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Home My WebLink About1984 Ebasco Grant Lake Hydro Project Detailed Feasibility AnL JR A� --� a m o y jIV M 9 0 Y =; OD p m m' E j,J a y 1D a GRANT LAKE _. f- r�„}„�ASKn. S ( t 7 7}}7 J � (a E� 1 EBAXO ' EBASCO SERVICES 'IWCORPORATED 1 }J_ Y January 1994 t (: �I,1�.SI�iA � � � �TJ �i IT' kl.,kSKA RESGURGIH.-`73 J.S. DEP-7. OF GRANT LAKE HYDROELECTRIC PROJECT DETAILED FEASIBILITY ANALYSIS for the Alaska Power Authority by Ebasco Services Incorporated Bellevue, Washington January, 1984 © 1984 Alaska Power Authority G "73� v, r EXECUTIVE SUMMARY 1.0 PURPOSE The purpose of this Feasibility Report is to: 1) describe the results of the studies conducted from October 1981 through January 1984 of the feasibility of the Grant Lake Hydroelectric Project; 2) define a selected project arrangement for the development of the hydroelectric potential at Grant Lake; 3) provide the engineering, environmental, and economic data required to assess the Project's feasibility; 4) present the results of a pre -feasibility study of the expansion of the existing Cooper Lake Hydroelectric Project; and 5) present the results of a feasibility -level investigation of the upgrading and/or replacement of the Daves Creek -Seward transmission line. The Grant Lake Project has been the subject of several previous studies; however, all previous investigations have lacked site specific data upon which to base a reliable evaluation of the project feasibility. The current study, which includes the required field investigations for evaluation of project feasibility, was authorized by the Alaska Power Authority (Power Authority) in September 1981. 2.0 SCOPE The results of studies performed from October 1981 through February 1982 were presented in an Interim Report (Ebasco, 1982), dated February 1982. The results of studies performed subsequent to the Interim Report are presented in this Feasibility Report, along with a summary of the Interim Report findings. INTERIM REPORT SCOPE The scope of investigations and activities which were performed for the Interim Report include the following: 1 o Performance of field studies at the Grant Lake site, including surveying and mapping, geotechnical, hydrological, and environmental investigations; o = Compilation and revie of existing- 1-iterature and' data; o. Identification of reasonable alternatives for development of the power potential at site; _o--___DeVeJ_opment .of_ a__monthly__streamf l_ow _mo.d.el-.__and ___f_lood o Performance of reservoir operation and power output studies for each alternative arrangement; o Performance of preliminary design and preparation of conceptual layouts of project features for each alternative arrangement; o Assessment of potential environmental impacts associated with each alternative arrangement; o Preparation of comparative conceptual -level estimates of construction cost for each alternative arrangement; o Determination of the annual cost of each alternative and the resulting cost of power; o Comparison of technical, environmental and economic considerations of each alternative and selection of one alternative for further study; o Conduct of meetings and correspondence with resource agencies to coordinate the environmental studies; 2 o Conduct of public meetings in Seward and Moose Pass, Alaska; and o Establishment of 1982 study plan. These studies provided the basis for comparing the technical, environmental, and economic considerations of the alternative schemes for development of the project. Six alternative schemes, called Alternatives A through F, were identified in the study. Alternatives A, B, C, and D use only the inflow to Grant Lake for power generation; Alternatives E and F utilize Grant Lake inflow and flow diverted from Falls Creek. Alternatives A, B, and C include the construction of a main dam at the natural outlet of Grant Lake with a saddle dam across a low divide approximately 1.1 miles north of the main dam. Alternatives D and F utilize the existing lake level and provide for regulation by means of a low level lake tap, thus requiring no dams on Grant Lake. Alternatives D and F (the lake tap alternatives) were found to have the lowest cost of power and the least environmental impacts. On this basis the Power Authority authorized further investigations of Alternatives D and F for the remainder of the feasibility study. In subsequent studies the Falls Creek diversion was dropped due to the high cost per kWh of energy from the diversion. The high cost is due primarily to the length of the diversion and the short operating season of the diversion due to freeze up. FINAL REPORT SCOPE The scope of investigation performed on the lake tap alternatives, which extended from March 1982 to January 1984, include the following: o Execution of 1982 field work program which included additional subsurface geotechnical investigations, surveying and mapping, hydrological data collection and environmental surveys; 3 o Designation of a selected project arrangement for development of hydroelectric potential at Grant Lake based on optimization studies and consideration of environmental impacts and mitigation options; o Performance of reservoir operation and power output studies for the selected project arrangement; o Performance of preliminary design and preparation of conceptual drawings Of of project features__ for- the _selected -project-arrangement; - o Assessment of potential environmental impacts and designation of a mitigation plan for the selected project arrangement; o Preparation of feasibility -level estimates of construction and ---- operation and maintenance costs for the selected project arrangement; o Performance of an economic analysis for the Grant Lake Project, including selection of a recommended generation plan for the City of Seward, and a comparison of the cost of power from the Grant Lake Project with other potential generation sources in the region; o Conduct of meetings and correspondence with resource agencies to coordinate the environmental studies and to establish mitigation alternatives; o Conduct of public meetings in Seward and Moose Pass, Alaska; o Conduct of prefeasibility investigation of the expansion of the existing 15 MW Cooper Lake hydroelectric project; 4 o Performance of a feasibility -level investigation of upgrading and/or reconstruction of the existing 24.9 kV transmission line which extends from the Daves Creek substation to the City of Seward. The results of these studies are presented in this Feasibility Report, which is organized as follows: VOLUME I: PART I - SELECTION OF GENERATION PLAN PART II - COOPER LAKE EXPANSION INVESTIGATION PART III - DAVES CREEK-SEWARD TRANSMISSION LINE INVESTIGATION PART IV - FEASIBILITY ASSESSMENT OF GRANT LAKE HYDROELECTRIC PROJECT VOLUME II: ENVIRONMENTAL REPORT VOLUME III: TECHNICAL APPENDIX 3.0 CONCLUSIONS Based on the results of the studies outlined above, the following conclusions have been reached: 1. The existing Daves Creek -Seward transmission line is inadequate for the existing loads and will become more inadequate as electric power requirements in Seward increase. A new 115 kV transmission line - generally routed along the Seward -Anchorage Highway - should be constructed as soon as possible to upgrade the electrical power supply to Seward to acceptable standards. This transmission line is required regardless of the generation resources required to meet Seward's load. W 2. The present worth cost of the Base Case Plan and four alternative plans for providing forecasted power requirements to the City of Seward from 1983 to 2037 are as follows, assuming a medium load growth scenario over the next 20 years and forecasted marginal prices for natural gas at Sherman Clark's (SC) escalation rates: Total Present Benefit/Cost Plan Worth - Jan 83 Ratio (gas -fired generation) $150,141,000 -- Alternative Plan I-1 (gas -fired generation with the Grant Lake Project) $148,344,000 1.012 Alternative Plan I-2 (gas -fired generation with a portion of the 90 MW Bradley Lake Project) $146,983,000 1.021 Alternative Plan I-3 (gas fired generation with a portion of the 135 MW Bradley lake Project $149,313,000 1.006 i Alternative Plan I-4 (gas fired generation followed by complete reliance on the Susitna Hydroelectric Project) $156,200,000 0.961 i Alternative Plan 1 is also slightly more economical than the Base Case Plan assuming either a high load growth scenario or a low load i growth scenario, with marginal gas prices at SC escalation. 3. The results of the economic analysis indicate that the presence of ' the Grant Lake Project in the generation resource mix serving the i City of Seward would result in a slightly lower cost of power than the Base Case Plan without the project, and regardless of whether a low, medium, or high load growth scenario is realized (assuming forecasted marginal prices for natural gas at SC escalation). 7 4. The present worth of the plan including the Grant Lake Project is slightly higher than the plan including the operation of the 96 MW Bradley Lake Project. The present worth of the plan including the Grant Lake Project is less than the plan including a portion of the 135 MW Bradley Lake Project. The 135 MW Bradley Lake project includes cost of transmission facilities for the Anchorage-Soldotna Intertie. The plan relying on Susitna after its online date is higher in present worth than the Grant Lake Plan. 5. The Grant Lake Project is economically feasible with the outcome of the economic analysis being particularly dependent on the assumptions made for the price of gas and the rate of escalation of that gas. The most recent values for anticipated prices and escalation have been used in the analysis. In addition to the economic benefit, the Grant Lake Project would increase the electric system stability and reliability as the project is located closer to the load center than the major generation sources. The Grant Lake Project would also provide an additional benefit by providing a generation source earlier than the Bradley Lake Project. The timing studies indicate that the earlier the on-line date for the Grant Lake Project the greater the benefit as it allows for earlier displacement of gas fired generation. However, no computations were.performed on a combination alternative consisting of gas fired generation, Grant Lake, and the Bradley Lake Project: 6. The most economical and environmentally attractive alternative identified in the Interim Report for the Grant Lake Project is Alternative D. Diversion of Falls Creek into Grant Lake to increase power production from the Grant Lake Project is uneconomical. 7. The selected project arrangement for the Grant Lake Project consists of a lake tap intake on the west shore of Grant Lake, an inclined tunnel leading to a powerhouse on the east shore of Upper 7 Trail Lake with an installed capacity of 7 MW, an access road and transmission line extending from the powerhouse across the narrows between Upper and Lower Trail Lake to the Seward -Anchorage Highway, an access road to Grant Lake, recreation facilities at Grant Lake, and salmon rearing facilities adjacent to the powerhouse and tailrace. The average annual energy production from the project is 24.94;GWH, as delivered to -the City of Seward. 8. The bid price estimate of construction cost for the Grant Lake Project i-s-$24--713-, 000 _i-n--J-anuary 1-983--do-1 l-ars .--The-earl i-est practical dh-line date for the project is April 1987.= For ease o computation the economic analysis assumes a January 1988 on-line date at the earliest. 9. The environmental impacts associated with the development of the Grant Lake Project are generally insignificant. The primary environmental impact of the Grant Lake Project is foss of the fish habitat in Grant Creek. Although Grant Creek would be dewatered for its full length, only the lower 1/2 mile is currently utilized by fish. An estimated 100 chinook and 500 sockeye salmon adults _would.b.e_lost-annually from-Grant-Creek.--In-addition, habitat for rainbow trout and Dolly Varden would be eliminated. Because of the mitigation measures employed, the Grant Lake Project would not cause a net loss to fisheries resources_ , 10. A prefeasibility investigation of the potential for expanding the energy output of the existing Cooper Lake hydroelectric project shows that, when compared to the cost of energy from gas -fired combined cycle generation, the Stetson Creek diversion would be economical and the Ptarmigan Creek diversion would be marginally economical. The addition of installed capacity of the existing Cooper Lake powerhouse would be uneconomical and unnecessary for development of either of the diversions studied. 8 4.0 RECOMMENDATIONS In view of the above stated conclusions, it is recommended that: 1. The Power Authority proceed with the design and construction of the 115 kV Daves Creek -Seward transmission line. 2. The Power Authority proceed with the development of the Grant Lake Hydroelectric Project in order to displace gas fired generation earlier than can be achieved with the Bradley Lake Project and to provide improved system stability and reliability once Bradley Lake is constructed; 3. An application for a license to construct and operate the Grant Lake Project be prepared and submitted to the Federal Energy Regulatory Commission; 4. Design activities for the Grant Lake Project be commenced in 1984. 7 TABLE OF SIGNIFICANT DATA FOR THE GRANT LAKE HYDROELECTRIC PROJECT HYDROLOGY - -Drainage area, sq Mi - * : 44.1 Avg. annual runoff, cfs/sq. mi, 4.4 Maximum monthly streamflow, cfs 504 Average annual streamflow, cfs 196 Minimum monthly streamflow, cfs 27 PROJECT POWER DATA Avg. annual___gng.rgy---gg�ne-rate-d--.-a.t--p.1-ant,---.GWh-. _25-40 Avg-. annualenergyat load center, GWh 24.9.4 Annual firm energy generated at plant, GWh 18-82 Annual firm energy at load center, GWh 18.48 Dependablecapacityat load center, MW, 6.55 Annual plant factor 0.41 RESERVOIR Normal maximum power pool elevation (msl) 691 Minimum power pool elevation (msl) 660 Reservoir area at normal maximum pool, ac. 1,650 Active storage capacity, A-F 48,000 Highest reservoir level during possible maximum flood (msl) 709 POWER INTAKE Type - Lake tap intake structure with steel trashrack, located 900 ft north of natural outlet of Grant Lake Invert elevation (msl) 643 POWER CONDUIT Type - Horseshoe tunnel excavated in. rock. Shotcrete lining on tunnel sides and crown, and concrete lining on floor Length, ft 3,200 Inside diameter, ft 9 Average shotcrete thickness, inches 3 POWER STATION GENERATING EQUIPMENT Turbine Type - Vertical Shaft Francis Number of units Rated net head, ft 206 in Rated flow, cfs 459 Speed, rpm 400 Runner diameter, in 52 Centerline elevation of spiral case 470 Rated turbine capacity,'best gate, hp 9,580 Generator Type - vertical shaft synchronous with enclosed cooling Generator unit rating, kVa 7,780 STRUCTURE Length 45'-6" Width 40'-011 Height (above plant grade) 50'-0° Generator floor elevation 487.0 TAILRACE CHANNEL Length, ft 640 Bottom width, ft 20 to 100 Maximum velocity, fps 6 TRANSMISSION LINE Type - Wood pole construction Voltage, kV 115 Length, mi 1.2 SITE ACCESS Access Roads Class A - Used to provide permanent access from Seward -Anchorage Highway to powerhouse Length, mi 1.2 Width, ft 24 Maximum grade, percent 8 Class B - used to provide access to gate shaft and recreation area at Grant Lake Length, mi 1.2 Width, ft 18 Maximum grade, percent 8 Bridges: 1 required at narrows between Upper and Lower Trail Lakes: Type - Prestressed concrete Length, ft 140 SITE ACCESS (continued) 1 required across Grant Creek to recreation area: Type - Timber Length, ft 60 11 TABLE OF CONTENTS - VOLUME I EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . 1 TABLE OF SIGNIFICANT DATA FOR GRANT LAKE HYDROELECTRIC PROJECT 10 PART I - SELECTION OF GENERATION PLAN 1.0 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . 1-1 1.1 AUTHORIZATION . . . . . . . . . . . . . . . . . . . . . 1-1 1.2 BACKGROUND TO PRESENT STUDIES . . . . . . . . . . . . . 1-2 2.0 FORECASTED POWER REQUIREMENTS . . . . . . . ... . . . . . . 2-1 2.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . . . 2-1 2.2 KENAI PENINSULA DEMAND AND ENERGY FORECAST . . . . . . 2-2 2.3 SEWARD AREA DEMAND AND ENERGY FORECAST . . . . . . . . 2-3 3.0 GENERATION PLANS IDENTIFIED. . . . . . . . . . . . . . . . . 3-1 3.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . . . 3-1 3.2 BASE CASE PLAN I . . * ' * * ' * * * i * * * ' * * * * 3-3 3.3 GENERATION PLAN WITH GRANT LAKE PROJECT (ALTERNATIVE PLAN I-1) . . . . . * * * * * * * * * ' ' ' 3-6 3.4 GENERATION PLANS WITH BRADLEY LAKE PROJECT (ALTERNATIVE PLANS 1-2 AND 1-3) . . . . . . . . . . . . 3-7 3.5 GENERATION PLAN WITH SUSITNA PROJECT (ALTERNATIVE PLANS 1-4) . . . . . . . . . . . . . . . . 3-8 4.0 EVALUATION OF GENERATION PLANS . . . . . . . . . . . . . . . 4-1 4.1 GENERAL . . . . . . . . . . . . . . . . . * * * * ' * * 4-1 4.2 METHODOLOGY AND ASSUMPTIONS FOR ECONOMIC ANALYSIS . . . 4-1 4.3 DERIVATION OF COST OF PLAN COMPONENTS . . . . . 4-5 4.4 OPTIMUM TIMING FOR GRANT LAKE PROJECT . . . . . 4-16 4.5 RESULTS OF ECONOMIC ANALYSIS . . . . . . . . . . 4-16 4.6 ENVIRONMENTAL EVALUATION . . . . . . . . . . . . . .... 4-19 4.7 SELECTION OF GENERATION PLAN . . . . . . . . . . . . . ��4-22 PART II COOPER LAKE EXPANSION INVESTIGATION 5.0 COOPER LAKE EXPANSION INVESTIGATION . . . . . . . . . . . . 5-1 5.1 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . 5-1 5.2 STETSON AND PTARMIGAN CREEK DIVERSIONS . . . . . . . . 5-2 5.3 COOPER LAKE CAPACITY EXPANSION . . . . . . . . . . . . 5-7 5.4 CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . . 5-8 i TABLE OF CONTENTS - VOLUME 1 (Continued) Paae PART_III -_D.AVES CREEK-SEWARD_ TRANSMISSION LINE INVESTIGATION _ 6.0__DAVES CREEK-SEWARD TRANSMISSION LINE . . . . . . . . . . . . 6-1 6.1 HISTORICAL DATA . . . ... . . . . . . . . . . . . . . . 6-1 - 6.2 ELECTRICAL CONDITIONS . . . . . . . . . . . . . . . . . 6-2 6.3 PHYSICAL CONDITIONS . . . . . . . . . . . . . . . 6-3 7.0 LOAD FORECAST . . . . . 7-1 - -7.1 ___HISTORICAL_DATA . __. : _. 7-1.__.__.. 7.2 RECENT AND .PLANNED DEVELOPMENTS . . . . . . . . . . . . 7-1 7.3 DESIGN LOAD ELECTRICAL PEAK DEMAND. . . . . . . . . . . 7-1 8.0 TRANSMISSION REQUIREMENTS . . . . . . . . . . . . 8-1 8.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . . . 8-1 8.2 SELECTION OF LINE DESIGN . . . . . . . . . . . . . . . 8-1 8.3 PERFORMANCE_ EVALUATION_ OF SELECTED LINE ALTERNATIVE . . _B-8_ I I 8.4 CORRIDOR . . . . . . . . . . . . . . . . . . . . . B-9 8.5 GEOTECHNICAL CONDITIONS . . . . . . . . . . . . . . B-12 8.6 RIGHT-OF-WAY . . . . . . . . . . . . . . . . . . . . . . B-14 8.7 SUBSTATIONS AND SWITCHING STATIONS . . . . . . . . . B-16 8.8 INTERFACE WITH CHUGACH ELECTRIC ASSOCIATION . . . . . . 8-19 9.0 SUBTRANSMISSION REQUIREMENTS_ ..._. ,_ _,_ . .___. _. ._ 9-1 9.1 EXISTING 12.47 KV LOADS FROM CITY OF SEWARD TO MILEPOST 9 . . . . . . . . . . . . 9-1 9.2 EXISTNG 24.9 KV LOADS FROM MILEPOST 9 TO LAWING METERING STATION . .. . . . . . •. . . * . . . . . . . 9-1 9.3 24.9 KV LOADS FROM LAWING METERINGSTATIONTO DAVES CREEK SUBSTATION . . . . . . . . . . . . . . . . 9-1 9.4 SERVICE DURING CONSTRUCTION . . . . . . . . . . . . 9-1 9.5 EMERGENCY OPERATION . . . . . . . . . . . . . . . . . . 9-2 i 10.0 TRANSMISSION LINE COST ESTIMATE.AND SCHEDULE . . . . . 10-1 10.1 COST ESTIMATE . . . . . . . . . . . . . . . . . . . . . 10-1 10.2 OPERATION AND MAINTENANCE COST . . . . . . . . . . . . 10-1 10.3 SCHEDULE . . . . . . . . . . . . . . . . . . . . . . . 10-1 ii TABLE OF CONTENTS - VOLUME 1 (Continued) Page PART IV - FEASIBILITY ASSESSMENT OF GRANT LAKE HYDROELECTRIC PROJECT 11.0 EXISTING SITE CONDITIONS . . . . . . . . . . . . . . . . . . 11-1 11.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . 11-1 11 .2 TOPOGRAPHY . . . . . . . . . . . . . . . . . . . . . . . 11-1 11.3 GEOLOGY . . . . . . . . . . . . . . . . . . . . . . . . 11 -2 12.0 ALTERNATIVE PROJECT ARRANGEMENTS . . . . . . . . . . . . . . 12-1 12.1 EARLY STUDIES . . . . . . ... . . . . . . . . 12-1 12.2 INTERIM REPORT STUDIES . . . . . . . . . . . . . . . . . 12-3 12.3 GENERATION WITH GRANT LAKE INFLOW ONLY - ALTERNATIVES A, B, C, AND D . . . . . . . . . . . . . . 12-4 12.4 DIVERSION OF FALLS CREEK - ALTERNATIVES E AND F . . . . . . . . . . . . . . . . . 12-16 12.5 COMPARATIVE CONSTRUCTION COST ESTIMATES . . . . . . 12-18 13.0 FIELD INVESTIGATIONS . . . . . . . . . . . . . . . . . . . . 13-1 13.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . . . 13-1 13.2 SPECIAL USE PERMITS . . . . . . . . . . . . . . . . . . 13-1 13.3 EXECUTION OF FIELD WORK . . . . . . . . . . . . . . . . 13-2 13.4 SURVEYING AND MAPPING . . . . . . ... . . . . . . . . . 13-2 14.0 GEOTECHNICAL STUDIES . . . . . . . . . . . . . . . . . . . . 14-1 14.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . 14-1 14.2 REGIONAL GEOLOGY . . . . . . . . . . . . . . . . . . . 14-2 14.3 SITE GEOLOGY . . . . . . . . . . . . . . . . . . . . . . 14-5 14.4 ENGINEERING GEOLOGY FOR PROJECT STRUCTURES . . . . . . 14-10 14.5 GEOLOGIC HAZARDS . . . . . . . . . . . . . . . . . . . 14-15 15.0 HYDROLOGICAL STUDIES . . . . . . . . . . . . . . . . . . . . 15-1 15.1 GENERAL . . . . . . . . . . . . . . . . . . . . . . . . 15-1 15.2 EXISTING DATA . . . . . . . . . . . . . . . . . . . . 15-1 15.3 FIELD STUDIES . . . . . . . . . . . . . . . . . . . 15-2 15.4 DEVELOPMENT OF MONTHLY STREAMFLOW MODEL FOR SITE . . . 15-2 15.5 FLOOD HYDROLOGY . . . . . . . . . . . . . . . . . . . . 15-5 i i i 2440B TABLE OF CONTENTS - VOLUME 1 (Continued) Page 16.0 POWER OPERATION STUDIES . . . . . . . . . . . . . . . . . . 16-1 _ 16.1 POWER STUDY OBJECTIVES . . . -.. . . . . . . . . . .. . . . _ 16-1 1 16.2 STUDY METHODOLOGY . . . . . . . . . . . . . . . . . . . 16 -1 _ 16.3 INPUT DATA: _. 16-2 16.4 SUMMARY OF INTERIM REPORT STUDIES . . . . . . . . . . 16-6 16.5 DEIAILED POWER STUDIES PERFORMED FOR LAKE TAP ALTERNATIVES . . . . . . . . . . . . . . . . . . . . . 16 -7 16.6 SELECTION OF OPTIMUM INSTALLED CAPACITY FOR j ALTERNATIVE D . . . . . . 16-9 ! 16.7 EVALUATION OF ECONOMICS OF FAILS CREEK DIVERSION 16-11 17.0 SELECTED PROJECT ARRANGEMENT 17.1 GENERAL . . . . . . . . . . . . . . . . . . . 17.2 RESERVOIR . . . . . . . . . . . . . . . . ... . . . . . 1 7 -2 17.3 INTAKE AND GATE -SHAFT . . . . . . . . . . . . . . . 17-3 17.4 POWER CONDUIT . . . . . . . . . . . . . . . . . . . 1 7 -4 17.5 POWERHOUSE AND TAILRACE . . . . . . . . . 1I-6 17.6 ACCESS ROADS AND BRIDGES . . . . . . . . . . . . . . . 17-8 _- _ 1-7.1-TRANSMISSION- OF POWER . ,___, , _; - ;__ . -- _- , - _, . ,_ _,_ 17 -8 17.8 MITIGATION FACILITIES . . . . . . . . . . . . . . . . . 17-9 17.9 FALLS CREEK DIVERSION WORKS . . . . . . . . . . . . . . 17-10 18.0 PROJECT COSTS AND SCHEDULE . . . . . . . . . . . . . . . . . 18-1 18.1 GENERAL . . . . . . . . . . . . . 18 -1 I 18.2 PROJECT CAPITAL COST. . . . . . . . 18-1 18.3 ANNUAL COSTS . . . . . . . . . . . . . 18-3 18.4 DESIGN AND CONSTRUCTION SCHEDULE. 18-4 18.5 ALTERNATIVE DETAILED COST ESTIMATE. . . . . . . . . . 18-5 19.0 REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . 19-1 VOLUME II - ENVIRONMENTAL REPORT VOLUME III - TECHNICAL APPENDIX I� 1, iv m LIST OF TABLES Table Number Title Page EXECUTIVE SUMMARY - SIGNIFICANT DATA FOR GRANT LAKE HYDROELECTRIC PROJECT 9 PART I - SELECTION OF GENERATION PLAN 2-1 LOAD FORECAST FOR KENAI PENINSULA 2-5 2-2 INDUSTRIAL DEVELOPMENTS AND ASSOCIATED LOADS FOR CITY OF SEWARD 2-6 2-3 LOAD FORECAST FOR CITY OF SEWARD 2-7 3-1 EXISTING GENERATION RESOURCES ON KENAI PENINSULA 3-10 3-2 DETERMINATION OF CONSTANT RESERVE REQUIREMENT ALLOCATION TO THE CITY OF SEWARD 3-11 3-3 DETERMINATION OF BRADLEY LAKE ALLOCATION TO CITY OF SEWARD FOR USE IN ECONOMIC ANALYSIS - 3-12 4-1 SUMMARY OF ECONOMIC ANALYSIS USING 20 YEAR PLANS 4-24 4-2 SUMMARY OF ECONOMIC ANALYSIS FOR GRANT LAKE EQUIVALENT OPTIONS 4-25 4-3 FORECASTED PRICE OF COOK INLET GAS FOR USE IN ECONOMIC ANALYSIS 4-26 4-4 COMPUTATION OF INTEREST DURING CONSTRUCTION FOR GRANT LAKE HYDROELECTRIC PROJECT 4-27 4-5 OPTIMUM TIMING ANALYSIS FOR GRANT LAKE PROJECT 4-28 PART II - COOPER LAKE EXPANSION INVESTIGATION 5-1 STETSON CREEK DIVERSION - PREFEASIBILITY LEVEL COST ESTIMATE SUMMARY 5-9 5-2 PTARMIGAN CREEK DIVERSION - PREFEASIBILITY LEVEL COST ESTIMATE SUMMARY 5-10 PART III - DAVES CREEK - SEWARD TRANSMISSION LINE INVESTIGATION 10-1 COST ESTIMATE FOR DAVES CREEK - SEWARD TRANSMISSION SYSTEM - 115 KV 10-2 10-2 COST ESTIMATE FOR DAVES CREEK - SEWARD TRANSMISSION SYSTEM - 115 KV - DETAILS 10-3 v 2440B LIST OF TABLES (Continued) Table { Number Title Page PART IV - FEASIBILITY ASSESSMENT OF GRANT LAKE HYDROELECTRIC PROJECT 12-1 ESTIMATE OF CONSTRUCTION COSTS FOR ALTERNATIVE PROJECT ARRANGEMENTS 12-21 12-2 COMPARISON OF COST OF `ENERGY FROM ALTERNATIVES - 12-22 14-1 SUMMARY OF PERMEABILITY TESTS 14-22 14-2 CHARACTERISTICS*OF SEISMIC SOURCES 14-23 15-1 MONTHLY INFLOWS FOR GRANT LAKE 15-12 15-2 COMPARISON OF 1982 GRANT CREEK FLOWS WITH LONG TERM - --- AVERAGE_FLOWS. ----- ----- --. _.--- -- ._ - -----_.-_ __- - - _ __ -- - 15-1-3 _ . - 15-3 FALLS CREEK/GRANT CREEK MONTHLY STREAMFLOW RATIOS 15-14 15-4 GRANT LAKE PROBABLE MAXIMUM STORM, 6-HOUR PRECIPITATION I AND TEMPERATURE VALUES 15-15 16-1 DISTRIBUTION OF MONTHLY ENERGY CONSUMPTION FOR ANCHORAGE/ i COOK_ INLET__ AREA AND CITY OF._SEWARD _ ___ _ 16-1.5 16-2 SUMMARY OF RESULTS OF POWER STUDIES PERFORMED FOR INTERIM REPORT 16-16 16-3 SUMMARY OF RESULTS OF POWER STUDIES PERFORMED FOR OPTIMIZATION OF LAKE TAP ALTERNATIVE 16-17 16-4 DETERMINATION OF OPTIMUM INSTALLED CAPACITY FOR ALTERNATIVE D 16-18 16-5 COMPARISON OF ECONOMICS OF LAKE TAP ALTERNATIVE WITH AND WITHOUT FALLS CREEK DIVERSION 16-19 18-1 SELECTED PROJECT ARRANGEMENT SUMMARY OF PROJECT CAPITAL COST 18-6 18-2 SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST 18-7 18-3 ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST 18-14 vi 2440B LIST OF FIGURES Figure Number Title Page I-1 ANNUAL LOAD DURATION CURVE FOR THE ANCHORAGE AREAS 4-29 II-1 COOPER LAKE ALTERNATIVES - STETSON AND PTARMIGAN CREEK DIVERSIONS 5-11 III-1 ONE -LINE DIAGRAM 10-8 III-2 PLAN - SEWARD TO MILEPOST 12, SHEET 1 10-9 III-2 PLAN - MILEPOST 13 TO MILEPOST 25, SHEET 2 10-10 III-2 PLAN - MILEPOST 26 TO DAVES CREEK SUB., SHEET 3 10-11 III-2 PLAN.- SEWARD TO MARINE - INDUSTRIAL PARK (WITH ELEVATION VIEWS), SHEET 4 10-12 III-3 TRANSMISSION LINE PROJECT SCHEDULE 10-13 IV-1 PROJECT LOCATION MAP 19-4 IV-2 GENERAL PROJECT AREA 19-5 IV-3 ALTERNATIVE PROJECT ARRANGEMENTS 19-6 IV-4 ALTERNATIVE A - GENERAL PROJECT ARRANGEMENT 19-7 IV-5 ALTERNATIVE B - GENERAL PROJECT ARRANGEMENT 19-8 IV-6 ALTERNATIVE C - GENERAL PROJECT ARRANGEMENT 19-9 IV-7 ALTERNATIVE D - GENERAL PROJECT ARRANGEMENT 19-10 IV-8 BORING PLOT PLAN 19-11 IV-9 DEPTH TO BEDROCK POWERHOUSE COVE 19-12 IV-10 REGIONAL GEOLOGIC MAP OF THE PROJECT AREA 19-13 IV-11 GEOLOGIC MAP ALONG TUNNEL ALIGNMENT SECTION 19-14 IV-12 TUNNEL - INTERPRETIVE GEOLOGIC CROSS SECTION 19-15 IV-13 CUMULATIVE DISTRIBUTION OF RQD VALUES, BOREHOLES DH-3, DH-4 AND DH-5 19 -16 IV-14 'GRANT LAKE AREA - CAPACITY CURVES 19-17 vii LIST OF FIGURES Figure Number Title Page ' / - IV-15 FLOOD HYDROLOGY AND NATURAL OUTLET RATING CURVE 19-18 IV-16 _MONTHLY 3TQ[AMFLOWDI3TRIBUTION _`_ / ' ^ ' REGULATION � ' �� — 19-19 - IV-17 SELECTED PROJECT ARRANGEMENT SITE PLAN 19-20 | ` IV-lB POWER CONDUIT PLAN AND PROFILE 19-21 IV-19 GRANT LAKE CHANNEL EXCAVATION 19-22 { i -� ------------------_r�--�-�-�-�-- �'--��-_---��-�_'��----------------------\ - IV-21 POWERHOUSE AREA PLAN AND PROFILE 19-24 ' IV-22 POWERHOUSE PLANS AND SECTIONS 19-25 IV-23 POWERHOUSE MAIN ONE LINE DIAGRAM 19-28 IV-24 ACCESS ROADS - TYPICAL SECTIONS 19-27 / IV-25 FALLS CREEK DIVERSION WORKS - PLAN AND PROFILE 19-28 IV-26 FALLS CREEK DIVERSION DAM 19-29 ` IV-27 PROJECT SCHEDULE ` 19-30 ' 244OB f PART t SELECTION F GENERATION PLAN 1.0 INTRODUCTION 1.1 AUTHORIZATION In August, 1981, Ebasco Services Incorporated (Ebasco) submitted a proposal to the Alaska Power Authority (Power Authority) to perform a detailed feasibility analysis and prepare a FERC License Application for the Grant Lake Hydroelectric Project. The proposal was accepted by the Power Authority and a contract for engineering services for the study was executed in September 1981. An Interim Report (Ebasco, 1982) was submitted in February 1982 in accordance with the terms of the contract and with discussions with the Power Authority. The Interim Report compared the reasonable alternative schemes for development of the project, recommended one alternative for further study and described the results of the field studies conducted to that time. The comparison of alternatives in the preliminary studies permitted the subsequent field studies to be designed specifically for the project arrangement selected for further study. This feasibility report of the Grant Lake Hydroelectric Project describes the field studies that were conducted to investigate the feasibility of the project and presents the results of these field and office studies, in accordance with the terms of the contract and the discussions with the Power Authority which have occurred during the course of the study. Two modifications to the scope of work were executed during the study period. The first modified the field study program to more specifically apply to the project alternatives recommended for further investigation in the Interim Report. The second modification added a review of the potential for expansion of the existing Cooper Lake Hydroelectric Project, an investigation of the need for and cost of upgrading and/or replacing the existing transmission line serving the City of Seward, and provided for additional environmental studies if required. The changes to the scope of work in the second modification to the contract resulted from concerns expressed by the City of Seward over their future power supply. 1-1 2675B 1.2 BACKGROUND TO PRESENT STUDIES The earliest published investigation of the project area is a geologic report and map of the Kenai Peninsula by Martin et al. in 1915. More detailed studies were performed in the early to mid 1950s, with the topographic mapping of Grant Lake and Grant Creek by Giles, the publicationof a_preliminary study of._a_proposed hydroelectric development at Grant Lake by R.W. Beck and Associates (Beck, 1954), the ` publication of the results of geologic investigations at the site by the U.S. Geological Survey, and finally, the filing of an.Application to the Federal Power Commission for a Preliminary Permitforthe project by Chugach _Electric Association in 1959. The above studies did not result; in the construction of the project, probably due to the low cost of energy from alternative sources during this period. - _ I After a period of intermittent interest in the development of the project, there has been a recent (late 1970's) increase in interest resulti-ng--from the--energy--shortage--and--the major- upset -in -the --price- of - fossil fuels, notably petroleum products. The most recent studies have been a Reconnaissance Study of Hydroelectric Power Alternatives for the City of Seward, Alaska (CH2M-Hill, 1979) and a Feasibility Assessment of Hydropower Development at Grant Lake (CH2M Hill,.1980). The latter report contains an assessment of the cost of power from alternative sources and a review of alternative hydroelectric projects that were available to meet the projected needs of Seward. This essentially was an office study and did not include any field investigations of either a geotechnical or environmental nature. Reconnaissance level investigations were performed on several development alternatives. These included. -development of Crescent Lake, Grant Lake, Ptarmigan Lake and a combination development of Grant Lake and Ptarmigan Lake (see Figure IV-1). Based on environmental and economic considerations, Grant Lake plus the diversion of nearby Falls Creek into Grant Lake was selected as the most economical and environmentally acceptable. It was concluded that the Grant Lake project showed sufficient feasibility to justify undertaking more detailed feasibility investigations. j 1-2 2675B The Power Authority has accepted the 1980 CH2M Hill report as adequate to meet its needs for a reconnaissance -level evaluation of alternative energy sources for the City of Seward. The Power Authority's focus.in the present study is on the development of the Grant Lake project to meet the need for power on the Kenai Peninsula in conjunction with other proposed resource developments and to specifically evaluate the development of the project to meet the future power requirements of the City of Seward. The study is a detailed feasibility investigation of the project, including subsurface geotechnical and environmental investigations, surveying and mapping, and hydrological data collection in the project area. The studies are of sufficient detail to support an application for a license to the FERC should the Power Authority proceed with the project. 1-3 2675B 2.0 FORECASTED POWER REQUIREMENTS 2.1 GENERAL The Power Authority project evaluation procedure compares the total present worth cost of a base case plan to the total present worth cost of one or more alternative plans for meeting a forecasted requirement for power in a specific area for a given planning period. One or more of the alternative plans will include the proposed new generation project under consideration. The plan having the lowest total present worth cost is the most economic plan under this procedure. Two key elements in this procedure are the electrical demand and energy forecast for the area and the definition of the area to be considered for utilization of the proposed new generation resource. In determining the area to be served and the electrical load forecast to be used in the economic feasibility studies for the Grant Lake project, it was recognized that the project is located only 25 miles from the City of Seward load center and that Seward is the southern terminus of a developing interconnected electric system encompassing the entire Railbelt area. Located throughout the Railbelt are a number of existing and proposed electrical generating plants and load centers. In discussions with the Power Authority, it was decided that the economic evaluation of the Grant Lake Project should be based on comparison of a base case plan and alternative plans for meeting the forecasted power requirements for the City of Seward. It was also decided that a second type of economic evaluation would be.included which involves a regional comparison of the cost of power from the Grant Lake Project with other generating resources being considered to serve the Anchorage -Cook Inlet area, particularly those serving the Kenai Peninsula. This regional comparison, however, did not require a load forecast, since the analysis involves only a comparison of the cost of power from several proposed generation resources. 2-1 2676B i 2.2 KENAI PENINSULA DEMAND AND ENERGY FORECAST A number of forecasts of the power requirements for the Kenai Peninsula have been made. In 1980, a load forecast of utility requirements for the Railbelt was prepared by the University of Alaska's Institute of - Social and--Economic--Research-(ISER,-1980), which--included--a forecast for the Kenai Peninsula. The ISER forecast was utilized, with some modifications, in the Bradley Lake Project Power Market Report (Alaska Power Administration, 1982) and the Kenai Peninsula Power Supply and Transmission Study (Beck, June 1982). The most comprehensive recent forecast is contained in the Railbelt ElectricPowerAlternatives Study: Evaluation of Railbelt Electric E-nergy'Plans (Battelle, 1982). The forecast incorporated a number of population projections and economic scenari-os for both the public and f private sectors. The Supplement - Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982) used the low economic -- - scenario,-P-l:an--1-A--fr-om the --Battelle -report,--to-r-e-eval-uate the--- ----- - - - alternative plans ,for power generation and transmission facilities for the Kenai Peninsula. The Battelle forecast was modified in the Beck report to incorporate a portion of potential military and industry I power requirements that are currently met by military and industrial generation facilities. The energy forecast is of utility sales only and, therefore, does not include utility usage -and -losses. In i addition, the Beck report separated the combined Greater Anchorage -Cook Inlet load in the Battelle report into separate forecasts for the j Greater Anchorage and the Kenai Peninsula areas. The Beck power supply l study also assumed a requirement for reserves for the Railbelt region of 200 MW, based on the coincidental outage of the two largest generation units in the Anchorage area. The load forecast for the Kenai Peninsula, including the modifications and adjustments made in the Beck study, is used.herein as a basis for allocation of the required resources, including reserves for the Kenai Peninsula to the City of Seward in the economic analysis in the subsequent sections of this report. Utilization of this load forecast 2-2 2676B was made in accordance with discussions with the Power Authority, and it is considered to be the most applicable available forecast of power requirements for the Kenai Peninsula. This load forecast demand for the Kenai Peninsula is shown on Table 2-1. 2.3 SEWARD AREA DEMAND AND ENERGY FORECAST For the past 25 years, the City of Seward has obtained its power by purchase from Chugach Electric Association via a 24.9 kV transmission line from a 115/24.9 kV substation at Daves Creek, some 48 miles north of the City. Peak demand for the City occurred in 1979 at 6.7 MW, as reported in Analysis of Voltage Drop and Energy Losses, (Dwane Legg Associates, 1982); however, recent years have shown a lower, but steadily growing power demand. Peak demand grew at an average annual rate in excess of 10 percent per year from 1967 to 1980. Since 1980, demand has grown at a lower rate. Likewise, the maximum annual energy requirement has experienceda steady growth with 25 Gwh consumed in 1981. Current developments in the Seward area, primarily a marine -industrial park on the east side of Resurrection Bay near the Fourth of July Creek, developments in and near the small boat harbor, and infrastructure to support these developments, could result in substantial increase in the power requirements in the next few years. No adequate load forecast for a 20 year planning period was found to exist for the City of Seward Electric System. In the Kenai Peninsula Power Supply and Transmission Study (Beck, June 1982), a forecast for Seward is developed based on Seward's historical share of the total power requirements for the Kenai Peninsula. This forecast, which is based on a forecast prepared in June 1980 by the University of Alaska, Institute of Social and Economic Research, does not consider the potential for larger incremental growth in Seward resulting from the current industrial developments nor does it reflect the decrease in the rate of growth experienced subsequent to its formulation. Table 2-2 shows the industrial developments which are either currently under construction or are planned for construction in the near future. 2-3 2676E A forecast for the City was, therefore, developed for use in the Grant Lake feasibility study which utilizes the most recent (1981 and 1982) historical data and future rates of growth equal to those used in the Supplement — Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982). As noted above, this forecast was developed from the low economic scenario, Plan lA -in the-Railbelt Electric- Power - -- Alternatives Study: Evaluation of Railbelt Electric Energy Plans (Battelle, 1982). Three load forecasts were prepared, which are shown on Table 2-3. The low demand forecast was developed by using historical data from Seward for 1981 and.1982 for demand, and then applying the same rates of growth to demand for years 1983-2001 as were used in the Supplement Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982). The low demand forecast assumes no incremental growth in power requirements from the planned industrial developments in Seward. The low energy forecast also has the same growth rate for 1983 to 2001 as shown -in -the December 1982 -Beck study. -The-medium demand forecast - ----- assumes those projects under construction will be completed and one half of those projected to be built will add a load increment to the system in 1983 and 1984, with the growth rate from 1985-2001 the same. for the low forecast. The high demand forecast assumes all those industrial projects currently under construction and all projected industrial projects will add a load increment to the system in 1983 and 1984 with the growth rate from 1985 — 2001, the same as for the low forecast. In other words, for all three forecasts, loads beyond 1984 were assumed to grow at the average annual rates of growth projected in the December 1982 Beck study for the entire Kenai Peninsula. It was agreed with the Power Authority that the economic evaluation of the Grant Lake Project will be conducted using the medium growth forecast developed herein, and the low and high growth forecasts will be used to. evaluate the sensitivity of the analysis to varying rates of growth. 2-4 2676E TABLE 2-1 LOAD FORECAST FOR KENAI PENINSULA1/ Peak Demand Energy Year (MW) (GWH) 1983 82 397 1984 84 408 1985 86 419 1986 89 433 1987 92 447 1988 94 462 1989 97 476 1990 100 490 1991 102 499 1992 104 508 1993 106 517 1994 108 526 1995 110 535 1996 ill 542 1997 112 549 1998 114 555 1999 115 562 2000 116 568 2001 119 581 2002 1222� 5942/ 1/ For years 1983-2001, load forecast is obtained from Supplement to Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982). 2/ Load growth from 2001 to 2002 is assumed to be the same as from 2000 to 2001. 2-5 2676B TABLE 2-2 INDUSTRIAL DEVELOPMENTS AND ASSOCIATED LOADS FOR CITY OF SEWARDY , Peak Load Year lype-of Development (MW)_ 1983 State Grain Terminal (In Construction) 1.0 AVTEC CenterZ/ (In Construction) .75 Fourth of July Shiplift (In Construction) 1.20 Fourth of July Industrial Development (Projected) 2.0 Infrastructure - Residential and Light Commercial (Projected) 2.0 i Total in Construction = 2.95 MW { Total Projected = 4.0 MW 1984 Gateway -Subdivision (Scheduled for 1983 construction season) 1.5. Fourth of July Industrial Development (Projected) 6.0 Infrastructure - Residential and Light Commercial (Projected) 3.0 i4 Total Projected = 10.5 MW All data obtained from the City of Seward. Alaska Vocational Technical Education Center. 2-6 2676B TABLE 2-3 LOAD FORECAST FOR CITY OF 3EWARD Peak Demand (MW) Energy (GWH) Year /~^l/ Medj^mV High;!/ /~^4/ Medium-5/ HjRh5/ 1981Y 5.2 5.2 5.2 27.1 27'1 27.1 l98�==�� 5.7 5,7 5,7 29.1 29,1 29.1 1983 5'9 9,8 11,1 29.9 48.7 50,3 1984 8'0 13.8 20.4 30.7 70.8 104,4 1985 6'2 14,2 21,0 31'5 72'5 107'2 1988 8'4 14.6 21.6 32'5 74'8 110'7 1987 6'0 15.1 22'3 33.6 77.2 114-2 1988 6.8 15'8 23,0 34'6 79.7 117'9 1989 7.0 18'0 23,7 35'8 82.2 121'6 1990 7,2 16,5 24,5 36,9 84'9 125'5 1991 7.4 16.9 24'9 37'6 88,4 127'8 1992 7'5 17.2 25,4 38-2 88.0 130'1 1993 7.7 17'5 25'9 38.9 09.5 132.4 1994 7.8 17.8 26.4 39-6 91'2 134.8 1995 7'9 18,2 26.9 40,3 92,8 137.3 1996 8'0 18'4 27'2 40.8 93.9 138.9 1997 8-1 18'6 27.5 41,3 95.0 140,8 1998 8,2 18.8 27.8 41'8 06.2 142'3 1999 8'3 19.0 28,1 42.3 97.3 144,0 2000 8.4 18'2 28,4 42.8 98.5 145,7 2001 8.6 19'7 29.1 43.8 ]O0.8 149'0 2002 8.8 20.2 29,9 44'8 103.1 152'5 Low forecast assumes no load growth from industrial development I/ (both under construction and planned) in Seward area as shown on Table 2-2. This forecast has the Danm growth rates as that shown in the Supplement - Kenai Peninsula Power Supply and Transmission Study (Beck, December 1902), except that 1981 and 1982 show actual historical data. 2/ Medium forecast assumes all industrial projects in Seward area which are currently under construction Will be completed and one-half of the planned industrial projects will be completed (see Table 2-2 for list of industrial projects and associated loads). 2-7 2578B TABLE 2-3 (Continued) LOAD FORECAST FOR CITY OF SEWARD Footnotes (Continued) 3� High forecast assumes all industrial projects currently under construe-tion in--the-Seward--area will,be completed -and all-pl-anned projects -will - also be completed (see Table 2-2 for list of industrial projects) 4� Low energy forecast has the same growth .rate as that shown in Supplement - Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982), except that the energy for 1981 and 1982 has been adjusted for the difference in peak demand in the Beck forecast and the actual historical peak loads from the Citv. For the medium and high energy fo ecasts for the years 1983 and 1984, the energy required is estimated by using the same load - factors as used in the low forecast for these years. For the years beyond 1984, the medium and high forecasts have grown at the energy growth rates given in the Supplement- Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982). 6� Peak demand values are historical data for City of Seward. 2-8 2676E 3.0 GENERATION PLANS IDENTIFIED 3.1 GENERAL Five generation plans have been identified which would satisfy the forecasted energy and demand requirements for the next 20 years for the City of Seward. After 20 years the demand and energy are assumed to remain constant until 2037, the end of the Grant Lake Project economic life. These plans include: 1) a Base Case Plan which involves continued use of existing simple cycle and new combined cycle natural gas -fired generation units on the Kenai Peninsula with no new hydroelectric project included, referred to herein as Base Case Plan I; 2) an alternative plan that includes the proposed Grant Lake Hydroelectric Project with the remaining power requirements being provided by existing and new gas -fired generation facilities, referred to herein as Alternative Plan I-1; 3) an alternative plan that includes a portion of the proposed 90 MW Bradley Lake Hydroelectric Project, with the remaining power requirements being provided by existing and new gas -fired generation units, referred to herein as Alternative Plan I-2; 4) an alternative plan that includes a portion of the alternative 135 MW Bradley Lake Hydroelectric Project and the Anchorage Soldotna Intertie, with the remaining power requirements being provided by existing and new gas -fired generation units, referred to herein as Alternative Plan I-3; and 3-1 5605B 5) an alternative plan that includes a portion of the Sustina Project with the pre 1993 power requirements being provided by existing and new gas -fired generation units, referred to herein as Alternative Plan I-4. The evaluation__ period for each_of the plans begins in 1983 and extends for 55 years through -2037, -since the economic -life of --the -proposed, Grant Lake Hydroelectric Project is 50 years and the optimum timing for bringing the project on line is January 1988 (5 years from January 1983). Each of the plans are described in more detail below and the economic comparison of the plan is shown in Section 4.0. In addition to the five basic plans for meeting the entire projected needs for the City of Seward, five direct comparisons with the Grant Lake capacity and energy output were made. Each direct comparison plan would provide 24.94 GWh of net energy to Seward. Furthermore, using capacity adjustments based on equivalent thermal capacity, each direct comparison -is equal to providing 6.5.5_MW of capacity to Seward. The designation for these alternatives is distinguished from the detailed 20 year plan studies by preceding each alternative with the Roman numeral "II". In summary the five direct comparison alternatives include.: 1) new combine cycle combustion turbines, herein referred to as Base Case Plan II; 2) the Grant Lake Hydroelectric Project, herein referred to as Alternative Plan II-1; a) the 90 MW Bradley Lake Project with an appropriate capacity adjustment factor; 5605E 3-2 4) the 135 MW Bradley Lake Project and Anchorage-Soldotna Intertie with an appropriate capacity adjustment factor, and 5) the Susitna Hydroelectric Project based on cost of energy with an appropriate capacity adjustment factor. 3.2 BASE CASE PLAN I. The Base Case Plan I was developed to identify the most economical means of meeting Seward's need for power, assuming the Grant Lake project was not built. Based on discussions with the Power Authority, the Base Case Plan I was defined as a combination of existing and new natural gas -fired generation facilities located on the Kenai Peninsula which is comparable to a continuation of existing means of providing power. Although the purpose of the Base Case Plan I is to address Seward's requirements, the Plan begins with a development of loads and resources for the Kenai Peninsula (as do Alternative Plans I-1 and I-2). This approach is required to provide a basis for assigning portions of new plant costs, plant retirements, and reserve requirements to the Seward market area since the basic data from which the comparsion data is taken is based on meeting the entire Kenai load. The Base Case Plan I is comprised of the following three components: Component 1 New combined -cycle combustion turbine units on the Kenai Peninsula (in the Kenai-Nikiski area) for satisfying new capacity addition requirements. All new capacity additions in the Base Case Plan I will be provided by new combined -cycle combustion turbine units because these units are considered to be the most economical form of new thermal generation. 