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1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
December 15, 2020
VIA ELECTRONIC DELIVERY
Ms. Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83714
Re: PAC-E-04-07 2019 Service Quality & Customer Guarantee Report for the period
January 1 through June 30, 2020
Dear Ms. Noriyuki:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the Service Quality
& Customer Guarantee report covering January 1 through June 30, 2020. This report is provided
pursuant to a merger commitment made during the PacifiCorp and ScottishPower1 merger. The
Company committed to implement a five-year Service Standards and Customer Guarantees
program. The purposes behind these programs were to improve service to customers and to
emphasize to employees that customer service is a top priority. Towards the end of the five-year
merger commitment the Company filed an application2 with the Commission requesting
authorization to extend these programs.
If there are any additional questions regarding this report please contact Ted Weston at (801) 220-
2963.
Sincerely,
Joelle Steward
Vice President, Regulation
Enclosures
cc: Terri Carlock
1 Case No. PAC-E-99-01.
2 Case No. PAC-E-04-07.
RECEIVED
2020December 15, PM 1:56
IDAHO PUBLIC
UTILITIES COMMISSION
IDAHO
SERVICE QUALITY
REVIEW
January 1 – June 30, 2020
Report
IDAHO
Service Quality Review
January – June 2020
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Table of Contents
Table of Contents ......................................................................................................................................... 2
Executive Summary ...................................................................................................................................... 3
1 Reliability Performance ......................................................................................................................... 4
1.1 System Average Interruption Duration Index (SAIDI) ..................................................................................................... 4
1.2 System Average Interruption Frequency Index (SAIFI) ................................................................................................... 5
1.3 Major and Significant Events .......................................................................................................................................... 6
1.4 Restore Service to 80% of Customers within 3 Hours .................................................................................................... 7
2 Reliability History ................................................................................................................................... 8
2.1 Idaho Reliability Historical Performance ......................................................................................................................... 8
2.2 Controllable, Non-Controllable and Underlying Performance Review ........................................................................... 9
2.3 Underlying Cause Analysis Table .................................................................................................................................. 11
2.4 Cause Category Analysis Charts .................................................................................................................................... 12
3 Reliability Improvement Process ......................................................................................................... 13
3.1 Reliability Work Plans ................................................................................................................................................... 13
3.2 Project Approvals by District ......................................................................................................................................... 13
4 Customer Response ............................................................................................................................. 15
4.1 Telephone Service and Response to Commission Complaints ..................................................................................... 15
4.2 Customer Guarantees Program Status ......................................................................................................................... 15
5 Service Standards Program Summary ................................................................................................. 16
5.1 Idaho Customer Guarantees ......................................................................................................................................... 16
5.2 Idaho Performance Standards ...................................................................................................................................... 17
5.3 Cause Code Analysis...................................................................................................................................................... 18
5.4 Reliability Definitions .................................................................................................................................................... 19
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Executive Summary
Rocky Mountain Power developed its Customer Service Standards and Service Quality Measures in 1999. The
Company developed the program by benchmarking its performance against relevant industry reliability and
customer service standards. In some cases, Rocky Mountain Power has expanded upon these Standards. In other
cases (largely where the industry has no established standard) Rocky Mountain Power developed its own metrics,
targets and reporting methods. The Standards guide and reaffirm the importance of customer service both external
and internally.
The Company distinguishes between non-controllable outages (e.g. lightning; vehicle collisions) and controllable
outages (e.g. animal interference; equipment failure) and takes cost-effective steps to minimize both. As part of
the Company’s Performance Standards Program, it annually evaluates individual electrical circuits to focus on those
that have the most frequent interruptions. These are targeted for improvement, which is generally completed
within two years.
For the period January to June 2020, results of network performance as measured by System Average Interruption
Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) in Idaho is unfavorable to the
Company’s plan. Rocky Mountain Power strives to deliver reliable service to its customers in Idaho. In response to
the declining performance for the first half of the year, the Company is outlining a resiliency plan focused on
addressing transmission and substation issues impacting its customers. This is in addition to previously identified
multi-year projects already scoped and under construction.
Our goal continues to be supplying safe, reliable power to Idaho. We are dedicated to learning from our past service
experiences and continuing to make improvements to our operations and customer service to ensure we meet
Idaho’s needs.
Below is a summary of our mid-year 2020 performance serving the customers of Idaho.
