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Home My WebLink AboutAPA146Tyo'L.. " ~ Tvon.e J.akl'! ~ SuSttn .. u .. I .. Lak-eLou.ist!- KEY MAP SCALE I: 3,000,000 ALASKA POWER AUTHORITY Anchorage -Fairbanks Transmission lntertie Economic Feasibility Study Report December 1979 ~ INTERNATIONAL ENGINEERING COMPANY, INC. • : ~ ROBERT W. RETHERFORD ASSOCIATES Chapter 1 2 3 4 5 CONTENTS ABBREVIATIONS INTRODUCTION SUMMARY AND CONCLUSIONS 2.1 Study Summary 2.2 Conclusions LOAD FORECASTS FOR RAILBELT AREA 3.1 Energy and Demand Forecasts Range 3.2 Demand Forecasts for Gener<Ition Planning .i 3.3 References SELECTION OF INTERTIE ROUTE 4.1 Review of Earlier Studies 4.2 Survey of Alternative Corridors 4.3 Preferred Route for Transmission Intertie 4.4 Field Investigations 4.5 Preliminary Environmental Assessment 4.6 References TRANSMISSIGN LINE DESIGN 5.1 Basic Design Requirements 5.2 Selection of Tower Type Used in the Study 5.3 Design Loading Assumptions 5.4 Tower Weight Estimation X 1-1 2-1 2-4 3-1 3-8 3-10 4-1 4-1 4-1 4-3 4-4 4-11 5-1 5-1 5-2 5-2 Chapter 5 6 7 8 CONTENTS TRANSMISSION LINE DESIGN (Continued) 5.5 Conductor Selection 5.6 Power Transfer Capabilities 5.7 HVDC Transmission System 5.8 References SYSTEM EXPANSION PLANS 6.1 Generation Planning Criteria 6.2 Multi-Area Reliability Study 6.3 System Expansion Plans 6.4 References FACILITY COST ESTIMATES 7.1 Transmission Line Costs 7.2 Substation Costs 7.3 Control and Communications System Costs 7.4 Transmission Intertie Facility Costs 7.5 Cost of Transmission Losses 7.6 Basis for Generating Plant Facility Costs 7.7 Generating Plant Fuel Costs 7.8 MEA Underlying System Costs 7.9 Construction Power Costs for the Upper 5-3 5-4 5-4 5-5 6-1 6-4 6-10 6-12 7-1 7-4 7-5 7-5 7-5 7-6 7-7 7-8 Susitna Project 7-8 7.10 References 7-9 ECONOMIC FEASIBILITY ANALYSIS 8.1 Methodology 8.2 Sensitivity Analysis 8.3 Economic Analysis 8.4 References i i 8-1 8-2 8-3 8-8 ..,T_-,--, CONTENTS Chapter Page 9 FINANCIAL PLANNING CONCEPTS 9.1 Sources of Funds 9-1 9.2 Proportional Allocations Between Sources 9-5 r-9.3 Allocated Financial Responsibility for Participants 9-7 9.4 Costs for Reserve Sharing and Firm Transfer 9-11 9.5 Financial Plans for Future Staged Development 9-12 9.6 References 9-13 ,....., 10 INSTITUTIONAL CONSIDERATIONS ,... 10.1 Present Institutions and Rail belt I Utilities 10-1 10.2 Alaskan Interconnected Utilities 10-3 r"" 10.3 References 10-5 !"""' APPENDIXES /"""" Appendix '*""" A NOTES ON FUTURE USE OF ENERGY IN ALASKA A-1 !"""' B TRANSMISSION LINE COSTS ANALYSIS PROGRAM (TLCAP) B.1 General Description B-1 -8.2 Computer Program Applications for Optimum Transmission Line Costs B-2 !"""' B.3 TLCAP Sample Outputs B-6 r-. c MULTI-AREA RELIABILITY PROGRAM (MAREL) C-1 i i i CONTENTS Appendix Page D DATA AND COST ESTIMATES FOR TRANSMISSION INTERTIE AND GENERATING PLANTS D-1 D.l Data and Cost Estimates for Trans- mission Intertie D-1 D.2 Data and Cost Estimates for Gene- rat 1 ng Plants D-13 D.3 Data and Cost Estimates for Supply of Construction Power to Upper Susitna Project Sites D-24 D.4 Alternative Generating Plant Fuel Costs D-38 E TRANSMISSION LINE ECONOMIC ANALYSIS PROGRAM E-1 F TRANSMISSION LINE FINANCIAL ANALYSIS F-1 iv -i r r -' Table 3-1 3-2 3-3 3-4 3-5 3-6 5-1 6-1 6-2 6-3 6-4 6-5 6-6 6-7 6-8 TABLES Anchorage-Cook Inlet Area Utility Forecasts and Extrapolated Projections Fairbanks-Tanana Valley Area Utility Forecasts and Extrapolated Pojections Combined Utility Forecasts for Railbelt Area Load Forecast for Upper Susitna Proj- ect by Alaska Power Administration Load Demand Forecasts for Railbelt Area to Determine Statistical Average Forecast Peak Load Demand Forecasts for Railbelt Area with Range Limits for Sensitivity Analysis Conductor Size Selection Criteria Existing Generation Sources, Anchorage- Cook Inlet Area Existing Generation Sources, Fairbanks- Tanana Valley Area Load Model Data, Anchorage Area, Probable Load Forecast Case Load Model Data, Fairbanks Area, Probable Load Forecast Case Load Model Data, Anchorage Area, Low Load Forecast Case Load Model Data, Fairbanks Area, Low Load Forecast Case Loss of Load Probability Index for Study Cases IA and ID, Probable Load Forecast Case Loss of Load Probability Index for Study Case IB, Probable Load Forecast Case v Page 3-11 3-12 3-13 3-14 3-16 3-17· 5-6 6-14 6-15 6-16 6-17 6-18 6-19 6-20 6-21 Table 6-9 6-10 6-11 6-12 7-1 7-2 7-3 7-4 7-5 8-1 to 8-6x 9-1 9-2 9-3A and 9-3B A-1 TABLES (Continued) Loss of Load Probability Index for Study Case IIA, Probable Load Forecast Case Loss of Load Probability Index for Study Case IA and ID, Low Load Forecast Case Loss of Load Probability Index for Case IB, Low Load Forecast Case Loss of Load Probability Index for Case IC, Probable Load Forecast Case Cost Summary for Intertie Facilities Present Worth of Intertie Line Losses, 1984-1997 Study Period Cost Summary for Generating Facilities Summary of Alternative Generating Plant Fuel Costs Alternative Costs for Construction Power Supply to Watana and Devil Canyon Hydropower Sites during Con- struction of Upper Susitna Project Differential Discounted Value of Base Year (1979) Costs Alternative Disbursements of Capital Investment for Generation Expansion Allocation of Total Project Costs Between Participants to Alaskan Intertie Agreement Allocated Costs for Reserve Capacity Sharing and Firm Power Transfer MEA Statistical Summary -Past, Present and Future vi Page 6-22 6-23 6-24 6-25 7-10 7-11 7-12 p:.--:.;o"., 7-13 7-14 8-9 to 8-21 9-14 9-15 9-16 and 9-17 A-4 - r -I r I Figure 3-1 3-2 3-3 3-4 3-5 3-6 3-7 3-8 4-1 4-2 4-3 5-l 5-2 FIGURES Comparative Net Energy Generation Fore- cast for Combined Utilities and Indus- trial Load -Railbelt Area Projected Range of Net Energy Genera- tion Forecast for Combined Utilities and Industrial Load, Railbelt Area Projected Range of Net Energy Gener- ation Forecasts for Combined Util- ities and Industrial Load, Anchorage- Cook Inlet Area and Fairbanks-Tanana Valley Area Comparative Annual Peak Demand Fore- casts for Combined Utilities and Industrial Load, Railbelt Area Projected Range of Annual Peak Demand Forecasts for Combined Utilities and Industrial Load, Railbelt Area Annual Peak Demand Forecasts for Com- bined Utilities and Industrial Load, Anchorage-Cook Inlet Area and Fairbanks- Tanana Valley Area Peak Load Demand Forecast with Range Limits for Sensitivity Analysis~ Anchorage-Cook Inlet and Fairbanks-Tanana Valley Area Loads Peak Load Demand Forecast with Range Limits for Sensitivity Analysis~ Railbelt Area Loads Nenana-Fairbanks-Tanana Transmission System Anchorage-Matanuska-Susitna-Glenallen- Valdez Transmssion System Cook Inlet-Kenai Peninsula Transmission System 230 kV Tangent Tower 345 kV Tangent Tower vii 3-18 3-19 3-20 3-21 3-22 3-23 3-24 3-25 4-12 4-13 4-14 5-7 5-8 Figure 6-1 6-2 6-3 6-4 6-5 6-6 6-7 6-8 6-9 6-10 6-11 6-12 7-1 FIGURES (Continued) Non-Coincident 1975 Peak Demands, Anchorage and Fairbanks Areas Independent System Expansion Plans, Anchorage and Fairbanks Areas, Probable Load Forecast Case Interconnected System Expansion Plan, Anchorage-Fairbanks Area without Susitna Project, Probable Load Forecast Case, Case IA and ID Interconnected System Expansion Plan, Anchorage-Fairbanks Area with Firm Power Transfer, Probable Load Forecast Case, Case IB Interconnected System Expansion Plan, Anchorage-Fairbanks Area with Upper Susitna Project, Probable Load Expansion Case, Case II Independent System Expansion Plan, Anchorage- Fairbanks Area, Low Load Forecast Case Interconnected System Expansion Plan, Anchorage-Fairbanks Area, Low Load Forecast Case, Case IA and ID Interconnected System Expansion Plan, Anchorage-Fairbanks Area, Low Load Forecast Case with Firm Power Transfer, Case IB Case I -Alternative A and B Case I -Alternative C Case I -Alternative 0 Case II Construction Plan for Upper Susitna Project viii Page 6-26 6-27 6-28 6-29 6-30 6-31 6-32 6-33 6-34 6-35 6-36 6-37 7-15 r r - - Figure B-1 D-1 and D-2 D-3 D-4 FIGURES {Continued) Transmission Line Cost Analysis Program Methodology Nomogram Calculates Economy of Scale in Power Plants Estimates of Future National Gas Prices Estimates of Future Coal Prices ix Page B-4 D-45 and D-46 D-47 D-48 ac alternating current ACF annual cost of fuel ACSR aluminium conductor, steel reinforced AlA Alaskan Intertie Agr~ement AML&P Anchorage Municipal Light and Power Company API\ Alaska Power 1\uthority A.R.R. Alaska Railroad AVF avcraye value factor bpd barrels per day BTU British thermal units C[/\ Chugilch Electric Association, Inc. CFC Cooperative Finilnce Corporation de direct current DOE U.S. Department of Energy EEl Edison Electric Institute FFB Federal Finance Bank FGD flue gas desulphurization FOfl forced outage hours FMUS Fairbanks Municipal Utility System ft feet gal ga 11 on GVEA Golden Valley Electric Association, Inc. GWh gigawatt-hours (million kilowatt-hours) HEA Homer Electric Association, Inc. IIVIJC high voltage, direct current IArAT Inter·ior Alaska Energy Analysis Team IECO International Engineering Company, Inc. IEEE Institute of Electrical and Electronics Engineers I SER kcmi 1 kV Institute for Social and Economic Research thousand circular mils kilovolts kVa kilovolt-amperes kW kilowatts kWh kilowatt-hours ABREVIATIONS X LNG liquid nitrate gas LOLP loss of load probability MAREL Multi-Area Reliability, a computer program developed by PTI MBTU Million British thermal unit MEA MVA MW NESC NOx O&M ORV PCF P.l. PRS PTI REA RI RWRA SIC SCGT Sll Matanuska Electrical Association, Inc. megavolt-amperes megawatts National Electrical Safety Committee nitrous oxide operations and maintenance off-road vehicle Plant capacity factor point of intersection power requirements studies Power Technology, Inc. Rural Electrification Administration radio interference Robert W. Retherford Associates, Inc. single circuit simple cycle combustion turbine surge impedance loading TLCAP Transmission line Cost Analysis Program, a computer program developed by IECO TLEAP Transmission line Economic Analysis Program, a computer program developed by I ECO TLFAP Transmission line Financial Analysis Program, a computer program developed by IECO tpy tons per year TVI television interference USA USGS VAR United States of America United States Geological Survey volt-amperes reactive CHAPTER 1 INTRODUCTION CHAPTER 1 INTRODUCTION This report presents a determination of the economic feasibility for a transmission line interconnection between the utility systems of the Anchorage and Fairbanks areas. It includes an objective evaluation of the specific conditions under which the intertie is economically feasi- ble. An interconnection between the two previously independent power systems will reduce total installed generation reserve capacity, provide means for the interchange of energy, reduce spinning reserve require- ments, and provide the means for optimum economic dispatch of generating plants on the interconnected system basis. The later integration of the Upper Susitna Hydropower Project into the interconnected Anchorage-Fairbanks power system would serve to increase the benefits already available from early operation of the intertie. The work described in this report was performed under the authority of the 26 October 1978 contract between the Alaska Power Authority and the joint-venture of International Engineering Company, Inc. (IECO) and Robert W. Retherford Associates (RWRA). Alternative system expansion plans were developed and analyzed during this study for each of the following areas: • Independent Anchorage area • Independent Fairbanks area • • Interconnected Anchorage-Fairbanks area (generation reserve sharing option) Interconnected Anchorage-Fairbanks area (generation reserve sharing and firm power transfer option) 1 Interconnected Anchorage-Fairbanks area (with inclusion of the Upper Susitna Hydropower Project) 1 - 1 This study confirms the economic feasibility of the Anchorage-Fairbanks transmission line interconnection as well as the possibility of an early implementation date for the project, prior to longer-range development of the Upper Susitna Hydropower Project. This study also establishes additional intertie benefits from the supply of construction power to the sites of the Upper Susitna Hydropower Project. It also evaluated potential benefits from firm power supply to Matanuska Electric Associa- tion•s system at the intermediate Palmer substation of the intertie. Preliminary financial and management plans for the implementation of the project were developed and are presented in the last two chapters of this report. An Intertie Advisory Committee, composed of managers of Railbelt area utilities with the chairmanship of the Executive Director of the Alaska Power Authority, was formed. During the performance of this study three Intertie Advisory Committee meetings were held (4 December 1978, 8 Jan- uary 1979, 14 February 1979, and 18 May 1979) to review factors related to the intertie and to discuss preliminary findings of this study. The following Railbelt utilities were represented on the Intertie Advisory Committee: • Anchorage Municipal light & Power (AML&P) • Copper Valley Electric Association (CVEA) • Chugach Electric Association (CEA) • Fairbanks Municipal Utility System (FMUS) • Golden Valley Electric Association (GVEA) • Homer Electric Association (HEA) • Matanuska Electric Association (MEA) The Consultants wish to acknowledge the valuable information, comments, and support received from the managers and engineers of the Railbelt utilities, and the Alaska Power Administration during the performance of this economic feasibility study. 1 - 2 ,.,.,-. CHAPTER 2 SUMMARY AND CONCLUSIONS -\ CHAPTER 2 SUMMARY AND CONCLUSIONS The purpose of this economic feasibility study is to determine the conditions under which a transmission interconnection between the util- ity systems of Anchorage and Fairbanks would be economically feasible. Following are the important aspects of work performed and the conclu- sions of this study. 2.1 STUDY SUMMARY A. Load Forecasts for Railbelt Area Load forecast is the basis for system expansion planning. The most re- cent load forecasts for the ut·ility servite areas in the Railbelt area were examined to establish the basis for projection of future trends. The sum of the most recent forecasts made by the individual utilities in the area has been selected as the upper growth l"imit to the forecast ranges for the Railbelt area. The median forecast prepared by the Alaska Power Administration, as a revision to the Susitna Project Market Study, was selected as the lower limit. The statistical average of these two forecasts was calculated and used in this study as the 11 probable 11 forecast. The long-range 11 probable 11 load demand projections in MW for the load areas are: 1980 1985 1990 1995 2000 Anchorage 573 977 1581 2402 3446 2 - 1 Fairbanks 153 231 338 477 663 Combined Area 749 1194 1896 2842 4054 B. Selection of Intertie Route Alternative transmission corridors considered in previous studies were analyzed as to access-ibility, cost of right-of-way, transmission line design, and environmental and aesthetic considerations. The preferred corridor described in the Susitna Report, along the Parks Highway from Anchorage to Fairbanks, was selected for the intertie route. It was selected because of its favorable length, accessibility, and environ- mental considerations. This corridor was further defined by preparing preliminary layouts. Field trips to important sites along this 323-mile line route were made to confirm the suitability at this corridor for the intertie. C. Transmission Line Design To provide a basis for intertie cost estimation, conceptual designs for 230-kV and 345-kV transmission lines and substations were made. The transmission Line Cost Analysis Program (TLCAP), a computer program de- veloped by IECO, was used to select optimum designs. The results fa- vored relatively long spans (1300 feet) and high-strength conductors. Tubular steel, guyed towers and pile-type foundations were selected for both the 230-kV and 345-kV lines as being well suited for Alaska condi- tions. D. System Expansion Plans To determine the intertie 1 s economic feasibility, alternative system ex- pansion plans were prepared with and without the Anchorage-Fairbanks inter- tie. System expansion plans were developed to meet both the 11 probable 11 and 11 low" load demand projections. 2 - 2 ~~~-· r ! r To assume a nearly constant level of power generation reliability (LOLP Index) for all system expansion plans, a multi-area reliability (MAREL) computer study was performed. Annual load models for both areas were developed. The load models indicate that there is little diversity between the loads in the Anchorage and Fairbanks areas. The 1984-1997 study period was selected to best suit system requirements. The earliest year when the interti~ can be operational is 1984. Based on optimistic assumptions, the last generating unit of Upper Susitna Hydro- power Project will be on-line in January 1997. E. Facility Cost Estimates Cost estimates were developed for alternative system facilities to allow for economic comparisons. All costs were adjusted to January 1979 levels. Transmission line costs were calculated by using the TLCAP program. The same computer program calculated the line losses. To provide a means for optimum economic dispatch of generating units on an interconnected system basis, costs for control and communication sys- tems were included in the intertie cost estimates. Cost estimates for new generating plant facilities (gas-turbine units and coal-fired steam plants) were based on cost information in the Power Supply Study -1978 report to GVEA, prepared by Stanley Consultants. Appropriate Alaskan construction cost location adjustment factors were applied to derive spe- cific site cost estimates. Construction power costs for the proposed Susitna Project were calcu- lated. The results indicate a clear advantage for utilizing the intertie as a source of construction power. 2 - 3 F. Economic Feasibility Analysis The economic feasibility analysis of the intertie was performed by discounting two cash flows (independent and interconnected systems) to a common year and then measuring the project benefits by the net present worth value. Facility costs for those new generating plants not af- fected by the introduction of the intertie were excluded from the anal- ysis. The Transmission Line Economic Analysis Program (TLEAP), a com- puter program, was used to analyze the sensitivity of different escala- tion and discount rates on the capital costs of various alternatives. For principal investigations to establish definite feasibility analysis a 10% rate was used to discount cash flow in constant 1979 do 11 ars. G. Financial and Institutional Planning A preliminary financial plan for implementation of the transmission intertie on a progressive basis was developed. The probable composition of institutions and participating utilities for ownership, management, and operating responsibilities is reviewed in this report, and present arrangements and possible future requirements are discussed. 2.2 CONCLUSIONS The study shows that: • The 230-kV single circuit intertie, having a 130-MW line load- ing capability (Case IA), is economically feasible in 1984, based only on benefits due to reduction of generation reserve plant capacity (reserve sharing). The net present-worth or the benefits are $12,475,000. The benefits become marginal ($945,000) if intertie costs are increased by 25 percent. In the case of 11 low 11 load forecast scenario the benefits are $2,704,000. 2 - 4 ,.,.... I - - • An increase in benefits is obtained if the 230-kV single circuit intertie {double circuit after 1992), in addition to generation reserve sharing, includes firm power transfer capability {Case IB). The benefits are $24,054,000 or an increase of 93 percent over Case IA. Additional benefits due to supply of construction power to the Upper Susitna Project sites are $5,579,000. • The 345-kV single circuit intertie {Case IC) is not economically feasible in 1984 based on the two scenarios developed in this study: generation reserve sharing only and reserve sharing plus firm power transfer capability. In the second scenario the results are negative ($-426,000). Further studies are recommended to pursue the economic feasibility of the 345-kV intertie because from technical point of view the 345-kV voltage is more appropriate for the trans- mission distance between Anchorage and Fairbanks. • The 230-kV single circuit intertie with intermediate substa- tions at Palmer and Healy {Case ID) is economically feasible in 1984. The benefits are $20,344,000 including the power sup- plies to MEA system to Palmer and the proposed Upper Susitna Hydropower Project sites. If i nterti e costs are increased by 25 percent the benefits become $11,656,000. • The fully integrated interconnected system operation generates additional benefits which are not quantified in this study. These benefits could be due to: Decrease in spinning reserve requirements by reducing the on-line plant capacity for the combined system. Coordination of maintenance scheduling which would improve combined system security and provide cost savings. Economies from optimum dispatch of generating units on the interconnected system basis. It is definitely recommended that a multi-area production costing simulation study be perfonned to establish these additional benefits. 2 - 5 • Expansion plans for the interconnected system with the proposed Upper Susitna Project were developed to detennine the effect of this project on the interconnected system expansion plans, the displacement of thermal generating units, and intertie transmis- sion requirements with Susitna Project. e If an early 230-kV transmission intertie is constructed in 1984, due considerations should be given for constructing the Anchorage- Susitna portion of this intertie for 345-kV and operating it tem- porarily at 230-kV. ' The average value of energy transfer cost (1984-2015) thru the 230-kV intertie is 8 Mills/kWh at 55 percent load factor when financed by 40/60% REA/FFB loan package and municipal bonds issued by Anchorage and Fairbanks. • This Intertie Feasibility Study is only a part of the over-all power system expansion plans for the Railbelt area. Further studies will be required to establish definitive characteristics for this transmission intertie. These studies should be closely coordinated with the future expansion plans of all utilities in the Railbelt area. 2 - 6 CHAPTER 3 LOAD FORECASTS FOR RAILBELT AREA 3.1 ENERGY AND DEMAND FORECAST RANGE CHAPTER 3 LOAD FORECASTS FOR RAILBELT AREA The basis for establishing a range of future load projections for the Anchorage -Cook Inlet and Fairbanks -Tanana Valley areas, together with a combined forecast for an interconnected system service area in the Railbelt, was obtained from an examination of previous forecastsl1 com- pared in the Battelle Report of March 1978 (Ref. 1). These were examined in relation to a combination of the most recent utility forecasts pre- pared for the REA and an August 1978 revision of previous forecasts for the Upper Susitna Project, issued by the Alaska Power Administration in December 1975 (Ref. 2). A. Range of Energy Consumption Resulting from Battelle Study The Battelle study provides a compendium of previous forecasts and an analysis of assumptions intrinsic to their projections. It attempts to eliminate low probability scenarios and select a range of utility and industrial loads for the intertied Railbelt system. The following summary of annual energy consumption, excluding national defense and non- interconnected users, represents the definitive results of the Battelle study: Annual Consumption-GWh Upper Range Limit Interval Growth Rate Lower Range Limit Interval Growth Rate 1974 1,600 1,600 1980 3,400 13.4% 15.3% 2,600 8.4% 9.6% l/ See Section 3.3 for references used in this chapter. 3 - 1 1990 2000 10,800 22,500 10.2% 8,500 16,000 4.0% Battelle selected this energy consumption range after carefully evaluating the methodology used in several previous forecasts and relevant assumptions pertaining to economic factors. Two load studies were deemed most appro- priate to future load projections for the Railbelt. They are, in order of preference, the Upper Susitna Project Power Market Study by the Alaska Power Administration, and the report Electric Power in Alaska, 1976-1995 (Ref 3.) by the Institute for Social and Economic Research (ISER) of the University of Alaska. 1. Forecasts for Anchorage -Cook Inlet Area -From the several load forecasts corresponding to various growth scenarios of the ISER study, Batte 11 e se 1 ected Forecasts 2 and 4 as most appropriate for the Anchorage and Cook Inlet area. These forecasts assume limited petroleum development, which was considered to be the most likely prospect. The assumptions underlying the scenario for limited petroleum development are: 1 Petroleum Production will be 2 million bpd in 1980, and 3.6 million in 1990. 1 A natural gas pipeline will be constructed from Prudhoe Bay through Canada. 1 An LNG plant for natural gas from the Gulf of Alaska will be constructed. The assumptions regarding electrical energy consumption are: • • Sector Residential Commercial/Industrial Case 2 Case 4 Moderate Electrification No Growth Growth as Usual 3 - 2 Minimum Electrification - r ,f"' The ISER study did not include new industrial consumption in forecasts, other than expansion of existing loads served by utilities. However, it did relate utility forecasts to economic scenarios, in which future energy consumption was quantitatively projected according to specified assumptions of petroleum development, population, aggregate income, saturation levels, and average usage per customer. In 1975 the Alaska Power Administration prepared forecasts for the po- tential power market of the Upper Susitna Project. The forecasts con- tained projections of industrial load for existing and possible future installations. Battelle modified these projections to include the follow- ing assumptions: • In addition to gradual expansion of existing refinery capacity, a new 150,000-bpd refinery will be built by 1983. An aluminum smelter with a capacity of 300,000 tpy will be constructed, to be on-line by 1985. • A nuclear fuel enrichment plant, included in previous load projections, was deleted from future industrial load. Industrial development in the interior region was assumed to be excluded from the load area of an intertied Railbelt system. A summary of industrial facilities included in the Battelle forecast for the Anchorage and Cook Inlet area is as follows: Existing Facilities Chemical Plant LNG Plant Refinery T-imber Mills New Facilities Aluminum Smelter LNG Plant Refinery T-imber Mills Coal Gasification Plant Mining and Mineral Processing Plants New City 3 - 3 2. Forecasts for Fairbanks -Tanana Valley Area - A similar evalua- tion by Battelle defined the most probable forecasts for the Fairbanks and Tanana Valley area. It assumed that industrial development in the interior region will consist largely of self-supplied mining operations in remote areas. Thus, load growth will be attributable only to utility customers in the service areas of the Fairbanks Municipal Utilities System (FMUS) and the Golden Valley Electric Association, Inc. (GVEA). In the judgment of Battelle, the most likely consumption range for the Fairbanks area is bounded by the mid-range projections of the Upper Susitna Market Study, with mid-range forecasts prepared by the Interior Alaska Energy Analysis Team (IAEAT) (Ref. 4) as the upper bound and the ISER Case 4 as the lower bound. 3. Combined Forecasts for the Railbelt-The Battelle energy and demand forecast range for the combined utility and industrial load of the Railbelt, encompassing the Anchorage -Cook Inlet and Fairbanks - Tanana Valley areas, is shown graphically on Figures 3-1 and 3-4, re- spectively. These are intended to serve as background comparisons with combined utility forecasts and the revised projections of the Alaska Power Administration for the potential market of the Upper Susitna Project. B. Forecasts by Utilities and the Alaska Power Administration The most recent Power Requirements Studies (PRS) of the REA utilities (Ref. 5) in the Anchorage and Fairbanks areas were obtained, together with the most probable load forecasts, as projected for the Anchorage Municipal Light and Power Company (AML&P) and the Fairbanks Municipal Utilities System (FMUS). Tables 3-1 and 3-2 provide tabulations of utility forecasts and extrapo- lated projections to the horizon year 2000, for the Anchorage -Cook Inlet area and the Fairbanks -Tanana Valley area, respectively. The Valdez -Copper Valley area is not included in the forecasts for the 3 - 4 r r r.::,l I ~ I r ,.... ' tf Railbelt, as these load areas are assumed not to be interconnected with the intertied Railbelt system until after the completion of the Upper Susitna Project. As the PRS provided load projections for a base year and at two 5-year intervals, interpolations were made on the basis of assumed compound growth between reported values. On the further assump- tion that growth rates will decline progressively to the horizon year, extrapolations were made of net energy generation with growth rates declining from reported values at 5-year intervals to 2000. These growth rates were applied on the assumption that there will be no abrupt transition to low growth rates. Rather, growth will diminish in gradual steps as markets are saturated and the effects of conservation and price elasticity reflect in future energy consumption levels. Reported load factors were interpolated for intermediate years and the trend extrapo- lated to the horizon year to obtain projections of annual peak demand. The utility forecasts were combined for the Anchorage -Cook Inlet area, the Fairbanks -Tanana Valley area, and the total Railbelt. Table 3-3 provides tabulations of net energy generation, load factor, and annual peak diversified demand. It is obtained by the application of coinci- dence factors to the sum of individual ~;~tility peak demands. These load forecasts are shown on Figures 3-1 through 3-6, in comparison with load projections prepared in August 1978 by the Alaska Power Administration for the Upper Susitna Project, as revisions to previous power market forecasts evaluated as part of the Battelle study. A summary of the Alaska Power Administration load forecasts is given in Table 3-4. These forecasts include only utility and industrial load projections on the assumption that national defense installations will not be supplied as part of the interconnected system load. Since the Battelle forecasts also excluded load forecasts for national defense installations, direct comparisons can be made. The range of Alaska Power Administration load forecasts for peak % Differential from median: demand and annual energy was 1980 1985 High + 8 + 21 Low - 8 -18 3 - 5 as follows: 1990 1995 2000 + 31 + 41 + 54 -27 -33 -38 The range of load forecasts exhibited this diverging spread from the 1977 base-year load level. The industrial load projected by Battelle was included in the Alaska Power Administration forecast range on a selective basis. The differential between the 11 high'' and ''extra high 11 forecasts is an additional 280 MW of load, representing an aluminum smelter. The 11 lOW 11 forecast excludes the load projected for the New City. C. Comparison and Selection of Forecast Range The forecasts of net energy generation for the Railbelt are shown on Figure 3-1. Curve 1 represents the combination of the most recent forecasts for municipal and REA utilities, as presented in Tables 3-1, 3-2, and 3-3. The forecast aligns closely up to 1990 with the upper bound of the Battelle forecast range. Beyond 1990 the divergence arises from the different assumptions made in regard to growth rates in the 1990-2000 period. The upper bound of the Battelle range exhibits an abrupt change of growth rate, from 15.3% to 10.2%, applied to total energy in the Railbelt, while the combined utilities forecast exhibits a more gradual transition to lower growth rates. Although many economic factors will contribute to lower overall growth rates in energy consump- tio, a reasonable approach to establishing an upper limit has been taken, in that individual utility forecasts were assumed to decline without abrupt change. This assumption is based on the fairly constant percentage expenditure from disposable income for energy needs, as determined by the study of future consumption patterns in Alaskan service areas (Ref. 6), the results of which are given in an extract from the RWRA report (Ref. 7) presented in Appendix A. Accordingly, the combined utilities forecast has been selected as the upper limit to the possible range of total energy forecasts for the Railbelt. The median forecast prepared by the Alaska Power Adminis- tration, as a revision to the Susitna Project Market Study, has been selected as the lower limit to the forecast range for the Railbelt. This recently prepared forecast exhibits lower growth than the 1975 3 -6 r 1 r \ r I r r ~! -I r" I forecast for the Susitna Project, and represents a prudent choice for a conservative growth scenario. Figures 3-2 and 3-3 show the relationship between.the combined utilities forecast and the range of forecasts prepared by the Alaska Power Adminis- tration. The effect of the aluminum smelter load can be observed as the differential between curves 2C and 3C on Figure 3-2, and curves 2A and 3A on Figure 3-3. The median forecast also excludes the aluminum smelter load but provides for a reasonable realization of the industrial potential in the Anchorage area. In setting the lower limit of the forecast range in the context of the considerable industrial growth potential of this area of Alaska, it is thought that the selected forecast range will provide a good test of the economic feasibility of establishing an interconnection in the Railbelt. A similar comparison of forecast demand can be made by reference to Fig- ures 3-4, 3-5, and 3-6. The combined utilities demand forecast is below the upper bound of the Battelle range until after 1985 and aligns in fairly close proximity until 1990. Beyond 1990 divergence occurs based upon the assumption discussed previously in relation to energy growth. The median demand forecast for the Susitna Project, prepared by the Alaska Power Administration, exhibits a growth characteristic that roughly par- allels the lower bound of the Battelle range between 1985 and 2000. As the low growth limit to the range of demand beyond 1981 selected for the interconnection study, it represents a moderately conservative view of overall growth potential. Prior to 1981, the short-range combined utilities demand forecast is below the median forecast for the Susitna Project, approximately at Battelle mid- range. The demand forecasts for the Susitna Project may be observed in relation to the combined utilities demand forecasts of Figures 3-5 and 3-6. The selected range of demand forecasts represents a moderate to high expectation of a continued growth of the Railbelt economy through the end of the century, this being accentuated by the interconnection of utility systems in the area. 3 - 7 3.2 DEMAND FORECASTS FOR GENERATION PLANNING The range exhibited by load forecasts for the Railbelt Area is consider- able. Therefore, it remains to select definitive demand forecasts for generation expansion planning that are a reasonable representation of anticipated load growth under projected economic conditions. A. Selection of Peak Load Demand Forecasts The combined utilities forecast is appropriate to a high growth scenario that may not be possible under future economic constraints and prevail- ing trends towards greater conservation. The median forecast by the Alaska Power Administration does not include the entire industrial load potential that could be realized by a steady commitment towards economic growth in the State. It also specifically excludes the possibility of development of the aluminum smelter in the Anchorage area. The selection of the statistical average forecasts, given in Table 3-5, for peak load demand is consistent with the moderate to high expectation of continued growth in the Railbelt economy. The natural resources of Alaska, particularly oil and gas, will largely determine the extent of future growth possible within the State. A steady pressure for addi- tional domestic oil and gas supplies for the lower forty-eight will be engendered by the continuing energy crisis within the United States. The impact of additional exploitation of the North Slope on the State economy will be reflected in continued growth within the Railbelt. Thus, the conditions are present to ensure the realization of optimistic expectations for moderate to high growth of load demand. B. Forecast Range for Sensitivity Analysis In order to determine the effect of load growth on the economic feasi- bility of the Anchorage-Fairbanks Intertie, a suitable range of load growth must be established for sensitivity analysis. 3 - 8 r i r r r The uncertainty associated with a load forecast increases with time, so the range of demand should also increase with time. The values given in Table 3-6 correspond to a range of load demand that steadily increases through time from a bandwidth of + 1% in 1979 to + 21% in 2000. The long-range load projections for the Anchorage-Cook Inlet and Fairbanks- Tanana Valley areas are shown on Figure 3-7, with their corresponding range limits. The diversified demand for the combined areas of the Rail- belt is given on Figure 3-8, the peak load rising to approximately 4000 MW in the year 2000. 3 - 9 3.3 REFERENCES 1. Battelle Pacific Northwest Laboratories, Alaska Electric Power: An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region, March 1978. 2. U.S. Department of the Interior, Alaska Power Administration, ~ Susitna River Hydroelectric Studies, Report on Markets for Project Power, December 1975. 3. University of Alaska, Institute for Social and Economic Research, Electric Power in Alaska, 1976-1995, August 1976. 4. Interior Alaska Energy Analysis Team, Report of Findings and Recommenda- tions, June 1977. 5. Rural Electrification Association, Power Requirements Study for: Alaska 2 -Matanuska Electric Association, Inc., May 1978 Alaska 5 -Kenai-Homer Electric Association, Inc., May 1978 Alaska 6-Golden Valley Electric Association, Inc., May 1976 Alaska 8 -Chugach Electric Association, Inc., May 1976 Alaska 18 -Copper Valley Electric Association, Inc., May 1977. 6. E. 0. Bracken, Alaska Department of Commerce and Economic Development, Power Demand Estimators, Summary and Assumptions for the Alaska Situation, June 1977. 7. Robert W. Retherford Associates, System Planning Report, Matanuska Electric Association, Inc., January 1979. 8. U.S. Department of the Interior, Alaska Power Administration, A Report of the Technical Advisory Committee on Economic Analysis and Load Projections, 1974. 9. Federal Power Commission, The 1976 Alaska Power Survey, Vol. 1, 1976. ~· 10. U.S. Army Corps of Engineers, South-central Railbelt Area, Alaska, Upper Susitna River Basin Interim Feasibility Report, December 1975. 11. U.S. Department of the Interior, Alaska Power Administration, Bradley Lake Project Power Market Analyses, August 1977. 12. Tippett and Gee, Consulting Engineers, 1976 Power System Study, Chugach Electric Association, Inc., Anchorage, Alaska, March 1976. 3 -10 ] w -I-' ] -~--·~. 1 Anchorage Municipal Light and Power Comoan1 Net Lead Peak Energy Factor Demand Year {GWh} _ill_ __D:i!1_ i979 633.6 58.1 124.4 1980 699.4 58.1 137.5 1981 770.6 57.9 151.8 1982 8.47 .3 57.8 167.3 1983 929.6 57.7 183.9 1984 1,017.5 57.€ 201.8 1985 1,110.8 57.4 220.8 1936 1,209.5 57.3 241.1 19!37 1,313.2 57.1 262.5 1:!88 1,421.6 56.9 285.0 1939 1,534.2 56.8 308.5 1990 1,550.5 56.6 333.0 1991 1,769.8 56.4 358.2 1992 1,891.3 56.2 324.1 1993 2,014.4 56.0 410.5 1994 2,138.0 55;8 437.2 1:195 2,244.9 55.6 460.9 !996 2,357.1 55.4 485.7 i997 2,475.0 55.2 511.3 1990 2,598.8 ss.o 533.4 1999 2,728.7 54.8 568.4 ·2000 2,865.0 54.6 599.0 Gr-owth ilates: Repcrtec L ogi st i c Cune 3 "'') ~ 'I ·-~-1 1 ~·1 ern·•·] ~1 .. '1 -~~] r~l TABLE 3-1 ANCHORAGE -COOK INLET AREA UTILITY FORECASTS AND EXTRAPOLATED PROJECTIONS Alaska 2 -Matanuska Alaska 5 -Kenai Electric Association, Ir.c. Hrnr..er Electric Assoc., Inc. Kenai Cit.z: Light Slstem Net Load Peak Energy Factor Demand {GWhi .J!L (MW) 280.4 47.5 67.4 332.8 47.0 80.8 395.1 45.5 97.0 468.0 56.0 116.1 559.3 45.0 J41.9 668.3 44.5 171.4 7~8.6 44.0 207.2 954.4 43.5 250.5 1,140.0 43.0 302.6 1,322.4 44.0 343.1 1,534.0 45.0 389.1 1,779.4 46.0 441.6 2,064.1 47.0 501.3 2,394.4 43.0 569.4 2 ,705. 7 49.0 630.3 3 /l57 .4 50.0 698.0 3,454.9 51.0 773.3 3,904.0 52.0 857.0 4,411..5 53.0 950.2 4,852.7 St..O 1,025.9 5,337.9 55.0 1,107.9 5,871.7 56.0 1,196.9 13.7% {1977-1982) 19.5~ {i983-1937) Net Load Energy Factor (GWh) _l!L 275.2 55.0 336.6 55.0 411.6 55.0 502.0 55.0 572.3 55.0 652.4 55.0 743.7 55.0 847.9 55.0 967.0 55.0 1,083.0 55.0 1,213.0 55.0 1,358.6 55.0 1,521.6 55.0 1,704.2 55.0 1,874.6 55.0 2,062.1 55.0 2,268.3 55.0 2,495.1 55.0 2,744.6 55.0 2,964.2 55.0 3 ,201. 3 55.0 J,457.4 55.0 22.3t (1977-1982) 14.0~ {1983-1987) Peak Demand (MW} 57.1 69.9 85.4 104.2 118.8 135.4 154.4 176.0 201.0 224.8 251.8 282.0 315.8 353.7 389.1 428.0 470.8 517.9 559.7 615.2 664.4 717.6 Net Load Energy Factor (GWh) .J!L 34.4 56.0 37.5 56.0 40.8 56.0 44.4 56_(; 48.1 56.0 52.1 56.0 56.4 56.0 61.1 56.0 66.3 56.0 71.5 56.0 77.0 56.0 83.1 56.0 89.5 56.0 96.5 56.0 103.5 56.0 111.1 56.0 119.2 56.0 127.9 56.0 137.3 56.0 146.9 56.0 157.2 56.0 168.2 56,0 8.8% (1977-1982) 8.3% {!983-1987) Peak Demand ~ 7.0 7.6 8.3 9.1 9.8 10.6 11.5 12.5 13.5 14.6 15.7 16.9 18.2 19.7 21.1 22.6 24.3 26.1 28.0 29.9 32.0 34.3 -----~] 1 Alaska B -Chugach Electric Association, Inc. Net Load Peak Energy Factor Defoland {GWh} .J!L {M~l 1,108.9 53,0 238.8 1,283.0 54.0 271.2 1,467.8 54.0 310.3 1,679.1 54.0 355.0 1,920.9 54.0 406.1 2,197.5 54.0 464.5 2,509.0 54.0 530.4 2,810.1 54.0 594,1 3,147.3 54.0 655.3 3,525.0 54.0 745.2 3 ,_948.0 54.0 834.6 4,421.7 55.0 934.7 4,863.9 55.0 1,022.2 5,350.3 55.0 1,131.0 5,885.3 55.0 1,244.1 6 ,473. 9 55.0 1,363.6 7,121.2 55.0 1,505.4 7,69().9 55.0 1,625.8 8,306.2 55.0 1,755.9 8,970.7 55.0 1,900.6 9,688.3 55.0 2,048.1 10,463.4 55.0 2,211.9 15.71 {l977-l9ac) 14.4~-{1931-1985) ----~-------------~-----------------·------------------~--~---------~~----------------------~----------·------------------~-----------------------------~---Projected 5.0% (1995-2000) !6.0% (1933-1992) 13.0% (1993-1997) .w.cn (1998-2ooo) 12.0,; (l'?<A3-:992) lO.C% (1993· 1997) B.Dl (1998-2COO) 7.8% (1988-1992) 7.3'1 (1993-1997) 7.0% (1998-2000) 12.G~-(1986-1990) !0.~ (1991-1995) S.C~ (1995-2COO) TABLE 3-2 FAIRBANKS -TANANA VALLEY AREA UTILITY FORECASTS AND EXTRAPOLATED PROJECTIONS Fairbanks Municipal Alaska 6-Golden Valley Utilities S~stem Electric Association~ Inc. Net Load Peak Net Load Peak Energy Factor Demand Energy Factor Demand Year (GWh} {%) {MW} {GWh) {%) {MW) 1979 144.3 50.0 32.9 450.0 46.3 111.0 1980 153.0 50.0 34.9 501.8 46.6 122.9 1981 162.2 50.0 37.0 559.5 46.9 136.2 1982 171.9 50.0 39.2 624.6 47.2 150.9 1983 182.2 50.0 41.6 692.6 47.3 167.1 1984 193.2 50.0 44.1 768.8 47.3 185.5 1985 204.7 50.0 46.7 853.4 47.4 205.5 1986 217.0 50.0 49.5 947.3 47.4 228.1 1987 230.0 50.0 52.5 1,050.0 47.5 252.3 1988 243.9 50.0 55.7 1,155.0 47.5 277.6 1989 258.5 50.0 59.0 1,270.5 47.6 304.7 1990 274.0 50.0 62.6 1,397.6 47.6 335.2 1991 287.7 50.0 65.7 1,537.3 47.7 367.9 1992 302.1 50.0 69.0 1,691.0 47.7 404.7 1993 317.2 50.0 72.4 1,843.2 47.8 440.2 1994 333.0 50.0 76.0 2,009.1 47.8 479.8 1995 349.7 50.0 79.8 2,189.9 47.9 521.0 1996 367.2 50.0 83.8 2,387.0 47.9 568.9 1997 385.5 50.0 88.0 2,601.8 48.0 618.8 1998 404.8 50.0 92.4 2,809.9 48.0 668.3 1999 425.1 50.0 97.1 3,034.7 48.0 721.7 2000 446.3 50.0 101.9 3,277.5 48.0 779.5 Growth Rates: Reported 6.0% (1978-1990} 11.5% (1977-1982} 11.0% (1983-1987) ------------------------------------------------------------------------Projected 5.0% (1991-2000) 3 -12 10.0% (1988-1992) 9.0% (1993-1997) 8.0% (1998-2000) ~7· ~"'~ 1 TABLE 3-3 COMBINED UTILITY FORECASTS FOR RAILBELT AREA Anchorage Cook -Inlet Fairbanks-Tanana Valle~ Combined Load Areas Net Load Peak 1 Net Load Peak 2 Net Load Peak 3 Energy Factor Demanc:i=-/ Energy Factor Demand~./ Energy Factor Demancj.:::./ Year (GWh) (%) (~W) (GWh) (%) (MW) (GWh) (%) ( MW) 1979 2,332.5 56.1 475 594.3 47.6 142 2,926.8 55.3 605 1980 2,689.3 56.4 544 654.8 47.9 156 3,344.1 55.6 686 1981 3,085.9 56.2 627 721.7 48.0 171 3,807.6 55.6 782 1982 3,540.8 56.0 722 795.9 48.3 188 4,336.7 55.5 892 1983 4,030.2 55.7 826 874.8 48.3 207 4,905.0 55.3 1,012 1984 4,587.8 55.5 944 962.0 48.3 227 5,549.8 55.2 1,148 1985 5,218.5 55.2 1,079 1,058.1 48.4 250 6,276.6 55.0 1,302 1986 5,883.0 54.9 1,223 1,164.3 48.4 275 7,047.3 54.8 1,468 w 1987 6,633.8 54.6 1,387 1,280.0 48.4 302 7 ,913.8 54.6 1,655 1988 7,423.5 54.7 1,548 1,398.9 48.4 330 8,822.4 54.7 1,840 ...... 1989 8,306.2 54.9 1,728 1,529.0 48.5 360 9,835.2 54.9 2,046 w 1990 9,293.3 55.0 1,928 l ,671.6 48.5 394 10,964.9 55.0 2,276 1991 10,308.9 55.2 2,133 1,825.0 48.5 429 12,133.9 55.2 2,511 1992 11,436.7 55.3 2,360 1,993.1 48.5 469 13,429.8 55.3 2,772 1993 12,583.5 55.5 2,587 2,160.4 48.6 507 14,743.9 55.5 3,032 1994 13,842.5 55.7 2,836 2,342.1 48.6 550 16,184.6 55.7 3,318 1995 15,208.5 55.9 3,105 2,539.6 48.6 596 17,748.1 55.9 3,627 1996 16,575.0 56.1 3,372 2,754.2 48.7 646 19,329.2 56.0 3,938 1997 18,074.6 56.3 3,663 2,987.3 48.7 700 21,061.9 56.2 4,276 1998 19,533.3 56.5 3,947 3,214.7 48.7 753 22,748.0 56.4 4,606 1999 21,113.4 56.8 4,244 3,459.8 48.7 811 24,573.2 56.6 4,954 2000 22,825.7 57.0 4,569 3,723.8 48.7 873 265,49.5 56.8 5,333 Diversified Demand for Coincidence Factor: 11 0.96 2/ 0.99 II 0.98 1. TABLE 3-4 Sheet 1 of 2 LOAD FORECAST FOR UPPER SUSITNA PRCAJECT BY ALASKA POWER ADMINISTRATION 1977 1980 1985 1990 1995 ANCHORAGE-COOK INLET AREA POWER DEMAND AND ENERGY REQUIREMENTS (Excluding National Defense) Peak Demand {MW) Utility Loads High 620 1,000 2,150 3,180 Median 424 570 810 1,500 2,045 Low 525 650 1,040 1,320 Industrial Loads Extra high 32 344 399 541 High 32 64 119 261 Median 25 32 64 119 199 Low 27 59 70 87 Total Extra high 652 1,344 1,914 2,691 High 652 1,064 1,634 2,411 Median 449 602 874 1,234 1 ,.699 Low 552 709 890 1,127 Annual Energy (GWh) Utility Loads High 2,720 4,390 6,630 9,430 Median 1,790 2,500 3,530 4,880 6,570 Low 2,300 2,840 3,590 4,560 Industrial Loads Extra high 170 1,810 2,100 2,840 High 170 340 625 1,370 Median 70 170 340 630 1,050 Low 141 312 370 460 Total Extra high 2,890 6,200 8,730 12,270 High 2,890 4,730 7,255 10,800 Median 1,860 2,670 3,870 5,510 7,620 Low 2,441 3,152 3,960 5,020 3 -14 2000 p:J;~.- r·-· --, 7,240 3,370 1,520 683 403 278 104 1""--', 3,863 3,583 2,323 1,424 13,920 ;w-·, 8,960 5,770 3,590 2,120 1,460 550 17,510 16,040 10,420 6,320 r- 1 l r I· '!i r -i' ('!""' i )' -I !"""' I 2. 3. TABLE 3-4 Sheet 2 of 2 LOAD FORECAST FOR UPPER SUSITNA PROJECT BY ALASKA POWER ADMINISTRATION 1977 1980 1985 1990 1995 FAIRBANKS-TANANA VALLEY AREA POWER DEMAND AND ENERGY REQUIREMENTS (Excluding National Defense) Peak Demand (MW} Uti 1 ity Loads High 158 244 358 495 Median 119 150 211 281 . 358 Low 142 180 219 258 Annual Energ~ {GWh} Utility Loads High 690 1,070 1,570 2,170 Median 483 655 925 1,230 1,570 Low 620 790 960 1,130 COMBINED ANCHORAGE-COOK II~LET AND FAIRBANKS-TANANA VALLEY AREAS Peak Demand (MW} Extra high 810 1,588 2,272 3,186 High 810 1,308 1,992 2,906 Median 568 752 1,085 1,515 2,057 Low 694 889 1,109 1,385 Annual Energ~ (GWh} Extra high 3,580 7,270 10,300 14,440 High 3,580 5,800 8,825 12,970 Median 2,343 3,325 4,795 6,740 9,190 Low 3,061 3,942 4,920 6,150 3 -15 2000 . 685 452 297 3,000 1,980' 1,300 4,548 4,268 2,775 1,721 20,510 19,040 12,400 7,620 Year 1979 1980 1981 1S82 1983 w 1984 1985 I-' 1986 (J) 1927 1988 1989 1990 100" JJl 1992 1993 1994 1995 1996 1oo-JJ I 1998 1999 2000 TABLE 3 - 5 LOAD DEMAND FORECASTS FOR RAILBELT AREA TO DETERMINE STATISTICAL AVERAGE FORECAST Anchorage -Cook Inlet Fairbanks -Tanana Valle~ Alaska Power Statistical Combined Alaska Power Stat1stical Combined Ut i1 it; es Administration Average Utilities Administration Average Forecast Median Forecast Forecast ~;edian Forecast c~~w} Forecast (MW} (MW} (MW) Forecast ( ~~~-~) ( ~1W) 475 546 511 142 139 141 544 602 573 156 150 153 627 648 638 171 161 166 722 698 710 188 172 180 826 752 789 207 184 196 944 810 877 227 197 212 1079 874 977 250 211 231 1223 937 1080 275 223 249 1387 1004 1196 302 237 270 1548 1077 1313 330 251 291 1728 1154 1441 360 265 313 1928 1234 1581 394 281 338 2133 1315 1724 429 295 362 2360 1402 1881 469 310 390 2587 1495 2041 507 325 416 2834 1593 2215 550 342 446 3105 1699 2402 596 358 477 3372 1809 2591 646 375 511 3663 1925 2794 700 393 547 3947 2049 2998 753 412 583 4244 2182 3213 811 432 622 4569 2323 3446 873 452 663 Combined Load Areas Combined Alaska PoHer Statist ica 1 Ut i1 it i es Administration Aver.oge Forecast ~led ian Forecc.st (r!;'li) Forecast (r1W) {r!tl} 605 685 645 686 752 719 782 809 796 892 870 881 1012 936 974 1148 1007 1078 1302 1085 1194 1468 1160 13111 1655 1241 1•:48 1840 1328 1584 2046 1419 1733 2276 1515 1396 2511 1610 2061 2772 1712 2242 3032 1820 2.126 3318 1935 2627 3627 2057 2842 3938 2184 3061 4276 2318 3297 46C6 2461 3534 4954 2614 3734 5333 2755 4054 w ....... -...J TABLE 3-6 PEAK LOAD DEMAND FORECASTS FOR RAILBELT AREA \-J I TH RANGE LIMITS FOR SENSITIVITY ANALYSIS Anch~rage -Cook Inlet Fairbanks -Tanana Valle~ Lo wer ?eak Load Upper Lo1~er ?eal-: Load Upper Rc:nge Jer-:~nd Range Range De r::and Range Li mit* F orec~st** L i-:-:it Li~it* Fo r ecast** L i r:1 it Year ~ ~H·-1) . __lGD_ __Gill_ (!·f..l) ~ 1379 508 511 514 140 l41 142 1938 570 573 576 151 153 1 55 1931 635 638 641 163 166 169 1982 702 710 718 175 180 185 193 3 765 789 813 188 196 204 1924 832 877 922 202 212 222 198 5 908 977 1046 218 231 244 1936 985 1030 1175 232 249 266 1937 1068 1195 1324 248 270 292 1988 1156 1313 1470 264 291 318 1939 1250 1441 1632 281 313 345 1990 1350 1581 1812 300 338 376 1991 1451 1724 1997 317 362 407 1992 1562 1881 2200 337 390 443 1993 1677 2041 2405 355 416 477 1994 1 800 2215 2630 377 446 515 1995 1933 2402 2871 398 477 556 1995 2070 -2591 3112 420 511 602 1997 2215 2794 3373 444 54 7 650 1998 2365 2998 3631 469 583 697 1999 2525 3213 3900 495 522 749 2000 2697 3446 4195 522 663 804 * Low load forecast case in this study. ** Probable load forecast case in this study. Combined Loc:d Areas LOI'Ier Pea~ L0ad Up;Jer Range :;:;::;" -,d ~a01 g e Limit* Forecast** L i~it ~ ~ :.\',!) ~ 641 615 649 744 749 754 790 70::;. J~ 802 874 831 883 949 974 999 1031 107 2 1125 1121 1194 1267 1212 1314 141 6 1310 1448 1586 1413 1534 1755 1523 1733 1943 1642 !896 2150 1760 2061 2362 1888 2242 2595 2021 2426 2831 2167 262 7 3087 2319 2842 3365 24 76 3051 3646 2644 3297 3950 2820 3534 4248 3004 3724 4564 3203 4054 4905 w N (J"J 3: ::;; 0 ~ ::!: w 0 :.: < w .:>.. _, <( ::> z z < 1979 1980 1985 1990 1995 2000 FIGURE 3-8 ----~-____ ,_. _____ ----· ---· -:--.--·-·--.---------~--~--------i-·- -i ~ : . . . . f. f_:_:; ---. ;· 5ooo:--~~~~~~~~~----~-~7-~~~~~==~~~~~~~~~~~~~~~~~~~~~~~~~==~~~~--~-~- .. -. 40~0-~~-~~-~~~--~~~--~~--~~--~~--~~~~~~~=+~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ ---······-·--. ---------: -;- 2000~~----~---------+---~--~----~--~--~---+~c_~~~--~-=~ i -l c:_::-: ~: :.::::-' , - t ---------.---• -- ~ ~~~-~: ~--_: : ~-------· -----i----+----+---+--"'--;...,.,...""'-~-=--;:: . -----'----~-'-+ u--~..:tE--E--;-L--TI·-r··--+-'-t): -'-+;+ -------B----~ -~<:~,=~~-':J~~-~~-!-~~~!:~hf~t~~-=;:~if$*!·:-t+~~~~t~ ·[~·>·i -.. : ;__ -~ -· --: UPPER RANGE LIMIT PEAK LOAD DE:~. AND {PROBABLE l LC~ER RANGE LIMIT PEAK LOAD DEMAND FORECAST WITH RANGE LIMITS FOR SENSITIVITY ANALYSIS RAILBELT .AREA LOADS "'Tl ...... G"> c: :;;c 1"1'1 w I co · CHAPTER 4 SELECTION OF INTERTIE ROUTE r r ,-. I ~ .. I 4.1 REVIEW OF EARLIER STUDIES CHAPTER 4 SELECTION OF INTERTIE ROUTE A number of studies have considered the electrical interconnection of the Fairbanks, South Central, and Anchorage areas (Refs. 1-8). The ·susitna Hydroelectric Project Interim Feasibility Report (Ref. 2), here- after called Susitna Report, reviewed a number of alternative transmission corridors in considerable depth. None of the studies included a specific route for a transmission line. The Susitna Report provides an excellent inventory of topography, geology, soils, vegetation, wildlife, climate, existing development, land ownership status, existing rights-of-way, and scenic quality and recreation values by corridor segments of about S-mile widths. 4.2 SURVEY OF ALTERNATIVE CORRIDORS Alternative corridors reviewed for this report were those along or near the Railbelt region between the Anchorage and Fairbanks areas. A recon- naissance (by USGS Quad 1 s and local knowledge)~of routes connecting the '~ Railbelt area to Glennallen was also made to provide a basis for estimating the cost of such a connection at a later date. 4.3 PREFERRED ROUTE FOR TRANSMISSION INTERTIE The preferred corridor described in the Susitna Report was further de- fined by making an actual prel·iminary layout of a def·initive route (with some alternatives) using engineering techniques. This preliminary routing provides a basis for refining cost estimates, displaying a definitive lo- cation for use in studying potential environmental impacts, and providing a specific engineering recommendation for use in right-of-way negotiations. 4 - 1 The preliminary line routing is shown on the accompanying maps, Figures 4-1, 4-2, and 4-3, these being spatially related to the key map on the inside of the front cover of this report. These routes come from a working strip map of l" = l mile (USGS Quad 1 s.) on which these preliminary routes are drawn. The route was plotted by an engineer with nearly 30 years of experience with Alaskan transmission systems. It was also visually in- spected throughout much of its length over the Parks Highway from Anchorage to Fairbanks. The definitive line route was established within the preferred corridor, with due regard to the following restraints, insofar as they could be identified in this preliminary review: • Avoidance of highway rights-of-way, which are better locations for distribution lines that will be required to serve homes and enterprises served by the highway. • Avoidance of telephone lines, because of electrical interference problems. (An open-wire telephone circuit exists on the entire length of the Alaska Railroad right-of-way.) • Avoidance of aircraft landing and takeoff corridors, including all lakes of sufficient size to accommodate small floatplanes. Where lines may cross landing patterns, at least 1/2 mile is allowed from the end of runways or lakes, so that special de- signs are not required. • Avoidance of highly subdivided land areas and dwellings. 1 Avoidance of crossings over developed agricultural lands. • Selection of routings that provide for minimum visibility from highways and homes. 4 - 2 /"""'· i F"" I r • • Avoidance of heavily timbered lands . Selection of routes that provide for minimum changes in grade as the terrain will allow. 1 Parallel alignments with property lines are favored, if not pre- cluded by other considerations. 1 Avoidance of sensitive wildlife areas, if practicable, and co- operation in regard to construction and operating restraints where lines pass through such areas. 1 Alignments located in reasonable proximity to transportation corridors (roads, railroads, navigable waterways) so that con- struction, operation, and maintenance routines are not inordi- nately difficult. 4.4 FIELD INVESTIGATIONS Principal engineers of the IECO-RWRA team made field trips by helicopter and surface transportation to important sites and typical structures of existing transmission lines in both the Anchorage and Fairbanks areas. Particular attention was given to lines using designs developed especially for Alaskan conditions of muskeg swamp, permafrost, and flood plain. These designs have had more than ten years of successful service, and are the basis for more recent tubular steel structure designs now being installed on Alaska projects. Actual field records of Resident Engineers and Inspectors on Alaska trans- mission line construction projects were analyzed along with contractor bids for these projects to provide authoritative basic data on the actual man- hours, materials use, and dollar costs of completed transmission lines. 4 - 3 4.5 PRELIMINARY ENVIRONMENTAL ASSESSMENT A. Description of the Environment 1. Point MacKenzie to Talkeetna-The corridor travels north along the east flank of the Susitna River Valley, an extremely wide and poorly drained plain. Heavy forests of bottomland spruce and poplar, interspersed with muskeg and black spruce, are typical. The soils vary from deep, very poorly drained peat to well-drained gravels and loams, with the well- drained soils being more abundant. Although permafrost is almost absent in this lower part of the Susitna Valley, the poorly drained areas are subject to freezing and heaving in the winter. A sizeable concentration of moose inhabits the lower Susitna River Valley. This valley also supports black and brown bear and a moderate density of water fowl. The proposed transmission line route generally follows a 11 tractor trai 111 (USGS designation) to three miles northeast of Middle Lake. Here, at the approach to the Nancy Lake area, an alternate route (A) may be used to avoid this area. The proposed route (B) is located in marshes and wetlands, between Papoose Twins and Finger Lakes, across the Little Susitna River. The corr·idor then travels northward along the east side of Lynx Lake, Rainbow Lake, and Long Lake where it crosses the Willow River. Here alternate routes (A) and (B) rejoin and intersect an existing 115-kV MEA transmission corridor at the Little Willow Junction and a proposed corri- dor to Anchorage on the east side of Knik Arm. Travelling north, the corridor crosses several major tributaries of the Susitna River including Sheep Creek and the Kashwitna River. In this area the terrain becomes more rolling, and the relative proportion of well-drained soils support- lng thick poplar-spruce forests is considerably greater than to the south. The corridor then travels some five miles east of Talkeetna to the Bart- lett Hills P. I. (point of intersection). 4 - 4 ,- ' r I -"- r r <, 2. Talkeetna to Gold Creek-From Bartlett Hills P.I. the corridor crosses the Talkeetna River near the confluence of the Talkeetna and Chulitna Rivers, where it follows the west bank of the Chulitna River at a mean elevation of 600 feet. Where the Chulitna River curves east- ward, the corridor travels northward, along the Susitna River Valley, through forested uplands, gradually rising to an elevation of 1000 feet. The uplands above. the valley support sparser forests, and increasing amounts of permafrost soils are encountered. At the 1000-foot elevation, one to three miles east of the Susitna River, the corridor crosses Lane Cr-eek, MacKenzie Creek, Portage Creek, Deadhorse Creek, and numerous other small tributaries of the Susitna River. It then crosses Gold Creek and the Susitna River, 1-1/2 miles east of A.R.R. Mile 265, to the Susitna Junction, one mile east of A.R.R. Mile 266. At the Susitna Junction, the proposed Devil Canyon-Watana-Glennallen line meets the corridor. 3. Gold Creek to Glennallen-The corridor parallels the Susitna River to the proposed Devil Canyon damsite and then travels east to the proposed Watana damsite. The vegetation in the canyons varies from up- land spruce-hardwood to alpine tundra. Soils vary from poorly drained river bottoms to unstable talus. Permafrost occurs in this portion of the corridor. Some localized moose populations are crossed. The corridor passes through low lake areas west of Lake Louise until it intersects the Richardson Highway at Tazlina. From Tazlina the route follows the Richardson Highway into Glennallen. 4. Gold Creek to Cantwell -The transmission corridor travels north some 1 to 3 miles east of the Alaska Railroad between elevation 1500 and 2000 feet. The timber density becomes successively less in this area. This portion of the corridor is a good bear and moose habitat. Shallow permafrost occurs in this portion. The corridor crosses several major and minor tributaries to the Chulitna River including Honolulu Creek, Antimony Creek, Hardage Creek, the East Fork of the Chulitna River, and the Middle Fork of the Chulitna River. The corridor area is of medium scenic quality and is not readily accessible, except at the Denali Highway Crossing. 4 - 5 5. Cantwell to Healy-The corridor rises to the 3200 foot level along the west side of Reindeer Hills and then descends into the Nenana River Valley. It follows the east flank of the Nenana River northward at the 2200 foot level, through sparsely timbered country. This is an area of high scenic quality especially in the canyons. The terrain varies from rolling hills and valleys to high passes and sharp ridges. Habitats of moose, bear, and Dall sheep are traversed. Bedrock is exposed in the canyons. The corridor crosses several tributaries to the Nenana River including Slime Creek, Carlo Creek, Yanert Fork, and Montana Creek, and the Nenana River itself. It also crosses the Alaska Railroad at the Moody Tunnel, near A.R.R. Mile 354 and the Healy River. The boundary of Mt. McKinley National Park is on the west flank of the Nenana River. 6. Healy to Ester -The corridor leaves Healy and crosses the Parks Highway near Dry Creek. It then roughly parallels the west side of the highway at elevation 1500 feet, crossing several tributaries to the Nenana River. It crosses the GVEA line 1-1/2 miles north of Bear Creek, the Alaska Railroad and the Nenana River at A.R.R. l~ile 383, and the Parks Highway. The route then parallels the GVEA line. The corridor crosses the Tanana River at the Tanana P.I. and follows the Tanana River flood plain for several miles until the route again crosses the highway where it travels on the west side of the Bonanza Creek Experimental Forest. The route parallels the GVEA right-of-way the rest of the way to Ester. The Healy to Ester portion of the route passes through some private lands (mining claims, homesteads, etc.), as well as near the towns of Healy, Lignite, and Nenana. An archeological site exists near Dry Creek. Portions of the corridor are heavily forested and provide habitat for moose, caribou, and bear. Poorly drained areas in this corridor are subject to potential permafrost degradation and frost heaving. 4 - 6 - r ! r r B. Environmental Impacts Construction and maintenance of other Alaskan transmission systems has shown that most negative environmental impacts caused by a transmission system can be minimized. Golden Valley Electric Association, Matanuska Electric Association, and Chugach Electric Association have constructed and are operating several lines on poor soils and under harsh climatic conditions. Except for anticipated slight visual impacts, most environ- mental impacts caused by a transmission system would be far less than those of many transportation and communication systems. Specific areas to be impacted are discussed below. 1. Ecosystems -The major positive impact will be on human environ- ment, while adverse effects to the other ecosystems will be minimal. The route has been selected to avoid adverse impacts on these ecosystems wherever possible. The human environment will be benefited by the pro- vision of energy, vital to the growing state of Alaska. The development of many potential renewable energy resources will be made feasible by the Anchorage-Fairbanks intertie. The project will contribute to the reduction in costs of electrical energy, improvement in reliability of electrical service, and enhancement of opportunities for renewable energy resources (such as hydro and wind) to displace non-renewable energy resources (such as gas and oil) for the generation of electricity. Alteration of vegetation patterns will affect wildlife. This corridor traverses many areas of moose concentrations, and moose should benefit from the introduction of brush resulting from regrowth on the clearing. Since the clearing must be maintained, this brush area will last for the lifetime of the project. Animals such as squirrels will suffer loss and displacement. However, their faster reproductive rates will allow their populations to adjust rapidly. 4 - 7 Construction itself will affect wildlife. Larger mammals may temporar- ily leave the area to return after the construction activity. Smaller animals will suffer individual losses, but should recuperate rapidly once construction is completed. The density of forest in portions of the corridor will allow animals to move only a short distance to avoid contact with construction activities. Vegetation suppression, by whatever method, will periodically remove cover from along the right-of-way. However, due to the surrounding cover of the uncleared forests, this impact will be insignificant. 