HomeMy WebLinkAbout2024-09-30 Study Session0
Ire Council Study Session Meeting Agenda
ASHLAND CITY COUNCIL
STUDY SESSION AGENDA
Monday, September 30, 2024
Council Chambers, 1175 E Main Street
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HELD HYBRID (In -Person or Zoom Meeting Access)
Public testimony will be accepted for both general public forum items and agenda items.
If you would like to submit written testimony or if you wish to speak electronically during the meeting, please
complete the online Public Testimony Form no later than 10 a.m. the day of the
meeting.
5:30 p.m. Study Session
1. PUBLIC FORUM
15 minutes — Public input or comment on City business not included on the agenda
II. USDA Update
USDA Loan - On -Bill Financing Update
III. Electric Master Plan
Electric Master Plan Council Communication
b. Electric Master Plan
IV. ADJOURNMENT
In compliance with the Americans with Disabilities Act, if you need special assistance to participate in this
meeting, please contact the City Manager's office at 541.488.6002 (TTY phone number 1.800.735.2900).
Notification 72 hours prior to the meeting will enable the City to make reasonable arrangements to ensure
accessibility to the meeting (28 CFR 35.102-35.104 ADA Title 1).
"`Agendas and minutes for City of Ashland Council, Commission and Committee meetings may be found at the
City website, ashlandoregon.gov,
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�::� Council Study Session
Date: September 30, 2024
Agenda Item
USDA Loan - On -Bill Financing Update
From
Mariane Berry, Finance Director
Contact
mariane.berry@ashland.or.us
SUMMARY
On June 15, 2021, Council approved Resolution 2021-15 Establishing the On -Bill Financing Program. Staff has
worked with the USDA Office of Loan Origination and Approval to provide the necessary financial documents for
approval under the program. USDA provided their approval on September 22, 2023 informing City of Ashland of
their loan commitment in the amount of $10,000,000.
We are at the loan agreement phase of the process. USDA does not have many municipalities as borrowers
under this program. Thus, in July 2024, the legal counsel for USDA requested that we bring in a nationally
recognized bond counsel who would provide a written opinion to USDA to complete the loan agreement. As such,
legal counsel for all parties continue to discuss the items that Bond Counsel has brought up, namely, borrowing
authority, security of debt, and lending of credit issue. Staff will provide the status of this discussion and the
anticipated timing of the program at the Study Session.
POLICIES, PLANS & GOALS SUPPORTED
N/A
BACKGROUND AND ADDITIONAL INFORMATION
FISCAL IMPACTS
N/A
SUGGESTED ACTIONS, MOTIONS, AND/OR OPTIONS
N/A
REFERENCES & ATTACHMENTS
None
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��, Council Study Session
Date: September 30, 2024
Agenda Item
Electric Master Plan Council Communication
From
Thomas McBartlett III, Director
Contact
thomas.mcbartlett@ashland.or.us
SUMMARY
This item is on the agenda to give Council the opportunity to review the recently completed Electric Master Plan
and to ask questions prior to the plan being brought to a regular business meeting for adoption.
POLICIES, PLANS & GOALS SUPPORTED
• Quality infrastructure and facilities through timely maintenance and community investment
• Safe and reliable delivery of electricity to Ashland residents and businesses
BACKGROUND AND ADDITIONAL INFORMATION
In August of 2023, with the approval of Council, the Electric Department authorized Stoddard Power Systems to
conduct a study of the City's electric system and develop a Master Plan. The purpose of the Plan is to do a
thorough evaluation of the City's electric infrastructure and make recommendations to meet future growth and
timely replacement of assets.
FISCAL IMPACTS
Funding for the plan was included in the current budget. Future fiscal impact from implementation of Plan
recommendations will be brought forward through future budget process and contract approvals
SUGGESTED ACTIONS MOTIONS AND/OR OPTIONS
DISCUSSION QUESTIONS
The Plan makes numerous recommendations, a few that are likely to spark discussion-
• Recommendation to implement AMI metering (smart meters)
• Recommendation to expand Mountain Ave. substation for increased capacity
• Recommendation to build a new substation on Nevada St. across from the existing Pacific Power
substation
Staff would like to bring the Master Plan to a regular Council Business Meeting in November for adoption.
REFERENCES & ATTACHMENTS
None
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CITY OF ASHLAND
ELECTRICAL SYSTEM MASTER PLAN
September 2024
Prepared For: pw.� I
gram
C 1 T Y OF
-ASHLAND
CITY OF ASHLAND
90 N. Mountain Avenue
Ashland, OR 97520
Version: DRAFT, 08/08/2024
FINAL, 09/09/2024
Prepared By: IgSTODDARD
S Y S T E M S
1600 VALLEY RIVER DRIVE, SUITE 380 ■ EUGENE, OR 97401 ■ PHONE (541)-228-9353
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Table of Contents
Chapter1 Introduction...............................................................................................................1-1
1.1
Purpose..........................................................................................................1-1
1.2
Project Authorization......................................................................................1-1
1.3
Scope of Work...............................................................................................1-1
Chapter 2 EXECUTIVE SUMMARY...................................................................................................2-1
2.1
General..........................................................................................................2-1
2.2
Major Improvements Since the 2013 System Study......................................2-1
2.3
Comments & Recommendations...................................................................2-1
Chapter3 Load Forecast...........................................................................................................3-1
3.1
General..........................................................................................................3-1
3.2
Historical Operating Systems........................................................................3-1
3.3
Weather -Related Considerations...................................................................3-1
3.4
Growth Forecasts...........................................................................................3-1
3.5
Conclusions...................................................................................................3-1
Chapter 4 System Planning Criteria.........................................................................................4-1
4.1
General..........................................................................................................4-1
4.2
System Loading.............................................................................................4-1
4.3
System Reliability...........................................................................................4-1
4.4
System Design...............................................................................................4-1
4.5
Capacitor Banks.............................................................................................4-1
Chapter 5 TRANSMISSION & SUBSTATION PLANNING......................................................................5-1
5.1
Transmission System....................................................................................5-1
5.2
Substation Systems.......................................................................................
5-1
5.3
Substation History and Ownership................................................................5-1
5.4
Improvement Discussion...............................................................................5-1
5.5
Implications of NERC Bulk Electric System Classification (BES)..................5-1
5.6
Conclusion.....................................................................................................
5-1
5.7
Recommendation...........................................................................................5-1
Chapter 6 DISTRIBUTION SYSTEM EVALUATION..............................................................................6-1
6.1
Background....................................................................................................6-1
6.2
Distribution System Capacity.........................................................................6-1
6.3
Distribution Equipment Inventory Review......................................................6-1
6.4
System Performance.....................................................................................
6-1
Chapter 7 POWER FLOW ANALYSIS............................................................................................... 7-1
7.1
Method........................................................................................................... 7-1
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 1
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7.2
Power Flow Case, Load Allocation and Results............................................7-1
Chapter 8 SHORT CIRCUIT ANALYSIS............................................................................................8-1
8.1
Method........................................................................................................... 8-1
8.2
Analysis Results.............................................................................................8-1
Chapter 9 Protective Device Coordination..............................................................................9-1
9.1
Method...........................................................................................................
9-1
9.2
Protection Criteria..........................................................................................9-1
9.3
Fuse Selection Examples..............................................................................9-1
9.4
Substation Protective Device Settings...........................................................9-1
9.5
Field Recloser and VFI Switchgear Settings.................................................9-1
9.6
Protective Device Coordination Curves.........................................................9-1
9.7
Analysis of Existing Settings..........................................................................9-1
9.8
Conclusions...................................................................................................9-1
Chapter 10
Renewable Energy............................................................................................10-1
10.1
General........................................................................................................10-1
10.2
Climate & Energy Action Plan (CEAP)........................................................10-1
10.3
Transition To Clean Energy.........................................................................10-1
10.4
Discussion and Recommendations.............................................................10-1
Chapter11
Appendix............................................................................................................11-1
A.
Time Current Curves....................................................................................11-1
B.
Drawings......................................................................................................11-1
C.
Model One Line............................................................................................11-1
D.
Power Flow Summary Results.....................................................................11-1
E.
Short Circuit Fault Results...........................................................................11-1
F.
Protective Device Coordination Additional Fuse Tables..............................11-1
G.
Information Request.....................................................................................11-1
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 11
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Chapter 1 INTRODUCTION
1.1 PURPOSE
The purpose of this study is to perform an electrical system evaluation and develop an orderly,
economic improvement plan for the City of Ashland Electric Department. The evaluation and
improvement plan is intended to help ensure that Ashland's electrical system has the
operational capacity, reliability, and flexibility to meet long-term planning criteria. The study
identifies and recommends system improvements that allow Ashland to supply adequate and
quality power to customers for the intermediate future (10 years) and practical improvements to
support long-term operations.
The study provides recommendations for modifications to existing facilities as well as new
construction to economically meet projected system load changes and growth so that no
facilities become obsolete or underrated early in their service lives. In addition, the study
considers impacts on the City's distribution system caused by known and planned Bonneville
Power Administration (BPA) and PacifiCorp facility modifications.
The recommendations presented in this report should be used as a guide by City of Ashland
management and staff in planning and implementing electrical system improvements.
Suggested improvements are based on projected system load growth and changing electrical
industry conditions with the aim of improving service quality and reliability while complying with
construction, operation, and safety standards.
This study was conducted based on the best available information at the time. Some
assumptions were necessary and are noted in the report. Any changes in equipment or system
configuration from the data used in this report may result in a change in recommendations.
Except where noted, this study evaluated the system as it was configured at the time the study
was performed.
Over time, conditions generally change, and these changes can affect the feasibility or
practicality of certain system improvements. This report should be reviewed and updated
periodically since changing system conditions, supply chains, and available technologies may
affect the economic viability or integrity of the recommended plans. By following an approach of
periodically reviewing and updating the plan, Ashland will maintain a valuable, up-to-date tool to
aid management and staff in the process of system operation, maintenance, and planning.
1.2 PROJECT AUTHORIZATION
In August 2023, City of Ashland Electric Department (Ashland) authorized Stoddard Power
Systems (SPS) to conduct a study of the City of Ashland Electric Department's Electric System
Master Plan. The study consists of various tasks as described in the Technical Proposal from
June 2023 and some detailed areas of concentration as identified during the project. This report
contains the results of the City of Ashland Electric System Master Plan.
1.3 SCOPE OF WORK
The following is a summary of the scope of services performed in this study.
SYSTEM PLANNING STUDY, CITY OFASHLAND-SEPTEMBER2024 1-1
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Load Forecast: Evaluation of the Ashland system -wide growth patterns based on
historical, recent (prior 10-year period) and expected future growth, from data provided
by the Ashland's Electric Department and population projections from the City of
Ashland, Jackson County, BPA, PacifiCorp and Regional Planners. This data is used to
estimate future feeder and substation peak loading throughout the system analysis
period and to determine recommended system improvements.
System Planning Criteria: Establishment of realistic planning criteria and objectives
upon which short-term and long-term planning are based. These planning standards
were used to determine loading guidelines, the appropriate level of backup support
under outage conditions, practical conductor sizes, acceptable voltage drop levels, and
improvement timing.
Transmission and Substation Evaluation: Evaluation of the existing transmission
system facilities serving Ashland for interconnection and switching flexibility, looping
capabilities, isolated segments, and overall operation and performance for power supply
and delivery to the Electrical Department facilities. Also, evaluation of the existing
substations' points -of -delivery for equipment ratings, capacities, and configurations. This
effort includes consideration of reliability, protection components, protection philosophy,
interruption frequency and duration, power availability and the ability to serve growth,
and operation and maintenance programs.
Analysis of the Existing System: Evaluation of the ability of the existing electric
system to provide economical, high -quality service in terms of component loading,
voltage levels, line losses, power factor, and reliability in the short-term and intermediate
future. This effort includes a review of the existing system performance based on the
following criteria:
• System reliability
• System capacity
• System flexibility
• System and feeder peak loads
• System construction practices
• Operation and maintenance policies
• Environmental sensitivity
• System equipment aging
• Identification of trouble spots and poorly performing equipment
• Review adequacy of system record keeping
Power Flow Analysis: Analysis of the City's electric system circuits using computer
modeling software. The system was modeled on a system -wide single-phase and three-
phase basis using Milsoft software package. The power flow analysis modeled the
system for the following conditions:
• Case 1 A Base Case Peak Load
• Case 1 B Base Case Light Load
SYSTEM PLANNING STUDY. CITY OFASHLAND - SEPTEMBER 2024 1-2
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• Case 2A
Ten -Year Growth Case
• Case 2B
Twenty -Year Growth Case
• Case 3A
Ashland Substation Transformer Out -Of -Service
• Case 3B
Mountain Avenue Substation Transformer Out -Of -Service
• Case 3C
Oak Knoll Substation Transformer K1 Out -Of -Service
• Case 3D
Oak Knoll Substation Transformer K2 Out -Of -Service
• Case 4A
AS/A2000 Business Feeder Out -Of -Service
• Case 4B
AS/A2001 North Main Feeder Out -Of -Service
• Case 4C
AS/A2002 Railroad Feeder Out -Of -Service
• Case 4D
MAS/M3006 N. Mountain Feeder Out -Of -Service
• Case 4E
MAS/M3009 Morton Feeder Out -Of -Service
• Case 4F
MAS/M3012 S. Mountain Feeder Out -Of -Service
• Case 4G
MAS/M3015 Wightman Feeder Out -Of -Service
• Case 4H
OKS/K4056 HWY 99 Feeder Out -Of -Service
• Case 41
OKS/K4070 HWY 66 Feeder Out -Of -Service
The Power Flow analyses performed for the conditions noted above identified the
system configuration voltage drops, load balance, real and reactive power flows, and
system losses at system buses as labeled. The results presented in the Power Flow
Chapter detail the analysis output reports.
Short Circuit Analysis: A short circuit analysis was performed under the Base Case
configuration to update the maximum fault availability throughout the system. The results
are presented in the Short Circuit Chapter with detailed fault data examples and analysis
output reports. The short circuit ratings for all equipment were evaluated for adequacy
based on the expected maximum short circuit currents.
Protective Device Coordination: The system coordination and protection were
evaluated using the system model developed for the power flow and short circuit
calculations. A time -current curve coordination chart showing the devices listed below is
presented for each distribution feeder:
• Transformer damage curve
• Conductor or insulation damage curve
• Maximum available short circuit symmetrical and asymmetrical fault current
• Time -current curves of primary protection devices
• Time -current curves of secondary protection devices
• Time -current curves of major backbone protection devices
The results are presented in detailed tabulation with recommended settings for existing
protective devices. In addition, analyses of coordination charts and recommended
protective device changes that will improve system reliability are provided. The
SYSTEM PLANNING STUDY, CITYOFASHL4ND - SEPTEMBER 2024 1-3
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development of a fusing application guide for the sizing of downstream fuses is also
provided.
Renewable Energy: The City of Ashland has a Climate and Energy Action Plan (CEAP)
implemented. Transition to clean energy by adopting electric appliances and electric
vehicles is a major part of the CEAP. The study discusses the existing situations of the
City's policy, program, load profiles, and challenges, and provides an overview of
potential actions that can be taken to prepare the electrical infrastructure for future
increased distributed renewable energy programs and steps to align system planning
with the City's CEAP to a practical extent.
Prepare Electric System Master Plan Report: A report summarizing the results of the
study is provided that includes:
• Documentation of references, planning criteria, related calculations, computer
reports, and techniques used in the analysis.
• Analysis and evaluation of the existing electric system, identification of alternative
improvement options and suggested areas that need focused attention.
• A list of conclusions, recommendations, and proposed system improvements
with projected construction timing and estimated costs.
• System maps and analysis plots showing the configurations and results of the
various study cases, including recommended system improvements.
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 1-4
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Chapter 2 EXECUTIVE SUMMARY
2.1 GENERAL
The City of Ashland's is presently serving approximately 12,817 customer meters. The City's
electric service area is surrounded by the Pacific Power (PacifiCorp) Medford service region.
All electric power sold by the City of Ashland is provided by Bonneville Power Administration
(BPA) and transmitted through PacifiCorp's 115 W transmission system. The City owns and
operates its distribution facilities (12.47/7.2 W) and takes service from three substations:
• Mountain Avenue Substation, which is now City -owned and was purchased from BPA in
March 2023. Mountain Avenue serves four (4) City distribution feeder circuits and has
two (2) spare positions.
• Ashland Substation, which is owned and operated by PacifiCorp, feeds a City -owned
distribution facility serving four City feeder circuits.
• Oak Knoll Substation, which is owned and operated by PacifiCorp, feeds three (3) City -
owned distribution feeder circuits.
Over the last 10 years, PacifiCorp has made improvements to the transmission system serving
the City of Ashland. The City's electric system is now served by a looped 115 W transmission
system with multiple backup sources. The transmission source to these substations is fed from
a ring bus at PacifiCorp's Baldy Switching Station located in the Medford region. Line 19
originates at the Baldy Switching Station and is then tapped becoming Line 82, providing
service to PacifiCorp's Oak Knoll Substation and continuing onto PacifiCorp's Ashland
Substation. Between Oak Knoll and Ashland Substations, the line is again tapped to serve the
BPA short transmission circuit feeding the City -owned Mountain Avenue Substation. Alternate
transmission sources are available to the Ashland area from PacifiCorp's Copco 2 and Sage
Road facilities. In addition to the two substations, PacifiCorp owns and maintains a few
distribution poles in and adjacent to the City's service territory and city limits.
The City's distribution system (12.47/7.2 W) consists of 52.7 miles of overhead three-phase and
single-phase primary circuitry; and 79.5 miles of three-phase and single-phase underground
primary circuitry. A high-level view of the City's electric distribution feeder system and service
territory is shown in Figure 2-1 and Figure 2-2, respectively.
In 2023 the City eliminated a substantial portion of the BPA Transfer Service Delivery Charge
per -kW -per -month for power delivered at 12.47/7.2 W by taking ownership of the Mountain
Avenue Substation. This change established a 115 W point -of -delivery transmission tap with
BPA's transmission line along Mountain Avenue that extends to the PacifiCorp circuit at the
Nevada Street intersection.
The City continues to have an exclusive power purchase agreement with BPA based on energy
and peak demand, and BPA has a General Transfer Agreement (GTA) with PacifiCorp for the
use of their transmission and substation facilities. The City pays $1.12 per kW per month for
delivery at 12.47 W at Ashland and Oak Knoll Substations. Delivery charges, substation
ownership, and transmission improvements are further discussed in Chapter 5.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 2-1
Pane 11 of 137
There is a strong correlation between ambient temperature (high and low) and peak loading on
the City's electric system. Evaluation of the electric system's load data indicates that its most
recent peak was 45.9 MW, which occurred in June 2021. In the evaluation period from 2004 to
2013, the highest system peak was 43.5 MW, and occurred in December 2013. Recent demand
records show that the City now has more of a summer peak pattern. We recommend the City
continue to monitor summer peak demands as equipment ratings under summer conditions
should not be overloaded and equipment (e.g., cables) full -load ratings are lower than under
winter conditions due to the inherently higher ambient temperature in the summer. Historical
data, weather trends, and future system growth are further discussed in Chapter 3.
Figure 2-1: City of Ashland Electric Distribution Feeder System Map
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-2
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Fo
Ashland Service Territory 2022
Ashland City Limits f
Service Territory 2022: 9.17 square miles
Possible Future Expansion
�' r"• Locations w/ Equipment
I , (beyondprevrars service boundary)
16
� I
I r
Date Prepared: 4/19/2022
h Ry
0 0.25 0.5 r 1 Miles
1,500 3,000 6,000 9,000Feet
Figure 2-2: City of Ashland Electric System Service Territory
Ashland's annual energy usage from 2003 to 2023 was around 175,000 MWh with an
approximate 5,300 MWh (or 3%) standard deviation. A slight decreasing energy useage trend
appeared in the last two years, partly because only 2/3 of the Mountain Avenue Substation load
was captured due to a blown PT fuse from June 2022 through September 2023. Additionally,
there has been an increase in PV installations around the City that may be contributing to the
decrease. Overall, the relatively consistent annual energy use indicates that there is an unlikely
potential for a new summer or winter energy consumption peak until an extreme cold or hot
weather event is experienced. Presently the City's electric system infrastructure is sized
adequately to serve expected peak system loads.
Based on available system load data and the assumptions used for this study, there is sufficient
substation transformer and distribution system circuit capacity to serve the City's expected peak
demand load through 2033, under normal operating conditions. However, the loss of any single
major system component (`single -contingency' failure condition) could result in a reduction of
the overall system capacity to below the capability to serve potential historic peak demand.
Single -contingency limitations and concerns are described in greater detail in Chapter 5 and
Chapter 7.
The conclusions and recommendations throughout the remainder of this section are based on
the overall goal of maintaining adequate substation capacity, and a flexible distribution system
available to reliably serve existing and future projected loads.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-3
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2.2 MAJOR IMPROVEMENTS SINCE THE 2013 SYSTEM STUDY
In the 11 years since the previous study, some significant electric system changes have taken
place that improved service and reliability to the City's electrical department customers. Major
improvements are listed below.
2.2.1 Transmission
PacifiCorp's upgrade from the 69-kV source at Ashland Substation to 115-kV significantly
increased the capacity from that source. Additionally, other PacifiCorp Medford regional area
transmission system upgrades and reconfigurations enabled other strong backup sources to the
Ashland transmission loop.
2.2.2 Substations
Mountain Avenue Substation
The City's purchase of the Mountain Avenue Substation from BPA is a significant adjustment in
power transformation charges for the City. It will now allow the electric system to expand,
monitor, and improve facilities at this substation as deemed necessary. Although the City had
previously owned the 12.47/7.2 kV distribution facilities at this substation, they now own the
property, all high -voltage components, and the control building. Suggestions for operation and
maintenance improvements at this site include:
a) One -day training session by a capable engineering group for City staff and crews that
will operate and maintain this facility. Training should include:
• Explanation of the existing facility's purpose and function (control building to yard)
• Review of all substation design drawings
• Major equipment monitoring and routine service
• Functional operation of all components
b) Preparation of a complete inspection and maintenance schedule for both City staff and
services to be performed by contractors.
c) A proposed timeline schedule for equipment retirement and replacement.
d) Recommendation for adding a second transformer bank with primary protection,
regulation, and completion of the remaining two distribution feeders. This improvement
along with distribution system circuit configuration modifications will allow the City to
transfer considerable load from PacifiCorp substation(s) to the City -owned Mountain
Avenue Substation, giving the City more control over their facilities and saving power
purchase costs by eliminating wheeling some power through PacifiCorp substation
facilities.
e) The City should be aware that the existing transformer was manufactured in 1976 and
was installed used. The estimated remaining service life is approximately 20 years.
However, obtaining a new transformer will require development of a purchase document
and technical specification, time for suppliers to propose, bid reviews, evaluation and
award recommendation, manufacture, and delivery. In today's market conditions, this
process could take up to 5 years to obtain a new transformer.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 2-4
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Ashland Substation
The PacifiCorp-owned Ashland Substation (also known as Nevada Street Substation) contains
a City -owned distribution rack originally constructed in the 1950/60s which has undergone
several modifications during its existence. Although functional, by today's standards the rack
could be considered outdated and somewhat of a liability.
In 2012 the City converted an existing City -owned building near this substation to a control
facility and installed new microprocessor multifunctional circuit controllers for all 4 feeders. This
improvement gave the City control and monitoring capability of these feeders from the off -site
control building, and remote monitoring capability via its SCADA system.
In 2015 consideration was given to replacing the aged City -owned distribution facilities inside
the PacifiCorp Ashland Substation with a City -owned substation directly across Nevada Street
on City -owned vacant property. This location seemed ideal since two looped transmission
sources exist directly outside the lot and the new facility could easily tie into the existing four
City distribution feeders.
Preliminary layout and rendition drawings were created for both open -rack and metalclad-style
substations. Although this improvement would give the City control over the substation and
distribution facilities and save power purchase costs by eliminating wheeling through
PacifiCorp's Ashland Substation facilities the concept was not pursued further.
As the City's existing distribution rack in the PacifiCorp Ashland Substation yard continues to
deteriorate the City may want to reconsider building a new substation as described above at this
existing City -owned site.
Oak Knoll Substation
In 2014 the City installed pole -mounted recloser controllers adjacent to the PacifiCorp Oak Knoll
Substation giving the City control of its three distribution feeders served from this substation,
and it also provided the City with monitoring and control capabilities of these feeders from
outside the substation via its SCADA system.
2.2.3 Distribution
• In 2018 the electric department revised and updated both the commercial and residential
New Service Application forms.
In 2018 the electric department's Supervisory Control and Data Acquisition (SCADA)
System situated in the dispatch center was upgraded to a new Ignition software platform
to improve the monitor and control capability of distribution feeder circuits, field reclosers
and capacitors, including the Reeder Gulch Hydro facility. This improvement offers the
City the ability to monitor and document system performance in real-time, identify and
prevent potential problems, and assist with troubleshooting when necessary. The City
should further expand the SCADA system to include monitoring of the newly acquired
Mountain Avenue Substation 115 kV protection devices.
• In 2019 the City installed underground construction consisting of multiple conduits and
vault system from the Mountain Avenue Substation along Hersey Street to N. Main
Street for future installation of major backbone circuits and lateral taps.
• The electric department is currently implementing several fire mitigation activities, such
as potential fuel clearing, installation of composite poles in lieu of wood poles, fuse spark
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-5
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inhibitor products, and many other devices in accordance with the recommendations in
the recent (2022) Wildfire Mitigation Plan.
• In 2023 the Electric Service Requirements (ESR) manual was upgraded to conform with
City and neighboring PacifiCorp policies on system interconnection and service
construction standards for internal, developer and contractor use.
• The City installed self-supporting steel poles for the East Main 1-5 feeder crossing east
and west of the interstate highway.
• The City installed self-supporting steel poles with recloser protection, monitor and control
capability of the three distribution feeders directly outside the PacifiCorp Oak Knoll
Substation.
• The City installed a new underground circuitry interconnection with various solar projects
on the SOU campus and major PV developments within the City's service territory.
• The City completed several underground conversions and cable replacements,
strengthened circuit intertie connections, and looped circuits to serve critical customers.
2.3 COMMENTS & RECOMMENDATIONS
In general, we recommend the City's electrical department adopt the planning criteria and
implement the system improvements as presented in this report and specifically noted in Table
2-1. Improvements should be made as necessary to economically serve the actual load, while at
the same time meeting prudent service quality and reliability standards.
We recommend that the electrical department review and update this report approximately
every five years to confirm that decisions regarding improvements are based on current system
conditions. All new facilities should be constructed in accordance with the latest expansion plan
to ensure that no facilities become obsolete early in their service lives.
Specific recommendations resulting from this study are intended to meet normal load growth
requirements and resolve specific operating deficiencies. All cost estimates shown are in 2024
dollars and are based on work performed by a contractor after competitive bidding unless
otherwise stated.
It should be noted that some of the recommended improvements are already in progress and
other recommendations do not have a fixed timeline or cost associated with them. In some
instances, the work associated with the improvement is expected to be performed by the City's
electrical department staff and line crew as part of their ongoing maintenance activities. In other
instances, costs cannot be accurately estimated until the scope of the improvement to be
undertaken is refined.
Transmission
With PacifiCorp's facility improvements made over the last several years, the transmission
sources and system are now capable of serving the entire City's electric load for the foreseeable
future. The existing multiple source configuration and available backup transmission paths will
provide the City with adequate service integrity and reliability into the long-term future.
Substations
As discussed in Chapter 3 and Chapter 7, sufficient substation capacity is currently available to
serve the City's expected peak loads for the next 10 years under normal operating conditions.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-6
Pan- 16 of 1.17
However, the loss of any single major system component under high load conditions can create
the potential for overloading portions of the system and creating extended outages for electric
customers.
The failure of a transformer at either the Mountain Avenue Substation or PacifiCorp's Ashland
Substation during a peak load condition could create severe transformer overload conditions on
the remaining in-service substation transformers.
A prioritized list of recommended substation -related improvements and budgetary cost
estimates are presented in Table 2-1 of this Chapter. Major recommendations related to the
substations serving the City include:
• Purchase and install one 115-12.47/7.2 kV, 15/20/25 MVA power transformer as the
second transformer bank at Mountain Avenue Substation to increase the capacity to
serve load and reduce reliability on PacifiCorp's facilities, while at the same time
reducing power purchase costs.
• Perform staff training for operation and maintenance of all facilities at the Mountain
Avenue Substation as outlined in this report.
• Prepare a comprehensive inspection and maintenance schedule for the Mountain
Avenue Substation for services to be performed by City Electric Department staff and
contracted service providers.
• Consider retiring the existing City -owned distribution rack at PacifiCorp's Ashland
Substation and constructing a new City -owned Nevada Street Substation at the City -
owned property as described above.
Distribution
Based on the projected peak for 2033, all City -owned distribution system components have
sufficient capacity at this time. The electrical department has strengthened some feeder
backbone conductors and feeder tie circuits over the last several years. However, as load is
added and growth occurs feeder and conductor loading should be monitored to ensure spare
capacity remains and is available when load transfers become necessary.
Transferring certain feeders at peak load will become problematic in the next ten years,
particularly during summer peak loading because equipment's summer ratings are lower than
their winter ratings.
Recommended distribution system improvements are also listed in Table 2-1. Major
recommendations related to the distribution system include:
• Monitor and balance existing feeder loading to minimize phase imbalance.
• To enhance the City's wildfire mitigation activities the electric department might want to
consider implementing the following practices:
o Replacement of fuses and installation of S&C TripSaver devices on circuit taps in
wooded areas of the distribution system.
o Installation of S&C VacuFuse devices to cover fuses and prevent sparks and hot
debris from potential fire -causing blown fusses, particularly on transformer
protection fuses on circuit taps in wooded areas of the distribution system.
• The electric department may want to consider updating its existing customer metering
technology by implementing an Automated Metering Infrastructure (AMI) system that can
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-7
Panes 17 of 117
telemeter customer usage data directly to the electric and water departments plus billing
department collector system, consistent with industry -standard smart metering trends.
o Automatic Meter Reading (AMR) is an automated technology used to collect
consumption, diagnostic and status data from electric, gas and water metering
devices. The AMR system transfers this data to a central database for billing,
troubleshooting and analysis. Over the past several decades, most utilities have
integrated advanced metering technologies throughout their service areas. The
implementation of this technology has improved customer service and helped
utilities function more efficiently.
o Around the year 2000 Ashland installed the Itron automatic meter reading (AMR)
technology, including Itron drive -by or hand-held encoder receiver transmitter
(ERT®) devices to gather metered data used for customer billing. While this
technology has been effective for that purpose, utilities are increasingly finding
that one-way communication networks limit their ability to support advanced
customer and operational applications, and that benefits of two-way
communications capability is preferred.
o One option to upgrade the existing City metering is to adopt the Tantalus
TRUConnect multi -purpose utility platform, which will enable Smart Grid
applications for monitoring and control of electric, water and gas utilities. This
two-way AMI communications platform supports a variety of high -value utility
applications which can include:
■ Advanced Metering Infrastructure (AMI)
■ Closed Loop Voltage Reduction (CLVRO)
■ Outage management
■ Remote connect/disconnect
■ Prepay of electric power
■ Power quality analysis
■ Load management
■ Revenue assurance
■ Reliability analysis
■ Asset management
■ Streetlight control
• Net metering
o For the City of Ashland, which has a large investment in ERT technology in its
existing metering system, there is a process to enable advanced applications
while continuing to leverage the ERT assets. The TRUConnect ability will allow
the City to build on its existing AMR groundwork to take advantage of
operationally efficient advanced applications at a fraction of time and cost of a full
system replacement. The system is designed to be strategically deployed as
determined by the utility, since Tantalus and Itron have developed solutions to
help mitigate full system replacement costs.
o The solution developed by Tantalus and Itron would deploy TUNet network
infrastructure over Ashland's complete service area or a specific strategic
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-8
Pane 1 R of 117
geographic area by replacing a percentage of electric meters. Typical full ERT
overlay deployments involve a replacement of 15% to 20% of the existing electric
meters without the need to replace any ERTs on the water meters. Further
information on this matter should be requested from the Itron/Tantalus NW
representative.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEIUBER 2024 2-9
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Table 2-1: Recommendations
Item
Description
Estimated
Cost (2024)
General System
G-1
The City should consider the future of Electric Vehicle (EV) impact on the distribution facilities by increasing transformer capacity
NA
in new developments. An estimated 5 kW per resident should be allocated when sizing new transformers. The EV charger minimal
use time will impact transformer energy losses which must be paid for by the serving utility (City of Ashland) and will likely impact
future electric rates.
G-2
Self -healing distribution systems may be desirable in the near future, especially in highly congested downtown areas. Although
$75,000
such sectionalizing systems are currently available they may not be cost-effective. To minimize downtime due to faults, many
Overhead Mount
utilities now utilize automated fault interrupting and sectionalizing switches with SCADA system interconnection at critical
distribution locations. The City may want to evaluate the use of these devices for'self-healing' (automated restoration) of the
$150,000
distribution system at key locations. The cost estimates provided include all equipment and installation costs per switch, This will
Pad Mount
require SCADA communication interconnection which should be easily implemented.
G-3
Consider an update to the previous Arc -Flash Study (2010) to bring it into compliance with present standards.
$7,500
G-4
Consider an update to the previous Spill Prevention Control and Countermeasures Plan (SPCC) to bring it into compliance with
$4,200
present standards.
G-5
The City may want to consider modifications to the Distributed Generation Interconnection Control Ordinance. These changes
NA
could regulate how low -voltage generators are connected to the City's distribution system. The language should require that
interconnection control must be in accordance with IEEE and NEC standards. New technology has advanced distributed
generation devices to the point where their installation is common, however because of the potential for these devices to cause
system disturbances that can affect sensitive customer loads and the overall system performance, the adoption of this change will
allow the City to take the appropriate action should policy violations occur. The inclusion of this type of interconnection control and
net metering language may require modifications to the existing Electric Ordinance.
G-6
The potential upgrade of the City's customer revenue metering could be considerably enhanced by implementing new AM I
TBD
devices that can interact with the existing meters and then transmit metered data onto the City's billing department collective
system. In addition to monitoring usage, the system revisions would include the capability to provide outage notifications, and
have remote disconnect and reconnect capabilities.
G-7
System Development Charges We recommend that the City evaluate its policies and procedures concerning the review and
NA
assessed fee schedule for system development construction. It is important that City develop service and construction standards
to cover typical system developments and apply these standards consistently. The city's fee schedule of charges to developers
should include all City -related costs as well as necessary engineering services required for design, review, and services during
construction. The fee structure should be periodically reviewed to maintain comparable charges with similarly sized municipalities.
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 2-1
Panes 2n of 117
Item
Description
Estimated
Cost (2024)
G-8
The City has an electric system map with most of the data up to date. However, there is missing information on conductors and
Normal
protective devices including fuses (size and type) and pad -mount switchgear settings. We recommend the City continue the
Maintenance
practice of updating information into its distribution mapping system so all the information reflects the field's as -built conditions and
Activity
can be readily available for line assessment, system troubleshooting, future planning studies, as well as component inventory
database.
Transmission System
T-1
The City's crew should be trained regarding service and maintenance on the high -voltage primary switching sequence to de-
(see S-1)
energize and re -energize the substation equipment at Mountain Avenue Substation.
