20160608Service Quality Report 2015.pdf

ROCKY MOUNTAIN
POWER
A T)|VISION OFPACIFICORP 1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
June 8,2016
VIA OVERNIGHT DELIVERY
Ms. Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,ID 83702
PAC-E-04-07 2015 Service Quality & Customer Guarantee Report for the period
January I through December 31,2015.
Dear Ms. Jewell:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the 2015 Service
Quality & Customer Guarantee report. This report is provided pursuant to a merger commitment
made during the PacifiCorp and ScottishPowerl merger. The Company committed to implement
a five-year Service Standards and Customer Guarantees program. The purposes behind these
programs were to improve service to customers and to emphasize to employees that customer
service is a top priority. Towards the end of the five-year merger commitment the Company filed
an application2 with the Commission requesting authorization to extend these programs.
If there are any additional questions regarding this report please contact Ted Weston at (801)
220-2963.
Sincerely,
Torl [k Dw /A',,*
Ted Weston
Manager, Idaho Regulatory Affairs
Enclosurescc: Rick Sterling
Terri Carlock
Beverly Barker
I Case No. PAC-E-99-01
2 Case No. PAC-E-04-07
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Re:
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE CUATITY
REVIEW
Janua ry L- December 3L, 2015
Report
ROCKY MOUNTAINmR"IDAHO
Service Quality Review
January - December 2015
TABLE OF CONTENTS
2.2 System Average lnterruption Frequency lndex (SAlFl). ..............8
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFle)....... ........ 9
2.5 Controllable, Non-Controllable and Underlying Performance Review...,..... ..........,........... 14
2.7 lmprove Worst Performing Circuits or Areas by Target Amount .................. 20
2.8 Geographic Outage History of Under-performing Areas........... .........,.,........ 2t
2.9 Restore Service to 80% of Customers within 3 Hours ........... ........................ 39
2.10 Telephone Service and Response to Commission Comp|aints................. .......................... 39
CUSTOMER GUARANTEES PROGRAM STATUS......... ....................... 39
1.1
L.2
Page2 of 42
IDAHO
Service Quality Review
January - December 2015
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 are defined by 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.
L SERVICE STANDARDS PROGRAM SUMMARY1
1,.1 ldaho Customer Guarantees
Customer Guarantee 1:
Restorine Suoolv After an Outase
The Company will restore supply after an outage within 24 hours of
notification with certain exceDtions as described in Rule 25.
Customer Guarantee 2:
Aooointments
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,
subterfuse 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
workine davs.
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 workins davs.
Customer Guarantee 7:
Notification of Planned lnterruptions
The Company will provide the customer with at least two days' notice
prior to turning off power for planned interruptions.
Note: See Rules for a complete description of terms and conditions for the Customer Guorantee 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.
Page 3 of 42
ROCKY MOUNTAIN
Pol,YER
ROCKY MOUNTAINFOI'ER IDAHO
Service Quality Review
January - December 2015
1.2 ldaho Performance Standards
Note: Performonce Stondords 7, 2 & 4 ore for underlying performonce doys ond exclude those clossified os Mojor
Events.
2 When in the future, the Company discovers that marginal improvement costs outweigh marginal improvement benefits, the Company can propose
modifications to the Performance Standards Program to reco8nize that maintaining performance levels is appropriate.
3 Reliability performance indicators (RPl) will be calculated by aggregating customer transformer level SAlDl, SAlFl, and MAlFl, and are exclusive of major
events as calculated by IEEE L366-2OL2; they are a modification to the Company's historic CPl. RPI excludes breaker lockout events.
a Prospectively, the Company will work with Commission Staffto determine methods to report the target area performance and cost-benefit results.
Page 4 of 42
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
Underlvine distribution events.
Network Performance Standard 2:
Report System Average lnterruption Frequency lndex
(sArFr)
The Company will report Total, Underlying, and Controllable
SAIFI and identifiT 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
Underlvins distribution events.
Network Performance Standard 3:
lmprove2 Under-Performing Areas
Annually the Company will select at least one
underperforming area based upon a reliability performance
indicator3 (RPl). Within five years after selection the
Company will reduce the RPI by an average of tO% for the
areas selected in a given year. The Company will identify the
criteria used for determining these areas and the plansa to
address them.
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/oof customers on average.
Customer Service Performance Standard 5:
Telephone Service Level
The Company will answer 80% of telephone calls within 30
seconds. The Company will monitor customer satisfaction
with the Company's Customer Service Associates and quality
of response received by customers through the Company's
eQuality monitoring system.
Customer Service Performance Standard 6:
Commission Complaint Response / Resolution
The Company will a) respond to at least 95% of non-
disconnect Commission complaints within three working
days and will b) respond to at least 95% of disconnect
Commission complaints within four working hours, and will c)
resolve 95%o of informal Commission complaints within 30
davs.
IDAHO
Service Quality Review
January - December 2015
2 REIIABIIITY PERFORMANCE
During 2015, the Company experienced mixed reliability results, with underlying interruption duration (SAlDl)
that was unfavorable to plan while interruption frequency (SAlFl) performance that was favorable to plan.
