Exhibit E - Example Planning Study-3-21-16.pdf

Northern Wasco County PUD

Prepared by:

570 Kirkland Way, Suite 100 Kirkland, Washington 98033

A registered professional engineering and management services corporation with offices in Kirkland, WA and Portland, OR

Telephone: (425) 889 2700 Facsimile: (425) 889 2725

Capital Needs and Reliability Study 2016 2030

570 Kirkland Way, Suite 100 Kirkland, Washington 98033

Telephone: 425 889 2700 Facsimile: 425 889 2725

A registered professional engineering and management services corporation with offices in Kirkland, WA and Portland, OR

March 21, 2016

Mr. Paul Titus, Assistant General Manager & Director of Engineering Northern Wasco County PUD 2345 River Road The Dalles, OR 97058

SUBJECT: Capital Needs and Reliability Study 2016 2030 – Final Report

Dear Paul:

Please find attached the final report summarizing the Northern Wasco County PUD’s system conditions over the 15 year planning horizon.

Please contact me directly if there are questions.

Very truly yours, EES CONSULTING, INC.

KC Fagen, P.E.

Senior Electrical Engineer

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY i

Contents CONTENTS .......................................................................................................................................................... I

SECTION 1 – EXECUTIVE SUMMARY

INTRODUCTION

EXISTING SYSTEM ANALYSIS

CONDITION ASSESSMENT OF SUBSTATIONS

RECOMMENDED SYSTEM IMPROVEMENTS – YEAR 1

RECOMMENDED SYSTEM IMPROVEMENTS – FUTURE YEARS

HIGH PRIORITY PROJECTS

MEDIUM PRIORITY PROJECTS

LOW PRIORITY PROJECTS

SECTION 2 – INTRODUCTION

OVERVIEW OF THE COMPANY ELECTRICAL SYSTEM

SECTION 3 – STUDY OVERVIEW

CONTRIBUTIONS

DATA

ASSUMPTIONS

DISTRIBUTION SYSTEMMODEL

MODELED LOAD ALLOCATION

SECTION 4 – PLANNING CRITERIA

INTRODUCTION

FORECASTED AND PROJECTED LOAD SCENARIOS

EQUIPMENT AND CONDUCTORMAXIMUM CAPACITY/LOADING

ECONOMIC CONDUCTOR SELECTION

VOLTAGE DROP

POWER FACTOR

PROTECTION AND SECTIONALIZING

RELIABILITY

LOAD AND PHASE BALANCE

LOAD SHIFTING CAPABILITIES FEEDER REDUNDANCY

AGE

SAFETY

SECTION 5 – EXISTING SYSTEM REVIEW

POWER TRANSFORMERS

SUBSTATION AND LINE VOLTAGE REGULATORS

CAPACITY LIMITS

DISTRIBUTION CIRCUITS

SUBSTATION TRANSFORMER OUTAGE ANALYSIS

Second Street Transformer 1 Out of Service – Feeders 11, 12, and 13

Second Street Transformer 2 Out of Service – Feeders 14, 15, 16, and 17

10th Street Out of Service – Feeders 23, and 24

Columbia Heights Out of Service – Feeders 23, and 24

Seufert Out of Service – Feeders 41, and 42

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY ii

SECTION 6 – ASSESSMENT OF EXISTING SYSTEM CONDITIONS

COLUMBIA HEIGHTS SUBSTATION

FIELD ASSESSMENT SUMMARY

SEUFERT SUBSTATION

FIELD ASSESSMENT SUMMARY

10TH STREET SUBSTATION

FIELD ASSESSMENT SUMMARY

2ND STREET SUBSTATION

FIELD ASSESSMENT SUMMARY

DISCOVERY SUBSTATION

FIELD ASSESSMENT SUMMARY

DUFUR SUBSTATION

FIELD ASSESSMENT SUMMARY

TYGH VALLEY SUBSTATION

FIELD ASSESSMENT SUMMARY

THREEMILE SUBSTATION

FIELD ASSESSMENT SUMMARY

SECTION 7 – LOAD FORECAST

INTRODUCTION

SYSTEM LOAD GROWTH

FEEDER LOAD GROWTH

SUBSTATION LOAD GROWTH

SECTION 8 – FUTURE SYSTEM ANALYSIS

INTRODUCTION

PROPOSED SYSTEM IMPROVEMENTS

Short Term System Improvements

Proposed Substation Additions

Feeder Improvements

SECTION 9 – RECOMMENDED PLAN

RECOMMENDED SYSTEM IMPROVEMENTS – YEAR 1

RECOMMENDED SYSTEM IMPROVEMENTS – FUTURE YEARS

HIGH PRIORITY PROJECTS

MEDIUM PRIORITY PROJECTS

LOW PRIORITY PROJECTS

PLANNING LEVEL COST ESTIMATES

APPENDIX A – HISTORIC LOAD DATA

APPENDIX B – EXISTING SYSTEM FEEDER DIAGRAMS

APPENDIX C – OUTAGE ANALYSIS FEEDER DIAGRAMS

APPENDIX D – LOAD FORECAST TRENDING BY FEEDER

APPENDIX E – YEAR 2030 FEEDER DIAGRAMS

APPENDIX F – COST ESTIMATE DETAILS

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY iii

List of Tables

Table 1 1 Power Transformer Loading Table 1 2 Existing System Performance Table 1 3 Substation Condition Assessment Table 1 4 Planning Level Cost Estimate Summary Table 2 1 Substation Transformer Data Table 2 2 Voltage Regulator/LTC Data Table 2 3 Distribution Line Capacitor Data Table 3 1 Normalized Non Coincident Feeder Loading Table 4 1 Equipment Loading Criteria Table 4 2 Overhead Conductor Ampacity Table 4 3 Underground Conductor Ampacity Table 4 4 Economic Overhead Conductor Selection Guide – Initial Loading Table 4 5 Equipment Life Expectancy Table 5 1 Power Transformer Loading Table 5 2 December 2014 Substation Voltage Regulator Loading Table 5 3 Feeder Capacity Limits Table 5 4 Normalized Feeder Loading Table 5 5 System Performance Table 5 6 Heavily Loaded Tie Line Sections (> 50 Percent) Table 5 7 Heavily Loaded Non Feeder Tie Line Sections (>75 Percent) Table 6 1 Substation Condition Assessment Table 6 2 Columbia Heights Substation Assessment Table 6 3 Seufert Substation Assessment Table 6 4 10th Street Substation Assessment Table 6 5 2nd Street Substation Assessment Table 6 6 Discovery Substation Assessment Table 6 7 Dufur Substation Assessment Table 6 8 Tygh Valley Substation Assessment Table 6 9 Three Mile Substation Assessment Table 7 1 Feeder Load Growth Year 2030 Table 7 2 Existing Configuration Power Transformer Loading – Year 2030 Table 8 1 Reconfigured Power Transformer Loading – Year 2030 Table 9 1 Planning Level Cost Estimates