Substations [MAS = Mountain Avenue Substation, AS = Ashland Substation, OKS = Oak Knoll Substation]
S-1
The City should conduct a staff training session for the operation and maintenance of all facilities at the Mountain Avenue
$7,500
(MAS)
Substation as outlined in this report as soon as possible. This training should be provided by a qualified engineering service
provider who has experience in such activities.
S-2
The City should have a comprehensive inspection and maintenance schedule created for the Mountain Avenue Substation
$7,500
(MAS)
describing services to be performed by City staff and contracted service providers. This schedule should be prepared by a
qualified engineering service provider that has experience in such activities.
S-3
Now that the City owns Mountain Avenue Substation it should consider installing an online gas -monitoring system on the existing
$7,500
(MAS)
power transformer to continuously monitor transformer health. Sensor capabilities vary widely but could allow the City to monitor
Base Unit
up to eight critical fault gases in addition to moisture. It can be installed while the unit remains in service and is field -based,
$25,000
requiring no manual oil sampling or lab testing.
Unit With Pump
S-5
The City should have a Bid Procurement Document and Technical Specification prepared for the purchase of a second bank
$1,350,000
(MAS)
transformer at the Mountain Avenue Substation. The transformer should be rated 12/16/20 MVA or 15/20/25 MVA suited to
Transformer
complement the intermediate replacement of the existing transformer. It is estimated this process could take 5 years from onset
$750,000
until a transformer is placed on the foundation pad. The preparation of this document, advertisement, bid activities, evaluation and
Construction
award should be performed by a qualified engineering service provider that has experience in such activities.
S-6
To coincide with the addition of a second transformer bank at Mountain Avenue Substation as described in improvement S-5, the
$150,000
(MAS)
City should have the necessary design prepared to implement the new transformer. This will require a Construction Document
consisting of Bid Documents, Technical Specifications and Drawings, and should be performed by a qualified engineering service
provider that has experience in such activities. It will entail procurement of all necessary equipment and contractor services for
construction and installation activities.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-2
Pane 91 of 137
Item
Description
Estimated
Cost (2024)
S-7
With improvements S-5/6, to shift load onto the City owned Mountain Avenue Substation, the City should construct the two
$200,000
(MAS)
remaining available feeder circuits out of the Mountain Avenue Substation. The circuits should be installed, and existing Mountain
(each feeder)
Avenue Substation feeders adjusted to shift load off the Ashland/Oak Knoll circuits and place greater load on the Mountain
Avenue Substation. The cost estimates assume underground conductors installed by City crews in existing ducts and vaults. Each
underground feeder cable construction is estimated to be 6,000-feet at $30/ft for all material and labor including any line
extensions and sectionalizing switchgear.
S-7
The existing transformer protection at Mountain Avenue Substation only has one level of phase and neutral overcurrent protection.
$15,000
(MAS)
We recommended that the City consider adding a transformer differential protection relay for improved transformer protection. At
Engineering
the same time the City should consider including monitor and control of the substation high -voltage circuit switcher and protective
$25,000
relay devices into the SCADA system.
Material and labor
S-8
The City should consider the retirement of the City -owned distribution rack located in the PacifiCorp Ashland Substation. An ideal
$3,000,000
(AS)
replacement would be construction of a new substation located on the City -owned property directly across from this facility on
Engineering,
Nevada Street. This location has looped transmission circuits adjacent to the property and could easily interconnect with the
Transformer,
existing distribution feeder circuits. Substation concept renditions have been previously prepared and could be pursued or
Construction
modified as needed, Followed by planning department approval, necessary design, equipment procurement, and contractor
construction. Again, it is estimated this process could take 5 years from onset until a transformer is placed on the foundation pad
S-9
At all substations, implement a periodic (5-year) microprocessor relay testing, calibrating, and maintenance program.
Normal
Maintenance
S-10
The existing bank 1 power transformer was fabricated in 1976 and installed 'used' at Mountain Avenue Substation. Because of the
$20,000
(MAS)
age and expected service life of this transformer the City should plan for its replacement at some point.
Engineering
$1,350,000
Transformer
Distribution System
D-1
The City should continue to implement activities and materials as noted in the Wildfire Mitigation Plan, especially in the heavily
Normal
wooded areas of the City's western service territory.
Maintenance
Activity
D-2
As load increases, rebalance existing loads as necessary to maintain equal distribution of loading to the extent possible, under
Normal
normal operating conditions. Balance phase loading on each phase as practical and ensure sufficient feeder capacity is available
Maintenance
under system tie configurations.
Activity
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 2-3
Pane 99 of 117
Item
Description
Estimated
Cost (2024)
We recommend that phase imbalance on all feeders be monitored under peak load conditions. If imbalance on the listed feeders
exceeds 15%, action should be taken to shift load and reduce imbalance to below 10%,
D-3
To standardize construction practices the City should confirm the use of existing overhead conductor sag and tension construction
Existing
stringing charts for multiple conductors and conditions based on NESC Zone 2 Loading District. These charts are based on
Sag -Ten Tables
calculations and specific weather criteria to ensure consistent installation standards for the mid -valley region.
D-4
The City should target 500-1000 feet of aging bare concentric neutral cable per year for replacement in addition to replacing
$100/ft
segments as they fail. These bare neutral cables are known to corrode leading to potential public safety issues as well as voltage
$50,000-
problems due to loss of neutral return.
$100,000
D-5
The City should consider and continue the practice of adding overhead and underground fault indicators on feeder main
$150 each
backbones to assist in location of faults.
D-6
For underground facilities, where applicable, fused elbow connectors in vaults or at equipment can help isolate circuit taps and
$350 per Elbow
minimize the number of customers experiencing interruptions or outages. The City may want to consider installation of fused load-
$250 per Fuse
break elbows at specific backbone circuit taps or major tap locations presently not sectionalized. See Section 9 for further
discussion of pad mount distribution equipment
D-7
The City should ensure that all crew members have sufficient knowledge and training regarding pad -mounting sectionalizing
NA
equipment operation and tap interruption restoration.
D-8
Depending on the load distribution, some of the backbone fuses, 140K and 100K, along the Ashland/Business feeder are
Normal
recommended to be monitored, as they will likely exceed their rated capacity. The City should monitor the through load and make
Maintenance
necessary adjustments if needed.
Activity
D-9
Verify Feeder M3009 recloser settings and change them to be identical with other Mountain Avenue Substation feeder settings if
Normal
(MAS)
inappropriate implementation is confirmed.
Maintenance
Activity
D-10
The City should consider conforming to pole testing requirements by having poles tested every 10-12 years, or test approximately
$100/Pole Est.
10% each year. For poles that have not been inspected for some time, it is suggested primary circuit poles receive a full intrusive
inspection, which includes excavation around the pole to a depth of 18", and inspection of the pole exterior for decay and
treatment with a boron/copper-based product to prolong pole life. Testing should include sound and bore to determine if the pole
has any voids. If voids are present the pole should be treated with a copper -based product to slow decay. Poles with extensive
decay and not serviceable should be rejected. The poles should also receive a periodic visual inspection for obvious signs of
damage or decay.
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 2-4
Pane 91 of 117
Item
Description
Estimated
Cost (2024)
D-11
The City should consider having an infrared thermal imaging investigation performed on all substation and switching station
$25/Pole Est
equipment and on all primary circuit overhead pole assemblies. This service should be performed after the pole inspection,
$500/Sub Bay
treatment and/or replacement is complete, so that the infrared inspection is performed on pole top assemblies that will remain in
Est.
service.
Renewable Energy
R-1
The City has existing programs and policies to encourage if not require non -fossil fuel sources for house appliances and vehicles.
NA
Any reduction in non-renewable energy consumption will put the City closer to achieving the 100% goal. However, this will shift the
burden of non-renewable reduction to the electric system in terms of load growth.
Another approach is developing programs to incentivize energy efficiency improvements and energy use reductions, which have
the highest effectiveness in reducing non-renewable energy consumption.
R-2
Adding renewable generation to the City's system. This can be achieved by continuing to support community projects to add
NA
distributed generation resources. The City does not own transmission resources and has limited siting available for large-scale PV
generation.
As discussed in Item S-8, we recommend the Ashland Substation be expanded to a new City -owned substation to increase
capacity and reliability. If a suitable site near Oak Street can be identified, adding a large PV system to the new substation
development would be an option for adding the needed capacity.
R-3
The City purchases all electric energy from BPA, the majority of which comes from the hydroelectric facilities in the BPA territory.
NA
As such, BPA's energy fuel mix is generally 78% to 85% renewable and an additional 11% non -greenhouse gas -producing
nuclear. Therefore, only 5% to 10% of the energy purchased by Ashland is potentially greenhouse gas producing. One approach
the City might consider taking to achieve 100% greenhouse gas -free energy use is simply to identify enough renewable energy
such that it offsets 5% to 10% of what would have been required to be purchased from BPA.
R-4
The EV increase rate is hard to predict as it depends on many factors such as various levels of incentives from the Federal, State,
NA
and City, economic, and supply chain situations. We recommend the City continue monitoring the EV registrations and charger
installations in town and consider an evaluation period of every two to three years. If the growth is rapid, the City may want to
consider implementing a dynamic rate structure or smart charging policy to avoid significant peak demand increase in the evening.
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 2-5
Panes 94 of 117
Chapter 3 LOAD FORECAST
3.1 GENERAL
This chapter describes a load forecast developed for the City of Ashland Electric Department
based on the system peak demand expected for a 1 in 10 year cold or hot weather event.
Included are five-year, ten-year, and twenty-year projections covering the period from 2024 to
2043, based on BPA and Electrical Department metered data as well as information and
projections provided by the following sources:
• The City of Ashland Urban Growth Boundary
• The City of Ashland Buildable Lands Inventory
• The Jackson County Comprehensive Plan
• The Oregon Office of Economic Analysis (OEA)
• Portland State University Population Research Center
• Bonneville Power Administration Customer Portal
• PacifiCorp
• United States Census Data
• The Public Utility Commission of Oregon
• National Oceanic and Atmospheric Administration (NOAA) Climate Data Online Search
The load forecast projections and assumptions are the result of population growth and weather
experienced during the period from 2013 through 2022. The analysis shows a strong correlation
between temperature and system power demand for both cold and hot temperatures.
3.2 HISTORICAL OPERATING SYSTEMS
The City of Ashland's customer base has grown approximately 2.3% from 2003 to 2023 but has
slowed in the last 10 years. Now the City serves approximately 12,817 customers.
• From 2003 to 2013, customer growth was from 10,100 to 12,705, -2.3% annual growth
rate.
• From 2014 to 2023, customer growth was from 12,705 to 12,817, -0.09% annual growth
rate.
In the 2003 study, it was noted that the City of Ashland's historical maximum system peak, 44.6
MW, occurred in December 1990. In the evaluation period from 2004 to 2013, the highest
system peak was 43.49 MW, and occurred in December 2013. Per the metered data available
for the last 10 years, the electric system's maximum peak was 45.92 MW, which occurred in
June 2021. This peak load was divided between the City -owned Mountain Avenue Substation,
PacifiCorp's Ashland Substation (AS) and Oak Knoll Substation (OKS). The concurrent demand
at each substation during the peak was 14.4 MW (MAS), 14.3 MW (AS), and 17.4 MW (OKS).
Table 3-1, Figure 3-1, and Figure 3-2 demonstrate comparisons between energy, peak demand,
and population from 2003 through 2023. The population growth from 2010 to 2022 shows a
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 3-1
Pane W; of 1.7
slow but steady increasing pattern (-0.7% annually). There was a 0.8% decrease in 2023,
however, population growth is expected to continue at a rate of around 0.63% for the next
decade according to Portland State University's Population Report.
Based on the curves shown in Figure 3-1, Ashland's annual energy usage from 2003 to 2023
was around 176,000 MWh with an approximate 4,500 MWh (or 3%) standard deviation. The
energy consumption has been stable over the last several years. This relatively consistent
annual energy use indicates that there is an unlikely potential for a new summer or winter
energy consumption peak until an extremely cold or hot weather event is experienced.
Ashland's annual peak demand profile in Figure 3-2 indicates that the correlation between peak
demand and population isn't strong in most of the last 20 years. The peak trends appear to be
more closely linked to weather than population.
Average energy consumption typically correlates with population. Even though the population
growth is expected to slow, with the City's carbon neutrality goal and Climate & Energy Action
plans, the City's average energy consumption is likely going to increase due to the gradual
change from fossil fuel to electric -powered appliances and electrical vehicle (EV) chargers.
Therefore, energy and demand are expected to increase with fluctuations more influenced by
weather in the near future (-5 years). More EV chargers are expected to be installed in the City,
which will likely affect some of the feeder peak demands. However, the EV increase rate is hard
to predict as it depends on many factors such as various levels of incentives from the Federal,
State, and City, economic, and supply chain situations. The City should continue monitoring the
EV registrations and charger installations in town and should consider an evaluation period of
every two to three years due to the rapidly changing EV market.
More discussion about the load forecast can be found in Section 3.4.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 3-2
Pang 96 of 1.17
Table 3-1: Population Growth, Energy Use, and Peak Demand
Year
Peak (kW)
Energy (kWh)
Population
2003
37,970
171,920,100
20,430
2004
38,330
175,293,480
20,590
2005
38,690
178,064,595
20,880
2006
39,070
180,419,455
20,974
2007
39,430
182,696,625
21,062
2008
39,800
184,296,170
20,782
2009
40,160
177,741,226
20,996
2010
40,530
168,980,735
20,078
2011
40,880
176,722,735
20,255
2012
41,260
179,815,430
20,325
2013
43,490
185,231,385
20,295
2014
38,885
173,668,763
20,340
2015
38,940
174,410,074
20,405
2016
39,940
171,240,240
20,620
2017
38,505
178,273,030
20,700
2018
38,700
173,236,580
20,815
2019
37,605
172,884,771
20,960
2020
38,195
170,324,005
21,105
2021
45,920
175,664,178
21,554
2022
40,670
173,338,189 (a)
21,642
2023
42,914
173,389,804 (a)
21,457
Notes
a) A fuse blow on the BPA metering station in Mountain Avenue Substation resulted in incorrect metering from June 2022
through September 2023- The values above include the unmetered amount estimated by BPA.
24,000 200,000,000
23,500
23,000 180,000,000
t
22,500 ?�
c 22,000
0
21,500
a
0
4 21,000
20,500
20,000
19,500
19,000
ti
-e Ile lip", L011 101" ,ti0s1
--*--Population -1- Energy (kWh)
Figure 3-1: System Annual Energy Use vs. Population
160,000,000
c
0
a
140,000,000 E
V
120,000,000
0
c
W
100,000,000
80,000,000
,yo
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SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
3-3
Pane 97 of 1.17
23,000
I
22,500
22,000
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O
21,500
CL
21,000
20,500
20,000
o�1, o,� o`� Ci c1
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—*—Population—*—Peak(kW)
Figure 3-2: System Annual Peak Demand vs. Population
50,000
45,000
40,000
Y
35,000 E
is
Y
w
30,000 ow
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20,000
The electric systems' coincidental monthly peak demands and some statistics for the period of
2014-2023 are shown in Table 3-2 and plotted in Figure 3-3 (BPA data for 2013 is not
complete). Over the last 10 years, the average peak demand had an overall growing trend with
variations possibly due to a combination of changes in weather patterns and business operating
profiles. The difference in energy and demand trends may also be due to the increase in PV
development in the City's system which has a cumulative effect on energy but a lesser effect on
demand due to the time period of demand peak being non -coincident with the PV production
peak (specifically, demand peaks are generally in the morning and early evening while PV
product peak is in the early afternoon).
Historically, the City's peak demands are more characterized by winter and summer peaks.
Specifically, the annual peak demands in the last 10 years occurred in the summer except for
2017, in which its winter peak and summer peak were about the same (38,505 kW vs. 37,890
kW, with only a 615-kW difference). We assumed that summer peaks will continue to be the
dominant yearly peak in the future with the possible exception of years with an extreme winter
storm condition.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 3-4
Pane 2R of 137
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PacifiCorp Load
Table 3-3 lists the peak demands for the three transformers in PacifiCorp's Ashland Substation
and Oak Knoll Substation as well as the peak demands for the Ashland loads only. PacifiCorp's
loads served by these transformers are shown as a percentage and must be considered in the
transformer capacity evaluation. The estimated average demand for PacifiCorp's load through
Ashland Substation is approximately 4.2 MW with a peak of 5.5 MW in the past 10 years, and
the estimated average demand for PacifiCorp's load in Oak Knoll Substation is approximately
6.5 MW with a peak of 9.0 MW.
Notes:
Table 3-3: PacifiCorp Facility Load Data and Comparison with BPA Data
Year
Ashland Sub
Total Peak
Demand, PCorp
Record la1(d)
Oak Knoll Sub
Toal Peak
Demand, PCorp
Record (a) tq (e)
Ashland Sub,
Peak Demand,
Ashland Load
Only tb1
Oak Knoll Sub,
Peak Demand,
Ashland Load
Only (b)
2014
15,653
19,346
12,490
13,560
2015
17,383
25,313
14,820
15,890
2016
16,412
20,482
13,200
13,890
2017
17,463
22,528
13,830
14,890
2018
15,902
20,429
12,450
13,350
2019
15,352
19,959
17,805
15,120
2020
16,488
20,976
12,010
14,520
2021
18,602
22,979
20,775
17,260
2022
18,777
22,727
14,470
16,870
2023
17,446
21,898
12,800
14,600
a) Based on data provided by PacifiCorp. This load includes PacifiCorp's feeder Toads and Ashland's loads.
b) Based on BPA's meter data for the City of Ashland.
c) Summation of the peak demands for the two transformers (non -coincident).
d) Approximately 30% of the Ashland Substation transformer load is for PacifiCorp's load.
e) Approximately 33% of the Oak Knoll Substation transformer load is for PacifiCorp's load.
3.3 WEATHER -RELATED CONSIDERATIONS
To examine the effect of weather on system peak demand and energy use, we obtained Oregon
Climate Service data from the Ashland weather station for 2013-2023. Analysis of the data for
this period yields statistical 1 in 10-year cold and hot weather events of approximately 190 F and
1120 F. The all-time records for this region are -200 F and 1150 F respectively.
Figure 3-4 shows the heating degree days (HDD) during the winter months vs. the City of
Ashland's winter energy consumption for the period of 2014-2023. The average HDD for this
period is also included in the graph. Figure 3-5 shows the number of cooling degree days (CDD)
and average during the summer months vs. the City of Ashland's summer energy consumption
for the same period. HDD and CDD are measurements, based on outside air temperature, that
are designed to reflect the demand for energy needed to provide heat or cooling for a building or
home for every degree above or below 650 F.
Figure 3-4 shows that Ashland's winter energy consumption has a strong correlation with the
number of HDDs in a given year for the last 10 years. The correlation coefficient between
energy consumption and HDD is about 0.71 for the period from 2014 to 2023 (Note: A
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 3-6
Panes 30 of 137
coefficient of 1 indicates a perfect positive relationship while -1 indicates a perfect negative
relationship.). Similarly, the City's summer energy consumption and the number of CDD's in this
period show a strong correlation but slightly lower correlation (Figure 3-5), with an overall
correlation coefficient of 0.77.
Figure 3-6 shows the monthly mean demand plotted with the monthly mean temperature for
2014-2023. It is important to note that there are two peaks each year, one in summer and one in
winter. The overall correlation between them isn't strong, however, if breaking a year into two
evaluation periods, the mean demand is negatively correlated with mean temperature in winter
months, and positively correlated in summer months. Also, Ashland's summer demands are
relatively higher than the City's winter demand, indicating the City's customers may use air
conditioning and irrigation during the summer more than they use heating in the winter. This
seems to be a trend in many western Oregon regions as CDD's (or high temperatures days) are
increasing in frequency and the installed AC capacity is also increasing.
53,000,000
52,000,000
51,000,000
L
� 50,000,000
7
O
L
49,000,000
Y
48,000,000
47,000,000
2,600
2,400
2,200
N
2,000
N
1,800 c
R
S
1,600
1,400
46,000,000 1,200
2014 2015 2016 2017 2019 2019 2020 2021 2022 2023
-Energy Usage -HDD- HDO Average 2014-2023
Figure 3-4: Heating Degree Days Recorded by Ashland Weather Station vs. The City's Energy Consumption
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 3-7
Pant- *11 of 1.17
47,000,000
46,000,000
45,000,000
L
44,000,000
00
43,000,000
c
W
42,000,000
41,000,000
600
550
500
N
T
450 0
d
400 CL
00
c_
350 o
0
U
300
250
4Q000,000 200
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
—Energy Usage —CDD—CDDAverage2014-2023
Figure 3-5: Cooling Degree Days Recorded by Ashland Weather Station vs. The City's Energy Consumption
30,000 120
110
25,000
100
i
20,000 90
80
c 15.E
E 70 E
y v
10,000 60
50
5,000
40
0 _. 30
tiA �P yh y`) ti`0 y( 11 tit ti� ti� y1) ti°' ti0 tiQ$ y"I L"I LL L1V L'5
lac 1J lac 1J lac 1J lac 1J lac 1J lac 1J lac 1J lac 1J lac 1J lac
--0—Monthly Mean Demand -Monthly Mean Temp
Figure 3-6: Monthly Mean Temperature and Monthly Mean Demand (kKq
Table 3-4 and Table 3-5 show the two highest winter and summer peaks for 2014-2023 with
correlated minimum and maximum temperatures for the respective peak days. The June 28,
2021 peak is used as the base case for the 10- and 20-year peak load growth projections. It is
assumed, but unknown, that the demand and temperature are coincidental. However, the time
of day for each peak is consistent with the expected proximity to the minimum or maximum
temperature.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
3-8
Panes .12 nf 1.7
Notes:
Table 3-4: Highest Winter Peaks and Correlated Minimum Temperatures
Date
Peak (MW)
Temperature (F)
12/9/2013, 9:00:00 AM
43.5
8°
1/16/2014, 9:00:00 AM
36.7
24'
1/612017, 9:00:00 AM
38.5
9°
Table 3-5: Highest Summer Peaks and Correlated Maximum Temperatures
Date
Peak (M"
Temperature (F)
6/28/2021, 5:00:00 PM
45.9
112°
7/29/2022, 5:00:00 PM
40.7 (a)
113'
8/14/2023, 6:00:00 PM
42.9 (a)
110,
a) A fuse blow on the BPA metering station in Mountain Avenue Substation resulted in incorrect metering from June 2022
through September 2023.
3.4 GROWTH FORECASTS
Since the City must be able to serve all customers reliably under peak load, system planning,
and design requirements should incorporate the Peak Demand Forecast.
The BPA annual peak forecast for the Ashland area is presented in Table 3-6 alongside the
Peak Demand Forecast estimated in this study.
The BPA forecast is based on a growth rate of 0% for the next ten years. This growth rate may
be reasonable, but it must be noted that the BPA forecast typically uses a 1 in 2-year weather
event as its planning criteria. By design, this BPA method results in peak demand estimates that
do not account for the possibility of extreme cold or hot weather events. The City's actual
system peak each of the past 10 years was higher than the BPA forecast peak for each of the
next 10 years.
PacifiCorp also provided a growth forecast for its Ashland Substation and Oak Knoll Substation
for the 2024-2033 period which assumes an average annual growth rate of approximately 1.0%
for Ashland Substation and 0.5% for Oak Knoll Substation. According to PacifiCorp staff, this
forecast is based on historical data and calculated annual growth rate using linear regression.
The City of Ashland has implemented a series of Climate & Energy Action plans to reach the
carbon neutrality goal, including fuel switching, more clean energy, EVs, energy -efficient
equipment/appliances, etc. Some of these initiatives are likely to reduce the peak demand and
energy usage, while some will contribute to an increase. We recommend that the City base its
system planning on a minimum of at least a 1 in 10-year weather criteria and assume a
consistent correction between energy/demand and population. The City's Peak Demand
Forecast in Table 3-6 is based on this criterion and an annual growth rate of 0.72%. This growth
rate is slightly higher than the projected growth rate in Portland State's 2023 Population
Forecast (0.6% average annual growth rate). This rate is reasonable for long-term forecasting
purposes based on the City's energy, peak demand, and population profile in the last 10 years.
Figure 3-7 shows the yearly peak demand during the past 10 years along with growth forecasts
and available transformation capacity. PacifiCorp's coincident peak data was estimated based
on the data provided. Total transformation capacity is shown under various transformer cooling
SYSTEM PLANNING STUDY CITY OF ASHLAND — SEPTEMBER 2024 3-9
Pane .3 of 1.7
conditions. Transformation capacity margin of the system decreases slowly from the present to
2033 due to load growth at the forecast rate. The City's overall available transformation capacity
exceeds the current and projected peak demands with a margin of about 42% capacity over the
worst -case projected peak. This available margin is only available if all three substations are
fully in service.
If either Ashland Substation or Mountain Avenue Substation is offline, about 24% of the overall
capacity would be unavailable. The rest of the transformer capacity appears to be sufficient to
support the historical and forecast peak demand with proper switching and load transfer.
However, if Oak Knoll Substation is offline or any two transformers are out of service, the City's
margin is greatly reduced, particularly when considering the 650 C rating of the transformers.
The individual substation peak load and forecast load profiles are illustrated in Figure 3-8,
Figure 3-9, and Figure 3-10 for Ashland Substation, Mountain Avenue Substation and Oak Knoll
Substation respectively.
For Ashland Substation, the combined peak loads (Ashland's and PacifiCorp's) are mostly
above the transformer's Forced Air Level 1 rating (Figure 3-8). However, both PacifiCorp's
forecast and this planning study's forecast for the next 10 years show the combined load could
exceed the existing transformer Forced Air Level 2 rating. Even though the 650 C MVA rating
provides an additional 12% capacity, we recommend the City initiate a dialogue with PacifiCorp
proactively about replacing the existing transformer with a larger unit. Or consider building a
new City -owned substation on the City -owned property next to the existing site. The latter option
is preferred as the existing equipment at PacifiCorp's substation was built in 1960's and the new
substation would provide the City with improved reliability and flexibility.
The existing transformer at Mountain Avenue Substation appears to be sufficient for the
historical and forecast peak demands for the next 10 years (Figure 3-9). Similarly, the combined
transformer ratings at Oak Knoll Substations are sufficient for the forecast peak demands
(including both Ashland's and PacifiCorp's loads). Individual transformer capacity was not
evaluated due to limited data, however, we do not expect it will be a problem.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 3-10
Pane �4 of 117
Table 3-6: SPA and Estimated Load Forecasts
Year
BPA Forecast,
Ashland Sub
BPA Forecast,
Mountain Ave
Sub
SPA
Forecast Oak
Knoll Sub
BPA Forecast Overall
(Non -Coincident /
Coincident) c
Estimated Load
Forecast
2021
N/A
N/A
N/A
N/A
45,920
2024
12,800
12,100
14,600
39,500 / 37,700
46,251
2025
12,800
12,100
14,600
39,500 / 37,700
46,584
2026
12,800
12,100
14,600
39,500 / 37,700
46,919
2027
12,800
12,100
14,600
39,500 / 37,700
47,257
2028
12,800
12,100
14,600
39,500 / 37,700
47,597
2029
12,800
12,100
14,600
39,500 / 37,700
47,940
2030
12,800
12,100
14,600
39,500 / 37,700
48,285
2031
12,800
12,100
14,600
39,500 / 37,700
48,633
2032
12,800
12,100
14,600
39,500 / 37,700
48,983
2033
12,800
12,100
14,600
39,500 / 37,700
49,335
2034
N/A
N/A
N/A
N/A
49,691
2035
N/A
N/A
NIA
N/A
50,048
2036
N/A
N/A
N/A
N/A
50,409
2037
N/A
N/A
N/A
N/A
50,772
2038
N/A
N/A
N/A
N/A
51,137
2039
N/A
N/A
N/A
N/A
51,505
2040
N/A
N/A
NIA
N/A
51,876
2041
N/A
N/A
NIA
N/A
52,250
2042
N/A
NIA
N/A
NIA
52,626
2043
N/A
N/A
N/A
NIA
53,005
Notes:
a) The study was performed in 2023. The historical peak in the past 10 years was used as the base case for the forecast.
b) BPA forecast is for 10 years and only goes to 2033-
c) Non -coincident peak is the direct summation of peak demands for the three substations.
90,000
85 000 Total Cap FA2
80,000 !
75,000
70,000 Total Cap FA3
j 65,000 4 10-Year Forecast,
v Historical Peak, Ashland + PCorp Ashland+PCorp
c 60,000 i
A
C55,000 ' Total Cap OA
50,000
10-Year Historical Peak, Ashland 10-Year Forecast, Ashland
45,000 10-Year Forecast- BPA, Non-
40,000 ! Coincident
i
35,000 10-Year forecast- BPA,
Coincident
30000
'1. " 01y 111 01^ I'll' ti Op ti a 1 0"' 'L p16 Otis 'Y O1'1 ti
p1O 11 O•'�'1 O�ti
'L '1. ti ti ti titi ti 'L ti ti ti
Figure 3-7: Projected Growth of Potential Peak Demand vs. Transformation Capacities (MVA ratings at 55' C are
used.)
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 3-11
Pane 35 of 137
24,000
SPS Forecast,
22,000 Ashland Sub Forecast, Ashland+PCorp
Ashland Cap FA2 PCorp
I
20,000 --
Ashland Sub Peak
18,000 Demand, PCorp Record
Ashland Cap FAl
16,000 01
Ashland Load Peak
SPS f
14,000 Demand ��_ Forecast -Ashland
Only
12,000
BPA Forecast - Ashland Ashland Cap OA
10,000 Only
8,000 - _ _ - ---
2014 2016 2018 2020 2022 2024 2026 2028 2030 2032
Figure 3-8: Projected Growth of Potential Peak Demand vs. Transformation Capacities, Ashland Substation (MVA
ratings at 550C are used.)
22,000
20,000 r— --
18,000
16,000
Mountain Ave Sub Peak
Demand
14,000 A
10,000
Mountain Cap FA2
SPSforecast
Mountain Cap OA
Mountain Cap FA1
BPA Forecast
8,000 `
2014 2016 2018 2020 2022 2024 2026 2028 2030 2032
Figure 3-9: Projected Growth of Potential Peak Demand vs. Transformation Capacities, Mountain Avenue Substation
(MVA ratings at 55' C are used.) [Note: The peak demands in 2015 and 2017 are way higher than the typical peak
demands seen at this substation. These two peaks were likely from abnormal system conditions or switching
configurations and are not used for the forecast base.]
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 3-12
Panp 36 of 1.17
50,000
45,000
40,000
35,000
30000
Oak Knoll Cap FA2
Oak Knoll Cap FAl
SPS Forecast- Ashland i
Oak Knoll Cap OA PCorp
25,000 Oak Knoll Sub Peak
Demand, PCorp Recoi
20,000
10,000 { Ashland Load Peak
I
5,000 Demand
0
2014 2016 2018 2020 2022
Oak Knoll Sub Forcast, rSPS Forecast - Ashland
PCorp t Load Only
SPA Forecast
2024 2026 2028 2030 2032
Figure 3-10. Projected Growth of Potential Peak Demand vs. Transformation Capacities, Oak Knoll Substation (MVA
ratings at 55' C are used.)
3.5 CONCLUSIONS
The recommended improvements and improvement schedule used in this study are based on
the system peak demand calculations summarized in Table 3-7. These demands were
determined using a conservative system peak growth rate of 0.72% similar to, but slightly
greater than the population trending information from Portland State University's report,
Coordinated Population Forecast in conjunction with the recent 2021,10-year system peak of
45.92 MW as a base value.
The schedule of improvements should be evaluated annually and modified as needed to
correspond with actual growth and peak demand as the load develops. As the system currently
stands, there is sufficient total transformation capacity to handle 10-year and 20-year peak
demand events during normal operating conditions. However, the transformer capacity at
Ashland Substation may not be sufficient for the forecasted future growth, and adjustments and
upgrades should be considered at this facility.
Table 3-7. Study Load Forecast Summary
Base Case: 2021 Peak
10-Year Forecast
20-Year Forecast
System Load
45.92 MW
49.34 MW
53.0 MW
Notes:
a) This forecast is the system coincident peak.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024
3-13
Pane .17 of 137
Chapter 4 SYSTEM PLANNING CRITERIA
4.1 GENERAL
As part of the planning study, specific guidelines and planning criteria were developed and
tailored to the City of Ashland's electric system and service objectives. Many of the criteria
discussed below were established in the previous electric system planning study and are based
on factors that affect system operations and maintenance, these include:
• Providing dependable and economical electric service to ratepayers while giving strong
attention to public and personal safety.
• The planning, construction, and operating practices of comparable electric utilities.
• The risk taken by following less stringent planning practices.
• The development of transmission and substation criteria so that in the future the City
may take ownership, operate, and maintain such facilities.
4.2 SYSTEM LOADING
The City of Ashland experienced steady growth from the mid-1990s through approximately 2008
when both population and energy consumption increased, as seen in Table 3-1. Local and
regional planning entities project the population of the City of Ashland to increase throughout
the planning period at an average annual rate of less than 1 %. A discussion of population and
load growth is presented in Chapter 3 and specific areas of growth are presented in Chapter 7.
Prudent utility practices require that system improvements be implemented prior to load growth
to allow the utility to meet customer service demand. On the other hand, existing facilities
should be utilized to the maximum practical extent to avoid costly premature construction of new
facilities. Therefore, the recommended improvements in this report should be made as needed
based on the best available growth data. The time frame of improvement implementation should
be adjusted if the actual load growth varies significantly from the load forecasts but with
sufficient time allowed for necessary engineering, permitting, material procurement and
construction.
4.3 SYSTEM RELIABILITY
A primary consideration in system planning is reliability. As of the last study, the City adopted a
"single -contingency reliability criterion" and this reliability criterion approach should be
continued. Single -contingency reliability is achieved when an outage of any single major
component of the electrical system (transmission or distribution line, substation transformer,
protective device, cable segment, switching component, etc.) results in only minor service
interruption to as few customers as possible.
To meet these objectives, and assure acceptable service continuity to the extent practical, the
following criteria are recommended for use in planning and operating the electric system:
• Substations should have at least one alternate transmission line source (looped).
• Transmission line sections should be capable of being removed from service for
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEA48ER 2024 4-1
Panes .R of 117
maintenance without causing customer service interruptions.
• Single substation transformer outages should not cause prolonged customer service
interruptions. This requires the ability to transfer all feeders to an alternate source under
all potential loading conditions.
• The electric utility should have documented distribution circuit switching schemes ready
at all times. These schemes should allow for the transfer of load in case of the loss of
any individual feeder or substation.
• The electric utility should have a documented emergency load curtailment plan that
identifies probable load -shedding schemes, critical loads, and establishes load
restoration plans.
• Arrangements for substation emergency backup during failure or planned maintenance
through use of mobile transformers should be negotiated.
• Distribution feeders should be designed to be loaded to a maximum of approximately
7.5 MW (-340 A) during normal operation and temporary loading up to 11 MW (-490 A)
during planned maintenance or emergency system outages with load transfers.
• Each distribution feeder should be capable of being supplied by one or more alternate
distribution sources through group -operated, load -break switching devices installed at
appropriate system locations. This will allow circuit breakers or reclosers and other
feeder components to be taken out of service while maintenance is performed without
causing lengthy customer service interruptions.
• When feeder circuits are connected to two separate substation transformers (parallel
operation or hot transfer), load sharing between the two transformers will generally not
be equal due to variations in the transformer impedance and line characteristic
impedances. When opening feeder tie switches, considerable current and voltage can
exist across the switch. We recommend, to the extent possible, all tie switching
involving connection and disconnection of two energized transformers be done via
three -pole group -operated switches, preferably with load -break capability.