2. Recreation-The corridor will approach several recreational and wayside areas in the lower Susitna Valley. The largest of these is the Nancy lake Recreational Area. The corridor will also approach the Denali State Park, but will be separated from the Park by the Susitna River. This corridor will provide access to areas previously difficult to reach. The largest such area is that south of Nancy lake to Point MacKenzie. Dense forest and muskeg limit travel. Further north the corridor parallels the east border of Mt. McKinley National Park, being separated by the Parks Highway, the Nenana River, and the Alaska Railroad. 3. Cultural Resources -The National Register of Historical and Archaeological Sites lists the following sites which will be approached by the transmission corridor: Knik Village, Dry Creek, and the Tangle lake Archaeological District. The line will be routed to bypass these areas. During construction and preconstruction surveys, other archaeological sites may be discovered which may be eligible for nomination to the National Register. This is a positive benefit of the corridor, as ar- chaeological and other cultural resources are often difficult to find in the great Alaska wilderness. 4 - 8 r r r r 4. Scenic Resources -The southern portion of the corridor does not traverse any areas of good or high quality scenic values. The northern portion is, however, more scenic than the southern portion. In the north- ern portion the fairly continuous, moderately dense forest will provide ample screening from transportation routes. Further south, the forests are more intermingled with open muskeg. Glimpses of the transmission line will be seen from the highway or railroad through these muskeg areas. South of Nancy Lake the transmission corridor and the transportation cor- ridors diverge, and although cover becomes more sporadic, the line will no longer be visible from the transportation routes. The transmission line will not be visible from most of the Nancy Lake Recreation Area. As the Alaska Railroad and the transmission corridor approach Gold Creek, the valley becomes more confined, and screening becomes more difficult. However, it appears that the line can be concealed through most of this portion. The corridor passes through an area recognized as being of good to high scenic quality from Devil Canyon to Healy. The possibility of screen- ing throughout this area varies from moderate in the southern portion around Chulitna, to minimal in the Broad Pass and the upper and lower canyons of the Nenana River. Scenic quality will be impacted, the im- pact being a function of existing scenic quality and the opportunity for screening. The proposed line design will incorporate weathering tubular steel towers which blend well into the environment. Non-specular conductors might be used where light reflection from the line would cause unacceptable adverse visual impact. Impact in the Nenana Canyon will be high; impact on Broad Pass will be moderate to high; impact elsewhere will be moderate. Two favorable factors mitigate the impact somewhat: 1) the corridor is not visually intact as the Alaska Railroad and the Anchorage-Fairbanks Highway have already reduced scenic quality some- what; and 2) the major views south of the canyons are to the west, toward the Mt. McKinley massif, whereas the transmission line corridor lies to the east of the transportation routes. 4 - 9 5. Social -Some economic impact can be expected, as flying services, motels, restaurants, and entertainment facilities receive business, not only from the transmission line workers, but from related personnel. Due to the high cost of a low-load tap on a high voltage line, the likelihood of use of the energy by small communities along the corridor is remote. However, in places where the demand could justify such a tap, it would pr'ov ide a re 1 i ab 1 e source of e 1 ect rica 1 energy for growing communities. C. Special Impact Mitigation Efforts During Construction Right-of-way clearing will be accomplished by approved methods such as the hydro axe, and chips will be spread along the right-of-way. The line will be screened wherever possible. The towers will be designed to blend into the environment, thereby reducing visual impact. Movement of men and equipment during construction will be scheduled to avoid excessive damage to the ground cover. This is generally accom- plished by winter construction. The tower design will allow movement of men and equipment along the right-of-way centerl-ine, thereby elimi- nating the need for an access road in addition to the transmission line clear-ing. Major river crossings will be required over the Talkeetna River, Tanana River, Healy Creek, and the Susitna River. Minor stream crossings may be made either by fording or ice crossings. Special efforts will be made to avoid siltation of fish streams. Oil will be carefully handled to avoid spillage. Where larger quantities of oil are to be stockpiled, dikes will be constructed to protect against spills. Since most of the construction will occur far from communities, noise is not anticipated to be a problem. Suitable muffling devices will be used to protect men and wildlife from excessive noise. 4 -10 fi''', p- ,_, 1" ,...., - Prior to and during construction, special efforts will be made to consult with State historical and archaeological authorities, the Soil Conserva- tion Service, the Bureau of Land Management, the Alaska Department of Fish and Game, and the U.S. Forest and Wildlife Service, and any other agencies having jurisdiction over the construction area, in an effort to ensure sound environmental practices. 4.6 REFERENCES L 2. Robert W. Retherford Associates, North Slope Natural Gas Transport Systems and Their Potential Impact on Electric Power Supply and Uses in Alaska, March 1977. U.S. Army Corps of Engineers, Southcentral Railbelt Area, Alaska, Upper Susitna River Basin Interim Feasibility Report, (Appendix I, Part II (G) Marketability Analysis, (H) Transmission System, (I) Environmental Assessment for Transmission Systems, December 1975. 3. Kozak, Edwin, under the direction of J. R. Eaton, Performance Characteristics of a 350-Mile Electric Power Transmission Line (Fairbanks to Anchorage), A project in EE 494, Department of Elec- trical Engineering, University of Alaska, June 1973. 4. Ch2M-Hill, Electric Generation and Transmission Intertie System for Interior and Southcentral Alaska, 1972. 5. Federal Power Commission, Alaska Power Survey, 1969. 6. Alaska Power Administration, Alaska Rai-lbelt Transmission System, working paper, December 1967. 7. The Ralph M. Parsons Company, Central Alaska Power Study, undated. 8. The Ralph M. Parsons Company, Alaska Power Feasibility Study, 1962. 4 -11 EXISTING TRANSMISSION LINES INTERTIE ROUTE ALTERNATE INTERTIE ROUTE NEW LINE SCHEDULED FOR CONSTRUCTION -···-···-FUTURE LINE "'"'"'"' ''" SUBMARINE CABLES UTILITY SERVICE AREA ROBERT W. RETHERFORD ASSOCIATES CONSULTING ENGINEERS A DIVISION OF ARKANSAS GLASS CONTAINER CORP. ~ w;., \ \ 1 ~~\ NENANA-FAIRBANKS-TANANA TRANSMISSION SYSTEM ---EXISTING TRANSMISSION LINES INTERTIE ROUTE ALTERNATE INTERTIE ROUTE NEW LINE SCHEDULED FOR CONSTRUCTION -···-.. ·-FUTURE LINE //// ,,,, SUBMARINE CABLES UTILITY SERVICE AREA FIGURE 4-2 lt"~l ROBERT W. RETHERFORD INTERNATIONAL ENGINEERING COMPANY, INC. •• CONSULTINQ ENGINEERS ::; ~-. -~ A MORRISON -KNUDSEN COMPANY ~ ' A DI VISION OF ARKANSAS GLASS CONTAINER CORP. f ~ ~.~'{fj!J~ 'l!r z~~ ~~,J:,., -~~~~=-· .:r1fi\t~""-~~)\~--.-~~;~f{~~~r:-~nr · (;.L-__ •• ~--' ANCHORAGE-MATANUSKA -SUSITNA -GLENNALLEN-VALDEZ TRANSMISSION SYSTEM : .. .. • Nord }O' hla nd~.O • "' Su s ond,() 0 BARREN .. ISlANDS Aiol1 k <> ~c'J Ha'bo' Island ~No too lslo,.,d o• • OCh•Sw@ll /:.land NG SOUND ~Stor•y Island ~C~@/eak ulond f to no iS land ~Naked Is/end PRINCE lVILLI ,\/ SOUND :·i:i: Seal ls /ond .. &Ji~ded Islands LEGEND EXISTING TRANSMISSION LINES INTERTIE ROUTE ALTERNATE INTERTIE ROUTE NEW LINE SCHEDULED FOR CONSTRUCTION -···-.. ·-FUTURE LINE ///;' "" SUBMARINE CABLES UTILITY SERVICE AREA SCALE 1:1000,000 I ELEVATION IN METERS INTERNATIONAL ENGINEERING COMPANY, INC. A MORRISON -KNUDSfN COMPANY ----· ROBERT W. RETHERFORD ASSOCIATES CONSULTING fNGINffRS A DIVISION 01' ARKANSAS GLASS CONTAINfR CORP. COOK INLET -KENAI PENINSULA TRANSMISSION SYSTEM CHAPTER 5 TRANSMISSION LINE DESIGN r -' [\ I ! r 5.1 BASIC DESIGN REQUIREMENTS CHAPTER 5 TRANSMISSION LINE DESIGN Experience in Alaska with both wood-pole H-frame, aluminum lattice guyed-X towers, and tubular steel guyed-X towers with high-strength conductors (such as Drake 795 kcmil ACSR) has demonstrated the excellent performance of lines designed with relatively long spans and flexible structures. This general philosophy has been followed in establishing the input param- eters for the Transmission Line Cost Analysis Program (TLCAP) used to optimize line designs for the Anchorage-Fairbanks Intertie study. Sample outputs of TLCAP and descriptions of the program methodology are found in Appendix B. The results of this computer analysis for 230-kV lines favor relatively long spans (1300 ft) and high-strength conductors (such as Cardinal 954 kcmil ACSR). This confirms the previous Alaskan experience and contributes substantially to a more economical design, as Chapter 7 will illustrate. 5.2 SELECTION OF TOWER TYPE USED IN THE STUDY Due to rather unique soil conditions in Alaska, with extensive regions of muskeg and permafrost, conventional self-supporting or rigid towers will not provide a satisfactory performance or solution for the proposed intertie. Permafrost and seasonal changes in the soil are known to cause large earth movements at some locations, requiring towers with a high degree of flexibility and capability for handling relatively large founda- tion movements without appreciable loss of structural integrity. The guyed tower is exceptionally well suited for these type of conditions. Therefore, the final choice of tower for this study was the hinged-guyed X-type design, which has been considered for both the 230-kV and 345-kV 5 - 1 alternatives. These towers are essentially identical in design to towers presently used on some lines in Alaska, which have proven them- selves during more than ten years of service. The design features include hinged connections between the leg members and the foundations which, together with the longitudinal guy system, provides for large flexibility combined with excellent stability in the direction of the line. Transverse stability is provided by the wide leg base which also accounts for relatively small and manageable footing reactions. The foundations are pile-type, consisting of heavy H-pile beams driven to an expected depth of 20 to 30 feet depending upon the soil conditions. Tower outlines with general dimensions for the two voltage levels are shown on Figures 5-l and 5-2. 5.3 DESIGN LOADING ASSUMPTIONS According to available information and experience on existing lines, heavy icing is not a serious problem in most parts of Alaska. NESC Heavy Loading is presently used for all line designs throughout the Rail- belt region. However, there are locations where Light Loading probably could be used. Some line failures have occurred due to exceptionally heavy wind combined with very little or no ice. Such locations should be identified and carefully investigated prior to the final line design. In this study, NESC Heavy Loading or heavy wind on bare conductor (cor- responding to NESC Light Loading) was used, whichever is more severe. 5.4 TOWER WEIGHT ESTIMATION In order to arrive at realistic tower weights and material costs for the study, actual tower designs for both the 230-kV and the 345-kV 5 - 2 - - .., - - r-, I r \ / r r alternatives were obtained from Meyer Industries of Red Wing, Minnesota (Ref. 1). This company has designed similar towers for other lines in A 1 as ka. Based on these reference designs and additional manual calculations, tower weight formulas were developed to account for variations in tower weight due to changes in tower height and load as a function of the type of conductor used. 5.5 CONDUCTOR SELECTION Conductor size (see Table 5-1) was selected by the use of the Transmission Line Cost Analysis Program (TLCAP) which was specially developed by IECO for this type of study. Given an appropriate range of conductor types and sizes, span lengths, and other pertinent data, TLCAP determines the most economical conductor-span combination. The program includes a sag-tension routine which calculates the con- ductor sag and tension for a given set of criteria. Using this informa- tion, the tower height and loads are then determined for each discrete span length. These values are then applied to the tower weight formula with the pertinent overload factors included. In the process of this analysis, the program also evaluated the effect of the cost of the power losses over a specified number of years. The power losses were minimized by varying the sending and receiving end voltages by ~ 10% and by providing required shunt compensation at both line terminals. Applicable material and labor costs, together with pro- jected escalation rates, were included to enable the program to calculate the total installed cost of the line. A discount rate of 7% per annum was used for the determination of the present worth of transmission line losses. 5 - 3 For this particular study, material and labor costs were obtained from 11 as built 11 cost information realized on recently completed (138-kV and 230-kV) lines in Alaska. 5.6 POWER TRANSFER CAPABILITIES Preliminary transmission line capabilities, based on surge impedance loading (SIL) criteria, were obtained from the National Power Survey Re- port (Ref. 2). Additional investigations indicate that for the 230-kV alternatives (Cases IA, IB, and ID), the calculated intertie power angle is near 30 degrees. To improve the 230-kV intertie's steady state and transient transmission capability, series capacitors will be necessary. Interconnected power system studies should be performed to determine the final series and shunt compensation requirements. Such studies are out- side the scope of this work. 5.7 HVDC TRANSMISSION SYSTEM Because of its asynchronous nature, the interconnection of two isolated alternating current (ac) systems by a point-to-point HVDC transmission link provides the desired power exchange without being prone to inherent stability problems. Furthermore, HVDC transmission can provide stabilizing power, and be very effective in damping system oscillations. While the state-of-the-art in HVDC technology is advancing, the resulting develop- ments are keeping pace with inflation. Preliminary investigations have shown that HVDC transmissi~n, using 180- kV mono-polar transmission and ground return, is competitive with single- circuit 230-kV ac transmission in the transfer 130 MW of power over 323 miles. However, if the point-to-point transmission link is required to supply intermediate locations with power (either initially or in the future) then it is unlikely that de transmission can be competitive with an ac alternative. 5 - 4 ' ) -I I - ~ l { r r r 5.8 REFERENCES 1. Letter from ITT Meyer Industries to Robert W. Retherford Associates, Anchorage, Alaska, January 15, 1979. 2. FPC Advisory Committee Report No. 6, National Power Survey, Vol. II, p. IV2-12, 1964. 5 - 5 CJ1 0'\ _) J TABLE 5-l CONDUCTOR SIZE SELECTION CRITERIA Optimum ACSR Loa~/ Case and Voltage Line Length Conductor Per Circuit A 1 te rnat i vJ-1 Interconnection (kV + 10",q (miles~ (kcmil) (M~J l I A & B Anchorage-Ester 230 s/c 323 1/c -954 130 I c Anchorage-Ester 345 s/c 323 2/c -795 380 I D Anchorage-Palmer 230 s/c 323 2/c -954 130 Healy-Ester I I A Anchorage-Devil Canyon 345 s/c'}j 155 2/c -954 600 Devil Canyon-Ester 230 s/cl/ 189 1/c -1510 185 Watana-Devil Canyon 230 s/cl/ 27 1/c -2156 488 11 Case I Alternatives exclude the proposed Susitna Project; Case II Alternative A includes the Susitna Project. £! 100% voltage support at both ends. ]_/ Two si ngl e-ci rcuit 1 i nes on the same right-of-~'/ay. Note: s/c = single circuit; 1/c = single conductor; 2/c = two conductor bundle. '""<-· J ---J ,J ) .,,'---.~ .J ~ c~--~ J ,c_ "I ··--··· .~--J } L. ~.J ~.J .... J ~ .J J FIGURE 5-1 20'---•J..ol~c-------20' •! I~ - 89:3' - 230KV TANGENT TOWER ~··'\ 5 - 7 FIGURE 5-2 l~""'""f------27' ------i~ll ...... f------27' -----ll>--11 - - 94.7' ·~· - 345KV TANGENT TOWER - 5 - 8 CHAPTER 6 SYSTEM EXPANSION PLANS -i - CHAPTER 6 SYSTEM EXPANSION PLANS One benefit of transmission interconnection between two independent power systems is the reduction in the installed generating capacity that is possible, while maintaining the same electric power supply (generation) reliability level for both the independent and interconnected power sys- tems. To calculate this reduction in installed generating plant capacity (megawatts), generation expansion plans had to be developed for both the independent and the interconnected power systems. This chapter describes the actual process used in the generation expan- sion planning for the independent power systems of the Anchorage and Fairbanks areas, and for an interconnected Anchorage -Fairbanks power system. Generation expansion planning is a rather complex process. A brief description of the somewhat simplified method used in this Economic Feasibility Study is described below. 6.1 GENERATION PLANNING CRITERIA A. Generating Unit Data Existing generating unit data were obtained from the Battelle (Ref. 1) and University of Alaska, August 1976 (Ref. 2) reports. These available data were reviewed and updated using new information obtained by IECO-RWRA engineers during interviews with the managers of the Railbelt utilities. The updated existing generation unit data is presented in Tables 6-l and 6-2. Preliminary information on near future (1979-1986) generation expansion planning, including probable generation capacity requirements, for the AML&P and CEA systems was obtained directly from the two utilities. More 6 - 1 detailed information on GVEA generation expansion plans was available in the review copy of the report Power Supply Study -1978 (Ref. 3) and the Report on FMUS/GVEA Net Study (Ref. 4). B. Installed Reserve Capacity At the present time, there is apparently no uniform pol icy as to the required installed generation reserve margins for Alaskan electric power utilities. By definition~ the installed generation reserve capacity includes spinning reserve, 11 hot" and "cold" standby reserves, and gener- ating units on maintenance and overhaul work. No effort is made in this study to separate the installed reserve capacity into spinning and other types of reserves. Utilities in Alaska currently keep spinning reserves to the very minimum, mainly because of the no-load fuel cost incurred by the spinning reserves, and because most generating units in Alaska•s Railbelt area are quick starting, combustion turbine-type units. This situation may change in the future when new larger, slow starting, thermal power plants are constructed, exceptions being hydro plant units which can be started rather rapidly. To develop alternative generation expansion plans for this study, guide- lines for installed reserve generation capacity had to be established. A minimum of 20% reserve margin or the largest single unit at the time of peak system load was decided on as the installed generation reserve guideline. In general, the 20% value is close to the actual installed reserve margin of most u.s.A. utilities. Recently, the Department of Energy•s Economic Regulatory Administration reported the following for the 1978 winter peak load of the lower 48 states: "According to the forecast, total available power resources for the lower 48 states will total nearly 500,000 MW. Peak demand is anticipated at 380,000 MW, for a reserve of nearly 120,000 I~W or 31.5 percent. The lowest reserve -the 21.1 percent -will occur for the southeastern Electric Reliability Council, the DOE said, with the Mid-Atlantic Council experi- encing the highest reserve margin at 45.1 percent" (Ref. 5). 6 - 2 - - - - .... - C. Unit Retirement Except for the Knik Arm Power Plant (CEA), no other generating units were reported for retirement by the Railbelt utilities during the 1980-1992 period. Later, to include the effect of the proposed Susitna Hydroelectric Project and to obtain a better economic analysis, this study period was extended through 1997. An assumption was made that the generati~g units available from 1980-1992 will also be available from 1993 through 1997. Many of them, however, will serve as system standby reserve units. D. Generation Expansion Planning To-program the economic feasibility study and to establish transmission line interconnection benefits, generation expansion plans for the 1980- 1997 period were developed for: • Independent Anchorage area system. • Independent Fairbanks area system . • Interconnected Anchorage-Fairbanks system (intertie for re- serve sharing only). • Interconnected Anchorage-Fairbanks system (intertie for re- serve sharing and power transfer) . • Interconnected Anchorage-Fairbanks system (with Susitna Hydro- electric Project). Basically, generation planning includes three aspects: forecasting future loads (previously described in Chapter 3); developing generation reserve and reliability criteria (discussed later in this chapter); and determining when, how much, and what type of generation capacity is needed (which is discussed below). Generation timing and capacity were determined by the most probable load forecasts for the Anchorage, Fairbanks, and combined Anchorage-Fairbanks areas, as described in Chapter 3. 6 - 3 Unit sizes for the alternative system expansion plans were determined by the ability of the power system to withstand the loss of a generating unit (or units) and still maintain reasonable system generation reliability. In determining unit sizes, due consideration was given to the valuable generation expansion planning data for the 1979-1986 period which was obtained by IECO-RWRA engineers from the Railbelt area utilities, and as the power system grows the economy of larger unit sizes. IECO-RWRA engineers determined the type of generation mix for the expan- sion plans based on: 1 Preliminary planning information obtained through interviews with Railbelt utilities. • Information available in the Battelle Report and Alaska Power Administration's January 1979 report draft (Ref. 6). • The judgment of IECO-RWRA power system planners. Most of the planned generation additions are baseload-type thermal steam power plants burning coal, gas, or oil as fuel. They are mixed with a few additional peaking-type combustion turbine generating units using natural gas or oil as fuel. It is assumed that in the later years of this study many existing combustion turbine generating units, presently used as baseload or intermediate units, will become peaking or standby units. 6.2 MULTI-AREA RELIABILITY STUDY A. Purpose The PTI Multi-Area Reliability (MAREL) Computer Program is used for alternative generation expansion planning, mainly for its ability to maintain a nearly constant level of generation supply reliability in all cases. This approach provides a nearly equal reliability level as far as generation ability to meet the load is concerned. The MAREL program 6 - 4 - - - - - - - r I - r r ! ' I""' j ,, I r gives reliability equivalence to both individual area and interconnected system generation planning alternatives. The MAREL program manual (Ref. 7) introduces this program with the following: 11 The PTI Multi -Area Re 1 i ability Program MAREL determines the reliability of multi-area power systems. It has been written in FORTRAN IV for use on a PRIME 400 time-sharing computer. Reliability indices computed by the program include system loss of load probability (LOLP), LOLP values for the indivi- dual areas, probability of various failure conditions and probability that each transmission (intertie) link is limit- ing in the transfer of generation reserves from one area to another.11 MAREL program results helped determine the effectiveness of a transmission line intertie between the Anchorage and Fairbanks areas, and established the amount of generating capacity needed to give the individual areas approximately the same LOLP as for the interconnected system. MAREL study results are also applicable to the alternative which includes the Upper Susitna Project. In this instance the study became a three area reliability study with the Susitna area having only net generation and no load. B. Reliability Index To perform individual and interconnected system reliability studies (MAREL), it was necessary to select a reference system generation reliab-ility index. As described above, the MAREL program uses LOLP calculation techniques for each study case. For each load condition the program user adjusts input data, specifically generator unit sizes, generator types, location of generating plants, and intertie capacities, to obtain generation ex- pansion plans of near equal reliability for various alternatives. The LOLP method is very much the adapted method used by U.S.A. utilities during the last 30 years. According to the IEEE/PES Working Group on 6 - 5 Performance Records for Optimizing System Design, Power System Engineering Committee (Ref. 8): "This {LOLP reliability) index is defined as the long run average number of days in a period of time that 1 oad exceeds the available installed capacity. The index may be expressed in any time units for the period under consideration and, in general, can be considered as the expected number of days that the system experiences a generat·ing capacity deficiency in the period. This index is commonly, but mistakenly, termed the 11 loss of load probability, (LOLP)11 • A year is generally used as the period of consideration. In this case, the LOLP index is the long-run number of days/year that the hourly integrated daily peak load exceeds the available in- stalled capacity." There is no standard value of LOLP which is used throughout the electric power industry. However, one day in ten years is a very much accepted value by the lower 48 utilities. Since to the authors• knowledge, LOLP index has not previously been used in Alaska, it was decided to use one day in ten years as reference LOLP index in this study. The use of this LOLP index may imply larger generation reserve margins than are presently used in Alaska, but an equal or even lower LOLP index is justifiable for Alaska for at least the following reasons: • In very cold climatic zones the loss of electric power may be more critical than in more temperate climates. • There is very little ·information on existing generation and transmission outage rates in Alaska. Therefore, there is more uncertainty about the study input data. • At_present. most of the power systems in Alaska are independently operated. In case of emergency, utilities cannot rely on help from neighboring utilities or power pools as can most of utilities 6 - 6 J!!lllll I - - - - -- - r .... - .... - C. in the lower 48. Therefore, a lower LOLP reliability index is justifiable. • Higher planned generation reserves may be needed to provide protection against possible unplanned delays in construction of new larger thermal units. Program Methodology A general description of the MAREL computer program methodology is con- tained in Appendix C. The particular program application to this study is 11 Planning of interconnections to achieve regional integration and more widespread sharing of generation reserves 11 (Ref. 7). Briefly, the program models each area as a one-bus system to which all generators and loads are connected. Transmission interties between areas are modeled as having limited power transfer capabilities and specified line outage rates. The method assumes that each area takes care of its own internal trans- mission needs. D. Load Mode 1 Annual load models were developed for the Anchorage and Fairbanks areas. Daily peak load data for 1975 were obtained from AML&P, CEA, FMUS, and GVEA. The Railbelt utility representatives agreed that 1975 was a typical year with normal weather conditions. The 1975 load models were converted into per unit system for the MAREL program. The computer program multi- plied this 1975 load model (input) by the respective study year peak loads to obtain annual load models for each year of the study. Forecasted annual peak loads and the per unit annual load models for the Anchorage and Fairbanks areas are shown in Tables 6-3 through 6-6. Annual demand curves indicating biweekly non-coincident peaks are shown on Figure 6-1. Figure 6-1 also indicates that there is very little diversity between the loads of the Anchorage and Fairbanks areas . 6 - 7 E. Generating Unit Data Information on existing generating unit data, as indicated in Tables 6-1 and 6-2, was used in the study. Unit base ratings were rounded off to the nearest megawatt in the study. Sizes for new generating units used in the expansion plans are indicated on Figures 6-2 through 6-8. Generating unit outage rates, which are required for calculating LOLP indexes, were obtained from the most recent Edison Electric Institute (EEl) report on equipment availability (Ref. 9). The rates for combustion turbines were obtained from the actual operating experience of CEA and GVEA at the Beluga and Zehnder Power Plants. The EEl publication defines the forced outage rate as: Forced Outage Rate = FOH/(SH + FOH) x 100 Where FOH represents forced outage hours and SH represents service hours. Generating unit outage rates used in the MAREL study are indicated below: Unit Designation Combustion Turbine* Hydroelectric Plant Thermal Steam Plant (small units) ' Thermal Steam Plant (100-200 MW) Thermal Steam Plant (300 MW) Forced Outage Rate (%) 5.5 1.6 5.9 5.7 7.9 *The Forced Outage Rate for combustion turbines was based on the follow- ing ·information: • CEA experience at Beluga during 1977-1978 period, six units base loaded. 6 - 8 - -i - - - - - - - - - - -' r I l r - - - Unit availability Scheduled maintenance Forced outage 87% of the time 8% of the time 5% of the time Therefore, the calculated Forced Outage Rate equals 5.4%. • In 1975 GVEA experience at Zehnder Station, Units No. 1 and 2 provides calculated Forced Outage Rates of 4.2% and 4%, re- spectively; however, these units were basically standby units. F. Generating Unit Maintenance The MAREL program automatically schedules generating unit maintenance within the specified restnctions. For the purpose of this study, it was assumed that no unit maintenance will be scheduled during the November- March winter season. G. Intertie Data The MAREL program models the transmission intertie by limiting intertie transfer capabilities and considering intertie outage rates. No load loss sharing method was used. This means that one area will share its generating reserves only up to the limit of intertie transfer capability or available reserves in the other area, whichever is limiting. The forced outage rates (on a per year basis) used in the study for trans- mission and line terminal equipment are indicated below: Line Voltage (kV) 230 345 Forced Outage Rate (per unit/100 miles) 0.00113 0.00225 Note: The following outage rate was used for both 230-kV and 345-kV line terminals: 36 hours/10 years. 6 - 9 6.3 SYSTEM EXPANSION PLANS A. Planning Study Period Based on generation planning criteria and the results of the MAREL re- liability study (previously described in this chapter), alternative gener- ation expansion plans were developed. The 1984-1997 period was selected for the alternative expansion plans for the following reasons: • 1984 is the earliest year when the interconnected system can be operational. • The 1992-1997 period includes the Upper Susitna .Hydroelectric Project, based on the optimistic assumption that Watana Unit No. 1 will be on-line in January 1992. • The study period is long enough for the present worth economic analysis method, and includes most of the costs and benefits obtainable by the introduction of an intertie in 1984. To close ~he gap between the existing generation systems and the first study year (1984) of the intertie economic feasibility study, generation expansion plans for the independent Anchorage and Fairbanks areas for 1980 through 1983 were developed. Information on planned generation additions supplied by the generating utilities in the Railbelt area was used for this purpose. B. Independent System Expansion Plans Generation expansion plans for the independent Anchorage and Fairbanks systems were also needed to calculate economic benefits of the inter- connection. The planned generation additions consist of thermal base load and peaking units. They do not include the Upper Susitna Project (Watana and Devil Canyon Hydro Plants), which are only included in the 6 -10 - - ..... - - ,.... i! r ,.... ! interconnected system expansion plans. The independent Anchorage and Fairbanks generation expansion plans are indicated on Figure 6-2 for the probable load forecast case and Figure 6-6 for the low load forecast case. C. Interconnected System Expansion Plans Two cases of system interconnection were studied-Case I, direct inter- connection between Anchorage and Fairbanks (Ester), and Case II, inter- connection between Watana-Devil Canyon with Anchorage and Fairbanks sys- tems. Under Case I the alternatives were developed as follows: • Case IA includes a single-circuit 230-kV transmission line having 130-MW power transfer capability allocated for reserve sharing only. This plan is shown on Figures 6-3 and 6-9 for the probable load forecast case and on Figures 6-7 and 6-9 for the low load forecast case. • Case IB includes one single-circuit 230-kV transmission line (1984-1991) and two single-circuit 230-kV transmission lines (1992-1997) having the following generation reserve sharing capabilities: 100 MW (1984-1987), 130 MW (1989-1991) and 190 MW (1992-1997). In addition, this alternative has a firm power transfer capability of 30 MW (1984-1987), supplying 14% of peak load in Fairbanks area in 1984, and 70 MW (1992-1997) supplying 18% of peak load in Fairbanks area in 1992. This plan is shown on Figures 6-4 and 6-9 for the probable load forecast case and on Figures 6-8 and 6-9 for the low load forecast case. • Case IC includes one single-circuit 345-kV transmission line having a total of 380 MW power transfer capability allocated for generation reserve sharing and for firm power transfer. The case is similar to Case IB (230 kV) except that only one 345 kV line is required during the 1992-1997 period. This plan is shown on Figures 6-4 (similar) and 6-10. 6 -11 • Case ID is the same as Case IA, except with intermediate switch- ing stations at Palmer and Healy. This plan is shown on Figures 6-3 and 6-11 for the probable load forecast case and on Figures 6-7 and 6-11 for the low load forecast case. Under Case II, only one solution was studied: two single-circuit 230-kV transmission lines from Watana to Devil Canyon; two single-circuit 230-kV lines from Devil Canyon to Ester (Fairbanks); and two single-circuit 345-kV lines from Devil Canyon to Anchorage. D. Reliability Indexes The results of the MAREL study show loss of load probability (LOLP) indexes for independent system expansion plans and plans for an inter- connected system (with and without the Upper Susitna Project), and are indicated in Tables 6-7 through 6-12. As previously discussed in Subsection 6.28, the LOLP index of one day in ten years (0.1 day/year) was used as a reference standard throughout the study for comparing different alternatives. During the performance of the MAREL study the LOLP index was kept as close to the standard as reasonably possible. 6. 4 REFERENCES 1. Battelle Pacific Northwest Laboratories, Alaskan Electric Power, An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region, Vol. I, March 1978. 2. University of Alaska, Institute for Social and Economic Research, Electric Power in Alaska, 1976 -1995, August 1976. 3. Stanley Consultants, Power Supply Study-1978 for Golden Valley Electric Association, Inc. 4. Alaska Resource Sciences Corporation, Report FMUS/GVEA Net Study, Vol. 1, May 1978. 6 -12 - _., J - - - ,_ I I - i 5. Electric Light and Power, Capacity Can Meet Winter Peaks -DOE, November 1978. 6. 7. 8. Alaska Power Administration, Upper Susitna River Project, POWER MARKET ANALYSES, Draft, January 1979. Power Technologies, Inc. PTI Multi-Area Reliability Program (MAREL), Computer Program Manual , September 1978. 11 Reliability Indices for Use in Bulk Power Supply Adequacy Evalua- tion'', IEEE Transactions on Power Apparatus and Systems, Vol. PAS-97, No. 4, July/August 1978. 9. Edison Electric Institute, Report on Equipment Availability for the Ten-Year Period 1967-1976, December 1977. 6 -13 6 -14 iF"" I! 'I ·: ·~ !!"""' ,.... 'I " 1] r"" r r I I r ,.... ,~"""' Unit Name/Location Reference --- TABLE 6-2 EXISTING GENERATION SOURCES FAIRBANKS -TANANA VALLEY AREA Unit Rat i n9 Year of Base Peak Install at ion Type (kW) (kW) FAIRBANKS MUNICIPAL UTILITIES SYSTEM {FMUS) Fairbanks Chen a 1 1954 ST 5,000 Fairbanks Chen a 2 1952 ST 2,000 Fairbanks Chen a 3 1952 ST 1,500 Fairbanks Chen a 4 1963 ST 20,000 Fairbanks Chena 5 1970 SCGT 5,350 7,000 Fairbanks Chen a 6 1976 SCGT 23,500 Fairbanks Diesel 1 1967 Diesel 2,665 Fairbanks Diesel 2 1968 Diesel 2,665 Fairbanks Diesel 3 1968 Diesel 2,665 GOLDF:N VALLEY ELECTRIC ASSOCIATION {GVEA~ Zehnder Sub. Unit 1 1971 SCGT 17,553 20,000 Zehnder Sub. Unit 2 1972 SCGT 17,553 20,000 Zehnder Sub. Unit 3 1975 SCGT Zehnder Sub. Unit 4 1975 SCGT Zehnder Sub. Units 1-7 1970 Diesel Healy Unit-1 1967 ST Healy Diesel 2,500 Northpole Unit 1 1976 SCGT 64,800 70,000 Northpole Unit 2 1977 SCGT 64,800 70,000 U. of Alaska Units 7&8 Diesel Delta Diesel 6 -15 Dependable Capacity (kW) Remarks 17.400 Peaking Service 17,400 3,500} Leased to HEA 3,500 (1977-1979) 12,900 26,200 5,100 500 ~1obi l e Unit TABLE 6-3 LOAD MODEL DATA ANCHORAGE AREA PROBABLE LOAD FORECAST CASE ANNUAL PEAK LOAD IN MW (1983-1997) 709. 077. 977. 1080. 1!96. 1313~ 1441. 1581. 1724. 1881. 2041. 2215. 2402. 2591. 2794. INTERVAL PEAK LOADS IN P. U. OF ANNUAL PEAK LOAD (26 INTERVALS I YEAR) .U333 .6667 .7404 .7500 .6571 .6346 .6122 .5865 .5481 .3353 .5224 .3168 .4904 .5032 .4968 .5160 .5737 .5769 .6154 .~827 .8429 .8526 .91351.0000 DAILY PEAK LOADS IN P. U. OF INTERVAL PEAK LOAD (260 WEEK DAYS I YEAR) 1. 0000 .9769 ,9731 .9t§36 .9500 .9462 .6962 .8731 ,81577 ,8423 1.0000 .9303 .9663 .9663 .9615 .9615 .9519 .9519 .9423 .9375 I. OLHJO .9913 .9784 .9027 .9697 .9654 .9437 ,9307 .9221 .8918 I. OUiJ() .9829 .9487 .9359 .9017 .8889 .8889 .8846 .8333 .• 8034 ! .0000 .9512 .9317 .9171 .9171 .9073 .9073 .9024 .9024 .8976 I, 000[) .9048 ,9798 .9747 .9646 .9495 .9444 .9343 .9293 .9141 1.0000 .9686 .9634 .9529 .9529 .9476 .9424 ,9372 .9058 ',9058 ! .ooou .9781 .9727 .9617 .9563 .9563 .9344 .9344 .9071 .9071 I • (i(}c)() .9B83 .9883 .9825 .9825 .9708 .9708 .9649 .9591 .9415 l. \)00\) . 9')40 ;9620 .9701 .9581 .9461 .9401 .9341 .9281 .9162 1 • (l\l,:ll . '}?39 .9877 .9571 .9571 .9509 .9509 .9448 .9202 .8589 ~ . 0·.' ',') . ')')38 .98t4 .9689 .9565 .9379 .9379 .9379 .9255 .9255 l. !lO(l,) .9010 .9684 .9620 .9494 .9494 .9430 .9367 .9304 .9177 l . 000() .9004 .9739 .9739 .9673 .9608 .9542 .9542 .9477 .8824 ! • l!000 . 9El73 .9745 .9554 . 94.·90 .9490 .9427 .9427 .9299 .9299 ' . ll CWO 1 . 0')00 .9935 .9671 .9806 .9742 .9677 .9613 .9548 .9484 1.0000 • •)938 .9614 .9689 .9627 .9565 .9565 .9441 .9441 .9379 I . (l(lil(l .9777 .9609 .9441 .9274 .9106 .8883 .8715 .6715 .8045 •. \hJ(ll) .9944 .9944 .9722 .9722 .9722 .9611 .9276 .9222 .9222 l ,Ul:OO • <)943 .9896 .9896 .9687 .9583 .9531 .9375 .9323 .8802 ! • t~ (~ :· 0 .•JB59 .9484 .9437 .9390 .9296 .9249 .9202 .9155 .9014 1, {)!Ill) .9962 .9658 .9466 .9466 .9087 .7985 .7757 .7719 .8555 ~ . \hltl() t ,11()()0 .9887 .9662 .9549 • 9511 .9474 .9398 .9361 .9323 J • \llHII.! . •i754 .8632 .8596 .8421 .8386 .6386 .8386 .6386 .8175 I. tHHh} .'HHO .9679 .9519 .9359 .9327 .9327 .9135 .8654 .8045 1 • 01)0() . 'i7ao .9730 .9614 .9614 .9575 .9575 .9537 .9421 .8340 6 -16 ~ .5064 .8301 ""''I J ~ ~ I """"' """l ,I!II!Kl! ~ ~ ~ r r I r r ( r I TABLE 6-4 LOAD MODEL DATA FAIRBANKS AREA PROBABLE LOAD FORECAST CASE ANNUAL PEAK LOAD IN MW ( 1983 -1997 ) 196. ~~~-231. 249. 270. 291. 313. 338. 362. 390. 416. 446. 477. 511. 547. INTERVAL PEAK LOADS IN P. U. OF ANNUAL PEAK LOAD ( 26 INTERVALS I YEAR~ 41. B7590. ()1)900. 73710.76040.57490.59710.56630.51 110.43240l41130. 38330.37470.3587 n. :l 5~mo. ~mono. 41770. 420 1 o ~ 43730. 46190. 53190. 57490 .89 190; 93370. 9349 1 • 00000.7690 DAILY PEAK LOADS IN P. U. OF INTERVAL PEAK LOAD (260 WEEK DAYS /YEAR) : • illliHH). 'i7480. 94670.94670.94530.93130.89480.86540. 84290• 8177 :.00000.93670.92790.92790.90510.89980.88050.85940.82790.7891 l. 00000. 9(}330. 96670 .94830·. 94000.92330.90330.88000. 86670'. 8267 1.00000.97580.96120.94510.86910.83200.82390.81100.79000;6769 1.00000.90500.98290.95940.95300.94660.91880.90810.90170~8825 !.00000.99790.99590.98770.97940.95880.93620.90530.89300.8827 r.onooo.9U4B0.95010.93710;91970.89370.88070.87200.B6120~8091 l . 0\hlOO. 96ll70. 96150.95190.93510. 91590.88700.88220. 87980~ 8558 l. 00000. ')9150. 99150.99 150.97160.96870.93180.89200. 88920'.8693 ! • 0(;00 I. 00000.96120.93130.92840. 92840.92240. 90750.90450.8955 l.0~000.99040.99040.94550~92310.91990.91670.91350.87820J8558 1.00000.96720.95410.92790.92460.90490.89840.89510.87870~8721 1.00000.96920.96920.95890~95890.94520.94520.93150.92120~9041 I • 00000. (Hl')60. 97220.96870. 95830. 94790. 934·00, 92360.92010. 8507 1.00000.96770.93870.93230.91290.90320.90320.90320.87100~8677 I. 110000. 87350.87060.86760,86460.85880.84710,84410.83820.8059 t .llOOOO. 94440.90640.90640.89470. 82750.82750.82460.81870.8012 1.00000.99720.97750.96350.96350.94940.93820.93820.91010.8904 1.00000.99470.96810.93090.92820.90960.90690.90160.88830.8856 t.onooo.9BB50.93300.91450.90990.B96I0.88910.88450.86370~8568 1.00000.99150.98080.97650.94020.92950.92740.91880.91450,9017 t.n0000.96690.91180.89260J88840.79890.73970.64460.61020.6088 1,00000.97710.91050.90790~90790.89340.88950.88550.86320~8434 l.I~0C00.97Il0.86330.83050.81870.79630.79240.74510.73320.7201 1 . tll:ooo. 99510.98160.97300.97170. 955ao. 91650.88450.82430.6818 !.00000.99840.93930.92010.89940.88980.88500.84820.81310.7971 6 -17 TABLE 6-5 LOAD MODEL DATA ANCHORAGE AREA LOW LOAD FORECAST CASE ANNUAL PEAK LOAD IN MW (1983-1997} 765. 832. 9.0'8. 985. UJ68. 1156. 125.0'. 135.0'. 1451. 1562. 1677. 1800. 1933. 2.0'70. 2215. INTERVAL PEAK LOADS IN P. U. OF ANNUAL PEAK LOAD {26 INTERVALS I YEAR} .U333 .6667 .7404 .7500 .6571 .6346 .6122 .5865 .5481 .5353 .52241 .5160 .50641 .4904 .5032 .4968 .5160 .5737 .5769 .6154 .~827 .8429 .8526 .91351.0000 .8301 DAILY PEAK LOADS IN P. U. OF INTERVAL PEAK LOAD (260 WEEK DAYS I YEAR) I. 0000 .9769 ,9731 .91538 ,9600 .9462 .8962 .8731 .8577 ,8423 I. 0000 .9808 .9663 .9663 .9615 .9615 .9519 .9519 .9423 .9375 l • 0000 .9913 .9784 .9827 .9697 .9654 .9437 .9307 .9221 .8918 I. 0000 .9029 .9487 .9359 .9017 .8889 .8889 .8846 .8333 .• 8034 t. 0000 .9512 .9317 .9171 • 9171 .9073 .9073 .9024 .9024 .8976 I. 0000 .9048 .9798 .9747 .9646 .9495 .9444 .9343 .9293 .9141 I. 0000 .9686 .9634 .9529 .9529 .9476 .9424 .9372 .9058 ·.9058 l. 0000 .9781 .9727 .9617 .9563 .9563 .9344 .9344 .9071 .9071 I. 0000 • 9f183 .9883 .9825 .9825 .9708 .9708 .9649 .9591 .9415 1 • 00110 .9940 .9020 .9701 .9581 .9461 .9401 .9341 .9281 .9162 1 • (H)(Jll . '>939 .9877 .9571 .9571 .9509 .9509 .9448 .9202 .8589 I • (Will} .')930 .9814 .9689 .9565 .9379 .9379 .9379 .9255 .9255 I. 0000 .9810 .9684 .9620 .9494 .9494 .9430 .9367 .9304 .9177 !.OIJ()O .9804 .9739 .9739 .9673 .9608 .9542 .9542 .9477 .8824 I. 0001) .9873 .9745 .9554 .9490 .9490 .9427 .9427 .9299 .9299 ! . oouo 1. 0')00 .9935 .9871 ,9806 .9742 .9677 .9613 . • 9548 .9484 I. OODO • ')<)30 .9814 .9609 .9627 .9565 .9565 .9441 .9441 .9379 l • (HIIlfl .?777 .9609 .9441 .9274 .9106 .8083 .8715 .8715 .8045 • . lhH'a .')944 .9944 .9722 .9722 .9722 . 9611 .9278 .9222 .9222 l. Ot.:Ou . ')')48 .9096 .9896 .9687 .9583 .9531 .9375 .9323 .8802 1.nn~·n • i) 1159 .9484 .9437 .9390 .9296 .9249 .9202 .9155 .9014 1 • 0•: oll) .996~ .9650 .9460 .9460 .9087 .7985 .7757 .7719 .0555 ! . \HH!O 1 . 11000 .9807 .9662 .9549 . 91) 11 .9474 .9398 .9361 .9323 l.uUO() .•)754 .8632 .6596 .8421 .8386 .8386 .8386 .8386 .8175 I • 0000 .9840 .9679 .9519 .9359 .9327 .9327 .9135 .8654 .804:S I • OlHH\ .97:30 .9730 .9614 .9614 .9575 .9575 .9537 .9421 .8340 6 -18 - - ~ """"'i -, - """! ~ ,..., ii t! ,,..... r r 1"'""- 1 !"""' i 188. 355. 2.fl2. 377. TABLE 6-6 LOAD MODEL DATA FAIRBANKS AREA LOW LOAD FORECAST CASE ANNUAL PEAK LOAD IN MW (1983-1997) 218. 232. 248. 264. 281. 398. 42.fl. 444. 31J.fl. 317. 337. INTERVAL PEAK LOADS IN P. U. OF ANNUAL PEAK LOAD ( 26 INTERVALS I YEAR) o. B7590. 69900.73710.76040.57490.59710.56630.51 no. 43240.41150.38330.37470.3:587 0.35380.38080.41770.42010.43730.46190.53190.57490.89190.93370.93491.00000.7690 DAILY PEAK LOADS IN P. U. OF INTERVAL PEAK LOAD (260 WEEK DAYS I YEAR) 1.00000.97480.94670.94670.94530.93130.89480.86540.84290~8177 1.0uooo.9a670.92790.92790.90510.899B0.88050.85940.82790.7891 1.00000.99330.96670.94830~94000.92330.90330.88000.86670~8267 1.00000.97580.96120.94510.86910.83200.82390~81100.79000;6769 1.00000.98500.98290.95940.95300.94660.91880.90810.90170.8825 I . 00000.99790. 99590.98770. 97940.95880. 93620. 90530. 89300', 8827 !.00000.98480.95010.93710.91970.89370.88070.87200.86120.8091 1.00000.96870.96150.95190.93510.91590.88700.88220.87980~8558 1. 00000.99150. 9915(). 99150.97160.96870.93160.89200. 88920'.8693 l.OC001.00000.96120.93130.92840.92840.92240.90750.90450.8955 !.00()00.99040.99040.94550~92310.91990.91670.91350.87820J8558 I. 00000.96720.95410.92790,92460.90490.89840.89510. 87870', 8721 l . 0'(}000. 96920. 96920. 95890·. 95890. 94520. 94520. 93 150. 92120'. 9041 1.00000.9B960.97220.96870.95830.94790.93400.92360.92010.8507 1.00000.96770.93870.93230.91290.90320.90320.90320.87100~8677 1.00000.87350.87060.86760.86460.85880.84710.84410.83820;8059 1.00000.94440.90640.90640.89470.82750.82750.82460.81870.8012 1.00000.99720.97750.96350~96350.94940.93820.93820.91010.8904 1.00000.99470.96810.93090.92820.90960.90690.90160.88B30~8856 l. 00000.98850.93300.91450.90990. 896 10.08910. 83450. 86370·. 8568 1.00000.99150.98080.97650.94020.92950.92740.91880.91450.9017 l.00000.96690.91180.89260JOB840.79890.73970.64460.61020~6088 !.00300.97710.91050.90790.90790.89340.83950.83550.86320.8434 t.00000.971l0.86330.83050~81870.79630.79240.74510.73320.7201 1.00000.99510.98160.97300.97170.95580.91650.83450.82430~6618 1.00000.99840.93930.92010.89940.80960.88500.84820.81310.7971 6 -19 TABLE 6-7 LOSS OF LOAD PROBABILITY INDEX (LOLP~/ FOR STUDY CASES IA & I~/ PROBABLE LOAD FORECAST CASE Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Ex pans i orJ-1 Expans i o nil Expansi oJ-1 Expansi ani/ 1984 0.0262 0.0063 0.8193 0.0066 1985 0.0123 0.0275 0.1446 0.0242 198~/ 0.0199 o. 0113 0. 2868 0.0236 1987 0.0247 0.0208 0.6795 0.0546 1988 0.0408 0.0698 0.1140 0.0278 1989 0.0290 0. 0613 0.2318 o. 0376 1990 0.0242 0.0625 0.0593 0.0652 1991 0.0184 0.0595 0.1550 0.1276 1992 0.0168 o. 0259 0.0276 0.0269 1993 0.0539 0.0297 0.0586 0.0598 1994 0.0393 0.0296 0.1583 0.1358 1995 0.0307 0.0622 0.0373 0.0426 1996 0. 0901 0.0568 0.0899 0.1014 1997 0.0676 0.0367 0.0441 0.0419 ll LOLP in days per year. 1:./ 230 k V s/c, 130 MW reserve sharing only. }j See Figure 6-2. !!._/ See Figure 6-3. ~/ Starting in 1986 includes Bradley Lake Hydro Project. 6 -20 ~ ~~ _, """' ~ ""'!! ~ 111111\ r I r r:-- r r ! I""' ,, \ I. r r r TABLE 6-8 LOSS OF LOAD PROBABILITY INDEX (LOLPt!/ FOR CASE I~/ PROBABLE LOAD FORECAST CASE Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Expansi oJ-1 Expansi on:±-1 ExpansioJ.I Expansio~/ 1984 0.0262 o. 0077 o. 8193 0.0018 1985 0.0123 0.0329 0.1446 0.0096 1986 0.0293 0.0220 0.2868 0.0152 1987 o. 0288 0.0306 0.6766 0.0299 1988 0.0482 0.0799 0.1140 0.0300 1989 0.0330 0. 0677 0.2318 0.0394 1990 0.0265 0.0680 o. 0593 0.0670 1991 0.0193 0.0633 0.1550 o. 0130 1992 0.0189 0.0644 0.0276 0.0227 1993 0.0546 0.0703 0.0586 o. 0354 1994 0.0427 0.0550 0.1583 0.0654 1995 0.0326 0.0991 0.0373 0.0369 1996 0.0931 0.0838 0.0899 0.0506 1997 0.0676 0.0520 o. 044-1 0.0244 ll LOLP in days per year. ~/ 230-kV transmission system with reserve sharing and firm power trans- fer capability. 'l/ See Figure 6-2. ±I See Figure 6-4. 6 -21 TABLE 6-9 LOSS OF LOAD PROBABILITY INDEX (LOLP)-.!/ FOR CASE II~ PROBABLE LOAD FORECAST CASE Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Exeansio~/ ExeansioJ/ Exeansio~/ ExEansi oJ-1 1992 o. 0189 o. 0476 0.0276 0.0972 1993 0.0546 0.0418 0.0586 0.0299 1994 0.0427 0.0235 0.1583 0.0244 1995 0.0326 0.0070 0.0373 0.0089 1996 0.0931 0.0226 0.0899 0.0207 1997 0.0676 0.1240 0.0441 0.0461 ll LOLP in days per year. l:..l Includes interconnections between Devil Canyon-Anchorage (345 kV), Devil Canyon-Watana (230 kV), and Devil Canyon-Ester (230 kV). ll Interconnected expansion for three area system: Anchorage, Fairbanks, and Upper Susitna (generation only). See also Figure 6-5. il See Figure 6-2. 6 -22 ·~· -·, -: ~ !""" ,..... r I ~ . .-\j r il r I r r r ,...... ! ,.... ,.... i TABLE 6-10 LOSS OF LOAD PROBABILITY INDEX (LOLPt!/ FOR STUDY CASES IA-& I~/ LOW LOAD FORECAST CASE Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Ex pans i or2./ Expansio~/ Expansior2./ Expansio~/ 1984 0.0262 0.0063 0.8193 0.0066 1985 o. 0123 0.0275 0.1446 0.0242 1986 o. 0199 o. 0113 0~2868 0.0236 1987~/ o. 0134 0.0527 0.2697 0.0501 1988 0.0095 0.0068 0.0329 0.0035 1989 0.0724 0.0701 0.0741 0.0222 1990 0.0309 0.0376 0.1511 0.0207 1991 0.0350 0.0533 0.0061 0.0387 1992 o. 0182 0.0334 o. 0591 0.0502 1993 0.0359 0.0351 0.1207 0.0173 1994 0.0190 o. 0264 0.2499 0.0264 1995 0.0129 o. 0211 0.0340 0.0463 1996 0.0075 0.0601 0.0711 0.0152 1997 0.0393 0.0393 0.0207 0.0225 ll LOLP in days per year. !:_I 230 kV s/c, 130 MW reserve sharing only. 11 See Figure 6-6. il See Figure 6-7. il From 1987, figures include Bradley Lake Hydro Project. 6 -23 TABLE 6-11 LOSS OF LOAD PROBABILITY INDEX (LOLP)-!/ FOR CASE rs_g/ LOW LOAD FORECAST CASE Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Expansi oJ-1 Expansio~/ ExpansioJ.I Expansio~/ 1984 0.0064 0.0012 0.4650 0.0006 1985 0.0105 0.0225 0.0807 0.0044 1986 0.0232 0.0745 0.1515 0.0176 1987 0.0217 0.0918 0.2697 0.0393 1988 0.0121 0.0090 0.0329 0.0037 1989 0.0869 0.0822 0.0740 0.0238 1990 0.0344 0.0428 0.1511 0.0219 1991 o. 0393 0.0602 0.2557 0.0413 1992 o. 0189 0.0366 0.0591 0.0515 1993 0.0366 0.0393 0.1207 0.0180 1994 0.0209 0.0288 0.2499 0.0271 1995 0. 0133 0.0207 0.0340 0.0024 1996 0.0078 0.0126 o. 0711 . o. 0195 1997 0.0427 0.0692 0.0207 0.0029 ll LOLP in days per year. ll 230-kV transmission system with reserve sharing and firm power trans- fer capability. ll See Figure 6-6. if See Figure 6-8. 6 -24 ~ .....,, ~ ~ ' ~ -, - -, ~ ,11111!1\ -"! r j r - r TABLE 6-12 LOSS OF LOAD PROBABILITY INDEX {LOLP~/ FOR CASE IcJ./ PROBABLE LOAD FORECAST CASE Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Ex~ansioJ-.1 Exeansio4/ Exeansi oJ-1 Exeansio4/ 1984 0.0262 0.0063 0.8193 0.0066 1985 0.0123 0.0275 0.1446 0.0242 198~/ 0.0199 o. 0113 o. 2868 0.0236 1987 0.0247 o. 0208 0.6795 0.0546 1988 o. 0408 . 0.0698 0.1140 0.0278 1989 0.0290 0.0613 0.2318 0.0376 1990 0.0242 0.0625 0.0593 0.0652 1991 0.0184 0.0595 0.1550 0.1276 1992 0.0168 0.0616 o. 0276 0.0388 1993 0.0539 0.0666 0.0586 0.0620 1994 0.0393 o. 0511 0.1583 0.1198 1995 0.0307 o. 0971 0.0373 0.0486 1996 0.0901 0.0830 0.0899 0.0699 1997 0.0676 0.0516 0.0441 0.0354 l/ LOLP in days per year. ~/ 345-kV transmission system with reserve sharing and firm power trans- fer capability. 1/ Se~ Figure 6-2. !ll See Figure 6-4. The 345 kV {Case IC) is similar to 230 kV (Case IB) except that only one 345-kV line is required during the 1992-1997 period, instead of two 230-kV lines. ~/ Starting in 1986 includes Bradley Lake Hydro Project. 6 -25 ~rf~\ t P,RMrt U.S, : ··:· -.,:··:•·~nr 0.9 I() 1'-0.8 en -~ o. 7 llJ a. ~ 0.6 ::> z z <( 0.5 ll.. 0 ::> 0.4 z 0 0.3 z <( 2 w 0.2 0 0.1 NON-COINCiDENT 1975 PEAK DEMANDS ANCHORAGE AND FAIRBANKS AREAS FIGURE 6-I I 2 3 4 5 6 7 8 9 10 I I 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 TIME (TWO WEEK INTERVALS) 6 -26 """"" i """'l>, 'J ·----') ~{) .::.z:c "·Y" --·· -- :seo: 36CC -·--·~ ::'>"~' 32G:: :;:: 30CO :; 2800 0"1 0 c:: 0 25C'O _J N "" '""-! c:: Z~J':; u..J a. 0 2200 ;z < >-t: 20:JC u < a.. !BOO c:: u 0 1600--w _J _J ~ 14:)0 t.~ ='= IZOC ICIJC I !~':~ s ·=zl 600 I sccJ <+:o 0 !979 J • ,-' r --· ____ _J IX~ , A_,tH 7 t7Sl I A'"; 75 •Zl,l 1'~'7'. 4 t7i :, BE:..:J S ~St, ------1 '] LEGEND :.JNIT AODI'ri::JN INSIALLEO CAPACITY IN MW IN S':"ALLED CAPACITY LESS LARGEST UNIT IN MW AN<H 8 -t7S !NTL 5 +7! 1--'~_>o _ _J,-------J 9-67 1---'-_jl ___ --J _____ .... -~-~ 1960 1981 1982 i9 63 1984 1 19ss -1 -~~} '~-~, -C'~, ~---, ; COAL 3 1986 1987 1 1983 1989 1s9o 1 1991 P£A~ AI +7 1 ~ l ~~, ~-_:_ _____ Fl G U_R~ -~--_2_ ZS2S ~---l0E~ 3 •JD:; I?C<'"Z •?e, I I;E:< 1•>:c:l ANCHORAGE AREA 792 ----------L--=·--!.·7~,3~-=:::=J=-===-=----~ --..,--,-,_--.J FAIRBANKS AREA -·------·----____ ,... 1992 i 1993 1994 I 1995 I 1996 I 1997' I 199S! INDEPENDENT SYSTEM EXPANSION PLANS ANCHOR.4GE AND FAIRBANKS AREAS PROBABLE LOAD FGRrCAST Ct.SiC ~m .. ___,___ 1 0 -'I _) _j j ___ J J _J _.) J ) ________ ,) .:__:,_· '>:-"' ,..._,. •:... --- I :=~~_:::,,f"'-'-'-:::::J <Ok~:;'oo ·JI-------~ ~---- 1 I ! ~-~~.__J ~~~~:~_:~~~o~_J_ I ~C:-::::11 I ___ _J J I zszg _ r ____ J I . __ .:_,__J. , I -----' __ j •:--_·t::L~~: ! ---~-J-~:-: A-· ---;--_____ , __ -_.-_=----~=--~~ J ------~----_:,______ ----------t . --·~=•=-=1 INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA WITHOUT SUSITNA PROJECT PROBABLE LOAD FORECASt CASE 8/79 ) ,,I c.l ·-:..:;;: ... ) J (") "T'J )> ....... U') G":l rn c:: ;;o ....... f'T1 )> 0"1 12"> I w ....... c •c• O't N 1.0 LARGEST UNIT 36CO- UNIT DELETION 3400 -- 3 2'JO ------ ;>: 3CCJ 2 2SC'C a <:( 0 ...J 2600 ----·. "' <:( '-'-' "-24CO ------------------· ---------- 0 z <:( 220·:' >- I- u 2.000 -··--.. ------------ ""' a.. \BOO·····----· -·-· --<:( u 0 w ...J !600 ...J <:( I- C') 1400- z 1200 ·-----··· lOCO-· -··-···--·--··---··------------ 600- 400 ;::_·_-_-_· __:_· _____ _ 200 ·------------------- ---------~----·-_ _-_ .. ~--~----~ ------··--* . rOAl +SOO•l ClJAtA -+ZOO: I 1-------!---_.J l 1----...J I 30!0 ~--_ _J I FIGURE 6 :_1. 1--'l"'-8"''~'---'----J I ___ __, Z5Z8 2328 .2.12.'8 I 1----'1---_ _j I AHCH 3 +78 1928 ···I l-_;_:-'--'----....! I 1828 I I- 1-----....J I 1--''-"6:.:28..._~,-----J 147'2. ,---'-"""----!-- - ---' I -----1 ----...J • ; r __________ j ~------~-~ __ __c__ ___ _ ----;----------;--------------~---- ' _]__ PEAK LOAD DEMAND 70 MW _____ -· ·----··----r POWER TRANSFER )j< * ::;<:'*TWO 230KVLINES (1992-1996) 0 ) 1979--f-19_8_6 Tl9elj-I9ai-]19-83_i __ I984T 1985 I -1986-1 1987--I-19-88Ti989n[--i99oT-199"1-r-,992 r 1993T-199_4_f_i995-TI9"9u·l997 r !99i i INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA WITH FIRM POWER TRANSFER PROBABLE LOAD FORECAST CASE 6 '"' a ct 0 0'1 ...J :.:: <t w c.. w 0 0 z ct >- 1- <.) c::: c.. <t <.) 0 w ...J ...J ct 1- l/) z zacc .----:---~---.. - 2600 ---- -·~r·-·;. 2400 ____ ., -----------+-----7-·---+--- :: -.•.. · cP '~t-+ fffl.s.,. 1-"'=-"--'-'~:_"'",,828=--!1-----! 1800 .·------·--------------~--' l ' ' - f -! -----1----------------1 L~-, ·_ .:.; --------t--=~----~-.. - 1600-;---~_j~_-.-~-----:---·4t--:-:-::~~---_:-:~~i:-~---:-~{~:-~---~·-4_t-~-~-~+r-::-i~~+l:~~--l 1400 ~: . __ ...:-:~:-::·:-:- ----.... 800 i -·-,-·---~ .. .-• 600i--~-· t--------·· .--- ~-------- 1-__ . __ _j_:_. _____ , ____ _ I I 1-...... "'-----ll-__ _....~ _____ : ___ _ I I 1----~--~-~-:::.-_J. I ___ ...J PEAK LOAD DEMAND ··1 1 -·------:-- L...:.~~.:__:=.:_:~::_:_::: i ::.::.· t: -.l i· UPPER .SUS I TN A PROJECT .. ---i ___ _j ----' ~ :t_·-----,-- 400~i-=-~~t=~~~~~~~~:t==t==~~~~~~~~-==~~~~=t==~~=~~~~~~hit=~~r==t==f=~==~~==~====t-=====r=~ r· ' __ -___ _:'. -J } ,} •• J .,J j J 199o 1 1991 "} \-~-.... 1 INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA ). WITH UPPER SUSITNA PROJECT PROBABLE LOAD FORECAST CASE 8179 j _, ) l n "'T1 :P 1-1 (.1) Ci) IT1 c ;;o 1-1 ITI ..... 0'1 I (.11 J >~, 0 < ::r. 0 ...J --< ..o.l -:L 0 z < >-t: u < ""' < u a u..: ....1 ....1 <! !-v-: z ~1 -~--. '} } "~) ,-~~ 1 ~--l •·~-l ~~') ~~ ~~". ~-~, ~ -) -"'--"~ ) ---------'FIGURE 6 - 6 INSTAi_i_EO CAPACITY JN MW 3S::'C INSTAI_i_EO CAPACITY i_ESS . . LARGEST UNIT .IN MW . ------~--~-~--------.---- 32CC --~:·:----,----~-:-::-----:------. --;-·---:-:-~>-:--:~:::-::-:-:::-:-:-:-"~:------'~---::--·~-;--~----. ----->-·----->----·;..· _;__........:..::......, ! GUt i -3-Y)• L : :> ~-- ~.c:-c --~ _!-. --I -. -r (a.\L 5 ... ,we. . --. -i- 2800 ---~--~·--------------------. _______ _,_ _______ , ______ +:---'·:_ ____ , _____ ~·------------. ---------------,-------~.--'-'~---.1 ! . Ca.4:...4 -tZC::1 Z6CO ' . ' -----------------~----------~------------~--~-----------------------~-- ,:_.....::.;<3:.:':..5 --'-- -_j "f. ----,-----~ ---~-~---~----- ·1 ' zzoo ,__z;..'.;;.z;;._...J _____ J Z041 1 -1-~---1--- 1647 f.----_) 2000 ----, ~-------------------------~-------~-~-·-----=-~-----~==r-------·f· ==="i ' 1'----+, -----! ,_....:..:..:..::......_,, I r----_j ---------~~:r.~·':-:-''-'_':"_=-:-:,r=='---'c::J 1800 . - -----------. --------------·-'··· ANCHORAGE AREA is:;c--....... , .. ~-------1'---'-=----._...,J,--"""-__, I ,_...:..:c:..::......-:-_:-.:_ .::_·.::_ -.::_ .=-·......:-,; 1400 ·-··-~1 -------------i .----~ ICCG sco CCALFZ. JIY,) 60;] ------- .;oo =~~-~-~~-~·~--==--~~-=...;._;_=~~~~-~~...;.e'~--~--~~=·~· ~-~-!~;~~;~~;:_;~-~-!t::-~-~~-~-~----~;:_~·__:~~~~~,;~==··~~-~--~--~~·~-"f! :--=.::_~-~-~---~._:__~--·. p~·-~-~A-~K~_:__~-L-O:.:.A·~·-D:._~-~=D~E=::M~:._A-~·~~~-::_:-D~:._~--~_:_:~_JI' ~-~-~-=-=--~-=-~--:~---~-=~-::=-c-=-_--~--~-=-~--~-~-=--~-~· ~F~A~I R;B~A~N~K~S:~A~R;. EA~= ---~ zoo = ---------. ...,. ----. ------'--" ~ LOWER RANGE CASE 1988 1989 1-19.90 /991 INDEPENDENT SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA LOW LOAD FORECAST CASE 0\ c <t 0 J w ~ <t 1'\) w (L 0 z <t >-1- u <t (L <( u 0 w -' ;;. 1- Ul z ---------r------- '---------,-----------c -------------------"-----•-----··- !ZOO INSTALLED CAPACITY IN MW .:~-,--~=- 3600 -i- --l- ---~ - ____ j INSTALLED CAPACITY LEss··-__ ~~ __ 3.:oo ~--_:_: ___ lOCO ___ LARGEST UNIT IN MW --· -----_]-- -------------------r-------+--- UNIT DELETION i -·'---·-------------,-------~- ·-t· ---+---3COO ·! 2800 -·-I 800 ~--·-· ---_-_+L----'--------,....----i. 400 i .. -I -... ·r.:~:: j .) J -·-----·------,-----------:--------_._ ______ _:.___~----__ -;---------- Z9C! I ~=---!1 I r----J ,_~n.:.;<>~'-...1 ...... -__ J I I J........:;Z;;5D::I_.J 1 _ _ _ _ _J -_, ~-__ _J 3301 ---' . I ,_--'''""''"54,_-!-..:_ .:_-.J I r-=~1 I ·----l f-------~----J -I -----I . ___ ...:._..,._j l _· !--- <cJ sJ .J, ,_) ,. --------------------------------··--:--------=-:! __ j , -~ t994 T 1995-!1996 I· t997 r-,9-9D INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA LOW LOAD FORECAST CASE • I l ) l ("") , :X::. ....... "' "' ..., c ;;o ....... :X::. ..., 0"1 ~ I ....... ....... 0 l 0'1 w w -1 ) -l -l -) ) -) -""""---... 1 --J ~, ~-l ~-~1 ~~~) --------l Lc~c, ----·~ ) 0 <;t 0 __J "' < ..u ::.. 0 ;z: < ,_ !:::: u ~ <;t u 0 w ::l ~ U) z LEGEND 400C !.~<eH6 +1%: UNIT ADDITION 3800 ~ __ _; __ __:_:_______ •-----------~- l2.M ~6C.O --------·· - ' ____ J 3400 ------<':Jil ~000 -----------· 2600 INSTALLS:C CAPACITY IN. INSTALLED CAPACITY LESS LARGEST UNIT IN MW .! FIGU~E 6 -8 i --------------~----- r -~- !3<:1 ' ··; -~ __ ·-i-----·-· _--:-· ·--~--~~-~-~ 3001 !'-----'--------. I ---'-~· --'-------,----~--- COAL3 t-200 NCH II +104 2354 I - -I F----:_:'7.::,0:.,.1 --!----_J I F-_::.:ZSO::::;_I --!-_ '-_ j . --·-~-I . 2ZCO ---j--~---; _ _:_:_:~:.:.:.1 : _ _:_::_:__:_ __ ,'=_ =~7-:--F=-:---,--____ _ ' I~RAD\1 +50 : r----l I Zl54" ~~~~--~ 2000 1800 . -·-------~--------+--------~ 1600 ----------------;-~~ 1400 1200 ~------· -~~~~~. ' 1000 eRAD~ z .-sol zoso I ----r-=-~-=-:J J-...:=..:::___ _ __;_.;___J_ -~-.-/ I -, 70 MW FIRM POWER TRANSF"ER ----. -------------------, RANGE CASE ____ _, ; -. . . . -. :~ j ---'---+-----r----~ :J~_:__:___:,~ ____ : ______ :_· ·_ -~-'----· _:__-_-__ · _-__ :_:_] . . I 1-'. • ... ---~ ----·-· L --.. -. .. t-· · --·-· j -~~~-=~r~-~-:~~=-~-~=~~r~=-~~~:~-·----~t------·---~------l--~-~~~r~~~~-t=~~~-~---------~ ----------------------------j ' --·--:~---1---=:~! --.;::: .. -r::::;---~---· ----'---------!---'--;'--· _ ___; __ . -· _--f--.----------------------~~~·_,~;f~~~~·~~~-~-i~~~~-:~_I;E:::::::~;::~c,::~:~:s~=-800 600 :__ ___ -~:_: __ ~--- 400 o,- 1 ;-... ·! ---... ----- - - r979-TI98o_f_i9sr-j'l9s2_l_i983--j-t9~4T-fi:1a·s-ri·9-86TI987-·i--19s·e-r-I9~TI99o-Qri,992TI~-93"T-1994-l ~l-995r-199s-l1997--TI9¥] INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA LOW LOAD FORECAST CASE WITH FIRM POWER TRANSFER n "Tl ):» ,_. (/) G) rn c ;:o ,_. rn c:o 0'1 I co '..::! ::.3 V'll., ;-.... ; 230KV TIL ;-' .. --; /3$.BMVA ~~~-5~·1 [/3f?/.?30KY! 10 J ;c 1 ~~) b21'-CY~ '-Q-/. (323m.) "0--" .J.. "-0-"' l '-0-/. ~ -'--' ~ 1 -23X/2M'AA ~ 4Xi2MIAA J T i3XI6MVAR ANCHORAGE ESTER CASE I Alterr;atives ll. & B ~ J l •• J J l .• ~J -l ) J '-(-;:_. ,._,} ,.,,_ .. _;. ·-.. J •• l .J I J l --·"'1 -··---, -l l __ /) ~, --) J J ._, ----·--, •. ANCHORAGE -'"1 ~--~l £--~-C ) ~-, 1 ESTER !G84 ti.VA .-----+-----, [ 138/345 KV:!. 10;/. -< ~--- fg l-15MVAR CASE I Alt!Zrnafivz C -- ,~ lfg ,~ L---------------------~----------------------------------------------~--------------~----~ -1 20MVAR ·....:..= 3/1'/I:J._ c~ 230KV TIL --·-r<v··~., t-~-:::'~v .;iC.,./"1 li ~"{Yl'-{Y (40m) :--..y ... '--!:Vl '-[]--" (19/m-) . .., -n , 'I c~ ( 4 X i2!vf\AA '---...... --...... -;. * 6 t.u ANCHORAGE PALMER ~-J -f J -~~ l J \·'~''---- ,_, ~~ ~ _,J J _J .I 20MVAR r'--J. ~1'-Q--"1'-0---" (92m) I ~.'"* '-------~ HEALY J J [.. .. J ,J f31CB!'{W o/ [f53t'<'30 -10;· ~1'-(}-"l'Q/. F-±3XI2M~ l, 1 3XfGMVAR ESTER CASE 1 A!"terT!dfi\/.Z D J J :;,..;.:-·-c) "'·'-<l ., ..... "' c::: ::0 m 01 I ,_. - I I 0)1 --· 2::x:: .::--.~.:.. c t .,.. A ,\:C.HORAGE i J. 200MVAR !55 m) 23Ci<'l -;-/L I (189m) (189m) 230kV (27m) (27m) 4'X!80MVA DEVIL CANYON 230KV 1 l 666 3 X 343MVA WATANA ESTER CASE I£ ., ....... '"' c: ;;o fTl 0) I ...... N CHAPTER 7 FACJL ITY COST ESTIMATES ,-. ! - .- 7.1 TRANSMISSION LINE COSTS CHAPTER 7 FACILITY COST ESTIMATES The transmission line costs were obtained from past and current experience of the Consultants with the design and construction of transmission lines in Alaska. Cost data was escalated to 1979 levels and a factor of 1.46 (AVF =Average Value Factor) was applied to total costs to give an average value for construction in the area. The AVF includes a 10% addition for anticipated difficulty with the constraints associated with the selected 1 i ne route. A. Alaskan Experience Facility cost estimates for alternative transmission intertie designs are based on an in-depth analysis of pertinent Alaskan transmission lines that have been built and are now in successful operation. Analyses were made based on actual experience to develop material and man-hour costs, together with specific installation requirements for structures, con- ductors, and footing assemblies. In addition, typical right-of-way clearing costs and other costs associated with the solicitation and obtainment of right-of-way easements, permits, and environmental reviews were gathered to provide representative costs for estimating component items for the Anchorage-Fairbanks Intertie. The first Alaskan transmission line capable of operating at voltages as high as 230 kV was the Beluga Line. It was constructed for Chugach Electric Association (CEA) in 1967 by City Electric, Inc. of Anchorage. This line traverses about 42.5 miles of undeveloped land, of which about 65% was muskeg swamp. No roads existed to connect the line right-of-way to any highway or railroad, requiring that access be by water (Cook Inlet- Susitna River), by air (helicopter), or by ORV (off-road vehicle). One major river crossing was required along the transmission line route. 7 - 1 The Beluga Line was constructed of aluminum lattice, X-shape, hinged-guyed towers and Drake (795 kcmil ACSR) conductor by the Contractor. Using one _. tower assembly yard at Anchorage, the Contractor made extensive use of helicopter delivery of men and materials with ORV equipment during winter weather to construct the line. This project was completed at a cost of about $50,000 per mile, including right-of-way clear·ing. The hinged-guyed, X-shaped tower proved successful and has since been used for the following lines described below. 