Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
Tyee-Lake Intertie Project Detailed Feasibility Analysis Final Report Volume 1 1984
TYEE-KAKE INTERTIE PROJECT — DETAILED FEASIBILITY ANALYSIS FINAL REPORT VOLUME | EBASCO SERVICES INCORPORATED MARCH 1984 30 [kn OF Se so ALASKA POWER AUTHORITY =) 20038 FINAL FEASIBILITY REPORT AND RECOMMENDATION TYEE-KAKE INTERTIE PROJECT EBASCO SERVICES INCORPORATED BELLEVUE, WASHINGTON 98004 WITH R AND M CONSULTANTS, INC. JUNEAU, ALASKA ALASKA ECONOMICS, INC. JUNEAU, ALASKA POLARCONSULT, INC. ANCHORAGE, ALASKA SUBMITTED MARCH, 1984 2.0 3.0 TABLE OF CONTENTS 1.1 PROJECT BACKGROUND ...... 2... 2. ee ee eee 1.2 OEFINITION OF FEASIBILITY STUDY ........6.6. 1.3 TYEE-KAKE PROJECT OBJECTIVES ..........2.. 1.4 CONSULTATION AND COORDINATION. ... 2... 2.2... 1.5 REPORT ORGANIZATION... 2... 2... 2 ee ee ee 1.6 OTHER CONSIDERATONS ... 2... 2... 2.22. ee eee PROJECTIONS FOR ENERGY CONSUMPTION AND ELECTRICITY DEMAND IN KAKE, ALASKA... 2... 2. ee ee eee ee 2.1 RESULTS OF EARLIER STUDIES OF ENERGY CONSUMPTION . . 2.2 CURRENT FORECAST FOR ENERGY CONSUMPTION... ... ; 2.3. FORECAST FOR MAXIMUM CAPACITY PLANNING ....... 2.4 FORECAST FOR ECONOMIC ANALYSIS .........2.. Zo) CONCLUSION SS ae eile) ee eee el er eel NON-TRANSMISSION LINE ENERGY OPTIONS AVAILABLE FOR KAKE, AUASKA Ss =e eee se lee eee ee ree es 3.1 ELECTRICAL ENERGY GENERATION OPTIONS ........ 3.1.1 Diesel Power Generation (Base Case) ..... 3.1.1.1 Existing Diesel System ....... 3.1.1.2 Future Diesel System ........ 3.1.1.3 Future Diesel System Functional Description:..6 © s36 3s aca os & 4 3.1.1.4 Future Diesel System Costs ..... 3.1.1.5 Conclusions ............. 3.1.2 Combustion Turbine Power Generation ..... Cosi Data is mo crs ste ets) een ee Sale Salsene, GOneluUsIONS:.. ..4. 6.6 ae a = 5 3.1.3 The Hydroelectric Power Option. ....... Cathedral Falls ........... Sal oees 3.13.2 Gunnuk Creek «<6 os ew aw as 3.1.4 The Wood Fired Option ............ Biomass Availability ........ a4} 4.2, Fuel Costs . 3 a6 36 wo «in oo ii TABLE OF CONTENTS Page 3.1.4.3 Sizing of the Biomass Facility ... 3-44 3.1.4.4 Conceptual Design. ......... 3-44 3.1.4.5 Material and Energy Balance ..... 3-46 3.1.4.6 Environmental Impacts ........ 3-49 3014.7 , GOSt Estimate = <0: 2s 3 ss ss = 3-49 S146 Conclusions ... .. .. 1. +. s © 3-53 3.1.5 Wind Generation Option. ........... 3-53 3.1.5.1 Resource Considerations ....... 3-53 3.1.5.2 Siting Considerations ........ 3-56 3.1.5.3 Technology Considerations ...... 3-59 Seleo24 Conclusions’ oj 0. 2 2 2 es. 2 2 3-61 3.2 NON-ELECTRIC ALTERNATIVES... .........2.. 3-64 3.9 CONCLUSION Gem sh a3 is me oo A ew Sl 3-65 TYEE-KAKE TRANSMISSION LINE .... 2... 2.5.2.2 ee ee 4-1 4.1 TRANSMISSION LINE OPTIONS ....... 2.2.2.2. 4-1 4.1.1 Overhead Transmission ............ 4-1 4.1.2 Underground Cable ...........4..-.- 4-2 4.1.3 Submarine Cable ............4.2..- 4-2 4.1.4 Mixed Overhead/Underground Transmission ... 4-3 @.2 GENERAL, LINE ROUTING... . 2 2. ss we mss sw as 4-3 4.3 PRELIMINARY SCREENING FOR VOLTAGE SELECTION. .... 4-6 4.3.1 Voltages Currently Available. ........ 4-10 4.3.2 Other Voltages Considered .......... 4-11 4.3.3 Selection Process ...........2.4.. 4-11 4.4 OVERHEAD TRANSMISSION LINE OPTION. ......... 4-14 474.1 ine Rotting. 3... 52.55 65 sss 5 0 o 4-14 4.4.2 Detailed Line Design... ........2.. 4-14 4.4.2.1 Alternate Line Designs and Clearing Considerations ..... 4-14 4.4.2.2 Foundations! = ss = ss 6 3 6 es 4-26 4.4.3 Interconnection at Petersburg and Kake.... 4-32 4.4.4 Submarine Cable Facilities .......... 4-33 A405 ACG@SS 35 5 sis = ae se se as es 4-33 454.6 Construction... «<< 6 6 o «a «1 6 4-37 TABLE OF CONTENTS Capital Cost Estimate ........ Operation and Maintenance Costs... Oleseli Backup. 2. sec mc mane ac [tne EOSS@S 3 <9 «si Sil grr Glass PPpPpL ~ 0 wo 4.5 Underground Transmission Line Option ........ -1 Underground Line Routing. .......... 2 Cable Selection =<. «23 3 © 3 @ 3 5 5 2 os s 5 -3 Interconnection at Petersburg and Kake .... -5.4 Submarine Cable Facilities .......... 35 6 7 Reliability «6 os 6 oe wee ow 5 we HS ws Cost Estimate «06 6 65 6 os 6 so PHPPPHHPL Ann nnn Capital Cost Estimate ........ Operation and Maintenance. ..... Diesel Backup. 3 2. 6 366 36 «so Linellosses! sss <2 ee ele eet aonnn PPPL ssn PWN 4.6 ENVIRONMENTAL CONSIDERATIONS . . 2... 2... 2. eee 4.6. SoWS s0.5 52 55s 5s AS 5 Se © wt ow 6.2. Water Resources . 2. wee ns cnuen wun 4.6.3) Fist! 22 ss Sew wus we Se we Se 4.654 Wildlife «5555 ses es oes eww se 4 4.6.5 Visual Resources . 2.6. <6 as semeiss oc 5 4.7 PERMITS AND RIGHT-OF-WAY REQUIREMENTS ........ G0.) Permits .«. ec emen oe vem swe He 4.7.2 Right-of-Way Requirements .......... 48) (SCHEDULE Ss eo ee ee ee we ie ls) at 5.0 BENEFIT/COST ANALYSIS OF THE KAKE, ALASKA ELECTRICITY SUPPLY ORTIONS SG roa ao ae ee se eae © 5.1 ASSUMPTIONS FOR ANALYSIS ... 2... 2.2. eee eee 5.2 PRESENT WORTH OF COSTS AND BENEFIT/COST RATIOS ... Deo SENSITIVITY ANALYSIS 25 355 2 2 see © 1 2 5.4 TIMING CONSIDERATIONS ..... 2... 2.2. eee eee 5.5 CONCLUSIONS... 2 2 2 5 eo eo sw ee ew 8 we os 6.0 CONCLUSIONS AND RECOMMENDATIONS .... 2... eee eee iv Installation ..2..0- 5055 en ss se ao : Table No. 3-4 3-5 3-6 3-7 3-9 3-10 3-11 3-12 3-13 3-14 3-15 3-16 LIST OF TABLES Title Alaska State Regulations Defining Purpose of a Feasibility Study as Stated in 3ACC 94.060 Kake Energy Consumption Summary Annual Electricity Consumption, 1983-2035 Capital Equipment List for Diesel Plant Cost Estimate Summary, Diesel System Combustion Turbine Generator Specifications Capital Cost of the Combustion Turbine System Comparison of Diesel and Combustion Turbine Systems Cathedral Falls Hydro Project Significant Data Cathedral Falls Hydro Project Detailed Reconnaissance Level Cost Estimate Cathedral Falls Hydro Project Energy Generation and Utilization Summary Distribution of Hydroelectric and Diesel Electric Power Generation for the Cathedral Falls Project Gunnuk Creek Hydro Project Significant Data Gunnuk Creek Hydro Project Detailed Reconnaissance Level Cost Estimate Distribution of Hydroelectric and Diesel Electric Power Generation for the Gunnuk Creek Project Wood Fuel Availability in the Vicinity of Kake Operating Assumptions for the Heat Balance of the Condensing Power Plant Emission Rates of Air Pollutants Net Emissions Change 3-11 3-14 3-15 3-20 3-23 3-27 3-28 3-32 3-36 3-38 3-42 3-47 3-50 3-51 Table No. 3-17 3-18 3-19 3-20 3-21 4-1 4-2 5-5 5-6 5-7 LIST OF TABLES (continued Title Capital Cost Estimate for a 1500 kW Wood Fired Power Plant Wind Power Classes and their Relationship to Kake, Alaska Wind Power in Watts Per Square Foot as a Function of Nominal Tower Heights Nominal kW Capacities for Rotor Diameters Medium Sized Wind Turbine Capacities Capacity of Tyee-Kake Intertie Capital Cost Estimate Summary of the 24.9 kV Overhead Transmission Line Cost of Clearing Activities Cost Estimate Summary of the 24.9 kV Underground Transmission Line General Assumptions for Benefit-Cost Analysis Summary of Alternative - Specific Assumptions and Values Capital Investment Schedules by Project The Present Worth of Costs for Electricity Supply Options for Kake, Alaska Benefit Cost Ratio of the Electricity Supply Options for Kake, Alaska Alternative - Specific Assumptions for Sensitivity Tests Present Worth of Cost Comparison vi Page 3-52 3-55 3-60 3-62 3-63 4-13 4-39 4-4] 4-58 5-3 5-4 5-6 5-6 5-8 5-9 Figure No. 2-1 3-1 3-2 3-7 3-8 3-10 3-11 3-12 3-13 3-14 4-] 4-2 LIST OF FIGURES Title Kake Load Forecast An Overall View of the Diesel Generator Sets in the Kake Powerhouse A Closeup View of a 300 kW Diesel Generator Set in the Kake Powerhouse Diesel Generator Building Arrangement Combustion Turbine Schematic Cathedral Falls Hydroelectric Project Alternative Hydraulic Data Cathedral Falls Hydroelectric Project Alternative Project Arrangement Cathedral Falls Hydroelectric Project Alternative Dam, Power Conduit and Powerhouse Details Gunnuk Creek Hydroelectric Project Alternative Project Arrangement Gunnuk Creek Hydroelectric Project Alternative Dam and Powerhouse Arrangement Gunnuk Creek Hydroelectric Project Alternative Hydraulic Data General Facility Layout of Wood Fired Power Plant Schematic Diagram of Material Flows of the Wood Fired Power Plant Material and Energy Balance About Wood Fired Power Plant Possible Wind Generation Sites Adjacent to Kake Transmission Line Study Corridors Transmission Line Route vii 3-12 3-16 3-18 3-19 3-30 3-31 3-34 3-40 3-41 3-48 3-58 4-4 4-5 Figure No. 4-3 4-4 4-5 4-6A 4-6B 4-6C 4-60 4-7 4-9 4-10 4-11 4-12 4-13 4-14 4-15 4-16 4-17 4-18 4-18A 4-188 LIST OF FIGURES (Continued) Title Alternative Duncan Canal Crossings Duncan Canal Crossing Route Through Pass Between Duncan Canal and Hamilton Creek Overhead Transmission Line Route Overhead Transmission Line Route Overhead Transmission Line Route Overhead Transmission Line Route 24.9 kV 3 Phase Overhead Line Structure Detail : 24.9 kV Overhead Cable Transmission Line Structure Detail 24.9 kV 3 Phase Overhead Line Right-of-Way Clearing 24.9 kV 3-Phase Overhead Line Danger Tree Clearing 24.9 kV Overhead Cable Transmission Line Right- of-Way and Danger Tree Clearing Requirements Map of Soils between Wrangell Narrows and Duncan Canal Screw Anchors for Guyed Poles Grouted Guy Anchor in Rock Wood Plank Stabilizer Screw Anchor and Log Anchor Typical 25 kV Cable Cross Section Underwater Cable Facilities Underground Transmission Line Route Underground Transmission Line Route viii 4-15 4-16 4-17 4-18 4-19 4-20 4-23 4-24 4-25 4-27 4-28 4-29 4-30 4-31 4-34 4-35 4-45 4-46 Figure No. 4-18C 4-18) 4-19 4-20 4-21 4-22 LIST OF FIGURES (Continued) Title Underground Transmission Line Route Underground Transmission Line Route Typical Cable Installation in Roads Typical Cable Installation in Unroaded Areas State Easement on East Shore of Wrangell Narrows Crossing Design and Construction Schedule ix Page 4-47 4-48 4-52 4-54 4-64 4-65 SUMMARY Ebasco Services Incorporated has undertaken an evaluation of alternative means for meeting the electricity requirements for Kake, Alaska. The form of this analysis includes analyzing the demand for electricity in Kake, describing the range of alternatives potentially applicable for meeting that demand, and analyzing the most appropriate alternatives using benefit/cost analysis. The analysis was undertaken to determine the economic merits of constructing a transmission line from Petersburg to Kake. This determination was made by comparing the transmission line to the current practice of supplying power by diesel generation, and by comparing other supply options to diesel power. For purposes of planning the electricity capacity requirements of Kake, exclusive of the cold storage plant requirements, a "Capacity Planning" load forecast was prepared. The forecast was developed assuming electricity prices of 20¢-36¢/kWh (1982 dollars). Twenty cents reflects the subsidized cost of power in Kake while 36¢ reflects the current unsubsidized cost. At that price level electricity is not used to meet heat requirements. The following optimistic load forecast is used: Total Consumptionl/ Base Loadl/ Peak Loadl/ Year (kWh) (kW) (kW) 1981 1,525,300 103 475 1990 2,434,700 nc2/ nc2/ 2000 3,185,130 nc2/ nc2/ 2005 3,711,800 247 1140 For purposes of economic analysis, however, a “most likely" electrical energy consumption forecast was used. It employed the following annual consumption estimates: Year Annual Electricity Consumption (kWh) 1981 1,525,300 1985 1,974,200 1990 2,228,900 1995 2,537,300 2000 2,836,100 2001-2034 3,239,500 ed SS Based on Capacity Planning Forecast. Not calculated. In = All options considered were evaluated on their ability to meet the full range of loads that could occur in Kake. The options studied in terms of meeting that requirement included the following opportunities: 1) Continuation of diesel electric generation, 2) Replacement of diesel units with combustion turbines, 3) Construction of the Tyee-Kake transmission line, 4) Construction of the Cathedral Falls hydroelectric project, 5) Construction of the Gunnuk Creek hydroelectric project, 6) Construction of a wood fired generating unit, 7) Installation of wind turbines, 8) Weatherization of buildings, 9) Insulation of buildings 10) Passive solar space heating, 11) Passive solar water heating, 12) Fuel oi] furnaces, 13) Heat pumps, and 14) Household wood furnaces. Of these potential options the following proved sufficiently promising to be subjected to benefit/cost (B/C) analysis: diesel electric transmission line Cathedral Falls hydroelectric wood fired power generation. Of the others, combustion turbines proved to be both capital intensive and inefficient when compared to diesel. Gunnuk Creek offered insufficient power potential to be a realistic alternative to diesel. Wind power appeared to have insufficient reliability based on the data at hand. Weatherization, insulation, solar heating, oi] furnaces, heat pumps, and wood furnaces all appeared to have no influence on electrical demand. Benefit/cost (B/C) ratios were estimated assuming the Alaska Power Authority methodology.1/ Assumptions used in this analysis included: 1) A leveling of electricity demand after 20 years; 2) <A discount rate of 3.5% (real); 3) An inflation rate of 0% (real); 4) A fossil fuel price escalation rate of 2.5% (real) for 20 years, and 0% thereafter; 5) An evaluation period of 53 years based upon the investment life of Cathedral Falls; and 6) Various facility investment lives, per the Alaska Power Authority schedule. 1/ See memo from R. Mohn to Engineering Staff regarding Economic Analysis, 7/1/82, for detailed assumptions. xi = { 4 ii t || Vout iG LS Given these assumptions, and the data developed in the system studies, present worth of cost (PWC) values were calculated for each system. They are as follows: Option Present Worth of Cost Diesel: $14,600,000 Overhead Transmission Line: $14,600,000 Cathedral Falls: $18,000,000 Wood Fired Plant: $17,700,000 Underground Transmission Line: $11,800,000 Calculation of the B/C ratios was performed using the following formula: PWC Diesel/PWC Alternative = B/C On this basis preliminary benefit-cost ratios are as follows: Diesel = 1.0 Overhead Transmission Line = 1.0 Cathedral Falls = 0.81 Wood Fired Unit= 0.82 . Underground Transmission Line = 1.24 From the studies conducted in this feasibility analysis, Ebasco concludes that a transmission line is the best alternative for meeting Kake's future energy requirements. The decision on whether to proceed with the project also depends on a financial analysis that will be conducted by the Alaska Power Authority's staff using data included in this feasibility analysis. User agreements for power sale contracts might also be required before state participation in the project would occur. Thus, this feasibility report does not constitute the final decision document. The results of the economic analysis performed by Ebasco indicate that the underground transmission line alternative is economically preferred. The economic analysis might not take full account, however, of the risks associated with using underground cable laying techniques that are unproven in Alaska. Ebasco recommends that two tests be performed to reduce the uncertainty surrounding underground cable installation for the Tyee-Kake Intertie. First, aging tests should be conducted that simulate the conditions in the project area. Second, the Alaska Power Authority should install a test section of cable somewhere in southeast Alaska where conditions are similar to those in the project area. This second test would provide valuable information concerning the feasibility and cost of laying underground cable in shotrock roads, roaded muskeg ares, unroaded muskeg, and other soils. Ebasco concludes that Kake's future energy needs will be best served by a new transmission line. Unless the results of the above-mentioned tests suggest otherwise, the line should be installed underground in unroaded muskeg and other unroaded ares where the underground line appears to have a cost advantage. Again pending the results of the tests, overhead construction may be preferable in roaded areas. xii Ha TH nit anise c| oon) fonanan pane | aaa Of AiG oy bt a ama tm it cn 1.0 INTRODUCTION 1.1. PROJECT BACKGROUND The electricity used in Kake is presently produced by Tlingit and Haida Regional Electric Authority (THREA) diesel generators located in the powerhouse building south of town. These diesel generators are in good condition and are well maintained, although they are expensive to operate because of the cost of the diesel fuel they require. Further, the cost of power produced by diesel generation has increased substantially in recent years as the cost of diesel fuel has risen. In order to stabilize the cost of electricity and decrease the dependency of Kake on fossil fuel, a number of studies have been undertaken to assess the options available to Kake. In October, 1979 Harza Engineering Company completed a reconnaissance report of the Cathedral Falls Project for the Alaska Power Authority. That study, which drew on findings of earlier reports prepared for the Federal Power Commission and the Alaska Power Authority, concluded that the Cathedral Falls Project was economically marginal and suggested that other alternatives, including a transmission intertie to Petersburg and a wood-fired power plant, be investigated. In 1981 a second reconnaissance report, focusing on the transmission line and also analyzing a wood-waste fired power plant, was completed by Robert W. Retherford Associates, part of the International Engineering Company (IECO). This report, entitled “Transmission Intertie Kake-Petersburg, Alaska", concluded that a transmission tie to the Tyee Lake Project would be the most economical means of meeting Kake's future electricity requirement. After the reconnaissance report was completed and reviewed by a number of State agencies, it was determined that a detailed feasibility study would be conducted to determine whether the Tyee-Kake project was feasible. Ebasco Services Incorporated (Ebasco) was selected to prepare this detailed feasibility study. The primary objectives of the feasibility study were to conduct engineering and environmental studies at a level sufficient to develop a detailed cost estimate that would enable full evaluation of the economic viability of this project in comparison with other options. As a part of the feasibility study, it was specified by the Authority that four separate reports be prepared. The first of these reports, the Interim Report, analyzes the generation alternatives which could be used in Kake. The second report, the "Routing and Environmental Report," explains how one route was identified and selected for detailed engineering and economic evaluation. The Routing and Environmental Report is the companion document to this Feasibility Report and was circulated concurrently with the Draft Report for public comment. A third report, the Cost and Engineering Report presents a detailed description of the transmission line alternative including its cost. 2003B After submittal of the three reports described above for review, in November 1982 the Alaska Power Authority requested further study of the underground transmission line alternative. Along with clarification of other details, Ebasco prepared the "Overhead/Underground Reconnaissance Report" in November 1983, followed by the resulting Draft Feasibility Report Supplement in January 1984. These earlier reports were all issued under the title Kake—Petersburg Intertie Project, so named because the transmission line would run from Kake to an area near Petersburg. As described in Section 4.4.3 of this report, however, the actual participation of the City of Petersburg is not assumed for this project or for the Tyee Lake hydroelectric project. The project name has therefore been changed to Tyee-Kake Intertie Project, because the intent of the transmission line alternatives is to transmit power from the Tyee Lake hydroelectric project to Kake. This final project report draws together information from the earlier reports and presents additional information which will aid the Authority in making a decision on how to proceed with any of the alternatives identified for providing Kake with the electricity it needs. 1.2 DEFINITION OF FEASIBILITY STUDY The requirements of feasibility level studies are established by State Law AS 44.83.177, as implemented by regulation 3 AAC 94.060. These requirements are provided in Table 1-1. Briefly, these regulations establish the requirement that a range of alternatives be investigated and analyzed so that the engineering, environmental, and economic merits of these alternatives can be evaluated and compared. An opportunity for public and agency review must also be provided between the draft and final feasibility reports. In the case of the Tyee-Kake feasibility study, the need to consider alternatives is especially important as this has not been done at the feasibility level in prior studies. The project alternatives fall into two categories. First are non-transmission line alternatives including hydroelectric, wood fired, and other generation options. Second are routing alternatives for a transmission line linking Kake and Petersburg. Detailed information on those sets of alternatives was presented in earlier reports which are included in the Appendices to this report. 1.3. TYEE-KAKE PROJECT OBJECTIVES It is useful to explicitly identify project specific objectives when conducting a feasibility study. For the Tyee-Kake transmission line project, Ebasco has identified the four objectives listed below as being of prime importance. These include conceptually designing a project that: Te Provides reliable electric service to Kake. 2. Is based on sound engineering principles. 20038 1-2 TABLE 1-1 ALASKA STATE REGULATIONS DEFINING THE PURPOSE OF A FEASIBILITY STUDY AS STATED IN 3 AAC 94.060 3 AAC 94.060. FEASIBILITY STUDIES. (a) A feasibility study will be used to assess the technical, economic, and environmental aspects of a power project or program identified in a reconnaissance study so that the authority may decide whether to apply for any licenses or permits, or invest in detailed engineering and design. A feasibility study will include information about the project, a statement of all assumptions which affect the economic feasibility of the project and a comparative analysis of all reasonable alternatives to the project under study. (b) In conducting a feasibility study the authority will use various techniques and methods to insure that (1) local, state and federal agencies are consulted to assist in defining the scope of work for the feasibility study; (2) information about the proposed project will include all project construction costs, all project operating costs, the timing and amount of estimated power output from the completed project, a benefit-to-cost ratio, the estimated cost of power based on hypothetical financing conditions, the possible effect of the project on the environment of the area which will be served by the project, the availability of other financing, and estimates of major indirect costs and benefits; (3) a statement of all assumptions which affect the economic feasibility of the project is included which includes the discount rate, relative price trends, the electric load growth assumptions, and the planning period; the statement of assumptions must also address the hypothetical financing conditions upon which the cost-of-power estimate is based, including debt-equity ratio, terms of financing, interest rate or rates, and inflation rate; (4) a comparative analysis of alternatives is included which addresses the preferred plan, the base case plan, and, in the discretion of the authority, the second most preferred plan as identified in a reconnaissance study; the preferred plan may be the same as the base case plan; if a feasibility study is undertaken in the absence of a previous reconnaissance study completed in accordance with 3AAC 94.055, the alternative plans to be addressed will be determined by the authority based on available information; (5) draft feasibility reports are distributed for comment to affected local governments, utilities, public land managers, and to affected federal and state agencies; these recipients must comment on the draft report within 30 days; (6) the completed feasibility report is transmitted to the division of budget and management, Office of the Governor, with a statement of findings and recommendations; (7) copies of the completed report are distributed to affected local governments, utilities, libraries, public land managers, and to affected federal and state agencies. (c) In order to allow comparative analysis of alternative power sources the authority, to the extent applicable, will use the following standard criteria and measures in conducting a feasibility study: (1) a base case plan will be developed that would meet the estimated electric power requirements of the community or region that would result from a continuation of present practices in the community or region or a reliance on liquid fossil fuel generation modes; the hase case plan will be used when comparing alternative plans; (2) other alternatives, either singly or in combination, will be incorporated into the plans, each of which will satisfy the estimated requirements; to the extent possible each plan will be formulated to provide an equally reliable source of power; (3) a reference year and planning period will be established for economic evaluation; the planning period is 20 years unless the set of alternatives under consideration requires a shorter or longer period; (4) the costs to engineer, design, construct, maintain, and operate the power project will be estimated for each plan in terms of reference year dollars, taking into account relative price trends; the relative price trends will be established each year by the authority not later than July 1 after consulting with federal and state energy and budget agencies, but may be changed from time to time as economic and financial conditions change or as the authority deems prudent; (5) using a discount rate representing the estimated long-term real cost of money, the present worth of the cost of each plan over the planning period will be calculated as of the reference date, with adjustment for varying economic lives; the discount rate or a range of discount rates will be established each year by the authority no later than July 1 after consulting with federal and state energy and budget agencies but may be changed from time to time as economic and financial conditions change or as the authority considers prudent; (6) various combinations of alternatives and timing will be evaluated to formulate plans which cost the least; (7) the following indicators will be used to evaluate each plan: (A) economic: (4) present worth of plan cost as compared to the base case plan cost; and (ii) cost of power; -(B) environmental: (i) community preferences; (11) impact on community infrastructure; (iii) timing in relation to other capital projects; (iv) air quality; (v) water quality; (vi) fish and wildlife impact; (vii) land use impact and ownership status; (viii) terrestrial impact; and (x) visual impact; and (C) technical: (i) safety; (if) reliability; and (iif) availability; and (8) the hypothetical financing conditions upon which the cost of power estimate is based will be established each year by the authority not later than July 1 after consulting with federal and state energy and budget agencies, but may be changed from time to time as economic and financial conditions change or as the authority considers prudent. (Eff. 9/13/81, Reg. 79) 19408 1-3 3's Is environmentally acceptable. 4. Minimizes costs. These four objectives underlie Ebasco's basic approach to formulating and evaluating the options under study. Meeting these objectives is a requirement of all options and these objectives were considered in developing and evaluating the alternatives described in Sections 3.0 and 4.0 and in analyzing the two corridors presented in the Routing and Environmental Report. 1.4 CONSULTATION AND COORDINATION Throughout their efforts on the Tyee-Kake study, the Authority and its consultant, Ebasco, have sought the input of interested agencies and organizations. The objectives of these activities included: focusing attention on issues of concern early in the planning process, making the planning process open and flexible, and allowing for local input into project studies. Coordination with affected local, state and federal agencies, and organizations early in the planning process was a key factor in identifying the environmental factors used in analyzing and selecting a preferred corridor, and in defining a specific route within that corridor. : Consultation and coordination involved three components: 1) meeting with agency representatives; 2) conducting a public meeting in Kake; and 3) soliciting input from all agencies and organizations that would have an interest in the project. Public meetings were held in both Kake and Petersburg after allowing time for review of the draft project documents. A list of the agencies and organizations contacted, a sample letter sent to the agencies, and their responses are provided in Appendix A of the Routing and Environmental Report. All of these contacts were an integral part of the planning studies on this project. 1.5 REPORT ORGANIZATION An integral part of the assessment of the feasibility of a project such as the Tyee-Kake line is a complete analysis of the full range of alternatives available to serve Kake's future energy needs. Such an analysis, in turn, requires forecasts of future consumption. In light of these two considerations, this Report is organized to present a description of Kake's future energy needs in Section 2, entitled "Projections for Energy Consumption and Electricity Demand in Kake, Alaska," followed by an analysis of the nontransmission line energy options available (Section 3), entitled "Nontransmission Line Energy Options Available for Kake, Alaska." In Section 3, alternatives are characterized according to certain parameters (e.g. reliability and efficiency) which allow them to be screened so that only the most viable alternatives are included in the evaluation of the alternatives in Section 5. Section 4 presents the transmission line alternatives, summarizing much of the information in the Cost and Engineering, Overhead/Underground Reconnaissance, and Supplement Reports. Section 4 also describes the proposed line's routing, design, construction, operation, maintenance, costs, permits, right-of-way requirements, and schedule. 20038 Section 5, presents a summary of the evaluation of the alternatives which were not screened from detailed evaluation. The alternatives selected for economic analysis are assessed as independent alternatives, and in combination according to their capability to be combined with other alternatives. These combined or individual alternatives are assessed in regard to the load forecast identified by Alaska Economics personnel as the “most likely" forecast. Factors related to the timing of the potential development associated with the alternatives are also presented so that the decision-makers can assess which alternatives they should pursue and also identify the implications of either delaying or expediting development of any of the alternatives. Section 6 presents Ebasco's recommendation. This recommendation is qualified. The potential effects of the recommendation on future generation, transmission line, and test programs are discussed in this section. Finally, the economic implication of the recommendation is addressed. Appendices A through D in Volume II of this report include prior reports, data, maps, and printouts which are a part of the study. 1.6 OTHER CONSIDERATIONS There are several factors to consider in reviewing this report. In general, the report presents detailed information about the most relevant alternatives available for meeting Kake's future electrical energy needs. For example, a major finding of this study is that the thermal and electrical needs of Kake are met independently, by separate and distinct energy sources. Further, for economic reasons, these needs will continue to be satisfied separately for the foreseeable future. For this reason, nonelectrical energy systems are not treated extensively in this report. Those alternatives are analyzed in Polarconsult's Evaluation of Unconventional Energy Alternatives Reportl/, prepared as a part of this feasibility study. Along with adopting a thorough approach, this report is based on proven systems and known costs. In light of this policy, manufacturers were contacted about a specific piece of equipment's suitability for a given application and its cost. Such information was used in this study and where used is appropriately cited.2/ 1/ This report was prepared by Polarconsult, Anchorage, under a subcontract to Ebasco Services Incorporated as a part of the Tyee-Kake Intertie Detailed Feasibility Analysis. 