20160719Service Quality Report 2015.pdf

ROCKY MOUNTAIN
POWER
June 8,2016
VA OWRNIGHT DELIVERY
Ms. Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,lD 83702
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
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PAC -E.D-OL
Re:PAC:EE0++7{1015 Seruice Quality & Customer Guarantee Report for the period
January 1 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
progftrms 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
220-2963.
Sincerely,
report please contact Ted Weston at (801)
Torl [k D,< /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
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE AUATITY
REVIEW
January t - December 3L,2015
Report
|ROCKY MOUNTAIN
PIOU/ER
A DIWil OF TqBCOBP
IDAHO
Service Quality Review
January - December 2015
TABLE OF CONTENTS
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............ ...................2L
2.9 Restore Service lo 80% of Customers within 3 Hours ........... ........................ 39
2.10 Telephone Service and Response to Commission Complaints................. .......................... 39
CUSTOMER GUARANTEES PROGRAM STATUS......... .......................39
t.t
L.2
Page2 of 42
ROCKY MOUNTANmk"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.
T SERVICE STANDARDS PROGRAM SUMMARY1
1.1 ldaho Customer Guarantees
Customer Guarantee 1:
Restoring Supply After an Outage
The Company will restore supply after an outage within 24 hours of
notification with certain exceptions as described in Rule 25.
Customer Guarantee 2:
Appointments
The Company will keep mutually agreed upon appointments, which
will be scheduled within a two-hour time window.
Customer Guarantee 3:
Switching on Power
The Company will switch on power within 24 hours of the customer or
applicant's request, provided no construction is required, all
government inspections are met and communicated to the Company
and required payments are made. Disconnections for nonpayment,
subterfuge or theft/diversion of service are excluded.
Customer Guarantee 4:
Estimates For New Supply
The Company will provide an estimate for new supply to the applicant
or customer within 15 working days after the initial meeting and all
necessary information is provided to the 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
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 I nterruptions
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 Guorontee Progrom.
1 On June 29, 2OL2, 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 MOUNTAINFOIIER !DAHO
Service Quality Review
January - December 2015
L.2 ldaho Performance Standards
Note: Performance Standards 7, 2 & 4 ore for underlying performonce doys and 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 recognize 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 L36G2OL2; 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-benefit results.
Page 4 ot 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 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 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 L0% 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% ofcustomers on averase.
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% of informal Commission complaints within 30
davs.
IDAHO
Service Quality Review
January - December 2015
2 RELIABILIW 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
o 7l29l2Ot5: A line fault occurred on the Rigby-Thornton transmission line. During the event three
substations, 12 circuits, and 16,496 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.. 8/L/2OL5: 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
Montpeliel when the bus on the Grace 161 kV line locked out, de-energizing the 46kv 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.o 8/2912015 - 813012015: 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 MOUNTAIN#&"
2015
20t6
869,108
76,97L
15.95
t4.82
L,237,173
L,LAL,067
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 42Yo
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 MOUNTAIN
POYT'ER
Ilate Causs General Dccrlptlon EYent SAIDI % ofTotal Year
End SilllDl
March 28,20ts Snow and wind storm cause pole fire and downed line.6.07 3.1%
April 14,2015 Wind and snow storm related outage and loss of supply 10.98 5.6Yo
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.L4.47 7.3%
June 9, 2015 Wind Storm, trees on lines.5.09 2.5o/o
July 3, 2015 Neutral line down across primary lines 4.32 2.2o/o
July 20, 2015 Flash occurred at substation of manufacturing plant
causing a loss of transmission.5.20 2.6%
July 2d 2015 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 3s%
August 17,201,5 Loss of transmission, Bird nest caused flashover. Fire
restriction line patrol before restoration.4.3L 2.2%
September 22,zOLs Equipment failure. Power fuses blew on substation
transformer 5.40 3.2o/o
December 16, 2015 Loss of transmission: line down s.02 2.s%
December 31, 2015 Loss of transmission: line down 3.93 2.0o/o
TOTAT 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
2.1 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)
rA rAd€ooi;'
ROCKY MCII'NTAIN
FOWER
rnlnrnrlll.A!,il,!lrll,'888888868.\1 .\1 6lr-l^l ^lNN.{
dHH
2015 SAIDI Plan
Controlabh Actnl
.... o. Totd lndudng ttbl6rEvent3
-ufisflylqAcUal
-
urdcdylry Phn
PageT of 42
IDAHO
Service Quality Review
January - December 2015
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying interruption frequency performance results for 2015 were favorable plan.
