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Robert H Fletcher 1 Distribution System Efficiency Voltage Optimization Application to Rural Feeders Case Study 2010 Robert Fletcher, PhD, P.E. Utility Planning Solutions (425) V3

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Rural Feeders Rural Distribution Substation 2 Overhead Rural Feeder Long Feeders (5 to 15 miles) Long single phase laterals Low voltage (<114V) at end of feeders Large neutral currents Large Ampere Phase unbalance Low Customer Density (<1000 kW per sq mi) Line Regulators are typically applied Feeder wire sizes are small compared to urban

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Rural Feeder Considerations Rural feeder service infrastructure costs per customer are high compared with urban feeders. Rural feeder voltage drops are typically higher than urban feeders and typically require line regulators. Line Regulators are used to establish both non-VO or VO voltage-control-zones. Energy savings are not determined for non-VO control zones. Significant system reconfiguration, phase upgrade, load balance, capacitors and line regulators are typically needed for VO on rural feeders. All minimum system thresholds must be applied for all rural feeder VO voltage-control-zones. 3

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Volts 114 Allowed ANSI Service Voltage Range 126 – 114 V (120 V ± 5%) Rural and Urban Feeders Average Customer Service Voltage With CVR ± 2.5% Non CVR National Average4 DSE and VO System Objectives Reduce End-Use energy Consumption (reduce average service voltage) Increase Distribution System Efficiency (lower losses) Improve Service Reliability and Voltage Quality (increase backup capability)

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1. 1. Gather Substation Area Data – –Substation Annual MWh delivered – –Feeder Peak KW and kVAr hourly load patterns – –Feeder connected kVA and locations – –Feeder phase ampere demands. – –Voltage Control settings for Substation, Line Regulators, and Capacitors Establish System Modeling – –Feeder conductor characteristics (OH & UG) and locations – –Feeder connected kVA and locations – –Line phase configuration locations (i.e. single phase, two phase, three phase) – –Line voltage regulator and shunt capacitor locations Determine System Characteristics – –Indentify system load factor LDF and loss factor LSF – –Determine minimum allowed primary volts (on 120 V base) Rural Feeder DSE & VO Design Process5

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4. 4. Perform Peak Load Flow Simulation – Existing System – –Perform peak load flow simulation for existing system – –Determine maximum voltage drops for all feeders and voltage-control-zones – –Identify VO system non-compliance with operation thresholds (bal, pf, volt drop) – –Determine existing system peak line loss Perform Average Load Flow Simulation(s) – Existing System – –Perform average load flow iterative simulations to determine solutions to meet (bal and pf) thresholds: Perform Peak Load Flow Simulation(s) – with Improvements – –Perform peak load flow iterative simulations to determine solution(s) to meet (volt-drop) thresholds and optimal VO design: – –Determine maximum volt-drop for each VO voltage-control-zone – –Determine system peak line loss with improvements (Pre-VO) 6 Load balancing Phase upgrades Revised lateral taps Var Compensation (Capacitors) Switching Load Transfers Reconductoring Voltage-Control-Zones (new or modified)

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7. 7. Perform Pre-VO Operation Assessment – –Identify kVA connected for each voltage-control-zone –Determine kW load for each VO voltage-control-zone – –Identify feeder volt-drop % variance for VO substation feeders –Indentify Pre-VO voltage control settings for each VO voltage-control-zone – –Calculate Pre-VO Weighted Average Voltage Perform Post-VO Operation Assessment –Indentify Pre-VO voltage control settings for each VO voltage-control-zone – –Calculate Post-VO Weighted Average Voltage – –Determine average change in customer voltage Determine System VO Factor – –Identify % of customers with electric space heating for substation area – –Identify % of commercial load for substation area – –Identify climate zone for substation area – –Using ESUE Calculator, determine VO Factor 7

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9. 9. Determine Expected DSE & VO Energy Savings – –Distribution System line loss change (MWh/yr) – –Connected kV A no-load loss reduction (MWh/yr) – –VO Energy Savings (MWh/yr) Perform Economic Life-Cycle Cost Evaluation – –Estimate Costs – –Identify Financial Factors – –Determine Economic Impacts Identify Metering and Engineering Analysis Recommendations 8 Installation Costs Annual O&M Costs Marginal cost of Energy BPA Incentive Payment Inflation Rates Present Worth Factors Utility Net Revenue Requirements Life Cycle Cost of Energy Saved Benefit Cost Ratio NPV Benefits & Costs

