated by, Black Hills. A contract under which two 615-megawatt units were constructed and are being operated by Ohio Power Co. at the Cardinal plant. Own- ership of one of the units was transferred to Buckeye Rural Electric Cooperative, Inc., upon completion. Buckeye financing in this instance came from the open market. An arrangement between the Garden City, Kansas Municipal Utilities, and the Wheatland Electric Cooperative, Inc., whereby the munici- pal generating plant is interconnected with and operated by the Cooperative. A joint venture in which the Duane Arnold 538-megawatt nuclear plant near Cedar Rapids, Iowa, will be owned by one investor-owned util- ity and two cooperatives. Ownership is: Iowa Electric Light & Power Co., 80 percent; Central Iowa Power Cooperative, 10 percent ; and Corn- belt Power Cooperative, 10 percent. There are numerous examples of coordinated construction of transmission lines. Generally, each utility constructs, owns, and operates the section of the line in its own service area. If connection costs are not reasonably in balance with use of the line by individual utilities, equalizing pay- ments are made. ¥any power-pool agreements encompass dif- ferent ownership segments in a single-pool agree- ment. A fe w examples include: The Texas Municipal Power Pool which in- cludes the cities of Bryan, Garland, and Green- ville, Tex., and the Brazos Electric Power Co- operative, Inc. I ! il It An upper Michigan group composed of the cities of Grand Haven and Traverse City, the Northern Michigan Electric Cooperative, Inc., and the Wolverine Electric Cooperative, Inc. A Louisiana group composed of the city of Lafayette Utilities System, the Louisiana Rural Electric Corp., and the Dow Chemical Co. The Missouri Basin Systems group which in- cludes a large number of organizations under Federal, municipal, and cooperative ownershjp. Within the period of development covered by the Survey, many of the small scattered utilities are un- likely, to find economic ways to join even with their closest neighbors because of problems of intervening terrain, water, weather, and distance. An appraisal has been made, however, of the possibilities for in·· terconnections between utilities and villages most likely to be benefited. Interties, other than those required to interconnect the Anchorage-Kenai and Fairbanks load centers, likely would be at voltages lower than 115,000. A system using single-phase, single-conductor with earth return, at 79,000 volts has been suggested to provide electric service to small communities in the outlying Fairbanks area. Underground direct-current cable has also been suggested for some areas. The Rural Electrification Administration (REA) has recently allocated $5 million for beginning a project to supply electric power to some of the larger native villages, generally with populations in excess of 200, which do not have electric service. Most of the villages are widely separated and are not in position to be interconnected. The Alaska Village Electric Cooperative was originated in 1967 as a statewide REA borrower to serve these scat- tered villages. It is contemplated that power would be supplied by diesel-electric generating units which could be flown into a central repair shop for necessary servicing and maintenance. Construction and maintenance would be handled by a small cen- tralized staff using native workers. Day-to-day serv- icing and maintenance of underground distribution c facilities would be performed by an on-the-job trained resident of the village on a part-time basis. At best, the cost of electric service will be high, tentatively projected to be in the range of 15 cents per kilowatt-hour for residential service and 10 cents per kilowatt-hour for small commercial service: Planning by Regions The following sections discuss the various regions of Alaska in terms of present electric power facili- 71 ties, potential for growth, and suggestions for fu- ture development. Southcentral Region Load Distribution In 1965, the nonmilitary population of the South- central Region was estimated to be 108,000, making up 60 percent of the nonmilitary population for the entire State. The principal concentration of popu- lation and industry in this area is in the Kenai Pe- ninsula, the greater Anchorage area, and the Matanuska Valley. · The discovery of oil and gas in the Cook Inlet area, the construction of an oil refinery and petro- chemical plant, and the prospects of a liquified gas market portend, by far, the largest economic evolu- tions in Alaska's history. This exploration and ac- companying production activity has resulted in an unprecedented load growth in the Kenai Peninsula and greater Anchorage areas. The loads of the Homer Electric Association have grown from a peak of 450 kilowatts in 1956 to nearly 5,000 kilowatts in 1965, for an average annual growth of 31 percent. The Chugach Electric Association and the Anchor- age Municipal Light & Power systems have also enjoyed very substantial load growths. Their com- bined loads in 1956 totaled 28,800 kilowatts; their 1965 total was approximately 82,000 kilowatts. The load growth in the Matanuska Valley area, served by the Matanuska Electric Association (MEA), has also been exceptional, although not as steady as in ~the Kenai Peninsula or greater Anchorage areas. The MEA load in 1965 was 7,900 kilowatts. In addition to the loads of the four major utilities mentioned above, there are smaller isolated loads served by the Cordova Public Utility, Seward Elec- tric System, Copper Valley Electric Association of Glena1len and Valdez, and the Kodiak Electric Association. Existing Interconnected Operations and Power Pools Existing system interconnections in Southcentral Alaska are, at present, maintained for the purpose of mutual assistance in times of emergency, rather than for broadly planned pooling benefits. In the past, Alaskans have been inclined to ac- cept power interruptions as something to be ex- pected and tolerated as a way of life in the far north. If service was restored within an hour or so, there was little, if any, complaining. Now, however, as in the lower States, electricity has become a com- modity in which great dependence is placed on a minute-by-minute basis, and generation and trans- mission reliability must be emphasized in planning system additions. The utilities in Southcentral Alaska are especial- ly cognizant of the need for an organized power pool, not only for the purpose of improving overall relia- bility, but also to enable them to obtain energy at the lowest possible cost. Much cooperation and detailed study in the midst of rapidly growing power systems is required to set up areawide scheduling of power sources in order that full advantage may be taken of the inherent characteristics of the various types of prime movers and fuels available. Present Generating and Transmission Facilities Appendix A lists , by location and total installed 1965 capacities, the various utilities serving South- central Alaska. Through initial necessity, individual systems have grown in increments of relatively small generating units. Even at this time, units in the 15- megawatt class are still the largest sizes being in- stalled. This practice results in high-basic generat- ing costs. Many of these existing small package- type units will continue to serve a useful role as a source of peaking and standby capacity even after large ( 100 megawatts and up) steam or hydro units come into operation. There is presently only one backbone transmis- sion system in operation in Southcentral Alaska. This is the interconnected 115-kilovolt line of the Alaska Power Administration (APA), serving Pal- mer and Anchorage, and the Chugach Electric Association's line from Anchorage to its Cooper Lake hydroelectric project. Possible Programs of Development by 1975 and 1985 The Chugach Electric Association ( CEA ) in early 1968 completed and placed in service a 138- kilovolt transmission line which will transmit power from its new 32-megawatt well-head gas -turbine powerplant in the Beluga gas fields . This line crosses the Knik Arm from near Point McKenzie to An- chorage via submarine cables. The line continues overhead to the Chugach Electric's International substation to provide an interconnection with Cooper Lake and the APA Eklutna hydroplant. The CEA's Beluga plant constitutes the largest ex- pansion of generating facilities under construction in the region at the present time. The initial installa- tion is two 16,000-kilowatt gas turbines with gas commitments for an ultimate 125-megawatt capac- 72 This 8,850-kilowatt Bernice Lake gas-turbine generating plant on the Chugach Electric Association System is located on the western side of the Kenai Peninsula. ity. Expansion of generation at Beluga should con- sider gas-fired steamplants with their lower produc- tion costs. The Anchorage Municipal Light & Power System installed a third 16-megawatt gas turbine during the fall of 1968. There are also plans to add a 22- megawatt steamplant by 1975 which would utilize waste heat from the turbine units. The Bradley Lake Hydro project on the Kenai Peninsula was authorized in 1962 for Federal con- struction. However, funds have not been provided to date. New hydrology data suggest that bus-bar generation costs can be reduced. Generation from the Bradley Lake project can be attractive, par- ticularly for peaking purposes. Consideration is being given to a 25-percent load factor, 187-mega- watt plant design. The above plants are essentially peaking-type in- stallations and because of their small size do little to produce low-cost, baseload energy required to meet projected powerloads. Large low-cost genera- tion sources must be developed if there is to be a reduction in rates and improvement in reliability of service to the ultimate consumer. In order to justify the initial investment in these larger baseload generating plants, this study suggests that large, well-head gas-fired central steamplants be built near the Kenai and Beluga gas fields and that interconnections with Interior Alaska be con- sidered for the purpose of absorbing the surplus energy and augmenting plant reserves, while at the same time making lower cost energy available in the Fairbanks area. Reinforcement of the present interconnection be- tween Homer, Kenai, Seward, Anchorage, and the Matanuska Valley is necessary. The addition of a 230-kilovolt tie between the Kenai Peninsula and Anchorage and a 115-kilovolt line to Palmer will be necessary to meet systemwide reliability and elec- trical stability under assumed 1985 loads. The Copper Valley Electric Association is study- ing an intertie between Valdez and Glenallen. This system will ultimately (beyond this study peri<?_d) tie into the railbelt system at Palmer or at the Susitna River power complex. Summary of Southcentral Region With practically unlimited gas reserves in the Cook Inlet area and attractive hydro sites on the Kenai Peninsula and on the Upper Susitna River, every effort should be made to take full advantage of these natural resources. To do so requires that the thermal generation be accomplished with the largest central station gas-fired steam units that an~ ticipated loads will justify. Once this baseload en- ergy resource is established, the most attractive hydro sites should be fully explored as a source of low-cost peaking capacity for coordinated operation with a gas-fired unit. With the development of these energy resources, the operating utilities and other entities have an obligation to unify their individual efforts through joint planning of transmission systems and inter- connections to establish a basis for the pooling of these resources and facilities for the maximum bene- fit of the ultimate consumer. Southcentral Alaska utilities are in a most favorable position to make substantial contributions to the overall economy of a large segment of the State of Alaska. Interior Region Load Distribution The Interior Region is characterized by concen- tration of population, commerce, and Federal facil- ities along the main transportation route following 'the Tanana and Nenana Rivers. The principal population center is the city of Fairbanks. Much smaller concentrations occur along the transpor- tation belt in the small cities of Delta Junction, North Pole, Nenana, and Healy. The principal Fed- eral installations include Fort Greely, Eielson Air Force Base, Fort Wainwright, Clear Air Force Base, and McKinley National Park. North of this main transportation belt are numerous very small military 73 and FAA installations. With very few exceptions, central station electric service is not available in these outlying communities. Small isolated diesel generating units, at or near the loads, provide essen- tial electricity. The concentration of population and commerce in the immediate vicinity of the city of Fairbanks means, of course, that the use of electricity is also concentrated in this same area. It is expected that, over the period of this study, electrical loads will continue to grow at a rapid rate, but with no sig- nificant change from the basic pattern of concen- tration in the vicinity of Fairbanks and scattered distribution along the transportation route. Two peculiarities of the Interior Region may have considerable effect on the development of the Re- gion's electric systems. The present utilities in this Region were established in the early 1950's. Conse- quently, the military bases and industries established before 1950 (and in some instances, much later than 1950) of necessity had to provide their own generating facilities. The larger complexes utilized coal for fuel and extraction steam for space heating. Coal is still the lowest cost source of thermal energy for space heating. However, the utilities are making rapid progress in reducing the price of electricity, and it is conceivable that before long, electricity may replace coal as the principal source of thermal energy, even for the relatively large military and industrial installations. Local climatic conditions result in the production of ice fog from combustion products during many days of the winter, and public recognition of the undesirable results could bring about the substitu- tion of electricity for onsite combustion somewhat in advance of the dictates of pure economics. The Fairbanks public has become familiar with ice fog and the University of Alaska has been conducting research studies on the problem. Perhaps the ice fog situation, coupled with a promotional rate struc- ture and the decision of many residents to move to higher ground after the 1967 flood, accounts for the fact that Fairbanks already has 400 electrically heated homes. Operating Utilities Appendix A lists the principal operating utilities in the Region. In addition, very small electric utili- ties certified by the Alaska Public Service Commis- sion are in operation at Tok, Fort Yukon, Hughes, Manley Hot Springs, Northway, Lake Minchu- mina, Dot Lake, and Rampart. The Fairbanks Municipal Utilities System gen- erally serves the city of Fairbanks, and the Golden Valley Electric Association, Inc., provides electric service in the suburbs, such as College, where the University of Alaska is a major power purchaser. Golden Valley also operates an extensive subtrans- mission system to connect with military bases, and serves outlying communities, such as Delta Junc- tion, Nenana, and Healy. Existing Interconnected Operation and Power Pools The two utilities, Fairbanks Municipal and Golden Valley, have since their inception, been in- terconnected by ties of n;latively small capacity. In recent years, the previously isolated military instal- lations of Fort Wainwright, Eielson Air Force Base, and Fort Greely have been interconnected through the subtransmission and distribution facilities of Golden Valley. The principal use of this military interconnection has been to wheel energy from Fort Wainwright to the other military installations. There are no true power pools at present though rapid progress is being made toward the establish- ment of a Fairbanks pool. Present Generating and Transmission Facilities Present generating and transmission facilities, by ownership, are as follows: Fairbanks Municipal ........ . Golden Valley Electric ...... . Fort Wainwright. ........... . Eielson Air Force Base ....... . Fort Greely ............. . Clear Air Force Base ........ . University of Alaska ..... . GVEA .... 8.5 mw. steam, 7.0 mw. I. C. 22.0 mw. steam, 9.5 mw. steam,! 11.7 mw. I.C. 22.0 mw. steam. 9.0 mw. steam. 5.0 mw. I.C. 22.5 mw. steam. 3 .0 mw. steam. 69-kv. subtransmission Fairbanks to Eielson Air Force Base via Fort Wainwright, 138- kv. Healy to Fairbanks. I Used as reserve and scheduled for early retirement. Possible Programs for Development by 1975 and 1985 Assuming that the Interior Region remains iso- lated electrically from the rest of Alaska, as is now the case, the best known source of additional elec- trical e nergy through 1985 appears to be mine- mouth coal-fired steamplants at Healy. By 1975 , there should be 110 megawatts of installed capacity 74 I I / Typical tangent structure with conductors in stringing sheaves on the Golden Valley Electric Association, Inc. 138-kilo v olt transmission line from Healy Generating Plant to Fairbanks. at the Healy Power Plant. Energy will be trans- mitted to the load center at Fairbanks by two 138- kilovolt transmission lines. Standby and peaking capacity will be furnished by diesel and gas-turbine units. By 1985 steam capacity at Healy will need to be increased to about 220 megawatts and the transmission facilities to the Fairbanks load center will include three ( 138-and /or 230-kilovolt ) trans- mission lines. By this time, the principal secondary load centers and Federal installations should be interconnected with the facilities of the utilities by 138-and 69-kilovolt subtransmission lines. It appears desirable and possible, however, for a 230-kilovolt transmission interconnection to be con- structed between the Interior Region and the South- central Region by 1975. In all probability, major generating facilities for both regions, when op- erated on a coordinated basis, will be located in the Southcentral Region. In this event, total installed steam capacity at Healy in the Interior Region would probably be limited to about 66 megawatts. It is possible that by 1985, 230-kilovolt transmission lines linking the two regions wiil be over two routes, one the direct route along the railroad between Healy and Anchorage and the other through Delta Junction and Glennallen to Anchorage. A preliminary examination of the possibility of providing electric service to the following small scattered communities near Fairbanks has been considered. Assumed load for study- Community kilowatts Manley Hot Springs-Baker. . . . . . . . . . . . . . . . . . . . . . 600 Tanana ..................................... . Livengood ................................... . Rampart .................................... . Stevens ...................................... . I, 800 600 400 800 Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4, 200 The proposed service consists of single-phase, single-conductor, earth return, 79-kilovolt (L-G) tap lines from the existing Healy-Fairbanks 138- kilovolt transmission line (as indicated on fig. 9) via the following routes: Distance Route No. I: in miles Nenana (tap) Zitziana River (junction)... . . . . 50 Zitziana River-Manley Hot Springs, Baker. . . . I8 Zitziana River-Tanana..................... 57 Route No.2: Fairbanks (tap)-Livengood......... . . . . . . . . . 62 Livengood-Fish Creek· (junction). . . . . . . . . . . . . 20 Fish Creek-Stevens.......... . . . . . . . . . . . . . . . 24 Fish Creek-Rampart....................... 38 Total routes I and 2. . . . . . . . . . . . . . . . . . . . . 269 Line construction and equipment capital costs are estimated to be : 1. Single-pole, single-conductor (Penguin), pole- top, station post-type insulator, ~-inch ice loading, 22-foot ground clearance, 6% struc- tures per mile at $6,930 per mile. 2. Single-phase, 79-kilovolt/4.2-kilovolt (or other convenient distribution voltages) 1,000-kilo- Figure 9 PROPOSED 79 KV SINGLE PHASE SERVICE TO REMOTE VILLAGES volt-ampere transformer at $10 per kilovolt- ampere. 3. Single-pole, 79-kilovolt, 3-megavolt-ampere load-break disconnect switches at $15,000. 4. Cost of miscellaneous facilities, such as relay- ing, land acquisition, surveying, etc., at $2,500 per load terminal. 5. Some phase-balancing equipment may be needed on the three-phase system from which these small single-phase loads are to be served, but the cost has not been estimated. All of the above-cost estimates include an "Alaska factor" of 1.4. The capital investment and annual costs for the above routes were estimated to be: Assumed Dollars per Dollars per Investment Annual cost I load-kilowatt kilowatt Route No. I .................................... . Route No.2 .................................... . Total ................................. ··.· $9I6, 000 I, 060,000 I, 976,000 I Assumes Rural Electrification Administration financing. 75 $57, 940 67, I50 I25, GOO kilowatts per year 2,400 I, 800 4,200 382 589 470 24. I5 37.30 29.80 ~~ ' ·' Regulation and losses are summarized below: Route No.1 ... . Route No.2 ... . Percent regulation at end of line for 0.9 power factor load 2.4 at Tanana ... . 3.1 at Stevens ........ . Peak losses (kilo- watts) 15.4 24. 8 An interesting alternate plan of service (which has been suggested but not examined ) is 15-kilovolt d.c. underground cable or overhead line with earth return. Summary for the Interior Region Plans for isolated development of electrical facili- ties in the Interior Region have been exhaustively studied by operating utilities. Coal-fired steam gen- eration at Healy, backed up by internal combustion standby and peaking units at the load centers, is recognized as the most feasible and economical method of providing lo cal generation for the Im- mediate future. There are two fields of study that deserve Im- mediate and concentrated attention. One is the transmission interconnection between the Interior and Southcentral Regions and the installation of large, low-cost gas -fired steamplants to achieve the economic benefits available to both regions. The other is finding a practical means of providing elec- tric service to the relatively small and dispersed set- tlements in the northern portion of the Interior Region, such as the 79-kilovolt single-phase, ground- return transmission scheme discussed above . Southeast Region The southeastern Alaska coastal region is a very rugged area with peaks on the mainland and islands rising to an elevation of 5,000 to 10,000 feet in just a short distance from tidewater. A tremendous ice- cap is located near the international boundary about 40 miles inland and parallels the Region for most of its length. This icecap feeds many glaciers and fjords. Bays and inlets indent all coastlines result- ing in difficult and expensive roadway and trans- mission system construction and maintenance. The coastline climate of the Region is mild. Rain- fall is heavy with typical annual averages of 152 inches at Ketchikan and 90 inches at Juneau. Dense forests with heavy undergrowth extend up to an elevation of about 2,500 feet. The more level areas · 76 are often poorly drained, resulting in bogs of mus- keg interspersed among timber stands. Load Distribution Major load centers of southeast Alaska that might be served by interconnected power systems by 1985 include Juneau-Sitka, Petersburg-Wrangell-Kake, and Ketchikan-Metlakatla areas. Distances and ter- rain preclude system interties at this time with other load centers within this Region . Construction of a large pulp mill somewhere in southeastern Alaska is a requirement under the terms of a timber sale involving an ultimate 8.75 billion board feet of timber. Historically, sawmills and pulp mills in Alaska generally produce their own power, either with diesel units or steam turbines fired with waste products. This is particularly true of the pulp mills which, in addition to chips, also have waste process liquors for fuel. The two dis- solving pulp mills in southeast Alaska generate ap- proximately 258 million kilowatt-hours and pur- chase only about 6 million kilowatt-hours annually. The mill and logging operations associated with a new pulp mill are expected to employ approximately 1,000 persons. A population increase of this magni- tude, together with supporting facilities, might in- crease the power requirements by 16,300,000 kilo-. watt-hours per year with a peak increase of 3,400 kilowatts in 1975. Total Southeastern Alaska Region Year 1965 .................. . 1975 l 1985 l Energy kilowatt- hours 147, 741, 000 355,000,000 841, 000, 000 Noncoinci- dental peak kilowatts 32,200 74, 800 174,900 1 Includes new pulp mill-related requirements. Existing Interconnected Operation and Power Pools The Juneau-Douglas area, consisting of the cities of Juneau and Douglas and surrounding rural area, is presently served by the Alaska Electric Light & Power Co. and the Glacier Highway Electric Asso - ciation, with power supplied from the intercon- nected plants of AEL&P and the Alaska-Juneau Mining Co. The A-J company wholesales all power produced to the AEL~P. The Glacier Highway Electric Assoc. is presently a wholesale customer of the AEL&P company but will become a preference r I I customer of the Alaska Power Administration (APA) upon completion of the Snettisham project. Present Generation and Transmission Facilities The Juneau-Douglas area, as mentioned above, is served by the AEL&P with power produced by A-J company in addition to its own facilities. A-J owns and operates three hydroelectric plants in the Juneau area. Each plant has two 1,400-kilowatt units. Thesethree plants were constructed in 1915 to supply power for gold mining operations and- the mining camps. Since all mining activities are now closed, the total output of these three plants is sold to the AEL&P. Power is delivered to the utility over the mining company's 23-kilovolt transmission system. The AEL&P operates five diesel driven generators with a combined capacity of approximately 8,000 kilowatts and three run-of-stream hydro units total- ing 1,600 kilowatts. Petersburg and the surrounding rural area is served by the Petersburg Municipal System. It operates a two-unit diesel electric plant within the city of Petersburg and a remotely controlled hydro- electric plant at Crystal Lake, approximately 16 miles from the city. The installed capacities of the plants are 1,250 and 2,000 kilowatts, respectively. The Wrangell area is served by the Wrangell Municipal Light Department. Its generation con- sists of a five-unit diesel electric plant with a total installed nameplate capacity of 1,735 kilowatts. The Ketchikan area is served by the Ketchikan Public Utilities. They presently operate two hydro- plants. The Beaver Falls plant, located 12 miles southeast of Ketchikan, has four hydro units totaling 6,000 kilowatts. The Ketchikan Lakes plant has three hydro units at 1,400 kilowatts each and three internal combustion generating units totaling ap- proximately 800 kilowatts. An additional 2,000- kilowatt unit is being added. Under recent amend- ment to the Beaver Falls license, Ketchikan, in 1968, completed the installation of a 2,100-kilowatt plant between the Upper and Lower Silvis Lakes for an added firm capacity of 1,140 kilowatts. A 34-kilovolt line transmits the power to Ketchikan. The Metlakatla Power & Light Co. serves the Annette Island area, which includes the city of Metlakatla, the Coast Guard station, the Annette Island Airport, and the adjoining residential area for airport related personnel. The company oper- ates a 3,000-kilowatt hydroelectric plant and a 1,250-kilowatt diesel electric plant. 77 The Sitka area, consisting of the city of Sitka, Mount Edgecumbe (made up of the Bureau of In- dian Affairs and PHS Alaska Native Health Serv- ice) , and surrounding rural areas, is served by the Sitka Public Utilities. They operate the two- unit hydroelectric plant at Blue Lake with a total installed capacity of 6,000 kilowatts. In addition, they have a four-unit diesel plant with a total in- stalled capacity of 1,300 kilowatts. The Bureau of Indian Affairs has a 250-kilowatt, steam-electric standby unit to supply the hospital in emergencies. The city of Haines is served by the Haines Light & Power Co. It operates a five-unit 1,100-kilowatt diesel plant. The nearby city of Skagway is served by the Alaska Power & Telephone Co. which utilizes both diesel and hydro generation with a total installed capacity of 840 kilowatts. Other small isolated communities operating diesel plants include Craig, Pelican, Hoonah, and Yakutat. Possible Programs for Development by 1975 and 1985 Additional generation will have to be developed to meet the projected loads for southeast Alaska. With no known gas fields or coal supplies, the only source of low-cost, large-unit generation for this Region is hydro, or possibly nuclear if it should be- come reasonably competitive in sizes compatible with the relatively small loads involved. One major project presently under construction is the Federal Sriettisham project, located on the tide flat of the Speel Arm of Stevens Passage, ap- proximately 28 air miles southeast of Juneau. It was authorized by Congress in 1962 and is being constructed by the Corps of Engineers. The project will be operated by the Alaska Power Administra- tion (APA) and will ultimately furnish the Juneau- Douglas area with 331 million kilowatt-hours of firm energy and 20,800,000 kilowatt-hours of non- firm energy annually. The ultimate installed name- plate capacity for the three-unit plant is 70,000 kilo- watts. Two units will be installed in the first stage of construction with a total nameplate capacity of 46,700 kilowatts. Present scheduling is for the first unit to be on the line in December of 1972. Power at Snettisham will be converted to direct current using solid-state technology and transmitted 45 miles to the Juneau-Douglas area through two high-voltage, direct-current submarine cables with provisions for emergency se~ return. Direct-current tapping techniques may open the way to a direct- current power grid in southeastern Alaska with the most likely first step being an underwater interti e with Sitka on the west coast of Baranof Island. Ap- proximately 125 miles of cable will be required and 20 miles of overhead construction across the island. A possible source of additional generation to meet projected loads in the Ketchikan area is the Lake Grace h yd ro proj ect, located on the eastern side of Rivallagige do Island, approximately 32 air miles northeast of K etchikan. The Lake Grace project could furnish 94 million kilowatt-hours of firm en- ergy and 6,270 ,000 kilowatt-hours