20180711Service Quality Report 2017.pdf

VA OVERNIGHT DELIVERY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise, D 83702
Re: CaseNo.PAC-E-04-07 ?n< - t2'DS- 08, Pqc - E^ li -o2--_
2017 Service Quality & Customer Guarantee Report for the period January I
through December 31, 2017
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, ("Company") hereby provides a copy of the
2017 Service Quality & Customer Guarantee report. This report is provided pursuant to a merger
commifrnent made during the PacifiCorp and ScottishPowerl merger. The Company committed to
implement a five-year Service Standards and Customer Guarantees program. The purpose 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 commitunent 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.
Sincerely,
ROCKY MOUNTAIN
HP,H.EN"^"
July 11, 2018
Ted Weston
Manager, Idaho Regulatory Affairs
Enclosures
Terri Carlock
Beverly Barker
I CaseNo. PAC-E-99-01
2 Case No. PAC-E-04-07
RECEIVED
2018 iUL I I AH 9: tr+
,ir: , ,.:-'r r/r:,.., . t'_1 -:LlU,i , :. :,-ilill,ilSSl0l_j
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
aoLl)nu*r-,'- ltva
cc:
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE AUALITY
REVIEW
January L - December 3L, 2OL7
Report
\
ROCKYPOVI'ER MOUNTAIN IDAHO
Service Quality Reviewa Dvr90 or mFEmP
January - December 2017
TABLE OF CONTENTS
TABLE OF CONTENTS.
EXECUTIVE SUMMARY
1 SERVICE STANDARDS PROGRAM SUMMARY
2.5 Controllable, Non-Controllable and Underlying Performance Review..........
2
3
3
3
4
5
7
8
9
2.L System Average lnterruption Duration lndex (SAlDl)
2.2 System Average lnterruption Frequency lndex (SAlFl)
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFl").........
2.4 Reliability History 13
L4
2.6.1 Underlying Cause Analysis Table
2.6.2 Cause Category Analysis Charts............
2.7.3 Reduce CPI for Worst Performing Circuits or Sub-circuits 20
2.8 Geographic Outage History of Under-performing Areas............ ................22
34
2.10 Telephone Service and Response to Commission Complaints 34
3 CUSTOMER GUARANTEES PROGRAM STATUS.......................34
4 APPENDIX:ReliabilityDefinitions 35
16
t7
18
Page 2 of 37
2.9 Restore Service to 80% of Customers within 3 Hours ............
3ROCKYPo\'\'ER MOUNTAIN IDAHO
Service Quality Review
January - December 2017
EXECUTIVE SUMMARY
Rocky Mountain Power has a number of Customer Service Standards and Service Quality Measures with
performance reporting mechanisms currently in place. These standards and measures define Rocky Mountain
Power's target performance (both personnel and network reliability performance) in delivering quality customer
service. The Company developed these standards and measures using relevant industry standards for collecting
and reporting performance data. ln some cases, Rocky Mountain Power has expanded upon these standards. ln
other cases, largely where the industry has no established standards, Rocky Mountain Power has developed
metrics, targets and reporting. While industry standards are not focused around threshold performance levels,
the Company has developed targets or performance levels against which it evaluates its performance. These
standards and measures can be used over time, both historically and prospectively, to measure the service quality
delivered to our customers.
1 SERVICE STANDARDS PROGRAM SUMMARY'
1.1 ldaho Customer Guarantees
Note: See Rules for a complete description of terms ond conditions for the Customer Guorontee Progrom.
1 On June 29, 2Ot2, 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 PaBe 4 of 15.
Page 3 of 37
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.
3 ROCKYPo\'I/ER MOUNTAIN IDAHO
Service Quality ReviewAdv60orrcFqP
L,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 t0Yo the reliability performance
indicator (RPl) on at least one area on an annual basis
within five years after selection) or by application of its
Open Reliability Reporting Program.
Network Performance Standard 4:
Supply Restoration
The Company will restore power outages due to loss of
supply or damage to the distribution system within three
hours to 80% of customers on average.
Customer Service Performance Standard 5:
Telephone Service Level
The Company will answer 80% of telephone calls within 30
seconds. The Company will monitor customer satisfaction
with the Company's Customer Service Associates and
quality of response received by customers through the
Company's eQuality monitoring system.
Customer Service Performance Standard 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.
Page 4 of 37
January - December 2017
Y ROCKY MOUNTAIN
Hgly,E#*,
IDAHO
Service Quality Review
January - December 2017
2 RETIABITITY PERFORMANCE
For the reporting period, the Company experienced underlying interruption duration (SAlDl) and interruption
frequency (SAlFl) performance in ldaho that was unfavorable to plan. Results for ldaho underlying performance
can be seen in subsections 2.1 and 2.2 below.
Major Event General Descriptions
Two events during the reporting period met the Company's ldaho major event threshold level2 for exclusion from
underlying performance results.
March L8, 2O\7: Shelley, ldaho, experienced an outage when a potential transformer (PT) at the
Sugarmill substation failed. The failed PT damaged the operate bus causing several other circuit breakers
in the substation to be de-energized. The event affected three substations, feeding 10 circuits, serving
L6,L6L customers, for durations ranging from L hour 45 minutes to 2 hours 19 minutes.
November 78,20L7: portions of SW Wyoming, Northern Utah, and South Eastern ldaho experienced a
loss of transmission line event when the static line on the 69 kV line failed. The event affected three
transmission substations, feeding 14 distribution substations, serving 18 circuits, suppling power to
9,500 customers. ln ldaho the event met the major event threshold with approximately 4,800 customers
in Montpelier out of power. Outage durations for these customers ranged from 6 hours 45 minutes to
12 hours 36 minutes.
