20190521Service Quality Report 2018.pdf

ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
RECEIVED
liltgHAY?t Pil $08
IDA*C PUSLIC
:T il'.i r rrs c0h{Mtssl0N
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
May 21,2019
VIA OVERNIGHT DELIWRY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,ID 83702
Re: PAC-E-04-07 Ppt-E- os-o7, Pnt- E- t4oL
2018 Service Quality & Customer Guarantee Report for the period July 1 through
December 31, 201t
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the December 2018
Service Quality & Customer Guarantee report. This report is provided pursuant to a merger
commitment made duringthe PacifiCorp and ScottishPowerl merger. The Companycommittedto
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 commitnent 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
(80r)220-2963.
c
Heidi Caswell
Director of Engineering
Enclosurescc: Terri Carlock
Beverly Barker
I Case No. PAC-E-99-01
2 Case No. PAC-E-04-07:
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ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE AUATITY
REVIEW
January L- December 3L,2018
Report
\
ROCKY MOUNTAINPOVER IDAHO
Service Quality Review
January - December 2018
TABLE OF CONTENTS
TABLE OF CONTENTS 2
EXECUTIVE SUMMARY 3
1 SERVICE STANDARDS PROGRAM SUMMARY 4
I.2 ldaho Performance Standards 5
2.L System Average lnterruption Duration lndex (SAlDl) .........................8
2.2 System Average lnterruption Frequency lndex (SAlFl) .......................9
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFl") ....................10
2.4 Reliability History ................15
2.5 Controllable, Non-Controllable and U nderlying Performance Review 16
2.6 Cause Code Analysis 18
2.6.7 Underlying Cause Analysis Table.
2.6.2 Cause Category Analysis Charts..
..19
..20
2.7 Reliability lmprovement Process ..............27
2.7.L Reliability Work Plans ,,2L
..2L
..22
2.7.2 Project approvals by district
2.7.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
2.8 Geographic Outage History of Under-performing Areas ..24
2.9 Restore Service to 80% of Customers within 3 Hours ......................36
2.10 Telephone Service and Response to Commission Complaints .36
3 CUSTOMER GUARANTEES PROGRAM STATUS... ....,...........36
4 APPENDIX:ReliabilityDefinitions .37
Page 2 of 39
Y IDAHO
Service Quality Review
January - December 2018
EXECUTIVE SUMMARY
Rocky Mountain Power developed its Customer Service Standards and Service Quality Measures nearly 20 years
ago. The Standards were developed as a way to demonstrate to customers that the company is serious about
serving them well and willing to back its commitments monetarily in cases where the company fell short. The
Standards also help remind employees about the importance of good customer service. 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 Company distinguishes between non-controllable outages (e.g. lightning; vehicle collisions) and controllable
outages (e.g. animal interference; equipment failure) and takes cost-effective steps to minimize both. As part of
the Company's Performance Standards Program, it annually evaluates individual electrical circuits to focus on those
that have the most frequent interruptions. These are targeted for improvement, which is generally completed
within two years.
For the period January to December 2078, 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.
Nonetheless, ldaho customers did experience three major outage events in the month of December 2018. The
number of ldaho customers impacted by these events ranged from 77,t49 to 19,259. 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 additionaltransmission and substation assets as well as reconfiguration
of existing 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 Mountain Powe/s goalcontinues to be supplying safe, reliable powerto 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 ldaho's needs.
The following is a summary of our 2018 performance serving the customers of ldaho.
ROCKY MOUNTAIN
BgyEn*"
Page 3 of 39
VROCKY MOUNTAINv(Pot,lrER
! ^NrSrOto@P(.rr,cort
IDAHO
Service Quality Review
January - December 2018
L SERVICE STANDARDS PROGRAM SUMMARY1
1.1 ldaho Customer Guarantees
Note: See Rules for o complete description of terms ond conditions for the Customer Guorontee 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 4 of 39
Customer Guarantee 1:
Restoring Supply After an Outage
The Company will restore supply after an outage within 24 hours of
notification with certain exceptions as described in Rule 25.
Customer Guarantee 2:
Appointments
The Company will keep mutually agreed upon appointments, which
will be scheduled within a two-hour time window.
Customer Guarantee 3:
Switching on Power
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 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 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.
\
ROCKY MOUNTAIN
HglF*n*,
IDAHO
Service Quality Review
January - December 2018
1,2 ldaho Performance Standards
Note: Performonce Stondords 7, 2 & 4 are for underlying performonce doys ond exclude those clossified os Mojor
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 70% 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
hoursto 80% ofcustomers 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 95o/o of informal Commission complaints within
30 days.
Page 5 of 39
YROCKY MOUNTAIN
HHHYE*K"
IDAHO
Service Quality Review
January - December 2018
2 RELIABITITY 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 2.1 and 2.2 below.
Major Event General Descriptions
Three events during the reporting period met the Company's ldaho major event threshold leve12 for exclusion from
underlying performance resu lts.