of nonfirm en- ergy. Two units would be installed with a total ca- pacity of 20,000 kilowatts. Power would be delivered at 115-kilovolts over a 42-mile overhead transmis- sion line. From KetchikaB, power could be delivered to the Metlakatla area on Annette Island with a 34.5-kilovolt intertie requiring approximately 16 miles of overhead transmission line and .approxi- mately 1 mile of submarine cable. Another possible source of power for the Ketchikan-Metlakatla area to be explored in cooperation with Canadian au- thorities would be an intertie with the British Co- lumbia Hydro Peace River project in Canada or power purchased from the Pacific Northwest with such energy being wheeled over Canadian fa cilities. British Columbia Hydro is presently building two 500-kilovolt lines, with the first now in operation, from Portage Mountain in British Columbia to the lo wer mainland. Lines are also under construction or planned to tap this backbone system at Prince George and extend the system westward to Prince Rupert and north to Ali ce Arm . Either of these terminals present feasible interconnection points with Ketchikan, Alaska, through approximately 100 miles of submarine cable or 120 miles of overhead line. Be cause of the high investment cost of h yd ro elec- tric projects in Alaska, it is apparent that the im- mediate program for meeting future load growth for the P e tersburg, Wrangell , and Kake areas will be the addition of diesel or gas turbine generation. Hydro projects, such as Thomas Bay (table 17 ), may become economical wh en loads deve lop beyond those projected to 1985. A d es irable alternati ve for Petersburg and Wran- ge ll is a direct-current submarine cable syst em in- terconnection with Snettisham and /or K etchikan . This could form the initia l phase of an ultimate backbone transmission grid for the entir e inland passage from Ketchikan to Skagway. The key to this proposal lies in the successful development of eco- nomical lo w capacity a.c.jd.c. solid-state power 78 conversion equipment. Direct-current submarine cable itself has a cost advantage compared with overhead transmission in the difficult terrain of Southeast Alaska. To meet the projected loads in the Sitka area, the Takatz Creek hydro project has been proposed. This project, located on the eastern side of Baranof Island, approximately 21 miles northeast of Sitka, could furnish 96,850,000 kilowatt-hours of firm en- ergy and 2,030 ,000 kilowatt-hours of nonfirm en- ergy annt.\ally to the Sitka area with the installation of two 10,000-kilowatt units. Twenty-eight miles of 115-kilovolt transmission line would be required. An alternative to the high investment cost of the Takatz Creek hydro project would be a direct-cur- rent submarine cable installation from Snettisharn as described earli er. Summary of Southeast Region Lacking fossil fuels, southeast Alaska must look to its water resources as the most economical alterna- tive to power generation using fuels which are bur- dened with high shipping and handling costs. The relatively small area loads appear to preclude adop- tion of nuclear generation because of high unit costs of small package installations. Good hydro sites abound throughout the Region, but full utilization of these sites is handicapped by the diffi cult terrain over which conventional trans- mission lines must be built and maintained. Most of the h ydro poten tials are small, r e latively high- unit power cost deve lopments. Although probably beyond consideration as a po- tential resource which could be realized within the period of this projection, it is worthy of note here that the Yukon-Taiya project is reported to have a potential of 3,200 megawatts in the range of 2.4 to 4 mills per ki lowatt-hour at the bus bar and is sus- ceptible to stage development. Estimates indicate that the unit cost of a 1,200 -megawatt initial stage development would be in the same range. The Gov- ernments of Canada and the United States have recently announced the initia tion of preliminary joint examinations of the Yukon-Taiya possibilities, wi th initial emphasis to be placed on an exchange of data and views to assist both Governments in as - sessi n g power market possibilities which coul d jus- tify further studies of the power development po- tential of the Upper Yukon watershed , including alternative wat er diversion schemes to supply power developme nts in either British Columbia or Alaska. A lik ely lo cation of the principal h ydroelectric plant ne ith of ~a, :d. of :a, n- n- m of d. 1e r- m :o l-,_ e )- it 1, y t would be on the Taiya River as it enters the Gulf of Alaska (Lynn Canal) in the general vicinity of Skagway. Until low-capacity, solid-state, high-voltage, direct-current terminals are proven to be available at a competitive cost, and d.c . inline taps are ac- ceptable, system interties appear to be limited to the Petersburg-Wrangell-Kake and Ketchikan-Metla- katla areas. There is also the possibility of inter- connections with British Columbia Hydro in both areas. Planning beyond 1985 should anticipate the technical and economic feasibility of a direct-cur- rent power grid utilizing a bipolar system and sub- marine cable with emergency sea return, or a homopolar system with permanent sea return, either system giving dual-circuit capabilities. Northwest and Southwest Regions Load Distribution The Northwest and Southwest Regions cover a land area of approximately 180,000 square miles . However, only six areas have sufficient population density to justify central station generating facilities . The 1965 population, excluding military bases, was estimated to .be only 9,230 for the two Regions com- bined. Projections indicate a population of approxi- mately 15,000 by 1985. The 1965 total utility-type load for the combined regions was 3,400 kilowatts, largely concentrated in the principal villages of Point Barrow, Kotzebue, Nome, Naknek, King Salmon and Dillingham. Un- les s load growth is stimulated by petroleum and related commercial and industrial developments or presently unforeseen large -s cale mining develop- ments, the 1985 demand, excluding military and other nonutility-type loads, will probably not ex- ceed 16 ,000 kilowatts. Operating Utilities Appendix A lists operating utilities in the two Regions and installed generating capacities, mili- tary, and other nonutility generating facilities . It is noted that all generation is with diesel-driven generators. The military, Federal Aviation Agency, and the Bureau of Indian Affairs each maintain power gen- eration to meet the needs of their individual instal- lations. The FAA also procures energy from outside sources where it is economically a v ailable and also, under Public Law 647, may sell surplus energy to individuals. 79 Oil storage tanks at Kotzebue, above the Arctic Circle, emphasize the importance of the village not only as a tourist attraction but as a supply and trading "hub" for many thousands of square miles of Arctic area. Present Transmission Facilities The only existing transmission facility between villages in the Northwest-Southwest Regions consists of a 14-mil•, 12.5-kilovolt line between King Salmon and Naknek. Possible Programs for Development Power development for these small widespread villages of northwest and southwest Alaska is ex- pected to continue generally, as in the past, with small internal combustion or gas -turbine electric plants being added lo cally as needed. There are areas within the Northwest and South- west Regions where power interconnections ·between communities and the military would be mutually desirable . However, in view of the sensitivity of the military loads, it is unlikely that interties will be made until such times as the local utility loads de- velop to the point where utilities can justify the in- stallation of relatively large central plant generation with the reserves and reliability required to satisfy the military requirements. Some study is being given to the possibility of r eaching the small scattered loads in the Southwest Region by means of single- phase, ground return, transmission. An example of such a system was discussed for possible service to some of the small remotely located villages in the Interior Region. Summary of Northwest and Southwest Regions It is conceivable that the proposed extension of the Alaska Railroad and highways into the North- west Region with accompanying expansion of min- eral exploration and development could, within the study period, bring about a need for large central station power installations or extension of high-volt- age transmission systems from the Interior or South- 80 central Regions. Furthermore, the recent oil discoveries in the Prudhoe Bay area and the continu- ing explorations along the Arctic Slope could con- ceivably lead to much more rapid development than has been generally assumed in the survey. Pending such developments, limited extension of power facil- ities by such means as single -phase ground return transmission should be seriously considered. il L- 1- n lg 1- n CHAPTER VII TRANSMISSION AND INTERCONNECTION STUDIES BETWEEN INTERIOR AND SOUTHCENTRAL REGIONS As has been indicated in earlier chapters of the report, an analysis of the predicted loads, terrain, and power resources, together with the rapid load growth in the Anchorage, Kenai, and Fairbanks areas and the relatively short transmission distance (compared with Alaska distances in general) be- tween major load centers, made it desirable to investigate the cost savings and other benefits associated with transmission interconnections be- tween the Southcentral and Interior Regions. To realize part of the survey's goal of bringing into focus the economic significance of intercon- nections and coordination among systems, eight different models of generation and transmission pat- tems were developed. On the basis of these models, costs were developed which indicate the relative economies of the several schemes for supplying the future power requirements of the Anchorage, Kenai, and Fairbanks areas. To simplify the com- parisons, the model studies . gave consideration primarily to the utility loads because of their pre- dominance in the expected growth effects during the period of the study. The eight possible generation and transmission plans, summarily studied by the Subcommittee on Coordinated System Development and Intercon- nection, included six combinations of gas-fired steamplants in the Beluga and Kenai natural gas- fields, hydro peaking installations at Bradley Lake and Devil Canyon, and nuclear powerplants. For comparative cpurposes, two additional studies were made. One study (plan VII), provides for coordina- . tion within the Interior and the Southcentral Re- gions, but no interconnection between the two. The second study, plan VIII, represents a continuation of uncoordinated utility planning and operation very much as now practiced. In comparing this plan with the others, it should be noted also that it does not include defense base loads which are accounted for in plans I through VII. 81 Genera·l Considerations and Assumptions for Study Cases In each of the six interconnection plans studied, generation and transmission systems were assumed to supply the estimated 1985 loads. It should be noted that the generation and transmission systems assumed were not optimized. The projected 1975 load level was considered to determine an appro- priate interim system that would be consistent with the 1985 plans investigated. The load and generation requirements for each level of development considered the combined civil- ian and military systems operated on an integrated and coordinated basis for each of the intercon- nected plans. The generation and transmission in- stallations were sized accordingly. In most cases, larger sized units and plants can be justified by 1985. To the extent possible, the existing higher cost fuel-fired plants, together with their presently planned expansions, in the Interior and South- central Regions were assumed to be allocated to generation reserves and standby use. Stability and reliability were emphasized in the generation and transmission facilities assumed for these studies, but more detailed system analyses, voltage regulation, and stability studies will be r:equired to determine the optimum plan of service before adopting a final generation and transmission system for future development. While a detailed cost analysis was not made, it was considered reasonable to assume that it would be more economical and desirable to electrically transmit the low-cost gas energy from the Kenai and Beluga gas fields to the Interior rather than trans- port the gas directly by pipelines to thermal genera- tion sites at the load centers. The studies for each of the interconnection plans considered the cost benefits of: (a) reduced gen- erating reserves, (b) maximum use of economy 115-kilovolt transmission line tower on Turnagain Arm. energy, (c) installation of larger generating units, (d) larger total capacity in each generating plant, and (e) coordination of hydro and thermal genera- tion. Other benefits that will a lso accrue, although not given a monetary evaluation, include: (a) daily and seasonal load diversity, (b) use of surplus sec- ondary hydro energy for fuel displacement, (c) more efficient thermal plant operation, (d) effect of streamflow diversities, and (e) national defense. Generation reserves were considered in arriving at the size of units assumed and the level of gen- eration for each plan. With coordinated operation, the combined level of required reserves can be re- duced. For these studies, peak generation reserves equivalent to the capacity of the larges t unit were assumed. As mentioned above, such peaking re- serves , to the extent possible, were assumed to be supplied from existing older and more expensive thermal capacity. A 5-percent energy reserve based on the estimated loads was included for all plans. In some of the cases, the standby capacity available from the older and more expensive thermal plants was used to provide backup for a single transmission circuit. It is important in planning and operating a trans- mission system to have a completely reliable bulk- power supply system in order to eliminate the 82 possibility of cascading failures and inadequacy in meeting peakload requirements. The foundation of reliability is an adequate transmission system with fully coordinated controls. Coordination among utilities in the planning and operation of their facil- ities and particularly in the development of adequate transmission networks and interconnections within each region is essential. The peak and energy transmission losses vary with each different generation and transmission plan, and these losses were accounted for in de- termining the level of generation required for each of the 1975 and 1985 conditions studied. In each plan analyzed, the generating plants and individual units were sized to match as nearly as possible the 1975 and 1985 load conditions. The 1975 load level was investigated to determine how the interim system would fit in with the 1985 sys- tem. Generating reserves were analyzed and applied for each individual plan. The reserve requirements vary with the different sized units assumed. Capital and annual cost studies were prepared for each of the six interconnected plans and compared to similar cost studies for plan VII which, as stated earlier, "assumes