IDAHOSAIFI
(excludes Prearranged and Customer Requested)
ROCKY MOUNTAIN
FOUIER
2.5
2.O
UIE '-sotg,
ILt t'o
o5
0.0 ia|a6ra6ra Foooooo.{ a{ .{ a\,t Al .\t
dF{Fl
SAlFlActual 2015 SAIFI Plan
Total (major event included)
-
coNtrofublcActnl
...... Totd lndudtg ttlllorhrcgts
-
Undedylq Actnl
-u6lsflyltgPbn
Page 8 of 42
IDAHO
Service Quality Review
January - December 2015
2,3 Momentary Average lnterruption Event Frequency lndex (MAIFle)
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 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.
o Clifton #11: breaker readings between July 2015 and October 2015 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.
o Holbrook #11: 57 trips were added to the count as a result of the difference between the last recorded
reading in2Ot4 (August t7,2OL4l 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 ALEXANDER #11 ALX11 2
MONTPELIER ARrMO #11 ARM11 6
MONTPELIER ARTMO #12 ARM12 19
MONTPELIER BANCROFT #11 BAN11 10
MONTPELIER BANCROFT #12 BAN12 7
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 74
MONTPELIER GRACE #12 GCE12 3
MONTPELIER HENRY #11 HRY11 0
MONTPELIER HORSLEY #11 HRS11 1
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 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.
Page 9 of 42
ROCKY MOUNTAINmn"""
ROCKY MOUNTAIN
POYI'ER IDAHO
Service Quality Review
MONTPELIER INDIAN CREEK #17 IND11 L4
MONTPELIER LAVA #11 LVA11 99911
MONTPELIER LUND #11 LND11 2a
MONTPELIER MCCAMMON #11 MCC11 t2
MONTPELIER MCCAMMON #12 MCC12 0
MONTPELIER MONTPELIER #11 MNT11 I
MONTPELIER MONTPELIER #13 MNT13 7
MONTPELIER MONTPELIER #14 MNT14 I
MONTPELIER RAYMOND #11 NORTH TO GENEVA RAY11 11
MONTPELIER RAYMOND #12 SOUTH TO PEGRAM RAY12 t4
MONTPELIER ST CHARLES #11 sTc11 5
PRESTON CLIFTON #11 DAYTON & BANIDA CLF11 65
PRESTON CLIFTON #12 CLI FTON/OXFORD/SWANLAKE ctF72 3
PRESTON DOWNEY #11 DWN11 4
PRESTON DOWNEY #12 DWN12 0
PRESTON HOLBROOK #11 HLB11 60
PRESTON MALAD #11 MLD11 3
PRESTON MALAD #12 MLD12 3
PRESTON MALAD #13 MLD13 4
PRESTON PRESTON #11 PRS11 19
PRESTON PRESTON f12 PRS12 37
PRESTON PRESTON #13 PRS13 31
PRESTON TANNER #11 MINK CREEK TNR11 72
PRESTON TANNER #12 RIVERDALE/TREASURETON TNR12 2
PRESTON WESTON #12 NORTH TO DAYTON WST12 7
PRESTON WESTON#11 SOUTH - WESTON/FAIRVEW 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 L
REXBURG ARCO #13 ARC13 1
REXBURG ASHTON #11 ASH11 I
REXBURG BELSON #11 BLS11 0
REXBURG BELSON f12 BLS12 0
REXBURG BERENICE #21 BRN21 1
REXBURG BERENICE f22 BRN22 2t
REXBURG CAMAS #11 cMs11 7
REXBURG CAMAS #12 cMs12 0
REXBURG CANYON CREEK # 22 CNY22 1
REXBURG CANYON CREEK #21 CNY21 9
REXBURG DUBOIS #11 DBS11 7
REXBURG DUBOIS #12 DBS12 0
REXBURG EASTMONT #11 EST11 4
REXBURG EASTMONT #12 EST12 8
REXBURG EGIN #11 EGN11 L46
REXBURG EGIN #12 EGN12 4
REXBURG HAMER #11 HMR11 23
REXBURG HAMER #12 HMR12 6
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 f13 MDY13
REXBURG MUDLAKE #11 MDL11 0
REXBURG MUDLAKE f12 MDL12 t
REXBURG NEWDALE #11 NWD11 0
REXBURG NEWDALE #12 NWD12 0
January - December 2015
Page 10 of 42
ROCKY MOUNTAIN
FOT'I'ER IDAHO
Service Quality Review
REXBURG NEWDALE #13 NWD13 1
REXBURG RENO #11 REN11 3
REXBURG RENO #12 REN12 0