1. Knik Arm Transmission Line-230 kV (Aluminum Lattice Towers, 795 kcmil Drake ACSR Conductor), 1975. This line was built using Owner- furnished material by force account and contract methods. The Owner (CEA) installed the piling and anchors, and contracted for the right-of-way clearing, tower erection, and wire stringing. Piling and anchors were installed using ORV equipment to carry the power tool for installing anchors and the Del Mag-5 diesel hammer and welding equipment for the piling work. City Electric, Inc. accomplished the tower erection and wire stringing using helicopter and ORV equipment. Summar~ of Actual Costs: $/Mile Construction Cost 87,294 Right-of-way Clearing Cost 19,049 Right-of-way Solicitation Cost 7,706 TOTAL (w/o Engineering) 114,049 2. W·illow Transmission Line-115 kV (Tubular Steel Towers, 556.5 kcmil Dove ACSR Conductor), 1978. This line was built by contract using I Owner-furnished material. Right-of-way clearing was accomplished by one contractor and line construction by another (Rogers Electric -an ex- perienced Alaska contractor). This line contractor used a vibratory driver to install the 811 H-pile with great success. (This driver has - since been used to drive 10 11 H-pile for another line. In one case, the -~ tool drove a 14 11 H-pile for a sign support. The contractors are preparing ~ I, 7 - 2 .... ,. .... -:T """' I - to drive more 14 11 piles for a new CEA line.) The introduction of the vibratory pole-driving technique, together with the application of the tubular steel, hinged-guyed, X-tower is expected to realize substantial cost savings on future transmission line projects. Summary of Actual Costs: Construction Cost Right-of-way Clearing Cost Right-of-way Solicitation Cost · TOTAL (w/o Engineering) $/Mile 73,863 10,312 4,909 89,084 B. Material Costs The estimated cost for the tower steel, as well as the physical character- istics were obtained from ITT Meyer Industries (Ref. 1). The cost of stee 1, therefore, has 19.79 as the reference year. The cost of foundation steel was taken to be $0.31 per lb for WG Beam. This value is somewhat conservative, as the current market price is $0.22 per lb. Prices for insulators and conductors have a reference year of 1977; there- after, the price was escalated at 7 percent per year through 1979. The cost of right-of-way was based on actual average values paid by utilities in the same area as the proposed lines. Other factors used, that provide good indication of projected costs for the transmission line are: • Terrain Factor -This factor is used to correct the number of calculated towers per mile to actual towers per mile. • Line Angle Factor -This factor is used to increase the ef- fective transversal load on the tower, and accounts for the 3° design-angle for the towers. 7 - 3 • Tower Weight Factor -This factor is used to increase the total estimated tower weight, to account for heavy angle and dead-end towers. C. Labor Costs Labor costs were obtained from actual construction experience, obtained by the Consultants 1 construction records for transmission lines built in Alaska. This information included the cost of labor and a detailed breakdown of the man-hours required for every specific task included in the construction program. A multiplier of 1.33 was applied to the estimated cost of labor for this period, which then was multiplied by 1.1 as explained in 7.1 above to obtain the 1.46 AVF indicated above. D. Transportation Costs An estimated unit cost of $100 per ton was taken to represent the trans- portation and shipping costs from the Pacific Northwest to the line route staging depot, including loading and unloading (Ref. 2). 7.2 SUBSTATIONS COSTS For this report, the facility costs for substations were obtained from the U.S. Department of Energy 1978 version of the previous FPC publication 11 Hydroelectric Power Evaluation 11 (Ref. 3). As the values included in the publication are list prices, with 1977 as reference year, they were adjusted to 1979 values by using the U.S. Bureau of Reclamation Index (Ref. 4). The cost of the substations includes the shunt compensation, required at both ends, for operation from no-load to full-load. No re- active power (VAR) compensation support from the source generators was considered in this study. 7 - 4 - -·I - - .- 7.3 CONTROL AND COMMUNICATIONS SYSTEM COSTS Control and communications sytems costs are included in the intertie cost estimates. The system is necessary to provide effective control of power system operations, and economic energy dispatch throughout the ·j nter- connected Anchorage-Fairbanks area. The cost estimates include a power line carrier type communications system, a digital supervisory control and data acquisition (SCAOA) system, and automatic generation control equipment. 7.4 TRANSMISSION INTERTIE FACILITY COSTS As previously discussed in Chapter 5, transmission line costs were calcu- lated using TLCAP. Computer printout sheets indicating input data and the calculated results for all five intertie alternatives are shown in Appendix B. Costs for substation facilities and the control and communi- cations system were added to the transmission line costs, thus obtaining the investment cost for the total intertie facilities. A cost summary for each of the five alternatives studied is presented in Table 7-1. Detailed cost estimates and supporting data are included in Appendix D. 7.5 COST OF TRANSMISSION LOSSES The Transmission Line Optimization Program (TLCAP) for the selection of the optimum span-conductor combination~ includes the cost of demand and energy losses for long transmission lines. The loss components are opti- mized by varying the voltages at the receiving and sending ends. The program assumes 100 percent volt support at both ends. Table 7-2 presents the present worth (1979) costs of calculated transmission line energy and demand losses. 7 - 5 7.6 BASIS FOR GENERATING PLANT FACILITY COSTS Cost estimates were prepared for all new generating plants (five gas- turbine units and five coal-fired steam plants), and associated substation and transmission facilities which will be affected by the transmission interconnection. The costs for the facilities are summarized in Table 7-3. The most recent cost data and estimates available for both gas-turbine and coal-fired steam plants planned for the Railbelt area was used as a basis for the generating plant estimates. The three principal sources of cost data and information are included in the references at the end of this chapter. The Battelle study report (Ref. 2) provided background information and specific factors to determine applicable Alaskan con- struction cost location adjustment factors. The Stanley Consultants report to GVEA (Ref. 5) provided detailed cost estimates for both the 104-MW coal-fired plant at Healy and combustion turbines at the Northpole substation in Fairbanks. These estimates were then used to derive refer- ence costs for other gas-turbine and coal-fired units of different capacity at other Railbelt sites. The nomogram developed by Arkansas Power & Light Company (Ref. 6) was used to determine the 100-MW reference cost estimate from reported costs relevant to the 104-MW coal-fired plant at Healy. The same nomogram was then used to determine plant costs for unit ratings of 200 and 300 MW, taking into consideration economies of scale. Sub- sequently, the Alaskan construction cost location adjustment factors were applied to derive site specific cost estimates. Cost estimates for the associated transmission facilities were obtained from cost data developed during this study for the transmission intertie, the Stanley Consultants report (Ref. 5), and typical costs experienced in recent Alaskan transmission projects. The cost estimates and supporting data are contained in Appendix D. 7 - 6 - - -i - - - - - - - r - - 7. 7 GENERATING PLANT FUEL COSTS Benefits in addition to those resulting from generation reserve capacity sharing will result from the supply of firm power over the intertie. An analysis was made of the relative generation costs for both independent and interconnected system expansions to determine the comparative economic advantage of firm power interchange. The fuel cost component of operating expenses is the salient factor which affects the economic comparison of alternative system expansions. Therefore, a year-by-year analysis of alternative modes of generation was completed for each period during which firm power transfer over the intertie is possible, as follows: From 1984 1992 To 1987 1996 11 Case lB. Duration 4 yrs. 5 yrs. Transmission Intertie Firm Power Transfer Capacity % Power Loss]/ Energy~/ %Energy Loss]/ 30 MW 70 MW 6.9 6.9 145 GWh 337 GWh 1. 05 1. 05 21 Annual Transmission Capacity Factor of 0.55 assumed for analysis. Fuel costs were estimated utilizing the trend curves from the Battelle report for future natural gas and coal prices in the Rai"lbelt area. The energy loss component of firm power transfer over the intertie was considered, in estimating the total cost of fuel required to generate sufficient energy in one area to displace a block of energy otherwise generated by a local plant in an independently supplied area. A year-by-year analysis of the comparative cost of generation is given in Appendix D. Table 7-4 summarizes these costs. Although this analysis is germane to the confirmation of salient considerations regarding the economic feasibility of the intertie, this level of study of fuel costs is in no way a definitive substitution for a detailed year-by-year analysis of pro- duction costing for the multi-area interconnection. 7 - 7 7.8 MEA UNDERLYING SYSTEM COSTS The construction of transmission intertie with the intermediate substation at Palmer (Case ID) provides an opportunity for Matanuska Electric Asso- ciation (MEA) to purchase power at the intermediate substation at Palmer. Information in the System Planning Report (Ref. 8) indicates the following MEA system expansion investment cost for transmission lines and substation facilities with and without the intertie: Interconnected System Independent System Independent System $1,356,000 (1987) $6,646,000 (1987) $2,004,000 (1992) The above costs are in 1979 dollars, values were escalated by 10% from 1978 to 1979 level. These values were used in an economic analysis to obtain additional benefits for Case ID. 7.9 CONSTRUCTION POWER COSTS FOR THE UPPER SUSITNA PROJECT Completion of the transmission interconnection, prior to the development of the Watana and Devil Canyon sites of the Upper Susitna Project will enable the supply of electrical energy for construction power. A tempo- rary wood-pole line to the sites will be supplied from a transmission tap along the intertie route, near the junction of the site access road with the main highway between Anchorage and Fairbanks. Generally, isolated diesel generation is used at such remote hydropower plant sites. A comparison was made of the relative costs of isolated diesel generation and energy supply to the sites via the tap-line. Table 7-5 shows alter- native cost streams through the construction period corresponding to the introduction of the Watana and Devil Canyon units to the interconnected Railbelt generation expansion, shown on Figure 6-5. The construction schedule, as outlined on page 94 of the Interim Feasibility Report (Ref. 7), 7 - 8 - - - - r r I l r ~· -I was followed to establish the time frame for economic comparison of alter- native modes of construction power supply. Results of the economic com- parison indicate a clear advantage for utilizing the inte,rtie as a source of construction power. 7.10 REFERENCES 1. Letter from ITT Meyer Industries to R. W. Retherford Associates, Anchorage, Alaska, January' 15, 1979. 2. 3. 4. 5. 6. 7. 8. Battelle Pacific Northwest Laboratories, Alaska Electric Power: An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region, March 1978. DOE, Federal Energy Regulatory Commission, Hydroelectric Power Evaluation (Final Draft), August 1978. U.S. Bureau of Reclamation, 11 BuRec Construction Costs 11 , Engineering News Record, 22 March 1979. Stanley Consultants, Power Supply Study - 1978, Review Copy of Report to Golden Valley Electric Association, Inc. Power Engineering, 11 Nomogram calculates economy of scale in power plants", Volume 83, February 1979. U.S. Army Corps of Engineers, South-Central Railbelt Area, Alaska, Upper Susitna River Basin Interim Feasibility Report, December 1975. Robert W. Retherford Associates, System Planning Report, Matanuska Electric Association, Inc., January 1979. 7 - 9 TABLE 7-1 COST SUMMARY FOR INTERTIE FACILITIEs!/ Total Cost at 1979 Levels {$1000} Case IA Case IB Case IC Case ID Case II 1. Transmission Line: Eng'g. & Constr. Supv. 3~012 3~012 7~988 3~012 15~442 Right-of-Way 8~837 8~837 7~573 8,837 12,994 Foundations 8,445 8,445 12,160 8~445 22,966 Towers 21~615 21,615 33,990 21~615 64,974 Hardware 477 477 477 477 1~096 Insulators 503 503 755 503 1,396 Conductor 10,761 10~761 17~663 10~761 36,946 Subtotal 53,650 53,650 80,606 53~650 155,814 2. Substations: Eng'g. & Constr. Supv. 1,352 1~352 1,855 2~816 6,902 Land 57 57 46 81 185 Transfonners 1~703 1,703 3,291 1,703 11,917 Circuit Breakers 1,093 1,093 1,323 1,953 6,410 Station Equipment 1,223 1,223 1,933 1,345 4,375 Structures & Accessories 3~628 3,628 3,978 4,026 16~411 Subtotal 9,056 9,056 12,426 11,924 46,200 3. Control and Communications: Eng'g. & Constr. Supv. 125 125 125 165 200 Equipment 2,375 2,375 2~375 3~135 3,600 Subtotal 2~500 2,500 2,500 3,300 3,800 Total Baseline 1979 Costs 65,206 65,206 95,532 68,874 205,814 Y The interest and escalation during the construction and other financial charges are excluded from the costs in this summary. These costs are not relevant for the economic analysis and they appear only in the financial analysis (See Chapter 9 for Case ID). 7 -10 - 1111!1!1, ] i ., 1111!1!1 ' IIIII!!! -' -, - -, 1111!1!1 - iWI -' r ..... -' -I i !"""' r r """" .... .... -i - TABLE 7-2 PRESENT WORTH OF INTERTIE LINE LOSSES 1984-1997 STUDY PERIOD!/ Case $ X 1000 {1979) IA & ID {230 kV) 5,410 IB (230 kV) 7,071 IC (345 kV) 6,429 II A (230 & 345 kV) Anchorage -Devil Canyon 11,476 Devil Canyon -Ester 7,076 Watana -Devil Canyon 2, 708 l/ Cost of losses, energy, and demand, escalated at 3% per year. 7 -11 TABLE 7-3 COST SUMMARY FOR GENERATING FACILITIE~/ (Costs at 1979 Levels-!/) Installed Cost Total Cost-Y Unit Name Code Jj T,l~J_I MW Thousand $ $/kW Thousand $ Northpole #3 NORT 3 SCGT 69 24,385 353 27,934 Beluga #9 BELU 9 SCGT 71 33,548 473 42,498 North pole #4 NORT 4 SCGT 69 24,385 353 25,185 Anchorage PEAK A2 SCGT 78 22,620 290 23,400 Northpole #5 NORT 5 SCGT 69 24,385 353 25,185 Anchorage #11 ANCH 11 Coal 104 99,084 953 105,636 Unit F2 COAL F2 Coal 100 130,000 1300 151,980 Unit No. 5 COAL 5 Coal 200 200,000 1000 212,245 Unit No. 6 COAL 6 Coal 300 274,000 913 292,250 Unit No. 1 GEN 1 Coal 300 274,000 913 292,250 Unit No. 2 GEN 2 Coal 300 274,000 913 292,250 }:__/ Investment costs adjusted to January 1979 levels, excluding IDC. 21 Code name used in MAREL study. ll SCGT-Simple cycle combustion turbine, ·includes NOx removal equipment. COAL -Steam turbine, coal-fired with FGD equipment. !!.l Total cost includes substation and transmission costs. 2./ The interest and escalation during the construction and other financial charges are excluded from the costs in this summary. These costs are not relevant for the economic analysis and they appear only in the financial analysis. 7 -12 $/kW 405 598 365 300 365 1016 1520, 1061 974 974 974 """"! J!llll1 ., l!ll'll .1 ~ - """'l - - - - I""' I I I - - ,-. I""" ' ' - r~ - r TABLE 7-4 SUMMARY OF ALTERNATIVE GENERATING PLANT FUEL COSTS $ 1000 (Escalated) Independent Interconnected Year S_ystem O~eration S_ystem O~eration 1984 1985 8,468 7,648 1986 9,324 8,498 1987 10,267 9,029 1992 6,851 8,324 1993 7,212 8,654 1994 7,933 8,016 1995 8,654 8,745 1996 9,015 9,109 7 -13 TABLE 7-5 ALTERNATIVE COSTS FOR CONSTRUCTION POWER SUPPLY TO WATANA AND DEVIL CANYON HYDROPOWER SITES DURING CONSTRUCTION OF UPPER SUSITNA PROJECT 1979 Baseline Costs -$1000 Isolated Diesel Tapline Supply Year Generation at Site From Intertie 1985 2,835 267 1986 695 483 1987 697 481 1988 696 478 1989 3,055 752 1990 1,324 902 1991 187 734 1992 623 430 1993 623 419 1994 -sool/ 304 1/ Negative sign indicates that resale value of generating plant exceeds cost of generation in final year. 7 -14 - ~ - """! ~ - - ~. - ~ I - -I - r .... I SUSITNA TRANSMISSION TAP STATION 230/69kV UPPER SUSITNA RIVER PROFILE RIVER MILES 120-290 MAIN TRANSMISSION LINE (~\ 6> \ <;0' ' ~ -, &o I u'lc \ FIGURE 7-1 HAN:~M1::;01UN CORRIDOR ANCIIOHAGE · FAIRBANKS INTEfrfiE ();/ ( ~)-\ I I ,, u ·,r:All ~---1 (I 'J 10 15 ~'OM1Ies ' ~ ~~ . . ;·' ,~~ UPPER SUSITNA HYDROPOWER DEVELOPMENT (Source: Plan of Study for Susitna Hydropower Feasibility Analysis by Alaska District U.S. Army Corps of Engineers, Sep. 1977) CONSTRUCTION PLAN FOR UPPER SUSITNA PROJECT: Ref. Inter-im Feasibility Report-P.94, IJ) Army r:orp~ r)f fngin@~r~. 1? !),t,i_. 19n Construction Period for Selected Projects: Watana Dam - 6 Years Devil Canyon Dam - 5 Years Total Period -10 Years (1 Year Overlap) SUGGESTED REVISED SCHEDULE: Ref. Chapter 6, Figure 6-5 First Unit On-Line at Watana -Beginning Year 1992 Last Unit On-Line at Devil Canyon-End of Year 1996 Period of Overlap in Construction - 2 Years Due to Introduction of First Unit at Devil Canyon in 1994 7 -15 ' \_ CHAPTER 8 ECONOMiC FEASIBILITY ANALYSIS - -I r- 1 ~ i CHAPTER 8 ECONOMIC FEAS IB IL ITY ANALYSIS An economic feasibility analysis was perfonned to determine which system expansion plan provides the best use of available resources for supplying electrical power to the Railbelt area. Alternative system expansion plans and faci 1 ity cost estimates were developed in Chapters 6 and 7. In this chapter, the results of the economic feasibility analysis are presented. 8.1 METHODOLOGY This economic analysis uses the conventional present-worth model. Annual capital disbursement tables, on a year-by-year basis, were prepared for independent and interconnected system expansion plans. To evaluate these plans on an equal basis all capital disbursements were discounted to the 1979 base year and then totalized for each plan to obtain a single 1979 present-worth value for each plan. The difference between the two present worth values is the net present worth or project benefits. This approach does not include additional capital disbursements after 1997. Such dis- bursements will be required later to replace retired facilities. However, the extension of the present-worth model over the whole life of the pro- posed intertie will not significantly affect the results of this feasibil- ity study. The year 1997 was chosen as the final year of the study period to include the last unit of Upper Susitna Hydropower Project (Devil Canyon Unit No. 4). Figures 6-2 thru 6-8 in Chapter 6 show that many plant additions for both independent and interconnected system expansion plans do not vary. Therefore, in this economic analysis, facility costs for the new generat- ing plants not affected by the introduction of the intertie are not con- sidered. Also excluded from the analysis are plant fixed operation and maintenance costs. The exclusion of these O&M costs will somewhat favor tne independent system expansion alternatives. 8 - 1 Only capital costs are used to evaluate generation reserve capacity shar- ing benefits. This simplification is based on the assumption that an average operating cost of generation for reserve sharing is approximately the same in the Anchorage and Fairbanks areas. To account for generating plant operating costs with reasonable accuracy, a multi-area production cost study would be needed. The multi-area production cost model simu- lates an economic dispatching of generating units in the system and com- putes expected fuel and variable O&M costs based on the energy (MWh) out- put for each unit, taking into consideration intertie transfer limits. Since such a study is outside the scope of the present work, a somewhat simplified method was used in this feasibility study. It is definitely recommended that a multi-area production cost study be performed as the next step to finalize this Intertie Economic Feasibility Study. 8.2 SENSITIVITY ANALYSIS A computer program was developed by IECO to analyze the sensitivity of different escalation and discount rates on the capital costs of various alternatives. This program, the Transmission Line Economic Analysis Program (TLEAP), provides the following outputs: • Tables indicating independent minus interconnected system costs, discounted to the base year 1979. • Separate tables indicating the discounted value of base year (1979) costs for the independent and interconnected systems. • Cost disbursement tables for alternative system expansion plans. These tables also include intertie line losses. Computer printout sheets indicating input data and calculated results for all alternatives included in this economic feasibility analysis are found in Appendix E. 8 - 2 - - - - - - - r - r I r-. I r 8.3 ECONOMIC ANALYSIS Tables included in this chapter and in Appendix E indicate economic ana- lyses for a range of annual escalation rates of 0% to 12%, and a range of discount rates from 8% to 12%. For principal investigations below, a 10% discount rate is used and cash flow for facilities under conside- ration is expressed in constant 1979 dollars, only the fuel related energy costs are escalated. The 10% is regarded as the appropriate discount value for Opportunity Cost of Capital and is now required by the Office of Management and Budget (Ref. 1) for economic analyses to determine benefits for all federal projects. For the purposes of the economic analysis, it is the discount rate cor- responding to the opportunity cost of capital which is used to calculate all present values of costs and benefits; the particular cost of in- terest actually paid on bonds or other obligations is irrelevant since it bears no relationship whatsoever to the project•s internal rate of return. It is only a financial (or budgeting) parameter. Therefore, the interest during construction and other financial changes are ex- cluded from the economic analysis. These charges appear only in the financial analysis. A. Benefits Due to Generation Reserve Capacity Sharing (Case IA) Three cases were investigated to determine intertie benefits due to generation reserve capacity sharing alone; the 230-kV single circuit intertie between Anchorage and Fairbanks. In all cases 130 MW of power transfer capacity was allocated for generation reserve capacity sharing purposes. The economic analysis results indicate the following benefits due to intertie (differential of present worth}: Load Intert i e Cost Reference Benefits ($ x 1000} Forecast {Percent} Table {PW 1979} Probable 100 8-1 12,475 Probable 125 8-1x 945 Low 100 8-1-LL 2,704 8 -3 The above results indicate that the 230-kV intertie is economically feasible based on generation reserve capacity sharing alone. Sensitivity of the results to variations in escalation and discount rates are indicated in Tables 8-1, 8-1x and 8-1-LL. Computer printouts indicating details are included in Appendix E. B. Benefits Due to Generation Reserve Capacity Sharing and Firm Power Transfer (Case 1B) Six cases were investigated to determine combined 230-kV intertie benefits due to both firm power transfer and generation reserve capacity sharing. These study cases have one 230-kV single circuit line during the 1984-1991 period and two single circuit 230-kV lines during the 1992-1997 period except for low load forecast case (Table 8-3LL) when the second 230-kV circuit is added in 1995. The economic analysis results indicate the following intertie benefits (differential of present worth): Load Intertie Cost Reference Benefits ($ x 1000) Forecast (Percent) Table (PW 1979) Probable 100 8-3 24,054 Probable 125 8-3x 12,533 Low 100 8-3-LL -2,626 If the above intertie benefits are combined with the additional benefits due to supply of construction power to the Upper Susitna Hydropower Project site (see Section 7.9), the economic analysis results indicate the following benefits (differential of present worth): 8 - 4 - - -I - ~""" r r f""' -! r I r Load Interti e Cost Reference Benefits ($ x 1000) Forecast (Percent) Table (PW 1979) Probable 100 8-4 29,633 Probable 125 8-4x 18,112 Sensitivity of the results to variations in escalation and discount rates are indicated in Tables 8-3, 8-3x, 8-3-LL, 8-4 and 8-4x. Computer printouts indicating details are included in Appendix E. c. Benefits Due to Generation Reserve Sharing and Firm Power Transfer (Case IC) Two cases were investigated to detennine 345 kV intertie benefits due to both: generation reserve sharing only (first line) and genera- tion reserve sharing combined with firm power transfer (second line). These study cases consider one 345 kV single circuit line between Anchorage and Fairbanks. The economic study results indicate the following intertie benefits (differential of present worth): Load Intertie Cost Reference Benefits ($ x 1 000) Forecast (Percent) Table (PW 1979) Probable 100 8-2 -3,556 Probable 100 8-7 426 The above results indicate that the 345 kV intertie is not economically feasible based on the conditions specified in this study. Additional studies, including interconnected system production costing, may prove the 345 kV intertie feasible. Sensitivity of the results to variations in escalation and discount rates are indicated in Tables 8-2 and 8-7. Computer printouts indicating details are included in Appendix E. 8 - 5 D. 230-kV Intertie with Intermediate Substations (Case ID) Four cases were investigated to determine additional benefits due to supply of power to the I~EA System at Palmer substation, and construc- tion power to the Upper Susitna Hydropower Project. These cases include a 230-kV single circuit line between Anchorage and Fairbanks (Ester), with intermediate substations at Palmer and Healy. The economic anal- ysis results indicate the following intertie benefits: Load Intertie Cost Reference Benefits ($ x 1000) Forecast (Percent) Table (PW 1979) Probable 100 8-5 17,814 Probable 125 8-5x 9,125 If the above intertie benefits are combined with the additional benefits due to supply of construction power to the Upper Susitna Hydropower Project sites (see Section 7.9), the economic analysis results indicated the following benefits (differential of present worth): Load Intert i e Cost Reference Benefits ($ x 1000) Forecast {Percent) Table {PW 1979) Probable 100 8-6 20,344 Probable 125 8-6x 11,656 Sensitivity of the results to variations in escalation and discount rates are indicated in Tables 8-5, 8-5x, 8-6 and 8-6x. Computer printouts indicating details are included in Appendix E. 8 - 6 - ~ -, ~ - - r i r r r E. Intertie with Upper Susitna Hydropower Project Only system reliability (MAREL) analyses and facility cost estimates were developed for this alternative system expansion plan (Case II~ Chapter 6). The economic feasibility analysis was not performed for this alternative because: • The methodology of this economic analysis is more appropriate for thermal generation systems. It is not applicable to a large mixed hydro/thermal generation systems. A multi- area production cost study~ involving extensive analyses of optimum hydro operations in conjunction with thermal plants~ would be required to obtain accurate results. t A draft copy of the Upper Susitna project report prepared by the Alaska Power Administration (Ref. 2) was received by the Consultants in the course of this study. It includes revisions to unit ratings for the Upper Susitna Project used in the MAREL analyses (as described in Chapter 6). The new total installed capacity is 1573 MW, versus the 1392 MW installed capacity used in development of the expansion plans analyzed in this report. A study should be perfonned to accommodate the above revisions to the Susitna power ratings and change to the production economics due to major hydro substitution for thermal energy. The study should examine in detail the economic feasibility of Susitna hydropower, due to the displacement of large increments of thermal power. For reference, Figure 6-5 in Chapter 6 indicates the initial expansion plan developed for this study. This figure also indicates the thermal generating unit displacement by Upper Susitna Hydropower units. 8 - 7 MAREL study results indicate the following intertie requirements for maintaining the study criteria of equal reliability system expansion with introduction of Upper Susitna power: Period 1992 1993 1994-1997 8.4 REFERENCES Requirement One 345-kV S/C line to Anchorage One 230-kV S/C line to Fairbanks One 345-kV S/C line to Anchorage Two 230-kV S/C lines to Fairbanks Two 345-kV S/C lines to Anchorage Two 230-kV S/C lines to Fairbanks 1. Business Week, Economics, Pages 96-97, February 19, 1979. 2. Alaska Power Administration, Upper Susitna River Project Market Analyses Report, March 1979. 8 - 8 - - - - ···~.·.} -~------~-----~.:---·-·------------.. --~----------·-···-----------------.. -- IlLilS"-A PIJ;·;fl~ AlJftiOI?l l 'f AtJ(H(J"A.GE-FA!R•:Ji\;-JKS INif:RTIF f: C 0 !\ U •': I C F 1:: AS I h T L I T 'f S T i t i)Y CASE IA, 230 kV GENERATION RESERVE SHARING ONLY . PROBABLE LOAD FORECAST CASE ·· · ·· -· ---- . . . OJFH~EN1IAL OlSCOUNTF.IJ V'ALUF OF 8ASE YE.AR (1979) COSTS INDFPP;OEN1 SYSTEM COSTS MINUS PITERCO~;NtCTEI) SYSTI:.M CUSlS (IN $l00U) TAHLE 8-1 ----------------------------~---------ESCALATION RAJtS----------------------------------------- 0 I Sll~llf·Jl IP. ill '.> 'r. h% 7 "1. H "1. 9% l () :1: I D.: 1 i'7. B.~J H. L:'S 1'1,51) f\,75 9,il0 q.,:c., ,, • ') l) 9. t') 1 0 "{: () l () .<'') !11,'-JO 1 (J. 7 5 I l • \l tl J 1.2 ... ll. ';\() J l • 1 '-, l ,2. (\() Note: 1 (;, 'll '\ .t i. I 75 l 1 I 1.1 I 4 \ 1 I h .S lj 11, W3o l ,~ i (J 2 0 I r' ,j HI\ ~~·''" l?,•J/5 1 ?. " 5 ~; h ! ? I J \i 3 12,7'-J"l l ?. I A 7 'I ],),Q£.'-1 l~l{)fJ/ ! ; , (l '-, '.) 1 3, li '15 2,4)4 3. i!<L-.! 3,927 ~,oil S,?S& ~,l'o'.i (,, ;, 'l? 6,9fl3 7' '• 91 7 1 U()q i1, 1.; J I f.,l\3-1 «,.?51 9,':-49 9, 'i'• 3 I P, 2o 1J 1 ,, , ':Jb2 -\, ,>! ro -,.>'j 1 64 7 l , 'j() 3 2 1 51 II 5,01'1 .~, "() 0 :l , /j l) l 5 I J 5 f.\ ':1 I (' ij Q 6, .~?.~ b,'iu7 7,5"111 /,1151-1 1\, }09 e, n2 9, 129 -'>,r_.b2 -:J, .'l 0 1 -31 )]'-) ~2, 321J -[I 321 -371 'J31 1, 3H') 2 I I <,'Lj 2, 91}(\ 3 I i:-!' ':j IJ t _s 7 1 5,0!'-1 5,6)0 6,?.0':\ 6, 7~2 7,2o5 -Il,u'-1? -'-l,ol9 -n,?.o') -b,9l7 -5, 7'~2 -ll,':lliH -3 I lj AI -.-',<J30 -1 I !J .S I -'-11:\4 41'-:i I I 2bi3 .?,076 2,1:\41 3,'J66 4,?.S?. 4,900 -li.111'."h -t•,,/71 - 1 iJ, l _) j -1<.',">79 -tl,QGo -Cl I t>/d Ad,339 -7., 0':>9 -5,1\41 -IJ 1 h ,0, (> -S,SRl -,2,~7,/j -J,'.>iJ() -:.95 301 l, I'.>? 1,9'.>~ -,>:,,147 -_', ti, I rJ a -.:; .. l, g(lf) -2 5, i) q t) -.St,7Sn -~~ i ,u)f.) -? 1, I .$6 -c!Y,llill -3'-1,!79 -!'l,<.'nli -?1,]91 -36 I 'j!J U -1 7, ,, !lh -?':i,Oll -511 1 (II "( -15,756 -2_$,1)1JO -31,<>0'.> -14,166 -21,102 -29,)01 -t?,b2l -14,<-'':i? -27,1l9Q -ll,lll9 -!7,1JI:jh -<''J,'/41-t -9,"/47 -t'->, hJ<' -2~,91'.1 -8,LI11 -]f.l, 145 -21,065 -7,1.$9 -l<',o~>2 -!9,27,'> -':i,ll21;1 -11,202 -I 7 I •I H b -4, "llb -9,,;()Q -1'.>,1l16 -3,61:\() -1'>,41:1?. -14.223 -2,6)7 -/,?11'. -!2, 103 - 1 , t>4 7 -6,014 -11 .2S3 In early years of the expansion plan capital requirements are higher for the independent system plan, but in the later years capital requirements are higher for the interconnected system plan. As-the discount rate increases, the-sum of present worth decreases more for the interconnected system plan than for the independent system plan, therefore, the differential of the stimS of the discounted values increases with the increase in the dis- count rate. Due to larger capital requirements in the later years of the expansion plan, the increase in the escalation rate causes a greater increase in capital costs for the interconnected system. As a consequence, ·the differential of the discounted values (benefits) decrease. Refer to-APPENDIX E for capital disbursement tables and tables of discounted values. -'>ltt!"l2 _..,)' !<', 3 -~,!),1>00 -II 7 1 II 58 -4ll,'Jll -41,663 -3e,(nd -.Sn,53.S -55, HIH -31,4':;11 -2 'I I I t\ 1 ·27,005 -?4,~~? -2?.,'~$4 -21,05<l -19,219 -J7,4flb :3 AUGUST 7'1 ALASKA Pl.ll'i~l-l Al.llHOJ,illY TABLE. 8-lX co .... 0 .J il'lCHORAGt.-F:.IRt3Af•f<:S lNlERTIE C: C f1 ~,, l ~q C F E A S I •H L 1 J Y S 1 lJ f) 'r' CASE IA, GENERATION RESER'~ SHARING ONLY TRANSMISSION LINE COSTS INCREASED BY 25% PROBABLE LOAD FORECAST CASE l) IFF ERE NT I A L D fs C 0 U td C: 0 Y A L U t -0 F 8 AS ( yt A R ( 1 9 7 9 ) C 0 S T S lNDEPE~DENl S'r'STt.M CUSJS MINUS INTERCONNECTED SfSTEM COSTS (IN $10\JO) --------------------------------------ESCALATIU~ RATES----------------------------------------- U I S C PUt' J I)/. ll'f. ')% 6% 7'7. 1;% 9% I 0 ~ I I I. .. J kAlE:_ ----------------------------------------------- H.ll() • 1 , •l I (1 -11,771; -15,92/ -2ll,t\'17 -26.1:!0'1 -53, 74P. -u2,019 -'->!,642 -o2.~t>O I'.<'S -1, li'lo -Ill, M q l -l<l,':l':iO -14,~9tl -i?.':>,c-'53 -31,91Jb -39,1J2ij -l.l'-1, O')IJ -S9, 13?.1 r;.~o -., l14 -10,()48 -13,rl24 -18,360 -2S,lbil -30,17') __ ,1,125 -4b,'::J77 -5o,910 f. /5 -'i~-<.S -'-1, ('1J7 -12,<'<-17 -17,178 -22, 35U -2d,IJ/3ll -5), 710 -4'l,206 -5 1J, 122 q. ll ll -1'1 -t', lj t\'j -11,'117 -16,0'>?. -20,907 -<'•>• i\h£1 -3~,7'111 -ill, 9 _) 7 •51,4SI '1,2'> l.ill -7,7t,l -11,032 -I'J, 9 7 'I -19,705 -2S, .'i23 -31,962 -3'-1,7{>1:> -aK,i:\'-1~ '1.So lj I> I> -7, (17 Ll -10,190 -U, '1':> 7 -ltl,•J73 -2~,1-\IJd -30,207 -.H,MIIl -~b,<l4b '1.1') 7 I Q -1:>1 IJ22 -9, .Srl9 -12,'-li\2 -17,247 -22,440 -?.0,S29 -~s,·1oo -«a, 102 10.00 <liJ <; -"i, 1<0) -rl,o27 -12, tl')ij -lo,l7b -21,09'} -26,</26 -B, 7<;JH -;j I , A') 7 10,<'';> 1 , 1 t' I -';>, 2 1 () -7,"103 -11,171 -1':>,107 -14,1:\10 -2'i,!d!> -31,979 -3'1, 101:1 !0.'10 1, )n 1 _,,, o':''l -1,215 -II), BO -Ill, I) t)/j -IK,St-1') -2'i,<fr'fl -~1),23il -57,b':>l 1 '-' • 1 c;, 1 ' ') /j" -11 I I ~?. -b,'H>2 -9,',29 -13,116 -l 7, Ill ') -22,':->c?A -21".~)7Ll -.S':i,oH2 \ 1 • •J ,} I , 7? I --$,o$2 -S,9ill -1\,lt>"A -12. 1'-10--1n,20/-l -21 d 'I! -c'o,'-IH.S -3~.191) I l • 2 S j,/iAI -3, 1 :-i'l -., ' S"d -B,04<J -I I, 30H -IS,23.S -19,414 -2'),461 -31,9'-15 1 I • ':> () 2, l) 50 -2,7!2 -ll,7911 -/,)')<; -10,.:!6tJ -111,217 -!P.,b9') -.?<I, 0 tlb -30,2oCl 1 1 •. , ";, 2' \ bb -2,<'59 -LI,c't>S -1>,701 -9,o6d -LL248 -17,53\J -22,olo -21i,t>l8 11.00 2,291 -l,li89 -j,/63 -i:>,079 -H,~07 -12,32':) -1b,lll8 -21 d8 7 -27,03Cl Note: This case is similar to the case pres-ented in Table 8-l, except for the increa-se in intertie costs by 25 percent which caused an increase in capital requirements for the interconnec-ted-system expansion plan. -For case analysis refer to note in Table 8-I. J J .J J J j j • J J '<'-''"~ J 12% ----... -75,1:\89 -72.533 -t>~,92ll -h5,658 -hc:',S?d -S9,S2'1 -so,b56 -'l3,903 -51,26', -Qf\,7_)tl -46,,~HI -LJ3,99<,) -41,719 -39,&52 -37,ol~ -35,bb5 -B,798 J J ) -~ ~. ) 28 AUGUST 7q ALASKA POWER AUTHORITY ANCHORAGE • FAIRBANKS !NTERTIE ECONOMIC FEASlBILITY STUDY TABLE 8•l•LL co I-' I-' CASE IA, 230 kV, GENERATION RESERVE SHARING ONLY LOW LOAD FORECAST CASE DIFFERENTIAL DISCOUNTED VALUE Of BASE YEAR (1979) COSTS INDEPENDENT SYSTEM COSTS MINUS INTERCONNECTED SYSTEM COSTS (IN $1000) •••••••·~~-·-·······-~---·-··--·-··•••ESCALATION WATES·--·-·--········~·-••••••••••••••••-·-~•·• DISCOUNT 0'% 4X 5% 6% 7% fl% 9% lOX tit 12% R A Tt:: ::::::: -------·--------===== -----====: ===== -----===·== s.oo 41292 61955 71203 71 166 61765 C,l904 4,475 21351 •619 •11,605 8.25 lll095 61860 7 r1 6 7 71206 61903 6 r I 6 7 41895 21964 232 -1,466 8.50 3,897 6,751l 7,1 14 71225 7 I 0 I Q 61396 51272 31523 lr0\6 •2,409 1:\. 75 31691\ 61·o38 71048 71225 71 1 0 0 61593 51607 41031 11 13b •1,430 9.00 31499 61513 bl966 7,1207 7 ,!63 bl759 5190ll lll119l 21391 q.25 31300 6, 'H9 61876 7 I I 7 2 7,203 61897 6, I 65 4,906 31001 9.50 3 I I 0 I 61237 61773 71 122 7,?24 71008 61392 51278 31552 Q.75 21902 6101\8 6,660 7,058 71225 71095 61588 51610 41053 10.00 2,704 51933 6.537 61981 7,209 7, 159 61753 5,904 41507 10.25 21507 51772 61406 61892 7,! 7 7 71201 o 1 891 b I I 63 41917 10.50 2 I ~ 11 5,606 6,267 61791 7.129 7,223 71003 6 1 3f\8 5,284 10.75 2 I 116 ~1435 6 I 121 61681 71068 71226 71090 b I C,IH 51613 11.00 11923 51261 51969 6 I 56J 619'13 71212 71 155 61748 51904 11. 2S 1 ,7 31 5,083 5,811 6,433 6,907 71 11\2 7, 198 61885 b I I 6 I 11.50 11541 41902 516!l7 61.?96 6180'/ • 7 I 136 71222 6,997 61385 11.75 1, 3':13 Ql718 511l79 61 15 ~ 6,7 0 I 71077 71227 71085 6,578 12.00 11166 4 •. '> 32 51308 6100Q 61584 71005 7 . .2 I Q 7 ,151 6,742 Note: In the early years of the expansion plan capital requirements are somewhat lower for the independent system expansion plan (less new generating capacity is required). In the later years capital requirements are lower for the interconnected system plan. As the discount rate increases, the sum of the present worth decreases more for the independent system plan, therefore, the differential of the sums of the discounted values decrease with the increase in the discount rate. The above analysis is applicable at the lower escalation rates. Due to marginal differences between capital requirements for both independent and interconnected expansion plans, at higher escalation rates the situation reverses, the differential discounted values (benefits) increase with the increase in the discount rate and decrease with the increase in the escalation rate. Refer to APPENDIX E for capital disbursement tables and tables of discounted values. •5211 312 11083 1 r 79 I 21442 31037 31580 410711 Ql522 41927 5,290 5,615 5190Q co I -I I I ) 23 AlJGUST 79 D 1 scour~ r f< AT t 1".\10 ii.?.S M.'::>ll (X) d. 7'::> ~~ • 0 l~ ...... 9.2'> N '-1 • '-, (, ~. 7'> 1 :) • ll (J Ill.?'> \ll • s" L;. 75 1 1 • ·~ ,: ll.h tt.'Ju I 1 • 75 12.lJiJ J ALASKA PO-ER AU1HOR1TY ANCHU~AGE -FA1RHANKS INTERTIE I:.CUNO~I I C F EAS 1 f3 ll IT Y __ STuO_Y ___________ _ CASE IC, 345 kV GENERATION RESERVE SHARING ONLY ------------.PROBABLE LOAD .FORECAST._ --- [IJFffRcNTIAL f:!ISCOtJNTfll VALUt (_lf BASt: YEAR (!979) COSTS I NDH'EfliJI:.N! SYSH:.M COSTS ~1! NUS If'< T ERCONNI::C lED SYSH./4 COSTS ( I I~ !liiVvO) TABLE 8-2 -------~------------------------------[SCALAliON RATES----------------------------------------- OX ... k S% b% I% ----------------·---------- -iJ , f\ f., b -IO,rlo9 -15,279 -II">, 167 -J9,t,(l1 _,,. ,, 7 q -\ l• • .5':>•1 -12,6'13 -I ') I lj l 2 -!8,b9i'l •4,1li.HI -'-l,i)b':J -l2,<J51 -l:.J,b92 -J7,rlY:i -···~ll2 -<I. IJ 0 I -I l , •I fj"' -14,00<:> -17,011 -lj , 1 3;; -h,li':J9 ""I 0, 9'i•.J -13,.)'-,} -tb,?C'') -~. ·n ~ -1:\, ..,,J u -l•),ll3t> -1?, 72P. -I 5. /j {'I -3, 1'2'1.1 -M 1 ]43 -9,9V.7 -12,1.S:.. -14,7'->o •$,t-,;<':;, -I, 7 bb •9,'-lf\3 -11,':>68 -11.1,075 -5,':>~6 -7,'-itJ>'. -9,1)<12 -11,029 -13,423 -3··•5h -7,070 -IJ,o22 -1u,<Jt7 -12,<102 -3.3?5 -6, 1 {J 4 -il,22.:t -1(),0?9 -12,210 -3,2<'2 -o, l~, .. ~ -7,i>47 -9,565 -I 1 , o 1, b -.,. 127 -,,ISH -l,i~l:.ld -9,123 -!!,tva ... ; , 0 tJ (~ -'::>,0/ltl -7, I iJ'! -~.704 -l0,')9o -2,45'l -S,o3J -b,d27 -5,30'::> -10,109 -2,,til> -':l,38tJ -o,522 - 7 I 92 7 -9,6<15 -2,<119 -s, 159 -6,235 -7.~o8 ~9,204 ill. 9% 107. --------------- -?~,l>'JI::! -2fJ,4?! -n,'lti'' -?2,51:.13 •27,1SO • 5<' 1 tj 59 -?\,':>So -?5,9S':> -.SI,OStl -21),574 -211,771 -29,oil7 -19,o.So -;>3,6Sil -c'B, 37<' •Jtl,734 -22,'J4.5 -27,111 -l7,8B2 -21,'::>75 -25,913 -17,063 -20,olll -24,761 -lb,2R2 -J9,ob'l -23,658 -l':>,S35 -1"',179 -22,o03 -1«,825 -!1,92R -21,')93 -Ja,t43 -17,11S -20,r.21 -1:!.,1',94 -to.535 -19,7v2 -12,1:i75 -l'J,':J4b -lll,B!9 -12,285 -14,1:187 -17,973 -11,722 -14,210 -17,lo5 -11,1/36 -13,5b<l -16,393 .J I!% ----- -'-10,4')0 -31),700 -37,0?3 -.S':>,lJ!5 -3'i,87ll -32, Fi7 -30,9!32 -2'-l,b?b -21:1,328 -27,083 -2':),892 -21.1,751 -23,651:1 -n. 612 -21,611 -20,6';,2 -1'<,735 J 12% --·--- -47,93i.J -45,893 -43,936 -1.12,059 -1.10,259 -3i:J,':J32 -3b,57b -35,28'1 -B, 766 -32,307 -30,908 -?9,567 -28,282 -,n,OS1 -25,871 -2LI,71ll -23,658 -1 ):> CD r- rrl (X) I 1"\) .. ~ .. 1 -·----··--~. oJsco•1;,r ~ ... :. 1 c. k ... ;,·1 rJ ,..,,:, I' • ') (i o. I<; 9, r) () 'f.;?~:J 9.l.,O c • i ';, J ,1 • ,, 11 1 tl. 2 ':J 00 I 0 • "ll I t.r • l':> ..... 1 l • \10 w I I. 2') 1 l.'Ju l l • ,,, 1 2. (I 0 t\LAS~i\ Ptl~tK AilfhORiiY ~NC~~~b,;t.,._--.;!:_-Ft..{i-\ds\~~".5 !~.;TE~TlE f:C~~~.,;n~1 iC FF::~.SlSIL11Y S~ttO'f l CASE IB, 230 kV, GENERATION RESERVE SHARING PLUS FIRM PO\.ffiR TRA.~SFER PROBABLE LOAD FORECAST CASE L'InEr<EII.TlAL IJlSCUl>NTED VALliE [l ~: RASE:. YEAR (1979) I NUE: ,.>F_ oll)c N f S'!'SiEM cosrs :--!It-iUS 1•·:11:.RCOIIINI:C lED SYSTEM (lN SlOOG) l } TABLE 8-3 COSlS COSTS ---------------------------~----------ESCALAilON RAlES-----------------------~----------------~ fl ~! W7.. ',Z 67. 77. i':l~ •n. 107. 114 12! ------·--------------------------------------------- ~'~, 7 ?.6 cS1.'>1~> ?.c.>,uS4 2t~,2S2 l7, .'\'? .s 1 il 1 f. 7 C ll,v9c 6,GL!ti 1'21 -'l~Olf\ ? 1 4., t~ 1 ~ c5,',~>S 22' ~'!') 20, 74') 1/i I~ 'j j 1 '::>' 7ij () ;?., 12!1 1' 7 2 3 2,372 -o, G':> S ,'U,t,J'/ ?_ ~:,, 7 P. H 22' 1 r!" 21,203 1 'I, 1 !J7 lo,'l7K 13, 1 tl6 1),'152 3,!lL!4 -2 ,i!7tl £' <4 , ') rj 9 2 s' Q(i 7 2 .s 1 n 2e 21 , o27 ]9,713 11,c'09 11l,028 10,075 'j,21.12 -51:19 ?·!, tJbi\ 2lJ 1 \ 0, l'i,S05 221017 ?11,21.10 17,t'oil Jll,HQH 11.1Sl 6,561! I , 0 I b ,) lj, j 1"' 211, 51., ?.'jl')':i! 22,577 20, 72~ 11:1,55o 15,71o 12,179 7,1;2'j 2,':>1l5 <' 11, {' 7 'I 2·~,q~"\t,.) ?. ~, 17 •l 2?., !Oo ?. \ , 1 fllj I q, 136 16,4!i(1 I .3, 14ll 9,016 3, qq 3 2 l' l 7 l (' il,.., (> 3 2~r'l73 (!_ j r I) (1 7 c 1 1 htl tj (<JI(>Of J7,20q 1<~10So 1 0, Ill 1.1 ':>,569 ?. -. , [1 S 'I 2~ I t:)SR {!lj, 1llQ 2.S,?i<l ? 1, <.)()) 20,219 17,KR7 1ll,9l':i I 1 , 2 l I 6,1:<76 ?. ~ I ') ~ 1 241754 2:1, )Oil 2~,';>29 22,3?0 2 \[, 7 \)C::, 1H,523 1 s, 7 21l 12,220 7, q 16 2\,M(lU 211 I {Q .s c II, 4 3;) ?3,7S2 22,b7H 2~,1S7 I 'I , I l 1:1 16,41\':i 1 ·s , 1 7 11 9,091 t?S,n6? c'<J,>\)C, 2«,':iS2 2519')1 l,?,971) 21,')1'} I 9, b 111 17,201 lll,07S 1 0 , 2 (J 11 2 $, '., 1 K ;'l .. ,~h) ?.4,o<Jil ?4,l('tl 2S,cS2 2\, 9h 1 2•),192 U,f\73 I'', 921l 11,2">1:1 t?3,3o9 ;?ll' ~ '0 241l?.o 2'l '2~·· 2 L 119'1 22, 317 '20,675 1 il , 5 ll 3 1':,,'{('<} 12,?">'> 2 5,? 1 .. 2u,tl7q 2IJ, 7/< 7 211,11\9 '2.5,723 2?,ol11J ?.1,123 19,093 lb,ll78 13,197 23,1>':>3 21~ , .. ~ 6 u 2r<,r\31 2 11,'53~ ?.3,92.~ 2~,91jll 21, s 39 1'1,644 J7,lli7 1U,Of<7 2?1~'':111 /?Ll, 1'\')3 211 1 /) t'-1 2IJ 1 o5? i?l.l,lOO 23,217 211921.1 20,!59 17,H53 ILI,928 00 I w AUGUS I 1'1 DISCr.n;~•T ~ h If_ r..uo !1.?5 tl.:,o M.7':) o. loO <~.c'-> 9. "(j <J. 7.., ll' • {I {l 1 l 1 • t? s OJ 10.')0 lf,. 7'; J1 • (I 0 ..... 11.?') ..p. l I • ') 0 l I • 1 <, I 2 • li 0 ,\LAS"·' f'll•~tf{ ,\illHtWJlV AN c H \! ,, h r, E -. F A !1<1\ A •• K s I N H R 1 1 E ~CQ~nMIC F~ASIHILITY STUOY CASE IB, 230 kV, GENERATION RESERVE SHARING PLUS FIRM POWER TRANSFER TPJrnSMISSION LINE COSTS INCREASED BY 25% PROBABLE LOAD FORECAST CASE l)lFFt:RENTlAL i)lSCOUNTED VALliE OF RASE. YEAR (I'H9) COSTS INDEPENDENT SYSTEM COSIS MINUS INTERCONNECTED SYSTEM COSTS (IN $\000) TAMLE 8-.>X ----------------------------~---------ESCALATION RATtS---------------~------------------------- !II,. 4/. ':)% bi. 7% ----------_._ ___ ---------- 12, .'Ill 0,11~ 7, ~ 2 6 S,Q2b 2, 1 )6 le',1Jb7 o,1181 ·1, >~ I 1 '),648 2, 41 7 12, Stl9 9,1.122 t\,26£1 b, 233 3, 65 1J I ? , 'i <! o l!l,l\>1 H,t>P.l b, 71'1 4' ~'i I) p,C,';tl I u, 'l24 q' 0 ':l I 7,2'-fo '),OilS 12,':\1)7 1•J,o'l7 Q, q (J ~~ ., , 771:1 5, ()21 l(',':;n"i lv,«43 9,li3A ~..~.2~1) (>,201 1 2, ')')II I I , I <-fl I 0 , 1 <1 .~ P.1 6tl<J o,7Llo l?,':>B 11, .5 73 I 0, 3'14 9, OLI 2" 1,2S7 12,')04 IJ,'j')H 1 () t,., 61 9, Ll () 7 7, 1.1;6 I;:>, II 'J6 11 , 7 2') 10,'107 9,7/.Jo 5, 1 1:<5 L:', il ;>I 11,!-\7') 11.133 IO,OoO fl,oOlJ !.?do9 12, \l \)" 1!,33f\ llld'Jl 8,995 l?.,~v'l 12,l2'J 11,')2<J 10,619 9,35'1 12, ,?IJ Ll 12,221:1 1 1 1 I> q 2 1\l,dh':) 9,o97 12, 11?. 12,316 ll,fi/J4 1 1 , I) 9 1 10,011 12,1)9'; 12,.3'11 llt'HR 11,297 10,302 .J H% 9% 10% --------------- -1, IHO -':>,769 -10,9!17 -llo':i -ll,')r.'Jt -9,561.1 4£10 -3,£113 -t\,211 I, 315 -2, <.II I -h,9;'4 2, I 3 3 -l,'l01l -'>,700 2' q •) b -tj') \) -ll , 'J 5 7 3, b :' b ll':i4 -3,1•.~2 tJ,.)2') I , :~ I 0 -2, )f:\ ~ 1.1,'?7";, 2, 121 -I ,31:\7 ':),')87 2,887 -£143 b, 1 6 3 3d> 10 451 b' 7ll 4 I~ 1 294 1,209 7,212 ll,<.J:~tl 2, I 0 2 7,ofl9 S,':>Ll6 2,tl61 1'1' 1 35 6,115 3,';7i\ ~.';:152 6,6':ib 4,25b 8,9Ll2 7' l b 1 lJ,89o J I 1% ----- -17,202 -l'-i,Ll99 -13,1176 -1 c, BO -10,1'57 -9,!154 -1',!19 • 0 1 /i If (\ -S,o4\J -4,LJ9! -5,39'1 -2,31>2 -1,378 -4'HI 442 ld£'.2 2,077 12% ----- -2<!,54!1 -?2,':>?2 -20,591 -IH, 74~ -16,'?90 -t':J,31lJ -IS,i\'> -I.?, I 90 -10.7.513 ~9,3':>4 -8,036 -b,7P.2 -:,,',()}\ -4,4':,3 -3.371.1 -i!, 3£18 -1,374 -1 6; r-rn co I w X .. J 28 AUGUST 79 DISCOUNT RATE a.ao 8.2'5 8,50 8.75 9,00 9,25 9.50 9.75 10,00 10.25 10,50 10.75 co 11.00 11.25 I-' 11,50 (J1 11,75 12.00 J ALASKA PO~~R AUTHORITY ANCHORAGE • FAIRBANKS INTERTIE ECONOMIC FEASIBILITY STUDY CASE IB, 230 kV, GENERATION RESERVE SHARING PLUS FIRM POWER TRANSFER LOW LOAD FORECAs-T CASE DIFFERENTIAL DISCOUNTED VALUE OF BASE YEAR (19791 COSTS INDEPENDENT SYSTEM COSTS M!N0S INTERCONNECTED SYSTEM COSTS (IN UOOO) ••••••••••••••••••••···~····••••••••••ESCALATION RATES••••••••••••••••••••••••~•••••••••••••••• n 4% '5X &X 7X ex 9l lOX llX l2X ::~:::.: ===== ===== ===== :.::::: =-~--::::.:: :::=== a:==== c::;: ·729 4,879 b,790 8,952 11 , 39'5 14, 152 17,258 20,7'55 24,&69 29, 111 •99& 4,430 6,279 e, 373 10, 7H 1!,408 16,416 19,802 23,&11 27, 892 •1r25tl 3,995 5,786 7,813 10,10ll 12,688 1'5,601 18,881 22,569 26,711.1 •1r503 3,S7S 5,309 7,271 9,490 11,993 14,81£1 17,990 21,562 25,57& •1,743 3,169 4,847 6,7£18 8,896 11' 321 1£1,053 1 7' 129 20,S89 24,476 -1, (n6 2, 776 4,401 6,242 8,322 10,671 13.318 16,297 19,6118 23,1113 -2,200 2,396 3,969 s, 752 7,767 10,042 12,606 15,493 18, 738 22,385 •2,1.117 2,029 3,552 5,279 7,231 9,43£1 11,918 14,714 17,859 21,391 •2r626 1, b 7 4 3, 149 4,821 6, 711 8,846 11,253 13,962 17,008 20,431 -2,828 1, 3 31 2r759 4,378 b,?oq 8,278 10,609 13,234 16, 186 19,502 •3,023 999 2,381 3,949 5,724 7,727 9,987 12,530 15, 390 18,603 •3r212 678 2,016 5,535 S,254 7,195 9,384 11r849 14,621 17, B4 •3,394 368 1, 664 3,13ll 4,799 6,680 8,802 11 ,1 90 13,876 16,894 •3r569 67 1,322 2,747 4,360 6,182 Ar2~8 1 a, 55 3 13,156 16,081 -3,739 -223 992 2,372 3,934 s, 700· 7,693 9,936 12r£160 15,294 •3,902 ·S03 673 2,009 3,52 ~ 5,234 7, 165 9, 339 11.185 1£1,533 •1.1,060 •77S 364 1, 658 3,12£1 ll,785 &,654 8,7b2 11,133 13, 797 -I ~ co r rn co I w I r r ?3 ~li~USl 79 I)I;,cr'u~n '"'A It t< • I){) ~.25 ~-<.')() t' • 7 5 " • t1 tl u.,.:) '1.:>() 9. 7<; I \J • ll 0 I L•. 2':> i ii • ':> •) co i '-' • I':> ) ~ • \I (I I I • r' ·:, ~ 11. ')(r 0\ 11. 7':> 12.110 ) j ~ -· ~ L 1\ S K 4 f' il~>l L ~· 1\ I I T t 'I) f: ! I Y ANCHUkf•G:: -Ffi!RH.\NKS 11'-Tf_Rll!:. lCO~U~lC F!:.I\S!HILT!Y STUDY CASE IB: , 230 kV, GENERATION RESERVE SHARING PLUS FIRM POWER TRANSFER & SUSITNA PROJECT CONSTRUCTION POWER PROBABLE LOAD FORECAST CASE i)J r F U< f: N T I A L DISCOUNTED VALIJE OF I::\ A Sf Yt:. A R (197<)) COSTS I N[>F PE I·Jl)t.N 1 SY S T E:t-1 cosrs MH,LJS 1'-iTlRCO"!NECTE.D SYSTEM COSTS ( HJ $1000) TAULE o-t! ·-----------------~---------~---------ESCALAflU~ HAltS----------------------------------------- 0/. 1.1/. ':>% b% I% P% 'i% $1% 117. 1?t ------------------------------------.... --.... ------.... --- 51, ).11() 3?.,21?. 31,731 _Fl,/4t\ c'J., 2ll9 ?/,!')1 ?4, 564 20,71:\5 lo,.~t)3 10,791 .~ I , t) ~ I 51. 5':>\i 31,'1iJA 31, 0 tJ I 29,<:>79 ?.{,71~2 ;?':i, 11! 3 21,7(13 17,SS.2 12,330 30,/l')C} 32:,407 32,USR 31,51)2 50,072 2t\, 25'1 ?S,t\70 22,71'1 lC\,730 13,7A7 S<1, 1:> 7 ~ 3?. , 114 3 3(',1f;3 ) l , ') 3Ll 3(1, 1~?9 21\,7'14 ?~:>,':>47 25,':)97 1 'I , tU~ 0 1 ':>, 164 .~~·I 11 7 H _,?,litd: 3?,;>il') 31 , 7 .H, S I) , 7 <; 1 2'1,2SH ?i,l77 ?iJ,lllR ('(I, /'.H 4 lh,llh', '·Uu!lt-!>2, /J~ij 3c,~n.> )!,<JI?. 3 1 , $ lj?. ? <)I h f\ lj 27,1o1 <''Jilt'7 21. fl.66 1 7 , & "'/j ~ •J, n oH .>?, /l ~11 3,', ·1? 1 32' Ill)? )1,!>01 30,072 {' t'· , 5 I) I 2':>,'1<)4 2 2, 7 H '! IH,H':>? 2 '!I H., 3 ~?, ,, [I? 3f!,t1~;d 32, !il7 31.531 3o, ,, <'o 21ilfl00 ?tl, ':J 7 2 23,o"i3 1'1,'14'-> ('41hS:S :v. 351 5?,47tJ 32,?1:\R 31 I 733 30,146 2'1,?5'1 2 I, I 4'l zq,'lbiJ 20,973 (.'<l I ·I'• 1 ,S,'1 2H4 3 2, 117 h 3r"?, 'S61'. 3 1 , ,, () tl S I , 0 3 1~ ?9,61:10 2l,770 2">,222 21,940 ,.'"', I in 3?, Plli1 5?' (J~,I\ 3?,'-lc(, 32, \1'1 7 3!,292 3\J,Ub') ?t<, 5l)':) ?'),'!?9 22, f\119 r? X' u ·.! 1 '> 2 , I I !J 5? 1 •L>rj 3?, !j b 'J S?, 1112 31 , ':>?0 30,illh 2fl, l<JH 26, Sll'l 23,702 2ii, I <~2 .5 (., I ii {) _; !u',~/4 3? 1 Llilij 32 r c'l<"i 3 1, i? I !>{I, 7 ~ 5 ?'1,2"d 21,20'> 2/.l,')Ol c! 11 , II C, 'l 3t,f\t<':) 3?, '>I (I 3~, .:.J (~ j_} :s2, 3~>"i ~~J,,;q"' 3l,U2(J 2'1,670 27,77.~ 2'Jr249 <' ll , ?. I I 51,1'Jo !>?, 2 .'>2 32,u7U :s 2, 'l2 'J 3?.,0Llb 31,2/b 30,052 25,502 2':>,941'1 2/,t:lt:>l 31, bIb 32, l4ll 3?.,438 ~2.~<b"> 32,112. 31,0:,04 30,39q 21:1,700 ?h,600 27,709 3\,llbb 32,1l37 32,391 32,4tlo 32.27":. 31,104 30,115 2<1,240 27,207 J. J _J ~J _.J c) '"'-······ ,J J .J ,) .J ,, ,c.• .•.• J J 2 5 1\IJGUS I 74 OlSCOU~l I?.\ TF_ 1:<.00 M.?.C, t.. '::IU tJ.7C., <l.PO '1.25 ,_,. '> 0 4. 15 \ \) • iJ II OJ lli.~? .. t. 1 t> • c, {' 1 0. 7'..> .... I I , llll -..) 11.25 l l. so l 1 • 7 5 11.00 J ,-.. l ALA5KA 1-'UWf:f.: /ltJIHUh'I1Y ANCHURM~l:: -'FA!J.ItlAN.<S !NTI:.Hllf: t C 0 fJ 0'·: I C F f: ,\ S If' T L I T'l' STUDY . CASE IB, 230 kV, GENERATION RESERVE SHARING PLUS FIRM POWER TRANSFER & SUSITNA CONSTRUCTION POWER TRANSMISSION LINE COSTS INCREASED BY 25% PROBABLE LOAD FORECAST CASE l)fHf:I\!ENT)AL UlSCOUNffl) VALUE (JF 8ASE YEAR ( 1979) COSTS INDEPf~Df:NT SYSTEM COSTS MINUS l~TERCUNNECTEU SYSTf:H COSTS (lN 'HO\•Ol } TAHLt a-ax -----------------·-·----~---·---------ESCALATIUN RAT~s-~-------------------------·-------·---~- •)% 4~ ':i ;.; b% 7'1. BZ 97, 10% II X 12X -----===== ----- ---------- ----- -------------------- )!;,.!<>\ 1 f., () h9 l 7, 02 11 1':>,5?.5 I.;, 1142 IO,t-1119 I, ':J 0? .3,3')0 -1,721 -7,835 1>-~,t<<'S 1>-~,?oo 17,.3?4 IS, '144 1'~,1)')':) I l , S 71:l H,O;?q 4,1195 -319 -b, 139 I tl I ]IJ 4 1/.i t /j 41 I 7, ')9p 16,352 l4,'j79 12.?60 Q I 2<lt s.':i76 1,00'1 -II. ':>27 \h,t,.,) PI, '-44 1/,1.142 !6,oi\Q l':>,Ut>':) 12,1199 I 0, I 08 6, ~141'\ ?.,?OEl -2,qq5 )l'o,C.,r>9 lr, 7ho PI, Oo3 I 7 I Ills l"i,':>lb 13,49o 11),!\/C:, 7,'51>2 !,,<leO -I, 542 Ill, 4 o '' 1><,~31\ IH,?.hO 17,51.$ 1 ., , 4 ~II Ill , 0 c; 3 l I, ':>'IS 8, 4 7 I 4,',1\1:\ -lb3 ltl,$'>5 lb,'I.H 111, 'I Y) II, ':> 1111 lbdl'l 1 1J~":J7(' lc,no 9, .S<'II '),o'>4 1,1ll5 ll-',i?.$7 1°,007 JH,''il'\1\ }7,1'129 lb,I17.S 1':>,054 12,'102 10,H4 l;o,ot>l 2, -~85 IP.,IIc 1 ,, , {J(l(J l/\,7<'0 lH 1 ()ll<l 16,49/ 15,":102 I 3, IJ 42 lO,I:l'12 7,61') 3,5':>9 1 7 1 ')Ill) 19,1\)9 Ill, H)!, PJ,2ll6 1/,291~ l':>,~lo I4,UIJ4 ll,bU5 1:1,510 II, 67 1 1 I , <l L1 3 I 0 I 1 ;I) 111,·~.u li\1 LJ21 17,':>1Jt.l 11>,29/:1 11.1,')',/l 12,271 9, .~':>6 '),722 I 7 , 7 C)!) 19, 14'1 14,004 ll:l,'17ll lf,l}\)1:1 lo,b':)O l';,O!,t> 12,t\<Jo I 0, 1 '),? 6, 71 b 17,".':>2 IQ,l49 1 ·~,(I IJij lti,707 11l,Oi:'l\ 1~>,472 1'l,4HO I .3, 4 II I 10,901 7,b':>5 17,39'1 1 <~, HS 19, !Ill'\ J/l,i12l IH,i:'2':J 17,2ol'l 1':>,1)91 \1~,02R JJ,oO':> H,C,IJI II.CLl2 19,109 19,1)11 lc:\,416 18,11!)0 17,':>37 ln,271 l1J,':>'S7 12 .26o 9,377 17,UHO 19,072 19, I ':>3 IR,9'?1J 1.91':153 17,7ll1 16,621 t<;,OI2 I 2, !HY:) 10, I b!J 16,41'> 19,0?.4 I 4, I <;1.1 19,05o llj, 61::11 11l,Oll1 16,942 1'),4')2 15,464 10,905 l D I SCC'.J'-T f. A Ti: ~ • (i I) 1-l,h 1:1.~0 /<. 7 s q • ll I) 9,2~ 9,':>0 'I • I') 1 lJ • I, l) IU,25 1 (I • ') (\ co ! (! • I ') I I • 1) n J 1 • .,! '> ....... 1 1 • ':> J co 11. 7') 12.vo CJ ,J A l ~ 5 K A f' U w [ H /II J 1 H ll !~ K S I I'. T E. R i I !::. F CD N U 11 I C F E A:::; J ti I L I l Y S T lJ D Y CASE ID, 230 kV, GENERATION RESERVE SHARING WITH INTERMEDIATE SUBSTATIONS PROBABLE LOAD FORECAST CASE D!FffRENf!Al DISCOUNifU VALUt OF HASE YFAR (1979) COSTS [NI)!:.f'E.'<0£NT SYSTEI~ ClJSfS '~!NUS lNTI:.RCONNECTf:D SYSTEM COSTS ( IN $I u 0 \l J TAI:ILE e-c; ----------------------~----~----------ESCALATION I?Al[S----------------------------------------- ll% il% '>% h% 7"/. ------------....... _ ---------- 1 e, c~ b u IT,'JSU 1 t>. <)92 IS,t!Y·J 1 L ~31 I 11, qo6 17,72>1 lb,IJSM I'), t> 111 JS,q;>q It!,.)~) I 1 , r< ~<, '> 17,101 15,9').$ lil,SPLJ 1A,2U. I p., I)<' b I 7, Sc' t! lo,i't>'i 1 ·~,>:\I 2 1 .9, 1 q •l I>\, ! 1J H 1 7. ':>21 \b,':>t>O I'>, 21 u 1 ri , 1 lj ll lr\,(''13 l 7 , I v 1] lo,il27 I ':>, ')>In I rl • II I i) II:·, 5 ·~ ~ J7,eno 1 7, •J 7 \) 1':>,9~2 l 7, 17,')1-9 l ~·. ·~ ').., 1~,32'> 17,d5') I 7. (1 il 0 I 7 , J 7 o 1•1, ':> 7 h IH,q02 !l,Q'{fl, 17,2b2 I 7 , .~ •I" I h, '-> 1'. ':> ld,q64 I R, I o 4 l7,uh'J 17,217 1'1,..,82 I •I, 51 3 1 ;\, 2 Jl.j 17,oi',£, I 7 I •) /'.5 ll:i,.., {J 9 l H, S 4 t1 I tl, .) Cl 7 !7,804 lo,9•l9 l",')Ll7 lli,Sf2 11:\, 5A6 17,9<;,tJ 16, i\ I o Jt;,':ll'i lR,St\3 P,l, 4':>1 18,Ufl2 J CJ .J ~ ] .. J ·--· ... ,J ·-· 1)% 9% I 07. --------------- I I , 1 0 0 rl, I 6 fl il, r)52 I I, 7 35 8,91>7 5, 5 1~ I 12, .HO 9, 7 21 t:.Jtil7o 12,!iH9 10,4~1 !, 36?. I S , 11 l .5 I 1 , 1 0 () f\ • I q F\ I 3, 'IO?. 11,729 H,9R9 };J,:$')9 lt!d?O 9,734 [Q, 1P.5 12,o74 1 0, il}ti 1'->tlt\2 13, sq4 11,! ll 0 lS,')SO 13,htl0 II , 7 2 3 l'~,tl9l til,S~':> 12,309 ]fl,207 111,/59 I 2, H6\) lo,4'i/ 1 ':>, I S 11 13d7o lo,lo5 1'),..,21 l.~. !;')'-/ ]7,U09 1 S, H61 [II , .5 i I 17, 1:'32 I b, 1 7o 14,7,!,,!, 17,43') 16,i.l67 15tli!b .. 1 J l .._, I 1 1 7. ----- 157 1, 363 ?.,SOil ,!,,595 4,625 S,oOl o,S?S 7,il00 tl,c2H '1,009 9,7il7 I 0, 4 u :~ 1 1 , I o ll I 1, 71 H 12,299 12 I 1\!.j':) 13,3':>8 l J 127. ----- -'),122 -3,665 -2,21',0 -963 21l'l 1, IJ 71l 2,t>O~ 3,61\0 i.l,b96 '::>,660 b,';i7!J 7,4311 8,256 9,030 9,760 !O,i.JSO 11,!00 .J .l co I (J1 .. I OlSCUUIIT kll I( h,OII II 0 (~ "·~() f\,1-. 9,(!0 <t.?.~ 4,50 ., .7') tu.uo ll1 • i".> CX> Jl•. ':! () li1.7"> I I • 0 J ....... 11.2'--1 1.0 1 I • ')I) 11.7':! 12.00 l AlASKA f-'Owtt< AliiiHJI< l I Y ANCHORAGE ~ FAIR~ANKS JNl[RllE ECO~UMIC FEASIHILTTY STUDY CASE ID 7 GENERATION RESERVE SHARING PLUS INTERMEDIATE SUBSTATIONS TRANSMISSION LINE COSTS INCREASED BY 25% PROBABLE LOAD FORECAST CASE 1 OJFF[Rt:NTIAL DISCOIJNl[D VALUE:. OF J;ASI: YE.AR < 1 Q7<n !NO[ PENDENT SYSTEM COSTS MINUS I NTERCONN[( TED SYSTtM (!Ill .$1000) TABLE ft-Sx COSTS COSTS -------------------~------------------ESCALATION RAT£:.5----------------------------•·----------- 0% £1% ~% t)% 7% 1:\% 9Y. 107. 11% 124 ------------------------------ -------------------- '~r1~') ;,,772 ':),£120 3,bl>!. l.IJ39 -!,31Q -ll,of\'il -",755 -15,oll -1qr3o3 q, !Ill 7,1)£13 '>,71'>3 4, LB i!,Ol,b -'j 77 -3, 778 -7,6':!1 -12.2!15 -17.783 Q, I 9 7 ., , i>QIJ 6,121 ll,57~ 2,591:1 125 -2,<11';) -brb01 -ll,Oc2 •lbr27b . -<1,2115 7,')2Q 6, 1136 £1,91\Q 3, 1c'll 78<1 -2,09') -~rh03 -q,~tq -1£1,83ij q,lll/.1 7. 7 -~0 b,l29 ~ r -~ 17 3r6?b I, 1H 7 -1,319 -ll,h'5') -ii,o73 -1 3, 'l oo "', J<l") 7, 9 H 7,0(11 '),740 ll,(l'l') 2,UOQ -~HI.I -5,151.1 -,7,')f\3 -12,15Q Q, I 1'1 1!,)01>1 ·1,2s2 b,tHH Ll,~35 2r5bfl IU -o:?,HqQ -IJ,')1~6 -1 0, q 12 •lrl"i'> f\,269" 7,rlt\4 o,:sqs 1.1,91JI) 3,094 171 -2,.01\1\ -5,S59 -9,7?5 9,12') H, II} S 7,697 o,bl'.b s,:s~s 3,590 1,394 -1,31Q -tJ,o.21 -~.sqq q,uHq 8,5llu l, f\9 5 6,9'i9 <;;,o9f 4,057 l, 9~2 -5QO -3,7.30 -7,517 Q, Ut17 l\ rhO 3 A,tl72 7,211 b, 0 ;<; II r ~QS 2,., )8 100 -2,tlall -b, IJ92 fo.,q4Q 1:\. 1 b 7 1'. ""3 'j 7, IJ£11~ 6,:~')1) 4,907 .S,Ot>1 751.1 -2,0H1 -S,'>Ib 1_;, 9iJo tl,l\')ti 8 1 .)IU l,b5A brbllLI '),293 5,'>55 I, 37 2 -1..319 -4,589 ~,Mh~ 8,Q~H 1-\, ':>1 (> 7,t\Stl br<)l7 ~,6')4 £1,020 lr9'>6 -~96 -3,707 tl,~C?5 'l,OOt> tl,n36 8,03t> 7, 1 7 0 o;,qQ2 l.l,£15b 2,501:1 a a -2,t170 fl,7'l8 9,063 8,74i'. 8,201 7,£10'1 6,308 '1,867 3r02~ 7H -2,07'1 8 1 MI7 9, 109 8,B.S5 8,3':>1 7,620 brb02 5,2S2 3,520 1,.350 -1,319 .. );! tXJ r f'T1 co I (11 X ~--l ALt.;)!<. A PU"Li? AliH•t:f/]1 Y A~Chu~tG[-FA!R0A~KS l~lt:R!lf ECUNUM!C ~EaSI~ILJTY STUOY CASE ID, 230 kV, GENERATION RESERVE SHARING --· --------------------WITH ·INTERMEDIATE SUBSTATIONS & SUSITNA CONSTRUCTION POWER PROBABLE LOAD FORECAST CASE ~ -·--------~---------·-------·-·--·--·--------~------·---. - f) IFF r:RUJ 1 I t,L DU\CUUNlE1> VALli!: OF nASI:: YEAR (1979) COSTS I ·.; U f. P I; '" 0 t r.. T SYSTti'> UJ~IS t-ii~us l ~~ I 1::: R C (1:'-: I·J!: C l t I) SYSHM COSTS ( IN li i i)V 0) T AfiLE B-6 -----------------~--------------------I::SCALATIUN HAJfS------------------------------~---------- () T SCOU'·J T t) i! JJ% ':>% h •. -"' 7'!. H% 9% !Of. 1 I f. li'X ,, ,, ll -------------------------------------------------- h • I} r. c I , _'i '' ') ? 1' 3h l ?(I' o ·n I 'I' I) 1) y Ill , I 0 1 1 '', U I\':> 15,41)!:> ]0,?)9 6' 1 q I) I, 29o " • <:.., ; I , ?:1 '• 2 \ t 1-ll" 3 ?(I' 1\7 7 I 'I, '1•.14 l A,'_; 1 8 li>,t>)'< 111' r.' 0 il l I,! I I 7, 50 I 2,6':>1 r • ':> r, (' l ' ,_, Ll i'1,'>t!U 21, V':>S 20, Pi?. l H, 'i •.l 'I I 7, l':>b I II, 1169 Il,'16Ll 0,352 3,'?37 h • ,., .? l ,\I] t\ 2 \ , of> (j i?l,?.l2 ;>(l,'l30 I '-!' ? ., 'I 17, h H I 5, 'I 'I 7 !2, 762 9' ~ •I'> ~. 156 ". llil ('11,1;'1') ?\,1?.3 21 'jill-\ ? \)' ,,,) 5 19,~1\') jM,•Jil') JI,,Ofj', 1.$,'->H 1U,21\~ 6,31?. 4. ?') r.'\<,7uo 21' "171! ?.l,ilt>'::> ('1),(1')1~ l4,t\Hq lo'\,4'1'1 lo,t>·sq )Ll,dl\ II,J7c:.' 7,407 !; • L.. ~i 2 ()'I> $\l C l , I~\.).$ ?.1,'>6':) ?1,03~ 211, I'> 7 1 il.' i< 8 $ 1 7' 14 "! 14, Mil I 12,00~ (l, IJ4:5 \) .. 7 c_) 2<.1' ;140 ? l, >PI 21 ',,ll7 2!,1'-11 ?0,<.105 I 'I, c:.' 3 7 1 7, o25 1'>,':>03 l 2, 7 'I 7 9,Ll23 I n. l_, {, ,) II , ) •I '·I 21, >12n ?!,71?. 21 d29 211, t~e'l }9,':>b2 jK,Oo9 )6,01)') !.5,'J39 1 OdSO 1 ,) _co:; 2V, I "4 r.' 1, H 1 1\ 21, foe 21 '•I L) 0 ?O,M)l !'f,c.bO ]I),LlFJI 11>,1>3() 14,237 l 1 '2 .-'b 00 ]II .'-,•) <' ()' !) .s<< ?1,79'1 21, 74 I c'l ,':>49 2 1, 0 I I 2 o, I 3 .S lll,bo2 !1,131) ]IJ,M93 12,0':>2 I0./':1 .\'f,tl/\,) 21,11:10 2 i , 11 II'\ 21,6$3 21,170 20,.)f.l 19,(:'1':) 1 l' (> 12 1'),')0,1) 12,i:l31 II • 0 0 19,71 7 21,72"1 2l,rl.?!> 21,701 2\,)C)Q ;>O,nOo !'I,'J39 1 A, ll':i 5 lo,Otl':l 13,'J6ll N I 1 • e'J ]9,')')1 2\,olc! ? ], £121 21,7')~ 21,1<\0 2\l,l:ll)l:\ 1'1,1:337 18,463 lo,o2~ 14,2':>5 0 1 I • ':> o 19,)C<2 21' t>l () 21, t\0 II 21 ,791 i?I,SB 20,9Aii ? 0, I 09 ll\,1:\'42 I 7, 129 14,904 11. 7'-, l9' 2\)9 i?I,~-~Q 21' l7b 21,Hl? ?!,ot9 2l,! 49 20,.$57 1"1, !'IS 17,600 1~,51ll 12.00 I q, d 311 2l,il59 21,7)7 ('1,i\2') 2!,o8"1 21 '29 0 2(1' ':il:l2 19,5lo 1,,051; 16,085 "' '-"". \-· J J J •._ e~ J .J J j • .l .. J .J ] J J ·--.{--.I ~ 3 •' Ut>IIS I 79 f) 1 S ClltHJT h A Tf 6,1.!0 }l. 2':, /I.':> (l H. i '1 4.PO G.c?S ·;; . "(1 ,, • 1 ':) ll'.OO \li.?'S cP tu.'io 1 u. I 5 I l , 0 0 N ll.t!C:., ....... li.SO 11.7') 12.00 -J 1 J ,\I. AS I\ A Pl'l·lt" '''-' THUIH I Y hi~Ct·t•l"'I\GE. -f ,q><!<t.ra,s l'HI:.RT lE I:.CtlrHJI'lC H:t.Slrl!LJIY SlUuY CASE ID, 230 kV, GENERATION RESERVE SHARING WITH INTER}lliCIATE SUBSTATIONS & SUSITNA CONSTRUCTION POWER TRANSMISSION LINE COST INCREASED BY 25% - PROBABLE LOAD FORECAST CASE D t 1-F t. PEN T T A L D I S C til J N 1 E D VA LlJ t. lJ ~ 1:3 AS E YE A~ ( I 9 7 q } C O_S T S INOEPL~DI:.~T SY~lt.M COSIS MJN~S lhTtRCUNHtCTED SYSTEM COSTS {It< blOOO) -------------------~-------~----------ESCALATION ~~Arts----------------------------------------- OY. /j 4 'J% t>'' r. 17. H/. 9t lO'X. llt 1<'% ------.-.... -·-----------"'!" ---------------------=-------- 12,0'10 [(},')?,9 9,50o t\,032 6, l 0 tl 'i,oo6 629 ~3,0Hft -f,'-)7(; -t2,'Hio 1 2, IJ 11'-ll),}'i!:l Q,l\02 <1, 4 S? b,6?9 ''• .S2M 1 ' 'l "ll -2,071~ -o,.S'lf\ -il,ll67 IJ,9"a \u,CJI->7 10in7':i P.,l:i04 7, I I I IJ,'I'>1 2,234 ·11113 -':>, 1/9 -l<l, CJS9 1 I , ') 5 i J 1 I 1 ')f\ 10, ~26 9, 1'10 7.'::>74 '),53/ ?.,<171 -20.5 •11 1 068 •1-3,719 1\,4i}S l l , ~ I 1 \ (I 1 '.> ':> 0 9, •l 7 0 1-1,001 6,089 .s,o6o 61>0 -.5,01) -7,lll.l5 1 j , 1\') 2 I 1 , l il 7 1 il, I hb 9, 7 h 7 H,LIOO o,bOo '1,!>22 1,LI/o -2,012 -6,?31) 1 I , 7 '< ~ ll,'Jbl:\ lO,'I':>o 10,0LJO lj,/7i 7, () q 1 4,9ll0 c,cLI/3 -1. Otd -5,077 1 I , 1 ;> 7 11,tJ7.$ l I, 1 ?H 10,2'12 9, II b 7' ., lj h 5.'><>2 2,'177 -16) -3, 'lfl! tl,n'Jt, 1 1 , 'ftl II 1J,(>fl.) 10,'::>?5 CJ,LJ5i'J 7,971 6,069 3,o6b 690 -2,<Hi0 1 1,':.79 j),l'li.l2 1 !,i.J21 1 u, 1.n 9, I i2 1\, .So 7 6,'JH3 4, H6 l t I.J <)] -1,9")2 I I , 'J9 to 1l,'H•6 I I, •,114 10,92':> 10.01)6 ij, 7 .H l,Oo', 4,'1?<J 2,<'bl -1,014 1 1 , •j () '/ I I , 'I'J 1\ 11,o'i1 I I, 049 )ll,?'il:l 9,Ut12 7, ':> 1 7 s,soo 2 1 9H5 •124 lldiM ll,'l'li! 11,745 11,2':>'5 1 0, 1IIP'1 CJ,I.JQl 7 t I)IJ 0 b, O'iO 3,ho6 719 1 1, ?; 2 lr',ll?7 IJ,>\2'1 11,.~9') 10,701 9,o98 8.5 ~6 0, ':>I><) 1.1,.\10 1, 51~ lltl.-'2 12,0£lo 11, o91 11,'>20 10,6'11.1 9, '472 8,701.1 7,01.10 1.1,918 2,274 ll,ill/1 lf',l!'l'l I 1 , '< IJ b 11 ,6?..'1 11.069 10,2.?1.1 9,0'18 7,'1119 '),Ll91 2,990 lv, 91 1 t;>,054 1\,989 11 .7 25 11,22'/ 10,45o 9,3b7 7, 911 b,031 3.bbb J 23 1\lJGUS i 74 i) I S C 0 li ~I T f<Alr t~ • \' I, i b.2':> n.')n 8.7'> y. l} !j 9.;>c., y. <:,,, 00 9. t:j 1 v. \} ,} N liJ.2':> N 1 0. ·~,) 1 (). 1 s ! 1 • d ll !I.e'S 1 1. ':>v l 1. iS 12.LJ } ~-· •• " ALASKA Pili'ii:hi AuThOR I l Y ANCHORAGt -FAI~BA~KS INTEHTIE tCO~UMIC FEASI81LITY SlUDY CASE IG . , 345 kV, GENERATION RESERVE SHARING PLUS FIRM POWER TRANSFER & SUSITNA PROJECT CONSTRUCTION POWER PROBABLE LOAD FORECAST OIH'E~[r-JTJ,\L OISCCJU:<Tfl) VALUE UF HASf n·AR (1979) COSTS I N i) t Pi: 1.; iJ Et' T .s y s 1 [t>'l CUSTS hI ''lJS 1 r, T t: RCUN'Jt:.C I tD SYSTtr~ CUSTS C I~:· :f. I 0 () 0) TABLE 8·7 --------------------------------------ESCALATION RA1ES--~--------------------------------------vi; t-,~%_ 'J% t>% 1% t\% 4% 10% II% 12% ---------------------------------------.------ -1 I ~·!'4 -n 1 4Ci'J •i1 I I)~/) •] 1 1 ci• I) •1 lj 1 .~ f 'J •1 i:J 1 11 b •22 I 'JIJ1 -21, 160 -53,!:\bO -401'159 -!l?.il .,, , •J 3S -13 I ObG -1(),",/j'~ -131 '>4l) • 1 71 j ) ;~ -21 1 5')/j -?b 1 3Ll9 • 321 l ')(\ -391013 •1 I 1 c2 -S,nut -1,')32 .QI/192 -12. 11< "> -1 b, 1 5'-f -?012l':i -241499 -3tl 1oUI:i -.S7,141;. -97'1 -~, 190 -1. (l 2 3 -'112bh •1J 1 '/i:J1 -1'>1?49 -141128 -231709 -2910b7 -351363 -il,lll -<4. 'd) 2 -bl')iJl) •I) I Cl 7 '=, •11 I 261 -14 I 5FII -!f\1090 -221iJ17 -2716)1 -3.516':>3 -12i:l -t.;,q.)o -bldr:\5 -61113 -lu 1 'Jt'l2 -131'JSiJ •1 7 1 1 0 t) -211299 -21:-,2.39 -321016 -b1b -y, v9! -:o,o':11 -11 St'J -<.j 1 'J .StJ -121 7bb -101 1 ss -20, 174 -24191)1 -301449 -';; 1 -3, 1ho -";124? -7. l) 7.5 •'J 1 _q 1 •1? 1 (lj 0 -1 ':i1 cS-'l -14,099 -<'~1 o3Ll -21:l,'l49 -'<?.n -.S, 4 ':J'l -4,BStJ •6 1 ',4<~ -lll72.5 -11 1.H•2 •1 <j 1 S9':> -1f\lun -221iJ11 -271513 -31~ ij -.5. 17 j -£..i 1 I~ 9 C -6,)39 -til 1611 -!IJ 1 n22 -U,'J7o -171044 -21,2':>3 -2t>ll39 -270 -21<.!01 -t~, Jil7 -51 1 (/9 -1 1 o54 -91976 -121795 -161159 •20 1 14] -24 1 R2S -2us •2 1 l)iJ 7 • 3, R? .S -')13l!2 -I I 1 s 1 •9 1 3n 1 -!2 1 0S2 -151267 -191079 -2.51567 -!Lib -;.>I .'J (J'J -31 'J 1 7 -lj 1917 -6 1 oSI.! -t-1 777 -1113iJ3 -1414lb -ll:l10biJ -221565 •Y') •2 1 15o -31 ?3;) -41554 -bl201 -61222 -l0 1 tJ69 -1316()4 -1711)41~ -211215 -Sl ..... 1 , lf 1 rj -2,959 -'.!I 210 -':>177) -7 1 oG4 -1 i) 1 02 7 -12,1:130 -161 169 -20,115 -1 ~ •j I]{):'; -?1 I \15 -51 1-\.>-\(J -s~3o1 -11144 -91417 -!2,093 -1512o':l -19,065 1 :l -1,oli2 -2,467 -31'::>1il -41'1i:lcl -6,719 -8,63t> -111390 -141442 -18,060 .) J ·-· J J ] ] J .J • ) JJ J J ) ""'" .. ,, .. ) CHAPTER 9 FINANCIAL PLANNING CONCEPTS r l -I r ;>- 1 I ,.,..., I - CHAPTER 9 FINANCIAL PLANNING CONCEPTS The approach taken towards the financial planning for the intertie faci- lities represents an initial effort to structure the financial package required to implement the Railbelt interconnection. The concepts in- cluded in this chapter are intended to be representative of the condi- tions under which funding would proceed but are in no way ~efinitive re- commendations. Rather, they are anticipated to stimulate discussion amongst the participants and increase the understanding of projected financial obligations. The proportionate allocation of total project costs between participants has been determined in relation to the tangible cost savings derived from the interconnection and represent an equitable division of the total finan- cial burden. The acceptance of these allocations by participants to an Alaska Intertie Agreement (AIA) will require individual utility financial positions to be evaluated. Provision has been made for projected debt ser- vice to be analyzed for each participant, to facilitate the eva1uation of financial impact on individual utility operations. What follows is an ini- tial exploration of possible financial arrangements, which will serve as a starting point for successive evaluations by each potential participant as more definitive financial plans are evolved. 9.1 SOURCES OF FUNDS An initial appraisal of possible sources of funds has been made, to determine a combination which will be both financially advantageous and appropriate to the principal division of cost savings between REA and municipal utilities. 9 - 1 The following sources were examined: • State of Alaska revenue bonds floated by APA • REA loans negotiated by APA and participants • FFB loans negotiated as part of REA loan package • CFC loans negotiated in conjunction with REA loans • Municipal bond issues by Anchorage and Fairbanks A. State of Alaska Revenue Bonds As State of Alaska revenue bonds would be legally secured by project revenues, a complex formula for revenue generation would be required to arrive at an acceptable level of cash flow to repay the bonds. The formulation could be based on wheeling charges for power flow over the intertie but the number of participants and the differences between their operational requirements could prove an insupperable obstacle to the realization of a final agreement. It is thought that the issue of State bonds should be deferred from present consideration, until such time as a combined generation and transmission project is ready for funding. Within the confines of the Railbelt development, this would be appropriate when consideration is given to the financing of the first hydropower development of the Upper Susitna Project, together with its associated transmission facilities. Although APA bonds have been retained in the Transmission Line Financial Analysis Program (TLFAP), for analytical purposes, consideration has been given only to the remaining sources in these initial financial plans for implementation of the intertie. The transmission intertie facilities represent what may be regarded as the first stage development of the ultimate transmission system that will be required for the Watana and Devil Canyon hydropower plants of the Upper Susitna Project. The financial sources discussed in the following sections were con- sidered for composite funding of the Anchorage-Fairbanks Interconnection. 