interconnection and coordination by 1985 of all utilities, including military installa- tions within each Region, but not interconnection between the two Regions." Bases of Cost Estimates In preparing the cost studies of each alternate generation and transmission plan, composite fixed- charge rates calculated by FPC where used. This FPC composite fixed-charge rate was based on the weighted average of existing private, municipal, REA, and Federal investment provided to supply utility electrical loads in Alaska. An alternate financing method assumed Federal funds would be available for all generation and transmission fa cilities . Also, a weighted average in- terest rate was computed assuming 2 percent REA financing and 5 percent municipal financing. The weighted average was based on the 1965 existing loads of Chugach Electric Association, Golden Val- ley _ Electric Association, and the Fairbanks and Anchorage municipal systems. This calculated com- posite interest rate was 3.2 percent, or essentially the same as Federal financing at 3Ys percent. There- fore, the alternate financing method assumed in the cost calculations can be construed to be t ypical of either Federal financing or composite municipal and REA cooperative financing. in of th lg il- te m ry >n e- :h as b.e rs- ~d tts or ~d ~d )n a- m .te d- us b.e :tl, 'ly al ld n- .A b.e lg tl- ld n- lly ·e- b.e of 'al Descriptions of Models Used for Planning Studies The following sections describe the system repre- sentations used in the various planning studies for cost comparisons of the selected interconnection ar- rangements. In all cases, the planning studies were somewhat general in nature. Therefore, they are not suitable for direct application, and detailed sys- tem analyses and voltage regulation studies would be required before developing a final plan for-an interconnected system. Simplified maps and power flow diagrams are included for plans II and III, the most economically attractive arrangements. Plan 1-Beluga and Devil Canyon Generation A new gas-fired steamplant in the Beluga area, with two 150-megawatt units in 1975 and an addi- tional 200-megawatt unit by 1985, will supply the base energy load for the interconnected system. Peaking capacity in 1975 will. be supplied by the Healy coal-fired steam plant (assumed to have an installed capacity of 66 megawatts by 1975) and the 30-megawatt Beluga gas turbine plant. Peaking capaci~y in 1985 will be supplied by the 66-mega- watt Healy plant and the four 100-megawatt hydro units at Devil Canyon. The Beluga gas turbine plant is assumed to be allocated to reserve and standby use by 1985. The 1975 main 230-kilovolt transmission grid in- terties and intraties will connect major stepdown substations at Anchorage ( 250 megavolt-amperes) , Healy (75 megavolt-amperes) and Fairbanks (250 megavolt~amperes) . Series compensation totaling 30 megavars will be required at Healy to keep the electrical angle between points of generation and load within 30°-35°, in 1975, when any heavily loaded line in the system is removed from service. By 1985, an additional 230-kilovolt transmission line will tie Anchorage to Fairbanks while the Anchorage area substation capacity will have grown to 750 megavolt-amperes. A L 120-megavolt-ampere ca- pacity substation at Kenai and 70 megavars of com- pensation at Quartz Creek will be required by 1985 to serve loads and maintain stability under .emer- gency operating conditions. In this plan, 230-kilovolt submarine cables are used to transmit Beluga generated power to An- chorage via the Knik Arm underwater crossing while Devil Canyon power is fed into Susitna Switching Station, about midway between Anchor- age and Fairbanks. Militaryloads and resources are 83 assumed to be interconnected and coordinated for both the 1975 and 1985 levels of development. Plan 11-Beluga Generation A new gas-fired steamplant in the Beluga area, with two 200-megawatt units in 1975 and two addi- tional 250-megawatt units by 1985, will supply the base energy load and part of the peaking capacity. The remaining peaking capacity in 1975 and 1985 will be supplied by the Healy coal-fired steamplant which is assumed to have 66 megawatts by 1975. The Beluga gas-turbine plant is assumed to be allo- cated to reserve and standby use for both the 1975 and 1985 levels of development. Major stepdown substations will be constructed at Kenai ( 120 mega- volt-amperes), Anchorage ( 250 megavolt-amperes), Healy (75 megavolt-amperes), and Fairbanks (250 . megavolt-amperes).· A major switching station will be located at Nancy, midway between Beluga and Anchorage. Most facilities will be connected to- gether by 230-kilovolt transmission lines. Kenai will be tied to Anchorage by a 115-kilovolt line. These connections are shown on figure 10 and the com- panion power flow analysis is shown on figure 11. Series compensation of 30 megavars will be re- quired at Healy in 1975 to maintain system stabil- ity during periods when any critical transmission line is removed from service. Local standby and re- serve generation in the Fairbanks area will provide backup capacity for that part of the 1975 load which is being supplied from the single 230-kilovolt intertie line between Anchorage and Fairbanks. By 1985, an additional 230-kilovolt intertie line will be required to provide reliable transmission capacity for Fairbanks. By 1985, series compensa- tion of 120 megavars at Nancy and 45 megavars at Quartz Creek will be required to maintain system stability. (Figs. 12 and 13). Anchorage area sub- station capacity will have grown to 750 megavolt- amperes. Military loads and resources are assumed to be interconnected and coordinated for both levels of development. Plan Ill-Kenai and Beluga Generation Gas-fired steamplants at Kenai (150 megawatts) and Beluga (250 megawatts) in 1975 will supply the base energy load. Peaking capacity will be sup- plied by the Healy coal-fired steamplant, which is assumed to have 66 megawatts by 1975. By 1985, two additional units of 250-megawatt capacity at Beluga will be required to serve the increased load. I ,,, rr,: r'' LEGE II) ---&ini"SSli ... l -N.wlil1n I PLAN II -1975 I ~ S..ll-wSwitdringStatloa 0 Gtt.-ingPI..t 1>----<JScl'-riiMic.ble{l) Figure 10 PLAN II -1975 POWER FLOW DIAGRAM BELUGA. 230KV , ... HEA.LY l38KV }: LOSSES=llMI ••• SEWARD Figure 11 ANCHORAGE 130KV ll7MW LEGEND ---Existing Lines --Newlines 84 LEGEND ---E.iati"!!L&Iin -N.wLiH• {J S.ll-wSwitchi"'IStatiOII 0 ~raii"!!PI•t t>----<1 Sc. .... ;.,.Cab/e{•) Figure 12 PLAN II -1985 POWER FLOW DIAGRAM BELUGA 230KV 106MW 120MVA 3-lB+ lSjlare X LOSSES=.59MW Figure 13 31 MW SEWARD LEGEND ---Existing lines __ Newlines Peaking capacity in 1985 will be supplied by the 66-megawatt Healy plant. Major stepdown substation~ will be constructed at Kenai ( 120 megavolt-amperes) , Anchorage ( 300 megavolt-amperes), Healy (75 megavolt-amperes), and Fairbanks (250 megavolt-amperes) by 1975. All facilities will be tied together by 230- kilovolt transmission lines, except for a single Kenai-Quartz Creek-Anchorage tie which will be 115 kilovolts. Series compensation of 30 mega- vars at Healy will be required in 1975 to keep the electrical angle between Beluga and Fairbanks within 30°-35° when any critical transmission line is out of service. (Figs. 14 and 15.) Local genera- tion allocated to reserves and standby will be used as a backup source to supply any portion of the 1975 Fairbanks load which would not otherwise be served, if it is necessary to interrupt the single tieline between Anchorage and Fairbanks. By 1985, 40 megavars of series compensation will be required at Quartz Creek to maintain system sta- bility under emergency operating conditions. A sec- ond 230-kilovolt intertie line will be required by 1985 to transmit reliable power from Beluga to Fairbanks. An additional 115-kilovolt line between Anchorage and Quartz Creek will be required for reliability purposes. Anchorage substation capacity will grow to 600 megavolt-amperes. (Figs. 16 and 17.) Mili- LEGEND ---Exiollllflinu -HewliMI {J Sub-•SwitchingSt~;..., 0 G-neroting Plont , 1>----<3 Su!. .. ineCoL!.{s) Figure 14 85 tary loads and resources are assumed to be inter- connected and coordinated for both the 1975 and 1985 levels of development. PLAN Ill -1975 POWER FLOW DIAGRAM SUSITHA L lOSSES=IIMW FAIRBANKS ll7MW LEGEND , .. ---Exi51inglines SEWARD -KewUnes Figure 15 LEGEND ---Exilli"'llau -Hewlineo tJ Sub-orSwltchingStaliOII O Gerl .. crli"'!Piant t>--<J Su"-riaeCoble(s) Figure 16 li I i, I ! :I , I ,, ' , I I , PLAN Ill -1985 POWER FLOW DIAGRAM SUSITNA SEWARD ,I: LOSSES =4<1MW Figure 17 216MW LEGEND ---Existinglinu _Newlines Plan tV-Kenai, Beluga, and Bradley Lake Generation Kenai area gas-fired steam units of 150-and 200- megawatt capacity will supply the 1975 base energy load while the 30-megawatt Beluga gas turbine plant and Healy coal-fired steamplant (assumed to have 66 megawatts by 1975) will supply peaking capacity. An additional 250-megawatt unit at Kenai and a single-unit 1 GO-megawatt gas-fired steam plant at Beluga will be required to serve the 1985 load. Peaking capacity in 1985 will be shared by two 93.5- megawatt hydro units at Bradley Lake and the 66- megawatt Healy plant. Bradley Lake will be tied in at Kenai substation via two 115-kilovolt transmis- sion lines. The main transmission grid voltage in 1975 and 1985 will be 230-kilovolts. Major substations will be constructed by 1975 at Anchorage (300 megavolt- amperes), Kenai ( 150 megavolt-amperes), Healy (75 megavolt-amperes), and Fairbanks (250 mega- volt-amperes) . Series compensation of 35 mega- vars at Healy will be required in 1975 to maintain system stability if any critical transmission line is removed from service. By 1985, additional compen- sation of 40 megavars at Kenai and 5 megavars at Nancy will be required to maintain a 30°-35° 86 maximum electrical angle between point of genera- tion and point of delivery during emergency operation. In 1985, two 230-kilovolt lines will tie Anchorage and Fairbanks together. The substation capacity at Anchorage will increase to 600 mega- volt-amperes by 1985. A 230-kilovolt submarine cable will transmit part of the Beluga generation to Anchorage in 1985. All Kenai generation will be transmitted to Anchorage via 230-kilovolt sub- marine crossings at Fire Island. Military loads and resources are assumed to be interconnected and coordinated for both the 1975 and 1985 levels of development. Plan V-Kenai, Beluga, Devil Canyon, and Bradley Lake Generation Two new gas-fired steam units near the Beluga and Kenai gas fields with 100-and 200-megawatt capacities, respectively, will supply the load in 1975. Peaking capacity will be supplied by the Beluga 30-megawatt gas turbine plant and the Healy coal- fired steamplant, which is assumed to have an in- stalled capacity of 66 megawatts by 1975. An additional 100-megawatt unit will be needed at Beluga by 1985 to supply the base energy load. Peaking capacity in 1985 will be supplied by four 100-megawatt hydro units at Devil Canyon, two 93.5-megawatt hydro units at Bradley Lake, and the Healy plant. The Beluga gas turbine plant is assumed to be allocated to reserve and standby use by 1985. A 230-kilovolt main transmission grid will con- nect stepdown substations at Kenai ( 150 megavolt- amperes), Anchorage ( 300 megavolt-amperes), Healy (75 megavolt-amperes), and Fairbanks (250 megavolt-amperes) in 1975. By 1985, the substation capacity at Anchorage will grow to 600 megavolt- amperes. Series compensation of 30 megavars will be required at Healy to maintain system stability in 1975 if any critical transmission line is removed from service. Local generation at Fairbanks will pick up any loss of the main power supply if there should be an interruption of service over the single intertie line in 1975. In 1985, there will be two cir- cuits to the Anchorage area. Devil Canyon power will enter the system at Susitna switching station, approximately midway between Anchorage and Fairbanks, and Bradley Lake will be tied in to the Kenai substation. Military loads and resources are assumed to be interconnected and coordinated for both the 1975 and 1985 levels of development. Plan VI-Nuclear Generation A single-unit, 200-megawatt nuclear steamplant will be located near both Anchorage and Fairbanks in order to supply the 1975 loads on the intercon- nected system. By 1985, nuclear steamplants of 200- and 250-megawatt capacity will be required in the Anchorage area to supply base energy load. Peak- ing capacity in 1985 will be supplied by a new 100- megawatt gas-fired steam unit near the Beluga gas fields. The Beluga gas turbine and Healy coal- fired steamplant are assumed to be allocated to re- serves and peaking use in both 1975 and 1985. Ma- jor stepdown substations will be constructed at Kenai ( 120 megavolt-amperes), Anchorage ( 250 megavolt-amperes) , Healy ( 7 5 megavolt-amperes), and Fairbanks ( 150 megavolt-amperes). A major switching station will be located at Knik near the proposed Anchorage nuclear plant. All facilities will be interconnected by 230-kilovolt overhead transmission lines. Series compensation of 5 megavars at Quartz Creek will be required, in 1975, in order to limit the electrical·angle between generation and point of delivery to 30°-35° when any critical transmission line is removed from serv- ice. Existing higher cost thermal generation capacity in the Fairbanks and Anchorage areas will supple- ment power imported over the intertie line in the event of a local nuclear steamplant outage. Anchor- age area substation capacity will increase to 750 megavolt-amperes by 1985. Series compensation of 20 megavar~ at Quartz Creek by 1985 will be re- quired to maintain system stability during emer- gency operating conditions. Military loads and resources are ·assumed to be interconnected and coordinated for both the 1975 and 1985 levels of development. Plan VII-Isolated Systems (No Transmission In- terconnection Between Interior and South- central Regions) Interior Region The existing coal-fired steamplant at Healy, as- sumed to have 66-megawatt capacity by 1975, will need a new 44-megawatt unit by 1975 (and single 60-and 70-megawatt units by 1985) to supply the Fairbanks area load. An additional 138-kilovolt transmission line will be required by 1fl75 between Healy and Fairbanks and a total of three lines will be needed by 1985. Military loads and resources were not assumed to be interconnected and coordi- nated in the 1975 level of development due to the relatively small system. Military loads and resources 87 were incorporated in the 1985 case, however, be- cause the coordinated utility system was considered to be more reliable by that time. Southcentral Region The 1975 base energy load for the Anchorage area will be supplied by two, single-unit, 90-mega- watt gas-fired steamplants near the Kenai and Bel- uga gas fields. By 1985, the Beluga plant will have an additional 135-megawatt unit ·and the Kenai plant will have three additional 135-megawatt units. Beluga power will be transmitted to Anchor- age by two 230-kilovQlt transmission lines. The out- put of the Kenai plant will be transmitted to An- chorage by two overhead transmission lines which cross the Turnagain Arm at Bird Point. In 1985, an additional 230-kilovolt line will be required to reliably transmit Kenai supplied power to Anchor- age. Military loads and resources were not assumed to be operating on a coordinated basis with