December 7,20t8: Rexburg, experienced an outage when a switch failed on the 69 kV line from the Rigby
substation to St, Anthony, downing the conductor, and causing the circuit breakers at both substations to
trip open. The event affected nine substations, feeding a total of 25 circuits, serving L7,977 customers,
with outage durations ranging from2 hours 39 minutes to 4 hours 38 minutes.
December 26,2018: Shelley, experienced an outage when the circuit breaker at the Sugarmill Substation
tripped open, due to a car hit pole. The event affected three substations, feeding a total of 10 circuits,
serving 17,t49 customers. The outage duration ranged from 51 minutes to t hours 54 minutes.
December 30-31, 2018: Rexburg and Shelley, begin experiencing outages as a winter storm brought snow,
ice, and high winds, damaging equipment across the region. During the two day event 63% of all customer
minutes lost and 73o/o of all customer outage events were the result of loss of supply outages, as
transmission lines experienced fault operations from the heavy wind gusts, ln total, 129 sustained outages
caused L9,269 customer interruptions, with an average outage duration of 4 hours 36 minutes.
2 Major event threshold shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost7/7-L2/3712078 80,004 76.67 1,333,663
a
a
a
CauseDate SAIDI
December 7,2OLg Loss of Transmission 44.35
December 26,2018 Loss of Transmission from car hit pole 27.04
December 30-31,2018 Wind Storm 66.46
Page 6 of 39
Major Events
\
IDAHO
Service Quality Review
January - December 2018
Significant Events
Significant event days add substantially to year on year cumulative performance results; fewer significant event
days generally result in better reliability for the reporting period, while more significant event days generally
means poorer reliability results. During the reporting period eight significant event days3 were recorded, which
account for 59 SAIDI minutes; about 40% of the reporting period's underlying 146 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; it has recognized transmission system
reliability risks previously and has been developing improvement plans.
ROCKY MOUNTAINPol'IIERaw6&@rcr(@f
Date Cause: General Description Event SAIDI % of TotalsAlDt
January 25,2OL8 Raccoon interference 10.23 7.0%
Apri! 2,2018 Wind Storm 7.79 5.3%
Apri! 17,2018 Car hit pole 6.87 4.7%
May 23, 2018 Loss of substation 8.48 5.8o/o
June 17,2018 Lightning related outages including a loss of transmission.3.77 2.6%
August 11,2018 Loss of substation 6.16 4.2%
September 23,2018 Loss of transmission line due to car hit pole tL.73 8.0%
November 18,2018 Pole fire 3.83 2.6%
TOTAT 58.87 40.4%
3 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results
Page 7 of 39
Significant Event Days
Y ROCKY MOUNTAIN
BFIIYE*N*"
!DAHO
Service Quality Review
2.t System Average lnterruption Duration lndex (SAlDl)
The Company's underlying interruption duration performance for the year was favorable to plan
January - December 2018
Actual
(reporting period)
Plan
(year-end)
Total (malor event included)278
L45 t79Underlying (major event excluded)
Controllable 38
3oo
280
260
240
220
200
180
160
140
L20
100
&)
@
40
20
0 66aEaltalr6@clr606(EddidddddddddooocrooooooooNFINNNNNT{^,lF/!.,1 f\l
ddd
Controllable Acual
...... Total lncludng lt/hJorEvents
-
underlyi]E Act al
Underlyiq Phn
0o
=.s
=E
,n
IDAHO SAIDI
(excludes Prearranged and Customer Requested)
Page 8 of 39
IDAHO
SAIDI
.,J
aa at
i.ta
YROCKYPo\A'ER MOUNTAIN IDAHO
Service Quality Review
January - December 2018
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying interruption frequency performance results for the year are favorable to plan.
Actual
(reporting period)
Plan
(year-end)
1.939Total (maior event included)
Underlying (major event included)1.258 1.580
0.273Controllable
2.2
2.O
1.8
1.6
1.4
t2
1.0
0.8
? 0.6c
E04E o.2
,A 0.0 o@8ctGr00666666ddiddddHddddoctctoooooooooFr6ta{r{a\r{NNatNFIFJ
ddd
Controllable Achral
...... Totd lncludng MaiorEvents
-
lJndsrlylry Actual
-
urdedyiq Pbn
IDAHO SAIFI
(excludes Prearranged and Customer Requested)
Page 9 of 39
IDAHO
SAIFI
-4.