During situations when the electric utility has substations served by different
transmission systems, parallel operation or hot transfer of feeders from the two
substations served under this configuration should be avoided to prevent a condition of
extreme fault current available at the tie point of the two sources. If the utility
determines it is necessary to parallel operation from two transmission systems, it
should first be confirmed that the two transmission systems are synchronized and the
transmission operator should be notified.
• The coordination of protective devices should be reviewed and updated as needed to
ensure proper protection of system components and to minimize the impact of faults
and disturbances on adjacent portions of the system.
• Specific inspection and maintenance procedures with reporting documentation should
be developed and adopted to ensure that all facilities are maintained in proper condition
and that all safety and reliability criteria are met.
• Transmission line sections should be capable of being removed from service for
maintenance without causing customer service interruptions.
• Single substation transformer outages should not cause prolonged customer service
interruptions.
• The City should continue the practice of updating distribution circuit sectionalizing
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 4-2
Pane 3A of 137
schemes. These schemes should allow for the transfer of load in case of the loss of any
individual feeder or substation.
4.4 SYSTEM DESIGN
The design of new facilities should be based on the following criteria:
The City should continue using the standard distribution conductor sizes as selected in
the previous study and recent electric development construction projects. The
conductor selections and characteristics are shown in Table 4-1 through Table 4-6
below. The ampacities listed in these tables show that the distribution backbone
conductors are capable of supporting greater loading than the design criteria, allowing
for some reserve capacity.
• Where practical each backbone feeder circuit should be interconnected with two
adjacent backbone circuits to accommodate load transfer.
• The design criteria philosophy is to allow any feeder to carry approximately two-thirds
(2/3) of an adjacent feeder's load in case of the loss of the adjacent feeder.
• The application of standard distribution conductor sizes should be continued and follow
the outline shown below:
Table 4-1: Overhead Conductors
Voltage
Conductor
Circuit Application
12.47/7.2-kV
556.5-kcmil AAC
Distribution Main Backbones
12.47/7.2-kV
336.4-kcmil AAC and #4/0-AAC
Distribution Large Taps
12.47/7.2-kV
#1/0 AAC and #2 AAC
Distribution Small Taps
Table 4-2: Underground Conductors
Voltage
Conductor
Circuit Application
12.47/7.2-kV
750-kcmil AL
Distribution Main Backbone
12.47/7.2-kV
500-kcmil AL and #4/0-AL
Distribution Large Taps
12.47/7.2-kV
#1/0-AL and #2-AL
Distribution Small Taps
• The maximum ampacity rating and relative MW capacity for winter and summer loading
for typical overhead and underground conductors and the City's standard conductor
sizes are shown in Tables 4-3 through 4-6 below:
SYSTEM PLANNING STUDY. CITY OF ASHLAND — SEPTEMBER 2024 4-3
Pnnp 40 of 137
Table 4-3: Capacity of Overhead Conductors
Conductor
Winter (b)
Summer M
Copper
ACSR
AAC
Am aci
MW (C)
Ampaci
MW (C)
#6
165
3.46
115
2.41
#4
225
4.71
155
3.25
#4
170
3.56
118
2.47
#4
164
3.44
113
2.37
#2
290
6.08
200
4.19
#2
225
4.71
155
3.25
#2
220
4.61
152
3.18
#1/0
295
6.18
204
4.27
#1/0
297
6.22
205
4.29
#2/0
348
7.29
240
5.03
#2/0
345
7.23
238
4.99
#4/0
450
9.43
310
6.49
#4/0
465
9.74
320
6.70
336.4
670
14.04
464
9.72
336.4
628
13.16
435
9.11
397
746
15.63
517
10.83
556.5
925
19.38
642
13.45
556.5
868
18.18
602
12.61
795
1174
24.60
815
17.07
Notes:
a) Based on 75 Celsius (degrees) conductor temperature, 0 Celsius (degrees) Winter Ambient, 40 Celsius (degrees) Summer
Ambient.
b) Electric Transmission and Distributions Reference Book, Westinghouse Electric Corporation, Pg. 48, Figures 25 and 26.
c) All MW ratings assume a three-phase system with 97% power factor.
Table 4-4: Underground Cable Capacity 7.2 kV, EPR 133%, Full Concentric (a)
Conductor
In Duct Bank (b)
One Circuit
(Amps)
MW (C)
1-Phase
#2 AL
135
0.94
#1/0 AL
175
1.22
#2/0 AL
205
1.43
#4/0 AL
260
1.82
Notes:
a) Based on Okonite URO-I literature for ONE single-phase circuit, one conductor in one conduit, with 105 deg C, 220 mil, 133%
EPR insulation level with full concentric neutral_
b) 105 C conductor temperature, RHO = 90, 20 Celsius (degrees) ambient earth temperature, 100% load factor (applicable both
summer and winter loading).
c) All MW ratings assume a single-phase system with 97% power factor.
Table 4-5: Underground Cable Capacity 15 kV, EPR 133%, 113 Concentric (a)
Conductor
In Duct Bank (b)
One Circuit
(Amps)
MW (C)
3-Phase
#1 /0 AL
170
3.56
#4/0 AL
255
5.34
500 kcmil AL
405
8.48
750 kcmil AL
505
10.58
Notes:
a) Based on AIEE-ICEA Power Cable Ampacity Ratings, Volume I and II and Okonite URO-) literature for ONE three-phase
circuit, three conductors in one conduit, with 105 deg C, 220 mil, 133% EPR insulation level with 1 /3 concentric neutral.
Derating is required for multiple circuits in a single duct bank.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 4-4
Pant- 41 of 137
b) 105 C conductor temperature, RHO = 90, 20 Celsius (degrees) ambient earth temperature, 100% load factor (applicable both
summer and winter loading).
c) All MW ratings assume a three-phase system with 97% power factor.
Table 4-6: Underground Cable Capacity — TWO Circuit Duct Bank (a)
Conductor
In Duct Bank IN
Two Circuit
(Amps)
MW (C)
3-Phase
#4/0 AL
222
4.65
500 kcmil AL
357
7.48
750 kcmil AL
438
9.18
Notes:
a) Based on AIEE-ICEA Power Cable Ampacity Ratings, Volume I and II and Okonite URO-J literature for TWO three-phase
circuits, three conductors in each conduit, with 105 deg C, 220 mil, 133% EPR insulation level with 113 concentric neutral.
b) 105 C conductor temperature, RHO = 90, 20 Celsius (degrees) ambient earth temperature, 100% load factor (applicable both
summer and winter loading).
c) All MW ratings assume a three-phase system with 97% power factor.
Other recommendations include:
• Phase load imbalance on distribution feeders should be minimized to avoid overloading
individual phases and reduce the need to oversize feeder backbone and tap
conductors. If the imbalance on any feeder exceeds 15% during high load conditions,
loads should be shifted between phases to reduce imbalance to 10% or below. This
practice will help minimize neutral current and reduce neutral -to -ground potential.
• Substation main regulated bus voltage should be maintained in a range of 122-volt to
126-volt on a 120-volt base. Acceptable voltage standards and ranges are presented in
Table 6-9 appearing in Chapter 6, Distribution System Evaluation.
• Voltage regulator settings should include first -house protection limiting the voltage to
126-volt maximum, and line drop compensation settings established to take into
account line characteristic parameters.
• During high load conditions, the capacity of voltage regulators can be increased by
programming the regulator controller to limit the maximum voltage adjustment range
from the normal +/-10% to a lesser range. This allows the regulator to carry greater
load (current), known as the so-called "load bonus" capability of most regulator controls.
The capabilities for "load bonus" operation are dependent on the specific regulators and
associated regulator controllers.
• Future substations should standardize on 15/20/25-MVA or 20/26/33-MVA, 115-
12.47/7.2-kV, power transformer ratings, serving four to six feeder bay capacity.
Substation improvement planning should begin when peak loading reaches the existing
substation facilities' self -cooled (OA) transformer ratings, and if continued growth is
expected to occur.
• The implementation of self -healing load -transfer smart switches at key locations within
the distribution system could be considered as a long-term goal to increase system
reliability and uninterrupted service.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 4-5
Pane 49 of 1.17
• The Electric Department should continue the practice of updating information in its
distribution mapping system so it can be readily available for line assessment, system
troubleshooting, future planning studies, as well as component inventory database.
4.5 CAPACITOR BANKS
The installation of capacitor banks should be considered to maintain power factors between 97
to 99 percent lagging at peak load and on feeders that experience low end of line voltage.
Improving peak power factor will reduce demand charges and improve system efficiency.
• For large commercial or industrial customers, the preferred location of capacitor banks is
the customer's site.
• A General Rule of Thumb for locating connected (fixed) capacitor banks on residential
feeders is to locate the capacitor bank at a distance of about 1/2 to 2/3 of the total line
length from the substation.
• If needed or desired, computer modeling simulation can provide optimal capacitor
location placement and necessary settings.
• Total installed fixed capacitor bank installations should be limited to avoid an excessive
leading power factor during low load conditions.
• Feeders with large, variable reactive power demands are often most effectively served
with a combination of fixed and automatically switched capacitor banks. Fixed capacitor
banks should be sized to the maximum that does not result in excessive leading power
factor under low load and switched capacitor banks should be sized to make up the
difference between fixed and the required kVAR under peak conditions at the target
minimum power factor (typically 0.97).
• When installing or replacing capacitors the following guidelines should be observed:
o Larger capacitor banks are typically more economical per kVAR than smaller
banks, and it is generally best to avoid the use of capacitor banks less than 300
kVAR whenever possible.
o Care should be exercised in sizing and locating switched capacitors so that the
maximum primary voltage flicker does not exceed 3 volts (120-volt base) during
normal capacitor switching.
o Capacitors should not be installed on the load side of single-phase sectionalizing
devices, as distorted or resonant voltage conditions may result from single -
phasing.
o Fixed capacitor banks should be manually switched seasonally as necessary to
avoid excessive leading power factors during lowest demand periods.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 4-6
Pane 43 of 137
Chapter 5 TRANSMISSION & SUBSTATION PLANNING
5.1 TRANSMISSION SYSTEM
5.1.1 Existing System
The City of Ashland's distribution service area is located within PacifiCorp's Medford service
territory with power delivered to the City over the PacifiCorp transmission system, and a short
0.8-mile BPA-owned transmission line tap into the Mountain Avenue Substation. A simplified
one -line diagram of substations and other descriptive diagrams of PacifiCorp's system related to
the service to Ashland's electric facilities appear in Figure 5-1. Relevant drawings or references
are provided in Appendix B.
Since the last study in 2013, PacifiCorp has completed the following upgrades to the Medford
region transmission facilities (refer to Appendix B1 and B4 in Appendix B for a transmission map
of the region)
• Added 115 kV circuit breaker at Oak Knoll Substation on 115 kV transmission supply
from Line 19 via Oak Knoll Tap in 2014.
• Replaced ABB relays with SEL-751 on Oak Knoll 5R55, 5R56, 5R70, 5R93 and 5R94 in
2014.
• Replaced Lone Pine 115 kV circuit breaker 2R1 on 115 kV transmission supply to Line
19 in 2020.
• Replaced Oak Knoll 12.5 kV circuit breakers 5R55 and 5R56, added HIFD to SEL-751,
and added RTAC in 2022.
• Installed new recloser on Oak Knoll 5R56 at Facility Point 01439001.0233601, July
2023.
Since mid-2013, the normal transmission supply to the City of Ashland has been 115 kV from
Lone Pine Substation via Baldy Switching Station. The 115 kV loops through Ashland from Oak
Knoll Substation to Mountain Avenue Substation and then to Ashland Substation. The Ashland
Substation 115 kV loop connects back to Lone Pine via a 115 kV to 69 kV transformer at
Belknap and a 69 kV line back to Lone Pine. If a transmission element along this path fails,
automated switching procedures will be implemented by PacifiCorp grid operations remotely to
isolate the affected line section and reconfigure the system to provide an alternate transmission
path to Ashland, Mountain Avenue, and Oak Knoll substations. The Copco 2 Substation
provides an alternate source via the Oak Knoll Tap.
Listed in Table 5-1 are PacifiCorp's normal and alternate transmission source circuits with
summer and winter rated capacity based on the limiting conductor size, type, and loading
criteria. According to PacifiCorp, the Sage Road Backup Source may have limited capability to
supply Ashland -Oak Knoll at summer peak due to other system loads. All other sources have
sufficient capacity to serve current and future peak winter and summer loads into the long-term
future.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 5-1
Pnnp 44 of 117
r0 LONE PNE lPgU
ro /PPH,
CITY OF ASHLAND
Figure 5-1: One Line Diagram — Transmission and Distribution System for Ashland
(Note. Mountain Avenue Substation has been owned by the City of Ashland since 2023.)
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 5-2
Pane 45 nt 1.17
Table 5-1: Transmission Source Continuous Ratings
Source Name
Description
Summer
Rating MVA)
tinter
Rating MVA
Normal Source to
Line 19 South 4 Baldy Switching 4 Line 74 4 Voorhies
116
Ashland Substation
rossing 4 Line 3 4 Talent Substation 4 Ashland Substation
Normal Source to Oak
ine 19 South 4 Baldy Switching 4 Line 19 4 Line 82 4 Oak
97
noll Substation
<noll Substation
opco2 Backup
opco2 4 Baldy Switching 4 Ashland transmission loop
110
?
ource
age Road Backup
Sage Road 4 Jacksonville 4 Griffin Creek 4 Voorhies
101
?
ource
:;rossing 4 Ashland transmission loop
5.1.2 PacifiCorp and BPA Future Plan
BPA has no major modifications currently planned that would involve the transmission system
serving the Ashland area. PacifiCorp planned improvements include:
• Replace 115 kV transmission switches 2R104 and 2R105 at Oak Knoll Tap with
upgraded switching capability in 2023-2024.
• Replace line protective fuses on Oak Knoll 5R56 and Ashland 5R241 distribution feeders
as part of wildfire mitigation upgrades. Project is planned to be completed in two phases
with work beginning in 2023.
• Meridian Remedial Action Scheme (RAS) Expansion in 2024. Addition of 115 kV
transmission circuit supplying several substations including Ashland, Mountain Avenue
and Oak Knoll to be armed for load shedding in an event that two 500 kV transmission
sources into the Medford region are lost during heavy load conditions.
• Replace relays on Ashland Substation 5R241 with SEL-751 w/HIFD in 2025.
• Replace Lone Pine — Whetstone 230 kV line in 2025.
• Expansion of Copco No. 2 Substation 115 kV yard to a breaker -and -a -half configuration
in 2025-2026 (provides alternate transmission supply to Oak Knoll, Mountain Avenue
and Ashland substations).
• Lone Pine — Sage Road 115 kV Line #2 (includes conversion of 69 kV Line 49-1 to 115
kV and new line extension) in 2026.
• Rebuild and conversion of Lone Pine to Belknap 69 kV transmission line to 115 kV (long-
range project proposed for 2032).
5.1.3 Discussion
With the facility improvements made over the last 10 years, all normal transmission sources are
now capable of serving the entire Ashland regional load (48.98 MW in 2032) into the long-term
future. The present looped configuration and available backup transmission paths provide the
City of Ashland with additional service integrity.
Reliability criteria established for most major utilities dictates that any transmission lines
supplying 50 MW or more, and serving two or more substations, should be provided with an
adequate alternate looped source if such capability can be provided at a reasonable cost. The
Copco2 and Sage Road backup sources transmission system satisfies this reliability criterion for
the foreseen future.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 5-3
Pane 48 of 117
The transmission configuration for this area has not changed. As discussed in the previous
study, a permanent fault on the 5.4-mile 115 kV Line 82 between the Ashland 115 kV breaker
(2R266) and the Oak Knoll 115 kV breaker (2R262) would interrupt supply to the entire City of
Ashland for some period of time. Restoration of power would be the responsibility of PacifiCorp.
If this does happen, PacifiCorp has stated that they will first remotely open the isolation switches
at Oak Knoll and Ashland Substations and remotely close the 115 kV breakers to restore power
to Ashland and Oak Knoll. Local PacifiCorp crews would then need to be dispatched to find the
faulted segment and isolate it via manually operated line switches before restoring power to
Mountain Avenue Substation. If possible, all customers would be restored before line crews
would begin repair work on the faulted line segment.
To reduce the impact of a 115 kV fault to the City, it would be necessary for PacifiCorp to install
additional 115 kV circuit breakers and protective relaying to help automatically restrict the
outage to a smaller portion of their transmission system. Alternatively, more remotely operated
isolation switches could be installed. However, the present level of sectionalizing provided by
PacifiCorp is typical for the number of substations and total number of customers involved.
Improvements to the 115 kV system sectionalizing capability should be a point of future
discussions between the City and PacifiCorp.
The weak link in the transmission system is the 0.81-mile 115 kV radial BPA segment tapped
from Line 82 that serves Mountain Avenue Substation. An outage on this line would de -energize
and take out Mountain Avenue Substation until repairs are completed. This line is owned by
BPA. As discussed above, an outage along Line 82 between Oak Knoll and Ashland
Substations would require manual switching to restore service to Mountain Avenue. Although it
would be desirable to have this tap looped and the switching automated, it is unlikely either will
happen and this situation is not unusual given the short length of this tap.
PacifiCorp has provided a summary of transmission outages affecting service to the City of
Ashland. Since 2013, there have been 30 outages of greater than 15 minutes with an average
outage time of approximately 140 minutes and a most common outage duration of 30 minutes.
BPA also provided an incomplete outage report for Mountain Avenue Substation which listed
four unique events in addition to some of the transmission outages provided by PacifiCorp.
There was a total of 3 BPA Planned Outages during this period with durations lasting anywhere
from 409 minutes to 2 days. It should be noted that planned outages have loads transferred
beforehand to ensure continuity of service to BPA customers. Detailed outage lists can be found
in Chapter 6.
5.2 SUBSTATION SYSTEMS
5.2.1 Existing Systems
Three substations provide distribution services to the City of Ashland. PacifiCorp owns both the
Ashland and Oak Knoll Substations providing service to the City of Ashland 12.47 kV
distribution rack facility (POD) and four distribution feeders within the PacifiCorp Ashland
Substation, and to the three 12.47 kV distribution points -of -delivery (POD) outside the
PacifiCorp Oak Knoll Substation. The City has owned the Mountain Avenue Substation since
2023 providing service to the City of Ashland distribution feeders. The POD is at 115 kV while
the BPA's meters are situated on the 12.47 kV bus.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 5-4
Pane. 47 of 137
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Since the previous study, the City has:
COKO
PA
• Extended the distribution rack at Mountain Avenue Substation to add more feeder
positions;
• Upgraded the recloser protective devices at Ashland Substation and installed the
controllers in a City -owned control building;
W&LI
• Installed City -owned pole mounted protective recloser controllers outside the PacifiCorp
Oak Knoll Substation;
• Installed a Supervisory Control and Data Acquisition (SCADA) system that now includes
all City -owned feeder circuit controllers at the Mountain Avenue, Ashland, and Oak Knoll
Substations;
• The electric department's SCADA system allows real-time monitoring and control of
connected system devices, such as substation reclosers and voltage regulators from a
computer terminal in the Electric Department's main office;
• Installed pad -mounted sectionalizing VFI switchgear for various new developments.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 5-5
Pane 4R of 137
The City purchases power from BPA with power delivered through a General Transfer
Agreement via the PacifiCorp transmission system and facilities as described below. Under its
contract with the City, PacifiCorp is responsible for providing service consistent with prudent
utility practices. BPA meters these independent points of delivery as identified in Table 5-2.
Table 5-2: BPA Metering Designations
Substation
Point -of Delivery Name
Meter Number
Ashland
Business/North Main/Railroad/North Mountain
575
Oak Knoll
East Main
1705
Highway 66
1014
Highway 99
1304
Mountain Avenue
I Morton/South Mountain/Wightman
1820
The existing substation transformer nameplate capacity, manufacture date, winter ratings, and
the transformation capacity available to serve City loads are shown in Table 5-3.
Table 5-3: Transformer Capacity Available
Ave.
Transformer
inter Planning
Substation
Peak
Annual
Monthly
Transformer
Nameplate Rating
Rating (,Ha)
Secondary
Transformer
Load
Energy
Load
Voltage
(MVA) at Specified
(MW) at
of
Regulation
Mfgr. Date
(kW)
(kWh)
Factor
(kV)
Temp Rise
Specified
Ambient Temp
Ashland
Substation
115-
12/16/20 @ 55 °C
°
- 9 kVA
3499
19,520
-56,500,000
2.6%
12 47/7.2
13.4/18/22.4 @ 65 °C
5.7 @ 5 C
b, c
k om.
Nom.
1974s
/ _ 10 %
Mountain Ave
1-3N 2000kVA 7.2
Substation
17.750
60,000,000
0.2% �B�
115-
12/16/20 55 °C
5.7 @ 5 °C
b, c
V
-1573
12.47/7.2
13.4/17.9/2 _4 @ 65 °C
/- 10°!0
10%
1978
Oak Knoll
Substation
12,720
115-
12/16/20 @ 55 °C
5.7 @ 5 °C
b, c
LTC
3234
12.47/7.2
°
13.4/17.9/22.4 @ 65 C
1967
Oak Knoll
-59,600,000
6.6% (°)
1-30 2000/2667 kVA
Substation
3856
11,050
115-
12.47/7.2
15/20/25 @ 55 °C
8.8 @ 5 °C
b, c
.2 kV Nom.
/- 10%
1992
Notes:
a) Typical planning MW ratings are at 0.97 power factor, 5 degrees C ambient, and 100% load factor based on ANSI standard
C57.91 - 2011.
b) Peak Load, Annual Energy, and Ave. Monthly Load Factor figures are maximum values from the period of December 2023
through December 2032. Al values displayed are downloaded from BPA raw metered data.
c) If voltage regulator maximum nameplate rating is exceeded the City should implement the equipment Load Bonus, Add -Amp or
similar feature to adjust the current range upward to match the load but limit the voltage regulation.
d) Winter planning ratings based on Table 3 in IEEE C57.91 - 2011.
e) Both Ashland Substation and Oak Knoll Substation feed one PacifiCorp circuit, which has a peak demand of about 5.5 MW and
9.0 MW respectively -
One -line diagrams of each substation are presented in Appendix B as 132, 133, and 135/136. A
brief description of each substation and its facilities that serve the City follows below:
5.2.2 ASHLAND SUBSTATION
At Ashland Substation, the City takes delivery from the regulated 12.47/7.2 kV bus through one
PacifiCorp secondary 1200 A breaker (5R241). This PacifiCorp breaker feeds a City -owned
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 5-6
Pant- 49 of 137
distribution rack and four distribution reclosers serving four City feeder circuits. Both the
substation and the City -owned distribution rack were constructed in the 1950/60s era.
The City of Ashland's four reclosers serving the feeders from the Ashland Substation City's
distribution rack includes a fused bypass arrangement for each feeder, should a recloser be out -
of -service or require maintenance. The feeder reclosers are rated 560 A with 400 A bypass
fuses.
In 2013 the City replaced and upgraded the recloser controllers, placing them in an existing City
owned and refurbished building across Nevada Street from the Ashland Substation. The City
has implemented SCADA capability for these four feeders and in 2014 considered replacement
of the distribution rack with a new City -owned substation due to age, reliability, and safety
concerns, but no further action was taken.
Also in 2013, PacifiCorp upgraded the 69 kV terminal of the Ashland Substation to 115 kV and
removed the 69/115 kV auto -transformer. The substation is now looped at 115 kV. Distribution
facilities are served through a 116 kV x 12.47/7.2 kV, 12/16/20 MVA transformer (T-3499) with a
manufacture date of 1974, three single-phase voltage regulators, and a 12.47 kV distribution
rack with main and auxiliary buses. The 115 kV transmission source from Talent Substation and
Voorhies Crossing is protected with a primary circuit switcher. The 115 kV source on Line 82
from Oak Knoll Substation has a disconnect switch which can be remotely operated.
In addition to breaker 5R241, a 15.5 kV, 1200 A secondary breaker (5R245) serves the
PacifiCorp Valley View distribution circuit. Should breaker 5R241 serving the City fail or need to
be removed from service, City loads would be protected by the City -owned reclosers, the 400A
City owned recloser by-pass fuses, or transferred via the auxiliary bus to PacifiCorp breaker
5R245. Breaker 5R245 was replaced with a 1200 A rated breaker in 2015. It will have the
capacity to serve all Ashland Substation load in addition to the normal PacifiCorp loads should
the need arise.
5.2.3 OAK KNOLL SUBSTATION
At Oak Knoll Substation, PacifiCorp provides 12.47 kV service to the City from three distribution
breaker positions serving three separate PODS and City feeder circuits. City ownership of the
Oak Knoll feeders begins just outside the substation.
The PacifiCorp Oak Knoll Substation, constructed in 1965, has two 115 kV incoming terminals
serving two power transformers with both transformers normally in service. Transformer T- 3234
(Bank #1) rated 116 kV x 12.47/7.2 kV, 12/16/20 MVA with a manufacture date of 1967, has
load -tap changer regulation and normally feeds the substation bypass bus serving the
PacifiCorp Siskiyou distribution feeder and the City of Ashland Highway 99 feeder.
Transformer T-3856 (Bank #2) rated 116 kV x 12.47/7.2 kV, 15/20/25 MVA with a manufacture
date of 1992, has secondary voltage regulation and normally feeds the substation main bus
serving the City of Ashland Highway 66 and East Main feeders.
Feeder breakers 5R56 and 5R93 are rated for 600 A, and 5R70 is rated for 1200 A. The
substation also has a normally open 1200 A tie breaker that can connect the main and bypass
buses. The substation configuration offers flexible switching should any one device fail or need
to be out -of -service for maintenance. The City of Ashland owns no equipment within the Oak
Knoll Substation.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 5-7
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The City has installed three separate pole -mounted reclosers just outside the PacifiCorp Oak
Knoll Substation. This improvement allows the City to directly control these feeders without
involving PacifiCorp staff. The installation included equipment with SCADA capability allowing
the City to remotely monitor and control these feeders.
5.2.4 MOUNTAIN AVENUE SUBSTATION
At Mountain Avenue Substation the site, high voltage equipment, control building and ancillary
components previously owned by BPA were purchased by the City in 2023. The City now takes
delivery of power at 115 kV and owns all high -voltage equipment plus the previously City -owned
three-phase voltage regulator, two distribution racks plus sectionalizing equipment, the six
distribution reclosers and feeder getaway facilities presently serving four feeder circuits. The
City now owns the Control Building and all ancillary devices plus the previously City -owned
panel -mounted feeder recloser controllers and SCADA system equipment.
The Mountain Avenue Substation, constructed in 1994, has one 115 kV incoming source.
Distribution facilities are served through a 115 kV x 12.47/7.2 kV, 12/16/20 MVA rated
transformer (T-1573), with a 1976 manufacture date, and secondary voltage regulation feeding
a 12.47 kV distribution rack with main and auxiliary buses. A 115 kV circuit switcher provides
transformer protection.
The original distribution facilities, consisting of a rack serving three City feeders through 560 A
reclosers, were expanded by the City in 2010 to include the addition of a second distribution
rack capable of serving three additional City feeders. The distribution racks are configured with
main and auxiliary buses allowing flexible switching arrangements so that load can be
transferred to another source or circuit should a recloser need to be taken out -of -service. The
racks are tied together via gang -operated load break tie switches and the second (newer)
distribution rack also contains a transformer bay to be served from a future second power
transformer.
5.3 SUBSTATION HISTORY AND OWNERSHIP
In 1996, Bonneville Power Administration (BPA) began to offer the sale of BPA-owned
Distribution Substations to its customers, and early on BPA approached City of Ashland offering
the sale of Mountain Avenue Substation. The City considered purchase of the substation and
had its present worth evaluated in 2003 and again in 2013, however BPA's asking price was
considerably above its assessed value and the City concluded this option was not in its best
interest at that time.
Because of the great value in cost savings for eliminating BPA's low voltage transformation
'delivery charge' by taking ownership of the substation and power delivery at transmission
voltage, the City successfully negotiated purchase of the substation from BPA in October 2023.
Prior to the Mountain Avenue Substation purchase the City took delivery of all power at the
substation at the 12.47/7.2 kV secondary voltage and was required to pay a Utility Delivery
Charge (UDC) for all energy purchased through the BPA-owned substation. BPA put the UDC
charge in place in 1996 to recover the costs of owning, operating, and maintaining low -voltage
facilities. Since then, BPA has increased these rates significantly to fully recover costs from
utilities that continue to take low -voltage delivery.
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The BPA Delivery Charge rate increased from $0.75/kW in 1996, to $1.399/kW in October 2013,
to $1.27/kW in 2022, to $1.12/kW in 2024. Approximately 10 years ago BPA stated it was likely
to continue to increase every two years in 5 to 15 percent increments. However, since then BPA
has renamed Delivery Charge to Transfer Service and dispersed these charges into other
account areas. Nonetheless, the monthly and annual savings from the City's reduction in Utility
Delivery Charges because of the purchase of Mountain Avenue Substation is a significant
source for continuing support for the electrical department's objective of gaining control of its
own power delivery, system configuration, switching schemes, and facility maintenance.
Presently, based on the average substation monthly peak of 11,058 kW in 2021 (Table 5-4) and
the current Transfer Service rate of $1.12/kW, the City saves approximately $12,385 monthly
and $148,620 annually by owning the Mountain Avenue Substation.
The City could further reduce the transfer service cost with construction of a City -owned
substation on Nevada Street across from PacifiCorp's Ashland Substation site. By doing this the
City could save approximately $11,409 monthly and $136,913 annually based on an average
substation monthly peak of 10,187 kW (Table 5-5).
Substation ownership allows the City to independently determine substation facility needs and
reduce the total cost of providing service in the long-term. However, the City would also assume
the risk associated with owning substation facilities as well as operations and maintenance
costs.
Table 5-4: Energy and Demand Data — Meter 1820, Mountain Avenue Substation, 2021
Month
Energy
kWh
Demand
k
Peak Hour
& Date
January
5,718,375
11,950
1/26/2119:00
February
5,159,100
11,300
2/4/219:00
March
4,984,900
10,600
3/16/219:00
April
3,782,475
1 8,125
4/26/219:00
May
3,682,250
1 13,475
5/13/2119:00
June
4,376,688
14,350
6/28/2117:00
July
5,076,375
11,700
7/6/2118:00
August
4,586,300
12,000
8/11/2118:00
September
3,701,650
8,750
9/8/2118:00
October
4,216,725
8,900
10/12/219:00
November
4,939,000
10,150
11/22/219:00
December
6,146,975
11,400
1 12/27/2118:00
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Table 5-5: Energy and Demand Data — Meter 575, Ashland Substation, 2021
Month
Energy
kWh
Demand
kW
Peak Hour
& Date
January
5,270,920
10,680
1/26/2119:00
February
4,740,140
10,700
2/7/2113:00
March
4,626,900
9,280
3/15/2110:00
April
3,633,860
1 7,320
4/6/218:00
May
3,485,960
8,840
5/31/2119:00
June
4,576,080
14,310
6/28/21 17:00
July
5,352,110
12,360
7/3/21 19:00
August
4,663,520
11,780
8/11/21 18:00
September
3,734,660
8,830
9/8/21 18:00
October
4,000,820
8,060
10/12/21 8:00
November
4,659,090
9,510
11/22/218:00
December
5,809,360
10,570
12/31 /21 18:00
5.4 IMPROVEMENT DISCUSSION
5.4.1 Substation Expansion
The power flow analysis indicates that the loss of either the Ashland or Mountain Avenue
Substation transformer under current peak load conditions could lead to the inability to serve
customers without significant transformer overload and accelerated transformer aging.
The PacifiCorp Ashland Substation located close to the City's load center contains a City -owned
12.47 W distribution rack that is old and in deteriorating condition. In the past the City had
considered a new distribution rack that would enhance flexibility and maintenance, however, the
new distribution rack would still be served from a single PacifiCorp breaker. In 2011 the City
considered construction of a City -owned substation across Nevada Street from PacifiCorp's
Ashland Substation on City -owned property. This concept should now be reconsidered. The City
has easy access to this site with looped transmission source readily available and a control
building is already in place. By constructing a City -owned substation at this location and taking
delivery at 115 W the City would reduce the power purchase transformation charges similar to
Mountain Avenue Substation.
The Oak Knoll Substation, located in the southeast region of the City's service area, is well
situated for load growth in its general vicinity. However, due to its location it has limited ability
for extension that could efficiently reach the City's core load center. The previously installed
City -owned sectionalizing reclosers on the three Oak Knoll feeders outside the substation,
which have SCADA monitor and control, is about the extent of improvements the City can make
to enhance service from these feeders.
The most practical substation facility for improvement and future expansion is the Mountain
Avenue Substation. This substation recently purchased by the City is centrally located to the
core load and consists of a developed site suitable for expansion. In 2008 the City expanded its
distribution facilities by adding a second distribution rack with three new feeder bays and a
transformer bay. The Mountain Avenue Substation has been constructed so that capacity can
be increased with the addition of a second power transformer.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 5-10
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It is expected the City will need additional substation transformation capacity within the
intermediate (10-year) future to comply with the single -contingency planning criteria, and as
noted previously in this study it is suggested that the City plan to add this second transformer
bank. This is because of the age of the existing transformer and time involved to procure,
fabricate, and deliver a second transform to the site.
Once a second transformer is available it will:
• relive the concern of having the ability to meet expected peak loads,
• provide single contingency outage flexibility at peak load, and
• reduce the exposure to lengthy outages while a mobile transformer is placed in service.
5.5 IMPLICATIONS OF NERC BULK ELECTRIC SYSTEM CLASSIFICATION (BES)
FERC has recently issued its Final Ruling regarding the NERC definition of the Bulk Electric
System (BES). In its ruling it accepted the NERC definition of the BES. Portions of the electric
power grid falling under the BES definition are required to maintain a specified level of reliability
and security. This imposes additional record -keeping and documentation requirements on the
owning utility and can result in the imposition of fines if the NERC requirements are not met.
The basic rule is that transmission facilities operating at 100 kV or higher are considered part of
the BES. However, this voltage limit is not an absolute dividing line. There are several
"Exclusions" and "Inclusions" that are applied that depend on system criteria other than voltage.
Because the City takes power delivery at 115 kV but does not own the transmission system,
only serves load, and is not operated as a contiguous loop its facilities are not considered part
of the BES designation. This is because of Exclusion E-1 in the NERC BES definition as
described in the FERC ruling:
Exclusion E1 provides as follows:
Radial systems: A group of contiguous transmission Elements that emanates from a single point of
connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusions 12, 13, or 14, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in
Inclusion 12, 13, or 14, with an aggregate capacity of non -retail generation less than or equal to
75 MVA (gross nameplate rating).
Note 1— A normally open switching device between radial systems, as depicted on prints or one -line
diagrams for example, does not affect this exclusion.
Note 2 — The presence of a contiguous loop, operated at a voltage level of 50 kV or less, between
configurations being considered as radial systems, does not affect this exclusion.
5.6 CONCLUSION
Over the last 10 years, PacifiCorp has made major improvements to the transmission facilities
serving the City of Ashland. The current looped configuration and available backup transmission
paths provide the City with satisfactory service reliability and capacity into the long-term future.
The substation facilities serving the City of Ashland provide adequate capacity to serve the
City's winter and summer peak load under normal conditions. However, with additional load
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 5-11
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growth and in contingency situations, the City's electric system may not be able to meet the
single contingency outage criteria.