9 - 2 - -\ r r B. Rural Electrification Administration (REA) The prospective participants, with the exc~ption of the Anchorage and Fairbanks municipal systems, are all REA utilities of the Alaska Dis- trict. Therefore, a combination of REA insured and guaranteed loans is assumed for the maximum amount of total project financial requirements allowed by federal regulations. REA loans are normally limited to 70 percent of total project costs; however, as OMB restrictions are ex- pected to affect future REA commitments for project funding, this 70 percent limitation was taken to be the magnitude of a loan package com- prising both REA and FFB loans. The percentage division between the two sources varies, recent past experience and future projections indi- cating a range of possibilities, with the FFB portion considerably larger than that of REA. In the present study, a range of between 20/80 and 40/60 for the combi- nation of REA/FFB loan funds has been assumed for analytical purposes, these percentages being applied to the 70 percent limit for the total loan package, as a proportion of total project costs. REA loans carry a 5 percent interest rate and have a repayment period of 35 years, the first three years of which require interest only. C. Federal Financing Bank (FFB) REA makes guaranteed loans through FFB as a source of supplementary fund- ing for REA utilities. Interest rates for FFB vary but are generally within the range of 9 to 9-1/2 percent. An average of 9-1/4 percent has been used in the financial analysis for this study. A s·imilar 35 year repayment period to that for REA insured loans is normal, with the first three years of interest only also applicable. The combination REA/FFB loan package offers a means of financing 70 per- cent of project costs with a minimum of negotiation, as precedents have 9 - 3 been set for this type of financial arrangement. The goal of negotiation would be to maximize the REA loan portion and secure the best interest rate applicable to the FFB loan. 0. National Rural Utilities Cooperative Finance Corporation (CFC) CFC makes loans to REA utilities to supplement REA funds, although these loans are generally used for distribution type facilities. It is possible that a CFC loan could be obtained for a transmission project such as the Intertie but for purposes of this analysis it has been assumed that CFC funding will not be required. If at the time of negotiation there is a definite advantage to be gained by inclusion of a CFC loan portion with sufficiently attractive terms, the resultant impact on the financial plan can be determined. E. Municipal Bonds Anchorage and Fairbanks municipalities both have the authority to arrange financing for a portion of the project by the issuance of tax-exempt, general obligation bonds. As separate bond issues would possibly be made, the bonding rate pertaining to Anchorage could differ from that of Fair- banks. A recent bond issue by the Anchorage Municipal Bond Bank to cover G & T expansion on the AML & P system realized a bond rate of 6.48 per- cent, with 20 year maturity bonds. A rate of 6.5 percent has been used in this study for the projected Anchorage bonds, with a somewhat more conservative level of 7 percent assumed for the Fairbanks bonding. Both sets of bonds were assumed to be of 20 year maturity. 9 - 4 - - - 9.2 PROPORTIONAL ALLOCATIONS BETWEEN SOURCES In the ultimate financial package for the Transmission Intertie, the final negotiated amounts for debt financing and bonding will be agreed to by APA and AlA participants. To arrive at the final allocation of total project costs between possible sources will require a concerted effort on the part of APA and AlA participants, in the successive ne- gotiations with REA and other federal funding agencies such as FFB, to- gether with the officials responsible for decisions relating to issuance of municipal bonds. To assist with an evaluation of financial positions in relation to pos- sible agreement on questions pertaining to proportional allocations between sources, the Consultants offer the following approach for fur- ther consideration. • A combination of REA and FFB funds would be used to finance a total of 70 percent of project costs. In order to examine the relative improvement of composite financial terms by changes to the percentage allocation between the two sources over a range of combinations, the following allocations were evaluated: Allocation within loan package Allocation of total project costs Combination REA/FFB -% 20/80 40/60 14/56 . 28/42 • The balance of funding, 30 percent of project costs, would be obtained from the following bond issues: Percentage allocation by municipality 9 - 5 General Obligation Bonds Anchorage 18 Fairbanks 12 In preparing a financial plan to follow this approach the following analysis was completed us·ing computer programs TLFAP and COMPARE. The results of this analysis are contained in Appendix F, Sheets F-1 thru F-29. 1. An initial run of TLFAP was made with the following allocations and assumptions for funding terms and conditions: Project Funding Source Interest Rate 14% REA 5% 56% FFB 9.25% Above loans have 35 year repayment period with interest only for first three years, during construction period. 18% 12% AMU FMU Above bond issues have 20 year maturity. 6.5% 7.0% 2. On the assumption that the overall financial terms can be im- proved by changing the proportions of the combination REA/FFB loan package, a second run of TLFAP was made with the following adjustments: Project Funding 28% 42% Source REA FFB Interest Rate 5% 9.25% All other components of project funding remained the same. It is of interest to compare the composite interest rate for project funding to determine the overall improvement in financial terms. The net effect was a decrease from 8.9 to 8.3 percent for the entire project funding, including all financial sources. 3. To translate this improvement into a present value for purposes of comparison of the respective loan packages, two runs were made using program COMPARE to determine the differential present value of future debt service associated with the two REA/FFB combinations. A net reduction of $1,472,000 in total financial costs was realized. These computations are shown on Sheets F-27 thru F-29. 9 - 6 ·~ ' -,., i' - ,....., ' 9.3 ALLOCATED FINANCIAL RESPONSIBILITY FOR PARTICIPANTS A. Basis for Assumption of Financial Obligation The approach followed to determine the allocated responsibility for finan- cial participation and debt service matched the proportions of total project costs to allocated cost savings derived from interconnection. The cost sav- ings to be realized from implementation of the transmission intertie are several, these being derived from: 1. Reserve capacity sharing, resulting in cancellation or post- ponement of in-service dates for certain generating units that would be required with ind~pendent system expansion. This in turn results in a reduction of total capital investment. 2. Improvement in overall economics of system operation, within the limits of potential power transfers over the intertie. 3. Reduction in capital expenditures for transmission expansion that would be required if the intettie were not built. A definite saving of this type would be realized by Matanuska Electric Association (MEA) if their system could be supplied from the Palmer bus. 4. Reduction in the cost of construction power for the Susitna Project, by use of a transmission tap-l·ine. Of the above cost savings, the first and third have been fully quantified in this study, the second would require a detailed computer analysis of the operational costs using a multi-area production costing program. In estimating the cost advantages of power transfer, a simplified analysis was made of the potential economies to be obtained from substitution of se- lected generation blocks on the basis of fuel cost only. This demonstrates adequately the potential for cost saving but is no substitute for a com- prehensive analysis of system operation. This would provide a breakdown 9 - 7 by year of the production cost for each unit on the system, whether inde- pendent or interconnected, and would include both fuel and 0 & M compo- nents. The simulation of economic dispatch for unjts on alternative sys- tems is essential for a definitive apportionment of the operational sav- ings between utility participants. Accordingly, the allocation of cost savings has been determined on the basis of reduction in capital investment by reserve sharing and the elimi- nation of certain expenditures by MEA for transmission expansion. The cost savings to the Susitna Project is not germane to the financial allo- cations between utilities and has been excluded from analysis. The cost savings from reserve sharing have been determined by segregating capital disbursements for generating units affected by interconnection between the respective utilities owning and operating the particular units. Table 9-1 indicates the annual capital disbursements by generat- ing utility for independent and interconnected system expansion, together with the cumulative present worth for each of the investment streams. Cost savings for each participating utility are given by the differential present worth between independent and interconnected investment streams. To these are added the cost savings to MEA for elimination of alternative transmission supply facilities by establishment of the Palmer bus. The cost savings are derived as follows: Participating Present Worth of Future Investment -$1000 Utility Independent Interconnected Cost Savings AML&P 103,647 91,869 11,778 CEA 236,840 229,941 6,899 MEA 2,097* GVEA 43,203 43,203 TOTAL 63,977 * MEA Cost savings obtained from Section 8.3C on P.8-6. 9 - 8 - J - ~ .:! .. -. • I ,- l""' ! - r- ! r The large magnitude of savings accruing to GVEA (68% of total) should be subdivided between GVEA and FMIJS, as the municipal system will also benefit directly by association with GVEA and the continued purchase of power generated by GVEA will ultimately be reflected in the customer rates of the FMIJS service area. To approximate the division of savings, a long- term average ratio between ·load forecasts for the two systems in the Fair- banks area was taken to be representative of relative magnitudes and re- sulted in the following apportionment: GVEA FMUS Percentage Allocation of Cost Savings 56 12 No further breakdown of allocated benefits was deemed appropriate at this stage; however, it may well be that other utilities such as Homer Elec- tric Association (HEA) may decide to assume a minor share of the responsi- bility for debt service of the total investment in support of the project. In which case non-generating utilities can participate on an elective ba~is and future analysis can take into consideration minimum funding participa- tion as a percentage of the total. The only utility which is not an imme- diate direct beneficiary of the intertie is CVEA. Although TLFAP contains a provision for later participation by this utility, it is not anticipated that CVEA will exercise this option prior to the connection of the Glennallen- Valdez system to the Railbelt system, following completion of the first stage development of the Upper Susitna Project. The assumption of financial obligation was taken to be directly related to the proportionate division of allocated cost savings. The basis for financial apportionment of total project costs is as follows: Part i C"i pat i ng Utility AML&P CEA MEA GVEA FMUS TOTAL Cost Savings $ 1000 11,778 6,899 2,097 35,827 7,677 63,977 Percentage Participation 18 11 3 56 12 100 These values of percentage participation were used for financial analysis. 9 - 9 B. Allocation of Total Project Costs An attempt was made to relate the allocation of project costs between par- ticipants to physical facilities in sections of the intertie. Table 9-2 contains a division of total project costs on a percentage basis and a breakdown of percentage allocations between participants, to relate their percentage allocation of total project costs with projected potential ownership of physical facilities within their own service area. The allocation of costs was aided by considering the logical division of the total facility into three sections: Section I II III From Anchorage Palmer Healy To Palmer Healy Ester Distance (Miles) 40 191 92 % Total 12 59 29 The costs included in Table 9-2 pertain to Case ID transmission facilities for the probable load forecast expansion, consisting of a single-circuit 230 kV transmission line with intermediate switching at Palmer and Healy. This also allows the realization of investment participation by MEA in the AlA to the extent indicated in Table 9-2, which corresponds to the allo- cated percentage for MEA. These costs are assumed to be largely asso- ciated with the Palmer substation. Similarly, the costs allocated to FMUS are assumed to be related to the Healy-Ester line section, on a joint basis with GVEA. C. Allocation of Debt Repayment and Sinking Fund Payments The responsibility for loan servicing and payment of sinking fund install- ments is shared by utility participants, in direct proportion to the cost savings derived from the interconnection. A tabulation of the annual payments by each participating utility is given in Appendix F, Sheets F-13 through F-18. It should be noted that the annual payments do include the pro-rata share of payments to the municipal bond sinking funds tabulated on Sheets F-19 and F-20. The totals are given on Sheets F-21 through F-26. 9 -10 - -\ - r r r - 9.4 COSTS FOR RESERVE SHARING AND FIRM POWER TRANSFER An analysis was made of the relative costs of reserve capacity and firm power transfer for the two alternative financial plans. Tables 9-3A and B provide annual costs for reserve capacity and firm power transfer based upon the total debt service per year required for the two alter- native financial plans, including REA/FFB loan packages in two propor- tionate combinations. The division of costs between reserve capacity sharing and firm power transfer was made on the basis of the line capacity which was allocated to each specifc purpose. The total transfer capacity of the 230 kV single-circuit line is 130 MW, this being divided into 100 MW for re- serve capacity and 30 MW for firm power transfer. The annual costs for firm power transfer were converted into energy costs equivalent to wheeling charges for load factors of 40, 55 and 70 percent and energy transfer of 105, 145 and 184 GWh, respectively. The cost streams progressively diminish according to the magnitude of total debt service for the transmission interconnection facilities. The following summary tabulation provides an indication of the average values over the 32 year loan repayment period, following the interest only three year construction period. AVERAGE VALUES FOR RESERVE CAPACITY AND ENERGY TRANSFER Reserve Energy Transfer Cost Combination Capacity Equivalent to Wheeling Charge REA/FFB Cost Energy Cost -Mills/kWh Loan Package ($7kW7Yr) (40% LF) (55% LF) (70% LF) 20/80 43 12 9 7 40/60 41 12 8 7 It may be observed that the average values correspond approximately to the actual values at the year 2003. 9 -11 - 9.5 FINANCIAL PLANS FOR FUTURE STAGED DEVELOPMENT The following is one possible way to plan for funding successive expan- sions and extensions of the projected interconnection of Railbelt utilities. ~ A. Interconnection Extension Between Systems The implementation of the Anchorage-Fairbanks Transmission Intertie will cause Railbelt utilities to examine their system expansions in relation to those of other utilities, to determine mutual benefits of additional trans- mission facilities to firm ties between adjacent systems. The cost of associated facilities could be financed on a comprehensive basis, pos- sibly on more advantageous terms than if attempted by individual utilities or municipalities. The cost of such additions to utility systems could be met from a revolving fund administered by APA, on behalf of the participants. One possibility for application of major funds for system extension would be the interconnection of the CVEA system to the Anchorage end of the intertie. The participation of CVEA in the AlA would then be desirable, with possibly a small allocation for initial intertie facilities, prior to the determination of the timing and cost of the facilities to link the initial interconnection with the CVEA system at Glennallen. This could be implemented on a separate basis, or as part of an integrated plan for transmission of hydropower from the Susitna Project. B. Expansion of a Susitna Transmission System The implementation of the Susitna Hydropower Project would require that a comprehensive financial plan be followed for funding the generation proj- ect and associated transmission facilities. The large increments of power possible from the Susitna development would require the expansion of the initial intertie, to receive energy for transmission to Anchorage and Fairbanks. 9 -12 - - .... As part of the comprehensive financial plan, the funding of transmission line and substation facility expansion through time could be arranged on the basis of total incremental funding, with partition of costs and finan- cial obligations between APA and utility participants, on a similar basis to that used for this initial approach to first stage financing of the transmission system interconnection in the Railbelt . 9.6 REFERENCES 1. International Engineering Company, Inc. Financial Planning Model 2. Moody's Bond Record ~ 'Tax Exempt Bond Fields by Ratings' - .... 'Tax Exempts Vs. Governments and Corporates' January 1979 9 -13 TABLE 9-1 ALTERNATIVE DISBURSEMENTS OF CAPITAL INVESTMENT FOR GENERATION EXPANSION $1000 (1979) Anchorage Municipal Light & Power Chugach Electric Association Golden Valley Electric Association S~stem Ex~ansion S,lstem Extansion System Ex~ansion Year !2W' Inde12endent Interconnected Inde12endent -nterconnected Inde12endent Interconnected 1979 1.0000 1982 0.9151 2,009 1983 0.8885 8,037 10,959 7,670 1984 0.8626 30,139 31,539 10,959 20,264 l.D 1985 0.8375 37,172 31,539 ..... 1986 0.8131 21,127 ~ 1987 0.7894 7,152 2,009 1988 0.7664 8,-037 7,555 1989 0.7441 30,139 5,480 17,630 1990 0.7224 37,172 21,920 5,480 1991 0.7014 21,127 82,200 21,920 1992 0.6810 7,152 101,380 82,200 1993 o. 6611 7,020 58,450 101,380 1994 0.6419 7,020 16,380 22,820 58,450 1995 0.6232 16,380 22,820 TOTAL pw 103.64 7 91,869 236,840 229,941 43,203 NOTE: Present worth obtained using 3% discount rate, equivalent to 7% cost escalation and 10% discount rate. J .J I ... -~I .J J ---1 -/] ~] J ---~ ---J Anchorage INTERTIE COMPONENTS \.0 Transmission Line ...... Substations: U1 Anchorage 3976 (6) Palmer Healy Ester Cant rol & Communications TOTAL AlA PARTICIPANTS AM&LP CEA MEA GVEA FMUS ] -~------1 ----) ---J --] ' --l TABLE 9-2 ALLOCATIOn OF TOTAL PROJECT COSTS BETHEEN PARTICIPMTS TO ALASKAN IrHERTIE AGREEMENT A I A SECTIONAL INTERCONNECTION DIVISIONS Palmer Healy Section I Section I I 40 M 191 M PROJECT COSTS -1979 $1000 (%) 6644 {10) 31,726 {46) 717 (1) 717 (1) 717 (1) 717 (1) 1,450 {2) 400 ( 1) 12,787 (19) 33,560 {49) ALLOCATIONS OF TOTAL PROJECT COSTS (%) ( 8) ( 10) ( 8) (3) ( 3) ( 36) ,.., __ -1 -1 ---1 1 Este.- Section I I I 92 r~ TOTAL FACILITY 15,282 (22) 53,652 (78} 3,976 ( 6) 1,434 (2) 1,434 ( 2) 5' 080 (77,) 5,080 (7) 1,450 {2) 3,300 ( 5) 22,529 {32) 68,876 {100) (18) ( 11) ( 3) {20) (56) (12) ( 12) Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TABLE 9.3A ALLOCATED COSTS FOR RESERVE CAPACITY SHARING AND FIRM POWER TRANSFER WITH Total FINANCIAL PLAN ALT. 1 -20/80% COMBINATION REA/FFB LOAN PACKAGE AND MUNICIPAL BONDS Cost of Reserve Capacity Sharing and Firm Power Transfer Based on Capacity Allocation 100 MW Reserve (Annual Cost of 30 MW Firm Power Transfer Debt Service Reserve Capacity) Annual Cost !Ener~y Char~e -Mi11s7kWhl (1979/$1000) ($1000) !$71<W7'i'r.) ($1000) (40% LFl !55 LFl (70% LF) 8,670 6,669 67 2,001 19 14 11 8,523 6,556 66 1,967 19 14 11 8,376 6,443 64 1,933 19 13 10 8,229 6,330 63 1,899 18 13 10 8,082 6,217 62 1,865 18 13 10 7,934 6,103 61 1,831 18 13 10 7,787 5,990 60 1,797 17 12 10 7,640 5,877 59 1,763 17 12 10 7,493 5,764 58 1 '729 17 12 9 7,346 5,651 57 1,695 16 12 9 7,199 5,538 55 1,661 16 11 9 7,052 5,425 54 1,627 16 11 9 6,905 5,312 53 1 ,593 15 11 9 6,758 5,198 52 1,560 15 11 8 6,611 5,085 51 1,526 15 11 8 6,464 4,972 50 1,492 14 10 8 6,317 4,859 49 1,458 14 10 8 6,170 4,746 47 1,424 14 10 8 6,023 4,633 46 1,390 13 10 8 5,876 4,520 45 1 ,356 13 9 7 3,515 2,704 27 811 8 6 4 3,368 2,591 26 777 7 5 4 3. 221 2,478 25 743 7 5 4 3,074 2,365 24 709 7 5 4 2,927 2,252 23 675 6 5 4 2,780 2,138 21 642 6 4 3 2,633 2,025 20 608 6 4 3 2,486 1,912 19 574 6 4 3 2,339 1, 799 18 540 5 4 3 2,192 1,686 17 506 5 3 3 2,045 1,573 16 472 5 3 3 1,898 1,460 15 438 4 3 2 9 -16 - ~- """" ....., - - - -. ..., """! - ~ - j ..... -I !I'll!! - TABLE 9.3B ALLOCATED COSTS FOR RESERVE CAPACITY SHARING AND FIRM POWER TRANSFER WITH FINANCIAL PLAN ALT. 2 -40/60% COMBINATION REA/FFB LOAN PACKAGE AND ~ MUNICIPAL BONOS -Cost of Reserve Capacity Sharing and Firm Power Transfer Based on Capacity Allocation lOO MW Reserve -Total (Annual Cost of 30 MW Firm Power Transfer Debt Service Reserve Capacity) Annual Cost !Energy Cnarte-Mi11s7KWnl Year ( 1979/$1000) {$!000) ! $7KW7Yr. j ( $1 000) (40% LF) (55 LFl !70% LFl I""" 1984 8,194 6,303 63 1 ,891 18 13 10 1985 8,061 6,201 62 1,860 18 13 10 1986 7,929 6,099 61 1,830 18 13 10 -1987 7,797 3,998 60 1,799 17 12 10 1988 7,665 5,896 59 1,769 17 12 10 1989 7,533 5, 795 58 1,738 17 12 9 1990 7,401 5,693 57 1,708 16 12 9 1991 7,268 5,591 56 1,677 16 12 9 1992 7,136 5,489 55 1,647 16 11 9 1993 7,004 5,388 54 1,616 16 11 9 .... 1994 6,872 5,286 53 1,586 15 11 9 1995 6,740 5,185 52 1,555 15 11 8 1996 6,608 5,083 51 1,525 15 11 8 -1997 6,475 4,981 50 1,494 14 10 8 1998 6,343 4,879 49 1,464 14 10 8 1999 6,211 4,778 48 1,433 14 10 8 2000 6,079 4,676 47 1,403 13 10 8 2001 5,947 4,575 46 1,372 13 9 7 r"" 2002 5,815 4,473 45 1,342 13 9 7 2003 5,682 4,371 44 1,311 13 9 7 r-I, 2004 3,337 2,567 26 770 7 5 4 I r 2005 3,204 2,465 25 739 7 5 4 -2006 3,072 2,363 24 109 7 5 4 2007 2,940 2,262 23 678 7 5 4 2008 2,808 2,160 22 648 6 4 4 -2009 2,676 2,058 21 618 6 4 3 2010 2,544 1,957 20 587 6 4 3 .... 2011 2,411 1,855 19 556 5 4 3 i 2012 2,279 1,753 18 526 5 4 3 2013 2,147 1,652 17 495 5 3 3 2014 2,015 1,550 16 465 4 3 3 2015 1,883 1,448 14 435 4 3 2 .... 9 -17 CHAPTER 10 INSTITUTIONAL CONS lOERA TI ONS r - r - CHAPTER 10 INSTITUTIONAL CONSIDERATIONS The Intertie Advisory Committee has proven itself most useful during this study. It has enabled initial discussions to be held between potential participants in the projected interconnection of Railbelt utilities via the Anchorage-Fairbanks Transmission Intertie. This committee represents a sure, first step towards the formation of a continuing, viable, cohesive entity, through which the intertie can be built and the resulting benefits realized by the continued expansion and operation of the interconnected utility systems in the Railbelt. 10.1 PRESENT INSTITUTIONS AND RAILBELT UTILITIES The predominant pattern of ownership management and operating responsi- bility by public power organizations in Alaska is exemplified by the prospective participants to an Alaskan Intertie Agreement (AlA). In addition to REA and municipal utilities in the Railbelt, it is anticipated that both the Alaska Power Administration and the Alaska Power Authority would be parties to the AlA. The probable composition of institutions and participating utilities is anticipated to be: • Alaska Power Authority • Anchorage Municipal Light and Power • Chugach Electric Association, Inc. • Homer Electric Association, Inc. • Matanuska Electric Association, Inc. • Golderi Valley Electric Association, Inc. • Fairbanks Municipal Utility System • Alaska Power Administration The above group of utilities may be joined by Copper Valley Electric Association, Inc. at a later date, to extend the interconnected facilities to the Glennallen-Valdez system. 10 - 1 A. Statutes and Limitations The enabling legislation for the Alaska Power Authority (APA) is con- tained in HB 442 for the legislature of the State of Alaska. It provides for the establishment of power projects and the authorization to proceed with developments that wi 11 serve 11 to supply power at the 1 owest reason- able cost to the state's municipal electric, rural electric, cooperative electric, and private electric utilities, and regional electric author- ities, and thereby to the consumers of the state, as well as to supply existing or future industrial needs 11 • APA would mainly act on behalf of the municipal and rural electric util- ities as a party to the AlA. Therefore, it is not presently anticipated that the authorized 11 powers to construct, acquire, finance, and incure debt" would be required for the Intertie Project. Rather APA could integrate and coordinate the efforts of the other participants to the AlA, to ensure that an expeditious approach is maintained during the course of the project. APA is in an excellent position to coordinate regional programs with its state-wide involvement. For example, such coordination may assist in the process of securing an abridgement of the two county rule for the transmission intertie. left unresolved, such existing statutes may otherwise constitute a roadblock to the realization of the benefits to be achieved by interconnection of systems of participat-ing utilities over the large geographical area encompassed. B. Jurisdiction and Service Territories The A 1 ask a Power Authority exercises juri sdi cti on over power projects in Alaska as a State entity. It parallels the Alaska Power Administration, which has federal jurisdiction in Alaska for the United States Department of Energy in Washington, D.C. Both State and Federal entities have statewide responsibility in Alaska. 10 - 2 ~ I - - - - - -i - ..... ' The service territories of the municipal and rural electric utilities are shown on the maps of Figures 4-1, 4-2, and 4-3 in Chapter 4. The confines of the Railbelt result in elongated geographical service areas. Such areas are particularly appropriate in relation to the transmission corridor for the intertie and enable the delineation of easements along the route to be made relative to existing transmission and distribution facilities in the area. 10.2 ALASKAN INTERCONNECTED UTILITIES To provide an identity for the utility participants to the AIA, it is suggested that the name Alaskan Interconnected Utilities (AIU) be adopted by the existing Rai"lbelt utilities to be included in the institutional and management plan for the implementation and operation of the intertie. A. Present Arrangements and Future Requirements To a certain extent, the operating utilities in the Anchorage and Fair- banks areas have already evolved mutual interests. These interests now need to be augmented, to satisfy future operat ·j 11g requirements. Prior to interconnection, there would be a need to coordinate revised planning for system expansion, the scheduled construction of facilities, and the separate building programs of each utility. A Planning Sub- committee of the Intertie Advisory Committee, composed of technical staff from AIU, would be desirable in the near future if this program is implemented. This planning subcommittee could be empowered to resolve joint planning problems affecting participating members. Later on, an Operating Subcommittee would be required to determ·i ne oper- ating procedures and coordinate system planning policy, working towards centralized economic dispatch for the interconnected system. The need for communications facilities will also need to be addressed, together with the mode of overall system control and data acquisition for inter- connected facilities. 10 - 3 B. Evolution of Institutional Framework In any approach toward projecting institutional requirements for the establishment of the necessary framework to support the Anchorage- Fairbanks Transmission Intertie, it is essential to preserve a sense of perspective towards the future and allow for the possibility of integrating the presently conceived plans and concepts within a larger and more comprehensive institutional structure. This is par- ticularly appropriate to the task of system interconnection, when successive expansions are necessary to accommodate the incremental additions associated with major generating plants. In the case of the Railbelt, the possible implementation of the major hydrop?wer developments of the Upper Susitna Project, would require that the institutional structure required for the transmission inter- tie be compatible with future institutional needs of the Susitna devel- opments. Thus, whatever institutional changes would be brought about by a program of hydropower development of the Susitna should represent only a transition between organizational requirements keyed to trans- mission system expansion without the facilities of the Susitna develop- ments and with the addition of major hydropower sources, such as Watana and Devil Canyon. The evolutionary approach to effecting this transition is preferable over an abrupt change of institutional structures and it is thought that, with the acceptance of a pattern of multiple participation in the planning, financing, implementation, and operation of the Intertie, a suitable mode of proportionate involvement can also be considered for applicability to other transmission facilities required for the Susitna Project. This division of fiscal and managerial responsibility can also be extended into the operation of the system. In this way a maximum of local utility participation can be achieved, with a financially beneficial allocation of total project costs between funding sources to arrive at a least financial cost package to multiple borrowers having pre-arranged sharing of debt-service obligations. 10 - 4 - """'l ' - - - - - - .... !"""' I ' .... -f - - r ! I I 10.3 1. 2. 3. REFERENCES Battelle Pacific Northwest Laboratories, Alaska Electric Power: An Ana1ysis of Future Requirements and Supply Alternatives for the Railbelt Region, March 1978. University of Alaska, Institute for Social and Economic Research, Electric Power in Alaska 1976-1995, August 1976 • House Bil1 442 in the Legislature of the State of Alaska, Finance Committee, Tenth Legislature-Second Session. 10 - 5 APPENDIX A; NOTES ON FUTURE USE OF ENERGY IN ALASKA - - r ,_ I ..... I ~ I -I ~""' I r APPENDIX A NOTES ON FUTURE USE OF ENERGY IN ALASKA Power requirements studies analyzing historical data and forecasting future trends have been regularly accomplished for the REA-financed electric utilities in Alaska since they began operation. These studies and their forecasts over the years provide an interesting perspective as to the changes in use of electricity and the change in numbers of users, but do not fully account for the forces that produce these changes. It is observed that electrical uses increase as the dreary, manual rou- tines of everyday life are displaced by the equivalent electrically-powered devices. This allows the human effort to be directed elsewhere or elimi- nated. Electric lighting, water pumping (many Alaska homes have their own water systems) and heating, clothes washing, refrigerator, freezer, vacuum cleaner, dishwasher, cooking aids, radio and TV (education and recreation), lawn mower, chain saw, etc., all direct electrical energy toward improving the quality of life and making human effort more pro- ductive. The typical Alaskan family is becoming more productive as a unit through an increasing percentage of the family partners entering the community group of wage earners. Increasing income allows the family to seek out new means of improving the quality of living. There are on the horizon a number of technological triumphs that will undoubtedly find uses in those communities where the families ~an assign some of their resources to enhancing their lives. The home computer with its implications of many more 11 robots 11 to come and the electric car are just two of such items nearing the scene. These considerations certainly support the trends of electrical energy use that are being forecast and could well result in the forecasts being A - 1 exceeded, if the rising standards of Alaskan life are maintained into the future. The following paragraphs are a direct excerpt from a system planning re- port (see Ref. 7 in Section 3) completed in early 1979 for the Matanuska Electric Association, Inc. of Palmer, Alaska. This electric system is the oldest REA-financed system in Alaska and the statistics cited which relate the use of electrical energy to the average family earnings over a period of 35 years of actual history and a forecast of 15 to 25 years are interesting indeed. *INTRODUCTION The accomplishment of long-range planning requires that data be estimated for future conditions and that technical answers for those conditions be evaluated in a prudent manner. Technical answers to a defined set of conditions can be readily developed using state-of-the-art methods. An occasional set of conditions prompts innovation when conventional methods appear limited; but, it is demonstrably clear that the estimate of future conditions is the single most significant factor affecting the ultimate value of a long-range plan. It will be noted in the following System Planning Report a great effort was made to provide accurate and detailed historical data. A better understanding of the nature of electrical consumers and their actual performance amidst the set of observed environmental restraints (political and natural) is bound to be enhanced by such data. It is believed that forecasts of future conditions will also benefit in sufficient measure to make the effort a bargain. * Excerpted from MEA System Planning Report, January 1979 -see Chapter 3, Ref. 7. A - 2 - - - ~ I r The understanding of a long-range plan in the context of the whole growth of a community or region and in terms more useful to the consumer of electricity and his representatives is believed extra difficult today because of environmental concerns, high inflation and other cost aberrations. To provide some perspective that is intended to illuminate the broad impact and position of the MEA electric supply system on its service area a tabular listing of significant MEA statistics is included herewith on the following page, Table A-1. This table contains the 35-year history of MEA and a 20-year forecast based on the data in the Long-Range Plan. The numbers listed may surprise the reader at first inspection but this simple listing of historic factual data and related future estimates serves to demonstrate the power- ful influence of electricity on the quality of life and the productivity of the MEA service area. A - 3 ):> +>- . j MEA STATISTICAL SU~~~RY -PAST, PRESENT JI,N!J FORECAST Ave. No. Ave. )lo. ~1i 1 es Canst. Ave. Cost Average Average Average ~v!::n"cne Portion Served (v1/o LP) of Per Purch. Revenue Revenue 8ill/C0'1St. "F;~;fy of ,l,verage Average Line ~i 1 e Po\'ler Total Sales (w/o LP) (w/o LP) :~c~e I nco:ne Year k',,hf Mo. kWh/~o. Dist. T~ans. Dist. $! k/lh S/k~·:h $/kWh $/:-.10 0 S/"o. Percent (1) (2) (3) (4) ( 5) ( 6) (7) (8) (9) (lO) ( 11) 1942 210 188 90 2.3 0.020 0.0628 0.1074 5.07 1 ~r 2.9 m 4'1 0 .,:J 1954 1401 1393 313 4.5 0.0196 0 0 0450 0.0531 17.82 590 3.02 --sn -m -0 1965 3134 3113 708 4.4 0.0114 0.0348 0.0366 25.40 885 3.9 95T "694 03 1977 9434 9352 1430 6.6 0.0128 0.0359 0.0368 48.50 2243 2.4 T5TS" T318 ~ See Footnotes Level I 16693 16510 2212 ( '82-85') 2100 1785 241 7.5 0.0187 0.0546 0.0559 99.78 3303 3.02 Level II 30510 30060 2705 ('87.,.'92) 2199 2488 269 11.3 0.0348 0.0692 0.0705 175.30 4853 3.60 Level I I I 55744 54956 3041 ('92-'99) S7T4 3494 293 18.3 0.0488 0.0829 0.0837 292.45 7131 4.10 The basi .. c historical data was taken from the REJI, From 7. Each column is explained as follows: .J {1) The year of operation -MEA first energized its system on January 19, 1942. Level I, II, and III refer to the Load Levels of the December 1978 Long Range Plan. The years in parenthesis are estimated dates ~men these levels might be reached. (2) The total average r.umber of consumers with LPs and their average monthly energy (kWh) use. (3) The average number of consumers (w/o LPs) and their average monthly energy (k\~h) use. (4) Miles of line at year end. (5) Average number of consumers served per mile of distribution line-Columns (2) divided by Column (4). (6) Cost of purchased power-at Levels r, rr and III these are estimates developed by RWR from miscellaneous sources. These forecast are believed to be consistent with other elements of the forecast. (7), (8), and (9) For levels I, II and Iri the figures resulted from a generalized forecast of costs using the investments i~cicated by the Long ~ange Plan escalated at 7% per year, the operating costs per consumer escalated@ 7% per year and the rurchased power costs of Col- umn (6). It \'las also assur.~ed that there would ~e 10% losses of energy and that VEA margins would be 10% of Gross Revenue. (10) The estimated average family income is developed from old payroll records, the "Statistical Abstract of the U.S." (Public by Bureau of the Census) 1977, and "The Alaska Economy, Year-End Performance Report 1977" (Published by Alaska Department of Commerce and Econo- mic Development). Future income estimates made by escalating 1977 nunbers at 1.08 per year which is the approximate average growth rate of income for the last 35 years. (11) Column (9) divided by Column (10) multiplied by 100. .J J J J J I ~} .J .J .] .J .I "' ..·~·-J ·- .. 1 APPENDIX B TRANSMISSION LINE COST ANALYSTS PROGRAM (TLCAP) APPENDIX B ~~ TRANSMISSION LINE COST ANALYSIS PROGRAM (TLCAP) r ! r B.l GENERAL DESCRIPTION The Transmission Line Cost Analysis Program (TLCAP) calculates the in- stallation, operation, and maintenance costs of a transmission line using a detailed unit cost model. It also automatically determines the 11 optimum 11 span and conductor size combination. Applications include the following: 1 Voltage Selection -TLCAP examines the relative economics of various voltage levels. • Span and Conductor Optimization -Span and conductor are opti- mized simultaneously to provide a matrix of present worth costs. Sensitivity of present worth costs to assumed discount rate is also automatically included. • Tower Type Selection -TLCAP compares the cost impact of alter- nate tower types. B.2 COMPUTER PROGRAM APPLICATIONS FOR OPTIMUM TRANSMISSION LINE COSTS Choosing the most economical voltage level and other line parameters for any projected transmission line is a complex problem. It requires the simultaneous consideration of a multitude of interrelated factors, each of which will have a decided influence on line performance and the installed and operational costs of both the line and the overall system. The installed cost of a line increases rapidly with the voltage used. For typical single-circuit ac lines, the cost increase is approximately in direct proportion to the increase in voltage. On the other hand, the load carrying capacity of a line increases with the square of the voltage, B - 1 but this is partially offset by the increase in phase spacing and the resultant increase of line impedance. Another factor affecting the load carrying capacity and line cost is the size of the conductor and the number of conductors per phase. Since the installed cost of the conductors may constitute as much as 28% of the total line cost, the selection of the conductor is an important decision in any line design. For EHV lines, conductor size selection is first governed by two basic electrical requirements -the current carrying capacity and the corona performance in terms of corona loss radio interference (R.I.) and tele- vision interference (T.V.I.). As the line voltage increases, the corona performance becomes more and more the governing factor in selecting con- ductor size and bundle configuration. If consideration is given to the electrical aspects alone, there is an optimum solution as to the size and number of conductors for each voltage level and load carrying requirement. However, the size of the conductor affects the loads on the structures supporting it, as well as the sag, tension, span length, and tower height and weight. All such factors influence the total cost and economics of the line. Hence, both the electrical and mechanical aspects must be considered together in order to arrive at a truly optimized overall line cost. Often a solution which is entirely satisfactory from the electrical viewpoint alone will be in conflict with the mechanical requirements. This is particularly true at locations where heavy ice loading is encountered. For example, a small conductor in a bundle of three may meet all the electrical require- ments but may be entirely unsatisfactory mechanically due to excessive sag and overstress. This results in higher towers or shorter spans with more towers per unit length of line than would a larger conductor in a bundle of two. A large number of conductor and phase configurations must usually be tried before an optimum solution is found for a specific voltage 1 eve 1 . B -2 -1 - - - r -I I ,...., I i r The voltage level for any given line should be chosen on the basis of its effect on the system to which it will be connected. This may re- quire medium-or long-range estimation of load flow. For example, it may be more advantageous to build a single 750-kV line instead of two 400-kV lines. Each solution has its own impact on the system with respect to reliability, stability, switching over-voltages, transfer of power, and possibly the cost of future expansion. In other words, the line should be custom designed to meet present and future needs of the system within which it is to operate. It should also provide for the lowest overall cost in terms of investment and operation. Without proper attention to future needs, the 11 lowest initial cost solution 11 for a line between two given points may not necessarily be the most desirable or satisfactory one. In addition to the variables mentioned above, there are numerous other line parameters that must be considered to properly evaluate and compare the various solutions. A few of the more important ones are: • • • • Conductor material, size, and stranding . Tower types, such as rigid or guyed, single or double-circuit, ac or de, metal or wood. Foundation costs . Wind and ice load criteria, and their effect on tower cost through transverse, vertical, broken-wire, and/or construction 1 oads. • Number and strength of insulators. • Insulator swing and air gap. • Applicable material and labor costs . • Investment charges, demand, and annual energy loss charges. To accurately assess all the complexities and interrelationships, and to integrate them into a totally coordinated design that will produce a line of required performance at minimum cost, a carefully engineered computer program was developed by IECO. Program methodology of TLCAP is shown on Figure C-1. Briefly, program elements include: B - 3 FIGURE B-1 TRANSMISSION LINE COST ANALYSIS PROGRAM (TLCAP) METHODOLOGY I Tower Design Studies \ It Tower Weight Estimation · Algorithm -- Electrical & Mechanical Right-of-Way Costj Performance Specification \ It \ If \ I/ Unit Material & -Transmission Line Cost / System Economic Labor Costs -Analysis Program -Parameters I II I I\ Transportation CostsJ Inflation Rates! \ It \ l \ J Input Detailed Optimum Span & Data Design & Conductor Cost Summaries Capital Cost Summaries Summaries ~ I \ B - 4 . - -' :' ~ I :l • • • Conductor Selection - A large variety of conductor sizes and strandings are on file for automatic use by the program. De- pending upon line voltage and load, the program determines the minimum power and energy losses for each conductor studied . Insulation Selection -The program calculates the incremental cost differences caused by changes in the insulator length, which together with other studies of system performance indi- cates the best insulation for each voltage level. To ensure maximum transmission capacity, the minimum possible phase spacing is used with each type of tower, considering clearance to tower steel and insulator swing. Tower Selection and Span Optimization -The installed cost of towers represents a large portion of the total line cost. There- fore, this item is given special and careful consideration in the calculations. The installed cost of a tower is usually a function of the weight of the steel used. A considerable dif- ference in weight between different tower configurations can be experienced, even in cases where the loads are identical. If to this variable, the variations in loads due to conductor size, bundling, and climatic criteria are added, it becomes evident that correct tower weights can only be determined by an actual tower design in which all the variables are properly considered. Therefore, the optimization program is complemented with a tower design program. Appropriate foundation· and insulation costs are added to each tower solution to obtain the total installed cost per tower location. This information is then used by the opti- mization program to determine the optimum span length (the span that results in the lowest tower cost per unit length of line) for each conductor configuration being considered. In processing these criteria, including a present worth evaluation of annual energy loss and other time-related charges, the optimization pro- B - 5 gram arrives at a long-range minimum cost solution for each voltage level investigated. However, as previously mentioned, the final evaluation of the adequacy of a line should be based upon its pr~sent and future effect on the system as a whole. Therefore, the lowest cost solution for a select number of conductor configurations, with their specific electrical characteristics, should be tried in a few additional system study runs to obtain a proper basis for a final decision. B.3 TLCAP SAMPLE OUTPUTS Sample outputs of the TLCAP computer program are shown on the following pages. The output cases are listed below: • Anchorage -Fairbanks, 230 kV (Case IA). • Anchorage Fairbanks, 230 kV (Case IB). • Anchorage -Fairbanks, 345 kV (Case IC). • Anchorage -Devil Canyon, 345 kV (Case II-1). • Devil Canyon -Ester, 230 kV (Case II-2A). • Watana -Devil Canyon, 230 kV (Case II-3A). E - 6 - .-*If ~ ,-. '""'' .. ~··~·1 1 INTEk~AJIO~AL ENG!NE~RING CO. INC SAN FRANCTSCO C~LTFORNIA TRANSMISSION LINE COST ~NALYSIS P~OGRAM VERSION 1: 23 FEB 1Q79, ANCHORAGE-FAIRBAN~S INTERTIE CASE lA 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION SYSTFH ECONOMIC FACTORS STARTING YEAR Of STUDY fNOING YEAR Of STUDY HASE YEAR FOR ESCALATION ~11\XI"'.UM CIRUJIT LoADING AVERAGE CIRCUIT LOADING DEMAND COST FACTOR tt:FJH;y COST ~ACIOR V ~ R C (IS l F A.C 1 (] R CAPITAL COST/DTSCUUNT RAT~: M!NfMIIM MAXIMUM NlJMFlfR OF INTERVALS Oli.M COST FACTOJ.I RIGHT OF wAY COST FACTOR RIGHT OF WAY CLEARING CQST I~TEJ.ItST DURING CONSTRUCTION FNGINEERING HF DATE: 12 APR 79 TIME: 9:29:47 •••••••••••••••••• • • • INPUT DATA * • * •••••••••••••••••• INPUT VALUE:. 1979 1996 1977 136.8 ~1VA 41.0 MVA B.o $/Kw 13,0 MILLS/KWH 0,0 $/KVAR 7,0 PFRCENT 10,0 PERCENT 1 1,5% CAP,COST 715,0 $/ACRE 14'30,0 $/ACRE 0,00 ?: lNST.CST 11,00% INST.CST REFERENCE YEAR FOR INPUT -------------~---------- 1992 191/2 1979 1979 19HLI 1979 1979 Jq79 IJ:j I 00 ; .• A~CHOR~GE-FAJRRA~~s INTFRTIE CASE !A ?30 KV TRANSMISSION LINF COST A~ALYSIS AND CONDUCTOR OPTIMIZATION OATE: 12 APR 7q TIME: q;?q:~7 lONI>UC TOR lJ~TA --·------------------·-----------------·· "JtJ'1'lF~ "'HI f'I-1AS[ (fl'J~UCl •)P SPA(. PH; VC'LlAGt VIILTAG'-VA'<I~JIU'l Ll.'•E F'-"I'Uf.'·l(Y Ff.['i,..EAT••l'< LOSSFS lPli,. LF-1GTH Pu..;ER F.\( [nR w t r. 1 HER 0 AT A (),0 IN 230 i<V 10,00 PCT oO CPS (),00 K_,/MI ~23,00 MTLES \ o,qs ---------------~---------------·------·-- 'H)(JMY·' R A l r, f-·' L l fi ATE I. PI !N/HR K~ ll' f ·~· J" f.: A Plf-.'-LL J)IJilt.l!ON 1 11RS/YR A\[·if.Gf R A PrF ~ ll t<ATF 0,03 !N/HR A 'v F.'< A ::;r f.J t. T '<FAll llliiiAT !0~1 o3t> HRS/YR "1 A X I t~,.JI St;l),,f-.\ L L 1-/Alf': I .ll 7 lN/HA ·~~X I" J'·· S t J\1 "F ! l l. t)III-IATION 1 HRS/YR AvtJHGF ~IJt'"~~LL •u.rE 0,13 !N/HR A~ F R ,, (, ~ Sfli[),,fALl 111.JI< AT I ON 2o~ HRS/YR RtLATIVf AIH -lf'JS I TY 1,000 ,J I ] J ,I ········****•••••• * * * l"'PUT OATA * * ·-·*··········•**• GROUNJ)wiRE DATA 0 NUMBER PER TOWff-1 DIAMETER Wt.lGHT 0.00 IN 0.0000 LBS/FT J J ,) J J MJNIMisM MAXIMUl1 INTERVAL J J SPAN DATA J CJ 1200, FT 1&00. Fl 100,0 FT _J •' cc~ l l ,_, _____ J ,_ .. ,"., __ , ) ---,_) ··-----, ----} l ---=---) l ANCHUPAGE-FAIRHANKS INTERTIF CASt IA 210 KV TRANSMISSION lINt COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 Tl~E: q:?9:47 SAG/TENSION Dt.SJGt-.j FACTORS ------------------------·- ****************** * * * INPUT DATA * * * ****************** ) _, 1 ') t.Vf.RYOAY STRESS TEMPERATURE ICE A~D WIND l~MPENATURE HIGH WIND TFMPtRATURt. EXTREME ICE TEMPERATURE liO • o. 110. 30. DEGREES DEGREES DEGRfES OEGf.IE.ES F F F F ICE AND WTN~ TENSION (PCT UTS) HI~H wiND TENSION (PCT UTS) E.XTRE~E ICE TENSION (PCT UTSJ ICE THICKNESS WITH WJNO MAX DESIGN TfMP fOR GND CLF.ARANCE t.DS TFNSION (PCT UTS) NESC CONS TAN I TOTAL NUHRER OF PHASES PtiASF $PACfNG CONDUCTOR CONFIGURATION FACTOR GROll NO Cl.f Af~MJCf NO. OF INSULATORS PER TOWFR INSULATOR SAFETY FACTOR STRING LENGTH I, VEE, OR CUMAINATION HlUNDAT J(JN TYPf TERRAIN FACTOR LTNE ANGLf FACTOR TOWER GROUNDING TRANSVERSE OVERLOAD FACTOR VERTICAL OVERLOAD FACTOR L(lNGI TUDINAL LOAD MISCELLANEOUS HARDWARE WEIGHT lOWER WEIGHT FACTOR TOWER WEIGHT ESTIMATION ALGORITHM 120. DEGREES F 20. PE:.RCENT 0.31 LBS/FT TOWER DESIGN 3 20.0 FEET 1.0? 28.0 FEET ll8 z.so 6.5 FEET 3 ll 1.06 PER UNIT • 01\bll 0 2.50 1.50 1000. LtiS 0.11 TONS/TOWER 1.02 TOWER TYPE q: 2l0KV TOWER WIND PRESSURf WITH ICE HIGH WIND EXTREME ICE DISTANCE. BETWEEN PHASES: D1 [)2 03 [)4 05 or. T~ : O.OOOlo*TH••? -3,09797•TH••0.3333 -O.OII9li5•EFFVDl • o.l7167•fff!UL t O.OO~lO•TH•EfFTDL t OoOOlbO•TH•tfFVUL t 18.37911 KJPS "} ) 50. PfR(tNT 50. PERCENT 70. PERCENT o.So II'IIOtfS 4.00 LBS/SQ.f'T. 9.0 lBS/SQ,FT. 0.50 INCHES 20.00 FT ?0.00 FT 40.00 FT 0.00 FT o.oo FT 0.00 FT 'l A~CHORAGE-FAIRSANKS !NTE~Tlf CASE !A 2~0 KV T~ANSMISSlON LINE COST A~ALYSIS A~D CONDUCTOR OPTIMIZATlO~ . ~ATE: 12 APR 79 TJH[: 9:29:47 -·*****•••••••**** • • * INPIJT DATA • • ····~·······•***** CO~JDUC TUR SUI-IMARY ************••••• TEp.1P,COF.F, STRANDING UNIT WEIGHT OUT.DlAM, TOTAL AREA MOOUlUS AIYHA•E-6 ID I;IJ'1RER NAME:. S!7ECKCM) ( AL/S T) (LI:lS/FT) (!NCHES) ( s IJ • IN • ) (fF/E:.b PS!) PER OF_G F -----------·--------------------.. _.,. ______ ----------------------------- 21.1 (,kflSilE A K 636,0 26/ 7 O,F\750 0,9900 O,'JHO'I I I, 0 0 1 (). 3 I;]:;J ?:. f GRE T 656,0 30/19 0.9fll:i0 1,0190 0,1>154 I 1 , 50 9,7 I 21:> FlAMINGO bbb,O 24/ 7 O,F\590 1.0000 0,5914 10,55 I 0, 7 t-' 0 27 GA"J'<f T 61:>6,0 261 7 0,91i:l0 1,0140 O,oOi\7 11,U0 1 0. :s 2H STILT l1 ':i. 0 24/ 7 0,9210 1,0360 0,63Lll\ 10,55 I 0, 7 n STARLING 715,0 ?.hi 7 O,'IR50 1.0510 0,6535 11 • 0 0 I 0. 3 )f) Rtfhi!tJG 715.0 30/19 1.1110 1.081() 0,6901 1 j • 50 9,7 ) I CUCKOO 795,0 24/ 7 1.021.10 1,0920 0.70S3 10.">5 1 0. 7 3.? lHI A" F 7'15.0 2bl 7 1,0940 1. l 080 0,7261 1 I , o 0 I 0, 3 B TfRN 795,0 45/ 7 0,8960 1,0630 0.6676 9,40 I 1 • 'l .S4 CO>,;DOR 7'15,0 '::>4 I 7 1. 0 2110 1,0930 0,70'>3 10.8'5 I 0. 9 35 MALLAIW 795,0 30/19 1.2350 1,1'l00 0,7bhR I 1 • 50 9.7 3!:> Rili)I)Y 900,0 £15/ 7 1,0150 1.1310 0.7069 9,40 I I , 5 H C A 'JAR Y QOO,O ':>'H 7 1,1'590 1.1620 0,7'18'> 10,5'5 I 0, 9 31-1 PAfL 9'::>£1.0 4'5/ 7 1,0750 1.1650 O.ROil 9,40 11.':1 3? CARDJraL 954.0 51.1/ 7 1. 22'10 1,19b0 O,f\1.164 10,85 I 0. 9 .J J ] J _) ) _) J ,J .J "J .. J .l J ) J l .J ._._,_j .., ____ --.. ·~· ;,_,__..·-- ·~ <c ) ) l ~--~ 1 -) -~~~. ') J ) -~] l ,--:o.-. ) << l -~} ~-1 ··-J -... ~} ) ANCHORAGE-FAIRBANKS lNTfRTIF CASE IA 230 KV TRANSMISSION LINE COST ANALYSIS AND CO~DUCTOH OPTIMIZATION DATE: 12 APR 7~ TI~t: 9:29:47 *****•••·········· * * .. INPUT Dll TA • "' * •••••••••••••••••• CONDUCTOR SIJI~MAHY ••••••••••••••••• AC RESIST. ULT.TENS, GFOM,MEAN THE:.RM,L!MIT AT 25 DEr.C IND,REt<CT, CAP.~EACl. I[) 'J!J'-jf'\t:.H NAME STRfNGTfi(LAS) RADIUS(FT) PRICE<$/LRl (AMPf_HfS) (OHMS/MILE) (OHMS/1-ItLEl (MQHM-MILI':.S) --------------------·---------.. --______ .... ___ ,. --------- ______ .... ..,. ___ ----------------------- ;>q (;fdlSflt AK 2">000 .o 0,0335 0,62811977 790, 0,1ll'S2 0,4113 2,o3Ll7 O::J ?S F GHl T 31<;00.0 0,0.551 0,609/1977 870. 0,1447 0,4060 2,o136 I ?b FLI\MTNGO 23700,0 0. 0 535 0,640/19/7 810. 0.1399 0,4118 2.6291.1 f-' I-' :>f I~ANI~E l 211200,0 0,03'~3 0,609/1977 1\20. 0,1373 0,4042 2,6347 ?i\ S l J L T 2L,'i00,0 0,0347 0,6?.7/1917 f\40. 0.1320 0,40hb 2,61.l00 ;>q SlAi-<Ll"1G ?!l!OO,O 0. 0 Y)5 0,60fl/1977 850. 0,12'-14 O,LIOSQ 2,bl.l5'3 ~0 RE!lr<ING "$1"600,0 0,0372 0,612/1977 1\60. 0,1213El 0,399.? 2,'lhbl 51 ("lj[l\(}0 27!00,0 0,03t>o 0,636/1977 900. 0,12!4 0,3992 2.5502 ~2 DRAKE 31?00,0 0,0375 0,62211977 910. 0,1172 0.349? 2,5450 B HRN 2?'100,0 0,03'::12 0,677/1977 1'90. 0,111-\ll 0,4060 2.S7b6 34 ((l"J()()f.l 21-\'}00,0 0,0368 0.6~S/1977 90\J, 0,117? 0,1.100? 2,55')5 ~s MAL LAP[) ~l'lll 00. 0 0. 0 592 0,599/1977 910. 0. 1162 0,3928 2,518h 36 RUODY 2 'J /~ 0 0. 0 0,0374 O,b7ol1977 935, 0. 1-0 82 0,39?8 2,50ll0 ~7 CANARY 32300,0 0,0592 0. 63311977 950, 0 • 1 0.4 0 0,3928 2. 5027 V\ RAIL 26900,0 0,03R5 0,67111977 970. 0,0998 0, H49 2,5027 )9 CARO!NAL 34?00,0 0,01104 0,632/1977 990, 0,0987 0,3902 2,4816 ) td I 1-' N j J J A~CHOWAGE·FAIRriAN~S !NIE~liF CASt lA 2.;0 KV lPANSMlSS!ON LINt COSl A..,ALYSIS AND COI\o()UCTOR OPT!MJlAT!ON DATE: 12 APR 79 TI~E: 9:29:47 • ,. INPUT OATt. • • .. ****•••*******•••• UNIT M~IERIALS COSTS INPUT VALl!f REFERENCE YEAR FOR INPUT PRICE OF Tflr;tR MATERIAL P~ICE OF CO~CRETE PRICE OF GROUND "IRE INSTALLED COST OF GROIJtWING SYSTEM T 0 1'1 F R S FT lH' TrJwf R ASSE~IRI Y FOUNDATION SUliP FOIJNDAT!ON ASSP1HLY FOUNDATION lXCAVAT!ON PRICf. OF MISCELLANEOUS HARD,..ARE !JNIT LAfiOR COSTS RFFFRENCE YEA~ LABOR COST S T R I '< G G R 0 ll N fl w I R f STRING LAHOR MARKUP tiNI I TRANSPORTAl ION COSTS --~·----~-~-------------- TOwER FOUNDATION CONCRETl FOUNDATION STEEL CONDUCTOR GROU~D '~IRE INSULATOR HARO.,ARF J I J J J 0,9":>7 $/LB 0,00 $/CU,YO. 0,000 $/LH 0. 00 $/TOWER 1751. $ 0,4')5 $/LB 0. $ 4140,00 $/TON 0,00 $/CU.YO. 290,00 $/TOWE.R 24,00 $/MANHOUR 0,0 :'</MILt 4,2 PER UNIT 100,0 $/TON 100,0 $/Yf) 100,0 $/TON too.o snoN 100.0 $/TON 100.0 $/TON OR $1M••3 100,0 $/TON ,,) J ,) ) 1979 1977 1977 1977 1979 1979 19/9 1979 1979 1977 J J ) J ~ ') '~'~-'"} .~~ J CWdJUCTlJR -·-·-~~~~--·- Nrl. KCH SPAN(FI) -------- t:;:; I 3'1 951.1. 1300. I-' tJ-.1 y:; 79"i. 1300. 3':.> 795. 1 II 0 0, 3"7 '100, i300, 3q 'I ':J II , JIJ 0 () • 37 900, 1400, 3'~ 7<J5, 1'l00, 3? 79S, 1300, 30 71 5. I 30 0, .3() 71'), 1<J00, ~" 7<JS, uoo. 3? Fl":.. II.! 0 I). 3'1 9511. 1500, 3i\ 9C:,/J. 1 300. 3<J 951J. 1c'OO, 3 i 900. 150 0. 3tJ 79'), 1 1.10 0. 3') 795, 1600, 30 7 I S. 1':>00. 3':1 79':;, 1200, 31 QOO, 1200, 29 71S, 1300. 21.1 636. 1200, 3c' 79'), 1500, 3h 900. 1300. "-~) ~---1 ) -) A~CHU~AGE•FAIRBANKS INTERTIE CASE IA 230 KV TRANSMISSION LINE COST ANALVSIS AND COND0CTOR OPTTMIZAfiON DATE: 12 APR 79 TIME: 9:29:47 ****************•********************* * * * * AUTOMATIC CONDUCTOR SELECTION ALL QUANTITIES PER MILE * * * * ************************************** CAPITAL COST/DISCOUNT RATE OF 7,00 PERCENT ------------------------------------------- INSTALLED COST -----------------------·--·------------------------··------------MATERIALS TRANSPORTATION INSTALLATION ENG/I DC SUBTOTAL -------------.----------' ---·---·------------------- 61'\JIH, 3831.1, 84796, 9328, 166104, 64664. ~5721. 82616. 9088, 160089. 6537S. 3684. 1:12031. 90?3. 160113. 67?99, 377?... 84608, 9307, 161.1986, 695'12. 3A2P., 84613. 9314, 167367. 68697, 37bb, 8449l.l, 9291.1, 1662':11. 66Fl79, 361\9, 8.?176. 9039. 16171:\4, 6'.:15')8, 368'.:1. 831\93. 922il, 162364, h3510. 3615, 82301, Q05.S. IS847fl. 61.1.:'04. 3'176, H1729, 8990, 1SI\49A, 651\07. 3659, 84359. 9279. 163104, 66784', 3669, 83683. 9205, 163342, 711\43. 31:170, 8':l337. 93P.7, 170437. 701~6. 3831 • 86787, 95l.l7, 170300. 703R6, 4035, 87082. 9579, 171080, 70983, .5807, 85172. 9369, 169331. 67235. 3653. 8429fl, 921.5, 161.1459. 69124. 3735. 82979, 9128. l649o6, 65702. 3580, 81896. 9009, 160187, 66809, 3916, 8'5020. 9352, 165176, 69631. 3977. 86926, 9':;62. 170096. 64091. 3'593, 83683. 920':>, 160573. '58648. 3.345. 82481. 9073, 153'548, bf\81'13. 3 701. 84257. 9268. 166109. fl9499, 3780. 86&82. 9'.:13':>. 169496, ~ ~ ) l --~ l ---··-~ ) ) PRESENT wOt<TH ~-----------~------------------------· LINE LOSSES OK.H COST LINE COS1 ·---------------·-----------SUBTOTAL SlJRTOTAL TOTAL ---------------- 32600, 3?84, 201981-l, 39120. 3151 • 20?35<~. 3'1120. ~1b1, 20?39<J, 3l.l543. 32':l7, ?0?7A'l, 321>00, 3322. ?0328il, 34S43, 3?94, 204f)P,k, 391?0. .5206, ?Otd 09 • 39523. 31'15. 20Svi'.2, 1.14166, 31 12. 20575b, 44166, 3122 • 2057H7, 39'199. 3209, 205913. 39523. 3.?26. 20 h~O 9 1 , 32600, 3.$97. ?0~>433. 32997, 33 71. 20bhhl. 3?600, 331\5, 207Cib':l, 3451.13, 3369, ?0724?. 39599, 3248, 20730o, 39120. 3282. 207)67, 41.1166, 316 7. 207520. 39120. 3254. 20l'l49, 34':>43. 3 361 • 207<J99, 44801.1, 3!':>0. 20R527, 52193, 297S. 208715. 39':>23. 3?95, 20FI926. 36096. 3351. 201'\942, 0:1 I f-J *"' J t:.·.--,,, J ,r A~CHURAGE•FAIRBANKS INTERTIF CASE I& 230 Kv TRANSMISSION LINE COST A~ALYSlS AND CD~DUCTOR OPTJHIZAT!O~ lN.'ilALLFD COST llh't AK!l(Jw~ llll At-irfiS 4,3 FOU'·.IIA T IONS /J. 3 RIGHT !IF wAY 13. IOC It r-.Glt~ft:.Rl'JG ---------------TOTtLS LOSS t'.Nlll.YSIS --------------------· RESISTANCE LOSSES CORO~<A LOSSES ---------·~---·-·---TOTALS J J J ,._,._ -· ~ J DATE: 12 APR 79 Tl~E: 0129:47 ***********-************'***** * .,. COST OUTPUT PER MILt PRESENT VALUt WATE 7,00 PERCENT * ····~··············~····••**** CONDuCTOR MIHBtR : 39 9511, KCMIL 1300, FT SPAN 87,7 FT TOwFR MATfRIAL TRANSPORTATION INSTALLATION COSTC$) TONNAGE COSH$) COSTC$) ----------------·------------------------ FT 14086, 9. 73 973, 182'>7. FT 0. 0,00 o. o. UNITS 1313. 1 , 1 II 2114, 1429, 0 ,Ill 47, lJIH T S 381:170, 20,31 2031, 260 19. UNITS 3327. '538, 22280. ACRES 91?0, 111?41, 9328. ------------------- bl:\147, 31,65 3834, 84796, PRESENT VALUE ( $) DEMAND LOSSES ENERGY LOSSES TOTAL LOSSt::.S -------------__ ..., ___ ... _4_.,. __ ----------~-245BR. 7992, 32'>80, 0. 19. 1 9. --------------------- 24':>8R. 8011. 32600. _,I J ,) ,.I .: .. _ .... J } J .... J TOTAL COST($) ------- 3331 b. 0 • 1'5'>7. 11177, bhl/21. ?614'5, i'73b], 9321J, .................. 166101.1, ) J J -l ) INTER~ATIO~AL fNGINfERING CO, INC SAN FRA~CISCO CALIFORNIA TRANSMISSION LlNf COST ANALYSIS PROGRAM ·VERSION 1: 23 FEB 1979, ANCHORAGE•FAIReANKS INTERTIE CASE IB 230 KV TRANSMISSION LINt COST ANALYSI! AND CONDUCTOR OPT!MlZATtON PATE: 12 APR 79 TIME: 9:37:07 SYSTFM ECONOMIC FACTORS ****************** • * * • INPUT DATA * • ****************** INPUT VALUE -------·---------------................•....... STARTING YtAR 0~ STUDY ENOING YFAR Of STUDY BASE YEAR FOR FSCALATION MAX!Ml!M CIRCl:JIT LOAI)ING AVEf~i~GE Clf<Clll T LOADING DEMAND COST fACTOR ENFRGY COST FACTOR VAR CUST FACTOR CAPITAL COST/DISCOUNT RATE: MINJMIJM MAll I r~UM NIJMAFH OF INTERVALS OS.M COST FACTOR RIGHT OF ~AY C~ST FACTOR RIGHT OF wAY CLEARING COST INTtREST PURING CONSTRUCTION ENG!Nt.ERING FH 1979 199b 1'177 l3b,8 MVA tJ9,2 MVA 73,0 $/KW 1.5,0 fHLLS/KWH 0,0 $/KVAR 7,0 PE:.RCENT 10,0 PERCENT 1 l,S % CAP,COST 715,0 $/ACRE Hl30,0 $/ACRE. 0,00 X INST,CST 11,00: lNST,CST 1111Jil 1'J'1i! tq?q 1q7q 19111.1 PHI~ 1'Hll.l 111711 tq?q 1 91'1 .J ANCHORAGE•FA!R~AN~S INTFRTI~ CASE IS 230 KV TRANSMISSION LINE COST ANALYSIS AhD CONDUCTO~ OPTIMIZATION L D N I) U C I f) f.? D A T A 'ill"iJf q Pt11 f'HASf Cll-'JDlJC TOR SPA C H<G VOLT.\Gf V!JLThG( V~lll~l!ON L l ~ t. F q' lJ U E r; C y FAJ~nEAlHtR LOSSES LINE u··IGTH POiitR F!CTOR >'tATtH:Y f\ATA MAX1MJ'1 RAP~FAIL RAH 'H ¥ 1 MU!-" RAINFALL OUI<A T I (J'-J AvERAGF fH!NrALL r<A rt AVE>1/•Gl RAINFALL iJIJfiU !O'J MAXiMJ:1 s~.o.-.r ALL f!AH MAX!MrJM BNO~FALL DUI~ HI ON AVfi:RAGJ" 5NOO'Ji=" AU_ RAa AVt:fL~Gt SNO~FA6L fJURAT!ON iH.LATI>'E AIR DCNS I H 0,0 IN 230 KV 10,00 PCT 60 CPS 0,00 KW/M! '23.00 MILES 0,95 1. 18 lN/HR 1 HRS/YR (),03 lN/HR tJ311 HRS/YR !. 8 7 !N/HR 1 HRS/YR 0.-13 IN/HR 264 HRS/YR 1.ooo J DATE: I? APR 79 TIME: 9:17107 •••••••••••••••••• • * * INPUT DATA GROIJND~IRE DATA * * 0 NlJMbE!< PER TOWER DIAr~ETfR WEI GMT 0,00 !N 0,0000 LBS/FT J J J MINIMUM MAXIMUM INTERVAL f.J J SF'lAN DATA J ,,I 1200, FT 1600, FT 100,0 FT J ·•~.;) -l bJ I I-' -.,J ) J A~CHORAGE•FAIHBANKS INTERTIE CASE lR 230 KV TRANSMISSION LINE COST ANALYSIS AND CO~DUCTOR OPTI~lZATlCN DATE: 12 APR 7q TIME: q:37:07 SAG/T~NSION DESIGN FACTORS tVfRYDAY STRESS TEMPERATURE !CF AND WIND TEMPERATURE HIGH ~IND TEHPtRATURE ~XlRf~E:. ICE TfMP~RATURE MAX OESIGN TEMP FOR GND CLEAHANCE:. EDS lENSION (PCT UTS) NfSC CONSTANT TOTAL NUMRER OF PHASE:.S PHASt SPI>ClNG CONOliCTOR CONfiGURATION FACTOR GRilUNf) CU:ARANCF NO, OF INSIJLATORS Pf.R TOWER INS\ILATOI< SAFETY FACTOR Slf.'ING U:NGTH I ' VU', OR CO~'BINATlON HliiWH T [ON TYPf Tf>;RAIN FACTOR L I '·IF ANGLE FACTOR JO..,FR bROUNOlNG TRANSVERSE OVFRLOAD fACTOR VERTICAL 0 V HH. 0 ~ D F A C T OR LONGITUDINAL LOAD 11! SCH LANE OUS HARD~ ARE. WEIGHT TO.,FH .;EIGHT FACTOR TQ,.;tR wEIGHT FSTIMATION ALGORITHM * * • II>IPllT DATA • • • •••••••••••••••••• LID. DEGREES F o. DEGRFES F 40. OFGRFES F 30. fJEGREES F 120. DEGREES F 20. PERCENT 0.31 L8S/FT TOwER DESIGN --.. ·-------- 3 20.0 FEFT l.O.? 28.0 FEfT 48 c?,50 6.5 FEET 3 4 I. 06 PE.R IJNI T .0864 0 2.~0 1. 50 1000. Lf!S 0. 11 TONSITO.,E.R 1.02 TOw~R TYPE 9: 230KV TOWER ICE AND WIND TENS[ON (PCT UTS) HIGH WIND TENSION (PCT UTS) EXTRE~E ICE TENSION (PCT UTS) IC~ THICKNESS wiT~ wiND WIND PRESSURE WITH ICE HIGH wiND EXTREME ICE. DISTANCE BETwEEN PHASES! 01 D.? lH D4 D5 Db TW : O.OOO!h•TH••2 • 3.09797•TH••0.3J33 • 0,089U3•EFFVOL • o.775h7•EFFTOl t 0.005IO•TH•FFfTDL t O.OUlbO•TH•E~~VDL + 18.H91i' ~II-'S 1 1 ')0. PERCENT 50. PERCENT 7fJ. PERCENT o.SO ltJCHES 4 • 0 0 l. ~ S I S r~ • F T • 9.0 t.BS/SQ.fl'. o.~o INCHES .?o.oo fT 20.00 FT «O.OO FT o.oo F T o.oo FT o.oo F"T A~CHOkAGE•FAI~HANKS INTERTIE CASE IB 230 KV lRA~S~lSSJON li~E COST A~ALVSJS AN~ CONDUCTOR OPTIMIZATION DATE: 12 APR 79 Tl~t: 9:37:07 ••**.****•******** • • INPUT D A T.l> * • ·············***** CONDUCTOR SUM~1ARY *****•*******•*** TEMP, CUFF. STRANDING UNIT WEIGHT OlJT,DIAH, TOTAL AREA MODULtJS ALPHht•b TD NU'HJE R N M"E SllUKCMl (Al/ST) (L5S/FT) (INCHES) (SO. IN,) (EF/E6 PS Il PER DEG F --··-------·--... --.. -------_ .... _____ _____ .... .,. --------·--·----------------· 2'-l GkOSREAK 6-,6.0 26/ 7 0,8750 0,9900 o.ssoq I 1 • 0 o I 0. 3 2':> F GR f T tdb. 0 30/19 0,9880 1.0190 0,6134 I 1 , 3 0 9,7 2n FL~MINGrl 666,0 2/J/ 7 0,8590 1.0000 0,591/J 10,5'> 10. 7 1:0 27 r, Ar~f,F r 6b6,0 26/ 7 0,91fl0 I , 0 Ill 0 0,6087 I 1 , 0 0 10. 3 I J--1 ?"I s r 1 LT 715,0 2lll 7 0,9210 1,0360 0,63ll8 10,':15 I 0, 7 00 ?.9 SlAPLl"'G 715,0 ?61 7 0,9850 !.OSlO 0,6':>35 I I , 0 0 I o • ~ 3 r) Rt_l),; I t<G 715.0 30/19 1,1110 1,0510 0,6901 11 • 3 0 '1,7 3 t (IJ(KQ() 795,0 24/ 7 1.0?40 1,0420 0,7053 10,':>5 1 0. 7 3~ DkfiKE 795,0 26/ 7 1,0940 1,1080 0,7261 11 • 0 0 1 0. 3 33 f!::.f.HJ 795,0 ll5/ 7 0,8960 1,0630 0,6676 9,40 11 • 5 3 I CUNl'Ok 79'1,0 5ll/ 7 1 .02 1~0 I , 09 3 0 0,7053 10,115 10,9 3':> HALLARD 795.0 30/19 1.2350 1.1400 0,7bt-B 11 • 3 0 9,7 3;, PU['OY 900,0 45/ 7 1,0150 1,1310 0,70o9 9,40 11.5 3/ C AoJAtl Y 900,0 'jlJ/ 7 1. !590 1,1620 0,7955 IO,ii'J I o, 9 3>\ RAIL 9':,4,0 45/ 7 1,0750 1,1650 0,8011 9,40 I 1 , 5 39 CARDINAL <l54,0 54/ 7 1,2290 1,1960 0.8464 10,85 I 0, 9 J ) _j j J _l ········) l ANCHORAGE•FAIRBA~~S INTE~TIE CASE IB 230 KV TRANSMISSION LINE COST A~ALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIME: 9:37:07 ****************** * * .. It-.~PUT DATA * * * ···············•** CONDUCTOR SUMI"ARY ...................... AC ~ESTST. lJL T, TENS. (;EuM,MEAN THfRM.LIMIT A T 25 DEG c IND,RI:.ACT. OP,REACT. Ill NUfHlER NAMf STRI::NGTH(LBS) RADIUSCFT) PRICEC$/LB) (AMPERES) (OHMS/MIL U (OHMS/MTLI:.) (MOHM•!-1!U 5) ----··-----·----------------------------------------------------·-··------------------- 24 GROSH[AK 25000,0 0,0335 0. 6i?A/ I 'l77 790, 0,11<52 0,4118 2.6347 ?S EG!-!ET 31500.0 0,0351 0,60'1/l'l77 870. 0.1447 0,4060 2.6136 26 FL.\MINr.O 2.3700,0 o. o.n5 0,640/1977 8 I 0. 0.1399 0,4118 2,6294 b:;j ?7 GHJNf. T 2o2ll0,0 0,0343 O,b09/1Q77 820. 0.1373 0,4092 2,6347 I ?i\ S T ! L 1 ?5"i00,0 0,0347 0,627/1977 840, 0,1.320 0,4066 2,61100 1--' \.0 ?.9 Sl A~LING 28100.0 0,0.355 0,608/1977 8')0, 0,1294 0,4050 2,6453 "30 fH D1d NG 34600.0 0.0372 0,612/1977 860, 0.1.?88 0,3492 2,5661 .31 CUCKOO 27100.0 0,0366 0,636/1'177 900 • 0,1214 0.3992 2,S502 32 Dh'AKE 31200,0 0.0375 0,622/1977 91 0. 0,1172 0.399? 2.54">0 33 TF ~'' 22900,0 0,0.