2/ Report reviewers should not construe any discussion of a particular manufacturer's product as an endorsement of that product or as a recommendation that it be used. Rather, any mention of specific products should denote that such equipment is available for the proposed application and that there is a firm basis for identifying its cost. 20038 1=5 When making cost estimates or analyzing and evaluating costs for the various alternatives only "out-of-pocket" or incremental costs were considered. The cost of existing systems for generation and distribution of energy were considered as "sunk." For example, costs of the base case calling for timed replacement of old and additional new diesel generation capacity do not include the cost of existing generation and distribution equipment. The "Capacity Planning" and “most likely" load forecasts used in this study represent a conservative approach to forecasting and analysis of electrical energy needs. When a range of forecasts for future energy needs can be identified, as is the case here, the highest or one of the higher forecasts is chosen for planning future generating capacity, in order to be certain of meeting the potential demand of the higher growth scenarios. Developments required to reach this capacity while meeting all interim demands are used to determine capital costs for the study. The “most likely" forecast is used to determine actual consumption of energy for the study period and to estimate fuel. and operating and maintenance (O&M) costs. All of these estimates of capital costs, fuel costs, and O&M costs. 2003B 2.0 PROJECTIONS FOR ENERGY CONSUMPTION AND ELECTRICITY DEMAND IN KAKE, ALASKA During the course of this feasibility study, the time elapsed since the initial publication of Economic and Energy Load Forecast, City of Kake, Alaska, combined with changing conditions, prompted a reevaluation of those forecasts. For that reason, the electricity demand in Kake as it was forecast in 1982 is presented in Section 2.1 and the current evaluation as of January 1984 is presented in Section 2.2. 2.1 RESULTS OF EARLIER STUDIES OF ENERGY CONSUMPTION Load forecasts appearing in the Draft Feasibility Report (Ebasco 1982a) were prepared by David Reaume of Alaska Economics, Inc. His two reports, Economic and Energy Load Forecast, City of Kake, Alaska (Reaume 1982a) and Kake Electricity Demand, Low Demand (Reaume 1982b), appear as Appendices A.1 and A.2. The process used to develop the forecasts, and the forecasts themselves, are described briefly below. Consumption analyses were performed to forecast the consumption of electricity through the year 2005. They were made under the assumption that consumers can change fuel and energy sources as a result of changing conditions. Further, they were made assuming a cost of power of 20¢/kilowatt hour (kWh) at the low end, and 36¢/kWh at the high end (1982 dollars), consistent with Alaska Power Authority assumptions. These costs are based upon subsidized and total costs of power supplied to consumers in Kake. Forecasts were also made recognizing the existence of one self-generator of power, the Kake Cold Storage plant. This self-generator could dramatically increase the consumption of electricity provided by Tlingit and Haida Regional Electrical Authority (THREA) if it elected to stop generating its own power and purchase power from THREA. The Kake Cold Storage load was not included in the scenarios used for capacity planning or economic analysis. Once the demand estimates were developed using the Alaska Economics forecasts, they became the basis for formulating and evaluating all of the options available to Kake. These estimates established the size of systems required. Consequently, the estimates influenced capital, operating, maintenance, and fuel costs of systems. To evaluate potential projects, five levels of demand were forecast. The basic differentiation between these scenarios is presented below: 20008 Forecast for Total Electricity Consumption in Kake, Alaska (MWh ) (1) (2) (3) (4) (5) Low Demand Low Demand High Growth High Growth Most Likely Without With Cold Demand Without Demand With Demand Without Year Cold Storage _Storage Cold Storage Cold Storage _Cold Storage 1981 1,525.3 2,026.3 1.525.3 2.026.3 1,525.3 1985 1,750.5 2,650.5 2,123.4 3,023.4 1,974.2 1990 1,920.3 2,820.3 2,434.7 3,334.7 2.228.9 1995 2,109.9 3,009.9 2,822.3 3,722.3 2,537.3 2000 2,312.7 3,212.7 3,185.1 4,085.1 2,836.2 2005 2,531.0 3,431.0 3,711.8 4,611.8 3,239.5 Forecast for Capacity Planning Based on the results given by Reaume (Section IV, Appendix A.1 of this report), the High Rate of Growth economic scenario was used. This scenario indicates that total Kake energy demand will increase by 61.6 percent in the period 1982 through 2005. In satisfying a major portion of this growth, demand for electricity will increase by 128 percent from 2026 megawatt hour (mWh) in 1981 to 4612 mWh in 2005. This data is presented in Table 2-1. After removing Kake Cold Storage from the consumption estimates, growth for THREA during the study period is 143 percent from 1525 mwWh in 1981 to 3712 mwWh in 2005. By using these figures to obtain an average load in 2005 with the 1981 peak to average and base to average ratios, the following load growth table was generated: Growth of Electric Loads in Kake, Alaska High Growth Scenario, Without Cold Storage 1981 2005 Hourly Base Load 103 kW 251 kW Hourly Average Load 174 kW 424 kW Hourly Peak Load 475 kW 1157 kW The peak capacity to be planned for Kake in the year 2005 then is 1157 kW. There are two main factors which could affect this figure. They are a shift from fueled space heating (011 and wood) to electric space heating or a change in policy at Kake Cold Storage resulting in the purchase of power from THREA. The potential for sale of power to Kake Cold Storage is addressed further in Section 2.2 The main factor which could influence a change from fueled space heat (99.7 percent of all space heat in 1981) to electric space heat is price. However, even when fossil fuel price escalation rates as high 2-2 20008 €-2 1981 ALL SOURCES (MMBTUS) RESIDENTIAL 35658.98 COMM/GOVT 24375.27 MANUFACTURING 3912.13 ALL SECTORS 63946. 33 ELECTRICITY (MWH) RESIDENTIAL 113.49 COMM/GOVT 651.36 MANUFACTURING 661.47 ALL SECTORS 2026.32 FUEL OIL (000'S GALS) RESIDENTIAL 166.22 COMM/GOVT 158.38 MANUFACTURING 11.83 ALL SECTORS 336.83 BOTTLED GAS (000'S GALS) RESIDENTIAL 18.96 COMM/GOVT 1.49 MANUFACTURING +22 ALL SECTORS 20.66 woop (CORDS) RESIDENTIAL 600.00 COMM/GOVT 10.00 ALL SECTORS 610.00 EXCILUDES FUEL OIL USED FOR POWER GENERATION BY THREA AND THE KAKE COLD STORAGE TABLE 2-1 KAKE ENERGY CONSUMPTION SUMMARY 1985 4437666 27945.51 5868.19 78190.36 1165.88 865.31 992.21 3023.40 206.03 178.68 17.15 402.46 27.67 1.68 +33 29.68 662.21 11.28 673.49 1990 "8249.58 30149 .82 6043.76 84443,17 1279.61 1011.90 1043.19 3334.70 223.99 190.86 17.75 432.61 30.29 1.79 +35 32.43 115.99 12.05 728.04 1995 50708. 30 33159.93 6219.33 90087 .56 1399.95 1228.16 1094.17 3722.28 235.35 207.11 17.175 460.21 32.77 1.95 +36 35.08 733.91 13.08 746.99 2000 53713.96 35474.95 6394.90 95583.60 1532.79 1407.18 1145.15 4085.13 249.27 219.29 17.75 486.31 35.58 2.06 +38 38.02 760.28 13.85 774.12 2005 57320.81 39438.96 6570.46 103330.23 1679.13 1736.51 1196.18 4611.78 265.99 239.59 17.75 523.34 38.74 2.25 40 41.39 196.13 15.13 811.26 as 5.2% above that of electricity were considered, there was no price incentive for consumers to shift from fuel oi] and wood space heating to electric space heating. The optimistic forecast was, therefore, considered a reasonable representation of high load growth, regardless of changes in fossil fuel prices. 2.2 CURRENT FORECAST FOR ENERGY CONSUMPTION The load growth forecasts discussed above were made in 1982 based on data through 1981. For this final report, electricity consumption figures for the City of Kake in 1982 and 1983 were compared to the earlier forecasts. The Kake Cold Storage load was reevaluated, as was the possibility that their load might be added to the THREA system. Possible future industrial development was also considered. These topics and resulting conclusions are discussed below. Load Growth in 1982 and 1983 Electricity consumption records for the City of Kake were examined for the years 1982 and 1983. Consumption by residential, commercial/ government, and industrial sectors was compared to the detailed forecasts which appeared in the Draft Feasibility Report. Residential use in 1982 was 835 MWh, in line with the optimistic load growth forecast. Residential use in 1983 was 852 MWh, slightly below the most likely forecast for that year. Residential consumption figures therefore indicate that actual use has been within the range originally predicted. Consumption figures for the commercial/government and manufacturing sectors are less clear. Changes in reporting procedures, plus the correction of previous meter readings for the public facilities sector, make precise data comparisons difficult. Actual use appears to be in the middle to upper portion of the original forecast range. In general, actual use in 1982 and 1983 suggests that the original range of forecasts is adequate for further planning. The most likely forecast is still a viable assumption. Future Industrial Development The original load forecast assumed the there was little liklihood of increased industrial development associated with the area's forest resources. If such industrial development did take place, however, it should stimulate higher load growth. The degree of change is uncertain, however. If a new industry provides its own power, as is often the case in the forest products industry, the impact on load growth will be associated primarily with employees moving into the area, plus some secondary impacts. This effect would fall within the high growth forecast developed in 1982. If the industry does not produce its own power, but plans to purchase electricity from THREA, the load could increase significantly. Because such industrial development and its relationship to THREA is uncertain, no additional forecast has been prepared. 20008 Kake Cold Storage The 1982 forecast assumed that the Kake Cold Storage load, if added to the system, would increase system load by 900,000 kWh annually and 900 kW peak load.1/ This is double the facility's self-generated peak of nearly 450 kW in 1981. At the time the earlier forecast was prepared, the company planned to double its capacity. By the end of the 1982 summer season, peak load was expected to reach 800 kW. The expected doubling of the Kake Cold Storage peak load has not taken place at this time. Recent discussions between THREA and Kake Cold Storage, however, suggest that the facility is considering contracting with THREA for as much as 375 kW peak during the summer and 50 kW peak during the winter. Plans are not firm, but engineering design has been started for the distribution hookup. The connection is not included in the "most likely" load forecast at this time. Because of the continuing uncertainty surrounding the possible size of the Kake Cold Storage load and its relationship to THREA, several options were developed for use in the economic analysis. It is hypothesized that the facility may continue to generate its own electricity, adding nothing to the Kake load; it might add roughly 400,000 kWh to the system load, as the current negotiations suggest; it might add 900,000 kWh to the system load, as assumed in the earlier report; or it might fall somewhere in between, adding about 650,000 kWh to the system load. Complete forecasts of annual energy consumption and peak loads by year for each set of assumptions are shown in Appendix A.4. The forecasts are summarized in Table 2-2. 2.3 FORECAST FOR MAXIMUM CAPACITY PLANNING The foregoing review of 1982 and 1983 electricity consumption and reevaluation of forecasts did not result in any findings which would change the forecast to be used for capacity planning. The High Growth Demand Without Cold Storage remains the forecast to be used for planning. By applying 1981 ratios for peak/average and base/average capacities, the required capacities can be calculated and compared to the existing capacity, less retirements, that will exist in those years. 1/ The calculations made for the Draft Feasibility Report used the actual 1981 load factor to estimate the relationship between the Kake Cold Storage facility's peak load and its annual energy use. Later calculations made for the Draft Feasibility Report Supplement indicate that the load factor would change as the Kake Load itself changes. The following formula shows the relationship of peak load to annual kWh energy. Peak Load (MW) = (((kWh Load/1000)/8760)/Load Factor) Complete forecasts are included in Appendix A.4. 2-5 20008 TABLE 2-2 ANNUAL ELECTRICITY CONSUMPTION, 1983-2035 (MWh/year) Most Likely Forecast Low Forecast High Forecast KCS=0 KCS = KCS = KCS = KCS=O KCS = KCS = KCS=0 KCS = 400 650 900 400 900 900 Year MWh MWh MWh MWh MWh MWh 1983 1735 = 2135 2385 2635 1634 2034 2534 1800 2700 1985 1974 ©2374 2624 2874 1751 2151 2651 2123 3023 1990 2229 2629 2879 3129 1920 2320 2820 2435 3335 1995 2537 =. 2937 3187 3437, ~=2110 2510 3010 2822 3722 2000 2836 3236 3486 3736 2313 2713 3213 3185 4085 2002- 3000 3400 3650 3900 2398 2798 3298 3386 4286 2035 KCS = Cold Storage. 2-6 20008 Unretired Firm Existing Capacity Required Capacity (kW) Year Total (kW) (kW) Base Average Peak 1985 1600 1100 143 242 661 1990 1/ 600 300 165 278 759 1995 600 300 191 322 879 2000 2/ 0 0 215 364 994 2005 0 0 251 424 1157 Whatever source is planned for supplying Kake's electrical energy must, at a minimum, be able to satisfy the differences between peak required and firm existing capacities in any given year. Further, the total system must be able to supply the energy for consumption described in Section 2.4. The transmission line alternatives, for example, have been designed to meet the full range of electrical demand forecasts. 2.4 FORECAST FOR ECONOMIC ANALYSIS A total of nine load forecast scenarios were used in the economic analysis of the underground transmission line alternative and the diesel generation base case to test the sensitivity of the results to changes in the load forecast. Other alternatives were evaluated only using the most likely load forecast. The nine configurations include: Most likely forecast without Kake Cold Storage (KCS) Most likely forecast plus KCS at 400 MWh Most likely forecast plus KCS at 650 MWh Most likely forecast plus KCS at 900 MWh Low forecast without KCS Low forecast plus KCS at 400 MWh Low forecast plus KCS at 900 MWh High (optimistic) forecast without KCS High (optimistic) forecast with KCS at 900 MWh oooo0oo0o00090 These forecasts are shown in detail in Table 2-2. The most likely load forecast without Kake Cold Storage is considered the most probable situation. Six of the nine forecasts are displayed in Figure 2-1, in graphic form. The results of the economic evaluation are discussed in Section 5.0. 2.5 CONCLUSION Demand for electricity in Kake, Alaska will grow in a range bounded by the low and high growth forecasts. Its growth will be influenced by industrial growth, population growth, and the purchase of appliances, but not by the use of electricity to serve space heating needs. Im ~ The two 500 kW diesel generators will be retired or replaced in 1989. The two 300 kW diesel generators will be retired or replaced at the end of 1995. Im hy 2-7 20008 8-6 x= = = z o e a. = > no z 9° Oo > E 9 a Fe Oo WwW — Ww LEGEND —-— LOW, W/O KAKE COLD STORAGE(KCS) MOST LIKELY, W/O KCS LOW, PLUS KCS AT 400kW PEAK —-—— — HIGH, W/0 KCS MOST LIKELY, WITH KCS AT 660kW PEAK — ---—— HIGH, WITH KC8 AT 900kW PEAK ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS KAKE LOAD FORECAST Figure 2-1 _EBASCO SERVICES INCORPORATED Perhaps the most significant single factor influencing demand will be whether or not Kake Cold Storage alters its current practice of being a self-generator of power, and ties into the THREA system. This is currently considered uneconomic. Because of this variation in forecasts, a high growth scenario has been chosen for prudent capacity planning. The median or most likely forecast has been chosen for economic analysis. These scenarios, however, do not include the Cold Storage electricity consumption and represent a lower forecast than either the low or high growth scenarios which include Kake Cold Storage. 2-9 20008 3.0 NONTRANSMISSION LINE ENERGY OPTIONS AVAILABLE FOR KAKE, ALASKA In addition to the Tyee-Kake Transmission Line, which is addressed in Section 4.0, numerous options are available for supplying the energy requirements of Kake, Alaska including: 1) Diesel Power Generation (the base case); 2) Combustion Turbine Power Generation; 3) Hydroelectric Power Generation; 4) Wood Fired Power Generation; 5) Wind Turbine Power Generation; 6) Weatherization of Buildings; 7) Insulation of Buildings; 8) Passive Solar Space Heating; 9) Passive Solar Water Heating; 10) Fuel Oi] Furnaces; 11) Heat Pumps; and 12) Household Wood Furnaces. Waste heat recovery is considered in the context of thermal power generation. It is potentially appropriate for thermal generation systems, such as diesel, combustion turbines, and wood or coal-fired steam plants. The alternatives listed above are discussed in this section, and considered in terms of the following parameters: 1) Relevance to meeting future electricity requirements of Kake, Alaska; 2) Proven reliability; 3) Efficiency; 4) Suitability, including environmental impacts; and 5) Cost considerations. The above parameters are screening tools and are used to select those options which are to be carried forward for economic (benefit/cost) analysis in comparison with the transmission line alternatives. "Relevance" in meeting the future electricity requirements of Kake is important because the economic and energy forecasts, as discussed in Section 2, demonstrate that there is a clear separation between heating and electricity sources. Alternative fuel sources for meeting space heating requirements will not influence electricity demand, since space heating is most economically achieved by using oil or wood fuel. Similarly, methods for conserving fuel used for space heating will not 20018 influence future power requirements. As a consequence, such systems will not influence decisions to reinvest in diesel units, construct a transmission line, or opt for yet another electricity supply system. "Proven reliability" in commercial practice is used to differentiate potentially interesting but unproven technologies from those with demonstrated ability to generate electricity in a cost effective manner. This is particularly important in remote areas where no established interconnecting transmission grid can be used to supply power when unscheduled outages occur. "Efficiency," for thermal options, is a (fuel) cost consideration. Efficiency is an important factor in assessing the feasibility of an alternative in the long run. "Suitability," including environmental impacts, refers to the assessment of whether each alternative has attributes which are incompatible with the conditions which prevail at Kake. For example, if development of a particular alternative causes environmental impacts which are significant in a local context then that option is determined to be unsuitable. In the following analysis, the suitability of a particular scenario is only raised as an issue when it is considered important enough to jeopardize the development of that option. Suitability also has cost implications because it may be necessary to modify a proposal, including increasing its cost, to make it suitable in Kake. These costs, as well as other costs such as capital outlays, are significant issues and are vitally important in characterizing alternatives. By use of these screening parameters, analysis of the most promising alternatives is facilitated. Comparisons can be made on an equivalent basis not only in terms of economic assumptions but also in terms of system considerations. Characterization of all of the alternatives in light of these considerations enables identification of which alternatives will be carried forward and compared to the transmission line alternatives in the economic analysis. 3.1 ELECTRICAL ENERGY GENERATION OPTIONS 3.1.1 Diesel Power Generation (Base Case) 3.1.1.1 Existing Diesel System Currently, the electricity needs of the community of Kake are provided by a diesel generating station owned and operated by THREA. The plant consists of two 13-year old Caterpillar generators rated at 500 kW each, and two 7-year old Caterpillar units rated at 300 kW each. Total capacity, then, is 1600 kW. Firm capacity (total capacity less the capacity of the largest unit) is 1100 kW. The existing capacity, with scheduled replacements of slightly larger size as discussed below in Section 3.1.1.2, is adequate to meet the capacity requirements of Kake through 2005. 2001B 3-2 The current power plant is well maintained, as illustrated in Figures 3-1 and 3-2. Major overhaul occurs every 3 years on each unit. Lubricating oi] is changed every 1,000 hours on the large units and every 200 hours on the smaller units. The coolant mix of water/ anti-freeze is adequate to -31°F, and it is changed every 2 years. For purposes of this analysis it is assumed that these units have a remaining useful life of at least 7 years on the larger units and 13 years on the smaller units. This is consistent with Alaska Power Authority guidelines for estimating the useful life of power generation systems. The diesel units are located approximately 2 miles from town, principally in order to minimize noise impacts from their operation. They are quite efficient for small power plants, as shown in the table below. MANUFACTURER'S ESTIMATE FOR HEAT RATES FOR EXISTING DIESEL at AT FULL LOAD AND 50% LOAD (In Btu/kwWh) Unit Load . 300_kW 500_kW 100% 11,060 10,550 50% 11,110 11,660 Source: Caterpillar Generator Set Manual The heat rates cited above, approximately 11,000 Btu/kwWh (higher heating value basis), are based on manufacturer's specifications in the absence of detailed data on the existing units. They are comparable to central station power plant values. If achieved in practice they are quite attractive when the scale of the operation is considered. They are particularly attractive in partial load situations, as other types of equipment (e.g., steam and combustion turbines) perform less effectively in such situations. It should be noted that the heat rate cited above, and used throughout the remainder of this report, has not been adjusted for in-plant electricity consumption, or losses associated with the system beyond the generator. Such uses and losses are expected to be small. Further, a conservative assessment of alternatives is achieved by using the 11,000 Btu/kWh heat rate in calculating the costs of the base case. 20018 FIGURE 3-2 A CLOSEUP VIEW OF A 300 kW DIESEL GENERATOR SET IN THE KAKE POWERHOUSE. 3-4 FIGURE 3-1 AN OVERALL VIEW OF THE DIESEL GENERATOR SETS IN THE KAKE POWERHOUSE. ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS DIESEL GENERATORS IN THE POWERHOUSE EBASCO SERVICES INCORPORATED 3.1.1.2 Future Diesel System One option available to Kake, then, is to continue operating the diesel plant, investing in new equipment as replacements are required. This option is discussed below. The diesel option includes incremental investments to maintain the power plant as an efficient, effective unit generating all THREA supplied power to the community. The system will be built. in stages, based upon replacing existing units and systems at the end of their useful life. In 1989 the two 500 kW generators will be replaced with 600 kW units. In 1995 the two 300 kW generators will be replaced with another 600 kW unit. This plan calls for scheduled replacement only. As can be seen by reviewing Section 2.3, the existing firm capacity with the above described replacements (1200 kW from 1989 on) will be able to meet Kake's maximum required capacity in the year 2005. In 1995 the building, fuel oi] storage tanks, and other systems will also be replaced. Replacements will occur on a 20 year cycle, to the year 2035. A functional description of the power plant as it will exist in 1995 is provided in Section 3.1.1.3. The possibility of utilizing waste heat from the diesel plant was investigated. Waste heat from the exhaust gases and the cooling water jacket may be captured and converted into hot water or steam for distribution to community structures (e.g., the community building and high school) and residences. This is potentially quite attractive from an efficiency perspective. The location of the diesel plant relative to such heat users and the relatively low energy density of such structures, however, makes this proposition appear impractical. In addition, because the power plant was moved outside of town in response to objections concerning noise and land requirements, it is doubtful that relocation to the center of town would be well received. Further, an analysis of potential sites adjacent to the potential waste heat users was conducted and no suitable sites could be found. 3.1.1.3 Future Diesel System Functional Description Fuel oi] will be stored outdoors in aboveground American Petroleum Institute (API) approved tanks with a suggested minimum of 30 days of fuel capacity. The tanks will be equipped with internal heaters for maintaining the fuel at a temperature above its pour point. The tank(s) will be located immediately adjacent to the powerhouse. Two 100 percent capacity fuel oi] transfer pumps will be installed inside the powerhouse. Each pump will be sized to be capable of 20018 3-5 supplying the entire needs of two generating units. The transfer pumps will supply oi] to the diesel day tanks on demand from level switches in the day tanks. The individual diesel day tanks are equipped with fuel injection pumps. Each diesel generator will be a complete skid mounted unit. The generators will be self exciting, brushless, single bearing, close coupled machines capable of delivering 600 kW at the rated speed. Combustion air will be drawn from outdoors for all three machines with a residentially rated exhaust silencer installed indoors and a horizontal exhaust through the powerhouse walls. A small motor driven compressor with air receiver will supply compressed air for starting the diesels. In the event of a black start, the air in the air receiver will be capable of four (4) normal starts. The heat rate for these diesels is 11,875 Btu/kWh (lower heating value basis), or 11,000 Btu/kWh (higher heating value basis). The diesel generator will be supplied with all necessary controls for fully automatic operation including start-up, load following, and shutdown. The complete power plant will include an all weather, fully enclosed, insulated structure for housing all three replacement units. All equipment necessary for starting, operating, and normal maintenance of the units, and synchronous control of the generators, will be inside the structure with the exception of the fuel storage tanks. The equipment required for this system is shown in Table 3-1. The layout of this system is shown in Figure 3-3. 3.1.1.4 Future Diesel System Costs The capital cost estimate for this system is calculated at $1,333,000 or $740/kW installed. The total costs are shown in Table 3-2. The total cost is the same as that shown in the Draft Feasibility Report Supplement. It represents a change from the original estimate in the Draft Feasibility Report. The estimate has been updated to 1983 dollars, and the contingency increased to 20 percent. Operating costs for the diesel system include a labor force of two nonsupervisory operating persons at an annual cost of $53,000 each. Annual maintenance costs come to $49,800/year, assuming $1,060/year spare parts, the continuation of the current maintenance schedule, and a major overhaul every 18,000 (machine operation) hours. It is recognized that these operating and maintenance (O&M) costs are conservative. However, they reflect the need for high system reliability in a remote village. They contribute to the high cost of diesel power. Fuel costs are the final variable. A survey of the Union Oi] and Chevron 011 distributorships in Ketchikan, Alaska provided a delivered price (1983 dollars) of $1.19/gal assuming bulk delivery. This is 20018 3-6 TABLE 3-1 CAPITAL EQUIPMENT LIST FOR DIESEL PLANT *Air inlet filter(s), silencer(s), and ducting *Exhaust silencer(s) and ducting *Diesel/hydraulic starter(s) or air start system system(s) *Day tank(s) *Fuel transfer pump Fuel centrifuge Lighting *0.C. control power source *Synchronization equipment *Switchgear *Control panel(s) Heating and ventilating equipment *Skid mounted diesel or turbine/generator sets *Lube oi] coolers Compressor, piping, and receiver for air start system Fuel storage tank heaters Three 600 kW diesel engines *Items with asterisk are included in turbine generator purchase price. 20018 ELECTRIC DISTRIBUTION CENTER COOLING AIR EXHAUST LOUVER (TYP 3) SSS COOLING AIRY] INLET (TYP 3) RADIATOR DOUBLE VENTED DOOR (TYP 3) SESS DIESEL --— EXHAUST (TYP 3) SSSSSSSO_ESSS RADIATOR / y L ! y | y Y Y ! y H | ALASKA POWER AUTHORITY FUEL STORAGE . TYEE - KAKE INTERTIE PROJECT 100,000 gal. DETAILED FEASIBILITY ANALYSIS DIESEL GENERATOR BULDING ARRANGEMENT FIGURE 3-3 EBASCO SERVICES INCORPORATED TABLE 3-2 COST ESTIMATE SUMMARY, DIESEL SYSTEM Current Estimate (1983 $) 3-600 kW diesels $636,000.00 Auxiliaries & Piping 155,000.00 Electrical Systems 99,000.00 Building & Foundations 106,000.00 Subtotal 996,000.00 Engineering (14%) 138,000.00 Contingencies (20%) 199,000.00 Total Installed Cost $1,333, 000.00 Operation/Maintenance Cost (yearly) 155,800.00 Fuel Cost in Base Year $/million BTU 9.02 $/MWh 99.22 20018 equal to $9.02/Btu x 106. The difference between this price and the home heating oi] price previously quoted is largely the cost of small lot distribution. 3.1.1.5 Conclusions The design described above provides a highly reliable means for meeting 100 percent of the electricity needs of Kake, Alaska. It is an extension of current practice and is therefore used here as the base case. : 3.1.2 Combustion Turbine Power Generation The use of combustion turbines is, as a practical matter, a variant on the base case. During periods of replacement, smal] combustion turbines (e.g., less than 1 MW) can be substituted for diesel engines. All other equipment (e.g., structure, controls, fuel tanks, etc.) is identical for both diesel and combustion turbine power generation. The combustion turbine option was investigated on this basis. Combustion turbine technology is well developed. The cycle considered here is the simple or open cycle. In this form a combustion turbine system is smal] and light. It requires only a modest foundation and building, no cooling water, and can be run unattended. Its desirable characteristics for the Kake, Alaska setting include dependability, low Maintenance requirements, long life, and rapid start-up and loading. Open cycle was evaluated here due to the small size of the equipment. While combined cycle systems are more efficient, they are only available in much larger sizes. As a consequence, the combined cycle approach was determined to be inappropriate for Kake. Waste heat recovery for space heating was also evaluated. Problems with the current site being located 2 miles from town, and noise emissions from the electricity generating station apply equally to diesel and combustion turbine alternatives. Consequently, waste heat recovery was not considered to be a viable option. The specifications of combustion turbines presently available dictate replacing the two 500 kW diesels with two 500 kW combustion turbines and replacing the two 300 kW diesels with a single 800 kW unit. The specifications of these units are presented in Table 3-3. The combustion turbine layout is shown in Figure 3-4. Of critical importance are the heat rates: 17,000 Btu/kWh for the 500 kW units and 16,250 Btu/kWh for the 800 kW unit. These heat rates indicate a significant loss of efficiency when compared to diesel, resulting in a substantial fuel cost increase. They are high relative to most combustion turbines because of the very small size of the Machines. These heat rates would also increase dramatically under partial load conditions. Combustion turbines are highly inefficient when operated at less than 70% capacity. 20018 3-10 TABLE 3-3 COMBUSTION TURBINE GENERATOR SPECIFICATIONS Item 500 kW 800 kW Mf r/Model ONAN/560 GTD Solar Turbine/Saturn Compressor Two Stage - Radial 8 Stage - Axial Turbine Three Wheel - Axial 3 Stage - Axial Gear box Pressure Lube - Double Spur’ Press. Lube, Two Lube System Start System Fuel Type Fuel Consumption Suggested Overhaul Heat Rate Start Time Dimensions Shipping wt 20018 Reduction 16 gal., pos. disp. Press. 24V, Pneumatic (150 psig) Diesel, Fuel Oi] 460 lb/hr at 500 kW 30,000 hrs 17,000 Btu/kwW-hr 10 sec 138" x 57" x 76" 6800 Ibs 3-11 Stage, Planetary 110 gallon, gear type Air, 0.C., or Diesel Diesel, Fuel Oi] 744 1b/hr at 800 kW 30,000 hrs 16,250 Btu/kW-hr 30 sec 239" x 70" x 90" 16,010 Ibs OUTDOORS —+——— | ———-# INDOORS EXHAUST TO er ATMOSPHERE SILENCER @ FILTER MUFFLER AMBIENT AIR INTAKE [cen | s00kW COMPRESSOR COMBUSTION CHAMBER TO AIR STARTER SYSTEMS FUEL OIL STORAGE TANK HEATER COMPRESSOR AIR | RECEIVER FUEL OIL TRANSFER PUMPS A&B ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS COMBUSTION TURBINE SCHEMATIC FIGURE 3-4 | EBASCO SERVICES INCORPORATED 3-12 3.1.2.1 Cost Data Based upon the combustion turbine layout shown in Figure 3-4 and the specifications presented above, a capital cost estimate has been developed (Table 3-4). The total capital cost is approximately $1.78 million. Operating and maintenance costs for the combustion turbine are essentially the same as those associated with the diesel engine. Because the combustion turbine system is a variation on the base case, direct comparison is possible. The combustion turbines have higher capital costs and higher fuel costs, as illustrated in Table 3-5. 