the utility system in 1975. They were, however, assumed to be fully coordinated with the local systems by the 1985level of development. Plan VIII-Isolated Systems-Individual Utilities In order to measure the benefits, if any, accruing from coordination and interconnection within and between the individual Interior and Southcentral Regions (Plans I through VII), an estimate of the capital and annual costs of the two major utilities in each region is required. Plan VIII satisfies this requirement. VIII-A City of Anchorage In 1975, two additional 15-megawatt gas tur- bines will be required to serve the municipal base energy load and to supply peaking capacity. Sub- station capacity will be increased by four 10-mega- volt-ampere distribution stepup transformers. By 1985, two more 15-megawatt gas turbines and four 10-megavolt-ampere distribution stepup trans- formers will be required. The 16-megawatt share of Eklutna hydro capacity allocated to the municipal utility is assumed to be utilized under both levels of development. . VIII-B Chugach Electric Association Three 30-megawatt gas turbines and one 15- megawatt unit are assumed to be installed in the vicinity of the existing Beluga gas turbine plant by 1975 to serve base energy load and supply peaking capacity. New transmission required by 1975 would I' 1. i[' ,li !i[ ! II be a second 138-kilovolt line and submarine cable between Beluga and Anchorage and a 115-kilovolt line between Quartz Creek and Kenai where a new 120-megavolt-ampere substation is assumed to be constructed. Anchorage substation capacity will be supplemented by the installation of two 150-mega- volt-ampere stepdown transformer banks. By 1985, gas-fired steamplants are assumed to be installed at Kenai ( 100 megawatts) and Beluga ( 360 mega- watts) to satisfy the increased requirements. The new Beluga generation is assumed to be transmitted to Anchorage via two 230-kilovolt lines around Knik Arm. Near Palmer, a line tap and 75-megavolt- ampere substation will be needed to serve part of the Palmer-Matanuska load. Reliability of service to the Kenai area will be increased by construction of a second 115-kilovolt line from Anchorage through Quartz Creek to Kenai substation. The 9-megawatt share of Eklutna hydro capacity allo- cated to Chugach Electric Association is assumed to be utilized under both levels of development. VIII-C City of Fairbanks Two additional coal-fired steam units with ca- pacities of 5 and 10 megawatts, respectively, will be required by 1975 to serve the base energy load and to supply peaking capacity. Substation capacity will be increased by adding two 10-megavolt-am- pere distribution stepup transformer banks. By 1985, two more 10-megawatt coal-fired steam units will · be required as will additional substation capacity of two 10-megavolt-ampere banks. VIII-D Golden Valley Electric Association The principle source of generation for this utility is the Healy coal-fired steamplant. By 1975, a second 22-megawatt unit will be needed to meet the growth of base energy load and capacity requirements. A second 138-kilovolt line between Healy and Fair- banks will be needed in order to increase reliability. Substations of 75-megavolt-ampere capacity each will be required at Healy and Fairbanks to handle the increased generation and load, resp~ctively. By 1985, a third 22-megawatt unit and two 44-mega- watt units will be needed as well as an additional 75-megavolt-ampere transformer bank at both Fair- banks and Healy. In an emergency, one transmission line can handle the power flow so no new construc- tion will be required. Conclusions From Interconnection Studies The results of the cost benefit studies are sum- marized for each of the study plans. Annual utility 88 cost benefits based on 1965 Alaska cost levels and totaling up to $9,098,000 in the single year of 1985 are estimated to be achievable with coordinated area operations and an interconnected generation and transmission system to supply the combined Interior and Southcentral Alaska loads as opposed to existing isolated utility operation. This combined level of 1985 annual cost savings represents the fol- lowing individual utility system savings in that year. Estimated Level of Cost Benefits in 1985 1 Anchorage .......... . Chugach ........... . Fairbanks ........... . Golden Valley ........ . Esti- mated 1985 energy load (kilowatt- hours) 526 2, 575 184 543 Cost benefits (mills per kilowatt- hour) 4.45 . 36 13.86 6.04 Annual savings dollars2 2, 341,000 927,000 2,550,000 3,280,000 Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9, 098, 000 1 Based on the difference in unit cost per kilowatt-hour with continued isolated utility operation as compared with plan III. 2 Based on 1965 Alaska cost levels .. NoTE.-It is not intended that this study anticipate power rate arrangements or assume that small localized area rates should be established in preference to zoning rates. These calculated annual cost savings can be ex- pected to continue to increase beyond the 1985level of development. Other benefits, mentioned earlier but not given a monetary evaluation, could further increase the savings from interconnected and co- ordinated operation. The lowest cost plan (Plan III) for supplying the 1985 interconnected system involves the installa- tion of gas-fired steamplants near the Kenai and Beluga gas fields. In determining the actual location and timing of future gas-fired steamplants, strong consideration should .be given to the rate of load growth in the near vicinity of the generating plants. For example, the Kenai Peninsula loads have in- creased rapidly during the last 5 years and are ex- pected to continue to increase rapidly during the next two decades. There are stability, reliability, and transmission line advantages to the location of gas- fired steamplants in both the Kenai and Beluga areas, even though the cost of a bulk power supply system is essentially the same with all the generating capacity near Beluga. r -r A 230-kilovolt. transmiSSion voltage was deter- mined to be the minimum voltage that should be considered for interties between the two Regions. Series compensation will be required in the trans- mission circuits between the Southcentral and In- terior Regions to transmit the magnitude of loads involved. Some shunt compensation may be re- quired to control voltage under light load conditions. In designing a system for the 1985 level of _de- velopment, consideration should be given to the utilization of hydro peaking capacity to be oper- ated on an integrated and coordinated basis with the steam generation. By this means, the gas-fired steamplants can be scheduled to operate at a high capacity factor, thus resulting in a lower unit gen- eration cost. The sites considered for the develop- ment of hydro peaking capacity in these studies were Bradley Lake and Devil Canyon. Other sites should also be investigated and studied before a final plan for the installation of hydro peaking capacity is adopted. Bradley Lake is located in the fast growing Kenai Peninsula area and Devil Can- yon is at a convenient midpoint between the Inte- rior and Southcentral load centers. Table 19 contains a summary of the estimated costs for plans I through VII based on the FPC computed composite annual cost ratios. Plan VIII was not included because the composite cost basis is not applicable to plan VIII assumptions. Table 20 includes Plan VIII and presents simi- lar summary type information, but is based on as- sumed Federal financing and does not include defense base loads. The figures in this table will also typify composite municipal and Rural Electrifica- tion Administration cooperative financing as pre- viously discussed. Plans II and III each have a sig- nificantly lower level of annual costs by 1985 than the other interconnected plans or isolated regional operation. This assumes that the installed peaking capacity at Devil Canyon (plan I) is matched to just meet the 1985 level of development with an in- stalled cost per kilowatt estimated at $605. This is considerably higher than the estimated $300 per kilowatt installed cost for the ultimate Upper Susitna project (Watana, Vee, and Devil Canyon) TABLE 19 Summary of Estimated Capital and Annual Costs-1985 [FPC computed composite annual cost ratios] Plans Generation INTERCONNECTED REGIONS 2 I Beluga Gas and Devil Canyon Hydro. II Beluga Gas ....................... III Kenai and Beluga Gas .............. IV Kenai, Beluga Gas, and Bradley Lake Hydro ..................... v Kenai, Beluga Gas, Devil Canyon, and Bradley Lake Hydro .. ·'· ..... VI Nuclear .......................... ISOLATED REGIONS 2 VII (a) Anchorage-Kenai and Beluga Gas ........................ (b) Fairbanks-Healy Coal .......... Total combined ............ 1 Based on 1965 Alaska cost levels. Capital costs 1 dollars in millions Annual costs, dollars in millions Energy load Gener-Trans-Gener-Trans- arion nnsmon ation nnsmon 321.0 79. 7 27.059 6. 175 136.5 76. 7 18. 163 5.995 135.8 68.9 18.527 5. 321 184.2 98.0 20.4!55 7. 316 382.2 89. 1 30. 315 6.821 253.6 45. 1 28.834 3.598 120.4 47.2 15. 671 3.520 44.3 8.5 7. 101 . 654 164. 7 55. 7 22. 772 4. 174 Total Average Megawatts 33.234 503 24. 128 503 23.848 503 27. 771 503 37. 136 503 32.432 503 19. 191 393 7. 755 110 26.946 503 Giga- watt hours 4,406 4,406 4,406 4,406 4,406 4,406 3, 436 970 4,406 Mills per kilo- watt- hour 7.54 5.48 5.41 6.30 8.43 7. 36 5.59 7.99 5.64 2 Utility and military loads and resources assumed to be coordinated within each region. 89 II II '"I' , I ~ TABLE 20 Summary of Estimated Capital and Annual Costs-1985 [Annual cost ratios based on Federal financing I] Plans Generation Capital costs • dollars in millions Annual costs dollars in millions Energy load Gener-Trans-Gener-Trans-Total ation mission ation mission Average Giga- Megawatts watt hours Mills per kilo- watt- hour INTERCONNECTED REGIONS 3 I Beluga Gas and Devil Canyon Hydro. 321. 0 79. 7 II Beluga Gas ....................... 136.5 76. 7 III Kenai and Beluga Gas ............. 135.8 68.9 IV Kenai, Beluga Gas, and Bradley Lake Hydro ..................... 184.2 98.0 v Kenai, Beluga Gas, Devil Canyon, and Bradley Lake Hydro ......... 382.2 89. 1 VI Nuclear .......................... 253.6 45. 1 IsoLATED REGIONS 3 VII (a) Anchorage-Kenai and Beluga Gas ........................ 120.4 47.2 (b) Fairbanks-Healy Coal ........... 44.3 8.5 Total combined ............ 164.7 55. 7 IsoLATED UTILITY OPERATIONS 4 VIII Anchorage ........................ II. 4 . 7 Chugach ......................... 93. 1 29.6 Fairbanks ......................... 13. 1 .4 Golden Valley ..................... 39.6 5.4 Total combined ............... 157.2 36. 1 1 Costs are also representative of composite municipal and Rural Electrification Administration cooperative financing. 2 Based on 1965 Alaska cost levels. as developed by the Hydro Resources Subcommittee for a peaking type installation. If this lower installed unit cost is assumed for Devil Canyon, plan I, the level of annual cost would, of course, be correspond- ingly lower. By 1985, the two regions will just begin to reap the calculated savings achievable from intercon- nected and coordinated operation, and beyond 1985, the amount of benefits and savings will mcrease. An alternative means to supply electric utility loads in the Fairbanks area, other than by an inter- tie with Anchorage area power sources or by burn- ing coal (or oil) in the Fairbanks area plants, would 90 20.239 4,484 24. 723 503 4,406 5.61 15. 130 4.366 19.496 503 4,406 4.42 15.540 3.860 19.400 503 4,406 4.40 16.479 5.233 2l. 712 5031 4,406 4.93 22.222 4.933 27. 155 503 4,406 6. 16 23.256 2.650 25.906 503 4,406 5.88 13.021 2.521 15.542 393 3,436 4.51 6. 127 .474 6.601 110 970 6. 79 19. 148 2.995 22. 143 503 4,406 5.03 4.506 149 4.655 60 526 8. 85 10.280 I. 965 . 12.245 294 2, 575 4. 76 3.285 75 3.360 21 184 18.26 5.298 372 5.670 62 543 10.44 23.369 2,561 25.930 437 3, 828 6. 78 3 Utility and military loads and resources assumed to be coordinated within each region. 4 Assumes no military-utility coordination and existing public agency utility financing. be to use Cook Inlet natural gas piped to the Fair- banks plants. The cost of a pipeline, if constructed by private financing, would add an estimated 45 cents per million British thermal units to the field gas price. The delivered cost for quantities required by utilities and the military for the generation of electric power and to supply space heating and in- dustrial demands would not be competitive with the cost of Healy field coal delivered to the Fairbanks area. Nor would it be more economical than to transmit the gas energy as electricity from the Kenai and Beluga gas fields to Fairbanks. The patterns of generation and transmission dis- cussed here are in no sense a program or blueprint, but they may prove helpful-especially to persons not intimately involved in power supply planning for a large area. In this and previous chapters, an attempt has been made to identify ways in which costs of electric system operations can be reduced. Few, if any, elements in the structure and opera- tion of power systems remain constant. Even small changes in fuel costs, transportation, or other ele- ments of various system expansion alternatives could substantially alter the kind of generation and trl!.nS- mission system to be built in the future. Hence, it is not possible to predict with assurance the pattern of generation and transmission that will eventually serve Alaska's projected loads. Only through plan- ning which looks far beyond the requirements of a particular system or locality, however, can the most economical supply of power to all users be achieved. It should be clearly understood that effective coordination of major power transfer facilities can- not be achieved through interconnections alone. Coordination must encompass mutual review of load projections, coordinated construction plans, and agreement on operating practices and safe- guards. Once adequate transfer facilities exist, economy of bulk-power supply will be enhanced through exchanges of capacity and energy among systems, sharing of spinning and standby reserves, 91 and transfer of emergency power to meet needs due to unusual weather conditions and other contingen- cies. Economy and reliability are closely associated objectives, but reliability must have priority. The transmission system should be carefully engineered and well-maintained so as to insure a high degree of service continuity. Particular attention must be paid to protecting the lines and line terminals against overloading, and the system against equip- ment failure. A program should be designed to match loads to the available power supply to pro- vide for a minimum of interruptions of essential services. As a backup in the event of loss of power, utility supplied hospitals, water systems, police and fire protection centers, transportation and commu- nication facilities, and related essential services should have available automatic-start, standby power supplies, continuously maintained for emer- gency use. The full advantages can be achieved only by joint planning which extends beyond the bounds of a corporate or other entity, an area, or a region. Coordinated planning and operation must bridge differences in management philosophies. Reliability and economy should be available to all users of elec- tric power, regardless of the nature of the systems serving them. ' .. CHAPTER