REXBURG RENO #13 REN13 0
REXBURG REXBURG #11 RXB11 0
REXBURG REXBURG #12 RXB12 2
REXBURG REXBURG #13 RXB13 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 f13 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 sMtTH #11 SMT11 18
REXBURG sMtTH #12 SMT12 9
REXBURG sMtTH #13 SMT13 3
REXBURG sMITH #14 SMT14 t
REXBURG SOUTH FORK #11 IDAHO PACIFIC POTATO SFK11 0
REXBURG SOUTH FORK #13 ANTELOPE FLATS SFK13 0
REXBURG ST ANTHONY #11 STA11 L
REXBURG ST ANTHONY #12 STA12 0
REXBURG ST ANTHONY #13 STA13 0
REXBURG SUGAR CITY #11 SGR11 0
REXBURG SUGAR CITY #12 SGR12 0
REXBURG SUGAR CITY #13 SGR13 0
REXBURG SUGAR CITY f14 SGR14 0
REXBURG SUNNYDELL f11 SNN11 I
REXBURG SUNNYDELL #12 SNN12 2
REXBURG TARGHEE #11 TRG11 0
REXBURG TARGHEE #12 TRG12 0
REXBURG THORNTON #11 THR11 t
REXBURG THORNTON #12 THR12 1
REXBURG WATKINS #11 NORTH AND EAST WTK11 5
REXBURG WEBSTER #11 EAST AND SOUTH WBS11 t6
REXBURG WEBSTER #12 NORTH WBS12 4
REXBURG WEBSTER #14 WBS14 35
REXBURG WINSPER #21 WN521 0
REXBURG WINSPER #22 WNS22 0
SHELLEY AMMON #11 AMM11 5
SHELLEY AMMON #12 AMM12 1
SHELLEY Cinder Butte #11 CIB11 0
SHELLEY CINDER BUTTE #13 crB13 1
SHELLEY Cinder Butte #17 CIBLT 4
SHELLEY CLEMENTS S11 CLE11 11
SHELLEY CLEMENTS f12 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 \1
SHELLEY HOOPES #11 WEST HPS11 8
SHELLEY HOOPES #12 NORTH HPS12 0
SHELLEY IDAHO FALLS f11 IDF11 2
Januarv - December 2015
Page 11 of42
ROCKY MOUNTAIN
HSHY,E*N"",
IDAHO
Service Quality Review
January - December 2015
SHELLEY IDAHO FALLS #12 IDF12 37
SHELLEY IDAHO FALLS #13 IDF13 9
SHELLEY IDAHO FALLS #14 IDF14 3
SHELLEY JEFFCO #21 IFF2L 22
SHELLEY )EFFCO #22 JFF22 3
SHELLEY KETTLE #21 KTT21 18
SHELLEY KETTLE #22 KTT22 8
SHELLEY MERRILL #11 MRR11 19
SHELLEY MERRILL #12 MRR12 16
SHELLEY MERRILL #13 MRR13 16
SHELLEY MERRILL #14 MRR14 8
SHELLEY oscooD 111 osc11 26
SHELLEY oscooD f12 osc12 5
SHELLEY oscooD #13 OSG13 6
SHELLEY oscooD #14 osc14 9
SHELLEY SANDCREEK #11 SND11 I
SHELLEY SANDCREEK #12 SND12 5
SHELLEY SANDCREEK #13 SND13 1
SHELLEY SANDCREEK #14 SND14 11
SHELLEY SANDCREEK #15 SND15 32
SH ELLEY SANDCREEK #15 SND16 7
SHELLEY SHELLEY #11 SHL11 27
SHELLEY SHELLEY #12 SHL12 0
SHELLEY SHELLEY #13 SHL13 0
SHELLEY SHELLEY #14 SHL14 5
SHELLEY UCON #11 UCN11 2
SHELLEY UCON #12 UCN12 5
SHELLEY WATKINS #12 SOUTH THEN EAST WTK12 7
Page 12 of 42
IDAHO
Service Quality Review
January - December 2015
2.4 Reliability History
Depicted below is the history of reliability in ldaho. \n2002, the Company implemented an automated outage
management system which provided the background information from which to engineer solutions for
improved performance. Since the development of this foundational information, the Company has been in a
position to improve performance, both in underlying and in extreme weather conditions. These improvements
have included the application of geospatial tools to analyze reliability, development of web-based notifications
when devices operate more than optimal, focus on operational responses via CAIDI metric analysis, in addition
to feeder hardening programs when specific feeders have significantly impacted reliability performance.
