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HomeMy WebLinkAboutReconnaissance Design & Cost Estimate Snettisham-Juneau DC Transmission System 1983Enclosure (tc) suN-1 Reconnaissance Design on and Cost Estimate SNETTISHAM/JUNEAU DC TRANSMISSION SYSTEM Alaska Power Authority LIBRARY COPY Prepared for UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION Under Contract No. 85-82AP10041 APRIL 1983 Enclosure (3) Juneau Area Generation Facilities Unit Name Plant Name of Plant Location No. Type KW Snettisham Thane Sub 1 Hydro 23,000 2 Hydro 23,000 Total 46,000 Annex Creek Taku Inlet 5 Hydro 1,850 Hydro 1,850 Total 3,700 Gold Creek Capital Ave. 1 Hydro-NF 900 2 Hydro-NF 400 3 Hydro-NF 400 4 Diesel 1,250 5 Diesel 1,250 6 Diesel 1,188 7 Diesel 3,500 8 Diesel 1,188 Total 8,376 Upper Salmon Cr. Upper Salmon* 3 Hydro 1,400 Powerhouse 4 Hydro 1,400 Total 2,800 Lemon Creek Lemon Creek# i Diesel 2,500 2 Diesel 2,500 3 Diesel 2,500 4 Diesel 2,500 = Gas Turbine 17,500 6 Gas Turbine 17,500 Total 45,000 GHEA Auke Bay al Gas Turbine 3,000 Diesel 2,500 Total 5,500 Total Snettisham/AELP/GHEA 111,376 *During 1984 AELP expects to complete the rehabilitation of the Lower Salmon Hydroelectric Project which will provide 2,800 KW of capacity and 9,000,000 KWH of firm energy annually. #During 1984 AELP plans to install three additional 2,500 KW diesels at the Lemon Creek Plant. NOTICE This report was prepared as an account of work sponsored by the United States Government. Neither the United States nor the United States Department of Energy, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, mark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. RECONNAISSANCE DESIGN AND COST ESTIMATE OF THE SNETT ISHAM/ JUNEAU DC TRANSMISSION SYSTEM April 1983 Prepared for United States Department of Energy Alaska Power Administration Under Contract No. 85-82APi0041 Prepared by Teshmont Consultants inc. ll46 Waverley Street Winnipeg, Manitoba R3T OP4 3. RECONNAISSANCE DESIGN AND COST ESTIMATE OF SNETTISHAM/JUNEAU DC TRANSMISSION SYSTEM INDEX INTRODUCTION SUMMARY SELECTION OF DC RATINGS 3.1 General 3.2 Generation in the Juneau and Snettisham Areas 3.3. Juneau Load Projections 3.4 Ratings of DC Systems 3.5 Selection of Synchronous Condenser Ratings 3.6 Selection of DC Submarine Cable Size RELIABILITY 4.1 General 4.2 Existing AC Systems 4.3 DC Systems 4.4 Combined AC/DC System - Case 7A 4.5 Combined AC/DC System - Case 7B 4.6 Combined AC/DC System - Cases 7C and 7D DC FACILITIES 5.1 Converter Stations 5.2 Electrodes 5.3 DC Submarine Cable 5.4 DC Transmission Lines 5.5 Communication System COSTS ESTIMATES 6.2. Capital Costs 6.2 Operation and Maintenance 6.3 Transmission Losses GENERAL COMMENTS ON SYSTEM DESIGN 7.1 Benefits of Interconnection 7.2 Snettisham-Juneau-Skagway DC Scheme 7.3. Rating of Snettisham and Juneau Converter Terminals REFERENCES id WWWW WW 1 NUWwWrre > 1 hr 2 PPP bP Db 1 2 PDN EH uw 1 bh aon 1 WWNNFH bee ~ 1 ne Page Tables 3-1 Hydroelectric Generation in the Juneau/Snettisham Area 3-9 3-2 Load and Generation in the Juneau/Snettisham Area 3-10 4-1 Transmission Line Outages 4-5 4-2 . Snettisham-Juneau DC System, Estimated Forced and Scheduled Outages 4-6 4-3 Reliability Performance - Case 7A 4-7 4-4 Reliability Performance - Case 7B 4-8 6-1 Estimated Capital Cost of DC Transmission Facilities 6-5 6-2 Indirect Costs and Contingencies 6-6 6-3 Estimated Annual Operation and Naintenance Costs 6-7 6-4 Estimated Transmission Losses 6-8 Figures 3-l Transmission Routes Between Snettisham and Juneau 3@11 3-2 Simplified Single Line Diagrams for Cases 7A and 7B 3=12 3-3 Simplified DC Single Line Diagram, Cases 7C and 7D #13 3-4 Juneau Loads and Resources Based on Case 4 3-14 3-5 Juneau Loads and Resources Based on Revised Load Growth Projections 315 5-1 Typical Power Circuit Diagram, Juneau Converter Station 5-5 5-2 Snettisham DC Facilities 5-6 5-3 Converter Station Site, Snettisham 5-7 5-4 Juneau DC Facilities 5=8 5-5 Converter Station Site, Juneau 5-9 6-1 Cost of DC Schemes Between Snettisham and Juneau 6-9 6-1 DC Contract Package Cost Estimates 6=20 6-2 DC Submarine Cable Cost Estimates 6-11 Appendix I DETAILED COST ESTIMATES 1. Introduction The Alaska Power Administration (APA) is carrying out a study of the interconnection of a number of communities in Southeast Alaska to utilize hydroelectric plants in that region and to minimize fossil-fueled generation. As part of that study, APA authorized Teshmont in January 1983 to provide a cost estimate of a dc submarine cable transmission link between Juneau and Snettisham to provide a more reliable transmission system between the two locations. This work is an extension of the contract of Teshmont with APA to provide reconnaissance level designs and cost estimates for a number of transmission schemes that were provided by APA. This report covers establishing the ratings and preparing cost estimates of four dc schemes between Snettisham and Juneau as follows: Case 7A DC rating based on the dc system, plus local genera- tion which would be in place in Juneau by 1990, meeting the Juneau load to year 2000. This would defer additions of further fossil-fueled generation at Juneau which would have been necessary to take into account outages of the 138 kV ac transmission line between Snettisham and Juneau. Case 7B The dc rating equivalent to the fully developed Snettisham area generation. This would defer fossil- fueled generation additions at Juneau beyond the year 2000 which would have been necessary to take into account outages of the 138 kV ac transmission line. Case 7C As for Case 7A but assuming that there would be a dc connection from Snettisham to Petersburg/Ketchikan/ Borax (e.g. Case 4 in Reference 1). This would reduce the cost of the portion of the Snettisham terminal that can be considered part of the Snettisham-Juneau system as the terminal cost would be based on the incremental cost for increasing the dec rating from 25 MW. Case 7D As for Case 7B but again assuming that there would be a dc connection from Snettisham to Petersburg/ Ketchikan/Borax. The case numbering sequence is a continuation of the case numbering system used in the previous studies described in Reference l. 2. SUMMARY The dc systems described in this report will increase the reliability and security of the electrical supply to Juneau from the Snettisham area. At present, a power interruption on the 138 kV ac transmission system from Snettisham results in the shutting down of the Juneau load until such time as local standby fossil-fueled generation can be started. With the dc system in parallel with the 138 kV ac transmission line, trans- mission capacity equivalent to the rating of the dc system can be maintained. This will reduce the amount of load shedding in Juneau when transmission is interrupted on the 138 kV ac trans- mission line. When the Lake Dorothy hydro electric plant is installed in the early 1990's complete interruption of power from the Snettisham area on the 138 kV transmission line will only occur for outages on the section of the system between Taku East and Juneau. Outages on the longer section of the 138 kV transmis- sion line between Taku East and Snettisham will leave the Lake Dorothy plant connected and available to supply Juneau. The dc system ratings considered in this report are based on complete interruption of power transmission from the Snettisham area. The minimum and maximum dc system ratings that could reasonably be used were established as follows: Case 7A DC system rating: 35 MW. With this rating, the dc system plus the standby genera- tion that would be in place in Juneau by 1990, will meet the Juneau load up to the year 2000, based on the recently revised load growth projections. Case 7B DC system rating: 110 MW. With this rating, the dc system plus the standby genera- tion that would be in place in Juneau by 1990, will meet the Juneau load beyond year 2000 even under the assumption of a higher rate of load growth in Juneau, as used in previous’ studies. The load in that year will have increased to a level at which it would not be possible to defer addition of fossil-fueled generation by increasing the rating of the de system. Case 7C Snettisham-Juneau de system rating: 35 MW. In this alternative, the Snettisham-Juneau dc system is interconnected with the dc transmission system between Petersburg, Ketchikan and Borax described in Case 4 of te 1 ‘i Reference 1. The dc system would have five dc terminals. The ratings are equal to those in Case 7A and the cost estimates are the costs to construct the Snettisham-Juneau portion of the system assuming that the dc system of Case 4 is already in place. Under normal operating conditions with the ac and de transmission systems to Juneau in ser- vice, the rating of the Snettisham terminal is sufficient to permit all the surplus energy in the Snettisham area to be transmitted south to Borax. Case 7D Snettisham-Juneau dc system rating: 110 MW. This dc scheme is similar in configuration to Case 7C except that the dc rating is equal to that in Case 7B. The dc schemes are monopolar with sea return. The de voltage selected for all the schemes is -100 kV. A reliability analysis was carried out to estimate the impact of dc transmission on the reliability of power supply to the Juneau area. An estimate was made of the cost benefit due to the increased energy availability at Juneau due to the addition of de transmission. A brief description is given of the dc terminal stations, dc submarine cable, dc transmission lines, sea electrodes and communication requirements. A summary of the estimated capital cost of the dc transmission facilities is as follows: Estimated Capital Cost (in millions of 1982 dollars) Case 7A - 35 MW 30.6 Case 7B - 110 MW 49.2 Case 7¢ - 35 MW 22.1 Case 7D - 110 MW 40.6 An estimate of capital costs of dc transmission facilities for ratings between 35 and 110 MW is given in the main body of this report. The cost estimates are based on evaluation of cost information obtained from equipment suppliers and other sources, as described in Reference 1. These cost estimates are considered conservative and suitable for budgeting purposes. However, cost estimates from suppliers displayed significant differences so “high" and "low" estimated project costs are also given. Appendix I gives detailed cost estimates itemized in accordance with the Federal Energy Regulatory Commission (FERC) Uniform System of Accounts. to ' to The operating and maintenance costs for these schemes are also given. Once a rating of the dc system between Snettisham and Juneau is selected, it will be necessary to carry out further system studies to finalize system parameters, particularly synchronous condenser sizes, and to design a suitable load shedding scheme for Juneau. Also, the dc equipment and dc submarine cable manufacturers could be asked to supply estimating prices for equipment with specific ratings to confirm the estimates given in this report. A general discussion of the benefits of interconnecting the power systems in Southeast Alaska is included in the report. The points discussed include the improved flexibility with regard to generation development, maximum use of available hydroelectric energy, increased reliability of supply to com- munities and minimization of environmental impact on Southeast Alaska. 