VIII OUTLOOK FOR COST REDUCTIONS The final consideration of the Survey, and the one of greatest significance to Alaska's electric power industry and its customers, is the influence of pro- jected trends and patterns on the price of electricity in the future. The numerous factors that have a bearing, directly and indirectly, on electric power costs have been discussed earlier and can be grouped into the following principal categories applicable to the Survey's projections: ( 1) The generous growth in future electric power loads largely caused by expected increases in the use of electricity per customer and anticipated strong growth in the do- mestic and industrial segments of Alaska's economy, promoted by an agressive power marketing pro- gram; ( 2) the suggested use of large thermal-elec- tric generating plants located at fuel sources; (3) the prospects for lower fuel costs and lower opera- tion and maintenance expenses; and ( 4) the insti- tution of affirmative coordinated planning for the construction and operation of regional sources of generation, including bulk power transmission fa- cilities and appropriate interties. This chapter offers estimates of average costs of electric power for the 1985 period in relationship to current costs, and eva,luates potential cost reduc- tions in terms of current dollar values. Suggested Target for 1985 The 1965 average cost of electricity supplied by the utilities in Alaska before distribution to the ultimate consumer was estimated to be 1.98 cents per kilowatt-hour. Based on the same relative dollar value, the projected lowest Alaska average cost by 1985 is 0.71 cents per kilowatt-hour. This would be a 64-percent reduction and appears possible with cooperative and coordinated planning and opera- tion of electric power facilities. A target of less than %-cent power may seem to be an overly optimistic prediction of future develop- ments. It is, however, a statewide average-a target which some Alaska utilities cannot approach within the survey period. Nevertheless, for most large 93 utilities, the goal of less than 1-cent power by 1985 is within reach. This is roughly comparable to the average cost in the 48 States in 1962. A cost decrease of this magnitude would be consistent with the Alas- ka electric utilities history of accomplishment, par- ticularly since the early 1950's. Projected Power Costs-1985 Price inflation during and after World War II exerted strong upward pressures on all costs throughout Alaska. In this period, utility load growth and system expansion were rapid. The pres- su·re of inflation on power costs was offset by im- provements in technology, economies from installa- tion of larger generating units, the addition of new hydroelectric sources, and use of interconnecting links between sources. Electric power production costs vary widely in Alaska. In remote areas, without hydro power sources and far removed from bulk fuel supplies, costs are high. Where natural gas is economically produced and marketed, as in the Anchorage area, and coal, as in the Fairbanks area, their use pre- dominates and power production costs are lower. Where hydroelectric power supplies a high percent- age of the load and fuel is relatively low priced as in the Panhandle area, costs are also lower. Natural gas, as a hydrocarbon mixture, can be converted to other valuable products. Alaska's natural gas re- sources are potentially so great, however, that com- peting demands for its use are not expected to affect the price structure significantly. Costs of Alaska's liquid fuels are expected to decrease as the search for additional oil resources continues, sources of high-quality petroleum products are discovered, and the crude products are refined in Alaska. Economic as well as environmental factors were considered in projecting the kinds and sizes of gen- erating plants expected in the different regions. A definite downward trend in fuel, labor, and material costs is reflected in past years' fossil fuel generating plant power production expenses. This trend is ex- II' ,, I ,il' II ,, I, pected to continue as larger, more efficient and more economic power production facilities are introduced into Alaska's power supply. At present there are large differentials in average power costs among the five regions; table 21 shows average 1965 costs and projected 1985 costs. In 1965, the lowest cost was 1.65 cents per kilowatt- hour in the Southeast Region, which benefits from having a high proportion of low-cost hydroelectric sources and from being near to relatively low-cost sources of fuel used in its diesel plants. In addition, the average energy usage per customer is higher than in other regions. As expected, the highest costs are experienced in the Northwest and Southwest Re- gions where fuel prices are high and small internal- combustion engine generating units are in use. TABLE 21 Cost of Electric Power 1965 and 1985 1 [Cents per kilowatt-hour] Region and State Northwest ................. . Southwest. ................ . Southcentra~ ............... . 1965 esti- mated cost 4.68 4.68 I. 80 1985 pro- jected cost Per- centage re- duction 3. 62 23 3. 51 25 Without intertie 2 • • . . . • . . . . • • . . . . • 83 54 With intertie 3 • • • . . . . . . • . . . . . . . • • • 56 69 Interior. . . . . . . . . . . . . . . . . . . . . 2. 84 .............. . Without intertie 2 • • • . • • . . . . • • • . • . I. 42 50 With intertie 3 • . • . • . • . . • • • • • . • • • . • 77 73 Southeast. . . . . . . . . . . . . . . . . . . I. 65 1. 3 7 1 7 Alaska average. . . . . . . . . . . . . . 1. 98 .............. . Footnote 2 conditions. . . . . . . . . . . . . 1. 04 47 Footnote 3 conditions. . . . . . . . . . . . . . 71 64 1 Annual average costs of power delivered to subtrans- mission and distribution points. (Based on costs of generating plants and transmission facilities in use and projected.) 2 Anchorage and Fairbanks utility power sources sep- arately integrated and coordinated; and not interconnected; utility loads only supplied. 3 Anchorage and Fairbanks load center power sources interconnected, and system operations integrated and coordinated; utility and defense loads supplied. Target estimates for the five regions reflect a con- siderable narrowing of cost differentials by 1985 as illustrated by figure 18. Reductions are projected for all regions, but the largest percentage reductions are foreseen for the Southcentral and Interior Regions. The Southeast Region exhibits the least prospect . for a sizable percentage reduction in power cost. As stated above, the average cost is now below other 94 regions, and annual average energy usage per cus- tomer is generally higher. The numerous widely separated communities are relatively small with well.:established economies and are expected to re- main so. The need for, or opportunities to, install larger and more economic generating units are, therefore, not substantial. The greatest prospects for sizable percentage re- ductions in power costs prevail in the Southcentral and Interior Regions. Although average costs are currently in the median range, the avenues open to the regional utilities for dramatic cost reduction programs are so numerous and varied that by 1985, average costs could well be 50 to 70 percent below today's levels. In addition to the many economic prospects for cost improvements at sources of generation and through intraregional utility cost reduction pro- grams, additional benefits can be realized through interregional interconnections. How such economies can be effected was discussed earlier in the report. PROJECTED TRENDS IN POWER COSTS 1965 -1985 l J 3"0!-;:19:-;65:--------:N:-:O:=RT::-,H::::W=ES:=T-::R=EG:-::IO:-::N:--------;-;19:;:-!85 r J 3·0!-;:19c:-:65:-------S-O-UT_H_W-ES_T_R-EG-IO-N-------;1.,-!985 OL--------~--~------~ 1965 SOUTHCENTRAL REGION 1985 0~------~~~~~------~ 1965 INTERIOR REGION 1985 2.01 l.Of-: --------------------( 0 ~196~5-------:S:=O:=UT:-:-:H:=EA~s=T=RE~G~IO~N------~19~85 2.0r=~~~ ~-----No lntertie Fclirbanks-Anchoro -----.... 1.01-~------.:C ge Interconnected 0 ~19"'65------~AL~A:=SK~A~Ac:-:V=ER~A=GE~-----~19:;:-!85 Figure 18 Many Alaska utilities will not have the oppor- tunity to interconnect. Of the studies made during the course of the Survey, an Anchorage-Fairbanks area interconnection holds the greatest promise for achieving power ecqnomies. The economic attract- iveness of the Anchorage-Fairbanks interconnection is illustrated by the cost differences shown in table 22, which compares the cost of providing power for the 1985 load requirements of the two areas with and without an interconnection. As indicated-by the estimates, an annual cost reduction of more than $2~ million could be expected in an intercon- nected system. While the cost of transmission for an interconnected arrangement would be over $1 mil- lion more, the generation cost would be nearly $4 million lower with the two areas interconnected. Interconnections between some Panhandle utilities, although now marginally economic, may later prove feasible. Evaluation of Cost Reductions The projected lowest statewide unit power cost in 1985 of 0.71 cent per kilowatt-hour reflects the decrease in power costs by interconnecting the Anchorage and Fairbanks load centers and supply- ing both defense and civilian utility loads. Without the interconnection and with civilian utility loads separately supplied, the statewide average utility power cost in 1985 would be 1.04 cents per kilowatt-hour. The differential between the Alaska average cost of power in 1965 of 1.98 cents per kilowatt-hour and the 0.71-cent cost for 1985, applied to the com- bined estimated defense and civilian power require- ments of 5.3 billion kilowatt-hours in 1985, repre- sents a gross reduction of $67 million a year. With- out the interconnection and with civilian loads supplied separately, the average utility cost of 1.04 cents per kilowatt-hour would produce a gross re- duction in power cost of $45 million annually. Table 23 brings into focus the magnitude of the power cost reductions projected for each region. Reductions projected for the Southcentral Region by 1985 are substantial even if its utilities do not interconnect with those in the Fairbanks area, but are still more significant if a coordinated intercon- nection is established. Even greater benefits can be realized by utilities in the Fairbanks area. While the cost reductions projected for the other regions are not of the magnitude suggested for the Anchorage and Fairbanks areas, they do suggest a relative high order of achievable savings. Cost Estimating Assumptions Costs are based on present price levels and on price-cost relationships estimated to exist between Alaska and the lower 48 States at the present time. Power cost estimates for 1965 were developed from actual costs and thus reflect a very modest degree of intersystem integration and coordination. Pro- TABLE 22 Cost Differen.ces in Delivered Power/ Anchorage and Fairbanks Load Centers, by 1985 GENERATION Projected annual costs 2 ---------------Percentage Non-inter-Inter-Cost reduction connected 3 connected 4 difference Dollars (1 ,OOO's) ............................................. . $22, 772 5. 17 $18,527 4. 20 $4,245 . 97 19 19 Mills/kilowatt-hour .......................................... . c TRANSMISSION Dollars (l,OOO's) ............................................. . $4, 174 . 95 $26,946 6. 12 $5,321 I. 21 $23,848 5. 41 $1, 147 ............. . Mills/kilowatt-hour ........................................ , .. . (. 26 ) ............ .. Total dollars (I ,OOO's) .................................... . $3,098 II Total mills/kilowatt hour ................................. . . 7l II 1 Costs are based on FPC computed composite annual cost ratios and are for the bulk-power supply system only. Distribution costs are not included. 2 Does not include annual costs for existing and presently planned expansion of thermal-electric plants and hydro sources. 95 3 Anchorage costs are for natural gas-fired steam-electric plants in Kenai and Beluga gas fields; Fairbanks plant cost is for coal-fired steam-electric plant at Healy field only (table 19). 4 Interconnected steam-electric plants: Beluga and Kenai natural gas-fired pla'tlt cost only (table 19 ). 'li'l I .,,I ,, rrl I, , ,, I il 1,! I>', , , ;II,' i :11;1,,! 1 !1 ',I TABLE 23 Reduction in Costs of Electric Power/ by 1985 Region and State Condition 1985 energy megawatt- hours Unit cost reduction (cents per kilowatt- hour) Total cost reduction ($1,000's) Northwest. .................................. · ................ · N.I. 44, 790 24,790 3,319, 880 3, 607,090 721,350 1. 06 1. 17 475 290 32,203 44, 728 10,243 20,037 Southwest ................................................... N.l. Southcentral ................................................. {N·~: . 97 1. 24 1.42 2.07 Interior ..................................................... {N -~: 967,980 668,630 Southeast .................................................... N.I. . 28 .94 1. 27 I, 872 45,083 67,402 Alaska total. ............................................. {N·~: 4, 779,440 5, 313, 280 I Reduction from 1965 in annual cost of power delivered to subtransmission and distribution points. N.I.-No interties except existing and no interconnections between regions (defense load and nonload center loads excluded). jected power costs are those expected to obtain in a program dedicated to integrating, coordinating, and interconnecting as many systems as possible and, in all cases, reflect the use of larger size, lower unit cost generators, lower cost fuels, and reduced unit costs of operation and maintenance. The cost of all equipment and facilities shown on the geographical diagrams, figures 12 and 16, and the power flow diagrams, figures 13 and 17, for study plans II and III, and similar diagrams (not included in the report) for the other plans have been included in the cost summaries, tables 19 and 20. Hydroelectric power production costs are in- cluded in the total. Costs for existing plants were estimated on the basis of 1965 prices of salable hy- dro power. Costs of power from potential projects were based on available estimates. Average power costs by region and for the State as a whole were based on energy prod~ction costs for the same kind of generating plants, taking into account each group's contribution to the present and future energy loads. Applicable transmission costs were included. Group power costs were developed from estimates of fixed and variable components reduced to manageable units to simplify the mass of detailed costs. Although the component costs are 96 I. =Anchorage load center systems (Southcentral) inter- connected with Fairbanks load center systems (Interior). Defense load included (1985). Nonload center loads are excluded. not given, a brief explanation concerning their re- lationship and value follows. The fixed power cost component consists of an- nual fixed charges and fixed operating costs which are essentially unaffected by a generating plant's energy output. Estimates of annual fixed charges (the portion of total power cost directly related to investment in generating plants and transmission facilities) were developed by use of composite fixed- charge rates shown in table 24. Thus, the cost to all ownership segments of Alaska's electric power in- dustry is placed on the same financial base. While the composite rate established fixed power costs on a uniform basis, we recognize the composition of and variation in the ownership structure of Alaska's elec- tric utility industry. The variable power cost component is the incre- mental cost associated with the generation of en- ergy. With respect to thermal-electric plants, a large portion of the cost of fuel consumed and related labor and operating costs is considered to be a vari- able cost, with the cost of fuel being the major ele- ment. For a hydroelectric plant, the variable cost is that incurred when it is generating, and consists largely of operation and routine maintenance expenses. TABLE 24 Composite Annual Fixed-Charge Rates, Electric Utility Generating Plants and Transm,ission Facilities HYDROELECTRIC PLANTS (75-YEAR LIFE) Mode of financing: Private ....................................................... . Municipal and other public non-Federal. ......................... . REA cooperative .............................................. . Federal. ...................................................... . Hydroplant total annual fixed-charge: ·Ownership weighting factors 0. 