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY iv

List of Figures

Figure 3 1 PUD System Coincident Peak Figure 3 2 PUD Non Coincident Feeder Peak Total Figure 4 1 ANSI C84.1 Voltage Ranges Figure 6 1 Columbia Heights Substation One line Diagram Figure 6 2 Seufert Substation One line Diagram Figure 6 3 10th Street Substation One line Diagram Figure 6 4 2nd Street Substation One line Diagram Figure 6 5 Discovery Substation One line Diagram Figure 6 6 Dufur Substation One line Diagram Figure 6 7 Tygh Valley Substation One line Diagram Figure 6 8 Three Mile Substation One line Diagram Figure 6 9 Pole Birthdate by Decade Figure 7 1 BPA Load Forecast 2016 2030 Figure 8 1 Potential New Substation Locations

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 1

Section 1 – Executive Summary

Introduction The Northern Wasco County People’s Utility District (PUD) is located in The Dalles, Oregon and is a publicly owned utility. The PUD serves approximately 9,900 residential and commercial customers through the transmission and distribution electric grid. The PUD’s service territory includes the City of The Dalles and the communities of Dufur, Tygh Valley and Wamic.

The PUD engaged EES Consulting (EES) to perform a Capital Needs and Reliability Study for its electric power system for a 15 year period, 2015 to 2030. The purpose of the study is to review the capacity and configuration of the PUD’s electric power delivery system, and its ability to reliably and efficiently meet the projected load increase over the next 15 years.

Existing System Analysis EES modeled the PUD’s distribution systems using Milsoft’s WindMil® engineering analysis software, and performed unbalanced load flows on the Year 1 (2015) peak loading and identified areas that did not meet the planning criteria. Appendix A lists historic peak loads by feeder, which were then normalized to eliminate feeder switching. In addition, EES performed a field review of the existing electric facilities and performed an assessment of the condition of the existing substations.

EES identified areas of the system that did not meet the system planning criteria. Most of the issues involved substation power transformer loading; conductor loading for major tie lines exceeding 50 percent of the thermal capacity; and voltage levels that fell below the minimum voltage limit of 118 volts (on a 120V base) at the primary system voltage level.

The Columbia Heights transformer has exceeded its top OA/FA/FA rating of 25MVA. The system does not have sufficient resources to serve all loads if either Columbia Heights or Seufert substation are out of service. The transformers at Second Street, Columbia Heights, and Tygh Valley substations are exceeding the planning limit; 50 percent of capacity for both transformers at Second Street and 75 percent of capacity at the other substations. The remaining substation transformers are loaded below the planning criteria limits, as shown in Table 1 1 below. The Discovery substation is a customer owned facility and the Three Mile substation is a transmission substation and are not included in the capital assessment analysis, but were included in the condition assessment.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 2

Table 1 1 Power Transformer Loading

Substation Transformer Load (kVA)

Rating (kVA) % Loading

% of Planning Limit Mfgr Yr Age

Second Street T1 1 12,377 4 20,000 62% 124% 1994 21 Second Street T2 1 13,752 20,000 69% 138% 1994 21

10th Street 2 16,495 25,000 66% 88% 1980 3 35 Columbia Heights 1 25,200 25,000 101% 134% 2006 9

Dufur 5 2,257 6,500 35% 46% 2010 5 Seufert 1 7,805 14,000 56% 74% 1975 40

Tygh Valley 1,300 1,500 87% 116% 1949 6 53

1. Data from meters on transformer bank

2. Non-coincident summation of feeder loads

3. Assumed based on PCB tag

4. A peak of 16,106MVA was recorded on October 12, 2012. This peak was significantly higher than recorded peaks and was assumed to be due to load switching. The next largest recording of 12,377 was used as the normalized peak.

5. Peak from 2015 data recording.

6. Estimated age

Nine of the 20 feeders are loaded above 65 percent of the conductors’ thermal capacity. Three feeders have voltage levels below the minimum planning criterial of 118V on a 120 volt base.

Appendix B contains feeder maps showing the voltage levels and conductor loading for sections that exceed the planning criteria as well as a complete list of lines sections that exceed the planning criteria thresholds. Table 1 2 provides a summary of loads, voltage, and conductor loading for each feeder.

Table 1 2 Existing System Performance

Substation Feeder Peak Load (KVA/KW) Losses (kW)

Maximum Conductor

Loading

Minimum Voltage Level (V)

Power Factor 1 Imbalance 2

Second Street Fdr 11 4,550 22.1 69% 123.4 95% 8% Second Street Fdr 12 8,258 146.5 78% 119.9 98% 8% Second Street Fdr 13 3,139 13.1 30% 123.7 98% 3% Second Street Fdr 14 6,976 31.9 64% 123.3 - 92% 0% Second Street Fdr 15 5,155 23.5 47% 123.8 98% 4% Second Street Fdr 16 187 0.0 2% 125.0 96% 0% Second Street Fdr 17 3,074 113.7 65% 112.4 99% 29%

10th Street Fdr 23 7,336 123.9 55% 107.3 98% 11% 10th Street Fdr 24 9,158 169.5 87.4% 119.6 98% 3%

Col Hts Fdr 31 9,680 165.1 107% 120.3 98% 13% Col Hts Fdr 32 2,700 10.6 67% 123.5 98% 32% Col Hts Fdr 33 6,300 55.7 94.2% 122.0 98% 14% Col Hts Fdr 34 6,900 33.0 45% 123.8 99% 5%

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 3

Table 1 2 Existing System Performance

Substation Feeder Peak Load (KVA/KW) Losses (kW)

Maximum Conductor

Loading

Minimum Voltage Level (V)

Power Factor 1 Imbalance 2

Seufert Fdr 41 907 0.9 32% 125.8 98% 8% Seufert Fdr 42 7,056 179.8 97.8% 118.3 98% 26% Dufur 3 Fdr 61 1,160 2.1 32.7% 124.3 99% 13% Dufur 3 Fdr 62 1,100 1.0 15.7% 124.6 99% 15%