Y IDAHO
Service Quality Review
January - December 2018
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFl")
The Company annually reports the occurrence of short interruptions using two different metricsa. The chart
below displays, for the circuits with SCADA devices, the operating area-weighted MAlFl"s performance.
ln the table below, allcircuits that do not have SCADA are evaluated for performance, and where the breaker
counters appear unusual, these counts are investigated and necessary corrections undertaken. Highlights of
current findings for breakers with unusual levels of counter operations are summarized here.
o Bancroft #11: On June 27,2018, relay operations performed scheduled maintenance on this circuit
breaker resulting in high trip counts.
o Weston #11: Trip counts are the result of issues with the McGraw Edison Control, both relay and
operations tested the breaker which resulted in higher than normal trip counts.
o Bernice #21: High trip counts on the breaker were attributed to relay testing.
o Mudlake #11: High trip counts on the breaker were attributed to relay testing.
o Mudlake #12: High trip counts on the breaker were attributed to relay testing.
o Sunnydell #12: the circuit breaker log shows a total of 8 trips from January 2018 to January 2019. lt
appears a recording error occurred which has been corrected.
o Clements #11: the circuit breaker log shows a total of 5 trips from December 2OL7 to April 2019. lt
appears a recording error occurred which has been corrected.
o Hayes #11: the circuit breaker log shows a total of 9 trips from January 2018 to April 2019. lt appears a
recording error occurred which has been corrected.
o Hayes #12: the circuit breaker log shows a total of 4 trips from January 2018 to April 2019. lt appears a
recording error occurred which has been corrected.
r Jeffco #21: High trip counts on the breaker were attributed to relay testing.
o Osgood #11: High trip counts on the breaker were attributed to relay testing, which occurred on October
25,2017 and September 25,2OL8.
r Shelley #13: the circuit breaker log shows a total of 10 trips from January 2018 to January 2019. lt
appears a recording error occurred which has been corrected.
a ldaho state commitment l1O.
On January 31, 2005, the Commission accepted Rocky Mountain Power's proposal to eliminate its Network Performance Standard relating to Momentary
Average lnterruption Frequency lndex (MAlFl) in light of the Company's commitment to develop an acceptable alternative to MAIFI as soon as possible. The
Company has developed its proposed measurement plan and is scheduled to present to the Commission Staff at its next reliability meeting (scheduled for
December 20, 2005). Within 60 days after this meetin& the Company will file the plan with the Commission. MEHC and Rocky Mountain Power commit to
implement this plan and provide the results of these calculations to Commission Staff and other interested parties in reliability review meetinSs.
5 MAlFle events are measured using the circuit customer count for those circuits where a trip and reclose occurred during the reporting period, and do not
include customer counts for circuits where no event was recorded.
Page 10 of 39
ROCKY MOUNTAIN
B*THN-,
MAIFIE (SCADA)Operating Area
Montpelier 0.592
Preston t.407
Rexburg t.235
Shelley 1.280
Januarv 1 throush December 31. 2018
\
ROCKY MOUNTAIN
BggEn*,
IDAHO
Service Quality Review
Operating
Area Circuit Name Circuit lD Operations Corrected
Operations
MONTPELIER ALEXANDER #11 ALX11 0
MONTPELIER ARTMO #11 ARM11 0
ARTMO #12 ARM12 LMONTPELIER
MONTPELIER BANCROFT #11 BAN11 65
BANCROFT #12 BAN12 0MONTPELIER
MONTPELIER CHESTERFIELD #11 cHs11 9
CHESTERFIELD #12 HATCH CHS12 37MONTPELIER
MONTPELIER covE #12 cov12 1
EGT11 3MONTPELIEREIGHT MILE #11
MONTPELIER GEORGETOWN #11 GRG11 8
MONTPELIER HENRY #11 HRY11 1
MONTPELIER HORSLEY #11 H RS11 1
MONTPELIER INDIAN CREEK #11 IND11 1
MONTPELIER LAVA #11 LVA11 0
MONTPELIER LUND #11 LN D11 29
MONTPELIER MCCAMMON #11.MCC11 2
MONTPELIER MCCAMMON #12 MCC12 20