1276 . 3710 . 3620 . 1394 Estimated fixed-charge rates (percent) 13.08 6.03 3.49 3.63 Composite (weighted) rate (percent) I. 67 2.24 I. 26 . 51 Rate...................................................................................... 5. 68 Use....................................................................................... 5. 70 CONVENTIONAL STEAM, INTERNAL-COMBUSTION AND GAS-TURBINE ELECTRIC PLANTS:. AND GENERATING PLANT AND TRANSMISSION SUBSTATIONS (35-YEAR LIFE): Mode of financing: Private ....................................................... . Municipal and other public non-Federal. ......................... . REA cooperative ............................................... . Federal ....................................................... . Steam, 1-C, and G-T and substations total annual fixed-charge: o. 1276 . 3710 . 3620 . 1394 14.21 7.46 5.35 5.34 l. 81 2. 77 l. 94 . 74 Rate ....................................... .".............................................. 7. 26 Use....................................................................................... 7. 30 TRANSMISSION LINES A. Wood pole (35-year life): Mode of financing: Private ........................................... · · .. · . · · · · · Municipal and other public non-Federal ....................... . REA cooperative ............. : ............................. . Federal. ............................................ · · ... · · · Wood-pole total annual fixed-charge: 0. 1276 . 3710 .3620 . 1394 13.91 7. 16 5.05 5.04 1.77 2. 66 l. 83 . 70 Rate................................................................................... 6. 96 Use.................................................................................... 7. 00 B. Steel tower (50-year life): Mode of financing: Private ....... , ................ · · .. · · · · · · · · · · · · · · · · · · · · · · · · · Municipal and other public non-Federal ....................... . REA cooperative ........................................... . Federal ....................................... ·············· Steel-tower total annual fixed-charge: o. 1276 . 3710 .3620 . 1394 13.34 6.43 4. 13 4. 18 l. 70 2. 39 l. 50 .58 Rate........................................................... . . . . . . . . . . . . . . . . . . . . . . . . 6. 17 Use................................................................................... 6. 20 97 I II ' I i Conclusions Growth in electric energy use is not readily separ- able from other factors which have a bearing on reductions in cost. Growth is both the result and cause of future economies. Maximum growth in electric power consumption in many localities in Alaska will occur only if electric rates are lowered as fast as cost reductions will permit. Cost reduc- tions, in turn, will largely depend on the extent of growth in power usage. The patterns and guidelines are not presented as an optimization of power planning for meeting Alaska's future loads, but it is believed that they represent a reasonable approach toward achieving economy in Alaska's power supply. 98 There are positive indications of significant sav- ings which can be realized through coordinated planning, design, and operation of the electric sys- tems. Furthermore, the availability of an abundant supply of low-cost electric power will promote eco- . nomic growth and development which is not likely to be achieved without the ready availability o~ this resource. We hope that the Survey will accelerate interest in more comprehensive electric utility industry plan- ning and promote greater emphasis on the coopera- tive and coordinated efforts by which economic gains can be realized by both the suppliers and users of electricity in Alaska. ,. I I ACKNOWLEDGMENTS The Federal Power Commission gratefully ac- knowledges the cooperation and assistance of the many people . who have contributed to the Al~ska Power Survey. In preparing the Survey report, we have depended largely upon the historical records, the future projections, and the many related ma- terials assembled by the members of the Alaska Advisory Committee and its four special subcom- mittees without whose help a comprehensive Survey would have been impossible. The names and affiliations of those who served on the Advisory Committee and Subcommittees at various times since their initial organization in August 1965 follow: ALASKA POWER SURVEY ADVISORY COMMITTEE Chairman: L. J. Schultz, Chugach Electric Asso- ciation, Inc. Co-Chairman: Carroll A. Oliver, Anchorage Mu- nicipal Light & Power Department Members: Lt. Col. John Brewer, Alaskan Command, De- partment of Defense Morris Chertkov, Alaska Public Service Commission William Corbus, Alaska Electric Light & Power Co. E. N. Courtney, Alaska Department of Commerce Col. Clare F. Farley, Corps of Engineers, U.S. Army Joseph H. Fi~zGerald, Field Committee for Development Planning in Alaska Donald E. Hall, Alaska Public Service Commission Ernest L. Hardin, Jr., Corps of Engineers, U.S. Army James Hendershot, Alaska Public Service Commission Phillip R. Holdsworth, Alaska Department of Natural Resources Mark Hunt, Fairbanks Municipal Utilities System 99 ·Lt. Col. David B. Keezell, Alaskan Command, Department of Defense Tho:mas E. Kelly, Alaska Department of Natural Resources Franz D. Nagel, Alaska Electric Light & Power Co. Gus Norwood, Alaska Power .Administration George N. Pierce, Bureau of Reclamation Herbert Purcell, Golden Valley Electric Asso- ciation, Inc. Burke Riley, Department of the Interior George Sharrock, Alaska Department of Commerce U. M. Staebler, Atomic Energy Commission Eugene C. Starr, Bonneville Power Adminis- tration Major Richard W. Towne, Alaskan Com- mand, Department of Defense Subcommittee for Economic Analysis and Load Projection Chairman: E. N. Courtney, Alaska Department of Commerce Members: Morris Chertkov, Alaska Public ServiCe Commission William Corbus, Alaska Electric Light & Power Co. J. H. FitzGerald, Field Committee for Devel- opment Planning in Alaska Lt. Col. D. B. Keezell, Alaskan Conimand C. A. Oliver, Anchorage Municipal Light & Power Department Burke Riley, Department of the Interior E. C. Starr, Bonneville Power Administration Subcommittee for Fuel Resources and Types of Generation Chairman: P. R. Holdsworth, Alaska Departinent of Natural Resources Members: Col. C. F. Farley, Corps of Engineers, U.S. Army J. H. FitzGerald, Field Committee for Develop- ment Planning in Alaska Herbert Purcell, Golden Valley Electric Asso- ciation, Inc. Burke Riley, Department of the Interior L. J. Schultz, Chugach Electric Association, Inc. U. M. Staebler, Atomic Energy Commission Subcommittee for Coordinated System Development and Interconnection Chairman: Eugene C. Starr, Bonneville Power Administration Members: William Corbus, Alaska Electric Light & Power Co. J. V. House, Alaska Power Administration Col. D. B. Keezell, Alaskan Command F. D. Nagel, Alaska Electric Light & Power Co. C. A. Oliver, Anchorage Municipal Light & Power Department 100 G. N. Pierce, Bureau of Reclamation H. C. Purcell, Golden Valley Electric Associa- tion, Inc. Burke Riley, Department of the Interior George Sharrock, Alaska Department of Commerce L. J. Schultz, Chugach Electric Association, Inc. E. B. Titus, Fairbanks Municipal Utilities System Subcommittee for Hydro Resources Chairman: George N. Pierce, Bureau of Reclama- tion Members: Col. C. F. Farley, Corps of Engineers, U.S. Army P. R. Holdsworth, Alaska Department of Nat- ural Resources r APPENDIX A Generating Plant Capacity-Ownership and Location, Alaska Electric Power Industry, Utility-Installations, Dec. 31, 1965 Installed kilowatts Load center number and location · Hydro Steam Diesel Other Total Northwest: Private total ................................................. . 0 0 (1) Barrow Utilities, Point Barrow .................................................... . (3) Nome Light & Power Utilities, Nome .............................................. . 0 250 2, 100 Municipal total ............................................... . 0 0 2, 350 0 0 (2) Kotzebue Electric Association, Inc., Kotzebue ....................................... . 1,400 ....... . Matanuska Electric Association, Inc., Unalakeet ................................... . 485 ....... . Point Hope Power and Light Cooperative, Point Hope .............................. . 40 ....... . Cooperative total .............................................. . Federal total .................................................. . Total Northwest Region .................................... . Southwest: 0 0 0 0 1, 925 0 0 0 4, 275 Aniak Power Co., Aniak ................... : ...................................... . 1 50 1 580 480 ( 4) Northern Commercial Co., Bethel. ........ , ....................................... . Northern Commercial Co., McGrath .............................................. . Private total .................................................. . Municipal total. .............................................. . 0 0 0 1, 110 0 0 (6) Naknek Electric Association, Inc., Naknek .......................................... . 1, 550 850 (5) Nushagak Electric Cooperative, Inc., Dillingham .................................... . Cooperative total .............................................. . Federal total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 2,400 0 0 Total Southwest Region.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 -0 3, 510 Southcentral: (10) Consolidated Utilities Ltd., Kenai .................................................. 2 2, 650 Private total ............................................... .".. . . . . . . . . . . . . . . . . . 2, 650 0 0 0 0 0 0 0 0 (12) Anchorage Light and Power Department, Anchorage ... , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 6, 536 2 3U, 260 (15) Cordova Public Utilities, Cordova.................................................. 2, 479 ....... . (10) Kenai City Light, Kenai ......................................................................... . ( 11) Seward Electric System, Seward. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 000 ....... . 0 250 2, 100 2, 350 1, 400 485 40 1, 925 0 4,275 50 580 480 1, 110 0 1,550 850 2,400 0 3,510 2,650 2,650 36, 796 2,479 so 3,000 ------------------------------ Municipal total ............................................... . 0 0 12,015 30,260 42,275 See footnotes at end of table. 101 Generating Plant Capacity-Ownership and Location, Alaska Electric Power Industry, Utility Installations, Dec. 31, 1965-Continued Installed kilowatts Load center number and location Hydro Steam Diesel Other Total (12) Chugach Electric Association Inc., Anchorage ........................ 15, 000 14, 500 2, 350 4 37, 550 Copper Valley Electric Association, Glenallen........................................ 1, 200 ....... . (14) Copper Valley Electric Association, Valdez.......................................... 896 ....... . (9) Homer Electric Association, Inc., Kasilof. .......................................................... . (8) Homer Electric Association, Inc., Seldovia.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 325 ....... . (7) Kodiak Electric Association, Kodiak.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 563 ....... . (13) Matanuska Electric Association Inc., Palmer ......................... : .............................. . Matanuska Electric Association Inc., Talkeetna ............................ , . . . . . . . . . . 406 ....... . 69,400 I, 200 896 so 1, 325 3,563 40 406 Cooperative total ............ -................................... 15,000 14, 500 9, 740 37, 550 76, 790 (12) USDI, Alaska Power Administration, Eklutna .. : ..................... 30,000 30,000 Federal total .................................................. 30,000 30,000 Total Southcentral Region .................................... 45, 000 14, 500 24,405 67, 810 I5I, 715 Interior: (16) Chatanika Power Company, Inc., Chatanika......................... 5, 625 ....................... . Fort Yukon Utilities, Fort Yukon.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300 ....... . Alaska Power and Telephone Co., Tok.............................................. I, 000 ....... . Private total. ................................................. . 5,625 0 I, 300 (16) Fairbanks Municipal Utilities, Fairbanks ................................... . 8,500 4 7, 000 5,625 300 1, 000 6,925 15, 500 Municipal total ................................................ . 0 8,500 0 7, 000 15, 500 (16) Golden Valley Electric Association, Fairbanks ............................... . 9,500 11, 745 Cooperative total. ............................................ . Federal total .................................................. . Total Interior Region ... : .................................... . Southeast: 0 9,500 11,745 0 0 0 5,625 18,000 13,045 0 0 7, 000 (19) A. J. Industries,7 Juneau .......................................... 7 8, 400 ....................... . (19) Alaska Electric Light & Power Co., Juneau. . . . . . . . . . . . . . . . . . . . . . . . . I, 600 . . . . . . . . 7, 086 ....... . Alaska Power & Telephone Co., Craig.............................................. 210 ....... . Alaska Power & Telephone Co., Hydaburg.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 ....... . (17) Alaska Power & Telephone Co., Skagway........................... 375 . . . . . . . . 465 ....... . (17) Haines Light & Power Co., Haines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 800 ....... . Pelican Utilities Co., Pelican.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 500 . . . . . . . . 225 ....... . Tongass Power & Light Co., Hyder ............................................................... . Yakutat Power Co.,u Yakutat ..................................................................... . 21,245 21,245 0 43,670 8,400 8,686 210 75 840 800 725 8 0 0 Private total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10, 875 0 8, 861 0 19,736 See footnotes at end of table. 102 Generating Plant Capacity-Ownership and Location, Alaska Electric Power Industry, Utility Installations, Dec. 31, 1965-Continued Load center number and location Installed kilowatts Hydro Steam Diesel Other Total (18) Hoonah, city of, Hoonah.......................................................... 200 ....... . 200 (23) Ketchikan Public Utilities, Ketchikan.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9, 800 . . . . . . . . 