$52 D,b7ll!'l77 890, 0,11f\R 0,40hll 2,576b .34 CU~iiJO~ 21l'i00,0 0,0368 0,63">/1977 900, 0.1172 0,4002 2.5'555 v; MAll AIW 31:<400.0 0,0.$'12 0,599/1977 91 0. 0,1162 0,3928 2.5186 .36 RUDDY 25400,0 0,0374 0.676/1977 935 • 0.1011.? 0.3'128 2,501::10 .37 CM;A"Y 32300.0 0,039.::' 0,633/1977 950. 0.1040 0,39.?.8 2.':J027 3'3 RAIL ?6900,0 0.0385 0,671/1977 970, 0,0998 0.3949 2,5027 3'1 CARDINAL 34200.0 0. 0 ,. 0 4 O,o32/1977 990, 0,0987 0,3902 2,<!816 c ") tp I N 0 } ANChURAGE•FAIR~ANKS INTERTif CASE IR 250 K~ TRANSMISSION LINt COST A~ALYSIS AND CO~OUCTOR OPTIMIZATION DATE: 12 APR 79 TINt: 9:37:07 * * * INPUT DATA * * lr ········~********* WJlT MATERIAlS COSTS INPUT VALUE REFERENCE YEAR rOR INPUT ------------------------------- PRICE OF TU~lR MATERIAL PRICE OF CONCRETE PRICE OF GHOUND Wl~E INSTALLED COST Of GROUNDING SYSTEM TOWER SETUP 1 o~~n~ ASSE t1RL Y r OUNDA r !Or-. St. TUP FOUNDATION ASStMBl Y FOUNDATION EXCAVATION PRICE OF MISCEllANEOUS HARD~ARE UNIT LAROR COSTS REFERFNCF YEAR LABOR COST STRI'J!; GIWUND w!f<F STRING LABOR MARKUP UNIT TRANSPORTATION COSTS TOWER FOUND AT !ON CONCRE H FOliNf"lATIUN STEEL CONDUCTOR GROUND WIRE. INSULATOR HARDWARE J ""'. ·P'•·~'"···· ~) 0,957 $/LR 0,00 $/CU,YD, 0,000 $/U3 0,00 $/TOWER 1 7 ') 1 • $ o,4SC:. $/LH 0. $ 4140,00 $/TON 0,00 $/CU,YD, 290,00 '!;/TOWER 24 • 00 $/~~MHWUR o.o $/"'ll f. 4,2 Pt.R UNIT 100.0 $/TOt~ 1 0 0. 0 $/YD 100,0 $/1 ON 1oo.o $/TON 100,0 $/TON 1 0 0 '0 $/TON OR $/M••3 100,0 $/TON ) J ~,J J J 19H 1977 1977 1977 1979 197q 1919 1979 1979 1977 ,.J ,} J I Cfli\tllJC TOR ---------~ J l) • KCH SPAN(FTl -------- tJ:j 39 'lt.,lj. 1300, I N 37 900, I 30 0, 1--' 3'i 79'), I 3 0 il, 35 7'15. 1400, ~q 9~1.1. 140 0. 57 900, 140 0. 35 795, 1')00, ~2 79S, 1300. 59 9Sil·, 1~00, 311 7'15. I 3 0 (J. ~I\ 9':>4, 1300. '>2 705, 1400, 30 71 5. 1300. 30 715. 1400, 39 954. 120 0. 37 900. 1500, 34 795, \400, 55 79'1, 1600. 37 900. 1200, 3') 1'1'1. 1200, 30 7 1 c,. 1500, 36 ~oo. uoo. 51\ 90:,4, I 400, 32 795, 1500, 29 715. 1300, ---) ANCHORAGE-FAIRbANKS INTERTIE CASE IB 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIHilATlON DATE: 12 APR 79 TIME: 9:37:07 *************************•············ • • * * AUTOMATIC CONDUCTOR SELECTION ALL QUANTITIES PER MILE * * * • CAPITAL CDST/OISCOUNT RATE OF 7,00 PERCENT INSTALLED COST ---------··----·----··-·-----------------------------------------MATERIALS TRANSPORTATTON INSTALLATLON HJGITDC SlH:lTOTAL ------... ---------------------·------____ .,....,. ..... -·------ 61\ l'l 7, 3834, 81l796, 9328, 166104, 672'19, 377 2. H460f\, 9307, 161l9o6, 6461>4, 3 7 21 • R2616, 901\8, 160089. 6537'), 3684, R2031, 9023. 160113. 69552, 3828, 84673, 931ll, 167367, 68697, 3766, 84494, 9294, 166251. 661\79, 36/:l'l, 82176. 9039~ 161784, 6~5~8. 36R5, R3R93, 9228, 162361.1, 718'13. 3870, 85337, 93137. 170437, 6~1\07, 3659. All359, 9279, 163104, 70136, 3£131, 86787, 9547, 170300, 667811, 3669, 83683, 920~. 163342. 63510, 3615. 1:12301, 9053. 15847R, 1>4201.1, 3.S 7 6. 81729, 11990, 1584911, 70~H6, 4033, 117082. 9'579, 171080, 70'11:\3, 3il07. 1'.5172, 9369, 169351. 6 7 2 35. 31:>53. 8'~298. 9273. l6ll459, 69124, 3735. 82979, 912il, 164966, 69631, 3977. A6926, 9':51>2, 1700'16, 661\ll'l, 3916, 85020, 93':52. 165176, 6':>702, 3580. 81896, 9009, 160187, 69499, 3780, R6682, 9~35. 169496, 7?348, 31'6 I. 87234. 9591:>, 17.3039, 6888.). 3701, 8425?. 9268, 166109, 64091, 3593, 836R3. 9205, 160573. PRES!: NT WORTH -------------R--·--------------------- UN I: LOSSES 01'.~1 COST LINE COST ,.,. __________ ______ ,._ ---------SUllTOTAL SUBTUTAL TOTAL -------- ___ ., ____ 3'5856, 32H4, 205244, 37993, 3?57. 206235, 43028, 3151, 206267, IH028, 31 b I , 206302, 35HS6. 3322. 206545, 37993, 3294, 207538, 43028. 3206, 208017. 43461\, 3195, 209027. 3'>856, B97, 209t:>B9, 4354':5, 3209, 209558, 36293, 3371. 209963. 431.168, 3226. 210036, 4856 I. 3112. 210!51. 411'>61, 3122. 210182. 35HS6, 331\5, 210321. 37993, 3 369. 210693. IH~IJ<i, 3241\, 211251. 4302fl. 3282. 211275. 37993, 336 I. 211450, 43028. 3?')1.1, 2111.157. 41\561, 3167. 21191'.:!. 39701. B~l. 212547. 36293. 3440, 212771. 431l68. 3295, 212871. 492?2. 3150, 212944, 0:1 I N N .. J ANCHORAGE-FAIR~A~KS INTFRTIE CASE JA 230 KV TRA~SMISSION LINt COST ANALYSIS AND CONDUCTOR OPTlMflAliON ' !N~TMUD COST hf.l~ Af<.ll(i,,t, rWANIITY ---------------------- CONDtJCTflR 1~840. GROLJf'D" I ~t 0. I N;llJL A TOi~S 207. H!,fif)"ARf JO.,ft-iS 4.3 F OlHdJA T I O'JS 4.3 RIGttl OF ;~A y 1 3. IDC/fNGPH-t:RING ...... _____________ TOIALS LflSS ANALYSIS -----------------~·· ~ESISTA~<CE LDSSfS COROI'.A Lt1SSES --------·--·------~· TOTALS .,, ·-~··.:) \;~" . .J ' J DATE: 12 APR H Tl~E:..: 9:37:07 " • * * COST OUTPUT PER MILE PRESENT VALUE RATE 7.00 PERCENT CONDUCTOR NUMHfR = 39 • " * * " 9~4. KCMIL 1300. FT SPAN 87.7 FT TOwER --------~-----------------~--~-----~--·-------~---- MAT!:.RIAL TRANSPORTATION INSTALlATION COST($) TONNAGF COST($) COST($) ------·--------.-------------------------- FT 14086. 9. 73 973. 18257. F r v. o.oo 0. o. UNITS 1313. \ • I 4 244. 1429. 0.47 4 7. UNITS 38870. 20.31 2031. 26019. UNITS 3327. ~38. 22?1'10. ACRES 9120. 18241. 9328 • ---------·----·-----·----- 68147. 31.6~ 3831.1. 81.1796. PRF.SfNT VALUE' ( $) -~---·~-----------------------------------------------------------l..lfMAND LDSSE:.S ENfRGY LOSSE:.S TOTAL LOSSES -------------------------- ________ .,.. ___ 21.1588. 1121.19. 35837. o. 19. 19. --------------------- 2458f!. 11268. 35856. .J J ,~ ~·"' J ,~J .I J J '~ .. 1 TOTAL COST($) ------- 33316. 0. 1557. 14 77. 66921. 26145. 27361. 9328. _ ____ ..... _ 166104. J cJ .J. -) c:o N w "------l ,.~----) ·--~---, --) ) ~-l ---) ') -~':·-,--. ) '1 INTERNATIONAL ENGINEE~ING CO, INC SAN FRANCISCO CALIFORNIA J TRANSMISSION LTNf COST ANALYSIS PROGRAM VE~SION ?: 02 AUG ]979, ANCHOPAGE-FAIRBANKS INTERTIE CASE I-C 34~ KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 15 AUG 79 TIME: 14:06:42 * * INPUT DATA • • • ) ) SYSTEM ECONOMIC FACTORS . INPUT VALUE REFERENCE YEAR FOR INPUT RASE YfAR FOR PW ANALYSIS [rJI) I% YF.:AR OF STUDY ~ASt YEAR FOR FSCALATION MAXiMU~ CIRCUIT lUftD!NG AvfRAGE CIRCUIT LUAOlNG OFAA~D COST FAClOR ENERGY COST FACTOR Vf.R COST FACTIJR CAPITAL COST/UISCO!JNT RATE.$: O~M COST FACTOR RIGHT QF WAY COST FACTOR RIGHT OF wAY CU:ARING COST !NTEPtSI DURING CO~ISTRUCTION f.r<Gli<EERPrG F!:F --~-------------· 1979 t9n 1'/77 I 68, 11 MVA 58,9 t~VA 73,0 $/KW 1 3. 0 MlLLS/KWfi o.o $/'<VAR 7.0 PERCENT 1 0. 0 PERCENT 1.5 'l: CAP,COST 715.0 $/ACRE 1430,0 1/ACRF. 0,00 r. PJST ,CST 11.00 7. INST.CST 1984 19R4 tn9 19-79 198!1 198!1 1 9f\4 1 ) ~) J A~CHURAGE-FA[ASANKS !NTfRTIE CASE I•C 3U5 Kv TPANS~IS~IO~ LI~E COST ANALYSIS A~D CONDUCTOR OPTIMIZATION DATE: 15 AUG 79 TI~E: !U:Oo:U2 * * INPUT DATA * • * •J******•********* CONDUCTOR DAU G P 0 lHJ 0 w I R E DATA ·--------~------------------~------------ 'IIU~f3E ~ PE'R PfiASE (()NIJII[ T I)P SPA(. I 'Jr. VOL I A •.;F VOLTAG~ VAPJATIU~ lIN[: "Pl OUHlCY F A I R w E A I f~ t 1J l Ll SSE S LINE LFNGTH PuwU~ FACTOR WE.ATHE~ DATA 2 I 6. o 311') 10.0!1 hO t. 70 323. 0 0 o.os I ~I KV 1-'CT (.PS ~WI~ I MILES ----------------------------------------- MAX I ~1Uf' R A I fJF All RATE I , 18 IN/HR MAXI MU"1 RAINFALL I)IJ R h T I £J N I HRS/YR AvERAGF RA[IJFALL R h 1 E 0,03 PI/HR A'/f''HCE fH HJ!''AL L ll 1 JIJ ~. r 1 u ~ b3b HRS/YR MAXP1UM SNO~>:F AlL RATF t. f\ 7 lN/HR f'AXIMUfA S 1<0"F ALL DlJkATTUN 1 ~!RS/YR AVE=/hGr SIJO,..F ALL RAT f ',; 0. 1 3 IN/HR' AVFRhGE SI<OwF ALL l)llf-IATIU"J ~hll HRS/YR RELA,TIVE AIR IJ[NSITY 1.000 ,} ''&'·<·< .l J \,--L J ) ,I NUM~ER PER TOwER I)JAMETER WEIGHT J ,J l J 0 MINIMUM . _ 0,00 IN _____ MAXIMUM 0,0000 LRS/FT INTERVAL .. 1 J l SPAN DATA ;' ] J 1000, F:r 1600, fT 100,0 FT l ,) N tn ) A~CHGRAGE•FAIPBANKS !NTERT!E CASE I•C 14~ KV TRANS~!SSTO~ LINE COST ANALYSIS A~U CONDUCTOR OPTIMIZATION DATE: IS AUG 79 Tl~~: 1U:O~:I.I2 SAG/TENStUN ~ESIGN FACTORS EVERYDAY STRESS TEMPERATURE ICE A~O wiND Tf~PERATURE Hl~H W!~D TE~PERATUR~ EXTREME ICE TE~PERATURE ~Ax UFSTGN t~up FOR GND CLEARANCE fnS ~~~S!~N (~ll UTSJ tJf SC CU~JSTA~JT TO l AL NIJMRER OF PHAS~S PHASE. SPACING cnNDUCTOR CONFIGURATION FACTOR GRO•INf'J CLE ARA"JCI: Nn. OF TNSULAT~PS PER TOWER l ~ S I ! L a Hlfl S A F E 1 Y F A C T 0 R S 1 R 1'1 I! U: !J[_, Hi I, VEE, I.IR [!l~~r\ TNA T TUN FOUtl,lJAT TU'J TYPE Tfi-'Ri\PJ FACTilR LJt-if' ANGLF: FACTOR 1 O"FR GPIJUND 1 ~Ji~ TRAriSVERSF: Ovf RLOA[) F-ACTOR VF'kT !(AI rlVf~L!JA{) FACTOR L W J G I T I) I) J ~J A l l U A I) M I SC[t.l At•F.UIIS HAf![lWAkE WE I GHT Tn>jER wEIGHT FACTOR TUWfP WEIGHT ESTIMATION ALGORITHM • • * UJPU T OAT~ 1.10. DEGREES F O. DEGREES F llO. DE\,REtS F 30. Df:(;Rf ES F 120. DE.GRE~S F ?0, PERCENT 0. 3 t Ul S/ F T TOWER DESIGN 3 27.0 F~ET 1.00 32.0 FEET 7? 2.50 9.5 FEET 3 1. 06 PER UNIT .01161.1 0 2.50 1. 50 1000. U:JS 0, II TONS/TOWER 1. 02 Tn~fk TYPE 10: 3ll5KV TOWER " " " ICE AND WIND TENSION (PCT UTS) ~IGH WINO TENSION CPCT UTS) EXTREME ICE TfNSION (PCT UTS} ICE THICKNESS WITH WINO WIND P~ESSURE WITH ICt HIGH WINO EXTREME ICE DISTANCE BETWEEN PHASES: 01 02 03 oa· -· DS 06 1~ : O.OU043•T~I~•? • 0.992ltl•TH••O,b000 • O.I0371•EFFVOL - 0.273~5•tFf TUL + O,OOS03•TH•EFFTOL + O.OOIHI•TH•EFFVOL + 20.77701 ~.TPS ,···. l 50. PERCENT SO. PERCENT 70, PERCENT O.SO INCHES ll,OO UJS/SQ,FT, 9.0 LBS/SO.FT. O,SO ItJC~ES 27.00 FT 27.00 FT 5£1.00 FT 0.00 FT 0. 00 FT 0,00 FT TO NlJ"HHR Nf\ME _.,,. ______ ?'"I S T Af.i L PI r, tc 30 ~~ [[1 I, I ~H; 3 1 CUCI\OU N ~2 I) I! A K E 0"1 3.3 H RN 3 lj CONI) OR 35 lql.l~IW ,., 11Ur11JY 37 CA~IARY 311 R~JL Vl C~RD!rH>.L lJO ORTOLAN t.'ICHOi'AGE-FAIRElANKS lNTERTlt CASE I-C 345 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTJM!ZATION DATE : I 5 AUG 7 9 T P~ E : Ill: 0 6: ll 2 __ -~ _ . -----~~---- STRANDING SIZHKCM) (AL/ST) ---------------- 715.0 26/ 7 715.0 30/19 7'15.0 2/JI 7 7'1'),0 26/ 7 7'15,0 lj')/ 7 79'),0 Sll/ 7 795,0 30/19 '1()0.0 liS/ 7 900,0 5/J/ 7 9')11. (\ 1.15/ 7 9'lll.O SiJ/ 7 103:'J,O tJSI 7 ****************** * I~~ P IJT DATA * * * ****************** CONDUCTOR SUMMARY UNIT WEIGHT OUT.DIAM. (LflS/FT) (INCHES) ---------------- 0.9A50 1.0510 1 • 1 II 0 I. 0131 0 1,02/JO I. 09?.0 1,0940 1 • 1 01\0 0.1:1960 1,0630 1.02/JO 1.0930 1,2350 1.1400 1.0ISO I • 1 3 1 0 1 • 15 q 0 I. l 620 1.0750 1.1650 1.2?'10 1.1'160 I. 16'l0 I • 21 3 0 -------------- TOTAL AREA (SQ. IN.) -------- 0.6'535 0,6901 0.7053 0.7261 o.6676 0.7053 0,7668 0.7069 0. 7985 0: p, 011 0.8ll6ll 0.8678 MODULUS (EF/c6 PS J) ----------- I I. 0 0 11. 30 IO.'lS I 1 • 0 0 9,1.10 10.85 11 • 3 0 9./JO 10.115 9./JO 10.85 9.llO ------- J TEHP.COEF. ALPHA*E•6 PER DEG F ---------- 10.3 9.7 10.7 10.3 1 1 • s 10.9 9.7 1 I. 5 10.9 I 1 • 5 10.9 1 I • 5 ID N!J'11"JER NAME ... -------· tx:l ?9 STIIRLJN(; 30 Rff)W!NG ~ 1 CliCKOU N 3? ['\RAKE ""-1 ~ s TF.I<'J 3 j [IJ'JI)[)fl ~5 M h l. l A R I) 36 R II f) I) Y 37 CANARY lfl RAIL 39 CAPLJ!I~Al QO ORTULAN ANCHORAGE-FAIRbANKS l~TEHTIE CASE l•C lQS KV TRANS~ISS!UN LINE COST A~ALYSIS ANU CnNOUCTOR OPTIMIZATION DATE: 15 AUG 79 TI~E: 1ll:06:a2 I.ILT.TENS, GEOM,MEAN S Hl E ~H; T H ( l R S ) PADIUS(FT) ---------------------..... 21<100,0 0,0355 3llhOO.O 0.0572 27100,0 0.0366 31?00,0 0,0375 22900,0 0.0352 ?1<0::.,00,0 0.056tl 31'lll () 0. () 0,03'12 ? 'J II II 0 , () 0,037£1 32300,0 0,0592 ?nouo.o O.OSAS 31J 2 0 0. 0 o.oaoa 213900,0 O,O£J01 **********•*•••*•• INPUT LJATA • • CONDUCTOR SUMMARY ••••••••••••••••• THFRM,LIMIT PPICEC$/Lfl) (AMPERES) ...... ---..... -.... ---------- 0.605/1977 RSO. 0,612/1977 RoO. 0.636/1977 900. 0.622/1977 '-110. 0,677/1977 R'-10, 0,63":l/1977 900. 0,59'-1/1977 910. 0,676/1977 ens. O.b33/l'177 950. 0.671/1977 970. 0.632/1977 990. 0,670/1977 1020. AC RESIST. /IT 25 OEG c (OHMS/MILE) ----------- 0.129lJ 0. 1281\ 0.1.?1ll 0,1172 0.111:11'1 0.1172 0,1162 0,10tl2 0,10£10 .o. 09'-18 0,0987 o.o921l IND.REACT. CAP,REACT. (OHMS/MILE) (MOHM-MILES) --------.--------------- o.aoso 2,6tJ':)3 0,3992 2,5661 0,3992 2,5502 0,3992 2,5£150 O,QOhO 2.5766 o.aooc: 2.5555 0.3<J28 2. 5 Plo 0,3928 2.5080 0,3'-1?8 2.5027 o. )'-/lJ'-1 2. 5027 0.3'-102 2.lJ/l16 0,3902 2,£11';158 J N co l ,f 345 ANC~DDAGE-FAIR~ANKS !NTEQT!E CASE I•C KV TPANS~!SSION LINE COST ANALYSIS AND CONDUCTOR OPTIMTZATION ________ DATE: IS AUG H TI~-<E.: 14:06:42 **************•**• • PIPUT DATA * • *******•********•• UNIT ~ATFRJALS COSTS INPUT VALUE REFERENCE YEAR FOR INPUT PRJC[ OF TOWER ~ATERIAL PqiCE. UF CONCRETE PPICE OF G~0UND WIRE P~STALLElJ cnsT OF GROLI•'JDING SYSTEM T I),, F:f~ sF Tll p TfJ,..fR IISSUWL Y FOUND AT I U11 SE. T UP FOUNI)ATIU~ ASSEMBLY F n u 'Jll" r r u ~~ F x r AvA T I o ~~ PRICE 11 F ~~ 1 S U. L l AN E 0 US H A R lJ W APE liN IT LABOR COSTS R ff-F I< EN C F:: Y fAR LA A 0 R C 0 S T STfdtJG Gf<OlJN() l-ITRE STRT~H; l.ARIIP MARKUP IJNU I'<ANSPURTATiflN COSTS --~-----------------~---- I Tf)l~FR FOUNOAl!UN CONCRETE ~-0 LJ',J IJ h T I 0 N STEEL CflNDIJC TOR (,RO!JrJ[) W!Pf-_ I NSIJL h TOF< liAF<lJ..;ARE ¥' __ I .J ,I _j 0,957 $/LB 0.00 $/CU.YD. 0,000 $/LI:l 0. 00 $/TOWER 1751. $ 0,455 $/LB 0. $ Q!4o.oo snoN 0.00 "t/CU,YD, 290,00 $/TOWER 24,00 $/MANHOUP 0.0 'b/MILE u • ?. P E. R 1.J r~ I T 131.0 $/TON 131.0 $/YD 131.0 $/TON 131.0 $/TON 131,0 $/TOr~ 1~1.0 $/TON OR $/~*•3 131,0 $/TON f " -~·· "''-_I J .J !979 1977 !977 1977 !979 1979 1979 1 •'H9 1979 1977 J J ..; J l ··"' I "--·-"} --~ 1 ..., _____ l 7 --~ CO'Ji)UC fllR ---------Nl), KCM :)PAN(FTJ -----... ·- 0:1 35 7'-15. 1 300. N .55 ?CIS. 10 no, 1..0 30 7l c;. I 3 0 0. 3S 7 ... '5. 12 n li. 30 71'), 1 ~ r) li • 37 9()(), 1 3 0 0. 32 79'), I 30 0, 3"i 7'1'5. 1'>00, H 951J, 1 :.s 0 0. 37 q (I 0, 1 2 r) (). 30 q ') IJ • I 20 0, 30 715. 1 2 0 (). )l.l 7'-IS, I S 0 0. 52 795 ·-I 20 0, 29 7 1 ., • I 3 0 0. 3 0 • 7'-IC:,, 1200, 30 7 15. 1':>00. 32 79S, 1 0 0 0. 37 0 I)(), Ill o o,, ?.o 7 1 5. 1 2(1 (1. _39 9';,11, ] l.j 0 0. 29 7 I r; • l (j 0 0. 34 795. 140 (). 35 79'), I I 0 v • 3 7 900. 1 I 0 !: • ~~--") .. } ,..,, "] -;5:. ___ -· '1 ~---~] ~-----1 .-~1 J ANCHOPAGE•FAI~BANKS INTERTIE CASt 1-C 345 KV TRANSMISSIUN LINE CDST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: IS AUG 79 TJMt: 14:06:42 AUTOMATIC CONDUCTOR SELECTION * * ALL QUANTITIES PER MILE * * * CAP I T A l C 0 S T I I) T S C 0 l I fJT P A T E U F 7 , 0 0 PEP CENT PRESENT WORTH ($) ) '1 l ------·-----------·-----------------·-------·-------~--------------------·---------------------------------- INSTALLEO CUST LINE LOSSES 08.M COST LINE COST --------------------·--------------~--------------~------·--·--------------------------------MATE:.R!ALS TRANSP, INSTALL. ENGJNEtR, IDC SUBTOTAL SU~TOTAL SUHTOTAL TOTAL ---------------· ----------------· --------... ______ -------- lOf:\?53. h4f12, 1 1 0 01:\h. 24730. 0. 249551. 46122. 3372, 299006, 1 I (In 3q, IJil/'\_5 • I OIH\1!9. 207'-11. 0. 250162, 4612.?. 3381, 29'-1665, 10'>62?.. 6257, 10936A, 24337. 0. 2455f\ll, 52150. 331 q. :.SO!OS3, lfl77'-l'-l, h':!57, 112490, 24953. 0. 2')1799, lib In. 3403, 3'JJ32'J, 1073;?4, 1',2S3, I Ol:ll OS. 2 1J385. 0. 206066, 52150. 3325. 3015Jl, 11 2fll 2. h':>79, 11264A, 255211, 0. 257563, 01403, 3481. 302iJiJ7, 1042'>5. 1139':,, 111472. 2ll'Hl3. 0. 25210b,' ll7191, 3ll07. 302703. ---~---·-·----· -· I 1 3 o 2 I • 65">(), 1081>17. 2':>101. 0. 253289, 46122. 3023, 302R3ll, 114706, 671_0. I I ~ 01:1 ll, 2')795, o. 260295. 39129, 3517. 30 C '< 'J I , 11151-'S. h608. 111JIJ90, ?.5574, 0. 2SP.061. 41403. 348 7. 30 2'1') 1 • 113?.t:'P., f-736, I \ ll q I ':i. 2'>1-\37. 0. 260716. 39129. 3523. 30)367. 10':>?32. h3~6. 1117R7. 24')69, 0. 2U79,?1.l, 521':>0. 3350, 30 30,)1!, 10'-IS711, h337. 1\1951. i?501JI, 0. 25.?6R7, li7S90, 31J15. 303.,91. I 0 HI 21 • 6 1J3<1, I I _511 t> R • 25083. 0. ?53111. ll7191. 3420. 3037?2. 10S9SS. 6199, 1101:171'1. 211534. o. 2117':>65. ''l3308, 3345. 30U2!9, to-/'-1'11, 6369, 1137711, 25095. o. 253229, 07590. 3022, 3042U?, 110237. 63\o, 10711')7, 21.l685. 0. 20QOQ5, 52150, 3366. 301.161 I, 1 , 1 (\ 0 "i. 6432. 1 I 0 1:> 1'1 fl. 2'>182. 0. 2')4106, 47191. 3ll34, 304731. Jl')h79. f. t)3 1 • 11202U, 25777. 0. ?bOll<'. 4lli03. 3515. 305029. jf)I.J.<\b~. t-,(:'lJb, ll281fl. ?.Oo39, 0. 2llR632, 533013. 3360, 30530(), 1176?0, 1--765. !1 2'113. 2o050, 0. 2h?913. 39129. 355 3. 30'.>590, 1 o 1111 eo • h2 33. II 0 1 u 3. 211730. o. ?49545, 533011. 337 2. 306?2S. 112220. f-386, 11132.?. 252'-IC. 0. ?.':>5220. 07':i90. 3049, 30t>2'.>Q, I 08P. 31. 6 11 fl. 116?63. 25099, 0. ?.':>7312. U6122, 3477. 306911. 1 1 I SCi 0. 6 ., 30. II 77 f'JS. ?.5970. 0. ?6206':>. 41003, 3'->lll. 307ooq, o::l w 0 .. :! !NSTALLFD COST L~ R E f, .1<. f1 0 w r' ·------------- c o 'J n u c r oR GRO\JN[),.,JHE I NSIIL A I nHS Hl\h>fi•-IARF 10;-.U<S FrllJ';l)A l TCJ"JS A~C4UQAGE-FAIR9ANKS INTEHTlE CASE I-C 31.l5 KV TPA~SMlSSJON LINE CCST ANALYSIS AND CONDUCTOR OPT!~IZATIQN DATE: 15 AIJG 79 TI~E.: I£J:06:U2 ----·--------·--- QUhrq lTV ------·- 316/:'n, Fl n. Fl . - 3 I 0. UNITS II. 3 UNITS lJ. 3 UNITS * * COST OUTPUT PEP ~Il E PPESt'J T VhLUt RATE 7,00 PERCENT ***'***•**••••••*•••·········· CONr:lUCTCJH N\JMPER : 35 795, KCMIL 1300, FT SPAN 89.3 FT TOWER -· MATERIAL TRANSPORTATION COSf($) TONNAGE COST($) ----------------------------- 3">171, 19,56 2":>63. 0. o.no u. 2582, l • 7 0 l!BO, !R7U. O,lll 62. tl31:12t.l, -? 33. IJ I -4377.- b('RQ, 1 0 IS, >< 1 (Jfl r OF WAY (107Ff) l 3. ACRES I 21 6 7, ---------------------------------- SUll-TOIALS 11111:197, 55. 15 81.197, !DC tNGPJF[PING PRE SC. IJ I i><ORTH 10R253, 6482. IDC ENGINEE.RING PRfSFNT WORTH ($) INSTALLATION COST($) ------------ 33947, o. ll9735. 1.120511, 1851:>5, ------ 11.11.130 1 • 110086, --------------------·------------------~--------------------------L 0 S S MH L Y S T S RESISTANCE LUSSES COkONA lUSSfS: INSIJLATORS CONDi.JCTOI< 1f!TALS I ·~· DfMAN[) LOSSES -·-----------25LIIl3, l62LI. ------- 27107. j J: J ENERGY LOSSES ---·--·------ll.l/.11.11 • 3\LIS. 11130. ------- 1q01'5. ] .. ~·I J J TOTAL LOSSES I 3<~qzu. 47aH. lll30. Llbl22. J TOTAL COST($) ................. 71681 • o. 3062. IQ3b. !37<136. IJ93lJ9, 3073?. ------- 291.lb9S, 0. 32LII6, ------- TOTAL 327111. 2?LIIl21. o. 2LI730, --~---- TOTAL 2Liq5S I. I 1 l INTERNATIO~AL ENGINEERING CO. l~C SAN FPANCISCO CALIFORNIA TRANSMISSi0N LINE COST ANALYSIS PROGRA~ VtRS!ON 2: 02 AUG !979, ANCHORAGE-DEVIL tANYON CASE IT•I 34'5 KV TRANSMISS!lHI LINE COST ANALYSTS AN[) CONDUCTOR OPTTMTZArti}N; DATE: IS AUG 79 T!Mt: 15:56:14 **•*************** I ~IPllT OA 1A * * * .tl**•••••••******** SYSTfM tCONOMIC FACTORS INPUT VAI_Uf REfERENCf YEAR FOR INPUT RASE.YEAR FOR P~ ANALYSIS. f; <Gl'l t_; Y f A R (W 3 T U C' Y AASf YEAR FUR FSCALATION ~AYJMUM CIRCUit LO~UING AVE:LIAGE CIRCUIT LOAUING n[MA:·m ens r r AC rn~< f~fRGY COST FACTnR VAR COST Fl>.CTliP CAPITAl_ COSTIUTSCOU"<T R~TES: 0><.~1 COST FACTUP Rl(;11T 0~ ,,Ay COST FACTOR Rl(;HT OF ~ftY CLEARING COST INTEQESl UUR!NG CONSTRUCTION f '< l~ I 'l E. F R I ~' G F t r 197'1 1997 1977 631.6 MVA 31J7.4 MVA 73,0 $/KW 13,0 MILLS/KWH 0.0 $/KVAR 7.0 PERCENT 10,0 PERCENT 1.5 '1. OP.COST 715,0 :1>/ACkE l'no.o li/.l.CRF 0.00 % INST.CST 11.00% !NST.CST 1992 1992 1979 1979 19f\4 1984 1984 19f\4 1479 1979 w N ] ~~CHORAG~-D~VTL CA~YON CAS~ IT-I 345 ~y TPA~S~ISSIJN LINE COST A~ALYS!S AND Cr~~UCT0R OPTlMllATION DATE: IS AUG 7q Tlvt: 15:~6:1~ CON1'lUClOR OAiA ' -----------------------·----------------- illiJMBE"'l PER PHASt CONDUCTOR SPACING V'Jl TAGf' VOLT,GE VAR]ATIUN l l 'J E r ><l rw F ~' C y FAH.-.EC>\THf:'< lUSSFS L!Nf L.~'<l.TI-1 Pllrd:.R F AC l nR WE::AlHtR DATA 2 11.'.0 IN 3115 1\V 10.00 f-'[T biJ [PS 1.70 KI'<IMl 155,00 ~ILfS 0.0 5 ~---------------------------------------- MAXP'UM flA fNFALL fJ ,\ T ~-1 • 1 ~ !NIH~: MAX]M~'1 '<ATNFALL. lllli<ATTUI\J l e~RSIYR AVHAGF PA[r-.Ft,Ll. iH TE 0,03 I': I I< Q AVERAGF RfdNFALL Ill if< A 1 i UI\J t>3h HPSIYR MAX ].v<J'·\ S~·JOr;f. ALL .;'AT F. I • R 7 I ~J I HR ~"'t.t..I·~J~ Si;[Jv; FA l L i)LIRATTU"' HRSIYR AVf•iAGF sr,[l,.,F ALL r< A It 0. 13 l'J 11-'R A v F 'I~ (;t: Si,[l,.;FAL L DIIRAT!ti'J Cbr..t f1f'31YP RELATlvt. ATR l)[iJSlTY 1 '0 0 0 J ,I .J .. 1 J J ****************~~ * * l"PIJT [)AlA * * ••***********~**** GROLJNO..,IRE DATA NUMBER PER TC'IWFR OIAMETER 0 o.oo l"' 0,0000 LBSIFT wEIGHT J .J J I .. ~1 ,I MINIMUM i"'AXIMUM INTERVAL c,.J ... J SPAN DATA I .J 1000, FT lb\JO, FT 100,0 FT .... J '-'l ...•... ) w w i] A~CHOQAGE-DEVIL CA~YO~ CASE If•! ~aS KV IRANSMJSSIO~ LlNE COST A~ALYSIS ANO CONDUCTOR OPTIMIZATION DATE: 15 AUG 7Q TI~~: !S:5o:la SAG/T~NSlU~ nESIGN FACTORS EVERYnAY STRESS Tf~PERATURE !Ct AtJl) ••!NO TP'PEHATURF H l G H w I'm T F >I P F: Ph T UP f IXIREM~ j[f: TfMpf:PATUPE MAX DFSIG~ T~~P ~OH GNU CLEARA~CE ~ D S T F ~. S I il1'l l PC T ll T S ) ~~ESC CO~'STANT TOTAL NUMA~R OF PHASES f'Hr.SE SPAC!~(, CONDUCTOR C~NFlGU~ATlON FACTOR GROIJN[) CLEA>=1HI(i'" ~Hl, UF lNSULt..TUPS PFR TOV.tR IN!)LJLATOh' SAFF:lY Ft.CTOR STRI:~r, LFNl;TH I, VEF, OR CUMtlTNt.TION FllUNllATIOtJ TYF'E lFtd-'ATr·.! FhCTUP LTNF A~~Lf FACTOR l [)~;fR G'H:iJ"'i) [ ~H; TRANSVt~Sf OVFRLUAD FACTOR VFh'T [CAL nvfh'L llhD FACTOii L 0 N G I T tJ n JIH, L l U t.. D M I S C U L At< E u 0 S t1 !\ R 0 wARE WE. I G H T TOYiffi r<F.lr..HT FACIOK ----·-·---~---------------------- * * * JNP[.tj DATA ao, f'lEGREt:S F 0. f'lEGf?U::S F (10, DE.GREtS F 30, flf_GREES F 1?0. Dt:GRf'tS F 20, PERCF_.'I T 0. 31 l t3S/F T TOWER DESIGN 3 27,0 FHT 1,02 3?.0 FEF.T 72 2,50 Q,'i FEET 3 (j \,06 PeR UNIT ,Of\t>IJ 0 2.'::>0 !,50 lOOU, U.lS 0,11 TO~iS/TOwER 1 • 0 2 T0wfR TYPE 10: 3aSKV TOWER ICE AND WTNf'l TENSION (PCT UTSJ HI~H WINO TfNSlON (PCT UTS) EXTREME ICE TENSION !PCT UTSJ ICE THICKNESS wiTH WIND ~INf'l PRESSURt wiTH ICE HIGH WINO EXTREME ICE DISTANCE BETWEEN PHASES: Dl 02 03 [)II 05 Db T•·l = rJ,Oi!O<I~•TH'*2-O,Qq2lll*TH**O.o0()0-0,1037l•F.FFVDL- 0.275~~•LF~TOL + 0.0U'i03•TH*EFFTDL t 0.00\B\*TH*EFFVDL + 2 () , 7 i 7 (I 1 K J 1-' S 1 l ···~·· J '50, PERCENT 50, PERCENT 70, PERCENT 0,50 I NOlES £1,00 U1S/SQ,FT. Q,Q LRS/SQ,FT. 0,50 INCHES 27,00 FT 27,00 fT 5£1.00 FT 0,00 FT 0,00 FT 0,00 FT 10 NU'ifH.R ~IAr-<E --------- 29 SHRL!NG 30 PEn,.,[NG OJ 31 CliCK PO 32 Di< h K E w B HR~ .j::> 34 C (;'-;;,np ~5 ,'-1 A l. l ~ R 1_1 36 Pllf"\[}Y 37 C A 'J A P Y 38 '<ATL 39 CARLi T r1 A L IJO OPTOL•\N J .-... J .l I 4NC~ORAGE-OEVTL CANYON CASE II-1 345 KV !PANS~ISSTON LINE COST ANALYSIS A~O CO~DUCTOR OPTIMIZATION DATE: IS AUG 79 TIME: 15:56:14 STRANDING SIZECKCM) (AL/ST) -------·- _.,. _____ 71"i,O 26/ 7 715,0 30/19 795,0 t!.4/ 7 79'i,O 26/ 7 7'15.0 £15/ l 74"i,O 54/ 7 7'-15, 0 .30/\9 9(10,0 45/ 7 CJOO,O 51J/ 7 QS4.0 45/ 7 9~/J. 0 C,IU 7 10.S3.0 45/ 7 J .J J .J ****•••**•~******* " . J"!Pllf D!'.Th * * * ***~************** CONDUCTOR SUMMARY *•***•*•*****•*** UNIT wEIGHT OUl.DlAM, (LRS/FT) (INCHES) ---------------- 0,9P.50 1.0510 1,1110 1.0810 \,0240 1,0920 1,0<140 I.IOP.O 0,8960 1.0630 1,0240 1,09~0 1,t!.350 I • 1.£10 0 1,0150 1.1310 1,1590 \,\620 1.0750 I • l b"iO l,t!.290 1,1960 1,1650 1,2130 .I .. J .. 1 .J TOTAL AREA MODULUS (SQ,JN,) ·(EF/Eb PSI) ------------------- 0,65~5 11 • 0 0 0,6901 I 1 • 3 0 0,7053 10,55 0.7261 11.00 0,6676 9,40 0,7053 10,85 0.7668 11,30 0,7069 9,40 0,79R5 10,85 O,ROI1 ·-' -··-···-·--9,40 O,R464 10,85 0,8678 9,£10 ------------ ,. I I,__ .J TEMP,COEF. ALPHA•£-& PER DEG F ---------- 10.3 9,7 1 0. 7 I 0. 3 I I • 5 I 0 • 9 9,7 1 1 • 5 10.9 11 • 5 10,9 I I • 5 J J .J TD Nll'1RER NAME. --------- OJ C'"' STAPL!'IG 30 RI:P~>!'lG 31 CUCI\IlU w 32 ORhi\E c:..n 33 1 E ~Hi 3/l CIJ'.![;IlR Vi ~·A l.L h ><I) 3o RUI)UY '>7 CfiNA'n 3'3 PAlL 39 C A Rtl I NAL LJO OkTi•LAN M!CHORAGE•UE::viL CANYON CASt:: IT-1 3US KV TRA~SMlSSION LINE COST ANALYSIS AND CONrUCTOR OPTIMIZATION DATE: I~ AUG 7~ TIMC:: 1~:56:14 ·~··~··········~*· * l'J P liT D A T A • **••*•••**~**•*••• CONDUCTOR SUMMARY •*********••••••• AC RESIST. ~LToTENSo GEOMoMEAN THFRM,LP.'IT AT 25 OEG C-lNDoREACT. CAPoREACT, S1RE.~:GTH(LBS) RADIIJS(FT) PRICE($/LR) (AMPERES) (OHMS/MILE) (OHMS/MILE) (MOHM•MlLES) 2HTLi0o(\ 0,03">'; OohOP./1977 R~Oo 0 0 l29£l 0~4050 2o6453 34600.0 0,0372 O,bl2/1077 860, D.l2tlfl 0 0 3992 2o5661 27100o0 0.0366 0,63(>/1977 ooo. 0,1?14 o. 3992 2,5502 31?00.0 0. 0 375 0 0 t>22/ 1977 <II 0 o Oo1172 0,3902 2,5450 220(>0,0 Oo0352 O,b77/1077 R90o O,lltlfl 0,4060 2,5766 .?fl<;uo.o 0oO.S6tl 0,635/1977 900o 0,1172 0,4002 2o5555 3KIJ \) () 0 () Oo0392 OoS0'.//\077 010o 0, 1 I 62 0,3928 2o~1116 2'JUl!Oo0 O,OS74 Ooo7t>/1977 93'5o Oo101:\2 Oo39213 2o50AO 32.)00.0 (),0392 O.oB/1977 9:-.o. 0.1040 0,3921:1 2 0 5027 2o 0 00,0 o.o3R5 Ooo7l/io77 970. Oo0998 0,3949 2,'j027 ----------- )I.J? I)() • 0 Oo0404 Ooo32/l977 990, o.o9tJ7 Oo3902 2,4816 2dQJlO,O OoOiH)l Oob70il977 1020o Oo092'l 0,3'102 2,4658 l J w 0'1 I J J ANCHO~AGE-O~VIL CANYON CASE Il-l 345 KV TRANSWlSSIO~ LINE COST ANALYStS AN0 CONDUCTOR OPTl~IZATION DATE: IS AUG 79 TIM(: !5:56:1LI * P<Pl' T Oil T A * ,. * ~•**************** IINTT ~lATF.RIALS CQSTS I'JPUT VALUE P~IC[ OF TOWER ~ATERIAL PRICE OF CONCRET( PRICE OF GROUND wTRE PISTALLF:D COST OF GROlJNDING SYSTEM T0><F R SF TliP T 0 ,, E fi A S SF M p, L Y FOU'JU/ITTON SETUP FOUNDATION ASSEMBLY F fJ i 1 ~JI) h TI 0 ~, F XC A V A T I 0 N PRlCl liF MISCELLANEOUS HARDWARE urnr LhhOR COSTS REFERENCE YEAR LAHOR COST SHITNG GROltNO ~JRE ST><TUG Ll\1-<0R ~·ARI'.lJP UNIT TRANSPORTATION COSTS TOw F. R FOlJN!)ATTON CONCRETE fCJLJ'JilATION STEEL c o~wuc TOR G'~lli !r~n w I Rf: INSIILATO~: t1 (\ i·il ) " 1\f'( F. .~J I J '"-~j .. J 0,957 $/LB 0,00 $/(U,YD. o.ooo $/LB 0,00 ~/TOWER 1 7 ~ 1 • $ o.ass ,'li I L tl 0. ~ Lll 1~o.oo 5/TON o.oo 'li/CU,YD, 290,00 $/TOwER 2LI,OO $/MANHOUR 0,0 $/"'JLE Ll,2 PER IJNJl 2?5.0 $/TON 225,0 $/YD 225,0 $/TON 225.0 $/TON 2?.5.0 $/TON 225.0 $/TON OR $/M*•3 2?5. 0 tilTON .J ] RF.FERENCE YEAR FOR INPUT I 1979 1977 I 977 I 977 1079 1979 1979 1979 1919 I 977 ... J J --~ ..... J ~' J .,~··-, ~~~ .--] CONDUCTOR ---------\10. K C 'I SPAN(~\) -------- OJ 39 954. I .3 0 0 • w 39 954. 1200. -......! uo I 0 3 ~. I <' t)ll • 39 ot, t!. l4f10, 40 10 B. I .3 o 0 • 57 91)0. I 30 II. 37 900. 1 c:' () 0. 40 I 03 L I 1 o 0. 37 '100. I 4 0 (). 59 9')4. 1 l ()(I • .38 9')4. 1?00. .3R 954. I 30 0. .sq 9~~. 1 s n u. 40 lOB. IL!Ou. .3R osq. 1 I n ll • 37 0(11). I I" u. 35 795. I .3 0 1J • 35 79'1. 14 0 I). 37 9UO. I ':> 0 U • 3? 954. 11.100, 35 79'1. I';>Ou. 3') 7'!'). lc:'OO. 32 7'! s. I ) 0 0. 36 9110, I 20 U. 34 79'), 1 30 il. ~--~ --~ ,.,,~-, ~~1 -1 c·~·~ f""-'~c•>"-' 1 ----~~] .. 1 1 A~CHCRAGE•OEVIL CANYON CASE IT·! 5US KV 1RA~SMISSION LINi COST ANALYSIS ANO CONDUCTOR OPTI~IZAT!ON DATE: IS AUG 79 TIME: 15:56:10 ************************************** • * • * AUTO~AT!C CONDUCTOR SELECTION All QUANTITIES PfR MIL[ * * * * ************************************** CAPlTAL COSf/DISCOlli~T RATE. OF 7.00 Pf:.RCI:NT -~ PRESENT WURTH ($) r -~~ 1 ···-1 '~l ---------·----------------------------~--------------------------------------------------------------------- INSTALLED COST LINE. LOSSES O&M COST LINE COST ----------------------------------------------------------------- __ .. ___ .. ___ ... ----------------- 'LHERl~LS TRANSP. U<STALL. F~<GlNEfR. IDC SlJI\TOT AL SURTDTAL SUfHf'JTAL TOTAL -----------·-----------------..---------------------------- 111l706, r.Hl7. 10o~li3. 2''>10'J. 0. ?.53320. 103751. 31i 2 3 • 36 0 IJ 9ll o 11 ~228. 6733. 10'1119. 25199. 0. 25027"/. 1037')1. 3436. 361466. 11771'.2. 6835. I I I I il 9. 25934. 0. ?616'17. 96912. 353b. 362145. I 17620. (:,71:>3, IOS670. 25306. 0. 25S.S58. IO.H':il. )OS I • 362560. I 2 0112 0. hi'oh2. 109426. i'6038. 0. ;>6;>747. 96912. 3551 • 363209. 112Rt2. h'J77. IOoBS. 24R.30. o. 2':>0SS.3. 109b9S, 3386. 363634. l I HilS, r. 6 (q, • 108671. 21!9.33, 0. ;>5159U. I 0%95, 3UOO. 364689. II o89G. h<l03. 11LJ3£AO, 2ol9b. 0. 2o4.337. 9b<ll2. 3572. 361.1821. 1151170. 6o29. I05Hn. 250.?4. 0. 2'::i2')16. 10969S. 3412. 365623. II 3 H3, hRS.:;'. 11.?1158. .?Sr. H. 0. 2SR700, 103751. 3Q96. 365947. !ILI0'14. h65'::i. 110421. 2S"i21l. 0 • ;>S759H. IOSI3R. 3 1< 8 I • 366218 • I I 1 •; I 0 • 61> 7 f.. 10d644. i?Sh II. 0. 2'>8002 • IOS13f\, 3492. 367073. l?JI\t\0, f,t<92. IO':i'iR5. 2S779. 0. ?1>0134. 103751. 351'). 367400. !;>4hRL f:,llR2. IOK9i\2. 26U7 L 0. 2o7117. 96912. 361 0. 367h39. 11lJ23i. t-.152. II)Mo6. 2SR09. o. 260438. 1051.~8. 3519. 36(j096, 1 I I 'i k <l • h7?1:\. 1124!1. ?'1.379. 0. 25609/l, 1006'-lS. )116 I • 3h92':>3. 101);>')3. (,II p 0. IO<libh. ? lj 0 19. o. 242978. 123194. 321\3, 369455. 111)059. h•H\1). 102%2. 2lJ OllR. 0. 241,069. 123194. 32A':>, 369">0A. 119B<.l'>. o/5':>. !050130. ?SIJ90. 0. 2":>7.:;?0. 109695. 3476. 370391. 1216il5. (,791). 11Hll4?.. 2o02 ·~. o. 262o01. I 05 I 3P. 3509. 3712bR. I I .3112 I • t,'-, IH<. 101721\. 2113 4 3. 0. 2ll"o40. 12 31 'l4. 3)19. 372154.. lnll"'l. t-'1">'-i. 1070D3. 21131.l9. 0. ?l.l'570S. 123llliJ. 33?0. 372::>20. I'' '1? ') s. 6)05. IO'J?iO. 2Cl2'11l, 0. 2ilSI">.3. 12Uh75. 331 3. 313141. ]1 3IJ Cl/1, h'1 1lb. II llO .$7. 2')309, 0. 2553AO. IIUS!J'i. 34'il. 373311'}. !O<Jl.1R, t-.~H4. IOSS29. 21lB7. (). ?4'1'178. I ?UIHiS, 3319. .373781. J Q~CHUOAGE-OfVIL CANYON CASE I!-1 345 Kv IRANS~ISSJON LINE COST ANALYSIS A~O CONDUCTO~ OPTIMIZATION DATE: 15 AUG 71 TI~E: 15:56:1~ * * * COST OUTPUT Pt~ MILE * * PRESf..'>T VAL! IE RATE * * 7. 0 0 Pft"(Ct:N1 * • * ·············************~**** CONDUCTOR NUMREP : Y? 954, KCMIL 1300, FT SPAN 9~.7 FT TOWER !NSTALU'D COST t5Pr_ At-Jlt)W"J MATERIAL COST($) TRANSPORTATION INSTALLATIO"l CONOUCTO>< G~Ol.ll';[);, T RE lNSI.ILA Tll~S HA f!f)y, hf.<E Tf1•,rhS F ()Lr~,~-·A 1 T :J'JS RTGI•I LIF b><AY (113FT) !:>UH-TOiAL~ IDC f..Nt; I NFE:. ~I •rG PPESE'IT b><ORTH !DC ENGINHRING LOSS ANALYSTS RESISTANCE LO~SES 11UANTITY 3!6b0, 0. 31 0. 4,3 ~.3 1 /J • COKO\A I USSfS: INSIILATOR$ CONnUCTOf.? lOT ALS .... 1 J FT FT UNITS 6341~9. 0. 4436, 321'-J, 1542o':'i. 10790, 2.?11\1, UNlTS UNITS ACRES 11~706, DF.~1ANn LOSSES 5~177, 69b, ';31\72, ] .. J TONNAGE ------- 19.1J7 o.oo I • 7 0 0,47 3'i. 79 ------ 57.43 PRESENT WORTH ($) ENERGY LOSSES l.lt\OoR. ll.lt?R, 31 ~. J COSH$) COSTC$) -------------------------- ~380, 0. 82~. 107, 8052. 1744, ------ 15107, 6707, 5826~. o. 90323. 72256, 19697, __ .. ,. __ 2~0540, 106803, -------------- TOTAL LOSSES 101?45, 219~. 3! 3. 1 0 57':11. TOTAL COST($) ------- 126091~. o. 5260, 3326, 252640, 84790, 411\77, ------- 513987, o. 56539. ------- TOTAL 570526. 228216. o. 2':>104, -------- TOTAL 253320. J -1 -~J ~-~l --~-1 .···--1 ---1 -1 ~~~ l 0] ~--) INTER~AT[~\AL E~GINEER!NG CO, INC SAN F~o~CISCU CALIFORNIA TRANS~ISSION LINE COST ANALYSIS PROGQAM VEt;>S!ON ?.: 02 Al!G 1979, DfVIL CANYON-ESTER CASE !T-?A 230 ~V TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 16 AUG 74 TI~E: 1~:14:31 ****************** * * * INPIJT DATA * * * ***************~·· ] -1 SYSTEM ECONOMIC FACTORS INPUT VALUE REFERENCE YEAR FOR INPUT RASE YEAR FOR pw ANALYSIS ENfl!NL~ Y[AR OF STUDY RASE YEAR FUR ESCALATION MAXI'-111~1 CIRCUIT L(JADING AV~RAGE CIPCUIT LOADING f) c." A 'I[) C r1 S T FACT 0 I< F~tRGY COST FArlOR VhR COST FACTIJP CAPITAL COST/IllSCOUNT RATES: r:Jio:.'~ COST FACTOR RIGHT OF ~hY cnST FACTOR R ![:: H T I)> "AY Cl tARING C 0 S T I:JT~Dt:ST /)IJRJrJG CONSTRUCTION P•Gl"'EFfnr-<G Ft"F 1974 ]'107 147 7 I CJ4. 7 I 0 7 , I 73,0 I 3. o o.o 7.0 1 0. 0 1.5 715,0 llJ 3 0. 0 o.oo 1 I , 0 0 ------~--·--·------------- MVA 1 C)CJ2 MVA ICJCJ2 $/KW 197'1 -· --· ---···-MILLS/KWH 1979 $/KVAR 19~4 PERCENT 198£1 PERCENT 1913£1 Y. CAP.COST 1984 $/ACRE 19H $/ACRE 1979 % INST.CST ~ lNST.CST 1 J OJ +:> 0 0 f ', T L C .\ \ v c_1 '< -::: S H R C A S E I I - 2 A 230 KV fCA~SviSSIUN LINE COST ANALYSIS ANO CONnUClOR QDTIMIZATION -------___ _: _______ DATE: lb AUG 7"1 T1'-'E: .. I3:1~:3t ______ __c._ COrJOUCTQR DATA ~---------------------------------------- NtJMrit=l PFR PHA~f C[)"J!)IJCTUR SPA( T~d; 11,0 IN v (11_ T a::; F 230 ~. v vo L r ~.:;' \IARl/ITlU'J 1 0 • (ll) PCT L J 'J t. ""t r!UEIJ( Y 60 CPS FA [l(r,E/dH[P LOSStS 0. 0 0 K"l"l L I fl r L ~ •Jr; T H PlO,[lO Mll ES P[r<'lf_R F.~[TO" (l,QS WeATHER DATA ------------------~---------------------- '1AX[M,_IM IHir~>At.l RATF I • l I' 1"-IHK "'AX)'1U'I R A I'<F ALl I)IJR~TTO'J I HPS/YQ AVf-YAGE flAINFALL Rqf 0,03 1'-:I"R AYf:'IA:,E' Rh!NFhlL IJlJRATION b3b H.R$/YR '1AX!M'J'1 S~J()i'JF ALL RATE I , R 7 p;;HR MAXI"'J" SNONFALL rl\IRATIO"J I HPS/YR AvEI'lhGf': 5'J0r.F' ALL R h T t '> 0. I 3 I •: I "ii-i· .\vE.=?,,~;F SNP~'<FALL f)IJRhflU"' 26•1 HP$/YR RELATlV[ A[h Uti~S [ lY I. 0 0 l) ' .J NUMBER PEP. DlAr-if.lF.R WEIGHT ***-'**···-····••*-** * * I'IPUT I)ATA * GROUND<'I!RF. DATA TC1<'1Ef~ 0 0.00 IN 0,0000 LBS/FT .J .J MINIMUM MAXIMUM INTERVAL SPAN DATA 100{'. FT !CJOO, .FT 100,0 FT DfVlL CA~YON-ESTER CAS~ 1I-2A 230 KV TRANS~ISSION LINE COST ANALYSIS AND CO~DUCTOR OPTIMIZATION D~lE: 16 AUG 79 TJ~E: 13:14:31 SA~/TENSlON nESJ~N FACTORS fVERYOAY STRESS ffMP(RATURE IrE ANU wiNO Tt~PERATURE HIGH WIND TEMPERATURE EXl~[Yt ICE IFMPERATURE. M4X Uf:S!(~'J U:~H' ~·tJI'I t;ND CLEARANCE tnS IFNSin~ (PlT UTS) r;f: SC CONSTANT lOT ~L NIJM8E.R Of PHASES PHASE SPAC!Nt; CO~nUCTOk CONFIGURATION FACTO~ GRUII'in Clf ARA"ilT Wl. llF Jr,~)l!LAfllRS PFR TO,.F.R INSIJLA101'1 SAFF.TY FACTOR S lRT ,,r; l.t >J(; TH I, vtl:, Uli C0~1bl11ATION fOU~JLJATlO'J TYrE. TFtJRAIN FACTOR LINE ANGLE F~CTOR tn..,fR (;ROiJNDINt; lRANSVfRSF OVftJLUAD FACTOR VERTICAL nVfRLUAD FACTOR UH<G[TlllllNAL UJhO MISCtLLAf,[lli!S HAt<OwARE WEIGHT lOwF::R r~f!GHT fAClUI'I TOwER WtlGHT ESTJMA1ION ALGORITHM -----------------------~--------- **'*i***~·~····'** • * INPIJT DATA * * •*****'****•~***** 1.10, DEGREtS F o. DEGREES F lJQ, DEGREES F ~o. DEGREES F 12 0. ')£ GfifE.S F ?0, PEPCENT 0. 31 l.tlS/FT T\J~ER DESIGN 3 20,0 FEET 1 • 0 2 28.0 FEET 41\ 2.50 6,'5 FEfl 3 lj 1. 06 PER UNIT ,Ofl6l.l 0 2.50 1,50 1000, Lt3S 0, 1 I T 0 NS I Tll W F.: R I , 02 TO~ER TYPE. 9: 230KV TOwER ICE AND ~IND TENSION (PCT UTS) HIGH WIND TENSION (PCT UTSI tXTRtME lCt TENSlON (PCT UTS) ICE THICKNESS WITH wlND ~INn PRESSURE wiTH ICf. ~I It; H WIN f) EXTREME:. ICE DISTANCE BET~EEN PHASES: Dl 02 03 011 DS Db TW = 0,00016~TH••2 -3.0~797•TH••0.3333 -0,01\945•E:.FFVDL - 0.275b7•EfFTLJL t 0.005IO•TH•EFFTDL + 0,00160*TH•EFFVDL + Pl.)7QJ? KTPS .' l 50, PERCENT SO, Pf:.RCENT 70, Pf:.RCF.NT 0,50 INCHES 4,00 LHS/SO,FT, 9,0 L[J$/SQ,FT. 0,50 INCHES 20,00 FT 20,00 FT 40,00 FT o.oo FT 0,00 FT 0,00 FT ID Nli'1REP --------- 3'5 0::1 ~b 37 ~ 3':\ N 3'1 llO 'n ll2 u 3 /J (J /J 5 lib ll7 45 ll9 50 S I ,r::, ~ ')3 ')IJ 55 J ------------- DEVIL CANYO~-ESTER CASE II-2A ~30 ~V TRANSMISS!O~ LINE COST I~ALYSIS AND CONOUCTnR OPTIMIZATION _______ DATE:_I6 AUG 79 TIME: 13:1ll:31 __ ~~------- * 1 ~J P U T lJ A T A * *********•~·*~•~c•• CONDI!C TOR SlJ'1MARY ***************** -----------------------~---------~-~---------~-------- STRANDING UNIT WEIGHT OUT.OlAr-1, TOTAL AREA MODULUS NAM[ Sl2'fCKCMJ (AL/ST) CLBS/FTJ (INCHES) (StJ.IN.) (Ef/E6 PSI) ------------------------------------------------------·· ~~All A q D 7Y"i,O 30/19 1. 2 35 0 1.1ll00 0.766(1 11. 30 h'LifllJY ooo.o £15/ 7 1.0150 1.1310 0.7069 9.110 CANARY 900,0 sv 7 1. 1 "i90 \,16?0 0,7985 10.85 <'~fiT! 054.0 liS/ 7 I • 0 7':i 0 l.loSO O.R011 9,ll0 CA'?I)TfJAL 9C,L!,("l sa; 7 1.2?90 I. 1%0 0,1\llhll 10.85 f) R T (IL AN 1o.n.o •l"i/ 7 1.1650 1.2130 0.8678 9.£l0 CURLE\\ 103~.1"1 511/ 7 1.5310 l.?ll60 0,9169 10.8'5 -------·-R L II F_ .JAY 1 I I 3. 0 45/ 7 1.zs:.o 1.2')90 0,93llb q,lJO F[>.jCH 111~.0 "ill II 9 1.4~10 1.2930 0,98lJ9 10.30 R U 'I T T r" r. 11 Y?, 0 liS/ 7 1.34110 \,3020 (. 00 I 0 9.ll0 G'iACI<:L~-11 Q 2. 0 Sll/19 t.S350 1.3330 I. O'J52 10.30 K I I f ~ R IIJ 127?.0 £15/ 7 1. <d'-10 l,,ll')O I. Obf\0 9.ll0 Pt'~-AS ANT 127?.0 5 1J I 1 9 1.6'3')0 1. 3820 1.12':>6 10.30 fJIPf'F.R I 55 1 • 0 £15/ 7 1.5220 1.31:150 l.t:SSO 9.£10 "APliN 1351.0 ';4/19 1. B70 !,ll?UO 1.19':>9 10.30 Allf-IUL INK 1431.0 US/ 7 l.b\30 1.11270 1.2020 9.LIO PLrJvfR lll)I,O 'jiJ/ I q 1.81JOil 1,11650 1.?663 10.30 NUTHATCH 1'110,0 liS/ 7 1.70~0 \,U6b0 1.?61'10 q,uo PAPL<OT 1510. I) 51J I 1 9 1,91J20 1. 5060 1.3366 10.30 I_AP~.lNG 1Sq0,() !JS/ 7 1.7920 1.S020 1.3350 9.£l0 F AJ__ CPN 1590,0 511/19 2,0q£iO 1.5 11'50 1.11076 10.30 .J J .J TEMP,COEF. ALPHA•E-6 PER DEG F ---------- 9.7 1 1 • 5 10.9 11 • 5 10,9 11 • 5 10,9 11 • s 10.8 11 • s 10,8 I 1 • 5 10.13 I 1 • 5 10.8 1 I • 5 10.8 1 I • 5 10.8 1 1 • s 10.8 ... J -1 ---1 ID .'JU..,RER NA~!: --------· co 3', "AL_L fiR I) 3b RUI'lDY 37 CANARY ~ 3'1 PhiL w 3q C r, P D 1 ~~ h L 41) (Ji<l lll AN ll I CURLF"' U2 !:'LIIl:.J A Y Ll) F l ~IC H 44 !3U~J T T NG 45 r.><ACKLE lib fl!TIF~N 47 Pf!F h SA~ T IPi DJPPEfi 4<J ~ARTTr: 50 QfH'Ol l r.JK'.'; "il PLi1YFR 52 rJUT t1A TC:H 'c; 3 PARRnT 5IJ LAPwiNG '55 FALCON • : -~ ---1 -l ~--1 ----~1 "1 -1 l -'') DEVIL CANYON-ESTER CASE J!-2A 2JO KY lPANSMlSSJON LINE COST ANALYSTS AND CONDUCTOR OPTIMIZATION DATE: lb AUG 70 TIME: 13:14:31 * • 1 ._.PI IT DhTA * •••••••••••••••••• CO'I!DI_ICTOR SU'-1~1ARY ********""**•*••~~: AC RESIST. liLT.TENS. GEDM.MEAN THF.RM.LP11T -AT 25 fJEG c S 1 R OJG T H ( L R S) RADILIS(FT) PRICt:: ( $/UlJ (AMPERES) (OHMS/MILE) --------------------... ·-------------·--------.. --·------- 3/'lllOO.n n.o3a2 0,500/1077 9 I 0. 0.1162 2':JLJUO.O 0.0374 0.676/1977 935. 0.1082 3;>~00.0 0.0392 O.b:B/1977 950. 0.1040 ?ooO(I,O 0.03KS O.h71/!977 970. 0.0998 31l?OO.O 0.0404 0,632/1'117 9'10, 0.0987 ?Hanrl.O 0. 0 00.() 0,0436 o,..,l,9/tC?77 10'10. o.oRS'i 3.3.?00.0 0,0431 0,665/1'777 I I 2Cl. D.Ofltl8 1131 0 n. tl O,OLI'i! 0 • b 11 2 I \ '-1 7 7 1 I 3 0. 0,0797 35£lU0,(l O,Ollll'5 O,bb')llr'll7 I I b 0. 0,0760 (j ll A\! 0. 0 0,0£J6b O.o~8/IG77 I I 8 0. 0.0750 3 7h on. 0 O,OLJ59 0,663/1°77 121 0. 0,072.3 4{hll0,0 0,0!.11-lO O,to311/I077 1230. 0.0708 3<~Rnn.o 0.0 1J72 0,662/1977 1?50. 0.0686 51! /j () (). () 0,04'-IIJ O,to37/1977 1 no .. 0,0671 4 I HlO. 0 0,0/.lf\':i O,h6'~/IQ77 I 3 0 0. O.ObUO 5'3?00,0 o.O'i81l 0,6'l,0/1977 1320. 0.0602 £131-lOO.O 0.0497 0.660/1977 I '3 Ll 0 • 0,062~ 56000,0 0.0521 0,6'36/1'177 !360. 0.0612 l -· ') --1 IND.REACT. CAP.REACT. (OHMS/MILE) (MOHM-MILESJ ----------------------- o. 'H28 2.5186 0.3928 2.5080 0. 3928 2.5027 0. 3'1119 2. 5027 0,3902 2.4816 0,3902 2,LI6513 0.3!)1J9 2,/JlJLih 0,38b0 2.£13/ll 0.3R02 2,4130 0.3817 2.£1077 0.3759 2.31'166 o. 3no 2.3A13 0.3722 2.3602 0.3738 2.3602 0. 3bM 2.33311 0.3712 2.33313 0.3648 2.307ll 0.3670 2.3126 0,3b?2 2.2862 0.'3o3R 2,29.15 0.3580 2.C70Q J .J J CEVTL CA~YON-ESTER CASE II-2A 230 KV TQA~S~ISSION LINE COST A~ALYSIS A~D CO,DUCTQR OPTI~lZATJON _ _ _ ________ DATE : I 6 A !J r, 7'1 T I~ E : 1 3 : ! 1.1 : 3 1 * " INPUT DATA * * UNIT MATERIALS COSTS INPUT VALllf REFERENCE YEAR FOR INPUT PRICE OF TUW[R MATERIAL PI;' I Cl: OF ((INCRE 1E. PPICI: 0~ G~OUND ~IRE l'lSTALLED CflST OF GROUNDING SYSTEM T n.-<F I~ SETUP T n 1'1 F R A S S F ~~ R L Y Fllll'lf)f. T I U~-: SETUP FIJIJNl)h T TON 1\SSE"'113l Y FOti~-II)ATION E;<C:AVATION 1-'PICI: OF MJSCFLLANEOliS HARDWARE \!NIT LAfiOR COSTS RE~EPENCI: YFAR LA~OR COST STRJ~G G~OUNO .. IRE S Tl\ J !~{; L ARtJQ MARK\JP UNIT TRANSPORTAl!ON COSTS --~----------------------~~·; T0~-<Ef-l F[llJ"<IJA T ION CONCR!: rt: FOIJfiDAT!ON SlEEL CO!'-I!JUC TOR GRUIINO WIRE I ~JS\JLA TOR Hi\RI)WARE J ._J 0,957 'li/LR 0,00 'li/Cil,YO. 0,000 S/Li-3 0,00 $/TOWER 1 l5 1 • $ O,IJ55 $/Ltl 0. ~ IJillO,OO $/TON 0,00 $/CU. YD. 290.00 $/TOl-lER 2iJ,OO $/MANHOUR 0,0 $/Mit.E 4,2 PER UNIT 225.0 $/TON 22').0 $/Y[) 225.0 $/HlN 225.0 $/TQ"J 225,0 $/TON 225 .o $/TOtJ OR $/M**3 225.0 $/T(1N .I J 1919 I 977 1917 1977 1979 !979 1979 1979 1919 I 9 77 1979 I 977 J .J J ~--1 --1 CONDUCTOR 0::1 _ _, _______ ·~ (I • O:CM SPAN(F"f) ~ ------.. - U'i 'i3 I<; In. 150(). iJS I I U?. 1.30\l, 53 I 5 I 0 • I 4 0 0. lJ5 11 rJ?. 1 4 f\ rl. S3 I 'i I 0 , I i! tlll • iJC) I 3 <;, I , 1 _s 0 o. lJ 7 \272. 130(1, U3 11 I~. 1 _so o. 51 1'1 5 1 • 13 0 0. ll3 I I I 3. 1 '-'f) 0 • lJ7 I 2 7 2. 14 0 0. Llo 1151 • 1 4 0 I). lJ') I 1 9 2. 1 2 01). ':ll !lJ 31. I IJI) ll • u I 1 n 3 3. IS 0 0. lJ q' I 3S 1 , I 2 00. II 7 1 2 '2. 12 0 0. ':l'i I 'i'IO, 1300, 51 llJ 31. u 0 1),, w I I 0 3 "'>. I II 0 0. 4"7, I I 1 3. 1.? 0 I). ':-5 I c, q n. ]t.j (I 0. 5'5 I ':i q 0 • I 2 CllJ • lJ I 1 on. 1 2 no. iJP. 1 351 • I 3 0 0. ~-1 --1 -~ ') --·---1 -~--1 --1 ---~«"I D~YIL CA~YO~·ESTEP CASE 11-~A 23Q ~V TQI~S~lSSIUN LIN~ COST ANALYSIS A~O CO'IOUCTOR OPTIMIZATION DATE: 16 AUG 70 TIM~: 13:1~:51 * * * AUTOMATIC CONnUCTOR SELECTION ALL ~UANT1.TIFS PER MILF • * * * ······················~··············· CAPITAL COST/DISCOUNT RATE OF 7,00 PERCENT PRESENT WORTH ($) 1 -~--~-------~---------------~------------------------------------------------------------------------------- INSTALLEn COST LINE LOSSE.S O&M COST LINE COST ---------------------------------------------------------------------------------------------'1Aff.PJ~LS TRA'JSP, INSTALL. f.NGHIEF.R. TOC SUtlTOTAL SURTOTAL SUBTOTAL TOTAL _.., ____ ,. __ ----------.. ~---------------------------- -------- 77"iOO. /j 4 7 ':i. 77~09. I 7 'i I 0 • 0. 17h693. 26?0 I. 23R8. 21'l':l322. 7193?. /j \)"' 5 • 7':i'il0. lo6611. (]. 16Rio4. 3'::>3R2. 2273. 20511tlo. 7919?.. '~41\o. 7o292. 17597. o. 177568. 26241. 2U00, 206209, 733?'1. llORO, 71llJ ':'>6. 16705. 0. 1oRS7l. 353H2. 2278. 206231. 76778. Ll s 1 7. 7WJS2. 17627. (l • 177fHU, i'62U I • 2£JOU, 206519. 7'j070, ll2'l I • 76S2'S. I 7 I uP, () . 171034. 311 61. 2338. 206533. 737~11, Lt 20 I • 7oiRT. lo9SLI, 0. t7108o .. 331U2, 2312. 2065<J0, 7n5'12. 3°97, 7'it92, loll7o. 0. 166257. 3817lJ. 22lJT, 20667R, 7o"'>'l7, ll 3 f\ 5 • 761\72. 1 73•l2. 0. 1 7£J 9oo. • ?oU29. 2365. 206787. 7ton. v-~n. 7" 1 57. 16'i 12. (1 • 1obol7. 381 7 4. 22'S2. 207(1<13. 7'))27. 112 05 • 7':)?.26. 1702). o. 17171<2. 3.3142. 2521, 2072U5, 766f\5. 11,!08. 7'J'i77. 17222. 0. 1737111. 3 I 1 61 • 23£J8. 207290. ',.> 71111<6, llllJ 2. 7nc<,o, 16R) 1 • 0. 11:>9839, 353H2. ?295. 207Sl6. 71\n':>l. /l_!,Q?. 7'j<l_3C), 17U22. 0. I 7580£1, 291J29. 2.376, 20760P, 6<"~27?. )'-11 (1. 7LJ075. !o29R, 0. lblJU64, ll1005. 2222. 207692. 7 lllJ 2 <; • /j 3 ~ t:\ • 7R300, l 72 7 7 • 0. 1 7/1 s Ll (). 3 I 1 61 • 25'56. 207857. 7_)151. /j 2 1l9. 77Q(lJ, 1 7089. 0. 17?<l£J3, 33142. 2:no. 207916. 7905R. 1.1':>66. 775UI. 17728. o. \78fl9U, 26692. 2UI7, 208003. 7S715. lJll2H. 78650, I l 4 65. o. 176238. 29U2o. ?3P.2. 20ROU~. 70670. 301 3. no 56. 1b33R. 0. 16Lit\65. U1005. 222H, 2013091\, 7011:>1. 110 5S. 770bh. 1664\, 0. 1&702-!J. 38174, 2269. 20R36R, R I) 7 '-J?. l.l')f\0, 7bh'•?. 17821. 0. 17'153'). ?b692. 2ll30. 20130'::>7. ]i;?._'IF\. Ltb0o, 792b7, 17P.30, 0. 11\0010, 266'12. ?U 33 • 20'113/.l, hf.RI3. 3<}76, 7bR.29, 1oi.J5"1, n • 16607':>. UI005. 221J4, 20032U, 7 b 07 0. 11,!3LI, '77504. 11359. 0. 175166. 31875. 2567. 209lJOA. c;c ~ O'l . . J DEVIL CA~YO~-~STER CASE II•2A ?30 KV fQANS'-'ISSION LINE COST ANALYSTS AND CONOUCTOR OPTIMIZATION !NSTtoLLED COST B R E ~ K I) 0 W 1-J -------------- C0 1<flUC T nR GROilr-.rJ•·rTRF 1 " S U L h fr.1 R S HAt<[J<.Akl:. Tn~'r"~ ~ OUNl)d T IONS RIGHT UF WAY !101FT) -----.. ---.------ SUt:l-TOTALS !flC ENGINEERING PRESENT llfl~TH ,, I DC '/ E"JGINE"ERING Lf')SS ANALYSIS RESISTANCE LOSSES QUANTITY ..... _____ 151\40, n • 207, 4. 3 4. 3 I ? • CORONA LOSSES: INSULATORS Cflt-muc T 01-1 TnTALS J J FT r1 lli-Jl T S UNITS UNITS ACRES 0 h T E: I b AUG Fl T I '-'1:.: 13: 1 'I: 31 _ _ __ ---~-- ****~*********~··••••********* ., ., CO~T OUTPUT PER 1>1!LE PRESE"lT VhLUE. RATE 7,00 PERCENT 53 "' ., • "' !<j!O, KCMIL C 0 ~ D U C TO I~ N ll M R E R : 1300, FT SPAN 84,9 FT_TOWfR _____ _ Mt.TERIAL TRANSPORTATION COST($) TONNAGE COST($) ..... --------------------------- tJ9<171. l'j,38 3tJb 1. 0. o.oo o. ?957. I • I 4 549, 3219. O,IH 1 0 7. q l 0 0 tl, 2! • 1 1 4 750. 7493, 1 2 1 1 • 1989':), -------__ ,.. ___ ------ !74')44, 31'1.10 10078, 77500. PRESENT WORTH ($) JNSTALLATIOfll COST($) ------------ IJ5797, 0. b02Q7, 50178. 17667, ------ 1751189, ···--·---------------·-----~-----------------·--------------------DErHND LOSSES 13781, o. 13781 • ENEf~GY LOSSES 1245q, o. 1 • 1~460, J TOTAL LOSSES 2b2tJO, o. 1 • 262tJ1. J TOTAL .... J TOTAL COST($) ------- qq22q, o. 3507. 3326. 1'56006. '51lll82. 37C.,b?, ------- 3'58'511 • o. 39tJ36. ------- 39HtJ7. 15q183. o. 17'510. .J l ____ ,l ·---1 --1 1 , __ 1 ~---~-o 1 1 INTE~NATIO~AL ENGfNEtRING CO. INC SAN FRANCISCO CALIFO~N[A ] TPANSMJS~lnN LIN~ COST ANALYSIS PROGRAM VERSION ?: 0? AUG 197~, wal,.I\JA-DtVJL CANYON CASE IT-3A 230 ~V JRANS~ISSION LINt COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: I~ hUG 79 TIME: 16:29:16 *·~···········~··· • * * ****************** INPUT DATA * SYSTEM ECONOMIC FACTORS INPUT VALUE REFERENCE YEAR FOR INPUT J..\ASi: YF A.R FOH f''" ANALYSIS F cW• [ '1 (; 'r f. A H 0 F S T tJ D Y '1,\Sf:: Y'>:A'< .FUf< FSCAt ATION Mfl~IMUM CIRCUIT LOAUlNG IVFFIAGE Cl!IClJ!T LOADING OFMA~n COST FAtTOH F\~~GY COST Fft(Tnk V·\R [11$1 f A[T110 CAPl i~L (iJST /iJTSClJI.HJT RATF.S: r:;c,Y COST FA[l(IR RIG•1T UF ,..Ay CflST FACTOR Ri~HT nF ~Ar CLfARJNG COST T ;,r t.'-1 LSI fl l If< I,, r. r: 0 1\i S T R U C T [ 0 N F>'<Gl '!d:R t r,r; H F 1979 !907 1977 514,0 2R2.7 n.o 13.0 o.o 7.0 l 0. 0 1.':> 71':>,0 1430,0' o.oo 1 I • o 0 MVA MVA $/KW MILLS/KwH· $/KVAR PERCENT PEF;CENT % CAP,COST $/ACRf $/ACRE I. lNST,CST " JNST.CST \992 t9n 1979 1979 191\l! 191'14 19M I 91'\ll !979 1979 ,.~I&,A-DtVIL CANYON CASE II-3A 230 ~V fQ~~S~ISSION LI~E COST ANALYSIS AND CO~D0CTOR OPTIMIZATION DATE: I~ auG 79 TI"~: 16:?9:16 •••••••••••••••••• ~ INPUT DATA • ****••······~····· GROUNOI'<IRF:: OATA ----------------------------------------- 'IIJ'1:1t"' PPI PHAS[ CO'i')!IC TOR SPAC!IJG Vl.!L 1 tt ::;~ V()Li~.~:;-VAR]t.T!OIJ L I .\J E ~ =-< t.. r~ u f \1 C Y FAI~~~~THLR LUSSES Ll';E ~Ft;r;rH PtJ1itR FACTLW ~«EATHi:-R PATA 1 0. 0 230 10.0!) biJ o.oo 2 7. f);\ n.os IN l'-V '-'C T CPS ~,,I •.• I ~ .. 1LES ----------------------------------------- ,V, A X [ JA J v, R4P;FAI.L f< A r 10 1 , ! R p,; /1; ;< '1AXl"J" RATI\FALL iJ!I•< AT TON I ~·uS/Y.q AVF><A~;f RA[t,FALL RATE 0. Q ~ I ... I --·R AVE"<~i,f'" PA P•F ALL l)l It< A l T ur~ t;';h h;;>SI'r'R MAX J'I,J:~ S''Jf)" ~A I. L f/ A If' 1 • 8 7 PU•iR MAXI'-'J'I $1\ir]riFAlL {)IIR/ITTON t HRSIYP A¥ E•n:;l' s:,Q,F AI L R~Tf 0. I 3 I,, I..,~ A~ERA:;<: S'·Jn~ F AI_ L IJIJi; AT I UI.J 2b!J HRSIYR R[LAT[Vt ATf/ IJE r,s IT 'r' I • 0 f1 0 J .J NiJMHFR PFR TOWER I")IAM!:TER WEIGHT J 0 0.00 IN 0.0000 LElS/FT ,.J MINIMUM MAXIMUM INTlRVAL J j SPAN DATA J 1200, FT 1600, FT 100,0 FT J J ~ITANA-SEV!L CA~iON CASE !I•3A ?30 KV ]UA~S~ISSIO~ L I~t COST A~ALVS!S A~U C~~DUCTOR OPTJM!ZATIUN LlATE: 1<; AI!G 79 TP.'t: 16:29:16 [V~RYflAY STRESS TF~PERATURE I C t. •HJLl fi p; n T t. '1 f-F k !d lJ R E H I G f< "' T r.J D T E ~~ P f R A T U R f EKTHF~E ICf TFMPfPATURF "AX UtSTG'J TP'·I' ~Of< (,rJI) CLEARANCE. f n S i F ;, S l fi \1 ( PC T ! I T S J i,! t ~·1 C r. () ~ J S T A r-J T TOTAL N!JMRER OF PHASES PHAS~ SPA[ I NG C 0 i'v I) IJ C T DR C 0 1'1 F I G UR A T I 0 !~ FA C T 0 R GROIJrll) [lfARA~JCF :<r1. UF T USUL.A Tf_WS PFR TOWFR I ~! S I I l A Trlfl SA F F T Y F ACT 0 f./ S T K I \; r; l t ~\ L~ T t1 I , v f F , ··' !< C r·, M tll N A T T 0 N Ftir.l'!i)A r I U'r f YPt I F i"~F I< (,Rill IIJI)! Nt. T u A '·! S V i' 'l :; F il v F '' I_ U A 0 F A C T LJ R V t >i f l C' A L n V [ ~·! I I ~ [) r A C J () P L(l ~' G I T I j f) ]'I A {_ L IJ ~. i) ~I.T3CI:LLMJFl!1.1~3 r-i~HO,..AI-1~ ,_ETGHT TO•·E>l _,f[C~HT FACTOR TQWF~ ~tl~HT ~STT~ATION ALGORITHM ***************~** * P<PIJT ()ATA * * ***1t****'t****~**** lJ(). DEl.'-IEE:.S F 0. DEr.>.:EtS F lJO. EiE:.GREE:.S F "S i) • r'lfGRFES F 12 0. OEGRfE:.S F ?0. Pt:YCENT 0. 3 I L BS /F T TOWER DESIGN 3 20.0 FE.ET I • 0? 2A.O FEFT lJfl 2.50 1>.5 FEE'T 3 il 1,06 PER UNIT • 08hll 0 2.')0 1 • "0 I 0 0 i). Lf1S 0.11 TONS/10~ER I , 0? ICE AND WIND TENSION (PCT UTS) HIGH WIND TENSION CPCT UTSJ EXTREME ICE TENSION (PCT UTS) IrE THICKNESS wTTH WIND WJND PRESSUPE ~ITH ICE HTGH WINlJ OTSTANC~ BETWEEN PHASES: Dl 02 03 ()(j 05 06 Tw: o.noOJh•TH•~2 • 3.09797*TH•*0.3333 • O.OA91.13*E.FfVOL - li.c'75hl•tHTI:l t O.OOSlO*ill*cFFTDL t O.OO!t>O.tTH•E.FfVOL + 1R.379!? KIPS l so. PERCENT so. PERCENT 70, PERCENT o.so Jt~CHES q.oo LBS/SQ.FT, 9.0 LBS/SQ .FT. 0,50 !NOiE S 20.00 FT 20,00 FT IJO,OO FT 0,00 FT 0.00 FT 0,00 FT JD "iU'1P.ER r-JAMF ---------- to S2 ~UTHATCI-1 53 PAD~rJT 54 LA f'" I:, G (.TI 55 F /1 L C n ~. 0 So CtHI" Ak S7 P.LIIi::.Rli?D ':iB 1\ 1 ;'I .J _I rlATANA-DEVIL CANYON CASE II-3A 230 KV lRANSMlSSION LINE COST ANALYSIS ANU CONDUCTOH OPTIMIZATION DATE: 15 AUG 79 TIME: 16:29:16 ULT.TENS. GEOM.MEAN STRI::.NGTI11LRS) RADIUS(FTJ 1.!!600.0 Q • 0 ~~A~ 'i3.?!ll). 0 0.0501:1 43ROO.O 0,01197 'ibOOO,O 0,0521 ':i~hOO,O (1. 0~ '51.1 l:diJ()O.O o.o~AH 50'HiO.O 0.0'>70 J ) ,I J • * • INPUT DATA * * * CONDUCTOR SUMMARY ***********•***** T11ERM.l!MJT PRICf($/LBJ (AMPEPES) 0.664/1977 1300. 0.630/1977 1320. o.o00/1977 1340. o.o~o/1°77 1360, O,b7~/1977 11140. . O,b7Sil977 1 b 1 0 • 0,699/1977 1.600. J J ,J ) AC RESIST, AT 25 DEG C IND.REACT. (QHMS/Mllf) (OHMS/MILE) 0,06119 0.3670 0.0602 0.3622 0.0623 0.3638 0,0612 0.3580 0.0560 0.3'l48 0.0475 0.31.11.13 O.OLII:lO 0,3 1J80 .. l J CAP.REACT. CMOHM-MILES) 2.3126 2.2862 2.2915 2.2704 2.2387 2.lbll8 2.1806 J I -~· -1 Ji) \JIJ'IflE. R Nt.:·tE --·-·---- OJ '>2 NUTHATCH 53 PARt<nT s~ LAPw Jt.Jf. U1 'J') ~AI cnr·• 1-' <ih CIPii\A~ ')7 ><1 tlciJ I RO <,c~ ~ !1• I ¥-ATA'JA-r.EVIL CANYO'J CASE 1!-~A 250 KV TRA~SuiSSTON LINE COST ANALYSIS AN~ CnNDUCTOR OPT!~!ZATJON DATE: 15 AUr. 79 liME: 16:?.9:16 StZUKCM) I 'i 1 o. 0 1510.0 1':;90.0 1'190.1') 17.'10.0 ~1':11>.0 ?\1>"1.0 STRANO!tJG f4LISTl ------- ll')/ 7 54/19 ll5/ 7 54119 84/19 R4/l9 '1 2/ 7 • • • 1"<1-'llf DATA * * * CO~WIJCTOP SUMMARY *****A-**"•*••••*• UNIT WE:.I GHT OUT.D!AM. (LAS/FTJ (!NCHESl ·-------·------- 1. 10~0 1.1Jo60 1.91J20 1.5060 I. 1920 1.5020 2.04ll0 I. ')450 2.071.j0 l.hO?O 2.5120 1.7620 2.5040 I. 7 5'10 TOTAL AREA (SQ,JN.l -.. --... --- 1.?61'10 1. 331)-6 1.3350 1.4076 1.51?0 I.R2fl0 1. 7760 l TEMP.COEF, MODULUS ALPHAt>E•6 (fFIEb PSl) PER OEG F --·---------------·-- 9.ll0 11 • 5 10.30 10.8 9.ll0 11 • 5 10.30 10.8 9.05 I I , 3 9.05 I I , 3 9.25 12,0 .] U1 N .... 1 RITANA-~EVIL CA~YON CASE IJ-3A 230 Kv TPANS~ISSIUN LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATf: 15 AUG 79 TIM[: 16:29:16 ****************** * * * INPUT DATA • * *****~****•**~**** Wd T MAT F: RIAl S C n S T S INPUT VAL U F REFERENCE YEAR FOR INPUT -----------------------~--·---- PP!Cf 0F TO~ER MATERIAL PQlCE OF CONCRETE PRICE: llF Gf<nUNLJ "'T RE l~ISTALLEt> Cf.>ST OF GPOUNDlNG SYSTEM rn,,u; sETlJr' rn ... F'R ASSf.t1RI Y FfliJt.J[lA T TON Sf TUP FflUNUATTUN ASSEMRLY Fnu'•I!I\ITiJ~J FXCAVAT!ON PRJC~ OF MISCELLANEOUS HARDWARE UNIT LAbOR COSTS R E H R F N c't: YE .A R LAB 0 R C 0 S T STRP•G GrllliJND f>llRE STh'TN(; LARl1R MARKIJP UNIT lRANSP041AT!UN COSTS 1 n.·,FJ< F n ti''JiJ A T I () N C 0 r• C R E. T t FOUNPATTON STFEL UlNPUC T nR GRU!IfW wIRE. lNSIILATOf< f1 .\ R lh< A f.< E 0,957 , /Lt~ o.oo 'f./CU.YD, o.ooo $/Lf3 o.oo $/TOWER I 7 51 • $ O,li5S $/L H 0. .~ IJ!IJO,OO $/TOIII o.oo $/CU,YD. 290,00 $/TOWER 2li,OO $/MANHOUR 0,0 $/MILE 11,2 Pf:.R UNIT 225.0 $/TON 2?5. 0 $/YD 2?5.0 $/TON 22S.O $/TON 2C'J. 0 $/TON 2?':!,0 :!>/TON OR 225,0 $/TON .J .l .J I cnq 1917 1977 !977 1979 1979 1979 1979 1979 1977 1979 1977 CONDUCTOR ---------c:c 'ill. K[M SPA'J(FT) -------- CJ'1 57 2156. 1.3110. w 57 21'ib, 1llOO. 57 ?.156. 12 0 0. t)f3 21 t• 7. 1 5 no, '; 7 2 ~ ') 1-:. l s 0 0. S'\ 21o 7. 1200. 5'1 21 b 7. ! q 0 (J. '57 ?ISh. 1-nnu. ':!6 I 7 I' 0. 1 .50 0. ':)6 1 71i (\. 14 0 (). 58 2167, IS o \1, S.h 1 7 K 0, 1200. 53 I 'i I o. 1 _, (! ~) • S6 1 7RO. 1 ')Oti • 53 I 'l I 0. i 41\0. 53 IS I 0. I SO<J. ':)3 1 o; I 0 • 12 (l 0. 55 1">40. 1500. <;R 21 h 7. 1 b t) (J. Sn 1 7 ;J, (\. ·1 t')OI). 55 1SJO. 1 1.1 no. 53 I r:; 1 <'. I" n u. c;s 1 'JO 'I • 1 ')O o. 'J? IS1l1. \200. 55 1 S'it1. 1 ,' 0 I) • ) ---, ~'TA~A-nEVll CANYO~ CASt !J-3A ?30 ~w T~A~SMJSSION Ll~E COST ANALYSIS A~J CONDUCTG~ OPTI~IZATIO~ JATf: 1~ AUG 79 TI~E: 16:29:16 AUTOMATTC CONDUCTnR SfLFCTION ALL ~UANT!T!tS PF~ M]Lf * * * *****************************••······· CAPITAL COST/DISCULI"lT PATF OF 7.00 PERCENT ----~-----··---------------------·--------- PRESENT WORTH ($) .. ·~~.) -.·1 ------------------------------------------------------------------------------------------------------------- I ~• S T a L L E [) COST LINE. LOSSES O&M COST LlNE COST -~------~-----~--~-~--~~-----------------------------·------------------------·--------------MATf.<<J.\LS TRA"lSP. HJSTr.I.L. E"<GI~E.FR. IDC Sl.lt3TOTAL SlJFHOTAL SUC!TOTAL TOTAL ------------------------_____ ..,.. ___ -----------·---· -------- A<><ji)O • <;100. AOll19. 19.?60, 0. 19ll31J9. Ill 0 ')II 0. 26?6. 337515. 021c'3, <;l')S. 7492R, 1 9 II 9 3 • o. !96698, 11.10540, 2658. 339896, Q() 1 3 7. '521.?. P.27S9. ]9<;9?. 0. 197700. 140.,40. 2672. 340911. 92tll5. '>120, /lc?.H~. 1971j0. 0. 199603. lll2049. 2697. 344350• 9':-7t,9. c; ,.!6;. /l01Kf\. 1993ll, 0. ?01155. 140540. 2718. 344413. 02?54. 5199. 1'.4?211. 1991P. 0. ?.01640. 1112049. 2725. 346414. 9';:,<lK9. <;??I • 11?3.~5. 201'-10, 0. 203134, 142049. 2753. 348537. 1 no lbS. <;Ill 7. RIU1. ?OSlll, o. ? I) 7 2 711. \.ll O':i 110. 21301. 3'50615. 1-12 7tJIJ 0 4 h '711. 78631. 1826R. o. 18ll.S36, 166?66. ?491. 353093, Rl.IO':l 1. ll70'!. 719bb. ll\439, o. 181>066. l66?t>6. 2514. 354/l46. 10067?. '5 3A 1 • A.F'II. 201'\]9, 0. ?1008-L 1420ll9. ?839. 354971. R; I)') I • Q/9.?, P.10?9. 18620. 0. 18'7890. 166266. 2539. 356695. 7'7'-:JOO, I~ 4 7 ') • 77209. 17C,10. 0. 171>693. 174055. .?388. 3S8137, f\f\llbM. 479';. 7 H 0 I" 0 • 18799. 0. I 8 <J 7 0 1. l6tJ266. 2564, 358530. 7419?. ll4~6. 762'i2. 1154 7. 0. 17756H. 179055. 2ll00, 359023. RJ7t.o. 4S4':l, (ht1H7, llP.b.3. 0. 18025'l. 179055. 2436. 361"7<16,. 7'-li)R). ill>·) 7. ROOLlR. 18014. o. Ull1f32. 179055, ?457, 363294, 7'iP':,P.. IJ':lob • 77Sill. 117 28. o. 178894. 1112109. 2417. 36:S420. I06S'i2. ')')9<1. P,4Rll7, 2lh70. o. ?IR667, lll204q. 29~5. 363&71. 'li'l!/1. IJ'J? 7 0 71< 7M 1. 1tJ33h. 0. 195115. 166?66. 21>37. 364017. p. :) 7 '!?. IJ5KO. 7M•ll2. I 7 R21. 0. 1791\55. 1112109. 2430. :Sb43B. A'Jl 1,!-\. iJI)ll'!. 7 6'121. 182'c11->. 0. !Boon. I 790':>5. 2ll95. 366174. R31J 00, linlll • 7oil':l3. 1 ~091J. 0. I fl?':ifHl. I 821 0 9. ?ll67. 367164, 7£'GOS. IHI\3. 7 14 11'1. I 7 0 0 /J. o. 171590, 193450. 2319. 31>7338. RI!St>O. 117 ?<'.. RO~<I3. ll:l21 9. 0. 183H46. lfl2109, 2484. 368439, AA[A~A-DEYIL CA~YON CASE I!-31 230 Ki TgA~SMISS!ON LINE COST A~ALYS!S A~O CONDUCTOR OPTI~IZATION !"JSTALLfll COST BRE.AilflUwr~ cor.ouc 1 (1;1 GROilf'D"' T RE I ~!Sill~ l f!f-IS HARIJI'Af.:F Tf1 ,; F >-1 S F (1LP I[! A 1 I UN S RIGHI UF wAY (104FT) Sllb-TrJlhLS IOC E"lGI~•Et.PJNG PRESENT ~ORTH IDC E"JGTNElPlNG LOSS a~HLYSTS RFSISTANCF IOSSFS OUMiT I TY 15t\IH1, () . 2ll 7. !1,3 4. 3 1 3. COfWI'.A LUSSFS: l'lSUl ATf1-<S (.flr,;),IC T f1R TOTALS FT FT UNITS UNITS UNITS ACRES 0ATf: IS AUG 79 Tl"E.: 16:?9:16 • • COST QIITPUT >'F.4 "~ILE i-JPlSUJT VAll If RATE 7, 00 PfRCF'll * • • * * *•*•****'****•***'*A****t***** 2156, KOHL MATERIAL COST($) o905Q, o. 2957. .5219. QH')4/, 7493, 20/Jol. 2017?7. 89569. I 3 IJ 0 , F T S P A N 87,ll FT TOioifR TONNAGE !9,90 o.oo I . ILl 0,47 22.Ro PRESENT WORTH ($) TRANSPORTATION COST($) 4Ll76. 0. 5119, 107. 511J4, I 2 I I • 11487. 5100, INSTALLATION COST($) 41\9/JO, o. 63832. 50178, 18170. 181119. ------------------------------------------------------------------LlEMANO tOSSES 731119. o. . ] ENERGY LOSSE.S l t>6721. o. o. 6o 72 I • TOTAL LOSSES 1405110. 0. o. 140540. .J J TOTAL COSTCS) --··-·-- 122466. o. 3507. 3326. 1&7522. 58ij82. 38650. ···---- 39QTB. o. 113377. ------- TOTAL 1137710. 17508q, o. 19260. ------- TOTAL 19Q3Q9, J APPENDIX C MULTI-AREA RELIABILITY PROGRAM (MAREL) - SUMMARY I?RCGRAM ELEMENTS liND MODELS MULTI AREA RELIABILITY PRCGPJ\M (l'IAREL) SCHENECTADY, NEW YORK 12301 APPENDIX C !3ULIEI'JN PTI/103 Page 1 of 3 518 374-1220 The Multi-Area Reliability Program (MAREL) computes the Loss of Load Proba- bility (LOLP) reliability index for electric generating systems of several areas interconnected by a transmission network without any restrictions on the network top:~logy. The program permits the study of large r:cwer IXJOlS and reliability councils as well as individual utilities imbedded in an ex- tensive interconnection. The program is intended to be used in the design and analysis of generation systems and the interconnection capability re~ quirements needed to share reserves among the interconnected areas. The program may be used for as many as six or seven interconnected areas modeled directly. A greater number may be accommodated by developing equivalent systems. The output includes area and total system LOLP indices as well as data or the probable causes of failures and their locations in the network. The program structure is flexible so that load and capacity models may be as detailed as required and at the same time, the complex evaluation of ::he individual area reliability levels may be performed with efficiency. The structure of MAREL is shown in block form on Figure 1. Input data may be provided for each case or partially supplied by saved case files. ~e program structure is set up to analyze one year at a time under the control of the user. This facilitates the development of system expansions inter- actively or with a series of runs on a batch basis without the risk of the possibility of using excessive computer time. I ~J CAPACITY- PROIW3ILITY TABLES LOAD MODELS WJ!U<ING FilES FIGURE 1 MULTI AREA RELIABILITY EVAWATIW STRUCI'URE OF MULTI AREA. RELIABILITY PR<XiRAI1 c -1 SAVE FILES 1 PTI/103 Page 2 of 3 PF.C.GAAM APPLICATIONS • Loads are modeled by area with distributions of peak loads for each 'season' of the year. A season may be of whatever length is appropriate for the study, weeks, months, or longer intervals. • Capacity Models are developed for each area for each season of the year and are available capacity-probabil- ity density tables. • Maintenance Outages are simulated either by adding the capacity on outage to the appropriate area and season load model or by modification of the proper capa- city-probability table. Maintenance may be prescheduled and input or done automatically within MAREL by an algorithm designed to level available area generation reserves over the year. • Transmission Interconnections are modeled by the use of a linear flow network which models the limitations on individual tie line transfer capabilities considering their forced outage rates {if desired) without restric- tions on the network configuration or topology. • Program Controls are set by the user to establish the fineness with which the loads and capcities are rep- resented and to set tolerance levels on the LOLP com- putations to save unnecessary computer effort and cost. • Program Output may include area load and capacity models as well as maintenance schedules, three sets of both seasonal and annual area and SJstem LOLP indi~es, the probabilities of various failure modes. That is, the program automatically calculates area LOLP values as though the area were isolated and then two separate LOLP values with the actual interconnection. These two LOLP indices represent the extremes of possible operating policies concerning the sharing of generation reserves, {1) sharing only available reserves, and {2) sharing load losses up to the transfer limitations imposed by the network. Pailure mode probabilities show the prob- abilities and locations-of failures caused by generation shortages or transmission limitations as well as com- binations and indicate the probabilities that each individual tie may be limiting. These data are useful in developing reliable system designs. • System Size is not restricted except by limits on accep- table computational effort and cost. Past PTI system studies have included two interconnected reliability councils represented by nine or ten areas and incor- porating approximately 500 units for a total of 100,000 mw of generation. • • • Generation reliability level analysis which includes the effects of the interconnected system for the expansion planning of individual utilities and power pools. Planning of interconnections to achieve regional inte- gration and more widespread sharing of generation reserves. Evaluation of the reliability benefits of strengthening ties vis-a-vis additions to generation reserves. c -2 - r - !""'· ' Pri/103 AVl'.ILABILITY AND SUPPORT FOR FURTHER L"lFDRMATION l/78 • • • Page 3 of 3 Assistance in locating weak portions of a system in order to locate new bulk power facilities for maximum reliability improvement. Analysis of the reliability benefits of new joint- ly-owned plants located remotely or within one system's territory. Evaluation of the ability of individual utilities to re- liably survive the postponement of new plant additions in their own and interconnected systems. MAREL is available for use at PTI for studies by individual utilities or groups of systems. It may also be leased for installation on a client's computer. The lease entitles the user to: • Complete set of source code for all modules including all MAREL activities and subroutines. • Engineering and program reference manuals. • Installation on a suitable PRIME 400 computer at the client's site and a training seminar. Installation on other computers is feasible but will only be done on the basis of charging for the time and expense required. Since PTI is a consulting engineering organization and uses MAREL in studies for clients, the program is continually being enhanced and updated. While updates are not included in the MAREL lease price, PTI will offer all significant MAREL improvements to lessees at add-on prices. PTI can assist MAREL users in the development of system equivalents where their use is attractive to the user. Contact: C.K. Pang, Senior Engineer or A.J. WOOd, Principal Engineer Power Technologies, Inc. P.O. Box 1058 Schenectady, N.Y. 12301 Tel. (518) 374-1220 Telex 145498 POWER TECH SCH c -3 MULTI-AREA RELIABILITY PROGRAM (MAREL) SAMPLE OUTPUT SHEETS FOR TWO-AREA RELIABILITY STUDY -YEAR 1989 • Interconnected System Expansion Plans, with Firm Power Transfer (years 1984 through 1987 and 1992 through 1996) c -4 .-. I -"~} n (J'l ~~~<l ·"~"-~~-} Lc ) 4··:'} l '" -•~) ·-·~, "-j "" ... ~~ ) l ' IECREL *TIE89 0 1/ 1 8/79 1 1 : 01 PRT018 "'"'*:i<''';:**:!t*-"'*~~,.~*Oi::i:)/::i:~~*******:t.*****~~**~~~~:l:***********~<:::i:*******~***:l"-*~~:i:*:.':*~~***~~*:i:**:i:*~~:t:~":)/:;,"-"'t:l::i:'l/:;{.~~··"'··"**;~:(.::i(~~* ;·~· :Z*!''~**~~~*;.t:>(!:~:;:~:*~~~'!******~-;*<;,":*:.,~-:~:~'!*-'~*****~*;-:~**********-:t-i:**-*****:i:*********:.~.:t:*!r":*!t:*~~**:;:.**;·~**';("...;f:*~*!i~~:;*>,::f::t:::.<:::***:?.:.'~~ ., ... )/:)/: ** .... ~ ** .... ffi'th' h'hl\'WW mrw 11'1-ili'W "''WWWW w ~~* .... 1{ 1{ w w 1{ w ~{ 1{ ** ... ~ .... ~· 1{ II' 1{ w l{ ,., ** ····:--w 1.'\;I{W w 1{\·I'HW W'HWW ,., ** ..... w 1{ '"' HW H w ** ... ,, ,., 11' w w 1{ w w w· w ** ····· 1{\{1y 1\1il~V.'W wrrw w w "''h'W1oltT 1·mwww ** .. ..,. :.~* ...... ** .... ** ...... 1fhwlm \{\','\{ 'h'hli'IVW KlfH 1vV.'1v ** ;:; ;~: www w w 1{ 1Y w ,., w ** ····· "'"''\{ w w w w· ,., w w :~:;: ... 11'\V l1l'i' 1{ w ll"''·t'h"'\{ mvw "''h1Vll' ** ....... 11'lvl{ 1{ w w w w w ** !:!':,~ w w 1·/ w w "' 1{ ,., w ** ::· ~!: w Tfh"i{ ""~'''''W mm 1>.'1flY *-:!: . ~·-** ** .... ** ~-> **:t~:-:~~**~~**~!!!~.":~~~*~:***;t;r.::~*;f;;~~:.~**!f.**~~**':~*****~****;r..~~*:::~**~**********************;;:,****~*:t;*'****::t::t!***~*** ~.::.c~*"':;;:;<:i:**~**~'*~:*~~*:::~::i<~:******""**********~~*********~~***********************************************•~*:f.***** n ~ ... J '"' J POWER TECillrQLOGIES, INC. I-WLTI-AREA RE.LIADILITY PROGRAM: MULTI-AREA RELIADILITY PROGII.AM-MABEL -- ----VERSION : NOVE~lliER 15, 1978 ---- ----POHER TECHNOLOGIES, INC. ---- ********************** ** ** ** 01 -18 -1979 ** ** ** ****~***************** B T U D Y C A S E: **************************************************************************** ** ** ** ANCIIORAGE -FAIRBANKS TRANSMISSION INTERTIE. ECONmUC FEASIBILITY ** ** ** ** 2-AnEA ItELIADILITY STUDY-YEAR 1989 : INTERCONNECTED -l/15.11979 ** ** ** ************************"~*****;~********************************************* .) ;,,; J J J ) J J J .) l ~.) .J <._I j J .J POWER TECHNOLOGIES, INC. MULTI-AREA RELIADILITY PROGRAM' 1 ***:lt*******************;~:t.:l:******************************'******************** ** ** ** AllCHOI\AGE -FAIRllAJU<S TRANSMISSION ll'ITEI\.TIE ECONOMIC FEASIBILITY ** ** ** ** 2-hRF.A RELIADILITY STUDY-YEAR 1969 : INTERCONNECTED -l/15/1979 ** ** ** **************;r.************************************************************* YEAR OF STUDY = 1989 PROBABILITY T9RESHOLD = 0.10E-07 FAILURE PROB. THRESHOLD = 0.20E-08 PROD. RATIO FOR LOAD LEV.= ROUNDING MW STEP SIZE "' 0.0100 1 MAX. NO. OF AnEAS WITH NEGATIVE !1-\.RGIU TO DE EXANINED = 2 MAX. OF CAPACITY STEPS = -----SYSTErt DATA --- NO. OF AREAS OR BUSES 2 NO. OF AREAS WITH GENERATION = 2 NO. OF AREAS WITTI LOADS NO. OF LINES lHTll OUTAGES NO. OF FIRM LINES = = 2 1 0 50 n co .) J POWER TECITNOLOGIES, INC. MULTI-AREA RELIADILITY PfiOGRAH• AJICIIORAGE -FAIRDANKS TRANSMISSION Il'ITERTIE ECONOMIC "FEASIBILITY 2-AllEA IlELIABILITY STUDY -YEAR 1989 : INTERCONNECTED -1/13/1979 -----DATA FOfi LINES WITH OUTAGES ----- ---AVAILAnLE CAPACITY Pfi03AlliLITY --- LINE NO. 1, LinK NO. 3 TIE FROU AREA 1 ANCllOn -TO-AREA 2 FAIIlBA LEVEL CAP( FOR> CAPC REV> PfiODADILITY. 1 2 0 130 0 130 -TIME USED IN CPUS : INCREMENT = J 0.004000 0.996000 2, ELAPSED =· • 2 J· ) ' .·· -J J CJ {'•Y•c• ''') J-.. ,,) /~) " .. l ,---·,--) ~..,. ___ l ----l 1 ,...--_ ) ---l ·~\ --·-,c-} ') ~-. } '"l J POWER TECH10LOGIES, INC. MU1.. T 1-APJ.:A ru:L I ABILITY PTIOGRJ\M l GENEnATOTI UNIT DATA FOTI ANCHORAGE-FAIRBANKS STUDY 'f\10 lillEA SYSTEU JANUARY 15 1979 SUH!IARY ON CAPACITY, PEAK LOAD AND MAINTENANCE : AitEA ANCHOR. SEASON 1 2 3 4 5 6 7 6 C} IUSTALLED CAPACITY ( Mlil 1747 1747 1747 1747 1747 1747' 1747 1747 1747 PEAK LOAD C MWl 1200 882 789 752 729 725 826 886 1441 INSTALLED RESERVES n MW 547 865 958 995 . 