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City of Seward Alaska Transmission System Alternatives 1983
AYA For ia G ' REPORT | CITY or SEWARD ALASKA TRANSMISSION SYSTEM ALTERNATIVES LE? PPA FP By Frwy a> Ge NO i NA il a ' a Lin i" OCTOBER 1983 I FRACCOY CITY OF SEWARD TRANSMISSION SYSTEM ALTERNATIVES TABLE OF CONTENTS Page EXECUTIVE ‘SUMMARY 2 css cuss ae te a ol = v INTRODUGTION Sica om mw ee ws 1-1 EXISTING POWER SYSTEM... 2... 2.2 ee eee eee 2-1 2.1 EXISTING TRANSMISSION FACILITIES. ........ 2-1 Zae SUBSTATIONS 2 Ss ccs 9 es) se eo ie i 6 ie 2-2 2.3 POWER FLOW STUDIES... .......2.4.24.4.426.-. 2-4 2.4 MOTOR STARTING STUDIES. ........2.4.44.4.. 2-4 LOAD & ENERGY FORECASTS... 1... 2. ee eee eee 3-1 3.1 PURPOSE & APPROACH. .........424.64066-. 3-1 3.2 LOAD & ENERGY FORECASTS ............. 3-2 Jed METHODOLOGY © 5 cas cam ac ee ne a 3-7 334 ASSUMPTIONS 2 2 pe ews es cs os 3-36 3.5 DATA SOURGES = 3 Soc as ewe i ee 3-39 ALTERNATIVES FOR SEWARD TRANSMISSION SYSTEM... ... 4-1 4.1 SYSTEM ALTERNATIVES .. 2... 2.22. ee ee eee 4-1 4.2 ROUTING ALTERNATIVES... ........222-2 4-44 4.3. OTHER ALTERNATIVES... ... 2.2.2 ee ee eee 4-714 APPENDIX ete ee) ter eee) ee el el ie ele 4-107 EVALUATION (CRITERIA) 2 0 2 we es a ee es ae 5-1 5.1 SYSTEM PERFORMANCE CRITERIA ........... 5-1 5.2 STATE OF ALASKA EVALUATION PROCEDURES ...... 5-20 AND CRITERIA 5.3 AVALANCHE EVALUATION CRITERIA ....... % m= 5-22 5.4 ENVIRONMENTAL & PERMITTING CRITERIA ....... 5-24 COMPARISON OF ALTERNATIVES ........2.2-+-e- 6-1 6.1 ENGINEERING COMPARISON. .........2.6.24.. 6-1 6.2 ECONOMIC COMPARISON ..........2.244.2.. 6-6 6.3. ENVIRONMENTAL COMPARISON... ......2.+.-.. 6-14 6.4 CONCLUSIONS AND RECOMMENDATIONS ......... 6-14 ii — io io —_ jo 1 = Sa 1 anf won—-— www 14 ww www WWwWww nN aie on LIST OF TABLES Title VOLTAGE DROP AND ENERGY LOSSES - EXISTING SYSTEM COMPARISON OF LOAD AND ENERGY FORECASTS FOR 2014 HIGH GROWTH SCENARIO MODERATE GROWTH SCENARIO LOW GROWTH SCENARIO NOTES ON TABLES 3.3-1, 3.3-2, and 3.3-3 HIGH GROWTH SCENARIO ENERGY FORECAST MODERATE GROWTH SCENARIO ENERGY FORECAST LOW GROWTH SCENARIO ENERGY FORECAST NOTES ON TABLES 3.3-4, 3.3-5, and 3.3-6 JANUARY 1983 ENERGY CONSUMPTION BY SECTOR JANUARY 1983 ENERGY CONSUMPTION BY RESIDENTIAL SECTOR FISCAL 1983 PEAK DEMANDS BY SECTOR FISCAL 1983 ENERGY CONSUMPTION BY SECTOR GROWTH SCENARIOS FOR SEWARD INDUSTRY LINE PARAMETERS PER PHASE AND PER UNIT LENGTH LINE PARAMETERS METHOD OF CALCULATING ANNUAL LOSSES LOSSES AT 2014 MEDIUM PEAK LOADS CONCEPTUAL COST SUMMARY UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS, ALTERNATIVE 1 UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS, ALTERNATIVE 2 UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS, ALTERNATIVE 3 iii Page 2-5 3-3 3-10, 3-11 3-12, 3-13 3-14, 3-15 3-16 to 3-18 3-20 3-21 3-22 3-23, 3-24 3-31 3-32 3-34 3-35 3-38 4-4 to 4-15 4-16 to 4-37 5-4 5-5 to 5-19 6-5 6-8, 6-9 6-10, 6-11 6-12, 6-13 Po — — io io — jo ny > ar i_-— oo] >t ° ee Ne nm ONIN WwOn—n— -2-1 to 4.2-3 NI 1 > oa oe ° ei) Ons owe e 3 6 io Pwn—oO PPPHPPPPHPPLS > > WwWwww -: * —WNHMNMMNMMMNM= Treas aor Co aes aw =I nN ret °o an tot m= LIST OF FIGURES Title MOTOR STARTING STUDY DIAGRAMS COMPARISON OF LOAD GROWTH FORECASTS COMPARISON OF ENERGY GROWTH FORECASTS COMPARISON OF LOAD GROWTH SCENARIOS COMPARISON OF ENERGY GROWTH SCENARIOS TYPICAL JANUARY LOAD SHAPE CURVE BY SECTORS AVALANCHE MAP EXISTING RIGHT OF WAY MAP VARIABLE WIDTH RIGHT OF WAY CLEARING TERN LAKE AVALANCHE AREA UPPER TRAIL LAKE MUSKEG AREA KENAI LAKE AVALANCHE AREA SNOW RIVER CROSSING GOLDEN FIN TRAIL MUSKEG SEWARD AND DAVES CREEK SUBSTATION AREA REVISIONS SUBSTATION AREAS REVISIONS COOPER LAKE-SEWARD TRANSMISSION LINE ALTERNATIVE ONE LINE AND LOAD FLOW DIAGRAMS FOR THE SIX ALTERNATIVES 115 kV CONDUCTOR ANALYSIS 69 kV CONDUCTOR ANALYSIS iv Page 2-9 to 2-22 3-4 3-5 3-9 3-19 3-33 4-48 to 4-50 4-55 to 4-57 4-59 4-64 4-66 4-67 4-69 4-71 4-13 4-15 4-11 4-86 to 4-106 EXECUTIVE SUMMARY The City of Seward is serviced by a 40-mile transmission line between the City's Seward Substation and Chugach Electric Association's Daves Creek Substation. Operating at 24.9 kV, the line is already beyond its capacity limit by present day standards, and three prior studies have concluded that prompt action is required to provide adequate service to the City. The current peak load is approximately 5 MW and results in a line loss of approximately 20 percent and a voltage drop during peak conditions greater than 15 percent. There is concern that the current system may not be capable of operating the new shiplift facility under construction at the Marine Industrial Park. To assess this situation, studies were performed to determine the effects of starting the shiplift facility motors on the existing system. These studies indicate that motor starting is possible with acceptable voltage drop if all 5.5 MW of diesel generator capacity is made operational prior to attempting to use the shiplift facility. As use of the facility will be relatively infrequent, and as this is also only an interim measure until the transmission system can be upgraded in 1984, it is felt that this offers a solution which will be acceptable to the City. Coordination between the shiplift operators and the City Engineering Department would be required in order to minimize the effects on acceptable voltage to the remainder of the consumers on the system. To evaluate the future requirements, load and energy forecasts were developed for the Seward area during the next thirty years. The forecasting method combines an analysis of the Seward area's economic and demographic growth within the context of the Railbelt with an assessment of end uses for electricity in industry and the residential sector. High, moderate, and low forecasts were developed for both load and energy. The high forecast was utilized for selection of equipment re capacities with loss evaluation and conductor optimization studies based on the moderate load forecast. For the year 2014, the forecasts are as follows: Low Moderate High Peak Load 12.18 MW 16.56 MW 27.49 MW Energy 58387 MWH 68424 MWH 82885 MWH Based upon the above forecast, 36 alternatives were studied. Thirty were eliminated as being technically or economically impractical and 6 cases were selected for further evaluation. Based on a conceptual level capital cost estimate and an evaluation of losses, this quantity was further reduced to 3 cases for economic life cycle analysis. In all cases the present Chugach Electric Association customers along the line will continue to be supplied by Chugach at 24.9 kV One of the basic criteria of the current evaluation and design effort is that the construction of the transmission system upgrade should take place during the 1984 construction season. Because obtaining the requisite permits is critical in achieving this goal, it is proposed to make maximum use of the existing right-of-way. However, the cost estimates include widening of the existing right-of-way by an additional 10 feet of average width. It is felt that one of the ways which the city could improve the reliability of the transmission line is to insure that the right-of-way is maintained at regular intervals and kept clear of brush and danger trees. In order to try and improve accessibility, particularly during the summer months when muskeg areas are difficult to traverse, recommendations are made for rerouting. These occur from milepost 32 to 34 and from milepost 11 to 13. In addition, investigations are being made into the possible use of rights-of-way held by the Alaska Department of Transportation and the Alaska Railroad. vi rc The existing line has suffered from avalanche damage and one of the areas for improving reliability is to attempt to mitigate the consequences of potential avalanche damage. Much of the route is subject to potential avalanche hazard and the opportunities for relocation in these areas are few. Also, complete insurance against avalanche hazard by the use of direct buried cable or submarine cable would be extremely costly, so it is proposed that a variety of passive mitigation measures be used together with underground cable where this would be economic. An estimate will be made for individual areas based upon the estimated frequency of avalanche and an average outage time versus the mitigation costs. This will be undertaken during the design phase. Costs for this cannot be included at this time and all conceptual differential costs in this report are based on the use of aerial construction. The report also considers an alternate route requested by Chugach Electric Association to take power from the Cooper Lake Hydroelectric Plant via a route along the south shore of Kenai Lake to join the existing right-of-way in the area of the Snow River crossing. A detailed study of the terrain shows that this route would only incur more of the same problems which exist on the present alignment in that the area is subject to avalanche hazard and accessibility would be very difficult. Also, the area is designated as roadless by the forest service and hence is environmentally sensitive. This route would require a full environmental impact statement and would most likely not be licensable in time to meet the 1984 construction season deadline. It was therefore concluded that even though this route would offer some advantages in that it would be shorter and would offer an alternate source of power to the city, it was not a viable option. Public hearings are scheduled to be held in Seward and Moose Pass on October 25 and 26, 1983, and it is possible that this public participation may influence the final routing. vii rm The report does not make any attempt to divide the cost of the transmission system upgrade between the City of Seward and Chugach Electric Association. RECOMMENDATION The recommended alternative is a system transmitting power at 115 kV from Daves Creek to Seward with the supply to the Marine Industrial Park from Seward Substation being at 69 kV. Two new three-winding transformers rated 12/16 MVA would be installed in the Seward substation. The existing transformers in the Seward substation, together with their circuit switchers, would be moved to the Marine Industrial Park substation. This scheme provides maximum use of existing equipment including both the present transformers in the city substation and also the new 69 kV transmission line along Nash Road to the Marine Industrial Park. This system is not only the most economic but provides ample capacity for future growth. A final recommendation for the underbuild to supply customers between Lawing and Seward will be made as the detailed design develops. viii INTRODUCTION 1. INTRODUCTION The main source of electric power for the City of Seward is provided by a 40 mile transmission line between the City's Seward Substation and Chugach Electric Association's Daves Creek Substation. Recent growth in Seward is taxing the capabilities of the system, and the 24.9 kV transmission line is already beyond its capacity limit by present day standards. The City's current peak load of approximately 5 MW results in a line loss of approximately 20 percent and voltage drop during peak loading of the line is greater than 15 percent. Considerable industrial growth is currently taking place at the Fourth of July Creek Marine Industrial Park and there is concern that the current system may not be capable of operating the new shiplift facility currently under construction. Three studies have recently been performed to assess the overall situation: ° City of Seward Electric System Planning Study, CH2M Hill, August 1979 ° Analysis of Voltage Drop and Energy Losses, Dwane Legg Associates, 1982 ° Daves Creek-Seward Transmission Line Feasibility Study; Part III of Volume 1 of the Grant Lake Hydroelectric Project Detailed Feasibility Analysis, Ebasco Services Incorporated, February 1983 All of the above studies concluded that prompt action is required to provide adequate service to the City. The load forecast from these studies are compared in Section 3.2. 4815B 1-1 The present report commences with a review of the existing substation and transmission facilities. Following this, the results of power flow and motor starting studies are discussed in order to determine the impact of the new shiplifting facility on the City's present electric system until late 1984, when the present system is scheduled to be upgraded. The basis for the upgrading will be the recommendations contained in this report, which are based on load and energy forecasts by Ebasco. A variety of alternatives both in system design and for routing of the transmission system are discussed and evaluated. The objective is to provide a system which will minimize total project costs while serving the City's long term needs. In addition, the selected alternative shall minimize the dangers of avalanche to system integrity, and, where practical, improve the accessibility of the new line over that of the existing line. The new design must also be one where the required permits can be easily obtained so that construction can be completed before the end of the 1984 construction season. In all alternatives Chugach's customers along the Daves Creek to Seward segment will continue to be supplied by Chugach at 24.9 kV. Customers between Lawing and Seward will be supplied by the City. In all but one alternative the latter line segment will remain at 24.9 kV, and potential interconnecting and metering will be available at Lawing. Conceptual level cost estimates are also included for the technically viable alternatives, together with life cycle cost analyses. These analyses follow the procedures mandated by the Alaska Power Authority. 4815B 1-2 EXISTING POWER SYSTEM 2. EXISTING POWER SYSTEM 2.1 EXISTING TRANSMISSION FACILITIES In 1955, the City of Seward 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. The transmission line from Daves Creek Substation to Seward Substation has a 4/0 ACSR for its entire 40 mile length. The Chugach section of the line from Lawing to Daves Creek is built as 24.9 kV construction using wood poles with horizontal wood crossarms. The Seward section of the line from Lawing to Seward Substation is built as 69 kV construction on wood poles using various configurations such as vertical compact without crossarms, wish bone construction with crossarms, and H-frame with crossarms. 4830B 2-1 re ms ike tw 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-Anchorage 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. Areas of the transmission line are subject to avalanche damage. The area that is reported to be most affected is between Milepost 18 and Milepost 23. Furthermore, some avalanche problems are reported near Moose Pass (Milepost 34) and the junction of the Seward and Sterling highways (Milepost 37). 2.2 SUBSTATIONS The City of Seward and Chugach Electric Association have the following substation facilities in the area: Seward Substation Marine Industrial Park Substation Lawing Metering Station Daves Creek Substation ooo °o Seward Substation - The City's Seward Substation is located on the north end of Seward at the terminus of the existing transmission line. It is presently operated as a 24.9 kV to 12.5/7.2 kV distribution substation with five outgoing feeders. The capacity is about 20 MVA with two 7.5/9.4/10.5 OA/FA/FA three phase transformers. It has a modern steel structure which has been in service for less than five years. 4830B 2-2 hel The primary bus and equipment is designed for dual 69/24.9 kV operation. The primary bus consists of aluminum tubing on nominally 6 foot centers along the west fence. Two positions are tapped off this bus to two 69 kV circuit switchers which are used for protection of the transformers. The transformers have dual 69/24.9 kV primary windings. Voltage control is maintained by LTC equipment which is part of the transformers. The secondary structure has five bays for outgoing feeders. Each feeder is protected with an 01] circuit recloser and underground getaways are used out of the substation. The substation section of the yard south of the control house and generators is approximately 150' x 200'. Of this, there is about a 40' x 150' vacant area along the south fence. Thus, expansion would most likely occur toward the south. Marine Industrial Park Substation - The City is planning a distribution substation at the Marine Industrial Park which is on the east side of Resurrection Bay. It will be located at the terminus of the Fourth of July Creek Transmission Line. Currently, the only equipment at the site is a set of voltage regulators. Lawing Metering Station - The Lawing Metering Station is used as a metering point between the City of Seward's system and Chugach's system. It has a 24.9 kV 01] circuit recloser at the intertie with a fused bypass. Daves Creek Substation - Chugach's Daves Creek Substation is located approximately 40 miles north of Seward on the Sterling Highway. It taps Chugach's Quartz Creek 115 kV transmission line and transforms the voltage to 24.9 kV for two outgoing circuits. One of these circuits feeds the City of Seward's system and the other feeds the Cooper Landing area. The capacity is limited to about 14 MVA due to the 10/14 MVA OA/FA three phase transformer. 4830B The transformer is protected by power fuses and the outgoing circuits by reclosers.. A strain bus which terminates on lattice type towers is used for both the primary and secondary. There is about a 100' x 100' cleared area adjacent to the east fence. However, approximately 3 feet of coarse fill would be required to prevent periodic flooding by Quartz Creek. 2.3 POWER FLOW STUDIES Power flow studies for the existing systems were performed by Dwane Legg Associates and are reproduced in Table 2.3-1. From the table it can be seen that even for a 5 MW load the voltage drop at Seward is 23% which is way beyond acceptable limits. This reaffirms the conclusion that the presently existing transmission system has to be replaced in order to meet future needs. Additional information can be obtained from the next section. 2.4 MOTOR STARTING STUDIES Although the shiplifting facility at the Marine Industrial Park is planned to start operating before the summer of 1984, the new transmission line between Daves Creek and Seward will not be operational until the last quarter of that year. Therefore, for several months the shiplifting facility has to operate from the existing electrical system. The purpose of the studies presented in this section is.to evaluate the effects of the starting of the shiplifting motors on the existing system and to establish procedures by which the adverse affect of the starting of these motors can be minimized. 4830B r TABLE 2.3-11/ VOLTAGE DROP AND ENERGY LOSSES EXISTING SYSTEM CALCULATED AT .90 POWER FACTOR 1000 KW LOAD AT MOOSE PASS kW Load PU Voltage Annual MwH Losses Seward Lawing Seward D.C-Lawing Lawing-Seward Total 4000 -899 -806 1413 1080 2494 5000 -883 -771 2063 1690 3753 6000 -867 7138 2839 2433 5272 7000 853 - 708 3738 3312 7050 8000 -840 - 680 4761 4326 9087 9000 -827 -654 5909 5476 11385 10000 -816 -630 7179 6760 13939 11000 -805 -608 8574 8180 16754 12000 -795 587 10092 9735 19827 13000 -876 -567 11735 11425 23160 14000 -178 -549 13502 13251 26753 15000 - 769 - 532 15392 15211 30603 16000 - 762 -515 17407 17307 34714 17000 754 -500 19545 19538 39083 18000 - 7148 -485 21808 21905 43713 19000 -741 -472 24194 24406 48600 20000 -735 -459 26703 27043 53746 V ~“ Reprinted from the report by Dwane Legg Associates, October 1982. Sea Uta EUS NEES SUES 4830B 2=5 The shiplifting facility employs 28 motors in two groups of 14 each. The motors will be manufactured by the Louis Allis Mfg. Co. According to the manufacturer, their current at full load is 20 ampere, at 460 volt, the efficiency is 86% and their power factor, at rated load, is 0.84; at full voltage the locked rotor current is 105 ampere. Each group of motors will start simultaneously and reach full speed in less than 0.5 seconds. The second group of motors starts half a second after the first group of motors has been started. Consequently, at the time of the starting of the second group, the first group is already at full speed. For the purpose of these studies the worst case conditions were assumed, which means that the first group is at full speed and that the second group of 14 motors has just been switched onto the line. For the starting conditions it is assumed that the locked rotor power factor of the motors is 0.2. With these data, the total electrical load caused by starting the second group of motors is 390 kW and 1,180 kVAR. Figure 2.4-1 shows the electrical system that was modeled on the digital computer. Figures 2.4-2 and 2.4-3 show the impedance diagrams. A large number of studies were carried out initially without considering the diesel generators on line during the start or having only the 2.5 MW unit on line. Both alternatives proved to be unsuccessful and the flicker along the system was excessive. The following starting procedure was developed. First, the 12.47/0.48 kV transformer of the shiplift facility has to be set toa tap which provides maximum secondary voltage. For the load flow studies, a 0.9 HV tap setting was assumed, giving a 10 percent boost to the 480 volt system. This could also be accomplished by using the 0.95 HV tap setting of a 12.0/0.48 kV transformer. 48308 2-6 ha If the city load is more than 1 MW at the time of starting the motors, all three diesel generators at the City power plant will have to be started and synchronized with the Chugach system. Approximately half of the City's load, both megawatt and megavar, has to be carried by the diesel generators and the other remaining portion by Chugach. The power factor correcting capacitors which are installed on the Seward system have to be on the line. Under these conditions the voltage will drop by approximately 20% on the 480 volt bus of the shiplifting facility. This voltage drop is acceptable and should cause no problems during the start of the motors. The 400 kW real power has to be absorbed for only 0.5 seconds and, as the diesel capacity connected to the system is 5.5 MW, this should cause no problems. The conditions can be seen when comparing Figures 2.4-4 and 2.4-5. Should the voltage level during starting be unacceptable to the manufacturer, a 600 MVA capacitor bank can be installed at the 12.47 kV bus on the Marine Industrial Park. The capacitor bank should preferably be switched on simultaneously with the starting of the motors. It is our understanding that the City has two such switchable banks in stock. The conditions can be seen comparing Figure 2.4-8 and 2.4-9. Though the voltage drop on the 480 V bus did not decrease, the range has been shifted. At no load the voltage is about 9% high so during start, the voltage drop is only 15%. Further improvements can be made if both 600 kVA switchable capacitor banks are connected to the system at the time of starting. This can be seen by comparing Figures 2.4-6 and 2.4-7. With this arrangement the flicker on the 12.47 kV bus of the Marine Industrial Park is only 12%. On the other extreme it was assumed that the motor starting takes place during a time when the City's load is very light, which was assumed to be 0.5 MW only. Comparing Figures 2.4-10 and 2.4-11 reveals that in this case the starting will not cause major problems even if no capacitor is switched onto the 12.47 kV Marine Industrial Park bus. 4830B e-7 The light load situation was explored also with the diesels not connected to the system at all. The results indicate that in case of low loads the motors can be started even without turning the diesels on. This can be seen in Figure 2.4-14. However, it is recommended that a uniform procedure be introduced which mandates the starting of all the diesels in case of starting the shiplift motors. It is recognized that starting the diesels for every shiplifting activity is a nuisance; however, this is only a temporary situation and is very cost-effective. In conclusion, Ebasco recommends that whenever the shiplifting motors are started, all diesels should be connected to the system and approximately half of the City's megawatt and megavar load be transferred to the diesel generators prior to starting the motors. It is also recommended that, unless the manufacturer of the motors objects or customer complaints become prevelant, no capacitors be switched during the start at the Marine Industrial Park. 4830B 2-8 eas 115kv Chugach System 115kV 24 .9kV 16 Miles Daves 24 .9kV (69)24.9/12.47 Generator Trans former 2.4kV Generator Transient Reactance 2-9 Daves Creek 115/24.9 Transformer Creek to Lawing 24 Miles Lawing to Seward Trans former 12.47kV 2.5 Miles along Nash Road 12.47kV 4 Miles New Line 12.47kV Shiplift Transformer 480V Shiplift Motors CITY OF SEWARD MOTOR STARTING STUDY ONE LINE DIAGRAM Date OCTOBER 19835 EBASCO SERVICES INCORPORATED rm 40.309 j0.86 2-10 1.53 + 1.75; (0.7 MVAR Charging) 2.32 + §3.06; (0.9 MVAR Charging) 2.5 + j1.22; (0.03 MVAR Charging) 0.765 + j1.75; (0.04 MVAR Charging) 57.14 Shiplift Motors CITY OF SEWARD MOTOR STARTING STUDY IMPEDANCE DIAGRAM Date OCTOBER 1983 [Figuac2.4-2 | EBASCO SERVICES INCORPORATED 115kV j9.8; 2.5MW diesel in service 4.5 All diesels in service Diesels 2-11 3.85 + j6.06; (0.16 MVAR Charging) 12.47kV 3.27 + j2.96; (0.007 MVAR Charging) 12.47kV Shiplift Motors CITY OF SEWARD MOTOR STARTING STUDY CONSOLIDATED IMPEDANCE DIAGRAM DATE OCTOBER 1963 EBASCO SERVICES INCORPORATED rz ta 0.84 /-15.2° TAP : 0.9 0.94 /-16.4° CITY 0.94 /-16.4° TAP: 0.9 1.04 /-16.4° 1.0 /-11.6° CiTY OF SEWARD TRANSMISSION SYSTEM MOTOR STARTING STUDY Peak City Load, 0 MVAR Capacitors at Marine Industrial Park, Motors Off. Bate OCTOBER 1985 2-12 EBASCO SERVICES tNCORPORATED re oo eo O nee Peak City Load, 0 MVAR Capacitors at Marine Industrial a Park, Motors Start. 2-13 0.88 /-15.5 0.82 /-12.9° TAP: 0.9 0.8 /-15.1° MOTOR STARTING STUDY Date OCTOBER 1963 EBASCO SERVICES INCORPORATED o 0.88 /-16° TAP: 0.9 .02 /-19.4° TAP: 0.9 .13 /-19.5° Peak City Load, 1.2 MVAR MOTOR STARTING STUDY Capacitors at Marine Industrial Park, Motors Off. ate OCTOBER 1983 EBASCO SERVICES INCORPORATED 2-14 TAP ; 0.9 Peak City Load, 1.2 MVAR Capacitors at Marine Industrial Park, Motors Start. 0.83 /-15° 2-15 0.9 /-16.2° TAP: 0.9 0.91 /-18° CiTY OF SEWARD MOTOR STARTING STUDY OatEe OCTOBER 1983 EBASCO SERVICES ¢NCORPORATED ~~ 0.86 /-15.7° TAP ; 0.9 Peak City Load, 0.6 MVAR Capacitors at Marine Industrial Park, Motors Off. 2-16 0.98 /-18.1° TAP: 0.9 1,09 /-18.1° CITY OF SEWARD MOTOR STARTING STUDY DATE OCTOSER 1983 EBASCO SERVICES INCORPORATED mo rm 0.81 /-14.6° TAP; 0.9 0.86 /-14.6° TAP: 0.9 0.85 /-16.6° Peak City Load, 0.6 MVAR Capacitors at Marine Industrial Park, Motors Start. Sate OCTOBER 1963 2-17 MOTOR STARTING STUDY EBASCO SERVICES WNCORPORATED re CITY 1.02 /-6.2° 1.01 /-6.2° TAP: 0.9 1.12 /-6.2° MOTORS CiTY OF SEWARD MOTOR STARTING STUDY Light City Load, .0 MVAR Capacitors at Marine Industrial Park, Motors Off. ss Bate OCTOBER 1985 2-18 EBASCO SERVICES INCORPORATED 0.94 /-2.8° TAP ; 0.9 1.04 [-3.1° 0.99 /-1.4° TAP: 0.9 1.02 /-2.9° MOTORS CiTY OF SEWARD MOTOR STARTING STUDY Light City Load, 0 MVAR Capacitors at Marine Industrial Park, Motors Start. Bate OCTOBER 19863 2-19 EBASCO SERVICES INCORPORATED nw TAP ; CITY 1.02 /-6.4° Light City Load, 0.6 MVAR Capacitors at Marine Industrial Park, Motors Off. 1.1 1.11 /-6.4° 2-20 1.04 /-7.7° TAP: 0.9 1.16 /-7.7° MOTORS CITY OF SEWARD MOTOR STARTING STUDY Oate OCTOBER 19635 EBASCO SERVICES INCORPORATED eo mm 1.07 /-5.3 TAP? 14 CITY 0.95 /-4.7° TAP: 0.9 0.97 /-6.3 1.02 /-4.6 ° MOTORS CITY OF SEWARD TRANSMISSION SYSTEM MOTOR STARTING STUDY Light City Load, 0.6 MVAR Capacitors at Marine Industrial Park, Motors Start. Dave OCTOBER 1903 [FiGumc2. 4-13 | EBASCO SERVICES INCORPORATED 2-21 rf Light City Load, Diesels Off, 0.6 MVAR Capacitors at Marine Industrial Park, Motors Off. 2-22 1.03 /-5.9° TAP: 0.9 1.06 /-7.1° MOTORS CiTY OF SEWARD MOTOR STARTING STUDY ate OCTOBER 1983 [Figuac2.4-14 | EBASCO SERVICES INCORPORATED LOAD & ENERGY FORECASTS 3. LOAD AND ENERGY FORECASTS 3.1 FORECAST PURPOSES AND OVERALL APPROACH Electric power demand and energy forecasts largely determine the size and type of transmission system needed to provide adequate service to the Seward service area during the next 30 years. Because of the importance of these load and energy forecasts in transmission line design, a forecasting method offering the highest possible reliability and rationale was selected. The forecasting method combines an analysis of the Seward area's economic and demographic growth, within the context of the Railbelt, with an assessment of end uses of electricity in industry and the residential sector. The peak load and energy forecasts for the Seward service area were made in a sequential manner. First, existing load and energy forecasts were reviewed and evaluated. Next, current economic and demographic information for the service area was assembled, along with electricity end use data by sector. Particular attention was given to future industrial and commercial sector load growth which may not have been considered in earlier forecasts. Electric appliance saturation data, electricity prices and alternative fuel prices, conservation effects on energy consumption, household formation rates, and other related factors were incorporated in the residential demand forecast. The economic, demographic, and end use load data were then linked with load trends to produce estimates of future peak demand. Three forecast scenarios were prepared in order to provide a range within which actual loads and energy can reasonably be expected to occur. The high, moderate, and low forecasts correspond to different assumptions about the size and nature of local economic growth and the resulting demand for electricity. The range of forecasts provides a test of the sensitivity of electrical demands to changes in the underlying assumptions. 