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Home My WebLink AboutItem 3 Attachment 1 - TDPUD 2019 System Master Plan_Rev4 2019 ELECTRIC SYSTEM MASTER PLAN Prepared For: Truckee Donner Public Utility District 11570 Donner Pass Road Truckee, California 96161 Prepared By: Electrical Consultants, Inc. 3521 Gabel Road Billings, MT 59102 Truckee Donner Public Utility District 2019 Electric System Master Plan Engineer’s Certification ENGINEER'S CERTIFICATION 2019 Electric System Master Plan Truckee Donner Public Utility District 11570 Donner Pass Road Truckee, California 96161 Upon completion of construction of the facilities proposed herein, the system will provide adequate and dependable service to approximately 13,923 customers and 57 MW of non- coincidental load, as projected in the analysis. The recommended system improvements included in this report are in general agreement with the Truckee Donner Public Utility District Planning Criteria. I certify that this report was prepared by me or under my direct supervision and that I am a duly registered Professional Engineer. Name Richard L. McComish, P.E. November 2019 Date Reg. No. Truckee Donner Public Utility District 2019 Electric System Master Plan Index i 1.0 OVERVIEW & PURPOSE ........................................................................................ 1-1 1.1 Overview ............................................................................................. 1-1 1.2 Purpose ................................................................................................ 1-1 2.0 EXECUTIVE SUMMARY ....................................................................................... 2-1 2.1 Existing System Performance ............................................................. 2-1 2.2 Recommended System ........................................................................ 2-4 2.3 Contingency Analysis ......................................................................... 2-5 2.4 Cost Summary ..................................................................................... 2-5 2.5 Project Prioritization ........................................................................... 2-6 3.0 SYSTEM PLANNING CRITERIA ........................................................................... 3-1 3.1 Electrical System Performance Criteria……………………………...3-1 a. Distribution System Voltage Level……………………………….3-1 3.2 Voltage Regulation ............................................................................. 3-2 3.3 Phase Balancing .................................................................................. 3-3 3.4 Capacity and Loading ......................................................................... 3-5 a. Load Periods ................................................................................ ..3-5 b. Equipment Loading ...................................................................... ..3-5 c. Conductor ..................................................................................... ..3-6 3.5 Power Factor & Losses ....................................................................... 3-8 3.6 Contingency System Conditions ......................................................... 3-8 3.7 Mechanical Condition and Reliability Criteria ................................... 3-8 4.0 PROTECTION PHILOSOPHY ................................................................................. 4-1 4.1 Basic Principles of System Coordination ............................................ 4-1 4.2 Sectionalizers ...................................................................................... 4-1 4.3 Fuses ................................................................................................... 4-2 4.4 Electronic Recloser Applications ........................................................ 4-3 4.5 Safety Considerations ......................................................................... 4-3 4.6 Guide to Performed Calculations ........................................................ 4-4 5.0 HISTORICAL DATA & LOAD FORECAST .......................................................... 5-1 5.1 Description of Service Area ................................................................ 5-1 5.2 Power Supply ...................................................................................... 5-1 a. Energy Efficiency and Conservation ........................................... ..5-1 5.3 Transmission ....................................................................................... 5-1 5.4 Connection Statistics & Growth Patterns ............................................ 5-1 a. Residential.................................................................................... ..5-2 b. Commercial (< 50 kW) ................................................................ ..5-2 c. Commercial (> 50 kW and < 200 kW) ........................................ ..5-2 d. Commercial (> 200 kW) .............................................................. ..5-2 e. Public Authority ........................................................................... ..5-3 f. Water Pump ................................................................................. ..5-3 g. The District Use ........................................................................... ..5-3 5.5 Line Statistics .................................................................................... 5-12 5.6 Historical Demand and Growth Patterns .......................................... 5-13 Truckee Donner Public Utility District 2019 Electric System Master Plan Index ii 5.7 System Load Factor .......................................................................... 5-14 5.8 Reliability of Electric Service ........................................................... 5-15 5.9 Annual System Demand ................................................................... 5-15 5.10 Status of Previous Master Plan Items ............................................... 5-16 6.0 CONSTRUCTION RECOMMENDATIONS ........................................................... 6-1 a. Loading and Capacity .................................................................. .6-1 b. Mechanical Condition of Plant .................................................... .6-1 c. System Analysis ........................................................................... .6-1 d. Contingency System Planning ..................................................... .6-1 e. Sectionalizing Recommendations ................................................ .6-1 Tables 6-2 6.1 DONNER LAKE SERVICE AREA ................................................... 6-4 6.2 GLENSHIRE SERVICE AREA ......................................................... 6-9 6.3 MARTIS VALLEY SERVICE AREA ............................................. .6-11 6.4 TAHOE DONNER SERVICE AREA .............................................. .6-15 6.5 TRUCKEE SERVICE AREA ........................................................... .6-20 6.6 SYSTEM WIDE IMPROVEMENTS ............................................... .6-26 APPENDICES Costs Maps Truckee Donner Public Utility District 2019 Electric System Master Plan Section 1.0 1-1 1.0 OVERVIEW & PURPOSE 1.1 Overview This report contains an analysis of the present system and the 2019 Electric System Master Plan for Truckee Donner Public Utility District (the District or TDPUD). The Executive Summary, Section 2, contains the required information for the District's management to include in long-range financial forecasts and a summary of the recommended plan. The Planning and Sectionalizing Criteria is described in Sections 3 and 4 respectively, while Section 5 provides a review of historical trends and load forecasts. Section 4 includes the philosophy used by the Engineer to provide proper coordination between the protective devices in the District’s system. Section 5 of this report examines performance of the existing distribution system for voltage drop, voltage and current imbalance, line loading, equipment capacity, power factor and losses with present peak, projected 5 and 15 year peak conditions. 1.2 Purpose The main purpose of this report is to provide Truckee Donner Public Utility District with an orderly plan for carrying out construction, protective coordination and other needed improvements. Complementary to this purpose is the study’s goal of planning and completing improvements in the most economic manner possible. A second major purpose of this report is to provide the most up-to-date forecast possible of financial requirements for the next 15 years. These cost estimates provide the utility with the data necessary for completion of their annual business work plans and budgets and serve as a basis for long-term financial forecasts. Service reliability and quality of service are the very essence of operational goals in any electric utility. The function of system planning is to evaluate the existing and projected system configuration, voltage levels and load balance in a manner that endeavors to increase the quality of service. In a continuing effort and in order to serve its intended purpose, planning must change dynamically as governing conditions change. This plan provides the Owners’ and Engineers’ current philosophy on those specific improvements which will best meet the present needs of the system. In addition to the Master Plan construction recommendations, a detailed sectionalizing study was completed to provide the best possible protection for the utility and consumers. This evaluation of the system takes into consideration the following items: · Increased fault levels due to system improvements · Loading of equipment · Reliability Taking into account each of the above items, the system was evaluated to ensure that all devices met maximum interrupt rating, while not exceeding their continuous current ratings, and that devices would pick up minimum fault currents based on a 40 ohm ground resistance. Proper coordination between devices was also evaluated in an attempt to Truckee Donner Public Utility District 2019 Electric System Master Plan Section 1.0 1-2 eliminate simultaneous operation. As a result of this evaluation, the sectionalizing study provides recommendations which will enable the District to provide a high level of reliability to its customers. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 2.0 2-1 2.0 EXECUTIVE SUMMARY This report presents the results of a Master Plan prepared by Electrical Consultants, Inc. (ECI) for Truckee Donner Public Utility District (the District). This study evaluates the District’s distribution system which provides electric service in Northeastern California. Based upon the planning criteria identified in Section 3.0 and pertinent historical trends and load forecasts identified in Section 5.0, distribution system performance was evaluated in order to identify criteria violations for voltage drop, voltage and current imbalance, line and equipment loading, as well as power factor and losses. System performance was evaluated by first performing load flows for peak loading conditions. A thorough review of the existing system performance with the present, transition (5 year) and long range (15 year) loading was performed. The peak model is represented by the existing system maps located in the Appendix, which include voltage loading levels through the District’s distribution system. Results of the load flow analysis are summarized in Section 6.0 along with recommendations for system improvement. After load growth was implemented in the model, protective device settings were updated to reflect the existing system. Changes are recommended where minimum pick up levels are above minimum fault current levels within the protection zones. Other recommendations provided within this report provide increased coordination intervals and new sectionalizing points. Most of the improvements are considered minor in nature and would bring the District’s system reliability to a higher level. All feeders on the District’s system utilize an electronic recloser for feeder protection. All of these controls, with the exception of Glenshire, have high current trip (HCT) and high current lock out (HCL) enabled on the controls. Ideally, the use of HCT and HCL will trip and lock out a recloser for a fault on the main underground feeder. Setting changes are recommended to many of the reclosers to increase the trip levels on the HCT and HCL to allow down line faults to be cleared by tap fuses while the feeder recloser only lock out for a close in fault on the underground. All recommendations were designed to be in general concurrence with planning criteria and to ensure that no adverse impacts to the integrity of the District’s system were imposed. The mechanical condition of the District’s plant, along with reliability of service to members, was also factored into the recommendations for system improvement. Single contingency outages were investigated through analysis of load flow and voltage drop studies to address system requirements during such operating conditions. 2.1 Existing System Performance Figure 2-2-1 displays the District’s system kW demands since 1991 and projected 15 year usage based upon historic load data and least squares statistical regression technique. The non-coincidental peak load that was utilized for the load flow analysis was 47 MW for existing system loads. In consideration of potential growth over the 15 year study period, 53 MW was utilized for projected 5 year growth and 57 MW was utilized for projected 15 year growth. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 2.0 2-2 Analysis of existing systems shows no substations have voltage less than 116.0 volts. This means that in its current shape, there are very few improvements that will be required during the next 15 years. ANSI C84.1-2011 sets normal voltage levels for equipment on a distribution system. Minimum service voltage set by this standard is 114.0 volts under normal operating conditions. Service voltage is defined as the connected point between the customer and the utility, which is considered the meter. Analysis of the District’s system consisted of voltage drop on the primary line and did not account for voltage drop from the transformer to the meter. A minimum voltage of 118.0 volts on the primary line allows for a 4.0 volt drop through the transformer and secondary wire to the meter. Refer to Section 3.0, System Planning Criteria, for voltage criteria used for system planning and other criteria. Conductor loading over 80% was noted for the existing system in the Donner Lake service area. At the projected fifteen (15) year loads, additional conductor overloading was also noted in the Donner Lake service area on Feeder 1. A single contingency load transfer of each substation was performed with existing as well as projected 5 and 15 year loads. This single contingency assumes a loss of substation service transferring feeders to adjacent service areas. Complete load transfer of all substations be accomplished under peak loading conditions. The balance of the substations could be transferred to adjacent substations; however, voltage levels fell below planning criteria, where transformer and conductor overloading was also noted during these load transfers. Figure 2-2-1 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 2.0 2-3 2.2 Recommended System Improvements were recommended for the Electric System Master Plan which would first improve voltage levels under peak loading conditions for both existing and projected 15 year loads. Phase balancing was also recommended for the existing system to not only improve voltage levels but to reduce losses. Single phase taps with greater than 30 amps of load should be considered for rebuild to three-phase to allow for more effective phase balancing throughout the system. It was recommended to use minimum standard conductor size of 2/0 AWG ACSR for these rebuilds, however, local demographics may warrant the use of smaller conductors, such as 2 AWG ACSR, in areas of anticipated low growth. The following is an overview of the major projects recommended for the District’s service area: · Rebuilding of the three-phase line from Davos Dr. and Northwood Blvd. at the substation to Fjord Rd. and Northwood Blvd. This project is required to improve voltage during transfer to Donner Lake to above 114.0 V. It will also improve loading, as the existing conductor is over 100% loading during contingency. · The District is interested in installing a photovoltaic system on the District headquarters building in 2020. Not only would the District be reducing its own carbon footprint, all of the District’s customers would benefit with a lower District complex electric bill. Additionally, all generation would count towards the District’s renewable portfolio requirements. · The District has completed 4 phases of optical communication line installation. Four additional phases are expected to be required for connection to all remaining District facilities. At completion, there will be a redundant network to all facilities, with 2 distinct physical paths from each facility back to the main office. · Upgrading the Truckee Substation transformers to either a set of three (3) 8.3 MVA single-phase transformers or a 25 MVA three-phase transformer in order to provide load transfer capability between Martis Valley and Truckee substations when Martis Valley is cleared at 15-year loading levels. · The District will replace all T-link expulsion fuses with ELF current limiting fuses in Tahoe Donner by 2022. TDPUD’s standard fuse manufacturer and type are Kearney Type T fuses. The Kearney fuse has a relatively quick clearing time on a majority of the fuse sizes. It is recommended that all taps off of the main three-phase line be fused, so as not to have an outage on a short tap, resulting in a feeder recloser going to lock-out. For each feeder on the system, there is a fuse coordination table listed, showing maximum T fuse size to be used with up- line reclosers. On longer taps, it is recommended that the tap be fused and additional fuses down-line be used to increase coordination. This will not only improve reliability, but also aid in locating faults. It is important to fuse the single-phase taps off from the main three-phase line to improve Truckee Donner Public Utility District 2019 Electric System Master Plan Section 2.0 2-4 reliability. This is especially true on short taps where a two or three span tap with a fault would result in the feeder seeing the blink or having an outage. 2.3 Contingency Analysis Using the recommended model as a basis, contingency analysis was performed. Currently there is load transfer capability between all of the substations for individual feeders. There are a large number of existing possible contingency options between substations, which allows for a wide array of possible load transfers. All possible contingency options between feeders of different substations were analyzed and projects were provided in order to make load transfer possible in the case of a total substation outage. 