20181018Service Quality Report 2018.pdf

ROCKY MOUNTAIN
HP,IY.E^"*"",
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1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
October 18, 2018
VA OVERNIGHT DELIVERY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington
Boise,lD 83702
Re: CaseNo.PAC-E-04-07 Pqa- g- 9f -o?, Pftt' €- ,7'o?-
2018 Service Quality & Customer Guarantee Report for the period January 1
through June 30,2018.
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the June 2018 Service
Quality & Customer Guarantee report. This report is provided pursuant to a merger commitment
made during the PacifiCorp and ScottishPowerl 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 authorizationto extend these programs.
If there are any additional questions regarding this report please contact Ted Weston at (801) 220-
2963.
Caswell
Director of Engineering
Enclosurescc: Terri Carlock
Beverly Barker
I Case No. PAC-E-99-01
2 Case No. PAC-E-04-07
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
!DAHO
SERVICE AUALITY
REVIEW
January L - June 30, 2OI8
Report
\
ROCKY
POI'I/ER
MOUNTAIN IDAHO
Service Quality Review
January -June 2018
TABTE OF CONTENTS
TABLE OF CONTENTS 2
3
3
3
4
5
6
7
8
9
EXECUTIVE SUMMARY
1 SERVICE STANDARDS PROGRAM SUMMARY
1.1 ldaho Customer Guarantees
7.2 ldaho Performance Standards
2 RELIABILITYPERFORMANCE
2.1 System Average lnterruption Duration lndex (SAlDl),.
2.2 System Average lnterruption Frequency lndex (SAlFl)
2.3 Reliability History
2.4 Controllable, Non-Controllable and Underlying Performance Review
2.5 Cause Code Analysis ....11
2.5.1 Underlying Cause Analysis Table L2
2.5.2 Cause Category Analysis Charts .......13
2.6 Reliability lmprovement Process 1.4
2.6.1 Reliability Work Plans 74
2.6.2 Project approvals by district L4
15
2.7 Restore Service lo 80% of Customers within 3 Hours ......................t7
2.8 Telephone Service and Response to Commission Complaints t7
3 CUSTOMER GUARANTEES PROGRAM STATUS t7
Page 2 of 20
2.6.3 Reduce CPI for Worst Performing Circuits or Sub-circuits..........,.,,...
\
ROCKY MOUNTAIN
F'OYI'ER IDAHO
Service Quality Review
January - June 2018
EXECUTIVE SUMMARY
Rocky Mountain Power has a number of Customer Service Standards and Service Quality Measures with
performance reporting mechanisms currently in place. These standards and measures define Rocky Mountain
Power's target performance (both personnel and network reliability performance) in delivering quality customer
service. The Company developed these standards and measures using relevant industry standards for collecting
and reporting performance data. ln some cases, Rocky Mountain Power has expanded upon these standards. ln
other cases, largely where the industry has no established standards, Rocky Mountain Power has developed
metrics, targets and reporting. While industry standards are not focused around threshold performance levels,
the Company has developed targets or performance levels against which it evaluates its performance. These
standards and measures can be used over time, both historically and prospectively, to measure the service quality
delivered to our customers.
1 SERVICE STANDARDS PROGRAM SUMMARY'
1.1 ldaho Customer Guarantees
Note: See Rules for a complete description of terms ond conditions for the Customer Guarontee Progrom.
1 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.
Page 3 of 20
Customer Guarantee 1r
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
The Company will switch on power within 24 hours of the customer
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
nonpayment, subterfuge or theft/diversion of service are excluded.
Customer Guarantee 4:
Estimates For New Supply
The Company will provide an estimate for new supply to the
applicant or customer within 15 working days after the initial
meeting and all necessarV information is provided to the Company.
Customer Guarantee 5:
Respond To Billing lnquiries
The Company will respond to most billing inquiries at the time of the
initial contact. For those that require further investigation, the
Company will investigate and respond to the Customer within 10
working days.
Customer Guarantee 6:
Resolving Meter Problems
The Company will investigate and respond to reported problems
with a meter or conduct a meter test and report results to the
customer within 10 working days.
Customer Guarantee 7:
Notification of Planned lnterruptions
The Company will provide the customer with at least two days'
notice prior to turning off power for planned interruptions
consistent will Rule 25 and relevant exemptions.
