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Home My WebLink AboutAPA146dALASKA POWER AUTHORITY Anchorage -Fairbanks Transmission lntertie Economic Feasibility Study Report I April1979 DRAFT ~ INTERNATIONAL ENGINEERING COMPANY, INC. • % ~ ROOERT W. RETHERFORO ASSOCIATES Tyo'L.. " ~ Tvon.e J.akl'! ~ SuSttn .. u .. I .. Lak-eLou.ist!- KEY MAP SCALE I: 3,000,000 CONTENTS Chapter Page ABBREVIATIONS ix 1 INTRODUCTION 1-1 2 SUMMARY AND CONCLUSIONS 2.1 Study Summary 2-1 2.2 Conclusions 2-4 3 LOAD FORECASTS FOR RAILBELT AREA 3.1 Energy and Demand Forecasts Range 3-1 3.2 Demand Forecasts for Generation Planning 3-8 3-3 References 3-10 4 SELECTION OF INTERTIE ROUTE 4.1 Review of Earlier Studies 4-1 4.2 Survey of Alternative Corridors 4-1 4.3 Preferred Route for Transmission Intertie 4-1 4.4 Field Investigations 4-4 4.5 Preliminary Environmental Assessment 4-5 4.6 References 4-11 5 TRANSMISSION LINE DESIGN 5.1 Basic Design Requirements 5-1 5.2 Selection of Tower Type Used in the Study 5-1 5.3 Design Loading Assumptions 5-2 5.4 Tower Weight Estimation 5-2 i CONTENTS Chapter Page 5 TRANSMISSION LINE DESIGN (Continued) 5.5 Conductor Selection 5-3 5.6 Power Transfer Capabilities 5-4 5.7 HVDC Transmission System 5-4 5.8 References 5-5 6 SYSTEM EXPANSION PLANS 6.1 Generation Planning Criteria 6-1 6.2 Multi-Area Reliability Study 6-4 6.3 System Expansion Plans 6-10 6.4 References 6-12 7 FACILITY COST ESTIMATES 7.1 Transmission Line Costs 7-1 7.2 Substation Costs 7-4 7.3 Control and Communications System Costs 7-5 7.4 Transmission Intertie Facility Costs 7-5 7.5 Cost of Transmission Losses 7-5 7.6 Basic for Generating Plant Facility Costs 7-6 7.7 Generating Plant Fuel Costs 7-7 7.8 MEA Underlying System Costs 7-8 i 1 7.9 Construction Power Costs for the Upper Susitna Project 7-8 -..J 7.10 References 7-9 8 ECONOMIC FEASIBILITY ANALYSIS 8.1 Methodology 8-1 8.2 Sens it i vityAna lys is 8-2 8.3 Economic Analysis 8-3 8.4 References 8-8 r ii) Chapter 9 10 CONTENTS FINANCIAL PLANNING CONCEPTS 9.1 Sources of Funds 9-1 9.2 Proportional Allocations Between Sources 9-4 9.3 Allocated Financial Responsibility for Participants 9-6 INSTITUTIONAL CONSIDERATIONS 10.1 Present Institutions and Railbelt Utilities 10.2 Alaskan Interconnected Utilities 10.3 References 10-1 10-3 10-5 APPENDIXES Appendix A NOTES ON FUTURE USE OF ENERGY IN ALASKA A-I B TRANSMISSION LINE COSTS ANALYSIS PROGRAM (TLCAP) :J B.1 General Description B-1 B.2 .Computer Program Applications for Optimum Transmission Line Costs B-2 B.3 TLCAP Sample Outputs C MULTI-AREA RELIABILITY PROGRAM (MAREL)C-1 iii I ) I j CONTENTS Appendix Page 0 DATA AND COST ESTIMATES FOR TRANSMISSION INTERTIE AND GENERATING PLANTS 0-1 0.1 Data and Cost Estimates for Trans- mission Intert te 0-1 0.2 Data and Cost Estimates for Gene- rating Plants 0-13 0.3 Data and Cost Estimqtes for Supply of Construction Power to Upper Susitna Proj ecfSites .0-24 0.4 Alternative Generating Plant Fuel Costs 0-38 E TRANSMISSION LINE ECONOMIC ANALYSIS PROGRAM E-1 F TRANSMISSION LINE FINANCIAL ANALYSIS F-1 iv Table ED ~ @ 3-4 3-5 3-6 5-1 ~ 6-2 6-3 6-4 6-5 6-6 6-7 7-1 7-2 TABLES Anchorage-Cook Inlet Area Utility Forecasts Fairbanks-Tanana Valley Area Utility Forecasts Combined Utility Forecasts for Railbelt Area Load Forecasts for Upper Susf t na Proj- ect by Alaska Power Administration Load Forecasts for Railbelt Area to Determine Statistical Average Forecasts Load Demand Bandwidth for Railbelt Area Forecasts Conductor Size Selection Criteria Existing Generation Sources,Anchorage- Cook Inlet Area Existing Generation Sources, Fairbanks- Tanana Valley Area Load Model Data,Anchorage Area Load Model Data, Fairbanks Area Loss of Load Probability Index for Study Cases IA and 10 Loss of Load Probability Index for Study Case IB Loss of Load Probability Index for Study Case IIA Cost Summary for Intertie Facilities Present Worth of Intertie Losses, 1984-1997 Study Period 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 7-10 7-11 TABLES (Continued) Table Page 7-3 Cost Summary for Generating Facilities 7-12 7-4 Summary of Altenative Generating Plant Fuel Costs 7-13 7-5 Alternative Costs for Construction Power Supply to Watana and Devil Canyon Hydropower Sites during Con- struction of Upper Susitna Project 7-14 8-1 to 8-6 Differential Discounted Value of Base Year (1979)Costs 8-9 to 8-14 9-1 Allocation of Total Project Costs Between Participants to Alaskan Intertie Agreement 9-10 A-1 MEA Statistical Summary -Past, Present and Future A-4 FIGURES Figure 3-1 Comparative Net Energy Generation Fore- cast for Combined Utilities and Indus- trial Load -Railbelt Area 3-18 3-2 Projected Range of Net Energy Genera- tion Forecast for Combined Utilities and Industrial Load,Railbelt Area 3-19 3-3 Projected Range of Net Energy Gener- ( I ation Forecasts for Combined Util- 1_\ities and Industrial Load,Anchorage- Cook Inlet Area and Fairbanks-Tanana Valley Area 3-20 3-4 Comparative Annual Peak Demand Fore- casts for Combined Utilities and Industri al Load,Railbelt Area 3-21 vi FIGURES (Continued) Figure Page 3-5 Projected Range of Annual Peak Demand Forecasts for Combined Utilities and Industri al Load,Railbelt Area 3-22 3-6 Annual Peak Demand Forecasts for Com- bined Utilities and'Industrial Load, Anchorage-Cook Inlet Area and Fairbanks- Tanana Valley Area 3-23 3-7 Probability Model Representation of Load Forecast Uncertainty 3-24 3-8 Normal Distribution Probability Plot to Establish Bandwidth for Railbelt Area Forecasts 3-25 3-9 Load Demand Forecasts,Bandwidth:Most Probable +2 Standard Deviations,Anchor- age-Cook Tnl et and Fairbanks-Tanana, Valley Area Loads 3-26 3-10 Load Demand Forecast Bandwidth:Most Probable +2 Standard Deviations,Ra il- belt Area-Loads 3-27 4-1 Nenana-Fairbanks-Tanan~Transmission System 4-12 4-2 Anchorage-Matanuska-Susitna-Glenallen- Valdez Transmssion System 4-13 4-3 Cook Inlet-Kenai Peninsula Transmission System 4-14 5-1 230 kV Tangent Tower 5-7 5-2 345 kV Tangent Tower 5-8 6-1 Non-Coincident 1975 Peak Demands, Anchorage and Fairbanks Areas 6-21 6";;2 Independent System Expansion Plans, Anchorage and Fairbanks Areas 6-22 vi i Figure 6-4 6-5 7-1 B-1 0-1 and 0-2 0-3 0·-4 FIGURES (Continued) Interconnected System Expansion Plan, Anchorage-Fairbanks Area without Susitna Project Interconnected System Expansion Plan, Anchorage-Fairbanks Area with Firm Power Transfer Interconnected System Expansion Plan, Anchorage-Fairbanks Area with Upper Susitna Project Case I -Alternative A and B Case I -Alternative C Case I -Alternative 0 Case II Construction Plan for Upper Susitna Project 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 viii Page 6-23 6-24 7-15 B-4 0-45 and 0-46 0-47 0-48 ]ABREVIATIONS A.R.R.Alaska Railroad AML&P Anchorage Municipal Light and Power Company LNG liquid nitrate gas LOLP loss of load probability MAREL Multi-Area Reliability.a computer program developed by PTI MBTU Million British thermal unit ac ACF ACSR AlA APA AVF bpd BTU CEA CFC\ dc DOE EEl FFB FGD alternating current annual cost of fuel aluminium conductor,steel reinforced Alaskan Intertie Agreement Alaska Power Authority average value factor barrels per day British thermal units Chugach Electric Association,Inc. Cooperative Finance Corporation direct current U.S.Department of Energy Edison Electric Institute Federal Finance Bank flue gas desulphurization MEA MVA MW NESC NOx O&M ORV PCF P.I. PRS PTI REA RI 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 requ-irements studies Power Technology,Inc. Rural Electrification Administration radio interference FOH forced outage hours FMUS Fairbanks Municipal Utility System ft feet gal gallon GVEA Golden Valley Electric Association,Inc. GWh gigawatt-hours (million kilowatt-hours) HEA Homer Electric Association,Inc. HVDC high voltage,direct current IAEAT Interior Alaska Energy Analysis Team IECO Internatipnal Engineering Company,Inc. IEEE Institute of Electrical and Electronics Engineers ISER Institute for Social and Economic Research kcmil thousand circular mils kV kilovolts kVa kilovolt-amperes RWRA Robert W.Retherford Associates,Inc. SIC single circuit SCGT simple cycle combustion turbine SIL 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 IECO TLFAP Transmission Line Financial Analysis Program,a computer program developed by IECO tpy tons per year TVI television interference USA United States of America USGS United States Geological Survey VAR volt-amperes reactive kW kWh kilowatts kilowatt-hours ix CHAPTER 1 INTRODUCTION I I,I 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 spi nning reserve requi re- 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 thi's 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 e Independent Fairbanks area @ Interconnected Anchorage-Fairbanks area (generation reserve sharing option) •Interconnected Anchorage-Fairbanks area (generation reserve sharing and firm power transfer option) Interconnected Anchorage-Fairbanks area (with inclusion of the Upper Susitna Hydropower Project) 1 - 1 r 'I '~i,I .t!!J ~ 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, and 14 February 1979) to review factors related to the inter- tie 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) e Copper Valley Electric Association (CVEA) •Chugach Electric Association (CEA) •Fairbanks Municipal Utility System (FMUS) •Golden Valley Electric Association (GVEA) •Homer Electric Association (HEA) J e Matanuska Electric Association (MEA) U _.1 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 utility service 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 limit 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 IImost probable ll forecast. The long-range IImost probable ll load demand projections in MW for the load areas are: U Anchorage Fairbanks Combined System 1980 573 153 749 1985 977 231 1194 J 1990 1581 338 1869 1995 2402 477 2842 2000 3446 663 4054 2 - 1 B.Selection of Intertie Route Alternative transmission corridors considered in previous studies were analyzed as to accessibility,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 ~as 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. 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 1 ines as bei ng well sui ted for Alaska condi- tions. 11 IJ C.Transmission Line Design ) I J D.System Expansion Plans To determine the intertie's economic feasibility,alternative system ex- pansion plans were prepared with and without the Anchorage-Fairbanks inter- tie.All system expansion plans were prepared to meet the IImost pro- bable ll load demand projections. 2 - 2 [] o To assume a nearly constant level of generation reliability (LOLP Index) for all system expansion plans,a multi-area reliability (MAREL)compu- ter study was performed.Annual load models for both areas were de- veloped.The load models indicate that there is very 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 intertie 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 the 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 results indicate a clear of construction power. for the Susitna Project were calculated.The advantage for utilizing the intertie as a source 2 - 3 ,) !IU u j F.Economic Feasibility Analysis The economic feasibility analysis of the intertie was performed using the discounted present-worth method.Facility costs for those new gener- ating plants not affected by the introduction of the intertie were ex- cluded from the analysis.The Transmission Line Economic Analysis Program (TLEAP),a computer program,was used to analyze the sensitivity of dif- ferent escalation and discount rates on the capital costs of various al- ternatives.In this analysis,a 7%long-term average annual escalation rate and a 10%discount rate was used for principal investigations. 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 loading capability (Case IA)is economically feasible in 1984, based only on benefits due to reduction of generation reserve plant capacity. T~e present-worth of net benefits is $7,968,000. •A considerable increase in benefits is obtained if the 230-kV single circuit intertie (double circuit after 1992),in addition to line capacity allocated to reserve sharing,includes firm 2 - 4 power transfer capability (Case IB).The increase in present- worth net benefits is from $7,968,000 to $14,589,000,or an increase of 83 percent.Additional benefits due to supply of construction power to the Upper Susitna Project sites is $2,943,000,or an added increase of 18 percent. •The 345-kV single circuit intertie (Case lC)is not economically feasible in 1984 if based only on the benefits due to reduction of i nsta 11 ed generation reserve capaci ty.Further studi es , not made,will probably indicate that a 345-kV intertie would be feasible if firm power transfer benefits are included. e The 230-kV intertie with intermediate substations at Palmer and Healy (Case ID) has the following net benefits: Study Case lA (Reserve sharing only) ID (Plus supply to MEA) ID (Plus constr.power supply) PW of Net Benefits $7,968,000 $10,065,000 $13,113,000 •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. 2 - 5 •Expansion plans for the interconnected system with the Upper Susitna Project were developed to determine the effect of this project ~n the interconnected system expansion plans,the dis- placement of thermal generating units,and intertie transmission requirements with Susitna Project. •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. •Generation and interconnection planning is a complex and con- tinuous process.This Intertie Feasibility Study is only a part of the overall power system expansion plans for the Railbelt area.Further intertie 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 n CHAPTER 3 LOAD FORECASTS FOR RAILBELT AREA 3.1 ENERGY AND DEMAND FORECAST RANGE 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 forecasts!1 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: 1974 1980 1990 2000 Annual Consumption-GWh Upper Range Limit 1,600 3,400 10,800 22,500 Interval Growth Rate 13.4%15.3%10.2% Lower Range Limit 1,600 2,600 8,500 16,000 Interval Growth Rate 8.4%9.6%4.0% .II See Section 3.3 for references used in this chapter. 3 - 1 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,Battelle selected 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: •Petroleum Production will be 2 million bpd in 1980, and 3.6 million in 1990. •A natural gas pipeline will be cons tructed from PrudhoeBay through Canada. •An LNG plant for natural gas from the Gulf of Alaska will be constructed. The assumptions regarding electrical energy consumption are: Sector Case 2 Case 4 I j I ,I,I ..Residential ..Commercial/Industrial Moderate Electrification No Growth Growth as Usual Minimum Electrification 3 - 2 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 Ti mber Mi 11 s New Facilities Aluminum Smelter LNG Plant Refinery Timber 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 Fairbank? 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). \ables 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 I. IJ. 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 utility 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 projections is given in Table 3-4.These projections include only utility and industrial load forecasts,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. 3 - 5 ( .1 (. . 1 The range of load forecasts was based on a ~20%spread from projected mid-range growth to 1980.The industrial load projected by Battelle was included in the forecast range on a selective basis.The differential between the IIhigh ll and lI ext ra high ll forecasts is an additional 280 MW of load,representing an aluminum smelter.The IIl oW"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- tion,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 maximum growth 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 forecast 3 - 6 -I ) r ! for the Susitna Project,and represents a prudent choice for a conserva- tive 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 ac- ceptable as a single demand projection,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,thi s bei ng accentuated by the i nterconnecti on of ut i1 i ty systems in the area. 3 - 7 .!. 3.2 DEMAND FORECASTS FOR GENERATION PLANNING Once the range of load forecasts has been established,it remains to select definitive demand forecasts for generation expansion planning. Between the upper limit of the combined utilities forecast and the lower limit,represented by the median forecast by the Alaska Power Administra- tion,lies a range of possible load growth projections,each having a certain probability of realization through time. A.Probabilistic Representation of Load Forecast Uncertainty On the assumption that the load forecast range obeys a normal probability distribution,the uncertainty associated with the forecast can be repre- sented by the normal continuous probability curve of Figure 3~7A.The most probable forecast for this symmetrical representation is then the statistical average between the maximum and minimum limits,these being assumed to occur at the +3 standard deviation extremities of the normal bell curve.The statistical average forecasts for the Railbelt area are given in Table 3-5,these being now designated the most probable forecasts for the selected range.The statistical average or mean value is the same as the most probable value,due to the basic assumption regarding the symmetrical shape of the normal probability distribution curve. The variability of the forecast is defined in terms of standard ~eviations from a most probable value,with the bandwidth of the forecast taken to be within ~2 standard deviations from the most probable value.The degree of uncertainty associated with the forecast range determines this bandwidth,which may be expressed as a 95%chance that the actual peak demand will lie between the limits of the selected bandwidth. As the uncertainty associated with a load forecast increases with time, the demand value defined by the bandwidth will increase with time;how- ever,the probability of being within the bandwidth will remain constant. The demand values corresponding to this bandwidth are given in Table 3-6, these being obtained from the range of forecasts,as follows: 3 - 8 The demand forecast limits define the range of possible values,such that the actual future peak demand will have a 99.8%probability of being within the upper and lower forecast limits,these being the!3 standard deviation bounds. This can be represented by the probability plot of Figure 3-8,the implicit assumption being that the forecast limits correspond approximately to the 99.9 percentile on the three standard deviation limit.Connection of the extreme percentile limits enables the determination of the bandwidth between the!2 standard deviations limits,as a 2/3 ratio between the high and most probable forecasts at any point in time.The bandwidth is given in terms of demand values,as tabulated in Table 3-6.The probability multipliers given in this table,for the load levels corresponding to the forecast bandwidth,are obtained from the discrete representation of fore- cast uncertainty shown on Figure 3-7B,this being the usual representation of forecast uncertainty for generation planning studies. B.Selection of Demand Forecasts for the Railbelt Area The most probable load demands and forecast bandwidths for the Anchorage - Cook Inlet,Fairbanks - Tanana Valley and the Railbelt areas are shown on Figures 3-9 and 3-10.As the!2 standard load level limits cross over for the Anchorage -Cook Inlet area,the divergent bandwidth is shown on Figure 3-9 as beginning in 1982.The most probable forecast then appears as a single demand line from 1979 through .1981,which considering the short time projection is quite reasonable.The demand 'trend is well established for the Anchorage area and can be expected to persist in the immediate short-range time frame. The long-range load projections are given in Table 3-6,with a t6tal diversified demand for the combined areas of the Railbelt rising to ap- proximately 4000 MW in the year 2000. 3 - 9 -I ) 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-J 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.O.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 r 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 '-----'--- TABLE 3-1 ANCHORAGE -COOK INLET AREA , UTILITY FORECASTS AND EXTRAPOLATED PROJECTIONS Anchorage Municipal Alaska 2 -Matanuska Alaska 5 -Kenai Alaska 8 -Chugach Light and Power Company Electric Association,Ir.c.Homer Electric Assoc., Inc.Kenai City Light System Electric Association,Inc. Net Load Peak Net Load Peak Net Load Peak Net Load Peak Net Load Peak Energy Factor Demand Energy Factor Demand Energy Factor Demand Energy Factor Demand Energy Factor Der.Jand Year (GWh).J!L -'!il:!.L (GWh).J!L (MW)(GWh).J1L (MW)~-l!L -'!il:!.L (GWh).J!L ~ 1979 633.6 58.1 124.4 280.4 47.5 67.4 275.2 55.0 57.1 34.4 56.0 7.0 1,108.9 53.0 238.8 1980 699.4 58.1 137.5 332.8 47.0 80.8 336.6 55.0 69.9 37.5 56.0 7.6 1,283.0 54.0 271.2 1981 770.6 57.9 151.8 395.1 46.5 97.0 411.6 55.0 85.4 40.8 56.0 8.3 1,467.8 54.0 310.3 1982 847.3 57.8 167.3 468.0 56.0 116.1 502.0 55.0 104.2 44.4 56.0 9.1 1,679.1 54.0 355.0 1983 929.6 57.7 183.9 559.3 45.0 )41.9 572.3 55.0 118.8 48.1 56.0 9.8 1,920.9 54.0 406.1 1984 1,017.5 57.6 20L3 668.3 44.5 171.4 652.4 55.0 135.4 52.1 56.0 10.6 2,197.5 54.0 464.5 1985 i .ne.s 57.4 220.8 7~8.6 44.0 207.2 743.7 55.0 154.4 56.4 56.0 11.5 2,509.0 54.0 530.4 1936 1,209.5 57.3 21B.1 954.'+43.5 250.5 847.9 55.0 176.0 61.1 56.0 12.5 2,810.1 54.0 594.1 w 1937 1,313.2 57.1 262.5 1,140.0 43.0 302.6 967.0 55.0 201.0 66.3 56.0 13.5 3,147.3 54.0 665.3 1388 1,421.6 56.9 285.0 1,322.4 44.0 343.1 1,083.0 55.0 224.8 71.5 56.0 14.6 3,525.0 54.0 745.2 198!J 1,534.2 56.8 308.5 1,534.0 45.0 389.1 1,213.0 55.0 251.8 77.0 56.0 15.7 3,948.0 54.0 834.6..........1990 1,650.5 56.6 333.0 1,779.4 46.0 441.6 1,358.6 55.0 282.0 83.1 56.0 16.9 4,421.7 55.0 934.7 1991 1,769.8 56.4 358.2 2,064.1 47.0 501.3 1,521.6 55.0 315.8 89.5 56.0 18.2 4,863.9 55.0 1,028.2 1992 1,891.3 56.2 384.1 2,394.4 48.0 569.4 1,704.2 55.0 353.7 96.5 56.0 19.7 5,350.3 55.0 1,131.0 1993 2,014.4 56.0 410.5 2,705.7 49.0 630.3 1,874.6 55.0 389.1 103.5 56.0 21.1 5,885.3 55.0 1,244.1 1994 2,138.0 55.8 437.2 3,057.4 50.0 698.0 .2,062.1 55.0 428.0 111.1 56.0 22.6 6,473.9 55.0 1,363.6 1995 2,244~9 55.6 460.9 3,454.9 51.0 773.3 .2,268.3 55.0 470.8 119.2 56.0 .24.3 7,121.2 55.0 1,505.4 1996 2,357.1 55.4 485.7 3,904.0 52.0 857.0 2,495.1 55.0 517 .9 127.9 56.0 26.1 7,690.9 55.0 1,625.8 1997 2,475.0 55.2 511.8 4,411.5 53.0 950.2 2,744.6 55.0 559.7 137.3 56.0 28.0 8,306.2 55.0 1,755.9 1996 2,598.8 55.0 539.4 4,852.7 5~.0 1,025.9 2,964.2 55.0 615.2 146.9 56.0 29.9 8,970.7 55.0 1,900.6 1999 2,728.7 54.8 568.4 5,337.9 55.0 1,107.9 3,201.3 55.0 664.4 157.2 56.0 32.0 9,688.3 55.0 2,048.1 2000 2,e65.0 54.6 599.0 5,871.7 56.0 1,196.9 3,457.4 55.0 717.6 168~2 56.0 34.3 10,463.4 55.0 2,211.9 Gr-owth Rates: Reported Logistic Cur'/e 3 18.7%(1977-1982) 19 ;5%{1933;'1937). 