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HomeMy WebLinkAboutUpper Susitna River project Power Market Analyses- March 1979This report is included as Section G, Appendix - Part 2 of the Southcentral Railbelt Area, Alaska, Upper Susitna River Basin, Supplemental Feasibility Report by the Corps of En- gineers, revised February 1979. e,L� I " U10--i Department Of Energy Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 April 2, 1979 Colonel George R. Robertson District Engineer, Corps of Engineers P.O. Box 7002 Anchorage, Alaska 99510 Dear Colonel Robertson: This is Alaska Power Administration's new power market report for the Upper Susitna Project. It's an update of the previous power market analyses provided for the Corps' 1976 Interim Feasibility report. The power market report includes: a new set of load projections for the Railbelt area through year 2025 and a review of alternative sources of power. Load/resourceand total .power system cost analyses were prepared for different scenarios under various assumptions to determine effects on power. rates. Under .the assumptions made for this report, Alaska Power Administration determines that the Upper Susitna Project is feasible from a power marketing standpoint. A draft of this report was circulated to the area utilities and con cerned State officers for informal review and comment. Comments hav6 been incorporated and the letters of comments are appended. Sincerely, j Robert J. Cross Administrator CONTENTS TITLE PAGE NO. PART I - INTRODUCTION ...................................... 1 PART II - SUMMARY ......................................... 3 PART: III - POWER MARKET AREAS ............................. 7 Anchorage -Cook Inlet .................................... 7 Fairbanks -Tanana Valley ................................. 8 PART IV - EXISTING POWER SYSTEMS .......................... 10 Utility Systems and Service Areas ....................... 10 National Defense Power Systems 12 Industrial Power Systems ................................ 13 Existing Generation Capacity ............................ 13 Planned Generation Capacity ............................. 15 PART V - POWER REQUIREMENTS ............................... 16 Introduction ............................................ 16 Data .................................................... 16 Analysis Utility .... ........ ......... 23 National Defense ..................................... 33 Self -Supplied Industry ............................... 33 Energy & Power Demand Forecasts ........ 33 Assumptions and Methodology ..................... 33 Population ................................. 33 Utility ...... 33 National Defense ........................... 36 Self -Supplied Industry ..................... 36 Estimate of Future Demands ..................... 38 Comparison With Other Forecasts ................. 38 Load Distribution ..... ......... ...... ........... 55 Capacity Requirements .................................... 61 PART VI ALTERNATIVE POWER SOURCES 63 Introduction ............................................ 63. Alternatives Considered ................................. 63 Coal .................................................. 63 Location ........................................ 63 Capacity ......................................... 64 Investment. Costs ................................ 64 Fuel Cost and Availability 67 Cost of Power ...... 70 Comparative. Cost of Power (FERC) 70 Oil and Natural Gas .................................. 71 Hydro ................................................ 71 Criteria ...................................... 71 Single Large Capacity Sites ..................... 71 Combinations of Small Capacity Sites 72 Summary ............................ 73 i CONTENTS (Continued) Title Page No. Nuclear .............................................. 73 Wind ................................................. 73 Geothermal ........................................... 73 Tide ................................................. 73 Conclusion .............................................. 74 PART VII - LOAD/RESOURCE AND SYSTEM COST ANALYSES ......... 75 Introduction ... ......................................... 75 Basic Data and Assumptions .............................. 75 Study Methodology 77 Results .............................................. 79 Load/Resource Analyses ................. 79 System Power Costs ................................... 79 PART VIII - INVESTMENT COSTS .............................. 86 PART IX - OPERATION, MAINTENANCE, AND REPLACEMENT PLAN AND COSTS ..................................... 89 Operation and Maintenance 89 Plan Description ........................... 89 Marketing and Administration .. 90 Annual Costs .,:...................................... 9.0 Replacements ....... .. 91 PART X - FINANCIAL ANALYSIS .. 97 Market for Project Power ................................ 97 Cost of Project .... • .......................... 98 Average Rate Determination • 101 Power Marketing Considerations ....................... 102 Market Aspects of Other Transmission Alternatives ....... 105 Anchorage -Cook Inlet Area . ••105 Comparison of Susitna to SteamplantsWithand Without Inflation .......................................... 106 PART XI - GLENNALLEN-VALDEZ AREA 108 Introduction ............................................ 10.8 Power Market Area ....................................... 108 Power Requirements.109 Transmission Plan and Cost • . . 110 Operation and Maintenance Cost... ........ 114 Assessment of Feasibility ... .. ................ 116 APPENDIX ............... ........ . ..... ..... 117 1. Letter dated January 3, 1979 to Col. G.R. Robertson, Alaska District Corps of Engineers, transmitting responses to OMB questions falling in APA's area of responsibility., ii 2. Previous Studies and Bibliography. 3. LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION OF ALASKA: 1978=2010 --Informal Report-- by Battelle Pacific Northwest Laboratories, Richland, Washington - January, 1979. 4. Comments. a. Federal Energy Regulatory Commission, San Francisco, California. b. Battelle Pacific Northwest Laboratories, Richland, Washington. c. Corps of Engineers, Anchorage, Alaska d. The Alaska State Clearinghouse, Juneau, Alaska e. Municipal Light and Power, Anchorage, Alaska TABLES NUMBER PAGE NO. 1. RAILBELT AREA GENERATION CAPACITY SUMMARY - 1977 ...... 14 2. BASIC POWER AND ENERGY FORECASTING DATA ANCHORAGE -COOK INLET AREA (INCLUDING SEWARD) .......... 18 3. BASIC POWER AND ENERGY FORECASTING DATA FAIRBANKS-TANANA VALLEY AREA .......................... 19 4. BASIC POWER AND ENERGY FORECASTING DATA RAILBELT AREA (ANCHORAGE -COOK INLET AND FAIRBANKS-TANANA VALLEY) .............................. 20 5. NET GENERATION (GWH) ANCHORAGE -COOK INLET AREA ............................. 21 6. NET GENERATION (GWH) FAIRBANKS-TANANA VALLEY AREA .......................... 22 7. AVERAGE ANNUAL UTILITY GROWTH SUMMARY ................. 26 8. POPULATION ESTIMATES 1980-2025 ........................ 34 9. • NET ANNUAL PER CAPITA GENERATION (KWH) RAILBELT AREA UTILITIES ................................. 39 10. POWER AND ENERGY REQUIREMENTS (ANCHORAGE -COOK INLET AREA) ........................... 40 11. POWER AND ENERGY REQUIREMENTS (FAIRBANKS-TANANA VALLEY AREA) ........................ 43 12. RAILBELT AREA POWER AND ENERGY REQUIREMENTS ANCHORAGE -COOK INLET AREA AND FAIRBANKS-TANANA VALLEY AREACOMBINED ......................................... 46 13. COMPARISON OF UTILITY ENERGY ESTIMATES, 1975 MARKETABILITY REPORT, UPDATE OF 1975, AND 1978 ANALYSIS ..................................... 49 14. UTILITY ENERGY FORECASTS (GWH) ANCHORAGE -COOK INLET AREA ............................. 52 15. UTILITY PEAK DEMAND FORECASTS (MW) ANCHORAGE -COOK INLET AREA ............................. 53 16. UTILITY ENERGY AND PEAK DEMAND FORECASTS FAIRBANKS-TANANA VALLEY AREA .......................... 54 iv TABLES (Continued) NUMBER PAGE NO. 17, LOAD DISTRIBUTION CHARACTERISTICS MONTHLY PEAK LOADS AND LOAD FACTORS ................... 59 18. MONTHLY ENERGY REQUIREMENTS AS PERCENT OF ANNUAL REQUIREMENT ........................................... 60 19. COMPARISON OF INVESTMENT COSTS FOR COAL-FIRED STEAMPLANTS........................................... 65 20. GENERATION COSTS FOR CONVENTIONAL COAL-FIRED STEAMPLANTS........................................... 69 21. SUMMARY OF THERMAL GENERATING CAPACITY ADDITIONS TO THEYEAR 2010......................................... 78 22. ANNUAL POWER SYSTEM COSTS - 0% INFLATION (COMBINED ANCHORAGE -COOK INLET AND FAIRBANKS-TANANA VALLEY AREAS) ................................. 81 23. AVERAGE POWER COSTS ANCHORAGE -COOK INLET AREA - 0% INFLATION .................................... 83 24. AVERAGE POWER COSTS - 0% INFLATION FAIRBANKS-TANANA VALLEY AREA .......................... 84 24a. COMBINED ANCHORAGE -COOK INLET AND FAIRBANKS-TANANA VALLEY AREA AVERAGE ANNUAL POWER COSTS ................ 85 25. CONSTRUCTION COST SUMMARY ............................. 87 26. INVESTMENT COST SUMMARY 88 27. ANNUAL OPERATION AND MAINTENANCE COST ESTIMATE ........ 92 28. OPERATION AND MAINTENANCE COST SUMMARY ................ 95 29. REPLACEMENT COSTS ........ 96 30. MARKET FOR UPPER SUSITNA POWER (ANCHORAGE AND FAIRBANKS AREAS) MEDIUM LOAD GROWTH ESTIMATES ......... 99. 31. INVESTMENT AND OM&R COST SUMMARY ...................... 100 32. COST SUMMARY COMPARISON WITH 1976 INTERIM FEASIBILITY REPORT .................................... 103 33. AVERAGE RATE DETERMINATION (WATANA AND DEVIL CANYON) 1044. MIA TABLES (Continued) NUMBER PAGE NO. 34. HISTORIC DATA (GLENNALLEN-VALDEZ AREA) ................ 111 35. UTILITY NET GENERATION (GWH) (GLENNALLEN-VALDEZ AREA) .............................. 112 ,y 36. UTILITY FORECASTS (VALDEZ-GLENNALLEN AREA) ............ 113 37. TRANSMISSION SYSTEM INVESTMENT COST SUMMARY (GLENNALLEN-VALDEZ AREA) .............................. 114 38. TRANSMISSION SYSTEM OPERATION, MAINTENANCE, AND REPLACEMENT COST SUMMARY (GLENNALLEN-VALDEZ AREA) ..... 115 o vi FIGURES NUMBER 1. UPPER SUSITNA RIVER BASIN PROJECT FEATURE SITE LOCATION ................................. 2. UPPER SUSITNA RIVER PROJECT AREAS PRESENTLY SERVEDBY RAILBELT UTILITIES .......................... 3. ENERGY SECTOR RATIOS ANCHORAGE -COOK INLET AREAS AND ANNUAL ENERGY GENERATED OR SOLD ANCHORAGE -COOK INLET AREA.................................................. 4. ANNUAL ENERGY USE PER CAPITA & PER CUSTOMER ANCHORAGE -COOK INLET AREA ............................. 5. ANNUAL POPULATION, EMPLOYMENT, AND UTILITY CUSTOMERS ANCHORAGE -COOK INLET AREA . ...... . 6. ENERGY SECTOR RATIOS FAIRBANKS-TANANA VALLEY AREA AND ANNUAL ENERGY GENERATED OR SOLD FAIRBANKS-TANANA VALLEY AREA ........................................... 7. ANNUAL ENERGY USE PER CAPITA AND PER CUSTOMER FAIRBANKS-TANANA VALLEY AREA .......................... 8. ANNUAL POPULATION, EMPLOYMENT, AND UTILITY CUSTOMERS FAIRBANKS-TANANA VALLEY AREA .......................... 9. ENERGY FORECAST ANCHORAGE -COOK INLET AREA ............. 10. PEAK LOAD FORECAST ANCHORAGE -COOK INLET AREA .......... 11. ENERGY FORECAST FAIRBANKS-TANANA VALLEY AREA .......... 12. PEAK LOAD FORECAST FAIRBANKS-TANANA VALLEY AREA ... 13. TOTAL RAILBELT AREA ENERGY FORECAST ................... 14. TOTAL RAILBELT AREA PEAK LOAD FORECAST ................ 15. SYSTEM DAILY GENERATION CURVE ANCHORAGE AREA 1976 ..... 1:6. SYSTEM DAILY GENERATION CURVE ANCHORAGE AREA 1977-78 .. 17. LOAD DURATION CURVE - 1977 ANCHORAGE AREA ............ 18. ANNUAL POWER SYSTEM COSTS WITH AND WITHOUT SUSITNA COMBINED ANCHORAGE -COOK INLET AND FAIRBANKS-TANANA VALLEY................................................ 1.9. COMPARISON OF SUSITNA AND ALTERNATIVE COAL-FIRED STEAMPLANT RATES CONSIDERING 5% ANNUAL INFLATION ...... vi i PAGE NO. 11 27 28 29 30 31 32 41 42 44 45 47 48 56 57. 58 82 107 C7 VICINITY MAP 2-230 KV TRANSMIMISSIC LINES 2-345 TRANSMISSION LINES % 1 IRBANKS Figure 1 t2;OFLTA HEALY ' DEVIL CANYON /DA[vi S I TE�4 � �-.. VIA AN DAM S 11E`-----' APA 12/78 PART I. INTRODUCTION The Interim Feasibility Report of the Upper Susitna River Basin Project (1976 report) was completed by. the Alaska District Corps of Engineers (Corps) in 1976. Alaska Power Administration (APA) provided the trans- mission system and power market analyses for that report. The Corps submitted the 1976 report to the Office of Management and Budget (OMB) for, review. In September 1977, OMB requested the Corps obtain additional data before submitting the report to Congress. The requested data were to: (1) provide additional geologic data for the Watana damsite; (2) reanalyze the cost estimate contingency factor; (3) reanalyze area development benefits; and (4) reanalyze the projected construction schedule. There were also questions about power supply and demand, including; sensitivity to developing a large block of power in APA's area of responsibility. This report updates the power market analysis and addresses OMB concerns. It uses three years additional data on power usage, effects of the oil embargo, and other factors. Specifically, it (1) updates the. power demand forecasts reflecting data since the 1976 report; (2) updates the transmission and project OM&R costs; (3) presents load/resource analyses to determine timing of major generation and transmission investments and reflect resulting impacts on power system costs; (4) presents system power cost analyses that show annual system -wide costs of power with and without the Upper Susitna Project; (5) examines the value of an Anchorage to Fairbanks interconnection with and without Susitna; (6) provides a subanalysis of the feasibility of delivering Susitna power to the Valdez-Glennallen area; (7) determines power rates and marketability of Susitna power compared with alternative generation methods; and (8) responds to the OMB questions in APA's areas of responsibility. APA gave the Corps, for their report purposes: updated transmission system costs and project OM&R estimates; load estimates; detailed load/resource and system cost analyses with and without Susitna project; and proposed responses to OMB questions pertinent to APA areas of responsibility. The. Corps' current proposal for the Upper Susitna Project is essentially the same as plan 5 in the 1976 report: a two-phase, two -dam complex including Watana and Devil Canyon dams and powerplants, with the Watana phase and._a.,.transmission system interconnecting Anchorage and Fairbanks coming on-line first. Power production facilities include Watana dam, reservoir, and powerplant, and Devil Canyon dam, reservoir, and powerplant. Watana dam would be an earthfill structure with reservoir. normal water surface elevation of 2,185 feet; the powerplant would have 795 MW capacity. Devil Canyon dam would be a double -curvature concrete -arch structure with maximum pool elevation of 1,450 feet, providing water for a 778-1AW powerplant. The transmission system would be constructed in conjunction with the first stage (Watana), and, 1 as planned, would be totally required for system reliablilty. The system would incude two parallel 230-kv single circuit lines from Watana to Devil Canyon (30 miles), two parallel single circuit 345-I.v lines from Devil Canyon to Pt. McKenzie (Anchorage, 135 miles), and two parallel single circuit 230-kv lines from Devil Canyon to Ester -Gold Hill (Fairbanks, 198 miles). Several significant changes were made by the Corps since the 1976 report: (1) The Devil Canyon dam design and costs are presented for both a gravity structure and a thin -arch concrete structure. The 1976 report was based on a thin -arch concrete structure. (2) The construction period for Watana was increased from 6 years to 11; Devil Canyon from 4 years to 7; and the Anchorage -Fairbanks intertie re -scheduled for 1991--three years before Watana POL. (3) Watana dam (earth fill) was redesigned, based on new geologic data. The APA power market report uses certain assumptions that differ from the Corps plan, namely: (1) Design power generation capacity; The Corps design capacity is based on critical year primary energy and 50 percent annual plant factor (1,392 M. The APA load/resource analyses assume a design capacity based on average annual energy and 50 percent plant factor (1,573 MW). APA analyses include both primary and secondary energy as well as firm and agn-firm power. (2)- Transmission intertie schedule: The Corps plans show a 1991 on-line date for the transmission intertie. The APA system cost analyses examine alternative on-line dates of 1990, 1992, and 1994. The load/resource analysis showed the earliest intertie dates could be 1986, 1989, and 1991. APA financial analyses are consistent with the Corps schedule. (3) For Devil Canyon Design: The APA. system cost and financial analyses assume the thin -arch design for Devil Canyon as presented in the 1976 report, rather than the more costly gravity structure alternative now being used by the Corps for feasibility testing. A separate analysis demonstrates the effect of the gravity dam alternative on cost of power. The term "1976 report" is used throughout this report. This term refers to the Corps of Engineers Interim Feasibility Report on the Upper Susitna project, dated Decembpr 1975, revised June 1976. It also refers to APA's Power Market analysis dated 1975 and included as Appendix G in the revised Interim Feasibility Report. 2 Part II. SUMMARY Current studies have updated and revised the power market analyses of the 1976 Upper Sustina Report (1976 report). New estimates of power requirements through the year 2025 have been prepared. The 1976.report used energy and power estimates based on data through December 1974. The new analyses benefit from three full years of additional data through December 1977. This provides a full four years of "post oil -embargo" data --especially significant from the viewpoint of identifying conservation trends. Evidence of conservation shows in the Anchorage -Cook Inlet area growth comparisons before and after the. 1973-74 fuel crisis. The 1970-73 average annual growth in net generation dropped from 14.2 percent to 12.7 percent in the 1973-77 period. The decrease was more dramatic for per capita net generation: A drop from 8 percent to 3.8 percent. Because the net generation kwh/capita raio seemed to reflect the closest correlations, particularly in recent years, this ratio and population were used to forecast net generation values between 1980 and 2025. The following Railbelt totals are detailed in Part V. Trended values offer an interesting comparison but are not presented as part of the forecast. The trend is an average annual growth of 12.3 percent resulting from 12.7 percent for the Anchorage area and 10.5 percent for the Fairbanks area. Railbelt Area Energy Forecast (GWH) 1977 1980 1990 2000 2025 (Historic) Utility: High 3,410 8,200 16,920 38,020 Mid 2,273 3,155 6,110 10,940 17,770 Low 2,920 4,550 7,070 8,110 National Defense: High 348 384 425 544 Mid 338 338 338 338 338 Low 330 299 270 210 Self -Supplied. Industry: High 170 2,100 3,590 8,490 Mid 70 170 630 1,460 3,470 Low 141 370 550 1,310 Total: High 31928 10,684 20,935 47,054 Mid 2,681 3,663 7,078 12,738 21,578 Low 3,391 5,219 7,890 9,630 Trend @ 1973-77 annual/growth : (3,215) (10,270) (33,000) (601,000) 3. Area load characteristics data were updated and new estimates of monthly energy distribution were made. The conclusion was that the 50 percent plant factor sizing assumption is still valid. A further review of possible power supply alternatives included oil and natural gas, coal, alternative' hydro projects, nuclear, wind, geothermal, and tide. It concluded again that coal-fired steam plants are the most logical alternatives for major railbelt area power supplies in the proposed Susitna project timeframe. New estimates of cost of power from coal-fired steamplants were prepared using results of several recent studies. They indicate: Investment costs of $1,620-$1,860/kw Unit cost of power of 5.2-6.4e,/kwh (including transmission to load center) A set of load/resource and annual system cost analyses were performed to examine the -effects of Susitna and the transmission intertie from an overall power system approach. These analyses were needed to provide responses to OMB questions regarding: (1) the value of an interconnected transmission system between Anchorage and Fairbanks; (2) scheduling of major powerplants; and, (3) sensitivity of developing large blocks of power. APA's response to the OMB questions are appended. Three cases were analyzed using three projected load growth estimates: Case 1. A without Susitna Project and without transmission intertie situation assuming all generating capacity to be supplied by coal-fired steamplants. Case 2. Same as case 1 but with transmission intertie. Case 3. A with Susitna Project and with intertie situation assuming additional generating capacity supplied by coal-fired steamplants. Theload/resource'analyses showed the schedule of new plant additions needed for all three cases for 1978-2011. The system cost analyses compared annual power system costs for all three cases, assuming 0 and 5 percent inflation rates. The analyses showed annual system cost savings of $2.23 billion between 1990 and 2011, with the Susitna project. Average power system rates for the year 2000 assuming no inflation will be: 4 Lo ad Forecast High Mid Low Case 1 Without Susitna or Intertie 6.6 1/ 6.9 1/ 7.5 1/ c'/KWH Case 2 Case 3 Without Sustina With Susitna With Intertie and Intertie 6.4 5.8. 6.6 5.7 6.7 6.4 l/ Anchorage and Fairbanks are not interconnected for case 1; the combined system rate is shown for academic purposes. only. For the medium energy use range, system rates, compared to those without Susitna or interconnections, will be 5.71/ percent less with interconnections 18.6 percent less with Susitna.— The analyses showed Susitna will result in cheaper power cost to Anchorage and-Tairbanks in all load growth cases. It also shows that the wi ect power could be fully used under all projected power demand cases.— In comparison with the 1976 report, investment costs are 89 percent ($1.567 billion) greater. Contributing factors are: interest rate increase from 6 5/8 to 7 1/2 percent total construction period increase from 6 years to 10 years, cost inflation; and redesign of Watana dam and powerplant facilities. New construction cost estimates for Watana dam (containing effects of both design quanitity changes and unit cost inflation) are $595 million (72 percent) higher. Construction cost estimates for Devil Canyon dam (thin -arch concrete) power plant facilities, and the transmission system were updated primarily by indexing. This resulted in a 54 percent increase over the 1976 report ($233 million for Devil Canyon and $82 million for the transmission system). The total interest during construction increase is 265 percent ($657 million). In summary, the increases in construction costs are: Watana $ 595 million Devil Canyon 233 it Transmission System 82 it Interest during Construction 657 if Total $1567 million project investment cost increase Financial analyses were based on the October 1978 price level, Fiscal Year 1979 Federal interest rate of 7 1/2 percent, Intertie in 1991 or 1992; and repayment of all principal and interest within 50 years after the last unit is installed. 1/ Case 2 Value (6.6%) -1 = -5.7%;.Case 3 Value (5.7%) -1 = -18.6% Case 1 Value (7.0%) Case 1 Value (7.0%) 2/ Interconnection benefits leading to lower rates involve load supply flexibility, economics of scale and operations, decreased reserve requirements, and better reliability. 5 A comparison of the rate for Sustina at 4.7(,I/kwh with the coal-fired steamplant alternative at 5.2/kwh to 6.4�/kwh shows Susitna is less costly. The Glennallen-Valdez area was considered as a market area supplementary to the Railbelt. The.Copper Valley Electric Association (CVEA) plans to construct a Glennallen-Valdez transmission line, and the presence of the pipeline terminal in Valdez with its related economy has made this area a more attractive market since the 1976 report. Service to the area would require a 138-kv line from Palmer to Glennallen (136 miles). Area market factors are subject to fluctuation. Potential industrial loads are difficult to project at this time, but service to utility loads can be evaluated for a probable range of demands. Energy costs to serve the incremental market area will range from 2.6c/kwh to 1.3�/kwh for a range of loads from 150 to 300 kwh/year in addition to the project energy cost of '4.70,/kwh. Inclusion of the market area costs with other project costs for a single project -wide rate would not adversely affect the rate. 2 PART III. POWER MARKET AREAS Throughout its history of investigations, the Upper Susitna River Basin Project has been of interest for hydroelectric power generation because of its central location to the Fairbanks and Anchorage areas. These areas have Alaska's largest concentrations of population, economic activity, services, and industry. Under any plan of development, major portions of the project power will be used in these two areas. In addition, the basic project transmission system serving Anchorage and Fairbanks could provide electric service to present and future developments between the two cities. The potential major market areas are the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area. Anchorage -Cook Inlet Area This area includes the developed areas of the Matanuska Valley, Greater Anchorage Area, and Kenai Peninsula. This general area has been the focal point for most of the State's growth in terms of population, business, services, and industry since World War II. Major building of defense installations, expansion of government services, discovery and development of natural gas and oil in the Cook Inlet area, and emergence of Anchorage as the State's center of government, finance, travel, and tourism are major elements in the history of this area. Because of its central role in business, commerce, and government, the Anchorage area is directly influenced by economic activity elsewhere in the State. Much of the buildup in construction and operation of the Alyeska pipeline, much of the growth related to Cook Inlet oil development, and much of the growth in State and local government services since Statehood has occurred in the immediate Anchorage vicinity. Initially,- economists overestimated the impacts of completion of the trans -Alaska oil pipeline. In a recent study prepared by the University of Alaska Institute of Social and Economic Research, the projected 1980 population for Anchorage -Cook Inlet was lower than that of the historical 1977 population., Though this has been corrected, it indicates that the area's economy has been stronger than anticiapted. The Greater Anchorage Area Borough estimated its July 1, 1977 population at 195,800, an increase of nearly 55 percent since the 1970 census. This was more than 48 percent of the total estimated State population in 1977. 7 The Matanuska Valley includes several small cities (Palmer, Wasilla, Talkeetna) and the State's largest agricultural community. Other economic activities include recreation and light manufacturing. Much recent growth in the Borough has been in residential and recreational homes for workers in the Anchorage area. Estimated 1977 population was 15,740, a 61 percent increase since 1974. The Kenai Peninsula Borough includes the cities of Kenai, Soldotna, Homer, Seldovia, and Seward. with important fisheries, oil and gas, and recreation resources. Estimated 1977 population was 23,100, a 39 percent increase since 1974. Present and proposed activities indicate likelihood of rapid growth in this general Cook Inlet area for the future. Much of this activity is related to oil and natural gas, including expansion of the refineries. The State capital city site relocation issue remains unresolved. In the November 1978 general election, voters turned down the $966 million bond issue to relocate the capital. In the same election, voters approved an initiative which would require full disclosure of the costs to move the capital. Therefore, it is impossible at this time to include specific assumptions concerning the capital move. The area will continue to serve as the transportation hub of western Alaska, and tourism will likely continue to increase rapidly. Major local development seems probable. Fairbanks -Tanana Valley Area' Fairbanks is Alaska's second largest city - the trade center for much of Alaska's Interior, the. service center for several major military bases, and the site of the main campus of the University of Alaska with its associated research center. The outlying communities of Nenana, Clear, North Pole, and Delta Junction are included in the Fairbanks -Tanana Valley area. Historically, the area is famous for its gold. s The completion of the pipeline construction has taken its toll in Fairbanks. The area is experiencing a severely depressed economy. Employment in the construction industry has decreased to half of the previous pipeline level. There has been a slight increase in employment generated by government, distributive industries, and retail _trade. In 1977-78, Fairbanks and its outlying areas experienced a 16 percent decline in population. The decision favoring the ALCAN route for the proposed natural gas pipeline was made in late 1977. The proposed gas pipeline will follow the route of the trans -Alaska oil pipeline route from Prudhoe Bay to Delta Junction. Fairbanks has been selected as the operation headquarters by the Northwest Pipeline Company, responsible for construction and operation of the gas pipeline. The Fairbanks -Tanana Valley area will probably be heavily impacted again by the pipeline construction; however, a more stable permanent employment base is likely to become established. 0 The Fairbanks -North Star Borough had an estimated. 1977 population of 44,262 and an estimated additional 8,000 in the outlying communities within the power market area. The total population decreased 10 percent since 1974. 9 PART IV. EXISTING POWER SYSTEMS Utility Systems and Service Areas The electric utilities in the Railbelt power market area are listed below, and areas now receiving electric service are shown on figure 2. A detailed listing of power generating units is in the appended Battelle report, table 3.4. Installed Nameplate Anchorage -Cook Inlet Area Capacity MW —/ Alaska Power Administration (APA) 30.0 Anchorage Municipal Light and Power (AML&P) 121.1 Chugach Electric Association (CEA) 345.7 Matanuska Electric Association (MEA) Homer Electric Association (HEA) 1/ Homer (Standby) 0.3 Seldovia, English Bay, Port Graham 1.8 Seward Electric System (SES) 5.5 1/ Fairbanks -Tanana Valley Area Fairbanks Municipal Utility System (FMUS) 69.6 Golden Valley Electric Association (GVEA) 219.2 1/ Major generation supplied by CEA system. 2/ Consists of 45 MW hydro. All the rest are fuel -fired (80% gas turbine). 10 Fi c-rtarP � APA 12/78 ,I1 These totals differ from the Battelle appended report because the report includes some planned units not installed in 1977 as well as use of some ratings other than nameplate. APA operates the Eklutna hydroelectric project and markets wholesale power to CEA, AML&P, and MEA. AML&P serves the Anchorage Municipal area. CEA supplies power to the Anchorage suburbs and surrounding rural areas, and provides power at wholesale rates to HEA, SES, and MEA. The HEA service area covers the western portion of the Kenai Peninsula, including Seldovia, across the bay from Homer. MEA serves the town of Palmer and the surrounding rural area in the Matanuska and Susitna Valleys. The utilities serving the Anchorage -Cook Inlet area are now loosely interconnected through facilities of APA and CEA. An emergency tie is available between the AML&P and Anchorage area military installations. FMUS serves the Fairbanks municipal area, while GVEA provides service to the rural areas. The Fairbanks area power suppliers have the most complete power pooling agreement in the State. FMUS, GVEA, the Univer- sity of Alaska, and most of the military bases have an arrangement which includes provisions for sharing reserves and energy interchange. The delivery point for Upper Susitna power to the GVEA and FMUS systems is assumed at a substation of GVEA near Fairbanks. Other small power generating systems in the Fairbanks -Tanana Valley area were included in determining the power requirements of the region. They include: Installed Fairbanks -Tanana Valley Area Capacity MW Alaska Power and Telephone Company 2.28 (Tok and Dot Lake vicinity) Northway Power and Light Company 0.48 (Northway vicinity) ° National Defense Power Systems The six major national defense installations in the power market area are: Anchorage area-- Elmendorf Air Force Base Fort Richardson C 12 Fairbanks .area -- Clear Air Force Base Eielson Air Force Base Fort Greely Fort Wainwright Each major base has its own steamplant that is used for power and for central space heating. Except for Clear Air Force Base, each is inter- connected with the local utility. Numerous small isolated installations are not included in this study. In the past, national defense electric generation has been a. major portion of the total installed capacity. With the projected stability of military sites and the growth of the utilities, the national defense installation will become a less significant part of the total generating capacity. Industrial Power Systems Three industrial plants on the Kenai Peninsula maintain their own power - plants, but are interconnected with the HEA system. The Union 76 Chemical Division plant generates its basic power to satisfy its energy needs, receiving only standby capacity from HEA. The Kenai liquified natural gas plant buys energy from HEA, but has its own standby generation. Tesoro Refinery buys from HEA and also satisfies part of its own needs. Other self -supplied industrial generators include oil platform and pipeline terminal facilities in the Cook Inlet area. Existing Generation Capacity Table 1 provides a summary of existing generating capacity. The table was generally current as of 1978o The Anchorage -Cook Inlet area• had a total utility installed capacity of 504.5 MW in 1977-78. Natural gas -fired turbines were the predominant energy source with 435.1 MW. Hydroelectric capacity of 45 MW was available from two projects, Eklutna and Cooper Lake. Steam turbines comprised 14.5 MW. Diesel generation, mostly in standby service, accounted for the remaining 9.8 MW. The Fairbanks -Tanana Valley area utilities had a total installed capacity of 288.8 MW in 1977. Gas turbines (oil -fired) provided the largest block of power in the area with an installed capacity of 203.1 MW. Steam turbine generation provided 53.5 MW of power and diesel generators contributed 32.1 MW to the area. 13 4 Table 1 RAILBELT AREA GENERATION CAPACITY Summary - 1977 Upper Susitna Project Power Market Analysis Area Installed Capacity - MW Diesel Gas Steam Hydro . Int. Comb. Turbine Turbine Total Anchorage -Cook Inlet Utility System 45.0 National Defense Industrial System Subtotal 45.0 Fairbanks -Tanana Valley Utility System National Defense Subtotal 9.8 435.l 14.5 504.5 9.2 40.5 49.7 10.2 14.8 25.0 29.3 449.9 55.0 579.2 32.1 14.0 46.1 203.11 • 53.5 288.8 63.0 77.0 203.1 116.5 365.8 Notes: The majority of the diesel generation is in standby status. Rounding causes differences between summations of the parts and the totals shown. Source: Utility reports to Alaska Public Utility Commission to the Department of Energy, the Alaska Air Command, the oil and gas companies, and APA files. (Minor differences exist between this table and the appended Battelle Report.) 14 APA 11/78 Planned Generation Capacit The two major utilities in the Anchorage -Cook Inlet area, AML&P and CEA, plan to add a total of approximately 420 MW installed capacity to their existing system between 1979 and 1985. A'�L&P plans to add a 16.5-MN combined cycle system to their existing combustion turbine. in addition, CEA has plans to complete the 230-kv interconnection loop with MEA. In December 1978, GVEA decided to postpone development of their proposed Healy II steam turbine system (104 MW) until more favorable economic conditions prevail. A unit by unit breakdown of planned generating systems is presented in the appended Battelle report, table 3.8. PART V. POWER REQUIREMENTS i Introduction This summarizes the analyses of historic data and estimates of future needs in the power market areas. The study examines in detail electric utility statistics 1970 to 1977 with special effort to identify changes in use patterns related to conservation measures since the 1973 oil embargo. Estimates of future utility power needs are derived from estimates of individual energy use and area population. Population projections were developed by the University of Alaska, Institute of Social and Economic Research (ISER). The individual use forecast was estimated by assumed conservation -induced changes in kwh/capita growth rates. The end results are forecasts of net generation (kwh) and peak load demand (kw). The three energy use sectors analyzed in this study are: Utility - Includes all utilities which serve residential and commercial/industrial customers.. National Defense - Includes all military installations. Self -Supplied Industry - Includes limited number of heavy industries, i.e., natural gas and oil processing industries on the Kenai Peninsula which generate their own power. The study assumes that these industries will purchase energy if it 'becomes economically feasible. Some have interchange agreements with local utilities. Evaluations of monthly energy distribution and installed capacity requirements are included and are premised on characteristics of area power demands. Data This presents the basic parameters used in the analyses leading to the Susitna Power Market forecast assumptions. The historical data summarizes the Anchorage -Cook Inlet and Fairbanks -Tanana valley areas which comprise the Railbelt area. Each area is divided into utility, national defense, and self -supplied industrial components (Fairbanks -Tanana Valley area has no known significant self -supplied industries). The utility component is divided into four sectors: Residentia<11 Commercial -Industrial, Total Sales, and Net Generation. 16 0 Data= wa's collected from utility and industry reports to various government agencies, from utilities directly, from Alaska military commands, by correspondence with industry, and from various statistical publications and news media. Basic data needed for the 1970-1977 analysis are presented on tables 2, 3, and 4 included is utility annual energy and customers for each sector, national ,defense and industrial annual energy consumption, utility and national defense annual peak load, industrial installed capacity, annual population, and average annual employment. In addition, utility net generation, listed on tables 5 and 6, was compiled for the 1960-1977 period. As part of the forecasting foundation, the following historical chronology indicates fluctuations affecting Railbelt energy use. 1970. Uncertainty concerning the oil pipeline design, construction, and approval. Native land claims legislation pending. Above average temperature. 1971. Uncertainty concerning pipeline. Below average temperature. 1972, Uncertainty concerning pipeline. Coldest year of period. 1973. Start of fuel crisis and conservation publicity in December. Below average temperature. 1974. Start of pipeline construction. Near average temperature. 1975. Peak of pipeline construction activity. Near average tempera- ture. 1976. Start of pipeline construction "wind -down." Electric power cable across Knik Arm out of service for an extended period (all but one circuit). Above average temperature. 1977. Oil started flowing in pipeline. Warmest year of period. Residential construction boom in Anchorage. Large increasein non-residential authorizations issued. 17 Tab le 2 BASIC POWER AND ENERGY FORECASTING DATA ANCHORAGE -COOK INLET AREA (INCLUDING SEWARD) Upper Susitna Project Power Market Analysis Utility Energy Sales (GWH) Net Generation (GWH) Year Resi. Comm./Indu. Total 1/ 1970 310.5 342.3 678.7 1971 369.7 393.9. 792.5 1972 421.6. 454.0 911.6 1973 459.5 514.8 1,012.2 1974 496.1 552.8 1,087.4 1975 595.1 631.9 1,270.6 1976 677.6 738.7 1,462.? 1977 741.0 813.4 1,600.8 Utility Customers Utility 2/ Nat. Def. 3/ Indu. 744.1 156.2 1.65 886.9 161.2 1,003.8 166.5 45.3 1,108.5 160.6 1,189.7 155.1 45.3 1,413.0 132.8 1,615.3 140.3 1,790.1 130.6 69.5 Peak Load (MW) Year Resi. Comm./Indu. Total Utility Nat. Def. Indu. 4/ 1970 39,271 5,230 45,042 165.2 34.6 12.3 1971 42,501 5,581 48,670 184.8 1972 46,724 6,104 53,278 212.8 33.9' 12.3 1973 49,307 6,491 56,280 2Z9.9 1974 52,585 6,798 59,893 257.2 .32.6 12.3 1975 56,801 7,478 64,797 345.8 1976 61,881 8,220 70,622 349.'9 1977 68,320 9,221 78,066 423.9 40.5 24.8 Population Employment Civilian Total Avg. Annual 1970 135,963 149,428 47,408 1971 145,108 159,046 51,092 1972- 155,084 167,765 54,329 1973 160,162 174,280 57157 1974 165,938 179,544 65,919 1975 196,320 209,049 78,786 1976 207,090 219,337 83,604 1977 222,424 234,674 88,869 Excludes deliveries to national defense. 