20191106Service Quality Report 2019.pdf

ROCKY MOUNTAIN
F'OYI/ER
A OIVTSTOI OF PA,CIFICORP
RECEIVED
l0l9 HOY -6 AH ll : 09 1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
November 5, 2019
,1SS
VA OVERNIGHT DELIVERY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
11331WChindenBlvd
Building I Suite 201A
Boise. Idaho 83714
Pftt-e-os' o3, PAc ' E- tA-o2-
PAC-E-04-07 2019 Service Quality & Customer Guarantee Report for the period
January 1 through June 30, 2019.
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the Service Quality
& Customer Guarantee report covering January I through June 30,2019. This report is provided
pusuant 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
authorization to extend these programs.
If there are any additional questions regarding this report please contact Ted Weston at (801) 220-
2963.
Sincerclv,
Re
iA;^r* C A"rr --,eidi Caswell
Director of Engineering
Enclosures
cc: Terri Carlock
I Case No. PAC-E-99-01.
2 Case No. PAC-E-04-07.
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE QUALTTY
REVIEW
January 1 - June 30, 2019
Report
ROCKY MOUNTAINPC'WER IDAHO
Service Quality Review
TABLE OF CONTENTS
EXECUTIVE SUMMARY
1 SERVICE STANDARDS PROGRAM SUMMARY
1.1
t.2
ldaho Customer Gua rantees.....
ldaho Performance Standards..
2 RELIABILITYPERFORMANCE
2.1. System Average lnterruption Duration lndex (SAlDl)...........
2.2 System Avera8e lnterruption Frequency lndex (SAlFl)...
2.3 Reliability History..
2.4 Controllable, Non-Controllableand Underlying Performance Review
2.5 Ca use Code Analysis.............
UnderlyinB Cause Analysis Table......
cause Category Analysis Charts ......
..,,,,,,,...'2
........3
4
4
5
7
6
....8
....9
..10
2.5.L
?.5.2
t2
13
14
15
15
15
16
18
2.6 Reliability lmprovement Process
2.6.7 Reliability Work Plans...
2.6.2 Project approvals by district
2.6.3 Reduce CPI for Worst Performing Circuits or 5ub-circuits
2.7 Restore Service to 80% of Customers within 3 Hours .............-.
2.8 Telephone Service and Response to Commission Complaints..
3 CUSTOMER GUARANTEES PROGRAM sTATUs
4 APPENDIX: ReliabilityDefinitions..
..1.8
18
19
Page 2 of 2L
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January - June 2019
TABTE OF CONTENTS
Y ROCKY MOUNTAINP(il'ER IDAHO
Service Quality Review
January - June 2019
EXECUTIVE SUMMARY
Rocky Mountain Power developed its Customer Service Standards and Service Quality Measures in 1.999. The
Company developed the program by benchmarking its performance against relevant industry reliability and
customer service standards. ln some cases, Rocky Mountain Power has expanded upon these Standards. ln other
cases (largely where the industry has no established standard) Rocky Mountain Power developed its own metrics,
ta rgets and reporting methods. The Standards guide and reaffirm the importance of customer service both externa I
and internally.
The Company distinguishes between non-controllable outages (e,9. lightningj vehicle collisions) and controllable
outages (e.9. 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.
Rocky Mountain Power's goal continues to be supplying safe, reliable power to ldaho. 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 the expectation or our ldaho customers.
The following is a summary of our 2019 performance through June.
Page 3 of 21
For the period January to June 2019, results of network performance shows the average frequency and duration
of customer outages in ldaho to be favorable compared with the company's plan, showing steady improvement
throughout the reporting period, and continuing the trend of improving reliability over a longer period of analysis.
During the first half of the year ldaho customers experienced one major outage event in April 2019. The number
of ldaho customers impacted by the event was 17,319. While the Company's restoration processes were effectively
executed, the events had significant negative impacts to our customers, communities and other important
stakeholders. As part of its processes to continuously improve service to customers, the Company previously
identified the need for transmission and substation modifications and has developed a multi-year plan which
includes additional transmission and substation assets as well as reconfiguration of existinB stations to afford
better reliability for the circuits which they feed. While under construction certain portions of the system may be
more vulnerable to routine operational events, resulting in customer impacts. As much as possible, the Company
will strive to mitigate these risks to customers.
