20220516Service Quality Report 2021.pdf

i;:E{l': iVli)ROCKY MOUNTAINffiF.*,. - .!._\! . F D,J ,). ll+, .-.ii'i li irr u'
' l;,' -:'- *-.::.-.i/' " :, :; --";--,,lr'$iQli
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Re:
May 16,2022
VA ELECTRONIC DELIWRY
Ms. Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
I l33l W. Chinden Blvd.
Building 8 Suite 20lA
Boise,ID 83714
Pne--t 'os'of t i?RC- e- t ?-c L
PAC-E-04-07 - Service Quality & Customer Guarantee Report for the period
January I through l)ecember 31,2021.
Dear Ms. Noriyuki:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the Service Quality
& Customer Guarantee report covering January I through December 31, 2021. 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
authorization to extend these programs.
If there are any additional questions regarding this report, please contact Ted Weston at
(801)220-2e63.
Joelle Steward
Senior Vice President, Regulation & Customer Solutions
Enclosurescc: 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 AUALITY
REVIEW
January 1- December 3I,202L
Report
x ROCKYF(ruER MOUNTAlN !DAHO
Service Quality Review
January - December 2021
Table of Contents
Executive Summary
1.1 System Average lnterruption Duration lndex (SAlDl)
L.2 System Average Interruption Frequency lndex (SAlFl)
L.4 Restore Service to 80% of Customers within 3 Hours
2.2 Controllable, Non-Controllable and Underlying Performance Review..........
2.3 Underlying Cause Analysis Table
3
4
4
5
5
7
8
8
9
5.1.1 Rocky Mountain Power Customer Guarantees.........5,t.2 Rocky Mountain Power Performance Standards
4 Customer Response
4.1 Telephone Service and Response to Commission Complaints
4.2 Customer Guarantees Program Status
11
13
t4
L4
L4
16
16
16
L7
L7
18
19
20
Page2 ot 22
\
ROCKY MOUNTAIN
POIA'ERArcGffi
IDAHO
Service Quali$ Review
January - December 2021
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. 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,
targets and reporting methods. The Standards guide and reaffirm the importance of customer service both external
and internally.
The Company distinguishes between non-controlldble 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 December 2O2L, results of network performance as measured by System Average
lnterruption Duration lndex (SAlDl) and System Average lnterruption Frequency Index (SAlFl) in ldaho is
unfavorable to the Company's plan. The Company's goal continues to be supplying safe, reliable power to ldaho.
Rocky Mountain Power is dedicated to learning from our past service experiences and continuing to make
improvements to our operations and customer service to ensure ldaho's needs are met.
Below is a summary of our 2021 performance serving the customers of ldaho.
Page 3 of 22
\
IDAHO
Service QualiU Review
January - December 2021
1 Reliability Performance
Rocky Mountain Power strives to deliver reliable service to its customers in ldaho. For 2021, the Company's
network performance was unfavorable as measured by System Average lnterruption Duration lndex (SAlDl) and
System Average tnterruption Frequency lndex (SAlFl) in ldaho. Results for ldaho underlying performance can be
seen in subsections 1.1 and 1.2 below. During the year there were three major events and nine significant event
days. Details regarding these events are found in section 1.3. Section 1.4 show Company outage response
performance. Transmission outages continue to cause a significant impact to the customers in ldaho, especially for
SAlFl. These outages have a greater tendency to reach the established Major Event thresholds and make up' the
majority of significant event days. The Company is outlining a resiliency plan focused heavily on addressing
transmission and substation issues. This plan outlines short- and long-term projects to provide resiliency to the
system and limit the impact of these outages. ln 2O2O, the outline for the plan was established and in 202L projects
are being scoped and vetted for feasibility. Projects were identified and added to the reliability improvement plan
for completion between 2022-2025.
1.1 System Average lnterruption Duration lndex (SAlDll
Below is the Company's underlying interruption duration performance for 2021.
2021IDAHO SAID|
(orcludes Prearrarycd and Customer Requ6ted)
uzL 2121 y2t 4l2t 5l7t 6l2t ilzt u2t 9l2t lont 11nt L2n1,
-QljfirUndtdylr:Actutl
*-.-.- OhndrrControlhbhActurl
r r o o o CtlondtrToerl tndudl4 i/blot Ev.ntt
-
Unds{ylry PLn
ROCKY MOUNTA|N#s*
300
280
260
2&
220
200
180
160
140
120
100
80
@
t|()
20
0
aeIc
=o
6
Actual
(reporting period)
Plan
(year-end)
Total (maior events lncluded)259.4
Underlying (major events excluded)168.6 131
3L.4Controllable
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Page 4 of 22
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ROCKY
FTOWER
MOt lUf,AtN IDAHO
Service Quality Review
January - December 2021
L.2 System Average Interruption Frequency lndex (SAlFl)
Below are the Company's underlying interruption frequency performance results for 2O2L.
