20170615Service Quality Report 2016.pdf

il _ :l ::, ','t DROCKY MOUNTAIN
BP,yy.E-.n"*
June 15,2017
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116ar:,1'!
L",;: !1,',' r'a. r '-J r..J,-.iJ
Re:
VA OWRNIGHT DELIVERY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,lD 83702
PAC-E-04-07 2016 Seryice Quality & Customer Guarantee Report for the period
January 1 through December 31,2016.
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy ofthe 2016 Service Quality& Customer Guarantee Report. It is accompanied by an excel file (Idaho 2014 ORR data
support.xlsx) containing two worksheets supporting the Open Reliability Reporting Process (ORR),
which is the new best-cost reliability improvement program which the Company has developed; one
worksheet, titled "Approvsd" delineates line-item data for the selected reliability projects to be
completed, while the worksheet, titled "Effectiveness" delineates the completed projects'
performance results for those projects which have had suffrcient time since their implementation to
gauge effectiveness. Commission Staffrequested this detail for the initial reporting on this program.
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 commitmentthe Company filed an application2 with the Commission requesting
authorization to extend these progtams, which has been subsequently amended and extended.
If there are any additional questions regarding this report please contact Ted Weston at
(80r)220-2963.
ItjL
, P.E.
Director-T&D Asset Performance
Enclosures
cc:Terri Carlock
Beverly Barker
I Case No. PAC-E-99-01
2 Case No. PAC-E-04-07
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE qUAIITY
REVIEW
January L- December 3I,201,6
Report
\
ROCKY MOI'NTAN
POYI'ER IDAHO
Service Quality Review
January - December 2015
TABLE OF CONTENTS
TABLE OF CONTENTS
EXECUTIVE SUMMARY
1 SERVICE STANDARDS PROGRAM SUMMARY
1.1 ldaho Customer Guarantees
1.2 ldaho Performance Standards
2 RELIABILITYPERFORMANCE...,.........
2.1 System Average lnterruption Duration lndex (SAlDl)
2.2 System Average lnterruption Frequency lndex (SAlFl)
2.3 Momentary Average lnterruption Event Frequency lndex (MAlFl").....................
2
3
3
3
4
5
7
8
9
2.4 ReliabilityHistory..............13
2.5 Controllable, Non-Controllable and Underlying Performance Review
2.6 Cause Code Analysis
2.6.L Underlying Cause Analysis Table
2.6.2 Cause CategoryAnalysis Charts............
2.7 Reliability lmprovement Process
2.7.L ReliabilityWorkPlans.......2.7.2 Project approvals by district.
2.7.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
2.8 Geographic Outage History of Under-performing Areas............
2.9 Restore Service lo 80% of Customers within 3 Hours
2.10 Telephone Service and Response to Commission Complaints
3 CUSTOMERGUARANTEES PROGRAMSTATUS...........
4 APPENDIX:ReliabilityDefinitions
t4
16
.....L7
..... 18
19
19
19
20
22
34
34
34
35
Page 2 of 37
V.ROCKY MOI.INTAINIPOtrER.\emuarumr
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 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.
I SERVICE STANDARDS PROGRAM SUMMARY1
1.1 ldaho Customer Guarantees
Note: See Rules for a complete description of terms ond conditions for the Customer Guarontee Progrom.
1 On June 29,2012, in Docket PAC-E-12-02 and Order 32583, the Commission ordered that Rocky Mountain Power had delivered upon commitments it
made in pursuant to the MidAmerican transaction in PAC-E-05-08 and Order 29998. The Commission also ordered the acceptance of modifications to the
Service Standards Program proposed by Rocky Mountain Power, as shown on Page 4 of 15.
Page 3 of 37
Customer Guarantee 1:
Restorinc Suoolv 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:
Apoointments
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 Companv
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
workinq 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 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.
\
R()cKY
POIYT'ER
MOUNTAlN IDAHO
Service Quality Review
January - December 2015
t.2 ldaho Performance Standards
Note: Performonce Stondards 7, 2 & 4 are for underlying performance doys and exclude those clossified ds Mojor
Events.
2 When in the future, the Company discovers that marginal improvement costs outweigh marginal improvement benefitg the Company can propose
modifications to the Performance Standards Program to recognize that maintaining performance levels is appropriate.
3 Reliability performance indicators (RPl) will be calculated by agSregating customer transformer level SAlDl, SAlFl, and MAlFl, and are exclusive of major
events as calculated by IEEE 135G2012; they are a modification to the Company's historic CPl. RPI excludes breaker lockout events.
4 Prospectively, the Company will work with Commission Staff to determine methods to report the target area performance and cost-beneflt results.
Page 4 of 37
Network Performance Standard 1:
Report System Average lnterruption Duration lndex
(sArDt)
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:
lmprove2 U nder-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 LOYI 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 SOYo 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
Companv's eQualiW monitoring svstem.
Customer Service Performance Standard 6:
Commission Complaint Response / Resolution
The Company will a) respond to at least 95% of non-
disconnect Commission complaints within three working
days and will b) respond to at least 95% of disconnect
Commission complaints within four working hours, and will
c) resolve 95% of informal Commission complaints within
30 days.