MONTPELIER MONTPELIER #11 MNT11 29
MONTPELIER MONTPELIER #13 MNT13 4
MONTPELIER MONTPELIER #14 MNT14 L
MONTPELIER RAYMOND #11 NORTH TO GENEVA RAY11 3
MONTPELIER RAYMOND #12 SOUTH TO PEGRAM RAY12 12
MONTPELIER ST CHARLES #11 sTc11 0
CLIFTON #11 DAYTON & BANIDA CLF11 5PRESTON
PRESTON cLTFTON #12 CLTFTON/OXFORD/SWANLAKE CLF12 1
DOWNEY #11 DWN11PRESTON 0
PRESTON DOWNEY #12 DWN12 L2
PRESTON HOLBROOK #11 HLB11 4
PRESTON MALAD #11 MLD11 3
MLD12PRESTONMALAD #12 3
PRESTON MALAD #13 MLD13 0
PRS1LPRESTONPRESTON #11 1
PRESTON PRESTON #12 PRS12 L
PRESTON PRESTON #13 PRS13 0
PRESTON TANNER #11 MINK CREEK TNR11 24
PRESTON TANNER #].2 RIVERDALEIREASURETON TNR12 2
PRESTON WESTON #],2 NORTH TO DAYTON WST12 0
WESTON#11 SOUTH - WESTON/FAI RVEW WSTl1 81PRESTON
REXBURG ANDERSON #11 WEST AND11 0
ANDERSON #12 EAST AND NORTH AND12 0REXBURG
REXBURG ANDERSON #13 NORTH AND13 38
REXBURG ARCO #11 ARC11 37
REXBURG ARCO #12 ARC12 0
REXBURG ARCO #13 ARC13 15
REXBURG ASHTON #11 ASH11 t4
REXBURG BELSON #11 BLS11 2
REXBURG BELSON #12 BLS12 0
REXBURG BERENICE #21 BRN21 77
January - December 2018
Page 11 of 39
2018 Breaker Trip Operations (includes Major Events)
Y ROCKY MOUNTAIN
POIA'ER IDAHO
Service Quality Review
Operating
Area Circuit Name Circuit lD Operations Corrected
Operations
BERENICE #22 BRN22 4REXBURG
REXBURG CAMAS #11 cMs11 L6
CAMAS #12 CM512 20REXBURG
REXBURG CANYON CREEK # 22 CNY22 9
CNY21 4REXBURGCANYON CREEK #21
REXBURG DUBOTS #L1 DBS11 10
REXBURG DUBOTS #12 D8512 1
REXBURG EASTMONT #11 EST11 13
REXBURG EASTMONT #12 EST12 2
REXBURG EGIN #11 EGN11 7
REXBURG EGIN #12 EGN12 7
REXBURG HAMER #11 HMR11 9
REXBURG HAMER #12 HMR12 3
REXBURG MENAN #11 MNN11 1
REXBURG MENAN #12 MNN12 3
MENAN #13 MNN13 1REXBURG
REXBURG MILLER #11 MLL11 6
MILLER #12 MLL12 3REXBURG
REXBURG MOODY #11 MDY11 1
MOODY #12 MDY12 1REXBURG
REXBURG MOODY #13 MDY13 7
MDL11 62REXBURGMUDLAKE #11
REXBURG MUDLAKE #].2 MDL12 68
NWD11 4REXBURGNEWDALE #11
REXBURG NEWDALE #12 NWD12 0
NWD13REXBURGNEWDALE #13 8
REXBURG RENO #11 REN11 t4
REXBURG RENO #12 REN12 7
REXBURG RENO #13 REN13 7
REXBURG REXBURG #11 RXB11 9
REXBURG REXBURG #12 RXB12 8
REXBURG REXBURG #13 RXB13 53
REXBURG f1.4 RXB14 1REXBURG
REXBURG REXBURG #15 RXB15 L
REXBURG REXBURG #16 RXB16 5
REXBURG RIGBY #11 RGB11 2
REXBURG RIGBY #12 RGB12 0
RGB13 2REXBURGRIGBY #13
REXBURG RIGBY #14 RGB14 1
RtRtE #12 RIR12 0REXBURG
REXBURG ROBERTS #11 RBR11 2
ROBERTS #12 RBR12 5REXBURG
REXBURG RUBY #11 RBYl].5
REXBURG SANDUNE #21 SDN21 9
REXBURG SANDUNE #22 SDN22 0
REXBURG sMtTH #11 SMT11 0
REXBURG sMrTH #12 SMT12 7
REXBURG SMITH #13 SMT13 0
January - December 2018
Page 12 of 39
2018 Breaker Trip Operations (includes Major Events)
3 ROCKY MOUNTAINffiB-"IDAHO
Service Quality Review
Operating
Area Circuit Name Circuit lD Operations Corrected
Operations
REXBURG sMtrH #14 SMT14 9
REXBURG SOUTH FORK #11 IDAHO PACIFIC POTATO SFKl].0
SOUTH FORK #13 ANTELOPE FLATS SFK13 36REXBURG
REXBURG ST ANTHONY #11 sTA1L 1
ST ANTHONY #12 STA12 7REXBURG
REXBURG ST ANTHONY #13 STA13 4
SGR11 0REXBURGSUGAR CITY #11
REXBURG SUGAR CITY #1"2 sGRL2 3
REXBURG SUGAR CIW #13 SGR13 9
REXBURG SUGAR CITY f14 SGR14 0
REXBURG SUNNYDELL #11 SNN11 0
SUNNYDELL #12 SNN12 423 8REXBURG
REXBURG TARGHEE #11 TRG11 0
TARGHEE #12 TRG12 7REXBURG
REXBURG THORNTON #11 THR11 5L
THORNTON #12 THR12 29REXBURG
REXBURG WATKINS #11 NORTH AND EAST WTK11 13
WEBSTER #11 EAST AND SOUTH WBS11 58REXBURG
REXBURG WEBSTER #12 NORTH WBS12 24
WEBSTER #14 WBS14 22REXBURG
REXBURG WINSPER #21 WNS21 5
WN522 5REXBURGWINSPER #22
SHELLEY AMMON #11 AMM11 8
AMMON #12 AMM12 1SHELLEY
SHELLEY Cinder Butte #11 ctBL1 24
ctBL3 17SHELLEYCINDER BUTTE #13
SHELLEY Cinder Butte #17 ctB17 29
CLE11 283 5SHELLEYCLEMENTS #1.1
SH E LLEY CLEMENTS #12 CLE12 4
SHELLEY GOSHEN #11 GSH].].3
SHELLEY GOSHEN #12 GSH12 1
SHELLEY GOSHEN #13 GSH13 5
SHELLEY HAYES #11 HYS11 384 9
HYS12SH E LLEY HAYES #12 4959 4
SHELLEY HAYES #13 HYS13 5
HPS11SHELLEYHOOPES #11 WEST 45
SHELLEY HOOPES #12 NORTH HP512 29
IDF11 1SHELLEYIDAHO FALLS #11
SHELLEY IDAHO FALLS f12 IDF12 2
IDF13 2SHELLEYIDAHO FALLS #13
SHELLEY IDAHO FAL6 #14 IDF14 1.