1/ 2/ Total retail sales of energy + non -revenue energy used + losses. 3/ Includes receipts from utilities, excludes deliveries to utilities. 4/ Self -supplied industrial data is installed capacity rather than peak load. GWH = million KWH MW = thousand KW KW = Kilowatt APA 11/78 18 Table 3 BASIC POWER AND ENERGY FORECASTING DATA FAIRBANKS-TANANA VALLEY AREA Upper Susitna Project Power Market Analysis Utility Energy Sales (GWH) Year Resi. Comm./Indu. Total 1/ 1970 91.7 108.3 210.2 1971 112.4 119.8 244.3 1972 122.3 127.3 262.9 1973 134.4 139.5 282.3 1974 155.8 150.3 323.0 1975 193.0 196.3 409.2 1976 195.9 204.2 420.5 1977 200.7 221.6 442.7 Net Generation (GWH) Utility 2/ Nat. Def. 3/ 239.3 203.5 275.5 201.4 306.7 203.3 323.7 200.0 353.8 197.0 450.8 204.4 468.5 217.5 482.9 206.8 Utility Customers Peak Load (MW) Year Resi. Comm./Indu. Total Utility Nat. Def. 1970 10,364 1,721 12,268 56.3 44.4 1971 11,014 1,779 12,947 65.3 1972 11,584 1,539 13,611 66..6' 41.4, 1973 11,931 1,929 14,041 72.7 1974 12,832 2,069 15,084 87.5 40.8 1975 14,025 2,247 16,447 110.0 1976 15,569. 2,435 18,179 102.6 1977 16,709 2,580 19,463 118.9 41.0 Population Employment Civilian Total Avg. Annual 1970 42,310 52,141 15,681 1971 43,188 50,585 15,817 1972 452516 52,383 16,873 1973 45,396 52,246 16,794 1974 51,137 57,836 21,960 1975 60,884 67,011 34,451 1976 58,051(e) 63,762 34,325 1977 47,155(e) 52,155 27,385 1/ Excludes deliveries to national defense. 2/ Total sales + non -revenue use + losses. 3/ Includes receipts from utilities, excludes deliveries to utilities. 4/ Self -supplied industrial data is installed capacity rather than peak load. GWH million KWH MW = thousand KW APA 9/78 W Table 4 BASIC POWER AND ENERGY FORECASTING DATA RAILBELT AREA Upper Susitna Project Power Market Analysis Utility Energy Sales (GWH) Net Generation (GWH) Year Resi. Comm./Indu. Total Utility Nat. Def. Indu. Total 1970 402.2 450.6 888.9 983.4 359.7 1.6 1,344.7 1971 482.1 513.7 1,036.8 1,162.4 362.6 25(e) 1,550.0 1972 543.9 581.3 1,174.5 1,310.5 369.8 45.3 1,725.6 1973 593.9' 654.3 1,294.5 1,432.2 360.6 45.3(e) 1,838.1 1974 651.9 703.1 .1,410.4 1,543.5 352.1 45.3 1,940.9 1975 788.1 828.2 1,679.8 1,963.8 337.2 45.3(e) 2,246.3 1976 873.5 942.9 1,882.7 2,083.8 357.8 45.3(e) 2,486.9 1977 941.7 1,035.0 2,043.5 2,273.0 337.4 69.5 2,679.9 Utility Customers Peak Load (Ml?) Year Resi. Comm./Indu. Total Utility Nat. Def. Indu. Total 1970 49,635 6,951 57,310 221.5 79.0 12.3 312.8 1971 53,515 7,380 61,617 250.1 77(e) 12.3(e) 339.4 1972 58,308 7,943 66,889 279.4 75.3 12.3 367.0 1973 61,238 8,420 70,321 302.6 74(e) 12.3(e) 388.9 1974 65,417 8,867 74,977 344.7 73.4 12.3 430.4 1975 70,826 9,725 81,244 455.8 73(e) 12.3(e) 541.1 1976 7.7,450 10,654 88,801 452.5 76(e) 12.3(e) 540.8 1977 85,029 11,801 97,529 542.8 81.5 24.8 649.1 Total Avg. Annual Population Employment 1970 201,569 63,089 1971 209,631 66,909 1972 220,148 71,202 1973 226,526 73,951 1974 237,380 87,879 1975 276,060 113,237 1976 283,099 117,929 1977 286,829 116,254 APA 11/78 20 41 rl = N h -4 U-) m O Ln m h O x i0 N N m U.) 0J N o 1D h llp 1:4 M .-a 9 00 �7 r-•i I; O -o --1 -4 r -4 1.4 'A r-1- O C7 4-J U) a) •r•I a) y rl � h N � �?' � h �o �1' O OJ D1 r--I rf•1 �7' � M O� r•I r--I Q7 co 1-4 m 00 1-4 M �10 00 -�J- Cl) M co 00 0 r- -t h It ry +-J mU-)r--I -t(DU*)ohMmr-o al�-4-40 p N N N M m �t -t U') V1 I.D h 00 o 1.0 00 >, H a) G O a) •r-I m U 1-4 > 4 m {{ h N h -4 r-i --t r--i r•-i N U') 00 ' cd iJ w C c1] U1�DMo00000C;00C;a;C; o r-I w a� � x � - 3H r� `•� �+ U .-•t N N N m t!1 I'D O W 011 00 h I I l l l LnzH 3 O o C) H x a HHO ?, n!.OU NCO N�7�Yu1I�N�tr�M�ON�t�1�t1 U cd WI H L:q I U 41 T MOOS 1 r•+-4 -4 NNN Mm�tM00 w u O — C� C � •r•I H O w x crr � z L) i C r- r- N N rn h o0 o0 a1 -{ M cn cn ( I I t f Q r14+ 000o000C 0c; C; -a - O m o � cn tO p N a) IC M . m h 1- 4 1.4 N U1 U') N h O> O m -4 .-+ L-) I'D a) G . . . . . . . . . . . . M O N D N.0 cc Ln r v t r-I r•r) M o. P-4 00 mU')LI)-It Cl) mhrr)U•)u)%0m mr--iO o U E, � r•-t r� r� � .-t --i .--r r-1 .--I .-{ r-i r-r '--r .-a N •rl 4 U a3 r-i U•) m 00 t1) U') :T cD 'D Ln 'o N M 00 rn h h�thO�ttcl�o�7hCJC0 Z;� 44 U N :1- O 0 m %,o o r•-4 c H 00 h Ln Ln h 00 rn r-- 0 -4 -4 NNN mm.,2-Lf) 1�0 %D000r-q U) r— •r� 11141 E N O h M N to r•-i M r-t O m 0 0 \D m 91 m U � U O M 0 U) h _-+ CO O rl) 10 yr U'1 O O\ m N O a) N v)M000N�tM ,r r-v)o0oD-7cV _qr-ir--1.-1.-1N N MMM-t-Ir m a� o U } 1 O• N m -t tr) � h 00 m 0-� N M-- Lo t0 h G cd `o �o 110 �D �D %.o �o 1.0 h h h h r. h hh H a) 0% Cry CT O'� O>. Cry 011 m m m � m Cry m m O, � 1-4 r� r•-; r-i r-i r--I �--i r•-1 1-1 r-� r-4 '- r-4 -4 -4 r-r r-� r-1 21 F+ 3 0 w G -o 0 G G •ri cd o G 4J rl O tSJ O i•) i-i z U rl •r U u m cd E a m m C U +J t C r-: U coi G -rl -rl CA U7 •r-i U � �+ C I•+ C U U m -rd U f•+ r� P i-) .v Q) C) W 4-3 -r-1 U a) W o cd a) -ri r-i tO W 4-1a p O Cd x C i-i -r-I N O N G c�C w CC.>C�xxcn I I I I l I I w 0 • Tab le 6 NET GENERATION (GWH) FAIRBANKS-TANANA VALLEY AREA Upper Susitna Project Power Market Analysis (Includes receipts of electric energy from military; excludes electric energy deliveries to military) Year FMU GVEA AP&T DIE NP&L Total Growth 1960 36.7 24.4 -- 0.1 0.6 61.8 1961 38.8 29.4 -- 0.1 0.6 68.9 11.5 1962 42.3 33.3 1. 0.1 0.6 77.2 12.1 1963 45.4 39.1 1.2 0.1 0.6 86.4 11.9 1964 48.4 53.6 1.5 0.1 0.6 104.2 20.6 1965 49.5 56.6 1.8 0.1 0.6 108.6 4.2 1966 52.6 67.0 2.1 0.1 0.6 122.4 12.7 1967 55.9 75.9 2.0 0.2 0.6 134.6 10.0 1968 64.0 97.9 2.0 0.2 0.6 164.7 22.4 1969 72.2 118.1 2.1 0.2 0.6 193.3 17.4 1970 85.6 150.2 1.9 0.2 0.6 238.6 23.4 1971 106.7 164.9 2.4 0.2 0.6 274.7 15.1 1972 120.3 182.2 2.6 0.2 0.8 306.1 11.4 1973. 115.4 202.2 2.7 0.2 0.9 321.4 5.0 1974 123.0 214.3 3.5 0.2 1.2 342.1 6.4 1975 137.2 28.6.9 3.9 0.2 1.6 429.7 25.6 1976 139.6 315.1 4.2 0.2 1.4 460.4 7.1 1977 133.5 346.3 4.5 0.2 1.4 485.8 5.5 FMU - Fairbanks Municpal Utilities GVEA - Golden Valley Electric Association AP&T - Alaska Power and Telephone (Tok) DIE - Dot Lake Electric (Purchased by AP&T in 1978) NP&L - Northway Power and Light 0 22 t, Analysis Detailed investigations of relationships among the basic data components are listed in tables 2, 3,, and 4. Analysis was done separately for each major sector (utility, national defense, and self -supplied industry) within each geographic area. Utility The analysis of utility data set out to develop assumptions for fore- casting net generation and peak load. Investigations evaluated the impact of changes in population, employment, customers, weather, tariffs, and other events upon energy use. These evaluations then helped to: (1) determine if energy sectors (residential, commercial -industrial, total sales) other than net generation needed to be forecast; (2) determine which energy ratio (kwh/capita, kwh/employee, " kwh/customer) to use in the forecasting procedure; (3) develop procedure for forecasting utility annual net generation from energy use assumptions and demographic parameters (population, employees, or customers); (4) determine load factor with which to calculate peak load forecast from the net generation forecast. Constants, small amplitude cycles, or trends in relationships among the energy use and customer sectors were investigated for use as forecasting aids. If, for instance, the residential energy use/net generation ratio remained almost constant from 1970 through 1977, only net generation need be subjected to the forecasting procedure. The same type of analysis was applied to energy use ratios: a look for an average or trend to be used as a factor in forecasting net generation. After developing the net generation forecast, the peak load forecast was calculated using energy and an assumed load factor. Analysis of historic load factors determined an average or trend from which the assumed load factor was derived. Forecasted net generation and the assumed future load factor were then used in the formula: Peak load = 8,760 hr/yr. x load factor x net generation. The evaluations showed a mix of similarity and contrast between the two Railbelt areas. In both areas, the major energy use determinants were the trans -Alaska oil pipeline construction and. the fuel crisis of 1973-74. Other correlations with weather, tariffs, etc., seemed. insignificant. For instance, energy growth increased in some years despite above average temperatures which reduced energy need. Anchorage -Cook Inlet Area Analysis Results - The foregoing evaluation procedures resulted in the following observations for the Anchorage -Cook Inlet area. 23 (a) Observations indicate no significant shift in energy use patterns or in share of total load among the various utility sectors (residential, etc.). The ratios among the sectors (residential/total sales; total sales/net generation, etc.) remained essentially constant through the study period. This was true for both energy and customers. Therefore, only one sector --net generation --represents all sectors in the forecast. (b) Energy rate of growth per customer and per capita had a significant reduction after the 1973-74 fuel crisis. The 1973-77 per capita average growth rate was about half that for 1970-73. It appears that conservation can -be considered an influence after 1973. (c) Events impinging upon energy use are listed in the previous section. Between 1973 and 1977, several events bear repeating for emphasis: fuel crisis in 1974; start of pipeline construction in 1974; peak pipeline activity in 1975; decrease of pipeline activity in 1976 and 1977; cables across Knik Arm, which carry a large share of Anchorage energy, went out of service in 1976; warmer than average weather in 1974, 1976, and especially 1977. Yearly growth rates reflected rather large fluctuations as different historical events influenced each parameter. (This is a recurring phenomenon in Alaskan history). (d) Parameters were not influenced alike as'f igures 3 through 8 attest. For instance, customer growth -reacted' to events in a steadier pattern than did population and employment. Reasons for this are more people per customer and time needed for connecting more customers to a utility system at the initial onslought of large demographic growth. (e) Comparing the energy fluctuations with others, such as population and employment, gave a measure of correlation between parameters. (The energy use and customer growth fluctuations correlated only in part; their patterns did not coincide every year). However, energy and popu- lation growth rate changes were coincidental for every year but 1977. That is, when the energy growth rate increased, so did the population growth rate; when the population growth rate decreased, so did the energy growth rate. (f) Energy use and weather comparisons were inconclusive. Warm weather did not bring corresponding reduction in energy use. Cold weather increases in energy use were buried in other events (pipeline construction, etc.). (g) Because the net generation kwh/capita ratio seemed to reflect the closest correlations, particularly in recent years, this ratio and population were used to forecast net generation values between 1980 and 2025. (h) Values basic to the forecasting assumptions are the kwh/capita ratio averaging 3.8 percent average annual growth between 1973 and 1977 and net generation averaging 12.7 percent. (i) Average annual growth results are summarized on table 7. Figures 3, 4, and 5 are graphs of pertinent elements of the analysis. 24 Fairbanks -Tanana Valley Area Analysis Results - Some of the Anchorage -Cook Inlet area evaluation results apply also to the Fairbanks -Tanana Valley area, others do not. The following observations parallel those of Anchorage -Cook Inlet. (a) No significant shift in energy use patterns or in share of total load among the various utility sectors (residential, etc.). Again, only one sector --net generation --need be forecast. (b) Energy growth was similar to that of Anchorage (somewhat smaller in the pre-1973 period); but customer, population, and employee growth were different in the two areas. Consequently, the energy use per customer, per capita, and per employee ratios indicate different growth patterns in Fairbanks. The large swings of employment and population in Fairbanks during pipeline construction compared to almost constant preconstruction values cloud comparisons of the two periods. (c) Although the effects of pipeline construction are evident, the population/employee ratio (2.29 average through the study period) was constant enough to indicate that either population or employment can be used as,a forecasting parameter. (d) The effects of weather on energy use could not be detected. In some years, degree day variations were not in phase with energy,use variations. (e) Energy use/capita exhibited wider variations than the other two ratios, but, nevertheless, had the nearest to constant average annual growth rates. Because of this and the other observations, net generation kwh/capita and population were used to forecast net genera- tion. (f) As in the Anchorage -Cook Inlet area, values basic to the forecasting assumptions are the net generation/capita growth, averaging 10.6 percent per year, and net generation growth, averaging 10.5 percent per year between 1973 and 1977. (g), Growth rate results.are summarized on table 7. Figures 6, 7, and 8 are graphs of some pertinent elements of the analysis. rl 25 Tab le 7 AVERAGE ANNUAL UTILITY GROWTH SUMMARY ANCHORAGE -COOK INLET AREA Upper Susitna Project Power Market Analysis Avg. Growth Avg. Growth 1970• 1973 1977 1970-1973 1973-1977 Energy GWH Residential Sales 310 460 741 14.0% 12.6% Commercial/Industrial 342 515 813 14.7 12.1 Total Sales 679 1,012 1,601 14.2 12.1 Net Generation 744 1,108 1,790 14.2 12.7 Energy Use, kwh/Customer Residential 7,907 9,319 10,846 5.6 3.8 Commercial/Industrial 65,449 79,310 88,212 5.6 2.6 Total Sales 15,068 17,985 20,506 6.0 3.3 Energy Use, kwh/Capita Residential 2,284 2,869 3,332 8.0 3.8 Commercial/Industrial 2,518 3,214 3,657 8.6 3.3 Total Sales 4,992 6,320 7,197 8.3 3.3 Net Generation 5,473 6,921 8,048 8.0 3.8 Fairbanks -Tanana Valley Area Avg. Growth Avg. Growth 1970 1973 1977 1970-1973 1973-1977 Energy GWH Residential Sales 92 134 201 13.4% 10.7% Commercial/Industrial 108 140 222 9.1 12.2 Total Sales . 210 282 443 10.2 11.9 Net Generation 239 324 483 10.8 10.5 Energy Use, kwh/Customer Residential 8,852 11,262 12,010 8.3 1.7 Commercial/Industrial 62,931 72,303 85,899 4.8 4.4 Total Sales 17,134 20,104 22,746 5.4 3.1 Energy Use, kwh/Capita Residential 1,759 2,572 3,848 13.5 10.6 Commercial/Industrial 2,077 2,670 4,249 8.7 12.3 Total Sales 4,031 5,403 8,488 10.3 12.0 Net Generation 4,589 6,196 9,259 10.5 10.6 APA 11/78 26 51 50 49 48 ^ 47 [ 46 45 C 44 43 42 41 4 r� Figure 3 ULNT,'120Y SEC110P, RAT1O3 ANOI^.''RA G COOK IN-TIET 111'SN Upper Susitna Project Power Market Analysis Commercial -Indus trial Sales Total Sales Avg. = 50.30 Residential Sales Total Sales Avg. = 46.11. �----------------' Residential Sales ----- -- r , Net Generation Avg. _ rr1.7% 97n r 1972 1973 1974 1975 1976 1977 YEARS ANUNU11L =. P3Y G=RKTD OP SOLD R-CHOR ,LZ-COOK I= AP.F=1 1800 Upper Susitna Project Power Market Analysis 1700 1600 150,0 1400 c 1300 ° 0 7,OU 110U� �. FIT1000 Generation F" 900 t+c U e Soo 700 >, catist,r. is 500 c nG0 pesidci,tLal Sal.e� 300 1970 1971 1.972 1973 1974 1975 197G 1977 y -Ars APA 12/78 27 11,000 10,000 9,000 8,000 7,000 6,000 'a w w 5,000 4,000 3,000 Figure 4 ANNUAL 1-1,=,Z. USE PER CVITA AND PEP, CUS'IrA\IER RX I IORAGE-COOK 1NU. r AI:TiA Upper Susitna Project Power Market Analysis l- omen Re51ae��laS. Yes Res1ae�t1al sales ei S�aG G,> . Sraostxyal e=Glal� Comp` sales Y eY �aus��yal 1 czclal,S Covz\ a Ca�yt Y ex Genexatior l�,a tir l het ex Cap eta�lor Y het Gem Pei Capita Sale' Comm exoial�xrdllstxldl entyal Sale. Per Capita 2,000 I i-- 19'70 1971 28 YI AAP'3 APA 12/78 250,000 nsAiy� F �j�)E' �``�� {^ �g �+z.5q . A€ %JUAL iii,i�F. LAB 10bVp EP.a1 LO, tY EM t, AND U T UT Y C JS j GP=TEES 225,00.0 175,000 LJ d d150,000 L_ 0 +x m 125,000 z 100,000 75,000 50,co0 c1� _ po9u�ation �..-- i�clltial Customers h 25,000 1970 1971 1972 1973 1974 YEARS 29 Figure .5 1975 1976 1977 APA 1/79% Figure 6 ENERGY SECTOR RATIOS RAI R SANKS-TANANA VALLEY AREA 52 Upper Susitna Project Power Market Analysis Commercial -Industrial Sales 50 Total Sales Avg. 48.9% 48 46 Z Residential Sales Avg. - 46.4% �. Total Sales 44 O a 42 Residential Sales- Avg_ = 41.3% 40 Net Generation 38 36 1970 1971 1972 1973 1974 1975 1976 1977 YEARS ANNUAL ENERGY GENERATED OR SOLO 500 I=AIRBANKS-TANANA VALLEY AREA, Upper Susitna Project Power Market Analysis 2 ann Y z O J 3 00 Generation <G� iet • tt 2 0 200 z Caaunercial-Industrial Sales (; v } Residential Sales ( ) m 100 Re Z 0 1970 1971 1972 1973 1974 1975 1976 1977 YEARS 30 APA 1/79 Figure 7 ANNUAL ENERGY USE PER CAPITA AND PER CUSTOMER FAA RBANKS-TANANA, VALLEY AREA Upper, Susitna Project Power Market Analysis 14,000 13,000 127000 s�oses C1. yZ, 117000 esyaex'�l Yes g 10,000 sa�•�s a er C�Stom 39000ci..Znd`s1a1- Cfl�e= 8000 y 7000 c1���nausY _ Comes ltaPl� Scale 10) bY., (,e - 6000 Ls3 Z CT.t•3--7 Capita. tion La 5 000 xet Generz, .4000 3000 ciiastrial Sales Per Capita (Tt1. ) Com�°1al-Ind 2000 ta Residential gales Per Cap i 1000 0 1970 ' 1971 1972 1973 1974 1975 1976 1977 YE. RS 31 APA 1/79 70,000 �Ws • m W. 40,000 0 ttt M 30,000 D z go 0_0A WEE ^t970 Figure 8 ANNUAL. POPULATION, EMPLOYMENT, AND UTILITY CUSTOMERS AIR 5-& KS�-- T A NA VALLEY AREA 1971 1972 1973 1974 `t tAR' S z� 1975 1976 1977 APA 1/79 National Defense Evaluation of historical national defense data resulted in net generation and peak load averages. The analysis encompassed the U.S. Army. and Air Force installations in the Anchorage and Fairbanks areas. No definite trends surfaced --only a small, cyclic decrease in the Anchorage area net generation and. an increase in peak load. In the Fairbanks area, net generation increased slightly and peak load decreased. Total national defense is about 15 percent of utility for both net generation and peak load. Self -Supplied Industry Railbelt industry and the upper Kenai Peninsula complex showed no significant change in capacity and energy generation until 1977 when the chemical plant expanded. Therefore, the analysis consisted of a plant factor determination only. Other factors needed in forecasting are discussed as assumptions in the next section. Energy and Power Demand Forecasts This section presents future energy and power requirement estimates developed from the previous analyses. Work for the new estimates consisted of: (1) using the analyses to obtain forecasting assumptions; (2) using the assumptions in forecasting utility net generation/capita; (3) combining net generation/capita with Institute of Social` and Economic Research (ISER) population projections to obtain the utility net generation forecast, and forecasting national defense and industry generation from pertinent assumptions; and (4) combining the net generation forecast with load factors resulting from the historical data analysis to obtain peak load (power requirement) forecasts. Assumptions and Methodology Population - The ISER econometric model of the Southcentral Region Water Study (Level B) furnished high and low range population forecasts. The model disaggregated the Anchorage -Cook Inlet area from a statewide population forecast. No recent, applicable forecast of Fairbanks -Tanana Valley population was available; therefore, APA assumed statewide growth rates from the ISER model applied to the Fairbanks -Tanana Valley areas.. (See table 8). Utility - Assumptions, based on the preceding analyses, lead to the net generation and peak load forecast. Net generation is the product of forecasted energy use per capita and projected population. Peak load demand is derived from net generation and the assumed utility load factor. Multiplying these growth rates by forecasted 1980 values of kwh/capita resulted in the energy use estimates. 33 Table 8 POPULATION ESTIMATES 1980-2025 RAILBELT AREA Upper Susitna Project Power Market Analysis Anchorage -Cook Inlet 1/ Statewide -L/ Year High Low High Low 1980 270,200 239,200 513,766 500,225 1985 320,000 260,900 640,718 563,303 1990 407,100 299,200 790,042 618,397 1995 499,200 353,000 947,312 680,286 2000 651,300 424,400 1,157,730 743,034 2025 904,000 491,100 1,484,784 820,369 e Fairbanks -Tanana Valley l/ High Low 62,020 60,390 77,350 68,010 95,370 74,660 114,360 82,130 139,760 89,700 179,240 99,040 Notes: * No mid -range estimates are shown because, when the forecasts were done, ISER 1/ had made only the high and low projections. A comparison of the mid -range forecast already performed (see text for method) with one using the mid -range population, when received, indicated no reason to re -do the forecasts. * Values shown include national defense population 1/ From Iser, Southcentral Alaska's Economy and Population: A base Study 1965-2025. September 1978 with December 1978 revisions. 2/ Calculated from statewide growth rates. W 34 Since the ratios of residential, commercial -industrial, and total sales energy to net generation remain constant, net generation is assumed. to be an appropriate forecasting parameter. The evaluations indicated that the other sectors do not need individual forecasting. The basic energy use (net generation kwh/capita) assumption for the entire Railbelt area is a 3.5 percent average annual, mid -range, 1980-85 growth rate. It is based on the Anchorage -Cook Inlet area value of 3.8 percent annual growth lf�rom '1973-77 and an assumed continuation of the post-1973 conservations- trend. As mentioned in the Anchorage -Cook Inlet area evaluations, a conservation trend was apparent when comparing energy use growth rates for 1973-77`and 1970-73 (see table 7). Tied to this is the assumption of gradually increasing effectiveness of future conservation programs coupled with perhaps upper limits of electric energy use. These are reflected in an average annual growth by the year 2000 or 2 percent for high range, 1 percent for mid -range, and 0 percent for low range. These assumptions result in decreased growth rates for each five-year increment, as shown below: Time Period High Mid Low 1980-1985 4.5% 3.5% 2.5% 1985-1990 3.5% 3.0% 2.0% 1990-1995 3.0% 2.5% 1.5% 1995-2000 2.5% 2.0% 1.0% 2000-2025 2.0% 1.0% 0% Multiplying these growth rates by forecasted 1980 values of kwh/capita resulted in the energy use estimates. The 1980 mid -range value of kwh/capita was derived from the 1973-1977 average annual growth of net generation. The 1980 net generation was estimated. The Anchorage -Cook Inlet mid -range assumption of 12 percent annual load growth rate for 1977-80 net generation came from a historical 12.7 percent. The respective Fairbanks -Tanana Valley values were 10.5 percent assumed, 10.6 percent historical. Mid -range 1980 kwh/capita was calculated using the estimated net generation and projected population. The 1980 high and low range average annual kwh/capita growth rates for Fairbanks -Tanana Valley were assumed 120 percent and 80 percent of the calculated mid -range value respectively. Comparable values for Anchorage -Cook Inlet were 130 percent and 80 percent. The differences between the two areas reflect population estimates and an attempt to derive a reasonable 1977-80 transition period coupled with the population estimates. Peak -load (WI) forecasts were calculated using a 50 percent load factor. Anchorage -Cook Inlet area load factor averaged 51.9 percent between 1970 and 1977 and 51.0 percent between 1973 and 1977. Fairbanks area averaged 48.9 percent and 48.4 percent in the same periods. 1/ Conservation here includes results of the fuel crisis and perhaps of nationwide publicity on the need for saving energy. Other factors may be involved, but no other events are as coincidental with reduced energy use as is the fuel crisis. 35 National Defense - Historical data from Army and Air Force installations in the Anchorage and Fairbanks areas indicate reasonable energy assumptions to be: 1. 0 percent annual growth for mid -range forecast, 1 percent for high range, and -1 percent for low range. 2. A 50 percent load factor was assumed for use with energy (net generation) to obtain peak load. Self -Supplied Industries - The following assumptions were developed from existing data and conditions, consultations with many knowledgeable people in government and industry, and from reports on future developments: 1. ' Industries will purchase power and energy if economically feasible. 2. Forecast based on listing in the March 1978 Battelle report. 3. High range includes existing chemical plant, LNG plant, and refinery as well as new LNG plant, refinery, coal gasification plant, mining and mineral processing plants, timber industry, city and aluminum smelter or some other large energy intensive industry. 4. Mid -range includes all of the above except the aluminum smelter. 5. Low range includes all listed under high range except the aluminum smelter and the new capital. 6. In some instances, high, mid, and low range may be differentiated by amount of installed capacity as well as the type of installations assumed. 7. No self -supplied industries are assumed for the Fairbanks -Tanana Valley area. Any industrial growth has been assumed either (1) included in utility forecasts or (2) not likely to be interconnected with the area power systems. 8. Net generation forecast calculated from forecasted capacity and a plant factor of 60 percent. The ISER model assumed the following Cook Inlet area industrial scenario. It is compared to industries assumed for the self -supplied industrial forecasts of this report. 36 Cook Inlet Industrial Scenarios Assumptions ISER Self -Supplied Industries Forecast Oil treatment and shipping facilities Existing refinery (2.4 MW) Small LNG Existing LNG plant (.4 to .6 MW) Beluga Coal (40 employees in shipping) Coal gasification (0 to 250 MW)2/ New capital (2,750 employees 1982-84) New city (0 to 30 MW) Refinery -petrochemical complex l/ New refinery (0 to 15.5 MW) Pacific. LNG New LNG plant (0 to 17 MW)' Bottom fish industry Oil lease development Mining and mineral plants (5 to 50 MW) No new pulp mills or sawmills Timber (2 to 12 MW) Existing chemical plant (22 to 26 MW) Aluminum smelter or other energy intensiv industry (0 to 280 MW) MID RANGE 3/ L 0 W RANGE Pacific LNG New LNG plant (0 to 17 MW) Existing refinery (2.4 MW) Existing LNG plant (.4 MW) Existing chemical plant (22 MW) Coal gasification (0 to 10 MW) New refinery (0 to 15.5 MW) Mining and mineral plants (0 to 25 MW) Timber (2 to 12 MW) 1/ A recent decision by ALPETCO changes this to the Valdez area. The changes involved were not enough to warrant forecast revisions. 2/ Part of coal gasification could be equivalent to "Beluga Coal," but it is much more than "40 employees in shipping." 3/ At the time this forecast and analysis was performed, no ISER mid -range projections of populations and employment had been developed. 37 Estimate of Future Demands Using the high and low population projections and high, mid, and low kwh/capita assumptions, six different net generation utility forecasts were obtained. From these, the high population/high energy use and the low population/low energy use were used for the high and low range final forecasts. The mid -range final forecast came from averaging the high population/low energy use and the low population/high energy use forecasts. In lieu of a mid -range net generation based on a mid -range population projection, these last two forecasts were enough alike to justify the average as mid -range net generation. Near the completion of this analysis, ISER provided APA with a mid -range population projection. Comparing the previous results with forecasts using these mid -range projections, APA concluded that the two were consistent and that no changes were necessary. National defense and self -supplied industrial forecasts were calculated from the.assumptions and summarized with the utilities on table 10 for the Anchorage -Cook Inlet area and table 11 for the Fairbanks -Tanana Valley area. Railbelt totals, both peak load demand and net generation, are summarized on table 12. Appropriate graphs follow each table on figures 9 and 10 for Anchorage -Cook Inlet, 11 and 12 for Fairbanks -Tanana Valley, and 13 and 14 for the Railbelt totals. Trend lines based on 1973-1977 average annual energy growth are superimposed on the energy graphs, figures 9, 11, and 13. 1973-1977 Average Annual Growth Anchorage -Cook Inlet 10.9% Fairbanks -Tanana Valley 7.1% Railbelt 9.9% Historical and forecast energy use comparisons are summarized in table 9. Comparison with Other Forecasts This section compares the present forecast (1978) with two previous forecasts, and forecasts available from various utilities. The previous forecasts included the 1976 report and its 1977 update. The 1977 update used 1975 criteria and assumptions. See table 13 for a comparison tabulation. In general, the present forecasts produced values less than the previous ones. 38 Table 9 NET ANNUAL PER CAPITA GENERATION (KWH) RAILBELT AREA UTILITIES Upper Susitna Project Power Market Analysis 1970 1977 1990 2000 2025 Anchorage -Cook Inlet Area Historical 4980 7630 High 16,300 21,400 35,100 Mid 14,000 17,500 22,400 Low 12,000 13,600 13,600 Fairbanks -Tanana Valley Area Historical 5655 10,240 High 18,400 24,000 39,000 Mid 16,300 20,300 26,000 Low 14,100 15,800 15,900 APA 11/78 Energy use per capita nearly doubled in both areas in the historical seven years. Growing use of electric space heating, electric cooking in place of gas and oil, and many other possibilities can justify the assumptions shown. Again, conservation has been factored in through decreasing growth rates. 39 N rl W rl cd Cn H z - +� i >4 CO H E-1 o, a �4 0 ~ O rr p+ x Pa � W O 4J � W W n El 0 O a x v J Pi O v] 000 00000 v'1 OO M000 N I d Ih N � M --I --I \Z u) O S CO O N M N w w O 0 1r1 0 00 0 -,7' M CO -t ri CY O CO N cM M N CO I- 0 O u1 -t 0 N w O M lO CV r1 0*1 M M N rl cl Cl: u1 000 \�OO�t 01 I ul O -t rn Cq N 7 ON 00 N N tr1 O� — u•1 rl I\ rl rl w w w w N � ri N r-i rl O lr1 ir) O1 0%% O O a\ -1-4 N MM N mr{n 2111 a% LI) r4 CO c+l .-I CII N m r-I rl rl rl U') o O O N p 00 d' .t m 1 nM CO I 0 ri u M M N �t �O Lr) I, Ol m O CO M M ON I" r, w O O O ul .-1 0 O1 N N I-, M N rI CO Rj N Cl CO MMN 00MCO m 1.0 ul vi rl M ) W rn z � A � W w o 04 •T-( o -t •H o Pa E-4 a x a x a EE a z H O O O � q -i 0 0 O -1 -1 •-4 3 O u1 I- rr M 00 all n ­4 O un 110 C7 w p m N '-I -t It m -;t M O •-� �t �O CO 1 -+ O Cb CO M� tetra o O O Ln r! -zr 00 O LI) --{ -t N ',0 I- "D M O ON \�O ul I" Ln N U a% ON rl --I Ln -It Ln �-O u'1 -t M CO 1 C O 110 x O O O .-i ir1 cc o r� rt Ln 3 M I" \.O u 1 M O -,t un �,O N u'1 N C7 d u•1 Ln CO o �t �t w 1 � �O d' N •--� N i� u'1 0 0 0 C% r♦ Ln 0 0 O 01 -4 lr1 M CO all d' m ,-i O M I" I` �' I,- C7 \.O CO Ln 1-1 ,� ri M CD \.0 O y �D 't Cn N CO ul �t 0 0 0 N •--1 ,-1 O O N N rl M O% m -t M N ri rl -It 0 I- C7 M ire CO •-.I ' 1 ri CO M M M O N �t M N rl ti0 �t M x O O Ln --t I� O O -4 Ln rl CO 3 co NC M M N r� I, v N o %O C5 w u1 M Tw 1 - i --I rt ,-I r4 o CO Ln N N,N M N N o rl o j o 01 Co o \-O r-4 ri n L O W M z w W W Q b 3 ^d 3 to"d 3 tov 3 y •�+ o r.4 •H o 94 •r-i� •,o •r-i -H o HxZ azx aE+za Cn F-4 40 Figure 9 -j ow .z Ui �. .-. 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Historic values through 1977 fell between the high and low ranges of the forecast. The 1976 report was based on load data through 1974 and the following assumptions for utility load growth: Average Annual Growth Rates 1974-1980 1980-1990 1990-2000 High Range 14.1% 9.0% 8.0% Mid -Range 12.4 7.0 6.0 Low Range 11.1 6.0 4.0 The following percentages compare this report and the above assumptions. Average Annual Growth Rates From 1978 Utility Energy Forecast 1977-1980 1980-1990 1990-2000 High Range 14.5% 9.0% 7.5% Mid -Range 11.5 6.8 6.0 Low Range 8.7 4.5 4.5 The 1976 report based the utility energy forecast on assumed average annual growth rates. The 1978 report based the forecast on assumed growth in population and per capita energy use. Both reports considered energy conservation, but it was given more specific and higher importance in the 1978 forecast. Forecasts available from various utilities are tabulated on tables 14, 15, and 16. Some were done by the utilities, some by consultants, and some by REA. All data was tabulated and, where necessary, extrapolated as part of the State Alaska Power Authority Railbelt Intertie Study. Comparisons are summarized in 5-year increments. Energy (GWH) 1980 1985 1990 1995 2000 Peak (MW) 1980 1985 1990 1995 2000 Utility Forecasts 3,344 6,277 10,965 17,748 26,550 1978 Susitna Forecasts High Mid Low 3,410 3,155 2,920 5,460 4,455 3,630 8,200 6,110 4,550 11,600 8,140 5,690 16,920 10,940 7,070 725 778 720 667 1,377 1,244 1,021 830 2,986 1,873 1,396 1,039 3,835 2,645 1,858 1,298 5,641 3,865. 2,497 1,617 50 The utility forecasts run higher than those of this report. No definite reason for the differences can be made other than the utilities assumed higher growth rates. The basis of the utility assumptions was not considered in this study. Tab le 14 UTILITY ENERGY FORECASTS (GWH) ANCHORAGE -COOK INLET AREA Upper Susitna Project Power Market Analysis Year AML&P 1/ CEA 2/ MEA 3/ HEA 4/ Total 1979 634 1,109 280 310 2,333 1980 699 1,283 333 374 2,689 1981 771 1,468 395 452 3,086 1982 847 1,679 468 546 3,541 1983 930 1,921 559 620 4,030 1984 1,018 2,197 668 705 4,588 1985 1,111 - 2,509 799 800 5,219 1986 1,210 2,810 954 909 5,883 1987 1,313 3,147 1,140 1,033 6,634 1988 1,422 3,525 1,322 1,155 7,424 1989 1,534 3,948 1,534 1,290 8,306 1990 1,650 4,422 1,779 1,442 9,293 1991 1,770 4,864 2,064 1,611 10,309 1992 1,891 5,350 2,394 1,801 11,437 1993 2,014 5,885 2,706 1,978 12,584 1994 2,138 6,474 3,057 2,173 13,843 1995 2,245 7,121 3,455 2,388 15,209 1996 2,357 7,691 3,904 2,623 16,575 1997 2,475 8,306 4,412 2,882 18,075 1998 2,599 8,971 4,853 3,111 19,533 1999 2,729 9,638 5,338 3,359 21,113 2000 2,865 10,463 5,872 3,626 22,826 a Source: Obtained from utilities in 1978 for Alaska Power Authority Railbelt Intertie Study. l/ Anchorage Municipal Light & Power Department 2/ Chugach Electric Association 3/ Matanuska Electric Association 4/ Homer Electric Association APA 1/79 52 Table 15 UTILITY PEAK DEMAND FORECASTS (MW) ANCHORAGE -COOK INLET AREA Upper Susitna Project Power Market Analysis Year AML&P 1/ CEA 2/ MEA 3/ HEA 4/ Total 1979 124 239 67 64 495 1980 138 271 81 78 567 1981 152 310 97 94 653 1982 167 355 116 113 752 1983 184 406 142 129 860 1984 202 465 171 146 983 1985 221 530 207 166 1,124 1986 241 594 251 188 1,274 1987 263 655 303 214 1,445 1988 285 745 343 239 1,612 1989 309 835 389 267 1,800 1990 333 935 442 299 2,008 1991 358 1,028 501 334 2,222 1992 384 1,131 569 373 2,458 1993• 411 1,244 630,' 410 2,695 1994 437 1,369 698 451 2,954 1995 461 1,505 773 495 3,234 1996 486 1,626 857 544 3,512 1997 512 1,756 950 598 3,816 1998 539 1,901 1,026 645 4,111 1999 568 2,048 1,108 696 4,421 2000 599 2,212 1,197 752 4,759 Source: Obtained from utilities in 1978 for Alaska Power Authority Railbelt Intertie Study. l/ Anchorage Municipal Light & Power Department 2/ Chugach Electric Association 3/ Matanuska Electric Association 4/ Homer Electric Association 'APA 1/79 53 Table 16 UTILITY ENERGY AND PEAK DEMAND FORECASTS FAIRBANKS-TANANA VALLEY AREA Upper Susitna Project Power Market Analysis Net Energy (GWH) Peak Demand (MW) Year GVEA 1/ FMU 2/ Total GVEA FMU Total 1979 450 144 594 111 33 144 1980 502 153 655 123 35 158 1981 .560 162 722 136 37 173 1982 62-5 172 796 151 39 190 1983 693 182 875 167 42 209 1984 769 193 962 186 44 230 1985 853 205 1,058 206 47 253 1986 947 217 1,164 228 50 278 1987 1,050 230 1,280 252 53 305 1988 1,155 244 1,399 278 56 334 1989 1,271 259 1,529 305 59 364 1990 1,398 274 1,672 335 63 398 1991 1,537 288 1,825 368 66 434 1992 1,691 302 1,993 405 69 474 1993 1,843 317 2,160 440 72 512 1994 2,009 333 2,342 480 76 556 1995 2,190 350 2,540 521 80 601 1996 2,387 367 2,754 569 84 653 1997 2,602 386 2,987 619 88 707 1998 2,810 405 3,215 668 92 760 1999 3,035 425 3,460 722 97 819 2000 3,278 446 3.724 780 102 882 Source: Obtained from utilities in 1978 for Alaska Power Authority Railbelt Intertie Study. l/ Golden Valley Electric Association 2/ Fairbanks Municipal Utilities APA 1/79 54 Load Distribution Reservoir operation studies used in sizing reservoirs need an average monthly distribution of annual energy to help relate hydroelectric output to the electric load. This section reports updated averages of monthly energy use divided by annual energy use within the Anchorage -Cook Inlet area. This section also reports a study of hourly load distribution in the weeks of winter peak load (same as annual peak) and summer minimum peak load. By studying these load curves from several years, hydroelectric plant factor is evaluated. (See capacity section). The utility systems have had combined annual load factors slightly over 50 percent in the past few years (54 percent in 1977 as shown on figure 17) Data presented in table 17 shows that mid -summer peaks have been . running about 60 percent of mid -winter peaks and that monthly load factors generally exceeded 70 percent. For 1977, the December load factor was 76 percent. Figures 15 and 16 illustrate that winter and summer loads are quite similar. The load duration curves of figure 17 present these daily load curves concisely. The 1976 report contains daily load curves of previous years. Winter and summer curves are plotted together showing similarities of slope and shape. The update of average monthly energy is presented as percent of the annual value in table 18. Average percentages used in the 1976 report compare closely with 1970-77 averages. Slight changes are reflected in the "recommended distribution" column. Winter load is about two-thirds of total. 55 Figure 17 Al"'mICHORAGE AREA LOAD DURATION CURVE 1977 Upper Susitna Project Power Market Analysis December 1977 54% Load Factor Winter Peak Load Winter Base Load f June 1977 i Summer Peak Load Summer Base Load 65% 27% 0 10 20 50 40 50 60 70 80 90 100 % TIME APA 12/78 58 ul ca cn F-1 F�T W $ 4: U O 0 - t� t-1 E-i U Gt r4 p n �f rn PWi Qa � H � 4 01-4 a.: o. :161L.1 P1'0`1 -tto j t0 tD to r Ir r to r t0 -. r 'D r M t t0 r 03 r V• r to r M r r r N to .r a, v� o o M .-t M r r Gl ' t RMA OT AGrou; N M M C, ' .-f O r i lD rt .i t0 tof 9 (O 4 Gl t CV N O N C0 i U C14 r .-1 t0 i �: .-1 V' .-4 to —f iD 14 r is r4 Xnod jt:tWtltl •, co Q c0 co O O N O, r Co O Gl N CD O r to t0 M 10 r t0 is r co r M v` c0 O V' m O rl tD M O �,�f X�•ad O, to O t0 N 0 tD r to to a, ID 1; M v' co to t7 r to -4 Ch O 14 M to el C4 Ir M M M M N N N N M �oPt peol uo:d0 Ir n In iD 17 r 91- r- r, r- C- t0 O N M M to to O O O � Ol N r al LIMA Oi AGzau j in to to M cn r a% to co Q` o, -4r1 9 to a% N 14. 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G p +7 u k. 14nt :: Q rJ .: � ri n +7 t r2 Q to i .... r-i Table 18 MONTHLY ENERGY REQUIREMENTS AS PERCENT OF ANNUAL REQUIREMENT Upper Susitna Project Power Market Analysis 1970-1972 1970-1977 Utility Utility Recommended MONTH Loads 1/ Loads 2/ Distribution 3/ Oct. 7.9 8.1 8.2 Nov. 8.9 9.2 9.0 Dec. 10.2 10.2 9.7 Jan. 11.3 10.8 10.2 Feb. 9.2 9.3 9.1 Mar. 9.8 9.4 9.1 April 8.0 7.8 7.9 May 7.2 7.3 7.6 June 6.5 6.6 7.0 July 6.4 6.7 7.1 Aug. 7.1 7.1 7.4 Sept. 7.5 7.5 7.7 Total 100.0 100.0 100.0 SEASONAL Oct. -April 65.3 64.8 63.2 May -Sept. 34.7 35.2 36.8 1/ Combined loads of CEA, AML&P, GVEA, FMUS, for Oct. 1970-Sept. 1972. Basis for (1975 Susitna Power market analysis) 1976 report. 2/ Combined net generation of CEA, AML&P, APA, GVEA, FMUS, for Oct. 1970-Sept. 1977. Updated Basis. 3/ Assumes total requirements consisting of 25 percent industrial loads and 75 percent utility loads. Update of previous recommendations. 