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Rural Feeders DSE & VO Case Study /20/25 MVA Power Transformers with four feeders Mix of Rural and Urban Feeders in Climate Zone H2 and C2 Average customer % electric heat is 50% Substation LTC provides only voltage regulation – Reg Volt Set is 125 V No Line Voltage Regulators are installed, mix of existing capacitors Power Factor is poor due to lack of capacitors Existing Metering Data Peak Load kWkVArkVAPF(%)CustomersCom Load FDR % FDR % FDR % FDR % Substation kW losses191 Sub MWh/yr =69882 Load Factor LDF =0.41 Loss Factor LSF =0.204

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10 FDR 1 FDR 2 FDR 3 FDR 4 Substation Service Area: 3806 customers Four Feeders Mix of Rural and Urban Load Service area 10 mile x 7 mile Average 300 kW per sq mi 4.Perform Peak Load Flow Simulations – Existing System Legend: FDR 1 FDR 2 FDR 3 FDR 4

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11 FDR 1 – Rural FDR 2 – Urban & Rural FDR 3 – Urban & Rural FDR 4 – Urban & Rural 4.Perform Peak Load Flow Simulations – Existing System Legend: FDR 1 FDR 2 FDR 3 FDR 4 Urban Area

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12 FDR 1 FDR 2 FDR 3 FDR 4 4.Perform Peak Load Flow Simulations – Existing System Legend: 795 kCM AAC 336 kCM AAC 2/0 AA Rural Feeders have mostly 336 kCM AAC Urban Areas have 795 kCM AAC conductor as substation get-a-ways Laterals are 2/0AA

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13 4.Perform Peak Load Flow Simulations – Existing System Rural Feeders have mostly 336 kCM AAC Urban Areas have 795 kCM AAC conductor as substation get-a-ways Laterals are 2/0AA Legend: 795 kCM AAC 336 kCM AAC 2/0 AA Urban Area

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14 FDR 2 FDR 1 FDR 3 FDR 4 4.Perform Peak Load Flow Simulations – Existing System Identify Non-Compliance Issues: High Load Unbalance Poor power factor Low primary voltage High voltage drops Poor Voltage Variance Determine peak line loss (191 kW) Legend: Volts (lowest phase) 6.64% Volt drop % Accum 10.9 Miles from 3ource

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15 4.Perform Peak Load Flow Simulations – Existing System Power Factors at Peak FDR % FDR % FDR % FDR % Legend: Volts (lowest phase) 6.64% Volt drop % Accum 10.9 Miles from 3ource Urban Area

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Legend: Voltages below V 16 Determine Minimum Primary Volts FDR 1 FDR 2 FDR 3 FDR 4 4.Perform Peak Load Flow Simulations – Existing System 3φ Primary Volt (Min) VD%Volts Secondary Volt Drop (Max) Customer Service Volt (Min) Primary 3φ Volt (Min)

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17 5.Perform Average Load Flow Simulation(s) – Existing System Fixed Capacitors needed to achieve 100% power factor for average kW load conditions Average_kVAr_Demand = Annual_kVArh / 8760 hr Perform average load flow iterative solution(s) to identify upgrades to meet thresholds (bal, pf): Load balancing Phase upgrades Revised lateral taps Var compensation (Caps) Average Load Flow Scenario P =41% Q = 60% Fixed Shunt Capacitor Additions Caps Added (kVAr) FDR 1600 FDR 2900 FDR 3600 FDR Sub Total3300

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Perform Peak Load Flow Simulations – with Improvements Perform peak load flow to assess (volt drop): After Balance, Phase, and Capacitor Upgrades Legend: O Added kVAr Capacitors 3 phase Plan New 1 to 2ph 3 to 2ph 1 to 3ph 2 to 3ph 18 Lat Taps

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Perform Peak Load Flow Simulations – with Improvements Perform peak load flow to assess (volt drop): After Balance and Capacitor Upgrades Legend: O Added 300 kVAr Capacitors 3 phase Urban Area

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20 After adding Balanced and Capacitor upgrades, next identify system reconfigurations to meet (volt drop) thresholds Switching Load transfers Reconductoring New feeders New voltage control zones 6.Perform Peak Load Flow Simulations – with Improvements Consider Switching to add load to FDR 4 from FDR 2 and FDR 3

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21 The Pre-VO system is how the system looks before initiating VO Determine distribution of connected kVA After Switching 6.Perform Peak Load Flow Simulations – with Improvements Existing Connected kVA Pre-VO Connected kVA Connected kVAkW Load Connected kVAkW Load FDR FDR FDR FDR Sub Pre-VO Operation (with Bal, Caps, and Switching) Peak Load Caps Added kWkVArkVAPF(%)kVAr FDR %600 FDR %900 FDR %300 FDR %1500 Sub %3300 kW line losses =161 Determine peak line loss (161 kW) and power factors