Tygh Valley 3 Fdr 71 1,300 69.2 57.8% 114.5 99% 14%

1. Winter power factor.

2. Imbalance at feeder source, [1 avg(amps)/max(amps)]

3. Data is from updated data provide January 2016

Condition Assessment of Substations EES visited each substation and logged the nameplate information for major equipment within the substation. The general condition of the substation equipment is considered to be good condition for the age of plant with some of the newer substation in excellent condition. Tygh Valley substation is in poor condition due to the age of the power transformers and bus structure. Table 1 3 below provides a summary of the substation conditions, the approximate year of the major equipment was installed, and EES’s opinion of its overall condition. There were some minor issues found during the assessment summarized below:

1. Minor oil seeping from transformer and reclosers

2. Tracking across surge arrestor

3. Lack of oil containment systems

4. Drawings not matching field conditions or equipment ratings

5. Ruminants of bird nests in equipment

6. Vegetation growing in substation

7. Underrated disconnect switches (limiting element in circuit)

8. Equipment has reached the expected service life.

9. Fault line through substation

10. Equipment grounding

Table 1 3 Substation Condition Assessment

Substation Transformer

Capacity (MVA) Issues 1 Approximate Year Condition Second Street 2 - 12/16/20 2, 4, 8 1994 Good to Excellent

10th Street 15/20/25 1, 3, 8 1980 Fair to Good

Columbia Heights 15/20/25 1, 3, 4, 6, 7, 9, Upgraded Tsf 2006 & Recl.

Good to Excellent, with some areas Fair Dufur 5/6.5 3, 4, 5 Rebuilt 2010 Excellent

Seufert 10/14 1, 5, 8 1975 Good

Tygh Valley 1.5 1, 3, 8

1949 substation transformer, 1962 wooden bus structures, V-Regs and Recloser 2013

Fair, with some equipment Good to Excellent

Discovery Customer Owned None 2014, 115kV Equipment Only Excellent

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 4

Table 1 3 Substation Condition Assessment

Substation Transformer

Capacity (MVA) Issues 1 Approximate Year Condition Three-Mile 7.5 3 2005 Good to Excellent

1. Reference the list above.

Recommended System Improvements – Year 1 The following recommendations are needed to bring the system to within the planning criteria limits for the existing loads and system configuration. These improvements are also necessary to meet planning criteria at the 2030 load levels and proposed configuration.

1. Reset LTC and voltage regulator voltage settings increase voltage during peak load conditions.

2. Perform Feeder 17 improvements including phase balancing to correct for voltage and loading, and add a 150kvar fixed capacitor bank to improve voltage.

3. Perform Feeder 23 improvements including reconductoring area with old 6 copperweld conductor to 1/0ACSR, phase balancing, and add a 150kvar fixed capacitor bank. These improvements are necessary to improve voltage levels, reduce line losses, and improve phase balancing for voltage and loading.

4. Perform Feeder 71 improvements including phase balancing to correct for voltage and loading, and reconductoring areas with old 6 copperweld conductor to 1/0ACSR improve voltage.

5. Replace the underrated disconnects switches at Columbia Heights Substation.

6. Perform analysis to determine the underground feeder get a way ampacities at substations. Variables that need to be identified include identifying the feeders that run in a common ductbank, load factor for feeders in common ductbanks, burial depth of ductbank, and backfill material (i.e., sand, concrete, dirt). This will help the PUD better understand the capacity limits for each feeder.

7. The transformer at Tygh Valley and Seufert substations have reached the expected service life of between 40 and 60 years. Oil sample analysis should be conducted annually and after exposure to through faults to monitor for indications of pre failure until the transformer can be replaced.

Recommended System Improvements – Future Years The analysis performed for an outage of a substation or substation transformer identified two vulnerabilities in the existing system configuration and equipment capacities. If Columbia Heights or Seufert substations were out of service, the surrounding feeders and substation could not pick up all of the system and meet the planning criterial requirements. The projects listed under the High Priority Projects were selected to address these issues.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 5

High Priority Projects

1. Add the second transformer to Columbia Heights Substation and a fifth distribution feeder position. Move one feeder from the existing transformer to the new transformer.

Rebuild, reconductor, and reconfigure the distribution feeders.

2. Construct the new Highway 197 substation with a 12/16/20MVA transformer and at least two feeders. Construct, rebuild, reconductor, and reconfigure the distribution feeders.

Medium Priority Projects

1. Construct the River Road Substation with a 12/16/20MVA transformer and three underground feeders and ductbanks. Construct, rebuild, reconductor, and reconfigure the distribution feeders using option 2, underground circuit crossing I 84 underground feed from the new Feeder 1 circuit. Note, this project is highly dependent on the potential industrial load grown in the north area of The Dalles and may change in priority ranking based on the timing of the industrial loads in the area.

2. Replace the substation power transformer and bus structure at Tygh Valley with a 5/6.25 MVA transformer due to age. The larger size transform provides capacity to back up Wasco Electric Cooperation (WEC) loads. Having the ability to provide backup to WEC could lead to an agreement with WEC to provide backup for the PUD’s load in Tygh Valley.

Low Priority Projects

1. Replace the substation power transformer at Seufert Substation with the same size unit due to age.

Planning level cost estimates were developed for budgeting purposes for each of the recommended projects. The planning level cost estimates are grouped by substation area as the substation projects drive the addition of new feeders and reconstruction of existing feeders.

Table 1 4 Planning Level Cost Estimate Summary

Proje ct Description Total Cost

1 River Road Substation

New Substation 20MVA, 3 Feeder Bays, New Feeders, Feeder Improvements $3,718,000 2 2nd Street Substation Feeder Improvements $18,200 3 10th Street Substation Feeder Improvements $291,000

Columbia Heights Substation

New Transformer 25MVA, 1 Feeder Bay, New Feeder, Upgrade Disconnect Switches, Feeder Improvements $1,271,300

5 Seufert Substation New 14MVA Transformer $909,500

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 6

Table 1 4 Planning Level Cost Estimate Summary

Proje ct Description Total Cost

6 Tygh Valley Substation New Substation with a 5/6.125MVA Transformer $1.041.600 7 Highway 197 Substation

New Substation 20MVA, 2 Feeder Bays, New Feeders, Feeder Improvements $2,991,200

Total $10,240,800

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 7

Section 2 – Introduction

The Northern Wasco County People’s Utility District (PUD) is a public utility located in Wasco County, Oregon. The PUD provides electric service to approximately 9,862 customers. The PUD owns and operates approximately ten (10) miles of 115 KV transmission; twenty seven (27) miles of 69 KV transmission; two hundred thirty nine (239) miles of distribution; and eight (8) electrical substations throughout its ninety five (95) square mile service territory. The PUD’s service territory includes the City of The Dalles and the communities of Dufur, Tygh Valley and Wamic.