3-1 4787B tS a The following sections describe the forecasts of peak electric power demand and energy consumption, and summarize the basis for the forecasts. Section 3.2 presents in tabular format peak demand and energy forecasts for each of the three scenarios. Section 3.3 summarizes the methodology applied to generate the forecasts. Principal assumptions utilized in each scenario are provided in Section 3.4. Section 3.5 lists the data sources for the forecasts. 3.2 LOAD AND ENERGY FORECASTS Summaries of the load and energy forecasts for each scenario are shown on Table 3.2-1. The end of the economic life of the transmission system is 2014. It defines the end point of the design and economic evaluation. Total peak load in the year 2014 varies from a high of 27.49 megawatts (MW) to a low of 12.18 MW. The moderate forecast reaches a peak load of 16.56 MW by the same year. Total energy use in the year 2014 ranges from a high of 82,885 megawatt hours (MWH) in the high scenario to 58,387 MWH in the low scenario. The moderate forecast reaches a total energy use of 68,424 MWH in the same year. These correspond to 0.34, 0.55, and 0.47 load factors, respectively. Several load and energy forecasts have been made for the City of Seward during the last few years in conjunction with rate studies (Kennedy/Jenks 1983) ,2/ earlier studies of the transmission system (Dwane Legg Associates 1982) and studies of the Grant Lake Hydroelectric Project (CH2M Hill, Inc. 1979; Ebasco Services Incorporated 1983). Figures 3.2-1 and 3.2-2 compare the peak and energy forecasts respectively for the most likely or moderate scenario in each of the above referenced reports with the moderate growth scenario developed in this report . The reader is referred to the referenced reports for detailed information on assumptions and alternative growth scenarios. y/ References are listed at the end of this chapter. 3-2 47878 TABLE 3.2-1 COMPARISON OF LOAD AND ENERGY FORECASTS FOR 2014 Growth Scenario High Moderate Low Population 5,463 5,392 5,320 Employment 2,113 2,084 2,055 Exogenous Industrial 17.45 7.20 4.27 Peak (MW) Total Peak (MW) 27.49 16.56 12.18 Energy (MWh) 82,885 68,424 56,387 Load Factor 0.344 0.472 0.528 3-3 4787B = fz ZH VSZSYFIMOe AYMV 3a 1988 1985 FIGURE 3.2-1 COMPARISON OF LOAD GROWTH FORECASTS MODERATE GROWTH SCENARIO SEWARD CDWANE LEGG ASSOC., 1982) GRANT LAKE CCH2M HILL, 1979) GRANT LAKE CEBASCO, 1983) 1998 1995 2080 2885 YEAR 3-4 2018 2015 a s of tet ZH ~QOAM2S™M THOUSANDS FIGURE 3.2-2 188 COMPARISON OF ENERGY GROWTH FORECASTS 98 8a 78 68 58 48 MODERATE GROWTH SCENARIO SEWARD CKENNEDY/JENKS ENGINEERS, 1983 38 SEWARD CDWANE LEGG ASSOCIATES, 1982) GRANT LAKE CCH2M HILL, 1979) GRANT LAKE CEBASCO, 1983) 28 1988 1985 1998 1995 - 2888 2885 20198 2015 YEAR 3-5 vo fod The Grant Lake forecast (Ebasco Services Incorporated 1983) was based on information provided by the City of Seward (City of Seward 1982) in late 1982. This forecast has been revised downward and several of the projects have been delayed. There is a difference of approximately 3 MW between the forecast used for the Grant Lake Report and this report when the diversity factor of 75% is taken into account, which is a measure of the peak loads which occur simultaneously. The remaining difference can be accounted for by slower commercial and residential development which results from slower industrial growth. The energy forecast used in the Grant Lake report assumed the low factor (initially 58%) in the load growth scenario would apply to the moderate growth scenario. Since that time, additional energy projections have been made (Landman 1983) which are considerably lower. An example is the largest new load to be added in the moderate growth scenario (see Table 3.4-1). VECO's load is projected to peak at 4 MW but the load factor is only 5%. This load is largely responsible for the lower future load factors mentioned at the beginning of this section. The earlier studies (CH2M Hill, Inc. 1979; Dwane Legg Associates 1982) lie between the two Ebasco load forecasts. The CH2M Hill study did not contain detailed information on the new industrial loads that are projected and is fairly outdated. The Dwane Legg report incorporates new industrial growth as a high percentage growth function and is based on earlier information which indicated more rapid industrial development. The Kennedy/Jenks study provides a reasonably close estimate of energy growth when the latest energy projections for new industrial development are taken into account. The other studies produced significantly higher energy forecasts due to higher assumptions on load factor and/or earlier industrial development. 4787B ie 3.3. FORECASTING METHODS The load and energy forecasts were produced by summing loads and energy in each of four sectors: industrial, government, commercial, and residential. To estimate load and energy growth in each of these sectors, economic indicators were developed, along with end use electric power data. The economic indicators, employment and population forecasts were prepared using a method that produced results consistent with the economic forecasts used in the July 1983 Susitna Hydroelectric Project license application. This method involved initially disaggregating the Railbelt forecasts used for the Susitna Project to the Seward area, and making adjustments to reflect specific industrial developments not explicitly taken into account in the Railbelt forecasts. Electric power end use data were developed for each of the principal power consuming sectors in the Seward area. This process involved developing data for both specific industrial developments as well as average use data for use sectors. The economic and demographic and end use analyses are described in more detail in the following subsections. Table 3.3-1 summarizes the economic and demographic data on which the load and energy forecasts are based in the high growth scenario. The table also summarizes the procedures followed to produce the final load forecasts. Table 3.3-2 presents corresponding information for the moderate growth scenario, including the adjustments made to the economic, demographic, and industrial end use data summarized in Table 3.4-1 and described in detail in Sections 3.3 and 3.4. Table 3.3-3 provides corresponding information for the low scenario. Each table, 3.3-1, 3.3-2 and 3.3-3, is divided into two sheets: Sheet 1 Economic and demographic data and initial adjustments. This part is the same for all three scenarios. Exogenous population and employment adjustments are also included. Sheet 2. Load forecast for each growth scenario. 3-7 4787B For ease of explanation, the columns are numbered sequentially through all both sheets of the table. Figure 3.3-1 provides a graphical comparison of the three load growth scenarios. ‘ Table 3.3-4 through 3.3-6 summarize the procedures followed to produce the final energy forecast. Tables 3.3-4, 3.3-5 and 3.3-6 correspond to the high, moderate and low growth scenarios respectively. Figure 3.3-2 provides a graphical comparison of peak loads for the average annual energy for each of the three growth scenarios. Notes following the tables describe the relationships between table columns. The notes provide an overview of the procedure followed to derive the load and energy forecasts. Each note includes a Report Section Reference Number which refers the interested reader to a more detailed discussion of data sources, assumptions, and procedures. 3.3.1 Economic and Demographic Forecasts Economic and demographic parameters were prepared for this project by the University of Alaska's Institute of Social and Economic Research (ISER). ISER disaggregated the Railbelt forecasts that serve as the reference case for the Susitna Hydroelectric Project July 1983 licence application. The Seward area forecast is, therefore, consistent with the Susitna reference case. Two adjustments, however, were made to the ISER forecast. The first adjustment increased the total 1983 employment projection in order to bring it in line with historical employment data for the Seward area. The second adjustment was made in exogenous basic industrial development. When the demand for goods and services outside a region leads to economic growth within a region, that growth can be called “exogenous." That is, the growth is a result ' of a combination of forces outside the local economy and the competitive advantages of the region in question. Exogenous growth takes place first in the basic industries. Both adjustments are discussed fully in Sections 3.3.1.2 and 3.3.1.3. 3-8 4787B Sz ZH VZPFPIMSo APYrMV FIGURE 3.3-1 30 COMPARISON OF LOAD GROWTH SCENARIOS 25 28 15 18 5 ——— HIGH GROWTH SCENARIO seneeeees MODERATE GROWTH SCENARIO weceeee LOW GROWTH SCENARIO 8 + 198 1985 1990 1995 2888 2005 2018 2015 YEAR 3-9 = — TABLE 3.3-1 HIGH GROWTH SCEARIO (SHEET 1 OF 2) SEWARD REGIONAL YEAR EMPLOYMENT (SER) PoP. ADJUSTED EMPLOMENT® % POP. PERSONS HSHLDS.## EMPLOYMENT — EXOGENOUS EXOGEN. TOTAL TOTAL EMPLOYMENT ADJ. FOR EXOGEN. EFFECT BASIC GOVT, SUPPORT TOTAL Basic cor. SUPPORT TOTAL EMPLOYED PER EXOGEN.EXOGEN. POP. HSHLDS. POP. HSHLDS. BASIC GOVT, SUPPORT T01 % % % HSHLD BASIC SUPPORT 1 2 3 ‘ 5 ‘ ? 8 9 10 i 12 19 4 15 16 ” 18 9 2 a n 2 a 5 1982 297 495.269, *1022S OSB AN 39.28 455 36.58 = 37541244 40.68 2.881108 se 106) SS 1983 318 «© 452,—S 28010503147 439 34.37, 5235.37 387 30.26 = 1278 40.6 2.861 1100 47003952 87 1984 3204542891064 3249 M4241 AS43505 399 30.82 1295-09. 94 2.854 1136 10 4 % 1903279452 AO: 1985 335 474s 302—sNN.—=—s«384H—( MKS AH 35.02- 730.8195 40.47 2.841177 25 i 89 37th 9B aH a 1906 3484903412 3455 480 34.20 A 34.94 433 0.851402 40S 2.894129 33001263: (a a 1987 357 499—s«320—s*dN7H~—=s«58B AZ 4.35497 34.86 AAT 0.79143) 40.4 2.826 1252 3663-(«128——i(itiP aK i9e0 359 505s375s«dP«35B5— AS34750 BP 4B 30.94 1447 40.37 2.817 1273 20 ’ n 2 «9782s (tH a 1909 375505 s«339Ss«212-—=—ss 3484S 34.84 50S 34.239 456 0.931475 40.37 2.812 1299 30511370569 SS 1990 396 «= 506 43—s«*28G=CsC7H—s«SAZ 95.71 506 33,36 469 30.93 517 40.65 2.806 1330 10 4 % Sy nn | 1991 39) = 502,-s«350-«1249-=« 3790-533 35.26 = 502 33.18 = 4784.56 1513.39.92 2.801 1359 4231438 9B8—( 0 NHC 1992 405 «522, 36S——s«1292—=—— 86S 8898514 S22 33.1 98.67) 1573 40.6 2.793 1384 10 4 % 1941331400 6B SDH 1993 4165363781329 4090-547 95.03 58633, SIS 1.891418 40.14 2,788 1445 ae 1542s— SH KB 1994 417548 38413474128 5784.69 SHB 93.97 S24 3.9 16K2 39,78 2.782 1484 439615804 BSS 1995 4125613113639 4201549 39.96 = SHE 33.8) S35 32.29 1459 39.49 2.777151 49109 388 SH KB 1996 4145633951972 424BS S47 93.92 5633.71 SAN 92,37 1670 39.91 2.772 1532 45161629 42 863K 1997 417561 39913784285 S70 34,01 S61 33.45 S46 32,54 1677 39.14 2,767 1549 45531646 AS SHC SD 1998 421 552 4041977 4310574 34.22 552) «32.93 S50, 92.84 1676 = 38.89 2.763 1560 457816574 SS2 SM 5444101374335 577 34.40 54432. 557 93,19 1479 38.72 2.788 1572 460216952 iS 5399416 139844364 5824.57 537 32.00 563 33,.44 1685 38.60 2,755 1584 432 hs (aS SIF 5444241393 4405883469 8343.49 573 33.81 1496384 2.751 1599 46681697 69 S04 5 432,102, 4437 5944.79 590, 31,06 = 98934161707 38.46 2.747181 45171966 SK 52744) AA 4475 600 34.89 527 30.62 594344 7E 38.46 2.744183 ama 1729s 6S SF 52545) :1428 4520 0B. 34.98 525 30.20 0S 34.82 1738 38.46 2.741149 4701747 89525 IP. 523461 1445456917 35.09 523. 29.73 6135.17 1789 38.50 2.737 1869 4037 «1767, 92,829 SZ 522473, 14694624628 35.16 5229.31 3935.53 1781S 8.512.735 Nat 4092 «1789 ULC 2‘ S21 48614844689 637 35.25 S21 28.84 6495.91 = 1806 = 98.52 2.732176 49571814712 S218 5214991506) 4759. M7 35.28 S21 28.42 665 346.90 1833 98.57 2.730174 021839722 (ase 522 S13. 15284824656) 35.25 5228.07 «682 34.68 1840 38.56 2.727 1769 5021867) SDHC 523 527,582 4896S 64S «35.28 = 523 27.68 «= 700 37,04 = 1889) 38.59 2.725 1797 sid 1095 (82D 4969 = 676 35.26 531 27.6B8 8037.04 = 197 38,59 2.723 1825 5237 1923s a SH Nt 5043 687,«35.28 «= 539 27.68 «= 721 37,04 = 1946 98.59 2.721 1853 sul 195282 SK 5119 = 697,«35,28 = 547—27,68 = 731 37,04 1975 38.59 2.719 (1882 5907198) SAP Hk 5195 707, 35.28 «585 27.6B = 4237.04 = 2004 38.59 2.717 1912 5469-201) 7828S Ht © REFERENCING MEMORANDUM OF SEPTEMBER 16, 1983 TO BILL HUTCHINSON FROM 0. S. GOLDSMITH, ISER, SUBJECT: APA REFERENCE CASE PROJECTIONS FOR SEWARD; 1982 EMPLOYMENT OF 1244 AS PER ALASKA POPULATION OVERVIEW, ALASKA DEPT. OF LABOR. #6 HOUSEHOLD SIZE FROM 2011 ON 1S EXTRAPOLATED USING LOG-LOG REGRESSION. 3-10 TABLE 3.3-1 HIGH GROWTH SCENARIO (SHEET 2 OF 2) RESIDENTIAL DISCRETE DISCRETE TEAR ALL ALL NON-ALL RESIDENT COMMERCIAL GOVT. EX0GEN. EXOGEN. ENDOG. INDUSTRIAL TOTAL MARINE MARINE TOTAL PEAK ELECTRIC ELECTRIC ELECTRIC PEAK PEAK PEAK INDUST. INDUST. INDUST. - PEAK PEAK INDUST. INDUST. W/O PARK HSHLDS. PEAK PEAK LOADS PEAK PEAK PRK LOAD PRK PEAK (Ma) (Ma) (ma) (a) (ma) (Ma) (Md) (Mu) (Ma) (Md) (a) (a) (Ma) 2 28 2” » Kd] 2 33 4 35 % ” 8 x» 40 4a 1983 39 1.90 0.62 2.52 1.07 0.79 sau 1984 568 2.08 0.62 2.70 1.07 0.50 13 5.85 1985 640 2.94 0.42 2.96 1.12 7.27 8.17 13.06 1986 682 2.50 0.62 3.12 1,16 7.60 0.93 8.52 13.64 1987 m5 2.62 0.42 3.24 1.18 7.65 0.95 8.80 14.08 1988 762 2.79 0.62 241 ay 10.67 0.99 = 11.86 17.35 1989 789 2.89 0.62 3.51 ay 11.33 1.02 12.35 17.96 1990 832 3.04 0.62 3.66 ay 12.40 1.09 = 13.50 19.29 1991 855 3.13 0.42 3.75 19 12.32 1.08 = 13.39 19.28 1992 899 3.29 0.42 29 1.23 13,19 113° 14,32 20.47 1993 961 3.52 0.62 4.14 1.27 13.57 1.15 14,72 2.16 1994 999 3.66 0.42 4.28 1.29 13.70 1.16 14.86 21.49 1995 1028 3.76 0.62 4.38 1,32 13.65 1.15 14,80 21.58 1996 3.84 0.42 4.46 1.93 13.79 1.15 14,94 21.81 1997 1065 3.90 0.42 4.52 1.32 13.95 1.16 0 15.01 22.05 1998 1076 3.94 0.42 4.56 1.390 14.16 1.17 15.26 22.23 1999 1088 3.98 0.62 4.60 1,28 14.26 1.17 15.43 22.43 2000 1100 4.03 0.62 4.65 1.27 14.44 1,18 = 15.62 22.67 2001 6 4.09 0.62 4.7 1.26 14.65 1.19 (15.84 22.95 2002 1132 4.14 0.42 4.76 1.25 14.04 1.20 16.05 23.22 2003 1148 4.20 0.62 4.82 1.24 15.07 1.21 16.29 23.53 208 = 12.27 2004 1166 4.27 0.62 4.89 1.24 15.24 1.23 16.47 23.80 12.40 2005 1186 4.34 0.62 4.9% 1.23 15.45 1,24 16.69 24.12 12.57 2006 1208 4.42 0.62 5.04 1.26 1,23 15.64 1.26 i6.90 4.43 12.73 2007 1234 4.52 0.62 5.14 1.29 1.23 15.88 1,28 17.16 24.81 12.92 2008 1258 4.61 0.62 5.23 1.32 1,23 16.10 1.30 17.40 25.18 13.01 2009 128600 4.71 0.62 3.33 1.35 1.23 16.30 1.31 17.62 25.53 13.27 2010 1314 4.0) 0.62 3.43 1.38 1.23 16.54 1.33 17.88 3.93 13.46 2011 1342 491 0.62 3.53 1.40 1.25 16.77 1,35 18.12 26.31 13.64 2012 1371 3.02 0.62 5.64 1.42 1.27 16.99 1.37 18.36 26.69 13.63 2013 1400 5.13 0.62 3.75 1.44 1.29 17.22 1.39 18.61 27.09 14.08 2014 1430 3.23 0.62 3.85 1.46 1.31 17.45 1.41 18.86 27.49 14.20 3-11 TABLE 3.3- MODERATE GROWTH SCENARIO 2 PER HSHLD (SHEET 1 OF 2) SEWARD REGIONAL YEAR EMPLOYMENT (1SER) POP. ADJUSTED EMPLOYMENT # BASIC GOVT. SUPPORT TOTAL BASIC GOT. SUPPORT TOTAL EMPLOYED % a x 1 2 3 4 5 6 ? 8 9 10 i 12 13 14 1982 297 455 269 1022 3058 414 (33.28 455 36.58 375 30.14 1244 40.68 1983 318 452 280 1050 3147 439 34.37 45200 (35.37 387 30.26 1278 40.41 1984 320 454 289 10464 3243 44200 394,13 454 (35.05 399 = 30.82 1295 39.94 1985 335 44 302 12 3346 46300 (34.17 474 (35.02 417 (30.81 1354 40.45 1986 348 490 a4 1152 3455 480 (34.20 490 34.94 433 30.86 1402 40.59 1987 357 499 320 1176 3538 4920 34.35 499 34.86 441 30.79 1431 40.46 1988 359 305 925 1189 3585 495 34.17 3054.89 448 30.94 1447 40.37 1989 375 505 333 1212 3654 S14 34.84 505 34.23 4560 30.99 1475 40.37 1990 396 306 443 1246 731 34200 (35.71 306 (33.36 469) -30.93 1517 40.65 1991 391 302 350 1243 3790 533° 35.26 502 (33.18 4781.56 1513 39.92 1992 405 522 465 1292 3865 353° 0(35.14 522. 33.19 498 31.67 1573 40.49 1993 416 536 378 1329 4030 367) 35.03 3360 (33.13 5 1.83 1618 40.14 1994 417 548 384 1349 4128 578 34.69 348 (33.37 3243.94 1642 39.78 1995 412 36! 9 1363 4201 363 (33.96 3610 33.61 3350 (32.23 1659 39.49 1996 414 363 395 1372 4248 567 (33.92 36300 (33.71 S41 32.37 1670.39.31 1997 417 S6t 399 1378 4285 5370 34.01 361 33.45 3460 (32.54 1677 (39.14 1998 421 352 404 1377 4310 574 34.22 352 (32.93 550 32.84 1676 38.89 1999 425 344 410 1379 4335 57? 34.40 344 32.41 357 33.19 1679 38.72 2000 430 539 416 1384 4364 38200 (34.57 539 (32.00 3630 (33.44 1685 38.40 2001 435 334 424 1393 4400 388 34.69 5343.49 373° 33.81 1696 = 38.54 2002 440 530 432 1402 4437 594 34.79 530 31.06 383° 34.16 1707 38.46 2003 446 327 441 1414 4475 600 34.89 52?) 30.62 594 34.49 1721 38.46 2004 453 325 451 1428 4520 408 (34.98 525° (30.20 605 = 34.82 1738 38.46 2005 460 323 461 1445 4569 617 (35.59 323° (29.73 619 (35.17 1759 38.50 2006 4468 322 473 1463 4624 626 35.16 3220 29.31 633° (35.53 1781 38.51 2007 477 352i 486 1484 4689 637 35.25 52) 28.84 649 35.91 1806 = 38.52 2008 485 321 499 1506 4753 647) -35.28 S2i 28.42 $65 36.30 1833 38.57 2009 493 522 33 1528 4824 656 95.25 522. 28.07 682 36.68 1860 38.56 2010 502 523 327 1552 4896 666 (35.28 523. (27.68 700 -37.04 1089) 38.59 2011 4969 676 (35.28 S31 27.68 710 = 37.04 1917 38.59 2012 3043 687 (35.28 539° (27.68 721 37.04 1946 38.59 2013 wy 697 35.28 547 (27,68 731 37.04 1975 38.59 2014 S195 707 -35.28 555 27.48 742—«37.04 2004 = 38.59 © REFERENCING MEMORANDUM OF SEPTEMBER 14, 1983 TO BILL HUTCHINSON FROM 0. S. GOLDSMITH, ISER, SUBJECT: APA REFERENCE 1982 EMPLOYMENT OF 1244 AS PER ALASKA POPULATION OVERVIEW, ALASKA DEPT. OF LABOR. #4 HOUSEHOLD SIZE FROM 2011 ON 1S EXTRAPOLATED USING LOG-LOG REGRESSION. 3-12 15 2.881 2.861 2.854 2.843 2.834 2.826 2.817 2.812 2.806 2.001 2.793 2.788 2.782 2.777 2.772 2.767 2.763 2.758 2.755 2.751 2.747 2.744 2.741 2.737 2.735 2.732 2.73 2.727 2.725 2.723 2.721 2.719 2.717 CASE PROJECTIONS FOR SEWARD; % POP. PERSONS HSHLDS.## 16 1061 4100 1136 4177 129 1252 1273 1299 1330 1353 1384 1445 1484 1513 1532 1549 1560 1572 1584 1599 1615 1631 1649 1669 1691 1716 1741 1769 1797 1825 1653 1882 1912 ws EMPLOYMENT =—- EXOGENOUS EXOGEN. EXOGEN.EXOGEN. POP. HSHLDS. BASIC SUPPORT 17 18 9 20 10 4 % 13 5 iW 89 au 5 2 18 4 15 7 33 19, eb ai TOTAL TOTAL EMPLOMMENT ADJ. FOR EXOGEN. EFFECTS POP. HSHLDS. a 22 3058 1061 3147 1100 3279 1149 3471 4221 3580 1263 3663 1296 3728 1324 397 1350 3928 1400 3987 1423 4062 1454 4227 1516 4325 1555 4398 1584 4445 1603 4482 1620 4507 1631 4532 1643 4561 1655 4597 1671 4634 1687 4672 1703 4717 1721 4766 1741 4821 1243 4886 1788 4950 1013 5021 1641 5093 1869 3166 1897 5240 1926 S35 1955 5392 1984 BASIC 23 a4 49 452 498 w5 527 335 554 597 608 622 625 418 622 625 629 632 63? 643 649 655 663 672 681 692 2 mt m1 m1 742 752 762 GOVT. SUPPORT “4 23 455 375 452 387 454 404 474 433 490 448 499 456 305 466 305 44 306 494 302 302 522 523 536 539 548 549 Sot 559 363 565 Sét 370 352 35 344 382 539 388 534 598 530 Cl 527 618 325 600 523 643 522 657 321 673 321 690 $22 07 523 724 331 735 539 745 347 756 555 1) TOTAL % 1244 1278 1310 1404 1453 1482 1505 1533 1596 1592 1652 1697 1722 1739 1750 175? 1756 1758 1764 1775 1766 1801 1818 1838 1860 1686 1913 1939 1969 1997 2025 AN) 2084 TABLE 3.3-2 MODERATE GROWTH SLENARIO (SHEET 2 OF 2) RESIDENTIAL DISCRETE DISCRETE YEAR ALL ALL NON-ALL RESIDENT COMMERCIAL GOVT. EXOGEN. EXOGEN. ENDOG. INDUSTRIAL TOTAL MARINE MARINE TOTAL PEAK ELECTRIC ELECTRIC ELECTRIC PEAK PEAK PEAK INDUST. INDUST. INDUST. - PEAK PEAK INDUST. INDUST. W/O PARK HSHLDS. PEAK PEAK LOADS PEAK PEAK PRK LOAD PRK PEAK (mu) (ma) «may (Md) (ma) (Mu) (Md) (mu) (ma) (md) (ma) (ma) (ma) ru 28 29 0 uv 2 23 4 35 % 0 8 9 a 4 1983 oy 1.90 0.62 2.52 0.73 4.07 0.79 0.79 Sil 5. 1984 556 2.03 0.64 2.67 6 1.07 0.81 iy 5.69 5.69 1985 610 2.23 0.66 2.89 2 1.12 5.48 10.31 3.77 6.55 1986 642 2.35 0.67 3.02 85 1.16 3.57 10.60 3.82 6.77 1987 666 2.44 0.468 3.12 6 1.18 3.465 10.81 3.88 6.93 1988 687 2.51 0.69 3.21 68 1g 5.80 11.07 4.01 7.06 1969 7 2.59 0.70 3.29 0.89 19 3.69 11.27 4.07 7.20 1998 4 2.72 0.72 3.44 0.93 iy 7.53 13.09 3.63 7.46 1991 762 2.799 0.72 351 0.95 ay 7.37 13.21 5.69 7.53 1992 785 2.87 0.73 2.41 0.99 1.23 7.66 13.48 3.74 7.74 1993 831 3.04 0.75 3.80 1.02 1.27 7.74 13.62 5.60 8.02 1994 860 3.15 0.76 3.91 1.04 1.29 7.81 14.05 5.86 8.19 1995 882 3.23 0.77 4.00 1.06 1.32 7.85 14.23 5.92 8.32 1996 497 3.28 0.78 4.06 i 1.33 7.92 14.37 3.97 8.40 1997 909 3.33 0.79 4 i 1.32 7.98 14.49 6.03 8.46 1998 917 3.36 0.79 45 1.09 1.30 8.04 14.58 6.09 0.49 1999 926 3.399 0.79 4.18 1.10 1.28 8.11 14.67 6.15 8.53 2000 936 3.43 0.80 4.22 iit 1.27 8.17 14.78 6.20 8.58 2001 947 3.47 0.88 4.27 1.13 1.26 8.24 14.90 6.26 8.64 2002 959 351 4.32 1.45 1.25 8.31 15.02 6.32 8.71 2003 m 3,55 4.37 4.17 1.24 8.38 15.16 6.38 8.78 2004 985 3.60 4.42 ay 1.24 8.39 15.24 6.38 6.87 2005 1008 3.66 4.49 1.21 1.23 8.41 15.34 6.38 8.97 2006 . 1016 4.72 4.55 1,24 1.23 1.22 8.42 15.45 6.38 9.07 2007 1035 3.79 4.63 1.27 1.23 1.24 8.44 15.57 6.38 9.20 1054 3.86 4.71 1.30 1.23 1.26 8.46 15.70 6.38 9.32 2009 1075 3,93 4.79 1.33 1.23 1.28 8.48 15.84 6.38 9.46 2010 1096 4.01 4.88 1,37 1.23 1.30 8.50 15.98 6.38 2011 117 4.09 4.96 1.39 1.25 1.32 8.52 16.12 6.38 2012 1138 4.17 5.05 1.41 1.27 1.33 8.53 16.26 6.38 2013 1160 4.25 5.14 1.43 1.29 1.35 8.55 16.41 6.38 2014 1182 4.33 3.23 1.45 1.31 1.37 8.57 16.56 6.38 3-13 7a 661 961 vot Woh 681 set cel 081 Bit a sat ‘wit eat zt zt wa zt Wat on vt at Gt 9S ist 1) iv Mol sv net uz beet w WiOl esc sss dv as EL aes 9d 4s sie ees oo as tev ws wy Ws ov zs vey ees ty ses ow as 86s es 68S ves os oes es bos 99S ss 19S 196 985 e9¢ «s 196 os ors tes ves ois ws tor 20S cer 905 Tt sos 1% sos wp 660 9b 6p i bdb 0» Sb Cee Sb See Ssh Ss? ve 180deNS | * 109 che wee we We ted iO 7a? wa 19 ese te se ay ey ay uw or so zo 065 sor zo 88S ars us bes szs ws ois cub cop 6eb vib JISvG = “SCTHSH “dd 5193433 *N3909 YOI “POY LGWOTE WLOL WLOL 0561 6261 6681 1281 eves siet det zat ect stat Sort vert ad Soot 4) civ sort best ecst est 62s Url 62h 86E1 cet eet wet 621 dszt wt oot oon i901 es bers aris boos 10s 6b6b 86> vip éblb bor SP 007 79s Szcp 68by OF) Sepp Oly ce veep ecb Ssib SIGE 192€ 269 SUPE 2986 78EE 6226 vie OS0E % ’ ot z s sz if 6 4 el ve » “ w a“ 81 a LUOddNS = JISVE “SOTHSH “dOd = °N390%3°N390%3 “N390%9 SMIONI90X9 = LNGWAD Td zi6t 7881 eset zat uh 692i 7a vat Vey 699i ont tev stv 66S! bast ust O9st vst zest cist vert Sool veel eset ocet 6621 eczt iszt 6Izt au vert oor 1901 +A] vI-€ CUCt 6S BE 62 6S BE (e265 BE Etc2 SBE Stl’? 6S" BE Qt BE ee S"8E wec't USB sec'z IS" @E deez OS BE Wee'2 9b BE bec’ (Ph BE dct Mh RE WSc°2 OS BE SSc°2 OP" BE OCc'2 2d" BE e9c'2 68" BE dct UN 6E it Ut bb bE tec" BLE 882°2 bt OF 66°26 OF 108'2 = 26°6E na zee LE" diez LE" OF 97e°2 9h Ob vea'z = 6S" Ob €ve'z. Sh OP wse'z bE 198°) 19" O 198° BPO si ot OSH voor Sot Pet dit 6881 vet eeel 9081 tect a) 8EcI Wet dot 969 sort 6a vent ay ov 6st coer bit ecst ist cist Sdbt dol tent Zon set S6zt 8221 bez G3d O3A0TGE W101 Se SQTHSH SNOSU3d ‘d0d % (2 30 1 1335) O1WAGIS HLAOUS M07 €-€°€ TOL borce berce o'ce vorce verce 89° PE GE'9E 16°SE es"se dV'Se 7B°bE én be i've te'ee bee 6c be'ze Sze ce°2E e2°2e ber le £6°0€ zegearze RSSS8282283882 ~ “NOISS3¥938 907-907 SNISN OILVWdOLG SI ND 1102 WOU 3Z71S CTOHISNOH #8 “WOEY) 30 1430 YISU TY ‘PEIAIAD NOLLVWdOd YHSYTY U3d SY bbZI 40 LNGHOTAG 7861 SQMVMES Od SMDILIICONd 3SV) 3INGNIIIG Ve SLIFCNS WIS] “HLINSCTOS “S “O HONS NOSNIMILNH 1116 OL £861 "91 W3EHILdIS 30 WRONVYOKON ONIININII39 # tye 42 We a oe ve? ow ov ee oy so 6s 8s ees 9s ass cs 90S ts ses ws sis 86h 8b 69 9b Op tb te die 66E Let Sce L80dans ore? er'dz o9°c2 er'd2 o9'd2 0°82 th" 8z be°ez te" 62 €L°62 a coe 90° E one 0'ze ihe £6°ze Spee We'ee te'ce ce"EE cree 6I'ee eres EEE C2"ve 68° ¥E 96" bE 6" bE 20°SE So'se ESE OS'9E sss as eS 4es ees ws Ws tes zs 4) ses as oes ves ES bos ess 196 9S 19s Ors ves as 70s 906 sos sos 66y Ob bab bor tsb SSb 6 “109 RST SKSIRAKELRES SSSSSSERRBBBERBBB Orbe 1e°se easssacs SSSASTSS % au io (9 ve 999 Me aw ay vey ay oor 78s us ws us os eG us an ess ces cys bis S6p t6y 06» eo tb 6e> oly 2188 #LNBHAD TANG OILSNOY Seis ous tres 696b 968) zap ecb 689 2% 69Sh Wor Slop cto OOpy woth Seep Oley Sez Over tezy Ozib or Svee O6cE tee wore Sace BESE SSvE PREE coe dvi OS0E asst est gest vert 9p Shot azo bibs cot toet weet 6cet det acer cet evel bret 6zet t6zt tect Poet cit oot veut zit au over oser cot as cis sy cub 1% Isp tb cep bt oy 1 bor 16 ae che ete Sze we vie 20e 692 ees ws ies is ws ez szs as «es oes ess 196 9s 196 ws 706 905 ses 665 Oy bly wor Sb SSb 6 C6 sé dv of ™ tsp Seb Lu St We aly vip a ab oy St Woe %6E sce ase Ove See we ale 162 WIOL =sOudnS “109 JISHE (8351) LNBHAD Ta TDIS3Y CaMRES bez Elo 7102 02 0102 6002 8002 2002 9002 Soo 002 002 7002 1002 0002 6665 8661 L661 9661 S661 beet 661 2661 1661 0661 6861 8861 1861 9865 $061 86! 861 7861 1 Wah cat as oe TABLE 3.3-3 LOW GROWTH SCENARIO (SHEET 2 OF 2) RESIDENTIAL OISCRETE DISCRETE YEAR ALL ALL NON-ALL RESIDENT COMMERCIAL GOVT. EXOGEN. EXOGEN. ENDOG. INDUSTRIAL TOTAL MARINE MARINE TOTAL PEAK ELECTRIC ELECTRIC ELECTRIC PEAK PEAK PEAK INDUST. INDUST. INDUST. - PEAK PEAK INDUST. INDUST. W/O PARK HSHLDS. PEAK PEAK LOADS PEAK PEAK PRK LOAD PRK PEAK (mu) (Mia) (ma) (Ma) (ma) (Ma) (Mu) (ma) (Ma) (Ma) (Ma) (Ma) (Ma) 2 28 a 30 4 22 33 cD] 35 % ” 38 wv 40 4a 1983 3 1.90 0.62 2.52 0.73 1.07 0.79 Sail 1984 342 1.98 0.65 2.64 0.76 1.07 0.38 1g 5.46 1985 36t 2.05 0.68 2.74 0.80 1.42 0.38 1.22 35.87 1986 393 2.17 0.73 2.90 0.84 1.16 3.22 0.92 4.23 2.94 69 1987 609 2.23 0.75 2.98 0.86 4.18 3.37 0.94 4.31 2.99 6.32 1988 609 2.23 0.77 3.00 0.87 ay 9.42 4.36 3.04 6.38 1989 409 2.23 0.81 3.04 0.69 119 3.47 4.45 3.10 6.47 1990 609 2.23 0.86 3.08 0.91 ay 3.60 4.64 3.22 6.60 1991 609 2.23 0.89 3 0.93 ay 3.65 1.02 4.67 3.28 6.63 1992 609 2.23 0.92 3.15 0.97 1.23 3.70 4.76 3.33 6.79 1993 609 2.23 1.00 3.23 1.00 1.27 3.75 4.84 3.38 6.96 1994 609 2.23 1.05 3.28 1.02 1.29 3.01 4.89 3.43 7.06 1995 609 2.23 1.09 3.32 1.04 4.32 3.86 4.93 3.48 743 1996 609 2.23 i 3.34 1.05 1.33 a9 4.99 3.54 7.48 1997 609 2.23 1.14 3.36 1.06 1.32 3.96 1.09 3.05 3.59 7.21 1998 609 2.23 1.15 3.38 1.07 1.30 4.01 1.09 Su 3.64 7.22 1999 609 2.23 1.17 3.39 1.08 1.28 4.07 1.10 5.17 3.69 7.24 2000 609 2.23 1.18 341 1.09 1.27 4.12 i 3.23 3.74 7.2% 2001 609 2.23 1.20 3.43 1a 1.26 4.17 1.12 5.29 3.80 2002 609 2.23 1.22 3.45 1.13 1.25 4.22 1.13 5.35 3.05 2003 609 2.23 1.24 3.47 145 1.24 4.27 1.44 5.42 3.90 2004 609 2.23 1.26 3.49 1.17 1,24 4.27 1.16 5.43 3.90 2005 609 2.23 1.29 3.52 1.20 1.23 4.27 1.17 3.45 3.90 2006 409 2.23 1.32 3.55 1.22 1.23 4.27 1.9 3.46 3.90 2007 609 2.23 1.35 3.58 1.25 1,23 4.27 1.21 5.48 3.90 2008 609 2.23 1.38 3.461 1.29 1.23 4.27 1.23 5.50 3.90 2009 609 2.23 1.42 3.65 1.32 1.23 4.27 1.24 5.52 3.90 2010 409 2.23 1.45 3.68 1.35 4.23 4.27 1.26 5.54 3.90 2 409 2.23 1.49 3.72 1.37 1.25 4.27 1.28 5.55 3.90 2012 609 2.23 1.53 3.75 1.39 1,27 4.27 1.30 3.97 3.90 2013 609 2.23 1.56 3.79 14 1.29 4.27 1.32 5.59 3.90 2014 609 2.23 1.60 3.83 1.43 1.31 4.27 1.33 5.61 3.90 3-15 Po at — ha Notes on Tables 3.3-1, 3.3-2 and 3.3-3 The values shown as examples below are taken from the high growth scenario. Where a different approach is taken on the moderate and or low growth scenario additional detail is provided. Column Report Section Sheet Number Data Source or Calculation Reference No. ls Seward Regional Employment and Population Scale (1) Year (2) Inst. of Soc. & Econ. Res. (ISER) forecast (3) Inst. of Soc. & Econ. Res. (ISER) forecast (4) Inst. of Soc. & Econ. Res. (ISER) forecast (5) Inst. of Soc. & Econ. Res. (ISER) forecast (6) 1982-2010: Inst. of Soc. & Econ. Res. (ISER) forecast 2011-2014: Continue same growth rate Seward Adjusted Employment Sided ee (7) 1982 / (2) + 53% of 222 added jobs 1983-2010: same growth rate as (2) 2011-2014: maintain same percent of total (8) (7) 7 (13) (9) Same as (3) (10) (9) 7 (13) (11) 1982: (4) + 47% of 222 added jobs 1983-2010: same growth rate as (4) 2011-2014: maintain same percent of total (12) (11) 7 (13) (13) (7) + (9) + (11) (14) (13) 7 (6) Households 3c3s cd (15) (APA, 1983) MAP Report (16) (6) 7 (15) 3-16 4787B tow Sheet 47878 Notes on Tables 3.3-1, 3.3-2 and 3.3-3 (continued) Column Report Section Number Data Source or Calculation Reference No. Exogenous Effects 3.3.1.4 (17) Table 3.4-1 3.4 (18) (17) x (11)/(9)72 3.3.1.4 (19) {(17) + (18)] 7 (14) (20) (19) 7 (15) (21) (6) + (19) (22) (16) + sum of (20) to date (23) (7) + sum of (17) to date (24) Same as (9) (25) (11) + sum of (18) to date (26) (23) + (24) + (25) Load Forecast (27) Year 3.3.2, 3.4 (28) 519 estimated for 1983. Increase in (22) for each year is added to (28) preceding year. In moderate growth scenario 75% of increase in (22) for each year is added to (28) preceding year. In low growth scenario 1983 split between all electric and non all electric is maintained through 1987. Thereafter there is no increase in all electric. (29) 1.90 MW/519 Customers times (28) (30) Remains constant at 0.62 MW in high growth scenario. In moderate growth scenario 25% of increase in (22) for each year is added to (30) for preceding year. In low growth scenario 1983 split between all electric and non all electric is preserved through 1987. Thereafter 100% increase in (22) is applied to (30). (31) Sum of (29) and (30) 3-17 Notes on Tables 3.3-1, 3.3-2 and 3.3-3 (continued) Column Report Section Sheet Number Data Source or Calculation Reference No. (32) 0.73 in 1983. Increases proportionately to increase in (25). (33) 1.07 in 1983. Increases proportionately to increase in (24). (34) See Table 3.4-1 for discrete exogenous industrial loads. Diversity factor of 75% is applied in low and moderate growth scenarios. (35) 0.50 in 1984. Multiply (35) for previous year by (23) for current year over (23) for previous year and add (34). (36) 0.79 in 1983. Increases proportionately to increase in (23). (37) Sum of (35) and (36). (38) Sum of (31), (32) and (33) and (37). (39) Marine Industrial Park component of (34). 