As the City considers options for additional transformation capacity, it should
• Consider adding a second transformer bank at Mountain Avenue Substation, and
• Revisit the option of a new City -owned substation on Nevada Street with removal of its
distribution facilities from the PacifiCorp Ashland Substation.
5.7 RECOMMENDATION
The major improvement recommendations presented below are in order of priority, selected
from the options identified in this chapter and relate to substation facilities serving the City's
electric facilities. Summary descriptions and associated costs for these and miscellaneous
improvements appear in Table 2-1. These estimates assume the City will incur costs directly for
the improvements with construction performed by contractors. The estimates do not include any
site acquisition, establishment of rights -of -way and easements, or environmental and impact
permitting studies, since none are believed to be necessary. It is suggested the City thoroughly
explore each recommended improvement and determine complete costs prior to moving
forward with any improvement option.
Major Improvement 1 — Mountain Avenue Substation
Expansion of the substation facilities by adding a second transformer bank. This will require the
necessary primary dead-end structure and protection device, the secondary voltage regulation,
required bus support structures and buswork, plus required relaying and control ancillary
components and construction installation.
Cost Estimate Power Transformer $1,350,000
Substation Components and Construction 750,000
Total Cost $2,100,000
Major Improvement 2 — New Nevada Street Substation
Construct a new City -owned Nevada Street Substation on existing City -owned property. This
will require the necessary site development, power transformer, primary dead-end in -out
structures and protective device, voltage regulation, required bus support structures and
buswork, plus relaying and control ancillary components and construction installation. The City
may decide to use the existing control building or replace it new.
Cost Estimate Power Transformer $1,350,000
Substation Components and Construction $1,650,000
Total Cost Estimate $3,000.000
Major Improvement 3 — Replace Mountain Avenue Substation - Bank 1 Transformer
As mentioned elsewhere in this study the existing bank 1 power transformer was fabricated in
1976 and installed `used' at Mountain Avenue Substation. Because of the age and expected
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEA48ER 2024 5-12
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service life of this transformer the City should plan for its replacement which could take up to
five years from creation of a procurement document to transformer installation.
Cost Estimate Power Transformer $1,350,000
Engineering/Contractor Services $ 200,000
Total Cost $1,550,000
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 5-13
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Chapter 6 DISTRIBUTION SYSTEM EVALUATION
6.1 BACKGROUND
The City of Ashland's electric distribution system was evaluated for capacity under high and low
load conditions. The high load case is based on historic metering data. To produce 10-year and
20-year load estimates for analysis and planning, the base -case system peak demand was
adjusted to increase proportional to the population growth as outlined in Chapter 3. Specific
areas of system growth are modeled and discussed in detail in Chapter 7. Table 6-1 below,
indicates loading conditions examined in this study.
Table 6-1: Study Loading Conditions
Base Case
(Light)
Base Case (Historical
Peak, 2021)
10-Year
(2033) W
20-Year
(2043)W
System Coincident Peak te)
31.8 MW
45.9 MW
49.3 MW
53.0 MW
Ashland Substation Modeled Load (b)
9.4 MW
14.3 MW
15.5 MW
15.9 MW
Mountain Avenue Substation Modeled load (b)
11.3 MW
14.2 MW
15.2 MW
16.2 MW
Oak Knoll Substation Modeled load (b)
11.2 MW
17.6 MW
19.0 MW
20.4 MW
Notes:
a) Coincident system peak demand based on BPA's hourly data.
b) Coincident system peak demand for individual substations with normal switching configurations. Load allocation in the model
considers large clients using their actual peak and small customers by linear distribution. This load allocation process may
result in a small difference between the total substation feeder loads and the system loads listed above, but it is acceptable to
this study.
c) Detailed forecast growth rate is discussed in Chapter 3.
The preparation of this study is based on detailed distribution system information gathered from
the City of Ashland staff and the distribution system GIS maps. The GIS maps include data on
location, name, connectivity, size, and rating for system components such as conductors,
transformers, capacitor banks, switches, protective devices, poles, and vaults. The analysis
model used, which indicates node and segment electrical data, is included in Appendix C.
6.2 DISTRIBUTION SYSTEM CAPACITY
Results of the model analysis show the City's distribution system presently provides reliable
service at acceptable voltage levels for all loading conditions including the historical peak when
operating in the normal system configuration.
Substation meter data was obtained through the BPA customer portal website for each point of
delivery. Table 6-2 to Table 6-6 indicates energy use and peak demand data for all substation
feeders for the 10-year historical peak in 2021. Individual feeder data at Ashland Substation and
Mountain Avenue Substation is not available from BPA, however, the City's SCADA system has
an archive of individual feeder data.
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Table 6-2: Ashland Substation Loading Summary 2021, BPA Meter #575
Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
peak Hour & Date
Power
Factor
Load
Factor
January
5,270,920
2,150
10,680
1/26/2119:00
100
66.33
February
4,740,140
1,050
10,700
2/7/2113:00
100
65.92
March
4,626,900
180
9,280
3/15/2110:00
100
67.1
April
3,633,860
450
7,320
4/6/218:00
100
68.95
May
3,485,960
25,550
8,840
5/31/2119:00
100
53
June
4,576,080
389,700
14,310
6/28/2117:00
99.64
44.41
July
5,352,110
624,220
12,360
7/3/2119:00
99.33
58.2
August
4,663,520
387,460
11,780
8/11/2118:00
99.66
53.21
September
3,734,660
97,860
8,830
9/8/2118:00
99.97
58.74
October
4,000,820
200
8,060
10/12/218:00
100
66.72
November
4,659,090
710
9,510
11/22/218:00
100
67.95
December
5,809,360
6,910
10,570
12/31/2118:00
100
73.87
Notes:
a) The reactive power consumption in summer is higher, resulting in relatively lower power factors, but is still dose to unity.
Table 6-3: Mountain Avenue Substation Loading Summary 2021, BPA Meter #1820
Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
Peak Hour & Date
Power
Factor
Load
Factor
January
5,718,375
0
11,950
1/26/2119:00
100.00
64.32
February
5,159,100
0
11,300
2/4/219:00
100.00
67.94
March
4,984,900
0
10,600
3/16/219:00
100.00
63.29
April
3,782,475
0
8,125
4/26/219:00
100.00
64.66
May
3,682,250
9,200
13,475
5/13/2119:00
100.00
36.73
June
4,376,688
231,325
14,350
6/28/2117:00
99.86
42.36
July
5,076,375
429,125
11,700
7/6/2118:00
99.64
58.32
August
4,586,300
351,550
12,000
8/11/2118:00
99.71
51.37
September
3,701,650
231,450
8,750
9/8/21 18:00
99.81
58.76
October
4,216,725
80,450
8,900
10/12/219:00
99.98
63.68
November
4,939,000
129,750
10,150
11/22/219:00
99.97
67.49
December
6,146,975
151,200
11,400
12/27/21 18:00
99.97
72.47
Notes:
a) The reactive power consumption in summer is higher, resulting in relatively lower power factors, but is still dose to unity.
Table 6-4: Oak Knoll Substation Loading Summary 2021, Feeder E. Main, BPA Meter #1705
Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
Peak Hour & Date
Power
Factor
Load
Factor
January
1,950,530
122,090
3,990
1/26/219:00
99.8
65.71
February
1,784,970
92,470
3,990
2/4/219:00
99.87
66.57
March
1,758,780
166,670
3,650
3/16/219:00
99.55
64.85
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 6-2
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Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
peak Hour & Date
Power
Factor
Load
Factor
April
1,429,190
191,430
2,970
4/6/219:00
99.11
66.83
May
1,401,210
180,840
3,140
5/31 /21 16:00
99.18
59.98
June
1,787,970
186,900
6,160
6/28/2116:00
99.46
40.31
July
2,055,120
147,900
5,070
7/29/2116:00
99.74
54.48
August
1,845,910
119,120
4,960
8/13/2116:00
99.79
50.02
September
1,481,050
145,290
3,880
917/2117:00
99.52
53.02
October
1,524,330
217,490
3,110
10/12/21 9:00
99
65.88
November
1,730,920
171,490
3,510
11/22/219:00
99.51
68.4
December
2,100,070
97,070
3,870
12/15/2111:00
99.89
72.94
Notes:
a) The reactive power consumption in summer is higher, resulting in relatively lower power factors, but is still dose to unity.
Table 6-5: Oak Knoll Substation Loading Summary 2021, HWY 66, BPA Meter #1014
Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
Peak Hour & Date
Power
Factor
Load
Factor
January
1,790,430
15,250
3,620
1/26/2111:00
100
66.48
February
1,652,060
9,950
3,340
2/4/21 11:00
100
73.61
March
1,715,400
15,950
3,270
3/15/21 11:00
100
70.6
April
1,443,580
22,060
2,670
416/219:00
99.99
75.09
May
1,438,780
55,870
3,110
5/31 /21 18:00
99.92
62.18
June
1,725,730
188,600
4,690
6/28/2117:00
99.41
51.11
July
1,945,660
246,510
4,160
7/612117:00
99.21
62.86
August
1,764,510
174,980
4,080
8/11/2117:00
99.51
57.8
September
1,446,660
68,670
3,230
9/7/2117:00
99.89
62.21
October
1,523,940
19,400
3,320
10/26/2115:00
99.99
61.7
November
1,614,380
2,610
3,060
11/8/219:00
100
73.17
December
1,901,970
500
3,440
12/15/2118:00
100
74.31
Notes -
a) The reactive power consumption in summer is higher, resulting in relatively lower power factors, but is still dose to unity.
Table 6-6: Oak Knoll Substation Loading Summary 2021, HWY 99, BPA Meter #1304
Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
peak Hour & Date
Power
Factor
Load
Factor
January
2,496,400
20
5,610
1/26/2119:00
100
59.81
February
2,265,700
50
5,200
214/219:00
100
64.84
March
2,129,760
19,270
4,750
3/16/219:00
100
60.35
April
1,565,060
143,910
3,500
4/12/218:00
99.58
62.11
May
1,482,860
153,490
4,130
5/31 /21 19:00
99.47
48.26
June
1,901,330
185,640
6,640
6/28/2118:00
99.53
39.77
July
2,205,370
174,690
5,560
713/2119:00
99.69
53.31
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 6-3
Pane 59 of 137
Month
Energy
(kWh)
Reactive
(kVARh)
Demand
(kW)
Peak Hour & Date
Power
Factor
Load
Factor
August
1,927,680
114,440
5,370
8/11/2119:00
99.82
48.25
September
1,501,360
88,960
3,840
9/6/2119:00
99.82
54.3
October
1,713,090
82,050
4,910
10/26/2115:00
99.89
46.89
November
2,053,910
25,770
4,490
11/8/218:00
99.99
63.45
December
2,710,880
9,680
5,200
12/27/2119:00
100
70.07
Notes:
a) The reactive power consumption in summer is higher, resulting in relatively lower power factors, but is still dose to unity.
A useful aid to help visualize system load characteristics are the winter and summer daily load
profiles as seen in Figure 6-1 and 6-2, respectively. Peak loads are represented for each hour of
the day, averaged separately for weekdays and weekends.
The winter load profile, Figure 6-1, created from recorded data during the study period shows a
trend with daily winter peaks in the morning and early evening hours as expected for a
predominantly residential load system. The power consumption during weekend days is slightly
lower than on weekdays. The summer load profile, Figure 6-2, created from recorded data
during the study period shows a different trend with single afternoon peak characteristics likely
attributed to air conditioning or industrial/commercial load. Additionally, the power consumption
during weekend days is slightly lower in the daytime.
The general patterns seen in these daily load profiles may give the City a better idea of how to
achieve system load balance if desired. Loading could be shifted to different times of the day,
such as the operation of motors to fill reservoirs or operate lift stations.
33000
3 29000
Y
o 27000
C
A
y 25000
d
23000
d
Q 21000
tM'TC041
17000
W-1
--*--Hourly Average - Weekday, Winter —0 -Hourly Average -Weekend, Winter
Figure 6-1: Average Hourly Peak Load for January 2017
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 6-4
Pane Fin of 137
30000
28000
26000
3 24000
Y
22000
C
R
m 20000
d
18000
L
d
Q 16000
14000
12000
10000
--0—Hourly Average -Weekday, Summer f Hourly Average - Weekend, Summer
Figure 6-2: Average Hourly Peak Load for June 2021
Ashland is currently providing quality electric service and has made continual system
improvements since the last study in 2013. Based on the most recent system peak (June 2021),
with any feeder out -of -service, the City can serve loads from adjacent circuits under normal
conditions. However, loss of some feeder circuits during peak conditions could cause other
parts of the system to exceed capacity. Additionally, the loss of a substation transformer at peak
load could result in severe transformer overload conditions at another substation. These
conditions will become more severe as load growth occurs and could lead to the City not being
able to meet single contingency outage criteria in the future without an increase in system
capacity.
6.2.1 Distribution System
The City's electric system serves customers from 10 distribution feeders, having a total of 12
substation feeder positions available. Table 6-7 and Table 6-8 summarize the summer and
winter existing feeder voltage ratings, backbone conductor characteristics, capacities, kW
ratings, recommended loading, and actual (non -coincidental) loading from 2014 through 2023.
From data in these two tables, it appears that:
• All the feeders currently have adequate capacity to serve peak loads under normal
conditions and under the emergency sectionalized conditions evaluated.
• However, some feeders are more loaded than others, and this plus load imbalance
reduces operational flexibility during emergency operating conditions. As future load
growth occurs, the City should add load strategically, where feasible, to balance loading
between existing feeders to minimize feeder and conductor overloading especially under
sectionalized conditions.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 6-5
Pane 61 of 117
Table 6-7: Existing Feeder Loading -Normal Conditions (SUMMER)
Feeder Main Conductors
Summer Peak Load
Peak Load
% of Conductor
Substation/
Voltage
Size/Material(c)
Rating tblla>
Present
Recom'd
Rating
Recom'd
Feeder
(kV)
Amps
kW
(kW) (a)
(kW) (e)
Loading
Ashland Substation
A2000 -
Business
12.47/7.2
556 AAC
642
13,450
6,076
7,500
45%
56%
A2001 -
12.47/7.2
750 kcmil, URD
505
10,580
6,110
7,500
58%
71%
North Main
12.47/7.2
556 AAC
642
13,450
6,110
7,500
45%
56%
12.4717.2
750 kcmil, URD
505
10,580
2,226
7,500
21 %
71 %
A2002 -
Railroad
12.47/7.2
556 AAC
642
13,450
2,226
7,500
17%
56%
12.4717.2
336 AAC
464
9,721
2,226
7,500
23%
77%
A2003 - N.
12.47/7.2
See information for Feeder M3006
Mountain Alt
Mountain Avenue Substation
M3006 - N.
12.47/7.2
750 kcmil, URD
505
10,580
1,677
7,500
23%
71 %
Mountain
12.47/7.2
556 AAC
642
13,450
1,677
7,500
16%
56%
M3009 -
12.47/7.2
750 kcmil, URD
505
10,580
5,803
7,500
12%
71 %
Morton
12.47/7.2
336 AAC
464
9,721
5,803
7,500
55%
77%
12.47/7.2
750 kcmil, URD
505
10,580
4,603
7,500
60%
71 %
Mountain S. M
12.47/7.2
566 AAC
642
13,450
4,603
7,500
44%
56%
12.47/7.2
336 AAC
464
9,721
4,603
7,500
34%
77%
12.47/7.2
750 kcmil, URD
505
10,580
2,268
7,500
47%
71 %
M3015 -
Wightman
12.47/7.2
566 AAC
642
13,450
2,268
7,500
21 %
56%
12.47/7.2
336 AAC
464
9,721
2,268
7,500
17%
77%
Oak Knoll Substation
K4056
(5R56) -
12.47/7.2
336 AAC
464
9,721
6,357
7,500
65%
77%
HWY 99
K4070
(5R70) -
12.4717.2
336 AAC
464
9,721
4,632
7,500
48%
77%
HWY 66
K4093
(5R93) - E.
12.4717.2
336 AAC
464
9,721
5,808
7,500
60%
77%
Main
a) Individual winter feeder peaks are from City's SCADA system data for 2022.
b) All kW ratings assume a three-phase system with 97% power factor.
c) Conductor size/material data obtained from City staff and system maps.
d) Overhead conductors shown with summer ampacity ratings.
e) Recommended loading is for normal conditions, non -sectionalized. More discussion can be found in Chapter 4
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 6-6
Pane 69 of 137
Table 6-8: Existing Feeder Loading -Normal Conditions (WINTER)
Feeder Main Conductors
Winter Peak Load
Peak Load
% of Conductor
Substation/
Voltage
Size/Material(c)
Rat! ng(b) (d)
present
Recom'd
Rating
Recom'd
Feeder
(kV)
Amps
kW
(kW) ta)
(kW) (e)
Loading
Ashland Substation
A2000 -
12.47/7.2
556 AAC
925
19,379
4,820
7,500
25%
39%
Business
A2001 -
12.47/7.2
750 kcmil, URD
505
10,580
4,613
7,500
44%
71%
North Main
12.47/7.2
556 AAC
925
19,379
4,613
7,500
24%
39%
12.4717.2
750 kcmil, URD
505
10,580
1,472
7,500
14%
71%
A2002 -
Railroad
12.47/7.2
556 AAC
925
19,379
1,472
7,500
8%
39%
12.47/7.2
336 AAC
670
14,037
1,472
7,500
10%
53%
A2003 - N.
12.47/7.2
See information for Feeder M3006
Mountain Alt
Mountain Avenue Substation
M3006 - N.
12.47/7.2
750 kcmil, URD
505
10,680
924
7,500
9%
71%
Mountain
12.4717.2
556 AAC
925
19,379
924
7,500
5%
39%
M3009 -
12.47/7.2
750 kcmil, URD
505
10,580
4,858
7,500
46%
71%
Morton
12.47/7.2
336 AAC
670
14,037
4,858
7,500
35%
53%
12.47/7.2
750 kcmil, URD
505
10,580
4,145
7,500
39%
71%
Mt - S.
12.4717.2
566 AAC
925
19,379
4,145
7,500
21 %
39%
Mountain
12.47/7.2
336 AAC
670
14,037
4,145
7,500
30%
53%
12.47/7.2
750 kcmil, URD
505
10,580
2,067
7,500
20%
71%
M3015 -
Wightman
12.4717.2
566 AAC
925
19,379
2,067
7,500
11 %
39%
12.4717.2
336 AAC
670
14,037
2,067
7,500
15%
53%
Oak Knoll Substation
K4056
(5R56) -
12.47/7.2
336 AAC
670
14,037
5,613
7,500
40%
53%
HWY 99
K4070
(5R70) -
12.47/7.2
336 AAC
670
14,037
3,360
7,500
24%
53%
HWY 66
K4093
(5R93) - E.
12.4717.2
336 AAC
670
14,037
3,952
7,500
28%
53%
Main
a) Individual summer feeder peaks are from City's SCADA system data for 2022.
b) Adl kW ratings assume a three-phase system with 97% power factor.
c) Conductor size/material data obtained from City staff and system maps.
d) Overhead conductors shown with winter ampacity ratings_
e) Recommended loading is for normal conditions, non -sectionalized- More discussion can be found in Chapter 4.
6.2.2 Capacitor Banks
The City's electric distribution system presently has eight (8) 12.47/7.2 kV capacitor banks
installed at various locations throughout the system. Capacitors are generally used to maintain
adequate voltage and power factor, as well as reduce line losses. Table 6-9 shows the electric
system's existing capacitor banks, their feeder, location, size and type of control.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 6-7
Pant- 61 of 1.17
Based on the analysis results of the present system configuration, no additional capacitor
installations are required within this intermediate planning period for overall system correction.
For general recommendations regarding capacitor placement and configuration, see Chapter 4
Table 6-9: Electric System Capacitor Banks
Feeder
Location
Rating
Type and Status
A2000 - Business
Heiman & Tracks
600 kVAR
Fixed "ON" At 12.47 kV
A2001 - N. Main
Maple Street
600 WAR
Fixed "ON" At 12.47 kV
M3009 - Morton
Morton & East Main
600 kVAR
Fixed "ON" At 12.47 kV
M3012 - S. Mountain
S. Mountain & Iowa
900 kVAR
Automatic, At 12.47 kV
M3015 - Wightman
N. Mountain & Clear Creek
600 kVAR
Automatic, At 12.47 kV
5R56 - Hwy 99
35 Crowson Rd
600 kVAR
Automatic, At 12.47 kV
5R70 - Hwy 66
Hwy 66 & Crowson Rd
600 kVAR
Automatic, At 12.47 kV
r5R93 - E. Main
3018 Green Springs Hwy 66
900 kVAR
Automatic, At 12.47 kV
6.3 DISTRIBUTION EQUIPMENT INVENTORY REVIEW
6.3.1 Transformer
Based on the inventory provided by the City (Table 6-10), there are about 2140 distribution
transformers within the Ashland electric system. Distribution transformer life is affected by
several factors, such as loading, environmental temperature, maintenance (e.g., oil, bushing),
testing, etc. According to reference documents (`The Feasibility Of Replacing Or Upgrading
Utility Distribution Transformers During Routine Maintenance') by the Department of Energy,
present distribution transformers are designed to operate for 20 years at designed load and
specified hot -spot temperature. Underloaded transformers are less stressed thermally and may
have lives extending well beyond 30 years, but transformers loaded to greater than nameplate
rating for extended times may have significantly shortened lifetimes. The national average age
for utility distribution transformer life is about 31.95 years with a standard deviation of 6.4 years.
According to a utility company survey in the DOE document, the retirement age ranged from 14
to 35 years and the average age was nearly 25 years, with a standard deviation of about 5
years.
Besides abnormal transformer failures, Ashland might consider the replacement of older
distribution transformers by adopting a retirement age such as 24 years based on the national
perspective, an earlier age such as 20 years, or adjusted based on the electric department's
field experience.
Table 6-10: City of Ashland, Transformer Inventory
Year
Qty.
Year
City.
2000
13
2013
14
2001
11
2014
14
2002
17
2015
16
2003
54
2016
25
2004
17
2017
25
2005
2
2018
38
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 6-8
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Year
Qty.
Year
Qty.
2006
1
2019
37
2007
4
2020
30
2008
4
2021
42
2009
2
2022
18
2011
19
2023
15
2012
28
Unknown
1692
a) Most of the manufacture dates were not recorded.
6.3.2 Poles
The City's inventory list shows a total of 2,517 poles in the system with construction additions
tabulated starting in 1950 (Table 6-11). We recommend the City conform with standard pole
testing requirements by having poles tested every 10-12 years or testing approximately 10%
(250 poles) each year. For any poles that have not been inspected for some time, it is
suggested primary circuit poles receive a full intrusive inspection, which includes excavation
around the pole to a depth of 18", and inspection of the pole exterior for decay and treatment
with a boron/copper-based product to prolong pole life. Testing should include sound and bore
to determine if the pole has any voids. If voids are present the pole should be treated with a
copper -based product to slow decay. Poles with extensive decay and that are not serviceable
should be rejected and replaced. The poles should also be visually inspected for obvious signs
of damage or decay.
Table 6-11: City of Ashland, Pole Inventory
Year
Qty.
Year
Qty.
Year
Qty.
1950
6
1976
3
2004
14
1951
1
1977
2
2005
13
1954
6
1978
4
2006
1
1955
4
1979
2
2007
9
1957
2
1980
2
2008
2
1958
1
1983
3
2009
39
1959
4
1987
1
2010
18
1960
2
1988
3
2011
29
1961
15
1989
2
2012
16
1962
4
1990
3
2013
39
1963
14
1991
7
2014
9
1964
14
1993
19
2015
18
1965
2
1994
15
2016
6
1966
6
1995
2
2017
7
1967
3
1996
2
2018
24
1968
1
1997
1
2019
15
1969
5
1998
4
2020
14
1970
1
2000
4
2021
8
1971
8
2001
7
2022
4
1972
5
2002
7
2023
11
1973
4
2003
21
Unknown
1999
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 6-9
Pane 6S of 117
a) Most of the manufacture/installation dates were not recorded.
6.3.3 Conductors
The City has a total of 2,736 conductor segments in the system with new construction additions
tabulated starting in 2012 (Table 6-12). The City has a program established to periodically
perform infrared thermal imaging investigations of all City -owned distribution infrastructure,
including primary circuit overhead pole assemblies and circuit conductors. This service should
be performed after pole inspection, treatment, and/or replacement is complete so that the
infrared inspection is performed on pole top assemblies that will remain in service. Conductors
should also receive a periodic visual inspection for obvious signs of damage. In 2023, the City
found several hot spots on switches using drones with infrared cameras and cleared a few bird
nests on poles.
Table 6-12: City of Ashland, Conductor Inventory
Year
Qty. (segment)
2012
39
2013
20
2014
13
2015
23
2016
69
2017
39
2018
26
2019
46
2020
60
2021
47
2022
24
2023
27
Unknown
2,303
a) Most of the manufacture/installation dates were not recorded.
6.3.4 Meters
There are approximately 12,172 meters in the City's distribution system with new meter
additions tabulated starting in 2011. Many of them might have been installed earlier but not
recorded by the City.
Table 6-13: City of Ashland, Meter Inventory
Year
Qty.
2011
58
2012
12
2013
32
2014
58
2015
86
2016
76
2017
106
2018
90
2019
85
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 6-10
Pane 66 of 117
2020
96
2021
79
2022
86
2023
21
Unknown
11,287
a) Most of the manufacture/installation dates were not recorded.
6.4 SYSTEM PERFORMANCE
6.4.1 Service Reliability
As discussed in Chapter 5, reliability of electric service is a primary consideration in system
planning. The City's electric system should use a single contingency reliability criterion, which
means the outage of any single major component of the electric system cannot result in a
prolonged outage to any customer.
The IEEE has developed specific guidelines through Standard 1366, Guide for Power
Distribution Reliability Indices, to evaluate distribution reliability consisting of measures for
monitoring outage duration and frequency. These reliability indices have received industry -wide
acceptance and are divided into two categories, customer -based indices and load -based
indices.
Customer -based indices record the frequency and duration of outages from individual
customers and are used mainly for residential areas. Load -based indices record the frequency
and duration of outages of circuits that are relevant to serving industrial and commercial loads.
The IEEE sustained interruption indices are defined below for convenience.
SAIFI: System Average Interruption Frequency Index
Total Number of Customers Interrupted
Total Number of Customers
SAIDI: System Average Interruption Duration Index
Sum of Customer Interruption Durations
Total Number of Customers
CAIFI: Customer Average Interruption Frequency Index
Total Number of Customers Interrupted
Number of Distinct Customers Affected within Reporting Period
CAIDI: Customer Average Interruption Duration Index
Sum of Customer Interruption Durations (SAIDI)
Total Number of Customers Interrupted (SAIFI)
ASAI: Average Service Availability Index
Customer Hours Service Availability
Customer Hours Service Demand
ATPII: Average Time per Interruption Index
Sum of Interruption Duration
Number of Interruptions
CMPII: Customer Minutes per Interruption Index
Sum of Customer Interruption Duration
Number of Interruptions
SAIFI is expressed with a unit of outages per year for the average customer. Both the SAIDI
and CAIDI are expressed in minutes, and ASAI is a percentage. The national averages for
SAIFI, SAIDI, CAIDI, and ASAI from example years between 2005-2020 are shown in Table 6-
14 below.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 6-11
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The City has established a program and collects necessary data for calculating some of these
indices listed above annually or every few years. The City recorded a total of 230 outages from
2014 through 2023, and a summary of the number of affected customers and total duration is
shown in Table 6-11.
The available data shows that SAIFI is -0.12 interruptions per customer on average for the last
10 years. The City's average interruption frequency is less than the 2020 National average of
0.86. SAIDI and CAIDI are about 20.8 and 171.4 minutes respectively. Compared to the
National Outage Data for 2020, system average outage duration is shorter, 20.8 vs. 139.2;
however, the outage duration for the affected customers is about 28 minutes (-20%) longer,
171.4 vs. 143.5. CAIDI reflects the average time required to restore service to the affected
customers and can change significantly every year. Many different factors contribute to outages
(Table 6-16) and the required time for service restoration. Outages due to extreme weather and
fire are typically challenging to recover from, especially for clients in rural and wooded areas.
Overall, the City has good service reliability.
Table 6-14: National Average Outage Data (APPA Reliability and Operations Report)
Survey Year
SAIFI
(interruptions)
SAIDI
Minutes
CAIDI
Minutes
ASAI (%)
2005
1.6
54.03
65.91
99.79
2007
4.18
69.8
90.06
99.97
2009
0.88
68.98
86.75
99.9
2011
0.81
46.36
73.86
99.86
2013
1.11
58.49
96.47
99.87
2015
0.91
62.53
78.8
99.91
2018
0.99
60.02
82.4
99.95
2020
0.86
139.16
143.52
99.97
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 6-12
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Table 6-15: City of Ashland Outage Data — Last 10 Years
Circuit Name
Substation Name
Number of System Interruptions
A2000 - Business
Nevada Street
41
A2001 - North Main
Nevada Street
31
A2002 - Railroad
Nevada Street
11
M3006 - North Mountain
Mountain Ave
4
M3009 - Morton
Mountain Ave
39
M3012 - South Mountain
Mountain Ave
33
M3015 - Wightman
Mountain Ave
8
K4056 - Hwy 99
Oak Knoll
31
K4070 - Hwy 66
Oak Knoll
14
K4093 - East Main
Oak Knoll
18
Circuit Name
Substation Name
Customer Interruptions
A2000 - Business
Nevada Street
1583
A2001 - North Main
Nevada Street
944
A2002 - Railroad
Nevada Street
672
M3006 - North Mountain
Mountain Ave
4
M3012 - South Mountain
Mountain Ave
3609
M3009 - Morton
Mountain Ave
2394
M3015 - Wightman
Mountain Ave
1953
K4056 - Hwy 99
Oak Knoll
1529
K4070 - Hwy 66
Oak Knoll
359
K4093 - East Main
Oak Knoll
2526
Circuit Name
Substation Name
Customer Outage Duration (min.)
A2000 - Business
Nevada Street
199222
A2001 - North Main
Nevada Street
184910
A2002 - Railroad
Nevada Street
72514
M3006 - North Mountain
Mountain Ave
536
M3009 - Morton
Mountain Ave
532471
M3012 - South Mountain
Mountain Ave
547367
M3015 - Wightman
Mountain Ave
353301
K4056 - Hwy 99
Oak Knoll
318852
K4070 - Hwy 66
Oak Knoll
65071
K4093 - East Main
Oak Knoll
395544
SYSTEV PLANNING STUDY, CITY OF ASHLAND — SEPTEAIBER 2024 6-13
Panes RA of 1'17
Table 6-16: City of Ashland Outage Cause Profile, Last 10 Years
Cause
Total Outages
Percentage
Squirrel
53
22.7%
Equipment Worn Out
35
15.0%
Tree
29
12.4%
Electrical Failure
26
11.2%
Vehicle Accident
13
5.6%
Lightning
13
5.6%
Unknown
12
5.2%
Equipment Damage
7
3.0%
Bird
7
3.0%
Overhead
7
3.0%
Underground
6
2.6%
Wind
5
2.1 %
Fire Department
3
1.3%
Non -Utility Excavation
3
1.3%
Storm
3
1.3%
Other - Lightning
2
0.9%
Repairs
2
0.9%
Human Accident
2
0.9%
Failure of Greater Transmission
1
0.4%
Contractor -Dig -In
1
0.4%
Equipment Replacement
1
0.4%
Contact with Foreign Object
1
0.4%
Ice
1
0.4%
BPA and PacifiCorp provided their recorded 10-year outages for the circuits serving the City's
electrical system, these are presented in Table 6-17 and Table 6-18. Of these events, about
50% have a duration of more than 2 hours.
Table 6-17. BPA 10-Year Outage Record
Outage Start
Outage End
Duration
kV
Auto/Planed
Cause
Responsible
Component
Date/Time
Date/Time
(min.)
System
6/15/2015 3-00
6/15/2015 18:50
950
12.5
Auto
Bird or Animal
BPA
Transformer,
Power
10/5/201513-18
1017/201515:10
2992
12.5
Plan
Maintenance
BPA
5/16/2017 7:34
5/16/2017 14:23
409
12.5
Plan
Maintenance
BPA
Not
6/251201717:27
6/251201718:08
41
12.5
Auto
Unknown
Customer
Applicable
9/19/2017 7-47
9/20/2017 13:48
1801
12.5
Plan
Maintenance
BPA
SYSTEM PLANNING STUDY. CITY OF ASHLAND — SEPTEMBER 2024 6-14
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Table 6-18: PacifiCorp 10-Year Outage Record
Year
Outage Class
Duration (mins)
Substation
2013
1/26/13 9:47 AM
Distribution
75 to 90 minutes
Ashland (Mtn.Ave, PUD)
2/13/13 11:53 AM
Distribution
45 to 60 minutes
Ashland (Mtn.Ave, PUD)
6/12/13 1:29 PM
Distribution
30 to 45 minutes
Ashland (Mtn.Ave, PUD)
10/31/13 1:43 PM
Distribution
15 to 30 minutes
Oak Knoll
2014
4/14/14 5:25 PM
Transmission
0 to 15 minutes
Lone Pine
12/15/14 7:30 AM
Distribution
45 to 60 minutes
Ashland (Mtn.Ave, PUD)
2016
3/12/16 4:42 PM
Distribution
225 to 240 minutes
Oak Knoll
2017
117/17 8:48 AM
Distribution
495 to 510 minutes
Oak Knoll
117/17 8:48 AM
Distribution
495 to 510 minutes
Ashland (Mtn.Ave, PUD)
1/22/17 3:13 AM
Distribution
135 to 150 minutes
Oak Knoll
5/20/17 2:46 PM
Distribution
345 to 360 minutes
Ashland (Mtn.Ave, PUD)
5/20/17 2:46 PM
Distribution
330 to 345 minutes
Ashland (Mtn.Ave, PUD)
6/25/17 5:27 PM
Distribution
30 to 45 minutes
Oak Knoll
6/25/17 5:27 PM
Distribution
30 to 45 minutes
Ashland (Mtn.Ave, PUD)
6/25/17 5:27 PM
Distribution
30 to 45 minutes
Oak Knoll
2018
1/24/18 9:25 PM
Transmission
0 to 15 minutes
Lone Pine
6/24/18 10:51 PM
Distribution
240 to 255 minutes
Oak Knoll
7/21/18 8:27 PM
Distribution
390 to 405 minutes
Ashland (Mtn.Ave, PUD)
7/21/18 9:12 PM
Distribution
345 to 360 minutes
Ashland (Mtn.Ave, PUD)
12/14/18 8:24 AM
Distribution
195 to 210 minutes
Oak Knoll
12/14/18 8:24 AM
Distribution
195 to 210 minutes
Ashland (Mtn.Ave, PUD)
2019
2/13/19 11:47 AM
Distribution
0 to 15 minutes
Ashland (Mtn.Ave, PUD)
7/24/19 4:30 PM
Distribution
45 to 60 minutes
Ashland (Mtn.Ave, PUD)
7/24/19 4:30 PM
Distribution
45 to 60 minutes
Oak Knoll
2021
6/27/21 9:06 PM
Distribution
15 to 30 minutes
Oak Knoll
6/27/21 9:06 PM
Distribution
15 to 30 minutes
Ashland (Mtn.Ave, PUD)
6/27/21 9:06 PM
Distribution
15 to 30 minutes
Oak Knoll
10/26/21 9:09 AM
Distribution
300 to 315 minutes
Oak Knoll
2022
3/5/22 7:32 AM
Distribution
105 to 120 minutes
Ashland (Mtn.Ave, PUD)
3/5/22 1:15 PM
Distribution
75 to 90 minutes
Ashland (Mtn.Ave, PUD)
4/11/22 8:06 AM
Distribution
240 to 255 minutes
Oak Knoll
5/31/22 12:04 PM
Distribution
135 to 150 minutes
Oak Knoll
5/31/22 12:04 PM
Distribution
105 to 120 minutes
Oak Knoll
6.4.2 System Voltage Levels
In accordance with standards established by the American National Standard Institute (ANSI
C84.1, Range A), the voltage ranges in Table 6-19, shown as acceptable voltage or allowable
voltage drop, should be maintained throughout the City's electric system. The voltages shown
are presented on a 120 volt base, however the percentages indicated apply to any voltage
base, for example 12.47/7.2 W, 480/277 V, etc., as applicable to the location.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 6-15
Panes 71 of 137
Table 6-19: Acceptable Voltage Levels
Facility
Acceptable Voltage or Allowable
Voltage Drop (120V Base Volts)
Acceptable
Percentage
Bus voltage range at substation
122 - 126
102% - 105%
Maximum voltage drop along a distribution feeder
8
6.7%
Voltage range at primary terminals of distribution
transformers
118 - 126
98% - 105%
Maximum voltage drop across distribution
transformer and service conductors
4
3.3%
Voltage range at customer's meter
114 - 126
95% -105%
Voltage range at customer's utilization equipment
110 - 126
92% - 105%
The Base Case Power Flow results indicate that present system voltages under peak conditions
are at acceptable levels, with the maximum voltage drop on any feeder between substation and
last customer at approximately 1.1 %. However, substation voltages should be monitored to
ensure proper distribution voltage levels are being maintained. In addition, during substation
outages or feeder transfers, feeder voltage levels should also be monitored to ensure proper
voltage levels are maintained.