2 ! w 3 Selection of Ratings of DC Systems 3.1 General As noted in Section 10 of a previous report (Reference 1), most of the power for Juneau is obtained at present from hydroelec- tric plants located in the Snettisham area. The power is transmitted over one 138 kV ac transmission line and it is understood that if a second 138 kV line was built, the terrain would require that it be on the same right-of-way. The second line would not greatly increase reliability of the transmission system as the same event could result in the loss of both lines. To provide for the possibility of prolonged outages of the line, the APA load resource analysis is based on local capacity reserves in Juneau being equal to about 100% of the local load. The reserve capacity is mainly fossil-fueled generation. A dc system from Snettisham to Juneau would operate in parallel with the existing ac line and would provide an alternative transmission supply to Juneau. As this firms up the trans- mission system, it would allow substantial reduction in the amount of required reserve generating capacity in Juneau. In accordance with Reference 1, it is assumed that the dc system would commence operation in 1990. The basic criteria for selecting the rating of the dc systems, as described in Section l, is that adequate generating capacity must be available to Juneau to meet the load with the 138 kV ac line between Snettisham and Juneau out of service. After Lake Dorothy is constructed, the output of that plant would be available to Juneau during an outage of the ac line section between Snettisham and Lake Dorothy. However, for an outage between Lake Dorothy and Juneau, it would not be possible to transmit any power over the ac line to Juneau. Since this latter condition is more severe, the ratings of the dc systems are based on that condition. The selection of the de ratings is based on two load growth projections that were provided by APA. A load growth pro- jection from previous studies (Reference 1) was used for establishing the relatively large dc rating used for Cases 7B and 7D, while a revised load growth projection utilizing a lower growth rate was the basis for selecting the smaller dc rating for Cases 7A and 7C. The use of the data associated with the two load growth projections forms a basis for the selection of maximum and minimum dc system ratings that could reasonably be used between Snettisham and Juneau. In Cases 7C and 7D, it is assumed that the Snettisham-Juneau dc system would be interconnected with the de system of Case 4 of a=! the study described in Reference l. Case 4 was selected from those considered for that study as it required the most rapid build-up of generation in the Snettisham area and the largest amount of generation. With the extension to Juneau, the resulting de scheme would be five terminal, interconnecting the main load and generation centers in Southeast Alaska, from Juneau to Borax. The ac and dc transmission routes between Snettisham and Juneau are given in Figure i-l. Simplified single line diagrams of the transmission schemes for Cases 7A and 7B are shown in Figure 3-2 and for Cases 7C and 7D, in Figure 3-3. The dc systems are monopolar with sea electrodes. 3.2 Generation in the Juneau and Snettisham Areas The ratings and average energy of the hydroelectric generating ‘plants in the Snettisham and Juneau areas are given in Table 3-1. The Snettisham. plant and the small hydroelectric plants in Juneau are currently in service. Diesel generation is also provided at Juneau. The Crater Lake unit and the Long Lake Dam Addition, which will increase storage but not capacity, are planned to be in service before 1989. The Crater Lake unit would feed into the sub- station at Snettisham. The load/resource analysis assumes that additional diesel or gas turbine generation is planned for installation in Juneau to maintain 100 percent standby genera- tion in the Juneau area to ensure availability of power supply during outages of the 138 kV transmission line from Snettisham. The Lake Dorothy hydroelectric plant is planned to be available in 1992 for Case 4 and in 1994 for the generation installation program for the revised load growth projections. This plant is located on the east side of Taku Inlet and would connect to the 138 kV transmission system near the Taku East submarine cable termination. The generation planning for Case 4 includes the Sweetheart Lake generating plant which would be connected to the Snettisham substation. This plant would be installed in 1996. The Speel River and Tease Creek hydroelectric plants that are shown in Table 3-1 are possible future plants but are not included in the generation planning discussed in this section as they would not be constructed until well beyond the year 2000. 3.3 Juneau Load Projections Two load growth projections were used in the study. The load growth projection up to year 2000 in Figure 3-4 was used for Cases 7B and 7D and is based on load information given in the APA load/resource analysis (Reference 3). It had been used in the previous studies described in Reference l. The load growth projections were subsequently updated as shown in Figure 3-5 to reflect a lower load growth (Reference 4). The main reasons for the revision were a lower number of assumed all-electric customers as well as lower consumption per customer for these customers. The loads in the Juneau and Snettisham areas in years 1989 and 2000 are shown in Table 3-2. The total load includes 5% for transmission losses. 3.4 Ratings of DC Systems Case 7A In this scheme, the MW rating of dc system is selected so that the generating capacity available to Juneau from Snettisham over the dc scheme plus the local generation which. would be in place when the dc scheme goes into operation in 1990, will meet the Juneau load in year 2000, assuming the revised load growth. These assumptions result in the smallest dc ratings that could reasonably be considered for the Snettisham-Juneau connection. The following data is taken from Table 3-2 for the revised load growth projections: Year Juneau Load Snettisham-Juneau Total Load Juneau (peak MW) Transmission Supplied From Generation Losses (MW) Snettisham (peak MV) (MW) 1989 70.0 208 7345 70.0 2000 103.7 5.4 108.9 Note l Note l Juneau generation in year 2000 would be 103.7 Mi if the dc system is not installed. If the de system is installed, it is assumed that the generation at Juneau would remain at 70.0 MW up to the year 2000. The dc system rating required at Juneau is equivalent to the total load in year 2000 less Juneau generation in year 1989, i 'Ge 103.7 — 70.0 MW or 33.7 MW. Thus a rating for the dec system of 35 MW was used. Case 7B For Case 7B, the de system rating is based on firming up trans- mission from the Snettisham area so that for the total genera- tion available to the Snettisham/Juneau area in Case 4, the peak Juneau load can be met with the APA criteria of 20 percent system generation reserve. This size of dc system would delay the addition of fossil-fueled generation at Juneau beyond the year 2000 and results in the largest dc rating that could reasonably be used with the given load and generation data, From Table 3-2 Juneau generation in year 2000 would be 177.6 MW if the dc system is not installed and 105.1 MW if the dc system is installed. The total peak generation available from the Snettisham, Crater Lake and Lake Dorothy plants is 124.4 MV. When the Sweetheart Lake plant is added, the total generation in the area is 157.8 MW. The total installed generation available to the Juneau area in year 2000 is the generation in the Snettisham area less trans- mission losses (5 percent assumed in the APA load/resource analysis) plus local generation in Juneau, i.e. 157.8x0.95 plus 105.1 or 255 MW. The maximum permissible Juneau load that can be served by that generation if the 20% generation reserve criteria is met would be given by the total generation in Juneau and Snettisham divided by 1.2, that is, 213 MW. The rating of the de system was selected for this load so that when the 138 kV line between Snettisham and Juneau was out of service, the dc system plus local Juneau generation could meet this load. Thus the rating of the dc system required is equal to the Juneau load less the local generation, that is 213-105.1 MW or 107.9 MW. On this basis a de rating of 110 MW was selected for Case 7B. Case 7C For this alternative, the Snettisham-Juneau system is part of the de transmission system connecting Petersburg, Ketchikan and Borax as in Case 4 of Reference 1. The dc system would have five terminals as shown in Figure 3-3. The same de ratings as those in Case 7A have been selected for the Snettisham-Juneau system. The dc rating of 35 MW at the Snettisham terminal provides suf- ficient capacity to transmit south surplus energy from the Snettisham area. From Figure 3-5 the maximum energy surplus in the area occurs in 1995 and corresponds to 140 GWh. At the 80 percent load factor of Borax this energy corresponds to about 20 Mii. Thus with the Snettisham terminal rating of 35 MW there is still capacity available to transmit power to Juneau by dc 3-4 while transmitting the surplus south. During an outage of the ac line, of course, the transmission of surplus south would be curtailed to provide power to Juneau. The amount of surplus energy in the Snettisham/Juneau area decreases after 1995 as the Juneau load increases. The loading of the dc system between Snettisham and Juneau will depend on a number of factors including the optimum loading of 138 kV transmission line and parallel dc system and the optimum generation dispatch condition for the interconnected Southeast Alaska system. Case 7D For this alternative, the dc system described for Case 7B would be part of the dc system connecting Petersburg, Ketchikan and Borax as shown in Figure 3-3. The rating of 110 MW for the Snettisham-Juneau dc system would enable the surplus energy that is available in the Snettisham area, particularly after the Sweetheart Lake plant is completed, to be transmitted south to Borax. The maximum surplus energy occurs in 1996, as shown in Figure 3-4, and corresponds to 190 GWh or about 27 MW at the 380 percent load factor of Borax. It would be possible to transmit a substantial amount of power to Juneau’ from Snettisham over the dc system at the same time as power is being transmitted south. 3.5 Selection of Synchronous Condenser Ratings Synchronous condensers for the dc system are sized such that the dc systems can continue to operate up to their ratings even when the parallel 138 kV transmission line is out of service. This would provide an improved reliability of supply to Juneau from the combined ac/dc system as compared to that with the single 138 kV ac line. At present, an interruption to the 138 kV transmission line results in a power interruption to essentially all of the load at Juneau until such time as local diesel and gas turbines can be started or the 138 kV transmission line and associated generation is restored to service. With a dc system in parallel with the 138 kV transmission line, firm transmission capacity can be provided equivalent to the rating of de system. This will reduce the amount of load shed in Juneau when transmission is interrupted on the 138 kv transmission line. To ensure that the dc system will continue operating when power transfer on the 138 kV line is interrupted, adequate short circuit MVA must be available at the inverter ac bus. Short B=) circuit MVA can be provided by synchronous condensers. Accept~ able dc system performance can be achieved with an effective short circuit ratio of about 2.5 and this value was used as a basis for selecting synchronous condenser rating in this study. A lower short circuit ratio may also provide satisfac- tory performance but this would need to be confirmed by simula- tor studies. The effective short circuit ratio is the ratio of the three phase short circuit level at the converter ac bus to the dc power transfer level. The local hydroelectric generators in Juneau would assist in providing short circuit level to the Juneau system if they are in operation when power from Snettisham is interrupted. How- ever, these generators are generally not in service for part of the year and so the synchronous condenser sizes were determined with the generators out of service. It should be noted that if synchronous condensers are not provided, the inverter ac bus voltage will collapse with the result that the dc system will shut down and will be unable to restart. As standby diesel and gas turbine generation was brought into operation the short circuit level of the Juneau ac system would increase, thus stabilizing the ac bus voltage, and making it possible for the dc system to satisfactorily operate at a level determined by the available short circuit level. Other factors which can affect the system design should be studied in detail in the future after the rating of the dc interconnection is selected. These include consideration of the Juneau ac system inertia to maintain ac system frequency within specified limits for ac and dc system faults, the rate at which the loading on the dc system can be increased particu- larly with regard to the supply of VARs from synchronous con- densers, determining suitable load shedding schemes to minimize the disturbance to the Juneau load for power interruption and establishing the best method of limiting fundamental frequency overvoltages. Cases 7A and 7C Synchronous condenser requirements can be reduced if arrange- ments can be made to operate standby generators as synchronous condensers. This would require provision being made initially for a clutch to allow