AO!r$d OF Bcrrr@p
3 ROCKY
POVI'ER
MOUNTAIN IDAHO
Service Quality Reviewadvr$fr ortcrFr@P
January - June 2018
L.2 ldaho Performance Standards
Note: Performonce Stondords 7, 2 & 4 ore for underlying performonce days and exclude those clossified os Major
Events.
Network Performance Standard 1:
Report System Average lnterruption Duration lndex
(sArDr)
The Company will report Total, Underlying, and
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,
Non-Controllable and Underlying distribution events.
Network Performance Standard 2:
Report System Average lnterruption Frequency
lndex (SAlFl)
The Company will report Total, Underlying, and
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,
Non-Controllable and Underlying distribution events.
Network Performance Standard 3:
lmprove Under-Performing Areas
Annually, the Company will target specific circuits or
portions of circuits to improve performance by a forecast
amount, using either its legacy worst performing circuit
program (to reduce by L0% the reliability performance
indicator (RPl) on at least one area on an annual basis
within five years after selection) or by application of its
Open Reliability Reporting Program.
Network Performance Standard 4:
Supply Restoration
The Company will restore power outages due to loss of
supply or damage to the distribution system within three
hours to 80% of customers on average.
Customer Service Performance Standard 5:
Telephone Service Level
The Company will answer 80% of telephone calls within 30
seconds. The Company will monitor customer satisfaction
with the Company's Customer Service Associates and
quality of response received by customers through the
Company's eQuality monitoring system.
Customer Service Performance Standard 6:
Commission Complaint Response / Resolution
The Company will a) respond to at least 95% of non-
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
30 days.
Page 4 of 20
ROCKY
PO\,I/ER MOUNTAIN !DAHO
Service Quality Review
January -June 2018
2 RETIABILITY PERFORMANCE
Forthe reporting period, the Company experienced an underlying interruption duration (SAlDl)that was at plan
and interruption frequency (SAlFl) performance that was favorable to plan. Results for ldaho underlying
performance can be seen in subsections 2.Land 2.2 below.
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 mean
poorer reliability results. During the reporting period five significant event days3 were recorded, which account for
37 SAIDI minutes, or about 49% of the reporting period's underlying 76 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 weather or to events within the transmission system.
2 Malor event threshold shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
7h-r2/3r/2oL7 78,594 16.56 !,307,4477h-12/3u2OL8 80,004 t6.67 1,333,663
Date Cause: General Description Event SAIDI % of Tota! sAlDl
January 25,2OL8 Animal interference 10.23 L3.5o/o
April2,2O18 Wind Storm 7.79 70.3%
April 17,2018 Car-hit transmission pole with underbuild 6.87 9.L%
May 23,2018 Loss of Substation 8.48 77.2o/o
June 17,2018 Lightning related outages including a loss of
transmission.3.77 s.0%
TOTAT 37.15 49%
3 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results.
Page 5 of 20
Major Event General Descriptions
No events occurred during the reporting period which met the Company's ldaho major event threshold level2 for
exclusion from underlying performance results.
Significant Event Days
VROCKY MOUNTAINxrPOYr,ER
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IDAHO
Service Quality Review
January -June 2018
2.L System Average lnterruption Duration lndex (SAlDl)
The Company's system average underlying interruption duration performance for the reporting period was at
plan.
IDAHO SAIDI
(excludes Prearranged and Customer Requested)
200
180
160
140
t20
100
80
60
tO
20
0
o
5c
E5at^o000qrooqr00006oDddddddddidddocrcr€rclttc)c)ctoool\IAIN'{N'{I{NNdN.\l
ddd
Actual
(reporting period)
Plan
(year-end)
76Total (ma.jor event included)
Underlying (major event excluded)76 t79
24Controllable
Controlable Actual
o o o o o r Total lncludng Major Evcnts
-
undedyiry Actlal
Pbo
Page 5 of 20
IDAHO
SAIDI
\
IDAHO
Service Quality Review
January - June 2018
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying system average interruption frequency performance results for the reporting period
is favorable to plan.