The City should keep in mind the fact that minor voltage regulation can have noticeable effects
on customer equipment. For example, a situation where typical household equipment
experiences an under -voltage of 10 percent can result in reduced lighting output of 30 percent
and can cut heating and range output by up to 20 percent. Over -voltage of 10 percent in
household equipment can result in a reduction of lamp life up to 70 percent and cause
overheating of heaters and ranges.
At present, customers expect an extremely high quality of service and reliable power supply.
Momentary interruptions, voltage disturbances, and sine wave distortions that would have gone
unnoticed a few years ago are not as well tolerated with modern day loads. Among these
sensitive loads are business and home computers, cash registers, security alarms, digital
devices, home business center and entertainment equipment, and other sensitive equipment.
6.4.3 Phase Current Imbalance
The primary concern of imbalanced loading between phases of a circuit is the resulting
unbalanced phase voltages. Unbalanced voltages can cause additional negative sequence
currents to circulate in three-phase motors. This negative sequence current can lead to motors
overheating. Load imbalance also causes excessive neutral currents, which can cause
increased system losses and can affect ground relaying.
Because system loads are continually changing, and since single-phase loads are present on
each feeder, it is nearly impossible to achieve perfect phase balance. During high load
conditions we recommend a policy of monitoring phase imbalance on each feeder. If the
imbalance on any feeder exceeds 15%, loading should be transferred between phases to
reduce imbalance to 10% or below. System balance may fluctuate seasonally or with system
peaks, but these fluctuations should not be excessive if the policy above is followed.
Based on the field system reading on January 26, 2024, the imbalance percentages for the
three substations are given in Table 6-20. For all three substations, although some feeders have
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 6-16
Pant- 79 of 137
an imbalance range greater than 10% but less than or equal to 15%, the overall substation
imbalance rates are between 5% and 7%.
Table 6-20: Phase Imbalance of Connected Load, January 26, 2024
Feeder
Number
Phase A
am
Phase B
am
Phase C
am
Max Imbalance
am
Imbalance
A2000 - Business
166
154
118
20
14%
A2001 - North Main
115
145
161
21
15%
A2002 - Railroad
1 35
1 46
1 48
1 5
1 12%
Substation Total
316
345
327
16
5%
M3006 - North Mountain
25
32
29
3
12%
M3009 - Morton
167
134
142
19
13%
M3012 - South Mountain
131
139
121
9
7%
M3015 - Wightman
67
63
57
5
7%
Substation Total
390
368
349
21
6%
K4056 - Hwy 99
155
155
162
5
3%
K4070 - Hwy 66
110
129
102
15
13%
K4093 - East Main
123
145
122
15
12%
Substation Total
388
429
386
28
7%
We recommend that the City monitor the imbalance on all feeders during various load
conditions and adjust phasing where feasible to improve overall load balance, with the goal of
maintaining imbalance to below 10%. A period of monitoring is necessary following field
changes of any feeder to identify the effect of the change on feeder balance. Additionally, phase
balance should be considered prior to adding or reconfiguring feeder loads.
Although the phase loading and ampacity imbalance deviations shown above in themselves are
not ANSI/IEEE standards violations, these conditions can result in end -of -feeder voltage
imbalance that may be in violation of ANSI C84.1 standards. We suggest the City occasionally
monitor voltages at the end of lengthy feeders to ensure the electric supply is operating to limit
the maximum voltage imbalance to 3 percent when measured at the electric utility revenue
meter under no-load conditions.
SYS TEAS PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 6-17
Pane 73 of 137
Chapter 7 POWER FLOW ANALYSIS
7.1 METHOD
The City of Ashland electric distribution system was modeled based on the following data:
• The City's distribution system maps and data compiled during the study process
including updated records of conductor type, size, and phasing; transformer locations,
kVA ratings and phase connections; fuse locations and ratings; switching and
sectionalizing schemes; capacitor devices with ratings and connection type; and switch
location and status.
• BPA point -of -delivery meter data and Ashland SCADA data for the system, substations,
feeders, and large industrial/commercial/irrigation loads.
• All distribution transformers (connected loads) and their kVA ratings, entered as the
corresponding load type in the analysis database. These connected loads were scaled
to match the total feeder load in the model to the historical peak feeder demands.
• The most recent coincidental feeder and system peak demand of 45.9 MW from June
2021 was used as the Base Case Peak Load criteria, Case 1A.
• Case 1 B is the Base Case Light Load. Data from recent years was examined, and a
system load of 31.8 MW was modeled to create the conditions from January 2019.
• In the ten-year growth case, Case 2A, a system peak demand of 49.3 MW was modeled
based on the load forecast projections in Chapter 3. Allocations of additional kVA are
detailed in Section 7.1.2 of this chapter.
• In the twenty-year growth case, Case 2B, a system peak demand of 53 MW was
modeled based on the load forecast projections from Chapter 3.
• To assess the loss of a substation transformer, the system was modeled under Base
Case (1A) conditions with each substation power transformer individually removed from
service and its load transferred to adjacent substation feeders. These transformer out -
of -service models are evaluated and identified as Case 3A, Case 3B, Case 3C and Case
3D analyses.
• To assess the loss of a feeder, the system was modeled under Base Case (1A)
conditions with each feeder circuit removed individually from service and its load
transferred to adjacent feeder circuit(s). These feeder out -of -service models are
evaluated and identified as Case 4 analyses (Case 4A to Case 4G).
• The observed feeder power factor varies from 0.98 to 0.997. A conservative load power
factor, 0.98, was used in the model for all cases.
• BPA's voltage schedules for this area and surrounding regions are typically 117 kV to
119 kV with a 2 kV band. This system has been modeled with BPA voltage at LOW or
117 kV and all voltage regulators and LTC at a voltage set point of 123V (+2.5%) on a
120V base, as most of the cases consider historical or forecasted peak demands.
Power flow analysis was conducted based on the above data. A printout of the Milsoft model
can be found in Appendix D. Analysis was performed with major load peak data and the spot
feeder loads scaled as necessary to simulate historic peak demand conditions unless otherwise
stated. Some loads were distributed across the various system sections proportionally to
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-1
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Ashland Assisted Living Llc
154.4
140.8
117.6
139.8
141
151.2
143.8
143.6
121.2
117
130.4
136.8
m Real Estate Services Inc.
41.77
44.98
45.6
50.29
51.28
51.97
53.03
53.03
52.64
47.56
41.5
46.15
Cpm Real Estate Services Inc.
49.6
30.4
24
25.6
27.2
25.6
25.6
25.6
24
33.6
60.8
52.8
Mountain Meadows
Homeowners Assoc
84
72
66
76
84
84
72
64
72
72
86
76
Parks Dept
58.4
58.4
58.8
58.8
0.4
0.4
58.4
58.4
58.4
58.4
58.4
0.4
OSFA
53.4
53.4
53.4
53.4
53.4
53.4
31.56
31.32
33.48
37.92
53.76
53.4
Varsity Theatre
48
48
44
28
30
30
30
48
52
54
56
60
OSFA
108.64
114.08
105.12
108.48
98.6
68.96
87.2
98
105.6
107.6
140
140
Ashland Springs Hotel
196.8
191.6
164.4
175.6
170
166.4
160
174.8
181.8
190.8
196
208.6
Ashland Springs Hotel
202.8
173.6
224.4
277.6
277.6
267.2
250.8
240
188.8
214.8
240.4
244
Ashland Springs Hotel
20.2
20.2
16.2
16.8
16.6
15.6
15.4
15
18.8
191.8
212.2
203
OSFA
71.2
76
76
76
1 47.2
30.4
1 110
104
134
60
68
32
Domestic Solutions Llc.
20.4
20
20
22
16
16
10
it
14
19
16.8
140
Jackson County Library District
72.8
72.8
72.8
72.8
64.8
64.8
64.8
64.8
64.8
59.2
61.6
61.92
Ev Charging Solutions, Inc
7.12
7.16
7
3.68
7.12
6.96
7.12
57.36
49.72
7.16
54.36
58.84
Ashland Elks Lodge #944
50.16
39.92
30.48
33.28
28.88
33.52
31.88
42.68
48.56
46.04
52.68
46.88
SOU
65.28
65.28
66.24
76.48
74.24
75.52
94.4
84.4
60.16
76
76.48
76.48
SOU/Physical Plant
Department
902.4
828
861.6
880.8
849.6
873.6
900
892.8
871.2
878.4
844.8
Vishal Patel
48
38.4
58.8
57.6
57.6
61.2
67.2
67.2
67.2
50.4
54
54
City Of Ashland, Electric Dept-
Tracking
200.4
193.5
155.7
156.3
171
167.1
160.5
155.1
149.7
160.8
176.7
183.9
City Of Ashland, Service Ctr
32.76
96.72
123.72
123.72
123.72
123.72
147.6
147.6
147.6
147.6
147.6
36
City Of Ashland
52
24.6
20.36
18.36
19.96
19.72
19.2
19.08
32
32
19.44
23.48
Hull Properties
116.8
109.76
114.88
151.68
177.44
172.8
173.76
184.48
167.2
102.08
100.8
108.48
Lachlan Scotland
73.2
73.2
73.2
73.2
50
37.2
1 46.8
59.6
64
70.8
86
61.2
Lachlan Scotland
123.4
110
102.6
123.2
108.6
78.8
119.4
139.2
145
144
145.8
137
OSFA
128.4
138
114.8
96.2
68.16
77.8
51.2
55.52
54.72
54.24
115
117.4
Sou/Physical Plant Department
1322.4
1216.8
1075.2
496.8
504
463.2
482.4
484.8
928.8
1046.4
1111.2
1012.8
Sou/Physical Plant Department
861.6
837.6
828
756
758.4
756
712.8
679.2
708
727.2
7"
744
7.1.1 Evaluation Criteria
The following electrical criteria were used in power flow analysis.
• Overvoltage: >105%
• Undervoltage: <95%
• Overload: >100% equipment capacity
• Overload warning: >=90% and <=100%
Service voltages should be maintained in the acceptable range per ANSI C84.1 as discussed in
Section 6.3.2. Equipment running above its rated capacity is considered an overload and is
recommended to be upsized. Equipment identified as an overload warning is recommended to
be monitored and considered in the future improvement plan.
7.1.2 Power Flow Result Understanding
In general, caution should be practiced when interpreting system problems indicated by the
power flow analyses. Power flow results typically identify system problems such as heavily
loaded or overloaded conductors and undervoltage conditions. The modeled conditions are the
result of analysis under peak or other 'worst case' conditions that may be considered extreme.
The goal is to evaluate system operation under realistic worst -case conditions. We recommend
that where problems are noted, the City should verify that the actual system components and
conditions support the analysis conclusions.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-3
Pane 76 of 1.17
Also, as with any model, the results will only be as accurate as the data used. For example,
conductor sizes and materials, system component phasing, and interconnectivity are modeled
using information from the City's distribution system detail maps and correspondence with City
staff. If there is inaccuracy in the map compilation or any parameter of the data characteristics,
there could be inaccuracy in the results.
7.2 POWER FLOW CASE, LOAD ALLOCATION AND RESULTS
NORMAL CONFIGURATION
To evaluate the electric system's capacity and operating concerns in the existing (or normal)
system configuration, the following scenarios were analyzed:
7.2.1 Case 1A: Base Case Peak Load
The Base Case Peak Load power flow analysis was performed under the most recent peak load
conditions. Based on load data from BPA metering system, a coincident demand of 45.9 MW
occurred on June 28, 2021. The modeled loads for Ashland Substation, Mountain Avenue
Substation, and Oak Knoll Substation are approximately 14.3 MW, 14.2 MW, and 17.6 MW
consecutively, based on the distribution system loading. The PacifiCorp-owned Ashland
Substation and Oak Knoll Substation have separate feeders for PacifiCorp's customers. At the
same time during the historical peak in 2021, the estimated PacifiCorp loads in Ashland
Substation and Oak Knoll Substation are approximately 4.3 MW and 5.5 MW, which was
modeled to evaluate the substation transformers. This power flow model evaluates the system
in its normal configuration with each substation serving its own feeders.
The feeder loading (kW) and power factor from the power flow results of Case 1 A are
summarized in Table 7-2. The results of this analysis indicate that there are no conductor and
transformer overload problems or bus voltage problems for the majority of the City's electric
system.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBEP 2024 7-4
Pane 77 of 117
Table 7-2: Case 1A Power Flow Details
Feeder Load
kW
PF (%)
Amps
A2000 — Business
6,321
98.0
291.4
A2001 — North Main
6,192
97.7
286.1
A2002 — Railroad
1,819
98.0
98.0
M3006 — N. Mountain
985.6
98.9
45.0
M3009 — Morton
5,683
97.9
262.1
M3012 — S. Mountain
5,131
97.5
237.8
M3015 — Wightman
2,403
98.1
110.7
K4056 (5R56) — HWY 99
6,699
97.3
311.1
K4070 (5R70) — HWY 66
4,748
97.8
219.3
K4093 (5R93) — E. Main
6,168
97.0
287.3
Ashland System Load
kW
46,150(a)
Substation Load
kW
AS Transformer
18,795(b. `)
MAS Transformer
14,267
OKS Transformer T1
12,265(b, c)
OKS Transformer T2
10,955
a) System noncoincident peak load is slightly different from the peak load as discussed previously due to scaling
factors and system losses.
b) Ashland Substation load includes —4.3 MW for PacifiCorp.
c) Oak Knoll Substation load includes —5.5 MW for PacifiCorp.
Feeder backbone voltage profiles based on the power flow analysis for Case 1A are shown in
Figure 7-1 to Figure 7-10. The feeder voltages appear to be in acceptable ranges for utility
services and reasonably balanced. Depending on the load distribution, some of the backbone
fuses, 140K and 100K, along the Ashland/Business feeder are recommended to be monitored,
as they may reach their rated capacity.
The estimated peak load in Ashland Substation in this case is only 6% away from the
transformer overload rating of 20 MVA. PacifiCorp typically uses 120% of the nameplate rating
as their guide for Winter capacity rating, however, the City of Ashland has a Summer peak load
pattern. The available summer capacity at Ashland Substation is near capacity and could
become underrated with future load growth or extreme weather events.
The transformers at the other two substations appear to have sufficient capacity for the
historical peak loads and there is room for future load growth for normal feeder switching
configuration.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 7-5
Pane 79 of 1.17
084E69
see.a
AW Paaes
(A) 123.440 V
la) 123.913 v
(C) 122.644 V
(A) 327.277 A
to) 31s.317 A
(C) 231.502 A
(A) 0.054 VD
111) 0.031 vD
Ic) 0.620 VD
Ashland
ONS271
Substation
.Se4aO
W 131.89E V
(a) 122.466 V
(l7 122.E21 V
t..
W 203.290 A
(a) 174.144 A
(c) 131. 414 A
p) 0.022 VD
IC) 0.020 VD
_. r i
W POAee
(A) 121.492 V
(a) 122.337 V
(C) 122.249 V
W 1E3. 601 A
(a) 9a.ssa A
(C) 111.4Ef A
W 0.041 VD
(a) 0.01E VD
(c) 0.034 VD
Passe
W 120.739 V
(a) 122.016 v
ICI 121.E06 v
lA) 3.303 A
(2
1 -0.042 A
(C) -0.041 A
(A) 0.004 vD
la) -0.001 VD
ICI -0.000 VD
Pease
1 120.711 V
3.463 A
0.001 VD
Phax
W 121.036 v
(a) 132.108 v
(c) 122.E7o v
(A) 4.aN A
(a) ,.413 A
(c) 7.E7a A
W 0.003 VD
(a) 0.002 VO
(c) 0.002 VD
Figure 7-1: Case 1A Voltage Profiles - Ashland Substation /Business Feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-6
Pane 79 of 117
c
0 0
_�, Q,mmmMv�o
N
U
amUawUaYOU
mM+m000
o mel a'ut0000
p N tl N N N O N m
N W
d
aa�u awu40u
1
> a >
tiro,
i
o
JOa
Fg—a
la �J
C 1.l
o m m o 0 0 0 0 0
s o r o 0 0 0 0 0
n 0 0 0 0 0 0 0 YI N M m M M �D YI N
O N ryN N tl• 1 1
a m U a m U a 10 U
P a >
J A O
YI M O
r
w
c
c
a
a:
c
Cc
a
0111242
ennead
PAale
C) 122.011 V
2-0.001 A
0.000 VD
UG778
zaead
LBC Beaee
W 12295 v
(a) 122:.9995 V
(C) u2.994 V
(a) is. 451 A
(a) 79.9E3 A
ICI 86. 184 A
{A) 0.003 VD(a) 0.006 w
(CI 0.00E w
6'
ezQ:oma
oaaus
-
py
esaae
12222.4F1 .404 Y
(a)
1v
(C)
122.182 v
_ --•--•----
(A)
87.701 A
'-"
(a)
25.659 A
(C)
49.849 a
W
0.027 w
(a)
o.o15 w
(C)
0.047 w
Ashland
Substation
QE806
9Lex
(A) 122779 V
(a) 122:762 V
(C) 122.712 v
(IU 83.301 A
(6) 68. 275 A
(C) 86. 173 A
(A) 0. 010 VD
(a) 0.010 w
(C) 0.017 w
UG1310
1919VAd
NBC Phale
(A) 122.340 V
I81 122.446 v
IC) 122.151 V
(AI 3.377 a
(a) 3.314 A
(C) 1.102 A
(A) 0..0 w
(a) 0.000 w
(C) 0.000 w
Figure 7-3: Case 1A Voltage Profiles — Ashland Substation / Rail Road Feeder
SYSTEM PLANNING STUDY. CITY OF ASHLAND — SEPTEMBER 2024
7-8
Panes fit of 137
001333
U�U.g.cmd
(A) 121.618 V
(a) 122.076 V
(C) 121.852 V
(A) 17.SS7 A
45) 17.600 A
(C) 17.532 A
p) O.032 w
(a) 0.812 V0
to 0.012 w
OHM6
u
LIbc 9h".
(A) 119.459 V
(a) 121.668 V
(C) 121.035 V
W e.ae6 A
(a) 1.442 A
(C) 2.070 A
(A) 0.013 w
(a) 0.008 w
(C) 0.002 w
O02618
ub".9-d
pt,
W 119.189 V
(a) 1.21.0 6 V
(C) 121.143 V
(A) -4.J54 A
. -5.568 A
(C) -S.SS7 A
W -0.005 VD(a) -0.009 VD
(C) -0.008 VD
UG2646
( .9-d
ABC 4h.-
(A) 119.527 V
(a) 121.885 V
(C) 121.21, V
(a) -0.413 A
(C) -0.411 A
(A) 0.002 w
(a) -0.001 VD(c) -0.000 VD
Mount2in
(A) 12219 V
la) 122.945 V
Avenue,
(C) 122.047 V
')
~
Substatio
a) 0.681 A
(C) -0."' A
(C) ..000 w
O01471
..d
Aw
BA.s!
- - p)
120842 V
(a)
121:903 V
_ (C)
121.342 V
' (A)
192.511 A
(a)
123.125 A
(C)
112.092 A
W
o.ose w
W
o.003 w
(C)
0.014 w
UIC 9A..e
(A) 120.130 V
18) 121 741 V
(C) 121.142 V
W 78.922 A
(a) U.300 A
(C) 25.224 A
(A)0.03o V0
(a) 0.003 VD(C) 0.004 w
OG3335
' .LOxauad
eh -
(A) 119.161 V
(A) 3.213 A
(A) 0 0023 w
Figure 7-4: Case 1A Voltage Profiles - Mountain Avenue Substation / Morton Feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-9
Pan- 89 of 1.17
OA401
Overhead
ABC Phase
(A) 122.905 V
(B) 122.859 V
(C) 122.908 V
(A) -0.002 A
(B) -0.002 A
(C) -0.002 A
(A) 0.000 VD
(B) 0.000 VD
(C) 0.000 VD
UG922
Underground
ABC Phase
(A) 122.906 V
(B) 122.842 V
(C) 122.906 V
(A) -0.039 A
(B) -0.039 A
(C) 1.022 A
(A) -0.000 VD
(B) -0.000 VD
(C) 0.001 VD
W-1
OA47
Overhead
ABC Phase
(A) 122.915 V
(B) 122.887 V
(C) 122.923 V
(A) 38.587 A
(B) 44.651 A
(C) 39.950 A
(A) 0.009 VD
(B) 0.011 VD
(c) 0.007 VD
Mountain
Avenue
Substation
ABC Phase
(A) 122.996 V
(B) 122.994 V
(C) 122.995 V
(A) 41.042 A
(B) 49.521 A
(C) 44.477 A
(A) 0.004 VD
(B) 0.006 VD
(c) 0.005 VD
UG82
Underground
ABC Phase
(A) 122.910 V
(B) 122.875 V
(C) 122.919 V
(A) -0.024 A
(B) 2.742 A
(C) -0.024 A
(A) -0.000 VD
(B) 0.001 VD
(c) -0.000 VD
Figure 7-5: Case 1A Voltage Profiles - Mountain Avenue Substation / North Mountain Feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-10
Pane 81 of 137
OH3061
Overhead
C Phase
(A) 121.755 V
(B) 121.409 V
(C) 121.860 V
(A) -0.001 A
(B) -0.001 A
(C) -0.001 A
(A) 0.000 VD
(B) 0.000 VD
(C) 0.000 VD
DG3054 /
Underground
B Phase
(B) 120.516 V
(B) -0.040 A
(B) 0.000 VD
OH2724
Overhead
ABC Phase
(A) 121.993 V
(B) 121.953 V
(C) 122.122 V
(A) 197.067 A
(B) 212.644 A
(C) 200.321 A
(A) 0.040 VD
(B) 0.044 VD
(C) 0.036 VD
Mountain
Avenue
ABC Phase
(A) 122.960 V
(B) 122.958 V
(C) 122.962 V
(A) 238.92E A
(B) 245.842 A
(C) 228.604 A
(A) 0.040 VD
(B) 0.042 VD
(C) 0.038 VD
WC Phase
(A) 121.838 V
(B) 121.971 V
(C) 122.073 V
(A) -0.001 A
(8) 1.968 A
(C) -0.001 A
(A) 0.000 VD
(e) 0.001 VD
(C) -0.000 VD
DG3199
Underground
ABC
Phase
(A)
121.V
(B)
121.962962 V
(C)
122.056 V
(A)
1.310 A
(B)
1.308 A
OH2871
(C)
1.307 A
Overhead
(A)
0.000 VD
C
Phase
(B)
0.000 VD
(A)
121.855 V
(C)
0.000 VD
(B)
121.624 V
(C)
121.704 V
""""
(A)
-0.001 A
(B)
-0.001 A
(C)
21.333 A
(A)
-0.007 VD
(B)
0.003 VD
(C)
0.023 VD
OH2915
Overhead
AC Phase
(A) 121.859 V
........
(C) 221.673 V
(C) -0.002 A
(A) 0.000 VD
(C) 0.000 VD
Figure 7-6: Case 1A Voltage Profiles - Mountain Avenue Substation / South Mountain Feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
7-11
Pane 84 of 1.17
ABC Phase
(A) 122.984 V
(B) 122.984 V
(C) 122.987 V
(A) 118.939 A
(B) 114.552 A
(C) 98.474 A
(A) 0.016 VD
(B) 0.016 VD
(C) 0.013 VD
ABC Phase
(A) 122.733 V
(B) 122.791 V
(C) 122.836 V
(A) 87.085 A
(B) 87.749 A
(C) 69.544 A
(A) 0.014 VD
(B) 0.010 VD
(c) 0.007 VD
Mountain
Avenue
Substation
ABC Phase
(A) 122.632 V
(B) 122.727 V
(C) 122.781 V
(A) 82.789 A
(B) 77.696 A
(C) 65.255 A
(A) 0.014 VD
(B) 0.009 VD
(C) 0.008 VD
OH4183
Overhead
ABC Phase
(A) 122.279 V
(B) 122.420 V
(C) 122.539 V
(A) -0.001 A
(B) -0.001 A
(C) -0.001 A
(A) 0.000 VD
(B) 0.000 VD
(C) 0.000 VD
ABC Phase
(A) 122.579 V
(B) 122.690 V
(C) 122.693 V
(A) 1.443 A
(B) -0.001 A
(C) -0.001 A
(A) 0.001 VD
(a) -0.000 VD
(C) 0.000 VD
OH4110
ABC Phase
(A) 122.537 V
(B) 122.662 V
(C) 122.744 V
(A) -0.002 A
(B) -0.002 A
(C) -0.002 A
(A) 0.000 VD
(B) 0.000 VD
(C) 0.000 VD
ABC Phase
(A) 122.305 V
(B) 122.447 V
(C) 122.566 V
(A) 39.894 A
(B) 40.571 A
(C) 39.808 A
(A) 0.012 VD
(B) 0.013 VD
(C) 0.012 VD
Figure 7-7: Case 1A Voltage Profiles - Mountain Avenue Substation / Wightman Feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
7-12
Pane RIS of 1.7
.�lAl l3T. it-0 r
i(CI ]]f.4El 9 '+ate
IW 22i.ltf a
'Pr ]xa.6Te a
I/cl Jar. 44 a
w o.a1 YD
W 9. i vo
Orerse.0
ew.1
_ w uf.fu Y
lAl ]IT.TH 4
IQ uT,ge r
w rA. aal i
I I IDI -0.wl A
ICI -O.Oal
w o. wo w
PI O. mesa w
Le"' oafzr.
w ue.Tf, . n.Gf
le) Its.9T4 v (U ua.zs: v
IC) lil.lil 4 (D) IJO.G54 4
' W ]IS.Mi a fCl 110. uC O
IG ifl.i44 A (y ]ST,wf
ICI 21a.lGi A (.l ..).Tfl A
w c.14f w (a nQ.ul A f
le) C.72S 49 (AI o.iw vs
ICI c.1D9 A P) a.o9c vD I
tC)
lOGGe
Y -a.ou a
Y Q•WO eD
b]e
w
lac.vf v
P)
121.asa v
... ..... ........ (C)
l2C.TT1 v
W
AA
le)
-C.2.s,f
A
.1T A
.
W
O.tWl W
P)
-c.9Do v0
Iq
_C.oDo w
p� ef.w
•' (e) f.901 rp w 1u.eo3 v
llf e) Ixz.e94 v
Daloaw Ia ui.TfG v
fp st>a� w a».wf
A lelfw lel STa.aTG A
IA) )t4.419 Y IU I1f.Ti5 v IC) 3if.SG) A
Ii7 C.IfG a {11 11T::12 O w 0.na2 W
lid VC ICI 11T.aT3 Y 1A) O.aN 4D
fAi -0.MP A Oak '• 1c) D.css w
PI l.=31 A
1C) 1.:44 A Substation
IA) A.M2 49
P) G.O11 vD
IQ WL sD
Figure 7-8: Case 1A Voltage Profiles - Oak Knoll Substation / East Main Feeder
At the end of the East Main feeder, Phase A voltage is close to 0.97 pu, which is still acceptable
for utility delivery voltages.
IEI va.nz v W iJc.no o P> lz0.eex r
Pr 1.4it A ID/ 1JQ.ili 4 cc))
12:.2T9 4
ler Q.Oai 10 (Cl 1J1.D93 Y iCI 12i.125 1'
- IA) 121.D1E A W =21.044 i
Pf 119,09, A 1D) 309.490 i
ICY 119.T35 A (C) lfs.of9 A
a)
"MI Yp W 0.0?1 YD
IDf C.w4 VD P1 D.Oif YD
aaac>l IY�
ITiflet
lAaN '
W 3x0.flf ♦ b>w
PI 13e. f2! ♦
tC) 123.OJO IT / 1..3l...
l i
tA) -9.001 A --- iP44,T \e.FF „ICI 1]l.11f 4
ID1 -0.991 A ornoae �. W 1f.991 a i
(C) -0.OD1 A 4!w]az PI 1f.400 a
W 0.000 YD lil 120.934 r Ic) 1f.4f3
(D) 0.000 YD PI 380.09E r W 0.001 VD
(e) O.000 VD lC7 181.OT2 v ID/ D.0a1 VD dUfal _-
W 14.51( A In D.00s 4D ovfrnG.G
IDI 19.aaa a D012f
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W a.aas YD iyff P) 1. 2,M v
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(CI 120. to V
W -0.003 a
W D. DOD rD L
(a) 0.o l
Oa -• l
tq u.ow m
Substation
Figure 7-9: Case 1A Voltage Profiles - Oak Knoll Substation /HWY 66 Feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
7-13
Panes 88 of 117
Off11 ODllill
rOiV DDlllf2
W 11f.101 Y (A) 11 S.ttO Y 31e0
Ill i19. ]if V w -0.DOI a �"
I[1 31t.N1 V (U 0.000 w h""�•. •• IC) 119.42. V
ql -0.007 A IC)
ICI 0.00] w
161 -0.001 a
ICI A 069s2! q!9195
lot D.000 w cmmd ]fags twfe
Icl D.000 w 21a ;AI 12"42 v (A) 21..t]f P
RI i1f.SK V bl 114.90/ P 16) I2o.1f1 v
AI lif.Ttl V iCl 111.601 Y tc) 219.dT5 Y
ICI IIT:912 P iA) llZ.flz A w z11.oi2 A
VI 4.126 A fDl 1l1 .'I. A (D) z]c.ul A
IDI 1.121 A fcl 211:113 A (C) 2Tt.i1! A
IQ 1.l% A w c.02[ w lA) O.oTs w
AI o.002 w ul C. o12 v.0) O.o9! w
ilk:0. oo2 w tcl c.Dfz w (C)
.Dau11
M uf.alo v
A
u) -f.coo w �
1 G111os
�a9zoffa __
9na.f
W 11t.2)) V
-43
ABC Ph-
0619clo W IU.054 V (A) 121.f19 P
t1) u9.a1) v (D) 121.1c9 P
- 9ttue - (q 423..i1. P CC) 121.11� Y
W .1
1.]1t P (A) UA W 2f9.34f A
(D) llfl P ID) 11.0f01 A p) ST1.Gt1 A
In u1.1. v (c) 9.OD2 A
to !1l.109 A
W aGa A W 9.uc w (A) 1
.G1; w
u) o.o1w
(a) -0.001 A (C) -9.c00 w p-) o,a10 w
(a)o.No w -
W o.9w w 061odJ1
(c7 9.aCD w Lsaa
leave
ID) 119.TT1 V
IDI O.TN YD
Figure 7-10. Case 1A Voltage Profiles- Oak Knoll Substation I HWY 99 Feeder
7.2.2 Case 1 B: Base Case Light Load
Oak Knoll
substation
9fafS
fU 12z.f1S P
(D) 122.f11 V
rq .f11 V
(A) -u1.811 A
(•) 211 AM A
IC
) 2N.11T a
W o.ot2 w
(at o.oH w
1C) o.oft w
To determine representative light load conditions for modeling, we examined the BPA metered
demand data from recent years. A system demand of 31.8 MW was modeled based on data
from January 2019. Similarly, load was distributed to each feeder using historical observations
of BPA load data and the City's records on large customers. Small loads were linearly scaled
down to achieve the base case light load level.
The results indicate that there are no conductor and transformer overload problems, or bus
over/undervoltage violations. The feeder loading (kW) and power factor from the power flow
results of Case 1 B are shown in Table 7-3.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024
7-14
Panes 87 of 137
Table 7-3: Case 1 B Power Flow Details
Feeder Load
kW
PF (%)
Amps
A2000 - Business
4,199
98.2
193.1
A2001 - North Main
4,036
98.1
185.8
A2002 - Railroad
1,192
98.1
54.9
M3006 - N. Mountain
773
99.1
35.2
M3009 - Morton
4,461
98.1
205.4
M3012 - S. Mountain
4,068
97.5
188.4
M3015 - Wightman
1,968
98.2
90.5
K4056 (5R56) - HWY 99
4,246
97.7
196.2
K4070 (5R70) - HWY 66
3,017
98.2
j 138.8
K4093 (5R93) - E. Main
3,897
97.7
180.2
Ashland System Load
kW
31,857 (a)
Substation Load
kW
AS Transformer
13,812(b c)
MAS Transformer
11,310
OKS Transformer T1
9,787 (b, c)
OKS Transformer T2
6,929
a) System noncoincident peak load is slightly different from the peak load as discussed previously due to scaling
factors and system losses.
b) Ashland Substation load includes -4.3 MW for PacifiCorp.
c) Oak Knoll Substation load includes -5.5 MW for PacifiCorp.
7.2.3 Case 2A: Ten -Year Growth Case
The load forecast presented in Chapter 3 calls for an additional 3.4 MW of peak demand growth
considering a 0.72% annual growth rate. The modeled allotment of the growth was implemented
by linearly scaling up the load profile in the base Case 1A. Adding these loads results in a
combined peak load of 49.3 MW distributed as shown in Table 7-4.
No undervoltage or overvoltage violations were observed in the ten-year growth case based on
normal regulator bank operation. The substation transformers have sufficient capacity except for
the transformer in the Ashland Substation. PacifiCorp customer loading of 4.3 MW and 5.5 MW
were considered in Ashland Substation and Oak Knoll Substation respectively, along with their
historical last 10 year peaks of approximately 5.5 MW and 9 MW. Considering the assumed
load growth and PacifiCorp's loads, the total substation load in Ashland Substation will likely
exceed the transformer overload rating of 20 MVA by 5% to 10%. PacifiCorp typically adds 20%
to the nameplate rating as their guide for Winter capacity rating, however, it does not
compensate for the City of Ashland Summer peak loading pattern.