ROCKY MOUNTAIN#a.,IDAHO
Service Quality Review
January - December 2015
2 RELIABILITY PERFORMANCE
For the reporting period, the Company experienced underlying interruption duration (SAlDl) and interruption
frequency (SAlFl) performance in ldaho that was favorable to plan. Results for ldaho underlying performance can
be seen in subsections 2.1 and 2.2 below.
Major Event General Descriptions
Five events during the reporting period met the Company's ldaho major event threshold levels for exclusion from
underlying performance results.
May 9, 2015: Rexburg, ldaho experienced a wind storm coupled with equipment that was damaged at a
substation resulting in a loss of substation event. The storm caused several localized outages causing
lines to connect, blowing fuses and tripping circuit breakers. The wind also caused damage to facilities
breaking crossarms and poles.
July 19, 2015: The 161 kilovolt (kV) capacitor bank inside the Goshen Substation, in Shelley, ldaho,
experienced an internalfault, when two crows made contact with the capacitor bank. The capacitor bank
locked out and caught fire, subsequently causing the east and west substation busses to trip.
August 29,20L6: Rexburg, ldaho, experienced an outage when one ofthe three phase conductors on a
69 kilovolt (kV) line failed and fell to the ground. The event affected L6,497 customers, or approximately
51% of the customers served in the Rexburg operation area.
December 5, 2016: While operating in an abnormal configuration related to a scheduled construction
project, Rocky Mountain Power customers in Preston, ldaho, experienced an outage resulting from a line
failure which operated the protective equipment of a mobile transformer. Attempts to close the
protective equipment resulted in a series of outages over a 15 hour period.
December 7, 2OL6: Rocky Mountain Power customers in Rexburg, ldaho, experienced an outage when
a potential transformer (PT) at the Rigby Substation failed. The failed PT damaged the operate bus
causing several other circuit breakers in the substation to de-energize. Station service power was also
lost. The event affected 17 substations, feeding 46 circuits, serving 27,778 customers, for durations
ranging from 2 hours 42 minutes to 5 hours 23 minutes.
5 Major event threshold shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
th-L2137120L6 76,971 L4.82 t,l4t,O67
a
a
a
a
a
Date Cause SATDI
May 9, 2016 Wind Storm/Loss of Supply 18.33
July 19,2016 Loss of Substation 86.47
August 29,2OLG Loss of Transmission 2L.45
Loss of Substation 24.O3December 5-6,2016
Loss of Substation 89.64December 7-8,2016
Page 5 of 37
x IDAHO
Service Quality Review
January - December 2015
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 ten significant event dayss were recorded, which
account for 63 SAIDI minutes; about 42% of the reporting period's underlying 152 SAIDI minutes.
ROCKY MC'I,NTAIN
HSIH*
Date Cause: General Desclptbn EuentSAlDl xof Toral$lDl
March 14 2016 Loss of Transmission - high winds 4.32 6.8%
Aprll24 2016 Loss of Substation - blown fuse 4.49 7.O%
June 4 2015 Loss of Supply - circuit breaker lockout 6.49 LO.2%
June 9,2016 Lightning 10.89 L7.Lo/o
July 25, 2016 Equipment failure: underground fault 9.80 6.4%
July 2& 2015 Equipment failure: blow fuses and burnt insulator s.58 3.7%
August 18,2016 Car hit pole 4.67 3.t%
September 23,2016 Pole Fire 3.83 25%
october l7,2ot6 Weather/pole fires 6.24 4.t%
october 30,2016 Loss of transmission 6.7L 4.4%
TOTAT 53.13 41.5%
5 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAl0l results.
Page 6 of 37
\
ROCKYPol,YER MC'I.INTAlN IDAHO
Service Quality Review
Actual
(reporting period)
Plan
(year-end)
392Total (major event included)
U nderlying (major event excluded)L52 L70
Controllable 43
2.1 System Average lnterruption Duration lndex (SAlDl)
The Company's underlying interruption duration performance for the year was favorable to plan
January - December 2015
t00
380
360
340
320
300
280
260
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220
200
180
160
140
L20
100
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PageT of37
x R()cKYPOWER MOUNTA|N IDAHO
Service Quality Review
January - December 2016
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying interruption frequency performance results for the year are favorable to plan
tDAt{o sAtFt
(erdudcs Prcrrangcd rnd qrstomer Requcsted)
12
30
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Actual
(reporting period)
Plan
(vear-end)
3.040Total (major event included)
UnderlyinS (major event included)L.362 L.547
0.322Controllable
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Page 8 of 37
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ROCKY
POYI'ER
MOUNTAlN IDAHO
Service Quality ReviewAdm*ffiP
January - December 2016
2.3 Momentary Average Interruption Event Frequency lndex (MAlFlel
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 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 Bancroft #12: the circuit breaker log shows a total of l trip in 2016. lt appears a recording error has
occurred and will be corrected.
o Arco #12: the control was changed in March of 2015. The control is where the counter information is
recorded. The new control's initial trip count was 739. There were no trips in 2015.
o Targhee #12: this breaker was test tripped as part of its normal maintenance plan. Fifty-nine were not
actual trips, but test trips while offline. ln 2016 the breaker experienced 10 trips while online.
o Winsper #22:the breaker was changed out on May 23, 2015 and a new breaker was installed. The new
breake/s initial trip count was 509. There were no trips in 2015.