ROCKY MOI'NTAIN
POYI'ER IDAHO
Service Quality Review
January - June 2019
1 SERVICE STANDARDS PROGRAM SUMMARY,
1.1 ldaho Customer Guarantees
Customer Guarantee 1:
RestorinS 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 ofthe 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 L5 workinB days after the initial
meeting and all necessary information is provided to the Company
omer 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 l0
working days.
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:
Notifi€ation 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.
I 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{5-08 and Order 29998, The Commission also ordered the acaeptance of modifications to the
Serviae Standards ProSram proposed by Rocky Mountaln Power, as shown on PaBe 4 of 15.
Page 4 of 21
Note:
'ee
Rules for o complete description of terms ond conditions for the Customer Guorontee Program.
Customer Guarantee 6:
Resolving Meter Problems
Y ROCKY MOUNTAINFOWER IDAHO
Service Quality Review
January - June 2019
1.2 ldaho Performance Standards
Note: Perlormonce Stondotds 1, 2 & 4 ore for underlying performonce days ond exclude those clossified ds Mdjor
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. TheCompanywill also
report rolling twelve month performance for Controllable,
Non-Controllable and UnderlyinB distribution events.
Network Performance Standard 2l
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 10% 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 5 of 21
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ROCKY MOUNTAINFol'VER IDAHO
Service Quality Review
lanuary -June 2019
2 RELIABILITY PERFORMANCE
For the reporting period, the Company experienced underlying interruption duration (SAlDl) and interruption
frequency (SAlFl) performance in ldaho that was favorable to plan. Results for ldaho underlying performance can
be seen in subsections 2.1and 2.2 below,
Major Event General Descriptions
One event during the reporting period met the Company's ldaho major event threshold level2 for exclusion from
underlying performance results.
April 3, 2019: Shelley, ldaho, experienced an outage when the 59 kV transmission line fed between
Sandcreek and Sugarmill Substations experienced an unknown trip event. The event should have caused a
circuit breaker momentary trip and reclose at the Sugarmill Substation, however the substation ground
relay element remained in the trip position blocking the reclosing on the circuit breaker, causing a
sustained outage event. The event affected three distribution substations, feeding a total of 11 circuits,
serving 17,319 customers, with outage durations ranging from t hours 4 minutes to 2 hours 27 minutes.
The loss of supply event affected approximately 64% of the customers served within the Shelley operating
area.
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 reportinB period, while more si8nificant event days generally
means poorer reliability results. During the reporting period one significant event day3 was recorded, which
account for 6.7 SAIDI minutes; about 13.5% of the reporting period's underlying 50 SAIDI minutes. The com pany
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; it has recognized transmission system
reliability risks previously and continues on-going improvement plans.
r A Major Event (ME) is defined as a 2+hour period where SAlDl ex.eeds a statistically derived threshold value (Reliability Standard IEEE 1366-2012) based
on the 2.5 beta methodology. The va lues used for th e reportinS period a re shown below:
Effective Date Cu5tomer Count ME Threshold SAlDl l{E Customer Minutes Losttll-1213L120L9 A2,079 1s.09 t,238,812
Date Cause
Apnl 3, 2019 Loss of Transmission 19.48
Date cause: General Description Underlying
SAIDI
Unde yint
SAIFI
% ofTotal
Underlying
sArDr (so)
% of Total
Underlying
sArFr (0.s801
6.8 0.012 r3'/o 2.1%June 6, 2019 Loss of Transmission Line (Wind storm
downed lines in Shelley, ldaho)
TOTAL 6.8 0.012 t3%2.1%
I On a trial basis, the Companyestablished a variable of 1,75 timei the standard deviation oI its natu ral lo8 SAIDI results.