2.4 Cost Summary Table 2-4-1 through Table 2-4-4 show recommended and contingency project costs by substation and priority year. Project CodeMiles/ QtyConstruction Description Unit CostTotal CostSub MulPriorityRecommended CostTable 2-4-1TDPUDSubstation:District WideFO-011$875,000SCADA Reliability Improvement Project Phase 5 Install $875,000District Wide 11FO-021$100,000SCADA Reliability Improvement Project Phase 6 Design $100,000District Wide 12FO-031$500,000SCADA Reliability Improvement Project Phase 6 Install $500,000District Wide 13FO-041$300,000SCADA Reliability Improvement Project Phase 7 Design $300,000District Wide 14FO-051$850,000SCADA Reliability Improvement Project Phase 7 Install $850,000District Wide 15FO-061$350,000SCADA Reliability Improvement Project Phase 8 Design $350,000District Wide 16FO-071$850,000SCADA Reliability Improvement Project Phase 8 Install $850,000District Wide 17FO-081$650,000SCADA Reliability Improvement Project Phase 9 Design $650,000District Wide 18FO-091$650,000SCADA Reliability Improvement Project Phase 9 Install $650,000District Wide 19FUS-011$225,000CL Fuse Installations - Tahoe Donner$225,000District Wide 11FUS-021$250,000CL Fuse Installations - Tahoe Donner$250,000District Wide 12Friday, November 15, 2019Page 1 of 4 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostSub MulPriorityRecommended CostTable 2-4-1TDPUDFUS-031$300,000CL Fuse Installations - Tahoe Donner$300,000District Wide 13FUS-041$400,000CL Fuse Installations - Prosser Lakeview$400,000District Wide 14FUS-051$300,000CL Fuse Installations - Prosser Lakeview$300,000District Wide 15FUS-061$300,000CL Fuse Installations - Prosser Lakeview$300,000District Wide 16SRP-011$150,000Solar Awning Project$150,000District Wide 11SYS-01A50$6,000Pole Replacements$300,000District Wide 11SYS-02A50$6,000Pole Replacements$300,000District Wide 12SYS-03A50$6,000Pole Replacements$300,000District Wide 13SYS-04A50$6,000Pole Replacements$300,000District Wide 14SYS-05A50$6,000Pole Replacements$300,000District Wide 15$8,550,000Total District Wide CostSubstation:Donner LakeFriday, November 15, 2019Page 2 of 4 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostSub MulPriorityRecommended CostTable 2-4-1TDPUDDL-01.46$254,950Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$117,000Donner Lake 13DL-02.1$254,950Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$25,000Donner Lake 14DL-SEC1$15,000R30 Replacement$15,000Donner Lake 11$157,000Total Donner Lake CostSubstation:GlenshireGL-01a1$100,000Engineering for installation of step up transformer$100,000Glenshire 11GL-01b1$750,000Install Glenshire Autotransformer Equipment $750,000Glenshire 12$850,000Total Glenshire CostSubstation:Martis ValleyMV-01a1$50,000Engineering for substation upgrades$50,000Martis Valley 11MV-01b1$200,000MVAL Circuit Switcher Replacement and other upgrades $200,000Martis Valley 12MV-SEC1$15,000R35 Replacement$15,000Martis Valley 11$265,000Total Martis Valley CostSubstation:Tahoe DonnerFriday, November 15, 2019Page 3 of 4 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostSub MulPriorityRecommended CostTable 2-4-1TDPUDTD-04.7$278,142Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$195,000Tahoe Donner 12TD-SEC1$30,000R20 and R50 Replacement$30,000Tahoe Donner 11$225,000Total Tahoe Donner CostSubstation:TruckeeTR-01.22$254,545Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$56,000Truckee 15TR-021.22$382,425Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$467,000Truckee 11TR-031$970,000Sub control house and containment improv.$970,000Truckee 11$1,493,000Total Truckee Cost$11,540,000Total Recommended CostFriday, November 15, 2019Page 4 of 4 Project CodeMiles/ QtyConstruction DescriptionUnit CostTotal CostFeederSubstation/ Item PriorityRecommended Cost by YearTable 2-4-2TDPUDDL-SEC1$15,000R30 Replacement$15,000DL-3Donner Lake 1FO-011$875,000SCADA Reliability Improvement Project Phase 5 Install$875,000DistrictDistrict Wide 1FUS-011$225,000CL Fuse Installations - Tahoe Donner$225,000DistrictDistrict Wide 1GL-01a1$100,000Engineering for installation of step up transformer$100,000GL-1Glenshire 1MV-01a1$50,000Engineering for substation upgrades$50,000Martis Valley 1MV-SEC1$15,000R35 Replacement$15,000MV-2Martis Valley 1SRP-011$150,000Solar Awning Project$150,000DistrictDistrict Wide 1SYS-01A50$6,000Pole Replacements$300,000DistrictDistrict Wide 1TD-SEC1$30,000R20 and R50 Replacement$30,000TD-1Tahoe Donner 1TR-021.22$382,425Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$467,000TR-5Truckee 1TR-031$970,000Sub control house and containment improv. $970,000Truckee 1$3,197,000Total Year 1 CostFO-021$100,000SCADA Reliability Improvement Project Phase 6 Design$100,000DistrictDistrict Wide 2FUS-021$250,000CL Fuse Installations - Tahoe Donner$250,000DistrictDistrict Wide 2GL-01b1$750,000Install Glenshire Autotransformer Equipment $750,000GL-1Glenshire 2Friday, November 15, 2019Page 1 of 3 Project CodeMiles/ QtyConstruction DescriptionUnit CostTotal CostFeederSubstation/ Item PriorityRecommended Cost by YearTable 2-4-2TDPUDMV-01b1$200,000MVAL Circuit Switcher Replacement and other upgrades$200,000Martis Valley 2SYS-02A50$6,000Pole Replacements$300,000DistrictDistrict Wide 2TD-04.7$278,142Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$195,000TD-2Tahoe Donner 2$1,795,000Total Year 2 CostDL-01.46$254,950Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$117,000DL-3Donner Lake 3FO-031$500,000SCADA Reliability Improvement Project Phase 6 Install$500,000DistrictDistrict Wide 3FUS-031$300,000CL Fuse Installations - Tahoe Donner$300,000DistrictDistrict Wide 3SYS-03A50$6,000Pole Replacements$300,000DistrictDistrict Wide 3$1,217,000Total Year 3 CostDL-02.1$254,950Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$25,000DL-3Donner Lake 4FO-041$300,000SCADA Reliability Improvement Project Phase 7 Design$300,000DistrictDistrict Wide 4FUS-041$400,000CL Fuse Installations - Prosser Lakeview$400,000DistrictDistrict Wide 4SYS-04A50$6,000Pole Replacements$300,000DistrictDistrict Wide 4$1,025,000Total Year 4 CostFO-051$850,000SCADA Reliability Improvement Project Phase 7 Install$850,000DistrictDistrict Wide 5Friday, November 15, 2019Page 2 of 3 Project CodeMiles/ QtyConstruction DescriptionUnit CostTotal CostFeederSubstation/ Item PriorityRecommended Cost by YearTable 2-4-2TDPUDFUS-051$300,000CL Fuse Installations - Prosser Lakeview$300,000DistrictDistrict Wide 5SYS-05A50$6,000Pole Replacements$300,000DistrictDistrict Wide 5TR-01.22$254,545Rebuild 1-phase #2 AWG ACSR with 3-phase #2 AWG ACSR$56,000TR-1Truckee 5$1,506,000Total Year 5 CostFO-061$350,000SCADA Reliability Improvement Project Phase 8 Design$350,000DistrictDistrict Wide 6FUS-061$300,000CL Fuse Installations - Prosser Lakeview$300,000DistrictDistrict Wide 6$650,000Total Year 6 CostFO-071$850,000SCADA Reliability Improvement Project Phase 8 Install$850,000DistrictDistrict Wide 7$850,000Total Year 7 CostFO-081$650,000SCADA Reliability Improvement Project Phase 9 Design$650,000DistrictDistrict Wide 8$650,000Total Year 8 CostFO-091$650,000SCADA Reliability Improvement Project Phase 9 Install$650,000DistrictDistrict Wide 9$650,000Total Year 9 Cost$11,540,000Total Recommended CostFriday, November 15, 2019Page 3 of 3 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostFeeder Sub MulYr of ImprovContingency CostTable 2-4-3TDPUDDL-C1.35$284,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$99,470TR-4 Truckee 18DL-C22$37,500Install S&C PMH-9, Pad-Mtd. Switchgear, 15 kV Equipment$75,000DL-2 Donner Lake 18DL-C4.77$283,450Rebuild 2-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$218,257DL-2 Donner Lake 110DL-C51$60,000Install 328 amp, 250 kVA Equipment$60,000MV-3 Martis Valley 112DL-C6.8$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$222,560DL-3 Donner Lake 15MV-C31$950,000Install three (3) single-phase 7.5 MVA transformers$950,000MV-1 Martis Valley 16MV-C6.2$282,700Rebuild 1-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$56,540MV-3 Martis Valley 18MV-C7.08$913,357Rebuild 3-phase 500 kcmil 260 MIL EPR with 3-phase 750 MCM$73,069MV-4 Martis Valley 115TD-C2.83$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$230,906TD-1 Tahoe Donner 11TD-C3.74$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$205,868TD-1 Tahoe Donner 14TD-C4.67$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$186,394TD-3 Tahoe Donner 11TD-C51$278,000Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$278,000TD-2 Tahoe Donner 11TR-C1.33$284,200Rebuild 3-phase #2 AWG ACSR with 3-phase 397 kcmil AAC$93,786TR-3 Truckee 17TR-C2.59$284,200Rebuild 3-phase #4/0 AWG ACSR with 3-phase 397 kcmil AAC$167,678TR-2 Truckee 111TR-C3.15$913,330Rebuild 3-phase #500 MCM with 3-phase 750 AWG EPR$137,000TR-2 Truckee 113TR-C41$750,000Install three (3) single-phase 7.5 MVA transformers$750,000TR-2 Truckee 114TR-C5.18$284,200Rebuild 3-phase #4/0 AWG ACSR with 3-phase 397 kcmil AAC$51,156TR-2 Truckee 112Thursday, November 14, 2019Page 1 of 2 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostFeeder Sub MulYr of ImprovContingency CostTable 2-4-3TDPUDTR-C6.04$913,357Rebuild 3-phase #500 MCM with 3-phase 750 MCM$36,534TR-2 Truckee 112$4,883,757Total Contingency CostThursday, November 14, 2019Page 2 of 2 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostTDPUDFeederSubstation/ ItemYr of ImprovContingency Cost by YearTable 2-4-4TD-C2.83$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$230,906TD-1Tahoe Donner 1TD-C4.67$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$186,394TD-3Tahoe Donner 1TD-C51$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$278,000TD-2Tahoe Donner 1$834,400Total Year 1 CostTD-C3.74$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$205,868TD-1Tahoe Donner 4$278,200Total Year 4 CostDL-C6.8$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$222,560DL-3Donner Lake 5$278,200Total Year 5 CostMV-C31$350,000Install three (3) single-phase 7.5 MVA transformers$950,000MV-1Martis Valley 6$950,000Total Year 6 CostTR-C1.33$278,200Rebuild 3-phase #2 AWG ACSR with 3-phase 397 kcmil AAC$93,786TR-3Truckee 7$91,806Total Year 7 CostDL-C1.35$278,200Rebuild 3-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$99,470TR-4Truckee 8DL-C22$23,669Install S&C PMH-9, Pad-Mtd. Switchgear, 15 kV Equipment$75,000DL-2Donner Lake 8MV-C6.2$278,200Rebuild 1-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$56,540MV-3Martis Valley 8Thursday, November 14, 2019Page 1 of 3 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostTDPUDFeederSubstation/ ItemYr of ImprovContingency Cost by YearTable 2-4-4$190,510Total Year 8 CostDL-C4.77$278,200Rebuild 2-phase #2/0 AWG ACSR with 3-phase 397 kcmil AAC$218,257DL-2Donner Lake 10$214,214Total Year 10 CostTR-C2.59$278,200Rebuild 3-phase #4/0 AWG ACSR with 3-phase 397 kcmil AAC$167,678TR-2Truckee 11$164,138Total Year 11 CostDL-C51$20,697Install 328 amp, 250 kVA Equipment$60,000MV-3Martis Valley 12TR-C5.18$278,200Rebuild 3-phase #4/0 AWG ACSR with 3-phase 397 kcmil AAC$51,156TR-2Truckee 12TR-C6.04$907,357Rebuild 3-phase #500 MCM with 3-phase 750 MCM $36,534TR-2Truckee 12$146,370Total Year 12 CostTR-C3.15$84,480Rebuild 3-phase #500 MCM with 3-phase 750 AWG EPR $137,000TR-2Truckee 13$913,330Total Year 13 CostTR-C41$350,000Install three (3) single-phase 7.5 MVA transformers$750,000TR-2Truckee 14$750,000Total Year 14 CostMV-C7.08$907,357Rebuild 3-phase 500 kcmil 260 MIL EPR with 3-phase 750 MCM$73,069MV-4Martis Valley 15Thursday, November 14, 2019Page 2 of 3 Project CodeMiles/ QtyConstruction Description Unit CostTotal CostTDPUDFeederSubstation/ ItemYr of ImprovContingency Cost by YearTable 2-4-4$72,589Total Year 15 Cost$4,883,757Total Contingency CostThursday, November 14, 2019Page 3 of 3 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 2.0 2-5 2.5 Project Prioritization The first aspect to consider when determining a project’s priority is whether the project is for the normal system improvement or for a contingency improvement. Normal system improvements would have first priority over a contingency improvement. The next consideration would be voltage levels of the system and at what year those voltage levels fall below planning criteria. Projects required to correct voltage for a transition period or long range period would have a lower priority than those needed to correct the existing system. The next item to consider would be the number of customers being served in the area requiring the project. An area with a high number of projects, although it may not have as low of voltage as other areas, would have a higher priority. The last item to consider would be budget constraints in completing the project. Some systems may require a number of projects to correct existing system voltages requiring a large portion of the overall projects be completed within the first few years of the plan. However, this may not be feasible and would require that the projects be spread over a number of years, even though they are required as soon as possible. In these cases, the best approach is to try to complete projects that provide the most for your money. For example, completing a number of three-phase projects to allow phase balancing, improving voltage in a number of areas versus one major line rebuild. Although the plan may prioritize projects, it is best to spread them over the planning period. Projects may need to be prioritized due to events of construction that may occur at an earlier time frame. For example, a project may be slated for year five, however, the county has just informed the District that it is going to rebuild a road in that area and that the line would need to be rebuilt, resulting in this project construction being moved up by three years. Another example may be that a subdivision did not develop as planned and that project may be moved back until such time that the subdivision is constructed. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-1 3.0 SYSTEM PLANNING CRITERIA The design criteria presented within this section was used to guide the development of the 2019 Electric System Master Plan. Criteria were developed to provide minimum standards for all system improvement, operation, and maintenance activities affecting system facilities. Compliance with these minimum standards will result in adequate voltage, acceptable thermal loading of system components, and a distribution system capable of providing safe, reliable service. This study considers quality of service and service continuity to be critical issues to the District. Geographical conditions, including occasions of severe inclement weather in this service area, serve as a factor in the results. Meeting established criteria will help the District maintain an excellent quality of service to their consumers. The District has, and will continue to, utilize current technologies to improve the quality of service to the membership, allow efficient operations, and provide the ability to gather data to evaluate potential improvements to the system. All criteria were established jointly between Electrical Consultants, Inc. (ECI) and Truckee Donner Public Utility District (the District). 3.1 Electrical System Performance Criteria This section describes basic electrical performance criteria for the system for both normal and contingency operating conditions. Regulated load flows were utilized for by-phase analysis of the performance of the District’s system. a. Distribution System Voltage Level Voltage levels for the plan are defined with regulated substation bus voltage set to 124.0 volts during all seasons for purposes of the voltage drop study. Maximum voltage at any point of the distribution feeders is limited to 126.0 volts. The system developed for the plan period is designed to maintain 118.0 volts at all distribution transformer primaries. This 118.0-volt limit is consistent with ANSI standards which specify 114.0 volts minimum to the consumer premises where the additional 4.0 volts drop represents service transformer and service wire drop. For contingencies, the system developed for the plan period is designed to maintain voltage levels of 114.0 volts at the primary terminals of any distribution transformer on the system. For voltage levels below 114.0 volts during contingencies, improvements will be recommended. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-2 Voltage Class Nominal System Voltage Nominal Utilization Voltage Voltage Range A Voltage Range B Maximum Minimum Maximum Minimum 3-wire 3-wire Utilization and Service Voltage Service Voltage Utilization Voltage Utilization and Service Voltage Service Voltage Utilization Voltage Low Voltage Single-Phase Systems 120-240 115 115/230 126 126/252 114 114/228 110 110/220 127 127/254 110 110/220 106 106/212 Standard Nominal System Voltages and Voltage Ranges Table 3-1-1 As defined by ANSI C84.1-2011: Service Voltage: The voltage at the point where the electrical system of the supplier and the electrical system of the user are connected. Utilization Voltage: The voltage at the line terminals of utilization equipment. Range A: Electrical supply systems shall be so designed and operated that most service voltages will be within the limits specified for Range A. The occurrence of service voltages outside of these limits should be infrequent. Range B: Range B includes voltages above and below Range A limits that necessarily result from practical design and operating conditions on supply or user systems, or both. Although such conditions are a part of practical operations, they shall be limited in extent, frequency, and duration. When they occur, corrective measures shall be undertaken within a reasonable time to improve voltages to meet Range A requirements. 3.2 Voltage Regulation This section describes the application of a load tap changer (LTC), voltage regulator, line drop compensation, first house protection, and reverse power flow devices. Upon installation of regulators in the recommended plan, the R and X values will be computed to assure optimal settings. The criteria utilized in this study include, but are not limited to, the following: a. Voltage limit settings of 126.0 volts for first house protection shall be utilized whenever possible to prevent excessive voltage to consumers. Significant consideration to voltage regulator compensation settings shall be given to assure that regulator controls do not inadvertently result in “out of criteria” voltages during peak loading conditions. b. In lieu of regulating the substation bus, line drop compensation (LDC) settings attempt to regulate a level of system voltage at a theoretical Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-3 load center on the feeder by adjusting voltage levels as a function of power flow. LDC settings will cause voltage at the substation bus and end-of-line to fluctuate, while attempting to maintain a relatively fixed voltage near the center of the feeder. Without LDC, bus voltage remains fairly constant with relatively large voltage fluctuations at remote points on the feeder. Use of LDC may create problems for large industrial, or other voltage sensitive customers located near the substation, due to the frequency and magnitude of system voltage changes. c. In order to maximize the use of the distribution system, it is necessary to operate the substation tap changers/regulators to adequately compensate for swings in the transmission voltage and provide a sufficient voltage range for allocation across the distribution system. d. Feeder regulation, instead of bus regulation, will be considered at substations where the loading conditions or load density vary significantly between feeders. e. Reverse power flow will be considered at strategic locations for load transfer between feeders that can be source fed from either direction. f. Regulation at the substation, as well as one stage of regulation installed on the feeder, is acceptable in all system design, however, cascaded feeder regulators will be considered on a case-by-case basis. Cascaded regulators may provide the best long-term solution for load transfer on feeders where capacity is not the limiting condition. 