3-3 Component 2 Continued used of gas —fired generation from the existing Component 3 simple cycle combustion turbines at Bernice Lake on the Kenai Peninsula until the units are retired. These existing generation resources are listed on Table-3-1 No new simple cycle combustion turbine units are assumed to be built to satisfy required capacity additions, as simple cycle combustion turbines are not as economical as new combined —cycle combustion turbine units. The last existing simple cycle combustion turbine unit is retired in the year 2002. The proposed Daves Creek -Seward 115 kV transmission line. The Daves Creek —Seward transmission line is a nongeneration component of the Base Case Plan I which has been included because several studies, City of Seward Electrical -System-Planning -System--(CH 2 M H11-1,- -August -- - - 1979), and the Analysis of Voltage Drop and Energy Loses (Duane Legg Associates, October 1982), have indicated that the existing 24.9 kV transmission line that extends from the Daves Creek substation to the Seward substation will have to be replaced, and that it is cost effective to replace the line with a new 115 kV transmission line as soon as possible. A feasibility -level assessment of the upgrading and replacement of the Daves Creek —Seward I_ transmission line is provided in Part III of this report. (� The existing 5.5 MW of diesel capacity owned and operated by the City of ;Seward is not included in the Base Case Plan I or any of the alternative plans because the cost to operate these units is greater than the cost of providing generation from either simple cycle or combined —cycle gas —fired turbines. Furthermore, the diesel generators are old and are not even considered appropriate for meeting Seward's reserve requirements. Also, as a simplifying assumption, the City's Mount Marathon 150 kW hydro project, and Chugach Electric Association's 15 MW Cooper Lake Hydroelectric Project were not included in the existing resource mix serving Seward. 3-4 The demand and energy forecasts for the Kenai Peninsula and for the City of Seward which are used in the Base Case Plan I and alternative plans are described in Section 2.0 of this report. The load forecast used for the Kenai Peninsula was obtained from the Supplement - Kenai Peninsula Power Supply and Transmission Study (Beck, December 1982). The load forecast used for Seward in the Base Case Plan I is the medium growth scenario described above in Section 2.0, with sensitivity analyses being performed using the high and low growth scenarios. The assignment of reserve requirements to the Kenai Peninsula is based on taking the 200 MW reserves used in the Beck report for the entire Railbelt region and proportioning that total amount by the average ratio of the Kenai Peninsula load to the Railbelt load for each year of the 55 year evaluation period. The 200 MW reserve requirement is based on the coincidental outage of the two largest generation units in Anchorage. As the Railbelt becomes more fully and reliably interconnected, reserve requirements may become lower. However, the 200 MW value was considered appropriate for purposes of proportioning reserve requirements for the Kenai Peninsula and the City of Seward in this study. Based on the proportioning procedures described above, the resulting constant reserve requirement for the Kenai Peninsula is 28.1 MW. Seward's share of the Kenai Peninsula reserve requirements is based on the average ratio of the Seward load to the Kenai Peninsula peak load over the 55 year evaluation period and was calculated to be a constant 4.6 MW. The derivation of these reserve requirements is shown on Table 3-2. These values are also used in Alternative Plans I in the economic analysis.. In all plans, reserve requirements are met by simple cycle generation units from 1983 through 1987, and from 1988 on, reserves are met with new combined cycle units. The procedure for sizing new combined -cycle units was to add capacity in approximately 25 MW increments in a manner such that a deficit never occurs, while at the same time minimizing the occurrence of surplus capacity to less than 25 MW, for the Kenai Peninsula. The last unit is added such that a zero surplus exists from 2002 through 2037. Seward's 3-5 • 1 _ capital cost for new combined -cycle generation facilities is computed on $/kW basis, with the assumption that Seward will be paying for a portion of a larger, new plant located in the Kenai-Nikiski area. The estimated costs for both simple and combined -cycle units, and a tabulation of capacity additions and retirements for the Base Case Plan I are provided in -Part I -I -I -of the -Technical Appendix, 3.3 GENERATION PLAN WITH GRANT LAKE PROJECT (ALTERNATIVE PLAN I-1) The generation plan with the Grant Lake Project assumes that a 7,000 kW hydroelectric project at Grant Lake will come on-line in early January 1-988.- As discussed in Section_16.0, optimization studies performed for the project determined that net benefits were maximized at an installed capacity of 7,000 kW, where the value of the benefits was based on the cost of providing alternative gas -fired generation facilities. As indicated in Section 4.4, a project timing analysis showed that the i optimum on-line date is 1988. In the generation plan with the Grant Lake Project, power from the hydroelectric project is assumed to displace energy and capacity that would otherwise be generated from gas -fired units included in the Base Case Plan I. The available dependable capacity from the Grant Lake Project is assumed to displace the need for adding the same amount 'of new combined -cycle capacity. Details of the procedure for allocation I of energy generation between the Grant Lake Project and gas -fired units are provided in Section 4.3.9. Alternative Plan I-1, then, is comprised of the following components (it should be noted that the numerical order of the components in this and the following plan descriptions are arbitrary and bear no relationship to the"priority which may exist for the actual development and construction of any component): 3-6 5605B Component 1 The 7 MW Grant Lake Project, with an on-line date of January 1988. Component 2 New combined -cycle combustion units on the Kenai Peninsula for satisfying capacity requirements which cannot be met by existing units and the Grant Lake Project. Component 3 Continued use of gas -fired generation from existing . simple -cycle combustion turbines as described above for the Base Case Plan I. Component 4 Daves Creek -Seward 115 kV transmission line (non -generation component). 3.4 GENERATION PLAN WITH BRADLEY LAKE PROJECT (ALTERNATIVE PLANS I-2 AND I-3) Two alternative generation plans were developed that includes a portion of the proposed Bradley Lake Hydroelectric Project, which is located on the Kenai Peninsula and is being evaluated by the Power Authority. Costs and information on Bradley Lake were taken from the Bradley Lake Hydroelectric Power Project Feasibility Study, published in October of 1983 by Stone & Webster for the Alaska Power Authority. The purpose of this plan is to show the effect on the economics of Grant Lake of including a portion of a large scale hydro project in the resource mix for Seward. This plan is the same as the Base Case Plan I except that a portion of the Bradley Lake Project at two different levels of development is added to the resource mix serving the City of Seward. The portion of Bradley Lake which would be allocated to the City of Seward has not been designated by the Power Authority. For the purpose of this study the portion of the project to be assigned to Seward was determined by taking the average ratio of Seward's peak load to the combined peak load for the Greater Anchorage area and the Kenai Peninsula area. The analysis assumes that the installed capacity of 3-7 5605E Bradley Lake will be 90 MW and 135 MW for the respective case. The projected project on-line date of October 1988 has been rounded back to January 1988 for ease of direct economic comparison with the Grant Lake Project. The resulting portion of Bradley Lake capacity that goes to Seward is 4.02 MW for the 135 MW project. Table 3-3 shows the ' derivation of_this value. -The 90 MW project share allocated to Seward ! is proportional to the value computed in Table 3-3 or 2.68 MW. Component 1 A 2.68 MW share of the 90 MW Bradley Lake Project for Alternative Plan I-2, or a 4.02 MW portion of the 135 MW Bradley Lake Project and share of the Anchorage-Soldotna Intertie--for Alternative Plan I-3,_assumed _to_come _ on-line in 1988. Component 2 New combined -cycle combustion turbine units on the Kenai Peninsula for satisfying capacity requirements which cannot be met by the Grant Lake Project, the Bradley Lake Project, or the existing gas turbine units. Component 3 Continued use of gas -fired generation from existing simple -cycle combustion turbines at Bernice Lake, as described above for the Base Case Plan I. I Component 4 The Oaves Creek -Seward 115 kV transmission line i (non -generation component). 3.5 GENERATION PLAN WITH SUSITNA PROJECT (ALTERNATIVE PLANS I-4) An alternative generation plan was developed that includes a portion of the proposed Susitna Hydroelectric Project, which is located on the Susitna River near Talkeetna and is being evaluated by the Power Authority. The purpose of this plan is to show the effect on the economics of Grant Lake of meeting all of Sewards energy requirements from the Susitna Project once the project is online. This plan is the 3-8 5605B same as the Base Case I until 1992. The portion of the Sustina Project which would be allocated to the City of. Seward varies on a year to year basis to match load growth (energy) in the City of Seward. When surplus or deficit capacity exists, a capacity adjustment is made which is equal to the equivalent value of thermal capacity. Because the cost of energy from the Susitna Project varies with utilization, the cost of the project must be based on an annuity with the same effective present worth as actual cashflows for the year in which they occur. Because this approach is computationally (not economically) different from the other components only the cost of energy (with an appropriate capacity adjustment) is included in the detailed economic study tables. The derivation of the cost of energy from the Sustitna Project is included as Table III-24 in the Technical Appendix. The components which comprise Alternative Plan I-4 are: Component 1 Seward's energy requirements met entirely by the Susitna project from 1993 on. Component 2 New combined -cycle combustion turbine units on the Kenai Peninsula for satisfying capacity requirements which cannot be met by the existing gas turbine units. Component 3 Continued use of gas -fired generation from existing simple -cycle combustion turbines at Bernice Lake, as described above for the Base Case Plan I. Component 4 The Daves Creek -Seward 115 kV transmission line (non -generation component). 3-9 5605E TABLE 3-1 EXISTING GENERATION RESOURCES ON KENAI PENINSULAY Generation Capacity Retirement Resource Owner Type (MW) Year2/ Bernice Lake 1, CEA NGT 8.85 1983 Bern-i-ce__Lake 2 C-EA NGT 1-8-.95 ----__1.99.2____ Bernice Lake 3 CEA NGT 24.3 1998 Bernice Lake 4 CEA NGT 24.3 2002 Cooper Lake CEA Hydro 15.0 2011 .Seward Combined SES Diesel 5.5 NGT = Natural.gas-fired combustion turbine CEA = Chugach Electric Association SES = City of Seward Electric System Data are from the Alaska Power Administration's Bradley Lake �- Project Power Market Report, January 1982. List does not include City of Seward's Mount Marathon 150 kW hydroproject or any industry -supplied generation facilities. 2/ Retirement dates based on economic life of facility as defined in APA's economic analysis parameters for FY 1983 (20 years for gas -fired combustion turbines, 50 years for hydroelectric projects). 3-10 5605B TABLE 3-2 DETERMINATION OF CONSTANT RESERVE REQUIREMENT ALLOCATION TO CITY OF SEWARD RAILBELT RESERVE REQUIREMENTS: 200 MW Kenai Peak Railbelt Peak Kenai Peak: Kenai Share of Seward Peak Seward Peak: Seward Share of Year Load (MW) Load (MW) Railbelt Peak (%) Reserves (MW) Load (MW) Kenai Peak (%) Reserves (MW) 1983 82 590 13.90 27.80 9.6 11.71 3.25 1984 84 610 13.77 27.54 13.8 16.43 4.52 1985 86 630 13.65 27.30 14.2 16.51 4.51 1986 89 665 13.38 26.77 14.6 16.40 4.39 1987 92 702 13.11 26.21 15.1 16.41 4.30 1988 94 736 12.77 25.54 15.6 16.60 4.24 1989 97 773 12.55 25.10 16.0 16.59 4.14 1990 100 808 12.38 24.75 16.5 16.50 4.08 1991 102 816 12.50 25.00 16.9 16.57 4.14 1992 104 824 12.62 25.24 17.2 16.54 4.17 1993 106 832 12.74 25.48 17.5 16.51 4.21 1994 108 840 12.86 25.71 17.8 16.48 4.24 1995 110 848 12.97 25.94 18.2 16.55 4.29 1996 ill 842 13.18 26.37 18.4 16.58 4.37 1997 112 837 13.38 26.76 18.6 16.61 4.44 1998 114 832 13.70 27.40 18.8 16.49 4.52 1999 115 827 13.91 27.81 19.0 16.52 4.59 2000 116 821 14.13 28.26 19.2 16.55 4.68 2001 119 832 14.30 28.61 19.7 16.55 4.74 2002 122 843 14.47 28.94 20.2 16.56 4.79 Average 1983-2037 115.019 817.963 14.04 28.09l/ 18.9574 16.45 4.62-2/ -1/ Used as constant reserve requirement for Kenai Peninsula in 20 year plans. ?/ Used as constant reserve requirement for City of Seward in 20 year plans. 3-11 O a 3 W N LL. O F7 Lti v H Z Y O -I� � 4 M Q O J Z W O Q •Z W � J Z r J W CO C L6 O Z O Q Z H ^L W E- W O 4- o� 3 ro N N r i. ro _3..m-_... . L% zz Y to Jhd C. N .0 C. - -3 to _ ar Y t/> b a 3y 8 J Q) to N N C i Y m 4- O to a to a c E Y fn N � v D. to C O i g Y u � c Q Ln o to Lcm _ L~i d t��1 .OG O U J W Q J J d to _ z a LN W C 0 he J Y -� W ER J i ro c m O N 0) O N N N r M W N N r r N M O O O Ch O O O O O O O O O O O O O N 0 pp p p.... cT. d' M d' d' d' c7 d' -d• d' �!' d'- ci' �!' ct -: ct - d' .. i . O) O n 'd* r co Ln co r 01 N Ln Ln t0 d' Ln d' d' tD Ln Ln Ln Ln Ln d' Ln Ln to Cr U) Ln Ln Ln LO Ln tD tp tD tD tD tD tD lD tD tD tD t0 t0 tD r tD tD tD tD lD t0 M to co N tD r lD O Ln 0) N LL) W N -;t tD CO O N n N Ln 01 M 4 Ln Ln tD tD k. Ch n n W W W W( l 01 01 O a r r r r r r r r r r r r r r r r r r N .. 1 O N r d• 01 01 t d- W M M Ln tD O P- M O O O d. N N N N N M M M M N M N N N M r M O O O O O .CV._..Cyj N N N N N N N N_N N-...N N. N m h. ct M Ln M OL M M tD N Ln d' n M W N r r 0 0 0 O1 D1 01 01 01 O. O O O 0� O O� � Qt O O I W W n^ W CO W W W n n W , W W W N f N 't t0 m to d• N O I,- N n r- m!' Lt') Ln d' CWd• LOn LLt m m mL ) IWn LOO LO to to to %DD ttoo W to N O O O m I\ O r- Ln d' N r m Ln N W W M m M ti' Ln t0 I- W M m O r N M .t Ln r M co O) O L-' M M M d' d' d' d' d' d' d' d' d' et Ln IY) Ln Ln L1) Ln Ln Ln N ct w a1 N d' n O N --:t lD W O r N d' Ln tD 01 N co I W W W W m m 01 O O O O C) r r r r r r r r r r r n O 01 N t M d• Ln W P- W a1 O r N m ct m tD f\ t;O 61 0 r N W W W W W W 01 01 Q) 01 01 O) O� Ot 01 O O O � I i co co > W p o rn 0, rn rn rn rn rn o, rn rn rn rn o, o, rn a, o, O m Q r r r r r r r r r r r r r r r r r r N N N 3-12 4.0 EVALUATION OF GENERATION PLANS 4.1 GENERAL Each of the five basic generation plans described in Section 3.0 for meeting the City of Seward's forecasted energy and demand requirements were evaluated using both economic and environmental criteria. The economic analysis was performed using the Power Authority's project evaluation procedure which provides a comparison of the cumulative present worth cost of the plans. The environmental evaluation provides a comparison of the major impacts of each project. Based on a comparison of the economics and the environmental considerations of each of the plans, a recommended generation plan was selected. 4.2 METHODOLOGY AND ASSUMPTIONS FOR ECONOMIC ANALYSIS 4.2.1 Basic Assumptions The criteria and basic assumptions for performing the economic analysis were based on the Power Authority's project evaluation procedure, on economic analysis parameters for fiscal year 1983 provided by the Power Authority, and on specific discussions with the Power Authority regarding the feasibility analysis for the Grant Lake Project. The assumptions used were as follows: 1. Inflation rate of 0% (constant dollars assumed). 2. Real (inflation —free) discount rate of 3.5%. 3. Natural gas prices are forecasted marginal prices escalated at the rates developed in the Sherman Clark No Supply Disruption Case (NSD) developed for the Susitna Hydroelectric Project (APA, Susitna License Application, 1983). Sensitivity analyses using marginal prices at 0% escalation and melded prices (includes impacts of 4-1 current gas contracts) at 0% and Sherman Clark NSD escalation were performed. These values are summarized in Table 4-3. A total of 23 cases were investigated in the analyses. (See Part IV of the Technical Appendix for detailed discussion of gas prices). 4. Forecasted electricalenergyand demand requirements from the medium load growth scenario described in Section 2.0, with sensitivity analyses being performed using high and low growth scenarios. 5. The total period of evaluation for the economic analysis is 55 years (1983 through 2037). 6. The economic life for simple -cycle gas -fired combustion turbines is 20 years. 7. The economic life for combined -cycle gas -fired combustion turbines is 30 years. B. The economic life of a hydroelectric project is 50 years. 9. The economic life of transmission lines with wood poles is 30 years and the economic life of transmission lines with steel towers is 40 years. 10. The capital cost for construction of new generation facilities are overnight costs which consist of project bid price estimates without escalation during construction. All capital costs are expressed in January 1983 dollars. Interest during construction is included. 11.'Estimated construction and operation and maintenance costs obtained from other sources for the Bradley Lake project are escalated to January 1983 dollars by -0.66% for July 1983 to January 1983 (USER Composite Index, September, 1983). Estimated construction and i operation and maintenance costs obtained from other sources for gas -fired generation facilities are escalated to January 1983 dollars by 7% for calendar year 1982. The 7% escalation was based on the economic analysis parameters issued by the Alaska Power Authority on July 1, 1982. Subsequent to Ebasco's development of thermal prices an additional memo was issued on May 31, 1983 by APA which directed the use of 4.3% escalation for hydro projects. The original 7% escalation was retained for thermal plants based on ENR's Quarterly Cost Roundup published June 23, 1983 which states that "Cost hikes for fossil plants slowed 3.3% last year to a 6.8% annual rate of increase." (p. 66). 12. The total annual cost for a given year in any plan is the sum of all capital and interest costs which occur in that year plus all annual operation and maintenance cost plus any fuel cost. 13. The total cost of any plan is obtained by discounting the annual cost for each year of the plan to 1983 using a discount rate of 3-1/2% and summing the present worth cost of each year. 14. The within year present worth is always preserved at January 1st levels. Therefore, cashflow which occurs later in the year is disounted back to January 1. Interest during construction is discounted in the same manner. Actual cashflows developed for Grant Lake and the Daves Creek -Seward Transmission Line are used in assessing those projects. For the other projects a uniform (linear) cashflow is assumed where the same amount is expended each quarter. 4.2.2 Interest During Construction Interest during construction is the interest paid on funds borrowed to undertake construction during the construction period. Obviously there are no revenues from the project during this period and hence the 4-3 interest paid on these funds represents an additional cost which must be amortized over the life of the project. The amount of interest during construction is controlled by four factors as follows: 1)-- The discount rate -which serves as the interest rate in an economic analysis. 2) The cash flow during the project construction period. 3)__ The assumed _date the funds -are borrowed. 4) 4) The assumed date of the construction contractor progress payments. An economic analysis generally makes some simplifying assumptions to facilitate the computation of interest during construction. For the Grant Lake and alternative projects the following assumptions are made: 1) There is no 10% or other retainage on funds due the contractor. 2) The interval over which the analysis is made is not as small astypically used in a financial analysis (i.e. monthly). For this study a quarterly interval has been selected. 3) It is assumed that funds are borrowed three months before payment is due the contractor. However, the funds are assumed to accrue interest during this period at the rate of discount (3.5%) and hence has no cost impact on the project. 4) As a result of 3) the interest is calculated on the cumulative amount borrowed up to the previous quarter.. Table 4-4 illustrates the computation of interest during construction for the Grant Lake Project. Similar computations were made for each component of the various cases. 4-4 4.2'3 Sensitivity Analyses The economic analysis procedure Was performed for the Base Case Plan I and Alternative Plans I-1 using the medium load growth scenario and gas prices based on marginal rates With Sherman Clark N3D (3C) real escalation. These assumptions for load growth and the future price of gas are considered to provide the most realistic evaluation of the cost of each of the plans. ID order to assess the effect that differences in the assumed load growth and gas prices would have on the outcome of the economic analysis, various sensitivity analyses were performed on the Base Case Plan and on Alternative Plan I-l. The total cost of the Base Case Plan and Alternative Plan I-1 Was computed holding all other parameters equal and using both the low and high load growth scenarios developed in Section 2,0, Also, the total plan cost for the Base Case Plan I and Alternative Plan I-1 was computed Using the medium load growth scenario and varying the assumption for the price of gas by using three other gas price scenarios. A summary of all of the economic analyses perfor0ed, including the sensitivity analyses, is shown on Table 4-1 with a discussion of the results being provided in Section 4.5. Detailed economic analyses for each case investigated are presented in Part III of the Technical Appendix. 4.3 DERIVATION OF COST OF PLAN COMPONENTS 4.3.1 General The Base Case Plan I and Alternative Plans I-1, I-2, 1-3 and I-4 include Up to a total of four different generation components and one non -generation CompoDant. The basis for assignment of capital and operation and maintenance costs for each of these components, 'and for the price of natural gas is described below. 4-5 53988 4.3.2 Simple Cycle Combustion Turbines No capital costs are required for simple cycle combustion turbine units because all new thermal generation capacity is assumed to be combined -cycle rather than simple cycle units. The operation and maintenance costs for simple cycle combustion turbine generation were obtained from the draft North Slope Gas Feasibility -Study (Ebasco Services Inc., January 1983), where a value of 4.60 mills per kilowatt-hour was estimated in January 1982 dollars.Escalating this value one year to January 1983 using a 7% escalation rate provides'a value of 4.92 mills pe r kilowatt-hour. The breakdown between the fixed _ and _variable (excluding fuel costs) components of operation and maintenance was not estimated because of the negligible amount of fixed cost attributable to operation and maintenance of simple cycle units. A heat rate of 12,000 Btu's per kilowatt-hour has been used for simple -cycle combustion turbine.generation (Supplement -Kenai Peninsula Power Supply and Transmission Study, R.W. Beck and Associates, December i 1982). 4.3.3 Combined Cycle Combustion Turbines The capital and operation and maintenance costs for new combined cycle generation facilities was obtained from the draft report on the North Slope Gas.Feasibility Study (Ebasco Services Inc., January 1983). A cost estimate was developed in that study for a 220 MW combined -cycle plant located in the Kenai/Nikiski area. The total estimated cost for this plant in January 1982 dollars was $135,610,000, which results in a cost of $616 per kilowatt. Using a 7% escalation rate from January ( ; 1982 to January 1983, the January 1983 capital cost becomes $659 per kilowatt. Operation and maintenance costs were estimated at 4.0 mills per kilowatt-hour, which, when escalated to January 11983, becomes 4.28 i mills per kilowatt-hour. I 4-6 5398E The cost of transmission facilities for the combined cycle plant were obtained from the Kenai Peninsula Power Supply and Transmission Study (Beck, June 1982). In that study a value of $564,523/MW (January 1982 dollars) was used for the construction costs of transmission facilities, and a value of $9,534/MW.(January 1982 dollars) was used for operation and maintenance costs. These values were escalated to January 1983 using 7% escalation. The Federal Energy Regulatory Commission's Hydroelectric Power Evaluation manual, August 1979, recommends the application of a capacity value adjustment factor of 5% to 10% to reflect the greater reliability of hydroelectric projects when compared to thermal generation facilities. A capacity value adjustment factor of 5% was therefore applied to the at -market cost of capacity from the combustion turbine facility. This resulted in a cost of $692 per MW. This capacity value adjustment factor was also applied to the.at-market thermal capacity values in the economic analysis for the Bradley Lake Project in both the Bradley Lake Project Power Market Report (Alaska Power Administration, February 1982) and the Kenai Peninsula Power Supply and Transmission Study (R.W. Beck and Associates, June 1982). As reported in the North Slope Gas Feasibility Study, referred to above, the heat rate for units of this type ranges from 8350 to 9200 Btu/kWh. The heat rate for combined cycle units used'in the Supplement to the Kenai Peninsula Power Supply and Transmission Study (R.W. Beck, December 1982) is 8700 Btu/kWh, which is near the mean of the range of heat rates given in the North Slope Gas Study. A heat rate of 8700 Btu/kWh is used in this study as a value representative of average operating conditions considering varying load, start-up and shut -down periods, and efficiency of the units over their economic life. This value is consistent with the value used in the Beck report. 4-7 5398B The capital and operation and maintenance costs for the 7,000 WN Grant Lake Project are developed in Section 18.0 of this report. The total overnight estimated project cost in January 1983 is $23,390,000 with �- the lchMstruttidr['p6riod-extend0ng-nVer two-aMdoMe h8lf-year�-.-�Thg ~ ` operation and maintenance costs were estimated to be $302,000-per year. 4.3.5 Bradley Lake Hydroelectric Project | ' The estimated construction costs for the Bradley Lake Project were ^ ----obta1ned-fromthe -Power- -AVthoritv-(3tone,-and-Webster, -October, -l98 -- These costs were developed for a SO MW and a 135 MW installed capacity ' development at Bradley Lake With the assumption that construction Would begin in 1983 and the project would be operational iM'October ``lgBB. | The 90 MW project is the preferred developmant. The total estimated | construction cost in July 1983 dollars is $283,019,000 . Costs Were / — d6_6stalat6d-to-JaMU8ry-T983-dollars -bvdedbctTMml)�86-percent -df`Che'-' cost in accordance with the U38R Composti1e Index of Water and Power � ` Costs resulting in an adjusted overnight cost of $281,163,000, Operations and maintenance costs Were given as $1,252,000 (July, 1983) ^ ' and adjusted to $1,243,800 (January, 1983) by the same factor. The —^ � �hfl i il ^l d` t�d ''- l �.- following: ^ proJgu� cashflow was �� r� ya_Jus U resulting n the Calendar Year 1983 1984 1985 1986 1987 1988 ($UOO, January 1983' 2,186 8,146 65,557 77,848 82,535 45,091 5398B 4-8 The cost of the project assigned to Seward is based on the 4.02 MW portion of the installed capacity which Seward is assumed to receive (see Section 3.4 for derivation of 4.02 MW). The 135 MW Bradley Lake Project, presented in the feasibility study, is from an earlier comparison study conducted by Stone & Webster. It is not directly comparable with the latest version of the 90 MW Bradley Lake Project since the 90 Mw project includes additional refinements which were not applied to the 135 MW project. However, as a matter of interest, the 135 MW project is included in this study. A major difference between the 90 MW and 135 MW project is the addition of the Anchorage-Soldotna Intertie to the 135 MW case. The intertie is required to transmit the higher peak load flows in the 135 MW development. The cashflow for the project is assumed to have the same percentage distribution as the 90 MW project. Operations and maintenance costs are given as $1,243,800 (January 1983 dollars), the same as for the 90 MW plant, by Stone & Webster. The Anchorage-Soldotna Intertie is assumed to be built in 1987 (personal communication, Stone & Webster, December 15, 1983). Operations and maintenance costs for the intertie are $936,800 per year. 4.3.6 Daves Creek -Seward Transmission Line The capital and operation and maintenance costs for the Daves Creek -Seward transmission line are developed in Section 10.0 of this report. The estimated overnight construction cost for the line is estimated to be $11,799,000 and the annual operation and maintenance costs are $250,000, both in January 1983 dollars. The projected date for the line to become operational is November 1984. The costs for this transmission line are included in all plans because the results of the feasibility study for the line indicate that regardless of the 4-9 5398B method of providing power to the City of Seward, the existing 24.9 kV I transmission line that extends between the Daves Creek switchyard and the City of Seward will require replacement. For purposes of inclusion i of the cost of the line in the economic analysis, the operational date for the line has been assumed to be January 1985. f 4.37-_ Price of -Natural Gas The price of natural gas used in the economic analysis was based on the following: 1) Volume 1, Exhibit D of the Application for License for I _---Ma j-o r--P r-o j-e c-t ;---Sus-i-t n a-H yd-r-o el-e c tr i c -P-r- o j-e c-t___2 )._ p r- i-ce--f o r-e ca-s ts---.--_ developed-in--the--Rail-belt Electric. -Power -Alternatives -Study: —Fossil --- -- Fuel Availability and Price Forecasts, Vol. VII (Battelle, March 1982), and 3) an additional gas price forecasting analysis performed by the { Power Authority in December 1983 which is contained in the Tehcnical Appendix in Part IV.- i The method used in the License Application for the Sustina Project for estimating the future price of natural gas is to tie the price to the world price of oil. This is particularity applicable since the recent Enstar contracts escalate the price of gas in relation to the price of y oil. Several scenarios for estimating the future world price of oil Were evaluated and are described in Section 5.4 of Exhibit B in the C Sustitna License Aplication. The world oil price scenario adopted for Susitna was the Sherman Clark Associates No Supply Disruption case. For the sake of brevity in charts and text this case is abbreviated "SC" The Battelle Study contained historical and forecasted prices for natural gas for years 1980-2000 for the Alaska Gas and Service Company (AGAS) and Chugach Electric Association (CEA). These price forecasts (Tables 2.7 and 2.8 in Part III of the Technical Appendix) incorporate the effect of the differing costs and escalation rates of the various existing gas supply contracts, and the cost of supplemental (marginal) gas supplies which will be required in the future to meet demand in excess of the contracted supply. 4-10 5398B The Power Authority, in its January 1983 analysis, revised the Battelle forecasts to account for the following: 1) Historical use of North Cook Royalty Gas by AGAS - while Battelle had estimated that North Cook Gas would provide 4 BCF/year in 1980 and 1981, only 2.68 and 1.03 BCF/year were used in actuality. This represented such a small proportion of the total gas supply that its effect was ignored totally in the Power Authority's analysis. In addition, ENSTAR has indicated that they will be purchasing little, if any, royalty gas. 2) Estimates provided to the Power Authority from ENSTAR of the proportion of new, non -royalty supplemental gas which would be included in the total gas supply to AGAS in future years (1983-20%, 1984-30%, 1985-40%, . . . 1990-90%, 1991 and beyond, 100%). The Power Authority's analysis of the cost of gas using the above data is contained in the Technical Appendix. A total of four different gas price scenarios were identified in this analysis for use in the economic analysis: 1) Marginal rates at SC escalation, 2) Marginal rates at 0% escalation, 3) Melded rates at SC escalation, and 4) Melded rates at 0% escalation. The forecasted prices for each of these scenarios are shown on Table 4-3. The marginal (or non -royalty supplemental) gas rates shown in Table 4-3 were obtained from the analyses performed to forecast the weighted price of gas to AGAS. Also, the melded gas prices were computed ('at 0% and SC escalation) based on the respective generation of CEA and Anchorage Municipal Light and Power. The derivation of these price scenarios is shown in the Technical Appendix. 4-11 5398B W The marginal price of gas at SC escalation was used for the sizing and I optimization of the Grant Lake project features, and in the economic analysis. Use of the marginal price of gas is considered reasonable and justifiable because the hydro project is being compared with the cost of new gas -fired generation on the Kenai Peninsula and because I contracts for supply of gas will expire (exc-luding the recent Shell and _Marathon contracts_) from use at existing power plants and for non -electrical uses. In addition, if a gas -fired generating plant were to be replaced by a non -gas -fired generating facility, the units shut down would be those using the highest cost fuel. 4.3.8 Transmission Losses 4.3..8.1 General Transmission losses were estimated for delivery of power from each generation component to the City of Seward. A discussion of the assumptions and procedures which were used to estimate the losses __is - provided below. I 4.3.8:2 Grant Lake Project Transmission losses from the Grant Lake Project to the City of Seward were estimated based on the transmission line configuration shown in Part IV of this report from the powerhouse to the Seward -Anchorage i Highway, and the assumption that the new 115 kV Daves Creek -Seward transmission line would be built, as discussed in Part III of this report. It was assumed that the transmission line from the Grant Lake powerhouse would be connected to the new 115 kV Daves Creek -Seward line, over which Grant Lake power would be transmitted to Seward. The l station service and transmission losses were estimated to be 1.8% for energy and 0.8% for capacity. 91M 5398B 4.3.8.3 Thermal Generation Facilities The transmission losses from the vicinity of the City of Kenai to the City of Seward were estimated for the existing and new gas -fired thermal generation facilities used in the base case plans and alternative plans . The transmission losses from the area near the City of Kenai to the City of Seward consist of two main segments. The first segment is the existing 115 kV transmission line from Kenai to Daves Creek substation (about 40 miles northwest of Seward) and the second portion is the new 115 kV line from Daves Creek to Seward (as presented in Part III of this report). The transmission losses for the first segment from the area near Kenai to Daves Creek Substation are estimated to be about 5% for peak loading and about 3-1/2% for average normal load. This estimate is based upon the following information. o That the 115 kV transmission line from Daves Creek to Soldotna (near Kenai) has a 556 ACSR conductor. This conductor size information was received from Chugach Electric Association. o That the estimated load now on this line is 10 MW with a direction of power flow from Soldotna toward Daves Creek. This information obtained from the draft copy of Railbelt Reliability Study for 1982/83 peak load base. o That the load forecast in Section 2.3 of 20 MW be used for peak loading. It is assumed that this load would be added to the line's present load. o That transformer losses are small enough to be ignored. Information obtained from Chugach Electric indicated that this segment of line load was higher than 10 MW and more in the order of 20 to 30 MW. If this is the case, then losses for peak loading would be more in the area of 10%. However, the lower figure is used. 4-13 5398B i The transmission losses for the second segment of this line from Daves 1 Creek to Seward are estimated to be 2.7% for the peak demand and 1.1% for average normal loading. This information is presented in Section t 9.3 and Part V of the Technical Appendix. When these -.two segments are combined, the total loss is 7.7% for pea demand and 4.6% for average normal loading. These values were rounded - off to 8% and 5% for use in the economic analysis. 4.3.8.4 Bradley Lake Project The transmission losses from the Bradley Lake -Hydro project to Seward -- - ' were given by Stone & Webster as 8% for both capacity and energy (personal communication, Stone & Webster, December 15, 1983). I 4.3.9 Allocation of Generation Between Plan Components The energy allotment between generation resources was as to follow" the economically rational approach of using least expensive sources I prior to more expensive sources. In all 20 year plans, hydroelectric energy (if included in the plan) is allocated first since there is no �. variable (fuel) cost associated with its provision. The next lowest cost alternative is combined cycle combustion turbine since the heat rate of 8,700 MMBtu/ GWH is lower than the 12,000 MMBtu/GWH for simple cycle turbines resulting in lower fuel consumption (i.e., cost) per GWH of energy generation as well as slightly lower variable operation and maintenance costs. Finally, after all other generation sources are exhausted, the simple cycle turbines contribute the remaining energy C requirement until they are completely retired in 2002. After they are retired, each plan ensures adequate capacity and energy are available from the new sources to meet Seward's needs until the end of the evaluation period. 4-14 5398E Generally, once hydroelectric energy is fully allocated (or immediately in the case of the Base Plan I), the combined cycle combustion turbines are allocated. A maximum capacity factor of 0.75 was used for the combined cycle unit after reserves were accounted for, which results in a maximum energy of 6.57 GWH per MW of combined cycle combustion turbine installed capacity. If the remaining energy demand is less than 6.57 GWH per MW then only the energy needed is generated. When the energy demand exceeds the supply capable of being provided by combined cycle combustion turbines the simple cycle combustion turbines are allocated. An additional complication exists in allocating energy during the years prior to retirement of the simple cycle turbines in all plans. It may be impossible for the combined cycle combustion turbines to operate at the stated capacity factor of 0.75 or even a reduced capacity factor, based on meeting the remaining energy demand, owing to the shape of the load duration curve for the region and reserve requirements. To overcome this problem an algorithm was developed for allocating energy generation between simple cycle, turbines, combined cycle turbines, and hydro power. The first step in creating the algorithm was to develop an annual load duration curve for the region based on load duration data provided in the Bradley Lake Power Market Report (Alaska Power Administration 1982). A piecewise linear approximation at 10 percent intervals of the curve for December was applied to the fall and winter months of October through March when peak load is highest using the mid -range peak load distribution for the Anchorage/Cook Inlet region. A similar approach was taken using a piecewise linear approximation for June and applying it to the spring and summer months of April through September. The resulting percentages of peak load were ranked and plotted as an annual load duration curve. Based on the plot, equations were developed which described the relationship of percentage of annual peak to percent exceedance of load. Integrating the equations yielded the amount of 4-15 5398B energy which must be generated by combined cycle combustion turbines at | a given level of installed capacity adjusted for reserve requirements. The remaining energy is allocated to simple cycle turbines. 4.4 OPTIMUM TIMING FOR GRANT LAKE PROJECT - -- - -- --- - -- - - - -- The project schedule, shown VO Figure IV-27, indicates that the earliest practical time that the project can be constructed and come � ' on-line is April 1987. The load and resource analysis part of the economic study shows that new generating resources for the Kenai | ( �rfxqui red _uUtil19-8-8. _TDal]ow_for-pVs5ibl-e s]i -----�-I n-the project-schedU]e/and -to-meet -the -need-f'or -add i'tional-oe capacity in 1988, We have assumed for the purposes of performing the / economic analysis that the earliest the project could come on-line �� '} January 1988. | A study was performed to determine the optimum timing for the ' | ------trV�ti-- -f the 8r��-LaP-"---t--Th�--- -------f�rmed-� - -- -� �#D� u� o � roJg� , s�UUy �a� p�r� --- by . � varying the on-line data for the project and computing the total '-^ | present worth cost of Alternative Plan I-1for each assumed on-line date to find the date that results in the lowest total cost. As shown / on Table 4-5, this systematic search for the optimum project timing showed that the lowest total cost for Alternative Plan I-1 results with . \ a project on-line data of January 1988 (assuming marginal prices for ' gas a' DC escalation and medium load growth). As the on-line date for the project was moved further ahead, the total plan costs increased. ) It Will be noted, however, that the difference in the total plan cost for the years immediately ahead Of the optimum date is extremely small. / 4.5 RESULTS OF EC ' lC ANALYSIS A summary of the total present worth of the cost of each plan including | all sensitivity analyses described above, is shown on Table 4-1, The , detailed analysis for each of the 15 cases studied as twenty year plans | 53988 is shown on Tables III-1 to III-15 in Part III of the Technical Appendix. As shown on Table 4-1 with Cases 1, 2, and 3, using the medium load growth scenario and the marginal price of gas at SC escalation, Alternative Plan I-1 is lower in cost than the Base Case Plan I, and Alternative Plan I-2 has the lowest cost of all plans. Therefore, the economic analysis using these parameters shows that the Grant Lake Project is economically feasible and is preferrable to purchasing a similar share of combined cycle combustion turbine facilities. Using either the low load growth scenario (Cases 6 and 7), or the high load growth scenario (Cases B and 9), the alternative plan including Grant Lake is preferable. Using any of the assumptions for lower gas prices (Cases 10-15), the Base Case Plan I is more economical than Alternative Plan I-1. This illustrates the sensitivity of the economics of the Grant Lake Project to the assumptions made for the price of natural gas. However, the assumption considered to be most realistic for the price of gas is that of marginal rates at SC escalation, and under this assumption the Grant Lake Project is shown to be slightly more economical than the Base Case Plan I, regardless of whether a low, medium, or high load growth scenario is realized. Although the differences in the total cost of the Base Case Plan I and Alternatives I-1 and I-2 are not substantial, the results of the economic analysis indicates that the presence of the Grant lake Project in the generationresource mix serving Seward would result in a lower cost of power than without the project. Furthermore, the project is much more economical relative to base case than the benefit cost ratio indicates since substantial portions of each plan represent common denominators. Table 4-1 also shows the net benefits and benefit/cost ratios associated with each case. In accordance with the Power Authority's project evaluation procedure, benefits are defined as the present worth total cost of the Base Case Plan I, supplemented by any subsidiary benefits of a particular plan. Subsidiary benefits are beneficial outputs other than power production. In the case of Alternative Plan 4-17 i I- 1, subsidiary benefits would be provided from the production of fish from the fisheries mitigation plan and from the use of the recreational facilities of Grant Lake. However, no attempt has been made to quantify these subsidiary benefits, and they have been conservatively assumed to be equal to zero. Therefore, the benefit/cost ratio for any case is the ratio of the cost of the Base___ Case Plan to the. cost.. -of the plan of interest. As indicated on Table 4-1, the benefit cost ratios for all cases is essentially 1.0, indicating marginal economic feasibility for the Grant Lake Project. Therefore, the thermal alternative and the Grant Lake Project are approximately at a break-even point, in view of the fact that the largest._dff_e.rence__in_ I—-___ __ _ __ . __ _ - :.. _ the Base Case Plan I versus Alternative Plan .I-1 is only three percent in the case of melded gas prices at 0% escalation. A summary of the total present worth of the cost of each plan equivalent to Grant Lake is shown on Table 4-2. The detailed analysis for each of the 8 cases studied is shown on Tables III-16 to I11-23 in Part III of the _ -Technical Appendix. As shown on Table 4-2 with Cases 16, 17, 18 19 and 20, using the medium load growth scenario and the marginal price of gas at SC escalation, Alternative Plan II-1 (Grant, Lake) is lower in cost than the Base Case Plan II, and Alternative Plan II-2 (90 MW Bradley Lake)has the lowest cost of all plans. Alternative Plan I1-4 I (135 MW Bradley Lake) is also less expensive than Alternative Plan II-2, but Alternative II-5 (Susitna) is most expensive The benefit cost ratio of Alternative II-1 (Grant Lake) is 1.148. For the cases where fuel prices are lower than the Sherman Clark marginal prices, a significant difference between the results for the 20 year plans and the Grant Lake equivalent analyses is evident. For example note that the benefit cost ratio for the 20 year plan utilizing marginal gas prices at 0% escalation is 0.990 while the Grant Lake equivalent yields a benefit cost ratio of 1.024. The reason for the differing conclusions is that in the Base Plan I, the combined cycle combustion turbines are operated at higher capacity factors, with the additional capacity requirements being met by the simple cycle combustion turbines. Grant Lake is hydrologically limited to a 4-18 capacity factor of 41.4%, not 75% like the combined cycle turbines, and therefore the increased reliance on simple cycle combustion turbines causes the overall Alternative Plan I to be more expensive than the comparable Base Case I at 0% escalation of the Sherman Clark gas prices. 4.6 ENVIRONMENTAL EVALUATION This section compares the environmental impacts associated with the gas turbines and the alternative plans for supplying power to the Seward area. An evaluation of the environmental impacts associated with each plan is provided in the following paragraphs. 4.6.1 Gas Turbines Environmental impacts associated with the gas turbines primarily consist of air emissions from the Bernice Lake plant and aesthetic and biological impacts associated with the Daves Creek -Seward transmission line. Air emissions from gas -fired units are relatively "clean" compared to other fossil fuel plants. Appropriate emissions controls, such as water or steam injections to reduce nitrogen oxides levels, would ensure compliance with the applicable air quality standards. Because the Bernice Lake site is in an exposed coastal area, the air quality and meteorological conditions generally favor power generation. 