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Maximum Feeder Volt drops FDR % FDR % FDR % 6.Perform Peak Load Flow Simulations – with Improvements Perform peak load flow to assess (volt drop): After Switching Upgrades

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Perform Peak Load Flow Simulations – with Improvements Perform peak load flow to assess (volt drop): After Switching Upgrades Maximum Feeder Volt drops FDR % Urban Area

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24 Consider Additional Voltage Control Zones Add VO voltage control zone to FDR 1A at 1.86% Add VO voltage control zone to FDR 1B at 2.05% Add VO voltage control zone to FDR 2 at 1.55% 6.Perform Peak Load Flow Simulations – with Improvements After adding Balanced and Capacitor upgrades, next identify system reconfigurations to meet (volt drop) thresholds Switching Load transfers Reconductoring New feeders New voltage control zones

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25 6.Perform Peak Load Flow Simulations – with Improvements Legend: Accumulated volt drop% 0.0 to 1.5% 1.5 to 2.5% 2.5 to 3.5% 3.5 to 5.0% Perform peak load flow to assess (volt drop): Identify possible locations of voltage control zones SUB LTC 1.85% FDR 1A 1.55% FDR % FDR 1B

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26 Simulate system with new control zones for volt drop improvements Added three New Voltage Control Zones 6.Perform Peak Load Flow Simulations – with Improvements Legend: New Voltage Regulators Accumulated volt drop% 0.0 to 1.5% 1.5 to 2.5% 2.5 to 3.5% 3.5 to 5.0%

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27 No Line Regulators added for in urban area Perform Peak Load Flow Simulations – with Improvements Urban Area

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Legend: 795 kCM 336 kCM 2/0 AA lateral tap revisions 1ph to 2ph 2/0AA 1.3 mi 2ph to 3ph 2/0AA 1.3 mi 2ph to 3ph 2/0AA 1.6 mi 1ph to 3ph 2/0AA 0.3 mi 3-219A Line Regulators kVAr Capacitors Summary of DSE & VO Improvements Reg & EOL Metering $375,000

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Voltage Control Zone Adjusted kW load Connected kVA kW LoadMax VD%VD% Var Sub LTC FDR FDR FDR FDR Sub LTC FDR 1A Reg FDR 1B Reg FDR 2 Reg Total kW Determine kW load for each voltage-control-zone 7.Perform Pre-VO Operation Assessment

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Max VD% Max Volt Drop (V) A Max Volt Rise (V) B Reg Volt Set VFR Average (V) Reg Total kW load Less Control Zones kW load Zone kW Adjusted V * kW FDR FDR FDR FDR Sub LTC FDR 1A Reg FDR 1B Reg FDR 2 Reg Weighted Adjusted Voltage = Reg_Set_Volt – ½ * A * LDF Assign a fixed 124 V for all new voltage control zones regulation sources 7.Perform Pre-VO Operation Assessment Determine Post-VO Weighted Average Voltage After Capacitors, Reconfiguration, and Regulators Added

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Max VD% Max Volt Drop (V) A Max Volt Rise (V) B Reg Volt Set LDC Average (V) Reg Total kW load Less Control Zones kW load Zone kW Adjusted V * kW FDR FDR FDR FDR Sub LTC FDR 1A Reg FDR 1B Reg FDR 2 Reg Weighted Adjusted Voltage = Reg_Set_Volt + LDF * (½ * A + (B – A)) Assign LDC set voltage of 120 V for all voltage control zones regulation sources Determine Post-VO Weighted Adjusted Voltage After Capacitors, Reconfiguration, and Regulators Added 8.Perform Post-VO Operation Assessment

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9.Determine System VO Factor Identify % of customers with electric space heating for substation area 50% Identify % of commercial load for substation area 20% Identify climate zone for substation area H2 & C2 Using ESUE Calculator, determine VO Factor (pu) Weighted Adjusted Average Voltage Change (V) = =3.649 Average Voltage Change (pu) on 120 V base = Change in Energy = VO Factor(pu) * Total MWh Load * Average Voltage Change (pu)

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33 10.Determine Expected DSE & VO Energy Savings Distribution System Efficiency Savings Distribution System Energy Savings from VO improvements (1-(1/(1.030)) 2 ) * 1159 Distribution System Improvements Estimate of Energy Savings LSF = 0.85*LDF^ *LDF System Loss Factor LSF = Peak Loss Reduction (kW) 30 Annual MWH Reduction (MWh/yr) 54 No-Load kW loss Reduction Assumed average 3 watts of no-load loss per kVA connected Connected kVA = Total No Load Loss (kW) =132 Total No Load Loss (MWh) =1159 Reduction (MWh) = 67 Weighted Adjusted Average Voltage Change (V) = =3.649 Average Voltage Change (pu) on 120 V base = 0.030