ROCKY MOUNTAINPOI'ER
A OG0 OF rcis@P
IDAHO SAIFI
(excludes Prearranged and Customer Requested)
1.8
1.6
L.4
1.2
1.0
o8
0.60
E04
ur; o.z
A' o.o oo6@Goooooqr@ddid6dd6ddddoclooocroooooo,{NNr{r{r\lNct,tN.{N
ddd
Actual
(reporting period)
PIan
(year-end)
Total (major event included)0.582
Underlying (major event included)0.582 1.580
Controllable 0.158
Controiable Acoal
...... TOtd ln6ludng Malgr Ev€nts
-
Undqdyl.g Actual
Undcdylry Pbn
PageT ol20
IDAHO
SAIFI
Y MOUNTA!N IDAHO
Service Quality Review
January -June 2018
2.3 Reliability History
Depicted below is the history of reliability in ldaho. ln 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, in addition to
feeder hardening programs when specific feeders have significantly impacted reliability performance. Recently,
the Company has recognized underperformance of portions of the transmission system and has begun preparing
improvement plans.
ldaho Reliability History - tncluding Major Events
ISAIDI ICAIDI .'-SAIFI
2.9
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=
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7
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2.6
1.9
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3
1
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2008 2fr)9 2010 2011 2OL2 2013 2014 2015 2016 2OL7 June
2018
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ldaho Reliability History - Excluding Major Events
ISAIDI ICAIDI +SAIFI
2.2
2m8 2m9 2010 2011 ?OLz 2013 201.4 2015 2OL6 2017 June
2018
0
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Page 8 of 20
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IDAHO
Service Quality Review
January - June 2018
2.4 Controllable, Non-Controllable and Underlying Performance Review
ln 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.
So, for example, animal-caused interruptions, as well as equipment failure interruptions have a less random
nature than lightning caused interruptions; other causes have also been determined and are specified in Section
2.5. Engineers can develop plans to mitigate against controllable distribution outages and provide better future
reliability at the lowest possible cost. At that time, certain stakeholders were concerned that the Company would
lose focus on non-controllable outages. ln 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 355-
day basis. Analysis of the trends displayed in the charts below shows a general improving trend for all charts,
however shows recent upticks in performance. ln 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. lt also has undertaken efforts to establish impacts of loss of supply events on its
customers and deliver appropriate improvements when identified. lt uses its web-based notification tool for
alerting field engineering and operational resources when devices have exceeded performance thresholds in
orderto react as quickly as possible to trends in declining reliability. These notifications are conducted regardless
of whether the outage cause was controllable or not.
100
90
8o
70
ldaho 365-Day Rolling Controllable History as Reported
.1m.2@7 Js.20(}8 ,m-2OOg Jm-m10 h-2O11 J.n-2O12 tm.20l3 ,m.2O14 h.2015 ,.n-2O16 J&2Ol7 Jr-2O18
5116r pcr'lod
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=610
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0.6
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Page 9 of 20
VROCKY MOUNTAINxcPOYI/ER
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IDAHO
Service Quality Review
ldaho 365-Day Rolling Noncontrollable Historyas Reported
300
2!0
200
150
l0o
ro
3
2.3
2
a
tG
=o
aE
,.t E
L
I
0.5
0 0
,m.2007 Jm-200E ,.n.2@!, J.n.2010 Je.2oll Jm.2012 ,lm-2o13 ,rn-2014 Jm-2015 ,i-2016 ,.n.2017 Jm.20J,8
Stre3r pGrbd
-SAtDt -gllFt -tincer
(SAlDl)
tdaho 365-Day Rolling Underlying Historyas Reported
3(tr 3
250 2.5
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,m.2007 ,ar-2008 Jm.2000 lm.20l0 ,.n.2011 Jm-a012 ,..r-2013 ,m-2014 Jm-1015 J&.2016 ,m.20t7 Jm-2018
sb.gr p.rbd _s,{o _sAtfl
-[incrr6ArDtl
January - June 2018
Page 10 of 20
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3 MOUNTA!N IDAHO
Service Quality Review
January - June 2018
2.5 Cause Code Analysis
The tables below outlines categories used in outage data collection. Subsequent charts and table use these
to deve for rformance.
ROCKYPo\A'ERadvrsfro, acrf@aP
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.
Animals
o Animal (Animals)
r Bird Mortality (Non-protected species)
o Bird MortaliW (Protected speciesXBMTS)
o Bird Nest
o Bird or Nest
o Bird Suspected, No Mortalitv
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
fires (not including fires due to faults or lightning).