4.6.2 Daves Creek -Seward Transmission Line Construction of the Daves Creek -Seward transmission line will engender several environmental impacts. Because the line will be located near the Anchorage -Seward Highway for most of its length, the line will have an aesthetic impact on viewsheds between Seward and Moose Pass. Single wood poles will be used to minimize this impact. A low profile substation configuration will be used that can easily be screened with existing vegetation. The transmission line will also cause minor impacts on wildlife habitat due to clearing of the right- of -way and access road construction in the areas where the line is not built in 4-19 61411.1 the existing right-of-way. A short-term increase in erosion rates during the construction phase may slightly increase sedimentation in nearby waterbodies, thereby degrading the water quality. Because this impact will be short-term and low in intensity, the effects would not be significant. 4.6.3 Grant Lake The primary environmental impact of the .Grant Lake Project is loss of fish habitat over the 1.1-mile length of Grant Creek. Although Grant Creek would be dewatered for its full length only the lower 1/2 mile is currently uti-l-i-zed -by fi-s-h-. --An-estimated -1-00---ch-i-nook ---and- - 500---s,ockeye-------- --- ------------ sa . lmon adults would be _16s; - t annually f ro m - Grant Creek--.- In-'addit-ion,-' habitat for rainbow trout and Dolly Varden would be eliminated. The loss of these fish would be mitigated by adding salmon culture facilities at a nearby state hatchery and by planting trout into Grant Lake or a nearby lake to replace sport fishery losses. Because of the mitigation measures employed, the Grant Lake Project would not cause a net loss to fisheries resources.. A detailed assessment of potential impacts of the Grant Lake project and proposed mitigation measures is .provided in Volume II, Environmental Report. The environmental, impacts associated with Grant.,Lake-.in,combination with gas turbines include those discussed for the gas turbines in addition to those associated with the Grant Lake Project. The Bernice Lake generation capacity would be reduced by 7 MW as compared with the base plan, resulting in a corresponding decrease in air emissions. Some environmental impacts of Grant Lake and gas are significant, but these can be mitigated. 4.6.4 Bradley Lake The Bradley Lake Project will inundate approximately 2,000 acres, eliminating more than half of the tall shrub habitat in the immediate vicinity of Bradley Lake. The effects of this habitat loss to the 4-20 5398B local moose population is unknown, but permanent displacement is possible. Because the project reservoir would more than double the lake's surface area, the high water and exposed shoreline could impede moose migration between Fox River Valley and the Kenai National Wildlife Refuge, the shrub habitat along Kachemak Creek and upper Bradley River, and dispersion through the Bradley River - Nuka River pass. This dispersion is believed to sustain the only moose population on the outer coast of the southern Kenai Peninsula (Bradley Lake Hydroelectric Project Final Environmental Impact Statement, U.S. Corps of Engineers, 1982). Approximately 400,000 cubic yards of clay material will be excavated from the Sheep Point barge basin, its entrance canal, and the tailrace. This material will be placed on about 40 acres of intertidal land and adjacent uplands. This placement may affect existing waterfowl habitat and the overall intertidal ecosystem. Environmental impacts associated with Alternative Plan I-2 and I-3 include those discussed for Plan I-1 in addition to Bradley Lake impacts. Because the generating capacity of the Bernice Lake plant would be reduced 11 MW by the Bradley Lake project, air emissons in the Kenai area would be somewhat less than for Plan 2. In summary, impacts associated with all three plans will generally be insignificant. 4.6.5 Susitna Hydroelectric Project The Susitna Project includes two dams, Watana and Devil Canyon, that will create 48-mile and 26-mile long reservoirs, respectively. During construction, temporary construction camps will be located at each dam site. A permanent town will be developed near Watana and an access road built from the Denali Highway to the dam sites. 4-21 5398B Impacts to fisheries will occur in downstream tributaries, side channels and sloughs. All species of Pacific salmon, but predominantly chum salmon, will experience effects on spawning and juvenile rearing. Mitigation planning includes controlling water temperatures and flow regime and possibly modifying habitat, or constructing a hatchery. Principal wildlife species in the project area are moose, caribou, wolf, wolverine, bear and Dall sheep. Loss of moose habitat by inundation will occur and downstream grouse may be affected by altered flow regimes. Reservoir inundation and increased access will also i affect grazing above the dam sites. Caribou migration and calving patterns may be affected by the access road and reservoir ice -- -- conditions. Some black bear reductions are likely from flooded dens, but much less impact is expected to brown bear. Partial inundation of a mineral lick may impact sheep usage and some regulation of furbearer 1 trapping may be required. A slight reduction in wolf population may occur because of reduced moose population. Socioeconomic impacts are projected to largely affect the communities of Cantwell, Talkeetna, and Trapper Creek based on immigration of workers and their families. Archeological and historical resources will be preserved through avoidance and removal. Alternative Plan I-3 would have the highest level of environmental impacts of the three plans considered. 4.7 SELECTION OF GENERATION PLAN Based on the results of the economic and environmental evaluation of the Base Case Plan I and Alternative Plans I-1, I-2, I-3, and I-4, the following conclusions can be reached: o The 115 kV Daves Creek -Seward transmission line would be included in any generation plan for Seward. a 4-22 5398B o Alternative Plan I-1 (includes Grant Lake Project) is lower in cost than the Base Case Plan, assuming the medium load growth scenario and marginal gas prices with SC escalation; o Alternative Plans I-2 and I-3 are also economically feasible. Alternative Plan I-4 has a benefit -cost ratio slightly below 1. o The environmental impacts associated with either the Base Case Plan I and Alternative Plan I-1 are not significant enough to effect the decision of the choice of the plan; and o The 7 MW Grant Lake Project is economically feasible independent of Bradley Lake Project considerations. More significantly, the Grant Lake Project has a benefit -cost ratio of approximately 1.15, based on the value of power from displaced gas fired combined cycle generation with marginal gas prices with SC escalation. Based on these conclusions, the recommended generation plan for Seward is Alternative Plan I-1 which includes the 7 14W Grant Lake Hydroelectric Project and the 115 kV Daves Creek -Seward Transmission Line. 4-23 TABLE 4-1 SUMMARY OF ECONOMIC ANALYSES USING 20 YEAR PLANS Total Present Reference North Cost Net Benefit Table of Case Plan Load Growth Price of Gas of Plan Benefits Cost Technical No. Description Scenario (rates) (Jan 1983 $000)_ Jan 1983 1000 Ratio Appendix -1 -----Base Case L/- ---Medium--_--Marginai--®SC- esc, -1-50-.141- -- 0- -1_000------ - ...-- -III-1- 2 Alt. I-1V Medium Marginal SSC esc. 148.344 1,797 1.012 III-2 3 Alt. I-23i Medium Marginal OSC esc. 146.983 3,158 1.021 III-3 4 Alt. 1-3-4/ Medium Marginal SSC esc. 149,313 828 1.006 III-4 5 Alt. I-45/ Medium Marginal SSC esc. 156.200 -6.059 0.961 III-5 6 Base Case I Loa Marginal SSC esc. 77.354 0 1.000 I11-6 7 Alt. I-i Loa Marginal SSC esc. 76.321 1.033 1.014 III-7 8 Base Case I Nigh Marginal SSC esc. 217.080 0 1.000 III-8 9 Alt. I-1 High Marginal SSC esc. 215,220 1.860 1.009 III-9 10 Base Case I Medium Marginal SOS esc. 136.777 0 1.000 III-10 11 Alt. I-i Medium Marginal 90% esc. 138.198 -1,421 0.990 III-11 12 Buse Case I Medium Melded SSC esc. 131.869 0 1.000 I1I-12 13 Alt. I-i Medium Melded SSC esc. 132,260 -391 0.997 III-13 14 Base Case I Medium Melded 00% esc. 118.024 0 1.000 III-14 15 Alt. 1-i Medium Melded SOS esc. 121,641 -3,617 0.970 III-15 V Base Case Plan I consists of existing and new gas -fired generation. 2/ Alternative Plan I-i includes the Grant Lake Hydroelectric Project. which displaces gas -fired generation. 3/ Alternative Plan I-2 includes the 90 MN Bradley Lake Hydroelectric Project, which displaces gas -fired generation. 4i Alternative Plan I-3 includes the 135 MN Bradley Lake Hydroelectric Project. which displaces gas -fired generation. 5i Alternative Plan I-4 includes the Susitna Hydroelectric Project . which displaces gas -fired generation. 4-24 14T:IM11 % SUMMARY OF ECONOMIC ANALYSES FOR GRANT LAKE EQUIVALENT OPTIONS Total Present Referenc Worth Cost Net Benefit Table of Case Plan Load Growth Price of Gas of Plan Benefits Cost Technica No. Description Scenario (rates) (Jan 1983 $000) (Jan 1983 $000) Ratio Appendix 16 Base Case I LIV Medium Marginal @SC esc. 31,648 0 1.000 III-16 17 Alt. II-12/ Medium Not Appicable. 27,579 4,069 1.148 III-17 18 Alt. II-23/ Medium Not Applicable. 21,939 9,709 1.443 III-18 19 Alt. II-34/ Medium Not Applicable. 25,582 6,066 1.237 III-19 20 Alt. II-�./ Medium Marginal @SC esc. 33,060 -1,412 0.957 III-20 21 Base Case II Medium Marginal @0% esc. 28,236 0 1.000 III-21 17 Alt. II-1 Medium Not Applicable. 27,579 657 1.024 III-17 22 Base Case II Medium Melded @SC esc. 29,043 0 1.000 III-22 17 Alt. II-1 Medium Not Applicable. 27,579 1,464 1.053 III-17 I 23 Base Case II Medium Melded @0% esc. 25,642 0 1.000 III-23 17 Alt. II-1 Medium Not Applicable. 27,579 -1,937 0.930 III-17 Base Case Plan II is new gas -fired combined cycle generation. ?� Alternative Plan II-1 is the Grant Lake Hydroelectric Project. 3� Alternative Plan II-2 is the 90 MW Bradley Lake Hydroelectric Project with an appropriate adjustment for capacity credit. 4� Alternative Plan II-3 is the 135 MW Bradley Lake Hydroelectric Project with an appropriate adjustment for capacity credit. 5� Alternative Plan II-4 is initially new gas -fired combined cycle generation followed by complete reliance on the Susitna Hydroelectric Project from 1993 on with an appropriate adjustment for capacity credit. 4-25 | ) TA8LE4-3 '\ FORECASTED PRICE OF COOK INLET GAS FOR E IN ECONOMIC ANALYSI5V Marq1Dal�_Rates�/�� !/ - � � 1 -�C escalation ��_esc�lati��nescalation� — -�- — --- O��e��a|�t escalation ox � _. -- -=�^ ' ~- �� C�8/ �/MCFl� � 4� �/�C �/M � 'Year �/MCF— - r�' +r=~ ~~._-- \ 01.95 �/9ou-- ----~~' ' ---2.90 l l3 �� |�U/ �2 7�� 2 9O , ---l987 ^ ` ' �- —l-��U ----- ---- ----- ---�-----�2�Ul�--—l27--' �----- -----'----- lg8� 2 77 ' � - ` < ` - l 35 ''"~ - l 4l 1989 2.77 2.97 . .'^' ^ ..l� 1990 3^ 3.05 1.54 1'51 l 73 l 73 / 3 l4 , 1991 3.12 ' '`'^ � �- } ' - ' � | 75 - l 8l 3 �2 . l992 3 l2 , ..'^ � ` ' - -- l gb '''� - - l 84 1998 3.12 3'31 . /."^ ` ^ ^ 2'O7 3 4O l gl T994 3^l2 ^ � l8 > l995 3.12 3'49 1.96 . ) ^ 294 �� 3 59 -l9�6 - 3.12 , �.=^''`�� —__ ^ - - � 94 3.51 3 b9 1997 3 l� ' "',� � ^ - � 94 3 hl 3 79 ' ( l998 3'l2 ' �'�` _ _� - �' 2 94 3 7l ' ' 3 89 ` l999 3 l2 , ^'"` - ^ - -' 2 94 3.82 �- 4 UO 2OOO 3 ]2 "',� � ^ � 2 94 3 93 / - 3 l� 4 ll ' ' 2OOl ' ` - -� 4 O5 / - �- 2 94 ' - 3.12 4 23 ^ `',^ 2OO2 �' _ _� ' l/� O�r�Vati�D of all values i n this table is provided in a Power / — d �o File dated 3�nu�ry 12 1983, which is Authority Memorandum , , contained in Part IV of the Technical Appendix' 2/ The term "marginal" rates refers tthe contracted price of � — nmD-royalty, supplemental gas to A8A3' � dprice' 0f gas �0 3/ The term "melded" rates refers to the forecasted � — Anchorage Municipal Light and Power and Chugach Electric Association, Where the melded rates are based on the respective amount of energy \ generated by each utili1y' dj Part IV Prices derived on Table A, Technical Appendix, � . -` Prices derived on Table B, Technical Appendix, Part IV. / =' Prices derived on Table C, Technical Appendix, Part IV, =' Prices derived on Table D, Technical Appendix, Part IV. 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J-Ci co � j Cam• r r M O N 4J C 11 4Jw r L O r = fa. toro 3 4J 4J L �4 ti O C U) co = C 7 CU 4J N M et 0 d• C 4-J •FJ R% 0 to V) +-J co d• ct r` fu C VJ •7 CJ CJ C N Ol g co h 7 = CD 5 L O Or 0LON O L C- U U Mco U CJ O ^ �� 1.0- i 10 O H Y L O F- CD Ci) :.J Z Alternative 1 1988 Alternative 1 19903/ Alternative 1 19933/ Alternative 1 19983/ Base Case TABLE 4-5 OPTIMUM TIMING ANALYSIS FOR GRANT LAKE PROJECT�� SC $148,344 SC 148,424 80 Sc 148,600 ---- 256 Sc 148,735 391 SC 150,141 1,797. 1 !/All cases shown use medium load growth scenario and 55 year evaluation period (1983-2037) ?Sherman -Clark Marginal price of gas was used in the optimum timing analysis 3/See Tables III-25, III-26, and III-27 of the Technical Appendix for detailed studies. .I I 4-28 5398B P E R C E N T 0 F A N N U A L mmommmmmommmmmm -mm, m ammommmmmmmmmmmmmm -omm-mmmmmmmmmmmommm onommmmmommmommmmo Emmmmmummmmmmmm M-mmmi mmmmmmmmb"11,015mmmmmmmmmm mmmmmmmmmmummmmmmmmm mmmmmmmmmmmmmmmmman-'m mmmmmmmmmmmmummmmmmmmmmmmmmmm- - mmmmmmmmhqbw, PERCENT EXCEEDENCE /- [ IMWI., ACTUAL LOAD DURATION CURVE """"' APPROXIMATION OF LOAD DURATION CURVE COOPER LAKE EXPANSION INVESTIGATION 5.0 COOPER LAKE EXPANSION INVESTIGATION 5.1 INTRODUCTION A review of the existing Cooper Lake Hydroelectric Project was added to the scope of work for the Grant Lake Project feasibility study to determine if additional energy generation or installed capacity could be economically developed at this site to assist in meeting the need for power for the region and specifically for Seward. The Cooper Lake Project, located about 12 air miles southwest of the Grant Lake site, utilizes head between Cooper Lake and Kenai Lake. The project came on-line in 1959 and consists of a 70' high dam on Cooper Creek at the outlet of Cooper Lake, a gated intake to a power conduit on the southeast shore of Cooper Lake, and a combination tunnel -penstock power conduit incorporating a steel surge tank extending from the intake to the powerhouse on the southwest shore of Kenai Lake. The powerhouse contains two 7,500 kW generators directly connected to Francis turbines which operate at 720 rpm and are rated at 726 feet of head. The project, as conceived in the Definite Project Report (North Pacific Consultants, 1955), includes the diversion of Stetson Creek, a tributary of Cooper Creek, into Cooper Lake and the diversion of Ptarmigan Creek (also referred to as Porcupine Creek), a small stream which crosses the power tunnel, by pumping into the power conduit. These diversions, however, have never been constructed. A license application for the project was filed with the Federal Power Commission (FPC) in 1956 and the license was issued in 1957 (FPC Project No. 2170). A condition of the license required that construction of the Stetson Creek diversion be deferred until minimum flows for preservation of the fishery in lower Cooper Creek could be established. The flows available for diversion that were subsequently established by the U.S. Fish and Wildlife Service in 1958 were 5-1 2223B determined to make the diversion uneconomical at that time and the incorporation of this feature was deleted from the license. The diversion of Ptarmigan Creek into the power conduit was not constructed. The addition to the Grant Lake feasibility study was to perform a -pre-f easi b-i 1 i ty -study to -determine -the -viability of diverting Stetson Creek and Ptarmigan Creek into Cooper Lake, -the provision -of additional generating capacity at the Cooper Lake Powerhouse, and the incorporation of the results of these studies in the Feasibility Report. ----- _5.-2- -STETSON--AND--P-TARMI-GAN—CRE_EK---D-IVERS-LONS-- 5.2.1 Hydrology The basis for the evaluation of the hydrology for the Stetson and -Ptarmigan diversions is the adjusted flow data for Stetson Creek -- i contained in the Supplemental Design Report on Reservoir Storage Study and of Diversion From Stetson Creek (North Pacific Consultants, 1958). The adjusted flow data from that study is based on the flow records at the USGS gaging station on Cooper Creek, 0.7 miles above its confluence with the Kenai River. The adjusted data developed by North Pacific Consultants for water years 1950 through 1957 was used to develop a relationship between the time of year and streamflows as a percent of average flow. From these relationships, and annual precipitation records for the years 1913 through 1957, a representative historical , streamflow record was developed for Stetson Creek. A similar record t was prepared for Ptarmigan Creek by ratio of drainage areas between Ptarmigan and Stetson Creeks. j In evaluating the water that would be made available for power generation from the Stetson Creek diversion, the restrictions and minimum flow requirements in the 1958 license amendment were assumed. It was determined that the average annual flow available from the diversion would be 22 cfs and the potential diversion rate during the 5-2 22236 low water year of 1952 would be 8 cfs. The average annual diversion rate for Ptarmigan Creek was found to be 4.8 cfs for the pumping system selected. 5.2.2 Environmental Considerations The major environmental concern for the diversion schemes is the fishery in lower Cooper Creek and the minimum flows required to maintain the fishery.. Review of the FPC license and agency correspondence received at that time revealed no apparent concern regarding the Ptarmigan diversion. The USGS topographic mapping of the project area indicates much steeper gradients at the mouth of Ptarmigan Creek than at the mouth of Stetson Creek, thus possibly eliminating fish runs for any significant reach in Ptarmigan Creek versus Stetson Creek. This prefeasibility evaluation of the Stetson diversion assumes that the minimum flows established in the 1958 license amendment for the Cooper Lake Project are still applicable. Any further investigations of the feasibility of the Stetson Creek diversion should include the necessary environmental analysis to determine whether these minimum flows are still adequate. Other environmental impacts of the diversion schemes would no doubt be assessed should the schemes undergo a more detailed level of investigation; however, at the prefeasibility level of investigation no impacts are apparent that would preclude development of the diversions. 5.2.3 Diversion Works The Stetson and Ptarmigan Creek diversions evaluated herein are essentially the same in concept to the alternatives put forth in the Definite Project Report. The Stetson diversion would utilize gravity flow for diversion of flows into Cooper Lake. The major features of 5-3 2223E the Stetson diversion would include an access road, a small concrete gravity diversion dam with an ungated spillway section and a closed ` diversion conduit leading to Cooper Lake. The significant change for the Stetson diversion from that proposed in the Definite Project Report is the use of a closed conduit versus an open channel for conveying the - water to Cooper Lake. This modification was assumed due to anticipated requirements -of -environmental -agencies and their -concern for movement, of wildlife across the diversion channel. The dam would be located approximately .6 miles upstream from the confluence of Cooper and Stetson creeks and would impound water to an approximate elevation of 1,250. A conduit approximately 8,400 feet in length would extend from the diversion dam to Cooper Lake at approximately elevation e- - Cooper Lake spillway crest elevation. A plan showing the location of 1 the dam, access road and conduit is provided in Figure II-1. The Ptarmigan Creek diversion would utilize a pumping station to pump water from Ptarmigan Creek into the power conduit leading to the powerhouse.-----It.-would _be_.located_near the point where the existing f power conduit for the Cooper Lake Project crosses Ptarmigan Creek. i Major features would include a concrete sill across the streambed, a pumping station containing 2 vertical turbine pumps and an estimated 100 feet of 18 inch diameter pipeline extending from the pumping f station to the existing power conduit. Figure II-1 shows the locations of the diversion features relative to the existing Cooper Lake Project. 5.2.4 Diversion Operations and Increased Generation The operation of the Stetson Creek diversion is assumed to be in accordance with Article 30 of the order amending the Cooper Lake Project License issued in 1958. Minimum in -stream flow restrictions are specified in this Article by the U.S. Fish and Wildlife Service. The restrictions would limit the diversion of water from Stetson Creek to that which would still maintain the following minimum flows in Cooper Creek at a point 0.7 miles from its mouth: 5-4 22238 May 30 cfs June 80 cfs July 70 cfs August 40 cfs September 35 cfs October 35 cfs November 25 cfs December -April No diversion It is further assumed that the maximum diversion rate would be 70 cfs as was proposed in previous studies. The results of an operation evaluation for the years between 1913 and 1957 show that the average annual diversion would be 22 cfs with a corresponding increased average annual energy generated at the powerhouse of approximately 10,162,000 kWh. The estimate of energy output assumes an average net head of 716 feet and an overall plant efficiency of 87 percent. The potential average annual increase of flow for the low water year of 1952 was found to be 8 cfs with a corresponding increase in firm energy of 3,695,000 kWh based on the same assumptions as for the average annual energy. The Ptarmigan Creek diversion with its pumping station is assumed to be operational during times when the flow in the creek is equal to or greater than 4 cfs. The capacity of the pumping station would be about 12 cfs. The limits are based on the flow duration curve developed for the site as well as manufacturers' pump curves for the selected pumps. A cycling mode of operation would allow for flows less than 4 cfs to be utilized in conjunction with storage capacity but would not impact the overall feasibility to a significant degree at the prefeasibility level; however, this should be further evaluated if the diversion is to be implemented. The results of the evaluation for the pumping scheme show that on an average annual basis the diversion rate would be 4.8 cfs and the generation at the powerplant could be 5-5 2223B increased by approximately 2,190,000 kWh with,a pumping energy requirement of about 876,000 kWh, thus resulting in an average annual net increase in generation of 1,314,000 kWh. 5.2.5 Cost of Diversions 0 The cost of the Stetson Creek diversion was evaluated using a preliminary layout for the diversion. works, estimating quantities required and applying unit costs to the quantities. The estimated total construction cost for the diversion. works is $6,473,000 at a i January 1983 level as shown in Table 5-1. The total construction cost i - -- -- - - includes and T5% for engineering and construe ion 25% for contingencies- - -- management, but does not include interest during construction. Assuming 3.5% interest based on Power Authority guidelines, and a 50 ' year amortization of the total construction cost and $15,000 per year for 0&M and other costs, the estimated annual cost is $292,000 at a January 1983 level. The costs for the Ptarmigan Creek diversion is based on preliminary layouts and sizes for project features. Quantities for the various .project features were estimated and unit costs were applied. Cost estimates for major equipment items.were based on experience and manufacturers' information. The -estimated --total construction-cost__for the'Ptarmigan diversion is $384,000 at a January 1983 level as shown in Table 5-2. The total construction cost includes 25% for contingencies and 15% for engineering and construction management, but does not I include interest during construction. Assuming 3.5% interest in accordance with APA criteria for a 50 year amortization of the total construction cost and $50,000/year for 0&M, the estimated annual cost is $66,400 at a January 1983 level. i i - 1 5-6 22236 I 5.2.6 Cost of Power The Stetson diversion would increase plant generation by 10,162,000 kWh per year at a cost of approximately 29 mills per kWh based on the January 1983 annual cost of $292,000. The Ptarmigan diversion would increase net generation by 1,314,000 kWh per year at a cost of about 51 mills per kWh based on the estimated January 1983 annual cost of $66,400. Based on a comparison of the levelized cost of energy from gas -fired combined cycle combustion turbines (51 mills/kWh, as derived from information contained in Table III-16 in the Technical Appendix) the Stetson diversion would be clearly economical and the Ptarmigan diversion would be marginally economical. 5.3 COOPER LAKE CAPACITY EXPANSION In view of Chugach Electric Association (CEA) owning and operating the Cooper Lake Project, the evaluation of capacity additions must take into account the regional CEA system. The report Alaska Electric Power Statistics 1960-1981, dated August 1982, lists the total CEA installed capacity at 507,800 kW and a total peak demand of 330,700 kW. The various components of the installed capacity include 421,300 kW of gas turbine capacity, 71,500 kW of steam turbine capacity and 15,000 kW of hydro capacity. The total 1981 net generation was 1,472,670,000 kWh of which 1,414,919,000 kWh was supplied by gas and 57,751,000 kWh supplied by hydro. The Cooper Lake Project has an installed capacity of 15,000 kW, the capacity that was recommended in the Definite Project Report, if the Stetson and Ptarmigan diversions were also constructed. Review of operating summaries for the years 1977 through 1981 indicate that no water was spilled from the reservoir. In addition, the operating reservoir levels experienced over the period 1977-1981 indicate that substantial additional storage has been available but not used. The unused storage could, on the average, store the additional water from the Stetson and Patrmigan Creek diversions for an entire year. In view 5-7 of the above and considering that the average plant factor for the period 1977-1981 was 40 percent, the installation of additional capacity at the powerhouse would not provide any additional energy generation over that which could be generated with the existing __equipment.___ -. In a low water year equivalent to that experienced in 1952, with a minimum reservoir elevation of 1,166, and with th e diversions from Stetson and Ptarmigan Creeks in place, the dependable capacity is less than the present installed capacity. There is, therefore, no dependable capacity benefit to -be derived from-1the- install-ati-on----of-- - - - - - additional generating equipment. In addition, It is apparent from the relatively large ,amount of gas turbine generation on-line in the CEA system at any given time, and excess gas -fired turbine capacity above the peak demand, that capacity _ and -spinning _reserves are presently.adequate-In the _.CEA system with _ respect to any potential capacity expansion at the Cooper Lake Project. 5.4 CONCLUSIONS In summary, based on these prefeasibility level investigations, there would be no additional benefits for any.capacity expansion and therefore, any expansion involving additional units cannot be justified. This being the case, a preliminary cost estimate was not developed for a capacity expansion using an additional unit or units. Also, based on this prefeasibility investigation, additional energy can be produced by the incorporation of the Stetson Creek diversion at a cost that appears to be attractive, while the Ptarmigan Creek diversion appears to be marginally attractive. The gain in energy is not large and its realization would require an application for amendment of the existing license held by CEA which includes review and continent by the agencies. Also, the feasibility of the diversions would be adversely affected by a revision in previously designated minimum streamflow requirements. 5-8 TABLE 5-1 STETSON CREEK DIVERSION PREFEASIBILITY LEVEL COST ESTIMATE SUMMARY Item 1.0 Mobilization 2.0 Reservoir Clearing 3.0 Diversion & Care of Water 4.0 Dam and Spillway 5.0 Diversion Conduit 6.0 Mechanical Equipment 7.0 Access Roads Direct Construction Cost Contingencies @25% Subtotal Engineering & Construction Management @15% Total Construction Cost Debt Service 2/ Operation and Maintenance Total Annual Cost Average Annual Energy (kWh) Cost of Energy (mills/kWh) 1/ January 1983 level. Z/ 50 years @ 3.5% interest Costl / $ 214,000 5,000 30,000 422,000 2,971,000 61,000 800,000 4,503,000 1,126,000 5,629,000 844,000 $6,473,000 267,000 25,000 292,000 10,162,000 28.7 5-9 2223B TABLE 5-2 PTARMIGAN CREEK DIVERSION PREFEASIBILITY LEVEL COST ESTIMATE SUMMARY Item 1.0 Mobilization 2.0 Reservoir Clearing 3.0 Diversion & Care of Water. -4--.-0 - -Overf-1-ow-S-i-1-1 5.-0--Pump S-tiW&V- -------- 6.0 Pipeline 7.0 Mechanical Equipment 8.0 Electrical Equipment 9.0 Transmission Line 10.0 Access Roads . _._.- Direct ... Construction Cost Contingencies @25% Subtotal Engineering & Construction Management Total Construction Cost Debt Service 3/ Operation and Maintenance Total Annual Cost Average Annual Energy Generated (kWh) Pumping Energy Required (kWh) Net Average Annual Energy (kWh) Cost of Energy (mills/kWh) January 1983 level. As power source for pumping station. 3/ 50 years @ 3.5% interest 5-10 2223E Cost l/ $ 13,000 2,000 5,000 27,000 65,000 40,000 30,000 2,000 267,000 67,000 334,000 50,000 $384,000 16,400 50,000 66,400 2,190,000 876,000 1,314,000 50.5 6.0 DAVES CREEK - SEWARD TRANSMISSION LINE 6.1 HISTORICAL DATA The City of Seward was incorporated in 1912, but it had its official beginning much earlier, on August 23, 1903. By 1905 private companies were supplying both water and electricity to the City. A hydroelectric plant located at the foot of Jefferson Street on Resurrection Bay utilized water from Lowell Creek to generate electricity. This plant has since been abandoned. In 1938, the City formed its own electric system and constructed a diesel-electric generating plant on the shores of Resurrection Bay near what is now Seventh Avenue and Armstrong Street. The Seward electric system was then in competition with the privately owned Seward Light and Power Company. The two organizations competed for customers until 1951 when the City took over the Company's system, In 1955, the City began the planning and construction of a transmission line designed for 69 kV, but initially energized at 24.9 kV, between the City and Milepost 25 on the Seward -Anchorage Highway. The construction of this line was the initial step in an effort to provide an adequate power supply for the City and for, the cities of Homer and Kenai. The plan included the construction of a hydroelectric power plant at Crescent Lake, about 32 miles north of Seward. The Crescent Lake project was later abandoned and, on June 1, 1961, Seward entered into an agreement with Chugach Electric Association to purchase wholesale power with delivery at Milepost 25, which became known as. Lawing metering station. Chugach constructed a 24.9 kV transmission line from a transformation tap off its 115 kV transmission line near Daves Creek to connect to the Lawing metering station. This line was built to 24.9 kV standards. The line continues to be the main source of electric power for Seward and numerous taps exist to serve consumers along the entire length of both the Chugach section and the Seward section of the line. 6-1 2611E 6.2 ELECTRICAL CONDITIONS The transmission line from Daves Creek substation to Seward substation has a 4/0 ACSR (Alum w/center of steel reinforcing) for its entire 40 mile length. The Chugach section of the line from Lawing to Daves ....Creek is___bui.lt as. 24_.9_kV_-_cons_truct -on using wood poles with, horizontal wood crossarms. The Seward section -of the line from Lawing to Seward substation,is built as 69 kV constructionon wood poles using various configurations such as vertical compact without crossarms, wish bone construction with crossarms, and H-f rame with crossarms. i This 24.9-kV transmission line is at its capacity limit: —The city°-s -- - current peak load of approximately 6 MW results in a line loss of 1 approximately 20%. The voltage drop during peak loading of the line is greater than 15% as shown in the Technical. Appendix Part V. However, 4 this voltage is able to be raised by load tap changers on the main incoming transformers in Seward substation. Voltage levels can also be _ra.i.sed_by_runni-ng_.Sewar_d's_.Emergency Diesel Generators, which are located at Seward substation. It is reported that in fact it has been j necessary to start these generators during peak loads to maintain reasonable voltage levels. It also has been reported that when an outage from Chugach Electric occurs, the tie is opened and once Chugach �t power is restored-, the open -circuit vol-tage-is too high to reclose with Seward's voltage levels as supplied by their diesel. These diesels are also expensive to operate. Information on existing electrical conditions was obtained from field trips, from City of Seward officials, and past report and drawings. A i one -line diagram and plan of the system as it now exists, as well as planned modifications, are shown in Figures III-1 and 2. i Various reports have been completed in the past which give a fairly complete description of Seward's system. The most recent report was ' prepared by Dwane Legg Associates in October 1982 and is titled Analysis of Voltage Drop and Energy Losses. The City Engineer of 6-2 2611E Seward also submitted information on conditions in an August 30, 1982 memorandum to the City Manager. A summary of existing reports, that became available to Ebasco is provided in Section 19. 6.3 PHYSICAL CONDITIONS The existing transmission line from the City of Seward to the substation at Daves Creek is over 25 years old. Many of the 60 foot poles from the city'to Milepost 7 have been replaced, but the poles from Milepost 7 to the metering station are the original poles and consequently are in poor condition. Likewise, Chugach's line from the metering station to Daves Creek is generally the original construction and near the end of its economic life. The transmission line is adjacent to the Seward-Ancorage highway from the city to Milepost 7 and between Mileposts 23 and 26. For the remaining length, the line is located on its own right-of-way. The transmission corridor is up to 3000 feet from the highway as shown on Figure III-2, Sheets 1 and 4. Where the transmission line is remote from the highway, access to the line for maintenance and repair is extremely difficult in the winter. In addition, portions of the line between Lawing and Daves Creek are inaccessible in the summer due to swampy conditions. Areas of the transmission line are subject to avalanche.damage. The area that it reported to be most effected is between Milepost 18 and Milepost 23. Some avalanche problems are reported near Moose Pass (Milepost 34) and the junction of the Seward and Sterling highways (Milepost 37). 6-3 2611E 7.0 LOAD FORECAST 7.1 HISTORICAL DATA Since the initial connection of the transmission line, the City has continued to purchase power from Chugach. The City's load has shown a steady growth over the years with an average annual rate of growth in excess of 10 percent from 1967 to 1980; however, since 1980 the peak load growth has been less than 5 percent per year reflecting the general economic conditions in the period. The peak demand in recent years has ranged between 5.0 and 6.7 MW with 1979 being the peak year. The system load factor is approximately 0.55 with a maximum energy consumption of approximately 27 million kWh in 1981 (see Table 2-3). 7.2 RECENT AND PLANNED DEVELOPMENTS The City of Seward has recently completed the initial site work, and construction is underway, on a new Seward Marine Industrial Park. This development is located about six miles southeast of downtown Seward where the Fourth of July Creek flows into Resurrection Bay. Approximately 260 acres have been developed at a cost of $31 million. The City anticipates that development of this industrial area, expansion of the existing small boat harbor, and the supporting infrastructure will add significantly to the City's electric demand and energy needs. 7.3 DESIGN LOAD ELECTRICAL PEAK DEMAND Section 2.3 of this report entitled "Seward Area Demand and Energy Forecast," describes the development of the electrical demand and energy forecast to be used in the evaluation of the existing and any proposed new transmission lines for the City of Seward. The load 7-1 5595E forecast extends over the 20 year planning period and includes the increased loads in the mid 1980s resulting from the industrial ' developments in the City. 1 Based on the medium growth scenario defined in Section 2.3, the maximum demand in -2003 -is-approximately-2-0 - MW and the eneergy-- requirement -As _..10.5__million kWh. 5595E 8.0 TRANSMISSION REQUIREMENTS 8.1 GENERAL The general requirements of the upgraded transmission system are to provide the following: o a means of supplying Seward's projected load growth, o a means of tying in the output of the proposed Grant Lake Hydro Project to Seward and other Kenai Peninsula loads, and o a means of accepting the output of other generation resources that may be developed (such as Bradley Lake hydro or Kenai area thermal) to meet the projected load for the Seward area. 8.2 SELECTION OF LINE DESIGN A number of alternative designs were evaluated to meet the above requirements. The alternatives evaluated and the conclusions reached concerning each alternative are given in the following paragraphs. 8.2.1 Continued Use of the Existing Line The continued use of the existing 24.9 kV line would result in substandard service voltages and high energy losses. It would be mandatory that the Seward generators be operated at peak -load times to prevent voltage levels from dropping to completely unacceptable levels. As the system load continues to grow, it would become necessary to operate Seward's diesel generators more hours each month, which will cause power costs to rise. It may become necessary to buy additional diesel generators to meet the rising load as well as to replace the existing units as they reach the end of their economic life. 8-1 5596B Correcting power factor by adding capacitors on the existing line will only cause an insignificant increase in voltage level, and minimal decrease in energy losses. This would at best be only a temporary solution and would not last for the 20 year planning period. Providing automatic voltage regulators would also be a'temporary solution and would be very expensive. --I-t would be possible..,. by__ins.talli_ng_ a ___ sufficient number of regulators, to provide proper levels of service voltage, but losses would continue to increase as Seward's load grows. 8.2.2 Convert to 69 kV Transmission Voltage This alternative would be implemented by op11 erating the existing 11ne - - -- from Law ing to Seward at 69 kV and by building a new 69 kV line from Daves Creek to Lawing or converting the existing one. A 115 kV to 69 kV autotransformer would be located at Daves Creek Substation instead of the Seward Substation. This alternative was studied for several cases using various conductor sizes and a computerized load - flow program. The results of the evaluation are given in Appendix_ _ III-1 and,are summarized below. { o The first case considered used 4/0 ACSR conductor from Daves Creek to Seward with a total load of 20 MW at Seward. The voltage drop to the Marine -Industrial Park was just over 34% and the power loss was just over 23%. Both of these values are unacceptable. I o The second case evaluated was the same as the first except that a 556 kCM ACSR conductor was used. The voltage drop at the Marine -Industrial Park was just over 18% and the system loss was 5.5%. This voltage drop is generally too high, although the power loss is more acceptable. o The last case evaluated a 1.590 KCM ACSR conductor alternative, which is a very large conductor. The system power loss was at low value of 2.8% and the voltage drop to the 8-2 5596B Marine -Industrial Park was still 15%. The voltage could be raised to reasonable levels by transformer tap changers, however, this line would be expensive to build because of the large size conductor. The studies show that to convert the existing line to 69 kV can barely be considered feasible even as a shorter term solution. In addition to the obstacles listed above, several concerns exist on using the existing line from Lawing to Seward. Some of these are as follows: o The existing line is over 25 years old and wood poles have an estimated life of 30 years. It has been reported that only few poles have been replaced between Mileposts 7 and 25. o Provisions would have to be made for supplying customers that are now fed directly off this line north of Milepost 9. o Insulators would need to be inspected and replaced as necessary before operating at 69 kV. Also, the number of discs per insulator varies from 4 to 6 on the existing line, raising the question as to varying dielectric strengths. o The line would still be subject to the avalanche conditions previously described. o There would be no emergency tie, as described in Section 10.5. o The cost of an all new 69 kV line from Lawing to Seward with a 556 ACSR conductor would not be significantly lower than the cost of a 115 kV line and would still have marginal voltage conditions. o The mechanical strength of all existing poles, even recently replaced ones, would need to be checked for adequate strength for the loading conditions mentioned in Section 9.2.4 with a conductor at least as large as a 556 kCM ACSR. 8-3 8.2.3 Combination 115/69 kV Transmission This alternative would require a new 115 kV line from Daves Creek to Lawing, a 115 -69 kV substation at Lawing, and operation of the existing line from Lawing to Seward at-69 kV. Although this alternative seems to be viable, it has all the concerns of the 69 kV line mentioned above as well as concern about the mechanical strength of the existing 4/0 ACSR conductor, as indicated by -- ---the _s-a_g--and- t-ens-i-on- c-omputer-c-alcul-ation-giv-en-_i_n -Part---V---of--the Technical Appendix. These calculations show that with the existing spans this conductor does not comply with current codes. 8.2.4 115 kV Transmission Line The voltage selected for.. the- transmission_ 1-ine-from_Daves--Creek Substation to the City of Seward substation is 115 kV. The selection of this voltage is based on the following: o Computerized load flow studies indicate this to be the optimum voltage for supplying theprojectedload growth to 20 MW in terms of maintaining acceptable voltage levels and minimizing power losses. The results of the load flow studies are presented in Part V of the Technical Appendix. The data show that a voltage drop of around 8% would occur between Daves Creek and Seward Substation. This is a very reasonable voltage drop and is within the range that can be accomodated on the 115 kV transmission line that.supplies Daves Creek. The 115 kV Daves Creek -Seward line should have lower voltage dips, compared to a lower voltage transmission line during starting of large electrical motors that may be added at the Marine -Industrial Park in the future. �4 8-4 0 The estimated life of a wood pole transmission line is 30 years. While the proposed 115 kV line is marginally optimum in terms of the 20-year estimated projected load growth to 20 MW, its economic benefits continue to increase for the remaining 10 year life of the line to effectively supply power to the City of Seward, assuming loads continue to increase with time. 0 115 kV is the voltage level of the line that supplies Daves Creek substation and thus its use eliminates the need for intermediate transformation at Daves Creek. Further, the main transmission system between the major Kenai Peninsula substations of Girdwood, Portage, Hope, Quartz Creek, Soldotna, and Bernice Lake is a 115 kv system. The proposed Seward line is, therefore, a logical extension of the existing system. 8.2.5 Configuration The type of line construction selected is the Vertical Compact construction on single wood poles. This construction is described in the EPRI Transmission Line Reference Book; 115-138 kV Compact Line Design which is shown in Part V of the Technical Appendix. This type of construction is used on portions of the existing 24.9 kV transmission line, for example, in the area where the Seward -Anchorage Highway crosses the Snow River and on the 69 kV transmission line to the Seward Marine -Industrial Park. The advantage of vertical compact line construction is that it has the least negative visual impact since no crossarms are used on normal spans. Only those portions of the line that have a lower voltage underbuild will have crossarms mounted onto the poles. However, these crossarms are for the low voltage underbuild and are therefore below the pole tops and have low visible impact. 8-5 5596E The conductor selected for the 115 kV line is 336,400 circular mil aluminum cable, steel —reinforced, also known as 336 KCM ACSR. ACSR conductors are widely used by electrical utilities and are the type used on the existing system in -Yari-ou,s.. si-zes.--, Specifically, the 336 KCM conductor selected has 30 outer strands of aluminum and 7 inner strands of steel and is designated by the code word Oriole. This conductor size was determined primarily by mechanical strength requirements rather than thermal limits due to electric loading of the conductor. This means that the line can carry more than normal load current,before overheating. 8.2.7 Mechanical Considerations The mechanical considerations of the line were evaluated using the results of hand and computer calculations on s.a_g,.cjn4.jension_s for - various conductor sizes and spans. The following were used as preliminary design parameters: NESC modified heavy loading Ice loading: I" radial Temperature: -25°F to 120*,F Wind: Up to 110 mph (31 lb/sq ft.) .Part V of the Technical Appendix gives details on this aspect of the line design. Some of the main items to be considered in line evaluation are the following: 0 The National Electrical Safety Code requires that the normal final stress be no more than 25% of rated tensile strength (RTS) stress and no more than 35% RTS for the initial stress. 8-6 5596B o The National Electrical Safety Code also requires that the final stress under ultimate load be no more than 60% of RTS; however, it is preferred not to exceed 50% RTS. o The Electric Power Research Institute guidelines for phase spacing is acceptable. This affects maximum sags. o The National Electric Safety Code clearance requirements also affect maximum sags. The smallest size ACSR conductor that meet these and other requirements is 336 KCM, Oriole for spans ranging between 400 and 450 feet. The existing 4/0 ACSR conductor was evaluated so that it might be used on existing poles, but was found to exceed today's codes and practices on, line design. Results of this investigation are also shown in the Technical Appendix. The type of insulator to be generally used with this compact type of construction is a non -porcelain type. One manufacturer's type of insulator is made of fiberglass rod and polymer compound exterior watersheds. This type of insulator has three times the strength accompanied with a weight reduction of 10 to 20 times of that of the porcelain variety. Since this type of insulator is lighter and stronger, it is less subject to careless handling and is also much less subject to vandalism. The proposed transmission line will be constructed of Class H1 wood poles with an estimated average height of 60 feet. It is presently planned that long spans at the Snow River crossing between Milepost 17 and 18 be constructed with tubular steel poles. This crossing occurs at the mouth of the Snow River as it flows into Kenai Lake. The river crossing area is swampy and many of the poles are in water. The new line is routed in the same area and similar foundation conditions can be anticipated. 8-7 5596E 8.3 PERFORMANCE EVALUATION OF SELECTED LINE ALTERNATIVE The proposed 115 kV transmission line was modeled with a load flow computer program to verify its performance for different operating conditions. The model was set up using 336 KCM ACSR conductor with resistances and reactances as shown in Part V of the Technical Appendix. The first case considered no generation from Grant take, no city diesel generation, and a total load of 20 MW (10 MW at Seward Substation and 10 MW at Marine -Industrial Park). ---T-he--r-e-su-lts-i-nd-i-cate-that--the- Y of Seward'-Cit -Seward _._mai_n__-12.4.7 voltage drop of --slightly over-8% whichcanbe corrected by the--ex-is-trng --- - load tap changers. The voltage at the Marine -Industrial Park has a drop of just over 11% which also can be corrected with transformer taps. The amount of energy loss for this condition is 0.63 MW, which is 3.2% of the 20 MW load. I The second case is the same as the first except that the Grant Lake project is on line. The results are very similar to the first case except that the load bus voltages are slightly higher. In this case Grant Lake Hydro is fully loaded and absorbs reactive power within its midrange rating. Only slight improvements in voltage at the load buses can be expected, since Grant Lake is much closer to Daves Creek (13 miles) than to the city load buses (27 to 33 miles) and the Kenai Penninsula system load is much larger. The line performance was also investigated at 10 MW and 30 MW loads to verify operation at these levels. The results of all the studies are in Part V of the Technical Appendix and show that the voltage drops and power losses under the tested conditions are acceptable for the forecast loads. 