2021ldaho SAIFI
(excludes Prearranged and C$tomer Requested)
uzt u21 y2t 4121 3l2r 6l2L lzL AA 9lA tont nnr Dnr
-C.l.rd.rUndeilylqActurl
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2.8
2.6
2.4
2.2
2.O
1.8
L6
L4
L2
LO
o8
o6
o4
o.2
0.0
Actual
(reporting period)
Plan
(year-end)
Total (malor events included)2.558
Underlyi ng (major events included)2.067 1.552
0.315Controllable
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Page 5 of 22
Y IDAHO
Service Quality Review
January - December 2021
1.3 Major and Significant Events
Major Event General Descriptions
Three events during the year met the Company's ldaho major event threshold levell for exclusion from
u nderlying performance results.
Februarv 3
During the early morning hours of February 3,2021, a cold front passed through southeastern ldaho. The
storm brought a burst of moderate snow and gusty south by southwest winds to the area. Snow
accumulations in the upper Snake River Plain were approximately 2 to 3 inches with peak wind gusts
between 35 and 45 mph. The event impacted 14,930 customers in the Rexburg and Shelley areas. A major
event report was submitted to the Commission on May 24,2021.
a March 29
On March 29,202!, a fast-moving cold front brought unusually strong wind gusts to the Upper Snake River
Plain and surrounding areas, including 61 mph at ldaho Falls and 55 mph at Rexburg. These wind speeds
are in the top L% of all wind gusts measured forthese locations. Gusty winds decreased significantly behind
the front later that morning, though breezy northwesterly winds continued through the afternoon. During
this period of extreme weather, a loss of substation event occurred and impacted L7 ,077 customers in the
Shelley area. A major event report was submitted to the Commission on August L9,2O2!.
a October 29
On October 29,202L,ldaho experienced a loss of power event at the Rexburg Substation. The outage was
caused by an arc flash that occurred within the substation on air-break switch 1AB during a switching
procedure. The 12.47 kilovolt (kV) system at 1AB developed an arc at the power fuses of the Bank 1
transformer. The power fuses failed to operate. The opening operation of the 59 kV breaker at Rigby
provided the means to extinguish the arc. The total length of the event was over 50 seconds and resulted
in a loss of power occurrence at the substation for approximately four hours. Crews responded to the
damaged bus, switches, power fuse holders, and stand offs before repowering the substation.
Approximately 10,000 customers were without power during the event. A major event report was
submitted to the Commission on January 6,2022.
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 Lostth-72/3t12027 8s,383 14.035 r,798,472rl7-1213L12O22 86,628 14.839 r,28s,887
ROCKY MOUNTAIN
PolAIER
a
CauseDate SAIDI
February 3 Weather - Wind and Snow 25.7
March 29 Weather - Loss of Substation 47.7
october 29 Equipment Failure - Loss of Substation 27.7
Total 101.1
Page 6 ol 22
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IDAHO
Service Quality Review
January - December 2021
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 year nine significant event days2 were recorded, which account for
78.1 SAIDI minutes, 46 percent of the reporting period's underlying 168.6 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.
L.4 Restore Service to 80% of Customers within 3 Hours
Overall, the Company restored power outages due to loss of supply or damage to the distribution system
within three hours to94o/o of customers, achievingthe goalof greaterthanSO%.
ROCKY MOI,NTAN
Hgm*"
Date Cause: General Descrlptlon Underlylng
SAID!