ldaho Reliability History - lncluding Major Events
ISAIDI ICAIDI +SAIFI
3
6,PtOr>ZlrJ
L
0
cY09 cY10 cY1l CY12 CY13 CY14
ROCKY MOUNTAINm*n*"
400 .oP
=300 s
=2m
ldaho Reliability History - Excluding Major Events
TSAIDI rcAlDt +SAIFI
CYO9 CY1O CY11 CY12
Page 13 of42
-,ROCKY
MOUNTAIN-(Povt ER\ I otvrsm or uc'c'coeP
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.
ldaho 355-Day Rolling Controllable History as Reported
0.9
o.7
0.6
Eo
o,s i
r
=0.4
-60ots
=s06
6N
o.2
0.1
0.lm-20o7 j.n-20o8 lsn-2009 .lan-2010 Jrn-2011
stress Period
-sAlDl
Jan.20l2 J.n.2013 J!n-2014
-SAlFt -tinear
(SAtDtl
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 14 of 42
ROCKY MC'UNTAN
HSHN-,
IDAHO
Service Quality Review
January - December 2015
ldaho 35$Day RollltU ilonGontrollable Hlstoryas Reported
JD.2m7 Jfr.2(n ln 20 Jr}2010 ,rt 2011 ,fr-2012 1r}.201!l Jlt-2oL JrFlOls
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Page 15 of 42
ROCKY MOUNTAN#s*IDAHO
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 including 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 nearby 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 balloou other
interfering object such as straw, shoes, string, balloon.
Animals and Birds Any problem nest that requires removal, relocation, trimmin& etc.; any birds, squirrels or other
animals, whether or not remains found.
Operational
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
eouioment.
Planned
Transmission requested, affects distribution sub and distribution circuits; Company outage taken
to make repairs after storm damage, car hit pole, etc.; construction work, regardless if notice is
siven: rollins blackouts.
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 lCustomer Requested ond Customer Notice
Given line items) with subtotals for their inclusion, while the grand totals in the table exclude these
prearranged outages so that grand totals align with reported SAIDI and SAIFI metrics for the period. 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.