8-8 55968 8.4 CORRIDOR 8.4.1 General Plan In selecting the transmission corridor, accessibility was a prime consideration. Because of the existence of the highway generally paralleling the transmission line, access has been assumed to be by overland vehicles and not by helicopter. As mentioned in Section 6.3, access to the existing line is difficult in certain areas at different seasons of the year. In order to improve the access, the basic corridor plan uses a combination of the existing transmission right-of-way and newly obtained permits in the Alaska Highway Department of Transportation right-of-way (Seward -Anchorage and Sterling Highways). The general plan for the transmission line from the Seward Substation to Daves Creek Substation is as follows. o From the city (Milepost 0) to Milepost 7: Install new poles in existing locations next to the highway as indicated on Fig. III-2. Existing poles that have recently been replaced in this reach, and that meet detailed design criteria for the proposed 115 kV line, may be retained. o From Milepost 7 to Milepost 23: Install new poles on Seward -Anchorage Highway right-of-way as shown on Fig. III-2. The existing transmission line right-of-way is generally .to remain as is. o From Milepost 23 to Lawing Metering Station (Milepost 25), the new transmission line will follow the routing of the existing transmission line along the Seward -Anchorage Highway. o. From Lawing Switching Station to Daves Creek (Milepost 41) the new routing will generally be along the Anchorage -Seward Highway instead of the right-of-way for the existing 24.9 kV line. In some areas, the 24.9 kV line is presently routed 8-9 5596B along the highway and it may be necessary to use the existing transmission line right-of-way, due to limited highway right-of-way or other problems. Conflicts of this nature will have to be resolved on a case by case basis during final design of the transmission line. 8.4.-2 - Spec ial-_Cons-iderati.ons.._._. 8.4.2.1 Avalanches The segment of the existing line from Milepost 18 to Milepost 23 is subject to damage from frequent avalanches. The existing line is now located up to 1000 feet away from the highway on the uphi sa a as shown on Fig. III-2. The proposed new line has been located on the downhill side of the highway to place it further from the avalanche chutes, where it would receive some protection from the highway and where it can be more easily replaced if damaged by an avalanche. - - The C-i-tyof---Sewa-rd-has-tri-ed various- _types _._of___li_oe__construction in the avalanche areas. One unsuccessful construction was to build the line very heavy -with substantial pole structures. However, the conductors and poles were still knocked down by the avalanches. This happened even with avalanche deflectors located uphill from the structures. When the conductors and poles were knocked down, the reconstruction of the line has taken as much as several.days because the wood poles were broken at the snow line and pole replacement vehicles and equipment could not get to the line to effect the replacement. I... The best type of construction experienced by the City of Seward in avalanche prone areas was to design the line so that the conductors will breakawayduring avalanches without pulling the Poles and supports down. This was accomplished by installing breakway devices in the conductors and locating structures outside of the avalanche chutes. The rationale of this approach is that though an outage will still occur, the outage will be substantially less because the poles are likely to remain intact. The relocation of the transmission 55968 line downhill of the highway, within the latter's 100 foot wide right-of-way, would not only lessen avalanche danger to the line, but would also make repairs much easier and faster by making the line much more accessible. Construction of the transmission line in all avalanche prone areas must consider the access to the line and the time required to effect the repairs. During detailed design, the areas of most active avalanche chutes, would be specifically defined. This definition would permit optimum placement of supports, the consideration of special structures, and the use of long spans to reduce likelihood of pole damage and resulting line outage. 8.4.2.2 Environmental Assessment Final detailed definitions of the route for the Daves Creek -Seward transmission line will require conducting a comprehensive analysis of engineering and environmental constraints, both of which influence the final route. Various sections of this report discuss the engineering constraints considered in the feasibility phase of the Daves Creek -Seward transmission line design. Though efforts were made during the study to consider environmental constraints, no detailed environmental evaluation of the proposed Daves Creek -Seward transmission line has been conducted. Therefore, the transmission line route depicted in Figure III-2 is subject to change following a detailed environmental evaluation.. An environmental study of a proposed transmission line involves the investigation of the topography, geologic hazards, soils, land use, socioeconomics, aesthetics, cultural resources, aquatic and wildlife resources. The proposed Daves Creek -Seward transmission line described herein is, for the most part, routed along the right-of-way of the existing transmission line or within the right-of-way of the transportation corridor. Consideration in this proposed route selection has been given to the topography, geologic hazards, land use and avalanche potential. The major emphasis of the required detailed environmental study should be an analysis of the proposed line's impact on aesthetics, cultural resources, and aquatic and wildlife resources. 8-11 5596B The design selected for the proposed transmission line has considered > the impact on the aesthetics, and components of the transmission line ' have been selected to minimize the impact by Using single wood poles, / and low profile substation configuration that can easily be screened by | the existing vegetation. . During the detailed environmental evaluation, coordination with the relevant federal, state and local agencies would be continued and the / | final transmission line and equipment location would be adjusted, if necessary. The detailed environmental study Would need to begin with the onset of engineering design and has to be completed in a timely / incurred as a result of the environmental evaluation, then the � engineering/construction schedule could be delayed. . 8.5 6EOTECHNICAL CONDITIONS - This section -characterizes- the_genlUgic_dnd�spi-l-s_conditinDs forth8�_ Seward to Daves Creek transmission line corridor. The regional geology � is presented in three ports: morphology, stnatiQrdphy and lithology, and geologic structures. Seismicity is also addressed. ( 8.5.1 Morphology The morphology of the project region is generally of sub -arctic, glaciated terrains' Broad U-shaped valleys dissect the mountain ranges and form lowlands with lakes, ponds, and streams. Elevations in the project region range from sea level at the City of Seward to over 5000 ' feet in the adjacent mountains. Much of the region Was stripped clean by the 0oVe0an1 of Olacfers, laaViOg bedrock exposed over large areas. The transmission line route lies completely in lowland regions, which are typically elongated with varying amounts of 1DfilliOg' Streams are common in the lowland areas, as are lakes and ponds' Small bogs, 8-l2 55968 formed in bedrock depressions resulting from glacial scour, are common on the ridge tops. Such bogs are also present at lower elevations, one example being Tern Lake. 8.5.2 Stratigraphy and Lithology The bedrock in the project region is a complex assortment of metamorphosed sandstone, siltstones, and mudstones interbedded with volcanic basalts and detritus: The predominate rock types in the project region are low grade metamorphosed sedimentary rocks, including slates and meta -sandstones. Unconsolidated surface deposits are relatively rare in the project area and are typically mixtures of silt, sand, and gravel. Soils in the project area vary from very gravelly well drained soils to no soil cover and as such are classified as non frost susceptible. Frost heave should therefore not be a major design parameter. 8.5.3 Geologic Structures The predominant geologic struture in the transmission line corridor is the "Kenai Lineament". "Kenai Lineament" is used to refer to the Trail Lakes valley, which is a north -trending valley that extends from the City of Seward to Upper Trail Lake. The trend of the valley is nearly parallel to the north-northwest fault set observed in the region, and the Kenai Lineament may represent one of these fault zones that was extensively eroded during the glacial period. It is unlikely that the Kenai Lineament represents a major, active fault. More likely it is a glacial valley whose orientation and location followed the north-northwest trend of the major fault set observed in other areas. Features observed throughout the area during the field investigations repeatedly emphasized the effects of.the great thickness of ice that once moved through the region, with minor differences in rock strength or fracturing resulting in major differences in the extent of erosion in response to the forces of moving ice. B-13 5596B 8.5.4 Seismicity The Seward to Daves Creek transmission line corridor lies completely within earthquake zone four, which indicates very severe seismic conditions. 8.6 RIGHT-OF-WAY The location of the 115 kV line, as discussed in the corridor section, will require rights -of -way for the line and the substations. 8.6.1 Alaska _Department of -Transportation The Department of Transportation built the Seward and Sterling Highways upon which new poles are to be set. The highway right-of-way is generally 200 ft. wide. Placement of poles within the highway right-of-way is an important part of this proposal. The following noteworthy_ information was received verbally from the Alaska Department of Transportation. o State accommodation policy (Alaska Statute 19) allows public utilities to put poles into,highway right-of-way under permit _from. the Department. o Poles should generally be at least 30 feet from the edge of the travelled way. o It is preferred that utility poles be only on one side of the road. o There are no apparent plans for major construction projects from Milepost 7 to Daves Creek. o The highway between Mileposts 18 to 23 is not closed too frequently due to avalanches. 8-14 5596B o It would take 2 to 4 weeks to process a permit for pole easements. o Alaska Department of Transportation accepts National Electric Safety Code. Minimum required clearance at crossings is now 18 feet with probable increase to 20 feet next year. o Costs associated with Department of Transportation inspection of work in their right-of-way will be charged to the owner of the line. 8.6.2 Other Agencies It is generally planned that a minimum amount of right-of-way will be required from the Alaska Railroad. The City of Seward reports mixed success in obtaining right-of-ways in the past. However, it may be possible to obtain permits, as is reported to be done on the 345 kV intertie that is just beginning to be constructed between Healy and Willow. Some right-of-way will be required from the forest service. Special use permits for the right-of-way can be applied for following forest service procedures which consider environmental, engineering, and compatible use considerations. Some right-of-way may be required from private property owners in areas where the highway right-of-way is very narrow or when land is needed for a substation. Some right-of-way will be required on city property and roads which should not be a problem. The existing Chugach Electric 24.9 kV transmission line runs mostly in its own right-of-way. Since some of the new line would be located on Chugach's right-of-way, easements or some other forms of agreement will be required with Chugach and the forest service on whose land a major portion of the Chugach line is located. Further details are presented in Section 8.8 on Interface with Chugach Electric Association. 8-15 5596B 8.7 SUBSTATIONS AND SWITCHING STATIONS 8.7.1 City of Seward Substation The City of Seward Substation now provides for switching and transformation -of the, existing _24.9_kV incoming transmission line. In order for this substation to be able to accept the 115 kV transmission dine, the following additional equipment will be added, as shown on the one -line diagram, Fig. III-1: o Two 115 kV to 69 kV, 15 MVA autotransformers o Two 1-15 kV circuif switcfiers o One 69 kV circuit switcher There is enough room for this equipment within the existing substation area. However, the layout and specific requirements will be defined during the final design. Fortunately, the 24.9 kV side of this sub..station__i_s__a_l_r_eady. designed for_.69._.kV__operation ,_ Th, ,s_ includes_ the two 7.5 MVA main transformers that have a dual voltage (24.9 kV/69 kV) primary windings. Based on the assumption that both transformers can be used to supply the load, they should have adequate capacity for the next 20 years if most of the major load growth takes place at the IY Seward Marine-I-ndustrial -Park.-- At sometime -in -the-future, -a -third transformer may be required to provide reserve capacity for maintenance in case of equipment failure. The Seward Substation would have two transmission lines connected to it after completion of the proposed work. One would be the main incoming 115 kV supply line. for Seward and the other would be the outgoing 69 kV line to the Seward Marine -Industrial Park. The available fault short circuit duty will be increased substantially from its present value as a result of these modifications at Seward Substation. Part V of the Technical Appendix, contains the results of a study of worst case conditions for a fault. From this study, it is 8-16 5596E concluded that the circuit switchers on the 69 kV side of this substation (rated 4000 Amp) will be able to interrupt this new fault value of 1495 Amp. The equipment on the 12.47 kV side of the substation will still be adequate, since the available fault duty is reduced to about 100 MVA by the 69 kV to 12.47 kV transformers. 8.7.2 Lawing Metering Station This station now serves as a metering point between the City of Seward's system and Chugach's system. This station also has a 24.9 kV recloser with fused bypass. This recloser is radio controlled from Seward. If the metering point for the new 115 kV line is located at the Daves Creek substation then no new equipment will be required at Lawing. 8.7.3 Grant Lake Hydro Switching Station This switching station would be a new station and would function as the 115 kV tie-in point of the Grant Lake Hydro Power to the Kenai Peninsula power grid. The main new equipment that would be installed would be three 115 kV disconnects. One 115 kV disconnect would allow the 1.2 mile long 115 kV transmission line from Grant Lake powerhouse switchyard to be disconnected from the 115 kV line running from Daves Creek to the City of Seward. One of the other 115 kV disconects would function to isolate Grant Lake and the City of Seward loads from Chugach's system; this could prove to be of great benefit when problems on Chugach system occur, because it would allow the City of Seward to still receive power from Grant Lake Hydro plant. The third switch would allow Seward to be disconnected for problems or maintenance and still allow Grant Lake Hydro to stay on line by supplying power to Chugach's system, if so desired. The arrangement is shown on the one -line diagram Fig. III-1. 8-17 5596B 8.7.4 Daves Creek Substation The existing Daves Creek Substation is part of Chugach Electric Association's system and serves as the source of power for the 24.9 kV transmission line that supplies the City of Seward. The incoming -voltage to this substation_is_115_.kV which comes from a tap on the 115 kV line between Portage and Quartz Creek Substations. - - With the proposed transmission line this substation will serve as the tie --win point to the Chugach System. The new major equipment required at Dave s Creek is a 115 kV circuit breaker, revenue metering equipment, - - — and equipment for termination of tof this he 1T5 kV line. The exac oca�ron equipment would need to be coordinated with Chugach Electric during detailed design phases. As a result of Grant Lake Hydro, the three phase short circuit capacity at Daves Creek would be increased from the present 324 MVA to - approximately-363 MVA.- at--1-1-5-_.kV_._as_:shown.-..i--,--- Part ,V of the Technical Appendix. This small increase is not anticipated to have a severe impact on this substation. 8.7.5 Milepost Nine Substation The existing-12.47 kV distribution line, that runs north out of the city, ends at Milepost 9. This line serves customers along its route. From Milepost 9 to the Lawing Metering Station, Seward customers are i served from the 24.9 kV line. The customers along this 16 mile section could be served by installing a transformer at Milepost 9 to step up th e 12.47 kV voltage to 24.9 kV and connecting the high voltage winding to the existing line.. The 24.9 kV recloser at Lawing will be opened. This will mean that the normal power flow through this substation will f be from the city out to Lawing. During emergency operation, when the 115 kV line is out of service but the 24.9 kV line is still in service, the 24.9 kV recloser at Lawing would be closed and power would be supplied to the city and all 5596B customers between the city and the Lawing Switching Station through this substation. The following major equipment is envisioned at the Milepost Nine Substation: o One 3 MVA, 24.9 kV to 12.47 kV transformer with load tap changer. o One 12.47 and one 24.9 kV fused disconnect switches. The exact location of this substation will be determined during detailed design. 8.8 INTERFACE WITH CHUGACH ELECTRIC ASSOCIATION In order to be able to perform the investigations presented in this report, the following technical information on Chugach's 115 kV transmission system and Daves Creek substation was obtained: o The short circuit duty at Daves Creek Substation on the 115 kV side is 324.5 MVA for a 3 phase fault and 294.1 MVA for a phase to ground fault. o The 115 kV line tapped to Daves Creek substation can handle a load increase of about 30 MW. Additional and updated information will be required for detailed design activities connected with the new 115 kV transmission line serving Seward. 8.8.1 115 kV Connection at Daves Creek The design of the substation for connection at the new 11.5 kV transmission line to Seward will have to be coordinated with Chugach Electric. If the new 115 kV transmission line is generally routed in the highway right-of-way as shown in Figure III-2, the existing Chugach 24.9 kV transmission line from Daves Creek to Lawing will not be 8-19 5596E changed, except between Mileposts 36 and 39. In this segment the old 24.9 kV line would be underbuilt on the new 115 kV line, and ownership of this line and the associated right-of-way would have to be agreed upon with Chugach Electric Association and the Alaska Power Authority. If the new 115 kV line will not be owned by Chugach Electric, then the best location for revenue metering would be at the Davey Creek substation area. If negotiations with Chugach conclude that the entire existing 24.9 kV transmission line and right-of-way between Daves Creek and Lawing be acquired by the Alaska Power Authority, Chugach would be entitled to -- compensation for this line. A detailed evaluation of this trans -miss -ion -- line and property right would be required. It is estimated, on a gross I preliminary basis, that the cost of acquiring this line could amount to approximately $200,000. Since the 24.9 kV line is-located.on a right-of-way leased from the Forest Service, no cost for land is included in this estimate. The cost of acquiring this transmission line is not. included in the es-t-imate -oVthe--cost - of -.the--new 11.5_ kV_ transmission line to Seward. 8.8.2 24.9 kV Connection at Lawing The existing interface with Chugach is at the Lawing Metering station at Milepost 25. Customers south of the metering station are served by Seward and those north of the station are served by Chugach. Service of customers by the respective utilities will not change if the 24.9 kV line south of Lawing is energized from the City and the 24.9 kV breaker at Lawing is left open. if this arrangement is followed, the interface between Chugach Electric and the City of Seward can remain as it is except that the intertie breaker would normally be left open. The breaker could be closed for emergency operation. The existing revenue metering equipment could remain as is, if this proposal is accepted, to serve for billing of emergency power. The new metering for normal power would be at Daves Creek. Should emergency operation be desirable from Seward towards the 24.9 kV Chugach system, some minor additions will become necessary. M.E 9.0 SUBTRANSMISSION REQUIREMENTS 9.1 EXISTING 12.47 kV LOADS FROM CITY OF SEWARD TO MILEPOST 9 The 12.47 kV distribution line, from Milepost 1 in Seward to around Milepost 9, services loads along the highway going north of Seward. This line can be underbuilt on the new 115 kV transmission line to Milepost 7 and from there will remain as an underbuild on the old 24.9 kV line poles to Milepost 9 (Fig. III-2). 9.2 EXISTING 24.9 kV LOADS FROM MILEPOST 9 TO LAWING METERING STATION The substation at Milepost 9 will step-up the voltage from 12.47 kV to 24.9 kV and service.the small loads along the next 16 mile section of highway (Fig. III-2). In most locations this line section could remain as it now exists. However, in some locations it would need to be underbuilt on the new 115 kV transmission line. This line passes through the high avalanche area betweem Mileposts 18 and 23. In this area, the 24.9 kV line could be placed underground to improve the reliability of this line for use as an emergency power source for the city as discussed in Section 9.5 on emergency operation. 9.3 24.9 kV LOADS FROM LAWING METERING STATION TO DAVES CREEK SUBSTATION The loads along this 15 mile line section can continue to be served by Chugach at present. In those areas where the proposed 115 kV and the existing line occupy the same right-of-way, for example from Milepost 36 to 39 and 25 to 26, the 24.9 kV line could be underbuilt on the new 115 kV transmission line. However, most of the line would remain as it now exists (Fig. III-2). 9.4 SERVICE DURING CONSTRUCTION If the construction of the new 115 kV transmission line can be completed in the near future, service to the City can probably be maintained during construction, by use of the Seward Diesel Power Plant 9-1 5597E with all 3 machines operating. As Seward's load increases, the ability of the diesel plant to meet the load will become more questionable. Most of the new line is planned, to be installed separately from the existing 24.9 kV line, which helps to provide service during construction since the latter can be kept energized. However, there are areas where the new line will be built on the right-of-way of the old line. Some possible considerations for minimizing service distruptions are a5 follows: o Rent or purchase additional diesel generators that can be used to provide service during line outages. Either small units - - for res-i-dential -loads--or large units for -in-city-use-can-be - -- - considered. i o Schedule line outages for minimal cutover time. o Maximize work during summer months when load is lower and effects of outages are less severe. ! o Develop a sound approach regarding work around energized lines i versus time of service outages. 9.5 EMERGENCY OPERATION With the substation at Milepost 9 installed, limited power transfer between Seward's and Chugach's system can be provided should service from the 115 kV line be interrupted. This emergency arrangement would use the existing 24.9 kV line from Daves Creek to Milepost 9 and the existing 12.47 kV distribution line from Milepost 9 into the city. By using of this emergency tie and the city's diesel generator sets, two sources of emergency power would be available. Since parts of the I existing 24.9 kV line are in high avalanche areas, its reliability will be improved by installing underground cable sections, totaling 9-2 5597B approximately 3 miles, in the vicinity of the avalanche chutes. The location of these areas would need to be better defined during a more detailed level of design. The capacity of this emergency supply source would be limited mainly by the 9 mile section of the 12.47 kV, #2 ACSR line. During detailed design, the maximum line loading capacity and stability would need to be studied further. An automatic load shedding system would need to be incorporated with this emergency tie, the existing diesel generators and a determination of priority loads. See Part V of the Technical Appendix for some preliminary load flow computer runs of emergency operation. 9-3 5597E 10.0 TRANSMISSION LINE COST ESTIMATE AND SCHEDULE 10.1 COST ESTIMATE Feasibility level capital costs and operation and maintenance costs were developed for the selected transmission line described in Section B.O. The capital cost estimate includes the direct construction costs of the transmission line and substations described herein, indirect construction costs, contingency and engineering and owner administration costs. The cost estimate is an overnight price estimate with the escalation during construction shown separately. The costestimate is shown on Table 10-1 and shows a total cost of $12,074,000 in January 1983 dollars. 10.2 OPERATION AND MAINTENANCE COST An estimate of the annual operation and maintenance cost for the transmission line was made which considered the environment in which the line exists, the topography, and the need for a reliable power supply. The annual cost for O&M is $250,000 which provides for adequate maintenance equipment and manpower to service the line. 10.3 SCHEDULE Fig. III-3 shows the schedule for design and construction of the new transmission line. The earliest the line tan be in operation is the fall of 1984 which assumes that environmental studies, and preliminary design studies are initiated in the spring of 1983 so that permits for the necessary right-of-way can be obtained and construction begun in the spring of 1984. 10-1 5598E TABLE 10-1 COST ESTIMATE FOR DAVES CREEK-SEWARD TRANSMISSION SYSTEM - 115 kV ' FERC ACCOUNT _ DESCRIPTION_ _ TOTAL COST($)./ i 350 Land and Land Rights $ 270,000 I 352 Station Structures and Improvements 73,500 353 Substation and Switching Equipment 1,426,300 ) 354 Steel Poles/Towers 1,160,450 I' - -- --- - 355 Wood Poles Fixtures 2,32 ,2 356 Overhead Conductors/Devices 3,084,100 357 Underground Conductors/Devices 245,000 Indirect 461,500 Engineering & Environmental, 1,218,650 Construction Management, I Owner_ Administration _ Contingency 1,539,000 j I Project Subtotal;/ 11,798,700 Escalation during construction 3/ 275,300 Total Capital Cost 12,074,000 /January 1983 price level 2/Represents overnight cost in January 1983 dollars 3/Escalation based on project schedule shown in Fig. III-3-and an annual inflation rate of 7% i 10-2 5598B LO .-. �r 4- 0 F- - V) O O O O O O O O O O O O O O O O O O O O O O O O O O O 4-3 U O O O LO d 00 cM O O O M O) O ci o n n n w n w n n N J O LO LO M N N N LO Lp cn I d r" I" m r-I N r M N M V) CV r sy O H 69- H V) M 00 M O O Il_ C) N C) M Cl C:)ko CD O O O O O O LO C) LO Lo O LO O Z CV M N r M d 3 LLJ > >- Y I r--+ C)LO Cl CD C) C) CDLO Lf) M I LO I— M r Cl O LO O O h LLJ r• Z O O N d' LLJ r- d w w tY O t p O C > I CY r N V) s;- W LLJ V.) 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TO QUARTZ CREEK SUBSTATION HYDROELECTRIC GEN 7 MW 4,16 kV -GRANT LAKE POWERHOUSE 9 MVA & 115: 4,16 kVSUBSTATION SEE FIGURE 17-23 it GRANT LAKE HYDRO LAWING METERING SWITCHING STATION CIRCUIT CITY OF SEWARD SUBSTATION SWITCHING STATION (MILE POST 25)SWITCHER r-1 (MILE POST 27) 10 MVA r-y-y-) 115:24.9kV 24 9 kV DAVES CREEK SUBSTATION (MILEPOST 41) WAAMEN 115 kV AS NOTED EXISTING - - - - - - - EXISTING TO BE REMOVED EXISTING LOADS INCLUDING MOOSE PASS 1 1 �_T 15MVA 1 24.9 kVIS: MILE POST 7! ------- < 169 kV (TYP 2 TRANSF) i CIRCUIT SWITCHER EXISTING LOADS 24.9 kV 3 MVA 24.9:12.47 kV MILE POST NINE SUBSTATION T I - EXISTING LOADS 69 kV (EXIST 24.9 kV)j CIRCUIT CIRCUIT SWITCH:11 WITCHER 75 MVA �_l 7.5 MVA 69/24-9: 69 / 24.9: -71" T 12-47 kV 12.47 V 12-47 kV 2 Li1=1 (TYP) 3- PLACES 3.25 MVA 12.47: 2.4 kV EXISTING LOADS EXISTING LOADS I L 2.4 kV DIESEL DIESEL DIESEL GEN I GEN 2 GEN 3 2.6 MW 1.2 MW 1.2 MW TO SEWARD MARINE-IND PARK N Ld DAVES CREEK SUBSTATION STERLING HWY w z v l36 <8> de ------------- :55�- <�> MOOSE PASS 3 ui z TO GRANT LAKE H.E.P. UPPER TRAIL LA 28 GRANT LAKE HYDRO SWITCHING STATION <0> a) TERN LAKE w (MUD LAKE) 3: UPPER TRAIL LAKE LOWER TRAIL LAKE w N kk*� Wm 1-2501,000 119WE NEW TRANSMISSION LINE EXISTING TRANSMISSION LINE ROAD RAILROAD O MILEPOSTS COMBINATION OF NEW & EXISTING TRANSMISSION LINE 1000, Ol 1000, 2000, 3000, SCALE SEWARD TRANSMISSION LINE ROUTING PLAN DATE FEB 1983 F-1 w z H Q r It z a \`l LOWER Z LAKEL m -"- -'-' FOREST SERVICE WORK CENTER LAWING SWITCHING - f'�-- �►RSTRIp STATTRAIL RIVER OW RIVER Q /� 14 SEE NOTE KENAI LAKE r wo m W ul 57 NOTES: [INDICATES :AREA OF FREQUENT AVALANCHE ACTIVITY LEGEND ® ®- NEW TRANSMISSION LINE '�-----+ EXISTING TRANSMISSION LINE ROAD RAILROAD 1 O MILEPOSTS COMBINATION OF NEW a EXISTING TRANSMISSION LINE 1000' 01000' 2000' 3000' SCALE rlwk Z - MATCH LINE 9, SHEET 4 ci Ln 7,4 - iT GROUSE CREEK /�KAIPo T R:PORT SEWARD SUBSTATION RESURRECTION GENERATING PLANT RIVER 1-"00-4-1� -�-�� mlus ----�~-^ --'----/ 9-suasTm'zow CREEK LMON v LEGEND NEW TeAwSposszow Lzws -�----��- EXISTING TRANSMISSION LINE �~�~��— ---'----- noxo nxlLRQvD r~\ mz�spuSTs ' �� RESURRECTION oxx 0--0 COMBINATION OFNEW @EXISTING TRANSMISSION LINE 1000, ' ' ' o' SCALE ALASKA POWER AUTHORITY z m GRANT LAKE HYDROELECTRIC PROJECT CITY OF SEWARD SEWARD TRANSMISSION LINE ROUTING PLAN ABOVE SHEET 3 DATE FEB 1983 FIGURE 1-2 EBASCO SERVICES INCORPORATED 115 KV VERTICAL COMPACT WITH UNDERBUILD 115 KV VERTICAL DELTA COMPACT (RESURRECTION BAY RD.) �SURRECTION' RIVER D .` O� 115 KV VERTICAL COMPACT 115 KV VERTICAL COMPACT LARGE ANGLE 115 KV VERTICAL COMPACT DEAD END 1 FOURTH OF - JULY CREEK i SEWARD MARINE INDUSTRIAL PARK 11 ® NEW TRANSMISSION LINE ®-----®- EXISTING TRANSMISSION LINE ROAD RAILROAD O MILEPOSTS COMBINATION OF NEW & EXISTING TRANSMISSION LINE 1000' 0' 1000' 2000' 3000' SCALE I GRANT LAKE HYDROELECTRIC PROJECT I SEWARD TRANSMISSION LINE ROUTING PLAN SHEET 4 DATE FEB 1983 FIGURE 11-2 EBASCO SERVICES INCORPORATED __ __ __ _ i i i i, _ _ _ __. __ _, _ __ __ � _: _ I I _. _ .. _ _ _. _ _ i j-- - -- __ _ � I I_ __ ' �i j �j �� I .; '� �. __ - . __ -- - ---- - -- ------ -- - -- _- '_. I __ __ -sc I I 1 I WORK ACTIVITY folau low 93000a I FEASIBILITY ANALYSIS logo Mall son C.MAJOR EQUIPMENT D.DETAIL DESIGN IV CONSTRUCTION A. TRANSMISSION LINE C. ENEAGIZATION MAJOR EFFORT ------- CONTINUING EFFORT L ' 4 � Y 1 V ' a N � � � t , L 11.0 EXISTING SITE CONDITIONS 11.1 GENERAL The project site is located on the Kenai Peninsula approximately 50 air miles south of Anchorage and 25 air miles north of Seward (see Figure IV-1). The site is adjacent to the Seward -Anchorage Highway and the Alaska Railroad line connecting Seward to Anchorage. The major project features lie between Grant Lake, which forms the upper reservoir, and Upper Trail Lake, which is the tailwater. 11.2 TOPOGRAPHY The Grant Lake project is located in the mountainous terrain that comprises the Kenai Mountain Range (see Figure IV-2). The major mountains that form the Grant Lake drainage basin are Lark Mountain to the north and Solars Mountain to the south. Both peaks rise above elevation 5000 feet and result in the fairly steep terain that surrounds Grant Lake. Grant Lake consists of upper and lower portions (referred to as Upper and Lower Grant Lake) nearly separated by a natural constriction and an island at the midpoint. The total area of the lake is nearly 1700 acres. Grant Lake has a surface elevation that fluctuates between 691 and 700 feet (mean sea level), and depths nearly as low as elevation 400. Its drainage area is 44.2 square miles, measured at the USGS gaging station on Grant Creek. Proceeding westward from Grant Lake to Upper Trail Lake over a horizontal distance of approximately 3,000 feet, the terrain rises abruptly to approximately elevation 900 and then slopes less abruptly to the Trail Lakes at elevation 467. The Trail Lakes valley is a long north -south trending valley that extends from Seward to the site area. Trail Lakes consist of an upper and lower section, referred to as the Upper and Lower Trail Lakes. They are separated by a narrow 11-1 2373E constriction at the midpoint. Bathymetric surveys across Upper Trail j Lake adjacent to the powerhouse cove -show the lake to be very shallow at that location. Depths generally range from 4 to 6 feet. Falls Creek, which was evaluated for diversion into Grant Lake, has a varied topography from its headwater to its confluence with Lower Trail - - Lake, 7-1/2 mil -es away. --At -its headwaters, which originate at... elevation 3800, -and for its first 2 miles Falls Creek drops abruptly at a 12% gradient, flattening to a 7% gradient for the next 4 miles, and ultimately a 6% gradient for the last 1-1/2 miles. Falls Creek lies in a steep sided valley cut in the surrounding mountains with the exception of the last 1-1/2 miles, where the surrounding terrain is _relatively_ flat.. The Falls Creek drainage area is 11.8 square miles, measured at the streamgage located at the Seward -Anchorage Highway bridge. - 11.3 GEOLOGY A detailed discussion of the geology of the area on both a regional and project -specific basis is presented in Section 14.0. A brief discussion of some of the more salient features is presented herein. The project area is typical of -sub -arctic, glaciated terrain consisting ' of U-shaped valleys with lowlands consisting of lakes, ponds and streams (see Figure IV-10). Overburden in the project area is either nominal or non-existent due to the stripping action of the glaciers. The bedrock in the project area is a complex assortment of metamorphosed sandstone, siltstone, mudstone and occasionally i fine -ground volcanic rock. Where overburden exists, it consists of glacial till, peat bogs and occasional unconsolidated alluvial deposits l of silt, sand and gravel. 11-2 2373E The orientation of the bedrock in the project area is consistent, with most units dipping approximately 50 degrees to the east and having strikes approximately north 5 degrees east. Joint orientations throughout the area vary widely. Fault and fracture zones are present in the project area and follow two general directions, as shown on Figure IV-10. One set trends northeast and the other north-northwest. 11-3 2373E 12.0 ALTERNATIVE PROJECT ARRANGEMENTS 12.1 EARLY STUDIES Development of the hydroelectric potential at Grant Lake has been the subject of study since the 1950's when it was considered as one of several energy supply alternatives for the Seward area. Chugach Electric Association filed preliminary permit applications with the Federal Power Commission in the 1950.'s and 1960's for the Grant Lake project development, along with three other hydroelectric developments in the same general area (filing for Grant Lake was done in 1959). In 1954 R.W. Beck and Associates performed a preliminary study of the development of Grant Lake and concluded that the project would be feasible (Beck, 1954). Based on very preliminary information, Beck recommended a two -staged development at Grant Lake. This consisted of raising Grant Lake by constructing either a concrete -faced -rockfill dam at the outlet of Grant Lake or an arch dam -downstream of the falls in Grant Creek. As part of this development, a powerhouse would be constructed on Lower Trail Lake to accommodate one half of the potential power at the site, with provisions to allow for expansion to the full potential of the site. The initial water conductors were to have been either sized for the full project development or else for the reduced capacity and thus requiring future penstock construction. More recently, in 1980, CH2M Hill completed a prefeasibility study of hydroelectric development at Grant Lake for the City of Seward (CH2M Hill, 1980). This study concluded that constructing a hydroelectric project at Grant Lake would present definite economic benefits to Seward; however, such a project alone would not generate enough energy to meet Seward's energy needs. The study report recommended proceeding with a detailed project feasibility study and submittal of a FERC license application. 12-1 2266B The investigations that were performed by CH2M Hill to arrive at these conclusions and recommendations consisted of the following: Preliminary reconnaissance investigations were performed on several development alternatives. These were: development of Crescent Lake, Grant Lake, Ptarmigan Lake and a combination development of Grant and Ptarmigan -Lakes. Based on environmental and economic considerations, Grant Lake -plus the diversion of nearbyFallsCreek into .Grant Lake was selected for further development. From preliminary hydrologic and power operation studies, CH2M Hill concluded that Grant Lake should be raised by constructing a 68 foot �. high concrete -faced rockf-i-11 dam at its natural outlet and a-3 -- oot high rockfill, concrete -faced saddle dam near Portage Trail on Grant Lake. The spillway crest on the main dam would be at elevation 750 resulting in an available reservoir capacity of 78,000 acre-feet between elevation 750 and elevation 700. As previously mentioned, flow from the Falls Creek drainage basin would be diverted into Grant Lake. _ ____-_The study- con.cluded__that. a. two__unit__abov_eground concrete powerhouse to accommodate an average flow of 380 cfs would be required. Power would be transmitted from the site over a 69 kV transmission line to Seward's Falls Creek metering point. CH2M Hill studied four subvariations to thisGrantLake development. These pertained to the location and elevation of the powerhouse, intake and, consequently, the energy output and length of the flow line. CH2M Hill's final recommended project layout brought the flow through an intake canal to the saddle dam. An intake structure at the saddle i dam brought this flow into a low pressure pipeline and high pressure penstock, to a powerhouse located approximately 2000 feet upstream of the outlet of Upper Trail Lake. This general configuration served as the starting point of Ebasco's detailed feasibility work. 12-2 2266B 12.2 INTERIM REPORT STUDIES Upon receiving the Power Authority's authorization in Septemer, 1981 to proceed with detailed feasibility studies, Ebasco retained R&M Consultants, Inc. of Anchorage to initiate preliminary aerial and ground surveys of the Grant Lake project area. Under Ebasco's direction R&M also performed limited field geotechnical studies. The purpose of these programs was to obtain a sufficient amount of site information early in the study to support the development of conceptual -level project alternative arrangements and cost estimates. A selection of one project arrangement for more detailed studies could then be made. During the ensuing period from October 1981 through February 1982, six alternative arrangements for the Grant Lake project were developed by Ebasco which were presented to the Power Authority in the Interim Report in February 1982. The purpose of the Interim Report was to: 1) describe the results of the preliminary feasibility studies conducted through February 1982; 2) present a comparison of the alternative project arrangements for the development of the hydroelectric potential at Grant Lake; and 3) recommend one alternative for further detailed feasibility studies. The project arrangements that were developed are identified as Alternatives A through F on Figure IV-3. Alternatives A, B, C, and D would use only the inflow to Grant Lake for power generation; Alternatives E and F would utilize Grant Lake inflow plus inflow diverted from Falls Creek into Grant Lake. Alternatives A, B, and C include the construction of a main dam at the natural outlet of Grant Lake with a saddle dam across a low divide approximately 1.1 miles north of the main dam. The differences between these three alternatives consist of the type and alignment of the power conduit and the location of the powerhouse on Upper Trail Lake. Alternative D 12-3 2266B would utilize the existing lake level and provide for regulation by means of a low level lake tap, thus not requiring dams. The power conduit for Alternative D would consist of an inclined tunnel to a j powerhouse in the same location as that used for Alternative B. 1 Alternative E would combine the diversion of Falls Creek with Alternative A (raised lake level) and Alternative F would combine the diversion of Falls _Creek -with Alternative_D (lake tap with no_dam5) I From the results of these studies it was concluded in the Interim ' Report that all of the alternatives are technically feasible. Alternative D, the lake tap scheme, was shown to be the most economical --based on the cost of energy, and also the most ac-ceptabl-e--f-rom- t e-- ---_ --- --- --- standpoint of potential environmental impacts. Alternative.F, which j consists of Alternative D plus the Falls Creek diversion, was shown to have a greater installed capacity than_D with only a slightly higher energy cost. It was therefore recommended in the I.nterim Report that Alternative F be developed through detailed feasibility studies. i Subsequent detailed optimization studies described in Section 16.0, however, concluded that a refined Alternative D is actually preferable and is presented in Section 17.0 as the recommended project arrangement. Descriptions of all the alternatives are presented in Sections 12.3 and 12.4. Section-12.5 presents the.c.omparati.ve_,constructi.on costs -for -the alternatives, as developed and presented in the Interim Report. 12.3 GENERATION WITH GRANT LAKE INFLOW ONLY - ALTERNATIVES A, B, C AND D Four of the six alternatives evaluated in the Interim Report would develop the project site through the regulation of only the naturally occurring inflow to Grant Lake. The general location of each of these alternatives is shown on Figure IV-3. Three of these alternatives involve raising the existing level of Grant Lake approximately 45 feet to elevation 745 by means of a dam at the natural outlet of the lake 12-4 2266E (referred to as the main dam) and another smaller dam in a low saddle area (referred to as the saddle dam) about 1.1-mile north of the main dam. The crest elevation of both dams would be elevation 766. For each alternative, a power conduit would convey water from Grant Lake to a powerhouse located on Upper Trail Lake. Three alternative locations for the location of the power.conduit and powerhouse were investigated. These are referred to as.Alternatives A, B and C. A fourth alternative, referred to as Alternative D, consists of a lake tap and power tunnel to convey water from Grant Lake to the powerhouse. This alternative would not require raising the lake and thus.requir-es no.dams. The,power Intake would be set low enough to allow sufficient drawdown capability for regulation of streamflow. As a result of the full feasibility studies conducted following the Interim Report studies, a modified version of Alternative D was recommended for development (see Section 17.0). 12.3.1 Alternative A -.Intake Upstream of Saddle Dam Alternative A is very similar to the preferred alternative in the CH2M Hill report and consists of raising Grant Lake from its existing level at approximately elevation 700 to a normal maximum pool level at elevation 745 and diverting its flow to a single -unit powerhouse with an installed capacity of 6 MW on.the east shore of Upper Trail Lake. Raising the lake would be accomplished by constructing two dams. The main dam would be built across Grant Creek at the natural outlet of Grant Lake. A saddle dam would be constructed across the low saddle area north of the main dam. These features are shown in the plan on Figure IV-4. Water would be conveyed from Grant Lake to the powerhouse via a power conduit with an intake structure located upstream of the saddle dam. The power conduit would consist of steel pipeline from the intake to a surge tank and then a steel penstock to the powerhouse. Discharge from the powerhouse would be through a tailrace channel to Upper Trail Lake. 12-5 2266B The main dam and saddle dam would both be rockfill dams with central impervious zones constructed using a slurry trench. Both dams and the spillway adjacent to the main dam are also utilized in Alternatives B, C and E, and are described separately below. The intake for the power conduit would be a submerged circular vertical concrete -structure --with vertical_trashracks and would be_located _at., elevation 700, approximately 1,300 feet upstream of the toe of the saddle dam. This arrangement was selected based on its simplicity and efficient hydraulic configuration. The trashrack arrangement would be relatively maintenance —free except for periodic cleaning of the racks. 1 This --would 6e accomplished-by-personne1 in a boat-or-d-i-vers--coll-ec-ting---- -- -- the debris from the racks when the reservoir is low and'ice-free. A more complicated arrangement consisting of an intake tower and bridge was considered, but was not selected. It was felt that the primary advantage afforded by the intake tower, which is the continuous accessibility of the trashracks for cleaning, was offset by the added _ construction costs for the tower and access bridge that it would require. r E The power conduit between the intake and surge tank would consist of a combination buried and above ground low—pressure steel pipe 6.75 feet --in diameter -and 3,840—feet long. This arrangement was selectedbased on economics and ease of construction. Where the conduit traverses through the soft peat areas upstream of the saddle dam and the surrounding high ground, it would be buried in a soil and rock cut trench. Where it crosses beneath the dam, the conduit trench would be backfilled to the top of rock with concrete, thus forming an impervious plug around the pipe and providing support to the pipe under the embankment loads. Beginning about 800 feet downstream of the saddle dam, where the conduit is located above ground, two support methods would be 12-6 2266B employed: The conduit would be held fixed by concrete collars and cradles, and would be allowed to move freely along its axis under temperature loading within intermediate steel supports. Preliminary hydraulic transients analyses indicated that a surge tank would be required at the end of the low pressure portion of the conduit to protect the conduit from negative waterhammer pressures. The surge tank for Alternative A was assumed to be of the above ground, restricted -orifice type, with the base located at elevation 690 feet. The steel tank would be supported by a concrete mat founded on rock. This arrangement was selected in lieu of a tank supported on columns because of the high seismicity in the area. The mat -support arrangement would be more stable under earthquake loading. The last segment of the power conduit would be an above ground steel penstock from the surge tank to the powerhouse. The penstock would be 5 feet in diameter, 580 feet long, and would be supported in a manner similar to the above ground low pressure pipe (i.e., fixed concrete supports and sliding steel supports). In selecting the type and configuration of power conduit for Alternative A, buried prestressed concrete pressure pipe, completely buried steel pipe, and surface steel pipe were considered. Based on economics and constructibility, the combination of buried and surface steel pipe was selected. The powerhouse for Alternative A would be a conventional indoor installation located approximately 180 feet from the east bank of Upper Trail Lake. The substructure would be concrete founded in bedrock. The superstructure would be structural steel with aluminum siding. The powerhouse would house a single vertical Francis turbine having an output of 8,300 horsepower under a rated net head of 247 feet. The total powerhouse discharge under these conditions would be 329 cfs. The generator would be a vertical unit with an output of 6,700 kVa with an assumed power factor of 0.9. 