Environment
r Major Storm or Disasterr Nearby Fault
o Pole Fire
o Condensation/Moisture. Contaminationr Fire/Smoke (not due to faults)
o Floodine
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
by fault on nearby equipment (e.g., broken conductor hits another line).
Equipment
Failure
r B/O Equipment
o Overload
. Deterioration or Rottingr Substation, Relays
Willful damage, interference or theft; such as gun shots, rock throwing, etc.; customer, contractor or other
utility dig-in; contact by outside utility, contractor or other third-party individual; vehicle accident, including
car, truck, tractor, aircraft, manned balloon; other interfering object such as straw, shoes, string, balloon.
lnterference
o Other Utility/Contractorr Vehicle Accident
o Dig-in (Non-PacifiCorp Personnel)r Other lnterfering Object
o Vandalism or Theft
Failure of supply from Generator or Transmission system; failure of distribution substation equipment.Loss of
Supply r Failure on other line or station
o Loss of Feed from Supplier
o Loss of Generator
o Loss of Substationo Loss of Transmission Line. System Protection
Accidental Contact by PacifiCorp or PacifiCorp's Contractors (including live-line work); switching error;
testing or commissioning error; relay setting error, including wrong fuse size, equipment by-passed; incorrect
circuit records or identification; faulty installation or construction; operational or safety restriction.
. Contact by PacifiCorp. Faulty lnstall. lmproper Protective Coordination
o lncorrect Records
o lnternal Contractor
o lnternal Tree Contractor
o Switching Error. Testing/Startup Error
o Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons.Other
o lnvalid Code
o Other, Known Cause
e Unknown
Transmission requested, affects distribution sub and distribution circuits; Company outage taken to make
repairs after storm damage, car hit pole, etc.; construction work, regardless if notice is given; rolling
blackouts.
Planned
. Construction
o Customer Notice Given. Energy Emergency lnterruption
. lntentional to Clear Trouble
. Emergency Damage Repairr Customer Requested
o Planned Notice Exemptr Transmission Requested
Growing or falling treesTree
o Tree-Non-preventable
o Tree-Trimmable
r Tree-Tree felled by Logger
Wind (excluding windborne material); snow, sleet or blizzard, ice, freezing fog, frost, lightning.Weather
. Extreme Cold/Heato Freezing Fog & Frost
r Wind
o Lightningr Rain
o Snow, Sleet, lce and Blizzard
Page 11 of 20
Operational
YHtrF}JOUNTAIN
IDAHO
Service Quality Review
January - June 2018
2.5.L 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 ond
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.
Note: DirectCausesarenotlistediftherewerenooutagesclassifiedwithinthecauseduringthereportingperiod.
Pase 12 of 20
Direct Cause
Customer
Minutes Lost
for lncident
Customers
in lncident
Sustained
Sustained
lncident
C.ount
SAIDI SA!FI
ANIMALS 888,677 5,287 63 11.11 0.07
218,342BIRD MORTALITY (NON-PROTECTED SPECIES)734 27 2.73 0.01
BIRD MORTALITY (PROTECTED SPECIES) (BMTS)s0,222 242 13 0.63 0.00
307 3 3 0.00 0.00BIRD NEST (BMTS)
BIRD SUSPECTED, NO MORTALIW 22,Osz 376 24 0.28 0.00
ANIMATS 1,L19,ill 6,676 130 ,[.74 0.08
B/O EQUIPMENT 7t,337 660 89 0.89 0.01
626,670OETERIORATION OR ROTTING 5,278 36s 7.83 0.07
OVERLOAD 31S 7 4 0.00 0.00