6 60 Capacity Requirements With reference to the load factor evaluations in the previous section, a trend towards somewhat higher annual load factors in the future is anticipated. In addition to benefitting from any load diversity in the interconnected system, peak load management (including such practices as peak load pricing) offers considerable opportunity for improving load factors, which in turn reduces overall capacity requirements for the system in any given year. For planning purposes, it is assumed that the annual system load factor will be in the range of 55 to 60 percent by the latter part of the century. System capacity requirements are determined by winter peak load requirements plus allowances for reserves and unanticipated load growth. The lower summer peaks provide latitude for scheduled unit maintenance and repairs. System daily peak load shapes indicate that a very small portion of the capacity is needed for very low load factor operation. Some of the gas turbine capacity now" used for base load is expected to be used mainly for peak shaving purposes, eventually. It will be operating during peak load hours for the few days each year when loads approach annual peak, and will be in standby reserve for the balance of the year. Figure 17, the annual peak week duration curve, shows that the highest 10 percent load occurs for 30 percent of the week (about two days). i Reliability standards would be upgraded as the power systems develop. Likely inclusions are specific provisions for maintaining spinning reserve capacity to cover possible generator outages and substantial improvements in system transmission reliability. Results — Examination of the winter load duration curve (figure 9) indicates that the base load portion is about 65 percent of total load and the peak load is about 35 percent of total load. Load factor for the peak portion is about 54 percent. Winter weekly load factors are approximately 8.0 percent. ,This is illustrated in the winter and summer load duration curves by proportioning the areas under the curves to the total possible area if peak load occurred 100 percent of the time. An annual plant factor of 50 percent is recommended for the proposed Upper Susitna Project. This is largely a judgment factor and is based on the following considerations: 1. The recommended plant factor provides for serving a proportional share of both peaking and energy requirements throughout the year while maintaining adequate flexibility to meet changing conditions in any given year. 2. Any significant reduction in this capacity could materially reduce flexibility. 61 3. A significant market for low load factor peaking capacity seems unlikely within the foreseeable future. Load management and additional industrial loads will probably increase the overall system load factor in the future. It is expectgd that several existing and planned gas turbine units could eventually be used for peak shaving. 4. It is recognized that the mode of operation for the hydro will change through time. In the initial years of operation, it is likely that the full peaking capacity will be used infrequently. For example, the mid -range Railbelt estimated system peak load for the year 2000 is 2,852 MW. Assuming load shapes similar to the current Anchorage area loads, the winter peak week would require about 1,850 MW of continuous power to cover the base loads and about 1,000 MW of peaking power. Load factors of the peak portion would be about 50 percent. A design capacity based on 50 percent plant factor applied to average annual energy (primary plus secondary) appears appropriate. Machine overload capability contributes to spinning reserves for emergencies or other short term contingencies. The Corps based nameplate capacity on 50 percent plant factor applied to critical year firm energy. This smaller capacity, when applied to average annual energy, results in a 56 percent plant factor. APA feels the smaller design capacity may unduly reduce flexibility. 62 PART VI. ALTERNATIVE POWER SOURCES Introduction This section examines alternative power supply options in, the Railbelt in lieu of the Upper Susitna Project and presents detailed cost estimates of power from new coal-fired steam plants. Alternatives premised on unproven technology were eliminated. Alternatives Considered Potential alternative sources of electric power generation are identi- fied by energy type. They are coal, oil and natural gas, hydro, nuclear, wind, geothermal, and tide. Some ,alternatives will be restricted in time or capacity because of Federal energy policy controlling use of energy resource. Others will be restricted by practical available energy supply. Still others are impractical because of lack of large-scale technology. Coal Evaluation of coal 'utilization is based on mine -mouth coal-fired steam generation. Potential advanced technology, such as gasification, is not considered because development would not be available within this study period. Recent studies provide general information about possible locations, sizing, and cost of new steamplants, but Alaska specific data are limited and extrapolations have been made for local conditions. Information sources of specific interest for this analysis are: studies by Battelle Pacific Northwest Laboratories (March 1978); the Electric Power Research Institute (EPRI) (January 1977); and the Washington Public Power Supply System (WPPSS) (June 1977); the Federal Energy Regulatory Commission (FERC) determination of power values for the Bradley Lake Project (October• 1977) and the Upper Susitna Project (October 1978); and evaluations of costs for the proposed Golden Valley Electric Association (GVEA) plant additions at Healy. These are all listed in the bibliography. Location - It is assumed that new coal-fired steamplants would be located near the Beluga fields for service to the Anchorage -Cook Inlet area and at Healy for service to the Fairbanks -Tanana Valley area. The plants would use known but undeveloped coal resources at Beluga and the existing coal mining operation near Healy. 63 It is recognized that other locations are possible. For example, it may be possible to locate a coal-fired plant on the Kenai Peninsula and .use coal from either local reserves or Beluga. A Kenai location might offer co -generation possibilities because steam could be reused in manufacturing by the petrochemical industry. The potential for mining coal on the Kenai Peninsula is substantially less attractive than for Beluga because of thin coal seams and other geologic factors. Capacity - These analyses are for two -unit 200-MW and 500-MW plants. This size range is considered appropriate for new coal-fired plants that might come on-line between 1985 and 2000. Investment Cost - Table 19 summarizes unit investment costs for new coal-fired plants presented in several recent studies. The data assembled by each entity is quite complex with respect to original estimated price levels, inflation to updated price levels, or projected future on-line dates, size, pollution control equipment, location, type of plant, and other items. Price levels were not adjusted to a uniform date because of the complexity of data involved. All 1977 and 1978 estimates are substantially higher than APA estimates for the 1976 Alaska Power Survey and the 1976 report. The most in-depth analysis was the WPPSS study which investigated the construction of 1,000-MW steamplants at 10 plant sites in Washington, Montana, and Wyoming. Several grades and sources were assumed. Costs were estimated for with and without sulphur dioxide scrubbers (scrubbers). Twenty-two options of plant sites, coal supply, and trans- portation were investigated. APA's estimate of coal-fired steamplant investment costs is derived from the WPPSS study. Procedures for adjusting costs to current Alaska conditions are similar to the analysis used in the appended Battelle report. 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P. J CO F z> G co r�-1tj H C 0 U p f=+ C5 r I Pa W C!) H H H O w ai H .0 ro U cn a P-1 cca a W 1--I rt I N I M I �' I U1 I�,o I^ I 66 Adjusting the cost for the time between mid-1976 and October 1978 using the Handy -Whitman Steamplant Cost Index increased the cost 18.4 percent. Without Scrubbers $656/kw With Scrubbers $810/kw Powerplants smaller than the 1,000 MW that will fit near -future Alaska power needs have a smaller total cost, but a larger cost per installed kilowatt. An adjustment needs to be applied to the costs to compensate for the loss of economy of the large scale plants. The factor recom- mended is the ratio of the plant size to the 0.85 exponent. A 500-MW plant thus costs 55.5 percent of a 1,000 MW plant, and a 200-MW plant costs 25.5 percent. Scaling the plants to 200 MW and 500 MW -gives: Plant Size $ Million Without Scrubbers 167,000 With Scrubbers 207,000 200 MW 500 MW $/kw $ Million $/kw 835 364,000 728 1,035 450,000 899 An Alaska factor of 1.8 was used to adjust Pacific Northwest costs to Alaska wages and conditions: Plant Size $ Million Without Scrubbers 300,000 With Scrubbers 372,000 200 MW 500 MW $/kw $ Million $/kw 1,500 655,000 1,310 1,860 810,000 1,620 Fuel Cost and Availability - There is a wide range of opinions about the probable future cost of coal. For many years, coal prices were set at a small margin above production costs so that coal could compete, with low-cost oil and natural gas. This situation has changed drastically because of price increases for oil and gas and incentives for power generation and has resulted in industrial conversion to coal. Coal production costs are also increasing rapidly due to normal inflationary and regulation factors. FERC reported the national average price of coal at 96.2�/million Btu in July 1977, up from 80.8(� in July 1975, and 39.8(,, in August 1973. Alaskan coal prices have shown sizable increases recently. The cost of coal at Healy in September 1978 was 80 cents per million Btu, up from 62 cents in 1975. The Fairbanks Municipal Utility System (FMUS) pays an additional $6/ton shipping cost for Healy coal resulting in a price of .$1.15 per million Btu at the powerplant in Fairbanks. 67 In October 1978, owners of the Beluga coal field stated that large reserves in the Beluga coal field may compete in the world energy market at a price of $1.10 to $1.40/million Btu stockpiled on the shore of Cook Inlet. The conclusions were based on company studies that included geologic investigations, drilling, bulk sampling programs, mining preparation, environmental evaluation, and navigation and shipping studies. FERC estimated $1.00/million Btu for determination of power values in the Bradley Lake Project (October 1977). Other recent studies suggest this is a reasonable current (1978) cost for Beluga coal delivered to a steamplant at Beluga, with no allowance for price increase in future years. Earlier APA studies for the 1976 FPC Power Survey and the 1976 Susitna report assumed $1.00 to $1.50/million Btu for coal at 1985 price levels in 1974 dollars. This included consideration of future economies of scale of larger mining operations. APA analyses for this report are still based on a coal cost of $1.00 to $1.50/million Btu for a mine -mouth plant at either Beluga or Healy for mid-1980 conditions. This is comparable with $1.28 in 1985, estimated by GVEA for Healy coal by increasing the current 80 cents by 7 percent annually. Because of the wide diversity of studies and opinions, analyses based on a range of costs are presented. In this study, we are assuming fuel values will increase about 2 percent per year --more rapidly than overall price indexes. This is consistent with other analyses. Table 20 GENERATION COSTS FOR CONVENTIONAL COAL-FIRED STEAMPLANTS Upper Susitna Project Power Market Analysis 1985 COSTS (1978 PRICES)l/ Number of Units Investment Cost, Raifbelt, $/kw Capital Cost, mills/kwh Operation and Maintenance, mills/kwh Subtotal Assumed Fuel Costs, mills/kwh Transmission Cost to Load Center Total Energy Cost, mills/kwh 1994 ENERGY COST Capital Cost, mills/kwh Operation and Maintenance, mills/kwh Transmission Cost, mills/kwh Subtotal Plant Size, MW 200 500 2 2 1,860 1,620 38.5 33.5 6.5 5.6 45.0 39.1 1.00/mmBtu 1.50/mmBtu 10.0 15.0 10.0 15.0 4.0 4.0 3.0 3.0 59.0 64.0 52.1 57.1 Fuel escalated 2%/year 1985 to 1994 38.5 33.5 6.5 5.6 4.0 3.0 49.0 42.1 Fuel, Inflated 2% 1985 to 1994 12.0 17.9 12.0 17.9 Total 61.0 66.9 54.1 60.0 Fuel Escalated 7%/Year from 1285 to 1994; Capital Cost and 0&M Escalated 5%/Year from 197.8 to 1994 Capital Cost 80.0 Operation and Maintenance 13.5 Transmission 8.3 Subtotal 101.8 Fuel Total 18.4 27.6 18.4 120.2 129.4 105.9 69.7 11.6 6.2 87.5 27.6 115.1 l/ APA estimate basedon studies by Washington Public Power Supply System Studies 1977. Cost of Power - The estimated total cost of electric power that would be generated by a coal-fired steamplant alternative to the Susitna project is presented in table 20. Development of the estimated cost applied to a plant in either the Beluga or Healy area is based on the investment and fuel costs discussed earlier in this section, and includes other criteria developed in this report. In summary, the parameters are: 1. Investment cost includes all construction, overhead, and interest during construction, and is based on updating and adjusting WPPSS Pacific Northwest costs for Alaska conditions. Annual capital costs are based on a 35-year life and 7 percent interest rate. 2. Operation and maintenance costs are based on a detailed WPPSS personnel and materials estimate adjusted for plant capacity in the same manner as investment costs, increased by 50 percent for Alaska conditions, as developed in the 1976 Alaska Power Survey, and indexed from January 1977 to October 1978 using the U.S. Department of Labor index. 3. Fuel costs of both $1.00 and $1.50/kw are presented with a heat rate of 10,000 Btu/kwh. 4. Transmission costs are for lines connecting Beluga with Anchorage, and Healy with Fairbanks. The resulting average unit cost of electric power from coal-fired steamplants to supply the Railbelt market area ranges from 5.21 to 6.40,/kwh, varying with fuel cost and plant capacity. Table 20 also presents an analysis of the cost of energy with fuel costs escalated at 2 percent anually from 1985 through 1994 (Susitna project, Watana phase on-line) and fuel cost escalated at 7 percent annually from 1985 through 1994. Comparative Cost of Power (FERC) - FERC evaluated alternative costs for coal-fired steam plants at Beluga for the Anchorage area and Healy for the Fairbanks area as part of their power benefit studies for the Upper Susitna Project. The FERC estimates of 4.93 to 5.64(,�/kwh are in the same range as those estimated by APA for the Anchorage area. However, the FERC estimates of 4.02 to 4.30(,%/kwh for the Fairbanks area are low compared to APA estimates. FERC estimated construction costs (July 1978) at $1,475/kw compared to $1,810/kw estimated by APA. In addition, GVEA recently estimated a cost of $1,800/kw for a comparable Healy steamplant. FERC data are based on: 1. An Anchorage area plant assumed to be a two -unit 450-MW plant with fuel cost of $1.10/million Btu and a heat rate of 10,000 Btu/kwh. The Fairbanks plant is assumed to be two units, totaling 230 MW, with a fuel cost of $0.80/million Btu and a heat rate of 10,500 Btu/kwh. For non -Federal cases, the Anchorage area plant investment cost was estimated at $1,240/kw and the Fairbanks investment cost at $1,475/kw. 70 , 2. Financing is based -on a composite Anchorage -Kenai interest rate of 7.9 percent with 75 percent financing by REA at 8.5 percent and. 25 percent by the municipality of Anchorage at 6.25 percent. The interest rate for Fairbanks is 5.75 percent assuming State of Alaska Power Authority financing. In comparison, a Federal rate of 6.875 percent is used for both areas, the same rate 'used in the Corps of Engineers benefit analysis. Oil and Natural Gas The Upper Susitna Project involves a large new power supply beginning in 1994, with an expected life in excess of 100 years. APA does not believe that oil and natural gas are realistic alternatives for equivalent power supplies, particularly in view of the timeframe (start in 1994) and very long life (through 2094). Hydro Criteria - Evaluation of possible hydroelectric generation alternatives to the Susitna project is based on comparing: (1) the potential generation capability, and (2) unit cost of power. Possible sites are identified by: (1) single sites with sufficient capacity to supply the projected' power demands; (2) combinations of smaller sites within selected geographic areas and river basins; and (3) a combination of the best sites from all areas accessible to the Railbelt. The hydro evaluation considered power requirements ranging from 600 MW to 2,290 MW, which are, respectively, the low -range and high -range projected increases in Railbelt demands from 1990 to 2000. Associated annual firm energy requirements would range from 2,670 gwh to 10,260 gwh. By comparison, the Susitna project is scheduled to provide about 1,573 MW capacity and 6,100 gwh annual firm energy. Possible hydro generation alternatives were selected from the APA inventory of hydroelectric resources. The inventory estimates unit cost of power at the generator bus bar based on 1965-1966 cost at 3 174 percent interest rate. Susitna inventory cost data indexed to 1975 price levels give unit costs within 10 percent of that determined for the 1976 report. Single Large Capacity Sites - Seven single sites have sufficient capacity potential to be an alternative to supplying minimum Susitna market area requirements. These are within a maximum of 1.4 times the unit cost for Susitna power. However, land use designations (National Parks and Monuments and Wild and Scenic Rivers) and/or known major environmental impacts preclude consideration of developing any of the sites at the present time. 71 The sites are: Site Stream Firm Capacity Percent Energy MW of Susitna GWH/yr Cost Holy Cross Yukon R. 12,300 2,800 140 Ruby Yukon R. 6,400 1,460 62 Rampart Yukon'R. 34,200 5.,040 32 Porcupine Porcupine R. 2,320 530 79 Woodchopper Yukon R. 14,200 3,200 71 Yukon-Taiya Yukon R. 21,000 3,200 52' Wood Canyon Copper R. 21,900 3,600 51 None of the above sites can be considered available resources in the 1990's timeframe. This is due to: (1) Holy Cross, Ruby, Rampart, and Woodchopper are main -stem Yukon River sites with known major environ- mental problems, (2) Porcupine, Woodchopper, and Yukon-Taiya have major international considerations, and (3) Wood Canyon has a known major fishery problem. Sites within the Nenana River basin have also been identified in past work. Their economic feasibility depends upon being developed as a unit. However, several of the sites are located partially within Mount McKinley National Park and are precluded from development. In conclusion, no single, large hydro generation sites are available as alternatives to the Upper Susitna Project. Combination of Small Capacity Sites - Combinations of single sites with less capacity than the Susitna project consist of 78 sites within the Matanuska, Tanana, Yentna-Skwentna, Talkeetna, and Chulitna River basins, the northwest drainage of Cook Inlet, the Kenai Peninsula, and scattered small sites' and small basins within the Railbelt area. None of these areas contain sites with total capacity potential to supply minimum Susitna requirements. (Site combinations with the most capacity --the Yentna-Skeentna River basin and Kenai Peninsula --total 609 MW and 646 MW respectively, but with costs for individual sites ranging from 1.4 to 20 times Susitna costs.) If consideration is given to combining the best small sites from each of the geographic areas, 12 sites totalling 1,276 MW are within the range of twice the cost of Susitna. Only one (Chakachamna) is near Susitna cost (103 percent), and has 366 MW potential. Chakachamna is partly within the new Lake Clark National Monument. Other new or proposed Federal land withdrawals would preclude sites with about half of the total potential of the combined sites. Other sites have various environmental impact potentials. Some streams that would be affected have major anadromous fish resources. Also, because the sites are widely distributed, the needed transmission systems would be fairly extensive and costly. 72 Summary - Based on examination of individual sites and combinations of sites, there are no hydro generation opportunities available to provide enough power to be an alternative to the Susitna Project. Small individual sites may be available, but would satisfy only a small portion of the market area demand. Other sites, with apparently acceptable quantity and economic capability, have been or will be precluded by land status designation. Nuclear Nuclear generation may be technically viable in Alaska, but probable cost and siting problems eliminate it as a potential alternative to Susitna. Available information indicates that in other states, nuclear is economically competitive with coal, depending on specific conditions. Difficult conditions, possible seismic and environmental siting problems, and readily available coal indicate that nuclear generation will probably not be economically attractive in Alaska in the foreseeable future. Wind The State has shown serious interest in wind generation technology by developing pilot projects in the bush communities of Ugashik, Nelson Lagoon, and Kotzebue. Wind seems to provide near -term power for small communities presently dependent on high -cost diesel generation. The cost and applicable scale of technology does not make wind power a viable alternative for large near -future power demands. Geothermal Investigations to date have found no high quality geothermal resources suitable for power development in areas accessible to the Railbelt area. Geothermal potential is considered high in the Wrangell Mountains and portions of the Alaska Range, and may be applicable to the Railbelt in the future. At this time, insufficient data are available to define the resource, even for appraisal of the large Susitna project market. Tide There is a large physical potential for tidal power development in the Cook Inlet area where the State estimates that a total of 8,560 MW could be harnessed.' A potential of 785 MW is estimated for Knik Arm alone, and approximately twice that amount for Turnagain Arm. Several different concepts have been developed for the Cook Inlet tidal potential because of the interest in alternative energy sources. There is merit to preparing a good reconnaissance of this alternative, as pointed out in the 1976 report. However, the scope of work involved to develop the tidal resource, the large, cost of development, and the important environmental considerations eliminate tidal power as a reasonable alternative to the Susitna project. 73 The range of power options for the Alaska Railbelt is narrowing rapidly. 1. Oil and natural gas are very suspect in terms of long-range national supply and availability for use in power production. 2. Coal is proving to be far more expensive as a power source than previously anticipated. 3. Many hydroelectric alternatives have moved to the "unavailable" classes because of land area designations. The remaining are less desirable in terms of cost and ability to meet projected requirements. 4. Nuclear is expected to be as expensive as coal. 5. Geothermal, tide, and wind are unrealistic planning alternatives at this time. 74 PART VII. LOAD/RESOURCE AND SYSTEM POWER COST ANALYSES Introduction A series of load/resource and system cost analyses were made to demonstrate impacts of the Susitna project in terms of overall power system costs. The load/resource analysis -determined probable timing of new major investments in generation and transmission facilities. It also shows annual energy from each type of plant. The load/resource analyses were prepared for these basic power supply strategies: Case 1. All additional generating capacity assumed to be coal- fired steam turbines without a transmission interconnection between the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area. load centers. Case 2. All additional generating capacity assumed to be coal- fired steam turbines, including a transmission interconnection. Case 3. Additional capacity to include the Upper Susitna project (including transmission intertie) plus additional coal as needed, and for the three load limits (high, medium, and low). The system cost analyses, keyed to the load/resource, determined cost by year to amortize investments and pay all annual costs (fuel, 0&M expenses, etc). Inflation rates of 0 and 5 percent were considered. APA developed a number of the key inputs, e.g., demands, unit sizes and costs, etc. APA contracted with Battelle to make the' studies and prepare the report. This section summarizes key assumptions and results. More detailed information is available in the appended Battelle report. Basic Data and Assumptions Basic data and assumptions used in the load/resource and system power cost analyses are: 1. Interest rate for repayment of facilities = 7 1/2 percent. 2. Inflation rates of 0 and 5 percent, with construction costs increasing at inflation rate, and fuel costs increasing at 2 percent above -inflation rate. 3. System reserve capacity of 25 percent for non -interconnected load centers and 20 percent for interconnected systems. 4. Transmission losses of 1.5 percent for energy and 5 percent for capacity. 75 5. Retirement schedules for proposed generating facilities (economic facility lifetime):l/ Years Coal -Fired Steam 35 Oil -Fired Steam 35 Gas -Fired Combustion Turbine 20 Oil -Fired Combustion Turbine 20 Hydroelectric 50 Diesel 20 6. Plant factors for new and most of the existing facilities are: Percent Hydro 50 Steam 75 Combustion turbine 50 Diesel 10 The factor for combustion turbines was reduced to 10 percent in the study when adequate steam turbine capacity was available. l/ See tables 3.4 and 3.5 of appended Battelle report for estimated retirement dates of existing facilities. 7. Hydro plants designed for 115 percent of nameplate capacity for limited reserve requirements. 8. Watana power on-line (POL) in 1994 and Devil Canyon POL in 1998. 9. Existing and planned generating facilities for Anchorage and Fairbanks are shown in the appended Battelle report. 10. New coal-fired steamplants for Fairbanks assumed to be 100-MW units (first six), then 200-MW units. Anchorage units assumed to be 200 MW (first five), then 400-MW units. 11. New coal-fired steamplants to be located at Beluga for Anchorage area and at Healy (or other sites within 100 miles) for Fairbanks. 12. Fuel costs --see appended Battelle report. 13. Power demands will be met by resource allocation using Susitna hydro generation first, coal-fired second, and natural gas and oil last. 14. Heat rate for new coal-fired steamplants = 10,500 Btu/kwh. 76 15. Total investment cost in October 1978 dollars. Plant 100-MW Coal Steam Turbine 200-MW Coal Steam Turbine 400-MW Coal Steam Turbine Watana Dam (795 MW) and Transmission Line Devil Canyon Dam (778 MW) Total Susitna Project (1,573 MW) ($ million) ($/kw) 245.4 2,454 372.0 1,860 646.8 1,617 2,020.7 2,554 470.5 -- 834.0 1,072 3,335.2 2,120 16. Operation, maintenance, and replacement costs. Plant 100-MW Coal Steam Turbine 200-MW Coal Steam Turbine 400-MW Coal Steam Turbine Watana Dam (795 MW) Devil Canyon Dam (778 MW) New Transmission Facilities Study Methodology ($ million/yr.) ($/IOW/yr.) 3.76 37.6 5.7 28.5 9.3 24.5 0.74 0.941/ 0.73 0.941/ 2.01/ As stated in the introduction, three cases were analyzed to determine timing of generation and transmission (G&T) investments and their impact on total power system costs. The first step in estimating the cost of power from alternative generation and transmission system configurations was to perform a series of load/resource analyses. These analyses determined the schedule of major investments based on assumptions of load growths, capacity and energy production of the potential generating facilities, and constraints as to when the facilities could come on-line. The load/resource analyses also determined the annual power production from each type of generating plant in the system. The system cost analyses then determined the annual cost for amortizing and operating the facilities. Summing the annual cost for generation and transmission of each of the generating facilities gave a total cost, by year, for the entire system being analyzed. Dividing the total annual cost by'the power produced gave an average annual cost of power for the entire system. 1/ This breakdown of OM&R costs by project feature for convenience of the load/resource analysis resulted in slightly higher cost. Sign if i- cance to Susitna rate is, at most, less than 1 percent. 77 Rounded Thermal generating capacity additions to the year 2010 from the previous tables are summarized as follows: .Table 21 SUMMARY OF THERMAL GENERATING CAPACITY ADDITIONS TO THE YEAR 2010 Upper Susitna Project Power Market Analysis Case 1: Without Interconnection & Without Susitna Assumed Load Megawatts Growth Anchorage Fairbanks Total Low 2,600 471 3,071 Mid 4,600 871 5,471 High 8,200 1,471 9,671 Case 2: Interconnection Without Susitna, Assumed Load Megawatts Growth Anchorage Fairbanks Total Low 2,200 471 2,671 Mid 4,200 671 4,871 High 8,•200 1,271 9,471 Case 3: Interconnection With Susitna Assumed Load Megawatts Growth Anchorage Fairbanks Total Low 1,000 171 1,171 Mid 3,000 371 3,371 High 6,600 1,071 7,671 Note: Bradley Lake and Susitna hydroelectric projects are not included. 78 i Results Load/Resource Analyses The schedule of new plant additions for Anchorage and Fairbanks for 1978-2011 are shown in the appended Battelle report. A summary of the thermal generating capacity additions is in table 21. Further discussion of the computer model results and graphs are also shown in the appended Battelle report. Under the criteria used, completion of construction for interconnection is scheduled in 1986, 1989, and 1994 for high, mid and low load growth cases, respectively, without Upper Susitna. With Upper Susitna, the corresponding dates are 1986, 1989, and 1991. System Power Costs Annual system costs and unit power costs are presented in detail, both tabular and graphically, in the appended Battelle report. The following tabulations summarize these findings. Table 22 shows annual power system costs for cases 1, 2, and 3, high, mid and low range, with 0 percent inflation. The first few years after Watana comes on-line, the total annual power system costs increase slightly. However, comparing the total annual power system costs for the 1990-2011 period to case 1, construction of the Susitna project results in a savings of $2.20 billion, or 12 percent. Figure 18 shows the relative savings in annual cost for case 3, with Susitna, and case 1, without Susitna, for the three load growth assumptions. Tables 23, 24, and 24a summarize Anchorage and Fairbanks separately plus the combined system average annual power costs in (,I/kwh for 1978-2011. The tables verify the feasibility of the intertie in power cost savings for Anchorage and Fairbanks. By the year 2000, system wide power rates would be: 79 Average Power System Rates for Anchorage and Fairbanks - 0% Inflation (,,I/kwh) Case 1 Case 2 Case 3 Without Susitna With Intertie With Susitna or Intertie and'Intertie Combined Combined Combined Anch. Fbks. System Anch. Fbks. System Anch. Fbks. System High 6.2 8.8 6.6 1/ 6.1 8.0 6.4 5.8 6.2 5.8 Mid 6.6 8.9 6.9 1/ 6.2 8.4 6.6 5.5 6.7 5.7 Low 7.1 9.2 7.5 l/ 6.2 8.8 6.7 6.1 7.8 6.4 Comparison of Power Costs by Year 2000 Percent Change in Cost of Power Below Case 1 - 0% Inflation Case 2 Combined Anch. Fbks. System High -1.6 -10.0 -3.1 Mid -6.5 -6.0 -4.5 Low -14.5 -4.5 -11.9 Case 3 Combined Anch. Fbks. System -6.7 -41.9 -13.8 -20.0 -32.8 -21.1 -16.4 -17.9 -17.2 For the Anchorage -Cook Inlet area, inclusion of the Susitna Project into the system (case 3) generally raises the cost of power above cases 1 and 2 during the first two to four years after Watana comes on-line, but lowers power costs during the 1996-2011 period. This reduction in the cost of power is significant in most cases. For the Fairbanks -Tanana Valley load center construction of the inter- connection (case 2) again generally reduces the cost of power compared to without an interconnection (case 1). The inclusion of the Susitna project (case 3) generally raises the cost of power above case 2 for about two years after Watana comes on-line, but, as with the Anchorage -Cook Inlet area, results in lower power costs during the 1996-2011 period. l/ 'Anchorage and Fairbanks are not interconnected for case 1, the combined system rate is shown for academic comparison purposes only. :e # q* + 'S.' C')N O611!'1M tJ NO r-I W t�-i CO r�li r-I 1J7 ",T h Ci`f O t: Ol O to co"r"O M O C. 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CENTS PER KILOWATT HOUR - 0% INFLATION Upper_Susitna Project Power Market Analysis - Case l Year High Medium Low 78-79• 1.3 1_3 1_4 79-80 1.4 1.5 1_7 -80-81 1.3 1.6 -1.8 81-82 1.2 1.6 1.9 82-83 3.2 2.9 2.2 83-84 3_6 2.8 2.1 84-85 4.0 2.8 2.2 85-86 4.6 4.3- 2.4 86-87 5.0 4.2 2.3 87-88 4.8 4.7 3.7 88-89 5.4 4.4 3.5 89-90 5.1 4.8 4.2 90-91 4.8 4.5 4.1 91-92 5.2 5.0 4.1 92-93 5.5 5.6 .4.7 93-94 5.3 5.3 4.6 94-95 5.5. 5.1 5.3 95-96 5.8 5.6 5.7 96-97 5.9 6.2 6.5 97-98 6.0 6.5 -6.3 98-99 6.1 6.3 6.1 99-2000 6.2 6.6 7.1 00-01 6.3 6.4 6.9 01-02 6.1 6.3: 6.9 02-03 6.2 6.6 6.6 03-04 6.3 6.5 6.8 04-05 6.1 6.4 6.7 05-06 6.3 6.9 7_6 06-07 6.4 -6.8 7.5 07-08 - 6.3 6.8 7.5 08-09 6.4 6.7 7.5 09-10 6.5 6.6 7.5 10-11 6.3 6.9 7.5 * Interconnection Installed #r Watana on-line + Deveil Canyon on-line Case 2 Case 3 High Medium Low High Medium Low 1.3 1.3 1.4 1.3 --- 1.4 1.4 1_5 '1.7 1.4 --- 1.7 1.3 1.6 1.8 1.3 --- 1.8 1.2 1.6 1.9 1.2 --- 1.9 3.2 2.9 2.2 3.2 --- 2.2 3.6 2.8 2.1 3.6 --- 2.1 4.0 2.8 2.2 4.0 --- 2.2 4.6 4.3 2.4 4.6 --- 2.4 4.8 * 4.2 2.3 4.8 * --- 2.3 5.3 4.7 3.7 5.3 --- 3.7 5.1 4.4 3.5 5.1 4.4 3.5 5.7 4.5 4.2 5.7 4.5* 4.2 5.4 4.8 4.1 5.4 4.8 4.1 5.7 5.3 4.1 5.7 5.3 4.6* 5.4 5.9 4.7 5.4 5.9 4.4 5.7 5.6 4.6 5.7 .5.6 5.0 5.5 5.4 4.9* 6.4 6.9x 7.3 a 5.6 5.8 5.4 6.0 6.5 6.8 5.8 6.4 5.8 6.2 6.1 6.5 5.9 6.1 6.6 6.2+ 5.8+ 6.3+. 6.0 6.5 6.4 6.1 5.8 6.1 6.1 6.2 6.2 5.8 5.5 6.1 6.2 6.6 7.2 5.5 5.3 5.9 6.3 6.4' 7.2 5.6 5.2 5.6 6.4 6.3 7.1 5.7 5.7 5.7 6.2 6.7 7.1 5.6 5.6. 5.6 6.1 6.6 7.0 5.8 5.5 5.6 6.2 6.5 7.0 5.9 5.4 5.5 6.3 6.4 7.0 5.8 5.8 5.5 6.5 6.9 7.0 5.9 5.8 5.5 6.3 6.8 6.9 6.0 5.7 5.4 6.4 6.7 6.9 5.9 5.6 5.4 6.5 6.7 6.9 6.0 5.9 5.4 83 APA 11/78 Table 24 AVERAGE POWER COSTS - 0% INFLATION (�^M) FAIRBANKS-TANANA VALLEY AREA Upper Susitna Project Power Market Analysis Case 1 Case 2 Case 3 Year High Medium Low High Medium Low High Medium Low 78-79 4.1 4.3 4.4 4.1 4.3 4.4 1.3 4.3 4.4 79-80 4.1 4.3 4.5 4.1 4.3 4.5 1.4 4.3 4.5 80-81 4.1 4.3 4.7 4.1 4.3 4.7 1.3 4.3 4.7 81-82 4.0 4.3 4.7 4.0 4.3 4.7 1.2 4.3 4.7, 82-83 3.8 4.2 4.7 3.8 4.2 4.7 3.2 4.2 4.7 83-84 3.4 3.8 4.3 3.4 3.8 4.3 3.6 3.8 4.3 84-85 5.2 3.4 3.9 5.2 3.4 3.9 4.0 3.4 3.9 85-86 4.7 5.4 3.6 4.7 5.4 3.6 4.6 5.4 3.6 86-87 5.9 5.1 3.3 5.5 * 5.1 3.3 4.8 * 5.1. 3.3 87-88 5.6 4.8 3.0 5.1- 4.8 3.0 5.3 4.8 3.0 88-89 5.5 4.8 3.1 5.0 4.8 3.1 5.1 4.8 3.1 88-90 6.5 6.3 5.6 4.7 5.8 * 5.6 5.7 5.8 * 5.6 90-91 6.5 6.4 5.8 4.6 5.9 5.8 5.4 5.9 5.8 91-92 6.2 6.2 5.9 4.4 5.7 5.9 5.7 5.7 7.2 92-93 6.8 7.3 5.6 6.3 5.4 5.6 5.4 5.4 6.9 93-94 6.6 7.1 5.5 7.3 5.2 5.5 5.7 5.2 6.8 94-95 7.4 6.9 .7.1 7.0 6.5 6.7 * 6.4 # 6.8 # 8.8 # 95-96 7.2 6.9 7.3 7.8 7.7 6.9 6.0 6.7 8.9 96-97 7.6 7.8 7.1 8.2 7.4 8.3 6.2 6.4 8.6 97-98 8.1 8.3 7.9 8.7 7.8 9.1 6.2 6.9 7.8 98-99 8.9 9.1 9.4 8.3 8.7 '8.9 6.1 + 6.9 + 7.6 + 99-2000 8.8 8.9 9.2 8.0 8.4 ' 8.8 5.8 6.7 7.8 00-01 8.3 8.7 9.3 7.7 8.3 8.8 5.5 6.6 7.8 01-02 8.0 8.6 9.3 7.5 8.2 8.8 5.6 6.5 7.7 02-03 7.7 8.4 9.1 7.2 9.0 8.7 5.7 7.3 7.6 03-04 8.5 9.8 9.1 8.0 8.9 8.7 5.6 7.2 7.6 04-05 8.2 9.7 9.1 8.7 8.8 8.7 5.8 7.1 7.5 05-06 8.0 9.5 9.0 8.4 8.6 8.6 5.9 7.0 7.4 06-07 7.8 9.4 9.0 8.2 8.6 10.1 5.8 6.9 7.4 07-08 8.5 9.3 9.1 8.1 8.5 10.1 5.9 6.8 7.4 08-09- 8.4 9.2 9.0 7.9 8.4 10.1 6.0 6.8 7.4 09-10 8.2 9.1 9.1 7.7 8.3 10.2 5.9 6.7 7.4 10-11 8.0 9.1 9.1 7.6 8.2 10.2 6.0 6.6 7.4 * Interconnection Installed # Watana on-line + Devil Canyon on-line 84 Table 24a COMBINED ANCHORAGE -COOK INLET AND FAIRBANKS-TANANA VALLEY AREA AVERAGE ANNUAL POWER COST 1/(c/KWH) Upper Susitna Project Power Market Analysis Case 2 Case 3 YEAR HIGH MEDIUM 'LOW HIGH MEDIUM LOW 1978-79 1979-80 1980-81 1981-82 1982-83 1983-84 1984=85 1985-86 1986-87 4.90 * 4.90 1987-88 5.31 5.31 1988-89 5.07 5.07 1989-90 5.56 4.79 * 5.56 4.79 1990-91 5.24 5.06 5.24 5.06 1991-92 5.52 5.39 5.52 5.39 5.14 1992-93 5.58 5.83 5.58 5.83 4.89 1993-94 5.94 5.57 5.94 # 5.57 # 5.35 1994-95 5.71 5.63 5.28 * 6.67 6.91 7.59 1995-96 5.92 6.19 5.69 6.25 6.52 7.25 1996-97 6.18 6.61 6.29 6.35 6.17 6.93 1997-98 6.34 6.44 7.08 6.30 6.01 6.56 1998-99 6.36 6.88 6.91 6.14 + 5.96 + 6.39 + 1999-2000 6.37 6.61 6.68 5.84 5.68 6.42 2000-2001 6.47 6.87 7.54 5.70 5.50 6.23 2001-2002 6.53 6.75 7.51 5.89 5.40 6.16 -2002-2003 6.55 6.75 7.39 5.93 5.99 6.02 2003-2004 6.51 7.06 7.37 5.90 5.90 5.98 2004-2005 6.47 6.96 7.33 6.05 5.80 5.93 2005-2006 6.52 6.85 7.30 6.11 5.71 5.88 2006-2007 6.58 6.76 7.55 5.97 6.02 5.85 2007-2008 6.71 7.18 7.53 6.04 5.94 5.82 2008-2009 6.57 7.09 7.51 6.11 5.86 5.79 2009-2010 6.62 7.01 7.50 6.10 5.78 5.76 2010-2011 6.67 6.92 7.48 6.23 6.07 5.74 1/ Case I not interconnected, therefore combined system rate does not apply. * Interconnection Installed # Watana on-line + Devil Canyon on-line 85 Part VIII. INVESTMENT COSTS Construction costs for power producing facilities were prepared by the Corps of Engineers (Corps); those for the transmission facilites by Alaska Power Administration (APA). APA prepared estimates of interest during construction based on 7 1/2 percent. Corps estimates include alternative design concepts for Devil Canyon--thin-arch, as orgirially proposed by Bureau of Reclamation (USBR), and the concrete gravity design, which is more costly and conservative. Transmission estimates are based on same plan presented in 1976 report, with costs updated by indexing. Current costs for transmission facilities are based on indexing construction costs presented in the 1976 report (January 1975 prices) to current levels (October 1978 prices) by applying a factor of 1.38 to clearing and rights -of -way, 1.33 to all other transmission line components (access roads, structures, etc.), and 1.28 to substations and switchyards, resulting in an overall factor of about 1.32. The clearing and rights -of -way factor is based on experience of the Alaska Department of Transportation and on recent experience of the USBR and Bonneville Power Administration (BPA). The 1975 prices are based on component prices from BPA with an increase of 90 percent for labor and 10 percent for material transportation from the pacific Northwest to Alaska. Examination indicated that these factors are also valid for this analysis, but should be reevaluated if more detailed cost estimates are made in future years. Transmission system costs are summarized in table 25. Investment costs are calculated by adding interest during construction at the annual rate of 7 1/2 percent to construction costs presented previously. The project schedule includes (1) first -stage construction of Watana dam and powerplant and the total project transmission system, and (2) second -stage Devil Canyon dam and powerplant. The transmission system will be completed about three years before completion of Watana to develop interconnection benefits by deferring of required steamplant capacity (discussed in Part XIII, Load Resource Analysis), Table 26 summarizes the investment costs required. Table 25 CONSTRUCTION COST SUMMARY Upper Susitna Project Power Market Analysis Item Construction Cost ($1,000 - 10/78) System No. 5 Transmission Lines Clearing Right -of -Way Access Roads Line Structures Subtotal - T.L. Switchyards and Substations Fairbanks Substation Talkeetna Substation Anchorage Substation Healy Switchyard Watana Switchyard Devil Canyon Switchyard Subtotal - S.S. Total Rounded 87 $ 3,350 5,000 19,110 242,190 $269,650 $ 11,710 10,100 15,890 4,770 6,360 19,660 $ 68,490 $338,140 $338,000 APA 10/78 Stage Table 26 INVESTMENT COST SU41ARY ($/MILLION) Upper Susitna Project Power Market Analysis Devil Watana Canyon (lst) (2nd) Total Power Production Facilities Construction Interest during Construction Investment Power Transmission Facilities Construction Interest during Construction Investment Total Investment - Susitna 1,427.0 665.0 2,092.0 603.7 168.6 772.3 2,030.7 833.6 2,864.3 338.0 338.0 132.5 132.5 470.5 T77 2,501.2 833.6 3,334.8 APA 10/78 m PART IX. OPERATION, MAINTENANCE, AND REPLACEMENT PLAN AND COSTS Operation and Maintenance This updates information furnished in the 1976 report. Operation, maintenance, and replacement costs were indexed for this report. Plan Description This plan assumes Federal operation of the facilities. The plan assumes the headquarters and main operations center for the Susitna project will be near Talkeetna or at some other equally accessible point. Equipment at the center will remotely control the operation of the generation and transmission system and operation of Devil Canyon and Watana dams and reservoirs. Electrician/operators and mechanic/operators will be located at the powerplants to provide routine maintenance and manual operation when required. Specialized personnel, such as electronic technicians and meter and relay repairmen, will service both powerplants and the substations and switchyards from the project headquarters. Project administration, including supervision of power production, water scheduling, and transmission facilities, will also be from the project headquarters. Major turbine and generator inspection and maintenance will be done by electricians, mechanics, engineers, and other experienced personnel from AFA. Manufacturers' representatives and other specialized expertise will be consulted. Alaska Power Administration's (APA) headquarters office in Juneau will handle power marketing, accounting, personnel management, and general administrative services. Transmission line maintenance will be performed by two line crews, with assistance from the existing Eklutna Project line crew. Transmission line maintenance warehouses and parts storage yards will be at Devil Canyon or Watana, approximately mid -way between Devil Canyon and Fairbanks, and at the project headquarters. Line crew personnel will be stationed along the lines at designated maintenance stations and at the major substations to provide routine line patrol and maintenance tasks. Crews from throughout the project will be assembled for major work. Visitor facilities with provisions for self -guided powerplant tours will need assistance from operation personnel. Project -related recreation facilities will require cooperation between Federal, State, and local interests, and are assumed to be maintained by a State or local entity. :J Project operation, maintenance, and administration could be combined with the existing Eklutna Project. Eklutna could be supervisory controlled from the Susitna project operations center with electrician/operators and mechanic/operators stationed at Eklutna. It is estimated that approximately $100,000/year could be saved by joint operation. Marketing and Administration Marketing and administration include three main functions: 1. Administration Personnel management Property management Budgeting Marketing policy Rate and repayment studies _ 2. Accounting Customer billing Collecting Accounts payable Financial records Payroll 3. Marketing Rate schedules - Power sales contracts Operating agreements System reliability and coordination Part of this work would be carried out by the project, with overall administration and support services provided by the APA headquarters staff. , Annual Costs The estimated annual costs for operation, maintenance, marketing, and administration are based on itemized estimates of personnel, equipment, supplies, and services needed to do the work, with a provision for contingencies. The estimate assumes Federal classified personnel providing management and administrative functions and wage grade personnel performing technical operation and maintenance activities. Classified salaries are based on a mid -grade rate. gage grade rates are based on those in effect in the Anchorage area and include basic hourly rates, benefits, and overtime. 