3.3 Phase Balancing If the load on the feeder is poorly balanced between phases, reasonable measures should be taken to achieve balance. Balanced conditions mean equal current in each phase with corresponding minimum regulation at system design loading. Unbalanced feeders can result in poor voltage regulation, unnecessarily increased line losses, and facilities that may be overloaded. This is possible even if the total three-phase load is not excessive. An ideal design, although usually not achievable in practice, will provide load balance throughout the entire feeder, not just at the substation. If a feeder serves only three-phase load, then balance is typically not a problem. Phase balance is also a primary concern when considering sectionalizing. The following items provide a general indication of potential phase balance problems. To be most effective, attempts shall be made to achieve good balance at system design loading. a. Substation Transformer Unbalance – Goals of balancing substation loads include maintaining balanced flow of power on the distribution system and reducing the risk of transformer bank Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-4 Protective device operation. The percentage unbalance recommended allows a reasonable margin for the effects of downstream sectionalizing during contingencies. Substation unbalance, as defined at the end of this section, should not exceed 25%, or 75 amps, whichever is less, where practical. b. Feeder Unbalance at Substations – The purpose of these criteria is to maintain balanced flow of power on the distribution system and reduce the risk of overloading of the substation feeder and protective devices, as well as the substation transformers. For feeders where the highest loaded phase is 149 amps or less, unbalance should not exceed 40% or 50 amps, whichever is less. For feeders where the highest loaded phase is 150 amps or more, unbalance should not exceed 25% or 75 amps, whichever is less. c. Feeder/Tap Unbalance – The purpose of limiting unbalance in downstream feeders is to maintain balanced flow of power on the distribution system and reduce system losses and voltage drop. For locations where the highest loaded phase is 149 amps or less, unbalance should not exceed 24% or 30 amps, whichever is less. For locations where the highest loaded phase is 150 amps or more, unbalance should not exceed 25% or 100 amps, whichever is less. For single-phase taps with greater than 30 amps, extension of three- phase should be considered. d. Voltage Unbalance – Normally, when loads are balanced, voltages will also be balanced. However, phase voltages may not be balanced due to unbalance in loading. Based on ANSI/IEEE Standard 141- 1993, the target for maximum allowable voltage unbalance is 2%. The formula to calculate such unbalance is: VoltageUnbalance = Maximum Difference Phase Voltage - Average Voltage Average Voltage Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-5 3.4 Capacity and Loading This section defines criteria related to equipment loading, including the effect of seasonal conditions and ratings, to be considered. a. Load Periods Winter peak loading conditions generally determine the system peak for the District. b. Equipment Loading A key objective of this plan is to maintain peak feeder loading during normal system conditions at desired loading levels to allow for load transfer and protective coordination. Normal system loading is generally desired to be a maximum of 80% conductor loading and 50% conductor loading for feeder ties to allow load transfer. Equipment loading, expressed as a percent of nameplate rating, should not exceed the following: Transformers – A transformer shall not be thermally loaded by more than the following percentage of its nameplate rating: Continuously loaded to 125% of OA rating (no fans) during average winter daily temperatures of 32°F (0°C) plus 5°C margin. Continuously loaded to 100% of OA rating (no fans) during average summer daily temperature of 72°F (22°C) plus 5°C margin. The above limits are based on Table 3 of IEEE Standard C57.91-2011 edition, shown on the following page. Table 3 of IEEE Standard C57.91-2011 Loading on Basis of Temperatures (Ambient other than 30°C and Average Winding Rise Less than Limiting Values) (For Quick Approximation) (Ambient Temperature Range 0°C to 50°C) Type of Cooling % of Rating Decrease Load for Each °C Higher Temperature Increase Load for Each °C Lower Temperature Self-cooled – ONAN 1.5 1.0 Water-cooled – ONWF 1.5 1.0 Forced-air-cooled – ONAN/ONAF, ONAN/ONAF/ONAF 1.0 0.75 Forced-air-cooled – OFAF, OFWF, ODWF, and ONAN/OFAF/OFAF 1.0 0.75 *See 5.1 in IEEE Std C57.12.00-2010. -average ambient other than 30 ° C and average winding rise less than limiting values, for quick approxim ation, ambient temperature range –30 ° C to 50 ° C Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-6 Table 3-4-1 lists substation transformer ratings. Substation Transformer Size °C Donner Lake 12 MVA 65° Glenshire N/A N/A Martis Valley 3-1PH 5 MVA 55° Tahoe Donner 3-1PH 5 MVA 55° Truckee 3-1PH 5 MVA 55° Substation Transformer Table 3-4-1 Substation and Line Voltage Regulators – Substation and line voltage regulators shall be monitored for possible replacement at 80% loading on feeders with high load factors during summer peak conditions and 100% during other seasonal conditions. Consideration to increase loading capability by limiting the tap range is given for substation regulators as an alternative to replacement. Hydraulic Circuit Reclosers – Hydraulic circuit reclosers should not be loaded more than 80% during peak and load transfer conditions. Excessive loading of these devices can cause inadvertent oil flow in the device timing mechanism, causing reduced operating time and possible mis-coordination. Electronically Controlled Reclosers and Relay Controlled Breakers – Electronically controlled reclosers and relay controlled breakers should not be loaded more than 100% during peak conditions, including load transfer conditions. c. Conductor Primary conductors should not to be loaded over 80% of their thermal rating under normal service conditions, especially when age and condition elements are present. In addition, loading should be conservatively determined to provide sufficient load transfer capability. Primary conductor sizing for improvements will be determined on a case-by-case basis using the following criteria: a. Economic conductor size; and b. Minimum size for main three phase line segments for contingency load transfers determined necessary and practical between the District and ECI. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-7 c. The District’s standard conductor sizes are as follows: 2 AWG ACSR 4/0 AWG AAC 2/0 AWG ACSR 397 kcmil AAC 1/0 AL EPR 795 kcmil AAC 500 AL EPR The following, Table 3-4-2, provides conductor economic sizing data based upon various conductor sizes used on the District’s system for 12.47 kV. This table is used by first estimating the peak kW load anticipated over the future fifteen-year period and the construction type (single or three-phase). The conductor size and approximate thermal capacity may be found in the adjacent columns. Anticipated Peak kW @ 12.47 kV Phase Capacity in MW @ 12.47 kV Select Minimum Conductor Size 0-600 1 1.3 2 AWG ACSR 0-800 3 3.9 2 AWG ACSR --- 3 6.3 2/0 AWG ACSR 600-1,500 3 8.2 4/0 AWG AAC 1,400-6,300 3 12.4 397 kcmil AAC 6,300+ 3 20.0 795 kcmil AAC 0-1,300 1 1.1 1/0 AL EPR 1,300-3,600 3 3.3 1/0 AL EPR 3,600+ 3 8.0 500 AL EPR Note: The following assumed values were used: · Present Worth Interest (%) = 4.15 · Demand Charge ($/kW/Yr) = 0 · Number of Years in Study = 15 · Energy Charge (mills/kWh) = 71 · Power Factor (%) = 98 · Power Cost Inflation Rate (%) = 4 · Load Factor (%) = 68.39 · Demand Adjustment Factor (%) =70.93 · L-L Voltage in kV = 12.47 · Annual New Carrying Charge (%) = 18.36 · Conductor at 75°C, air at 25°C, wind at 1.4 miles Economic Conductor Selection 12.47 kV and Peak Loads Table 3-4-2 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 3.0 3-8 3.5 Power Factor & Losses Power factor correction to 97.5% lead to lag or better at the delivery points is desired in all service areas of the system. Consideration should also be given to the installation and optimum location of shunt capacitors on distribution lines. Capacitors provide a relatively low cost means to boost voltage and improve and control power factor. These improvements usually result in some demand reductions, energy conservation, and lower power costs. Some voltage regulation can be achieved with the judicious sizing and locating of (usually switched) capacitor banks. Transformer and voltage regulator losses should be evaluated as a component of purchase for new equipment. 3.6 Contingency System Conditions Contingency conditions to be reviewed in this plan include loss of a single substation transformer, as well as feeder loss on a case-by-case basis. 3.7 Mechanical Condition and Reliability Criteria The criteria described within this section must be considered in the analysis in order to provide complete evaluation of the system. Often plans overlook the needs of the present system and leave physically deteriorated facilities in place. In addition, several operational concerns can be addressed through the careful evaluation of these constraints with outage concerns and age of facilities. Specific mechanical items include, but are not limited to, the following: a. Distribution lines are to be rebuilt and/or relocated if found to be unsafe or in violation (when constructed) of the General Orders 95 and 128 or applicable codes and regulations. b. Poles and/or cross arms are to be replaced if found to be physically deteriorated by visual inspection and/or tests (ordinary replacements). c. Conductors (and associated poles and hardware, as required) shall be considered for replacement if found to contain an average of over two (2) splice(s) per phase per span in any one (1) mile increment, or if the conductor is old, in poor condition, or has been annealed. System improvements should be considered and made, if necessary, in specific areas where members have experienced more than one customer hour for suburban and five customer hours for rural outage hours per year, excluding outages caused by major storms or the power supplier, for the last five consecutive years. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 4.0 4-1 4.0 PROTECTION PHILOSOPHY 4.1 Basic Principles of System Coordination The following basic principles of system coordination were considered in development of the District’s Protection Philosophy: a. The basic purpose of a distribution system protection scheme is to provide protection for system equipment, as well as ensure safety of the public in the event of a fault. b. The distribution protection scheme is designed to quickly provide restoration of service to as many consumers as possible. In designing the protection scheme, it is understood that cost, practicality and service reliability must be viewed as a whole, with the optimum combination of these three considerations determined by judgment of the Engineer. c. Protective devices should correctly and specifically isolate faults so that operations personnel can easily locate the faulted section, make repairs, and restore service to consumers. d. Locations for proposed protective coordination devices, where supplied by the Engineer, should be field verified by operations personnel. The actual location for installation must meet protection requirements, as well as provide reasonable access for operations crews. e. A final objective of protective coordination is to minimize short circuit stress on system equipment, in particular, power transformers. 4.2 Sectionalizers A description of the philosophy used in recommending the use of sectionalizers is as follows: a. Modern “cutout style” sectionalizers are preferred over oil-filled sectionalizers to provide superior visual indication of open line sections. b. The application of sectionalizers on major overhead line sections where fuses are unsuitable due to the nature of the load or high incidence of momentary faults caused by lightning or line contact with trees is encouraged. c. Sectionalizers are not normally used to isolate URD lines, except where the underground line feeds a downstream section of overhead distribution, or where the URD meets the following requirements: i. The URD feeder is of sufficient length to justify multiple in-series sectionalizers. ii. URD of questionable reliability is installed downstream from newer URD cable. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 4.0 4-2 iii. The number of consumers or other characteristics of the feeder require multiple in-series sectionalizers to provide service reliability. iv. Sections of URD which are inaccessible during certain periods of the year, or otherwise present difficult operations and maintenance requirements. v. Load levels prevent use of properly sized fuses. vi. Where lightning will cause false trip of fuses. 4.3 Fuses The suitability of overhead line fuses for protection of the cooperative’s distribution system is evaluated upon the following criteria: a. Distribution systems in areas of high isokeraunic level, where lines are not shielded by trees or surrounding terrain, require field experience to optimize the application of overhead line fuses. In general, limiting fuses to as few locations as possible, which are easily accessible to operations personnel, will result in optimum service reliability. b. Use of overhead line fuses in areas of high isokeraunic level, where trees provide shielding or adjacent terrain, will be effective if momentary contact of trees with lines is infrequent. c. In areas of low isokeraunic activity, overhead line fuses provide an excellent means of isolating faults, if momentary contact of trees with power lines is infrequent. d. All URD taps should be fused and properly coordinated with upstream reclosers, except where sectionalizers are used for fault isolation. Load conditions may cause a need for VFI device types. e. Fuses used for protection of taps fed from main trunk lines are recommended to be coordinated with upstream reclosers as follows: i. Fuses on URD taps are sized to blow before the upstream recloser operates on its fast curve, provided that fuses can be adequately sized for the necessary load current. ii. Fuse protection of overhead lines connected to main trunk feeders are coordinated such that they blow before the upstream recloser operates on its fast curve only if the probability of momentary line faults due to lightning or trees is very unlikely. iii. For all other overhead line fuses, coordination results in blown fuses between fast and slow curves of the upstream recloser, provided that adequate current carrying capacity is provided. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 4.0 4-3 4.4 Electronic Recloser Applications Electronically controlled reclosers are recommended for substation feeders serving predominantly urban or semi-urban areas where load currents are relatively significant or where fault levels are high and additional coordination intervals can be justified. The selection between electronically controlled single or three-phase reclosers can be difficult at times. Single-phase installations trip the phase on which the fault is located, allowing service to continue to more members, but are more limited in application as loads approach 120 - 150 amps on 7.2/12.47 kV systems. At these load levels, single-phase device pickup settings may not be adequate for minimum fault levels. Three-phase devices are available, which allow single-phase tripping-single-phase lockout, single-phase tripping-three-phase lockout, and three-phase tripping three-phase lockout. Use of three-phase devices allows lower minimum faults to be picked up while allowing larger load currents. Three-phase devices use separate phase and ground settings and are not limited in this application. Generally, the sectionalizing scheme becomes more complicated as load levels increase, lending more desirability to three-phase devices. Most taps would generally be protected with a device, leaving three-phase line sections protected by the substation recloser. The following applications specifically lend themselves to the use of three-phase reclosers: a. Three-phase reclosers are recommended for feeders serving either urban or rural areas with predominantly three-phase loads and feeders serving one or more critical three-phase load(s) where it is undesirable for operations to result in single-phase service conditions. Examples of such areas include areas with large irrigation pumps, small and large commercial services, as well as other special load categories. b. Three-phase reclosers are strongly recommended for areas with long URD feeders with ferro-resonant potential. Ferro-resonance is an inductive-capacitive “tuned” circuit that can result in extremely high voltages and catastrophic failure of equipment. 4.5 Safety Considerations The following application criteria were considered to provide a degree of safety to District personnel as well as to the general public in preparation of this study: a. Interrupt rating for protective devices must meet or exceed maximum anticipated fault MVA at the point of application, including a margin for asymmetrical components for any system operating condition. b. The distribution protective coordination must detect and isolate minimum fault currents using conservative values of fault resistance as suggested by RUS in Bulletin 61-2. Protective equipment should provide “one-shot” capability for protection of maintenance personnel when working near energized facilities or lines. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 4.0 4-4 4.6 Guide to Performed Calculations In the application of overcurrent protective devices for distribution systems, the Engineer must have knowledge of short duration currents that flow under fault conditions at various locations on the system. These provide the “Guide to Performed Calculations” in the analysis. At each recloser location, maximum fault current levels are computed to evaluate equipment interrupting ratings and coordination. In a radial system, maximum current through a device occurs for a bolted fault at the device terminals. Minimum values of fault current are also needed to determine the applicable zone of protection for protective devices. If the upstream recloser or fuse cannot detect minimum fault levels, either a new zone of protection must be established, or device settings must be changed to provide detection of these minimum currents. Minimum fault currents are established by inserting an impedance of specified value into the fault path. Analytical analysis in the application of protective devices included: a. Source Impedance Data obtained from the power supplier for each delivery point. b. Conductor Size - Maximum fault calculations were based upon conductor size and computer models provided by TDPUD. Minimum phase-to-ground fault levels were based on the projected system as presented in the work plan with fault resistance for overhead lines (40 ohms). c. Load currents were also addressed in the study. Reclosers, fuses and sectionalizers each have a continuous current rating. Equipment ratings were compared to the most recent load data. In general, a hydraulic recloser will be changed out if load currents exceed 80% of the continuous current rating. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5-5 5.0 HISTORICAL DATA & LOAD FORECAST 5.1 Description of Service Area Truckee Donner Public Utility District (the District), headquartered in Truckee, California, is located in northeast California. The District’s service area served approximately 13,723 electric customers at the end of 2018. 5.2 Power Supply The District receives its power from Utah Associated Municipal Power Systems and Western Area Power Administration through four distribution substations. This power is wheeled over NV Energy's transmission system. I. Energy Efficiency and Conservation When acquiring a new resource, energy efficiency and conservation are considered the first resource. The District complies with California’s renewable energy, public benefit, and energy efficiency requirements. As part of the California Energy Commission’s (CEC) energy efficiency goal setting requirements, the District adopted the following goals in 2007 for reducing electricity usage: · Average Annual Feasible Energy (MWH) Target: 0.59% per year over 10 years · Average Annual Feasible Demand (MW) Target: 0.28% per year over 10 years · In addition, the District’s Board passed a resolution setting an internal energy goal of 1% per year over 10 years Since setting these goals, the District has invested heavily in cost-effective energy efficiency programs both internally and with their customers. 