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1 Reliability Performance
For the reporting period, the Company experienced underlying interruption duration (SAIDI) and interruption
frequency (SAIFI) performance in Idaho that was favorable to plan. Results for Idaho underlying performance can
be seen in subsections 1.1 and 1.2 below. For the period January to June 2020, results of network performance as
measured by System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency
Index (SAIFI) in Idaho is unfavorable to the Company’s plan. Rocky Mountain Power strives to deliver reliable
service to its customers in Idaho. Transmission outages continue to cause a significant impact to the customers in
Idaho, especially for SAIFI. These outages have a greater tendency to reach the established Major Event thresholds
and make up a majority of significant event days. In response to the declining performance for the first half of the
year, the Company is outlining a resiliency plan focused on addressing transmission and substation issues impacting
its customers in Idaho. This is in addition to previously identified multi-year projects already scoped and under
construction.
1.1 System Average Interruption Duration Index (SAIDI)
The Company’s underlying interruption duration performance mid-year 2020 is unfavorable to plan.
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SAIDI
(reporting period)
(year-end)
Total (major event included)
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1.2 System Average Interruption Frequency Index (SAIFI)
The Company’s underlying interruption frequency performance results for the year are favorable to plan.
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SAIFI
(reporting period)
(year-end)
Total (major event included)
(major event included)
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1.3 Major and Significant Events
Major Event General Descriptions
Two events during the reporting period met the Company’s Idaho major event threshold level0F
1 for exclusion
from underlying performance results.
Major Events
Date Cause SAIDI
Loss of Substation 38.9
Loss of Transmission Line 14.3
• January 23, 2020
Rocky Mountain Power customers in Rigby and Rexburg, Idaho, experienced a loss of substation event. At
10:44 PM, a circuit breaker at Rigby Substation had an internal phase-to-phase fault and locked out the
69kV bus at the Rigby Substation. The event affected 15 substations and 30,356 customers.
• June 22, 2020
On the morning of June 22, 2020, Rocky Mountain Power customers in Shelley, Idaho experienced a loss
of transmission line event. At 9:03 AM, a circuit breaker at Sugarmill Substation opened due to a line fault
approximately 0.5 miles past Sandcreek Substation. During recloser and sectionalizing operation, switch
75A at Sandcreek Substation flashed over causing the circuit breaker at Sugarmill Substation to lock out.
This outage de-energized the transmission line serving Sandcreek and Ammon Substations. This outage
impacted 15,186 customers in the Shelley area. This line has been in a non-standard configuration as the
route from Goshen to Ammon is being rebuilt to 161 kV construction which limits restoration capability
until Goshen projects are completed.
1 A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value (Reliability Standard IEEE 1366-2012) based
on the 2.5 beta methodology. The values used for the reporting period are shown below: Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost 1/1-12/31/2020 82,079 15.09 1,238,872
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Significant Events
Significant event days add substantially to year-on-year cumulative performance results; fewer significant event
days generally result in better reliability for the reporting period, while more significant event days generally
means poorer reliability results. During the reporting period seven significant event days1F
2 were recorded, which
account for 48.2 SAIDI minutes, about 60 percent of the reporting period’s underlying 81 SAIDI minutes. The
Company has recognized that these significant days have caused a negative impact to performance, and that
they have been generally attributable to events within the transmission system. The Company has recognized
transmission system reliability risks previously and continues on-going improvement plans.
1.4 Restore Service to 80% of Customers within 3 Hours
RESTORATIONS WITHIN 3 HOURS
Reporting Period Cumulative = 96%
January February March April May June
89% 100% 100% 95% 98% 98%
2 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results.
Significant Event Days
Date Cause: General Description Underlying
SAIDI
Underlying
SAIFI Underlying Underlying
April 11, 2020 Loss of Transmission Line 3.5 0.043 4.3% 3.5%
April 20, 2020 Vehicle Accident and Loss of Substation 3.5 0.026 4.3% 2.1%
May 4, 2020 Loss of Transmission Line – Failed
Transformer Arrestor 4.7 0.013 5.8% 1.0%
May 6, 2020 Weather – Strong Winds 4.7 0.030 5.8% 2.4%
May 28, 2020 Loss of Transmission – Switching Error 12.0 0.666 14.8% 53.4%
June 6, 2020 Weather – Strong Winds 1.8 0.014 2.2% 1.1%
June 27, 2020 Weather – Wind and Lightning 4.9 0.023 6.1% 1.8%
TOTAL 48.2 0.997 59.5% 79.9%
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2 Reliability History
Depicted below is the history of reliability in Idaho. In 2002, the Company implemented an automated outage
management system which provided the background information from which to engineer solutions for improved
performance. Since the development of this foundational information, the Company has been in a position to
improve performance, both in underlying and in extreme weather conditions. These improvements have included:
the application of geospatial tools to analyze reliability, development of web-based notifications when devices
operate more than optimal, focus on operational responses via CAIDI metric analysis, and feeder hardening
programs when specific feeders have significantly impacted reliability performance.