coupling and decoupling of the generator and prime mover during operation or, alternatively, decoupling the prime mover when it is at rest and providing a starting system to enable operation of the generator as a synchronous condenser. Standby generation of about 15 MW is required to be added to the Juneau system between 1985 and 1989. For the purposes of 5=6 this study it is assumed that these generators would be suit- able for operation as synchronous condensers but the cost of making such provision (which would be about 5 to 10 percent of the capital cost of the gas turbines) is not included in the cost estimates. Based on a synchronous condenser subtransient reactance plus step-up transformer impedance of about 0.3 per unit on the machine base, an additional synchronous condenser of 15 MVAR is required to provide the required short circuit level. The cost estimates include the cost of this synchronous condenser. Some load shedding would still occur when transmission on the 138 kV transmission line is interrupted as the dc system would not meet the entire Juneau load. It would be necessary to start the standby generation to make up the power deficiency. Case 7B and 7D The selection of synchronous condenser ratings for Case 7B was made on the same basis as for Case 7A. Standby generation of about 30 MW is required between 1985 and 1989 and it is assumed that these generators could be operated as synchronous condensers. Additional synchronous condensers with total rating of 60 MVAR are required to provide the necessary short circuit level. Two 30 MVAR synchronous condensers have been assumed for the cost estimates. As with Case 7A, some load shedding may occur, but of a lesser amount, when transmission on the 138 kV transmission line is interrupted and the Juneau load exceeds the rating of the dc system. It would be necessary to start standby generation to meet the total load. 3.6 Selection of DC Submarine Cable Size The size of the dc submarine cable is based on the optimization of the installed cost of cable and the cost of losses. Also the cable size selected must have adequate thermal current carrying capacity so that the de system can operate up to its rating. The basis of the cost optimization calculations is described in Appendix 1 of Reference l. The cost of losses was determined from a cost of energy of 10 cents per kWh with an interest rate of 9 percent over a period of 30 years. The energy losses depend on the load factor of the dc system. The load factor is affected by the method of operation of the ac and dc systems between Snettisham and Juneau. Normally, the ac and dc systems will share the transmission of power. A possible operating mode would be to load the systems so that transmission losses are minimized. This would result in the dc systems being operated at about 50 to 60 percent of their rating when peak generation is being transmitted in year 2000. As the generating plants have a plant factor of about 50 per-= cent, the load factor of the de systems would normally be well below 50 percent. The optimum dc submarine cable size for Cases 7A and 7C was selected conservatively based on a load factor of 50 percent of the de system rating (35 MW). The optimum cable is 450 MCM. For Cases 7B and 7D, .the load factor of the de system could vary greatly depending on the operating conditions. Therefore it was decided to select a cable size which would have a thermal current rating equal to the dc system rating, (1100 A). Hence, a cable size of 1100 MCM was selected. The current rating of the cable is based on information supplied by cable manufacturers for the study described in Reference 1. Where the cable is buried at the cable terminations, some special precautions, such as increasing the thermal conductivity by using special back-fill material, may be required. TABLE 3-1 HYDROELECTRIC GENERATION IN JUNEAU/SNETTISHAM AREA Capacity Average Peak Nameplate Energy (MW) (MW) (GWh ) Utilities (Juneau) 11.9 10.35 60 Snettisham 54.2 47.2 216 Crater Lake 31.1 27.0 118 Long Lake Dam Addition « a 25 Lake Dorothy 3962 34.0 150 Sweetheart Lake 33.4 29.0 125 Speel River tau 63.0 275 Tease Creek 18.4 16.0 70 Note: Capacity and average energy of generating plants are as given in Reference 4. B=9 TABLE 3-2 LOAD AND GENERATION IN JUNEAU/SNETTISHAM AREA (Peak MW) Year: 1989 Load Growth Revised Projections Load Used in Growth Previous Projection Studies Load in Juneau 98.2 70.0 Losses 4.9 3.5 Total 103.1 73a Load generation in Juneau Hydroelectric 11.9 11.9 Fossil fueled 932 $8.1 Total 105.1 70.0 Generation in Snettisham Area Snettisham 54.2 Sas 2 Crater Lake sled sled Lake Dorothy Total 855.3 85.3 Sweetheart Lake (Cases 4 and 6A only) Total (1) 2000 Load Growth Projections Used in Previous Studies Generation required at Juneau to meet load/resource Revised Load Growth Projection criteria if no dc system between Snettisham and Juneau. = \e JUNEAU DOUGLAS ISLAND ADMIRALITY ISLAND 83/03/03 DC SUBMARINE CABLE \ oN Z 1O0kY 42 WILES \ r SNETTISHAM \ CRATER LAKE Suit MILES a 138 kV \ vs— _ AC TRANSMISSION LINE —= nn TESHMONT CONSULTANTS INC es JUNEAU (CONVERTER STATION Qo ao Ya DOROTHY S SUBMARINE ont LONG LAKE ~ o-oo TRANSMISSION ROUTES BETWEEN SNETTISHAM AND JUNEAU FIGURE 3-1 3-11 cv) LAKE DOROTHY (39.1 MW JUNEAU ala ; THANE SUBSTATION | 69 kV 15 MILES | 7.4 MILES 3.1 MILES ! 30 MILES TAKU #EST TAKU EAST 438 kV AC | | | 40 MILES SYNCHRONOUS -100kVOC , 35.MW | CONDENSER 15 MVAR ie Case 7A | | | LAKE DOROTHY (39.1 MW) \ JUNEAU aK THANE SUBSTATION 69k | 5 MILES | 1.4 MILES 3.1 MILES | 30 MILES | ee ee ee | TAKU WEST TAKU EAST nee | | LOAD 1 MILE 40 MILES SYNCHRONOUS -100 «VOC , 110 MW CONDENSERS 2x 30 MVAR Case 7B SNETTISHAM SUBSTATION 138 kV | | | Oy) SNETTISHAM (54.2 MW) 5S MILES SNETTISHAM | SUBSTATION | 138 kV SNETTISHAM (54.2 MW ) ———— OVERHEAD LINE —-——-- SUBMARINE CABLE SIMPLIFIED SINGLE LINE DIAGRAMS FOR CASES 7A & 7B FIGURE 3-2 n= TESHMONT CONSULTANTS INC. 3-12 _—————<—_ me qt | 69 kV SYNCHRONOUS CONDENSERS -100 kV CASE 7C 1x15 MVAR CASE 70 2x30 MVAR CASE 7C ui JUNEAU 42 mi CASE 70 110 MW 138 kV a CASE 7C 113 mi CASE 70 110MW SNETTISHAM mi 138 kV PETERSBURG 119 mi 115 kV = KETCHIKAN 72 mi 69 kV BORAX SYNCHRONOUS CONDENSERS 2x45 MVAR (-] HIGH SPEED BREAKER SIMPLIFIED DC SINGLE LINE DIAGRAM CASES 7C &7D FIGURE 3-3 TESHMONT CONSULTANTS INC. 83/03/03 3-13 PEAK DEMAND / CAPACITY (MW) ENERGY (GWh) JUNEAU LOADS AND RESOURCES BASED ON CASE 4 180 4 160 5 140 4 120 100 a“ e SWEETHEART LAKE poy io it UAKE OOROTHY _praugdles ea an ol a 4 | . I | ol CRATER LAKE —— | ° —— soe = | OAD 80 4 i © oe ee ame ee ee oo HYDRO RESOURCES 60 86 88 90 92 94 96 98 2000 YEAR 700 7 SWEETHEART LAKE f= ————=— ! | 650 4 | i ] 600 4 | LAKE DOROTHY parti Ya §50 4 ° a 500 4 | o oad 450 4 Fa 400 | ° CRATER CAKE ne 350 4 86 LONG LAKE mom ~ —-—- LOAD m= AVERAGE HYDRO GENERATION 88 90 92 94 96 98 2000 YEAR Cases 7B & 7D FIGURE 3-4 er aes ae TECHNO. CONSULTANTS hpodqueanaine-iedeoedieddniiianiie 3 140 S LAKE DOROTHY r Sear es ea a = = 120 1 ! g 100 | _ — 2 CRATER LAKE R= = : ~ 1 ee > . 3 80 1 —— S | _— = |1o.— 5 60 =? ee = LOAD <s < ------ HYDRO RESOURCES Ge 86 88 90 92 94 96 98 2000 YEAR 600 - 550 4 500 4 450 4 I I I | ! | I ] LONG LAKE R= ————— i I . CRATER LAKE p———e—s a“ ENERGY (GWh) ee ee = | OAD 300 + 7 fas ee AVERAGE HYDRO GENERATION 200 T T T T T i a 1 86 88 90 92 94 96 98 2000 YEAR Cases 7A & 7C JUNEAU LOADS AND RESOURCES BASED ON REVISED LOAD GROWTH PROJECTIONS FIGURE 3-5 [ine TEEN CONSULTANTS INC. SS Se — 4. Reliability 4.1 General A simplified reliability analysis was carried out to estimate the impact of the addition of a dc transmission system between Snettisham and Juneau on the reliability of power supply to the Juneau area. The reliability analysis covered three transmis- sion systems as follows: a) the existing ac system consisting of a 138 kV transmission line from Snettisham to Juneau. b) a combined ac/dc system consisting of a 35 MW de transmis- sion link between Snettisham and Juneau in parallel with the existing ac system of (a). The dc system is described in Section 3.4 under Case 7A. Cc) a combined ac/dc system consisting of a 110 MW dc trans- mission link between Snettisham and Juneau in parallel with the existing ac system of (a). The dc system is described in Section 3.4 under Case 7B. 4.2 Existing AC System APA has provided data on outages of the 138 kV transmission line between Snettisham and Juneau over the past six years. The data are summarized in Table 4-1. As indicated in Table 4-1, there have been on the average 3.67 forced outages per year of that line and the average outage duration is 26.6 hours per outage. The average total outage duration per year is 3.67 x 26.6 = 97.6 hours per year. The outages included one structural transmission line failure of prolonged duration in that 6 year period. Excluding that failure, the remaining outages represent 3.5 outages per year with an average duration of 11.9 hours per outage. There have been on the average 1.17 scheduled outages of the 138 kV transmission line per year with an average duration of 26.6 hours per outage. The average scheduled outage duration per year is 1.17 x 26.6 = 31.1 hours per year. Since most of the power requirements for Juneau are supplied over this single 138 kV line from Snettisham, each forced outage event of the line will result in an interruption of supply to Juneau and consequent loss of load. Standby fossil-fueled generation must then be started and power supply restored. The fossil-fueled generation is shut down after the supply from Snettisham is restored. In the case of scheduled outages, it is assumed that fossil- fueled generation is brought on line prior to the outage so that there is no interruption in the supply of power to Juneau. Based on the outage data in Table 4-1, it is expected that there will be 3.67 events per year with loss-of-load or load shedding at Juneau up to the amount of power being supplied from Snettisham. In 1990, the peak capacity from Snettisham and Crater Lake plants is 85.3 MW. When the Lake Dorothy plant with a capacity of 39.1 MW is installed in 1994 as per the revised load growth projections, the maximum amount of power supplied over the line will increase to 124.4 MW. In this analysis, it is assumed that in 1994 and beyond, 3/4 of the outage events would involve interruption of supply from Snettisham only (i.e. 85.3 MW) and the remaining 1/4 of the events would interrupt the entire supply of 124.4 MW. The ratio of outages is in proportion to the transmission line lengths. 4.3 DC Systems The dc system between Snettisham and Juneau will consist of converter terminals at the two stations and a 40 mile 100 kv submarine cable and 2 miles of overhead lines interconnecting the two stations as described in Section 5. In Case 7A, the converter terminals are rated 35 MW. One 15 MVAR synchronous condenser is provided at Juneau. In Case 7B, the converter terminals are rated 110 MW and two 30 MVAR synchronous condensers are provided at Juneau. The expected number of forced and scheduled outages of the dc system, and the average duration per outage, are shown in Table 4-2. The outage data are based on historical experience of dc systems and dc cables in service around the world as described in Section 6 of Reference 2. As indicated in Table 4-2, it is expected that there will be about 11 forced outages and one scheduled outage per year for the system in Case 7A, and 12 forced outages and one scheduled outage per year in Case 7B. However, most of these outages will not result in interruption of power supply to Juneau as the dc systems are operated in parallel with the ac system. Hence it is necessary to consider the impact of outages on the transmission capability of the combined ac/dc system. 