5.3 Transmission The District owns a few spans of transmission line from their Donner Lake Substation to NV Energy's transmission line. 5.4 Connection Statistics & Growth Patterns Statistics were compiled and visual aids prepared to show connection statistics and growth trends for the District. These statistics were compared to results of the most recent Power Requirements Plan to assure that all projections in the plan were consistent. In 2008 The District reclassified a significant number of customers, and due to that, the trend plots changed significantly. The trend plots are shown from 2008 on in order to properly depict growth. Figure 5-4-15 which is included at the end of this section shows the total number of connections from 1998 to 2018; the District has had a 1.49% increase in connections, annually since 1998. The District had a non-coincidental peak of 38.1 MW in December of 2015 and had a total of 13,388 connections for the year 2015 resulting in an average of 2.84 kW per connection. Although the District has grown to serve 13,723 customers in 2018, the non-coincidental peak for 2018 is lower than in 2015. This is most likely due to higher efficiency appliances and equipment being used by customers. The District has a projected fifteen (15) year peak Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5-6 of approximately 48,862 kW and 17,759 total projected connections for the year 2035 resulting in an average 2.75 kW per connection. Residential The number of residential connections has increased 1.47% per year over the last 21 years. This growth trend is expected to taper off. Residential monthly average usage per connection has varied over the last 21 years from 607 kWH in 1999 and down to 523 kWH in 2003. Usage is expected to remain at approximately 554 kWH per month. Figures 5-4-1 and 5-4-2, included at the end of this section, shows residential consumer statistics, historical usage, as well as a linear regression model projection. The usage regression shows a 1.11% compounded growth rate. However, over the last five years, TDPUD has had almost no increase in residential customers. Small Commercial (< 50 kW) Commercial connections (< 50 kW), or small commercial connections, grew at an average growth rate of 1.23% per year over the past 21 years, with average connection usage at about 1,598 kWH per month. Within the past 10 years, the number of connections has plateaued with an average growth rate of 0.22% over the next 15 years. The District anticipates a growth rate of 1.0% for these connections. Small commercial connection statistics, historical usage, as well as a linear regression model projection are shown in Figures 5-4-3 and 5-4-4 at the end of this section. Medium Commercial (> 50 kW and < 200 kW) Commercial connections (> 50 kW and < 200 kW) are classified as medium commercial connections. The number of annual connections has decreased from a high of 50 connections in 2004 and to 41 connections in 2018. The District anticipates a growth rate of 0.5% for these connections over the next 15 years. Medium commercial connection statistics, historical usage, as well as a linear regression model are shown in Figure 5-4-5 and 5-4-6 at the end of this section. The linear regression line shows a decrease in future years, but it is expected that the number of connections will plateau at 41 consumers. Large Commercial (> 200 kW) Commercial connections (> 200 kW) are classified as large commercial connections. The number of annual connections has stayed constant at 5 connections in the last 10 years. It is expected that the growth rate of 0.0% over the past 21 years will remain the same. The monthly usage per connection has decreased by 1.81% in the past 10 years. This trend is expected to plateau with roughly 3-5 customers within the next 15 years. Large commercial connection statistics, historical usage, as well as a linear regression model are shown in Figure 5-4-7 and 5-4-8 at the end of this section. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5-7 Public Authority The number of public authority connections has increased from 32 in 2007 to 220 in 2018. The increasing number of connections has increased the total usage by almost 40% in the past ten (10) years. It is expected that the number of connections and usage will plateau at roughly 223 customers. Public authority statistics and historical usage are shown in Figure 5-4-9 and 5-4-10 at the end of this section. Water Pump The number of water pump connections has plateaued with the growth rate of 0.67% in the last ten (10) years. Pumps belonging to the District's Water Department make the vast majority of these connections. The number of connections is expected to stay at 49 per year. Water pump connections and historical usage are shown in Figures 5-4-11 and 5-4-12 at the end of this section. The District Use The District’s usage has increased by 3.56% in the last ten (10) years. The usage is expected to remain the same at approximately 41,000 kWH/month until late 2020, when the addition of the Solar Awning Project will begin. District usage is then expected to decrease by approximately 3,000 kWH/month (36,000 kWH annually). The District’s usage and historical usage are shown in Figure 5-4-13 and 5-4-14 at the end of this section. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5-8 Figure 5-4-1 Figure 5-4-2 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5-9 Figure 5-4-3 Figure 5-4-4 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 10 Figure 5-4-5 Figure 5-4-6 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 11 Figure 5-4-7 Figure 5-4-8 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 12 Figure 5-4-9 Figure 5-4-10 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 13 Figure 5-4-11 Figure 5-4-12 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 14 Figure 5-4-13 Figure 5-4-14 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 15 Figure 5-4-15 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 16 5.5 Line Statistics As of 2018, the District’s system consisted of approximately 136.07 miles of overhead line and 87.86 miles of URD. A summary of the construction types are provided in Table 5-5- 1. The service area operates at 12.47 kV. There are approximately 13,723 active services, for a density of 61.28 consumers per mile of line. A little over half of the conductors on the system are 3-phase. Construction Type Miles of Line Overhead Line: Single-Phase Two-Phase Three-Phase 68.18 5.94 61.95 Underground Line: Single-Phase Two-Phase 34.46 2.19 Three-Phase 51.20 TOTAL MILES: 223.93 Truckee Donner Public Utility District Approximate Distribution System Plant as of 2018 Table 5-5-1 The existing system is a composite of conductor types, as is indicated by the tables on the following pages. Table 5-5-2 lists conductor miles by size and type for the system and Table 5-5-3 lists conductor miles by size and type for each substation. Table 5-5-4 displays the total line miles of the existing underground by size and type. Conductor Type Three Phase Two Phase Single Phase Total Table 5-5-2 Truckee Donner PUD - Total Line Miles 1/0 ACSR OH 1.39 0.00 0.00 1.39 1/0 AL UG 25.97 1.33 24.37 51.68 2 ACSR OH 7.30 5.27 66.47 79.03 2 AL UG 2.68 0.85 9.11 12.64 2/0 ACSR OH 30.31 0.00 1.10 31.41 2/0 AL UG 0.77 0.00 0.39 1.16 2/0 CU UG 0.00 0.00 0.25 0.25 336 ACSR OH 1.29 0.00 0.00 1.29 397 AAC OH 13.77 0.00 0.00 13.77 4 CU OH 0.00 0.63 0.00 0.63 4/0 AAC OH 0.41 0.00 0.00 0.41 4/0 ACSR OH 3.39 0.00 0.19 3.58 500 AL UG 19.88 0.00 0.09 19.97 750 AL UG 1.89 0.00 0.00 1.89 795 AAC OH 2.33 0.00 0.00 2.33 AL Bus OH 0.68 0.00 0.01 0.69 CU Bus OH 1.09 0.04 0.37 1.50 UNK SEC OH 0.00 0.00 0.05 0.05 UNK SEC UG 0.00 0.00 0.25 0.25 Totals 113.16 8.13 102.64 223.93 Summary for the TDPUD Area Page 1 of 1 Substation Conductor Type Three Phase Two Phase Single Phase Total Table 5-5-3 Truckee Donner PUD - Total Line Miles 1-Donner Lake 1/0 ACSR OH 0.17 0.00 0.00 0.17 1/0 AL UG 2.56 0.00 2.17 4.72 2 ACSR OH 0.94 0.59 17.44 18.97 2 AL UG 0.34 0.07 2.16 2.57 2/0 ACSR OH 10.24 0.00 0.05 10.29 397 AAC OH 2.43 0.00 0.00 2.43 4/0 AAC OH 0.20 0.00 0.00 0.20 4/0 ACSR OH 0.57 0.00 0.00 0.57 500 AL UG 1.04 0.00 0.00 1.04 750 AL UG 0.09 0.00 0.00 0.09 795 AAC OH 2.33 0.00 0.00 2.33 AL Bus OH 0.11 0.00 0.00 0.11 CU Bus OH 0.02 0.00 0.01 0.03 Summary for 1-Donner Lake Totals 21.04 0.66 21.83 43.53 2-Tahoe Donner 1/0 AL UG 1.47 0.00 1.89 3.36 2 ACSR OH 0.40 0.42 26.12 26.94 2 AL UG 0.23 0.00 0.69 0.92 2/0 ACSR OH 12.17 0.00 0.05 12.22 2/0 AL UG 0.00 0.00 0.03 0.03 397 AAC OH 0.63 0.00 0.00 0.63 500 AL UG 0.09 0.00 0.00 0.09 750 AL UG 0.43 0.00 0.00 0.43 AL Bus OH 0.10 0.00 0.00 0.10 CU Bus OH 0.00 0.00 0.03 0.04 Summary for 2-Tahoe Donner Totals 15.53 0.42 28.81 44.76 Page 1 of 3 Substation Conductor Type Three Phase Two Phase Single Phase Total Table 5-5-3 Truckee Donner PUD - Total Line Miles 3-Truckee 1/0 ACSR OH 1.22 0.00 0.00 1.22 1/0 AL UG 16.59 0.00 16.34 32.93 2 ACSR OH 2.11 0.72 15.54 18.36 2 AL UG 0.98 0.00 3.73 4.71 2/0 ACSR OH 3.21 0.00 0.83 4.03 2/0 AL UG 0.08 0.00 0.34 0.42 2/0 CU UG 0.00 0.00 0.11 0.11 336 ACSR OH 1.29 0.00 0.00 1.29 397 AAC OH 6.10 0.00 0.00 6.10 4/0 ACSR OH 0.09 0.00 0.05 0.14 500 AL UG 15.28 0.00 0.04 15.32 750 AL UG 0.13 0.00 0.00 0.13 AL Bus OH 0.35 0.00 0.00 0.35 CU Bus OH 0.58 0.00 0.26 0.84 UNK SEC OH 0.00 0.00 0.05 0.05 UNK SEC UG 0.00 0.00 0.25 0.25 Summary for 3-Truckee Totals 48.01 0.72 37.53 86.25 4-Martis Valley 1/0 AL UG 5.33 0.01 3.98 9.32 2 ACSR OH 0.89 0.03 7.37 8.29 2 AL UG 1.10 0.00 2.53 3.63 2/0 ACSR OH 4.70 0.00 0.17 4.87 2/0 AL UG 0.69 0.00 0.01 0.70 2/0 CU UG 0.00 0.00 0.15 0.15 397 AAC OH 4.60 0.00 0.00 4.60 4/0 AAC OH 0.21 0.00 0.00 0.21 4/0 ACSR OH 2.73 0.00 0.14 2.87 500 AL UG 3.47 0.00 0.05 3.52 750 AL UG 1.25 0.00 0.00 1.25 AL Bus OH 0.12 0.00 0.00 0.12 CU Bus OH 0.48 0.00 0.06 0.54 Summary for 4-Martis Valley Totals 25.55 0.03 14.47 40.05 Page 2 of 3 Substation Conductor Type Three Phase Two Phase Single Phase Total Table 5-5-3 Truckee Donner PUD - Total Line Miles 5-Glenshire 1/0 AL UG 0.02 1.33 0.00 1.35 2 ACSR OH 2.96 3.51 0.00 6.48 2 AL UG 0.04 0.79 0.00 0.82 4 CU OH 0.00 0.63 0.00 0.63 CU Bus OH 0.01 0.04 0.00 0.05 Summary for 5-Glenshire Totals 3.03 6.30 0.00 9.34 Totals 113.16 8.13 102.64 Summary for the TDPUD Area 223.93 Page 3 of 3 Conductor Type Three Phase Two Phase Single Phase Total Table 5-5-4 McKenzie Electric Cooperative - Total URD Line Miles 1/0 AL UG 25.97 1.33 24.37 51.68 2 AL UG 2.68 0.85 9.11 12.64 2/0 AL UG 0.77 0.00 0.39 1.16 2/0 CU UG 0.00 0.00 0.25 0.25 500 AL UG 19.88 0.00 0.09 19.97 750 AL UG 1.89 0.00 0.00 1.89 UNK SEC UG 0.00 0.00 0.25 0.25 Totals 51.20 2.19 34.46 87.85 Summary for the TDPUD Area Friday, July 19, 2019 Page 1 of 1 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 17 5.6 Historical Demand and Growth Patterns Present substation capacity and peak demand are shown in the Feeder Summary. The District provides distribution-level voltage through four (4) substations; Donner Lake, Martis Valley, Tahoe Donner and Truckee. Glenshire Service Area is served off of NV Energy’s existing 14.4 kV line and does not include a substation. Figure 5-6-1 shows the growth characteristics of the District’s entire system for the period 1991 through May 2019, as well as projected load growth through year 2035. Figures 5-6- 2 through 5-6-5 display information about past peak demand for each Substation between 2005 and 2019. Figure 5-6-1 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 18 Figure 5-6-2 Figure 5-6-3 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 19 Figure 5-6-4 Figure 5-6-5 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 20 Figure 5-6-6 During the historical 10 year period that was analyzed, the District has experienced minimum to little growth in peak demand based on substation peak data from 2004 to 2019. Since 2006, the average peak demand has plateaued on the District’s system. This can also be seen by the number of connections in Section 5.4. There was no available data between June 2008 and December 2008. As such, those values are averages of previous data and could slightly skew the results. Having developed a predictor of future average growth, it was then necessary to assign growth. All areas with potential new development were identified and a growth percentage was applied to these areas based on the type of development. Since there has been minimum growth on the system, the only new growth expected during this planning period is new commercial. Spot loads were added to the existing system to represent this growth. FEEDER SUMMARYkVAPFkVAPFkVAPFAmperesCustomersLosses kW LossesFeeder1-Donner LakePH0 YR4 YR5 YR0 YR4 YR5 YR0 YR4 YR5 YR0 YR 4 YR 5 YR1-Donner LakeA2019.5B2090.5C2361.6Total6455.192.697.894.995.42037.82121.92394.66537.091.297.093.594.22037.82121.92394.66537.091.297.093.594.248.350.056.548.750.757.348.750.757.37957048332332-369.1393.1-23.60.3-369.1393.1-23.60.3-369.1393.1-23.60.3-6.0%6.4%-0.4%0.0%-6.0%6.4%-0.4%0.0%-6.0%6.4%-0.4%0.0%---------DLR1A459.6B368.4C362.9Total1190.496.897.795.996.9459.6368.4362.91190.496.897.795.996.9459.6368.4362.91190.496.897.795.996.960.848.748.060.848.748.060.848.748.02021911665595.0-12.623.916.45.0-12.623.916.45.0-12.623.916.40.4%-1.1%2.1%1.4%0.4%-1.1%2.1%1.4%0.4%-1.1%2.1%1.4%---------DLR2A491.9B441.9C373.9Total1307.795.796.296.396.0491.9441.9373.91307.795.796.296.396.0491.9441.9373.91307.795.796.296.396.065.158.449.565.158.449.565.158.449.510021424455864.74.34.573.564.74.34.573.564.74.34.573.55.2%0.3%0.4%5.9%5.2%0.3%0.4%5.9%5.2%0.3%0.4%5.9%---------DLR3A1388.9B921.2C1645.5Total3954.994.195.694.494.61388.9921.21645.53954.994.195.694.494.61388.9921.21645.53954.994.195.694.494.6183.7121.9217.7183.7121.9217.7183.7121.9217.7493299423121550.625.061.5137.050.625.061.5137.050.625.061.5137.01.4%0.7%1.6%3.7%1.4%0.7%1.6%3.7%1.4%0.7%1.6%3.7%---------466422722722712307.0Total kW3882.0Total kVAR12904.795.312984.494.712984.494.71.8%1.8%1.8%Substation SummaryTransformer Size102.8103.5103.512307.04139.012307.04139.012/16 MVA 16000 55/65 °CMonday, August 26, 2019Page 1 of 6 FEEDER SUMMARYkVAPFkVAPFkVAPFAmperesCustomersLosses kW LossesFeeder2-Tahoe DonnerPH0 YR4 YR5 YR0 YR4 YR5 YR0 YR4 YR5 YR0 YR 4 YR 5 YR2-Tahoe DonnerA2906.3B2603.1C2578.5Total8074.696.093.597.695.92944.72626.82612.98170.594.892.196.894.72944.72626.82612.98170.594.892.196.894.769.562.261.670.462.862.570.462.862.5817921584232251.8-396.5344.90.351.8-396.5344.90.351.8-396.5344.90.30.7%-5.1%4.5%0.0%0.7%-5.1%4.5%0.0%0.7%-5.1%4.5%0.0%---------TDR1A536.6B402.6C296.0Total1235.294.894.994.994.9536.6402.6296.01235.294.894.994.994.9536.6402.6296.01235.294.894.994.994.971.053.239.171.053.239.171.053.239.1181151744067.65.83.416.87.65.83.416.87.65.83.416.80.6%0.5%0.3%1.4%0.6%0.5%0.3%1.4%0.6%0.5%0.3%1.4%---------TDR2A1012.5B1138.2C977.1Total3127.897.497.297.497.31012.51138.2977.13127.897.497.297.497.31012.51138.2977.13127.897.497.297.497.3134.0150.6129.3134.0150.6129.3134.0150.6129.330236726893744.345.540.5130.244.345.540.5130.244.345.540.5130.21.5%1.5%1.3%4.3%1.5%1.5%1.3%4.3%1.5%1.5%1.3%4.3%---------TDR3A1306.7B1405.1C1001.5Total3713.294.994.595.094.81306.71405.11001.53713.294.994.595.094.81306.71405.11001.53713.294.994.595.094.8172.8185.8132.5172.8185.8132.5172.8185.8132.533340224297737.435.819.993.137.435.819.993.137.435.819.993.11.1%1.0%0.6%2.6%1.1%1.0%0.6%2.6%1.1%1.0%0.6%2.6%---------464224024024015476.0Total kW4591.0Total kVAR16142.695.816235.695.316235.695.31.6%1.6%1.6%Substation SummaryTransformer Size128.6129.4129.415475.04911.015475.04911.0(3) 5/7 MVA 22500 55/65 °CMonday, August 26, 2019Page 2 of 6 FEEDER SUMMARYkVAPFkVAPFkVAPFAmperesCustomersLosses kW LossesFeeder3-TruckeePH0 YR4 YR5 YR0 YR4 YR5 YR0 YR4 YR5 YR0 YR 4 YR 5 YR3-TruckeeA3665.6B3546.6C3604.4Total10815.696.896.797.497.04646.04519.24586.613750.994.594.595.394.86057.85927.95997.317982.393.493.494.093.687.684.886.2111.1108.0109.7144.8141.7143.45906146081812-57.0-98.9156.80.9-58.0-101.1160.71.7-58.3-102.0162.42.1-0.5%-0.9%1.5%0.0%-0.4%-0.8%1.2%0.0%-0.3%-0.6%1.0%0.0%---------TR1A322.6B339.3C461.9Total1123.498.698.497.498.11063.51080.51204.73348.696.396.396.096.22177.52194.22318.06689.795.695.695.495.542.744.861.1140.8142.9159.3288.1290.3306.750471001975.14.95.115.110.29.910.030.115.214.714.544.30.5%0.4%0.5%1.4%0.3%0.3%0.3%0.9%0.2%0.2%0.2%0.7%---------TR2A451.2B200.9C216.6Total867.792.095.694.693.6451.2200.9216.6867.792.095.694.693.6451.2200.9216.6867.792.095.694.693.659.726.628.659.726.628.659.726.628.64223339827.430.5-5.252.727.430.5-5.252.727.430.5-5.252.73.4%3.8%-0.6%6.5%3.4%3.8%-0.6%6.5%3.4%3.8%-0.6%6.5%---------TR3A333.1B228.5C197.0Total758.496.497.297.596.9333.1228.5197.0758.496.497.297.596.9333.1228.5197.0758.496.497.297.596.944.130.226.044.130.226.044.130.226.07844321543.13.22.08.33.13.22.08.33.13.22.08.30.4%0.4%0.3%1.1%0.4%0.4%0.3%1.1%0.4%0.4%0.3%1.1%---------TR4A1483.1B1483.1C1582.6Total4548.897.097.196.997.01631.41631.61731.14994.096.896.996.796.81853.51853.61953.65660.796.696.796.596.6196.3196.2209.4215.9215.8229.0245.3245.3258.415514322352147.344.745.7137.848.746.047.0141.749.446.647.5143.51.1%1.0%1.0%3.1%1.0%1.0%1.0%2.9%0.9%0.9%0.9%2.6%---------TR5A770.6B1000.3C575.2Total2345.297.896.898.297.5770.61000.3575.22345.297.896.898.297.5770.61000.3574.22344.297.896.898.297.5101.9132.376.0101.9132.376.0101.9132.376.021330417469112.731.09.953.512.731.09.953.512.731.09.953.50.6%1.4%0.4%2.3%0.6%1.4%0.4%2.3%0.6%1.4%0.4%2.3%---------Monday, August 26, 2019Page 3 of 6 FEEDER SUMMARYkVAPFkVAPFkVAPFAmperesCustomersLosses kW LossesFeeder3-TruckeePH0 YR4 YR5 YR0 YR4 YR5 YR0 YR4 YR5 YR0 YR 4 YR 5 YRTR6A362.4B380.1C433.2Total1175.697.197.197.097.1362.4380.1433.21175.697.197.197.097.1362.4380.1433.21175.697.197.197.097.148.050.357.348.050.357.348.050.357.35253451508.05.58.421.98.05.58.421.98.05.58.421.90.7%0.5%0.7%1.9%0.7%0.5%0.7%1.9%0.7%0.5%0.7%1.9%---------362331029032620978.0Total kW5258.0Total kVAR21626.997.027219.295.735437.194.91.4%1.2%1.0%Substation SummaryTransformer Size172.3216.9282.426059.07862.033665.011066.0(3) 5/7 MVA 12500 55/65 °CMonday, August 26, 2019Page 4 of 6 FEEDER SUMMARYkVAPFkVAPFkVAPFAmperesCustomersLosses kW LossesFeeder4-Martis ValleyPH0 YR4 YR5 YR0 YR4 YR5 YR0 YR4 YR5 YR0 YR 4 YR 5 YR4-Martis ValleyA3030.6B2804.2C2848.4Total8678.199.799.5100.099.83667.73431.33477.510571.998.598.099.298.64615.84381.44418.813412.397.296.697.997.372.467.068.187.782.083.1110.4104.7105.6679946583220833.5-293.1260.00.334.8-297.7263.50.635.5-299.7265.00.80.4%-3.4%3.0%0.0%0.3%-2.9%2.5%0.0%0.3%-2.3%2.0%0.0%---------MVR1A278.2B341.7C353.1Total972.996.095.795.795.8278.2341.7353.1972.996.095.795.795.8278.2341.7353.1972.996.095.795.795.836.845.246.736.845.246.736.845.246.71832152156132.94.34.511.72.94.34.511.72.94.34.511.70.3%0.5%0.5%1.3%0.3%0.5%0.5%1.3%0.3%0.5%0.5%1.3%---------MVR2A767.2B954.7C752.0Total2474.095.395.195.295.2915.21102.7900.32918.295.295.095.195.11137.51325.01122.33584.895.094.995.095.0101.5126.399.5121.1145.9119.1150.5175.3148.52624552089259.311.79.330.313.816.113.142.916.518.815.450.70.4%0.5%0.4%1.3%0.5%0.6%0.5%1.5%0.5%0.6%0.5%1.5%---------MVR3A794.6B846.6C604.0Total2243.499.799.7-100.099.81112.51165.1918.13195.298.798.899.398.91593.01644.91397.64635.397.497.697.997.6105.1111.979.9147.2154.1121.5210.7217.6184.822821511355629.918.613.461.854.439.430.7124.570.353.342.7166.31.3%0.8%0.6%2.8%1.7%1.2%1.0%3.9%1.6%1.2%0.9%3.7%---------MVR4A1207.4B1020.2C974.5Total3193.6-99.5-97.2-96.5-98.11342.91147.21100.53584.0-99.9-98.7-98.2-99.21550.01347.31298.34191.1100.0-99.7-99.5-99.9159.7134.9128.9177.6151.8145.6205.1178.2171.766147114118.8104.446.0269.1123.7106.648.5278.9126.2107.949.8283.93.8%3.3%1.5%8.6%3.5%3.0%1.4%7.8%3.0%2.6%1.2%6.8%---------441645937351317321.0Total kW1085.0Total kVAR17354.998.621053.398.126624.497.42.2%2.2%2.0%Substation SummaryTransformer Size138.3167.8212.220846.02947.026094.05288.0(3) 5/6.25 MVA 18750 55/65 °CMonday, August 26, 2019Page 5 of 6 FEEDER SUMMARYkVAPFkVAPFkVAPFAmperesCustomersLosses kW LossesFeeder5-GlenshirePH0 YR4 YR5 YR0 YR4 YR5 YR0 YR4 YR5 YR0 YR 4 YR 5 YR5-GlenshireA359.1B467.0C551.4Total1356.889.799.891.895.4359.1467.0551.41356.889.799.891.895.4359.1467.0551.41356.889.799.891.895.441.153.563.141.153.563.141.153.563.11061481834370.00.00.00.00.00.00.00.00.00.00.00.00.0%0.0%0.0%0.0%0.0%0.0%0.0%0.0%0.0%0.0%0.0%0.0%---------GL1A359.1B467.0C551.4Total1356.889.799.891.895.4359.1467.0551.41356.889.799.891.895.4359.1467.0551.41356.889.799.891.895.441.153.563.141.153.563.141.153.563.1106148183437-59.7193.1-84.049.4-59.7193.1-84.049.4-59.7193.1-84.049.4-4.6%14.9%-6.5%3.8%-4.6%14.9%-6.5%3.8%-4.6%14.9%-6.5%3.8%---------8744949492588.0Total kW816.0Total kVAR2713.695.42713.695.42713.695.41.9%1.9%1.9%Substation SummaryTransformer Size103.6103.6103.62588.0816.02588.0816.0N/A N/A N/A °CMonday, August 26, 2019Page 6 of 6 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 21 5.7 System Load Factor Annual load factor is a percentage comparison of a system’s actual kWH purchased versus the kWH that the system would have purchased if the maximum annual kW demand were used continuously throughout the year. A high load factor is good for a utility because it means that the system’s equipment is being fully utilized. Annual variations in kWH usage are influenced by spring precipitation and by summer and winter temperatures. A mild winter and wet spring will cause a low load factor because electric residential heating is reduced. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 22 5.8 Reliability of Electric Service Outage data was provided for the last five years as shown in Table 5-8-1. Figures 5-8-1 through 5-8-4 describe outage data over the last five years. Figure 5-8-1 Figure 5-8-2 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 23 Figure 5-8-3 Figure 5-8-4 Outages Minutes Outages Minutes Outages Minutes Outages Minutes Outages Minutes Outages MinutesTransmission3 557811 25 6041127 13 1960323 371 15145056 2 2806463 26 4796384Weather10 243326 7 4162704 4 1956865 76 13726139 23 710830 38 1198754Animals7 142984 8 3363927 28 925218 26 2226219 5 420748 3 886476Switch Operation5 80075 45 1953122 18 868883 43 2041627 2 174478 6 640670Undetermined1 14040 7 580102 17 200957 65 1709586 16 78476 75 585405Human Cause3 7169 1 165207 2 2519 9 1511093 35 57045 15 427579Unknown2 5648 3 118208 0 0 9 307872 17 53646 15 249092Planned Outage3 6 2 105708 0 0 6 154373 1 32080 110 238045Equipment Failure0 0 5 200 0 0 23 75026 12 14460 12 32408Non-Outage0 0 0 0 0 0 1 12479 14 12893 35 31322Vegetation0 0 0 0 0 0 4 431 4 562 2 11177Foreign Interference0 0 0 0 0 0 0 0 1 0 0 0Totals34 1051059 103 16490305 82 5914765 633 36909901 132 4361681 337 9097312TDPUD Outage Data 2014-2019Table 5-8-12014 2015 2016 2017 2018 2019 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 24 5.9 Annual System Demand Demand is the number of kilowatts being used at an instantaneous point in time. Demand is averaged over 15-minute intervals. The District’s non-coincident peak demand in December 2015 was 38.1 MW. Peak demand is based on winter and summer peaks. Table 5-9-1 shows the individual substations and whether they are winter or summer peaking. Summer peaks usually consists of motor loads for irrigation or air conditioning units, while winter peaks occur due to an increase in electric heat. Donner Lake Substation’s peak loads do not have significant jumps between the winter and summer months. Summer peaking was chosen based on a slightly higher peak loading in 2013, but it is negligible and thus, either summer or winter peak loads could be used. Peak Demands Based on Season Table 5-9-1 Summer Peaking Winter Peaking Truckee Tahoe Donner Donner Lake Glenshire Martis Valley Truckee Donner Public Utility District 2019 Electric System Master Plan Section 5.0 5- 25 5.10 Status of Previous Master Plan Items Table 5-10-1 lists 2014 Electric System Master Plan Items with the project status and any additional remarks. Status of 2014 Electric System Master Plan Items Table 5-10-1 Substation Code Description Length (Miles) Current Status of Project Donner Lake DL-C1 Rebuild 3Æ 2/0 AWG ACSR with 3Æ 397 kcmil AAC .35 Carry-Over (LR) Donner Lake DL-C2 INSTALL S&C PMH-9, PAD-MTD SWGR, 15KV EQUIP 2 Carry-Over (LR) Donner Lake DL-C4 Rebuild 3Æ 2/0 AWG ACSR with 3Æ 397 kcmil AAC .77 Carry-Over (LR) Donner Lake DL-C5 Install 328 Amp, 250 kVA Equipment 3 Carry-Over (LR) Glenshire GL-01 Install Glenshire Autotransformer Equipment 1 Carry-Over (LR) Glenshire GL-02 Construct 3Æ 500 MCM 1.9 Completed Martis Valley MV-C1 Rebuild 3Æ 350 EPR with 3Æ 750 EPR .014 Completed Martis Valley MV-C2 Rebuild 3Æ 350 EPR with 3Æ 500 MCM .34 Completed Tahoe Donner TD-01 Construct 3Æ 397 kcmil AAC .89 Completed Tahoe Donner TD-03 Construct 3Æ 397 kcmil AAC .65 Completed Tahoe Donner TD-C1 Rebuild 3Æ 500 EPR with 3Æ 750 EPR .12 Completed Tahoe Donner TD-C2 Rebuild 3Æ 4/0 AWG ACSR with 3Æ 397 kcmil AAC .8 Carry-Over (LR) Tahoe Donner TD-C3 Rebuild 3Æ 4/0 AWG ACSR with 3Æ 397 kcmil AAC .86 Carry-Over (LR) Truckee TR-C1 Rebuild 3Æ 2 AWG ACSR with 3Æ 4/0 AWG ACSR .33 Carry-Over (LR) Truckee TR-C2 Rebuild 3Æ 4/0 AWG ACSR with 3Æ 397 kcmil AAC .59 Carry-Over (LR) Truckee TR-C3 Rebuild 3Æ 350 Al EPR with 3Æ 750 MCM .15 Carry-Over (LR) Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-1 6.0 CONSTRUCTION RECOMMENDATIONS This section discusses the analysis of the existing distribution system by substation, projected loading on the existing system, and substation changes and distribution system improvements required over the next 15 years. MilsoftTM reports showing results of the regulated load flows for the existing system and projected 5, 10 and 15-year system are included in each section. Voltage drop, loading and capacity, power factor, losses, conditions of plant, and service reliability are discussed for the present system with existing and projected loading. These results can also be found on the accompanying flash drive, along with the system model. a. Loading and Capacity This section details the substation, number of transformers, service bays, etc. Any equipment overloading is listed in this section b. Mechanical Condition of Plant This section details each service area’s unique electrical performance and characteristics. c. System Analysis This section provides individual feeder information and recommended projects in order to improve the feeder to planning criteria. Also included are the total costs for the recommended projects. d. Contingency System Planning This section of the report provides various summaries to show system performance with the loss of a single substation transformer and various feeder contingencies. Several of the reports utilized for the normal system may be reproduced for the system contingency. e. Sectionalizing Recommendations This section of the report provides various summaries to show system performance with the loss of a single substation transformer and various feeder contingencies. Several of the reports utilized for the normal system may be reproduced for the system contingency. The table below summarizes the two main types of hydraulic reclosers (Type E and H) on the District’s system and the recommended Kearney T fuse sizes to be placed downline from the reclosers. In the case of a maximum three-phase bolted fault, a fuse may melt even if it is classified in the fuse-saving column. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-2 Size Type Fuse Saving Non- Fuse Saving Type Fuse Saving Non- Fuse Saving E T T H T T 50 2A2B 15 6 2A2B 15 6 2A2C 25 6 2A2C 20 6 35 2A2B 12 3 2A2B 12 3 2A2C 15 3 2A2C 15 3 25 2A2B 8 3 2A2B 8 3 2A2C 12 3 2A2C 12 3 15 2A2B 6 N/A 2A2B 6 N/A 2A2C 8 N/A 2A2C 8 N/A 10 2A2B 3 N/A 2A2B 3 N/A 2A2C 6 N/A 2A2C 3 N/A 5 2A2B 3 N/A 2A2B 3 N/A 2A2C 3 N/A 2A2C 3 N/A Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-3 6.1 DONNER LAKE SERVICE AREA The Donner Lake Service Area has a projected growth rate of 0.85%1, with losses compounded annually for the plan period. This service area serves consumers in the western area of TDPUD’s system, which includes consumers to the west and south of Donner Lake, with service to approximately 3,619 customers and a total load of 7.9 MW. There are existing 3-phase ties between TD-1 and DL-3, TR-4 and DL-1 and MV-3 and DL-1. a. Loading and Capacity Donner Lake Substation has two (2) three-phase 12/16/20 MVA 60/12.47 kV transformers, three (3) distribution bays in service and 667 kVA, 875 amp regulators. One transformer is currently a spare. The substation transformer loading is at 50.4% with 15-year loads. b. Mechanical Condition of Plant There are no deficiencies noted for Donner Lake Service Area. c. System Analysis i. DL-1 CIRCUIT Feeder DL-1 serves the area to the east of the Donner Lake Substation, where it then wraps around Donner Lake to tie to Feeder DL-2. There is approximately 1.7 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. ii. DL-2 CIRCUIT Feeder DL-2 serves the area to the south of the Donner Lake Substation, where it serves the customers to the west and south side of Donner Lake. There is approximately 1.7 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. iii. DL-3 CIRCUIT Feeder DL-3 extends to the north of the Donner Lake Substation, and serves as a tie point to Tahoe Donner Substation’s Feeder TD-1. There is approximately 4.5 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. 1 Load growth was calculated from 02/2016 to present due to skewed results when including 2015 historical values, during which a load transfer from TD-1 occurred. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-4 Project DL-01 This portion of the line has over 30 amps on a single phase. It is recommended to rebuild approximately 0.46 miles of single-phase 2 AWG ACSR with three-phase 2 AWG ACSR. This line starts west of the intersection of Northwoods Blvd and Davos Drive, where it follows Skislope Way north. Estimated Cost: $ 117,300 Project DL-02 This portion of the line has over 36 amps on a single phase. It is recommended to rebuild approximately 0.1 miles of single-phase 2 AWG ACSR with three-phase 2 AWG ACSR from the R30 recloser to the west intersection of Hillside Dr. and Gyrfalcon St. and upgrade the R30 recloser to three single-phase reclosers. Estimated Cost: $ 25,000 d. Phase Balancing Projects · Move OHP_3806 from A-phase to B-phase · Move OHP_73472 from C-phase to B-phase e. Contingency Options In the event of the loss of a substation transformer, the following devices are recommended to be switched: Close switch A59 Close switch A36 Close recloser R-10 Portions of Martis Valley Feeder 3 are overloaded at 15-year peak loading levels including OHP_4321-S1958 to OHP_4321-S1100, OHP_81233 to OHP_81887- S6936 and OHP_21923-S2589 to OHP_21923. Minimum Voltages On Donner Lake Service Area During Contingency Existing 5-year 15-year A 111.9 110.4 108.0 B 112.8 111.3 109.1 C 113.4 112.0 109.9 Tahoe Donner Transformer Loading 59.3% 59.3% 59.3% Tahoe Donner Regulator Loading 65.9% 65.9% 65.9% Martis Valley Transformer Loading 62.0% 71.7% 86.4% Martis Valley Regulator Loading 61.5% 71.1% 85.7% Table 6.1-1 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-5 i. DL-1 Feeder DL-1 has one (1) tie to Martis Valley MV-3 feeder (recloser 169.451/switch 166.1675) and a 2-phase tie to Truckee TR-4 feeder as well as a tie to DL- 2. Instead of feeding from Truckee or Martis Valley substations, it is recommended to tie DL-1 to Tahoe Donner Substation. This substation is the closest to the tie point. There is low voltage of 111.7V on DL-1 along the north side of Donner Lake at 15-year peak loading levels. Project DL-C1 It is recommended to rebuild approximately 0.35 miles of 2/0 AWG ACSR with 397 kcmil AAC. This will improve voltage at the end of the line during load transfer and improve conductor loading. This line starts west of the intersection of Northwoods Blvd and Donner Pass Road, where it follows Donner Pass Road for approximately 690 feet before turning south to Deerfield Drive. Estimated Cost: $ 99,000 ii. DL-2 Feeder DL-2 has no existing ties to any adjacent substations. It has two (2) ties to DL-1. In order to transfer the entire feeder to DL-1, it is possible to close either of the existing switches or as recommended below, a new tie could be built between DL-3 and DL-2 at the substation. There is low voltage of 112.0V on DL-2 along the west side of Donner Lake at existing peak loading levels and low voltage of 108.0V at 15-year peak loading levels. Project DL-C2 This substation has URD feeder getaways. It is recommended that switches be installed to tie feeders DL-2 and DL-3 together. Two switchgear units, such as S&C 330, could be installed with a URD cable connecting the switchgear using one bay in each to tie the feeders together. Estimated Cost: $ 75,000 Project DL-C4 It is recommended to rebuild approximately 0.77 miles of existing 2/0 AWG ACSR to 397 kcmil AAC between the intersection of Donner Pass Road and Donner Lake Rd to the intersection of S Shore Dr and Maple St. This will improve voltage to the end of the line. Estimated Cost: $ 218,000 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-6 Project DL-C5 It is recommended to install a bank of 328 amp, 250 kVA regulators near the Crossroads Shopping Center. Estimated Cost: $ 60,000 Project DL-C6 It is recommended to rebuild approximately 0.8 miles of existing 2/0 AWG ACSR to 397 kcmil AAC from S108 to A59. This line is loaded to 140% with existing loading levels when Tahoe Donner is transferred to Donner Lake. Estimated Cost: $ 223,000 iii. DL-3 Feeder DL-3 has one (1) tie to Tahoe Donner TD-1 feeder (switch A-59). There is no low voltage or conductor overloading during load transfer with existing or future loads. f. Sectionalizing Recommendations Donner Lake Substation has one (1) 12/16 MVA 60-7.2/12.47 kV distribution transformer, with SEL-587 relays for differential protection. The following recommendations are made for the Donner Lake Substation: a) Substation relay protection New relay settings are shown at the end of this section. It is recommended to disable all negative sequence protection settings, and disable all EM Reset settings. b) Feeder Recloser New relay settings are shown at the end of this section. Voltage Highside Protection Transformer Size % Impedance Donner Lake 60 kV SEL-587 (1) 12/16 MVA 7.80 The following table shows the fault location impedances for the existing electronic reclosers existing on Donner Lake Substation. These impedance values are used on the Form 6’s to locate faults on the line by calculating the approximate distance from the recloser based on impedance data from the fault. Though these will not give exact locations of the fault, it will help to narrow down certain areas the fault may have occurred, making it easier for fault locating. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-7 Substation Recloser R X R0 X0 Miles Donner Lake DL-1 0.94 2.98 2.22 5.29 2.86 DL-2 1.61 2.89 2.85 5.20 2.25 DL-3 0.35 2.70 0.68 4.64 2.35 Due to Donner Lake Substation being rebuilt, new settings will be provided by ECI. Any recommendations provided herein for Donner Lake Substation are temporary settings until the completion of the rebuild. The following equipment is recommended for removal or installation on Donner Lake Substation: i. DL-1 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 8.9 miles of primary line on this circuit, with a majority of the line being overhead conductor. There are fuses protecting branch circuits on this feeder and an open recloser between DL-1 and MV- 3. The following recommendations are made for this feeder: a. Feeder Recloser It is recommended to disable the high-current trip settings and change the phase and ground fast curves. Refer to the settings sheet at the end of the section. ii. DL-2 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 8.15 miles of primary line on this circuit, with a majority of the line being overhead conductor. There are fuses protecting branch circuits on this feeder. a. Feeder Recloser It is recommended to disable the high-current trip settings and increase pickup settings. Refer to the settings sheet at the end of the section. iii. DL-3 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 26.43 miles of primary line on this circuit, with a majority of the line being overhead conductor. This feeder serves primarily as a tie point to Tahoe Donner TD-1 Feeder. The district has recently installed two SPEAR reclosing units on this feeder. a. Feeder Recloser It is recommended to change the phase and ground fast curves. Refer to the settings sheet at the end of the section. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-8 b. Recloser 1R20 It is recommended to replace this recloser with a Spear recloser with Cooper Form 6 control. Estimated Cost: $ 15,000 c. Recloser 1R30 It is recommended to replace this recloser with a Spear recloser with Cooper Form 6 control. Estimated Cost: $ 15,000 Donner Lake Substation Fuse Size T Device No. Fuse Saving Non Fuse Saving DL-1 Recloser 50 12 DL-2 Recloser 50 12 DL-3 Recloser 50 12 R10 Recloser 40 8 R20 Recloser 25 8 R30 Recloser 25 8 R50 Recloser 25 8 R65 Alder Recloser 40 8 R90 Recloser 30 10 Current in Amperes1,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 179 Minimum Fault 744 A PU U4-US Ext Inv 1488 A PU U4-US Ext Inv 592 A PU U4-US Ext Inv 124 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 200 A PU U4-US Ext Inv 5743 Three Phase Fault TDPUD 2019 Master Plan 10/21/2019 Donner Lake Coordination 7.2 kV Current in Amperes1001,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 6113 Phase-Ground Fault 179 Minimum Fault 744 A PU U4-US Ext Inv 592 A PU U4-US Ext Inv 1488 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 124 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 200 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 Donner Lake Coordination 7.2 kV Current in Amperes1,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 179 Minimum Fault 4973 Phase-Phase Fault 744 A PU U4-US Ext Inv 592 A PU U4-US Ext Inv 1488 A PU U4-US Ext Inv 124 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 200 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 Donner Lake Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 100 1,000 170 A Amp: Curve--140 330 A Amp: Curve--117 330 A Amp: Curve--103 170 A Amp: Curve--104 1135 R30 Phase-Ground Fault 169 Minimum Fault 130 A Amp: Curve--117 130 A Amp: Curve--106 TDPUD 2019 Master Plan 10/21/2019 DL-3 Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 100 1,000 330 A Amp: Curve--103 170 A Amp: Curve--104 330 A Amp: Curve--117 170 A Amp: Curve--140 170 Minimum Fault 1669 R90 Three Phase Fault 100 A Amp: Curve--106 100 A Amp: Curve--117 140 A Amp: Curve--104 140 A Amp: Curve--135 250 A Amp: Curve--117 995 R50 Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 DL-3 Coordination 7.2 kV Current in Amperes100 1,00010,000Time In Seconds.01 .1 1 10 100 1,000 330 A Amp: Curve--103 170 A Amp: Curve--140 330 A Amp: Curve--117 170 A Amp: Curve--104 1679 R65 Three Phase Fault 170 Minimum Fault 140 A Amp: Curve--104 250 A Amp: Curve--101 140 A Amp: Curve--135 250 A Amp: Curve--117 TDPUD 2019 Master Plan 10/21/2019 DL-3 Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.01 .1 1 10 100 1,000 10,000 330 A Amp: Curve--103 330 A Amp: Curve--117 170 A Amp: Curve--140 170 A Amp: Curve--104 179 Minimum Fault 6113 Phase-Ground Fault 1488 A PU U4-US Ext Inv 592 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 200 A PU U4-US Ext Inv 744 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 124 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 Donner Lake Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 100 1,000 330 A Amp: Curve--117 170 A Amp: Curve--140 330 A Amp: Curve--101 170 A Amp: Curve--106 1771 R20 Phase-Ground Fault 175 Minimum Fault 130 A Amp: Curve--117 130 A Amp: Curve--106 TDPUD 2019 Master Plan 10/21/2019 DL-3 Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 173 Minimum Fault 100 A Amp: Curve--135 160 A Amp: Curve--101 100 A Amp: Curve--106 160 A Amp: Curve--117 330 A Amp: Curve--103 170 A Amp: Curve--105 170 A Amp: Curve--135 330 A Amp: Curve--117 2305 R10 Three Phase Fault TDPUD 2019 Master Plan 10/21/2019 DL-1 Coordination - R10 Alt 1 7.2 kV Current in Amperes101001,00010,000100,0001,000,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 6113 Phase-Ground Fault 179 Minimum Fault 744 A PU U4-US Ext Inv 170 A Amp: Curve--105 330 A Amp: Curve--103 170 A Amp: Curve--135 330 A Amp: Curve--117 592 A PU U4-US Ext Inv 1488 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 124 A PU U4-US Ext Inv 200 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 DL-1 Upline Coordination 7.2 kV Current in Amperes101001,00010,000100,0001,000,000Time In Seconds.01 .1 1 10 100 1,000 10,000 179 Minimum Fault 6113 Phase-Ground Fault 744 A PU U4-US Ext Inv 170 A Amp: Curve--106 330 A Amp: Curve--101 330 A Amp: Curve--117 170 A Amp: Curve--135 592 A PU U4-US Ext Inv 1488 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 124 A PU U4-US Ext Inv 308 A PU U4-US Ext Inv 200 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 DL-2 Upline Coordination 7.2 kV Current in Amperes101001,00010,000Time In Seconds.01 .1 1 10 100 1,000 40 -Total Clear 5348 40T Three Phase Fault 178 Minimum Fault 170 A Amp: Curve--135 330 A Amp: Curve--117 330 A Amp: Curve--101 170 A Amp: Curve--106 TDPUD 2019 Master Plan 10/21/2019 DL-2 Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 100 1,000 170 A Amp: Curve--140 330 A Amp: Curve--117 330 A Amp: Curve--103 170 A Amp: Curve--104 169 Minimum Fault 1771 R20 Phase-Ground Fault 130 A Amp: Curve--117 130 A Amp: Curve--106 TDPUD 2019 Master Plan 10/21/2019 DL-3 Coordination 7.2 kV Substation Donner Lake Feeder DL-1 Location Device Form 5 Exis Rec Exis Rec Min Trip Phase 330 Min Trip Ground 170 TCC1P 101 103 TCC2P 117 TCC3P -- TCC4P -- TCC1G 106 105 TCC2G 135 TCC3G TCC4G Oper to LO Phase 4 Oper on TCC1 Phase 2 Oper to LO Gnd 3 4 Oper on TCC1 Gnd 2 2 TCC1P Mult 1 TCC1P Adder 0 0.04 TCC1G Mult 1 TCC1G Adder 0 0.04 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase (ON/OFF) On Off High-Current Trip Ground (ON/OFF) On Off High-Current Trip Phase (Trip)15 High-Current Trip Ground (Trip)8.3 High-Current Trip Phase (Trip No.) High-Current Trip Ground (Trip No.) High-Current Lockout Phase (ON/OFF)Off High-Current Lockout Ground (ON/OFF)Off High-Current Lockout Phase (Trip)4780 High-Current Lockout Ground (Trip)1620 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Substation Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Donner Lake Substation Feeder DL-2 Location Substation Device Form 5 Exis Rec Exis Rec Min Trip Phase 280 330 Min Trip Ground 180 170 TCC1P 101 TCC2P 117 TCC3P -- TCC4P -- TCC1G 106 TCC2G 135 TCC3G TCC4G Oper to LO Phase 2 Oper on TCC1 Phase 1 Oper to LO Gnd 2 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase (ON/OFF) On Off High-Current Trip Ground (ON/OFF) On Off High-Current Trip Phase (Trip)14.3 High-Current Trip Ground (Trip)8.33 High-Current Trip Phase (Trip No.)1 High-Current Trip Ground (Trip No.)1 High-Current Lockout Phase (ON/OFF)Off High-Current Lockout Ground (ON/OFF)Off High-Current Lockout Phase (Trip) High-Current Lockout Ground (Trip) High-Current Lockout Phase (Trip No.) High-Current Lockout Ground (Trip No.) Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Donner Lake Substation Feeder DL-3 Location Substation Device Form 6 Primary Alternate 1 Exis Rec Exis Rec Min Trip Phase 330 Min Trip Ground 170 TCC1P 101 103 TCC2P 117 TCC3P -- TCC4P -- TCC1G 106 104 TCC2G 140 TCC3G TCC4G Oper to LO Phase 2 Oper on TCC1 Phase 1 Oper to LO Gnd 2 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0.03 0.04 TCC1G Mult 1 TCC1G Adder 0.03 0.05 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase (ON/OFF) Off High-Current Trip Ground (ON/OFF) Off High-Current Trip Phase (Trip) High-Current Trip Ground (Trip) High-Current Trip Phase (Trip No.) High-Current Trip Ground (Trip No.) High-Current Lockout Phase (ON/OFF)Off High-Current Lockout Ground (ON/OFF)Off High-Current Lockout Phase (Trip) High-Current Lockout Ground (Trip) High-Current Lockout Phase (Trip No.) High-Current Lockout Ground (Trip No.) Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Donner Lake Feeder Substation High Side Location Device SEL-551 Primary Exis Rec CTR 40 CTRN 40 50P1P 38.5 OFF 51P1P 7.7 51P1C U4 51P1TD 4 50N1P OFF 51N1P 5 51N1C U4 51N1TD 11 50G1P 31 OFF 51G1P 3.1 51G1C U4 51G1TD 6.6 50Q1P OFF 51Q1P 4.2 OFF 51Q1C U4 51Q1TD 6.6 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Donner Lake Feeder Substation High Side Location Device SEL-587 MVA VWDG1 VWDG2 CTR1 CTR2 TAP1 TAP2 50P1P 50P1D 50P1H 51P1P 51P1C 51P1TD 50Q1P 50Q1D 5 51Q1P 4.2 OFF 51Q1C U4 51Q1TD 6.6 50N1P OFF 31 50N1D 16000 6 50N1H 31 OFF 51N1P 3.1 51N1C U4 51N1TD 5 50P2P 5.1 31.3 50P2D 10800 6 50P2H 31.3 OFF 51P2P 9.3 51P2C U4 51P2TD 4 50Q2P OFF 50Q2D 16000 51Q2P 5.1 OFF 51Q2C U4 51Q2TD 4 50N2P OFF 50N2D 5 50N2H OFF 51N2P 3.7 51N2C U4 51N2TD 5 4 OFF 38.5 OFF 7.7 U4 4.63 4.2 38.5 10800 6 40 160 3.85 16 60 12.47 Primary Exis Rec Substation Feeder 3 Location R20 Device Cooper SPEAR Exis Rec Min Trip 130 TCC1 106 TCC2 117 TTL 4 Oper #1 TCC1 Oper #2 TCC1 Oper #3 TCC2 Oper #4 TCC2 TCC1 Mult 1 TCC1 Adder 0 TCC1 Min Response Time DISABLE TCC1 HCT DISABLE TCC1 HCT Time Delay DISABLE TCC2 Mult 1 TCC2 Adder 0.04 TCC2 Min Response Time DISABLE TCC2 HCT DISABLE TCC2 HCT Time Delay DISABLE Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Donner Lake Primary Substation Feeder 3 Location R30 Device Cooper SPEAR Exis Rec Min Trip 130 TCC1 106 TCC2 117 TTL 4 Oper #1 TCC1 Oper #2 TCC1 Oper #3 TCC2 Oper #4 TCC2 TCC1 Mult 1 TCC1 Adder 0 TCC1 Min Response Time DISABLE TCC1 HCT DISABLE TCC1 HCT Time Delay DISABLE TCC2 Mult 1 TCC2 Adder 0.04 TCC2 Min Response Time DISABLE TCC2 HCT DISABLE TCC2 HCT Time Delay DISABLE Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Donner Lake Primary Substation Feeder 3 Location R65 Alder Device Cooper Form 4 Primary Exis Rec Min Trip Phase 250 Min Trip Ground 140 TCC1P 101 TCC1G 104 TCC2P 117 TCC2G 135 Oper to LO Phase 4 Oper on TCC1 Phase 2 Oper to LO Gnd 4 Oper on TCC1 Gnd 2 TCC1P Mult TCC1P Adder 0.02 TCC1G Mult TCC1G Adder 0.02 TCC2P Mult TCC2P Adder TCC2G Mult TCC2G Adder Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Donner Lake Substation Feeder 3 Location R90 Device Cooper Form 4 Primary Exis Rec Min Trip Phase 250 Min Trip Ground 140 TCC1P 101 TCC1G 104 TCC2P 117 TCC2G 135 Oper to LO Phase 4 Oper on TCC1 Phase 2 Oper to LO Gnd 4 Oper on TCC1 Gnd 2 TCC1P Mult TCC1P Adder 0.02 TCC1G Mult TCC1G Adder 0.02 TCC2P Mult TCC2P Adder TCC2G Mult TCC2G Adder Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Donner Lake Substation Feeder 3 Location R50 Device Cooper SPEAR Primary Exis Rec Min Trip 100 TCC1 106 TCC2 117 TTL 4 Oper #1 TCC1 Oper #2 TCC1 Oper #3 TCC2 Oper #4 TCC2 TCC1 Mult 1 TCC1 Adder 0 TCC1 Min Response Time DISABLE TCC1 HCT DISABLE TCC1 HCT Time Delay DISABLE TCC2 Mult 1 TCC2 Adder 0.04 TCC2 Min Response Time DISABLE TCC2 HCT DISABLE TCC2 HCT Time Delay DISABLE Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Donner Lake Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-9 6.1 GLENSHIRE SERVICE AREA The District takes service from NV Energy’s 14.4 kV line to serve the Glenshire service area. The Glenshire Service Area has a projected growth rate of 1.78%, with losses compounded annually for the plan period. It is located on the far eastern portion of the District’s service territory with service to approximately 485 customers and a total load of 1.3 MW. a. Loading and Capacity Glenshire Service Area takes power from NV Energy’s existing 14.4 kV line. b. Mechanical Condition of Plant There is approximately 0.63 miles of 4 HdCu, which makes up 6.7% of Glenshire Service Area. c. System Analysis i. GL-1 CIRCUIT Feeder GL-1 serves the area to the east and south of the primary meter. There is approximately 1.3 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. Project GL-01 Within the planning period, TDPUD would like to engineer and then install a new autotransformer where they are metered off NV Energy’s existing line in order to create a three-phase tie with TR-1. Estimated Cost: $ 850,000 d. Contingency Options There are no contingency options for Glenshire service area. It is recommended to install a step-up transformer on Truckee Feeder 1 in order to tie Glenshire to Truckee. Table 6.2-1 the results of adding a step transformer. Minimum Voltages On Glenshire Service Area During Contingency Existing 5-year 15-year A 121.4 121.2 121.0 B 122.4 122.3 122.1 C 119.6 119.5 119.4 Truckee Transformer Loading 56.6% 69.3% 88.6% Truckee Regulator Loading 62.9% 76.9% 98.4% Table 6.2-1 *NC=did not converge Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-10 e. Sectionalizing Recommendations The following table shows the fault location impedances for the electronic reclosers located at the meter point. These impedance values are used on the Form 6’s to locate faults on the line by calculating the approximate distance from the recloser based on impedance data from the fault. Though these will not give exact locations of the fault, it will help to narrow down certain areas the fault may have occurred, making it easier for fault locating. Substation Recloser R X R0 X0 Miles Glenshire GL-1 1.69 1.05 2.54 2.89 1.20 SPPC 0.11 0.07 0.16 0.16 0.18 i. GL-1 Feeder This feeder is protected by a WE recloser with Cooper Form 6 control. There are approximately 9.34 miles of primary line on this circuit, with a majority of the line being overhead conductor. There are no recommendations made for this feeder. ii. GL-1 SPPC Feeder This feeder is protected by a WVE recloser with Cooper Form 6 control. There are approximately 410 feet of line on this circuit, with a majority of the line being overhead conductor. There are no recommendations made for this feeder. Glenshire Service Area Fuse Size T Device No. Fuse Saving Non Fuse Saving GL-1 Recloser 65 8 SPPC GL-1 Recloser 65 8 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-11 6.2 MARTIS VALLEY SERVICE AREA The Martis Valley Service Area has a projected growth rate of 2.21%2, with losses compounded annually for the plan period. This service area serves rural and urban residential, commercial and industrial consumers in the southern portion of TDPUD’s service area. This substation serves approximately 2,526 customers with a total load of 8.7 MW. There is an existing 3-phase tie between TR-1 and MV-4, two separate ties between TR-2 and MV-3, two between TR-3 and MV-3, one between TR-4 and MV-3 and one between DL-1 and MV-3. a. Loading and Capacity Martis Valley Substation has three (3) 5/6.25 MVA 120/13.2 kV transformers and four (4) distribution bays in service with no spares. A set of 667 kVA, 875 amp regulators follow the transformer. The substation transformer loading is at 96.2% with 15-year loads. b. Mechanical Condition of Plant There are no deficiencies noted for Martis Valley Service Area. c. System Analysis Project MV-01 Within the planning period, TDPUD would like to engineer and then install a new circuit switcher at the Martis Valley substation. Estimated Cost: $250,000 i. MV-1 CIRCUIT Feeder MV-1 serves the area to the southwest of the Martis Valley Substation. There is approximately 930 kW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. ii. MV-2 CIRCUIT Feeder MV-2 serves the area to the south and southeast of the Martis Valley Substation. There is approximately 2.4 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. iii. MV-3 CIRCUIT Feeder MV-3 serves the area to the west of the Martis Valley Substation. There is approximately 2.2 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. iv. MV-4 CIRCUIT Feeder MV-4 serves the area to the east of the Martis Valley Substation. 2 Load growth was calculated from 01/2014 to present due to skewed results when including earlier historical values. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-12 There is approximately 3.1 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. d. Contingency In the event of the loss of a substation transformer, the following devices are recommended to be switched: Close switch A19 Close switch A7 Close switch PMS22-2 Close switch A18 Close switch PMS7-2 Minimum Voltages On Martis Valley Service Area During Contingency Existing 5-year 15-year A 122.3 122.3 122.3 B 122.5 122.5 122.5 C 122.7 122.7 122.7 Truckee Transformer Loading 89.9% 111.9% 146.1% Truckee Regulator Loading 99.9% 124.4% 162.4% Table 6.3-1 *NC=did not converge There is conductor overloading with 15 year loads and transformer overloading of 111.9% with 5 year loads, which increases to 146.1% with 15 year loads. There is no low voltage during the planning period. Project MV-C3 It is recommended to upgrade the existing set of three (3) single-phase 5 MVA transformers at the Martis Valley substation to three (3) single-phase 7.5 MVA transformers in order to maintain capacity at 15-year loading when transferring load from Truckee to Martis Valley. Alternatively, portions of Martis Valley could be transferred to Donner Lake or Truckee substations. The following additional switching would keep Truckee transformer loading below 100% at 15-year peak loading when transferring Truckee to Martis Valley: Close switch S106 Open switch S136 Estimated Cost: $ 950,000 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-13 Project MV-C6 There is conductor overloading during 5-year and 15-year loading levels when transferring Donner Lake to Martis Valley. The conductor is loaded at 104.7% with 15-year loading levels. It is recommended to rebuild approximately 0.2 miles of 2/0 AWG ACSR with 397 kcmil AAC. This line begins west of the Deerfield Road and Highway 89 intersection and ends south of the Crossroads Shopping Center. This project should occur within 5 year loading levels. Estimated Cost: $ 57,000 Project MV-C7 It is recommended to rebuild approximately 0.08 miles of existing 500 kcmil to 750 kcmil between PMS30-1 and the substation and also between PMS30-2 and the riser. This line is loaded to 52.8% with existing loading levels and is at 113.6% with 15 year loading levels when Truckee is transferred to Martis Valley. Estimated Cost: $ 73,000 MV-1 Feeder MV-1 has two (2) ties to MV-2, but no ties to adjacent substation feeders. As such, in order for total substation transfer, MV-1 will have to tie directly to MV-2, which will then tie to several more feeders. See the contingency for MV-4 for a full analysis. MV-2 Feeder MV-2 has two (2) ties to MV-1 and one additional tie to MV-4. There are no ties to any adjacent substation feeders from MV-2. In order to serve the load from a different substation, it will have to be served from MV-4, which will then be served from a different substation. See the contingency for MV-4 for a full analysis. MV-3 Feeder MV-3 has one (1) tie to Truckee TR-2, two (2) ties to TR-3, one (1) tie to TR-4, one (1) tie to Donner Lake DL-1 and one additional tie to MV-4. There is no low voltage or conductor overloading during load transfer with existing or future loads. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-14 MV-4 Feeder MV-4 has one (1) tie to Truckee TR-1, one (1) tie to MV-2 and one additional tie to MV-3. There is no low voltage or conductor overloading during load transfer with existing or future loads. e. Sectionalizing Recommendations Martis Valley Substation has three (3) 5,000 kVA 120-7.62/13.2 kV distribution transformers, with SEL-587/551 relays for high side protection. The SEL-587 Instantaneous (IOC) and Time Over-Current (TOC) settings are currently disabled at the Martis Valley substation. It is recommended to update the Line-to-Line voltage settings in the SEL-587. Voltage Highside Protection Transformer Size % Impedance Martis Valley 115 kV SEL-587/551 (3) 5/6.25 MVA 8.44 The following table shows the fault location impedances for the electronic reclosers existing on Martis Valley Substation. These impedance values are used on the Form 6’s to locate faults on the line by calculating the approximate distance from the recloser based on impedance data from the fault. Though these will not give exact locations of the fault, it will help to narrow down certain areas the fault may have occurred, making it easier for fault locating. Substation Recloser R X R0 X0 Miles Martis Valley MV-1 0.86 2.30 1.59 3.03 1.58 MV-2 0.83 2.19 2.13 2.31 2.38 MV-3 1.01 2.72 2.47 4.62 2.72 MV-4 0.79 3.18 1.95 5.56 2.94 The following equipment is recommended for removal or installation on Martis Valley Substation: i. MV-1 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 9.45 miles of primary line on this circuit, with both overhead and underground. There are fuses on this feeder. There are no recommendations made for this feeder. ii. MV-2 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 13.23 miles of primary line on this circuit, with a majority of the line being underground conductor. There is a mixture of hydraulic reclosers and fuses on this feeder. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-15 The following recommendations are made for this feeder: a. R35 Fir Drive It is recommended to replace the existing 4H 70A recloser with a Cooper Spear recloser with Form 6 control. The interrupt rating on the 4H 70A is lower than the highest line-to-ground fault current. Estimated Cost: $ 15,000 iii. MV-3 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 8.81 miles of primary line on this circuit, with a majority of the line being overhead conductor. There are fuses on this feeder. The following recommendations are made for this feeder: a. R10 Donner Pass Rd This is a tie recloser between MV-3 and DL-1. The current settings do not coordinate with DL-1’s feeder reclosers. It is recommended to include alternate settings in this device in order to coordinate with DL-1. Refer to the settings sheet at the end of the section. iv. MV-4 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 8.51 miles of primary line on this circuit, with a majority of the line being overhead conductor. There is an electronic recloser and fuses on this feeder. There are no recommendations made for this feeder. Martis Valley Substation Fuse Size T Device No. Fuse Saving Non Fuse Saving MV-1 Recloser 50 12 MV-2 Recloser 50 8 MV-3 Recloser 50 25 MV-4 Recloser 65 30 R25 Joerger Drive Recloser N/A 65 Current in Amperes1001,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 100,000 1,000,000 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv 179 Minimum Fault 5981 Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 Martis Valley Coordination 7.2 kV Current in Amperes1001,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 100,000 1,000,000 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv 179 Minimum Fault 4577 Phase-Phase Fault TDPUD 2019 Master Plan 10/21/2019 Martis Valley Coordination 7.2 kV Current in Amperes1001,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 100,000 1,000,000 179 Minimum Fault 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv 5287 Three Phase Fault TDPUD 2019 Master Plan 10/21/2019 Martis Valley Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.01 .1 1 10 100 1,000 10,000 179 Minimum Fault 5981 Phase-Ground Fault 280 A Amp: Curve--133 170 A Amp: Curve--142 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 MV-2 Upline Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.01 .1 1 10 100 130 A Amp: Curve--117 130 A Amp: Curve--106 280 A Amp: Curve--133 170 A Amp: Curve--142 176 Minimum Fault 3335 R35 Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 MV-2 Coordination 7.2 kV Current in Amperes1101001,00010,000100,0001,000,000Time In Seconds.01 .1 1 10 100 1,000 10,000 100,000 170 A Amp: Curve--106 380 A Amp: Curve--104 170 A Amp: Curve--140 A+170.00 380 A Amp: Curve--133 5981 Phase-Ground Fault 179 Minimum Fault 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 MV-3 Upline Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.01 .1 1 10 100 100 -Total Clear 170 A Amp: Curve--106 170 A Amp: Curve--140 A+170.00 380 A Amp: Curve--104 380 A Amp: Curve--133 179 Minimum Fault 5008 100T Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 MV-3 Coordination 7.2 kV Current in Amperes1101001,00010,000100,0001,000,000Time In Seconds.01 .1 1 10 100 1,000 10,000 100,000 480 A Amp: Curve--133 170 A Amp: Curve--106 480 A Amp: Curve--104 170 A Amp: Curve--140 179 Minimum Fault 5981 Phase-Ground Fault 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 MV-4 Upline Coordination 7.2 kV Current in Amperes110100 1,00010,000100,000Time In Seconds.01 .1 1 10 100 140 A Amp: Curve--106 140 A Amp: Curve--135 280 A Amp: Curve--101 280 A Amp: Curve--133 170 A Amp: Curve--106 170 A Amp: Curve--140 480 A Amp: Curve--104 480 A Amp: Curve--133 175 Minimum Fault 2591 R25 Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 MV-4 Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.001 .01 .1 1 10 100 1,000 10,000 100,000 480 A Amp: Curve--101 170 A Amp: Curve--104 480 A Amp: Curve--133 170 A Amp: Curve--140 5981 Phase-Ground Fault 179 Minimum Fault 240 A PU U4-US Ext Inv 156 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 MV-1 Upline Coordination 7.2 kV Current in Amperes10100 1,00010,000100,000Time In Seconds.01 .1 1 10 100 65 -Total Clear 480 A Amp: Curve--101 170 A Amp: Curve--140 480 A Amp: Curve--133 170 A Amp: Curve--104 176 Minimum Fault 3311 65T Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 7.2 kV Substation Martis Valley Feeder MV-1 Location Device Form 6 Exis Rec Exis Rec Min Trip Phase 480 Min Trip Ground 170 TCC1P 101 TCC1G 133 TCC2P 104 TCC2G 140 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0.05 TCC1G Mult 1 TCC1G Adder 0.05 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled) Yes High-Current Trip Ground TCC1 (Enabled) Yes High-Current Trip Phase TCC2 (enabled) Yes High-Current Trip Ground TCC2 (Enabled) Yes High-Current Trip Phase TripX TCC1 8 High-Current Trip Ground TripX TCC1 23 High-Current Trip Phase TripX TCC2 8 High-Current Trip Ground TripX TCC2 23 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)4320 High-Current Lockout Ground (Trip)4080 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Substation Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Martis Valley Feeder MV-2 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 170 TCC1P 101 DISABLE TCC1G 104 DISABLE TCC2P 133 TCC2G 142 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes High-Current Trip Ground TCC1 (Enabled)Yes High-Current Trip Phase TCC2 (enabled)Yes High-Current Trip Ground TCC2 (Enabled)Yes High-Current Trip Phase TripX TCC1 21 High-Current Trip Ground TripX TCC1 32 High-Current Trip Phase TripX TCC2 21 High-Current Trip Ground TripX TCC2 32 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)6160 High-Current Lockout Ground (Trip)5950 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Martis Valley Feeder MV-3 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 380 Min Trip Ground 170 TCC1P 104 TCC1G 106 TCC2P 133 TCC2G 140 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1.5 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes High-Current Trip Ground TCC1 (Enabled)Yes High-Current Trip Phase TCC2 (enabled)Yes High-Current Trip Ground TCC2 (Enabled)Yes High-Current Trip Phase TripX TCC1 13 High-Current Trip Ground TripX TCC1 30 High-Current Trip Phase TripX TCC2 13 High-Current Trip Ground TripX TCC2 30 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5320 