2.1 Idaho Reliability Historical Performance
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2.2 Controllable, Non-Controllable and Underlying Performance Review
In 2008, the Company introduced a further categorization of outage causes, which it subsequently used to
develop improvement programs as developed by engineering resources. This categorization was titled
Controllable Distribution Outages and recognized that certain types of outages can be cost-effectively avoided.
As an example, animal-caused or equipment failure interruptions have a less random nature than lightning
caused interruptions; other causes have also been determined and are specified in Section 2.3. Engineers can
develop plans to mitigate against controllable distribution outages and provide better future reliability at the
lowest possible cost. At that time, there was concern that the Company would lose focus on non-controllable
outages2F
3. In order to provide insight into the response and history for those outages, the charts below
distinguish amongst the outage groupings.
The graphic history demonstrates controllable, non-controllable, and underlying performance on a rolling 365-
day basis. Analysis of the trends displayed in the charts below shows a general improving trend for all charts. In
order to also focus on non-controllable outages, the Company has continued to improve its resilience to extreme
weather using such programs as its visual assurance program to evaluate facility condition. It also has undertaken
efforts to establish impacts of loss of supply events on its customers and deliver appropriate improvements when
identified. It uses its web-based notification tool for alerting field engineering and operational resources when
devices have exceeded performance thresholds in order to react as quickly as possible to trends in declining
reliability. These notifications are conducted regardless of whether the outage cause was controllable or not.
3 3. The Company shall provide, as an appendix to its Service Quality Review reports, information regarding non-controllable outages, including, when applicable, descriptions of efforts made by the Company to improve service quality and reliability for causes the Company has identified as not controllable. 4. The Company shall provide a supplemental filing, within 90 days, consisting of a process for measuring performance and improvements for the non-controllable events.
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2.3 Underlying Cause Analysis Table
The table and charts below show the total customer minutes lost by cause and the total sustained interruptions
by cause. The Underlying cause analysis table includes prearranged outages (Customer Requested and Customer
Notice Given line items) with subtotals for their inclusion, while the grand totals in the table exclude these
prearranged outages so that grand totals align with reported SAIDI and SAIFI metrics for the period.
Idaho Cause Analysis - Underlying 1/1/2020 - 6/30/2020
Direct Cause Minutes Lost for Incident Incident SAIDI SAIFI
ANIMALS 17,903 235 54 0.21 0.003
BIRD MORTALITY (NON-PROTECTED SPECIES) 5,053 93 15 0.06 0.001
BIRD MORTALITY (PROTECTED SPECIES) (BMTS) 24,294 63 9 0.29 0.001
BIRD NEST (BMTS) 4,013 25 8 0.05 0.000
BIRD SUSPECTED, NO MORTALITY 48,337 718 22 0.58 0.009
CONTAMINATION 254 4 2 0.00 0.000
FIRE/SMOKE (NOT DUE TO FAULTS) 501 3 2 0.01 0.000
B/O EQUIPMENT 317,114 2,897 95 3.80 0.035
DETERIORATION OR ROTTING 848,259 5,286 313 10.17 0.063
OVERLOAD 116 1 1 0.00 0.000
POLE FIRE 274,211 1,922 22 3.29 0.023
RELAYS, BREAKERS, SWITCHES 0 - 7 - -
STRUCTURES, INSULATORS, CONDUCTOR 790 4 5 0.01 0.000
DIG-IN (NON-PACIFICORP PERSONNEL) 27,747 225 7 0.33 0.003
OTHER INTERFERING OBJECT 34,066 152 13 0.41 0.002
OTHER UTILITY/CONTRACTOR 49,256 124 3 0.59 0.001
VEHICLE ACCIDENT 398,052 4,033 27 4.77 0.048 509,122 4,534 50 6.10 0.054
LOSS OF FEED FROM SUPPLIER 61,906 781 4 0.74 0.009
LOSS OF SUBSTATION 147,109 5,509 24 1.76 0.066
LOSS OF TRANSMISSION LINE 2,287,847 64,375 126 27.43 0.772
OTHER, KNOWN CAUSE 2,633 21 17 0.03 0.000
UNKNOWN 240,981 3,484 105 2.89 0.042
CONSTRUCTION 2,050 28 5 0.02 0.000
CUSTOMER NOTICE GIVEN 994,039 5,710 90 11.92 0.068
CUSTOMER REQUESTED 92 3 3 0.00 0.000
EMERGENCY DAMAGE REPAIR 277,388 3,439 65 3.33 0.041