3.1.2.2 Conclusions Since the combustion turbine option has higher capital costs and higher fuel costs, it is less economic than the diesel option. Consequently, it is not considered for further analysis. 3.1.3. The Hydroelectric Power Option Hydroelectric power offers the second discrete alternative for Kake, Alaska. In this alternative, a free renewable resource (water) can be at least partially substituted for costly non-renewable fossil fuels. Again, the process is largely one of substituting capital investments for some operating costs. There are two basic hydroelectric alternatives available for Kake, Alaska: Cathedral Falls and Gunnuck Creek. Each alternative has its own characteristics in terms of hydrology, power potential, and cost. Since both of these projects are "run of river" they do not provide reliable power year round. It is not recommended that a large portion of any utilities' power source be this unreliable. For that reason, in no foreseeable situation would both of these projects be constructed. 3.1.3.1 Cathedral Falls The Cathedral Falls Project can provide energy to meet part of the Kake system energy requirements, thereby reducing the amount of fuel oi] presently used in electrical generation. The plant cannot provide dependable capacity to the system but is useful as a source of energy because it will operate on a run-of-river basis. As shown in Figure 3-5 there are times when flows will be lower than the minimum required for generation. Since no dependable capacity will be available from the Cathedral Falls Project, existing diesel generation capability must be maintained. The Cathedral Falls Project consists of a low, concrete gravity dam across the river, founded on rock, with an uncontrolled spillway, an intake and emergency closure gate for the power conduit, a temporary diversion structure, a power conduit approximately 470 feet long including about 360 feet placed in an excavated tunnel, and a 20018 3-13 TABLE 3-4 CAPITAL COST OF THE COMBUSTION TURBINE SYSTEM Item 2-500 kW Turbines 1-800 kW Turbine Auxiliaries and Piping Electrical Systems Building and Foundations Subtotal Engineering (9 percent) Contingencies (9 percent) Total Installed Cost Rounded Amount 20018 Cost $572,400 466,400 208,396 99,004 159,000 $1,505,000 3-14 $1,505,200 135,468 135,468 $1,776,136 $1,780,000 TABLE 3-5 COMPARISON OF DIESEL AND COMBUSTION TURBINE SYSTEMS Size Fuel Heat Rates (Btu/kWh) Building Size (ft) Total Installed Cost ($) Annual Fuel Use @ 420 kW Average Load 20018 Diesel 3 - 600 kW units Various Oils 11,000 40 x 50 x 18 1,333,000 310,700 gal 3-15 Turbine 2 - 500 units 1 - 800 unit Various Oils 500 kW - 17,000 800 kW - 16,250 40 x 50 x 18 1,780,000 550,200 gal + °o °o °o oO POWER OUTPUT (KW) DISCHARGE (CFS) nN ° °o RQ WNIT 2 ANS SSSSNELOWS PONT Ui PERCENT OF TIME 60 FLOW-DURATION AND POWER OUTPUT VS. PERCENT TIME ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS CATHEDRAL FALLS HYDROELECTRIC PROJECT ALTERNATIVE HYDRAULIC DATA FIGURE 3- EBASCO SERVICES INCORPORATED 3-16 powerhouse containing one turbine initially and space for a second unit addition. A record unit is not envisioned as being required during the planning period and has not been included in the economic analysis. Additional facilities include a switchyard, access road and transmission line. Water for power operations is diverted via the steel power conduit from the dam to the powerhouse. Due to required excavation, benching, and support, if a surface penstock were used a tunnel for the penstock would be included. The conduit bifurcates just prior to entering the powerhouse. Turbine flows discharge into the turbine pits and flow into the river. A general Project plan and approximate power conduit profile is shown in Figure 3-6. Details of project features are shown in Figure 3-7. These general project features are essentially the same as those presented in the Cathedral Falls Reconnaissance Report prepared by Harza Engineering Company (1979). Some concept modifications and refinements have been made and costs have been updated. Table 3-6 presents significant data for the project. Hydrology: A daily flow duration curve was developed for the site on Cathedral Falls Creek using 4 years of data available from the Hamilton Creek gauge. The Hamilton Creek gauge has the most extensive record in the immediate vicinity of Kake and measures a drainage basin only a few miles from the Cathedral Falls Creek drainage basin. The flows for the site were adjusted on the basis of the ratio of drainage areas between the Hamilton Creek gauge and the Project site. The flow duration curve was found to correlate very well in the lower and more significant ranges of streamflow to the curve developed and used by Harza in its 1979 report on Cathedral Falls. The flow duration curve developed is shown in Figure 3-5. Power Operation: The run-of-river mode of operation allows for generation approximately 57.5 percent of the time using the selected units. The selected units have a minimum operating level of about 45 cfs with a maximum of about 65 cfs. This corresponds to a minimum level of generation of about 280 kW. The initial unit will have a design discharge capacity of approximately 65 cfs and a maximum output of 400 kW. A power duration curve is also depicted in Figure 3-5. This curve illustrates the levels and availability of generation from the project as well as the plant's capability if a second unit were installed. Environmental Considerations: Potential impacts on anadromous fish populations will be minimal due to the selected mode of operation and the fact that the powerhouse will be located near the base of the existing Cathedral Falls. The existing falls form a natural barrier to spawning salmon, thus the impact of diverting upstream flows to the base of the falls via the powerhouse will be negligible. The natural level of streamflow in the reach of the stream containing the salmon population will not be altered by power operations. 20018 3-17 8I-€ REMOVE ROCKS AS JNDICATED TO IMPROVE SPILLWAY (FALLS) OUTLET Zz CONSTRUCTION \ DIVERSION DURING _ SPILLWAY PROTECT FACE WITH CK BOLTS AND WIRE MESH UNNEL ENTRANCE ENCLOSED IN CONCRETE ee) WS. EL. 5 PLAN 200 FEET W. EL. 126.5 STATIONS POWER CONDUIT PROFILE NOTE: DRAWING REPRODUCED FROM CATHEDRAL FALLS, PROJECT , A RECONNAISSANCE REPORT HARZA ENGINEERING COMPANY, 1979 ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS CATHEDRAL FALLS HYDROELECTRIC PROJECT ALTERNATIVE PROJECT ARRANGEMENT IGURE 3- EBASCO SERVICES INCORPORATED 6I-€ TOP OF DAM —SPILLWAY EL. 125 CREST EL. i ~e SECTION OF DAM LOOKING UPSTREAM © 20 40 FEET Stand SCALE SPILLWAY SECTION Oo 4 GFEET ut SCALE ‘STIFFENER RING €L.102 'Y STEEL AND CONTINUOUS CONCRETE ‘SUPPORT EMPORAR’ CONCRETE SUPPORT: EL. 100t TOP OF FRACTURED AND JOINTED hone Rock SOUND ROCK = STEEL > win oo COUPLINGS pr 10-0 Oc. CONCRETE PIER PENSTOCK ABOVE GROUND PENSTOCK SECTION UNLINED TUNNEL WITH PENSTOCK SECTION ° 4 S FEET ° 4 8 FEET SCALE &L. 32 ROOF WITH, PREFABRICATED POWE! HOUSE TRAVERSE SECTION ° 4 SCALE 6 FEET UNIT 2 & UNIT I (FUTURE) +5 I sot GENERATOR 1 1 00 Kw 2 NOTE: DAM, SPILLWAY AND PARTS OF POWER CONDUIT INFORMATION IS BASED ON CATHEDRAL FALLS PROJECT RECONNAISSANCE REPORT. HARZA ENGINEERING COMPANY, OCTOBER 1979 ALASKA POWER AUTHORITY POWERHOUSE PLAN a 4 FEET ‘SCALE A HYDROELECTRIC PROJECT ALTERNATIVE DAM, POWER CONDUIT AND POWERHOUSE DETAILS EBASCO SERVICES INCORPORATED TABLE 3-6 CATHEDRAL FALLS HYDRO PROJECT SIGNIFICANT DATA RESERVOIR Water Surface Elevation, ft ms1 Normal Maximum Minimum Surface Area at Normal Maximum Elevation, acres Estimated Useable Storage, acre-feet Type of Regulation HYDROLOGY Drainage Area, sq mi Avg. Annual Runoff, cfs/mi2 1/ Streamflow, cfsl/ Maximum Monthly Average Annual Minimum Monthly DAM Type Height, ft Top Elevation, ft ms] SPILLWAY Type Crest Elevation, ft ms] Width, ft Design Discharge, cfs TUNNEL Diameter, ft Length, ft PENSTOCK Type Diameter, ft Length, ft Shell Thickness, in. adjusted for drainage area. 20018 3-20 115 -110 30 None aon 504 - 125 13 Conc. 27 125 Conc. 115 710 8,600 360 Steel 470 Gravity Ogee - 188 1/ Based on data for water years 1977-1980 from Hamilton Creek gauge TABLE 3-6 (Continued) CATHEDRAL FALLS HYDRO PROJECT SIGNIFICANT DATA POWERHOUSE Number of Units 1 Turbine Type Horizontal Francis Rated Net Head, ft 84 Generator Unit Rating, kW 400 Full Load Discharge, One unit, cfs 65 Normal Tailwater Elevation, ft ms] 26 POWER AND ENERGY Installed Capacity, kW 400 Firm Capacity, kW 0 Avg. Annual Energy Generation, MWh (See Table 3-8) COSTS AND ECONOMICS Construction Cost, (1983 $) © : $7,450,000 full term BASIC ASSUMPTIONS Contingencies 20 percent of Direct Construction Cost Escalation During Construction 10 percent of Direct Construction Cost Engineering and Owner Administration 15 percent of DCC w/contingencies and escalation during construction 20018 3-21 Potential impacts during construction would consist mainly of a short term increase in suspended solids in the water due to construction activities. Careful construction techniques will be employed and construction activities will be scheduled at times most desirable for minimizing impacts. Project Costs: The cost estimate for the Project is based on the preliminary arrangement and project features shown in Figures 3-6 and 3-7 as previously presented. Quantities for some Project features were left unchanged from the 1979 Harza reconnaissance report. Quantities for other features were based on the revised arrangements. Construction cost estimates for the Project were based on Harza unit prices escalated using U.S. Bureau of Reclamation (USBR) indices, recent Alaska project cost estimates prepared by Ebasco and manufacturers information. A summary of the construction costs for the Project is shown in Table 3-7. This table reflects an estimate based on a January 1982 bid level and a construction period of approximately 1.5 years. For this final report, all costs have been updated to 1983 dollars. The total construction cost includes escalation during construction, contingencies, and engineering and owner administration. Interest during construction is not included. The factors applied to develop items other than the direct construction cost are shown in Table 3-6, as previously presented. . The additional annual operating and maintenance costs for this Project have been estimated at $64,800 per year (1983 $). Fixed operating and Maintenance costs already covered by the existing system are not included. This cost estimate includes manpower requirements for operation and maintenance assumed to be one skilled person employed half time at $26,500/year; interim replacements equal to 0.3% of the total investment cost (TIC) or $22,350/year; insurance equal to 0.1% of the TIC or $7,450/year; and a miscellaneous cost of $8,500/year. This is expected to cover all incremental O&M costs for this project, including the backup diesel unit. The interim replacement cost is included to cover relatively major items over the life of the Project such as turbine runner replacement or rewinding of generators, while miscellaneous expenses are assumed to cover the more frequent and minor parts replacement such as bearings and seals. The mode of operation for the project as proposed will be run-of-river and will operate depending on the availability of water and the system load demand. Due to periods of flow below which the unit cannot operate and lack of storage, there will be periods of no generation and therefore the project will not provide any dependable capacity. In such periods diesel units will have to be operated, with their attendant costs. During periods of adequate flows it is anticipated the Project will utilize the flow available up to the units' hydraulic capacity or will generate at a power level equal to the system load. 20018 3-22 CATHEDRAL FALLS HYDRO PROJECT DETAILED RECONNAISSANCE LEVEL COST ESTIMATE (1983 $) TABLE 3-7 Item No. Item Unit Quantity Unit Pricel/ Amount 1.0 Mobilization LS $530,000 2.0 Land & Land Rights 2.1 Reservoir AC 6.0 $1,988 11,660 2.2 Powerhouse & Comp site AC 32.0) 1,325 4,240 2.3 Water Conductor AC 1.0 URES) 1,060 2.4 Roads AC 4.0 Woe) 5,300 Subtotal 22,260 3.0 Reservoir Clearing AC - 5.0 9,540 47,700 4.0 Diversion & Care of Water LS 254,400 5.0 Dam Spillway & Intake 5.1 Rock Excavation cy 280 62.01 16,960 5.2 Common Excavation cy 280 9.01 2,120 5.3 Drilling & Grouting Foundation LF 450 46.64 21,200 5.4 Concrete, Mass GY 1,450 424.00 614,800 5.5 Concrete, Structural cy 35 848.00 29,680 5.6 Cement — CWT 5,800 18.23 106,000 5.7 Reinforcing Steel LBS 17,650 1.42 25,440 5.8 Drain Holes LF 225 69.96 15,900 5.9 Trashrack, Gate, Embedded Parts LS 517,280 5.10 Channel Excavation cy 3,000 15.48 46,440 Subtotal 1,396,020 6.0 Waterconductor 6.1 Steel Penstock LBS 52,000 aot 248,040 6.2 Rock Supports 6.2.1 Excavation CY 100 110.24 10,600 6.2.2 Concrete CY 160 848.00 135,680 6.2.3 Cement CWT 890 18.23 15,900 6.2.4 Reinforcing Steel LBS 8,100 1.42 11,660 20018 3-23 Item 7.0 8.0 9.0 20018 TABLE 3-7 (Continued) CATHEDRAL FALLS HYDRO PROJECT DETAILED RECONNAISSANCE LEVEL COST ESTIMATE Item U Clearing (100' wide) Tunnel Excavation 9' @ Concrete Tunnel Backfill Rock Bolts Steel Ribs Vacuum Relief Valve Penstock Drain Valve DAMMAAMNM WODAANPLPW Subtotal Powerhouse -1 Rock Excavation 2 Common Excavation 3 Concrete 4 Cement -5 Reinforcing Steel 6 Precast Roof Panels 7 Precast Wall Panels 8 Precast Beams 9 Clearing -10 Sewer and Water Treatment NNYNN NYY Subtotal Mechanical & Electrical Equip. 8.1 Turbine Governor 8.2 Generator 8.3 Butterfly Valve 8.4 Transformer 8.5 Misc. Elect. & Mech. Equipment 8.6 Switchgear Subtotal Roads & Bridges 3-24 nit AC CY cY CE LBS EA EA cy CY cy CWT LBS SF SF UE AC LS EA EA EA LS Mile Quantity Unit Pricel/ Amount 40 -48 40 56 01 01 80 23 42 25 -96 -10 0.3 95). 1,225 538 0 = 840 38. 19,425 4. 1 10,600 1 5,300 50 62. 15 9. 70 455. 350 18. 1,000 Ie 650 13. 2,170 16 22 143 3.0 9,540 1 182,320 1 96,460 1 16,960 0.6 530,000 3,180 659,320 32,860 89,040 10,600 5,300 1,222,180 3,180 1,060 31,906 3,180 1,060 8,480 37,100 3,180 28,620 47,700 165,360 182,320 96,460 16,960 31,800 327,540 318,000 TABLE 3-7 (Continued) CATHEDRAL FALLS HYDRO PROJECT DETAILED RECONNAISSANCE LEVEL COST ESTIMATE Item No. Item Unit Quantity Unit Price!’ Amount 10.0 Tranmission 10.1 12.5 kV-Wood Pole Single Circuit Mile 9.0 71,020 639,180 11.0 Supervisory Controls 11.1 Supervisory Controls at Diesel Powerhouse LS 74,200 74,200 Direct Construction Cost ' : 4,996,840 Engineering (19 percent) : 949,400 Contingencies (30 percent) 1,499,052 Total Construction Cost2/ 7,445,292 Rounded Amount $7,450,000 V Unit prices have been adjusted from original estimates by updating from 1982 to 1983 dollars. Cost estimates are reconnaissance level estimates, despite their apparent precision. 2/ Does not include interest during construction. 20018 3-25 Conclusions: Due to the nature of the Cathedral Falls Project and the system it is intended to supply, not all of the potential generation will be utilized within the system. Since high flow periods will occur throughout the day during peak load periods and at night during minimum load periods, it is anticipated that spill will occur at night since storage is negligible and potential generation will exceed the load. In estimating the generation that would be utilized within the system it was assumed that all energy generated at base load or less would be used. Generation between the base and peak loads was assumed to be utilized at a 50 percent rate. Because a minimum amount of daily load curve information was available, the assumption was based on an estimate. A change in the percent of peak energy utilized within the system over time is uncertain due to the lack of detailed daily load information available. Modest changes in the percent utilized would also have minimal effect on the economic analysis and would not provide a greater confidence in the values due to the hypothetical nature of the analysis. The levels of baseload energy, potential peak generation, and the estimated peak energy utilized are summarized in Table 3-8. Generation utilized within the system, thus the fuel replacement benefit for the project, versus the potential generation for the Project is also summarized in Table 3-8. Table 3-8 has been used to apportion the electricity production between hydroelectric and diesel power. This distribution is shown in Table 3-9. All diesel costs employed in the economic analysis are based upon Table 3-9. It is assumed that one replacement cycle will be required (see Section 3.1) for capital investment. All other fuels and operation and maintenance costs associated with diesel power are assumed here as well, because diesel generation would be required for about 20 percent of all electricity consumed in Kake. The above description, then, defines an alternative to the transmission line and base case (diesel power plant). It provides a significant replacement of fossil energy with renewable energy resources. As a consequence, it is evaluated in the Economic evaluation in Section 5. 3.1.3.2 Gunnuk Creek The Gunnuk Creek Project will provide energy to meet a part of the Kake system energy requirements and thereby reduce the amount of fuel oil presently used in electrical generation. The plant will not provide dependable capacity to the system but will be primarily a source of energy because it will operate on a run-of-river basis. Since no dependable capacity will be available from the Gunnuk Creek Project, existing diesel generation capability must be maintained. 20018 3-26 TABLE 3-8 CATHEDRAL FALLS HYDRO PROJECT ENERGY GENERATION AND UTILIZATION SUMMARY Total Utilized Peak Peak Energy or Fuel Baseload Baseload Generation Utilized Replacement Year (kW) 1/ Energy2/ Potential3/ @.254/ Benefit2/ (kWh) (kWh) (kWh) (kwh) 1985 122 609 ,000 1,330,000 333,000 942,000 1986 129 644,000 1,295,000 324,000 968,000 1987 136 679,000 1,260,000 315,000 - 994,000 1988 142 709,000 1,230,000 308,000 1,017,000 1989 149 744,000 * 1,195,000 299,000 1,043,000 1990 155 774,000 1,165,000 "291,000 1,065,000 1991 162 809 ,000 1,130,000 283,000 1,092,000 1992 168 839 ,000 1,100,000 275,000 1,114,000 1993 175 874,000 1,065,000 266,000 1,140,000 1994 182 909,000 1,030,000 258,000 1,167,000 1995 188 339,000 1,000,000 250,000 1,189,000 1996 195 974,000 965,000 241,000 1,215,000 1997 201 1,004,000 935,000 234,000 1,238,000 1998 208 1,039,000 900,000 225,000 1,264,000 1999 214 1,069,000 870,000 218,000 1,287,000 2000 221 1,103,000 836,000 209,000 1,312,000 2001 227 1,133,000 806,000 202,000 1,335,000 2002 233 1,163,000 776,000 194,000 1,357,000 2003 240 1,198,000 741,000 185,000 1,383,000 2004 245 1,223,000 716,000 179,000 1,402,000 2005 250 1,248,000 691,000 173,000 1,421,000 1,939,000 kWh/year - average annual energy potential V/ Minimum level of electrical demand in the system. 2/ Hydro generation at baseload or less. 3/ Generation available above the baseload level. 4/ Generation above baseload level assumed to be utilized in Kake system. Based on assumed 25 percent utilization. Values shown are 25 percent of the potential generation shown in pevious column in table. 5/ Baseload energy plus peak energy utilized. 3-27 TABLE 3-9 DISTRIBUTION OF HYDROELECTRIC AND DIESEL ELECTRIC POWER GENERATION FOR THE CATHEDRAL FALLS PROJECT* (Values in KWh) Percentage of Production Hydroelectric Diesel Supplied By Year Total Production Production Diesel 1982 1,619,600 -0- 1,619,600 100 1983 1,713,900 -0- 1,713,900 100 1984 1,808,100 -0- 1,808,130 100 1985 1,974,200 942,000 1,032,200 §2..3 1986 2,025,200 968,000 1,057,200 52.2 1987 2,076,000 994,000. - 1,082,200 52.1 1988 2,127,100 1,017,000 1,110,100 52.32 1989 2,178,100 1,043,000 1,135,100 52.1 1990 2,228,900 1,065,000 1,163,900 52.2 1991 2,290,600 1,092,000 1,198,600 52.3 1992 2,352,300 1,114,000 1,238,300 52.6 1993 2,414,000 1,140,000 1,274,000 52.8 1994 2,475,600 1,167,000 1,308,600 52.9 1995 2,537,300 1,189,000 1,348,300 53.1 1996 2,597,100 1,215,000 1,382,100 53.2 1997 2,656,900 1,238,000 1,418,900 53.4 1998 2,716,700 1,264,000 1,452,700 53.5 1999 2,776,400 1,287,000 1,489,400 53.6 2000 2,836,100 1,312,000 1,524,100 53.7 2001 2,916,800 1,335,000 1,581,800 54.2 2002 2,916,800 1,357,000 1,559,800 53.5 2003 2,916,800 1,383,000 1,533,800 52.6 2004 2,916,800 1,402,000 1,514,800 51.9 2005-2034 2,916,800 1,421,000 1,495,800 51.3 * Based on generation data in Table 3-8. 20018 3-28 The Project will utilize the existing dam and consist of a power conduit extending from the existing 36 inch diameter outlet works conduit to the powerhouse. The conduit will follow the route of a previously existing wood stave penstock and an existing 6" diameter water line to the fish hatchery. A tee will be located on the power conduit at the outlet works location to provide reservoir drawdown and sediment discharge if necessary. The powerhouse will contain two 150 KW horizontal francis turbine-generators in a standard package configuration which includes a butterfly inlet control valve. Turbine flow will discharge into the turbine discharge pits and into Gunnuk Creek. Additional facilities will include a switchyard, access road, and a transmission line. A general Project plan and approximate penstock profile is shown in Figure 3-8 and individual Project features are shown in Figure 3-9. Table 3-10 shows significant data for the Gunnuk Creek Project. Hydrology: A daily flow duration curve was developed for the site using 4 years of data available from the Hamilton Creek gauge. - Hamilton Creek is a stream located about 8 miles southeast of Cathedral Falls on Kupreanof Island. The drainage area for the existing water supply dam was determined to be 14.5 square miles. The flows for the site were adjusted on the basis of thé ratio of drainage areas between the Hamilton Creek gauge and the: Project site. The flow duration curve developed is shown in Figure 3-10. Power Operation and Energy Generation: The run-of-river mode of operation will allow for generation approximately 49 percent of the time using the selected units. The selected units have a minimum operation level of 20 cfs. This corresponds to a minimum level of generation of about 100 KW. The plant will have a capacity up to approximately 60 cfs and a maximum output of about 300 KW. The average annual energy generation potential for the Project as proposed is 933,000 KWh. A power duration curve is also depicted in Figure 3-10. In evaluating the average annual generation based on the flow duration curve, a minimum fishery release of 10 cfs was used at streamflow levels equal to or greater than 10 cfs. The fishery release was considered unusable for power generation. Water diversions at the dam for the city's water supply and hatchery purposes was assumed negligible. Environmental Considerations: The potential impact on the fishery in Gunnuk Creek would result from varying natural flows in the creek in the reach between the existing dam and the proposed powerhouse. Fishery personnel who were operators of the hatchery and longtime Kake residents felt that a flow of about 5 cfs was adequate to maintain the fishery. In evaluating the potential generation capability of the Project a flow of 10 cfs for fishery releases was assumed. Potential impacts during construction would consist mainly of a short term temporary increase in suspended solids in the water due to the construction activities. Careful construction techniques should minimize the potential impacts, with construction activities scheduled at the most desirable time of year. 20018 3-29 og-€ EXISTING ROAD TO KAKE BE EXISTING pay GUNNUK CREEK ae wo 3.0' @ POWER CONDUIT ALIGNMENT EXISTING 8" PVC PIPELINE EXISTING DAM ACCESS ROAD (APPROXIMATE ALIGNMENT) ’ sasamennaies re an eee | = Cc 1000 12-00 14+00 16100 18+00 20+00 STATIONS POWER CONDUIT PROFILE EXISTING TIMBER BUTTRESS DAM WITH COUPLINGS POWER CONDUIT TYPICAL SECTION ° 2 4 FEET | SCALE NOTE: PART OF PROJECT PLAN AND PROFILE INFORMATION IS BASED ON KAKE HATCHERY DEVELOPMENT PHASE IL REPORT. KRAMER, CHIN & MAYO, INC. APRIL 1980. ALASKA POWER AUTHORITY a GUNNUK CREEK HYDROELECTRIC PROJECT ALTERNATIVE) PROJECT ARRANGEMENT FIGURE 3-8 EBASCO SERVICES INCORPORATED Té=¢ ROOF WITH. REMOVABLE TIMBER BUTTRESS DAM CREST EL. 90# PREFABRICATED BUILDING ? foo fEosries 36 F EXISTING 30" @ OUTLET PIPE CONNECTED TO 8 @ OUTLET PIPE : PVC PIPE TO HATCHERY DAM-DOWN STREAM ELEVATION ° 20 FEET POWERHOUSE TRAVERSE SECTION o 64 3O"BUTTERFLY VALVE Wine 8: q UNIT I TIMBER BUTTRESS : (FUTURE) DAM GENERATOR 150 KW FOOT BRIDGE: il ; ORIZONTAL FRANCIS ‘URBINE ‘SPILLWAY CHUTE | GUNNUK CREEK POWERHOUSE PLAN ALASKA POWER AUTHORITY DAM- PLAN yA TYEE - KAKE INTERTIE PROJECT SCALE DETAILED FEASIBILITY ANALYSIS. 10 20 FEET GUNNUK CREEK SCALE HYDROELECTRIC PROJECT ALTERNATIVE DAM AND POWERHOUSE ARRANGEMENT FIGURE 3-6 EBASCO SERVICES INCORPORATED TABLE 3-10 GUNNUK CREEK HYDRO PROJECT SIGNIFICANT DATA RESERVOIR Normal Water Surface Elevation, ft V 84 Surface Area at Normal Maximum Elevation, ac Negligible Estimated Useable Storage, ac-ft None Type of Regulation None HYDROLOGY Drainage Area, sq mi 14.5 Avg. Annual Runoff, cfs/mi2 2/ 4.6 Streamflow, cfs 2/ Maximum Monthly 269 Average Annual 67 Minimum Monthly 7. DAM Type : Timber Buttress (Existing) Height, ft . : . 21 Top Elevation, ft V/ 90 SPILLWAY Type Broad Crested Wood Chute (Existing) Crest Elevation, ft 1/ 84.0 Width, ft 29.5 Design Discharge, cfs unknown PENSTOCK Type Steel Diameter, ft 3.0 Length, ft 1,960 Shell Thickness, in. -188 1/ Elevations based on datum in the April 1980 report on the Kake Hatchery by Kramer, Chin and Mayo. 2/ Based on data for water years 1977-1980 from Hamilton Creek gauge adjusted for drainage area. 20018 3-32 TABLE 3-10 (Continued) GUNNUK CREEK HYDRO PROJECT SIGNIFICANT DATA POWERHOUSE Number of Units Turbine Type Rated Net Head, ft Generator Unit Rating, kW Full Load Discharge, One unit, cfs Normal Tailwater Elevation, ft 1/ POWER AND ENERGY Installed Capacity, kW Firm Capacity, kW Avg. Annual Energy Generation, KWh COSTS AND ECONOMICS Construction Cost (1983 $) BASIC ASSUMPTIONS Contingencies Escalation During Construction Engineering and Owner Administration 20018 3-33 2 Horizontal Francis _ 716 150 30 am 300 0 933,000 3,550,000 20 percent of Direct Construction Cost 10 percent of Direct Construction Cost 15 percent of DCC w/contingencies and escalation during construction POWER OUTPUT OF UNIT 2 POWER OUTPUT OF UNIT POWER OUTPUT (KW) DISCHARGE (CF S) NAN NNSA NSASSI SASSER WN MSIL SALA AANA NANA MPUNTT EES NSS SAHARA SE LOWS | ARAN SSSSSSTSS ‘\ ANNAN NA BRABRSNSNSNS 0 30 4 0 0 5 PERCENT OF TIME 60 FLOW--DURATION AND POWER OUTPUT VS. PERCENT TIME ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS GUNNUK CREEK HYDROELECTRIC PROJECT ALTERNATIVE HYDRAULIC DATA FIGURE 3-10 EBASCO SERVICES INCORPORATED 3-34 Project Costs: The quantity and cost estimate for the Project is based on the preliminary arrangement and Project features as shown in Figures 3-8 and 3-9. In developing the construction cost for the project, unit prices were established based on recent Alaska project cost estimates prepared by Ebasco and equipment manufacturer information. These unit prices were then applied to quantify estimates. A summary of the construction costs for the Project is shown in Table 3-11. This summary reflects the estimated costs based on a 1982 bid level and a construction period of approximately 1.5 years. For this final report, all costs have been updated to 1983 dollars. The total construction cost includes escalation during construction, contingencies, and engineering and owner administration. Interest during construction is not included. The factors applied to develop items other than the direct construction cost are shown in Table 3-10. As previously indicated, operating and maintenance costs are identical to those estimated for Cathedral Falls. Conclusions: The mode of operation for the Gunnuk Creek Project as proposed will be run-of-river and as such will operate depending on the availability of water and the system load. Due to periods of flow below which the unit cannot operate and due to lack of storage, there will be periods of no generation and therefore the project will not provide any dependable capacity. During periods of adequate flows it is anticipated the Project will utilize the flow available up to the units' hydraulic capacity or will generate at a power level equal to the system load. Since the installed capacity of the Project approximates the estimated future base loads, at the time of installation it is anticipated that essentially all of the generation from the Project can be utilized within the system. Because the Gunnuck Creek project is designed to produce 933,000 kWh/yr, a distribution of hydroelectric power vs. diesel power has been calculated. This distribution is shown in Table 3-12. As is shown in Table 3-12, diesel generation must always supply one-half to three-fourths of the electricity required in Kake, Alaska over the life of the project. As a consequence, Gunnuck Creek is not considered as a cost-effective alternative and is not analyzed further. 3.1.4 The Wood-Fired Option Kake, Alaska is a heavily wooded region where logging currently is on-going. Further, within reasonable (barge) transportation distances are sawmills and pulp mills. As a consequence, the use of biomass fuels in this region is a reasonable option. Biomass fuels are now used for power generation in the forest products industry. Critical questions are fuel supply, system design, and cost. 20018 3-35 GUNNUK CREEK HYDRO PROJECT TABLE 3-11 DETAILED RECONNAISSANCE LEVEL COST ESTIMATE (1983 $) Quantity Unit Pricel/ Amount Item No. Item Unit 1.0 Mobilization LS 2.0 Dam, Spillway, & Intake 2.1 Intake Area Cleanup LS 2.2 Trashrack LBS 2.3 Misc. Improvements LS 3,500 4 Subtotal 3.0 Waterconductor . 3.1 Steel Penstock LBS 121,800 4 3.2 Penstock Supports 3.2.1 Rock Excavation cY 20 106. 3.2.2 Common Excavation CY 380 9 3.2.3. Fill cY 90 5 3.2.4 Concrete cY 200 848. 3.2.5 Cement CWT 1,128 18. 3.2.6 Reinforcing Steel LBS 12,000 1 3.3 Clearing & Preparation LF 1,800 42 3.4 Additional Rock Excavation CY 45 106. 3.5 Fishery Pipe Relocation LF 2,260 5 3.6 Vacuum Relief EA 2 10,600 3.7 Penstock Drain Valve LS Subtotal 4.0 Powerhouse 4.1 Area Preparation LS 4.2 Rock Excavation cY 50 62. 4.3 Common Excavation cy 30 9 4.4 Concrete cy 710 455. 4.5 Cement CWT 350 18. 4.6 Reinforcing Steel LBS 3,000 1 4.7 Precast Roof Panels SF 650 13. 4.8 Precast Wall Panels SF 2,170 16 4.9 Precast Beams LF 22 143. Subtotal 20018 3-36 -17 -77 00 -01 30 00 23 -42 -40 00 -30 01 01 80 23 -42 25 -96 10 $318,000 53,000 21,200 53,000 127,200 580,880 2,120 3,180 1,060 169,600 20,140 16,960 76,320 4,240 11,660 21,200 5,300 912,660 2,120 3,180 1,060 31,800 6,360 4,240 8,480 37,100 3,180 97,520 TABLE 3-11 (Continued) GUNNUK CREEK HYDRO PROJECT DETAILED RECONNAISSANCE LEVEL COST ESTIMATE Item No. Item Unit Quantity Unit Pricel/ Amount 5.0 Mechanical Equipment 5.1 Turbine & Governor EA 2 182,320 364,640 5.2 Generator EA 2 96,460 192,920 5.3 Butterfly Valve EA 2 16,960 33,920 5.4 Transformer 5.5 Misc. Elect. & Mech. Equipment LS . 42,400 5.6 Switchgear Subtotal : i 633,880 6.0 Access Roads & Bridges 6.1 Powerhouse Access Road Mile 0.25 530,000 132,500 6.2 Log Bridge Ls 10,600 6.3 Temporary Access Roads Mile 0.25 106,000 26,500 Subtotal 169,600 7.0 Transmission 7.1 12.5 kV Wood Pole Single Circuit Mile 0.5 71,020 36,040 8.0 Supervisory Controls 8.1 Supervisory Controls at Diesel Powerhouse Ls 74,200 Direct Construction Cost 2,369,100 Engineering (20 percent) 473,820 Contingencies (30 percent) 710,730 Total Construction Cost2/ 3,553,650 Rounded Amount $3,550,000 V Unit costs have been updated from the original estimates in 1982 dollars to 1983 dollars. Cost estimates are reconnaissance level estimates, despite their apparent precision. eh Does not include interest during construction. 20018 3-37 TABLE 3-12 DISTRIBUTION OF HYDROELECTRIC AND DIESEL ELECTRIC POWER GENERATION FOR THE GUNNUK CREEK PROJECT (Values in KWh) Percentage of Production Total Annual Hydroelectric Diesel Supplied By Year Consumptionl/ Production Diesel 1982 1,644,900 -0- 1,644,900 100 1984 1,884,100 933,000 951,100 50.4 1985 2,123,400 933,000 1,190,400 - 56.1 1990 2,434,700 933,000 1,501,700 61.7 1995 2,822,300 933,000 -1,889,300 66.9 2000 3,185,100 933,000 2,252,100 70.7 2001 3,290,400 933,000 2,357,400 71.6 2002-2034 3,290,400 933,000 2,357,400 10.6 V The capacity planning forecast was used to best illustrate the relationship of the Gunnuk Creek Project and the total capacity required. 