2 Malor event threshold shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lostllr-72/37/2or7 78,594 16.56 r,3O1,M7
a
a
Date Cause SAIDI
March 18,2017 Loss of Substation 23.25
November t8,2Ot7 Loss of Transmission 45.57
Page 5 of 37
Major Events
3 IDAHO
Service Quality Review
January - December 2017
Significant Events
Significant event days add substantially to year on year cumulative performance results; fewer significant event
days generally result in better reliability for the reporting period, while more significant event days generally
mean poorer reliability results. During the reporting period eleven significant event days3 were recorded, which
account for 65 SAIDI minutes; about 53o/o of the reporting period's underlying 193 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 MOUNTAIN
HgYEfu,
Date Cause: General Description Event SAIDI % of Total sAlDl
January 6,2OL7 Loss of transmission Line 4.55 3.7%
January l1-,2017 Loss of transmission Line - snow storm 6.L4 5.O%
March 11,2017 Loss of transmission Line - BPA 5.77 4.7%
April8,2Ot7 Pole fire/Snow storm 12.45 L0.Lo/o
Apri! 18,2017 Loss of transmission Line 11.35 9.2%
May24,20L7 Wind storm s.29 4.3%
lune12,2017 Loss of Substation 4.7t 3.8%
luneL4,2OL7 Loss of transmission line due to car hit pole 4.93 4.O%
lune22,2OL7 Loss of transmission Line 5.37 4.3%
lune24,2Ol7 Loss of transmission Line 4.47 3.6%
December 4, 2017 Equipment Failure - downed line 7.82 4.L%
TOTAT 72.84 37.8%
3 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results.
Page 6 of 37
Significant Event Days
3 ROCKY MOUNTAIN
POYI'ER NMOf re@P
IDAHO
Service Qualiry Review
Actual
(reporting period)
Plan
(year-end)
267Total (major event included)
193 160Underlying (major event excluded)
Controllable 49.2
January - December 2017
2.t System Average lnterruption Duration lndex (SAlDl)
The Company's underlying interruption duration performance for the year was unfavorable to plan.
280
260
240
220
200
180
150
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Page 7 of 37
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3 ROCKY MOUNTAIN
POvt,ER IDAHO
Service Quality Review
Actual
(reporting period)
Plan
(year-end)
2.46LTotal (maior event included)
2.193 L,4TLUnderlying (major event included)
Controllable 0.373
January - December 2017
2.2 System Average lnterruption Frequency Index (SAIF!)
The Company's underlying interruption frequency performance results for the year are unfavorable to plan.
2.6
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(excludes Prearranged and Customer Requested)
Page 8 of 37
A OVISTS OF rcrFr@rP
IDAHO
SA!FI
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aot
\
IDAHO
Service Quality Review
January - December 2017
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFle)
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" performance.
ln the table below, all circuits 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 lndian Creek #11: high trip counts are a result of narrow framed structures and floaters which has been
identified by field engineers. A reliability work plan is in place to correct these issues and work should be
completed by end of year 201,8.
o Raymond #11: the circuit breaker log shows a total of 27 trips occurred in 2OL7.lt appears a recording
error occurred which has been corrected.
o Arco #13: The circuit breaker log showed a total of 25 trips between December 2016 and December
2OL7. LG of these trips were the result of a damaged jumper outside the substation, which has since been
repaired. The system recording error has been corrected in the system.
r Sanddune#2L: Trip counts are the result of underground cable failures that have been repaired or
replaced. Field personnel continue to closely monitoring several additional underground sections of
cable.
o Hoopes #12: the circuit breaker log shows a total of 51 trips from April 2017 to March 2018. lt appears a
recording error occurred which has been corrected.
4 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 Frequenry lndex (MAlFt) 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 willfile 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 meetings.
Page 9 of 37
ROCKY MOUNTAIN#A"
Operating Area MAIFI" (SCADA)
Montpelier Not applicable
Preston o.L24
Rexburg 0.723
Shelley 0.928
Circuit Name Circuit lD Operations Corrected
Operations
Operating
Area
MONTPELIER ALEXANDER #11 ALX11 4
ARTMO #11 ARM11 2MONTPELIER
MONTPELIER ARTMO #12 ARM12 47
BANCROFT #11 BAN11 4MONTPELIER
MONTPELIER BANCROFT #12 BAN12 2
MONTPELIER CHESTERFIELD #11 CHS11 9
cHs12 7MONTPELIERCHESTERFIELD #12 HATCH
MONTPELIER covE #12 cov12 26
EIGHT MILE #11 EGT].1 9MONTPELIER
MONTPELIER GEORGETOWN #].1 GRG11 5
GCE11 20MONTPELIERGRACE #11
January t throuch December ?t.2OL7
2017 Breaker Trip Operations (includes Maior Events)
Y ROCKY MOUNTAINm"!DAHO
Service Quality Review
Circuit NameOperating
Area Circuit lD Operations Corrected
Operations
MONTPELIER GRACE #12 GCE12 LL
HENRY #11MONTPELIER HRY11 0
MONTPELIER HORSLEY #11 HRS11 L4
INDIAN CREEK #11MONTPELIER IND11 56 56
MONTPELIER LAVA #11 LVA11 1
MONTPELIER LUND #11 LND11 5
MONTPELIER MCCAMMON #11 MCC11 8
MONTPELIER MCCAMMON #12 MCC12 26
MONTPELIER MONTPELIER #11 MNT11 0
MONTPELIER MONTPELIER #13 MNT13 1
MONTPELIER MONTPELIER #14 MNT14 1
MONTPELIER RAYMOND #11 NORTH TO GENEVA RAY11 51 27
MONTPELIER RAYMOND #12 SOUTH TO PEGRAM RAY12 L2
MONTPELIER ST CHARLES #11 STC11 6
PRESTON CLIFTON #11 DAYTON & BANIDA CLF11 4
PRESTON cLt FTON #12 CLt FTON/OXFORD/SWAN LAKE CLF12 1.