POLE FIRE 211,656 7,724 25 2.65 0.01
gff,973 483EQUIPMENT FAITURE 7,69 tt.t7 0.09
DrG-rN (NON-PACTFTCORP PERSONNEL)35,918 764 74 0.45 0.00
OTHER INTERFERING OBJECT 72,777 263 7 0.16 0.00
98,086OTHER UTILITY/CONTRACTOR 775 6 7.23 0.01
VEHICLE ACCIDENT 902,947 3,961 31 17.29 0.05
1,0,.9,722 5,163 58 Lt.t2 0.06INTERFERENCE
LOSS OF GENERATOR 160,002 7,727 3 2.00 0.01
LOSS OF SUBSTATION 668,094 5,679 4 8.3s o.o7
328,037 3,689 23 4.70 0.0sLOSS OF TRANSMISSION LINE
1,156,133TOSS OF SUPPTY 10,495 30 L4,4S 0.13
FAULTY INSTALL 422 5 3 0.01 0.00
944 \1-1 0.01 0.00IMPROPER PROTECTIVE COORDINATION
INCORRECT RECORDS 67 7 1 0.00 0.00
PACIFICORP EMPLOYEE. FIELD 29 1 L 0.00 0.00
1,455 18 5 0.02 0.00OPERATIONAL
5,670OTHER, KNOWN CAUSE 67 13 o.o7 0.00
UNKNOWN 203,778 2,672 743 2.54 0.03
208,848 2,7t9 155 2.6t 0.03OTHER
CONSTRUCTION 1,530 22 5 0.02 0.00
CUSTOMER NOTICE GIVEN 774,774 4,867 725 9.68 0.06
774,449 1,930 M 2.78 0.02EMERGENCY DAMAGE REPAIR
276,635 1,556 6 0.02INTENTIONAL TO CLEAR TROUBLE 2.71
PLANNED NOTICE EXEMPT 77,879 1,158 6 0.97 0.01
TRANSMISSION REQUESTED 92,391 954 7 1.15 0.01
PIANNED 1,336,9t 8 10,481 193 t6.71 0.13
93,816 970 43 7.77 0.01TREE. NON-PREVENTABLE
TREE. TRIMMABLE 7,337 18 5 0.09 0.00
TREES 101,153 988 48 t,26 0.01
246,629 3,447 67 3.08 0.04LIGHTNING
SNOW, SLEET AND BLIZZARD s,829 47 9 0.07 0.00
WIND 727,772 5,490 99 9.09 0.07
979,630 8,984 L7S L2.24 0.11WEATHER
5,923,515 52,613 1,279 0.66ldaho lncludiry Prearranged 86.54
ldaho ExcludlnB Prearranged 6,O7L,522 46,594 1,148 75.89 0.s8
ldaho Cause Analvsis - Underlyinc,OLl0tlzALS -06130120L8
V.ROCKY MOUNTAINxSpowen
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IDAHO
Service Quality Review
January - June 2018
2.5.2 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.
Cause Analysis - Customer Minutes Lost (SAlDl)
T WEATHER 15%
IJ TREES 2%T ANIMATS 19%
Y PI.ANNEDS%
U OTHER 4%
r OPERATIONAI.096
E EQUIPMENT
FAILURE 15%
v rossoFsuPPtY 19%
INTERFERENCE 17%
Cause Analysls - Customer lnterruptlons (SAlFl)
Y PLANNEDlO%r4 TRTES 2%
IJ OTHER 6%
I I-O55OF SUPPLY 23%T WEATHER 19%
Y OPERATIONAL O%T ANIMATS 14%
I INTERFERENCE 11%I EqUIPMENT
FAILURE 15%
Cause Analysis - Sustained lncidents
r ANTMALS 11%T EQUIPMENT
TAITURE 42%
I. WEATHER 15%
C TREES4%T INTERFERENCE 4%
Y PLANNED5%E TOSSOFSUPPTY 3%
Y OTHER 14%T OPERATIONAI. 1%
Page 13 of 20
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ROCKY
POYI/ER
MOUNTAIN IDAHO
Service Quality ReviewANrgdd&FrdP
January - June 2018
2,6 Reliability lmprovement Process
Over the past decade the Company and the Commission Staff have discussed methods to ensure that cost
effective reliability improvements are being implemented within the Company's network. ln 2015 the Company
made significant strides in furthering the processes that can deliver such an outcome, by replacing its legacy
selection method for improving under-performing areas, as described in Performance Standard 3 and explored
in Section 2.7.3, with a new approach titled Open Reliability Reporting (ORR) process, As the Company has
evaluated outage data and the outage analysis and monitoring processes it has developed, it found better ways
to ensure the most cost effective reliability improvements were being delivered to customers. As a result, the
Company developed the foundation of the ORR process.