22.3%(1977-1982) 14.01 (1983-1987) .8~8S (1977-1982) 8.3%(1983-1987) 15.7%(l977-193G) 1~.4~(198~~19a5) ------------------------------------------~---~~~-----------------------------~-----------~--~~-------------~~-----------------------------------~----------Projected 5.0~(199S-2000)16.0~(1983-1992) '13.0%(1993-1997) 10;0%(1998-2000) 12.0%(1~0B-1992) 10.0%.(1993-1997) B.OS n998-2000} 7.8%'(1988-1992) 7.3'1.(1993-1997) 7.0%U998-Z000) TABLE 3-2 FAIRBANKS -TANANA VALLEY AREA UTILITY FORECASTS AND EXTRAPOLATED PROJECTIONS Growth Rates: ~eported 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) TABLE 3-3 COMBINED UTILITY fORECASTS FOR RAILBELT AREA Anchorage Cook -Inlet Fairbanks -Tanana Valley Combined Load Area~ Net Load Peak 1 Net Load Peak 2 Net Load Peak 3EnergyFactorDemand=-I Energy Factor DemancF-I Energy Factor DemancFI Year (GWh)(%)(MW)(GWh)eo (MW)(GWh)--ill (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 1,468w19876,633.8 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 1,671.6 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 11 0 •98forCoincidenceFactor:II 0.96 ..21 0.99 (I )TABLE 3-4 Sheet 1 of 2 LOAD FORECAST FOR UPPER SUSITNA PROJECT BY 1\ ALASKA POWER ADMINISTRATION 1977 1980 1985 1990 1995 2000 1-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 7,240 Median 424 570 810 1,500 2,045 3,370 Low 525 650 1,040 1,320 .1,520 Industri al Loads Extra high 32 344 399 541 683 High 32 64 119 261 403 Median 25 32 64 119 199 278 Low 27 59 70 87 104 Total Extra high 652 1,344 1,914 2,691 3,863 High 652 1,064 1,634 2,411 3,583 Median 449 602 874 1,234 1,699 2,323 Low 552 709 890 1,127 1,424 Annual Energy (GWh) Ut il ity Loads High 2,720 4,390 6,630 9,430 13,920 Median 1,790 2,500 3,530 4,880 6,570 8,960 Low 2,300 2,840 3,590 4,560 5,770 Industrial Loads Extra high 170 1,810 2,100 2,840 3,590 High 170 340 ·625 1,370 2,120 Median 70 170 340 630 1,050 1,460 Low 141 312 370 .·460 550 Total Extra hi gh 2,890 6,200 8,730 12,270 17,510 I High 2-,890 4,730 7,255 10,800 16,040 J Median 1,860 2,670 3,870 5 510 ....7,620 .10,420Low2,441 3,152 3 :960"5,020 6,320 3.- 14 (-j ) TABLE 3-4 Sheet 2 of 2 LOAD FORECAST FOR UPPER SUSITNA PROJECT BY ALASKA POWER ADMINISTRATION 1977 1980 1985 1990 1995 2000 2.FAIR.BANKS-TANANA VALLEY AREA POWER DEMAND AND ENERGY IREQUIREMENTS (Excluding National Oefense) Peak Demand (MW) Utility Loads High 15~244 ,358 495 685 Median 119 150 211 281 358 452 Low 142 180 219 258 297 Annual Energy (GWh) Utility Loads High 690 1,070 1,570 2,170 3,000 Median 483 655 925 1,230 1,570 1,980 Low 620 790 960 1,130 1,300 3 - 15 TABLE 3 - 5 LOAD DEMAND FORECASTS FOR RAILBELT AREA TO DETERMINE STATISTICAL AVERAGfFORECAST .J Anchorage ~Cook Inlet Fairbanks -Tanana Valley Combined Load Areas Combined Alaska Power Statistical Combined Alaska Power Statistical Combined Alaska Power Statistical Utilities Administration Average Utilities Administration Average Util ities Administration Average Forecast Median Forecast Forecast Median Forecast Forecast Median Forecast Year (MW)Forecast (MW)(MW)(MW)Forecast (MW)(MW)(rljvl)Forecast (r4W)(MW) 1979 475 546 511 142 -·-1;)9··T4r 605 685 645 1980 544 602 573 156 150 153 686 752 719 1981 627 648 638 171 161 166 782 809 796 1982 722 698 710 188 172 180 892 870 881 1983 826 752 789 207 184 196 1012 936 974 w 1984 944 810 877 227 197 212 1148 1007 1078 1985 1079 874 977 250 211 231 1302 1085 1194.....1986 1223 937 1080 275 223 249 1468 1160 13140"1 1987 1387 1004 1196 302---237 270 1655 ··1-241 1448 1988 1548 1077 1313 330 251 291 1840 1328 1584 1989 1728 1154 1441 360 265 313 2046 1419 1733 1990 1928 .1234 1581 394 281 338 2276 ·1515 1896 1991 2133 1315 1724 429 295 362 2511 1610 2061 1992 2360 1402 1881 469 310 390 2772 1712 2242 1993 2587 1495 2041 507 325 416 3032 1820 2426 1994 2834 1593 2215 550 342 446 3318 1935··2627 1995 3105 1699 2402 596 358 477 3627 2057 2842 1996 3372 1809 2591 646 375 511 3938 2184 3061 1997 3663 1925 2794 700 393 547 4276 2318 3297 1998 3947 2049 2998 753 412 583 4606 2461 3534 1999 4244 2182 3213 811 432 622 4954 2614 3784 2000 4569 ·2323 3446 873 452 663 _5333 .2.155 _4054 '-------- i__~ TABLE 3-6 LOAD DEMAND BANDWIDTH FOR RAILBELT AREA FORECASTS IIMOST PROBABLE II FORECAST +2 STANDARD DEVIATIONS Anchorage -Cook Inlet Fairbanks -Tanana Valley Combined load Areas load level ~lost load level Load level Most Load level Load Level Most load Level -2 Standard Probable +2 Standard -2 Standard Probable +2 Standard -2 Standard Probable +2 Standard Deviations Forecast Deviations Deviations Forecast Deviations Deviations Forecast Deviations Year (MW)~(MW)(MW)(MW)(MW)(MW) ---~(MW)_(MVJ) 1979 535 511 487 140 141 142 671 645 619 1980 592 573 554 151 153 155 741 749 697 19.81-6-4.4-638-632 16-3 1:66 189 eros Jg6 ID 1982 702 710 718 175 180 185 874 881 888 1983 765 789 813 188 196 204 949 974 999 1984 832 877 922 202 212 222 1031 1078 1125 1985 908 977 1046 218 '231 244 1121 1194 1267w19869851080 1175 232 249 266 1212 1314 1416 1987 1068 1195 1324 248 270 292 1310 1448 1586.....1988 1156 1313 1470 264 291 318 1413 1584 1755 -....J 1989 1250 1441 1632 281 -313 345 1523 1733 1943 1990 1350 1581 1812 300 338 376 1642 1896 2150 1991 1451 1724 1997 317 362 407 1760 2061 2362 . 1992 1562 1881 2200 337 390 443 1888 2242 2596 1993 1677 2041 '2405 355 416 477 )2021 2426 2831 1994 1800 2215 2630 377 -446 515 2167 2627 3087 1995 1933 2402 2871 398 477 556 2319 2842 3365 1996 2070 2591 3112 420 511 602 2476 3061 3646 1997 2215 2794 3373 444 547 650 2644 3297 3950 1998 2365 2998 3631 469 583 697 2820 3534 4248 1999 2526 3213 3900 495 622 749 3004 3784 4564 2000 2697 3446 4195 522 .663 804 3203 4054 4905 Probabil ity Multipliers 0.0665 0.383 0.0665 0.0665 0.383 0.0665 0.0665 0.383 0.0665 I __ -----I ---' 1974 1975F¥f-ijJi_...:-:::-_ 30000 --m-g-- 1980 _..--.--. ..-_=:::- 1990 I I 20000 ----&+::r I-+----:- w ...... CO z§2000EJ z IAI Cl I- IAI Z :, ! riTi II L j I' ---..:1 _.---- 400,.~ 300 s-·, ~::~:--~:::..-.- =.==-.--:t::t:+.-- I -~.. 200 , ~ 1 COMBINED UTILITIES FORECAST 2 UPPER BOUND -BATTELLE STUDY FORECAST,MARCH 1978 3 LOWER BOUND -BATTELLE STUDY FORECAST,MARCH 1978 4 MEOIAN FORECAST -ALASKA POWER ADMINISTRATION,SUSITNA PROJECT MARKET STUDY,REVISIONS OF AUGUST 1978 ""T1.....mc: ;:0 fTl , I ;i I ::TI ill ·LI-W·· I!irrt -iT j-},-r COMPARATIVE NET ENERGY GENERATION FORECASTS FOR COMBINED W UTILITIES_AND_lt-iDUS'tRIAt.:LOAD ~ RAILBELT AREA ~ 100 ."..... Ci)c::;c IT! W I N 1C 2000 ~ -:-:-:=1 J 'I.11h 1995 PROJECTED RANGEOF NET ENERGY GENERATION FORECASTS FOR COMBINED UTILITIES AND INDUSTRIAL LOAD RAILBELT AREA I I I I I i I I I II i I l-r I i III :I!.I;1 ':.'~.':~'~':;:"':c .:~':~-:':._SC .~;=~;=;;=3:'===.t:::-'7- , , j COMBINED UTILITIES FORECAST EXTRA HIGH FORECAST}ALASKA POWER A[)'o!INISTRATION HIGH FORECAST SUSI TNA PROJECT HARKET STUDY HEDI AN FORECAST REVI SIONS.OF AUGUST 1978 LOW FORECAST -rl--.-: 1C 2C 3C 4C 5C I~t~~~9__.::-==-- 30000 20000 w ...... <..0 ,.---.-J ...~..__.- 1A-=:::-T··_ ~-:~2A ,--::;;;.-l 3A 2000· ~~:::~B 1995 ~ 1990 II I I i 20000 40000 1975 ~~-~ ;, , , I .,I I I I I I I ::-~~E§~~:=a~?~~~~:5::;~'§·.f-7J:.:§i:§.~j¥~ .:..;.:=;.:=.r-r-::.~,~!=i==;':.:.~:=.:;::;-~~r=E?:;F:·:;·::--+;T~"'::-;:';'~-y==;;:.::::: 2~ 3000 s:;4000 :t CI zo !i 0:: UI Z UI CI I- UI Z Na w -. - 200 " I " , I ",...,...,--rrr; 1111+'.i I I 1 I ,"""i,I,:l:1+1-l1-1!-T1!IJ.::j.:j..t+H+-f f I I UTIII TI ES FORECAST fOR ANCHORAGE -COOK I NLET AREA EXTRA HIGH FORECAST}ALASKA POWER AIJ.IINISTRATION HIGH fORECAST SUSITNA PROJECT MARKET STUDY MEOIAN fORECAST REVISIONS Of AUGUST 1978 LOW fORECAST 1F UTILITIES fORECAST fOR fAIRBANKS -TANANA VALLEY AREA 2F HIGH FORECAST }ALASKA POWER AI).lINISTRATION 3F MEDIAN fORECAST SUSITNA PROJECT MARKET STUDY 4F LOW fORECAST REVISIONS Of AUGUST 1978 100 1A 2A 3A 4A. SA f i 1 t t I II I f I (II I IIII III II!:II!I+++++++++++++H+l-.LltHttm-ttnttTtlitn t-t+ni I !H ill n ill ~' I I 11'1 i 1.-I., .I I I I I; ~: : "!1 i NET ENERGY GENERATION FORECASTS FOR COMBINED' UTILITIES AND INDUSTRIAL LOAD ANCHORAGE-COOl<INLET AREA AND FAIRBANKS-TANANA VALLEY AREA ""T....crc ;::I,., U I U 1 COMBINED UTILITIES FORECAST 2 UPPER BOUND -BATTELLE STUDY FORECAST,MARCH 1978 3 LOWER BOUND -BATTELLE STUDY FORECAST,MARCH 1978 4'MEDIAN FORECAST -ALASKA POWER AiJ'lINISTRATION,SUSITNA PROJECT MARKET STUDY,REVISIONS OF AUGUST 1978 "T1..... G: C ::;I: IT v; I ~ 3 ZOOO ... -1--- _.J._.. .;.~_._- --!.__.-.--~--=~~ ! ,~i t,-1. t1t~Jj :~:" 'c:~c¥f3C:;; I '._':I: I '.:''';=/'0,,-,.c..; --"--j CQMPARA" ANNUAL PEAK. DEMAND FORECASTS FOR COMBINED UTILITIES AND INDUSTRIAL LOAD RAILBELT AREA -r-t-r-r-e- --'-'--1 -'-~ .-:.-,-...:....,.-- ~.=I+=:+t·r.;- -; "-;-r-rr ::~~r .t-Tl ,-'1 C' '::8 -' :p: r ~ 1- ~ :..:+-- r;-;-.....::J-=--+~_ ,, T .t-~ :--+-i- I 1I ---....;- I!I ~ l-'-- r.- ZOOO '3000 1974 1975 1980 6000 .-.. 5000 -_.-j:-i -+-----I---t.~J4000'" L-=!. ;I: ::E I W Q 1000z 4 900 ::!: N IIJ 800 l-' Q :.:700 4 IIJ Q.600 ..J 4 ::;)500z Z 4 400 '300 ; ZOO 1C 1995 11--.'-':':""---- .:.~-=.= 19901985_~m-':=.t:: 1980 5ooo·IJitl·J~~=*~.6000 4000~::--=---...;--i- t=::=""i1~I~ , r-r-t- --'-- ;1-'-'------t+:- ~ ~I"""rl---j r. ....;::I ..I :".;"':'1 1-;l..l :-I'~::-.';~I·:'.;':'~--':-~·':::::-.:.=-'_·_I;:-_:-=C:.:1-":.:.:.1 -C I :'_I,..:-: ""'I"'~~"""""""I""""""'1'"......,....,...,... :::::;:;':~4 '-~- ~-=I:.~ b=·.=..::-- g.._... -..'-.-';~::-:1I!=-y;.-..'.,....- ,~.:l 500 600 .t:L.-rB.:r::::tt H-1='"tlt -t-r.·••TI·H ...·C!:.j::f::~.....:...:t::I:±de ,'3:f.:+-C+H-.'.-¥cJ.;ld:=U:I..!:j':tj;;t'"$±tt:j:.l-l-l-.' ,.......LT •._...v::Y .,.~r--t +:-t-t-t-: '-r-r-r-, .:t::J:J-i.r.:t:l ....,.~~.~~"8 :!:.~.j-:..ti :;:.f.:Ef .il E'-:ttid~'"t'..~,,,R'l+H+td :M:'.."""r~·be C ."X~E23'EfE'F~E~c·.",..."=,"'X "''".1'1."t --r-,fc3.'E "--'..~=I·,':"; ",r-'-'T .,tt~'".i:i 'Ii.:..,"',~C'+,"-c ~:~-='l'.~5C ,co ~--f"RE~~.~.'~--'.-~"'.C .:~M .E1i±"ioF,:";;;';.,;=£. 300.±l~~'--F -r--t '.,,~.==,c+·~"Er"+',~.o.+i '"'.,,,~r~'=~~...~±l :t-+-+..=t=H ~:'I=""";::I:~..::±-I--l-.:t±l::tl::l ...,...,::I:~ft-l-;..-....... ::j:::j:±±j::j:j:±I:I :+:t±L+i .,~__c,-=1=:~~::_~ 700 400 2000', 3000 ;: ~ I C 1000z et 900 :E:g 800 x:et W II. ..J et :::l Z Z et w N N j'.H--i-+-'...:....r 200 !i; ,:.;::r-L.L..l-J..-i<::r: .- t::::::: 1C 2C 3C 4C 5C H.:~._-=~ COMBINED UTILITIES FORECAST EXTRA HIGH FORECAST}HIGH FORECAST ALASKA POWER ADMINISTRATION MEDIAN FORECAST SUSITNA PROJECT MARKET STUDY LOW FORECAST REVISIONS OF AUGUST 1978 -'§fT-.-¥:.=-.---.-,__+._..:..:.:-..:::.-.c==--!===1 -r---------I--==t==::1 ...tcP.Jt.~rt:D RANGE OF ANNUAL PEAK DEMAND FORECASTS FOR COMBINED UTILITIES AND INDUSTRIAL LOAD RAILBElT AREA .,.,...... G) c:: ;:::0 rr1 W I U1 L-.,-+ 4000liiiiiiiilllillilllllllllllllllllill-,- 1980==c::I I iii i I I i:::l 1985 1990 1995 2000 =1:..=., ;- ~=::t:==hq~4A -H+J-~/-H+H+H-++I-H+I+ ~ :E •-- :"':~-.•.-i -,.-------.L.I:.:....:..-:.-r--'.'..--...,-. .-. ...-..~:J' I i Iii .~ _~SA 1~{lf'flflflflflfril(llflflrl.~llllffiflf'rll'If,'I"i .- "::.I:.·'-I:'·"jz1 1F --_._-._---._.-_.._-_._--------',i I I I I I I I I I!I I II II ___________..~_________Ii".~., ;: ·!t-~-f;....o'!"""I!;:;·~:il,';il'~1 !.-}-·!"II'11 ;-·;1'/1:.:;0"'"./1 ';I;:~;,I'r rr rr r r : n !/":~I.Li ;;:f f·;·-~iii ~;f~t4~3:.I:Lr;k r!!j 700 w N W 600 400 ____.:..:,a?+ I---·-+-r-----'-I~-_r_'_ 300 ~.:-----t-.--~~~git~4F--- 200 I, 1A UTILITIES FORECAST FOR ANCHORAGE -COOK INLET AREA 2A EXTRA HIGH FORECAST}ALASKA POWER A(X>II.NI STRATI ON 3A HIGH FORECAST SUSITNA PROJECT MARKET STUOY 4A MEDIAN FORECAST REVISIONS OF AUGUST 1978SALOWFORECAST 1F UTILITIES FORECAST FOR FAIRBANKS -TANANA VALLEY AREA 2A HIGH FORECAST }ALASKA POWER A(X>IINISTRATION 3F MEDI AN FORECAST SUSITNA PROJECT MARKET STUDY4FLOWFORECASTREVISIONSOFAUGUST1978 -_.- -.::;_;_n -- ANNUAL PEAK DEMAND FORECASTS FOR COMBINED UTILITIES AND INDUSTRIAL LOAD ANCHORAGE-COOK INLET AREA AND FAIRBANKS -TANANA VALLEY AREA .,., ....... 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Mlr'tI -ONVlr'tI30 >lV3d 1ltnNNV 3 -27 · CHAPTER 4 SELECTION OF INTERTIE ROUTE I, I CHAPTER 4 SELECTION OF INTERTIE ROUTE 4.1 REVIEW OF EARLIER STUDIES 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 5-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'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 preliminary layout of a definitive 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 1"=1 mile (USGS Quad's.)on which these prel iminary 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 Fai rbanks. 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 1ines may cross 1andi ng patterns,at 1east 1/2 mile is a 11 owed from the end of runways or 1akes,so that speci a 1 de- signs are not required. •Avoidance of highly subdivided land areas and dwellings. •Avoidance of crossings over developed agricultural lands. •Selection of routings that provide for minimum visibility from highways and homes. 4 - 2 •Avoidance of heavily timbered lands. •Selection of routes that provide for minimum changes in grade as the terrain will allow. •Parallel alignments with property lines are favored,if not pre- cluded by other considerations. •Avoidance of sensitive wildlife areas,if practicable,and co- operation in regard to construction and operating restraints where lines pass through such areas. •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 "tractor trail" (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 corridor 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 SusitnaRiver including Sheep Creek and the Kashwitna River.In this area the terrain becomes more rolling,and the relative proportion of·well-drained soils support- ing 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 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 Creek~MacKenzie Creek,Portage Creek,DeadhorseCreek,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.Mile 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 th~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 Este.r. 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 j I ( 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 ~positive benefit of the corridor,as ar- chaeological and other cultural resources are often difficult to find in the great Alaska wilderness. 4 -e 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 tha 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 J J .1 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, provide a reliable source of electrical energy for growing communities. C.Special Impact Mitigation Efforts During COhstruction 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 centerline,thereby elimi- nating the need for an access road in addition to the transmission line clearing. 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 ] ~] 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 1. Robert W.Retherford Associates,North Slope Natural Gas Transport Systems and Their Potential 'Impact on Electric Power Supply and Uses in Alaska,March 1977. 2.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 Railbelt 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 O~If"~1 ROBERT W. RETHERFORD ASSOCIATES :a INTERNATIONAL ENGINEERING COMPANY, INC.'..CONSULTING ENGINEERS ~< A MORRISON -KNUDSEN COMPANY f V ..A DIVISION OF ARKANSAS GLASS CONTAINER CORP.Ef·,.6l~~~~~~~-~-\~~~~'2~\\\~~~'\\~V j)fA\\\~~i. NENANA-FAIRBANKS-TANANA TRANSMISSION SYSTEM Ol~ FIGURE 4-2 o I~I ,I (... :...... :his;Jc Island tannery oin ~ 'V'V<" llpno<' :').1llt. () Anc Dar~ 111 ..."~~~",'.I*.~~()\\\,~~,AI~:nd1°?"i.~~~"'H~1 Poin/~de t;t pOin~1 Elizobe,n Islond~'-".~_~~..~*.... Perl Is/ondl'~~EOS'Chugoch Islond*"i~ CHUGACH ISLANDS "'"*~ ~c!J .,Islond t;f No 100 Island O· ...°Chiswell Islond SOUND Cope 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' ,. OMiddle,OO Islond INTERNATIONAL ENGINEERING COMPANY, INC. A MORRISON - KNUDSEN COMPANY ROBERT W. RETHERFORD ASSOCIATES CONSULTING ENGINEERS A DIVISION OF ARKANSAS GLASS CONTAINER CORP. Nord lsi nd ...<:l":Jot Islond~est Amotuli Island I)East Amofuli Island 71)95} Su OS and<J Q gar/ooUsland BARREN ISLANDS ** ~ \. m \\ COOK INLET - KENAI PENINSULA TRANSMISSION SYSTEM CHAPTER 5 TRANSMISSION LINE DESIGN I.J CHAPTER 5 TRANSMISSION LINE DESIGN 5.1 BASIC DESIGN REQUIREMENTS 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 kcmi 1 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 descri pt ions 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 ~conomical 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 change~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 quyed 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 5-1 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 "\ I I i alternatives were obtained from Meyer Industries of Red Wing,Minnesota (Ref.1).This company has designed similar towers for other lines in Alaska. 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 criter{a.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 i l For this particular study,material and labor costs were obtained from lias built"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 lA, IB, and ID),the calculated intertie power angle is near 30 degrees.To improve the 230-kV intertie1s 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 transmission,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 dc transmission can be competitive with an ac alternative. 5 - 4 I, 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 TABLE 5-1 CONDUCTOR SIZE SELECTION CRITERIA Optimum ACSR Load~/ Case and Voltage Line Length Conductor Per Circuit Alternativel/Interconnection (kV +10%)(mil es)(kcmi 1)(MW). I A &B Anchorage-Ester 230 sic 323 llc -954 130 I C Anchorage-Ester 345 sic 323 2/c - 715 380 I D Anchorage-Palmer 230 sic 323 2/c -.954 130 Healy-Ester (J1 II A Anchorage-Devil Canyon 345 s/c'l.l 155 2/c ...954 600 0"> Devil Canyon-Ester 230 sic'll 189 llc -954 185 Watana-Devil Canyon 230 sic'll 27 llc -2156 488 1/Case I Alternatives exclude the proposed Susitna Project;Case II Alternative A includes the Susitna Project. £1 100%voltage support at both ends. ~Two single-circuit lines on the same right-of-way. Note:sic =single circuit;llc =single conductor;2/c =two conductor bundle. FIGURE 5-1 2°·--....·1 ........--20·--~ 89.3' 230KV TANGENT TOWER 5 - 7 I ! I ) ( .1 94.7' ----27'---_lo l.....----27'---_ 345KV TANGENT TOWER 5 - 8 FIGURE 5-2 CHAPTER 6 SYSTEM EXPANSION PLANS 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'6-1 and 6-2. Preliminary information on near future (1979-1986)generation expansion planning,including probable generation capacityr~quirements,for the AML&Pand 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 policy as to the required installed generation reserve margins for Alaskan electric power utilities.By definition,the installed generation reserve capacity includes spinning reserve,"hot"and "col d"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 are quick starting,combustion turbine-type units.This situa- tion 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,a cri- terion for installed reserve generation capacity had to be established. A 20%reserve mqrg;n or the largest single unit at the time of peak sys- tem load was decided on as the installed generation reserve criterion. In general,the 20%value is close to the installed reserve goals 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 MW 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 per-cent" (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 generating 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 thapter 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 IECQ-RWRA engineers from the Railbelt area utilities. IECQ-RWRA engineers determined the type of generation mix for the expan- sion plans based on: •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 IECQ-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 1 i 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: liThe PTI Multi-Area Reliability 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. Re 1i abil ity 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.II 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 reliability 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,specifi ca lly generator unit sizes,generator types ,1ocat ion 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 ye~rs.According to the IEEE/PES Working Group on 6 - 5 \- ! ) j Performance Records for Optimizing System Design,Power System Engineering Committee (Ref.8): "This (LOLPre1i abil ity ) index is defi ned as the long run average number of days in a period of time that load 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 generating capacity deficiency in the period.This index is commonly,but mistakenly, termed the "10s s of load probability,(LOLP)".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.II 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 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: e In very cold climatic zones the loss of electric power may be more critical than in more temperate climates. e There is very little information on existing generation and transmission outage rates in Alaska.Therefore,there is more uncertainty about the study input data. e At present,most of the power syst~ms 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 u J 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. C.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 "Planning of interconnections to achieve regional integration and more widespread sharing of generation reserves"(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 Model 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 and 6-4.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 6-2,6-3,6-4,and 6-5. 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 U J *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 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 restrictions.