4.4 Combined AC/DC System - Case 7A The transmission system configuration for this case is shown in Figure 3-2. As stated in Section 3.5, the proposed synchronous condenser capacity assumed to be available would enable rapid loading of the de system to its full rating following loss of the parallel 138 kV ac line. This will minimize the amount of load shed at Juneau. (This reliability analysis is based on the premise that this operating criteria will be fulfilled in the final design of the dc system and that detailed studies will be carried out at a later date to confirm the presently selected synchronous condenser sizes or to select appropriate ratings to achieve this performance). Also as stated in Section 3.1, the dc rating is a minimun rating that could be utilized based on the revised load growth projections for Juneau. For this case, the generating capacity at Snettisham (Snettisham and Crater Lake) is 85.3 MW in 1990. Lake Dorothy, with a capacity of 39.1 MW, is installed in 1994. The total capacity that is transmitted to. Juneau is therefore 85 MW between 1990 and 1993, and 124.4 MW between 1994 and 2000. The reliability performance of the combined ac/dc system is shown in Table 4-3. The reliabilty performance of the ac system alone for the same generation installation program is also shown for comparison purposes. As shown in Table 4-3, the total number of transmission outages of the combined ac/dc system would be 16.9 per year as compared to 4.84 outages per year for the ac system alone. However, most of the dc system outages do not result in loss of load or load shedding. The number of load shedding events per year of the combined ac/dc system is 3.83, slightly greater than the 3.67 events per year for the ac system alone due to the addition of the dc system. However, because the dc system can supply 35 MW during an ac system outage, the amount of load shed or the curtailment in overall transmission capacity for most of the outage events for the combined ac/dc system is lower than for the ac system alone. The reduction in curtailment of delivered power is 35 MW for most events, and the reduction in curtailment of energy is 3950 MWh per year for the 10 year period between 1990 and 2000. The amount of energy is based on an assumed load factor of 90% as the 35 MW represents a relatively small por- tion of the total Juneau load and the de system would therefore be loaded to almost its full capacity during each ac system outage. Hence the benefit provided by the 35 MW de system is that it reduces the amount of load shed at Juneau by 35 MW for 3.42 net events per year and reduces the amount of fossil-fueled energy by 3950 MWh per year. The net reduction of load shedding in the amount of 3.42 events is obtained from a reduction of load shedding at Juneau for 3.58 events on the ac system and an increase of 0.16 events due to de system outges. At an average (1982) cost of energy of 10.5¢/kWh from Juneau diesel/gas turbine plants, this represents a fuel saving of $415,000 per year, or a capitalized value, calculated at a 9 percent interest rate over a 30 year period, of $4.3 million. If the cost of fuel was escalated at 3 percent per annum the capitalized value would be $5.8 million. 4.5 Combined AC/DC System - Case 7B The transmission system configuration for this case is shown in Figure 3-2. The reliability performance of the combined ac/dc system and the alternative ac system alone is shown in Table 4-4. In this case, Sweetheart Lake (33.4 MW) is installed in 1996 and hence the total generation supplied to Juneau is 158 MW after 1996. It should be noted that the ac system alone cannot transmit the full capacity of 158 MW as the 138 kV ac submarine cable is thermally rated at 124 MVA. Hence an additional submarine cable or other reinforcement of ac transmission would be required if it were considered that all of the output from Snettisham and Lake Dorothy were to be transmitted by ac only. This aspect has not been considered in the reliability analysis. As shown in Table 4-4, the reduction in curtailment of delivered power due to the 110 MW dc system is between 85 MW and 110 MW for 3.40 net events per year. The reduction in energy curtailment is between 6363 and 8235 MWh per year. Assuming that the reduction in energy curtailment would remain at 8235 MWh per year for the remaining 20 year period (beyond 2000) of the 30 year assumed economic life, the capitalized value of this reduction in energy costs is $8.1 million or $11.3 million with 3 percent per annum fuel cost escalation. 4.6 Combined AC/DC System - Cases 7C and 7D The reliability performance of Cases 7C and 7D is expected to be equal to or slightly better then Cases 7A and 7B respec- tively in terms of supply of power to Juneau as power could be obtained from other locations, such as Petersburg, during periods when the ac line from Snettisham is not available and the dc station at Snettisham is also not available. However, the amount of support to Juneau during such emergencies is dependent (or limited by) the rating of the dc station at Juneau. TABLE 4-1 TRANSMISSION LINE OUTAGES 138 KV LINE SNETTISHAM - JUNEAU (THANE SUBSTATION) Transmission distance - overhead line 37.4 miles submarine cable 3.1 miles Total 40.5 miles Forced Outages Scheduled Outages Number Average duration Number Average duration Year per year per outage (hrs) per year per outage (hrs) 1977 4 5.7 0 1978 4 0.2 0 1979 8 23.9 4 13.9 1980 2 13.9 2 2935 1981 3 oe 2 4355 1982 1 336.5 2 52.1 Average 3« 67 26.6 dai? 26.6 Average (excluding structrual failure) 3.5 11.9 Structural Failures 0.17 336.5 TABLE 4-2 SNETTISHAM - JUNEAU DC SYSTEM ESTIMATED FORCED AND SCHEDULED OUTAGES Forced Outages Scheduled Outages Average Average duration duration Item Number per outage Number per outage per year (hrs) per year (hrs) Snettisham de station 5) 5.0 coincident Snettisham-Juneau cable 0.06 720 - - Juneau dc station 5 5,0 1.0 120 Synchronous condenser (each) az 5.0 coincident TOTAL 11.06* 8.9* 1.0 120 * For systems with two synchronous condensers, the number of outages is 12.06 per year and average duration is 8.6 hours per outage. TABLE 4-3 RELIABILITY PERFORMANCE - CASE 7A (based on revised load growth projections for Juneau) Transmission Decrease (Juneau) in Curtailment Load Curtailment Compared to AC System Shedding in MW MW MWh (3) Outages Total duration Events 1990 1994 1990 1994 1990 1994 Type (1)Number hrs/yr I BNOw ws) 29.93 20,0,0/(2)) = 998) = 2000)" 993) 2000 AC System (existing) F 3. 67 97.6 36 67 85 85/124 s sy, ewe y 0 85 85/124 Total 4.84 128.7 3.67 85 85/124 AC System Plus 35 MW DC System - Case 7A AC-F 3.67 97.6 3558 50 50/89 35 35 3000 3000 0.09(4) 85 85/124 0 0 0 0 =S Pel] 3151 0 50 50/89 35 35 980 980 DC-F 11.06 98.2 0.04(5) 35 35 (35) (335) (30) (30) O26) 35) 35 0 0 0 0 =-S 1.0 120 0 0 0 0 0 0 0 Total) 16.9 32.33 BS 35 3950 3950 (1) F = forced, S = scheduled (2) It has been assumed that 3/4 of the ac system outages curtail transmission from Snettisham only (i.e. 85 MW) and the remainder from both Snettisham and Lake Dorothy (i.e. 124 MW) Calculated at assumed 90% load factor for 35 MW dc rating Outages of ac system during period when dc system is on forced or scheduled outage. Outages of dc system during period when ac system is on scheduled outage. The Mihs associated with these load shedding events (30MWh) reduce the energy in the line above (980MWh) which did not include the effect of dc outages. (6) Outage of de system during period when ac system is on forced outage. an ew rer TABLE 4-4 RELIABILITY PERFORMANCE - CASE 7B (based on the load growth projection used in previous studies for Juneau) Transmission Decrease (Increase) in Curtailment Load Curtailment Compared to AC System Total Shedding in MW MW MWh (3) Outages Duration Events 1990 1992 1996 1990 1992 1996 1990 1992 1996 Type (1) No. hrs/yr No./Yr__ 1991 1995(2) 2000(2) 1991 1995 2000 1991 1995 2000 AC System (existing) E 3.67 97.6 3.67 85 85/124 119/158 s a Sk sib 0 85 85/124 119/158 Total 4.84 E28. 7 3.67 85 85/124 119/158 AC System Plus 110 MW System - Case 7B ACG-F 3.67 97.6 3.58 0 0/14 9/48 85 85/110 110 4856 5213 6284 0.09(4) 85 85/124 229/258 0 0 0 0 0 0 —S TL? Shot 0 0 0/14 9/48 85 85/110 110 ES9E $703 2053 DC-F 12.06 102.2 0.05(5) 85 85/110 110 (85) €85/7T1R) (130) (79). €84) -(202) 0.13(6) 85 85/110 110 0 0 0 0 0 0 =§ 1.0 120 0 0 0 0 0 0 0 0 0 0 Portal 17.9 3.85 85 85/110 110 6363. .°6832. 8235 (1) F = forced, S = scheduled (2) It has been assumed that 3/4 of the ac system outages curtail transmission from Snettisham only and the remainder from both Snettisham and Lake Dorothy (3) Calculated at assumed 60% load factor for 110 MW dc rating. (4) Outages of ac system during period when dc system is on forced or scheduled outage. (5) Outages of dc system during period when ac system is on scheduled outage. The MWhs associated with these load shedding events (79/84/102MWh) reduce the eneryy in the line above (1586/1703/2053MWh) which do not include the effect of dc outages. (6) Outage of dc system during period when ac system is on forced outage. Su. DC Facilities 5.1 Converter Stations General features of converter stations are described in detail in Reference 1. This section highlights only the more signifi- cant aspects of the converters. At Snettisham the converter station would be connected to the 138 kV bus at the Snettisham substation. The ac filters would be connected to the bus by load break switches. There would be only one filter bank for the 35 MW terminal and two filter banks for the 110 MW terminal. Two filter banks are assumed for the larger rating so as to reduce the amount of MVAR switched at one time. The Juneau terminal would be similar to the Snettisham terminal except that the converter station would be connected to the 69 kV bus at the Thane substation. The Thane substation is conveniently located southeast of Juneau and is also the termi- nation point for the 138 kV system. Terminating the cable near Thane results in a cable route that is located away from main shipping anchorages. The synchronous condensers, one for the 35 MW terminal and two for the 110 MW terminal, are each con- nected to the converter bus via a step-up transformer and a circuit breaker. A typical power circuit diagram for the Juneau terminal is shown in Figure 5-l. DC filters have not been included as the short overhead dc transmission line sections at Snettisham and Juneau are assumed to be located away from telephone circuits. Presumably, an additional 138/69 kV autotransformer will be required at the Thane substation to supplement the two existing 53.3 MVA autotransformers when the generation in the Snettisham area increases. Also, the rating of the ac submarine cable across the Taku Inlet may have to be increased due to the pre- sent 124 MVA rating limit. A map of the proposed dc facilities in the Snettisham area is shown in Figure 5-2. The converter station site was visited during the field reconnaissance trip which was carried out as part of the work described in Reference l. The Snettisham ac switchyard has limited area for expansion and to obtain suffi- cient area for the converter station it may be necessary to relocate the road to the generating station. Figure 5-3 shows a typical converter station layout. The layout is similar to that given in Reference 1 except that the converter building size is increased by about twenty percent for the 110 MW termi- nal and there are two ac filter banks. A map showing the location of the dc facilities in the Juneau area is given in Figure 5-4. A typical converter station layout for Juneau is shown in Figure 5-5. The layout is p= similar to that for Borax in Reference 1 except for a larger converter building and filter area is required for the 110 MW terminal. The area near the Thane substation was not visited during the reconnaisance trip but based on discussion with APA there is likely sufficient land area available. 5.2 * Electrodes A detailed description of sea electrode requirements is given in Reference l. As the power will flow from Snettisham to Juneau and as the dec voltage is negative, the Snettisham electrode will normally he an anode and the Juneau electrode a cathode. As corrosion will occur only at an anode, the Snettisham electrode is larger than the Juneau electrode. For the purposes of the cost estimates, the electrodes are based on a 30 year life with the Snettisham terminal operating as an anode 100 percent of the time and the Juneau terminal operating as an anode 25 percent of the time with load factors of the de systems of 50 percent for Cases 7A and 7C and 40 percent for Cases 7B and 7D. The electrodes are assumed to be made of high-silicon iron, Durichlor 5l. All the electrodes, except for the Snettisham electrode in Case 7A, require fish screens because of potential gradients at the surface of the electrodes. The electrode in Juneau could, in fact, be designed for opera- tion as a cathode 100 percent of the time. Since there is no corrosion of the cathode, the electrode could be of a simple design with copper cables, reducing the cost of the electrode from that assumed for the cost estimates. 