JEFFCO #21 JFF27 82SHELLEY
SHELLEY JEttco #22 JFF22 6
SHELLEY KETTLE #21 KTT21 15
SHELLEY KETTLE #22 KIT22 10
SHELLEY MERRILL #11 MRR11 8
SHELLEY MERRILL #12 MRR12 5
SHELLEY MERRILL #13 MRR13 5
January - December 2018
Page 1.3 of 39
2018 Breaker Trip Operations (includes Major Events)
\
ROCKY MOUNTAIN
BglYEn*"
IDAHO
Service Quality Review
Operating
Area Circuit Name Circuit lD Operations Corrected
Operations
MERRILL #14 MRR14 5SHELLEY
SHELLEY oscooD #11 osc11 7L
SHELLEY oscooD #12 osc12 0
osGooD #13 OSG13 24SHELLEY
SHELLEY oscooD #14 osc14 45
SANDCREEK #11 SND11 0SHELLEY
SHELLEY SANDCREEK #12 SND12 1
SHELLEY SANDCREEK #13 SND13 0
SHELLEY SANDCREEK #14 SND14 t4
SANDCREEK #15 SND15 0SHELLEY
SHELLEY SANDCREEK #16 SND16 4
SHL11.13SHELLEYSHELLEY #11
SHELLEY SHELLEY #12 SHL12 0
SHELLEY #13 SHL13 902 10SHELLEY
SHELLEY SHELLEY #14 SHL14 0
SHELLEY ucoN #11 UCN11 9
SHELLEY ucoN #12 UCN12 13
WTK12 1SHELLEYWATKINS #12 SOUTH THEN EAST
January - December 2018
Page 14 of 39
2018 Breaker Trip Operations (includes Major Events)
Y IDAHO
Service Quality Review
January - December 2018
2.4 Reliability History
Depicted below isthe historyof 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. Sincethedevelopmentofthisfoundational information,theCompanyhasbeeninapositionto
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.
tdaho Reliability History - lncluding Major Events
ISAIDI ICAIDI +SAIFI
2.9
1.9 2.92
0 0
2m8 2m9 2010 20LL 20t? 2013 20L4 201s 20L6 2017 2018
ROCKY MOUNTAIN#s-"
an
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3
ldaho Reliabitity History - Excluding Major Events
ISAIDI ICAIDI +SAIFI
2.2
2008 2009 2010 2011 20L2 2013 20L4 2015 20L6 20L7 2018
300
250
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Page 15 of 39
Y ROCKY MOUNTAINm*"IDAHO
Service Quality Review
January - December 2018
2.5 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 2.6. 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
outages6. 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 365-
day basis. Analysis of the trends displayed in the charts below shows a general improving trend for all charts. ln
orderto also focus on non-controllable outages, the Company has continued to improve its resilience to extreme
weather using such programs as its visualassurance 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.
tdaho 355-Day Rolling Controllable Historyas Reported
t, I t
1
90 0.9
0,8
o.7
0.6
o
o.s g
ra
0.4
0,3
o,2
0.1
80
70
-60o5.s
=s0oe6to
30
20
10
0 0
Jan-2007 ,an-20o9 Jan-2fi)9 Jan-2010 .lan-2011 Jan-2012 Jan-2013 Jan-2014 ,an-2015 Jan-2016 .lan-2017 lan-2018
Stress period
-s/[|Dt -S0qlH -Unear
(SAlDll
5 3. The Company shall provide, as an appendix to its Service Quality Review reports, information regarding non-controllable outages, including when
applicable, descriptions of efforts made by the Company to improve service quality and reliability for causes the Company has identified as not controllable.
4. The Company shall provide a supplemental filing, within 90 days, consisting of a process for measuring performance and improvements for the non-
controllable events.