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34 10.Determine Expected DSE & VO Energy Savings Distribution System VO Energy Savings VO Energy Reduction Change in Energy = VO Factor * Total MWh Load * Average Voltage % Change VO Factor0.450Based on ESUE Calculator end-use factor Total MWh Load69882 Avg Volt % Change0.030 VO Energy Savings956 Weighted Adjusted Average Voltage Change (V) = =3.649 Average Voltage Change (pu) on 120 V base = 0.030

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DSE & VO Total Energy Saved MWh/yr DSE Loss Reduction 54 No Load Loss Reduction67 VO Energy Savings 956 Total Energy Savings for Sub Determine Expected DSE & VO Energy Savings Distribution System DSE & VO Total Energy Savings

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36 11.Perform Economic Life-Cycle Cost Evaluation Utility Inputs DSE General / Substation - INPUT Scoping Study Cost ($)$8,000 Feasibility Study Cost ($)$15,000 Utility Project Cost of DSE & VO Improvements ($)$375,000 Customers per Substation (#)3,891 Average Customer Energy Consumption (kWh/yr)15,000 DSE Savings / Substation - INPUT Total DSE Line Loss Savings (kWh)54,000 Total DSE No-Load Loss Savings (kWh)67,000 Total VO Savings (for End-Use) (kWh)956,000 Total DSE & VO Energy Savings per year1,077,000 kWh/yr Financial Factors - INPUT Average Annual Retail Energy Rate ($/kWh)$0.070 Average Marginal Purchase Power Rate ($/kWh)$0.060 or High Tier Rate (BPA) Annual Cost increase for Construction (%/yr)3.0% Annual Cost increase for kWh Energy (%/yr)4.0% Operations, Maintenance, and Insurance (%/yr)5.0% Present Worth Rate for Cost of Investment (%/yr)7.0% Present Worth Rate for Cost of Energy Losses (%/yr)6.0% Planned life of energy savings (yr) 15 Distribution System DSE & VO Economic Evaluation

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BPA Energy Efficiency Incentive Payment to Utility / Substation DSE & VO Energy Saved1,077,000kWh/yr BPA Energy Efficiency Incentive ($/kWh)$0.25 A - BPA willing to pay First Year$269,250 Utility Project Cost of Improvements$375,000 BPA Energy Efficiency Incentive Rate (pu)70% B - BPA willing to pay First Year$262,500 Total BPA Incentive Payment (lower of A or B)$262,500 BPA Benefit Cost Analysis / Substation Scoping Study Reimbursement$8,000 Detail Study Reimbursement$15,000 BPA Incentive Payment$262,500 Total BPA Costs$285,500 BPA Levelized Cost per kWh saved$0.021per kWh saved 37 BPA Costs 11.Perform Economic Life-Cycle Cost Evaluation Distribution System DSE & VO Economic Evaluation

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Utility Benefit Cost Analysis / Substation Utility Project Cost of DSE & VO Improvements$375,000 NPV Operations, Maintenance, and Insurance$208,470 Less BPA Efficiency Incentive Payment($262,500) Net Utility NPV Investment Costs$320,970 Utility Levelized Cost per kWh Saved (Cost)$0.023per kWh saved Utility Levelized Purchase Power Costs Avoided per kWh (Benefit)$0.060per kWh saved Benefit / Cost Ratio2.59 Utility Revenue Requirements / Substation Total NPV Utility DSE & VO Costs$320,970 Less NPV Purchase Power Costs for End Use($830,319) Net NPV Utility DSE & VO Costs / Substation($509,350) Negative shows Reduction Benefit / Cost Ratio2.59 Present Worth Comparison Substation Costs per year$28,868 Less Purchase Power Savings per year($64,620) Net Substation Savings per year($35,752)Negative shows Reduction in Requirements 38 Utility Benefits and Costs 11.Perform Economic Life-Cycle Cost Evaluation Distribution System DSE & VO Economic Evaluation

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Customer Impact / Substation Average Customer Energy Consumption (before DSE & VO)15,000 kWh per year Average Customer Energy Consumption (after DSE & VO)14,754 kWh per year Average Customer Energy Reduction per year246 kWh per year Customer Average Annual Bill (before DSE & VO)$1, per year Customer Average Annual Bill (after DSE & VO)$1, per year Bill Reduction Per Customer per year($9.19) Negative shows Reduction Customer Present Value of Savings$ Distribution System DSE & VO Economic Evaluation Customer Benefits and Costs 11.Perform Economic Life-Cycle Cost Evaluation

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Robert H Fletcher, PLLC Comments and Questions 40

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