5.3 DC Submarine Cable The dc submarine cable would likely have the following general features, based on Reference 1: - copper conductor - impregnated paper insulation - lead sheath - polyethylene sheath - single or double armour wire - polyethylene yarn outer covering. The dc submarine cable route is based on the route proposed by the US Army Corps of Engineers during the investigation of dc transmission between Snettisham and Juneau in 1968. The cable route is shown in Figure 3-l. As in the previous study (Reference 1) the selected cable land- ing site at Snettisham is a small bay south of Star Point and the route from this point along Speel Arm would follow the west 5-2 shoreline, but sufficiently offshore to be in deep water. The route through Stephens Passage would follow near the north shoreline, pass close to Grave Point and pass up the north side of Gastineau Channel to a point near the Thane substation. 5.4 DC Transmission Lines Short lengths of overhead dc transmission line are required between the dc cable terminations and the converter stations at both locations. Based on the reconnaissance carried out for the study described in Reference 1, at Snettisham the dc transmission line route will go along the shoreline from the converter station located next to the Snettisham substation to the submarine cable termi- nal in a small bay south of Star Point, as shown in Figure 5-2. The length of the transmission line is about one mile. For Cases 7A and 7C, the dc line would carry one pole conductor and an electrode conductor. For Cases 7B and 7D there would be an additional separate pole conductor as one pole conductor is required for the connection to Juneau and the other pole con- ductor for the connection to Petersburg. At Juneau there was no reconnaissance of the cable termination site but based on discussions with APA it is likely that a con- verter station site can be found close to the dc submarine cable termination. For the purposes of the cost estimates, a transmission line length of one mile was assumed. The dc transmission line would carry a pole conductor and an electrode conductor. Conceptual designs of the dc transmission line structures are given in Reference l. A "Bittern" conductor, 1.345 inch dia- meter, 54/7 ACSR, was assumed for the cost estimates for all the schemes. 5.5 Communication System For optimum operation of the dc system, a communication system with high reliability and security is required between Snettisham and Juneau for the transmission of converter control and supervisory data. For Cases 7A and 7B, the main communication system would be by microwave with terminal stations at Snettisham and Juneau and two repeater stations. As in the previous study, it is assumed that these communication facilities would be owned by the entity operating the dc system. The back-up system would consist of channels leased from Alascom. This leased system would utilize microwave links that do not involve satellite links as satellite links introduce 5-3 transmission delay times that are not acceptable for dc links. Cases 7C and 7D would use similar main and standby communica= tion systems although the main communication system is assumed to require only one additional terminal station and one addi- tional repeater station over that necessary for Case 4. These cases, being multiterminal, will require communications to the central controller and the operations center. In the previous study (Reference 1), these were located in Ketchikan and Juneau, respectively. 5-4 | SYNCHRONOUS CONDENSERS 12 = PULSE VALVE GROUP | | SEA ELECTROOE CONNECTION ee ey arasnasna ee! rm oe EEE BA / ‘ 8 Gy t> (> ~ OC = LINE SWITCHING vo 8° a9 HSS TR 89 | | Vv SEA ELECTRODE TYPICAL POWER CIRCUIT DIAGRAM JUNEAU CONVERTER STATION FIGURE 5-1 TESHMONT CONSULTANTS s-Ss INC | Cc ; AC FILTERS | CA Tse HSS \ oO Se ie Ss / / v WALL BUSHING CURRENT TRANSFORMER CAPACITOR LIGHTNING ARRESTER LOAD SWITCHER RESISTOR REACTOR SYNCHRONOUS CONCENSER THYRISTOR VALVE CONVERTER TRANSFORMER GROUNOING TRANSFORMER TRANSOUCTOR SYNCHRONOUS COND TRF POTENTIAL TRANSFCRMER VOLTAGE OIVIDER AC CIRCUIT 3REAKER OISCONNECT CR GROUND Sw HIGH SPEEO SWITCH TO SNETTISHAM a= pi sti 807 eure a aera ONT SINVLINSNOD LNOMHS3L ere er ee ee ei @-S 3yYNDIS SAILIMOVA OG WVYHSILLANS aiuvwens’ 90 =< SS a oe Geo LR NSS 9NI7 300819373 ONY. = x SSS=— INIT NOTSSINSNVYL 905 Q0U193 13" ERPS / a Aa: y CS ~ A TAF \ 1S _¥3LU3ANO9 SIVHS LL LINS cee S 128 kV SZ TRANSMISSION LINE ra OC TRANSMISSION . LINE & ELECTRODE LINE » ) . Kb | \ \ ‘ | \ i PCWER“OUSE / ENTRANCS: Ly 7 RCAD | FISH HATCHERY | <I — AC FILTERS ' ' | [ een ee Ki : \ ‘ — Fis | — | ~ 1 Comey , ‘ at —J__ac FILTERS an Y | | I =a ee ee Se iS Eee Sea | \ x \ © SMOOTHING) REMOVE EXISTING OE rey H \ ————— FENCE ee —*— a poo + 4 yy z / i x . . . 4 CONVERTER — LC % TRE | see > / es eee | |conrren | CONVERTER | BUILOING BUILOING 106236} (26 1 46°) t | \ NOT TO SCALE | Typical Layout for Case 7B CONVERTER STATION SITE. SNETTISHAM FIGURE 5-3 be TESHMONT CONSULTANTS INC Se ee 83/03/03 5-7 8-S pn ent a “ON! SINYIIUASNOD LNOWHS31 £0, £0/€8 y-S 3YNDSIS SAILIMOVA OG NVANN VWaNS cae tee a (1 sais 300419373 907. 1Y3ANO9 Sa 4 : We. yoapeaa) | COOLER if] f q C:RCUIT BREAKER | al YA i la Ree | | | ———$—_. »— ‘ SYNCHRONOUS CONOENSER 1 | TRE 7“ o> ——_+ aie \ | ica eee aaa = 1, | AUXILIARY oisconnect | Loan | BUILDING | switcr ; BREAK | (30! « $0") | . op —_————. aaa | | ! | pil | SYNCHRONOUS CONOENSER (Seg) | Rectan ee i COOLER j \ 170° | [oa] | t | coNveRTER | | ITAANSECRMER | | CONVERTER | contROL | | i BUILDING | SUILOING | | \ i (281 48) (16 436) j | | , ea | \ | , TO SNETTISHAM ELECTROOE LINE | oe (CABLE) ete NOT TO SCALE Typical Layout for Case 7B CONVERTER STATION SITE JUNEAU FIGURE 5-5 AaNaNa TESHMONT CU SERS INC. PA ee ee a 6. Cost Estimates 6.1 Capital Costs The capital cost estimates for the de facilities for Cases 7A through 7D are summarized in Table 6-1. The costs for Cases 7C and 7D are lower than Cases 7A and 7B as they represent the additional costs that would be involved over the cost of the dc system required for Case 4. The rating of the Snettisham terminal in Case 4 is 25 MW. Details of the capital costs are given in Appendix I in accord- ance with the FERC Uniform System of Accounts. The cost estimates are based on July 1982 price levels. Federal and State taxes and insurance are not included. How- ever, customs duty has been applied to the estimating prices submitted by foreign suppliers to cover the equipment to be imported. The estimates do not include interest during con- struction. The indirect costs which include project management, engineer- ing and Owner's administration and contingencies have been allowed for as percentages of the capital costs. These per- centages are given in Table 6-2. Project management includes overall coordination, monitoring and control of engineering, procurement and construction of the work. Engineering includes system and environmental studies, design, specification writing, procurement, construction and commis- sioning. Owner's administration covers the costs which would be incurred by the Owner such as general administration, insurance, finan- cial management, commissioning staff and staff training. A contingency has been applied to both capital and indirect costs to allow for uncertainties in the costing of the HVDC equipment and the submarine cable, unanticipated construction problems and other similar unforeseen factors. The cost estimates are based on evaluation of cost information obtained from equipment suppliers, actual cost of transmission lines in Southeast Alaska and other sources. These cost esti- mates are considered conservative and suitable for budgetary purposes, However, it should be noted that cost estimates obtained from suppliers, in particular for small sizes of con- verter equipment, displayed significant differences. Hence, "high" and “low" estimated project costs have also been pre- pared based on the range of costs provided by suppliers for 6-1 major cost items, namely dc converter stations and dc submarine cables. These “high" and “low" estimates, which are shown in Table 6-1 may be used for sensitivity analysis by APA. The estimating prices are given on the same basis as the previ- ous study described in Reference 1 which also gives more detailed background to the costs. The variation of total capital cost of the Snettisham-Juneau dc system with dc system rating is shown in Figure 6-l. 6.1.1 Stations Current prices for the supply and installation of converter stations including the dc equipment, converter buildings, structures and foundations were obtained from the principal suppliers of HVDC equipment on the basis of a short form inquiry specification. The cost estimates of the HVDC package used in this report are based on the suppliers' estimated budget prices and are shown in Figure 6-2. Estimated costs of the remaining equipment in the stations were based on actual costs incurred on other projects. The converter station cost estimates are itemized as follows: - Land - a cost of $30,000 was allowed for each site - Site Improvements - The estimates are based on a limited knowledge of each site and include the cost of clearing and grading the site and of installation of site roads. = AC Switchyard Connections - The estimate includes the cost of a circuit breaker and disconnect switch for connecting the converter transformer to the ac switchyard bus. For each ac filter and capacitor bank a load break switch, ground switch and_ potential transformer have been included. Also included are the costs of installation, bus connections, foundations, structures, protection and grounding where the items are not included with the HVDC equipment or synchronous condensers. - Synchronous Condensers - The estimate includes the cost of the machine, exciter, starting motor, circuit breaker, transformer, controls, protection, cooling, building, foundations and installation. = Estimates were made during the study described in Reference 1 of the cost of the HVDC contract package based on information received from HVDC equipment suppliers. This information has been combined with cost information Obtained on other projects to extend the cost curve in Figure 6-2 to 110 MW. An allowance has been made for the higher cost of labor in Alaska. - No major spares are included. 6.1.2 Electrode Sites The cost estimates were based on the conceptual designs that were prepared for each sea electrode. The costs of the elec- trodes are included with the associated converter stations in the summary costs in Table 6-l. The price Durichlor anodes was obtained from suppliers. The costs of other materials and the installation costs are based on costs projected for other projects for work of a similar nature. The submarine cables associated with the electrodes are based on the estimated cost of the cable and an installation cost of 10 dollars per foot. These costs are included in the summary costs with the dc submarine cable costs. The costs of the associated overhead electrode lines are included with the converter stations in the summary costs in Table 6-1. 6.1.3 DC Transmission Lines The cost estimates for the dc lines were estimated by reviewing the cost data in the study described in Reference 1 and taking into account that there is only one mile of dc transmission line required at each terminal so the unit cost per mile will be higher. The costs of the dc transmission lines are included with the associated converter stations in the summary costs in Table 6-1. 6.1.4 Submarine Cables DC submarine cable costs for cables for the study described in Reference 1 were obtained from cable manufacturers using a short form inquiry specification. The estimating prices of 100 kV cables, including delivery and installation costs are shown in Figure 6-3 for various cable sizes. The submarine cable lengths used for costing have _ been increased by 5 percent from the measured length to allow for small variations in routing. 6.1.5 Communications Estimated costs of equipment required for the APA-owned micro- wave system terminals and repeaters are based on information given in Reference l. 6.2 Operation and Maintenance An estimate of the annual cost of operation and maintenance has been made for each case and these costs are presented in Table 6-3. The estimate includes the cost of labour and the purchase of consumable spares not covered by the capital estimates. The operation and maintenance requirements for converter stations and dc submarine cables and the basis for determining these costs are described in detail in References 1 and 2. The annual cost of leasing back-up microwave communication channels has been estimated as follows based on cost informa- tion provided by Alscom: dollars per year Case 7A 20,000 Case 7B 20,000 Case 7C 140,000 Case 7D 140,000 For Cases 7A and 7B, the leased circuit is between Snettisham and Juneau and for Cases 7C and 7D additional circuits are required between Juneau and Ketchikan for communication with the master controller, as described in Section 5.6. 