1018 1022 921 861 306 \,0 PERCENT 45,58 98,07 121.42 132.31 139.64 140.97 111.50 97.18 21.24 CAPACITY ON MAinTENANCE < J'I.W) 0 135 227 256 286 287 188 122 0 RESERVES AFTER MAINTENANCE : MH 547 730 731 739 732 735 733 739 306 PERCENT 45.58 82.77 92.65 98.27 100.41 101.38 88.74 83.41 21.24 UNIT RETinEMENTS AND INSTALLATIONS t NO, U1l!T CAP<Mli> F.O.R. ItET/INST SEASON DATE 1 COAL 2 200 0.057 INST 1 1/1989 POWER TECIEWLOGIF..S, INC. ~1UL T I-AR..t.:A RELIABILITY PROGRAM' CEr!EfiATOI\ UniT DATA FOR ANCHORACE-FAIRB.hNKS STUDY TWO AREA SYST£1'1 JANUARY 15 1979 SUMMARY ON CAPACITY, PEAK LOAD AND JI1AINTENANCE ; AP.EA F AI RBA.c. SEASON 1 2 3 4 5 6 7 8 9 INSTALLED CAPACITY Otw> 335 385 385 385 385 385 385 385 385 n PEAK LOAD < ffi{) 274 177 135 119 112 130 136 166 313 ~ 0 INSTALLED RESERVES l1W 111 203 250 266 273 255 249 219 72 PERCENT 40.51 117.51 185.19 223.53 243.75 196.15 183.09 131.93 23.00 CAPACITY ON l1AINTENAIICE <m{) 0 14 55 72 100 65 54 25 0 RESERVES AFTER MAINTENANCE : H1'1' 111 194 195 194 173 190 195 194 72 PERCENT 40.51 109.60 144.44 163.03 154.46 146. 15 143.38 116.87 23~00 UNIT RETIRENENTS hND INSTALLATlONS t riO. U1HT CAPOni> F.O.R. RET/INST SEASON DATE .....•... ) ) ) j .) _ .. -, .. J ) ) ) ,~ ,} J ) --_) ',..~, ~-J ,J l .. _ ~.1 ~ J ·~ -.,-·-: ''\ y-' ) 1\ l 1 n t-' 1--' ~,~, ,.--·-----} ') c) <--, POWER TECITNOLOGIFS, INC. HULTI-AREA RELIABILITY PROGRAM ". -··<>) . --~, - l CENEilATOR UlflT DATA FOR ANCHORAGE-FAIRBANKS STUDY THO AilE!\ SYSTEM JANUARY 15 19?9 Sillii11\RY ON CAPACITY AND PEAK LOAD BY AREA AREA ANCHOR FAIRBA ------------ PEAK LOAD SEASON 9 9 fNSTilLLED CAPACITY CMW> AT AIIUUAL PEAK 1747 385 ANNUAL PEAK LOAD < '!'I'b') 1441 . 313 IITSTALLED IlESEHVES ( MlO 306 72 RESERVES IN PERCENT OF JIJINUJ\1. PEAK LOAD 21.24 23.00 ARE.4. HE I GHTED AVERAGE Uli IT FOR < PERCEHT) 5.46 ?.42 AREA ANNUAL A VEilt\GE l't\ l NTENAilCl~ 9.65 11.11 ) } j J ?Oli'E.Il TE.CITNOLOC I ES, INC. TWLTI-AREA RELIABILITY PflOGRAM: CENEMTOR UNIT DATA FOR ANCHORAGE-FAIRBANKS STUDY THO AI\EA SYSTEM JANUARY 15 1979 -----SUfflfARY BY AREAS---- AREA flO. OF UNITS CAP. (1111-1) 1 ANCHOR 2 FAII\DA ---------------------36 24 1747 385 SEASONAL IlESEriVES IN PERCEUT OF PEAK LOADS AFTER MAIHTEriANCE OF UNITS FOR TilE TOTAL SYSTEM · SEASON RE~ER\'""ES ORDER SEASON RESERVES ------------------------1 44. 6<!·~4 1 9 21.5:307 2 07.2521 2 1 44.6404 3 100.2164 3 2 87.2021 4 107. 1132 4 6 8fl.613R2 5 107.6100 5 7 96. 4.·657 6 1CO. 1H71 6 3 100.2164 7 96.4657 7 4 107. 1182 8 a a. 6.!132 8 5 107.6100 9 21. tl507 9 6 100.1871 . ) ~l .J ; .J ~!f-• J .. J J -... ~ J I ) J ··. J ,,,,~ -1 -···J ----) n ....... w --1 ) --J POWER TEC~~OLOGIES. INC. i'IULTI-J\nE,\ RELIABILITY PROGRAM' ) ~J J ) CF.NEMTOR UNIT DATA FOR ANCHORAGE-FAIRBANKS STUDY THO ArtEA SYSTEM JANUARY l:J 1979 J MAINTENANCE SUN:r!Al\Y BY MW AND PERCENT OF TOTAL AREA CAPACITY c SEASON AREA ANCHOR AI\EA FAIRDA ---------------------------- 1 0 o.oo ·0 0.00 2 13() 7.73 14 3.64 3 227 12,99 55 14.29 4 256 14.65 72 13.70 5 286 16.37 100 25.97 6 287 16.43 65 16.86 7 lll3 10.76 54 14.03 8 122 6.93 25 6.49 9 0 0.00 0 0.00 AREA EFOil 5.4550 7.4169 SYSTEM EFOR = 5.8093 EFOR : WEIGDTED EFFECTIVE FORCED OUTAGE RATE_Ilf PERCENT. *** END OF PROGflAM MNTCE *** Tim: usED m crus INCREMENT = TINE USED IN CPUS INCREl'IENT = t'** AREA 1 ArlCIIOR ll/\S NO UNITS ON *** ~:t:* HAlNTEHAHCE FOR SEASpNS .: 1 9 fl'** *** AREA 2 FAinnA HAS NO UNITS ON *** 2. ELAPSED = 0, ELAPSED = 4 4 ) ' -} ;<;;j,;~ HA I NTENA!lCE FOR SEASONS POllER TECnNOLOGIES, INC. l'!ULTI-AREA RELIAIHLITY PROGRAJif M:cnoM.CE -FA.IlillMII<S TRANSMISSION IftTERTIE ECONOMIC FEASIBILITY 2-A.REA IlELIAlliLITY STUDY -YEAR 1989 : INTERCONNECTED -1/U/1979 ---LOSS OF LOAD PRODABILITY AT VARIOUS AREAS --- AT AI\EA PRODABILITY ISOLATED PRODABILITY WITII LLS PROBADJLITY WITHOUT LLS 1 ANCllOR 0.149268E+00 0.798471E-01 0.676829E-0l 2 FAIRBA 0.190494E+01 0.90967~E-Ol 0.394379E-0l SYSTEU 0.915377E-01 0.915377E-01 NOTE : LLS = LOAD LOSS SHARING ***** ALL PRODADILITIES ARE IN DAYS/PERIOD ***** --.I "-~• I J '~'" _J PO~~R TECa~OLOGIES, INC. rfULTI-AitEA RZLIAIHLITY PROGRAM' 1\NCHOMGE -FAIRDANKS TRAl'fSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AnEA RELIADILITY STUDY -YEAR 1989 : INTERCONNECTED -l/15/1979 PROD/I.BILITY OF :mNHIAL CUTS - CUT PRODADILITY CUT MEMBERS<LINXS> 1 0. 792771£-0 1 2 2 0,570032E-03 1 3 3 0.116904E-01 2 3 ***** ALL ~RODf~ILITIES ARE IN DAYS/PERIOD ***** J J .J J J ~• ,_} _,l ~ .. ;J ,J ~ _, • -- , ("") ...... -.....! 'J POWER TECflNOLOGIES, INC. JIWLTI-AREA RELI.I\BILITY PROGRAM! AI1CIIOMCE -FAIIUl.i\NKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AH.EA HF.LIAIHLITY STUDY -YEAR 1909 : INTEnCONNECTED -1/151'1979 --MINIHAL CUTS AND DEFICIENT NODES<AREAS> --- CUT PfiODADILITY NODESCARE.i\S) IN DEFICIENT REGION ----------------------------------------~- 1 0. 79277 lE-O 1 1 AllCIIOR 2 FAIRBA 2 0.510032E-03 1 ANCIIOR 3 0.116904E-01 2 FAIIIDA ***** ALL PRODADILITIES ARE IN DAYS/PERIOD ***** n POllER TECIIDOLQGIES. INC. !·illLTI-ARE.!\ P..ELIABILITY PROGRAM AUCIIOMGE -FAinBANI<B TRANSMISSION INTERTIE EGOlVOJ.IIIC FEASIBILITY 2-AREA. 1\ELI./\BILITY STUDY -YEAR 1989 : INTEllCONNECTED -l/15/19?9 LirfE LINK PilOEADILITY TIIAT EACH LINE IS LIMITING --- DESCRIPTION TOTAL A R E A TO A R E A PRODADILITY FORWARD DIRECTION REVERSE DIRECTION 3 t ANCHOR TO 2 FAIRDA 0.t22604E-01 0~116904E-Ol 0.5?0032E-03 ***** ALL PRODABILITIES ARE IN DAYS/PERIOD ***** _,I .J .-J _l ,I I J .I J ,J ~-···F••• _} ------] ""l --J n -\.0 -.-·-·-'] "-] 1 1 -----1 .~ --1 c.<·~~: J l ] 't l li POWER TECirn'OLOGIES, INC. MULTI-AREA RELIABILITY PROGRAM: sEAsON ----- l 2 3 4 5 6 "l 8 9 YEAR ANCHORAGE -FAIRDANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-/IIlEA R.ELIADILITY STUDY -.YEAR 1989 : INTERCONNECTED -l/15/1979 ISOLATED S ITUATJON -SUMMARY : AREA LOLP IN DAYS/PEniOD BY SEASONS•' J\Il.EA AltEA ANCITOit FA I RnA ------------ 0.0021 0.3096 0.0000 0.0071 o.oooo 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 o.cooo 0.0000 0.0000 0.0000 0.1472 1.5DB2 0. 1493 1.9049 J ] ... · l n N 0 o.l .?OWER TECITI'iOLOC I FS, I l'TC. HULTI-AREA RELIAI3ILITY PROGRAM" AlfCIIOI\AGE -FAIRDANKS TRANSMISSION Il.'ITERTIE ECONOMIC FEASIBILITY 2-AREA RELIABILITY STUDY-YEAR 198«) : INTERCONNECTED -1/15/1979 ISOLATED SITUATION -SUNHARY : EXPECTED N1i-DAYS LOSS BY SEASONS. AflEA AREA SEASON ANCHOR FJ\InDA ------------------- 0.09 7.45 2 o.oo 0.14 3 o.oo 0.00 4 0.00 0.00 5 0.00 0.00 6 0.00 0.00 7 0.00 0.00 B 0.00 0.00 9 3.87 44.23 YEAR 8.9548 51.3097 .J J J -_y .J .J .I .. l <· t J J I J l ~-·-1 n N 1--' ''] ,,~-] ..... ,-,·-1 J PO~~ TE~P~OLOGJES, INC. r::-JLTI-AHEA Il.ELIJ\BILITY PROGRAM' -.-, ~-. <-·"C--' '] ·---) -~ ArlCIIOMGE -FJ\IRBJ'.NKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-J\I'..EA llELIJ\niLITY STUDY -YEAR 1989 : INTERCONNECTED -l/15.11979 ISOLATED S ITU/\TION -SUfofi'IARY : EXPECTED MH DEFICIENCY DY SEASON. ArtE/\ AilE A SEASON ANCllOil FAIIlBJ\ ------------------ 1 42.38 24.04 2 13.37 19.22 3 0.00 0.00 4 o.oo o.oo 5 0.00 0.00 6 o.oo o.co .7 0.00 0.00 8 o.oo 0.00 9 60.24 27.85 INDICES FOR TilE YEAR MW-DAYS 8.95 31.81 LOLP-DAYS 0. li; 1.90 E( IDD 59.99 27.20 I ""'"'-) l n N N J I I POf.'ER TECHnOLOGIES. INC. HULTI-ArtEA nELIAlliLl'I'Y PROGRAJ11 SEASON ---- 1 2 3 4 5 6 7 8 9 YEAR _) AllCI!OMCP.. -FAIIIDANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILI'IY 2-/\nEA IlELI!illiLITY STliDY -YEAR 198') : INTERCONNECTED -1/l:i/1979 INTERCOrH!ECTED UITII LOAD LOSS SIIJ\RING Ail.EA LOLP IN Di\YS/PERIOD DY SEASONS. AilE A AREA ANCHOR FAIIUlA ------------ 0.0004 0.0020 0.0000 0.0000 0.()000 0.0000 0.0000 0.0000 0.0000 o.oooo 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0794 0.0890 0.0798 0.0910 i.,._,,l ,_ __ J ' .. J ~"-~J -~~-'-' .I J I I . ~, ... 1 J ) n N w ] l -J POWER TECHNOLOGIES, INC. ~TI-AnEA RELIABILITY PROGRAM: -1 1 ANCllOMCE -FAIRBANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-i\REA RELIABILITY STUDY-YEAR 1989 : INTERCONNECTED -l/15/1979 • INTERCONNECTED WITII NO LOAD LOSS SHARING AREA LOLP IN DAYS/PERIOD BY SEASONS. AREA AREA SEASON ANCI!OR FA I IillA ---------------..... 1 0.0003 0.0017 2 0.0000 0.0000 3 0.0000 0.0000 4 0.0000 0.0000 5 0.0000 0.0000 6 0.0000 0.0000 7 0.0000 0.0000 8 0.0006 0.0000 9 0.0673 0.0378 YEAR 0.0677 0.0394 -l .J .J ,) J (_, __ J J POWER TECmlOLOGIES, INC. MULTI-AltF.A RELIABILITY PROGRAM: AJ;cnoRACE -FAIRBANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AREA nELIABILITY STUDY·-YEAR 1989 : INTERCONNECTED-l/15/1979 ---SYSTEM RESULT STJmfARY IN PER UNIT -- PROOABILITY OF SUCCESS EVENTS PROrlABILITY OF FAILU11E EVENTS "' 0.999648E+00 = 0.352068E-03 PROOABILITY OF NEGLECTED UNSPECIFIED EVENTS!= 0.270125E-08 SUM OF TIIE ABOVE 3 PROBABILITIES ,.. 0. 100000E+Ol PROBABILITY OF UNCLASSIFIED FAILURE EVENTS = 0,620649E-09 *************************************************** *** NOTE: TIIE SUU OF THE FlllST 3 ~lUST BE 1.0000 *** *** 'HTIHN REASONABLE TOLERANCE. *** *************************************************** DEFINITION OF EVENTS : SUCCESS ALL LOADS SATISFIED. FAILURE orm OR ~IOilE AREA LOADS NOT SATISFIED. UNSPECIFIED : NOT IDENTIFIED AS EITHER SUCCESS OR FAILURE. UNCLASSED FAILURE : CAUSE OF FAILURE NOT ESTABLISHED. CAUSE OF FAILURE IS INDICATE!) BY MINHIAL CUTS. TOTAL ELAPSED TilliE IN CPUS = 20 ***** END OF PROGRAM l'IAREL ***** J ~J J .I -. J .~---~ .I "··J J ~ _;,:.:;;.' J .... J .I N Ul ... --) ... J ] Al!Cl!ORAGE -FAIRBANKS TRANSMISSION INTERTIE ECONOMIC FEASIDILITY ANCITORACE -FAinDAUKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AREA nELIADILI1Y STUDY -YF~ 1996 : INTERCONNECTED -1/15/1979 2 1 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 1 1 1 4 1996 O.lE-07 0.2E-07 0.5E-05 0.010.10 2 1 50 2 1 0 2 2 ANCilOilFAinBA 1 2 2' 0 0 0.004009 2 130 130 0.996000 I.OAD DATA m PER UNIT INTERVAL DURATION CURVE TWO AREA SYSTEH JANUARY 15 19?9 1 1 1 2 10 26 9 14 1933 1 0. 01 1., 00 0 1 1 1 1 1 1 2 2 3 3 4 4 s 5 6 6 ? ? a a 9 9 9 9 9 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 AilCIIOR 20 0. 0 781. 077. 977. 1080. 1196. 1313. 1441. 1531. 1724. 1881. 2041. 2215. 2402. 2591. .8333 .6667 .7404 .75CO .6571 .6346 ,6122 .5U65 .5401 .5353 ,5224 ,5160 .5064 .4904 .:032 .4960 .5160 .6737 .5769 .6154 .6827 .8429 .0626 .91351.0000 .8301 1.0000 .9769 .9731 .9538 .9500 .94G2 .0962 .3731 .057? .8423 1.0000 .93~3 .9663 .9663 .9615 .9615 .9G19 .9519 .9423 ~9375 1.0000 .9913 .9784 .9C27 .9697 .9654 .9437 .9307 .9221 .8918 1.0000 .9829 .9187 .9359 .9017 .8089 .flflR9 .UU46 .0333 .C934 1.0030 .9512 .9317 .9171 ,9171 .9073 .9073 .9924 .9024 .0976 ~0000 .9340 .9793 .9747 .9646 .9495 .9444 .9343 .9293 .9141 1.0000 .96C6 .9G34 .9329 .9G29 .9476 .9424 .9372 .9050 .9038 1.0030 .9701 .9727 .9617 .9G63 .9363 .9344 .9341 .9071 .9071 1.C030 .93C3 .9~83 .9225 .9E25 .9703 .9703 .9649 .9391 .9415 l.CO:>O .99";0 .9[120 .9701 .9GC1 .9461 .9'!·01 .9311 .92Bl .9162 1.0000 .99n9 .9077 .9G71 .9571 .9509 .9509 .9~~8 .9202 .C589 1.0000 .99J8 .9814 .9609 .9365 .9379 .9379 .9379 .9253 .9255 1.0030 .9810 .9681 .9620 .~4~4 .9494 .9430 .9367 .9204 .9177 1.0000 .9004 .9739 .9739 .9673 .9608 .951~ .9542 .9477 .6824 1.0000 .9073 .9745 .9554 .9493 .9490 .9427 .9427 .9219 .9299 1.C0001.C~OO .993J .0871 .9~~~ .9743 .9677 .9613 .9G40 .94C4 1.0030 .9930 .9H14 .96fi9 .9627 .9563 .9GG3 .9441 .9441 .9379 1.oooo .9777 .9G09 .9411 .9274 .9106 .eeu3 .G715 .D?l5 .G015 1.0000 .9944 .9944 .9722 .9722 .9722 .9611 .9273 .9222 .9222 1.0030 .99?3 .9C96 .90?6 .9607 .95~3 .9~31 .9375 .9323 .0002 1.0000 .933~ .9~C4 .9~J7 .9390 .9296 .92~9 .9202 .91~5 .9014 1. 0000 . 9962 , 96SG . 9'!6D . 9'!63 . 90C7 . 79B5 • 775.7 . 7719 . 11535 1.00001.0000 .~UC7 .9662 .9549 .9511 .9474 .9393 .9361 .9323 1.0300 .9754 .8632 .0596 .C421 .83H6 .G335 .8386 .D3C6 .6175 1.0000 .9840 .9679 .9519 .9359 .9327 .9327 ~9135 .0654 .0045 1.0000 .9730 .9730 .9614 ,9614 ,9575 .9575 .9537 .9421 ~6340 2 FAinnA 20 0.0 196. 212. 231. 249. 270. 291. 313. 338. 362. 390. PAGE 0001 .. J N m AJICIIORAGE -FAIRBAr{f".S 'I'I\i\NS.MISSION HITERTIE ECONO!I!IC FEASIBILI1Y ?16. ~46. <,77. 511. o. :)7:;90. 69900.737 10.76040.57490 0 59710.56630. 51110.43240 J 41150.38330.37470.3587 0. 353C~. 33~ao. 41770.42010.43730.46190.53 ICJO. G74?0. 139190,93370,934~ 1. 00000.7690 1. coono .. 9?4:!~. 9~670. 946?0 .94·~30. 93130. m4nO. 3654·0. n~·~9o. B177 1 • G" JC 0 o 93670 o 92790. 92700. C) 05 10. C')l)g(). Cfl!)GO. G:'i9·~0. 13!!790. 7BC) 1 1. cc:;;:o. 993:~0. 96670. 94r:.:w. 94ooo. 92330. 903~30. i!WJo.a. GuG7o. e267 1. CG:)J0. 97;j~!').% 120, 9"!::; 10. C6910. C320~. ~~390. C 1100.79000 J 67'69 1 .l:OvOO. 935(J0. 93290.%94.0. 95300. 94560. 91BBO. 901110.90170. Gu25 l. OO:'JOJ. 997()0. 99590. 9B770. 979<!0. %Cl!O. 93620. 90;}30. 0 1)300. CC27 l.COJC0.9U~n3.95010.93710.91970.89370.Ce~70.87200.86129.E09l 1. OCJCO. 96G70.% IGO. 95190.93510.91500. 8n700. lli!220. 8798~. 8550 l.OOJ00.99150.991~0.99150.97160.96870.03lfl9.8~200.fln020.8693 l.OOJOl.OGGC0.95120.93130.92~40.92810.92340.90750.901~0.8055 1. CC;);;J. 990<·0. 9')0'10. CJ<!.350. 92310.91990 ,I) 1670.91350. B'7B~O. fl55fl 1. 0(/J~·J. 967~d.%410. 0271)0. 92160.90490. fiJB'!!O. G% 10. B7e70. 8721 l.OC~C0.96920.96020.958~0.95H90.94G20.94J23.931G0.92120.9041 1.00~~~.~G9G0.97220.96870.95330.94790.93100.92360.92010.0507 l.OOJCJ.96770.93U70.93230.91290.90J20.90320.90320.U7100.R677 l.G0000.373~0.C7060.06760.C6460.8~833.8~7l0.81110.83B20.8059 1. OOJ:)O. 9·~.-:~o. <;CMO. 90;&<:.0. f./)470. G27GO. i3:!7GO. n::N60, EH B70 • UO 12 l.COOC0.99'l20.977~0.96350.963G0.940~0.9nD20.93320.91010.8904 1.C00~0.99~?0.96810.93C90.92820.90960.90690,90160.8RD30.8836 1.COOC0.93~J0.93300.91450.90990.R9610.0CJlO.Cn450.86370.8568 l.C01C0.991G0.9BDC~.97650.9~~20.92950.92740.91C39.91450;9017 1.COJC0.96690.911C0.892GO.COC40.79890.73970.64460.61020.60B8 1.C01C0.97710.910G0.90790.90790.89340.80~50.88~50.R6320.8434 l.COJGJ.9?110.86330.83050.81870.79fi30.79240.74510.73320.7201 l.C0CC0.90510.9Bl60.97300.97170.95533.91650.084G0.02430.6010 ! . CO;)GO. 900!,.0. 93930. 92C 10. S99·HL flfl,{)~m. 3BJOO. 84320. Gl310. 7971 G£Ti£ItATCH UriiT DJ\TA FOR ANCIIORAGE-FAIIillJ\IHCS STUDY TI.'O AilEA SYSTEH JANUAitY 15 1979 1 1 1 •2 1 l.OE-12 AHCHOR 44 12 1. () 1 AHCII 1 2 1\flCil 2 3 AnCfl 3 4 "..I:cn 4 5 .J\IICH 5 6 r,r:cn 6 7 AHCf! 7 0 AHCII7S 9 tJICH 0 10 BELU 1 11 c:::LU 2 12 llELU 3 13 IlELU 4 14 n:.-:LU 5 15 BF.LU 6 16 U:::LU 7 17 I~E.LU B tn DEitlf 1 19 r.~mr 2 ::o .m:.IUl 3 15 0.005 15 0.055 19 0.055 32 o.orm 37 0.055 12 o.o:m 73 0.055 21 o.o::m 73 0.055 15 0.055 15 O.CGG 54 0.055 9 0.055 5·~ 0.055 60 O.C55 63 O.C35 60 0. 035 B 0.055 20 0.055 24 0.055 .J .J PAGE 0002 J .. J .... ) ~--1 ' --~ ---] ,_ -J ---1 1 -~----I _,,_ 1 ---1 -~'1 -1 -1 1 i\NCITORAGE -FAII\BANKS Tll.ANSHISSIOH INTERTIE ECONOUIC FEASIBILITY PACE 0003 21 INTL 1 14 0.055 22 IUTL 2 14 0.055 23 INTL 3 19 0.055 24 COOP 1 B 0.016 25 COOP 2 B 0.0t6 26 Krl!T A 15 0.059 R · l/1986 27 IJiTL 4 71 0.035 23 IIITL 5 71 O.O:i5 29 INTL 6 71 0.0:35 30 IJIT'L 7 71 0.055 31 l!O::Erl 1 O.O::i::i 32 EKLliTH 30 0.016 33 UZLU 9 71 O.OG::i N 1/1986 34 ,ua;u 9 70 0.05:) N l/1985 3:3 AI1CJI10 104 0.057 rf l/1986 3& COAL 1 200 0.0:::)7 N 1/1937 37 AIICII 11 10<1· O.OJ7 n 1/1993 .,.., uu COAL 2 200 O.OJ7 N 1/ 19G9 39 COAL 3 200 0.057 N 1/1990 40 CO;\L 4 200 O.O::i7 N 1/1991 41 CO.'\L 5 200 0.057 N 1/1992 .n 42 I'CAKi\1 7B 0.055 N . 1/1993 43 CEll 1 300 0.079 N 1/1994 4-J. GEH 2 3CO 0.079 N 1/1996 N 45 PEAKI\2 7B 0.055 N 1/1995 '-J -99 COOP 1 COOP 2 EKLUTN -99 1 9 -99 .FAiflDA 26 12 1.0 1 CITE IT 1 5 0.059 2 cm:n 2 2 0.059 3 cnr~n 3 2 0.059 4 CIIEU 4 20 0.059 r. CIIEH 5 5 o.o::m ... 6 CHEN 6 24 O,O;j5 7 !JIES 1 3 0.29G {} Dlf.S 2 3 0.295 9 DIES 3 2 0.295 10 ZEEH 1 17 0.055 11 ZEEI'l 2 17 O.OJ::i 12 ZEllrl 3 4 0.0()5 13 ZEHU 4 ·1-o.o::;::; 14 zt:r:HDi :1 0.295 15 7.El!HD2 3 0.!<:05 1u ZE!IiiD3 3 0.20:i 17 ZEBHD4 2 0.295 tn ZEt:rm5 2 0.:?.95 19 IJE!\L 1 26 0.059 20 UEAL D 3 0.,295 N cc .... 1 J Ail'CIIOIL4.GE -FAIRDANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 21 n:mT 1 ::!2 HO!'.T 2 ::!3 u:..LASK ::!5 COALFl ::!7 CO/\.LF2 213 COALF3 -1)9 -')9 1 9 -99 65 0.055 6() 0.055 5 0.295 100 0.057 N 100 0.057 N 100 0.057 N .J .... J ; ' J . ,,_,,,) l/ 1988 l/ 1992 l/1995 PAGE 0004 , , .I I APP~NDIX D DATA AND COST ESTIMATES FOR TRANSr11ISSION INTERTIE AND GENERATING. PLANTS """' ! 0.1 """"" A. I !"""- !"""' r r- !"""" ,....., r r- II""'\ APPENDIX D DATA AND COST ESTIMATES FOR TRANSMISSION INTERTIE AND GENERATING PLANTS DATA AND COST ESTIMATES FOR TRANSMISSION INTERTIE Cost Summary and Disbursements for Intertie Facilities Total Cost at 1979 Levels -$1000 Case IA Case IB Case IC Case ID Case II 1. Transmission Line: Eng•g. & Constr. Supv. 3,012 3,012 7,988 3,012 15,442 Right-of-Way 8,837 8,837 7,573 8,837 12,994 Foundations 8,445 8,445 12,160 8,445 22,966 Towers 21,615 21,615 33,990 21,615 64,974 Hardware 477 477 477 477 1,096 Insulators 503 503 755 503 1,396 Conductor 10,761 10,761 17,663 10,761 361946 Subtotal 53,650 53,650 80,606 53,650 155,814 2. Substations: Eng•g. & Constr. Supv. 1,352 1,352 1,855 2,816 6,902 Land 57 57 46 81 185 Transformers 1,703 1,703 3,291 1,703 11,917 Circuit Breakers 1,093 1,093 1,323 1,953 6,410 Station Equipment 1,223 1,223 1,933 1,345 4,375 Structures & Accessories 3,628 3,628 3,978 4,026 16,411 Subtotal 9,056 9,056 12,426 11,924 46,200 3. Control and Communications: Eng•g. & Constr. Supv. 125 125 125 165 200 Equipment 2,375 2,375 2,375 3,135 3,600 Subtotal 2,500 2,500 2!500 3!300 3,800 Total Baseline 1979 Costs 65,206 65,206 95,532 68,874 205,814 Capital disbursements for each of the above cases are given on following computation sheets, these being identical to those later used for financial planning purposes with selected alternative. 0 - 1 CAPITAL INVESTMENT DISBURSEMENTS FOR TRANSMISSION INTERTIE CASES lA & IB 1. TkANSHISSION LINE ENGINEERIN& AND CONSTRUCTION SUPERVISION RIGHI Of. ~jAY fOIINIJAIIIJN:l 10WE~S HARDWARE JNSULATOHS CONDUCTOR SUe-TOTAL 2. SUBS lA Tl ONS ENGINEtRING & CONSTRUCTION SUPERVISION LANO TRANSFORMERS CIRCUIT BREAKERS STATION EQUIPMENT STRUCTURES & ACCESSORIES SUB-TOTAL. 3. CONTROL. ANO COMMUNICATIONS ENGlNEtRING ANO INSTALLATION SUPERVISION EQUIPMENT 19131-1 452 0 0 0 0 0 0 270 57 0 i) 0 0 0 0 1961-2 70:.3 U09 u u 0 0 0 29&2 270 0 0 0 0 0 270 0 0 1'182-1 0 &&2~ 0 0 0 0 0 ooc6 270 0 .341 219 2115 72b 1800 0 0 1982-2 '392 0 UIIO 0 0 0 II 2&72 270 0 590 383 428 1451 3128 0 0 1983-1 o'1.3 0 td ll'l 'HiT 72 ~~ 1b14 1634b 135 0 59b 383 428 11151 2'193 0,4 95\) 1983-2 723 II 0 11888 405 428 9147 225'11 135 0 170 109 122 0 ~37 71 11125 TOTAL 3012 8837 Hllll'l 21615 477 503 107&1 53oso 1352 57 1703 1093 1223 3o28 9o5o 125 2375 ----------------------------------------------------------------------SUB• TOTAL. TOTAL TOTAL FOR YEAR 0 779 0 0 0 3233 1:1428 4012 0 0 1004 1119& 2500 5800 20!342 24o24 b520b 14226 0 4&9o7 b52Ub CAPITAL INVESTMENT DISBURSEMENTS FOR TRANSMISSION INTERTIE CASE IC 1. TRANSMISSION LINE EN~INEERING AND CONSTRUCTION SUPt:.RVISlCI'I fllG11T OF I'!AY FUUNlJAflUNS il)•IFHS "IAiW~AHE I NSIJL ~ l ORS COtl'llJC TOll SUIJ-TLITAL 2. SUBS TA 1I ONS lNGI~Et~lNG & CONSTRUCTION SUf't':i1YJ::ilUN I. Mill I H ~NSFllHMERS ~!NCU!T HRlAKERS STATION [~UIP~ENT ST~UCTURES ~ ~CCESSORIES 1981-1 1198 0 0 0 0 0 0 11'18 371 Ill> 0 0 0 0 SuH-TOTAL 417 l. CONTHOL AND COMMUNICATIONS ENGlNEEfllNG ANU INSTALLATION SUP~~V!SION 0 EQUIPMENT 0 1961-2 1997 1a•n 0 D 0 0 0 3690 371 0 0 0 0 0 371 0 0 1982-1 0 5b80 0 0 0 0 0 5b80 371 0 o':i8 2o5 387 79b 247o 0 0 1982-2 1038 0 3283 0 0 0 0 4322 371 0 J 152 lib! o77 1591 4254 0 0 1963-1 1837 0 8877 15290 72 113 2649 28844 16b 0 1152 llb3 b71 1591 40b8 54 950 1963-2 1917 0 0 16&95 405 &42 15014 3bb12 16& 0 329 U2 193 0 840 71 1425 TOTAL 7988 7573 121b0 33990 477 755 17bb3 80b0b 160:.5 4o 3291 1323 19H 3978 125 ins ----------------------------------------------------------------------sue-TOTAL TOT.&L TOTAL F OH YEAR 0 1&15 0 0 112o1 587& 0 8156 0 0 - 2 0 8575 16731 10011 3391& 0 1496 391109 72925 2500 95532 .95532 - - - - - - - CAPITAL INVESTMENT DISBURSEMENTS FOR TRANSMISSION INTERTlE CASE ID t. TRANSMISSION LINE ENGINEERING AND CONSTRUCTION SUPERVISION RIGHT OF WAY f0UNOAT10NS towfH!I HARDWARE INSULATORS CONDUCTOR SUR-TOTAL 2. SUBS TA liONS ENGINfERING & CONSTRUCTION SUPERYISlON LAND TRANSFORMfRS CIRCUIT BREAKERS STATION EQUIPMENT STRUCTURES & ACCESSORIES 1152 0 0 0 0 0 0 1152 56'5 81 0 0 0 0 753 2209 n 0 0 0 0 2962 'i63 0 0 0 0 0 0 6628 n 0 0 0 0 6628 563 0 '5111 391 ?69 805 198?-? "i92 n ??110 0 0 0 0 2672 563 0 "i96 684 471 1610 693 0 tolt>"i 9727 72 75 l6lll 18346 ?8? 0 596 684 1171 1610 723 0 0 11!18!1 liO"i 1128 9147 22591 ?82 0 170 195 B5 0 TOTAL 3012 88]7 flllll"i 21&15 471 503 10761 'i3650 2816 81 1703 1953 1345 4026 ---------------------------------------~------------------------------SUR-TOTAL 3. CONTROL AND COMMUNICATIONS ENGINFERING AND INSTALLATION SUPERYISJON EQUIPMENT SUB-TOTAL TOTAL TOTAL FOR YEAR 0 0 0 1096 0 563 0 0 0 3525 11&21 2369 0 0 0 0 0 n 0 b"i96 15"i9? 3642 71 1254 1325 23313 0 782 911 1881 25348 118661 119211 lbr; l13'i BOO 688711 688711 CAPITAL INVESTMENT DISBURSEMENTS FOR TRANSMISSION INTERTIE CASE II 1. TRANSMISSION LINE ENGINEl~lNG AND CONSTRUCTION SUPERVISIO"l R!GHf OF WAY fOUNDhflONS TU><Ek3 HA><O>tAHE l~"::uLA TORS LUNDu~TOH SU!l•TOTAL 2. SUfiS! ATIOI~S t~GI~EE~!NG & CONSTRUCTION S<JPi:.><VI;;!ON LAc<D Ti<A'JSFllRMEf<S CIMLU!l HMEAKERS STAilON EQUIPMENT STHUC1URtS & ACCESSORIES 1981-1 2316 0 0 0 0 0 0 23!b 1360 185 0 0 0 0 SUB-TOTAL 15b'5 3. CONTHUL AND COMMUNICATIONS tN~INEtR1NG ANU INSTALLATION SUPERYlSIUN 0 tUUIPMtNl 0 1981·2 l861 32119 0 0 0 () (i 1360 0 0 0 0 !) 1380 0 0 1982-1 0 9114b 0 0 0 0 () 1380 () 2383 1282 875 3282 9203 0 0 1<;82-2 2007 0 o20t 0 0 0 il 8208 1380 0 1:171 22414 1'531 6564 15890 0 0 1983-1 3552 0 1b7b5 29238 1bll 209 551.12 551171 690 0 4171 22411 1531 b5bll 15200 86 111110 1983-2 .HOb 0 0 l573b 932 1187 31140'1 72964 690 0 1192 6'11 4l6 0 2960 114 21!>0 TOTAL 1511112 12994 229M 6li97U 1096 1396 3&9'16 1558111 b902 185 11917 !>'110 ll.HS 16411 116200 200 3600 ----------------------------------------------------------------------SUB-TOTAL 0 TOTAL 3882 TUUL FOR YEAR 0 0 81189 12371 D - 3 0 189118 0 0 1526 2271l 3800 211099 72197 78198 205814 1130117 0 150396 205814 B. Case IA & IB, Anchorage-Fairbanks Intertie, 230 kV s/c Transmission System, 323 Miles 1. Cost Summary T/L Cost @ $166,104 per mile Anchorage Substation Ester Substation Control and Communications System TOTAL 2. Anchorage Substation Costs 1 138-kV Circuit Breaker Structures and Accessories 1 138-kV Air Disconnect Switch Structures and Accessories 4 13.8-kV, 12-MVAR Shunt Reactor Bank Structures and Accessories 4 13.8-kV Circuit Breaker Structures and Accessories 4 13.8-kV Air Disconnect Switch Structures and Accessories 4 10 -48 MVA, 138/230-kV Autotransfonner Structures and Accessories 2 230-kV Circuit Breakers Structures and Accessories 4 230-kV Air Disconnect Switch Structures and Accessories Land 2 acres TOTAL D -4 $53,652,000 3,974,000 5,080,000 2,500,000 $65,206,000 $ 86,000 108,000 11,000 38,000 420,000 315,000 154,000 119,000 31,000 64,000 1,020,000 538,000 338,000 407,000 70,000 232,000 23,000 $3,974,000 - - - - '*" I 3. Ester Substation Costs 1 138-kV Circuit Breaker Structures and Accessories 1 138-kV Air Disconnect Switch Structures and Accessories 3 13.8-kV, 12-MVAR Shunt Capacitor Bank Structures and Accessories 3 13.8-kV Circuit Breaker Structures and Accessories 4 10, 46 MVA, 138/230-kV Autotransformer Structures and Accessories 3 230-kV Circuit Breaker Structures and Accessories 9 230-kV Air Disconnect Switch Structures and Accessories 3 230-kV, 16-MVAR Reactor Structures and Accessories Land 3 acres TOTAL $ 86,000 108,000 11,000 38,000 265,000 198,000 116,000 89,000 984,000 516,000 507,000 613' 000 157,000 528,000 474,000 356,000 34,000 $5,080,000 C. Case IC, Anchorage-Fairbanks Intertie, 345 kV s/c Transmission System, 323 miles 1. Cost Summary T/L Cost@ $249,551 per mile Anchorage Substation Ester Substation Control and Communications System TOTAL 0 - 5 $80,606,000 6,195,000 6,231,000 2,500,000 $95,532,000 2. Anchorage Substation Costs 1 138-kV Circuit Breaker Structures and Accessories 1 138-kV Air Disconnect Switch Structures and Accessories 1 13.8-kV 16-MVAR Shunt Reactor Bank Structures and Accessories 1 13.8-kV Circuit Breaker Structures and Accessories 1 13.8-kV Air Disconnect Switch Structures and Accessories 4 Ul -48-MVA, 138/345-kV Autotransformer Structures and Accessories 2 345-kV Circuit Breaker Structures and Accessories 5 345-kV Air Disconnect Switch Structures and Accessories 4 10 -33-1/3-MVAR, 345-kV Shunt Reactor Structures and Accessories Land 2 acres TOTAL 3. Ester Substation Cost 1 138-kV Circuit Breaker Structures and Accessories 1 138-kV Air Disconnect Switch Structures and Accessories 1 13.8-kV, 15-MVAR Shunt Capacitor Structures and Accessories 1 13.8-KV Circuit Breaker Structures and Accessories 1 13.8-kV Air Disconnect Switch Structures and Accessories D - 6 $ 86,000 108,000 11,000 38,000 112,000 84,000 39,000 30,000 8,000 16,000 1,936,000 725,000 653,000 340,000 114,000 330,000 882,000 660,000 23,000 $6,195,000 $ 86,000 108,000 11,000 38,000 132,000 100,000 39,000 30,000 8,000 16,000 -I - - ~' -i -3. Ester Substation Cost (Continued) 4 10 -48 MVA, 138/345-kV Autotransformer Structures and Accessories 2 345-kV Circuit Breaker Structures and Accessories 5 345-kV Air Disconnect Switch Structures and Accessories 4 10 -33-1/3-MVAR, 345-kV Shunt Reactor Structures and Accessories $1,936,000 725 '000 653,000 340,000 114,000 330,000 882,000 660,000 ~ Land 2 acres 23,000 $6,231,000 - D. r r TOTAL Case ID, Anchorage-Fairbanks Intertie, 230 kV s/c Transmission System, 323 miles 1. Cost Summary T/L Cost@ $166,104 per mile Anchorage Substation Palmer Substation Healy Substation Ester Substation Control and Communications System TOTAL $53,652,000 3,976,000 1,434,000 1,434,000 5,080,000 3,300,000 $68,876,000 2. Anchorage-Palmer, 230 kV s/c Transmission System, 40 miles T/L Cost@ $166,104 per mile Anchorage Substation Palmer Substation Control and Communications System TOTAL 0 - 7 $ 6,644,000 3,976,000 717,000 1,450,000 $12,787,000 3. Palmer-Healy, 230 kV s/c Transmission System, 190.5 miles T/L Cost@ $166,104 per mile Palmer Substation Healy Substation Control and Communications System TOTAL $31,726,000 717,000 717,000 400,000 $33,560,000 4. Healy-Ester, 230 kV s/c Transmission System, 92 miles T/L Cost@ $166,104 per mile Healy Substation Ester Substation Control and Communications System TOTAL 5. Anchorage Substation Costs 1 138-kV Circuit Breaker Structures and Accessories 1 138-kV Air Disconnect Switch Structures and Accessories 4 13.8-kV, 12-MVAR Shunt Reactor Bank Structures and Accessories 4 13.8-kV Circuit Breaker Structures and Accessories 4 13.8-kV Air Disconnect Switch Structures and Accessories 4 10 -48-MVA, 138/230-kV Autotransformer Structures and Accessories 2 230-kV Circuit Breakers Structures and Accessories 4 230-kV Air Disconnect Switch Structures and Accessories Land 2 acres TOTAL D - 8 $15,282,000 717,000 5,080,000 1,450,000 $22,529,000 $ 86,000 108,000 11,000 38,000 420,000 315,000 154,000 119,000 31,000 64,000 1,020,000 538,000 338,000 407,000 70,000 234,000 23,000 $ 3,976,000 - ~ I - - - 0 - 9 8. Ester Substation Costs (Continued) 9 230-kV Air Disconnect Switch Structures and Accessories 3 230-kV, 16-MVAR Reactor Structures and Accessories Land 3 acres TOTAL E. Case II, Anchorage -Upper Susitna -Fairbanks Intertie 345 kV 2-s/c Anchorage-Devil Canyon 155 miles 230 kV 2-s/c Devil Canyon-Ester 189 miles 230 kV 2-s/c Watana-Devil Canyon 27 miles 1. Cost Summary $ 157,000 528,000 4 74,000 356,000 34,000 $5,080,000 Anchorage -Devil Canyon T/L @ $506,640 per mile* $ 78,529,000 Devil Canyon-Ester T/L@ $353,386 per mile* 66,790,000 Watana -Devil Canyon T/L @ $388,698 per mile* 10,495,000 Anchorage Substation Devil Canyon Substation Ester Substation Watana Substation Control and Communications System TOTAL * Includes two single-circuit lines. D -10 23,160,000 10,109,000 11' 339,000 1,592,000 3,800,000 $205,814,000 I - -' - - - - 2. Anchorage Substation Cost 2 138-kV Circuit Breaker Structures and Accessories 2 138-kV Air Disconnect Switch Structures and Accessories 7 10-210.5-MVA, 138/345-kV Autotransformer Structures and Accessories 9 345-kV Circuit Breaker Structures and Accessories 18 345-kV Air Disconnect Switch Structures and Accessories 2 345-kV, 200-MVAR Shunt Capacitor Structures and Accessories Land 5 acres TOTAL 3. Devil Canyon Substation Cost 3 345-kV Circuit Breaker Structures and Accessories 6 345-kV Air Disconnect Switch Structures and Accessories 7 10-90.3-MVA, 230/345-kV Autotransformer Structures and Accessories 6 230-kV Circuit Breaker Structures and Accessories 12 230-kV Air Disconnect Switch Structures and Accessories Land 4 acres TOTAL D -11 $ 172,000 216,000 23,000 76,000 8,516,000 3,404,000 2,938,000 1,528,000 408,000 1,191,000 2,647,000 1,984,000 57,000 $23,160,000 $ 981,000 509,000 138,000 399,000 3,418,000 1,466,000 1,015,000 1,224,000 210,000 703,000 46,000 $10,109,000 4. Ester Substation Cost ~ $ -2 138-kV Circuit Breaker 172,000 Structures and Accessories 216,000 2 138-kV Air Disconnect Switch 23,000 Structures and Accessories 76,000 7 10 -65-MVA, 138/345-kV Autotransfonner 2' 086,000 Structures and Accessories 1 '253, 000 6 13.8-kV Air Disconnects 46,000 ~ Structures and Accessories 96,000 6 13.8-kV Circuit Breaker 232,000 Structures and Accessories 181,000 6 13.8-kV, 6-MVAR Capacitor 264,000 Structures and Accessories 200,000 """"r 9 230-k V Circuit Breaker 1,523,000 Structures and Accessories 1,838,000 ~ 18 230-k V Air Disconnect Switch 314,000 Structures and Accessories 1,055,000 ~ 2 230-kV, 80-MVAR Capacitor 968,000 Structures and Accessories 727,000 ~ Land 6 acres 69,000 TOTAL $11' 339' 000 - 5. Watana Substation Cost ~ 3 230-kV Circuit Breakers $ 508,000 Structures and Accessories 613,000 - 6 230-kV Disconnect Switch 106,000 Structures and Accessories 348,000 Land 17,000 TOTAL $ 1,592,000 ~ ~ - D -12 - -· -' 0.2 DATA AND COST ESTIMATES FOR GENERATING PLANTS B. Cost Estimates and Disbursements for Generating Plants Note: Only specific units affected by interconnection of Anchorage and Fairbanks systems are considered: 1. Northpole #3 (NORT 3) 69 MW SCGT in Fairbanks Area. This unit is necessary for independent system expansion. Will not be required if interconnection assured. Rating -68.6 MW (net) Combustion Turbine Fuel -Distillate from North Pole Refinery Ref. Table B-1, Appendix B of Stanley Consultants Review Report For 1983 Installation: Unit Cost = NOx Cost $31,482,000 1,387!000 Subtotal $32,869,000 or $476/kW Assoc. Transm.1/ 4,783!000 TOTAL $37,652,000 or $546/kW See Also: P. 45 of GVEA Power Supply Study -1978 by Stanley Consultants & P. 28 -Table 10 Escalation Rates. GNP Deflators Period 1983-1980 1980-1979 Labor (~ 20%) Material (~80%) 1.085 1.07 1.095 1.08 Summary of Costs: Facil it~ 1979 Baseline Gas-Turbine Unit $24,385,000 or Assoc. Transm. 3,549,000 Total Capital Investment $27 '934 '000 or Disbursements -$1000 Pre-Oeerational Period 1st Year (1983) Gas-Turbine Unit 7,315 (30%) Assoc. Transm. 355 (10%) Total Facilities $7,670 Composite 1. 075 1. 085 Costs $353/kW $405/kW 2nd Year (1984) 17,070 (70%) 3,194 (90%) $20,264 l/ Relocation of facilities and expansion of existing Northpole substation. D -13 2. Beluga #9 (BELU 9) 71 MW RCGT in Anchorage Area. This unit will be postponed for one year by interconnection, from beginning year 1985 to 1986. This unit will draw on Beluga gas reserves for fuel supply. Design of unit is assumed to be simple-cycle, similar to existing units on Chugach System-Ref. Beluga Units 1, 2, 4, 6, & 7. Estimated Cost of Unit: From Reference Cost Estimate for NORT 3 at Fairbanks Cost at Bus-bar of 69 MW unit $353/kW By comparison for 71 MW unit $350/kW Now applying Alaskan construction cost location factors from Battelle Report, Table 6.3, P. 6.12 Applicable factor from Fairbanks to Beluga = i:~2 = 1.35 Estimated Cost = $473/kW or $33,548,000 Disbursements: Pre-Operational Period Independent Expansion Interconnected Expansion Proportion of Total Investment -$1000 1st Year 1983 1984 30% 10,064 Associated Transmission Facilities: 2nd Year 1984 1985 70% 23,484 Transmission Line (allow 50 miles)@ $126,000/m"ile Total Cost of Line Facilities= $6,300,000 Substation Additions at Beluga and Knik Arm = $2,650,000 Total Transmission Line and Substation Facilities= $8,950,000 Disbursements: Pre-Operational Period Independent Expansion Interconnected Expansion Proportion of Total Investment -$1000 Transm. & Substations Total Facilities 1979 Baseline Costs 1st Year 2nd Year 1983 1984 1984 10% 895 D -14 1985 90% 8,055 $42,490,000 -' -\ - 3. Northpole #4 (NORT 4) 69 MW SCGT in Fairbanks Area. This unit is necessary for independent system expansion. Will not be required with an interconnected system. Scheduled In-Service Beginning Year 1990 Unlike NORT 3, no transmission additions will be required, with completion of relocation and expansion of the substation. Considering only cost of unit with assoc. transf. and swgr. For 1979 Baseline Cost Levels: Total Capital Investment = $25,185,000 or $365/kW Disbursements: Pre-Operational Period GT unit, transf. & swgr. 1st Year (1988) 7,555 (30%) 2nd Year (1989) 17, 630 (70%) 4. Anchorage Peaking Unit #2 (PEAK A2) 78 MW SCGT This unit is required for both independent and interconnected systems but in-service date is advanced one year with intertie. Basing cost of addition on Northpole Unit 4 installation - i.e. SCGT unit with associated transformer and switching. Estimated cost based on rating, with allowance for scale. For 1979 Baseline Cost Levels: 69 MW GT Unit Total Cost = $25,185,000 or $365/kW 78 MW GT Unit Total Cost = $28,080,000 or $360/kW Now applying Alaskan construction cost location adjustment factor from Battelle Report Table 6.3 P. 6.12 Applicable factor from Fairbanks to Anchorage = 1/1.2 = 0.83 Total Capital Investment = $23,400,000 or $300/kW Disbursements: Year 1 2 Independent 1994 1995 Interconnected 1993 1994 D -15 % Total 30 70 Cost - $1000 7,020 16,380 5. Northpole #5 (NORT 5) 69 SCGT in Fairbanks Area. This unit is necessary for' independent system expansion. Will not be required with an interconnected system. Scheduled In-Service Beginning Year 1997 The addition of this unit completes the expansion for the inde- pendent systems of the Railbelt Area, the time frame is such that for interconnected expansion, with the staged increments of hydro capacity from the Susitna development, the last unit at Devil Canyon would be on-line beginning year 1997. Similar to NORT 4, no transmission additions are assumed to be required, such that power would be delivered from the expanded Northpole Substation to the existing system. Considering only cost of unit, with associated transf. and swgr. For 1979 Baseline Cost Levels: Total Capital Investment = $25,185,000 or $365/kW Disbursements: ($1000) Pre-Operational Period: GT unit, transf. & swgr. 1st Year (1995) 7,555 (30%) D -16 2nd Year (1996) 17 '630 (70%) - - r ., 6. Anchorage #11 (ANCH 11) 104 MW Coal-Fired Steam-Electric Plant. This unit will be required for independent system expansion but will be postponed, with interconnection, from in-service 1988 to 1993. Cost estimate for this plant is based on Healy Unit 2 estimate prepared by Stanley Consultants, with applicable Alaskan con- struction cost location adjustment factor. From Stanley Consultants Report to GVEA, Appendix A, P. A-1. For 1984 Installation Date (1978 Cost Levels): Healy Unit 2 Plant (Without FGD): Plant and Equipment Contingency Total Construction Cost Eng'g., Legal & Overhead TOTAL Escalating @ 10% to 1979 Cost Level Total Baseline 1979 Cost without FGD = $102,924,000 3,088!000 $107,012,000 14,982,000 $121,994,000 $134!160,000 Now Including Cost of Desulphurization: Plant and Equipment $111,174,000 Contingency 3 !335 ,000 Total Construction Cost $114,509,000 Eng' g., Legal & Overhead 16,031,000 TOTAL $130,540,000 Escalating @ 10% to 1979 Cost Level . . Total Basel·ine 1979 Cost with FGD = $143,520!000 Associated Transmission Facilities: or $ 990/kW or $1029/kW or $1173/kW $1290/kW or $1069/kW or $1101/kW or $1255/kW $1380/kW Assuming relatively short transmission line with substation facil- ities required, for connection to existing AML&P transmission system in Anchorage area. Cost Estimate for Transmission Line: Transmission Line (allow 30 miles) @ $126,000/mile Total Cost of Line Facilities = $3,780,000 D -17 Cost Estimate for Substation Facilities: Equipment Contingency Total Construction Cost Eng'g., Legal & Overhead TOTAL Escalating @ 10% to 1979 Cost Level Total 1979 Baseline Cost Summary of Costs: $2,700,000 203,000 $2,903,000 377,000 $3,280,000 $3,608,000 WO/FGD W/FGD Coal-Fired Plant (104 MW) Transmission Line Substation Facilities $134,160,000 3,780,000 3,608,000 $143,520,000 3,780,000 3,608,000 TOTAL $141,548' 000 $150,908,000 Now applying Alaskan construction cost location adjustment factor from Table 6.3 P. 6.12 of Battelle Study Report: From Healy to Anchorage -Location Factor = 1. 7/2.42 = 0.70 Applying this factor, Total Costs = $99~084,000 $105!636!000 or = $953/kW $1016/kW Disbursements -$1000 Coal-Fired Plant (ANCH 11) 1979 Baseline Costs Pre-O~erational Year: ~ Total W07FGD W7FGO IndeQendent Interconnected 1. 1982 1987 2 1,878 2,009 2. 1983 1988 8 7,513 8,037 3. 1984 1989 30 28,174 30,139 4. 1985 1990 37 34,747 37,172 5. 1986 1991 20 18,783 20,093 6. 1987 1992 3 2,817 3,014 Associated Transmission Facilities 5. 1986 1991 20 1,034 1,034 6. 1987 1992 80 4,138 4,138 0 -18 - ~ """\ ~ ' ~ """"' .... - } - r !""'-. I - r""' i i 7. Coal-Fired Unit F2 (COAL F2) 100 MW in Fairbanks Area. This unit will be required for both the independent and inter- connected system expansions, with generation reserve sharing only. However, with both reserve sharing and firm power transfer, it is replaced, together with COAL 5, by a 300 MW unit (COAL 6). This unit will be very similar to ANCH 11, which in turn was based on the Healy Unit 2 Plant, as reported by Stanley Con- sultants. The unit costs will be increased proportionately, to allow for the change of unit size from 104 MW to 100 MW. This has been economically scaled using the nomograph (Figures D-1 and D-2) in this appendix. For Generating Plant COAL F2: Plant Cost Estimates: Without FGD With FGD 1979 Baseline Cost Levels $120,000,000 or $1200/kW $130,000,000 or $1300/kW Associated Transmission Facilities: Assuming a plant site location at or near Healy, the trans- mission line and substation requirements are similar to those required for Healy Unit 2. Reference Stanley Consultants Review Report to GVEA, Appendix A, P. A-1: Transmission Facility Costs: Equipment and Material Contingency Construction Cost Eng' g., Legal & Overhead TOTAL D -19 1979 Cost Levels (1.1 x 1978 Costs) Transmission Substation Line Facilities $15,510,000 $3,348,000 465!000 100,000 $15,975,000 $3,448,000 2,455~000 102!000 $181430,000 $3,5502000 Disbursements -$1000 Coal-Fired Unit (COAL F2): 1979 Baseline Costs Pre-Operational Year: ?{; Total W07FGO W7FGD 1. 1986 2 2,400 2,600 2. 1987 8 9,600 10,400 3. 1988 30 36,000 39,000 4. 1989 37 44,400 48,100 5. 1990 20 24,000 26,000 6. 1991 3 3,600 3,900 Associated Transmission Facilities: 5. 1990 20 4,400 4,400 6. 1991 80 17,580 17,580 8. Coal-Fired Unit 5 (COAL 5) 200 MW in Anchorage Area. This unit will be required for both the independent and inter- connected system expansions, with generation reserve sharing only. However, with both reserve sharing and firm power transfer, it is replaced, together with COAL F2, by a 300-MW unit (COAL 6). The cost estimate for this generating plant was obtained by scaling costs from a base reference of 100 MW to 200 MW, using the nomograph (Figures 0-1 and D-2) contained in this Appendix. Then Alaskan construction cost location adjustment factors were used to determine the cost relevant to the Beluga site in the Anchorage Area. From Healy to Beluga-Location Factor = 2. 75/2.42 = 1.14 For Generating Plant COAL 5 Plant Cost Estimates: Without FGD With FGD 1979 Baseline Cost Levels ($1000) Healy Site Beluga Site $165,000 or· $825/kW $175,000 or $875/kW D -20 $188,000 or $ 940/kW $200,000 or $1000/kW - -·I ~"""' I - - I""' i I -\ '( I Associated Transmission Facilities: Assuming a section of transmission line and substation facilities, for connection to existing transmission system in Anchorage area. Transmission Line (allow 50 miles) @ $174,000/mile Total Cost of Line Facilities = $ 8,700,000 Substation Terminal at Knik Arm = Total Transmission Facilities Disbursements -$1000 Coal-Fired Unit (COAL 5) Pre-O~erational Year: % 1. 1986 2. 1987 3. 1988 4. 1989 5. 1990 6. 1991 Associated Transmission Facilities: 5. 1990 6. 1991 3,545,000 $12,245,000 1979 Baseline Total 2 8 30 37 20 3 20 80 WO/FGD 3,760 15,040 56,400 69,560 37,600 5,640 2,450 9,795 9. Coal-Fired Unit 6 (COAL 6) 300 MW in Anchorage Area. Costs W7FGD 4,000 16,000 60,000 74,000 40,000 6,000 2,450 9,795 This unit will not be required either for independent or inter- connected system expansion for generation reserve sharing only. However, with reserve capacity sharing and firm power transfer, it will replace both COAL F2 and COAL 5. The cost estimate for this plant has been derived from the cost for the reference 100 MW plant, using the nomograph (Figures D-1 and D-2) contained in this Appendix. This enabled consideration of economies of scale obtained when the unit capacity is changed from 100 to 300 MW and the differential costs associated with the two sites, according to the Alaskan construction cost location adjustment factor, similar to that developed for COAL 5. D -21 Plant Cost Estimates: Without FGD With FGD 1979 Baseline Cost Levels ($1000) Healy Site Beluga Site $200,000 or $667/kW $240,000 or $800/kW $228,000 or $760/kW $274,000 or $913/kW Associated Transmission Facilities: Assuming a section of transmission line and substation facilities, for connection to existing transmission system in Anchorage area. Transmission Line (allow 50 miles) @ $240,000/mile Total Cost of Line Facilities = $12,000,000 Substation Terminal at Knik Arm = Total Transmission Facilities Disbursements -$1000 Coal-Fired Unit (COAL 6) 6,250,000 $18,250,000 1.979 Baseline Pre-O~erational Year: % Total WO/FGD 1. 1986 2 4,560 2. 1987 8 18,240 3. 1988 30 68,400 4. 1989 37 84,360 5. 1990 20 45,600 6. 1991 3 6,840 Associated Transmission Facilities: 5. 1990 20 3,650 6. 1991 80 14,600 D -22 Costs W/FGD 5,480 21,920 82,200 101,380 54,800 8,220 3,650 14,600 - ~. ~ ~ 10. Coal-Fired Unit 2 (GEN 2) 300 MW at New Site in Anchorage Area. r-This unit is required for both independent and interconnected systems but in-service date postponed one year with intertie.· ~ I - For Generating Plant COAL 6: It is assumed that site will be near to previous plant location at Beluga, in sufficient proximity to assume cost basis to be identical, with difference only in the time frame for construction. Cost estimate for plant and associated transmission facilities are then identical to that for COAL 6. Disbursements -$1000 Coal-Fired Unit (GEN 2) 1979 Baseline Costs Pre-O~erational Year: % Total WO/FGD W/FGD Inde~endent Interconnected 1. 1989 1990 2 4,560 5,480 2. 1990 1991 8 18,240 21,920 3. 1991 1992 30 68,400 82,200 4. 1992 1993 37 84,360 101,380 5. 1993 1994 20 45,600 54,800 6. 1994 1995 3 6,840 8,220 Associated Transmission Facilities: 5. 1993 1994 20 3,650 3,650 6. 1994 1995 80 14,600 14,600 D -23 D.3 DATA AND COST ESTIMATES FOR SUPPLY OF CONSTRUCTION POWER TO UPPER SUSITNA PROJECT SITES The requirements of the combined Rai.lbelt area generation expansion, with inclusion of both Watana and Devil Canyon power from the Susitna develop- ment, schedules Unit 1 from Devil Canyon in January 1995, only 3 years after the first unit goes on line at Watana Damsite. Assuming as a first construction schedule that of the U.S. Army Corps of Engineers, the con- struction periods are 6 and 5 years, respectively, for Watana earthfill dam and the concrete arch dam at Devil Canyon. Thus, with the generation staging of the plan for interconnection, the total construction period would be 11 years, with pre-operational construction periods of 6 years for Watana and 5 years for Devil Canyon. There would be concurrent con- struction during 2 years. Prior to the first unit on-line at Watana, construction power would be required for 6 years at Watana and 2 years at Devil Canyon. It is assumed, for purposes of analysis, that separate provision would need to be made for the full construction power needs at both sites. From estimates by the Consultants: Connected Load Watana Devil Canyon 4000 kW (est·imated at 3750 kW) 3400 kW (estimated at 3350 kW) Operational Assumptions for Both Sites: 6 months/yr intensive operation @ 0.65 LF 6 months/yr light loading @ 0.30 LF Corresponding to construction planning assumptions of U.S. Corps of Engineers. Figure 7-1 of Chapter 7 shows the recommended sites at Watana and Devil Canyon for the Susitna development and the routing of the tap line to the sites from the transmission tap station, located on the main transmission corridor for the Anchorage-Fairbanks Intertie. The tap line can later be used also for a subtransmission circuit for distribution in the area, following the completion of the construction program. D -24 ~ ~ -' ~ ' - ·- - - -l A. Alternative 1 -Cost of Construction Power by Diesel Generation (This will constitute benefits for B/C analysis) Basic Assumptions: 1. 2. Diesel units purchased for Watana will be used for a period of 6 years and then sold at depreciated value. Diesel units purchased for Devil Canyon will be used for a period of 5 years and then sold at depreciated value. 3. No provision will be made at Devil Canyon for tapping 230-kV line from Watana once energized, due to prior purchase of diesel units for construction power. 4, Diesel units will be installed in multiples of 675 kW net/unit. 6 units at Watana 4050 kW net capacity 5 units at Devil Canyon 3375 kW net capacity From previous construction power estimates for diesel unit installations: 1979 Cost = $700/kW Installation for Watana construction power units would be made in 1985, ready for service in January 1986. Escalating@ 7% through 1985 -Cost Level = $1050/kW. Installation for Devil Canyon construction power units would be made in 1989, ready for service in January 1990. Escalating@ 7% through 1989 -Cost Level = $1377/kW. Cost of Diesel Installations: Watana = $1050 X 4050 = $4,252,500 Devil Canyon = $1377 x 3355 = $4,647,375 This capital investment would be disbursed in 1985 and 1989, respectively, for Watana and Devil Canyon. D -25 Cost of Diesel Operation During Construction Basic Assumption: Maximum Coincident Demand = Connected Load This, incidentally, introduces a measure of maximum loading which tends to compensate for an initial lower estimate of construction power requirements by a factor equivalent to projected diversity. Average Energy Usage Per Year: Watana 3750 (0.65 + 0.30) 8760 kWh = 15,603,750 kWh 2 Say 15.60 GWh/yr for 6 yrs. Devil Canyon 3350 (0.65 + 0.30) 8760 kWh = 13,939,350 kWh -2- Say 13.94 GWh/yr for 5 yrs. Operating Characteristics of Diesel Units: Fuel Rate Assumed -13 kWh/gal (diesel fuel) Base Price for Diesel Fuel -41. 2 t/ga 1 (1977 actual) Plus 5% Allowance for Lube Oil -43.3 ¢/gal To be escalated @ 11% to 1980 and 7% thereafter. O&M for diesel units estimated at 5% of total cost of incremental generation. Year Watana Dam Year Devil Canyon 1986 $1,118,500 1987 1,198,100 1988 1,280,800 1989 1,371,200 1990 1,468,000 1990 $1,311,800 1991 1,569,400 1991 1,402,400 1992 1,501,300 1993 1,607,300 1994 1,708,800 D -26 - - - DIESEL GENERATION OPERATING COSTS Diesel Fuel Including Lube Oil O&M Total Operating Cost Year t/gal mills/kWh (mills/kWh) (mills/kWh) !"""" 1977 43.3 33.3 1.7 35.0 1978 48.1 37.0 1.9 38.9 !"""" 1979 53.3 41.0 2.1 43.1 1980 59.2 45.5 2.3 47.8 -1981 63.3 48.7 2.4 51.1 f"""'. 1982 67.8 52.2 2.6 54.8 1983 72.5 55.8 2.8 58.6 .,..... 1984 77.6 59.7 3.0 62.7 1985 83.0 63.8 3.2 67.0 1986 88.8 68.3 3.4 71.7 -1987 95.1 73.2 3.6 76.8 1988 101.7 78.2 3.9 82.1 1989 108.8 83.7 4.2 87.9 1990 116.5 89.6 4.5 94.1 ,.,.., 1991 124.6 95.8 4.8 100.6 1992 133.3 102.5 5.2 107.7 1993 142.7 109.8 5.5 115.3 ~ 1994 152.6 117.4 5.9 123.3 r"'"'· I ~ """"' i ! D -27 Depreciated Value of Diesel Units: Basic Assumption of 15-Year Service Life" Assume Straight-Line Depreciation 1. Watana Installation Installed Cost (new) = $4,252,500 (1985) Depreciation/Year = 283,500 Depreciated Value (1991) 6-Year Period = $2,551,500 2. Devil Canyon Installation Installed Cost (new) = $4,647,375 (1989) Depreciation/Year = 309,825 Depreciated Value (1994) 5-Year Period = $3,098,250 Discounted Value of Benefits (Diesel Generation Alternative) Base Year 1979 (Discounted @ 7%) Year 1979 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 PWF 1 1.00000 0.66634 0.62274 0.58200 0.54393 0.50834 0.47509 0.44401 0.41496 0.38781 0.36244 Construction Cost ($) 4,252,500 4,647,375 -2,551,500 -3,098,250 Operating Cost ($) 1,118,500 1,198,100 1,280,800 1,371,200 2,779,800 2,971,800 1,501,300 1,607,300 1,718,800 (-sign denotes assumed resale value) D -28 Total Cost ($) 4,252,500 1,118,500 1,198,100 1,280,800 6,018,575 2' 779,800 420,300 1,501,300 1,607,300 -1,379,450 TOTAL PW 1 Present Value ($) 2,833,611 696,535 697,294 696,666 3,059,482 1,320,655 186,617 622,979 623,327 -499!968 10,237,198 - - - -. - - - - - r"" 1 B. Alternative 2 -Cost of Construction Power by Temporary Tapline (This will represent costs for 8/C analysis) Basic Assumptions: 1. Same loading conditions and time frame as per Alternative 1. 2. Sequence of temporary construction as per previous assumptions. 3. Reuse of substation equipment possible after construction program completed but no salvage value on line material. (Note: Possible reuse as distribution line to recreational areas.) Assume resale value of substation equipment to be depreciated value based on 25-year life of facilities. 4. Cost of power based on wholesale rates in Railbelt area. From previous estimates for line and substation facilities: Construction Costs: 69-kV subtransmission line $3,200,000 (1985 level) Susitna tap station+ Watana substation facilities Baseline cost level = $26.50/kVA (1979) Escalating @ 7% to 1985 (6 yrs) Construction Cost = $40/kVA (1985) Total Construction Cost = $400,000 69/4.16 kW, 5 MVA, Substation at Devil Canyon (1979 levels) Transformer $45,000 fob factory (Virginia) A 11 owing 5% for shipping and handling, etc. At jobsite cost = $47,250 Fused Disc. Sw. = 2,750 Structure, Cone, pad, etc. :::: 5,000 TOTAL $55,000 0 -29 Construction Costs: Equi prnent Labor Design 60% 30% 10% $55,000 28,000 9,000 TOTAL $92,000 or $18.4/kVA (1979) Substation would be installed in 1989. Escalated at 7% from 1979 levels. 1989 Construction Cost = $36.2/kVA Total Construction Cost= $181,000 O&M For Tem~orart Construction Power Line Maintenance 69 kV Wood Pole line -Approximately 40 miles 1 ong (11 Total O&M Year $/M Costs ($) 1986 330 13,200 1987 345 13,800 1988 360 14,400 40 M Total 1989 380 15,200 1990 400 16,000 1991 420 16,800 29 M Total{ 1992 440 12,800 1993 460 13,300 1994 485 14,000 + 29 M) Note: That due to overlap in construction schedules for Watana and Devil Canyon the capacity of the Susitna tap station will need to be doubled by addition of second 5 MVA transfer. This will be moved to spares inventory after 2 years. D -30 -1 - ~ 1 - - - - .... r I ~ I ~ ! Cost of Construction Power Supplied over Temporary Line Facility Based on information from RWRA 2/1/79 Wholesale rates for Railbelt area, with combination of Susitna Hydropower and large coal-fired plant feeding interconnection. Year 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 2000 Rate of Change 8% 7% 5% Wholesale Rate (mills/kWh) 17 18 20 22 24 26 28 30 32 34 37 39 42 45 47 50 D -31 Cost of Energy (mills/kWh) Bus-Bar Substation Note: 1977 Cost Levels 27.3 31.0 33.2 36.2 30.2 33.5 36.6 39.1 Conversion of Total Energ~ Rate to 2-Part Tariff """" Assumption: 100 MW Power Transfer at 0.6 LF is 525.6 GWh/yr. """' i Total Revenue 50/50 Revenue From: Eguivalent Tariff ~ Bulk Rate for Bulk Rate Demand En erg~ Demand Rate Energy Rate Year {mills/kWh2 ($1000) ($1000) ($1000) ($/kWh) (mi 11 s/kWh) -; 1979 17 8,935.2 4,467.6 74.5 8.5 1980 18 9,460.8 4,730.4 78.8 9.0 - 1981 20 10,512.0 5,256.0 87.6 10.0 1982 22 11,563.2 5, 781.6 96.4 11.0 ~ 1983 24 12,614.4 6,307.2 105.1 12.0 """"'! 1984 26 13,665.6 6,832.8 113.9 13.0 1985 28 14,716.8 7,358.4 122.6 14.0 """ 1986 30 15,768.0 7,884.0 131.4 15.0 1987 32 16,819.2 8,409.6 140.2 16.0 - 1988 34 17,870.4 8,935.2 148.9 17.0 1989 37 19,447.2 9,723.6 162.1 18.5 , 1990 39 20,498.4 10,249.2 170.8 19.5 - 1991 42 22,075.2 11,037.6 184.0 21.0 I ' 1992 45 23,652.0 11,826.0 197.1 22.5 "'"1 1993 47 24,703. 2 12,351.6 205.9 23.5 ~ 1994 50 26,280.0 13,140.0 219.0 25.0 ., Allow 5% adder for line and substation losses -assume the resulting rates are applicable to price construction power. """'' I -, D -32 -Cost Estimate for Construction Power -Assuming same loading as for diesel generation alternative. L Watana Damsite (3750 kW 1 15.6 GWh/tr) ,.... Demand Rate Energy Rate Construction Power Costs Year ($/kW) (mills/kWh) Demand ($) Energt ($) Total ($) 1986 138.0 15.8 517,500 246,480 763,980 1987 147.2 16.8 552,000 262,080 814,080 1988 156.3 17.9 586,125 279,240 865,365 1989 170.2 19.4 638,250 302,640 940,890 1990 179.3 20.5 672 '375 319,800 992,175 1991 193.2 22.1 724,500 344,760 1,069,260 - 2. Devil Canton Damsite (3350 kW 1 13.94 GWh/yr) Demand Rate Energy Rate Construction Power Costs -Year ($/kW) (mills/kWh) Demand ($) Energt ($) Total ($) 1990 179.3 20.5 600,655 285,770 886,425 1991 193.2 22.1 647,220 308,074 955,294 1992 207.0 23.6 693,450 328,984 1,022,434 1993 216.2 24.7 -724,270 344,318 1,068,588 1994 230.0 26.3 770,500 366,622 1,137,122 r D -33 Depreciated Value of Substation Facilities Basic Assumption of 25-Year Service Life Assume Straight Line Depreciation 1. Watana Substation Installed Cost (new) = $ 27.6/kVA (1985) == $138,000 = $ 5,520 Depreciation/Year Depreciated Value = $104,880 (1991) (6-year period) 2. Devil Can~on Substation Installed Cost (new) = $ 36.2/kVA (1989) = $ 181,000 Depreciation/Year = $ 7,240 Depreci~ted Value = $ 144,800 (1994) (5-year period) 3. Susitna Tap Station/Watana Bus Tap Installed Cost (new) = $ 262,000 (1985) Depreciation/Year = $ 10,480 Depreciated Value = $ 167,680 (1994) (7-year period) To transfer 5 MVA facility from Susitna Tap to Watana. Cost of removal and transfer == $30,000 (1991) Cost of second 5 MVA step-down facility at Susitna tap. In 1989 for Supplementary power to Devil Canyon = $343,400 Depreciated value after 2 years = $315,900 0 -34 - - - - - - r 0 -35 0 -36 r -' r I t -I r r I • I I r I r I r L -I ! r ' I SUMMARY BASELINE COSTS (1979) ASSOCIATED WITH TWO CONSTRUCTION POWER ALTERNATIVES $1000 {1979) (Independent) (Interconnected) Diesel Tapline Year Generation Su~~l,l 1985 2,835 267 1986 695 483 1987 697 481 1988 696 478 1989 3,055 752 1990 1,324 902 1991 187 734 1992 623 430 1993 623 419 1994 -5oo.Y 304 11 Negative sign indicates net resale value predominates over costs. D -37 0.4 ALTERNATIVE GENERATING PLANT FUEL COSTS The year-by-year analysis of comparative fuel costs follows: A. First Period (1984-87) -Firm Power Transfer of 30 MW, 145 GWh Year 1984 1985 Interconnected System Expansion The number and type of generat- ing plants is identical to that for each system operating inde- pendently. Independent System Expansion Each independent system would be supplied by operational units on basis of economic dispatch to meet individual area needs. The determination of relative economic advantage to either system, of a firm power transfer, would require a detailed analysis, necessitating production costing of economically dispatched units for the Anchorage and Fairbanks systems. It is a reasonable measure to delete the comparison of marginal advantages accruing for this year of operation. ANCH 9 -78 MW SCGT is added to AML&P system, obviating the need for both NORT 3 and BELU 9. Two units are required in Anchorage area, ANCH 9 - 78 MW SCGT and BELU 9 - 71 MW RCGT, together with NORT 3 -69 MW SCGT unit at the Northpole Station in Fairbanks. As a first approximation, the relative generation cost advan- tage may be determined by estimating the respective fuel costs associated with the generation of 145 GWh of energy by either ANCH 9 or NORT 3, taking into consideration different primary fuel costs and thermal efficiencies. The unit ratings are sufficiently close to justify this analytical approach, on the basic assumption that equivalent energy would be generated during the year by the two units. An adjustment would then be made to allow for the differential cost of supplying line losses in the transmission intertie, which would amount to 1. 5 GWh/yr. D -38 - - , - - - - r ~ i ! l Comparative Fuel Costs: ANCH 9 -78 MW SCGT From Battelle Report (see Figure D-3) See Figure D-1 Trend Curve for HR8444 New Gas with 8% inflation and escalation 1985 Fuel Cost = $3.60/MBTU Net Heat Rate = 14,500 BTU/kWh Annual Cost of Fuel (ACF) to generate 145 GWh: ACF@ 0.21 PCF~/ = $3.60 x 145 x 14,500 = $7,569,000 NORT 3 -69 MW SCGT From Stanley Consultants Report P. 21 1978 Fuel Cost = $1.98/MBTU Escalating @ 10% per year!1 : 1985 Fuel Cost = $3.86/MBTU For distillate from North Pole refinery From Table 6, P. 22: Net Heat Rate = 15,130 BTU/kWh Annual Cost of Fuel (ACF) to generate 145 GWh: ACF@ 0.24 PCF~/ = $3.86 X 145 X 15,130 = $8,468,000 The total cost comparison is in favor of ANCH 9 generation to supply Fairbanks. Total cost of generation, including loss component = $7,648,000. 1986 BELU 9 -71 MW SCGT is added to CEA system, the inter- connection having served to delay the in-service of the combustion turbine by one year. It is assumed that this unit will be operated for supply to CEA system only during first year of operation. ANCH 10 -104 MW coal-fired plant is added to AML&P system for both independent and interconnected system expansions. KNIK A -15 MW thermal power plant (CEA) is also retired from both expansions. The relative economic advantage is attributable to the fuel cost differential between distillate for NORT 3 generation and Beluga gas for generation by either ANCH 9 or BELU 9. Selecting ANCH 9 as in the previous analysis for 1985: !/ 7% inflation + 3% escalation. 2/ PCF = Plant Capacity Factor. D -39 Comparative Fuel Costs: ANCH 9 -79 MW SCGT 1986 Fuel Cost = $4.00/MBTU Net Heat Rate = 14,500 BTU/kWh Annual Cost of Fuel (ACF) to generate 145 GWh: ACF@ 0.21 PCF = $8,410,000 NORT 3 -69 MW SCGT 1986 Fuel Cost = $4.25/MBTU Net Heat Rate = 15,130 BTU/kWh Annual Cost of Fuel (ACF) to generate 145 GWh: ACF@ 0.24 PCF = $9,324,000 The cost comparison is once again in favor of ANCH 9 generation to supply the equivalent amount of energy over intertie, as would otherwise be generated locally in Fairbanks. Total cost of ANCH 9 generation, including transmission loss = $8,498,000. 1987 This is the first year of operation of COAL 1 -200 MW coal-fired plant on the Anchorage system. As this would be the first year of operation for the first major coal-fired plant in the Railbelt, for either independent or interconnected expansions, it would be thus common to the two alternatives. The relative cost advantages would then again be determined by consideration of the relative generation cost for ANCH 9 and NORT 3. Comparative Fuel Costs: ANCH 9 -79 MW SCGT 1987 Fuel Cost = $4.25/MBTU Net Heat Rate = 14,500 BTU/kWh Annual Cost of Fuel (ACF) to generate 145 GWh: ACF @ 0.21 PCF = $8,936,000 NORT 3 -69 MW SCGT 1987 Fuel Cost = $4.68/MBTU Net Heat Rate = 15,130 BTU/kWh Annual Cost of Fuel (ACF) to generate 145 GWh: ACF@ 0.21 PCF = $10,267,000 Total cost of ANCH 9 generation, including transmission loss = $9,029,000. 0 -40 - - '- r ,.... ' r I r- ! B. Second Period (1992-96) -Firm Power Transfer of 70 MW, 337 GWh Year 1992 Interconnected System Expansion . Interconnected operation obvi- ates the need for COAL 5 -200 MW unit in Anchorage area and COAL F2 -100 MW unit in Fair- banks area. Comparable genera- tion is maintained by COAL 6 - 300 MW unit in Anchorage area. Independent System Expansion COAL 5 would have to be added to Anchorage system and COAL F2 to Fairbanks. Comparative economic advantage is determined by relative magnitude of fuel costs, for either COAL 6 or COAL F2, to generate same energy. Comparative Fuel Costs: • COAL 6 -300 MW From Battelle Report (see Figure D-4) Fuel Cost in 1992 $2.60/MBTU Net Heat Rate 9,500 BTU/kWh ACF to generate 337 GWh $8,324,000 • COAL F2 -100 MW $1. 90/MBTU 10,700 BTU/kWh $6,851,000 The comparative advantage in this case moves to the use of Healy coal. However, as with interconnection, the unit COAL F2 will be eliminated in favor of the economies of scale associated with the COAL 6 unit. Without production costing, it is not possible to determine the overall economic advantage of introducing COAL 6, so for present analysis it is assumed that no economic energy transfer is possible. However, as a first approximation, the fuel costs for this year will be entered into economic analysis to consider the effect of the differential. D -41 1993 ANCH 11 -104 MW coal-fired unit added to AML&P system in this year for interconnected ex- pansion, after an interval of five years following the in- service date for same unit with independent expansion. PEAK A1 - 78 MW combustion turbine also in- service from beginning of year. PEAK A1 -78 MW combustion turbine in-servi~e from beginning of year, for independent ex- pansion of Anchorage system. Of interest in this year is a comparison between the cost of energy generation for ANCH 11 and COAL F2 using the same source of fuel, Healy coal. Thus, the relative advantage of either generating at the existing plant site at Healy or in the vicinity of Anchorage may be examined for similar capacity units having the same thermal efficiency, to determine the economies of energy transfer by intertie. Comparative Fuel Costs: • ANCH 11 • COAL F2 Cost of Healy coal in 1993 $2. 4/MBTU.1/ $2.00/MBTU~/ Net Heat Rate 10,700 BTU/kWh 10,700 BTU/kWh ACF to generate 337 GWh $8,654,000 $7,212,000 Once again the comparative advantage lies with the generation of energy at the Healy site. However, with interconnection the need for COAL F2 disappears in favor of the economies of scale attendant on COAL 6. It may be noted that the cost differ- ential in favor of Healy disappears if the COAL F2 site would be moved away from Healy for environmental reasons to say Nenana. In this case, the cost of generation would be approximately the same whether coal were transported either to Anchorage or Nenana, as the transmission loss, associated with ANCH 11 (104 MW) generation and transfer over the intertie, would be compensated for by the slightly higher heat rate to be expected with the 100 MW unit of COAL F2. 11 Delivered to Anchorage plant site. 2/ Delivered to Healy plant site. 0 -42 - - - - - - - - .- - r r -I -r 1994 As GEN 1 -300 MW coal-fired generating plant added for both independent and interconnected system expansions, the previous combination of ANCH 11 and COAL F2 can again be examined to determine the differential cost of fuel. Comparative Fuel Costs: I ANCH 11 I COAL F2 Cost of Healy coal in 1994 $2.5/MBTU $2.2/MBTU (Minemouth Generation, FOB Tipple) Net Heat Rate 10,700 BTU/kWh 10,700 BTU/kWh ACF to generate 337 GWh $9,015,000 $7,933,000 It may be noted that due to divergence of fuel cost trends after 1993, for coal delivered to either Anchorage or Nenana, rather than minemouth, the economic ad- ~antage moves progressively towards generation at an Anchorage location, with transfer of the equivalent energy over the intertie. However, in 1994, it is possible to transmit energy generated economically at Healy to Anchorage over the intertie. Total cost of COAL F2 generation, including transmission loss = $8,016,000. 1995 COAL F3 -100 MW coal-fired plant is introduced to the Fairbanks area and PEAK A2 - 78 MW combustion turbine is added to the AML&P system. Interconnection results in the postponement by one year of the 300 MW GEN 2 in the Anchorage a rea. GEN 2 -300 MW coal-fired plant is introduced to the Anchorage area with independent system expansion but the 78 MW com- bustion turbine PEAK A2 is not required in addition to the large coal-fired plant. COAL F3 is added to the system in the Fairbanks area. As COAL F3 is common to both the independent and interconnected system expansions, it is of interest whether the gas-fired PEAK A2 in Anchorage could economically displace the equivalent energy generated by the coal-fired unit COAL F3 in the Fairbanks area. D -43 Comparative Fuel Costs: Cost of New Gas in 1995 (HR 8444-8% infl. +esc.) Cost of Healy Coal in 1995 (Minemouth Plant, FOB Tipple) Net Heat Rate ACF to generate 337 GWh There is a definite economic advantage transfer over the intertie to displace • PEAK A2 • COAL F3 $7.70/MBTU $2.40/MBTU 14,500 BTU/kWh 10,700 BTU/kWh $37,626,000 $8,654,000 to co a 1 generation at Healy and energy gas-fired generation in Anchorage. Total cost of COAL F3 generation, including transmission loss = $8,745,000. 1996 GEN 2 -300 MW coal-fired plant is introduced to the Anchorage area, the inter- connection serving to post- pone its in-service date by one year. PEAK A2 -78 MW combustion turbine is introduced to the AML&P system in Anchorage. In this final year of analysis, it is of interest to compare the relative economic advantages of coal-fired generation at either the Fairbanks (Healy) or Anchorage (Beluga) sites. Comparative Fuel Costs: Cost of Beluga Coal in 1996 Cost of Healy Coal in 1996 Net Heat Rate ACF to generate 337 GWh e GEN 2 $3.3/MBTU 9,500 BTU/kWh $10,565,000 • COAL F3 2.5/MBTU 10,700 BTU/kWh $9,015,000 Once again it is more economical to generate in the Fairbanks area and transfer energy south over the intertie to Anchorage. Total cost of COAL F3 generation, including transmission loss = $9,109,000. 