75% diversity factor is applied in low and moderate scenarios. (40) Multiply (40) for previous year by (23) for current year over (23) for previous year and add (39). (41) Subtract (40) from (38). 3-18 4787B ier ZH <~ONM2™M THOUSANDS FIGURE 3.3-2 COMPARISON OF ENERGY GROWTH SCENARIOS 88 72 68 So 40 HIGH GROWTH SCENARIO MODERATE GROWTH SCENARIO LOW GROWTH SCENARIO a =| 1988 1985 1990 1995 2080 2005 2018 2015S YEAR 3-19 7 = YEAR ALL RESIDENTIAL ALL NON-ALL RESIDENT COMMERCIAL GOVT. EXOGEN. EXOGEN. ENDOGEN. TABLE 3.3-4 HIGH GROWTH SCENARIO ENERGY FORECAST (SHEET 1 OF 1) OISCRETE INDUSTRIAL ELECTRIC ELECTRIC ELECTRIC ENERGY ENERGY ENERGY INDUST. INDUST. INDUST. ENERGY HSHLDS. ENERGY ENERGY 1983 1984 1985 1986 1987 1988 1989 1998 1991 1992 1993 1994 1995 1996 1997 1998 1999 2008 200) 2002 2003 2004 2005 2006 2007 2008 2009 2018 2011 2012 2013 14 «idit) 2 a 308 6612.40 557 7250.38 629 8188.49 671 0739.80 704 9168.65 751 9770.52 778 10120.99 821 1081.19 044 10988.19 888 11556.77 950 12361 .46 988 12863.47 1017 13242.47 1037 13501.16 1054 13713.53 1065 13862.32 1077 14019.40 1089 14180.08 1105 14362,24 4121 14509.72 1137 14794,35 1155 15032.48 1175 15296.94 1197 15577.52 1223 15912.78 1247 16235.23 1273 16600.47 1303 16962.23 1331 17329.66 1360 17702.85 1389 10081 .88 1419 10466.06 (MY MH) (MAH) (dD 4 5 4 7 3346.70 9959.18 6359.00 9454.00 3344.70 10597.08 4635.35 9495.83 3346.70 11535.39 7111.52 9914.15 3346.70 12086.50 7349.65 10248.81 3346.70 12515.35 7502.03 10437.05 3346.70 13117.22 7762.99 10562.54 3346.70 13467.69 7905.00 1052.54 3346.70 14027.89 8187.45 10583.46 3344.70 14334.89 8326.30 10499.00 3346.70 14903.47 6736.52 10918.12 3346.70 15708.36 9014.76 11210.94 9346.70 16210.17 9171.27 11461.93 3346.70 16589.37 9338.94 11733.84 3346.70 16847.86 9434.89 11775.47 3346.70 17060.23 9522.66 11733.84 3346.70 17209.02 9598.45 11545.59 3346.70 17366.10 9707.29 11378.27 3346.70 17526.78 9810.11 11273.49 3346.70 17728.94 9974.83 1169.11 3346.70 17936.42 10131.31 11085.44 3344.70 18141.05 10309.44 11022.49 3344.70 18379.38 10499.23 1090.86 3344.70 10645.64 10718.06 10939.03 3346.70 18924.22 10951.13 10918.12 3346.70 19259.48 11213.24 10897.20 3346.70 19581.93 11488.07 10897.20 3346.70 19947.17 11765.17 10918.12 3346.70 20308.93 12051.27 10939.03 3346.70 20676.36 12222.95 11102.30 3346.70 21049.55 12397.19 11268.01 3346.70 21428.58 12574.04 11434.19 3346.70 21813.56 12753.52 11606.87 (Ma) = (MH) 1300.08 1300.00 6965.00 8396.13 231.94 6914.73 231.94 9357.37 5354.94 15118.26 231.94 15082.74 1048.94 17982.92 231.94 17974.80 1981.94 20631 .99 231.94 21532.38 231.94 21859.08 231.94 21082.21 231.94 22221 .05 231.94 22590.31 234.94 22932.87 231.94 23300.08 231.94 23704.57 231.94 24150.57 231.94 24580.49 231.94 25061 .37 25339.54 25685.04 2601167 26405.47 26778.99 2710.11 27511.23 27880 .31 28254.90 28635.08 29020.94 3-20 ENERGY ENERGY = ENERGY (MH) = (Mt) 10 Ty 4319.00 4319.00 4443.68 5743.68 4891.90 13288.02 058,92 13973.65 5178.49 14535.85 5403.15 20521.41 5593.47 21476.22 5963.69 23946.61 5864.08 2385.87 6170.59 27002.58 6309.35 2741.73 6337.12 28196.20 6276.58 28158.79 6307.25 28528.30 6346.22 26936.54 6377.30 29310.17 6414.92 29715.00 6462.42 30166.99 4520.78 30671.35 6574.23 31154.73 6640.82 31702.19 6714.52 32054.06 6806.29 3249213 6892.63 32904.30 6997.03 33402.70 7095.95 33874.94 7183.70 34293.81 7209.98 34801.21 7387.78 35268.09 m4 35741.94 7587.78 36222.87 7490.03 34710.97 DISCRETE TOTAL «= MARINE «MARINE = TOTAL ENERGY ENERGY (MH) 12 30091 .10 3247194 41049.08 43678.60 44990.28 51964.16 53411.45 56745.41 57019.86 61560.69 63775.79 65039.57 65820.93 66586.71 467253.26 67663.42 681466.66 68777.56 69544.22 70307.90 71175.37 71913.52 72795.66 73697.26 7472.61 75842.14 76924.25 78100.44 79269.70 00456.49 81661 .67 82684.92 IMOUST. —INDUST. ENERGY = — ENERGY (MaH) = (MH) MD W/0 PARK 13 14 1S 3009110 32471.94 4565.00 4545.00 37284.08 231.94 4952.80 38725.80 231.94 5301.80 39688.48 4894.94 10426.75 41537.41 231.94 11025.97 42385.48 231.94 11987.0¥ 44757.72 231.94 12059.60 44940.26 231.94 12878.76 48681.93 231.94 13400.31 50375.48 231.94 13691.22 51348.35 231.94 13792.37 $2028.56 231.94 14091.70 52495.01 231.94 14410.72 52842.54 231.94 14713.22 $2950.20 231.94 15031.95 53134.71 231.94 15375.21 53402.36 231.94 15745.99 53798.23 231.94 16107.02 54200.89 231.94 16502.08 54673.29 16685.24 55228.28 16913.27 $5862.38 17127.82 56569.94 17387.25 57385.36 17633.07 58209.07 $7851.11 59073.15 18115.23 59985.21 18358.26 cO?11.44 18604.91 61851.78 18855.25 62806.42 19109.32 6375.68 ed 7 YEAR ALL RESIDENTIAL aL TABLE 3.3-5 HODERATE GROWTH SCENARIO ENERGY FORECAST (SHEET 1 OF 1) DISCRETE WON-ALL RESIDENT COMMERCIAL GOVT. EXOGEN. EXOGEN. ENDOGEN, INDUSTRIAL S ELECTRIC ELECTRIC ELECTRIC ENERGY ENERGY ENERGY INDUST. INDUST. INDUST. ENERGY WSHLDS. ENERGY ENERGY 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1994 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2018 201 2012 2013 m4 (a) 2 3 508 345 599 on 655 46 696 6612.40 7090.88 7794.62 6207.95 8529.59 8794.92 9057.44 733 -9539.03 7S) 9769.06 774 1007.01 820 10674.23 049 11050.04 O71 11334.00 086 11527.41 898 11686.23 906 11797.46 915 11914.82 925 12035.05 9346 12186.30 948 12341.54 960 12494.74 974 12673.28 989 12872.53 1005 13081.28 1024 13332.44 1043 13574.09 1064 13847.74 1085 14118.87 1106 14394.26 1127 14673.96 1149 14958.05 1174 15246.59 4239.61 15925.84 (ai) (I) CMa) 4 5 é ? 3346.70 9959.18 3490.90 10521.79 3554.75 11349.37 427.49 11835.44 3404.09 2213.48 3730.79 12525.71 3776.99 12834.43 3061.74 13400.77 3902.22 13671.28 3955.36 14026.37 4041.51 14735.74 4127.65 5177.70 4177.42 15511.62 4211.66 15739.07 6359.00 9454.00 6635.35 9495.83 MNNS2 9904.15 7369.65 10248.8) 7502.03 10437.05 7653.25 10562.54 7795.26 10562.54 0114.29 10583.46 8253.14 10499.60 8590.21 10918.12 0848.44 11210.94 9024.95 11461.93 9192.62 1733.84 9288.57 1775.67 9376.34 11733.04 9452.33 11733.84 9560.97 11563.78 9663.00 11457.50 4259.18 14056.64 4279.04 14194.45 4300.99 16336.04 4327.61 14513.99 9626.52 11351.21 4354.93 16696.47 9904.99 11266.18 4381.89 16876.63 10143.12 11202.41 4413.30 17086.50 10352.91 11159.90 4448.38 17320.91 10572.54 1117.38 4405.11 17566.39 10804.81 11096.13 4529.31 17861.75 11066.92 11074.87 4571.04 18145.93 11341.76 11074.87 4620.00 18467.74 11618.85 11096.13 4667.71 18786.58 11904.95 11117.38 4716.18 19110.43 12076.63 11283,32 4765.40 19439.36 12250.87 11451.72 4815.39 19773.44 12427.72 11622.64 4066.17 20112.76 12607.28 11796.12 (Mia) (a) 1300.08 5927.00 251.39 251.39 1306.00 7227.00 7478.39 7729.78 ‘314.39 6244.17 251.39 8495.56 4651.39 13146.95 251.39 13398.33 251.39 13649.72 251.39 13901.11 251.39 1452.50 251.39 14403.69 251.39 14655.28 251.39 14906.67 251.39 15158.06 251.39 15409.45 251.39 15660.84 251.39 15912.22 251.39 16163.41 251.39 16415.00 16415 16415 16415. 16415.00 16415.00 16415.00 16415.00 3-21 (ai) (aH) 4319.00 4319.00 4443.68 5743.68 4891.90 1218.98 9058.92 12537.31 5178.49 12908.26 5255.67 13499.04 3446.00 13941.55 5865.37 19012.32 ‘5785.76 19184.09 5973.96 19623.48 6112.72 20013.83 6140.48 20292.98 6079.95 20483.84 6110.41 20765.69 6149.59 21056.25 6100.66 21338.72 6218.28 21627.72 6265.78 21926.42 6324.14 22236.37 6377.68 2254.21 4444.18 22859.18 6517.89 22932.89 6609.65 23024.45 6695.99 23110.99 6800.39 23215.40 6899.32 23314.32 6987.06 23402.06 7093.35 23508.35 7191.15 23606.15 7290.41 23705.41 7391.15 23806.15 7493.39 23908.40 TOTAL ENERGY 30091, 32396. 40493, 419m. 43061. 44241. 42133. ‘Suite. 51608, 53158. 54828. 55957. 54921. ‘57549. 58092. 58581 .| 5e947. DISCRETE WARINE MARINE TOTAL ENERGY INDUST. INOUST. W/O PARK ENERGY ENERGY (ua) = (Midi) CIMA) 12 13 14 1S 10 30091 .10 46 3239666 93 3777.00 3777.00 36714.93 20 251.39 4028.39 37962.01 02 251.39 4279.70 38781.24 34 514.39 4794.17 39447.17 79 251.39 5045.56 40088.23 04 4651.39 9496.95 41413.90 32 251.39 9948.33 41459.98 37 251.39 1019.72 42950.64 95 251.39 10451.11 4377.84 56 251.39 1072.50 45255.06 91 251.39 10953.89 45968,02 19 251.39 11205.28 46363.91 27 251.39 11456.67 4635.61 52 251.39 1170806 46873.47 13 251.39 11959.45 44987.68 59383.95 251.39 1210.84 47173.12 59930.00 251.39 12447.22 47467.78 60488.86 = 251.39 12713.61 47775.25 61101.34 251.39 12965.00 48136.34 61532.20 12965.00 485467.20 62035.48 12965.00 49070.48 62578.32 12965.00 49613.32 63218.94 12965.00 50253.94 63876.08 12945.00 50911.68 64584,77 12965.00 51419.77 65317.27 12965.00 52352.27 66076.53 12965.00 53111.53 66847.37 12965.00 53882.36 6762995 12965.00 54664.95 68424.48 12965.00 55459.47 TABLE 3.3-6 LOW GROWTH SCENARIO ENERGY FORECAST (SHEET 1 OF 1) RESIDENTIAL DISCRETE DISCRETE YEAR ALL ALL NON-ALL RESIDENT COMMERCIAL GOVT. EXOGEN. EXOGEN. ENDOGEN. INDUSTRIAL TOTAL «MARINE §=MARINE TOTAL ENERGY ELECTRIC ELECTRIC ELECTRIC ENERGY ENERGY ENERGY INDUST. INDUST. INDUST. ENERGY ENERGY —INDUST., INDUST. W/O PARK HSHLDS. ENERGY ENERGY ENERGY == ENERGY = ENERGY ENERGY = ENERGY (Mu) (MH) (MH) (MH) (MH) (MH) (MH) (MH) MH) (MH) = (MH) (MH) (Mu) 1 2 3 4 5 4 ? 8 9 10 i 12 13 14 15 1983 508 4612.40 3346.70 9959.10 6359.00 9454.00 4319.00 4319.00 30091 .10 3009110 1984 531 6907.04 3527.97 10495.00 6635.35 9495.83 4443.68 5743.68 32309.87 32309 .87 1985 549 7151.55 3478.39 10829.95 4928.62 9914.15 1300.00 4646.10 5946.10 33618.82 33618.82 1986 581 7556.52 3927.53 11484.05 7333.07 10248.) 4639.00 5009.76 9448.76 38714.69 3339.00 3339.00 35375.49 1987 596 7754.47 4049.31 11803.78 7465.45 10437,05 4858.12 5129.33 9987.45 39693.73 219.12 3558.12 36135.61 1968 596 7754.47 4192.29 11946.76 7580.09 10562.54 5077.24 $157.35 10234.59 40323.99 219.12 3777.24 36546.75 1989 596 7754.47 4376.93 12131.40 7722.10 10562.54 5296.36 5347.68 10644.04 4060.09 219.12 3996.36 37063.73 1990 596 7754.47 4628.70 12383.17 7967.98 10583.46 5778.48 5668.74 11447.22 42301.82 402.12 4478.48 37903.34 1991 596 7754.47 4790.31 12544.78 8106.83 10499.80 5997.60 5589.12 11586.72 42738.12 219.12 4697.60 38040.52 1992 596 7754.47 £302.36 12756.82 0443.69 10918.12 6216.72 5777.32 11994.04 44112.87 219.12 4916.72 39196.15 1993 596 7754.47 5426.67 13181.14 8722.12 11210.94 6435.84 5916.08 12351.92 45466.11 219.12 5135.84 40330.27 1994 596 7754.47 5690.83 13445.30 8878.64 11461.99 6654.96 5943.85 12598.81 46384.68 = 219.12 5354.96 41029.72 1995 596 7754.47 5890.40 13644.87 9046.30 11733.84 6874.08 5883.31 12757.39 47182.39 219.12 5574.08 41608.31 1996 596 7754.47 6026.23 13780.70 9142.25 11775.67 7093.20 5913.97 13007.17 47705.79 = 219.12 5793.20 41912.59 1997 596 7754.47 6137.71 13892.18 9230.02 11733.64 7312.32 5952.95 13265.27 4121.31 219.12 6012.32 42108.99 1998 596 7754.47 6215.75 13970.22 9306.01 11545.59 7531.44 5984.03 13515.47 48337.28 219.12 6231.44 42105.04 1999 396 7754.47 6298.04 14052.51 9414.65 11378.27 7750.56 6021.64 13772.20 48617.63 219.12 6450.56 42167.07 2000 596 7754.47 6382.48 14136.95 9517.48 11273.49 7969.68 4069.15 14038.83 48966.94 © 219.12 6669.48 42297.26 2001 596 7754.47 6488.69 14243.16 9682.20 1169.11 219.12 8188.80 4127.51 14316.31 49410.77 219.12 6888.80 42521.97 596 7754.47 6597.71 14352.18 9038.67 11085.44 219.12 8407.92 6180.96 14588.88 49065.18 219.12 7107.92 42757.26 2003 596 7754.47 6705.35 14459.82 10016.80 1022.49 219.12 8627.04 6247.54 14874.58 50373.90 219.12 7327.04 43046.86 2004 396 7754.47 6830.79 14585.25 10204.59 10980.86 0627.04 6321.25 14948.29 30721.00 7327.04 43393.96 2005 596 7754.47 4970.83 14725.30 10426.22 10939.03 0627.04 6413.02 15040.06 31130.61 7327.04 43803.57 2006 596 7754.47 7117.65 14872.12 10658.49 10918,12 8627.04 6499.36 15126.40 51575.12 7327.04 44248.08 2007 596 7754.47 7294.25 15048.72 10920.60 10897. 20 9627.04 6603.76 15230.80 2097.32 7327.04 44770.28 2008 596 7754.47 7464.23 15218.70 11195.44 10897.20 0627.04 4702.68 15329.72 52641.05 7327.04 45314.01 2009 596 7754.47 7656.66 15401.13 11472.53 10918.12 8627.04 4790.42 15417.46 53219.23 7327.04 45892.19 2010 596 7754.47 7847.39 15401.86 11758.63 10939.03 8627.04 6896.71 15523.75 53823.27 7327.04 46496.23 2011 596 7754.47 8041.11 15795.58 11930.31 11102.30 8627.04 4994.51 15621.55 54449.74 7327.04 47122.70 2012 396 7754.47 8237.87 15992.33 12104.56 11268.01 8627.04 7093.77 15720.81 95085.71 7327.04 47750.67 2013 396 7754.47 8437.71 16192.18 12281.40 11436.19 8627.04 7194.51 15621.55 55731.32 7327.04 48404.28 2014 596 7754.47 8640.49 16395.16 12460.88 11606.87 8627.04 7296.76 15923.80 36386.72 7327.04 49059.68 3-22 - ™ a ry Notes on Tables 3.3-4, 3.3-5 and 3.3-6 The values shown as examples below are taken from the high growth scenario. Where a different approach is taken on the moderate and or low growth scenario additional detail is provided. Column Report Section Sheet Number Data Source or Calculation Reference No. Vs Energy Forecast 3.3.3, 3.4 (1) Year. (2) 508 all electric households for 1983. Note that number is higher for peak reflecting more persons in residence during winter than the average for the year. Increase is the same as (23) for peak. For low and moderate scenarios the increase in all electric households is as outlined for peak load. (3) 6,612.4 MWH/519 Customers times (2) (4) Remains constant at 3,346.7 MWH. In moderate scenario 25% of new households are non all electric and the increase is 3,346.7 MWH/1086 households per new household. (5) Sum of (2) and (3) (6) 6,359.0 in 1984. Increases proportionately to increase in (26) in peak table. (7) 9,454.0 in 1983. Increases proportionately to increase in (25) in peak table. (8) See Table 3.8 for discrete exogenous industrial energy. (9) 1,300 in 1983. Multiply (9) for previous year by (25) from peak table for current year over (25) for previous year and add (8). 3-23 47878 = 7 4787B Notes on Tables 3.3-4, 3.3-5 and 3.3-6 (continued) Column Number (10) qq) (12) (13) (14) (15) Data Source or Calculation 4,319 in 1983. Increases proportionately to increase in (24). Sum of (9) and (10). Sum of (5), (6), (7) and (11). Marine Industrial Park component of (8). Multiply (14) for previous year by (25) from peak table for current year over (25) for previous year and add (13). Subtract (14) from (12). 3-24 Report Section Reference No. rm ow 3.3.1.1 ISER Forecast The forecasts provided for this project by the Institute of Social and Economic Research (ISER) included employment in the basic, government, and support sectors, and total area employment. The Seward area forecasts were made for the Seward Census Division, as defined for the 1970 Census. The ISER forecasts are shown in columns 1 through 6 of Tables 3.3-1, 3.3-2, and 3.3-3. The employment sectoral definitions are as follows: Basic = mining, manufacturing, construction, agriculture, forestry, fisheries, exogenous transportation, proprietors, and tourism Government = federal civilian, federal military, state, and local Support = all other For several basic industries, ISER allocated the Seward area share of Railbelt basic employment. Forestry and lumber products employment, Miscellaneous mining employment, and traditional commercial fishing and fish processing employment were all derived from the Railbelt forecasts for the Susitna reference case. Portions of statewide endogenous construction, proprietor, and tourism employment were also allocated to the Seward basic sector according to formulae developed by ISER. Government employment is also consistent with the reference case used for the Susitna Hydroelectric Project license application. Federal civilian and federal military employment are derived from the reference case. State and local government employment are derived from the state total. Employment in the support sector is a function of basic and government employment. In includes typical local services such as finance, real estate, and retail trade. 3-25 4787B al a jw ISER also provided forecasts of population and households for the Seward area. These factors were forecasted largely as a function of projected industrial activity in the Railbelt and Seward's likely share of that activity. Trends in the ratio of population-to-employment and households-to-population were also taken into account in these forecasts. 3.3.1.2 Adjusted ISER Forecast Employment data from the Alaska Department of Labor indicate the following Seward area employment for recent years: 1974 936 1975 1,152 1976 1,137 1977 1,138 1978 1,227 1979 1,359 1980 1,410 198] N/A 1982 1,244 Actual 1982 employment was 1,244, compared to ISER's forecast of 1,022 for the same year (Tables 3.3-1, 3.3-2, and 3.3-3, column 5). ISER's regionalization model underallocates employment to the Seward area by that amount. The source of the error is, at least in part, an underallocation of fishing employment to Seward. An adjustment is made to the ISER forecasts to correct for the underallocation. The adjusted forecasts appear in columns 7 through 13 of Tables 3.3-1, 3.3-2, and 3.3-3. The population projection and government employment forecast derived by ISER are assumed to be accurate. The additional 222 jobs in 1982 were distributed between basic and support sectors in the same proportion that the two sectors originally held. Thus 117 jobs, or 53% of the additional jobs, were added to the basic sector. The support sector was increased by 106 jobs, 47% of the additional jobs. 3-26 4787B Le Given the adjusted starting point in 1982, employment by sector was projected to increase at the same rate assumed in the ISER forecast. Employment was also extrapolated for the years 2011 through 2014 using rates of change forecasted for the period 2000-2010. 3.3.1.3 Persons per Household and Number of Households The number of persons per household and the number of households in the Seward area are shown in columns 15 and 16 of Tables 3.3-1, 3.3-2, and 3.3-3. The number of households, provided from the MAP Report (APA 1983), was divided into population to estimate the number of persons per household, a value needed in order to make adjustments to the ISER forecasts described below. 3.3.1.4 Adjustments for Exogenous Industrial Growth The adjusted estimates of employment by sector plus the estimated number of households are used as a base for all three forecast scenarios. However, additional adjustments in the ISER forecasts were made on the moderate scenario in order to take into account industrial developments planned for the Seward area but not explicitly recognized in the ISER forecasts. Additional potential industrial development was assumed to occur in the high scenario, and appropriate adjustments in the ISER forecasts were also made. Seward enjoys several characteristics important to industrial development that suggest the appropriateness of giving full consideraton to the high scenario. Seward has a deepwater port, and is uniquely situated at the southern end of the Alaska Railroad. The citizens and government of Seward have a growth orientation, and would like to take advantage of the site's proximity to the lower 48 states. These factors potentially give the area a competitive advantage over other regions, despite Seward's lack of a large, resident labor force and its small geographic area in which to grow. 3-27 47878 In order to predict the size of probable and potential additional industrial growth, information concerning planned industrial development was compiled. Individuals involved in the development of Seward's Fourth of July Industrial Park were contacted to obtain updated information on planned development. Community business leaders and officials involved in planning the area's commercial and industrial development were also contacted. From these contacts, a list of specific, planned industrial projects was developed. For the high, moderate, and low scenarios, different assumptions were made concerning which projects would actually be built. The assumptions made for each scenario are discussed in Section 3.4. This section is limited to an explanation of how the additional exogenous industrial growth was used to adjust the forecasts of population, employment, and number of households for each scenario. For the high growth scenario, this employment impact is shown in Table 3.3-1, column 17. Expansion of employment in the basic sector gives rise, through a multiplier effect, to a derived expansion in the support sector, herein referred to as exogenous support to reflect its relationship to exogenous industrial development assumptions. These effects are shown on Table 3.3-1, column 18. Exogenous population growth is a function of exogenous employment growth. On Table 3.3-1, exogenous population is shown in column 19. The exogenous population is then used to estimate exogenous household formation, shown in column 20. These estimates of exogenous employment, population, and households are then added to the earlier adjusted totals to provide final estimates for each scenario beginning with the first year that exogenous employment occurs. The resulting economic and demographic estimates are shown in columns 21 through 26 Government employment (col. 24) remains unadjusted. Total employment (col. 26) equals the sum of basic, government, and support employment. 3-28 4787B ia The adjusted forecasts of number of households and employment by sector are used as the basis for making the load and energy forecasts. 3.3.2 Electric Power Demand Forecasts Electric power demand forecasts were generated by combining economic and demographic forecasts with end use forecasts by sector. The process of estimating end use demand characteristics involved first estimating the current peak use for the system, then disaggregating that peak demand into demand sectors: industrial, commercial, government and residential. End use trends were projected and specific new industrial loads were assumed to occur, reflecting exogenous industrial development described above. To estimate future demand it was first necessary to develop as accurate an assessment as possible of current peaks and energy use by sector in the City of Seward Electric Department. This was accomplished by first analyzing 15 minute load strip charts provided by the City. The actual fiscal year 1983 peak was found to have occurred on January 11, 1983. By applying the calibration factor of 0.4988 (Landman 1983), peak demand for that date was estimated as 4.64 MW. This was confirmed by the Chuagach billing records which indicate a peak of 5.688 MVA or 4.64 MW based on a power factor of approximately 0.81. A power factor of 0.8123 was computed by Mr. Landman of Acres Hanscomb on September 27, 1983 based on his actual observation. The observed peak required further adjustment to obtain a maximum probable peak load for fiscal year 1983. The rationale for this adjustment is that 1983 was a particularily warm year and temperatures for January 1983 were several degrees above average. To make the adjustment several 1983 week day peaks were correlated with temperature and a regression equation was developed. Extrapolation of the equation to record cold conditions resulted in a system peak approximately 10 percent higher than that observed on January 11, 1983. Therefore 5.11 MW was selected as the fiscal year 1983 peak. 3-29 4787B re Having estimated the system peak, the next step entailed disaggregating the peak loads according to the economic sectors used in the forecasting model: commercial, government, industrial and residential, and further dividing the residential sector into all-electric residential and non-all-electric residential. Actual peak metering by sector is not done in Seward. However, it was possible to make a reasonable estimate of each sector from other information provided by City. The disaggregation of peak loads was accomplished by analyzing the relationship between energy and peak. The energy for a given day may be calculated by integrating over time the peaks in megawatts that occurred on a given day. Similarily, by knowing the approximate peak or load shape curve for a given sector and the total energy consumption by that sector, it is possible through successive approximations to derive reasonable estimates for the peaks in each sector. The approach for making those estimates is as follows. First, information on energy consumption in each sector for January 1983 was obtained from the City's billing department. Dividing those values by 31 yielded average daily energy consumption values. Next, by systematically observing peaks throughout the month of January, a typical January 1983 day was identified. The energy consumed on that day was estimated by numerically integrating the 15 minute load curve at one to two hour increments and comparing it to the January average. The day selected was Monday, January 24, 1983 which had a peak of 4.14 MW and an energy consumption of 84.73 MWH resulting in a load factor of 0.85. The average daily peak for January 1983 was 4.14 MW and the average energy was 90 MWH resulting in differences of 0% and 6%, respectively, from the load and energy figures for the typical January day. This results in a load factor of 0.905. The energy consumption by sector, including number of customers for January, are shown in Table 3.3-7. 3-30 47878 TABLE 3.3-7 JANUARY 1983 ENERGY CONSUMPTION BY SECTOR Category Megawatt Hours No. of Customers Percent of Total Energy Domestic 954.2 1005 34.0% Commercial 521.2 176 18.5% Government 766.1 141 27.3% Industrial 567.1 231 20.2% TOTAL 2808.6 1553 100.0% Source: (Pearson 1983) In allocating loads to individual sectors, the smal] boat harbor and boat harbor power categories were allocated to the industrial sector. Based on conversations with the city engineer, the major use of power in the harbor is for pumping, a typical industrial use. This classification will also allow better representation of the fishing industry's need for shore power, moorage lighting, and other requirements. Available information did not distinquish between current all electric and non-all electric residential consumption. In 1980, however, that information was available due to different rate schedules for the two categories. By comparing annual and January energy consumption for fiscal years 1981 and 1983 it was estimated that in fiscal year 1983 there were an average of 508 annual all electric customers, and during the month of January 1983, there were 519 all electric customers. By comparing earlier records of all electric versus non-all electric use and adjusting for changes in billing practices, it was estimated that all electric energy consumption for January 1983 was 2.5 times non-all electric residential consumption. These results are shown in Table 3.3-8. 3-31 4787B in is TABLE 3.3-8 JANUARY 1983 ENERGY CONSUMPTION BY RESIDENTIAL SECTOR Category Megawatt Hours No. of Customers Percent of Total Energy All Electric 691.5 519 24.6% Domestic 262.7 486 9.4% Total 954.2 1005 34.0% A residential load curve which considered the effects of the short days and higher heating requirements in Alaska during January was estimated. Through successive approximations curves for both all electric and non-all electric homes were developed which were consistent with the energy values given in Tables 3.3-7 and 3.3-8. A potential load-time curve for a typical January day is shown in Figure 3.3-3. The total approximates actual observation for January 24, 1983. The various sectors were computed as discussed above. The peak January day was then calculated by increasing the typical peak by 12 percent. To convert the peak occurring on the peak day to a maximum probable peak for unusually cold conditions, the increase in system peak was allocated 70 percent to all electric residential and 30 percent to other non residential sectors. The result was a “worst case" January 1983 average peak of 1.9 kW per all electric household. To verify the approach the City's Agent for this study was: contacted and he indicated the average all electric peak should lie between 3 and 5 kW per household (Landman 1983). Total peak demand for the 519 all electric residential customers was estimated to be 3.84 MW. The 1983 peaks by sector are summarized in Table 3.3-9. 3-32 4787B fz ZH UPrOr N FIGURE 3.3-3 TYPICAL JANUARY LOAD SHAPE CURVE BY SECTORS ALL ELECTRIC RESIDENTIAL COMMERCIAL INDUSTRIAL GOVERNMENT DOMESTIC 4 6 8 19 12 14 16 18 20 HOUR OF DAY 3-33 22 24 = bo TABLE 3.3-9 FISCAL 1983 PEAK DEMANDS BY SECTOR Category Maximum Probable Peak (MW) All Electric Residential 1.90 Non-All Electric Residential 0.62 Commercial 0.73 Government 1.07 Industrial 0.79 TOTAL 5.01 These peaks formed the baseline condition for future peaks by sector in the Seward system. 3.3.2.2 Application of Economic and Demographic Effects The economic and and demographic forecasts described in Section 3.3.1 were applied to the fiscal year 1983 peaks in the following manner. In the residential sector the all electric peak was calculated by multiplying the estimated number of all electric households by the 1983 peak demand per household. Non-all electric residential peak was forecasted in a parallel fashion. Assumptions relating to the distribution of future households between these groups is provided in Section 3.4. Commercial peak demand is determined by the increase in support sector employment. The peak in a given year is directly proportional to 1983 peak and employment. Government and endogenous industrial peaks are adjusted in a similar manner based on employment in their respective sections. The treatment of exogenous industrial load is discussed in section 3.4. The total peak is the sum of the peaks in the various sectors. The total peak was broken out into the new marine industrial park and the remainder of the city in order to size the various conductors and transformers needed in the transmission system. 