Results for ldaho underlying performance can be seen in subsections 2.1 and 2.2 below.
Three outage events during the reporting period meet the Company's ldaho major event threshold levels for
exclusion from underlying performance results.
Major Event General Descriptions
. 7/2912015: A line fault occurred on the Rigby-Thornton transmission line. During the event three
substations, 12 circuits, and 76,496 customers were without power. Personnel were promptly
dispatched to the area. An inspection of the Rigby-Thornton tap showed the insulator had burned,
causing the circuit breaker to trip.. 8lU2Ot5: ldaho experienced two loss of supply events. The first event occurred in Shelley, when a
faulty low oil sensor triggered a transformer at the Sugarmill Substation causing a lockout. The
transformer is a source to the Sandcreek, Ammon, and Ucon Substations, and caused outages to a total
of 10 circuits, impacting L6,222 customers for just over 2 hours. The second event occurred at in
Montpelier, when the bus on the Grace 151 kV line locked out, de-energizing the 45kv transmission
lines leaving the substation. These lines feed six surrounding distribution substations. The incident
event impacted 10 distribution lines and 4,168 customers for less than 2 hours.. 8/29/2075 - 8/30/2015: A severe thunderstorm brought lightning, wind, and heavy rain to southeast
ldaho. During the storm two significant outages occurred. The first outage occurred in Mud Lake when
high winds, specifically micro-bursts, caused damage to almost a dozen poles. The outage affected 431
customers, with restorations ranging from 2 hours to 17.5 hours. The second significant impact
occurred at 10:58 pm, when lightning made contact with the Ucon substation, faulting the substation
and de-energizing two circuits, affecting 2,664 customers for 5 hours and 53 minutes.
s Major event threshold shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
ROCKY MOUNTANnmn*,
2015
20L6
869,108
76,97L
1s.95
L4.82
t,237,L73
L,L4L,O67
Page 5 of 42
IDAHO
Service Quality Review
January - December 2015
Significant Events
ln 2015, 13 significant event dayss were recorded in the period, which account for 83 SAIDI minutes; about 42%
of the reporting period's underlying 197 SAIDI minutes. 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.
ROCKY MOUNTAINmn*,
Daie Cause: General Deqptption ErentSlDl 96 ofTotal Year
End SATIX
March 28,2015 Snow and wind storm cause pole fire and downed line.6.O7 3.1%
April14,2015 Wind and snow storm related outage and loss of supply 10.98 5.6%
May 12,2015 Loss of transmission: no cause found. Lightning reported
in the area 5.14 2.6%
June 1,2015 Wind Storm caused several downed lines and poles.14.47 73%
June 9, 2015 Wind Storm, trees on lines.5.09 2.6%
July 3, 2015 Neutral line down across primary lines 4.32 2.2o/o
July 2Q 2015 Flash occurred at substation of manufacturing plant
causing a loss of transmission.5.20 2.6%
luly24,2Ol5 Tree limb fell on primary line 4.48 2.3%
August 5, 2015 Wind and Lightning storm, loss of supply and windblown
downed equipment.7_69 3.9%
August t7,2OLs Loss of transmission, Bird nest caused flashover. Fire
restriction line patrol before restoration.4.31 2.2%
September 22,zOtS Equipment failure. Power fuses blew on substation
transformer 6.40 3.2%
December 16,2015 Loss of transmission: line down s.02 2s%
December 31, 2015 Loss of transmission: line down 3.93 2.0%
TOTAL 83.10 42.2%
6 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 42
IDAHO
Service Quality Review
January - December 2015
2.t System Average lnterruption Duration lndex (SAlDl)
The Company's underlying interruption duration performance during 2015 was unfavorable to plan.
IDAHOSAIDI
(excludes Prearranged and Customer Requested)
150
100
50
o la66rrlHdddooooa{NNr{\\\\dmq
ROCKY MCn lrlTAlN
FOWER
300
250
2fi)UIo5c
E6
an
6 ., r,i l^ lrl
oooooN.\l'{NN\\\\\60roda{dHd
Controlabh Afiral
o..... Totd lndudng ilbforEvents
-ufisflylqAfiral
-
ufisflylrg Phn
PageT of 42
IDAHO
Service Quality Review
January - December 2015
2.2 System Average lnterruption Frequency lndex (SAlFll
The Company's underlying interruption frequency performance results for 2015 were favorable plan.
rDAr{osAtFt
(excludes Prearranged and Customer Requested)
.A .,)ddoob -='
ROCKY MOI'NIAIN##*
UIEL5ott!
tL
B ,.0
fa|,lt,,
dd€oooa{ a{ .{\\\oda{ddH
rnr,llara|,i6l^dfr(iHddooooooo6INA'NN'YN
Total (major event included)
Page 8 of 42
IDAHO
Service Quality Review
January - December 2015
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFle)
The Company annually reports the occurrence of short interruptions using two different metricsT. The chart
below displays, for the circuits with SCADA devices, the operating area weighted MAlFle 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 Lava #11: the breaker count was incorrectly recorded. The breaker counter leads with nines, as opposed
to zeros, and was incorrectly recorded into the system as such. Records have been updated to reflect the
correct trips as 3.