PRESTON DOWNEY #11 DWN11 11
PRESTON DOWNEY #12 DWN12 1
PRESTON HOLBROOK #11 HLB11 4
PRESTON MALAD #11 MLD11 7
MALAD #12PRESTON MLD1.2 6
PRESTON MAI.AD #13 MLD13 4
PRESTON #11PRESTON PRS11 0
PRESTON PRESTON #12 PRS12 1
TANNER #11 MINK CREEKPRESTON TNR11 5
PRESTON TANNER #12 RIVERDALE/TREASURETON TNR12 2
WESTON #12 NORTH TO DAYTONPRESTON WST12 2
PRESTON wEsToN#11 SOUTH - WESTON/FA|RVEW WST11 2
ANDERSON fl1 WESTREXBURG AND11 t
REXBURG ANDERSON #1.2 EAST AND NORTH AND12 1
ANDERSON #13 NORTHREXBURG AND13 5
REXBURG ARCO #11 ARC11 1
REXBURG ARCO #12 ARC12 0
REXBURG ARCO #13 ARC13 51 25
REXBURG ASHTON #11 ASH11 32
REXBURG BELSON #11 BLS11 2
REXBURG BELSON #12 BLS12 1
REXBURG BERENICE #21 BRN2].3
REXBURG BERENICE #22 BRN22 25
REXBURG CAMAS #11 CMS11 3
REXBURG CAMAS fi12 CMS12 5
REXBURG CANYON CREEK # 22 CNY22 1
REXBURG CANYON CREEK #21 CNY21 1
REXBURG DUBOTS #11 DBS11 t2
REXBURG DUBOIS #12 DBS12 2
REXBURG EASTMONT #11 EST11 4
REXBURG EASTMONT #].2 EST1.2 1
REXBURG EGIN #11 EGN].1 L
REXBURG EGIN #12 EGN12 1
HAMER #11REXBURG HMR11 4
REXBURG HAMER #12 HMR12 1
REXBURG MENAN #11 MNN11 2
REXBURG MENAN #12 MNN12 1
January - December 2017
Page 10 of 37
2017 Breaker Trip Operations (includes Maior Eventsl
\
ROCKY MOUNTAIN##*,
Circuit lD OperationsOperating
Area Circuit Name Corrected
Operations
REXBURG MENAN #13 MNN13 1
MLL11 t4REXBURGMILLER #11
REXBURG MILLER #12 MLL12 2
REXBURG MOODY #11 MDY11 2
REXBURG MOODY #12 MDY12 8
REXBURG MOODY #13 MDY13 16
REXBURG MUDLAKE f11 MDL11 1
MDL12REXBURGMUDLAKE S12 3
REXBURG NEWDALE #11 NWD11 6
REXBURG NEWDALE #12 NWD1.2 3
REXBURG NEWDALE #13 NWD13 11
REXBURG RENO #11 REN11 1L
RENO #12 REN12 6REXBURG
REXBURG RENO #13 REN13 10
REXBURG #11 RXB11 3REXBURG
REXBURG REXBURG #12 RXB12 1
REXBURG #13 RXB13 4REXBURG
REXBURG REXBURG #14 RXB14 7
RXB15REXBURGREXBURG #15 2
REXBURG REXBURG #16 RXB16 1
RGB11 0REXBURGRIGBY #11
REXBURG RIGBY #12 RGB12 1
RGB13 8REXBURGRIGBY #13
REXBURG RIGBY #14 RGB14 3
RIR12 1REXBURGRtRrE #L2
REXBURG ROBERTS #11 RBR11 3
RBR12REXBURGROBERTS #12 3
REXBURG RUBY #11 RBY11 2
SDN21 51 51REXBURGSANDUNE #21
REXBURG SANDUNE #22 SDN22 1
SMT11 1REXBURGsMtTH #11
REXBURG sMtTH #12 SMT12 0
REXBURG sMtTH #13 SMT13 49
REXBURG sMtTH #14 SMT14 0
REXBURG SOUTH FORK #11 IDAHO PACIFIC POTATO sFKr.1 10
REXBURG SOUTH FORK #13 ANTELOPE FLATS SFK13 8
REXBURG ST ANTHONY #11 STA11 3
ST ANTHONY f12 STA12 4REXBURG
REXBURG ST ANTHONY #13 STA13 0
REXBURG SUGAR CITY #11 SGR11 4
SGR1,2 LREXBURGSUGAR CITY #12
REXBURG SUGAR CITY #13 SGR13 2
SUGAR CITY #14 SGR14 4REXBURG
REXBURG SUNNYDELL #11 SNN11 3
SUNNYDELL #12 SNN12 5REXBURG
REXBURG TARGHEE #11 TRG11 5
TARGHEE #12 TRG12 16REXBURG
REXBURG THORNTON f11 THR11 8
THORNTON S12 THR12 9REXBURG
REXBURG WATKINS S11 NORTH AND EAST WTK11 2
WEBSTER #11 EAST AND SOUTH WBS1l tREXBURG
REXBURG WEBSTER #12 NORTH WBS12 7
WEBSTER #14 WBS14 2REXBURG
January - December 2017
Page 11" of 37
IDAHO
Service Quality Review
2017 Breaker Trip Operations (includes Maior Eventsl
\
ROCKY MOUNTAINms*"IDAHO
Service Quality Review
January - December 2017
Circuit lD Operations Corrected
Operations
Operating
Area Circuit Name
REXBURG WINSPER #21 WN521 3
WINSPER #22 WN522 0REXBURG
SH E LLEY AMMON #11 AMM11 3
AMM12 0SHELLEYAMMON #1.2
SH E LLEY Cinder Butte #11 ctB11 0
ctB13 0SH ELLEY CINDER BUTTE #13
SH E LLEY Cinder Butte #17 ctB17 2
CLE11 1SH E LLEY CLEMENTS #11
SH ELLEY CLEMENTS #12 CLE12 16
SH ELLEY GOSHEN #11 GSH11 8
SH ELLEY GOSHEN #12 GSH12 4
SHELLEY GOSHEN #13 GSH13 3
HAYES #11 HYS11 1SHELLEY
SHELLEY HAYES #12 HYS12 2
SH E LLEY HAYES #13 HYS13 1