873 ....... . 10,673 3,000 3, 250 7,300 1,500 (24) Metlakatla Indian Communications, Metlakatla...................... 3, 000 ....................... . (21) Petersburg, city of, Petersburg. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2, 000 1, 250 ....... . (20) Sitka Public Utilities, Sitka ................... -:,.. . . . . . . . . . . . . . . . . . 6, 000 . . . . . . . . 1, 300 ....... . (22) Wrangell, city of, Wrangell... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 500 Municipal total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20, 800 0 5, 123 0 25,923 (19) Glacier Highway Electric Association, Inc., Auke Bay. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . to 0 Cooperative total. ............................................. . 0 0 0 0 0 0 0 0 0 0 Federal total ................................................. . Total Southeast Region ....................................... 31,675 0 13, 984 0 45,659 1 Estimate. 2 Natural gas-fired, oil to start. 3 PurchaSes all requirements from Consolidated Utilities, Ltd. 4 Gas-turbine capacity. 5 Purchases all requirements from Chugach Electric Association. 6 Purchases all requirements from Bureau of Reclamation, Eklutna project. 7 A. J. Industries, an industrial establishment, sells entire output of its hydroelectric plants to Alaska Electric Light & Power Co. s Purchases all requirements from British Columbia Elec- tric Co. at Stewart, British Columbia, Canada. 9 Yakutat Power Co. started operations in 1966 with 625 kw. of diesel-engine capacity. 10 Purchases all requirements from Alaska Electric Light & Power Co. 103 :I jl I Generating Plant Capacity-Ownership and Location, Alaska Electric Power Industry, Non utility Installations, Dec. 31, 1965 Installed kilowatts Organization and Location Hydro Steam Diesel Other Northwest: National defense- FAA, AIR t ...•......................................................... 8, 331. 0 ........ ACR, ACS, ACW I ..................................................... . 2, 888.0 Subtotal ............................................................. . II, 219. 0 Other- BIA .................................................................. . 2, 381. I ........ EDU,JOM ............................................................ . 41.4 ........ Subtotal. ............................................................ . 2,422.5 Total 8, 331. 0 2,888.0 11, 219. 0 2, 381. I 41.4 2, 422.5 Total nonutilities .................................. . 0 0 13, 641. 5 0 13, 641. 5 Southwest: National defense- FAA, AIR I ............................................................ . ACR, ACS, ACW I ........ ' ............................................ . U.S. Navy, Adak ....................................................... . Subtotal .................................................. , .......... . Other- BIA1 ................................................................. . EDU,JOM ............................................................ . Subtotal ............................................................. . 28, 122. 0 3, 655.0 15,900.0 47,677.0 3, 516. 5 305.0 3, 821. 5 Total nonutilities .................................. . 0 0 51,498.5 Southcentral: National defense- FAA, AIRI ............................................................ . ACR, ACS, ACW I ..................................................... . U.S. Air Force, Elmendorf Air Force Base.......................... 22, 500 U.S. Army, Fort Richardson..................................... 18,000 U.S. Navy, Kodiak............................................. 4, 000 Subtotal .................................................... . 44,500 Other- BIA .................................................................. . EDU,JOM ............................................................ . Subtotal. ............................................................ . Total nonutilities .................................. . 0 44,500 See footnote at end of table. 104 4, 946.8 6, 115. 0 I, 600.0 6, 100.0 18, 761. 8 80.0 474.0 554.0 19,315. 8 •••••• 0. • • • 0 • • • • ........ ........ 28,122.0 3, 655.0 15, 900. 0 47,677.0 3, 516. 5 305.0 ~. 821. 5 0 51,498.5 ........ . ....... . . . . . . . . 0 4,946.8 6, '115. 0 24, 100.0 24, 100.0 4, 000.0 63, 261. 8 80.0 474.0 554.0 63,815. 8 Generating Plant Capacity-Ownership and Location, Alaska Electric Power Industry, Nonutility Installations, Dec. 31, 1965-Continued Installed kilowatts Organization and Location Hydro Steam Diesel Other Interior: National defense- FAA, AIR 1 •••••• • • · · • • • · · · • · • • · · • • · · · · · • · · ..........••..•••..•••••..••• 12,987.4 ....... . ACR, ACS, ACW 1 • . • . . • • • • • • • • . . . . . . . . . . . • . . . . • . . . . . • • . . • • . • . . . • • • • • • • . 4, 155. 0 ....... . U.S. Air Force, Eielson Air Force Base ....... -...................... 10,000 5, 000.0 ....... . U.S. Air Force, Clear Air Force Base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22, 500 . . . . . . . . . . . NU U.S. Army, Fort Greely .......... · · · · · · ·. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 800.0 2, 000 U.S. Army, Fort Wainwright..................................... 23,500 3,500. 0 ....... . Total 12,987;4 4,155.0 15,000.0 22,500.0 5,800.0 27'006. o·· • : :~ < Subtotal ........... · · · · .. · · · · · · · · · · · · · · · · · · · · · · · · · · ·.. . . . . . . . 56,000 29,442.4 2, 000 87,442.4 Other- University of Fairbanks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 000 ................... . BIA.......... ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 377.5 ....... . 3,000.0 . '377.5' EDU,JOM............................................................. 128.5 ....... . 128.5 Subtotal ....................................... ······ ........ . 3,000 506.0 3,506.0 Total nonutilities .................................. . 0 59,000 29,948.4 2,000 90,948.4 Southeast: National defense- FAA, AIR I .•••....................................................•.... ACR, ACS, ACW t •...•............••......••......••..••.•.........•••• Subtotal .................. , .......................................... . Other- 1, 619.7 2,455.0 4,074. 7 BIA 1. . • . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924. 0 ....... . EDU,JOM............................................................. 0 ....... . Alaska Lumber and Pulp, Sitka... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15, 000 .................. . Ketchikan Spruce Miiis, Ketchikan ....... ~ . . . . . . . . . . . . . . . . . . . . . . . 900 .................. . Ketchikan Pulp Co., Ketchikan................................... 20,000 750.0 ....... . Subtotal ......... ·. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35, 900 1, 674.0 1, 619. 7 2,455.0 4,074. 7 924.0 0 15,000.0 900.0 20,750.0 37,574.0 Total nonutilities .................................. . 0 35,900 5, 748. 7 0 41,648.7 Alaska total: National defense 2 ••• ••• • • • • • • • • • • • . • • • • • • • • • • . • • . . • . • • • • • • • . • • . • • • • • • 100, 500 104, 474. 9 2,000 206,974.9 0 47, 878. 0 Other. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38, 900 8, 978. 0 Total nonutilities......................................... 0 139,400 120, 152.9 . 2, 000 261,552.9 Small industrial (approximately).................................................................. 4, 167. 1 Grand total, non utilities ........................................................ ·. . . . . . . . . . . . . . . 265, 720. 0 1 Various remote sites. munication sites. 2 Including Federal Com- FAA-Federal Aviation Agency. AIR-Alaskan Air Command (AAC). ACR-Alaskan Communication Region. 105 ACS-Alaskan Communication System. ACW-Aircraft Control and Warning. BIA-Bureau of Indian Affairs. EDU-Department of Education. ]OM-Johnson O'Malley School. NU-Nuclear. Generating Plant Capacity-Ownership and Location, Alaska Electric Power ·Industry, Utility and Non utility Installations, Summary-Dec. 31, 1965 Installed kilowatts Organization and Location Hydro Steam Northwest: a. Utility.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 b. Nonutility.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 Subtotal............................................ 0 Southwest: a. Utility... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 b. Nonutility.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 Subtotal............................................ 0 Southcentral: a. Utility ................................................ 45,000 b. Nonutility. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 Subtotal ....................... : . . . . . . . . . . . . . . . . . . . . 45; 000 Interior: a. Utility ............................................... . b. Non utility ................. · ........................... . Subtotal ........................................... . Southeast: 5,625 0 5,625 a. Utility ................................................ 31, 675 b. Nonutility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 Subtotal ............................................ 31,675 Small industrials throughout State: b. Nonutility (approximately).............................. 1, 197 Alaska: a. Total utility ........................................... 82, 300 b. Total non utility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 197 Total Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83, 497 1 Gas turbine. 2 Nuclear. 106 0 0 0 0 0 0 14, 500 44,500 59,000 18,000 59,000 77,000 0 35, 900 35,900 1, 385 32,500 140, 785 173, 285 Gas tur- Diesel bine and nuclear 4,275 0 13, 642 0 17, 917 0 3, 510 0 51,499 0 55,009 0 24,405 1 67, 810 19, 316 0 43,.721 67, 810 13, 045 1 7, 000 29,948 2 2, 000 42,993 9,000 13,984 0 5, 749 0 19, 733 0 1,585 0 59,219 1 74, 810 121, 739 2 2, 000 180, 958 76,810 Total 4,275 13,642 17, 917 3,510 51,499 55,009 151, 715 63,816 215,531 43,670 90,948 134, 618 45,659 41,649 87,308 4, 167 248,829 265, 721 514, 550 APPENDIX B Annual Electric Power Requirements, Number of Customers and Use Per CustQmer, Electric Util!ty Systems, Total Alaska · Category of use 1950: Customers t (number) Annual average energy use per customer (kilowatt- hours) Residential (nonfarm)..................................... 19,850 2, 700 Irrigation and drainage...... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 Farm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 408 1, 590 Commercial..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2, 621 11,930 Industrial. .............................................................. , ....... . Other uses ...................................................................... . Total consumption ............................................................. . Losses and unaccounted for ....................................................... . Total energy for load ........................................................... . 1955: Residential (nonfarm)..................................... 37,029 2, 690 Irrigation and drainage..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 Farm ............................... ·.................... 445 4,050 Commercial.............................................. 5, 351 16,430 Industrial. ...................................................................... . Other uses ...................................................................... . . Total consumption ............................................................. . Losses and unaccounted for ....................................................... . Total energy for load ............................. · .............................. . 1960: Residential (nonfarm)..................................... 40,580 4, 140 Irrigation and drainage.' . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 Farm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 370 6, 900 Commercial..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6, 446 16, 850 Industrial. ...................................................................... . Other uses ...................................................................... . Total consumption ............................................................. . Losses and unaccounted for ....................................................... . Total energy for load ........................................................... . See footnote at end of table. 107 Energy· use (gigawatt• hours)· 54 0 0.65 31 3.5 13 102 13.0 115 99 0 1.8 88 18 18 225 25 250 167 0 3 109 56 17 352 40 392 89 11 100.0 40 0 35 7 7 90 10 100 43 0 1 28 14 4 90 10 100 Annual Electric Power RE!'quirements, Number of Customers and Use Per Customer, Electric Utility Systems, Total Alaska-Continued Category of use 1965: Customers 1 (number) Annual average energy use per customer (kilowatt- hours) Residential (nonfarm)..................................... 49,672 5, 677 Irrigation and drainage....... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 Farm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 425 11,764 Commercial.............................................. 7, 972 29,353 Industrial ....................................................................... . Other uses ...................................................................... . Total consumption .............................................................. . Losses and unaccounted for ....................................................... . Total energy for load ........................................................... . 1975: Residential (nonfarm) .................................... . 80,000 9, 125 Energy use (gigawatt- hours) 282 0 5 234 75 49 645 75 720 730 Energy use (percent of total) 39 0 0. 7 33 10 7 90 10 100 40 Irrigation and drainage ................................................................................... . Farm................................................... 627 14,350 9 0. 5 Commercial.............................................. 12,400 37, 100 460 25 Industrial ....................................................................... . 350 19 Other uses .............................................................. · ........ . 102 5.5 Total consumption ............................................................. . 1, 651 90 Losses and unaccounted for ....................................................... . 190 10 Total energy for load ........................................................... . I, 841 100 1985: Residential (nonfarm) .................................... . 122, ·100 14,000 1, 710 36 Irrigation and drainage· ................................................................................... . Farm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 830 30, 120 25 0. 5 Commercial.............................................. 19,000 46, 840 890 18.5 Industrial. ...................................................................... . Other uses ...................................................................... . Total consumption ............................................................. . Losses and unaccounted for ....................................................... . Total energy for load ........................................................... . 1, 360 340 4,325 490 4, 815 28 7 90 10 100 1 Farm customer category adjusted in attempt to show billing may place them in residential and commercial number of farms actually served by electric utilities although categories. 108 , U.S. GOVERNMENT PRINTING OFFICE' 1969 Q-339--844