0 -44 - _, - - -I r FIGURE D-1 NcxTKJ~Jram ca cu ates CXXJI IUIIIY U SCCl8 ir1 rx)wer pants By JAMES McALISTER, Arkansas Power & Light Co. Historically. the ~er unit cost of larger power plants has been less than that of smaller plants. The proportionality was examined in some detail in the article "Economy of Scale in Power Plants" in the August 1977 issue of POWER ENGI- NEERING Magazine, p. 51. The basic equation is: (C,/C7 ) (MW 1/MW2 )P Where: C, · cost of plant 1 C~ cost of plant 2 MW 1 capability of plant 1 MW:. capability of plant 2 P proportionality factor For many years, this proportionality factor averaged about 0.6, which led to the so-called "Six-tenths Power ·Law." However, as explained in the article referred to above, extended project schedules and inflation cause the factor to increase This nomogram solves the equation and permits a cost comparison of plants of different sizes. It assumes, of course. that they are essentially identical in construction technique, design and time frame, and that the only significant difference is in size. Example: A 200-MW plant can be ·built for $200 million. Find the cost of a similar 1000-MW plant. Solution: (1) Connect unit ratings of 200 MW and 1000 MW on the MW1 and MW 2 scales, and mark intersec- tion with Reference Line X. (2) Align this point with assumed scaling fac- tor P = 0.6 and extend to cut Reference line Y. (3) Connect this point with 0.2 on C 1 scale and extend to C 2 scale. Read answer as $0.53 billion. £ND To obteln en extra copy ol this article, circle 206 on Reader Service Cerd ____ , _____ --------------------------- R1llions ol dollars MW1 y UJ z ::J UJ u z 1.0 UJ a: li 0.130 UJ a: 0.120 1.5 104 POWER ENGINEERING/FEBRUARY 1979 D -45 Mr•qiiWil\1 co~po~hlilty MV\11 1500 1000 MVV1 X w z X L&J z _J MW~ 100 c1 D -46 Bill lOlls oi dollars 1.0 1.5 y w z :J w u z w a: li L&J a: Flliil()llS Ol dolliHS 1.0 1.5 y L&J z :J w u z w a: li w a: FIGURE 0~2 0.53 - - """"\ -I ,.... - ~ :::1 ~ CCI E E "- il) 10~ 5 0.5 I ~ I HR 8444 NEW GAS1 1 l 8% INF. & ESC. 5% INF. AVER. REFINERY CRUDE OIL ACQ. PRICE~ SURVEV14l RW RETHERFORD ANCHORAGE<&l WELL HEAD171 BELUGA/CHUGACH WITH PALNG19l BELUGA/CHUGACH ABSENT PALNG11o1 I I '-...-/ POSSIBLE LIFE BELUGA FIELD COMMITIED RESERVES 0.1~----~------~------~------~------~------~----~ 70 75 80 85 90 95 2000 YEAR ESTIMATES OF FUTURE NATURAL GAS PRICES FIGURE D-3 (Source: Battelle Final Report 'Alaskan Electric Power', March 1978/Figure 6-6) D -47 FIGURE D-4 10~--------------------------------------------------~ 1.0 ::l ..... co E E " <l)o HEALY COAL FOB NENANA INTERIOR ALASKA ENERGY ADVISORY TEAM - FAIRBANKS GVEA HEALY EXPERIENCE BELUGA \ INTERIOR ALASKA ENERGY ADVISORY TEAM -HEALY 0.1L-----~~----~-------~-------L-------L------~----~ 70 75 80 85 90 95 2000 YEAR ESTIMATES OF FUTURE COAL PRICES (Source: Battelle Final Report 'Alaskan Electric Power', March 1978/Figure 6-7) D -48 APPENDIX E TRANSMISSION LINE ECONOMIC ANALYSIS PROGRAM (TLEAP) ,......, ,-. ,...., ' r ,-. - ,.... r""' -I - TABLE 8-1 TABLE 8-1x TABLE 8-1-LL TABLE 8-2 TABLE 8-3 TABLE 8-3x TABLE 8-3-LL TABLE 8-4 TABLE 8-4x TABLE 8-5 TABLE 8-5x TABLE 8-6 TABLE 8-6x TABLE 8-7 APPENDIX E TRANSMISSION LINE ECONOMIC ANALYSIS PROGRAM (TLEAP) CASE IA CASE IA CASE IA CASE IC CASE IB CASE IB CASE IB CASE IB CASE IB CASE ID CASE ID CASE ID CASE ID CASE IC E - 1 2> AUGUST 79 DISCOU'iT '<AT!: 1.\,PO 1).2':J tl.So .. <:1. 75 9. 0 !) 9,25 'I • "\) '!,7') ]I) • 00 1U.2') I 0. '1 0 1 u. /5 (Tl 1 1 • ,; I) 11.25 1 1 • 5 () N I 1 • l S 12.oo DISCOUNT ~AlE ~.no 1-1.2':) fl.'JO lj. 75 9.1)0 9.2':1 9.':JO 9.7S 1 0. I) 0 I0.2S tO.':JO ] (I • 7 ') 1 1 • u 0 11.25 11 • s n 11.1"> 12.00 J J J D I 5 C 0 Lf'• T E 0 V.!LUE ALASKA POWER AUlHO~ITY ANCHORAGE -·FAIR8A~KS INT[RTIE ECONO~lC FtASIBILITY STUDY OF BASE YE.A~ (1979) INDEPEIIIDENJ IN $1000 SYSTEM cosTs -----------------------------------------ESCALATION RATES---~---~------------------------------- li% 41. 57. 6% 7Y. 8% 9% 10% 11% 12% =====:::= ======= --------------======= ---------------------======= ======= ----------------------------------- 2 ,,,. , ,, 7 (' 3Sq,1{)9 31'.,~, 971', 427,474 '16'!,977 516,90.3 "ioti.,712 62~,909 689,048 75'3,73o 2)9, ~h'> 34o,.>35 .H<0,203 417,69'; 4"i9,(l79 ':JOII, 760 ':l55, 1811 610,5~'1 672,263 71~0, 046 23 ., , "59-I 331:1,';81 37\,o75 £108,193 4tH:\, 493 1192,967 542,0i.IR 596,209 65':1,972 721,910 229,')56 B 1,11.10 5td' 5131> 3'~8,960 431\,209 41:\\,'513 ':129,292 '>82,005 6ll0,159 701J,309 2 2 !I, ,3 'I 7 32.3, 90·'l 3'55,)21\ 389,9137 :<28,211 ll70,386 ':J1o,903 568,213 62tJ,fl0H 687,225 2d:, 2b2 .31o.~6h )t.l.,, ij'/'j 3R1,266 4113,'107 4')'1,"i76 50'-l,f\70 ':JSLI,820 b09,903 67{1,641 21 ':i, 7'Jfl, 31 \1 , u 2 ·~ 33°,~7R Y/2,787 409,1)70 t.l£19,073 "193, 181 '541,1:112 ':)95,430 6'i4,51Jl 2 11 , 4 'J 1 50.3, 3or• 332,471 3h ll, 5115 3<.J9,1'.'17 43':\,f\67 4P1,fl24 529, 117 'il:\1,375 631\,909 2U7,2!7 2CJt:J,I''12 325,2o/ 356,5.30 390,981 428,<.J47 47U,789 ':116,903 ':)67,124 62.3,729 203,093 29iJ,':J91 .31!1,2",9 31~8, 736 382,312 1119,5U5 <160,066 504,97tl '>'::>4,4611 60tl,986 l<l9,1)76 21'4,'-161 311,'1 1J3 341,1'}6 37S,R83 409,932 ll4'1,b44 493,390 5111,581 594,667 1 <l"\, I 62 27':<,49<.1 30l.i,iiJO 3B,7!:13 365, 1)/i 6 400,820 439,513 48(',129 529,065 580,7'}7 1 <1] , )tJ i:l 272,bf.7 296,~':)7 326,611 351,711.1 391,959 420,o65 471,185 S1b,903 567,244 11:'· 7. fd l 267,(•3<l 292,076 q 9, 6 32 3119,960 31:1.3,343 420,091 ll60,511o 50':i,0H'I ')51J, 114 1 !J 'l, I) P8 261,':J3L• 2P.C,,963 312,131.12 342,<117 374,963 410, 7A1 450,204 lJ93,')9b 'jlJ1,355 1(111 1 11"{6 2':16,112 2AU,i)13 506,234 B5,071:1 36b,l:ll1 401,728 1140,!1J'I llll2,lJ29 52H,o5') 177,035 2':J•), 953 27q,220 299,1:102 321,936 3Sf:I,Rtl2 392,'123 430,372 471,571~ 516,903 DISCO~:,TED V.~LUE Of tlASF Yt AR (1979) INTt.RCONNECTED SYSlEM COSTS IN 'li1000 -----------------------------------------ESCALATION RATES-----------------------·--------------- 0% 47. 5% b•t. 7"1. 1:1% 9% 10% 11 % 12% --------=====;::::: -------___ ,.. ___ ======= ======== -------======== ======= -------======= =====::= ------- 2B, 560 5S1,h7'~ 390, 1HH 1.133,136 l.ii\1,019 ':JV1,3f\9 ':19.3,859 61:>0,105 !35,1:\711 1-1!5,988 228, I'll 31.13,033 380,:161) IJ2<', IBb lJ6tl,69d ':120,531 578,278 642,59lJ 714,202 793,899 222,9HO )34, nSIJ ~71,028 '111,S73 1.156,758 507,104 563, 1P.II 625,633 69':>, 151 772,510 217,022 S2~>,S28 S t> I , 'J 13.3 401,2114 114'::>,18o 1.194,092 51.18,560 609,20? 676,699 751,797 21 ~,011 .5 1 l:l , t> 11,., 353,0\S 391,309 4.35,969 u8l,i.IB2 S3ll,389 595,C84 6Sfl,fl25 731,731:> 20tl,242 311,000 .3'.14 , lJ 11.1 381,6)6 liZ 3, 0 911 l.l69,2o0 ':J20,b56 577,860 6ll\,509 712,3011 2ll3,610 303,':>1<2 336,072 372,257 lJI2,551 4':)7,1.112 507,31.16 5o2,9111 621.1, 731 693,i.i79 ]49.112 29o,3RS 527,'-!HO 363,160 II 02, 32"1 114 5, 925 49ll,(li.l5 51.18,1129 o08,474 675,2ll1 191.1.74~ 28<J,'.l01 320.1<'9 354, .Bb 392,1.112 1131.1,788 i!8\,93A 5311,38<1 592, 720 657,569 19(),1191 2ec,625 312,511 .~4rJ, 776 3!'2, 796 lJ23,91-1tl £169,ot2 520,779 577,450 oilll, 1.1114 1Hh,3/~ 27 t, \) lj 5 .3115,11~ :B l, 1.171 ')73,1.1btl lll3,513 11':)8,05 11 ':J0/,58':1 '51:>2,bll9 623,1-147 1 t12, ) t> II 2o4,bSb 297,'liJ3 329,1.1!2 3o4,i.llf\ ~03,354 l.lt1o, 6'52 4911, 792 S/.18,300 o07 ,760 I 7 P., 116 9 26~,4">5 290,979 321,':>'12 3':J':l,o3H .3'1.5,ll99 lJ55,593 I.Jfl2, 3Rb ':J.~lJ,3H9 59?,166 I 111, o b 2 2':J7,i.13i.l 21:14,218 3!4,1l02 3LJ7,119 383,93tl 42ll,hb7 470,3S':J '1?0,900 577,048 17\,000 2S1.51<1 277,o5i.l .306, 6:$4 53H,t\51 374,661 41'~.461 iJ';8,1:>~6 507,R19 56£?,389 lb7,421 245,'1011 271,2111 299,41:12 Bo,826 3o5.oS9 40'1,365 £14 7, 36"( 1195, 132 0:,118,174 163,'?1J! 2Litl 1 39i 26',,091 i9?,5~tl 3?.3,03o 3'::>o,923 394,':169 4 )b, 3f\(> 4f\2,1'>27 '131.1,389 '~~~ .J _j ,) ~- ,] """~- _J ,_,_.,,.dJ J ,J j J ,~,J J J i?l AUGUST 79 ALASKA POWER AUTHO~llY ANCHORAGE -FAIRBANKS JNTfRTIE ECONOMIC FEASIBILITY STUDi . -·-·· -·--·-----------·------------------· --- CAPITAL DISBURSEMENTS . FUEL COMPONENT OF OPERATING COSTS lN ___ $1000-FOR --------------IN-$(000 FOR ----- ALTERNATIVE SYSTEM EXPANSIONS ALTERNATIVE SYST~M EXPANSIONS INDEPENDENT INTERCONNECTED COSTS -$79 COSTS -$79 lNOEPt::NDE.NT E:SCALATtD $ HHfRCONNECTED ESCALAltD $ --·--------~-------------------·-·· 1"1"1 __ L_ __ ----------- ·W 1919 19>l0 1 Q p. 1 ll , () 0 1 ------------ 1952 2,\1<19 Jti,22B 1983 2b,bbb l!b,9b7 _______ ! 9HLI_ _ ___ 81 ,9ll2 ______ _1 1, 515 __ ------· ----~---~------_,.,.,.- 19d~ 37,172 32.062 198b 21.127 492 1987 7.1~2 2,412 1988 7,555. 8,473 1989 23,110 30,549 19'10 ----------2 t, 920. _4 3, () 38 1991 82,?00 4:~.411 \992 10!,3d0 R<J,69ll 1993 ':>R,li":>O 108.723 199(1 29,840 75,13(1 1'~95 lo, 3AO 23,106 1996 . ---····-----270 ----------------~--~¥_...,.~......-,_... ---------- 1997 254 1979 19A(l 1981 )9/32 1Q8.S 198/J 1985 19136 19tH l9R8 19tl9 1990 1 91}1 1992 I9'H 19<14 tr-1'15 t«l~ll Jq~? ADOJTIONAL DISBURSEMENTS IN $1000 FOR UNDERLYING TRANSMISSION SYSTEM lNDEPE,~DHJ"I INTERCONNECTED cosrs -S79 cosTs -579 SUSITNA CONSTRUCTION POWER COSTS JN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GE.NEMATlON lNlEHTIE TAPLINE COSTS -$79 COSTS -$79 } TABLE 8•1 23 AUGUST 79 DISCOUNT HAlt 1'>.00 ti.25 11.'10 b. 75 9.(1{) 9.25 9.'"10 9. 75 10.uu !!!.?.':i 1 0. ',o I C! • 7 <J 1 l • IJ 0 rn I l • i~ 5 l I • S 0 . .p. I I • 7 5 12.00 DISCOUNT RATf; 8.00 8.25 'd • ') (l d.lS 9.00 9.25 <1.'10 9.75 1 \1. 0 t) 10.25 IO.So 10./'j 11.\Jil 11 • 25 11.50 11.75 t2.00 J ALASI\A I'01otEH AliTHORlTY ANCH0~4GE -FAIRBANKS lNTERTlE ECQ~O~!C FEASI8ILITY STUDY TABLE. 8-lX DISCOUNTED VALUE OF BASE YEAR ll979) INOEPENDE~l SYSTEM COSTS IN $1000 -~-----------~-~---------------~----------ESCALATION ~ATES--------------·-·---------------------- 07. 4% 5% 6% 7"1. 84 9% 10% 11% 12% -------======= ---------------------======= ======= ---------------------------------------------------------------------- 2'J 4. 4 7 i' 35<~,109 388,97B 427;474 469,977 ')16,903 568,712 6~5,909 689,048 758.736 2~'1.~65 3ll6,235 3d0,203 lj 1 7, 695 Ll59,079 50<1,760 555,184 610,839 o72,263 740,0116 (> _$ •l , ~ 0 I~ 33d,S81 37\,675 •.106,193 1J48, 493 L!92,967 5£12,0£18 59o,209 655,972 721.910 229,556 33l,lllLl 363, _SH6 39ii,Y60 ll38,209 £181.513 529,292 582,005 640,!S9 704,309 2 2 'J I ':\ /j 1 323,90il )C,':i. 328 389,91'.7 428,217 470,_51-16 516,903 568,213 624,808 687,225 220,262 31o,bo8 347,~95 381,266 Ll!8,507 Ll59,57b 50'-l,tl70 5':it.l,820 609,903 o70,6111 21':>,/qi:l 31 \), 1_12 4 339,1i7B 372,7'07 IJ 09 r (j 7 0 4'-19,073 <J93, 181 541,812 59~,'-130 6511, ':>41 2ll,ll')l )(13,368 332,471 36'J, SuS 399,i397 438,867 481,82L! ')29, 177 581,375 638,909 207,217 29o,to92 32'),267 35o,530 390,981 1121:1, 9t~ 7 470,189 Sto,903 5o7,721.J 623,729 2 :) _), 0 9 3 290,591 318,2':i9 31J8,73b 3fl2,312 Lll9,305 L!o0,066 50LI,97tl 55li,46L! 608,986 199,076 2t\Ll,4ol H 1, cl43 3Lll,t5o 373,81:\3 Ll09;932 ll49,oll4 493,390 5ll1,':->!:l1 59ll,667 1'!5,!b2 2lb,ll9'-l 304,tll0 333. 71'3 3o5,686 400,820 Ll39,513 482,]29 529,065 580,757 1Yl,)1-ltl 272,hf!7 29;;,357 32o,61l 3':,7, 71 1J 3'11,95'1 '-129,665 47\,18") ')16,903 567,244 ll:l I , b .. ~ I 261,034 292,076 3!Y,o32 349,'160 383,3ll3 1.120,091 ll60,546 ':iU'J,084 ')",4 ,11LI 1/:l4,008 2oi,S30 285,963 312,1:\42 5ll2,ll17 374,9o3 Ll!0,781 450,20ll li93,S96 ">41,3':15 180,4'76 2':>6,172 2!HJ,013 30or231J 335,078 366,811 401,728 llll 0, 149 ll'32,tJ29 528,955 177,!l!d 2'JO,<.J53 27!.J,220 299,8v2 327,936 3511,882 31.}2,923 430,372 ll71,574 ')16,903 DISCOUNTED VALUE IJF Bt~SE YEAR (1979) I NTE RCOtmEC TED SYSTEM COSTS IN $luuo ------------~----------------------------ESCALATION RATES------------------·----------.---------- 0% 4% 5% 6% 7% 8% 9% 10% 11% 12% ======= ======·= --------------======= ---------------------======= ------------------------------------------------- 245,1183 36'),Hf\7 4QIJ,905 L!4tl,371 496,7'05 S50,701 610,731 677,551 751,908 834,625 2'10,lll1 3"i7,12o 39S,OS3 431,2f'J3 41:lll,33.2 536,706 59">,008 659,893 732,0I:lll 812,379 235,098 34b,629 _Hl'J,~99 Ll2o,5">3 '-172,2ol 523,1LJ3 579,773 642,786 712,882 790,83LI 229,939 _)ll0,386 Ho, 23 3 t.l}6,!39 460,559 S09,997 56':i,009 626,211 69'-1,281 7b9,967 224,92tl 332,5'09 367,2LI5 40o,04V 449,213 !)97,2':>4 550,701 610,150 671:>,259 7119,753 220,061 :>2'i, IJ29 )58,527 396.2ll5 431:1,212 '-1811, 900 S36,tl32 594,')86 658,798 730,171 21 s, 332 311,09ti 350,1)67 31:lb,74LI 427,5ll3 Ll72,922 523,3fl8 0:,79,500 641,8/b 711.197 210,737 ~0'-1, 78Q 34t,d59 377,527 Lll7,195 461,306 510,353 564,877 625,,477 692,811 ?.uo,272 3U<',o95 333,894 3613,51)5 !l01,157 li50,042 Q97,715 550,701 609,581 674,994 2vl,933 295,1:1(}7 32o,162 359,907 397,419 1.1.)9, 116 485,ll58 536,956 594,172 6")7,72LI 197,711J 28<1, 12tt 316,6':1>1 351,4Ho 387,9"11 ll2tl,5!7 473,~72 ':i25,62tl 579,.233 640,985 193,61'1 <'H~~, o2o 311,372 3Ll3.312 37A,B02 L!I8,23LI Ll62,042 510,703 ':i6l.l, 748 62LI, 756 ltl9,b?.b 276,319 30<~,c9B 335,37" )69,905 L!Ot\,251 1150,857 £191:1,!6/ 550,101 609,022 11-1'),749 27U, !'I$ 297,~29 32/,67o 3ol,268 391:l,576 llliO,OO':i 486,007 537,078 593,766 tl:ll,97il 26<1,2il2 290,757 320,197 Y:i2,8B5 31'19,180 IJ29,LI76 474,211 523,865 '578,970 178,310 251:1,41:>1 2'0Ll, 2 77 31<'.,q_s5 3Ll L!, 7llb 380,059 llt9,258 1~62,765 51l,Olltl 564,!:120 I 14, 7'12 25<', M43 2 77, 9rl_~ -~v':l, !Hq 33o,tltJI.! 311,20o L!09,j41 L!Sl,t>59 L!98,612 550,701 ·.J J J 23 Allt~tiSI 79 1 ALASKA POnEri AliHHlRllY ANCHO~AG£ ~ FAIH~A~KS INI[~TIE ECO~OMIC FEAS19lLllY STUDY ------------------ __ --~-~--_____________ CAPITAL OISBURSEI-IENTS FUEL COHPONENT OF OPERATING COSTS ---------------~--~~---$-i-OOl).-FOR 1979 1980 li.Jtit 191:'2 1983 191:14 1C!>J5 19t'o }<lk7 \908 \9P.9 1990 1'191 19<12 1q<.f~ 1'1-lll \9<1') . 19 116 1Q97 !979 19~0 19~1 1982 19t\3 19134 1985 11.Jilo 19~7 1981:1 19~9 l 1NO l9Q1 1992 1993 199ll }Q9':) 190b 1997 IN $1000 FOR ALTEH~ATIVE SYSTEM EXPANSIONS ALlERNAllV£ SYSTEM EXPANSIONS lNOEPEI'IOt:NT COSTS -$79 INTERCONNECTED ______ I NDEPENDEN l-INTERCONNECTED ESCALATE() $ COSTS -$79 ESCALATED $ 2,009 2b,bbb 81,9£12 37.172 21,121 7, 1 ":>2 7.555 23,110 21,920 11?,200 101,3•10 ')!;,ll'jO 29,~·J0 1o.31:\0 5,014 17,7tl5 5~.709 11.515 32,062 £192 2,iJ72 8,475 30,54~ U3,03R 1~3,£111 89,o94 108,723 75. \3<1 23,106 270 254 ADDITIONAL DISBURSEMENTS IN $1000 FOI< UNDERLYING TRANSMISSION SYSTEM lNOEPEnDUJ T 1NTEkCOi~NECTED COSTS -$79 COSTS -179 SUSlTNA CONSTRUCTION POWER COSTS IN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GENERATION INTERTIE TAPLINE COSTS -$79 COSTS -~7q ) 1 TABLE 8-lX 28 AUGUSl 7q DISCOUNT RATE 8,00 8,25 8,50 8,7':1 9,00 9,25 9,50 9,75 10,00 10,25 10,50 10,75 I 1 , 0 o 11 • 25 I'T1 11,50 11,75 12,00 0'1 DISCOUNT RATE 8,00 8,25 8,50 8,75 9,00 9,25 9,50 9,75 10,00 10.25 10,50 10,75 I 1 , 0 o t 1. 25 11,50 1 1 • 7 5 12,00 ,) J ~··~ .... I ALASKA POwER AUTHORITY A~CHORAGE • FAlRAA~KS lNlE~TlE ECONOMIC fEASIBILITY STUDY TABLE 8•1•ll DISCOUNTED VALUE Of BASE YEAR (197Q) INDEPENDENT SYSTEM COSTS IN $1000 a-•••••••••••····-···-··•-·••••···--·-···ESCALATION RATtS••••••••••••••••··-••••·•-•••••··•••••• 0% 4% 5% oX 7'1. HX 9% lOX 11% 12% ======= ====::;: ======= =====;: -------======= ======= ======= -------======= -------____ ,.. __ 238,103 373,719 418,575 1.168,876 52':1.259 588,1.132 65'1,178 738,366 826,958 926,017 232, 028 363,6'11 tJ07,220 456,025 510,725 'J71,998 640,1>10 717,398 80 3 ,2'14 899,327 226 ,IIJ2 353,981 39o,227 ll'.l3,586 496,654 ':>56,0Q':I 622,643 697,112 780,403 873,513 220,437 344,57H 38">,583 431,543 483,037 540,704 605,258 677,485 758,25/l 848,542 214,906 335,470 375,276 419,884 469,854 525,1107 588,!132 65H,492 no,IB2 8.?4,384 209,545 3?6,648 365,293 !IO~,':i93 !1"17,090 ':)11,386 572,1!17 640,112 716,099 801,012 201J,347 318,101 35'J,624 397,b59 1144,732 IJ97,1l24 556,382 622,322 696,03':i 778,396 199,306 509,820 314 6, 25 7 3H7,069 ll32,764 4H3,906 5111 , 121 60':>, 102 676,616 756,510 !94,1117 301,795 337,182 376,811 421,173 470,8\6 526,345 5Ml,432 657,8!C1 73':1,328 189,676 294,019 328,390 366,873 409,946 458,158 512,037 57?:,292 639;625 714,825 185,076 286,482 3!9,869 357,?44 399,070 44':1,859 498, 1Hl 556,665 622,007 694,978 180,oll.l 279,176 311,611 347,914 381:l,':l35 43:3,965 48!1,761 5111,531 604,950 675,763 176,284 272,093 303,607 338,873 378,324 tg2j>,442 471,762 526,871.1 58B,4}2 657,159 172,0A2 26'J,226 295,RI.I9 330,110 368,431 411,278 459,170 512,677 572,435 639,1lll.l 168,001.1 2'JH,S67 288,526 321,616 358,843 400,460 4llb,CI70 498,925 55!:1,942 621,697 16ll,046 252,110 281,033 313,381 349,550 3<>.9,977 435,148 485,602 541,934 601.1,800 160,203 ?4<;,846 273,961 305,398 31.10,541 3/9,816 423,693 472,694 527,39lj 58f!,ll32 DISCOUNTED VALUE OF BASE YOR (1979) lNTE.RCONNfCTEO SYSTEM COSTS IN $1000 ••••••••••••••··-••••••-•••••••••••-•••••E.SCALATION RATES------·-··--·---··-----·----·---·------ ox 4% 5% oX 7"1. 8% 9X 10% 11% 12"1. -----------------·---======= ----·--======= ======= --------------======= ------------------------------------------ 233,811 366,765 411,372 461,709 ')J8,ll95 51i2,528 654,703 736,015 827,576 930,622 227,934 .556,831 400;054 448,819 503,821 565,831 63':i,714 714;431.1 803,0b2 902,7'13 222.245 347,227 389; 113 lg36,361 489,641 549,699 617,372 693,')89 779,387 875,922 216,739 'B7 ,940 378,536 1!24,319 475,937 ':>'4,112 599,b'51 673, ll55 75b,522 A49,972 211,407 328,957 36H,308 412,o77 462,691 519,01l8 '582,528 654,001 73ll,ll35 82!!,909 ?06,245 320,269 358,417 401,421 1.1119,887 5011,!189 565,982 635,206 713,098 800,700 201,246 311,864 3411,851 390,537 437,50R 490,4lb 549,990 617,044 692,1!82 777,313 196,ll04 303,732 539,';:,97 .580,011 tJ25,':i'H3 476,fll1 534,53!1 599,492 b72,562 75ll,718 191,713 295,1:'16.5 330,645 369,830 413,963 463,b':i7 519,~92 582,':>28 b53,512 732,886 187,169 28H,247 321,984 3'J9,981 u02,7o9 450,937 50'>,146 566,130 63ll,707 711,788 182,765 280,876 .313,602 350,453 391,9lll 438,636 491,178 '>50,276 616,723 691,398 178,!198 273,741 30S,490 341,233 581,465 tg26,739 ll77,671 53tg,948 599,337 b71,689 174.361 266,833 . 297 ,"639 352,312 571,331 tg15,230 464,607 'J20,1?6 582,528 652,637 170,351 260,1ll4 290,038 323,677 561,5.?4 404,097 451,971 505,792 566,275 634,217 166,463 253,666 282,679 315,319 352,034 393,324 439,74R 49],928 ')50,557 616,ll07 162,693 247,592 275 1 S5ll 307,228 342,AII9 .582,900 427,422 478,517 535,356 599,!84 159,037 241,314 268,653 299,394 533,957 372,1:111 1.116,479 ll65,543 520,652 582,528 .J I .) .. ;c.J .,.,, .. ,.1 J J J J I j ) J . ·-J .·~~] 28 AUGUST H 1979 1980 1981 1982 1983 198£1 1985 1986 1987 1988 1989 1990 1991 1992 1993 199ll 1995 1996 1997 1979 1980 1 <HH 1982 1983 198£1 19R5 1986 1987 1988 1989 1990 19Q1 19Q2 1993 199£1 1995 1996 1997 ALASKA POWER AUTHORITY ANCHO~AGE • FAI~SANKS INTERTIE ECONOMIC FEASlSILI1Y STUDY CAPITAL DISBURSEMENTS IN $1000 FOR ALTtRNATIVE SYSTEM EXPANSIONS INDEPENDENT INT~RCONNECTED COSTS • $79 COSTS • S79 18,629 58,823 16.380 2.600 23,£135 78,550 130,300 131,780 79,930 30,375 17,630 t1, 0 1 I 14, 228 llb,967 11,515 32,0b2 ll92 llb5 ll3b £110 2,9A6 23,799 78,892 130,b23 132,084 80,216 23.090 25£1 ADDillONAL DISBURSEMtNTS IN $1000 FOR UNDERLYING TRANSMISSION SYSTEM INDEPENDENT lNTERCOI-lNECTED COSTS • $79 COSTS -$79 .FUEL COMPONENT OF OPERATING COSTS IN SlOOO FOR ALTERNATIVE SYSTEM EXPANSIONS INDEPENDENT ESC ALA ltD S INTt::RCONNECTED ESCALATED $ SUSITNA CONSTRUCTION PO~ER COSTS IN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GENERATION INTERTIE TAPLINE COSTS • S79 COSTS • $79 -.. } TABLE 8•1•LL J 23 AUJ;lJ!) 1 I 'I DISCOUNT I<ATE. t<.vo c>.25 ~.:.o !:l.75 ~ • •JO 9 • .?<; 'I.':JO "1.75 I !) • II I} 10.25 I ,; • ._, o Ju.75 I I • ll 0 IJ.;:>S I I • ') 0 11.15 I 2. l' 0 ALASI\A PUWFH, 1\\JTI.IORI fY ANCHO~AGE -FAIRBANKS INTERTIE ECONOMIC FEASIBILITY STUDY_ DISCOUNTED VALUE OF SASE YEAR (1979} INDEPENDENT SYSTt~ COSTS IN l>IOUO TABLE 8-2 ----------------------~------------------tSCALATIO~ RATES----~--------------------------------- 01 4% 5% b% 7% 8% 9% 10% 11% 12% ======= 251,4~2 2Jo,071 2'11'), illl7 235.766 2~v,n23 226,015 221, ~55 216,TH2 ?12, Sil9 2t'8,<l3S 203,tLSll 1<JQ,7£1LI !'IS, 7td 19!,flt\1 11\P.,IIJ2 JMIJ,,I21 !iHJ,I'\.53 ======= 3o7,521 35o, 1 ~9 y,o,9o>J, .543,088 .53 S, II 0 3 .327,"136 32.0,o7B 313,b24 306,166 300,(196 293,615 287,309 2tH, 177 27S,211 ('1)9,407 26~,7<:;9 2511,26.5 ======= <104,713 30'),342 .386,242 371,404 36tl,l:l19 360,Lli:IO 352,377 )4<l,'::!03 33&,fl50 329,412 322,182 315,152 308, HI> .SOI,o69 295,203 2P,H,91ll 2P,2,1"15 ======= Lll!5,o()7 435,430 ,, 2'l, ;:>r-,13 4\5,3H2 40':;,.791 396, iHb 387,429 .S78,6.39 370,099 361,801 3")5,736 3~5,898 33tl,27H 3.30,f\69 323,660 3!6,6t:.J 30'1,!147 --------------- 491,538 479,82£1 1~61", 4').4 L1 '). 7, 11 I 7 ijllb,703 43o,299 4t?o,19o 416,313!1 40b,i)53 397,59£1 3H8,S98 379,8':i':> 371,361 :563, I 04 355,07/ 347,273 339,o86 -------------- 542,088 528,991 516,28.5 503,94"1 49),979 480,358 469,077 4';>8,123 1147,1186 IJ3/,15LI 427,119 417,370 ll07,tl98 391:1,691.1 ~ll9,7t.j"' .HII,055 372,601.1 =====::= 59fl, 088 583,£1117 569,243 555,461 '><l2,081:1 529, I 1 0 51o,S1<' '>Oil, 2BLI 492,412 111:10, 88£1 46'-1,689 ll58,f117 448,256 431,996 428,021'1 418,3£11 408,928 -------------- 660,126 643,75Q 627,885 612,487 597,54tl 583,054 'lb!J,'-188 555,338 '::!42,0fl8 529,226 ':>16,738 504,613 !.192,837 4131,1.101 470,292 459,£199 /J£19,01£1 DISCOUNTED VALUE OF BASE YEAH (1979) INTERCONNECTED SYSTEM COSTS IN $1000 --------------728,81~8 1 1 o, 5.5o o92,818 t:>TS,61'). 658,9?.9 b£12,744 627,041 bli,80LI 591,018 582,ob8 5btl,7.59 555,217 542,081:1 529,3£10 516,960 50£1,936 493,25o ======= 80£1,970 78£1,529 764,711 7£15,£195 72n,861 70R,789 69!,260 67£1,255 657,757 6£11,7£18 626,213 611,134 596,£198 5B2,2B9 568,49£1 555,0<Hl 542,088 -----------------------------------------ESCALATION RATES--------------------------------------- 0 IS C Ll U ~H 0% 4% 57. 6% 7 i. fl% 9% 1 0% 1 U 12% .l RATt b. (l 0 1:1.25 (1.50 1:!.75 9.1)0 9.25 9.5u 'J.75 IO.uo lf1.25 10.SO ll1 • l') 11 • 0 0 ll.2S 11.50 11.75 1.?.{!0 ==::::==== 25br32B 250,/50 24"),332 t'UO,U69 234,9~5 229,9P.7 2<'5,!':!9 220rllbl 215,90') ?11,£171 2t•7, !59 202,9o6 1"18,flE<Ii l'li1,9.?1 1'1!,11<>2 1i'7,j0J u•3, oS2 .J =~====:: 37B,.590 369,ll93 360,8o3 352,489 :5LitJ,.)o3 336,476 32ti,tl21 321,389 )14,17£1 307,\bB 300,.363 <'93, 754 28/, B4 281,097 275,036 26'J, 1.4 7 2t>.5, 422 -------------- Lit 7 , ') 9 1 407,995 .59fl,299 3H8,1:191! 379, {69 370,91o 362,524 3S3,986 3£15,1:192 33H,035 330,40<> 322, '199 .51'-J,i-\~15 30tl,o1T 3vc,o3o 29':>, 1~56 289,028 -------------- 4b2,074 4"iO,fl42 439,950 42"1, 388 •t~J9,!4.~ 409,204 399,563 390,207 3R 1, 1 29 312,.518 .5o3,/o5 355,462 347,401 339,57.5 .3H,9H 324, ..,IH 317,ll'l5 J -------------- '>11,139 1198,522 486,289 474,429 /J62,927 LIS1,773 4!10,95£1 1130, £159 420,276 1.110,396 IIOO,BOI::I 391,502 31l2,!!69 3I .5, 100 .565,186 3":.6,919 348,890 -------------- 56':>, 71~6 551,575 537,1\39 5?4,5?£1 Sll,o!l~ £199,097 486,9')9 IJ75, 18o 463,767 Ll52,o90 4111, '/<12 L13!,"i13 421,~92 411,569 402,0.54 392,778 38.3,'7<10 -------------- 626,509 610,597 '>'-15, 1 77 5130,2.32 565,7£16 551,703 5HI,08/ 52!1,tl5'J 512,081 £199,663 487,ol7 475,932 46£1,'>94 453,S92 li£12,915 Ll.5?.,5<il 422, Jl92 .J ======~ 694, 110 67b,2LI8 658,9ll3 61!2,173 625,922 610,170 59£1,901 ':180,099 56':;,71~6 551,828 5~8. 3.51 52'l,239 512,540 500,;?19 L188,Zo5 £176,bb':> '16'::!, 401 -------------- 769,298 7£19,256 729,8£10 7ll,030 b92,803 b7S, 1£11 6':18,023 b41,LI30 bi?5,3LI6 60'1,751· 594,630 ':179,967 565, {Lib ':.51,952 ':138,5 70 525,':188 512,991 -------------- 852,90£1 830,£122 808,bll7 787,551.1 767,120 747,321 728,136 709,5LILI 691,523 o7l.I,OSS 657,121 6£10,702 o2LI,780 609,3£10 59£1,365 579,£138 5b5,11Jb 23 AUGUST 7"1 ; ALASKA PO~EW AUT"OWITY ANLHUNA~E -fAIR~A~KS INTERJIE t~U~UMIC FEA~IHIL!IY STUDY -------------------------~------- ----------------· ______ --------------(~PIT AL_ DlSt3URSEM[).If5 FllE_L_C_Q~~\)NENT_(JF __ !)PERAllr.!G COSTS !N SlOOO FOR ALTtRNATlvt SYSTEM EXPANSIONS 1 <r;Q l'IHO ------·---------·-------14~1 19132 191:13 19.'\1.1 lq/:'5 1 •J 15 b 19h7 1968 1 'H'i 9 19'10 1991 I 992 ]4'13 19911 1995 1996 1 9•17 1979 191'10 1931 l<lf\2 l'HB }9tlll 191:15 1986 l<lfl7 191:18 191}9 19<10 )941 1<192 1993 1994 l <J(j'j 1996 1 9'H IN ~1000 FUR ALTERNATI~E SYSTEH tXPA~SlONS INUEPENOtNI COSTS -H9 2,009 26,bbb _ --· _ ___ IH , 9 iJ 2 .n. 112 21,127 l, i 52 7,5~5 2.5.110 21,920 82,200 I <J t , 3 ~ 0 SK,il':>O 29, 1:\;1 0 23,93~ 17,b.50 I ::n ERC ONNEC T E 0 COSTS -H9 ll,~l2 lt\,056 72,!:>01.1 --------11, 326 -· 31,t\Bb '528 2.31 q /3,')29 3\J,b\)1.1 1.13, 042 4~,463 89,973 101:1,41\t\ 75, HH 23.3£17 £199 1.173 ADDITIUNAL DISBURSEMtNTS IN $1000 FOR UNUERLYJNG TRANSMISSION SYSTEM l~DEPENOENI INTERCONNECTED COSTS -$74 COSTS -$79 INIJEPHIOENT ESCALATED $ INTERCONNECTED ESCALATED !i SUSITNA CONSTRUCTION POWER COSTS . -IN $1000 ~OR . ALTERNATIVE MODES OF SUPPLY DIESEL GENEHATION INTERTIE lAPLINE COSTS -i79 COSTS -$79 } l TABLE 8-2 23 II.IJ!;IJS1 /q DISCQil:l;f f.iAif. t-.no 11.25 H,')O i<. 7 5 9,00 9.25 9,',0 9. 7S I 0. o 0 10.25 10.')0 I 0. 7 'i ,...., I I • co 11.25 11.')0 ...... 1 I • 1 c., Q 12.00 D I SCOtlN T KATt: 1:'.0(,) 8.25 1:1.~0 H.75 9.00 9,25 9.':10 9,15 10.00 10.25 IO.':itt 1 () • 75 I 1 • II 0 I 1. 25 11.':>lJ 1 I • 75 I2.VO "' ,.J ALASKA PU~ER AUTHORITY ANCHORAGE -FAIRBA~KS lNTERTIE ECOhOMIC FEASJAILITY STUDY TABLE 8-3 0 I SCC1UtHEO VALUE OF BASE YEAR (1Q79) II'IIDE:.PH!DENT SYSTHl COSTS IN $1000 -----------------------------------------~SCALA liON RATES--------------~------------------------ OY. i.l% 5~ b% 7"1. 8% 9% 10% 11% 1?X ======= ======== -------======= --------------------------------------------------------======= --------------------- 11':;-(1, iliJl ~:>llo,F<h7 70~,932 711,231~ 852,3H6 9_3':,, Ot>ll 1,0?.6;007 1,12t>,021 1,23':>,993 1.356,869 <H 0, ':iS A 1>32, l ;q o9c,oll'::l 7':iQ,2tn 1:13?,ll"-6 913,013 1,001,606 1,099,020 1,206,111! 1.323,827 430,93'3 o17,i:ll3 b7b,P.Ob 7111,101 P.13,tl80 l:l91,S78 977,1:192 1,072,784 1, I 7 7, 086 1,291,712 lj 21, 57 4 605,1'.77 661 , IJ 0 I 724r6b7 79 4, 2112 870,7112 9':ill,81l4 1,0l!7,287 1,!<18,1l82 1,?60,512 l.IJ?,il58 ')90,320 646,1115 708,101 775,923 850, 48/J 932,1J39 1,022,507 1r121,l!71J 1,?30, 199 l.l:1 3,5rt2 ')77,12P. 63l,P.3il 691,9P.7 758, 109 1:130,787 9IO,o511 998,420 1,091J,I:I38 1,?00,7llll 3'?<l,9Y:? 56'1,292 ':l!1,6':J!l o7o,312 1 II<) r 7 R 7_, /:111,c32 All o , 1l 1'\ I 97'5,006 1,061-!,9£18 1.172,120 3Ao,0>22 'j')J,709 o03,M.':itJ obi,Oo3 72'>,929 793,004 flb8,1Hl6 9',2,2!11 t,Oll3,7!n 1,14£1,300 371"1,323 559,6110 '::> 91) t 4 <' <J bl1o,?25 7 0 1 , ':i 3 :j 77li,BI'oS 84/:1,863 9~0,107 1,019,317 1,117,258 3J,),331 527,804 '::l77,!J'j3 o3!,787 b9l,':i83 7';7,260 829,386 901:1,583 995,530 1,1)90,971 3,2,5"8 '::>11>,282 So <J, o.~o 617,757 676,0o3 7'-10,113 810,1141 887,650 972,400 1,065,414 35l.l,9/~ 5<''i,Ob3 'i52, ,?.lj6 bl) lj, 061 660,959 723,430 792,011 867,290 9£19,907 1,0£10,564 3--17,':i<?2 iJ'l4, 139 ':i lj 0, [I:\ I\ 0:,90,/119 6<16, 260 707,!96 774,081 8tJ7,ll65 928.031 1,016,399 )·Cj \) 1 ~'-i <J '-IIU, SO 1 '-i2h,--<L18 57/,791 651,952 69!,398 756,635 828,218 90o,752 992,899 )~"5.~7<J '-l 7 3, ltJ I ">17,01o 5~:>5, 171.1 61d,025 676,022 739,658 809,1172 88o,OS2 'H0,0£11 52o,S<~2 IJ6.3, U49 SOS,t\133 552, !:!1:\9 601.1,11.-,7 66\,0'ib 723,136 79!,.?31 865,91.S 91J7,807 519dln q')3,218 LI9S,Oll0 51.l0,925 591,2o", 6£16, 1-!86. 107,055 773, l.l80 8!16,318 926,177 IJ 1 SCOUN T [I) VALUE OF BASE YEAR 11979) INTERCONNECTED SYSTEM COSTS IN $}000 ------•----------------------------------ESCALATION RATES----------------~--------------------·· Oi. ll% 5% 6% 7"1. 8i. 9~ 10% 11% 12'% ======= -------======= --------------======= ----------------------------------------------------------------------------- 42<,, 71S b23,S51 b/:lt>,l:\99 756,982 f13q,l.l93 920,195 1,0]<1,91£1 l,tl9r573 lr23Srl72 1.362,807 1115, 8 ~ 0 6Vi3,'57il 670,250 7 31\, lj 7 3 fii..S,914 897,3t3 989,!178 1,091,297 1,203,7£12 1,327,880 4\)6,320 59'-l,02') 6511,080 720,1198 793,933 875,100 9611,786 1,063,852 1rl73,2LI2 1,293,990 397,U2t> '579,890 6311, 312 7 0 3, 0 110 77!1,529 8'::>3,533 91.10,1:H5 1,037,212 1.143,61!0 1, .?61, 1 0 1 31{7,Q0l) ';1:>6, 157 o23,11S 6f\b,Otl3 755. 6!14 1:132,590 917,541 1,011,350 1,114,906 1,229,183 3 7 q, .:?•l'-1 'SS2,1:111 6(}6,287 669,610 737, )80 812,251 89ll,942 9B6,2tJ2 1,087,1115 1,198,201 371l,oo0 539,1:!il2 593,1:11:10 6':>3,606 H9,S99 792,1196 872,995 961,861 1,0">9,933 1.168,]27 362,3')1 52"1, 2 56 579,<'81 638,05o 702,325 1B,307 1;51,680 938,186 1,033,639 },138,930 ~5'-1, 269 51'-1,9/:l"'i 566 r 2 7 IJ 622,91J5 68'i,':Jll2 75ll,b66 830,976 91':i,192 1,008,106 1.110,582 3'-lb,il\)7 503,071 ">53,0£19 o08,2':i9 6h9, 2B 73o, 555 8111,863 89.?,859 983,310 1,083,055 3~H,75R 119 I, i.J t19 5'-lO, 192 595,98':> 653,38tJ 718,957 791,323 871,l6"l 9">9,226 1.056,323 Bld\5 'li-\U,22~ 527,t.>93 5/:10,110 o37,9;H 70!,1:l'::>5 772, Btl 850,089 935.832 1r030,360 32q,(175 ilb0,?.71 515,')40 ':ibb,621 623,tlOI:l 685,2V:i 75~,689 8?9,t>l2 9\3,106 1,CJQ5,1ll2 317,•J25 l.l':)B,62o 503, 123 S53,S;;J7 60o,453 669,081 73':>,960 809,715 891,027 980,bllll ~10, leo lll.lt<,26o !!92,230 54 IT, 755 59li,J0.3 6')3,)78 718,535 790,379 869,573 9S1:!,8LILI >O)Illk8 li3R,11'\9 litH, 052 528, 35 1J 51'\0,')44 631-\,112 701,597 771,586 8ll8,72b 93>,720 29b, q;q~ LJ211, 3.85 1170,!79 Sto,29tt 5o7,1o'l 623,t!70 685,131 753,321 828, £11:!5 911,250 ·•>·""'] • J J '-'··"' .J J J '\-o~.~ .) ,_.c.;J .J .. ... J rn ..... ..... 1979 1980 19f:<1 19tl2 t9e3 1 91HI 198'5 191\6 t987 I 91Hl 1 91'-9 J9lll! 1 9 'I I 1092 !993 1994 1995 1996 1997 -----·---1979 1980 1981 ---------1 91)2 1983 19~1.1 1985 ALASKA Pl.l~[P? AUlfHI!.'JlY ANCHO~aGE -FAl~HAN~S !NJ~NTIE ECONO~IC FEASIHILITY STUDY ~APlTAL DISBURSEMENTS I'l $1000 FOR ·ALTERNATIVE SYST~H EXPANSIONS !~DEPENDENT INTERCONNECTED COSTS -~7q COSTS -~79 4,0\1 2,009 1<lr2213 2o, 6•>6 1.16,9o7 81,9<12 lt,';'j1 H, I 72 .32,097 27,727 6r00.6 33,5'52 2ll,lll'O 106,'555 90,673 11~5.210 1.35,9ll0 9£!,71:>0 11'5,716 1 19, IJ 75 1\3,]91) 1 <l I , 3':1 0 H9,b9Q 58, 4':ill ]08,723 29, 8 ~~ 0 75,1.34 23. 9.~5 23, lOb t7,o~O 270 254 ADDI l!O~JAL DISi;URS[~l[NTS IN $1000 FOR UNDERLYING TRANSMISSION SYSTEM INDEPENDENT INTERCONNECTED COSTS -~79 COSTS -$71 fU~~ COMPONENT OF OPERATING COSTS .. IN $1000 FOR ALTERNATIVE SYSTEM EXPANSIONS .. JNOEPENOENT . ESCALATED $ 8,468 9,32£1 10.267 6r851 7.212 7, 9 33 8,65£1 9,015 INTERCONNECTED ESCALATED $ 7,6£18 8,1198 9,029 8,32£1 8,654 s.uto 8,745 9.109 SUSITNA CONSTRUCTION POWER COSTS IN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GENERATION INTERTIE TAPLINE COSTS -$79 COSTS -$79 . ·------------------------------. ------------------------------------· --~---------~~- 1986 l4H7 191itl 191-\9 199(\ ---------!<I'll 1992 19'-'J 1991l ]90", I 44(> ]Q~l .. -l TAI.iLE 6-5 23 AUGUSl 79 DISCOUNT RATt H.UO ·". <'5 M.50 .. tl.7'i 9.1_\C) 4.2'> 4.')0 9.75 1o.oo 10.25 10.':>0 10.7S 1 l • 0 0 rr1 1 1 • 2 ':> 1 l • 'i (l 1--' 11 • 7 5 N 12.00 ------·.-··--· DISCOUNl RATE 8.00 8.25 ll.So /j. 7 s --·--·---<f.vo 9.2'> 9.50 9.75 10.00 10.25 10.')0 10.75 11. 0!) 11.2? I 1 .SO 11 • 75 12.00 .J .) j ALAS~A POwER AUfHORilY ANCHO~AGE -FAIRBANKS lNTERTIE ECONOMIC FEASIBILITY STUDY TABLE 8-3X DISCOUNTED VAL~E ~F-~ASE YEiR £1979) INDfPE~D~NT SYSTEM COSTS IN $1000 -----------------------------------------ESCALATION RAT£5--------------------------------------- 0% £1~ 5:1:: 6% 7% II% 9% 10% 11?.: 12% --------------======= ======= --------------------------------------------------------------------------------------------------- <! 5 (I 1 llrl1 o<lo,Mt>7 701:1,932 777,23<l 852,386 935,0t>ll 1,02t>,007 1,1C'o,021 1,23':,,993 1,356,869 ll!!Q,5')8 t-32,139 69(!,645 759,218 832,i.15o 913,013 1,001,606 1,099,020 t,2\li:>,1lll 1,323,827 IJ.SI),9~8 t>l7,.'\13 67t:>,80t> 7£J1,701 813,080 891,578 977,892 1,U7?.,78<J 1,177,086 1,291,712 iJ;_>j,'i71l 605,877 bi:>l,li!Jl 72i.l,bb7 7 9IJ I 2<J 2 l:l70,71J2 954,844 1,0£17,287 1,1llf:I,R82 1,2oll,512 ·Hi'. IJS8 590,3<?0 o1Jt>,il1':> 708,101 77';,923 8';0,1J8/J 932,ll39 1,022,507 1,121,li7/J 1,230,199 LIO.~,'ili2 ')77,] 21:1 tdl,83'> 691,987 758,109 B3\l,7fl.7 910,658 998,420 1,091.1,838 lr200,7Qll YllJ I 9)') 56<~,292 ol7,o54 67b, )12 7tJ0,7tH M.11,o32 Hl:\9,<1131 975,00b 1,068,9Qfl 1,172,120 Ho, 5<'2 ')')1,799 60.5,054 bb1,0o3 723,929 79.5,00'1 861'1,81'\8 9'.>2.i'41 1,0'1~~.78~ 1,14ll,300 -~ 7 p,, ~ 2 3 ')39,o4U 590, 1l2ll oilo,225 707,')3.!4 77£J,885 IW/3,8o3 930,107 1,019,317 1,117,2')8 370,357 527,P.O<.i 577,353 o31,7fl7 o91,5H3 757,260 829,38o 908,583 995,':>30 1,090,971 362,558 51o,282 5b/J,630 617,737 o7b,063 7li0,1t3 810,£141 1387,650 972,400 1,065,414 3~1J,978 505,063 552.246 60IJ,Oo1 660,959 723,ll30 792,011 867,290 9<19,91)7 1,0ll0,564 3117 I ')'-12 <l'l,J, 13° 540, 111[3 590,7ll9 oll6,2ou 707,196 174,081 l:\tJ7,ll85 921'1,031 1,016,399 34l1' )l)'.j q~3,'>C'l 52H,<l<'H) 577,791 63\,9'52 o91,39H 75o,635 828,218 91)6, 752 992,1399 3 3 3d 79 4 7 _) 1 J IJ 1 ?17,01t> 565,174 611:1,025 t>lb,022 739,o58 809,472 8Ro,052 970,0ll1 326, ';IJ2 <l63,0«9 505,883 552,1'1119 o04,1Jb7 oo\,056 723,136 791,231 8b5,913 9ll/,807 319,876 Ll53,21tl <495,0/JO 540,925 591,265 61Jo, 486 707,055 773,480 tlllo,318 926,177 DlSCllUNTED VALUE OF BASE YeAR (1979) INTERCONNECTED SYSTEM COSTS IN $1000 -~·-·-·----------------------------------ESCALATION RATES--------------------------------------- 0% Uf. 5% 6% 7% 8% 94 I 0% 11% 12% --------------======= -------======= --------------===:::=== ------------------------------------------___ ..,.. ___ -------------- <J31l,030 o37,754 701,o06 772,207 8')1) 1250 93o,ll95 1,0:.H,776 1,137.008 1,2"i3,195 1,381,433 II<' Fj I 09 1 o22,o58 o84,d34 753,570 1329,539 913,ll78 1,006,197 1,106,585 1.221,613 1,3Lio,31.19 4\tl,lJ29 t>07,'191 668,5lJ1. 735,<~o9 809,426 891.129 9!H, 365 !,080,995 1,190,963 1,312,303 qo9,o)c, 5<13,739 o52, 715 717,B8o 71",9,H92 tl69,LI27 957,255 1,054,211 1.16!,211 1,279,261 3'-;19,ii'i9 579,P.01 o37,BLI 700,1'105 770,919 13/H:\ I 351 933,81.13 1,028,207 1,132,531 1,2LI7,190 391, ll15 56h,Ll31 622,390 684,209 752,ll88 827,881 911,1011 1,002,957 ],10Ll,292 1,216,058 3112,374 553 I -~4q 607,867 668 I OtH 7 34,582 807,996 889,026 978,1137 1,077,067 1,18'>,834 373,9t>8 51lll,b31 593,751 652,41tJ 717,183 788,t>79 P.67,'>7H 954,624 1,050,631 1,1<;6,LI90 3o5. 7'-lo 52>~,268 580,030 637,18<1 700,277 769,910 846,742 93],491.1 1,024,957 1.127,996 3S7,831l 51o,<'ll.., 5o6,oaJ o2?,3R1 o83,t147 751,673 826,1.199 909,026 t.ooo,o21 1,100.325 35o,uot ')0iJ,5'>7 ')').5,723 61)/,991 oo/,1)71'. /33,951 80o,H31 8!\7, 199 975,HOO 1,073,1.150 "5/12,')57 49),188 5ilt,113 59tJ,Oil1 o52, 555 716,726 787,711 8b5,991 9'::)2,269 1,0ll7,346 33'), 22.~ '-Hl2, Ul 52t:l,ii50 '>!l0,399 o37,2o5 699,98£1 769,1tH 84'}, 38.~ 929,408 1 I 021 t 988 .328,085 ll/1,376 51b,'12tl 567,172 622,59tl 6!:13,709 751,089 825,357 907,195 997,352 321,135 ll60,913 '.>O':i I f2Q 554,S09 608,328 oo7,!lfl7 733,540 1305,893 885,o09 973,lll5 3!/J, HO <J'iO, 733 1~911, u 40 541,7<11', 59<J,ij<;5 652,503 71&,4~0 7S6,97!.l 861l,t>31 950,•1';6 3U I, 782 <ti.I0,!'\2tl <I!:\3,0o2 5£>9,o2~ ",80,963 o37,51.1ll 699,89S 7()(!,51:!3 f\1.14,2/J1 927,552 ---~----· I .) --~ -.J ~t J .,.A·"•••• c .• ~-' ) .J j J ~ ;d J J ..... w --, 1979 !98U 19-'.!1 19~2 19R3 19Ri.j 19!:\5 191\o l9tl7 1988 l<i'iQ 1900 t ')9 I 19'12 !9<13 199/.j 19<15 1'19() 1'-''H 1CI79 1980 !9R1 1982 ) ~LAS~A PU~lR AU1HORI1Y ANCHVHAGE -FAl~HA~KS INJEMTI[ ECO~OMlC FEAS181LITY STUDY CAPITAL DIS8URSEME~TS I"l '!i1000 FOR ALTERNATIVE SYSTEM EXPANSIONS l~DEPENDENl INT[HCON~ECTED cusrs -$79 cosrs -!79 2,009 2o,ol\b 81,9·~2 .H.t72 27,727 .B.5S2 106,555 tu5,210 'l'~, 7oO 1 l 0 ,1.j7") 101,3~0 ')11,'~50 29,81.10 23,935 !7,o.SO 5,0!£1 17,785 ·58,709 11 ,551 32.097 6,006 24,£120 90,b73 135,940 1!5,71b 1U,!9t{ t9,69ll 108,723 75,134. 23,10o 270 254 ADOITION-L DISBURSEHEN1S IN $1000 FOR UNDERLYING TMANSMISSION SYSTEM INDEPENDENT INTERCONNECTED COSTS -$79 COSTS -$79 FUEL COMPO~ENT OF OPERATING COSTS Jll $1 0 0 0 F 0 R ALTERNATIVE SYSTEM EXPANSIONS lNOEPEIIIOE.NT ESCALATED $ 8,4o8 9,32'1 10,267 6,851 7,212 7,933 8,654 9,015 INTERCUNt.E.CTEO ESCALATED $ 7 1 o4R 8,498 9,029 8,3?1.1 1\,654 a,o1o 8,}U5 9.109 SUSITNA CONSTRUC.TION POwER COSTS .. I~ $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GENERATION INTERTIE TAPLINE COSTS -$79 COSTS -$7q ~-~· ··-------. !983 19~11 !9H5 19/ib 19"7 191:18 1989 1990 1991 1992 1993 1994 1'l 0 5 J99o 19'-l7 28 AUGUST 7tJ DISCOUNT RATE 8.oo 8.25 e.5o 8,75 9.00 9.25 Q.5o 9. 75 10.00 10.2') 10.50 10.75 I 1 • 0 0 11 • 25 fT1 11.50 1 I • 7 5 ...... 12.00 .j:::. OISC.OUNT RATE a.oo 8.25 8,50 8.75 9. 00 9,25 9.50 9. 75 10.00 10.25 to.5o 10.75 1 I • 0 0 11 • 25 11.50 11. 75 12.00 J ,} ,- ALASKA POWER AUTHORITY ANCHORAGE • FAIRHANKS lNTERTlE ECONOMIC FEASIBILITY STUDY TABLE 8•J•LL DISCOUNTED VALUE OF BASE YEAR CI9H) INDEPENDENT SYSTEM COSTS IN S1000 ••••••••••••••••••••••••••••••••··~·-···•ESCALATION RATES··~·····••••·•••••••••••••••••••••••••• ox 4% St 6% 7X 8% qx lOX 1U 12X ======= ======= ======= ======= :::;::: ======= ======= ======= ======= ======= 237,690 352,1.149 389,84Q 431,534 477,Q81 529,713 587,311 651,414 722,726 802,024 232,026 343,607 379,955 420,ll60 ll65,585 515,836 571,777 634,027 703,268 780,253 226,529 335,031 370,360 409,724 l.l':d, 568 502,386 556,724 617.180 684,417 759,164 221 .t n 326,713 361,055 399,312 4111,917 489,349 542,134 600,855 666,153 738,734 216,009 318,642 352,029 389,216 ll30,621 476,710 527,992 585,033 648,454 718,939 210,977 310,812 34~,274 379,'123 419,667 461.1,1155 511.1,283 '569,698 631,302 699,759 206,090 303,214 33ll,779 369,924 409,043 452,S72 500,992 554,8 B 614,678 681,172 201,342 295,840 .326,537 360,709 398, 739 441,049 488,105 ')40,1.121 598,564 663, 157 196,7~0 288,683 318,539 351,769 388,7'H. 429,872 475,608 526,448 582,943 645,696 192,250 281,735 310,777 3ll3,093 379,045 ljJ9,031 463,ll87 512,899 567,798 628,769 187,896 274,990 303,242 334,674 369,636 408,':114 451, 732 ll99,759 553,112 612,359 183,6o5 268,41.11 295,9?1\ 326,503 360,500 3Q8,310 440,.328 1.187,015 538,1\71 596,447 179,552 262,082 2813, 827 318,572 351,6ll5 388,1109 ll29,26'> 1.171.1,653 525,059 581 , 0 18 175,555 255,906 281,9.32 310,872 34.3,044 378,801 418,':131 462,661 511,663 566,0511 171,669 249,908 275,2.37 303,396 334,690 369,476 408,11':1 451,026 498,667 551,541 167,890 241.1,081 268, 734 296,138 326,591 360,425 398,006 439,736 48o,060 537, 4b3 164,216 2~8,420 262,419 289,0139 318,722 351,639 388,195 428,781 1173,827 523,806 DISCOUNTED VALUE OF BASE. YEAR (1979) INTERCONNECTED SYSTEM COSTS IN 51000 •••····-~---·~·w•••••••••••••••••••••••••ESCAL.T!ON RATES•••·•••••••••··-···--····--·-·•••••••••• ox 4% sx ox 7% ax 9X 10% lU 12% ======= =====::c= ======z ======= ======= ======= ======= ======== ======= ======= 238,419 347,569 383,QS9 1122,582 1.166,':186 515,562 570,0':13 630,6':19 698,037 772,913 233,022 339,177 373,675 412,087 454,846 502,429 555,362 614,225 679,657 752,361 2Z7,783 331,036 364,':i74 401,911 Lj 4 3, 1164 489,698 51.11,122 59tl,299 661,848 732,450 222,695 323,138 355,747 392,041 432,428 417,3')6 527,32\J 582,865 61.14,591 713.158 217,753 315,474 31.1/,182 3tl2,468 421,725 465,389 513,939 567,904 627,865 694,463 212,'153 308,036 338,873 373,182 ll II .345 453,784 500,965 553,1.101 611,654 b7bd4b 208,290 300,818 330,810 .361J,I72 401,276 41.12,5.30 488,38o 539,340 595,940 658,787 203,759 293,1:111 322,98':1 355,431 391,508 431,61£1 476,187 525.707 580,705 641,766 199,356 287,009 31'),390 31.16,948 382,032 ll21,026 1.161.1,355 512,486 565,Q35 625,265 195,07A 280,405 308,018 338,716 372,836 410,753 452,878 1.199,o65 551,612 609,268 190,919 273,9'12 300,861 330,725 363,913 400,786 441,74') 4P.7,229 S37 ,722 593,756 186,876 267,761.1 29:\,912 322,9o8 355,252 391,115 430,9LILI 47'j, too '>24,250 578,713 182,9116 261,71') 287,164 315,1137 31.1o,dll':i 381,729 1.120,I.Io!> 463,463 'JI1,!B3 564,124 l79,t21.1 255,839 280,610 308, 125 338,685 372,61'1 410,293 452r108 498,506 S4Q,974 175,407 250,130 2711,245 301,025 330, 76 I 363,776 400,422 441r0QO 1186,208 536,247 171,792 244,584 26A,v62 291.1,129 323,0b8 35':>,191 390,841 430,397 474,274 ':122,930 168,276 239,1911 262,055 287,431 315,597 346,8':>b 381,':141 420,019 462,694 510,010 ------1 -··''-'"' J J ,.l J J ._ .. _.,j ·-·"-·',. J .J _) J } J ,J ) -,-"<--\. -· .. , . ., -... J 'j ----1 28 AUGUST 79 TTl .!"-' U1 1979 1980 1981 !982 1983 1981.1 1985 19Bo 1987 1988 1989 1990 1991 1992 1993 19911 1995 199b 1997 1979 1980 19/H 1982 1983 1981.1 1965 19Bo 1987 1988 1989 1990 1991 19'l2 19'1~ 199ll 19'10:, 194b 1997 1 ALAS~A POwER AUTHORITY ANCHORAGE • FAlRBA~KS INTERT!E Eta~o~rc FEASIBILITY STUDY CAPITAL DISBURSEMENTS IN $1000 FOR ALTERNATIVE SYSTEM EXPANSIONS INDEPENDENT INTERCONNECTED COSTS • SH COSTS • $79 u, 0 1 I 11l,?28 1~,o.29 ~o,9o7 58,B2.S .11.':151 16.3130 32,097 526 1.195 43o />,bOO 5,890 33,955 22,30b 116,630 90,119 122.100 123, 3b3 72,8SO 73,001 37,275 70,091 7,555 2fl6 1.7,b30 270 2'JLI ADDITIONAL DISBURSEMENTS IN S1000 FOR UNDERLYING TRANSMISSION SYSTEM INDEPENDENT INTERCONNECTED COSTS • S79 COSTS • $79 FUEL COMPONENT OF OPERATING COSTS IN $!000 FOR ALTERNATIVE SYSTEM EXPANSIONS INOE"PENOENT INTERCONNECTED ESCALATED $ ESCALATED S 8,uoe 7,6!18 9,324 8,1198 10,2b7 9,029 8,654 8,74'5 9,015 9, 109 SUSITNl CONSTRUCTION POWER COSTS IN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GENERATION INTERTIE TAPLINE COSTS • S79 COSTS • S79 1 ···-·) TlBLE 8•3•Lt 2.s AtH_;usr T'l DISCOLI'H r<AH e.oo 8.2'1 ~.so. 8.7CJ 9.00 o.2S 'J • ':J (I 9. I':> I 0 • 0 0 10.<''::. 10.'::>0 11). 7 5 I l • o fl 1"1'1 i 1 • <' 5 I 1 • CJ !I ...... I I. 7'i 0'\ 12.vO OlSCOIJNT ~AT t l'l.ou t~.25 li.SO 13.7'1 9.00 9.25 9.~0 9.75 10.00 10.25 lv.c,u ll'.7S 11.00 I I • 2S 1 1 • 5tl I 1.75 12. vo ALAS~A PO~tW AUTHORITY ANCHORAGE -FAIM8AN~S INTEHTIE ECONOMIC FEASlijJLilY SJUDY DISCOU~TEO VALUE OF HASE YE4R {19/9) INDEPENDENT SYSTEM COSTS IN $1000 tABLE 8-4. '---------------------·----------------~-----------------~--------ESCALAl!UN RATES-----------------------~--------------- 0% 4% 5% 6% 7% 8% 9% 10% It% 12% -------======= -------======= -------======== ------------------------------------------------------------------------------ ·~utl,ll?b 'C>b0,5bb 725,o?._?_ '193,213 l:lo<1,7ol 9':d,QQ9 !,04t>,S25 1,JiJ8,507 1,260,188 1,383,148 '1 '; 'I , 'I') 3 o<IS, -~b"i 1(17,:)37 77U,!j/2 649,•'175 9.$1,S10 1,021,701 1,}20,8/.lll 1,2<:'9,80o 1,349,':>37 ... d i), \ 1.19 t) 5 I) , 7 7 II 1:>90,'-107 7S7,(l3f'. 1-524, 153 900,691 997,5711 1, 091.1, 1':)6 1,200,286 t,3to,886 <J 30, hll<l o1o,S79 675,218 759,1:>911 1:110,516 81l!:\, U91 97£1,122 1,061:1,<:'20 1, 171,o02 1,285,163 U2lr311 ooc,/6!'J b59,95o 722,112<1 741,927 l:lo7,P.72 9':>1,32£.1 1,0£.13,010 t,lll3,72o 1,254,340 1-+1?, ?._62 5H0,32<.1 c'IS,IOB 70t),LI15 77 5, 790 847,822 929,158 1,018,5011 1,116,632 1,224,387 a 1.'), 45 0 C:.,lb,c'">O 630,oo0 69 0, 1~">2 7~6, JllR 8,'1!,32!1 907,606 9'14,~:>80 1,090,.?97 1,195,276 3'l<J,'lh/ '::>t:d, ">21 61o,60! o7<1,920 75tj,9P,1 t\09,360 886,647 <i71,Sio 1,01)4,696 1,166,981 3Mt:>,SOI' '::>'::>1,131 60r',QJ<.~ oS'I,ti\J8 7<'?.,29<:' 790,913 8oo,261.1 941:1,992 1,u39,8\J5 1,139,477 37t:-,3hiJ ')59,070 589,o02 oa':>,101 70o,OLI7 772,967 8'J6, 438 927,087 ),015,603 1,112,737 370,450 527,327 S7o,o39 630,7il7 690,239 75':>,S08 827,151 905,782 992,0o8 1,086,739 >o<:',700 515,1193 56£J,(ll9 616,855 671.1,856 738,519 808,389 885,1)',9 9"69, 1 79 J,061,ll58 >':>5.161 C,{)tJ,750 ':)51,732 oo.S,292 6'j9,!'>1l5 721,987 790, I B 864,899 9llo,916 1,036,872 ~ u 7' 1\?5 lJ9~~,GI6 539,161 ')<>0,0K?{ 61.1':>,30/:l 70":!,897 772,369 l:lll':l,285 925,259 1,012,961 \'lU, hr:-,q Lll::\'1,,3SU ':52i\, 1 I 6 577,252 631,119 690,236 7')5,01:11 H2o, zoo 901.1,190 989,702 5~5.69i.l IJ73,(!66 516,761:1 "io4,713 ol7.~il5 674,991 738,25':) 81)7,629 883,o91 967,075 3c'br /i'lll 465,0<13 ':>0'1,715 C,C,2,520 603,1'\54 boO, 11.19 7?.1,877 189,555 863, 71.15 945,062 f) I SCOUiJTED VALIJt OF clASt: Yt:AR (1979) lNTERCONNECTt:D SYSTEM COSTS IN $1000 -----------------------------------------t:SCALATION RATES--------------------------------------- ox 1.1% St. 6% 7% 8% 9% 10% 1U 121. ======= ======= -------======= ======= ======= ---------------------======= ---------------------------- 11211,1\20 bi:'H, 09'~ 69I,H91 162,4611 flli0,512 926, 799 1, 022,162 1,127,522 1,2£.13,886 1,372,357 IJ!I\,9]7 1>15,1ll5 675, 129 7Ll3,EI31 1<19,706 905,768 996,':)58 1,099,061 1,212,254 1,337,207 1Jl)',l,2<i0 59A,3o7 oSI:l,di19 725,735 799,681 881,408 971,704 I,07!,ll37 I , 181, 5So 1,303,099 "t,'·IQ 1 Q 52 '>84,!36 6£15,03':) 7GH, 160 780.147 1:159,o97 947,575 I,Ollll,o2.S 1,151.,762 ),269,999 59tJ,!\B S/0,30P. 627,~:>71 o'll, OR8 761,176 838,61!1. 924,147 1,018,592 1,122,841 1,237,875 5 >' I , ·~ >i 5 5Sb,H71 612,7lit.l 674,503 742,7£18 815,139 901,398 993,31ft 1,09ll,7bb 1,206,693 313. ~b2 5113,1'\12 5913,239 t>S8, 3'10 l24,tlll7 79B,252 879,305 968, 776 1,067,509 1,17o,42ll 3o S, 0 I 11 531,119 '~8ll,l43 642,733 7o7,ll':io 778, 93'-1 857,848 9lll.l,944 1,041,0112 1,147,037 3';6,875 51o,781 570,41.13 6?7,':)19 690,':>59 lbO, 167 837,005 9<:'1,798 1,015,31.11 1,1l!l,504 3<Hl,<.IS7 50t>,7Ro ss7,126 612,733 o7ll,l39 741,933 816,/58 899,316 990,382 1,090,797 3·•1,2':><l 1.19'), l<:'ll C,l.l••,l/:11 ':>91:1,360 658,182 7211,216 797,0116 817,477 966,139 1,063,889 3_q,7'-,9 IJI\_S, ?l:ll.l 531,S<l5 5flll,390 o<~<:',67.~ 706,991'1 777,973 85o,2o1 94(>,590 1,037,756 5c:'a,'IL'J5 '-17?, lSi> 'JI9d51 570,1:\08 oi?/,':>91'! o90,?o':> 759,399 IHS, bi.lo 919,712 1,012,371 H•J,3ol 4 be,,, 3 v '507,4')7 ':)57,oP2 b 12, <UL} 67i.l,OOI 741,549 81':>,615 897,48(> 987,712 3t2,tJC,8 1.151,':>9rt 1~95, ;J84 51.1ll,7o<:' 591:\, o91~ 6':itl,l90 725,tl05 796,149 87S,Ii88 9o3,754 5l1 5, 733 l.l<ll,llll9 '18 <I, o?ll 552,275 5tlli,K'I\l 642,819 70o,7S1 777, 2~9 8')1.1,901 9Q0,47b ?9Q, IKb 4H,'-)7o <J73,u11; C,?l),1~0 C,7),jh9 6?7,874 690,17.S 7':>8 ,}.1110 834,50Q 917,8':>b J J I _J J .I ...., ...... ........ -------- ----···--·---- 1979 19KQ 19~1 191:12 \'183 1'!84 !085 1986 191:17 l'l813 19.'\'-1 )990 1 'I 9 I \992 )495 1994 l99'j 1'1'-16 1'.197 1979 19H() 191\1 1982 19H.3 191'4 191:15 l9ilt- )Q/<] 191-'8 19tJ9 14911 1'1'11 1992 199 ~ 1'-l<l<j 19'1'; 1991) I 9'1 I } ALAS.._A PIJ.,FR AUTHOHlTY A"'CH•Jf.ll\t;E: -FA l !.riiA!\11\S IN H.R 11 [ ECONO~IC ~tASl~lLJTY STUDY CAPITAL DISoU~SEME"'TS {1-; $1000 FOR All EIH-iA TI v f SYSIEM EXPANS!O~S lNDtPE.NOE"'T iNTERCUN!XECTED COSTS -$79 CUSTS -'i79 4,011 2,009 14,228 26,66b l.l6,9o7 81,9!12 11, 5S 1 3 7, I 72 52,097 27,727 6,006 53,5S2 2/.l,£120 106,555 9(),673 1!15,210' 1 5':.>, 9/J 0 9 1•, 760 115,716 ll9,1J/'-; 11 3, 1 91_1 IOI,3t\O &9,694 5t\,Q':i0 1013,723 29,840 75, U4 23,9\'5 25, I Oh 17,650 210 2~4 ADO! T IO~JAL DlSBUfiSI:::MEIHS IN $1000 FOR UNDE~LYING TRANSMISSION SYSTEM INUEPENDE~r I"'TERCONNECTED COSTS -~79 COSTS -179 6,6116 1,356 2,004 FUEL COMPON~NT OF OPERATING COSTS IN $1000 FOR ALT~RNAT!VE SYSTEM EXPANSIONS INO~PE"<DENT ESCALATED $ 8,468 9,324 10,267 6,1351 7 r? 12 7,935 8rb':i4 9,015 INTERCONNt:C H::D ESC ALA TED $ 7,646 8,498 9,029 8,324 8,65(J 8,016 8,745 q,1oq SUSITNA CONST~UCTION POWE.R COSTS IN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIESEL GfNERATION lNTERTJE TAPLJNE COSTS -$79 COSTS -$79 2,835 b95 697 696 3r0'>5 1 • .324 187 623 623 -500 2b7 .. 483 481 478 752 902 7311 Li:SO <Jl9 3011 1 TABLE 8-CI ll Aur.us r I<~ D lSCOi_lrH I-< ATE '1.uo B.2S i:I.SQ d. 15 'l.ill.! 9.2'> q. ':dl 9. 15 I o • 0 fl 10.2'; Ill, So 1u.7S I 1 • i.' 0 rr1 1 I , 2 'i II. Sf' ...... 11.7'i 00 tc>.uo DlS(OLiNl RATE 1:1.(10 8.2') ~>.':to 8.7') 9.00 '-1.25 9,50 9,7') 1u.no 10.2"1 IO.':tu J 0. 75 11.00 I 1 • 25 1 I • 50 l J • 75 lc.OO I 0 Ll .) ALASKA PU~f~ AUIHO~llY ANCHORAGE --FAI~BANKS !NTEHTlE ECO~O~IC FEASIHILJIY STUDY TABLE 8-liX lJTSClliJNTED Vt.LUE OF F!ASE YEAR I 1979) INDfPt:.ND!:NT SYSTEM COSTS IN $1000 -~-~---~-~---------~~-~~---~----------·--ESCALATION HATES--------------------------------------- 04 ll7. 5% 6% 7% H~ 97. 107. 11% 12t -------======= ======= -------======= -------======= ======= -------------------------------------------------- llbU,tl2b ~oJ,.56o 723,1J2?. 795,215 ~\1)9,161 953,9Q9 I,Ollo,':>25 l,[lltl,307 1.260,[81:1 1,383,148 ll'~9.'-153 o4'-,,_~b5 707,037 7 1 Lj , .fl 7 2 8Q9,U75 '131,510 1,021,701 1,120,84ll 1,229,80o 1,31J9,537 Lj ·'I!), Ill 9 !• 3 (', 7 7 4 o90,907 757,058 1-\29, 753 909,697 997,574 I, 09'~,! 5n 1,200,2.86 1,316,886 4 5 !j, 6 0 4 blt>,579 o75,21d 759,69Q l:ll0,576 IH\I),ll91 974, 122 I,06H,22U ],171,602 1,255,!63 'J21,311 o0?,7611 6':'>9,956 7?2,H2'~ 7b1,'~27 667,872 9':-JI,524 1,0IJ5,010 t,lll3,-726 1,254,3110 lj 12,262 SHe;, .'>29 bi.l':i, l OH 7 0 o, tJ I 5 7 B, 790 P,47,i:l?2 929,158 I,UJ.H,'i()Q 1rll6,o32 1.224,387 II'' ~, ~ Scl :)7o,25U 63ll,6b0 0 9 lJ, IJ ';. 2 7':ib,J4fl t12tl,3?ll 907,oOo 9'11l,ot\O 1,1)90,29"1 1.195,276 ~9·1, 'lt> 7 r,6~,521 olb,601 o·7~~, 920 l3t:J,9i37 809,360 l:lfl!), 61~ 7 971,':do 1,064,696 1.166,981 V-<1:1, SuH 551,1)1 1>02,91'-l I)C,9,501:l 7?2,292 /90,91) 8bb,2bli 9<Hl, 992 1,0)9,M05 1,!39,477 37B,3o4 53L>,IJ7u 5il9,o02 6ll':i, 101 70tJ,047 772,967 846,438 927,087 1,015,603 1.112,737 370,,J50 ':J27,.527 576,63"1 o30, 7fl7 690,259 755,508 1'>21,151 905,782 992,068 1,086,739 )t)2,7ll0 51'>,1:193 564, t)! 'l bl6,tl55 67ll,l:l"i6 73~-<,519 130b,389 bl:l5,0')9 969,179 1,061,458 :> ':> ':>, I o i 'J()tJ,7'J9 551,/.32 60~.292 659, .~1'15 "12 I , 9 fl 7 790, u 5 864,fl'-/9 946,916 1,036,872 "'iiJ7,62S 495,916 'i5'!, 167 590,08/'1 6ll5, Hlrl "105,1397 772,369 54"i,285 92':>,259 1,012,961 _$/J (I 1 b0'-1 llfl3,3':i4 521<, I 16 ')77,232 631,\19 b'I0,23o 75':>,081 l:l2o,200 90Q,190 989,702 35.$, 694 Q75,0oo Slo,768 564,71.5 b\7,50') 671J,991 758,255 807,629 81:\3,691 967,075 5t:'t>,H9ll ll63,1.)4.$ 505,71':> ':>52,520 603,85ll o60, 1«9 721,577 7119,')55 863,74':> 945,062 01SCOUNTE:.D VALUE OF !-lASE YtAR (19 70) !t~,TERCONNE.CTEO SYSTEM COSTS IN $1000 --------------------------~--------------ESCALATION RATES--------------------------------------- OY. LJ<; 5% 6% 7% 8% 9% 10% 114 12% ======= ======:: ======= -------======= ======= -------======= ------------------------------------------/j!J\,!34 o~<?.,?97 7(16,'-,91; 777,o90 85t>,269 0 1J3, 101 1, 0 ")9, 0 2 5 l,l41J,<J"i7 1,261,909 1,390,9811 ll31.!2ll 627,1!99 6R9, 71' 75H,928 l:l35,ll?1 910,932 1,015,278 1,116,349 1,230.125 1,355,676 IJ21,'-l0(1 612,3.33 to73,.511 740,706 8\5,174 l:l97,436 981:\,283 1,081:\,580 1,!99,277 1,321,1112 4 I I , 'ill 0 C.,07,ai:IS 657,'>76 723,00':5 795,511 57':>,S91 961<,01':> I,Ool,t>22 I, 169,333 1,288,159 402,742 5~'-1,042 b4I,FI93 70':>,809 716,411 1:\5«,376 9lli.),IJ49 J,05S,ll<Hl 1,140,266 1,255,882 .3<13,796 570,491 &2o,81~/ 68'1,102 7':>1,fl''io 1'133,769 917,')6/J 1,010,o:B 1,112,045 1.224,5ll9 Sti5,095 S'J7,H9 h!i:',225 672,1:\t>tl 750,tl5\) f\13,752 b9':>,336 985,353 1,084,643 1,194.131 .37o,o31 5'~·•,514 59H,OIIJ 6')7,091 722,315 79t.J.,.305 b73,71J6 961.383 1,058,0311 I, 164,597 3bH,3q6 5.32,()bb 584,199 641,/51'. 705,2'J'-I 71':>,411 852,771 938,100 1,032,!<J3 1.135,918 .5t>0,3>i4 51'4,"'1)? S70,16'J 62b, 135'l b8t'>, 155 "157,052 552,394 915,1Jf14 I,Oo"!,O<:J3 1,108,066 1,52,'~1<7 ')OH, 191 557,711 ol2, 56b b72,b7b 75'1,210. 1:\12,':>94 t\93,511 91:12,712 l,Obi,Ot6 1,45,001) 491,, 744 ':>45,015 'J'JII,2f\l 657,0IJ8 72!,B69 793,553 872,11>2 959,027 1,05l!,7ll2 537,bl5 .J/3':>,611 S32,t>68 51:\'I,SH') 6lll,eS5 70':>,014 l74,o53 8':>1,418 936,014 1,029,217 3.H1 ,ll26 IJ71~,71lll ':>20,1>':>9 '>71,267 627,0/B 688,629 756,1J7tJ t\31 , ?S 7 913,6':>4 I,QOII,II19 323,428 'lhll,?4ll 50o,97!:i 558, ~16 oi2,12U 672,699 738,810 511,663 891,925 980,325 31o,6lll 45~,403 ljQ7,616 ')£l5,7!8 5'-lil,7"i2 657,210 721,63') 792,ol7 810,807 '1'36,912 1,(>4,9/? 44'1,019 <t86,i61 '::>.5.3,llh':i se5, lo7 642,\ll9 7()11,93':> 77LJ,I03 8':>0,280 934,! 58 -,.J J J if,''-' .J _, ,I ~.eel .,.) J .. ,J J '~-.I i! 3 hl)\iiJ!' i i'l I"T1 1979 !9(\U I '71:\l 19f\2 191'13 19R4 191'.5 19~>6 l9R7 l<lf\8 I 9fl9 1990 1991 19'12 1993 l</'lil 19<15 19<l6 19<17 1979 1980 19Al 19R2 1 9!15 1 <H< 14 191:\'5 1</~b 19H7 191:\8 I<Jt'9 1 '190 J </9 1 1 <1Q2 1993 1994 1995 199b 19<J7 l ALASKA t>OI~t.!-1 A!.llHUWIIY ANCHUWAG[ -FAlHKANKS !NTEWTIE ECON0MlC FEASlHllfTY SlUDY CAPITAL DTSBUNSEME~TS IN .itOOO FOR ALTER~ATIVE SYSTEM EXPA~SIONS lNOEPENOENl INlERCO~~ECTtO COSTS -~79 COSTS -$79 2,009 2o,666 t\1,9~2 37,172 ?..7,727 B, 5'>2 1uo,5'lS 1'6,210 4'1,760 11<1,'175 101,350 '::iti,I.I'Sil 29,8il0 23,935 17,o30 5,014 17.71;5 58,709 11.5'>1 32,097 6,(!0o 2<J,Ll20 90,673 135,9QO 115,716 113.198 il<l,b94 10H,723 75,13Q 23,106 210 254 AD!Jl Tlil~-J~L DlSAURSE•1EN1 S HI $1000 FOR UNDERLYING TRANSMISSION SYSTEM l~UEPENDENT lNTEHCUNNECTEO COSTS -179 COSlS -179 ----------~----- 1, 35& 2,0011 FUEL COMPONENT OF OPERATING COSTS IN $1000 fOR ALTERNATIVE SYSTEM EXPANSIONS INDtPENOENT E.SCALATEiJ $ 8,1.168 9r32ll 10,267 6,8~1 7.212 7,933 5,651.1 9,015 INTfRCONNECTEO ESCALIITEO ~ 7,648 8,1Jq8 9,029 8,324 8,651.1 8,016 8,745 9,109 SUSITNA CONSTRUCTION POWER COSTS II~ $1000 fOR ALTERNATIVE MOUES OF SUPPLY DIFSEL GENERATION INTERTIE TAPLINE COSTS -$79 COSTS -$79 2,835 267 -~-~-----·--·-----~----------------------695 483 697 1181 o9b 478 3,055 752 1.321.1 . 902 187 734 623 430 623 ll19 ~5QO 30ll ) TABLE 8-IIX 23 AUG•JST 79 DISCOUNT RAlf 8.00 I:I.<'S c.'JO 5.75 9.00 9 • .?5 <i.':JO '1.7", 1 u. ,, p I 0. ,<~ I \> • ·c 1 C • I ') f'T1 1t.ou 11 .25 1 l.')v N 1 1 • 7 5 0 }2, (I() DISCOUNT h'ATE B.oo 8.25 ~-~0 8.75 9 .lHl 9.25 9.So 9.7S to.oo 10.25 11.1.':>0 1U.7<; I I. I• o 11.25 tt.so l I • 7 S 12.00 QL~S~A PUwt~ AUTHO~llY ANChORAGE -FAIRAANKS INTE~TIE ~CUNOMIC FtASIHILITY STUDY DISCUUNTED VALUE OF BASE YEAR (tq79) INDEPENDtNT SYSTEM COSTS IN $1000 TAI:ILE 6-5 -----------------------------------------ESCALATION RATES--------~--------------------------~--- 07. 4% 5% b% 7% f\7. 9t lOt 11%. 12% ======= ======= -------======= ---------------------======= -------------------------------------------------------- ;o'JS,710 373,6"2 £11l,tl07 ll5),201 ll99,483 550,738 607,">02 670,367 739,91:\':, IH7,076 o::' '> 1) , 3 1 1 .5o':>, 1 ')tJ ·Hl1,6CI/I 41!2,573 4117,603 ':>37,460 S92,662 65),7~3 721,<l56 796,376 ?;•5, ()I) 1 3Sb,fli:59 392,on3 '132, 25 ~ 476,072 52 1~.57"> 578,265 631,698 703,41'\1 776,307 239,~!,7 54H,1:!59 31:!3,o'l3 <l22.233 llb<l,878 512,0b9 S64,29S 622,094 61\6,059 756,845 2 !,4, fl13 3<ll,(l57 >,?•J, 980 412,501 ,.<;<1,009 1199,'130 5')0,731:1 606,'154 669,154 737,97~ 22'1,Q2iJ 33_s,47,. 366,514 403, 1)1.19 iJ43,45'j 48/:1,11J5 537,':>80 ':>92,264 652,7')4 719,666 N.0.,,1o/ 32t>,]04 351:\,df\9 ~9.~,Hh7 455.~05 ll7b, 104 5211,/:IOtl ~lf\,007 636rtl113 701,909 c'?u,537 _'ilii,<~4u ~50,.::'95 3134,947 II c? .3. 25 0 ll65, 5'1 3 ')12,408 5611,170 62l,L102 h8ll,682 <'lh,il30 _q I, <17'1 342,Sc'6 37o,279 413,579 IJS4,/:l03 S00,369 ~50,738 606,417 1:>67,966 / 1 t, b4 s 305,205 5 3'l, 9 7 3 36/,1'-'Jo 4 ()(I, 18 3 4llll,322 481:l,o71:1 537,6'18 591 rl:lB 651.746 ·'' ! I .S /1 29H,o1~ 321,o31 5S9,6o9 39~,0':JLI ll 311 ,, 1112 'l77,325 525,037 577,154 &36,004 ?•.•),212 292,.::'13 320,1.192 351,711 31:\o, 1 e2 424,2"iU 1166,297 S12,7'l2 56<l,O'l7 620,723 1 99, I 61 21'\':>,983 313,550 543,975 "371,~':>9 414,640 li':J~.~84 ':>00,801 550,138 605,590 1<1':>,21~ 279,<1.::'2 306, 199 536,455 369,118 40~.300 l)£1~,176 48'1,202 537,1114 591,!189 l 'i 1, q l ?7·~,1)2':) !J()0,232 329, 13R 3bl,050 396,223 43S,063 471,956 525,261 577,506 tH7,b?6 2nb,2&o 293,1:1 1•3 322, ()('iJ !J'J5, 1 oe 587,399 '•?5,236 466,9f\9 '>13,069 S63,927 II', ~, 9 7 7 2o2, 1u2 ?.1'.1,621 31'J, Ill~ .3 11 ':J, 4 0 4 311:\,821 41~,oll'l 4')6,353 '>01,225 550,738 DISCOUNTED VALUE:: OF BASE YEAh' (1979) INTERCOIIJNECTED SYSTt:M COSTS IN $1000 -----------------------------------------ESCALATJO~ RATES-------------------------------·------- 0% IJ% 5% 6% 7% 8% 9% 10:( 11% 12:( =====-== =======::: ======= -------======= ---------------------======= ------------------------------------------ ?.37,!Jt0 .$56,112 ~94,816 437,9o2 486,0')2 5)9,638 599,334 665, IH 5 739,828 822.198 231,90') 3L~1,4ct> 385,040 426,963 473,o79 52':>,725 583,695 648,243 720,092 800,01.12 22b,o':>tl 5~9,003 37'J,5o2 416,301 '~61, b88 512.244 ')68,':>41.1 631,222 700,978 778,587 221,565 .$30,!<33 361>,312. ll05, 96tl ll5Q,065 IJ99, 180 553,1i64 614,752 6/3.2, 464 757,808 216,1,]9 322,<~00 ~~7,459 39S,9112 1138, 74o !11\b, ">1 7 539,638 598,756 66!1,529 737,683 211.815 315,221 3t11J,ti14 3Ho,2?5 '•27,131'> 47ll,21l3 52~,851 5113,27'5 61l 7, 15 3 7!8.188 ?ll7, ISO )07,i62 540,LJ21'-376, 197 !117,21:13 462,344 ':>12,488 561:\,273 63ll,3t7 699,301 202,bl9 300,'J2u 332,293 367,6')') <l!l7,012 <l5tl,il08 499.~3/J 5~3,732 614,002 681,002 19~,.?16 ?95,4<f9 !>24,399 351:1,787 3'/7,050 439,&21 486,975 ':>39,638 598,190 66.$,270 193,959 286,6131 316,740 !J':!O,lf\3 3Hl,!J88 '<2H,772 1174, 798 52~, 971.1 582,864 646,08';) 189,162 c'IJv,Vo3 )09,506 5<1l,t134 37b,Oi4 4!11,250 462,990 512,727 568,007 629,1130 1t>S,7112 273,o37 302,041 333,135 .H)t\, 920 4iJII,044 ll':!1,53fl !.199,882 553,o03 613,285 pq,Hl'i 261, ~qb c<JS,<l~o 3?S,I371 3oO,IJ'lo 391l,142 '14 0. 4 30 ll87,425 539,6313 597,b3LI 117,991'\ 261 d39 21'\I:\,2Rt> 318,23'1 ~')1,532 38!:1,535 429,6')6 47S,~4LI 526,096 58.:',!160 174.2116 25~,455 2HI,ntl3 310,531 343.221 579,213 419,202 465.625 512,962 567,71J6 170,677 249,7ll0 275,271 303,6)8 33'J,154 370,167 409,060 45<:',256 500,221l 553,477 lb7, 167 244,lb7 269,0LI4 2<fi> ,.t,~LI 327,323 361.386 399,2lll !141,227 Ll87,1:167 539,6.38 J "" J ,-1 J .J J I ~J .J' J I Z3 -"UGUST 7~ f'T1 N ...... 197'-1 lOtiO 19>31 19H2 !9t\3 19~11 l 9 K-5 l'-11'16 Jql:\7 19i\ll 191•9 )9'10 J qr~ 1 1 'I'} 2 1993 !994 l'-14':> 1096 1'1'17 1979 1980 1481 19M2 1983 I q_p. II 190~ 1'-l~o lql-\7 I llh8 191:'4 1'1'10 l<l'-11 !9'12 1943 !944 1995 J9<ln )'197 l ALAS!I.A POnt!~ Al!lfil'Rl TV ANCHURAGE -FAlNHAN~S l~IERTIE ECONUMiC F~ASl9ILITt STUDY CAPITAL DISBURSE~ENTS 1 IN $1000 FOI< ALTEA~Al!VE SYSTEM EXPA~SIONS FUEL COMPONENT OF OPERATING COSTS IN $1000 FOK ALTERNATIVE SYSTEM EXPANSIONS --·--- INDEPENDENT INTERCONNECT~[) COSTS-579. COSTS-$79 4,621 2,009 15,5911 2b,6b6 1.18,1:\74 ~1,9112 -----!1,515 --------------- 37.172 32,062 21 ,1<'7 492 7, !52 ?._,472 7,')':15 lhll73 23,] 10 30,')Ll9 21,920 £1~,031:1. ------------------- 82,2110 l.j_$,!1ll 101,3':\0 89,o94 58,450 10!:1.72.S 29,840 7C,, 134 23,935 23.106 U,tdO 270 2511 ADDITIONAL DISBURSEMENTS l NDI::YENDEN T ESCALA T£D $ -----· ----------- INTERCONNECTI:.D ESCALATED $ --·---~-------- IN .1>1000 FU~ U~DERLYING TRANS~ISSION SYSTEM SUSITNA CONSTRUCTION POwER COSTS IN $1000 FOR ALIERNATlVE MODES OF SUPPLY I rwEPUJDf.hJl CDSTS -"1>79 lNTERCO:IINECTtD COSTS -$7'1 1.~56 biESEL GENERATION cosrs -$79 INlEIHIE TAPLIN£ COSTS -$79 1 TABLE 8-S Z5 AUGUST 7'1 DISCOUNT ,; A Tl: 8,1'0 1"1.25 ~.':ill K. 75 () ~ (.1 0 '1,2'> '"i,SO '1,75 I ll. (l 0 IO.<'S I 0. ':>(I 1 o • r c., rn I I • '' iJ I I , <'5 I I • S 0 .N I I • 7 5 N 12.00 DISCUUfl.l ~Aft a.oo 8.2':l 8.50 8. 75 9.00 9.25 <~.~o 9,75 1 0. ,) 0 10.25 10.'::10 IV. 1':! 1 I • 0 0 11.25 11.50 11.75 12.(10 .. "1 .t I ALAS~A POWtR Al)THONllY ANCHORAGE -FAIRBANKS INlERTIE ECONOMIC FEASI8ILI1Y STUDY TABLE 8-SX DISCOU~TED VALUE OF BASE YEAR (19791 INDEPENDENT SYSTEM COSTS IN $1000 ----------~------------------------------ESCALATION RATES-----------------------------~--------- 0% 4% 5% ox 7% 8% 9% 10% 11% 12':< -------======= -------======= ======= ======= ---------------------------------------------------------------------- 2SS,770 373,662 4!1,1107 «':d,201 49<?,41:\.S 550,731:1 607,502 670,367 739,985 f\17,076 250,)11 3t>S,ISI.I 401,tl91:1 41.12,573 1.187,t>03 '::-37,1.160 592,662 653,783 721,4':!6 796,376 ? rJ ') 1 i) (J 1 3"it>,KI:'9 392,o63 432,25.~ iJ7o.072 52t.i,575 S7fl,265 637,698 703,481 776,307 2.~0,I'd7 3'lt1,1'59 38),693 422,233 46'-l,tl7tl ?12,069 56ll.c95 622,094 o8b,OS9 7<)6,84':! c' VI,; I 3 )1.!1,051 37 11,9111) 4)c',50! "54,009 !199,930 550,7.38 606,95ll 669,t':!ll 737,972 22CJ, '12£l 533,471.1 366,51<1 <103,049 Lll.l3,tJ5'J 488,11.15 537,580 592,26<1 65c',7Sll 719,666 225,167 326,104 3:.1i,2H9 )03,,.,h7 iJ_)3,c'05 l.i7b, 704 52tJ,i\(18 578,007 636,81.13 701,909 220,537 31tl,9LIO 350,295 31:111, <:147 423,2Su 465,593 512,1.108 56<1,170 621,402 684,682 2lb,030 311,975 3LJ2,Sc?o 37o,?.79 413,579 I.I<)I.I,M03 ')00,36'l ')50,738 60o,417 667,'l66 211 ,I,<J 3 30S,203 334,973 367,RSo I.IOLJ,ll:l3 4<1LJ,322 <1!18,678 537.b98 591,873 n51,7li6 2U7,371 29/:J,611:1 327,o31 3S9,o6'l 3'15,05ll 1.134,1LJ2 LJ77,325 525,037 577,754 636,0011 N3.212 2'12,213 320,1~92 351,711 386,11:12 421.1,250 £166,297 512,71.12 5b4,0li7 620,723 199,1ol 2i<'),~l'3 513,<;50 31.13,91':! 317,559 1.111.1,61.10 <l55,S84 500,801 ':!';1),738 605,890 1YS,215 27<:1,922 30o, 10<:1 336,1..1')3 369,178 405,300 445,176 <189.202 537,814 ':!9l,liB9 191.371 274,025 300,232 32<:1,13tl 361,030 396,223 <135,063 477,936 52S,261 ')77,506 11~7,62o 26H,2Rb 293,d 1J3 322,021.1 3')3,108 3R7, H9 425,236 46b,989 513,069 ':!63,927 1d.S,'Il7 262,702 287,621 315, lOS 31.15,1.104 37H,821 415,681.1 456,353 501,225 550,738 DlSCUlJNTELl VALLIE OF !:lASE YEAR (1979) INTERCONNECTED SYSTE.M COSTS IN $1000 -----------------------------------------ESCALATION RATES-------------------------------~------- 0); 1.1% 5% 6% 77. 87. 97. 10% 1U 127. ======= ===-==== ======= -------======= ======= ----------------------------_____ _.._ ---------------------------- 2 1Jo,6l":! 3bb. 1;1{19 liO"i,9RI\ LILJ9,539 1.19~, t)llll 552,057 612,191 679,121 753,5'l6 f\36,439 2 1J1,130 358,111 .S'lo, 115 438,113'1 485,561:\ 538,037 596,4lll 661,4314 733,141 814, 15'l 2.~S,thl4 3<19,595 3fl6,S42 1127,678 473,1..171.1 ':icLJ,li50 SA1,180 644,299 711.1,509 792.582 23\l, 6:~2 341,335 371,257 <117,2/.lll <161,750 511,280 56o,390 627,6'l7 695,878 771,683 22'J,oll'l 333,320 3613,251 <107,121.1 LIS0,383 496,513 ':!52,057 611,bO'l 677,828 7':!1,438 220, 7<>9 32'),':>43 359,":!14 397,310 1~39,360 486,137 538,164 S9o;018 660, B 7 731,825 21<),911{1 317,996 3':!1,037 387,790 42t1,670 4711,136 52<1,695 580,'l06 643,388 112,821 211 dill 310,671 342,811 371:1,554 418,3ll2 462,ll99 511,637 566,258 626,961 69li,ll06 2uo,90"i 503,'161 33<1,8('8 3()9,593 4ll8,('1.14 451,213 1.198, ''175 552,057 611,039 676,560 202,'J511 2'1o,b57 327,080 360,1:197 391.\,I.IP.6 440,26'::1 486,o96 S38,2~8 595,603 65'l,262 190..521.1 C'tl<l,95':l 319,SS9 352,LIS8 389,019 1.129,6<16 ll]IJ, 787 524,93o 580,639 642,li95 !9ll,2!3 2P.· 3,1.146 312,2':17 34'1,267 379, tl32 1.119,343 llb3,235 511,981:1 566,128 626,240 1'1(1,215 271,124 305,161 336, 31o 370,9lb 1~09, -~46 452,029 49'l,429 ')52,057 610,479 IH6, 327 270,9tiiJ 2'18,282 328,S'l7 362,261 399, 61J5 441,157 41'17, 24 6 ':138,410 595,196 11~2, 546 26S,Ul9 2'l1,S96 321, J 0 2 353,1160 390,23\1 430,607 475,427 525,173 51)0, 375 t71';,86fl 25<1,22LJ 2!:15,1(>1 31.$,1123 3£1':>, 704 381,091 420,369 463,960 ':112, 332 Sob,001 175.290 2';3, '::~92 27tl, 192 3 ()I,, 1 'J ll .B7,785 57?.,220 i.!lV,ll32 452., 833 li99;f\75 ·552,057 J J I .I J .J il I .J .I ~J .~· .:1 J J N w 1979 l 1Hl0 I Q/11 1'1£12 l'l/13 l'lt<4 1~!-<'> J<l>\t) 191:!7 191:lt1 11/liQ 1 QfJ ll 19'11 1 'I 'I~ 1 9'13 1 q ·~'I 1'14':1 JQO!:I )<147 11179 t91i0 I 9/i I 19iic? 14113 19~.:1 JQ~O:, JQflo 14117 1-l"A I ~.-14 14'11) 14 '1\ 1Q<.Il l\.1<,13 LY~tl l'l<l'> 1'-1'-lt> JQ'lf IHI\S"A P!l"EI.' AllnHH<fTY At-.C~t(Jt-!A(;t -fAl14fHINK5 PII!:.IHlE ;tco~O~lC ~EASIBILITY STUDY CAPlT~L OJSBUHSEME~TS I\i UOOO FOH ~LTERNATIVE SYSTtM (XPANSIO~S HH>EPI:~:OENT l~TE.HCOi~NECrE.D COSTS -~10. COSTS -$79 2,009 ~o.t>i>b 111,9.:J2 '37, I 12 .? 1 ,J ?.7 7,1':::~?. 7,<;r.;5 i?l,!IO 21,920 t'>?., 2•) () I o I ddl! ") 8, ~~., () ?.9,840 iB, 9.S':i 17.6'0 5,0111 l7,HlS ';8, 7l)q 11,':115 32.06«!! 492 (!,tt72 a,t~73 30,549 1.1 ~, 11 )1:1 (l ~ 1 q I I 1:\9, n9:J I (I 8 , 7 i' J, 7<:;,L34 2.St!Ub 270 ;?~U AD l)! f I I H• A L D I s tW H s ~ ~·EN T s iN $1000 FIJH UNO~~LY!t•G lHANSM[SSION SYSTEM ~~~EP~~OtNl !Nl~RCUN~~CfED cu~TS • ~79 COS1S • ~79 1.3'56 2,004 FU~L tO~PONENT OF OPERATING COSTS IN $1000 FOR ALTERNAllV~ SYSTEM ~XPANSIONS yr.otPE.NOENT ESCALATI:D $ INTERCONNECTED ESCALAfED "' S0SITNA CONSTRUCTION POWER COSTS IN $1000 FOR ALTERNATIVE MOOES OF SUPPLY OIESFL GFNERAFIUN INIERTI~ TAPLINE COSTS • $7~ COSTS -$79 D1SC0!1'H fJ Jl ! f-_ Ct. lH• 11.r''"> M • "> r) 1_1,7., 'I. 1l 0 '1.?<, '1,'-,P 9. 7 ') 10.00 10.25 1u.-:,o 1u.75 I I • 0 tl rTJ I l. 2S I I • c., I) N 11 • 7 '-, +=-' 12. oo I) 1 SCChJN T RATt 8,0{1 6,25 A.-:,o ~.1S q • Q I) 9,25 9.SO 9,75 10.00 10.25 10.50 10.75 l I • o u 11.25 1 1 • 5 n 1 1 • 7 c., 12.00 ··-·-· ~<c~~ , __ , J ALASKA PUWt~ AUTHURllY A~CHOR~GE ~ FAlRrlANKS INTERTIE ECONOMIC FEASldiLITV STUOY TABLE 8-6 !JlSCOUtHED liALUE OF 13ASE. YEAR ( 19 79 J I NOE:.PE~Of: NT SYSTEM COSTS l.N $1000 ---~---~---------------------------------ESCALATJU~ RATES--------------------------------------- 04 ll% 5% 6% 7'1. 