SHELLEY HOOPES #11 WEST HPS11 0
SH E LLEY HOOPES #12 NORTH HPS12 865 51
SHELLEY IDAHO FALLS #11 IDF11 0
IDAHO FALLS #12 IDF72 3SH E LLEY
SHELLEY IDAHO FALLS #13 IDF13 0
IDF14 0SHELLEYIDAHO FALLS #14
SHELLEY JEFFCO #21 JFF2l 29
JFF22 7SH E LLEY JEFFCO #22
SH E LLEY KETTLE #21 KTT21 50
KETrLE#22 KIT22 1SH ELLEY
SH ELLEY MERRILL #11 MRR].1 3
MRR12 50SH ELLEY MERRILL #12
SH ELLEY MERRILL #13 MRR13 10
MRR14 8SH ELLEY MERRILL #14
SH E LLEY oscooD #11 OSG11 13
oscooD #12 OSG12 0SH E LLEY
SH ELLEY oscooD #13 OSG13 2
SH ELLEY oscooD #14 osc14 5
SH ELLEY SANDCREEK #11 SND11 0
SND12 1SH ELLEY SANDCREEK #12
SH ELLEY SANDCREEK #13 SND13 0
SANDCREEK #14 SND14 31SH E LLEY
SH ELLEY SANDCREEK #15 SND15 3
SND16 10SH ELLEY SANDCREEK f16
SH ELLEY SHELLEY #11 SH 111 0
SHELLEY #12 SH 112 4SH ELLEY
SH ELLEY SHELLEY #13 SH 113 6
SHELLEY #14 SHL14 11SH ELLEY
SHELLEY ucoN #11 UCN11 0
SHELLEY ucoN #12 UCN12 15
SHELLEY WATKINS #12 SOUTH THEN EAST WTK12 4
Page 12 of 37
2017 Breaker Trip Operations (includes Maior Eventsl
Y IDAHO
Service Quality Review
January - December 2017
2.4 Reliability History
Depicted below is the history of reliability in ldaho. ln2002, the Company implemented an automated outage
management system which provided the background information from which to engineer solutions for improved
performance. Since the development of this foundational information, the Company has been in a position to
improve performance, both in underlying and in extreme weather conditions. These improvements have
included the application of geospatial tools to analyze reliability, development of web-based notifications when
devices operate more than optimal, focus on operational responses via CAIDI metric analysis, in addition to
feeder hardening programs when specific feeders have significantly impacted reliability performance.
ldaho Reliability History - lncluding Major Events
ISAIDI ICAIDI +-SAIFI
2.9 3.0
6@
5m
4m
3(x)
2(D
1@
2.5
0
2m8 2009 20LO 20LL 20t2 2013 20L4 2015 20t6 20L7
ROCKY MOUNTAIN
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ldaho Reliability History - Excluding Major Events
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2m8 2009 2010 20LL 20L2 2013 20L4 2015 20t6 20L7
Ga, (no(h 00 <lON ar, <to+dl fn rfr\ri (D rno
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ISAIDI ICA]DI +SAIFI
Page 13 of 37
0
Y IDAHO
Service Quality Review
January - December 2017
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.
So, for example, animal-caused interruptions, as well as equipment failure interruptions have a less random
nature than lightning caused interruptions; other causes have also been determined and are specified in Section
2.5. Engineers can develop plans to mitigate against controllable distribution outages and provide better future
reliability at the lowest possible cost. At that time, there was concern that the Company would lose focus on
non-controllable outagess. ln order to provide insight into the response and history for those outages, the charts
below distinguish amongst the outage groupings.
The graphic history demonstrates controllable, non-controllable and underlying performance on a rolling 355-
day basis. Analysis of the trends displayed in the charts below shows a general improving trend for all charts. 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.
ldaho 365-Day Rolllng Controllable Hlstoryas Reported
lm-20o7 Jr-2@ ,s-2009 J.n-2010 Jm-2011 Jm-2012
Strcrs Period
-SAIII
Jm-2013 lm-2014 Jrn-2019 Jrn-2016 ).n-2O17
-nUH -tinc.?