2001B 3-38 The layout and conceptual schematic for such a plant are shown in Figures 3-11 and 3-12, respectively. The plant will consist of a fuel receiving and processing area, fuel storage and handling, and a building housing the boiler and generator with auxiliary systems. This plant will occupy an area of approximately 5 acres and should be located outside of Kake proper but within 2 miles of the city. Cogeneration (secondary use of the power plant's steam energy) or waste heat recovery for the flue gas or turbine exhaust are technically feasible with a plant of this type. However, no viable use for this energy can be identified in the Kake area. 3.1.4.1 Biomass Availability The viability of any biomass fired power plant is intimately related to the source of fuel. Important fuel characteristics include the type of material, species, moisture content, particle size, cost, and availability. The biomass fuel available to this project includes Sitka spruce and western hemlock, which are common to this region of southeastern Alaska. In order to locate fuel, sawmill and Togging operations within the general vicinity of Kake were surveyed by Ebasco. The results of the survey indicate that there are in excess of 48,860 o.p.1/ tons/year of residues available as indicated in Table 3-13. Except for the fuel from Mitkof Lumber Company, all of the residues are located off of Kupreanof Island. From Table 3-13 it can be seen that there are approximately 6,800 0.D. tons/year of residues available from the Mitkof Lumber Company located at Petersburg. However, the facility does not operate any barges and would need to rely on Alaska Lumber and Pulp (ALP) for barge transportation or would have to rent and operate the barges themselves. As can be seen from Table 3-13, the only remaining sources of fuel are from the ALP operation at Wrangell and from local logging operations in the vicinity of Kake. There are 23,400 0.0. tons/year available from ALP. Ample fuels (e.g., 15,000 0.D. ton/yr) are also available from the logging operation near Kake. As indicated by the logging contractor, this material includes slash and unmerchantable trees. Under usual circumstances large diameter trees with a significant amount of butt rot offer the most economic recovery of selected clear materials. It is assumed that this is not the case here because of the expense of removing dead material from the woods and transporting it to a sawmill. V 0.D. - Oven dry, this is a standardized measurement for the maximum amount of energy available in biomass, wherein 100% of the moisture in the fuel has been removed. 20018 3-39 CONTROL ROOM TRANSFORMER AND SWITCH | COOLING TOWER FEEDWATER TREATMENT FEED V-BELT CONVEYOR DRAG FLIGHT 7 CONVEYORS 18% RISE RETURN v-BeLT | RECLAIMER CONVEYOR | 16% SLOPE DRAG FLIGHT CONVEYOR STOKER A AUXILLARY BINS S FEED CONTROLS MULTICLONE WOOD FRAME AND SHEET Ly wera ROOF 20% PITCH DRAG FLIGHT CONVEYORS 30% RISE AUXILLARY MATERIAL PREPARATION CONTROLS TRUCK DUMP STACK AND BUILDING C GRADED AND TURBINE - GENERATOR COMPACTED DIRT FLOOR 2% ” FUEL STORAGE STRUCTURE DROP GATE DRAG FLIGHT DISTRIBUTION CONVEYOR q HOG DRAG FLIGHT CONVEYOR 10" TIMBER 1-BEAM WALLS WITH CONCRETE FOOTING Ase GaaCEL, COMPACT SOIL AND CRUSHED ROCK ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS GENERAL FACILITY LAYOUT OF WOOD FIRED POWER PLANT FIGURE 3-11 INCORPORATEN NOMENCLATURE AD ASH DUMPSTER AH AIR HEATER AP ASH PIT BC BOBCAT DC ORAG CHAIN CONVEYOR DCD DISTRIBUTION DRAG CHAIN FBC FEED BELT CONVEYOR FC FUEL CHUTE FD FORCE DRAFT FAN FDO FUEL DISTRIBUTOR OPENING FH FP FS H HR 1D FUEL HOUSE FUEL PILE FILTER SILENCER HOG HAND RAKE INDUCED DRAFT FAN IDG INTERMITTENT DUMPING GRATE IFD MC INDIVIDUAL FEEDER DRIVES MULTICLONE RBC RETURN BELT CONVEYOR RECLAIMING CONVEYOR ROTARY FEEDER ROTARY VALVE RETAINING WALL STACK SURGE BIN SCREW FEEDER SPREADER STOKER SOURCE TEST PLATFORE TRUCK DUMP TRIP GATE ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS SCHEMATIC DIAGRAM OF MATERIAL FLOWS OF THE WOOD FIRED POWER ee FIGURE 3-12 EBASCO SERVICES INCORPORATED Company Mitkof Lumber Company Alaska Lumber and Pulp Alaska Lumber and Pulp Local Logging Operations TABLE 3-13 WOOD FUEL AVAILABILITY IN THE VICINITY OF KAKE 1/ Location Petersburg Wrangell] Rowan Bay Kake Type of Fuel 53% bark 33% sawdust 14% planer shavings 100% bark logging residue (bark) unmerchant- able timber and slash Moisture Content (Green) 50% 50% 40% 40-50% Quantity Quantity Tons Actual Available (0.D.) Weight Heat Per Year Tons/Year Btu/Yr 6,800 13,600 123.4x109 23,400 46,800 424.5x109 18,5002/ 25,900 335.6x109 15,000- 21,000- 272-326.5x 18,000 36,000 109 1/ All calculations assume an average moisture content on a green basis of 50%, a weight density of 49.2 lbs/ft3 S.W.E. and 85 ft3 S.W.E./unit. 2/ An additional 25,600-29,800 0.0. tons of bark residue are currently stock- piled at the logging site in Rowan Bay. 20018 3-42 The material being considered is expected to be high in ash as well as moisture content. To be burned as fuel this material would have to be reduced in size to about one or two inches nominal dimension. This can be done in the woods or at the power plant. Size reduction in the woods is inappropriate because chip vans are unavailable to carry this material from the woods to the plant, and larger diameter material would need to be split before being fed to a mobile size reduction unit. As a result it would seem that this material would need to be hogged at the power plant. The equipment required for processing the wood at the plant would include a log unloader, a log splitter for larger material, a hog or similar size reduction unit, and all associated conveyors and drives. The unit would require between 500 and 600 horsepower. 3.1.4.2 Fuel Costs As discussed previously, fuel can be purchased and barged to Kake. The cost of doing so was evaluated during the survey, and found to be $2.54/MM Btu, not including additional barge unloading costs. There is no practical way of unloading the fuel barges at Kake short of constructing a pneumatic unloading facility, which would be very costly. Consequently, the local fuel is preferred, and purchased fuel from ALP is not considered further. As indicated earlier, fuel can be obtained locally from logging operations in the vicinity of Kake. It was indicated by one logging contractor that there is sufficient residue available to supply 15,000 to 18,000 0.0. tons/year for between 30 and 40 years. This material would cost somewhere between $32 and $42/0.D. ton of material delivered. The cost of $32 to $42/0.D. ton of material corresponds to $16 to $21/green ton at a 50% moisture content on a green basis. Chipping of timber stand conversion material on the Hoopa Indian Reservation has been calculated by Ebasco at a maximum of $21/green ton. Chipping of all material exceeded this by a factor of 1.5 on the Reservation because of the large diameter and breakage problems. The cost of timber stand improvement material on USDA land in southwestern Washington was indicated to be $11 to $13/green ton. There are cases of in-woods chipping costs in excess of $40/green ton depending on site-specific conditions. It was felt that the cost of fuel of $16 to $21/green ton at Kake was appropriate if: the cost of logging and a portion of the skidding can be attributed to the logging of merchantable timber; that double entry logging or skidding will not be used for the collection of residues but that all of the material will be brought out at the time of logging to the landing; if the log diameter is compatable with mechanized portable chipping units. Further, the cost selected was higher than the USFS estimate because a capital investment would be required by the logging contractor to purchase equipment to process chips, since no such equipment exists in the region. Thus the annual delivered cost of the fuel for the 1500 kW facility would vary from $110,500 in 1985 for 2,611 0.D. tons of fuel to $258,010 in 2005 for 6,100 0.D. tons of fuel at $2.33/MMbtu. 20018 3-43 An ultimate analysis of the material was estimated by using data available for Sitka spruce and western hemlock. The analysis calculated is 5.7% hydrogen; 51.8% carbon; 38.4% oxygen; 0.1% sulfur; 0.2% nitrogen; and 3.8% ash. The higher heating value (HHV) used is 9070 Btu/1b.1/ 3.1.4.3 Sizing of the Biomass Facilities The biomass fired electrical generation facility was sized as a result of current loads and expected load growths in the near future. It was also designed as a base load unit although it can accept load swings with an associated decrease in efficiency. As a result, a 1500 kW full condensing power plant was chosen for electricity generation in Kake. Biomass fuel requirement for this power plant was calculated from the conceptual design. The plant will require approximately 15,900 0.D. tons/year of fuel. This is sufficient fuel to operate the facility for 8300 hours/year, which is well within achievable limits demonstrated in the pulp and paper industry. 3.1.4.4 Conceptual Design Because there are ample fuel supplies available at a reasonable cost, a conceptual design has been developed for a 1500 kW wood fired system. This design includes the materials handling system, the boiler, the turbine generator, and other associated equipment (e.g., the air quality control system). Materials Handling. Procuring, preparing, and delivering fuel supplies to the power plant could be expensive. The major problem associated with material handling is processing of whole logs removed from the woods. The use of whole logs from the local logging contractors in the area involves significant problems. The most appropriate method is to transport the logs to the power plant for size reduction. This would involve a log truck unloader, a bucking station, a splitter, and a wood hog. A significant amount of conveying equipment and storage decks will be required to keep a constant feed on the hog, thus maximizing its efficiency and reducing the operating time of the wood preparation facility. Further, when the facility is operating the hog will require approximately 500 to 600 hp, assuming a uniform feed. Another 50 hp will be needed for the conveying equipment. Due to the size of the power plant and anticipated electrical demand, the log preparation operation would probably need to operate at night when electricity demand is low. 1/ This is the total heat available in a base dry pound of fuel. The heat available for steam production decreases as moisture content increases. For example, a pound of 50% MC fuel will contain only 0.5 pound of fuel, and further energy will be lost due to the evaporation of the 0.5 pound of water contained in that fuel. 20018 3-44 Power Plant Design. The system chosen for analysis here is a biomass fired, full condensing power plant with a maximum electrical generating capacity of 1500 kW. The power plant could be operated as a baseload unit near full capacity during periods of average energy demands. During hours of low energy consumption the power plant can be run at below capacity, although the steam rate of the turbine would increase significantly. The condensing steam turbine cycle was chosen due to the lack of any significant steam loads in Kake, Alaska. Although steam district heating could be employed, the cost of the distribution system as well as the increase in the steam rate of the turbine and the increased use of fuel associated with a cogeneration plant would make the approach very costly. The 1500 kW power plant requires approximately 4-to-6 acres for the boiler house, fuel storage and handling areas, and the truck dump. A general facility layout of the power plant is presented in Figure 3-11. As can be observed, the majority of the land requirements are associated with fuel storage and handling. A schematic representation of the material flows of the proposed 1500 kW power plant is presented in Figure 3-12 (these material flows are less the handling and size reduction requirements necessary to get the fuel to the fuel storage area). This flowsheet can be readily evaluated in relation to the general layout in Figure 3-11. To understand the design constraints in the material handling flowsheet it is necessary to understand the characteristics of the fuel which will be burned. All of these measures were incorporated into the design of the material handling system. o There must be sufficient fuel stored to continue operating the power plant though the winter months when possible delays in logging may occur. Thus, a large area is required for fuel storage. Oo Because of the weather in Kake a certain amount of the fuel will be stored under cover to prevent any further gain in moisture content and to allow for a certain degree of air drying. o The facility should be capable of handling chip trucks if any in-woods chipping of slash is done. At steady state maximum firing, the boiler will consume approximately 350 ft3/hour of fuel. This corresponds to 3.88 tons/hour or 7770 lbs/hr of fuel at a 50 percent moisture content on a green basis. The covered portion of the fuel house holds an eight-day continuous supply of fuel while the whole fuel house is large enough to hold a 16-day supply of fuel. Adjacent areas can also be used to store any additional quantities of fuel or logs as required. The fuel house would employ a compacted dirt floor with a 2 percent slope to facilitate runoff of water. The walls could be constructed of 4" x 10" x 10' timbers inserted in the flange of a W4-14 I-beam in a continuous concrete footing. The roof associated with the covered portion of the fuel house is wood framed with corrugated sheet metal roofing and a 20 percent pitch to facilitate water and snow runoff. The roof of the 20018 3-45 fuel house ranges in height from 15 to 25 feet above the side walls. Approximately 50 percent of the side wall area above the 10 foot retaining wall is left open to allow the unobstructed passage of wind. From the fuel house the fuel is recovered using a reclaimer. A rubber tired bulldozer is also used to keep the reclaimer conveyor covered with fuel. The fuel is then transported by a covered belt conveyor to a drag flight conveyor which distributes the fuel to the respective 10-minute surge bins of the stokers on the combustor. The fuel is fed at a rate of 20 percent above that required for combustion, the excess being returned to the fuel house. The boiler used in this design is a spreader stoker with a power-dumping grate with intermittent bottom ash discharge. The spreader stoker will use reciprocating feeders with individual feeder drives and distributor openings. The power-dumping grate spreader stoker intermittently discharges ash into the ash pit located directly under the stoker grates. Four-way hand operated pneumatic or steam powered cylinders activate the dumping mechanism. The installation as designed does not allow for sub-floor excavation and the installation of an ash hopper and automatic ash collection system. Because of the low fuel feed rate and the high cost of sub-floor excavation and foundation work, hand raking of ash was selected. The boiler to be used will produce 25,000 lbs/hr of superheated steam at 450 psig/575°F. The turbine generator employed is manufactured by the Terry Steam Turbine Company. The unit is rated at 2000 Hp or 1500 kW with a steam rate of 14.7 1bs/kWh. 3.1.4.5 Material and Energy Balance The steam cycle employs the boiler, flash tanks, deaerator, blowdown heat exchanger, turbine, and the condenser. Several assumptions were made before a heat balance was calculated. These assumptions are presented in Table 3-14. A heat balance about the boiler and the steam cycle is presented in Figure 3-13. The net enthalpy gain across the boiler will be 26.5 x 10° Btu/h. This will require approximately 35 x 10 Btu/h of fuel feed with a calculated gross boiler efficiency of 72 percent. The blowdown is 3 percent; it is flashed to steam and condensate in the flash tank. The feedwater pump is operated by a steam turbine while the condensate pump is operated by an electric motor. A blowdown heat exchanger is used to preheat the makeup water. A cooling tower is employed in conjunction with the condenser. Based upon the data presented in Table 3-14 and Figure 3-13, a heat rate of approximately 24,000 Btu/kWh can be calculated. This heat rate corresponds to a cycle efficiency of 14.2%. A typical heat rate fora large wood-fired unit would be approximately 14,000 Btu/kWh. The very small size of this unit, however, results in the severe efficiency penalty. Despite this penalty, however, wood fired units may be cost effective. At $2.33/million Btu, the cost of fuel is $.056/kWh. This compares to $0.99/kwWh for diesel assuming a heat rate of 11,000 Btu/kWh and a fuel cost of $9.02/million Btu. 20018 3-46 TABLE 3-14 OPERATING ASSUMPTIONS FOR THE HEAT BALANCE OF THE CONDENSING POWER PLANT Parameter Value BOILER CYCLE Combustion Air Temperature (to air preheater) 40°F Combustion Air Temperature (to combustor) 200°F Stack Flue Gas Temperature 280°F Fuel Moisture Content 50 percent Excess Air 40 percent Carbon Conversion 98 percent STEAM CYCLE Blowdown 3 percent Deaerator 10 psig Steam to Turbine Steam Conditions Turbine Efficiency (multistage) Condenser Pressure 22,534 Ibs/h 450 psig/575°F 62 percent 5" HgA Flash Tank Split (mass and energy balance) 25 percent steam, 75 percent condensate Feedwater Turbine Steam Usage 349 lbs/h Feedwater Turbine Efficiency 65 percent GENERATOR Generator Efficiency 96 percent Electricity Production (gross) 1500 kWh Electricity Production (net)// 1300 - 1400 kwh, 1/ Less the requirements for the log preparation equipment. 20018 3-47 MULTI- | 8.398x10%Qju/h ea ONE STACK EXHAUST 6.39 Ib/h Particulate STACK 5.00 Ib/h NO> GAS Ae 4.48 |b/h SO> A | AIR 33278 Ib/h 2.39 Ib/h CO i \ 0.416x106 Btu 25000 Ib/h__450 psig/575°F 22534 Ib/h ANY () 1286.7 Btu/b 32.168x10°Btu/n GENERATOR PREHEAT 28.995x10° Btu/h 1500 kW 349 Ib/h AIR 756 Ib/h 450 psig/575°F 1663x108 Btu/h 441.06 Btu/ib 12867 Btu/Ib 450 psa err 0.449x106 Btu/h SOLER 0.333x108 Btu/Ib 2117 Ib/h i] 349 b/h lOpsig 1049 Btu/ib 450 psig/575°F OH=26.503x10® 6 1286.7 Btu/Ib Btu/h 0.365x 10° Btu/h FEEDWATER 2.724 x108Btu/h n= 72% TURBINE FUEL 7772\b/h VENT LOSS CONDENSER 6 6 ents 35.246 x108 Btu/h 0.026 x10 Btu/h 185 Ib/h_239°F 1160.4 Btu/ib 0.215x10® Btu/h ‘ ASH 124 Ib/h 2534 Ib/h_ 101.68 Btu/Ib Oo p 0.598x108Btu/h (34°F 2.291x10° Btu/h RADIATION LOSS 571 Ib/h 199°F 1.410x 10° Btu/h 25750 Ib/h 167.8 Btu/Jb 220 Btu/Ib 57lIb/h_239°F 207.8 Btu/Ib 0.095 x |0°Btush 5.665xI0°Btu/h 0.118x 10° Btu/Ib LK 7itb/h 28 Btu/Ib 60°F 0.016 Btu/h RASEUE MATER ine) HEAT EXCHANGER FEEDWATER PUMP 6HP CONDENSATE PUMP ALASKA POWER AUTHORITY TO WASTE 571 Ib/h 68Btu/Ib 100°F 0.039xI0 Btu/h MATERIAL AND ENERGY BALANCE ABOUT WOOD FIRED POWER PLANT FIGURE 3-13 EBASCO SERVICES INCORPORATED The use of a stack gas dryer on this system would be inappropriate because of the low static gas exhaust temperature of 280°F. There would not be enough enthalpy available for any signficant moisture removal. Further, the temperature gradiant is small and boiler efficiency would suffer if the air heater were removed. 3.1.4.6 Environmental Impacts Due to the small size of the facility it is not expected that air pollution requirements will be difficult to meet, particularly when burning wood or bark fuel. Air pollution limits were taken from Title 18 Environmental Conservation; Chapter 50, Air Quality Control; Article 1, Program Standards and Limitations for Industrial and Process and Fuel Burning Equipment. The calculated uncontrolled emission rates of particulate, nitrogen dioxide, sulfur dioxide, and carbon monoxide as well as the allowed emission limits and net emissions from the boiler are presented in Table 3-15. It can be seen that all facility emissions, except those of particulate, are below the allowed emission limits. For the control of particulates a multiclone or a baghouse can be used. With these control methods net emissions of particulate will be 154 lbs/day and 8 lbs/day, respectively. Current diesel emissions at this load, postulated boiler emissions in excess of 90 percent of load, and the net change of emissions around the diesel and biomass units are presented in Table 3-16. Although particulate and sulfur dioxide emissions will increase slightly, the emissions of nitrogen dioxide and carbon monoxide will be significantly reduced as a result of the biomass unit being operated. Bottom ash from the dumping grates will amount to approximately 125 lbs/h or 1.5 tons/day. Collected flyash from the multiclone willbe 57 lbs/hr or 0.69 tons/day while collected flyash from the multiclone and baghouse, if used, will be 60 lbs/hr or 0.72 tons/day. The bottom ash will be hand raked into a dumpster while collected flyash will be screw fed to hoppers. This material can be land filled. 3.1.4.7 Cost Estimate A detailed cost estimate (bid basis) of the wood fired unit has been prepared in 1982 dollars and updated to 1983 dollars, based upon the design presented above. It assumes no unusual site or soil conditions, a system designed for 95% reliability, no auxilliary fuel, and Alaska construction conditions and practices. The capital cost estimate is $3,850,000, and is detailed in Table 3-17. It is assumed that, through the use of package equipment, the system can be engineered and built within an 18 month time frame depending upon scheduling and weather. Consequently, the unit could be operated within two years after a decision is made to proceed. 20018 3-49 OS-€ TABLE 3-15 EMISSION RATES OF AIR POLLUTANTS Net Uncontrol1ed2/ Allowed Emission Emission Emissions Pollutant Tbs7hr Tbs/day ~ ppm Limit (1bs/day) Compliance Control Ibs/day Particulatel/ 64.00 1536 -- 2806/ No Mul ticloge8/ 154 BaghouseZ: 8 Nitrogen Dioxide2/ 5.00 120 94.5 no limit Yes None 120 Sul fur Dioxide3/ 4.48 108 61.2 10122/ Yes None 108 Carbon Monoxi de4/ 3.20 77 74.0 4407/ Yes None 77 J/ Assumes 66 percent of ash and unburned carbon as bottom ash and 34 percent as flyash. 2/ Assumes a 20 percent conversion of fuel bound nitrogen to nitrogen dioxide. 3/ Assumes a 60 percent conversion of sulfur to sulfur dioxide with the excess of 40 percent being present in the bottom ash. 4/ Assumes 10 percent of unburned fly-carbon is converted to carbon monoxide and a carbon conversion efficiency of 98 percent. 5/ All values are at 11 percent C02 on an ACFM basis and 14 percent on an SDCFM basis. §/ This value was calculated for an emission limit of 0.15 grains/SDCFM, J/ This value was calculated from an emission limit of 500 ppm. 8/ Assumes a multiclone efficiency of 90 percent on a weight basis. 9/ Assumes a baghouse collection efficiency of 99 percent with a multiclone efficiency of 50 percent. A low multiclone collection efficiency was used to facilitate the proper formation of flyash on the bags which directly effects bag porosity and thus the collection efficiency. TABLE 3-16 NET EMISSIONS CHANGE Current Postulated Net Net Emission From Emission Change4/ Change4/ Dieselsl:2/ From Boiler In Emissions In Emissions Pollutant lbs/hr lbs/hr lbs/hr lbs/day Particulate 0.10 6.40 multiclone 6.3 ~ 151.2 0.30 baghouse 0.2 4.8 Nitrogen Dioxide 18.05 5.00 (11.25)5/ (270)2/ Sulfur Dioxide 3.80 4.48 160 24 Carbon Monoxide 9.30 3.20 (5.20)2/ (125)2/ I- “iy 1450 kWh or approximately 2000 BHP. In ~ Using manufacturers average recommendations. Particulate 0.024 grams/HP-HR; carbon monoxide 2.17 grams/HP-HR; and nitrogen dioxide 4.2 grams/HP-HR. 3/ sulfur dioxide estimated from AP-42 estimates. Rate is 142 x 5 percent sulfur by weight in oi] = 1bs/103 gallons. Weight percent sulfur 0.3 percent in distillate oi]. Fuel usage 90 gallons/hour. 142 x 5 percent/1,000 = 0.1425 lbs/gallon. Therefore, 0.142 x 0.3 x 90 = 3.80 Ibs/hr. > ~ From Table 3-2. 5/ values in parenthesis indicate a net decrease. 20018 3-51 TABLE 3-17 CAPITAL COST ESTIMATE FOR A 1500 KW WOOD FIRED POWER PLANT Item Costl/ (1983 $) Boiler System (includes firebox grates, steam generator and superheater, stokers and breaching) $866,020 Turbine-Generator System 304,220 Materials Handling System 170,660 Air Quality Control System 57,240 Other Mechanical Systems 361,460 Miscellaneous Mechanical and Electrical Systems (includes controls, fans and ductwork, and electrical switchgear) 513,040 Civil Engineering Systems (includes foundation, structure and site preparation) 620,100 $2,892,740 Subtotal $2,892,740 Engineering (8 percent) 231,419 Contingencies (25 percent) 723,185 Total Installed Cost $3,847,344 Rounded Amount $3,850,000 V/ - Costs have been updated from the original estimate in 1982 dollars to 1983 dollars. Costs are feasibility level estimates, despite their apparent precision. 20018 3-52 Nonfuel operating and maintenance costs are estimated at $312,700/yr. This includes two persons per shift (4-shift basis), a supervisor, and $26,500/yr for parts and general maintenance. These operating costs are significantly higher than those estimated for other systems. Wood fired units are more labor intensive because of the material handling problems. 3.1.4.8 Conclusions In conclusion, the option does exist for replacing diesel fuel with a combustible renewable resource. The trade-off is between high fuel costs and high capital and operating costs. Thus, this alternative is analyzed in the Economic Analysis in Section 5. 3.1.5 Wind Generation Option The use of windmills or wind turbines is the final electricity generation option studied as an alternative to the use of diesel power in Kake, Alaska. Again, renewable resources are substituted for fossil energy. As a consequence, this alternative is considered in detail here. Considerations involve resource availability, siting considerations, and available technologies.1/ 3.1.5.1 Resource Considerations Traditionally, the area of distribution of the wind resource has been described by isopliths of wind speed. However, in defining the wind resource for use in estimating the potential output from wind machines, a more useful measure is wind power density, or the power per unit of cross-sectional area of the wind stream. Power density (P/A) can be defined by the following equation: P/A = 1/2 pv3 where p = air density and V = velocity. This equation illustrates the important influence of wind speed. Power is a cubic function of wind speed. A doubling of wind speed increases wind power eight times. Unfortunately, there is very little specific data with which to form a conclusion on wind power at Kake. Although wind speed and direction have been recorded at Kake for some time, the information exists only in unsummarized form. In addition, the wind recording equipment at Kake, while on a 30 foot high tower, is located on the beach below 1/ This analysis is contained in: Barkshire, J. and M. Newell. 1982. Evaluation of Unconventional Energy Alternatives. Interim Report, Kake-Petersburg Transmission Line Study. Polarconsult, Anchorage, Alaska. 20018 3-53 the road, thus making the net height only 10-15 feet. It is also partially obstructed by the post office across the road. It is highly likely that this data is not representative of the entire Kake area. Compounding the problem of analyzing wind conditions at Kake is the fact that wind conditions in southeastern Alaska are extremely local. The two closest wind recording stations, at Sitka and Petersburd. are probably not representative of Kake at all, as Wise has shown. L Most of the wind power in southeast Alaska is generated by atmospheric pressure gradients with lowest pressure associated with storms in the Gulf of Alaska and relatively high pressures over the mainland. The pressure gradient winds tend to blow along the isobars - mostly from the southeast - but in areas of rough terrain the wind will blow almost directly from high to low pressure. Consequently, the winds in southeast Alaska tend to blow parallel to the axis of a channel, strait, passage, or valley. Kake's location on Keku Straight adjacent to Frederick Sound makes it a prime candidate for a fairly high wind power class rating. In lieu of accessible recorded data, we must rely on the ratings used in the above referenced work by Wise. Wind power classes throughout southeastern Alaska are shown on Table 3-18, along with estimated wind classes for Kake, Alaska. The whole of Kupreanof Island has been assigned an annual average of 5, towards the upper end of the scale. Wise further broke down the classes into seasonal wind power. In all but a few isolated cases in southeast Alaska, the highest to lowest wind power seasons are winter, autumn, spring, and summer. Seasonal power classes for the Kake area are shown in Table 3-18. It should be noted that each power class represents the range of wind power likely to be found at well exposed sites. These classes are approximations of the aerial distribution of wind power, and the demarcation between them should not be construed to represent definitive boundaries. In mountainous areas the estimates are based on the correlation between mountaintop wind speeds and free air wind speeds. Wise extrapolated upper air data to lower elevations, e.g., mountain crests, from the mean scaler wind and use of Rayleight wind speed distribution to Produce a power estimate. To account for frictional effects near the surface, this extrapolated free-air wind speed was reduced by two-thirds for power at 33 feet, and one-third for power at 164 feet. 1/ Wise, J. "Wind Energy Resource Atlas: Volume 10 - Alaska." Prepared under contract to Battelle Pacific Northwest Laboratory, December, 1980. 20018 3-54 TABLE 3-18 WIND POWER CLASSES AND THEIR RELATIONSHIP TO KAKE, ALASKA Wind Power Density Watts/ft2 Wind Power Class (at 33 ft) Wind Power Classes by Energy Density 1 1080 2 1610 3 2150 4 2690 5 3230 6 4300 7 10760 Seasonal Wind Power At Kake Season Power Class Winter 7 Autumn 5 Spring ; 4 Summer 2 20018 3-55 It should be obvious from the above that there is a need to more fully determine the wind resource at Kake. The first step would be to summarize the existing data, coupled with a more in-depth monitoring of specific sites. Due to a lack of other data, further assumptions concerning wind generator power production in this report will be based on the wind power class rating, referenced herein, of 3230 watts per square foot at a 33 foot height as an annual average. 3.1.5.2 Siting Considerations There are some problems with siting wind generators in the Kake area. The village sits upon a very narrow coastal plain at an elevation beginning around 8 feet above sea level. At the eastern side of this plain, the hillside rises rapidly to an elevation of 100 to 150 feet. The hillside then gradually rises toward the top of Kupreanof Island, with a dense spruce cover creating an almost unbroken carpet. The highest point in the vicinity is at the northern part of the island at an elevation of 2867 feet, and is a considerable distance from Kake. Because of prevailing wind directions from the sea and the dense tree cover, siting to avoid turbulence would be of extreme importance at Kake. It is likely that towers higher than those usually used would be necessary to adequately clear the trees in the vicinity of the wind generator site. The higher tower(s) would also minimize the turbulence from the hillside behind the village. It is important to recognize that a good wind site is not only one with high winds, but also steady winds. Turbulence at high speeds is hard on wind generators, producing stresses which can destroy machines which could survive much higher winds if they were steady. Turbulence also lowers wind generator output, since the machine cannot react instantly to rapid changes in wind direction. Two generalized areas at Kake where wind generators could be sited are 1) adjacent to the town, or 2) on the hilltops behind. One large advantage to the latter is that turbulence could, in theory, be minimized at higher locations. This is by no means a given, however. A study of topographic maps combined with a flight over the hillside confirmed that there is a fairly uniform slope all the way to the top. Thus, a generator would need to be sited a considerable distance from Kake, on the ridgetops, to be theoretically free from topographically influenced turbulence. Weighing the increase in transmission line costs and the difficulty of accessing such a site against the possible benefits discussed above, it was decided that a site(s) closer to town would prove to be more feasible. Taller towers and careful siting would probably alleviate any potential turbulence problems. 20018 3-56 Wind generator sites adjacent to Kake are somewhat limited by topography, tree cover, and present land use. Three candidate sites were chosen after an exhaustive walk-through of the village area and subsequent study of topographical maps. They are illustrated in Figure 3-14. Site number 1 is located on the hillside directly above the village proper, on a small knoll at 166 foot elevation. The hill does not rise to an evalation above this knoll for approximatly 1200-1400 feet north/northeast. Access to this site is not difficult, as a new road (under construction at this writing) connecting the newer housing subdivision to the school/city hall area is about 400 feet away. There is a dense cover of spruce at and all around the knoll; clearing of the immediate site area and access road would be necessary. (Although the height of trees was not measured during the site visit, height of the spruce trees appears to be in the 60-80 foot range.) Thus, tower requirements would dictate at least 100 foot heights for small machines; actual height would depend on wind generator size and the related rotor diameter Site number 2 is directly adjacent to the powerhouse, approximately 1 mile south of the village proper. It is a plateau that sits on a bluff about 50 feet above the road. The area is partially cleared and has a much less dense tree cover than site number 1. Access could most easily be accomplished by running a road directly behind the powerhouse up to the plateau. Although this second site offers advantages due to its proximity to the powerhouse and its relatively clear area, the hillside does rise quicker and more sharply beyond the plateau. Elevation is approximately 100 feet higher at a distance of 800 feet from the bluff. Although use of a taller tower would most likely alleviate any turbulence problems, this site would require monitoring by instrumentation to determine minimum tower heights prior to any capital investment for wind generator equipment. Site number 3 is located approximately 1000 feet from number 2, directly up the hillside on a knoll at 149 feet elevation. It is the highest point in a radius of 1200 feet. This site exhibits many of the same characteristics of site number 1, with slightly less dense spruce cover. It is closer to the powerhouse than site 1, and less prone to potential direct turbulence from the hillside behind than site 2. However, of the three sites examined, site number 3 would have the longest and most difficult access road. In addition, the hillside above it rises to a series of peaks, forming several narrow and shallow valleys. The extent of turbulence from this phenomena is presently unknown. 