3-34 47878 3.3.3 Electric Energy Forecasts The procedure for developing electric energy forecasts has several similarities to the procedure used in developing the peak forecasts. Again it was necessary to define baseline conditions for fiscal 1983. This was considerably simpler since actual records on 1983 consumption were made available by the City of Seward. The only significant adjustment required was to convert energy consumption for fiscal year 1983, which was a warm year, into the energy consumption that would have occurred had fiscal year 1983 been an average year with respect to heating degree days. To convert 1983 to an average year a regression equation was developed which related annual energy consumption per all electric household to the year and the heating degree days. All electric residential energy demand was thereby estimated at 6,612.3 MWH for a “normal" fiscal 1983. No adjustment was made to the other sectors since they are not as temperature sensitive. The resulting breakdown by sector is shown in Table 3.3-10. TABLE 3.3-10 FISCAL 1983 ENERGY CONSUMPTION BY SECTOR Category Energy Consumption (MWH) All Electric Residential 6612.4 Non-All Electric Residential 3346.7 Commercial 6359.0 Government 9454.0 Industrial 4319.0 TOTAL 30091.1 Source: (Pearson 1983) Residential consumption computed by Ebasco. 3-35 4787B = aa Future energy demands were projected based on growth in households in the all electric residential and non-all electric residential sector. Increases in the commercial, government, and industrial sectors were computed based on growth in support, government, and basic employment respectively. Specific assumptions for the high, moderate, and low growth scenarios are presented in Section 3.4. A review of other energy forecasts for the Railbelt region was made (Alaska Power Authority, 1983). It was found that in the residential sector large appliance energy consumption is expected to decrease over time. However, this savings is totally offset by an increase in small appliance consumption. Therefore no adjustment was made to residential energy consumption over time. Adjustments were not made in the area of heating fuel mode due to lack of natural gas as an alternative fuel. However, the low growth scenario includes a major fuel switch from electricity to oil. 3.4 FORECAST ASSUMPTIONS The load and energy forecasts for each scenario depend on different assumptions about the size and nature of changes in exogenous industrial growth. Table 3.4-1 summarizes the exogenous industrial growth assumptions made for each scenario. Projects, online dates, loads, and energy needs were determined in a series of consultations with community business leaders, industrial developers, and officials involved in planning the Seward area's commercial and industrial development. Additional assumptions made for each scenario are outlined below. 3-36 4787B = 3.4.1 High Growth Scenario The high growth scenario produces the highest forecasts of loads and energy use. Specific assumptions include: ™ 100% of new households will be all electric. This creates a greater residential demand for electricity than that assumed jin the other scenarios. Exogenous industrial growth is higher than in the moderate and low scenarios, as detailed on Table 3.4-1. Some facilities, such as the Avtec school building addition and Veco, are assumed to create greater loads or use more energy than in the other scenarios. Seward fisheries expansion, lumber mil] expansion, and the grain terminal development are assumed to take place only in the high growth scenario. The exogenous industrial diversity factor is 92%. This assumes all loads occur simultaneously except that the grain terminal is operating in an off season load pattern with a 0.2 MW peak rather than 1.2 MW during harvest season. 3.4.2 Moderate Growth Scenario I. The moderate growth scenario produces what should be considered the “most likely" forecasts of load and energy use. Specific assumptions - include: ba 4787B 75% of all new households will be all electric. Exogenous industrial growth is moderate, as shown in Table 3.4-1 Some developments assumed in the high growth scenario do not take place; others have lower demands for energy or are later in time. On the other hand, several 3-37 & t . HIGH GROWTH SCENARIO 17h ONLINE LOAD ENERGY YEAR = (Mid) (MH) AUTEC CENTER (10) © 1984 3 1300 ANTEC SCHOOL BLDG. ADDITION (5) 1985 2 300 HISC. 4TH OF JULY INDUSTRY (8) #8 = 1985 6 2100 VECO (10) #0 1985S 2190 LOUISIANA PACIFIC LUMBER MILL REOPEN 1985 3 1900 SHIPLIFT FACILITY (2) #8 1985 4 100 CATHODIC PROTECTION FOR SHIPLIFT #8 1965 02 175 4TH OF JULY BOAT HARBOR (5) ## 1988 A] 263 COAL PORT FACILITY (15) #8 19882 4400 SEWARD FISHERIES EXPANSION 1988 3 460 LUMBER MILL EXPANSION 1996 5 817 GRAIN TERMINAL (10) 1992 1.2 1730 TOTAL NEW INDUSTRIAL LOADS 12.65 TOTAL NEW INDUSTRIAL LOADS ON PEAK 11.65 TOTAL MARINE INDUSTRIAL PARK LOADS 9.5 # EXOGENOUS ENPLOYMENT #4 MARINE INDUSTRIAL PARK FACILITIES SEWARD TRANSMISSION LINE: TABLE 3.4-1 GROWTH SCENARIOS FOR SEMARD INDUSTRY EDIUM GROMTH SCENARIO COMMENTS YEAR 1984 1985 INCREASE UNIFORMLY TO 1.8 Md IN YEAR 1985 2003. 2003 ENERGY 1S 4700 MuH. 1985 1985 1985 INCREASE UNIFORMLY TO .2 Md IN YEAR 1985 2003. 2003 ENERGY 1S 1750 Mut. APPLY ONLY 0.2 Md TO WINTER PEAK EFFECTIVELY A 92% DIVERSITY FACTOR. 4 02 9.6 7.2 ONLINE LOAD ENERGY (mu) (aH) 1782 1900 106 175 263 4400 3-38 LOM GROWTH SCENARIO COMMENTS ONLINE LOAD =— ENERGY YEAR = (Md) (MuH) 1984 3 1300 INCREASE UNIFORMLY TO 1.8 Md IN YEAR 1986 2003. 2003 ENERGY 1S 4700 NaH. 1986 INCREASE UNIFORMLY TO .2 Mu IN YEAR 1986 2003. 2003 ENERGY 1S 1750 Mal. 75 % DIVERSITY FACTOR SOURCES: (LANDMAN, 1983), (OWANE LEGG ASSOCIATES, 1982), (MH. DUNN, KENAI LUMBER CO., 1983), (1. REESE, SEWARD FISHERIES, 1983) 5.7 4.275 1750 1314 175 263 INCREASE UNIFORMLY TO 1.5 Md IN YEAR 2003. 2003 ENERGY 1S 3900 Ma. INCREASE UNIFORMLY 10 .2 Md IN YEAR 2003. 2003 ENERGY 1S 1750 MaH. 75 % DIVERSITY FACTOR to facilities and associated loads are assumed here that are not included in the low growth scenario. They include the Avtec school building addition, reopening of the Kenai Lumber Company mill, a shiplift facility, and a coal port facility. The exogenous industrial diversity factor is 75%. Only 75% of new industrial load is assumed to occur simultaneously. 3.4.3 Low Growth Scenario The low growth scenario provides a “low end" forecast for expected growth in the Seward area, although it still produces a population forecast in the year 2010 which is about 3% higher than the original ISER projection. The low growth scenario assumes: The current proportion of all electric households remains constant at 52% of total households through 1987. Thereafter, no new homes are electrically heated. Exogenous industrial growth is limited, as shown in Table 3.4-1. Total new industrial loads are less than one-half that assumed in the high growth scenario. The exogenous industrial diversity factor is 75%. Only 75% of new industrial load is assumed to occur simultaneously. 3.5 DATA SOURCES Data sources used to determine existing load conditions and to project changes include the following: 1) 4787B CM2M Hill Inc., City of Seward Electric System, Planning and Sectionalizing Study for the City of Seward, Alaska, Electric Department, August, 1979. 3-39 2) 3) 4) 5) 6) 4787B Kennedy/Jenks Engineers, Electric and Water/Sewer Rate Study, Preliminary Draft, City of Seward, June 30, 1983. Dwane Legg Associates, Analysis of Voltage Drop and Energy Losses, Prepared for: City of Seward, Seward, Alaska, October, 1982. (Used for estimating Kenai Lumber Company mill loads.) J. Landman of Acres/American, Personal Communications. In phone conversations on September 19 and 20, 1983, Mr. Landman provided Ebasco with low, moderate, and high growth scenarios for exogenous industrial loads and assumptions. Followup conversations between Ebasco staff and existing industrial customers added additional load assumptions in certain scenarios including the reopening of the lumber mill, expansion of the mill, and expansion of the fish processing facility. Ebasco staff estimated jobs created by all the additions. Mr. Landman added development by VECO in a phone conversation on October 3, 1983. Institute of Social and Economic Research, "Reference Case Projections by the City of Seward," prepared for Ebasco Services Incorporated, September 16, 1983. Unpublished. These projections served as the baseline economic and demographic forecasts for the Seward service area. 15 minute kW readings, Lawing Substation, December 1982 through February 1983 provided by the City Engineering Department. Conversion factor provided by J. Landman of Acres/American on September 28, 1983. Conversion factor of 0.50 and system power factor of 0.81 was developed from observations of volt and ammeters at Lawing substation by J. Landman on September 27, 1983. 3-40 7) 8) 9) 10) 11) 12) 47878 Chugach demand charge of 5.688 MVA for the 1/2/83-2/1/83 billing period provided by Mr. Bob Pearson of the City of Seward on 9/26/83. Mr. Pearson also provided the January 1980 and January 1983 energy sales by sector. Mr. Pearson also provided fiscal 1980 billing data by category since references 1) and 2) did not include data for 1980. Mr. Pearson provided all electric household data for fiscal 1974 through 1979 because reference 1) included only calendar year data. Alaska Power Authority, Before The Federal Energy Regulatory Commission, Application for License for Major Project, Susitna Hydroelectric Report, Volume 2C, RED Model (1983 Version), Technical Documentation Report, July, 1983. Used to adjust residential appliances saturation rates. D. Baker, Acres/Hanscomb, Personal Communication, September 21, 1983. Provided information on residential development and estimated transmission line on-line date for fall 1984. T. Pflum, City of Seward, City Engineering, Personal Communication, September 21, 1983. Provided information on trend toward all electric homes in Seward. Recommended Seward Fisheries and Cold Storage be included in winter peak. Department of Commerce, United States of America, National Oceanic and Atmospheric Administration, Environmental Data and Information Service, National Climatic Center, Climatological Data, Alaska, 1971-1983. Used to adjust 1983 energy consumption by all electric residential sector to normal consumption based on 9242 heating degree days. Temperature data used to correlate peak loads with temperature. M. Dunn, Kenai Lumber Company, Personal Communication, September 20, 1983. Indicated potential for lumber mil] reopening in 1985 with proper economic conditions and further expansion several years later. 3-41 13) T. Reese, Seward Fisheries and Cold Storage, Personal Communication, September 20, 1983. Indicated potential expansion in five years. : 14) City of Seward, Forecast Electric Demand for City of Seward Electric System, (unpublished), 1982. Used for diversity factor in low and moderate growth scenarios. 15) Alaska Power Authority, Before The Federal Energy Regulatory Commission, Application for License for Major Project, Susitna Hydroelectric Report, Volume 2B, Man-in-the Arctic Program (MAP) Technical Documentation Report, July, 1983. Used to compute number of persons per household. 3-42 4787B ALTERNATIVES = | 2 4. ALTERNATIVES FOR SEWARD TRANSMISSION SYSTEM Alternative means to satisfy the City of Seward's transmission needs include system, routing, and other alternatives. System alternatives are the primary focus of this report because a system alternative must be selected before design work proceeds. Routing alternatives are also presented in this report with the intent of soliciting comments on the alternatives identified so that an optimum, reliable route can be defined. It is expected that routing recommendations will be made by mid-November so that permitting requirements can be completed by the end of 1983. The third category of alternatives includes other alternatives evaluated during the project planning process. Information on these alternatives is provided to provide reviewers with a greater understanding of the project planning process. 4.1 SYSTEM ALTERNATIVES 4.1.1 General Considerations In order to design a functional and economic transmission system, both the high and the medium forecast data were considered. The high peak forecast for the year 2014 was used for sizing the equipment; this assures that the system will be able to supply power to the city if the high forecast proves to be correct. However, as the moderate forecast figures are felt to be more realistic, these were used in the economic evaluation. The following data were used from Tables 3.3-1 and 3.3-2: ° High peak load City 13.3 MW Marine Industrial Park 14.2 MW Total 27.5 MW 4-1 4782B = ° Moderate peak column City 10.2 MW Marine Industrial Park 6.4 MW Total 16.6 MW It was assumed that the power factor will be 0.9 in the year 2014, and with this the following figures were established: ° High peak load data City 13.3 MW 7.2 MVAR 14.8 MVA Marine Industrial Park 14.2 MW 6.9 MVAR 15.8 MVA Total 27.5 MW 13.3 MVAR 30.6 MVA ° Moderate peak load data City 10.2 MW 4.9 MVAR 11.3 MVA Marine Industrial Park 6.4 MW 3.1 MVAR 7.1 MVA Total 16.6 MW 8.0 MVAR 18.4 MVA Based on the above high forecast data, preliminary calculations were performed to estabiish potentially feasible voltage levels. The method developed by Ebascol’ was used for this purpose. This method calculates the MVAmiles, the product of power and distance of the transmission line, and uses tables to select suitable voltages. Page 232 of Volume WV displays data for 69 kV transmission. For 0.9 power factor and 795 kCMil aluminum conductor the table indicates that 753 MVAmiles can be transmitted at 6% voltage drop and 1,255 MVAmiles at 10% drop. V/ Electric Distribution System, Engineering Manual; Ebasco/Electrical World, New York, NY 4-2 47828 om For the year 2014, the corresponding value for the moderate peak forecast load is 18.4 x 40 = 736 MVAmiles and for the high peak load it is 30.6 x 40 = 1,224 MVA miles. There is no table for 115 kV, but only for 138 kV, which is shown on page 234 of Volume WV, The corresponding values are 1026 MVAmiles at 3% voltage drop and 1,224 MVAmiles at 4% drop. Comparing the above figures, the conclusion can be reached that 115 kV, which is not too far below 138 kV, is probably a suitable voltage. However, 69 kV is also promising and can not be ruled out at this early stage of the investigations. Therefore, 69 kV and 115 kV transmission systems are analyzed. In view of the fact that both 69 and 115 kV are considered with several line lengths ranging from 2.5 to 40 miles and several conductor sizes from 4/0 AWG ACSR to 1590 kCMil ACSR, the circuit parameters of these lines are tabulated in one location. These parameters per one mile length are shown in Tables 4.1-1 through 4.1-12. The tables are arranged in ascending voltage levels and within voltage level in ascending conductor sizes. The actual line parameters, both in ohms and per units, are tabulated in Tables 4.1-13 through 4.1-34. There is one table for each combination of voltage, conductor size, and line length. The tables are arranged in ascending order of first, voltage; second, conductor size; and, finally, line length. 4-3 4782B ™ TABLE 4.1-1 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage i Conductor Thermal limitl/ Equivalent delta spacing . Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance land ~~ Sunshine and 2 ft/sec (1.4 mph) wind. Ino SS At 50°C conductor temperature. 4-4 4782B 69 4/0 AWG 365 83.2 42 600 0.563 0.788 0.849 3.3 -0.170 -0.392 366 kV ACSR ampere inch feet ohm meter ohm/mile2/ ohm/mi le ohm/mi1e2/ ohm/mile M ohm/mile M ohm/mile ohm a TABLE 4.1-2 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal 1imitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-5 47828 69 266 kCM 455 83.2 42 600 0.377 0.700 0.663 3.21 -0.165 -0.387 340 kV ACSR ampere inch feet ohm meter ohm/mi1e2/ ohm/mile ohm/mi1e2/ ohm/mi le M ohm/mile M ohm/mile ohm a TABLE 4.1-3 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance / sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4782B 69 336 kCM 530 83.2 42 600 0.297 0.68 0.583 3.19 -0.161 -0.383 331 kV ACSR ampere inch feet ohm meter ohm/mi 1e2/ ohm/mite ohm/mile2/ ohm/mi le M ohm/mile M ohm/mile ohm ba TABLE 4.1-4 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-1 4782B 69 556 kCM 730 83.2 42 600 0.182 0.655 0.468 3.16 -0.154 -0.376 318 kV ACSR ampere inch feet ohm meter ohm/mi1e2/ ohm/mi le ohm/mi1e2/ ohm/mi le M ohm/mile M ohm/mile ohm ro TABLE 4.1-5 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-8 4782B 69 795 kCM 910 83.2 42 600 0.128 0.633 0.414 3.14 -0.149 -0.371 307 kV ACSR ampere inch feet ohm meter ohm/mi 1e2/ ohm/mile ohm/mile2/ ohm/mi le M ohm/mile M ohm/mile ohm LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ TABLE 4.1-6 Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4782B 4-9 69 954 kCM 970 83.2 42 600 0.109 0.63 0.395 3.14 -0.147 -0.369 305 kV ACSR ampere inch feet ohm meter ohm/mile2/ ohm/mi le ohm/mi1e2/ ohm/mi le M ohm/mile M ohm/mile ohm TABLE 4.1-7 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal 1imitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance V/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-10 4782B 69 1272 kKCM 1180 83.2 42 600 0.082 0.607 0.368 3.12 -0.142 -0.364 294 kV ACSR ampere inch feet ohm meter ohm/mile2/ ohm/mile ohm/mi1e2/ ohm/mile M ohm/mile M ohm/mile ohm e TABLE 4.1-8 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ ee Equivalent delta spacing 1 Avg. conductor height above ground bs Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4782B 4-11 69 1590 kCM 1360 83.2 42 600 0.0666 0.593 0.353 3.1 -0.139 -0.361 287 kV ACSR ampere inch feet ohm meter ohm/mile2/ ohm/mi le ohm/mile2/ ohm/mile M ohm/mile M ohm/mile ohm TABLE 4.1-9 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal 1imitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-12 47828 115 266 kCM 455 114.2 42 600 0.377 0.738 0.663 3.13 -0.174 -0.368 359 kV ACSR ampere inch feet ohm meter ohm/mi1e2/ ohm/mi le ohm/mile2/ ohm/mile M ohm/mile M ohm/mile ohm TABLE 4.1-10 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance J/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-13 4782B 115 336 kCM 530 114.2 42 600 0.297 0.719 0.583 3.11 -0.17 -0.364 350 kV ACSR ampere inch feet ohm meter ohm/mi1e2/ ohm/mi le ohm/mi1e2/ ohm/mi le M ohm/mile M ohm/mile ohm i: TABLE 4.1-11 - LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage J Conductor Thermal limitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance ' 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-14 4782B 115 397 kCM 590 114.2 42 600 0.254 0.714 0.54 3.11 -0.168 -0.362 _ 347 kV ACSR ampere inch feet ohm meter ohm/mite2/ ohm/mi le ohm/mi1e2/ ohm/mile M ohm/mile M ohm/mile ohm TABLE 4.1-12 LINE PARAMETERS PER PHASE AND PER UNIT LENGTH Design voltage Conductor Thermal limitl/ Equivalent delta spacing Avg. conductor height above ground Ground resistivity (estimated) Xcap + Xcap o Surge impedance 1/ sunshine and 2 ft/sec (1.4 mph) wind. 2/ at 50°C conductor temperature. 4-15 4782B 115 477 KCM 640 114.2 42 600 0.214 0.715 0.5 3.11 -0.167 -0.361 346 kV ACSR ampere inch feet ohm meter ohm/mi1e2/ ohm/mi le ohm/mile2/ ohm/mi le M ohm/mile M ohm/mile ohm TABLE 4.1-13 LINE PARAMETERS LAWING TO SEWARD (EXISTING) Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ sunshine with 2 ft/sec (1. 4782B in Table 4 mph) wind. 4-16 69 kV 24 mile 4/0 AWG ACSR 44 MvAl.2/ 4.1-1 Ohm/phase Per Unit 13.5 0.284 18.9 0.397 20.4 0.428 79.1 1.66 -0.00709 x 106 149 -0.0163 x 106 343 0.7 MVARL/ 13.5 mMWl/ 100 MVA 69 kV 47.61 ohm TABLE 4.1-14 LINE PARAMETERS ALONG NASH ROAD Rated voltage 69 kV Length 2.5 mile Conductor 266 kCM ACSR Thermal limit 54 MVAL.2/ Per unit length data in Table 4.1-2 Ohm/phase Per Unit Ry 0.943 0.0198 Xy nSURy 0.367 Ro 1.66 0.0348 Xo 8.02 0.168 Xcap + -0.066 x 106 1385 Xcap 0 -0.154 x 106 3251 Line charging 0.1 MVARI/ Surge impedance load 14 Mwl/ Base power 100 MVA Base voltage 69 kV Base impedance 47.61 ohm I- SS At rated voltage. ke In ~N 4782B Sunshine with 2 ft/sec (1. 4 mph) wind. 4-17 oy LINE PARAMETERS ALONG NASH ROAD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4782B TABLE 4.1-15 in Table 4-18 69 kV 2.5 mile 336 kCM ACSR 63 MVALL2/ 4.1-3 Ohm/phase Per Unit 0.743 0.0156 0.0357 46 0.0306 7.97 0.167 -0.0642 x 106 1350 -0.153 x 106 3220 0.1 MVARL/ 14.4 MWl/ 100 MVA 69 kV 47.61 ohm TABLE 4.1-16 LINE PARAMETER END OF NASH ROAD - MARINE I Rated voltage Length Conductor Thermal limit Per unit length data in Table Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4-19 4782B Ss NDUSTRIAL PARK 69 kV 4 mile 336 kKCM ACSR 63 MVAL.2/ 4.1-3 Ohm/phase Per Unit 1.1 0.0 2.7 0.0 2.3 0.0 12.8 0.2 -0.0401 x 108 843 -0.0957 x 108 2010 0.12 MVARI/ 14.4 MWl/ 100 MVA 69 kV 47.61 ohm co TABLE 4.1-17 LINE PARAMETERS SEWARD MARINE INDUSTRIAL PARK Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance I- ~ At rated voltage. N £/ Sunshine with 2 ft/sec (1. 4782B in Table 4 mph) wind. 4-20 69 kV 6.5 mile 336 kCM ACSR 63 MVAL2/ 4.1-3 Ohm/phase Per Unit 1.93 0.0405 4.42 0.0929 3.79 0.0796 20.7 0.435 -0.0247 x 106 519 -0.0589 x 106 1240 0.2 MVARI/ 14.4 Mwl/ 100 MVA 69 kV 47.61 ohm £ TABLE 4.1-18 LINE PARAMETERS DAVES CREEK - SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance Vat rated voltage. 2/ Sunshine with 2 ft/sec qd 4782B in Table -4 mph) wind. 4-21 69 kV 40 mile 336 kCM ACSR 63 MVAL.2/ 4.1-3 Ohm/phase TU9 27.2 23.3 128 -0.00401 x 106 -0.00957 x 106 0.12 MVARL/ 14.4 MWl/ 100 MVA 69 kV 47.61 ohm Per Unit 0.25 0.571 0.49 2.68 84.3 201 £ TABLE 4.1.19 LINE PARAMETERS DAVES CREEK - SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance I~ Ss) At rated voltage. eS Sunshine with 2 ft/sec (1 4782B in Table -4 mph) wind. 4-22 69 kV 40 mile 556 kCM ACSR 87 MVAL.2/ 4.1-4 Ohm/phase Per Unit 7.28 0.153 26.2 0.551 18.7 0.393 N27 2.66 -0.00385 x 106 80.8 -0.0094 x 106 198 1.2 MVARL/ 15 Mwl/ 100 MVA 69 kV 47.61 ohm ke TABLE 4.1-20 LINE PARAMETERS DAVES CREEK - SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1. 4782B in Table 4 mph) wind. _ 4-23 69 kV 40 mile 795 kCM ACSR 109 MVAL.2/ 4.1-5 Ohm/phase 5.12 25.3 16.6 126 -0.00372 x 106 -0.00927 x 106 1.3 MVARL/ 15.5 MWl/ 100 MVA 69 kV 47.61 ohm Per Unit 0.108 0.532 0.348 2.64 78.1 195 c -m ww i= NON 4782B TABLE 4.1-21 LINE PARAMETERS DAVES CREEK -— SEWARD Rated voltage 69 kV Length 40 mile Conductor 954 kCM ACSR Thermal limit 116 MVAL.2/ Per unit length data in Table 4.1-6 Ohm/phase Per Unit Ry 4.36 0.916 Xy 25.52 0.529 Ro 15.8 0.332 Xo 126 2.64 Xcap + -0.00368 x 108 11.3 Xcap o -0.00923 x 106 1984 Line charging 1.3 MVARL/ Surge impedance load 15.6 MWl/ Base power 100 MVA Base voltage 69 kV Base impedance 47.61 ohm At rated voltage. Sunshine with 2 ft/sec (1.4 mph) wind. 4-24 rm TABLE 4.1-22 LINE PARAMETERS DAVES CREEK -— SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1 4782B in Table -4 mph) wind. 4-25 69 kV 40 mile 1272 kCM ACSR 141 MvAl.2/ 4.1-7 Ohm/phase 3.28 24.3 14.7 125 -0.00355 x 106 -0.00911 x 106 1.3 MVARL/ 16.2 Mwl/ 100 MVA 69 kV 47.61 ohm Per Unit 0.0689 0.51 0.309 2.62 714.6 191 = TABLE 4.1-23 LINE PARAMETERS DAVES CREEK — SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1 4782B in Table -4 mph) wind. 4-26 69 kV 40 mile 1590 kCM ACSR 163 MVALL2/ 4.1-8 Ohm/phase 2.66 23.7 14.1 124 -0.00347 x 106 -0.00902 x 106 1.4 MVARL/ 16.6 MWL/ 100 MVA 69 kV 47.61 ohm Per Unit 0.056 0.5 0.296 2.61 72.9 190 het TABLE 4.1-24 LINE PARAMETERS ALONG NASH ROAD Rated voltage 115 kV Length 2.5 mile Conductor 266 kCM Thermal limit 91 mMvAl.2/ Per unit length data in Table 4.1-9 Ohm/phase Per Unit Ry 0.943 0.00713 Xe 1.85 0.014 Ro 1.66 0.0125 Xo 7.83 0.0592 Xeap + -0.0697 x 108 527 Xcap 0 -0.0147 x 106 1114 Line charging 0.2 MVARI/ Surge impedance load 36.9 MWl/ Base power 100 MVA Base voltage 115 kV Base impedance 132.25 ohm V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4-27 4782B te | ua TABLE 4.1-25 LINE PARAMETERS DAVES CREEK - LAWING Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4782B in Table 4-28 115 kV 16 mile 266 kCM ACSR 91 MVAL.2/ 3 Ohm/phase Per Unit 6.03 0.0456 11.8 0.0893 10.6 0.0802 50.1 0.379 -0.0109 x 106 82.3 -0.023 x 106 174 1.2 MVARI/ 36.9 MWl/ 100 MVA 115 kV 132.25 ohm co a; ~ & TABLE 4.1-26 LINE PARAMETERS DAVES CREEK - SEWARD Rated voltage 115 kV Length 40 mile Conductor 266 kCM ACSR Thermal limit 91 MvALs2/ Per unit length data in Table 4.1-9 Ohm/phase Ry 1s sl Xy 29.5 Ro 26.5 Xo 125 Xcap + -0.00436 x 106 Xcap o -0.00921 x 108 Line charging 3 MVARL/ Surge impedance load 36.9 Mwl/ Base power 100 MVA Base voltage 115 kV Base impedance 132.25 ohm I- ~ At rated voltage. Inm ~N Sunshine with 2 ft/sec (1.4 mph) wind. 4-29 4782B Per Unit 0.114 0.223 0.201 0.947 32.9 69.6 i) TABLE 4.1-27 LINE PARAMETERS END OF NASH ROAD - MARINE INDUSTRIAL PARK Rated voltage 115 kV Length 4 mile Conductor 336 kKCM ACSR Thermal limit 106 MVAL.2/ Per unit length data in Table 1 Ohm/phase Per Unit Ry 1.19 009 Xy 2.87 .0217 Ro 2.33 .0176 Xo 12.45 -0941 Xcap + -0.0425 x 106 321 Xcap o -0.091 x 106 688 Line charging 0.3 MVARI/ Surge impedance load 37.8 MWl/ Base power 110 MVA Base voltage 115 kV Base impedance 132.25 ohm V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4782B 4-30 Ks TABLE 4.1-28 LINE PARAMETERS SEWARD - MARINE INDUSTRIAL PARK Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance I- =~ At rated voltage. Ino ~ Sunshine with 2 ft/sec (1 4782B in Table -4 mph) wind. 4-31 115 kV 6.5 mile 336 kCM ACSR 106 MVAL.2/ 4.1-10 Ohm/phase Per Unit 1.931 0.0146 4.67 0.0353 3.79 0.0287 20.2 0.153 -0.0262 x 106 198 -0.056 x 106 423 0.5 MVARI/ 37.8 MWl/ 100 MVA 115 kV 132.25 ohm ts TABLE 4.1-29 LINE PARAMETERS DAVES CREEK-LAWING Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4782B in Table 4-32 115 kV 16 mile Oriole, 336 kCM, ACSR 106 MVALL2/ 4.1-10 Ohm/phase Per Unit 4.75 0.0359 11.5 0.0869 9.33 0.0706 49.8 0.377 -0.0106 x 106 80.3 -0.0227 x 106 172.0 1.2 MVARL/ 37.8 Mwl/ 100 MVA 115 kV 132.25 ohm as LINE PARAMETERS DAVES CREEK-SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ Sunshine with 2 ft/sec (1 4782B TABLE 4.1-30 jin Table -4 mph) wind. 4-33 115 kV 40 mile 336 kCM ACSR 106 MVAL.2/ 4.1-10 Ohm/phase Per Unit 9 0.09 28.7 0.217 23.3 0.176 124.5 0.941 -0.00425 x 106 32.1 -0.0091 x 106 68.8 3.1 MVARL/ 37.8 MWl/ 110 MVA 115 kV 132.25 ohm e TABLE 4.1-31 m LINE PARAMETERS DAVES CREEK - LAWING re r rm Rated voltage Length * Conductor Thermal limit Per unit length data in Table Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. ~ 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4-34 4782B 115 kV 16 mile 397 kCM ACSR 118 MVAL2/ 4 Ohm/phase Per Unit 4.06 0.0307 11.4 0.0864 8.64 0.0656 49.7 0.376 -0.0105 x 106 79.6 -0.0226 x 106 m1 1.3 MVARL/ 38.1 MWl/ 100 MVA 115 kV 132.25 ohm eo LINE PARAMETERS TABLE 4.1-32 DAVES CREEK — SEWARD Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance V/ at rated voltage. 2/ sunshine with 2 ft/sec (1.4 mph) wind. 4782B in Table 4-35 115 kV 40 mile 397 kCM ACSR 118 MVAL.2/ 4.1-11 Ohm/phase Per Unit 10.2 0.0768 28.6 0.216 6 0.163 124.3 0.94 -0.00421 x 106 31.8 -0.00906 x 106 68.5 3.1 MVARL/ 38 Mwl/ 100 MVA 115 kV 132.25 ohm fos hae kes TABLE 4.1-33 LINE PARAMETERS DAVES CREEK - LAWING Rated voltage Length Conductor Thermal limit Per unit length data Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance Im SS At rated voltage. In ~S Sunshine with 2 ft/sec (1 4782B in Table -4 mph) wind. 4-36 115 kV 16 mile 477 kCM ACSR 127 MVAL.2/ 4.1-12 Ohm/phase Per Unit 3.42 0.0259 11.4 0.0865 8.0 0.0605 49.7 0.376 -0.0105 x 106 79 -0.0226 x 106 m 1.3 MVARI/ 38.3 MWl/ 100 MVA 115 kV 132.25 ohm ce - —_ be Im SS S 2/ Sunshine with 2 ft/sec (1.4 mph) wind. 4782B Rated voltage Length Conductor Thermal limit TABLE 4.1-34 LINE PARAMETERS DAVES CREEK - SEWARD Per unit length data in Table Xcap + Xcap o Line charging Surge impedance load Base power Base voltage Base impedance At rated voltage. 