Page 6 of 21
Major Events
SAIDI
Significant Event Days
ROCKY MOUNTAIN
PC'WER IDAHO
Service Quality Review
Actual
(reporting period)
Plan
(year-end)
Total (major event included)70
Underlying (major event excluded)50 1,62
controllable 11
2.1 System Average lnterruption Duration lndex (SAlDl)
The Company's underlying interruption duration performance for the year was favorable to plan
IDAHO SAIDI
(exclude! PrearranBed and C ustomer Requested)
January - June 2019
180
160
140
120
100
80
@
a,!o
Ezoe6o o\ o\ o or 6 (n <h cr or (h (h (h
oooooooooo.{ a.tl a{ .{ N a! 61 t{ N N N rt
d.\trn<tnllrF.@(hO
controlable Actual
...... Total Includng lvlajorEvcnts
-
Unde.lyiq Actual
-
Underlyilf, Phn
PaEe 7 of 2l
IDAHO
SAIDI
Y ROCKY MOUNTATN
POVVER IDAHO
Service Quality Review
ianuary - June 2019
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying interruption frequency performance results for the year are favorable to plan
!DAHO SAIFI
(exclud€s PrearranSed and CustomerRequested)
,-6
1.4
L2
,-0
o8
o5
o4
o2
o0
c
a,
t! 6r ot (D aD or (r! or or ot ot ('r
oooooooooort a{ Fl r{ N it N ag a{ N N r\l
Adual
{reporting period)
Plan
(year-end)
Total (major event included)o.793
Underlying (maror event included)0.580 7.520
0.105Controllable
Cortrolabh Act al
.. .... Totd IncludnS Maior Events
-
undedylng Actual
-
unde r$/lng Phn
Page 8 of 21
IDAHO
SAIFI
\
IDAHO
Service Quality Review
January -.lune 2019
2.3 Reliability History
Depicted below is the history of reliability in ldaho. ln 2002, the Company implemented an automated outaBe
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 ofBeospatial tools to analyze reliability, development ofweb-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.
ldaho Reliability History - lncluding Major Events
ISAtDt ICAtot ---SAtFl
ROCKY MOUNTAIN
POYVER
4
3.4
2.9 3.0
cat
ql
3 2.6
2
2.L o
3
=
9L.75
a0.87
2m9 2010 201,7 20t2 2013 201,4 2015 20L6 2017 20L8 20L9
thru June
r,lot-a O €<t slNFCO otN <l r-II
3
2
1,
0
ldaho Reliability History - Excluding Major Events
ISAIDI rcatDt --.- sAtFl
2.3
2.L
1.
2m9 20.to 201L 20L2 2013 20L4 2015 2016 2017 2018 2019
thru June
2.2
3m
zfi
2m
150
100
50
0
2
o
fc
=I(,N o<t rno tt(o rD(DN
Page 9 of 21
6m
500
4m
3m
2m
1@
00
co
uJ
N(o
3 ROCKY MOUNTAINFOWER IDAHO
Service quality Review
January - June 20L9
2.4 Controllable, Non-Controllable and Underlying Performance Review
ln 2008, the Company introduced a further cateBorization 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 liBhtning
caused interruptions; other causes have also been determined and are specified in Section 2.6. 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
outagesa. ln order to provide insight into the response and history for those outages, the cha rts below distingu ish
amongst the outage grou pings.
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. ln
order to also focus on non-controlla ble outages, the Company has continued to improve its resalaence to extreme
weather using such programs as its visual assurance program to evaluate facility condition. lt also has undertaken
efforts to establish im pacts of loss of supply events on its customers and deliver a ppropriate improvements when
identified. lt uses its web-based notification tool for alerting field engineerint 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.
ldaho 365-Day Rolling Controllable History as R€ported
d"d'rf ',
lo
t0
m
?t
0,t
o8
o.7
o6?60
Ilso
E
0,
(Ia
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30
:0
lo
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d .6,' tr+ d,+ {,e 6' 'l os1f ,,, $ $ \f, ,{f 1, O *rd ,"d .,r's
slrt r P.dod
-SAl0l -sAlFl -UrE.. lsAloll
a 3. The Company shall provide, as an appendir to its Sewice Quality Review reports, information regardin8 non-controllable outages, including. when
appliceble, descriptions of efforts made bythe Company to improve service quality and reliabilityfor causes the Company has identified as not controllable.
4. The Company shall provide a supplemental filin& within 90 days, consistinB of a process for measurinS performance and improvements forthe non-
controllable events.
Page 10 of 21
I
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ROCKY MOUNTAIN
POWER IDAHO
Service Quality Review
3
2.5
2
U
29
2C[
0.5
r 15{)t
oa
loo
,o
-S .! .'! ^., .l ^9 -r.