Clifton #11: breaker readings between July 2015 and October 2OLS indicate 59 of the total 65 operations
taken in 2015. Extensive maintenance work was performed on the line during this period causing an
increase breaker trips; maintenance trips increment the counter, but do not result in impacts to
customers.
Holbrook #L1:57 trips were added to the count as a result of the difference between the last recorded
reading in2074 (August LL,2O74l and the first reading in 2015 (February 2,2OL51. Since then only 3
breaker operations occurred, from February to October 2OL5.
. Egin #11: the circuit breaker log shows a total of 26 trips in 2015. lt appears a recording error has
occurred and will be corrected.
Operating Area Circuit Name Circuit lD Operations
MONTPELIER ATEXANDER #11 ALX11 2
MONTPELIER ARrMO #11 ARM11 6
MONTPELIER ARTMO #12 ARM12 19
MONTPELIER BANCROFT #11 BAN11 10
MONTPELIER BANCROFT #12 BAN12 1
MONTPELIER CHESTERFIELD #11 cHs11 2
MONTPELIER CHESTERFIELD #12 HATCH cHs12 5
MONTPELIER covE #12 cov12 3
MONTPELIER EIGHT MILE #11 EGT11 10
MONTPELIER GEORGETOWN #11 GRG11 0
MONTPELIER GRACE #11 GCE11 L4
MONTPELIER GRACE #12 GCE12 3
MONTPELIER HENRY #11 HRY11 0
MONTPELIER HORSLEY #11 HRS11 1
7 tdaho 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 meeting, 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 meetings.
Page9 of 42
ROCKY MOUNTAINmn"""
ROCKY MOUNTAINPOIIER !DAHO
Service Quality Review
R INDIAN CREEK #11 IND11
MONTPELIER LAVA #11 LVA11 99911
MONTPELIER LUND #11 LND11 28
MONTPELIER MCCAMMON #11 MCC11 72
MONTPELIER MCCAMMON #12 MCC12 0
MONTPELIER MONTPELIER #11 MNT11 1
MONTPELIER MONTPELIER #13 MNT13 7
MONTPELIER MONTPELIER #14 MNT14 1
MONTPELIER RAYMOND #11 NORTH TO GENEVA RAY11 L\
MONTPELIER RAYMOND #12 SOUTH TO PEGRAM RAY12 74
MONTPELIER ST CHARLES #11 sTc11 5
PRESTON CLIFTON #11 DAYTON & BANIDA CLF11 65
PRESTON CLIFTON f 12 CLIFTON/OXFORD/SWANLAKE CLF12 3
PRESTON DOWNEY #11 DWN11 4
PRESTON DOWNEY #12 DWN12 0
PRESTON HOLBROOK #11 HLB11 50
PRESTON MALAD #11 MLD11 3
PRESTON MALAD #12 MLD12 3
PRESTON MALAD #13 MLD13 4
PRESTON PRESTON #11 PRS11 19
PRESTON PRESTON #12 PRS12 37
PRESTON PRESTON #13 PRS13 31
PRESTON TANNER #11 MINK CREEK TNR11 t2
PRESTON TANNER #12 RIVERDALE/TREASURETON TNR12 2
PRESTON WESTON #12 NORTH TO DAYTON WST12 7
PRESTON WESTON#11 SOUTH - WESTON/FAI RVEW WST11 4
REXBURG ANDERSON #11 WEST AND11 0
REXBURG ANDERSON #12 EAST AND NORTH AND12 0
REXBURG ANDERSON #13 NORTH AND13 0
REXBURG ARCO #11 ARC11 1
REXBURG ARCO #12 ARC12 I
REXBURG ARCO #13 ARC13 1
REXBURG ASHTON #11 ASH11 L
REXBURG BELSON #11 BLS11 0
REXBURG BELSON #12 BLS12 0
REXBURG BERENICE #21 BRN21 1
REXBURG BERENICE #22 BRN22 2t
REXBURG CAMAS #11 cMs11 1
REXBURG CAMAS #12 cMs12 0
REXBURG CANYON CREEK # 22 CNY22 1
REXBURG CANYON CREEK #21 CNY21 I
REXBURG DUBOTS S11 DBS11 1
REXBURG DUBOTS #12 DBS12 0
REXBURG EASTMONT f11 EST11 4
REXBURG EASTMONT #12 EST12 8
REXBURG EGIN #11 EGN11 t46
REXBURG EGIN #12 EGN12 4
REXBURG HAMER #11 HMR11 23
REXBURG HAMER #12 HMR12 5
REXBURG MENAN #11 MNN11 0
REXBURG MENAN #12 MNN12 0
REXBURG MENAN #13 MNN13 0
REXBURG MILLER #11 MLL11 0
REXBURG MILLER #12 MLL12 0
REXBURG MOODY #11 MDY11 0
REXBURG MOODY #12 MDY12 0