(SAIOI
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 L4 of 37
ROCKY MOUNTAINm*"
1@
90
80
70
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6(640
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Y ROCKY
FIo\'I/ER MOUNTAIN IDAHO
Service Quality Review
.,I-
cte6
ldaho 355-Day Rolllng NonControllable Hlstoryas Reported
o
Jr-2@7 Jn-2008 ,lm-2009 Jrn-2010 lm-2011 .hn-20u Jm-2013 Jrn-2011 Jen-2019 lm-2016 ,l.n-2017
Strcss period _9{l0t _sAtH
-lJng11(sAlpll
tdaho 365-Day Rolllng Underlylng Hlstoryas Reponed
3
2.5
39,
250
2m
150
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,m
January - December 2017
2
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Jm-2007 Jr2008 Jm-2009 Jm-2010 Jm-2011 J.n-2012 ,lm-2013 l.n-2014 .lm-2015 ,i-2015 lm-2017
socss pedod _sAlu _sAlH olJ1g67 (sAlpll
Page 15 of 37
)
I
\
MOUNTAIN IDAHO
Service Quality Review
January - December 2017
2.6 Cause Code Analysis
The tables below outlines categories used in outage data collection. Subsequent charts and table use these
to deve for ance.
ROCKY
POVI'ER
A UV€fi Or rcf,t@at
Direct Cause
Category Category Definition & Example/Direct Cause
Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels or other animals,
whether or not remains found.
Animals
o Animal (Animals). Bird Mortality (Non-protected species). Bird Mortalitv (Protected species)(BMTS)
o Bird Nesto Bird or Nest
o Bird Suspected, No Mortality
Contamination or Airborne Deposit (i.e. salt, trona ash, other chemical dust, sawdust, etc.); corrosive
environmen! 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
. Major Storm or Disaster
o Nearby Faultr Pole Fire
o Condensation/Moisture. Contamination
o Fire/Smoke (not due to faults)r 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
Failure
o B/O Equipment
o Overload
. Deterioration or Rottingr Substation, Relavs
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/Contractor
o Vehicle Accident
o Dig-in (Non-PacifiCorp Personnel)
o Other lnterfering Objectr Vandalism orTheft
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
o Loss ofGenerator
o Loss of Substation
o Loss of Transmission Liner 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. Faulty lnstall
o lmproper Protective Coordination
o lncorrect Records
o lnternal Contractor
r lnternal Tree Contractoro Switching Error. Testing,/Startup Error
o Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons.Other
o lnvalid Code
o Other, Known Cause
o 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
o Construction
o Customer Notice Given. Energy Emergency lnterruption. lntentional to Clear Trouble
. Emergency Damage Repair. Customer Requestedr Planned Notice Exemptr Transmission Requested
Growing or falling treesTree
o Tree-Non-preventable
o Tree-Trimmable
r Tree-Tree felled by Logger
Wind (excluding windborne material); snow, sleet or blizzard, ice, freezing fog, frost, lightning.Weather
. Extreme Cold/Heat
o Freezing Fog & Frost
o Wind
. Lightning
o Rain
e Snow, Sleet, lce and Blizzard
Page 16 of 37
3 MOUNTAIN IDAHO
Service Quality Review
January - December 2017
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 lCustomer 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.
ROCKY
Pol/TIER
Dlrect Cause
Customer
Mlnutes Lost
for lncldent
customers
in lncident
Sustained
Sustained
lncident
Count
SAIDI SAIFI
ANIMALS 293,967 3,234 779 3.74 0.041
59,872BIRD MORTALITY (NON-PROTECTED SPECIES)664 116 o.76 0.008
BIRD MORTALITY (PROTECTED SPECIES) (BMTS}32,690 328 24 o.42 0.004
BIRD NEST (BMTSI 437 3 3 0.01 0.000
99,439BIRD SUSPECTED, NO MORTALITY t,278 77 7.27 0.015
ANIMALS 486,40s 5,U7 393 6.19 0.069
FIRE/SMOKE (NOT DUE TO FAULTS}728 7 3 0.00 0.000
128 1 3 0.00 0.000ENVIRONMENT
B/O EQUIPMENT 183,797 1,618 161 2.34 0.021
DETERIORATION OR ROTTING 2,902,262 t8,474 803 36.93 o.234
74,277 231 9 0.18 0.003OVERLOAD
577,O75POLE FIRE 3,762 22 7.34 0.048
EQUIPMENT FAILURE 3,577,N5 24,O2s 99s 46.79 0.306
DIG-IN (NON-PACIFICORP PERSONNEL}50,938 420 31 0.65 0.005
8,847 737 18 0.002OTHER INTERFERI NG OBJECT 0.11
OTHER UTILITY/CONTRACTOR 38,293 437 10 0.49 0.00s
VANDALISM OR THEFT 8s3 57 3 0.01 0.001
710,582 5,769 67 9.O4 0.073VEHICLE ACCIDENT
809,512INTERFERENCE 5,814 L29 10.30 0.087
LOSS OF FEED FROM SUPPLIER 6 1 7 0.00 0.000
LOSS OF SUBSTATION 819,086 8,832 26 10.42 o.772
4,679,568 83,612 250 59.54 1.064LOSS OF TRANSMISSION LINE
toss oF suPPt Y s,494,662 92,45 277 59.96 1,L76
FAULTY INSTALL 28 7 1 0.00 0.000
IMPROPER PROTECTIVE COORDINATION 48 1 1 0.00 0.000