,f .,, rf \f .,f, \f, \f,
,$'
.Il'
January - June 2019
$,{ +!5.'f r,dd.+ .{f
0
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a
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r.s E
i
g
ll@
Stc'' Pcrlod
-5Al0l -sAlFl -tin...
(S/AIDD
ldaho 365-Day Rolling Underlying Hirtory as Reported
.d d d d," ,F+ fo ,eg f,)+ +f +" .d d9 4,9sf rf $ rf sl rJ f, 1f ,{f .sf ,{f .'.f r+
stt... P.rlod
-SAlDi -sAlfl -tlne.r l5Al0ll
PaBe 11 of 21
1
ldaho 365-Day Rolling NonControllable History as Reported
IDAHO
Service Quality Review
gro u s to develop patterns for ou erformance
ROCKY MOUNTAIN
POI,VER
e
Direct Cause
Category Category Deflnition & 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 Mortality (Non-protected species). Eird Mortality (Protected species)(BMTS)
. Bird Nest. Bird or Nest. Eird SusDected, No Mortalitv
Contamination or Airborne Deposit (i.e. salt, trona ash, other chemical dust, sawdust, etc.); corrosive
environmenti 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).
Envlronment
. Condensation/Moisture. Contamination. Fire/Smoke (not due to faults). Floodins
. Major Storm or Disaster. Nearby Fault. Pole Fire
Strudural deterioration due to age (incl. pole rot); electrical load above limits; failure for no apparent
reason; conditlons 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
. B/o Equipment. Overload
. Deterioration or Rotting. Substation, Relays
Willful damage, interference or theft; such as gun shots, rock throwin& etc.; customer, contractor or other
utility diB-in; contad by outside utility, contractor or other third-party individual; vehicle accident, including
car, truck, tractor, aircraft, man alloon; other interfering ob.iect such as straw, shoes, string, balloon.
lnterference
. Dig-in (Non-Pacificorp Personnel). Other lnterfering Object. Vandalism or Theft
. Other Utility/Contractor. Vehicle Accident
Failure of supply from Generator or Transmission sy5tem; failure of distribution substation equipment.Loss of
Supply . Failure on other line or station. Loss of Feed from Supplier. Loss of Generator
. Loss of Substation. Loss ofTransmission Line. system Protection
Accidental Contad by PaclfiCorp 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 identific installation or construction; operational or safety restriction.
Operational
. Contad by Pacificorp. Faulty lnstall. lmproper Protective Coordination. lncorrect Records. lnternal Contrador
. lnternal Tree Contrador. Switching Error. Testing/Startup Error. Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons,Other
. lnvalid code. Other, Known Cause
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 lf notice is given; rolling
blackouts-
Planned
. Emergency Damage Repair. Customer Requested. Planned Notice Exempt. Transmission Requested
. Construction. Customer Notice Given. Energy Emergency lnterruption. lntentional to ClearTrouble
Growing or falling treesTree
. Tree-Non-preventable. Tree-Trimmable
. Tree-Tree felled by Logger
Wind (excluding windborne material); snow, sleet or blizzard, ice, freezing fog, frost, lightningWeather
. Lightning. Rain. Snow, Sleet, lce and Blizzard
. Extreme Cold/Heat. Freezing Fog & Frost
Page !2 of 2L
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January - June 2019
2.5 Cause Code Analysis
The tables below outline categories used in outage data collection. Subsequent charts and table use these
Anlmals
7 ROCKY MOUNTAIN
FIOI'I'ER IDAHO
Service Quality Review
January - June 2019
2.5.1 Underlying Cause Analysis Table
The table and charts below show the total customer minutes lost by cause and the totalsustained interruptions
by cause. The Underlying cause analysis table includes prearranged outages (Cusfomer 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 sAlDl and sAlFl metrics for the period.