REXBURG MOODY S13 MDY13 1
REXBURG MUDLAKE #11 MDL11 0
REXBURG MUDLAKE S12 MDL12 1
REXBURG NEWDALE #11 NWD11 0
REXBURG NEWDALE #12 NWD12 0
January - December 2015
Page 10 of42
ROCKY MOUNTAINm*"IDAHO
Service Quality Review
REXBURG NEWDALE #13 NWD13 1
REXBURG RENO T11 REN11 3
REXBURG RENO S12 REN12 0
REXBURG RENO #13 REN13 0
REXBURG REXBURG #11 RXB11 0
REXBURG REXBURG #12 RXB12 2
REXBURG REXBURG #13 RXBl3 0
REXBURG REXBURG #14 RXB14 0
REXBURG REXBURG #15 RXB15 0
REXBURG REXBURG #16 RXB16 0
REXBURG RIGBY #11 RGB11 4
REXBURG RIGBY #12 RGB12 0
REXBURG RIGBY #13 RGB13 0
REXBURG RIGBY #14 RGB14 0
REXBURG RtRtE #12 RIR12 0
REXBURG ROBERTS #11 RBR11 1
REXBURG ROBERTS #12 RBR12 0
REXBURG RUBY #11 RBY11 5
REXBURG SANDUNE #21 SDN21 3
REXBURG SANDUNE #22 SDN22 0
REXBURG sMrrH #11 SMT11 18
REXBURG sMtTH #12 SMT12 9
REXBURG sMrTH #13 SMT13 3
REXBURG sMrTH #14 SMT14 I
REXBURG SOUTH FORK #11 IDAHO PACIFIC POTATO SFK11 0
REXBURG SOUTH FORK#13 ANTELOPE FLATS SFK13 0
REXBURG ST ANTHONY #11 STA11 1
REXBURG ST ANTHONY #12 STA12 0
REXBURG ST ANTHONY #13 STA13 0
REXBURG SUGAR CITY #1 SGR11 0
REXBURG SUGAR CITY S12 SGR12 0
REXBURG SUGAR CITY f13 SGR13 0
REXBURG SUGAR CITY f14 SGR14 0
REXBURG SUNNYDELL #11 SNN11 L
REXBURG SUNNYDELL #12 SNN12 2
REXBURG TARGHEE #11 TRG11 0
REXBURG TARGHEE #12 TRG12 0
REXBURG THORNTON #11 THR11 1
REXBURG THORNTON #12 THR12 1
REXBURG WATKINS #11 NORTH AND EAST WTK11 5
REXBURG WEBSTER #11 EAST AND SOUTH WBS11 76
REXBURG WEBSTER #12 NORTH WBS12 4
REXBURG WEBSTER #14 WBS14 35
REXBURG WINSPER #21 WNS21 0
REXBURG WINSPER #22 WNS22 0
SHELLEY AMMON #11 AMM11 5
SHELLEY AMMON f12 AMM12 1
SHELLEY Cinder Butte #11 CIB11 0
SHELLEY CINDER BUTTE #13 CIB13 L
SHELLEY Cinder Butte #17 CIB17 4
SHELLEY CLEMENTS fl1 CLE11 11
SHELLEY CLEMENTS #12 CLE12 18
SHELLEY GOSHEN #11 GSH11 0
SHELLEY GOSHEN #12 GSH12 8
SHELLEY GOSHEN #13 GSH13 3
SHELLEY HAYES #11 HYS11 0
SHELLEY HAYES #12 HYS12 1
SHELLEY HAYES #13 HYS13 LL
SHELLEY HOOPES #11 WEST HPS11 8
SHELLEY HOOPES #12 NORTH HPS12 0
SHELLEY IDAHO FALLS #11 IDF11 2
January - December 2015
Page 11 of 42
ROCKY MOUNTAINPO'I'ER IDAHO
Service Quality Review
January - December 2015
SHELLEY IDAHO FALLS #12 IDFL2 37
SHELLEY IDAHO FALLS #13 IDF13 9
SHELLEY IDAHO FALLS #14 IDF14 3
SHELLEY JEFFCO #21 JFF27 22
SHELLEY JEFFCO #22 JFF22 3
SHELLEY KETTLE #21 KTT27 18
SHELLEY KETTLE#22 KIT22 8
SH ELLEY MERRILL #11 MRR11 19
SHELLEY MERRILL #12 MRR12 15
SHELLEY MERRILL #13 MRR13 16
SHELLEY MERRILL f14 MRR14 8
SHELLEY oscooD #11 OSG11 26
SHELLEY oscooD #12 osc12 5
SHELLEY oscooD #13 osc13 6
SHELLEY oscooD #14 osc14 9
SHELLEY SANDCREEK #11 SND11 1
SH ELLEY SANDCREEK #12 SND12 5
SHELLEY SANDCREEK #13 SND13 t
SHELLEY SANDCREEK #14 SND14 11
SHELLEY SANDCREEK #15 SND15 32
SHELLEY SANDCREEK #15 SND15 7
SHELLEY SHELLEY #11 SH 111 27
SH ELLEY SHELLEY #12 SH 112 0
SHELLEY SHELLEY #13 SHL13 0
SHELLEY SHELLEY #14 SHL14 6
SHELLEY ucoN #11 UCN11 2
SHELLEY ucoN #1,2 UCN12 5
SHELLEY WATKINS f12 SOUTH THEN EAST WTK12 7
Page L2 of 42
ROCKY MOUNTANPOI/ER IDAHO
Service Quality Review
January - December 2015
2.4 Reliability History
Depicted below is the history of reliability in ldaho. ln 2OO2, 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.