8% q:, 10% IIX 12X -------==~:::=== -------======= ---------------------======= ----·----------------------------------------------------------- ?t>l,!.1?7 3Hl,Vl9 419,1~02 461,11oo 501:\,9U 56(1,973 618,607 on2,lllt 155,044 831.230 "'"'", ;~bb 57?.,3ob i! (I<) r 7 } ll 451,0P.3 496,1'43 51J 7 1 lll;l'i 60~,5£12 665,'>85 75U.,247 810,239 ?Sil, O') 7 36"5,'l5d ~ 0 0, 3'14 4liO,S9<-I lit\5, 127 53£1,401 581:1,925 6£19,258 716,017 789,885 2£14,795 3">S,ltl9 ~'11,2.?2 £130,'1013 £173,752 ">21,698 574, lliO 65S,LII4 6'18,335 770,146 23'1,676 3£17,.'151 "5R2,3o0 LJ20,515 llb2,10o ">09,367 ':>60,'173 61t;I,OO:,I 681,181 751,002 2$·•,o94 34U,l3., 573,/SO Ill 0, 9 0 5 £1')),91:\0 £197,3'14 5117,610 1:>03,137 66£1,538 732,43<' <'2", ''u;, B2,il3b -~os, 5.P.2 liOI,56R. 4•~ I, 562 4115,769 ':>3£1,638 5t\H,663 6£18,389 714,£117 22'), 127 S25,3i!o 551,25•) !,92,497 ll_) I , I~ 112 '-1 7 lj, Q 7 9 522, 0 '13 57!.!,613 632,717 1:>96,937 220,')_~4 31b,251 .Sll'.l, 3llo · 38 s, 6i\l ll21,610 463,51,3 '509,1\13 560,973 617,506 679,976 21o,l!h2 311,)61~ 3ll1,661 57'),11£1 £11?,"057 452,tlo2 497,936 5£17,130 602,7£11 663,515 211,71)7 ~0'-l, obO B!l, 190 366,786 Qu2,771J IJ!l2,51ll tl8o, 400 ":>3!.!,870 588,liOo o47,538 20/,i.!o6 29~, 1£10 326,925 35R,b'll 395,75~ ll32,ll')9 !.!75,194 522,381 51<1,1188 632,028 20,,536 291,79o 319,~60 350,fl20 584, 9tl·~ !.!2.?,o8H 4t,ll,307 510,.?'51 560,973 616,971 1'19,312 28~,, o25 312,9Hfl 34~~. 1o7 37o,!.!59 £115,193 1153,130 £198,468 0:,£17,847 60?,351 I 'i 5, 392 2l<i,t>20 3 () 6, .) 0 3 355,724 3b8,171 1.!0),963 IIIJ5, 4')0 £187,020 535,099 '>88,154 \'lJ,S/~ ?..i :,, 17o 299, '19'1 321\, llll 4 360,112 39<1,990 4:B,4o1 u75,13'17 522,71£1 574,366 I117,R'jl 261'\,0BB 293,1171 321,4 1~2 552,27';; 386, 2&1" ll£'3,750 1.16">,089 510,682 560,973 I; I SCUUN T F. I> VALIJE OF BASt: 'l't A R (197'1) INTERCONNECTED SYSTEM COSTS IN $10110 -----------------------------------------tSCALATION RATtS--------------------------------------- I)~ ll '; 5% 6% 7'1. 84 9'1. 10% 11 t 12% -------===::=== -------======= -------======= ======~ --------------------------------------------------------------- 2)9,':>fl2 559,h52 39M, 725 1~42,277 £190,812 ':>1~11, BIHI 605,121 672,193 7£16,85£1 829,93/.1 23ll,223 3';;0, 6t< 3 388,1:151 £131,175 478,.S25 531•,8tt9 589,342 65£1,466 726,94& 807,588 221\,9<'3 5!!2,378 579,289 4.20, 41 3 !.!66,223 517,21.15 57'-1,05':> 637.29'-1 707,665. 785,948 223,771 3 3 4, I :, 1) :no, o 1 o ll09,97r'o i.!':>ll,1193 50£1,061 ">59, 2'n 620,658 688,989 7&11,990 ?IR, 71\l 32t>,12H 361,012 399,861 4£1:,, 121 491,282 54£1,888 60£1,539 670,896 744,690 213,9c9 31~,56o Y)2,2Bil 390,()51 432,095 478,895 530,976 ';)88,91'1 655,367 725,025 ?09,?16 31t1,h3ll 343,1\IH 380,':J3'J ll21,40ll 4()6,1:186 517,1191 573.782 636,381 705,974 2 0 lj, 6.31 305,525 B':i,61lll 3li,~Ob 411,056 40:,0:,,242 50£1,418 559,110 619,'120 687,514 2fJ0, I 90 ?'lo,Ll31 327,b3U 362,353 400,981 043,951 £191. 71.1£1 Sllll,888 603,967 o69,625 1'15,Ao8 21l'J,')ll6 519,900 353,obo 391,227 '-135,001 ll79,ll55 551,100 58t\,504 652,289 I'll rbt>l:l 28t',no,> ~12,)93 3£15,231 .S81,7hll £122,380 L16l,'J37 .,11,n2 ':>75,':>13 63S,ll86 JK7,S<:>t> 27t>,37.~ 305,107 537,0':>8 372,':>83 412,078 II ')5, 9 7 9 ':>0£1,769 ':>0:.8,'180 619,198 1«3,nlM 2 7 \) f (I] 2 2911,034 329,119 St>3,o7ll 1.!1)2,083 ·~ll<l, 768 Q92 ,t 98 5'~Ll, nf\8 603,407 179,7o1 ?.td,453 29 l , 1 b 7 321.1~13 355,029 39(',385 4B,H'I3 £180,00'> 551,223 588,096 17b,U11 2SI'i,ll1!) 284,q99 313,93~ 346,t.>38 382,971~ ll23,3lll £168,178 517,969 573,250 172r3o(J 2':>2,237 2Hi,o25 506,1)7\J )38,493 H3,!:lll2 413,105 4':>6, 'lOll 505,114 558,852 lt>~,H17 2llo,o29 27 1, 7 3i~ 299,t>.l1 HO,":>H5 364,977 lj()3, 168 4LI5,572 1!92, o'-14 544,888 .J ---~1 .. J --.I J ... J J ... J ""--J J .I _,) J --I .J N U1 Alll$1\11 I'!I,.H? IIIJH•U,;-JfY ANCt!Ori'Al.t. • 1-AlRHANKS lNI(RTlE FCONOMIC FEASl~IliTY STUOY l -----------·----~ ----------~------~-----_CliP 1 TAL 01 SHURSE!-!ENTS fUEL CO~PONENT OF OPERATING COSTS 1111 $1000-FOR ALTERNATIVE SYSTEM EXPANSIOIIIS I'H 0 I'~ I' 0 1 9 1-i I lliH2 19~3 ----~-------_l Q {-II~ I <11i5 t9A6 1'-H37 llii'R 19H9 1 9') l) 1491 lll'l2 19'13 \90£1 1<1'15 1946 lllll7 1979 1980 19!:11 )Qf\2 1Yo3 198£1 19!:15 191<6 19h7 l'H~B . 1 llh9 19<10 19"11 I <192 \993 19'-14 j90') 19'/o 1'19'1 IN 'HOOO FOR ALTERNATIVE SYSTE~ EX~A~SIONS 2,ou9 26,666 i\1, 9LJ 2 .57.172 21.!21 7.152 7,555 23,110 21,920 Mc,2oo Ill l di:lO 51\,4':JU <'9,840 23,95':7 17,630 £1,621 15,59£1 4R,~\7!1 11,51<; 32,0o2 1492 2,472 8,li7:S 30,<;1~9 <l3,(l3i\ £13,411 89,69 1J lOi'-,723 7';, 13£1 23.106 270 c'SU ADDITIONAL UlS8URSEMlNTS IN $1000 FOR U~DERLYING TRANSMISSIO~ SYSTE~ !~DEPENDENT INTERCONNECJEO COSTS -il9 COSTS -$7ll 1.356 2r00ll !NDEPENOENT E~CALATED $ !NTE.RCOI-.NI:C TED ESCALATED $ SUSITNA CONSTRUCTION POwER COSlS IN $1000 FOR ALTERNATlVl MODES OF SUPPLY DIESEL GENFRAI!ON lNTERTIE T~PLINE COSTS -$79 COSTS -$7Q (:),855 b95 697 69b 3,055 1,32£1 187 623 623 -~00 2b7 U83 £181 478 752 902 nu 1.130 £11Q 3ull TABLE 6•o 25 AUGtiST 79 ALASKA PU~f~ AUTHUHllY ANCHUHAGE -· ~AIR~ANKS JNTERllE ECONOMIC FEASI~Il ITY STUDY ____ ~- TABLE 8-bX ~ ~--~---------- o 1 scuur~ r HAl~ fi. 1_1 0 e.2'::l e.so f. • /') 9. l.; 0 9.25 9 • .,0 4. 15 I u. 0 ll 10.2"-, 1\• • ., 0 11• • I r::; 1 L • ii 0 J'T1 11.25 11.'}{1 N 1 I • 7 ':> 0'1 12,()1) D IS C n u r·• T I< Art: M.PO 8.2'> t~.~o 8.75 '1.•J0 9.25 9.SO 9. 75 I 0. il o 10.25 U•.<:>O 10.75 1 I • \1 0 11.?.5 11. '::iO I l • 7 S 12.0() -. ,,,,. DISCOUNTED \IALUE Of tlASE YEAR C 1979} p.ii)EPEi--iDENi SYSTE.,-COSTS IN $1000 -----------------------------------------ESCALATION HAlES--------------------------------------- ()% 4% '>% b% 7"4 8% 9% 10% !IX 12% ======= ======= -------======= ======= -------======= -------======= ----------------------------------- ?~.>l,oc"l 3i'!I,OI<J tli9,£J(I2 461,.0.f\6 SCJtl, 9 U '::l61l, 97 3 618,607 61:\2,1.111 7':13,01.14 1'.31,230 2'-;5, :lbb 37?, ~bb Ll(l9,75'J ll')\,01'15 t.l96,t\43 5117,1J88 6(15,':>42 66.,,5!\3 75ll,247 1-110,239 2t:;(i,OC,7 3o3,9.,1!-u0(l,5111.1 41.10, C,Oij 1.11:15, 127 53 !.1, 110 I 51-11',925 649,2':>8 716.017 789,885 2J 1~,l<l5 Y:-i">,7i'o9 391,i2;> 430,'-l{Jtl ,, 7 5, 15 2 521,69H 574,7/JO 633,419 691'., .B5 770,146 2"1,0 ,':>/6 )t.j7,HSt 382,360 ll2ll,515 462,706 ',tJ9,367 560,973 611:1,051 6fll,!81 751,002 ?S£J,6'-l'~ 340,1~1> 573,7'>0 4 I<), 9!) 5 lJ'} I, 91\l> 4Q7,394 547,t>IO 603,137 notl,'::l3H 732,432 i:'29,1:\'IO . 3 52, o ·s" "36';,3.'\2 401,561\ ll '' I , '> h 2 ••85, l o9 53ll,638 58fi,663 6ll8,389 /1ll,417 2?:5.1(!1 32':1,3lJ6 3"-J/,250 5<J2,497 1.131,402 474,1.179 '::l2c,043 574,613 63.:?,717 b96,937 ?21),'i3'-l 311-1,257 34'l, Sllo 31:13,6111 421,1>10 463,513 509,1113 .,1:>0,<173 b17,SOo 679,976 2 I b, li62 31 1, 3b4 3i.il,t>6l 3 7 5 , I I tt 412,057 4',2,662 1~97, '1.~1.> C,£!7,730 60,;?,/41 663,515 2LJ,H>7 3(o:J, '>bO 331.1,1QO 361>, I tit> ll02,774 lJ4<',514 IH:It>, 400 'l54,R70 St\ll,llll6 oll7,538 ;>c,7,,"<,6 2'11', 1110 32o,92'> 3Sd,b91 593,753 'd2, 459 475,194 522,3/ll 57LI,48~ 632.028 2i 1 5,356 2'-~1 , /9o 319,H60 550,~20 31-14,98a 422,b81; llb4,307 510.2'>1 '>oO,<J73 616,971 1"9,312 2h5,h25 312,'/t:\1:) 343,167 376,459 413,193 1153,7 30 498,'l6H ':Jill ,l)ll] o02,351 !45,.~92 274,620 30o,303 3Y::i, 721.1 568,171 40),963 4115,450 487,01!0 535,099 588,154 191,573 273,776 1!99,7'>9 321:1,41:14 360,112 5'-11~, 99 0 433,461 475,897 522,714 57£!,366 l h 7, 1151 i!.bf:\,!)111.\ 243,<-171 321,41.12 552,275 31',6,267" 425,750 1~65, 089 510,682 560,973 n I sc uur, T E.D VALIJE OF IHSE HAR !1979) INH RCONNEC TFIJ SYSTEM COSlS IN $1000 -----------------------------------------ESCALAT)UN RAT£5--------------------------------------- l!% 1.1% 5% 67. 7% 8% 9% IO% 1U 12X ==::==== ======= ======= -------======= -------======= -------------------------------------------------------- ,>~ll, Q,P. 7 )7P,431i 40'-1,897 ll5.5,fl53 502,b04 ">57 ,.507 617,978 &11'>,499 760,622 84<1,175 245,~'-lil 361,':>&7 399,'132 44l',o51 490,214 ':)Lj 3, 160 602,088 667,657 7liO,'::l95 1:!21,706 2 38, •)69 352,971 39V,268 1.131,790 <H8, 009 529,1.150 5Rt>,691 6':.0,371 7?..1,196 799,944 232,1:\LI':) 344,b~2 3RO,tl9o 421 ,251:1 466, I 77 51o,lol '::i71,769 633,622 702,403 778,865 2r.7, 71 53o, 5'1l) ~ 7 I , 50 11 lll1,0LII.I 4';£!, 705 '}03,278 557,307 6tl,H2 684,194 758,445 222,Au2 32t<,oKii 562,<JHLI 401,138 4ll3,':>80 490,78£1 543,2fll:l 601,662 666,':>51 738,662 ?11:1,1}55 5i!.I,Obf\ ~5Ll,l.l26 591,5?8 4'>?,/91 478,678 52'-1,698 '::l86,ll15 649,452 719,4911 213,'-100 513,672 3'lo,J22 3fl2,205 422,326 ll66,.933 .,16,'>21 571,636 632,1:!80 700,918 ('(l!:\,1-\71', 3 (!6, <j 9 ~ 338,065 373,1')9 412,174 tJ5C,, ':>IJ3 505,74ll 5',7,307 6l6r81o 682,916 2t!LI,'lf\3 290,522 330, ?LIO 36Ll,3tl1 1.102.525 4ll0,4'-/4 Ll91,3'::i3 ':>45,41LI 601,243 665,1.166 2•.10, 21 () t!Q2,75i.l 322,bl.lb 3"-J'J,/361 592,769 433,776 419,53S 529,9111 5R6,14':! 648,5':>1 I96,0'::l7 286,1112 31':),271.1 3tH,':J9? 5H5,495 il25, 377 46/,677 516,815 '>71,505 632,152 l42,0LH ?..79,791i )Ot\,11'> 339,.')6'; 314, ljQ<j 413.CI:I7 .. ll'::lt>,"!..67 -5()11,202 5')7,307 616,252 1~8,1)91 275,598 30I,lo3 331,7/1 3o5,75b 403,ll9':> lll.l5,394 {jQ1,901\ 5£13,537 600,833 1 Iii.! , 2 11 .267,574 294,412 3?11,204 357,277 393,991 434,746 479,9B1 530,180 585,880 I tJ•.i, 5S5 2bl,721 287,!;1';3 516,1:\55 311'l, OiH 3All,766 ll211,413 4btl,408 511,223 571,376 17o,9ul) 2So,l!~il 2H I; Clf\2 >09,718 341,047 H':>,HI t .q4,583 1.151,178 c,oa,&52 557,307 I i-~ ,J ,, • __ ,_ ,. .J •• .,-1 {;. ,, .• _J ,. • rn N ........ ,, --1 ''1 -1 -~ --'1 --·~dl 1 ALASKA PO~><fR AUlfiOHJlY ANCHUH~Gt -fAl~HA~KS JNlfRflE ~CU-OMJC FEASI~ILilY STUDY l ~l _ -~-----· ____ . _________ C 4P l TAL D I Sf::lURSE "~EN T S FUEL COMPONf~T OF OPERATI~G COSTS IN J>1000 FOR ALTERNATIVE SYSTtM EXPANSIONS 19/9 1980 I 'Jill I 91!2 19>H 19Hll 1 9 l_i':) 19116 J9H7 1965 l9fl9 1990 )991 l'l<.J2 I 'Fl.) 194ll 1'195 19'16 19'-17 1979- 1960 1981 19112 l9fl3 19.'JLI 19H5 19<lb 1987 19~8 1 914 <) 19'-10 1<}91 19"12 19'n 14<1(1 19'1':1 I 9'lo )997 I'< ~1000 FOR ALTtR~AllvE SYSTEM EXPANSJOo,;S JNDEPE .. Dt~l l~TERCU~NtCfED COSTS -l79 COSTS -$79 s.ota 2,009 !7,755 2b,bb6 58,709 !:II , 9 it<' 11,515 37,172 32,061 21.127 IJ92 l ,152 2 ,.IJ] 2 7,555 l:l,tl73 23,110 30,5ll9 21,920 1.13,03R fl2, 21) 0 43,1J11 11) 1 , 5tH) 89,69/J 5R,4'i0 10ti,723 29, 8 ij 0 1':1, I 34 23,9.5') 23, I Ob 17,6.50 270 251.1 AODITIUNAl DISblffiSEMENTS IN .'f> I 0()0 FOR UNDERLYING TRANSMISSION SYSTEM I~UEPENDENT l~TERCO~NECTED COSTS -119 COSTS -$79 2,004 lNDtPENIJENT ESCALATED $ INTtRCONNE"C TED ESCALATED $ SUSITNA CONSTRUCTION POWER COSTS JN $1000 FOR ALTERNATIVE MODES OF SUPPLY DIEStL GENERATION INTERTIE TAPLINE COSTS -$79 COSTS -$79 2.835 695 697 696 3.0~5 1r324 111 7 6<'3 b23 -soo 267 .. 1.183 lllll ll78 752 902 734 430 419 304 :1 ---, TABLE 8-bX 23 AUGUST 79 DISCOUNT RATE 1:1.(11) B.<'5 'l.':JO d.75 9.vc '1.25 9.'>0 9. 7C:, I I) • l)l) LU.r'') 1 0. ') lJ l 0 • 7 ':> 1 I • 0 o ITl 11.25 -I_. I I • ')0 N I 1. IS 00 12.uo DISCOUNT ,(A Tt I'. l' tl 1:1.2'> ~:~.<;o 8.7") 9,011 9,25 Q.~o 9,75 1 0. 0 tl 10.2':! 10.')0 10.75 I 1 • 0 0 11.2'> 11.':>0 II. 75 12. •.1 0 ALASKA PO~ER AUTHO~lTY ANCHD~A~E -~AIRBANKS JNTE~TIE ~CUNOMIC FEASIHILllY STUDY TABLE 8•7 [.'JSCOU'~TED vALUE -OF BASE YEAR ( Iq]9) PlOtPENDE~JT SYSTEM COSTS IN $1000 -----------------------------------------ESCALATION ~AI~S-•------------------------------------- 0% 47. 5% 6% 7'X. 8% 9% 107. II% 12% ======= ---------------------======-= ------------------------------------------------------------------------------------------- 2h5,4o1 1105,61.10 £14l,llb9 /JI:\3,553 ">24, 729 581,0f\4 637,955 700,932 770,o69 8£17,886 279,50? 5'il.l,l.l2o '.131,253 472,01'> 51 I, I 39 561,095 o22,1J0c t:Jf\3,633 l':Jl,£123 826,£167 21.3,512 5tJS,477 '~21, .5 32 1.16l,OPCI 50il,41H 5S3,51H 607,512 6oo,o54 1".32,758 805,699 267,4tll:l 376,782 41l,o96 450,320 1.195,055 5LHI,31J2 592,1>69 o50,'J75 714,65/J 785,559 ?ol,t\25 3ol1,334 L~uc, 53~> ll39,'140 41:\I,S5o '121,551 '1713,459 65ll, 71:!1 697,092 766,027 256, ~1?. ~60, 125 393,2142 429,859 ll70,5S1 51':>,13/J 564,6o7 o14,45ll otl0,051.1 747,082 250,450 352, l'~o 31:\4, '4 0 6 IJ20,065 459,£JH8 503,078 551,27H bOll, 580 665,523 728.703 2£J':J,73ll 344, ~91 37'::i,820 410,551 'lll/:'.,937 491,370 538,280 ':>90, 142 blJ7,lltl0 l!O,f\72 21-10,657 33o,H51 367,1474 401,)06 1~313, t>811 llt\0,000 ':>25,659 576,127 b31,911 r)93,570 25';,716 329,':>21 3'i9,563 592,322 1.1?8,730 IJ6fl, 95o 5 u, IJ05 562,'::i20 o1b,798 676,779 230,906 322.~95 Y-> 1, IJ] 7 5H3,'l9U 419,0'::i4 4511,227 ':>01,500 549,3013 t>02, 126 660,483 226.223 31'),461 3ll3, tlU9 51':>, 102 '~ 0'1, t>S 1 447,803 489,'135 ':>36,477 '>R7,8H2 641J,b64 2?],bo3 3 0 ll, 7 11:1 .~3n,)5'l 36o,B5! ql)l),':J13 IJ37,b75 {J 78,706 524,015 'J7::J,O'::il 629,306 ?17,?.23 502,\511 329,102 3SB,Ii213 5'11,629 427,1B2 1.167,794 511,911 '::it>O,ol8 6IIJ.396 ?l<'rl~'ll:l 29~,/77 322, tl50 Y:>i, 02o 3H2,995 411:1,26':> 457,190 ':lOU, 151 547,572 ">99,917 2L•H, 6h6 28'i,'1o7 3\S, ll:lB 343,439 374,596 40h,965 446,1184 488,72.6 ':>34,1:199 ':i85,855 20ll,Sl:l2 283,5214 50tl,'J13 53o,O':i9 3ot:>,430 399,9?4 43b,ll68 477.623 522,587 572,197 DISCOUNTED VALUE OF BASE YEAR ( I 97 9 l INTtRCONNECTED SYSTEM COSTS ... IN $1000 ------------------•----------------------ESCALATION RATES--------------------------------------- 0% 4% 5% bi. 7"1. 8% 97. 107. 11% 12% -------======= -------======= --------------------------------------------------------------------------------------------------- 2Hh,QO'j lJ 1lJ, 1 3 ':i t.l5V,105 494,593 Sll4,101J 599,201 o60,'J02 72/:l,h'-12 t:!Oll,529 888,8115 ?<'0,578 I.IOO,llt>l il3'1,322 1Hl2, ':>61! 530,679 584,209 .. 64.5, 756. 709,982 7B3,o21 f\65,1179 2 fij r /~ 3 4 391,0]"1 42i:\,tlo4 470,900 ':)17,665 '"J69,678 62/,')21 691,853 "763,365 842,1:!47 26>1, ·~o7 3t.l1,'-172 418,fld 1.159,':>H!:l ')OS,Oll2 5':>5,':i91 611,79.7 67ll,285 7ll3,7<.10 820,922 2o2r'>71 '> 73, Uo liOB,876 4ll8,ol6 492,1'>05 ')41,932 ':>96,'Jll9 657,258 72<J,723 799,681 25 I, 0 11 o 3o4,561 399, 52':> iJ37,972 480,9!d 521:1,688 581,767 6"40, 753 706,293 779, 098 2'JI,':>61:l 356,237 390,057 1~2 7, 641~ 1!69,419 51<>,!!44 567,433 624,754 688,430 759,152 2'H>, 2') 1 34H,l56 3!31,062 ll17,1:>24 458,248 ':i03,3tlo 55 3, 5 3'l 609,242 b71.!14 739,821 2'n. os3 31.10,311 372,331 IJ()7,f\99 IJI~7,411 1191,302 540,0'lll 5911.200 651.1,327 721,083 236,0o0 332,o92 5b3,1:l5Ll 391:i,4o1 '' 3o, f\94 IJ79,':i7P. 526,979 579,614 63~,051 702,918 2H,176 .$25,294 355,624 .SHQ,299 42o,o81:l 4611,203 51LJ,296 ':>65,1~61 b22.2b8 685,307 2('o,427 3111,1011 3ll7,632 3RO,'l0<.1 lllb. 782 11':>7,164 501,990 ':>'}1,71~1~ 606,961 6b8.231 22lrt\!O 311,121 B9,f\71 371,/b!l 407,166 446,ll51 LI90,0')0 'J38,ll3l 592,11£1 651,671 217,318 30ll,545 332, B2 363,381 3Q7,fl30 1136,0':>3 478,1163 ':>25,515 577,713 635,611 212.9'j0 2'-17,754 .)2"),\lO'l 355.237 58H,766 425,9')9 ll67,217 512,982 '>b3,741 620,032 ?1)8,!>99 291, 35iJ 517,t19ll 3 117, 3.2S 379,91)3 4lb,lC:,9 456,301 500,819 sso .. u~q "604,920 2<.! cl, ':ib'l ?1:15, 126 3.10 I '1i\O 3 _sq ,61l0 371,414 olio,6/n 4LJ'J, 7011 Lll\9,013 517,029 ')90,<?58 ... I _] J J 1· ___ -_, .J . .. ".:1 J .. 1 ._cc•~ .' _l 1.· .• _,_l J .J J fTl I. N 1.0 23 AU.;u:; I 79 1979 !9~0 l<lf\1 t<Ji32 !983 19fl£1 19(15 1 'H\6 191l7 19il/j !91'9 1990 !491 1992 !993 19'-IQ !995 t'IYo !997 1979 19130 191'<1 1902 1983 19~£1 14~') 1 <:ji-\ 0 1987 19Mil 19~9 J9<lO J90J 1992 1993 19'HI 199') I 9'16 I q<l7 1 ~. A!. AS;<. A POWI:-R AIJII~OIH I Y AHCHUNAGt -~AIWHA~~S INTFATIE ECONOMIC FEASJdlliTt STUDY CAPITAL DIStlURSE.MENTS l\1 $1000 FOR ALTERNATivE SYST!:M E)(PA'ISIOI\IS 1Ni)£PFNDENT PITE RClJ"'NEC TE 0 COSTS -H9 COSTS -$79 4, 8 7 2 2,009 !R,056 26,6nt> 7<',604 ~ 1 , 9 112 11,326 37,112 3!,Rilb 21, 12 7 328 7,1')? 2,319 -7, s~c:; fl,')29 23, 11 (l 30,&0Q 2!,9~tl £1~,092 82,200 43,<163 lO!,~oO fi9, 9 73 58,Q'JO 10H,91'.fl 29,1\'-10 15,31)7 23,0_$'3 2 3, 3 117 I 7, t> 3 v /~99 473 ADDITIONAL DlSRURSEMENfS IN $1000 FOI< U'JDERLYING TRANSr~TSSTO"' SYSTEM JNIH:OPENDU~T l 1~TtRCUNNECTEO COSTS -$7Y CUSfS -i79 FUtL COMPONENT Of OPERATING COSTS IN $1000 FO!'< ALTERNATIVE SYSTEM EXPANSIONS lNOfPENDI::NT ESCAL.AltD $ ·1!,461'\ 9,32ll tu,267 6,A51 7,212 7,933 8,65£1 9,015 lNTERCONNECTtU ESC ALA TI:::D $ 7,648 8,498 9,029 8,32£1 8,654 8,016 8 r 7IJ5 9,109 SUSITNA CONSTRUCTION POWER COSTS IN $1000 FOR - Al.TERNAT I V~D-£5~ OF SUPPLY ,. DIESEL ~fNERATION INTERTIE TAPLINE COSTS -579 COSTS -579 2,835 o95 697 696 3, oss 1,.)24 187 623 623 -5()0 2&7 403 481 478 752 902 73£1 430 lll9 304 APPENDIX F TRANSMISSION LINE FlNANC IAL ANALYSIS - APPENDIX F TRANSMISSION LINE FINANCIAL ANALYSIS ANCHORAGE-FAIRBANKS INTERCONNECTION SEM1-ANNUAL DISBURSEMENTS FOR TRANSMISSION INTERTIE FACILITIES (TLFAP) 1979 BASE-LINE AND ESCALATED COSTS F-1 , I w 11J AUGUST 79 A~CHOPAC.t -F4IRdANKS lNTfRCUNNECTlO~ LT'Ilf NO 172.0 17LJ.(l 176.0 17R.o 11:10.0 18?.0 184.0 186.0 189.1) 190.0 1 q 1 • 0 ?00.0 202.0 204.0 206.0 208.0 21(1.0 21 1 • 0 215.0 216.0 217.0 21R.o ?19.0 220.0 2n.o 224.0 22&.0 nA.o 2~0.0 232.0 234.0 ns.o 1. TPANS''1lSSTliN L !"'f t'JGRG 1'. cnt'Jqf"'. SIIJ..>Ft-~v. R I(, H T li F ~JAY Ff1U"JDATTU"JS TOi><FRS 1-iAt<DwARF I NSLIL.A T flkS CONI)U(lnR SFMI-ANNUAL OJSAURSEMENTS FQR TRANSMISSION TNTERTTE FACJLITitS COSTS INFLATEn FRnM 1979 BASELINE IJ,2 0 0 0 0 0 0 7fH 2298 0 0 0 0 0 1982-1 () 7lbCI 0 0 0 0 0 440 0 256<; 0 0 0 0 AlO 0 121? 11379 BU 813 1Pt88 87Q 0 0 144b4 493 520 1112q TOTAL Bo5 9llo6 9777 25843 577 bOB 13017 ---·-------------------------------------------------------------·----SU~-Tt!TAL ? • St.lf~!' 1 fl. T T U'IS ENGRG 1<. (fl',ST. SUPf_RV. LAND TRAIIiSFUP>-1fRS CIRCUJl KPf'ai\FRS STATIO~ f~Ul~MtNT STRUCTURtS R ACCFSSf1RTE.S 4<:J2 t;63 t1 I 0 0 0 0 ~081 Cjl:'b 0 t1 0 0 0 7169 bOQ 0 lob A 422 ~91 M1 b)IJ 0 670 769 r.do 1 A 1 1 329 0 697 AOO .,.,, 1A84 343 0 207 238 164 0 62653 3064 81 1Q43 2229 t 535 41566 ------------------------------------------------------... --------------·-- SURTnTAL 3. CO~TROL. h"lD CnM..,IJf\JlCATIONS fNGINf:E.QPJG AND i'ISTALLATTON SlJPfRVJSJL)'j tQUTP"''fNT SUR-TUTAL TOTAL Su~'!Af.iY (lf. PQICE f:SC4LATION AT A.O~ PA 644 0 0 0 109h 0 586 (l 1 4 1 2562 0 0 0 9730 44111 0 0 0 8.3 1467 111:)50 ?7213 qs1 t 1 II 22Bq 2110~ 197 H'J6 A0021J 1 1 15 0 1 - - - ANCHORAGE-FAIRBANKS INTERCONNECTION ALTERNATIVE FINANCIAL PLANS 70% PROJECT FUNDING WITH REA/FFB LOAN PACKAGE l14% -REA LOAN @ 5%, 35 YEARS (20%) l ALT 1 l_56% -FFB LOAN @ 9\%, 35 YEARS (80%lJ . l28%-REA LOAN@ 5%, 35 YEARS (40%}l l_ 42% -FFB LOAN @ 9\%. 35 YEARS ( 60% 2J AL T · 2 30% PROJECT FUNDING WITH AMU/FMU BONDS 18% -AMU BONDS @ 6~%. 20 YEAR MATURITY 12% -FMU BONDS @ 7%, 20 YEAR MATURITY F-4 1t> AUGUST 79 A"<( rl(l><A Gf -F='AlRI1A"<I'.S T~lt.RCO!II'II[CTION 20•80 RlA-FFB FU•<OING snu~Cfs ANO P>TEPtST on><T'4G CU"lSTwliCTI(lN L 1 'liE lOKI-I 11'11;1-2 IQ82-1 1082-?. 1<;83-t ll'lR3-2 TOTAL ~0 4100,0 FuND!r~G Sur.t.<rt <; 1101,0 APA tHli<O 0 0 0 0 0 0 0 402.1) Q[A LOAN 153 c;n llo? 1039 3fi1EI 4318 11203 403,0 CFC L fl A'! 0 0 0 0 0 0 0 Ullll,O Fl'"l:l L(lA"f 614 20'53 5£l4Q 415'5 15273 17270 t1U81U /Joc;.o A"'U SHU'<[ lff<" lOAN 197 660 17~1 I:B5 £lQ09 5551 14404 406,0 F ~~ Ll SHl)Ql lf"'"l LOAN I 32 ·~qO 1168 P.90 32n HOt 9603 liOP.,() -------------------------------------~-------------------------------- liOQ,O TOTAL 109h .36t>h 9730 71.11 Q ?721"3 301139 80024 £110.0 Lill,(l l'JT!:.REST 11tt"' 1 I1G r o '1 s r R 1 J c T I n '' 411?,0 APA l"jfll,[1 f) 0 0 0 0 0 0 413,0 REA LOAN 2 I 0 3'~ o£1 124 ?26 460 UILI,O CFC LflA'l 0 () 0 0 0 0 0 415,0 FFB Lfl/1"-14 71:1 249 1.171 Q2t 1673 31.1 oc; 1.116,0 A"'ll! SH(lt<J lf><M LOhN I 0 53 173 32P. 6U0 11 6' 2366 1.117,0 ~"'U $HURT r F!< .. liJA"J 7 35 1 I b 211'1 427 775 1578 1.1?0,0 ----------------~--------------··------------------------------------- iJ2l,O T 01 ~L y~ 171.1 C:,72 1081 211? 31'138 7809 1.122,0 I o AlJGtl S 1 7<1 ANCHORAGE -FAIRBANKS JNTE.RCONNECTION 20•80 REA•FF~ DFHT TARLF Af\11') '"'T"1 COMPOSITE INTERfST RA Tl I U1 LI'IIf 1981-1 l9H1•2 IQH?-1 1982-2 1983-1 1983-2 TOTAL "JO 1.130.0 l OE~T A SSII...,f I) H'f EACH UTILITY ll32.0 A"4l 6 p 18 0 0 0 0 0 18 1!34,0 CfA I 1 n 0 0 0 0 11 1!36,0 >1f A ~ 0 0 0 0 0 J ll3R,O HE A 0 tl 0 0 0 0 0 llll?.o Po! US 12 0 (l 0 0 0 12 lii.II.I,O GVE:.A '}6 0 n 0 0 0 5o l.lll6.0 CVEA 0 (l 0 0 0 0 0 f.tl¥7.0 UI.IR,O ltll9.0 ao,o,n DE. AT AS~!IMFU bY f'AfH UTILITY 1.152.0 Al-4l ~ fJ ll'l7 bbO 1 751 1331) u9oc; 5551 ltii.IOLI .:a5a,o CfA I 21 1.103 1070 A1o 3000 3H2 8803 q')b.O MEA .33 I 1 0 292 U3 A18 925 2401 £15R.O Hf' A 0 0 0 0 0 0 0 l.lo2.o f"'US 1.32 IJ40 1 I bA R90 321'5 3701 q603 IJblJ,() GVf:A hiLl 2053 5449 tJI<;~ 15273 17270 I.IUA1t1 Ub6.0 C VE A 0 () 0 0 0 0 0 IJoA,O ---------------------------------------------------------------------- 470,0 T(ITAL DEbT !096 36ob 97.30 71t1Q 27273 30839 A0021.1 !t7?,0 tt7ll.O 1.176,0 51o;o C0>1POSlT[ !NlF~fST PAT!:: o.o~:~q 0,0 0,0 0,0 o.o o.o 0,08Q J J ] .J J I ~ j J ) I '-~---. j J .I ~· J _j .I J ] . ·-1 1 ) ·-l 1 ·-... 1 ) ) J ] ) ·-.1 l 1 lb AUGUST 7Q AIII(H(IIUGE . FAIRBANKS INTERCONNE.CT JON 110•&0 REA•FF8 FUNOlt.IG SflURCfS ANO INTERESt DURING CO"JSH<UCTION Ll"<F 1981-1 1981-2 191:12-1 1Q82-? 1983-1 19133-2 TOTAL NO 1100.0 F UNLl H.(: SOl If./( I: s 1101.0 APA !j(ll~[) 0 l) 0 0 0 0 0 1102.0 I'IEA L(lAI.J 30 7 I 027 2725 2077 7b3b Ao3'5 22407 403.0 CFC LOAt.J n 0 0 (1 0 0 0 4011.0 FFR LOMI !lt>() 1'540 40R7 51 1 b 1111')<; 1l9~3 Ho10 110'5.0 AMU SHOJ.I T TFf.ll'l liJHJ 197 ob'l 17':>1 IB<; 11909 5'5"::.1 11111011 1106.0 F"!IJ SH()J.il !FI-lM l 0 A•~ U.? IIllO 11 t>A 1'\90 5273 HOI 9603 408.0 -------------------------------------------------------------------·--1109.0 TOTAl 1096 3bbb 9730 71119 27213 308H 800211 1110.0 1111.0 I~•TE.RI:ST Ulin 11<1~ CU'~S HIUC T I ON 111?.0 liP A AflNfl 0 0 0 0 0 0 0 1113.0 REA LflA"J I~ 21 b1 127 249 ll':>? 920 4111.0 (F(. LOA II.> 0 0 0 0 0 0 0 415.0 Fftj L(lAN 1 I <:,7 1 A 7 3'::.4 b91 12~<; 25':)11 1116.0 AMU SHUQT TF~M LOA!Ij 10 ':)3 173 3lR b40 11 b 3 23oo 417.0 P1U SHIH~ T Tff.l"" l 0 A~• 7 35 t I b t'tA 427 775 1'578 1120.0 ------------~---------------------------------------------------------421.0 TOTAL 3 t 165 543 1027 lOOb 3645 11118 422.0 '"n I b AliGIIST Fl ANCHO~AGf -FAIRBANKS lNTt:RCONNEC T JON 110•&0 REA•FFB I 0'1 DEBT TABLE Ar~n COMPOSITE INTEREST RATE LINF: 1<181-1 1 1HH-2 1<ll:!2-l 1<l82-? 1983-1 (Q83-2 TOTAL "JO 1130.0 % 11fRT ASSII'~EI) !H EACH UTILITY 1132.0 AilofL g, ~ 1R 0 0 0 0 0 18 1.1311. 0 (fA 1 I 0 0 0 0 0 1 I llJo.o ME A 3 0 0 0 0 0 3 43R.O I-lEA 0 0 ,-0 0 0 0 0 41.12.0 f. "'US 12 0 0 n 0 0 12 11<14.0 6VEA 5o () 0 0 0 0 5o llllb.O CVEA 0 0 0 0 0 0 0 11117.0 11118.0 IIL19.D 11'50.0 DEAT ASSLJ'1flJ 8Y EACH UTILITY 11~2.0 A"1L (1. p 197 boO 1751 133'5 <1909 5551 1111.1011 11511.0 CEA t 21 1103 1070 816 3000 3392 8803 115&.0 "4[A 33 1 1 0 29? 223 818 92'5 21101 1151".0 hfA 0 0 0 0 0 0 0 llb2.0 FMUS t.Si? 1140 11o8 890 3273 3701 9&03 11()4.0 GVEA b14 2053 5411Q <lt'i<; 1 ~?7 3 17270 11118111 llo&.o CVEA n 0 0 0 0 0 0 468.0 ----------------·-------------·----------·----------·------------------1.170.0 lnTAL Oftjl 1096 3bbb 9730 71119 77273 30859 800211 IH2.0 111q.o 47&.0 'i10,.0 COMPOSITE INT.fRfSl RAT[ 0.083 o.o 0~0 o.o o.o o.o o.oal I 5 AUGUST 79 ANCHORAGE -FAIRBANKS INTtRCONNECTION 20-80 REA•FFB DEBT SERVICE SCHEDULE LINE 1984 1985 I 98b 1987 1988 1989 1990 1991 1992 1993 1994 1995 NO 152.0 APA 154,0 SINKING FUND 0 0 0 0 0 0 0 0 0 0 0 0 15b.O INTEREST DUE 0 0 0 0 0 0 0 0 0 0 0 0 158.0 -·-----------------------------------------------~--------------·------------------------------------------· lbO,O SoFUND+INTEREST 0 0 0 0 0 0 0 0 0 0 0 0 I b I • 0 lbb.O REA 1b8,0 REPAYMENT 350 350 350 350 350 350 350 350 350 350 350 350 171.0 OUTSTANDING 10853 10503 10153 9803 9453 9103 8753 8403 8052 7702 7352 7002 172,0 INTEREST DUE 5b0 543 525 508 490 473 455 438 420 403 385 3b8 1711.0 ------------------·-------~-------·------------------------------------------------------------------------· 17b,O DEBT SERVICE 910 893 875 858 840 823 805 788 770 753 735 718 177.0 182,0 CFC 1811,0 REPAYMENT 0 0 0 0 0 0 0 0 0 0 0 0 187.0 OUTSTANDING 0 0 0 0 0 0 0 0 0 0 0 0 -n 188,0 INTEREST 0 0 0 0 0 0 0 0 0 0 0 0 I. 190.0 ----------------------------·-------------------------------------------~-------------------------------···--..! 192.0 DEBT SERVICE 0 0 0 0 0 0 0 0 0 0 0 0 193,0 198,0 FFB 200,0 REPAYMENT 1400 11100 11100 11100 1400 11100 1400 11100 11100 1400 1400 1400 202,0 OUTSTANDING 4311!3 112013 110bl2 39212 37811 3blll1 35011 HbiO 32210 30809 29409 28008 203,0 INTEREST 111115 401b 388b 3757 3b27 31198 33b8 3238 3109 2979 2850 2720 204,0 -------------------·------------------·-----------------~------------------------------------------·--·--·--20b.O DEBT SERVICE 55116 54lb 5287 5157 5028 11898 47b8 4b39 11509 4380 11250 11121 207,0 212.0 AMU 214.0 SINKING FUND 371 371 371 371 371 371 371 371 371 371 371 371 21b.O INTEREST DUE 93b 93b 93b 93b 93b 93b 93b 93b 93b 93b 93b 93b 218,0 --------------------------------------·-----------------------------------------------------------------·---220.0 S,FUND+INTEREST 1307 1307 1307 1307 1307 1307 1307 1307 1307 1307 1307 1307 221.0 228.0 FMU 230,0 SINKING FUND 2311 234 2311 2311 234 2311 2311 234 2311 2311 234 234 232,0 INTEREST DUE b72 b72 b72 b72 b72 b72 b72 b72 b72 b72 b72 b72 234.0 -------------------------------------------------------------------------------------------------·--·-------23b.O S.FUND+INTEREST 90b 90b 90b 90b 90b 90b 90b 90b 90b 90b 90b 90b 250,0 TOTAL REPAYMENTS OR 251.0 s. FUND PAYMENTS 235b 235b 235b 235b 235b 235b 235& 235b 235b 235b 235b 235b 253.0 TOT INTEREST DUE b314 blb7 b020 5873 5726 5579 5432 5285 5138 il991 11843 11696 255,0 ---------------------------------------------------------------·--------------------------------------------257,0 TOTAL DEBT SERVI 8b70 8523 837b 8229 8082 79311 7787 7bll0 7493 734b 7199 7052 .J .] J J J J l 1 l ] ) --] --~.--~---·-· •--. 15 AUGUST 79 ANCHORAGE -FAIRBANKS I NTE RCONNEC 1 I ON 'IO•bO REA•FFB DEBT SERVICE SCHEOULE LINE 198'1 19tl5 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 NO 152,0 APA 15'1,0 SINKING FUND 0 0 0 0 0 0 0 0 0 0 (} 0 156,0 INTEREST DUE 0 0 0 0 0 0 0 0 0 0 0 0 158,0 -------------------------------------------·----------------------------------------------------------------160.0 S,FUND-tiNTEREST 0 0 0 0 0 0 0 0 0 0 0 0 1 b 1. 0 166,0 REA lb8,0 REPAYMENT 700 700 700 700 700 700 700 700 700 700 700 700 1 7 1. 0 OUTSTANDING 21707 21006 20306 19b0b 18906 18206 17505 16805 !biOS 15405 14704 14004 172,0 INTEREST DUE 1120 10tl5 10'50 1015 980 945 910 875 840 805 770 735 174,0 ------------------------------------------------------------------------------------------------------------176,0 DEBT SERVICE 1821 1786 17'51 1716 loll! 1645 1610 1575 1540 1505 1470 1435 177 0 0 182.0 CFC 184,0 REPAYMENT u 0 0 0 0 0 0 0 0 0 0 0 187,0 OUTSTANDING 0 0 0 0 0 0 0 0 0 0 0 ·0 "Tl 188,0 INTEREST 0 0 0 0 0 0 0 0 0 0 0 0 '-· 190,0 ----------------------------------------------------------------------------------------------------------·--OJ 192.0 DEBT SERVICE 0 0 0 0 0 0 0 0 0 0 0 0 193.0 198,0 FFB 200,0 REPAYMENT 1050 1050 1050 1050 1050 1050 1050 1050 1050 1050 1050 1050 202.0 OUTSTANDING 32560 31510 30459 29409 28359 27308 26258 25208 211157 23107 22057 21.006 203,0 INTEREST 3109 3012 2915 2817 2720 2623 2526 2429 2332 2235 2137 2040 204,0 -------------------------------------------------------------------~---------------------------------~------206,0 DEBT SERVICE 4159 4062 3965 3868 3771 3673 3576 3479 3382 3285 3188 3091 207,0 ~ 212.0 4MU 214,0 SINKING FUND 371 371 371 371 371 371 371 371 371 371 371 371 216.0 INTEREST DUE 93b 93b 93b 93b Cl3b 936 93b 936 93b 936 <no 9lb 218,0 -----------------------------------------------------------------------------------------------------·---~--220.0 S.FUNDtiNTEREST 1307 1307 1307 1307 1307 1307 1307 1307 1307 1307 1307 1307 221.0 228.0 FMU 230.0 SINKING FUND 234 234 234 2311 234 234 234 234 234 234 234 234 232,0 INTEREST DUE b72 b72 t:>72 b72 b72 672 b72 672 b72 b72 b72 672 234,0 --------------------------------------------·------------------------------------------------~------------·· 236,0 S,FUND+INTEREST CIOb 90b 90t:> 90b 90b Cl06 90b CIOb 90b 90b 906 906 250,0 TOTAL REPAYMENTS OR 251,0 s. FUND PAYMENTS 235b 2356 2356 2356 2356 2356 2356 2356 235t:> 23Sb 2356 2356 253,0 TOT INTEREST DUE 5838 5706 5573 5441 5309 5177 5045 4913 4780 4648 4516 4384 255.0 -------------------------------------------------------------------------------------------------------··---257,0 TOTAL DEBT SERVI 8194 8061 7929 7FI7 7665 7533 7401 7268 7136 70011 6872 6740 15 AUGUST 79 A~CI-101HGE -FAIRBANKS INTE:.RCONNECT ION 20-80 REA•FFB DEBT SERVICE SCHEDULE LINE 1996 !997 1998 1999 2000 2001 2002 2003 200/.1 2005 2006 2007 NO 152.0 AP,\ 15~.0 SINKING Fu•w 0 0 0 0 0 0 0 0 0 0 0 0 l5b,O INTEREST DUE 0 0 0 0 0 0 0 0 0 0 0 0 158,0 ------------------------------------~-----------------------------------------------------------------------lbO,O S,FUND+INTE:.QEST 0 0 0 0 () 0 0 0 0 0 0 0 I b I. 0 lb6,0 RtA 168,0 REPAYMENT 350 .350 350 350 350 350 .350 350 350 350 350 350 171.0 OUTSTANDING bo52 b302 5952 Sb02 5252 ~901 ~551 ~201 3851 3501 3151 2801 172,0 INTEREST DUE 350 333 315 298 2110 2b3 2~5 228 210 193 175 158 17/.1,0 -------------------------------------------·-------------------------------------------------------------·-·-176,0 DEBT SERVICE 700 OR3 o6':> b~R 630 613 595 <;78 560 5~3 525 508 1 77.0 182,0 CFC 18~.0 REPAYMENT 0 0 0 0 0 0 0 0 0 0 0 0 18 7. 0 OUTSTANDI'.Ili 0 0 0 0 0 0 0 0 0 0 0 0 , 188,0 INTEREST" \) 0 \} 0 0 0 0 0 0 0 0 0 .. 190,0 ··------------------------------------------------------------------------------------------------~---------1.0 192,0 DEBT St:RVICE 0 0 0 0 0 0 0 0 0 0 0 0 193,0 198,0 FFB 200,0 REPAYto<E:.NT 1~00 1~00 1/.100 1~00 1~00 1~00 1~00 1~00 1~00 11100 11100 11100 202.Q OUTSTANDING 2b60B 25208 23807 22/.107 21006 19606 1B20b 16805 15~05 1~00~ 1260~ 11203 203,0 INTEREST 2591 2Lib1 2332 2202 2073 19£13 181~ lb8~ 15511 1/.125 1295 11bb 20/.1,0 ----------~----------------------------------·-----------------------------------·---·-----------····---------20b,O DERT SERVICE H91 38b2 3732 3b03 3~73 33/.1~ 321~ 308/.1 2955 2825 2b9b 2566 207,0 212.0 AMU 2111,0 SINKING F UNO .371 371 371 371 371 371 371 371 0 0 0 0 216,0 INTEREST DUE 936 93b 93b 936 936 936 936 936 0 0 0 0 218.0 -------------------------------·---------------------------------------·---~---------------·-------------·-· 220.0 S,FUND+INTEREST 1307 1307 1307 1307 1307 1307 1307 1307 0 0 0 0 221,0 228.0 F_,U 230.0 SINKING FUND 23~ 2.3~ 23/.1 23~ 23~ 23~ 23~ 2.3~ 0 0 0 0 232,0 INTEREST 11UE 672 672 b72 b72 672 b72 672 b72 0 0 0 0 23~.0 ---------------------~-----------------~-----------------------------------------------------------·--------23o,o S,FUND+JNTEREST 906 906 90o 90b 906 906 90b 90b 0 0 0 0 250,0 TOTAL REPAY"'E"'TS OR 251.0 s. FUND PAY"ENTS 23'56 2356 235o 2356 235b 2356 235b 235b 1751 l 7 51 1751 1751 253,0 TOT INTEREST DUE ~5~9 /.11102 ~25"> <l108 3961 381/.1 3bb7 3520 176"> 1b17 11170 1323 255,0 -------------------------------------------------------------------------------------------------·-----------257.0 TOTAL OEtH SE:Rvr b90':i b758 bb1l b46~ b317 6170 6023 587b 3515 3368 3221 3074 1 I J .J J J ) J .J l l 15 AUGUST 79 t.NCHfli<AGf -FA lfHIA•JKS T'<TE.RlQNNECTION 40•60 RE.A•FFB DEBT SERVICE. SCHEOULE LI~t 199o 1997 1998 1999 2000 2001 2002 2003 200'< 200S 2006 2007 NO 152.0 A f.> A 15ii,O SINKif><G FUND 0 0 0 () 0 0 0 0 0 0 0 1'>6.0 INTERtST DUE 0 0 u 0 I) 0 0 0 ll 0 0 0 158.0 --·-------·--------·-------------------------------------------·----------------------------------------·---160.0 S,fUND+TNTEREST 0 0 0 0 0 0 0 0 ;; 0 0 0 161 • 0 l66o0 REA 1b8.0 REPAYMtNl 700 7 (I 0 700 7\JO 7 0 0 700 70() 700 700 700 700 700 1 7 I • 0 OUTSTANDING 1 3504 1?6011 11904 11 ?0 3 10503 91l03 910.3 81103 7702 7002 6302 5602 172.0 INTEREST DUE 700 665 630 ':>9':> 560 5c5 490 1155 LJ2Q 385 350 315 1711.0 --------------------------·------------·----------------------------------·---------------------------------1 7b 0 0 DEflT SERVICE 1LJ0() 1365 1.331) 1290, 1260 122<; II 9 0 liS<; 1120 1085 1050 1015 I 77 o o 182o0 uc 18ilo0 REPAYMENT u 0 0 0 0 0 0 0 0 0 0 0 18 7 0 0 OlJTSTANOING 0 0 0 0 () 0 0 0 I) 0 0 0 "TJ 18~ .• 0 INTEREST 0 0 0 0 0 0 0 0 0 0 0 0 I l90o0 -" -------------------------"·-----------~---------------------------------------------------------------------0 192.0 DEflT SERVICE 0 0 0 0 () 0 0 0 0 0 0 0 193.0 198o0 FFB 200.0 REPAYME:NT 1050 1050 1050 1050 IO':lO 1050 1050 1050 1050 1050 1050 1050 202oO OUTSTANDING 19956 1H90b 17855 16805 I 5 75 ':> 11170£1 13654 126011 1155.3 10503 9ll53 6ll03 203.0 INlER~ST 19113 1846 1749 1652 )5<jll 1457 1.360 1263 1166 1069 972 87tl 204o0 ---------------------------------------------------------------·----------------------------------------·---206.0 DEAl SE:.RVJCE ?993 2896 ?799 2702 .?60S 2508 2ii!O 2313 2216 21 19 2022 1925 207.0 212oO AMU 21ii.O SINKING FIJND .371 3 /1 371 371 .371 371 371 3 7 I 0 0 0 0 216.0 INTEREST DUF 93o 93b 936 9.)b 93'b 936 936 936 (J 0 0 0 211lo0 -------------------------------------------~------------------------------------------------------------·--· 220o0 SoFUNO+PdERE:SI 1307 1307 1.3 0 7 1307 130 7 1307 1307 1307 0 0 0 0 221.0 228.0 FMU ?30.0 SINKING FIJNI) 234 2.311 2 .3i~ 2 3ll c34 23ll 2311 234 (> 0 0 0 232.0 INTFRFST DUE b72 672 672 672 h72 672 672 672 0 0 0 0 23ilo0 -------------------------------------------------------------------------------------------------------·----236.0 S. F UNO+ T ~~ T t REST 90o 906 906 906 901, 906 906 906 0 0 0 0 25o.o TOTAL REPAYMENTS t)~ 251.0 So FUNO PAYMENTS .2.356 23':>6 2.356 <:'356 235t> 23S6 2.356 2356 I 75 I 1 7 51 1 751 1751 253.0 TOT INTEREST Dl1E ll252 ll120 3987 385<; 3 72.$ 559 l 3459 3327 1586 11.15£1 1322 1189 255.0 ---------------------·-----------------------------------~-------·-------------------·-----------··-----~---257o0 TOfAL lJE f:H SE:.RVI 6601:1 6i170:. 63113 h2ll 6079 5947 <j8J':> S682 3337 320ll 3072 29ll0 l '5 AiJGlJST 7Q A'I(HORAGf. -FAIRBANKS !NTE.RCONNtCTTUN 20-80 Rt4•FFB DERT SERVICE SCHEDULE Ll'-E 200ft 2009 2010 20 II 2012 c:>ol3 ?.01<1 201'5 1\1[) 1':.2.0 APA 151!.0 SINKING Ftn,o (l 0 0 0 0 0 (J 0 151:>.0 !NTERE.:iT DUE. 0 0 0 0 0 0 0 0 158.0 ·-~---------------------------~-----------------------------------------160.0 S.~lJNDt fi<TU<!:S T 0 0 0 0 () 0 0 0 161 • 0 lbo,o RE.A lb8,0 RE.PAYMP-IT 350 v;o )50 v:;o 3'5 \) .~50 350 3')0 I 71 • 0 OLITSTANDI>.IG 2«'51 21ll I 1751 1400 10'50 700 350 0 1 7 2. 0 11\lTfRF:ST DuF I 4 0 123 lO':i 81'1 70 'H 35 18 174,0 ------------------·---------------~~---------·---------------------·----176.0 DI:~H SI:.RVICF. <19(1 4n 455 43R 4?0 /J 0~ 385 ~bR 1 77. [) 182.0 CFC 184.0 RU'AY"'f.NT 0 0 lJ 0 0 0 () 0 187,0 DLITSTANf'l"JG I) 0 0 0 0 0 0 0 "'T1 188.0 INTEREST () 0 0 0 0 0 0 0 I 190,0 --------------~--------------·---------·--------·-----------------------__. __. 192.0 DE~T Sf:.RVICI: 0 0 I) 0 0 0 0 0 193,0 198,0 FFR 200,0 REPAYMENT I'~ 00 1400 1'-100 1400 1400 11!00 1400 1400 20;::>.0 Ol!TSTANDlNG 9f<03 8Q03 7002 560;::> 4cOI 2801 !!I 0 0 0 203.0 INTERI:ST 1036 907 777 bQil 518 389 Z59 130 20U,O -~-------·-------------.-------------·------------·-·-----------------~--20b.O DfAT SeRVICE" 2437 23!l1 217~ 2041l 1919 1789 1660 1530 207.0 212.0 AMI) 211.1.0 SINKING F UNO 0 0 0 0 0 0 0 0 216,0 lNTERfST OUE 0 0 0 0 0 0 0 0 218.0 ------------------------------·-----------------------------------------220,0 S,FlJND+INTfRtST 0 0 () 0 0 0 0 0 221.0 228.0 FMU 230.0 SINKING "''-'"[) 0 0 I) 0 0 0 0 0 232.0 INTEREST DUE 0 0 0 0 0 0 0 0 2311.0 --------------------------------~---------------------------------------236.0 S.~UNDt!f-JTERFST 0 0 0 0 0 0 0 0 250.0 TUTAL REPAn•PHS OR 251. 0 s. FUN[) PAYMENTS 1 751 I 7 ~I I /51 I 751 1751 l 7 'll I 751 1751 253.0 lOT INTEREST f)Uf 117b 1029 81l2 735 588 441 291! 147 255.0 -------------------·----------------------------------------------------257.fl TOTAL IJE t' T StRVI ?927 2780 2633 21!86 2339 2192 2045 1898 J J J J J j J J J -· ,_] .J ,I J ,I ~J ·~j .. c.J .J .J J 1 ) 1 1 ) 15 AUGUST 79 ANCHORAGE -FAIRAAIIIKS I NTI::RCONNEC T I ON £10-60 REA-Ff'B DE:.I:lT SERVICE SCHEDULE LINE 2008 2009 2010 20 11 2012 2013 2014 2015 NU 152.0 APA 154.0 SINt<H;G F!JND 0 0 u 0 0 0 0 0 151:>.0 INTEREST DUE 0 0 0 0 0 0 0 0 158.0 ------------------------------------------------------------------------1t.o.o S.FUNDtTNTEREST 0 0 0 0 0 0 0 0 161.0 16o.o ~EA 1oR.o REPAYMENT 700 700 700 700 700 700 700 700 1 7 I • 0 OUTSTANDING 4901 £1?01 3501 2801 <'I 0 I 1400 700 0 172.0 INTEREST DUE 280 ?45 210 175 140 105 70 35 174.0 ------------------------------------------------------------------------171:>.0 DEBT SERVICE 980 945 910 875 8£10 805 770 735 I 77.0 182.0 CFC 184.0 REPAYMENT 0 0 0 0 0 0 0 0 187.0 OUTSTANDING 0 () 0 0 0 0 0 0 ,., 188.0 INTEREST 0 0 0 0 0 0 0 0 I _..:; . I 90. 0 ---·-----------------------------------------------------------------·--N 192.0 DE tiT SERVICE 0 0 0 () 0 0 0 0 --I 9 3. 0 198.0 FFA 200.0 REPAYMENT 1050 1050 1050 1050 1050 1050 1050 1050 202.0 OUTSTANOI"JG 7352 6302 5252 4201 3151 2101 1050 0 203.0 INTEREST 777 680 ':!83 486 389 291 194 97 204.0 ------------------------------------------------------------------------206.0 OEFlT SERVICE 1828 1730 207.0 1633 1 "i3b 1439 1342 12£15 I 14 7 212.0 AMU 214,0 SJNKlNG f-UND 0 0 0 0 0 0 0 0 216.0 INTEREST DUE 0 0 0 0 0 0 0 0 218.0 ------------------·-----------------------------------------------------220.0 s.FUNDtiNTEHST 221.0 0 0 0 0 0 0 0 0 228.0 FMU 230.0 SINKING FUND 0 0 0 0 0 0 0 0 232.0 INTHifST DUE 0 0 0 0 0 0 0 0 23'1.0 -----------------------------------------·------------------------------236.0 S.FUNDtiNTER~ST 0 0 0 0 0 0 0 0 250.0 TOTAL REPAYMENTS OR 251.0 s. FUND PAYMENTS 1751 17':!1 1751 1751 1751 1751 1751 1751 253.0 TOT INTEREST DUE 1057 925 793 6b1 529 396 264 132 255.0 ------------------·-----------------------------------------------------257.0 TOTAL DEBT SERVI ?808 2676 2':144 211 1 1 2279 2147 2015 1883 IS A\IGUSl 79 A\IC•WiHGE • FA!~84NI(S INltRCONNECTION 20•80 REA•fFH DEBT REPAY"'ENT A"lrl SP-iKING FUND ALLOC AT !0"1 13Y LIT!LITY L1'lf 1984 19~5 198o to87 !988 I'H\9 1990 I 9·9 I 1902 1993 19911 199'l NO 3S2,0 A''L 1'. p ~C,ll.O REP~YM£!\1 A·'1UUNT 424 ll.?ll ll21.1 1.121.1 42iJ 42iJ 1.124 1.121.1 1.124 iJ21.1 1.121.1 1.121.1 .35/l,U OUTSlA!\[)1'-Jb <H70 4574 ll.379 1.1181.1 " .39119 3793 3598 31.103 3207 3012 2817 2bi.Z 3b0,0 !Nlf_RF_Sl DUE I I .3 7 I 11 0 I 0 8·~ 1057 I 0 31 1001.1 978 951 92':> 1191\ 872 111.15 361.0 362.\l CEA 364,0 REPAYMENT AMUIJ'd 25<l 259 2"i9 259 259 .?5o 259 2':19 259 259 259 259 .3o8,!l 0 tl T S T II 'IJ D ! N (; 2qlr; 27o<J 2o7o 2"><)7 2tJ37 2318 2199 2079 1960 1841 1721 1602 HO.O P·ilf>IEST Dlif bO'i 678 ob2 6iJ6 o~O 611.1 'j97 581 565 549 ':!H 517 3 71. 0 372,0 MEA 374.0 R~PAYMUJl H101.1NT 7 I 7 I 7 1 7 I 7 1 7 I 71 7 I 71 7 I 71 71 378.0 OUTSTA~WJN[; 70'j 7o2 730 6''17 6b<J 632 bOO 567 5.35 502 1.169 1.1.37 380.0 INTEREST flllf I~Q 11:15 lA 1 l7b 172 167 ltd 159 151.1 150 11.15 11.11 ., 381 • 0 1 31l2.0 HtA ..... .381.1,0 Rfi-'AYMI::Nl AMUUNT 0 0 u 0 0 0 0 0 0 0 0 0 w 388,0 OUTS I AND! r~(.; v 0 I) 0 I) 0 0 0 0 0 0 0 390.0 INTERfST flU[ 0 0 () 0 0 0 0 0 0 0 0 0 H1.0 402,0 ~MUS 1.101.1,0 RfPAH1E:.NT M10UNT 28~ ,?83 21:\3 283 283 283 283 2fl3 28.3 2fl3 283 283 1.108.0 OUTSTANOJNt; ~1110 30':)0 291Q 2789 265'1 2529 2:)99 22b8 21J8 2008 1878 1748 1.110.0 !NTfREST OUF. . 7 <;8 71.10 722 705 bR7 669 b52 b31.1 bl7 599 '581 '564 411.0 1.112.0 GVEA 1.111.1.0 ~fi-'AY"lE:.NT AMOUNT 131'1 1319 I 31 q 131 Q 1.31q 1319 1319 1319 1319 1319 1.31 q 1319 41b,O CUMULAlTVE 1319 2b3~ 395/l <;27 7 b59o 7915 9235 10551.1 118 7 3 13192 11.1512 1'5831 418.0 OUTSTANDlNI.l 14/:13<l 11.1231 13o211 !.301b 12ll0Q IIROI 11191.1 1058b 9979 Q371 8761.1 8156 1.120,0 INTERF.ST flUE 3S3o .3ll53 B71 3289 320b 3124 3042 2959 2877 2795 2712 2630 1121 • 0 ll22.0 CVEA 1.124,0 REPAYME:.NT AMOUNT 0 0 0 0 l) 0 0 0 0 0 0 0 1.12b,fl CUMlllAlJVf 0 0 0 0 0 0 0 0 0 0 0 0 428.0 OUTSTANfll'lll 0 0 0 0 0 0 0 0 0 0 0 0 1.130,0 INTEREST flU F. tl () 0 0 0 0 0 0 0 0 0 0 J J I J J .I --. l ~-. 1 l ] 15 AtJGus r 79 M•CHORAGE • FAIRBANKS INTERCONNECTION 40•!>0 REA•FFB DE: t:ll REPAYMENT AND SINKING FUN() ALLOCATION BY UTILI TV LINE 1984 1985 1986 1987 1988 1989 1990 1991 1992 I 993 1994 19<15 NO 352.0 AML !(. p 354.0 REPAYr-IENT AMOUNT 424 424 421.1 424 1.124 424 421.1 424 421.1 424 424 11211 3':>8.0 OUTSTANDING 6') 37 !>284 603? 5779 55?7 52711 5022 11769 4517 4265 11012 37&0 3oo.o · INTEREST OuE 1051 I 027 1003 979 956 932 908 8811 f\60 R31 813 789 361. 0 362.0 CEA 3611,0 REPAYMlNT A"''OUNT 259 259 259 ?5<1 259 259 259 259 254 259 259 259 36R,O OUTSTANDING 3995 5840 3686 3532 3378 3223 3069 2915 2760 2606 2452 2298 370.0 INTEREST DUE 6112 628 613 599 584 569 555 5LIO 526 511 1197 1182 371.0 372.0 1o1EA 3711.0 REPAYt-<ENT AMOUNT 71 71 7 I 71 7 1 .,, 71 n 7 1 71 7 I 7 1 HB.O OUTSTANDING 1089 10'17 1005 963 921 879 837 745 753 7 1 I 669 b27 380.0 INTEREST DUE 175 171 167 163 159 155 151 147 1113 139 135 1 32 381,0 , 382,0 HEA I ....... 3811.0 REPAYMENT AMOUNT 0 0 0 () 0 0 0 0 0 0 0 0 _.,. 388.0 OUTSTANDING 0 0 0 0 0 0 0 0 0 0 0 0 390.0 INTEREST OUf' 0 0 0 0 0 0 0 0 0 0 0 0 391. 0 1102.0 FMUS 1104.0 REPAYMENT AMOUNT 283 283 283 283 283 283 283 283 283 283 283 283 1108.0 OUTSTANDING 11358 4190 4021 31153 36R5 3516 33118 3180 3011 28113 2675 250b 1110.0 INTEREST DUE 701 685 669 653 637 621 60':> 590 5711 558 5112 52b 1111.0 1112.0 GVEA 11111,0 REPAYMENT AMOUNT 1319 1319 1314 1319 1319 1319 I 31 9 1319 1319 1319 1319 1319 1116.0 CUMULATIVE 1319 2638 3958 5277 6596 7915 9235 105511 118 73 13192 111512 15831 1118.0 OUTSTANDING 20337 19551 18766 17980 17195 161109 1'5624 ILI838 111053 l 3267 121182 11&96 1120.0 INTEREST DUE. 3269 319') 3121 3047 2973 2899 2825 2751 2677 2603 2529 21155 1121. 0 1122.0 CvEA 4211.0 REPAYM!:NT AMOUNT 0 0 0 0 0 0 0 0 0 0 0 0 1126.0 CUMULA T J VE 0 0 0 0 0 0 0 0 0 0 0 0 428.0 OUTS lANDING 0 0 t) 0 0 0 0 0 0 0 0 0 430.0 INTEREST DUE 0 () 0 0 0 0 0 0 0 0 0 0 I 5 .l'IGl!ST 79 AN(HClRAGE -F~!RAANKS lNHRClJNNECl ION 20-80 RU-FfS i)t_ tl T REPAY'"~ENT Ar·W SI"'K!NG FUND ALLOCATION FlY UTILITY Ll NE \'l'lb !9'17 1'1'18 1'1'1'1 200\l 2001 2002 2003 2001.1 2005 2006 2007 NO 352.0 AML " p 354.0 RI:PAY'~ENT AMtlUr. T 424 424 424 424 424 424 424 4211 315 3\S 315 315 3SB.O OUTSTAr-<[){NG 2426 2231 2036 1840 1645 1450 125') 10')9 <173 1387 800 714 .3oO.O !NTERlST r)UE t\19 7'12 lbb 73'1 713 I;>B7 660 6311 H8 2'11 265 231'1 361.0 36?..0 CEA 364.0 REYAYt-<UH AMOUNT 25'1 25'1 259 2';9 2C,'I 2':l'l 259 259 19.3 1'13 1q3 193 36fi.O UUTSTANOli\JG 14B.l 1363 1244 1125 1005 886 767 647 595 542 489 436 370.0 {NTfRfST DUE ':>Otl 484 '168 452 436 420 403 387 194 1 78 162 1116 3 71.0 372.0 I" E. A 374.0 REPAYMENT A'1CJUNT 7 1 71 71 7 I 71 71 7 1 7 1 53 53 53 53 378.0 OUTSTANDING 40~ 372 B9 307 (!71:! 242 20q 177 162 148 133 11'1 380.0 INTERfST DUF 136 132 128 123 I 1 q I Ill I 1 0 106 53 ll9 411 40 381. 0 -.., 382.0 HI: A ! 384.0 REPAYMUJT AMOlJ"H 0 0 0 0 0 0 0 0 0 0 0 0 _, <.Jl 388.0 OUTSTANDING I) 0 0 0 0 0 0 0 0 0 0 0 390.0 INTE::RF-ST DUE 0 0 0 0 0 0 0 0 0 0 0 0 3'11. 0 '~ 0 2. 0 PlUS 404.0 REPAYMENT AMOUNT 21:\3 283 21'1.3 283 283 283 283 283 210 210 210 210 ll08.0 OUTSTANDING 1618 1ll87 1.35 7 1227 1 0'17 . 967 836 70b 649 5'11 534 476 410.0 INTEREST DUE S46 528 511 493 475 4')8 440 422 212 I 'Ill 176 159 lj 11 • 0 ll12.0 GVEA 414.0 REPA HIE.N T MtOUNT !51 9 1319 131 q 1319 151'1 1 319 1319 1319 980 960 980 980 llii:>.O CUMULATTVE I 715 U 18llo9 1971'19 211 08 22427 237ll6 25065 26385 27365 283115 29326 30301> 418.0 OUTSTANDING 754'1 b'llll 6333 ')726 ') 1 18 ll511 3903 3296 3027 2759 2490 2221 420.0 INTEREST OUE 2541:1 2ll65 2383 2301 2218 2136 2054 19 71 9A8 'lOb 623 741 421.0 ll22.0 CVEA 424.0 REPAYMENT AMOUNT 0 0 0 0 0 0 0 0 0 0 0 0 ll26.0 CUMULAlJVF 0 0 0 0 0 0 0 0 0 0 0 0 428.0 OUTSTANDING 0 0 0 0 0 0 0 0 0 0 0 0 430.0 INTEREST QUE 0 0 0 0 0 0 0 0 0 0 0 0 J J _) J .J I j l,_:, "' J J \ ... " . J .J ] l 1 -~ ) .. l ··· ... l 1 15 AUGUST 79 ANCrlORAGE. . FAIRFlA~K:S tNH.RCONNEC T I ON llO•bO RU.~FFB DEi:lf RE.PAY"lENT AN f) SlNI\ING FuND ALLOCATION BY IJT I L I T Y LI:-.JE 199t> !997 1998 1999 .?000 200t 2002 2003 200£1 2005 2006 2007 NO 352,0 A,_.L & p 354,0 REPAY"~ENT A "~LliJN T 42'~ 424 L12LI ll2LI £124 LI2LI 42LI 424 3t5 315 315 315 358.0 OUTSTANDING 3507 3255 3002 2750 2497 2245 t992 1740 1596 1453 1309 1166 3t>O,O lo'JTEKEST Dl!f. 765 7ll? 718 694 b70 646 623 599 285 262 238 2tLI 361. 0 362.0 CEA 36LI,O fiEPAYI-IENT A"'fJU"lT 259 259 259 259 254 259 259 259 193 193 193 193 368,0 OUfSTANDING 21ll3 1989 tf\3S 1680 1';.26 1372 121 7 1063 976 888 800 712 370 .o INTEREST l)l)f ll68 4':>3 ll3<1 424 litO 395 380 366 174 160 145 I 3 1 3 71.0 372.0 MEA 374,0 fiE PAYMENT AMOUNT 7 I 7 I 7 I 11 7 1 71 7 1 7t ':13 53 53 53 378.0 OUTSTANDING 585 5ll2 ':)0() 458 416 374 332 290 266 242 218 19LI 380,0 INTEREST flUE 128 124 t20 116 1t2 !Of\ 104 100 LIB 4LI 40 36 381.0 , I 382.0 HEA ....;.., 38ll,O REPAYMENT AMOUNT 0 0 u 0 0 0 0 0 0 0 0 0 0'1 388,0 OUTSTANDiNG 0 0 () 0 0 0 0 0 0 0 0 0 390,0 INTEREST DUE 0 0 0 0 0 0 (J 0 0 0 0 0 391,0 LI02.0 FMlJS 404.0 REPAYMENT A"10UNT 283 283 283 ?f:\3 283 283 283 283 210 210 210 210 408,0 OUTSTANDING 2338 21 7 0 200t tAB 166';. ;)11.196 1328 1160 1064 968 873 777 1.110,0 INTEREST DLIE 5t0 494 li7B ll63 £147 431 415 399 190 171.1 !59 11.13 Lj 11.0 412.0 GVEA 414,0 REPAYMENT A~OUNT 13t9 1319 1319 1319 tH9 1319 t319 1319 980 980 980 980 416.0 CUMULATIVE 17t50 t8469 19789 21108 22ll27 23746 25065 26385 27365 283ll5 29326 30306 418,0 UUTSTMIO!NG 10 911 t0125 9.SLIO 8')55 7769 6984 6198 5LI13 496b Ll520 1.1073 3627 420.0 INTEREST Dllf 23Rt 2307 223) 2159 2085 2011 t937 18.63 888 814 71.10 6b6 1.121.0 Ll22.0 C Vf.A 1.121.1.0 RFPAYMI:.NT Al-l OLIN T 0 0 0 0 0 0 0 0 0 0 0 0 1.126.0 CIJMIJL AT I Vf 0 0 () 0 0 0 0 0 0 0 0 0 1.128,0 OUTSTANDING () 0 0 0 0 0 0 0 0 0 0 0 1.130,0 lNTERE:ST DUf 0 0 0 0 0 0 0 0 0 0 0 0 1", AUGUST 79 ANCHORAGE -FA!R~ANKS t"'lERCONNECTION 20-80 REA-FFB Df:I:H REPAY"'ENT A 'II) SINI(!I'.IG FU"J[} ALLOCATION t;Y UTILITY li"'E 2006 2009 2010 2011 2012 2013 2011.1 2015 NO "JS2.o A"'L ~ p 351.1.0 RfPAYMtNT A'10U"lT .SIS 315 315 315 515 315 31':> 315 358.0 OUTSTAI'iOING 628 S4l 1155 3o9 282 196 11 0 23 360.0 JNTERfST l'lUE 212 185 159 132 lOb 79 53 26 361. 0 362.0 CEA 364.0 REPAYMENT AMDlHJl 195 193 1<n 193 193 193 193 193 36A.o OUTSTAN0!NG 3RI.I 331 27h 225 1B 1c>O 67 14 370.0 INlERE.ST DUE 12<1 1 I 3 Q7 R1 65 49 32 16 3 71.0 372.0 "1EA 374.0 REPAYMENT A1140!1NT 53 53 53 53 53 53 53 53 378.0 OUTSTANDl"JG 105 90 76 61 117 33 18 4 380.0 INTEREST nut 35 31 26 2?. PI 13 9 4 381.0 ., 382.0 HE:. A I .....::. 38'1.0 REPAYMtNT Ai'IOUrJT 0 0 0 0 0 0 0 0 ......... 388.0 OUTSTANDING ll 0 0 0 0 0 0 0 390.0 INTEREST f)tJE l1 0 0 0 0 0 0 0 391.0 1102.0 F"'US 1104.0 REPAYMENT Al"lJUNT 210 210 210 210 210 210 210 210 408.0 OUTSl ANop,r, 1.118 361 503 246 188 1 3 1 73 16 410.0 INTEREST Dllt I 4 I 1211 lOb 88 71 53 35 18 411.0 1112.0 GVEA 414.0 REPAYI'IE.NT AMOUNT 980 980 980 980 '180 980 980 980 416.0 CUMULAllVt 31286 32266 332117 311227 35207 36181'> 37168 38148 418.0 l1UTSTAND!NG 1953 16tl'l 1416 111!7 878 610 341 73 420.0 lNlFkEST DUt: 6<;Q 576 494 412 329 247 16"l 82 421.0 112.?.0 CVFA £124.0 REPAYMENT AM()IJNT 0 0 0 0 (} 0 0 0 1126.0 CUMULATIVE 0 0 0 (} 0 0 0 0 428.0 LIUTSTAHI)ING 0 0 0 0 0 0 0 0 430.0 lNifRfST flUE 0 0 0 0 0 0 0 0 I ...... 1 .J J I 'J l ,··~· 1 l ~15 AUGUST 79 ANCHORAGE -FAIRAANK.S INTE.RCONNE.CT!ON U0•60 f.IEA-FFB OE8T REPAYMENT AND SP-11\ING FUND ALLOCATION BY I.J TIL IT Y LI'IIE .?008 ~009 ?010 2 01 1 2012 ?013 2014 2015 NO 352,0 AML & p 3'::>4,0 REPAYME.NT AMOUNT 315 31'> 515 315 31S 3l'l 515 315 3')A,O OUTSTANDING 1022 879 735 59? 448 305 161 1 7 3b0,0 INTERFST DUE 190 167 143 1 1 9 95 71 Ull 24 361.0 3b2,0 CEA 364,0 REPAYMENT AMOUNT 195 193 195 193 195 193 193 193 36A,O 0 U T S T A N 0 PIG 62') ')57 449 3o2 274 186 98 1 1 370.0 INTEREST DUE 1 1 b 102 87 73 58 44 29 15 371.0 372.0 MEA 374,0 REPAYMENT AMOUNT 53 53 55 53 53 53 53 53 378.0 OUTSTANDING 170 146 123 99 7'::. 51 27 3 380,0 INTEREST DUE 32 28 24 20 16 12 8 4 381.0 , 382,0 HEA I """"' 384,0 REPAYMENT AMOUNT 0 0 0 0 0 0 0 0 co 388,0 OUTSTANDING 0 0 0 0 0 0 0 0 590,0 INTEREST DUE 0 0 0 0 0 0 0 0 391,0 402.0 FMUS 404,0 REPAYMENT AMOUNT 210 210 210 210 210 210 210 210 40A.O OUTSTANDING 681 586 490 394 299 203 107 12 410.0 lNTERE.ST DUE 127 1 1 1 95 79 6 s 4fl 32 16 411.0 412.0 GVEA 4111,0 REPAYMENT AMOUNT 980 980 980 980 980 980 980 980 416.0 CUMULA T T VE 31286 322bb 33247 34227 35207 36188 37168 38148 411'1. 0 OUTSTANDING 3180 27 34 2281 1841 1394 947 501 54 420.0 INTERFST DUE 592 ')18 444 370 296 222 148 74 421.0· 422.0 CVEA 1.124,0 REPAYME"JT AMOUNT 0 0 0 0 0 0 0 0 426.0 CUMULATIVE 0 0 0 0 0 0 0 0 428.0 OUTSTANDING 0 0 0 0 0 0 0 0 430.0 INTERFST f1UE 0 0 0 0 0 0 0 0 I~ AtlGllS 1 7q 1\N(HORAGf -FATR8ANI\S I "'TtRCONNEC T TON 20•80 REA•FFB STNI<JNG FUNO ACCUI'IULATIONS LIIIE 1911<! l'HI"l l98b 1987 1988 19R9 1990 !991 1992 1993 fCI94 19CJS NO soo.o APA 502.0 S,fiJUD 1-' ~~ r 0 n 0 0 0 0 0 0 0 0 0 0 501!,() ft.jTI'RFST !h f liND 1) 0 0 0 0 0 0 0 0 0 0 0 'i06.0 TO I Ill l " F Uf·lfl l' •) 0 (1 0 0 0 0 0 0 0 0 ')20,11 A"'ll 522.0 s. FU"'Il tJ •A l HI HI HI 3 71 571 HI HI 371 371 371 371 371 S2Q,Il PJTfh'fSl (-lt>f ~ IINf'l tl cQ 'ill 77 tOo lH 170 20& 21!3 283 32'5 371 '526,0 rn r AL l N F If 'Ill 371 76h IIRl tn3"o 211? 2621 3162 3759 4 3'5 3 500b 5703 &1145 ')50,0 F'111 53<'.0 s. FU'J() f'MT 2 3·~ 2 5ll 23~ 2 3£1 2311 231l 231l 231l Hll 234 234 234 551l,O INTI'RFST (HI Fll" f) I) I b 311 53 B 94 I 1 7 1'12 tb8 t9b 227 259 536,0 In T 4L I 'J 'I I'll) c'\<l IHl<; 753 10110 I .)1~ 7 lb7b 2027 21103 280& 323& 3b~1 4190 "'TI I ,_. 1.0 LINE 199b 1997 199R 1999 2000 2001 2002 2003 "10 '500,0 APA 502.0 S,FliNI' PMT I) 0 0 0 0 0 0 0 501l,O !NTfREST n ~~ f'll Nf'l l) 0 0 0 0 0 0 0 SO&.o Tf1TAL I'' r I fiJr) 0 0 0 0 0 0 0 0 520.0 AMU 52(>,0 s. FUNIJ p,..q 371 HI .HI HI HI 371 HI 371 521l.O INTFfH ST rHJ ~liND IJI Q II 70 ':)25 'i83 btl') 7 11 7R2 85b 526,0 TOTAL lN F lltJI\ 72V-, !\(176 ll972 9'12b \ 0QIJ2. 12024 13177 1111101! "dO.O FMU 532.0 s. FUND '"'~· r 23<1 231l 2~<1 231l 2H 231! l311 2311 '534.0 lNfER~ST Of'< F II"'D 2Q3 :5.)(1 570 lll2 <l"i7 SOb 557 &13 53,&. 0 TOTAL IN FU"Jf) ii718 ~282 '}IJ8b b'5H 72211 79611 8756 9003 J J J • .] " J ' J J J 1 J J 1 l l I ') AUGIJS T 74 A~<j(!-IORAGE -FAllolflANKS I "'H RCONNEC T I ON ll O•bO RE.A-FFB SINKING FUNO ACCUMULATIONS L I ~E. 19~~ 1985 PH\6 1987 1988 1989 1990 1991 1992 1991 lqqq 199'5 NO 500,0 AP.A 502,0 S,FIIND PI-IT u 0 0 0 0 0 0 0 0 0 0 0 50q,O INTERfST (HJ I' li"J() v 0 0 0 0 0 0 0 0 0 0 0 506,0 TOTAL Ut F IJ"Jl! 0 0 0 0 0 0 0 0 0 0 0 0 'i<?O.O AMIJ '>.?2. 0 s. FUN[) P"T HI HI 371 HI HI 371 371 HI 371 'HI 371 371 5?/J,O lNlERfST fl N f. IIIIo [) I) 211 50 77 lOb tH 170 ?Ob 243 ?83 325 371 526,0 I OTAL IN F •J N n Hl 766 1 I fl I 1635 2112 21>21 3162 3739 £1353 5006 5703 b44'i 530.0 F.,, J '"n. 53?.0 s. FUN[) P'-11 23~ 23£1 23£1 2 3/J 23£1 234 234 23£1 23£1 <:>34 2Jij 234 I N' 534,0 INTfi<FST f1"J I' IINfl 0 lb 3£1 '}3 73 94 tt7 1£12 168 196 227 259 0 536,0 TOTAL IN FUfJI) 23" £18') 7<;3 101.10 13£1 I 1676 2027 2403 2806 3?36 3&97 4190 LINE IQ9() 1997 1998' 1999 2000 2001 2002 2003 NO 500,0 APA 502,0 S,FIJNfl PMT 0 0 0 0 0 0 0 0 504,0 HHERfST ON FIINO (l 0 0 0 0 0 0 0 506,0 TfJTAL IN l'tJI\Jil 0 0 0 0 0 0 0 0 520,0 A "'tt 522.0 S, FUNtJ Pi-ll )71 371 H1 371 HI 371 371 371 524,0 INTEREST f1N fiJND ~19 qJO 525 583 &45 711 782 856 526,0 lOTH IN FtJNO 72 S') 80 7t:o 8<H2 9926 10942 12024 13177 14404 '>30,0 FMU 532,0 s. FUND PMT 2J~ 234 23£1 ?34 234 ?34 234 234 53/J,O INTERfST or~ ~ fiNO 2'H HO 370 41? 457 '506 557 613 536,0 TOTAL iN FUN[) ll711i 528<:' 58A6 o"iH 72?4 7961J 8756 9603 15 AUGUST 79 20-80 R!;A:"*f"fB L!'IE 198'-1 19<15 1986 1987 19~8 I 91'19 1990 1991 !992 1993 l99Q 1995 "JO 551.0 CUM,PR!N/S,FUND* 235o (j 712 7067 9423 II 779 14135 16490 !88Q6 21202 23558 25914 28269 5'52.0 CUM, lNTE:RtST 6314 12LJ81 18501 2!1373 30099 35678 41 I 0 9 4639Q 5!532 56522 61366 66062 55.LO ---------------·--·~-···---------4------------------------------------------------·-------------------------554,0 CUM, DUH SE><VlC ~b7() 17192 255o8 33796 4lH78 49812 57600 65240 7273!1 110080 8727q 94331 555.0 556.0 * NOTE: THE SP•I<J'<t; Fu•~o ~EPAYMF.NTS TAKE. INTO ACCOUNT 557,0 THE: FACT THAT lf<HREST 15 ACCRUING ()N THE FUND, 558,0 THE TOTAL OF THIS LIN£, TrlEREFDf.IE, wiLL NOT MATCH THE 559,0 TOTAL PROJECT COST 560,0 560,5 CUMULATIVE PRINCIPAL AND S H11<1 NG f'U"JD PAYMENTS 561.0 APA 0 0 0 0 0 0 0 0 0 0 0 0 562,0 RE:A 350 700 1050 1400 1751 21 0 I 2451 2801 3151 3501 3851 4201 563.0 CFC 0 0 0 0 0 0 0 0 0 0 0 0 561.1,0 FFB 1400 2801 !1201 5602 7002 8LJ03 9803 11203 12604 1/.IOOLJ 151105 16805 565,0 AMU 371 7'-12 I I I 3 148!1 1855 2226 ?597 2968 3339 3710 4081 41152 566.0 FMU 23il <168 103 937 I I 71 1405 1640 1874 2108 2342 2577 2811 -n 567.0 -------------------·-------------------------------------------------·--·----------------------·------------I N 568,0 TOTAL 2356 4712 7067 9423 II 779 14135 16490 188Q6 21202 23558 259111 28269 --' 569.0 570,0 !NTERI:ST ON S l Nl\ PIG FUNDS 57 I • 0 APA 0 0 0 0 0 0 0 0 0 0 0 0 572.0 AMU 0 24 74 I 51 25 7 395 565 771 I 0 1 !I 129b 1622 1993 573.0 FMU () 16 50 103 17b 270 387 s2q 698 894 1121 1379 574.0 ------~--------·---·------------------------·----·----------·--------~-----------------------··-------------575.0 TOTAL 0 41 124 254 433 665 952 1300 I 7 1 1 2190 2742 3372 576,0 578,0 GRAND TOTAL 235b 47'::.2 7192 qb77 122!2 14Hq 171143 20146 22913 25748 2Bb56 31641 ~J J J ~ l l J .l ~~-} J J .J .~J J J .I c~ ·-'" ~J ] .. .J ... l ·-.. -1 -~l, c•···-·'"l 1 -~~-\ --~1 -~] -J ---· l <-·-c~-l l ~----1 -) ') 15 AUGUST 79 1.10-oo REA·FFB LI~E 19fiLI 1985 1986 1987 1988 1989 1990 1991 1992 1993 199£1 I 99' NO 551.0 CUM.PR!~IS.FUNU• 2356 Ll712 7067 9423 11779 1'1135 16£190 18f\LI6 21202 23558 2591£1 2826 552.0 CU"1. !NTE.RI:ST 5838 I I 54 3 I 7 11 7 ;;>2558 27867 .B04LI 380fl9 £13002 47782 52430 569£16 6133 553.0 ·----------------------------------------------------·-----~------------------------------------~----------554.0 CU"1. DI:8T SERVIC 819LI lb255 21.111\~ 3191:!1 396« t) £17179 5LI579 618£18 68981.1 75988 82860 8960 555.0 556.0 * NOT!:: THI: SINII;!NG FurW REPAYMENTS TAKE J I~ TO ACCOUNT 557.0 THE FACT THAT P•TI:RI:ST IS ACCRUING ON THf FUND. 556.0 THE TUTAL OF r HIS L I Nl:, THF-.RHORE, WILL NOT MATCH THE 559.0 TOTAL PROJECT COST 560.0 560.5 CUMULAT!Vf. PRINCIPAL AND S!Nt<ING FUND PAY"1E.IH S 561.0 APA 0 0 0 0 0 0 0 0 0 0 0 562.0 REA 700 1£100 2101 2801 3501 4?01 4901 5602 6302 7002 7702 8£10 563.0 CFC 0 0 0 0 0 0 0 0 0 0 0 56«.0 FFA 1050 21tJ1 3151 £1201 525? 630? 7352 8£103 9£153 10503 11553 1260 565.0 AMU 371 7£12 1 113 148£1 185') 2226 2597 2968 3339 3710 £1081 £145 566.0 FMU <!34 468 7()3 937 I I 7 I 1£105 16£10 187£1 2108 2342 2577 281 "T1 567.0 ---------------------------------------------------------------------------------------------------~-----·-I 568.0 TOTAL 2356 Ll712 7067 9423 11779 1£113'; 16LI90 188£16 ?1202 23558 25914 2826 N N 569.0 570.0 INTEREST UN SINKING FUN US 571.0 APA 0 0 0 0 0 0 0 0 0 0 0 572.0 AMU 0 24 74 151 2'5 7 395 565 771 1014 1296 1622 199 573.0 FMU 0 16 50 103 176 270 387 529 698 894 1121 137 574.0 ---·-----------------------------------------------~-----------------------------------------~------------~ 575.0 TOTAL 0 41 12ll 25£1 ll33 665 952 1300 1 71 I 2190 27£12 B7 576.0 578.0 GRANO TOTAL ?356 £1752 7192 9677 12212 14799 17443 201£16 22913 25748 28656 3164 1 5 AUGUST 7G 20-80 RU-FFH Ll'IE 1GGo !9'!7 1998 1999 2000 2001 2002 2003 2001.1 2005 2006 2007 '10 551.0 CUM,PRl'I/S,FUND* 30625 329~1 3533 7 37692 1.10048 ll2404 1.14760 1.1 7 116 48866 50617 52367 54118 552,0 CU~1, I~TEREST 7 Oo 11 75014 79269 83377 137338 9115 3 94820 98340 I0010ll 101722 103192 104516 553,0 -------------------·---------~---~---------------------------------------------~-------------------------·--55ll,O c U~1. DEAl SERVIC 1012~o I 0 7995 tt460o 121070 1c'7387 I B'>57 1 395 79 145455 148970 !52 338 155559 158633 555,0 556,0 * NOH: THt. SINKING FU'ID REYAYMENTS TAKE INTO ACCOUNT 557,0 THE FACT THAT INTEREST IS ACCRUING ON THE FUND, 558,0 THE' TOTAL OF THIS LINE, H<f REF ORE, -'ILL NOT "1ATCH THt 559,0 TOTAL PROJECT COST 560,0 5o0,5 CUMULATIVE PRINCIPAL AND SI'<KlNG FUND PAYMENTS Sol. o APA 0 0 0 0 0 0 0 0 0 0 0 0 562,0 REA u55! 4901 5252 5602 5952 6302 6652 7002 7352 7702 8052 81103 563,0 CFC 0 0 0 0 0 0 0 0 0 0 0 0 5o4,0 FFI:l !R20b 19606 21006 22ll07 23807 25208 26608 ?8008 29409 30809 32210 .B61 0 565,0 AMU 41l23 5194 5565 5936 6307 6678 70ll9 7420 7420 7420 7420 7420 566,0 FMU )01.15 3279 351ll 3748 3982 4216 4451 /~685 4685 4685 4685 4685 ..,., 567,0 --------·------------------------~---------------------------------------·-----·-----------------------·--·-I N 568,0 TOTAL 3062':l 32981 35337 37692 400!J8 42404 44760 47116 48866 50617 52367 54118 w 569,0 570,0 INTt.Rt.ST LJN S!~KlNG FU"'DS 571.0 APA 0 0 0 0 0 0 0 0 0 0 0 0 572,0 AMU 24 1 I 21'\82 34 0 7 3990 4635 5346 6128 69811 6984 6984 6984 b984 573,0 FMU I 6 73 2003 2373 2785 3242 3748 4305 4918 4918 4918 4918 11918 574,0 --~------·------·----·----------~----·-·-~·~---·------------------·-----------------------------------------575.0 TOTAL 1.1081.1 41\85 5779 6774 71:177 90'14 10433 11902 11902 11902 11902 11902 576.0 578.0 GRAND TOTAL 34709 378o5 4 1 1 I o LJ4467 1.17925 51498 55193 59018 b0768 62519 64269 66020 '=· ~ ,.I I -~ ] I J '"'" J J c •.• c.! .I -J J .J J ,J . --.. J --~--. 15 AUGUST 7'? LINE NO 551.0 552.0 553.0 554.0 555.0 55&.0 557.0 558.0 559.0 560.0 5&0.5 5&1.0 5&2.0 5&3. 0 564o0 5&5.0 5&&.0 5&7.0 5&8.0 569.0 570.0 571.0 572.0 5.73. 0 574.0 575.0 57&.0 578.0 CUM.PRINIS.FU~D* CUM. INTEREST 30o25 65'::182 32981 69702 1'198 353_37 nosq 37&Q;:> 77544 2000 40041:1 81268 ?001 2002 447&0 88317 2003 47116 91644 2004 (lf\866 93230 2005 50&17 94684 200& 52367 96005 2007 54118 97195 ----------------------·---------------------------------------~----------------------~----------------------CUM. DEAl SERVIC <1&207 102&83 10902& 11':1237 121316 * NOTE: THE SINKING FUND REPAYMENTS TAKE INTO ACCOUNT THf FACT THAT INTEREST IS ACCRUING ON THE FUND. THE TOTAL OF THIS LINE, THEREFORE, ~ILL NOT MATCH THE TOTAL PROJECT COST CUMULATIVE APA REA CFC FFB AHU FHU TOTAL PRINCIPAL AND Sl~Kl~G FUND 0 0 9103 9803 0 0 13o"i4 14704 4823 ':11 <14 3045 3279 30625 32981 INTEREST ON SINKING FU~DS APA 0 AMU 2411 FMU 1673 0 2882 2003 PAYMENTS 0 10503 0 15755 55&5 3'>14 35337 0 3407 2373 0 11203 0 1&805 5936 3748 37692 0 11904 0 17855 &307 39R2 40041:1 0 4635 3242 1C7263 0 12&04 0 18906 6678 4216 42404 0 5346 3748 133077 0 13304 0 1995& 7049 4451 447&0 0 &128 4305 138760 0 14004 0 21006 7420 4&85 4 7 t 16 0 &q84 4918 14209& 0 14704 0 22057 7(120 4&85 488&& 0 6984 4918 145300 0 15405 0 23107 7420 4&85 50617 0 6984 4918 148373 0 1&105 0 24157 7420 4685 52367 0 6984 4918 1513ll 0 16805 0 25208 7420 4&85 54118 0 6984 4918 ---------------·------------------------------------------------------------------------------·------·------TOTAL 4885 '5779 6774 7877 GRAND TOTAL 34709 37865 IH 116 44467 q7925 '51496 10433 \1902 11902 5'5193 59018 &0768 11902 &2519 11902 &4269 11902 66020 .. .. "'T1 I N U'l J 1'::1 o\UGUST 7q lii-lE NO 551.0 552.0 553.0 5">£1.0 555.0 556 •. 0 557.0 558.0 559.0 560.0 560.5 561.0 562.0 563.0 564.0 565.0 566.0 567.0 568.0 569.0 570.0 571.0 572.0 573.0 574.0 575.0 576.0 578.0 -.J CU~.PNINIS.FUND* CUM. INTEREST CUM. rlBT SERVIC 2008 55868 105692 2009 57t>l 9 106721 1643110 2010 59369 10760£1 I o6973 2011 61120 108339 169459 * NOll: TH~ SINKING FUND RtPAYMENTS TAKE INTO ACCOUNT THE FACT THAT INTEREST IS ACCRUING ON THE FUNU. TH[ TOTAL OF THIS LINE, THEREFORE, ~ILL NOT MATCH THE TOTAL PROJECT COST CUMULATIVE. PRINCIP~L AND SINKING FUND PAYMENTS 0 9£153 APA REA CFC FFt:l AMU FMU 0 0 8753 9103 0 0 .35011 36411 7421) 7420 1161\5 11685 0 37811 7420 11685 0 9803 0 39212 7420 4685 20!2 0 1015.5 0 <10612 7£120 46115 2013 6<1621 !09368 1 73989 0 10503 0 42013 7420 4685 bb371 109662 176034 0 10853 0 Ll34!3 7420 4685 2015 68122 109809 177931 0 11203 0 4481£1 7420 4685 ------------------------------------------------------------------------TOTAL 55868 INTEREST ON SINKING FUNDS APA 0 AMU 698£1 FMU £1918 57619 0 69!:1£1 £1918 59369 0 6984 4918 61120 0 6984 119111 62870 0 698£1 Ll918 64621 0 6984 49111 66371 0 69811 4918 68122 0 6984 4918 -----------------------------------------------------------·-------·----TOTAL 11902 11902 11902 I 1902 11902 t 1902 11902 11902 GRAND TOT~L 67771 69521 71272 73022 74773 76523 7827£1 8002£1 J J -I ·-I , ___ ,J 1 .. .I J 20•110 REA•FFB j I ,I .I .J , I - N C'l --] ] ] l 15 AUGUS I 79 LINE NO CU~.PRIN/S,FUND• CUM, INIEREST ·--] 2001\ SS86t:l 91\252 2009 57619 99177 1 -j 2010 ---l 2011 61120 100631 -~ 2012 62870 101160 -~-1 r.--- 2013 6ll621 101556 1 ~] ?Dill 66371 101821 -1 2015 68122 101953 551.0 5~2.0 '553.0 S~li.O 555,0 5~6.0 557.0 558.0 559,0 560,0 560,5 5b1. 0 562.0 563,0 56li,O 565,0 566,0 567,0 5MI.O 569,0 570,0 '571.0 572.0 5H.o 57li,O 575,0 576,0 578,0 ------------------------------------------------------------------------CUM, DERT SERVIC ISLI120 1'>6796 159340 1617':11 16ll030 • NUTE: TH~ SI~KING FUND REPAYMENTS TAKE INTO ACCOUNT THE FACT THAT INTEREST IS ACCRUING ON THE FUND, THE TOTAL OF THIS LINE, THfNffONE, ~ILL NOT MATCH THE TOTAL PROJECT COST CUMULATIVE APA NEA ere FFB A"''U FMU TOTAL PRINCIPAL AND SINKING FUND 0 0 17505 18206 0 0 262S8 <'7308 7ll20 7ll20 ll685 ll685 '>5868 57619 INTEREST ON SINKTNG FUNDS APA tJ AMU 698ll FMU 4918 TOTAL 11902 GRANO TOtAL b7 771 0 691l4 4918 11902 69521 PAYMENTS 0 18906 0 283'59 7420 ll685 0 6984 4918 11902 71272 0 19606 0 29409 7420 4685 61120 0 698Q 4911\ 11902 7 302<' 0 20306 0 30ll59 74?.0 li68S 6?.870 11902 74773 I 66177 0 <'1006 0 31510 7420 4685 64621 0 6984 4918 11902 76523 168192 0 21707 0 32560 7llf>O ll685 66371 0 6984 ll9!8 11902 7827ll 170075 0 22407 0 33610 7420 ll685 68122 0 6964 4918 11902 8002ll l 1 -] ---] -~ I ANCHORAGE-FAIRBANKS INTERCONNECTION FINANCIAL COMPARISON OF ALTERNATIVE REA/FFB LOAN PACKAGES (COMPARE) F-27 PRESENT VALUE COMPARISON OF REA/FFB COMBINATION LOAN PACKAGES Discounted @ 14 Percent ?0 All~,tJS T 74 ALT.l-20% REA@ 5%/80% FFB@ 9 1/4% 35 YEAR AMORTIZATION INTEREST ONLY L l '•~ Nll 1100,0 1102.0 !104,0 81?.0 815,0 1\C'O,O 112?,0 L I I; I; "JI) 1\UO,O llll?.o IIOU,o AI?,O A!'),O ~20,1) Ac?,O Ll IC;f "JO 'I() 0. f) llo?.n II 0 11, tl Rl?. n '11'>.0 R?,n,n 112?.0 J r----• 32 YEAR REPAYMENT PERIOD YEAR [I 5 b 7 q 10 11 AOJiJSl~f\ "F t\ I SfRV!CF. FOR; LOAN I (REA) I) 1 7 Q2 5'>b ~Ill e•n 875 115a 8110 R23 805 788 L04N 2 ( FFB) 0 101'1 595 <'L'B~ 49Qb llA811 11772 111>59 ll5117 41.134 432l IIllO ------------------------------------------·---------·-------------------·--·----------------·--·------------TOTAL jl l?'i oRb 21>39 <;QO/ 5 777 5oll7 5517 538 7 '5257 'H27 4997 f!lSCl•1 11\Ttn v A I II~ " I u<> '>21l I 7A I 311'17 :r.ooo ?5H nos 1!188 lbl7 1383 1182 PR[St•!T 'v ~I II f_ ,?1-dh~ n (l 0 I) 0 0 0 0 0 0 0 12 1' 111 1 'i I b 1 7 18 19 i?O 21 22 23 Afl.JUSlfi;. Df •I I St"VT(f FU~: LOAN I (REA) 77ll 7':J3 735 718 700 biB bb5 bliB &30 bl3 595 '578 L£11\"1 ? ( FFB) ~~oq r 39/l'i 3f\B HbO ~bll6 353"1 31123 H11 ~198 308b 29711 26bl ---·---------------------------------------~---------·--·--------------------------~·---------···-----------TOTAl 111'161'1 <!7\R Ubi] I\ ljlj 7 p, ll3118 U?IB U088 3q';iR 362q 3b99 35b9 .3113 q I J l ;j [ ,J: I • T F !1 V ~ l ,•F 1 0 I I) Ao3 no h~l 5><1 lJ')C, 3R 7 3?8 279 23b 200 lb9 PRFS~•·T > AL"r ,, 0 0 0 0 0 () 0 0 0 0 0 ;>t.J <:'5 ?,6 n ;>!l 2Q '0 31 32 H 34 35 AilJIJS IFL> I' F 'l T S~t.>vTCF FUR: L!IA'" 1 (REA) """ <, ,J ~ ':Ji''i "Jl)R ljQI) ljn 1.15'1 4:SR 4i?O ll03 3115 368 l n "-\I ? (FFB) ? 7'1'-' 2637 ?.':J?iJ 21.11? ?2Q9 ?1b7 2075 1962 lll"iO 1738 1625 1513 --------------------------------------------·------------------------·--------------------------------------]II TAL ,309 ~ 1 7 Q 51)U9 2Q(Q 2790 2bb0 ?':J>O 2400 2270 21110 2010 1680 I) r s r u 1 , -, r t. , ' V ~ [ ~If I fi l 12() I 0 I ll') 71 bfl ">U ll I 34 21\ ?3 19 PPt<iE'\1 .• ~ L I I~ 0 n ll n u 0 0 0 0 0 0 0 .I -.I I ] ' t;.;._ -_, J .J ,,_] ~---1 ] PRESENT VALUE COMPARISON OF REA/FFB COMBINATION LOAN PACKAGES Discounted@ 14 Percent ALT.2-40% REA@ 5%/60% FFB@ 9 1/4% 35 YEAR AMORTIZATION ?0 AUGUST 74 INTEREST ONLY 32 YEAR REPAYMENT PERIOD LT'IIf YEAR \) 2 ~ 4 5 b 7 8 q I 0 I t NO aoo.o Al)JUSTFO ll F rl T SF~VlCE FOR: AO?.o LOAN 1 (REA)· t) ~4 1R'J 7 I I 18?0 1785 I 750 I 11 5 1680 lb4'5 toto 1'57'5 R04.o LOAN 2 (FFB) u HI ~~ lj'J 1 7 1 3 3747 .Sbb' 3'57q 3494 HIO 332& 32112 11'57 Al?.o -----------~------------·-----------------------------------------·-----------------------------------------A15.n TOlAl 0 115 o3tl 242/J "151>11 544R s.s2q '>210 ">091 4Q71 48'52 4731 Ri!.O.O GISCUI'tlll n v Ill IIF ;, l\10 4115 1b.St:> 3297 ;>~~0 24?8 2082 1711':> 1">2Q 110Q I 120 112?.0 PPI:St.• f V ~ [ I! t ,>tj I"' Q 1 () 0 0 lJ 0 0 0 0 0 0 0 , I N 1.0 lT"--E 12 1 ~ 14 15 lb I 7 18 I q 20 21 22 21 1110 800.0 AUJUSTFU I>E rl T SE~VTCf FuR: R02.0 lOAN 1 (REA) 1 ')I~ 0 15U5 1470 I 435 1400 n~>5 lHO 129'5 12&0 122'5 I I qo I I so; 804.0 LOAI\J ? {FFB) 3l• 7 3 2Qt\Q ?404 2820 273b 2b5? 25&7 2483 l_J3QQ 231'5 2210 2111& 812.0 ---·--------------·-----------------------------------------------------------------~-----·--------------~·--81'5.0 T 0 T 4L ~b 1 3 . <UI'IIJ 4 .S7'J .42':>6 4131> 4017 J8Q8 3778 3b5Q l'5UO JUll .no 1 A2o.o DISCOtt~<TEn V,\1 Uf '1')1\ 1:1111 bQ4 54b 50H liB .\b'l 313 2bb 22& 192 162 fie??. 0 PRESf~T V h L I I[' (l 0 0 0 0 0 0 0 0 0 0 0 Ll"'f ?u 2'5 2b 27 ?8 29 30 ]I 12 B 1U .\'5 NO 800.0 AOJUS Tf 0 Df 1-'T SFPVTCI" FUR: AO?.O L(lAN I (REA) 11 ?1,) 1085 1050 1015 QSO Q4'5 QIO 87'5 840 80'5 770 73'5 eou.o LOAN ? (FFB) ?Ot>2 1Q77 t89.\ 1809 1725 lb40 t5'5b 1472 138 7 1303 12 I 9· I I 3'5 812.0 ---~----------------~--------------------------~---------------------------------------------·--------------Al">.o TOTAL .\IRl 30b3 2943 2824 2705 2':>8b 211&1> 2347 2228 2108 1qeq 1870 fl20.o OISCI!ttr-.;Tf_f' V t.l UF IH I I 6 98 H? b9 SR 48 40 34 2A 23 lq '1122.0 PRESt NT v AlliE u 0 0 0 0 0 0 0 0 0 0 0