Customer
Minutes tost for
lncident
Customers in
lncident
Sustained
Sustained
lncident
Count
sAtot SAIFIDirect Caure
40,980 448 58 0.50 0.005ANIMAL5
19,824EIRD MORTALITY (NON-PROTECTEO SPECIES)560 20 0-24 0.007
31,113 206 5 0.38 0.003ErRD MORTALTTY (PROTECTED SPECTES) {BMTS)
2,915 24 6 0.04 0.000BrRD NEST{8MTS)
9,114 0.001gIRD SUSPECTED, NO MORTALITY 119 16 0.11
ANIMATS 104,006 L,1s7 !.27 0.017
206 3 2 0.00 0.000CONTAMINATION
80FIRE/SMOKE (NOT DUE TO FAULIS}1 1 0.00 0.000
ENVIRONMENT 246 4 3 0.00 0,000
65,301 548 82 0.80 0.007B/O EQUIPMENT
675,735 5,525 340 0.057OETERIORATION OR ROTTING 8.73
NEAREY FAU LT 92 1 7 0.00 0.000
OVERLOAD 170 2 2 0.m 0.000
POLE FIR€234,552 2,349 24 2.91 0.029
EQUIPMEI{T FAII,URE 979,850 8,42s 449 0.10311.94
DIG.IN (NON-PACIFICORP P€RSONNEL)21,368 157 o.26 0.002
OTHER INTERFERING OB,JECT 5,801 49 8 0.o1 0.001
8,200OTHER UTILITY/CONTRACTOR 59 3 0.10 0.001
VEHICTE ACCIDENT 295,047 2,937 !7 3.s9 0.036
330,410 3,196II{TERFERENCE 36 4.03 0.039
LOSS OF FEED FROM SUPPLIER 18,687 195 11 0.23 0.002
LOSS OF SUESTATION 305,538 5,667 23 3.72 0.069
LOSS OF TRANSMISSION LINE 1,190,082 16,153 51 14.50 0,197
LOSS OF SUPPI.Y L,5L4,q7 22,0ts 85 18.45 0.268
OTHER, KNOWN CAUsE 33,M0 474 2l 0.40 0.005
UNKNOWN 327,724 4,482 159 0.0553.99
360,164 4,895 180 4.40 0,060
CONSTRUCTION 1,795 48 5 o.o2 0.001
CUSTOMER NOTICE GIVEN 655,165 s,303 96 7.98 0.065
CUSTOMER REQUESTED 2,974 40 5 0.04 0.000
EMERGENCY DAMAGE REPAIR 170,955 1,731 2.O8 o.o27
INTENTIONAI- TO CTEAR TROUBLE 37,686 203 0.46 0.002
MAINTENANCE 28 1 2 0.00 0.000
PLANNED NOTICE EXEMPT 297 1 L 0.00 0.000
PLANNED 868,894 7,327 158 10.59 0.m9
TREE. NON-PREVENTASLE 38,896 360 3S o.41 0.004
TRE€. TRIMMABLE 85,945 1,194 6 1.05 0.015
TREES 124,84L 1,5y 4L 1.52 0.019
FREEZING FOG & FROST 102 1 1 0.00 0.000
ICE 16,549 136 5 0.0020.20
LIGHTNING toa,167 1,258 67 1.33 0.015
SNOW, SLEET AND BLIZ2ARO 206,908 1,396 64 o.o71
WIND 17L,478 1,411 63 2.O9 0.017
W€ATHER 503,903 4,2O2 200 5.14 0.051
ldaho lncludinB Prearranged 4,747 362 52,976 1,258 58.33 0.645
ldaho Excluding Preananged 4,114,937 47,632 1,156 50.30 0.580
Note: Direct Causes are not listed ifthere were no outages classified within the cause during the reporting period.
Page 13 of 21
ldaho cause Analysis - Underlylnrli1l2oLg - 6lr0l2oL9
OTHER
7
ROCKY MOUNTAIN
B9IIYE*B-"
IDAHO
Service Quality Review
January - June 2019
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 (SAlDll
Y WEATHER 12%E ANIMALS 2%rJ TREES 3%r ENVIRONMENT O%Y PLANNED 5%
! OTHER 9%A EQUIPMENT
FAITURE 24%
3 INIERFERENCE E%I LOSSOF SUPPLY
37%
Cause Analysis - Customer lnterruptions (SAlFll
Y OTHER 10%3 LOSS OF SUPPLY 46%
I INTERFERENCE 7%
Y PLANNED4%
Y TREES 3%
g WEATHER 9%
E ANIMALS 3%
T ENVIRONMENT O%
I EQUIPMENT FAILURI 18%
Cause Analysis - Sustained lncidents
A EQUIPMINT
FAITURE 39%C ANIMALS9%
3 ENVIRONMENT O%
Y WEATHER 17%
!r TREES 4%
Y PLANNED 5%
I INTERFERENCE 4%
Z
F-
Y OTHER
r LOSSOF SUPPTY 7%
Page 14 of 21
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ROCKY MOUNTAIN
HgHyE*..