The ORR process shifts the Company's reliability program from a circuit or area-based view reliant on blended
reliability metrics (using circuit SAlDl, 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.
2.6.1 Reliability Work Plans
The Company has worked to improve reliability through Reliability Work Plans. To assist in identification of
problem areas, Area lmprovement Teams (AlT) meetings and Frequent lnterrupters 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. lf the project's cost
effectiveness metrics are favorable, i.e. low cost and/or 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 highly populated area with high improvement costs, districts can focus on
problem areas or devices and tactically target network improvements.
2,6.2 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, as would be
depicted in the table below.
Page 14 of 20
\
ROCKY MOUNTAIN
POYI'ER
A UViS OF rcFr@I
IDAHO
Service Quality Review
Proiec
count
Budgeted
CosVCML
Plans
Meeting
Goals
(>1 year
since project
completion)
Estimated
Avoided
annual
cMt
Actual
Avoided
annual
cMt
Budgeted
Cost per
annual
avoided
cMt
Actual
Cost per
annual
avoided
CML
Plans Not
Meeting
Goals
(not
included in
metrics)
Plans
waiting for
information
Montpelier 9 s1.79 L 230 230 Sss.se s71.84 0 8
5 319,151 910,539 s1.55 $0.72 0 8Preston13Sr.zs
1 54,080 t07,228 S2.s3 s0.70 t 7Rexburg9$4.ss
Shelley 13 s1.21 2 t46,272 259,025 s1.s2 s1.03 2 9
4 9 s29,733 L,277,022 s1.81 so.7e 3 32
January - June 2018
*Metrics cover RWP's opproved between 7/1/2015 and 06/30/2018
2.6.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln2OL2 the Company modified its previous program with regards to selecting areas for improvement. Delivery
of tools allowed more targeted improvement areas. As a result, the Service Standard Program was modified to
reflect this change. Prior to 2012,the company selected circuits as its most granular improvement focus; since
then, groupings of service transformers are selected, however, if warranted entire distribution or transmission
circuits could be selected. Since 2012, the Company has transitioned and further refined its approach to support
cost/benefit valuation for reliability improvements, which are a cornerstone of ORR, as discussed above.
Circuit Performance lmprovement (prior to 1213U2011)
On a routine basis, the Company reviews circuits for performance. One measure that it uses is called circuit
performance indicator (CPl), which is a blended weighting of key reliability metrics covering a three-year period.
The higher the number, the poorer the blended performance the circuit is delivering. As part of the Company's
Performance Standards Program, it annually selects a set of Worst Performing Circuits for targeted improvement,
The improvement projects are generally completed within two years of selection. Within five years of selection,
the average performance of the selection set must improve by at least20o/o against baseline performance. Those
program years which have met their target scores are removed from the listing below.
Reliabilitv Performance lmorovement (post 12131/2011 throueh 1213U2015)
On a routine basis, the Company reviews areas for performance. Utilizing a measure called reliability
performance indicator (RPl), which is a blended weighting of underlying reliability metrics covering a three-year
period, calculated at the service transformer, excluding loss of supply outages. The higher the number, the
poorer the blended performance the area has received. As part of the Company's Performance Standards
Program, it annually selects Underperforming Areas for targeted improvement. The improvement projects are
generally completed within two years of selection. Within five years of selection, the average performance of
the selection set must improve by at least 10% against baseline performance. Those program years which have
met their target scores are removed from the listing below.
Page 15 of 20
ApprovalMetrics Effectiveness Metrics ln
Progress
District
TOTAT s1.88
\
ROCKYPOWER MOUNTAIN IDAHO
Service Quality Review
PROGRAM YEAR 17 (RPl) Method
Clifton 11 (Figure 3C)COMPLETE 225 108
COMPLETE 195 155Dubois 12 (Figure 4C)
TARGET SCORE = 189 zto L37
PROGRAM YEAR 16
COMPLETE 127 35Lava 11 (Figure 1C)
COMPLETEPreston 11 (Figure 2C)36 50
TARGET SCORE = 73 Goal Met
PROGRAM YEAR 12
82 43
Grace 12 COMPLETE t24 46
COMPLETE L02 73Preston 13
Goal Met 113 59TARGET SCORE = 90
(lmprovement targets for circuits in Program Years 1-11and 13-15 have been met and filed in prior reports.)