UnderMng
SAIFI
% ofTotal
UnderMng
sArDt (1691
% ofTotal
Underlying
sArFr (2.0671
January 26, 2021 Loss of transmission line 11.3 0.L42 6.7%6s%
February 27,2021 Car hit pole 3.4 0.012 2.O%o.6%
April8,2021 Windstorm 4.L 0.071 2.4%3.4Yo
April 10,2021 Windstorm 8.1 0.059 4.8%2.8%
May 11,2021 Snow storm - loss of transmission line 3.8 0.059 2.2%3.40/o
June 12,2021 Loss of transmission line 20.9 0.302 L2.4%L4.6%
August 22,2021 Loss of Transmission line due to car
hit pole Lt.4 0.088 6.8%4.3%
September t0,2021,Storm and loss of transmission line 7,L 0.038 4.2%L.8%
october l2,2o2l Equipment Damage and Loss of
Supplv 8.1 0.072 4.8%3.5%
TOTAT 78.1 0.853 46%4t%
January February March April Mav June
99%86%96%82%98%96%
July August September October November December
98%90%89%94Yo 97%72%
'?On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results.
PaEeT of22
\
IDAHO
Service Quality Review
January - December 2021
2 Reliability History
Depicted below is the history of reliability in ldaho. ln2OO2, 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.L ldaho Reliability Historical Performance
ldaho Reliability History - lncluding Maior Events
ISAIDI ICAIDI -+--SAIFI
2
600
500
4m
3q)
2m
1m
0020t2 2013 20t4 2015 2015 2017 2018 2019 20,20 2021.
ROCKY MOUMTAIN
FOWER
4
3
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ldaho Reliability History - Excluding Maior Events
ISA]DI ICAIDI .'t* SAIFI
6m
5(x)
400
300
200
1m
00
(ihFa tOrad
(ootl <f?aN
qoL^Nol r!F.lll O)l{N a'l tnFt O)
rD(ot{9 1O\D Ol(oNa
2012 2013 2014 2015 2016 70L7 2018 2019 2020 20,2t
Page8ol22
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ROCKY MOTJNTAIN
H*HN*IDAHO
Service Quality Review
January - December 2021
2.2 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.
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
outages3. lnordertoprovideinsightintotheresponseandhistoryforthoseoutages,thechartsbelowdistinguish
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 long-term general improving trend for all
charts, reflecting in the recent period, however, the declining performance noted in this report. 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 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 reportt informatlon regarding non-controllable outaget includin& 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.
Page 9 of 22
ldaho 365-Day Rolling Controllable History as Reported
,.rd '.*s ,.d ,rrn ,tr*.,,trs ,rf 'rd ,rf '*s c$ .c'*d '*d *P
uFr SEess Perlod
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Xffi IDAHO
Service Quallty Review
ldaho !16$Day Rolllry tton@ntrollabh Hlstoryas Reported
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ldaho 35$Day Rolllng Underlytt3 History as Reported
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0
January - December 2021
Page 10 of 22
Y IDAHO
Service Quality Review
January - December 2021
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 excludes major events and includes prearranged outages
(Customer Requested, Customer Notice Given, and Plonned Notice Exempt 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.
ROCKY MOUNTAINPO'\'ER
Direct Cau$e Customer Minutes
lost for lnddent
Customers ln
lnddent Sustalned
Sustalncd
lncid€lrtCount SAIDI SAIFI
ANIMALS 0.68
BIRD MORTALITY (NON-PROTECTED SPECIES)
58,029
172,823
744
69 7.32
0.008
0.010
BrRD MORTALTTY (PROTECTED SpECTES) (BMTS)9 0.05 0.000
BIRD NEST (BMTS)
4,O82
138,739
722
8s8
29
515 7 1.62 0.006
BIRD SUSPECTED, NO MORTALITY 754,082 1,513 53 1.80 0.018
AN]MATS 467,736 3,637 242 5.48 0.043
coNDENSATTON / MOTSTURE 133 7 1 0.00 0.000
CONTAMINATION
FIRE/SMOKE (NOT DUE TO FAULTS)
7
5
0.02
0.00
0.000
0.000
ENVIRONMEilT