High-Current Lockout Ground (Trip)5270 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 column, all other settings would remain the same Primary Alternate 1 Note: Only the recommended changes are noted in the Rec Substation Martis Valley Feeder MV-3 Location R10 Donner Pass Rd Device Form 4C Exis Rec Exis Rec Min Trip Phase 300 160 Min Trip Ground 100 150 100 TCC1P 101 101 TCC1G 106 106 TCC2P 133 117 133 TCC2G 142 135 142 Oper to LO Phase 3 3 Oper on TCC1 Phase 1 1 Oper to LO Gnd 3 3 Oper on TCC1 Gnd 1 1 TCC1P Mult 0.2 1 0.2 TCC1P Adder 0 0 0 TCC1G Mult 0.2 1 0.2 TCC1G Adder 0 0 0 TCC2P Mult 1 1 1 TCC2P Adder 0 0 TCC2G Mult 0.5 1 0.5 TCC2G Adder 0 0 High-Current Trip Phase (ON/OFF)On Off On High-Current Trip Ground (ON/OFF)On Off On High-Current Trip Phase (Trip)6 6 High-Current Trip Ground (Trip)8 8 High-Current Trip Phase (Trip No.) High-Current Trip Ground (Trip No.) High-Current Lockout Phase (ON/OFF)On Off Off High-Current Lockout Ground (ON/OFF)On Off Off High-Current Lockout Phase (Trip)7 7 High-Current Lockout Ground (Trip)10 10 High-Current Lockout Phase (Trip No.)1 1 High-Current Lockout Ground (Trip No.)1 1 Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Martis Valley Feeder MV-4 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 480 Min Trip Ground 170 TCC1P 104 TCC1G 106 TCC2P 133 TCC2G 140 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1.5 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes High-Current Trip Ground TCC1 (Enabled)Yes High-Current Trip Phase TCC2 (enabled)Yes High-Current Trip Ground TCC2 (Enabled)Yes High-Current Trip Phase TripX TCC1 12 High-Current Trip Ground TripX TCC1 32 High-Current Trip Phase TripX TCC2 12 High-Current Trip Ground TripX TCC2 32 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)6240 High-Current Lockout Ground (Trip)6120 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Martis Valley Feeder MV-4 Location Joerger Dr Device Form 4C Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 140 TCC1P 101 TCC1G 102 TCC2P 133 TCC2G 165 Oper to LO Phase 3 Oper on TCC1 Phase 0 Oper to LO Gnd 3 Oper on TCC1 Gnd 0 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase (ON/OFF)Off High-Current Trip Ground (ON/OFF)Off High-Current Trip Phase (Trip) High-Current Trip Ground (Trip) High-Current Trip Phase (Trip No.) High-Current Trip Ground (Trip No.) High-Current Lockout Phase (ON/OFF)Off High-Current Lockout Ground (ON/OFF)Off High-Current Lockout Phase (Trip) High-Current Lockout Ground (Trip) High-Current Lockout Phase (Trip No.) High-Current Lockout Ground (Trip No.) column, all other settings would remain the same Primary Alternate 1 Note: Only the recommended changes are noted in the Rec Substation Martis Valley Feeder Substation High Side Location Substation Device SEL-551 CTR CTRN 50P1P 51P1P 51P1C 51P1TD 50N1P 51N1P 51N1C 51N1TD 50G1P 51G1P 51G1C 51G1TD 50Q1P 51Q1P 51Q1C 51Q1TD Rec OFF Primary Exis 15 120 35 6 U4 3 OFF 2 U4 10 OFF Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same OFF U4 1.5 OFF OFF 15 U3 Substation Martis Valley Feeder Substation High Side Location Substation Device SEL-587 MVA VWDG1 VWDG2 CTR1 CTR2 TAP1 TAP2 50P1P 50P1D 50P1H 51P1P 51P1C 51P1TD 50Q1P 50Q1D 51Q1P 51Q1C 51Q1TD 50N1P 50N1D 50N1H 51N1P 51N1C 51N1TD 50P2P 50P2D 50P2H 51P2P 51P2C 51P2TD 50Q2P 50Q2D 51Q2P 51Q2C 51Q2TD 50N2P 50N2D 50N2H 51N2P 51N2C 51N2TD 5 OFF OFF U4 12.4 15 OFF OFF U4 16000 6.6 OFF 16000 OFF OFF U4 15 OFF 2.5 OFF 138 69 OFF 5 OFF OFF U4 OFF U2 OFF 5 U2 3.8 OFF OFF OFF 5 240 3.47 3.62 Primary 15 RecExis Substation Feeder 2 Location R35 Device Cooper SPEAR Exis Rec Min Trip 130 TCC1 106 TCC2 117 TTL 4 Oper #1 TCC1 Oper #2 TCC1 Oper #3 TCC2 Oper #4 TCC2 TCC1 Mult 1 TCC1 Adder 0 TCC1 Min Response Time DISABLE TCC1 HCT DISABLE TCC1 HCT Time Delay 0.01 TCC2 Mult 1 TCC2 Adder 0 TCC2 Min Response Time DISABLE TCC2 HCT DISABLE TCC2 HCT Time Delay 0.01 Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Martis Valley Primary Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-16 6.3 TAHOE DONNER SERVICE AREA The Tahoe Donner Service Area has a projected growth rate of 0.09%3, with losses compounded annually for the plan period. This service area serves a large area to the north of Tahoe Donner Substation. A majority of the customers are residential with some commercial entities, while a majority of the homes served by Tahoe Donner are vacation homes. There is service to approximately 4,000 customers and a total load of 7.7 MW. There are existing 3-phase ties between TD-1 and DL-3, TD-2 and DL-2, TR-5 and TD-3 and two separate ties between TR-4 and TD-3. a. Loading and Capacity Tahoe Donner Substation has three (3) 5/5.6/6.25/7 MVA 60/12.47 kV transformers and three distribution bays in service with no spares. The transformers are followed by a set of 667 kVA, 875 amp regulators. No equipment exceeds its load rating during the plan period. b. Mechanical Condition of Plant There are no deficiencies noted for Tahoe Donner Service Area. c. System Analysis i. TD-1 CIRCUIT Feeder TD-1 serves the area to the west of the Tahoe Donner Substation. There is approximately 1.2 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. ii. TD-2 CIRCUIT Feeder TD-2 serves the area to the north and northwest of the Tahoe Donner Substation. There is approximately 3.0 MW of load on this feeder. Project TD-04 It is recommended to rebuild approximately 0.7 miles of existing 4/0 AWG ACSR to 397 kcmil AAC between between the intersection of Davos Dr. and Northwoods Blvd and the intersection of Northwoods Blvd and Northwoods Blvd. This will improve voltage between the two substations during load transfer. Estimated Cost: $ 231,000 3 Load growth was calculated from 01/2014 to present due to skewed results when including 2015 historical values, where TD-1 had been transferred to Donner Lake. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-17 iii. TD-3 CIRCUIT Feeder TD-3 serves the area to the west and northeast of the Tahoe Donner Substation. There is approximately 3.5 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. d. Phase Balancing Projects · Move OHP_3814 from B-phase to C-phase · Move OHP_55201 from B-phase to C-phase · Move OHP_3923 from A-phase to C-phase e. Contingency In the event of the loss of a substation transformer, the following devices are recommended to be switched: Close switch A59 Close switch S208 Open fuse F208 Close switch S128 Open fuse F128 Close switch A50 Close fuse F368 Open switch S368 Open switch S-502 Open switch S-514 Open XA21 Open S-516 Minimum Voltages On Tahoe Donner Service Area During Contingency Existing 5-year 15-year A 110.8 110.8 110.8 B 112.9 112.9 112.9 C 114.1 114.1 114.1 Donner Lake Transformer Loading 77.2% 77.2% 77.2% Donner Lake Regulator Loading 65.4% 65.4% 65.4% Truckee Transformer Loading 67.2% 93.5% 99.6% Truckee Regulator Loading 74.6% 88.9% 95.9% Table 6.4-1 *NC=did not converge Project TD-C2 It is recommended to rebuild approximately 0.83 miles of existing 4/0 AWG ACSR to 397 kcmil AAC between between Ramshorn East and the intersection of Davos Dr Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-18 and Northwoods Blvd. This will improve voltage between the two substations during load transfer. Estimated Cost: $ 231,000 Project TD-C3 It is recommended to rebuild approximately 0.74 miles of existing 4/0 AWG ACSR to 397 kcmil AAC between Ramshorn East and Christie Lane. This will improve voltage between the two substations during load transfer. Estimated Cost: $ 206,000 Project TD-C4 It is recommended to rebuild approximately 0.67 miles of existing 2 AWG ACSR to 397 kcmil AAC between Muhlebach Way and Chamonix Road. This will improve voltage between the two substations during load transfer. Estimated Cost: $ 186,000 Project TD-C5 It is recommended to rebuild approximately 1.0 miles of existing 2/0 AWG ACSR to 397 kcmil AAC between Snowpeake Way and Muhlebach Way. This will improve voltage between the two substations during load transfer. Estimated Cost: $ 278,200 TD-1 Feeder TD-1 Feeder can be transferred to Donner Lake DL-3 (switch 166.53649). TD-1 Feeder also has a tie to TD-2. When transferring load to DL-3 Feeder, there is no transformer overloading, conductor overloading or low voltage. TD-2 Feeder TD-2 Feeder has existing ties to both TD-1 and TD-3, but no available tie points to different substations. There is low voltage on TD-2 at all loading levels during contingency. TD-3 Feeder TD-3 Feeder has two (2) existing ties to Truckee Substation’s TR-4 Feeder, one tie to TR-5 and ties to TD-2. There is no conductor overloading, low voltage or transformer overloading during the planning period with this switching order. f. Sectionalizing Recommendations Tahoe Donner Substation has three (3) 5/7 MVA 60-12.47/7.2 kV distribution transformers, with SEL-587/551 relays for high side protection. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-19 The following recommendations are made for the Tahoe Donner Substation: a) Feeder Recloser New relay settings are shown at the end of this section. Voltage Highside Protection Transformer Size % Impedance Tahoe Donner 60 kV SEL-587/551 (3) 5/7 MVA 7.81 The following table shows the fault location impedances for the existing electronic reclosers on Tahoe Donner Substation. These impedance values are used on the Form 6’s to locate faults on the line by calculating the approximate distance from the recloser based on impedance data from the fault. Though these will not give exact locations of the fault, it will help to narrow down certain areas the fault may have occurred, making it easier for fault locating. Substation Recloser R X R0 X0 Miles Tahoe Donner TD-1 1.12 2.29 1.87 3.96 1.60 TD-2 1.26 2.69 2.18 4.93 2.20 TD-3 0.86 2.25 1.63 3.87 1.78 The following equipment is recommended for removal or installation on Tahoe Donner Substation: i. TD-1 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 7.28 miles of primary line on this circuit, with a majority of the line being overhead conductor. There is a mixture of hydraulic reclosers and fuses on this feeder. ii. TD-2 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 16.05 miles of primary line on this circuit, with a majority of the line being overhead conductor. There is a mixture of hydraulic reclosers and fuses on this feeder. The following recommendations are made for this feeder: a. Feeder Recloser It is recommended to disable the high-current trip settings and increase the high current lockout setting. Refer to the settings sheet at the end of the section. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-20 b. Recloser R50 (Wolfgang) The current settings for this recloser are unknown, therefore it is recommended replace this recloser with a Spear recloser with Cooper Form 6 control. Refer to the settings sheet at the end of the section. Estimated Cost: $ 15,000 iii. TD-3 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 21.36 miles of primary line on this circuit, with a majority of the line being overhead conductor. There is an electronic recloser and fuses on this feeder. The following recommendations are made for this feeder: a. Feeder Recloser It is recommended to disable the high-current trip settings and increase the high current lockout setting. Refer to the settings sheet at the end of the section. b. Recloser R15 (Sitzmark) It is recommended to change the phase TCC2 curve from 162 to 117 to better coordinate with the feeder recloser. Refer to the settings sheet at the end of the section. Tahoe Donner Substation Fuse Size T Device No. Fuse Saving Non Fuse Saving TD-1 Recloser 50 12 TD-2 Recloser 50 12 TD-3 Recloser 50 15 R15 Sitzmark Recloser 30 6 Current in Amperes1001,00010,000100,000Time In Seconds.01 .1 1 10 100 170 A Amp: Curve--104 170 A Amp: Curve--140 480 A Amp: Curve--101 480 A Amp: Curve--133 504 A PU U4-US Ext Inv 960 A PU U4-US Ext Inv 160 A PU U4-US Ext Inv 168 A PU U4-US Ext Inv 180 Minimum Fault 7600 Phase-Ground Fault TDPUD 2019 Master Plan 10/21/2019 TD-1 Upline Coordination 7.2 kV Current in Amperes10100 1,00010,000100,000Time In Seconds.01 .1 1 10 480 A Amp: Curve--101 170 A Amp: Curve--104 170 A Amp: Curve--140 480 A Amp: Curve--133 40 -Total Clear 176 Minimum Fault 3519 40T Three Phase Fault TDPUD 2019 Master Plan 10/21/2019 TD-1 Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.01 .1 1 10 100 480 A Amp: Curve--101 170 A Amp: Curve--104 170 A Amp: Curve--140 480 A Amp: Curve--133 504 A PU U4-US Ext Inv 960 A PU U4-US Ext Inv 160 A PU U4-US Ext Inv 180 Minimum Fault 7600 Phase-Ground Fault 168 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 TD-2 Upline Coordination 7.2 kV Current in Amperes1101001,00010,000100,0001,000,000Time In Seconds.01 .1 1 10 100 480 A Amp: Curve--101 170 A Amp: Curve--104 480 A Amp: Curve--133 170 A Amp: Curve--140 65 -Total Clear 5775 65T Phase-Ground Fault 172 Minimum Fault TDPUD 2019 Master Plan 10/21/2019 TD-2 Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.01 .1 1 10 100 280 A Amp: Curve--104 280 A Amp: Curve--133 170 A Amp: Curve--140 170 A Amp: Curve--106 7600 Phase-Ground Fault 180 Minimum Fault 504 A PU U4-US Ext Inv 168 A PU U4-US Ext Inv 960 A PU U4-US Ext Inv 160 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 TD-3 Upline Coordination 7.2 kV Current in Amperes101001,00010,000Time In Seconds.01 .1 1 10 100 200 A Amp: Curve--101 100 A Amp: Curve--106 100 A Amp: Curve--142 200 A Amp: Curve--117 280 A Amp: Curve--133 280 A Amp: Curve--104 170 A Amp: Curve--106 170 A Amp: Curve--140 2435 R15 Three Phase Fault 172 Minimum Fault TDPUD 2019 Master Plan 10/21/2019 TD-3 Coordination 7.2 kV Current in Amperes1001,00010,000100,000Time In Seconds.1 1 10 100 1,000 504 A PU U4-US Ext Inv 168 A PU U4-US Ext Inv 160 A PU U4-US Ext Inv 960 A PU U4-US Ext Inv 7128 Three Phase Fault 180 Minimum Fault TDPUD 2019 Master Plan 10/21/2019 Tahoe Donner Coordination 7.2 kV Current in Amperes1001,00010,000100,000Time In Seconds.1 1 10 100 1,000 504 A PU U4-US Ext Inv 168 A PU U4-US Ext Inv 180 Minimum Fault 7600 Phase-Ground Fault 160 A PU U4-US Ext Inv 960 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 Tahoe Donner Coordination 7.2 kV Current in Amperes1001,00010,000100,000Time In Seconds.1 1 10 100 1,000 504 A PU U4-US Ext Inv 168 A PU U4-US Ext Inv 6172 Phase-Phase Fault 180 Minimum Fault 160 A PU U4-US Ext Inv 960 A PU U4-US Ext Inv TDPUD 2019 Master Plan 10/21/2019 Tahoe Donner Coordination 7.2 kV Substation Tahoe Donner Feeder TD-1 Location Device Form 6 Exis Rec Exis Rec Min Trip Phase 480 Min Trip Ground 170 TCC1P 101 TCC1G 104 TCC2P 133 TCC2G 140 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0.05 TCC1G Mult 1 TCC1G Adder 0.05 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 11 High-Current Trip Ground TripX TCC1 32 High-Current Trip Phase TripX TCC2 11 High-Current Trip Ground TripX TCC2 32 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5760 6500 High-Current Lockout Ground (Trip)5610 6500 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Substation Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Tahoe Donner Feeder TD-2 Location Device Form 6 Exis Rec Exis Rec Min Trip Phase 480 Min Trip Ground 170 TCC1P 101 TCC1G 104 TCC2P 133 TCC2G 170 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0.05 TCC1G Mult 1 TCC1G Adder 0.05 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 11 High-Current Trip Ground TripX TCC1 32 High-Current Trip Phase TripX TCC2 11 High-Current Trip Ground TripX TCC2 32 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5760 6500 High-Current Lockout Ground (Trip)5610 6500 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Note: Only the recommended changes are noted in the Rec Substation Primary Alternate 1 column, all other settings would remain the same Substation Tahoe Donner Feeder TD-3 Location Device Form 6 Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 170 TCC1P 101 104 TCC1G 106 TCC2P 133 TCC2G 140 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0.05 0 TCC2P Mult 1 TCC2P Adder 0.05 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 18.9 High-Current Trip Ground TripX TCC1 32 High-Current Trip Phase TripX TCC2 18.9 High-Current Trip Ground TripX TCC2 32 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5760 6500 High-Current Lockout Ground (Trip)5610 6500 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Primary Alternate 1 Substation Tahoe Donner Feeder TD-3 Location Device Form 4 Exis Rec Exis Rec Min Trip Phase 200 Min Trip Ground 100 TCC1P 101 TCC1G 106 TCC2P 162 117 TCC2G 142 Oper to LO Phase 2 Oper on TCC1 Phase 1 Oper to LO Gnd 2 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes High-Current Trip Ground TCC1 (Enabled)Yes High-Current Trip Phase TCC2 (enabled)Yes High-Current Trip Ground TCC2 (Enabled)Yes High-Current Trip Phase TripX TCC1 6 High-Current Trip Ground TripX TCC1 9 High-Current Trip Phase TripX TCC2 6 High-Current Trip Ground TripX TCC2 9 High-Current Trip Phase Time Delay TCC1 0.05 High-Current Trip Ground Time Delay TCC1 0.05 High-Current Trip Phase Time Delay TCC1 0.05 High-Current Trip Ground Time Delay TCC1 0.05 High-Current Lockout Phase (Enabled)No High-Current Lockout Ground (Enabled)No High-Current Lockout Phase (Trip) High-Current Lockout Ground (Trip) High-Current Lockout Phase (Trip No.) High-Current Lockout Ground (Trip No.) Note: Only the recommended changes are noted in the Rec R15 Sitzmark Primary Alternate 1 column, all other settings would remain the same Substation Tahoe Donner Feeder Substation High Side Location Substation Device SEL-551 CTR CTRN 50P1P 51P1P 51P1C 51P1TD 50N1P 51N1P 51N1C 51N1TD 50G1P 51G1P 51G1C 51G1TD 50Q1P 51Q1P 51Q1C 51Q1TD Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same U3 15 1.5 OFF OFF OFF OFF U4 8 U4 2.5 U4 1.25 OFF 120 73 OFF 4 Primary Exis Rec 40 Substation Tahoe Donner Feeder Substation High Side Location Substation Device SEL-587 MVA VWDG1 VWDG2 CTR1 CTR2 TAP1 TAP2 50P1P 50P1D 50P1H 51P1P 51P1C 51P1TD 50Q1P 50Q1D 51Q1P 51Q1C 51Q1TD 50N1P 50N1D 50N1H 51N1P 51N1C 51N1TD 50P2P 50P2D 50P2H 51P2P 51P2C 51P2TD 50Q2P 50Q2D 51Q2P 51Q2C 51Q2TD 50N2P 50N2D 50N2H 51N2P 51N2C 51N2TD U4 12.4 5 OFF OFF U4 15 OFF OFF 16000 OFF OFF U2 2.5 OFF 5 OFF OFF U4 15 OFF 16000 OFF OFF U4 6.6 1.25 3 OFF 5 73 OFF 4 4.2 U4 8.1 OFF 73 5 40 120 2.78 OFF 138 69 Primary Exis Rec Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-21 6.4 TRUCKEE SERVICE AREA The Truckee Service Area has a projected growth rate of 0.05% with losses compounded annually for the plan period. This service area serves the central portion of TDPUD’s system. This substation serves approximately 3,100 customers and a total load of 10.5 MW. There are existing 3-phase ties between TR-1 and MV-4, TR-5 and TD-3, two ties between TR-2 and MV-3, two ties between TR-3 and MV-3, one tie between TR-4 and MV-3 and TR-4 and DL-1. a. Loading and Capacity Truckee Substation has three (3) single-phase 5/5.6/6.25/7 MVA 69/12.47 kV transformers and six (6) distribution bays with no spares. There are a set of 667 kVA, 875 amp regulators after the transformers. The substation transformer loading is at 124.7% with 15-year loads. b. Mechanical Condition of Plant There are no deficiencies noted for Truckee Service Area. c. System Analysis Project TR-03 This project improves the Truckee Substation control house and spill containment. Estimated Cost: $970,000 i. TR-1 CIRCUIT Feeder TR-1 serves the area to the east of the Truckee Substation. There is approximately 1.1 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. Project TR-01 This portion of the line has over 31 amps on a single phase. It is recommended to rebuild approximately 0.22 miles of single-phase 2 AWG ACSR with three-phase 2 AWG ACSR from the intersection of Glenshire Dr. and Olympic Blvd to the intersection of Olympic Blvd and East Ridge Rd. Estimated Cost: $ 56,100 ii. TR-2 CIRCUIT Feeder TR-2 serves a small area to the south of Truckee Substation. There is approximately 0.8 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. iii. TR-3 CIRCUIT Feeder TR-3 serves an area to the southwest of Truckee Substation. There is a maximum peak of approximately 735 kW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-22 iv. TR-4 CIRCUIT Feeder TR-4 serves an area to the west of Truckee Substation. There is a maximum peak of approximately 4.4 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. v. TR-5 CIRCUIT Feeder TR-5 serves an area to the north and northeast of Truckee Substation. There is a maximum peak of approximately 2.3 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. Project TR-02 This portion of the line has over 58 amps on a single