43INCORRECT RECORDS 1 7 0.00 0.000
PACIFICORP EMPLOYEE - FIELD 87 1 1 0.00 0.000
OPERATIONAI 207 4 4 0.00 0.000
199,699 7,763 44OTHER, KNOWN CAUSE 2.54 0.022
UNKNOWN 1,156,159 77,299 399 74.77 o.744
OTHER 1,355,858 13,052 43 L7.25 0.156
77,297 328 15 0.22 0.004CONSTRUCTION
CUSTOMER NOTICE GIVEN 2,744,504 16,691 209 27.29 o.272
CUSTOMER REQUESTED 726 1 1 0.00 0.000
EMERGENCY DAMAGE REPAIR 489,839 8,690 728 6.23 0.111
35,519 551 13INTENTIONAL TO CLEAR TROUBLE 0.45 0.007
109,415PLANNED NOTICE EXEMPT 2,763 6 1.39 0.03s
PTANNED 2,796,700 29,034 372 35.58 0.369
TREE. NON-PREVENTABLE 257,158 7,780 58 3.27 0.023
279,975 3,623 20 3.56 0.046TREE. TRIMMABLE
537,133 5,403TREES 88 6.83 0.069
tcE 70,935 223 13 0.90 0.003
LIGHTNING 266,574 2,603 104 3.39 0.033
804,638 3,010 53 70.24 0.038SNOW, SLEET AND BLIZZARD
1.083.520WIND 9,734 797 73.79 0.724
WEATHER 2,225,ffi6 t5,57O 377 24.?2 0.198
ldaho lncluding PrearranEed 17,s47,617 191,805 3,081 22r.23 2,UO
15,133,572 L72,350 2,865 192.55 2.193ldaho Excluding Prearranged
Note: DirectCausesarenotlistediftherewerenooutagesclassifiedwithinthecauseduringthereportingperiod.
Page 17 of 37
ldaho Cause Analysis - Underlying0{OLl20LT - t2hU2O17
Y MOUNTAIN IDAHO
Service Quality Review
January - December 2017
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.
ROCKY
FIOYI'ER
Cause Analysis - Customer Minutes tost (SAlDll
C LOSSOFSUPPLY36%T INTERFERENCE 5%
r ANIMALS 3%
I ENVIRONMENTO%
Y WEATHER 15%
Y TREES4%
Y PLANNED4%
EqUIPMENT
FAILURE 24%l. OTHER9%
C OPERATIONALO%
Cause Analysis - Customer !nterruptions (SAlFll
3 LOSSOFSUPPLY54%
Y OTHER8%
r. PLANNED 5%
Y TREES 3%
T OPERATIONALO%
l. WEATHER 9%
INTERFERENCE 4%
E EQUIPMENT
FAILURE 14%
I ANIMALS 3%
! ENVIRONMENTO%
Cause Analysis - Sustained lncidents
C EQUIPMENT FAILURE 35%
Y WEATHER 13%
T ANIMALS 14%
I ENVIRONMENTO%
Y OTHER 15%
Y PLANNED6%
g TREES 3%
A OPERATIONALO%
I LOSSOFSUPPLY 10%
r INTERFERENCE 4%
Page 18 of 37
I
\
ROCKY
POT'T'ER
MOUNTAIN IDAHO
Service Quality Reviewa Dvr80 or rcrrsP
January - December 2017
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 shifts the Company's reliability program from a circuit or area-based view reliant on blended
reliability metrics (using circuit SAlDl, SAIFI and MAIFI) to a more strategic and targeted approach based upon
recent trends in performance of the local area, as measured by customer minutes interrupted (from which SAIDI
is derived). The decision to fund one performance improvement project versus another is based on cost
effectiveness as measured by the cost per avoided annual customer minute interrupted. However, the cost
effectiveness measure will not limit funding of improvement projects in areas of low customer density where
cost effectiveness per customer may not be as high as projects in more densely populated areas.
2.7.L Reliability Work Plans
The Company has worked to improve reliability through Reliability Work Plans. To assist in identification of
problem areas, Area lmprovement Teams (AlT) meetings and Frequent lnterrupters Requiring Evaluation (FIRE)
reports have been established. On a daily basis the Company systems alert operations and engineering team
members regarding outages experienced at interrupting devices (circuit breakers, line reclosers and fuses).
When repetition occurs, it is an indicator that system improvements may be needed. On a routine basis, local
operations and engineering team members review the performance of the network using geospatial and tabular
tools to look for opportunities to improve reliability. As system improvement projects are identified, cost
estimates of reliability improvement and costs to deliver that improvement are prepared. lf the project's cost
effectiveness metrics are favorable, i.e. low cost and/or high avoidance of future customer minutes interrupted,
the project is approved for funding and the forecast customer minutes interrupted are recorded for subsequent
comparison. This process allows individual districts to take ownership and identify the greatest impact to their
customers. Rather than focusing on a highly populated area with high improvement costs, districts can focus on
problem areas or devices and tactically target network improvements.
2.7.2 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 yea/s plans, and actual versus forecast
results are assessed to determine whether targets were met or if additional work may be required, as would be
depicted in the table below.