INTENTIONAL TO CLEAR TROUBLE 91,575 691 7 1.10 0.008
PLANNED NOTICE EXEMPT 9,236 161 3 0.11 0.002
1,374,381 10,032 173 16.48 0.120
TREE - NON-PREVENTABLE 399,600 2,386 58 4.79 0.029
TREE - TRIMMABLE 6,700 43 8 0.08 0.001
ICE 6,086 56 7 0.07 0.001
LIGHTNING 200,665 1,546 30 2.41 0.019
SNOW, SLEET AND BLIZZARD 27,843 156 21 0.33 0.002
WIND 888,397 3,954 88 10.65 0.047
Note: Direct Causes are not listed if there were no outages classified within the cause during the reporting period.
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2.4 Cause Category Analysis Charts
The charts show each cause category’s role in performance results and illustrate that certain types of outages
account for a high amount of customer minutes lost but are infrequent, while others tend to be more frequent
but account for few customer minutes lost.
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3 Reliability Improvement Process
Over the past decade the Company has developed approaches, including tools, automated and manual processes
and methods to improve reliability. As it has done so, the Company’s ability to diagnose portions of the system
requiring improvement has improved, which yields its legacy “Worst Performing Circuit” program obsolete. As a
result it devised a more contemporary approach to identifying improvement plans, determining the value of those
plans and monitoring to ensure that results delivered meet or exceed expected targets. This program was named
Open Reliability Reporting (ORR).
The ORR process shifts the Company’s reliability program from a circuit-based view reliant on blended reliability
metrics (using circuit SAIDI, SAIFI and MAIFI) to a more strategic and targeted approach based upon recent trends
in performance of the local area, as measured by customer minutes interrupted (from which SAIDI is derived). The
decision to fund one performance improvement project versus another is based on cost effectiveness as measured
by the cost per avoided annual customer minute interrupted. However, the cost effectiveness measure will not
limit funding of improvement projects in areas of low customer density where cost effectiveness per customer may
not be as high as projects in more densely populated areas.
3.1 Reliability Work Plans
The Company has worked to improve reliability through Reliability Work Plans. To assist in identification of
problem areas, Area Improvement Teams (AIT) meetings and Frequent Interrupters Requiring Evaluation (FIRE)
reports have been established. On a daily basis the Company systems alert operations and engineering team
members regarding outages experienced at interrupting devices (circuit breakers, line reclosers and fuses).
When repetition occurs, it is an indicator that system improvements may be needed. On a routine basis, local
operations and engineering team members review the performance of the network using geospatial and tabular
tools to look for opportunities to improve reliability. As system improvement projects are identified, cost
estimates of reliability improvement and costs to deliver that improvement are prepared. If the project’s cost
effectiveness metrics are favorable, i.e. low cost and high avoidance of future customer minutes interrupted, the
project is approved for funding and the forecast customer minutes interrupted are recorded for subsequent
comparison. This process allows individual districts to take ownership and identify the greatest impact to their
customers. Rather than focusing on a large area at high costs, districts can focus on problem areas or devices.
3.2 Project Approvals by District
The identification of projects is an ongoing process throughout the year. An approval team reviews projects
weekly and once approved, design and construction begins. Upon completion of the construction, the project is
identified for follow up review of effectiveness. One year after completion, routine assessments of performance
are prepared. This comparison is summarized for all projects for each year’s plans, and actual versus forecast
results are assessed to determine whether targets were met or if additional work may be required. The table
below is provided to demonstrate the measures the Company believes represents cost/effectiveness measures
that are important in determining the success of the projects that have been completed.