tdaho Reliability History - lncluding Major Events
ISAIDI ICAIDI +-SAlFl
500
400 6of
=300 EE
2m
100
0
cY10 cYll CY12 CY13 CY14
3
5IPE.QtItut
t
0
ldaho Reliability History - Excluding Major Events
ISAIDI rcAlDl +SAIFI
300
oo+.2mE
=
100
0
cY09 cY10 cY1l CY12 CY13
Page 13 of42
IDAHO
Service Quality Review
January - December 2015
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. Plans are now centered on underlying
performance, however the Company and Commission agreed that controllable distribution metrics would be
valuable to continue to report.
The graphic history demonstrates controllable, non-controllable and underlying performance on a rolling 365-
day basis. Analysis of the trends displayed in the charts below shows a general improving trend for all charts. ln
order to also focus on non-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.
tdaho 365-Day Rolling Controllable History as Reported
ROCKY MOUNTAIN
POYIIER
0.9
0.8
o.7
aE
o.u .l
ga
0.4
-60e,
3E
=50ot640
0.3
0.110
o
J$-2007 ,1rn.2009 J.n-2010
Stress Period
Jtn-2ou Jrn-2012 J.n-2013 J.n-2014
-s/UDt
_SAtFt etinear (SAtDl)
8 3. The Company shall provide, as an appendix to its Service Quality Review reports, information regarding non-controllable outages, including, when
applicable, descriptions of efforts made by the Company to improve service quality and reliability for causes the Company has identified as not controllable.
4. The Company shall provide a supplemental filing, within 90 days, consisting of a process for measuring performance and improvements for the non-
controllable events.
Page t4 of 42
-R(r;KY
MOUNTAINIPoiirgl\AquE{ofre
IDAHO
Service Quality Review
January - December 2015
ldaho 35$Day Rolllng NonControllable Hlstoryas Reported
Jl! 2qr7 J.l 2U ln-2o9 J&2010 t&2011 ,tr-2olrl ,rr.2oul lrr.20L JG2OI5
rsrG.9r|od -gUU -S/UH -urnrF lDo
E
,.5 EE;
a
L,oI
E
0
1@
ldaho 36$Day Rolllry Udetlylry History as Reported
.L_l__f_ _I_ r _ r . r___I-_l--
Jr-2O7 ,r.2m ,fr-2ot ,rr 2010 ,I.2Oll 1I.20!:l ,&2013 ,rr'20L Jn2015
-sb..r9rlod -sJllDl -s/UFl -tli|.
r6Alul
Page 15 of 42
!DAHO
Service Quality Review
January - December 2015
2.6 Cause Code Analysis
The tables below outlines categories used in outage data collection. Subsequent charts and table use these
groupings to develop patterns for outage performance.
Environment
Contamination or Airborne Deposit (i.e. salt, trona, ash, other chemical dust, sawdust, etc.);
corrosive environment; flooding due to rivers, broken water main, etc.; fire/smoke related to
forest, brush or buildins fires (not includinE fires due to faults or liehtnine).
Weather Wind (excluding windborne material); snow, sleet or blizzard; ice; freezing fog; frost; lightning.
Equipment Failure
Structural deterioration due to age (incl. pole rot); electrical load above limits; failure for no
apparent reason; conditions resulting in a pole/cross arm fire due to reduced insulation qualities;
equipment affected by fault on nearbv equipment (i.e. broken conductor hits another line).
lnterference
Willful damage, interference or theft; such as gun shots, rock throwing, etc.; customer,
contractor or other utility dig-in; contact by outside utility, contractor or other third-party
individual; vehicle accident, including car, truck, tractor, aircraft, manned balloon; other
interfering obiect such as straw, shoes, string, balloon.
Animals and Birds Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels or other
animals, whether or not remains found.
Operatlonal
Accidental Contact by Rocky Mountain Power or Rocky Mountain Power'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.
Loss of Supply Failure of supply from Generator or Transmission system; failure of distribution substation
eouipment.
Planned
Transmission requested, affects distribution sub and distribution circuits;
to make repairs after storm damage, car hit pole, etc.; construction work,
eiven: rollins blackouts.
Company outage taken
regardless if notice is
Trees Growing or falling trees
Other Cause Unknown; use comments field if there are some possible reasons.
The table and charts below show the total customer minutes lost by cause and the total sustained
interruptions by cause. 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.
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. However,
for ease of charting, the pie charts reflect the rollup-level cause category rather than the detail-level direct
cause within each category. Therefore, the pie charts for Underlying include prearranged causes (listed within
the plonned category). Following the pie charts, a table of definitions provides descriptive examples for each
direct cause category.