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: Note:The following outage rate was used for both 230-kV and 345-kV line terminals:36 hours/10 years. u Li ne Voltage (kV) 230 345 Forced Outage Rate (per unit/100 miles) 0.00113 0.00225 6 -.9 J 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: e 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 the 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 interconnected system expansion plans.The independent Anchorage and Fairbanks generation expansion plans are indicated on Figure 6-2. 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 four 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 6-6. •Case IS 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) and 70 MW (1992-1997). This plan is shown on Figures 6-4 and 6-6. •Case IC includes one single-circuit 345-kV transmission line having a 130-MW power transfer capability allocated for genera- tion reserve sharing and a 250-MW capacity available for firm power transfer.This case was developed for comparative cost information purposes only without generation expansion plans (MAREL study)and is presented on Figure 6-7. •Case 10 is the same as Case lA,except with intermediate switch- ing stations at Palmer and Healy. This plan is shown on Figures 6-3 and 6-8. 6 - 11 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. O.Re 1i abil ity 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 6-7,6-8,and 6-9.As previously discussed in Subsection 6.28,the LOLP index of one day in ten years (0.1 day/year) or lower was maintained throughout the study. 6.4 REFERENCES 1.Battelle Pacific Northwest Laboratories,Alaskan Electric Power, An Analysis of Future Requirements and Supply Alternatives for the Rai1be1t 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. 5.Electric Light and Power,Capacity Can Meet Winter Peaks -DOE, November 1978. 6.Alaska Power Administration,Upper Susitna River Project,POWER MARKET ANALYSES,Draft,January 1979. 6 -12 \ I ) J 7.Power Technologies,Inc.PTI Multi-Area Reliability Program (MAREL), Computer Program Manual,September 1978. 8."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 TABLE 6-1 EXISTING GENERATION SOURCES ANCHORAGE -COOK INLET AREA Unit Rating Dependable Unit Year of Base Peak Capacity Name/Location Reference Installation ~-l!ili.L -l!ili.L (kW)Remarks ANCHORAGE MUNICIPAL LIGHT AND POWER (AML&P) Anchorage Diesel 2.200 Black start unit Anchorage Unit 1 SCGT 15.130 18,000 Anchorage Unit 2 SCGT 15.130 18,000 Anchorage Unit 3 1968 SCGT 18.650 21,000 Anchorage Unit 4 1972 SCGT 31.700 35,000 Anchorage Unit 5 1975 SCGT 36.800 40,000 }Cornbinedcycl e Anchorage Unit 6 1979 HRST 12.000 installation . CHUGACH ELECTRIC ASSOCIATION (CEA) Beluga Unit 1 SCGT 15.150 18,700 Beluga Unit 2 SCGT 15.150 18,700 Beluga Unit 3 RCGT 53,500 67,000 Beluga Unit 4 SCGT 9,300 10,000 Beluga Unit 5 RCGT 53,500 67,000 Beluga Unit 6 SCGT 67.810 72,900 Beluga Unit 7 1978 SCGT 67.810 72,900 Bernice Lake Unit 1 SCGT 8.200 16,500 Bernice Lake Unit 2 SCGT 19,600 20,500 Bernice lake Unit 3 1978 SCCT 24,000 I nternat i ona 1 Unit 1 SCCT 14,530 16,500 International Unit 2 SCGT 14,530 16,500 I nternat i ona 1 Unit 3 SCGT 18,600 21,500 Cooper Lake Unit 1 Hydro 7.500 9,600 Cooper Lake Unit 2 Hydro 7,500 9,600 16,500 Knit Arm Several ST 14.500 17,700 To be retired in 1985 MATANUSKA ELECTRIC ASSOCIATION (MEA) Talkeetna Diesel 600 Standby HOMER ELECTRIC ASSOCIATION (HEA) English Bay Diesel 100 Homer-Kenai Diesel 300 Leased to CEA Homer SCCT 7.000 Leased from GVEA Port Graham Diesel 200 (1977-1979) Seldovia Diesel 1.648 1.500 SEWARD ELECTRIC SYSTEM (SES) Seward Unit 1 Diesel 1,500 }Unit 2 Diesel 1,500 1,500 5,500 Standby Unit 3 Diesel 2,500 3,000 ALASKA POWER ADMINISTRATION (APA) Ekl utna Unit.1 Hydro 30.000 35.000 30;000 6 - 14 TABLE 6-2 EXISTING GENERATION SOURCES FAIRBANKS -TANANA VALLEY AREA 6 - 15 ,j TABLE 6-3 LOAD MODEL DATA ANCHORAGE AREA ANNUAL PEAK LOAD IN MW (1983-1996) 789.877.977.1080.1196.1313~1441.1581. 1724.1881. 2041.2215.2402.2591. INTERVAL PEAK LOADS IN P.U. OF ANNUAL PEAK LOAD (26 INTERVALS /YEAR) .8333 .6667 .74!04 .7500 .6571'.6346 .6122 .5865 .5481 .5353 .5224 .'5160 .5064 .4904 .5032 .4968 .5160 .5737 .5769 .6154 .6827 .8429 .8526 .913S1.0000 .8301 DAILY PEAK LOADS IN P.U. OF INTERVAL PEAK LOAD (260 WEEK DAYS /YEAR) 1.0000 .9769 .9731 .9538 .9500 .9462 .8962 .8731 .8577 .8423 1.0000 .9808 .9663 .9663 .9615 .9615 .9519 .9519 .9423 .9375 1.0000'.9913 .9784 .9827 .9697 .9654 .9437 .9307'.9221 .8918 1.0000 .9829 .94!87 .9359 .9017 .8889 .8889 .8846 .8333 ,.8034 1.0000 .9512 .9317 .9171 .9171 .9073 .9073 .9024 .9024 .8976 I.0000 .9848 .9798 .9747 .9646'.9495 .9444 .9343 .9293 .9141 1 .0000 .9686 .9634 .9529 .9529 .9476 .9424 .9372 .9058 '.9058 1.0000 .9781 .9727 .9617 .9563 .9563 .9344 .9344 .9071 ~9071 1.0000 .9883 .9883 .9825 .9825 .9708 .9708 .9649 .9591 .9415 I.UOOO .9940 .9820 .9701.9581.9461.9401.9341'.9281.9162 1.0l1 0t l .','939 .9877 .9571 .9571 .9509 .9509 .9448 .9202 .8589 I .0(\:.\0 .9938 .9814 .9689 .9565 .9379 .9379 .9379 .9255 .9255 1.0000 .9810 .9684 .9620 .9494 .9494 .9430 .9367 .9304 .9177 1.0000 .9804 .9739 .9739 .9673 .9608 .9542 .9542 .9477 .8824 I .0000,.9873 .9745 .9554 .9490 .9490 .9427 .9427,.9299 .9299 ~.OOOOl.0000 .9935 .9871 .9806 .9742 .9677 .9613,.9548 .9484 1.0000 .9938 .9814 .9689 ~9627 .9565 .9565 .9441 .9441 .9379 1.0000 .9777 .9609 .9441 .9274 .9106 .8883 .8715 .8715 .8045 '.Ou00 .9944 .9944 .9722 .9722 .9722 .9611 .9278 .9222 .9222 LOCOO .994!8 .9896 .9896 .9687 .9583 .9531 .9375 .9323 .8802 l.nnrn .9859 .9484 .9437 .9390'.9296 .9249 .9202 .9155 .9014 1.OhH}.9962 .9658 .9468 .9468 .9087 .7985 .7757 .7719 .8555 1 .00001 .HOOO .9887 .9662 .9549 .9511 .9474 .9398 .9361 .9323 J.\lOOO .9754 .8632 .8596 .8421 .8386 .8386 .8386 .8386 .8175 1.0000 .9840 .9679 .9519 .9359 .9327 .9327 .9135 .8654 .8045 1.0000 .9730 .9730 .9614 .9614 .9575 .9575 .9537 .9421 .8340 6 - 16 TABLE 6-4 LOAD MODEL DATA FAIRBANKS AREA ANNUAL PEAK LOAD IN MW (1983-1996) 196. 416. 212. 446. 231. 477. 249.270. 511. 291.313.338.362.390. INTERVAL PEAK LOADS IN P.U. OF ANNUAL PEAK LOAD (26 INTERVALS /YEAR) 0.87590.69900.73710.76040,~57490.59710.56630.5 U10.43240J41150.38330.37470.3587 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 /YEAR) I •OOOt)O.97480.94670.94670.94530.93130.89480.86540.84290;.8177 1.Ou000.93670.92790.92790.90510.89980.88050.85940.82790~7891 1 .00000.99330.96670.94830;.94000.92330.90330.88000.86670~8267 1.00000.97580.96120.94510.86910.83200.82390.81100.79000J6769 'I .00000.98500.98290.95940.:95300.94660.91880.90810.90170'~8825 1.00000.99790.99590.98770~97940.95880.93620.90530.89300~8827 1.00000.98480.95010.93710';91970.89370.88070.87200.86120.8091 1.00000.96870.96150.95190'.93510.91590.88700.88220.87980~8558 1.00000.99150.99150.99150.97160.96870.93180.89200.88920~8693 1.00001.00000.96120.93130~92840.92840.92240.90750.90450.8955 1.00000.99040.99040.94550~92310.91990.91670.91350.87820J8558 1.00000.96720.95410.92790.92460.90490.89840.89510.87870~8721 1.00000.96920.96920.95890;.95890.94520.94520.93150.92120:'9041 1.00000.98960.97220.96870,95830.94790.93400.92360.92010.8507 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'.92820.90960.90690.90160.88830~8856 1.00000.98850.93300.91450'.90990.89610.88910.88450.86370;.8568 1.00000.99150.98080.97650.94020.92950.92740.91880.91450~9017 I.00000.96690.91180.89260l88840.79890.73970.64460.61020~6088 !.00000.97710.91050.90790j90790.89340.88950.88550.86320~8434 I.OOOOO.97110.86330.83050~81870.79630.79240.74510.73320~7201 1.00000.99510.98160.97300.97170.95580.91650.88450.82430:.6818 1.OOOOO.99840.93930.92010~89940.88980.88500.84820.81310.1971 6 - 17 TABLE 6-5 LOSS OF LOAD PROBABILITY INDEX CLOLP)11 FOR STUDY CASES IA &IDg l Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Expansion Expansion Expansion Expansion 1984 0.0262 0.0063 0.8193 0.0066 ....,'~ 1985 0.0123 0.0275 0.1446 0.0242 1986 0.0293 0.0178 0.2868 0.0268 1987 0.0288 0.0255 0.6766 0.0575 1988 0.0482 0.0799 0.1140 0.0300 1989 0.0330 0.0677 0.2318 0.0394 1990 0.0265 0.0680 0.0593 0.0670 1991 0.0193 0.0633 0.1550 0.0130 I 1992 0.0189 0.0286 0.0276 0.0275 "1993 0.0546 0.0316 0.0586 0.0606I ) 1994 0.0427 0.0321 0.1583 0.1365 1995 0.0326 0.0652 0.0373 0.0426 1996 0.0931 0.0586 0.0899 0.1021 11 LOLP in days per year. gl 230 kV sic,130 MW reserve sharing only. 6 - 18 TABLE 6-6 LOSS OF LOAD PROBABILITY INDEX (LOLP)1/ FOR CASE IBf/ Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Expansion Expansion Expansion Expansion 1984 0.0262 0.0077 0.8193 0.0018 1985 0.0123 0.0329 0.1446 0.0096 1986 0.0293 0.0220 0.2868 0.0152 1987 0.0288 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 0.0593 0.0670 1991 0.0193 0.0633 0.1550 0.0130 1992 0.0189 0.0359 0.0276 0.0143 1993 0.0546 0.0703 0.0586 0.0354 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 1/LOLP in days per year. ~/230-kV transmission system with reserve sharing and firm power trans- fer capability. 6 - 19 r, if TABLE 6-7 LOSS OF LOAD PROBABILITY INDEX (LOLP)1 1 FOR CASE IIA~/ Anchorage Fairbanks Study Independent Interconnected Independent Interconnected Year Expansion Expansion31 Expansion Expansion31 1992 0.0189 0.0476 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 II LOLP in days per year. 21 Includes interconnections between Devil Canyon-Anchorage (345 kV), Devil Canyon-Watana (230 kV), and Devil Canyon-Ester (230 kV). 31 Interconnected expansion for three area system: Anchorage,Fairbanks, and Upper Susitna (generation only). 6 - 20 .> -,:---,," "..... G) c:::::c ("Tl 0'1 I W 200 600 400 800 1400 1000 1200 1600 4400 ._J •._'--'L,-I '-'--::j.:'~j..1El·JJj Ll.Ll.LlLl.Ll.Ll.Ll, .",I.j'l.LLh+H·!J ...Iilr'H '".....''''U'·'.'...,.-""!..~.i -"-.1.""-...a;'-,- r-----f .,rzeo ..1N,STAU.ED,.CA'iACI1Y,l~..MII ,l;,t"";;-i'·nt "iH!i1tn !hiJ f-+t"[J-~-tl 'irl·:+!~!·H-1T~·fr!·cl",·;;:""'-"r""'j+b ;+t,_j ..:.I.,I"••••,"",/,,i-,..~.'j 3600 ~;;~:::::!::_:,:::':f'::':.:.'-.J ..::';::;-::::::';ui't~~~;;::~~r ;r;;1:'::iff t4t A8;:;';11 :~i~j -;;l~~F it:i+:'.'~.;t;~i ..~-:'G~~:~~.349~7 .~~:;:..~~·:L::.~!f:'..:::.+==.:~;2:;..,:':'::~~~~;;'E~N~~~t;~·~~F.:1#t .r:r21'j~1l!!;Hl~;:H'~fl qhw :f!i·:l1tttt'fttjfm~j;~h~!/tmf ~l:i!:~~KI~I+~::':~L v I':::':;:-:h:~j ::i:~d~oH:t=J:::J:::-:::..:!:::.'.'t::;I<l':~f::::;T+;:;nHW:Ji}H~lifti i:tttjr rt f~ljIIR1t!m~l1fH~[!1Imliil$:llh;W~I:·:._!::':33:14''::C:t:::::j:;+~~r:=1 ._:,:::.~'·""'·""*1"/"'1.!..I,·..,....·,·",'1:_·;_,;1 ·"~,tth 'HH :,~.I!jJ';TWI.n:!i!hrl~Jti h1!,fHH Lr'O+-r-,.':":'"'~'*1.1 .1 ·,..1·-I.'·";i "'''---1 >'-I'.J~~I':'f~:':r'j;ti ",>:,,,,_';I':;"""'I"i1":'I"-";';I~ ,.j .':.:...,.:."T·-·i::·,Lji3t~g;~J~~~~:~~''':I'';~:;~llltHt;t:':1 ~):ti;;:;t-j ~ii~~;~k:JffiIT 1;';:±~:;:~::,::1:::.:'.i.::~.::..j.:::..;.::::,·:,,:;-1·::::8-==!·:::_:·= ,1--'.-~'!':~;':'.A~~S i.',i.'!'(•.,_l~;t'~;""tJ;~~-I~':lhl~~'I~J~~f:~~j;i~~~~I,c;J~I;I=~=.,I,~~ir~1~i2 !=:;~.:~~~:,..-I .;,.,.1..,..j ,1..]""'I'-"'f'-_.....,.'Hi.,:1--.--[---,-.:l-;..-l.-~.-.:.....1"1 "",''':'.'"..r._.."-'1--ol -'1·-._--I -•.:!---f 1 -i·'"-J --~-1··-,- -, .." -.-..;--!-_..---!...--:t··_--pr-·",-·~1~:...-.-!....••','--I ._,••;-.l •••••--_._••,---,.....---.,~79 1980 198\1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 TI~94 1 1995'f 1996 I 19971 19981 3=:: c <t 0 ..J :>:: <t !.oJ Q. 0'1 c Z <t )0- N I-W U <tQ. <tc..> C !.oJ ..J ..J <tI- (J) ~ INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE -FAIRBANKS AREA WITHOUT SUSITNA PROJECT m N.;:. 3800 3400 2800--- .aoc ~ooo ----- 400 1200 800 600 200----- 0'-1979- "t-f G>c:::::c I'T1 m I.;:. 4400 _.,..L_,_.'._..:~---,l-_._I __.......;.:.;.I!.'-'-!_H-Lp'J.p:,-mm14j<·"!JJ.:.!.::!.'"!'"I..,.......I._1_,..........-- ."..... G>c::: ;0 /"T1 Ol I U'1 PR OJECT MOST PROBABLe.. LOAD FORECAST SUS!TNAUPPER ..j ------_..~-_._------ 1600 1800,". 2600 '-'-'-'-'-'''-:', 2200 2000 2800 .--,-.--:-.--:--. .,3200 'l t. "~:UNIT I , 1 J--"-"7"!'-_::':"-_J :.-:::.:--Y:J ".-:--.-_.:..__..~;:;..:~IJ;2 ·I_.:-=-.=d~-t~- ,I'I ;183Z:,J , I·.~~~:~::._.~..: :t=ANCK9 ...78 ~-!--:-i -"T:+-'-1_d--;-1--"-.-··_····1·....;·_..i:__·_;·,-..·1 ''r-~-1'.,.",,'I .,.I 'I'::i;~;;:',:L':"::~-'.~3:'_--~_....:.:.::!~~_.-~-~-:-:-~1-.-·~-_-_,_-_;__.. .•.I ._1.."-"-,'---"I47Z -_..J.'-1',..r,l'~J •••"••I. ,.1 -.. 1400 ;-:-_.-----·-:~.._:..----·-·:~+~L ,.I~~.,~-7'';''~·-:-:-i--·j-··~~~t~,.t :_!~.~~~-+'-·i-:-h-:..-.- UPPERL.IMITlOADFORECAST..,~J .~!'.f;·..I:.i.:-:IF·-:~:~::l-~:!.·:···:..i:_:~:n~:n.-.-.;:~:_[_Qi~!:iu~~!5:i!~ii&1g~i:II------ 400·'J::::.,::,j ..i.:":.::::+;~::i "+:l::L:::,j.';:+:r:J:i:[1:Jl:!::dti::::''::;j;_',;:-:i ''!..::_;.---.----.h_.,__ 1-I i·· ·=~L:_-l-· i·~--·-_·=.:~~---::::-.~t~~.j~-:~:-·~-·'~.=~-:r·--:3::::::r:~ij:·-!lf·-:---:.-.-~t.:-~..----t..·-~-_:-~·-~'-.•*.: °rI979-D98o-l198~-Ti~--i;~8;Ci~'~-~-r;;8~"i~86H9ili88jjis-;-i~i990'r~J-rl~i 1'1993 11994'1"1995 '-1996'r 1997'r 1998-1 INTERCONNECTED SYSTEM EXPANSION PLAN ANCHORAGE-FAIRBANKS AREA WITH UPPER SUSITNA PROJECT 3= :;3000 0 ~ 0 ..J :.: ~ IIJ Q. Ol C Z ~,... N I- U'1 U ~ Q. ~ U 0 IIJ ..J ..J ~ l- ll) Z ·FIGURE 6-6CIl"<l-c 6 - 26 FIGURE 6...7II,~I (.)~S "-1~~4J+::!£!Vj~t ~C5~L...,.< I I : I 6 - 27 FIGURE 6-8 6 - 28 --- ANCHORAGE ESTER OOfvf\Mi 230KV T/L + 230KV T/L 271MVA r 23iV345KV![j""tl 230kV ,~v.,:I ,I .J j'~~ ~¢ fl~ 345KV T/~ -o-s-o-v-o- ~ E.3IfWIAOJ OO/345FY!1 1- -~1 200MVAR~ O'l Nso 4'X/80MVA DEVIL CANYON 230KV CASE 1I ." 1-1 Ci>c: ;0 l"11 O'l I U) CHAPTER 7 FACJL ITY COST ESTIMATES CHAPTER 7 FACILITY COST ESTIMATES 7.1 TRANSMISSION LINE COSTS 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 line 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 clear- ance costs and other costs associated with the solicitation and obtention of right-of-way ease~ents,permits,and environmental re~iews 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 clearance. 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. Summary of Actual Costs: Construction Cost Right-of-way Clearing Cost Right-of-way Solicitation Cost TOTAL (w/o Engineering) $/Mile 87,294 19,049 7,706 114,049 2.·Willow Transmission Line - 115 kV (Tubular Steel Towers, 556.5 kcmil Dove ACSR Conductor),1978. This line was built by contract using 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 1011 H-pile for another line.In one case,the tool drove.a 1411 H-pile for a sign support.The contractors are preparing 7 - 2 to drive more 1411 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) B.Material Costs $/Mile 73,863 10,312 4,909 89,084 I The estimated cost for the tower steel,as well as the physical character- istics were obtained from ITT Meyer Industries (Ref.I).The cost of steel,therefore,has 1979 as the reference year.A 10 percent addition to the material cost was included to account for the 1.46 AVF explained -above , 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 30 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'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 2 was applied to the estimated cost of labor for this period,in order 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 "Hydroelectric Power Evaluation"(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 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 operat ions,and economi c energy di spatch throughout the 'inter- connected Anchorage-Fairbanks area.The cost estimates include a power line carrier type communications system,a digital supervisory control and data acquisition (SCADA)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 frir 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 vpltages at the receiving and sending ends;The program assumes 100 percent volt support ?t both ends. Table 7-2 presents the present worth (1979)costs of calculated transmission line energy and ;demand los ses. 7 - 5 .I I 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 refer~nces 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 adjustement 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 considerati~n 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 -5 ,( 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 expense~is the salient factor,which affects the economic comparisori 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: Transmission Intertie Firm Power Transfer From To Duration Capacity %Power Loss!!Energy~!%Energy Loss!! 1984 1987 4 yrs.30 MW 6.9 145 GWh 1.05 1992 1996 5 yrs.70 MW 6.9 337 GWh 1.05 11 Case lB. 2/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 Railbelt 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 10)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 10. 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.Atempo- 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 I 1 J 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 intertie 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.Battelle Pacific Northwest Laboratories,Alaska Electric Power: An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region,March 1978. 3.DOE,Federal Energy Regulatory Commission,Hydroelectric Power Evaluation (Final Draft),August 1978. 4. U.S. Bureau of Reclamation,··BuRec Construction Costs··,Engineering News Record, 22 March 1979. 5.Stanley Consultants,Power Supply Study - 1978,Review Copy of Report to Golden Valley Electric Association,Inc. 6.Power Engineering,IINomogram calculates economy of scale in power plants ll ,Volume 83,February 1979. 7. U.S.Army Corps of Engineers,South-Central Railbelt Area,Alaska, Upper Susitna River Basin Interim Feasibility Report,December 1975. 8. 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 l.Transmission Line: Eng'g.&Constr.Supv.3,012 3,012 4,043 3,012 8,079 Right-of-Way 8,837 8,837 9,080 8,837 20,973 Foundations 8,445 8,445 12,160 8,445 22,966 Towers 21,615 21,615 33,719 21,615 64,088 Hardwqre 477 477 477 477 1,096 Insulators 503 503 755 503 1,396 Conductor 10,761 10,761 16,708 10,761 32,886 !i Subtotal 53,650 53,650 76,942 53,650 151,484 I 2.SUbstations: Eng'g.&Co.nstr.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 Ci rcuit 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 91,868 68,874 201,484 I J 7 -10 r I TABLE 7-2 PRESENT WORTH OF INTERTIE LINE LOSSES 1984-1996 STUDY PERIOD!/ Case IA &10 (230 kV) IB (230 kV) IC (345 kV) II A (230 &345 kV) Anchorage - Devil Canyon Devil Canyon -Ester Watana -.Devil Canyon $x 1000 (1979) 10,530 11,582 7,341 28,027} 14,816 $49,125 6,282 . I j !/Cost of losses,energy,and demand,escalated at 7%per year. 7 -11 .i TABLE 7-3 COST SUMMARY FOR GENERATING FACILITIES (Costs at 1979 Levelsl/) 7 - 12 TABLE 7-4 SUMMARY OF ALTERNATIVE GENERATING PLANT FUEL COSTS 1992 6,851 8,324 1993 7,212 8,654 70 MW 1994 7,933 8,016 337 GWh Firm Power Transfer 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 -$1000 Isolated Diesel Tapline Supply Year Generation at Site From Intertie 1985 2,835 267 1986 695 483 1987 697 481 1988 696 478 1989 3,055 752 1990 1,324 902 1991 187 734 1992 623 430 1993 623 419 1994 -5001/304 1/Negative sign indicates that resale value of generating pl~ntexceeds cost of generation in final year. 7 -14 FIGURE 7-1 UPPER SUSITNA RIVER PROFILE t vone :~~\ 5''''''0 LO"\~ (~\ <SI.q " 01--"- <SIo .....1 V-v.\<)~(~)-\ ) J '-\.,,'~\"~ <,os~~\>(J I.OUl' UPPER SUSiTNA HYDROPOWER DEVELOPMENT (Source:,Plan of Study for Susitna Hydropower Feasibility Analysis,by Alaska District U.S.Army Corps of Engineers,Sep.1977) 2 O'II_tlf.I.,O/flUlicbool .......l~ Eltoo!>all$U'"10 mUlII_lwfl 10 15 20MIlcs SCALE TEMPORARY 69kV WOODPOLE LINE MAIN TRANSMISSION LINE TRANSMISSION CORRIDOR ANCHORAGE FAIRBANKS INTERTIE RIVERMILES 120-290 SUSITNA TRANSMISSION TAP STATION 230/69kV CONSTRUCTION PLAN FOR UPPERSUSITNA PROJECT: Ref.Interim Feasibility Report - P.94,US Army Corps of Engineers,12 Dec.1975 Construction Period for Selected Projects: Watana Dam - 6 Years Devil Canyon Dam - 5 Years Total Period -10 Years (1 Year Overlap) SUGGESTED REVISED SCHEDULE: I I ..! 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 CHAPTER 8 ECONOMiC FEASIBILITY ANALYSIS u CHAPTER 8 ECONOMIC FEASIBILITY ANALYSIS An economic feasibility analysis was performed to determine which system expansion plan provides the best use of available resources for supplying I;) electrical power to the Railbelt area.Alternative system expansion plans and facility 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 y~ar and then totalized for each plan to obtain a single 1979 present-worth value.This approach does not include additional capital disbursements after 1996.Such disbursements will be required later to replace retired facilities.However,the extension of the present-worth model over the whole life of the proposed intertie will not significantly affect the results of this feasibility study.The year 1996 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 6-5 in Chapter 6 show that many facility costs 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 elimi- nated.Also excluded from the analysis are plant fixed operation and maintenance costs.The exclusion of these Q&M costs will somewhat favor the 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 recommended that a multi-area production cost study be performed at a later time. 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 Economics Analysis Prog~am (TLEAP),provides the following outputs: •Cost disbursement tables for alternative system expansion plans. •Discounted cost ratio (independent/interconnected)tables for system expansion alternatives. •Tables indicating independent minus interconnected system costs. e Separate tables indicating the discounted value of base year (1979)costs for the independent and interconnected systems. 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 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 4%to 12%,and a range of discount rates from 8%to 12%.In the analysis of the results below, a long-term average annual escalation rate of 7%and a'10%discount rate are used.The 10%discount rate is now required by the Office of Management and Budget for federal projects. A.Benefits due to Generation Reserve Capacity Sharing Two cases were investigated to determine intertie benefits due to.genera- tion reserve capacity sharing alone:the 230-kV single circuit intertie and 345-kV single circuit intertie between Anchorage and Fairbanks.In both cases 130 MW of power transfer capacity was allocated for generation reserve capacity sharing purposes (Cases IA and IC in Chapter 6).The economic analysis results indicate: 230 kV Independent Systems Interconnected System Benefit Less cost of line losses Net Benefit PW (1979 Costs x 1000) $406,853 388,355 18,498 10,530 $ 7,968 The above results indicate that the 230-kV intertie is economically feasible based on generation reserve capacity sharing only. 8 - 3 \.! 