7 ldaho state commitment l1O.
On January 31, 2005, the Commission accepted Rocky Mountain Power's proposal to eliminate its Network Performance Standard relating to Momentary
Average lnterruption Frequency lndex (MAlFl) in light of the Company's commitment to develop an acceptable alternative to MAIFI as soon as possible. The
Company has developed its proposed measurement plan and is scheduled to present to the Commission Staff at its ne)ft reliability meeting (scheduled for
December 20, 2005). Within 60 days after this meetin& the Company will file the plan with the Commission. MEHC and Rocky Mountain Power commit to
implement this plan and provide the results of these calculations to Commission Staff and other interested parties in reliability review meetings.
Page 9 of 37
Operating Area MAIFI" (SCADA)
Montpelier Not applicable
Preston 0.639
Rexburg 0.700
Shelley 1.519
Operating Area Circuit Name Circuit lD Operations Corrected
Operations
ALEXANDER f11 ALx11MONTPELIER 5
MONTPELIER ARTMO #11 ARM11 0
MONTPELIER ARrMO #12 ARM12 5
MONTPELIER BANCROFT #11 BAN11 8
MONTPELIER BANCROFT#12 BAN12 69 1
MONTPELIER CHESTERFIELD #11 cHsl1 0
MONTPELIER CHESTERFIELD #12 HATCH cHs12 0
MONTPELIER covE *12 cov12 1
MONTPELIER EIGHT MILE #11 EGT11 10
MONTPELIER GEORGETOWN #11 GRG11 13
GRACE #11 GCE11MONTPELIER 2
MONTPELIER GRACE #12 GCE12 0
MONTPELIER HENRY #11 HRY11 0
MONTPELIER HORSLEY #11 HRS11 7
MONTPELIER INDIAN CREEK #11 IND11 4
MONTPELIER LAVA #11 LVA11 1
MONTPELIER LUND #11 LND11 15
MONTPELIER MCCAMMON #11 MCC11 1
x ROCKYPOWH1
MOI,.INTAIN IDAHO
Service Quality Review
Operating Area Circuit Name Clrcult lD Operations Corrected
Operations
MCCAMMON #12 MCC12 1MONTPELIER
MONTPELIER MONTPELIER #11 MNT11 0
MONTPELIER #13 MNT13 0MONTPELIER
MONTPELIER MONTPELIER #14 MNT14 t
ST CHARLES #11 STC11 4MONTPELIER
PRESTON CLIFTON #11 DAYTON & BANIDA CLF11 1
PRESTON CLI FTON #12 CLIFTON/OXFORD/SWAN LAKE CLFL2 11
PRESTON DOWNEY #11 DWN11 t
DOWNEY #12 DWN12 0PRESTON
PRESTON HOLBROOK #11 HLB11 1
PRESTON MAI.AD fl1 MLD11 t
PRESTON MALAD #12 MLD12 3
PRESTON MALAD #13 MLD13 1
PRESTON TANNER #11 MINK CREEK TNR11 9
TANN ER #12 RIVERDALE/TREASU RETON TNR12 10PRESTON
PRESTON WESTON #12 NORTH TO DAYTON WST12 4
WESTON#11 SOUTH . WESTON/FAIRVEW WST11 3PRESTON
REXBURG ANDERSON #11WEST ANDl1 21
ANDERSON #12 EAST AND NORTH AND12REXBURG 8
REXBURG ANDERSON #13 NORTH AND13 5
REXBURG ARCO #11 ARC11 49
REXBURG ARCO #12 ARC12
REXBURG ARCO #13 ARC13 1
REXBURG ASHTON #11 ASH11 19
REXBURG BELSON #11 BLS11 30
REXBURG BELSON #12 BLS12 23
REXBURG BERENICE #21 BRN21 5
REXBURG BERENICE #22 BRN22 10
REXBURG CAMAS #11 cMs11 0
REXBURG CAMAS #12 cMs12 3
REXBURG CANYON CREEK # 22 CNY22 2
REXBURG CANYON CREEK #21 CNY21 1
REXBURG DUBOTS #11 DBS11 7
REXBURG DUBOTS #12 DBS12 0
REXBURG EASTMONT#11 EST11 0
REXBURG EASTMONT#12 EST12 2
REXBURG EGIN #11 EGN11 4
REXBURG EGIN #12 EGN12 5
REXBURG HAMER #11 HMR11 3
REXBURG HAMER #12 HMR12 0
MENAN #11REXBURG MNN11 3
REXBURG MENAN #12 MNN12 t
MENAN #13REXBURG MNN13 7
REXBURG MILLER #11 MLLl1 3
REXBURG MILLER #12 MLL12 2
REXBURG MOODY#11 MDY11 44
REXBURG MOODYfI2 MDY12 45
REXBURG MOODY#13 MDY13 48
REXBURG MUDIAKE #11 MDLl1 1
REXBURG MUDISKE #12 MDL12 0
REXBURG NEWDALE f11 NWD11 0
REXBURG NEWDALE #12 NWD12 0
January - December 2015
Page 10 of 37
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ROCKYPOWER MOt,NTAIN IDAHO