ROCKY MOUNTANmn*"
Page 15 of42
ROCKY MOI.INTAIN#n*"IDAHO
Service Quality Review
January - December 2015
2.6.L Underlying Cause Analysis Table
'}'.-.ffiffi ;.;rrflffi1,rffiIh*
ANIMAIS L8r'.,279 1,854 189 2.38 o.o24
BIRD MORTALITY (NON-PROTECTED SPECIES)404,447 2,568 83 5.2L 0.033
BIRD MORTALITY (PROTECTED SPECIES) (BMTS)81,023 642 22 1.(N 0.008
BIRD NEST {BMTS)59,417 1,596 11 o.77 0.021
BIRD SUSPECTED, NO MORTALITY 202,OSO 2,447 70 2.60 0.032
ANIMAIS.931,216 9,1o7 37s ilI.01 o.tt7
FIRE/SMOKE (NOT DUE TO FAULTS)1,499 23 5 0.o2 0.000
ENVIRONMEiI?1,499 2?5 0.02 0.(x,0
B/O EQUIPMENT 276,082 3,578 165 3.56 0.046
DETERIOMTION OR ROTTING 3,208,744 2L,826 878 4L.37 0.281
NEARBY FAULT LOz 1 1 0.00 0.000
OVERLOAD 6,467 42 13 0.08 0.001
POLE FIRE 748,949 3,86s 54 9.66 0.0s0
REIAYS. BREAKERS. SWITCHES 0 1
STRUCTURES, INSUIATORS, CONDUCTOR 0 5
EQUIPMEilT FAILUREI 4,24/,.,iyl1 2!t,ltz l,ll7 9.67 0.378
DIG.IN (NON-COMPANY PERSONNEL)54,089 294 38 o.70 0.004
OTHER INTERFERING OUECT 33,890 368 17 o.44 0.00s
OTH ER UTl LTTY/CONTMCTOR L2,882 t27 9 o.L7 0.002
VANDALISM ORTHEFT 2,573 4 1 0.03 0.000
VEHICLE ACCIDENT 927,LLL 7,O54 84 11.95 0.091
IITITERFERENCE 1,030,545 7,U7 149 13.29 o.101
TOSS OF SUBSTATION 2L3,97L 631 8 2.76 0.008
LOSS OF TRANSMISSION UNE 2,903,454 2t,239 L20 37.43 o.274
SYSTEM PROTECTION 0 2
LOSS OF SUPPLY 3,t17A24 21,870 130 40.19 o,282
FAULTY INSTALL 4,556 59 6 0.06 0.001
IMPROPER PROTECTME COORDINATION L20 2 L 0.00 0.000
INCORRECT RECORDS t72 3 3 0.00 0.000
COMPANY EMPLOYEE - FIELD 224 2 2 0.00 0.000
OPERANOI{A[I s,o72 66 12 0.07 o.001
OTHER. KNOWN CAUSE 5,442 236 25 0.07 0.@3
UNKNOWN 632,373 6,818 433 8.15 0.088
OIHER 617,8t.4 7,UA 4S8 a.22 0.0!r1
CONSTRUCflON 85,743 383 26 1.11 0.005
CONSTRUCNON - SCHEDULED SWTTGHING 0 24
CUSTOMER NOTICE GIVEN r.703.326 7,209 t62 2L.96 0.093
CUSTOMER REQUESTED 8,737 86 8S 0.11 0.001
EMERGENCY DAMAGE REPAIR 847,402 L2,327 148 10.93 0.159
INTEI,ITIONAL TO CLEAR TROUBLE t73,582 1,083 LT 2.24 0.014
MAINTENANCE 0 59
PIANilED 2,81&790 21,088 515 36.!14 o.272
Page t7 of 42
ROCKY MOUNTAIN
Fol,VER IDAHO
Service Quality Review
January - December 2015
Note: Direct Causes are not listed if there were no outages classified within the cause during the reporting period.
*Controllable causes (Animal, Equipment Failure, Operational, and Tree-Trimmable).
TREE - NON-PREVEi{TABLE L,312,881 8,316 71 15.93 o.to7
TREE-TRIMMABLE'48,271 302 L7 o.62 0.m4
rREES !p51,l!i:l 8,618 88 17.55 0.111
FREEZING FOG & FROST 241 2 2 0.00 0.0(x)
tcE 482 4 4 0.01 o.(n0
LIGHTNING 62,-,t93 4,318 t72 8.01 0.056
SNOW, SI,EETAND BLIZARD 40.3,7fi L,28L 45 5.2L 0.017
WIND L,826,154 9,337 LS7 23.54 0.120
WEATHER aE5!831 1.0,942 3m 35.77 0.193
Page 18 of42
ROCKY MOUNTANffi*IDAHO
Service Quality Review
C.ause Analysis - Customer Minutes Lost (SAlDll
I ANIMAIS5%
T WEATI{ER 17%r gnvtnonuENT0g6
C TREES8%
I PLANNEDlT%
I OPERATIONAT@6
E OTHER4%
January - December 2015
2.6,2 Cause Category Analysis Charts
I EQUIPMENT
FAITURE 25%
INTERFERENCE 6%
I LOSSOFSUPPLY 1895
Cause Analysis - Customer lnterruptions (SAlFtl
T WEATHER 12%I ANIMAI.SS%
I TREES 795
I rnuRoNuENTo%
T PLANNED 1896
r EQUIPMENT
FAITURE 24%
r OPERATIONALO96 I INTERFERENCE 796
E OTHER696 I lossoFsuPPtYlS%
Cause Analysls - Sustained lncidents
E WEATT{ER 12%I ANIMALS 1296
E TBEES396 I ENVIRONMENT0'6
r PLANNEDlS%
r EQUIPMENT
FAILURE 34%
E OTHEB14'6
r oPERATIoNAtog6
Page 19 of42
ROCKY MOUNTAIN
POIIYER IDAHO
Service Quality Review
January - December 2015
2,7 lmprove Worst Performing Circuits or Areas by Target Amount
ln 2Ot2 the Company modified its program with regards to selecting areas for improvement. Delivery of tools
has allowed more targeted improvement areas. As a result, the Service Standard Program was modified to
reflect this change. Prior to 2072, 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.