4-37 115 kV 40 mile 477 kCM ACSR 127 MVAL.2/ 4.1-12 Ohm/phase 8.56 28.6 20 124 -0.00418 x 106 -0.00903 x 106 3.2 MVARL/ 38.3 MWl/ 100 MVA 115 kV 132.25 ohm Per Unit 0.0647 0.216 0.151 0.94 31.6 68.3 ba ia 4.1.2 115 and 69 kV Alternatives Six basic configurations were developed and evaluated on the 115 and 69 kV level. All but one has 24 kV underbuilt on the entire length of the line to supply customers between Daves Creek and Seward. The Lawing metering station is retained in the 24.9 kV underbuild alternatives though it may be relocated and/or modified, and the switch at Lawing will be normally open. In one of the alternatives, Alternative 6, the underbuild is 12.47 kV between Lawing and Seward but remains at 24.9 kV between Daves Creek and Lawing. In this latter case, of course, there is neither metering nor switching provided at Lawing. For all of these versions those customers between Daves Creek and Seward who are presently Chugach customers will remain with Chugach and all those customers who are getting their power from the City of Seward will remain with the City of Seward in the future also. The 24.9 kV underbuild does not influence the high voltage transmission system in cost or otherwise. Therefore the studies outlined in this Paragraph were conducted only with regard to the 115 and 69 kV system. The only exception is Alternative 6 in which a 12.47 kV underbuild is considered; however, this alternative had to be discarded for reasons explained later. In all cases, at the request of the Chugach Electric Association, a three breaker 115 kV bus arrangement has been included at the Daves Creek Substation. All transformations on the high voltage system are accomplished with two parallel transformers, each capable of carrying somewhat more than half of the high peak forecast load. This applies to all 115/12.47 kV, V/ Daves Creek-Seward Transmission Line Feasibility Study; Part III of Volume 1 of the Grant Lake Hydroelectric Project Detailed Feasibility Analysis; Ebasco Services Incorporated, February 1983 4-38 4782B 69/12.47 kV and 150/69 kV transformations. The purpose of this arrangement is to increase reliability, to avoid the complete shutdown of the city in case of a transformer failure, and to permit easy maintenance of transformers and associated switchgear. Alternative 1 (see figures on pages 4-86 through 4-90) This alternative would demand the most radical changes in the present system and discard much of the available equipment. This version is an all 115 kV alternative. It connects directly, via a circuit breaker, to the 115 kV bus at Daves Creek and runs at this voltage to the Seward 115 kV bus. From here the line goes to the Marine Industrial Park. This alternative means that the existing 4 mile long segment, extending from the end of Nash Road to the Marine Industrial Park, has to be rebuilt. It also means that the present transformers and switchgear cannot be used. The one line diagram of this system is shown in Figure 4.1-1. Four different conductor sizes were evaluated between Daves Creek and Seward, 226, 336, 397, and 477 kCMil ACSR. In the case when the conductor between Daves Creek and Seward is 226 kCMil ACSR, the same conductor is used for the 2-1/2 mile section between the Seward Substation and the end of Nash Road. In all other cases the line between Seward and Marine Industrial Park is equipped with 336 kCMil ACSR. This arrangement offers the simplest configuration, the minimum amount of transformers, switchers, circuit breakers, and bus work. The results of the load flow calculations are shown in Figures 4.1-2 through 4.1-5. From these figures it can be seen that the 115 kV alternative results in a voltage drop in the vicinity of 6-7%. 4-39 4782B Alternative 2 (see figure on page 4-91) This alternative uses 115 kV as the voltage between Daves Creek and Seward. In this regard, it is very similar to Alternative 1, with the exception that at Seward, three winding transformers will be installed in order to transform the voltage to 69 kV to be transmitted to the Marine Industrial Park and to 12.47 kV to supply the city. The 69 kV transmission to the Marine Industrial Park will involve retaining the 4 mile section of the already built line and building a new 2-1/2 mile section from the Seward Substation to the end of Nash Road to join the already existing line. The two transformers and circuit switchers presently installed in the Seward switchyard would be moved to the Marine Industrial Park. Alternative 3 (see figures on pages 4-92 through 4-96) This alternative is a variation on Alternative 2. Instead of using three winding transformers, this alternative uses auto transformers to reduce the voltage from 115 to 69 kV at the Seward Substation. The 69 to 12.47 kV transformers presently installed in Seward would stay and new transformers would be purchased for the Marine Industrial Park. The one line diagram for this alternative is shown in Figure 4.1-7. The results of the load flow studies carried out for this alternative are shown in Figures 4.1-8 through 4.1-11. In this alternative, the conductor sizes used were 266, 336, 397, and 477 kCMil ACSR for the Daves Creek to Seward 115 kV line. For the Seward Substation-Marine Industrial Park 69 kV line in general 336 kCMil ACSR is used, with the exception of the case when 266 kCMil is used between Daves Creek and Seward when the same size is used for the 2-1/2 mile length between the Seward Substation to the end of Nash Road. 4-40 4782B en hea From the load flows it becomes clear that the voltage drop is somewhat more when compared to Alternative 1, by about 1%. This is due mainly to the additional transformation between the 115 and 69 kV system. However, even though the voltage drops are in the range of 7 to 9%, they are still well beyond the range which can be considered excessive. Alternative 4 (see figures on pages 4-97 and 4-99) This alternative was designed to take advantage of the presently existing section of the Seward transmission line which is insulated for 69 kV. This line is furnished with 4/0 AWG ACSR conductors. The length of this line segment, Lawing to Seward, is 24 miles. As 69 kV voltage is one of the feasible voltages, an investigation was made to find out whether the existing line segment can be retained. In this alternative transformation from 115 to 69 kV is accomplished at Lawing using auto transformers. Between Daves Creek and Lawing the line is essentially the same as in Alternatives 1 and 2. The one line diagram of the system is shown in Figure 4.1-12. The load flow is displayed in Figure 4.1-14. From the load flows it can be seen that with the moderate peak forecast load, the voltage drop on the 12.47 kV buses is 16%, which is excessive. Looking at the figure and looking at the difference between bus 16 and bus 3, it can be seen that the existing line with its 4/0 AWG wire causes 10% of this voltage drop. From this it was concluded that this alternative is not feasible at all and that the existing transmission line and its conductor cannot be used for the new high voltage transmission system. Alternative 5 (see figures on pages 4-100 through 4-106) This is an all 69 kV system in which transformation from 115 to 69 kV is accomplished at Daves Creek. For this alternative 556, 795, 954, 1272, and 1590 kCMil ACSR conductors were investigated between Daves 4-41 4782B Creek and Seward, and 336 kCMil ACSR between the Seward Substation and the Marine Industrial Park. The one line diagram of this alternative is shown in Figure 4.1-15. The load flows are displayed in Figures 4.1-16 through 4.1-21 and from them it can be seen that the voltage drops are acceptable only for conductor sizes larger than 795 kCMil. Even in these cases the voltage drop is up to its limit, namely 11% or 12%. Even though this voltage drop can be reduced by installing power factor correcting capacitors or static voltage compensators (SVC), if the load should become larger than the moderate forecast, this system would definitely be inadequate. Alternative 6 (see figures on pages 4-98 and 4-99) This alternative is very similar to Alternative 4, and on the high voltage side, it is identical. The main difference is on the feeder arrangement for customers between Lawing and Seward. Whereas Alternative 4 used 24.9 kV to supply these customers, this alternative uses 12.47 kV for the same purpose because between Lawing and Seward new underbuild has to be constructed (there is no underbuild at present on this line segment) . As it was shown in Alternative 4 that the existing line with its 4/0 ACSR conductors cannot be used, this alternative, as far as the 115 and 69 kV voltage segments are concerned, is not feasible. 4-42 47828 = eo ax 4.1.3 Supplying Customers Between Daves Creek and Seward 4.1.3.1 Daves Creek to Lawing Segment In all cases the Daves Creek to Lawing segment will be fed from the existing 115/24.9 kV transformer at Daves Creek unless Chugach Electric decides otherwise. There will be no change in this segment of the line, with the exception that the present line will be underbuilt, probably along the entire length on the new 115 kV or 69 kV transmission line. 4.1.3.2 Lawing to Seward Segment There are essentially two possibilities to feed these customers. One would be to retain the 24.9 kV voltage for the system and to underbuild the new line. This alternative could, and most likely will, retain the Lawing connection and its metering equipment. The other alternative is to save a transformer at Seward and supply these customers directly from the 12.47 kV system from Seward. 4.1.3.3 Other Options There are several other alternatives which can be considered to supply the customers between Daves Creek and Seward. One alternative would be to supply all local loads with 69 kV/110-220 volt transformers, should 69 kV become operational. However, as it will be seen later, 69 kV is not the most economic voltage and therefore this alternative was not investigated further. Regarding the supply of customers between Lawing and Seward, the following options are feasible. Keep the metering station at Lawing operational and its switch normally closed, and terminate the 24.9 kV line at Milepost 9; an optional switch at this location may be installed for emergency operations. The 24.9 kV line can be supplied also from a 12.47/24.9 kV transformer at Milepost 9 or the 24.9 kV 4-43 4782B be line can be extended to the Seward Substation and a transformer installed there. In any of those cases, using 12.47 kV for the customers along this branch line is also a possibility. A further possibility is to supply customers close to Lawing at 24.9 kV via the metering station and those close to Seward at 12.47 kV from the city. This arrangement would not permit emergency operation using the underbuild; however, it would save in capital costs by eliminating several miles of 24.9 kV underbuild. However, none of those alternatives affect the design of the 69 kV or 150 kV segments of the line and therefore they were not evaluated in detail at this time. 4.2 ROUTING ALTERNATIVES The previous studies conducted by Ebasco, Dwane Legg, and CH2M Hill, as described in the Introduction (Section 1), recognized that the existing transmission system is not as reliable as desired. In addition to the fact that the existing 24.9 kV system is simply too small to handle Seward's current and anticipated loads, the existing system experiences problems because of geotechnical conditions and the fact that maintenance of the line can be difficult due to poor access. Geotechnical concerns include avalanche, flood, and seismic hazards, while poor access affects scheduled and emergency maintenance activities throughout the year. In light of the concerns described above, Ebasco's efforts on the proposed transmission line project include identification and analysis of areas where geotechnical hazards are most severe and maintenance problems are the greatest. The results of these studies are described below. 4-44 4782B 4.2.1 Geotechnical Hazards R&M Consultants, Inc., working as a subcontractor to Ebasco, conducted a preliminary geologic and geotechnical evaluation of the proposed City of Seward Transmission System rebuild. The objective of the study was to identify and qualitatively describe geologic and geotechnical parameters which may effect transmission line routing, design, construction and operation. The preliminary results of these investigations are presented in this report, while more detailed information will be incorporated into the line's design. Maps providing additional information on the areas studied are provided in the appendix of Chapter 4. The preliminary geologic and geotechnical study consisted of: a review of the literature of the area including most importantly avalanche reports for the Seward Highway, Department of Transportation and Public Facilities (DOTPF) reports on the soils, material sources and bridge crossing of the Seward Highway and the effects of the 1964 earthquake; preliminary terrain unit mapping of the project corridor on high altitude 1:60,000 color infra-red (CIR) photographs; field checking of the photo interpretation; and site visit to the five special investigation areas. There are three major areas of geotechnical investigation which include avalanche, flood, and seismic hazards. Avalanche hazards are high along almost the entire route due to climatic factors and the steep topography in the project area. Further, much of the route crosses the lower slopes of the avalanche zones, where avalanche avoidance, control, and mitigation measures are limited and quite costly. Flood hazards are more localized and design measures can generally be adopted to minimize the risks of experiencing flood damage. Seismic hazards also exist throughout the project area, but it is generally more cost-effective to use a standard design and anticipate repairing damaged portions of the line. 4-45 4782B 4.2.1.1 Avalanche Hazards The project is located within the maritime and transitional climatic zones of Alaska. Mean annual snow fall ranges from 70 to greater than 100 inches (Hartman, and Johnson, 1978). Such heavy snow accumulations are known to have caused snow avalanching on steep slopes along the Seward Highway, resulting in property damage and traffic interruption. To evaluate snow avalanching along the route of the proposed transmission line, a thorough review is being made of existing literature and of both high and low-level aerial photographs. During a preliminary field investigation, avalanche chutes and tracks were observed and compared with data from existing sources. Information obtained from the literature as well as current interpretations have been used to plot avalanche zones or paths that may impact the proposed transmission line. These areas are identified on 1:63,360 scale USGS base maps as shown in Figures 4.2-1, 4.2-2, and 4.2-3. There are two general concepts that are broadly used as avalanche defense measures. The first is active defense, which is used to prevent avalanching or to at least cause the avalanche to occur in a controlled manner. The second concept is the passive defense measure, which does nothing to prevent the avalanche from occurring, but is only concerned with preventing or limiting damage caused by the avalanche. Active avalanche defense structures are generally located in or above the starting zone. Terraces, fences, nets and explosives are the most common defenses of this type. Explosives and/or artillery may be utilized to trigger avalanches, thus keeping their size and the hazard under control. 4-46 4782B 4 i & Passive avalanche defense structures are generally located in the lower track area or the runout zone. Snow shed, diversion dikes, terraces and other obstructions are the most common forms of passive avalanche defense. Proper site selection prior to construction of structures could also be considered as a passive defense measure. While this concept is widely used, the protected structures are subject to periodic avalanching which exceeds the ability of the defense mechanism to protect them. 4.2.1.2 Flood Hazards Several sections of the proposed City of Seward transmission system will be constructed on known floodplains, including most importantly the floodplains of Quartz Creek, Snow River, Resurrection and Salmon Rivers and Jap Creek. Flood hazards which could affect the transmission line are limited to the build-up of debris (trees and ice) around the poles with attendant lateral forces and the potential for partially scouring or completely excavating the poles. However, the amount of exposure to these problems is very slight because they are primarily in-channel hazards and the poles will be set back from the edge of the channel. At the Snow River crossing where the larger towers of a long span may be located close to the main channel, the flood hazard is limited by a rip-rap controlled channel maintained to protect the highway bridge. Therefore, only a channel change (to a pole location) in conjunction with a flood event could adversely effect the transmission line. The two project substations which are located on the Quartz Creek floodplain and Jap Creek fan are more susceptible to flood hazards because they have low tolerances for differential settlement. Flood waters covering the substation pads would have little effect on the transformers (until they reached a depth of several feet) but water entering a control room could damage the equipment. A channelized flow incident on or over the pads could erode or scour the pad, allowing differential settlement. Additionally, the build-up of debris and sediment around the transformers could cause slight shifts in their positions. 4-47 4782B CITY OF SEWARD TRANSMISSION SYSTEM AVALANCE HAZARD MAP ATION. (fo & il / LAWING (435 ‘METERING é is no ee J Locust Se-1 | EBASCO SERVICES INCORPORATED 4-48 _ © Mountain CITY OF SEWARD TRANSMISSION SYSTEM AVALANCE HAZARD MAP EBASCO STHVICES INCORPORATED SSeS NS NOY x rae tHe: Z ee eee { ) “i WE “fF , if BS A Age! TAN AL IN TLE GE ¢ <? Fs =H Phere es a ie eee NSS CITY OF SEWARD TRANSMISSION SYSTEM AVALANCE HAZARD MAP foxte gcrogga ees Trcunt ZRF | EBASCO SERVICES INCORPORA: EO At the present time the Quartz Creek channel is partially controlled by low dikes in the area of the Daves Creek Substation. However, the dikes have recently been breached and flowing water has come within about two feet of the top of the substation gravel pad. Repair of the berm and diligent maintenance by the Department of Transportation will decrease the hazard of short recurrence interval floods and assist in preventing minor channel changes, but will do little to mitigate the impacts of a large flood. The Seward Substation located on the Jap Creek alluvial fan appears safe from flood hazards because it lies more than a half mile from the Jap Creek channel and above the floodplain of the Resurrection River. However, the USGS has mapped the area of the Seward Substation as lying within the 100-year floodplain of the Resurrection River as mapped by the Corps of Engineers. Without channel control structures on Jap Creek the substation may be subject to flood hazards. Currently Jap Creek has no engineered channel control structures and none are planned (Dooley 1983); however, bulldozers have been used in the past to make channel berms during periods of high flow (Stan Jones 1983). Another hydrologic/geologic concern of northern latitudes is the formation of aufeis (icings or stream glaciation). This repetitive freezing and overflow of channelized water may allow a stream to leave its normal channels and invade its floodplain and adjacent areas. Structures built on the floodplain close to a stream may be subject to ice buildup. This process would probably not have any adverse effects on transmission line poles, but the Daves Creek Substation on the Quartz Creek floodplain may be more susceptible to damage from lateral ice pressures, high water, and more difficult maintenance. 4.2.1.3 Seismic Hazards The City of Seward transmission system lies within the seismically active megathrust area created by the subduction of the Pacific plate beneath the North American Plate. The project features are therefore subject to seismic hazards such as seismic shaking, liquefaction, and 4-51 4782B Be a induced mass wasting. The degree of exposure to these hazards, the amount of effort which should be put into mitigation of hazards, and the effectiveness of mitigation techniques is difficult to assess. There is a possibility/probability of another great earthquake affecting the transmission line corridor but the likelihood of such an event in the very near future is low, and if such an event occurs, it would be extremely difficult to protect the electrical supply and distribution system. In many situations the use of a standard design, with repair of damaged sections of the system in event of an earthquake, may be the most cost effective plan. Most major engineering projects of the same tectonic setting as the Seward transmission system have used maximum credible earthquake and design earthquake values in the 8.0 magnitude range (Bradley Lake Hydroelectric Project, Grant Lake Hydroelectric Project, and the Seward Dock facilities, Woodward-Clyde Consultants, 1981; R&M Consultants, 1982, 1978). This type of event occurring at a depth of about 30 kilometers could produce accelerations of 0.65 g with ground motions of 50 to 100 cm and have a duration of over 60 seconds (Page et al, 1972; Krinitzsky, 1978; Bolt, 1973; Campbell, 1981; Joyner & Boore, 1981). Recurrence interval predictions for Kenai Peninsula events of this magnitude range from 160 years to about 300 years with most estimates being about 200 years (Lahr, 19731 Plafler, 1969; Kanamori, 1977; Sykes and Quittmeyer, 1981). Lower magnitude events have a shorter recurrence interval. Damage to structures during and following an earthquake may take many forms. The transmission system may potentially be affected by the following phenomenon. Seismic shaking of the transmission line and poles in a great earthquake is not expected to present major design or alignment problems but could break guy lines, the conductor lines and cause poles to tilt and insulators to break away. More severe damage may occur at the substations, where shaking could exceed the stability tolerances of the transformers. 4-52 4782B In areas with a high water table and low density soils, the soils can liquify under seismic loading. When liquefaction occurs, the soils lose most of their strength, allowing poles and substation features, including the transformers, to settle and tilt. As the liquefied soils regain their strength (following the earthquake), differential settlement is very likely. Soils of the project area, which may be liquefaction sensitive, include the floodplains of the Snow River, Resurrection River, Quartz Creek and possibly the Jap Creek fan. This potential hazard may then affect the design of the long span towers crossing the Snow and Resurrection Rivers and the substations at Quartz Creek and in Seward. Minor earthquake induced differential settlement of soils (outside liquefaction sensitive areas) may occur but is not expected to present a major problem. Seismic activity may trigger failures of marginally stable and unstable soils (landslides and submarine and sublacustrine slumps). Preliminary terrain unit mapping did not identify any landslide deposits along the transmission line route and no significant landslides where noted along the corridor during the 1964 Good Friday earthquake, so landslide hazards are thought to be minimal. A number of seismically induced sublacustrine slumps in the deltaic and fan deposits of Kenai Lake and a large submarine slump at Seward occurred during the 1964 earthquake. The Seward submarine slump and resulting waves badly damaged the local power distribution system but did not affect the area of the Seward Substation or the incoming transmission line. Therefore, even a similar large scale submarine slump would not be expected to impact the current project facilities. (Similarly, the Seward Substation and incoming transmission line are out of the area of the 1964 Tsunami). The sublacustrine slumps at Kenai Lake did cause failure of subaerial portions of the deltas and fans on which they occurred and did destroy short segments of the railroad which closely followed the shoreline. The area of the existing transmission line corridor, located further upslope, was not damaged by the soil failure or the waves generated by the failure (which washed up as high as 30 feet above lake level). Based on this history, a transmission line in the vicinity of the 4-53 4782B existing line would not be threatened by slumps or their siech waves, but a corridor moved to the shoreline adjacent to the railroad may be exposed to seismically induced slump failure on the fans and deltas and to siech wave wash around the perimeter of the lake. 4.2.2 Maintenance Problem Areas Ebasco engineers and scientists undertook studies to identify areas along the existing transmission line route where maintenance problems are most severe. These areas were identified through discussions with personnel from the City of Seward familiar with maintenance problems along the existing line as well as through discussion with Chugach Electric Association personnel. In addition, U.S. Forest Service representatives were contacted regarding potential problem areas and experiences that agency had observed on the line within the existing right-of-way. Field and air photo investigations involving engineers and geotechnical, construction, and environmental specialists were also undertaken. The investigations described above led to the conclusion that Maintenance problems are greatest for all sections of the right-of-way not immediately adjacent to the road. The location of the existing line, relative to the highway, is shown in Figures 4.2-4, 4.2-5, and 4.2-6. In general, summer access problems relate primarily to the lack of easy access to the entire route. Wet swampy conditions in certain portions of the route inhibit maintenance activities on the line. In addition, those areas of the transmission line not immediately adjacent to the Seward or Sterling Highways make access to the right-of-way, which is located on steep ground, difficult during adverse weather conditions which occur during winter and summer. Specifically, the portion of the-route between mileposts 11 and 15 is often difficult to reach because the right-of-way is on steep slopes up to 3,000 feet from the highway. Maintenance problems are compounded by the muskeg and other poorly drained areas where access is difficult in summer months, requiring the use of low pressure vehicles for access. In winter the steep slopes in the area also reduce accessibility. 4-54 4782B f- No y : “SN \ SH SA y , Sy : ye | 8g z yx a | ahs ee << iN Eas e% HL , Ke : ut S = Ps : i = = " E 2 Fes sf ~ s : ~ s wy tt ’ ts. AA, SSS > ¢ > \ “3 : = * Ma \ : = web nedioortgea tithe tem | S oo \° . We “$ ) 7 SY, tr aN \ WX & Go. NN * SS 4 ~ Wey \" XS. \ \ \ ” es NS AR SS ' Aye f \ x s i atl th : “ } ‘ ‘ \ She : - e 8 WN’ eo No) ke qh m \ SN S : . a J " = aap i “ . 5 g | ss WS oe SRY a5 e s\ j P Ws omens NS YG wy . uf \ \Y J a. \ \ Sp. Sea, — A b > . _ = = wp \ z PNAC \ X (i ( \ qs = ~ & P x S 8 7 a: y \ re = oN , lip a \ 5 i} cose, MH //, che / td AWN S \ mc iy NN \ S SAN ee = Hi A. el \ Lh lt | ciry OF SEWAR | jp eevee eres \ \ 4a i gy ya | EXISTING TRANSMISSION LINE viecin Me; fe WS VY) y) abt mee) ZZ : Ts SALLI T_T EBASCO SERVICES INCORPORATED : 2S yy MA r yy r- yy) 4 “fs gaye) SES 2 hi Up Oh | o/ S) p) \ = zs i (( e BZ 4 Za eI ida gos iy q X. * Sele ty Yipes yp We if t eo - : WR Pp. Saat A a AS eee.) ae a m QQ : ea iN Ci it ZS KEAN ‘ (Sse SAS HE ey eB pil) GES SO See jj], CITY OF SEWARD __| [Z WEP AAR yy) ) Aq TRANSMISSION SYSTEM EXISTING TRANSMISSION LINE - N NN LE IN FEET WN RONWAS NI \ SW AN X S wr * 3 aS ITY SEWARD Ci hes ts In the vicinity of Kenai Lake maintenance problems occur even though the line is generally within 1,000 feet of the highway. Although steep slopes and the high avalanche hazard pose maintenance problems over a large section of the route, the problems are most severe in the avalanche area approximately 4 miles north of the Snow River Bridge, In the area between Moose Pass and Upper Trail Lake, muskeg and creeks limit access during most of the year. Furthermore, the poor pole foundations require additional maintenance and guying to keep the structures upright. Another area where maintenance problems are anticipated is near Tern Lake. The slopes east and north of Tern Lake are identified avalanche hazard areas (see Figure 4.2-1) and recent avalanches in this area indicate maintenance problems are a concern. During the course of investigations to identify areas where access and maintenance problems exist, it became apparent that the line's reliability could be improved if clearing practices were modified. There are numerous areas along the existing transmission line where adequate clearing widths are not maintained. Clearing practices could be improved by establishing a program whereby the right-of-way was cleared at variable widths depending upon the line's location. For example, at the mid-point of the span between two wood poles, the conductor is at its lowest point and most subject to wider swings due to wind loadings. In such areas, it is necessary to clear a wider area than near the wood poles themselves where the height and swing of the conductor are fixed. For this reason, Ebasco will be working with the Forest Service to establish a clearing program which will involve variable width clearing more responsive to local conditions and the requirements of maintaining a reliable line. Such an approach will improve the reliability of the line without having to relocate the line. Such a clearing program has been successfully employed on other projects and is depicted in Figure 4.2-7. 4-58 4782B ba PATTERNS OF CONDUCTOR SWAY SERVICE ACCESS CAN BE PROVIDED VIA A ZONE IN’ FREE OF SUBSTANTIAL WOODY VEGETATION Note: Structure type shown in this drawing is for illustrative purposes only and a different design will be used on the Seward project. Source: U.S. Forest Service National Landscape Management Volume 2, Chapter 2, 1975. 