If PacifiCorp does not upgrade Ashland Substation with a larger transformer or add a second
transformer in parallel in the next decade, we recommend the City consider building a new
Nevada Substation with a 15/20/25 MVA transformer with the benefits of zero wheeling cost or
transformation cost, full control of the substation, improved service reliability and backup
capability. With the new substation, the distribution circuits could be reconfigured to extend and
pick up portions of Oak Knoll feeders to reduce PacifiCorp dependence and transformation
charges at Oak Knoll Substation.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-15
Pane AS of 1.17
Depending on the load distribution, some of the backbone fuses, 140K and 100K, along the
Ashland/Business feeder are recommended to be monitored, as they will likely exceed their
rated capacity.
Table 7-4: Case 2A Power Flow Details
Feeder Load
kW
PF (%)
Amps
A2000 - Business
6,904
97.9
318.5
A2001 - North Main
6,638
97.5
306.9
A2002 - Railroad
1,954
97.9
90.1
M3006 - N. Mountain
985.6
98.9
45.0
M3009 - Morton
6,126
97.8
282.8
M3012 - S. Mountain
5,511
97.4
255.4
M3015 - Wightman
2,580
98.2
118.8
K4056 (5R56) - HWY 99
7,212
97.1
335.3
K4070 (5R70) - HWY 66
5,112
97.7
236.3
K4093 (5R93) - E. Main
6,640
96.8
309.8
Ashland System Load
kW
49,663 (a)
Substation Load
kW
AS Transformer
19,982(b c)
MAS Transformer
15,276
OKS Transformer T1
12,784 (b, �>
OKS Transformer T2
11,796
a) System noncoincident peak load is slightly different from the peak load as discussed previously due to scaling
factors and system losses.
b) Ashland Substation load includes -4,3 MW for PacifiCorp.
c) Oak Knoll Substation load includes -5.5 MW for PacifiCorp.
7.2.4 Case 2B: Twenty -Year Growth Case
Combined with the load additions for the previous growth case and the same growth rate, the
Load Forecast presented in Chapter 3 calls for an additional 3.7 MW of peak demand growth for
the twenty-year analysis. Similarly, the modeled allotment of the growth was implemented by
linearly scaling up the load profile in Case 2A. Adding these loads results in a combined peak
load of 53 MW distributed as shown in Table 7-5.
No undervoltage or overvoltage violations were observed in the twenty-year growth case based
on normal regulator bank and operation. As expected, the 20-year growth case results show
that the observed concerns noted for Case 2A will be further worsened. Some smaller -sized
transformers could likely reach their rated capacity (between 90% and 100%) if not overloaded.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 7-16
Pane RA of 1 .7
Table 7-5: Case 2B Power Flow Details
Feeder Load
kW
PF (%)
Amps
A2000 — Business
7,429
97.9
342.9
A2001 — North Main
6,380
97.7
295.0
A2002 — Railroad
2,099
97.9
96.9
M3006 — N. Mountain
1,147
98.8
52.5
M3009 — Morton
6,255
97.8
288.8
M3012 — S. Mountain
5,925
97.4
274.8
M3015 — Wightman
2,836
98.0
130.7
K4056 (5R56) — HWY 99
7,752
97
360.8
K4070 (5R70) — HWY 66
5,494
97.7
254.1
K4093 (5R93) — E. Main
7,148
96.6
334.0
Ashland System Load
kW
52,500 (a)
Substation Load
kW
AS Transformer
20,404(b c)
MAS Transformer
16,247
OKS Transformer T1
13,31 (b, c)
OKS Transformer T2
12,694
a) System noncoincident peak load is slightly different from the peak load as discussed previously due to scaling
factors and system losses.
b) Ashland Substation load includes —4,3 MW for PacifiCorp.
c) Oak Knoll Substation load includes —5.5 MW for PacifiCorp.
SECTIONALIZED CONFIGURATIONS
To evaluate the electric system's switching flexibility during outage conditions, sectionalized
power flow cases were performed under the Base Case (Case 1A) loading, 45.9 MW. The
following scenarios were analyzed:
• Individual substation transformer outages and substation outages
• Individual distribution feeder outages
7.2.5 Loss -of -Transformer Cases
Cases 3A to 3D modeled the base case as a sectionalized system under peak load with each
substation power transformer source out -of -service, and its load transferred accordingly. For
each loss -of -substation transformer scenario, the system is configured as identified in Table 7-6.
Case 3A Ashland Substation Transformer Out -Of -Service
The following system switching was modeled to simulate the necessary switching and transfer
of Ashland substation load to other substation transformers.
• Close SW-1073 to tie A2001 to A2000, close SW-1064 to serve both A2000 and A2001
from M3006.
• Close SW-1068 to serve A2002 from M3009.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-17
Pans An of 137
With the switching detailed above, all Ashland Substation load is transferred to Mountain
Avenue Substation feeders. The Mountain Avenue Substation transformer is heavily overloaded
to -160% of the nameplate fan -cooled overload capacity. Configuring the system as described
will significantly reduce the transformer's service life. In addition, the existing protection settings
(typically 150%) would likely trip the transformer off-line. Similarly, the 3-phase voltage regulator
will be overloaded. The North Mountain feeder would be required to serve approximately 13.8
MW of load, and segments of conductor along the North Mountain feeder would be at capacity
or overloaded as described below:
• The main 750 kcmil UG getaway will be loaded to 130% of capacity, 13.82 MW vs. 10.58
MW rating.
• The main 556 kcmil AAC overhead cables will be loaded to 109% of capacity, 13.69 MW
vs. 12.61 MW summer rating.
• The section of 750 kcmil UG cable between E6603 and E8601 is overloaded to 121 % of
capacity, 12.77 MW vs. 10.58 MW rating.
• The section of 336.4 kcmil AAC overhead cable connecting M3006 to the Ashland
Substation circuits is loaded to 138% of capacity, 12.61 MW vs. 9.11 MW summer
rating.
Based on the above, Mountain Avenue Substation does not seem to have sufficient capacity to
back up the City's peak loads supplied by Ashland Substation. The backbone circuit capacity for
North Mountain feeder is not rated for a total of 13.8 MW of loads. The City will have to make
significant upgrades (i.e., installing a second transformer in parallel) at the Mountain Avenue
Substation and its feeder to make the 100% backup feasible for peak conditions.
Table 7-6: System Sectionalizing Analysis - Single Transformer Bank Outage
Case
Substation &
Peak
Sectionalized
Sectionalized
Sectionalized
Sectionalized
Feeder
Load
Peak (kn
Peak (kM
Peak (!n
Peak
Ashland
18,795
AS XFMR
31,008
18,795
18,795
Substation
Out of Service
Case
3A
A2000 - Business
6,321
To M3006
12,490
6,321
6,321
A2001 - North Main
6,192
To M3006
6,192
6,192
6,192
A2002 - Railroad
1,819
To M3009
7,531
11819
1,819
Mountain Avenue
14,267
28,908
MAS XFMR
14,267
14,267
Substation
Out of Service
Case
M3006 - N_ Mtn
985.6
13,844
To A2000
985.6
985.6
3B
M3009 - Morton
5 683
7,530
To A2002
5,683
5,683
M3012 - S. Mtn
5,131
5,131
To A2000
5,131
5,131
M3015 - Wi htman
2,403
2,403
To K4093
2 403
2,403
Oak Knoll
23,226
23,226
25,819
OKS XFMR K1
Substation
Out of Service
Case
3C
K4056 - HWY 99
6,699
6,699
6,699
To XFMR K2
K4070 - HWY 66
4,748
4,748
4,748
-
K4093 - E. Main
6,168
6,168
8,745
-
Oak Knoll
OKS XFMR K2
Substation
23,226
23,226
25,819
23,295
Out of Service
Case
K4056 - HWY 99
6,699
6,699
6,699
6,699
-
3D
K4070 - HWY 66
4,748
4,748
4,748
4 748
To XFMR K1
K4093 - E. Main
1 6,168
1 6,168
8,745
1 6,168
1 To XFMR K1
a) PacifiCorp load is not included in the load transfer analysis.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 7-18
Pane Al of 1.17
Case 3B Mountain Avenue Substation Transformer Out -Of -Service
The following system sectionalizing was modeled to simulate the necessary switching and
transfer of Mountain Avenue substation load to other substation transformers.
• Close SW-1062 to tie M3006 and M3012, and close SW-1064 to feed M3006 and
M3012 from A2000.
• Close SW-1068 to feed M3009 from A2002.
• Close SW-1051 to feed M3015 from 5R93.
With the sectionalizing described above, the Ashland Substation transformer and regulators are
severely overloaded to 173% and 130%, respectively, of nameplate fan -cooled capacity under
peak loading with Mountain Avenue Substation out -of -service. The transformer at Oak Knoll
Substation seems to be sufficient. No additional overload or low voltage conditions are
encountered with normal regulator operations.
If the City desires to pursue a 100% backup, significant upgrades will be required at Ashland
Substation, or the development of a new City -owned Nevada Substation as discussed under
Section 7.2.3.
Case 3C Oak Knoll Substation Transformer K1 Out -Of -Service
When Transformer K1 (12/16/20 MVA) is out of service, Transformer K2 (15/20/25 MVA) needs
to support 23.3 MW (or 24.8 MVA) of load, which is just below the nameplate overload rating.
No additional overload or low voltage conditions are encountered with normal regulator
operations.
Case 3D Oak Knoll Substation Transformer K2 Out -Of -Service
When Transformer K2 is out of service, Transformer K1 needs to support 23.4 MW (or 25.4
MVA) of load, which is about 27% above its nameplate overload rating. The LTC within this
transformer can maintain all the service voltage to acceptable ranges.
7.2.6 Loss -of -Substation Cases
Case 3A and Case 3B are essentially the cases for loss of Ashland substation and loss of
Mountain Avenue Substation. As discussed above, loss of either substation at peak load will
result in severe transformer overload conditions at other substations, which would risk
accelerating the loss -of -life on transformers and cables. The level of overload may not be
allowed by typically thermal overload protection, which indicates the City might not have a
sufficient backup during peak load conditions as discussed.
When Oak Knoll Substation is out (or loss of the two transformers), the Oak Knoll feeders will
have to be supported by Mountain Avenue Substation based on the substation and feeder
locations. However, the transformer at Mountain Avenue Substation (12/16/20 MVA) is
expected to be loaded close to 75%, resulting in 5 MW of reserved capacity. It might be enough
to support one of the three Oak Knoll Substation feeders, but will not have adequate capacity to
be considered a full backup source. Under this condition without a second transformer at
Mountain Avenue Substation (as discussed under Case 313), it is assumed PacifiCorp would
utilize their portable transformer(s) to keep the Oak Knoll Substation feeders energized.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEM8ER 2024 7-19
Pane A? of 1.17
7.2.7 Loss -of -Feeder Cases
Cases 4A to 4K modeled the base case as a sectionalized system under peak load with each
distribution feeder circuit's source out -of -service, and its load transferred to the adjacent
feeder(s) accordingly. For each feeder out -of -service condition, the system is configured as
identified in Table 7-7.
Case 4A AS/A2000 Business Feeder Out -Of -Service
Close SW-1073 to feed AS/A2000 from AS/A2001.
A distribution feeder is typically designed with a maximum of approximately 7.5 MW (-340
A) normal operation capacity and 11 MW (-490 A) temporary or emergency rating. After
switching, no voltage concerns were observed; Feeder A2001 likely needs to carry 12.7 MW
of load, which is 15% above the emergency rating. Additionally, the 750 kcmil AL
underground conductors along Vansant Street are expected to have a through load of 11.58
MW during the analyzed peak condition, which exceeds its in -duct rating 9.18 MW (as
shown in Chapter 4) by 26%. This won't work for the in -duct cables, and the City will have to
feeder a portion of A2000 from another feeder other than A2001 to avoid that.
Case 413 AS/A2001 North Main Feeder Out -Of -Service
Close SW-1073 to feed AS/A2001 from AS/A2000.
After switching, Feeder A2000 is expected to be loaded to 12.6 MW, which is 15% above
the emergency rating. No voltage concerns and overloaded conductors were observed in
this case.
Case 4C AS/A2002 Railroad Feeder Out -Of -Service
Close SW-1068 to feed AS/A2002 from MAS/M3009.
After switching, Feeder M3009 is expected to be loaded to 7.5 MW. No voltage concerns
and overloaded conductors were observed in this case.
Case 4D MAS/M3006 N. Mountain Feeder Out -Of -Service
Close SW-1062 to feed MAS/M3006 from MAS/M3012.
After switching, Feeder M3012 is expected to be loaded to 6.1 MW. No voltage concerns
and overloaded conductors were observed in this case.
Case 4E MAS/M3009 Morton Feeder Out -Of -Service
Close SW-1020 to feed MAS/M3009 from MAS/M3015.
After switching, Feeder M3015 is expected to be loaded to 8.1 MW. No voltage concerns
and overloaded conductors were observed in this case.
Case 4F MAS/M3012 S. Mountain Feeder Out -Of -Service
Close SW-1062 to feed MAS/M3012 from MAS/M3006.
After switching, Feeder M3006 is expected to be loaded to 6.1 MW. No voltage concerns
and overloaded conductors were observed in this case.
Case 4G MAS/M3015 Wightman Feeder Out -Of -Service
Close SW-1051 to feed MAS/M3015 from OKS/K4093.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-20
Pane A3 of 137
After switching, Feeder OKS/K4093 is expected to be loaded to 8.745 MW, which is about
17% above the 7.5 MW typical maximum normal operation rating but less than the
emergency rating. No voltage concerns and overloaded conductors were observed in this
case with voltage regulators at 105% boosting.
Case 4H OKS/K4056 HWY 99 Feeder Out -Of -Service
Close SW-1039 to feed OKS/K4056 from OKS/K4070.
After switching, no voltage concerns were observed with voltage regulators at 105%
boosting; Feeder K4070 likely needs to carry 11.8 MW of load, which is 7% above the
emergency rating. Additionally, the backbone 336.4 AAC overhead conductors along HWY
66 are expected to be overloaded by 21 % (9.72 MW summer rating vs. 11.8 MW). During
peak conditions like this, the City may want to consider feeding a portion of K4056 from
another feeder other than K4070 to avoid that.
Case 41 OKS/K4070 HWY 66 Feeder Out -Of -Service
Close SW-1039 to feed OKS/K4070 from OKS/K4056.
After switching, no voltage concerns were observed with voltage regulators at 105%
boosting; Feeder K4056 likely needs to carry 11.8 MW of load, which is 7% above the
emergency rating. Similarly to Case 4H, the backbone 336.4 AAC overhead conductors
along Crowson Road and HWY 99 are expected to be overloaded by 21 % (9.72 MW
summer rating vs. 11.8 MW). During peak conditions like this, the City may want to consider
feeding a portion of K4070 from another feeder other than K4056 to avoid that.
Case 4J OKS/K4093 E. Main Feeder Out -Of -Service
Close SW-1051 to feed OKS/K4093 from MAS/M3015.
After switching, Feeder M3015 is expected to be loaded to 8.5 MW, which is about 13%
above the 7.5 MW typical maximum normal operation rating but less than the emergency
rating. No voltage concerns and overloaded conductors were observed in this case.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 7-21
Pane A4 of 137
Table 7- T System Sectionalizing Analysis - Loss -of Feeder Outage
Peak Load
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Sectionaliz
Case
Feeder
(kVA)
ed Peak
ed Peak
ed Peak
ed Peak
ed Peak
ed Peak
ed Peak
ed Peak
ed Peak
ed Peak
kVA
kVA)
(kVA)
(kVA)
(kVA
VA
VA
VA
VA
VA
Ashland Substation
18,630
18 630
18,630
16,810
18,630
18,630
18,630
18,630
18,630
18,630
18,630
A2000
A2000 -
Out of Serv.
Case4A
Business
6,321
To A2001
12,579
6,321
6,321
6,321
6,321
6,321
6,321
6,321
6,321
Close
SW1073
A2001
A2001 - North
Out of Serv.
Case 4g
Main
6,192
12,723
To A2000
6,192
6,192
6,192
6,192
6,192
6,192
6,192
6,192
Close
SWI073
A2002
A2002 -
Out of Serv.
Case4C
Railroad
1,819
1,819
1,819
To M3009
1.819
1,819
1,819
1,819
1,819
1.819
1.819
Close
SWI068
Mountain Ave Substation
14.203
14,203
14,203
16,050
14,203
14,203
14,203
11,843
14,203
14,203
20,432
M3006
M3006 - N.
Out of Serv.
Case4D
Mtn
985.6
985.6
985.6
985.6
To M3012
985,6
6,124
985.6
985.6
985,6
985.6
Close
SW1062
M3009
M3009 -
Out of Serv.
Case 4E
Morton
5,683
5,683
5,683
7,530
5,683
To M3015
5,683
5,683
5.683
5,683
5,683
C lose
SWI020
M3012
M3012 - S.
Out of Serv.
Case4F
Mtn
5,131
5,131
5,131
5,131
6,117
5,131
To M3006
5,131
5,131
5,131
5,131
Close
SW1062
M3015
M3015 -
Out of Serv.
Case 4G
Wightman
2,403
2,403
2,403
2,403
2,403
8,079
2,403
To K4093
2,403
2,403
8,497
Close
SW1061
Oak Knoll Substation
23,220
23.220
23,220
23,220
23,220
23,220
23,220
25,819
23,220
23,220
17,020
K4056
K4056 -
Out of SM.
Case 4H,
99
6,699
6,699
6,699
6,699
6,699
6,699
6,699
6,699
To K4070
11,796
6,699
Close
SW1039
K4070
K4070 -
Out of Sere.
Case 41
HVVY 66
4,748
4,748
4,748
4,748
4,748
4,748
4,748
4,748
11,801
To K4056
4,748
Close
SW1039
K4093
K4093 - E.
Out of Sere.
Case4J
Main
6,168
6,168
6,168
6,168
6,168
6,168
6,168
8,745
6,168
6.168
ToM3015
Close
SW1051
a) PacifiCorp load included in substation peak.
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 7-22
Pane G.ri of 137
Chapter 8 SHORT CIRCUIT ANALYSIS
8.1 METHOD
A short circuit analysis of the Ashland electric system was performed based on the following
data:
• Data for the circuit configurations and conductor segment sizes, material types, and
lengths as created for the power flow analysis.
• Short circuit fault -current data provided by PacifiCorp and BPA under the configuration
conditions noted herein:
Ashland Substation Data from PacifiCorp:
Three-phase Fault MVA at 115 kV = 1106.1 MVA
Single-phase Fault MVA at 115 kV = 829.5 MVA
Impedance X1/R1 = 7.84
XO/RO = 8.43
Oak Knoll Substation Data from PacifiCorp:
Three-phase Fault MVA at 115 kV = 1119.3 MVA
Single-phase Fault MVA at 115 kV = 906.6 MVA
Impedance X1/R1 = 8.75
XO/RO = 8.72
Mountain Avenue Substation Data from BPA:
Three-phase Fault MVA at 115 kV = 975 MVA
Single-phase Fault MVA at 115 kV = 722.9 MVA
Impedance X1/R1 = 6.8
XO/RO = 7.1
• For analysis purposes, the delivery voltage is set at nominal 12.78 kV or 1.025 per unit,
equivalent to —123 volts on a 120-volt base.
• Ground fault impedance is assumed to be 40 ohms as a guideline for minimum fault
current calculations as recommended by RUS Bulletin 1724E-102. The actual ground
fault impedance could be higher depending on the contacted surface characteristics.
Case -by -case fault analysis can be done upon request. Solidly grounded faults are used
to calculate the maximum fault currents.
8.2 ANALYSIS RESULTS
Table 8-1 shows the maximum fault current values available at the substation 12.47 kV
regulated buses with the system in normal configuration and all substations fed from BPA
normal source transmission systems. Figure 8-1 to Figure 8-3 show the color contour of the fault
currents. Some of the fault levels at the end of feeders are less than 2,000 A due to increased
feeder length and size of the circuit conductors, which is expected.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 8-1
Pane AR of 1.17
As time allows during routine service the City should check all nameplate ratings to verify that
distribution system protective devices are adequately rated in comparison to the short circuit
fault -current available at various system locations. If any equipment is found to be of insufficient
interrupting capacity, the device should be replaced.
Table 8-1: Normal Configuration Fault Currents (Symmetrical Amps)
SUBSTATION
SECONDARY BUS
L-G
L-L
L-L-G
3-PH
Ashland Substation
5,541
4,624
5,459
5,339
Mountain Avenue Substation
7,593
6,228
7,444
7,191
Oak Knoll Substation, Bank 1
5,584
4,661
5,500
5,382
Oak Knoll Substation, Bank 2
6,928
5,726
6,796
6,611
a) The short circuit information is based on single -ended faults at the 12.47 W bus.
Included in Appendix E is the complete short circuit analysis report as configured for the Base
Case. The short circuit analysis report printouts are presented for each feeder by substation.
The analysis model is developed based on various system junctions and conductors, and the
short circuit fault current data is organized in the same manner. For the majority of the analysis
`buses', these are pole, vault, and distribution system component numbers as taken from the
City's electric system maps. The City can determine the available fault current at any system
component or nearby component by referring to the substation -feeder short circuit report
printout and the associated system component number as they appear on the system maps.
The short circuit information provided is based on single -ended faults with one transformer
source feeding each fault location. During switching operations in which transformers are
paralleled the fault current will be considerably higher and may momentarily exceed equipment
ratings.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 8-2
Panes A7 of 117
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Chapter 9 PROTECTIVE DEVICE COORDINATION
9.1 METHOD
A coordination analysis was performed to determine proper protective device settings that will
quickly isolate the source of a fault or system interruption to minimize the number of customers
with interrupted service, system damage, and outage duration. In determining protective device
settings some compromise is generally required between system protection and continuous
electric service.
Major substation and feeder protective device coordination are analyzed in this study with
protective time -current curves provided for each feeder. The Ashland electric distribution system
was analyzed using the existing normal circuit configuration. The evaluation is based on
protective device settings at the substation and fuse ratings as displayed on the Ashland
mapping system. Fuse sizes should be verified by Ashland to ensure proper system
coordination. This fuse verification task is usually performed on a feeder -by -feeder basis as time
allows or when m is-coord i nation occurs.
The protection recommendations provided by the Institute of Electrical and Electronic Engineers
(IEEE), the American National Standards Institute (ANSI) and the National Electrical Safety
Code (NESC) establish the basis for this system coordination study. They provide the
boundaries that protective devices should operate within to ensure equipment reliability and
safety of the system.
The selection and coordination of the system's protective devices are determined by plotting the
time- versus -current operating characteristic curves for substation protection components and
for the individual protective devices on each feeder. Each device is compared with its respective
upstream device to ensure proper selectivity and protection. If lack of selectivity or protection is
found, methods of changing the device's current, time setting, or the device itself are identified
where possible.
In determining if sufficient protection exists all protective device characteristic -curves should fall
within the boundaries established by IEEE, ANSI and the NESC. All device curves must be
adequately separated to make certain that undesirable operations will not occur. The criteria for
adequate separation depends on the type of device used and the safety factor desired. The
settings recommended in this report are based on the following guidelines:
• For coordination between digital relays, separation between curves should be a
minimum of 0.2 seconds at the maximum expected short circuit current.
For coordination between digital relays and downstream fuses, the separation should be
a minimum of 0.2 seconds.
• For coordination between fuses, a clear separation of curves is required. Pre -loading
and safety factors should be considered.
The following general guidelines were used in determining the system protection plan.
Restrict outages due to permanent faults to the smallest system section for the shortest
time.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-1
Panes 101 of 137
• Provide special consideration for critical loads.
• The device nearest the fault should clear a permanent or temporary fault before the
backup fuse interrupts the circuit or the breaker/recloser operates to lockout.
• Coordinate devices for the best balance of protection and continuity of service.
• Assume 70 percent of overhead system faults are temporary.
• Assume 70 percent of overhead system faults are ground faults.
• Presently, the City has EEI-NEMA Types `T' and `K' fuse links installed in the system.
The `T' links are somewhat slower operating fuses and provide a better range of
coordination with breakers and recloser protection.
• Ideally, attempt to use no more than three fuses in series beyond a breaker, recloser, or
sectionalizer.
• Where possible, select a minimum trip on breaker and recloser protection that is at least
two times the peak load current. This facilitates cold load pickup.
• The load current should be less than 70 percent of the continuous current rating of the
device to allow for load growth.
• For overhead systems, ensure that all parts of the feeder are within the zone of a
reclosing device. This allows the breaker or the recloser to sense and operate for
minimum faults at the extreme ends of the feeder circuit.
9.2 PROTECTION CRITERIA
This section presents definitions and methodology specific to the applications of fuses and other
protective devices on the Ashland distribution system. A summary of substation protective
device settings is included in this section for use in verifying, tabulating, and making field
settings. Specific problems are addressed in the following discussion.
9.2.1 Fuse Application
The Ashland distribution system protection philosophy consists of applying fusing protection to
all tap points away from the main feeder backbone conductor. The application of distribution
class fuses on the Ashland electric system feeders includes the protection of main feeder tap
lines, radial line taps, underground taps, and distribution transformer fusing.
Due to the potential for heavy load currents and to minimize the number of customers
interrupted, the installation of fuses in the main feeder circuit backbone is not recommended. In
the future, even though loads are expected to grow, the addition of new feeders and the
balancing of loads should help reduce the load current on most feeders, resulting in easier
coordination capability.
Presently, Ashland has line electronic sectionalizing devices near major underground circuits
and taps. Should nuisance outages or misoperation between protective devices occur because
of improper coordination, the protective settings should be reevaluated and the installation of
line sectionalizing or recloser devices only be considered if necessary. For now, the systems
feeder downstream coordination design will continue to rely primarily on existing sectionalizing
devices and fusing.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-2
Panes 109 of 117
As a general rule, tap lines should be fused to protect the main distribution feeder backbone
lines. This includes long tap lines, taps that are known to have unusual or vulnerable exposure,
taps to underground risers/dips, and taps with a history of being subjected to an unusually high
number of faults.
Line tap fuses should normally have as small a rating as load current will allow, and yet provide
optimum coordination with the substation relays. Both the speed at which faults are cleared and
the sensitivity of the ground fault protection increase as the ratings of the line tap fuses
decrease. However, when coordinating with multiple -shot reclosing, the fuses must be large
enough to avoid damage during the reclosing "fast" operation. For this study, line tap fusing was
evaluated for adequate coordination with upstream protective devices but were not evaluated
for sizing based on tap load.
It appears that the electric department has not identified all distribution fuse sizes on the system
feeder maps. We recommend, as time allows, the electric department verify/install and indicate
all fuse sizes as necessary based on the criteria set forth in this study. The following
suggestions and data should assist the electric department in evaluating its existing fuse
practices and the selection of fuses in the future.
When describing two or more fuse links, or other system protective devices, conventional
definitions identify the nearest device to the fault on the load side as the "protecting" device and
the next device toward the source side as the backup or "protected" device. This convention is
used in the recommendations listed below.
SUWAnON
PROTECTED OR PROTECTING FUSE
BACKUPFUSE UNK UNK
PROTECTING FUSE
LINK
Figure 9-1: Conventional Definition of Protective Devices Based on Location
Fuse Selection
Fuse and cutout selection depends on the load current, system voltage, system type, and
available fault current, which determine the current rating, voltage rating, and duty type of the
cutout, respectively.
Fuse Current Rating - The rated continuous current of the fuse should be equal to or
greater than the maximum continuous load current that it will be required to carry.
Fuse Duty - The symmetrical interrupting rating should be equal to or greater than the
maximum calculated fault current possible on the load side of the fuse.
Voltage Rating - The proper voltage rating is determined by the following system
characteristics:
o Maximum system phase -to -phase or phase -to -ground voltage
o System grounding
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-3
Pane 1 n i of 137
o Single-phase or three-phase circuits
Selecting the proper voltage rating will ensure the basic insulation level (BIL) of the cutout will
match that of the system.
Fuse Types and Characteristics
Fuses can be applied to a variety of applications requiring overcurrent protection of distribution
systems and equipment. When properly coordinated with other overcurrent devices,
sectionalizing to isolate faulted feeder branches and equipment is accomplished.
Fuse links are designed to meet ANSI C37.42 and NEMA SG2.1 standards. Fuses are divided
into two categories, expulsion fuses classified as "zero -awaiting devices" which await the zero
point to extinguish an arc, and current -limiting fuses classified as "zero -forcing devices" which
introduce a high resistance into the circuit forcing the current to a relatively low value.
The ANSI standards define two classifications of fuses, Power Fuses and Distribution Fuses,
which apply to both expulsion and current -limiting fuse categories as follows.
• Power Fuses are typically applied in a substation or close to a substation, and,
according to ANSI C37.46 standards, have higher voltage ratings (2.8 to 169 kV) and
higher X/R ratio ratings (15 to 25).
• Distribution Fuses are typically applied away from substations, and, according to ANSI
C37.47 standards, have lower voltage ratings (5.2 to 38 kV) and lower X/R ratio ratings
(8 to 15).
Some fuses have specific electrical characteristics in accordance with rating systems defined by
industry standards. Understanding this rating system is important when applying fuses to
establish which manufacturer fuses are interchangeable. Fuses are electrically interchangeable
when they have:
• The same characteristics throughout the entire time range of standard time -current
curves. They are typically plotted from 0.01 seconds to a minimum of 300 seconds for
expulsion fuses and to 1000 seconds for current -limiting fuses.
• The same long-time continuous current ratings.
If fuses are not electrically and mechanically interchangeable, then a time -current characteristic
study should be completed to ensure coordination is maintained.
Electrical equipment such as transformers, switches, relays, and conductors are exposed to
various levels of current during normal operation. Generally, electrical devices can withstand
high electrical currents for a short period of time and low current for prolonged periods of time
without thermal failure or mechanical damage. The ability to withstand various levels of current
for varying periods of time is referred to as the `time -current characteristic.'
The coordination of power systems involves the selection of fuse links to protect equipment with
various time -current characteristics while coordinating with other system devices, reclosers,
sectionalizers, breakers, relays, and other fuses. Some types of fuse links, described below,
have a wide range of time -current characteristics as summarized in Table 9-1.
The speed ratio of fuse links 100 amps and below is the ratio between the current that melts the
fuse in 0.1 seconds to the current that melts the fuse in 300 seconds. The higher the ratio, the
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEM8ER 2024 9-4
Panp 104 of 117
slower the melting speed. The speed ratio for fuses rated above 100 amps is the ratio between
the melting currents at 0.1 seconds and 600 seconds.
The following information is provided to present some background on specific fuse criteria and
assist with fuse selection.
• Type K fuse link is a 'fast' fuse with a nominal speed ratio of 7 and is well suited for fast
time -current characteristic applications such as capacitor protection.
• Type 200 (N) fuse link is classified as a 'medium' speed fuse with a nominal speed ratio
of 9. It provides more surge withstand capability than type K fuse links and good
coordination with reclosers and relays.
• Type QA fuse link is also classified as a 'medium' speed fuse with a nominal speed ratio
of 9. It carries 100% of rated current without damage, providing good coordination
characteristics with reclosers and relays.
• Type T fuse link meets requirements for'slow' speed fuses, with a nominal speed ratio
of 12, providing slower time -current characteristics than K 200, and QA fuse links, and
coordinates well with reclosers and relays.
• Type KS fuse link employs dual element construction that gives high surge withstand
capability. With a nominal speed ratio of 20 it is classified as a 'very slow' fuse link and is
a good choice for line fusing and transformer protection.
• Type X fuse link employs dual element construction specially designed for transformer
protection, has an 'extra slow' nominal speed ratio of 32, and provides excellent surge
withstand to avoid nuisance blowing from lightning and switching surges.
Table 9-1: Fuse Speed Ratio Chart
SINGLE ELEMENT
DUAL ELEMENT
Designation
Fast
Medium
Slow
Very Slow
Extra Slow
Type
K
200 (N), QA
T
KS
X
Speed Ratio
6-8
7-11
10-13
20
32
Table 9-2 and Table 9-3 present the standard requirements of the expulsion and current -limiting
fuse rating system, respectively. Note that for some fuse types (e.g., N, QA, or X) the rating
system does not have a point -of -coordination requirement, as noted in Table 9-2. This means
that such fuses of different manufacturers will not be fabricated identically, and duplicate
coordination may not be maintained between different manufacturer devices.
Table 9-2: Expulsion Fuse Rating System
Fuse Series
Size
Coordination Point
Melting Current
ANSI Std.
0-100E
300 sec
200 - 240%
C37.46
E
125-200E
600 sec
220 - 264%
C37.46
0-100K
0.1, 10, 300 sec, Speed
Table 6 ANSI Std
C37.42
K
Ratio Fasta
140-200K
0.1, 10, 600 sec, Speed
Table 6 ANSI Std
C37.42
Ratio Fasta
T
0-100T
0.1, 10, 300 sec, Speed
Table 7 ANSI Std
C37.42
Ratio Slowa
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-5
pane 1 ns of 1 S7
Fuse Series
Size
Coordination Point
Melting Current
ANSI Std.
140-200T
0.1, 10, 600 sec, Speed
Table 7 ANSI Std
C37.42
Ratio Slowa
D, H, N, QA, S, X,
ALL
NONE
N/A
N/A
Ba -O-Net, etc.
a) Speed ratio is the ratio of minimum melting current at 0.1 second to the minimum melting current at 300 or 600 seconds,
depending on fuse size.
b) There are no standards requiring electrical interchangeability.
Table 9-3: Current -Limiting Fuse Rating System
Fuse Series
Size
Coordination Point
Melting Current
ANSI Std.
C
ALL
1000 sec
170 — 240%
C37.47
E
0-100E
300 sec
200 — 240%
C37.46
125-200E
600 sec
220 — 264%
C37.46
As stated previously, ANSI and IEEE standards divide fuses into classifications between extra
fast to extra slow type links. The choice of classification, fast -to -slow, depends on the desired
protection to be established for the distribution system. Fast links remove faults from the system
in less time, whereas slow links have a greater withstand capability to transient and inrush
currents, coordinate well with inverse relays and better with each other over a wide range of
currents.
Further, the continuous current rating of types T and K (tin) links is 150 percent of nameplate
and the continuous current rating of type K (silver) and type H and N (tin) links are 100 percent
of nameplate rating. Table 9-4 shows the continuous current rating that tin links will carry
without overheating when installed in properly sized cutouts.
Table 9-4: Fuse Continuous Current Ratings, Continuous Current -Carrying Capacity of Tin Fuse Links
High Surge
Link
Rating(amperes)
Continuous
Current
N Rating
Continuous
Current
(amperes)
MA K
or T R
or T Rating
Continuous
Current
(amperes)Ratin
EEI-NEMA
K or T
Continuous
Current
am res
1 H
1
25
25
6
9
40
60'
2H
2
30
30
8
12
50
75`
3H
3
40
40
10
15
65
95
5H
5
50
50
12
18
80
120t
8H
8
60
60
15
23
100
150t
75
75
20
30
140
190
N Rating
85
85
25
38
200
200
5
5
100
100
30
45
8
8
125
125
" Only when used in a 100- or 200-ampere cutout.
t Only when used in a 200-ampere cutout. Limited by
continuous current rating of cutout.
10
10
150
150
15
15
200
200
20
20
Specific Fusing Recommendations
The basic interruption device for the majority of Ashland's electric distribution system is the `T'
tin link expulsion fuse or type 'K' for both overhead and underground applications, with some
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEA48ER 2024 9-6
Pane 108 of 117
use of current -limiting fuses for three-phase pad -mount transformer applications. We
recommend that Ashland continue to use type 'T' fuse links and replace the existing type 'K'
fuses when possible. However, in areas of high fire danger, current limiting fuses should be
utilized instead of expulsion fuses as described in the City's Fire Mitigation Plan. This is
discussed further below.