12-7 2266E A single generating unit was provided in the powerhouse because of the size of the installation, and the economy resulting from a single unit installation compared with a multiple unit installation for a given capacity. The provision of a single unit should have no affect on the capability of the plant to produce the energy as estimated in the operation studies because of the high unit reliability and availability (97.5+ percent_ accordi.ng_to_ the FE,RC.) -of this equipment, the plant_ factor, and the regulation provided by the reservoir. A 180-foot-long tailrace channel would be excavated to Upper Trail Lake through the lake shore sands and gravels and into rock. It would have _side-sl-opes--of- 2H-:lV-- i-n soil and 1-H-:-4V- i-n- rock--.- The substation would be located adjacent to the powerhouse. For the conceptual layouts in the Interim Report, it was assumed that one three-phase transformer would transform the voltage from 13.8 kV to the 69 kV transmission voltage. The transmission corridor would parallel the main access road and follow the bridge across the Trail Lakes. It was assumed that the transmission line from the powerhouse would intertie with the existing Chugach line, presently operating at 24.9 kV, at the same location where.the main access road intersects the Seward -Anchorage highway on the west side of the Trail Lakes. Total length of access roads required for Alternative A would be 5.1 miles. This assumes that access to the general project area from the Seward -Anchorage highway would be provided by a bridge crossing Trail Lake over the narrows between Upper and Lower Lakes, as shown on Figure IV-4. An alternative considered in lieu of the bridge crossing would be the longer route around the south end and along the east side of Lower Trail Lake. The total length of access road using this route would be 7.2 miles. The bridge crossing, while slightly more -costly than the alternative route, was selected because of its decreased environmental impact and because of shorter length of required transmission lines associated with it. 12-8 2266B 12.3.2 Alternative B - Intake at Main Dam with Tunnel and Surface Conduit Alternative B involves raising Grant Lake to elevation 745 by constructing the main dam and saddle dam. Flow from Grant Lake would be diverted to a single unit powerhouse on Upper Trail Lake with an installed capacity of 6 MW. Alternative B combines a short power tunnel with the raising of Grant Lake as shown on Figure IV-5. Water would be conveyed from the intake structure at the main dam to the powerhouse by a combination of low pressure steel pipe, a short power tunnel and finally, a steel penstock. The main dam and saddle dam for Alternative B would both be rockfill with impervious central zones consisting of a soil-cement-bentonite mixture, the same as that required for Alternative A. The intake structure would be of the same configuration as that for Alternative A. It would be a submerged circular vertical concrete structure with vertical trash racks. The location of the structure would be just upstream of the main dam and would be set at elevation 700. Periodic cleaning of the racks would be accomplished by boat or diver during periods when the reservoir is ice -free. As with Alternative A, a more complex intake tower arrangement with removable trash racks was considered but discarded due to its cost (a gate tower and access bridge would have been required). From the intake structure to the power tunnel, the conduit would consist of a 7-foot-diameter low pressure steel pipe. For the first 300 feet of length, where this conduit passes beneath the dam, it would be placed in a rock cut trench and backfilled with concrete. The concrete backfill would result in impervious plug around the conduit as well as provide it with support to withstand the embankment loads. 12-9 2266E From the downstream toe of the main dam to the power tunnel this low pressure conduit would be supported above ground using the same surface support techniques discussed for Alternative A (fixed concrete supports and sliding steel supports). The tunnel would be horseshoe -shaped, 9-foot in diameter and would be lined with-shotcrete. At the portals and where poor quality rock was assumed to be encountered, the tunnel would be rock bolted in addition r to the shotcreting. An underground surge chamber would be located approximately 200 feet upstream of the tunnel exit at --elevation 697. It would be a restricted__-- — orifice type with surface venting. The chamber would also be lined with shotcrete. Rock bolts would be utilized where rock conditions are poor. Inside the tunnel, just downstream of the surge chamber, the power j conduit -would transition to a_5-foot-diameter steel penstock. This transition would occur at the location where the maximum hydraulic pressure in the tunnel is equal to the rock overburden pressure. The penstock would exit the tunnel and drop 220 feet to the powerhouse. It would be supported above ground using the combination of fixed concrete and -sliding -steel --supports discussed above for the low-pressure pipe. Construction of the tunnel would be performed using conventional drilling and blasting techniques. The excavation would head upstream to facilitate mucking and drainage. The surge chamber would be constructed using the raised bore shaft technique. A conventional indoor powerhouse would be located approximately IBO feet from the east bank of Upper Trail Lake (see Figure IV-5). At the I time of the Interim Report, no geotechnical suburface studies were performed in the area of this powerhouse and therefore it was assumed 12-10 2266B that foundation conditions would be typical of what was observed at the Alternative A powerhouse area during the Interim Report geotechnical studies. A 180-foot-long tailrace channel was assumed to connect the Alternative B Powerhouse to Upper Trail Lake. The mechanical and electrical equipment in the powerhouse was assumed the same as for the Alternative A powerhouse, except that the turbine would be rated at slightly different head and flow conditions. The substation would be located adjacent to the powerhouse and would utilize the same transformer and circuit breaker equipment as Alternative A. The transmission of power was assumed to utilize 69 kV lines and would tie into the existing Chugach line, which presently operates at 24.9 kV, on the west side of the Trail Lakes. The transmission corridor would parallel the main plant access road and would cross the Trail Lakes at the road bridge crossing. Construction of 2.8 miles of access roads would be required to provide access to all significant project features as shown on Figure IV-5. Access to the general project area would be from the Seward -Anchorage highway via a bridge crossing of the Trail Lakes at the narrows between Upper and Lower Trail Lakes as provided for Alternative A. 12.3.3 Alternative C - Intake at Main Dam With Surface Conduit Alternative C is similar to Alternatives A and B in that it involves raising Grant Lake to elevation 745 by constructing the main dam and saddle dam. Flow to the generating unit would originate at a submerged intake upstream of the main dam near the right abutment. The water would be conveyed through an above ground, low pressure steel power conduit and a steel penstock to the powerhouse. The single unit powerhouse with an installed capacity of 6 MW would be located on Upper Trail Lake. Figure IV-6 shows the general plan of these features. 12-11 2266B This alternative is unique in that the flow line consists almost entirely of above ground steel pipe. The one exception is where the { pipe is buried beneath the main dam; otherwise, no other methods of conveying water (tunnels, canals, etc.) are used. Also, the flow line for Alternative C is the longest, with an approximate length of one mile. The intake structure assumed for Alternative C is identical to the Alternative B intake, i.e., a submerged circular vertical concrete structure located upstream of the main dam at elevation 700. A 6.75-foot-diameter steel power conduit would traverse from the intake 1 and beneath the main dam within a rock cut trench backfi-i-i-ed--with - ---- - -- -- - concrete. Fromthedownstream toe of the main dam to the surge tank, the low pressure power conduit would be supported above ground, utilizing the design described for the alternatives. The Alternative C surge tank, located at elevation 690, would be a conventional above ground restricted -orifice type. This tank would be supported by a concrete mat founded on rock. The mat -supported surge tank was selected over one supported on columns because of its greater stability under seismic loading. From the surge tank to the powerhouse, flow would be through a 5.25-foot-diameter, 2,000-foot-long steel penstock. This penstock would utilize the same support arrangement as the low pressure conduit. The selection of above ground steel pipe for use as power conduit was made after sudying two other alternatives. These alternatives were buried steel pipe and buried prestressed concrete pressure pipe. Above ground steel was chosen based on economics and constructibility. 12-12 2266E The powerhouse would be located about 80 feet from the east shore of Upper Trail Lake. No geologic subsurface information was obtained at the Alternative C powerhouse area during the Interim Report studies, so conditions were assumed to be similar to those observed at the Alternative A site. It was therefore assumed that the structure would be keyed into bedrock. The powerhouse would be a conventional indoor installation with a concrete substructure and a steel superstructure and aluminum siding. Its mechanical/electrical equipment would be similar to the Alternative A and B powerhouses. The tailrace channel would be excavated approximately 80 feet long to Upper Trail Lake. The substation would be located adjacent to the powerhouse. Its features would be similar to those utilized for the Alternatives A and B substations. Power transmission would utilize 69 kV transmission lines and would tie into the existing Chugach line, which presently operates at 24.9 kV, west of the Trail Lakes. The transmission corridor would parallel the main plant access road and would cross Trail'Lakes at the access road bridge. Alternative C would require the construction of 3.4 miles of access roads, including the bridge across the narrows connecting the Trail Lakes as provided for Alternatives A and B. 12.3.4 Alternative D - Lake Tap For this arrangement, a lake tap from Grant Lake would supply water via a low-level power tunnel and short length of steel penstock to a single unit powerhouse with an installed capacity of 5 MW on Upper Trail Lake. This alternative arrangement provided the basis for Ebasco's preferred arrangement, as a result of the full detailed feasibility studies conducted following the Interim Report. Alternative D does not involve raising the water level of Grant Lake and therefore dam 12-13 2266E construction would not be required. Raising Grant Lake in conjunction with a lake tap was not considered in detail because of the obvious adverse impact the combination of a long tunnel and the construction of the required dams would have on power cost. Significant project features for Alternative 0 are the lake tap, a low-level inclined power tunnel, and a vertical gate shaft near the upstream end of the tunnel. These project features are Shown as part of the general project plan on Figure IV-7. The lake tap would have an intake invert at elevation 643. It would consist of an inclined 10-foot-diameter circular tunnel which would l incorporate a rocktrap located just downstream of the intake -portal.- A-- -- - - trashrack laced at the lake tap p portal would prevent debris from entering the power tunnel during plant operation. The power tunnel would extend from this lake tap intake to the downstream portal near i the powerhouse. The horseshoe -shaped power tunnel would be approximately 3,300 feet long from the lake tap to the powerhouse and would have a finished 1 diameter of 9 feet. The tunnel would be lined with shotcrete. The tunnel portal and areas of poorer quality rock would be rock bolted in addition to being shotcreted. Inside the tunnel, approximately 250 feet upstream of the downstream portal, the power conduit would transition to a steel penstock. At the tunnel portal, this 5-foot-diameter, 500-foot-long steel penstock would j drop to the powerhouse. This penstock would be supported by a ' combination of fixed concrete collars and sliding steel collars similar to the penstock supports discussed for the other alternatives. A gate shaft, 13 feet in diameter, would be located approximately 200 feet downstream of the lake tap. A gate house would be located on the surface of the 140-foot-deep shaft. The top of the shaft would be at elevation 780. The shaft would be lined with shotcrete and areas of poor rock would be bolted. 12-14 2266B A high-level tunnel alignment with a surge chamber and longer penstock was evaluated as a possible alternative to the selected low-level tunnel and shorter penstock. It was found that the increased costs associated with the high-level tunnel and surge chamber, as a result of increased rock excavation, precluded it as a viable alternative. Construction of the tunnel would be performed by conventional drilling and blasting excavation techniques. The excavation would head upstream from the lower tunnel portal to facilitate mucking and drainage. This process would proceed to within safe rock cover of the lake. The in -place rock would act as a plug and would remain in place until the entire power conduit is constructed. The vertical gate shaft would be excavated by the raised bore shaft technique. At the completion of the entire power conduit and gate shaft the in -place rock plug would be blasted free. A conventional indoor powerhouse, constructed of concrete and structural steel with aluminum siding, would be situated at the same location as the powerhouse for Alternative B, approximately 180 feet from the east bank of Upper Trail Lake as shown on Figure IV-7. The structure would house a single vertical Francis turbine having an output of 6,900 horsepower under a net head of 198 feet. The generator would be a vertical unit with a rated output of 5,600 kVa. These outputs were subsequently modified as a result of the full feasibility -level project optimization studies. The substation would be located adjacent to the powerhouse and would contain the same equipment as the other alternatives. The powerhouse tailrace channel would be excavated approximately 180 feet to Upper Trail Lake. No geotechnical field investigations were performed in the Alternative D powerhouse -tailrace area during the Interim Report studies; however, based on the subsurface information obtained in the Alternative A powerhouse area at that time, it was assumed that the channel would be excavated in the lake shore sands and gravels, and partly in rock. 12-15 2266E In order to assure adequate flow from Upper Grant Lake to Lower Grant Lake, the natural constriction at their intersection would have to be widened and made deeper. It was estimated that a channel 25-feet wide with an invert at elevation 655 would be required. This channel would be blasted open during the winter months and dredged clear in the spring. Power transmission would'utilize 69 kV transmission lines and would tie into. the existing Chugach line, which presently operates at 24.9 kV, west of Trail Lakes. The transmission corridor would parallel the main plant access road and would cross the Trail Lakes at the access road Construction of 2.7 miles of access roads would be required to provide access to all significant project features. Access to the general project area would be from the Seward -Anchorage highway via a bridge crossing of the Trail Lakes as described for Alternative A. 12.4 DIVERSION OF FALLS CREEK - ALTERNATIVES E AND F Alternatives A, B, C and D, described above, would utilize only the runoff into Grant Lake for purposes of power generation. The fifth and sixth_ alternati.ves_,_ referred. to as_ Alternatives, E and F, would divert the runoff from the Falls Creek drainage (located directly south of the Grant Lake drainage area) into Grant Lake for additional power production. For both or these alternatives, the diversion of Fall's Creek would be accomplished using a diversion dam and conduit to convey water northward from Falls Creek into Grant Lake as shown on Figure IV-3. Alternative E utilizes the .diversion of Falls Creek in combination with the raising of Grant Lake from its existing level to elevation 745. For this alternative the same power conduit and powerhouse arrangement as Alternative A is assumed. The effect of this diversion in 12-16 2266B combination with Alternative A would be representative of its effect on the other alternatives using a raised lake level (B and C). Alternative F would combine the diversion of Falls Creek with Alternative D, the lake tap scheme, and is the general project arrangement recommended in the Interim Report for detailed final feasibility studies. The results of these detailed studies, however, indicated that a refined Alternative D (no Falls Creek diversion) is, in fact, the most favorable project arrangement. 12.4.1 Alternative E - Falls Creek Diversion with Raised Lake Alternative E consists of diverting flow from Falls Creek into Grant Lake and using the Alternative A project arrangement. The resulting increased flow from Grant Lake would be diverted through the Alternative A power conduit to a 7 MW generating unit installed in a powerhouse on Upper Trail Lake. All other project features for Alternative A would apply (e.g., dams, roads, and transmission lines). The diversion would entail constructing a small concrete gravity dam approximately 20 feet high (crest elevation 1121 feet) and 66 feet long across Falls Creek at the 1100-foot contour approximately 1.6 miles upstream of its confluence with Trail River. Flow would be diverted from Falls Creek through a 3-foot-diameter buried steel pipe, approximately 2.1 miles to Grant Lake. Figure IV-3 shows a general plan view of the diversion route. The decision to bury the pipe instead of supporting it above grade was made because of its relatively small diameter and to provide protection from avalanches. The concete dam was selected instead of a rockfill dam or a roller -compacted concrete dam because of the small size of the dam, the narrow valley configuration, and the considerable amount of excavation for the spillway required with a rockfill dam. 12-17 2266B 12.4.2 Alternative F - Falls Creek Diversion With Lake Tap I Alternative F would combine the Falls Creek diversion with the i Alternative D project arrangement (lake tap). The Falls Creek diversion works would be identical to that described for Alternative E. The only difference in the arrangement of the lake tap at Grant Lake is that the powerouse would have an installed capacity of 6 MW, rather than the 5 MW plant for Alternative 0. �. 12.5 PRELIMINARY COMPARATIVE CONSTRUCTION COST ESTIMATES -1-2 5:1 - General During the studies performed for the February 1982 Interim Report, preliminary conceptual -level construction cost estimates were prepared for each of the six alternative project arrangements described in Sections 12.3 and 12.4. These cost estimates provided the basis for a comparison of the economics of each alternative. The economic comparison was subseqently incorporated into the decision process which led to the selection of Alternative F for more detailed study in the detailed feasibility phase. A summary of construction cost estimates tt for each alternative are shown on Table 12-1. The cost of energy for 1® each alternative is developed_on Table 1.2-2.___ 12.5.2 Basis of Cost Estimates Quantities were estimated in the Interim Report for each major project feature associated with each alternative. These quantities were based on the conceptual layouts of the alternatives as described in Sections 12.3 and 12.4 and on the topographical and geotechnical data obtained during the 1981 field studies. ' { The conceptual -level unit prices used for these estimates were developed primarily from the following sources: 1) bid tabulations 12-18 2266B from similar hydroelectric projects in Alaska which are either under construction or have been recently constructed, and 2) unit cost data recently developed by Ebasco in performing independent feasibility - level and construction -level cost estimates for the Power Authority for various hydroelectric projects in Alaska. For each unit cost selected, consideration has been given to the magnitude of quantities involved, the nature of the material being worked, and difficulty of access to and constructibility of the particular project feature. Mechanital and electrical equipment items were developed from the sources mentioned above as well as catalog values, vendor information, and experience. These estimates were prepared to reflect a January 1982 bid price level. The estimates include the following allowances which add to the direct construction cost: Contingencies Engineering, Construction Management, and Owner Administration Interest Rate Used for Computing.IOC Escalation 20 percent 15 percent 3 percent per annum zero Interest and escalation parameters were based on Fiscal Year 1982 Power Authority parameters. The estimates do not include any allowance for the cost of mitigation of the loss of fishery habitat resulting from dewatering Grant Creek. Such a cost would be required for.all of the six alternatives and would therefore not effect the economic comparison. The cost estimates prepared using the procedures outlined above provide a reliable basis for comparing the relative economic merit of each of the alternatives. It should be emphasized, however, that these estimates performed during the Interim Report and described in7this section were not feasibility -level estimates. Since the objective of the studies in the Interim Report was .to select the most desirable, project alternative, it was not judged to be cost effective to develop 12-19 2266B d detailed feasibility -level estimate for each of the alternatives. A full feasibility -level cost estimate, however, was prepared as part of the subsequent feasibility study, and is presented in Section 18.0 for the single -recommended and optimized project. 12.5.3 comparison of Cost of Power of Alternatives The annual cost of each of the six alternatives Was developed Using | \ economic parameters and discount rates established by the Power / Authority. Table 12-2 shows the derivation of the annual costs. An ( a1lowance foroperation and maintenance Was added to arrive at a total --dnUVal cost. As shown --on Tab]e-l2�3 Lthe-Lake-tu would be the most attractive for development strictly from the � standpoint of minimizing the cost of energy, closely followed by Alternative F (the lake tap plus Falls Creak diversion). The four '| remaining dlt'rnatiVes have 8 significantly higher cost of power When compared to Alternatives D and F. The results of this Comparison of energy co§ts-iM-con^UnctloV with technical'ODd-eOviPonmental -- considerations resulted in Ebasco's recommendation in the InterimReport ' that Alternative F be developed through feasibility -level studies' Primarily, it was felt, at that time, that the added energy benefit associated with theFalls Creek diversion outweighed its � slightly h�|her custo| -me . y. Subsequent detailed power -operation and plant optimization studies described in Section 18.0 revealed that / Falls a refined Alternative D arrangement without ou Creek is actually preferable. . ' |2-2D ` 2260B FERC ACCOUNT DESCRIPTION TABLE 12-1 ESTIMATE OF CONSTRUCTION COSTS FOR ALTERNATIVE PROJECT ARRANGEMENTS!/ A HYDRAULIC PRODUCTION PLANT 331. Power Plant Structures and Improvements 551,700 332.1 Reservoir 950,000 332.2 Dams 12,553,900 332.3 Waterways 7,024,000 333. Water Wheels, Turbines and Generators 2,066,000 334. Accessory Electrical Equipment 674,500 335. Miscellaneous Powerplant Equipment 650,000 336. Roads and Bridges 3,381,000 TOTAL HYDRAULIC PRODUCTION PLANT 27,851,100 TRANSMISSION PLANT 352. Transmission Plant Structures and Improvements 3,800 353. Substation and Switching Eqpt. 566,000 355. Poles and Fixtures 94,700 356. Conductors and Devices 56,900 TOTAL TRANSMISSION PLANT 721,400 TOTAL DIRECT CONSTRUCTION COSTS 28.572.500 INDIRECT CONSTRUCTION COSTS 3,162,500 SUBTOTAL FOR CONTINGENCY 31,735,000 CONTINGENCY (20 percent) 6,347,000 SUBTOTAL 38,082,000 ENGINEERING, CONSTRUCTION MGMT. AND OWNER MGMT, (15 percent) 5,712,300 SUBTOTAL 43,794,300 INTEREST DURING CONSTRUCTION (3 PERCENT PER ANNUM) 1,970,700 TOTAL CONSTRUCTION COST 45,765,000 1/ From Interim Report B 551,700 950,000 12,053,600 6,814,000 2,066,000 674,500 650,000 2,569,000 26,328,800 3,800 566,000 52,600 31,600 654,000 26.982.800 3,056,000 30,038,800 6,007,800 36,046,600 5,407,000 41,453,600 1,868,000 43,321,600 ALTERNATIVE C D 551,700 551,700 950,000 2,000,000 12,062,400 6,590,800 7,674,200 2,066,000 1,780,000 674,500 626,000 650,000 610,000 2,674,000 2,541,000 26,280,300 15,782,900 3,800 3,800 566,000 526,000 36,800 52,600 22,100 31,600 628,700 614,000 26,848,100 16,396,900 3,023,800 1,534,500 29,871,900 17,931,400 5,974,400 3,586,300 35,846,300 21,517,700 5,376,900 3,227,700 41,223,200 24,745,400 1,855,000 928,000 43,078,200 25,673,400 E F 551,700 551,700 950,000 2,000,000 12,951,400 367,500 10,318,200 10,798,800 2,371,000 2,066,000 723,000 674,500 775,000 650,000 4,557,000 3,717,000 33,197,300 20,825,500 3,800 3,800 606,000 566,000 94,700 52,600 56,900 31,600 761,400 654,000 33,958,700 21.479,500 3,716,300 2,058,300 37,675,000 23,537,800 7,535,000 4,707,600 45,210,000 28,245,400 6,781,500 4,236,800 51,991,500 32,482,200 2,339,600 1,218,100 54,331,100 33.700,300 2620B 12-21 U.j ce C) LL. cli CD uj LLJ -j uj m et U- CD V) C) U LL. C) C) V) CL 2: C) u PM LAJ Lu C) 01 r- tx) LO r-_ co r_: C-1; C"i U-) CY) 0 0- r— N U) LD r- C-i m r— ko • 00 tD CV C\j LO ci m co (D w co co fl, cn d Mto to cn cl; rl: Oli R:t 0i - Uto co -4, Cl to CD CO 00 m cli C) LO S— o 4- C\i td, 1.0 w co �d- 4J C% ll:� 00l r_: W ko a) m S- a) 4-) 4J LO a) C) 0) 0) N a tz fl, -d* r- a) Ill I,- r- a) m S. I LO W CL (D (D 4-3 0 CD CD -a C) 0) 64 cn 0 C) U C) 3 w 0000 C) > m 0 tn r— r- 4J 0) 4- u 0— CD (n S. m C) S.- S- s- +-) .1 3 C C) CL o w S- (A N w 64 Cf7 4-3 -P C p S- aj C) m uj r_ M: o uj N r_ m r- r= u r- 00 0 m 4J "0 m 4- 0) •r- w 0 m 4-3 u m m r_ -P 4J N .� .0 9 r_ > S- o r_ J� U) 0 (a , S- 4J 0 4J ci .,- < a) u S- = to ul 4-) cm C 0 4J 0 0 C:c Lj- U- 4J .0 w 4--) a) 4J OA ci ui in COY 12-22 TABLE 12-1 ESTIMATE OF CONSTRUCTION COSTS FOR ALTERNATIVE PROJECT ARRANGEMENTS-1/ (JANUARY 1962 DOLLARS) FERC ACCOUNT DESCRIPTION A B ALTERNATIVE C D E F HYDRAULIC PRODUCTION PLANT 331. Power Plant Structures and Improvements 551.700 551,700 551.700 561.700 551,700 551,7 332.1 Reservoir 950,000 %O.000 950.000 2,000.000 950,000 2,D00,C 332.2 Dams 12,653,900 12.053,600 12,062,400 12,951.400 367,! 332.3 Waterways 7,024,000 6..814.000 6.590.800 7.674.200 10,318,200 10,798,E 333. Water Wheels. Turbines and Generators 2.066.000 2,D66,000 2.066,000 1.780,0D0 2.371,000 2,066,( 334. Accessory Electrical Equipment 674.500 674,600 e 674.500 626,000 723,000 674,! 335. Miscellaneous Powerplant Equipment 650.D00 660.000 650.000 610.000 775,D00 650,( 336. Roads and Bridges 3,381,000 2.569.000 2.674.000 2.541,000 4.557,000 3,717,( TOTAL HYDRAULIC PRODUCTION PLANT 27,861,100 26,328,800 26,280,300 15.782,900 33,197,3DO 20,825,! TRANSMISSION PLANT 352. Transmission Plant Structures and Improvements 3,8DO 3,800 3,800 3.800 3,800 3,1 353. Substation and Switching Eqpt. 666.000 566,000 5".000 526,000 606,000 566,( 355. Poles and Fixtures 94.700 52,600 36.800 52.6DO 94,700 52,E 356. Conductors and Devices 66.900 31.600 22,100 31.600 56,900 31,E TOTAL TRANSMISSION PLANT 721,400 654,000 628,700 614,000 761,400 654,E TOTAL DIRECT CONSTRUCTION COSTS 7 ADO &jNA&0 UAM, 100 396 00 AL22 700 .! 21.47916 INDIRECT CONSTRUCTION COSTS 3,162,500 3.056,000 3,023.800 1,534,5DO 3,716,3DO 2,058,: SUBTOTAL FOR CONTINGENCY 31,736,000 30,038.800 29,671,900 17.931,400 37,675.000 23,537,E CONTINGENCY (20 percent) 6,347.000 6.007.800 5,974,400 3,586.300 7.536,000 4,707,( SUBTOTAL 38,062,000 36,046,600 35,646,300 21,517,700 45,210,000 28,245, ENGINEERING. CONSTRUCTION MONT. AND OWNER MGMT. (15 percent) 5.712.300 5.407.OD0 5.376.9DO 3,227.700 6.781,5DO 4,236.1 SUBTOTAL 43,794,300 41,453,600 41,223,200 24,745,4DO 51,991,500 32,482,: INTEREST DURING CONSTRUCTION (3 PERCENT PER ANNUM) 1.970.700 1.868.000 1.655.000 926,000 2,339,600 1.216, TOTAL CONSTRUCTION COST ZZI 321 0 4 .0-3�78 o �y7i� HJLI 100 3,700is 1/ From Interim Report 12-21 Ln V) L6 r. M P et r,%. en 31 0 CL cli Ln r%. t4o C4 rim LL) r— P— ot Ln en LAJ en CV N LO to - - -------- r*l (M v M %W %^0 04 LC) co q*l O qtr CD ko r- 00 cl ol; >1 " Q2 cl; r.: Q Ln - q** LO 00 �. 41 to C14 Qj LLB ai 0 CA 4m N 4J c ko 11% 44, f-- w r�- P.. r— u S. L9 cu Ca 4J 4a co (m co 0 Jd m tolp cn da 41 GJ C3 c CD �Ij 0 41 L. (u 1. im Vtom)C 44 4) 1.(. 4 0. ci 0 +4 c W G RI I cz IA uj c %C 401� "1 04 C p.- 4J V to 4- p a r- 4J IG to 44 .0 4j V 33 4j :ws %. 14.0- P- 41 c C (A C, P- 1. - 44 L m L i0 Q U. U. .0 IV 4a 4) 41 La -21% 1%01 13.0 FIELD INVESTIGATIONS 13.1 GENERAL Field investigations were conducted in both the 1981 and 1982 seasons. This work included surveying and mapping, bathymetric surveys, hydrological data collection, geotechnical explorations, environmental data collection and cultural resource investigations. The objective of the earlier 1981 field work was to gather site -specific data to support the Interim Report studies. Specifically, this data provided a reliable basis for developing conceptual layouts of the project features for each alternative, for evaluating the engineering and environmental considerations of each alternative, and for preparation of comparative conceptual -level estimates of construction cost for each alternative. The 1982 field investigations concentrated on obtaining more detailed site -specific information in the vicinity of the Alternative F arrangement which, at that time, was the preferred arrangement. The purpose of obtaining this information was to support the development of feasibility -level project layouts and to provide a level of project -specific information required for an FERC license application. 13.2 SPECIAL USE PERMITS The project lands are currently under the jurisdiction of the U.S. Forest Service (USFS) and, as such, Special Use Permits were required before any field work could be conducted which might disturb the lands. An application for a Special Use Permit for field investigations was submitted to the USFS on October 7, 1981 which described the work planned for the 1981 season. Authorization to proceed with the field studies was given to the Power Authority from the USFS by letter dated October 8, 1981. Another Special Use Permit Application for the 1982 field investigations was submitted to the USFS 13-1 2310B on March 31, 1982 with authorization given to the Power Authority in a letter dated June 1, 1982. In order to perform the cultural resource investigations an additional Special Use Permit for cultural resource evaluation was obtained from the USFS on May 24, 1982. Copies of this correspondence are included in Part VIII of the Technical Appendix. 13.3 EXECUTION OF FIELD WORK Field work began on October 12, 1981 and continued until work was halted during the 81-82 winter months. Logistical coordination for all field work was performed by R and M Consultants, Inc., under the overall direction of an on -site Ebasco representative. Lodging for field work personnel was provided at the nearby Crown Point Lodge. A float plane and helicopter were used to transport personnel and equipment between Trail Lake and Grant Lake and for aerial reconnaissance work in the project area. Inflatable boats with outboard motors were used on both lakes. Smaller helicopters were used -for-movement-of personnel_ engaged in ground control survey work._ A description of the surveying and mapping work is provided below. The geotechnical, hydrological and environmental field investigations are described in detail in Sections 14.0, 15.0 and Volume II - Environmental Report, respectively. A detailed description of the cultural resource investigations is also presented in Volume II. 13.4 SURVEYING AND MAPPING Aerial photography and topographic mapping for the project area were performed by North Pacific Aerial Surveys, Inc. Ground control surveying and bathymetric surveying were performed by R and M Consultants, Inc. Topographic and bathymetric mapping which was prepared for the project area includes the following: 13-2 2310B I" = 400'; 10-foot contour interval mapping of the entire Grant Lake reservoir area. 1" = 200'; 5-foot contour interval mapping of the area where the project features would be located. 1" = 400'; 10-foot contour interval bathymetric surveys of Grant Lake (both the upper and lower sections). 1" = 200'; 1-foot contour interval bathymetric survey across Upper Trail lake in the vicinity of the powerhouse tailrace. 13-3 2310B 14.0 GEOTECHNICAL STUDIES 14.1 GENERAL Field geotechnical investigations were performed during the fall of 1981 and during the summer of 1982. Studies were completed by R&M Consultants of Anchorage, under the direction of an Ebasco geotechnical engineer. The fall 1981 studies included geologic mapping, drilling of thirty-six auger holes, and the drilling of one diamond drill hole. These studies concentrated along the Alternative A Project arrangement, since previous work indicated that it would be the most desirable option at Grant Lake. Most of the field work was concentrated at the dam sites which.would have been required for the raised -lake alternatives. The results of these studies are contained in the Technical Appendix Part I, and the Interim Geotechnical Report, February, 1982 prepared by R&M Consultants. The summer 1982 field investigations were focused along features of the Alternative F Project arrangement as described in the Interim Report and which was recommended for detailed feasibility studies. This arrangement consists of a lake tap on Grant Lake, tunnel and diversion of Falls Creek into Grant Lake. As a result of these detailed feasibility studies, this alternative was dropped in favor of a modifi.ed Alternative D arrangement consisting of lake tap without the Falls Creek diversion. Field work began on June 9, 1982 and was completed July 12. Investigations consisted of additional regional geologic mapping, detailed geologic mapping along the tunnel alignment, reconnaissance mapping along the proposed Falls Creek diversion pipeline, and investigations of possible dam locations in Falls Creek. The results of these activities are presented in the Technical Appendix Part I and are summarized herein. A total of 5 diamond core holes were drilled along the tunnel alignment and in the powerhouse cove and intake area as shown on Figure IV-8. The detailed logs for these borings are presented in the Technical Appendix Part I. Water pressure 14-1 0290T (� / geophysical Surveys were also performed at the powerhouse site (see Figure IV-9). A bathymetric survey of Grant Lake Was completed during this field season. 14.2 REGIONAL GEOLOGY Studies of the regional geology consisted of^a review of available literature, as Well as reconnaissance mapping and StUdynf the area including Grant Lake, Upper and Lower Trail Lakes, Grant Creek, Falls Creek, and yagt and Kenai Lakes. The following discussion reviews the regional morphology, geologic structures,stratigrap y, Figure IV_10.shows the,location of the project geologic features discussed below. c"y . > \ The _NnrpholVRy._ofthe- _ _is- tvn1cal_of_sVb_8rtic jated___ terrains. Broad U-shaped valleys dissect the mountain ranges and form lowland areas With lakes, ponds, and streams. Elevations in the ' project region range from 380 feet above mean sea level at Upper Trail '~ Lake to over 5000 feet in the adjacent mountains. Much of the region \ Was stripped clean by the movement of glaciers, leaving bedrock exposed over large areas. Within the mountainous areas, topography is rugged and slopes are typically steep. Hanging valleys are common, With many of them containing lakes. Small glaciers occur at the head of most major valleys. The morphology of the mountainous areasindicate that most were at one time completely buried and overtopped by glaciers. Lowland areas are typically elongated, with varying amounts of alluvial infilliOO' Some of the east -west trending valleys, notably the Grant Lake and Kenai Lake valleys, have nearly right-angle bonds where they l4-2 O29OT intersect the major north -south trending lowlands. This morphology reflects diversion of side glaciers at their intersection with the major southward moving glaciers. Streams are common within the lowland areas, as are lakes and ponds' In several areas elongated ridges of relatively low relief form foothills to the major mountain paaks. One such ridge forms the area between Grant Lake and Upper Trail Lake. These bedrock ridges parallel the trend of the adjacent valley' Small bogs, formed in bedrock depressions resulting from glacial scour, are common on the tops of these ridgaS. Many are elongated in the direction of glacial flow. The bedrock in the site region is d complex assortment of metamorphosed sandstones, siltstones, and 0udstoOp, With some fine-grained volcanic units. The formations are part of the Valdez Group of Upper Cretaceous age (64 to lOO million years old). Intense deformation of the rocks caused extensive folding, faulting and 0e1amorphisN. The predominant - rock -types 1n the project region are lowgrademetamorphosed - sedimentary rocks, rocks, including slates and meta -sandstones (Tvsdal and Case, 1979)' Extensive glacial deposits are absent in the project Yegion. Minor glacial till deposits may exist at the base of some of the bogs and lakes in the area, and within some of the coves along Upper and Lower Trail Lakes' As shown on Figure IV-lO, unconsolidated sVrfic1al deposits are relatively rare in the project area, Alluvium is found at the head of Grant Lake, in the area between Lower Trail Lake and Kenai Lake, within a few of the coves around the Trail Lakes, and within the small bogs found in the low, bedrock ridge. flanking the Trail Lakes valley. l4-3 O29OT These deposits are typically mixtures of silt, sand, and gravel. Minor sand and gravel deposits are also found at the mouths of Grant Creek and Falls Creek. Poorly sorted mixtures of cobbles, gravel, sand and silt occur at the baseofthe-major avalanche_ chutes and are.the result of transport by snow avalanches during the winter and spring. These deposits are local and not extensive. Geologic Structures The complex deformational history of the bedrock in the project area has resulted in a large number of structural features. The primary foliation in the bedrock is parallel to bedding. Most units strike approximately north 5 degrees east (N05E) and dip 45.to 55 degrees to the east. Joints are common throughout the area. Joint orientations vary widely, although there are minor maxima oriented EW to NE -SW i -di-ppi ng--between _50--and- 90--degrees to -the,-south or _southeast. Minor faults and fracture zones were discovered in several areas. Two fracture directions are dominant. One set trends NE and the other N-NW. Both sets are clear on the aerial photography and satellite imagery due to differential erosion. Grant Creek follows the most obvious of these NE trending features,.which has been named the Grant Creek Fault. Exposures near the head of Grant Creek indicate that the fault zone is 15 to 20 feet wide. Other NE trending fractures occur both south and north of the Grant Creek Fault, and appear as discontinuous linear features (Figure IV-10). The expressions of many of the N-NW trending fractures have been accentuated by glacial action. Since these faults nearly paralleled i the direction of glacial advance, the fault zones were easily scoured. As a result, many of the fracture traces are now expressed as near vertical bedrock cliffs that trend N-NW across the project region. 14-4 0290T The Trail Lakes valley is a long, north -trending valley that extends from the town of Seward northward to Upper Trail Lake. It has been called the "Kenai Lineament" since it is obvious on satellite imagery as a long, linear feature. The trend of the valley is nearly parallel to the N-NW fault set observed in the region, and the Kenai Lineament may represent one of these fault zones that was extensively eroded during the glacial period. Foster and Karlstrom (1967) and Plafker (1969) have presented equivocal evidence for possible movement of a concealed fault along the Kenai Lineament during the 1964 earthquake. Careful field investigations during this study, however, found no evidence of recent faulting in any of the numerous outcrops along both shores of Upper Trail Lake. It is therefore unlikely that that Kenai Lineament represents a major, active fault. More likely it is a glacial valley whose orientation and location followed the N-NW trend of the minor fault set observed in other areas. 14.3 SITE GEOLOGY Powerhouse Cove The powerhouse site is within a small, elongated valley approximately 1000 feet long and 500 feet wide at the proposed powerhouse site (see Figure IV-8). The valley lies within a bedrock depression formed by glacial erosion. The valley is adjacent to and drains into Upper Trail Lake. Elevations within the valley range from the water line of Upper Trail Lake at elevation 467 to elevation 500 along its eastern margin. The bedrock within the powerhouse valley is similar to that outcropping throughout the area. Two exploratory borings indicate the presence of massively bedded greywacke with some interbedded slate and thinner greywacke beds. Within the valley itself there are several low ridges or hummocks underlain by resistant greywacke beds. 14-5 0290T Seismic refraction profiles within the valley indicate a layer of sedimentary infilling averaging 5 to 25 feet, with locally higher thicknesses over bedrock lows (Figure IV-9). The two exploratory borings (DH-1 and DH-2) penetrated 28 feet and 18 feet, respectively, of soils ranging from sand and silt near the surface to poorly sorted mixtures of cob_bles,__gravel, sand and silt at depth. The lower materials may represent glacialtillor outwash, while the upper material is probably recent stream or lake bed sediment. The groundwater table in the powerhouse valley is at or near the surface. No direct observations of geologic structure could be made due to the overlying thickness of overburden. Data from the borings and the outcrops surrounding the.valley suggest that the bedding within the bedrock strikes to the north and dips at 45-55 degrees to the east, paralleling the regional trend. Joints observed in the two exploratory borings dipped between 45 and 80 degrees. No evidence of shear zones was discovered in the borings. j Analysis of air photos, satellite imagery and topographic maps indicate a long linear feature trending N-NW from the eastern side of Vagt Lake, along the -eastern -side of the -powerhouse valley, and possibly extending several thousand feet to the north (Figures IV-10 and IV-11). The linear feature represents a steep cliff face that forms the eastern shore of Vagt Lake and the eastern boundary of the powerhouse valley. Investigations of this feature along its length from the ground and from the air revealed no positive evidence of fault control, although it likely that this linear feature is an old fault. Its present topographic expression is not the result of movement, however, but the result of differential erosion during glacial advances. The fault zone formed a zone of weakness nearly parallel to the direction of glacial movement, and thus was accentuated by erosion. 14-6 0290T Power Tunnel and Intake The power tunnel and intake would be completely within the bedrock that forms the ridge between Grant and Upper Trail Lakes. The rocks are typical of the bedrock throughout the area, and are composed of metamorphosed sedimentary rocks of the Valdez Group. Figures IV-11 and IV-12 present a geologic map and profile along the tunnel alignment. The predominant rock types are greywacke, slate, and mixtures of the two. Field investigations and exploratory borings indicate that the greywacke is an extremely hard and dense metamorphosed sandstone of varying composition. These units typically form massive beds up to several tens of feet thick, and are the most competent rocks in the area. Varying mixtures of greywacke and slate form the rest of the bedrock along the tunnel alignment and intake. The units typically consist of beds of greywacke up to 12 inches thick interbedded with slate beds of similar thickness. The small-scale topography of the area provides indication of the under -lying rock type. Ridges are commonly underlain by massive greywacke beds, while bedrock depressions or swales indicate higher percentages of slate (Figure IV-12). Bedding along the tunnel alignment parallels the regional trend. Most units strike to the north, and dip 45 to 55 degrees east. Joints are common throughout the area, although their orientations vary widely. Joint spacing is variable, and ranges from over three feet to less than 10 inches. Minor shear zones were encountered in the exploratory borings along the tunnel alignment. The shear zones were usually steeply dipping, and ranged in thickness from less than a few inches to several feet. In addition to the minor shear zones encountered in the exploratory borings, analysis of topography and aerial photographs indicates 14-7 0290T several N-NW trending linear features crossing the tunnel alignment. These linear features are topographically expressed as small stream valleys or low cliffs bounding the bogs found along the ridge. It is likely that these linear features mark the trend of minor faults. There is no evidence that these are active features, but rather old fractures that formed during the deformation and metamorphism of the area. The single exploratory boring (DH-5-82) in the intake area revealed two open and weathered shear zones that parallel the bedding orientation. These two zones are interpreted as bedding -plane failure surfaces, resulting from gravi-tationally-induc-ed movement of slabs --of massive- - -- -- --- greywacke. Such bedding plane failures are discussed in Section 1b.5. Reservoir Grant Lake is over six miles long, and fills an L-shaped depression formed by glacial erosion (Figure IV-10). It is divided into two parts at the bend in the "L" by a natural bedrock constriction. The shores of Grant Lake drop off steeply beneath the water, with slopes of over 2H:1V (25 degrees) in many areas. The lake is nearly flat-bottomed, with water depths as deep as 300 feet. The bedrock constriction at the �r bend in the "L" forms the Grant Lake narrows, where water depths range from 30 to less than 4 feet. Most of the shoreline of Grant Lake consists of steep bedrock slopes or cliffs. The two main exceptions occur at the head of the lake, where an alluvial delta has been formed by the glacial streams, and near the outlet of the lake at Grant Creek, where a small alluvial valley has developed due to the influx of avalanche debris from the adjacent peaks.- Materials within these areas consist of unconsolidated mixtures of silt, sand, gravel, and cobbles. Other unconsolidated deposits occur along the north shore of Grant Lake, just west of the narrows. These deposits consist of poorly sorted sand, gravel, and cobbles. 14-8 02901' Minor accumulations of similar material occur as small deltas around the shore of the lake, typically at the mouths of small side streams or avalanche chutes. The bedrock geology of Grant Lake is typical of that of the entire region. Lower Grant Lake is underlain and bounded by the same meta -sedimentary rocks discussed above. The units strike nearly north -south, and dip steeply to the east. Falls Creek Diversion - Revised Route Considered for Alternative F The alignment of the Falls Creek diversion dam specified in the Interim Report was relocated approximately 2500 feet upstream in the detailed feasibility studies based on the acquisition of more detailed survey information in the area (see Figure IV-25). The detailed survey information showed the original location to be in a steep -walled canyon. The area of Falls Creek considered for this revised location is underlain by the typical Valdez Group rocks exposed throughout the area. Bedrock is exposed along Falls Creek for virtually its entire length, except where it drains into Trail Lake. Reconnaissance investigations revealed interlayered greywacke and slate similar to that exposed around the project site. Little or no soil cover was found in the diversion dam area. The trend of the bedrock parallels the regional trend, striking north and dipping to the east. No major faults were discovered during the preliminary investigations. The revised Alternative F pipeline route between the Falls Creek diversion dam and Grant Lake, shown on Figure IV-25, would be founded on bedrock for about seventy percent of its length, and on unconsolidated sediments for about thirty percent of its length. Bedrock areas are overlain by a thin soil cover. 