Service Quality Reviewrc6mP
January - December 2015
Corrected
OoeratlonsOperating Area Circuit Name Circuit lD Operations
NEWDALE #13 NWD13 5REXBURG
5REXBURGRtRtE #12 RIR12
ROBERTS f11 RBR11 0REXBURG
RBR12 2REXBURGROBERTS #12
RUBY #11 RBY11 20REXBURG
REXBURG SANDUNE #21 SDN21 19
SANDUNE #22 SDN22 1REXBURG
REXBURG sMrTH #11 SMT11 0
SMT12 3REXBURGsMtTH #12
sMtTH #13 SMT13 3REXBURG
SMT14 7REXBURGsMtTH #14
SOUTH FORK #11 IDAHO PACIFIC POTATO SFK11 2REXBURG
SFK13 3REXBURGSOUTH FORK #13 ANTELOPE FLATS
STANTHONY f11 STA11 0REXBURG
STA12 0REXBURGSTANTHONY #12
STANTHONY f13 STA13 7REXBURG
SGR11 2REXBURGSUGAR CITY #11
REXBURG SUGAR CITY #12 SGR12 3
SGR13 13REXBURGSUGAR CITY #13
REXBURG SUGAR CITY #14 SGR14 2
SNN11 2REXBURGSUNNYDELL f11
SUNNYDELL #12 SNN12 11REXBURG
TRG11 L4REXBURGTARGHEE #11
REXBURG TARGHEE #12 TRG12 @ 10
THR11 3REXBURGTHORNTON #11
THORNTON #12 THR12 8REXBURG
WTK11 4REXBURGWATKINS #11 NORTH AND EAST
WEBSTER #11 EASTAND SOUTH wBs11 3REXBURG
WBS12 7REXBURGWEBSTER #12 NORTH
REXBURG WEBSTER #14 WBS14 18
wNs21 8REXBURGWINSPER #21
REXBURG WINSPER #22 wNs22 scl 0
lSHELLEYAMMON #11 AMM11
AMMON #12 AMM12 1SHELLEY
SHELLEY Cinder Butte #11 clB11 4
CINDER BUTTE #13 crB13 1SHELLEY
ctB17 0SHELLEYCinder Butte #17
SHELLEY CLEMENTS f11 CLE11 19
CLE12 77SHELLEYCLEMENTS #12
SHELLEY GOSHEN #11 GSH11 5
GOSHEN #12 GSH12 7SHELLEY
SHELLEY GOSHEN #13 GSH13 7
HAYES #11 HYS11 0SHELLEY
SHELLEY HAYES #12 HYS12 0
HAYES #13 HYS13 0SHELLEY
SHELLEY HOOPES #11 WEST HPS11 7
HOOPES f12 NORTH HPS12 5SHELLEY
0SHELLEYIDAHO FALLS #11 IDF11
IDAHO FALLS #12 IDF12 0SHELLEY
IDF13 0SHELLEYIDAHO FAL6 f13
IDAHO FALLS #14 IDF14 0SHELLEY
JFF2L 36SHELLEYJEFFCO #21
SHELLEY JEFFCO*22 JFF22 15
Page 11 of 37
x ROCKY MOI,NTANffi*IDAHO
Service QualiW Review
Circuit Name Clrcult lD Operations Corrected
OperationsOperatlng Area
SHELLEY KETTLE #21 KTT21 24
KETTLE #22 KTI22 7SHELLEY
SHELLEY MERRILL #11 MRR11 2
MRR12 26SHELLEYMERRILL #12
SHELLEY MERRILL #13 MRR13 4
MRR14 10SHELLEYMERRILL #14
SHELLEY oscooD #11 osc11 10
osc12 1SHELLEYoscooD #12
SHELLEY oscooD #13 osc13 0
osc14 L7SHELLEYoscooD #14
SHELLEY SANDCREEK #11 SND11 32
SND12 LSHELLEYSANDCREEK #12
SHELLEY SANDCREEK S13 SND13 0
SND14 1SHELLEYSANDCREEK #14
SHELLEY SANDCREEK #15 SND15 2
SND16 5SHELLEYSANDCREEK f15
SHELLEY SHELLEY f11 SHL11 0
SHL12 19SHELLEYSHELLEY f12
SHELLEY SHELLEY #13 SHL13 4
SHL14 9SHELLEYSHELLEY f14
ucoN #11 UCN11 4SHELLEY
UCN12 7SHELLEYucoN f12
WATKINS #12 SOUTH THEN EAST WTK12 1SHELLEY
January - December 2015
Page \2 ol 37
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ROCKYPol,YER MOt,NTAIN !DAHO
Service Quality Review
January - December 2016
2.4 Reliability History
Depicted below is the history of reliability in ldaho. ln2OO2, the Company implemented an automated outage
management system which provided the background information from which to engineer solutions for improved
performance. Since the development of this foundational information, the Company has been in a position to
improve performance, both in underlying and in extreme weather conditions. These improvements have
included the application of geospatial tools to analyze reliability, development of web-based notifications when
devices operate more than optimal, focus on operational responses via CAIDI metric analysis, in addition to
feeder hardening programs when specific feeders have significantly impacted reliability performance.