Page t6 ol 42
ROCKY MOU]$IAIN
Pot,YER IDAHO
Service Quality Review
2.6.t Underlying Cause Analysis Table
January - December 2015
W k*1.idf;
rr r*X***!1*titi,w:
ANIMALS 184,279 1,854 189 2.38 o.024
BIRD MORTALITY (NON-PROTECTED SPECIES)404,447 2,568 83 s.2t 0.033
BIRD MORTALITY (PROTECTED SPECIES) {BMTS}81,023 642 22 1.04 0.008
BITD NEST (BMTS)59,4L7 1,596 LL o.77 o.021
BIRD SUSPECTED, NO MORTALITY 202,O50 2,447 70 2.60 0.032
ANIMAISI 931,216 9,1o7 375 L2.Ot 0.1t7
FIRE/SMOKE (NOT DIJE TO fAULTS)t,499 23 5 o.o2 0.000
EITVIRONM:i'T 1,499 2t 5 0.o2 0.(x,0
B/O EQUIPMENT 276,082 3,578 165 3.s6 0.045
DETERIOMTION OR ROTTING 3,208,744 2t,826 878 4r.37 o.28L
NEARBY FAULT ro2 I 1 0.00 0.000
OVERLOAD 6,467 42 13 0.08 0.001
POLE FIRE 748,949 3,865 54 9.66 0.0s0
REIAYS, BREAKTRS, SWITCHES 0 1
STRUCTURES, Ii'ISULATORS, CONDUCTOR 0 5
EQUIPMEilT FAITURE+4,2&,?44 29,3r2 I,ll7 *,67 0.378
DIG-IN (NON-COMPANY PERSONNEL)54,089 294 38 0.70 0.004
OTHER INTERFERING OUECT 33,890 368 L7 0.44 0.00s
OTHER UTILITY/CONTRACTOR L2,882 L27 9 0.L7 0.002
VANDALISM ORTHEFT 2,573 4 I 0.03 0.000
VEHICLE ACCIDENT 927,]-LL 7,O54 84 11.95 0.091
NIERTERENCE 1,030,s4s 7,U7 149 13.29 0.101
LOSS OF SUBSTATION 2t3,97L 631 8 2.76 0.008
LOSS OF TRANSMISSION LINE 2,903,4s4 2t,239 t20 37.43 o.274
SYSTEM PROTECTION 0 2
LOSS OF SUPPLY 3,117,424 21,87O 130 40.19 o.282
FAULTY INSTALL 4,556 59 6 0.06 0.001
IMPROPEfi PROTECTTVE COORDINATION L20 2 1 0.00 0.000
INCORRECT RECORDS L72 3 3 0.00 0.000
COMPANY EMPLOYEE . FISLD 224 2 2 0.00 0.000
OPERANONAI.'s,072 66 !2 0.07 o.qr1
OTHER, KNOWNCAUSE 5,442 236 25 o.o7 0.003
UNKNOWN 632,373 6,818 433 8.15 0.088
OTHER 637,8t0 7,Oil 458 4.22 o.$r1
CONSIRUCTION 85,743 383 26 L,LL 0.005
CONSTRUCNON - SCHEDULED SWITGHING 0 24
CUSTOMER NOTICE GIVEN t,703,326 7,209 L62 2L.96 0.093
CUSTOMER REQUESTED 8,737 86 85 0.11 0.001
EMERGENCY DAMAGE REPAIR 847,402 L2,327 148 10.93 0.159
INTENTIONAL TO CLEAR TROUBLE t73,582 1,083 IT 2.24 0.014
MAINTENANCE 0 59
PIANNED 2,818,790 21,088 515 36.34 o.272
Page 77 of 42
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-PRB/ETTABLE 1,3L2,88L 8,316 77 16.93 o.to7
TREE -TRIMMASI.T+48,27L 302 t7 o.62 o.fiM
rREES rp6Lr52 &518 88 17.55 0.111
FREEZING FOG & FROST 241 2 2 0.00 0,000
tcE 482 4 4 0.01 0.000
LIGHTNING 621,L93 4,3L8 172 8.01 0.056
SNOW. SLEETAilD BUZZARD 40,3,7fi L,287 45 5.27 0.017
WIND L,826,t54 9,337 L57 23.54 0.120
WEATHER 4,851,t31 14,942 39,#.7t 0.r93
Page 18 of42
ROCKY MOI'NTANffin*IDAHO
Seruice Quality Review
January - December 2015
2.6.2 Cause Category Analysis Charts
Cause Analysis - Customer Minutes Lost (SAlDll
r ANIMAIS5%
T WEATI{ER 17%I gnunonuENTog6
I EqUIPMENTI TREESS%
3 PI.ANNEDlT%
T OPEMTIONAIO96
E OTHER4%
FAILURE 2596
INIERFERENCE 6%
r LossoFsuPPLY1895
Cause Analysis - Customer lnterruptions (SAlFll
I WEATHER 12%I ANIMATS8%
r guvrRonuENT0g6
E TREEST%
I PI.ANNED 1896
r EQUIPMENT
FAITURE 24%
I OPERATIONATO'6 r INTERFERENCET%
T OTHER6%r tossoFsuPPtY18%
Cause Analysls - Sustained lncldents
E WEATHER 12%r ANIMALS 1296
E TREES3,6 I ENVIRONMENTO6
E PI.ANNED 1696
I EQUIPMENT
FAITURE 34%
E OIHER 14%
I oPEMTIoNAI.O96
Page 19 of 42
IDAHO
Service Quality Review
January - December 2015
2.7 lmprove Worst Performing Circuits or Areas by Target Amount
ln 2072 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 2OL2, 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.