6.3 Transmission Losses Converter station losses at full load, excluding synchronous condensers, can be taken to be about one percent of the station rating. These losses can be assumed to vary approximately with the power loading down to about 50 percent of rating. Synchronous condenser losses are typically about 1.0 to 1.5 percent at rated output. However, synchronous condensers would normally operate at part load. The losses on the de portion of system will depend on the load- ing of that system and would normally be operating at part load, possibly to minimize total ac and de transmission losses as discussed in Section 3.6. The de system is only likely to Operate at its rating when the 138 kV ac system is out of service. A comparison of estimated transmission losses between the Snettisham 138 kV bus and the Thane substation based on peak generation for the systems shown in Figure 3-2 is given in Table 6-4. TABLE 6-1 ESTIMATED CAPITAL COSTS OF DC TRANSMISSION FACILITIES (in millions of dollars) Case 7A 7B 7G 7D) DC System Rating (MW) 35) 1X0 35 EO Converter Stations Snettisham S53 L455 eae ioe Juneau a7 19.8 9.7 19.8 Submarine Cables Snettisham-Juneau 10.6 1239 10.0 12.2 Communications 2.0 2.0 eaO™ 2,.0* TOTAL PROJECT ESTIMATE 30.6 49.2 22 ok 40.6 LOW ESTIMATE 26.8 45.8 19.9 38.8 HIGH ESTIMATE Soe 5265 24,1 an. 2) * Incremental costs over the costs associated with the 25 MI Snettisham terminal of Case 4 Note: Costs in 1982 dollars Project Manage- ment Engineering Environmental Studies Owner's Admini- istration Contingency NOTES: 1) 2) TABLE 6-2 INDIRECT COSTS AND CONTINGENCIES Trans- Converter mission Submarine Stations Lines cables 2% 3% 13% 5% 3% 4% 13 (Note 1) 23% 1% 2% 103% 5% 10/20% (Note 2) Communi- cations 3% 4% 4% 103% Cost of environmental studies included with engineering. 10% allowed on the capital cost of the HVDC cable, and 20% on all other cable work. Case No. 7A 7B 7 7D) Note: Note: TABLE 6-3 ESTIMATED ANNUAL OPERATION AND MAINTENANCE COSTS (in thousands of dollars) Station Lines Cables Communications Total 210 5 90 50 359 400 5 90 50 545 120 3 70 30 223 310 3 70 30 413 The annual operation and maintenance costs for Cases 7C and 7D are incremental costs over the costs associated with the 25 MW Snettisham terminal of Case 4. Costs in 1982 dollars. TABLE 6-4 ESTIMATED TRANSMISSION BETWEEN SNETTISHAM AND 138 kV ac system (dc not in service) Loading Losses DC system operating at rating Loading Losses AC/DC system operating at minimum loss ac system loading dc system loading ac dc Notes: system losses system losses total losses LOSSES JUNEAU Case 7A (MW) 124 2.4 35 1.4 107 or .. un nN . nN ey AC system data as given by APA 2) DC system losses include converter station, dc transmission and electrode lines and de submarine cable losses but not synchronous condenser losses. 3) Transmission system and peak generation as given in Figure 3-2. Case 7B (MW) 158 4.3 110 5.0 rT2 he o. oD ww . NI 1000 800 600 CAPITAL COST OF DC SCHEME (DOLLARS / kW) | 10 | | 200 | CAPITAL COST OF DC SCHEME (MILLIONS OF DOLLARS) 04 —— ! Lo 30 50 70 90 110 (HW) RATING OF OC SCHEME SNETTISHAM ~ JUNEAU TOTAL PROJECT ESTIMATES FOR SCOPE OF DC SCHEMES AND COSTS ARE ON SAME BASIS AS CASES 7A AND 78. COSTS IN 1982 DOLLARS LEGEND: —————— CAPITAL COST - MILLIONS OF DOLLARS ------ CAPITAL COST - DOLLARS PER kW COST OF DC SCHEMES BETWEEN SNETTISHAM AND JUNEAU FIGURE 6-1 eee SHWONT CONSULTANTS INC. od 83/03/03 6-9 300 -— = = 2004 s 3s = — nn oOo oO — = = 100 4 lu — | | aa la 7 Set ee —j 10 30 50 70 90 110 TERMINAL RATING (MW) LEGEND HIGH ESTIMATE (2) PROJECT ESTIMATE () LOW ESTIMATE DC VOLTAGE 100 kV COSTS IN 1982 DOLLARS DC CONTRACT PACKAGE COST ESTIMATES FIGURE 6-2 Renap-eepeiiermanntn tactic tsp TESHMONT CONSULTANTS INC. tl 83/03/03 6-10 COST INCLUDING INSTALLATION ( THOUSANDS OF DOLLARS PER MILE) 260: ¢——- 240 | --- - 220 200 conan 160 160 490 120 1 aa _ - aT 100 a 200 : 300 400 500 600 700 800 900 CONDUCTOR SIZE (MCM) CABLE VOLTAGE 100 kV COSTS IN 1982 DOLLARS DC SUBMARINE CABLE COST ESTIMATES FIGURE 6-3 a ESTIMATE fof oe | ee Low] ESTIMATE 1000 100 O4ECT ESTIMATE th 1200 83/03/03 TESHMONT CONSULTANTS INC. Tx General Comments on System Design 7.1 Benefits of Interconnection The de systems described in this report are intended primarily to provide additional transmission capacity between hydroelec- tric plants at Snettisham and the load at Juneau. In Cases 7C and ~7D, the Snettisham-Juneau system is interconnected with another proposed dc transmission system which would link other major communities in Southeast Alaska. In these cases, the Snettisham-Juneau link would become an integral part of the entire interconnection in Southeast Alaska and would enhance the interconnection as well as share in its benefits. The main benefits of interconnected operation are discussed briefly below. = Construction of large hydroelectric plants. Large-capacity hydroelectric plants are usually more economical per unit of output than small plants due to economy of scale. With an interconnected system, a few large plants can be constructed and loaded relatively promptly by supplying the needs of several communities over the dc system rather than building smaller plants in each of the communities independently. This will provide all communities with an access to a lower cost power source. Similarly, if economical power should become available from external sources due to large power developments in neighboring areas, an interconnection would enable utilization of this power. = Water management. A water management program could be implemented to make maximum and efficient use of available water for energy production by moving energy from one area to another over the dc system. Energy available in an area due to diver- sity of water flows and diversity of loads would be made available to other areas. Similarly, surplus energy available in an area due to high water flows or other reasons could readily be transmitted to areas where it can be utilized. - Installed generation reserve The amount of reserve generating capacity in each of the communities in Southeast Alaska that are interconnected by the de system can be reduced somewhat due to the support that can be obtained over the dc system from other communities. Reliability Support would be provided to communities over the dc system during emergencies such a loss of generation, loss of transmission, etc. This would improve the reliability of power supply by providing each community with an alter- native source of supply. Renewable and non-renewable resources The use of renewable resources, that is hydroelectric power, would be increased thus conserving non-renewable resources. Environmental impact There are often major environmental concerns associated with development of hydroelectric plants and_ their associated ac transmission systems. Interconnection may reduce the the number of hydroelectric plants and ac transmission schemes and so reduce the environmental impact on Southeast Alaska. As described in Reference l, there are minimal environmental problems with dc submarine cable systems. The environmental impact of hydroelectric developments is generally more acceptable than that of fossil-fueled generation plants. The development of remote hydroelec- tric plants would reduce the number of fossil-fueled generation plants required in the major communities such as Juneau. Stable power costs A greater reliance on hydroelectric power, with its rela- tively fixed cost of energy, should provide a more stable cost of power. Flexibility An interconnection would provide the community power sys- tems with greater flexibility in meeting a rapid increase in load due to new loads, industrial development or other factors. Infrastructure Installation of a dc interconnection would involve devel- opment of an infrastructure such as, for example, a com- munication network that is required for the de system but which would also serve other uses. 7.2 Snettisham-Juneau-Skagway DC Scheme Cases 6B and 6C of the previous study described in Reference 1 have a 20 MW dc connection between Juneau and Skagway. At the southern end, the dc submarine cable was assumed to terminate at a point just south of Yankee Cove and from there a dc transmission line would run along the coast to the converter station at Auke Bay north of Juneau. If this de system was to be built along with the Snettisham- Juneau dc system, it would be desirable to operate the Juneau converter station as a tap, thus reducing the number of conver- ter stations in Juneau from two to one. For such an arrangement, the two dc lines must be connected. It may be difficult to build a de transmission line through Juneau from Auke Bay to Thane. However, other routes are possible. The dc submarine cable from Skagway could terminate on Douglas Island and the connection made to Thane by a dc transmission line across Douglas Island and a short dc sub- Marine cable across the Gastineau Channel. Alternatively, the dc submarine cable from Skagway could pass around Douglas Island, through Stephens Passage and up the Gastineau Channel to Thane. A further consideration for the Snettisham-Juneau-Skagway scheme is the possible connection to a de system to Petersburg and other locations further south. In the previous study described in Reference 1, dc systems with five terminals were considered acceptable based on the anticipated development of dc controls by dc equipment manufacturers, the experience that will be obtained in the next few years on multiterminal schemes, and the staged build-up from three terminals initially, increasing to five terminals over a five year period. Careful consideration of the dc system would be required if more than five terminals were contemplated. 7.3 Ratings of Snettisham and Juneau Converter Terminals The ratings of the converter terminals at Snettisham and Juneau that are given in this report are about the minimum and maximum ratings that can reasonably be utilized. The minimum rating, 35 MW, is based on the revised load growth projection for Juneau and the maximum rating, 110 MW, is based on an earlier more rapid rate of load growth. Of course, intermediate ratings could also be selected. One possibility would be to select a rating such that, after the Sweetheart Lake plant is installed, the total peak capacity from the Snettisham area (not including the Lake Dorothy plant) can be transmitted with one line between Snettisham and Juneau out of service. The rating of each line would then be 119/2 or 60 MW. This matches the rating of the 138 kV ac line as a 60 MW loading at Snettisham corresponds to about 100 MW between Lake Dorothy and Juneau, and the ac cable is rated 124 MVA. Hence the dc system would consist of two 60 MW poles connected to form a bipole. The first pole would be installed in 1990 and the second pole installed to coincide with the construction of Sweetheart Lake. Other ratings are of course also possible. The 60 MW rating appears to be a reasonable compromise between the low rating of 35 MW, which is not as economical as the larger ratings on a per kW basis, and the large rating of 110 MW which would not be required for many years based on the revised load growth projection for Juneau. ze the dc transmission interconnection between other communities in Southeast Alaska were constructed, one pole of the Snettisham-Juneau de system could be interconnected with that system as in Case 7C and 7D, and the other pole of the Snettisham-Juneau system would remain independent. 