Page 15 of 39
MOUNTAIN !DAHO
Service Quality Review
January - December 2018
tdaho 365-Day Rolling NonControllable History as Reported
:m0
250
2(x,
150
1@
50
3
2,5
2
o:
.E
=o
Eor.s &
=
1
0.5
Jan-2007 Jan-2008 .lan-2009 .lan-2010 Jan-2OU Jan-2OUl J.n-2013 Jan-2014 Jan-2015 Jan-2016 J.n-2017 Jan-2018
sress pe?iod
-s/{DN -tNFl -tinear
(sAlDl}
{
I
ldaho 355-Day Rolling Underlying Historyas Reported
3m 3
250 2.5
2m 2
o
=E
=o
150
Eo
r.s E
r
1m 1
50 0.5
0 0
Jan-2007 Jan-20O8 Jan-2009 Jan-2010 J.n-20U Jan-2012 Jan-2013 Jan-20r.4 Jan-2015 J.n-2016 Jan-2017 Jan-2018
Str$s period
-SAtDt -SAtFt -tinear
(SA|DD
il il ilITi I
I
r
Page L7 of 39
W
0 0
V,ROCKY MOUNTAINYPo1AIER\ ^ m,s,or o. ry*.roc,
IDAHO
Service Quality Review
January - December 2018
2.6 Cause Code Analysis
The tables below outline categories used in outage data collection. Subsequent charts and table use these
grou to develo for outa erformance
Direct Cause
Category Category Definition & Example/Dlrect 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 Mortality (Protected speciesXBMTS)
o Bird Nesto Bird or Nest. Bird Suspected, No Mortality
ContaminationorAirborneDeposit(i.e.salt,tronaash,otherchemical dust,sawdust,etc.); corrosive
environmenU 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
o Major Storm or Disastero Nearby Fault
o Pole Fire
. Condensation/Moisture. Contaminationo Fire/Smoke (not due to faults)
o Flooding
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.9., broken conductor hits another line).
Equipment
Fallure
o B/O Equipment
e Overload
o Deterioration or Rotting
o 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/Contractoro Vehicle Accident
o Dig-in (Non-PacifiCorp Personnel)
o Other lnterfering Object
o Vandalism or Theft
Failure of supply from Generator or Transmission system; failure of distribution substation equipment.Loss of
Supply o Failure on other line or station
o Loss of Feed from Supplier. 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.
Operational
. Contact by PacifiCorp
o Faulty lnstall
o lmproper Protective Coordination. lncorrect Records
o lnternal Contractor
o lnternal Tree Contractorr Switching Error. Testing/Startup Erroro Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons.Other
o lnvalid Code
o Other, Known Cause
r 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
. Constructionr Customer Notice Given. Energy Emergency lnterruption
o lntentional to Clear Trouble
. Emergency Damage Repair
o Customer Requested
o Planned Notice Exempt
o 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
o Wind
. Lightningo Rain
o Snow, Sleet, lce and Blizzard
Page 18 of 39
3ROCKY MOUNTAIN#n*"IDAHO
Service Quality Review
January - December 2018
2.6.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.
Direct Cause Customer Minutes
Lost for Incident
Customers In
lncident Sustained
Sustained
lncident Count SAIDI SAIFI
928,147 5,765 158 11.60 0.072ANIMALS
0.014BIRD MORTALITY (NON-PROTECTED SPECIES)247,O82 7,t46 124 3.09
BIRD MORTALITY (PROTECTED SPECIES) (BMTS}100,L79 524 28 1.25 0.007
307 3 3 0.00 0.000BIRD NEST (BMTS)
92,916 7,087 72 1.16 0.014BIRD SUSPECTED, NO MORTALIW
ANIMAI.S 1,35&632 8,525 389 L7.tt 0.107
FIRE/SMOKE (NOT DUE TO FAULTS)721,779 322 5 1.52 0.004
L21.,779 322 5 1.52 0.m4ENVIRONMENT
727,329B/O EQUIPMENT 7,774 148 1.59 0.014
DETERIORATION OR ROTTING 7,342,046 9,552 644 76.77 0.119
33,633 1,505 6 o.42 0.019OVERLOAD
601.499 4,289POLE FIRE 39 7.52 0.054
EqUIPMENT FAII.URE 2,LfJd,SO7 16,460 837 26.31 0.205
DIG-IN (NON-PACIFICORP PERSONNEL}55,275 367 33 0.82 0.00s
51.,687 683 22 0.65 0.009OTHER INTERFERING OBJECT
99,398 800 7 7.24 0.010OTHER UTILITY/CONTRACTOR
VANDALISM OR THEFT 20,294 275 1 0.25 0.003
VEHICLE ACCIDENT 7,409,407 8,622 78 17.62 0.108
1,645,002 10,587 0.134INTERFERENCEt4l20.s7
LOSS OF GENERATOR 160,002 7,727 3 2.00 0.014
LOSS OF SUBSTATION 7,234,963 9,702 14 15.44 0.127
2,265,764 29,O45 725 28.31 0.363LOSS OF TRANSMISSION LINE