20018 3-57 SITE# | e ROAD UNDER MoNsTRUCTION. - ante q 2: \EXISTING = | ANEMOMETER Visite GUNNUK Sie LITTLE GUNNUK CREEK KEKU ROAD 1990 mee TT | = SITE#2 e POWERHOUSE TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS POSSIBLE WIND GENERATION SITES ADJACENT TO KAKE FIGURE 3-14 EBASCO SERVICES INCORPORATED 3.1.5.3 Technology Considerations There are about 50 manufacturers of wind generators in the United States today and an equal number abroad. Machines range from experimental first generation units to proven production models with several years of operating experience. Because of the wide variability in size, type, and energy output of wind generators, it is desirable to reduce these variables to a single parameter that reflects potential output capability. This parameter is defined as rotor swept area. The amount of energy intercepted by a wind turbine and converted to usable energy is primarily dependent upon this swept area; i.e., the area of the windstream that is intercepted by the wind turbine. Once the swept area is defined, potential output can be calculated by assuming an overall operating efficiency representative of today's high speed wind turbines. Thus, in equation form: P/A x A x % efficiency = Mean Power Output where, P/A is power density as described above and A is the swept area. Mean Power Output (MPO) is a measure of the average output of the turbine, it is independent of the generator size and can be used to produce an average energy output over any time period. Annual Energy Output is most often used. Wind speed and, hence, power increase with height above the ground. The above calculations are based on wind power at a 33 foot height. Most small machines will use at least 60 foot towers; at Kake the. tower height will be greater for utility intertied machines due to topography and tree cover. Therefore, it will be necessary to increase the MPO or Annual Energy Output to reflect the increased power available at greater heights. Wind power data as a function of various nominal tower heights are shown in Table 3-19. Wind Turbine Types and Sizes. Wind turbine rotors spin about either a horizontal or vertical axis. At present, vertical axis machines are not at commercial maturity. In addition, the turbines are typically mounted on very short towers, a problem at the Kake wind sites. For these reasons, our analysis will center on horizontal axis turbines. Wind generators have commonly been referred to by the size of the generator; this reflects conventional power plant design. Because wind speed varies so widely, it becomes necessary to define a wind speed at which a particular generator reaches its rated capacity. As there is no standard rated wind speed, generator size is a poor indicator of either Mean Power Output or Annual Energy Output. 20018 3-59 TABLE 3-19 WIND POWER IN WATTS PER SQUARE FOOT AS A FUNCTION OF NOMINAL TOWER HEIGHTS Power Class 33 Ft. 100 Ft. 150 Ft. 200 Ft. 1 1,080 1,740 2,070 2,340 2 1,610 2,610 3,100 3,520 3 2,150 3,470 4,140 4,680 4 2,690 4,350 5,160 5,860 5 3,230 5,210 6,200 7,020 6 4,300 7,820 9,310 10,540 7 10,760 17,370 20,680 23,400 20018 3-60 The methodology chosen for analysis uses rotor diameter to define wind generator sizes. Table 3-20 illustrates some comparisons between rotor diameter, kW capacity, and machine size. It should be noted that the large machine category reflects wind generators such as the MOD-1 at Boone, North Carolina, and the MOD-2 at Goodnoe Hill, Washington. This size of machine is not applicable at Kake, for the following reasons: 1. Capital cost is in the multi-million dollar range. 2. Stability to the grid is questionable in comparison to multiple medium sized units. 3. Flexibility to match future incremental loads as they come on line is diminished; i.e., overbuilding of capacity at an early stage. 4. Experimental nature. Small machines, operated at 30 mph wind speed, have a maximum capacity of 10-50 kW. Consequently, they would make little contribution to the supply of electricity in Kake. Further analysis, therefore, is limited to medium sized machines. No units in the medium size range have been installed in Alaska. Several units have been installed in the lower 48 and in Canada. There are only a handful of manufacturers presently building machines of this size and none are in mass production. However, a considerable number of hours have been logged on these machines and data on reliability and performance is available through the Department of Energy's MOD-OA program and tests done by WTG systems. Medium sized machines range in capacity from 200 to 500 kW of capacity, as is shown in Table 3-21. Most are in the 200-250 kW range. As a consequence a wind farm of 6-7 units would be required to meet the electricity needs of Kake, even at optimal wind speeds. 3.1.5.4 Conclusions There are uncertainties in the wind resource available at Kake, Alaska. While the location is generally favorable, data are not available to permit reliable resource estimation at this time. What data are available, however, demonstrate that the wind resource varies widely in quality throughout the year. This variation makes capital utilization difficult to plan. It carries the implication that any development would result in a system with less than the desired reliability, particularly given the lack of an intertie for electricity supply. Further, to provide the degree of reliability and utilization of the resource that is desirable, it would be necessary to add some method of energy storage. Such storage methods are currently beyond available technology and expected to be quite expensive when/if available. 20018 3-61 TABLE 3-20 NOMINAL KW CAPACITIES FOR ROTOR DIAMETERS kW Capacityl/ Rotor Diameter Smal] 0-50 0-50 feet Medium 50-1000 50-250 feet Large 1000-5000 250+ feet 1/ Rated at 30 mph. 20018 3-62 TABLE 3-21 MEDIUM SIZED WIND TURBINE CAPACITIES Manufacturer Capacityl/ Rotor Diameter (kW) (feet) WTG Systems 200 83 DAF 230 123 x 113 Alcoa 300-500 127 x 80 Westinghouse 200 127 Voland 250 93 1/ Rated at 30 mph. 20018 3-63 In addition to questions concerning the resource there are significant uncertainties concerning the viablity of sites available. There are also substantial limitations concerning the technology, which is not proven commercial technology and is not, therefore, necessarily ready for deployment in remote locations. 3.2 NONELECTRIC ALTERNATIVES Numerous non-electric alternatives have been considered for Kake. These are addressed in a report by Polarconsult as a part of the feasibility analyses. These include: Weatherization of buildings; Insulation of buildings; Passive solar space heating; Passive solar water heating; Fuel oil furances; Heat pumps, and Household wood furnaces. Many of these options are being used, at least partially, now. Others make sound economic sense, as studies have shown. 1/ The economic analyses of electricity demand in Kake, as presented in Section 2 of this report, demonstrate that heating requirements are unrelated to electricity requirements in Kake. As a consequence, the implementation of practices such as insulation and weatherization would not significantly alter the demand for electricity in Kake. Similarly, alternative means for heating households will not alter demand for electricity. It is useful to note that there is one partial exception to the total segregation of thermal and electrical systems, which is heat pump technology. Heat pumps basically transfer heat from a cooler location (outside a house) to a hotter location (inside a house). In the process the heat is intensified. Electrically powered heat pumps have been demonstrated successfully in Juneau, Alaska. Climatic similarities indicate that technical success could be achieved in Kake, as heat pumps can be effective at temperatures as low as 25°F (the mean low temperature in Kake is 36°F). Polarconsult, however, has concluded that heat pumps are not appropriate for Kake. The cost of electricity in Kake of 20-36¢/kWh 1/ This analysis is contained in: Barkshire, J. and M. Newell. 1982. Evaluation of Unconventional Energy Alternatives. Interim Report, Kake-Petersburg Transmission Line Study. Polarconsult, Anchorage, Alaska. 2001B 3-64 (compared to 3.6¢/kWh in Juneau) makes their operation prohibitively expensive. Polarconsult concludes: "It is clear that without a en in electric prices heat pumps are not viable at Kake. "1 As a consequence of this assessment heat pumps have not been included in the load forecast. Further, like the other thermal options, they are not included in the subsequent economic analysis. 3.3 CONCLUSION There are numerous alternative means for meeting the electricity requirements of Kake, Alaska. Of them, only the following three, plus the transmission line, show considerable promise and therefore are comparatively evaluated in Section 5. These include: Diesel Generation; Cathedral Falls Hydroelectric Project; and A Wood Fired Power Plant. Each option identified has distinct advantages and disadvantages in areas of capital cost, operating cost, and fuel cost. They are all subjected to present worth and benefit/cost analysis in Section 5.0. 1/ This analysis is contained in: Barkshire, J. and M. Newell. 1982. Evaluation of Unconventional Energy Alternatives. Interim Report, Kake-Petersburg Transmission Line Study. Polarconsult, Anchorage, Alaska. 20018 3-65 4.0 TYEE-KAKE TRANSMISSION LINE ALTERNATIVE The major focus of investigations in the overall analysis associated with the Tyee-Kake Project has been on the transmission line. Four reports have been prepared on distinct aspects of the transmission line. These include the Routing and Environmental Report (Nov. 1982), the Cost and Engineering Report (Nov. 1982), the Overhead/Underground Reconnaissance Report (Nov. 1983), and the Supplemental Draft Feasibility Report (Jan. 1984). The main points of those reports, as they relate to the overall assessment of the feasibility of the Tyee-Kake transmission line, are included below. 4.1 TRANSMISSION LINE OPTIONS The options available for transmission of surplus power from the Tyee Lake Project to Kake would require use of overhead, underground, or a mix of overhead and underground transmission. This section defines those options and discusses the major design criteria which characterize those options. Regardless of which option may be used, submarine cables will also be required for waterway crossings. Submarine cable characteristics are also addressed here. 4.1.1 Overhead Transmission Two overhead designs were considered. The first is a conventional three-phase overhead line and the second is insulated aerial cables. Both designs start on the same basis, that is, vertical wooden poles erected along an existing or cleared right-of-way from which conductors will be strung. The details of pole design, such as height and span, may vary slightly with loading variation from one type to the other. The details of overhead structure for the two design types are very different. Contrasting points of the two designs include cost of materials, constructability, and reliability. The cost of materials for the insulated cable is significantly higher than for the uninsulated, conventional three-phase conductors. This cost is more than offset by construction cost savings when clearing of rights-of-way through wooded areas is necessary. Under these conditions, the insulated cable design has the advantage of not needing crossarms, having much smaller right-of-way clearing requirements, and requiring less equipment for stringing. The reliability of three-phase construction is very good, as indicated by its worldwide use. The fact that insulated cable design reliability is excellent is less well known, but proven by its extensive use in New England and limited use in the Pacific Northwest and Alaska. 4-1 2015B Cost estimates show that the conventional overhead line is best where right-of-way already exists (is cleared) or where the line follows a road, thus minimizing clearing costs. The insulated cable design is most desirable on a cost basis for areas where significant clearing is required. 4.1.2 Underground Cables The possibilities for underground cable include direct burial, conduit enclosed, or bedded cable (cable buried in a trench bedded in gravel, sand or some other special medium). Preliminary review of these alternative cable installation methods indicates that only direct burial can be cost competitive with overhead construction. One of the primary advantages of underground cable is installation cost. Minimal clearing will be required in areas where a vibratory plow or direct trenching equipment can be used. The area cleared is limited to that required to pass the cable spooling equipment. Clearing is further reduced because the exact route of the cable is flexible, allowing the line to take advantage of existing clearings and avoid obstacles. On the negative side, the delivered cost of underground cable is high compared to overhead three-phase construction; its reliability with recently developed methods of construction, although expected to be high, is unproven, and repairs may be more difficult to effect. These points will be discussed further in Sections 4.6 and 4.7. A variety of direct burial underground cable alternatives were evaluated in Ebasco's Overhead/Underground Reconnaissance Report (Appendix B.2). Various sizes of cables were considered as well as different types of material within each cable. Discussion of the factors influencing the selection of the cable are described in Section 4.5.2 and in Appendix B.4. The reliability of underground cable, particularly in areas similar to Kake, Alaska, is less understood than the reliability of overhead lines or cables. Failure of the cable itself as a result of deterioration can be reduced to acceptable limits through good quality control during construction and installation. Failure due to rock punctures, dig-ins, or other environmental factors pose more of a hazard. Underground cable reliability is discussed further in Section 4.5.6. 4.1.3 Submarine Cable Either an overhead or underground Tyee-Kake transmission line would require two segments of submarine cable. A typical submarine cable cross section is shown in Figure 4-5. Each of the submarine cables is approximately 3.5 inches in diameter. At each end of both submarine cable crossings it will be necessary to install termination facilities. If an overhead line terminates into the cable, the facilities would include potheads on single poles. If the submarine cable terminates into an underground cable, the splices are housed within a small (approximately 4'x4'x4') box-like structure. 4-2 20158 Initially, a single cable is recommended due to the extremely low liklihood of cable failure. Cable failure probability does increase after six or seven years of service. At that time, the installation of a second redundant cable could be considered. The current cost estimates for both the overhead and underground transmission line options include the cost of only one submarine cable at each crossing. There area cases in which underground cables have been used in place of submarine cables, at a lower capital cost. Although this option was not included in the feasibility analysis, its potential cost savings should be evaluated during project design. 4.1.4 Mixed Overhead/Underground Transmission As pointed out in Sections 4.1.1 through 4.1.3, many alternative routes and designs could be employed on the Tyee-Kake Intertie Project. Overhead or underground alternatives along roads, across muskeg areas, or through forested areas can be developed. Overhead lines could be constructed using either standard three-phase overhead construction or an overhead cable. In the area where the Tyee-Kake line follows the same alignment as the transmission line from the Tyee Lake Project to Petersburg, it is possible to install the Tyee-Kake line on the same structures as the Tyee Lake line. Such alternatives were discussed in the Draft Feasibility Report (Ebasco 1982a), in the mixed Overhead/Underground Reconnaissance Report (Ebasco 1983b), and the Draft Feasibility Report Supplement (Ebasco 1984). Based on these investigations, an underground alternative with a short overhead segment underbuilt on the Tyee Lake line was also identified and analyzed. 4.2 GENERAL LINE ROUTING The initial activity in routing the proposed Tyee-Kake transmission line was to identify and compare two corridors with regard to their suitabilty for the proposed transmission line. The two corridors were identified based on an earlier report by Retherford (1981) and comments provided by agencies and the public. The corridors which were revised based on these comments and evaluated are shown in Figure 4-1. A more complete discussion of how these corridors were identified is provided in the Routing and Environmental Report (Appendix C.1). The comparison of the two corridors in the Routing and Environmental Report concluded that the south corridor was more desirable and better suited for routing the transmission line. A route was delineated within this corridor based on engineering and environmental considerations. The route selected for the overhead transmission line is shown in Figure 4-2. Figure 4.2 also indicates a short section of the route near Duncan Canal where the underground route varies slightly from the overhead route at a point where the overhead line skirts a muskeg area. Although a complete discussion of the considerations influencing the route's delineation is found in the Routing and Environmental Report, the major objectives in delineating the route include: 20158 r ‘A 5 , : ; : OLS) N° 3 ce ——————— RS Ke Ta€i (C SCALE IN MILES ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS TRANSMISSION LINE STUDY CORRIDORS FIGURE 4-1 EBASCO SERVICES INCORPORATED : TORS Por . \ ak « *) MES ¢ 4 us 4 mg e ia ; LUI OBOE E a) Ny \| \ \; &q - A nee ‘ a oS R BC Bk ear ARR Es SERN We ar i(G@ we Bf Poy Eres x 1 “AN j S » a = WY P S PAT oN. ce by A - re Zs i yh | : gore =) CEL, 75, [es RS os ‘+e: ry LEGEND MIXED OVERHEAD / UNDERGROUND TRANSMISSION LINE ROUTE | _ was ZT VERE } a ae is as ¥ - $ TYEE — KAKE INTERTIE Saree aS 5 Me ee al mio ar “| ‘DETAILED FEASIBILITY ANA\ YOKE OVERHEAD TRANSMISSION LINE ROUTE NOT USED BY MIXED OVE 7 UNDERGROUND LINE MN TRANSMISSION LINE ROUTE —— —- —— OVERHEAD AND MIXED OVERHEAD / UNDERGROUND At APY | | Me Va | pS MOAN FIGURE 4-2 TRANSMISSION LINE ROUTE r , ‘ aon EBASCO SERVICES INCORPORATED 1. Minimizing costs and environmental impacts by paralleling existing roads as much as possible. as For the overhead line, avoiding deep muskeg areas to reduce the costs and environmental impacts associated with constructing a line in such areas. The underground line does not require that limitation. 3. Locating the submarine cable crossings to minimize costs by avoiding wide channels and areas that are likely to be dredged while avoiding visually sensitive areas along the shoreline. 4. Avoiding steep or unstable slopes where the line would likely experience mass-wasting or related problems. Along with delineating a route to meet the general objectives listed above, sensitive areas along the route were identifed and considered in locating the transmission line route. Most notably, these include the Duncan Canal crossing and the route's crossing of the Pass between Duncan Canal and Hamilton Creek. Four alternative crossings of Duncan Canal were identified by the Forest Service and other agencies and were evaluated by study team members. The four routes considered are shown in Figure 4-3. In the evaluation of these alternatives engineering, environmental, and economic factors were considered. The results indicated that Route 2 was best overall and it became the preferred route. For this route care was taken to have the overhead line avoid muskeg areas while taking advantage of favorable channel conditions and other factors. The location of the route in this area is shown in Figure 4-4. Another sensitive area is the Pass between Duncan Canal and Hamilton Creek. This pass is the highest point on the entire route and contains some unstable slopes and rugged topography. For this reason, special care was taken in locating the route through the Pass and the route was delineated so that cliffs and other steep and unstable slopes would be avoided. Figure 4-5 shows the route through the Pass. As shown in Figure 4-2, the underground transmission line route is nearly identical to the overhead route. The two diverge at a point west of Duncan Canal. At that point, the overhead line goes around a muskeg area, while the underground line goes through it. 4.3 PRELIMINARY SCREENING FOR VOLTAGE SELECTION Selection of the appropriate transmission voltage is an important part of the optimum design of any transmission line. The voltage is usually selected to minimize line losses, environmental effects, and costs, while providing required reliable service in transmitting power from one end of the line to the other. On projects such as the Tyee-Kake transmisssion line project, the range of voltages considered is normally quite limited. This is because the optimum voltage to be selected depends on the power to be transmitted 4-6 20158 a A ERS: >] TYEE - KAKE INTERTIE PROJECT ) .. | DETAILED FEASIBILITY ANALYSIS RNATIVE DUNCAN CANAL CROSSINGS FIGURE 4-3 EBASCO SERVICES INCORPORATED MITCHELL ~ SLOUGH Need KUPREANOF \ LINDENBERG PENINSULA TRE o\, CENTERLINE PROPOSED TRANSMISSION LINE - CLEAR-CUT ADA 8 XK WN -. ROAD ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS ROOKERY ISLAND ~ ! DUNCAN _ CANAL CROSSING FIGURE 4-4 SCALE IN MILES EBASCO SERVICES INCORPORATED PROPOSED TRANSMISSION LINE & \ se HORZ.: I"=2000' VERT: 1*=200' ROUTE THROUGH PASS BETWEEN DUNCAN CANAL AND HAMILTON CREEK FIGURE 4-6 EBASCO SERVICES INCORPORATED over a certain distance; and the range of voltages is limited if the amount of power to be transmitted is quite small. In the case of the Tyee-Kake Intertie, the design power is 1600 kW which, at a power factor of 0.9, corresponds to 1800 kilovolt-ampere (kVA). These values were established based on the peak power requirements of the City of Kake in the year 2015 as described below. The line was sized to meet the complete range of loads, including the highest peak load that could occur in Kake during that planning period. The load forecast of Alaska Economics, Inc. (Appendix A.1) shows that the peak power in the year 2005 will be approximately 1157 kW (see Section 2.0). Extending this forecast to the year 2015 with an annual growth rate of 3%, and adding a margin of safety, the projected peak load for the City of Kake is approximately 1600 kW. Because the power factors of residential areas are close to unity, a typical value to use in planning electrical transmission and distribution systems in communities such as Kake ranges from 0.9 to 0.96. It is appropriate to use 0.96 if the load is composed of mainly lighting loads, ranges, toasters and some motor loads (e.g., refrigerators, mixers and other motor-driven small appliances). A lower value is more appropriate if more induction motors (e.g., small compressors, pumps, etc.) are installed. In order to accommodate such loads at Kake, it is estimated that the power factor may be as low as 0.9 and this figure was selected as a design parameter. Dividing the 1600 kW design load by the 0.9 design power factor results in the design kilovolt-ampere of 1800 kVA. These parameters served as the basis for subsequent studies. Based on the anticipated electrical needs in Kake, the following voltages were analyzed for possible use on this project: 69 kV three phase 40 kV single wire ground return (SWGR) 34.5 kV three phase 24.9 kV three phase 13.8 kV three phase eoooo$o 4.3.1 Voltages Currently Available Of these voltages, 69 kV three phase, 40 kV single phase and 24.9 kV three phase are available in the Petersburg area. The availability of these voltages in Petersburg suggests that they merit consideration on this project because the cost of voltage transformation could be reduced with their selection. 69 kV: The Tyee Lake-Petersburg transmission line, designed for 138 kV, will initially operate at 69 kV. A line built for 69 kV could be operated directly from the Tyee Lake-Petersburg transmission line until the time when the conversion to 138 kV occurs. At that time an additional transformer will have to be installed at the Petersburg substation. 24.9 kV: The existing line from Crystal Lake to Petersburg will be operated at 24.9 kV by the time the Tyee Lake-Petersburg line is completed. Selecting this voltage for the Tyee-Kake Intertie could 4-10 2015B eliminate the need for an additional transformer because 24.9 kV will be one of the standard voltages in the Petersburg system. Use of this voltage would reduce project cost. 40 kV: The voltage used to designate a three phase system is measured between line conductors. The voltage from a line conductor to ground, however, is less; namely, the voltage between line conductors has to be divided by the square root of three to obtain the line-to-ground voltage. Therefore, the line-to-ground voltage of the Tyee Lake-Petersburg transmission line is 40 kV = (69 kV/1.73). This was the reason that 40 kV was chosen for the single wire ground return system. 4.3.2 Other Voltages Considered Lines with a voltage of 13.8 kV or 34.5 kV would also be viable choices for this project because they are standard values for lines which can transmit the amount of power that the Tyee-Kake line would transmit. Consequently, these voltages were considered as well as the three available at Petersburg (69 kV , 40 kV SWGR, and 24.9 kV). 4.3.3 Selection Process In order to reduce the number of voltages under consideration, a method previously published by Ebasco (Dewberry 1982) was used. This method involves making certain assumptions and several sets of calculations. For the purpose of these voltage selection calculations, the condition was set that the voltage drop at Kake between no load and full load not exceed 10%. For each voltage level two conductor sizes were considered: 266.8 kCM and 3/0 AWG Aluminum Conductor Steel Reinforced (ACSR), except for the 13.8 kV version, where a 566.5 kCM ACSR conductor was chosen.!/ The voltage selection method employed also required that the conductor spacing of the three phase lines be specified. For this purpose conventional values were assumed: 84 inch for 69 kV, 72 inch for 34.5 kV, and 60 inch for 24.9 and 13.8 kV. Initial Screening: The result of the first step of the voltage selection calculations is the product of the load carrying capacity of the line and the distance of the transmission, commonly known as MVA-mile. To obtain the carrying capacity of the line, this number has to be divided by the line length in miles, i.e., by 54. V/ kCM stands for "thousand circular mils" and is a measure of the cross-sectional area of wire and cable. In order to convert this area into square inches, kCM is divided by 1273. AWG stands for “American Wire Gauge" and is used as a designation for wire and cable of a cross-sectional area less than 1/6 of a square inch. 4-1] 20158 In these preliminary calculations the underwater cable sections are not taken into account. This distance can be ignored during these preliminary calculations because only 1.6 miles, or less than 3%, of the total line length from Petersburg to Kake is underwater cable. However, during the line's final design, the cables are taken into account. The results of these preliminary calculations are shown on Table 4-1. From these calculations certain conclusions can be reached: le Projected loads for Kake do not justify the building of a 69 kV line because the capacity of such a line would be several times that of the load forecast for the year 2015. 2. The use of a 13.8 kV line also has to be eliminated because it does not give adequate capacity, despite the fact that it uses 566.5 kCM ACSR conductor, which is more than twice as heavy as the 266.8 kCM conductor. a. A 24.9 kV using 3/0 AWG ACSR conductor has to be ruled out also, because it can carry only 1.3 MVA to Kake, which is less than the 1.8 MVA required. 4. Using the 40 kV SWGR system is a viable alternative because its capacity is 2.6 MVA. 5. Among the 34.5 kV alternatives, the one with 266.8 kCM conductor has some merit. It could be operated at 24.9 kV for many years and the transformer could be installed at a later time, should the Kake load increase beyond what is projected for the year 2015. Another version, using 3/0 AWG conductor, would require additional clearing, more insulation, and the $150,000 transformer would have to be installed at Petersburg within a few years. 6. The 24.9 kV transmission voltage using 266.8 kCM ACSR conductors is well suited for the project, because its estimated capacity is 1.9 MVA, which is very close to, yet in excess of, the projected load for Kake of 1.8 MVA. Furthermore, should Kake Cold Storage be connected to the system, the line will be capable of carrying the load for many years to come; only near the end of the thirty years will corrective measures have to be initiated (e.g., installing capacitors). The line is, therefore, capable of handling the full range of loads forecast for Kake, both with and without the addition of Kake Cold Storage, for almost the entire project life. Detailed Comparison: Based on the conclusions described in the preceding paragraph, only three voltage levels were investigated in detail: Oo 24.9 kV o 34.5 kV o 40 kV SWGR 4-12 20158 TABLE 4-1 CAPACITY OF THE TYEE-KAKE INTERTIE 1.8 MVA 0.9 P.F. Load and 10% Voltage Drop Equivalent Voltage ACSR Delta Capacity kV Conductor Spacing MVA-Miles MVA 69 3/0 AWG 84" 521 9.6 4o swer -/ 3/0 ANG N/A 141 2.6 2/ 34.5 3/0 AWG 72" 131 2.4 2/ 34.5 266.8 kCM 12" 195 3.6 3/ 24.9 3/0 AWG 60" 69 1.3 24.9 266.8 kCM 60" 103 1.9 2/ 13.8 566.5 kCM 60" 52 1.0 Note: Projected load of Kake for the year 2015 is 1.8 MVA. V/ Single wire ground return. 2/ Viable alternatives. 3/ Can be put into service initially at 24.9 kV. 4-13 2015B Comparison of these voltages requires that several line designs and clearing requirements be examined. Because the intial feasibility analysis, as described in the Draft Feasibility Report, concentrated on an overhead transmission line option, the final recommendation on line voltage reflects some considerations unique to an overhead line. For that reason, the discussion of final voltage selection follows in Section 4.4, Overhead Transmission Line Option. 4.4 OVERHEAD TRANSMISSION LINE OPTION 4.4.1 Line Routing The overhead transmission line route, shown earlier in Figure 4-2, is displayed with further detail in Figures 4-6A through 4.60. The route includes long segments of unroaded forest area, where clearing costs affect the optimal transmission line design. 