345 kV Independent Systems Interconnected System Benefit Less cost of line losses Net Benefit PW (1979 Costs x $1000) $406~853 412~338 -5~485 -7~341 $-12~826 I \/The above results indicate that the 345-kV intertie is not economically feasible based on 130 MW power transfer capacity.To analyze the.345-kV intertie with different (higher)power transfer capacities allocated to generation reserve capacity sharing would require development of addi- tional expansion plans and new MAREL studies. Sensitivity of the results to variations in escalation and discount rates are indicated in Tables 8-1 and 8-2.Computer printouts~indicat ing cost disbursements~discounted cost ratios~and discounted value tables~are included in Appendix E (Economic Analyses Nos.1 and 7). B.Benefits due to Firm Power Transfer and Generation Reserve Capacity Sharing One case was investigated to determine combined 230-kV intertie benefits due to both firm power transfer and generation reserve capacity sharing (Case IB in Chapter 6).This study case has one 230-kV single circuit line during the 1984-1991 period and two single circuit 230-kV lines during the 1992-1996 period.The economic analysis results indicate: Independent Systems Interconnected System Benefit Less cost of line losses Net Renefit 8 - 4 PW (1979 Costs x $1000) $707~534 681~364 26 ~171 11~582 $14~589 The above intertie benefits can be combined with additional benefits due to supply of construction power to the Upper Susitna Hydropower Project sites (see Section 7.9). .J Independent Systems Interconnected System Benefit Less cost of line losses1/ Net Benefit PW (1979 Costs x $1000) $715,566 685,295 30,271 12,740 $ 17,531 The increase-in net benefits due to supply of construction power to the Upper Susitna Hydropower Project sites is $2,942,000 or approximately 20 percent. Sensitivity of the results to variations in escalation and discount rates are indicated in Tables 8-3 and 8-4.Computer printouts,indi- cating cost disbursements,discounted cost ratios and discounted value tables,are included in Appendix E (EconomicAnaly~es Nos.2 and 8). C.230-kV Intertie with Intermediate Substations Two cases were investigated to determine additional benefits due to supply of power to the MEA System at Palmer substation,and construc- tion power to the Upper Susitna Hydropower Project (Case ID,Chapter 6). These cases include a 230-kV single circuit line between Anchorage and Fairbanks (Ester),with intermediate substations at Palmer and Healy. The economic analysis results indicate: 1/Losses were increased by 10%to account for construction power. 8 - 5 I 1 II' I {' D.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 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. •A draft copy of the Upper Susitna proj ect report prepared by the Alaska Power Administration (Ref. 1)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 installaed capacity used in development of the expansion plans analyzed in this report. A study should be performed 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 detaii 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 Uppwer Susitna power: Period 1992 1993 1994-1996 8.4 REFERENCES Requirement One 345-kV SIC line to Anchorage One 230-kV SIC line to Fairbanks One 345-kV SIC line to Anchorage Two 230-kV SIC lines to Fairbanks Two 345-kV SIC lines to Anchorage Two 230-kV SIC lines to Fairbanks 1. Alaska Power Administration,Upper Susitna Project Power Market Report (Draft),February 1979. 8 - 8 5 APRIL 79 ALASKA POW~R AUTHORITY ANCHORAGE -FAIR~ANKS INTFRTIF ECONOMIC FEASIBTLTTY STUDY DTFFERENTT AL OlSCOUNTfD VALUE OF RASE YEAR (1979)COSTS INDFPENDENT SYSTEM COSTS MINUS INTERCONNECTFD SYSTEM COSTS (IN $1000) __________________________________ESCALATION RATES ---------------------------------- DTSCOIJNT 4~51-61.7"t.8':1.91.101-11'!::121. R.\TE ------------------------------------------------------ ------------------------------------------------------ A.OO l'l,')I?'If\,'>60 17,215 1S,417 B,09f\10,18'3 6,590 2,226 -3,011 8.?5 l o,h8f\1E1,El2'>17,'>8 11 lS,907 13,72'l 10,977 7,S72 '3,423 -1,567 8.50 19,R4S 19,066 17,925 16,~6'5 14,~2?11,727 R,502 IJ,S60 -193 8.7':J 19,983 19,286 lA,?40 16,791 14,871\12,433 'l,381 5,63'l 1, 1 14 9.00 20,104 l'l,1l83 lE1,529 17,187 lS,39R 1'3,09R 10,213 h,662 2,357 9.?5 20,207 19,6,61 18,7911 17,S54 IS,A8'>1'3,721J 10,9'}A 7,h3?3,S37 9.S0 20,?9'>19,1'119 19,OSh 17,A91l 16,31J0 l l l ,7,II 11,7110 R,550 4,6')9 0.75-20,3b7 19,059 1'l,256 1R,20A 1h,76 11 lll,A6~12,/B9 9,420 5,72'3 10.00 20,1J25 20,08?10,llS5 IR,1l9R 17,15E1 lS,380 17,,091'1 10,?1J2 6,733 10.2':J 20,/J6 Q 20,18f\19,63 l l 1R,76'3 17,'>25 15,f\blJ 13,718 11,019 7,691 10.50 20,500 20,218 1'l,794 19,00S 17,R6 11 16,316 Ill,30 1 11,75'3 A,59a 10.75 20,'>1 9 20,352 19,'l3f,19,226 1/'\,17 e lh,73 R 14,A/J R 12,1145 9,1l57 OJ 11 .00 21'\,S2S 20,413 20,060 1'l,IJ26 18,ll67 17,130 15,'362 13,09R 10,nO 11.25 2 0,521 20,1l60 20,16R -IQ,607 1R,73?17,IJ 9S 15,RIJ?13,713 11,039 11."0 20,506 20,/191J 20,?61)10,761'1f\,QlS 17,R3 11 I 16,29?11J,291 11,766 co 11.7')20,1J81 20,515 20,357 19,91?1 9,197 1E1,147 16,712 14,f\34 12,451 12.00 20,1l1J6 20,S2'>20,400 20,038 19,39R 1f\,!l36 17,10'3 lS,344 13,098 -f ::J:::> \jj Irn OJ I I-' 5 APRIL 79 .-x:---~._,~ ALASKA POWER AUTHORITY ANCHORAGE - FAIRBANKS INTERTIE ECONOMIC FEASIBILITY STUDY DIFFeRENTIAL DISCOUNTED VALUE OF BASE YEAR (1979)COSTS INDEPENDENT SYSTEM COSTS MINUS INTERCONNECTeD SYSTEM COSTS (IN $1000).... ______________________________~___ESCALATION RATES ----------~----------------------- DISCOUNT ur.57-670 _77-87-9r.lOr.11"12i. RATE ------------------------------------------======------ ------------------------------------------------ 8.00 -3,562 -5,375 -7,604 -10,311 -13,564 -17,438 -22,016 -27,391 -33,665 8.25 -3,183 -4,899 -7,016 -9,594 -12,698 -16,400 -20,781 -25,932 -31,950 8.50 -2,825 -4,449 -6,459 -8,912 -11,872 -15,u09 -19,602 -24,536 -30,308 8.75 -2,'HI 8 -4,024 -5,931 -8,265 -11,086 -14,465 -18,475 -23,201 -28,736 9.00 -2,1 71 -3,622 -5,430 -7,649 -10,338 -13,564 -17,399 -21,925 ~27,232 9.25 -1,873 -3,243 -4,9':>6 -7,065 -9,627 -12,705 -16,372 -20,705 -25,792 9.50 -1,594 -2,1\85 -4,507 -6,510 -8,949 -11,887 -15,392 -19,539 -24,414 9.75 -1,331 -2,548 -4,082 -5,91\4 -8,306 -11,108 -14,456 -18,426 -23,097 10.00 -1,OR6 -2,2.$0 -.3,681 -5,485 -7,694 -10',365 -13,564 -17,361 -21,836 10.25 -8':>6 -1,9.32 -3,302 -5,012 -7,112 -9,6':>8 -12,713 -16,345 -20,631 co 10.50 -641 -1,651 -2,944 -4,564 -6,560 -8,986 -11,902 -15,375 -19,479 10.75 -441 -1,387 -2,607 -4,141 -6,036 -8,.346 -11,128 -14,4 118 -18,377 11.00 -254 -1,140 -2,289 -3,740 -5,539 -7,737 -10,392 -13,564 -17,324 11.25 -80 -909 -1,989 -3,361 -5,068 -7,159 -9,690 -12,720 -16,318 I-'11.50 80 -693 -1,708 -3,003 -4,621 -6,610 -9,022 -11,916 -15,358 0 11.75 229 -u91 -1,443 -2,665 -4,191\-6,088 -8,386 -11,149 -14,440 12.00 367 -302 -I ,195 -2,3£17 -3,798 -'),592 -7,781 -10,417 -13,564 -I»co I' rr1 co I N '5 APRIL 79 .-~_.- ALASKA POWER AUTHORITY ANCHORAGE -FAIRBANKS INTERTIE ECONOMIC FEASISTLTTY STUDY DIFFERE.NT!Al OISCOUNTfD VAlliE OF BASE YFAR (1Q79)COSTS INDEPENDENT SYSTEM COSTS MINUS INTERCONNECTED SYSTEM COSTS (TN $1000) __________________________________FSCAl.ATION RATFS ---------------------------------- DISCOUNT 4%5%6'%7%B%9';10';11 %12% RATF ------------======------------------------------------ ------------------------------------------------ R.OO 27,096 26,190 2/.1,R211 22,92h 20,/J14 17,191\13,171 1I,?1I?2,268 R.25 27,259 26,456 2S,?12 2~,1I5h 21,110 18,086 1 11,2AII Q,6011 3,'127 8.50 27,400 26,69S 2'),S67 23,911R 21,760 lR,921,15,337 10,QOi'5,503 A.75 27,51 9 26,,908 2S,A91 2/1,L10?22,~67 19,70')16,325 12,127 6,998 Q.OO 27,617 27,096 26,IBS 2/1,1'120 22,932 20,1I110 17,257 13,285 11,417 9.25 27,69'5 27,25'1 26,1I50 2'1,?05 23,1l56 21,127 18,133 1/1,379 9,761 9.S0 ?7,7')4 27,/100 26,687 2S,S57 2~,943 21,770 l R,9')7 lS,L11?11 ,035 Q.75 27,79r:;27,c;19 26,R9 9 2S,A79 24,393 22,370 19,731 16,387 12,2111 10.00 27,A20 27,61R 27,086 2h,171 24,80 R 22,92 Q 20,/1')7 17,306 13,3112 10.25 27,R2R 27,h97 27,250 26,43 /.1 25,189 2~,4118 21,136 1R,171 111,1I60 CO 10.50 27,A21 27,757 27,391 26,671 2S,<;39 23,'130 21,772 lR,Q84 lS,L179 10.7S 27,799 27,1'100 27,S11 26,RI:,n 2S,R59 2 /1,37h 22,31:>6 lQ,711Q 16,4110 11 .00 27,76L1 27,826 27,hll 27,070 2h,14Q'211,7BA ??,91 Q 20,1166 17,3117 11.25 27,71S 27,/<36 27,h91 27,23 11 2h,lll?2S,167 23,L134 21,DA lR,201 ......11.S0 27,65S 27,A31 27,753 27,~76 26,649 2S,51S 23,Ql1 21,767 lQ,OOS ......11.75 27,583 27,All 27,797 27,497 26,R60 25,R33 2/1,3511 22,3','5 19,760 12.00 27,119Q 27,778 27,825 27,')98 27,048 26,123 24,763 22,Q03 20,470 -l )::> CO Irn CO I W 5 APRIL 79 ALASKA PowER AUTHORITY ANCHORAGE _FAIRBANKS INTERTI~ ECONOMIC 'FEASIBILl TV S1 UDY DIFFERENTIAL DISCOUNTED VALU~OF BASE YEAR (197C1)'COSTS INDEPENDENT SYSTEM COSTS MINUS INTERCONN~CTED SYSTEM COSTS (IN $1000) __________________________________ESCALATION RATfS ---------------------------------- DISCOUNT I.li.57-67-7i.8i.9i.10i.11'Z 12% RATE ------------------------------------------======------------------------------------------------------ B.OO 30,913 30,276 29,194 27,595 25,399 22,515 Hl,844 14,275 8,685 8.25 31,014 30,476 29,51 1 28,050 26,015 23,319 19,B65 15,546 10,243 8.50 31,094 30,649 29,796 28,IJ67 26,586 24,070 20,824 16,746 11,720 B.75 31,153 30,798 30,051 28,848 27,115 24,771 21,725 17,878 13,1 17 9.00 31,1 92 30,922 30,278 29,195 27,604 25,425 22,571 18,945 14,440 9.25 31,212 31,024 30,1177 29,509 28,053 26,033 23,363 19,950 15,689 9.50 31,214 31,104 30,650 29,793 28,466 26,597 24,104 20,895 16,870 9.75 31,199 31 ,164 30,798 30,046 28,844 27,120 24,796 21,783 17,985 10.00 31,169 31,201.l 30,923 30,271 29,188 27,604 25,442 22,617 19,035 10.25 31,123 31,225 31,025 30,470 29,500 28,049 26,042 23,398 20,025 CO 10.50 31,063 31,229 31,106 30,642 29,781 28,458 26,601 24,130 20,957 10.75 30,990 31,216 31,166 30,791 30,033 28,832 27,118 24,813 21,833 11 .00 30,903 31,188 31,208 30,916 30,258 29,17 11 27,596 25,451 22,655 I-'11.25 30,805 31,Jll4 31,231 31,019 30,455 29,483 28,037 26,04<;,23,427 N 11.50 30,695 31,086 31,236 31,100 30,628 29,763 28,443 26,597 24,149 11 .75 30,575 31,015 31,226 .31,162 30,777 30,014 28,814 27,110 24,824 12.00 30,444 30,932 31,199 31,205 30,902 30,238 29,154 27,583 25,455 -i )::> t:Or- rr1 CO I +::> 5 APRIL 79 ALASKA POwER AUTHORITY ANCHORAGE -FAIRBANKS INTERTIE ECONOMIC FEASI~ILITY STUDY '.._--- DIFFERENTIAL DISCOUNTED VALUE OF BASE YEAR (1979)COSTS INDEPEND~NT SYSTEM COSTS MINUS INTERCONNECTED SYSTEM COSTS (IN $1000) ----------------------------------ESCALATION RATES ---------------------------------- DISCOUNT 4i.5i.6i.7i.-8i.97-10i.1 i x 12i. RATE ------------------------------------------------------------------------------------------------------------ 8.00 21,225 20,637 19,6911 18,339 16,509 14,133 11,132 7,418 2,8"'6 8.25 21,319 20,1:110 19,960 18,715 17,0111 14,71\7 11,9"8 8,443 4,149 8.50 21,397 20,962 20,202 19,062 17,41:13 15,399 12,736 9,412 5,337 8.75 21,1l"8 21,095 20,ll20 19,381 17,920 15,9'13 13,'~69 10,321\6,'~61J 9.00 21,503 21,209 20,&16 19,6'13 18,.324 16,509 Ill,1".>7 11,193 7,531 9.25 21,554 21,305 20,790 19,939 18,699 17,009 14,804 12,00H 8,"41 9.50 21,551 21,385 20,9i.l3 20,11:10 19,Oll4 17,475 1".>,410 12,777 9,496 9.75 21,554 21,448 21,078 20,399 19,361 17,908 15,978 13,501 10,LIl)0 10.00 21,"45 21,496 21,1 93 20,".>95 19,652 18,310 16,"09 14,181 11,L>5.5 10.2')21,525 21,529 21,291 20,770 19,918 18,682 17,005 14,8?1 12,05H 10.S0 21,493 21,548 21,372 20,924 20,159 19,025 17,467 IS,4<'1 12,817 00 10.7')21,450 <'I,S')5 21,45R 21,060 20,578 19,.3112 17,897 15,983 13,532 11.00 21,3'18 21,S49 21,4.R8 21,177 20,574 19,652 18,296 16,509 14,205 .....11.2S 21,356 21,"51 21,525 21,277 20,750 19,897 18,666 17,001 14,1337 w 11.50 21,2b5 21,502 21,5i.l5 21,360 20,905 20,138 19,007 17,459 15,451 11.7')21,11.\"21,462 21,55ll 21,427 21,042 20,3"7 19,322 17,886 1",'181:1 12.00 21,09R 21,413 21,551 21,ll79 21,161 20,55ll 19,611 18,282 16,"09 ~ o:Jrrn 00 I (Jl 5 APRIL 79 ALASKA POwER AUTHORITY ANCHURAGE -FAIRBANKS INTERTIE ECUNUMIC FEASIBILITY STUUY DIFFERENTIAL DISCOUNTED VALUE OF BASE YEAR (1979)COSTS INDEPENDENT SYSTEM COSTS MINUS INTERCONNECTED SYSTEM COSTS <IN $1000) __________________________________ESCALATIUN RATES ---------------------------------- DISCUUNT I.Ik 5%6%7'1.8%9:>:10%11%12% RATE ------------------------------------------------======------------------------------------------------ 8.00 25,01.12 21.1,722.21.1,063 23,008 21,491.1 19,450 16,798 13,1.151 9,313 8.25 2.'),074 24,829 24,2')9 23,309 21,918 20,019 17,534 11.1,381 10,465 8.50 25,090 21.1,916 24,431 23,51:l2 22,309 20,548 18,224 15,256 11,551.1 8.75 25,091 24,985 24,':>81 23,828 22,668 21,039 18,869 16,079 12,':>83 9.00 25,078 2~,036 24,109 24,048 22,996 21,494 19,472 16,853 15,551.1 9.25 25,(}51 2'),07U 24,811 24,243 23,296 21,915 20,034 '17,579 14,469 9.50 25,011 25,089 21.1,906 21.1,410 23,567 22,302 20,557 18,26U 1':>,332 9.75 21.1,958 25,092.21.1,916 24,506 23,1:l12 22,61;,9 21,01.13 18,89"16,143 10.00 24,895 25,081 25,029 24,696 24,032 22,985 21,494 19,493 16,900 10.25 24,820 25,057 25,Uoo 24,805 24,228 23,283 21,911 20,048 17,623 cc 10,.50 21.1,135 25,020 25,087 24,1:)95 24,401 23,':>53 22,;396 20,506 18,295 10.75 2L1,641 24,971 25,093 24,968 24,552 23,797 22,049 21,01.17 18,924 11.00 2L1,S.H 24,910 2S,OB4 25,023 24,oB2 24,017 22,974 21,494 19,513 11.25 24,425 24,1:)39 25,063 25,061 21~,793 24,213 23,2'10 21,901 20,063 ......11.':>0 24,305 24,757 25,029 25,084 24,l:)tl5 24,31:)6 23,539 22,2B9 20,575 ..j:::a 11.75 24,1'17 21.1,666 24,9132 25,093 24,9')9 24,':>38 23,7B3 22,640 21,052 12.00 24,042 24,560 24,925 25,01:17 2S,015 24,669 24,002 22,902 21,QQQ --..i :J=oc::or rr1 co I 0) CHAPTER 9 FINANCIAL PLANNING CONCEPTS !l CHAPTER 9 FINANCIAL PLANNING CONCEPTS The approach taken in this study towards the financial planning for the ~"intertie facilities represents the preliminary conceptual structuring of the ultimate financial package needed to implement the Railbelt transmis- sion system expansion on a progressive basis.This approach seeks to be demonstrative of the methodology employed,rather than an attempt to arrive·at specific recommendations.The acceptance of debt allocations by participants to the Alaskan Intertie Agreement (AlA)will require individual financial positions to be evaluated,prior to negotiations on specific portions of the total debt for which a particular participant will ultimately agree to sign.Therefore,what follows is an initial exploration of possible financial arrangements,and will serve as a starting point for successive evaluations by each potential participant to the AlA. 9.1 SOURCES OF FUNDS An initial appraisal of viable sources of funds has been made to deter- mine the combination which will represent the most financially advan- tageous terms and also will reflect the projected allocation of finan-,- cial responsibility that may be acceptable to each of the participants. The following principal sources were examined: •State of Alaska revenue bonds floated by APA. •REA loans negotiated by APA and participants...CFC loans negotiated in conjunction with REA loans...FFB loans negotiated by APA and participants. •Municipal bond issues by Anchorage and Fairbanks. The conditions under which each of the above sources would be negotiable are dependent upon the ability to generate revenue to make repayment. 9 - 1 A.State of Alaska Revenue Bonds Of tnese sources,the issue of State of Alaska bonds would require the most complex formula for revenue generation,to arrive at an acceptable agreem~nt to ensure complete payback through time on a steady cash flow basis.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 facil- ities.Accordingly,although programmatic inclusion of APA bonds is retained in the Transmission Line Financial Analysis Program (TLFAP), for present analytical purposes,consideration has been given only to the remaining sources for analysis of initial financial plans for 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.Only the financial sources discus- sed in the following sect~ons were then considered for initial funding of.the Anchorage-Fairbanks Interconnection. B.Rural Electrification Administration (REA) The principal participants,with the exception of the Anchorage and Fairbanks municipal systems,are all REA utilities of the Alaska Dis- trict.Th~refore,REA funding is assumed for the ma~imum amount of total project financial requirements.In accordance with REA st{pula- tions,the loan ceiling is normally 70 percent of total project costs. Thus, a maximum of the full amount under the 70 percent ceiling was considered for the prime source of funds,at an interest rate of 5 per- cent over a repayment period of 35 years. Although not considered at this first level of financial planning,REA also makes guaranteed loans,which normally are made for prevailing interest rates of the order of 8-1/2 percent. 9 - 2 I,, .' OMB restrictions are expected to reflect through future REA commitments for project funding.Therefore,with the large capital outlay necessary for the intertie,it may be necessary to consider alternative sources of supplementary capital to structure a complementary loan package for the project.The Consultants have accordingly considered the CFC and FFB as part of financial contingency plans. C.National Rural Utilities Cooperative Finance Corporation (CFC) The CFC makes loans to REA utilities to supplement REA funds,with loans that are currently carrying an interest rate of 8.75 percent,with a re- payment period of 35 years.To structure a loan package for the balance of project costs,CFC funds would be drawn on to the extent justifiable under the primary criteria of providing the most advantageous overall financial terms. D.Federal Finance Bank (FFB) The FFB also provides supplementary funding,complementary to CFC as a financial source,with loans that bear interest at a higher rate than that to be obtained from CFC.Currently,the interest rate for FFB loans is 9.375 percent for project funding,with a repayment period of 35 years. 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.For purposes of analysis,the interest rate was assumed to be 7.5 percent under prevailing market conditions,with a maturity period of 35 years.These terms are to be construed as conserva- ~ive under present market conditions.In practice some measure of improve- me~t can be anticipated depending upon prevailing economic and financial considerations at the time of entry to the bond market. For purposes of illustration,a final interest rate of 7.25 percent was assumed to simulate the progressive improvement of terms anticipated for this project. 9 - 3 Thirty percent of the total project costs are assumed to be funded by municipal bonds, which is deemed reasonably reflective of the participa- tion of the municipal systems in the Alaskan Intertie Agreement.It also is the complementary portion of total project costs that would meet the ceiling of the maximum REA loan available to member utilities. 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 proportional allocation of total project costs between possible sources will require protracted effort on the part of APA and AlA participants,in the successiv&negotiations with REA and other federal funding agencies,together with the officials respon- sible for decisions relating to issuance of municipal bonds. To assist with an evaluation of financial positions in relation to possible agreement on resolution of questions pertaining to proportional allocations between sources,the Consultants offer the following approach for initial consideration: •REA funds would be used to the limit of the normal 70 percent ceil ing, as a proportion of project costs.If due to budgetary restraints REA is not amenable to funding the full proportion, supplementary loans would be sought from a combination ofCFC and FFB. •The balance of funding,30 percent of projects costs,would be obtained through a joint issue of general obligation bonds, by the municipalities of Anchorage and Fairbanks. In.preparing a financial plan to follow this approach the following analysis was completed using computer programs TLFAP and COMPARE. 9 - 4 "'.:: ,( ( 1.An initial run of TLFAP was made with the following allocations and assumptions for funding terms and conditions: •70%funding by REA loan,at 5%interest rate. •30%funding by general obligation municipal bonds,with equal division of obligation between Anchorage and Fairbanks~ A conservative rate of 7.5%was assumed for this issue. •35-year repayment period for both sources. 2.On the assumption that REA funds would have to be supplemented by loans arranged jointly with CFC and FFB,an analysis was made of a 20%portion of the total REA a 11 ocat ion,to i 11 ustrate the capability of minimizing total financial obligations through judicious combinations within the package. This was accomplished using program COMPARE,which derives the present value of future ,, payments for up to three loan sources under varying loan terms. To simplify the procedure,a similar repayment period of 35 years was assumed with base case and sensitivity runs,as follows: •Equal division 10/10%between CFC and FFB,with interest rates of 8.75%and 9.375%,respectively. •Sensitivity runs of +5%for both CFC and FFB,in converse proportion,at the same interest rates. 