IDAHO
Service Quality Review
January - June 2019
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 2016 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 shifted 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 ofthe 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 projests 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 ofthe 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 offuture customer minutes interrupted,
the project is approved for funding and the forecast customer minutes interrupted are recorded for subsequent
comparison. This process allows individualdistricts 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.
2.5.2 Project approvals by district
The identification of projects is an onBoin8 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 ofeffectiveness. 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 15 of 21
\
ROCKY MOTJNTAIN
PIOWER IDAHO
Service Quality Review
Effectiveness Metrics ln Progress
Plan!
MeetlnS
6oals (>1
year since
projed
completion)
Estlmated
Avoided
annual
CML
Actual
Avoided
annual
CML
EudSeted
Cost per
annual
avoided
CML
Actual
Cost per
annual
avoided
CML
Plans Not
Meeting
Goals (not
included in
metrics)
Plans
waiting for
lnformatlon
0 2Montpelier2S3.25 0
3 Lzs,578 204,978 s0.47 So.oo 0 1Prestons0.88
Rexburg s3.80 1 86,245 13,155 so-60 s1.28 1
453,844 s0,00 0 3Shelley95!.47 6 506,114 s0.39
Tota I 91.9s 10 665,668 724,246 S0.43 So.o2 L 9
January - June 2019
*Metrics cover projects approved between t hl21l6 and 6130/2079
2.6.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln 2012 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 20L2, 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 12l3U2011)
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 Sta ndards Progra m, it ann ually selects a set of Worst Performing Circuits for ta rgeted improvement.
The improvement proiects are generally completed within two years of selection. Within five years of selection,
the average performance ofthe selection set must improve by at least 20% against baseline performance. Those
program years which have met their target scores are removed from the listing below.
Reliability Performance lmprovement (post L213U2o17 throueh L2/37/20761
On a routine basis, the Company reviews areas for performance. LJtilizing 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 tar8eted 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 listinB below.
Page 16 of 21
20L6 - 2079 District Projects
Approval Metrics
Dirtrict Prorect
count
Budgeted
Cort/cML
4
3
20
\
ROCKY MC'I.,NTAIN
FTOWER IDAHO
Service Quality Review
PROGRAM YEAR 17 (RPl) Method
Clifton 11 (Figure 3C)IN PROGRESS 88
195Dubois L2 (FiBure 4c)COM PLETE L49
TARGET SCORE = 189 Goal Met 210 118
PROGRAM YEAR 16
COM PLETE 127 94Lava 11 (Figure lC)
COM PLETE 36 54Preston 11 (Figure 2C)
Goal Met 82TARGET SCORE = 73 74
PROGRAM YEAR 15
PROGRAM YEAR 12
1,24Grace 12 COM PTETED r4
102Preston 13 COM PLETED 83
TARGET SCORE = 90 Goal Met 113 49
(lmprovement targets for circuits in Pro8ram Years 1-11 and 13-15 have been met and filed in prior reports.)
Page !7 ol 2l
IDAHO WORST PERFORMING
clRcurrs STATUS BASEI.INE PERFORMANCE
6130120L9
Region Performance lndicator 2012 (RPlul Method
Circuit P.rformance lndicator 2005 (CPl05) Method
January - June 201.9
\
ROCKY MOIJNTAIN
POVYER IDAHO
Service Quality Review
2.7 Restore Service to SOYo of Customers within 3 Hours
2.8 Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
customerguarantees January to Juns 2019
January February March April May June
97%96%85%99%96%98%
Pss-Answer calls within 30 seconds 80%870/.
PSSa) Respond to commission complaints within 3 days 95%too%
PS6b) Respond to commission complaints regarding service disconnects
within 4 hours 95%
PS6c) Resolve commission complaints within 30 days 9s%too%
cG1
C@
cG3
cG4
cG5
cG6
cG7
?0t9
t-llB allEco
2018
F.tlrE * 9rc...