90 Costs of supplies, equipment, and .personnel requirements are based on Bureau of Reclamation (USBR) guidelines and the experience of the Eklutna and Snettisham Projects. The Eklutna Project is fully staffed, including a line crew, which has been in operation since 1955. The Snettisham Project is isolated; it is separated from the Juneau load center by 45 miles of rugged terrain and water. A maintenance crew resides and performs routine maintenance at the powerplant; project operations are remotely controlled from Juneau. The Susitna project would have some characteristics of both projects. Itemized costs for operation, maintenance, marketing, and administration are presented in table 27. Costs by major category and number of personnel are summarized in table 28. Replacements The annual replacement cost provision establishes a sinking fund to finance replacement of major items which have an expected service life of less than the 50-year project repayment period. The objective is to cover costs and ensure financing for a timely replacement of major cost items to keep the project operating efficiently throughout its life. The replacement cost is based on factors developed from USBR experience. The factors apply to the total powerplant, substation, switchyard, transmission tower, fixtures, and conductors. Replaceables include generator windings, communication equipment, a small .percent of the transmission towers, and items in the substation and switchyards. Items covered by routine annual maintenance costs include vehicles, small buildings, camp utilities, and materials and supplies. Major features, such as dams and powerplant structures, are considered to have service lives longer than the 50-year repayment period. Their costs are not covered by the replacement funds. Right-of-way and clearing costs are not included. The 72 percent interest rate used for project repayment was used to establish the replacement sinking fund. Table 29 presents calculations of the annual replacement fund. The following tabulation summarizes the operation, maintenance, and replacement costs: Annual Operation Annual Total and Maintenance Replacement OM&R $1,000 $1,000 $1,000 Watana $2,360 $260 $2,620 Devil Canyon 530 170 700 Total $2,890 $430 $3,320 Price base - October 1978. 91 Table 27 ANNUAL OPERATION & MAINTENANCE COST ESTIMATE Upper Susitna Project Power Market Analysis October 1978 Prices Dam and Powerplant, Total Transmission System Grade Personnel Number or Rate Supervisory & Classified Project Manager Assistant Project Manager Electrical Engineer Mechanical Engineer Supply & Property Clerk Administrative Assistant Clerk -Steno Subtotal Supervisory & Classified Wage Grade Electrician Mechanic Heavy Duty Equip. Operator Laborer Meter Relay Mechanic Electronic Technician Powerplant Operator Ass't. Powerplant Operator Subtotal Wage Grade Line Crew 1 1 1 1 1 1 1 II 2 2 1 2 1 1 6 4 19 GS-14 GS-13 GS-12 GS-12 GS-9 GS-7 GS -5 17.00/hr. 17.00/hr. 17.00/hr. 13.00/hr. 17.00/hr. 17.00/hr. 17.00/hr. 15.00/hr. Annual Cost $ 35,000 29,500 24,800 24,800 17,100 14,000 11,300 $. 156,500 $ 70,720 70,720 35,360 54,080 35,360 35,360 212,160 124,800 $ 638,560 Foreman 2 19.00/hr. $ 79,040 Lineman 4 17.00/hr. 141,440 Equipment Operator 2 17.00/hr. 70,720 Groundman 4 17.00/hr. 141,440 Subtotal Line Crew 12 $ 432,640 Allowances C.O.L.A.-Sup. & Class x 25% 39,130 Shift Differential 22,430 Sunday Pay 12,030 Overtime 32,000 Government Contributions 96,410 Longevity N. A. -- Subtotal-Allowances $ 202,000 TOTAL PERSONNEL COST 38 $1,429,700 92 Table 27 (cont.) ANNUAL OPERATION & MAINTENANCE COST ESTIMATE Annual Miscellaneous Cost Telephone $ 10,000 Official travel 19,000 Vacation travel 19,000 Supplies, Services & Maintenance--Powerplant 125,000 Supplies & Services --Vehicles & Equipment 50,000 Employee training 6,000 Line spray 25,000 Government camp maintenance 19,000 Subtotal - Miscellaneous $ 273,000 Equipment Operation, Maintenance, and Replacement Initial Service No. Cost Life Tractor with Dozer 1 $150,000 10 $ 15,000 Loader 1 75,000 10 7,500 Maintainer 1 75,000 10 7,500 Pickup 10 80,000 7 11,400 Sedan 1 5,000 7 700 Tractor & Lowboy 1 75,000 .10 7,500 Dumptruck 1 25,000 10 2,500 Flatbed 2 20,000 7 2,900 Firetruck 1 25,000 10 2,500 Sno trac 2 16,000 7 2,300 Backhoe 1 35,000 10 3,500 Crane, 50 ton 1 200,000 20 10,000 Hydraulic Crane, 20 ton- 1 100,000 20 5,000 Line truck 4 200;000 10 20,000 Subtotal - Equipment $ 98,300 APA Headquarters Marketing and Administration 165,000 Subtotal 1,966,000 Contingencies (20% +) 394,000 TOTAL WATANA & TRANSMISSION $2,360,000 93 Table 27 (cont.) ANNUAL OPERATION & MAINTENANCE COST ESTIMATE Devil Canyon Dam and Powerplant Personnel Watana and Devil Canyon, supervisory controlled from a remote operation -dispatch center. Increase base staff for Devil Canyon. Assistant operators 2@15.00/hr. $ 62,400 Electricians 2@17.00/hr. 70,720 Mechanics 1@17.00/hr. 70,720 Maintenance 1@15.00/hr. 31,200 Subtotal $ 235,040 Overtime 12,000 Government Contributions 21,160 Foreman Pay 6,500 Subtotal $ 39,660 Subtotal - Personnel $ 274,700 Miscellaneous Vacation travel $ 3,800 Employee training 1,200 Supplies, Services & Materials 112,500 Supplies and Services 13,400 Subtotal +- Miscellaneous $ 130,900 Equipment Initial Service/ Cost Life Pick up 2 @ 16,000 7 Snow tractor 1 @ 10,000 7 Subtotal - Equipment APA Headquarters Marketing and Administration Subtotal Devil Canyon Additions Contingencies (20% +) TOTAL DEVIL CANYON 0&M ADDITION TOTAL WATANA AND TRANSMISSION TOTAL SUSITNA PROJECT $ 2,300 1,100 $ 3,400 $ 35,000 444,000 86,000 $ 530,000 2,360,000 $2,890,000 94 O x � ro m E+ C; O S4 U ro T4 U N z a; co d 3 N z O w a a) E-+ ri z +3 c�U 6 N E+ n O A �4 ¢� A4 ro o 4-) H m O A+ i4 O (1) a. 0 ro m O U7 'n O ro m *-+ U O e-i �7 O^ -4 �4 q •,-I H a) cZ) yr A ro 74 ri O a) cc ro ,m 4-J 4-J S r` co O ro =3 cn H 3 z o cA O �4 r` C ro O N ca Q yr U H N A O z M .-4 O O O 1 O O O O r+ CD C)� �7 .-a N -zr It 00 N IN <n <lt O o 0 0 00 O O O O O Cr M O. o M 00 M M �t tt1 O O o O O O o O O O o O o 0 O o 0 0 rn M C�, Sri .o o G (2) ro W —f N r1 C)1 M M H >, O ra —4 N rn- O � Cl) cif •,-I a) r I d (7) O o4 , a M PLOcu �-,4 a u +I a r+ p •rl co ro o con con ; ro a E � v 6 � aa� HH ro m .. cU •O cC O U v� O a) a) O c�C v" r I m -H ro a) �71 U U b U •r•i w ro > ro C a) ro r; ;-4 m *- A �4 ro ro -r� x ro as ro cn a) a) a) Q o ++ +j O r+ ro as o cn M c a) <C o * ro* co v a) O x P4 N cn U 3 O H O �4 6 H e) c ro O o A, w rn U H 95 O O v� cd E G 0 ON U a-+ N a) z N E 3 w° 4J u N O a i ai O O co co 4J 1 C14 a. rz O CO' V O a) O O E d O O O .,I +j O u M O N }J cn CO w 0 '-t O U M O tr} U i O r-I a1 �D O 0 O 4J O r a) to O co04 U r-I •rl C O aJ •r1 O A +r u o a +J %�o N CO as +W O cn U o O CV 0 r-1 0 1 .H u o m ra u r� M •rl rl G U3o 1-I a1 E 4-J CD Cd O O O Cd +-J O u O co O n cd +J O 3 cn O � U C71 0 r-t U � i O O O O 1t N M V) N O M N O O O O n if1 N o O O —4 r, O 00 rn O tf} +h O C O 0 r-1 O O O O O O M O O IO CO O cn u1 110 N N {A- i/)- O O 0 O O O ri u +1 �4 O Iq Cl) cd cd O 0 •- 4 O M pR. u o 0 0 � u � x rX4 o 0 0 .. 0 m +J � U N O O C b +J O q u cd O 0 a W 14 G N 0 p O ctl Cl) U) rl Cd 4-1 u r-+ a) O O co rZ 3 cd k ,n •ra +J � a w E+ + H cn cn a G a) N u cz r-� a. (3) p 0 O 4-1 +� u cc 4) Fa •n 41 � w N • �a O 4-J r I co QI 4-J 4a U .0 }4 41 N a. w 0 N G 0 r-I •rl +J n H 0 O 41 b 1 cc ,n 0 � b la � co M Cd M a p 0 d-J u O cd u 4-+ C O a) a-J E~ U a1 � ca +J a, G R U m PART X. FINANCIAL ANALYSIS This part estimates the market for project power and evaluates power rates needed to repay the investment in power facilities. Power market size is in more detail in this study than in the 1976 report. Likewise, costs are slightly more detailed. The Upper Susitna Project is primarily for hydroelectric power generation and transmission.. Minor portions of project costs (less than 1 percent) would be allocated to other purposes, such as recreation and flood control. Project financial viability is the essential element in demonstrating feasibility of the power development. The repayment rate is influenced principally by size of the market, amount of investment, and applicable interest rates. Operation, maintenance, and replacement costs are a minor part of total annual costs; they influence these rates insignificantly. If rates needed to repay the hydro project are attractive in comparison to other available alternatives, the project is economically justifiable. The 1976 report compared the costs of five dam and reservoir plans for developing the Susitna River hydroelectric potential and found all costs were within a 15 percent range. Therefore, the scoping analysis was not repeated for this study. In addition to analyzing the basic Susitna project plan,'variations were also analyzed for sensitivity. These included interconnection with additional service areas, different timing for interconnection between Anchorage and Fairbanks, use of the more expensive Devil Canyon gravity dam instead of the arch dam, low load growth, and the effect of inflation. In addition, the load/resource and system cost analyses examine impact of the Susitna Project on overall system costs. Market for Project Power Upper Susitna will operate as part of a hydro/thermal power system. The 1976 report assumed the market for Susitna firm energy as 75 percent of the mid —range utility requirements. Average rates for firm energy were estimated on that basis. For this analysis, the market for firm energy was assumed to be approximated by load growth after Susitna power becomes available, plus market made available through retirement of older plants. The balance of the Susitna energy is assumed marketable as secondary energy for fuel replacement, as long as all energy fits under the load curve. A value is assigned for marketable secondary energy based on estimated future coal costs. The actual value is probably significantly higher. 97 The value of fuel replacement energy is the same as that used in the load resource analysis, which is $1.00 to $1.50/million Btu by 1985. This is based on the concept that large, efficient coal mines will be developed in the Beluga area by then. The price is escalated at 2 percent per year above the zero inflation rate from 1985 to 1994, resulting in a cost of $1.20 and $1.80/million Btu';. Table 30 summarizes the estimated market for Susitna energy using these criteria. Cost of Project Table 31 summarizes the construction cost, interest during construction, operation, maintenance, and replacement costs -for Devil Canyon and Watana phases. Construction costs were furnished by the Corps for an October 1978 price level. Interest during construction was calculated from Corps construction cash flow estimates with interest accumulated until the project becomes operational. OM&R costs were updated from APA earlier estimates. Costs have increased from the 1976 report for several reasons. Table 32 presents a summary comparison of the cost factors. Interest rates have increased from 6 5/8 to 7 1/2 percent. Design and cost changes were made by the Corps as a result of foundation drilling. Costs were updated for the Devil Canyon dam and the transmission line by indexing procedures. The major change in operation, maintenance, and replacement costs was due to inflation in personnel wages and provisions for con— tingencies such as unlisted items and state of the art. Watana's construction period was extended from 6 years to 10 years, increasing its construction period from 10 years to 14 years. The revised project investment cost is 89 percent higher than in the 1976 report. W. TABLE 30 MARKET FOR UPPER SUSITNA POWER ANCHORAGE AND FAIRBANKS AREAS Upper Susitna River Project Power Market Analysis MEDIUM ESTIMATE Firm Energy Fuel Replacement Year Sales G`WH Sales GWH 1994 633 2,401 1995 1,385 2,043 1996 2,231 1,197 1997 2,873 555 1998 3,531 2,872 1999 4,244 2,543 2000 4,686 2,101 2001 5,055 1,732 2002 5,630 1,115 2003 5,983 804 2004 6,352 235 2005 6,767 20 2006 6,787 0 COMPARISON WITH TOTAL AREA POWER -REQUIREMENTS Estimated Anchorage Estimated Market for and Fairbanks Energy New Hydroelectric Power Annual Energy Annual Energy Year Million KWH Million KWH 1995 10,323 1,385 (13)1/ 2000 13,288 4,686 — (35)1/ 2005 15,083 6,767 (45)1/ 1/ Percent of total area requirements Data Source: APA Load/Resources Analysis Medium Load Growth Estimates, Energy Losses are included. Unit Completion Date Table 31 INVESTMENT AND OM&R COST SUMMARY Upper Susitna Project Power Market Analysis Watana 1994 Costs - $1,000 Power Production Facilities Devil Canyon Total System 1998 Construction Costs 1,427,000 665,000 1/ Interest During Construction 603,700 168,600 Investment Cost 2,030,700 8339600 2,864,300 Transmission Facilities �/ Construction Costs 338,000 Interest During Construction 132,500 470,500 Investment Cost 470,500 3,334,800 Total System Investment Cost Annual Operation and Maintenance 2,890 Annual Replacement 430 Annual OM&R 3,320 Price level is October 1978. Interest rate for repayment purposes in FY 1979 is 7-1/2%. 1/ Costs are for arch dam plan at Devil Canyon. 2/ Transmission system assumed online in 1991. 100 Average Rate Determination Table 33 summarizes the estimated average firm energy rate for f_rm energy needed to repay project facilities investment for mid -range load growth conditions. The method used is similar to that used in the 1976 report. Present Federal criteria for power producing facilities require repayment -of project costs, with interest, within 50 years after the unit becomes revenue producing. The applicable interest rate for Fiscal Year 1979 is 7 1/2 percent.' Revenues were credited to the project from sale of secondary energy at a fuel replacement rate of 1.2(,I/kwh during early years of project operation. The average required rate for repayment over 50 years after the last unit is installed is 4.7,,,/kwh. Total repayment period will be 54 years with Devil Canyon coming on-line four years after Watana. Alternatives to the basic project plan were analyzed to determine effects on average power rates: 1. Devil Canyon gravity dam in lieu of the thin -arch dam: Investment cost increased $204.9 million. Average rate for firm energy increased to a total of 4.9',I/kwh. 2. Transmission investment deferred until Watana phase comes on-line (1994): Watana phase investment reduced $76 million. Average rate reduced 0.1�/kwh to a total of 4.6r,,/kwh. 3. Mid load..growth case, 5 percent inflation: Investment cost increased $3.598 billion. Revenue needs increased $243 million annually. Firm energy is the same for all mid growth cases. Average rate for firm energy increased 4.7r,�/kwh to 9.7r,,/kwh. 4. Low load growth case: Revenue needs same as for mid range growth case. Firm energy sales decreased; fuel replacement sales increased. Average firm energy rate increased 1.7c./kwh. All Corps plans are based on completing Watana first, followed by Devil Canyon four years later. This is appropriate for mid range and high range growth conditions, but if low range conditions remain, it may mean the Devil Canyon unit could be deferred a few years. 101 Power Marketing Considerations The average rate is useful for comparing the proposal with the alternatives. Actual marketing contracts will likely include separate provisions for demand and energy charges, wheeling charges, reserve agreements, and other factors. There are some built-in inequities for any method of pricing. What amounts to a postage stamp rate is used by most utilities and large Federal systems. That is, power rates are the same for all delivery points on the system. Actual costs vary with the distance, size, and characteristics of load --it is more.costly to serve a small load several miles from the power source than to serve a large load nearby. Policies vary from system to system as to "hookup" costs born by the customers. 102 Table 32 COST SUMMARY COMPARISON WITH 1976 Upper Susitna INTERIM FEASIBILITY REPORT Project Power Market Analysis 1976 1978 Difference Item Interim Marketability (Costs $ Million) Feasibility Analysis Amount Percent Report Update Interest Rate for Repayment 6-5/8% 7-1/2% + 7/8% + 13 Construction 13eriod Watana 6 yrs. 10 yrs. + 4 yrs. + 67 Devil Canyon 5 8 + 3 + 60 Transmission System 3 3 0 0 Total 10 yrs. 14 yrs. + 4 yrs + 40 Construction Cost Watana 832.0 1,427.0 + 595.0 + 72 Devil Canyon 432.0 665.0 + 233.0 + 54 Transmission System 256.0 338.0 + 82.0 + 32 Total 1,520.0 2,430.0 + 910.0 + 60 Interest During Construction Watana 165.4 603.7 +438.3 +265 Devil Canyon. 57.2 168.6 +111.4 +195 Transmission System 25.4 132.5 +107.1 +422 Total 248.0 904.8 656.8 +265 Investment Cost Watana 997.4 2,030.7 +1,033.3 +104 Devil Canyon 489.2 833.6 + .344.4 + 70 Transmission System 281.4 470.5 + 189.1 + 67 Total 1,768.0 3,334.8 +1,566.8 + 89 Annual Cost for Repayment of Investment 113.34 239.20 +125.86 +111 Annual Equivalent OM&R 2.27 3.14 + 0.87 + 38 Total Annual Equiv. Cost 115.61 2.42.34 +126.73 +110 (Less Secondary Energy Sales 1/ - (Fuel Replacement Sales)- 5.77 11.34 + 5.57 + 97 Total Net Annual Equiv. Cost 109.84 231.00 121.16 +110 Annual Equiv. Energy GWRV 5,218 4,923 -295 -6 Total Annual Equiv. Energy Cost - �/KWH 2.11 4.69 2.58 +123 1/ Median load growth Note: Total energy during period of analysis is the same in both reports. Difference is due to variation in load build-up. 103 O N T cd Hox H �4 H U � w a Q) M W H 3 `'wwa° a1AA H A u H 0 caa v H O a a A O rl to 04 x d) W G O 4J •ri u r-I O ;4 a 1 a� U cA cd N r-1 r-1 Pa ccl m 00 O 00 \-O .-4 N O l0 00 N V1 ` N CA M I'0 \.O -4 O -'P �10 1- 00 m O LI) .t Pa N r� m It O \.O N M LP) CO 'A M 00 1J ^ tc 3 �4 Lf-) Pi 0 O m 00 �.O . 4 Q> O -'r -,T I, C�) i� _4 0000ON01Lr) Ln LnN m mO\O't INN N -t W N Lr) ^ ^ ^ -.T 1- 00 00 m m 00 co M m a% 1 ^ -Zt .—c r-c N N N N N N N N N \.0 d• d •ri O� 01 M �O a..l Fes' N � O N d) U ri cd cd u> N M .--1 N crl -t Ul O O t0+ O? Ol� u 1 I- -,t O M -+ O M N O d• O ^ tr) 00 u•1 -i -1 00 N O ^ N N � W F� E 1 u •ri O O O O O O rn O O O O O O O O O 0 0 0 O O O O O O O O -t It O O "i C c'MOO a% m N .-i M M -It r-4 CM N N N 1 N (DIN V} -co- <J) M u1 ,--c M r-I -t 1�0 Ln O M cV t" n E M 00 M I, m -T 00 Ln M M Ln 1�0 w 7ri MN00 LnN1,00�Oo�Mnr, W �", +--1 N N w ?- n O1 N �t �.0 , f ,4 PaI M �O O \�O O cr) M �t N ^ Ol N N O ^ O N O N N N + 010 N cry O M a o � oO O o vo in O o -Wr!r = N N N cA ON m .—� �' �1 rn U 01 O C4N M r-c > cry -t N r I H N ^ co M ;j O O O O O O O O O O O O Pa) N N N N N N cN N N N N N 231 �-o 14 MrMMMMMMcn cA 4-1 O N N N N M M M M M M cM M O O OC) O cad Pa N d to O M co O 4-1 a 0 G n 00` P4 Pa H N co' ro M > d) •ri .IJ cd O O N U) r•? bD H t U1 \,0 I� CO a1 O r-1 N M �t cf'1 ,0 cd }a cd O1mmm m0\0000000 " G N N mONol\-m 0000000 O > >4 1-1 r+ '-1 -4 '-I .--I N N N N N N N E-H G; C, -- II O O O >1 o rN O W U] M N N v W +J U +) W N cd cd a o 0 N ::j O w Pa 0 o 0 I-q o Fit "I S:"+ P=i O Fi CD a) -4-I W > + *-+ p cd N G1 •rl 4 a\ i 43 R4 O W N M �t � vv I n i Actual rates for the Susitna system could reflect several items of costs and revenues not identified in the project studies. For example, during its life, project facilities would likely be used to wheel power rom other sources. Wheeling revenues will lower overall project power rates somewhat. Conversely, wheeling costs for project power delivered over non -Federal transmission lines will be added to project rate schedules. This is now done under APA marketing contracts for the Snettisham Project; there are similar situations in other Federal power systems. Market Aspects of Other Transmission Alternatives It is reasonable to expect modifications of the project transmission_ system as requirements (or needs) change. The main 345-kv and 230-kv lines could be upgraded substantially by adding compensation and transformer capacity. Substations could be added as future loads increase to a case -by -case determination of economics. Similarly, extensions of the project transmission lines to serve other areas would be considered on the basis of needs, economics, and available alternatives. Anchorage -Cook Inlet Area The costs in the proposed plan are premised on delivery points to substations near Talkeetna and Anchorage. Rough estimates indicate similar costs for a plan with delivery points at Talkeetna, Anchorage, and the existing APA Palmer substation. Basically the proposed plan includes costs to provide for delivery points on the existing CEA and APA systems north of Knik Arm, but does not include costs of delivering power across or around the Arm. With or without the Susitna project, additional transmission capability is needed on the approaches to Anchorage. CEA plans for a Knik Arm system considers 230-kv transmission an important step in developing this capability, but more capacity will be needed by the mid-1980's. Essentially the same problems will exist with alternative' power sources, such as the Beluga coals. Following project authorization, detailed studies will be needed to consider alternatives for providing power across Knik Arm. Costs would be worked into rate structures through wheeling charges on non -Federal lines or annual costs on project lines, if needed. The transmission plan to deliver project power in Anchorage will need to be worked out in the detailed post authorization studies. It will involve added costs, either wheeling charges for project power over non -Federal lines, or constructing project transmission lines around or under Knik Arm. These costs could be about the same for alternative power sources such as the Beluga coals. It is essential that scheduling of project facilities be closely tied to the marketing function. 105 Comparison of Susitna to Steamplants With and Without Inflation Without inflation, the 4.7�./kwh rate for the Susitna project is significantly lower than the estimated cost of power from coal-fired steamplants at 5.2 to 6.4c/kwh at October 1978 costs. donsidering inflation, the capital costs of both the steamplant and hydro powerplant increase until construction is complete. For the completed projects, inflation affects only the hydro project operation and maintenance cost, a small part of the energy cost: For the steamplant, inflation continues to increase the fuel cost as well as the much larger operation and maintenance cost. The difference of the effect of inflation is shown on figure 19. Capital and 0&M costs are assumed to inflate at 5 percent per year for both. Fuel costs are assumed to inflate 2 percent per year higher than a base price of $1.00 or $1.50 per million Btu in 1985. The conclusions are that Susitna is considerably less susceptible to inflation than steamplants. 0 106 COMPARISON OF SUSITNA Figure 19 AND ALTERNATIVE COAL-FIRED STEAMPLANT RATES CONSIDERING 5% ANNUAL INFLATION 17 Upper Susitna Pro ect Power M rket Anal s s 16 15 14 13 12 11. S �e-10 Z g W U . STEAMPLANT AL ERNATIVE w g a 7 6 5 SUSITNA 4 3 2 0 1978 1980 1985 1990 19941995 2000 YEAR OF PRICE BASE (Fue I cost inflated 2% higher) 107 APA 1/79 PART XI. GLENNALLEN AND VALDEZ Introduction The primary justification for the Upper Susitna project is to supply power and energy to the State's two largest power market areas, Anchorage -Cook Inlet and Fairbanks -Tanana Valley. The Glennallen-Valdez area is recognized as a possible additional market area. The two communities are the principal load centers for the Copper Valley Electric Association (CVEA). At present, both are supplied from oil -fired generators. CVEA is now moving into initial construction phases of its Solomon Gulch hydroelectric plant near Valdez, and is in final design stages for a 138=kv transmission line extending 104 miles to interconnect Valdez and Glennallen. CVEA could be interconnected with the major uitlities in the Anchorage -Cook Inlet area by adding a transmission line between Palmer and Glennallen. The transmission distance is 136 miles; minimum transmission voltage would likely be 139 kv. Depending on future demand, a higher voltage such as 230 kv may be justified. Very preliminary studies summarized in the following section indicate a good chance that the Palmer-Glennallen intertie is feasible. Power Market Area Introduction Similar to Fairbanks, both Glennallen and Valdez have been heavily impacted by trans -Alaska oil pipeline construction and operation. The pipeline terminus storage and shipping facilities are at Valdez. The pipeline was completed and went into operation in 1977. The Glennallen-Valdez area 1977 population was approximately 9,905, 39 percent higher than in 1974. However, the 1976 population (13,000) decreased 31 percent in 1977. Valdez is the proposed site of a major refinery and petrochemical complex to process the State's royalty share of Prudhoe Bay oil. Plans are not yet finalized, but construction could begin as early as 1980. This would have major impacts in terms of both construction employment and a long term increase in employment and population for Valdez. The operations phase of the refinery involves 1,000 new jobs according to recent reports. Glennallen's population and economy are expected to continue to grow. Existing Power System The Copper Valley Electric Association (CVEA) serves both Glennallen and Valdez. CVEA's radial distribution lines extend from Glennallen, 30 miles north on the Copper River, 55 miles south on the Copper River to Lower Tonsina, and 70 miles west on the Glenn Highway. Figure 2 outlines the area. 108 CVEA plans to construct 104 miles of 138-kv long transmission line between Valdez and Glennallen. This is related to the Solomon Gulch 12-MW hydro development now beginning construction. At present, the utility loads are served totally by diesel generation of 17.7 MW: 10.1 MW at Valdez and 7.6 MW at Glennallen. Two small utilities serving limited areas on the highways north of Glennallen are included in historical data. Their installed diesel capacity totals 1/3 MW. The Alyeska oil terminal facility at Valdez has 37.5 MW in oil -fired steam -turbine capacity. This is a total energy facility that satisfies the terminal's electrical and steam requirements. Power Requirements This section summarizes historic energy use and related data, information from a 1976 load forecast prepared for CVEA, and some general observations on likely magnitude of future power requirements. Historic Data Energy use and peak demand data were obtained from three power generating sources in the Valdez-Glennallen area: CVEA, the utility serving over 95 percent of the area; Chistochina Trading Post; and Paxson Lodge, Incorporated. The utility data yielded information on energy use, peak demand, and customer sector breakdowns. Population and employment data were derived from statistics provided by the State of Alaska Department of Labor. This information illustrates demographic characteristics of the study area. The 1970-77 Valdez-Glennallen area is summarized on table 34. Net generation by_utility from 1960-77 is on table 35. Analysis The energy use, population, and employment data reflect events tied to construction and operation of the Alyeska oil pipeline. The large jumps in population and employment during the construction years cannot be directly tied to utility power requirements since most of the workers were housed in construction camps that supplied their own power. The 1977 use data show total utility requirements at more than four times the 1970 level. Total number of customers tripled during the period. Per customer residential use increased from 3,846 to 6,423 kwh per year over the 7-year period. This historic data provides no clear insight to probable future levels of power use --any trends that would be useful in forecasting are hidden by the construction impacts. MW Forecast Table 36 summarizes future power demand estimates from CVEA's 1976 power requirements study. The study included estimates of demands through 1991; APA made a rough extension to the year 2000, assuming a 6 percent rate of increase. The average energy capability of the Solomon Gulch project is estimated at 55 million kwh/year. The forecasts indicate that the Solomon Gulch power would be fully utilized as soon as it comes on-line. By the time Upper Susitna power would be available, CVEA total demands would exceed Solomon Gulch capability by around 100 million kwh/year. The CVEA study predated the plans for the oil refinery at Valdez, hence there is substantial likelihood that the actual requirements will exceed the'forecast amounts. Transmission Plan And Cost Incremental service to the Glennallen-Valdez market areas would require constructing transmission facilities from Palmer to Glennallen to connect to the CVEA system serving the market area. Susitna project generation and transmission to the Anchorage -Cook Inlet area would be sufficient to accomodate the incremental service. The Palmer-Glennallen transmission system would have 136 miles of single circuit 138-kv line,• with a substation at Palmer, and a switchyard at Glennallen. The Palmer substation would have a 230/138-kv transformer, a 230-kv breaker, and a 138-kv circuit breaker. The Glennallen switch- yard would include two 138-kv circuit breakers, and would connect with the planned CVEA 138-kv line extending to Valdez. Peak capacity of the 138-kv Palmer-Glennallen line would likely be from 50 to 80 MW. This is an assumption for study purposes (stability, sizing, and power flow studies were not made). System costs are based on comparable elements of other project transmission systems, indexed from the 1976 report (January 1975 prices) to October 1978 prices (about 32 percent increase). The basic prices are based on Bureau of Reclamation (USBR) and Bonneville Power Administration (BPA) with adjustments for Alaska conditions (refer to Part VIII). Advance planning would analyze evaluations of structural, operation control, environment, and other elements affecting route location, design, and operation of the system serving this area. Investment costs are calculated by adding 711 percent interest annually during construction. The Palmer-Glennallen line would be constructed during the same period as other facilities, and would be ready for service when project power is available in 1994. Table 37 summarizes construction and investment costs. 110 Table 34 HISTORIC DATA GLENNALLEN-VALDEZ AREA Upper Susit-na Project Power Market Analysis Utility Energy Sales (GISH) Net Generation Res CI Total Utility Industry 1970 2.1 7.4 9.9 11.9 1971 2.6 7.8 10.8 12.8 1972 2_8 7.6 10.8 13.0 1973 2.9 8.3 11.6 13.8 .1974 3.7 10.4' 14.5 16.8 1975 7.7 16.0 24.4 28.2 1976 10.3 22.4 33..5 40.7 1977 10.9 31.0 42.9 48.7 39.4 Utility Custorers Peak Load (MW) Res CI Total Utility Industry 1970 546 221 793 2.4 1971 681 226 939 2.5 1972 655 237 926 2.6 1973 684 247 965 2.7 1974 911 317 1,268 4.0 1975 1,172 361 1,576 7.3 1976 1,677 404 2,128 8.6 1977 1,697 427 2,183 9.3 37 (38.6 installed capacity) Population (Total) Employment (Avg. Annual) 1970 3,098 831 1971 2,932 1,085 1972 3,464 904 1973 3,568 985 1974 3,633 1,526 1975 9,639 4,626 1976 13,000. 7,818 1977 9,905 3,918 Res = residential CI = Commercial -industrial APA 12/78 111 Table 35 UTILITY NET GENERATION (GWH) GLENNALLEN-VALDEZ AREA Upper Susitna Project Power Market Analysis Year CVEA CTP PLI Total Growth % 1960 3.2 0.1 3.3 1961 3.4 0.1 3.5 6.1 1962 4.0 0.1 4.1 17.1 1963 4.5 0.1 4.6 12.2 1964 4.2 0.1 4.3 -6.5 1965 6.5 0.2- 6.7 55.8 1966 8.0 0.2 8.2 22.4 1967 8.2 0.3 8.5 3.7 1968 8.6 0.4 9.0 5.9 1969 9.7 0.4 0.5 10.6 17.8 1970 10.7 0.4 0.7 11.8 11.3 1971 11.7 0.4 0.7 12.8 8.5 1972 11.8 0.4 0.7 12.9 0.8 1973 12.6 0.4 0.7 13.7 6.2 1974 16.6 0.4 0.7 17.7 29.2 1975 26.9 0.4 0.7 28.0 58.2 1976 39.3 0.4 0.7 40.4 44.3 1977 47.4 0.4 0.7 48.5 20.1 CVEA - Copper Valley Electric Association CTP - Chistochina Trading Post PLI - Paxson Lodge, Inc. APA 12/78 112 Table 36 VALDEZ-GLENNALLEN AREA UTILITY FORECASTS Upper Susitna Project Power Market Analysis _ Energy (gwh) CVEA 1/ Peak Demand (NII) CVEA 1/ Year Glennallen Valdez Total Glennallen 1976 12.5 24.5 37.0 40.7 2� 3.1 1977 21.0 27.0 - 48.0 48.7 - 4.2 1978 22.1 27.2 49.3 4.4 1979 24.0 27.6 51.6 4.6 1980 45.9 27.9 73.8 7.3 1981 48.5 30.5 79.0 7.7 1982 50.0 33.0 83.0 8.1 1983 52.2 35.5 87.7 8.5 1984 55.0 38.2 93.2 9.0 1985 57.6 41.4 99.0 9.5 1986 60.0 45.0 105.0 10.1 1987 63.1 48.5 111.6 10.6 1988 66.0 52.5 118.5 11.1 1989 69.1 56.8 125.9 11.7 1990 72.3 61.4 133.7 12.4 1991 75.0 66.4 141.4 13.0 1995 180 2000 240 2025 1,025 l/ Copper Valley Electric Association Forecast from 1976 REA Power Requirements Study. 2/ Historical values 113 Valdez 6.0 5.9 5.8 5.8 5.8 6.3 6.8 7.4 8.0 8.6 9.3 10.1 10.9 11.8 12.8 13.8 m Table 37 INVESTMENT COST SUMMARY GLENNALLEN-VALDEZ AREA TRANSMISSION SYSTEM Upper Susitna Project Power Market Analysis (Costs-$1,000 10/78) Construction Interest Investment During Construction Transmission Line (Palmer-Glennallen) Clearing $ 1,540 Right -of -Way 310 Access Roads 5,490 Line Structures 25,760 Subtotal $33,100 Switchyards & Substations Palmer Substation $ 3,880 Glennallen Switchyard 920 Subtotal $ 4,8.00 Total $37,900 Operation and Maintenance Costs $2,900 Addition of the 136-mile Palmer-Glennallen transmission line would involve comparatively minor increases in overall system operation, maintenance, and replacement costs. $40,800 For purpose of this analysis we are assuming the incremental O&M costs would be roughly equivalent to 1/3 of the annual cost of one transmission line maintenance crew. Adding an allowance for replacements, the annual OM&R cost is estimated at $131,000 per year. This is indicated on Table 38. 114 Table 38 OPERATION, MAINTENANCE, AND REPLACEMENT COST SUMMARY GLENNALLEN-VALDEZ.AREA TRANSMISSION SYSTEM Upper Susitna Project Power Market Analysis. Operation and Maintenance Personnel Salary & allowances for 6 Wage Grades Miscellaneout Telephone, travel, supplies, services training, line spray, camp maintenance Equipment (Replacement) Marketing and Administration Subtotal Contingencies 20% + Subtotal - O&M Rounded Replacement Transmission towers, fixtures, conductors 0.0001 x $25,766,000 Substations & Switchyards 0.0033 x $4,800,000 Subtotal - Replacement Rounded Total OM&R 115 Annual Cost - $1,000 Full Crew 1/3 Crew 240 80 10 3.3 8 2.7 22 7.3 280 93.3 60 20 340 113.3 113 PSG 15.8 18.4 18 131 Assessment of Feasibility A minimum intertie between Palmer and Glennallen would involve incremental investment costs on the order of $40.8 million. Incremental annual costs are estimated as: Amortization $3,140,000 OM&R 131,000 Total Annual Cost $3,271,000 Based on the utility forecast for CVEA, it is possible that a market in excess of 100 million kwh/year could be supplied over the Palmer-Glennallen line. This would equate to transmission costs of 3.3(,%/kwh. The'100 million kwh/year would be equivalent to 22.8 MW at 50 percent annual load factor. This is substantially less than half the estimated capacity for a 138-kv Palmer-Glennallen line. Full utilization of the intertie could involve transmission of 200 to 300•million kwh/year, in which case, average transmission cost would drop from one-half to one-third the cost indicated above. Regardless of the source of power --coal, oil, hydro --generation costs for CVEA will likely be higher than for the larger utility systems serving the Anchorage -Cook Inlet area. In this context, transmission costs on the order of 1.1 to 3.3(,%/kwh between Palmer and Glennallen may be justifiable. APA concludes that the Palmer-Glennallen intertie has a good chance for feasibility, and that a more detailed examination is warranted. 116 APPENDIX 1. Letter dated January 3, 1979 to Col. G. R. Robertson, Alaska District Corps of Engineers, -transmitting responses to OMB questions falling in APA's area of responsibility. 2. Previous Studies and Bibliography. 3. LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION OF ALASKA: 1978-2010 -- Informal Report - by Battelle Pacific Northwest Laboratories, Richland, Washington - January, 1979. 4. Comments. a. Federal Energy Regulatory Commission, San Francisco, California, March 6, 1979. b. Battelle Pacific Northwest Laboratories, Richland, Washington, February 27, 1979. C. Corps of Engineers, Anchorage, Alaska, March 19, 1979. d. The Alaska State Clearinghouse, Juneau, Alaska, March 23, 1979. e. Municipal Light and Power Company, Anchorage, Alaska, March 1, 1979. 117 DPI , im2i1 L Of - Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 January 3, 1979 Colonel George R. Robertson Alaska District Engineer Corps of Engineers P.O_ Box 7002 Anchorage, AK 99510 Dear -Colonel Robertson: Attached are our responses to the Susitna Project OMB questions we agreed to provide {re: our letters dated January 20, 24, 1978}_ Copies of these responses were sent via Goldstreak direct to Captain Mohn December 28, 1978_ Sincerely, Donald L. Shira Chief, Planning Division ME asked that the analysis of the "without" project condition be expanded to clearly analyze: 1. why, with natural gas projected to be in such short supply, the Anchorage utilities have only contracted for 55 percent of proved reserves or 25 percent of estimated ultimate reserves, and, 2.. The sensitivity of the analysis to the collapse of OPEC and the cost of shipping oil to the East Coast_ Both questions must be considered in terms of national energy policy_ The Nation needs to reduce dependency on oil imports on both a short- term and a long-term basis, and to accomplish a major shift away from oil and r_atural gas to alternative energy sources. The reasons for this include national economic considerationsx as well as very real limits on national and world supplies of oil and natural gas. In terms of national energy policy, oil and natural gas are not available alternatives for long-term production of electric power. There are remaining questions as to how quickly existing uses will be phased out and on how complete the prohibitions will be on new oil. and natural gas - fired powerplants. There is general agreement that implementation of national policy must. include strong efforts in conservation, substantial increase in use of coal, and major efforts to develop renewable energy sources_ Each of these components is sensitive to energy price and supply variables. A reduction in world oil prices or'a period of oversupply serves as a marketplace disincentive for conservation efforts and work on alterna- tive energy sources. The lowest cost alternatives and those with fully proven technology are the least sensitive; those that depend on further R&D are most easily sidetracked_ The Susitna Project involves large blocks of power and new energy from a renewable source, fully proven technology, long revenue -producing period (in excess of 100 years), and essential freedom from long-term price increases. Its unit costs appear attractive in comparison to coal-fired powerplants. it is a two -stage project with opportunity to defer the second stage if demands are lower than present estimates or if price relationships change. The above factors suggest that the Upper Susitna Project is much less sensitive to short-term oil price and supply variations than most other_ U-S. energy options. 