3.The best of the three test-cases,selected on the basis of least present value to borrower,was then substituted in TLFAP, with 'the following modifications to previous input of 1. above. •50%allocatio~to REA funding @ 5%interest rate. •20%source allocation;divided between CFC and FFB according to the results of the COMPARE analysis: 15%of total by CFC loan at 8.75%interest rate 5%of total by FFBloan at 9.375%interest rate This combination results in the lowest present value of the three alternative divisions,presented on Sheets F-7, F-8, and F-9 of Appendix F. 9 - 5 •30 %source allocation to municipal bonds at an improved interest rate of 7.25%,to indicate possible positive offset to the higher composite rate resulting from the combination of loans from CFC and FFB. The results of this analysis are contained in Appendix F. 9.3 ALLOCATED FINANCIAL RESPONSIBILITY FOR PARTICIPANTS A.Basis for Assumption of Financial Obligation Once the source allocations are determined,the next step involving dis- cussions,evaluations,and negotiations between the participants is the determination of the allocated responsibility for debt assumption and subsequent service over the repayment period.The approach fol- lowed was to match percentage of total funds to the AlA participants on the basis of service jurisdictions,potential benefits from facil- ities,and a certain judgement in relation to the acceptabilitY,or otherwise,of certain allocations to individual participants.A degree of tokenism was also judged to be appropriate at this initial stage,to allow for minimum funding partiCipation by utilities without major generating plants. This enables all utilities,that are directly affected by the inter- connection to take a major or minor share of the responsibility for debt service of the total facility costs in support of the project. The only utility which is not an immediate direct beneficiary of the intertie is CVEA.Although TLFAP contains a provision for later pattic~. ipation by this utility,it is not anticipated·that CVEA will exercise this option prior to the connection of the Glennallen-Valdez system to the intertie,at or before completion of the first stage development of the Upper Susitna Project. 9 - 6 B.Allocation of Total Pr~ect Costs Table 9-1 provides a division of total project costs on a percentage basis and a subsequent allocation between participants~This pre- liminary set of debt service allocations was used for the financial planning projections contained in Appendix F. These may be used by individual participants as a starting point for their own analysis and evaluation of the impact of their assumed obligation on their own financial operations. The allocation of costs was aided by considering the logical division of the total facility into three sections: Section From To Distance (Miles) I Anchorage Palmer 40 II Palmer Healy i91 I III Healy Ester 92 The costs included in Table 9-1 pertain to Case ID transmission facil- ities,single-circuit 230 kV transmission line with intermediate switch- ing at Palmer and Healy. This also allows the realization of investment participation by MEA in the AlA to the extent indicated in Table 9-1. Although the benefits of the interconnection are more indirect for HEA, a small percentage participation in the intertie project is included for this utility. C.'Effect of Sinking Fund on Total Revenue Requirements In evaluating the revenue requirements for each participant to the AlA; the cumulative effect of the municipal bond sinking fund on the allocated debt repayment should be noted.The total revenue required from each participant is indicated on pages F-8, F-9,and F-10 and F-19, F-20, and F-21 of Appendix F,and includes both debt service and sinking fund payments over the 35-year period,to full loan amortization and bond maturity. 9 - 7 9.4 FINANCIAL PLAN FOR STAGED DEVELOPMENT The fo11 owi ng is intended as one poss ib1e vi ew of future plans for fi nanc- ing successive expansions and extensions of the initial 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 oth~r 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 partic- ipants. One possibility for application of m~or 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 token allocation,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 the transmission system associated with the development of Susitna hydropower. B.Expansion of a Susitna Transmission System The implementation of the Susitna Hydropower Project would requtre that a comprehensive financial plan be followed for funding the generation proj- ect and associated transmission facilities.The large increments of firm .power possible from the Susitna development would reqUire the expansion of the initial intertie,to receive the energy blocks for transmission to Anchorage and Fairbanks. 9 - 8 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 participants,on a similar basis to that used for this initial approach to first stage financing of the transmission system. interconnection via the Railbelt. 9.5 REFERENCES 1.International Engineering Company,Inc. Financial Planning Model 2.Moody's Bond Record 'Tax Exempt Bond Yields by Ratings' 'Tax Exempts Vs.Governments and Corporates' January 1979 9 ~9 TABLE 9 - 1 ALLOCATION OF TOTAL PROJECT COSTS BETWEEN PARTICIPANTS TO ALASKAN INTERTIE AGREEMENT A I A SECTIONAL INTERCONNECTION DIVISIONS Anchorage Palmer Healy Ester I Section I I Section II I Section III I 40 M 191 M 92 M '-0 INTERTIE COMPONENTS PROJECT COSTS -1979 $1000 (%)TOTAL FACILITY ......Transmission Line 6644 (10)31,726 (46)15,282 (22)53,652 (78) 0 Substati ons: Anchorage 3976 (6)3,976 (6) Palmer 717 (1)717 (1)1,434 (2) Healy 717 (1)717 (1)1,434 (2) Ester 5,080 (7%)5,080 (7) Control &Communications 1,450 (2)400 (1)1,450 (2) 3,300 (5) TOTAL 12,787 (19)33,560 (49)22,529 (32)68,876 (100) AlA PARTICIPANTS ALLOCATIONS OF TOTAL PROJECT COSTS (~) AM&LP (5)(10)(15) CEA (10)(20)(30) HEA (1)(1) MEA (3)(3) CVEA (9)(27)(36) FMUS (10)(5)(15) CHAPTER 10 INSTITUTIONAL CONS lOERA TI ONS CHAPTER 10 INSTITUTIONAL CONSIDERATIONS The Intertie Advisory £ommittee 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 uti 1i ty systems in the Ra i 1be It. 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. •Golden 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 lito supply power at the lowest 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". 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 "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 proj ect , 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 participating utilities over the large geographical area encompassed. B.Jurisdiction and Service Territories The Alaska Power Authority exercises jurisdiction 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 u 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 AlA,it is suggested that the name Alaskan Interconnected Utilities (AIU)be adopted by the existing Railbelt 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 operati~g utilities in the Anchorage and Fair- banks areas have already evolved mutual interests.These interests now need to be augmented,to satisfy future operating 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 determine oper- ating procedures and coordinate system planning policy,working towards centralized economic dispatch for the interconnected system.The need ,for improved communications facilities will also need to be addressed, together with the mode of overall system control and data acquisition for interconnected facilities. 10 - 3 fl I j [J I 'i !J u 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 hydropower 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 impact 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 U lJ 10.3 REFERENCES 1.Battell e Paci fic Northwest Laboratories,Al aska El ectric Power: An Analysis of Future Requirements and Supply Alternatives for the Railbelt Region,March 1978. 2.University of Alaska,Institute for Social and Economic Research, El ectric Power in Al aska 1976··1995,August 1976. 3.House Bill 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 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- ducti ve. 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 can assign some of their resources to enhancing their lives.The home computer with its implications of many more "r obots"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-I \; exceeded,if the rising standards of Alaskan life are maintained into the fut~re. 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 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, el~ctricity and his representatives is believed extra difficult todnY because of environmental cdncerns,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-l. This table contains the 35~year history of MEA and a 20-year forecast based on the data in the LQng-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 ~...~-~',._<._' MEA STATISTICAL SUMMARY -PAST,PRESE~7 AND FORECAST Ave.No.Ave.No.Miles Const.Ave.Cost Average Average Average Average Portion Served (w/o LP)of Per Purch.Revenue Revenue Bill/Const.Family of Average Average Line Mil e Power Total Sales (w/o LP)(w/o LP)Income Income Year kWh/Mo.kWh/Mo.Dist.Trans.Dist.$/k~/h $/k~/h S/kWh $/Mo.2.L Mo•Percent (1)(2)(3)(4)(5) (6) (7)(8) (9)(l0)(11) 1942 210 188 90 2.3 0.020 0.0628 0.1074 5.07 175 2.9142470 1954 1401 1393 313 4.5 0.0196 0.0450 0.0531 17.82 590 3.02-m j"j5"0 1966 3134 3113 708 4.4 0.0114 0.0348 0.0366 25.40 885 3.995I69463 1977 9434 9352 1430 6.6 0.0128 0.0359 0.0368 48.50 2248 2.4T57B"TII8 -gr See Footnotes Level I 16693 16510 2212 7.5 0.0187 0.0546 0.0559 99.78 3303 3.02('82-85')2100 1785 241 Level II 30510 30060 2705 11.3 0.0348 0.0692 0.0705 175.30 4853 3.60('87-'92)2799 22f88 269 Level III 55744 54956 3041 18.3 0.0488 0.0829 0.0837 292.45 7131 4.10('92-'99)37I4 3494 293 The basic historical data was taken from the REA From 7.Each column is explained as follows: (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 when these levels might be reached. (2)The total average number 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 (kWh)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 I, II 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 III the figures resulted from a generalized forecast of costs using the investments indicated by the Long Range Plan escalated at 7%per year,the operating costs per consumer escalated @ 7%per year and the purchased power costs "of Col- umn (6).It was also assumed that there would be 10%losses of energy and that MEA 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."(Publ ic 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 numbers at 1.08 per year which is the approximate average growth rate of income for the 1ast 35 years". (ll)Column (9) divided by Column (10)multiplied by 100. -l ::t:>co I (TJ ::t:> I..... APPENDIX B TRANSMISSION LINE COST ANALYSTS PROGRAM (TLCAP) APPENDIX B TRANSMISSION LINE COST ANALYSIS PROGRAM (TLCAP) B.1 GENERAL DESCRIPTION The Transmission Line Cost Analysis Program (TLCAP)calculates the in- stallation,operation,and maintenance costs of a transmission ljne using a detailed unit cost model.It also automatically determines the lI opt imum li span and conductor size combination.Applications include the following: •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 l t ~ .t 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 ·'ines,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 level. B-2 i \ \ 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 advant.aqeous 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 IIl owe st initial cost solution ll 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 dc, metal or wood. •Foundation costs. •Wind and ice load criteria,and their effect on tower cost through transverse,vertical,broken-wire,and/or construction loads. •Number and strength of insulators. •Insulator swing and air gap. e 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-l.Briefly,program elements include: B-3 TRANSMISSION LINE COST ANALYSIS PROGRAM (TLCAP) METHODOLOGY FIGURE B-1 ri .I I Tower Des i gn Studies I \V Tower Weight Estimation Algorithm Electrical &Mechanical Ri ght-of-Way Cos tl Performance Specification \II \I \J "-----''---Unit Materi al &-(Transmission Line Cost ~System Economic Labor Costs -Analysis Program -Parameters I 1\I .\ Transportation Costs Inflation Rates \I \II \V Input Detailed Optimum Span & Data Design &Conductor Cost Summaries Capital Cost Summaries Summaries B - 4 i, I I,, [ ) •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 initalled 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 present 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-I). •Devil Canyon -Ester,230 kV (Case II-2A). •Watana - Devil Canyon,230 kV (Case 11-3A). B - 6 INTEkNAfIONAL ENGINE~RING co.INC SAN FRANCISCO Cf,LTFORNIA TRANSMISSION LINE COST ANALYSIS PROGRAM VeRSION 1:23 FEB 1979, ANCHORAGE-FAIRBANKS INTERTIt CASE IA . 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:Z9:Q7 ****************** **INPUT DATA ** t:d I -.:J SYSTEM eCONOMIC FACTORS----------------------- STARTING YEAR Of STUDY ENDING YEAR or STUDY BASE YEAR FOR ESCALATION ~II\XI"1UM CIRCUIT LOADING AvERAGE CIRCUIT LOADING DEMAND COST FACTOR EMERG~COST fACtOR VilR COST F A.CHHI CAPITAL COST/DISCOUNT RATe: MINIMUM MAXIMUM NUMBER OF INTERVALS O&M COST FACTOR RIGHT OF wAY COST FACTOR RIGHT OF WAY CLEARING COST .INTERESl DURING CONSTRUCTION ENGINeERING FEE ******************** INPUT VALUE ----------- 1979 1996 1977 13b.8 MVA 111.0 MVA 73.0 $/KW 13.0 MILLS/KWH 0.0 $/KVAR 7.0 PERCENT 10.0 PERCENT 1 1.5 %CAP.COST 715.0 $/ACRE lQ30.0 $/ACRE 0.00 X INST.CST 11.00 %INST.CST REFERENCE YEAR FOR INPUT------------------------ 1992 1992 1979 1979 19H1l 19a1l 19S11 1979 1979 1979 ANCHORAGE-~AIRaA~KS INTERTIE CASE IA ?30 KV TRANSMISSION LINF COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 7q TIME:q:?q:q7 *******••********* * * * INPUT DATA * ** COM\iJC TOR I)"TA **••••••**•••****. GROUNDwIRE DATA SPAN DATA--------------------------------------- to I 00 "l11"11F ~-r 1<I'HA SE Crl"l!)UCTor<SPAC!tJ(; VUL[AGf: VliLTAGc'VARIAIIll'i L PiE FP~[JUf:NCY FAr:'''EhfHf:.R LiJSSFS Ll ~J I:L r ,I GTI-l PU,JER F.\C Tf1R WF!dHER DATA 1 O. ()IN 230 KV 10.00 pcr bO CPS 0.00 Kw/MI 323.00 MILES 0.95 NUMBER PER TOwER DIAMETER WEIGHT o 0.00 IN 0.0000 LRS/FT MINIMUM MAXIMUM INTERVAL 1200.FT 11:>00.FT 100.0 FT "lAXI".I;·'RAINFALL HATE 1 • I f\IN/HR I~t.Xl '·1'F'RAI NI-ALL [)IHI AI ION 1 IfRS/YR A\['If.Gf la TtJF ALL tlATF 0.03 IN/HR AvF.'<AGF RA P.JF ALL DUll ATI O~I b3b HRS/YR "1 AXI f·11.W 5tJllWl-ALL RAI E 1.R7 IN/HR 'U XI ~'.J ~l S un wF ...LL Dl)PATION 1 HRS/YR AV!:RAGf StHh'Jr AI.L Ii A[E 0.1'3 IN/HR AV F ~.\[;1-SNOwFALL DURATION 2M HRS/YR Rt LATI Vf.All<DENSITY 1.0'00 ANCHORAGE-FAIR8ANKS INTERTIF CASEIA 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION .DATE:12 APR 7~TiME:q:29:47 ****************** ***INPUT DATA * ******************** SAG/TENSION DESIGN FACTORS-------------------------- tl:l I ~ EVERYOAY STRESS TEMPERATURE ICE AND WIND TEMPERATURE HIGH WIND TEMPERATURE EXTREME ICE TEMPERATURE MAX DESIGN TFMP fOR GND CLEARANCE EDS TFNSION (PCT UTS) NESC CONSTANT TOTAL NUMBER OF PHASES PHASE SPACING CONDUC TOR CONF IGURAT ro«FACTOR GROUND CLf Af?AtJCE NO.OF INSULATORS PER TOWER INSULATOR SAFETY FACTOR STRING LENGTH I,VEE,OR COMAINATION HJUNOAlICJN TYPE TERRAIN FACTOR LTNE ANGLE FACTOR TOWER GROUNDING TRANSVERSE OVERLOAD FACTOR VERTICAL OVERLOAD FACTOR LOI~GIT\JOINAL LOAD MiSCELLANEOUS HARDwARE WEiGHT tO~ER WEIGHT fACTOR TO~ER WEIGHt ESTI~AIION ALGORITHM --------------------------------- 40.DEGREES F O.DEGREES F 40.DEGRtES F 30.DEGREES F 120.DEGREES F 20.PERCENT 0.31 LBS/FT TOWER DESIGN 3 20.0 FEET 1.02 28.0 FEET 48 2.':>0 6.5 FEET 3 4 1.06 PER UNIT .0864 o 2.50 1.50 1000.LI:3S 0.11 TONSlTowER 1.02 ICE AND WIND TENSION (PCT UTS) HIGH WIND TENSION (PCT UTS) EXTREME ICE TENSION (PCT UTS) ICt THICKNESS WITH WIND WIND PRESSURf WITH ICE HIGH ~IND EXTREME ICE DISTANCt BETWEEN PHASES: Dl D2 D3 [)ll Dr; Dr. 50.PERCENT 50.·PERCENT 70.PERCENT 0.50 INCHES 4.00 LBS/SQ.FT. 9.0 lBS/SQ.FT. 0.50 INCHES 20.00 FT ?O.OO FT 40.00 FT 0.00 FT 0.00 fT 0.00 FT TOWER TYPE 9:230KV TOWER T~=O.OOOlh*TH*~?-3.09797*TH**0.3333 -O.OA9113*fFFVDL - O.?71b7*ffflUL +Q.OO~10*TH*EfFTDL +O.OOlbO*TH*~FFVUL+ 18.37917 KiPS '--.......--: ANCHORAGE-FAIRBANKS IN{EMTIE CASE IA 230 KV TRANSMISSION L[NE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIME:9:29:1I7 xx********x**x**x* **x INPlJT DATA * ** ****************** CONDUCTOR SUMMARY ******••********. TEMP.COEF. STRANDING UNIT WEIGHT OUT.DIAM.TOTAL AREA MODULUS ALPHA*E.-6 If)~HJ"'AER NAME:.SI7ECKCM)(ALlST)(LBS/FT)(INCHES)(SI).IN.)(H1E6 PST>PE.R DE.G F -------------------------------------------------------------------------- 211 Gf<f1SBEAK 636.0 261 7 0.8750 0.9900 0.5809 11.00 10.3 t:P ?:.EGRET 650.0 50/19 0.9880 1.0190 0.b1311 11.50 9.7 I 20 FL AM I NGll 606.0 2111 7 0.8590 1.0000 0.59111 10.55 10.7 I-' 0 27 GA"lt,jfT 61:>6.0 261 7 O.qUIO 1.01110 0.6087 11.00 10.3 21-\STILT 715.0 2111 7 0.9210 1.0360 0.6348 10.55 10.7 29 STARLING 715.0 201 7 0.9f\50 1.0510 0.653':>11.1l0 10.3 ')0 Rf:.Dv;PIG 715.0 30/19 1.1110 1.0810 0.6901 11 .30 9.7 ')1 CUCKOO 795.0 21.11 7 1.021.10 1.0920 0.7055 10.':)':>10.7 32 lHIAI\F 795.a 261 7 1.091.10 1.1080 0.7261 11.00 10.3 B -TERN 795.0 451 7 0.8960 1.0630 0.6670 9.1.10 11 .5 SlI CO"lDllR 795.0 541 7 1.02110 1.0930 0.70c;3 10.85 10.9 35 ~'ALLAIW 795.0 30/19 1.23':>0 1.1LtOO 0.7668 11.30 9.7 31>RUDDY 900.0 lI51 7 1.0150 1.1310 0.7069 9.40 11.5 H CANARY 900.0 ':>1I1 7 1.1590 1.1620 0.798':>10.85 10.9 38 RAIL 9':>4.0 451 7 1.0750 1.1650 0.8011 9.40 11.5 39 CARDINAL 9511.0 541 7 1.2290 1.1900 0.All6ll 10.85 10.9 ---- ANCHORAGE-FAIRBANKS INTERTIf CASE II 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 7~TIMt:9:29:47 **************•••• ** *INPUT DATA * *********••********* CONDUCTOR SUMMARY **••*****.**.***. AC RESIST. ULT.TENS.GfOM.MEAN THf:.RM.LlMIT AT 25 DEG C INO.REACT.CAP.REACT. I I)'JIJ"lfH:.R NAME STRfNGTHCLAS)RA()IUSCFT)PRICE($/LB)(AMPf-RES)(OHMS/MILE)(OHMS/MILE )(MQHM-MILf:S) ------------------------------------------------------------------------------------------ ?ll r,,,,nSHEAK 2')000.0 0.0~~5 0.628/1977 790.0.lll52 0.4118 2.63117 tx:l 25 F Gf?l T 31S00.0 0.0351 0.609/1977 870.0.lllll7 0.ll060 ~.o136 I ?b FLAMINGO 23700.0 0.0335 0.6ll0/1911 810.0.1399 0.lll18 2.629tl I-' I-'n f,ANI.El 2b200.0 0.0343 0.609/1977 820.0.1373 0.4092 2.63tl7 ?H S1 IL T 2':>SOO.O 0.<>-)47 o•6?7 11917 A40.0.1320 0.4066 2.641)0 29 S1ARLING 2HI00.0 0.03';5 0.b08/1977 850.0.1294 0.40S0 2.b1l53 ~O RflH·d NG 3 IJ6()0.O 0.0372 0.612/1977 ~60.0.128A 0.3992 2.';661 51 CUCKOO 27100.0 0.0366 0.636/1971 900.0.121tl 0.3992 2.5502 1,2 DRAKE 31?00.0 0.0375 0.622/1 977 910.0.1172 0.399?2.5450 B HIHJ ??qOO.O 0.0352 0.67711977 ~90.0.118A 0.406l)2.')106 34 CO'JOOR 2WiOO.1)0.0~68 0.635/1977 900.0.117?O.llon?2.55<;5 ~5 MALLARD ~8IJOO.0 0.0392 0.599/1977 910.0.1162 0.3928 2.5186 1,6 RUDDY 25 IJOO.O 0.0374 0.676/1977 935.0.1-082 0.'39?8 2.')01'10 H CANARY 32~OO.0 0.0392 0.633/1977 950.0.1040 0.3928 2.5027 1,8 RAIL 26900.0 0.0385 0.671/1977 970.0.09'18 0.39119 2.5027 ~9 CARDINAL 34200.0 0.0404 0.63211971 990.0.0987 0.3902 2.1181b A~CHORAGE-FAIRHANKS INTERl1f CASE 1A 230 KV TRANSMISSION LINE tOST ANALYSIS AND CO~OUCTOR OPTIMIlATION DATE:12 APR 79 TIME:9:29:Q7 k**k************** * *k INPUT DA TA * * * td I..... N UNIT MATERIALS COSTS prncr OF TIlwtR MATERIAL PRICE OF CONCRElE PRICE OF GROUND wIRE INSTALLED COST OF GROUNDING SYSTEM TOwER SPUP TOWER ASSntAl Y FOUNDA TION SETUP FOUNDATION ASStMHLY FOUNDATION txCAVATION PRICE OF MISCELLANEOUS HARDWARE UNIT LAIjOR COSTS REFFRENCE YEAR LABOR COST STRP,G GROll"lD WIRE STRING LABOR MARKUP llNIT TRANSPORTAllON COSTS TOWER FOUNDATION CONCRETE FOUNDATION STEEL CONDUCTOR GROUND lHRE INSULATOR HARDwARF *.*****.**.****.6* INPUT-VALUE 0.957 $/LB 0.00 $/ClJ.YD. 0.000 $/LB 0.00 $/TOWER 1751.$ 0.4'.,5 $/LB O.$ 41QO.00 $/TON 0.00 $/CU.YD. 290.00 $/TOWER 24.00 $/MANHOUR 0.0 UMILE 4.2 PER UNIT 100.0 $/lON 100.0 $/YO 100.0 $/TON 100.0 $/TON 100.0 $/-TON 100.0 $/TON OR $/M**3 100.0 $/TON REFERfNCE YEAR FOR INPUT 1979 1977 1977 1977 1979 1979 1919 1979 1979 1977 1979 1977 A~CHOKAGE-FAIRAANKS INTEHTIE CASE IA 230 KV TRANSMISSION LINE COST ANALYStS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:2q:47 **•••****.**.**••••**.************~*.* ** **• AUTOMATIC CONDUCTOR SELECTION ALL QUANTITIES PER MILE * * *•*.***••******••••**~••***•••*****.*.* CAPITAL COST/DISCOUNT RATE OF 7.00 PERCENT ------------------------------------------- ANCHORAGE-FAIRBANKS INTERTIF CASE IA2~0 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:Q:29:47 ******.*••*•••***•••••***••*•• *• •COST OUTPUT PER MILE • •PRESENT VALUE RATE • •7.00 PERCENT • **••••*•••••**••••••••••••••••*. CONDUCTOR NUMBER =39 954.KCMIL 1300.FT SPAN 87.7 FT TOWfR-------_._---------------------------------_._------ INStALLE"D COST MATfRIAL TRANSPORTATION INSTALLA TION TOTAL ARI:.AKOOWN iJLJAN TITY COSTeS)TONNAGE COSH$)COS H S)CaSTeS) ---------------------------------------------------------------------- t;d CONDUCTOR 15/HIO.FT 14086.9.73 973.182'.)7.33316. I ~GROLJNO ..IRE:O.FT O.0.00 O.-0.o. +:-1 fIISlILh TOf.lS ?07.UNITS 1313.1.14 244.15'.)7- HARP.-lARE 1429.0.47 47.1477 • TOW!:RS 4.3 UNITS 38870.20.31 2031.26019.66921. FOUNDATIONS IJ.3 UNITS 3327.538.22280.26145. RIGHT lIF WAY 13.ACRES 9120.18?41.27301. IDC/[NGTNEI:.RltIIG 9328. 9328. --------------------------.-------------------- TOTIILS 68147.31.65 ')834.84796.1661011. PRESENT VALUE ($) ------------------------------------------------------------------ LOSS ANALYSIS DEMAND LOSSES ENERGY LOSSES TOTAL LOSSES -----------------_.--------------------------------------- RESISTANCE LOSSES 24588.7992.32580. CORONA LOSSES O.19.19. -----------------~--...------------------ TOTALS 24581~•8011.32600. to I I-' tF1 INTERNATIONAL ENGINEERING CO. INC SAN FRANCISCO CALIFORNIA TRANSMISSION LINE COST ANALYSIS PROGRAM VERSION 1:23 FEB 1979, ANCHORAGE-FAIR~ANKS INTERTIE CASE IB 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:37:07 *************••••* •*•INPUT DATA •••******••***••***** SYSTFM ECONOMIC FACTORS----------------------- STARTING YEAR OF STUDY ENOING yEAR UF STUDY BASE YEAR FOR ESCALATION MA>:IMlJM CIRCtJIT LOAI)1NG AVERIGE CJRCUIT LOADING DEMAND COST fACTOR ENERGY COST FACTOR VAR COST FACTOR CAPITAL COST/DISCOUNT RATE: MI"'I:~IJM tH x I r~UM NUM~fR OF INTERVALS O&M COST FACTOR RIf,HT OF wAY COST FACTOR RIGHT OF ~AY CLEARING COST INltRESi DURING CONSTRUCTION E1'IGIN£ERING Ftf INPUT VALUE 1979 1996 1977 130.8 MVA 1J9.2 MVA 73.0 $/KW 1.3.0 f1ILLS/KWH 0.0 $/KVAR 7.0 PERCENT 10.0 PERCENT 1 1.5 X CAP.COST 715.0 $/ACRE 1£130.0 $/ACRl O.OOX INST.CST 11.00 X INST.CST REFERlNCE YlAR fOR INPUT------------------------ 1992 1992 1<U9 1979 198£1 19f14 1984 1979 1979 1979 ANCHORAGE-FAIRBANKS INTfRTIE CASE 16 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:Q:37:07 *************w**** * ** INPUT DATA * * ******************* -----------------------------------------CONDUCTOR DATA ----------------------------------------- GROUNDwIRE DATA 1200.FT IbOO.FT 100.0 FT SPAN DATA MINIMUM Io1AXIMUM INTE.RVAL ---------------------------------------- o 0.00 IN 0.0000 LBS/FT NUMl;ER PE.R TOWER DIAMETER WEIGHT 1 (l.O IN 230 KV 10.00 PCT bO CPS 0.00 KW/MI 323.00 MILES 0.95 NUM5E~PtR PHASf CONDUCTOR SPACING VOLTAGf VOLTAGE VARIATION LI NE.FR'QUEtJCY FAIR~EATHtR LOSSES LINE LfNGTH POwER FACTOR tp I I--' 0\ W!:.ATHE.R DATA----------------------------------------- MAXIMUM RAINFALL RATE 1.18 IN/HR MAXIMUM RAINFALL DURATION 1 HRS/YR AvERAGF RAINFALL RATE 0.03 IN/HR AVERAGE.RAINFALL DURATION 630 HRS/YA MAXIMUM SNowFALL RATE 1.87 IN/HR MAX PHJM SNOWFALL DURATION 1 HRS/VR AVERAGF SNOWFALL RATE 0.