14-9 0290T The areas of sediments crossed by the pipeline are bedrock depressions and small valleys filled primarily with poorly sorted mixtures of cobbles, gravel, sand and silt. Depth to bedrock in these areas is unknown at this stage of investigation. 14.4 ENGINEERING GEOLOGY FOR -PROJECT --STRUCTURES Powerhouse Preliminary layouts of the powerhouse assumed that the powerhouse would be constructed on bedrock near the center of the powerhouse valley. The results of the _mapping and boring programs and the seismic refraction survey suggest, however, that the powerhouse should be located in a cut constructed within the bedrock bounding the eastern edge on the valley. The mapping work in=this-area indicates that the north end of the powerhouse valley is bounded by a fracture zone that is one of the prominent NE trending lineaments, observed on the satellite imagery.-A-lthough this fracture zone -is -old -and not --active, it does present a zone of weakness that should be avoided. Similarly, analysis of air photos suggests that the eastern boundary of the valley is formed by a minor shear zone that occurs at the base of the bedrock cliff. No direct observation of this shear has been made to date, nor is it considered an active fault. It probably represents a zone of weakness and poor rock quality and was, therefore, avoided by locating the powerhouse in the sound bedrock to the east. See Figures IV-21 and IV-22. No major slope stability problems are envisioned at the powerhouse because of the orientation of the bedding. Bedrock in the cliff overlooking the powerhouse valley dips about 55 degrees to the east, and, therefore, is not subject to bedding,plane failures westward into the powerhouse area. 14-10 0290T Other structures in the powerhouse area include the tailrace channel and the salmon holding facility. These structures will be constructed in the valley. The two borings and the seismic refraction study indicate that depths to bedrock vary considerably in the valley, with depths along the tailrace channel exceeding 15 feet (Figure IV-9). The data suggests that the tailrace channel will be cut within the sedimentary valley fill. Tailrace slopes will be cut at 2H:1V and protected with rip -rap. Tunnel The engineering geology for the proposed tunnel alignment was investigated both by detailed surface mapping and with three boreholes (R&M Consultants, Nov. 1982). The detailed mapping was designed to identify any preferred tunnel alignments through the bedrock ridge. The results indicated that the original proposed location and orientation of the tunnel were as good as any nearby alternatives. The drilling program was then designed to intersect the tunnel alignment at depth. Two holes were drilled along the central part of the alignment, and one was drilled at the eastern end to investigate conditions near the intake and gate shaft locations (Figure IV-11). The total drilling length was 486 feet. Three primary rock types were encountered in the borings. An average of 40 to 50 percent of the core is hard, dense greywacke, ranging from massive to thinly bedded. Borehole thicknesses of greywacke units ranged from less than 5 feet to over 50 feet. The greywacke is the most competent rock unit in the section, with Rock Quality Designation (RQD) values exceeding 80 percent in most areas. RQD is the ratio of the sum of the length of core pieces greater than 4 inches in a core run to the total length of the core run, expressed as a percentage. The higher the RQD, the more competent the rock. The rock is typically unweathered. Joint spacing and orientation is variable, although spacings of 1 to 3 feet are typical. Most joint surfaces are unweathered. 14-11 0290T The second rock type encountered in the borings is slate, which makes up less than 15 percent of the total core. The slate is typically dark grey, hard, dense, and unweathered. It is characterized by many closely spaced fracture planes (called cleavage) which results in low RQD values and sometimes poor recovery. Most slate units observed in the borings are less than 3 feet thick. The third rock type is a mixture of slate and greywacke, and has been termed "sandy slate". The rock is light to dark grey, and consists of varying percentages of slate and greywacke. This unit makes up about 35 to 45 percent of the total core recovered. The rock unit is typically hard, dense, and unweathered, with RQD values ranging from 50 to 80 percent. Individual units are usually less than 6 feet thick in the borings. Joints and fractures vary in spacing and orientation, with spacings ranging.from over l foot to less than an inch. Water pressure tests were conducted.in these three boreholes to _i.d.ent_i_f.y any. openzones_ and. to_ determine- the.. overal_1 permeabi_1 ity___of the bedrock. Table 14-1 summarizes the results of these tests. Testing of the entire length of boreholes DH-3-82 and DH-4-82 yielded permeability values between 10-5 and.10-6 cm/sec. These data indicate very low permeability in the bedrock, suggesting that the joints found in the borings are closed and tight. Permeability values in borehole DH-5-82 at the intake area ranged from 10-4 to 10 5 cm/sec. These higher values reflected water loss through the two open fractures zones identified in the boring as possible bedding -plane I. failure surfaces. Plastic piezometer pipe was installed in boreholes DH-3-82 and DH-4-82. Water level monitoring indicates that the groundwater level is at or near the surface along the tunnel alignment in the intake area and along the top of the ridge between Grant and Trail Lakes. Therefore, most of the power tunnel would be below the water table, except near the portal at the powerhouse end. 14-12 02901' Additional data was obtained by a visit to the Case Mine, located about 2 1/4 miles north of the Grant Lake tunnel site. The objective of the visit was to observe the stability and in -situ conditions of rock similar to that at the Project site. Rock at the mine was estimated to contain about equal quantities of interbedded slate and greywacke, and strikes about N10W, dipping 55 to 60 degrees to the east. About 1200 feet of 4-foot by 6-foot section adits had been driven during the 50 years since the mine was opened. The mining activities followed a mineralized quartz vein and associated shear zones. The rock at the mine site is therefore, considerably more fractured and less stable than the rock encountered along the tunnel alignment. Noneless, the mine works are stable although unsupported. The rock along most of the tunnel alignment is of high quality. Figure IV-13 indicates the cumulative distribution of RQD within these three boreholes. The graph shows that nearly 80 percent of the core had RQD values of 40 and above, with over 60 percent of the core exhibiting RQD values over 70. These RQD values, coupled with the small design diameter of the tunnel and low bedrock permeability, suggest few problems in construction or operation of the tunnel. This conclusion is supported by the data obtained during the visit to the Case Mine. The results of the boring program suggest that, as preliminary design values, an average of 3 inches of shotcrete will be sufficient within the tunnel, and less than 15% of the tunnel length is anticipated to require rock bolting. Steel support structures will probably be unnecessary, except perhaps at the portals. These support requirements could very possibly be reduced as actual construction proceeds, and the condition of the rock is observed. 14-13 02901 Gate Shaft The geotechnical studies in the gate shaft area revealed very competent, massive greywacke. It is likely that less than 10% of the gate shaft will need treatment by rock bolting. An average of 3 inches of shotcrete lining is anticipated. (' The exploratory boring (DH-5-82) in the gate shaft/intake area revealed two steeply dipping shear zones at depths of about 44 ft and 60 ft (Geotechnical Report, R&M Consultants, Nov. 1982). These zones were open, unfilled, and bounded by weathered rock surfaces. These two -zones- are---presentl-y--consi-dered- -bedding-plane sli-ppage-pl-anes,-resulting -- - -- rom gravitationa failure of large slabs of greywacke. This type of failure would be expected along the western shore of Grant Lake, where the massive greywacke beds dip steeply towards the lake. The presence of these two planes suggests that additional borings should be completed in the intake/gate shaft area prior to final design to provide additional data for remedial measures, as necessary. Reservoir The bathymetric survey of Grant Lake completed during the summer of 1982 indicates that the narrows between upper and lower Grant Lake will act as a natural dam if the level of Grant Lake is lowered during operation of the project (Geotechnical Report, R&M Consultants, Nov. 1982). The controlling ledge of rock occurs beneath the southern of the two channels in the narrows, at an elevation of about 685 feet. This natural constriction would have to be excavated to allow movement of water from upper to lower Grant Lake during operation of the project. Reconnaissance mapping around the shores of Grant Lake was oriented towards the identification.of potentially unstable slopes that might i fail during project operation. The potential for slope failure around j the reservoir rim is discussed below. At this stage of investigation, the stabilization of reservoir slopes is considered unnecessary. 14-14 0290T Access Roads Access roads will be constructed to follow existing roads as much as possible. In areas with no existing roads, road alignments have been chosen to minimize extensive rock cuts and disturbance of the natural topography. No unusual engineering problems are foreseen for any of the proposed access roads. Falls Creek Diversion Dam and Pipeline (Alternative F) No detailed exploratory work was done in the area of the Falls Creek diversion dam and pipeline proposed for the Alternative F project arrangement. Preliminary work indicates, however, that the dam would be founded on competent bedrock, and that probably less than 3 feet of sediment exists in the streambed. Reconnaissance investigations indicate that much of Falls Creek is in a bedrock canyon, with most of the canyon walls near vertical. For this reason a pipeline route was established to follow Falls Creek downstream of the diversion dam and quickly ascend out of the canyon. Outside of the canyon, geologic mapping along the route suggests that about 30 percent of the pipeline would be founded on sedimentary material, and about 70 percent would traverse bedrock at or near the surface. The pipeline would have to cross one major avalanche chute about midway between Falls Creek and Grant Lake (Figure IV-10). Additional burial depth of the pipeline within the sedimentary deposits at the base of this chute would provide adequate protection from damage by avalanche. 14.5 GEOLOGIC HAZARDS Geologic hazards around the Grant Lake project site are related primarily to the high seismicity of the area. Other hazards considered are related to mass movements of material, including landslides, rockslides and avalanche. 14-15 02901 14.5.1 Seismicity Seismic hazards include vibratory ground motion, ground rupture, seismically -induced slope failure, s.eiche, and liquefaction. The potential occurrence of each of these hazards is discussed below. Vibratory Ground Motion --- ---. The high level of seismic activity in this ,region of Alaska suggests that the Grant Lake project features may at some time be subject to vibratory ground motion. Table 14-2 is a compilation of all the known sources of earthquakes that are close enough to the project site to have significant impact. The maximum credible, -earthquake (MCE) has been calculated for each structure using relationships developed by Slemmons (1977) or Wyss (1980), depending on the nature of the source feature. The MCE for the .__random crustal event was selected as magnitude 6.0, a conservative upgrade from the maximum recorded magnitude of 5.5. The peak acceleration values, calculated using the most recent accepted techniques, are indicated on the table. The maximum calculated acceleration (50 percentile value) at the site is 0.40 g from the random crustal event and 0.37 g from the Aleutian Arc megathrust. Return periods forthesemaximum events have been ,estimated using historical and instrumental earthquake data. Based on the estimated return periods and the time since the last major event, the likelihood of such events was estimated for the life of the project. The likelihood of another 1964-type event on the megathrust is low for the life of the project, since the return period is in excess of 160 years. The likelihood of a large random crustal event is moderate to high with return periods estimated between 50 and 100 years. However, since the location of this event is random, the probability of such an event occurring at the project site is actually quite low. 14-16 0290T Ground RuDture Rupture of the ground during seismic events can damage any structures that are located across the trace of the rupture. Ground rupture is associated with the movement of active fault zones. There are no known active faults crossing the project features at the Grant Lake site. During the magnitude 8'4 Alaskan Earthquake of 1964 many small faults moved as a result of the tremendous earth movements during that event' These faults are not considered active or capable in the normal sense of releasing accumulated stress, but occurred as sympathetic failures along pre-oxis1ting zones of weakness. In addition to those secondary movements, differential settlement occurred in many areas, resulting in ground cracking and heaving Without actual fault movement. Although some evidence has been found in the project region of such sympathetic shifting or differential settlement during the 1984 event, there is no evidence that such phenomena occurred in the area of the project features. Ground rupture resulting from any of these processes, then, is not considered d hazard for this project. Seismically Induced Slope Failure One of the most common features associated with moderate to large magnitude earthquakes is slope failure' Triggered by ground motion, naturally unstable slopes can fail, Slope failures can be broadly classified into landslides, avalanches, and slab or tumbling failures of rock faces. ` There is little material in the project area that would be susceptible to landslidin8 during seismic events. No evidence was found in the project area of major landslides or their deposits, although some minor landslide debris was noted uphill from the intake area, l4-l7 Seismically induced avalanches could occur in most of the mountains above the project area. The topography around the project facilities themselves, with the exception of the Alternative F Falls Creek diversion system, suggest no hazard from avalanche. The effects of avalanches along the Falls Creek Diversion system are discussed below. Slab or tumbling failure of rock faces during seismic events is common in areas of unstable rock slopes. The western shore of Grant Lake, j where the gateshaft and gatehouse are located, is particularly susceptible to such failures, as the slopes are steeply dipping slopes of bedrock. Data from the exploratory boring in the intake area suggest that bedding plane slides have aheady occ-urred -- - Feasibility -level remedial measures have been developed to preserve the i stability of the cut slope at the gatehouse. These measures would have to be confirmed during the detailed design phase by additional field y explorations. ___Sei-che-.-and_ Landslide -Induced Waves Seiches are waves in lakes that are formed by the sloshing of water back and forth'as the result of ground shaking during seismic events or i the catastrophic inflow of material by slope failures around the lake's rim There are several areas surrounding Grant Lake that could be sources of earth or avalanche material for mass movements into Grant Lake, which could generate seiche waves. However, field work did not reveal any areas along the shoreline of Grant Lake where wave damage above normal high water levels was noted. This observation suggests that significant wave run-up did not occur during the 1964 earthquake. Further, the volumes of material that could enter Grant Lake are ti probably not sufficient to generate very large seiche waves. 14-18 0290T Investigations around Lower and Upper Trail lakes indicate that the surrounding topography coupled with the shallowness of the lakes themselves present significantly less hazard from seiche. There are also no areas of material that could generate large waves by mass movement into the Lakes. The present design of the Grant Lake project indicates that it will not be susceptible to damage by seiches that might be expected to occur in Grant or Trail Lakes. Liquefaction l/ Liquefaction is the failure of loose, water -saturated sediments under seismic ground shaking. However, major project features would be placed on or in bedrock, so no liquefaction problem will exist. 14.5.2 Avalanches Hazards from avalanches have been recognized at the Falls Creek diversion dam area and along the diversion pipeline route for Alternative F. The upper reaches of Falls Creek are bounded by steep mountain slopes with extensive evidence of avalanche. Hazards associated with avalanche, causing dam overtopping, would be minimal since the Falls Creek diversion structure would not be impounding much water, especially in the winter months. The diversion pipeline would be located in areas of avalanche activity. In order to minimize the possible disruptive effects of avalanche activity on the pipeline, it would be located either to the west, and out of active areas, or at the very western limits of the active areas. In addition, the pipeline would be buried along its entire length and additional protective cover provided where it is within the western limits of the avalanche activity. 14-19 02901' 14.5.3 Hazards Induced by Reservoir Fluctuation Hazards related to the fluctuation of the level of Grant Lake during project operation include slope failure and reservoir -induced seismicity. These hazards are discussed below. �Slope The fluctuation of Grant Lake during project operation may trigger slope failures, especially along the north,shore of the lake, where old landslide and avalanche deposits exist. Failures are not expected to ' -�-------- ge , nor present any haz8rdto -the- proJe Reservoir -Induced Seismicity In 0aOV areas of the world, the filling of reservoirs or large fluctuations in lake or reservoir levels triggers small to medium --magOitUde'eacthqUakes. _ benoted,_howevers_that_the Water pressure changes merely act as triggers for these events, and do not actually cause stress build -Up in the rocks. The bedrock materials must already be stressed and prone to earthquake activity if reservoir -induced seismicity is to occur' Grant Lake is an existing reservoirwhich has already experienced a variety of changing stresses` ranging from filling and covering by thousands of feet of ice, to ice retreat, and filling with water' Little, if any, reservoir -induced seismicity is expected to occur during operation of the project. Any shocks that do occur Will likely be of small magnitude and present no hazard to the project or surrounding areas. l4-2U O29OT 14.5.4 Other Hazards Other geologic hazards addressed are seepage, subsidence, and mining. The potential hazards of each of these to the Grant Lake Project are discussed below. Seepage The groundwater table along most of the tunnel alignment is at or near the ground surface. Bedrock permeabilities are very low, however, so that seepage problems will only occur at the intersection of the tunnel with open joints or fractures. Seepage problems during construction are not anticipated to be severe. Ciikc4Aonrn There are no areas of project features that are susceptible to subsidence. Although large areas of southwestern Alaska either uplifted or subsided during the 1964 earthquake, such large scale changes would have had little or no impact on the Grant Lake project. Mining Although there are several active and inactive mines around Grant and Trail Lakes, none of the mining activites are near the project site. No exploratory shafts.or old mines exist near the project features. The results of field investigations and exploratory borings indicate no economic mineralization around the project site. Old or potential mining activities, therefore, are not considered hazard to the project. 14-21 0290T TABLE 14-1 SUMMARY OF PERMEABILITY TESTS l Boring No. Tested Interval Pressure Range (1) Permeability (2) ! DH-3-82 22.2 to 185.2 ft 25 to 150 psi 10-5 to 10-6 cm/sec DH-4-82 60.0 to 225.3 ft 20 to 40 psi 4 x 10-5 cm/sec 116.0_to 225.3 ft 20 to 40 psi 4 x_10-5 cm/sec DH-5-82 15.0 to 75.4 ft 20 to 50 psi 10-4 cm/sec ' 40.0 to 48.0 ft 30 to 50 psi2 x 10-4 cm/sec (3) 56.0 to 64.0 ft 30 to 60 psi 4 x 10-4 cm/sec (3) i t Notes: i (1) Pressures given are gauge pressures at the surface. - t (2) Representative or average values for entire test. (3) Identified shear zone (these two zones account for virtually all of water take during entire hole test (15.0 to 75.4 ft interval). Source:_ Geotechnical Report, Grant Lake Hydroelectric Project, R&M I Consultants, Nov 1982. 2620E 14-22 0290T Source Type of Fault Random Crustal Event Aleutian Trench -Arc Megathrust (Main Magethrust Thrust) Benioff Zone Megathrust Castle Mountain - Caribou Fault Oblique Strike-* Bruin Bay Fault Reverse Knik-Border Ranges Fault Reverse Johnstone Bay Fault Normal M Henning Bay Fault Revere Patton Bay Fault Reverse Volcanic Denali Fault Strike -slip and Yaktage & Shumigan Megethrust Seismic Gaps 6 Estimated Likelihood on in Estimated of Event Within Next a3ntile i Return Period 100 Year 6 50 to 100 Moderate to High 0 year 6 160 to 300 Moderate to Low 7 years 6 1 100 year. Moderate to High i Not I determined Moderato to low I )3 Not ►1 determined Moderate to Low Not determined Low I4 Not `1 determined Low Not I determined Moderate to Low t Not I determined Moderate to Low I Not I determined Modsr3te to Low I 80 to 200 I High year, Calculation methods used as indicated c Lake Hydroelectric Project 1) MCE calculadons based primarily OFm Geological Report rupture length instead of totallengpred by R & M Consultants, Inc., January 1982 2) MCE calculation based on Wyss (M 3) Based on the instrument recorded at 15.0 HYDROLOGICAL STUDIES 15'1 GENERAL Field and office hydrological studies have been conducted for the Grant Lake project for two pVrposes. First, an estimate of the available runoff on a monthly basis from the Grant Lake and Falls Creek basins has been made for the purpose of evaluating the power output potential and operational characteristics of the project. Secondly, the flood characteristics of both basins have been assessed to serve as a basis for sizing certain project features. The field study program was conducted by R and M Consultants, Inc' and office studies Were performed by both R and M Consultants and Ebascn' The studies which have been performed in these areas are discussed below. 15.2 EXISTING DATA The runoff from the Grant Lake drainage area was recorded for ll years at a U3G3 gaging station located 0'3 miles upstream of the mouth of Grant Creek' Continuous historical streamflnw records for Falls Creek did not exist prior to the implementation of the field data collection program in 1981. A summary of the available historical streamflow data in the project vicinity is given below, Station Drainage USGS Station Name Number Area (mi 2 Period of Record Grant Creek near Moose Pass 15246000 44,2 1947-1958, 1982 Falls Creek near Lawing 15250000 11.8 1913, 1963-1970 (Annual Peaks), 1982 Trail River near Lawing 15248000 181'0 1947-1974 Ptarmigan Creak at Lawing 15244000 32'8 1947-1958 Crescent Creek near Cooper Landing 15254000 31'7 1949-1966 Kenai River at Cooper Landing 15258000 634.0 1947-Present Wolverine Creek near LdWiVg 15236900 9.5 1968-1978 Nellie Juan River near Hunter 15287000 125.0 1980-1965 l5-1 25h2B The location of the Grant Creek, Trail River, and Falls Creek gaging stations are shown on Figure IV-2. 15.3 FIELD STUDIES To supplement the 'vexistiOo-historicel-datafop the 3ftoj'a»hydrological and - 6Od climatological f1elddacollection-program-was initi�ated1r)!the `fall of 1981. A climatological station \was installed at an exposed | site near the natural outlet of Grant Lake. Wind speed and direction, temperature and precipitation parameters were recorded at the station on inkless chart paper for periods of up to 30 continuous days VD a ` chart. D I of the� -' presented a total daily precipitation and maximum, minimum and mean daily < temperatures' / 3trea0flma gages were installed on Grant and Falls creeks in the fall of 1981, and periodic measurements of streamfl0a Were made on a monthly � < --basi-s-dUriOo-the-fall—and- winter- -months-ofl08l�--ContinunUs-recording gaging stations were established at both creeks in April l882, using \ ! Leopold and Stevens F-1 water level recorders. /. 15.4 DEVELOPMENT OF MONTHLY 3TREAMFLOW MODEL FOR SITE � 15'4-1 Grant Creek The historical monthly Streamflow`rPcVrd for Grant Creek (1947-1058) was extended using the H[C-4 Monthly 3Lreamflma Simulation Model' The historical data from the U3G3 gages at Trail River, Crescent Creek and Kenai River were used for this analysis' A total of 33 years of monthly data, extending from water year 1948 through 1880 was developed. The first ll years of record were taken directly from the historical data from the Grant Creek 8aSa" and the remaining 22 years of record were reconstituted by correlation' A tabulation of the 33 l5-2 2582B years of record is shown on Table 15-1' These inflows have been used in the power operation studies for both the Interim Report and Feasibility Report. The continuous streaNflow records gathered during 1982 at Grant Creek were examined to determine if there was any significant deviation from the long-term historical records (1947-1958) or the simulated monthly strea0flVW record (1959-1980) used in the power studies. This analysis Was performed to ascertain whether the results of the streamflmw extension performed in 1981 for the Interim Report needed any modification prior to performing power operation studies in 1982 and 1903 for the Feasibility Report. Roth 1982 data and long-term data for June -September are presented in Table 15-2' The average monthly streamflVws recorded in 1982 were within one standard deviation of the long-term mean for each month, and did not reflect any record high or low ValUes. Flows for June -August were lower than average, while September flows Were higher than average. A similar flow pattern Was observed on the Susitna River in 1982, so the pattern seemed to be rag1onal. The average monthly flows recorded in 1982 from Grant Creak were also compared to those of the Kenai River at Cooper Landing, which was a major station Used in extending the historical streamflow record for Grant Creek. A consistent pattern was found, with Grant Creek flows about 7% of those on the Kenai River except in September, When a glacial outburst flood occurred in the Kenai basin, but which did not effect Grant Creek flows. Based on this analysis, it Was concluded that the nature of strea0flow data collected in 1982 did not warrant any revision to the 22 years of extended straamfluw record developed in 1982, The 33 years strea0flow record used previously for the Interim Report studies was therefore considered appropriate use in the final power studies. l5-3 25b28 15.4.2 Falls Creek Monthly data for Falls Creek for use in the Interim Report studies was determined by developing monthly ratios of flow between Falls Creek and Grant Creek, using regression equations developed in the Water Resources -Atlas - for USDA,- Forest Service, Region X (Ott Water Engineers, 1979). These ratios -Were applied to the monthly Grant Creek streamflows to obtain a monthly streamflow record for Falls Creek. The streamflow data collected at the Falls Creek and Grant Creek gaging stations from May to mid —October in 1982 was utilized to develop monthly ratios _of flow between Falls Creek and Grant Creek for use in the final power studies. A mass balance of snowpack, rainfall and runoff was also performed,,which provided a check of the 1982 flow data. The ratios developed for Falls Creek were adjusted by area to 87 percent to account for the upstream location of the point of diversion--versus-the ... location -of--the -streamgage.- ----An -additional 10 percent reduction was applied to account for spill at the Falls Creek diversion during periods of high flow. This value was determined by running an hourly simulation model of the recorded Falls Creek flows based on actual daily flows and characteristic diurnal variation for each month. The adjusted monthly flow ratios for 1982 were applied to the average monthly GrantCreekflows for the period of record to estimate average monthly flows for Falls Creek and for use in the power operations studies to determine the energy contribution from Falls Creek. The adjusted ratios are shown in Table 15-3. Only flows for May through October are included, since freezeup may occur during any of the remaining months and the diversion is assumed to be shut down to prevent pipe freeze. Furthermore, the Falls Creek flow contribution is negligible from November through April. Flows in May and October are also somewhat less certain owing to freezing phenomena, which makes the gage reading less accurate. I 15-4 2562B 15.5 FLOOD HYDROLOGY 15.5.1 Probable Maximum Storm A detailed meteorological analysis of the Probable Maximum Storm (PMS) at Grant Lake is not available. Consequently, an analysis was conducted which transposed the PMS from Bradley Lake to Grant Lake. Grant Lake is located approximately 75 miles northeast of Bradley Lake. The Probable Maximum Precipitation (PMP) derived for Bradley Lake was derived using data from stations around the Gulf of Alaska. Due to the proximity of the lakes, parameters derived in this manner are as applicable to Grant Lake as they are to Bradley Lake. However, differences in basin elevation topography and distance to the Gulf of Alaska also had to be considered. These relationships were utilized in Water Resources Atlas for USDA, Forest Service, Region X, (Ott Water Engineers, 1979), when developing the mean annual precipitation and average monthly precipitation values. Similar ratios for the two lakes should also apply for large storms covering the entire region, such as those in which the PMP would occur. Consequently, the Grant Lake PMP is believed to be conservative, and appropriate for design of the spillway for those alternative arrangements which include a dam at the outlet of Grant Lake. The National Weather Service (NWS) analyzed available meteorologic data in the Gulf of Alaska to determine the PMS for Bradley Lake. Grant Lake is also close to the Gulf of Alaska, but recieves a lower amount of precipitation, based on the mean annual runoff at the two lakes. The basins of both Bradley Lake and Grant Lake are dominated by rock and ice, resulting in an estimated 95 to 100 percent of the input precipitation passing through the basin. The mean annual runoff from the two lakes was thus considered adequate as direct indicators of the relative amount of mean annual precipitation. The mean annual runoff is 101.6 inches for Bradley Lake and 59.3 inches for Grant Lake. 15-5 To develop a PMS at Grant Lake, the PMS at Bradley Lake was reduced by the ratios of'the average monthly precipitation at the two sites. The Bradley Lake PMS was developed for August and September, so these were the months :analyzed. Maps in Water Re ources:Atlas-for:USDA,_Forest ---Servi-ce Region - X_,--- (Ott --Water .Engi-neers,-1979)-- present. average- monthly precipitaton_as a_ratio of mean annual precipitation. Using these maps and the mean annual runoff values presented above, the following average monthly precipitation values at the two sites were estimated: __August. ---------.----$eptember Grant Lake 5.9" 8.9" Bradley Lake 9.1" 13.2" The ratios of precipitation at Grant Lake to that at Bradley Lake were 65 percent and 67 percent for August and September, respectively. The PMS for Bradley Lake is estimated as 41.0 inches over a 72 -hour period. The above ratios result in an August PMS of 26.7 inches and a September PMS of 27.5 inches for Grant Lake. The 6-hour precipitation values are shown on Table 15-4. Estimates of glacial melt are also required to compute the total precipitation input during the PMS.The Grant Lake basin has a glacial area of 18 percent of the basin, from Flood Characteristics of Alaskan Streams (Lamke, 1979), or approximately 7.96 square miles. The , degree-day temperature index method was used to estimate snowmelt from the glaciers. It was assumed that nonglacial areas were snow -free, and that glacial areas had sufficient snow so as not to be depleted during the PMS. A constant melt rate of 0.098 inches/OF day was used from Bradley Lake Hydroelectric Protect, Design Memorandum (Corps of Engineers, 1981). Temperatures during the PMS were assumed to be the same as those developed for Bradley Lake. Temperatures during the August PMS average 1.9°F greater than those in September, resulting in 0.1 inches snowmelt.more during the PMS than that occurring in September. The lapse rate from sea -level assumed by the NWS is as follows: Elevation (ft) Differences from Sea -Level (OF) 0 0 1000 -2.8 2000 -5.7 3000 -8.6 4000 -11.5 5000 -14.5 6000 -17.5 Average elevation of the glaciers in the Grant Lake basin is about 4000 feet, so that a decrease of 11.5°F was applied to the September PMS temperatures shown in Table 15-4. These temperatures resulted in a snowmelt rate of 0.01 inch/hour. Basin size and runoff characteristics for Grant Lake are such that the time of concentration for runoff is estimated at less than 1 hour. Consequently, the 6-hour rainfall periods previously presented were considered too long for proper hydrologic analysis. The 6-hour rainfalls were divided into hourly increments using the ratios of 1-hr, 2-hr, and 3-hr probable maximum precipitation to the 6-hour probable maximum precipitation, as presented in Study of Probable Maximum Precipitation for Bradley Lake Basin (U.S. Department of Commerce, 1961). The point probable maximum precipitation values for each period were adjusted for area. The hourly pattern for the final 3 hours was assumed to be slowly decreasing. The resulting hourly ratios were applied to each 6-hour period: Hour Percent of 6-Hour Precipitation 1 27 2 21 3 15 4 14 5 12 6 11 15-7 2562B The 6-hour rainfall pattern generally followed that recommended for ± , design general -type storms in Design of Small Dams (U.S. Dept. of Interior, 1977). The 6-hour periods were arranged in ascending order (except for the 3 periods with heaviest rainfall), and the hourly periods in each were also in ascending order. The top 3 rainfall periodswerearranged in the following order: 2, 1, 3. The hourly periods in these three 6-hour periods were arranged in the following order of magnitude: 1-6 hours: ascending 6-12 hours: 6,4,3,1,2,5 ' 12-18 hours descending It was assumed that there was no rainfall either prior to or immediately after the storm, but that snowmelt was occurring. The PMS hydrograph is shown on Figure IV-15 and the data is presented in Part VII of the Technical Appendix. 15.5.2 Probable Maximum Flood The Probable Maximum Flood (PMF) flowing directly into Grant Lake was developed for preliminary spillway design for project alternatives with a dam at the outlet of Grant Lake (Alternatives A, B, C and E) and for estimating the effect of routing the PMF through the natural lake outlet for the lake tap alternative. Although streamflow records are available for Grant Creek below Grant Lake, there are no corresponding nearby precipitation or temperature data. Consequently, the data base was considered inadequate to develop reliable hydrograph reconstitutions. Since the basin is so small, and its runoff characteristics result in nearly total runoff, a simplified triangular hydrograph technique described in Design of Small Dams (U.S. Dept. of Interior, 1977) was utilized to estimate the PMF flowing into the lake. 15-8 2562B This technique was applied to 41.3.sq. mi. Grant Lake basin which excludes the area of the reservoir. Precipitation falling directly on the reservoir, which has an estimated area of 2.9 sq. mi., was converted to its cfs equivalent and combined with the average hourly cfs of runoff from the rest of the basin. The resulting peak inflow into the reservoir during the PMF is 52,900 cfs. 15.5.3 PMF Flood Routing 15.5.3.1 Dam Alternatives For those alternatives which include a dam at the outlet of Grant Lake, (A, B, C, and E) the PMF hydrograph was routed through the reservoir and spillway, using HEC-1. A range of spillway widths (from 100 to 250 feet) was analyzed in order to evaluate the effect of varying the spillway width on the required dam height and on the amount of rockfill available from the spillway excavation. A spillway with an uncontrolled ogee -type overflow crest having a width of 125 feet was selected for the alternatives using dams. The resulting peak outflow during the PMF is 23,300 cfs and the maximum water surface level during the flood is E1 758.5. 15.5.3.2 Lake Tap Alternative The PMF was also routed through the reservoir and natural lake outlet for the lake tap alternatives (D and F). The stage -discharge relationship for the lake outlet was determined using the HEC-2 program, Water Surface Profiles. The best available topography was used (1'=200', 5 foot contour interval) for developing channel cross sections at the outlet. Also, a survey was performed at the lake outlet to establish the outlet control elevation (El. 691). Two values of Manning's "n" were used: n=0.06 for the channel proper and n=0.10 for the overbanks. The overbank flows are relatively small, even for the highest values of discharge during the PMF. Critical flow occurred 15-9 2562B at the point where the outlet channel steepness increases abruptly for all flow values; thus, critical flow at the lake outlet governs the lake level. The resulting rating curve developed using HEC-2 for the natural outlet is shown on Figure IV-15 and the actual tabulated data is shown in Part VII of the Technical Appendix. The PMF was routed through the reservoir for the lake tap alternatives using HEC-1. The starting lake level was taken as equal to the surveyed minimum channel elevation at the outlet, elevation 691 MSL. The maximum water surface level which occurs during the routing of the PMF is elevation 709.2 and the maximum discharge from the lake is 27,700 cfs. The inflow and outflow hydrographs_for the PMF are shown on Figure IV-15 and the actual tabulated data is shown in Part VII of the Technical Appendix. 15.5.4 Grant Creek Flood Frequency Data Construction Diversion Flood Flood frequency studies -for -Grant -Creek --have been-conducted-by=the-USGS - with the results published in Flood Characteristics of Alaskan Streams l (Lamke, 1979). Peak discharges for floods with recurrence intervals of l 1.25, 2, 5 and 10 years were computed using the Log Pearson Type -III analysis, using the 11 years of historical data from Grant Creek. Peak discharges for floods with 25, 50 and 100-year recurrence intervals" were computed using equations developed from a multiple regression analysis of other similar gaged basis with longer periods of record. These equations relate the magnitude 'of the peak discharge for a given 1 frequency to the climatic and physical characteristics of a stream's drainage basin. A flood frequency curve presenting the results of these studies is shown on Figure IV-15. A flood with a 5-year recurrence interval was selected for purposes of sizing construction diversion works project alternatives requiring a dam at the outlet of Grant Lake for the dam (Alternatives A, B, C, and E). A 5-year flood is considered reasonable for the 3-year 15-10 2562B 0 construction period associated with construction of the main dam. The peak discharge for Grant Creek using the Log Pearson Type -III analysis is 1,300 cfs. 15.5.5 Falls Creek Diversion Dam Spillway Flood A flood with a 50-year recurrence interval was selected for sizing the spillway for the Falls Creek diversion dam. This is based on criteria contained in Recommended Guidelines for Safety Inspections of Dams, (Army Corps of Engineers, Chapter 2). According to the Corps criteria, the Falls Creek diversion dam falls into the "small" size classification and "low" hazard potential classification. For these classifications, the recommended spillway design flood is a 50 to 100 year flood. A 50-year flood was considered appropriate for the Falls Creek Dam, considering that only short-term minimal overtopping would occur in the event of a 100-year flood. Using the regression equation for a 50-year flood with the basin characteristics for Falls Creek, as defined in Flood Characteristics of Alaskan Streams (Lamke, 1979), the peak discharge for the spillway design flood is 1870 cfs. 15-11 TABLE 15-1 MONTHLY INFLOWS FOR GRANT LAKE (cfs) Water_ Year Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sept Average 1948* 262 200 116 32 24 16 27 244 493 556 385 162 211 1949* 259 90 26 15 12 15 17 137 409 474 325 ' 446 186 1950* 194 197 71 37 21 18 26 ill 447 521 481 338 207 1951* 101 33 21 19 15 14 27 124 325 518 376 505 174 1.9.52* ___88_____.__ 5J_ 30___ 18 - __16 _ 16 14 66 __.375 __ 572 434 268 163 1953* 337 263 124 58 44 30 61 281 928 711 513 294 305 _fi954* 257__ 69- . -40 -32 -:-:33 -- :-28: _- 30 .. -::173 409 - .420 ---384.=- -201.- 1-74 1955* 168 145 51 42 24 18 18 72 291 643 407 273 181 1956* 81 42 25 20 17 l5 22 121 269 471 453 215 147 1957* 65 56 52 22 19 20 29 166 449 359 370 565 181 1958* 207 161 56 44 29 25 66 178 535 449 418 155 194 1959 183 61 39 29 17 18 31 190 780 399 290 121 181 1960 ill 95 50 46 29 26 28 289 494 534 378 268 197 1961 168 103 101 104 204 64 51 273 497 587 434 342 237 1962 ' 225 77 "34 32 34 18 33 123 403 548 1335 175 171 1963 65 120 47 48 40 37 36 132 338 533 417 293 176 1964 123 55 54 38 44 31 80 192 519 595 493 249 200 1965 192- -85 58 48 135 _ 33 73 146 295 __.430 375 _ 390 lgl 1966 139 35 33 46 27 - 23 40 115 418 430 411 518 187 1967 325 109 39 32 39 29 28 142 455 422 442 666 228 1968 184 76 59 60 39 44 29 208 358 420 373 210 173 1969 180 51 26 10 15 17 30 184 585 479 280 201 165 1970 400 173 156 65 63 40 56 187 510 500 446 195 234 1971 94 188 54 34 38 26 22 96 441 729 580 322 220 1972 188 61 30 17 15 15 17 69 293 485 425 286 157 1973 150 63 34 22 23 20 26 121 295 395 274 237 139 1974 74 43 28 33 14 16 26 166 383 432 335 374 161 1975 230 106 61 37 25 30 29 214 374 501 365 278 189 1976 258 72 31 18 23 18 23 133 397 420 395 500 191 1977 222 222 151 42 78 43 51 195 698 595 602 272 235 1978 226 114 38 53 46 41 36 197 440 445 415 468 211 1979 296 131 58 68 21 21 48 210 399 557 480 373 223 1980 234 137 49 126 107 65 34 283 445 598 564 360 251 Average 188 106 56 41 34 27 35 168 447 507 414 319 196 * Average Recorded flows - All other flows are synthesized using HEC-4 Monthly Streamflow Simulation Model. 15-12 TABLE 15-2 COMPARISON OF 1982 GRANT CREEK FLOWS WITH LONG-TERM AVERAGE FLOWS JUNE JULY AUGUST SEPTEMBER Grant Creek Flows (cfs) 1982 308 454 372 412 Long -Term Average 447 507 414 319 + Standard Deviation 308-585 400-614 329-498 138-500 Maximum Monthly/ 928 729 602 666 Minimum Monthly/ 269 359 274 121 Kenai River Flows (cfs) 4524 6348 5322 84363/ QGrant/RKenai .068 .072 .070 .049 1/ Based on 33 years of record, 11 of which are recorded flows from the Grant Creek gage and 22 of which are extended using HEC-4. 2/ From 33-year record. 3/ Glacial outburst flood occurred in this month. Records have not been adjusted to reflect this. 15-13 FALLS CREEK/GRANT CREEK MONTHLY STREAMFLOW RATIOSY Ratio Falls/Grant Grant Creek?/ Falls Creek3/ at Diversion Flow (cfs) Flow (cfs) Adjusted for Spill May 0.052 168 8.7 June 447 108.2 0.242 July 507.. __ 106.8 0.211 _ __-- August 41:4 _ _ 60.4 0.146 September 319 42.7 0.134 October 188 11.7 0.062 ?� Diversion of Falls Creek to Grant Lake is assumed to occur from May l to October 31, with the diversion being closed for the remainder of the year. 2/ Average monthly flows in Grant Creek based on 33 years of record. 3/ Average monthly flows in Falls Creek at diversion damsite based on streamflow data collected in 1982 and adjusted for spill and areal difference of drainage area at damsite versus gaging station. TABLE 15-4 GRANT LAKE PROBABLE MAXIMUM STORM, 6-HOUR PRECIPITATION AND TEMPERATURE VALUES August September Sea -Level Sea -Level 6-Hour Precipitation (in) Temperature Precipiptation (in) Temperature Period Total Increment (OF) Total Increment (OF) 1 7.2 7.2 60.0 7.4 7.4 58.2 2 10.9 3.7 59.0 11.3 3.9 57.0 3 13.8 2.9 58.1 14.2 2.9 56.1 4 16.3 2.5 57.3 16.8 2.6 55.4 5 18.2 1.9 56.6 18.8 2.0 54.7 6 20.0 1.8 56.0 20:6 1.8 54.1 7 21.8 1.8 55.4 22.4 1.8 53.5 8 23.1 1.3 54.8 23.8 1.4 52.9 9 24.1 1.0 54.2 24.8 1.0 52.4 10 25.0 0.9 53.7 25.8 1.0 51.9 11 25.9 0.9 53.2 26.7 0.9 51.4 12 26.7 0.8 52.8 27.5 0.8 50.9 15-15 2562B •. f i 16.0 POWER OPERATION STUDIES 16.1 POWER STUDY OBJECTIVES Power studies were performed throughout the course of the feasibility study for the following purposes: 1) Comparison of energy output and reservoir operation characteristics for project development alternatives A, B, C, D, E and F. The results of these power studies were presented in the Interim Report (Ebasco, 1982) and are summarized in Section 16.4. The estimates of energy output, along with comparative cost estimates and environmental considerations, provided the basis for selection of the lake tap alternatives (D and F) for more detailed study. 2) Comparison of energy output for various instream flow release schemes which were considered during the analysis of fisheries mitigation alternatives. The results of these power studies are presented in the Environmental Report, Volume II. 3) Estimation of energy and dependable capacity for various levels of installed capacity for the lake tap alternatives for use in optimization studies and economic analysis. The results of these power studies are presented in Section 16.5. 16.2 STUDY METHODOLOGY Power operation studies were performed using a single reservoir computer model developed by Ebasco which simulates, on a monthly basis, the energy production from a given set of constraints for the period of hydrologic record as developed in Section 15.0. The operational priority of the model is to first meet a specified energy generation requirement each month, then fill the reservoir, generate secondary 16-1 5602E energy and, if unavoidable, spill excess water. The model determines, by an iterative process, the quantity of water required to produce the specified amount of energy using the average gross head available during the month, minus the head loss. The quantity of water released and the average net head available during the month are converted to energy production. 16.3 INPUT DATA ' 16.3.1 Grant Lake Inflows A total of 33 years of monthly inflow data for Grant Creek was used as the streamflow.input data for the operation study. The development of the monthly streamflow record for Grant Lake is described in Section 15.4, and a tabulation of the flows is given in Table 15=1. 16.3.2 Available Storage in Reservoir Interim Report Studies, Area -capacity data used in the Interim Report studies for the reservoir above elevation 696 was determined using 1"=400' scale, 10 foot contour (" interval mapping of the entire Grant Lake rim which was prepared during the 1981 field investigations. This area -capacity data was used in the power studies for Alternatives A, B, C, and E. The volume of the reservoir between elevation 696 and elevation 650 (used in power I. studies for Alternatives D and F) was estimated using available USGS bathymetric data for portions of lower Grant Lake and extrapolation of the slope of the existing shoreline in areas where bathymetric data did not exist. It was recognized during the Interim Report investigations that further studies of Alternatives D or F should include obtaining more complete bathymetric data for Grant Lake. 16-2 5602B Studies Performed Subsequent to Interim Report After submittal of the Interim Report in February 1982 and authorization from the Power Authority to proceed with further studies on the lake tap alternatives, a bathymetric survey of Grant Lake was performed in the summer of 1982. This survey provided bathymetric mapping of the lake bottom for both the upper and lower basins of Grant Lake at a scale of 10=400 feet, with a 10 foot contour interval. The mapping was used to develop area capacity data below elevation 696, and the topographic mapping obtained in 1981 was used for elevation 696'and above. This data is tabulated in Part VII of the Technical Appendix and is summarized as an area capacity curve on Figure IV-14. Also, a survey was performed in 1982 to establish the control elevation of the natural outlet of the lake. This elevation was determined to be 691 MSL, and was used as the normal maximum reservoir elevation in the power studies. 