January -June 2018
Page L6 of 20
IDAHO WORST PERFORMING
crRcurTs STATUS BASELINE PERFORMANCE
05130120t8
Region Performance Indicator 2012 (RH12l Method
Circuit Performance lndicator 2005 Method
Y ROCKY MOUNTAIN
H*y,m,IDAHO
Service Quality Review
2,7 Restore Service to 8O% of Customers within 3 Hoursa
2,8 Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
customerguaranrees
January -June 2018
January to June 2018
February March April May JuneJanuary
62%99%98%95%97%8s%
PS5-Answer calls within 30 seconds 80%82%
95%100%PS6a) Respond to commission complaints within 3 days
95%noneP56b) Respond to commission complaints regarding service disconnects
within 4 hours
9s%too%PS6c) Resolve commission complaints within 30 days
ldaho
cGl
CG2
CG3
cG4
CG5
cG6
cG7
Overall Customer Guarantee performance remains above99%, demonstrating Rocky Mountain Power's continued
commitment to customer satisfaction. Major Events are excluded from the Customer Guarantees program.
a ln some cases a substation residing in one state may have a circuit which feeds customers within another state. ln this case restorations
times are allocated to the state in which the feeding substation resides, opposed the customer's physical location.
PageLT ol20
EEtrtj P..d
an8
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2017
Ernt3 F.iltffi tt 3ffir P.i,
17,752
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100i3
100!6
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b Elillrg lrquiies
b ldebr ftoblens
m Forer
oI Phnned
Itil,Fa 2 99.9$'6 t10o ttza77 15 r9.9$tr t750
RESTORATIONS WITHIN 3 HOURS
Reporting Period Cumulative = 85%
COMMITMENT GOAL PERFORMANCE
3 IDAHO
Service Quality Review
January - June 2018
4 APPENDIX: 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.
lnterruption Types
Below are the definitions for interruption events. For further details, refer to IEEE 1356-200312072s Standard for
Reliability lndices.
Sustained Outage
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentory Outoge 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 t366-200312012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliabilitv lndices
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. lt 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.
Doily SAIDI
ln 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. lt 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. lt 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.
CAID'
CAIDI (customer average interruption duration index) is an industry standard index that is the result of dividing
the duration of the average custome/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
s IEEE 1366-2003/2012 was first adopted by the IEEE Commissioners on December 23,2OO3. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
Page 18 of 20
ROCKY MOUNTAIN#A"
\
MOUNTA!N !DAHO
Service Quality Review
January - June 2018
Program within the context of the Service Standards Commitments, it has since been determined to be valuable
for reporting purposes. lt is derived by dividing PS1 (SAlDl) by PS2 (SAlFl).
MAIFIE
MAlFle (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. lt 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) lnterruptions. 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 (RPl)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
interru pted.
cPt99
CPl99 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. lt excludes Major Event and Loss of Supply or Transmission outages. The variables and
equation for calculating CPI are:
CPI=lndex*((SAlDl*WF*NF)+(SAlFl {'WF*NF)+(MAlFl*WF*NF)+(Lockouts*WF*NF))
lndex: 10.545
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-yearSAlDl*0.30*0.029)+(3-yearSAlFl*0.30*2.439)+(3-yearMAlFl*0.20'r0.70)
+ (3-year breaker lockouts * 0.20 * 2.00)) = CPI Score
cPt05
CPl05 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. Unlike CPl99 it includes Major Event and Loss of Supply or Transmission outages. The
calculation of CPl05 uses the same weighting and normalizing factors as CPl99.
RPI
RPI is an acronym for Reliability Performance lndicator, 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 CPl, more granular.
Page 1.9 of 20
ROCKY
POVVER
V-ROCKY MOUNTAIN
KPoYr/ER\ A OUsd OF &rfiCG'
IDAHO
Service Quality Review
January - June 2018
Performance Tvpes & 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 1365-2012) 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
tlL-Lzl3tlzoL7 78,594 16.56 7,30L,447
LIL-t2l3Ll2O78 80,004 76.67 1,333,663
Significont 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. lf 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
ln 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. (lt should be noted that
Controllable Events is a subset of Underlying Events. The Couse Code Anolysrs 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.
Page 20 of 2O