phase. It is recommended to rebuild approximately 1.22 miles of single-phase 2 AWG ACSR with three-phase 2 AWG ACSR from the intersection of Rainbow Dr. and Highway 89 north to the intersection of East Alder Creek Rd. and Pine Forest Rd.. Estimated Cost: $ 467,000 vi. TR-6 CIRCUIT Feeder TR-6 serves an area to the northeast of Truckee Substation. There is a maximum peak of approximately 1.1 MW of load on this feeder. No low voltage occurs on this feeder with existing or future loads. d. Phase Balancing Projects · Move OHP_91071 from A-phase to C-phase · Move XFMR-01049634 from A-phase to C-phase e. Contingency In the event of the loss of a substation transformer, the following devices are recommended to be switched: Close switch S-128 Open fuse F-208 Close switch A-28 Open switch A-49 Close switch S-368 Open fuse F-368 Close switch A-50 Close switch A-16 Close switch PMS3-2 Open switch A18 Close switch PMS27-1 Close switch A-19 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-23 Minimum Voltages On Truckee Service Area During Contingency Existing 5-year 15-year A 117.9 117.9 117.9 B 116.5 116.5 116.5 C 118.9 118.9 118.9 Martis Valley Transformer Loading 64.3% 85.8% 118.9% Martis Valley Regulator Loading 63.8% 85.1% 118.0% Tahoe Donner Transformer Loading 69.3% 71.4% 74.6% Tahoe Donner Regulator Loading 76.9% 79.3% 82.9% Table 6.5-1 Project TR-C1 It is recommended to rebuild approximately 0.33 miles of 2 AWG ACSR with 4/0 AWG ACSR. This line is located between Spring Lane and Levone Ave to around Tahoe Dr and Donner Way. Estimated Cost: $ 94,000 Project TR-C2 It is recommended to rebuild approximately 0.59 miles of 4/0 AWG ACSR with 397 kcmil AAC. This line is located on W River St. between Bridge St. and McIver Crossing/Foxmead Lane. This project should occur within 5 year loading levels. Estimated Cost:$168,000 Project TR-C3 It is recommended to rebuild approximately 0.15 miles of 500 kcmil with 750 kcmil. This line is located perpendicular to California 267, near Ranch Way. Estimated Cost: $ 137,000 Project TR-C4 It is recommended to upgrade the existing set of three (3) single-phase 5 MVA transformers at the Truckee substation to three (3) single-phase 7.5 MVA transformers in order to maintain capacity at 15-year loading when transferring load from Martis Valley or Tahoe Donner to Truckee. At existing loading, the transformers are at 146% capacity when Martis Valley is transferred. Alternatively, portions of Truckee could be transferred to Donner Lake and Tahoe Donner when picking up Martis Valley. The following additional switching would keep Truckee transformer loading below 100% at 15-year peak loading when transferring Martis Valley to Truckee: Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-24 Close switch S106 Open switch S136 Close switch PMS26-1 Open switch A55 Estimated Cost: $ 750,000 Project TR-C5 There is conductor overloading during 5-year and 15-year loading levels when transferring Martis Valley to Truckee. The conductor is loaded at 81% with existing loading levels and 137.2% at 15-year loading levels. It is recommended to rebuild approximately 1.01 miles of 4/0 AWG ACSR with 397 kcmil AAC. This line begins east of the W River St. and Bridge St. intersection and ends near the Truckee substation. This project should occur within 5 year loading levels. Estimated Cost: $ 51,000 TR-1 Feeder TR-1 Feeder can be transferred to Martis Valley MV-4 (switch 166.1669), as well as ties to TR-2 and TR-6. When transferring load to MV-4 Feeder, there is no transformer overloading, conductor overloading or low voltage. TR-2 Feeder TR-2 Feeder has two (2) ties to Martis Valley MV-3 Feeder, as well as ties to TR- 1 and TR-3. When transferring load to MV-4 Feeder, there is no transformer overloading, conductor overloading or low voltage. Switch 166.1679 should be closed to transfer load. TR-3 Feeder TR-3 Feeder has two (2) ties to Martis Valley MV-3 Feeder, as well as ties to TR- 1 and TR-3. When transferring load to MV-3 Feeder, there is no transformer overloading, conductor overloading or low voltage. Switch 166.12658 should be closed to transfer load. TR-4 Feeder TR-4 Feeder has two (2) ties to Tahoe Donner TD-3 Feeder, one (1) tie to Martis Valley MV-3 Feeder, as well as ties to TR-3 and TR-5. When transferring load to TD-3 and MV-3, there is no transformer overloading, conductor overloading or low voltage during the planning period. TR-5 Feeder TR-5 Feeder has one (1) tie to Tahoe Donner TD-3 Feeder, as well as ties to TR-4 and TR-6. When transferring load to MV-3 Feeder, there is no transformer overloading, conductor overloading or low voltage. Fuse 168.6010 should be closed to transfer load. Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-25 TR-6 Feeder TR-6 Feeder has ties to TR-1 and TR-5 but no additional ties to other substations. When transferring load to TR-5 Feeder, there is no transformer overloading, conductor overloading or low voltage. Switch 166.10096 should be closed to transfer load. f. Sectionalizing Recommendations Truckee Substation has three (3) 5/7 kVA 60-12.47/7.2 kV distribution transformers, with high-side protection from the utility. The SEL-587 Instantaneous (IOC) and Time Over-Current (TOC) settings are currently disabled at the Truckee substation. The following recommendations are made for the Truckee Substation: a) Feeder Recloser New relay settings are shown at the end of this section. Voltage Highside Protection Transformer Size % Impedance Truckee 60 kV S&C SMD-1A Slow 150A (3) 5/7 MVA 7.97 (Average of the three operating transformers) The following table shows the fault location impedances for the electronic reclosers on Truckee Substation. These impedance values are used on the Form 6’s to locate faults on the line by calculating the approximate distance from the recloser based on impedance data from the fault. Though these will not give exact locations of the fault, it will help to narrow down certain areas the fault may have occurred, making it easier for fault locating. Substation Recloser R X R0 X0 Miles Truckee TR-1 0.81 2.83 2.15 5.42 3.06 TR-2 0.13 1.12 0.28 1.12 0.32 TR-3 1.06 1.85 2.54 2.30 2.43 TR-4 1.10 2.44 2.57 4.44 2.69 TR-5 1.08 2.37 2.52 3.83 2.70 TR-6 0.77 2.65 2.19 4.82 3.06 i. TR-1 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 16.96 miles of primary line on this circuit, with a majority of the line being underground conductor. There are recommendations made for this feeder. Refer to the settings sheets Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-26 at the end of this section ii. TR-2 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 1.12 miles of primary line on this circuit, with a majority of the line being overhead conductor. There are recommendations made for this feeder. Refer to the settings sheets at the end of this section iii. TR-3 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 4.68 miles of primary line on this circuit, with a majority of the line being underground conductor. There are recommendations made for this feeder. Refer to the settings sheets at the end of this section iv. TR-4 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 11.43 miles of primary line on this circuit, with both underground and overhead conductor. There is a mixture of hydraulic reclosers and fuses on this feeder. There are recommendations made for this feeder. Refer to the settings sheets at the end of this section v. TR-5 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 41.41 miles of primary line on this circuit, with a majority of the line being underground conductor. There is a mixture of electronic reclosers and fuses on this feeder. The district has recently installed two SPEAR reclosing units on this feeder. There are recommendations made for this feeder. Refer to the settings sheets at the end of this section Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-27 vi. TR-6 Feeder This feeder is protected by a NOVA recloser with Cooper Form 6 control. There are approximately 10.58 miles of primary line on this circuit, with a majority of the line being underground conductor. There is a mixture of electronic reclosers and fuses on this feeder. There are recommendations made for this feeder. Refer to the settings sheets at the end of this section Truckee Substation Fuse Size T Device No. Fuse Saving Non Fuse Saving TR-1 Recloser 65 15 TR-2 Recloser 65 15 TR-3 Recloser 65 15 TR-4 Recloser 65 15 TR-5 Recloser 65 12 TR-6 Recloser N/A 20 R70 Alder Recloser 40 15 R40 Hwy 89 Recloser 20 3 R45 RainBow Recloser 25 6 R80 Recloser 30 8 Current in Amperes100 1,00010,000Time In Seconds.01 .1 1 10 100 140 A Amp: Curve--106 280 A Amp: Curve--104 140 A Amp: Curve--165 280 A Amp: Curve--133 3099 Phase-Ground Fault 176 Minimum Fault 65 -Total Clear TDPUD 2019 Master Plan 10/21/2019 TR-1 Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 100 25 -Total Clear 474 Minimum Fault 6727 25T Phase-Ground Fault 280 A Amp: Curve--104 170 A Amp: Curve--165 280 A Amp: Curve--133 170 A Amp: Curve--106 TDPUD 2019 Master Plan 10/21/2019 TR-2 Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.01 .1 1 10 100 65 -Total Clear 7064 65T Phase-Ground Fault 179 Minimum Fault 170 A Amp: Curve--106 170 A Amp: Curve--165 280 A Amp: Curve--104 280 A Amp: Curve--133 TDPUD 2019 Master Plan 10/21/2019 TR-3 Coordination 7.2 kV Current in Amperes1001,00010,000Time In Seconds.01 .1 1 10 100 65 -Total Clear 465 Minimum Fault 140 A Amp: Curve--106 140 A Amp: Curve--165 280 A Amp: Curve--104 280 A Amp: Curve--133 4671 65T Three Phase Fault TDPUD 2019 Master Plan 10/21/2019 TR-4 Coordination 7.2 kV Current in Amperes10100 1,00010,000Time In Seconds.001 .01 .1 1 10 100 3507 R70 Three Phase Fault 172 Minimum Fault 2189 R40 Phase-Ground Fault 2074 R45 Phase-Ground Fault 100 A Amp: Curve--101 100 A Amp: Curve--161 100 A Amp: Curve--132 100 A Amp: Curve--101 140 A Amp: Curve--106 200 A Amp: Curve--117 140 A Amp: Curve--119 200 A Amp: Curve--104 170 A Amp: Curve--151 480 A Amp: Curve--117 TDPUD 2019 Master Plan 10/21/2019 TR-5 Coordination 7.2 kV Current in Amperes101001,00010,000100,000Time In Seconds.1 1 10 100 250 A Amp: Curve--101 250 A Amp: Curve--117 140 A Amp: Curve--135 140 A Amp: Curve--104 170 A Amp: Curve--151 480 A Amp: Curve--117 480 A Amp: Curve--101 170 A Amp: Curve--106 5277 R80 Three Phase Fault 178 Minimum Fault TDPUD 2019 Master Plan 10/21/2019 TR-6 Coordination 7.2 kV Substation Truckee Feeder TR-1 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 140 TCC1P 104 TCC1G 106 TCC2P 133 TCC2G 165 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 8 High-Current Trip Ground TripX TCC1 15 High-Current Trip Phase TripX TCC2 8 High-Current Trip Ground TripX TCC2 15 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5500 6700 High-Current Lockout Ground (Trip)6000 6700 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Truckee Feeder TR-2 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 170 TCC1P 104 TCC1G 106 TCC2P 133 TCC2G 165 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1.25 TCC1P Adder 0 TCC1G Mult 1.25 TCC1G Adder 0 TCC2P Mult 2 TCC2P Adder 0 TCC2G Mult 2 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 13 High-Current Trip Ground TripX TCC1 20 High-Current Trip Phase TripX TCC2 14 High-Current Trip Ground TripX TCC2 22 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5500 6700 High-Current Lockout Ground (Trip)6000 6700 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Primary Alternate 1 Substation Truckee Feeder TR-3 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 170 TCC1P 104 TCC1G 106 TCC2P 133 TCC2G 165 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1.25 TCC1P Adder 0 TCC1G Mult 1.25 TCC1G Adder 0 TCC2P Mult 2 TCC2P Adder 0 TCC2G Mult 2 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 20 High-Current Trip Ground TripX TCC1 31 High-Current Trip Phase TripX TCC2 20 High-Current Trip Ground TripX TCC2 32 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5500 6700 High-Current Lockout Ground (Trip)6000 6700 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Truckee Feeder TR-4 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 280 Min Trip Ground 140 TCC1P 104 TCC1G 106 TCC2P 133 TCC2G 165 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0 TCC1G Mult 1 TCC1G Adder 0 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled) Yes OFF High-Current Trip Ground TCC1 (Enabled) Yes OFF High-Current Trip Phase TCC2 (enabled) Yes OFF High-Current Trip Ground TCC2 (Enabled) Yes OFF High-Current Trip Phase TripX TCC1 8 High-Current Trip Ground TripX TCC1 15 High-Current Trip Phase TripX TCC2 8 High-Current Trip Ground TripX TCC2 15 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5500 6700 High-Current Lockout Ground (Trip)6000 6700 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Alternate 1 Substation Truckee Feeder TR-5 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 480 Min Trip Ground 170 TCC1P 101 OFF TCC1G 106 OFF TCC2P 117 TCC2G 151 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0.08 TCC1G Mult 1 TCC1G Adder 0.08 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 11 High-Current Trip Ground TripX TCC1 31 High-Current Trip Phase TripX TCC2 11 High-Current Trip Ground TripX TCC2 31 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5700 6700 High-Current Lockout Ground (Trip)5600 6700 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Alternate 1 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Substation Truckee Feeder TR-5 Location Alder R70 Device Form 6 TS Exis Rec Exis Rec Min Trip Phase 200 Min Trip Ground 140 TCC1P 102 104 TCC1G 113 106 TCC2P 116 117 TCC2G 135 119 Oper to LO Phase 4 Oper on TCC1 Phase 2 Oper to LO Gnd 4 Oper on TCC1 Gnd 2 TCC1P Mult 0.5 1 TCC1P Adder 0 0 TCC1G Mult 0.15 1 TCC1G Adder 0.2 0 TCC2P Mult 7 1 TCC2P Adder 0 0 TCC2G Mult 1.1 1 TCC2G Adder 0 0 High-Current Trip Phase TCC1 (enabled)Yes No High-Current Trip Ground TCC1 (Enabled)No High-Current Trip Phase TCC2 (enabled)No High-Current Trip Ground TCC2 (Enabled)No High-Current Trip Phase TripX TCC1 5 High-Current Trip Ground TripX TCC1 0 High-Current Trip Phase TripX TCC2 0 High-Current Trip Ground TripX TCC2 0 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0 High-Current Trip Phase Time Delay TCC1 0 High-Current Trip Ground Time Delay TCC1 0 High-Current Lockout Phase (Enabled)No High-Current Lockout Ground (Enabled)No High-Current Lockout Phase (Trip)0 High-Current Lockout Ground (Trip)0 High-Current Lockout Phase (Trip No.)0 High-Current Lockout Ground (Trip No.)0 Note: Only the recommended changes are noted in the Rec column, all other settings would remain the same Alternate 1Primary Substation Truckee Feeder TR-6 Location Substation Device Form 6 Exis Rec Exis Rec Min Trip Phase 480 Min Trip Ground 170 TCC1P 101 TCC1G 106 TCC2P 117 TCC2G 151 Oper to LO Phase 3 Oper on TCC1 Phase 1 Oper to LO Gnd 3 Oper on TCC1 Gnd 1 TCC1P Mult 1 TCC1P Adder 0.08 TCC1G Mult 1 TCC1G Adder 0.08 TCC2P Mult 1 TCC2P Adder 0 TCC2G Mult 1 TCC2G Adder 0 High-Current Trip Phase TCC1 (enabled)Yes OFF High-Current Trip Ground TCC1 (Enabled)Yes OFF High-Current Trip Phase TCC2 (enabled)Yes OFF High-Current Trip Ground TCC2 (Enabled)Yes OFF High-Current Trip Phase TripX TCC1 11 High-Current Trip Ground TripX TCC1 31 High-Current Trip Phase TripX TCC2 11 High-Current Trip Ground TripX TCC2 31 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Trip Phase Time Delay TCC1 0.016 High-Current Trip Ground Time Delay TCC1 0.016 High-Current Lockout Phase (Enabled)Yes High-Current Lockout Ground (Enabled)Yes High-Current Lockout Phase (Trip)5500 6700 High-Current Lockout Ground (Trip)6000 6700 High-Current Lockout Phase (Trip No.)1 High-Current Lockout Ground (Trip No.)1 Primary Alternate 1 column, all other settings would remain the same Note: Only the recommended changes are noted in the Rec Substation Feeder 5 Location R40 Device Cooper SPEAR Exis Rec Min Trip 140 100 TCC1 101 TCC2 161 TTL 4 Oper #1 TCC1 Oper #2 TCC1 Oper #3 TCC2 Oper #4 TCC2 TCC1 Mult 1 TCC1 Adder 0 TCC1 Min Response Time DISABLE TCC1 HCT DISABLE TCC1 HCT Time Delay DISABLE TCC2 Mult 1 TCC2 Adder 0 TCC2 Min Response Time DISABLE TCC2 HCT DISABLE TCC2 HCT Time Delay DISABLE Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Truckee Primary Substation Feeder 5 Location R45 Device Cooper SPEAR Exis Rec Min Trip 125 100 TCC1 101 TCC2 132 TTL 4 Oper #1 TCC1 Oper #2 TCC1 Oper #3 TCC2 Oper #4 TCC2 TCC1 Mult 1 TCC1 Adder 0 TCC1 Min Response Time DISABLE TCC1 HCT DISABLE TCC1 HCT Time Delay DISABLE TCC2 Mult 1 TCC2 Adder 0 TCC2 Min Response Time DISABLE TCC2 HCT DISABLE TCC2 HCT Time Delay DISABLE Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Truckee Primary Substation Feeder 6 Location R80 Device Cooper Form 4 Primary Exis Rec Min Trip Phase 250 150 Min Trip Ground 140 80 TCC1P 101 TCC1G 104 TCC2P 117 TCC2G 135 Oper to LO Phase 4 Oper on TCC1 Phase 2 Oper to LO Gnd 4 Oper on TCC1 Gnd 2 TCC1P Mult TCC1P Adder 0.02 TCC1G Mult TCC1G Adder 0.02 TCC2P Mult TCC2P Adder TCC2G Mult TCC2G Adder Note: Settings in the recommended column that are the same as the existing settings are not listed unless otherwise noted. Truckee Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-28 6.6 SYSTEM WIDE IMPROVEMENTS In addition to the recommendations provided for the individual substations in the District’s service territory, there are several other system-wide improvements that are recommended through the 15 year planning period. a. Pole Replacements The District makes provisions every year to replace aging or physically deteriorated poles on their system. It is therefore recommended to replace approximately 250 poles within the next 5 years. Estimated Cost: $ 1,500,000 b. Solar Awning Project The District is interested in installing a photovoltaic system on the District headquarters building by 2020. Not only would the District be reducing its own carbon footprint, all District’s customers would benefit with a lower District complex electric bill. Additionally, all generation would count towards the district’s renewable portfolio requirements. Estimated Cost: $ 150,000 c. Optical Communication Line Installation The District has 25 electric and 55 water facilities located throughout the service territory. These facilities include electric substations, protection devices, planned AMI data concentrators, pump stations, wells, storage tanks, and control valves. Communication media includes leased data circuits, dial-up telephone lines, cellular modems, and radio systems. These communication systems, which are integral to District SCADA systems, are antiquated, difficult to maintain, unreliable and have limited bandwidth. The District has been installing optical communication lines since 2011 to replace these media systems. Optical communication lines and associated equipment provide a robust infrastructure that improves data capacity and communications reliability to District facilities. Transitioning to optical cable technology allows the District to "future proof" communications infrastructure and is the best option for communication cable media. The District has completed 4 phases of optical communication line installation. Four additional phases are expected to be required for connection to all remaining District facilities. Upon completion, there will be a redundant network to all facilities, with 2 distinct physical paths from each facility back to the main office. This means that a single contingency outage will cause no interruption of communication within the network. Electric and water facilities benefit equally from the completed system, therefore the costs associated with procurement and installation will be evenly split between the electric and water departments. Estimated Cost: $ 4,234,000 Truckee Donner Public Utility District 2019 Electric System Master Plan Section 6.0 6-29 d. Fuse Replacement Project The District is interested in replacing all expulsion fuses with ELF current limiting fuses. The District will start at the Tahoe Donner neighborhood and expects to replace all fuses by the end of 2021. From 2022-2025, the District will replace all expulsion fuses in the Prosser and Sierra Meadows areas. Table 6-6-1 and Table 6- 6-2 describes the conversion and transformer tables for ELF current limiting fuses Estimated Cost: $ 1,775,000 T-LINK ELF 6A ELF 8A ELF 12A ELF 20A ELF 30A ELF 50A ELF 80A 3T X 6T X 8T X 10T X 15T X 20T X 25T X 40T X 65T X Conversion Table Table 6-6-1 XFMR ELF 6A ELF 8A ELF 12A ELF 20A ELF 30A ELF 50A ELF 80A 5 KVA X 10 KVA X 15 KVA X 25 KVA X 37.5 KVA X 50 KVA X 75 KVA X 100 KVA X Transformer Table Table 6-6-2