16.3.3 Efficiencies A constant overall power plant efficiency of 0.854 was assumed for the range of operating heads and flows through the turbine for calculation of energy generated. This value is based on efficiencies of 88 percent for the turbine, 98 percent for the generator and 99 percent for the transformer. A constant efficiency is considered appropriate because of the relatively limited range of heads over which the turbine would operate. 16.3.4 Tailwater Elevation All power studies performed in support of findings in the Interim Report and for evaluation of instream flow alternatives (July 1982) used a tailwater elevation of 470 MSL. In August 1982, a bathymetric survey was performed of Upper Trail Lake in the area where the tailrace 16-3 channel would be located. This information, along with seasonal water level data for Upper Trail Lake and the configuration of the tailrace channel, was used to estimate a constant tailwater level of elevation 468.1 at the powerhouse. This value was used in all power studies performed for project optimization studies and economic analyses. 16.3.5 Monthly Operational Strategy The demand of energy drives the computer model used in the power ---operation- stud-i-es. --For--large -proposed--hydro --projects where a_majo_r -portion -of--the region '-s-energy--woul-d -be--provided- by--the---project;-it is conventional for the demand used in the operational model to closely track actual energy demand in the region, since it is necessary to find a sufficiently large market in which to sell the energy. Table 16-1 provides data on historical monthly energy consumption for the Anchorage/Cook Inlet region and the City of Seward. Grant Lake is a relatively small resource, whose supply of energy is always available to displace gas generation. Hence, the best use of the resource is to maximize energy output while simultaneously maximizing available dependable capacity during the peak winter months of November, December, January, and February in order to displace an increment of new combined cycle combustion turbine construction. Successive iterations were run for each power study in the final report to find the optimal target energy generation distribution on a monthly basis. This effectively defines an operating rule for the project. The strategy can be summarized as follows: refill the reservoir during June, July and August while meeting energy demand percentage close to the demand for the region. During September and October, a lower demand is targeted in order to conserve water for the critical months of November, December, January, and February. On the average, more energy is generated during September and October than in June, July, and August since the reservoir usually refills by September; however, during very dry summers and early falls, hedging is allowed to conserve 16 -4 water for the winter months. During the winter months, sufficient energy is targeted to meet peak energy requirements and ensure adequate capacity, even during the second worst year of the period of record. March has a low target energy and capacity to ensure at least some capacity on a year round basis. The remaining water is dumped during April and May to prepare the reservoir for refilling during the spring run-off season. This strategy almost totally eliminates spill and maximizes energy production and capacity credit. 16.3.6 Minimum Streamflow Requirements For power studies performed in support of the findings presented in the Interim Report, the instream flow requirements were taken to be zero for all six project development alternatives. Subsequent to the submittal of the Interim Report, studies were conducted in consultation with Alaska Department of Fish and Game, U.S. Fish and Wildlife Service and National Marine Fisheries Service, which evaluated available power output associated with a range of instream flow release alternatives. These flow release schemes ranged from 15 cfs to 100 cfs. After evaluation of numerous fisheries mitigation plans was completed, a plan was selected which did not include a minimum flow release (details of this analysis is presented in the Environmental Report, Volume II); thus, all final power studies used for optimization and economic analyses were performed using no instream flow. 16.3.7 Falls Creek Diversion Flows For the evaluation of the diversion of Falls Creek (Alternatives E and F), the flow data for falls Creek was generated by applying ratios to the Grant Creek monthly flows. A description of the derivation of these ratios is provided in Section 15.4. The diversions from Falls Creek were limited to the wet season from May to October. 16-5 5602E 16.4 SUMMARY OF INTERIM REPORT STUDIES A primary objective of the Interim Report studies was to provide an economic evaluation of the six alternative project arrangements (Alternatives A through F), based on a comparison of the cost of energy from each alternative. Accordingly,. --power -stud-ies were conducted -to estimate theavailableenergy from each alternative. - - _ i To determine the installed capacity to be used in the comparison of the alternatives, a brief study was conducted to identify the approximate j installed capacity that would provide the lowest cost of power for the I -- -- - - - - - - - - - - --- - - - various alternatives. This was accomplished by evaluating the effect that varying the installed capacity had on potential energy production and on the construction cost. This analysis led to the selection of a I 6 MWinstallationfor Alternatives A, B,-C, and F,-a 5 MW installation for Alternative D, and a 7 MW installation for Alternative E. - -A-detailed attempt was-not -made-in.--the.-February, t--made in--the.-Februar-y,- 1982 Lnter-irn-Report _ studies to optimize the installed capacity for any of the six alternatives. As discussed below, optimization studies were performed to establish the installed capacity for the preferred alternative for the feasibility report. A summary of the results of the Interim Report operation studies for each alternative is shown on Table 16-2. The table shows the average annual energy produced for the 33-year period for which the power studies were performed, along with other operational data. No transmission loss was included in the energy production calcuations for the comparison of alternatives, since transmission losses would be essentially equal for each alternative. The power study results were used in combination with construction cost estimates to establish an energy cost for each alternative. These costs, which are shown in Section 14.0 of the Interim Report along with 16 -6 5602E environmental considerations, were utilized to arrive at a recommendation in the report to proceed with more detailed studies of the lake tap alternatives (D and F). 16.5 DETAILED POWER STUDIES PERFORMED FOR LAKE TAP ALTERNATIVES 16.5.1 General After authorization from the Power Authority was received to proceed with more detailed studies on the lake tap alternatives, refinements were made to the input parameters, based on the results of additional field and office investigations performed in 1982. This included the tailwater elevation, the normal maximum reservoir elevation, the available storage in the reservoir, and the arrangement of project features, which affects head losses. With these refinements incorporated into the operational program, power studies were performed for the purpose of optimizing the installed capacity, evaluating whether the Falls Creek diversion should be included in the project, and for performing the economic analysis for the project. 16.5.2 Data Obtained from Detailed Power Studies Power studies were performed for a range of installed capacities (6 to 8 MW) to estimate energy and dependable capacity values for use in the process of optimizing the installed capacity for Alternative D (lake tap without Falls Creek diversion). After the optimum plant size (see Section 16.6) was determined for Alternative D (7 MW), power studies were performed for an 8 MW installation for Alternative F (lake tap with'Falls Creek diversion) for the purpose of evaluating whether the Falls Creek diversion should be included in the project. The results of these power studies are summarized on Table 16-3. For each value of installed capacity, the following values were obtained from the power studies: average annual energy, firm energy, secondary energy, and dependable capacity. An explanation of each of these values is provided below. 16-7 5602E � Average Annual Energy - This is the total energy available from the | project per year on an average basis, computed by dividing the total enargy produced from the entire period of hydrologic record by the � number of years in the record (33 years). Firm Energ-v - Firm energy is that generated on an annual basis during | ' - severe low flow conditioOs. For the purpose of this study, it is considered reasonable to base the available firm energy of the project / on the amount of energy Which is generated during the water year with the second most adverse hydrologic period' A low flow frequency / --------��aOal ' 1wh�ch--wdaperformed f or the 33years. -of - -record -used-1D the powerworst-year-hasrecurrence- interval ---- --- -studies -shUwed��that �-the second -wor- , ��-a----,-------'-- ' - . of approximately 25 years. Secondary Energy ' - The secondary energy i�^the ^ difference between ^the average annual energy and firm 8OOua| energy. - De --pe - -nd - --- --' le ---- ---l- - - ab ty - The d�p�Od8b cap��lty of � h�Uroa electric p|anT is considered herein as that available (at full Sat' operation) during ' ` the simultaneous occurrence of the highest peak demand period of the - year and severe low water conditions. The second worst hydrologic year Of record Was Used for this analysis, Which is consistent With the '- approach discussed above for firm energy' The highest peak demand months Were taken to be November through February, based on inspection ( of demand curves for the Ra1lbelt region. / 16.5.4 Utilization of Power Study Results The values of average annual energy and dependable capacity obtained from the power studies were utilized in the optimization studies described below in Section 18.8. At ~indicated in that Section, the optimum installed capacity for Alternative D was determined to be 7 MW and inclusion of the Falls Creek diversion works was found to be uneconomical. The power output values,for the 7 MW plant Were then lh-B 5OO2B utilized in the economic analysis presented in Part I of the report. Figure IV-16 graphically shows for an average hydrologic year the monthly variations in powerhouse discharge and reservoir level which would result from the proposed operation of the project for Alternative D. 16.6 SELECTION OF OPTIMUM INSTALLED CAPACITY FOR ALTERNATIVE D 16.6.1 General The procedure used for establishing the optimum installed capacity for the project was to first optimize the plant size for Alternative D, and then investigate whether it is economical to divert Falls Creek into Grant Lake (Alternative F). Once the basic project arrangement for Alternative D was established as discussed in Section 12.0, an optimization study was conducted to determine the most cost-effective installed capacity for the project. Costs and benefits for the project were estimated for installed capacities ranging from 6 to 8 MW. .The point at which the benefit -cost ratio from the project is maximized becomes the optimum installed capacity. The benefits and costs were computed for each year of the 50 year life of the hydro project, which was taken from 1988 through 2037. The cumulative present worth of each year's benefits and costs were then computed and expressed in January 1983 dollars. A more detailed description of this procedure is provided below. 16.6.2 Project Costs For each plant size, the cost of those items which would not vary as a function of installed capacity were obtained from the FERC code of accounts, contained in the cost estimate in Section 18.0. 16-9 5602B For those items which would vary in costs with installed capacity, cost estimates were developed for each level of installed capacity investigated, based on preliminary pricing data obtained from equipment suppliers and experience with similar projects. These items included the turbine, generator, governor, miscellaneous mechanical and electrical equipment, and civil -structural costs which would result i from varying the size of the powerhouse and tailrace. The total- construction costs so computed are shown on Table 16-4. 1 The annual operation and maintenance costs for the hydro project used are as developed in Section 18. The same operation and maintenance - - - - costs were used.for each installed capacity, because the difference in operation and maintenance costs between a 6 to 8 MW plant was considered to be insignificant. The total annual costs for each project were developed by amortizing the capital cost using APA criteria for interest rates and economic - fife,- and.. adding-- the- debt- se-rvi-ce -to-. the _annual_ operat.i.on and maintenance costs. The resulting total annual cost and 50 year cumulative present worth of project costs are shown on Table 16-4. 16.6.3 Project Benefits The amounts of energy and dependable capacity available from each level of installed capacity investigated were obtained from the power operation studies derived above in Section 16.5. The monetary value associated with the available energy and capacity is based on the cost of obtaining the same amount of power, as delivered to Seward, from the most economical alternative generation resource. The development of the alternative generation costs are discussed in detail in Section 4.0. The Base Case plan is the most economical plan for meeting Seward's projected loads, without the Grant Lake Project. Using the results of the Base Case Plan, the alternative resource against which Grant Lake was compared for computation of benefits is a combination of existing and new gas -fired generation. 16-10 1 5602E I The basic assumptions used in computing the value of the various components of'the project benefits are as follows: Avera4e Annual Energy - The value of the average annual energy from the project is taken to be the total variable annual cost (fuel plus operation and maintenance) of providing the same amount of energy from the gas -fired alternative described above. The price of natural gas and operation and maintenance costs for gas -fired generation are developed in detail in Section 4.0. Dependable Capacity - The value of dependable capacity from the project is based on the capital cost and fixed operation and maintenance costs of new combined cycle 9eneration. The cost of alternative combined cycle generation is developed in Section 4.0. 16.6.4 Results of Optimization Studies for Alternative D Using the assumptions and procedures outlined above, the benefits and costs were computed for a project having an installed capacity of 6, 7, and 8 MW. The results of this analysis are presented on Table 16-4. The analysis indicates that a 7 MW installation is the most cost effective plant size for development of the project without the diversion of Falls Creek. 16.7 EVALUATION OF ECONOMICS OF FALLS CREEK DIVERSION 16.7.1 General An analysis was performed to determine whether the diversion of Falls Creek into Grant Lake should be included in the project to obtain additional runoff for power generation. This analysis included comparing the economics of Alternatives D and F. 16-11 As discussed above, optimization studies performed for Alternative D showed that a 7 MW installation is the optimum size for the project without the diversion of Falls Creek. An 8 MW project was selected for Alternative F, since _the _plant factor_(ratio of- average annual -generation to the generation _. produced by conti.nuous_..plant oper..ati_on_throughout the__year_at capacity) for the optimized MW Alternative D project is 0.41, and applying the same plant factor to the available energy from Alternative F provides a value of 8 MW. On this basis, an 8 MW installation should represent about the optimum project size.for Alternative F. Ths was verified by computing benefit -cost ratios for A]ternative,__F__f_o.r_.__a _7_._MW and _9,MW..p.rojec_t,_._and__the_re_s.ults—of._..thi_s_.__che.ck..__.._ confirmed that the 8 MW size is the optimum installation for Alternative F. Having arrived at a plantsizefor Alternative F, the comparison of the project economics with and without the Falls Creek diversion was conducted using the following steps: l 1) Evaluation of project power output with and without the Falls Creek Diversion Works; 2) Evaluation of project construction and operation and maintenance costs with and without the Falls Creek diversion works; and 3) Comparison of benefit -cost ratios and levelized cost of energy from the project with and without the Falls Creek diversion works. Each of these steps are discussed below. 16.7.2 Power Output Evaluation Power studies were performed to estimate the power output available from an 8 MW installation with the Falls Creek diversion; using the same power operation program as was used for the optimization studies for Alternative D. The results of these studies are shown on Table 16-3. ,le 16.7.3 Project Costs The construction cost and operation and maintenance costs for Alternative D are developed in Section 18.0 along with the additional cost of Falls Creek diversion works. The total construction costs of Alternatives D and F are summarized by FERC accounts on Table 16-5. The costs for the Falls Creek diverson works were developed to the same degree of detail as the costs for Alternative D, and, accordingly, the same level of contingency has been applied to the cost estimate for both Alternatives D and F. The annual operation and maintenance cost for Alternative D of $302,000 is also developed in Section 18.0. An additional $20,000 was added to the operation and maintenance cost estimated for Alternative F to provide for maintenance of the Falls Creek diversion works. The total annual costs for Alternatives D and F are developed on Table 16-5, using APA economic analysis criteria for fiscal year 1983 to designate the interest rate, amortization period, etc. 16.7.4 Economic Comparison of Alternatives D and F Comparison of Benefit -Cost Ratios - The benefits for the 8 MW Alternative F were computed in the same manner as described above in Section 16.6.3 for the optimization of Alternative D. As shown on Table 16-5, the benefit -cost ratio for Alternative F is 1.05 and the corresponding value for Alternative D is 1.20, which indicates that Alternative D is more economical than a project that includes the Falls Creek diversion. Comparison of Levelized Cost of Power - To provide another basis for comparing the econonics of Alternatives D and F, the levelized cost of energy was computed for both cases. As shown on Table 16-5, the cost of energy for Alternatives 0 and F is 53.4 mills/kWh and 16-13 5602B 59.9 mills/kWh, respectively. This shows that the cost of energy from a project that includes the Falls Creek diversion is 12 percent higher than the project without the diversion. Based on these comparisons of benefit -cost ratios and levelized cost of power, it -was concluded that it is not economical to include the Falls Creek diversion works in the Grant Lake Project. Accordingly, Alternative D was adopted for detailed development in the selected project arrangement, which is discussed in Section 17. 16-14 5602B TABLE 16-1 DISTRIBUTION OF MONTHLY ENERGY CONSUMPTION FOR ANCHORAGE/COOK INLET AREA AND CITY OF SEWARD Distribution of Energy Consumption (Percent of Annual Demand) Month Mid -Range Energy Distribution Energy Distribution for Anchorage -Cook Inlet Area/ for City of Seward?/ October 8.2 7.6 November 9.3 9.5 December 10.6 9.4 January 10.2 7.5 February 9.2 8.1 March 9.2 9.0 April 8.0 8.8 May 7.4 8.4 June 6.7 9.1 July 6.8 8.2 August 7.0 7.2 September 7.4 7.5 ?/ From Bradley Lake Power Market Report (Alaska Power Administration, 1982), Section 4. Values are based on averaging utility data from 1975 to 1980. 2/ Values are derived from energy consumption data for the City of Seward for July 1980 to June 1982. 16-15 5602B TABLE 16-2 SUMMARY OF RESULTS OF POWER STUDIES PERFORMED FOR INTERIM REPORT�� - Alternative Project Arrangement A g g D E F ' Average Annual Inflow _196 _ 196 196 196 234 _ 234_- Power pool Limits r (Water Surface El) 745-710 745-710 745-710 690-660 745-710 690-660 Installed Capacity ' (MW) 6 6 6 5 7, 6 Rated Net Head (ft). 2,47 243 239 198 249 194 Rated Flow (cfs) 329 334 339 __ 342 _ 380 _. 419 Average Annual Power- house Flow (cfs) 191 192 192 190 225 224 Average Annual - 6 9 10 Spill (cfs) 5 4 4 Averagge Annual Energy (GWH)?� 29.9 29.5 29.1 23.8 35.6 27.6 Annual Plant Factor .57 .56 .55 .54 .58 .52 ?/ These values are not used in economic analysis of Grant Lake project. 2/ Energy values are at the powerplant at high voltage side of the transformer, before transmission line losses. 16-16 5602B TABLE 16-3 SUMMARY OF RESULTS OF POWER STUDIES PERFORMED FOR OPTIMIZATION OF LAKE TAP ALTERNATIVE!/ Installed Ca acit MW Alt D Alt D', Alt D Alt 6 7 ,i 8 8 Average Annual Inflow (cfs) 196 Power Pool Limits (Water Surface El) 660-691 Rated Net Head (ft) 208 Rated Flow (cfs) 390 Average Annual Powerhouse Flow (cfs) 190 Average Annual Spill (cfs) 5 Average Annual Energy at Plant (GWH) 25.27 Average Annual Energy at Load Center (GWH)Z/ 24.82 196 196 221 660-691 660-691 660-691 206 4 204 206 1 459 i 531 525 194 195 221 2 1 3 25.40 25.26 28.99 24.94 24.81 28.47 Firm Annual Energy at Load Center (GHW)Z/ 18.85 j 18.48 18.42 21.56 Secondary Annual Energy at Load Center (GHW)Z/ 5.97 ! 6.46 6.39 6.91 Dependable Cappacity at Load i Center (RW)31 5.70 1 6.55 ; 7.02 7.02 Annual Plant Factorl/ 0.48 0.41 0.36 0.41 1/ Values shown for Alternative D (7 ) used �economic analysis. ?� Values shown are at load center (Seward), after reduction of at -plant values for 1.8% station service and transmission losses on energy. 3� Values shown are at load center (Seward), after reduction for 0.8% transmission losses on capacity. 4 The plant factor is calculated by dividing the average annual energy at plant in by the product of 8,760 hours and the installed capacity in MW. i i 16-17 TABLE 16-4 DETERMINATION OF OPTIMUM INSTALLED CAPACITY FOR ALTERNATIVE DI/ INSTALLED CAPACITY FERC 6MW 7MW BMW ACCOUNT DESCRIPTION (S1000) ($1000) ($1000) PRODUCTION PLANT --------------- LAND AND LAND RIGHTS 0 0 0 331 STRUCTURES AND IMPROVEMENTS 2435 2724 2968 332 RESERVOIRS, DAMS AND WATERWAYS 7312 7352 7389 333 WATER WHEELS, TURBINES AND GENERATORS 2733 3001 3295 334 ACCESSORY ELECTRICAL EQUIPMENT 1300 1428 1569 --- _335 - M-I-SCEL-L-ANEOUS--POWER-PL-ANT--EQUIPMENT _ ___-----645- -------645-- ----- 646- --- - __._ . ROADS, RA.ILROADS__AND BRIDGES ___ _ _ 1498 1499 1498 352 353 355 356 61 64 69 60 TOTAL PRODUCTION PLANT 15923 16648 TRANSMISSION PLANT TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS STATION EQUIPMENT WOOD POLES AND FIXTURES OVERHEAD CONDUCTORS AND DEVICES TOTAL TRANSMISSION PLANT TOTAL DIRECT COSTS INDIRECT COSTS TEMPORARY CONSTRUCTION -FACILITIES LABOR EXPENSE MOBILIZATION/DEMOBILIZATION TOTAL INDIRECT CONSTRUCTION COSTS "SUBTOTAL CONTINGENCY SUBTOTAL INCLUDING CONTINGENCY 17364 5 5 5 469 469 469 46 46 46 73 73 73 593 593 593 16516 17241 17957 ENGINEERING 8 OWNER ADMINISTRATION TOTAL PROJECT COSTS (IN JANUARY, 1983 DOLLARS) DEBT SERVICE 0$M TOTAL ANNUAL COST PRESENT WORTH OF COSTS/ AVERAGE ANNUAL ENERGY AFTER LOSSES (GWH)3/ PRESENT WORTH OF ENERGY BENEFIT4/ DEPENDABLE CAPACITY AFTER LOSSES (MW)3/ PRESENT WORTH OF CAPACITY BENEFIT'Y PRESENT WORTH OF BENEFITS BENEFIT COST RATI06/ 200 200 250 ISO 150 195 826 862 898 1176 1212 1343 17692 18453 19300 2654 2768 2895 20346 21221 22195 2847 2971 3107 23194 24192 25302 989 1031 1079 302 302 302 1291 1333 1381 26386 27256 28222 24.82 24.94 24.81 21396 21498 21379 5.70 6.55 7.02 9719 11156 11967 31115 32654 33346 1.18 1.20 1.18 1/ All costs in. January 1983 dollars. / Based on 3.5% interest and a 50 year life. $/ Transmission losses to Seward are 1.8% for energy and 0.8% for capacity. Based on value of displaced combined cycle combustion turbine variable 5/ costs (see Section 4.3.3). Based on value displaced combined cycle combustion turbine capital and 6/ fixed costs. Ratio of present worth of benefits to present worth of costs. k TABLE 16-5 COMPARISON OF ECONOMICS OF LAKE TAP ALTERNATIVE WITH AND WITHOUT FALLS CREEK DIVERSION1/ ALTERNATIVE D ALTERNATIVE F (W/O FALLS CR) (W/FALLS CR) FERC 7 MW BMW ACCOUNT DESCRIPTION ($1000) ($1000) PRODUCTION PLANT LAND AND LAND RIGHTS 0 0 331 STRUCTURES AND IMPROVEMENTS 2724 2968 332 RESERVOIRS, DAMS AND WATERWAYS 7352 11617 333 WATER WHEELS, TURBINES AND GENERATORS 3001 3295 334 ACCESSORY ELECTRICAL EQUIPMENT 1428 1569 335 MISCELLANEOUS POWER PLANT EQUIPMENT 645 645 336 ROADS, RAILROADS AND BRIDGES 1498 2430 TOTAL PRODUCTION PLANT 16648 22524 TRANSMISSION PLANT 352 TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS 5 5 353 STATION EQUIPMENT 469 469 355 WOOD POLES AND FIXTURES 46 46 356 OVERHEAD CONDUCTORS AND DEVICES 73 73 TOTAL TRANSMISSION PLANT 593 593 TOTAL DIRECT COSTS 17241 23117 INDIRECT COSTS 61 TEMPORARY CONSTRUCTION FACILITIES 200 250 64 LABOR EXPENSE 150 195 69 MOBILIZATION/DEMOBILIZATION 862 1156 60 TOTAL INDIRECT CONSTRUCTION COSTS 1212 1601 SUBTOTAL 18453 24718 CONTINGENCY 2768 3708 SUBTOTAL INCLUDING CONTINGENCY 21221 28426 ENGINEERING & OWNER ADMINISTRATION 2971 3980 TOTAL PROJECT COSTS (IN JANUARY, 1983 DOLLARS) 24192 32406 DEBT SERVICE 1031 1382 0 & M 302 322 TOTAL ANNUAL COST $ 1333 1704 PRESENT WORTH OF COSTS-2/ 27256 34821 AVERAGE ANNUAL ENERGY AFTER LOSSES (GWH)3/ 24.94 28.46 PRESENT WORTH OF ENERGY BENEFIT4/ 21498 24528 DEPENDABLE,CAPACITY AFTER LOSSES (MW)3/ 6.55 7.02 PRESENT WORTH OF CAPACITY BENEFIT5/ 11156 11967 PRESENT WORTH OF BENEFITS 32654 36495 BENEFIT COST RATIO6/ 1.20 1.05 LEVELIZED COST OF ENERGY (MILLS/KWH) 53.4 59.9 Y All costs in January 1983 dollars. 2/ Based on 3.5% interest and a 50 year life. Transmission losses to Seward are 1.8% for energy and 0.8% for capacity. $/ Based on value of displaced combined cycle combustion turbine variable costs (see Section.4.3.3). 5/ Based on value displaced combined cycle combustion turbine capital and fixed costs. 6/ Ratio of present worth of benefits to present worth of costs. 2835B 16-19 17.0 SELECTED PROJECT ARRANGEMENT 17.1 GENERAL The studies conducted through the Interim Report phase developed six technically attractive hydroelectric development scenarios for Grant Lake. They are presented as Alternatives A through F in Section 12.0 and are shown on Figures IV-3 through IV-7. Based on an economic comparison of these alternatives, Alternative F was originally selected for detailed feasibility studies. Alternative F would require a lake tap intake structure on Grant Lake which would draw the lake down from its present level. The flow would be directed through a tunnel to a powerhouse on Upper Trail Lake. Additional power output would be achieved by diverting flow from Falls Creek through a buried pipeline to Grant Lake. As a result of plant optimization studies performed during the detailed feasibility effort, however, it was concluded that the Falls Creek diversion portion of the selected Alternative F arrangement should be deleted (see Section 16.7). It was furthermore concluded from the optimization studies that the project, which i.s essentially Alternative D, should have an installed capacity of 7 MW (2 MW greater than Alternative D identified in the Interim Report). The project arrangement and associated features described in this section are refinements of Alternative D and are the culmination of a level of engineering commensurate with a detailed feasibility study. The results of additional geotechnical field activities, and topographic and bathymetric surveys have been incorporated into these studies. The finalized project layout is shown on Figure IV-17 and a plan and profile of the power conduit are shown on Figure IV-18. 17-1 2510B 17.2 RESERVOIR Grant Lake will serve as the storage reservoir for the project (see Figure IV-2). The lake fills an L-shaped depression over six miles / long and in some areas is as deep as 300 feet. The natural outlet for -'the-Take-i�-GraDi�Cregk,o�hirh'is/at PlgVatioR-891-at the lVWpo1nt of \ .,the oUtl$t� The total VolU0� of Grant Lake below elevation 691 is �� 240,000 acre-feet and will provide 48,OUU acre-feet of active storage > ` between the '0iDimU0 pool at elevation 660 and the maximum pool at elevation 691'feat. / / Grant Lake actually consists.of two lakes connected by a natural constriction at the midpoint of the L-shaped depression. The two bodies of water are referred to as Upper and Lower Grant Lake' The ~^. pru]ect"s intake /structure will be located on Lower Grant Lake,the / westernmost leg of the lake. . \ - -The--selected,pro' c-t--`a W1l1-l1Ot-reqUire-the-cqnstructionof dams on Grant Lake. The active storage for power generation will be obtained by drawing the lake down from its present levels by a completely sUbmer8ed lake tap intake. The reservoir level fluctuations during d normal operational year are shown on Figure IV-18. As � - - mentioned earlier, the, reservoir will -annually -fluctuate between'- | elevation 880 and 891. The absolute maximum reservoir level occurring \ during the PMF will be elevation 709.2 and the absolute minimum level during a record drought year will be regulated to elevation 660' Refer ! | to Section 15.0 for a detailed hydrologic discussion of the lake fluctuations during the PMF. | The operation of the project will result in asgasonal lake level fluctuation of 31 feet below its present level, Which would expose and UOWater the natural constriction connecting Upper and Lower Grant Lake' Therefore, a channel Will be excavated through the constriction to allow for the passage of adequate flow (see Figure IV-19). This l7-2 25lO8 channel will be approximately 1200 feet long and 40 feet deep at its maximum section. The channel will be cut using conventional blasting techniques over most of its length during the winter months when the constriction freezes over. During the warmer months, the resulting channel will be dredged open. The project will be drawing the reservoir down from its present level, and therefore no additional reservoir work, such as clearing and grubbing, will be required. 17.3 INTAKE AND GATE SHAFT The intake will be located on the west shore of Lower Grant Lake approximately 900 feet north of the Grant Creek outlet (see Figure IV-17). Details of the intake and gate shaft are shown on Figure IV-20. The lake tap intake consists of a 10 foot diameter inclined tunnel with an invert at elevation 643. Downstream of the intake tunnel a rock trap will be provided to catch broken rock and debris entering the intake upon blasting the final segment of tunnel. After the final blast shot is made and the intake is filled with water, a semi -cylindrical steel trashrack will be installed over the resulting opening. This trashrack will be lowered in place by a barge -mounted crane and installed by divers. Rock bolts and tremie concrete will anchor it in place. From the intake a 9-foot inside -diameter horseshoe -shaped tunnel will emerge. This 90-foot long tunnel segment will be lined with 3 inches of shotcrete and rockbolted, as required. For estimating purposes and based on available geotechnical information, it is assumed that 15% of the entire tunnel will require rockbolting. The tunnel will then transition to a 10.5 foot -high, 7.5 foot -wide rectangular section directly beneath the gate shaft. This rectangular section will serve to seat the slide gate when in the down position. 17-3 2510E The gate shaft and gate house will be located, approximately 200 feet downstream of the intake. The gate house will be set in a rock cut at elevation 715 as shown on Figure IV-20. This will place the gate house i well above any reservoir level, including the PMF event. Due to the presence of steeply sloped rock bedding planes in this area, which could result in a slope instability problem, considerable rockbolting - is provided tostabilizethe cut.- Drainage holes are also provided to help relieve hydrostatic pressures in the cut. In an effort to minimize the size of cut and the amount of exposed rock, the gate house will be set back into the rock. Its north and west walls will be concrete, placed and tied directly against the rock. The south and east walls will be constructed using aluminum siding to minimize cost - - The entire gate house/gate shaft structure houses'a single 9 foot by 12 foot slide gate. This gate will have a downstream seal. Lift for the gate is provided by a hydraulic hoist and electrical controls for the hoist will be located in the gate house. Ladders will be provided in the shaft for access to the tunnel. Electrical power will be provided to the gatehouse from the powerhouse via a buried conduit within the access road right-of-way. 17.4 POWER CONDUIT The power conduit for the project consists of a gradually -sloping, low level horseshoe -shaped tunnel with an inside diameter of 9 feet at the spring line. The tunnel, shown in plan and profile on Figure IV-18, is approximately 3,200 feet long and connects the intake directly to the powerhouse. This profile was selected to facilitate construction and eliminate the need for a surge chamber. The determining factor in sizing the tunnel was space requirements for construction rather than hydraulics; therefore, the tunnel diameter was selected to provide the minimum practical cross section which would still provide the required 17-4 2510E space for construction activities. Studies were performed to verify that increasing the tunnel size would not increase the net benefits from the project, since the velocities in the 9 foot diameter tunnel are relatively low. Excavation of the tunnel will be by conventional drill and blast methods from a single heading at the powerhouse. The tunnel crown and sides will be lined along its entire length with 3-inch average -thickness shotcrete and approximately 15% of the tunnel is estimated to required rockbolting. These lining and support requirements are based on geological conditions assumed to exist n the tunnel as interpreted from the resuts of borings and surface mapping performed along the tunnel alignment. The invert of the tunnel will be lined with 6 inches average thickness of concrete to provide a working surface during excavation. The actual tunnel support and lining requirements may be reduced, based on the actual rock conditions observed during construction. As the tunnel approaches the powerhouse and the available rock cover diminishes, a combination concrete and steel tunnel liner is provided. The steel liner gradually reduces in diameter from 102 inches to 66 inches where it enters the powerhouse. The details of this transition are shown on Figure IV-21. Contact grout will be provided between the steel and conrete liners to ensure bond and homogeneity of support around the steel. Immediately upstream of the steel liner a rock trap will be excavated to catch debris or tunnel spalling that may"occur during the operation of the project. Accumulated debris would be removed via a blockout in the penstock at the powerhouse. 17-5 2510E 17.5 POWERHOUSE AND TAILRACE The powerhouse will be an indoor -type remote controlled structure set into the hillside adjacent to the east shore of Upper Trail Lake. It will be located approximately 3000 feet upstream of the lake outlet (see F-i gures -IV--1.7 and IV.-21) . The, substructure. of,_ the. powerl)ous_e_wi 11 be reinforced concrete founded in rock and the superstructure will be structural steel with aluminum siding as shown on Figure IV-22. The structure is set back into the hillside for several reasons. Doing so will shorten the flow line and eliminate the need for a surface steel penstock; it places the structure in more competent foundation material and it avoids shear zone observed along the Trail Lake valley, believed" - - to be a zone of poor rock quality (see Section 15.4). The powerhouse location will place the shear zone downstream of the structure. The rated flow to the powerhouse will be 459 cfs and the average annual powerhouse flow will be 194 cfs. The unit will be protected by,a - butterfly valve located immediately upstream of the turbine. Discharge from the powerhouse will be.via a 640-foot Long tailrace ' channel excavated to Upper Trail Lake. Velocities in the tailrace will range from approximately 6 fps at the powerhouse to 2 fps at the lake. I, The tailrace will, for the most part,- be excavated -in the -sands and gravels at a 2-horizontal to 1-vertical slope along the shore of the lake. Immediately downstream of the powerhouse, however, the tailrace will be cut in rock. The portion of the tailrace in soil will be lined with riprap to prevent erosion from occurring and depositing sediment in the lake. An aluminum picket fish barrier will be provided across the tailrace to prevent fish from entering the draft tube. The powerhouse will contain a single vertical Francis turbine -generator unit operating at a rated speed of 400 rpm. The turbine will deliver 9,580 hp at a rated head of 206 feet under best gate operation. The I generator will be a vertical shaft three phase synchronous unit rated 17-6 2510E at 7780 kVA with a 90% power factor. This will result in a plant installed capacity of 7000 kW, which will produce an estimated average annual energy of 25.40 GWH, with an annual plant factor of 0.41. See Figure IV-23 for the powerhouse main one line diagram. The generator unit will be enclosed and will utilize surface air coolers, a solid state exciter, governor and a CO2 fire protection system. As mentioned previously, the powerhouse will be'remotely controlled; however, the necessary facilities for manual control will be provided. To facilitate maintenance of the equipment, an overhead crane will be provided in the powerhouse. Periodic inspection of the turbine runner, spiral case and draft tube will be provided by the access galleries shown on Figure IV-22. A single turbine generating unit is proposed for this Project for the following reasons: o A single unit is more economical than multiple units. o The high reliability of hydro generating equipment assures a minimum of unscheduled outages. o The rare unscheduled outage will not adversely affect Seward, since the City's entire load can be supplied via the transmission line to Seward. o No loss of generation from the Project will occur, since the project plant factor is 0.41 and adequate storage exists in the reservoir through most of the year to avoid spills due to unit unavailability. o Frequent scheduled maintenance can be provided to insure reliability. 17-7 2510B 17.6 ACCESS ROADS AND BRIDGES A total.of 2.4_miles of access_ roads will be constructed at the site (see Figure IV-17). The roads are designated as Class A and Class B and typical sections of each are shown on Figure IV-24.. A Class A road will be-used--to-provide-permanent access--from--the Seward -Anchorage -- Highway to the powerhouse.` It will be 24 feet wide plus 5-foot shoulders. Surfacing will be 18 inches of crushed stone. The transmission line connecting the project with the Seward -Anchorage intertie will be within the corridor of this main access road. Class B roads will provide access to all other features. All Class B sections will be 18 feet wide and surfaced with 6 inches of crushed stone. No road grades will be steeper than 8 percent. Two bridges will be constructed at the site as part of the access. system. A 140-foot-long, four -span prestressed concrete bridge will provide the primary access to the site from the Seward -Anchorage - Highway. This bridgewillcross the -Trail -Lakes at thenarrow--- constriction separating the Upper and Lower portions (see Figure IV-17). The second bridge will cross Grant Creek near its outlet at Grant Lake (also shown on Figure IV-17). This bridge will be a 60-foot-long, four -span timber structure and will be used to provide access to the recreation area: 17.7 TRANSMISSION OF POWER The 4.16 kV output of the generator will be transformed to 115 kV by a 9 MVA transformer located in the switchyard. The switchyard will be a short distance to the south of the powerhouse next to the primary access road on a prepared, graveled and fenced site. Located in this switchyard will be a 115 kV circuit breaker and disconnect switch. Also located in the switchyard are smaller necessary items such as 115 kV lightning arrestors, carrier equipment wave trap, potential and current transformer, etc. Refer to Figure IV-23 for a one -line diagram showing this arrangement. 17-8 2510E From the switchyard a 115 kV transmission line is planned that would run alongside the primary access road to the Seward -Anchorage Highway, which is approximately 1.2 miles. At this point the Grant Lake switching station will be provided. This switching station will tie Grant Lake output into the newly planned 115 kV transmission for the City of Seward (see Daves Creek -Seward Transmission Line Investigation in Part III of this study). The 115 kV transmission line planned will be on wood poles and of a compact delta configuration. Preliminary line design criteria indicate that a 336 kcm ACSR conductor with an approximate span of 400 feet is most suitable. This section of line is anticipated to be basically the same design as the new 115 kV line between Daves Creek and Seward as described in the Transmission Line Investigation Section of this study. 17.8 MITIGATION FACILITIES Two facilities will be provided as part of the selected project arrangement which comprise part of the project fisheries mitigation plan. These facilities, which are described in detail -in Volume II - Environmental Report, include a salmon holding facility and a fish bypass facility. The salmon holding facility will be located adjacent to the tailrace channel (see Figure IV-21) and will consist of 2 aluminum raceways, channels connecting the raceways to the tailrace channel (water is supplied to the raceways from powerhouse discharges), a spawning shed, and provisions for security. The tunnel bypass facility will consist of a rotatable stainless steel inclined screen just downstream of the gate shaft and a 10 inch diameter fish bypass, which will be embedded in the tunnel invert concrete and will extend for the length of the tunnel, past the turbine, and into the tailrace channel. The tunnel bypass facilities are shown on Figures IV-18 and IV-20. 17-9 2510E Project recreation facilities will be located on the southern end of Grant Lake and will consist of picnic tables, fireplaces, a contained vault toilet and a boat launch area. 17.9 FALLS CREEK DIVERSION WORKS 17.9.1 General As discussed above, the detailed plant optimization studies resulted in the deletion of the Falls Creek diversion from the selected project arrangement. For completeness, a description of the diversion system developed through the detailed feasibility studies is presented herein Falls Creek has its headwaters in the mountains south of Solars i Mountain and presently discharges into Trail River just south of Lower Trail Lake (see Figure IV-2). The Falls Creek diversion system would require the construction of a small dam on the creek to divert flow - through-a-gravity--feed-pipeline to Grant.-Lake--as-shown --in_pl_an and profile on Figure IV-25. The system would result in the addition of approximately 1 MW of installed capacity to the project. + The system has been designed to accommodate a flow of 112 cfs, which was determined by an optimization study to maximize the flow and benefits of the system while minimizing spill and capital cost. The diversion will take place during the wet seasons between May and October. { 17.9.2 Falls Creek Diversion Dam and Intake Structure The diversion dam would be a concrete gravity structure with an uncontrolled ogee spillway and flip bucket, as shown on Figure IV-26. It would be located approximately 2 miles upstream of the confluence of Falls Creek and Trail River. The dam would be approximately 30 feet high (21 feet to the spillway crest at elevation 1404.5) and 17-10 2510E constructed in a section of Valley that has moderately steep (l-horizontal to 1-vertical) side slopes. This would result in a dam that is 75 feet long. This location represents a shift of approximately 2500 feet upstream from the dam location presented during the Interim Report stage. This change Was precipitated by the acquisition of more detailed survey information Which showed the original dam location to be in an area of sheer, nearly vertical, Cliffs. The spillway is sized to accommodate 8 50-year flood without overtopping' Larger floods than a 50 years event Would not damage the integrity of the structure, but would result in its being overtopped, in which case the dam would act as a submerged Wuir. The flip bucket is provided to minimize erosion at the too of the dam during periods of spill, which are estimated to occur for 800 hours during a normal flow year. The maximum spill during such a year would be 184 cfs' 17.9'3 Falls Creek Diversion Pipeline The Falls Creek diversion pipeline would be a 2/-9« diameter steel pipe originating at the dam and discharging into Grant Lake. The total drop in elevation would be approximately 700 feet from elevation 1400 to elevation 690, and would occur over a length of 12,800 feet. As shown on Figure IV-25, the pipeline Would closely parallel an access road. A typical pipeline/access road section is shown on Figure IV-24' The pipeline would be buried along its entire loUgth. The minimum burial depth would be 3 feet whore the pipeline slope is steeper than l% (which would be for most of its length) and 9 feet where the slope is flatter than l%' The pipe would be buried for several reasons: l) it would eliminate the need for above ground supports while utilizing the relatively inexpensive support afforded by burying it With excess road cut fill: 2\ burying the pipeline would protect it from potential hazards caused by avalanche; 3\ it would provide protection to the pipe l7-ll 25lO8 ` from freezing during the winter months when the system is shut down and water could accumulate in flat areas; and 4) burying the pipe would mitigate its environmental impact to the site. Two of the above benefits associated with burial are closely interrelated. Where the pipeline traverses an active avalanche chute, the slope of the pipeline is essentially flat (between stat-io.ns_7.0+00.and 90+00). Therefore,_ this area would require the 9 foot burial depth to prevent freezeups together with giving an additional degree of avalanche protection to the pipe. When the pipeline reaches Grant Lake it would discharge into a channel that would be dredged down to elevation 650 in the lake, well be ow t he minimum pool level. This channel would be lined with concreted riprap in order to eliminate the potential for erosion when the pipeline discharges into Grant Lake during a low pool condition. 17-12 2510B 18.0 PROJECT COSTS AND SCHEDULE 18.1 GENERAL Feasibility —level estimates of capital costs and operation and maintenance costs were developed for the selected Grant Lake project layout described in Section 17.0. The capital cost estimate has been prepared on an overnight price basis with escalation shown separately. Included in the project capital costs are the following: direct construction costs of the production plant and transmission plant; indirect construction costs such as temporary construction facilities and mobilization/demobilization; contingencies; overhead construction costs including professional services to the Power Authority; and escalation during construction. Interest during construction has not been included since current Power Authority procedures call for inclusion of IDC only in the nominal cost of the project, which is utilized in the plan of finance. The overnight cost estimate of the project includes all items in the bid price estimate except escalation during construction. The overnight cost has been used in the economic analysis for the project. A project schedule was developed based on the assumption that a FERC license application is submitted by the summer of 1983 and that construction will commence shortly after receipt of the license. This schedule, presented on Figure IV-27, was used as the basis for developing the cost of escalation during construction. 18.2 PROJECT CAPITAL COST The total project capital cost, including direct and indirect costs, contingencies, overhead expenses and escalation during construction, is $24,713,000. These items are presented on Tables 18-1 and 18-2, and treated separately below. 