ldaho Reliability History - lncluding Major Events
ISAIDI ICAIDI +sAtFt
4 600
500
/mO
:!oo
200
100
3.0
3 2.7 2.9
2.6
0Cotld
1.9 2.1
,ia,+atE
=
2
1
0
cv07 cYo8 cY09 cY10 cY11 cY12 CY13 CY14 CY15 CY16
tdaho Reliability History - Excluding Major Events
ISAIDI ICAIDI +SAIFI
4 tlOO
300
200
1@
3 2.6
2.1 2.'6a,oI
.E-
g
E
3rat
2.
2 1.5 1.5 1.4
I
o
cy07 cyo8 cY(x, cY10 c.r1l cY12 cY13 cY14 CYts CY16
OINNqlrnoFiO
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ON
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Page 13 of 37
x ROCKYPOffiR MOUNTTA|N !DAHO
Seruice Quality ReviewAMCre
January - December 2016
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 Iightning 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 outages8. 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 etdreme
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 36$Day bllllU GontrollaUe Hbtoryas Feported
,@
90
to
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8 3. The Company shall provide, as an appendix to its Service Quality Review report$ informatlon regarding non-controllable outages, including, when
applicable, descriptions of efforts made by the Company to improve service quallty and rellabillty for causes the Company has identified as not controllable.
4. The Company shall provide a supplemental filing, within 90 dayt consisting of a process for measuring performance and improvements for the non-
controllable events.
Page 14 of 37
x R()cKYPOWER Ir/lOUmAlN IDAHO
Service Quality Review
ldaho 36$Day Folllng NonControllable Hbtoryas Reportedu
2!0
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0
January- December2015
Page 15 of 37
\
IDAHO
Service Quality Review
January - December 2016
2.6 Cause Code Analysis
The tables below outlines categories used in outage data collection. Subsequent charts and table use these
grou to deve for o rformance.
ROCKY MOUNTAIN
BglfEA"
Dlrect Cause
CateSory Category Definltlon & Example/Dlrect Cause
Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels or other animals,
whether or not remains found.
Animals
o Animal (Animals). Bird Mortality (Non-protected species)
o Bird Mortality (Protected speciesXBMTS)
r Bird Nest
o Bird or Nest
o Bird Suspected, No Mortality
ContaminationorAirborneDeposit(i.e.salt,tronaash,otherchemical dust,sawdust,etc.); corrosive
environment; ffooding due to rivers, broken water main, etc.; fire/smoke related to forest, brush or building
fires (not including fires due to faults or lightning).
r Major Storm or Disasterr Nearby Fault
o Pole Fire
o Condensation/Moisture. Contamination
o Fire/Smoke (not due to faults)r Floodins
Environment
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
bv fault on nearby equipment (e.8., broken conductor hits another line),
Equipment
Fallure
. B/o Equipment
o Overload
. Deterioration or Rotting
o Substation, Relavs
Willful damage, interference or theft; such as gun shots, rock throwing, etc.; customer, contractor or other
utiliO 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/Contractorr Vehicle Accident
o Dig-in (Non-PacifiCorp Personnel)r Other lnterfering Object
o Vandalism or Theft
Failure of supply from Generator or Transmission system; failure of distribution substation equipment.Loss of
Supply r Failure on other line or stationr Loss of Feed from Supplier
o Loss ofGenerator
r Loss of Substationr Loss of Transmission Line. System Protection
Accidental Contact by PacifiCorp or PacifiCorp's Contractors (including liveline work); switching error;
testing or commissioning error; relay setting error, including wrong fuse size, equipment by-passed; incorect
circuit records or identification; faulty installation or construction; operational or safeW restriction.
Operational
. Contact by PacifiCorp. Faulty lnstall. lmproper Protective Coordination. lncorrect Records
o lnternal Contractor
o lnternal Tree Contractor
o Switching Errorr Testing/Startup Errorr Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons.0ther
r Unknowno lnvalid Code
. Other. Known Cause
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
. 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/Heatr Freezing Fog & Frostr Wind
o Lightningr Rain
o Snow. Sleet, lce and Blizzard
Page 15 of 37
Y IDAHO
Service Quality Review
January - December 2016
2.6.L Underlying Cause Analysis Table
The table and charts below show the total customer minutes lost by cause and the total sustained interruptions
by cause. The Underlying cause analysis table includes prearranged outages (Customer Requested ond Customer
Notice Given line items) with subtotals for their inclusion, while the grand totals in the table exclude these
prearranged outages so that grand totals align with reported SAIDI and SAIFI metrics for the period.