The PUD engaged EES Consulting (EES) to assist with the preparation of a Fifteen Year System Planning Study and Condition Assessment for its electric power system. The purpose of the study is to review the capacity and configuration of the PUD’s electric power delivery system, and its ability to reliably and efficiently meet the projected load increase over the next fifteen years. In addition, EES reviewed the substations and equipment and provides an opinion as to their overall condition. The system analysis included analyzing the existing and future performance of the electric grid in comparison the established planning criteria and a condition assessment of the substation equipment. An outage study for each substation was performed and a switching plan developed to attempt to service all loads. A capital plan with system improvements was developed to address areas that did not meet the planning criteria requirements.

Overview of the Company Electrical System The PUD’s power delivery system includes seven distribution substations, one primary delivery substation dedicated to a single customer, a transmission substation, 115kV and 69kV transmission lines, and a 12.47 kV distribution system with 14 PUD feeders.

The PUD takes service from the Bonneville Power Administration (BPA) at multiple points throughout the system, and provides services to Wasco Electric Cooperative (WEC) at the 10th Street substation and from the 69kV line. Table 2 1 lists the PUD’s substations and approximate dates of the original substation and upgrades of major equipment. See Section 6 Condition Assessment for a description of the substations.

Table 2 1 Substation Transformer Data

Substation Transformer Capacity

(MVA) Number of Feeders Approximate Year Second Street 2 - 12/16/20 7 1994

10th Street 15/20/25 4 (2 feeders are spare) 1980 Columbia Heights 15/20/25 4 Upgraded Tsf 2006 & Recl. 2009

Dufur 5/6.5 2 Rebuilt 2010 Seufert 10/14 2 1975

Tygh Valley 1.5 1 1949 Substation Transformer, 1962 wooden bus structure, V-Regs 2013, Recloser 2013

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 8

Table 2 1 Substation Transformer Data

Substation Transformer Capacity

(MVA) Number of Feeders Approximate Year Discovery 1 Customer Owned 2014, 115kV Equipment Only Three-Mile 1 7.5 0 2005

1. Not included in the scope of this study

The PUD owns and operates sections of the 115kV transmission system that interconnects Discovery, The Dalles, Second Street, Columbia Heights, Seufert, and Three Mile substations as well as the 69kV transmission line serving Three Mile, Dufur, and Tygh Valley substations. The PUD takes delivery of power from BPA at the Big Eddy Substation and has a connection to BPA at The Dalles substation. The Three Mile substation steps the voltage down from 115kV to 69kV through a 7.5 MVA transformer and the far end of the line is open just past the Tygh Valley substation.

Voltage regulation at the distribution primary voltage level is achieved through load tap changing transformer or bus voltage regulators. Voltage settings range from a 120 to 123 volt band center on a 120 volt base and a few substations use line drop compensation. The bandwidth is 3V (+/ 1.5V of band center) and a time delay of 30 to 45 seconds is used between tap changes. Table 2 2 provides a list of types of the voltage control devices for each substation.

Because of the long and radial nature of the PUD’s feeders, line voltage regulators are used in two locations. Both single phase and banks of single phase regulators are installed.

Table 2 2 Voltage Regulator/LTC Data

Element Name Regulator Amp

Rating Regulator CT

Rating Regulator Equipment

Regulator Output Volts

Tygh Valley Fdr 71 Line Regs 100 100 76.2kVA 126 Tygh Valley Substation Reg 100 100 76.2kVA 124.5 Dufur Substation Bus Regs 328 400 250kVA 122.5 Seufert Feeder 42 15 mile Line Regs 150 150 115kVA 123.5 Seufert Substation Bus Regs 519 400 1120kVA 121 Second Street LTC T1 1 926 1100 2nd St LTC 124 Second Street LTC T2 1 926 1100 2nd St LTC 124

10th Street Substation Bus Regs 875/1166 1000 2000/2667kVA, OAFA 123

Columbia Heights LTC 1 1157 1200 Col Hgts LTC 123.5

1. At nominal tap of 12.47kV, 841a at raised tap 16.

There are nine capacitor banks located on poles throughout the distribution system, where one capacitor bank is located just outside of the 10th Street substation. These banks are sized to provide 300 to 900 kVAR of fixed compensation. At this time, there are no switched capacitor banks in the system. Additionally, there are no capacitors in the PUD’s substations. Table 2 3 provides a list of the capacitor banks and their sizes.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 9

Table 2 3 Distribution Line Capacitor Data

Feeder Element

Name Type Upline Source Section Name Phases Size kVAR

Fdr 12 C-8 Capacitor 2nd Street Sub OH8469 ABC 450 Fdr 12 C-9 Capacitor 2nd Street Sub OH8468 ABC 450 Fdr 23 C-1 Capacitor 10th Street Sub OH4605 ABC 900 Fdr 23 C-6 Capacitor 10th Street Sub OH5568 ABC 450 Fdr 23 C-7 Capacitor 10th Street Sub OH5607 ABC 450 Fdr 24 C-5 Capacitor 10th Street Sub OH5732 ABC 300 Fdr 24 C-10 Capacitor 10th Street Sub OH6002 ABC 900 Fdr 34 C-3 Capacitor Columbia Hgts Sub OH2195 ABC 450 Fdr 34 C-4 Capacitor Columbia Hgts Sub OH2196 ABC 450

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 10

Section 3 – Study Overview

This section describes an overview of the approach used in the Study. It lists the assumptions and data used to construct the model, allocate load, and conduct the analysis.

Contributions Data used in this study was provided by Paul Titus, Assistant General Manager and Director of Engineering. EES conducted a field visit in the fall of 2014 to review the substations and selected other assets.

Data Data provided by the PUD for use in this study included:

Geographic feeder maps in GIS shape file format Substation one line drawings Transmission one line diagram Feeder metering records 2011 2013 Monthly peak System load data 2014 for BPA Meter Data Feeder Data Recordings January 2016 (Included Power Factor Readings) Billing data for major commercial loads BPA Load Forecast 2016 2030 BPA Load Forecast 2016 2025 MOD 017 18

Assumptions Modeled load was allocated by connected kVA at the feeder level.

Some line sections in GIS were missing conductor or cable definition information.

o Where conductor information was unknown, #4 ACSR was assumed o Where cable information was unknown, #2 XLPJ was assumed

Where transformers in GIS were missing rated kVA, 25 kVA was assumed Feeder level power factor data was provided from Feeder Data Recordings.

Model was developed based on best information available. Field measurements should be used for verification before implementing certain system improvements.