4-59 RIGHT-OF-WAY LINE (NOT THE CLEARING MEDIUM SIZED TREES CAN EXTEND INTO THE wy RIGHT-OF-WAY WHERE THEY DO NOT INTER- FERE WITH LINE SWAY AND SAG CITY OF SEWARD TRANSMISSION SYSTEM VARIABLE WIDTH RIGHT-OF-WAY CLEARING EBASCO SERVICES INCORPORATED ue 4.2.3 Routes Identified As a result of project team investigations and coordination with agency and utility personnel, four general conclusions regarding routing alternatives were reached. First, it was concluded that the avalanche hazard for the entire route was high and that there was no cost-effective way to avoid avalanche areas. Instead, it was determined that the best approach was to identify areas where avalanches have occurred more recently, or more frequently in the recent past, and attempt to design the line so that the effect of similar avalanches on the proposed line will be kept to acceptable levels. It must be recognized, however, that Ebasco's efforts to reduce potential avalanche concerns in no way represents an attempt to avoid avalanche effects. Instead, the design effort will weigh avalanche risks and mitigation costs to determine the most cost effective solution. A second important consideration in evaluating the merits of rerouting the existing line is the potential effect on clearing costs. Clearing costs, which can run upwards of $50,000 per mile, depending on the width of the right-of-way to be cleared and type of vegetation present, are an important consideration in determining where an existing line should be rerouted. There is a distinct cost advantage if the existing right-of-way can be followed, as the amount of new right-of-way clearing required would be substantially reduced. A third important consideration is the effect that rerouting the line will have on project schedule. Forest Service and other agency personnel have indicated that obtaining all the permits required for the proposed line will require less time if the existing right-of-way is used. Since the proposed project cannot afford lengthy permitting delays if construction is to occur in 1984, effects of permitting must be seriously considered in evaluating specific routing alternatives. 4-60 4782B wa Finally, the need for routing alternatives could be lessened if steps could be taken to reduce non-scheduled maintenance activities. The single most important step to reduce such maintenance activities would be to improve clearing practices. Increasing clearing widths and thereby decreasing the frequency of problems caused by trees falling onto the transmission line improves the line's reliability while avoiding other costs and other problems associated with rerouting the line. In light of the considerations discussed in the preceding sections, it was concluded that the best approach was to identify specific routing options to avoid areas where maintenance problems have been most severe. The specific areas where routing alternatives have been identified are described separately below. Comments received as a result of reviews of this report and at public meetings in Seward and Moose Pass will be considered in finalizing the routing of the proposed transmission line. 4.2.3.1 Parallel Highway One solution considered was relocating the proposed transmission line so that it would be adjacent to the highway for its entire length. This solution would minimize or eliminate access related problems, but would also cause other concerns. Disadvantages associated with a route located along the highway include significant environmental effects, primarily to the visual resource, and associated permitting difficulties. Along with environmental concerns, there are engineering disadvantages associated with a route located along the highway for its entire length. 4-61 47828 va r The two important environmental considerations are visual impact and permitting. The Seward and Sterling Highways are recognized for their scenic quality by both the State of Alaska and the U.S. Forest Service. Realigning the transmission line so that it would be adjacent to these highways would produce signficant impacts and the likely requirement that a full environmental impact statement be prepared. In addition, obtaining a right-of-way permit from the U.S Forest Service and the Alaska Department of Transportation and Public Facilities would be difficult and time consuming, given the controversial nature of such a realignment. Engineering concerns include the fact that a line adjacent to the highway could not be as straight as the existing line, thereby increasing the number of angle points in the line. Angle points (the term used to describe places along the transmission line route where the line turns, instead of going straight ahead) are costly because of the additional guying required to support the added loads on individual structures. Such guying might also require the installation of overhead guys, which include extra poles and associated hardware. Further, locating the line along the highway for its entire length may also decrease the line's reliability, due to the fact that the line would be more subject to damage from vehicles. However, Ebasco is currently investigating the use of right-of-ways controlled by the Alaska Department of Transportation and the Alaska Railroad in specific areas. The advantages of using sections of their right-of-way will be evaluated on an individual basis. 4.2.3.2 Tern Lake Avalanche Zone North and east of Tern Lake, near the junction of the Sterling and Seward Highways between mileposts 33 and 36 (see Figure 4.2-1), the present transmission line corridor crosses a series of avalanche paths and chutes representing a hazard zone about two and one-half miles in 4-62 4782B "= iu length. West of the avalanche hazard area the transmission line traverses steep but relatively stable slopes of talus, bedrock and glacial till and to the east the corridor crosses low hazard fluvial fans and glacial drift. Within this zone several of the avalanche paths are vegetated by shrubs and brush indicating the recency of activity and probably a shorter recurrence interval than adjacent and intervening areas which are characterized by young aspen. Soils in the avalanche hazard portion of the corridor consist of coalescing mixed colluvial and fluvial coarse-grained fan debris, with several exposed bedrock ribs or buttresses. Upslope of the fans are slightly incised, approximately 40 degree bedrock slopes. The bedrock ribs or buttresses which subdivide the upper portion of the colluvial and fluvial fan slopes act as avalanche control structures, deflecting some of the snow masses onto the fans, thereby forming somewhat protected areas in their lee sides. Several options are available to minimize the impacts of this avalanche hazard zone. Placement of transmission line poles immediately below the bedrock buttresses may decrease their avalanche exposure. Hazards May also be incrementally decreased by moving the transmission line corridor downslope, closer to or south of the Seward Highway (see Figure 4.2-8), although visual impacts may be increased. Another mitigation technique which is feasible at this site is burial of the 24.9 kV backup line should such backup be implemented. Realignment of the corridor to the south of Tern Lake would decrease the avalanche hazard, as only one large avalanche zone would have to be spanned instead of several. There would, however, be trade-offs in that visual impacts would be increased, new permits would need to be obtained, and construction and maintenance would take place a greater distance from the highway. 4-63 4782B ; A CITY OF SEWARD oe AS = TRANSMISSION SYSTEM SPECIAL INVESTIGATION SITE TERN LAKE AVALANCHE AREA = bee 4.2.3.3 Upper Trail Lake Muskeg Area The Upper Trail Lake muskeg area is located between Line Mile 32-34 and just to the west of the Upper Trail Lake fish hatchery. This area has been identified for potential alignment change due to accessibility concerns for maintenance of the transmission line during summer months. The existing transmission line traverses a muskeg area at the Carter Creek inlet and along Moose Creek. Soil types can be characterized as organic and floodplain materials overlying lacustrine deposits. Upper Trail Lake is located generally to the east of the proposed re-route area and the lower slopes of L.V. Ray Peak are to the south. A relatively large alluvial fan which shows evidence of recent avalanche activity occupies the lower slope of L.V. Ray Peak. A proposed alternative to the existing transmission line alignment is a new alignment on the southern edge of the Seward Highway right-of-way (see Figure 4.2-9). The present alignment will pose serious engineering concerns, because the taller and heavier poles for the proposed line will require special design considerations and lateral support systems due to the relatively low strengths of the organic and lacustrine deposits. Realignment along the road right-of-way would help avoid the muskeg area and would not significantly increase visual impacts since the area already has man-made development. Realignment to the south (the lower slopes of L.V. Ray Peak) would also help avoid the muskeg area, although rerouting in this direction would increase the proximity to the avalanche prone area. 4.2.3.4 Kenai Lake Avalanche Area The Kenai Lake avalanche area is located at approximately Line Mile 21.9, about 3.8 miles north of the Snow River bridge (see Figure 4.2-10). This area has been identified for potential alignment change or special design due to damage incurred by past avalanching events. The present alignment was moved from the original location after poles were taken out by a recent avalanche. 4-65 4782B YAS YH CITY OF SEWAR TRANSMISSION SYSTEM SPECIAL INVESTIGATION SITE ==aem=e EXISTING TRANSMISSION LINE =e=— POSSIBLE REALIGNMENT ame SEWARD HIGHWAY UPPER TRAIL LAKE MUSKEG AREA JOate ocroser i963 | riguee 4.2-9 | el oo 3 Tre A EBASCO SERVICES INCORPORATED ==ame EXISTING TRANSMISSION LINE ° , TRANSMISSION SYSTEM mee POSSIBLE REALIGNMENT ——— SEWARD HIGHWAY SPECIAL INVESTIGATION SITE KENAI LAKE AVALANCHE = ds Soils consist of avalanche deposits and granular alluvial fan material. The lower portion of the avalanche track is covered with low vegetation bordered by deciduous trees to the north and south. Records indicate that in April of 1959 the highway, which is downslope of the transmission line, was blocked by an avalanche. Highway traffic was also affected by avalanching during the winter of 1980 when an avalanche took out a guard rail west of the highway and ran into the lake (State of Alaska, Department of Natural Resources, 1982). Avalanche mitigation for this area could include two different design concepts. One concept would be an underground segment of the 24.9 kV line leaving the 115 kV line above ground with adequate pole separation to span the most recently active portion of the avalanche runout zone. Trenching for the underground line segment should pose few problems because of the granular, well-drained characteristics of the avalanche/alluvial fan material. Bedrock is not anticipated within the depth of excavation. The second design option is to relocate the transmission line further down-slope and to selectively place poles on either side of the most active portion of the avalanche runout zone, thus spanning most of the problem area. Furthermore, pole placement on the south end of the avalanche zone could take advantage of a bedrock knob located directly upslope of the proposed alignment. This feature would act as a diversion structure, thus diverting the major impact of an avalanche to either side of the pole. Soil conditions and groundwater should not pose any construction or maintenance problems to either of the design options considered. 4.2.3.5 Snow River Crossing The Snow River transmission line crossing is located at approximately Line Mile 25.7 and lies at the extreme southern tip of Kenai Lake where Snow River enters into Kenai Lake (see Figure 4.2-11). This area has been identified for potential alignment change or special design due to the long span of the center channel of Snow River, extreme winds, and past avalanching and mud slides on the lower slopes of Sheep Mountain. 4-68 4782B meee EXISTING TRANSMISSION LINE -| «eae POSSIBLE REALIGNMENT SEWARD HIGHWAY CITY OF SEWARD TRANSMISSION SYSTEM ~ =~ SPECIAL INVESTIGATION SITE fe!) ‘is . ee SNOW RIVER CROSSING Mh SV CTOBER 1985 V noV' POate OCTO ! [rigyme 4.2-11 | EBASCO SERVICES INCORPORATED ae Exposed bedrock and glacial till over bedrock was observed on both east and west sides of the flood plain. Soils across the floodplain itself consist of finer floodplain deposits of glaciofluvial outwash material. Currently, the transmission line spans approximately 1000 feet of the center channel of Snow River just upstream from the highway bridge. Guyed, wood H-frame structures are situated behind Department of Transportation (DOT) constructed river training structures for protection from flooding. Several design options have been considered in order to reduce the potential of failure due to geologic hazards. One concept would be to Maintain the existing alignment, but replace the existing wood H-frames with steel towers over the center channel. Although the tower foundations must be properly designed for subsurface conditions and adquate protection from flooding must be maintained, this option does not present any major geotechnical concerns. The second design option is to relocate the transmission line to the north side of the highway right-of-way across the entire floodplain. This realignment was considered in order to mitigate potential avalanche hazards along Sheep Mountain. This alternative would also improve the position of the transmission line with respect to flooding, but it might reduce the quality of the view of Kenai Lake. 4.2.3.6 Golden Fin Trail Muskeg At approximately Line Mile 11.5, the present transmission line traverses a muskeg area, which could restrict vehicular travel and maintenance of the line during summer months (see Figure 4.2-12). The muskeg is elongate with a north-south axis and lies in a small depression scoured into bedrock by glacial action. To the west a steep predominately bedrock slope rises from the muskeg and to the east there is a moderately sloping glacial till over bedrock slope. Golden Fin Hiking Trail (U.S. Forest Service) passes through the muskeg. 4-10 4782B i f Ws \ / P 5 yli " LOAN Lt ae ba The transmission line currently has several poles located in the muskeg and each of the poles has a triangular wooden brace system. Also, several poles are in a creek. These poles stand very straight, indicating that the soils and brace supply adequate bearing strength and lateral support. The present alignment is not thought to have geotechnical problems, although the taller poles of the proposed line will require special design consideration and a lateral support system. Realignment to the east by several hundred feet would avoid the muskeg and the associated access problems but it would increase the number of angles, require additional clearing in a new corridor and may increase visual impacts. 4.2.5 Seward and Daves Creek Substation Area Revisions In the vicinity of the Seward Substation a routing alternative has been identified which would shorten the line and eliminate an expensive angle point. This alternative, shown in Figure 4.2-13, enables the proposed alignment to avoid paralleling the Seward Highway south of the airport. The proposed alignment would not affect the portion of the route which crosses the approach to the Seward airport. The alternative shown in Figure 4.2-13 would be less costly and would slightly reduce visual impacts to travelers on the Seward Highway compared to following the existing line. The Daves Creek Substation is located adjacent to Quartz Creek and has been exposed to flooding in recent years. The highway department maintains a berm adjacent to Quartz Creek to channel the flow so that the channel does not cut a new course which would undermine the Sterling Highway. Additional protection would be required upstream from the existing Highway Department flood control berm in order to ensure the protection of the Daves Creek Seward Substation from flood damage. It would also be possible to protect the substation site itself from flooding activity through the installation of some type of protective barrier (e.g., gabions) or elevating the entire substation pad. Another alternative would be to relocate the Daves Creek Substation to a point further north of the existing line and then 4-12 4782B ALTERNATIVE SUBSTATION = 7 maee EXISTING TRANSMISSION LINE mee POSSIBLE REALIGNMENT SEWARD HIGHWAY oper it tf fat { +e ela : ein ped: Vid ' a a ‘ \ \ t KS \ ‘ ’ ay M CITY OF SEWARD SEWARD AND DAVES CREEK SUBSTATION AREA REVISIONS SV AOATE dF iGure 4.2-13 | ry EBASCO SERVICES INCORPORATED J connect a new transmission tap to the new substation. Figures 4.2-13 and 4.2-14 show possible sites for relocating the substation and transmission tap required to interconnect with the Seward transmission system. The primary disadvantages of relocating the Daves Creek Substation involve the increased costs associated with grading and developing a new substation site, as well as the additional cost associated with clearing a new transmission line right-of-way. Environmental affects will be analyzed in more detail in the environmental analysis which will accompany the permit application to the Forest Service, but in general, the proposed relocation of the substation to the site shown in Figure 4.2-13 would only increase impacts slightly as a result of the proposed access road's construction. Impacts from the substation and transmission line would be minimal and could actually result ina reduction in impacts if the new and existing systems were consolidated. Relocating the substation to the site shown in Figure 4.2-14 would likely increase visual impacts to travelers on the Seward Highway (because of the required new transmission tap) while not altering existing visual impacts on the Sterling Highway. 4.3 OTHER ALTERNATIVES Although Ebasco spent most of its effort evaluating overhead lines within the existing transmission line corridor between Daves Creek Substation and Seward, there are other alternatives for meeting the City of Seward's transmission needs. Alternatives available to the City include construction of a transmission line from the Cooper Lake Hydroelectric Project east and then south toward the existing line near the point where it crosses the Snow River. The city could also construct underground or submarine lines for major portions of the route. Each of these alternatives is described and analyzed below. 4-14 4782B 7 4 ALTERNATIVE / / ° 4 TRANSMISSION SYSTEM SUBSTATION AREA mene EXISTING TRANSMISSION LINE REVISIONS =o— POSSIBLE REALIGNMENT SEWARD HIGHWAY [pate] FIGURE 42-14 EBASCO SERVICES INCORPORATED =~ _— sa = Le 4.3.1 Cooper Lake-Seward Transmission Line Ebasco was requested to examine the viability of constructing a transmission line from Chugach Electric Association's Cooper Lake Hydroelectric Project to Seward. This alternative was to be addressed early in Ebasco's investigations so that a decision could be made whether to shift the focus of design activities to this alternative, as compared to an alternative near the existing line from Daves Creek Substation to the City of Seward. A line from the Cooper Lake Hydroelectric Project to Seward would proceed east along the south shore of Kenai Lake toward Black Mountain and then south toward the existing line near the point it crosses the Snow River. The general corridor is shown in Figure 4.3-1. Specific advantages and disadvantages, as well as a conclusion regarding the merit of this route, is presented below. 4.3.1.1 Advantages Constructing a line from the Cooper Lake Project to Seward would have the advantage of reducing the overall length of transmission line required on the project. A line from the Cooper Lake Project to Seward, as compared to a line from Daves Creek Substation to Seward, would reduce the total line length from approximately 40 miles to 30 miles. This reduction in length would reduce the material requirements for the project and would likely reduce line losses. Constructing a line from the Cooper Lake Project to Seward would also strengthen the existing transmission system in that it would provide two routes by which power could be transmitted to Seward. This offers the advantage that in the event that one line were out of service (e.g., from avalanche damage) the other line would still be able to serve the City of Seward. In general, constructing two lines, instead of one, leads to a stronger transmission system. 4-76 4782B a - g =ia Ww cw 9 o| <2 ra >| Faw [50 laze oO zi jor Zz wog -_ Oj; x az no o| <®e uw Sic o z=. Oo =| ao z/uz2 | lz Qe wi z|Q¢ on ro Ped El} o 9 ” < a Ww Wes: i (7 : ci a ( Cie NSC) br “i SION. : Z La CONC i} > Zs: Le? « ATM oa mea “3 fam Gnas Er — ~—a © J Po Gag fs <a —_ ‘ i a es 4.3.1.2 Disadvantages The most striking disadvantage of constructing a line along the south and west shore of Kenai Lake results from the fact that area is currently unroaded. Further, as can be observed in Figure 4.3-1, the area is very rugged with steep slopes extending down to the shoreline. Constructing a transmission line along the steep and unroaded slopes would be difficult and costly. Helicopters would likely be required as the construction of a new road into this area would be prohibitively expensive. Staging construction activities would also be costly because it will be difficult to get poles, conductors, and associated hardware close to the right-of-way. Material and equipment could be transported by barge on Kenai Lake, but there are few landing areas on the shoreline of Kenai Lake in the vicinity of where the line would be constructed. The steep slopes which extend from the shoreline inland make even helicopter construction difficult. Maintenance activities will also be difficult to conduct because of the route's remoteness and general topographic conditions. Access would be either by helicopter or barge or, when the lake is frozen, possibly by snow machine or other type of vehicle. Access during winter freeze up and spring breakup will be difficult. More conventional ground access by road is not viable because a new road would be difficult to permit and extremely costly to construct. A review of aerial photographs of the Cooper Lake route reveals that the avalanche hazard is severe along portions of the route. In general, the risk of avalanche danger appears to be quite small for the portion of the route south from Black Mountain toward the City of Seward. For the section of the route between Cooper Lake and Black Mountain, however, avalanche hazards are severe. The area between Cooper Lake and Black Mountain appears to experience large and frequent avalanches. 4-78 4782B Enviromental and permitting considerations also suggest that the Cooper Lake route is less desirable than the existing corridor route. The area beween Cooper Lake and the Snow River is administered by the U.S. Forest Service and has been inventoried as a roadless area. Environmental values are given a high priority in this area, primarily as a result of the scenic quality and unroaded condition. Contacts with Forest Service personnel have confirmed the fact that it would be difficult to obtain a permit for a line in this area when other alternatives exist. If such a permit could be obtained, it would also be subject to a more rigorous environmental review, including the possible requirement for the preparation of a full environmental impact statement. It is also possible that environmental groups opposed to any type of development in the roadless area crossed by the Cooper Lake route would seek to delay the issuance of a right-of-way permit in conjunction with either the Chugach National Forest Planning Process or the specific permitting activities associated with the transmission line planning process. The environmental impacts themselves from constructing a transmission line along the south and west shore of Kenai Lake could also be significant. The area is presently managed to preserve the pristine quality of the area in recognition of the importance of the scenic resource. Viewers on the Seward Highway as well as on Kenai Lake and campgrounds surrounding it would be subject to views of the transmission line which would detract from the area's overall scenic quality. In addition, construction on steep slopes near Kenai Lake could increase erosion and the risk of mass-wasting. Fishery resources with Kenai Lake and adjacent streams crossed by the proposed route could also be an important concern. 4.3.1.3 Conclusions Construction of the transmission line along the Cooper Lake-Seward Route identified in Figure 4.3-1 would be difficult and more costly than construction near the existing corridor. The rugged conditions and unroaded character of the area increase construction problems and 4-719 4782B — overall project costs. Maintaining a line in this area would also be difficult and costly and, given the avalanche potential in the area, it is doubtful that the reliability of a transmission line in this area would be as great as that of a line following the existing corridor. Further, it would be difficult to successfully obtain the required environmental permits to construct a line on the south and west shores of Kenai Lake and it would be virtually impossible to obtain the required permits prior to the 1984 construction season. As a result of the considerations described above, Ebasco recommended to the City of Seward that this alternative not be pursued and the design activities focus on a line between Daves Creek and Seward Substations following the existing corridors. 4.3.2. Underground Transmission Line Option As noted in other sections of this report, the potential for avalanches over most of the transmission line routing is high in the existing corridor, while the opportunity to avoid such areas and eliminate potential avalanche concerns during the design of an overhead line is very limited. Consequently, the alternative of constructing an underground transmission line for the entire route, or at least in the areas subject to severe avalanche damage, was investigated. Two major concerns influence the feasibility of constructing an underground transmission line. First, the voltage of the line greatly influences the type and cost of underground cable which would be required. Second, local conditions affect what installation techniques are practical and cost-effective. Local conditions will dictate whether plowing, trenching, or rock saw equipment would be required to install a cable. The difference in installation costs in rock versus loosely consolidated alluvial material is substantial because installing underground cables in rock will likely require 10 times the amount of time to complete construction as would a section of the line in loosely consolidated material. 4-80 4782B Sooo oes oe ny The voltage of the line is very important in determining material costs because different types of cable are required for different voltages. For distribution and low voltage transmission lines (below 35 kV), the use of underground cables is quite common and cost-effective if ground conditions are favorable. Relatively small flexible cable consisting of either an aluminum or copper conductor insulated with cross linked polyethylene (XLPE) type material is generally adequate. In higher voltage lines (69 kV and above) while solid dielectric insulation is now available, the most experience has been gained with oil-filled cables. Such cables include a copper conductor insulated with oi] impregnated paper and are more expensive and more difficult to install. The terminal facilities required at the endpoints of the underground 011 filled cable sections are also costly. Although the cost of constructing a 69 kV or higher voltage underground transmission line is estimated to be 3 to 5 times the equivalent overhead line, there might be specific instances where an investment in underground cable would be merited. Conditions likely to be most conducive to the installation of underground transmission lines exist in areas frequented by avalanches. In such areas a specific evaluation criteria have been developed (see Section 6.3) to determine if an underground cable should be recommended. Although the economics are generally unfavorable for constructing either a 69 or 115 kV transmission line underground, current plans to maintain the existing 24.9 kV line may offer the opportunity to improve the reliability of service to the City of Seward by constructing portions of the 24.9 kV line underground. Transmission lines with a voltage of 35 kV or lower can be installed much more economically underground than can higher voltage lines. In situations where a 24.9 kV line would be underbuilt on a higher voltage line, such as the case for the line between Daves Creek and Seward Substations, the cost of constructing an overhead line is also generally less because of the savings realized by avoiding the need to install a large number of wood poles. Nevertheless, efforts are being made to identify the areas 4-81 4782B = fara + as — omy om — § s —_—_ — bod ‘ 4 fa FS where avalanches occur most frequently and to evaluate the merit of constructing the 24.9 kV line as an underground line in those areas. As discussed in Section 4.2.3.4, such a situation exists in the identified avalanche chute near Kenai Lake. In that particular avalanche area, it appears that the risk and frequency of avalanches justifies the added expenditure of constructing certain segments of the 24.9 kV line underground. No other such areas have been identified along the route, although in the future, if avalanche damage does occur to the line, consideration should be given to installing the 24.9 kV line underground while leaving the higher voltage primary transmission line above ground. 