0a If it is assumed that Alaskan o.i.l and nat:tual. gas will be isolated from U.S. an,-] world demand and pri.ca.ng, Alaska would probably continue to use its oil and gas for most of its power. This assumption did, in fact„ prevail betuee:n the initial oil. and gas discoveries in the Cook Inlet area and the 1973 oil. embargo. In 3.960, the Anchorage -Cool; Inlet area power supplies came almost entirely from coal and hydro. The low cost, abundant gas brought a halt to hydro development and destroyed the area's coal industry. 'The one remaining Alaskan coal mine barely made it through the 1960's because of competition from relatively cheap. oil. The Cool; Inlet gas has been subjected to increasing competition in -the last few years, including proposals for LNG facilities, additional petrochemical plants, and consideration of pipeline alternatives to tie in with the Alcan pipeline project_ The competition resulted in increas- ing prices and increasing difficulty in bbtaini.ng long-term commitments of gas for power. The competitions and the price increases are expectei to continue. `rhe real question on gas availability as it pertains to Upper Susitna- is: «hat is the outlook for long-term gas supplies for power after 1990? That outlook is not good in terms of competing uses and national policy. 3 Response to OMB question 5.3. "The Necessity for an Anchorage -Fairbanks intertie at a cost of $200-300 million" The estimated construction cost (1978 dollars) for the transmission lines from the Susitna Project to the Fairbanks area is $152 million, and $186 million for the lines from the project to the Anchorage area (total $338 million). There are several previous studies'/ that demonstrate inherent feasibility of an Anchorage Fairbanks intertie with or without construction of the Upper Susitna Project_ The main reason that the intertie is not now in place is that short term benefits to the Anchorage area are quite small, i.e., most of the short term benefits for the intertie would occur through reduced energy and power costs in the Fairbanks area. APA studies in the 1975 feasibility report evaluated Susitna Project power to Fairbanks on a cost -of -service basis (see Appendix I, p. 6-89). This was a specific demonstration of feasibility of including Fairbanks as part of the Upper Susitna Power Market area. 1/ Among the previous studies are: s Alaska Power Survey, Federal Power Commission, 1969. Central .Alaska Power Pool, working paper, Alaska Power Administration, October 1969. Alaska Railbelt Transmission System, working paper, Alaska Power Admin- istration, December 1967. Electric Generation and Transmission Intertie System for Interior and Southcentral Alaska, CH2M Hill, 1972. Central Alaska Power Study, The Ralph M. Parsons Company, undated. Alaska Power Feasibility -Study, The Ralph M. Parsons Company, 1962. 4 Further verification of feasibility of the intertie is provided in the new load -resource analyses and system cost analyses prepared for the current studies. These general cases were analyzed: Case 1. All future generating capacity assumed to be coal-fired steam turbines without intertie. Case 2. All future generating capacity assumed to be coal-fired steam turbines with intertie. Case 3. ' Future generating capacity to include Upper Susitna Project plus coal-fired steam plants as needed. Includes intertie. Results of power cost analyses for Anchorage and Fairbanks for the year 2000, with and without intertie are as follows: Power Costs for Anchorage and Fairbanks (0% Inflation) (�;/KWH) Case 1 Case 2 Case 3 Without Intertie With Intertie With Susitna and Intertie Anchorage Fairbanks Anchorage Fairbanks Anchorage Fairbanks High 6.2 8.8 6.1 8.0 5.8 6.2 Med 6.6 8.9 6.2. 8.4 5.5 6.7 Low 7.1 9.2 6.2 8.8 6.1 7.8 The following table presents a comparison of the costs of power in the year 2000 for Case 2, and 3 as compared to Case 1. As shown the costs of power are reduced below the cost of power for Case 1 in all cases. The reduction in the cost of power is typically greater in the 5 Fairbanks -Tanana Valley area than in the Anchorage -Cook Inlet area because the Anchorage -Cook Inlet area will have a higher percent of its generation supplied by steam plants which are more costly than Susitna_ Comparison of Power Costs for Year 2000 Percent Change in Cost of Power Below Case 1 - 0% Inflations` Anchorage Fairbanks High Medium Low high Medium LOW Case 2 -1.6 -6_5 -14.5 -10.0 -6.0 -4.5 Case 3 -6.9 -20.0 -16.4 -41.9 -32.8 -17.9 Table 1 compares annual system costs for all three cases for Anchorage and Fairbanks during the 1990-2011 period. Table 1 shows the following percent savings in system costs (1990-2011) for Cases 2 and 3 compared to Case 1: , Anchorage Fairbanks Total Case 2 -0.4 -7.9 -1.4 Case 3 -10.7 -28.1 -14.1 A H� H H N H H m td U H N N U to O .1i Ind N P+ V le G R 0 W O f=t N N O N N N Lo O O N H 1- I r-I Lo d' O O l0 N N M v %0 1- I N cP O O a0 6l O ct d' 61 to to I O t0 I� CO Ol O O r-I N C•l ;zr N ( O woo o CO w N N N M d d' v 4v d 0o 1l 1- 1- 1- 1- Il 1- O ri r--I r-I H r-i H N ri ri rl r-1 r-i r-1 r-I r-I r-i ri H O r-I M Lo CO CO m r-1 to 61 O M cM N M d' Lo lO r-i co l0 -,- •l0 O 1- cn M 4 hM M (i 4 9 1- M 01 t.0 1- r cn N CO to O r- d' r-i ON w zp 1` Ln M d' O 1-4 M M c1' d' 1- 1\ M 1` 1� to l0 1` 1� v Ln Ln %0 M ri N N m v v Ln Lo to Lo Lo to O Ln to O l0 l0 l0 1- rh 1, 1- co I 1- Ln N r-I N O N N N 61 1- N to t0 Lo I N Ln Oo N to O Ol M CO N m d I Ol d' Ol O CO 61 v M M CO N �N I O to t0 CO m r-i O N' (n tf) t0 CO t0 CO co Ol co CO r-i dp 44;31 Ln 00 CO O CO OD O O r-i r-i r-i r1 -1 r4 ri to H rl r-i H ri ri M rl rl N N N N N N N N N l0 r-i M Ln CO CO Ol r-I M H Ln L— N N 1 r-1 M ri r- c Lf') H Ol . k r-I t, 1� 4 ri r rn 4 r4 io 4 co o 9 rl 4 r-I M ai co h Ln 4 c+1 C7 N v Ln M d' O r-i N co r� 1� Ln Ln CO r-1 N N co Ol O H O r-1 N CM N N' N cn qw d' 4 v Lo Ln l0 l0 O 1- 1, r- 1- lr oa 00 Ol (A Ol 0) 1 r-i Ln 1,0 CO N Lo M N lO d' O O CO 100 O) N O CO N rl Lo 4 Ln r q lD 100 O t.0 co Ol O N [- N 1- N co 1 r-i d' l0 Ln O N N M to t9 CO dl I Ln 41 Ol 61 r-i N N N to l0 O 61 O 6l C, dl M M M M M M M M d' r-I r 1 cy) td ONNtol�OlrOOl1�OOO1 61ri O N v IV t- r-i O m Ol Ln r- dr 0 r i CO O 1- t.0 ';F N r-i r-I r-I ON to .i'., 1, I. N O Ol O l0 v r j N Ol Cn Ol O1 t.0 t.O 1- l0 1` CO Crl O lO 1- 0 N N M eM M M-;T Ln ko l0 l0 Ol l0 O 1- t, r- co co O co Ol Ol 1 O O r-I O td O H N M V M l0 n O0 M O -P r-t N M -CT to \0 1` M 0 O H Ol M M M O M ON M M M N 0 0 0 0 0 0 0 0 0 0 r-1 ,4 1 t ! 1 1 1 1 1 1 I 1 1� 1 I I 1 I 1 i 1 1 1 I r-i O O rl N M to t9 1� O Ol O r-1 N M d' Ln t0 t` CD d> O Ld O Ol M M M M Ol Ol M M M O O O O O O O O O O r-I 4J —1-1 r-I V) Et 7 Response to OMB question 5.4. "Scheduling of powerplants and the reduced risk of building small increments." The Load/Resource analysis for without project condition addresses. the scheduling of steamplants and size of units needed. This is demonstrated in Chapter VIT of the marketability report. Annual power system costs shown in Table l under question 5.3 show savings from Susitna over the without Susitna case. The steamplants are smaller units than Susitna, but their higher cost contributes to higher overall system costs. An analysis of hydro alternatives indicate that there are not economical sites available in sufficient quantity to be comparable to Susitna. This is supported by APA's draft report on "Analysis of Potential Alternative Hydroelectric Sites to Serve Railbelt Area." 8 Response to OMB question 6.1, .2, and .3. Demand Estimates The analysis of load growth should be more specific with respect to: 1. Increasing use by consumers; and, 2. 1ncreasing number of consumers. 3. Industrial growth, i.e., where does Alaska's comparative �- advantage lie outside the area of raw materials and government functions? The new estimates of future power demand are responsive to the first two parts of this question. APA completed a very careful analysis of recent power use trends by class of customer, with particular emphasis on identifying recent trends that could be attributed _.o conservation . efforts. The future demands are based on future population estimates developed by the University of Alaska's Institute of Social and Economic Research and incorporate assumptions of substantially improved efficiency in use of electric power through conservation. The third part of the question requires consideration of the overall Alaskan economy, present and future, and the role of Upper Susitna power. Alaska is not a heavily industrialized State nor is it expected to be. The oil and gas industry is presently the dominating sector of the State's GNP, and will continue to be so for 'at least the balance of the 20th century. This is the principle source of revenues for the State and thus the driving force behind State programs for education, local government assistance, welfare, and so on. Other important industries are the fisheries, forest products, and recreation -tourism. The low- and mid -range population estimates incorporate very modest assumptions of industrial expansion based on pioneering of Alaskan natural resources for the most part. The specific industrial assumptions reflect proven sources of natural resources and projects that are well along in the planning stages. 9 Extraction and processing of natural resources will undoubtedly continue to be major aspects of the Alaskan economy. Other important aspects include business activities of Native Corporations and increasing amounts of land made available to State and private ownership. Actions pending on the new National Parks, Refuges, and Wild and Scenic Rivers will encourage further development of the recreation and tourism industries. As in most parts of the country, Alaska employment is not dominated by' the industrial sectors. Most jobs are in service. industries, the commer- cial establishments, transportation, utilities, and government. The new population estimate by ISER indicates that the distribution of employment will not change substantially. The anticipated growth in the economy, employment, and in power demands is primarily in the non -industrial sectors. _ It should be noted that the Railbelt area demands for electric energy in 1977 were 2.7 billion kilowatt-hours, which is approaching the firm energy capability of the Watana Project. The load resource analyses demonstrate full utilization of Watana energy essentially as soon as it becomes available, even under the lower power demand case. This basically leads us to a finding that the Upper Susitna justification is not dependent on major industrial expansion in Alaska. 10 Response to OMB Question 7. Under the topic Sensitivity Analysis, OMB provided the following comments: "Power demand should be subjected to a sensitivity analysis to better assess the uncertainties in development of such a large block of power. The typical utility invests on the basis of an 8-10 year time horizon. The Susitna plan has an 11-16 year horizon in face of risks that loads may not develop and the option of wheeling power to other markets is not available. It should be noted that the po-orer demand for Snettisham was unduly optimistic when it was built. This resulted in delays in installing generators. A similar error in a project the size of Susitna would be > much more costly and would.have a major adverse effect on the project's economics." The new power demand estimates, load .resources analyses, and financial analysis presented in this report, all provide a better basis for examining these questions. In addition, there is need to review some of the Snettisham Project history to bring out similarities and differences with the Upper Susitna case. Snettisham Review The Snettisham Hydroelectric Project is located near Juneau, Alaska, and is now the main source of power for the greater Juneau area. . The project was authorized in 1962 on the basis of feasibility investigations by the Bureau of Reclamation, constructed by the Corps of Engineers, and opera- ted by the Alaska Power Administration. The -project was conceived as a.two-stage development and construction of the first, or Long Lake, stage was completed in late 1973 with first commercial power to Juneau in December 1973. The second, or Crater Lake, stage would be added Finen power demands dictate. Juneau was, and is, an isolated power market area. Difficult terrain and long distances have thus far prevented electrical interconnection with other Southeast Alaska communities and neighboring areas of Canada; however, such interconnections may prove feasible within the next 15 to 20 years. The project planning and justification was premised on ser- vice only to the greater Juneau area. The Snettisham authorization was based on power demand estimates by the Alaska District, Bureau of Reclamation (now Alaska Power Administration). 1/ The estimates were based on actual power use through 1960 and projec- tions to the year 1987. The outlook'at that time was that the first - stage construction. would be completed in 1966, and that total project capability would not be needed until 1987. A comparison of power demand estimates at the time of authorization with actual demands is shown on Table 1. The 1977 energy load was 112,197 megawatt -hours or 81 percent of the amount estimated in 1961 based on historical records through 1960. 1/ Reappraisal of the Crater -Long Lakes Division,.Snettisham Project, Alaska, USBR, November 1961. 12 Table 1 Power and Energy Requirements -Juneau Area Fiscal Year (Oct. 1 - Sept. 30) Actual Demands MWH Peak MW Forecasted Demands at Time of Authorization 1/ MWH Peak MW 1958. . 23,945 4,788, 1959 26,297 5,321 1960 28,499 5,465 1970 58,266 12,420 73,400 15,230 1971 63,786 13,780 80,700 16,750 . 1972 70,225 14,910 88,800 18,430 1973 75,753 15,470 97,500 20,240 1974 83,059 16,220 106,900 22,190 1975 94,609 17,840 116,900 24,260 1976 106,296 19,800 127,600 26,480 1977 112,197 20,440 139,100 28,870 1/ From Reappraisal of the Crater -Long Lakes Division, Snettisham Project, Alaska, USBR, November 1961. 13 The inherent flexibility of a staged project proved to be very benefi- cial in the case of Snettisham. APA made periodic updates of the power demand estimates during construction of the Long.Lake stage. For several years, these forecasts indicated a need to proceed with the. Crater Lake stage construction immediately on completion of the Long Lake stage. The Corps of Engineers construction schedules and budget requests, based on the APA power demand estimates, anticipated start of construction on Crater Lake in FY 1977. Major factors in these fore- casts were plans for a major new pulp mill in the Juneau area and for iron ore mining and reduction facility in the vicinity of Port Snettisham. Neither of these developments were anticipated at the time of authoriza- tion. Both of these resource developments fell through, and this � resulted in a substantial reduction in the APA power demand estimate and a decision in late 1975 to defer the Crater Lake construction start. The pulp mill was particularly influential in the change in demand estimates. The mill was planned for operation in the early 1970's with a large population and commercial impact on Juneau. Initial access facilities were constructed and site preparation w'as well underway when the project became entangled in protracted law suits involving logging practices in Southeast Alaska. Several court decisions were made in favor of the development, but a last minute remand put.the project back to base one and led to cancellation in early 1975. This type of uncertainty faces all utility planners. The staged project like Snettisham affords a great deal of capability to adjust to changes in demand. Many other factors influenced Juneau area power demands and utilization of project power. Of particular concern at the moment is impact of Alaska's capital move initiative. This would certainly change use of project power, with the most likely outcome that the community would move more quickly into an all -electric mode (space heating and electric vehicles appear particularly attractive in this area) and industrial use of power would increase through economic diversification. 14 The key points of the Snettisham review are: 1. The project was planned and authorized with intent to handle growth in area power requirements for a 20-year period. 2. The load forecasts used -as a basis for authorization were reasonably accurate. 3. The actual use of project power may turn out to be substantially .different than originally anticipated. 4. The zlexibility of staged projects was actually used. S. The outlook for financial viability appears excellent at this time in history. Implications for Susitna First, the norm for utility .investments cannot remain as the basis of an 8 to 10.year time horizon. This is evidenced by experiences since about 1970 on time required to plan, obtain necessary permits or authorizations, find financing, and then build new powerplants and major transmission facilities. The 8 to 10 years is much too short for nuclear, coal, and hydro plants and for major transmission lines. ire a 20-year planning horizon with careful It appears appropriate to requ checks at each step in the process and business -like decisions to shift construction schedules if conditions (demands) change. We believe the Snettisham experience is very positive in this light. The Susitna Project is similar in that project investment is keyed to two major stages. The commitment of construction funds for Watana would be needed in 1966 or 1987 to have power on line by 1993 or 1994. If conditions in 1986 indicate need to defer the project, it should be deferred. Similarly, start of actual construction. on Devil Canyon can 15 and should be based on.conditions that actually prevail at the time.the decision is made. The level of uncertainty for Upper Susitna is greater than was the case for Snettisham on counts of higher interest costs and larger total investment. Sensitivity to change in demands is much less for Susitna. because of its large and diversified power market area. There are many more ways that Susitna Project power could be effectively utilized in the event that traditional utility power markets are smaller than anticipated at the present. Upper Susitna does not have as many uncertainities in terms of environ- mental questions as would equivalent power supplies from coal or nuclear ,plants. Uncertainties on air quality are particularly relevant for any larger Alaskan coal-fired powerplants. 16 Current Evaluation Power demands were estimated for High, Medium, and Low cases to year 2025 assuming logical variations in population and energy use per capita. The projections reflect energy use per capita based on detailed studies of 1970-1977 data from both the Anchorage and Fairbanks areas. The projections considered variations in per capita use ranging from increased use of electricity in the home to anticipated effects of conservation on decreasing the growth rates. A detailed discussion of the development of the power demands is included in Chapter 5 of this report. The load/resource and cost analysis provided system cost for comparison of cases both with and without the Susitna Project: The analysis also compared the power demands to the resources required to determine sizes and timing of new plants (the load/resource analysis is summarized in Chapter VII). Table 2 summarizes the resources needed during the 1990's for the range of projections. The Table indicates that even under the most conservative load growth condition (low), 1,500 MW are needed to meet the combined Anchorage - Fairbanks demands, which is roughly the capability of Susitna. Tables 3 and 4 show the power costs for Anchorage and Fairbanks during the 1990's with an interconnection and with and without the Susitna Project. It is readily apparent the rates are less for the case with Susitna. For example, in the medium case for the year 2000, Anchorage costs are 5.5,�/kwh or 13 percent less than without Susitna. In the Fairbanks costs, the difference is much larger, 6.7�/kwh or 25 percent less than without Susitna. In Table 5, annual system interest costs are composed with and without Susitna with intertie from 1990 to 2011. Examination of the system cost on an annual basis reveals the case with Susitna is cheaper than the without Susitna case for each year except the first few years after Watana comes on line. 17 Table 2. Schedule of Plant Additions -Ml Cases with Interconnection without Upper Susitna Anchorage Fairbanks Period High Median. Low High Median Low 89-90 400 * 200 - * 100 90-91 - 200_. 91-92 400 200 - - - - 92-93 - 400 200 200 - - 93-94 400 - - 100 - - 94-95 - - * - 100 95-96 400 400 200 .100 100 - 96-97 400 400 200 100 - 100 97-98 400 -. 400 200 100 100 93-99 400 ;` 400 - - 100 - 99-00 400 - - - - - a TOTAL 90-2000 3200 2000 1200 700 400 300 *Interconnection Installed case, in 1987 for high case, 1990 for median & 1995 for low case_ Replacement of military powerplants, many of which .also supply heat for buildings are additional but not shown here. 18 TABLE 3. Power Costs for Anchorage and Fairbanks Areas With Interconnection and Without Upper Susitna - 0% Inflation (cents/kwh) Anchorage Fairbanks Period High Median Low High Median Low 89-90 5.7 4.5 4.2 4.7 5.8 5.6 90-91 5.4 4.8 4.1 4.6 5.9 5.8 9,1-92 5.7 5-3 4.1 4.4 5.7 5.8 92-93 5>4 5.9 4.7 6.3 5.4 5.6 93-94 5.7 5.6 4.6 7.3 5.2 5.5 94-95 5.5 5.4 4.9 7.0 6.5 6.7 95-96 5.6 5.8 5.4 7.8 7.7 6.9 96-97 5.8 6.4 5.8 8.2 7.4 8.3 97-98 5.9 6.1 6.6 8.7 7.8 9.1 98-99 6.0 6.5 6.4 8.3 8.7 8.9 99-00 6.1 6.2 6.2. 8.0 8.4 8.8 : 19 TABLE 4. Power Costs for Anchorage and Fairbanks Areas With Interconnection and With Upper Susitna Coming on Line in 1994 - 0% Inflation (cents/kwh) . Fairbanks Anchorage Period High Median Low High Median Lola 89-90 5.7 4.5 4.2 4.7 5_8 5.6 90-91 5-4 4.8 4.1 .4.6 5.9 5..8 91-92 5.7 5-3 4.6 4.4 5_7 7.2 92-93 5.4 5.9 4.4 6.3 5.4 6.9 93-94 5.7 5.6 5.0 7.3 5.2 6.8 ' 94-95 6.4 6.9 7.3 7.9 6.8 8.8 95-96 6.0 6.5 6.8 7.7 6.7 8.9 96-97• 6_2 6.1 6.5 7:2 6.4 8.6 97-98 6.2 5.8 6.3 6.6 6.9 7.8 6.1 5.8 6.1 6.5 6.9' 7:6 98-99 99-00 5.8 5.5 6.1 6.2 6.7 7.8 TABLE 5. Power System Annual Costs for Anchorage and Fairbanks With Upper Susitna Coming on Line in 1994 - 0'- Inflation (million $) Anchorage Fairbanks 20 Period High Median Low High Median Low 89-90 508.5 254.5 173.4 85.2 84.2 63.4 90-91 514.1 293.8 175.0 89.0 89.0 68.5 91-92 591.8 343.8 206.0 90.2 90.2 87.4 92-93 597.3 409.9 205.0 137.8 88.2 85.5 93-94 666.0 414.1 244_5 166.8 69.2 86.4 94-95 798.5 537.5 372.3 192:2 120.5 115.6 95-96 806.1 537.9 368.4 198:0 124.8 119.2 96-97 898.6 543.0 368.5 198.5 124.0 117.5 97-98 793.1 549.3 369.9 192.5 139.2 109.2 98-99 1,009.1 576.3 376.1 201.3 145.1 109.7 99-00 1,018.9 577.2 391.7 203.5 145.7 114.9 00-01 1,025.1 573.4 381.4 228.6 146.5 114.5 01-02 1,101.3 578.5 380.3 254.0 147.4 114.5 02-03 1,172.1 658.E 375.3 254.3 168.E _ 111.9 03-04 1,190.4 665.1 376.E 291.6 169.6 112.0 04-05 1,287.7 670.8 376.8 296.0 170.6 112.1 05-06 1,366.8 677.E 378.0 296.1 170.2 110.7 06-07 1,386.8 744.4 379.4 299.2 171.2 110.8 07-08 1,467.2 751_6 380.8 302.4 172.3 110.9 08-09 1,548.1 759.0 382.2 305.7 173.4 111.1 09-10 1,569.9 766.7 383.7 . 343.5 174.6 111.2 10-11 1, 671.E 834.3 �- 385.2 347.0 175.7 111.4 Total 22,989.0 12,717.3 7,430.5 4,973.4 3,080.2 2,308.4 i 21 (continued). TABLE'5. Power System Annual Costs for Anchorage and Fairbanks Without Upper Susitna Coming, On Line in.1994 - 0% Inflation • (million $) Anchorage Period High Median Low 89-90 508.5 254.5 173.4 90-91 514.1 293.8 175.0 91-92 591.8 343.8 185.7 92-93 597.3 409.9 223.3 93-94 666.0 414.1 227.2 94-95 678.0 421.3 252.4 95-96 750.0 486.1 290.9 96-97 843.4 571.5 327.9. 97-98 918.8 578.7 389.8 98-99 998.3 650.2 396.7 99-00 1,074.0 657.2 397.9 00-01 1,160.8 714..3 470.6 01-02 1,238.6 721.1 472.5. 02-03 1,310.9 723.1 469.8 03-04 1,331.0 789.8 472.8 04-05 1,350.7 798.5 474.8 05-06 1,431.7 807.1 477.8 06-07 1,513.3 815.9 480.9 07-08 1,615.1 904.4 484.0 08-09 1,638.1 913.6 487.1 09-10 1,721.4 923.1 490.3 10=11 1,801.7 932.7 493.6 Total 24,253.5 14,124.7 8,314.4 Fairbanks High Median Low 85.2 84.2 63.4 89.0 89.0 68.5 90.2 90.2 71.1 137.8 88.2 69.2 166.8 89.2 70.1 169.4 114.9 87.2 201.3 143.7 91.8 224.8 143.2 113.1 253.4 158.5 127.6 256.3 182.6 128.4 259.7 184.5 '129.3 262.3 185.5 129.6 265.3 186.8 130.2 265.8 208.2 128.3 303.5 209.6 126.8 341.2 211.0 129.3 343.1 210.9 128.4 346.5 212.3 151.7 350.1 213.8 152.2 353.7 215.3 152.8 357.5 216.9 153.3 361.4 218.4 153.9 5,484.3 3,656.9 2,558..2 22 It should be noted that in the low energy use estimate the total system cost for Anchorage during this period amounts to $883.9 million less with,Susitna than without the project. The difference is even larger in the medium and high cases. The combined Anchorage -Fairbanks cash savings for the same period based on the medium power use estimate is almost $2 Billioi Previous Studies There was a fairly substantial backlog of power system and project studies relevant to the 1976 evaluation -of the tapper Susitna River Project. The previous studies most relevant include: 1. Advisory Committee studies completed in 1974 for the Federal Power Commission's (FPC) 1976 Alaska Power Survey. The studies include evaluation of existing power systems and future needs through the year 2000, and the main generation and transmission alternatives available to meet the needs. The power requirement • studies and alternative generation system studies for the 1976 power survey were used extensively. 2. A series of utility system studies for Railbelt area utilities include assessments of loads, power costs, and generation and trans- mission alternatives. 3. Previous work by the Alaska Power Administration, the Bureau of Reclamation, the utility systems, and industry on studies of various plans for Railbelt transmission interconnections and the Upper Susitna hydroelectric potential. It should be noted that many of the studies listed in the bibliography represent a period in history when there was very little concern about energy conservation, growth, and needs for conserving oil and natural gas resources. Similarly, many of these studies reflected anticipation of long term, very low cost energy supplies. In this regard, the studies for the 1976 power survey are considered particularly significant in that they provide a first assessment of Alaska power system needs reflecting the current concerns for energy and fuels conservation and the. environment, and the rapidly increasing costs of energy in the economy. The latter concern for conservation, etc. has been carried even further in this report. As yet unpublished studies by the Alaska Power Admini- stration have made a definite reflection of conservation assumptions. The resulting load forecasts were used in load/resource analyses done and reported by Battelle Pacific Northwest Laboratories in 1978 and 1.979. (Battelle also published a report in 1978 entitled Alaska Electric Power, and Analysis of Future Requirements and Supply Alternatives for the Railbelt Region.) Population and employment used. in the recent forecasts were projected and reported by the Institute of Social and Economic Research in September 1978. The result of their econometric model is entitled South Central Alaska's Economy and Population, 1965-2025: A Base Study and Projection. A partial bibliography of related studies including those of the 1976 Susitna report, is appended. 25 PARTIAL BIBLIOGRAPHY OF RELATED STUDIES The 1976 Alaska Power Survey, Federal Power Commission Vol. I and Vol. II. Alaska Regional Energy Resources Plant Project - Phase I, Alaska Division of Energy and Power Development, Department of Commerce. and Economic Development, October 1977. Volume I - Alaska's Energy Resources, Findings and Analysis Volume II - Alaska's Energy Resources, Inventory of Oil, Gas, Coal, Hydroelectric, and Uranium Resources Jobs and Power For Alaskans: A Program for Power and Economic Develop= ment, July 1978. Department of Commerce and Economic Development. Appendix: Power and Economic Development Program, July 1978. Alaska Electric Power Statistics 1960-1976, Alaska Power Administration, July 1977. The Proposed Glennallen-Valdez Transmission Line. An Analysis of Available Alternatives. Robert W. Retherford Associates, May 1978. Power Requirements Study, Matanuska Electric Association, Inc. Rural Electrification Administration, May 1978. 26 Southcentral Railbelt Area, Alaska, Upper Susitna River Basin Interim Feasibility Report. Hydroelectric Power and Related Purposes, Corps of Engineers, December 1975. Appendix I, Part I: (A) Hydrology, (B) Project Description and Cost Estimates, (C) Power Studies and Economics, (D) Foundation and Materials, (E) Environmental Assessment, (F) Recreational Assessment Appendix I, Part II: (G) Marketability Analysis, (H) Trans- mission System, (I) Environmental Assessment for Transmission Systems Appendix II: Pertinent Correspondence and Reports of Other Agencies. A Hydrologic Reconnaissance of the Susitna River Below Devils Canyon. Environaid, October 1974. Solomon Gulch Hydroelectric Project. Definite Project Report. Robert W. Retherford Associates, March 1975. Electric Power in Alaska, 1976-1995. Institute of Social and Economic Research, University of Alaska, August 1976. Southcentral Alaska's Economy and Population, 1965-2025: A Base Study and Projection. Report of the Economic Task Force, Southcentral Alaska Water Resources Study (Level B). Institute of Social and Economic Research, University of Alaska, September 1978 (Draft Report). 27 Interior Alaska Energy Analysis Team Report. Fairbanks Industrial Development Corporation for Division of Energy and Power Development, June 1977. Natural Gas Demand and Supply to the Year 2000 in the Cook Inlet Basin of Southcentral Alaskav, SRI International for Pacific Alaska LNG Company, November 1977. Load/Resource and System Cost Analysis for the Railbelt Region of Alaska;. 1978-2010. Battelle Pacific Northwest Laboratories, January 1979. Participation in Healv II Electric Generation, Fairbanks Municipal Utilities System. Harstad Associates, Inc. June 1978. Economic Feasibility of a Possible Anchorage -Fairbanks Transmission Intertie. Robert W. Retherford Associates for Alaska Power Authority (not yet completed). 1976 Power Systems Study, Chugach Electric Association,Inc. Tippett and Gee. March 1976. Comparative Study of Coal and Nuclear Generation Options in the Pacific Northwest, Washington Public Power Supply System, June 1977. Coal -Fired Powerplant Capital Cost Estimates, Electric Power Research Institute, January 1977. 28 Analysis of the Economics of Coal Versus Nuclear for a Powerplant Near Boise, Idaho, Idaho Nuclear Energy Commission, March 1976. Alaska Electric Power, An.Analysis of Future Requirements and Supply Alternatives for the Railbelt Region, Battelle Pacific Northwest Laboratories, March 1978. . Geology and Coal Resources of the Homer District Kenai Coal Field, Alaska, Geological Survey Bulletin 1058-F, 1959. Development of the Beluga Coal Field, a status report, A.M. Laird, Placer Amex Inc., San Francisco, California, October 1978. TTidal°Power From Cook Inlet, Alaska, Swales, M.C. and Wilson, E.M., published in Tidal Power, Proceedings of the International Conference on the Utilization of Tidal Power, May 1970. Advisory Committee Reports for`Federal Power Commission Alaska Power Survey: Report of the Executive Advisory Committee, December 1974 Economic Analysis, and Load Projections, May 1974 Resources and Electric Power Generation, May 1974 Coordinated Systems Development and Interconnection, December 1974 Environmental Considerations and Consumer Affairs, May 1974 Alaska Power Survey, Federal Power Commission, 1969. Devil Canyon Status Report, Alaska Power Administration, May 1974. Devil Canyon Project - Alaska, Report of the Commissioner of Reclamation, March 1961, and supporting reports. Reprint, March 1974. Reassessment Report on Upper Susitna River Hydroelectric Development for the State of Alaska, Henry J. Kaiser Company, Sept. 1974. Project Independence, Federal Energy Administration, 1974. A main report, summary, seven task force reports, and the draft environmental impact statement. Engineering and Economic Studies for the City of Anchorage, Alaska Municipal Light and Power Department, R. W. Beck and Associates and Ralph R. Stefano and As-sociates, August 1970. Power Supply, Golden Valley Electric Association, Inc., Fairbanks, Alaska, Stanley Consultants, 1970. 12 Copper Valley Electric Association, Inc. - 15 Year Power Cost Study, Hydro/Diesel, Robert'W. Retherford Associates, October 1974. 30 Environmental Analysis for Proposed Additions to Chugach Electric Association, Inc., Generating Station at Beluga, Alaska, Chugach Electric Association, October 1973. Central Alaska Power Pool, working paper, Alaska Power Administration, October 1969. Alaska Railbelt Transmission System, working paper, Alaska Power Administration, December 1967. Electric Generation and Transmission Intertie System for Interior and Southcentral Alaska, CH2M Hill, 1972. Central Alaska Power Study, The Ralph M. Parsons Company, undated. Alaska Power Feasibility Study, The Ralph M. Parsons Company, 1962. PNL-2896 INFORMAL REPORT LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION OF ALASKA: 1978-2010 for ALASKA POWER ADMINISTRATION U.S. DEPARTMENT OF ENERGY by J. J. Jacobsen W. H. Swift J. A. Haech January 1979 Pacific Northwest Laboratory Richland, Washington 99352 CONTENTS LIST OF FIGURES v LIST OF TABLES vi 1.0 INTRODUCTION 1 2.0 SUMMARY AND CONCLUSIONS 4 3.0 LOAD/RESOURCE ANALYSES 7 3.1 ANALYSIS METHODOLOGY '. 8 3.2 ASSUMPTIONS 8 3.2.1 Forecasted Power and Energy Requirements 8 3.2.2 Existing and Planned Generating Capacity 15 3.2.3 Reserve Margin 15 3`.2.4 Transmission Losses 21 3.2.5 Construction Schedule Constraints 21 3.2.6 Plant Availability Constraints .. 2.2 3.2.7 Economic Generating Unit -Size 25 3.3 SYSTEM CONFIGURATIONS: DEFINITION OF CASES ANALYZED 25 3.3.1 Case 1: Without Interconnection and Without Upper Susitna Project 25 3.3.2 Case 2: With Interconnection, Without Upper Susitna Project 26 3.3.3 Case 3: Interconnected System With Upper Susitna Project 30 3.4 RESULTS OF LOAD/RESOURCE ANALYSES 31 4;0 SYSTEM POWER COST ANALYSES' 66 4.1 FACTORS DETERMINING THE COST OF POWER 66 4.1.1 Capital. Costs 66 4.1.2 Heat Rate 68 4.1.3 Operation, Maintenance, and Replacement Costs 68 4.1.4 Financing Discount Rate 69 4.1.5 Payback Period 69 4.1.6 Annual Plant Utilization Factor 69 4.1.7 Unit Fuel Costs 69 4.1.8 General Inflation Rate 73 4.1.9 Construction Escalation Rate 73 iii 4.1.10 Fuel Escalation Rate. . 4.2 METHOD OF COMPUTING THE ANNUAL COST OF POWER FROM INDIVIDUAL GENERATING FACILITIES 4.3 METHOD OF COMPUTING AVERAGE SYSTEM POWER COST 4.4 RESULTS OF SYSTEM CASH FLOW AND POWER COST CALCULATIONS a 73 73 75 76 iv FIGURES 3.1 Railbelt Region Peak Loads 12 3.2 Anchorage -Cook Inlet Area Annual Energy 13 3.3 Fairbanks Area Annual Energy 14 3.4 Plant Utilization Factor versus Plant Age 23 3.5 Railbelt Region Showing the Watana and Devil Canyon Damsites, a Possible Route for the Interconnection, and the Belugd Area 28 3.6 Load/Resource Analysis for Anchorage -Cook Inlet Area Without Interconnection and Without Susitna Project (Case 1) 60 3.7 Load/Resource Analysis for Anchorage -Cook Inlet Area With Interconnection but Without Upper Susitna Project (Case 2) 61 3.8 Load/Resource Analysis for Anchorage -Cook Inlet Area With Interconnection and With Upper Susitna Project Coming On Line in 1994 (Case 3) 62 3.9 Load/Resource Analysis for Fairbanks -Tanana Valley Area Without Interconnection and Without Upper Susitna Project (Case 1) 63 3.10 Load/Resource Analysis for Fairbanks -Tanana Valley Area With Interconnection but Without Upper Susitna Project (Case 2) 64 3.11 Load/Resource Analysis for Fairbanks -Tanana Valley Area With Interconnection and With Upper Susitna Project Coming On Line in 1994 (Case 3) 65 4.1 Components of the Total Annual Cost of Power 67 4.2 Estimates of Future Coal Prices - 2% and 7% Escalation 70 4.3 Estimates of Future Natural. Gas Prices - 20 and 7% Escalation 71 4.4 Estimates of Future Fuel Oil and Diesel Prices - 20/10 and 7% Escalation 72 4.5 Power Costs for Anchorage Low Load Growth Scenario 116 4..6 Power Costs for Anchorage Medium Load Growth Scenario 117 4.7 Power Casts for Anchorage High Load Growth Scenario 118 4.8 Power Costs for Fairbanks Low Load Growth Scenario . 119 4.9 Power Costs for Fairbanks Medium Load Growth Scenario 120 4.10 Power Costs for Fairbanks High Load Growth Scenario 121 v TABLES 2.1 Comparison of Power Costs for Year 2005 6 3.1 Anchorage -Cook Inlet Area Power and Energy Requirements 9 3.2 Fairbanks -Tanana Valley Area Power and Energy Requirements 10 3.3 Total Power Requirements; Anchorage -Cook Inlet Area and Fairbanks -Tanana Valley Area Combined . 11 3.4 Existing (Fail-1978) Generating Capacities for Anchorage -Cook Inlet Area 16 3.5 Existing (Fall-1978) Generating Capacities for Fairbanks -Tanana Valley Area 18 3.6 Anchorage -Cook Inlet Area Existing Capacity and Maximum Annual Plant Utilization (October 1978) 19 3.7 Fairbanks -Tanana Valley Area Existing Capacity and Maximum Annual Plant Utilization (October 1978) 19 3.8 Planned Additions for Railbelt Region (1979-1995) 20 3.9 Transmission System Alternatives 27 3.10 Load/Resource Balance for Case 3: Medium Load Growth Scenario 32 3.11 Schedule of Plant Additions - (Megawatts) Base Cases Without Interconnections 54 3.12 Schedule of Plant Additions - (Megawatts) Cases With Interconnection Without Upper Susitna 56 3.13 Schedule of Plant Additions - (Megawatts) Cases With Interconnection With Upper Susitna Coming On Line in 1994 58 4.1 Anchorage -Cock Inlet Area, Low Load Growth Scenario, Case 1, 0% Inflation 78 4.2 Anchorage -Cook Inlet Area, Low Load Growth Scenario, Case 11 5% Inflation 79 4.3 Anchorage -Cook Inlet Area, Low Load Growth Scenario, Case 2 0% Inflation 80 4.4 Anchorage -Cook Inlet Area, Low Load Growth Scenario, Case 2, 5% Inflation - 81 4.5 Anchorage -Cook Inlet Area, Low Load Growth Scenario, Case 3, 0% Inflation 82 4.6 Anchorage -Cook Inlet Area, Low Load Growth Scenario, Case 3, 5% Inflation 83 4.7 Anchorage -Cook Inlet Area, Medium Load Growth Scenario, Case 1, 0910 Inflation 84 vi TABLES (contd 4.8 Anchorage -Cook Inlet Area, Medium Load Growth Scenario, Case 1, 5% Inflation . 4.9 Anchorage -Cook Inlet Area, Medium Load Growth Scenario, Case 2, 0% Inflation . 4.10 Anchorage -Cook Inlet Area, Medium Load Growth Scenario, Case 2, 5% Inflation . 4.11 Anchorage -Cook Inlet Area, Medium Load Growth Scenario, Case 3, 0% Inflation . 4.12 Anchorage -Cook Inlet Area, Medium Load Growth Scenario, Case 3, .5% Inflation , 4.13 Anchorage -Cook Inlet Area, High Load Growth Scenario, Case 1, 0% Inflation . 4.14 Anchorage -Cook Inlet Area, High Load- Growth Scenario, Case 1, 5% Inflation . 4.15 Anchorage -Cook Inlet Area, High Load Growth Scenario, Case 2, 0% Inflation . 4.16 Anchorage -Cook Inlet Area, High Load Growth Scenario, Case 2, 5% Inflation . 4.17' Anchorage -Cook Inlet Area, High Load Growth Scenario, Case 3, 0% Inflation . 4.18 Anchorage -Cook Inlet Area, High Load Growth Scenario, Case 3, 5% Inflation . 4.19 Fairbanks -Tanana Valley Area, Low Growth Scenario, Case 1, 0% Inflation . 4.20 Fairbanks -Tanana Valley Area, Low Growth Scenario, Case 1, 5% Inflation . 4.21 Fairbanks -Tanana Valley Area, Low Growth Scenario, Case 2, 0 Inflation . 4.22 Fairbanks -Tanana Valley Area, Low Growth Scenario, Case 2,' 5% Inflation . 4.23 Fairbanks -Tanana Valley Area, Low Growth Scenario, Case 3, 0/10 Inflation . 4.24 'Fairbanks -Tanana Valley Area, Low Growth Scenario, Case 3, 5' Inflation . 