4.4.2 Detailed Line Design 4.4.2.1 Alternate Line Designs and Clearing Considerations Clearing requirements and costs influenced the selection of the recommended voltage and design. Because clearing costs represent an important component of the overall project cost, and because the cost of clearing may influence the feasibility of the line itself, it is analyzed in more detail in this section and in Appendix B.5. It was recognized during the early stages of the design process that the clearing costs would form a significant portion of the total cost of an overhead transmission line. Therefore, avenues were explored to minimize the clearing costs. For this reason Ebasco decided to look into an alternative which conventionally has not been used to build long distance transmission lines, namely, use of insulated cables. Cables may be economical for lines with voltages of 24.9 kV or less, while 34.5 kV lines and higher are generally too costly to install a cable. Both underground and aerial 24.9 cables were considered in addition to conventional three-phase construction. A typical overhead three-phase structure is shown in Figure 4-7. Figure 4-8 shows a typical overhead cable structure. Overhead aerial cables showed promising possibilities. Inquiries made with companies that manufacture and install aerial cables revealed that 24.9 kV aerial cables are manufactured with full insulation and are relatively inexpensive. This alternative looked very attractive, and therefore was investigated in detail. Based on information gathered and the fact that three voltages had been identified as viable, four alternative designs were compared. They included: (A) A 24.9 kV insulated aerial cable line, using 266.8 kCM aluminum conductor, bundled with 11.5 inch spacing; 4-14 ~ 2015B SL. TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS OVERHEAD TRANSMISSION LINE ROUTE , FIGURE -4-6A EBASCO SERVICES INCORPORATED 4-15 / © ne gs ro SX “a 58 > OZ $ az a ACS) 5 fa = wi) Hs Fs n /< KT w = Nad eae On) DEA 20 I~ a), 4 J ha < = ; jlu<c , q H a is ! Ir hs LI =NA ff —- an Ss } TOT SOR NNN ie ‘ i #/(( O ~ FIGURE 4-6C OVERHEAD TRANSMISSION LINE ROUTE EBASCO SERVICES INCORPORATED ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS wo Ww 2 = z 3 <J IGURE 4-6D EBASCO SERVICES INCORPORATED ALASKA POWER AUTHORITY _ OVERHEAD TRANSMISSION LINE ROUTE TYEE - KAKE INTERTIE PROJECT | DETAILED FEASIBILITY ANALYSIS | ” w 2 2 z w 2 9 a POSITION OF GUY WHEN REQ POLE TO BE GAINED ON BOTH IDES TO PROVIDE FLAT SURFACES BRACKET FOR BRACKETS. ‘POLE TOP PIN ASSEMBLY MATERIAL LIST ITEM [No] INSULATOR, PIN TYPE Bt, EHIME, SR" X REQUIRED LENGTH [Be em , HER, RD. 1 3/8” DIAMETER WN, CROSSARM, STFEL, CLAMP TYPE OSSAR, 3 174" x 43/4" XR’ ve BURLE ARMING, SAR* Xx REQUIRED LEMTH @ oe oD sme ALASKA POWER AUTHORITY SI . Teh ° Eee Ya neren x1 172 TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS 24.9 kV 3 PHASE OVERHEAD LINE STRUCTURE DETAIL Oo A 8 Cc D p 6 " Ss u tA = FIGURE 4-7 EBASCO SERVICES INCORPORATED 4-19 sy + TANGENTS AS DEFINED FOR AERIAL CABLE CONSTRICTION INCLUDES “MIGLES TO 6° MAXIMUM. . AMY HORIZONTAL LOAD CREATED BY A MINOR AMGLE SHOULD BE GIYED MATERIAL LIST FOR PROPER CONSTRUCT 10K. TS-1 STIRRUP MUST BE BOLTED THROUGH THE HOLE CLOSEST TO THE EMD OF THE BRACKET MEAR THE MESSENGER CLAMP. WHENEVER VERTICAL LOADS ARE EXPECTED TO EXCEEN A MAXIMUM OF 1,000# THE USE OF 3° SQUARE CURVED WASHERS ARE RECOMMENDED. LOCKING WUT OD MOT INSTALL: STIRRIIP OR GROUND UNTIL CONDUCTORS ARE HEMOR [-CLAMP WITH TIES, (TYPE AS REQUIRED) INSTALLED. ALASKA POWER AUTHORITY IME BOLT, 5/8" X REQUIRED LENGTH TYEE - KAKE INTERTIE PROJECT SQUARE WASHER, 21/4" X 2 1/4" X 38" (HINIALD DETAILED FEASIBILITY ANALYSIS COWMELTOR, (SIZE AWD KIND AS REQUIRED) GROUND WIRE, S-D- COPPER, SOLID, #6 MINH : 24.9 kV OVERHEAD CABLE GROUND WIRE STAPLE, COPPER CLAD OR GALVAWIZED TRANSMISSION LINE sles tye GROUNDING ASSEMBLY, (TYPE AS REMUIRED, MOT SHOWN) -8 POLE, (LENGTH AWN CLASS AS REQUIRED) } EBASCO SERVICES INCORPORATED 4-20 (B) A 24.9 kV, conventional bare conductor REA overhead transmission line using 266.8 kCM ACSR conductors with 60" equivalent delta spacing; (C) A 34.5 kV bare conductor conventional REA overhead line with 266.8 kCM conductor using 72" equivalent delta spacing; and (D) A 40 kV single wire ground return (SWGR) transmission line using 3/0 AWG ACSR conductors. The four alternatives identified above involve different types of structures and clearing requirements. These factors were considered in developing the recommended project plan. The alternatives are described below in decreasing order according to voltage. 40 kV Single Wire Ground Return (SWGR): This alternative has been identified by Retherford in a report entitled, "Single Wire Power in Alaska" as being economically attractive for lines in remote areas of Alaska. Therefore, it would appear that this type of line would be appropriate at Kake. Upon closer examination, however, such a system would not be well-suited for the Tyee-Kake project for three important reasons. First, a single wire ground return system would not substantially reduce clearing requirements as compared to a conventional system. For a 40 kV SWGR line using uninsulated conductors clearing requirements would be 50 feet, or wider, essentially the same width as needed for more conventional lines. Second, the A-frame design proposed by Retherford is most economical for lines where long spans are possible. For the Tyee-Kake line, long spans would reduce the line's reliability and would require greater amounts of clearing. Further, the basic concept of the A-frame design is to have the conductor provide the longitudinal support for the structures. This concept, although perhaps well suited to open, treeless landscapes further north, is not appropriate for the line between Kake and Petersburg. Third, because the Tyee-Kake line would be single phase, it would load only one phase of the Tyee Lake-Wrangell-Petersburg system in amounts that could cause permanent damage to the generators at Crystal Lake and Tyee Lake. 34.5 kV System: A 34.5 kV transmission line would have greater capacity than a 24.9 kV line and could possibly serve loads in Kake further into the future. Such a line would, however, be more expensive and would require additional clearing. On the average, using the 34.5 kV voltage would increase costs over a 24.9 system by $10,000-20,000/mile, or total project costs by $500,000 to $1,000,000. These cost considerations, together with the load forecast for Kake, do not justify the 34.5 kV option. 24.9 kV System: A 24.9 system could employ a conventional 3-phase overhead design or an overhead cable design. The relative merits of each depend on local clearing requirements and the relative cost of the conductors and supporting structures. The relative cost of each of the 24.9 kV alternatives is influenced by the width of right-of-way required. The width of the right-of-way of a 4-21 20158 transmission line is established to assure that trees will not fall on the conductors. For this reason, a conventional 24.9 3-phase overhead transmission line requires a 55 foot wide right-of-way as shown in Figure 4-9. A detail of the structure is also included in Figure 4-9. In addition, tall trees which might fall and damage the transmission line have to be cut: these trees are called "danger trees." This type of line is a standard Rural Electrification Administration (REA) type line. Figure 4-10 indicates the problems involved with the right-of-way for a conventional transmission line. Trees that intrude into the area defined by the 45° line must be cut. Utility experience indicates that most faults of transmission lines are caused by branches of trees touching the transmission lines or falling on them. This is the reason trees are cleared within the 55 foot-wide strip and why the danger trees are cut. In contrast to the conventional 3-phase overhead line, an insulated aerial cable line requires much less cleared right-of-way. On aerial cable lines, the conductors are closer together and insulated as shown in Figure 4-8. In this case the clearing on the right-of-way need only be wide enough to accommodate vehicles during construction and maintenance and to prevent physical damage to the line by falling trees; the problems associated with vegetation touching the line and causing faulting is not as great a concern with the overhead cable as compared to conventional 3-phase lines. Ten feet on each side of the poles is generally considered adequate for this purpose, which results in a 20 foot wide right-of-way. Occasionally, larger areas will need to be cleared to enable construction equipment to operate. Figure 4-11 shows clearing requirements for the insulated aerial cable design. Because such a line can operate even if the branches touch the insulated conductors or if the line falls onto the ground, fewer danger trees have to be cut. Comparing Figure 4-10 with Figure 4-11 reveals that much less clearing is required for the insulated aerial cable compared to the standard 3-phase line. The amount of clearing is further complicated by the fact that the proposed transmission line parallels the road in some areas and not in others. Where the line goes through unroaded areas, the low clearing costs are advantageous enough to favor the overhead cable over the standard 3-phase design. Where the line parallels the road, however, one side of the transmission line right-of-way has already been cleared. This reduces the transmission line's overall costs; it also tends to favor the conventional 3-phase design over the overhead cable design. The 3-phase design tends to be favored along roadsides because the clearing costs of the standard 3-phase design, as compared to the overhead cable design, are not significant enough to warrant use of an overhead cable (which has higher costs per foot). The analysis presented above describes the relative merits of the various line voltages. Based on this analysis, the recommended alternative was identified as a 24.9 kV system. The recommended system 4-22 2015B DED ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS 24.9 kV 3 PHASE OVERHEAD LINE 3-PHASE CROSSARM —-WAY RING DOUBLE PRIMARY SUPPORT en ee wna 4-9 EBASCO SERVICES INCORPORATED DANGER yf TREE NOTE: ENGINEER WILL DESIGNATE ALL DANGER TREES WHICH ARE TO BE REMOVED OR TOPPED DANGER WaRee is i LORS. R.O.W. WIDTH = 55.0' ELEVATION PLAN VIEW ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS 24.9 kV 3-PHASE OVERHEAD LINE DANGER TREE CLEARING FIGURE 4-10 EBASCO SERVICES INCORPORATED 4-24 NOTE: ENGINEER WILL DESIGNATE ALL DANGER TREES WHICH ARE TO BE REMOVED OR TOPPED DANGER TREES —- yest £ “ase N N Y LENG ae VON oN ao iia | | R.0.W. WIDTH 20.0 ELEVATION ROW LINE“ o— ~ CO BRUSH co Es OO TO Et Os tO PLAN VIEW ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS 24.9 kV OVERHEAD CABLE TRANSMISSION LINE RIGHT-OF-WAY AND DANGER TREE CLEARING REQUIREMENTS - igure 4-11 EBASCO SERVICES INCORPORATED 4-25 is well suited to provide the electricity needs of Kake under the most likely load forecast, and can also handle the full range of forecast Kake loads, both with and without the addition of Kake Cold Storage, for almost the entire life of the project. 4.4.2.2 Foundations With the exception of those areas having extensive (and deep) muskeg deposits, pole embedment depths into competent soils can be taken as ten percent of the length plus two feet. For a typical pole length of 55 feet this results in 7.5 feet of embedment. For poles set exclusively in rock, pole embedment will typically be 10 percent of the pole length (i.e., 5.5 feet for a 55 foot pole). Where inorganic soils overlay rock, poles will be set to the same depth as for soil (ten percent plus two feet). Essentially, the above embedment criteria applies to that length of line extending from Petersburg to the Duncan Canal crossing (i.e., mile 0 to mile 15.7). As can be seen from the soil map (Figure 4-12) ,1/ the alignment is primarily confined to glacial and marine deposits and bedrock. However, occasional shallow (i.e., less than 5 or 6 feet) muskeg deposits may be encountered. In these instances the muskeg depth is to be ignored and the pole will be governed by the criteria for competent soil (or rock, where applicable). Embedment criteria for soil screw anchors and rock anchors for guyed structures are shown in Figures 4-13 and 4-14. The segment of transmission line from Duncan Canal (mile 15.7) to the Pass (mile 30) traverses large areas of deep peat, (i.e., greater than 5 or 6 feet in depth). Wood raft foundations in conjunction with guying will be required, as shown in Figures 4-15 and 4-16. The wooden raft is placed directly on the muskeg, thus utilizing the top vegetative layer. The wooden raft is approximately 15-feet by 6-feet in plan, and the transmission line pole extends approximately six feet below the raft to help stabilize the pole. A raft foundation is useless unless guy wires and anchors firmly embedded into competent soil (or rock) are utilized. Soil screw anchors entirely within muskeg cannot maintain a tension load without pulling out. Thus, if competent soil or rock is excessively deep (i.e., greater than eight to ten feet), a log anchor may be required, as seen in Figure 4-16. If suitable soil is not excessively deep, a screw anchor firmly twisted into inorganic soil is adequate. From the Pass (mile 30) to Kake (mile 53.9) peat averages from 0 to 5 feet thick, and glacial and colluvial soils predominate. Thus, the majority of the foundations will be conventional. However, between the Pass and westward to the terminus of the logging road, thicker peat deposits may be unavoidable, requiring raft foundations and perhaps log anchors. V/ this map is one of four soil maps covering the entire route. This Map, as well as the other three, are included in the Cost and Engineering Report (Appendix B.1). 4-26 2015B LANDFORM CLASSIFICATION ALASKA POWER AUTHORITY MANMADE DEPOSITS ORGANIC DEPOSITS wepROCK HE ~ FILL AND EMBANKMENTS © - ORGANIC DEPOSITS Bx - UNDIFFERENTIATED SEDIMENTARY, METAMORPHIC AND IGNEOUS BLOROCK FLUVIAL DEPOSITS MARINE AND MARGINAL HARINC DEPOSITS SURFACE PHASES TYEE — KAKE INTERTIE PROJECT F- FLA, wend FCRENT ATED MH ~ BEACH AND SHALLOW ne DEr0sits (Mt) - MARINE TERRACE. FORMER MARINE TERRACE . DETAILED FEASIBILITY ANALYSIS Fp - FLOOD PLAIN Mt - MARINE TIDAL FLATS Fpm - MEANDER FLOOD PLAIN Mte - EMERGED MARINE TIDAL FLATS FE = ALLUVIAL FAM Md - DELIA fo > or MAP OF SOILS BETWEEN WRANGELL COLLUVIAL DEPOSITS GLACIO-MARINE DEPOSITS © - PRESENCE OF “G" LANMFORN WITHIN 20°) OF SURFACE IN QUESTION NARROWS AND DUNCAN CANAL @ ~ coLLuviUM Gm - UNDIFFERENTIATED GLACIAL AND MARINE DCPOSITS GLACIAL DCPOSITS Ca - AVALANCHE DEPOSITS aan = FIGURE 4-12 oo ee EBASCO SERVICES INCORPORATED USAGE OF QUESTION HARKS IN TERRAIN UNITS APPROX. 40° (ALL ANCHORS) PROJECTION ADE CLAY, SILTY CLAY OR CLAYEY SILT PEAT DEPTH SAND (UNFROZEN) SILTY SAND OR SANDY SILT 2nd ANCHOR g 1st. ANCHOR INSTALLED INSTALLED SCREW ANCHOR SCREW ANCHORS FOR GUYED TOWERS ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS SCREW ANCHORS FOR GUYED POLES FIGURE 4-13 EBASCO SERVICES INCORPORATED 6" TO 12" PROJECTION INORGANIC SOIL RODS 10' OR 20' LONG AS REQ'D GROUTED AT LEAST TO ROCK SURFACE APPROX. 2 — DIA. HOLE ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS GROUTED GUY ANCHOR IN ROCK FIGURE 4-14 EBASCO SERVICES INCORPORATED 4-29 WOOD PLANKING WOOD PLANK STABLIZER FIGURE 4-15 EBASCO SERVICES INCORPORATED 4-30 INORGANIC SOIL SCREW ANCHOR WOODEN STAKES LOG ANCHOR SCREW ANCHOR AND LOG ANCHOR FIGURE 4-16 EBASCO SERVICES INCORPORATED 4-31 4.4.3 Interconnection at Petersburg and Kake The proposed Tyee-Kake transmission line would interconnect with the Tyee Lake-Wrangell-Petersburg transmission system in Petersburg so that power produced by the Tyee Lake project could be transmitted to Kake. The point at which the line to Kake begins is limited because the transmission line from Tyee Lake to Petersburg, designed for 138 kV, will be initially operating at 69 kV. Therefore, it will not be possible to connect the Kake line directly into the Tyee Lake line without installing a costly transformer to change the voltage from 69 kV to 24.9 kV. Because such a transformer will be installed at the proposed Petersburg Substation at Scow Bay anyway, it is not considered economically or environmentally prudent to propose the installation of an additional transformer solely for the use of the Tyee-Kake line. Therefore, it must be assumed that the line will begin where 24.9 kV voltage is available (i.e., after the transformation has been made at the proposed Petersburg Substation at Scow Bay). There are two possible ways to interconnect with the 24.9 kV system in Petersburg. The first would be for the Tyee-Kake line to originate at the proposed Petersburg Substation at Scow Bay. Under this scenario, a 24.9 kV line would be underbuilt on the Tyee Lake line (i.e., the first few miles of the Tyee-Kake line would be built on the same poles as the Tyee Lake line, but in a position well underneath the 69 kV conductors). The exact position that the Tyee-Kake line would have on the Tyee transmission line poles is not yet determined, because the line between Crystal Lake and Petersburg may be underbuilt on the Tyee Lake line as well. Regardless of whether the Crystal Lake-Petersburg line would be relocated onto the Tyee Lake line's poles, it would be possible to underbuild the Tyee-Kake line on the Tyee Lake line. The cost estimate developed on this option is based on the costs which would be required to underbuild the Tyee-Kake line on the Tyee Lake line, assuming the Crystal Lake line is also underbuilt on that line. A second, less costly option, would be for the Tyee-Kake line to connect (using engineering terminology, to tap) the Crystal Lake-Petersburg line. Such a tap would include remotely controlled switches to prevent problems on the Tyee-Kake line causing disruption in electrical service to customers in Petersburg. Metering to measure the power sent to Kake would also be required at this location. Tapping the Crystal Lake-Petersburg line would eliminate the need to build five miles of line between the proposed Petersburg substation and the Alaska Experimental Fur Farm. This would reduce project costs by approximately $170,000. This alternative would have the additional advantage of reducing line losses on the Crystal Lake-Petersburg line when the Crystal Lake Project is producing energy. In order for a tap of the Crystal Lake-Petersburg line to be seriously considered, an agreement with the City of Petersburg regarding use of the Crystal Lake-Petersburg line to serve Kake would be required. Agreements of this sort are commonplace and typically involve payments to the utility that owns the line (in this situation the City of Petersburg) for use of their line. In the case of the Tyee-Kake project, it appears that 4-32 2015B reaching such an agreement is unlikely. In the absence of such an agreement, the project cost estimate includes constructing a new circuit, not interconnected with the Crystal Lake-Petersburg line from the proposed Petersburg Substation at Scow Bay south to the Alaska Experimental Fur Farm. 4.4.4 Submarine Cable Facilities Two sections of underwater cable are required for the proposed transmission line. A typical submarine cable cross section is shown in Figure 4-17. One section crosses Wrangell Narrows from a point near the Alaska Experimental Fur Farm to a point near the Tonka Log Transfer Facility. The second segment crosses Duncan Canal several miles south of Indian Point. These crossings are shown in Figure 4-2. Each crossing contains one cable. Cable sections are set in place by a cable laying barge. The cable is placed beneath the subsurface for its entire length. A plan view and typical terminal structure are shown in Figure 4-18. Figure 4-18 also shows a second, optional, cable that could be added at a later time. The project cost estimate includes only one cable. The entire process of installing the cable can be accomplished in a few days at each crossing. Submarine cable is actually used for a distance of approximately 75 feet inland from each shoreline. This will establish a vegetative screen along the shorelines of Duncan Canal and Wrangell Narrows. Special structures are needed at the termination points of the submarine cable sections, which resemble the poles used along the majority of the route. Switches may be required at the eastern terminus of the Wrangell Narrows crossing. This terminal structure, however, is well inland, near the point where the route crosses the Mitkof Highway. Initially, a single cable is recommended due to the extremely low likelihood of cable failure. Cable failure probability does increase after six or seven years of service. At that time, the installation of a second redundant cable could be considered The original analysis presented in the Draft Feasibility Report assumed redundant cables would be installed at the beginning of the project. The new cost estimate includes only one cable instead of two. There are cases in which underground cables have been used in place of submarine cables, at a lower capital cost. A cross section of the type of underground cable that could be used is shown in Figure 4-17. Although this option was not included in the feasibility analysis, its potential should be evaluated during project design. 4.4.5 Access Good access to the transmission line is important during line construction and to future operation and maintenance. In general, it is best if the line is built adjacent to an existing road because materials and workers can be easily transported to the construction 4-33 2015B 2/0 AWG (19X) PLAIN COPPER EXTRUDED STRAND SCREEN | EXTENDED INSULATION EXTRUDED | SEMICONDUCTOR COLORED MYLAR STRIPS | PLAIN COPPER TAPE PLAIN COPPER | GROUND NEUTRAL FILLERS JACKET | TREATED JUTE BEDDING GALVANIZED STEEL WIRES, | BACKED WITH COVERING NYLON SERVING SLUSHED WITH TAR 3/0 AWG (19X) PLAIN COPPER SOLID PLAIN COPPER NEUTRAL EXTENDED SOLID JACKET TYPICAL 25kV CABLES: ALASKA POWER AUTHORITY TYEE -— KAKE INTERTIE PROJECT (a) Underwater DETAILED FEASIBILITY ANALYSIS. | (b) Underground TYPICAL 25kV CABLE CROSS SECTION | EBASCO SERVICES INCORPORATED 4-34 Figure 4-17 SHORE aie 3 TERMINAL STRUCTURE ( SUBMARINE CABLES TERMINAL | SECOND CABLE OPTIONAL } STRUCTURE PLAN VEIW ae WATER LINE UNDERGROUND CABLE CROSS SECTION TYPICAL TERMINAL STRUCTURE 4-35 Figure 4-18 site. Access is considered poor if there are no roads present, because helicopters or other special equipment will have to be used to construct the line. Good access during the line's operation is a function of the roads which are maintained for year round use. Essentially, the portion of the line parallel to the Mitkof Highway is the only part where operation and maintenance access can be considered good for the entire year. A more specific appraisal of local access conditions is provided below and in the Route Description sheets in Appendix C.2. The summaries below apply to the portions of the route on land. Access to the submarine portions of the route do not pose any unique problems. A More complete discussion of these crossings is found in the discussions of the bathymetric studies in the Cost and Engineering Report (Appendix B.1). Access to the overland segments can be categorized as follows: (1) Scow Bay to Wrangell Narrows: From Scow Bay five miles south to the submarine cable crossing in the vicinity of the Alaska Experimental Fur Station the transmission line is easily accessible from the Mitkof Highway. This section of the line would likely be built under the 69/138 kV Tyee Lake-Petersburg Transmission Line, which will run within a few hundred feet of the highway. (2) Wrangell Narrows - Duncan Canal: This section is the segment which runs on the Lindenberg Peninsula from the vicinity of the Tonka Log Transfer Facility to the cable crossing at Duncan Canal, south of Mitchell Slough. For some eight and one half miles this transmission line runs parallel to existing logging roads and, therefore, is easily accessible. The road ends on the west side of Lindenberg Peninsula, one and a half miles short of the cable crossing. The line is routed through about one-half mile of muskeg. The section between the road end and Duncan Canal could be built either as a continuation of the segment discussed earlier (building it out from Tonka) or building the line eastward from Duncan Canal. (3) ODuncan Canal - Pass: The next section begins at the west side of Duncan Canal at the cable termination and runs for thirteen and one half miles to the summit of the pass at an elevation of approximately 700 feet, of which about one mile will traverse muskeg in the vicinity of Duncan Canal. This section will require a floating construction camp unit to be moored along the west bank of Duncan Canal. There are no roads in this area and all material would have to be hauled in along the cleared right-of-way. (4) Pass to end of logging road near Hamilton Creek: The next segment is a seven mile long segment between the summit of the pass and the end of the logging road at the Hamilton Creek area. There are no roads in this area and, therefore, all 4-36 2015B material has to be hauled in via the cleared right-of-way. However, this section is more easily accessible than section (3) because this segment is accessible from Kake overland. (5) End of logging road near Hamilton Creek - Kake: The western portion of the transmission line would be built out of Kake. In this segment the intertie would be built along the logging roads and is easily accessible. This line segment is almost nineteen miles long. 4.4.6 Construction Constructing a 24.9 kV wood pole line such as the Tyee-Kake line involves three major steps: 1. clearing the right-of-way 2. setting the poles 3. stringing the conductor Clearing requirements are described in more detail in Appendix B.5. Basically, however, clearing along roads would resemble logging activities typical in the area. Several crews of three or more individuals would fall, buck, yard, and load merchantable timber onto logging trucks so that logs could be transported to a point where they are rafted and/or initially processed. The slash remaining after harvesting would be ptled or otherwise appropriately treated. In unroaded areas, the fallen logs are removed if required by the Forest Service and the remaining residual material appropriately treated. Clearing in the unroaded areas is accomplished in much the same way as in roaded areas, although equipment might have to be taken from one area to another via helicopter, depending on local conditions. Setting the poles can be readily accomplished along existing roads through the use of an auger/crane to auger the holes and set the poles. Again, one or more crews consisting of several workers are used to set the poles. As is the case with the clearing activities, setting poles along roads is much easier and less costly than in unroaded areas because standard wheel mounted vehicles can be employed. In the unroaded areas, special equipment such as low pressure vehicles in Muskeg areas and helicopters to transport materials, equipment and workers have to be used. Stringing the conductor, like clearing the rights-of-way and setting the poles, is also relatively easy and inexpensive along existing roads. It is, however, more expensive in unroaded areas where access is poor. Stringing operations, which involve laying out the conductor, raising it to the proper height and pulling it to the proper tension, also involve heavy equipment and a crew of several individuals. Helicopters are often used to help string the line, but their use depends on local conditions and the route's accessibility to other pulling and tensioning equipment. 4-37 2015B 4.4.7 Reliability The proposed line is designed to be operational for 30 years. The proposed line would be able to operate year round except for those times when the line is taken out of service either by unscheduled emergencies, or for scheduled maintenance. In the analysis it is assumed that the conventional overhead 3-phase lines would be out of service, because of emergency conditions, several times during the year. The line would also not be able to operate if the Tyee Lake to Petersburg section is out of service. Finally, scheduled maintenance activity may require that the Tyee-Kake line be de-energized at times, although most of the maintenance work can be completed with the line in service. Considering all of the outage conditions described above, it is estimated that the overhead line operates all but 2-1/2 weeks out of the year, or 95 percent of the time. 4.4.8 Costs Ebasco developed the costs of overhead transmission lines and included them in the Draft Feasibility Report. Costs from that report have been updated to 1983 dollars for use in this report. Two other changes have been made since the initial estimate. First, the submarine cable cost has been reduced to reflect the current recommendation for one, rather than two, cables at each crossing. Second, at the request of the Alaska Power Authority, the contingency estimate as been removed from the individual unit costs and is listed as a separate line item. 4.4.8.1 Capital Cost Estimate The estimated cost of the overhead transmission line is shown in the Estimate Summary Table, Table 4-2. The estimate shown is in 1983 dollars and is consistent with the estimates for the other alternatives described in Chapter 3.0. Detailed information on the values in the table is provided in the Cost and Engineering Report (Appendix B.1), while a brief explanation of some of the more important values in the table is provided below. Clearing Costs Clearing costs on this project were estimated by establishing two types of clearing activities: right-of-way clearing and danger tree cutting. In addition, the cost of these activities was estimated based on whether they occurred adjacent to a road or in an unroaded area. These categories were established because it is less expensive to clear vegetation adjacent to roads than in remote, inaccessible areas. The clearing cost analysis was further complicated by the additional costs associated with vegetation removal. Along a road this cost is moderate and is generally offset by the fact that merchantable timber that is removed can be readily transported to a point where it can be sold. Because clearing a right-of-way along a road is similar to roadside logging practices, its cost can be readily estimated. Also, because hauling costs are normally considered in analyzing a logging operation, they have been incorporated into the roadside clearing cost. 4-38 2015B TABLE 4-2 CAPITAL COST ESTIMATE SUMMARY OF THE 24.9 kV OVERHEAD TRANSMISSION LINE ITEM UNIT QUANTITY UNIT cost2/ cosT TOTAL COST (1983 $) aS——$———— eee TRANSMISSION PLANT Land and Land Rights 18,700 Structures and Improvements 30,800 Substation and Related Equipment 211,700 Roadside Clearing (includes removal) Right-of-Way Acres 77.36 4,664 360,800 Danger tree Trees 2545 46.64 118,700 Unroaded Clearing costs only Right-of-way Acres 67.73 7,462 505,400 Danger tree Trees 4384 46.64 204,400 Removal Costs2/ (0-2 miles of road) ee fers ol BE Danger trees rees 1 je 1 SUBTOTAL’ 1,539,100 Wood Poles and Fixtures/ Roadside (REA Type) Each 457 2,214 1,011,800 Unroaded (for aerial cable) Each 260 2,006 521,600 Wood Plank Stabilizers Each 31 6,017 186, 500 (in muskeg areas) SUBTOTAL 1,719,900 Conductor Cable & Devices ACSR Conductor (266.8 KC mil mile Mile 91.17 8,441 769, 600 for 3 x 30.39 miles) Overhead Cable (255.8 KC mil Mile 21,92 65,581 1,437,500 aluminum cable, 3 conductors, support wire, and accessories) Underground Conductor & Devices Submarine Cable Mile 1.59 573,987 912,600 End Terminals (two sets of surge LS 65,300 arresters and potheads) SUBTOTAL 3,185,000 INDIRECT CONSTRUCTION COSTS Temporary Construction Facilities Ls 135, 300 Construction Equipment Ls 317,200 Camp and Commissary LS 906, 700 Superintendance, Timekeeper, Ls 28,000 Clerk, etc. Insurance w/wage rates Mobilization w/directs SUBTOTAL 1,387,200 SUBTOTAL CONSTRUCTION COST (1983 $) 8,092,400 Contingencies 886,000 Design Engineering and Construction LS 860,000 Management SUBTOTAL 1,746,000 TOTAL PROJECT COSTS (1983 $) 9,838,400 ROUNDED AMOUNT 9,840,000 ae Includes 52,31 miles of 24.9 kV overhead line and 1.59 miles of submarine line for a total length of 53.9 miles. x Unit costs have been adjusted from original estimates by subtracting contingency costs and updating remainder to 1983 dollars. Cost estimates are still considered feasibility level 3/ estimates, despite their apparent precision. y Includes removal of merchantable logs. —/ Twenty percent guyed. 4-39 2015B In unroaded areas, helicopters may have to be used to remove the merchantable timber. Removing timber by helicopter is costly, often costing more than the value of the logs being removed. The clearing methods used in this analysis are described in Appendix B.5 in more detail and the costs involved are summarized in Table 4-3. Basically, a 20 foot right-of-way will be cut in the unroaded areas while a 25 foot right-of-way will be cut along roadsides. Danger trees will be removed along all segments and it is estimated that 200 trees per mile of line need to be removed in unroaded areas and 100 trees per mile of line would need to be removed in roaded areas. Another very important component in the assessment of clearing costs is the cost of removing merchantable timber from the cleared rights-of-way. Typically, on U.S. Forest Service lands, such timber must be removed so that it can be processed into various products. The cost of removing these merchantable logs varies considerably, depending on whether the logs are close to a road. In general, the logs can be economically removed if they are adjacent to roads. If the logs are farther from the road, but within 2 miles of a landing area, they would have to be removed by helicopter and the economics of timber harvesting with helicopters is marginal. Beyond two miles, log removal using helicopters is very costly and greatly exceeds the value of the logs. For example, for an average haul of four miles typical removal costs would be $1,200 per thousand board feet (mbf) when the logs themselves may be worth only $150/mbf. Because of the high cost and variable nature of clearing costs, three clearing scenarios were developed. Each of the three scenarios include the cost of clearing all transmission line rights-of-way and the cost of cutting all danger trees. In addition, for all three scenarios the cost of clearing along roads includes the cost of removing all merchantable logs (trees in the right-of-way and danger trees). The difference in the scenarios is a function of the amount of log removal to be undertaken in unroaded areas. The distinguishing features of each scenario are summarized below: Scenario 1 (lowest cost): Does not include the cost of removing any of the merchantable timber in unroaded areas. Scenario 2 (current practices): Includes the cost of removing merchantable timber (cleared right-of-way and danger trees) for portions of the route within 2 miles of log landing areas. Scenario 3 (highest cost): Includes the cost of removing all merchantable timber (cleared right-of-way and danger trees) from all portions of the route. The low cost scenario, Scenario 1, would cost approximately $1,351,500, which is $397,500 and $2,440,120 less than scenarios 2 and 3, respectively. 