Distribution SystemModel EES prepared a distribution system engineering analysis model (model) using Milsoft WindMil® version 8.1.3.2741. The model is a geographic representation of the medium voltage distribution system that includes electrical connectivity data, permitting unbalanced load flows, and detailed analysis of circuit condition. The model was digitized over a GIS feeder map provided by the PUD. The model includes feeder and lateral parameters such as routing, length, conductor size, phase, connected kVA, and other technical details supplied by the PUD in the

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 11

form of GIS files. The model was used to conduct the bulk of the analysis for this planning study.

Appendix B has a map that graphically shows the entire model as it was configured for Year 1 (2015) analysis.

Modeled Load Allocation The peak monthly feeder kW or kVA data was recorded by PUD from 1998 through 2013 as well as total system load data from BPA billing information for 2014. The more recent feeder data, from 2011 to 2013, was used for determining feeder peak loads in the analysis as this reflects current loads and configurations. Some metering data was observed during scheduled substation visits, but was limited in nature. Updated feeder data was provided in January 2016, which agreed with the historic feeder peaks and provided the power factor for each feeder.

This data was within the expected values when compared to the historic monthly peak data.

The feeder peak data is non coincident feeder peaks and when summed at the substation level is higher than the BPA non coincident substation loads as expected. This information was used to allocate loads out on the feeders within the WindMil model.

The PUD’s annual system coincident peak demand from the BPA data of 62.2 MW occurred in February 2014. The total energy purchased from BPA for 2014 was 271,141,313 kWh with January 2014 being the highest month of 29,091,882 kWh purchased. The 2014 system load factor was 49.8 percent. These data are shown in Figures 3 1.

Figure 3 1 PUD System Coincident Peak

The system annual non coincident peak demand of 74.6 MW occurred in December 2013. The peak is the sum of the month feeder peaks that occurred in December of 2013. Figure 3 2 is a graph showing the non coincident month peak from 2011 through 2013.

20000 40000 60000 80000

Ja nu ar y

Fe br ua ry

M ar ch

Ap ril

M ay

Ju ne Ju ly

Au gu st

Se pt em be r

O ct ob er N ov em be r

De ce m be r

System Month Peak (kW)

CSP SystemPeak KW 2014

10000000 20000000 30000000 40000000

Ja nu ar y

Fe br ua ry

M ar ch

Ap ril

M ay

Ju ne Ju ly

Au gu st

Se pt em be r

O ct ob er N ov em be r

De ce m be r

Month kWh

HLH KWH LLH KWH

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 12

Figure 3 2 PUD Non Coincident Feeder Peak Total

The WindMil model was calibrated to represent the system as it was configured during the peak. To accomplish this calibration, the individual feeder demand in kW recorded over the 2011 to 2013 time period was allocated to each corresponding circuit. This demand number is the non coincident feeder peak load, which represents the highest loading each individual feeder experienced during the three year period. The feeder peaks were normalized to address temporary load switching. The power factor was provided with the updated feeder data in January 2016. The peak load data from the updated feeder data was in line with the feeder peaks from 2011 to 2013. Table 3 1 below shows the peak load that occurred over the 2011 to 2013 time frame. Appendix A shows the loads by feeder for 2011 2013.

Table 3 1 Normalized Non Coincident Feeder Loading

Substation Feeder # Feeder Name Load Normalized

Peak Power

Factor 1, 3 % Imbalance 2 Second Street Fdr 11 Cascade Sq. KVA 4,550 95% 8% Second Street Fdr 12 Downtown KVA 8,258 98% 8% Second Street Fdr 13 Riverfront KVA 3,139 98% 3% Second Street Fdr 14 NWA Top KVA 6,976 - 92% 0% Second Street Fdr 15 W 2nd St KVA 5,155 98% 4% Second Street Fdr 16 NWA Bottom KVA 187 96% 0% Second Street Fdr 17 RDWena KVA 3,074 99% 29%

10th Street Fdr 23 Rowena KVA 7,336 98% 11% 10th Street Fdr 24 West 10th ST KVA 9,158 98% 3%

Col Hts Fdr 31 Scenic KW 9,680 98% 13% Col Hts Fdr 32 3 Mile/1st KW 2,700 98% 32% Col Hts Fdr 33 Dry Hollow KW 6,300 98% 14%

30,000

40,000

50,000

60,000

70,000

80,000

Fe b

Ap r

Ju n

Au g

O ct

De c

Fe b

Ap r

Ju n

Au g

O ct

De c

Fe b

Ap r

Ju n

Au g

O ct

De c kW /k

VA

Total System Monthly Non Coincident Peak (Sum of Feeder Monthly Peak)

Fdr kW/kVA

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 13

Table 3 1 Normalized Non Coincident Feeder Loading

Substation Feeder # Feeder Name Load Normalized

Peak Power

Factor 1, 3 % Imbalance 2 Col Hts Fdr 34 G St KW 6,900 99% 5% Dufur 3 Fdr 61 Southwest KW 1,160 98% 8% Dufur 3 Fdr 62 Northeast KW 1,100 98% 3% Seufert Fdr 41 Hospital/3 Mile KW 907 99% 13% Seufert Fdr 42 Celilo KW 7,056 99% 15%

Tygh Valley 3 Fdr 71 Tygh Valley KW 1,300 99% 14%

1. Winter power factor.

2. Imbalance at feeder source, [1 avg(amps)/max(amps)]

3. Data is from updated meter readings provided January 2016

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 14

Section 4 –Planning Criteria

This section of the report summarizes the planning criteria used to guide the distribution system analysis and development of the recommended projects. EES worked with the PUD staff to establish the planning criteria. The planning criterial will be applied to electric system for all planning years.

Introduction A system plan should be developed to provide adequate, reliable, and quality service at a reasonable cost to all consumers. The planning criteria helps establish thresholds and guidelines as to when system improvements are warranted.

Forecasted and Projected Load Scenarios The PUD should continue to update its load forecast every year coincident with BPA’s integrated resource planning requirements.

Equipment and Conductor Maximum Capacity/Loading Each of the following equipment items should not be thermally loaded by more than the percentage shown of its nameplate rating, evaluated on an individual basis. Table 4 1 lists the equipment loading criteria.