18-1 2622E 18.2.1 Direct Construction Costs The direct construction costs include all directly billable charges associated with each project feature and are overnight costs assuming January 1§83 dollars. These costs are summarized on Table 18-1 and presented --in detailon-Table 18-2. Thetotalcost of the hydraulic production plant and transmission plant is-$16,544,000 and includes all structures, waterways and 11 reservoirs, equipment for generation and transmission of power to the Seward -Anchorage intertie, fish mitigation facilities and all site access. Clearing costs associated with the transmission line have been included under access roads. This was done because the transmission line is located on he roadway shoulder for - its entire length. Also, no cost was included for land or land rights, since all of the project is located on federal lands, which are currently in the process of being transferred to state,ownersh.ip. The basis for developing this estimate includes the assumptions that labor rates for the project will be'_similar__to Anchorage__ union _ agreements and that all labor is to be performed on a contract basis. 18.2.2 Indirect Construction Costs The total indirect construction costs are summarized on Table 18-1 as $1,212,000 and are itemized on Table 18-2. This sum includes the cost of temporary construction facilities (shops, warehouses, trailers, etc.), extra travel pay compensation to the labor forces and mobilization/demobilization expenses. The assumptions incorporated into this estimate are that there will be sufficient craft labor commuting daily from Seward (no provisions for a labor camp) since the labor force will consist of approximately 30 men as discussed in the Environmental Report (Volume II) and adequate room exists in Seward and Moose Pass for such a crew. A work week consisting of 6-10 hour days, and mobilization/demobilization costsequal to 5% of the direct construction cost were also assumed. 18-2 2622E 18.2.3 Contingency The contingency for the project is $2,663,000 and is an allowance for any unforeseen events that may result in cost increases during construction. This amount is 15% of the total direct and indirect construction costs. 18.2.4 Professional Services and Owner Administration (Overhead Construction Costs) Professional services consist of engineering, design, construction management and related services and are estimated to be $2,971,000 (14% of all construction costs, including contingencies). 18.2.5 Escalation All the above costs are overnight and represent base year January 1983 prices. In order to present a true bid -level estimate for the project, an annual escalation rate of 7% for both material and labor was used. This escalation rate is in accordance with the Power Authority guidelines and considers escalation for a construction period starting at the base year. The total price escalation for the project is estimated to be $1,323,000. 18.3 ANNUAL COSTS Annual operation and maintenance (0&M) costs were developed for the project based on the experience encountered with other hydroelectric projects in Alaska and input from the Power Authority. The total 0&M cost is estimted to be $302,000 per year. Included in this estimate are the following: 18-3 2622E Yearly Labor Costs o Operations (including recreation ,and _fish facilities) - 1.5 men at $66,000/man yr. $99,000 I o Plant Maintenance - 4 man crew for 10 weeks at $66,000/man yr. $51,000 o Administration (Overhead) $25,000 $175,000 Dispatch Expenses $15,000 Yearly Replacements - _o Miscellaneous Equipment $12-,000__._ Insurance $50,000 Subtotal $252,000_ Contingency (20%) 5$ 0,000 Total $302,000 18.4 DESIGN AND CONSTRUCTION SCHEDULE ` The complete project schedule is shown on Figure IV-27. This schedule is developed based on an August 1, 1983 submittal of the FERC license application and a receipt of the license by November 1, 1984 (15 month processing period). Detailed design and bid document preparation would be performed concurrently with the processing of the license and would essentially be complete by the beginning of 1985. Some continuing design activity would be required through the construction phases and would be primarily for field support and to address any design changes that may be required. d commence in A I Actual construction would April 1985 with the award of m p contract and the start of mobilization. Construction would continue for two years with trial operation set for March 1987 and commercial operation for April 1987. 18-4 2622E 18.5 ALTERNATIVE F DETAILED COST ESTIMATE As discussed in previous sections, the project configuration originally recommended for detailed feasibility studies was Alternative F. This configuration was, in fact, modified and developed, and detailed feasibility -level cost estimates were prepared before it was eliminated as the preferred alternative. For comparative purposes, the detailed cost estimate developed for the Alternative F configuration, which is also described in Section 17.0, is presented on Table 18-3. The salient features of the Alternative F cost estimate are as follows: Hydraulic Production Plant Direct Costs Transmission Plant Direct Costs Indirect Construction Costs Contingency (15% of direct and indirect costs) Overhead Construction Costs (Engineering, Construction Management, and Owner Administration) Total Alternative F Project Cost in 1983 Dollars Escalation During Construction Alternative F Escalated Project Cost $21,546,000 $593,000 $1,587,000 $3,559,000 $3,932,000 $31,217,000 _$1 993,000 $33,210,000 TABLE 18-1 SELECTED PROJECT ARRANGEMENTY SUMMARY OF PROJECT CAPITAL COSTS Amount — January 1983 Cost Item Price Level ($1,000's) Production Plant $15,951 Transmission Plant 593 Total Direct Construction Cost $16,544 Indirect Construction Cost $ 1,212 Contingency 2.663 Total Indirect Construction Cost (Including Contingency) $ 3,875 Engineering, Construction Management and Owner Administration $ 2,971 Project Subtotal.2/ __ 23-390 Escalation During Construction!/ $1,323 Total Capital Cost 124,713 Selected Project Arrangement is Alternative D with minor refinements. The minor refinements decreased the project cost by $802,000. The decrease was due to a reduction in excavation quantities associated with the channel excavation and modified unit prices. 2/ Represents "overnight" cost estimate in January 1983 dollars. This value is used in the economic analysis of the project. 3/ Escalation Based on Project Schedule Shown on Figure IV-27 and Annual Inflation Rate of 7%. 18-6 FERC ACCOUNT 330. 331. .13 .131 .132 .133 .134 .135 .136 TABLE 18-2 SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 1 of 7 UNIT 10TAL DESCRIPTION UNIT QUANTITY COST COST HYDRAULIC PRODUCTION PLANT LAND AND LAND RIGHTS POWER PLANT STRUCTURES AND IMPROVEMENTS Power House Site Preparation Clearing AC Excavation - Rock CY Excavation - Common CY Substructure Concrete - Structural CY Reinforcing Steel TN Superstructure Structural Steel LB Aluminum Siding and Roofing SF Architectural Treatment LS Plumbing, Lighting and Electrical LS Miscellaneous Metal LB Heating and Ventilating LS Subtotal Powerhouse Not Included! 0.5 3800.00 1900 4,870 25.36 123500 310 11.94 3700 1,150 550.00 632500 60 2622.00 157300 111,500 2.32 258800 10,000 15.27 152700 88400 76400 5,500 3.04 16700 39900 1551800 All project lands are Federal lands which are currently being transferred to state ownership. 2620B 18-7 TABLE 18-2 SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 2 of 7 FERC UNIT_. TOTAL �... ACCOUNT DESCRIPTION UNIT QUANTITY COST COST 1 .2 Conservation of Fish and Wildlife .21 Salmon Holding Facility .211 Site Preparation and Grading AC' 034 7500.00 2550 - _.-j 212 - -- Gravel--Surfaci-ng CY --21-5 __ __ 1-9_._07. ___ 4.10-0-- _ .213 __.___ ._._Cl_ass B -Access- Road___ .2131 Clearing AC 0.25 4000.00 1000 .2132 Excavation - Rock CY 155 50.97 7900 .2133 Excavation - Common CY 430 9.30 4000 .2134 Crushed Stone CY 75 18.66 1400 , .2135 Random Fill CY 1,100 3.18 3500 .214 Common Excavation CY 1,450 9.24 13400 .215 Concrete - Structural CY 21 671.42 14100 ` .216 Reinforcing Steel TN 0.30 2133 640 .217 _ 6' Chain Link Fence LF 500 25.20 12600 .218 Aluminum Pickets LF 1,700 10.35 17600 .219 Miscellaneous .2191 Wood Foot Bri dge LS 9700 .2192 Emergency Water Supply LS 33800 .2193 Misc. Plumbing and Valves LS 6000 S .2194 Misc. Tanks and Equipment LS 143000 .22 Fish Bypass Facility ! .221 10" dia steel pipe, lined and coated LF 2,980 122.88 366200 .222 Pipe hangers EA 20 150.00 3000 .223 Bypass Screen (Incl hinges) SF 250 68.80 17200 .224 Bypass Screen Hydr. Piston LS 7800 .225 Bypass Screen Elect Controls LS Included in Acc't 334 .226 10" dia Butterfly valve EA 1 - 1600.00 1600 .23 Off -Site Fish Hatchery Module LS 456000 Subtotal Conservation of Fish and 1127090 Wildlife TOTAL POWER PLANT STRUCTURES 2678890 AND IMPROVEMENTS s TABLE 18-2. SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST F ERC UNIT ACCOUNT DESCRIPTION UNIT QUANTITY COST 332. RESERVOIRS AND WATERWAYS .1 Reservoir .11 Channel Expansion .111 Excavation - Rock CY .112 Excavation - Common CY .12 Recreation Facilities LS Subtotal Reservoir .2 Power Tunnel 9.0' Horseshoe (3200' .21 Excavation - Rock CY .22 Steel Sets LB .23 Rock Bolts LF .24 Welded Wire Fabric LB .25 Shotcrete Lining CY .26 Concrete - Mass CY .27 Lake Tap Incl. Rocktrap & Trashrack .271 Excavation - Rock CY .272 Shotcrete CY .273 Tremie Concrete CY .274 Trashrack LB .28 Concrete Transition .281 Concrete - Structural .282 Reinforcing Steel .29 Gates and Gateshaft .291 Gates .2911 Intake Gate .2912 Temporary Bulkhead Gate .292 Gate Shaft Excavation .293 Gate Shaft Shotcrete .294 Welded Wire Fabric .295 Steel Sets .296 Rock Bolts .297 Concrete - Structural .298 Reinforcing Steel CY TN 14,500 2,600 9,600 3,055 2,300 12,000 720 675 240 20 40 33,000 Sheet 3 of 7 TOTAL CO ST 19.00 275500 10.00 26000 45000 346500 380.00 3648000 5.79 .17700 25.78 59300 1.17 14000 768.65 553400 325.31 219600 380.00 91200 765.00 15300 322.50 12900 5.80 191400 110 557.27 61300 5.5 2127.00 11700 EA 1 65500.00 65500 EA 1 29500.00 29500 CY 352 700.00 246400 CY 30 851.42 25500 LB 250 1.60 400 LB 7,500 5.83 43730 LF 300 26.00 7800 CY 140 650.00 91000 TN 7.5 2120.00 15900 SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 4 of 7 FERC _ _ UNIT_ TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST -COST 332. RESERVOIR AND WATERWAYS (Cont'd) .299 Gatehouse .2991 Excavation - Rock CY ---.299-2--------Rockbol ts-_(1_3/8") _ _ _ __ LF .2993 Drain Holes- (2- ) LF .2994 Concrete - Structural CY .2995 Reinforcing Steel TN .2996 Structural Steel LB .2997 Aluminum Siding and Roofing SF .2998 Misc. Metal LB .2999 Miscellaneous :29991 Gate Hoist EA .29992 Misc. Electrical Controls LS - .2993 Bubbler System LS .3 Penstock (75' Lg)(shown as steel tunnel liner, 3/8" thick) .31 Penstock Steel LB .32 Contact Grout. SF .4 Tailrace (640'Lg) _ ..41 _ . Excavation --Rock CY .42 Excavation - Common CY .43 Rip -rap CY .44 Bedding CY Subtotal Waterways TOTAL RESERVOIRS AND WATERWAYS 333. WATER WHEELS, TURBINES AND GENERATORS INSTALLED CAPACITY) .1 lurDines, overnors and Valves .11 Turbine and Governor LS .12 Inlet Valve EA .13 Lube Oil System LS .2 Generator, Exciters and Appurt. LS TOTAL WATER WHEELS, TURBINES AND GENERATORS 2,750 _2,60025.77 16.93 46600 67000 800 26.25 21000 . 135 _---- ---_ _-_-_845.8g _____714200 _ 7.0 211900 14800 14,000 2.32 32500 2,100 15.29 32100 1,160 3.36 3900 1 24200.00 24200 i Incl in Acc't 334 j 30000__ 26,200 6.30 165100 1800 11.56 20800 4 3,035 _ _25.37 1 77000 17,430 6.18 107700 2,900 54.39 157700 860 18.95 16300 6352430 6698930 1647000 1 Incl Above 25000 a TABLE 18-2 SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 5 of 7 FERC UNIT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST COST 334. ACCESSORY ELECTRICAL EQUIPMENT LS 1428000 TOTAL ACCESSORY ELECTRICAL EQUIPMENT 1428000 335. MISCELLANEOUS POWER PLANT EQUIPMENT .1 Power Station Crane (30 Ton) EA 1 18 2400.00 182400 .2 Draft Tube Gates EA 2 31500.00 63000 .3 Miscellaneous Equipment LS 400000 TOTAL MISCELLANEOUS POWER PLANT EQUIPMENT 645400 336. ROADS AND BRIDGES .1 Access Roads .11 Access Roads Class A (24' wide) .111 Clearing AC 13 3723.00 48400 .112 Excavation - Rock CY 14,135 16.92 239100 .113 Excavation - Common CY 35,700 6.18 220600 .114 Crushed Stone CY 10,275 18.23 187300 .115 Random Fill CY 30,360 3.24 98300 .12 Access Roads Class B (18' wide) .121 Clearing AC 8 3719.00 29800 .122 Excavation - Rock CY 5,890 16.92 99700 .123 Excavation - Common CY 15,840 6.18 97900 .124 Crushed Stone CY 2,920 18.24 53300 .125 Random Fill CY 11,760 3.24 38100 Total Access Roads 1112500 .2 Bridges .21 Trail Lake Crossing .211 Bridge Girders - A.A. S.N. T. 0. EA 8 6975.00 55800 STD. 35' Lg .212 Concrete - Structural CY 310 560.64 173800 .213 Reinforcing Steel TN 31 2119.00 65700 .214 Barriers - N.J. Std Barrier LF 280 50.00 14000 .215 Expansion Joints - Metal EA 5 2320.00 11600 .216 Drains and Drain Pipes EA 16 681.25 10900 .22 Grant Creek Crossing .221 Dimension Lumber BF 9,350 3.26 30500 .222 Concrete - Structural CY 15 853.33 12800 18-11 TABLE 18-2 , SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 6 of 7 FERC UNIT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST COST 338 ROADS AND BRIDGES (Cont'd) .224 Reinforcing Steel TN 1.5 2133.00 3200 .225 Guard Rail - Weathering Steel LF 120 49.17 5900 --Mi_sc_.----Meta-1 -a-nd- Fa-stener-s- -----LB-- ---250------- ---6-,00---_1_500 --------- 1-1-1 Total -1 - Bridges 38-570-0-- TOTAL ROADS AND BRIDGES 1498200 TOTAL HYDRAULIC PRODUCTION PLANT 15950420 TRANSMISSION PLANT 352. TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS .1 Switchyard Civil .11 Fill -Random CY 30 3.33 100 .12 Excavation -Common CY 45 18.33 825 .13 Crushed Rock CY 40 18.00 720 �- .14 Fences and Gates LF 130 27.73 3605 TOTAL TRANSMISSION PLANT STRUCTURES 5250 AND IMPROVEMENTS 353. SUBSTATION AND SWITCHING EQUIPMENT LS 469000 TOTAL SUBSTATION AND SWITCHING EQUIPMENT 469000 355. POLES .1 Clearing Not Included Use Plant Roads .2 Poles (Douglas Fir) EA 18 46000 (6 Dead End, 12 Guyed) TOTAL POLES 18-12 ff., �m-&M SELECTED PROJECT ARRANGEMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 7 of 7 FERC UNIT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST COST 356. CONDUCTORS AND DEVICES .l Conductors (336 0cm AC3R) LF 19,425 2.57 50000 .2 Insulators [3 23000 TOTAL CONDUCTORS AND DEVICES 73000 TOTAL TRANSMISSION PLANT 593250 TOTAL DIRECT CONST COST 10543670 60. INDIRECT CONSTRUCTION COSTS 61. Temporary Construction Facilities [3 200000 ! 62. Construction Equipment LS Included in Direct Costs i 53. Camp and Commissary [3 Not Required 64. Labor Expense L3 . .l Travel Pay LS 150000 Total Labor Expense L3 —T= 69. Mobilization/Demobilization L3 862000 TOTAL INDIRECT CON3T COSTS 1212000 SUBTOTAL 17755670 Contingency /15%\ 2663330 SUBTOTAL /IDcl Contingency) 20419000 70. OVERHEAD CONSTRUCTION COSTS 71. Professional Services 2971000 TOTAL OVERHEAD CONSTR COSTS 2971000 TOTAL PROJECT COST (in January, 1983 Dollars) 23390000 ESra7atfOO 1323000 TOTAL ESCALATED COST | 24713000 18-l3 TABLE 18-3 ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 1 of 9 FERC UNIT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST. COST 44 HYDRAULIC PRODUCTION PLANT 330. LAND AND LAND RIGHTS --------- --- — ------ 331 . TO.-WER -PLANT.-.STR UCTURES A ND IMPROVEMENTS Power House .11 Site Preparation .111 Clearing AC 0.5 .112 'Excavation - Rock CY 4,870 .113 Excavation - Common CY 310 Not Included-1) 3800.00 1900 25.36 123500 11.94 3700 Az .121 Subs trus. Lu, e Concrete - Structural CY 1,150 550.00 632500 .122 Reinforcing Steel TN 60 2622.00 157300 .13 Superstructure .131 Structural Steel LB 111,500 2.32 258800 Aluminum Siding and Roofing SF 10,000 15.27 152700 .132 .133 Architectural Treatment LS 88400 .134 Plumbing, Lighting and Electrical LS 76400 Miscellaneous Metal LB 5,500 3.04 16700 .135 .136 Heating and Ventilating LS 39900 Subtotal Powerhouse 1551800 All project lands are Federal lands which are currently being transferred to state ownership. 18-14 W. ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST FERC ACCOUNT DESCRIPTION Sheet 2 of 9 UNIT TOTAL UNIT QUANTITY COST COST .2 Conservation of Fish and Wildlife .21 Salmon Holding Facility .211 Site Preparation and Grading AC .212 Gravel Surfacing CY .213 Class B Access Road .2131 Clearing AC .2132 Excavation - Rock CY .2133 Excavation - Common CY .2134 Crushed Stone CY .2135 Random Fill CY .214 Common Excavation CY .215 Concrete - Structural CY .216 Reinforcing Steel TN .217 6' Chain Link Fence LF .218 Aluminum Pickets LF .219 Miscellaneous .2191 Wood Foot Bridge LS .2192 Emergency Water Supply LS .2193 Misc.-Plumbing and Valves LS .2194 Misc. Tanks and Equipment LS .22 Fish Bypass Facility .221 10,dia steel pipe, lined and coated LF .222 Pipe hangers EA .223 Bypass Screen (Incl hinges) SF .224 Bypass Screen Hydr. Piston LS .225 Bypass Screen Elect Controls LS .226 10" dia Butterfly valve EA .23 Off -Site Fish Hatchery Module LS Subtotal Conservation of Fish and Wildlife TOTAL POWER PLANT STRUCTURES AND IMPROVEMENTS 18-15 0.34 215 0.25 155 430 75 1,100 1,450 21 0.30 500 1,700 2,980 20 250 7500.00 19.07 4000.00 50.97 9.30 18.66 3.18 9.24 671.42 2133 25.20 10.35 122.88 150.00 68.80 Included in Acc't 1 1600.00 2550 4100 1000 7900 4000 1400 3500 13400 14100 640 12600 17600 366200 3000 17200 7800 334 1600 456000 TABLE 18-3 I I ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 3 of 9 .FERC UNIT TOTAL ACCOUNT DESCRIPTION, UNIT QUANTITY. COST COST 332. RESERVOIRS AND WATERWAYS .1 Reservoir .11 Channel Expansion .111 Excavation - Rock Cy 14 500 19.00 275500 .112 Excavation - Common CY --A 2,600 .1-2 - R6cre- a-ti -on- Fa c 111 ti es- IS— Subtotal Reservoir 346500 .2 Palls Creek Concrete Gravity Dam .21 Diversion & Care of Water .211 Random Fill CY 500 4.12 2060 .212 Corrugated Metal Pipe (3' dia.)LF 40 61.50 2460 .213 Structural --Concrete -CY-,--- 5 -- 840.00 4200 .214 Reinforcing Steel TN 0.25 2120.00 530 .22 Clearing AC 0.50 3600.00 1800 .23 Excavation - Rock CY 180 50.83 9150 .24 Excavation - Common CY 60 18.67 1120 .25 Foundation Preparation .251 Surface Preparation LS 6900 .252 Grouting .2521 Drill Grout Holes LF 210 26.14 5490 .2522 Neat Cement CF 35 73.00 2550 .26 Concrete .261 Concrete - Mass CY 290 320.89 93060 .262 Concrete - Structural CY 90 828.89 74600 .27 Reinforcing Steel TN 5.0 2122.00 10610 .28 Miscellaneous .281 Structural Steel LB 1,200 2.33 2800 .282 Misc. Metal LB 800 18.00 14400 .29 Intake Structure .291 Structural Concrete CY 7 845.71 5920 ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST FERC ACCOUNT DESCRIPTION Sheet 4 of 9 UNIT T UNIT QUANTITY COST TO 332. RESERVOIRS AND WATERWAYS Continued .292 Reinforcing Steel TN 0.35 2114.00 740 .293 Structural Steel LB 975 2.32 2260 .294 Gate & Gate Works EA 1 20000.00 20000 .295 Trashrack LB 1,200 7.50 9000 .296 Sluiceway Gate LS 15000 .297 Rip -rap CY 50 51.00 2550 Subtotal Dams 287200 .3 Power Tunnel 9.0' Horseshoe (3200' .31 Excavation - Rock CY 9,600 380.00 3648000 .32 Steel Sets LB 3,055 5.79 17700 .33 Rock Bolts LF 2,300 25.78 59300 .34 Welded Wire Fabric LB 12,000 1.17 14000 .35 Shotcrete Lining CY 720 768.65 553400 .36 Concrete - Mass CY 675 325.31 219600 .37 Lake Tap Incl. Rocktrap & Trashrack .371 Excavation - Rock CY 240 380.00 91200 .372 Shotcrete CY 20 765.00 15300 .373 Tremie Concrete CY 40 322.50 12900 .374 Trashrack LB 33,000 5.80 191400 .38 Concrete Transition .381 Concrete - Structural CY 110 557.27 .61300 .382 Reinforcing Steel TN 5.5 2127.00 11700 18-17 TABLE 18-3 I I I ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 5 of 9 FERC UNIT --TOTAL ACCOUNT DESCRIPTION _ UNIT QUANTITY ..COST COST 332. RESERVOIR AND WATERWAYS (Cont'd) .39 Gates and Gateshaft .391 Gates .3911 Intake Gate EA 1 65500.00 65500 .3912 Temporary Bulkhead Gate EA 1 29500 00 29500 .392 Gate Shaft Excavation - CY 352 700 OD 246400 .393 Gate Shaft Shotcrete CY 30 851:42 25500 .394 Welded Wire Fabric LB 250 1.60 400 .395 Steel Sets LB 7,500 5.83 43730 .396 Rock Bolts LF 300 26.00 7800 .397 Concrete - Structural CY 140 650.00 91000 .398 Reinforcing Steel TN 7.5 2120.00 15900 .399 Gatehouse _ .3991 Excavation ---Rock CY 2,750__. _ __.16.93 - 46600-- .3992 Rockbolts (1-3/811) LF 2,600 25.77 67000 .3993 Drain Holes (2") LF 800 26.25 21000 .3994 Concrete - Structural CY 135 845.88 114200 .3995 Reinforcing Steel TN 7.0 2119.00 14800 .3996 Structural Steel LB 14,000 2.32 32500 .3997 Aluminum Siding and Roofing SF 2,100 15.29 32100 .3998_ Misc. Metal LB _1_,160 : _ 3.36_ _ 3900 .3999 Miscellaneous .39991 Gate Hoist EA 1 24200.00 24200 .39992 Misc. Electrical Controls LS Incl in Acc't 334 .3993 Bubbler System LS 30000 .4 Penstock (75' Lg)(shown as steel ` tunnel liner, 3/8" thick) .41 Penstock Steel LB 26,200 6.30 165100 .42 Contact Grout SF 1800 11.56 20800 i I .5 Tailrace (640'Lg) .51 Excavation - Rock CY 3,035 25.37 77000 .52 Excavation - Common CY 17,430 6.18 107700 .53 Rip -rap CY 2,900 54.39 157700 .54 Bedding CY 860 18.95 16300 TABLE l8-3 ALTERNATIVE DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 6 of 9 FERC UNIT T0TAL ACCOUNT DESCRIPTION UNIT QUANTITY COST COST It 333. .l .11 .l2 .l3 2.75/ Did. Falls Creek Diversion Pipeline (12,800/ LF) Clearing AC 2 Excavation - Ruck CY 13,685 Excavation - COm0nD CY 20,525 DrdglfDe EXCDVdti0n CY 240 Conduit Steel LB 1,084,000 BOckf/ll - General CY 33,200 BdCkffll - Bedding and 3UrrOVDd- 1Og Granular Fill CY 8dCkfill - Riprdp choked with Concrete CY Concrete Thrust Block CY Subtotal Waterways TOTAL RESERVOIRS AND WATERWAYS WATER WHEELS, TURBINES AND GENERATORS /8MW - INSTALLED CAPACITY) /uro/ncs, Governors mno va|Ves Turbine and Governor L3 Inlet Valve EA Lube Oil System LS .2 Generator, Exciters and AopUpt. L3 TOTAL WATER WHEELS, TURBINES AND GENERATORS 334. ACCESSORY ELECTRICAL EQUIPMENT LS TOTAL ACCESSORY ELECTRICAL EQUIPMENT l8-l9 4^AOO 3720.00 7440 33.83 463000 4.61 94700 6.25 1500 2.90 3143600 3.97 131800 18.96 91000 12 54.17 650 17 447.08 7600 10293720 10927420 TABLE 18-3 ALTERNATIVE F DEVELOPMENT } DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 7 of 9 FERG UNLT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST COST - 335. MISCELLANEOUS POWER PLANT EQUIPMENT .1 Power Station Crane (30 Ton) EA 1 18 2400.00 182400 .2- Draft —Tube Gates- EA -2_ 31-500-00 --6300-0- -- -- - .3 Miscellaneous Equipment LS 400000 TOTAL MISCELLANEOUS POWER PLANT EQUIPMENT 645400 336. ROADS AND BRIDGES .1 Access Roads f .11 Access Roads Class A (24' wide) .111 Clearing __-. AC 13 _ 3723`-00 4840 .112 Excavation - Rock CY 14,135 16.92 239100 .113 Excavation -Common CY 35,700 6.18 220600 Crushed Stone CY 10,275 18.23 187300 .114 .115 Random Fill CY 30,360 3.24 98300 .12 Access Roads Class B (18' wide) .121 Clearing AC 32 3719.00 119000 .122 Excavation - Rock CY 23,050 16.92 389900 .123 Excavation - Common CY 62,025 6.18 383400 f .124 Crushed Stone CY 11,450 18.24 208800 .125 Random Fill CY 46,060 3.24 149300 Total Access Roads 2044100 .2 Bridges .21 Trail Lake Crossing .211 Br i dge Gi rders - A. A. S. H. T. 0. EA 8 6975.00 55800 STD. 35' Lg .212 Concrete - Structural CY 310 560.64 173800 .213 Reinforcing Steel TH 31 2119.00 65700 .214 Barriers - N.J. Std Barrier LF 280 50.00 14000 .215 Expansion Joints - Metal EA 5 2320.00 11600 .216 Drains and Drain Pipes EA 16 681.25 10900 .22 Grant Creek Crossing .221 Dimension Lumber BF 9,350 3.26 30500 .222 Concrete - Structural CY 15 853.33 12800 TABLE 18-3 ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 8 of 9 FERC UNIT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST COST 336 ROADS AND BRIDGES (Cont'd) .224 Reinforcing Steel TN .225 Guard Rail - Weathering Steel LF .226 Misc. Metal and Fasteners LB Total Bridges TOTAL ROADS AND BRIDGES TOTAL HYDRAULIC PRODUCTION PLANT 1.5 2133.00 3200 120 49.17 5900 250 6.00 1500 385700 2429800 21545510 TRANSMISSION PLANT 352. TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS .1 Switchyard Civil .11 Fill -Random CY 30 3.33 100 .12 Excavation -Common CY 45 18.33 825 .13 Crushed Rock CY 40 18.00 720 .14 Fences and Gates LF 130 27.73 3605 TOTAL TRANSMISSION PLANT STRUCTURES 5250 AND IMPROVEMENTS 353. SUBSTATION AND SWITCHING EQUIPMENT LS 469000 TOTAL SUBSTATION AND SWITCHING EQUIPMENT 469000 355. POLES .1 Clearing Not Included - Use Plant Roads .2 Poles (Douglas Fir) EA 18 46000 (6 Dead End, 12 Guyed) TOTAL POLES 46000 18-21 TABLE 18-3 ALTERNATIVE F DEVELOPMENT DETAILED ESTIMATE OF CONSTRUCTION COST Sheet 9 of 9 FERC UNIT TOTAL ACCOUNT DESCRIPTION UNIT QUANTITY COST _ COST 356. CONDUCTORS AND DEVICES .1 Conductors (336 mcm ACSR) LF 19,425 2.57 50000 .2 Insulators LS __23000 _-- —TOTAL --- C-ON.DUCTORS-AND DEVICES_ _--------__---__---_-_-- __ 73000 TOTAL TRAN1. SMISSION PLANT 59325 -_ TOTAL DIRECT CONST COST 60. INDIRECT CONSTRUCTION COSTS 61. Temporary Construction Facilities LS 62. Construction Equipment LS 63. Camp and Commissary— _ __.___ . LS 64. Labor Expense LS .1 Travel Pay LS Total Labor Expense LS 69. Mobilization/Demobilization LS TOTAL INDIRECT CONST COSTS SUBTOTAL Contingency (15%) SUBTOTAL (Incl Contingency) 70. OVERHEAD CONSTRUCTION COSTS 71. Professional Services TOTAL OVERHEAD CONSTR COSTS TOTAL PROJECT COST (in January, 1983 Dollars) Escalation TOTAL ESCALATED COST 18-22 22138760 250000 Included in Direct Cos Not__Requi reed _ IT.IWO 195000 1142000 1587000 23725760 3559240 27285000 3932000 3932000 31217000 1993000 33210000 19.0 REFERENCES Alaska Department of Transportation, Seward and Sterling Highway Drawings. Alaska Power Authority.' 1982. Bradley Lake Power Market Report. Alaska Power Authority. 1983. Before the FERC, Application for License for Major Project, Susitna Hydroelectric Project, Volume 1, Exhibit -D. Battelle Pacific Northwest Laboratories. 1982. Railbelt Electric Power Alternatives Study: Evaluation of Railbelt Electric Energy Plans, Comment Draft. . 1982. Railbelt Electric Power Alternatives Study: Fossil Fuel Availability and Price Forecasts, Volume 7. Bolt, B.A.. 1973. Duration of Strong Ground Motion: Fifth World Conf. Earthquake Engineering, Rome. CH2M Hill. August 1979. City of Seward Electrical System Planning Study. Prepared for the City of Seward. CH2M Hill. February 1979. City of Seward Electric System (Plan Drawings). Prepared for the City of Seward. CH2M Hill. March 1979. City of Seward Light and Power Division Plant Inventory. Prepared for the City of Seward. CH2M Hill. March 1982. Drawings for 69 kV Transmission Line - 4th of July Creek, Drawing No.'s K15775.A1 sheets 2 to 9. Prepared for the City of Seward. Campbell, Kenneth W. 1981. Near -Source Attenuation of Peak Horizontal Acceleration. Bulletin of.the Seismological Society of America, Vol 71, pp. 2039-2070. Chugach Electric Association, Inc. Trans. Line drawings for Daves Creek to Lawing, #61-M-838 to 846. City of Seward. 1982. Forecast Electric Demand to 1984. Prepared by City of Seward. Commonwealth Associates, Inc. October 1982. Anchorage Area Reliability Study (Draft Report). Prepared for Alaska Power Authority. Dwane Legg Associates. October 1982. Analysis of Voltage Drop and Energy Loses. Prepared for the City of Seward. Ebasco Services Incorporated. 1983.. Use of North Slope Gas for Heat and Electricity, Draft Final Report Feasibility Level Assessment. . 1981. Grant Lake Hydroelectric Project, Interim Report 19-1 Federal Energy Regulatory Commission. 1979. Hydroelectric Power Evaluation. Foster, H.F., and Karlstrom, T.N.. 1967. Ground Breakage and Associated Effects in the Cook Inlet Area, Alaska, Resulting from the March 27, 1964 Earthquake, U.S. Geological Survey Professional Paper 543-F. Joyner, W.B. and Boore, D.M. 1981. Peak Horizontal Acceleration and Velocity from Strong -Mot ion Records Including -Records from the--1979- ImPerial Valley, California, Earthquake. Bulletin of the Seismological Society of America', Vol. 71, pp. 2011-2038. Krinitzsky, E.L., and Chang, F.K. 1977. Specifying Peak Motions for Design Earthquakes: U.S. Army Corps of Engineers, Miscellaneous Paper --MP _5--73-1_,__Repo-rt 7,__Waterways___Experiment_ Station,Vi_cksburg_,__ Miss._,__ 34 p• Lamke, R.D. 1979. Flood Characteristics of Alaskan Streams. U.S. Geological Survey Water Resources Investigations 78-129,66 pp., 1979. North Pacific Consultants. 1958. Cooper Lake Hydroelectric Project, Supplemental Design Report on Reservoir Storage Study and Study of Diversion from Stetson Creek. 1955. Cooper Lake Hydroelectric Project, Kenai Peninsula, Alaska, Definite Project Report. Ott Water Engineers. 1979. Water Resources Atlas for USDA Forest Service - Region X. Juneau, Alaska. Page, R.A. 1972. Crustal Deformation of the Denali Fault, Alaska, 1942-1970: Journal of Geophysical Research, v. 77, p. 1528-1533. Page, R.A., Boore, D.M., Joyner, W.B., and Coulter, H.W. 1972. Ground Motion Values for Use in the Seismic Design of the Trans --Alaska Pipeline system: U.S. Geological Survey Circular 672, 23 p.r Page, R.A., and Lahr, J.C. 1971. Measurements for Fault Slip on the Denali, Fairweather, and Castle Mountain Faults, Alaska: Journal of Geophysical Research, v. 76, p. 8534-8543. Plafker, G. 1969. Tectonics of the March 27, 1964 Alaska Earthquake, U.S. Geological Survey Professional Paper 543-I. - 1955. Geologic Investigations of Proposed Power Sites at Cooper, Grant, Ptarmigan, and Crescent Lakes, Alaska; U.S. Geological Survey Bulletin 1031-A. 19 -2 R&M Consultants, Inc. June, 1982. Alaska Power Authority, Grant Lake Hydroelectric Project, Interim Geotechnical Report. December, 1982. Alaska Power Authority, Grant Lake Hydroelectric Project, Geotechnical Investigations, Final Report. R. W. Beck, June 1982. Kenai Peninsula Power Supply and Transmission Study. Prepared for Alaska Power Authority. 1982. Supplement - Kenai Peninsula Power Supply and Transmission Study. R.W. Beck and Associates. May 1976. Electric System Study. Prepared for the City of Seward. R.W. Beck and Associates. January 1975. Report on Feasibility of Operation of the Electric Utiity System of the City of Seward by Homer Electric. Prepared for City of Seward and Homer Electric Association, Inc. Slemmons, D.B. 1977. Faults and Earthquake Magnitude: U.S. Army Corps of Engineers, Waterways Experiment Station, Vicksburg, Mississippi, Miscellaneous Paper 5-73-1, Report 6, 129 p. Tysdal, R.G. and Case, J.E. 1969. Geologic Map of the Seward and Blying South Quadrangles, Alaska, U.S. Geological Survey Map I-1150. U.S. Corps of Engineers. 1982. Bradley Lake Hydroelectric Project, Alaska. Final Environmental Impact Statement. U.S. Corps of Engineers, Alaska District. 1982. Bradley Lake Hydroelectric Project, General Design Memorandum. _ 1981. Bradley Lake Hydroelectric Project, Design Memorandum. Anchorage, Alaska. U.S. Department of Commerce, Weather Bureau. 1961. Study of Probable Maximum Precipitation for Bradley Lake Basin, Alaska. 16 pp. . Recommended Guidelines for Safety Inspection of Dams. U.S. Department of Interior, Bureau of Reclamation. 1977. Design of Small Dams. U.S. Government Printing Office, Washington, D.C. University of Alaska, Institute of Social and Economic Research. June 1980. Electric Power Consumption for the Railbelt: A Projection of Requirements. Wyss, M. 1979. Estimating Maximum Expectable Magnitude of Earthquake from Fault Dimensions: Geology, v. 7, p. 336-340. 19-3 2621E 43 0 4"rt k I "J 34 j j 1)ie of a d "h(lo ii 7: 800 P I kW H i Hi OUSE 1;j OWEN U Nbff 6 H NT • '.,, _. "may .--`-�---- '•;:;=�•�„_,,� _ ,`.%._....�=.�..�. � ;, , .�..�..f GLACIERS x q 0 ATION s GRAIN� CRPEK Ni- (V G C [)• ! ! i , ' G ° J V i . t• '. tl , '�� ,\ ..; \' � yf.� t 1 � ' \� t 4 \ i i i 0 IV! k' J;j) A8 A . .......... �S"c 00 ro ATIIJ 1 91 i `24 AT I QV " e ; LEGEND. TUNNEL ACCESS ROAD .... . m POWERHOUSE INTAKE AND GATESHAFT IV` X1. NOTES I. TOPOGRAPHIC DATA OBTAINED FROM U.S.G.S. 1.63,360 QUADRANGLES, SEWARD B6-B7. 3000t 0 300d so d- 11 SCALE I SEWARD- ANCHORAGE HIGHWAY t 2.6 MILES TO SEWARD -ANCHORAGE HWY. (ALTERNATE SITE ACCESS ROAD) -INTAKE i N SCALE I'!-- 100d DATUM - MSL NORMAL MAXIMUM POOL EL. 745 LEGEND ----ACCESS ROAD —SURFACE POWER CONDUIT --------BURIED POWER CONDUIT -----TRANSMISSION LINE 211olowz 1. TOPOGRAPHY PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC. NOVEMBER 1981. 2.ALTERNATIVE E SHARES THESE SAME PROJECT FEATURES BUT ALSO INCLUDES THE FALLS CREEK DIVERSION DAM, PIPELINE AND ACCESS ROAD (SEE FIGURE 2). 1 500! 0 500' 100d 150d SCALE 9-1 SEWARD- =HORAGE H IGHWAY 2.6 MILES TO SEWARD -ANCHORAGE HWY. (ALTERNATE SITE ACCESS ROAD) I SCALE I'-_'IOOd DATUM - MSL RMAL MAXIMUM 500L EL. 745 LEGEND ----ACCESS ROAD SURFACE POWER CONDUIT --------BURIED POWER CONDUIT (BENEATH MAIN DAM) ------------TUNNEL -----TRANSMISSION LINE NOTES TOPOGRAPHY PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC., NOVEMBER 1981. 500 0 500' 1000' 1500' SCALE ALASKA POWER AUTHORITY GRANT LAKE HYDROELECTRIC PROJECT ALTERNATIVE-B GENERAL PROJECT ARRANGEMENT DATE FEB 1983--7 FIGURE 3X "5 EBASCO SERVICES- INCORPORATED 1 19- ISEWARD— ANCHORAGE HIGHWAY i N SCALE 11=1000' DATUM— M-SL ORMAL MAXIMUM OOL EL. 745 I J qtewk ILI, ----ACCESS ROAD —SURFACE POWER CONDUIT ---------BURIED POWER CONDUIT (AT MAIN DAM) ------TRANSMISSION LINE NOTE' TOPOGRAPHY PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC. NOVEMBER 1981. 500' 0 500' 1000' 1500 SCALE . (ALTERNATE SITE ACCESS ROAD) N UPPER TRAIL LAKE / 900 800 700 J N u_ z 600 a w J w S00 450 N2,363,000 850 /o 800 0t® a® Tun 850 PLAN I. C> / 0co n^ � O tr ki I SHAFT BAKE TAPJ % INTAKE N m , V' 0 I m o NORMAL N I GATE HOUSE POOL MAXIMUM a?( ' 1 EL 715' EL 690' a Q, i = NORMAL MINI UM' I 12' GATE SHAFT 1 I I POOL EL 66 p I I LAKE TAP I T I ' INVERT EL 64 LINED ROC14 TRAP I TUNNELTCRETE POWERHOUSE I I m ( p5 5 m I vS= ', _ STEELILIN.D = o 0 TUNNEy UPPER TRAIL LAKE p EL 467 1+00 -S+On na.nn c Lnn z5+o0 30+00 NOTES: 1. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY RBhM CONSULTANTS, INC., IN 1981 AND 1982. 2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE ALASKA STATE PLANE GRID SYSTEM, ZONE 4. 900 800 600 i00 35+00450 BORING NO. COORDINATES DEPTH (FT) DH-1-82 N 2,362,521.139' 38.4' E 617 9101.707' DH-2-82 N 2,362,511.768' 31.3' E 617,181.894' DH-3-82 N 2,362,388,007' 185.2' E 617,578.888' DH-4-82 N 29362,289.464' 225.3' E 618,862.691' DH-5-82 N 2,362,128.059' 75.4' E 620,202.304' 200, 0 200' 400' 600' SCALE (UNLESS NOTED) I GRANT LAKE HYDROELECTRIC PROJECT I • \ _ i i \ I._ - __ _ �\ ,� i i I i � I _ _ -_ .� _ . � _. i r ,. _ I''- e N362,600 1 .............. 5 N362,360 zu u is cz C= c= C) C= cz Olt Ct ca N362,200 cS - !2 r- cc ui Lu ui ui ui 10 /DH-2-82 I . a --'-15 �- 20,." 25,, 30 EXPLANA TION — 0— 0- SEISMIC LINE SHOWING GEOPHONE LOCATION SHOT POINT e BOREHOLE LOCATION CONTOUR INTERVAL 5 FEET 60 0 6d j SCALE IN FEET ALASKA POWER AUTHORITY GRANT LAKE HYDROELECTRIC PROJECT DEPTH TO BEDROCK POWERHOUSE COVE DATE FEE) 1983 FIGURE IZ- 9 IQ-19 EBASCO SERVICES INCORPORATED Z� I ,. i ' \ / / t"` i \.. \` t , \ S j: t, ~' ... t,. : , r� n • :: a,. _ ... ,......__...........:...... ...... ..----._..., _... _.. .. \ t } ♦ t ,. 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'.i�. : TALU'S '' . .. .J-• '.�::..• > c ROCK GLACIER Cat `f{ Q \ c L %: f / J \� ,' r? . . 1,1 . k `� �� - / \ GRANT CREEK FAULT '/. y, h f v ;;� ':�' ,', f Gv ./. !� { . ti \ . `,�. ,a:R ,.\ �;: i ---- LINEAR FEATURES VISIBLE > 3 \ x' C �rf'.(!;,,.';fI':. . — . .��u: .I, ,\ , 1)!...I :.I 1�',.. .i.;) . �...I�. 1. �• y \. f it 1 r yC 1 \ t' \ ` d / $F•'r rQ _ . _ ,..��_,..:._-...a. _ _... _...,.....,.. :.:.�.....} ._ ... ..:,... ,.•.., ._..>..,,. _.... \`` c> c; GRAP s f . i' . ` � `: \ \..,.,,: . < _ `\;; , AND SATELLITE IMAGERYS _ .... ` l :,} ry `�< _:� ' \ t i ? y '�, NOTES• } r ,hk !F`4` •{' l /' r I ' ` < r \) t .. I. `\ \ `\ i r� . \ ,, \ ` \ : -.sue—: c�- r ` f j : : sI ` ``-`ti> �:. , " i` ' -- \ \ TOPOGRAPHIC D ' } ,�: t ;y,.> f� \ �\;';: ATA FROM US.G.S. MAPS, ( 3; . f W —. ,/. i i . rT ;v . % ,A \ , ti CJ SEWARD B6—B7. 1 . . ,/` + + ' i '" t i r'`'S` i`' .J�i:. ..i. ^,..t, •c i. s",� \... . ✓ //^'\,, • % G��- ,,,, } }¢ R __ t . t r* '..` 'M% i .3- t 3. . i AL, / a ,(•.4❑��yp h '........, t ., , r SCALE . ::,. . , / ; �:�<'_ \, :. . . ... \ ... ... �� • , . ...,, �i?. :• . . :,:- r� ,..`^.,.,.� .. ,�fitt••:: ; .. i ,• S? r i , .% , , j / .ram . \ i ' f : \:� /. . ,,- i I :..: .+, • , „ ,J,•• L.' is \`, _ r p p p I. ML/'t1SKM POWER Ell f'Yi! Y®RI 1 Y . , ✓ / „ r .. .... . Q *'••. ate,• %.`ice.`•: ..............._.,,........,. :. .. _ ,y:,i./.%j. . i3 rY : l\ • ' : :' \ e ,.g .. R ..... : , .\ _... .... ROELEC t .: _ \ . J ....... _ -�'a . A9dT LA9CE TRIO OJECT ,s �c�� \ °� _. ... ,. ! \"\ '' — ` s, \ \,,\\ \,,\\ \ _.. ;,';'`., REGIONAL GE . . `4i :: .... 0 LOGIC MAP :: t , / y s , :F... %.,.. f :,\. ,:' THE PROJECT AREA ... t •'LY L , . F' M 1000 — 950 — Soo — es0 — SOD — J 750 — in 700 — Z 650 — O Q 600 — w W 550 — 500 — 450 — 400 — ,000 — 950 — 900 — S50 — Soo — if) J 750 — Too — !L p 550— Q y 600 — W J W 550 — 500 — 450 — EXPLANATION BEDROCK - UPPER CRETACEOUS Gm Graywacke - Thick to massively bedded with minor sandy slate and/or state interlayers. GI Graywacke - Thin to medium bedded, with sandy slate and:or slate interlayers. SS Sanoy Slate - Gradational in composition between gray- wacke and slate, or intimately inter - layered packages of graywacke, sandy slate and slate. Slate - Thinly laminated to flaggy units with minor amounts of graywacke and/or sandy slate. Ali ol. Ton. ow t oHs'•e\ ) ) ) NO VERTICAL EXAGGERATION \Gm\ ss DH2-62 Diamond Core How PT. 16 Tunne, Alignmen. Survey Station — — — Contac., dasheo wnere Inferred —�— Llneamen„ promaase fault Fau,, —.—...._ Interpretive,\a.er rao.e �I. \sS\ G,\5\Gm \S\\ G. 5•\m 5�" SS .^• ss� \ \ \ \\ \ \ \ .SS S \ \ \ \\ \\ \ =lo Ss�\ Gm \s, \ \\\ \\\\ \ NEL ALIGNMENT \ Gm 0 NOTES: I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY RdM CONSULTANTS, INC., IN 1981 AND 1982. 2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE ALASKA STATE PLANE GRID SYSTEM, ZONE 4. 100, O 100, 200, 30V L—t I F I I I SCALE ALASKA POWER AUTHORITY RANT LAKE HYDROELECTRIC PROJECT TUNNEL — INTERPRETIVE GEOLOGIC CROSS SECTION DATE FEB 1983 1 FIGURE IZ— 12 $ ESASCO SER`/ICER IN('-nRP0QAT1=n 1 100 € f 90 f � � 80 ` Cr- 70 \ ` 3 Q 60L O' i 9 LU V~ 40 LJ , 30 CL s y 20 L 10 z 100 90 80 70 60 50 40 30 20 10 0 PERCENTAGE ROD NOTE: Total length of DH - 3, DH - 4 and DH - 5 is 486 feet. ROD includes all rock types. ALASKA POWER AUTHORITY GRANT LAKE HYDROELECTRIC PROJECT CUMULATIVE DISTRIBUTION OF RQD VALUES Boreholes DH - 3, DH - 4 and DH - 5 DATE FEB 1983 FIGURE 1Z- 13 EBASCO SERVICES INCORPORATED 19-16 2, 720 ^� 70 E—e J 66 III 640 AREA (ACRES) zoo 2,100 2,000 1,900 O O I,800 1,700 6600 1,500 1,400 RESERVOIR VOLUME RESERVOIR SURFACE AREA 60 ISO 200 220 240 260 280 Nola %loci VOLUME (ACRE-FEET x 1000) NOTE: ALLY VOLUME COMPUTATIONS ARE DERIVED FROM THE 111=400' TOPOGRAPHIC AND BATHYMETRIC MAPPING PREPARED IN 1981 AND 1982 BY NORTH PACIFIC AERIAL SURVEYS. INC. 19-17 oztA � r= � 0 ,a. x a,O EA ..EA V ww uj Tx av z u 1 2 3 4 5 6 7 80 6 12 18 24 30 36 42 48 54 66 72 78 84 90 60 TIME, HOURS PROBABLE MAXIMUM STORM RAINFALL DISTRIBUTION ou 55 50 45 40 35 30 ?5 ?0 OU FLOW IN-LOW- to- 0 0 6 12 18 24 30 36 42 48 54 60 66 72 78 84 9[ ,01, 11ROBABLE MAXIMUM FLOOD HYDROGRAPHS 6 Iz I9 24 90 36 42 48 54 60 66 72 78 84 90 TIME, HOURS PROBABLE MAXIMUM FLOOD RESERVOIR ELEVATIONS RETURN PERIOD (YEARS) 1.0001 1.01 1.11 1.25 2 5 10 25 50 100 1000 10, 10,000 7,000 6,000 5,000 4,000 3,000 2,000 LL 1,000 0 J LL 500 000 100 99.99 99 80 50 20 t0 5 2 1 0.1 . 0.01 PERCENT CHANCE FLOOD FLOW FREQUENCY FOR GRANT CREEK -0 5000 10000 15000 200M 25000 DISCHARGE, CFS NATURAL OUTLET RATING CURVE NOTES: I. PROBABLE MAXIMUM FLOOD WAS DERIVED BY TRANSPOSING BRADLEY LAKE PROBABLE MAXIMUM STORM TO GRANT LAKE AND RATIOING MEAN ANNUAL RUNOFF. 2. THE PMF INFLOW HYDROGRAPH INCLUDES SNOWMELT INPUT OF 0.01 INCH/ HOUR. 3.THE INFLOW HYDROGRAPH FOR THE PMF IS BASED ON 6HR. PERIOD AVERAGE FLOWS AND THE OUTFLOW HYDROGRAPH ON ACTUAL ROUTING RESULTS. 4. POINTS PLOTTED ON GRANT CREEK FLOOD FLOW FREQUENCY CURVE ARE BASED ON DATA GIVEN IN 11FLOOD CHARACTERISTICS OF ALASKAN STREAMS," USGS, 1979, FOR USGS GAGE NO. 15246000, GRANT CREEK NEAR MOOSE PASS. 5. ELEVATIONS BASED ON MEAN SEA LEVEL. 19- �1 V - UPPER MAIL LAKE N 900 800 700 600 :2. w -j w EM `W cl AGILITY Y PLAN . \, IL NORMAL GATE HOUSE MAXIMUM POOL EL 715' EL 691' v MINIMUMPOOL EL 6631 121 0 GATE SHAFT LAKE TAP 14 INVERT EL 64 S=.0 30-8 SH TCRETE LINED ROC TRAP TUNNEL POWERHOUSE TAILWATER (EL 468 AT STEEL LINED POWERHOUSE) —\ ;TUNNEL UPPER TRAIL LAKE EL 467 ----------- 450_ — 9+00 -,)+UU U+uu 5 00 10+00 15+00 20+00 25+00 30+00 PROFILE NOTES: 1. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH ... .. .... . PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY R&M CONSULTANTS, INC., IN 1981 AND 1982. QD 2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE o ALASKA STATE PLANE GRID SYSTEM, ZONE 4. co 3, BASED ON PRELIMINARY FIELD GEOTECHNICAL EXPLORATION PROGRAM, ROCKBOLTING IN THE TUNNEL IS ESTIMATED TO BE REQUIRED FOR APPROXIMATELY 15% OF THE TUNNEL LENGTH. X.F. GAT SHAFT I" J6 ROCKBOLTS (SEE NOTE) STEEL PENSTOCK LAICTAP ""'19-TAK E 4i 3" SHOTCRETE FOR INITIAL TUNNEL SUPPORT CONCRETE 3" MINIMUM I'l. I . *. — . .. - . GROUTED THICKNESS OF SHOTCRETE 10" 0 FISH LINING BYPASS 6" CONCRETE"PIPELINE SHOTCRETE LINED TYP STEEL LINED TUNNEL SECTION TUNNEL SECTION 41 ol 4' 81 12' SCALE 900 800 I! 7001t z (E w 200, 0' 200' 400' 600' 600 SCALE (UNLESS NOTED) ALASKA POWER AUTHORITY GRANT LAKE HYDROELECTRIC PROJECT 500 POWER CONDUIT PLAN AND PROFILE - 35+04500 DATE FEB 1983 1 FIGURE 17-18 EBASCO SERVICES INCORPORATED t 19- NORMAL MAXIMUM POOL v EL691 ' \\\V,�\�; 0 ASSUMED �\ a \O TOP OF ROCKI2�,.. i...\�\\\I 11 i r,� �/) jl� 11\\\ �� MPOOLM T50' lLA%�Li �i ri EL66d / x 696'-6 ''' / i' �'e�'-r`\ `�� 01% ve /II\ 111Ilk' / i by b• SECTION B-B GRANT /f! I \\\ ��\ ; 20/. 20' 0' 20' 40' NOTES: %�/i /' I LAKE ,,. _ "\ / SCALE L TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH '/ i I PACIFIC AERIAL SURVEYS INC. AND SURVEYS CONDUCTED BY RaM CONSULTANTS INC.,IN 1981 AND 1982. 2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL), HORIZONTAL CONTROL IS BASED ON THE //' ALASKA STATE PLANE GRID SYSTEM ZONE 4. mI W-AVAT� CH NEL — 'z S��' PLAN 200' 0' 200' 400' SCALE J O O ~ p EL 691' NORMAL MAXIMUM POOL. H w t= p EL 660' MINIMUM ,, f a = POOL / EL 650' w cv SECTION A -A 100' 0' fool 200' SCALE ORIGINAL GRADE ALONG CHANNEL CENTERLINE SECTION A -A TEMPORARY BULKHEAD- ---\ P -S=.OE 10" 0 FISH PIPELINE SECTION B-B DRAIN HOLES AS REQUIRED ROCK BOLTS ----- AS REQUIRED----yr� INVERT SECTION C-C i SUPPORT GATE HOUSE HYDRAULIC PISTON — HYDRAULIC GATE HOIST E L 715 .r u `F'gypA ni Fib GATE SHAFT AND INTAKE PROFILE 20' 0' 20' 40' 60' 1 111 1 1 1 1 SCALE VIEW D-D PLAN OF CIRCULAR TRASHRACK DETAIL E ,1 25' v ROCKBOLTS (TYP.) EMIE CONCRETE INTAKE INVERT EL. 643 TREMIE CONCRETE NOTE: I ELEVATIONS BASED ON MEAN SEA LEVEL 5' 0' 5' 10' 15' I I SCALE(UNLESS NOTED) 19- 550 J 525 at-1 h� NOTES: 1. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY RaM CONSULTANTS, INC., IN 1981 AND 1982. 2. VERTICAL CONTROL 14S BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE ER T N EL ALASKA STATE' PLANE GRID SYSTEM, ZONE 4. = - - - — = r 3. TAILRACE CHANNEL TO BE LINED WITH RIPRAP UP TO ELEVATION 470 BETWEEN STATIONS -0+50 AND -4+00 FISH PA S PIP TAPERING DOWN TO ELEVATION 467 FOR THE LOCAT D I SIDE U N REMAINDER OF THE CHANNEL. AND AS NG T RO G THE OW R HO E POWERHOUSE I 4 EL 488 UPPER TRA2 GAKE TURBI E EL. 470 lip STEEL LI DIAMETER DIAMETE FROM 10 4ER VARIES " TO 66' 9' _ TUNNEW R p _ EL 46 .001 OF TAILRACE. H S=.008 l c RO - S=. K TRAP 55 —S —_ Ur EL. 464.E 450 7+00 575 550 J N 525 H z 0 500 a w J W 475 450 -6+00 -5+00 -4+00 -3+00 -2+00 -1+00 0+00 1+00 2+00 3+00 AVERAGE TAILWATER TRANSITION TO PROFILE EL. 468 AT POWERHOUSE A LINED TUNNEL 50' 0' 50' 100' 150' SCALE (UNLESS NOTED) 45L6 14LO 31' 6 L EXCITER---'= 'W j 1: 7CONTROL ROOM GOVERNOR 'o AIR COMPRESSOR 0 z a.� 7780 kVA GENERATOR SERVICE BAY Fill MA H N SHOP SECTIONAL PLAN r@ EL 487.0 EL 532.0' D CRANE SWITCHGEAR EL 501.0' ROLL -Up OLL DOORUP 18L o 1 4 GENERATOR EL ALUMINUM SIDING ;ATE HOIST ,—DRAFT TUBE GATE 6d� BUTTERFLY VALVE TAILWATER EL 470.0' EL 468.0' DRAFT TUBE --------- - - - - - - - - - - ACCESS GALLERY 1 01101 FISH L 461.0 BYPASS PIPELINEA i6 EL 453.0' EL 456.5' TRANSVERSE SECTION THROUGH OF UNIT SPIRAL CASE ACCESS PALL EL 468.0 DRAINAGE SUMP .SECTIONAL PLAN f@ EL470.0' RAW-4ml FIRST STAGE CONCRETE SECOND STAGE CONCRETE NOTES: I. ELEVATIONS ARE BASED ON MEAN SEA LEVEL. 0 5' 10' 15' 2 0' SCALE LONGITUDINAL SECTION THROUGH � OF UNIT 19- EXCITATION k_� TRANSFORMER "7 SEE FIG. M- I 115 KV TRANSMISSION LINE WAVE TRAP CCPD OB BREAKER R REAKER ac* 0E) 3 A OE33 0 MAIN TRANSFORMER 9/10.6 MVA OA/OF 115 KV: 416 KV Z= 11.5 % GENERATOR BREAKER 1600A 4- SURGE PROTECTION C3 ECTION T Z DISCONNECT LINK BUS OR CABLE ID VOLT � REG. 51 N) �4L 600:5 n63 15 KV T T 7:3=-= 115KV:66.4V VAR) (Ylul") ( W ) (WH aw.1m BUS OR CABLE 0 a - DISCONNECT LINK )>-- SYNCH. 3 4.16 KV: 120V 3 Lp ------- (:�VAR .3 'o :TIFIER 41 u, 0 3 o 3 TA(53) 64 59 3 3 o GENERATOR EXCITATION (STATIC) GROUNDING TRANSFORMER �ffffumwmm mmm mralm GENERATOR 7.8 /9 MVA 0.90 PF, 60/80C 4.16 W 30 6OHz 400 RPM 7MW dw=wm=lm=lm 95 5 87 YID 3 __ 4.16 kV: 120 V 1200A V, a 2E L:3 51 50 ! 3G s it 0 ze STATION SERVICE TRANSFORMER 4.16 KV 480/277V 150 kVA Z-5% 60 87 480:120 V GT 2 VS v A 400 AF 480V MCC )IOOAF (TYP) 25 WA 120/208 V.A.C. 480V LOADS LOADS 1.5 ASSUMED � 3 TOP OF ROCK . = \ ORIGINAL GROUNDLINE 4 I RIGHT-OF-WAY CLEARING LIMITS r in In x 115 KV TRANSMISSION �I ASSUMED LINE w \ TOP OF ROCK -1 ORIGINAL GROUNDLINE CRUSHED STONE 5' a \ I.2O (TYP) COMPACTED 14 RANDOM FILL � 1 a CLASS A ROAD AND TRANSMISSION LINE TYPICAL SECTION FOR SLOPED TERRAIN 115 KV TRANSMISSION LINE ,r—DOUGLAS FIR L 35' TYPICAL RIGHT-OF-WAY CLEARING LIMITS TYPICAL 5WI -OF 'CLEARING LIMITS CLASS A ROAD AND TRANSMISSION LINE TYPICAL SECTION FOR FLAT TERRAIN L 20' 20, TYPICAL RIGHT-OF-WAY T TYPICAL RIGHT-OF-WAY CLEARING LIMITS CLEARING LIMITS TYPICAL CLASS B ROAD SECTION %,LGAKlN%3 LIMI I J JANU BEDDING TYPICAL CLASS B ROAD SECTION ADJACENT TO THE FALLS CREEK DIVERSION PIPE NOTES: I. CLASS A ROADS PROVIDE ACCESS TO THE POWERHOUSE. 2. CLASS.B ROADS PROVIDE ACCESS TO THE GATE SHAFT, FALLS CREEK DIVERSION DAM AND PIPELINE. 3. CLASS 8 ROADS ARE TYPICALLY LOCATED IN AREAS OF SLOPED TERRAIN. 5' O 5' 10, 15' 1 I I I I SCALE PAP in z 0 w -i w �E 623,000 + E.623,000 + o; 0! cli 00 1 0, MI ip _ CANAL REATIO.N GRANT LAKE A' ------ ......... . INTA TIMB R M-1 POWER - TUNN EL C? ACC PLAN 500' 0. 500' 100 0' 1500' Q%j �vv ru+uu 60+00 50+00 STATIONS DIVERSION PIPELINE PROFILE c-RE" PLAN LEGEND: DWAXON DIVERSION PIPELINE ACCESS ROAD 3a DIVER'Slon NOTES: PIP14LINE 1. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH PACIFIC AERIAL SURVEYS, INC., IN 1981 AND 1982. 2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE ALASKA STATE PLANE GRID biber-M, ZONE 4. Of J co EXISTING ROAD TO BE IMPROVED , lq 1300 1200 z 0 1100 w -i w 1000 DO 40+00 30+00 20+00 m DIVERSION PIPELINE PLAN 20�,20 . 0' 40' 60" L -1 SCALE OEM NTAKE DIVERSION DAM INTAKE LOW LEVEL GATE HOIST RELEASE rAf GATE HOIST 2 UNCONTROLLED SPILLWAY CREST 3'-0 MIN (TYPI ASSUMED TOP OF 4 COMPETENT ROCK LIMIT OF EXCAVATION---- :'I SPILLWAY UPSTREAMBUCKET FACE LIP INTAKE----- EXISTING LIMIT OF EXCAVATION GROUNDLINE DOWNSTREAM FACE LOW LEVEL A RELEASE PIPE ELEVATION - LOOKING UPSTREAM LOW LEVEL NOTES: RELEASE GATE HOIST- -4-0 1. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH SECTION A -A SUMED TOP OF MPETENT ROCK PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY RaM CONSULTANTS, INC., IN 1981 AND 1982. 2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE ALAqKA STATE PLANE GRID SYSTEM, ZONE 4. IQ` DO 10, 20' 30, -1 1 SCALE (UNLESS NOTED) t WORK ACTIVITY —Ear MO 103 BOMB soll3lummosol3l Ulm simme 0 1319 I FEASIBILITY ANALYSIS 11 LICENSING AND PERMITTING MEMO A. FERC LICENSE APPLICATION PREPAR rION MEMO MEN 13. FERC LICENSE APPLICATION PROCESSING i NEON OEM IN MEN■M■No MEN C. PERMITS R!m m, M MEN■0■ME■IN■MEN MOEN '111 DESIGN AND CONTRACT DOCUMENTS on Irl! a Zama WEN■0 0 moomm Tk.'d-ETAI:L*":ED �FIELD —INVE— STIGATIONS men B. SITEACCESSNOON No■0 N■MOENNONE■0■N EUI -- D. MA_J0_R P14-0-JECT —FEATURES m■mAORQPM MENOMONIE IV CONSTRUCTION Now 115, ro a me L A. SITE ACCES B. MAJORPROJEff —FEATURff—SAND mom EQUIPMENT BILIZATION/ DEMOBILIZATION TUNNE1 —AND S)fEff_LLINt`R':j_ GATESH4FT 0 NEON INTAKE (LAKE TA No IN ME POWERHOUSE mom EXCAVATION ONE SUBSTRUCTURE ANb m__ SUPERSTRUCTURE ■1111111111111111111111111111111111-770M ONO MECHANICAL EQUIPMENT 111■111■1111 1 ELECTRICAL EQUIPMENT_ ______ Will, mom GRANT LAXE CHA L IN P__NNE EXCAVATION C ON fA�ILRAd ■ON ON SWITCHYARD No mom MEMO OMEN TRANSMISSION LINE No NOW FIS ITI—GATION FACILIT_lE_S'_ No M 0 0■NONE OMEN RECREATION FACILITIES m C. START-UP ON IN 0 mm NONE ingols 0 m■No No IN MENEM ME■N_ m M SEEN ON ONE LEGEND: mooll NINE IN MAJOR EFFORT ------CONTINUING EFFORT PROJECT SCHEDULE DATE FEB. 1983 1 FIGURE m -27 t - I - I SERVICES INCORPORATED __ __.__. �._, . i _ _ _ _ _ _ I ,._ t _ __ ;� _ _ I i ., _ : _ ___