4-40 20158 TABLE 4-3 COST OF CLEARING ACTIVITIES (1983 $) Category Cost of Activitiesl/ R.O.W. CLEARING Roads ide2/ $ 4,664/acre Unroaded (incl staging area) $ 7,462/acre DANGER TREE CUTTING Roads ide2/ $ 47/tree Unroaded $ 47/tree TREE REMOVAL IN UNROADED AREAS WITHIN 0-2 MILES OF A LANDING AREA Removal of right-of-way timber $13,992/acre Removal of danger trees $ 117/tree TREE REMOVAL IN UNROADED AREAS FARTHER THAN 2 MILES FROM A LANDING AREA Removal of right-of-way timber $27,984/acre Removal of danger trees $ 233/tree I/ unit costs have been adjusted from original estimates by subtracting contingency costs and updating the remainder to 1983 dollars. Cost estimates are feasibility level estimates, despite their apparent precision. 2/ Includes removal cost. 4-41 20158 Because of its high cost, Scenario 3 is not considered further, while both scenarios 1 and 2 are analyzed in the economic comparison section. It should also be pointed out that the additional $397,500 cost of Scenario 2, as compared to Scenario 1, includes all additional costs, including fuel costs associated with removing these logs by helicopter. Wood Poles and Fixtures It is estimated that 748 poles will be required for the Tyee-Kake line, of which approximately 143 will be guyed. Of the estimated 748 poles, 457 will be located along roads. The unit costs of $2,006 for poles set in unroaded and $2,214 for poles in roaded areas were developed considering the higher installation costs in unroaded areas. Costs also reflect the higher cost of 3-phase poles and fixtures used along roads, which are more expensive because they include crossarms and associated hardware. The higher cost of installing poles in muskegs ($6,017) is because of the 31 wood plank stabilization structures required. Overhead Conductor and Devices The cost of overhead conductor and fixtures for the mixed 3-phase overhead cable line is shown in Table 4-2. The higher unit cost of the overhead aerial cable reflects the higher material cost for the overhead cable and the extra cost of installation. The installation cost of the overhead cable is more than the conventional 3-phase line, largely because it is built only in the unroaded segments of the route, where it has a cost advantage over a 3-phase line plus clearing. Submarine Cables Two submarine segments are constructed as part of the Tyee-Kake project. These segments, however, are treated as one unit because it is more economical to design and construct a line using this approach. As shown in Table 4-2, the total cost of the submarine cable and associated devices is $977,900. Indirect Construction Costs Because the proposed project would be constructed in a relatively remote area, indirect construction costs would be high. Such construction costs are particularly high for the unroaded area between Duncan Canal and Kake. It is anticipated that a floating camp has to be established on Duncan Canal and that it will be necessary to make extensive use of a helicopter to transport workers and equipment to relatively inaccessible areas along the route. The itemized indirect construction costs are shown in Table 4-2. Design Engineering, Construction Management,and Contingencies The overhead costs include costs associated with designing the line and Managing its construction. One of the largest components of these overhead costs would be the surveying and mapping activities and the 4-42 20158 costs associated with construction management. It is anticipated that one individual would be assigned to the project full time to oversee the construction activity. Contingency costs add approximately 11 percent to the cost estimate. 4.4.8.2 Operation and Maintenance Costs Inspection The line will have to be inspected periodically. Such visual inspection can be readily accomplished between Scow Bay and the Wrangell Narrows crossing because of the easy access to those areas. The rest of the overhead line, particularly during the winter months, is inspected from the air. During the initial year of operation, a monthly patrol overflight is to be conducted. As the flight route from Kake to Petersburg generally parallels the proposed intertie, it is likely that aerial inspections could be accomplished in conjunction with scheduled daily flights to reduce costs. It is estimated that these overflights would cost approximately $2,650 per year. Maintenance Each year there also will be costs associated with repair and Maintenance of the line. This includes replacing poles, repairing damaged insulators, and other maintenance activities. The cost of these activities, beyond what can be done by the power superintendent in Kake, is estimated at approximately 25 workdays or $10,600 while the materials to replace the poles and hardware is estimated to be approximately $10,600 per year. In addition, every eight to nine years the right-of-way has to be cleared of vegetation posing a threat to the line, including danger trees. The annualized cost of this clearing together with contingencies and other miscellaneous costs is approximately $23,850. Thus, the total annual cost of inspection and maintenance activities for the transmission line is $47,700. 4.4.8.3 Diesel Backup A backup diesel system is needed during outages. To the overall cost of the overhead transmission line, one must add the cost of fuel required to provide five percent of the Kake load. The existing diesel generators are assumed to provide adequate backup capability throughout the lifetime of the transmission line. 4.4.8.4 Line Losses There are line losses associated with transmitting power over the proposed Tyee-Kake transmission line. The estimated losses at peak loadings are 64 kW in 1982 and 110 kW in 2015. There is no economic value to these losses because of the availability of capacity at the Tyee Lake Hydroelectric Project. In other words, even though there is 4-43 20158 energy lost on the Tyee-Kake line, the lost energy would be composed of hydroelectric power that would not be generated without this transmission line. 4.5 UNDERGROUND TRANSMISSION LINE OPTION An underground transmission line alternative was evaluated and reported on in Ebasco's Overhead/Underground Reconnaissance Report and in the Draft Feasibility Report Supplement. This section summarizes those findings, plus additional information provided in response to comments on the earlier reports. 4.5.1 Underground Line Routing The underground transmission line route is nearly the same as that described for the overhead line. As shown in Figure 4-2, the overhead and underground alternative routes diverge for a short section near Duncan Canal. At that point, the underground route goes through a muskeg area while the overhead route goes around it. The underground route is shown in Figures 4-18A through 4-18D. 4.5.2 Cable Selection Unlike overhead lines, which are currently built exclusively with aluminum (AL) conductors or with aluminum conductors having steel reinforcement (ACSR), cables frequently use copper as conductor material. Several factors make copper more desirable than aluminum for many cable applications. Three of those weigh heavily in the case of the Tyee-Kake Intertie. First, the diameter of the copper conductor is smaller than that of aluminum based on same current carrying capacity. Consequently, a copper cable is more flexible. Also, more length can be transported on the same size reel for a copper cable as compared to an aluminum cable. A more flexible cable means easier installation, which is very important in remote areas. Larger unit lengths mean fewer joints, called "splices," whose careful completion is a time consuming porocess. Furthermore, experience indicates that the weakest points of newly installed cables are usually the splices. Therefore, the fewer number of splices an underground line has the more reliable it will be. Second, copper resists corrosion much better than aluminum. Therefore, in case of cable rupture, copper will resist the hostile chemicals found in the soil better than would aluminum. This can be particularly significant in the case of the Tyee-Kake Intertie, because relatively long periods of time may pass in the winter before the actual repair of a damaged cable may be undertaken. A third advantage is that welding and soldering copper is a much easier and more reliable process than it is for aluminum. This is an important point during both the installation and repair. 4-44 20158 SEGMENT #8 . & < Ke | nf ORIGINAL ~~~ 0s : os GROUND PROFILE OS Sp Risa See Sia ss, @ TYPICAL IN ROAD CABLE INSTALLATION END OF PROJECT MILE 53.05 P > . we Ome eed ‘ we ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYS!S . UNDERGROUND | 2 TRANSMISSION LINE ROUTE FIGURE 4-18A SCALE IN MILES 4-45 KEN, i Se We \ : 3 Z] i ahs < | ‘ Lo-v IIMS ZG Cee SEGMENT #5 SS Sy AN N 5 (G is a iH S VY HN ~ 3 ry TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS UNDERGROUND TRANSMISSION LINE ROUTE FIGURE 4-18C EBASCO SERVICES INCORPORATED 4-47 IS LA = he | { in OK ms \ LEA ( Gye: z ; hie YG 6 ; x / / ok » aed, '/ a = p ' 7]. (Oe SEGMENT #1 ou onamia 2 ste ee . 5 ; : @ TYPICAL IN ROAD CABLE INSTALLATION ; . ALASKA POWER AUTHORITY ROWE ~~ pee TYEE - KAKE INTERTIE PROJECT : \ \ \ SS \ DETAILED FEASIBILITY ANALYSIS SS UNDERGROUND TRANSMISSION LINE ROUTE FIGURE 4-18D EBASCO SERVICES INCORPORATED 4-48 In addition, the world price of copper per pound recently dropped below that of aluminum, apparently for the first time this century. This makes copper cables economically more attractive than formerly. For the reasons given, copper conductor was selected for the cable. The size of the copper conductor was chosen while considering the following. The Draft Cost and Engineering Report (Appendix B.1) indicated that transmitting the 1.6 MW power at 0.9 power factor via an overhead line would result in large voltage fluctuations at Kake. In order to compensate for these voltage variations, a tap changing transformer (LTC) with larger than the standard steps was specified.1/ Because of the closeness of the cables in the common trench the reactance of a cable transmission line is low. The ratio of X/R, reactance over resistance, in case of the 2/0 cable used in the studies is 0.44. The same ratio for the overhead alternatives studied was 1.38. Consequently, the reactive voltage drops less in the case of the underground line. In addition, the conductor must have a certain amount of cross-section to withstand the mechanical stress it is exposed to during the laying of the cable. Preliminary calculations indicated that 2/0 copper conductor cable would satisfy all the above conditions. Application of such cable would result in less than 10% voltage drop along the line. This means that the LTC at Kake can be of standard design. More detailed calculations indicated that 3/0 copper cable would result in an "over design." A 2/0 copper conductor was chosen because it is probably very close to the optimum. 4.5.3. Interconnection at Petersburg and Kake The alternatives available for interconnecting an underground transmission line from Kake to the Tyee Lake 69/138 kV line are the same as those for the overhead line discussed in Section 4.4.3. The underground transmission line option therefore includes a 4.9 mile overhead segment where the Tyee-Kake 24.9 kV line is underbuilt on the Tyee Lake line south of Petersburg. 4.5.4 Submarine Cable Facilities The underground transmission line option also includes the same submarine crossings as discribed in Section 4.4.4. The only difference is in terminal facilities. Where an overhead line terminates into the cable, the facilities include potheads on single poles. Where a submarine cable terminates into an underground cable, the splices are housed within a small (approximately 4'x4'x4') box-like structure. 1/ +16 steps at 1% was specified compared to the standard 5/8% steps. 4-49 2015B Some utilities recently installed conventional URD cables in underwater crossings. Therefore, the submarine cable could possibly be replaced by underground cable, particularly under Duncan Canal. That option should be evaluated during the design phase of the project. Like the initial overhead transmission line cost estimate, the underground line estimate has been altered in this report to reflect the installation of only one submarine cable at each crossing, instead of the two cables assumed initially. 4.5.5 Installation There are three basic types of equipment which can be used to install underground cables. These include plows, trenchers, and rocksaws. Local conditions dictate what type of equipment should be used in specific areas. Considerations related to the use of such equipment are presented in Section 3.4 of the reconnaissance report (see Appendix B.2). A summary of the major issues related to cable installation is provided below. Generally, plows are preferred when conditions allow their use. Cable installing plows move relatively quickly through loosely consolidated material. Production rates up to 1 mile per day have been recorded. In general, plows provide a very cost effective way to install cable where conditions are favorable. Problems which may be encountered when using a cable plow include rocky conditions, balling of root material in muskeg areas, and puncture at muskeg road support fabric. Vibratory plows move well in rocky conditions and even have the advanatage of "pulling" fines into the cable laying furrow, thus providing some bedding for the cable. Large rocks (2-foot diameter) are, however, a problem and will significantly slow production. Roots and vegetation will tend to ball in front of the plow in a muskeg area. These balls will have to be manually cut if allowed to develop. A better solution is to have a sawing operation in front of the plow cutting the line through the vegetation. In order to prevent change to support fabric when cable plowing on muskeg roads, it is necessary to closely control the plow depth to a minimum clearance above the fabric. This may result in laying a “shallow” cable in some areas. In areas of rock or other dense materials it would probably be necessary to either drill and blast or pre-rip material with a bulldozer prior to installing the underground cable. Cable laying trenchers are also effective in installing cable, although under ideal conditions they cannot move as rapidly as cable installing Plows. Another alternative in rock is to use a rocksaw which cuts through the rock material, providing a suitable location for the underground cable. Production rates for rocksaws, however, are extremely slow (200-300 feet per day) and their use on the Tyee-Kake Intertie 4-50 2015B underground option would be prohibitively expensive. Consequently, it is not anticipated that rocksaws or drilling and blasting would be used on the Tyee-Kake Project. In this report it is assumed that either a plow or trencher would be employed. The characteristics of each of these machines is described in more detail in the reconnaissance report (Appendix B.2). The discussion which follows highlights some of the major concerns and assumptions influencing the constructability and cost of underground cable installation in areas encountered along the route. These considerations are discussed in terms of typical conditions found in areas where the cable would be installed. Roads For the portions of the route where the proposed underground cable would be constructed within the road prism it is anticipated that the cable would be plowed into the side of the road using a plow or trencher trailed by a bulldozer supporting the cable spools. Following installation, the cables would be located as shown in Figure 4-19. Plowing the cable into the road is desirable and can be readily accomplished in many types of roads. In the case of the roads in the Tyee-Kake Intertie project area, however, installation could be difficult. The roads in the project area are constructed of shotrock, which is composed of many angular fragments of varying size up to 3 feet or possibly larger. These rocks would create problems for the cable installation equipment, and would be abrasive to the cable itself. Special care would need to be taken to ensure that the cable is not damaged during installation. Damage to the cable from sharp rock is also possible, due to vibration created by vehicular traffic on the road. Further testing or special design may be necessary before installing cable in these high-risk areas. Special care would also be required at any point along the route where a culvert is located. In such areas, the cable would have to be installed under the culvert or be buried several feet away from either the culvert inlet or outlet. A sketch of typical culvert installations is shown in Figure 4-19. The characteristics of the roadbed in the project area can be potentially troublesome to cable installation equipment. Large boulders could interfere with plowing or trenching operations, as could large stumps or other woody debris within the road itself. In addition, in many areas it would be very difficult and prohibitively expensive to provide the full 30 inches of cover over the cable as specified in the National Electrical Safety Code for standard installation of underground cable. In light of these conditions, it is recommended and assumed that only two feet of cover over the cable would be required and in some instances the cables could be even closer to the surface. Such reduced cable cover would be installed only where conditions prohibit deeper installation and where it is considered safe given the activities 4-51 2015B sey ORIGINAL ~2-~ ~~~ GROUND PROFILE WP ts eee een. @ TYPICAL IN ROAD CABLE INSTALLATION ALASKA POWER AUTHORITY TYEE -— KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS TYPICAL CABLE INSTALLATION IN ROADS EBASCO SERVICES INCORPORATED 4-52 Figure 4-19 expected along the road. Prior to such an installation, it is necessary to obtain the necessary State approval to vary from the established national code. Assuming such installation practices are acceptable, and that no major unforeseen obstacles to installation occur, it is expected that underground cable could be installed at a rate of approximately 1750 feet per day along a road. Unroaded Forest Installing an underground cable in unroaded forested areas requires site preparation work and limited clearing. The clearing required is limited to that amount which allows both the cable installation vehicle and trailing cable reel transport vehicle to maneuver within the designated right-of-way. It is assumed that a clearing width of approximately 10-15 feet is sufficient. Clearing of the right-of-way is flexible when compared to the clearing requirements of an overhead line, because in the latter case, a perfectly straight centerline is required. Activities required to prepare the soils for installation include pre-ripping of the surface in some areas. It is assumed that through careful route alignment it is possible to avoid areas of large rock outcroppings so that no drilling or blasting will be required. It is also assumed that in areas of shallow soil, small berms may be built up to provide adequate cover over the cable while preventing the need for costly cable installation within rock, hardpan, or other unfavorable conditions below the surface. Typical installed cable conditions in unroaded areas are shown in Figure 4-20. In areas where a berm is to be constructed to provide cover over the cable, adequate surface diameter will be assured. Such measures are particularly important in those forested areas along slopes where maintaining existing drainage patterns is important in minimizing environmental impacts. Unroaded Muskeg While researching the feasibility of the underground transmission line option, Ebasco found no one with solid experience installing underground cables in unroaded muskeg areas. Constructability and cost studies, however, were conducted using experience with tracked and other low-pressure vehicles on muskegs with characteristics similar to those encountered in the project area. Installation of underground cables in muskeg areas needs to be carefully planned so that the number of equipment crossings is limited. In addition, special efforts are required so that the weight of the cable installation plow or trencher and the cable reels is properly distributed and does not produce pressures beyond the bearing strengths of the muskeg. If underground cable is layed in muskeg, it is assumed that special wide track vehicles with winches will be employed to minimize the risk of bogging down in muskeg areas. A discussion of the types of equipment which are available to install cable under such conditions is found in Appendix B.2 of this report. 4-53 20158 @ TYPICAL CABLE INSTALLATION IN UNROADED AREAS 2 3% oS = s pee oS ore SS 3 Bos We are GROUND SURFACE Sone SHALLOW BEDROCK | } 2' BERM — : CEN @ TYPICAL CABLE INSTALLATION IN UNROADED AREAS WITH SHALLOW BEDROCK ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS TYPICAL CABLE INSTALLATION IN UNROADED AREAS EBASCO SERVICES INCORPORATED 4-54 Figure 4-20 Installation of underground cables in unroaded muskeg areas requires minor routing modifications so that ponds, rock outcrops, and small forested areas are avoided. For this reason, estimates for the length of cable include an allowance for periodic routing deviations from the original route. Recognizing the high variability in local muskeg conditions, it is difficult to develop an estimate of production rates with a high degree of confidence. In light of the experience in other areas, and considering local conditions, it is estimated that approximately 2500 feet per day of cable can be installed in the project area's muskegs. Background information on how this production rate was determined is shown in Appendix B.2. Cable splicing should be accomplished by using the newer one-piece factory splices, rather than tape splices. These splices are highly reliable, easily installed, and are finding wide acceptance by utilities. 4.5.6 Reliability The reliability of an underground transmission line is of concern to several public agencies which have offered comments on the Draft Feasibility Report Supplement (see Appendix D.1). In response to those comments, Ebasco performed an extensive survey, by contacting many utilities and contractors regarding their experiences installing underground cable. Utilities contacted include Snohomish County PUD, Washington Water Power Company, Montana Power Company, Puget Sound Power and Light Company, Idaho Power, Portland General Electric, Orcas Power and Light, Iliamna-Newhalen Electric, Bonneville Power Administration, Florida Power and Light, Utah Power and Light Company, and Saskatchewan Power Corporation. Contractors and vendors contacted include Dodge Electric, John Deere, Jacobson Brothers, Rome Cable, and Nations & Sons. Although individual experiences with underground cable varied, the following discussion represents a concensus of those utilities and contractors contacted. Failure of underground cable generally falls into one of two categories. These are failure of the cable itself (e.g., insulation failure, corrosion of conductors, or concentric neutral failure) and failure due to external or environmental causes (e.g., rock punctures of insulation, earth movements, or dig-ins). There seems to be no doubt that the first category, failure of the cable itself, is directly related to quality control measures. Utilities that have instituted strict quality control procedures for acceptance, handling, and installation have found that the cables will provide many years of service before failure occurs due to 4-55 20158 treeingl/ or other cable material problems. The likelihood of these problems occuring may be reduced further by use of tree retardant additives or more expensive insulating (XLPE or EPR) materials. Underground cables are not subject to the normal overhead environment problems of rain, wind, and falling trees. However, they are subject to damage from rock protrusion, soil settlement, corrosion, or dig-ins. Protrusions from rocks is a problem mainly with trench installation. It can be at least partially controlled by careful work procedures, such as assuring that approximately four inches of fine backfill is placed below and above the cable and that the rest of the backfill is not dropped into the trench carelessly. Problems are also avoided by keeping large, sharp-edged rocks away from the cable. When the cable is installed in a roadbed constructed of crushed rock, the problem is different. In this case, the vibration caused by traffic may result in movement between rock and cable. Tougher cable jacketing or cable armor can be used in such cases to reduce the probabilities of failure. As an advantage, cable installed in a road is more accessible to repair in the event of failure. Settlement is another problem that can occur where roads cross the cable route or where the cable is laid into or nearby the road prism. In such areas, the roadbed may subside and/or the adjacent soil may settle. Because the cable has only limited flexibility in the trench, if the elongation is excessive it will strain the cable beyond its limits and the cable will break. The stress in the cable can be more serious if the cable is inbedded in rockfilled roadbed, because the rocks can exert local abrasive pressures and hinder the cable's already limited capability to move. All this suggests that cables should not be installed in roads crossing muskeg, because road settling is likely to occur in these areas. This conclusion is supported by the fact that some Forest Service roads across muskeg areas are constructed on top of fabric materials. Disturbance of the underlying fabric could affect the integrity of the entire road. Corrosion generally occurs in low resistivity soils in the presence of an electrolyte. Investigations by Ebasco have, however, shown that the properties of modern jacketed underground cables eliminate the adverse effects of electrolytic or acidic soils. A pH as low as 3.5 is expected to have no effect on the cable. Failure due to dig-in typically occurs while constructing telephone cables, sewers, roads, or culverts, or if trenching occurs along the V/ The term "tree" in cable technology refers to the phenomenon that once solid insulating materials start to deteriorate at a certain location, the failure will propagate in hairbreadth channels, branching as it expands, leading ultimately to electric arcing. When bisected, the insulation shows patterns that looks like roots of trees, hence the name. 4-56 2015B cable route. Along the route proposed for the Tyee-Kake Intertie, the only area where this may occur is where the cable is in the roadbed or runs very close to it. The problem can be minimzed by clearly marking the cable route. A cable manufacturer has developed failure curves based on cable failure data obtained from 21 American utilities covering the years 1964 through 1982. The curve for XLP cable indicates first failure at the seventh or eighth year of service with a linearly growing failure rate reaching six failures per 100 miles of cable in the 20th year. This seems to be the only “hard data" presently available on cable reliability. There are many reasons to believe that a custom designed cable for the Tyee-Kake Intertie would perform significantly better. First, such a cable would represent advanced design and technology compared to the data base from which the curves were developed. That data base includes a conglomerate of production line cables. Second, most cables installed in the past have insulation thicknesses that are weaker than a custom designed cable could be. Third, the Tyee-Kake cable would not be exposed to almost daily temperature variations as are almost all cables installed in the lower 48 states. Finally, the Tyee-Kake cable would be only a few degrees above the ambient soil temperature, whereas cables in the lower 48 are generally subject to high (up to 75°C to 110°C) temperatures. Because experts generally agree that treeing does not occur at low temperature and low electric stresses, cables of the Tyee-Kake Intertie should give highly reliable service. 4.5.7 Costs 4.5.7.1 Capital Cost Estimate The basic cost estimate for the underground transmission line is the same as that given in the Draft Overhead/Underground Reconnaissance Report, with two exceptions. The estimate in the Draft Reconnaissance Report was prepared assuming the construction of a new Forest Service road for the North Irish timber sale. With the road in place, a portion of the line could have been installed under the road. This represented a savings of $700,000 when compared to the cost of installing the line in an unroaded forest and muskeg area. However, because of conditions in the local timber market, it now appears unlikely that the road will be constructed as scheduled in 1984. The cost of $700,000 has therefore been added to the original cost estimate. Careful consideration should be given to Forest Service plans for completing that road. If it is to be completed in the near future, development of the transmission line could be delayed accordingly, with a savings of $700,000. The second adjustment is a reduction in the estimate by $300,000. This reflects the new recommendation that one, rather than two, submarine cables be installed at each submarine crossing. The new cost estimate is shown in Table 4-4. A contingency estimate of 20 percent reflects the uncertainties of installing underground cable under the conditions found along the route. 4-57 20158 COST ESTIMATE SUMMARY OF THE TABLE 4-4 24.9 kV UNDERGROUND TRANSMISSION LINEL/ Land and Land Rights Substation (incl. mesg pore) Overhead (along road)1/ Submarine Cable2 Underground (Muskeg) 2/ Underground (Roads) 2/ Underground (Glacial Ti11)2/ Clearing Labor Camp Mobilization/Demobilization Additional Unroaded Areas Segment (see Section 4.5.7.1) Subtotal (1983 dollars) Contingency (20%) Professional Services Total Installed Cost Rounded Amount Operation/Maintenance Cost Fuel Cost in Base Year for Diesel Backup $/million BTU $/Mwh J/ Underbuilt on existing line. 2/ Unit of measure is line miles, not cable miles. 20158 Unit LS LS MI MI MI MI MI MI LS LS Ls 4-58 Unit Total Cost Quantity Price (1983 $) $ 20,000 566,000 4.95 64,240 318,000 1.59 635,849 1,011,000 9.32 70,172 654,000 31.05 65,090 2,021,000 5.22 77,200 403,000 16.79 16,320 274,000 348,000 295,000 700,000 $ 6,610,000 1,322,000 625,000 15,400/yr 9.02 99.22 4.5.7.2 Operation and Maintenance Costs Normally, cables do not need to be inspected regularly. Occasional inspection of the underground cable route could be best accomplished by vehicle in roaded areas and by overflights in unroaded areas. Visual inspection should be for settling, dig-ins, or other signs of underground movement that might damage the cable. Additionally, above ground points at transitions, termination cabinets, and reactors may be occasionally inspected. Location of faults in the underground cable can be accomplished through use of radar and thumpers. Because the line would have no taps, radar should detect faults accurately. Radar with ranges suitable to detect faults along the entire length of the Tyee-Kake underground line recently became commercially available. Once the approximate location of the fault is established, a crew can go and open up the line at a suitably located junction box. Radar from this location will locate the general area of the fault to within 100-200 feet. The thumper will pinpoint the exact area by sending a voltage through the line that creates an audible sound at the fault location. The sound can be picked up while one crew-member equipped with a walkie-talkie, walks along the cable route and places a detector (essentially a microphone) on the ground. Operation and maintenance costs for the underground transmission line are estimated at $15,400 per year. Maintenance is estimated at 10 working days per year, or $4,200, while the materials to replace the damaged sections of cable are estimated at approximately $6,300 per year. Right-of-way patrol, contingencies, and other miscellaneous costs should be approximately $4,900 per year. 4.5.7.3 Cost of Diesel Backup Some outages can be expected with the underground transmission line. Although careful inspection and quality control will minimize the number of defective splices, some are expected to occur. Defective splices or terminations that are not detected prior to energizing the line might fail within the first five to ten years of operation. There is also a possibility that the underground or marine cable could be accidently damaged by excavating equipment or marine equipment. Failure of the submarine cables is unlikely. However, if it does occur, it is expected that repair will require about three weeks. In addition, the line will not operate if Tyee Lake power is not available. Some equipment replacement and/or service outages may also be required. Considering all outages, it is estimated that the transmission line will operate all but six days of the year, or 99 percent of the time. The comparable figure for an overhead line is 95 percent, because it is exposed to more external hazards. The existing diesel generators will be maintained to provide backup power in case of an outage. The cost of providing this backup capability is equal to the fuel cost times one percent of the load in each year. 4-59 20158 4.5.7.4 Line Losses As with the overhead transmission line, underground transmission line losses are assumed to have zero value in this analysis. The lost energy would be composed of hydroelectric power that would not be generated in the absence of the transmission line. 4.6 ENVIRONMENTAL CONSIDERATIONS Environmental impacts of the overhead transmission line were analyzed jin the Draft Routing and Environmental Report. Comments on the Draft have since been incorporated into the final report, which is included here as Appendix C.1. Environmental impacts of the underground transmission line were discussed in the Draft Feasibility Report Supplement. The differneces between the overhead and underground transmission line impacts are summarized as follows. 