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In Progress
District Project
count
Budgeted
Cost/CML
Plans Meeting
Goals (>1 year
since project
completion)
Estimated
Avoided annual
CML
Actual Avoided
annual CML
Budgeted
Cost per
annual
avoided CML
Actual Cost
per annual
avoided
CML
Plans Not
Meeting
Goals (not
included in
metrics)
Plans waiting
for information
Montpelier 2 $0.66
Preston 5 $1.55
Rexburg 3 $0.82
Shelley 5 $1.43
Total 15 $1.22 3 118,008 355,493 $0.60 $0.62 0 12
2017-2020 District Projects*
Approval Metrics Effectiveness Metrics
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4 Customer Response
4.1 Telephone Service and Response to Commission Complaints
COMMITMENT GOAL PERFORMANCE
PS5-Answer calls within 30 seconds 80% 85%
PS6a) Respond to commission complaints within 3 days 95% 100%
95% 100%
PS6c) Resolve commission complaints within 30 days 95% 100%
4.2 Customer Guarantees Program Status
Overall Customer Guarantee performance remains above 99 percent, demonstrating Rocky Mountain Power's continued commitment to customer satisfaction. Major Events are excluded from the Customer Guarantees program.
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5 Service Standards Program Summary3F
4
5.1 Idaho Customer Guarantees
Customer Guarantee 1:
Restoring Supply After an Outage
The Company will restore supply after an outage within 24 hours of
notification with certain exceptions as described in Rule 25.
Customer Guarantee 2:
Appointments
The Company will keep mutually agreed upon appointments, which
will be scheduled within a two-hour time window.
Customer Guarantee 3:
Switching on Power or applicant’s request, provided no construction is required, all
government inspections are met and communicated to the
Company and required payments are made. Disconnections for
Estimates For New Supply applicant or customer within 15 working days after the initial
Respond To Billing Inquiries initial contact. For those that require further investigation, the
Company will investigate and respond to the Customer within 10
Resolving Meter Problems with a meter or conduct a meter test and report results to the
Notification of Planned Interruptions notice prior to turning off power for planned interruptions
Note: See Rules for a complete description of terms and conditions for the Customer Guarantee Program.
4 On June 29, 2012, in Docket PAC-E-12-02 and Order 32583, the Commission ordered that Rocky Mountain Power had delivered upon commitments it made in pursuant to the MidAmerican transaction in PAC-E-05-08 and Order 29998. The Commission also ordered the acceptance of modifications to the Service Standards Program proposed by Rocky Mountain Power, as shown on Page 4 of 15.
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5.2 Idaho Performance Standards
Network Performance Standard 1: Report System Average Interruption Duration Index
(SAIDI)
Controllable SAIDI and identify annual Underlying baseline
performance targets for the reporting period. For actual
performance variations from baseline, explanations of
performance will be provided. The Company will also
report rolling twelve month performance for Controllable,
Report System Average Interruption Frequency
Index (SAIFI)
Controllable SAIFI and identify annual Underlying baseline
performance targets for the reporting period. For actual
performance variations from baseline, explanations of
performance will be provided. The Company will also
report rolling twelve month performance for Controllable,
Improve Under-Performing Areas portions of circuits to improve performance by a forecast
amount, using either its legacy worst performing circuit
program (to reduce by 10% the reliability performance
indicator (RPI) on at least one area on an annual basis
within five years after selection) or by application of its
Supply Restoration supply or damage to the distribution system within three
Telephone Service Level seconds. The Company will monitor customer satisfaction
with the Company’s Customer Service Associates and
quality of response received by customers through the
Commission Complaint Response / Resolution disconnect Commission complaints within three working
days and will b) respond to at least 95% of disconnect
Commission complaints within four working hours, and will
c) resolve 95% of informal Commission complaints within
Note: Performance Standards 1, 2 & 4 are for underlying performance days and exclude those classified as Major Events.
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5.3 Cause Code Analysis
The tables below outline categories used in outage data collection. Subsequent charts and table use these
groupings to develop patterns for outage performance.
Direct Cause
Category Category Definition & Example/Direct Cause
Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels or other animals,
whether or not remains found.