4.25 Fairbanks -Tanana Valley Area, Medium Growth Scenario, Case 1, 0% Inflation . 4.26 Fairbanks -Tanana Valley Area, Medium Growth Scenario, Case 1,. 5% Inflation . Vil 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 TABLES (contd) 4.27 Fairbanks -Tanana Valley Area, Medium Growth Scenario, Case 2, 0% Inflation 104 4.28 Fairbanks -Tanana Valley Area, Medium Growth Scenario, Case 2, 5% Inflation 105 4.29 Fairbanks -Tanana Valley Area, Medium Growth Scenario, Case 3, 0% Inflation .. 106 4.30 Fairbanks -Tanana Valley Area, Medium Growth Scenario, Case 3, 5% Inflation 107 4.31 Fairbanks -Tanana Valley Area, High Growth Scenario, Case 1, .0% Inflation 108 4.32 Fairbanks -Tanana Valley Area, High Growth Scenario, Case 1, 5% Inflation 109 4.33 Fairbanks -Tanana Valley Area, High Growth Scenario, Case 2, 0% Inflation 110 4.34 Fairbanks -Tanana Valley Area, High Growth Scenario, Case 2, 5% Inflation . ill 4.35 Fairbanks -Tanana Valley Area, High'Growth Scenario, Case 3, 0% Inflation 112 4.36 Fairbanks -Tanana Valley Area., High Growth Scenario, Case 3, 5% Inflation 113 viii LOAD/RESOURCE AND SYSTEM COST ANALYSIS FOR THE RAILBELT REGION OF ALASKA - 1978-2010 Prepared for the Alaska Power Administration by Battelle Pacific Northwest Laboratories January 1979 1.0 INTRODUCTION The Alaska Railbelt region presents some unique attributes for considera- tion in future power system planning. The region currently consumes 83% of the State's electric power and even the lower estimates of electrical load growth (5q per annum) for the region are above the national average. The State, and particularly this region, is a difficult one in which to forecast load growths. This difficulty results from the nature of the economic activity base being influenced by external forces such as oil and gas develop- ments and transportation systems, -with their cyclical tendency. Also, since the economic base is still not large, the injection of a competitively scaled industry such as major petroleum refinery or electrochemicai'industry can sig- nificantly perturb a forecast. A major shift in the Alaskan Railbelt future power generating ;rode appears inevitable. The Cook Inlet Region's capacity is presently dominated by combus- tion turbines fired by currently low-cost natural gas; the Fairbanks -North Star Borough by a mix of coal-fired steam turbine generation and oil -fired combus- tion turbines. The oil and gas based mode of generation, however, are highly exposed to inflationary pressures, external market forces, and Federal regula- tory intervention. The Railbelt region, however, does have a number of options open in the future. These include: 1 • Continued use of oil and gas in existing plants. • Increased coal based thermal generation both in the interior based on the Healy Coal Field and in the Cook Inlet Region based on several coal fields, including the very large reserves in the Beluga Region. • Development of the significant hydroelectric potential, including Upper Susitna River and Bradley Lake. • A transmission intertie between the Cook Inlet and Fairbanks load centers is of obvious interest as a means of increasing reliability or alternately reducing additional generating capacity needed for reliability. Marketing of power from Upper Susitna projects will be dependent upon such an intertie. Electric power generation by whatever means is a very capital intensive activity. Different forms of generation, however, have different levels of exposure to inflation and escalation and, cost comparisons on a straight $/k�W of installed capacity can be misleading. Thus a higher cost per kilowatt hydro- electric project has this exposure largely limited to the time period during planning and construction. On the other hand, a fossil fueled plant faces rising fuel costs as well as operating and maintenance costs in the future. Regardless of these factors, all generation options are faced with long lead times from decision to proceed to commercial operating date. The purpose of this report is to examine the probable timing of major generation and transmission investments and their impact on system power costs under a range of assumptions about power demands and inflation and escalation rates for the following general P.ailbelt power supply strategies: Fl Case 1. All additional generating capacity assumed to be coal fired steam turbines without a transmission interconnection between the Anchorage - Cook Inlet area and the Fairbanks -Tanana Valley area load centers. Case 2. All additional generating capacity assumed to be coal fired steam turbines, including a transmission interconnection. Case 3. Additional capacity to include the Upper Susitna Project (including transmission intertie) plus additional coal as needed. 2 0 The first step involved in estimating the cost of power from alternative generation and transmission system configurations is to perform a series of load/resource analyses. These analyses determine the schedule of major invest- ments based on assumptions about the load growth, the capacity and power produc- tion of the prospective generating facilities, and constraints as to when the facilities can come on line. The load/resource analyses provide information on the annual power produc- tion of the various types of generating plants. Once the annual plant utiliza- tions are known, they can be used in conjunction with estimates of annual system costs to calculate the annual cost of producing power from the facili- ties. Summing the annual cost for generation and transmission of each of the generating facilities gives a total cost for the entire system being analyzed. Dividing the total annual cost by the power produced gives an average annual cost of power for the entire system. By comparing the average annual power costs over the period of interest (1978-2010) the alternative configurations can be ranked based on the cost of power. All other things being equal, the system configuration producing -power at the lowest cost should be selected as the most desirable system. The report was prepared on contract to the Alaska Power Administration (APA) as input to APA's power market analysis for the Upper Susitna Project. The APA furnished, and is responsible for, all data on power requirements, cost assump- tions, and certain key criteria for the study. The balance of the criteria were developed jointly by the APA and Battelle. Chapter 2 contains a brief summary of the results of the study. The load/ resource analyses are described in Chapter 3. Chapter 4 presents the methodol- ogy and results of the cash flow and power cost calculations. Appendix A con- tains the data used in the load/resource analyses. Appendix B contains a list- ing of the computer model (AEPMOD) used to perform the load/resource matching. The output of AEPMOD for the cases analyzed in this report are presented in Appendix C. Appendix D contains a listing of the model used to compute the cost of power and Appendix E contains some selected results of ECOST 4 model runs. 3 2.0 SUMMARY AND CONCLUSIONS Load/Resource Matching ® Forecasted peak loads for the Anchorage/Cook Inlet and the Fairbanks/ Tanana Valley load centers have been matched with schedules of plant addi- tions for low, median, and high forecasted load growths. These were replicated for cases considering 1) continued separation of the load cen- ters, 2) interconnection without development of Upper Susitna hydroelec- tric power, 3) interconnection including development of the proposed Upper Susitna hydroelectric projects beginning in 1994. ® Thermal. generating capacity additions to the year 2010 were estimated as follows: Case 1: Without Interconnection and Upper Susitna Assumed Load Megawatts Growth Anchorage Fairbanks Total. Low 2600 471 3071 Median 4600 871 5471 High 8200 1471 9671 Case 2: Interconnection without Upper Susitna Assumed Load Megawatts Growth Anchorage Fairbanks Total Low 2200 471 2671 Median 4200 671 4871 High 8200 1271 9471 Case 3: Interconnection with Upper Susitna Assumed Load Megawatts Growth Anchorage Fairbanks Total Low 1000 171 1171 Median 3000 371 3371 High 6600 1071 7671 9 • Provision of the interconnection without Upper Susitna reduces thermal plant addition requirements by 200 to 600 MW over the period. • Interconnection with Upper Susitna reduces thermal plant addition require- ments by 1500 to 1800 MW depending on the assumed load growth. • Under the criteria used, the interconnection is called for in 1986, 1989, and 1994 for high, median, and low load growth cases, respectively, with- out Upper Susitna projects. With Upper Susitna, the corresponding dates are 1986, I989, and 1991. System Power Cost • For the Anchorage -Cook Inlet load center construction of the inter- connection reduces the cost of power compared to the case without an i nterconnecti on. • For the Anchorage -Cook Inlet area inclusion of the Upper Susitna project into the system generally raises the cost of power above the other cases during the first 2 to 4 years after the Watana Dam comes on line with results in lower power costs during the 1996-2010 time period. • For the Fairbanks -Tanana Valley area construction of the interconnection again generally reduces the cost of power. • For the Fairbanks -Tanana Valley load center inclusion of the Upper Susitna project generally raises the cost of power above the case with the inter- connection for about 2 years after the Watana Dam comes on line but, as with the Anchorage -Cook Inlet area, results in lower -power costs during the 1996-2010 time period. • Table 2.1 presents a comparison of the costs of power in the year 2005 for the cases evaluated in the report using the case without either the interconnection or the Upper Susitna projects (Case 1) as the base. The costs of power computed in Case 1 are compared to cases with the inter- connection (Case 2), and with Upper Susitna coming on line in 1994 (Case 3). As shown, the costs of power are reduced below the cost of power for Case 1 in but one case. This reduction varies from 4.3% to 39.3% depend- ing upon the situation. TABLE 2.1. Comparison of Power Costs for Year 2005 Percent Change in Cost of Power Below Case 1 5% Inflation Anchorage Fairbanks High Median Low High Median Low Case 2 -4.3 .-10.1 -12.2 +8.9 -9.6 -4.2 Case 3 -10.5 -30.3 -39.3 -8.9 -30.8 -26.3 0 3.0 LOAD/RESOURCE ANALYSES The load/resource analysis is intended to match forecasted electric power requirements with appropriate generating capability additions. The analysis schedules new plant additions, keeps track of older plant retirements, and com- putes the loading of installed capacity on a year -by -year basis over the period 1978 to 2010. The analysis schedules the additions to assure that both peak loads and energy requirements (including reserves) are met on a year -by -year basis with the least amount of installed capacity and with generating plants loaded in any preselected order, typically in order of lowest to highest marginal power costs. A number of factors must be taken into account: 1. Forecasted loads in terms of peak power requirements in megawatts (MW) and annual energy requirements in millions of killowatt hours (MMkWh). 2. The stock of existing generating capacity by type, size, year of •retirement, and maximum allowable plant factor. 3. Desired reliability reserve margin to provide insurance against forced outages, unforeseen delays in plant availability, or load growths in excess of those anticipated. 4. Transmission and distribution losses. 5. Constru"ti-rl schedule constraints; i.e., lead times necessary between unit selection and first power on line date. 6. Plant availability constraints based on types and age. (Thermal plants generally have lower availability at the start and end of their economic life.) 7. Assumptions about the economic size of future generating plants in relation to -the loads. S. System configuration; i.e., interconnections, alternative siting strategies. 7 3.1 ANALYSIS METHODOLOGY The load/resource matching is done on an annual basis. The Alaskan elec- tric utility systems experience their annual peak load requirements during the. winter months and resources must be available to meet these peak loads. During recent years the annual load factor for Railbelt electrical demand has typi- cally been about 46-50%. It is expected to remain in the range of 50-52% during the time horizon of this study. The existing and planned future gener- ating capacity in the 'Railbelt region is capable of operating at a capacity factor either equal to or greater than 50%. Because of this, the decision to add new capacity will usually be based on the need for capacity (kW) rather than energy (kWh). Thus in this analysis capacity additions are scheduled based on peak loads rather than upon average annual energy. The general approach to load/resource analysis is to summarize existing and planned gross resources for each year, adjust them downward for a reliabil- ity margin and for system transmission losses to arrive at net resources. If these net resources exceed the critical period load for the year being analyzed, plant additions are not called up and the analysis proceeds to the next year and is repeated. At some point, the net resources will not meet the forecasted peak loads and additional capacity must be added. Also, for each year, the energy generated by each class of plants (e.g., hydro, steam turgine, combus- tion turbine, and diesel is computed so that plant utilization factors are available for review and system energy costs can be developed. The stepwise calculations are continued to the end of the period being studies (2010). 3.2 ASSUMPTIONS 3.2.1 Forecasted Power and Energy Requirements The analyses are based on forecasts prepared by the Alaska Power Adminis- tration for both the Anchorage -Cook Inlet and the Fairbanks -Tanana Valley areas. Probable high and low bounds were provided along with median forecasts. These are presented in Tables 3.1 through 3.3 and are shown graphically in Figures 3.1 through 3.3. In addition to utility loads, Anchorage -Cook Inlet forecasts include both national defense and industrial loads and the Fairbanks -Tanana Valley forecasts include national defense loads. M. TABLE 3.1. Anchorage -Cook Inlet Area Power and Energy Requirements 19771� 1980 1985 1990 1995 2000 2025 MW - MW MW MW MW MW MW UTILITY High 620 1,000 1,515 2,150 3,180 7,240 Median 424 570 810 1,115 1,500 2,045 3,370 Low 525 650 820 1,040 1,320 1,520 NATIONAL DEFENSE High 31 32 34 36 38 48 Median 41 30 30 30 30 30 30 Low 29 28 26 24 24 18 INDUSTRIAL High 32 344 399 541 683 1,615 Median 25 32 64 119 199 278 660 Low 27 59 70 87 104 250 TOTAL High 683 1,376 1,948 2,727 3,901 8,903 Median 490 632 904 1,264 1,729 2,353 4,060 Low 581 737 916 1,151 1,448 1,788 ANNUAL ENERGY UTILITY GWJ/ GWh GWh GWh GWh GWh GWh High 2,720 4,390 6,630 9,430 13,920 31,700. Median 1,790 2,500 3,530 4,880 6,570 8,960 14,750 Low 2,300 2,840 3,590 4,560 5,770 6,670 NATIONAL DEFENSE High 135 142 149 157 165 211 Median 131 131 131 131 131 131 131 Low 127 121 115 105 104 81 INDUSTRIAL High 170 1,810 2,100 2,840 3,590 8,490 Median 70 170 340 630 1,050 1,460 3,470 Low 141 312 370 460 550 1,310 TOTAL ' High 3,025 6,342 8,879 12,427 17,675 40,401 Median 1,991 2,801 4,001 5,641 7,751 10,551 18,351 Low 2,568 3,273 4,075 5,125 6,424 8,061 1/ MW = Megawatts GWh = Gigawatt-hours (Equivalent to MMkWh = Millions of kilowatt-hours) Source: Alaska Power Administration, October 1978 4 TABLE 3.2. Fairbanks -Tanana Valley Area Power and Energy Requirements 1977 / 1980 1985 19'90 1995 2000 2025 MW MW MW MW MW MW P'111! UTILITY High 158 244 358 495 685 1,443 Median 119 150 211 281 358 452 689 Low 142 180 219 258 297 329 NATIONAL DEFENSE High 49 51 54 56 59 76 Median 41 47 47 47 47 47 47 Low 46 44 42 40 38 29 TOTAL High 207 295 412 551 744 1,512 Median 160 197 258 328 405 499 736 Low 188 224 261 298 335 358 ANNUAL ENERGY GWhl/ GWh GWh GWh GWh GWh GWh UTILITY High 690 1,070 1,570 2,170 3,000 6,320 Median 483 655 925 1,230 1,570 1,980 3,020 Low 620 790 960 1,130 1,300 1,440 NATIONAL DEFENSE` High 213 224 235 247 260 333 Median 207 207 207 207 207 207 207 Low 203 193 184 175 166 129 TOTAL High 903 1,294 1,805 2,417 3,260 6,653 Median 690 862 1,132 1,437 1,777 2,187 3,227 Low 823 983 1,144 1,305 1,466 1,569 l/ MW = Megawatts GWh = Gigawatt-hours (Equivalent to MMkWh = Millions of kilowatt-hours) Source: Alaska Power Administration, October 1978 10 TABLE 3.3. Total Power Requirements;`Anchorage-Cook Inlet Area and Fairbanks -Tanana Valley Area Combined 19771/ 1980 1985 1990 1995 2000 2025 MW - MW MW MW MW MW MW TOTAL High 890 1,671 2,360 3,278 4,645 10,422 Median 650 829 1,162 1,592 2,134 2,852 4,796 Low 769 961 1,177 1,449 1,783 2,146 ANNUAL ENERGY GWh1/ GWh GWh GWh GWh GWh GWh TOTAL High 3,928 7,636 10,684 14,844 20,935 47,054 Median 2,681 3,663 5,133 7,078 9,528 12,738 21,578 Low 3,391 4,256 5,219 6,430 7,890 9,630 i/ MW = Megawatts GWh = Gigawatt-hours (Equivalent to MMkWh = Millions of kilowatt-hours) Source: Alaska Power Administration, October 1978 6000 5000 4000 3000 2000 w 1000 900 0 800 700 W 600 500 400 300 200 100, ANCHORAGE -COOK INLET AREA ®/H I GH MED I LIM LOW HIGH MEDIUM LOW FA RBANKS-TANANA VALLEY AREA 1980 1985 1990 1995 2000 2005 FIGURE 3.1. Railbelt Region Peak Loads 2010 12 20,000 0 0 J z 10,000 0 9000 8000 } 7000 c� 6000 5000 z 4000 z 3000 2000 HIGH MED I UM LOW 1980 1985 1990 1995 2000 2005 FIGURE 3.2. Anchorage -Cook Inlet Area Annual Energy 13 6000 5000 4000 3000 20M o 0 J 1000 900 800 700 600 500 400 z U M HIGH MED I UM LOW 1980 1985 1990 1995 2000 2005 2010' FIGURE 3.3. Fairbanks Area Annual Energy 14 The Alaska Power Administration data indicate that approximately 80/0 of the Railbelt region loads are expected to be in the Anchorage -Cook Inlet area. These loads have been interpreted as recognizing distribution losses. 3.2.2 Existing and Planned Generating Capacity The existing stock of generating capacity for the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area is presented in Tables 3.4 and 3.5, respectively. The total existing capacities and maximum plant utilization factors for the various generating types for the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area are shown in Tables 3.6 and 3.7, respectively. The load/resource matching analyses use these totals for the first year of the analyses (1978-1979). Generating capacity additions can be specified to be added in one of two ways. It can either be added in a specified year or can be added when it is required to maintain adequate generating capacity. In the former case the generating units are added whether they are required or not. The planned addi- tions shown in Table 3.8 are brought on line in the years specified. National defense generating units are assumed to be replaced by steam turbine generating units the same year as they are retired. (See Section 3.2.7 for a discussion of the units added as required to maintain adequate generating capacity.) 3.2.3 Reserve Margin Utility systems invariably carry a reserve margin of generating and trans- mission capacity as insurance against loss of load, unexpected peak require- ments as a result of severe weather, load growths more rapid than anticipated, adverse hydroelectric conditions, and delays in the commercial operation of new generation. The most appropriate reserve margin will vary from system to system depending on the nature of the loads and types of resources and special factors. Typically, a reserve capacity at peak of 20011 is used nationally. However, this can vary to as low as 12% as is the present case for the Pacific Northwest with its predominance of reliable hydropower and interruptable loads. 15 TABLE 3.4. Existing (Fall 1978) Generating Capacities for Anchorage -Cook Inlet Area Type of Capacity Retirement Unit Reference/Name Location Generation _ kW Year ANCHORAGE MUNICIPAL LIGHT AND POWER (AML&P) Deisel Anchorage Diesel 2,200 1982 Unit 1 Anchorage S.C.C.T.* 15,130 1982 Unit 2 Anchorage S.C.C.T. 15,130 1984 Unit 3 Anchorage S.C.C.T. 18,650 1988 Unit 4 Anchorage S.C.C.T. 31,700 1992 Unit 5 Anchorage S.C.C.T. 36,000 1995 Unit 6 Anchorage C.C. 16,500 1995 Subtotal 137,500(a) CHUGACH ELECTRIC ASSOCIATION (CEA) Bel uga Unit 1 Beluga S.C.C.T. 33,000 1988 Unit 2 Beluga S.C.C.T. Unit 3 Beluga R.C.C.T.* 54,600 1993 Unit 4 Beluga S.C.C.T. 9,300 1996 Unit 5 Beluga R.C.C.T. 65,000 1995 Unit 6 Beluga S.C.C.T. 67,810 1996 Unit 7 Beluga S.C.C.T. 68,000(e) 1996 Unit 8 Beluga C.C. 32,200 1996 Bernice Lake Unit 1 Bernice Lake S.C.C.T. 8,370 1983 Unit 2 Bernice Lake S.C.C.T. 17,860 1992 Unit 3 Bernice Lake S.C.C.T. 18,000 1998 Cooper Lake Cooper Lake Hydro 16,500 NA International Unit 1 S.C.C.T. 30,510 1985 Unit 2 S.C.C.T. Unit 3 S.C.C.T. 18,140 1991 Knik Arm Combined S.T.* 10,000(f) 1987 Subtotal 449,790 MATANUSKA ELECTRIC ASSOCIATION (MEA) Talkeetna Talkeetna Diesel 600(b) 1993 HOMER ELECTRIC ASSOCIATION (HEA) English Bay English Bay Diesel 100 1993 Homer & Kenaie Combined Homer Diesel 300(c) 1993 Homer Combined Homer S.C.C.T. 7,000(d) 1995 Port Graham Combined Port Graham Diesel 200 1993 16 TABLE 3.4. (contd) Type of Capacity Unit Reference/Name Location Generation__(kW) HOMER ELECTRIC ASSOCIATION (HEA) (contd) Seldovia Combined Seldovia Diesel 11500 Subtotal 9,100 SEWARD ELECTRIC SYSTEM (SES) Seward Combined Seward Diesel 3,000(6) 2,500 Subtotal 51500 ALASKA POWER ADMINISTRATION (APA) Eklutna Eklutna Hydro 30,000 Subtotal 30,000 NATIONAL DEFENSE Ft. Richardson/ - S.T. 40,500 Emendorf - Diesel 7,300 - Diesel 2,000 Subtotal 49,800 INDUSTRIAL Kenai - S.C.C.T. 12,300(g) TOTAL 685,290 Retirement Year 1980 1985 1996 NA 1991 1985 1991 1988 * S.C.C.T. - Simple Cycle Combustion Turbine R.C.C.T. Regenerative Cycle Combustion Turbine S.T. - Steam Turbine C.C. - Combined Cycle (a) Capacities for individual units are from sources 1 and 2. These sum to 118,810 kW. Total shown is from source 2. (b) Standby (c) Leased to CEA (d) Leased to HEA by Golden Valley Electric Association for 1977-1979. (e) Included in this study, but late 1978 plans are to defer Betuga 8 until 1980 and double the capacity. (f) Nameplate capacity derated to 10,000 KW from 14,500 KW. (g) Recent data shows industrial load to be 25,000 KW rather than 12,300 KW. SOURCES: I. Electric Power in Alaska, 1976-1995, ISER, University of Alaska, pp. J.5.2-7.4, August 1976. 2. Alaska Electric Power Statistics 1960-1976, Alaska Power Administra- tion, pp. 15-17, July 1977. 3. 1976 Power System Study, Chugach Electric Association, Inc., Tippett and Gee, Dallas, TX, p. 7, March 1976. 4. Alaska Power Administration, August 1978. 17 TABLE 3.5. Existing (Fall 1978) Generating Capacities for Fairbanks -Tanana Valley Area Unit Reference Type Capacity Year of Name Location Generation kW Retirement FAIRBANKS MUNICIPAL UTILITIES SYSTEM (FMUS) Chena 2 Fairbanks S.T. 2,000 1988 Chena 3 Fairbanks S.T. 11500 1988 Chena 1 Fairbanks S.T. 5,000 1988 Chena 4 Fairbanks S.C.C.T. 5,350 1983 Diesel 1 Fairbanks Diesel 2,664 1988 Diesel 2 Fairbanks Diesel 2,665 1988 Diesel 3 Fairbanks Diesel 2,665 1988 Chena 5 Fairbanks S.T. 20,000 2005 Chena 6 Fairbanks S.C.C.T. 23,500 1996 Subtotal 65,345 GOLDEN VALLEY ELECTRIC ASSOCIATION (GVEA - Fairbanks Diesel 24,000 1984 ,Healy 11 Healy S.T. 25,000 2002 - Fairbanks S.C.C.T. 40,000 1992 - Delta Diesel 500 1988 North Pole #1 North Pole S.C.C.T. 70,000 1997 North Pole #2 North Pole S.C.C.T. 70,000 1997 Subtotal 229,500 NATIONAL DEFENSE Combined - Diesel 14,000 1988 Clear A.F.B. and Ft. Greely - S.T. 24,500 1995 Ft. Wainwright and Eilson A.F.B. - S.T. 32,000(a) 1990 Subtotal 70,500 (a) 5 MW plant at Eilson A.F.B. installed in 1970 and old 1.5 MW plant at Ft. Wainwright were inadvertantly omitted. SOURCE: 1. Interior Alaska Energy Analysis Team, Final Report, June 1977. 2. Alaska Power Administration, August 1978. TABLE 3.6. Anchorage -Cook Inlet Area Existing Capacity and Maximum Annual Plant Utilization (October 1978) Plant Capacity Utilization MW (%) Hydro 46.5 50.0 Steam Electric 50.5 75.0 Combustion Turbine 575.01 50.0 Diesel 19.13 15.0 TABLE 3.7. Fairbanks -Tanana Valley Area Existing Capacity and Maximum Annual Plant Utilization (October 1978) Plant Capacity Utilization MW) W Hydro 0 50.0 Steam Electric 110 75.0 Combustion Turbine 208.9 50.0 Diesel 46 10.0 19 TABLE 3.8. Planned Additions for Railbelt Region (1979-1995) Unit Reference/ Year of Type of Name Installation Location Generation ANCHORAGE MUNICIPAL LIGHT AND POWER (AML&P) Unit 7 1979 Anchorage S.C.C.T. Unit 6 1979 Anchorage C.C. Beluga #9 X-1 Bernice Lake #4 X-2 Bernice Lake #5 Healy #2 Bradley Lake CHUGACH ELECTRIC ASSOCIATION (CEA 1979 Beluga C.C. 1980 S.C.C.T. 1981 Bernice Lake S.C.C.T. 1982 S.C.C.T. 1984 Bernice Lake S.C.C.T. GOLDEN VALLEY ELECTRIC ASSOCIATION (GVEA) As Required Healy S.T. ALASKA POWER ADMINISTRATION (APA) 1985 Bradley Lake Hydro Capacity kW 65,000(a) 16,500(6) 32,200(c) .100,000 18,000 100,000 18,000 100,000 70,000 NATIONAL DEFENSE 1985 Ft. Richardson and Emendorf A.F.G. S.T. 7,300 1988 Fairbanks Combined S.T. 14,000 1990 Ft. Greely and Clear A.F.B. S.T. 32,000 1991 Ft. Richardson and Emendorf A.F.B. S.T. 42,500 1995 Ft. Greely and Clean A.F.B. S.T. 24,500 (a) Unit 17 is a simple cycle combustion turbine unit which also supplies exhaust heat to Unit #6. (b) This increase reflects the increase in capacity resulting from the addition of Unit V. (c) Beluga #9 is a steam unit addition to Beluga 7#7 (converts these to a 100 MW combined cycle unit). S: . 1976 Power System Study, Chugach Electric Association, Inc., Tippett and Gee, Uallas, TX, pp. 7 and 25, March 1976. 2. Electric Power in Alaska, 1976-1995, ISER, University of Alaska, pp. J.5.2-7.4, August 1976. 3. Alaska Power Administration, August 1978. 20 Since a reserve margin effectively increases the amount of generating capacity in place at any given time, it does contribute costs to the system. Therefore, an excessive reserve margin is to be avoided while at the same time recognizing that an inadequate reserve margin could, on outage, result in a wide variety of social costs. For the purposes of this study, the Alaska Power Administration has suggested that the analysis be based on reserve margins of 250/0' and 20% for non interconnected load centers and the interconnected systems, respectively. In the future, a more refined analysis of the desired reserve margin appears warranted. 3.2.4 Transmission Losses Transmission losses must be added to forecasts of peak and energy loads to establish net capacity and energy at the plant substations. The Alaska Power Administration expects losses as follows: Capacity 5 Energy 1.5 The results of the load/resource analysis are thus in net deliverable capacity and energy and do not include energy and capacity required for internal plant operations. The above losses are reasonably applicable for the independent operation of the load centers, for interconnected systems including the Upper Susitna project and for configurations with future generation capacity additions being distributed proportionally near the load centers. In the case of interconnec- tion without Upper Susitna and with a tendency to centralize Railbelt thermal generation, the transmission losses may be considerably higher as discussed later in Section 3.2.8. 3.2.5 Construction Schedule Constraints Due to the lead times necessary for the permit processes and construction, generating unit and site selection must take place a number of years in advance 21 of the forecasted date when the units commercial operation will be required. For coal-fired thermal plants, the Pacific Northwest Utilities Conference Committee estimates a 62 month (5.2 years) period from final site selection to commercial operation for plants in the 500 MW and higher range based on recent U.S. experience. Although individual thermal plant capacities appropriate to Alaska's loads are somewhat smaller and may require less field erection work, the construction season is shorter and the 5 to 6 year scheduling period appears reasonable. For the potential Upper Susitna hydroelectric projects, the scale of effort is more demanding and increased site evaluation is necessary. Current understanding is that the Watana Dam and power plant could be brought to commer- cial operation by 1994, followed by Devil Canyon no sooner than 1998.. A transmission interconnection between Anchorage -Cook Inlet and Fairbanks - Tanana -Valley could be brought into service prior to completion of Watana, possibly as early as 1986. The load/resource analysis technology recognizes the above schedule con- straints by not allowing callup of new generation or transmission capacity that could not be made available. 3.2.6 Plant Availability Constraints Generating and transmission plant availability can be expressed in terms of maximum and minimum plant utilization factors (PUF). These factors are primarily dependent upon plant type and plant age. For purposes of this analy- sis we have assumed the following economic facility lifetimes after which the facility is retired from service-(l) Years Coal -Fired Thermal Generation 35 Oil -Fired Steam Generation 35 Gas -Fired Combustion Turbine 20 Oil -Fired Combustion Turbine 20 Hydroelectric Generation 50 (1) See Tables 3.4 and 3.5 for dates of expected retirements for existing systems. 2^ Due to the nature of the system, some plants could be retired from service prior to the expiration of their economic life. In actual practice, however, it is expected that utilities may elect to retain the units on standby. In order to assure their availability in emergencies, the utilities will periodi- cally operate the units to make sure they are in working condition. Experience has shown that large thermal plants experience a learning curve during the first few years of operation as "bugs" are worked out. Once past e this period they reach a maximum that allows for scheduled maintenance and replacement conducted during the off-peak season. Toward the end of the economic life, increased frequency and duration of outages for maintenance usually occur and the maximum plant utilization factor declines. For purposes of this analysis, we have assumed constraints on the maximum PUF for new coal- fired steam electric plants as shown in Figure 3.4. M 70 60 c 0 U 50 z 0 ¢ 40 IV r.+ J .-e H 0 30 z a 2'0 ilk 0 e 0 5 10 15 20 25 30 35 PLANT AGE (YEARS) FIGURE 3.4. Plant Utilization Factor versus Plant Age 23 Other types of generating capacity are allowed to run at their maximum PUF from the start. For new capacity and most types of existing capacity, the following maximum PUFs are assumed: Maximum Plant Utilization (%) Hydro 50.0 Steam Electric 75.0 Combustion Turbine 50.0 Diesel 10.0 Hydroelectric generation systems, as a result of their storage ability and conservative ratings, can make additional power available for peaking and it is assumed they can be scheduled at 115% of design capacity for this service. As pointed out earlier in Section 3.1, the peak demand during the winter usually determines the amount of generating capacity required rather than the annual energy. Because of this, some generating units are utilized at less than their maximum annual plant utilization factors. The decision as to which units should not be loaded is usually based on the margin cost of operating the facilities. In this analysis it is assumed that diesel capacity has the highest margin operating cost followed by combustion turbines, steam turbines and hydroelectric capacity in that order. It is assumed that diesel PUFs can be reduced to 0.0 while the PUFs for combustion turbine and steam electric capacity is not allowed to go below 10%. Transmission plant availability is generally not as schedule constrained as are generating plants with their long lead times. For purposes of these analyses, the interconnection between the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area will be provided 3 years before the completion of the Watana dam or when the Healy 1 (existing 25 MW) and Healy 2 (planned 100 MW net) plants become fully loaded, whichever occurs first. (2) This assumption in effect places oil -fired plants serving the area on standby after that date. •(2) It will probably be desirable to provide at least a portion of the inter- connection prior to Watana date on-line as a source of power for construction. 24 3.2.7 Economic Generating Unit Size The selection of optimum generating size can be a complex process involv- ing uncertain assumptions regarding probability of future load growth paths, desirability of sizing individual units in comparable sizes and types for each of maintenance, assuring that system reliability is not penalized by addition of too large a single unit,'smoothing of construction schedules for possible multiunit plants, and maintaining as small as possible departure from the desired reliability margin. A full optimization does not appear warranted at this stage and is beyond the scope of this analysis. Thus for the purposes of this study, the first six coal-fired steam electric plants in the Fairbanks -Tanana Valley area are assumed to be 100 MW units. Any additional units are assumed to be 200 MW units. In the Anchorage - Cook Inlet area the first five coal-fired steam electric plants are assumed to be 200 MW units, while any additional plants are assumed to be 400 MW units. These.size ranges, though probably not exact optimums, appear reasonable block sizes for introduction and typically become fully loaded at about 10% of plant life. 3.3 SYSTEM CONFIGURATIONS: DEFINITION OF CASES ANALYZED 3.3.1 Case 1: Without Interconnection and Without Upper Susitna Project The base case consists of power supply to the Anchorage -Cook Inlet and Fairbanks -Tanana Valley on a noninterconnected basis. in this instance, no power is available from the Upper Susitna project. Future capacity additions for the Anchorage -Cook Inlet load center are assumed to be near -mine -mouth coal-fired units located on the west side of Cook Inlet with a nominal 50-mile transmission distance using two 345 kV circuits with a capacity of 1500 MW. Capital cost of this transmission system is $228 million in October 1978.prices. Further capacity additions for the Fairbanks -Tanana Valley load center are assumed to be coal-fired units with a nominal 100-mile transmission distance. ® The Healy site is used as a proxy recognizing, however, that the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act may preclude 25 the siting of additional plants beyond the planned Healy 2 100 MW unit. A 230 kV single circuit will transmit up to 400 MW and a 230 kV double circuit, 800 MW. Capital costs are $44 million and $70 million, respectively. Table 3.9 provides a summary of the transmission system alternatives. A map of the Railbelt region showing the Watana and Devil Canyon dam sites, a possible route for the interconnection, and the Beluga area*is presented in Figure 3.5. 3.3.2 Case 2: With Interconnection, Without Upper Susitna Project In the case of an interconnected system without the Upper Susitna project and all new capacity coal fired, the load/resource analysis is not as straight- forward in that it is not readily apparent what strategy for siting plants should be followed. Two primary options are apparent: 1. All coal plants sited at a single location(') (Concentrated Siting). Advantages a) Lower capital and operating costs for generation. b) Economies of scale can be achieved. c) Siting problems in the interior may be avoided. Disadvanta es a) Higher transmission losses (and costs) are incurred for the fraction of Power flowing to the Fairbanks -Tanana Valley load center. These costs may cancel out savings from the advantages. b) The latter area becomes strongly dependent upon reliability of the transmission system --possibly to the point of requiring a second cir cuit or maintenance of additional standby combustion turbine capacity. c) Any adverse environmental effects are borne by a single area not neces sarily benefiting in proportion. 2. Coal Plants Sited in Proportion to Relative Load Growth (Distributed ° Siting).. (1) For the purposes of this analysis, mine -mouth location at Beluga is used as a proxy. 26 YI 4-) rL X 4) 84 O � i -P I CL N CL (3) V <L > N � O �•-� U a U N ^ RS N rL+ O N U O •r -1-I � a 41 r 3 r ct:I Q O_ n3 c U O .f..1 N a 0 N }� N ,•r- •r � � U N i � •r � U i Cn M LLJ J n O CO LnN LnN r CO b d' CO C• r cV r CV r c7- O cY CO a N GV r r N CV tO CD N M N M O O O O O O cI CO cY co co ko r O QJ 4J •r G1 � G7 C O } •''• O •r Y N V) Y Y Y c'M O O Ln O M M 3 N N M f— 27 M LO O r� 01) N r� O Q1 N CV U *: cl- N 03 Co CO Co O CO N N (� N N c1 to co M LO Ln 3 co O b r i 0 N Z 00 00 M 4) O O O lO n N M c1- L-7 LO cm o� lS•) r 0 IT M+ O O 4J Cn Cn O 1 Y r- +' O O Ln tt3 U M Z N N •f-•7 � r a cc .-7 (a •ram O G� r N 4-J r O •i- i cC cn N 4J > 3 cc -N cn O -� a ? 4J N (n CL 3 r cc I •r O r Y 4J Q1 •r Q) U) O U (Z O U (31 Z N (u 4) r O U O O +1 U O U O U Z c[ Z Cn C) 4) +) 4-) O O I r N FIGURE 3.5. Railbelt Region Showing the Watana and Devil Canyon Damsites, a Possible Route for the Interconnection, and the Beluga Area Advantages a) The interconnection becomes lightly loaded, thus reducing transmission losses to some degree although charging losses would continue. b) Transmission interconnection reliability dependence is reduced as the intertie assumes more of a capacity reserve characteristic. c) Environmental burdens are distributed, possibly with more equity. Disadvantages a) Possible economies of scale are lost. b) Generation costs in the Fairbanks -Tanana -Valley are increased. c) Siting problems related to meteorological considerations may result in the latter area. In this report coal plants are assumed to be sited in proportion to the relative load growths of the two load centers. As with Case 1, additional. coal-fired generating units are sited at Beluga to serve the Anchorage -Cook Inlet area and at Healy/Nenana to serve the Fairbanks -Tanana Valley areas. The transmission interconnection is used for capacity reserve allowing the reserve margin for both load centers to be reduced from 25% to 20% see Section 3.2.3). Under this scenario there is no net energy transfer during any single year. If one load center is low on capacity the other load center provides the additional capacity required assuming it has a surplus. If no surplus exists the original load center must add capacity. The interconnection is assumed to be brought on line in the same year as the Healy 2 coal plant becomes fully loaded and new generating capacity would be required in the Fairbanks -Tanana Valley area. Addition of the interconnec- tion allows the Fairbanks -Tanana Valley area to get capacity reserve from the Anchorage -Cook Inlet Area. This allows the Fairbanks area to postpone the construction of additional capacity by 2 to 6 years depending upon the scenario. In the high load growth case the interconnection would be completed in 1986, in the medium load growth case it would come on line in 1989, and in the low load growth case it would comp on line in 1994. In all cases 45'/' of the cost of the interconnection is assigned to the Fairbanks -Tanana Valley load center. 29 3.3.3 Case 3: Interconnected System With Upper Susitna Project In addition to the interconnection described in the previous section, Case 3 includes two hydroelectric generating facilities. The Watana dam is scheduled to come on line in 1994. The date is assumed to be the same for all three load growth scenarios. The Devil Canyon dam is assumed to come on line as soon as required following 1994 but not before 1998. It is assumed i-t would take at least 4 years to complete the Devil Canyon dam following comple- tion of the Watana dam. It turns out that the Devil Canyon dam is required in 1998 in the medium of high load growth scenarios but not until 1999 in the low load growth scenario. Because of reservoir filling requirements it is assumed that both dams will take 2 years to reach full capacity and power output. The capacities, power production and plant utilization factors for the two dams are show below. Watana Capacity Energy Utilization Year (MW) (MMkWh 1 7a3 3080 50.0 2+ 795 3480 50.0 Devil Canyon 1 689 3020 50.0 2+ 778 3410 50.0 For the medium and high load growth the transmission interconnection is assumed to come on line in 1989 and 1986 respectively; the same years as for Case 2. In the low load growth -scenario the interconnection comes on line in 1991 rather than 1994. This earlier completion date will allow the Watana dam construction site to be supplied with power from either the Anchorage -Cook Inlet area or the Fairbanks -Tanana Valley area. The power output of the two dams is divided between the two load centers in proportion to their relative energy consumption in 1994. This results in the percentage divisions shown below. 