7,426
142
1,700
20
2
2?13 0.02 0.(xro
B/O EqUIPMENT 349,627 3,377 274 4.09 0.039
DETERIORATION OR ROTTING 7,645,349 70,342 481 79.27 o.121
NEARBY FAULT 200,004 4,478 4 2.34 0.0s2
OVERLOAD 28,194 723 11 0.33 0.001
POLE FIRE 567,501 3,808 36 6.65 0.045
RELAYS, BREAKERS, SWITCHES 93 1 6 0.00 0.000
STRUCTURES, INSULATORS, CONDUCTOR 396 5 72 0.00 0.000
EqUIPMENT FAITURE 2,791,lil 32.6922,OL4 7il 0.2s8
DrGrN (NON-PACTFTCORP PERSONNEL)7.29
OTHER INTERFERING OBJECT
17
15 1.13
0.012
0.013
OTHER UTILITY/CONTRACTOR
7to,t20
96,224
4,764 73
1,065
7,074
6 0.06 0.001
VANDALISM OR THEFT 319 1 1 0.00 0.000
VEHICLE ACCIDENT 1,380,461 12,808 64 76.77 0.150
INTERFERENCE 1,591,888 15,021 103 18.64 o.176
LOSS OF SUBSTATION 5,547 5.65
LOSS OF TRANSMISSION LINE
482,493
4,836,540 87,430
15
745 55.6s
0.065
0.954
IOSS OF SUPPLY 5,319,032 86,971 150 62.30 1.019
FAULTY INSTALL 355 3 3 0.(x)0.(x)o
IMPROPER PROTECTVE COORDINATION 0.o7 0.002
INCORRECT RECORDS
1
1 0.00 0.000
INTERNAL CONTRACTOR 47,289
55
6,335
0.55 0.060
OPERATIONAT v,w
199
s,l2r
I
5,118 3
8 0.53 0.052
OTHER, KNOWN CAUSE 728 6.s2
UNKNOWN 781,938
556,s28 10,911
8,422 305 9.16
0.128
0.099
OTHER 1,338,465 19,333 433 15.68 o.226
CONSTRUCTION 3,722 0.04
CUSTOMER NOTICE GIVEN 2,726,Osg
70
18,103
8
186 24.90
CUSTOMER REQUESTED 45,050 0.s3
0.001
o,272
0.001
EMERGENCY DAMAGE REPAIR 7.72 0.025
INTENTIONAL TO CLEAR TROUBLE
787,074
792,684
7
50
4 2.26 0.009
PLANNED NOTICE EXEMPT 585,526
50
2,792
729
5,455 73 5.85 0.054
PIANNED 3,t34,tt4 26,s9!'328 36.71 0.312
Page tL of 22
\ffi tDAlro
Sn lr.e Quslity Reulpw
fl,g344 s,852 61 7.14 0,909
16,995 177
5E
8
0.98TI
9,n
0.015
0.@
@aJtg 3,582 1S)7.30 0,044
298,10t1 ?,217 ?8 3.t9 0.038
823.p33 7,N2 265 9;65 0.083
2o2t
PaSe ill of 22
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ROCKY MOI.INTAIN
HSIH*
January - December 2021
2.4 Cause Category Analysis Charts
Certain cause categories impact more customers for a given event, while others impact few customers but may
take longer to restore. The charts and graphs below show customer minutes lost (SAlDt) and sustained
interruptions (SAlFl) by cause category. Customer minutes lost is directly related to SAIDI (the average outage
duration for a customer), customer interruptions directly relate to SAIFI (the average outage frequency for a
customer) while sustained interruptions depict the total number of outages by their causes. Certain types of
outages typically result in a large amount of customer minutes lost, though they occur infrequently, such as Loss
of Supply outages. Others tend to be more frequent but result in few customer minutes lost. The pie charts below
show the percentage of SAtDl, SAIFI and lncidents by all cause categories. Total excludes major events and
prearranged outages within the Plonned cause category.
Cause Analysls - Customer Mlnutes lost (SAlDll
I OPIRATIONAIO9G
E OIHER 9TI [0650F
SUPPLY I PI.ANNID3X
E TREES SX
r. WEATHER 12'6
I INTERFERINCE r ANIMATS3%
I ENVIRONMENTO'(
I EQUIPMENT FAITURE 20'6
Cause Analysis - Customer lnterruptlons (SAlFll
r OPERAIIONAT 3'6
I ANIMAIS2%
r tossoF
SUPPLY
4916
5 OTHER 1196
3 PIANNEDzX
I TREES 495
Y WEATHER 8'6
! ENVIRONMENTO6
I INTERFERENCE 9!X I EqUIPMENT FAILURE 12%
Cause Analysls - Sustalned lncidents
r ENVIRONMENTl%
. ANTMAIS 1296 r EQUIPMENT
FAII.URE 3396
Y WEATHER 1996
INIfRFERENCE
4%
r rossoF suPPt_Y 796I TREES 396 T OPIRATIONAI. 096I' PTANNED T OTHER 1896
Page 13 of 22
IDAHO
Service Quality Review
\
MOUNTAIN IDAHO
Service Quality Review
January - December 2021
3 Reliability lmprovement 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 legary "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 Reportine (ORR).