• Animal (Animals) • Bird Nest • Bird Mortality (Non-protected species) • Bird or Nest • Bird Mortality (Protected species)(BMTS) • Bird Suspected, No Mortality
Contamination or Airborne Deposit (i.e. salt, trona ash, other chemical dust, sawdust, etc.); corrosive environment; flooding due to rivers, broken water main, etc.; fire/smoke related to forest, brush or building
• • • •
• •
• Equipment
Failure
Structural deterioration due to age (incl. pole rot); electrical load above limits; failure for no apparent
reason; conditions resulting in a pole/cross arm fire due to reduced insulation qualities; equipment affected
• •
• • Interference utility dig-in; contact by outside utility, contractor or other third-party individual; vehicle accident, including
• • • •
• Loss of
Supply
• •
• •
• • Operational testing or commissioning error; relay setting error, including wrong fuse size, equipment by-passed; incorrect
• • • • • •
• •
• Other
• • •
Planned repairs after storm damage, car hit pole, etc.; construction work, regardless if notice is given; rolling
• • • •
• •
• • Tree
• • •
Weather
• •
• • • •
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5.4 Reliability Definitions
This section will define the various terms used when referring to interruption types, performance metrics and
the internal measures developed to meet its performance plans.
Interruption Types
Below are the definitions for interruption events. For further details, refer to IEEE 1366-2003/20124F
5 Standard for
Reliability Indices.
Sustained Outage
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentary Outage Event
A momentary outage event is defined as an outage equal to or less than 5 minutes in duration, and comprises all
operations of the device during the momentary duration; if a breaker goes to lockout (it is unable to clear the
faulted condition after the equipment’s prescribed number of operations) the momentary operations are part
of the ensuing sustained interruption. This sequence of events typically occurs when the system is trying to re-
establish energy flow after a faulted condition, and is associated with circuit breakers or other automatic
reclosing devices. Rocky Mountain Power uses the locations where SCADA (Supervisory Control and Data
Acquisition) exists and calculates consistent with IEEE 1366-2003/2012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliability Indices
SAIDI
SAIDI (system average interruption duration index) is an industry-defined term to define the average duration
summed for all sustained outages a customer experiences in a given period. It is calculated by summing all
customer minutes lost for sustained outages (those exceeding 5 minutes) and dividing by all customers served
within the study area. When not explicitly stated otherwise, this value can be assumed to be for a one-year
period.
Daily SAIDI
In order to evaluate trends during a year and to establish Major Event Thresholds, a daily SAIDI value is often
used as a measure. This concept is contained IEEE Standard 1366-2012. This is the day’s total customer minutes
out of service divided by the static customer count for the year. It is the total average outage duration customers
experienced for that given day. When these daily values are accumulated through the year, it yields the year’s
SAIDI results.
SAIFI
SAIFI (system average interruption frequency index) is an industry-defined term that attempts to identify the
frequency of all sustained outages that the average customer experiences during a given period. It is calculated
by summing all customer interruptions for sustained outages (those exceeding 5 minutes in duration) and
dividing by all customers served within the study area.
CAIDI
CAIDI (customer average interruption duration index) is an industry standard index that is the result of dividing
the duration of the average customer’s sustained outages by frequency of outages for that average customer.
While the Company did not originally specify this metric under the umbrella of the Performance Standards
5 IEEE 1366-2003/2012 was first adopted by the IEEE Commissioners on December 23, 2003. The definitions and methodology detailed therein are now industry standards, which have since been affirmed in recent balloting activities.
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Program within the context of the Service Standards Commitments, it has since been determined to be valuable
for reporting purposes. It is derived by dividing PS1 (SAIDI) by PS2 (SAIFI).
MAIFIE
MAIFIE (momentary average interruption event frequency index) is an industry standard index that quantifies
the frequency of all momentary interruption events that the average customer experiences during a given time-
frame. It is calculated by counting all momentary interruptions which occur within a 5 minute time period, as
long as the interruption event did not result in a device experiencing a sustained interruption.
CEMI
CEMI is an acronym for Customers Experiencing Multiple (Sustained and Momentary) Interruptions. This index
depicts repetition of outages across the period being reported and can be an indicator of recent portions of the
system that have experienced reliability challenges. This metric is used to evaluate customer-specific reliability.
ORR
ORR is an acronym for Open Reliability Reporting, which shifts the Company’s reliability program from a circuit
based metric (RPI) to a targeted approach reviewing performance in a local area, measured by customer minutes
lost. Project funding is based on cost effectiveness as measured by the cost per avoided annual customer minute
interrupted.