There may be portions of the Ashland underground network system configured with no fusing
other than at the origin of the radial tap. This is not unusual for radial taps. Under faulted
conditions, this protection will isolate a fault from the main feeder backbone, but the lack of
downstream protection can result in interruption to a greater number of customers than is
necessary. Some UG sectionalizing devices have tap circuit electronic selectable protection
settings, whereas underground cabinets with only tap (junction) capabilities may have fused
elbows or no protection.
Should frequent outages occur in underground service areas, we suggest that Ashland consider
the use of current -limiting fuses, type NX, ELS, ELSP, ELST, or equivalent (depending on the
application) or the use of padmount sectionalizing devices with adjustable interrupting ratings.
Reference to Cooper Power System (Eaton) fuses is only for convenience and equivalent
manufacturer fuses are acceptable.
Ashland may want to consider the use of current -limiting type fuses at strategic underground
locations within the distribution system. Current -limiting type fuses provide superior overload
protection for underground cable distribution systems. These fuses are noiseless and expel no
hot gases or burning particles while interrupting currents. Their current -limiting capability greatly
reduces the momentary fault duty on protected equipment, extending life and saving
expenditures. The ability of current -limiting type fuses to interrupt low -current faults eliminates
the need for auxiliary devices to handle these troublesome current levels. These fuses extend
the system coordination because of their fast clearing and current -limiting ability, assisting in the
elimination of conductor and equipment damage caused by high fault currents. This operating
advantage to limit fault current, known as let -through current, reduces the burning and damage
at the point of fault.
Where flexible source sectionalizing is necessary and fast tap restoration is desired at critical
underground tap locations, the use of pad -mounted switchgear with load break isolation source
switches and quick operating, adjustable setting, single or three-phase interruption should be
considered. Although this type of equipment is considerably more expensive than fused tap
points, the superior sectionalizing, flexible interrupting protection, and quick service restoration
make it practical at strategic locations. At locations where three-phase loads are served, these
devices can also prevent troublesome single -phasing conditions.
The guidelines below identify the criteria used when evaluating and selecting fusing for the
Ashland electric system. It is recommended that Ashland adopt the practices suggested below
when applying fusing to the system in the future.
• Fuses should normally not be loaded more than 90 percent of continuous current rating
to avoid excessive fuse pre -loading which reduces fuse melting time. Where practical
the fuse size chosen should allow for load growth.
• Maximum clearing time of the protecting (load side) link should not exceed 75 percent of
the minimum melting time of the protected (source side) link. This assures the protecting
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEA48ER 2024 9-7
Panes 1 n7 of 117
link will interrupt and clear the fault before the protected link is damaged in any way by
compensating for pre -loading, ambient temperature, and heat of fusion.
• EEI-NEMA type T links are generally preferred over K links for both tap line fusing and
transformer protection. Type T links provide better coordination with substation relays
and have better overload and inrush characteristics than K links.
• EEI-NEMA type T (tin) and type K (tin) links are divided into two rated category series:
o Preferred sizes: 6, 10, 15, 25, 40, 65, 100, 140, and 200 amperes.
o Non -Preferred sizes: 8, 12, 20, 30, 50, and 80 amperes.
• We recommend Ashland install preferred category fuse sizes. Mixing fuses with adjacent
ratings from preferred and non -preferred categories reduces the coordination available
when applying fuses in series.
• Ashland may have installations of mixed preferred and non -preferred fuses. To save
expense where installations have mixed category fuses with adjacent ratings that will
clearly not coordinate well, Ashland may desire to change fuse size by utilizing both
categories but restrict use so that each radial tap uses only one fuse category. This
approach will, however, require more warehousing and good recordkeeping.
• Coordination of series combinations of fuses depends on the fuse types, their
continuous ratings, and the available fault current. Table 9-12 and Table 9-13 will assist
Ashland staff with coordinating Type K and T fuses in series, respectively.
• Coordinate line tap fuses with the substation breaker relay and feeder recloser control
settings. Avoid attempting to coordinate a line tap fuse with a downstream distribution
transformer fuse, which can result in the line tap fuse mis-coordinating with the
substation protective devices.
• Line tap fuses in series should always be coordinated with each other, the substation
breaker relays, and feeder protective devices. Attempt to minimize the number of fuses
in series. Normally, no more than three fuses in series can be completely coordinated.
• Avoid the use of 200-amp line tap fuses, as they provide limited coordination with the
substation breaker relays and feeder protective devices. When capacity of 200 amps is
required, consider installing an electronically controlled automatic line sectionalizer or
recloser with phase and ground sensing.
• Cutouts used for manual sectionalizing of the main feeder line should be equipped with
either solid links or oversized fuses. Multiple shot reclosing (with "Fuse Saving") will
coordinate with only a narrow range of fuse sizes and these should be used for line taps.
It is generally difficult to coordinate with both main line fuses and line tap fuses.
• If outages indicate that a protective device needs to be installed on a feeder 'main line'
to reduce the number of customers affected by faults, consider using an electronic line
recloser with phase and ground tripping and adjustable reclosing. These devices will
allow better coordination with upstream substation breakers or reclosers.
• Table 9-12 and Table 9-13, in conjunction with short circuit (fault) data provided in this
report should be helpful in applying line tap fuses. For effective ground fault
coordination, fuse ratings as low as feasible are preferred. Generally, it is desirable to
install fuse links rated to or less than 100 amps.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 9-8
Pane 108 of 137
The basic goal in coordinating downstream overhead fuses with substation relays is to fit
the fuse curve in between the relay fast and slow curves where "fuse saving" is being
applied. The fuse sizes selected will accomplish this over the fault current range
indicated. Fuses smaller than those suggested can be used with some sacrifice in
coordination. For these smaller fuses, a fault downstream of the fuse may cause both
the fuse and the relay to operate, but the reclosing relay should then reclose
successfully restoring the main line to service.
Fuse link applications for primary distribution transformer protection are guided by fusing
ratios. Link selection is always a compromise because primary links cannot distinguish
between short -time overloads, long -duration overloads, and high -impedance secondary
faults. These external fuse links are usually selected to blow when load current exceeds
a predetermined multiple of full load current for 300 seconds. This multiple is known as
the fusing ratio. As the transformer fusing ratio increases, overload protection decreases
but load -pickup ability increases.
A fusing ratio of 3 is most popular and allows an overload of 300 percent, with adequate
margin for inrush current. A schedule based on a fusing ratio of 2 to 3 is shown in Table
9-14. Type T and K links provide the best overload protection and rapidly remove
damaged transformers from the system, but at a sacrifice of the short -time overload
capability of the transformer. High -surge H fuse links, designed for primary fusing of
small -sized transformers, are also included in Table 9-14. The H fuse links provide
overload protection and withstand short -time current surges.
To assist in the selection of current limiting fuses, Table App F-1 and Table App F-2 are
provided in Appendix X. These tables describe transformer applications for single and three-
phase pad -mounted transformers, respectively.
Table App F-3 can be used for the selection of type NX fuses for coordination with standard
expulsion type fuses, if desired. For best coordination when applying current -limiting type fuses,
the expulsion (type T or K) link fuses should always be used as the source protection, and the
current -limiting fuse as the load protection. The NX type fuse provides good overload protection
for underground cable distribution systems by greatly reducing the momentary duty on protected
equipment and extends system coordination because of its fast clearing capability.
To assist with the selection of types ELS and ELST current -limiting fuses, Table App F4, Table
App F-5, and Table App F-6 are provided which display ELS fuse type continuous current
ratings, and single-phase and three-phase transformer current rating recommendations,
respectively; Table App F-7 and Table App F-8 are provided which display ELST fuse type
continuous current ratings, and three-phase transformer current rating recommendations,
respectively.
The ELS type full range current -limiting fuse is designed for use in series with Bay-O-Net fuses
(two -fuses scheme) for oil -filled padmount transformers and sectionalizing equipment devices
offering quiet and safe operating characteristics. The ELST type fuse consists of full range
current -limiting tandem fuses. The current -limiting section efficiently reduces the effects of high
fault current on upstream and downstream devices, while the expulsion section protects the
current -limiting fuse from system voltage.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-9
Pang 1 flA of 117
The electric department should be aware that modern Bay-O-Net fusing that is not applied in
series with a current -limiting fuse requires an isolation link. Ashland may currently be obtaining
pad -mount transformers with this type of fusing. Isolation links are not fuses and do not have an
interrupting rating. During a transformer failure, the isolation link will melt so that the opened
primary circuit of a faulted transformer cannot be re -energized by the line crew, providing extra
protection during re -fusing operations.
Wildfire Mitigation Considerations
Type T expulsion -style fuses are common for tap line protection and transformer protection and
they are fire -safe per the manufacturers' catalog. However, their primary characteristic is that
they are vented devices in which after their fuse element melts and arcs, the expulsion effect of
the gases produced by the interaction of the arc with other parts of the fuse results in the current
interruption in the circuit. The molten metal combined with ventilated gas could be a source of
ignition for fire. These fuses are not a good choice in areas that have high fire risks. Non -
expulsion fuses or current -limiting fuses (CLF) are recommended in the high -risk area. For large
and rural electrical systems, the current -limiting feature of the CLF may not be triggered due to
low fault currents, but the nonexpulsion feature is what provides the most benefit with regard to
wildfire mitigation.
The Cooper ELF current -limiting dropout fuse has a self-contained design that operates silently
and eliminates expulsive showers that are from typical expulsion fuse operation. These fuses
have a full -range current -limiting rating that ensures reliable operation of both overloads and
fault currents. These features make it suitable for areas where a high fire hazard exists. This
type of fuse has sizes up to 100A at 8.3 kV as shown in Table 9-15.
Cooper also has ELF-LR liquid fuse replacements that are noiseless and expel no hot gases or
burning particles while performing fault current interruptions. They are recommended in heavily
wooded areas and when tree trimming falls behind. This type of fuse has sizes up to 20A at 8.3
kV (Table 9-16), and is suitable for smaller circuits.
Both ELF and ELF-LR fuses are designed to protect pole -type transformers, single-phase and
three-phase laterals, and underground taps. They coordinate with Type T and Type K fuse links
as shown in Table 9-17 and Table 9-18 specifically.
9.3 FUSE SELECTION EXAMPLES
Three examples of distribution fuse sizing selection are provided below to assist in determining
the appropriate fuse sizes for Ashland's electric distribution system.
9.3.1 EXAMPLE 1. Fused Tap Protection
Given: Assume a tap is presently protected with three 25T fuse links and has upstream
protection consisting of 100T fuses. Further, assume the total connected load at this tap is as
follows; A -phase = 200 WA, B-phase = 487.5 WA, and C-phase = 150 WA, and the tap has an
available short circuit fault current of 2,860 amps.
Find: Evaluate the tap to determine if adequate protection is provided.
Solution: In the heaviest loaded phase, the maximum full load current is 487.5-kVA/7.2 kV = 68
amps. To account for future growth and connected transformer inrush current a typical multiplier
of 1.5 is taken times the current value, resulting in 102 amps. A fuse with a continuous current
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-10
Pane 110 of 117
rating near this value is sought. Table 9-4 indicates that a 65T fuse link is the proper size fuse
for this application.
However, notice that the connected WA loading at the location identified above is badly
unbalanced and should be adjusted. If loads are reconnected to provide good phase balance,
near 280 WA per phase, a 40T fuse link can be selected as the preferred fuse for this tap
location, (i.e., 280 kVA/7.2 kV x 1.5 = 58 amps, and the use of Table 9-4 suggests a 40T fuse).
Also, it must be determined if the selected fuse for the tap will coordinate with the three
upstream 100T fuse links of the main feeder tap. As noted above the short circuit report
indicates the maximum fault current available at bus x is 2,860 amps.
To determine if the downstream (protecting) fuse will coordinate with the upstream (protected)
fuse Table 9-13 must be examined. Table 9-13 indicates that the maximum fault current at
which the 65T protecting fuse link will coordinate with for the protected 100T fuse link is 2,200
amps. Since the available fault current (2,860 amps) exceeds this value the next smaller
preferred fuse size should be selected, this is a 40T fuse link. The chart in Table 9-13 shows
that these fuses will coordinate nicely to a fault value of 6,100 amps.
As shown in the above example, with properly balanced loads the 40T fuse link will provide
adequate continuous current and protection at this tap. It would therefore be recommended that:
a) the loads are reconnected to allow evenly distributed phase balance, and b) the existing 25T
fuses be removed and replaced with 40T fuse links.
9.3.2 EXAMPLE 2. Fused Three -Phase Transformer Tap Protection
Given: Assume an overhead line is to be tapped and that the tap is overhead connected to
serve an underground dip and a new 300 WA, 12.47 GrdY/7.2 kV x 208Y/120 V, 2 percent
impedance pad mount transformer, and that the fuse must coordinate with upstream 65A K or T
link fuse protection. The short circuit analysis indicates the maximum fault current available at
this tap as 2100 amps.
Find: Determine the proper size fuse to protect the tap and transformer and yet adequately
allow for cold load pickup and inrush currents to avoid fuse damage.
Solution: Although it is strongly suggested to compare time -current -curves to ensure adequate
continuous coordination and protection of all devices and associated conductors, the general
procedure required to size fusing for this application is as follows:
• Transformer full -load current = 300 kVA/(12.47 kV x 1.7321) = 13.9 amps
To avoid nuisance fuse operation, cold -load pickup should be evaluated. Fuse protection
will be sufficient if the fuse has a continuous current rating equal to approximately 2 x
full -load current. In this case 2 x 13.9 = 28 amps. In looking at Table 9-4, we see that a
20 amp K or T link fuse has a continuous current rating of 30 amps, and this fuse's
continuous current rating shown on the minimum -melt time -current curve falls to the right
of the 28 amp value on the curve.
The fuse's minimum -melt time -current curve should also be compared with other
multiples of transformer rated load current. These other points on the curve include 6 x
full -load current for 1 second, and 3 x full -load current for 10 seconds. In this case, 84
amps for 1 second and 42 amps for 10 seconds, respectively.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEA48EP 2024 9-11
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To account for transformer inrush, the combined magnetizing and load -inrush current,
referred to as hot -load pickup, the fuse must be able to withstand this momentary current
equivalent to 10 to 12 time full -load current for 0.1 seconds. In this case, that point is at
140 amps and 0.1 seconds. Here again, the selected fuse minimum -melt curve should
be to the right of this point on the time -current curve.
The EEI-NEMA Type K or T tin fuse minimum -melt curve is provided at the end of this chapter
and the points noted in the above example are highlighted to demonstrate that the chosen 20-
amp fuse satisfies all necessary selection criteria. It should also be observed that the 20K link
curve clearly coordinates with the 65K fuse, and by inspection of Table 9-12, the protecting 20K
fuse will coordinate with the protected 65K fuse up to 2200 amps, above the maximum available
fault current. If Ashland is adhering to the fuse selection criteria of using only preferred fuse
sizes, a 25K link will also coordinate nicely at this location.
9.3.3 EXAMPLE 3. Single -Phase Transformer Tap Protection
Given: Assume a fuse size selection is needed to provide protection for an overhead line tap
that is to serve one pole -mounted distribution transformer rated 100 kVA, 7.2 kV x 240/120 V.
Find: Determine the transformer full -load amps (FLA) and select the proper fuse size. Typically,
a suitable fuse will have a continuous current cap approximately 2 times FLA to accommodate
overload and inrush. Table 9-14 can be used to make this fuse selection by choosing the
connection type, in this case Wye -Connected Primary'Figure D' and then searching in the
`7200/12470Y' Column for the proper fuse. A more thorough evaluation can be accomplished by
using the method below but requires a comparison with the fuse time -current curve
characteristics.
Solution: Calculate the transformer magnetizing in -rush currents at 12 times FLA for 0.1
second and 25 times FLA for 0.01 second. Also, to avoid nuisance fuse operation include the
potential contributions of cold load pickup at the following multiples of FLA; 6 x FLA for 1
second, 3 x FLA for 10 seconds, and 2 x FLA for 15 minutes. These current and time values are
then to be compared with the selected fuse time -current curve characteristics to assure the fuse
is not damaged and does not operate under these conditions. Calculations for both fuse
selection methods follow:
• Calculate FLA = 100 kVA/7.2 kV = 13.9 amps. Therefore, 1.5 x = 20.8 and 2 x = 27.8
amps. So, a fuse with a continuous current rating in this range will be satisfactory, and,
since Ashland uses 'T' link fuses, we see from Table 9-4 that a 15 amp or 20 amp fuse
will be suitable. Table 9-14 agrees with this finding.
• Calculating the various currents for time -current curve comparison at specific times
results in the following values:
0 25 x FLA = 347 amps @ 0.001 second.
0 12 x FLA = 167 amps @ 0.1 second.
0 6 x FLA = 83.3 amps @ 1.0 second.
0 3 x FLA = 41.7 amps @ 10 seconds.
0 2 x FLA = 27.8 amps @ 15 minutes.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-12
Pan,- 119 of 137
A comparison of the currents and times calculated above with the 15K link minimum -
melt curve indicates the 15 amp fuse will satisfy the above criteria and is a suitable
installation.
9.3.4 Other Protective Devices
Sectionalizer Protection for Overhead Construction
Three-phase electronic sectionalizers should be considered in the future and are recommended
for locations that require overcurrent protection where a 140T fuse cannot carry the full load
current of the connected transformers (full load current x 1.5 multiplier), except in specific areas
where a vacuum fault interrupting device will provide better protection of large critical overhead
and underground taps. It should be noted that for most distribution applications Electronic
Sectionalizers have a maximum continuous rating of 200 amp, and that the minimum pickup
current is selectable. An example of such a switch is Eatons/Cooper, Distributed Automated
Switch (DAS) a switch with electronic control.
The possible use of sectionalizers is introduced in this study to present a method to secure
proper coordination due to potential load increase on particular taps. Sectionalizers have not
been required in the past because fuses could be sized to obtain adequate coordination. The
use of fuses larger than 140T is not recommended because they will not coordinate properly
with the upstream overcurrent protection. Although three-phase electronic reclosers are
preferable, consideration for the use of sectionalizers is suggested because of the cost savings
associated with their use.
The main disadvantage of using sectionalizers instead of reclosers is that sectionalizers cannot
reclose. A fault downstream of a sectionalizer will cause the next upstream reclosing device to
operate, temporarily interrupting service to a larger portion of the distribution system; this allows
the sectionalizer to then interrupt. A sectionalizer can sense fault current and then isolate the
downstream circuit while the line is de -energized by the upstream device (substation
breaker/recloser). Isolation can occur at a selectable number (count) of operations by the
upstream device (normally one or two counts).
The Ashland distribution system consists of substation reclosers with reclosing relays. A fault
downstream of a sectionalizer would cause the overcurrent and reclosing relays at the
substation to operate, interrupting service to the entire feeder, rather than isolating the fault and
interrupting service to a small portion of the distribution system, which would occur if a line
recloser were applied instead of a sectionalizer. Sectionalizers, where applied, can provide a
significant advantage over the use of fuses because sectionalizers are much easier to
coordinate due to a selectable range of settings. No specific installations of these devices are
recommended at this time, but consideration of their use is suggested on major taps off feeder
backbone circuits as loads grow and at important underground taps which should not be
subjected to reclose operations. We recommend that prior to the installation of such devices
that actual tap current measurements be performed to ensure system loading has developed to
justify the use of sectionalizers for protection.
Pad Mounted Switchgear Protection for Underground Construction
Vacuum fault -interrupting pad -mounted load -break switchgear is presently in use on the
Ashland electric system. These devices are placed at important switching and sectionalizing
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-13
Panes 111 of 137
locations within the distribution system to allow service from alternate sources, and to allow fast
interruption of faulted 200-amp major tap segments to minimize affected customers.
These devices typically accept one or two sources (600 amp) and offer two or more interruptible
tap services (200 amp), although other configurations are available.
These devices lend themselves well to placement within existing underground systems and can
easily be programmed to coordinate with upstream fusing and substation protective devices.
They offer the following advantages:
• Alternate source service
• Source load -break switching
• Tap vacuum fault interruption — no need for fuses
• Immediate service restoration — no fuse replacement
• Electronic control settings consisting of the following features:
a. adjustable coordination trip settings
b. three-phase or single-phase trip selection
c. instantaneous trip availability
d. ground trip availability
e. completely dead -front construction
f. compliance with all Standards requirements
9.4 SUBSTATION PROTECTIVE DEVICE SETTINGS
The various protective equipment at the three substation facilities are described in this section.
This includes the protective devices serving as transformer protection equipment and
distribution protection equipment. The substation and switch station arrangements are shown on
one -line diagrams presented in Appendix D.
9.4.1 Substations
PacifiCorp Ashland Substation
The PacifiCorp Ashland Substation transformer is protected by a 115 W Circuit Switcher 2R154
with two electronic multifunction relays (TPU2000R and Basler BE1-51). The TPU2000R
provides transformer differential protection, while the BE1-51 relay provides overcurrent
protection for the transformers. On the 12.47 W side, PacifiCorp has two CO-9 relays for phase
and neutral overcurrent protection for the City circuit. The City of Ashland -owned switch rack
within the PacifiCorp Ashland Substation has four reclosers with Cooper Form 6 controllers.
These reclosers are programmed with 3 shots at intervals of 0.6-sec/2-sec/lockout. These
device settings are summarized below in Table 9-5 and Table 9-6.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 9-14
Pane 114 of 137
Table 9-5: Ashland Substation PacifiCorp Relay Settings, Existing
Device
Element
Pickup
Time Dial
Instantaneous
Delay
Curve
BEl-51
Backup Phase
3 (180 A at 115 kV)
15
15 (2700 A)
-
B6
Primary Phase
2.5 (150 A at 115 kV)
3.0
-
-
VI
OC
TPU2000
Primary Phase
5.8 (1392 A at 12.47 kV)
3.0
-
-
VI
Primary
Ground OC
5.0 (1200 A at 12.47 kV)
3.5
-
-
VI
WEST. CO-9
Phase OC
6 1200 A at 12.47 kV
2.0
-
-
CO-9
Ground OC
6 1200 A at 12.47 kV
2.0
-
-
CO-9
Table 9-6: Ashland Substation City Feeder Relay Settings, Existing
A2000, A2001, A2002, A2003
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Slow
560 A
1
0
---
117
Phase Fast
560 A
1
0
---
104
Phase HC
Disabled
---
--
---
---
round Slow
240 A
1
0
---
135
Ground Fast
240 A
1
0
---
106
Ground HCT
Disabled
Reclose
0.6-sec/5-sec4ockout
3-shot
Phase CLPU
560 A
2
0
—
117
round CLPU
1 240 A
2
0
---
135
Reclose CLPU
I 5-sec/lockout, Active time: 15 seconds
a) CLPU indicates Cold Load Pickup, which is used to prevent inadvertent trips from occurring during restoration after a sustained
outage
City Owned Mountain Avenue Substation
Mountain Avenue Substation originally owned by BPA, was purchased by the City of Ashland in
April, 2023. The City has not made any substation upgrades to date. The transformer protection
is adopted from BPA. Currently, the substation transformer is protected by a Circuit Breaker with
phase and neutral overcurrent relays, both of which are BE1-51. Each feeder recloser has a
Cooper Form 6 controller for monitoring and control. These reclosers are programmed with 3
shots at intervals of 0.6-sec/2-sec/lockout. Their settings are summarized in Table 9-7 and
Table 9-8.
There is no transformer differential relay for this substation transformer. We recommended the
City consider a protection relay upgrade at this substation. Additionally, the feeder controller
settings for feeder M3009 (Morton) appear to have the same fast, slow, and CLPU curves for
phase and ground protections, which are not consistent with the settings for other feeders. It
does not look like Morton feeder needs a unique protection scheme like this, so the existing
settings are questionable and may not have been programmed correctly when installed. If there
is no particular reason, we recommend the City update the settings for feeder M3009 to
maintain consistency.
Table 9-7: Mountain Avenue Substation Relay Settings, Existing
Device
Element
Pickup
Time Dial
Instantaneous
Delay
Curve
BEl-51
Phase OC
2.0 240 A at 115 kV
7
15 3600 A
-
B6
BE1-51
Neutral OC
2.0 240 A at 115 kV
52
-
-
B6
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-15
Pane 115 of 117
Table 9-8: Mountain Avenue Substation Feeder Relay Settings, Existing
M3006
M3012 M3015
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Slow
560 A
1
0
0.1
165
Phase Fast
560 A
1
0
---
103
Phase HCT
Disabled
---
---
---
---
round Slow
240 A
1
0
---
135
Ground Fast
240 A
1
0
---
106
Ground HCT
Disabled
---
---
---
---
Reclose
0.6-sec/2-sec/lockout 3-shot
Phase CLPU
560 A
2
0
0.3
165
Ground CLPU
240 A
2
0
0.3
135
Reclose CLPU
5-sec/lockout. Active time: 30 seconds
M3009
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Slow
560 A
1
0
---
133
Phase Fast
560 A
1
0
---
133
Phase HCT
Disabled
---
---
---
---
round Slow
240 A
1 1
0
---
133
round Fast
240 A
1
0
---
133
round HCT
Disabled
---
---
---
--
Reclose
0.6-sec/2-sec/lockout 3-shot
Phase CLPU
560 A
2
0
0.3
133
round CLPU
1 240 A
2
0 4-0.3
133
Reclose CLPU
I 5-sec/lockout Active time: 30 seconds
PacifiCorp Oak Knott Substation
The PacifiCorp Oak Knoll Substation transformer has two transformer banks with main and
auxiliary buses implemented. During normal configuration, breakers 5R55 and 5R56 (Feeder
K4056) are served from transformer bank #1, and breakers 5R70 and 5R93 (Feeders K4070
and K4090) are served from bank #2. Each transformer has a primary breaker controlled by a
primary SEL 387E relay and a backup BE1-51 relay. Each 12.47 kV feeder breaker is controlled
by a SEL 751 feeder protection relay. The City of Ashland -owned switch rack within the
PacifiCorp Oak Knoll Substation has three reclosers with Cooper Form 6 controllers. These
reclosers are programmed with 3 shots at intervals of 0.6-sec/2-sec/lockout.
These device settings are summarized below in Table 9-9 and Table 9-10.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 9-16
Panes 116 of 117
Table 9-9: Oak Knoll Substation PacifiCorp Relay Settings, Existing
Device
Element
Pickup
Time Dial
Instantaneous
Delay
Curve
BE1-51,
Bank 1
Backup Phase
OC
2.25 (180 A at 115 kV)
17
11.2 (2016 A)
-
B6
Primary Phase
OC
2.0 (160 A at 115 kV)
3.3
-
-
U3
SEL 387E,
Bank 1
Primary Phase
OC
5.8 (1392 A at 12.47 kV)
3.6
-
-
U3
Primary
Ground OC
2.0 (480 A at 12.47 kV)
13.4
-
-
U3
SEL751,
Phase OC
7 560 A at 12.47 kV
5.5
-
-
U4
5R56
Ground OC
3 240 A at 12.47 kV
8.3
-
-
U3
BE1-51,
Bank 2
Backup Phase
OC
2.25 (203 A at 115 kV)
16
12 (2430 A)
-
B6
SEL 387E,
Bank 2
Primary Phase
OC
2.2 (198 A at 115 kV)
3.1
-
-
U3
Primary Phase
OC
4.4 (1760 A at 12.47 kV)
6.8
-
-
U3
Primary
Ground OC
1.2 (480 A at 12.47 kV)
14.8
-
-
U3
SEL751,
Phase OC
7 560 A at 12.47 kV
5.5
-
-
U4
5R70
Ground OC
3 240 A at 12.47 kV
8.3
-
-
U3
SEL751,
Phase OC
7 560 A at 12.47 kV
5.5
-
-
U4
5R93
Ground OC
3 240 A at 12.47 kV
8.3
-
-
U3
Table 9-10: Oak Knoll Substation Feeder Relay Settings, Existing
K4056,
K4070, K4093
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Slow
560 A
1
0
---
117
Phase Fast
560 A
1
0
---
104
Phase HCT
Disabled
--
---
round Slow
240 A
1 1
0
---
135
Ground Fast
240 A
1
0
---
106
Ground HCT
Disabled
--
---
---
---
Reclose
0.6-sec/5-sec/lockout
3-shot
Phase CLPU
560 A
2
0
---
117
Ground CLPU
240 A
2
0
---
135
Reclose CLPU
5-sec/lockout, Active time: 15 seconds
9.5 FIELD RECLOSER AND VFI SWITCHGEAR SETTINGS
Ashland has ten (10) CPS/Eaton VFI switchgear sectionalizing devices, and three (3)
CPS/NOVA field reclosers with Cooper Form 6 controls. The ten VFls are listed below and most
of the protected ways are set at 200 A as a feeder tap using the Cooper EF curve, while a few
others serve smaller taps with lower settings.
Address
• 811 Briggs Ln
1299 Hagen Way
• 396 Randy St.
• 842 Kestrel PW
Map Location ID
E5043630
E5101731
E5057535
E5046550
Settings
Tap 1 60A, Tap 2 60A
Tap 1 20A, Tap 2 40A
Tap 1 40A, Tap 2 40A
Tap 1 100A, Tap 2 100A
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
9-17
Pane 117 of 137
• 2202 Abbott Ave
E5112300
Tap 1 vacant, Tap 2 200A
• 2200 Ashland St.
E5142827
Tap 1 vacant, Tap 2 200A
0 310 Kestrel PW
E5046603
Tap 1 200A, Tap 2 200A
• 955 E Nevada St.
E5048601
Tap 1 200A, Tap 2 20A
• 489 Russell St.
E5097835
Tap 1 200A, Tap 2
• 449 Rogue PI
E5046183
Tap 1 200A, Tap 2
Their field NOVA controller settings for the three filed reclosers are summarized in Table 9-11.
Table 9-11: Field Recloser Controller Settings, Existing
2"d and
B Street, Feeder A2002
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Slow
200 A
1
0
---
165
Phase HCT
Disabled
---
---
---
---
round Slow
150 A
1
0
---
133
Ground HCT
Disabled
---
Reclose
lockout 1-shot
Phase CLPU
450 A
1
0
1---
165
Ground CLPU
210 A
1
0
1---
133
Reclose CLPU
lockout 1-shot , Active time: 30 seconds
Iowa and Morton Street, Feeder M3009
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Slow
200 A
1
0
---
165
Phase HCT
Disabled
---
---
---
Ground Slow
150 A
1
0
---
133
Ground HCT
Disabled
--
__
___
---
Reclose
lockout 0-shot
Phase CLPU
450 A
1
0
---
165
Ground CLPU
210 A
1 1
0
---
133
Reclose CLPU
lockout 1-shot Active time: 30 seconds
Southern Orei
Ion University,
eederK4070
Device
Element
Pickup Prima
Time Dial
Time Adder
Min. Res . Time
Curve
Cooper F6
Phase Fast
300 A
1
0
---
117
Phase HCT
Disabled
--
---
---
---
round Fast
150 A
1
0
---
138
Ground HCT
Disabled
--I
---
---
---
Reclose
lockout 1-shot
Phase CLPU
450 A
1
0
---
117
Ground CLPU
225 A
1
0
---
138
Reclose CLPU
lockout 1-shot , Active time: 30 seconds
9.6 PROTECTIVE DEVICE COORDINATION CURVES
Explanation of Time -Current Curves
Coordination analysis was performed using EasyPower software due to the extensive library of
devices. EasyPower plots the time -current curve characteristics of the various system protective
devices (relays/recloser controllers/fuses) corresponding to their particular rating or setting and
identifies each device curve with a label. Other useful information is plotted on the diagrams to
assist in interpreting the results, such as:
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBEP 2024 9-18
Panes 11 R of 117
Transformer Full Load Current: Full -load current is calculated based on the power
transformer nominal self -cooled or "OA" rating. This value of current is plotted on the
time -current curve's upper horizontal axis as a short, vertical line, labeled "XFMR X
FLA".
Transformer Inrush Current: Inrush current usually ranges from 8 to 12 times the
power transformer full -load current, at 0.10 seconds. This value is plotted as a bullet and
labeled "XFMR X INRUSH." Protective devices upstream of the transformer must be set
to allow transformer inrush current to flow without the device tripping.
Transformer Damage Curves: ANSI Standard C57.109 specifies damage curves for
transformers. For delta-wye transformers, EasyPower plots a two-part curve based on
this ANSI standard. The upper part of the curve is the 100 percent damage curve for 3-
phase faults. The lower part of the curve, starting with the vertical -line portion and going
downward, is the 58 percent damage curve for phase -to -ground faults. The lower part of
the 58 percent curve shows the mechanical damage curve.
Conductor Damage Curves: Conductor damage curves are included to indicate
conductor annealing characteristics and are labeled with the size and material of the
conductor. Usually only the smallest conductors (lowest ampacity rating) in the portion of
the system selected for evaluation are shown, with larger conductors inherently having
much greater capacity.
Maximum Fault Current: For devices having interrupting ratings, such as fuses and
circuit reclosers and circuit breakers, the plot cuts off at the value for maximum total fault
at that bus location. This total fault current may in fact be higher than the actual
maximum current the device must interrupt if there is motor contribution to fault current
from the load side of the protective device. These values are plotted as a short vertical
line, 'tick' marks, along the TCC lower horizontal axis, labeled "DEVICE ID", and also
identify the available asymmetrical fault current, the current used to determine trip time.
Protective Device Pickup Current: All protective devices have a current pickup setting.
This value of current is identified on the time -current curve upper horizontal axis by
plotting a short, vertical line, labeled "DEVICE ID".
Time -Current Curve Plots
In an attempt to condense the quantity of coordination time -current curves, where possible,
multiple downstream components have been placed on the same time -current curve plot. To
eliminate redundancy, most often the largest downstream tap or transformer has been chosen
to evaluate system coordination, assuming less rated devices will inherently coordinate.
A 'phase' and 'ground' time -current curve plot has been prepared for each feeder, displaying the
existing device settings and ratings. Curves for each feeder are presented in Appendix A.
9.7 ANALYSIS OF EXISTING SETTINGS
The protective device coordination evaluation for the City's distribution system indicated that all
Ashland Substation feeder recloser control settings are identical, all the Oak Knoll Substation
feeder recloser control settings are identical, and three of the four Mountain Avenue Substation
feeder recloser controls have the same settings except for Feeder M3009. Most of the feeder
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-19
Pane 11A of 1.17
reclosers have a scheme of 1-fast and two -slow operations until the recloser locks out, while
Feeder M3009 has slow operations only based on the record settings. All feeder reclosers have
Cold Load Pickup (CLPU) enabled as well.
The multiple shot reclosing allows for different coordination curves to be applied with each
reclose attempt. In this case with a 1-fast and two -slow' scheme, it allows for fast downstream
"fuse -saving" operation to be applied before slower operation and longer open intervals are
applied ("fuse -clearing") to allow downstream fuses to clear permanent faults. This feature is
illustrated in almost all the TCCs for feeder protection.
CLPU is used to prevent inadvertent trips from occurring during restoration after a sustained
outage. Cold load is the `phenomenon where excessive currents are drawn by distribution loads
when restored after extended outages'. Sometimes it may be extremely difficult to reenergize
the circuits without causing protective devices to operate due to high inrush currents caused by
magnetizing currents to transformers, motor starting, capacitor charging currents, currents to
raise heating device temperatures, loss of load diversity, etc., at different time durations varying
from cycles to seconds. The inrush current can be more than 200% of the normal operating
current for approximately 2 seconds, with the magnitude of the inrush current mostly related to
load diversity. Typically, a 200% to 400% of full load for CLPU is considered reasonable but
could be low and cause relay mis-operation during service restoration. It can also be achieved
by manipulating the time multipliers for the protection curves.