4.3.3 Underwater Cable Alternative Portions of the Cooper Lake-Seward alternative, as well as the existing corridor route, could avoid avalanche areas, without increasing the overall length of the line significantly, if underwater cables were used. There are several disadvantages, including cost, which make the use of underwater cables infeasible. Generally, underwater cables of a voltage of 69 kV or higher are oi] filled. Such cables are costly and in typical underwater applications cost 5 to 8 times more than similar voltage overhead lines. The cost of an underwater cable installation is dependent on the length of cable and local conditions (e.g., strong currents, rocky bottom, or area where there is considerable activity involving ships anchoring). In addition, the cost of mobilizing the proper cable installation equipment for both operation and maintenance activities is also important in the overall cost. The cost of mobilizing underwater cable installation equipment in Kenai Lake would be very significant. Untike most underwater cable applications, placing an underwater cable in Kenai Lake could not be accomplished with cable laying equipment existing in the area. In most applications, cable laying barges travel to the project area directly with the cable to be installed. These vessels begin operations when 4-82 4782B urea ase cag ee 1 ea rs they reach the location where the cable is to be used. If underwater cable were used in Kenai Lake, cable laying barges would have to be specially constructed so that they could be transported in sections to Kenai Lake and then assembled there. In addition, the cable itself would have to be transported over land to the vicinity of Kenai Lake. The costs associated with transporting the cable laying equipment and cable to Kenai Lake, assembling it there, and installing it would be very high. Once the cable laying operation is complete, it will also be likely that the cable laying equipment will be kept at Kenai Lake. Normally, failures which occur are corrected using cable installation vessels which could travel to an area where there is a need for such activity. Because the cost of removing the cable laying vessel and support facilities would be high, and because it would be very costly to transport a similar vessel back to the project area for maintenance purposes, the most likely approach to be utilized would be to leave the cable laying equipment used to install the cable at Kenai Lake for maintenance purposes. Provisions would need to be made to secure this equipment from adverse weather conditions. In addition, if a cable failure should occur during the winter months, when the lake is partially or completely frozen, it would be very difficult to correct the problem. Therefore, the overall desirability of using an underwater cable to serve the needs of the City of Seward is questionable. For the reasons described above, the underwater cable option is not appropriate for use on the Seward transmission system. 4-83 4782B pornee ea a9 ae more 4 om mam ems — — fia Fea fe ' ~ REFERENCES Alaska Department of Highways, 1963, Avalanche Study, Planning and Research Section: Douglas, Alaska, 41 p. Bolt, B.A., 1973, Direction of Strong Ground Motion: Fifth World Conference Earthquake Engineering, Rome. Campbell, K.W., 1981, Near-Source Attenuation of Peak Horizontal Acceleration. Bulletin of the Seismological Society of America, Vol. 17, pp. 2039-2070. Dooley, D., (Personal Communication). Hartman, C.W. and Johnson, P.R., 1978, Environmental Atlas of Alaska, University of Alaska; Institute of Water Resources, 95 p. Jones, S., (Personal Communication). Joyner, W.B. and Boore, D.M., 1981, Peak Horizontal Acceleration and Velocity from Strong-Motion Records including Records from the 1979 Imperial Valley, California, Earthquake. Bulletin of the Seismological Society of America, Vol. 71, pp. 2011-2038. Kanamori, H., 1977, Seismic and Aseismic Slip along Subduction Zones and their Tectonic Implications, in Talwani, M., and W.C. Pitman, III (eds.): Island Arcs, Deep Sea Trenches and Back Arc Basins, Maurice Ewing Series I: American Geophysical Union, p. 163-174. Kreig, R. and Reger, R., 1976, Preconstruction Terrain Evaluation for the Trans-Alaska Pipeline Project: In Geomorphology and Engineering, D.R. Coates, Ed., Dowden, Hutchinson and Ross, Inc., (Wiley), 360 pp. Krinitzsky, E.L., 1978, Earthquake Assessment at the Susitna Project, Alaska: in South-Central Railbelt Area, Alaska, Upper Susitna River Basin, Supplemental Feasibility Report Hydroelectric Power and related purposes, U.S. Army Corps of Engineers. March, G.D. and Robertson, L.G., 1982, Snow Avalanche Atlas, Seward Highway, Southcentral Alaska: State of Alaska, Department of Natural Resources, Division of Geological and Geophysical Surveys, Professional Report 81, 168 p. 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. Geol. Survey Circular 672, 23 p. Plafker, G., 1969, Tectonic of the March 27, 1964, Alaska Earthquake: U.S. Geol. Survey Prof. Paper 543-1, p. 174. 4-84 4782B nq & R&M Consultants, Inc., 1982, Grant Lake Hydroelectric Project Interim Geotechnical Report; Prepared for Ebasco Services Incorporated. Sykes, L.R., et al., 1981, Rupture Zones and Repeat Times of Great Earthquakes along the Alaska-Aleutian Arc, 1784-1980: in Earthquake Prediction, An International Review, D.W. Simpson and P.G. Richards, AGU. Maurice Ewing Series 4. pp. 73-80. Tysdal, R.G., and Case, J.E., 1979, Geologic Map of the Seward and Blying Sound Quadrangle, Alaska. U.S. Geol. Survey Map 1-1150, 1:250,000. U.S. Department of Interior; Geological Survey, 1975, Flood-Prone Areas of Seward, Alaska, unpublished map (also in pamphlet form). Woodward-Clyde Consultants, 1981, Report on the Bradley Lake Hydroelectric Project Design Earthquake Study. Submitted to U.S. Department of Army, Corps of Engineers. 4-85 4782B Tea es mes & se | Poe PS Ss om es DAVES CREEK JISKV Sky UNDEBUILD i 4/0 AWG Md f ' ‘ 44 / Ci ! ' ' 4OMILES soeod 336 KCMIL @iisky 2.5 MILES 6 KCMIL 4mMiLES NieKy Ree USKV a hee - 1 SKV ' SEWARD lI5KV oce 3SMVA SKY 12004 USKV | 3 15 KV 1200A WSKV 1200A CIRCUIT SWITCHER CIRCUIT SWITCHER Ea CARCUIT SWITCHER ciRcuIT SWITCHER 25/103 MVA 75/10.5 MVA 75/105 My¥A— 75/105 MVA U5 :125Kv 16 s125KV U5 2125 KV US S125 KV OT Se FUR LTC | WTO 36 xeMR LTC ( i 36 XFMR LTC fen ONE LINE DIAGRAM ALTERNATIVE 1 Bats OCTOBER 1963 [FiGuec 4i-1 | EBASCO SERVICES INCORPORATED 4-86 1.0 70° 6.6 115kV 0.96 /-1.7° Gs rd ( s ) Seward 10.2 All 115 kV System. ACSR Conductor: 226 kCMil, Except 336 kCMil for the last 4 Miles to Marine Industrial Park. Tap: 1 4.9 City 4-87 12.47kV_ 9 93 52° 0.96 /-1.8° Tap: 1 12.47kV ° Marine Industrial Park LOAD FLOW CASE 1-A Oats OCTOBER 1983 [Figuac 4i-2 ist EBASCO SERVICES INCORPORATED |" a Ss Fs eo ee & a ame —pammeng Ea SO es City All 115 kV System. ACSR Conductor: 336 kCMil 4-88 1.0 70° 0.97 /-1.8° Tap: 1 L2ATH 9 94 725, 2° 0.97 /-1.9° 4.9 Tap: 1 I2ATRV 9 95 7.4.09 Marine Industrial Park CITY OF SEWARD LOAD FLOW CASE 1-B Dats OCTOBER 1983 [Figure 4.)-3 | EBASCO SERVICES INCORPORATED row 115 kV System. ACSR Conductor: Daves Creek to Seward 397 kCMil, Seward to Marine Industrial Park 336 kCMil. 4-89 0.97 /-1.8° 0.97 /-1.9° Tap: 1 12.47kV 0.95 7=4.1° Marine Industrial Park LOAD FLOW CASE 1-C Batt OCTOBER 1983 [Figume 4.1-4 | EBASCO SERVICES INCORPORATED ee e=3 foe Pa FS SS oes es ooo ms coal onary = wae et All 115 kV System. ACSR Conductor: Creek to Seward 477 kCMil, Seward to Marine Industrial Park 336 kCMil. Daves 4.9 4-90 0.97 /-1.8° 0.87 /-2.0° Tap: 1 12.47kV ° 0.95 /-4.1 3.1 Marine Industrial Park LOAD FLOW CASE 1-D Date OCTOBER 1963 [Ficuac4.i-5 | EBASCO SERVICES INCORPORATED EF 3 Sa ” pose & +s mex 3 ome rs on 4 a3 uSKV ie DAVES CREEK NISKV QA oce feMiLes SKV UNDERBUILD { 4/0 AWG ek ILTE® ' 1 —— DAVES | CREEK 25KV 1 ‘ ’ f / j = 40 MILES f H BSS KCMIL ACSR ' ! WEKY 7 } ! aes" —— | Sey ONDER BU LD H avo Awe 25 MILES 36 KCMIL ACSR 69KV 4MILes 36 KCMIL ACSR _ oo BSR s MA \ 25/12.5KV 1 SEWARD 1ISKV ure 6°KV 69KV CIRCUIT CIRCUIT SWITCHER SWITCHER 69/I25KV 69/125KV THOS 7.5/94/105 av wWVA | 3 irc LTc MARINE _ | pec naa PARK | CITY OF SEWARD ONE LINE DIAGRAM ALTERNATIVE 2 Date OCTOBER 19863 [Ficume4i-6 EBASCO SERVICES INCORPORATED SKY uskV CIRCUIT SWITCHER CIRCUIT SWITCHER 36 SKY 36 UISKV aye MVA 12/te MVA ie aes] ee A Pre = ene : ‘ he | A eee eos | ZENS 4-91 usSKV OCB 1200A US ky OC! \2004° ~ DAVES CREEK IISkV ! pet | | | ! 16 MILES , KV UNDERBUILD t on whe, (NY ' — 3, -PAVES J CREEK 25Ky __ 1 ' Kh ( Is ( bys ' ' t ( s 25Kv for ocR aaah 24 MILES 25KV UNDERBUILD #4/0 AWG Caco 12s UI J SWITCHERS fz Seen 12/1@MVA oY 4mices MIBK 5 6OKV $6 KCMIL 3B.AUTO XFMRS 69 KV W/TERTIARY eran ae Ge > wry ' CIRCUIT 1 SWITCHERS 25KV i SEWARD 69K | | | ' i i SMVA | | 5 69KV wb SYK. 2s: 125Kv 62KV 62K ad : CIRCUIT SWITCHER FT CIRCUIT SWITCHER 39 XFMR LTC CIRCUIT SWITCHER egincuin, ! ' | t cad, 75/105 MVA cali, 25/105 MVA 7.5/ 10.5 HVA 75/105 MVA 69KV: IZSKV 69KV 21Z5KV 9 KV 212 5KV 6IKVIIZSKV - I “sp xeMRitc y 36 KEMR LTC SB XEMR Uc 3@ XFMR LTC ’ ‘ s ‘ MARINE ee EE SEWARD LIZ'S Kyo eee pon OR {2.5KV | INDUSTRIAL PARK CITY OF SEWARD ONE LINE DIAGRAM ALTERNATIVE 3 Gate OCTOBER 1963 [eiguac4.i-7 | EBASCO SERVICES INCORPORATED 4-92 mm my \ wt ee] 2 a EM ere tra 10.2 All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR Conductor: 226 kCMil Except 336 kCMil for the last 4 Miles to Marine Industrial Park. 4-93 0.95 /-3.2° 0.93 /-4.9° Tap: 1 12.47kV 0.91 /-7.2° 3.1 Marine Industrial Park LOAD FLOW CASE 3-A Gate OCTOBER 19863 EBASCO SERVICES INCORPORATED ea ET? Cc by a em, “> Eo —— All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. Daves Creek 115kV 1.0 70° 0.95 /-3.3° 0.92 /-6.9° 0.95 /-3.6° 4.9 Tap: 1 12.47kV 0.93 /-5 8° 3.1 Marine Industrial Park CITY OF SEWARD TRANSMISSION SYSTEM LOAD FLOW CASE 3-B Batl OCTOBER 1983 FiGume 41-9 EBASCO SERVICES INCORPORATED 4-94 — “ a k Daves Creek 115kV 1.0 10° 0.97 /-1.8° Tap: 1 0.95 /-3.3° 0.92 /-6.9° 0.95 /-3.6° aoe Tap: 1 12-47kV_ 9.93 /-5.8° 3.1 Marine Industrial Park LOAD FLOW CASE 3-C Gate OCTOBER 1983 [Ficume 4.1-10 | EBASCO SERVICES INCORPORATED All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR Conductor: Daves Creek to Seward 397 kCMil, Seward to Marine Industrial Park 336 kCMil. 4-95 puprenen, osm G3 feu Daves Creek 115kV All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR Conductor: Daves Creek to Seward 477 kCMil, Seward to Marine Industrial Park 336 kCMil. Tap: 1 Tap: 1 0.97 /-1.8° KY 0.93 /-6.9° 4-96 0.96 /-3.4° 0.95 /-3.6° Tap: 1 12.47kV 0.93 /-5.9° 3.1 Marine Industrial Park CITY OF SEWARD TRANSMISSION SYSTEM LOAD FLOW CASE 3-D Dati OCTOBER 1985 [Ficvac 4.1- | EBASCO SERVICES INCORPORATED i { is ry Goa = 4 | og "uSKV OCB ISKV OCB 1200A DAVES CREEK IISKV % oO leMILES 25KV UNDERBUILD i # 4/0 AWG svadas TN: See lkenic lor Sisk EASE LCREEK 25KV ' ih ' ot sky ( ue CIRCUIT ' | SWITCHERS ! | —— 12/16/20 MVA HISKV 2 69KV 3 AUTO KFMRS 25 KY UNDERBUILD 69Kv CIRCUIT # 4/0 ANG SWITCHERS, J | Z5MILES LAWING | 336 KoMIL eoKV | Oo ! S8e Kone 24 MILES eajoacsR ? [ isk EXISTING 1! --- ----4 ' ' ( 25Kv | _-Sewanp 6amy i _ ' ' VA | "S 69KV ‘Sh 69K SEY sav canv eoKy Y CIRCUIT SWITCHER 7 CIRCUIT GWITCHER 30 XPMR CIRCUIT SWITCHER CIRCUIT ! t tte SWITCHER ' 75/105 MVA : 7.5/10.5 MYA 15/10 5MvA 15/10. MVA Sahar 6912.5 KV tadas 69: 12.5KV 69/212 5 kV S25 KV CVYY) 3g XEMR (VYY) 36 XFMR 3¢_XFMR ; vTe , Lte ( utc ute \ | \ \ MARINE \ ‘ ' ' ___j_ SEWARD I25Kv_ | | r2sxy| wousTRiAL_PaRK _| CITY OF SEWARD ONE LINE DIAGRAM ALTERNATIVE 4 Oats OCTOBER 1963 [Figuac4i-i2 EBASCO SERVICES INCORPORATED 4-97 3 rae: & eS ES cs FS &" FS es Ss SKY OCB 1200A uSKV OCB 12004 DAVES CREEK IISKV SKY OCB 1200A 4 (@mMILES 25KV UNDERBUILD # 4/0 Awe sada yy 16 MILES 1 336 KCMIL @ sky / , WKY { T cIRCU ' SMITCHERS { ! | 12/16 VA LAWING UBEV69KY 3G AUTOXEMRS —!ZSKV U5 KY | - 24 MILES CIRCUIT | SWITCHERS se ab ~ | Z5MILES ! S36 KCMIL ! 4MILES 24MILES j 336 KCMIL R4/0 ACSR | EXISTING EXISTING = | -|---- -#---= \ 7 i 1 | ( ' | SEWARD 69KV L ! — SEWARD 69K t ' ' | 4 69KV 4 69kV 69KV 69KV a WITCHER IRCUIT SWITCH ! IRCUIT SWITCHER CIRCUIT 7 CIRCUIT SMITCHE! ~ CIRCUIT SWITCHER | ¢ gikcur 1 1 | 1 Li, 73/105 MVA 1 -25/10.5MVA 7.5/10.5 MVA 75/10 5MVA sodaz Bae ey sphes Se Bey | 69KV"I25KV 69 kv. i2.5KV if BG xEMR UTC | YT) 36 XFMR LTC i 36 KFMR LTC 3 KFMR t ' \ . ' MARINE ‘ . ' s _j__sewarpi2snv _ | , skv| woustaiar park _| ONE LINE DIAGRAM ALTERNATIVE 6 Sate ocToser 1963 [ricuac 41-13 | EBASCO SERVICES INCORPORATED 4-98 mq u Sead 115 kV Daves Creek to Lawing, 69 kV Lawing to Marine Industrial Park. ACSR Conductor: 336 kCMil Daves Creek to Lawing and Seward to Marine Industrial Park: Existing 4/0 AWG Between Lawing and Seward 1.0 70° fs 0.98 /-0.7° Tap: 1 S9kV 9 97 /-2.3° 4-99 0.87 /-5.1° 0.86 /-5.4° Tap: 1 -84 /-8.1° LOAD FLOW CASE 4&6 Gate OCTOBER i965 EBASCO SERVICES INCORPORATED 4 eae oy t 9 NSkV ocB 12008 USKv OCB (200A OAVES CREEK JNISKV 16MILES 25KV UNDERBUILD : # 4/0 AWE Reis NYS ' 12/16 MYA — DAVES {CREEK 25KY UBS 69KV 1 30 AUTO XFMRS ' 6.9KV CIRCUIT SWITCHERS ( Ta 1 \ | 1 ' L----4 24 MILES Z5KV UNDERBUILD @ 4/0 AWG 2.5 MILES 336 KCMIL ACSR @ 69Kv 4@MiLes 36 KCMIL ACSR é9KV ----5 ( | 25KV K—— sano cow FUL oe t 62KV "¢ e9Kv geva 69KV 7 CIRCUIT SWITCHER — y* CIRCUIT SWITCHER 38 eur Ure een SWITCHER giecu iT i i 15/105 MVA Ly 75/105 MvA HA Ne sede SURVEIZB KY RRP GORY LIZ SKY Bageey ge KY 1 36 XEMR LTC Y XPMR LTC 3@ XFMR LTC Se xeuR ' : ( ‘ MARINE ! ' — t_ SEWARD 125KV 0 jo PS | 25xv| INDUSTRIAL PARK | ONE LINE DIAGRAM ALTERNATIVE 5 Gate OCTOBER 1985 4-100 CITY OF SEWARD TRANSMISSION SYSTEM EBASCO SERVICES INCORPORATED tro a <2 oo om oa — All 69 kV System. ACSR Conductor: 336 kCMil. 4-101 0.87 /-6.4° 0.87 /-6.8° Tap: 1 12.47kV o 85 /-9.5° 3.1 Marine Industrial Park CITY OF SEWARD TRANSMISSION SYSTEM LOAD FLOW CASE 5-A Gate OCTOBER 1983 EBASCO SERVICES INCORPORATED = = pemenly ¢ a — Se? Go f= es ey All 69 kV System. ACSR Daves Creek to Seward 556 kCMil, Seward to Marine Industrial Park Conductor: 336 kCMil. 0.9 / 6.6° 69kV 0.87 /-10.7° 0.89 /-6.9° 10.2 4.9 Tap: 1 12.47k v0.87 /-9.5° 3.1 Marine Industrial Park LOAD FLOW CASE 5-B 4-102 CITY OF SEWARD TRANSMISSION SYSTEM Gate OCTOBER 1983 [Figume 41-17 | EBASCO SERVICES INCORPORATED os coal ou 8 F a t a rr 0.88 /-10.5° 4.9 All 69 kV System. ACSR Conductor: Daves Creek to Seward 795 kCMil, Seward to Marine Industrial Park 336 kCMil. 4-103 0.91 /-6.6° 9 /-6.9° Tap: 1 0.88 /-9.4° Marine Industrial Park CITY OF SEWARD TRANSMISSION SYSTEM LOAD FLOW CASE 5-C Gatr OCTOBER 1983 Figure 4.18 EBASCO SERVICES INCORPORATED 0.91 /-6.6° 0.91 /-6.9° Tap: 1 12ATKV 9.89 /-9.4° 3.1 Marine Industrial Park All 69 kV System. ACSR LOAD FLOW Conductor: Daves Creek to Seward 954 kCMil, CASE 5-D Seward to Marine Industrial Park 336 kCMil. Sats OCTOBER 1963 EBASCO SERVICES INCORPORATED 4-104 =e —— — a ma onan A maaan All 69 kV System. ACSR Conductor: Daves Creek to Seward 1272 kCMil, Seward to Marine Industrial Park 336 kCMil. 4.9 0.92 /-6.5° 0.92 /-6.8° 0.89 /-10.3° Tap: 1 12.47kV 0.90 /-9.2° 3.1 Marine Industrial Park LOAD FLOW CASE 5-E Dati OCTOBER 1985 [FiGuac 41-20 | EBASCO SERVICES INCORPORATED 4-105 ee om -_ a i f. a rs . an All 69 kV System. ACSR Conductor: Daves Creek to Seward 1590 kCMil, Seward to Marine Industrial Park 336 kCMil. 0.89 /-10.2° 4.9 4-106 Tap: 1 12.47kV Marine Industrial Park LOAD FLOW CASE 5-F Gartc OCTOBER 1983 EBASCO SERVICES INCORPORATED mew fa Cad CAN SS FSR Se foe me worm pmo oxen oe Peon t ‘ 54 b t t CHAPTER 4 APPENDIX we me = — Existing Transmission Line Corridor ‘ ee ee eee es POSSiDle Realignment Corridors (approximately located) ba Prepared By: { | ~ R&M CONSULTANTS, INC. ENGINEERS GEQLOGISTS PLANNERS SUMvVEYORS CITY OF SEWARD SPECIAL INVESTIGATION SITE UPPER TRAIL LAKE MUSKEG AREA foATE OCTOBER 1963 [Ficume EBASCO SERVICES INCORPORATED FIGURE < Ww « < 0 o a « w o | e oO ° wo . < a CITY OF SEWARD o | le = < a|r oO a Flo Z@ 9 Yiz< & a Oo “lE«< oO Z2i°oc> z 3/8 aa |g w 2) 2 vals a\2< & z|22 ie a|# z [Fo a wi % Fee De Nps ty if PLANNERS SURVEYORS ——w «ewe Fxisting Transmission Line Corridor —eme em’ Possible Realignment Corridors (approximately located) REM CONSULTANTS, INC. Locist teaver: Prepared By: ENGINEERS GEQLOGISTS io Ro LS dierent ere dE errr tet em cereal nd end eed “a or er | Eo oI OSs es oe ('T. FS FSS fe GS Prepared By: R&M CONSULTANTS, INC. ENGINEERS GECLOGISTS SL ANNEMS SUMVEYORS CITY OF SEWARD TRANSMISSION SYSTEM SPECIAL INVESTIGATION SITE GOLDEN FIN TRAIL MUSKEG DATE OCTOBER 1983 [Figure EBASCO SERVICES INCORPORATED EVALUATION CRITERIA in 5. EVALUATION CRITERIA 5.1 SYSTEM PERFORMANCE CRITERIA In evaluating a transmission system, two major criteria have to be considered. First, the voltage drop of the system cannot exceed certain limits. Second, the losses of the system have to be determined and their capitalized costs have to be calculated over the useful life of the project. The one line diagrams of those systems are shown in Figures 4.1-1, 4.1-6, 4.1-7, 4.1-12, 4.1-13, and 4.1-15. For each alternative only the 115 or 69 kV section of the system was considered and variations in the underbuilt were ignored. The criterion for maximum allowable voltage drop between the Daves Creek 115 kV bus and the 12.47 kV buses in Seward was set at 12%. This was based on the following: A standard LTC transformer has +16 steps each 5/8%, which means that it can cover a +10% or a total of 20% voltage range. Chugach Electric could not give information regarding the voltage variations at Daves Creek. Assuming that the latter will be approximately +4% in 2014 or, in other words, a total span of 8%, it can be concluded that a 12% drop between the 115 kV and 12.47 kV buses is acceptable. This means that in worst case the total voltage variation is 20%, which equals the Maximum variation the LTC can compensate in order to maintain constant voltage on its secondary. Seen from this point of view, only Alternatives 1, 2, 3, and 5 are acceptable, as already hinted in Section 4.1. 48148 The next items to be considered are the losses. Losses can be separated into two categories. First, there are the losses which are independent from the load. These are mainly the transformer no-load or iron losses. These losses were determined from manufacturers' data and the conclusion was reached that for the two winding transformers 0.15% of the self cooled rating of the transformer can be considered a good average value. For the 115/69 kV auto transformers, the no-load losses are about 0.1% of their self cooled MVA rating. The second group of losses are variable and are, essentially, proportional to the square of the load. The losses associated with the transmission lines were obtained from the load flow computer printouts. The losses for the transformers were, again, estimated from manufacturers' data. For the latter, it was concluded that in the transformer sizes involved in this study, 0.8% of the self cooled name copper losses.’ The same loss for the 115/69 kV auto transformers is approximately 0.2%. It should be noted that each transformation is comprised of two parallel operating transformers. The method of calculating the annual losses is presented in Table 5.1-1. First, three load factors are calculated, one for the city's load, another for the Marine Industrial Park's (MIP) load, and a third for the total load. The city's load affects only the losses of the 115/12.47 or 69/12.47 kV transformers. 4814B 5-2 ba i The Marine Industrial Park's load affects the losses of the transformers at the MIP Substation and the line between the Seward Substation and the Marine Industrial Park. The total load affects the losses in the line between Daves Creek and Seward, the 115/69 kV auto transformers, if any, or the three winding transformers at the Seward Substation in Alternative 2. From the load factors the corresponding loss factors are calculated using the REA formula. The actual yearly losses are calculated by adding the constant losses to the variable losses and multiplying by the total number of hours per year (8,760) as given by the formula presented at the bottom of Table 5.1-1 . The calculated losses for the 2014 moderate peak loads are shown in Tables 5.1-2 through 5.1-16. The values developed in the table can be used directly for inclusion into the formula in Table 5.1-1. The dollar value of these losses for each year is shown in Tables 6.2-1 through 6.2-3 for Alternatives 1, 2, and 3. 48148 5-3 | eet TABLE 5.1-1 METHOD OF CALCULATING ANNUAL LOSSES Load Factor Calculation: (LdFC) = (MWh/year City) (MW peak City) x (8760) (MWh/year MIP) (MW peak MIP) x (8760) (LdFP) (LdFT) = (MWh/year City + MWh/year MIP) (MW peak City + MW peak MIP) x (8760) Loss Factor Calculation: (LsFC) = (0.16) x (LdFC) + (0.84) x (LdFc)? (LsFP) = (0.16) x (LdFP) + (0.84) x (LdFP)2 (LsFT) = (0.16) x (LdFT) + (0.84) x (LaF)? Calculation of Annual Losses: 2 (MWh Loss/yr) = (CL) + (VLC) x (LSFC) x (Hil peak City) + (10.2) 2 + (VLP) x (LsFP) x (Mi-peak MIP)” + (6.4)2 + (VLT) x (LSFT) x (MW peak City + MW peak MIP)? x (8760) (16.6)2 Symbols: MIP - Marine Industrial Park The following loss data are taken from the 2014 medium peak forecast load flows as shown in Tables 5.1-2 through 5.1-16. CL - Constant (Load Independent) losses VLC - Variable (Load Dependent) losses, City VLP - Variable (Load Dependent) losses, Marine Industrial Park VLT - Variable (Load Dependent) losses, Total load 4814B 5-4 = TABLE 5.1-2 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _1-A All 115 kV system. ACSR conductor: 226 kCMil, except 336 kCMil for the last 4 miles to Marine Industrial Park. Constant losses: Variable losses: City: Transformer MIP: Line Transformer Total Total Load: Line V/ Max. Voltage Drop— Max. Voltage Drop at 2014 high forecast peak’ V/ Without line capacitors 4814B 5-5 0.044 MW 0.068 MW 0.009 MW 0.027 MW 0.036 MW 0.404 MW 1% 12% TABLE 5.1-3 LOSSES AT 2014 MEDIUM PEAK LOADS All 115 kV system. ACSR conductor: 336 kCMil Constant losses: Variable losses: City: MIP: Total Load: V Max. Voltage Drop— Max. Voltage Drop at 2014 high forecast pea V Without line capacitors 4814B Line CASE _1-B Transformer Total Line Kl/ 5-6 0.044 MW 0.068 MW 0.008 MW 0.027 MW 0.035 MW 0.315 MW 6% 10% coy le TABLE 5.1-4 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _1-C All 115 kV system. ACSR conductor: Daves Creek to Seward 397 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: Variable losses: City: MP: Line Transformer Total Total Load: Line Max. Voltage Drop!’ Max. Voltage Drop at V 2014 high forecast peak— VY Without line capacitors 48148 5-7 0.044 MW 0.068 MW 0.008 MW 0.027 MW 0.035 MW 0.267 MW 6% 10% TABLE 5.1-5 a LOSSES AT 2014 MEDIUM PEAK LOADS = CASE _1-D = All 115 kV system. a ACSR conductor: Daves Creek to Seward 477 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: 0.044 MW Variable losses: City: 0.068 MW MIP: Line 0.008 MW i Transformer 0.027 MW Total 0.035 MW Total Load: Line 0.223 MW i vy; Max. Voltage Drop 6% . Max. Voltage Drop at 10% 2014 high forecast peak’ 7 V without line capacitors 4814B 5-8 = ic TABLE 5.1-6 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _3-A All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR conductor: 226 kCMil, except 336 kCMil for the last 4 miles to Marine Industrial Park. Constant losses: Variable losses: City: MIP: Line Transformer Total Total Load: Line Transformer Total Max. Voltage Drop!’ Max. Voltage Drop at V 2014 high forecast peak VY Without line capacitors 48148 5-9 0.066 MW 0.068 MW 0.027 MW 0.027 MW 0.054 MW 0.430 MW 0.028 MW 0.458 MW 9% 15% be All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR conductor: Constant losses: Variable losses: City: MIP: Total Load: Max. Voltage Drop— TABLE 5.1-7 CASE_3-B 336 kCMil Line Transformer Total Line Transformer Total V/ Max. Voltage Drop at 2014 high forecast peak— V V/ — Without line capacitors 48148 5-10 LOSSES AT 2014 MEDIUM PEAK LOADS 0.066 MW 0.068 MW 0.024 MW 0.027 MW 0.051 MW 0.330 MW 0.028 MW 0.358 MW 8% 13% 7 TABLE 5.1-8 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _3-C All 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR conductor: Daves Creek to Seward 397 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: Variable losses: City: MIP: Line Transformer Total Total Load: Line Transformer Total Max. Voltage Dropl/ Max. Voltage Drop at 2014 high forecast peak’ VY Without line capacitors 4814B S=11 0.066 MW 0.068 MW 0.023 MW 0.027 MW 0.050 MW 0.281 MW 0.028 MW 0.309 MW 1% 12% TABLE 5.1-9 LOSSES AT 2014 MEDIUM PEAK LOADS CASE_3-D Al1 115 kV Daves Creek to Seward, 69 kV to Marine Industrial Park. ACSR conductor: Daves Creek to Seward 477 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: Variable losses: City: MIP: Line Transformer Total Total Load: Line Transformer Total Max. Voltage Drop!’ Max. Voltage Drop at 2014 high forecast peak’ V/ Without line capacitors 4814B 5-12 0.066 MW 0.068 MW 0.023 MW 0.027 MW 0.050 MW 0.235 MW 0.028 MW 0.263 MW 1% 12% TABLE 5.1-10 LOSSES AT 2014 MEDIUM PEAK LOADS CASES 4 AND 6 115 kV Daves Creek to Lawing, 69 kV Lawing to Marine Industrial Park. ACSR Conductor: 336 kCMil Daves Creek to Lawing and Seward to Marine Industrial Park; existing 4/0 AWG between Lawing and Seward. Constant losses: 0.066 MW Variable losses: City: 0.068 MW MIP: Line 0.029 MW Transformer 0.027 MW Total 0.056 MW Total Load: Line 1.503 MW Transformer 0.028 MW Total 1.531 MW V/ Max. Voltage Drop 16% Max. Voltage Drop at 27% 2014 high forecast peak’ VY Without line capacitors 48148 5-13 re Le is a TABLE 5.1-11 LOSSES AT 2014 MEDIUM PEAK LOADS All 69 kV system ACSR conductor: 336 kCMil Constant losses: Variable losses: City: MIP: Total Load: Max. Voltage Drop!’ Max. Voltage Drop at 2014 high forecast peak— V/ CASE _5-A Line Transformer Total Line Transformer Total V — Without line capacitors 48148 5-14 0.066 MW 0.068 MW 0.028 MW 0.027 MW 0.055 MW 1.158 MW 0.028 MW 1.186 MW 16% 27% ba te TABLE 5.1-12 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _5-B All 69 kV system ACSR conductor: Daves Creek to Seward 556 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: Variable losses: City: MIP: Line Transformer Total Total Load: Line Transformer Total Max. Voltage Dropl/ Max. Voltage Drop at 2014 high forecast peak’ Y Without line capacitors 4814B 5-115 0.066 MW 0.068 MW 0.027 MW 0.027 MW 0.054 MW 0.668 MW 0.028 MW 0.696 MW 13% 22% TABLE 5.1-13 LOSSES AT 2014 MEDIUM PEAK LOADS ° CASE _5-C All 69 kV system ACSR conductor: Daves Creek to Seward 795 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: 0.066 MW Variable losses: City: 0.068 MW MIP: Line 0.026 MW Transformer 0.027 MW Total 0.053 MW . Total Load: Line 0.457 MW Transformer 0.028 MW i Total 0.485 MW V/ Max. Voltage Drop 12% Max. Voltage Drop at 20% V/ 2014 high forecast peak oe V Without line capacitors i 4814B 5-16 Ls TABLE 5.1-14 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _5-D All 69 kV system ACSR conductor: Daves Creek to Seward 954 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: Variable losses: City: MIP: Line Transformer Total Total Load: Line Transformer Total Max. Voltage Drop// Max. Voltage Drop at 2014 high forecast peak!’ Y Without line capacitors 48148 5-17 0.066 MW 0.068 MW 0.026 MW 0.027 MW 0.053 MW 0.384 MW 0.028 MW 0.412 MW 12% 20% TABLE 5.1-15 LOSSES AT 2014 MEDIUM PEAK LOADS CASE _5-E All 69 kV system ACSR conductor: Daves Creek to Seward 1272 kCMil, Seward to Marine Industrial Park 336 kCMil Constant losses: 0.066 MW Variable losses: City: 0.068 MW MIP: Line 0.025 MW Transformer 0.027 MW Total 0.052 MW Total Load: Line 0.284 MW Transformer 0.028 MW Total 0.312 MW V/ Max. Voltage Drop 11% Max. Voltage Drop at 18% 2014 high forecast peak’ VY Without line capacitors 48148 5-18 ™ TABLE 5.1-16 re LOSSES AT 2014 MEDIUM PEAK LOADS a CASE_5-F All 69 kV system ACSR conductor: Daves Creek to Seward 1590 kCMil, Seward to Marine : Industrial Park 336 kCMil Constant losses: Variable losses: City: MIP: Line Transformer Total Total Load: Line Transformer Total Max. Voltage Dropl/ Max. Voltage Drop at 2014 high forecast peak// V Without line capacitors es 4814B 5-19 0.066 MW 0.068 MW 0.025 MW 0.027 MW 0.052 MW 0.228 MW 0.028 MW 0.256 MW 11% 18% 5.2 STATE OF ALASKA EVALUATION PROCEDURES AND CRITERIA The Alaska Power Authority has adopted a set of standard procedures and assumptions to be used for project evaluation. The Power Authority's project evaluation procedure reflects the organization's purpose and philosophy. The Power Authority was established as an instrument of the State to intervene for the purpose of bringing about worthy projects that would otherwise be excluded from development by the constraints of financial markets. The Authority's approach to project evaluation entails first assessing a project's “worthiness” apart from the constraints of financial markets, and, second, determining if there is the ability and political will to intervene to establish financing arrangements and terms that permit the project to be financed. The means that the Authority has adopted to assess a project's worthiness are consistent with traditional federal evaluation methods for public water resource projects. The goal is to maximize net economic benefits from the state's perspective, tempered by environmental, socioeconomic, and public preference constraints. The economic analysis for the Daves Creek-Seward transmission line follows the procedure outlined by the Alaska Power Authority. Once the alternative transmission systems have been defined, the economic analysis entails (1) estimating the capital costs, operation and maintenance costs, and any salvage value of each system over its life cycle; (2) estimating the value of energy losses from each system over its life cycle; (3) discounting the costs and losses of each system to a common point in time; and (4) comparing the total discounted costs plus losses for each system and determining the preferred alternative. Specific assumptions and procedures included in the analysis are as follows: Ie Inflation is assumed to be zero. The entire analysis is presented in constant 1983 dollars. 