Table 4 1 Equipment Loading Criteria

Equipment Criteria Substation Transformers

All except Second Street, Dufur, and Tygh Valley 75% Normal Configuration (100% Emergency)

Second Street Substation Transformers 50% Normal Configuration (100 % Emergency) Dufur, and Tygh Valley Substation Transformers 100% Normal Configuration (100 % Emergency) 1

Voltage Regulators (same exceptions as Transformers) 75% Normal Configuration (100 % Emergency) Oil Circuit Breakers/Reclosers 70% (100 % Emergency)

Vacuum Circuit Breakers/Reclosers 90% (100 % Emergency) Line Fuses 95% (100 % Emergency)

Conductors Non-Ties 75% Normal Configuration (100% Emergency) Conductors Ties 50% Normal Configuration (100% Emergency)

1. Does not backup other PUD substations, allow to reach 100% capacity for normal configuration.

The basis of the equipment loading criteria is to allow for contingency switching, where two or more substation transformers or feeders would be needed to pick up a substation transformer or feeder outage.

The maximum ampacities for conductor and cable loading are stated in Table 4 2 and Table 4 3 below. Allowable ampacities for overhead conductors are based upon a wind velocity of 2 feet per second, emissivity and solar absorption = 0.5, and a conductor temperature of 75°C. The copper, copperweld, and ACSR conductor ampacities were derived from the ABB (old

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 15

Westinghouse) Electric Transmission and Distribution Reference Book. The AAC conductor ampacities were derived from the Southwest Overhead Conductor Manual, Table 1 21.

Table 4 2 Overhead Conductor Ampacity

Normal

Conductor 25° C Ambient Winter #6 Cu 120 #4 Cu 170 #2 Cu 230 1/0 Cu 310 2/0 Cu 360 3/0 Cu 420 4/0 Cu 480

#8A CWC 100

#8C CWC 100

#6A CWC 140

#6C CWC 130

#4A CWC 180

#2A CWC 240

#4 AAC 138

#4 ACSR 140

#2 AAC 185

#2 ACSR 180

1/0 ACSR 230

2/0 ACSR 270

3/0 ACSR 300

4/0 ACSR 340

336.4 MCM AAC 513

556.6 MCM AAC 703

Underground cable ampacities for #2 and 1/0 are determined from NEC Table 310.60(C)(78) Figure 310.60 Detail 1 with a maximum operating temperature of 90°C. This covers a single circuit in a conduit (direct buried or in concrete ductbank). Underground cable ampacities for #4/0 and larger are based on values from NEC Table 310.60(C)(78) Figure 310.60 Detail 2 with a maximum operating temperature of 90°C. This covers two or three circuits in separate conduits (direct buried or in concrete ductbank) and includes the effect of mutual heating from an adjacent circuit in the same ductbank. Adjustments were made for a 50 percent load factor.

The 1000 MCM cable uses the Prysmain EPR Doubleseal ampacity ratings.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 16

Table 4 3 Underground Conductor Ampacity

Conductor Normal #2 Aluminum 120

#1/0 Aluminum 155 #4/0 Aluminum 231

350 MCM Aluminum 305 750 MCM Aluminum 475

1000 MCM Aluminum 90oC 530 1000 MCM Aluminum 105oC 580

Economic Conductor Selection The economic conductor selection guidelines will provide for the lowest ownership cost for reconductoring or constructing new distribution lines, which includes initial capital costs plus the cost of losses. Initial conductor loading for overhead single phase lines should be between 20 and 40 percent of winter ampacity depending on load growth. Initial conductor loading for overhead three phase lines should be between 30 and 50 percent of winter ampacity depending on load growth. The higher the load growth the lower initial loading.

Underground conductors have a much lower ampacity for the same resistance and therefor will have a higher initial percent loading than there overhead counterpart for the same line losses.

The initial loading for underground conductors should be around 70 percent, provided there is sufficient capacity for future growth.

Table 4 4 Economic Overhead Conductor Selection Guide – Initial Loading

Single-phase load Amps (min) Amps (max) kVA (min) kVA (max) Conductor

0 56 0 403 4 ACSR

48 92 330 662 1/0 ACSR

Three-phase load Amps (min) Amps (max) kVA (min) kVA (max) Conductor

0 70 0 1,512 4 ACSR

69 115 1,490 2,484 1/0 ACSR

102 170 2,203 3,672 4/0 ACSR

154 257 3,324 5,540 336.4 AAC

211 352 4,555 7,592 556.5 AAC

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 17

Voltage Drop Voltage levels shall fall within the ANSI C84.1 Range A for normal operation (114 126 volts on a 120 volt base from the substation bus to the customers’ meter for normal system configuration). Voltage drop shall not exceed 8 volts for normal service or 118V on the primary voltage line, and 12 volts for emergency service or 114V on the primary voltage line. This is allows an additional 4 volt drop (3.33 percent) across the distribution transformer and secondary conductors.

Figure 4 1 ANSI C84.1 Voltage Ranges

Power Factor Power factor at the feeder level should be 95 percent or higher. Leading power factors should be avoided.

Protection and Sectionalizing The PUD should review its protective device coordination study every five years to account for system changes, or when major system changes occur.

Reliability Conductors should be replaced if found to contain an average of over 2 splices per phase per span in a 1 mile (1.6 kilometers) section.

No more than an average of 5 consumer outage hours, per consumer, per year, excluding outages caused by major storms or the power supplier, for the last 5 consecutive years in any specific area.

Load and Phase Balance When building or reconfiguring primary distribution lines, effort should be made to balance load between phases throughout the circuit when possible, typically between switch points along the circuit or at a third and at two thirds of the circuit length. This may be accomplished

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 18

through modeling the anticipated load or selecting the phase of the new tap as different from those geographically adjacent to the location.

Load balancing between feeders should be achieved to reduce losses and to balance reliability.

Consideration should be given to the magnitude of the load, the percent line losses (takes conductor sizes into consideration), the number of customers, the length of the circuit, and the any critical loads on the circuits.

Load Shifting Capabilities Feeder Redundancy The PUD should aim to provide redundancy by creating ties between feeders where practical, to provide an alternate feed for customer load in the event of an outage.

For substations with multiple transformers, the load from loss of one transformer should be picked up be the remaining transformers.

For the loss of a feeder, the load should be switch to an adjacent feeder (same substation or neighboring substation) by opening one switch and closing a tie switch for normal load conditions.

Age As equipment reaches it expected end of life, it should be closely monitored, inspected, and assessed for replacement.

Facilities that reach their life expectancy with in the planning window will be scheduled for replacement with in the 5 years.

Table 4 5 Equipment Life Expectancy

Equipment/material Service Life Substation Recloser/Breaker 50

Substation Relays 30 Substation Transformers 40

Poles 50 Conductors 50 Crossarms 50 Line Fusing 30

Line Regulators 30 Line Reclosers/Sectionalizers 30

Safety Primary distribution lines should be recommended for rebuild if they are found to be unsafe or in violation of the National Electric Safety Code (NESC) associated with the year the line was built.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 19

Section 5 – Existing System Review

EES performed unbalanced load flow computations and contingency analysis at the Year 1 non coincident feeder peak to evaluate the existing system’s performance relative to the established planning criteria.