Upon reviewing the TCCs in Appendix A, it appears that:
• The protection between substation relays and feeder recloser controllers coordinate.
Fast operation by reclosers can save major tap fuses during momentary faults.
• Field VFIs and field reclosers coordinate well with substation feeder reclosers.
• The large downstream fuses may not coordinate with the recloser control in the long-
time region, especially for ground protection, but the coordination in the short -time and
instantaneous regions is acceptable.
• Along Feeder K4093, the underground tap to Clay St. is protected by 140A fuses based
on the City's electrical map, while the downstream VFI at E2300 (Abbott Avenue)
appears to be set at 200 A. The coordination around the short -time and instantaneous
region between these devices appears to be reasonable, however, we recommend the
City consider adjusting these tap pickups from 200 A to 140 A or less.
9.8 CONCLUSIONS
This report evaluates Ashland's major protective device components and feeder main tap
coordination during normal configurations. No specific protective changes are recommended,
except feeder M3009 recloser settings as noted. However, other minor suggested
recommendations presented in this report should be reviewed and evaluated by Ashland on an
as -needed basis or as time allows such verification and subsequent modification.
• The City's electrical map system is missing fuse data in many locations. We recommend
the City verify installed fuses and complete the map data.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 9-20
Pane 1 gn of 137
Verify Feeder M3O09 recloser settings and adjust them to be identical with other
Mountain Avenue Substation feeder settings if inappropriate implementation is
confirmed.
• Due to the age of equipment, test all feeder recloser and switchgear devices on a 5-year
basis to verify working condition. All sectionalizing devices should be exercised to
ensure proper operation.
• As stated above, this review addresses major substation protection and backbone
feeder coordination during normal configurations. Most of the small feeder tap fuses
were not modeled as they are note expected to have coordination problems with
substation reclosers. If the City has any concerns about any taps off the backbone
feeder, a specific review can be done upon request.
SYSTEM PLANNING STUDY. CITY OF ASHLAND - SEPTEMBER 2024 9-21
Pane 191 of 137
Table 9-12: Type K Fuse Link Coordination Between EEl-NEMA Type K Fuse Links
Protecting Fuse
Protected Link Rating
Link Rating
(amperes)
8K
10K
12K
15K
20K
I 25K
I 30K
I 40K
50K
I 65K I
80K
I 100K
140K
200K
Maximum Fault Current At Which B Will Protect A (amperes)
6K
190
350
510
650
840
1060
1340
1700
2200
2800
3900
5800
9200
8K
210
440
650
840
1060
1340
1700
2200
2800
3900
5800
9200
10K
300
540
840
1060
1340
1700
2200
2800
3900
5800
9200
12K
320
710
1060
1340
1700
2200
2800
3900
5800
9200
15K
430
870
1340
1700
2200
2800
3900
5800
9200
20K
500
1100
1700
2200
2800
3900
5800
9200
25K
660
1350
2200
2800
3900
5800
9200
30K
850
1700
2800
3900
5800
9200
40K
1100
2200
3900
5800
9200
50K
1450
3500
5800
9200
65K
2400
5800
9200
80K
4500
9200
100K
2400
9100
140K
4000
This table shows maximum values of fault currents at which EEI-NEMAType K fuse links will coordinate with each other. The table is based on maximum -clearing time curves for
protecting links and 75 percent of minimum -melting time curves for protected links.
Cooper Power Systems Reference
SYSTEM PLANNING STUDY, CITY OFASHLAND — SEPTEMBER 2024 9-22
Panes 199 of 1.37
Table 9-13: Type T Fuse Link Coordination Between EEI-NEMA Type T Fuse Links
Protected Link Rating
Protecting Fuse Link
Rating (amperes)
8T
10T
12T
15T
I 20T
I 25T
I 30T
I 40T
I 50T
65T
I 80T
100T
140T
200T
Maximum Fault Current At Which B Will Protect A (amperes)
6T
350
680
920
1200
1500
2000
2540
3200
4100
5000
6100
9700
15200
8T
375
800
1200
1500
2000
2540
3200
4100
5000
6100
9700
15200
10T
530
1100
1500
2000
2640
3200
4100
5000
6100
9700
15200
12T
680
1280
2000
2640
3200
4100
5000
6100
9700
15200
15T
730
1700
2540
3200
4100
5000
6100
9700
15200
20T
990
2100
3200
4100
5000
6100
9700
15200
25T
1400
2600
4100
5000
6100
9700
15200
30T
1500
3100
5000
6100
9700
15200
40T
1700
3800
6100
9700
15200
50T
1750
4400
9700
15200
65T
2200
9700
15200
80T
7200
15200
100T
4000
13800
140T
7500
This table shows maximum values of fault currents at which EEI-NEMAType T fuse links will coordinate with each other, The table is based on maximum -clearing time curves for
protecting links and 75 percent of minimum -melting time curves for protected links.
Cooper Power Systems Reference
SYSTEM PLANNING STUDY, CITY OFASHLAND — SEPTEMBER 2024 9-23
Pane 191 of 117
Table 9-14: Distribution Transformer Fuse Protection
Suggested Primary Fusing for Distribution Transformers
Fuse Ratings Based on Use of EEANEMA Type "K" or "T" Fuse Links and High -Surge Type "H" Links
(Protection Between 200% and 300% of Rated Load)
Delta -Connected Primary
A A B
Fiqure A rlgurr, B
I
I
I
( N
I
I
A B C I A
Figure C I Figure D
WyrConneeted Prirnary
N N
A B A B C
Figure E Figure F
7200 Delta
7200/12470Y
7620/13200Y
12000 Delta
Transformer Size
Figures A and B
Figure C
Figures D, E and F
Figures D, E and F
Figures A and B
Figure C
(kVA)
Rated
Amps
Link
RatingAm
Rated
s
Link
RatingAmps
Rated
Link Rating
Rated AmpsRating
Link
Rated
Amps
Link
Rating
Rated
Amps
Link
Rating
3
.416
1 H
.722
1 H
.416
1 H
.394
1 H
.250
1 H
.432
1 H
5
.694
1 H
1.201
1 H
.694
1 H
.656
1 H
.417
1 H
.722
1 H
10
1.389
2H
2.4
5H
1.389
2H
1.312
2H
.833
1 H
1.44
2H
15
2.083
3H
3.61
5H
2.083
3H
1.97
3H
1.25
1 H
2.16
3H
25
3.47
5H
5.94
8
3.47
5H
3.28
5H
2.083
3H
3.61
5H
37.5
5.21
6
9.01
12
5.21
6
4.92
6
3.125
5H
5.42
6
50
6.94
8
12.01
15
6.94
8
6.56
8
4.17
6
7.22
10
75
10.42
12
18.05
25
10.42
12
9.84
12
6.25
8
10.8
12
100
13.89
15
24.0
30
13.89
15
13.12
15
8.33
10
14.44
15
167
23.2
30
40.1
50
23.2
25
21.8
25
13.87
15
23.8
30
250
34.73
40
59.4
80
34.73
40
32.8
40
20.83
25
36.1
50
333
46.3
50
80.2
100
46.3
50
43.7
50
27.75
30
47.5
65
500
69.4
80
120.1
140
69.4
80
65.6
80
41.67
60
72.2
80
Continued on the next page.
SYSTEM PLANNING STUDY. CITY OFASHLAND - SEPTEMBER 2024
9-24
Pane 194 of 137
Continued from the previous page.
Suggested Primary Fusing for Distribution Transformers
Fuse Ratings Based on Use of Type "N" Fuse Links and High -Surge Type "H" Links
(Protection Between 200% and 300% of Rated Load)
Transformer Size
(kVA)
7200 Delta
7200112470Y
7620113200Y
12000 Delta
Figures A and B
Figure C
Figures D, E and F
Figures D, E and F
Figures A and B
Figure C
Rated
Amps
Link
RatingAmps
Rated
Link
RatingAmps
Rated
Link Rating
Rated Amps
Link
Rating
Rated
Amps
Link
Rating
Rated
Amps
Link
Rating
3
.416
1 H
.722
1 H
.416
1 H
.394
1 H
.250
1 H
.432
1 H
5
.694
1 H
1.201
1 H
.694
1 H
.656
1 H
.417
1 H
.722
1 H
10
1.389
2H
2.4
5H
1.389
2H
1.312
2H
.833
1 H
1.44
2H
15
2.083
3H
3.61
5H
2.083
3H
1.97
3H
1.25
1 H
2.16
3H
25
3.47
5H
5.94
10
3.47
5H
3.28
5H
2.083
3H
3.61
5H
37.5
5.21
8
9.01
20
5.21
8
4.92
8
3.125
5H
5.42
8
50
6.94
10
12.01
20
6.94
10
6.56
10
4.17
8
7.22
15
75
10.42
20
18.05
30
10.42
20
9.84
20
6.25
10
10.8
20
100
13.89
20
24.0
40
13.89
20
13.12
20
8.33
15
14.44
20
167
23.2
40
40.1
60
23.2
40
21.8
30
13.87
20
23.8
40
250
34.73
50
59.4
100
34.73
50
32.8
50
20.83
30
36.1
60
333
46.3
60
80.2
150
46.3
60
43.7
60
27.75
40
47.5
85
500
69.4
100
120.1
150
69.4
100
65.6
100
41.67
60
72.2
100
Cooper Power Systems Reference
SYSTEM PLANNING STUDY. CITY OFRSHLAND - SEPTEMBER 2024 9-25
Panes 195 of 1.17
Table 9-15: ELF Fuse Electrical Ratings and Characteristics
Fuse Ratings
Cutout Rating
Continuous Current Ratings We
Minimum
Maximum
Maximum
Interrupting
Voltage
Current
Voltage BIL
elt
ear
Current (A rms
(W)
(A)
(W) (W)
25"C 40°C 55°C
1 t (A2 • s)
1 (A2 • s)
symmetrical)
6
8 7 6
520
4550
8
12 11 11
1150
6500
12
18 17 16
1150
7000
18
25 24 23
1350
8600
20
27 26 25
2000
11700
25
34 33 31
2900
17000
8.3
15 110
31000
30
43 41 39
4000
20000
40
50 48 46
8000
39000
50*
68 65 62
16000
65000
65*
78 75 71
20000
100000
80*
95 91 87
32000
150000
100*
120 114 109
46000
215000
a. For temperatures other than listed, a deratlon factor of 0.26% per °C can be applied.
" Multi -barrel design
"" 15 W, 125 kV BIL, 6 through 25 A (single barrel part numbers FAK44W6 through FAK44W25) and 30 through 50 A (double barrel part numbers FAK44W30P, AK44W40, and
FAK44W50) have been tested and approved for 17.2 kV application.
Table 9-16: ELF-LR Fuse Electrical Ratings and Characteristics
Fuse Ratings Mount Rating Continuous Current Ratings (A)' Minimum Maximum
Voltage Current Voltage Melt Clear Maximum Current Interrupting
*V) (A) NV) WC 400C 550C 12t W-S) In (A2 s) (A rms symmetrical)
6 7.2 8 7 6 520 4000 50,000
8 7.2 12 11 11 1150 5000 50,000
8.3/13.2 12 7.2 18 17 16 1150 5000 50.000
18 7.2 25 24 23 1350 8000 50.000
20 7.2 27 26 25 2000 10000 50,000
a. For temperatures other than listed, a deration factor of 0.26% per °C can be applied.
Cooper Power Systems Reference
SYSTEM PLANNING STUDY, CITY OFASHLAND — SEPTEMBER 2024 9-26
Panes 196 of 117
Table 9-17.• ELF Fuse Coordination Between EEANEMA Type K Fuse Links
Protecting ELF
fuse current
rating (A)
Protected K-Link
1s 20
current rating (A)
28
30
40
50
65
80
100
140
200
6
31000* 31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
8
31000* 31000*
31000*
31000`
31000*
31000*
31000*
31000*
31000*
31000*
31000*
12
55 90
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
18
- -
90
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
20
- -
70
130
31000*
31000*
31000*
31000*
31000*
31000*
31000*
25
- -
-
90
170
31000*
31000*
31000*
31000*
31000*
31000*
30
- -
-
-
130
385
31000*
31000*
31000*
31000*
31000*
40
- -
-
-
-
170
230
350
31000*
31000*
31000*
' 31,000 A at 8.3 W. 20,000 A at 15 W
Table 9-18: ELF Fuse Coordination Between EEl-NEMA Type T Fuse Links
Protecting ELF ProtectedTlink current rating (A)
fuse current
rating (A) 15 20 25 30 40 50 65 80
100
140
200
6
31000* 31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
8
31000* 31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
12
- 31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
18
- -
31000*
31000*
31000*
31000*
31000*
31000*
31000*
31000*
20
- -
-
-
31000*
31000*
31000*
31000*
31000*
31000*
31000*
25
- -
-
-
31000*
31000*
31000*
31000*
31000*
31000*
31000*
30
- -
-
-
-
31000*
31000*
31000*
31000*
31000*
31000*
40
- -
-
-
-
-
31000*
31000*
31000*
31000*
31000*
" 31,000 A at 8.3 W. 20,000 A at 15 W
Cooper Power Systems Reference
SYSTEM PLANNING STUDY, CITY OFASHLAND - SEPTEMBER 2024 9-27
Pane 197 of 137
Chapter 10 RENEWABLE ENERGY
10.1 GENERAL
In 2011, the City of Ashland initiated a Climate & Energy Action Plan (CEAP) with a vision to
reduce greenhouse gas emissions and improve the resilience of the environment, infrastructure,
and people from future impacts of climate change. The Goals of the plan are to:
Reduce overall Ashland community greenhouse gas emissions by 8% on average every
year to 2050
• Attain carbon neutrality in City operations by 2030, and reduce fossil fuel consumption
by 50% by 2030 and 100% by 2050
• Be ready for projected climate changes
The focus of the electric department planning study is to attempt to prepare the electrical
infrastructure for future demands and includes a review of the impacts of growth, weather, and
climate concerns. To align system planning with the City's CEAP this section will address the
following considerations:
• Recommendations for integration of the City's Climate and Energy Action Plan (CEAP)
and potential impacts on electrical infrastructure.
• Opportunities and barriers for adding renewable energy resources such as solar, wind,
and/or hydro power, etc.
• An assessment of the City's readiness to accommodate high adoption of Electric
Vehicles (EVs) and fuel -switching (natural gas reduction)
This chapter discusses the existing situations of the City's policy, program, load profiles, barriers
and challenges, and provides recommendations attempting to prepare the electrical
infrastructure for future demands and align system planning with the City's CEAP to the extent
possible.
10.2 CLIMATE & ENERGY ACTION PLAN (CEAP)
Initiated in 2011 and approved in 2017, the City's CEAP outlines a vision of collaboration in a
long-term effort to achieve the CEAP goals by following several different paths, including:
• Transition to clean energy
• Maximize water and energy efficiency and reuse
• Support climate -friendly land use and management
• Reduce consumption of carbon -intensive goods and services
• Inform and work with residents, organizations, and government
• Lead by example
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 10-1
Pane 198 of 137
10.3 TRANSITION TO CLEAN ENERGY
Using clean energy is one of the major paths in the City's CEAP, and the City plans to do the
following to increase the clean energy resources gradually.
10.3.1 Natural Gas Ban Or Fuel -Switching Policy
In 2023, the City of Ashland voted and decided to develop an ordinary ban on natural gas for
new residential development. Ashland became the third Oregon city to commit to developing a
policy to transition new homes off fossil fuels. Once passed, appliances for heating or cooking
would have to be all electric for new home construction. This is intended to reduce fossil fuel
consumption and greenhouse gas emissions. However, the increased use of electric appliances
will increase the electric load and is likely to have an impact on the City's electric systems.
For example, based on the discussion in Chapters 3, 5, and 7 the peak demand (including
PacifiCorp's load) in Ashland Substation during the 10-year historical peak in 2021 was about
94% of the transformer overload rating of 20 MVA. PacifiCorp typically uses 120% of the
nameplate rating as their guide for Winter capacity rating. However, the City of Ashland has a
Summer peak load pattern. The Ashland substation is very near capacity and may be under
capacity if extreme summer weather conditions occur. Load growth that affects peak conditions
can be expected to further stress the system. The increase in use of electrical appliances, as
well as the shift from traditional vehicles to EVs, is likely to further exacerbate the stress on
Ashland Substation.
PacifiCorp also has a feeder served out of its Ashland Substation with considerable load. We
recommend the City work with PacifiCorp to monitor this substation peak, especially during
peaking hours in summer and winter.
To address the potential overloading condition on Ashland Substation and allow for load growth
the achieve the CEAP goals, relocating feeder sections to Mountain Avenue Substation can
provide temporary relief but, for long-term planning, we recommend the City consider building a
City -owned substation next to the existing Ashland Substation with more capacity, control, and
reliability for both normal feeder switching configurations and emergency configurations with
feeder interconnections to other substations feeders. This will greatly improve the resilience of
the City's electric system.
10.3.2 Increase Renewable Energy Portfolio
According to the US Energy Information Administration, utility -scale electricity generation in the
United States is mainly from three fuel categories: fossil fuels, nuclear energy, and renewable
energy. Other utility -scale sources include non-biogenic municipal solid waste, batteries,
hydrogen, purchased steam, sulfur, tire -derived fuel, and other miscellaneous energy sources.
Fossil fuels involve coal, natural gas, petroleum, and other gases, while renewable energy
sources include wind, hydro, solar (photovoltaic and solar thermal), biomass (wood, landfill gas,
solid waste, and other biomass waste), and geothermal.
Figure 10-1 shows the recent electricity fuel mix profiles for the nation and Oregon in general.
Figure 10-2 shows the electricity fuel mix profile for the Bonneville Power Administration (BPA).
Using the 2021 data as an example for a horizontal comparison in Figure 10-3, BPA's electricity
fuel mix profile shows much more renewable sources than the percentage at the national and
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 10-2
Pane 19A of 137
State levels, specifically -85% for BPA vs. 50% for Oregon in average and 22.5% for the nation
in 2021.
r
4
sdw
Z
WA s
4-
Natural Gas 39.3%
Coal 19.4%
Q Nuclear 18%
Wind 10.1%
Hydro 5.8%
O Solar 4.7%
Biomass 0.9%
Petroleum 0.8%
Waste 0.6%
• Geothermal 0.4%
Figure 10-1: National (on the right) and Oregon (on the left) Electricity Fuel Mix, 2021 [Source:
https://www.oregon.gov/eneruy/energy-oregon/pages/electricity-mix-in-oregon.aspx. The available data on this
website is only up to 2021]
BPA Fuel Alix Percent Summarv. Calendar Year 2023.
Biomass and Waste
Geothermal
Small H-s•droelectric
Solar
Wind with RECs
Coal
Large Hydroelectric
Natural Gas
Nuclear
Non Specified purchases t
EL\1 purchases
Wind without RECs 3
0.000%
0.0%
0.0%
0%
0.000%
0.0%
0.0%
0%
0.853%
0.7%
0.8%
0%
0.000%
0.0%
0.0%
0%
0.000%
0.0%
0.0%
0%
0.000%
0.0%
0.0%
0%
83.652%
84.20,o
77.2%
-7.1%
0.000%
0.0%
0.0%
0%
10.894%
11.0%
11.3%
0%
3.982%
3.4%
10.1%
6.7%
0.000%
0.3%
0.2%
0%
0.619%
0.4%
0.4%
0%
Total 100% 100°%0
1) Non Specified purchases are purchases made from another system without knowledge of speck fuel type. Reporting agencies
in Washington assign their generic fuel mix to the BPA purchase amount based on their determination of the Northwest power
pool region resources_ This figure does not include amounts of power available to BPA through participation in the EIM.
2) BPA joined the Western Energy Imbalance Market (EIM) in May 2022.
3) BPA conveys its RECs. to other parties and does not retire them.
Figure 10-2: BPA Fule Mix Summary in 2021, 202Z and 2023
[Source: httpsJlwww.bpa.govl--/medialAeplpowerlfuel-mixl2022-bpa-fuel-mix.pdf,
https://www. bpa. govl--/media/Aep/power/fuel-mix/2023-b pa -fuel -mix. pdf]
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
10-3
Pane 130 of 117
90.0%
80.0%
70.0%
60.0%
50.0%
40.0%
30.0%
0.0% 1
0.0%
0.0%
NaturatGas coal Nuclear Wind
■ US ■ Oregon ■BPA or Ashland
01im- --- - ___ - M
Hydro Solar Biomass Petroleum Waste Geothermal Non
Specufied
Figure 10-3: Electricity Resource Profile Comparison Between The Nation, Oregon, and BPA/Ashland, 2021
At the time of this study, the City of Ashland is a full -requirements customer of BPA and BPA
provides all of the electricity purchased by the City. Therefore, the City's fuel mix is mainly
determined by BPA's energy fuel mix. As a result, the City of Ashland's renewable energy
portfolio was approximately 85% in 2021 and 78% in 2023 for energy imported from BPA. The
actual percentage for the City will be slightly higher due to the small hydro and accumulated
small commercial and residential PV generation in the City's electric system. Also note that 11 %
of BPA portfolio is from nuclear power generation. Therefore, only 5% to 10% of the energy
purchased by the City is from potential greenhouse gas emitting production.
The annual percentage of renewable energy resources changes depending on weather,
reservoir storage, and other factors. For example, hydro generation dropped 7.1 % in 2023
compared to 2022, which affects Ashland's electricity fuel mix. If the BPA energy fuel mix profile
is not completely renewable, Ashland's fuel mix will be similar due to the BPA power import
dependency.
The City of Ashland can buy additional renewable resources from the open market and have
that energy wheeled through BPA's transmission network. That energy could be used to offset
the non-renewable energy in the BPA profile. The actual energy delivered by BPA would of
course still have the same energy mix but, by offsetting the amount of non-renewable energy
that would have been delivered, the City would effectively be 100% greenhouse gas free.
Adding residential, commercial, and community -level renewable energy resources such as solar
energy, small hydro, and other types has a similar impact in terms of the renewable energy
portfolio. Even though they are mostly small-scale, they are within or near the City's network
and do not need transmission wheeling services, which might be more cost-effective.
Solar Energy (Photovoltaic)
The City of Ashland started community and commercial solar projects in 2000. Figure 10-4
shows the annual installation capacity profile between 2000 and 2017. Based on the latest
information available the total installed commercial solar is about 1.28 MW, and the total
installed residential solar is about 3.82 MW. That is overall 5.1 MW of nameplate capacity. The
expected summer peak output is about 3.5 to 4 MW assuming fixed axis stands, modern PV
panel ratings, and Ashland's solar irradiance profile.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024
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For solar energy (or other renewables) less than or equal to 25 kW, there are generally no
barriers or issues with installation as long as they meet NEC and the City's metering and
installation requirements. For solar energy (or other renewables) greater than 25 kW and less
than 200 kW, depending on the location and total installed capacity versus available capacity,
prior consultation and approval by the City are required and generally engineering studies are
required to ensure voltage stability, service reliability, and no transmission export. The City,
State, and Federal Government have various incentive programs for these levels of solar
projects.
A system definition of 'Large' is relative to where the generation is connected. For distribution
level connections, large is greater than 200 W. BPA's standard classifies as a small generation
resource when a single or combined generating capacity is greater than 0.2 MW and equal to or
less than 20 MW. This is primarily a function of transmission connection. Post-2028 BPA
contracts under discussion with the City would allow the City to develop a single combined
generation capacity of up to 5 MW. However, the City has no transmission resources as the
City's electric infrastructure is distribution only. Interconnection of large PV generation requires
Feasibility, Impact, and Facility studies on the feeder level, substation level, and transmission
level by both the City and transmission provider (BPA or PacifiCorp in this case).
Ron
Annual Renewable F—gy Installed in Ashland Since 2000
Residental Commercial Community
2000 2001 2002 2003 2004 2005 2006 2007 2rO8 2009 2010 2011 2012 2013 201A 2015 2016 2017
Year
Figure 10-4: Installed Solar Energy Capacity (Watts) In Ashland Since 2000
Hydro Power
The City of Ashland has an existing small hydro generation, Reeder Gulch Hydroelectric (RGH)
at Hosler Dam, which has an 845 kVA generator with its power output limited by penstock and
water demand. According to the City's SCADA system, this unit is outputting -250 kW of power
continuously during normal conditions.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEA48ER 2024 10-5
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Adding additional generators is not feasible but the existing unit is capable of higher output.
Upgrades to the turbine and/or needle valves would allow for an increase in output closer to the
generator nameplate. Additional capacity improvements can be achieved by modifying the
penstock but would likely be at a much higher cost. In any case, the Reeder Gulch Hydro is a
significant renewable energy resource that is already owned and operated by the City and
should be utilized at maximum capacity. We also note that the capacity factor of the Reeder
Gulch Hydro is significantly higher than PV systems are capable of due to the ability to run 24
hours a day, dependent only on water resources. Therefore, to achieve the same energy output
a much larger PV system would be required.
Other Resources
Other potential renewable resources include biomass, biogas, geothermal, and wind. These do
not necessarily need to be within the City's electric service territory and can be in the nearby
region. For example:
• Potential biomass plant expansion in the Rogue Valley and potential biomass cogen
plant project at Southern Oregon University.
• Methane gas from food waste, yard waste, and manure that can be used to generate
electricity or as a vehicle fuel.
• Geothermal for power generation (e.g., geothermal plant in Oregon Institute of
Technology OIT campus, about 2 MW) or direct use for heating
• County -level collaborative efforts in wind energy
When these potential resources are considered, similar interconnection studies are required to
evaluate the feasibility, impact, required system upgrades, and associated budget for
construction and future maintenance.
10.3.3 Electric Vehicle (EV)
The use of EVs has increased steadily over the past 10 years as the technology matures and
more charging stations are available. EVs have the potential to meet transportation needs and
be part of the clean energy future. According to Oregon.gov, the total number of registered
electric vehicles in Oregon as of July 2023 was 74,427. The City of Ashland (Zip Code: 97520)
had approximately 900 in July 2023. EV growth over the past three years has averaged about
150 vehicles a year and is likely to continue near that rate or faster, depending on available
vehicles, charging infrastructure, and government incentives. As such, the City can expect to at
least double EV use in the next 5 to 6 years in Ashland depending on regulating & incentive
policies and supply chain considerations.
EVs are an important part of the City of Ashland's CEAP. The City has various incentive
programs for EVs, E-Bikes, chargers, etc. The City currently has approximately 4,590
households with an average car ownership of two per household. For planning purposes, if the
City is able to sufficiently incentivize EV use such that there is an average of one EV per
household along with the 0.63% growth rate discussed in Section 3, the City could see as many
as 5000 EVs in use in 10 years.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 10-6
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EV Increase
300
2'/1
200
ISO
100
so
70
13 ZpIS ?11
17 .11* zpll Z073
Total EV
G00
400
200
0
jpll
70
11
7p1S
7p1 j
7p19
7p71
7p73
Figure 10-5: Annual EV Increase and Accumulated Total From 2000 to 2023 [Source:
https://www.orepon.gov/energy/Data-and-Reports/Pages/Oregon-Electric-Vehicle-Dashboard.aspx. The above
statistic data stops in December 20231
Currently, the City has and/or plans to install the following charging stations:
• 16 City -owned, Level 2 chargers [Public access]
• 24 Tesla superchargers [Public access]
• 11 City -owned Level 2 chargers at the service center;
• Plan to add six more Level 2 and two Level 3 chargers at the service center
• Plan to add 20 more City -owned Level 2 public chargers in 2024 [Public access]
• Southern Oregon University has14 level 2 EV chargers on campus [Public access]
Table 10-1: Typical EV Charger Profile
Charger
Typical Output
Estimated Charging Time
Estimated Range
User Case
Type
Power
(40 kWh)
per Hour
Level 1
1 —1.8 kW
22 — 40 hours
3 — Jr rr les/hour
Home / Backup
Level 2
3 — 22 kW
2 — 13 hours
10 — 75 miles/hour
Work / Hotel / Public chargers
Level 3
30 — 360 kW
15 mins — 1.5 hours
120 —1400
Fleets / Dealer / Hwy service /
miles/hour
Supercharger
Different chargers have various performance and power requirements as outlined in
Table 10-1. Besides the clean energy feature of EVs, increased EV brings the following
challenges:
• Increase power demand. EV charging requires a significant amount of electricity,
especially during peak charging periods. This increased demand can strain the existing
electric system infrastructure, leading to potential issues such as voltage fluctuations
and load imbalances.
o Uncontrolled charging increases the system peak demand. For about 1000 EVs
(Figure 10-5), assuming each has a charger. 70% of the chargers are Level 1,
-1.5 kW, 30% are Level 2, --15 kW, uncontrolled charging, and a diversity factor
of 2.5 (40% are in use concurrently), The estimated total kW increase during the
charging hours is about 2.2 MW. Without diversifying the total estimated peak is
about 5.5 MW.
SYSTEM PLANNING STUDY, CITY OF ASHLAND — SEPTEMBER 2024 10-7
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o Smart charging technology or algorithms including delayed charging, controlled
charging, demand response, or using a dynamic rate structure to reshape the
load curve (aka. peak shift or shaving). These technologies or algorithms are
common in some of the public utilities in California. As EV counts increase, we
recommend the City monitor the daily feeder load pattern/shape and implement
associate alerts or flags. A smart charging policy/program may be needed and
should be discussed before the EV load profile becomes a concern.
Potential equipment overload. Simultaneous charging during peak times can overload
local transformers and distribution circuits, which can result in power outages or require
expensive infrastructure upgrades to meet the growing demand.
• Capital Cost from infrastructure upgrades.
Distribution transformers have to be sized with future EV additions. We recommend the
City consider the future of Electric Vehicle (EV) impact on the distribution facilities by
increasing transformer capacity in new developments. An estimated 5 kW per resident
should be allocated when sizing new transformers. The EV charger minimal use time will
impact transformer energy losses which must be paid for by the serving utility (City of
Ashland) and will likely impact future electric rates.
Other costs can be technology upgrades for smart charging based on demand response.
The impact of increased EV use in the City over the next 10 years will affect the City peak
demand and total energy consumption. However, the impact on peak demand is difficult to
predict as the charger technologies mature and the City may be able to take steps, such as
regulating smart charging, to help reduce coincident charging load. Based on information from
the Department of Transportation, Energy consumption can be estimated to be —11.81 kW-hrs
per day per EV. With an increase in vehicle count of 4000 EVs over the next 10 years, the total
energy consumption increase can be estimated to be about 17,242 MWh per year. That is an
increase of —10% in energy consumption based on the average yearly totals over the past 10
years.
As a rough estimate of peak demand impact, we can assume —70% Level 1 charging and —30%
Level 2 charging with power requirements of 1.5 kW and 15 kW respectively. With a diversity
factor (ratio of sum of non -coincident maximum load to coincident peak) of 2.5 the estimated
peak demand for EV charging can be estimated to be —8.9 MW. If that peak occurs coincident
with the existing summer peak, and with the estimated peak demand increase from growth
outlined in Section 5, the City could see peak demand in excess of 58 MW within a 10-year
period without using any smart charging technology or algorithms to shave or shift the peak.
10.4 DISCUSSION AND RECOMMENDATIONS
The City's goal of developing an electric energy usage that is 100% from non -fossil fuel
resources can be achieved using several approaches. The primary methods for eliminating non-
renewable energy from the City's use can be summarized as follows:
1. Reduce energy consumption. This approach can be used to reduce non-renewable
consumption but cannot fully eliminate it. The City can expect an increase in
consumption as EV numbers increase and the City's initiatives to electrify appliances
that could alternatively utilize natural gas or other non-renewable resources will shift the
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burden of non-renewable reduction to the electric system. However, any reduction in
non-renewable energy consumption will put the City closer to achieving the 100% goal.
2. Add additional renewable generation to the City's system. This can be achieved by
continuing to support community projects to add distributed generation resources. The
City's current community 1 MW project will certainly support this approach. However, the
City does not own transmission resources and has limited siting available for large-scale
PV generation.
3. Purchase renewable energy from an outside provider and have it wheeled to the
City. This option would typically involve identifying a renewable generation provider that
would establish a power purchase agreement with the City and establishing a wheeling
agreement with BPA and/or PacifiCorp. This requires the least amount of infrastructure
changes to the City but would ultimately result in higher rates to consumers.
The first option can be achieved by developing programs to incentivize energy efficiency
improvements and energy use reductions. A community program focused on energy efficiency
and consumption reduction could include:
• Building audits and retrofits to HVAC equipment, lighting equipment, insulation systems,
and appliances.
• Community awareness programs advocating good use habits including
o Fully disconnecting charging devices and switching off standby equipment.
o Draught -proofing windows and doors.
o Turning off or reducing lights.
o Reducing and/or consolidating washing.
o Avoiding tumble drying.
o Shorter shower durations and showers in lieu of baths.
o Adjusting heating and cooling setpoints to reduce cycling
• Community program to provide rebates for energy efficiency improvements
The improvements from the energy efficiency program have the highest effectiveness in
reducing non-renewable energy consumption.
The City and community -owned renewable generation resources directly create energy that
offsets non-renewable resources. As stated above, large-scale generation projects are not likely
to be feasible in the area without connecting directly to transmission. However, the City
purchases all electric energy from BPA, the majority of which comes from the hydroelectric
facilities in the BPA territory. As such, BPA's energy fuel mix is generally 78% to 85%
renewable and an additional 11 % non -greenhouse gas producing nuclear. Therefore, only 5%
to 10% of the energy purchased by Ashland is potentially greenhouse gas producing. Ashland's
energy consumption is typically on the order of 180,000 MWh per year. One approach the City
might consider taking to achieve 100% greenhouse gas -free energy use is simply to identify
enough renewable energy such that it offsets 5% to 10% of what would have been required to
be purchased from BPA. Therefore, a reasonable target for directly procuring or generating
renewable energy would be between 9,000 MWh and 18,000 MWh per year.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEA48ER 2024 10-9
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Currently, the installed commercial and residential PV capacity in the City is about 4 MW. The
planned community 1 MW PV development would increase that capacity to 5 MW. In estimated
effective capacity factor for PV in Southern Oregon is between 20% and 25%. At 20% the
current and planned PV systems can be expected to produce --9,000 MWh per year. The hydro
output averages -250 kW resulting in a total yearly production of about -2,200 MWh. As stated
above, we recommend the City work to increase hydro production which could improve the
energy contribution.
The City's total renewable energy production, with the planned 1 MW PV system, is about
11,200 MWh per year. To fully offset the -18,000 MWh of energy from greenhouse gas emitting
processes the City will need to produce and/or procure an additional -8,000 MWh of clean
energy. Assuming a 20% capacity factor, the City would need an additional 4.6 MW of installed
PV capacity or some other suitable clean energy source. The current growth trend in residential
and commercial installed facilities will help reach the needed capacity. As discussed earlier in
this report, we are recommending the Ashland Substation be expanded to a new City -owned
substation to increase capacity and reliability. If a suitable site near Oak Street can be identified,
adding a large PV system to the new substation development would be an option for adding the
needed capacity.
The third option is a viable option for adding additional renewable energy to the City's profile but
the cost of energy would be considerably higher than the rates the City currently pays. Unlike
renewable development programs, we are not aware of any grant or incentive programs to
offset the cost increases from wheeling energy directly from renewable power produce.
SYSTEM PLANNING STUDY, CITY OF ASHLAND - SEPTEMBER 2024 10-10
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