ldaho Cause Analysis -Unde rlvlnr 0 U Oil 2016 - Lzl ?ll 2016
Direct Cause
Customel
Minutes Lost for
lncident
Customers in
lncident
Sustained
Sustained
lncident
Count
SAIDI SAIFI
ANIMALS 63,764 930 135 0.83 0.012
BIRD MORTALITY ( NON-PROTECTED SPECIES)t28,514 t,97L L28 7.67 0.025
BIRD MORTALITY (PROTECTED SPECIES) (BMTS)61,611 487 29 0.80 0.006
BIRD NEST (BMTS}34,24L 224 3 o.44 0.003
BIRD SUSPECTED, NO MORTALITY L43.92L 7,437 40 1.87 0.019
ANIMALS 432,051 5.049 335 5.61 0.066
coNDENSAT|ON / MOTSTURE 10.955 228 1 0.14 0.003
FIRE/SMOKE (NOT DUE TO FAULTS)69.506 75 9 0.90 0.001
ENVIRONMENT 80,561 303 10 1.05 0.m4
B/O EQUIPMENT 338,555 3,188 145 4.40 0.041
DETERIORATION OR ROTTING 2.s24.398 16,489 591 32.80 o.274
OVERLOAD t57 3 2 0.00 0.000
POLE FIRE 493,55s 2,408 34 6.4L 0.031
STRUCTURES, INSULATORS, CONDUCTOR 659 1 8 0.01 0.000
EqUIPMENT FAITURE 3.357.1145 22,O89 7AO 43.62 o.247
DtG-rN (NON-pACtFtCORp PERSONNEL)32,O49 206 27 0.42 0.003
OTHER INTERFERING OBJECT 74.704 451 2L 0.97 0.006
OTHER UTILITY/CONTRACTOR 8,852 208 6 0.11 0.003
VEHICLE ACCIOENT r,L49,t79 9.585 76 L4.93 0.126
INTERFERENCE r,26,.,7u 10,550 130 16.43 0.117
LOSS OF SUBSTATION 234,428 619 5 3.0s 0.008
LOSS OF TRANSMISSION LINE L,942,8t2 27,367 L27 25.24 0.356
LOSS OF SUPPTY 2,L77,240 2r,986 tt2 28.29 0.364
FAULTY INSTALL 76 1 1 0.00 0.000
IMPROPER PROTECTIVE COORDINATION 46 1 1 0.00 0.000
PACIFICORP EMPLOYEE - FIELD 201 22 1 0.00 0.000
OPERATIONAL 32?24 3 0.00 0.(x)0
OTHER, KNOWN CAUSE 26,022 584 42 0.34 0.008
UNKNOWN 636,300 7,547 38s 8.27 0.098
OTHER 662,323 8,131 427 8.50 0.106
CONSTRUCTION 64,6U 663 30 0.84 0.009
CUSTOMER NOTICE GIVEN 903,276 6,567 135 7L.74 0.085
CUSTOMER REQUESTED 98 2 3 0.00 0.000
EMERGENCY DAMAGE REPAIR 882,L62 11,355 t62 rt.46 0.148
INTENTIONAL TO CLEAR TROUBLE 276,890 3.088 18 2.82 0.040
PLANNED NOTICE EXEMPT 7t7,t63 L,879 18 L.52 0.024
TRANSMISSION REQUESTED 6,570 t42 1 0.09 0.002
PI.ANNED 2,190,941 23,596 367 28.46 0.308
TREE. NON.PREVENTABLE 2to.760 t,904 67 2.74 0.025
TREE . TRIMMABLE 10.459 73 15 0.14 0.001
TREES 221,229 1,977 82 2.87 0.026
tcE 2t3 3 3 0.00 0.000
LIGHTNING 1,s96,027 8,283 L32 20.74 0.108
SNOW, SLEET AND BLIZZARD 347,4t5 2,474 32 4.51 0.032
WIND 401,883 2,734 LL4 s.22 0.036
WEATHER 2,!145,538 t3,494 28t 30.47 0.175
ldaho lncluding Pttarranged 12.7t2,335 113.2!t9 2,y8 t;65.42 1.472
ldaho Excludlng Prearranged tt,7tt.7!n 104,851 2.r92 152.16 1.352
Note: Direct Causes are not listed if there were no outages classified within the cause during the reporting period.
Page17 ol37
ROCKY MOUNTAINPOI'ER
IDAHO
Service Quality Review
January - December 2016
2.6,2 Cause Category Analysis Charts
The charts show each cause catego4y's role in performance results and illustrate that certain types of outages
account for a high amount of customer minutes lost but are infrequent, while others tend to be more frequent
but account for few customer minutes lost.
Cause Analysls - Customer Mlnutes Lost (SAlDl)
C WEAI{ER 2096
Y TREES2'6 I ANIMALS496
3 P1ANiIEDl(l'6 ! ENVIRONMEilT0,6
! OPERATIONAI.O'6
T OTHER 5X I EQI'IPMENT
FAITURE 2gT
I LOSSOFSUPPIYlSfi
I INTERFEREilCE 11'6
C:use Analysis - Customer lnterruptlons (SAlFll
3 WEATHER
Y TREES2,6
1 ,6 ! ANMAI.S5tr
! EI{VIRONMENTO'6
ROCKY MOI'NTANHSIH*
I PTANNEDI'I'6
I OPERANONALO*
T OTHERE.