4.6.1 Soils Installation of underground cable over long distances will affect considerably more soil than would construction of an overhead line. An underground cable installation would require a smal] trench or opening in the soil for the entire length of the route, while the overhead line requires in general only small excavations at each of the 15 poles per mile. In addition, the previously identified overhead route largely avoided sensitive muskeg areas, due to the engineering properties of those soils. The underground cable route essentially attempts to follow muskeg areas to minimize clearing and installation difficulties. Certain soil conditions would be altered as a result of the construction activity. In the roaded areas, a bulldozer would be operating behind the cable installation equipment to restore the road to its original condition following installation of the line, thereby reducing potential exposure to erosional forces. Similarly, the relatively narrow width of the area to be disturbed by the cable installation plow or trencher will be restored to the grade existing prior to construction as soon after installation as practicable. Nevertheless, soil erosion and other related considerations would be of More concern for the underground alternative than for the overhead line. In muskeg areas contract specifications will also have to be prepared so that the number of times a vehicle passes over a muskeg is kept to a minimum. Frequent crossings of the muskeg area could break up the fibrous material of the muskeg, thereby opening up the muskeg to more rapid water flow and other conditions which would change the muskeg's character. The trench itself may change flow patterns through the muskeg by channeling the flow along the trench. In the event that the cable-laying equipment bogs down in muskeg areas, the amount of soil disturbance in local areas may be substantially larger than the narrow right-of-way. Soil related concerns also arise from the possible construction of small berms in areas along the route. The berms are required to allow cable installation without use of a rock saw or blasting in areas of 4-60 2015B shallow bedrock and hardpan. Such berms, if not properly designed, could channel flow in areas where it could lead to increased erosion and soil loss. Careful consideration should be given to the location and design of such berms during project design. A program to insure rapid revegetation will also be important. 4.6.2 Water Resources The factors affecting soils described in the preceding section could also affect water resources in the project area. Drainage patterns in muskeg areas could change if care is not taken in planning construction activities in those areas. In addition, care must be taken to design berms such that natural drainage patterns are not altered. Another, more important, factor affecting water resources is the potential stream disturbance which could result from cable crossings. Installing an underground cable across a stream would require the use of a backhoe in large streams and plows or trenchers in small streams to remove the material prior to installation of the underground cable. An alternative to underground crossings of the streams would be to use overhead line at the stream crossings. Such crossings would be most appropriate at streams with relatively steep side slopes. During the design process, individual stream crossings would need to be considered on a case by case basis. 4.6.3 Fish Impacts on fish would be greater for the underground cable alternative than for an overhead line if overhead crossings were not planned for stream crossings. Impacts would be greater because of the potential effects on water resources described above and because of direct effects on fish habitat. Spawning gravels for anadromous fish could be directly disturbed by excavation in the stream or could be covered by a smothering layer of sediment from soil erosion. The potential effect on fish is of most concern in the area where the proposed underground cable would not follow existing roads. Consideration must be given to restricting the timing of instream and streamside construction activities. Activities should be limited to the period between when the juveniles have migrated from the spawning areas and before the adults have returned to spawn. 4.6.4 Wildlife During reviews of overhead transmission line effects, wildlife impacts drew the most concern from public agencies. Of particular concern was the potential impact on waterfowl using the flyway adjacent to Duncan Canal, because waterfowl might collide with the overhead line. The muskeg and pond area on the west side of Duncan Canal was of particular concern, given its relatively flat, open character and attractiveness to waterfowl. A secondary waterfowl concern was disturbance of nesting by construction activities. There was also concern regarding potential electrocution of bald eagles and potential disturbance of nesting sites. Designs chosen for the overhead alternative reduced the 4-61 20158 electrocution risks, while routing requirements which specified that the transmission line would need to be a specified distance from an eagle nest reduced that concern. The installation of an underground cable would effectively eliminate the concerns about collisions and electrocutions. Construction impacts on wildlife should be similar for either the overhead or underground option. 4.6.5 Visual Resources Visual impacts would be substantially less for underground alternatives than for the overhead. The proposed underground cable right-of-way would blend with the surrounding landscape as time passed and the proposed facility would take on a more natural appearance. 4.7 PERMITS AND RIGHT-OF-WAY REQUIREMENTS 4.7.1 Permits Permit requirements are described in Section 6 of the Routing and Environmental Report (Appendix C.1). As indicated there, permits will be needed in the following areas: Forest Service Special Use Permit to cross federal lands. U.S. Corps of Engineers Section 10 and 4045 Permit to install the submarine cable in navigable waters. Tidelands Permit from the State of Alaska for the submarine crossings. Cultural Resources investigations required in accordance with the requirements of the Forest Service and State Historic Preservation Office. 4.7.2 Right-of-Way Requirements The proposed transmission line will be located almost entirely on public land, the great majority of which falls within the Tongass National Forest administered by the U.S. Forest Service. Over forty miles of land administered by that agency are crossed by the line. Private land holdings, as shown on the Land Status Map in the Routing and Environmental Report, are concentrated at both ends of the line, near Petersburg and Kake. At the Petersburg end, the Tyee Lake transmission line easement would be used by the Tyee-Kake line for the first five miles south of the proposed substation at Scow Bay. On the eastern approach to the Wrangell] Narrows crossing, a vacant state easement appears to offer the best opportunity for routing the line. This easement, and a preliminary location of the transmission line on it, is shown in Figure 4-21. The Alaska State Department of Natural Resources was contacted regarding this routing and they identified no problems associated with it. 4-62 2015B Near Kake private land is also encountered, but in this area the line would follow existing roads where right-of-way acquisition problems should be minimal. 4.8 SCHEDULE Figure 4-22 shows a potential schedule for completion of the project construction activities in a single season. This would require planning all work around the start of construction activities (Right-of-Way Clearing) in April, which is Month 11 on the schedule. Testing and Energization could take place the same year in November with this schedule. 4-63 20158 = oa m a ' =x e > ° ” SOUTH - 32241 ALASKA POWER AUTHORITY TYEE - KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS LEGEND STATE EASEMENT ON EAST SHORE OF —--—— PROPOSED UNDERGROUND/ WRANGELL NARROWS CROSSING SUBMARINE CABLE FIGURE 4-21 PROPOSED 5-PHASE OVERHEAD LINE EBASCO SERVICES INCORPORATED 4-64 > g9- DESIGN ACTIVITIES FIELD SURVEYS AND INVESTIGATIONS ENGINEERING AND DESIGN STUDIES PROJECT MAPPING PREPARE B:D DOCUMENTS SOLICT CONSTRUCTION BIDS SELECT CONTRACTOR CONSTRUCTION ACTIVITIES CLEAR RIGHT-OF-WAY AND DANGER TREES INSTALL SUBMARINE CABLE SET POLES AND FIXTURES STRING CONDUCTORS COMPLETE INTERCONNECTION IN KAKE AND PETERSBURG TESTING AND ENERGIZATION SUPPORT ENGINEERING LEGEND A FUNDING OF PROJECT APPROVED TASK COMPLETED owmeeee INTENSIVE ACTIVITIES “m= LIMITED ACTIVITIES 1983 PROJECT MONTH j= om SS Ow cen 1984 5 6 7 8 9 10 1 a oe ee} me -=--@ ALASKA POWER AUTHORITY TYEE — KAKE INTERTIE PROJECT DETAILED FEASIBILITY ANALYSIS DESIGN AND CONSTRUCTION SCHEDULE FIGURE 4-22 EBASCO SERVICES INCORPORATED 12 13 | 14 16 16 | 17 18 19 5.0 BENEFIT/COST ANALYSIS OF THE KAKE, ALASKA ELECTRICITY SUPPLY OPTIONS Five options have been carried forward for economic evaluation: 1) Diesel-electric generation (the base case); 2) The Tyee-Kake overhead transmission line intertie; 3) The Cathedral Falls hydroelectric project, with supplemental diesel generation; 4) The wood fired power plant option; and 5) The Tyee-Kake underground transmission line intertie. Each of the options identified in this Feasibility Report can supply the electricity needs of Kake and, with the exception of the base case, can displace a large part of the fossil fuel based generation with renewable energy resources. Consequently, all options except the base case afford a significant measure of protection from escalating fossil fuel energy prices. The economic analysis presented here is intended to identify the alternative with the greatest excess of benefits over costs without considering the cost of power. This Feasibility Report provides input to a financial analysis that will be completed by the Alaska Power Authority. The financial analysis will identify the wholesale cost of power associated with the recommended alternative. The financial analysis will also consider other factors not treated here, such as how sensitive the project's financing is to State equity contribution and other financing methods. User agreements for power sales contracts would be required before state participation in the project could occur. 5.1 ASSUMPTIONS FOR ANALYSIS Benefit/cost (B/C) analysis is the method employed in this economic evaluation. Benefits are defined as the present worth of all costs associated with the base case ji.e., benefits are defined as costs foregone by eliminating the use of diesel generators. Costs are defined as the present worth of all costs associated with each alternative. The analysis is done in 1983 dollars, and the project base year is 1983. The termination year is defined by the life of the longest lived project. The Cathedral Falls hydroelectric project has the longest expected life, assumed to be 50 years following construction in 1985. The final evaluation year for all alternatives is, therefore, 2035. The general assumptions for benefit-cost analysis are shown in Table 5-1. The specific values and assumptions associated with each alternative are shown on Table 5-2. Capital investment schedules, by project, are presented in Table 5-3. | 20028 TABLE 5-1 GENERAL ASSUMPTIONS FOR BENEFIT-COST ANALYSIS Capital Investment Assumptions 1) 2) 3) 4) 5) Base Year = 1983 (Project Year 0); Project Planning Period = 1983 - 2002 Termination Year = 2035 (Project Year 52); Discount Rate = 3.5% (Real) and : Unused Project Life Capital Investment x Total Project Life Salvage Value Electricity Supply Assumptions 1) 2) Electricity demand will follow the Alaska Economics Projection to the year 2002; and Electricity demand will be constant for the years 2002-2035. Escalation Assumptions 1) 2) 3) Fossil fuel prices will escalate at a real rate of 2.5% to the year 2003, and remain constant thereafter; Operating and maintenance costs will escalate at the rate of inflation (real rate = 0%); and Capital costs will escalate at the rate of inflation (real rate = 0). 5-2 2002B TABLE 5-2 SUMMARY OF ALTERNATIVE-SPECIFIC ASSUMPTIONS AND VALUES Parameter Capital Costl/ ($ 1983) Project Life (yrs) Electricity Supply (Percent of total Kake requirement) Heat Rate (Btu/kWh) Fuel Cost (1983 $/ million Btu) 0 & M Costs (1983 $) IF Ie IN ic ~~ ON NON Iw ~ Project Overhead Cathedral Underground Base Case Transmission Falls Wood Fired Transmission Diesel Line Hydro Plant Line 1,333,0002/ 9,840,000 7,450,0003/ 3,850,000 98,560,000 20 30 50 20 30 100 95 47-40-50 4/ 95 4/ 99 11,000 N/A NA 24,000 5/ N/A 9.02 N/A N/A 2.33 N/A 155,800 47,700 64,800 &/ 312,700 15,400 Capital cost shown is for one plant of the selected technology. Does not include one cycle of diesel generation replacement. The remainder is supplied by diesel. The diesel heat rate applies to the percentage of power generated by that technology. 8/ This does not include 0 & M costs for a full diesel plant. 20028 Staged as replacements for existing units as described in Section 3.1.1 TABLE 5-3 CAPITAL INVESTMENT SCHEDULES BY PROJECT (1983 $) Year Project Alternatives Overhead Underground Diesel Transmission Diesel Transmission Calendar Project System Line Hydro for Hydro Wood Line 1984 1 9,840,000 3,850,000 8,560,000 1985 2 7,450,000 1989 6 573,200 573,200 1992 9 1995 12 759,800 759,800 2004 21 3,850,000 2009 26 573,200 2014 31 9,840,000 8,560,000 2015 32 759,800 2024 4] 3,850,000 2029 46 573,200 20351/ 52 (401,000) (2,950,000) -0- -0- (1,732,500) (2,568,000) / salvage values. 5-4 20028 The assumptions in Table 5-2 are somewhat complicated by the need for backup diesel generating capability for the nondiesel options. In the case of Cathedral Falls, for example, the system planned is a run-of-river project. As a consequence, a full diesel generation station must be maintained in a state of readiness. This implies a full work force, a regular maintenance schedule, and one investment rotation. The life of the new machines is considered sufficient to last through the life of the hydroelectric power facility due to reduced operating hours. The schedule for diesel backup investments is included in Table 5-3. The diesel component of the transmission line and wood fired units is estimated based upon reliability of the primary systems. In all three cases, 95 to 99 percent reliability is assumed. This reliability value may appear high, particularly for the wood fired units. However, 8,300 hr/yr is commonly achieved in well designed hog fuel boilers and cogeneration systems owned and operated by the pulp and paper industry. Because of this reduced diesel requirement no investment cycle is required, and diesel operating and maintenance (O&M) costs are largely subsumed into the work crews of the primary units, except in the years 1983 and 1984, when the primary (transmission or wood) units are not operating. In addition to the assumptions presented in Table 5-2, one final economic condition was assumed: the price of power from the Tyee Lake project, delivered to the Tyee-Kake transmission line, was considered to be zero dollars per kilowatt hour. This power is treated as "free" because there is an excess of capacity at the Tyee Lake project and there are no additional costs associated with the production of power sufficient to meet the needs of Kake. For evaluation purposes capital investments are assumed to start in the base year, 1983. This assumption is made for consistency in the economic analysis. It is relaxed in the consideration of optimum timing, presented later in this report. 5.2 PRESENT WORTH OF COSTS AND BENEFIT/COST RATIOS The present worth of costs has been calculated for each option based upon the costs and schedules shown in Tables 5-2 and 5-3. These results are presented in Table 5-4. The detailed calculations are included in Appendix A.4. The present worth of costs provide for a preliminary ranking of options as follows: 1) Underground transmission line; 2) Diesel electric (base case); Overhead transmission line; 3) Wood fired power generation; and 4) Hydroelectric generation. Benefit-cost ratios are presented in Table 5-5. Given the cost estimates and reliability criteria used in this analysis, the underground transmission line appears to be the most economically attractive option. 20028 TABLE 5-4 THE PRESENT WORTH OF COSTS FOR ELECTRICITY SUPPLY OPTIONS FOR KAKE, ALASKA (Values in Millions of 1983 Dollars) Overhead Underground Diesel Transmission Hydroelectric Wood Fired Transmission Base Case Line Power Unit Line Primary Unit 14.6 13.8 8.7 16.9 11.4 Diesel Backup N/A 0.8 9.3 0.8 0.4 Total 14.6 14.6 18.0 17.7 11.8 TABLE 5-5 BENEFIT COST RATIO OF THE ELECTRICITY SUPPLY OPTIONS FOR KAKE, ALASKA Calculation Option (Values in $ million) B/C Ratio Diesel (Base Case) $14.6/$14.6 1.0 Overhead Transmission Line $14.6/$14.6 1.0 Hydroelectric Generation $14.6/$18.0 0.81 Wood Fired Generation $14.6/$17.7 0.82 Underground Transmission Line $14.6/$11.8 1.24 5-6 20028 Given the confidence interval around the cost estimates, the benefit-cost ratio should be at least 1.2 before it is considered significantly different from 1.0; that is, before it clearly favors the transmission line. Similarly, the benefit-cost ratio could be as low as 0.8 before it offers a strong argument in favor or retaining the diesel system. At this level of cost estimation, a benefit-cost cost ratio within the range 0.8 to 1.2 offers no compelling economic reason to choose either the transmission line or the diesel generators. 5.3 SENSITIVITY ANALYSIS The Draft Feasibility Report Supplement included an extensive sensitivity analysis performed for the underground transmission line option. The cases considered are shown on Table 5-6. The capital cost estimate of the underground transmission line project has been reduced slightly since the sensitivity tests were perfomed. The earlier estimate was $8,800,000, while the current estimate of $8,560,000 reflects the cost savings from installing one rather than two submarine cables at each submarine crossings. This change would slightly increase all the benefit-cost ratios shown here. The results of the sensitivity test are shown in Table 5-7. Almost all cases indicate that the underground transmission line option has a benefit-cost ratio of 1.0 or better. Cases presenting a benefit-cost ratio less than 1.2 include several alternatives with low load forecasts and/or low fuel escalation rates. Comparing Alternatives 1.2 and 11.2, for example, indicates that reducing the fuel cost escalation rate from 2.5 percent to 2.0 percent reduced the benefit-cost ratio by one-tenth of a point, from 1.2 to 1.1. Cases presenting a benefit-cost ratio greater than 1.2 include those with a high load forecast and/or a fuel price escalation rate of at least 3.0 percent. Kake Cold Storage is assumed to add at least 650 MWH per year to the Kake load. The benefit-cost ratio is, therefore, a function of one's assumptions about load growth in Kake and the escalation of fossil fuel prices, as well as the capital cost of the projects themselves. This sensitivity analysis indicates that the construction of an underground transmission line is economically favorable, or at worst, neutral. 5.4 TIMING CONSIDERATIONS For the Draft Feasibility Report, an analysis was also made to determine the optimum timing of the overhead Tyee-Kake transmission line, recognizing the marginal nature of its benefit-cost ratio. This analysis was made assuming the most likely energy demand forecast and the higher capital cost estimate reported in the Draft Feasibility Report. 2002B TABLE 5-6 TYEE-KAKE INTERTIE PROJECT ALTERNATIVE - SPECIFIC ASSUMPTIONS FOR SENSITIVITY TESTS Kake Cold Fuel Capital Storage Peak Value of Escalation Cost Base/Alternative Load Forecast Load (MWH/yr) Tyee Power Rate (%) ($000,000) Base 1.0 Most Likely 0 Na 259) 3.3 Alt. 1.1 Most Likely 0 +V/ 2.5 8.8 1.2 Most Likely 0 0 2.5 8.8 1.3 Most Likely 0 + 2.5 9.4 1.4 Most Likely 0 + (a) 8.6 Base 2.0 Most Likely 650 NA 2.5 3.3 Alt. 2.1 Most Likely 650 2 2.5 8.8 252 Most Likely 650 0 2.5 8.8 2.3 Most Likely 650 . 2.5 9.4 2.4 Most Likely 650 + 2.5 8.6 Base 3.0 Low 0 NA a9 3.3 Alt. 3.1 Low 0 + 2.5 8.8 SoZ) Low ) 0 2.5 8.8 Base 4.0 Low 400 NA 25) 3.3 Alt. 4.1 Low 400 + 2.5 8.8 4.2 Low 400 0 25 8.8 Base 5.0 High 0 NA 2.5 3.3 Alt. 5.1 High 0 + 2.5 8.8 5.2 High 0 0 2.5) 8.8 Base 6.0 Most Likely 0 NA 3.0 3.3 Alt. 6.1 Most Likely 0 + 3.0 8.8 Base 7.0 Most Likely 650 NA 3.0 3.3 Alt. 7.1 Most Likely 650 + 3.0 8.8 Base 8.0 High 900 NA 3.0 3.3 Alt. 8.1 High 900 + 3.0 8.8 8.2 High 900 0 3.0 8.8 Base 9.0 Most Likely 400 NA 2.5 3.3 Alt. 9.1 Most Likely 400 + 25 8.8 Base 10.0 Most Likely 900 NA 225) 3.3 Alt. 10,1 Most Likely 900 + 25 8.8 Base 11.0 Most Likely 0 NA 2.0 3.3 Alt. 11.1 Most Likely 0 + 2.0 8.8 Alt. 11.2 Most Likely 0 0 2.0 8.8 Base 12.0 Most Likely 0 NA 1.0 3.3 Alt. 12.1 Most Likely 0 + 1.0 8.8 Alt. 12.2 Most Likely 0 0 1.0 8.8 Base 13.0 Most Likely 0 NA 0.0 303 Alt. 13.1 Most Likely 0 * 0.0 8.8 Alt. 13.2 Most Likely 0 0 0.0 8.8 Base 14.0 High 900 NA 0.0 3.3 Alt. 14.1 High 900 + 0.0 8.8 Alt. 14.2 High 900 0 0.0 8.8 Vv Value of Tyee power is greater than zero beginning in 1991, when the project is assumed to reach full utilization. 5-8 20028 TABLE 5-7 TYEE-KAKE INTERTIE PRESENT WORTH OF COST COMPARISON — we Present Worth of Benefit/ ‘i Cost Cost Alternative Description (million $) Ratio BASE 1.0 Most likely load, without cold storage, $14.6 1.0 2.5% fuel escalation ALT 1.1 Same, with full utilization Tyee Power 12.6 1.2 ALT 1.2 Same, without full utilization 12.2 7.2 ALT 1.3 Same, with full utilization plus higher construction cost 13.4 1.1 ALT 1.4 Same, with full utilization and lower construction cost 12.4 1,2 BASE 2.0 Mostly likely load, with cold storage, 16.8 1.0 at 650, 2.5% fuel escalation ALT 2.1 Same, with full utilization Tyee Power 12.8 1.3 ALT 2.2 Same, without full utilization 12.3 1.4 ALT 2.3 Same, with full utilization plus higher construction cost 13.6 1.2 ALT 2.4 Same, with full utilization and lower construction cost 12.6 1.3 BASE 3.0 Low load, without cold storage, 12.9 1.0 2.5% fuel escalation ALT 3.1 Same, with full utilization Tyee Power 12.6 1.0 ALT 3.2 Same, without full utilization 12,1 1.1 BASE 4.0 Low load, with cold storage @ 400 kw, 14.3 1.0 2.5% fuel escalation ALT 4.1 Same, with full utilization Tyee Power 12.8 1.1 ALT 4.2 Same, without full utilizaton 12.2 1.25 BASE 5,0 High load, without cold storage, 15.6 1.0 5% fuel escalation ALT 5.1 Same, with full utilization, Tyee Power 12.7 1.2 ALT 5.2 Same, without full utilization 12.2 1.3 BASE 6,0 Most likely load, without cold storage, 15.3 1.0 3.0% fuel escalation ALT 6.1 Same, with full utilization Tyee Power 12.7 1.2 BASE 7.0 Most likely load, with cold storage 17.7 1.0 at 650 kW, 3% fuel escalation ALT 7.1 Same, with full utilization Tyee Power 12.8 1.4 BASE 8,0 High load, with cold storage at 900 kW, 18.7 1.0 5% fuel escalation ALT 8,1 Same, with full utilization Tyee Power 13.1 1.4 ALT 8.2 Same, without full utilization 12.4 1.5 BASE 9.0 Most likely load with cold storage 16.0 1.0 at 400 kW, 2,5 fuel escalation ALT 9.1 Same, with full utilization Tyee Power 12.8 Tad BASE 10,0 Most likely load, with cold storage 17.7 1.0 at 900 kW, 2.5% escalation ALT 10.1 Same, with full utilization Tyee Power 12.9 1.4 BASE 11.0 Most likely load, without cold storage, 13.9 1.0 2,0% fuel escalation ALT 11.1 Same, with full utilization Tyee Power 12.6 1.1 ALT 11.2 Same, without full utilization 12.2 1.1 BASE 12.0 Most likely load, without cold storage, 12.7 1.0 1% fuel escalation ALT 12.1 Same, with full utilization Tyee Power 12.6 1.0 ALT 12.2 Same, without full utilization 12.2 1.0 BASE 13.0 Most likely load, without cold storage, 11.8 1.0 constant fuel price ALT 13.1 Same, with full utilization Tyee Power 12.6 9 ALT 13.2 Same, without utilization 12,2 1.0 BASE 14.0 High load with cold storage at 900 kW, 17.3 1.0 constant fuel price ALT 14.1 Same, with full utilization Tyee Power 13.1 1.3 ALT 14.2 Same, without full utilization 12.4 1.4 BASE = Diesel Generators ALT = Underground Transmission Line 5-9 20028 The timing analysis involved delaying the installation of the transmission line by up to 12 years (1995), when it would coincide with replacement of the last existing diesel units. The method used was to calculate the present-worth of costs and benefit-cost ratio for a variety of installation dates. The results indicated that the benefit-cost ratio for the transmission line rises as diesel replacement becomes necessary. As a consequence, the overhead transmission line may be favorably viewed as a replacement for diesel capacity when the existing diesel units are replaced. 5.5 CONCLUSIONS Under the most likely conditions, the lowest cost transmission line is the most economic solution. The underground transmission line appears to be the least expensive transmission line option, although there is still some question regarding its cost and reliability (see Section 4.5.6). If the risks associated with the underground alternative are judged acceptable, the transmission line is the best option for eliminating Kake's dependency on diesel fuel. Constructing a transmission line also appears to be the best option when it is time to replace existing diesel units at Kake. The overhead transmission line alternative would also be economically attractive at that time. Periodic reevaluation of the key elements in the project is recommended because a change in one or more of the assumptions in the economic analysis could affect the feasibility of the project. The most important assumptions influencing the feasibility of the project include: Te Kake Cold Storage will not interconnect with the THREA system. 2. The Kake load will grow at the rate specified in the most likely forecast. ae The existing diesel units do not require immediate replacement. 4. Diesel fuel costs will continue to escalate at 2.5 percent per year. Be The underground transmission line can be installed and reliably maintained for the cost assumed. 5-10 20028 6.0 CONCLUSIONS AND RECOMMENDATIONS Studies conducted in this feasibility analysis concluded that a transmission line is the best alternative for meeting Kake's future energy requirements. This conclusion is based on an economic analysis of a transmission line, hydroelectric, wood-fired power plant, and other generation resources conducted in accordance with the procedures established by the Alaska Power Authority. The decision on whether to proceed with the project also depends on the financial analysis, which will be conducted by the Alaska Power Authority's staff using data included in this feasibility analysis. Although information presented in this report support the finding that a transmission line alternative is the best economic solution to meeting Kake's future energy needs, there are several types of transmission facilities that could be employed. These include an overhead or underground option, or a combination of such facilities. The identification of one recommended type of facility, however, is not as straightforward as might appear. The relative merit of each option depends on one's perception of risk and potential cost savings associated with techniques unproven in Alaska. In general, underground transmission lines appear to offer the potential for being less costly to install and maintain. There is, however, much uncertainty associated with the actual installation and maintenance cost associated with underground cables in the Tyee-Kake Intertie Project area. As discussed in earlier sections of the report, there are reasons to be both optimistic and pessimistic regarding the viability of using underground cables in the project area. Installation difficulties will undoubtedly be encountered in shotrock roads, unroaded areas, and muskeg areas, but whether these difficulties will increase cost or reduce the cable's performance to such an extent that makes the overhead line preferable is not known. In spite of this uncertainty and risk, there is the potential cost savings of reducing the overall project cost by approximately 13 percent if the underground cables could be successfully installed. Moreover, utility experience in other areas suggests that new, high-quality cable can be expected to last for most of the 30-year design life without many failures if it is properly installed. Thus, whether or not one would proceed with the actual installation of underground cable depends on attitude toward risk and potential cost saving involved. Overhead lines can be constructed with a higher level of confidence, both in terms of the installation cost and long-term performance. For this reason, there is relatively little risk associated with installing an overhead transmission line. This reduced risk might justify the added capital cost, depending on one's attitude toward risk. 6362B After evaluating information available on cable performance and installation technique, in light of conditions in the project area, Ebasco recommends that further testing of cable be undertaken before proceeding with underground installation. Testing should be of two types. First, aging tests should be conducted, which would simulate the conditions in the project area. These tests could be conducted in a laboratory setting at an accelerated rate, thereby providing information on cable performance in a six-month to one-year time frame. At least one cable manufacturer indicated interest in designing and testing a cable specifically for the Tyee-Kake Intertie. Second, Ebasco recommends that the Alaska Power Authority install an underground cable at some location in southeast Alaska that approximates the conditions found along the Tyee-Kake Intertie transmission line route. It is recommended that a section at least one mile long be installed, and that the section should ideally include a shotrock road, roaded muskeg areas, and naturally occuring soil material. Ebasco firmly believes that such testing is required before proceeding with the design of an underground facility. In the absence of more definitive information on the cable installation techniques that can be employed in the project area and long-term cable performance in the project area, Ebasco would recommend constructing an overhead transmission line. The findings of the investigations of underground cable alternatives also provided insights into what environments are best suited for underground cable installations. In general, it appears that installing underground cables in unroaded muskeg areas offers the most potential to reduce cost and improve the performance of the facility compared to an overhead line. The major concern in crossing a muskeg area relates to the vehicle transporting the cable and the trenching equipment's ability to traverse the muskeg without being "bogged down." A related concern is the ability of the trenching equipment to cut through or move logs or other debris in the muskeg itself. If a testing program could satisfactorily remove such concerns, installing an underground cable in a muskeg area would be much preferred to installing an overhead line in the same area. Installing an underground cable in a unroaded area also offers potential for cost savings in that clearing can be reduced and the cost of transporting pole, hardware, and conductors into the area could be reduced. If cables can be installed in unroaded areas, using native materials to construct a berm if necessary, substantial cost savings could be experienced. Installing an underground cable in existing logging roads in the project area also appears to be potentially less costly than installing an overhead line. Such savings are not as great as is the case with 6362B muskeg or unroaded installations, however, because installing an overhead line along an existing road can be accomplished efficiently. Moreover, there is a high risk of having angular material in the existing roadbeds cause cable damage. Accepting this risk may not be warranted, given the relatively small difference in cost between jin-road cable installations and overhead transmission line installations adjacent to the roadbed. For the reasons listed above, Ebasco qualifies its regarding the use of underground cable pending the additional physical testing. In general, however, underground installations in unroaded muskeg areas areas offer the best potential cost savings, while recommendation results of Ebasco believes that and other unroaded underground installations in existing Forest Service roads offer the least potential savings. 6-3 63628