4814B 5-20 Ge i 4814B The real discount rate is 3.5 percent. The net present value of each alternative is equal to the discounted value of costs plus the discounted value of energy losses plus any discounted salvage value. Salvage value enters the equation as a benefit, or “negative cost." Capital costs are assigned to the year in which they occur. Operation and maintenance costs are generally assigned to the year in which they occur. In this analysis of the Daves Creek-Seward transmission line, operation and maintenance costs are the same for all alternatives. These costs are not included in the calculations of net present value because they would have no effect on the relative ranking of the alternatives. Furthermore, no increase over current operation and maintenance costs are anticipated for the transmission line upgrade. There is no real escalation of construction costs. The price of electricity, however, escalates at the rate contained in the Sherman Clark No Supply Disruption Case for the Railbelt Region (APA, 1983) until the year 2004, after which the price is constant. The standard economic life of each transmission system component is: Substations/switching stations 50 years Transmission lines with steel towers 40 years Transmission lines with wood poles 30 years 5-21 r om For the analysis of the Daves Creek-Seward transmission system, all six alternatives have the same project life of 30 years. That period is defined by the life of the wood poles, which are the primary system components. 8. At the end of the project life, components with any remaining economic life have a salvage value. The discounted salvage value is included in the calculation of each alternative's net present value. 9. Energy losses from each system were discussed in Section 5.1. The value of those losses also enters the calculation of net present value for each system. The results of the economic evaluation are discussed in Section 6.2. 5.3 AVALANCHE EVALUATION CRITERIA Although avalanche hazard areas pose risks to the reliable operation of the proposed transmission line, it is very difficult and extremely expensive to design an overhead line to withstand avalanches. The cost of designing a line sturdy enough to withstand avalanche damage without effecting operations is very high. Because the cost is high for an overhead line, constructing an underground transmission line, may be feasible under special conditions in localized areas where avalanche hazards are particularly severe. Ebasco has developed criteria to identify and evaluate the areas which warrant special design measures to mitigate avalanche concerns. In general, the avalanche evaluation criteria can not be used to distinguish between the various system alternatives, because each of the system alternatives can be modified during design to incorporate Measures to reduce the risk of avalanche damage. Consequently, the avalanche evaluation criteria described below will be used during the design process. 4814B 5-22 In order to determine whether undergrounding the proposed line is an economic and practical solution in specific avalanche areas, an economic analysis will be undertaken. The economic analysis will compare the difference in the present value of costs associated with constructing the underground option with the present value of costs associated with an overhead line. The present value of costs for an underground line is most influenced by the high capital costs of the underground cable and associated facilities. The present value of costs for an overhead line is influenced by the capital cost of the line and by considering the cost of repairing a transmission line damaged by avalanches. For the purposes of estimating the costs of avalanche damage repair in a specific hazard area, it will be assumed that all wood poles would need to be replaced in that area and that the conductors would need to be restrung. It will be assumed that such activities would occur during adverse weather conditions. There is another factor which will be considered in the economic evaluation of whether an underground line should be installed along certain sections of the route. It concerns the cost to the City of replacing power supplied by the transmission line with diesel power generated at the City. Assuming that a diesel backup system is maintained in a reliable state, it can be assumed that the additional cost for running the diesel systems is equivalent to the operating and maintenance costs for the diesel system, less the cost which the City must pay for the power transmitted over the transmission line. This cost will be factored into the calculation of the present value of costs associated with the overhead transmission line. Using the cost information developed for the overhead line, the break-even frequency of avalanche events will be computed. The break-even frequency (the number of years between major avalanche events) will be the frequency of avalanche events for which the present value of costs for the overhead and underground lines are equal. The anticipated frequency of avalanche events in the specific area being 48148 5-23 investigated will then be compared to break-even avalanche frequency. If, in a specific area being investigated, it is expected that avalanches will occur more frequently than the break-even frequency, underground or other special installation techniques will be recommended. If the frequency of expected avalanche events is less than the break-even frequency, the prudent economic approach will be to design an overhead line recognizing that portions of it will be taken out of service periodically by avalanches. Although Ebasco will use a sound engineering approach to plan and design the line in avalanche hazard areas, it must be emphasized that avalanches are natural phenomena that are difficult to predict and subject to natural events uncontrollable by humans. Consequently, there are inherent risks in designing a transmission line in avalanche areas, regardless of the approach adopted to mitigate potential problems. 5.4 ENVIRONMENTAL AND PERMITTING CRITERIA Two major factors constitute the environmental and permitting criteria to evaluate the alternatives under consideration. The first is the significance of environmental impacts and the second is the extent of permitting difficulties anticipated. The significance of environmental impacts cannot be determined until an environmental assessment is completed. Contacts with Forest Service and other agency personnel conducted to date, however, have provided guidance on what impacts will be significant for the various alternatives. Of most importance will be the potential impacts on visual resources. Maintaining the scenic quality of the Sterling and Seward Highways is important to the permitting agencies of this project. Potential land use impacts, particularly as they affect state-selected and private land, are also important in assessing the significance of impacts. The relative significance of impacts can be used to compare project alternatives. 4814B 5-24 r The extent of permitting difficulties associated with alternatives for the proposed project is largely reflected in the anticipated length of time required to get the necessary permits. In general, discussions with agencies have confirmed the fact that permits can be obtained more rapidly if the proposed line stays within existing transmission line corridor. In areas where routing alternatives are proposed, it will be easier to obtain permits if environmental impacts are not significant and if reasons for deviating from the existing corridor are clearly stated and well supported. Therefore, permitting criteria are based on the extent with which an alternative deviates from the existing corridor and the ease with which such deviations can be supported. These criteria can be used to analyze system and routing alternatives. 48148 5-25 REFERENCES 1) Alaska Power Authority, Before the Federal Energy Regulatory Commission, Application for License for Major Project, Susitna Hydroelectric Report, Volume 2C, RED Model (1983 Version), Technical Documentation Report, July, 1983. r 4814B 5-26 CONCLUSIONS | & RECOMMENDATIONS me | a pommatn, ‘ orang 6. COMPARISON OF ALTERNATIVES 6.1 ENGINEERING COMPARISON For a comparison of the six system alternatives as many assumptions as possible were kept the same to avoid influencing differential costs and performances. The system routing is the same for all cases, energy costs and usage rates were standardized, all unit prices and work rates for construction were the same, and data for cost and losses for major equipment were always from the same sources. To choose a conductor size for the line from Daves Creek to Seward (or Lawing in Alternatives 4 and 6) an optimization study was performed at both 69 kV and 115 kV. Load flow studies were run on the computer for each conductor size at each voltage with the medium load forecast. Loss data from these runs were used to calculate the present worth of these losses. This was then added to the differential construction costs for each case and plotted in Figures 6.1-1 and 6.1-2. From these graphs the conductor with lowest overal] costs was chosen for each voltage. A 336 kCM ACSR conductor was chosen for the 115 kV and a 556 kCM ACSR conductor was selected for the 69 kV alternative. During the load flow studies, voltage drops for various system conditions were analyzed and a maximum limit of 12% voltage drop was considered acceptable. This 12% limit allows a + 4% voltage variation by Chugach Electric at Daves Creek, while enabling the LTC's to maintain 12.47 kV at the feeder buses. Alternatives 4 and 6 both had 16% voltage drop and were considered technically unacceptable for this reason. Even if such an excessive drop were acceptable, there are no advantageous operating features in these two alternatives. It was also decided that at 69 kV, the minimum conductor size should be 795 kCM ACSR because any smaller size gives a voltage drop of over 12%. These criteria change the conductor size selected for Alternative 5 from 556 kCM ACSR to 795 kCM ACSR. 4816B 6-1 wr & es mee ca fm 4 * In Table 6.1-1, a preliminary comparison between the remaining Alternatives 1, 2, 3, and 5 shows that Alternative 5 has the highest construction cost and also the highest losses with the other three alternatives all being quite comparable in both construction costs and the present worth of projected losses over the project life. The voltage drops are 6% to 8% for all three alternatives in case of the moderate peak forecast (load); this allows a +6% to +7% voltage variation on the 115 kV Chugach bus at Daves Creek, while the LTC's can maintain the 12.47 kV voltage in Seward. Alternatives 1, 2 and 3 are therefore compared in a detailed economic analysis to obtain a more definitive comparison among these three cases. The results of that analysis is presented in Section 6.2. The major differences between Alternatives 1, 2, and 3 are best seen by examining the Seward substation in more detail for each case as follows. In its final form, Alternative 1 has the simplest and most straightforward substation arrangement, but surpluses the largest amount of recently installed equipment for which little or no salvage value can be recovered. Alternative 3 attempts to minimize modifications to the existing substation by adding two autotransformers alongside the existing equipment. This, however, increases system losses and complexity to reduce the amount of surplus equipment generated. Alternative 2 is a compromise between these two objectives. It reduces system complexity at the Seward substation by replacing the existing transformers. However, these two existing transformers and the 69 kV circuit switchers would be reinstalled at the Marine Industrial Park. The line between Seward and the Marine Industrial Park will be at 69 kV, which minimizes the amount of equipment surplused. It also allows the construction of the Marine Industrial Park Substation at a later date at a greatly reduced capital cost. 4816B eaten, Crna 115 kV CONDUCTOR ANALYSIS 900k 800k RELATIVE COST ———————> OF LINE (LOSSES +INSTALLATION) 700k 600k 500k PRESENT WORTH OF LOSSES 400k 300k 200k => DIFFERENTIAL 100k 206 336 307 477 KCM ACSA FIG 6.1-1 6-3 CONSTRUCTION COSTS pce Pere Pa = ny a — a alls ers ¢* Ea 69 kV CONDUCTOR ANALYSIS : 3,600k 3,400k 3,200k 3,000k 2,800k RELATIVE COST ————> OF LINE (LOSSES +INSTALLATION) 2,600k 2,.400k 2,200k 2,000k 1,800k >———— DIFFERENTIAL 1,600k CONSTRUCTION COSTS 1,400k 1,200k 1,000k PRESENT WORTH OF LOSSES 800k 600k 400k 200k 336 556 796 e654 1272 1590 KCMIL ACSR FIG 6.1-2 6-4 —— 7? Gao ACC'T DESCRIPTION 350. Land 352. Subst. Str. & Impr. 353. Subst. Equipment 354. Steel Towers 355. Wood Poles 356 OH Conductors Total Direct Const. Cost 60. Indirect Const. Cost Total 10/83 Const. Cost Escalation Total Esc. Const. Cost Contingency @ 12% AE/CM Total Escal. Cost Differential Cost Present Worth of Losses Notes: 1) TABLE 6.1-1 CONCEPTUAL COST SUMMARY (Amounts in $1,000's) ALTERNATIVE NO. 1 2 3 $ 30 $ 30 $ 45 71 90 110 2031 1844 2164 909 909 909 2838 2760 2760 3951 _ 3786 3786 9836 9419 9774 190 761 186 10626 10180 10560 534 «510 530 71160 10690 71090 1340 1280 1330 1200 1200 1200 $13700 $13170 = $13620 + 530 BASE + 450 1122 1268 1384 4 $ 660 130 2286 909 1188 _ 2715 7288 586 71874 — 394 8268 992 1100 $10360 - 2810 3202 $ 645 110 2096 909 3120 4543 10823 870 11693 85 12278 wn 1472 1200 $14950 + 1780 1541 $ 60 130 2218 909 1188 _ 1567 6072 — 488 6560 330 6890 830 1100 $8820 - 4350 3202 Pricing is based on adjusted unit prices from Table 11-2 of the Grant Lake Feasibility Study. 2) No salvage value for existing materials or revenues from marketable timber are included except that the existing 4/0 conductor is assumed to be reused on the 25 kV underbuild. 3) Allowance for Funds Used During Construction (AFUDC) is not included. 4) Installation costs for poles and conductors are based on sectionalizing procedures rather than hot line construction procedures and no incremental cost of producing power during outages is included. 4816B oo; eee bias 6.2 ECONOMIC COMPARISON Three alternatives - 1, 2, and 3 - performed well enough in the engineering comparison to be carried forward through the economic analysis. The economic analysis entailed (1) estimating the capital costs over each system's life cycle; (2) estimating the salvage value of any system components with an economic life longer than the system life; (3) estimating the value of energy losses from each system over its life cycle; (4) discounting the costs and losses of each system to 1983; and (5) comparing the total discounted costs plus losses for each system and determining the preferred alternative. Tables 6.2-1, 6.2-2, and 6.2-3 summarize the economic analysis of Alternatives 1, 2, and 3, respectively. The total present value of each is equal to the discounted capital costs plus the discounted value of energy losses, plus salvage value (where salvage value is entered as a negative number). The construction costs included in the economic evaluation differ slightly from those presented in Table 6.1-1 because of the absence of an escalation factor. According to Alaska Power Authority evaluation criteria, economic analysis is always done in constant dollars and inflation is assumed to be zero. Engineering cost estimates, on the other hand, generally include an escalation, or inflation, factor for financial planning purposes. In essence, the total capital cost presented for each project in Table 6.1-1 is stated in inflated 1984 dollars. The total costs stated in Tables 6.2-1, 6.2-2, and 6.2-3 are in constant 1983 dollars. Comparison of the total present value for Alternatives 1, 2, and 3 yields these results: Alternative Present Value 1 $13,427,341 13,114,825 13,467,778 4816B 6-6 ea oy mad — t ” ero ta oe oe? 4 ro es Alternative 2 has a slightly lower present value than the other two alternatives. The difference between the highest cost alternative (Alternative 3) and the lowest cost alternative (Alternative 2) is less than 3 percent, however. One can conclude that the three alternatives are virtually identical from an economic standpoint. 4816B 6-7 CONSTRUCTION COSTS BY FERC ACCOUNT 350 LAND AND LAND RIGHTS 352 SUBSTATION/SWITCHING STATION IMPROVEMENT 353 SUBSTATION/SWITCHING STATION EQUIPMENT 354 STEEL TOWERS AND FIXTURES 355 WOOD POLES AND FIXTURES 356 OVERHEAD CONDUCTORS AND DEVICES TOTAL DIRECT CONSTRUCTION COST 60 INDIRECT CONSTRUCTION COST TOTAL CONSTRUCTION COST CONTINGENCY 9 12% ENGINEERING TOTAL CAPITAL COST OPERATION AND MAINTENANCE COSTS ENERGY LOSSES PRICE OF ELECTRICITY ($/4MH) ENERGY LOSSES (MMH) TOTAL VALUE OF ENERGY LOSSES TOTAL COST PLUS LOSSES PRESENT VALUE OF COST PLUS LOSSES TOTAL PRESENT VALUE DISCOUNT RATE = 3.5% BASE YEAR FOR DISCOUNTING = 1983 732 3 fa 2 em oo oo os UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS TABLE 6.2.1 ALTERNATIVE 1 PAGE 1 OF 2 1983 1984 1985 19861987 1988 = 19891990 1991 1992 1993 1994 1995 1996 1997 30000 77000 2031000 909000 2838000 3951000 6 10626000 0 6 @ 1275120 4 6 (ASSUMED TO BE THE SAME FOR ALL ALTERNATIVES, AND THEREFORE NOT INCLUDED IN THE CALCULATION OF PRESENT VALUE) 44.19 45.12 46.46 47.46 48.35 48.89 = 50.19 SU.5S 52.33 53.45 55.03 54.05 57.00 755.99 804.20 825.48 848.29 868.89 963.60 1026.60 1064.13 1106.54 1136.05 1161.57 1179.34 1194.05 33407-36286 = 3835240260 = 42011 «= 48088 = 51463 | 548546 = 57905 = 6072263921 «64102 «68061 013101120 © 33407 36286 = 3835240260 «42011 «= 48088 = 51463 54856 = 57905 = 6072263921 «= 66102 = 48061 0 12658087 31186 = 32727-33421 «33898 «= 34176 = 37797 39082) 40249 )=— 41050 = 41591 = 42302 «42266 «= 42047 13427341 6-8 wey 57.90 1207.59 69nd 69919 41734 ae Pa me i? 7? Pes ~ an = co —_ ~~ CAL Pam ry UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS TABLE 4.2.1 ALTERNATIVE 1 PAGE 2 OF 2 SALVAGE 1999 20002001 2002 «= 2003, 2004 = 2005 2006 = 2007, 2008 = 2009 20102011 212-2013 2014 VALUE CONSTRUCTION COSTS BY FERC ACCOUNT LAND AND LAND RIGHTS SUBSTATION/SUITCHING STATION IMP. ~70008 SUBSTATION/SUITCHING STATION EQ. 812400 STEEL TOWERS AND FIXTURES -181800 WOOD POLES AND FIXTURES OVERHEAD CONDUCTORS AND DEVICES 2323222 TOTAL DIRECT CONSTRUCTION COST 0 0 4 0 0 6 6 4 0 0 4 6 6 é 0 0 INDIRECT CONSTRUCTION COST TOTAL CONSTRUCTION COST 6 6 6 0 0 6 0 4 Q 0 o 0 CONTINGENCY @ 12% 0 0 4 0 4 6 ENGINEERING TOTAL CAPITAL COST 6 6 6 0 Q 6 4 6 4 6 6 6 6 6 o 6 -1025000 OPERATION AND MAINTENANCE COSTS (ASSUMED TO BE THE SAME FOR ALL ALTERNATIVES, AND THEREFORE NOT INCLUDED IN THE CALCULATION OF PRESENT VALUE) ENERGY LOSSES PRICE OF ELECTRICITY ($/4aH) 38.75 59.53 60.09 «= 60.65 61.25 61.82 «61.82 61.82 61.82 61.82 961.82 61.82 = 61.82 = 61.82 1.82 41.82 ENERGY LOSSES (Mal) 1218.34 1231.15 1246.91 1263.20 1281.20 1295.59 1310.02 1325.49 1344.32 1363.64 1304.73 1406.70 1429.63 1453.20 1477.43 1502.33 TOTAL VALUE OF ENERGY LOSSES 71577-73290 = 7492776613 78474 «0093 = BOGS §=—B19S4 = 63106 = 84300» 85404 = 84962 8838889837 91335 = 92874 TOTAL COST PLUS LOSSES 71577 73290 »«-74927-« «76613 «78474 «= BO0093 «BUNS «= B19S4 = 83106 §=— 8430085404 §=— 849628380) 8983791335 ~=—:92874 -1025000 PRESENT VALUE OF COST PLUS LOSS 41279 40838 »= 40338 «39851 «39438 «= 38891-37994 37149 = 36397 35471 «34998 = 34351 «33731 9312732541 «= 31978 -352836 ead CONSTRUCTION COSTS BY FERC ACCOUNT LAND AND LAND RIGHTS SUBSTATION/SMITCHING STATION IMPROVEMENT SUBSTATION/SWITCHING STATION EQUIPHENT STEEL TOWERS AND FIXTURES W000 POLES AND FIXTURES QVERHEAD CONDUCTORS AND DEVICES 222882 TOTAL DIRECT CONSTRUCTION COST INDIRECT CONSTRUCTION COST TOTAL CONSTRUCTION COST CONTINGENCY 9 12% TOTAL CAPITAL COST OPERATION AND MAINTENANCE COSTS ENERGY LOSSES PRICE OF ELECTRICITY ($/4aH) ENERGY LOSSES (MH) TOTAL VALUE OF ENERGY LOSSES TOTAL COST PLUS LOSSES PRESENT VALUE OF COST PLUS LOSSES TOTAL PRESENT VALUE DISCOUNT RATE = 3.5% BASE YEAR FOR DISCOUNTING = 1983 “94 ESD _— revere mtocam ay a ‘ ‘ UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS TABLE 6.2.2 ALTERNATIVE 2 PAGE 1 OF 2 19631984 1985 19861987 1988 = 1989 1990 1991 1992-1993 1994 1995 6 ‘ 6 o 0 ‘ 6 6 6 6 6 © 10180000 0 4 0 ‘ 0 0 4 0 0 0 6 © 1221600 0 6 0 4 4 6 4 6 4 6 4 1200000 eenene encece a ecccce equese cannes eeewee wewene coweee enone © 12601600 0 0 6 6 6 6 6 6 0 (ASSUMED TO BE THE SANE FOR ALL ALTERNATIVES, AND THEREFORE NOT INCLUDED IN THE CALCULATION OF PRESENT VALUE) 44.19 45.12 46.46 47.46 = 48.95 48.89 = 50.19 SSS 52.33 53.45 (55.03 910.49 954.19 974.79 997,56 1017.37 1142.74 1180.55 1216.99 1258.09 1286.97 1312.07 40235 = 4305345289 «= 47344 «49190 = 55869 = 59181 = 62736 = 65836 «= 8789 §=— 72203 012601600 © 40235 «4305345289 «47344 «49190 «= 55849 = 59181 = 462736 «= 5836 «= 68789 = 72203 012175459 = 37559 = 38831 «39467-39863 = 40016 «43912 44943 = 46031 «= 4667247116 = 47783 13114825 6-10 1996 346.05 1329.82 74536 74536 47659 1997 57.00 1344.70 76648 76648 47352 1998 46949 UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS TABLE 6.2.2 ALTERNATIVE 2 PAGE 2 OF 2 1999 2000 2001 2002 2003 2004 2005 2006 = 2007 2008 = 2009-2010 CONSTRUCTION COSTS BY FERC ACCOUNT LAND AND LAND RIGHTS SUBSTATION/SWITCHING STATION IMP. SUBSTATION/SWITCHING STATION EQ. STEEL TOWERS AND FIXTURES W000 POLES AND FIXTURES OVERHEAD CONDUCTORS AND DEVICES 2228288 TOTAL DIRECT CONSTRUCTION COST 0 0 0 6 6 6 4 0 0 6 o 6 INDIRECT CONSTRUCTION COST TOTAL CONSTRUCTION COST ‘ 6 6 6 0 CONTINGENCY 2 12% ‘ 6 6 6 6 ENGINEERING TOTAL CAPITAL COST ‘ 0 6 ‘ 6 4 4 0 4 0 6 6 OPERATION AND HAINTENANCE COSTS ENERGY LOSSES PRICE OF ELECTRICITY ($/MH) 56.75 59.53 60.09 «60.65 1.25 61.82 9-61.82 61.82 61.82 61.82 61.82 61.82 ENERGY LOSSES (Mul) 1369.64 1382.75 1398.70 1415.15 1433.26 1446.63 1460.32 1475.20 1492.87 1511.21 1531.21 1552.05 TOTAL VALUE OF ENERGY LOSSES 00466 = 823154048 = 85829 «= 8778789431. «— 0277S «M1197 = 92289 = :93423-« «94659 =—95948 TOTAL COST PLUS LOSSES 0466 «= 82315 84048 = 85829» 87787 «89431 «90277-91197 =: 92287 = 93423 9465995948 PRESENT VALUE OF COST PLUS LOSS 46405 45846 «45248 «44644 «44119 4342542354 «41338 «40419 «39532-38700 «37901 6-11 (ASSUMED TO BE THE SAME FOR ALL ALTERNATIVES, AND THEREFORE NOT INCLUDED IN THE CALCULATION OF PRESENT VALUE) 2011 61.82 1573.81 97293 97293 37132 SALVAGE 2012 20132014 VALUE 36000 -737600 181800 61.82 61.82 61.82 1596.16 1619.15 1642.78 98675 100096 = 101557 90675 100096 += 101557 -955400 36386 «354662 «34959 -328878 — ow ram, CONSTRUCTION COSTS BY FERC ACCOUNT 2s2882 SUBSTATION/SMITCHING STATION IMPROVEMENT SUBSTATION/SWITCHING STATION EQUIPMENT STEEL TOWERS AND FIXTURES WOOD POLES AND FIXTURES OVERHEAD CONDUCTORS AND DEVICES TOTAL DIRECT CONSTRUCTION COST INDIRECT CONSTRUCTION COST TOTAL CONSTRUCTION COST CONTINGENCY @ 12% ENGINEERING TOTAL CAPITAL COST OPERATION AND MAINTENANCE COSTS ENERGY LOSSES PRICE OF ELECTRICITY (8/4) ENERGY LOSSES (Mai) TOTAL VALUE OF ENERGY LOSSES TOTAL COST PLUS LOSSES PRESENT VALUE OF COST PLUS LOSSES TOTAL PRESENT VALUE DISCOUNT RATE = 3.5% BASE YEAR FOR DISCOUNTING = 1983 san — ~~ e rapenem ~ Soe an UPGRADE OF SEWARD TRANSMISSION LINE ECONOMIC ANALYSIS TABLE 6.2.3 ALTERNATIVE 3 PAGE 1 OF 2 1983 1984 1985 1986 1987 1988 45000 110000 2164000 1989 1990 1991 1992 1993 1994 1995 (ASSUMED TO BE THE SAME FOR ALL ALTERNATIVES, AND THEREFORE NOT INCLUDED IN THE CALCULATION OF PRESENT VALUE) 44.19 (45.12 46.46 47.46 48,35 48,89 50.13 S1.55 52.33 53.45 55.09 985.27 1036.18 1059.49 1084.80 43539 46752, 4922451485 1107.26 1239.36 1283.76 1324.92 1371.40 1403.83 1431.93 53536-0592) 64355 6830071765 = 75035 78799 013027200 4353946752 «49224 «= 51485 = 53536 «= 6059244355 68300) 71765 «= 75035-78799 0 12586667 «40644 «= 42168 = 42896 «= 43349 13467778 6-1 Po 43552 47625 «48872, S014 50876 S395 52148 sae 4 1996 1997 0 ‘ e ‘ 6 6 6 6 34.05 (57.00 1451.59 1467.92 81362 83471 81362 63471 5202351691 4 os CONSTRUCTION COSTS BY FERC ACCOUNT 222883 OPERATION AND MAINTENANCE COSTS LAND AND LAND RIGHTS SUBSTATION/SWITCHING STATION IMP, SUBSTATION/SWITCHING STATION EQ. STEEL TOWERS AND FIXTURES WOOD POLES AND FIXTURES OVERHEAD CONDUCTORS AND DEVICES TOTAL DIRECT CONSTRUCTION COST INDIRECT CONSTRUCTION COST TOTAL CONSTRUCTION COST CONTINGENCY 2 12% ENGINEERING TOTAL CAPITAL COST ENERGY LOSSES PRICE OF ELECTRICITY ($/H) ENERGY LOSSES (Mat) TOTAL VALUE OF ENERGY LOSSES TOTAL COST PLUS LOSSES UPGRADE OF SEWARD TRANSHISSION LINE ECONOMIC ANALYSIS TABLE 6.2.3 ALTERNATIVE 3 PAGE 2 OF 2 1999 2000 2001 2002 =—-2003 2004 2005 2006 = 2007 2008 2009 2010 21 (ASSUMED TO BE THE SAME FOR ALL ALTERNATIVES, AND THEREFORE NOT INCLUDED IN THE CALCULATION OF PRESENT VALUE) 38.75 59.53 60.09 «= 0.65 1.25 61.82 961.62 61.82 «61.82 61.82 = 1.82 61.82 61.82 1495.02 1509.30 1526.00 1544.87 1544.83 1580.30 1596.01 1613.08 1633.37 1654.41 1677.37 1701.29 1726.26 07832 89849 )=— 91745 = 93696 «= 958446 = 97694 «= 9846S = «99721-««100975 102276 «103695 «105174 = 106717 07832 «89849 «91745 «= 93696 «= 95846 «= 97694 «= 4S 99721 «100975 «102276 «103695 105174 = 106717 PRESENT VALUE OF COST PLUS LOSS 50653 50044 «49392-48737 «48149 «= 47437-44289 45202 «44223-43278 «4239441545 40729 6-13 61.82 1751.92 61.82 1778.38 109935 109935 39167 ‘SALVAGE 2014 VALUE ~44000 865600 0 -1461600 61.62 1805.41 111610 111610 -1461600 30420 -503127 6.3. ENVIRONMENTAL COMPARISON Employing the criteria developed in Section 5.4, direct comparisons can be made among the system and routing alternatives. Of the technically viable system alternatives, there is no difference in their ability to satisfy the environmental and permitting criteria. In either case, the proposed facility would be developed within the existing corridor, except for possible minor deviations in local areas. Further, differences between the plans as related to transformer requirements would not affect the significance of impacts or permitting difficulty because all transformer modifications will be accommodated either within or adjacent to existing substation yards. Differences exist, however, among the routing alternatives. In general, although environmental impacts do not appear to be significant for any of the routing alternatives considered, impacts would be less for alternatives which follow the existing transmission line corridor than for alternatives in new corridors. It is recognized that environmental impact studies and tradeoff analyses will be required prior to the selection of the preferred route in each of the potential rerouting areas. Public and agency comments will be used to evaluate the alterntives identified in Section 4.2. Such comments, as they affect the potential significance of impacts and the permitting requirements will be considered in determining which routing alternatives should be adopted. The routing alternatives to be adopted will be identified prior to the time the project permit applications are submitted to reviewing agencies. It is expected that such recommendations will be developed by mid-November, 1983. 6.4 CONCLUSIONS AND RECOMMENDATIONS Based upon the above studies and evaluations, a 115 kV system voltage is recommended. This will give a maximum voltage drop for the projected moderate load of 6% to 8%. All 69 kV voltage options 4816B 6-14 resulted in voltage drops which were considered unacceptable. With the recommended conductor size of 336 kCMil, the 115 kV system will carry 106 MVA maximum load which covers the projected maximum load growth by a factor of 4. The three options which were studied in detail are all considered acceptable. All are comparable from an environmental and permitting viewpoint and there is less than 3 percent difference in the evaluated economic lifecycle costs. Ebasco recommends Alternative 2 which, in addition to having the lowest evaluated present worth cost, also permits maximum reuse of existing equipment. This alternative transmits power at 115 kV from Daves Creek to Seward with the supply to the Marine Industrial Park from Seward substation being at 69 kV. Two new three-winding transformers rated 12/16 MVA each would be installed in the Seward substation. The existing 7.5/9.4/10.5 MVA transformers in the Seward substation together with the 69 kV circuit switchers could be moved to the Marine Industrial Park substation and no modifications would be required to the newly erected 69 kV transmission line segment along Nash Road. With regard to routing alternatives, permitting is critical to insure construction in the 1984 season. The only major reroute considered was that proposed by Chugach Electric Association from their Cooper Lake Hydro Plant taking a route south of Kenai Lake to join the existing corridor in the area of the Snow River. Apart from any other considerations, we do not believe it would be possible to obtain the necessary permits to cross this environmentally sensitive area within the required time frame. Ebasco therefore recommends following the existing right-of-way except where improvements can be made for access or avalanche protection without jeopardizing the completion date. Some possible areas for access improvement have been discussed in the report and others, such as utilizing rights-of-way currently held by the Alaska Department of Transportation and the Alaska Railroad, are still under investigation. 4816B 6-15 a = ee ee In addition, feedback from the public meetings will be considered in refining the route. This, together with recommendations on the underbuild between Seward and Lawing, will be finalized over the next few weeks as the detailed design develops. Ebasco will work closely with the city to insure that advantage is taken of all feasible opportunities to improve the line's cost and reliability. 4816B 6-16