Page L9 of 37
\
ROCKY MOUNTAINPOI'YERlovrsooarcF@P
IDAHO
Service Quality Review
Effectlveness Metrics ln Progress
Plans
Meeting
Goals (>1
year since
project
completion)
Estimated
Avoided
annual
cMt
Actual
Avoided
annual
CML
Budgeted
Cost pel
annual
avoided
cMt
Actual
cost per
annual
avoided
cMt
Plans Not
Meeting
Goals (not
included in
metrics)
Plans
waiting for
information
Montpelier 9 s1.79 2 18,788 37,347 s2.90 So.80 1.6
Preston 13 s1.7s 5 319,151 976,29s s1.66 s0.67 0 8
Rexburg 8 s4.38 2 158,113 244,833 s2.31 So.sz 1 5
Shelley L2 s1.06 3 203,294 327,701 s1.23 s0.81 2 7
Total 42 s1.94 12 699,?46 1,596,176 $r.zr So.6s 4 26
20L5 -20t7 District Projects
January - December 2017
2.7.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln 2Ot2 the Company modified its previous program with regards to selecting areas for improvement. Delivery
of tools allowed more targeted improvement areas. As a result, the Service Standard Program was modified to
reflect this change. Prior to 2012, the company selected circuits as its most granular improvement focus; since
then, groupings of service transformers are selected, however, if warranted entire distribution or transmission
circuits could be selected. Since 2012, the Company has transitioned and further refined its approach to support
cost/benefit valuation for reliability improvements, which are a cornerstone of ORR, as discussed above.
Circuit Performance lmprovement (prior to 12131/2011)
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 least 20% against baseline performance. Those
program years which have met their target scores are removed from the listing below.
Reliabilitv Performance Improvement (post 1213U2011 throueh L2131/2016)
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.
Page 20 of 37
Approval Metrics
District Proiec
count
Budgeted
CosVCMt
Y ROCKYPOVI'ER MOUNTAIN IDAHO
Service Quality Reviewa Dvr96 or rcFrGP
(lmprovement targets for circuits in Program Years 1-11 and 13-15 have been met and filed in prior reports.)
January - December 2017
PROGRAM YEAR 17 (RPl) Method
Clifton 11 (Figure 3C)IN PROGRESS 22s 2L8
IN PROGRESS 195 167Dubois 12 (Figure 4C)
TARGET SCORE = 189 zLO t92
PROGRAM YEAR 15
Lava 11 (Figure 1C)COMPLETE 127 28
COMPLETE 36 52Preston 11 (Figure 2C)
TARGET SCORE = 73 Goal Met 82 40
PROGRAM YEAR 15
YEAR 12
COMPLETED 724 44Grace 12
Preston 13 COMPLETED 102 101
113 72TARGET SCORE = 90 Goal Met
Page 2L ol 37
IDAHO WORST PERFORMING
crRculrs STATUS BASELINE PERFORMANCE
t213112017
Region Performance lndicator 2012 (RHrz) Method
Circuit Performance lndicator 2005 (CPps) Method
Y ROCKY
POVT'ER
MOUNTAIN IDAHO
Service Quality Review
rE
ffiUpI !, in ilbr(don
I Oi*tut'or Sr*tnoo
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2.8 Geographic Outage History of Under-performing Areas
Figure 1A: Lava 11 Controllable View
January - December 2017
Page 22 of 37
I,J
L
il
Y ROCKYF'o\'IIER MOUNTAIN !DAHO
Service Quality ReviewA DVISS OT rcFI@P
UrtiLrtion Una!tSmbrtoE!u*a*o,:{mCtundl&llltt, iao<drtorit ly lgtta*..0
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Figure 18: Lava 11 Non-Controllable View
January - December 2017
Page 23 of 37
V,ROCKY MOUNTAINKpouren\ a uv,sq or rcr,mnp
IDAHO
Service Quality Review
a
l---,
."T;TI i
B{rbnbn [h.
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Figure 1Cr Lava 11 Underlying View excluding Loss of Supply
January - December 2017
Page 24 of 37
V,ROCKY MOUNTAINx(POYTTER
! a ovigiloF rcFrmt
IDAHO
Service Quality Review
MG
Cff
q
+
Dtthih.r tir.Lrysrdio.{e
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Figure 2A: Preston 11 Controllable View
January - December 2017
Page 25 of 37
IDAHO
Service Quality Review
rly9ffie
!otorruemCCtlbtlvlb@lorE, lyltl:
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Figure 28: Preston 11 Non-Controllable View
January - December 2017
Page 26 of 37
-,ROCKY
MOUNTAIN'(Po\n ER\ a uv,s,or o, mqr,mnp
\
ROCKY MOUNTAINm#*,!DAHO
Service Quality Review
Dgffi|rohf ottttrc*+o
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Figure 2C: Preston 11 Underlying Mew excluding Loss of Supply
January - December 2017
Page27 of37
V.ROCKY MOUNTAINx(PovrrER
\ r or,sm or rc,r,ep
IDAHO
Service Quality Review
Figure 3A: Clifton 11 Controllable View
January - December 2017
-t
._J
II
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f outotolrm
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Page 28 ol 37
.fs+
3 ROCKY MOUNTAIN
FOU'ER IDAHO
Service Quality Review
I
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Figure 38: Clifton 11 Non-Controllable View
January - December 2017
Page 29 ol 37
A DrV{9rS OF mOFrmBP
,|$a
Y ROCKYPOU'ER MOUNTAIN IDAHO
Service Quality Review
I ,J
,I
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Figure 3C: Ctifton 11 Underlying View excluding Loss of Supply
January - December 2017
Page 30 of 37
"'s'+
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YROCKY
POI/i'ER
A DVtSIff OF rcB@P
MOUNTA!N IDAHO
Service Quality Review
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January - December 2017
Page 31" of 37
Y ROCKY MOUNTAIN
H*CHYEN"""
IDAHO
Service Quality Review
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January - December 2017
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Y ROCKY MOUNTAIN
BSHYE#*"
IDAHO
Service Quality Review
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January - December 2017
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ROCKY MOUNTAIN
POYIIER IDAHO
Service Quality Review
2.9 Restore Service to 80% of Customers within 3 Hours
2.10 Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
customerguaranrees
January - December 2017
January to December 2017
January February March April May June
83%9L%89%75%90%96%
September October November DecemberJulyAugust
9t%9s%64%58%98%96%
80%8L%PS5-Answer calls within 30 seconds
PS6a) Respond to commission complaints within 3 days 95%100%
9s%PS6b) Respond to commission complaints regarding service disconnects
within 4 hours 700%
PS5c) Resolve commission complaints within 30 days 95%L00%
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Overall Customer Guarantee performance remains above 99/o, demonstrating Rocky Mountain Power's continued commitment to
customer satisfaction.