I EQUIPMENT
FALURE 21tr
INTERFERENCE 10,'
I LOSSOFSUPPLY2T%
Cause Analysls - Sustalned lncldents
I E1{VIROT{MENTO'6 I EQUIPMENT FAITURE 32Sr At{tMA[s 1416
T WEAIHER UT
I TREEs3'6 I II{TERFERENCE 'tt6
r PtANNEDlOff ! tossoFsuPPtY69S
T OPERANONAI.(,'6 I OTHER 1E"
Page 18 of 37
\
MOt.lNTAN IDAHO
Service Quality Review
January - December 2015
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.
2.7.1 Reliability Work Plans
The Company has worked to improve reliability through Reliability Work Plans. To assist in identification of
problem areas, Area lmprovement Teams (AlT) meetings and Frequent lnterrupters Requiring Evaluation (FIRE)
reports have been established. On a daily basis the Company systems alert operations and engineering team
members regarding outages experienced at interrupting devices (circuit breakers, line reclosers and fuses). When
repetition occurs, it is an indicator that system improvements may be needed. On a routine basis, local
operations and engineering team members review the performance 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.
ROCKYPOIi'ER
Page 19 of 37
\
ROCKY MOt.INTAINffin*IDAHO
Seruice Quality Review
Effectlveness Metr{cs ln ProgrEss
Plans
Meetllg
Goals (>1
yearslne
prorect
mmoletlonl
Esffmated
AYolded
annuol CItIL
ArcfuAI
Avolded
annual Oti!
audgeted
Cost per
annual
rYolded
cMr
Actual
Cost per
annual
arolded
cMr
PlarNot
Meetlng
Goals (not
lncluded ln
metdcsl
Plans
waldrgfor
lnfornaUon
Lava 3 s1.18 3 235,361 374.223 s1.18 s0.61 0 0
Preston 2 52.79 1 LO2,@7 4L0.428 s1.88 s0.s9 0 1
Rexburg 5 52.31 3 226,3il 537.298 52.06 s0.30 1 t
Shelley 3 53.04 7 2,159 6,169 s20.84 s0.00 t 1
TOTAI.t3 sz.oz 8 566,tt91 t,w,tt8 3r.eo so.ss 2 3
January - December 2016
2.7.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln 2OL2, 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 fortargeted 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 lmorovement (post 12131/2011 throueh 12131/2016)
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
x ROCKY MOUNTA|N#s*IDAHO
Service Quali{ Review
January - December 2016
(lmprovement targets for circuits in Program Years 1-11 and 13-15 have been met and filed in prior reports.)
PROGRAM YEAR 17 (RPl) Method
Clifton 11 (Figure 3C)IN PROGRESS 225 243
IN PROGRESS 195 186Dubois 12 (Figure 4C)
TARGET SCORE = 189 2t0 214
PROGRAM YEAR 16
Lava 11 (Figure 1C)COMPLETE L27 58
COMPLETE 36 79Preston 11 (Figure 2C)
TARGETSCORE = 73 a2 74
PROGRAM YEAR 15
PROGRAM YEAR 12
COMPLETED L24Grace 12 106
Preston 13 COMPLETED LO2 104
TARGETSCORE = !10 113 105
Page 21 of 37
xROCKY
FOM'ER
itounrrAlN IDAHO
Service Quality Review
Il. ,, I
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2.8 Geographic Outage History of Under-performing Areas
Figure 1A: Lava 11 Controllable View
January- December2016
Page2} of 37
xROCKY l,lOt[tITAlNrrowERAOlmCM
IDAHO
Service Quality Review
-t
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January - December 2015
Page23 ot 37
x R(NKYPOII'ER MOt.lNXAIN IDAHO
Service Quality Review
O sta.tac
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Flgure lC: Lava 11 Underlying View excluding Loss of Supply
January - December 2016
Page} of 37
ta6s
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\-
\
ROCKY MOUNTA|N
POWERAuvGoC@P
IDAHO
Service Quality Review
January - December 2015
Figure 2A: Preston 11 Controllable View
Paee2! of 37
\
ROCKYPOWER MOt,NTAIN IDAHO
Service Quality Review
O rrttror
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January - December 2015
Page25 ol 37
\
ROCKY
PCTTER
MC't.lNTAIN IDAHO
Service Quality ReviewAMem
January - December 2016
Figure 2C: Preston 11 Underlying View excluding Loss of Supply
I
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Page27 ol 37
R(XKY MOI.lh]TAlNPOM'ERAffiCM
IDAHO
Service Qualiry Review
aire*l.r
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January - December 2016
Page 28 of 37
x R(XI(YrroilER ircU}ITAr{IDAHO
Servlce Quallty Reviewamcm
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January - December 2015
Page29 ot37
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FOWEIT
IUlouhrrAlN IDAHO
Servlce Quallty ReviewAMGre
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January- December2016
Page 30 of 37
x R(XKY MOUNTAINPolA'ER IDAHO
Service Quality Review
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Page 31 of 37
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Service Quality Review
January - December 2015
Figure 48: Dubois 12 Non-Controllable View
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January - December 2015
Page 33 of 37
-.Rotr;KY
MOI.INTAIN!ps61!eumam
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
customefguarantees
January- December2015
Januaryb Desnber2016
February March April May JuneJanuary
98%9L%89%87%89%97%
July August September October November December
98%94%79%9L%90%76%
PS5-Answer calls within 30 seconds 80%8L%
PS6a) Respond to commission complaints within 3 days 95%L00%
PSGb) Respond to commission complaints regarding service disconnects
within 4 hours 95%100%
95%L00%PS5c) Resolve commission complaints within 30 days
cGl
cG2
ccit
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.