8. References Reference 1 Reconnaissance Design and Cost Estimate, South- east Alaska Intertie, DC Transmission System, dated November 1982 prepared for the Alaska Power Administration by Teshmont Consultants Inc. to Reference Reconnaissance Design and Cost Estimate, South- east Alaska Intertie, DC Transmission System Task A Report, dated September 10, 1982, pre- pared for the Alaska Power Administration by Teshmont Consultants Inc. Reference 3 Southeast Alaska Intertie Load/Resource Analysis, dated May 1982, prepared by the Alaska Power Administration. Reference 4 Alaska Power Administration Notes on Juneau Area Power Supply, dated November 19, 1982, and associated miscellaneous data sheets. sai APPENDIX 1 DETAILED COST ESTIMATES APPENDIX 1 Detailed Cost Estimates Index Page INTRODUCTION I-l COSTS IN ACCORDANCE WITH THE FERC UNIFORM I-2 SYSTEM OF ACCOUNTS eek Summary Costs by FERC Account Code 242 Detailed Cost Case 7A Case 7B Case 7C Case 7D ks Introduction The project cost estimates for Cases 7A to 7D are given in this Appendix. The cost estimates are given in accordance with the Federal Energy Regulatory Commission (FERC) Uniform System of Accounts. The costs are given in detail for the following major items:- - converter stations - dc transmission lines - dc submarine cables - electrode cables - communications Details are given of the costs for Cases 7C and 7D which correspond to the increase in costs required for Cases 7A and 7B, respectively, above the cost of the dc system in Case 4. Case 4 has a 25 MW terminal at Snettisham. As noted in Reference 1, there were significant differences in some of the cost data supplied by manufacturers, particularly for small sizes of converter equipment. Thus, the detailed costs also include costs based on "high" and "low" estimates for the major cost items, namely converter stations and dc sub- marine cables. These costs are given under the headings "highest" and "lowest". The total costs are summarized by the FERC Account Code for each case. The costs given in this Appendix are summarized in a different format in Table 6-1 of the main report. Tad 2. Costs in Accordance with FERC Uniform System of Accounts apod qunososy oygda Aq s3sop Azqewuwns TZ ATEN 350 352 353 354 355 356 358 397 DESCRIPTION LAND AND LAND RIGHTS STKUCTURES AND IMPROVEMENTS STATION EQULPMENT TOWERS AND FIXTURES POLES AND FIXTUKES OVERHEAD CONDUCTOKS AND DEVICES UNDERGROUND CONDUCTORS AND DEVICES COMMUN LCAT LON EQULPMENT SUB-TOTAL PROJECT MANAGEMENT AND ENGINEERING OWNEK'S ADMINISTRAT LON SUB-TOTAL, CONT LNGENCY TOTAL PROJECT ESTIMATE TESUMONT CONSULTANTS (SMILL 27.6 3.0 30.0 COST ESTIMATE DC ‘TRANSMISSION SYSTEM IN SOUTHEAST ALASKA ION) SUMMARY BY FERC ACCOUNT CODE CASE 7A PAGE INC 1 or 4 ITEM 350 352 353 354 355 356 358 397 DESCRIPTION LAND AND LAND KIGHTS STRUCTURES AND L1PROVEMENTS STATION EQUIPHENT TOWERS AND FIXTURES POLES AND FIXTURES OVERHEAD CONDUCTOKS AND DEVICES UNDERGROUND CONDUCTORS AND DEVICES COMMUNICATION EQUIPMENT SUB-TOTAL PROJECT MANAGEMENT AND ENGINEERING OWNER'S ADMINISTRAT LON SUB-TOTAL CONTINGENCY TOTAL PROJECT ESTIMATE (SMILL COST ESTIMATE DC TRANSMISSION SYSTEM IN SOUTHEAST SUMMARY BY FERC ACCOUNT COD! CASE 7B 10N) TESHUMONT CONSULTANTS INC. ALASKA E PAGE 2 OF 4 ITEM DESCRIPTION 350 352, 353 354 355 356 358 397 LAND AND LAND RIGHTS STRUCTUKES AND IMPROVEMENTS STATION EQUIPMENT TOWERS AND FIXTURES POLES AND FIXTURES OVERHEAD CONDUCTORS AND DEVICES UNDERGROUND CONDUCTORS AND DEVICES COMMUN [CATION EQUIPMENT SUB-TOTAL PROJECT MANAGEMENT AND ENGINEERING OWNEK'S ADMINISTRAT LON SUB-TOTAL CONTINGENCY TOTAL PROJECT ESTIMATE (SMILL U 8.3 on 8.2 re) Licel 4 19.8 Zeek TON) 3] TUEUS I HIMIOUNETINCIOUNISIUIDLTUAUNCENS TUNIC: DC COST ESTIMATE TRANSMISSION SYSTEM IN SOUTHEAST ALASKA SUMMARY BY FERC ACCOUNT CODE CASE 7C PAGE 3 OF 4 ITEM 350 352 353 354 355 350 358 397 DESCRIPTION LAND AND LAND RIGHTS STRUCTURES AND IMPROVEMENTS STATLON EQUIPMENT TOWERS AND FIXTURES POLES AND FIXTURES OVERHEAD CONDUCTOKS AND DEVICES UNDERGROUND CONDUCTORS AND DEVICES COMMUN LCATION EQUIPMENT SUB-TOTAL PROJECT MANAGEMENT AND ENGINEERING OWNEK'S ADMINISTRATION SUB-TOTAL CON'T INGENCY TOTAL PROJECT ESTIMATE (SMILLION) 203 -8 21.8 ol 204 10.1 +8 33.7 2,2 7 36.6 4.0 40.6 TESHMONT CONSULTANTS INC. COST ESTIMATE DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA SUMMARY BY FERC ACCOUNT CODE CASE 7D PAGE 4 OF 4 2.2 Detailed Costs ITEN DESCRIPTION 7 QUANTITY TOTAL COST ($x10U0) LOWEST PROJECT HIGHEST ESTIMATE 350 LAND AND LAND RIGHTS x 30 * 352 SLTE IMPROVEMENTS * 730 * 353 STATION EQUIPMENT DC PACKAGE 4010 5270 6880 DC FILTERS AND MAJOR SPARES = = = ELECTRODE x 93 x SYNCHRONOUS CONDENSER(S) - - - AC CONNECTIONS x 650 x SUB-TOTAL 5513 6773 8383 PKUJECT MANAGENEN'T 2%, ENGINEERING 5% 386 474 587 OWNER'S ADMINISTRATION 2% 110 136 168 SUB-TOTAL 6009 7383 9138 CONTINGENCY 10% 601 738 914 TOTAL 6610 8121 10052 - 7 TESHMONT CONSULTANTS INC. STATLON RATING 35 MW . COST ESTIMATE DC VOLTAGE 100. KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 138 KV SYNCHRONOUS CONDENSER RATT LNG - MVAK CONVERTER STATION CASE 7A SNETTISHAM PAGE | OF 8 ITEM : DESCRIPTION QUANTITY : TOTAL Cost a ($x1000) LOWEST PROJECT HIGHEST ESTIMATE 35uU LAND AND LAND RIGHTS * 30 * 352. SITE IMPROVEMENTS * 710 * 353 STATION EQUIPMENT DC PACKAGE 4010 5270 6880 DC FILTERS AND MAJOR SPARES ~ - - ELECTRODE * 44 * SYNCHRONOUS CONDENSER(S) x 1545 * AC CONNECTIONS * 400 * SUB-TOTAL 6739 7999 9609 PROJECT MANAGEMENT 2%, ENGINEERING 5% 472 560 673 OWNEK'S ADMINISTRATION 2% 135 160 192 SUB-TOTAL 7346 8719 10474 CONTINGENCY 10% 735 872 1047 TOTAL 8081 9591 11521 if TESHMONT CONSULTANTS INC, STATION RATING 35 MW COST ESTIMATE DC VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 69 KV SYNCHRONOUS CONDENSER RATING 15 MVAR CONVERTER STATION CASE 7A JUNEAU (THANE) PAGE 2 OF 8 ITEM DESCRIPTION QUANTITY UNIT COST ($x1000) TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND KIGHTS TRANSMISSION LINE R.O.W. 1 mi 1 I 352 LAND CLEARING 1 mi 20 20 395 POLES AND FIXTURES 1 mi 108 108 356 OVERHEAD CONDUCTORS 1 mi 36 36 SUB-TOTAL 165 PROJECT MANAGEMENT 3%, ENGINEERING 4% 12 OWNER'S ADMINISTRATION 1% 2 SUB-TOTAL 179 CONTINGENCY 5% 9 TOTAL 188 TESHMONT CONSULTANTS INC, TRANSMISSION LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 100 KV CONDUCTOR SIZE "BITTERN' 1.345 INCH DIA ACSRK DC TRANSMISSLON SYSTEM IN SOUTHEAST ALASKA DC TRANSMISSION LINE SECTION CASE 7A SNETTISHAM PAGE 3 OF 8 ATEM DESCRIPTION QUANTITY UNIT COST ($x1000) TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS TRANSMISSION LINE R.O.W. 1 mi 1 1 352 LAND CLEARING 1 mi 20 20 355 POLES AND FIXTURES 1 mi 83 63 356 OVERHEAD CONDUCTORS 1 mi 28 28 SUB-TOTAL 132 PROJECT MANAGEMENT 3%, ENGINEERING 4% 9 OWNER'S ADMINISTRATION 1% 1 SUB-TOTAL 142 CONTINGENCY 5% 7 TOTAL 149 TESHMONT CONSULTANTS ING TRANSMISSION LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE "BITTERN' 1.345 INCH DIA ACSK DC TRANSMISSION LINE SECTION CASE 7A JUNEAU (THANE) PAGE 4 OF 8B ITEM . DESCRIPTION QUANT LTY UNIT COST ($x1000) TOTAL COST ($x1l000) __ PROJECT PROJECT LOWEST ESTIMATE HIGHEST LOWEST ESTIMATE HLGHEST 350 LAND AND LAND KIGHT'S 2 SITES * 1 x * 2 x 352 SITE IMPROVEMENTS 2 SITES * 2 x * 4 x 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE - MATERIAL 42 mi 106.4 116.2 120.0 4469 4880 5292 - DELIVERY AND INSTALLATION (1) 42 mi 61.1 66.8 72.5 2566 2806 3045, SHORE PROTECT LUN - SNETTISHAM 1 x 210 x x 210 * - THANE . * 2lu x * 210 x SUB-TOTAL 7461 8112 8763 PROJECT MANAGEMENT 1%, ENGINEERING 4% 373 406 438 OWNER'S ADMINISTRATION 2% 149 162 175 SUB-TOTAL 7983 8680 9376 CONT LNGENCY (SUBMARINE CABLE 1087 1180 1272 MATERIAL 10%, OTHER 20%) ‘TOTAL 9u70 9860 10048 an roi 7 TESUMONT CONSULTANTS INC. CABLE LENGTH 42 MILES COST ESTIMATE VOLTAGE 1UU_ KV DC TRANSMISSION SYSTEM IN SOUTHEAS'T ALASKA CONDUCTOR ‘SLZE 450 MCM DC SUBMARINE CABLE CASE 7A SNETTLSHAM-JUNEAU (1) ENCLUDES MOBILIZATLON AND DEMOBLLIZAT LON PAGE 5 OF 8 ITEM oe DESCRIPTION QUANTITY UNIT COST ($x1000) _ TOTAL COST —(§x1l000) _ PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 1 Site 1 1 3532. SITE IMPROVEMENTS - 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE. CABLE — MATERIAL 13200 ft. 2025 330 - INSTALLATION 13200 ft. 2010 132 POTHEADS, SURGE ARKESTERS AND TEKMI- 1 Site 2 2 NATION STRUCTURE SUB-TOTAL 465 PROJECT MANAGEMENT 1%, ENGINEERING 4% 23 OWNEK'S ADMINISTRATION 2% 9 SUB-TOTAL 497 CONTINGENCY 20% 99 TOTAL 596 ~ TESHMONT CONSULTANTS INC. CABLE LENGTH 13200 FEET VOLTAGE 15 KV COST ESTIMATE CONDUCTOR SIZE 450 MCM DC TRANSMISSLUN SYSTEM IN SOUTHEAST ALASKA bC ELECTRODE CABLE CASK 7A SNETTISHAM PAGE 6 OF 8 ITEM DESCRIPTION Me QUANTITY —__ UNIT COST ($x10U0)___ TOTAL COST _($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 1 Site 1 352 SITE IMPROVEMENTS 1 Site 1 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE - MATERIAL 2640 ft. +025 66 - INSTALLATION 2640 ft. -OL0 26 POTHEADS, SURGE ARKESTEKS AND TERMI- 1 Site 2 2 NATLON STRUCTURE SUB-TOTAL 96 PROJECT MANAGEMENT 1%, ENGINEERING 4% 5 OWNER'S ADMINISTRATION 2% 2 SUB-TOTAL 103 CONTINGENCY 20% 21 TOTAL 124 LS ie “Tf: | TESHMONT CONSULTANTS: INC) [/7) CABLE LENGTH 2040 FELT VOLTAGE 15 KV COST ESTIMATE DC TRANSMISSLON SYS'TEM IN SOUTHEAST ALASKA CONDUCTOR SIZE 450 MCM DC ELECTRODE CABLE CASE 7A JUNEAU (THANE) PAGE ? OF 8 ITEM DESCKLIPTION QUANT LTY UNIT COST ($x1000) TOTAL COST ($x}000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 397 COMMUNT CATIONS EQULPMENT STATLON EQUIPMENT 2 Terminals 210 420 REPEATER STATLONS 2 Repeaters 600 £200, SUB-TOTAL 1620 PROJECT MANAGEMENT 3%, ENGINEERING 4% 1k3 OWNERK'S ADMINISTRATLON 4% 65 SUB-TOTAL 1798 CONTINGENCY 10% 180 TOTAL 1978 TESHMONT CONSULTANTS INC, COST ESTIMATE DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA COMMUN ICAT TONS CASE 7A SNE'TTISHAM~JUNEAU PAGE 8 OF 8 [TEM DESCRLPTLON © QUANTITY TOTAL COST (§$x1000) LOWEST PROJECT HIGHEST ESTIMATE 350 LAND AND LAND RIGHTS * 30 * 352 SITE IMPROVEMENTS x 730 x 353 STATION EQUIPMENT DC PACKAGE 9320. LUU9U 10860 DC FILTERS AND MAJOR SPARES - ELECTRODE x 404 x SYNCHRONOUS CONDENSER(S) - AC CONNECT LONS x 650 x SUB-TOTAL 11134 11904 12074 PROJECT MANAGEMENT 2%, ENGINEERING 5% 779 833 887 OWNER'S ADMINIS'TRATION 2% 223 238 253 SUB-TOTAL 12136 12975 13814 CONTINGENCY 10% 1214 1298 1381 TOTAL 13350 = 14273 15195 —= SS — _ — TESHUMONT CONSULTANTS INC. - STATLON RATING Llu MW COST ESTIMATE DC VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 138 KV SYNCHRONOUS CONDENSER KAT LNG - MVAR CONVERTER STATLON CASE 7B SNETTISHAM PAGE 1 OF & 1TEM DESCKIPTION QUANTITY TOTAL COST ($x1000) LOWEST PROJECT HIGHEST ESTIMATE 350 LAND AND LAND. RIGHTS * 30 x 352 SITE IMPROVEMENTS * 780 * 353 STATLON EQUIPMENT DC PACKAGE 9320. 10090 10860 DC FLLTERS AND MAJOR SPARES - - = ELECTRODE x 132 x SYNCHRONOUS CONDENSER(S) * 4940 x AC CONNECT LONS * 400 x SUB-TOTAL 15602-16372 17142 PROJECT MANAGEMENT 2%, ENGINEERING 5% 1092 1146 1200 OWNERK'S ADMINISTRATION 2% 312 327 343 SUB-TOTAL 17006-17845 18685 CONTINGENCY 10% 1700 1785 1869 TOTAL 18707 19630 20554 ~ - TESHMONT CONSULTANTS INC STATION RATING 110 MW COST ESTIMATE DC VOLTAGE 100 kV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 69 KV SYNCHRONOUS CONDENSER RATING 2x30 MVAR CONVERTER STATION CASE 7B JUNEAU (THANE) PAGE 2 OF 8 CTEM DESCKIPTION QUANTITY UNIT COST ($x1000) TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND KIGHTS TRANSMISSION LINE K.O.W. L mi 7 1 352 LAND CLEARING L mi 20 20 355 POLES AND FIXTURES L mi 108 108 356 OVERHEAD CONDUCTORS 1 mi 36 36 SUB-TOTAL 165 PROJECT MANAGEMENT 3%, ENGINEERING 4% 12 OWNER'S ADMINISTRATLON 1% 2 SUB-TOTAL 179 CONTINGENCY 5% 9 ‘TOTAL 188 -_ i iy TESHMONT CONSULTANTS INC, TRANSMISSION LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 100. KV DC TRANSMISSLON SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE "SLTTERN' 1.345 INCH DIA ACSR DC TRANSMISSION LINE SECTLON CASE 7B SNETTLISHAM PAGE 3 OF 8 ITEM | DESCRIPTION QUANTITY UNIT COST ($x1000) __ TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND KIGHTS TKANSMISSION LINE R.O.W. 1 mi 7 1 352 LAND CLEARING 1 mi 20 20 355 POLES AND FIXTURES 1 mi 83 83 $56 OVERHEAD CONDUCTORS 1 mi 28 28 SUB-TOTAL 132 PROJECT MANAGEMENT 3%, ENGINEERING 4% 9 OWNEK'S ADMINISTRATION 1% i SUB-TOTAL 142 CONTINGENCY 5% 7 ‘TUTAL 149 TESHUMNOKRT CONSULTANTS it. TRANSMISSION LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTUR SIZE "BITTERN' 1.345 INCH DIA ACSR DC TRANSMISSION LINE SECTION CASE 7B JUNEAU (THANE) PAGE 4 OF 8 ITEM DESCRIPTION —__ QUANT LTY UNIT COST ($x1000)___ TOTAL COST _($x1000) LOWEST PROJECT HIGHEST LOWEST PROJECT HIGHEST ESTIMATE ESTINATE 350 LAND AND LAND RIGHTS 2 sites * 1 * * 2 * 352 SLTE IMPROVEMENTS 2 sites * 1 * * 4 * 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE - MATERIAL 42 mi 134 154 174 5628 0468 7308 - DELIVERY AND INSTALLATION (1) 42 mi 65 74 84 2730-3108 3528 SHOKE PROTECT LON 1 * 210 * * 210 * - SNETTISHAM 1 * 210 * * 210 * - THANE SUB-TOTAL 8784 — 10002 11262 PROJECT MANAGEMENT 1%, ENGINEERING 4% 439 500 563 OWNEK'S ADMINISTRATION 2% 170 200 225 SUB-TOTAL 9399 10702 