Major Events are excluded from the Customer Guarantees program.
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RESTORATIONS WITHIN 3 HOURS
Reporting Period Cumulative = 89%
COMMITMENT GOAL PERFORMANCE
Y IDAHO
Service Quality Review
January - December 2017
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 1366-2003120L26 Standard for
Reliability lndices.
Sustained Outoge
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentary Outage Event
A momentary outage event is defined as an outage 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, fault counts at substation breakers are to be used.
ReliabiliW tndices
SAID'
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 othenrrise, this value can be assumed to be for a one-year
period.
Doily SAIDI
ln order to evaluate trends during a year and to establish Major Event Thresholds, a daily SAIDI value is often
used as a measure. This concept is contained IEEE Standard L366-2072. This is the day's total customer minutes
out of service divided by the static customer count for the year. lt is the total average outage duration customers
experienced for that given day. When these daily values are accumulated through the year, it yields the year's
SAIDI results.
SAIFI
SAIFI (system average interruption frequency index) is an industry-defined term that attempts to identify the
frequency of all sustained outages that the average customer experiences during a given period. lt is calculated
by summing all customer interruptions for sustained outages (those exceeding 5 minutes in duration) and
dividing by all customers served within the study area.
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
6 IEEE 136G2003/2012 was first adopted by the IEEE Commissioners on December 23,2@3. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
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Service Quality Review
January - December 2017
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).
MA|Fle
MAlFle (momentary average interruption event frequency index) is an industry standard index that quantifies
the frequency of all momentary interruption events that the average customer experiences during a given time-
frame. lt is calculated by counting all momentary interruptions which occur within a 5 minute time period, as
long as the interruption event did not result in a device experiencing a sustained interruption.
CEMI
CEMI is an acronym for Customers Experiencing Multiple (Sustained and Momentary) lnterruptions. This index
depicts repetition of outages across the period being reported and can be an indicator of recent portions of the
system that have experienced reliability challenges. This metric is used to evaluate customer-specific reliability.
ORR
ORR is an acronym for Open Reliability Reporting, which shifts the company's reliability program from a circuit
based metric (RPl)to a targeted approach reviewing performance in a local area, measured by customer minutes
lost. Project funding is based on cost effectiveness as measured by the cost per avoided annual customer minute
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*0.029)+(3-yearSAlFl*0.30*2.439)+(3-yearMAlFl*0.20'r0.70)
+ (3-year breaker lockouts * 0.20 * 2.00)) = CPI Score
cPt05
CPl05 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. Unlike CPl99 it includes Major Event and Loss of Supply or Transmission outages. The
calculation of CPl05 uses the same weighting and normalizing factors as CPl99.
RPI
RPI is an acronym for Reliability Performance lndicator, which measures reliability performance on a specific
segment of a circuit to identify underperforming circuit segments rather than measuring performance of the
whole circuit. This is the company's refinement to its historic CPl, more granular.
ROCKY MOUNTAINHm*,
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IDAHO
Service Quality Review
January - December 2017
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 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
uL-12131/20L7 78,594 16.56 L,30t,447
LIL-L2l3t/2018 80,004 L6.67 1,333,663
Significont Events
The Company has evaluated its year-to-year performance and as part of an industry weather normalization task
force, sponsored by the IEEE Distribution Reliability Working Group, determined that when the Company
recorded a day in excess of 1.75 beta (or 1.75 times the natural log standard deviation beyond the natural log
daily average for the day's SAIDI) that generally these days' events are generally associated with weather events
and serve as an indicator of a day which accrues substantial reliability metrics, adding to the cumulative reliability
results for the period. As a result, the Company individually identifies these days so that year-on-year
comparisons are informed by the quantity and their combined impact to the reporting period results.
Underlying Events
Within the industry, there has been a great need to develop methodologies to evaluate year-on-year
performance. This has led to the development of methods for segregating outlier days, via the approaches
described above. Those days which fall below the statistically derived threshold represent "underlying"
performance, and are valid. lf any changes have occurred in outage reporting processes, those impacts need to
be considered when making comparisons. Underlying events include all sustained interruptions, whether of a
controllable or non-controllable cause, exclusive of major events, prearranged (which can include short notice
emergency prearranged outages), customer requested interruptions and forced outages mandated by public
authority typically regarding safety in an emergency situation.
Controllable Distribution (CD) Eve nts
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.
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ROCKY MOUNTAINm*"