The ORR process shifts the Company's reliability program from a circuit-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.
3.1 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 engineeringteam 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 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.
ROCKY
POYI'ER
Page L4 of 22
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ROCKY MOUNTAIN
POWET IDAHO
Service Quality Review
Effectlveness Metrics ln Progresr
Plans
Meetlng
Goals (>1
year since
project
completion)
Estimated
Avoided
annual
cMt
Actual
Avolded
annual
cMr
BudFted
Cost per
annual
avoided
CML
Actual
Crst per
annual
avoided
cMt
Plans Not
Meetang
Goals (not
included in
metrics)
Plans
wahingfor
lnformatlon
Montpelier 2 So.oo 0 0 0 so.0o So.oo 0 2
Pr€ston 3 S2.83 3 26,807 91,694 s2.83 So.oz 0 0
Rexburg 2 s0.70 2 96,086 273,458 So.zo So.ze 0 0
Shelley 2 SE.zs 2 283,L22 6L7,343 S3.73 -s0.23 0 0
Total 9 $z.gg 7 406,015 982,495 $2.e5 ($o.or1 0 2
*Metrics cover RWP's approved between L/7{2OL9 and L2l3Ll2O2t
January - December 2021
Page L5 ot 22
\
IDAHO
Service Quality Review
January - December 2021
4 Customer Response
4.t Telephone Service and Response to Commission Complaints
The Company achieved its goals related to providing a timely response to customers concerns and commission
complaints.
4.2 Customer Guarantees Program Status
Overall Customer Guarantee performance remains above 99 percent, demonstrating the Company's continued
commitment to customer satisfaction. Major Events are excluded from the Customer Guarantees program.
customerguarantees January to tlecember 2021
ROCKY MOUMTAIN
POYI'ERAMCffi?
PS5 Answer calls within 30 seconds 80%82%
PSSa Respond to commission complaints within 3 days 95%t00%
PSSb Respond to commission complaints regarding service disconnects
within 4 hours 9s%Loo%
9s%L00%P56c Resolve commission complaints within 30 days
cGl
cG2
cG3
cG4
cG5
cG6
cG7
'2qr@\rI)6p0oB.
EY.ntr dd
zUXt
Frlu[a *3rcc.aa Eu.nla P.ld
?o.ib
Frlbrra *Sucaa.
181,809
I,189
391
537
593
1r8
18.100
100.0O/o
r00.(x)%
tm.(x)%
r00.m%
r00.qr%
r00.qll6
rm.oo9a
lo
to
lo
lo
s0
l0
lo
1C7,328
1ffi
348
43e
552Itt
r r.350
1m.m%
1m.m%
1q).(x)%
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30
lo Billing ln(lllrbs
to iibtor Probl€ms
on Piler
ol Pbnned
20211/, 0 100.0096 30 21't.356 I 90.oSr 350
ldaho
Page L6 of 22
Y ROCKY MOUNTAIN
PCNA'ER IDAHO
Service Quality Review
January - December 2021
5 Service Standard slProgram Summarlf
5.1 Service Standards Program
As referenced in Rule 25
5.1.1 Rocky Mountain Power Customer Guarantees
Note; See Rules for o complete description of terms ond conditions for the Customer Guorontee Progrom.
o On June 29,2072, 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 L7 ol 22
Customer Guarantee 1:
Restorins Supolv After an Outase
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
nonpavment, 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 necessary 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 davs.
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.
Y ROCKYPOA'ER
MOUNTAIN !DAHO
Service Quality Review^m@qw?
January - December 2021
5.L.2 Rocky Mountain Power Performance Standards
Network Performance Standard 1:
Report System Average lnterruption Duration lndex
(sArDr)
The Company will report Total, Underlying, and
Controllable SAIDI and identify annual Unded$ng 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 U nderlying distribution events.
Network Performance Standard 2:
Report System Average lnterruption Frequenry
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 U nderlvine 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 t0% 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 Reliabilitv Reportine Prosram.
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 eQualitv monitorins svstem.
Customer Service Performance Standard 5:
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.
Note: Performonce Stondards 7, 2 and 4 ore for underlying performonce doys ond exclude those clossified os Major Events.
Page 18 of 22
Y IDAHO
Service Quality Review
January - December 2021
5.2 Cause Code Analysis
The Company classifies outages based upon the cause categories and causes; causes are a further delineation
within cause categories. lt applies the definitions below to determine the outage cause categories. These
categories and their causes can help support reliability analysis and improvement efforts.