-13 IN/HR AVERAGE SNowFALL DURATION 2M HRS/YR RE.LATIVE AIR DENSITY 1.000 ANCHORAGE-f~IRBANKS INTERTIE CASE IA 230 KV TRA~SMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION .DAT~:12 APR 79 TIME:9:37:07 ***.************** ***INPIlT DATA * *****************.** SAG/TENSION DESIGN FACTORS----------------.---------- b:I I..... "-.J EVfRYDAY STRESS TEMPERATURE ICE AND WIND TEMPERATURE HIGH WINO TEMPERATURE EXTREME ICE TfMPERATURE MAX DESIGN TEMP FOR GND CLEARANCE EDSTEHSION (PCT UTS) NESC CONSTANT TOTAL NUMAER OF PHASES PHASE SPACING CO~JDlICTOR CONFIGURATION FACTOR GROUND CLEARAN(;f NO.OF INSULATORS PER TOWER INSULATor,SAFETY FACTOR STRING LtNGTH I,VEE,OR COMBINATION FOll~HlA I ION TYPf TERRAIN FACTOR LINF ANGLE fACTOR TlJ...F.R GROUNDING TRANSVERSE OVfRLOAD FACTOR VERTICAL OVE~LOAD FACTOR LONG1TUDINAL LOAD MISCELLANEOUS HARDWARE WEIGHT TOwFR ~EIGHT FACTOR TO~ER wEIGHT fSTIMATION ALGORITHM ------------------.-------------- 40.DEGREES F O.DEGREES F 40.DEGREES F 30.DEGREES F 120.DEGREESF 20.PERCENT 0.31 LI:lS/FT TOWER DESIGN 3 20.0 fEFT 1.02 28.0 FEET 48 c.SO 6.5 FEn 3 4 1 .Ob PER liN IT .08b4 o 2.S0 1.50 1000.LAS 0.11 TONSITOwER 1.02 ICE AND WIND TENSION (PCT UTS) HIGH WIND TENSION (PCT UTS) EXTREME ICE TENSION (PCT UTS) ICE THICKNESS WITH WIND WIND PRESSURE WITH ICE HIGH WIND EXTREME ICE DISTANCE BETWEEN PHASES: 01 02 In D4 D5 Db 50.PERCENT 50.PERCfNT 70.PERCENT 0_50 ltJCHES 4.00 LBS/SQ.FT. 9.0 LBS/SQ.FT. O.SO INCHES 20.00 FI 20.00 Fl 40.00 FT 0.00 FT 0.00 FT 0.00 FT TOWER TYPE 9:230KV TOWER Tw =0.OOOlb*TH**2 -3.09797*TH**O.3333 -0.OR943*EFFVDL - O.?7~h7*EFFTOl +O.00510*TH*ffFTOL +O_OlllbO*Hi*EFFVDL + Itl.H'H2 KIPS ANCHORAGE-FAIRBANKS INTERTIE CASE IB 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIME:9:37:07 ********.A •••••A•• •* *INPUTDA TA * ** ••AA'.AA.**A****** CONDUCTOR SUMMARY *.A.**A.*"""** TEMP.COE"F. STRANDING UNI.T WE IGHT OUT .DlAM.TOTAL AREA MODULllS ALPHAAE-6 TO NUV.AER NAt~E SIZUt<CM)(ALISn (LBS/FT)(INCHES)(SO.IN.)(EF/E6 PSI)PER [)EG F -------------------------------------------------------------------------- 2Q GROSREAK 636.0 261 7 0.8750 0.9900 0.5809 11.00 10.3 2~FGRET 636.0 30/19 0.9880 1.0190 0.6131.1 11.30 9.7 20 FLAMINGO 666.0 21.11 7 0.8590 1.0000 0.5911.1·10.5e;10.7 to 27 GANNFT 666.0 261 7 0.9180 1.011.10 0.6087 11.00 10.3 I I-'?I:I STILT 715.0 241 7 0.9210 1.0360 0.6348 10.55 10.7 co 29 SIAr~LI1IJG 715.0 ?61 7 0.9850 1.0S10 0.6535 11.00 10.3 3il RUh;I IJG 715.0 30/19 1.1110 1.0810 0.6901 11.30 9.7 31 ClJCKOf)795.0 241 7 1.0240 1.0920 0.7053 10.55 10.7 3~DRAKE 195.0 261 7 1.0940 1.1080 0.7261 11.00 10.3 33 TllHl 795.0 451 7 0.8960 1.0630 0.6676 9.40 11.5 3'1 C(J1IJDOR 79e;.0 541 7 1.021.10 1.0930 0.7053 10.85 10.9 3~MALLARD 795.0 30/19 1.2350 1.1400 0.7668 11.30 9.7 30 RUDDY 900.0 451 7 1.0150 1.1310 0.7069 9.40 11.5 37 CANARY 900.0 541 7 1.1590 1.1620 0.7985 10.1;~10.9 3H RAIL 9~4.0 451 7 1.0750 1.1650 0.8011 9.40 11.5 39 CARDINAL 954.0 541 7 1.2290 1.1960 0.8464 10.85 10.9 ANCHORAGE-FAIRBANKS INTERTIE CASE IB 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:37:07 ****************** ***INPUT DATA * ** ****-************* CONDUCTOR SUMMARY ***************** AC RESIST. llLT.TENS.GEOM.MEAN THERM.LIMIT AT 25 DEG C IND.RE::ACT.CAP.REACT.10 NU~1HER NAMf STRENGTH(LBS)RADIUS(FT)PRICE($/LB)(AMPERES)(OHMS/MILE.>(OHMS/MILt.>(MOHM-M I U"S)------------------------------------------------------------------------------------------ 2Q GROSHfAK 25000.0 0.0335 0.6e8/PH7 790.0.11152 0.4118 2.63117;>5 fGI<ET 31500.0 0.0351 0.609/1977 870.0.111Q7 0.1l060 2.613626FUMINGO23700.0 o.o.ne;;0.640/1977 810.0.1399 0.Ll118 2.6294ttl27GANNET20200.0 O.03113 0.609/1977 820.0.1373 0.1l092 2.63117I28STILT25'500.0 0.03117 0.627/1977 840.0.1320 0.40b6 2.641)0..... l.O 29 STA~UNG 211100.0 0.0.555 o•I>0 811 977 850.0.12911 0.Ll050 2.6453 30 Rl:.DldNG '1l600.0 0.0.572 0.612/1977 860.0.1?88 0 •.5992 2.5661 31 CUCKOO 27100.0 0.0366 0.636/1977 900.0.121£1 0.3992 2.5502 32 DRAKE 31200.0 0.0375 0.622/1977 910.0.1172 0.399;>2.5450,3 TE !<N 22900.0 0.0.552 0.1>77/1977 890.0.1188 O.QObO 2.576634CUNOOR2/)'500.0 0.0368 0.635/1977 900.0.1172 0.1l002 2.5<;5535MALLARD38400.0 0.0392 0.599/1977 910.0.1162 0.3928 2.518636RUODY25400.0 0.0374 0.676/1977 935.0.10H2 0.3928 2.50i;l0 37 CANAKY 32300.0 0.0392 0.033/1977 950.0.10110 0.3928 2.5027 38 RAIL 26900.0 0.0385 0.671/1977 970.0.0998 0.3949 2.5027 39 CARDINAL 3£1200.0 0.0£10£1 0.032/1977 990.0.0987 0.3902 2.4810 ANCHORAGE-FAIRHANKS INTERTIE CASf Ifl 250 Kv TRANSMISSION LIN~COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIMt:9:37:07 ***********a****** a * * * INPUT DATA * * t::d I No lINIl MATERIALS COSTS PRICt OF TUwtR MATERIAL PRICE OF CONCRETE PRICE OF GROUND wIRE INSTALLED COST Of GROUNDING SYSTEM TOWER SETUP TOWfR ASSEMRLY FOUNDAfION SETUP FOUNDATION ASSEMBLY FOUNDATION EXCAVATION PRICF OF MISCELLANEOUS HARDWARE UNIT LAHOR COSTS REFERENCE YEAR LABOR COST STRI~G CROUND WI~f STRING LABOR MARKUP UNIT TRANSPORTATION COSTS TOWER FOUNDATION CONCRtTE fOUNDATION STEEL CONDUCTOR GROUND WIRE INSULATOR HARDwARE, ****************** INPUT VALUE 0.957 $/LR 0.00 $/CU.YD. 0.000 $/LI:l 0.00 $110WER 17'51.s O.IISS $/LH O.s 111110.00 $/TON 0.00 $/CU.YD. 290.00 $</TOWER 24.00 $/NANHOUR 0.0 $/MllE 4.2 PER UNIT 100.0 $/TON 100.0 $/YD 100.0 $110N 11>0.0 $/TON 100.0 $110N 100.0 $/TON OR $/M**3 100.0 $,1TON REFERENCE YEAR FOR INPUT 1979 1977 1977 vn t 1979 1979 1979 1979 1979 1977 1979 1917 ANCHORAGE-FAIRBANKS INTERTIE CASE 18 230KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIME:9:37:07 •••••••••••••••••••••••••••••••••••••••• •AUTOMATIC CONDUCTOR SELECTION • • ALL QUANTITIES PER MILE • •••••••••••••••***•••••••*•••••••••••••• ~APITAL COST/DISCOUNT RATt OF 7.~OPERCENT PRE:.St:NT WORTH-------------------------------------- CONDUCTOR INSTALLED COST LINE:.LOSSES 0K.~1 COST LINE COST------------------------------------------------------------------------------------------------------ tJO •KCM SPAN(FTl MATERIALS TRANSPORTATiON I NSTALLAT I.ON .ENGIIDC SUtHOTAL SUBTOTAL SUBTUTAL TOTAL--------.------------------------------.__.------------------------------- td .59 9')/1.1300.681 /17..HUIl.81l796.9328.166101l •35856 •3;:>81l.2052aa. I 37 900.I 30(j~-·67299.3772.B4608.9307.164986.37993.3?57.206235.N I-'3<;79').1300.64664.3721.82616.90R8.160089./J3028.3151.206267. 35 7'15.ILJOO.65375.3684.82031.9023.160113.113028.3161.206302. 39 9S11.laoO.69552.3828.811673 •9311l.167367.351\S6.3322.206S115. 37 900.laoo..68697.3766 •8111l91l.9294.166251.37993.32911.207538. 35 795.1500.668 79.3689.82176.9039.161781l.43028.3206.208017. 32 795.1300.6S5':>8.3685.83893.9n8.162364.1l3468.3195.209027. 39.9'-,/l.ISOO.718 /13.3870.85337.9387.170437.3'i856.3397.209689. 3 /J 7<"15.130u.6Sil07.3659.Cla3S9.9279.163104.43545.3209.2091;\58. 38 9sa.130 (I.70136.3831.86787.9sa7.170300.36293.3371.209903. 32 795.1400.66784.3669.83683.920S.163342.43116R.3226.210036. 30 715.1.300.6.3510.3615.82301.9053.1581178.48561.3112.210!51. 30 715.1400.6420a.31)7&.81729.A9 QO.1581l9A.48S61.3122.210182. 39 9511.12011.70~1:!6.ao 33.87082.9579.171080.3511':>0.33A5.210.321. 37 900.1500.70t?1:!3.3(107.fl5172.9369.169331.37993.3369.210695. 34 795.IllOO.67?35.3053.811298.9273.16 /J45<1.113':>/IS.3248.211251. 55 79').1600.691211.3735.B2979.912a.16119b6.a302R.3282.211275. 37 900.leOO.69631.3977.R6926.9562.170096.37993.3361.211ll50. 3')195.1200.66889.3916.85020.9352.16S116.113028.32511.211£157. 30 71 'i.1500.65702.35RO~81896.9009.160187.llRS61.3167.21191 I). 36 'tOO.1300.69499.3780.86682.9535.169496.39701.33S1.2125117. 513 9S11.11100.7;>348.31.\61.87234.Q590.173039.36293.34LJO~212771. 32 7"5.15110.68883.3701.84257.Q268.Ib6109.113LJ68.3295.212571- ?9 715.1300.64091.3593.836R3.Q20S.160573.LJ92?2.3150.2129LJ'l. ANCHORAGF.-FAIR~ANKS INTERTIE CASE IA 230 K~TRANSMISSION LINt COST ANALYSIS AND CONDUCTOR OPTIMIlAtION DATE:12 APR 79 TIME:9:37:07 ****************************** ** * ** * COST OUTPUT PER MILE PRESENT VALUE RATE 7.00 PERCENT * ********************************* CONDUCTOR NUMBER =39 9S4.KCMIL 1300.FT SPAN 87.7 FT TowER-------------------------------------------------- I NST III LtD'COST MAHRIAl TRANSPORTATION INSTALlilTION TOTAL hlH AKlJn~.~j QUANTITY COST($)TONNAGE COS1($)COS1($)COST($) ---------------------------------------------------------------------- tt1 I CQNDIJCTOR 1':>840.FT 11.1086.9.73 973.1R257.33316. N GR Oll"II,"I ><1:O.FT u.0.00 O.O.O. N ItJ:;lJL A TO~S 207.UNITS 1313.1•11.1 241.1.1557- HAliD ,.ARf 1429.0.1.17 1.17.11.177. TO ..F';S 1.1.3 UNITS 3R870.20.31 2031.26019.66'121. F()ut;lJ II TI 0 'Ii S 1.1.3 UNJ IS 3327.':>38.22?AO.261£15. RIGHT OF '/lAY 13.ACRES 9120.1821.11.27361. IlJClf NGP.jf'I:RING 9328.9328. ----------------------------------------------- TOTALS 6811.17.31.6':>31l34.84796.166101.1. PRESENT VALUE ($)------------------------------------------------------------------ LOSS ANALYSIS UEHAND LOSSES ENERGY LOSSE.S TOTAL LOSSES ---------------------------------------------------------- ~ESISTA~CE LOSSES 21.1588.1121.19.351137. CORor,A Lt1SSES O.19.19. ----------------------------------------- TOTALS 21.1588.11268.35856. t:d I N t.N INTERNATIONAL£~GINEERING CO. INC SAN ~RANCISCO CALIfORNIA TRANSMISSION LINE COST ANALYSIS PROGRAM VERSION 1:23 FEB 1979, ANCHORAGE-FAIRBANKS INTERTIE CASE I-C 345 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:10:52 ****************** ***INPUT DATA * ******************** SYSTEM ECONOMIC FACTORS STARTING YEAR OF STUDY E:.NDING YEAR or STUDY HASE:.YEAR FOR ESCALATION MAXIMUM CIRCUIT LOADING AVERAGE CIRCUIT LOADING DEMAND ~OST FACTOR ENERGY C05T FACTOR VAR COST FACTOR CAPITAL COST/DISCOUNT RATE: !'1INIMlJt~ MAXIMUM NUMRE:.R OF INTFNVALS Oli.M COST FACTOR RTGliT OF wAY COST FACTOR RiGHT OF wAY CltARING COST INTEREST DURING CONSTRUCTION ENGINE:.FRING FEr INPUT VALUE 1979 1996 1977 168.4 MVA 58.9 MVA 73.0 S/KW 13.0 MILLS/KWH 0.0 $/KVAR 7.0 PERCENT 10.0 PERCENT 1 1.~X CAP.COST 715.0 $/ACRE 11130.0 S/ACRE 0.00 X INST.CST 11.00 X INSl.CST REFERE:.NCE YEAR FOR INPUT 1992 1992 1979 1979 19R1l 1981.1 1984 1979 1979 1979 ANCHORAGE-FAIRHANKS INTfRTIE CASE I-C 345 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:10:52 ****************** ***INPUT DATA * ******************** COf;()UCTOP DATA'GROIJNDwIRE DATA -----------------------------------------SPAN DATA-----------------------------------._. b:l I N-+::- ~U~l!5Ei<PE.R PHASf CUNDUCTIlR StJACTNG VOLTAGE VULTAGE VARIATION LINE F RLQIJF ,.!cy FAIRWtATHtR lOSSES LINf:.IF:NGIH POwER FACTOR WI:.ATHf:R DATA ~IAXI/I"J~RAINFALL IHTF ~,xl~~~RAINFALL DURATION AVFqA~~RAI~fALL RATE AvEiiA~,;::RAU~FAlL DIJf?ATION MAX IM,n SI,O,,;ALL RA H ~4XI~J~SNO~FAll DURATION AVERAGf SNO~FALL ~ATf AVEQAGf S~OftfALL DURATION Rf:.LATIVE AIR DENSITY 2 lR.O IN 345 KV 10.00 PCT 60 CPS 1.701<.../MI 323.00 ~lILFS 0.95 1.18 IN/HR 1 HRS/YR 0.03 IN/HR b36 fiRS/YR 1.87 IN/HR 1 fiRS/YR 0·.13IN/HR 2M HRS/.YR 1.000 NUMBI:.R PER TOWER ()IAME.TER WE:.!GHT o 0.00 IN 0.0000 LBS/FT MINIMUM MAX HlllM INTERVAL 1000.FT 1600.FT 100.0 FT --ANCffORAGI:.-FAIRBANKS INTERTIE 'CASE I-C- 345 KV JRANSMISSION LINE COST ANALYSIS AND CONDUtTOR OPTIMIZATION DATE:12 APR 79 TIME:10:10152 *•••*•••••••*•••** *• •INPUT DATA • **••••••••••••••••*. SAG/TENSION DESIGN FACTORS I:l:J I N til EVERYDAY STRI:.SS TEMPERATURE ICE AND WIND TI:.MPfRATURE HIGH wIND TEMPERATURE I:.XTRI:.MI:.ICI:.TEMPERATURE MAX DESIGN TEMP FOR GND CLEARANCE EDS TENSION (PCT UTS) NESC CONSTANT TOTAL NUMBER OF PHASES PHASE SPACING CnNDUCTOR CO~FIGURATION FACTOR GROUND CLEARANCE NO.OF INSULATORS PER TOWER INSULATOR SAFfTY FACTOR STRTNG UNGTH 1,VI:.F,OR COMBINATION FOUNDATION TYPl: TERRAIN FACTOR LINE ANGL'E FACTOR TOflFR GROUNDING TRANSVERSE OVfRLOAD FACTOR VERTICAL OVERLOAD FACTOR LONGITUDINAL LOAD MISCELLANEOUS HARDwARE WEIGHT TOwER riEIGHT FACTOH TOwER wEIGHT ESTIMATION ALGORITHM lIO.DEGREES F O.Dl:GREES F lIO.DEGRFES F 30.DEGREES F 120.Dl:GREES F 20.PERCENT 0.31 LBS/FT TOWER DESIGN 3 27.0 FEU 1.02 32.0 FE.ET 72 2.50 9.5 FI:.E T 3 1I, 1.0b PER UNIT .08bll o 2.50 1.50 1000.LBS 0.11 TONSITOWER 1.02 ICE A~D WIND TENSION (Pcr UTS) HIGH wIND TENSION (Pcr UTS) EXTREME ICE TENSION (PCT UTS) ICE THICKNESS wITH WIND WIND PRESSURE wITH ICE HIGH WIND EXTREME ICE DISTANCE BETWEEN PHASES: 01 02 D3 Dq 05 Db 50.PfRCENT 50.PERCE/IlT 70.PI:RCEtH 0.50 INCHES lI.OO LfiS/S(,).FT. 9.0 LElS/SQ.FT. 0.50 INCHES 27.00 FT 27.00 FT 54.00 FT 0.00 FT 0.00 FT 0.00 FT TOWER TYPE 10:3ll5KV TOwER TW =0.00041*TH**7 -0.Q97111*TH*'O.bOOO -O.10371*FFFVDL - 0.275b~*fFFTDL •O.00503*TH*lFfTDL •0.00181*TH*fFfVDL ~ 20.77701 KIPS ANCHONAGE-FAIRBANKS INTERTIE CASE I-C 345 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:10:52 ****************** ***INPUT DATA * ******************** ,~-- ANCHURAGE-FAIRBANKS INTfHTIE CASE I-C 3/15 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 7q TIME:10:10:52 ****************** ***INPUT DATA * ******************** CONDUCTOR SUMMARY ***************** AC RESIST. UlT.TrNS.GFOM.~lEAN THERM.LIMIT AT 2'5 DEG C IND.REACT.CAP.REACT. ID NLI:ijF:R NAMt-STR~NGTH(LBS)RADIUS(FT)PRICE($/LB)(AMPERES)(OHMS/MILE)(OHMS/MILE)(MOHM-MILES)-------_.-----------------------------------------------.--------------------------------- ('9 SIAl-ILTNG 28100.0 0.0355 0.608/1977 8!:>O.0.129/1 0.4050 2.64')3 .ttl 30 Rt.f)wINr.34600.0 0.0.572 0.61211977 860 •0.1288 0.3992 2.5601 I 31 CUCKO(J ?l100.0 0.0366 0.636/1977 900.0.12111 0.3992 2.5502 N 32 IWAKE 31{,00.0 O.0.H5 0.62211977 910.0.1172 0.3992 2.5450-...J 33 TUIN 2{'QOO.O 0.0352 0.677/1977 890.0.11R8 0./1060 2.5766 34 CU~~I)()R 28500.0 0.0368 0.635/1977 900.0.1172 0.11002 2.5555 35 MALLARD 38400.0 0.0392 0.599/1977 910.0.1162 0.3928 2.5186 36 IWi)j)Y 25400.0 0.0374 0.676/1977 935.0.1082 0.3928 2.':l080 37 CANARY 32300.0 0.0392 0.633/1977 950.0.1040 0.3928 2.5027 38 RAIL 26900.0 0.0.585 0.671/1977 970.0.0998 0.39119 2.5027 39 CAROTNAL 34?00.0 0.011011 0.632/1977 990.'0.0987 0.3902 2.4816 4@)ORTOLAN 28900.0 0.0401 0.670/1977 1020.0.09211 0.3902 2.11658 i~_ ANCHORAGE-FAIRgANKS INTERTIE CASE I-e 345 KV TRANSMISSION LINE COS1 ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIMt:10:10:52 ******AAAA*AAAA*AA A A -'* -'A INPUT DATA * * t:d I N 00 UNIT MATERIALS COSTS PRIC~OF TuwtR MATERIAL PRICE OF CONCRET~ PRICE OF GROUND wIRE INSTALLED COST OF,GROUNDING SYSTEM TOWER SETUP TOWER ASStMRlY FOUNDA TIO"J SE TUP FOUNDATIUN ASSEMBLY FOUNDATION EXCAVATION PRICE OF MISC~LlANEOUS HARDWARE UNIT LABOR COSTS REFERENCE YFAR LABOR COST STRING GROU"JD WIRE STRING LABOR MARKUP UNIT TRANSPORTATION COSTS ~_.---------------------- TOWeR FOUNDAIION CONCRETE FOUNDATION STEEL CONDUCTOR GROUND WIR~ INSULATOR HARDWARE *AAAAAAAAA*A*'A*** INPUT VALUE 0.957 S/tB 0.00 S/CU.YD. 0.000 $/LB 0.00 $ITDWER 1751.s 0.455 $/LB O.$ 4140.00 $ITON 0.00 $/CU.YD. 290.00 $/TOwER 24.00 $/MANHOUR 0.0 $/MILE 4.2 PER UNIT 100.0 $ITON 100.0 $/YD 100.0 $/TON 100.0 $/TON 100.0 S/TON 100.0 SITON OR SlMu3 100.0 SITON REFF.RFNCE YEAR FOR INPUT 1979 1977 1977 1977 1979 1979 19'9 1979 1979 1977 1979 1977 L-= ANCHORAG~-fAlRoANKS INfErtTIE CASE I-C 345 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 lIME:10:10:52 ANCHORAGE-FAIRBANKS INTERTIE CASF I-C 3q5 KV TRANS~lSSION LIN~COST ANALYSIS AND CONDUCTOR OPTIMIlATION DATE:12 APR 79 TIME:10:10:52 ****************************** ***COST OUTPUT PER MILE **PRESENT VALUE RATE * *7.00 PERCENT * ******************************** CONDUCTOR NUMBER: 30 71~.KCMIL 1300.FT SPAN 90.1 FT TOWER-------------------------------------------------- INSTALL~D COST MATERIAL TRANSPORT ATION INSTALLA TION TOTAL [jREA"DOWN QUANTITY COS1($)TONNAGE COST($)COST($)COST($) ---------------------------------------------------------------------- td Cll~~OUC TOR 31680 •.FT 2l1b61.17.60 1760-.-25306.51727. I GfHi!lND,.;TRf 0.·FT O.0.00 o.O.O. VI P'SULAIORS 310.UNITS 1970.1.70 366.2336. 0 ~IARD"AKF 1429.0.47 lI7.1 Ll77. TO"f.RS 4.3 UNITS 63399.33.12 3312.37681.10ll393. FOlJ~JDA IT ONS .lI.3 UNITS 4/91.775.320133.37MB. RIGHT OF WAY 13.ACRES 9371.11:l71~2.asi i e , IOC/PH;HJEfRING 12519.12519. ----------------------------------------------- TOTALS 105622.52.90 6261.113812.23~21l1. PRESENT VALUE ($) ?2728. 13l10~. 9323. TOTAL LOSSES 3735. 7235. 10Q70. --~---- ENERGY LOSSI:S------------- 9670. 2088. 117<)8. DEMAND LOSSES ------------- ------------------------------------------------------------------ TOTALS RESISTA~Cf LOSSES CORONA LOSSI:S LOSS A:JAL YSIS -------------------- -------------------- .•.. INTERNATIONAL E~GINEtRI~GCO.INC SAN FRANCISCO CALIFORNIA TRANSMISSION LINE COST ANALYSIS PROGRAM VERSION 1:23 FbB 1979, 0::; I VI ~ ANCHORAGE-DEVIL CANYON CASE 11-1 345 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:25:33 ****************** ***INPUT DATA * **••••**••********** SYSTEM ECONOMIC FACTORS StARTING YEAR OF STUDY ENDING YEAR OF STUDY BASE YEAR FOR ESCALATION MAXIMUM CIRCUIT LOADING AVERAGE CIRCUIT LOADING DEMAND COST FACTOR FNERGY CbST.FACTOR VAR CflST FACTOR CAPITAL COST/DISCOUNT RATE: MINIMUM MAXIMUM NUMBER OF INTERVALS O&M COST FACTOR RIGHT OF wAY COST FACTOR RIGHT OF:~AY CLEARING COST INTERE$T DURING CONSTRUCTION ENGINEERING FE.E INPUT VALUE 1979 1996 1977 631.b MVA 347.4 MVA 73.0 $/I<W 13.0 MILLS/KWH 0.0 $/KVAR 7.0 PERCENt 10.0 PERCENT 1 1.5 %CAP.COST 715.0 $/ACRE 1430.0$/ACRE "0.00 %INST•.CST 11.00 %INSTDCS"T REFERENCE YEAR FOR INPUT 1992 1992 1979 1979 198/~ 1984 19f\4 1979 1979 1979 ANCHORAGE-DEVIL CANYON CASE 11-1 3Q5 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:25:33 ****************** ***INPUT DATA * ******************** CONf)UCTOR DATA -----------------------------------------GROUNDWIRE DATA -----------------------------------------SPAN DATA ~------------------------------------_. b:l I VI N NUMHFR PER PHAS~ CONDUCTOR SPACINGvOLTAGE. VOLTAGE VARIATION LINE FREQUfNCY FAIRwtATH£R LOSSES LINt LENGTH POWER FACTOR WEATH~R DATA 2 18.0 IN 3Q5 KV 10.00 PCT 60 CPS 1.70 KW/MI 155.00 MILES 0.95 NUMBER PER TOWER DIAMETER -wEIGHr-- o 0.00 IN --0.0000 LAS/FT MINIMUM __MA.!JJ1 UlL.- INTERVAL 1000.FT 1600.FT 100.0 FT ----------------------------------------- MAXIMUM RAINFALL RATE 1.IA IN/HR MAXIMU~RAINFALL DURATION 1 HRS/YR AVERAGE RAI~FALL RATE 0.03 IN/HR AVERAGE RAINFALL DURATION 636HRS/YR MAXIMU~SNOWFALL RATE 1.87 IN/HR MAXIMUM SNOWFALL DURATION 1 HRSIYR AvERAGE SNOWFALL ~ATE 0.13 IN/HR AVERAGE SNOWFALL DURA1ION 201~HRSIYR RELATIVE AIR DENSITY 1.000 ANCHORACE-DEVIL CA~YDN CASE 11-1 3q5 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:25:33 k***k******k*••••• •* *• INPUT DATA *• ***.*••******••**. SAG/TENSION DESIGN FACTORS 0:1 I CJ-l CJ-l EVERYDAY STRESS TfMPERATURE ICE AND WIND TEMPERATURE HIGH WINO"TEMPERATURE EXTREME ICE TEMPERATURE MAX DESIGN TfMP FOR GND CLEARANCE EDS TENSION (PCT UTS) NEse CONSTANT TOTAL NUMBER OF PHASES PHASE SPAC I Nt; CONDUCTOR CONFiGURATION FACTOR GROIH~f)CLEARANCF. NO.UF INSULATORS PEH TOwER INSULATOR SAFETY FACTOR STRItlG LF.NGTH i,VEE,OR COMBINATION FOUNDA TTON TYPE TERRAiN fACTOR L1NE ANGLE FACTOH TowrR GROUNDING TRANSVERSE OVERLOAD ~ACTOR VERTICAL OVERLOAD FACTOR LONGITUDINAL LOAD MISCELLANEOUS HARDWANE WEIGHT TOwER WEIGHT fACTOR TOWER wEIGHT ESlIMATION ALGORITHM 110.DEGREES F O.Di:.GREES F 1.10.DcGRFES F 30.DEGREES F 120.DEGREES F 20.PERCENT 0.31 L8S/FT TOWER DESIGN 3 27.0 FEEl 1.02 32.0 FEfT 72 2.50 9.5 FEET 3 Ij 1.06 PER UNIT .08bQ o 2.50 1.50 1000.LBS 0.1 t TONSITOWFR~ 1.02 ICE AND WIND TENSION (PCT UTS) HIGH WIND TENSION (PCT UTS) EXTREME ICE TENSION (PCT UTS) ICE THICKNESS WIlH WIND WIND PRESSURE WITH ICE HIGH WIND lXTREME ICE DISTANCE BETWEEN PHASES: 01 D2 03 OQ D5 06 50.PfRcn,T 50.PERCENT 70.PERCENT 0.':>0 INCHES 1.1.00 LBS/Sf..l.FT. <1.0 lBS/SQ.FT. 0.50 INCHES 27.00 FT 27.00 FT 5Q.00 FT 0.00 FT 0.00 FT 0.00 FT TOWER TYPE 10:3Q5KV TOWER IN =0.0004'*TH**2 -D.QQ2111*TH**O.bOOO -0.ln37t~EFFVDL - O.273b~*lFFTDL t 0.00503*TH*lF~TDL t U.OOtal*TH.EFFUDL t 20.77701 KIPS ANCHORAGt-ufVIL CANYON CASE 11-1 315 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIMt:10:25:33 •••••••••••••••••••• •INPUT DATA • •••••••••••••••••••• CONDUCTOR SUMMARY•••••••••••*••*•• TEMP.COfF. STRANDING UN-H ···WEIGHT OUT .OlAM.-TOTAL AREA MODULUS-ALPHA·E-6 ID NI)'lRfR NAME SIZE(KCM)(ALIST)(L65/FT)CINCHES)(SQ.IN.)(EF It6 PSI)PfR DEG F--------------------------------------------------_._---------------------- 29 STAHLlNG 715.0 261 7 0.9R50 1.0510 0.6535 11.00 10.3 30 RElhllNG 715.0 .30/19 1.1110 1.0810 0.6901 11.30 9.7 O:l 31 CUCKOO 795.0 211 7 1.0210 1.0920 0.70'B 10.55 10.7 I 32 ORAKF 795.0 261 7 1.091.10 1.1080 0.7261 11.00 10.3 v-l 33 nRN 795.0 15/7 0.8960 1.0630 0.6676 9.1.10 11.5-1:::0 34 CONDOR 795.0 51.11 7 1.021.10 1.0930 0.7053 10.85 10.9 35 MALLARD 795.0 30/19 1.2350 1.1l100 0.7668 11.30 9.7 30 RUDDY 900.0 1.151 7 1.0150 1.1310 0.7069 9.1.10 11.5 37 CANARY 900.0 51.11 7 1.is90 1.1620 0.7985 10.85 10.9 38 RAIL 951.1.0 1.151 7 1.0750 1.1650 0.8011 9.1.10 11.5 39 CARDINAL 95l1.0 541 7 1.2290 1.1960 0.81.161.1 10.85 10.9 1.10 ORTOLAN 1033.0 I.ISI 7 1.1650 1.2130 0.8678 9.1.10 11.5 ,."~.~_.......--- ANCHORAGE-DEVIL CANYON CASE 11-1 )ll~KV TRANSMISSION l.INE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:10:25:33 ****************** ** * * INPUT DATA * * 28100.0 0.035~0.M811n7 850.0.1294 0.4050 2.6453 3 116UO.0 0.037c 0.612/1977 AbO.0.1288 o ~3992 2.5661 27100.0 0.0566 0.636/1977 900.0.1214 0.3992 2.5502 31rOO.0 0.037~0.62211977 910.0.1172 0.3992 2.5450 22900.0 0.0352 0.677/1977 890.0.1188 O.4ll60 2.5766 28';00.0 0.0.368 0.635/1977 900.0.1172 0.llU02 2.5555 3ijl~OO.0 0.0.392 0.599/1977 910.0.1162 0.39?fI 2.5186 2':l4ll0.0 0.0374 0.676/1977 935.0.1082 0.3928 2.5080 32300.0 0.0392 0.633/1977 950.0.1040 0.3921:\2.5027 26900.0 0.0385 0.671/1977 970.0.0998 0.3949 2.5027 34cOO.0 0.0404 0.632/1977 990.0.0987 0.3902 2.4816 28900.0 0.0401 0.670/1977 1020.0.0924 0.3902 2.4658 r D Nl)'·lBf:.R NAMf:.