Modeled load flows indicate that voltage drop on the primary system exceeds the recommended planning criteria of eight volts on a 120 volt base in several areas during Year 1 non coincident feeder peak conditions.

Power Transformers Most of the substation power transformers have adequate capacity under normal system configuration to serve the existing load during the Year 1 and Year 15 system peak loads. The Columbia Heights transformer has exceeded its top OA/FA/FA rating of 25MVA. The system does not have sufficient capacity to serve all loads if either the Columbia Heights or Seufert substation are out of service. The transformers at Second Street, Columbia Heights, and Tygh Valley are exceeding the planning criteria limit, 50 percent of capacity for both transformers at Second Street and 75 percent of capacity at the other substations. The remaining substation transformers are loaded below the planning criteria limits, as shown in Table 5 1 below. The Discovery substation is a customer owned facility and the Three Mile substation is a transmission substation and are not included in the scope of this study.

The transformer at Tygh Valley and Seufert substations have reached the expected service life of between 40 and 60 years. Oil sample analysis should be conducted annually and after exposure to through faults to monitor for indications of pre failure until the transformer can be replaced.

Table 5 1 Power Transformer Loading

Substation Transformer Load (kVA)

Rating (kVA) % Loading

% of Planning Limit Mfgr Yr Age

Second Street T1 1 12,377 4 20,000 62% 124% 1994 21 Second Street T2 1 13,752 20,000 69% 138% 1994 21

10th Street 2 16,495 25,000 66% 88% 1980 3 35 Columbia Heights 1 25,200 25,000 101% 134% 2006 9

Dufur 5 2,257 6,500 35% 46% 2010 5 Seufert 1 7,805 14,000 56% 74% 1975 40

Tygh Valley 1,300 1,500 87% 116% 1949 66

1. Data from meters on transformer bank

2. Non-coincident summation of feeder loads

3. Assumed based on PCB tag

4. A peak of 16,106MVA was recorded on October 12, 2012. This peak was significantly higher than recorded peaks and was assumed to be due to load switching. The next largest recording of 12,377 was used as the normalized peak.

5. Peak from 2015 data recording.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 20

Substation and Line Voltage Regulators Second Street and Columbia Heights substations have load tap changers (LTC) integrated into the substation power transformers. The remaining substation have substation bus voltage regulators that regulate the voltage for all down line feeders. The LTC at Columbia Heights has exceeded its rating and bus voltage regulators at 10th Street substation are at their full capacity.

The bus voltage regulators at Seufert Substation are reaching 75 percent of their full capacity.

The remaining substation and the line voltage regulators are below the planning criteria loading limits. See table 5 2 for information on the loading of the LTC’s and voltage regulators.

Table 5 2 December 2014 Substation Voltage Regulator Loading

Element Name Regulator

Amp Rating

Regulator CT Rating

(Amps) Regulator Equipment

Regulator Output Volts

Load Amps

Capacity

Tygh Valley Substation Reg 100 100 76.2kVA

124.5 46 46 Tygh Valley Fdr 71 Line Regs 100 100 76.2kVA 126 15 15 Dufur Substation Bus Regs 328 400 250kVA 122.5 68 24

Seufert Substation Bus Regs 519 400 1120kVA 121 388 76 Seufert Fdr 42 15mile Regs 150 150 115kVA 123.5 46 34

Second Street LTC T1 925 1 1100 20MVA 124 1480 69 Second Street LTC T2 925 1 1100 20MVA 124 1480 69

10th Street Substation Bus Regs 875/1166 1000

2000/2667kVA

OAFA 123 763 94

Columbia Heights LTC 1157 1 1200 25MVA 123.5 1211 105

1. At nominal tap of 12.47kV, 841a at raised tap 16

Capacity Limits Several system components were reviewed to determine the maximum capacity for each feeders. The equipment reviewed included the substation recloser, the substation disconnect switches, the substation feeder get a ways, and the feeder main back bone conductor. Some feeders also had a secondary back bone conductor where the conductor size change within a short distance of the substation. Table 5 3 lists the capacities for each feeder and the equipment limiting the capacity.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 21

Table 5 3 Feeder Capacity Limits

Substation Feeder # Limiting Equipment Capacity Limit

(Amps) Capacity Limit

(kVA) Second Street Fdr 11 Recloser 560 12,095 Second Street Fdr 12 Recloser 560 12,095 Second Street Fdr 13 336ACSR Back Bone 513 11,080 Second Street Fdr 14 336ACSR Back Bone 513 11,080 Second Street Fdr 15 336ACSR Back Bone 513 11,080 Second Street Fdr 16 336ACSR Back Bone 513 11,080 Second Street Fdr 17 Recloser 560 12,095

10th Street Fdr 23 Recloser 560 12,095 10th Street Fdr 24 Recloser 560 12,095

Col Hts Fdr 31 Substation Disconnects 600 12,959 Col Hts Fdr 32 Substation Disconnects 600 12,959 Col Hts Fdr 33 336ACSR Back Bone 513 11,080 Col Hts Fdr 34 Substation Disconnects 600 12,959 Dufur Fdr 61 336ACSR Back Bone 513 11,080 Dufur Fdr 62 336ACSR Back Bone 513 11,080

Seufert Fdr 41 3/0 ACSR Back Bone 300 6,479 Seufert Fdr 42 3/0 ACSR Back Bone 300 6,479

Tygh Valley Fdr 71 6C Back Bone 130 2,808

Distribution Circuits The non coincident peak feeder loads were normalized to account for load switching over the 2011 to 2013 periods. Table 5 4 shows the peak feeder loads used in the power flow and voltage drop analysis.