12U5U CONTINGENCY (SUBMARINE CABLE 1238 1403 1977 MATERIAL 10%, OTHER 20%) TOTAL 10637-12105 13627 rae ae == TESUMONT CONSULTANTS INC. CABLE LENGTH 42 MILES COST ESTIMATE VOLTAGE 100. KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE 1100 MCM (1) INCLUDES MOBILIZATLON AND DEMOBLLIZATION DC SUBMARINE CABLE CASE 7B SNETTISHAM-JUNEAU PAGE 5 OF 8 ITEM a DESCRLPT LON QUANTITY UNIT COST ($x1000) TOTAL COST (§x1000) PROJECT PROJECT ESTIMATE EST IMATE 350 LAND AND LAND RIGHTS 1 site 1 1 352 SITE IMPROVEMENTS - 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE - MATERLAL 13200 ft 03 396 — INSTALLATION 13200 ft OL 132 POTHEADS, SURGE ARKESTEKS AND TERMI- NATION STRUCTURE 1 site 2 2 SUB-TOTAL 531 PROJECT MANAGEMENT 1%, ENGINEERING 4% 27 OWNEK'S ADMINISTRATION 2% ll SUB-TOTAL 569 CONTINGENCY 20% 114 TOTAL 683 i TESHMONT CONSULTANTS ING CABLE LENGTH 13,200 FEET COST ESTIMATE VOLTAGE 15 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE 1100 NCM DC ELECTRODE CABLE CASE 7B SNETTISHAM PAGE 6 OF 8 ITEM DESCRIPTION QUANTITY UNIT COST _($x1000) TOTAL COST ($x100U) PROJECT PROJECT EST LMATE EST IMATE 350 LAND AND LAND RIGHTS l site 1 i 352 SITE IMPROVEMENTS 1 site l 1 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE — MATERIAL 2640 ft 03 79 - INSTALLATION 2640 Et 01 26 POTHEADS, SURGE ARRESTERS AND TERMI- NATION STRUCTURE 1 site 2 2 SUB-TOTAL 109 PROJECT MANAGEMENT 1%, ENGINEERING 4% 5 OWNEK'S ADMINISTRATION 2% 2 SUB-TOTAL Ll6o CONTINGENCY 20% 23 ‘TOTAL 139 TP NTN NL A nN a) TESHMONT CONSULTANTS ING CABLE LENGTH 2040 FEET COST ESTIMATE VOLTAGE 15 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCLOR SIZE LLOO MCM DC ELECTRODE CABLE CASE 7B JUNEAU (THANE) PAGE 7 OF 8 ITEM _ DESCRIPTION _ _ QUANTITY UNIT COST ($x1000) TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 397 COMMUNICATIONS EQULPMENT STATLON EQUIPMENT 2 Terminals 210 420 REPEATER STATIONS 2 Repeaters 600 1200 SUB-TOTAL 1620 PROJECT MANAGEMENT 3%, ENGINEERING 4% 113 OWNER'S ADMINISTRATLON 4% 65 SUB-TOTAL 1798 CONTINGENCY 10% 180 TOTAL 1978 TESHMONT CONSULTANTS INC COST ESTIMATE DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA COMMUN ICAT LONS CASE 7B SNETTISHAM-JUNEAU PAGE 8 OF 8 ITEM DESCRIPTION QUANTITY TOTAL COST ($x1000) TOTAL COST ($x1l000) LOWEST PROJECT HIGHEST LOWEST PROJECT HIGHEST ESTIMATE ESTIMATE CASE 7A CASE 4 350 LAND AND LAND RIGHTS * 30 * * 30 * 352 SLTE LAMPROVEMENTS * 730 * * 730 * 353 STATION EQUIPMENT DC PACKAGE 4010 5270 6880 2850 4170 6400 DC FILTERS AND MAJOR SPARES = a = = ELECTRODE * 33 * * 74 * SYNCHRONOUS CONDENSER(S) = es = = AC CONNECTIONS * 650 * * 650 * SUB-TOTAL 5513 6773 8383 4334 56054 7884 PROJECT MANAGEMENT 2%, ENGINEERING 5% 386 474 587 303 396 552 OWNER'S ADMINISTRATION 2% 110 136 168 87 1S) 158 SUB-TOTAL 6009 7383 9138 4724 6163 8594 CONTINGENCY 10% 601 738 914 472 616 859 TOTAL 6610 8121 10052 5196 6779 9453 COST FOR CASK 7C (AMOUNT OF CASE 7A ABOVE CASE 4) 1414 1342 599 CASE 7C CASE 4 RESP MHON Ti Co ws VE PANT Si Nic. STATLON RATING 35 25 MW COST ESTIMATE DC VOLTAGE 100 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 138 138 KV SYNCHRONOUS CONDENSER KAT LNG a = MVAK CONVERTER STATION CASE 7C SNETT ISHAM PAGE 1 ORT. ITEM DESCRIPTION QUANTITY TOTAL COST ($x1000) LOWEST PROJECT HIGHEST ESTIMATE 350 LAND AND LAND KIGHTS * 30 * 352 SITE IMPROVEMENTS * 710 * 353 STATLON EQULPMENT DC PACKAGE 4010 5270 6880 bC FLLTERS AND MAJOR SPARES = = a ELECTRODE * 44 * SYNCHRONOUS CONDENSER(S) * 1545 * AC CONNECTIONS * 400 * SUB-TOTAL 6739 7999 9609 PROJECT MANAGEMENT 2%, ENGINEERING 5% 472 560 673 OWNEK'S ADMINISTRATION 2% 135 160 192 SUB-TOTAL 7346 ~=—-8719 10474 CONTINGENCY 10% 435 872 1074 TOTAL su81 9591 11521 TESHMONT CONSULTANTS INC, STATION KATING 35 MW COST ESTIMATE bC VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 69 KV SYNCHRONOUS CONDENSER RATING 15 MVAR CONVERTER STATLON CASE 7C JUNEAU (THANE) pAGE 2 OF 7 pats OR 1TEM DESCKIPTION QUANTITY UNIT COST ($x1000) TOTAL COST* ($x1000) PROJECT PROJECT ESTIMATE EST LMATE 350 LAND AND LAND RIGHTS 1 mi TRANSMISSION LINE K,O.W. 352 LAND CLEARING 1 mi 355 POLES AND FIXTURES 1 mi 45 45 356 OVERHEAD CONDUCTORS 1 mi 15 15 SUB-TOTAL 60 PROJECT MANAGEMENT 3%, ENGINEERING 4% 4 OWNEK'S ADMINISTRATION 1% 1 SUB-TOTAL 65 CONTINGENCY 5% 3 TOTAL 68 *&CUST FOR CASE 7C BASED ON AMOUNT OF CASE 7A ABOVE CASE 4 TESHMONT CONSULTANTS TRANSMISSION LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE "BITTERN' 1.345 INCH DIA ACSR TWO POLE CONDUCTORS DC TRANSMISSION LINE SECTION CASE 7C SNETT ISHAM PACE 3) OF INC. 7 LITEM DESCRIPTION QUANTITY UNIT COST ($x1000) TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS TRANSMISSION LINE R.O.W. 1 mi 1 1 352 LAND CLEARING 1 mi 20 20 355 POLES AND FIXTURES l mi 83 83 356 OVERHEAD CONDUCTORS 1 mi 28 28 SUB-TOTAL 132 PROJECT MANAGENENT 3%, ENGINEERING 4% 9 OWNEK'S ADMINISTRATLON 1% i SUB-TOTAL 142 CONTINGENCY 5% 7 TOTAL 149 ~ TESHMONT CONSULTANTS INC. TRANSMISSION LINE LENGTH 1 MILLE | COST ESTIMATE VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE ‘BITTERN’ 1,345 INCH DIA ACSR DC TRANSNMISSLON LINE SECT LON CASE 7C = JUNEAU (THANE) PAGE 4 OF 7 ITEM DESCRIPTION QUANTITY UNIT COST ($x100U) TOTAL COST ($x1000) LOWEST PROJECT HIGHEST LOWEST PROJECT HIGHEST ESTIMATE “, | -RSTIMATE 350 LAND AND LAND RIGHTS 2 sites * 1 x x 2 x 352 SITE IMPROVEMENTS 2 sites * 1 * * 4 * 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMAKINE CABLE : - MATERIAL 42 mi 106.4 116.2 126.0 4469 4880 5292 - DELIVERY AND INSTALLATION (1) 42 mi 61.1 66.8 7265 2566 2806 3045 SHORE PROTECTLON 1 * 210 * * 210 * - SNETTISHAM 1 * 210 * x 210 * - THANE SUB-TOTAL 7461 8112 8763 PROJECT MANAGEMENT 1%, ENGINEERING 4% 373 406 438 OWNER'S ADMINISTRATION 2% 149 162 175 SUB-TOTAL 7983 8680 9376 CONTINGENCY (SUBMARINE CABLE 1087 1180 1272 MATERIAL 10%, OTHER 20%) TOTAL 9070 9860 10648 TESHMONT CONSULTANTS INC. CABLE LENGTH 42 MILES COST ESTIMATE VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE 450 MCM DC SUBMARINE CABLE CASE 7C SNETTISHAM-JUNEAU CL) INCLUDES MOBILIZATLON AND DEMOBILIZAT LON PAGE 5 OF 7 LEM ___DESCRIPTION _ __ QUANTITY UNIT COST ($x1000) __ _ TOTAL COST _($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 1 site 1 352 SITE IMPROVEMENTS 1 site 1 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE — MATERIAL 26040 ft 2025 66 - INSTALLATION 2640 ft 010 26 POTHEADS, SURGE AKRKESTERS AND TERMI=- NATION STRUCTURE 1 site 2 2 SUB-TOTAL 96 PROJECT MANAGEMENT 1%, ENGINEERING 4% 5 OWNER'S ADMINISTRATION 2% 2 SUB-TOTAL 103 CONTINGENCY 20% 21 TUTAL 124 TESHMONT CONSULTANTS ING CABLE LENGTH 2640 FEET COST ESTIMATE VOLTAGE 15 KV DC TRANSMISSLON SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE 450 MCM DC KLECTRODE CABLE CASK 7C JUNEAU (THANE) PAGE 6 OF i ITEM DESCRIPTION . QUANTITY UNIT COST ($x1000) TOTAL COST* ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 397 COMMUNICATIONS EQUIPMENT STATION EQUIPMENT 1 Terminal 210 210 REPEATER STATIONS 1 Repeater 600 600 SUB-TOTAL 810 PROJECT MANAGEMENT 3%, ENGINEERING 4% 57 OWNEK'S ADMINISTRATION 4% 32 SUB-TOTAL 899 CONTINGENCY 10% 90 TOTAL 989 * CUST FOR CASE 7C BASED ON AMOUNT OF CASE 7A ABOVE CASE 4 TESHMONT CONSULTANTS INC, COST ESTIMATE DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA COMMUNICATIONS CASE 7C SNETTLSHAM-JUNEAU PAGE 7 OF 7 ITEM DESCKIPTION QUANTITY TOTAL COST ($x1000) TOTAL COST ($x100U) _ LOWEST PROJECT HIGHEST LOWEST PROJECT HIGHEST ESTIMATE ESTIMATE CASE 7B CASE 4 350 LAND AND LAND RIGHTS x 30 x * 30 x 352 SITE IMPROVEMENTS x 730 x * 730 x 353 STATION EQUIPMENT DU PACKAGE 9320 10090 10860 2850 4170 6400 DC FILTERS AND MAJOR SPARES - - - - - - ELECTRODE * 404 x x 74 ‘ SYNCHRONOUS CONDENSER(S) - - - - - - AC CONNECTIONS x 650 * x 650 * SUB-TOTAL 11134 11904 12674 4334 5654 7884 PROJECT MANAGEMENT 2%, ENGINEERING 5% 779 833 887 303 396 552 OWNER'S ADMINISTRATION 2% 223 238 253 87 113 158 SUB-TOTAL 12136 12975 13814 4724 6163 8594 CUNTINGENCY 10% . 1214 1298 1381 472 616 859 TOTAL 13350 14273 15195 5196 6779 9453 COST OF CASE 7D (AMOUNT OF CASE 7B ABOVE CASE 4) 8154 7494 5742 T TT CASE 7D CASE 4 | TESHMONT CONSULTANTS ING STATION RATLNG 110 25 MW COST ESTIMATE DC VOLTAGE , 1u0 100. KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 138 138 KV SYNCHRONOUS CONDENSER RATING - - MVAR CONVERTER STATION CASE 7D. SNETTISHAM PAGE 1 OF 7 ITEM Te DESCRKIPT LON QUANTITY TOTAL COST ($x1000) LOWEST PROJECT HIGHEST ESTIMATE ” 350 LAND AND LAND RIGHTS * 30 * 352 SITE IMPROVEMENTS * 780 * 353 STATION EQUIPMENT DC PACKAGE 9320 10090 10860 DC FILTERS AND MAJOR SPARES - - - ELECTRODE * 132 * SYNCHRONOUS CONDENSER(S) x 4940 x AC CONNECTIONS * 400 * SUB-TOTAL 156u2 16372 17142 PROJECT MANAGEMENT 2%, ENGINEERING 5% 1092 1146 1200 OWNEK'S ADMINISTRATION 2% 312 327 343 SUB-TOTAL 17006 17845 18685 “CONTINGENCY 10% 1701 1785 1869 TOTAL 18707 19630 20554 TESHMONT CONSULTANTS ING, STATION RATING 110 MW COST ESTIMATE DC VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA AC VOLTAGE 69 KV SYNCHRONOUS CUNDENSEK RATING 2x30 MVAR CONVERTER STATLON CASE 7D JUNEAU (THANE) PAGE 2 OF 7 ITEM DESCKIPTION QUANTITY UNIT COST ($x1000) TOTAL COST *($x10U0) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS TRANSMISSION LINE R.O.W. 1 mi 352 LAND CLEARING 1 mi 855) POLES AND FIXTURES 1 mi 45 45 356 OVERHEAD CONDUCTORS 1 mi tS) 15 SUB-TOTAL 60 PROJECT MANAGEMENT 3%, ENGINEERING 4% 4 OWNERK'S ADMINISTRATION 1% 1 SUB-TOTAL 65 CONTINGENCY 5% 3 TOTAL 68 * COST OF CASE 7D BASED ON AMOUNT OF CASE 7B ABOVE CASE 4 TESHMONT CONSULTANTS INC, TRANSHISSLON LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 100 KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SLZE "BITTERN' 1.345 INCH DIA ACSR TWO POLE CONDUCTORS DC TRANSMISSION LINE SECTLON CASE 7D SNETTISHAM PAGE 3 OF 7 ITEM DESCRIPTION QUANTITY UNIT COST ($x10U0) TOTAL COST ($x1000) PROJECT “PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS TRANSMISSIUN LINE R.O.W. 1 mi 1 1 352 LAND CLEARING 1 mi 20 20 355 POLES AND FIXTURES 1 mi 83 83 356 OVERHEAD CONDUCTORS 1 mi 28 28 SUB-TOTAL 132 PROJECT MANAGEMENT 3%, ENGINEERING 4% 9 OWNER'S ADMINISTRATION 1% 1 SUB-TOTAL 142 CONTINGENCY 5% 7 TOTAL 149 TESHMONT CONSULTANTS ING TRANSMISSION LINE LENGTH 1 MILE COST ESTIMATE VOLTAGE 10U KV DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA CONDUCTOR SIZE "BITTERN' 1,345 INCH DIA ACSR DC TRANSMISSLON LINE SECTION CASE 7D JUNEAU (THANE) PAGE 4 OF ITEM DESCRIPTION QUANTITY UNIT COST ($x1000) TOTAL COST ($x1U00) PROJECT PROJECT LOWEST ESTIMATE HIGHEST LOWEST ESTIMATE HIGHEST 350 LAND AND LAND RIGHTS 2 SITES * 1 * * 2 * 352 SITE IMPROVEMENTS 2 SITES * 2) * * 4 * 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE - MATERIAL 42 mi 134 154 174 5628 6468 7308 - DELIVERY AND INSTALLATION (1) 42 mi 65 74 84 2730 3108 3528 SHORE PROTECTLON - SNETTISHAM 1 * 210 * * 210 * - THANE 1 * 210 * * 210 * SUB-TOTAL 8784 10002 11262 PROJECT MANAGEMENT 1%, ENGINEERING 4% 439 500 563 OWNEK'S ADMINISTRATION 2% 176 200 225 SUB-TOTAL 9399 10702 12050 CONTINGENCY (SUBMARINE CABLE 1238 1403 1577 MATERIAL 10%, OTHER 20%) TOTAL 10637 12105 13627 ii TES) HMO) Wer|)C) 0) NP SUR VAGN Gr) S)/)NIICa CABLE LENGTH 42 MILES COST ESTIMATE VOLTAGE CONDUCTOR SLZE _ LOO KV 1LOO MCM (1) LNCLUDES MOBILIZATLON AND DEMOBILIZAT ION DC TRANSNISSLON SYSTEM IN SOUTHEAST ALASKA DC SUBMARINE CABLE CASE 7D SNETTISHAM-JUNEAU PACE 5 OF 7 ITEM _ __ DESCRIPTION QUANTITY UNIT COST ($x1000) TOTAL COST ($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 1 Site 1 1 352 SLTE IMPROVEMENTS | Site 7 1 358 UNDERGROUND CONDUCTORS AND DEVICES SUBMARINE CABLE — MATERIAL 2640 ft. 03 79 - INSTALLATION 2640 ft. Ol 20 POTHEADS, SUKGE ARRESTERS AND TERMI- 1 Site 2 2 NATION STRUCTURE SUB-TOTAL 109 PROJECT MANAGEMENT 1%, ENGINEERING 4% 5 OWNER'S ADMINISTRATION 2% 2 SUB-TOTAL 116 CONTINGENCY 20% 23 TOTAL 139 - TESHMONT CONSULTANTS ING CABLE LENCTH 2040 FEET VOLTAGE 15 KV COST ESTIMATE CONDUCTOR SIZE 1100 MCM DC TRANSMISSLON SYSTEM IN SOUTHEAST ALASKA DC ELECTRODE CABLE CASE 7D JUNEAU (‘THANE ) PAGE 6 OF 7 ITEM DESCRIPTION QUANTITY UNIT COST ($x1000) TOTAL COST *($x1000) PROJECT PROJECT ESTIMATE ESTIMATE 350 LAND AND LAND RIGHTS 397 COMMUNICATIONS EQUIPMENT STATION EQUIPMENT 1 Terminal 210 210 REPEATER STATIONS 1 Repeater 600 600 SUB-TOTAL 810 PROJECT MANAGEMENT 3%, ENGINEERING 4% 57 OWNER'S ADMLNISTRATLON 4% 32 SUB-TOTAL 899 CONTINGENCY 10% 90 TOTAL 989 * COST OF CASE 7D BASED ON AMOUNT OF CASE 7B ABOVE CASE 4 TESHUMONT CONSULTANTS INC. COST ESTIMATE DC TRANSMISSION SYSTEM IN SOUTHEAST ALASKA COMMUNICATIONS CASE 7D SNETTISHAM-JUNEAU ~ PAGE 7 OF