--------- 2'1 STARLING 30 REflW ING 31 ClJC~.OO t:d 32 ORAK[ I 3 s TlRN t.N 3·1 CUNDORtil 3":}"""lLARD 3b RlJl)fJ'f 37 CANARY V.\RAIL Vi C!lRDINAl lit)ORTOLAN lIlT.TENS.GEOM.MEAN STRtNGTHCLBS)RADIUSCFT) *~**************** CONDUCTOR SUMMARY *******.********* AC RESIST. THERM.lIMIT AT 25 DEG C IND.REACT. CAP.REACT. PRTCE C$/LB)(AMP I:.RES ) -(OHMS/M ILE>(OHMS71H If)(MQHM;;'M I lES) ---------------------------------- ANCHORAGt-DEVIL CANYON CASE 11-1 3q~KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIME:10:25J33 ****************** ** ,-~~ * * INPUT DATA * * b:I I U-l 0\ UNIT MATERIALS COSTS PRICE OF TUWtR MAtERIAL PRICE OF CONCRETE PRICE OF GROUND wIRE INSTALLED COST OF GROUNDING SYSTEM TnwFN SETUP TOwER ASSEMBLY FOUNDATION SETUP FOUNDATION ASStMBLY FOUNOATION EXCAVATION PRICE OF MISCELLANEOUS HARDWARE UNIT LABOR COSTS REFERENCE YEAR LAHOR COST STRING GROUND WIRE STRING LABOR MARKUP UNIT fRANSPORTATION COSTS TOWER FOUNDATION CONCRETE FOUNDATION STEEL CONDUCTOR GROUND WIRE INSULATOR HARD"'ARE ****************** INPUT VALUE 0.957 $/LB 0.00 $/CU.YO. 0.000 $/L/:; 0.00 $/TOWER 17 5.1-.---$ 0.455 $/Ul O.s 4140.00 $/TON 0.00 $/CU.YD. 290.00 $/TowER 21.1.00 $/MANHOUR 0.0 $/MILE 4.2 PER UNIT 100.0 $/TON 100.0 $/YD 100.0 $/TON 100.0 $/TON 100.0 $/TON 100.0 $/TON OR $/M**3 100.0 $/TON REFERENCE YEAR FOR INPUT 1979 1977 1977 1977 1979 1979 1979 19'9 1979 1977 1979 1977 ANCHORAGE-DEVIL CANYON·CASE 11-1 345 KV TRANSMisSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIMt:10:25:33 ************************************** ** * ** AUTOMATIC CONDUCTOR SELECTION ALL QUANTITIES PER MILE * **************************************** CAPITAL COST/DISCOUNT RATE OF 7~00 PERCENT PRESr.NT WORTH-------------------------------------- CONDUCTOR INSTALLED COST LINE LOSSFS O&M COST LINE COST ------------------------------------------------------------------------------------------------------ NO.KCM SPAN(FT)MATFRIALS TRANSPORTATION INSTALLATION ENG/IDC SU13TOTAL SUHTOTAL SUBTOTAL TOTAL -------------------------------------------------------------------------- to 39 954.1500.114706.6714.117754.12953.252127_90411_5143.347681_ I 39 9')4_1200_113228_674n.-119225.13115.252308.90411.5125_347843. t.N 40 103"~_12011_1177H2_6840.121885_13407.259913.84621.')295.349829. -...,J 37 900_1300 _112812.6583.11 7342.12908.249645.95660.5082_350386_ 39 954_1400_117620_6769.117532_12928.254849_90411_5222.350482. 37 900.1200.111385.6612.l1R824.13071.249892.95660.')06').35061b. 39 954.1100 _113373_6f\59_122168.13438.255838_90411.5176.351425. 40 J033.110u_116899_6910.124193_13661_261664_84621.')307.351591. 40 1033.13011.120 /12 0 _'6Rb9.121120_13323.261732.(\/1621.5358_351711. !>7 900.140!)_115679.6b35.117111_12882.252308_95660.51'::>9.353126. 38 95u.\200.114994.b66?.12\202_13332.256189_91853.5204.353246. 35 795_1300.108253-6486.114488.12594.241821_107119_4908.353847. 57 900_1100_111';80.6734_121780.13396.253490_95660.5]18.354268. !>5 79'::>.14 -.>0.110039.0487.113599_12496_242620_10711<1_4<144_35 /46,33_ 3Po 954.13(1) _117510_.6684_120390_13243.257827_91853.5262.354"142_ 38 95 11 _1 100_1111231.6738_123557_13'::>91.258117_91853.5220.3':>5190. 35 79':>.120')•107799_b561.116571.1282!>.243753.107119.UQ?9.355800. 3Q 95a_1500_121880_6/399.118112'>_13027.260230.901111.53'::>7.3')5998. uo lOB_1400_124683.6989_121712_·13388.266772.8t1621.5488.356881. ~5 795_150'1.\13021_0554.113739.1251 \ • 2£15825.107119.503\_357975. 3?795_nov.109255_6399.116128_127714 _214£1556.1089314.tlQ60_35R450. 37 900.1<:'00.119895.0762_117998.lZQ80.257634.9'>660.52<13_358587. 3?795_1200_108121_ba1l3_II17b1J.12954_2452i:l2.101'934_4955.359170. 36 900_1200.1]3498.6<:.52.120883.13297.254229.100106.5156.359491. 34 795_1300.109378_031.11.116691_12836.245246_109437 _4972.359654_ '-:-~---::./ :'._~ ANCHORAGE-DEVIL CANYON CASE 11-1 3115.KV TRANSMISSTONLINI:::COST ANALYSIS ANO CONDUCTOR OPTIMIZATION DATE:1?APR 79 TIME:10:25:33 ****************************** ***COST OUTPUT PER MILE * *PRESENT VALUE RATE * *7.00 PERCENT * ******************************** CONDUCTOR NUMBER =39 954.KCMIL 1300.FT SPAN Qq.7 FT TOWER-------------------------------------------------- ------------------------------------------------------------------l.OSS ANALY SIS ~ESISTANCF LOSSES COROU LOSSES TOTALS lJf!'1A ND L OSSE S 111l314. 2088. llbll01. ENERGY LOSSES 39493. 4517. 44010. TOTAL LOSSES 83Fl07. 6b04. 90411. to I tN ~ INTERNATIONAL ENGINEERING CO.INC SAN FRANCISCO CALIFORNIA TRANSMISSION LINE COST ANALYSIS PROGRAM VERSION 1:23 FEB 1979, DEVIL CANYON-E~TER CASE II-2A 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:45:19 ****************** ***-1NPUI DATA * ******************** SYSTEM ECONOMIC FACTORS STA~TING YEAR OF STUDY EhDING YFAR OF STUDY BASE YfAH FOR ESCALATION MAXIMUM CIRCUIT LOADING AVERAGE CIRCUIT LOADING OEMAND COST FACTOR E~fRGY COST.FACTOR VAR COST FACTOR CAPITAL COST/DISCOUNT RATE: MINIMUM MAXIMUM NUMBER OF INTERVALS O&M COST FACTOR R1GHT OF WAY COST FACTOR RIGHT OF WAY (LEARING COST INTEREST DURING CONSTRUCTION ENGINEERING FEf:. INPUT VALUE 1979 1996 1977 194.7 MVA 107.1 MVA 73.0 $/KW 13.0 MILLS/KWH 0.0 $/KVAR 7.0 PERCENT 10.0 PERCENT 1 1.5 t CAP.COST 715.0 $/ACRE 11130.0 $/ACRE 0-.00 ~INST.CST 11.00 X INST.CST REFERENCE YEAR FOR INPUT 1992 1992 1979 t 979 198£1 19R£I 19811 1979 1979 1979 '-.--"'--' DEV1L CA~YUN-ESTER CASE 1I-2A 230 KV TRANSMISSION LINt COSI ANALYSIS AND CONDUCTOR OPTIMIZATION UAT£:12 APR 79 TIME:9:45:19 ****************** ***INPUT DATA * ***~**************** CONDUCTOR DATA----------------------------------------- GROUNDWIRE DATA ----------------------------------------- SPAN DATA---------------------------------------- NUMBER PER PHASE CO~OUC10R SPACING VOllASF VOLTAGF VARIATION LINl FREQUFNCY FAIRWEATHER LOSSES LINE llNGIH0/PUWtR ~ACTOR ~ CJ wEATHER DATA 1 0.0 IN 230 KV 10.00 PeT 60 CPS 0.00 "'W/MI 189.00 MILES 0.95 NUMBER PER TOi'lER DIAMETER WEIGHT o 0.00 IN 0.0000 LBS/FT MINIMUM MAXIMUM INTERVAL 1200.FT 1600.FT 100.0 FT ----------------------------------------- M~XI~I,)'~ M;\X 1'~:!" AVF;<AGI. A-Jt"A:;r M t<X I I~;"~ "'\A X I MJ'~ AvERA:; AiEi-/AG ReLATl RAINf-ALL RATE RAIMAll DURATION RAINFAll RATE: Rt.}m ALL DURATION SNOwFAll RATE StjOl-iF Al L ()lI1H T ION S~!();~F All.Rh IE SI,O.,FAlL DURA TION f AIR DENSITY 1.18 1 0.03 636 1.87 1 0.13 261.1 1.000 IN/HI< HRS/YR IN/HR HRS/YR IN/HR HRS/YR IN/HR IiRS/YR DEVTL CANYON-ESTER CASE II-2A 230 KV TRANSMISSION LINE COST ANAL~STS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:q5:19 **~********..**...**.. '"INPUT DATA ** '"****"'************.* SAG/TENSION DESIGN FACTORS-------------------------- tp I+::- I-' EVERYDAY STRESS TEMPERATURE ICE AND WIND TEMPERATURE HIGH WIND TEMPERATURE ExTREME ICE TEMPERATURE MAX DFSIGN TEMP FOR GND CLEARANCE EOS TENSION (PCT UTS) tlESC CONSTANT TnTAL NUMBER O~PHASES PHASE SPACING CONDUCTOR CONFIGURATION FACTOR GROUND CLEARANCE NO.OF INSULATORS PER TowFR INSULATOR SAFETY FACTOR STRING LENGTH I~VEE,OR CQMHINATION fOII'H)AIION TyPE HRRAIN FACTOR LINE ANGLE FACTOR TOwE R GROUND I Nl; TRA~SVERSE OVERLOAD FACTUR V(PTICAL nVERLUAD fACTOR LONGITUDINAL LOAD MISCELLANEOUS HARO~ARE wEIGHT TO~ER wEIGHT FACTOR TOwER wEIGHT ESTIMATIUN ALGORITHM --------------------------------- qO.DEGREES F O.DEGREES F qO.DEGREES F 30.DEGREES F 120.DEGREES F 20.PERCENT 0.31 LHS/FT TOWER DESIGN------------ "3 20.0 FE.ET 1.02 2/\.0 FEET 4/1 2.50 b.5 FI:.ET "3 4 1.0b PER UNIT .08bll o 2.50 1•")o 1000.L8S 0.11 TONSITOWER 1.02 ICE AND wIND TENSION (PCT UTS) HIGH WIND TENSION (PCT UTS) EXTREME ICE TENSION (PCT UTS) ICE THICKNESS wITH WINO wINO PRESSURE wITH ICF HIGH wIND EXTREME ICE DISTANCE B~TwEEN PHASES: 01 O? 03 Oq 05 06 '50.PERCEN.1 50.PERCENT 70.PERCENT O.~O INCHES 1l.00 LOS/SQ.FT. 9.0 LBS/SQ.FT. 0.50 INCHES ?O.OO FT 20.00 FT 110.00 FT 0.00 FT 0.00 FT 0.00 FT TOwER TYPE .9:·230KV TOwER TW =O.OOO\b*lIi.*2 -5.0'H9"*TH*"'0.533~-O.OHqll~*LFFVDL -O.273b7.EF~TDL t 0.00510*TH*tF~TDL +O.OOlbO"'TH.EFFVDL • 11l.3iQ12 KIPS DEVIL CANYON-ESTER CAS~lI-2A 230 KV THANSMISSI0N LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIME:9:45:19 **************~*** ** *INPUT DATA • ** ****************** CONDUCTOR SUMMARY ~**************** TEMP.COH.STRANDING UNIT WEIGHT OUT .DIAM.TOTAL AREA MODULUS ALPHA*E.-6I D.NlJ'iK.E.R NA'"11:SI7E(KCM)(AlIS T)(LflS/FT)CINCHES)(SQ,IN.)(EF 1E.6 PSI>PER DEG F------------------------------------------_._---------.w.________---------- 2'1 Gl<llSi-1E AI'636.0 261 7 0.8750 0.9900 0.5809 11.00 10.32')r I;RfT 636.0 30/19 0.91\BO 1.0190 0.6134 11.30 9.72t,~I.A:1INGD 666.0 241 7 0.8590 1.0000 0.'5914 10.55 10.727GANI\IFT 666.0 261 7 0.9180 1.0140 0.6087 11.00 10.3 t:d ?i\STTL T 715.0 241 7 0.9210 1.0360 0.6348 10.55 10.7I2"SIARllNG 715.0 261 7 0.9850 1.0510 0.6535 11.00 10.3..j:>.3')IH pi'TNG 715.0 30/19 1.1110 1.0810 0.6901 11.30 9.7N 31 CUCKOO 795.0 24/7 1.0240 1.0920 0.7053 10.55 10.73iDRAKE795.0 261 7 1.0940 1.1080 0.7261 11.00 10.333HRfl795.0 1151 7 O.R960.:1.0630 0.6676 9.110 11.'"311 C[lNDOR 795.0 54/7 1.0240 1.0930 0.7053 10.85 10.93':'H,~LLAfiD 795.0 30/19 1.2350 1.1400 0.7668 11.30 9.73"RUDDY 900.0 45/7 1.0150 1.1310 0.7069 9.40 11 •r,37 CA"/ARY 900.0 541 7 1.1590 1.1620 0.7985 10.85 10.93>\RAIL 954.0 451 7 1.0750 1.1650 0.8011 9.40 11.539CARDINAL954.0 54/7 1.2290 1.1900 0.8464 10.85 10.9 \.,---_..... DEVIL CANYON-ESTeR CAS~Ir-2A 2~0 KV lRANS~ISSIbN LINE COST ANALYSIS AND CONOUCTOR OPTTMIZATION DATE:12 APR 79 TIMe:9:45:~9 *************.**** ** *INPUT DATA * ** ****************** CONDUCTOR SUMMARY *****.*.********* AC RESIST. UtT.TENS.GEOM.MEAN THERM.LIMIT AT 25 DEG C IND.REACT.CAP.REACT.rD NU·\1fH:R NAME.STRENGTH(LAS)RADrUS(FT)PRICE($/LB)(AMPE.RES)(OHMS/MILE)(OHMS/MILE)(MOHM-M I LE.S)------------.--------------------------.--...--..-----.._------------------------------------ 2/1 f,PfJSHFAK (,50no.0 0.0335 0.6281l977 HO.0.11152 0.1l118 2.6311725tGf<f::T 31500.0 0.0351 0.609/1977 870.0.l il1l7 0.il060 2.0136coFLAMINGO23700.0 0.0.B5 0.640/1977 810.0.1399 0.4118 2.6294 td 27 GANNET 26200.0 0.0343 0.609/1977 820.0.1 H3 0.1.1092 2.031.17 I 2"-S11LT 25500.0 0.031.17 0.627/1977 840.0.1320 0.4060 2.b400.j::.z»S I ARLING 28100.0 0.0355 0.60Fl/1977 850.0.1294 0.4050 2.64~3Vl30RU);~ING 34000.0 0.0.$12 0.012/1977 860.0.1288 0.39<12 2.':>661 31 CUCr<QO 27100.0 0.0366 0.636/1977 900.0.1214 0.3992 2.5502 32 Df.?AKE 31200.0 0.0375 0.622/1977 910.0.1172 0.3992 2.51.150 35 H!<N 22900.0 0.0352 0.677/1977 890.0.11HH 0.4000 2.57h634CtJ'Jl)O!~28500.0 0.0368 0.035/1977 900.0.1172 0.4002 2.5555 35 MId_LARD 38/100.0 0.0392 0.599/1 en7 910.0.1162 0.3928 2.51863",RUDDY 25400.0 0.0374 0.070/1977 935.0.10R2 0.39;:>8 2.5080 37 CANARY 32300.0 0.0592 0.633/1977 950.0.1040 0.3928 2.5027 3H RAIL 26900.0 0.0385 0.671/1977 970.0.0998 0.3949 2.5027 . 39 CARDINAL 34200.0 0.0404 0.b321l977 990.0.0987 0.3902 2.4816 DEVIL CANYON-ESTER CASE II-2A 230 KV fRANS~lSSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:9:~5:19 ****************** * * * INPUT DATA * * * b:J I ..j:::. ..j:::. U~TT MATFRIALS COSTS PRICt OF TOWtR MATERIAL PRICtOF CO~CRFTE PRICE OF GROUND wIRE INSTALLED COST OF GROUNDING SYSTEM TOwER SETUP TOwER ASSH1BL Y FOUNDATIUN SETUP FOUNDATION ASSEMHLY FOUNDATION EXCAVATION PRICf OF MISCFLLANEOUS HARDWARE UNIT LAHOR COSTS---------------- RFFERENCE YEAR LABOR COST STRING GROUND WIRE STRING LAAOR MARKUP UNIT TfHNSPflRTATION COSTS --~---------------------- ****~************* INPUT VALUE 0.957 s I LEi 0.00 $/CU.YD. 0.000 $/LB 0.00 $ITOWER 1751 __$ O./JS';$/LB O.$ /JlI.jO.OO $/TON 0.00 $/CU.YD. 290.00 $/TOwER 211.00 $/MANHOUR 0.0 $/MILE 4.2 PER UNIT REFERENCE YEAR FOR INPUT---------------.-------- 1979 1977 1977 1977 1979 1979 1979 1979 1979 1977 1979 1977 TOWFR FOUNDATION CONCRETE FOUNDATION STEEL CONDUCTOR Gf?OlJNI)WIRE INSUUTOR HARDwARE. 100.0 $ITON 100.0 $/YD 100.0 $ITON 100.0 $/TON 100.0 SITON 100.0 $/TON OR $/M**3 100.0 S/TON O[VIL CANYON-ESTER - CASE IT-2A 230 KV TRA~SMISSruN LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DAlE:12 APR 79 TIME:9:Q5:19 **************************************•**AUTOMATIC CONDUCTOR SELECTION * *ALL QUANTITIES PER MILE * ***.*••*****••*.***••••*.**.************ CAPITAL COST/DISCOUNT RATE OF 7.00 PERCENT PRESENT wORTH-------------------------------------- CLlNDUCTOH INSTALLI:D COST LINE LOSSES O&M COST LINE COST .---...------------------------------------------._---------------------------------------------------- NiJ.1<.eM SPANUT)MATERIALS TRANSPORTATION INSTALLATION ENGIIDC SUBTOTAL SUBTOTAL SU!'lTOTAL rOTAL .-------..•----------------------------------_._---------------------------- 39 CiS"•1500.681/17.3R3Q.8/.\796 •9328.166104.369811.3284.206376. tx:J 57 r;')II •1500.67299.377?81160B.<1307.1611986.3qI9~.3257.?0711.56. I 3'5 7 'I".1300.646611.3"f21.82616.90RB.160089.111l3'59.31':11.207598. .j:>.~5 7'-15.ItlOO.6~375.368Q.82031.9023.160113.114359.3161 •207633. U1 59 (J '>/1 •ItlOU.695')2.3828.811673.93111.167367.369R8.B?2.2U7676. 37 r;i)().1400.6fi697.3766.81111911.92911.166251..39195.3?911.208]39. 35 7''1''>.1':>00.66879.361:l9.82176.9039.161784.4Q3':19.3206.209348. 32 795.1500.6S5~8.3685.83893.9228.162364.111l830.3195.2103139. ,9 <;':'lLJ •1':>00.718/B.3810.8~B7.93R7.1701J37.36988.3397.210821. 31\0',4.1500.70136.:.5831.86787.9547.,170300.374')6.3371.21112&. 34 i-I r,•1 50 o •651107.36')9.84359.9279.163101l.41.1915.3209.211228. 32 79')•1/100.66784.3669.83683.9205.163342.441\30.3226.211398. 3'<4:;4.1200.70386.403').87082.9':179.171080.36988.3385.2111153. 30 71 S.1500.63510.3615.82301.9053.1581178.5001l9.3112.211639. 30 7 I 'i.1:.l00.64204.3576.81729.8990.158a98.500a9.3122.211669. 37 '-1'1·0.1':>00.70983.3807.85172.9369.169331.39195.3369.211894. 35 795.1000.691dll.3735.82979.9128.16Q966.4 /1359.3282.21?607. 3 /J 7 '15.I /JOO.67235.36'53.R1l298.9273.164459.Q1I915.32 tHl . 212621. 57 4'JO.ldOll.69631.3977.136926.9562.170096.39195.3361.2126':>1. 35 79').leOO.66889.3916.85020.9352.165176.1143':19.3254.21278fi. 30 715.1"00.b5702.3':,80.81896.9009.160187.50049.3167.213402. 30 ":.10.1500.69/J99.371:\0.86682.9535.169496.40968.3351.213814. 3H 9':>1I..1400.723/J8.3861.8723/J.9596.173039.37456.3440.213934. 32 7 95.1500.68883.3701.8Q257.9268.166109..Q1l830.3295.214233. 38 QS/J.1200.71305.3980.88398.9724.173407.37456.3431.-214293. 0- DEVIL CANYON-ESTEH CASt 11-2A 250 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OP1IMIZATION DATE:12 APR 79 TIME:9:45:19 ••••••••••••••••••••*•••*••••* ***COST OUTPUT PER MILE • *PRESENT VALUE RATE * *7.00 PERCENT • ***.**••••****•••••••*.**.*••*** CONDUCTOR NUM8ER =39 954.KCMIL 1300.FT SPAN 87.7 FT TOWER HISTALLffl cns r MA TERIAL TRANSPORTATION INSTALLATIOIll TOTAL HRf AKNIWN QUANTITY COST($)TONNAGE COST($)COSH5»COST($)------------------..-------------------------------------------------- CO~JDI.IC TOR 15840.FT 14080.9.73 973.18257.33310. OJ GRLJIJ'JI)w TfiE O.FT o.0.00 o.O.o. I HJSlIl AlORS 207.UNITS 1313.1.14 2114.1.5<;7. .j::o.HAf{O"AR~lll29.O.tH 47.--~~~--11177.0"1 TmIF"S 1I.3 UNITS 38870.20.31 2031.2M19.66921. FOlJNIJATIONS 1I.3 UNITS 3327.538.22280..2blllS. RIGHT OF WAY 13.ACRI:.S 'H2O.18241.273b 1. I DC/E.NG H;HR IlliG 9328.9328.---------------------.------\-------------------- TOTALS c81117.31.65 3834.81.1796.Ib6101l. PRESENT VALUE ($) LOSS ANALYSTS DEMAND LOSSES ENERGY LOSSES TOTAL LOSSES----------------------------------------------------------RESISTANCE LOSSES 19547.171122.3b9b9. CORONA I.rlSSFS .0.19 •19. ----~---~---------~~----_.;..-------------- TOTALS 195t17 •.1711111.3&988. t;:; I+:- -...] HHERNATIO'NAL ENGINFERING co.HIC SAN FRANCISCO CALIFORNIA TRANSMISSION LINE COST ANALYSIS PROGRAM VERSION 1:23 FEB 1979, WATANA-DEVIL CANYON CASE II-3A 230 KV TRANSMISSION LINE COST"ANALYSISAND CONDUCTOR OPTIMIZATION DATE:12 APR 79 TIM~:9:02:Q3 ****************** ***INPUT DATA * **A*A*************** SYSTEM ECONOMIC FACTORS STARTING YEAR OF STUDY ENOIN(j YEAR OF STUDY 8ASE YEAR FOR ESCALATION MAXI'1lJM CIRCUIT LOADING AVfRAGE CIRCUIT LOADING DEMAND COST FACTOR ENERGV COST fACTOR VAR CUST FACTOR CAPITAL COST/DISCOUNT RATE: MINIMUM MAXIMUM NUMRER OF INTERVALS O&M COS1 FACTOR RIGHT OF wAY COST FACTOR RIGHT OF ~AY CLEARING COST INTERE:.ST DURING CONSTRUCTION ENGINEERING F~r INPUT VALUE 19H 19Q6 1977 514.0 MVA 282.7 MVA 73.0 $/KI'I 13.0 MIl.LS/KWH 0.0 $/KVAR 7.0 PERCENT 10.0 PERC~NT 1 1.5 X CAP.COST 715.0 $/ACRE lQ30.0 $/ACRf. 0.00 %INST.CST 11.00 %INST.CST REFERENCE:.YEAR FOR INPUT 1992 1992 1979 1979 19R1l 1984 198Q 1979 1979 1979 '--" WA'TANA-DEVILCANYON CASE Il-3A 230 KV TRANSMISSION l..INECOST ANALYSIS AND COr·lDUCTOR OPTIMIZATION DATE:12 APR 79 TIME:Q:02:43 *************~**** ***INPUT DATA * ******************** CONDUCTOR DATA --------~-------------------------------- GROUNDWIRE DATA ------~---------------------------------- SPAN DATA--------------------------------------- t1:J I ~ 00 NUMefk PfR PHA5~ CQ"J[JIICTOR SPACl'~G VOL1AGE VUL1~GE VARIATION l PH:.FREQUENCY FAIRWEA1HER LOSSES LINt lFtlGTH POwER FACTOR wrATHE.R DATA 1 0.0 IN 230'KV 10.00 PCT 60 CPS 0.00 KW/MI 27.00 MILES 0.95 NUMBER PER TOWER DIAMETER WETGHT o 0.00 IN 0.0000 LBS/FT MINIMUM MAXIIoIU'" INTERVAL 1200.FT 1600.F1 100.0 FT -----------------~----------------------- MAXIMJ~RAINFALL RATF 1.18 IN/HR MAXIM~M RAINFALL (lliRA1IOIIJ 1 HRS/YR AvERAS'RAI~FALL 1'1 ATF 0.03 IN/HI< AVERA~~RhI~FAll DURA lION 636 HRS/YR MAXIM'.I~S'If)~;FALL RATE 1.87 IN/Hk MAxIMU~sr.Or.f'All DURATTON 1 HRS/YR AVERA~E S~OwfALL RATf 0.13 IN/HI< AVE~A~[S~O~FALL DURATION "2M HRS/YR RELATL'If ATH DP.SITY 1.000 '~--_. WATANA-DEVIl CANYON CASE 11-34 230 KV TR~NSMISSION LINE COSl ANALYSTS AND COND~CTOR OPTIMIZATION DATE:12 APR 79 TIME:9:02:43 ••••••**••**•••*** •* *INPUT DATA * •• ****************** SAG/TENSION DESIGN FACTORS -------------~------------ t:d I +::-so ~VERY~AY STRESS TEMPERAtURE ICE AND WIND TEMPERATURE HIGH WIND TEMPERATURE [XTREME ICE TEMPERATURE MAX DESIGN TEMP FOR GND CLEARANCE EDS TENSION (PCT UTS) NESC CONSTANT TOTAL NUMAER OF PHASES PHASE SPACING CONDUCTOR CONFIGURATION FACTOR GROUND CLEARANCE NO.OF INSULATORS PER TOWER INSULATOR SAFETY FACTOR STRING LENGTH I,VEE,OR COMBINATION FOUNDATION TYPE H.RRA IN FACTOR LINE ANGLE FACTOR TOWFR GROUNDING TRANSVERSE OVERLOAD fACTOR VERTICAL OVERLOAD FACTOR LONGITUDINAL LOAD MISCELLANEOUS HARDWARE WEIGHT TOWER wEIGHT fACTOR TOWER WEIGHT ESTIMATION ALGORITHM --------------------------------- 40.DEGREES F O.DEGREES F lIO.DEGREES F 30.DEGREES F 120,DEGREES F 20.PERCENT 0,31 LBS/FT TOWER DESIGN ) 20,0 FEET 1,02 26,0 FEET lI8 2.50 6.5 FEET 3 4 1.00 PER UNIT .080il o 2,50 1.'50 1000.LBS, 0.11 TONSITOWER 1.02 ICE AND WIND TENSION (PCT UTS) HIGH ~IND TENSION (PCT UTS) EXTREME ICE TENSION (PCT UTS) ICE THICKNESS WITH WIND WINO PRESSURE wITH ICE HIGH WINO EXTREME ICE DISTANCE BETWEEN PHASES: 01 02 03 Oil 05 06 50.PERCENT 50.PERCENT 70.PERCENT 0.50 INCHES 4.00 LBS/SQ.FT, 9.0 LBS/SQ.FT. 0.50 INCHES 20.00 FT 20.00 FT 40.00 FT 0.00 FT 0.00 FT 0.00 FT TOWER TYPE 9:230KV TOWER rw =O,OOOlo*THu2 -3.09797*THuO.':n:B-0".Oal:)43*EFFVDL -. O.273h7*I::ff-'TDL +O.00510*TH*EFFTOL +O.001bO*JH*fFFVOL + 16.37912 KIPS WATANA-D~VIl CANYON CASE II-3A 230 KV TRANSMISSIoN LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79 TIMt:9:02:43 **"'*"*"**'**** ** * INPUT DATA * *• t:::J:j Ic.no ID "lU"[3[R 5? :>5 ')1 C;S C;" 51 5'1 t>JAMf ~JUTHATCH PARROT LAPwING FlILCOIll CtillKAR HLlIEI3 I RD KIWI ***,***.********,. CONDUCTOR SUMMARY *.***,**,*******. TEMP.COfF. STRANDING UNIT WEIGHT OUT.DlAM.TOTAL AREA MODULUS ALPHA*(-6 SIZF(KCM)(AL/ST)(LRS/FT)(INCHES)(SQ.IN.)(EF lEo PSI)PER DEG F------------------------------------------------------------- 1'510.0 451 7 1.7020 1.4660 1.2080 9.40 11.5 1<;10.0 54/19 1.9420 1.5060 1.3366 10.50 10.8 1590.0 451 7 1.7920 1.5020 1.33'i0 9.40 11.5 1590.0 5411 q 2.04LlO 1.5450 1.4076 10.30 10.8 1780.0 84/19 2.07ljO 1.0020 1.'5120 9.05 11.3 2156.0 8lj/19 2.5120 1.7620 1.8280 9.05 I 1 .3 2167.0 721 7 2.3040 1.7370 1.7760 9.25 12.0 WAIANA-DI:VIL CANYON CASE II-3A 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUC10R OPTIMIZATION DATE:12 APR 79 TIM!::9:02:Q3 """*""""'" A *,,INPUT DATA *, Q1600.0 0.oa85 0.66 1U1977 1300.0.06Q9 0.3670 2.3126 53200.0 0.0508 0.630/1977 1320.0.0602 0.3622 2.2862 43f\00.0 0.0497 0.660/1977 1340.0.0623 0.3638 2.2915 56000.0 0.0521 0.636/1977 1360.0.0612 0.3580 2.2704 53600.0 0.0534 0.675/1977 1440.0.0560 0.3548 2.2387 63400.0 0.05fl8 0.673/1977 Ibl0.0.0475 0.3443 2.1648 50900.0 0.0570 0.699/1977 1600.0.0480 0.3480 2.1806 10 IIJUMIIER 'NA"II:--------- 52 NUTHATCH 53 Pfd-lROT tJ:j 51l LAPwINGI55FALCONtJ1 I-'56 CHUKAR 57 RLlJi:.HIRD 58 KIwI ULT.TENS.GEOM.MEAN STRI:NGTHCLBS)RADIUSCFT) **A***A*'********' CONDUCTOR SUMMARY ~-...-~ A"'A**A"**'A*** THERM.LIMIT PRICE($/lB)(AMPERES) AC RESIST. AT 25 DEG C lND.REACT.CAP.REACT. (OHMS/MILE)(OHMS/MILE)(MOHM-MIlES) WATANA-DEVIL CANYON CASE II-3A 230 K~TRANSMISSION LINE COST ANALYSTS AND CONDUCTOR OPTIMIZATION DATf: 12 APR 79 TIME:9:02:Q3 ****************** ** * * INPUT DATA * * to I U1 N UNIT MATERIALS COSTS PRIcr Of TowfR MAIERIAL PRICE Of CONCRfl~ PRIC~OF GROUND WIRe INSTALLED COST OF GROUNDING SYSTEM TOWER SETUP TOWeR ASSFMRLY FOU~JOATIO"J SETUP FOUNDATIUN ASSEI-<ALY FOUNDATION [XCAVATION PRIC~OF MISCFLLANEOUS HAROWARE UNIT LABOR COSTS REFFPENCE YEAR LAHOR COST STRlNG GROUND WIRE STRING LABOR MARKUP UNIT TRANSPORTATIUN COSTS TOWER FOUNDATION CONCRETE FOUNDATION STEEL Cr1NDUCTOR GROUND WIRE INSULATOR HaRDWARE ****************** INPUT VALUF 0.957 $/LR 0.00 $/CI).YD. 0.000 $/LB 0.00 $ITOW[R 1751.s 0.Q55 $/LB O.s QIQO.OO $ITON 0.00 $/CU.YD. ,290.00 $/TOwER 2Q.OO $/MANHOUR 0.0 $/MILE Q.2 PER UNIT 100.0 $/TON, 1~0.0 $/YD 100.0 $ITON 10'0.0 $ITON 100.0 S/TON 100.0 $/TON OR $/M**3 100.0 -$!TON REFERENCF YEAR FOR INPUT 1979 1977 1977 1977 1979 1979 1979 lq79 197Q 1977 1q-,q 1977 WATANA-DEvIL CANYON CASE IT-3A 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR OPTIMIZATION DATE: 12 APR 79TI~E:9:02:ll3 ••••••••••******••**••*••*.******••*•• * * *• AUTOMATIC CONDUCTOR SELECTION ALL QUANTITIES PER MILE * * * *••••**.**_.*.*.*••****.**.********••** CAPITAL COST/DTSCOUNT RATF OF 7.00 PERC~NT PRESFNT WORTH COf\JDUCTfJR -INSTALl.ED COST LINF LOSSES O&M COST LINE COST------------------------------------------------------------------------------------------------------ Nll.:~lM SPAN(FT)MATFRIALS lRANSPOHfATTON INSTALLATION ENG/IDC SUBTOTAL SUBTOTAL SllHTOTAL TOTAL-------------------------------------.---------------------------....-------- I:d "17 21%.1300.1\9569.510'1.90'121.99'17.1951':>3.11633 11.H92.315£178.Ic.n 57 21'j6.1200.901.57.5217.92027.10123.1975011.1163311.4033.317f\70.