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.
Relia bilitv Performa nce I mprovement (post 1213 U201 1)
On an annual routine basis, the Company reviews areas for performance. Utilizing a new 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.
Region Performance lndlcator 2012 (Rpt12) Method
PROGRAM YEAR 15 (CPI99I MEthOd
Lava 11 (Figure 5C)IN PROGRESS 127 L23
Preston 11 (Figure 6C)IN PROGRESS 36 64
TARGET SCORE = 73 82 94
PROGRAM YEAR 15
Roberts 12 (Figure 3C)COMPLETED 2L6 199
Targhee 11 (Figure 4C)COMPLETED 176 180
TARGET SCORE = 175 196 189
PROGRAM YEAR 14
Berenice 21 (Fieure 1C)COMPLETED 290 236
Malad 13 (Fieure 2C)COMPLETED L22 85
TARGET SCORE = 185 GOAI MET 206 161
Page20 of 42
ROCKY MOUNTAIN
PolTYER
A qv|s oF rcBc@P
IDAHO
Service Quality Review
Clrcult Performance lndicator 2005 (CPlosl Method
PROGRAM YEAR 12
Grace 12 COMPLETED L24 53
Preston 13 COMPLETED L02 49
TARGET SCORE = 90 GOAL MET 113 51
(lmprovement targets for circuits in Program Years l through 11 and 13 have been met and filed in prior reports.)
2.8 Geographic Outage History of Under-performing Areas
January - December 2015
Figure 1A: Berenice 21 Controllable View
. 6REAIIRLry!6
\ Cituilt
. O6lrr br.E. C6Eit R.li.Uliiy Cortd.bL
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Page 2I of 42
IDAHO
Service Quality Review
\ciqb. OnrtrLtFre Cuomidl&tyIfiYr. tnge
OrrU.O
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Figure 1B: Berenlce 21 Non{ontrollable View
January - December 2015
Page22 ol 42
IDAHO
Seruice Quality Review
Figure lC: Berenlce 21 Underlylng Vlew excluding loss of Supply
. GtlAIRllFr\Ciort. OirbrtFrI Cr*rid$nylctf$p9ty
if,1fi0. htgrtt*r.o
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s.aa OfrgElicfruTnO&Bhi!.Ld
January - December 2015
Page23 of 42
\ffi.IDAHO
Service Quality Review
January - December 2015
Figure 2A: Malad 13 Controllable View
Pagel4ol 42
Xffi IDAHO
Service Quality Review
Flgure 28: Malad 13 Non{ontrollableView
January - December 2015
Page25 of 42
-R(XKY
lutothlrAf,tl!poru=n\AtrECrCnCil
!DAHO
Seruice Quality Review
Flgure 2C: Malad 13 Underlylng View excludlng Loss of Supply
January - December 2015
Page 26 of 42
ROCKY MC'T.h]TAIN
BSIH-IDAHO
Service Quality Review
Flgure 3A: Roberts 12 Controlleble Vlew
January - December 2015
Page27 ot 42
IDAHO
Service Quality Review
Flgure 38: Roberts 12 Non-Controllable View
January - December 2015
Page28 of 42
xffiouNrArN TDAHO
Service Quality Review
Flgure 3C: Roberts 12 Underlying View excludlng Loss of Supply
January - December 2015
Page29 of 42
-ROCKY
]IIEI.|]uTA[II!FOWER\Ailm{*affiil
IDAHO
Service Quality Review
Flgure 4A: Targhee 11 Controllable View
. Glfltnlryrt\(lqit. mrlilt. GrEnGittltcstoEnvh. hnfri trfr. O
fO<.v*r<10
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January - December 2015
Page 30 of 42
ROCKY MCIUNTAIN
FOWERagusrSm
IDAHO
Service Quality Review
Flgure 48: Targhee 11 Non-Controllable Vlew
. GrcAfAtFt\(i,ort. Oidnrttlt. CrerLbllttaccaifllHrrbt hlE!l *r.o
fo<.drclo
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Cl{f,=hdltDr.Oagrhdtr5G&OuElahdldd
TsOFgFEddd
January - December 2015
Page 31 of 42
ROCKY MOUNTAhIF(ruER IDAHO
Service Quality Review
Figure 4C: Targhee 11 Underlying Vlew excluding Loss of Supply
OirfrLlrrI G*rrffQtcdSqfitrh
' hqr
Or.r..of o<,*r<m
alo<.f,1x<20
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Dr.qtlfEhdrr.aStlsOr.gEhdrdTmOrrgcldrff
January- December 2015
Page 32 of 42
-R(TKY
MOUNTAIN!pgweR!rurnrcre
IDAHO
Service Quality Review
Flgure 5A: Lava 11 Controllable View
January - December 2015
Page 33 of 42
-ROCKY
MOI'NTAIN!ruwEp\roru*nm
IDAHO
Service Quality Review
Flgure 58: Lava 11 Non-Controllable Vlew
January - December 2015
Page 34 ol 42
xffiotNrArN IDAHO
Service Quality Review
Figure 5C: Lava 11 Underlying View excluding loss of Supply
January - December 2015
Page 35 of 42
IDAHO
Service Quality Review
Figure 5A: Preston 11 Controllable View
\ ciorrr. Of,rLy L.FE. CEbcr ndi.affV C.nbd$L
lEYtr. nngE
Onrr=O
ao<rdu<m(t 10 <= rde < 20
200 <= ntr < 30
a l& <= nhE < 4{D
f {m<=n&t<lm. C.ibrir
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iaEOr-E&rfrrdd
Tm Orrte Ldd.d
January - December 2015
Page 36 of 42
ROCKY MOUNTAN
POYi'ER IDAHO
Service Quality Review