IOSS OF SUPPTY 3,660,129 39,874 142 45.75 0.498
FAULTY INSTALL 422 5 3 0.01 0.000
944 11 1 0.01 0.000IM PROPER PROTECTIVE COORDI NATION
61INCORRECT RECORDS I 1 0.00 0.000
PACIFICORP EMPLOYEE . FIELD 29 1 1 0.00 0.000
OPERATIONAT 1/055 18 6 0.02 0.000
63,488 486 31 o.79 0.006OTHER, KNOWN CAUSE
UNKNOWN 470,357 4,454 293 5.88 0.061
OTHER 533,845 5,340 324 6.67 0.067
7,924 87 10 0.10 0.001CONSTRUCTION
3,019.096CUSTOMER NOTICE GIVEN 13,627 235 37.74 0.170
CUSTOMER REQUESTED 27,879 466 7 0.35 0.006
EMERGENCY DAMAGE REPAIR 294,545 3,164 88 3.68 0.040
279,874 1.60s 10 2.75 0.020INTENTIONAL TO CLEAR TROUBLE
L40,926 1,655 t2 t.76 0.027PLANNED NOTICE EXEMPT
92,397TRANSMISSION REQUESTED 954 7 1.15 0.012
PLANNED 3,802,s1s 21,558 359 47,53 0.259
TREE. NON-PREVENTABLE 365,628 2,972 87 4.57 0.037
25,596 186 16 0.32 0.002TREE. TRIMMABLE
39t,224 3,158 103 4.8r!'0.039TREES
FREEZING FOG & FROST 2,705 23 7 0.03 0.000
446 4 1 0.01 0.000tcE
349,424 4,010 101 4.37 0.050LIGHTNING
SNOW, SLEET AND BLIZZARD 15,853 106 19 0.20 0.001
WIND 850,840 6,311 153 10.63 o.o79
WEATHER 1,218,668 10,454 275 15.23 0.131
L4,A$,757 116,396 2,59r 185.50 1.455ldaho lncluding Prearranged
ldaho Excluding Prearranged 11,660,91s 100,648 2,t 7 t4s.75 1.2s8
Note: Oirect Causes are not listed if there were no outages classified within the cause during the reporting period.
Page 19 of 39
tdaho Cause Analysis - Underlyingtltlz0tS - tzlS1.lz0tg
Y IDAHO
Service Quality Review
January - December 2018
2.6.2 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!
I LOSS OF SUPPLY
3t%
I INTERFERENCE
t4%r OPERATIONAL
0%
ROCKYPol't'ER MOUNTAIN
Y EQUIPMENT
FAILURE 18%
I ENVIRONMENTO%
E ANIMALS 12%
Y OTHER5%
Y PLANNED5%
II TREES 3%
Y WEATHER 11%
Cause Analysis - Customer lnterruptions (SAlFl!
E LOSSOF
SUPPLY 40%I INTERFERENCE
tt%
T ANIMALS9%
I ENVIRONMENTO%
Y WEATHER 10%
U TREES 3%
Y PLANNED6%
Y OTHER 5%r EQUIPMENT
FAILURE 16%
r OPERATIONAL
o%
Cause Analysis - Sustained lncidents
I ANIMALS 17%
Y WEATHER 12%
I' OTHER 14%
Y PLANNED5%
r.l TREES 4%
I OPERATIONALO%
I LOSSOFSUPPLY6%
I INTERFERENCE 4%
E EQUIPMENT
FAILURE 36%r ENVIRONMENT
o%
Page 20 of 39
Y IDAHO
Service Quality Review
January - December 2018
2.7 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 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.
2.7.L Reliabiliff 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.
2.7.2 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.
ROCKY MOUNTAIN
EglyEn*,
Page 21 of 39
\
ROCKY
Po\A'ER
MOUNTA!N IDAHO
Service Quality Reviewarc&c&rrc@P
January - December 2018
2.7.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln 2072 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 20t2, 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 1.2/31/2011)
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 leasl20% against baseline performance. Those
program years which have met their target scores are removed from the listing below.
Relia bilitv Performa nce I mprovement ( post 1213 1/2011 th roueh 1213 1/2016)
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.
Effectiveness Metrics ln Progress
Plans
Meeting
Goals (>1
year since
proiect
completionl
Estimated
Avoided
annual
cMt
Actual
Avoided
annual
cMt
Budgeted
Cost per
annual
avoided
cMt
Actual
Cost per
annual
avoided
cMt
Plans Not
Meeting
Goals (not
induded in
metrics)
Plans
waiting for
information
Lava 7 Sr.zo 0 0 7
Montpelier 3 S3.5s 7 230 230 Sae.gs So.sg 0 2
Preston 8 So.ga 7 77,542 3s,084 Sr.rs So.ss 0 7
Rexburg 6 S3.8s 2 27,992 47,303 Sa.sg s2.38 1 3
Shelley 10 5t.42 4 70,747 779,230 S1.69 So,sz 0 6
Total 28 s1.70 8 116,511 26t,847 Sz.se So.zz 1 19
Page 22 of 39
2016 - 2018 District Projects
Approval Metrics
District Project
count
Budgeted
CosVCMt
\
ROCKY
PO\A'ER
MOUNTAIN IDAHO
Service Quality Review
(lmprovement targets for circuits in Program Years 1-l.L and 13-L5 have been met and filed in prior reports.)