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Page 34 of 37
\
MOT'NTAIN 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 1366-20O3l2OL2e Standard for
Reliability lndices.
Sustoined Outdge
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentory Outoge Event
A momentary outage event is defined as an outage equalto or less than 5 minutes in duration, and comprises all
operations of the device during the momentary duration; if a breaker goes to lockout (it is unable to clear the
faulted condition after the equipment's prescribed number of operations) the momentary operations are part
of the ensuing sustained interruption. This sequence of events typically occurs when the system is trying to re-
establish energy flow after a faulted condition, and is associated with circuit breakers or other automatic
reclosing devices. Rocky Mountain Power uses the locations where SCADA (Supervisory Control and Data
Acquisition) exists and calculates consistent with IEEE L366-ZN3/2012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliabiliw lndices
SAIDI
SAIDI (system average interruption duration index) is an industry-defined term to define the average duration
summed for all sustained outages a customer experiences in a given period. lt is calculated by summing all
customer minutes lost for sustained outages (those exceeding 5 minutes) and dividing by all customers served
within the study area. When not explicitly stated otheruise, this value can be assumed to be for a one-year
period.
DoilySAlDl
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 1366-2012. This is the day's total customer minutes
out of service divided by the static customer count for the year. lt is the total average outage duration customers
experienced for that given day. When these daily values are accumulated through the year, it yields the yea/s
SAIDI results.
SAIFI
SAIFI (system average interruption frequenry 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
e IEEE 1355-2003/2012 was first adopted by the IEEE Commissioners on December 23, 2003. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
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ROCKYPOWER
x MOI.INTA!N IDAHO
Service Quality Review
January - December 2016
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).
MA1Fle
MAlFlr (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'tWF*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 Factot 2.439
MAIFI: Weighting Factor 0.20, Normalizing Factor 0.70
Lockouts: Weighting Factor 0.20, Normalizing Factor 2.00
Therefore, 10.645 * ((3-year SAlDl * 0.30 r' 0.029) + (3-year SAlFl * 0.30 * 2.4391+ (3-year MAlFl r' 0.20 * 0.70)
+ (3-year breaker lockouts * 0.20 * 2.00)) = CPI Score
cPt05
CPl05 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. Unlike CPl99 it includes Major Event and Loss of Supply or Transmission outages. The
calculation of CPl05 uses the same weighting and normalizing factors as CPl99.
RPI
RPI is an acronym for Reliability Performance lndicator, which measures reliability performance on a specific
segment of a circuit to identify underperforming circuit segments rather than measuring performance of the
whole circuit.
Performance Tvpes & Commitments
Rocky Mountain Power recognizes several categories of performance; major events and underlying performance.
Underlying performance days may be significant event days. Outages recorded during any day may be classified
as "controllable" events.
Major Events
A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value
(Reliability Standard IEEE 1366-2012) based on the 2.5 beta methodology. The values used for the reporting
period and the prospective period are shown below.
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
LIL-L2(3L|2OL6 76,97t 14.82 L,L4L,O67
Ll7-1213L/2017 78,594 15.56 t,30L,447
ROCKY
PolA'ERldvEnere
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Service Quality Review
January - December 2015
Signilicont Events
The Company has evaluated its year-to-year performance and as part of an industry weather normalization task
force, sponsored by the IEEE Distribution Reliability Working Group, determined that when the Company
recorded a day in excess of 1.75 beta (or 1.75 times the natural log standard deviation beyond the natural log
daily average for the day's SAIDI) that generally these days' events are generally associated with weather events
and serve as an indicator of a day which accrues substantial reliability metrics, adding to the cumulative reliability
results for the period. As a result, the Company individually identifies these days so that year-on-year
comparisons are informed by the quantity and their combined impact to the reporting period results.
Underlying Events
Within the industry there has been a great need to develop methodologies to evaluate year-on-year
performance. This has led to the development of methods for segregating outlier days, via the approaches
described above. Those days which fall below the statistically derived threshold represent "underlying"
performance, and are valid. lf any changes have occurred in outage reporting processes, those impacts need to
be considered when making comparisons. Underlying events include all sustained interruptions, whether of a
controllable or non-controllable cause, exclusive of major events, prearranged (which can include short notice
emergency prearranged outages), customer requested interruptions and forced outages mandated by public
authority typically regarding safety in an emergency situation.
Controlloble Distribution (CD) Events
ln 2008, the Company identified the benefit of separating its tracking of outage causes into those that can be
classified as "controllable" (and thereby reduced through preventive work) from those that are "non-
controllable" (and thus cannot be mitigated through engineering programs); they willgenerally 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.
ROCKY
FOU'ERAmcrew
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