Table 5 4 Normalized Feeder Loading

Substation Breaker Feeder # Feeder Name Load Normalized

Peak 2 % Imbalance Second Street B220 Fdr 11 Cascade Sq. KVA 4,550 8% Second Street B218 Fdr 12 Downtown KVA 8,258 8% Second Street B219 Fdr 13 Riverfront KVA 3,139 3% Second Street B214 Fdr 14 NWA Top KVA 6,976 0% Second Street B215 Fdr 15 W 2nd St KVA 5,155 4% Second Street B216 Fdr 16 NWA Bottom KVA 187 0% Second Street B217 Fdr 17 RDWena KVA 3,074 29%

10th Street 5B506 Fdr 23 Rowena KVA 7,336 11% 10th Street 5B502 Fdr 24 W 10th St. KVA 9,158 3%

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 22

Table 5 4 Normalized Feeder Loading

Substation Breaker Feeder # Feeder Name Load Normalized % Imbalance Col Hts 5B510 Fdr 31 Scenic KW 9,680 13% Col Hts 5B512 Fdr 32 3 Mile/1st KW 2,700 32% Col Hts 5B511 Fdr 33 Dry Hollow KW 6,300 14% Col Hts 5B507 Fdr 34 G St KW 6,900 5% Dufur 8B5 Fdr 61 Southwest 1 KW 1,160 8% Dufur 8B7 Fdr 62 Northeast 1 KW 1,100 26%

Seufert 5B513 Fdr 41 Hospital/3 Mile KW 907 13% Seufert 5B514 Fdr 42 Celilo KW 7,056 15%

Tygh Valley 5K515 Fdr 71 Tygh Valley KW 1,300 14%

1. Load from updated feeder data, January 2016.

2. Power factor data not available and assumed at 95 percent

EES performed power flow simulations on the electric distribution system model and identified areas of the system that did not meet the system planning criteria. The LTC’s and substation voltage regulators were set at 125V, which is higher than the settings that were observed during the field visit. Most of the issues involved conductor loading for major tie lines exceeding 50 percent of the thermal capacity and voltage levels that fell below the minimum voltage limit of 118 volts (on a 120V base) at the primary system voltage level. Nine of the 20 feeders are loaded above 50 percent of the conductors’ thermal capacity (planning criterial limit). Feeders 17, 23, and 71 have voltage levels below the minimum planning criterial of 118V on a 120 volt base. Appendix B contains feeder diagrams showing the voltage levels and conductor loading for sections that exceed the planning criteria. Table 5 5 provides a summary of loads, voltage, and conductor loading for each feeder. Total primary line losses were 1,161 kW at peak loads.

Table 5 5 System Performance

Substation Feeder Peak Load (KVA/KW) Losses (kW)

Maximum Conductor

Loading

Minimum Voltage Level (V)

Power Factor 1 Imbalance 2

Second Street Fdr 11 4,550 22.1 69% 123.4 95% 8% Second Street Fdr 12 8,258 146.5 78% 119.9 98% 8% Second Street Fdr 13 3,139 13.1 30% 123.7 98% 3% Second Street Fdr 14 6,976 31.9 64% 123.3 - 92% 0% Second Street Fdr 15 5,155 23.5 47% 123.8 98% 4% Second Street Fdr 16 187 0.0 2% 125.0 96% 0% Second Street Fdr 17 3,074 113.7 65% 112.4 99% 29%

10th Street Fdr 23 7,336 123.9 55% 107.3 98% 11% 10th Street Fdr 24 9,158 169.5 87.4% 119.6 98% 3%

Col Hts Fdr 31 9,680 165.1 107% 120.3 98% 13% Col Hts Fdr 32 2,700 10.6 67% 123.5 98% 32% Col Hts Fdr 33 6,300 55.7 94.2% 122.0 98% 14%

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 23

Table 5 5 System Performance

Substation Feeder Peak Load (KVA/KW) Losses (kW)

Maximum Conductor

Loading

Minimum Voltage Level (V)

Power Factor 1 Imbalance 2

Col Hts Fdr 34 6,900 33.0 45% 123.8 99% 5% Seufert Fdr 41 907 0.9 32% 125.8 98% 8% Seufert Fdr 42 7,056 179.8 97.8% 118.3 98% 26% Dufur 3 Fdr 61 1,160 2.1 32.7% 124.3 99% 13% Dufur 3 Fdr 62 1,100 1.0 15.7% 124.6 99% 15%

Tygh Valley 3 Fdr 71 1,300 69.2 57.8% 114.5 99% 14%

1. Winter power factor.

2. Imbalance at feeder source, [1 avg(amps)/max(amps)]

3. Data is from updated data provide January 2016

The peak demand on all circuits is below the thermal limits of the conductor with the exception of one line section on Feeder 31. However, several feeders are exceeding the planning level limits of 50 percent for tie circuits. Table 5 6 below lists the tie conductors that exceed the planning criteria limits of 50 percent.

Table 5 6 Heavily Loaded Tie Line Sections (> 50 Percent)

Upline Source Upline Feeder Conductor

Element Name

Capacity Percentage

KW Thru Section

Miles From Source

2nd Street Sub Fdr12 1000ALJ UG8196 78 8258 0.03 2nd Street Sub Fdr12 750ALJ UG8322 78 6972 1.43 2nd Street Sub Fdr12 556.5 AAC OH8250 58 8243 0.13 2nd Street Sub Fdr14 336 AAC OH7803 66 6987 0.21 2nd Street Sub Fdr14 1000ALJ UG7787 65 7009 0.02 2nd Street Sub Fdr17 1/0C OH6838 62 2986 1.85 10th Street Sub Fdr23 556.5 AAC OH4612 55 7334 0.04 10th Street Sub Fdr24 336 AAC OH5763 85 9151 0.06 10th Street Sub Fdr24 1000ALJ UG5572 83 9158 0.02 10th Street Sub Fdr24 336 AAC OH5958 83 8812 0.26

Columbia Hgts Sub Fdr31 4/0 ACSR OH2305 108 7309 1.02 Columbia Hgts Sub Fdr31 556.5 AAC OH3010 64 9675 0.01 Columbia Hgts Sub Fdr31 1/0C OH2448 54 3379 1.41 Columbia Hgts Sub Fdr33 336 AAC OH1589 60 6300 0.10

Seufert Sub Fdr42 3/0ACSR OH3488 98 6022 0.55 Seufert Sub Fdr42 750ALJ OH3228 72 7058 0.03 Seufert Sub Fdr42 336 AAC OH3249 64 7043 0.30

Modeled load flows on the existing system indicate that some of the smaller conductors are exceeding their maximum thermal conditions (ampacity) at the non coincident system peak under normal feeder configuration. Table 5 7 below lists all of the non feeder tie conductors that exceed the planning criteria limits of 75 percent.

NORTHERNWASCO COUNTY PUD—CAPITAL NEEDS AND RELIABILITY STUDY 24

Table 5 7 Heavily Loaded Non Feeder Tie Line Sections (>75 Percent)

Upline Source Upline Feeder Conductor

Element Name

Capacity Percentage Thru kW Miles From Source

10th Street Sub Fdr24 4ACSR OH6495 87 2075 1.51

10th Street Sub Fdr24 4ACSR OH6512 87…