30 Load Growth Anchorage- Fairbanks - Scenario Cook Inlet Tanana Valley Low 80% 20% Medium 81% 19% Nigh 84% 16% 3.4 RESULTS OF LOAD/RESOURCE ANALYSES Using the methodology outlined in Section 3.1 and the assumptions explained in Section 3.2, a series of load/resource analyses were performed. As pointed out earlier, three basic cases were evaluated: Case 1 All additional generating capacity beyond utility plans assumed to be coal-fired steam turbines without a transmission interconnection between the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area load centers. Case 2 All additional generating capacity beyond utility plans assumed to be coal-fired steam turbines including a transmission interconnection. Case 3 All additional generating capacity beyond utility plans assumed to be coal-fired steam turbines but including the Upper Susitna project (including a transmission intertie) coming on line in 1994. For each of these three cases. Three load growth scenarios (low, medium and high) are evaluated resulting in a total of nine load/resource.analyses. The assumptions discussed in this chapter are incorporated in a computer model called AEPMOO. The output of AEPMOD for Case a assuming the medium load growth scenario is presented in Table 3.10. The results of all nine cases are presented in Appendix C. The AEPMOD computer code is presented in Appendix B and the data base necessary to make the runs is presented in Appendix A. The capacity additions called up in the various cases are presented in Tables-3.11, 3.12 and 3.13. The results of the runs are summarized in Figures 3.6 through 3.11. 31 TABLE 3.10. Load/Resource Balance for Case 3: Medium Load Growth Scenario ARFA: AmCHOkAbE ANCHUgAbE CASE: 2 •- MEDIUM LUAO Gkuw1H INIEHTIE YEAR: 1990 ' NUTES:OEC. b. 1976 ;/ U.S.-1994. •-----------------------------• C R I T I C A L P E R I U 0 / 19/8-1979 ----------- / ----1-b-0--------------------------------------- 1979-19b0 / 1980-1981 / PEAK MPOF APUF ENERGY / PEAK MPOF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- ------------ /-----• ---- ---- -------- /•----- ---- ---- -------- --------------- / REUUIREME.*vTS / 585. 2531. / 632. 2801. / 686. 3041. ---------------/ kESOUHGES £XIbTING MYUku / 53. .50 .50 204. / 53. .50 .50 204. / 53. .50 . 50 204 61EAM/ELEC / 51. .75 .75 332. / 51. .75 .75 332. / 51.. .75 .75 332., COMB.TUAbINE / 579.. .50 .40 2034. / 575. .50 .36 1610. / 689. .50 .35 2113. DIESEL / 19. .15 .00 U. / 19. .15 .00 0. 1 14. .15 .00 U, TOTAL / 698. 2569. / 696. 2346. / 812. 2b49, AU0II10145 STEAM/ELEC- Comm.TUFMINE / - - -- - / 114. .50 .50 497. / 100. ,50 .50 438. UltSF_L- kLTIREMEi1TS MTU»O / . - • - / - - / - . - . STEA•e/ELEC- 00-5.TUKdLNE- U1tSEL / - - - - / - - - - / 2. .00 .00 0. ---------------/ 4ROSS RESOURCES/ 698. 2569../ 812- 2343. / 910. 3087. CAP RES. MARGIN/ 0.193 /.0.284 / 0.326 kESERVE RED. / 146.. / 156. / 172. L0534S / 29. 38. / 32. 42. / 34. 46. NET KESOURCES / 523. 2531. / h22. 2801. / 704. 3041. TRANSFERED / 0. / 0. / 0. SURPLUS / -62. 0. / -10.- 0. / 18. 0. PEAK -- PEAK LOAO/GENERATING CAPACITY RE(JUIREMENTS(MEGANATTS) MP1JF -- MAXIMUM PLANT UTILIZATION FACTOR APUF -- ACTUAL PLAN1 uTIL1ZATION FACTOR ENERGY •- GENERATION/ANNUAL E14ENGY REOUIHkMENTS(MILLIONS OF KILUAATT-MUURS) 32 TABLE 3.10. (contd) Axt A: F4.100ANKS FAIRB ANKS CASE: 2 -- MEDIUM LUAU GROWTH IwTENIIE YEAR: 1990. ` NOTES:UtC. o. 1978 n/ U.S.-1494. ------------------------------------------------------------------------------------------ C R I T I C A L P E R I 0 0 / 19/4-1979 / 1979-196U / 19d0-1981 / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- ---- -------- /------ ---- ---- eEuij.'RE-ENlS / 184. 604. / 197. 862. / 209. 916. ---------------/ J / NEsnUACE3 EXI:iTI^.6 HYURO / fi.. .50 .50 0. / 0. .50 .50 0. / 0. .50. .50 0. STEAD•-/ELEC / 110. .75 .bb 633. J 110. .7S .72 692. / 110.. .7S .7S 723. COMo.TURbINE./ 209.. .50 .10 183.. / 209.. .50 ..10 183.. / 209. .50 .11 207. UItSEL / 40. .10 .00 0. / 46. .10 .Uo 0. / 46. .10 .00 0. J / / TOTAL / 365. 816. / 365. 875. / 365. 93U. AUDITIONS U1t5EL wET1AEMENTS K Y u R it / _ _ - _. / - . _ _ / ,. _ ►. _ STEA:d/ELEC- CD,o. TUH7INE DIESEL ---------------/ 6Ru5S kE50;)NCES/ 3b5- 816.. / 365... 875.. / 36!) 930. CAP KES. rARGINI 0.9n3 / U.8S2 / 0.746 RE5E-i4E R£9. / 46. / 49. / 52. LUSS�.S / 4. 12. / 10. is., 10. 114. NET kF_SOURCES / 310. 804. / 306. 862. ! 302. 916. SUxPLuS / 126. 0. / 109. 0. / 93. 0. PEAK -- PEAK LOAD/GENERAI1NG CAPACITY HEOUIREMENTS(MEGA YIATTS) MPUF -- MAXIMUM PLANT UTILIZATION FACTOR - AhUF -- ACTUAL PLANT UTILIZATION FACTOx ENERGY -- GENtRATION/ANNUAL ENERGY kEuuIREMENTS(MILLIONS OF KILOWATT -"OURS) 33 TABLE 3.10. (contd) AkFA: ANCnUnAi.E APICAnkAGF CAtit: 2 •• MEDIUM LOAD rkOWTM IVTEkrIL YEAR: 1990. NOTES:OEC. b, 1978 l/ U.S.-1994. -••.-•••.••••-.•••••••••.••••••--•--••-•-.•--.•••-•-•-.-------•----•-•---•••.••---------- C R I T I C A L P E k I U U / / 19d2.1983 / 19d3-19d•1 r / PEAK MPUF APUF ENERGY / PEAK MPl1F APUF ENERGY / PEAK MPUF APUF E14ERGY 1�, /------ ---- ---- -------- /------ ---- ---- -------- /••---- ---- ---- -------- .(�. KEUu1PE•IEr+T-3 / 741. 3481. / 795. 3521. / 850. 3761< kEbOu2CF_5 EX13TIIjr, / MYURO / 53. .SO .50 204. / 53. .50 .50 204. / 53. .50 .50 204-., STEAM-IELEC / 51. .75 .75 332. / 51. .75 .75 332. / 251. .75 .42 923. CUM8.10RUINE / 789. .50 .S9 271b. / 607. .50 .S2 2250. / dyl. .50 .35 2041. DIESEL / 11. .15 .00 U. / 17. .15 .00 0. / 15. .15 .00 0. / a TUrAL / 910. 3251. / 948. 2/85. / 1210. 3d17. A00I7I0.45 MYukrl / - - - - / - - 5TEA.4/FLEC / - - - - / 200. .75 .20 350. / - - - •. Cord.ruRy1;JE / id. .50 .50 79. / 100. .50 .5,0 438.- ulkSEI RETIREMENTS STEAM/ELEC CUMH.TURnINE / - - / 15. .00 .00 0. / d. .00 .00 0- UIESEL / - - - / 2.. .00 .00 0. / - - - 6kUSS RESOURCES/ 928. 333U. / '1210.. 3574. / 1202. 3811. CAP kES. MARGIN/ 0.252 / 0.523 / 0.414 kESERVE kEu. / IMS. / 199., / 213. LliSSES / 31. 49. / 40. 53. / 43. $o. NET RESOURCES / 706. 328i. / 972. 3521. / 947. 37b1. rRAN5FEHEb / -tl.,, / 0. / 0. SuNPLUS / -35. 0.. / 177. 0. / 91. U. r PEAK -- PEAK LOAD/GENERATING CAPACITY REUUINEMENTSCMEGAWATTS) MPUF •- MAXIMUM PLANT UTILIZAtION FACTOk APUF •- ACTUAL PLANT UTILIZATION FACruk ENERGY -- GENERATION/ANNUAL ENERGY kEUUIREMENrS(MILLI UNS OF KILOWATT-MUURS) m TABLE 3.10. (contd) AWEA: FAIkBANKS FAIknANKS CASt: 2 -- MEDIUM LUAU GR1fWIN INTERTIt YEAk: 1990. . NOTES:UEC, b, 19/6 n/ U.S.-1994. C k 1 T I C A L P E k I U 0 ------- ----------------------------------------.---------------_------------------------- / 19bl-1982 / 1982-1983 / 1963-1984 / PEAK MPUF APUF ENEkGY / PEAK MPUF APUF ENERGY ! PEAK MPUF APUF ENEKGY /------ ---- ---- -------- /------ ---- ---- -------- /------ ---- ---- --------.. ---------------/ Kt-:fi1REMLNtS / 27.1. 970. / 233. 1024. / 245. 1078. _ ---------------/ ktSuURCES EaISTI;:G MYuRO / 0. .50 .SU U. / U. .50 .50 0../ u. ,9U .50 0. STEAM/tLEC / 110. .75 .75 723. ! 110. .75 ..75 723. / 11u. .75 .75 723. COM9.TUP.bINE 1 209. .50 - .14 262. / 209. .50 .17 317. / 209. .50 .21 571. . OIESSL / ab. .10 -100 0. / 46. .10, .00 0. / 46. .10 .00 U. / 1 / TOTAL / 365. 98!3 / 365. 1039. / 365. 10,44.. AUDIT(ONS iTEA�t/FLFC vltSEL PETIRE:-ENTS 5TE+y/ELEC - - - CG•4d.Tl),4nINE / - - - - / - - - - / 5. .00 ,00 0. ufESEL --------- ----/ 6RUSS RESOUWCES/ 365.. 985../ 365.. 103%../ 360., 1094. CAP k£S. MARGIN/ 0.65E / 0.566 /-0.467 kESEKVE kEO. / 55. / 58. LOSSES / 11. 15. / 12.. 15. ! 12.. 16. NtT kE50URCES / 299. 910. / 295. 1024. ! 28b. 107b... TkANSFEREO / U. ! 0. / 0. SURPLU5 / 78,. 0. / 62.. U. ! 41.. G. PEAK -- PEAK L0AD/GENtRATl`1G- CAPOC-iIY-kEWUlltE.'aENT&(FrEGA*A-TTS)- MVUF -- MAXIMUM PLANT 11ILIZATION FACTOk APUF -- ACTUAL PLANT UTILIZATION FACTUW ENEKGY -- GtNtRATIUN/ANNUAL EntKGY kEUUIKEM.tNIS(MILLIONS OF. KILUwATT-t,UURS) 35 TABLE 3.10. (contd) AREA: A,'.CMOMAGE AIICHUkAGE CASE: 2 -- MEUIUM LUAU GkOWTH I.4TERTIE YEAR: 1990. NOTES:0EC. b. 1976 v/ U.S.-1994. ------------------------------ C R I T I C A L P E k I 0 U / 1904-1965 - - ------------------------------------------------------ / 1985-1986 / 19db-1967 / PEAR MPUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MOUF APUF ENEHr.Y ---- -------- /------ KEAnEREME,413 / 904. 4001. / 976. 4329. 11048. 4b57. EXISfF,4G HrOkO . / STEAM/ELEC / 53. 251. .50 .50 204. / 53. ,SO .50 204. / 134. .50 .50 510. CD:•in.TUk61NE / d83. ..75 .50 .53 ..54 1164. 2bi5. / 251. / 866. .75 .50 ,64 1405. 2116. / / 450. 855. .75 .ib 2259. DIESEL / 15.. .15 .00 0. / 15. .15 .28 .00 0. / 5. .50 .15 .26 .00 1958. 0. TOTAL / 1202. 39d2. / 1205.. 3724. / 1452. 4727. ADD ITTOw3 H YU klI 81. ,SO .50 301. / STEAM/ELEC / / 207. .75 .20 3b3. CUFiH.TUkbINE / Is .50 ,50 79. DIESEL HYUMQ bTtA:t/ELEC COH9.TU4t)IUE / 15. .UO .00 U. / 31. .00 .00 0. DIESEL / _ - / 10. .00 .00 0. / .. GHUSs nESOUrtCES/ 1205.- 4061. / 1452-_ 4394. / 1452. 4727, CAN IES..MARGIN/ 0.333 / 0.488 / 0.385 kESEkvE kEt1. / 226. / 244. / 262. LOSSES / 45._ 60. / 49. 65. / 52. 70. f.ET kESOUHCES / 934. 4001. / 1159. 4329. / 1138. 4657. IRANSFERED / U,• / 0. / U. SURPLUS / 30. 0. / 183. 0. / 90. 0. PEAK -- PEAK LOAD/GENERATING CAPACITY REOUIREM£NTS(MEGAAATTS) MPUF --'MAXIMUM PLANT UTILIZATION FACTUH APUF -- ACTUAL PLANT UTILIZATION-FRCTUrt` ENERGY - GENERATION/ANNUAL ENERGY REDUIREMENTS(MILLIONS OF KILOWATT-HOURW)L- 91.1 TABLE 3.10. (contd) AREA: FAIkbANKS FAIkHANKS CASt: 2 -- MEDIUM LOAD GRUwTM INTERTIE YEAk: 1990. NUTES:DEC. b, 1g76 s/ U.S.-1994. --------------------- C R I T I C A L P E k 1 0 0 / 1904-1995 ________________..__----_-_-_-_-_--__-_--__-----_-_-------_---------_ /. 19H5-196b / I9R6►1967 / PEAK MPUF APUF ENERGY J PEAK MPUF APUF ENERGY J PEAK MPUF APUF ENERGY /------ ---- ---- -------- /------ ---- ---- -------- l------ -- ---- ----- ---------------/ - J / R[G:IIRE-VEArS / 256. 1132. % 272. 1193. / 266. 1254. --------------/ REbO0RCES HYukU / u. .50 .50 U. / 0. .50 .50 0. / U, .50 .SO 0, SitAm/ELEC / 110. .75 ,f5 723.-/ 110. .75 .75 123•. / 21u, P75 .55 1016. CC:4d.TvRiJINE / 204. .50 .24 426. / 2G4 .50 .18 313. / 204. .50 .14 254. uIF5EL / 46, .10 .00 u, / 22. .10 .00 0. / 22. .10 .uO 0, J / ! TOTAL / 3b0. 1149. / 336. 1036.•/ 436, 1273. ' AUU1rIU.15 JTLA4/ELEC / - _ - - / 1oG. .7S .20- CU nH,. TuRI INE DIESEL RET1kEKtNT5 m y.Ril- STEAa/ELEC CO'*H. TURUI:4E UIESEL / 24. .00 .00 0. ---------------/ J / GROSS kESOURCES/ 336. 1149. / 436. i2I1. / 43b. 1273'. CAP RES.'MARGIN/ 0.3u0 / 0.601 / 0.523 DESERVE kEQ. / 65. / 68. ! 72. L.USSES / 1S. 17. / 14. IA. / 14. I9. 6ET RESOURCES ! 258. 1132. / 354. 1193, / 350. 125a, .lwArjbFFRED / .0. SURPLUS / 0, U. / 62. 0;-/ 64. U. PEAK -- PEAK LOAD/GENERATING CAPACITY REQUIREMENTS(MEGABATTS) MPUF MAXIMUM PLANT UTILIZATIUN FACTUR APUF -- ACTUAL PLANT UTILIZAr1ON FACTUr( E:cEkGY -- GENtRATION/ANNUAL ENERGY REQUIkEMENTSEMILLIONS OF KILUNATT-riOURS) 37 TABLE 3.10. (contd) AREA: Ai.CMOkA6E ANCHOw A6F CA.St: 2 -- MEUIUM LUAU GROWTH INTERTIE YEAR: 1990. NUTES:UEC. b, 1976 W/ U.S.-1994. C R I T I C A L P E k 1 0 0 --------•••-••••----••-----_••--••_-•-•--•••----•---------------------------------------- / 1967-1988 / 3988-1989 / 1969-1990 / PEAK MFUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MPUF AFUF EiltrtGY /------ ---- ----' -------- 1------ ---- ---- -------- /------ ---- •--- -------- kE+�uiREMENTS / 1120. 4985. / 1194. 5313. / 1264. 5b41. -------------/ REb;ugces EXI:,1IN6 hYUkN / 134. .50 .50 510. / 134. ;bo .50 510. / 134. .50 .50 5LU. STcAM/ELEC / 458. ..75 .63 2413. / 643. .75 .58 3254. / b43. .75, .b6 3145. CO+4.TUkeVIE / h55. .50 .24 1786. / 855. .50 .23 1b28. / 791. .5u .21 1471. UIESEL / S. .15 1.00 0. / 5. .15 .00 0. / 5. .15 .00 V. TOTAL / 1452. 4709.. / 1637. 5393. / 1573. 5726. AUUITIUNS r+YDRO- STtAr4/ELEC / 200. .75 .20 351).- LUmm.T'1kNINE / - - - - / - 7- - / - UIESEL / - - •. - / - - - - / - - PFTIRE,1ENTS STEAM/ELEC / 15. .UO .00 0. / - - - - / - • CONe.TUWUINE / - - - - / 64. .00 .00 0. / - - vItSEL .GROSS RESOURCES/ lb37. 5060. / 1573. 5393. / 1573. 5726. CAP NES. MARGIN/ 0.462 / 0.320 / 0.245 / / I RESERVE kEO. / 2840. / 298. / 253. ,LOSSES / 5b. 75. / 60. 80. / 63. 85. -%ET gESOURCES / 1301. 4985. / 1216. 5313. / 1257. 5641. TRA77SFEREU / 0. / 0. J 7. SURPLI)8 / 181. 0. / 24.. 0. / 0. 0. PEAK -- PEAK LOAD/GENERATING CAPACITY NEIIUIREMENTS(MEGAWAT'TS) APUF -- MAXIMUM PLANT UTILIZATION FACTOR AF11F -- ACTUAL PLANT UTIL12ATION FACTUM ENERGY -- GLNtRAT1OW/ANNUAL ENERGY REQUIHEMENTS(MILLIUNS OF KILOWATTZHOURS) nLt TABLE 3.10. (contd) AREA: FA19HANAS FAIRBANAS CASE: 2 -- MEDIUM LOAD GROWTH INTEkTIE YEAR: 1990. NUTES:DLC. 6. 1976 Al U.S.-1994, ------------------------------------------------- C R I T I C A L P E R I U O / 1967-19tsb / 19tld-1989 --------------------------------------- / 1909-1990 / PEAR MPUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- -..-- -------- /------ ---- ---- -------- /------ ---- ---- -------- ---------------/ ! ! NEIIUIRE�,E^ITS ! SOU. 1315. ! 314. 137b. ! 326. 1437. -------.--------/ k ESOi)RCE5 EAI2,TLNG "YURO ! 0_ .51 .50 0. ! 0. .50 .50 0. ! 0- .�10 .50 0. S:cA+t/ELEC / 21u. .75 .62 1134. / 210. .75 .ba 1194. / 216. .75 .ba 1250., COmm .."ultbINE / 204. .50 .11 19b. /_ 24)4. .50 .10 17d.. / 204. .50 ,IQ 176. UIGSEL / 22_ .10, .00 0. / 22. .10 .00 0.. ! 0. .10 .00 0. TOFAL. / 436.. 1335. / 436. 1372. ! 419.. 1459.. 40nIT10'45 HVURO- STEAM/ELEC ! - - - - ! 14. .75 ,20 25.- UIESEL- RETIRLMENTS STLA'a/ELEC- COMa.TI)kr)INE- UTESEL / - - / 22. .00 .00 0../ -, - - - ---------------/ ! / uRUSS <ESUU4CF5/ 436. 1335. / 419. 1397. / 419.. 1459- CAP KES. MARGIN/ 0.452 / 0.334 ! 0.277 kESERVE REQ. / 75. ! 79.- / 66. LOSSES / iS. 20. / 16.. 21. / lb, 22. NET tFSOORCES / 34b. 1315. / 325. 1376. / 337. 1437, TRAM,zFEREU / 1). / 0. ! -7. SURPLUS / 46. 0. / 11. 0. / 2. 0. PEAK -- PEAK LOAD/GENERATING CAPACITY REriOIREMENTS(MEGAnATTS) MPNF -- MAXIMUM PLANT UTILIZATION FACTOR APUF -- ACTUAL PLANT UTILIZATIUN FACTOR ENERGY -- GENtRATiON/ANNUAL ENERGY REDUIREMENTS(MILLIUNS OF KILUAAiT-HOURS) • 39 TABLE 3.10. (contd) ANEA: ANCHONAbE A•ICHORAGE CASC: 2 -- .MEDIUM LUAU GRUWTH INTERrIE YEAR: 1990. NuTES:OtC, o. 1978 w/ U.S.-1994. -_-----•------e----_----e-e------------------•-_e-_ee-----------_-------------------_---- C R I T I C A L P E R I 0 0 / 1990-1991 / 1991-1992 / 1992-1993 / PEAd MPUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- ---- ------- /------ ----' ---- -------- /------ ---- ---- -------- kE�uIkEME'+iS ! 1357. 6063. / 1450. 64d5. / 1543. 6907. EX14T(NG HYuk,l / 134. .50 .50 510. / 134. .50 .50 510. / 134. .50 .50 SIO. STEAAtELEC / b43. .75 .71 39a6. / 843. .75 .65 4552. / 1045. .75 .5b 51bb. Cr)Mn.TUNAINF / 791. .So .19 '1308. / 791. .50 .16 1095. / 773. .50 ,l0 634. UIt4EL. 1 5. .15 .Go 0. / 5. .15 .00 0. / 3. .15 .00 0. TOTAL / 157S. 5804. / 1773. 6157. / 1955. 6310. J / / ADO ITIWjS HYUkO STEAM/ELEC / 20U. .75 .20 350. / 243. .75 .20 425. / 400. .75 .20 701. C0"48.TURaINE / U I6SEL RETIREAENTS HYUkU / _ - - / _ - - - / - - • - e STEAM/FLEC / _ - - - / 41. .UO .00 U. Lb,lb. TUkH Ii4L / - - - e / Id. .fjo .00 U. / 5u. .00 .uo 0. OIESEL / - - - / 2- .00 .00 0. GR055 2ESOUkCES/ 1773. 6154. / 1955. 6582. / 230b. 7011. CAP kES- MARGIN/ 0.307 / 0.349 / 0.494 kE3ENvE REQ. / 271. / 290. / 309. LUSSdS / 68. 91. / 73. 91. / 77. 1U4. NET kESOURCE5 J 1434. 6063. / 1593.. 6485. / 1920. 6907. TRANSFEREO / U. / -29. / -64. SURPLUS / 77.-- 0. / 114. 0. / 289. 0. PEAK •- PEAA LOAO/GENERATING CAPACITY kEOUIREMENTS(MEGANATTS) MPUF •- MAXIMUM PLANT UTILICAiION FACTOR APUF ACTUAL PLAW OTILIIATIUN FACTOR ENERGY -- GENERATION/ANNUAL E�+ERGY REOUIkEMEN7S(14ILLION3 OF KILOWATT-HOUMS) 40 TABLE 3.10. (contd) AREA: FAIkHANK5 ' FAIRHAiNKS CASE: 2 -- MEDIUM LOAD GROWTH INTERTIE YEAR: 1990. NUTES:UEC. 6. 1978 a/ U.5.-1994. - ----------------------------------------------------------------------------------------- C R I T I C A L P E R I J D / 1990-1991 / 1991-1992 / 1g92-1v93 / PEAS( MPUF APUF E:ItkGY / PEAK MPUF APUF ENERGY ! PEAK MPUF APUF ENERGY /------ ---- ---- --------. /------ ---- ' ---- -------- /------ ---- ---- -------- ---------------/ kEUUIkE,AkNTS ! 343. 1505.. ! 358. 1573. / 374. 1641. ------._------- / ,REStIiiRCES J / / n Yuku - / 0. .50 .50 0. / 0. .50 .50 0. J 0.. .50 .50 U. STEAMYELEC / 216. .15 .73 1172. / 216. .75 .b8 1263. / 216. .79 .71 1334. CD,o.TUR$It;S / 204- .50 .17 300.: / 204.. .50 .18. 313. / 204. .50 .23 327. DIESEL / 0. .10 .00 0. / 0. .10 .00 0.. / 0. .10 .00 U. TOTAL / 419. 1472. / 419. 1597. / 419. 1666. AuU1TIUr,3 HYuko- bitA:a/ELEC ! 3i, .75 .20 56.- C O;iH.TUR9INF- UIt5EL FtTIREMtNtS STEAM/ELEC / 32. .00 .00 0.- CfiMH.T:1K+fINE / - - - - / - -. -. - / 40. .u0 .u0 0. D 1tSEL- ! / --------------/ ! ! yak U55.: kE30UNCES/ 419... 152E.., / 419... 1597. / 579.. 1666.. TAP kES..MARGIN/ 0.222'. f 0.170 / 0.013. ;ESEkVE REG. / 69., / 72. / 75. LOSSES / 17.. 23. / 18. 24. / I9. 25.. IET AESOURCES / 333. 1505. / 330. 1573. / 286. 1641. LRANSF ERtD / U. / 29. SURPLUS. / -10.. 0. / O. O. / U. U. PEAK PEA^ LOAD/GE�iERAT2NG CAPACITY REOUIREi,ExTS(MEGALAATTS) MPUF -- r-AXIMUM PLANT UTILIZATION FACTOR APUF -- ACTUAL PLANT UTILIZATION FACTUR ENERGY -- GENtRATIONIANNUAL ENERGY kEUUIREMEMi5(MIL"aN3 W KILOWATT-HOURS) 41 TABLE 3.10. (contd) AREA: ANCmOkAGE A-4CHOWA6E CASK: 2 -- MEDIUM LOAD GkuvsTH INTEPTIt YEAR: 1490. NUTES:DtC. 6, 1978 wl U.S.-1994. C R I T I C A L P E k I U D ----------------------------------------------------------------------------------------- / 1993-1994 / 1994-1995 / 1995-1996 ! PEAR NPUF APUF E149MGY / PEAK MPIIF APUF ENERGY / PEAK MPuF APUF -NERGY , /------ ---- ---- ------ /------ ---- ---- -------- ---- ---- ---- -------- --------------- / ! / KEUI1(?t,4tNrs / lb36. 7329. / 1729., 7751. / 1654. 8311. kEoUUUCES / / / EAISTING $4Yuku / 134. .50 .50 510. ! 134. .50 ..50 510. / 792. .tio .50 3u15. STEAM/VLEC / 1445. .79 .50 6645. / 1445. .75 .34 4Ob6. ! 1445. .75 .36 4hla . CDv8.TUR8IhE ! 724. .50 .10 586. / 669. .50 .10 586. / 664. .50 .10 417. UIESEL. / 3. .15 .ou 0. / 3. .15 .00 0. / 3. .15 .00 0. TOTAL. ! 2306. 7439. / 2251. 5362. ! 2909. 0106. AOU1 T T I)NS / MYUH0 /. - - - - / b5tl. .50 .50 250t. / 86. .50 .Su 329. 5TLAM/ELFC- COM8. Wool INE- UIL5EL RET1kEMENTS mYuMU / - ► - - / - -. < - / - - - -. sTEA.I/ELEC- CUA6.TUMHINE ! 55. .u0 .00 0. / - - - - / 125.. .00 .00 u. U145kL ! - - - -. ! - - - - ! - -. - - G.IUSS RESgURCE8/ 2251. 7439* ! 2909. 78b7., / 2B7I. 843tl.,. CAP "ES. MAkGIN/ 0.376 / 0.682 / 0.548 kESExVE MEU. / 327. / S4b.. LOSZL3 / 82. 110. / 86. 116. / 93. 125. 4ET RESOuRCE5 / 1842. 7329. / 2476. 7751. / 2407. 6311.. 7kANSFEREO / -ln7. - / 0. / U. SURPLUS / 99. 0. / 747., 0. / 553. 0. PEAK -- PEAK LUAU/GENERAIING CAPACIIY kEUulkEmLf4TS(MEGAwA(TS) MPUF -- MAXIMUM PLANT UT'ILIZATIUN FACTUR APUF -- ACTUAL PLANT UTILIZATION FACTOR ENERGY- -- GENEkATION/ANNUAL ENERGY kEPUIREMENTS(MILLIONS OF KILUVWT-HOURS) 42 TABLE 3.10. (contd) AREA: FAIRBatrAa FAIkHANNS CASt: 2 -- MEUIUit LUAU GliokTh ' lNTER11L YEAR: 1990. NOTES:0cC. a, 1978 A/ U.S.-1994. C R I T I C A L P t R 1 U U ----------------------------------------------------------------------------------------- i 1993-T994 / 1994-1995 / 1995-1496 / PLAR NPUF AMUF ENERGY / PEAK MPUF APOF ENERGY / PEAK MPUF APlJF ENERGY /_----- --_► --_- -«__�-- /------ ---- ---- -------- /------ ---- ---- -------- -------«««--/ / / - REuUIRLAtNTS / 389. 1709. / 405.. 1777. / 423. 165y, -«--«-«-- -.-- REJUURCES EXIaTI:NG HYt:k0 / 0. .50 .50 U. / 0. ..50 .50 0. / 151. .50 .50 574. STc A:4/ELEC" ! 21b..: .75 .73 1377. / 216. .75 .58 1086. / 216. .75 ,b3 1053. CO-i.TURbI14E / 164. .SO .25 357. / 164.. .50 .10 143. / 1b4. .50 .10 143.. GIcSEL / 0. .10 ,.GO 0- / U'. .10 .00 0. / 0. .10 .00 u. TOTAL / 379., 1735. /. 379.. 1224. / 530. 177U. AUD1 rives HYURU ./ - - -- - / 151. .50 .50 574. / 19. .50 .S0 74. STEAD/ELEC / -. - _ / - - - - / 25.. .75 .20 43.. CUwS.Tij-4Hli•:E �ETIRE�4E*tTS / / / STEA-./ELEC / - - - - / - - - - / 25. .00 .v0 0. COroH.TuknTNE ! - - - - / - _ - - / - _ - ---------------/ ! / GkUSa NFSUURCES/ 379, 1735.•./ 530. 1804. / 549. 1887. CAP RES. MARGIN/-0.02b / 0.308. ! 0.298 HEaEHuE kEU. ! 76. / 61. / 85. . LOSSES / 19. 26. / 20.- 27../ 21. 26. �rEf RESUORCES ! 292. 1709.. / 429. 1777. / 443. id". TkAr1SFERE0 / 107. / 0., / 0. SURPLUS / 0,. 0. / 24. PEAK -- PEAK LUAU/GENERATING CAPACITY .REW(JIREMENTS(MEGAAATTS) MPUF -► MAXIMUM PLAi4T UTILIZATION FACTOR APUF ACTUAL. PLAWT UTILIZATION FACTUR ENERGY --. GENERATIUN/ANNUAL ENERGY REQUIREMENTS (MILLIONS OF KILUAATl-#OURS) 43 TABLE 3.10. (contd) AREA: ANCHORAGE ANCMURAGE CAbc: 2 -- ,MEU1UM LUAU GkOwTH INTERTIE YEAR: 1990. NUTES:UEC. 6, 1976 w/ U.S.-1994. ----------------------------------------------------- C R I T I C A L P E R I O D / 1946-199-7 / 1997-1998 I---------------------------------- / 1998-1999 / PEAK MPUF MPUF ENERUY / PEAK MPUF APUF ENERGY / PtAA HPUF APUF ENERGY /------ ---- ---- -------- /------ ---- ---- -------- /------ ---- ---- -------- R EUU1kEMt14iS / 1979. 8411. / 2103. 9451. / 2228. 9991. RE50uRCE5 / / / HYuRU / a78.. .50 .50 3344. / 876. .50 .50 3344. / 818. .50 .50 3344. 5lkAt4/ELEC / 1449. .75 .42 5S6(3-. / 1445. .75 .47 5434. / 1445. .75 .32 d02,3. CO:+».TuQ,jIr1E / 545. .50 .10 294. / 335. .50 .10 294. / 335. .50 .10 218. U1tSEL / S. .15 .00 0. / U. .15 .00 U. / 0. .15 .00 0. (O(AL. / 2871. 9004. / 2659. 9572. / 2659. 7b48. ADgjTIUNS nrURU / - - - - / - - - - / 654. .50 .50 2493.. STEAM/ELEC (;Q"d.TUkblNt UIESEL / - - - - / - - - / - • - _ RETIREMENTS MYURU- STEAra/ELEC - _ COM8.TU4SiNE / 210. .uo .00 0. / - - - - / la. .00 .00 U. ---------------/ GkUS& s+E6UURCES/ 265y.. 9004. / 2bh9. 9572. / S295. 10141., CAP RES. MARGIN/ 0.343 / 0.264 / 4.479 kESEkVE kEO. / 396. / 421. / 446. LUSSES / 99. 133../ 105. 141. / ill. t5u. t+ET RESOURCES / 2164. 8811.. / 2133.. 9431. / 2738. 9991. THAt7SFEREU / -27. - / 0. / 0. . I / / SURPLUS / 15d. U. / 30. 0. / 510. 0. PEAK -- PEAA LOAD/GENERATING CAPACITY REUUIkEMENTS(MEGAwATTS) MPUF -- MAXIMUM PLANT UTILIZATION FACTUR APUF -- ACTUAL PLANT UTILIZATIUN FACTOR ENERGY -- GENtRATIU,V/A,4.NUAL ENERGY KERUIREMENTS(MLLLIONS OF KILUYATT-tiOURS) 44 TABLE 3.10. (contd) AREA: FAINBANKS FAIkOANKS CASE: 2 -- IIEUIUM LUAU GROWTH INTERTIe YEAR: 1v90. ' NOTES:OEC. 6. 1978 N/ U.S.-1944. -------------------------------------------------•------_-------------------------------- C R I T I C A L N E R I U 0 / 19Y6-1997 / 1997-1496 / 1998-1999 / PEAK HPUF AMt1F ENERGY / PEAK MPt1F APUF ENERGY PEAK +-iPtjF A"UF ENERGY /------ ---- ---- -----�-- /------ ---- ---- -------- /------ ---- ---- -------_ ---------------/ REI+ULREME.WS / 442. 1941. ! 461. 2023. / 480. 2195. ---------------/ RESOUPCES EXIbrVjG rfYUkO / 170. .50 .50 648. / 170. .50 .50 648. / 170. .50 .50 648. STEAM/ELEC / 216. ,15 ,04 iG90. / 216. ,75 ,65 1230. / 310, .75 .35 903. C+7tR8-TUkBINE / 164. .50 .10 123. / 140. .50 .10 0. / 0. .So. .10 U. Ui.cbEL /' 0.. .10 .00 0. / 0. .10 .00 U. / U. ,10 .00 0. TOTAL., / 549. 1970../ 526. 1878. / 486. 1611. AUUITIOUS HYUwO / - - - - ! -- - - - ! 138. .50 .SU 525, blEA4YELEC / - - - - / 100. .75 .20 17`9. / - - - _ - DIESEL- kETIeEMLfj73 n YURO / 5TEA:4/ELEC / CUrab.TURbIr4E / 24. .UO .00 0. / 140. .00 ,00- UIE5EL ---------------/ 6kU5:i RESUUkCE5/ 520y.. 1.970.../ 466.. 2053. / 624. 2137. PAP RES. 'A&RGIN/ 0.189- / 0.053. / 0.299 KESEAVE kEu. / en,. / 92. / 96. LOSSES / 22.• 29. / 23. 30. / 24. 32. r4ET kESOURC£S / 415. 1941.../ 370. 2023. / 504. 2105. rkA45FEREU / 27. / 0. / 0. L / / SURPLUS / 0. U, / -91.. 0, / 24. U. PEAK -- PEAK LOAD/GEWERATING CAPACITY REQUIREMENTS(MEGAwATTS) MPUF -- MAXIMUM PLANT UTILIZATION FACTOR APUF -- ACTUAL PLANT UTILIZATION FACTOR ENERGY -- GENERArIUN/ANNUAL ENERGY REOU1kEMENTS(MILLIONS OF KILUAATT-HUURS) 45. TABLE (Mid) ARM AN6pflNAU€ A146HONA4k 04561 3 as mauluFI 6UAU OWN 1kIi0NfIa UANI 19+1oa NOD15a0a e7 014 al/ Ua3a80941 0 5€ f 1 6 A 6 0€ 0 1 6 U ■■■■■■■aBii■■iP■■i■■aiYSSiaiSiSS�fSSiS3.'{i:3330.•-•..a..Q...•.:iiu:.•.:33:'.:•..o........•-...•r.. / PEAK MpUF�OApUFo VAMP / P6AA MOUfiSUAOUF} �p4g6� ! dC,R3 gr3��6�A�U�� �p[:ltlii /■■■■■n sas% soon sn■s:■■ss /s?.atssa :333 sags-ggss3z3 jazzaa3 .... .... ."3gagag ■■■■■■■■■■■■■■■/ / ! N$WUl7+8MBN18 / rjl58a 10551a / M i f t0363s ! Wos tt1i5 ■■■■■■■■■■■■■■■/ ! J M&NOUN665 ifsltbilwts / / ! N4UNU / 193ia ae0 ato 58838 / 1619a Ad Ad Moo ! i51is do 90 N664 b1&AMA6kG / t4450, Os 134 4543a+/ 140 ait 23 043s ! 14421 o 5604 COMSITURotNS / 317a a50 aid 8oe/ 06 to io i1q ! l3 a ai0 MR U1%886 / Oto add Oa J 0a a§ s60 &is do tea 10146 % 919Sa 105@ba 1 33406 ttdo 1 MOOR ti�43s: AUUIT101v6 / / J NYUFU / 85a a50 a50 7F�5a / a a c as / 3 s a a. OTBAM/R6EG, / a/ a c a a CuOd. TIJN1§1110, / ■ ® a d c a c c 1 3 a a c GtEalt6 / ■ ■. � a/ a c a/ a s a kgftN,BMtsf+ia / / J NVIJHf) / a ■, a a+. / a rr c a / a c 3; s bTbIM/tb6EG / ■ ■ o a/ o a. c a/ a si c a CT1MiAsTOWNINP / N2a, 600 ago da J iooa add a60 do; / lea Rod 600 Us I 1 J + MM NEaUUNCda1 524da loto4s,1 81064-, ltodaa.l MOOR it545b CAP N@a. MA401W 0.402, I / 0;321 / 6aaR97 a kE65ENVE Nelda / 471s / 4640 d 448a, LOSSES. / 119a lids / 121s 163i /' M . 1b8. NET NESUUNCES / 2710. 10551., / 2595. 10663. / 2558.. 11175. TRANbFERED / 0. / 0. SURPLUS / 357. 0. / 172. 0. / 61. 0. PEAR •• PEAh LOAU/GENERATING CAPACITY REQUIREMENTS(MEGAWATT81 MPUF• -• MAXIMUM PLANT UTILIZATION FACTOR APUF -• ACTUAL PLANT UTILIZATION FACTON ENERGY -- GhNtNATION/ANNUAL ENERGY kEUU1NEMEN73(MILLION3 OF KILOWATT-MOUKs) 46 TABLE 3.10. (contd) AkEA: FAIkBANKS - FATRRAtAKS CASs: 2 -- MEDIUM LOAD GROWTH INTEPTIt YEAR: 1990. NOTES:UEC. oY 1978 N/ U.S.-1994. C R I T I C A L P E R I O D / 1949-2000 / 2000-2401 / 2001-2002 / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY _______________/ / / kEwtlkEMtNTS / 499. 2187. / 508. 2229.. / 518. 2270. --------------- kcSuukCES / / / E;-ISTI14G 4YUku ! 308. .S0 .50 1173. / 326. .50 .50 1244. / 32b. .50 .50 1240. STEAM/ELEC / 516. .75 .35 980. / 316. .75 .37 3022. / 316. .75 .38 1064. r_OMa.TURdI4E / U.. .50 -10 0. / 0. .50 .10 0. / 0. .50 .10 0. DIESEL. .10 .DO 0. / 0. .10 .00 0. / 0. .10 .00 0. TOTAL / 624.. 2153. / 641. 2262.. / 641. 2304.. AU01TIOuS. r. Y uR11 / 16. .50 .50 67. / « •� _. - / - - «. �. STEAMIELEC / - -- 00'+d.TUknINE P£TIREMEVS DIESEL _ --/ Gku55 kESOURCES/ ,64I- 2220. / 641. 2262. / 641. 2304. CAP kE5..MAWrh/ 0.285 / 0.2b2 / 0.236 kESEkvE kEU. / 10u-. / 102- / 104. LOSSES / 25. 33. / 25. 33« ! 26 34.. +ET 4ESUORCE5 / 516.. 2187. / 514. 2229. / 512. 2270. / l / TRANSFERED / 0. _ 1 U. / 6. SURPLUS / 17. 0. ! 6. 0. / 0. 0. PEAK PtAK LOAD/GENERATING CAPACITY iFUUIkEMENTS(MEGAoiATTS) MPUF MAXIMUM PLANT UTILIZATION FACTOR APUF -- ACTUAL PLANT UTILIZATION FACTUk ENERGY -- GENERATINN/AN44UAL ENERGY kEUUIkEr4ENTS(MILLION3 OF KIL0*ATT«rfuuaS) 47 TABLE 3.10. (contd) AREA: ANCMORA4E ANCHIINAUE CASC: 2 -- MEDIUM LOAD GROWTH INTERTIE YEAR: 1990. hl1TES:OEC. bo t978 v!/ U,S.-094. C R I 1 I C A L P E R I 0 0 ----------------------------------- ►---►-------►---►------►------------------------------ / 20U2-2UO3 /, 2003-2U04 / 20u4-2005 / PEAK MPUF APUF ENFN GY,,-% PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- ------------ /------ ---- ------------ /------ ---- ------------ ---------------/ NEOUIREMFNTS / 2558. 11487. / 2b2b. 11799. / 2b94. 12111. NE50uaCE5, / / / ERISTING MYURO / 1617. .SO..` .SU b16J. / 1617. .50 ,So 6160.. / 1617. .SO .SO blc0. 5TEAti/ELEC / L445. .r3• .38 4163. / 1845. .75 .36 5801. / 1845. .75 .38 6133. .Cr7M9.Ttikjljr.E / lld. .SO .10 15. / lb.. .50 .10 15. / 18. .50 .10 U. UIESEL / 0 .15 .00 0. / 0. .15 .00 0. / 0. .15 .UO 0. TOTAL /y 3180. 10959. / 3480. 11976. / 3480. 12293. AUULIIWjb M Y IJ Ii:j / STtAW/tLES / 400,- .15 .20 701.. CO,44. 7UR6 tHE / - -- OIESEL HETLkEMENTS 6TEAM/ELEC - LUri6.TURuLf�t / IOU. ,Vo ,UU U. / - - - - / Id. .00 .00 U. bag56 8c5(iURCES/ 3480. 11659. / 3480. 1197b. / 3462. 12293. CAP-RES- MARGIN/-U.3hl / 0.325 / 0.281 RESERVE kEQ. ! 512. / 525. ! 539. LUSSES / 126. 172. / 131. 171. / 135. 182. NET KESCURCES / 2841. 11487. / 2824. 11199. / 2789. 12111. TRANSFEREO / 0. / 0. / U. SURPLItS / 283. 0., / 198. U. / 95. 0. PEAK -- PEAK LUAU/GENERATING CAPACITY REOUIREMENTS(MEGAwATTS) MPUF -- MAXIMUM PLANT UTILIZATION FACTOR APUF ACTUAL PLANT UTILIZATION FA.C141H E,VERGT -- GENERATINN/ANNUAL ENERGY HEOUIHEMENJS(MILLIONS OF KILUWATi-WUURSI t TABLE 3.10. (coned) AREA: FAIKdANKS FAIRR4NAS'CASc: 2 -- MEDIUM LOAD GROnTH `INTERTIE YEAR: 1990. NUTE5:UEC. 6, 1978 w/ U.S.-1994. ------------------------------------------------ C R I T I C A L .. _1' E R 1 0 D / 20u2-20U3 / .---------------------------------------- 2003-2004 / 2OU4-2005 / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- ---- -----t__ /------ -- .. kEUuIkEME"+TS / •527. 2312. / 537. 2353. / 546. 2395. EzI5TING nTURu STtA.M/ELEC / 326. .50 .So 124U. / 326. .50 .50 1240. / 326. .50 .50 12"0.. COup.TUkoLNE ! 316. .75 .37 I 0. 931..J 391. .75 .34 1146. / 391. .75 .35 1191. UIE5EL. .50 .10 / 6... -10 .uo.. 0../ 0. / 0.. .50 .10 0. U, 0. / / 0,. .50 .10 0; .10 .00 0. .10 .00 0. TOTAL / 641. 2171. / 716. 2388. / 716. 2431. AOuITIONS -� ST_AM/ELEC / 100. .75 .20 175../ Cu„H.TljRbINE / - - - RETIREMENTS rtYURO s TEA'A/ELI,C / 212. .uo .00 U. CLMd.. TuRd INE DIESEL - ,�-kC;S3.Kc`SOUKCES/ 716. 2347. / 716. 2388. / 716. 2431. CAP KES...MAKGIN/ O;359 J 0.333: / 0.3I1 RESERVE REG.. / 105. / 107.. / 109. LO,)SCS / 26.. 35. / 2.7. 35. / 27. 30.. hET RESOURCES / 584. 2312. / 562. 2353. / 580. 2395. TRANSFERED / 0. / 0. 1 V. J J ! SukPLUS / 57.. 0. / 45. 0. / 34. 0. PEAR -- PEAK LOAD/GENERATING CAPACITY WEUUIkEMENTSCMEGAAATTS) MPUF MAXIMUM PLANT UTILILATIUN FACTOR APUF _-ACTUAL PLANT UTILIZATION FACTOR ENERGY -- GENERATION/ANNUAL ENERGY REQUIREMENTS (MILLIONS OF T KILOAATT-HOURS) TABLE 3.10. (contd) AkEA: ANCHOHA.E AYCHIIHAUE CASs: 2 __ MEDIUM LUAU GROWTH INTERrIE TEAR: 199U'. NUTES:UEC. b. 1978 W/ U.S.-1994. C R I T I C A L P E H I 0 0 / / 2006-2007 / 2007-20un / PEAK MPUF API1F ENERGY / PEAK MPIIF APUF ENERGY / PEAK MPUF APUF ENERGY /------ --- ---- ----- /------ ---- ------------ HEUViRE14r-NiS / 2763. 12423. / 2631. 12735. / 2899. 13047, �EbOUHCES / / / EAIbTING nfukU , / 1617. .50 .50 61b0. / 1617. .50 .50 6160. / 1b17. .50 ,50 blbu. bThAm/ELEC / 1845. .15 .40 645U. / 1845. .75 .38 6060, / 2245. .75 .36 7083. CONS .TURBINE / 0. .50 .10 0. J 0. .50 .10 0. / 0. .SU .10 0. uIESEL / U. .15: .00 U. / 0. .15 .00 0. % 0. .15 ,uo 0. TOTAL•' / 3462. 12609. / 3462. 12225. / 3862. 13243. AUOITIUNS HYOkl7- STEAN/ELEC I _ - - - / 400. .75 .20 701.- CUMn.1URbINE- UIESEL RETIRE%4tNTS Hr0k4 STI:AM/ELEC- CU:40.TUHnINE- DIESEL ---------------/ GHUSS RESUUHCES/ 3462. 12b09../ 3862. 12926. / 386d. 13243. CAP PNkS..MARGIN/ 0.253 / 0.364 / 0.332 k£bEkYE HEN. / 553. / 566. / n8u. LObSES / 13d.. 186. / 142. 191. / 145. " 196. NET RESOURCES / 2771. 12423. / 3154. 12735. / 3137. 13047. TRAP44FEREJ / 0. / -10.. / -23. SURPLUS / 8.. 0. / 313. 0. / 216. 0. PEAK -- PEAR LOAD/GENERATING CAPACITY HEOUIkEMENTS(MEGAAATTS) PPUF _- MAAIMUM PLANT UTILIZATIUN FACTOR APUF _- ACTUAL.PLA,JT UTILIZATION FACTOR E.iERGY -- GENCRATIONJANNUAL ENERGY REUUIHEMkNTS(MILLIONS OF KILUWATT-nOURS) 50 TABLE 3.10. (contd) APEA: FAImOAN&S FAIk8ANAS CASC: 2 -- M£JIU14 LGAO GROWTM Tr,TERTIt•YEAR : 1y90. NUTES:OLC. 6. 1978 Al U,S.-1994. ----------------------------------------------------------------------------------------- C R I T I C A L P E R I 0 0 - / e0u5-2u00 / 2000-2U07 / 2007-2U08 ! PEAK hPuF APUF E14ERGY / PEAK MPUF APUF ENE'iGY / PEAK MPUF APUF ENERGY /-«►-- ---- ---- ---- -------- /------ ---_ �E:,UIREMENT5 ! SSb. 2437../ 565. 2478. / 575. 2520. - -------------/ ! EXI471hb MruR� ! 326. .t)0 .50 1240. / 326. .50 .50 12u0. / 326. .50 .50 1240. bii_A:�/ELEC ! 391. .15 .58 1234. / 371.. .75 .39 1275. / 371. .75 .41 1318. CO^te.TUk8Ir�E / 0. ,:30 .10 0. ! 0. .50 .10 0. ! 0. .50 .10 0. u1t8EL' / 0. .10 .00 0../ 0. .10 .00 0, / 0. .10 .00 0.. TOTAL / 710- 2474.,/ 696. 2515- ! 696- 2556. ADDITIONS STEAM/tLEC /- CUt+y.TU,?SINE �UTE5EL.- FETImEMtNTS :STEA4/ELEC / 20. .u0 ,00 0. j CGnH.TUQmINE- OIEbEL 6ii+ibb ^oES(IukCES/ 696 .. 2474. /' 696.". 2515... / 69b. 2558.. CAP- kES.. MARGIlf! 0.252 / 0.232' / 0,211 nESEkVE KVi. I Ill- / 113.. / 115. LOSSES / 28. 37. / 28. 37.. / 29. A. •iET RESOukCES_ / 557. 2437. / 555. 2478. / .552. 2520. 14ANSFEREU / U.. / 10. / 23.. SURPLUS / 1.' 0. ! 0.. 0. / 0. 0.. PEAK -- PEAK LOAD/GENERATING CAPACITY REuUIREmENTS(ME(,AwATTS) MOUF -- MAXIMUM PLANT UTTLIZATION FACTUR APUF -- ACTUAL PLANT UTILIZATION FACTOR ENErrGY -- GENtRATION/ANNUAL ENERGY REGUIREMENTS(MILLIUNS OF KILOWATT-mOURS) 51 TABLE 3.10. (contd) AREA: AwCMOkAbE Al:CHURAUE CA.6E: 2 -- 14EDIUM LOAD GROATH INTEkTIa ?EAR: 1940. kt1TES:UtC. t.t 1970 N/ U.S.-1944. C R I T I C A L P E R I U U --•---•----•••---•••-•-•------•-••-----------•------------•------------------------------ I 20u8-20U9 / 2009-ZOIU / 2010-2ull / PEAK MPUF APUF ENERGY J PEAK MPUF APUF ENERGY / PEAK MPUF APUF ENERGY /------ ---- ---- -------- /------ ---- ------------ /------ ---- ------------ ---------------/ 'kE:U:kEAENT5 / 296d. 13359. ! 303b. 13671. / 3104. 139a3. •--------------/ kE6:iuyCLS / e Y / EXISTING MYUkO J I617. .50 .50 6160. / lb17. .50 .50 6160. / lbll. .50 .50 blbu. S.TEA�;/ELEC J 2245. .75 .38 7400. / 2245. .75 .39 7716. / 22.45. .75 .37 7332. C0(A8.TUkn114E / ' u. .50 110 0. / 0.. .50 .10 0. / 0. .50 .10 U. UIzoEL / u.. .15 .UO U. / 0. .15 .DO •0.. / 0. .15 .:u0 U. TOTAL / 366,3. 135", / 3862. 13876. / 3bo2. 1S492. AuDITIOnS MYukp / - -1 / - • / • .. STEA.,/ELEC / - - / - - - - / 400. .75 .2U hut. C0x8.TURtsINE / - - - - / - - - - / - - - ult:StL RF_T IREMENT3 MY URD STEA'+/ELEC- COMM.Didtj1NE- UltSEL ---------------/ 6;WS4 RESOURCES/ 3862. 13559. / 3862. 13876. / 426Z. 14193. CAP kE8. MARGIN/ 0.301 ! 0.272 / 0.373 REa,ERVE kEU. / 594. / 607.. ! b21. Lr1S5E3 / 144.- 200. ! 152. 205. / 155. 210. NET k£S011RCES / 3120. 13359. / 3103. 13671. ! 3486. 13983. TRANaFEREO / -34. / -46. / -58. SURPLUS / lid. 0. / 21. 0. ! 325. 0. PEAK -- PEAK LUAU/GENERATING CAPACITY REDUIREMENTS(MEGAwATTS) MPUF -- MAXIMUM PLAni UTILIZATION FACTOR APt1F -- ACTUAL PLANT UTILIZATION FACTUtt EtVERGY -- GENcRATINN/ANNUAL ENERGY REDUIKEMENTS(MILLIONS OF KILUWATT-"OURS) 52 TABLE 3.10. (contd) AKEA: FAIXbANKS FAIRBANKS CASE: 2 -- MEDIUM LOAD GROIATH INTFkTIE YEAR: 1990. NU7c5:UtG. Or 1916 N/ U.S.-1494. --------------- --------------------------- C R I T I C A L P E R I U D / tOJ8.2U09 / ------------------ 2009-2010 ------------- / -__-_-_--------- 2010-2u11 / PEAK MPUF APUF ENERGY / PEAK MPuF 'APUF ENERGY / PEAK MPUF -APUF ENERGY ---- ---- -------- --__ _-__. /-0---- ---- ---- _ __ _ -_-/_..---- �______ --- keuUlkL,ENTS _- / 5d4. 2561. / 594. 2606. / 603. 2645, kE5uukCE3 / ExISTING myOKU STEAM/ELEC / 326..- .SO .50 / 371. 1240. / 326.. .50 .50 1240. / 326. .50 .50 1240_ COMB.TURbINE .75, .42 / 9. 1359. / 371.- 0. / .75 .43 la0z. / 371. .75 .45 1445. UI-SEL .50 ..0 / U. .10 ,00 0. 0.. / 0. .50 .10 0. / .10 .00 0. .10 .00 0- TO rAL / 696. / 2599.. / 696. 2b42. 2SA5 .. AJ01TIptqg STtArt/ELEC- uIcSEL WETikEyENTS STtA'a/ELEC- 00'+6.TUH6LNE OIcSEL G�05S RESJURCES/ 696. 2599. / 696.. 2642../ 696. 26d5... / CAP Nei.. MARGIN/ 0.Iva, / / 0.172 / / 9.154 RESExVE.REO. / 117. / 119. / 121.. LUSStS ! 29. 38. / 30.. 34. / 30. 40.. NET KESOURCES / 590. 2561. / 548. 2bO3. / 545. 2645... TRANSFEREO / 34.. / 46. SURPLUS / U. 0. / U. O. / 0. O. PEAK -- PEAK LOAO/GENERATING CAPACITY REQUIREMENTS(MEGAaATTS) MPUF » MAXIMUM PLA•9T UTILIZATION FACTOR APUF -- ACTUAL PLANT UTILIZATION FACTOR ENERGY -- GENERATION/ANNUAL.ENErtGY REOUIREMENT3(MILLIONS OF KILUV'ATT-HOURS) N 53 TABLE 3.11. Schedule of Plant Additions - (Megawatts) Base Cases Without Interconnections Period High Anchorage, Median Low High Fairbanks Median Low 78-79 - - - _ 79-80 1141 1141 1141 - 80-81 1001 1001 1001 - 81-82 181 181 181 - 82-83 5002 3004 1001 - 83-84 200 - - - 84-85 2184 181 181 100 - - 85-86 2886 2886 885 - 100 - 86-87 400 - - 100 - - 87-88 - 200 200 - - - 88-89 400 - - 147 147 147 89-90 - 200 200 100 100 100 90-91 - - - 327 327 327 91-92 4439 2438 437 - - - 92-93 400 400 200 100 100 - 93-94 - - - - _ - 94-95 4003 - 200 100 - 100 95-96 4003 400 200 257 257 257 96-97 4003 400 400 100 100 - 97-98 400.3 400 - 200 100 100 98-99 4003 - - 200 100 100 99-00 4003 400 400 - - - 00-01 4003 - - 01-02 - - - 02-03 4003 400 - _ _ _ 03-04 4003 - - 200 200 - 04-05 - - - _ _ _ 05-06 4003 400 400 - - - 06-07' 4CO3 - - _ 07-08 - - - 200 - - 08-09 4003 - - - 09-10 4003 - - 10-11 - 400 - TOTAL 78-11 8;231 4,681 2,681 1,471 871 471 See footnotes next page 54 TABLE 3.11. (contd) (1) Scheduled Combustion Turbines (2) Scheduled Combustion Turbines + 400 MW S.T. (3) Anchorage 400 MW Coal -Fired Units Could be Replaced with Staged 800 MW Capacity Units (4) Scheduled Combustion Turbine + 200 MW S.T. (5) Bradley Lake (70 MW) x 1.15 for Peaking + 7 MW S.T. National Defense (6) Bradley Lake (70 MW) x 1.15 for Peaking + 2.00 MW S.T. + 7 MW S.T. National Defense (7) National Defense (8) 200 MW S.T. + 43 MW S.T. National Defense (9) 400 MW S.T. + 43 MW S.T. National Defense 5J TABLE 3.12. Schedule of Plant Additions - (Megawatts) Cases With Interconnection Without Upper Susitna Anchorage Fairbanks Period High Median Low High Median Low 78-79 -• - - 79-80 1141 1141 1141, - - - 80-81 1001 1001 1001 - - - 81-82 181 181 181 - - - 82-83 5002 3003 1001 - - - 83-84 200 - - 84-85 2186 181 181 100 - - ' 85-86 2885 2885 884 - 100 - 86-87 -* - - _* _ _ 87-88 400 200 200 - - - 88-89 - - - 148 148 148 89-90 400 -* 200- - -* 100 90-91 - 200 - 328 328 328 91-92 44311 2439 438 - - - 92-93 - 400 200 200 - - 93-94 400 - - 100 - - 94-95 - - -* - 100 -* 95-96 4007 400 200 12510 12510 258 96-97 4007 400 -200 100 - 100 97-98 4007 - 400 200 100 100 98-99 4007 400 - - 100 - 99-00 4007 - - - - _ 00-01 4007 400 400 - - - 01-02 4007 - - - - _ 02-03 4007 - - - 100 - 03-04 - 400 - 200 - - 04-05 - - - 200 - - 05-06 4007 - -. - 06-07 4007 - - - - TOU 07-08 4007 400 - - - - 08-09 - _ 09-10 4007 - - - - - 10-11 4007 - - - - - TOTAL 78-11 8,231 4,231 2,231 1,271 671 471 See footnotes next page 56 TABLE 3.12. (contd) *Interconnection Installed (1) Scheduled Combustion Turbine Additions (2) 100 MW Scheduled Combustion Turbine + 400 MW S.T. (3) 100 MW Scheduled Combustion Turbine + 200 MW S.T. (4) Bradley Lake (70 MW) x 1.15 for Peaking + 7 MW S.T. National Defense (5) Bradley Lake (70 MW) x 1.15 for Peaking + 200 MW S.T. + 7 MW S.T. National Defense (6) 18 MW Scheduled Combustion Turbine + 200 MW S.T. (7) Anchorage 400 MW Coal -Fired Units Could be Replaced with Staged 800 MW . Units (8) National Defense (9) 200 MW S.T. + 43 MW S.T. National Defense (10) 100 MW S.T. + 25 MW S.T. National Defense (11) 400 MW S.T. + 43 MW S.T. National Defense 57 TABLE 3.13. Schedule of Plant Additions - (Megawatts) Cases With Interconnection With Upper Susitna Coming On Line in 1994 Anchorage Fairbanks Period High Median Low High Median Low 78-79 - - _ _ 79-80 1141 1141 1141 - - - 80-81 1001 1001 '1001 - - - 81-82 181 181 181 - - - 82-83 5002 3005 1001 - - - 83-84 200 - - - 84-85 2186 181 181 100 - - 85-86 2887. 2887 886 - 100 - 86-87 -* - - _* _ _ 87-88 400 200 200 - - - 88-89 - - - 1410 1410 1410 89-90 400 -* 200 - -* 100 90-91 - 200 - 3210 3210 3210 91-92 44314 24312 4310 - - -* 92-93 - 400 - 200 - - 93-94 400 - 200 100 - - 94-95 6773 6583 6443 1323 1513 1643 95-96 893 863 853 4211 4411 4611 96-97 400 - - - - - 97-98 400 - - - 100 - 98-99 6884 6544 - 1244 1384 - 99-00 864 854 6454 164 184 1474 00-01 - - 834 100 - 194 01-02 4009 - - 100 - - 02-03 4009 400 - - 100 - 03-04 - - - 200 - - 04-05 4009 - - - 05-06 4009 - 06-07 - 400 - - - - 07-08 400 - - - - - 08-09 4009 - - - 09-10 - - - 200 - - 10-11 4009 400 - - - - TOTAL 78-11 8,221 4,564 2,538 1,360 697 522 See footnotes next page 58 TABLE 3.13. (contd) *Interconnection Installed (1) Scheduled Combustion Turbine Additions (2) Scheduled 100 MW Combustion Turbine + 400 MW S.T. (3) Share of Watana Capacity x 1.15 for Peaking (4) Share of Devil Canyon Capacity x 1.15.for Peaking (5) Scheduled 100 MW Combustion Turbine t 200.MW S.T. (6) Bradley Lake (70 MW) x 1.15 for Peaking + 7 MW S.T. National Defense (7) Bradley Lake (70 MW) x .1.15 for Peaking + 200 MW S.T. + MW S.T. National Defense (8) Scheduled 18 MW Combustion Turbine +200 MW S.T. (9) Anchorage 400 MW Coal -Fired -Units Could be Replaced with Staged 800 MW Units (10) National Defense (11) Share of Watana Capacity x 1.15 for Peaking + 25 MW S.T. National Defense (12) 200 MW S.T. + 43 MW S.T. National Defense .(13) Share of Watana Capacity x 1.15 for Peaking + 25 MW S.T. National Defense '(14) 400 MW S.T.+ 43 MW S.T. Pational Defense 59 M M 5000 0 d 0 J u 4000 CL G z d cd 3000 0 Ln LW z 2000 z ett 80 85 90 95 2000 2005 2010 YEAR FIGURE 3.6. Load/Resource Analysis for Anchorage -Cook Inlet Area Without Interconnection and Without Susitna Project (Case 1). Low, Medium, and High Load Growth Scenarios .e] O1 c 5000 0 a w °- 4000 a z w v t� 3000 O N w r- w � t1t 0 80 85 90 95 2000 2005 2010 YEAR R FIGURE 3.7. Load/Resource Analysis for Anchorage -Cook Inlet Area With Interconnection but Without Upper Susitna Project (Case 2).. Low, Medium, and High Load Growth Scenarios 61. 