Supply 47,63 0
0
0
0
0
0
'rmt
1{x)!a
loora
lmtr
100tt
100ta
g)
so
,0
t0
$0
l0
so
on Powet
6r7tu
r0a
377
69
to Eilling lnquines
b ireler Probloms
17,752
a9t
r53
t58
3:t0
t49
4,06r
0
I
0
0
0
0
1
tq)!a
99_80!a
r(x)*'tflx
r0094
to0*
99.98t(
30
350
g)
l0
t0
50
t50
u,tn 0 rm% 30 5it.t94 2 g0.ggfh 3t00
lclaho
Overall Customer Guarantee performance remains above 99%, demonstrating Rocky Mountain Power's continued commitment to
customer satisfaction.
Major Events are excluded from the Cu5tomer Guarantees program.
Page 18 of 21
January - June 2019
RESTORATIONS WITHIN 3 HOURS
Reporting Period Cumulative = 96%
COMMITMENT GOAL PERFORMANCE
1,00%
January - June 2019
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 Tvpes
Below are the definitions for interruption events. For further details, refer to IEEE L366-2oO3l20L2s Standard for
Reliability lnd ices.
Sustained outoge
A sustained outage is defined as an outage Breater than 5 minutes in duration.
Momentdry outage Event
A momentary outaBe 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 1356-2003/2072. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
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 activitie!,
Page 19 of 21
UROCKY MOUNTAIN'<f Po\,\rER
\.hs6c{,6*
IDAHO
Service Quality Review
Reliabilitv lndices
SAIDI
SAIDI (system averaBe 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
wathin the study area. When not explicitly stated otherwise, this value can be assumed to be for a one-year
period.
Oaily SAlDl
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 1356-2012. This is the day's total customer minutes
out of service d ivided by the static custome r cou nt for th e yea r. lt is the total average outa8e duration customers
experienced for that given day. When these daily values are accumulated through the year, it yields the year's
SAlDl results.
SAIF'
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 durinB 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.
CAIDI
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
Y ROCKY MOUNTAIN
FIOWER IDAHO
Service Quality Review
January - June 2019
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 PSz (SAlFl).
MAIFh
MAIFIE (momentary average interruption event frequency index) is an industry standard index that quantifies
the frequency of all momentary interruption events that the averaBe 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 Experiencint 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. Pro.ject funding is based on cost effectiveness as measured by the cost per avoided annual customer minute
interrupted.
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 varia bles and
equation for calculating CPI are:
CPI =lndex*((sAlDl *wF+NF) +(SAlFl *WF* NF) +(MAlFl *wF*NF) + (Lockouts * wF * NF))
lndex: 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 Fador 2.00
Therefore, 10.545 * ((3-yearSAlDl * 0.30 * 0.029) +(3-yearSAlFl * 0.30 * 2.439) +(3-yearMA|Fl " 0.20 * 0.70)
+ (3-year breaker lockouts'i 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 outaBes. The
calculation of CPl05 uses the same weighting and normalizing factors as CPl99.
RP'
RPI is an acronym for Reliability Performance lndicator, which measures reliability performance on a specific
segment of a circuit to identify underperformin8 circuit se8ments rather than measuring performance of the
whole circuit- This is the company's refinement to its historic CPl, more granular.
PaEe 20 of 21
\
ROCKY MOUNTAIN
POTT'ER IDAHO
Service Quality Review
January - June 2019
Performance TvDes & Commitments
Rocky Mou ntain Power recognizes severa I categories of performance; major events a nd u nderlying performance.
Underlying performance days may be significant event days. Outages recorded during any day may be classified
as "controllable" events.
Mdjot Events
A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value
(Reliability Standard IEEE 1356-2012) 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
rlr-t2l3tlzoLg 82,079 1s.09 L,23a,872
Signilicont 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 Benerally associated with weather events
and serve as an ind icator 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.
contrclloble Disttibution (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). tor 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 engineerinB programs. (lt should be noted that
Controllable Events is a subset of U nderlying Events. The Couse Code Anolysis 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 cla ssificat ion. ) 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 outaBes are completed and
evaluated, and if the outage cause desi8nation 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 21 of 21