Dlreet €*use
eat€*orv Category Deftnltlon & Examph/Dlrect Cause
Animals Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels, or other animals,
whether or not remains found.
o Animal (Animals)r Bird Mortality (Non-protected species)o Bird Mortalitv (Protected soeciesl(BMTSl
r Bird Nest
o Bird or Nest
o Bird Susopcted. No Mortalitv
Environment ContaminationorAirborneDeposit(i.e.salt,tronaash,otherchemical 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).
o Condensation/Moisture. Contamination
o Fire/Smoke (not due to faults)r Floodins
o Major Storm or Disaster
e Nearby Fault
o Pole Fire
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 by fault on
nearby equipment (e.g., broken conductor hits another line).
o B/O Equipment
o Overload
. Deterioration or Rotting
o Substation. Relavs
lnterference 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 balloou other interferins obiect such as straw, shoes, string, balloon.
o Other Utility/Contractor
o Vehicle Accident
r Dig-in (Non-PacifiCorp Personnel)r Other lnterfering Object
o Vandalism or Theft
Loss of
Supply
Failure of supply from Generator or Transmission system; failure of distribution substation equipment.r Failure on other line or station
o Loss of Feed from Supplierr Loss of Generator
r Loss of Substation
o Loss of Transmission Line. Svstem Protection
Operational 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 safeW restriction.
r lnternal Tree Contractorr Switching Error. Testing/Startup Error
o Unsafe Situation
. Contact by PacifiCorp. Faulty lnstall. lmproper Protective Coordination. lncorrect Records. lnternal Contractor
(Xher Cause Unknown; use comments field if there are some possible reasons.
r lnvalid Code
e Other. Known Cause
o Unknown
Planned 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; rollins blackouts.. Constructionr Customer Notice Given. Energy Emergency lnterruption. lntentional to Clear Trouble
. Emergency Damage Repair. Customer Requested
o Planned Notice Exempt
o Transmission Reouested
Tree Growing or falling trees
r Tree-Non-preventableo Tree-Trimmable
a Tree-Tree felled by Logger
Weather Wind (excluding windborne material); snow, sleet or blizzard, ice, freezing fog, frost, lightning.
. Extreme Cold/Heatr Freezing Fog & Frost
o Wind
. Lightning
o Rain
o Snow, Sleet. lce and Blizzard
ROCKY MOUNTAIN
HSIYE*B*
Page L9 ol 22
3 MOUNTAlN IDAHO
Service Quality Review
January - December 2021
5.3 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 Tvoes
Below are the definitions for interruption events. For further details, refer to IEEE 1365-20O3/20L2s Standard for
Reliability lndices.
Sustained Outoge
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 equalto 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 t366-20O312012. Where no substation breaker SCADA exists, fautt
counts at substation breakers are to be used.
Reliabiliw 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 othenarise, this value can be assumed to be for a one-year
period.
DailySAlDl
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 1365-2012. 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
SAlDlresults.
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.
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
s IEEE 136G2@3 was adopted by the IEEE on December 23, 2003. lt was subsequently modified in IEEE L3ffi-2OL2, but all definitions used in this document
are conslstent between these two versions. The definitions and methodology detailed therein are now industry standards.
Page20 of 22
ROCKYPOWETaBffi6m
Y IDAHO
Service Quality Review
January - December 2021
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).
MAIFI
MAIFI (momentary average interruption frequency index) is an industry standard index that quantifies the
frequenry of all momentary interruptions that the average customer experiences during a given timeframe. lt is
calculated by counting all momentary interruptions which occur, as long as the interruption event did not result
in a device experiencing a sustained interruption.
MA|Fle
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
timeframe. lt is calculated by counting all momentary interruptions which occur within a S-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
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 variables 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 Factor 2.00
Therefore,10.645*((3-yearSAlDl*0.30't0.029)+(3-yearSAlFl*0.30*2.439)+(3-yearMAlFl*0.20*0.70)
+ (3-year breaker lockouts * 0.20't 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.
R()cKY
FOIA'ER
MOUNTAlN
Pase2lol22
V.ROCKY MOUNTAINYpovven\rrcucwa
IDAHO
Service Quality Review
January - December 2021
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 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
LIL-L2|3L/202L 85,383 14.04 t,L98,4L2
LIL-t213t12022 86,528 L4.84 1,285,887
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 L.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.
Controlloble 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 te)C 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 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.
Page?Zof22