January - December 2018
PROGRAM YEAR 17 (RPl) Method
Clifton 11(Figure 3C)IN PROGRESS 225 109
COMPLETE 195 106Dubois 12 (Figure 4C)
TARGET SCORE = 189 Goal Met 210 LO7
PROGRAM YEAR 16
Lava 11 (Figure 1C)COMPLETE 727 66
COMPLETE 36 72Preston 11 (Figure 2C)
TARGET SCORE = 73 Goal Met 82 69
PROGRAM YEAR
COMPLETED 724 t7Grace 12
Preston 13 COMPLETED t02 135
Goa! Met 113 76TARGET SCORE = 90
Page 23 of 39
TDAHO WORST PERFORMING
CIRCUITS STATUS BASELINE PERFORMANCE
t2l3tl20t8
Region Performance tndicator 2012 (RPl12) Method
PROGRAM YEAR 15
Circuit Performance lndicator 2fi)5 (CP!051 Method
\
ROCKY
PO,I/ER MOUNTAIN IDAHO
Service Quality ReviewAN'sSESTqP
2.8 Geographic Outage History of Under-performing Areas
Figure 1A: lava 11 Controllable View
January - December 2018
"l-ILUIT| -- I i
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Page 24 of 39
t
,l*b
VROCKY MOUNTAINKPowER! ^@'srdG4r.[@t
IDAHO
Service Quality Review
Figure 18l Lava 11 Non-Controllable View
January - December 2018
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Page 25 of 39
Lgimil'g tEdhg! :016{r-01 0
MOUNTA!N IDAHO
Service Quality Review
, D'nrubn Ue
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Figure lC: Lava 11 Underlying View excluding Loss of Supply
January - December 2018
Page 26 of 39
-(
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12.68
\
ROCKY MOUNTAIN
BSHTEB*"
IDAHO
Service Quality Review
Figure 2A: Preston 11 Controllable View
January - December 2018
T
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Page27 of39
't
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t
3 ROCKY
POVTIER
MOUNTA!N IDAHO
Service Quality Review
Figure 28: Preston 11 Non-Controllable View
January - December 2018
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Page 28 of 39
3 ROCKY MOUNTAIN
F,lolflER !DAHO
Service Quality Review
Figure 2C: Preston 11 Underlying View excluding Loss of Supply
January - December 2018
I
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Page 29 of 39
120765,.1 ! rt6,rr7
r3918
I
I
R
MOUNTAIN IDAHO
Service Quality Review
Figure 3A: Clifton 11 Controllable View
January - December 2018
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Page 30 of 39
Id+
VROCKY MOUNTAIN-<lPovt ER\ . m's,o* o. x,.,co"o
IDAHO
Service Quality Review
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Page 31 of 39
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Page 32 of 39
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Figure 4A: Dubois 12 Controllable View
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Page 33 of 39
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Service Quality Review
Figure 48: Dubois 12 Non-Controllable View
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Page 34 of 39
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Service Quality Review
Figure 4C: Dubois 12 Underlying View excluding loss of Supply
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Page 35 of 39
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Service Quality Review
2.9 Restore Service to SOTo of Customers within 3 Hours
2.10 Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
custometguaranrees
January - December 2018
January to December20l8
Jan uary February March April May June
99%98%9s%97%85%62%
July August September October November December
97%95%87%95%97%76%
PS5-Answer calls within 30 seconds 80%82%
PS6a) Respond to commission complaints within 3 days 95%700%
PS6b) Respond to commission complaints regarding service disconnects
within 4 hours 95%700%
9s%t00%PS6c) Resolve commission complaints within 30 days
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Overall Customer Guarantee performance remains above 99%, demonstrating Rocky Mountain Power's continued commitment to
customer satisfaction.
Major Events are excluded from the Customer Guarantees program.
Page 36 of 39
RESTORATIONS WITHIN 3 HOURS
Reporting Period Cumulative = 90%
COMMITMENT GOAL PERFORMANCE
Y IDAHO
Service Quality Review
January - December 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 Tvpes
Below are the definitions for interruption events. For further details, refer to IEEE 1356-2003120727 Standard for
Reliability lndices.
Sustoined 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 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 L366-200312012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliabilitv !ndices
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.
Daily 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 7366-20L2. This is the day's total customer minutes
outofservicedividedbythestaticcustomercountfortheyear. ltisthetotalaverageoutagedurationcustomers
experienced for that given day. When these daily values are accumulated through the year, it yields the yea/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.
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
7 IEEE 1366-2003/2012 was first adopted by the IEEE Commissioners on December 23,2003. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
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January - December 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).
MAlFle
MAIFIE (momentary average interruption event frequency index) is an industry standard index that quantifies
the frequency of all momentary interruption events that the average customer experiences during a given time-
frame. 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
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'r'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*0.029)+(3-yearSAlFl*0.30*2.439)+(3-yearMAlFl*0.20*0.70)
+ (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 38 of 39
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Service Quality Review
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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.
Mojor 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
u7-t2l3Ll2lt8 80,004 76.67 1,333,663
uL-L2l3Ll2O19 82,079 15.09 L,238,872
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 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 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 39 of 39
ROCKY MOUNTAIN
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