Reliabilitv Performa nce I m provement ( post 1213 1/201 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 Perfonnanea lndicator 2012 (RPl12) Method
PROGRAM YEAR 16 (CPIS)Method
Lava 11 (Figure 5C)IN PROGRESS t27 123
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 L76 180
TARGET SCORE = 176 196 189
PROGRAM YEAR 14
Berenice 21 (Fieure 1C)COMPLETED 290 236
Malad 13 (Fieure 2C)COMPLETED 122 86
TARGET SCORE = 185 GOAI MET 206 161
ROCKY MOUNTAIN
HHIYES*,
ROCKY MOt,lfiAIN
PiOWER IDAHO
Service Quality Review
(lmprovement targets for circuits in Program Years 1 through 11 and 13 have been met and filed in prior reports.)
2.8 Geographic Outage History of Under-performing Areas
Figure 1A: Berenlce 21 Controllable View
Page2tof 42
R(XKY MC'I,NTAIN
POWER IDAHO
Service Quality Review
\ Cirtir. Oii.ylrrgr. Arbil irl-Itt NG<ontElhtL
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Figure 18: Berenlce 21 Non-Controllable View
January - December 2015
Page22ol 42
R(TKY MOI'NTAIN
HgllEs*
IDAHO
Service Quality Review
Figure lC: Berenice 21 Underlying View excluding Loss of Supply
. GIIAIERLIFi\ Gto&t. OdryLryliI Craouf,*6r$lrds.?dylf,l,tt,. tr.EE
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January - December 2015
Page23 of 42
ROCKY ITIIOUNTTAtr{Hgm*IDAHO
Service Quallty Review
Flgure 2A: Malad 13 Controllable Vlew
January- December 2015
Page24ol 42
Xffi'*IDAHO
Service Quality Review
Flgure 28: Malad 13 Non-Controllable Vlew
January - December 2015
Page25ot 42
IDAHO
Service Quality Review
Flgure 2C: Malad 13 Underlylng View excludlng Loss of Supply
January - December 2015
Page26 of 42
R(TKY MOI,NTAN
H*HN*IDAHO
Seruice Quality Review
January - December 2015
Figure 3A: Roberts 12 Controllable View
Page27 of 42
ROCKY iIOI,.II]TAINmlH*IDAHO
Seruice Quality Review
Figure 38: Roberts 12 Non-Controllable View
January - December 2015
Page 28 of 42
ROCKY MC,I,NTANffi-IDAHO
Service Quality Review
January - December 2015
Flgure 3C: Roberts 12 Underlying View excludlng Loss of Supply
Page?9 of 42
R(TKY MC'I'NTANFolTER IDAHO
Service Quality Review
Flgure 4A: Targhee ll Controllable View
. (ilE tE'lryr\tui3. Oirf, Lr,Dr. Crbmmftceftol-Ltn!h. hnilGO*r=of o<rdrcm
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January - December 2015
Page 30 of 42
ROCKY MOI'}TTANffi"-IDAHO
Service Quality Review
Figure 48: Targhee 11 Non{ontrollable Vlew
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January - December 2015
Page 31 of 42
ROCKY MCIUNTAIN
FOWER IDAHO
Service Quality Review
Figure 4C: Targhee 11 Underlying View excluding loss of Supply
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January - December 2015
Page32ot 42
-ROCKY
MC'UNTAINIPOW T\eurucm
IDAHO
Service Quality Review
Flgure 5A: lava ll Controllable Vlew
January - December 2015
Page 33 of 42
-R(XKY
MOI'NTAN!FolTER!4il'mrclcnoD
IDAHO
Service Quality Review
Figure 58: lava 11 Non{ontrollable Vlew
January - December 2015
Page 34 of 42
xfficx,rt{rAlN IDAHO
Seruice Quality Review
January - December 2015
Flgure 5C: Lava 11 Underlying Vlew excludlng loss of Supply
Page 35 of 42
ROCKY MOI'NTAINFOVER IDAHO
Service Quality Review
Figure 6A: Preston 11 Controllable View
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January - December 2015
Page 36 of 42
Yffi}YOUNIAIN IDAHO
Service Quality Review
Figure 68: Preston 11 Non-Controllable View
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January - December 2015
Page37 of 42
ROCKY MOUNIAINMR,IDAHO
Service Quality Review
Figure 5C: Preston 11 Underlying View excluding Loss of Supply
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January - December 2015
Page 38 of 42
IDAHO
Service Quality Review
January - December 2015
2.9 Restore Service to 80% of Customers within 3 Hours
2.10Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
-ROCKY
MOI'N]AINIFOWER!.mo@ customefguaranfees January to December 2015
PS5-Answer calls within 30 seconds
PS6a) Respond to commission complaints within 3 days
PSSb) Respond to commission complaints regarding service disconnects
within 4 hours