Figure 58: Preston 11 Non-Controllable View
. GRt IIRLIFT
\GB,B. Ofilr,lrtq!, Grt c R.Llilty N*GoitElbbL
REYH. Ra.rEE
Onta=O
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Td,OEcEdud(d
January - December 2015
Page37 of 42
ROCKY MOUNTAIN
Pol,YER IDAHO
Service Quality Review
January - December 2015
Figure 6C: Preston 11 Underlying View excluding loss of Supply
. G|REAIIR|.FT
\c@it. OdLy L?cE. CEEncr Rdi.Llit, lE oa S{fpay
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? ; l .!._.-.-.
Page 38 of 42
IDAHO
Service Quality Review
2.9 Restore Service to 8O% of Customers within 3 Hours
2.l0Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
January - December 2015
&nuary to December 2015
ROCXY MOUNTAI\IFOWER customefguaranfees
PS5-Answer calls within 30 seconds
PSSa) Respond to commission complaints within 3 days
PSSb) Respond to commission complaints regarding service disconnects
within 4 hours
PSGc) Resolve commission complaints within 30 days
CGI
cG2
cG3
cG4
cG5
cG6
cG7
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.
20tE
EIE f.t ! igm. Prll
b ELlng lrttiliis
bMtrftoblcnrs
lleeB 0 l(Irr to8&t 0 r(tr* a05flt 0 l(xfi gl
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rzqtD7 0 lcrr to768 1 99.878 t6o6S 0 t(Irr $0
xn 0 ,qr* t0479 0 t(It* t0161 0 t(Ir* g,
t1g 5 s.$tr t250
Page 39 of 42
ROCKY MOUNTAIN
FOYI'ER IDAHO
Service Quality Review
January - December 2015
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 1365-2OO3/2OL2e Standard
for Reliability lndices.
Sustained Outage
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentory Outage 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 L366-2OO312012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliabilitv lndices
SAIDI
SAIDI (system average interruption duration index) is an industry-defined term to define the average duration
summed for all sustained outages a customer experiences in a given period. lt is calculated by summing all
customer minutes lost for sustained outages (those exceeding 5 minutes) and dividing by all customers served
within the study area. When not explicitly stated otherwise, this value can be assumed to be for a one-year
period.
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 L366-2OL2. 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.
CA'DI
CAIDI (customer average interruption duration index) is an industry standard index that is the result of dividing
the duration of the average customer'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
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).
e IEEE 136&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.
Page 40 of 42
ROCKY MOIJNTAIN
PIOYI,ERANStrrcmm
IDAHO
Service Quality Review
January - December 2015
MAlFle
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.
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: WeightinB Factor 0.20, Normalizing Factor 0.70
Lockouts: Weighting Factor 0.20, Normalizing Factor 2.00
Therefore, 10.545*((3-yearSAlDl *0.30*0.029) +(3-yearSAlFl *0.30*2.4391+(3-yearMAlFl *0.20*
0.70)+ (3-year breaker lockouts * 0.20 * 2.00))= CPI Score
cPt0s
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.
Performance Tvpes & Commitments
Rocky Mountain Power recognizes several categories of performance; major events and underlying
performance. Underlying performance days may be significant event days. Outages recorded during any day
may be classified as "controllable" events.
Major Events
A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value
(Reliability Standard IEEE 1366-2012) based on the 2.5 beta methodology. The values used for the reporting
period and the prospective period are shown below.
Significant 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
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IDAHO
Service Quality Review
January - December 2015
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 and customer requested
interruptions.
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 Anolysis section of this report
contains two tables for Controllable Distribution and Non-controllable Distribution, which list the Company's
performance by direct cause under each 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.
ROCKY MOUNTAINms*
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