CPI99
CPI99 is an acronym for Circuit Performance Indicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. It excludes Major Event and Loss of Supply or Transmission outages. The variables and
equation for calculating CPI are:
CPI = Index * ((SAIDI * WF * NF) + (SAIFI * WF * NF) + (MAIFI * WF * NF) + (Lockouts * WF * NF))
Index: 10.645
SAIDI: Weighting Factor 0.30, Normalizing Factor 0.029
SAIFI: Weighting Factor 0.30, Normalizing Factor 2.439
MAIFI: Weighting Factor 0.20, Normalizing Factor 0.70
Lockouts: Weighting Factor 0.20, Normalizing Factor 2.00
Therefore, 10.645 * ((3-year SAIDI * 0.30 * 0.029) + (3-year SAIFI * 0.30 * 2.439) + (3-year MAIFI * 0.20 * 0.70)
+ (3-year breaker lockouts * 0.20 * 2.00)) = CPI Score
CPI05
CPI05 is an acronym for Circuit Performance Indicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. Unlike CPI99 it includes Major Event and Loss of Supply or Transmission outages. The
calculation of CPI05 uses the same weighting and normalizing factors as CPI99.
RPI
RPI is an acronym for Reliability Performance Indicator, which measures reliability performance on a specific
segment of a circuit to identify underperforming circuit segments rather than measuring performance of the
whole circuit. This is the Company’s refinement to its historic CPI, more granular.
IDAHO
Service Quality Review
January – June 2020
Page 21 of 21
Performance Types & Commitments
Rocky Mountain Power recognizes several categories of performance; major events and underlying performance.
Underlying performance days may be significant event days. Outages recorded during any day may be classified
as “controllable” events.
Major Events
A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value
(Reliability Standard IEEE 1366-2012) based on the 2.5 beta methodology. The values used for the reporting
period and the prospective period are shown below.
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
1/1-12/31/2020 83,400 13.23 1,102,990
Significant Events
The Company has evaluated its year-to-year performance and as part of an industry weather normalization task
force, sponsored by the IEEE Distribution Reliability Working Group, determined that when the Company
recorded a day in excess of 1.75 beta (or 1.75 times the natural log standard deviation beyond the natural log
daily average for the day’s SAIDI) that generally these days’ events are generally associated with weather events
and serve as an indicator of a day which accrues substantial reliability metrics, adding to the cumulative reliability
results for the period. As a result, the Company individually identifies these days so that year-on-year
comparisons are informed by the quantity and their combined impact to the reporting period results.
Underlying Events
Within the industry, there has been a great need to develop methodologies to evaluate year-on-year
performance. This has led to the development of methods for segregating outlier days, via the approaches
described above. Those days which fall below the statistically derived threshold represent “underlying”
performance, and are valid. If any changes have occurred in outage reporting processes, those impacts need to
be considered when making comparisons. Underlying events include all sustained interruptions, whether of a
controllable or non-controllable cause, exclusive of major events, prearranged (which can include short notice
emergency prearranged outages), customer requested interruptions and forced outages mandated by public
authority typically regarding safety in an emergency situation.
Controllable Distribution (CD) Events
In 2008, the Company identified the benefit of separating its tracking of outage causes into those that can be
classified as “controllable” (and thereby reduced through preventive work) from those that are “non-
controllable” (and thus cannot be mitigated through engineering programs); they will generally be referred to in
subsequent text as controllable distribution (CD). For example, outages caused by deteriorated equipment or
animal interference are classified as controllable distribution since the Company can take preventive measures
with a high probability to avoid future recurrences; while vehicle interference or weather events are largely out
of the Company’s control and generally not avoidable through engineering programs. (It should be noted that
Controllable Events is a subset of Underlying Events. The Cause Code Analysis section of this report contains two
tables for Controllable Distribution and Non-controllable Distribution, which list the Company’s performance by
direct cause under each classification.) At the time that the Company established the determination of
controllable and non-controllable distribution it undertook significant root cause analysis of each cause type and
its proper categorization (either controllable or non-controllable). Thus, when outages are completed and
evaluated, and if the outage cause designation is improperly identified as non-controllable, then it would result
in correction to the outage’s cause to preserve the association between controllable and non-controllable based
on the outage cause code. The Company distinguishes the performance delivered using this differentiation for
comparing year to date performance against underlying and total performance metrics.