PSSc) Resolve commission complaints within 30 days
cGt
cG2
cG3
cG4
cG5
cG6
CG7
Overall Customer Guarantee performance remains above99Yo, demonstrating Rocky Mountain Power's continued
commitment to customer satisfaction.
Major Events are excluded from the Customer Guarantees program.
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Page 39 of 42
ROCKY MOUNTANPoT'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.
!nterruption Tvpes
Below are the definitions for interruption events. For further details, refer to IEEE 1366-2OO3/2OL2e Standard
for Reliability lndices.
Sustoined Outage
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentary Outage Event
A momentary outage event is defined as an outage 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 1366-2003/2012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliabilitv !ndices
SAIDI
SAIDI (system average interruption duration index) is an industry-defined term to define the average duration
summed for all sustained outages a customer experiences in a given period. lt is calculated by summing all
customer minutes lost for sustained outages (those exceeding 5 minutes) and dividing by all customers served
within the study area. When not explicitly stated otherwise, this value can be assumed to be for a one-year
period.
Daily SAIDI
ln order to evaluate trends during a year and to establish Major Event Thresholds, a daily SAIDI value is often
used as a measure. This concept is contained IEEE Standard I366-2OL2. 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 yea/s SAIDI results.
SAIFI
SAIFI (system average interruption frequency index) is an industry-defined term that attempts to identify the
frequency of all sustained outages that the average customer experiences during a given period. lt is
calculated by summing all customer interruptions for sustained outages (those exceeding 5 minutes in
duration) and dividing by all customers served within the study area.
CAIDI
CAIDI (customer average interruption duration index) is an industry standard index that is the result of dividing
the duration of the average custome/s sustained outages by frequency of outages for that average customer.
While the Company did not originally specifo 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).
s IEEE 136G2003/2012 was first adopted by the IEEE Commissioners on December 23,2OO3. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
Page 40 of 42
ROCKY MOTJNTAIN
HglF#*
IDAHO
Service Quality Review
January - December 2015
MAlFle
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
CP199 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: 10.545
SAIDI: Weighting Factor 0.30, Normalizing Factor 0.029
SAIFI: Weighting Factor 0.30, Normalizing Factor 2.439
MAIFI: Weighting Factor 0.20, Normalizing Factor 0.70
Lockouts: Weighting Factor 0.20, Normalizing Factor 2.00
Therefore, 10.545*((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
cPt05
CPl05 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to
identify underperforming circuits. Unlike CPl99 it includes Major Event and Loss of Supply or Transmission
outages. The calculation of CPl05 uses the same weighting and normalizing factors as CPl99.
RPI
RPI is an acronym for Reliability Performance lndicator, which measures reliability performance on a specific
segment of a circuit to identify underperforming circuit segments rather than measuring performance of the
whole circuit. This is the company's refinement to its historic CPl, more granular.
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 1355-2012) 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 L.75 beta (or 1.75 times the natural log standard deviation beyond the natural log
daily average for the day's SAIDI) that generally these days' events are generally associated with weather
events and serve as an indicator of a day which accrues substantial reliability metrics, adding to the cumulative
Page 4L of 42
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 MOUNTAINm"
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