5000 0 a 0 4000 a. a z a c� 30M 0 to w t- 2000 w z ill U 80 85 90 95 2000 2005 2010 YEAR FIGURE 3.8. Load/Resource Analysis for Anchorage -Cook Inlet Area With Interconnection and With Upper Susitna Project Coming On Line in 1994 (Case 3). Low, Medium, and High Load. Growth Scenarios t 62 12C m n 900 M 150 0 80 85 90 95 2000 2005 2010 YEAR FIGURE 3.9. Load/Resource Analysis for Fairbanks -Tanana Valley Area Without Interconnection and Without Upper Susitna Project (Case 1). Low, Medium, and High Load Growth Scenario 63 1200 1050 0 W V Ln 450 W t— W z i0 150 S0 85 90 95 2000 2005 2010 YEAR FIGURE 3.10. Load/Resource Analysis for Fairbanks -Tanana Valley Area With Interconnection but Without Upper Susitna Project (Case 2). Low, Medium, and High Load Growth Scenari '4 1200 1.1 900 n 0 750 W 600 w V 450 W w z 11 150 HIN 80 85 90 95 2000 2005 2010 YEAR FIGURE 3.11. Load/Resource Analysis for Fairbanks -Tanana Valley Area With Interconnection and With Upper Susitna Project Coming On Line in 1994 (Case 3). Low, Medium, and High Load Growth Scenarios 65 4.0 SYSTEM POWER COST ANALYSES This chapter describes the methodology used to evaluate the annual cost of power from individual generating facilities (or groups of similar generating facilities), the method of computing the average system -wide power costs, and presents -the results of the system power cost analyses. The first section briefly discusses the factors which determine the cost of power. The second section describes the computational method used to compute the annual cost of power. This method is incorporated into a computer model titled ECOST4. A listing of the computer code is given in Appendix D. The third section of this chapter contains a discussion of how the system -wide power costs are computed given the power costs for the indi- vidual facilities. The results are presented in the last part of the chapter. 4.1 FACTORS DETERMINING THE COST OF POWER Three cost categories are evaluated in this report: 1) interest and amortization charges (capital cost); 2) fuel costs; and'3) operating, maintenance and replacement costs. Of course, there are other cost items included in the cost of power to the consumer, such as taxes, insurance, distribution and billing charges, but these costs are not evaluated in this report since they typically do not vary among the three cases evaluated. These components of the cost of power are shown in Figure 4.1. The annual plant capital expenses are fixed by the initial financing and are typically constant over the life of the plant. Operation, maintenance, and replacement fuel costs typically increase over time as affected by inflation and real price increases. As a result, the total annual cost of power progressively increases over time. 4.1.1 Capital Costs The capital costs represent the total cost of constructing a gene- rating facility. The capital cost estimates used in this analysis include 0 COST OF ELECTRICITY (MILLS/KWH) TOTAL ANNUAL COST ry�1�1♦� ♦�♦♦1111♦ i����11111♦ .................... _1�♦111♦11/11111�1111• _.�11♦♦♦11♦�♦1♦11111♦♦111♦ .������1�1�1�♦�1� ♦ • ♦ 1 ♦ � � �.1��1��1♦111♦11�1♦1111� TIME (YEARS) FIGURE 4.1. Components of the Total Annual Cost of Power 67 a interest and escalation during construction. It is assumed that the capital costs are repaid in equal annual payments over the payback period of the plant. The capital cost estimates used are in terms of constant October 1978 dollars. The total investment cost for the coal-fired and hydroelectric generating facilities are shown below. 100 MW Coal Steam Turbine 200 MW Coal. Steam Turbine 400 RA Coal Steam Turbine Watana Dam (795 MW) Devil Canyon Dam (778 MW) Total Investment Cost (million $) ($/kW) 245.4 2454 372.0 1860 646.8 1617 2501.2 3146 834.0 1071.9 SOURCE: Alaska Power Administration, August 1978. Transmission facility costs are presented in Table 3.7. 4.1.2 Heat Rate The heat rate is the ratio of the Btu's going into the plant as fuel to the kWh's of electricity produced by the plant. The heat rate is assumed to remain constant for all plant utilization factors over the lifetime of the plant. The heat rate for new coal-fired steam electric plants is assumed to be 10,500 Btu/kWh. 4.1.3 Operation, Maintenance, and Replacement Costs The operating, maintenance, and replacement (OM&R) costs include the administrative and general expenses as well as the interim replacement costs. All estimates are expressed in terms of October 1978 dollars. They are escalated at a rate equal to the rate of general inflation. The OM&R costs for coal-fired steam electric and hydroelectric generating facilities and transmission facilities are shown below. 100 MW Coal Steam Turbine 200 Mb! Coal Steam Turbine 400 MW Coal Steam Turbine Watana Dam (795 MW) Devil Canyon Dam (778 MW) New transmission facilities OM&R Costs (million $) ($/kW/yr) 3.76 37.6 5.7 28.5 9.8 24.5 0.74 0.94 0.73 0.94 - 2.0 SOURCE: Alaska Power Administration, August 1978. 4.1.4 Financing Discount Rate The financing discount rate represents the cost of capital to utility. A rate of 7.0% is assumed in this report. This is assumed to be an average of all types of financing available. 4.1.5 Payback Period The length of time over which the plant is financed is the payback period. This is assumed to be equal to the plant lifetime except for hydra projects where a 50-year payback period is assumed versus at least a 100-year plant lifetime (see Section 3.2.6). 4.1.6 Annual Plant Utilization Factor The plant utilization factor (PUF) is the ratio of the actual power production during a year to the theoretical maximum if the plant was to run 8760 hours at 100% capacity during the year. The annual plant utilization factor is highly variable depending upon many factors (e.g., forced outage rate, cost of power from alternative sources, and power production requirements). Because of this, it is necessary to explicitly'consider the effects of the PUF on the cost or power over the lifetime of a plant. As pointed out earlier, the PUFs used in the report are determined by the load/resource analyses (see Section 3.2.6). 4.1..7 Unit Fuel Costs Fuel costs for thermal generation plants are expected to increase over times following paths shown in Figures 4.2 through 4.4 for natural 10 0.1 FAIRBANKS (FMUS) BELUGA & HEALY 80 90 2000 10 20 FIGURE 4.2. Estimates of Future Coal Prices - 2% and 7% Escalation SOURCE: Alaska Power Administration, August 1978. 70 10. 1.0 0. 1 ANCHORAGE - KENAI BELUGA 70 80 — 90 00 10 20 FIGURE 4.3. Estimates of Future Natural Gas Prices - 2% and 7% Escalation SOURCE: Alaska Power Administration, August 1978 71 1.0 FAIRBANKS ANCHORAGE - KENA I PENINSULA 70 80 90 00 10 20 FIGURE 4.4. Estimates of Future Fuel Oil and Diesel Prices - 2% and 7% Escalation SOURCE: Alaska Power Administration, August 1978. 72 gas (Cook Inlet areas), coal and distiilable oi'l. Although natural gas is likely to become available in the Fairbanks region in the early to mid 1980's, Federal policies are expected to preclude its use for power gen- eration except for probing and the cost is indeterrpent at the present time. 4.1.8 General Inflation Rate Because of the uncertainty involved in estimating the future rate of inflation, two alternative cases are evaluated. A constant dollar case (0% inflation), and a 5% inflation case. 4.1.9 Construction Escalation Rate In this analysis,.construction costs are assumed to escalate at the same rate as the rate of general inflation. 4.1.10 Fuel Escalation Rate The fuel escalation rate is set to equal the general inflation rate plus 2%. 4.2. METHOD OF COMPUTING THE ANNUAL COST OF POWER FROM INDIVIDUAL GENERATING FACILITIES During any year the electrical power production is computed thus: EPPROi.= (ICAP * PUFi * HPY)/ 1000* where: ICAP = Installed capacity (MW) PUFi = Plat utilization factor in year i (fraction) HPY = Hours per year (8760 hours/year) * Parameters with the subscript i are assumed to vary each year over the lifetime of the plant. Parameters without the subscript are assumed to be constant over the lifetime of the plant. 73 The total annual costs (TAC) are composed of two elements: variable costs and fixed costs. In equation form: TACT = VARCi + FIXCi where: VARCi = Variable costs in year i ($/Year) FIXCi = Fixed costs in year i ($/Year) The variable costs consist only of the fuel costs. VARCi = FUELCi where: FUELCi = Fuel costs in year i ($/Year). In turn, fuel costs are computed: FUELCi = HEATR * EPPROi * UFUELCi where: HEATR = Heat rate (Btu/kWh) EPPROi = Electrical power production in year i (MMkWh) UFUELCi = Unit fuel costs in year i ($/MMBtu) The fixed costs consist of two factors. These factors can be writ- ten in the following equation form: FIXCi = INTAM + OMRCi where: INTAM = Interest and amortization (capital recovery) charges ($/Year) OMRCi = Operations, maintenance and replacement costs in year i ($/Year). The interest and amortization charges (INTAM) represent the annual debt service payments. 0 74 INTAM = CRF * TINVC where: CRF = Capital Recovery Factor TINVC = Total Investment Costs ($) The capital recovery factor is used to compute a future series of equal end -of -year payments that will just recover a present sum p over n periods at compound interest (IR). It is computed thus:(1, p.26) CRF = IR(1 + IR)PBP (1 + IR)PBP_1. where: PBP = Payback period (years) The methodology described in this section is incorporated into a ` computer model called ECOST4. 4.3 METHOD OF COMPUTING AVERAGE SYSTEM POWER COST Once the costs of producing power from the various individual gen- erating facilities in a system are known, a method of comparing the total cost of power from the three alternative system configurations evaluated in this report is needed. To compare the overall cost of power produced by these alternatives a relatively straightforward method is used. The costs of producing and transmitting power for each of the generation and transmission facilities are added together for each year during the period 1978-2010. In equation form: n TACj = ACi j i=1 where: TACj = total annual cost of power production for the system in year j ($) 75 ACij = annual cost of producing...or'transmitting power for facility i during year j ($) n = number of generation and transmission facilities in system. Likewise the amount of power produced by each facility during each year is summed to give a system -wide total. n TAPP = PP � i=1 ij where: TAPPj = total annual power production for the system in year j (kWhs) PPij = power produced by each generating facility i during year j (KWHs) n = number of generating facilities in system By dividing the total cost by the total generation an average cost of power for the system is obtained for each year. TAC j EPCOSTj = TAPP. J where: EPCOSTj = average system -wide cost of power for year j ($/kWh) By comparing the costs of power, the system producing the lowest cost of power can be selected. 4.4 RESULTS OF SYSTEM CASH FLOW AND POWER COST CALCULATIONS The results of the system cash flow and power cost calculations are pre- sented in this section. As pointed out earlier in the report three cases were evaluated: Case 1. All additional generating capacity assumed to be coal-fired steam turbines without a transmission interconnection between the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley load centers. 76 Case 2. All additional generating assumed to be coal-fired steam turbines including a transmission interconnection. Case 3. Additional capacity to include the Upper Susitna project (including transmission interconnection) plus additional coal as needed. Upper Susitna assumed to come on line in 1994. Tables 4.1 through 4.36 present the.cash flow and power cost calculated for the 3 cases. The contents of these tables are summarized below: Table Load Growth Inflation Number Area Scenario Case Rate %) 4.1 Anchorage Low 1 0 2 If " it 5 3 If 2 0 4 if 5 5 „ �� 3 0 6 If it ,t 5. 7 Medium 1 0 8 „ If 11 5 9 „ 2 0 10 it 5 11 It 3 0 12 ,f It 5 13 It High 1 0 14 .. „ It 5 15 „ „ 2 0 16 ,f „ I, 5 1711 3 0 18 It ,f If 5 19 Fairbanks Low 1 0 20 if It it 5 21 it it 2 0 22 ,f It It 5 23 If if 3 0 24 if it It 5 25 If Medium i 0 26 ,f 1f 11 5 27 ,f 1f 2 0 28 It " Is 5 29 it it 3 0 30 f if f 5 31 High 1 0 32 If If If 5 33 if If 2 0 34 it if 5 35 If3 0 36 If " 5 77 L. N 2 3= O Y 6 \ tl V n p Q\ N N Q M h to N n b M n L9 M c a v m n b u to to b b O r r - r N N N N N M M Q Q V' Q Q 1n V'1 b b t0 h b b b b'o h h h h h h A H L ad N N .�i � N C e- �+C N �t Y '^ b p b O CV M M Q O. to to to tool to b to L'Y l'Y Q Q Q cn b O b h N m M T C N d3 n IO O to a M h M T t!') n p a O ^ N m Q O 10 N M 1f1 N Fti y N N N N N M 04 tr Iu'1j I.hj O N Q n T .- M b CI .- Q .-- ti7 t0 tm0 1n to 10 b b 10 b b b b b b ID Y G' Q F•• V � M s IO dJ N r to b H Q• Q r 10M t0 to M h ^ b In 10b n p m Q M n h p N N h O Yi r r r N N N C") C7. M M G Q C Q Q Q to L'1 7 t0 L7 Lf) U O cu lu •*' 'a+�.. In 1 1 1 / 1 1 t m cD o o n h m to In c.l a m m o 0 0 0 0 0 0 L Y N i•+ 1 1 1 1 1 t 1 N N m m b b Q M M N O O O O n n n n n h h n h n h h H? O I 1 1 1 1 1 1 r r to In p p a N N 1t) p M M M C1 T m C1 C1 T Q Q Q Q Q - r rC•. t.7 r ^ V N C a�a v <• Q Q Q Q C' Q b b b b b b b b b b b 10 m O m 19 p m p m p p m m aB N i C F O O O C O O O O O O M. M M M M M M M PM M M M to b 10 t0 10 10 to 10 In 10 10 1O 3 N� SO. 6tc u Mtn 4H N b 10 b t0 ID 10 10 b b In to In K] to In In to to to In In O O O O 0 0 0 0 0 0 n h h h h h In h h h n n M M M M M M M M M M M I�1 r r r r r r r r r- r O II J 3 O 1Y' � 1 1 1 1 1 1 1 v v Q Q C el• Q C C Q Q Q Q Q Q v v Q Q v et• v Q v e• et d10 O 0 C 1-0 d i. 'm V E N a a a a a C1 a T T T C1 L, a a a C1 a a a a a T a 171 C1 2 N H 1 1 1 1 I i 1 0 0 0 0 0 0 0 0 0 O O O O 0 0 0 0 0 0 O O O 0 0 0 O 3 j G01 7 1 1 Q� 0 Ir i� IH M M C b h n b b If! b b Q1 h Q p a Q M b 10 h m a Q .�N 1 1 1 I ^ a r ^ ^ ^ Y V O L 1 I 1 1 M M M m M b m b N 10 Q O b Q a Q O M b O M b a N to p N to z Q 0 1 1 1 1 r N N M Q L7 ICI tp 10 n p p m a tT C1 T O O O U ,Q 1 � o a+ ai of 0 7 +1 U wId i N C7 M O O h n m to In N a p p CO n h n n n h b to {o b b to i �d 41 1 1 1 1 i 1 1 Q ci N 1 1 1 t 1 1 t r r O O m m b 10 cl Q N N N N N N N 1V N N N N fV N N N �I C7 OI 1 I 1 / 1 1 ! 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O Lt7 er LO O N C Lp Cl N h O r1• Cl C O VJ M 7 M .1 U I 1 1 1 1 1 N M M Q Q .. Q Lp h O O O ^ N N M Lp h o c GJ 4/ E N iY @ Q b LD O O O v N N tV N N Q Lp Lp O O O O O O Q Q 61 N Yf' I 1 1 1 I 1 lA Lf, Ltl LO Q1 LT r. tp ttt In LO LO LO 'o tJ Q N N O O O O O O C = lu O I 1 1 ] I 1 N N N N N N v Q Li]. LSl 10 Lp b Lp t0 N p .p CC' O O m C m V N N N P) M M M M M LCI N a al C N Y U N r LD Ol lf1 h h LO Lp .O' ? h O V O M h O m M N O COh Of CO CDt0 COQl COh LO b b h h N N N 1 1 1 1 1 1 X R M M M Q M M M M N N N N M N N N N N 1 1 1 1 1 , y � CL R O � V r o L O O N M C' Li'f t0 h O Ol O N M T LS'i t0 h m Cl O N M .T Ln O h O Cl O R h p q q O C O p q q O Ol 0• T a Cl a Cl Cl Cl rn N O O O O O O O O O d _ I 1 1 1 I O Cl CDC.1 1 •S ut 10 h O Cl O N M .T LL') 10 h m Cl O N :') C ut t0 h O Cl p h h W m m m O O O O C O O C< Of Ot Cl Ct T m m m O O O O O O O O O O �- 113 All e-ntries in the tables are in millions of dollars unless noted. The first column is the total cost of the existing capacity. This includes investment, OM&R, and fuel costs except coal costs after 1982-1983 as noted below. This column includes the cost of the combustion turbine units planned through 1984 in the Anchorage area. The cost of existing capacity is assumed to be the same for all load growth scenarios and system configurations. This assumption is warrented in this case for two reasons. First, an examination of the load resource analyses for the alternative load growth scenarios and cases reveals relatively little variation in the plant utilization factors among the various scenarios and cases. Second, the cost of operating the existing capacity is a relatively small part of the overall system costs in the 1990-2010 time period which is of primary interest in this report. The next three columns present the costs, for the new coal-fired capacity. The investment cost is the total of all the individual plant investments. The OM&R costs are the sum of all the OM&R costs of the individual plants. Entries in these two columns begin the same year as the first coal-fired plant comes on line. The coal costs include the coal costs of the new coal-fired capacity. In addition, the coal costs of the existing capacity are included in this column after 1982-1983. (It is subtracted out of the existing capacity after 1982-1983.) The next two columns present the costs for any new hydroelectric capacity that is added. These are the Bradley Lake project, the Watana dam and the Devil Canyon dam. As pointed out earlier the Watana and Devil Canyon costs are divided between the Anchorage -Cook Inlet area.and the Fairbanks -Tanana area in proportion to their relative energy consumption in 1994. The transmission system costs are shown in the next two columns. *These columns contain the investment and OM&R costs for all the transmission lines required. The total investment cost column represents the sum of the new coal- fired capacity investment costs, the hydroelectric capacity investment costs, and the transmission system investment costs. The total system cost is the sum of all the costs (not including the new investment cost column). The total system consumption figures are the same as 114 the energy demand forecasts presented in Chapter 3. The average cost of power in the total system costs divided by the total system consumption. The costs of power for the 5% inflation cases are presented in Figures 4.5 through 4.10. While the power costs are different (lower) for the 0% inflation cases. The relationships among the various cases are the same for both infla- tion rates. For the Anchorage -Cook Inlet load center construction of the interconnec- tion.(Case 2) reduces the cost of power compared to the case without an inter- connection (Case 1). In general, construction of the interconnection also reduces the total investment costs. For the Anchorage -Cook Inlet area inclusion of the Upper Susitna project into the system (Case 3) generally raises the cost of power above Cases 1 and 2 during the first 2 to 4 years after the Watana Dam comes on line but results in lower power costs during the 1996-2010 time period. This reduction in the cost of power is significant in most cases. The addition of the Upper Susitna project appears to slightly increase the total investment costs for the Anchorage -Cook Inlet area although this varies from year to year. For the Fairbanks -Tanana Valley load center construction of the inter- connection (Case 21, again generally reduces the cost of power compared to the case without a.n interconnection (Case 1). in general, construction of the interconnection also reduces the total investment costs. For the Fairbanks -Tanana Valley load center inclusion of the Upper Susitna project (Case.3) generally raises the cost of power above Case 2 for about 2 years after the Watana Dam comes on line but, as with the Anchorage -Cook Inlet. area, results in lower power costs during the 1996-2010 time period. The addition of the Upper Susitna. project appears to slightly lower the total investment cost. In some of the scenarios it is difficult to determine which case resul-," in the lowest total investment or the lowest cost of power over the entire 1978-2010 time period by looking at.the tables or figures. One method of.'com- paring investment or cost over a period of years is to compute the presen worth. In equation form: S i ^ t 30 28 26 24 22 10 8 6 4 2 1985 1990-,- 1995 2000 2005 2010 FIGURE 4.5. Power Costs for Anchorage Low Load Growth Scenario a 116 28 26 24 22 20 18 U 16 C� 14 W 0 12 10 8 6 4 2 E1 - -- CASE 2 ._........ CASE 3 1985 1990 1995 2000 2005 2010 FIGURE 4.6. Power Costs for Anchorage Medium Load Growth Scenario 117 3 2 2 24 22 20 N .�., 18 C � 16 14 0 12 10 8 6 4 2 r ° J. ---- CASE 1 --- CASE 2 ............ CASE 3 1985 1990 1995 2000 2005 2010 FIGURE 4.7. Power Costs for Anchorage High Load Growth Scenario 118 30 28 26 24 22 20 N .}., IS Ln 16 0 14 LW 12 10 8 6 4 2 1985 1990 1995 2000 2005 2010 FIGURE 4.8. Power Costs for Fairbanks Low Load Growth Scenario 119 30 28 26 24 22 20 18 �, 16 VI � 14 W 0 12 10 8 6 4 2 CASE 2 •••••••••••• CASE 3 1985 1990 1995 2000 2005 2010 FIGURE'4.9. 'Rower Costs for Fairbanks Medium Load Growth Scenario 120 30 28 26 24 22 20 V3 18 16 0 14 0 12 a 10 8 6 4 2 ® ® ® CASE 2 ............ CASE 3 1985 1990 1995 2000 2005� 2010 FIGURE 4.10. Power Costs for Fairbanks High Load Growth Scenario 121 n 1 PW = L APC• i=n (1+r)i where: PW = Present worth of the cost of power APCi = Average power cost in year i r = Discount rate n = Total number of years. Using this formula the total investment cost and the average power cost over a period of years can be more easily compared. A 70/' discount rate is used in these analyses. The results for each of the load growth scenarios for both of the load centers are briefly discussed below. Anchora6e-Cook Inlet - Low Load Growth The present worth of the total investment and the present worth of average power costs are shown below. Reference P.W. Total P.W. Average Case Table No. Investment ( ) Power Costs (�/kWh) 1 2 2329 .78 2 4 2251 76 3 6 2504 70. Case 3 results in the lowest cost of power followed by Case 2 and Case 1. Case 2 gives the lowest overall investment costs while Case 3 results in the highest -investment costs. 122 Anchorage -Cook Inlet - Medium Load Growth' Reference P.W. Total P.W. Average Case Table No. Investment ($} Power Costs (t/kWh) 1 8 3920 83 2 10 3930 83 3 12 3920 77 The present worth of the total investment is almost identical for all three cases. The present worth of the cost of power is the same for Cases 1 and 2,.while the present worth power cost for Case 3 is lowest. Anchorage -Cook Inlet - Nigh Load Growth Reference P.W. Total P.W. Average Case Table No. Investment ( ) Power Costs (�/kWh) 1 14 7053 86 2 16 6837 85 3 18 7084 83 Again Case 3 results in the lowest present worth for the cost of power. For this scenario Case 2 results in the lowest present worth investment with Cases 1 and 3 slightly higher. Fairbanks -Tanana Valley - Low Load Growth Reference P.W. Total P.W. Average Case Table No. Investment (5) Power Costs (�/kWh) 1 20 666 110 2 22 699 113 3 24 742 104 Case 3 gives the lowest cost of power while Case I gives the lowest investment cost. Case 3 results in the highest present worth•investment cost. 123 Fairbanks -Tanana Valley - Medium Load Growth Reference P.W. Total P.W. Average Case Table No. Investment (S) Power Costs (t/kWh) 1 26 1128 117 2 28 1042 ill 3 30 970 99 Again Case 3 results in the lowest present worth cost of power. In this scenario however, Case 3 also gives the lowest present worth total investment costs. Fairbanks -Tanana Valley - High Load Growth Reference P.W. Total P.W. Average Case -Table No. Investment ( ) Power Costs (�/kWh) 1 32 1642 115 2 34 1587' 110 3 36 1527 703 Again Case 3 results in the lowest present worth cost of power and the lowest present worth total investment. a 124 REFERENCES - CHAPTER 4 1. Taylor, G. A., Managerial and Enqineerinq Economy, D. van Nostrand Company, Inc., Princeton, NJ, 1964. 125 • Y+.._. FED A AL ENERGY REGULATORY COMMISSION REGIONAL OFFICE 555 BATTERY STREET, ROOM 415 ',! l C it -- J , 3 3 SAN FRANCISCO. CA 94111 i j � i -i.• is � _� o March 6, 1979 Mr. Robert J. Cross Administrator Department of Energy Alaska Power Administration P. 0. Box 50 Juneau, Alaska 99802 Dear Mr. Cross: This will respond to your letter of February 2, 1979, requesting our informal review and comments on your Upper Susitna Project Power Market Draft Report. Although we were unable to make an in-depth review of the draft report due to time and staffing limitations, we do wish to make the following comments: Page 95, second paragraph, third sentence. FERC estimated costs are as Of July 1, 1978, not October 1978 as stated. Page 95, second paragraph, last sentence. The San Francisco Regional Office of FERC did include cost adjustments for Alaska conditions in its power value study as it routinely does for all studies in Alaska. Page 95, last paragraph, last sentence. The investment cost estimates of the Fairbanks plant are $14.75/kW (@ 5.75% financing) and $1510/kW (@ 6.875% financing). Cost estimates of the Anchorage -Kenai area plant are $1240/kW (@ 7.94% financing) and $1220/kW (@ 6.875% financing). Page 96, Oil and Natural Gas. Our thoughts on this subject were stated in our October 31, 1978, letter to the District Engineer, Alaska District, Corps of Engineers. In that letter we stated tha t oil -fired red combine d cycle and regenerative combustion turbine plants were significantly less cost) than alternative coal-fired plants for the Y a Upper Susitna P R' Ba sin. asin. We are not able to state, however, which alternative is the more probable source. The determining factors would be the Alaska fuel situation and the interpretation of the Fuel Use Act. 1 Mr. Robert J. Cross - 2 - March 6; 1979 While the Fuel Use Act prohibits the use of oil or natural gas as primary fuel for electrical generation, the Department of Energy, Economic Regulatory Administration (ERA), is promulgating regulations which will provide for various exemptions. The regulations are ex- pected to be issued in May. We suggest that you contact ERA on this matter. Page 105, item 5. The retirement schedule for combustion turbine is stated to be 20 years. Most studies -in the Continental United States use 30 years. Pages 159 and 160, Assessment of Feasibility. A cost estimate of Copper Valley Electric Association's purchase of Upper Susitna power would be useful to this discussion. Appendix, page 21, 3.2.4, Transmission Losses. The 1.5% for energy loss appears to be low. We appreciate the opportunity to.review and comment on your draft report. Sincerely, TEA�neTN�eb�lett Regional Engineer °'~ + L 1 D 30 1,14OU-310lieue Pacific Northwest Laboratories } r ti, P.O. Box 999 y'} Richland, Washington 99352 Telephone (509) 942-4745 February 27, 1979 Telex32-6345 Mr. Robert Cross Department.of Energy Alaska Power Administration P. 0. Box 50 Juneau, AK 99802 Dear Mr. Cross: Thank you for the opportunity to comment on your Draft Power Market Analysis. Both Ward Swift and I read it over and came up with only a few minor comments. The primary focus of our review was the consistency between the body of the report and our background analysis presented in Appendix 3. 1. Page 4, 2nd paragraph - The alternative on-line dates of 1990, 1992, and 1994 seem to refer to the interconnection on-line dates for high, medium, and low load growth cases respectively. I believe those dates should be 1986, 1989, and 1991. This would be consistent with the dates given in the last line on page 109. 2. Page 8, Table at bottom - It appears that the costs of power listed for Case 1 should be the same numbers listed for the Case 1 of the combined system in the table at the top of page 111.(i.e., the costs of power should be 6.6, 6.9, and 7.5¢/KWh rather than 7.0, 7.0 and 6. W KWh for the high, medium, and low load growths respectively). 3. Page 17, Installed name plate capacities - As pointed out on page T9 the totals differ from those used by us in Appendix 3. Most of the differences are relatively minor. The only major difference seems to be the capacity listed for the Chugach Electric Association. As you indicate these differences are due to recent changes in plans to install new capacity. The difference would have a minor impact on the 1978 through 1985 results and practically no impact on the results after 1985. Mr. Robert Cross February 27, 1979 Page 2 4. Pages 52, 59, 80, and Appendix 3 page 8 - Annual.Load Factors - On page 42 and Appendix 3, page 8, both reports are generally in agree- ment that the annual load factor is presently between 46-52%. In Appendix 3 we go on to say that it appears the annual load factor will remain in the 50-52% range during the time horizon of the re- port. On page 80 it is stated that for planning purposes it is assumed that the annual system load factor will be in the range of 55-60% by the latter part of the century. If the load factor is defined as: ALF = GEN CAP * 8.760 where: ALF = Annual load factor (fraction) GEN = Generation (MW) CAP = Capacity (GWH) and use data for the year 2000, low load growth as presented on page 59 we compute an annual load factor of 51%. i.e. ALF = i 86424• 0 = .51 This is lower than the 55-60% mentioned on page 80. 5. Page 95, Heady II plant costs - It would be good to point out that the GVEA estimate is probably in terms of 1985$. 6. Page 101-102, Conclusions - I think your summary of the alternatives available to Alaska is good. Mr. Robert Cross February 27, 1979 Page 3 7. Cover Sheet, Appendix 3 - Enclosed are different cover pages for our report presented in Appendix 3 and the Appendices to our report. Please replace the cover pages you presently have. Thank you for the opportunity to comment on the report. Sincerely, J. Jay Jacobsen Energy Assessment Unit Energy Systems Department JJJ:tw Enclosures f Etc tNfi• DEPARTMEN-T;OF THE ARMY ;.. � ALASkCAL21S�'fi'1�}SG�Cp,��t�32PS OF ENGINEERS j ttP 0: �0�C7002 +L 1e4ANQ,H0RA,GE..ALAS,KA 99510 • f REPLY TO ATTENTION OF: NPAEN-PL-R 19 YAR 1979 Mr. Robert J. Cross Administrator Alaska.Power Administration P.O. Box 60 Juneau, Alaska 99802 Dear Mr. Cross: I am writing to advise you of actions taken in response to your comments on the draft Susitna Supplemental Feasibility Report and also to comment on your draft Power Market Analysis. Your letter of 26 January 1979 transmitting your comments on our draft' report arrived during the final report printing. Any delay at that point would have caused us to miss our deadline which I was unwilling to permit except under extreme circumstances. On the verbal assurance from your staff that there was nothing of such gravity that the integ- rity of the report would be jeopardized, the decision was made to pro- ceed with the printing as scheduled. I regret that your written comments did not arrive sooner, because the report would have benefited from their incorporation. I am especially sensitive to your Contention.that insufficient credit was given where APA materials were used. In the future, my staff will be more careful in this regard. Our review of your excellent draft Power Market Analysis has resulted in only one comment. On page 4 you note that the more costly gravity structure for Devil Canyon is "currently proposed" by the Corps. This is inaccurate in that the gravity structure was presented to insure that estimated costs were sufficient to cover a range of possible foundation conditions at the Devil Canyon site. With appropriate word changes to correct this matter, we find nothing else requiring alteration. Since the Main Report and Appendix Part 1 are already in Washington, please transmit 20 copies of the final Appendix Part 2 to NQDA (DAEN-CWP-W), NPAEN-PL-R Mr. Robert J. Cross 19 MAR 1979 Washington D.C. 20314; 2 copies to Division Engineer, North Pacific Corps of Engineers, 210 Custom House, Portland, Oregon 97209, A'rTN; NPDPL; and the remaining 138 copies to the Alaska District, ATTN: NPAEN-US. If you have any questions, Mr. Chuck Bickley at (907) 752-5135 can pro- vide assistance. Sincerely yours, tRi EL T. Si Lt Colonel, Corps of Engineers Acting District Engineer G,�f ALP 0 STaresuFRtPLY TO NIPAEN-PL-R DEPARTMENT OF THE ARMY ALASKA DISTRICT, CORPS OF ENGINEERS P.O. BOX 7002 ANCHORAGE, ALASKA 99510 19 MAR 1979 Mr. Robert J. Cross Administrator Alaska Power Administration P.O. Sox 50 Juneau, Alaska: 99302 Dear fir. Cross: I an, writing to advise you of actions taken in response to your comments on the draft Susitna Supplemental Feasibility Report and also to comment on your draft Power Iiarket Analysis. Your letter of 26 January 1979 transmitting your comments on our draft report arrived during the final report printing. Any delay at teat point Mould have caused us to miss our deadline which I was unwilling to permit except under extreme circumstances. On the verbal assurance from your staff that there.eras nothing of such gravity that the integ- rity of the report would be jeopardized, the decision was. ;red& to pro- ceed with the printing as scheduled. I regret that your written comments did not arrive sooner, because the report would have benefited from their incorporation. I am especially sensitive to your contention that insufficient credit was given where APA materials were used. In the future, my staff will be more careful in this regard. Our review of your excellent draft Power Market Analysis has resulted in only one comment. On page 4 you note that the more costly gravity structure for Devil Canyon is "currently proposed" by the Corps. This is inaccurate in that the gravity structure was presented to insure that estimated costs were sufficient to cover a range of possible foundation conditions at the Devil Canyon site. With appropriate word changes to correct this matter, we find nothing else requiring alteration. Since the :"fain Report and Appendix Part 1 are already in �ashirgtan��g`� e. transmit 20 copies of the final Appendix Part 2 to HQDA (DAE[-C!,JP-I, °, ti U rj 7,�,76-1976 NPAEN-PL-R Mr. Robert J. Cross r9 I ARC 1W Washington D.C. 20314; 2 copies to Division Engineer, 'forth Pacific Corps of Engineers, 213 Custom ilouse, Portland, Oregon 972`09, ATT-1; NPDPL; and the remaining 133 Copies to the Alaska District, ATT=;: If you have any questions, Mr. Chuck Bickley at (907) 752-5135 can pro- vide assistance. Sincerely yours, ,aJLTC. Veme c T. SnAffi `gERNELLE T. SMITH L` Colonel, Corps of Engineers Acting District Engineer 2 F George M. Sullivan Mayor Alunidpal Li ,9 r +� r , 1200 EAST FIRST AVENUE `)4'R AURAM� 4USKA 99501 TELEPHON,9p1,27 7671 { ,� 0 March 1, 1979 UWEIR ADM. Robert.J. Cross, Administrator Department. of Energy Alaska Power Administration P..O'. Box 50: Juneau, Alaska 99802 Dear Mr. Cross: i 7'ya This letter responds to your letter of February 2, 1979, which requested informal comments on the draft Power Market Analyses of the Upper Susitna River Project. Mr. Stahr is outof town and I am writing without knowledge of his personal opinion and comments. The Municipal Light and Power's staff- comments appear in the two attached memorandums. Mr.- Stahr may forward more comments upon his return'. Thank you for the opportunity to review the draft. If you have any questions or -want more comments please do not hesitate to con- tact us. PROVIDE FOR TOMORROW, SAVE ENERGY TODAY. Municipality ®f Anchorage MEMORANDUM DATE: March 1, 1979 TO: �j% Thomas R. Stahr, General Manager, ML&P FROM: 1% 0 Max Foster, Revenue Requirements Supervisor, ML&P SUBJECT: DOE-APA Upper Susitna River Project Power Market Analyses This memo comments on the Alaska Power Administration's Upper Susitna River Project Power Market Analysis draft dated January 1979. My impression is that the demand projections for the Anchorage area are conservative. I also think that the installed cost of coal plants is conservative. The Susitna project costs are probably the most reliable cost estimates appearing in she report. I am not happy with the methodology developing the cost of coal. I think coal could actually cost much more than $1.00 to $1.50 per million BTU. The inflation rates used in the analysis (0% and 5%) seem low in light of recent trends. Significantly, despite the conservative assumptions contained within the report, the Susitna project represented the least cost option in every case. My page by page review of the report elicited the following comments. Page 37 - The lack of correlation to weather and price disburbs me. It may indicate improper equation specification caused by omitting important variable or failing to insert dummy variables in the regression equations to correct for cyclical abnormalities. Additionally, it seems to m� demand projections ley rate class would be more statistically ,Significant. Calf-lQCs 5 "t yG// CQ % la 17 Page 77 - The shape of the Anchorage Area load duration curve suggests that a heavy proportion of generation for the area could be large base load increments. This is very favorable for hydroelectric development. Page 94 - I don't like the treatment of 0 & M costs. How does this relate to prosent actual Anchorage labor costs and trends? I think the prices should be measured directly, not arbitrarily increased. Page 150 - The pipline terminal's 37.5 MW generation plant is not interconnected with CVEA. It is not a cogeneration facility. Memo to Thomas R. Marcia i, 1975 Page 2 Stahr, General Manager Appendix 3, Pages 66 to 75 - Where is the present worth or annualized cost of power computed? This is a major change from the earlier ECnSt2 model. I think the present worth analysis is an important part of any power cost analysis. In general, the analysis seems complete. The conclusions echo those of, previous studies. From an economic prospective, the Susitna Project is unquestionably justified. Its time to stop revising feasibility analyses and get on with 11-censing and construction.'" MV : bw C"-FEI ED JAY S. HAMMOND i 1 GOVERNOR OIFFIC , (lw ' 1 OVEIIi�Ton rt�� i. DIVISION Of POLICY DEVELOPMENT AND PLANNING POUCH AD-JUNEAU 99811 PHONE 465-3577 March 23, 1979 Mr_ Jim Cheatham U.S Department. of Energy Alaska Power Administration P.0_ Box.50 Juneau,' AK 99801 Subject: Power Market Analysis - Draft on the Upper Susitna River Project State I.D. No. 79020902 Dear Mr.. Cheatham: The Alaska.S'tate.Clearinghouse as co leted-4'revitewl.on the subject project. ,+. "' M,,,.. Y,., x.+'" •�� T°".^„ .�. �`�. The. State:. Clearinghouse -.ha no comment on this project., a a This letter'will satisfy,,the�, review requirements -of, the office of Management and Budget`s Circular A-95 Sincerel , Jerr Madden , CState-Federal Coordinator, a` ..q '.0 y >',, ;Municipality of Anchorage MEMORANDUM DATE: February 15, 1979 TO: Thomas R. Stahr, Gendral Manager FROM: H. C. Purcell, Assistant Chief Engineer SUBJECT: DOE APA UPPER SUSITNA RIVER PROJECT POWER MARKET ANALYSES I have reviewed the January 1979 draft of this report and find nothing controver- sial in it. There is an error, and there are a few points I will comment on, none of which, however, affect the conclusions reached. On page.33, Table 5 shows AML&P generation in 1965 as 156.2 GWH. This results in area growth 1964-1965 of 34.4% and 1965-1966 growth of -0.6%. AML&P generation in 1965 was actually 101.5 GWH. This changes the area total in 1965 to 407.0 GWH, 'J3�` 1964-1965 growth to 18.5% and 1965-1966 growth to 12.7%. pt b On pages 37 and 38, the report states ". correlations with weather seem- ed indeterminable or of little significance." and "Energy use and weather com- parisons were inconclusive." This does not agree with my work or with plain common sense. Growth between 1973 and 1977 is used to forecast energy requirements. In three of these four years, 1974, 1976 and 1977, the weather was warmer than normal.. Ignoring the influence,of weather depresses the growth rate. However, this does not affect the report materially, since it winds up using three different growth rates (low,.medium and high) in its market analyses. It is interesting that the situation hasn't changed in twenty years. Page 98 lists six major hydro projects with much better economics than the Upper Susitna. But they all remain tied up by "major environmental and land use problems." On pages 100-102 the report brushes off exotic energy sources as "not realistic planning alternatives ." I applaud this, but suspect that much more work will have to be done to convince the vocal proponents of "natural energy." On page.104 the report specifies "System reserve capacity of 25 percent for non -in- terconnected load centers and 20 percent for interconnected systems." I checked these numbers against the PROBS runs I. made in connection with DOE. regulations on transitional facilities. For, the Anchorage area at present, PROBS showed a loss, of load probability of 0.2 days per year with a peak load of 466.3 MW. On the same basis, 25% reserve.capacity would correspond to a peak load of 468.8 MW. 25% reserve capacity would result in LOLP only slightly over 0.2 days per year. With the larger interconnected system ten or twelve years in the future, 20% reserve capacity will probably provide reasonable LOLP. Page 34 of the Battelle Informal Report schedules a 200 MW steam plant to be on line in 1982, three years hence. Yet Battelle page 22 says "the 5 to 6 year sche- duling period [from final site selection to commercial operation] appears reason- able." Either CEA is about to break ground for its coal-fired steam plant or Battelle's dates are inconsistent. Again, however, it doesn't really matter. The relative economics of Susitna vs. coal-fired steam would not be affected. H_ C. Ourcel�IV re. - kloczlei