~ "7 2 1'i6.ILiO 0.92123.':>\60.9093ll.10003.198219.116334.il071.318h23. Sil 2i 67.130 o,<)21115.'::112':>•93237.10256.201033.117')83.~41111.322730. SR 21h7.12UO.9223ll.')?O/J.9ll210.10363.202012.117583.11125.323720. 57 21~6.IS00.95709.526R.92163.10138.203339.11633/J./J19ll.323866. 56 \71l O.1300.8276ll.4678.88729.9760.185931.157630.3767.327327. SR 2167.11100.959B'1.5226.9ll328.10376.205'119.117')83.1I?33.32773/J. 56 I 7RO.]1I(1().I\lIq~l.IHlll.88966.9786.18/:1il17.157630.3833.329879. 56 11RO.1200.1:134';1.11796.'10292.9932.1811471.137630.3812.329912. 53 \':,]0.1300.77500.4ll79.87032.9'573.178584.1/J8218.35 QO.330391. 57 ?1~6.1000.10(1185.5423.9ll1l14.10356.2101UR.11633ll.ll350.330792. "3 \',10.11100.791'1?£111'10.86974.9':>67.180224.141:1218.3637.332078. 56 17/:10.1 SO\).81106/:1.4799.90008.'1901.192776.137630.3937.331.l342. 53 1 ',10.120U.790113.1.l61~?•89077 •9798.182601.148211:1.3669.334£186. ')5 \',90.I 300.7905/:1./J570.87330.-9606.180565.ISO//JII.3640.3349119. 58 2167.IS00.100672.S386.96330.10S96.21298il.117583.4397.33ll96ll. 53 1')1O.1500.13 1760.11550.87688.96/H>•-i 83644.1£18218.3721.335':>82. 55 1':>90.I/JOO.807<)2./J58/J.87283.9601.la?260.1-5071.l4.361\8.336692. 52 1 '110.1200.7~'103.4188.871';9.9587.173837.160117.3459.337£113. ':>5 1')90.120n.130560.ll729.89311ll.9828._f8ll460.1507lll.l.3716.338920. 55 1'190.1500.85ll00.4646.88008.96fil.185734.15074/J.3773.340251. 56 \780.1600.92011./J932.917-88.10097.-198888.137630.4079.3ll0596. Sil 1<;90.1300.79970.4495.89119.9a03.1833/:17.153527.3692.3£10605. ':>3 1510.1600.85158.tl653.8'1108.9802.188721.148218.38/l0.31107-78. WATANA-DEVIL CANYON CASE II-3A 230 KV TRANSMISSION LINE COST ANALYSIS AND CONDUCTOR UPTIMIZATION DATE:I?APR 79 lIME:q:~2143 .AA***.******•••**A***•••***** **•COST OUTPUT PER MILE **PRESENT VALUE RATE * •7.00 PFRCENT * A * A*******••*****A************** CONDUCTOR NUMBER = 2156.KCMIL 1300.FT SPAN 57 87.4 FT TOWER !NSTALlFO COST MATERIAL TRANSPORTATION INSTALLATION TOTAL BRlAKf)(j1lN QUAIH I TV C05T($)TONNAGE:.COS1($)COST($)COSi($)------------------------------.---------------------------------------- Cf.Jt.DIIC TOR 15840.FT 30659.19.90 1990.21730.54378. GRilWJ[)W I RE:o.FT o.0.00 o.O.o.to PlSIIl A J(WS 207.UNITS 1313.1•"14 244.15')7.I tn HJlHD.",ANE 1429.0.47 l!7.1477 •.r;::.TO.-lfiJS 4.3 UNITS 43756.22.8b ?2R6.2831.12.74384. FOUNDATIONS 4.3 UNITS 3327.538.22280.26145. RIGHT OF WAY 13.ACRES 9085.11:\170.n 255. IOC/[rJGH,FFRJNG 9957.9957.----------------------------------------------- TOTALS 89569.1.14.37 5105.90S21.195153. PRESENT VALUE ($) LOSS ANALYSIS [)Fr~AN[)LOSSES E'Nff<GY LOSSES TOTAL LOSSES----------------------------------------------------------NI:SISTAI{Cf:.LOSSFS 61516.54818.Ilb334. COHor,A LaSSES o.o.o. ------------------~---------------._----- TOIALS 61'516.54/H8."116334. APPENDIX C MULTI-AREA RELIABILITY PROGRAM (MAREL) APPENDIX C MULTI AREA RELIABILITY PRroRAM (MAREL) SCHENECTADY,NEW YORK 12301 BULLE.TIN PTI/103 Page 1 of 3 51B 374-1220 SUMMARY 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 topology.The program permits the study of large power pools 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 the individual area reliability levels may be performed with efficiency. 1?RCGRAM ELEMENl'S AND MODELS 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.The program structure is set up to analyze one year at a time under the control of the user.This facilitates the devel.opment;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 INPur CAPACITY IDl\D TIE MAINTENANCE PRCGRAM CONTROL CAPACITY,- PROBI\BILI'I'Y TABLES MULTI AREA RELIABILIT'l EVAW1\TIOO LOAD MODEIS (~~jV SAVE FILES NJRKING FIIES____J FIGURE 1 STRUCl'URE OF MULTI AREA RELIABILITY PR<X;RAM C -1 PTI/103 PROGRAM APPLICATIONS o • • • • • • • Page 2 of 3 Loads are modeled by area with distributions of peak loads for each 'season'of the year.A season may be of whatever leng'th is appropriate for the study,weeks, months, or longer intervals. I'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 Contro!s 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 IDLP 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 system IDLP indices,the probabilities of various failure modes. That is,the program automatically calculates area IDLP values as though the area were isolated and then two separate IDLP values with the actual interconnection.These two IDLP 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.Failure 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 gration and more widespread sharing reserves. regional inte- of generation •Evaluation of the reliability benefits of strengthening ties vis-a-vis additions to generation reserves. C - 2 Pl'I/103 • • • 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 ~ility of individual utilities to re- liably survive the postponement of new plant additions in their own and interconnected systems. ] AVAILABILITY AND SUPPORI' FOR FURTHER INFORMATION 1/78 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 oniy be done on the basis of charging for the time and expense required. Since Pl'I 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,Pl'I will offer all significant MAREL improvements to lessees at add-on prices. Pl'I 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 J MULTI-AREA RELIABILITY PROGRAM (MAREL) SAMPLE OUTPUT SHEETS FOR TWO-AREA RELIABILITY STUDY -YEAR 1989 Note:The following other output sheets (35 cases)are on file with Alaska Power Authority under a separate cover: 8 Independent System Expansion Plans (years 1984 through 1996) •Interconnected System Expansion Plans (years 1984 through 1996) •Interconnected System Expansion,Three-Area Realiability Study with Susitna (years 1992 through 1996) •Interconnected System Expansion Plans,with Firm Power Transfer (years 1984 through 1987 and 1992 through 1996) C -4 co.............. C - 5 n O"l i _ POllER TECmlOLOGIES.INC. Y'roLTI-AREA RELIABILITY PROGRAM: MULTI-AREA RELIABILITY PROCIlAM -MABEL;-- ____VERSION :NOVEr-mER 15.1978 ---- ____POWER TECHNOLOGIES.INC.---- ****************************01 - 18 -1979 ** ************************** STU D Y CAS E: ****************************************************************************~.-**ANCIIORAGE -FAIRBANl<S TRANSMISSION INTERTIE.ECONo:mc FEASIBILITY ** ******2-AREA RELIABILITY STUDY -YEAR 1989 :INTERCONNECTED -1/15/1979 ** *************************************************~~***************************** --~! n L- POWER TECHNOLOGIES,INC. l\fi1LTI-AREA RELIABILITY PROGRAM ***~******************************************************************************MICHORAGE -FAIRBANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY ** ******2-ARF..A RELIABILITY STUDY -YEAR 1989 :INTERCONNECTED -1/15/1979 ** ******************:r.************************************************************* YEAR OF STUDY ::1989 PROBABILITY THRESHOLD =0.10E-07 FAILURE PROB.THRESHOLD ::0.20E-08 __J PROB..RATIO FOR LOAD LEV.= ---J ROUNDING I1W STEP SIZE .. 0.0100 1 MAX.no.OF I\REAS WITH NEGATIVE M.-illG In TO BE EXA1'I1 NED =2 MAX.OF CAPACITY STEPS ::50 SYSTEl'1 DATA --- NO. OF AREAS OR BUSES ::2 NO.OF AREAS WITH GENERATION·=2 . NO.OF AREAS vrrn LOADS NO. OF LINES vrrn OUTAGES NO. OF FIRM LINES ...2 =1 =0 CJ co ,-- POWER TECIINOLOGIES.INC. 11ULTI-AREA RELIABILITY PROGRAM' A!ICIIORAGE -FAIRBANKS TRANSMISSION I'NTERTIE ECONOMIC "FEASIBILITY 2-AREA RELIABILITY STUDY - YEAR 1989 :INTERCONNECTED -1/15/1979 -----DATA FOR LInES WITH OUTAGES ----- ---AVAILABLE CAPACITY PROBABILITY --- LINE NO.1.LI:NK NO.3 TIE FROH AREA.1 ANcnOR -TO-AREA 2 FAIRBA LEVEL CAP<FOR> CAP<REV)PROBABILITY 1 2 e 130 e 130 0.004000 0.996000 -TIME USED IN CPUS :INCREMENT =2.ELAPSED·I:'2 POWER TECHNOLOGIES,INC. MULTI-APJill RELIABILITY PROGRAM I GENERATOR UNIT DATA FOR ANCHORAGE-FAIRBANKS STUDY '1'\:0 AREA SYSTE~I JANUARY 15 1979 SumIARY ON CAPACITY. PEAK LOAD AND MAINTENANCE &AREA.ANCHOR. SEASON 1 2 3 4 5 6 7 8 ~ InSTALLED CAPACITY (MI'/)1747 1747 1747 1747 1747 1747 1747 ,-J.747 i747 PEAK LOAD (MID 1200 882 789 7~2 729 725 826 886 1441 INSTALLED RESERVES; n MW 547 865 958 995 -'1018 1022 921 861 306 \.D PERCENT 45.58 98.07 121.42 132.31 139.64 140.97 111.50 97.18 21.24 CAPACITY ON MAmTENANCE (lim)0 135 227 256 286 287 IB8 122 9 RESERVES AFTER MAINTENANCE & M'I'l 547 730 731 739 :'732 735 733 739 306 PERCENT 45.58 B2.77 92.65 98.27 100.41 101.38 88.74 83.41 21.24 UNIT RETIHEMENTS AND INSTALLATIONS : NO.mJIT CAPCNN)F.O.R.nET/INST SEASON DATE 1 COAL 2 200 0.057 INST 1 1/1989 UNIT RETIREf'1ENTS l1.ND INSTALLATIONS : no.un IT CAPonn F.O.R.RET/lNST SEASON DATE--------------------------- ***.(j\ PO C -14 POWER TECHNOLOGIES,rsc. ~1ULTI-AREA RELIABILITY PROGRAM' GErmIlATOR unrr DATA FOR ANCHORAGE-FAIRBANKS STUDY TWO AREA SYSTWI JANUARY 15 1979 SUMMARY ON CAPACITY,PEAK LOAD AND }IAINTENANCE :AREA.FAI RBA:.. SEASON 1 2 3 4 5 6 '2'8 «) INSTALLED CAPACITY OW)385 385 385 3B5 385 385 385 385 385 n PEAK LOAD (mH 214 177 135 119 112 130 136 166 313 I ....... 0 INSTALLED RESERVES MW III 203 250 266 273 255 249 219 72 PERCENT 40.51 11'2'.51 185.19 223.53 243.75 196.15 183.09 131.93 23~OO CAPACITY ON fIAINTENAITCE (mn 0 14 55 72 100 65 54 25 -0 nESERVES AFTER MAINTENANCE : till 111 194 195 194 173 190 195 194 72 PERCENT 40.51 109.60 144.44 163.03 154.46 146.15 143.38 1l6.8723~OO UNIT RETIREI'lENTS AND INSTALLATIONS : no.unrr CJ\POll{)F.O.R.RET/INST SEASON DATE POWER TECHNOLOGIES.INC. HULTI-AREA RELI-AIlILlTY.PROGRAlI:r! GENEIlATOR UlrIT DATA FOR ANCHORAGE-FAIRBANKS STUDY THO AREA SYSTEM JANUARY 15 1979 .....-:-----/ ~ -_.~.'---r:.._- PO\'ER TECmrOLOGIES.INC. HULTI-AREA RELIABILITY PROGRAl'!1: GENEItATOR UNIT-DATA FOR·ANCHORAGE-FAIRBANKS STUDY TWO AREA SYSTEM JANUARY 15 1979 -----SlJ11MAR'Y IlY·AREAS---- AREA NO.OF UNITS CAP.<:ml) --,--.---,' 0" I-' N 1 ANCHOR 2 FAIIIDA 36 24 1747 385 SEASONAL nESEItVES IN PERCENT OF PEAK LOADS AFTER MAIffTIWANCE OF UNITS FOR THE TOTAL SYSTEM "SEASon RESERv'"ES ORDER SEASON RESERVES---------------------------- 1 44.M·04 1 9 21.5507 2 07.2521 2 1 44.6404 3 100.2164 3 2 87.2{)21 4 107.1132 4 8 8!L 6382 5 107.6100 5 7 96.4657 6 res.W71 6 3 100.2164 7 96.4"657 "/4 107.1182 8 aa.6832 8 5 107.6106 9 21.s;ro,g 6 rea.rerr POWER TECnNOLOGIES.INC. l'ruLTI-AnEA RELIJ\BILITY PROGRA.M' GEN£!1ATOR UllIT DATA FOR ANCHORAGE-FAIRBANKS STUDY rvo AREA SYSTEM'JANUARY 15 191'9 AREA EFOR SYSTEM EFOR ::: 5.4G50 5.8093 7.4169 EFOR :WEIGIITED EFFECTIVE FORCED OUTAGE RATE_Hi PERCENT. ***END OF PROGRAM MNTCE *** THIE USED IN crus THIE USED III CPUS INCREMENT ::: mCRE~IENT = 2.ELAPSED ::: 0.ELAPSED = 4 4 ~:~*AREA 1 .t\1lCIIOR nAS NO UNITS ON *** 1«:<:*HAINTEUA1;CE FOR ~EASpNS.;1 9 if:** ***AnEA 2 FAlnnA nAS NO UNITS ON *** n .".~,.... PO"tlER TECrINOLOGIES,INC. NULTI-ARE/l.RELIABILITY PROGRAM I M:crrOllAGE -FAInBANI<S TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AIlEA RELIABILITY STUDY -YEAR 1989 :IHTERCONNECTED -1/15/1979 ---LOSS OF LOAD PROBABILITY AT VARIOUS AREAS --- ...... U1 AT AREA PROBABILITY ISOLATED PROBABILITY lVlTII LLS PROBABILITY WITHOUT LLS 1 ANCrrOR 0.149268E+00 0.79B471E-Ol 2 FAIRBA 0.190494E+01 0.909675E-Ol 0.676829E-O 1 0.394379E-0 1 SYSTEI'i 0.915377E-01 0.915377E-01 NOTE : LLS =LOAD LOSS SHARING *****ALL PROBABILITIES ARE IN DAYS/PERIOD ***** n-0) POWER TECll...I'{OLOGIES.INC. rfULTI-Aill~A RELIABILITY PROGRAM' ANCHORAGE -FAIRBANKS 'I'.RANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AllEA RELIAnILITY STUDY - YEAR 1989 :INTERCONNECTED -11'15/1919 PRODABILITY OF MINI~ML CUTS --- CUT PRODABILITY CUT MEMBEBS(LINKS)----------------------------- 1 0.792711E-01 1 2 2 O.510032E-03 1 3 3 O.116904E-01 2 3 *****ALL PROBABILITIES ARE IN DAYS/PERIOD ***** POWER TECITNOLOGIES.INC. fruLTI-AnEA RELIABILITY PROGRAl'II JU:cnOIlAGE -FAIIIDANKS TRAlfSMISSION INTERTIE ECONOI'fIG FEASIBILITY 2-/LHEA HELIAIHLITY STUDY -YEAR 1989 :INTERCONNECTED -1/15/1979 --MINHlAL ClITS AND DEFICIENT NODES(AREAS)--- ("")--....J CUT PROBABILITY 1 0.79277lE-O 1 2 0.570032E-03 3 O.116904E-01 NODES(Al\EAS)IN DEFiCIENT REGION 1 ANCIIOR 2 FAIRBA 1 ANCIIOR 2 FAIRllA *****ALL PROBABILITIES ARE IN DAYS/PERIOD ***** L.;;'-~_.>'_. POWER TEClmOLOGIES,INC. !'IULTI-AI\.Ei\RELIABILITY PROGRAM' ANCIJOItAGE -FAInBANKS TRANSMISSION INTERTIE ECONOMIC FEASIBIL'ITY 2-AREA RELIABILITY STUDY -YEAR 1989 : INTEllCONNECTED·- 1....15 ....1979 PROBABILITY THAT EACH LINE IS LIMITING --- n LINE LINK DESCRIPTION TOTAL ARE A TO ARE A PROBABILITY FORWARD DIRECTION REVERSE DIRECTION ~ 0:> R 3 R ANCHOR TO 2 FAIRBA 0.122604E-0 1 0;116904E-Ol 0.570032E-03 *****ALL PROBABILITIES ARE IN DAYS ....PERIOD ***** CJ I-'co POWER.TEClINOLOGIES,INC. MULTI-AREA·RELIABILITY PROORJ\ll[ ANCHORAGE -FAIRDANKS .TRANSMISSION INTERTIE:ECONOMIC FEASIBILITY 2-AREARELIABILITY STUDY -YEAR 1989 :INTERCONNECTED-1/15/1979 ISOLATED SITUATION -SUMMARY : ~LOLP IN DAYS/PERIOD BY·SEASONS. AREA-AREA· SEASON ANCHOR FAIRllA-----"------------ 1 0.0021 0.3096 2 0.0000 0.0071 3 0.0000 0.0000 4 0.0000 0.0000 5 0.0000 0.0000 6 0.0000 o.0000 7:0.0000 0.0000 8 0.0000 0.0000 9 0.1472 1.58B2 YEAR 0.1493 1.9049 POWER TECIINOLOGIFS.INC. HULTI-AREA RELIABILITY PROGRAM' AlfCIIORAGE -FAIRBANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AREA RELIABILITY STUDY -YEAR 1981}:INTERCONNECTED -1/15.11919 CJ N I-' POl\'ER TEt:;IINOLOGIES,nrc. r::JLTI-AHEA HELIABILITY PROGRAM' AnCIIQMGE -FAIRBANKS TRANSMISSION Il'ITERTIE ECONOMIC FEASIBILITY 2-1\nE1\IlELIADILITY STUDY - YEAR 1989 :INTERCONNECTED -1/15/1979 ISOLATED SITUATION -suur-tAllY·: EXPECTED Ml'l DEF I C JEIICY BY SEASON. AHEA AREA SEASON ANCIIOR FAUtBA------------------ 1 42.38 24.04. 2 13.57 19.22 3 0.00 0.00 4 0.00 0.00 5 0.00 0.00 6 0.00 O.CO 7 0.00 0.00 8 0.00 0.00 9 60.24 27.85 I rm ICES FOR TIlE YEAR !1W-DAYS LOLP-DAYS E(IDy) 8.95 0.15 59.99 Gl.81 1.90 27.20 POWER TECHNOLOGIES,INC. MULTI-AIlEA RELIABILITY PROGRAM I JUlcrrOMCF.-FAInDANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILI'IY 2-AREARELIABILITY STlJDY -YEAR 1989':INTERCONNECTED-lL/15/1979' INTERconNECTED lHTII LOAD LOSS SHARING AnEA LOLP TN DAYS/PEnIOD BY SEASONS.. AREA AREA SEASON ANcrron FAIMAn---------------- N 1 0.0004 0.0020 N 2 0.0000 0.0000 3 0.0000 0.0000 4 0.0000 0.0000 I)0.0000 0.0000 6 0.0000 0.0000 7 0.0000 0.0000 8 0.0000 0.0000 9 0.0794 0.0890 YEAR 0.0798 0.0910 POWER TECHNOLOGIES,INC. MULTI-AREA RELIABILITY PROGRAM: ANCnORAGE - FAIRBANKS TRANSMISSION IlfI'ERTIE ECONOMIC FEASIBILITY 2-i\REA IlELIABILITY STUDY -YEAR 1989 :IN1plCONNECTED -1/15/1979 INTERCONNECTED WITII NO LOAD LOSS SHARING : AREA LOLP IN DAYS/PERIOD ny SEASONS. n AIlEA AREA SEASON ANCIIOR FAIIIDA---------------- N W 1 0.0003 0.0017 2 0.0000 0.0000 3 0.0000 0.0000 4 0.0000 0.0000 5 0.0000 0.00130 6 0.0000 0.0000 '1 0.0000 0.0000 8 0.0000 0.0000 ()0.0673 0.0378 YEAR 0.0677 0.13394 POWER TECTINOLOGIES.INC. MULTI-AREA RELIABILITY PROGRAI1': AlrCHORAGE -FAIlIDANKS TRANSMISSION.Il'fl'ERTIE ECONOMIC FEASIBILrlY 2-AREA RELIABILITY STUDY·-YEAR 1989 :INTERCONNi::CTED -1/13/1919 ---SYSTEM RESULT StJm1l\RY IN PER'UNIT.-- PROnABILITY OF SUCCESS EVENTS PROnABILITY OF FAILURE EVENTS :'0~999648E+00 :0.352068E-03 PRonABI~ITY OF NEGLECTED UNSPECIFIED EVENTSI:0.270125E-08 CJ SIDt OF TIlE ABOVE 3 PROBABILITIES ll:'0.100000E+01 N .j:::.PROBABILITY OF UNCLASSIFIED FAILURE EVENTS '=0.620649E-09 *************************"'****************************NOTE:TllE sun OF TIlE FIRST 3 ~1UST DE 1.0000 ******WITIIIN REASOl~ABLE TOLERANCE.*** *************************************************** DEFINITION OF EVENTS : SUCCESS : ALL LOADS SATISFIED. FAILURE:ONE OR ~IORE AREA LOADS NOT SATISFIED. UNSPECIFIED :nOT IDENTIFIED AS EITIIER SUCCESS OR FAILUREe UNCLASSED FAILURE:CAUSE OF FAILURE NOT ESTABLISHED. CAUSE OF FAILURE IS INDICATED BY MINI~~CUTS. TOTAL ELAPSED TUlE IN CPUS =20 *****END 9F PROGRAM J:IAREL ***** ANCHORAGE -FAIRBANKS -TIlANS!'IISSION INTERTIE ECONOMIC FEASIBILITY PAGE 0001- .5224 .5160 .5064 .~1351.0000 .8301 .5Una .5401 .5353 .6321 .0429 .0526 .8731 .0571 .8423 .9519 .9423 ~9375 .9301 .9221 .8918 .nfi46 .0333 .8934 .9024 .9024 .0976 .9343 .9293 .9141 .9372 .9053 .9038 .9341 .9071 .9071 .9649 .9501 .9~15 .9341 .92nl .9162 .9~~3 .9Z02 .3589 .9379 .92~5 .9255 .9367 .9204 .9177 .9542.9477 .8324 .9427 .9219 .9299 .9613 .9548 .9434 .'1441 .')4.41 .9379 .8715 •un5 •Cfl'15 .92'(0 -.9222 -.9222 .9375 .9323 .n!302 .9202 .9155 .9014 .7757 .7719 .OG55 .9393 .9361 .9323 .0~a6 .03C6 .0175 .9135 .0654 .3045 .9531 .9421 ~8340 .95Gri.uaaa .9611 .%31 .92-1-9 .7935 .9474 .C335 .9327 .9575 .6122 .6Hi4 .0:>62 .9G19 .9437.uano .9073 .9444 .9424 .9344 .9703 .9401 •95GfJ .9379 .94·30 .951~ .94<17 .9677 .634·6 .5769 •94{;2 .9615 .9654 .aaso .9073 .9495 ~9476 .9563 .9703 .94ul .9509 .9379 .9494 .9603 •9L:,1)0 .97<:·2 .9.565 .9106 .9122 .95r.~l •929() .90D7 .9Gl1 .13336 .9327 .9575 2 14 1983 2 50 o ANCIIOIlI\GE -FAIRBANKS TRANSMISSION INTERTIE ECONOMIC FEASIBILITY 2-AREA IlELIABlLITY STUDY-YEAR 1996 :INTERCONNECTED-1/15/1979 2 1 (}()0 0 0 000 00 o 010 e 000o()0 0 0 () 1 1 1 '!t 1996- 0.1E-07 0.2E-07 0.5E-05 0.01 0.10- 2 1 2 1 ANCIIOnFAIRBA 1 2 2' 1 0 0 0.004009 2 130 130 0.996000 LOAD DATA II{PEI\. UNIT INTERVAL DURATION CURVE TWO AREA SYSTEU JArmARY 15 1979 1 1 1 2 10 26 9 1 0.01 1.,00 0 11111 1 2 2 3 3 4 4 ~5'6 6 7 7 889 9 ~~9 9 ()0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 000 1 AnCHOR 20 0.0 789.1317.971.1080.1196.1313.1441.1531.1724.1881. 2041.2215.2402.2591. .0333 .6667 .7404 .7500 .6571 .~904 .C032 .4960 .5160 .5737 1.0000 .9169 .9131 .9530 .9500 1~0000 .93~B .9663 .9663 .9615 1.0000 .9913 .9104 .9821 .9697 1.0000 .9829 .9487 .9359 .9017 1.00~O .9512 .9317 .9171 .9171 I~ODOO .9340 .979B .9747 .9646 1.0000 .9685 .9634 .9529 .9529 1.0000 .9731 .9727 .9617 .9563 I.COOO .90&3 .gee3 .9225 .9C25 I.COOO .99~O .9n20 .9701 .95Dl 1.0000 .99~9 .9071 .9571 .9571 1.0000 .99~13 .9n14 .9639 .956G 1.0000 .9310 .9631 .9620 .94~4 1.0000 .9304 .9739 .9739 .9673 1.ceH)C,..9373 •£j.,7~·5 .9554 •.9490 1.GOOO 1.COOO .993;:).'N171 .9f,O:i 1.0COO .9938 .9814 .9689 .9627 L 0000 •CJ-TZ7 .9(,09 .9·14 1 .9274- t •~OC(T •994'~•99"t4-•9-722 .9722 L (jO:}O .99-:'3 .9C%.913%.9687 1 .OO~O .93:>,).9<;04 .9ti<>7 .9390 1.0000 .9962 .9653 .9-:'60 .9463 1.00001.0000 .~OD7 ~9662 .9549 1.0~00 .9754 .8632 .0596 .3421 1.0000 .9340 .9679 .9519 .9359 1.0000 .9730 .9730 .9614 .9614 2 FAIRBA 20 0.0 196.212.231.249.210.291.313.338.362.390. Nen n AIlCUORAGE -FA1RBANKS TMNSlUSSION INTERTIE ECONmUC FEASIBILITY PAGE 0002 n·~ 6n 63 63 n 20 24 37 12 70 21 73 15 15 54 9 15 0.0:15 15 0.055 19 0.055 32 o.ons 0.055 0.0()5 0.0:15 o.oss 0.055 0.0:)5 O.C5'5" 0.055 o.osn 0.055 0.055 o.eGG 0.0:;:; 0.055 0.055 0.055 416.'\!-46.477.511 • 0.~lZ90.69900.73710.76040.57490.59710.56630.51110.43240.41150.38330.37470.3587 0.353C~.3a~3a.~1770.42010.43730.46190.53190.57490.8919Oi93370.93491.00000.7690 1.GOOoO.97"!,~a.9<i,670.94670,.94,530.93130.394UO.U6540.El"!'290.8177 1.00}CO .93670.92790.92790.9051C}.81)9BO.asase.Bti<H,a.82790.7B9 1 1.Ce;.:)00 •99330.<}6670.94r:.:lO:.94000.92330 •903aO.fla~@@.·fl6670.E267 1.G00JO.975~~,).%120.94:1 10.Cf}cHO.133200'.e23<JO.&lH)0-.7900(}-~616C),. I.VOvOO.935~0.9n290.9G940.9530C}.94660.9I8ll0.9()810.90I70.8025 1.00:;00.997,)0.99590.98770.97940.95m~O.93620.90530.89300.0027 I.COOOO.934n().95010.937I0.91970.B9370.Bn~70.87200.B6120.8091 l.nCOaO.lJ6370.96150.951l)O.93510.91590.8D'700.84220.B7lJBO.fl558 I.OOJOO.9l)150.99150.99150.97160.963'70.931nO.8~200.8n920.11693 1.OOJ~l •oocco .96120.931ao.92D<!·Or92n,1·0.92240.901.50:.90450.8955 1.ocoee.9()O<-0.<}')04,O.94350.92310.91990.91670.91350.n'lC20.B55S 1.0(;:.1(;;).96720.95410.92700.924,60.90490.O'JH10.fi'}5'10.ll7D70.3721 1.00JGO.96920.96920.95300.95H90.94520.94520.93150.92120.9041 1.000~O.~8c)GO.97220.96n70.95B~0.94790.93100.92360.92010.G507 1.C03CJ.96770.93D70.93230.91290.90320.90320.90320.U7100.867'7 1.00000.373;'0.erose.C6UlO.eM60.B5m~3.84710.34410.83S2(}.C059 1.()O~:JO.9"H~·O.9C6'1O.90MO.8:>470.G27GO.82750.32-1,60.n 1B7('),30 12 I.C00CO.99720.97750.963f>O.96350.940~O.9~fi20.93320.91010.3904 I.COO~O.99~?O.96010.93Cc)O.92n20.90l)60.90600.901GO.nr.n30.3356 1.COOGO.93':-::;0.93300.914,50.90990.89610.OW)10.U13450.[H,370.8568 1.CO~CO.~9150.9a~C~.97650.94~20.92950.92740.91D30.91450;9017 1.COJC0.96690.911CO.09260.CD040.79890.73970.64469.61020.6088 I.C01J~.97710.910GO.90790.90790.fl9340.83~aO.8aa50.n6320.3434 1.COOGJ.97110.S63~W.33050.ClB70.79630.79240.74510.73320.7201 1.GCOCO.99510.9S160.97300.97170.955no.91650.nS450.32430.6318 1.COOGO.9l)n~0.9ac)~0.92CI0.B9940.BB9nO.S8~00.B432(.}.G1310.7971 GEi~ERt\Tcn UnIT DliTA FOR AUCIIOR.l\.GE-!"liIIillAUKS STUDY T\'.'O AIl.EA SYSTEH JANUARY 15 1979 1 1 1 -2 1 1.OE-12 xncrron 44 12 1•() 1 liNCH 1 2 MICII 2 3 li!;cn 3 4 "'..!:cn 4 5 Allen 5 6 tJ:CII 6 7 AI:CI!7 8 Ar:CI17S 9 tJ1Cn 8 10 m::LU 1 11 D:::LU 2 12 I1ELU a- 13 DZLU 4- 14 D:::LU5 15 EF.LU 6 16 D~LU 7 17 I~F:LU 8 13 BEllii 1 19 p.:-:n.il 2 ::0 C:::JUl 3' N 0) ("') ANCHORAGE -FAIRBANKS TRANSMISSION INTERTIE.ECONOMIC FEASIBIL-ITY PAGE 0003 n N '-l 21 INTL 1 22 INTL2 23 !NTh 3 24 COOP 1 25 COOP 2 26 KnIT A 27 IItTL 4- 23 IIlTL 5 29 rnn,6 30 Inn 7 31 IIOILErt 32 EKUITlf 33 llI::LU 9 34 Allen 9 3~AI1CIIlO 3&COAL 1 37 AHe1I11 33 COAL 2 39 COAL 3 40 C01\L 4 41 COAL 5 42 PEAKAI 43 CEil 1 4"}CEIl 2 45 PEAKA2 -99 COOP 1 COOP 2 EKLUTII -99 1 9 -99 .FAIRBA 1.0 1 CIIE1'l'1 2 cnI::n 2 3 CIIErt 3 4 CHEn 4 r:;CHEn 5 6 ellEn 6 7 DIES 1 n DIf.S 2 9 DIES 3 10 ZI::IHt 1 11 ZEI!Ti 2 12 zrrm 3 13 ZEIHl 4 14 ZI::I:rmi 15 ZEIlHD2 16 ZEmm3 17 ZI::JrHD4 13 ZE~r;D5 19 HEAL 1 20 IIEl!.L D 14 0.055 14 0.055 19.0.055 B 0.016- B 0.0"6 15 0.059 R 71 0.055 71 0.0:;:; 71 0.0:)5 71 0.055 7 o.oss 30 0.016 71 0.055 N 78 0.0:>5 N 104·0.057 If 200 0.057 N 104 0.057 If 200 0.057 N 200 0.057 N 200 0.057 N 200 0.057 N 73-O.eas N 300 0.079 N 300 0.079 N 78 0.055 N 26 12 5 0.059 2 0.059 2 0.059 20 0.059 5 0.055 24 0.OG5 3 0.295 3 0.295 2 0.295 17 o.oss 17 0.0::)5 4 0.055 40.055 3 0.295 3 0.295 3 0.295 2 0.295 2 0.:<'95 26 0.05<) 30._295 1/1986 1/1986 1/1985 1/1986 1/1937 1/1993 1/1989 1/1990 1/1991 ·1/1992 .1/1993 1/1994 1/1996 1/1995 AllCIlOnAGE -FAIRnANKS TRANSmSSION INTERTIE .ECONOMIC FEASIBILITY PAGE 0004 CJ N 00 21 nonr 1 22 HOii.T 2 23 U;~ASK 25 COALFI 27 COALF2 28 COALP3 -99 -99 1 I} -99 65 o.oss 65 0;055 :>0.295 100 0.057 N 1/19BfI 100 0.057 N 1/1992 100 0.057 N 1/1995 APP~NDIX D DATA AND COST ESTIMATES FOR TRANSr11ISSION INTERTIE AND GENERATING. PLANTS APPENDIX E TRANSMISSION LINE ECONOMIC ANALYSIS PROGRAM (TLEAP) APPENDIX F TRANSMISSION LINE FlNANC IAL ANALYSIS