20171030Service Quality Report 2016.pdf

ROCKY MOUNTAIN
BP,YTI,E,^"B""-,
October 30,2017
RECEIVED
?0l10CT g0 At{ t0: tS
',
r, rl ?ff&o&'#,h I 8*,o*
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
VIA OVERNIGHT DELIWRY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,ID 83702
Re: PAC-E-04-07 -2016 Service Quality & Customer Guarantee Report for the period
January 1 through June 30,2017
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, hereby provides a copy of the Jur:re2}l7 Service
Quality & Customer Guarantee report. This report is provided pursuant to a merger commitment
made during the PacifiCorp and ScottishPowerl merger. The Company committed to implement a
five-year Service Standards and Customer Guarantees program. The purposes behind these
programs were to improve service to customers and to emphasize to employees that customer
service is a top priority. Towards the end of the five-year merger commitment the Company filed
an application2 with the Commission requesting authorizationto extend these programs.
If there are any additional questions regarding this report please contact Ted Weston at
(80r) 220-2e63.
Sincerely,
f.d UfuMt -/'tvn
cc
Ted Weston
Manager, Idaho Regulatory Affairs
Enclosures
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 AUALITY
REVIEW
January L - June 30, 20L7
Report
3 ROCKYPOWER MOUNTAIN IDAHO
Service Quality Review
January -June20L7
TABLE OF CONTENTS
TABLE OF CONTENTS 2
EXECUTIVE SUMMARY
1 SERVICE STANDARDS PROGRAM SUMMARY
1.1 ldaho Customer Guarantees
L.2 ldaho Performance Standards
2 RELIABILITYPERFORMANCE
2.1 System Average lnterruption Duration lndex (SAlDl)
2.2 System Average lnterruption Frequency lndex (SAlFl)
2.4 Controllable, Non-Controllableand Underlying Performance Review
2.5.L Underlying Cause Analysis Table
2.5.2 Cause Category Analysis Charts .
2.6 Reliability lmprovement Process
3
3
4
5
5
7
9
L7
L2
13
L4
2.6.1 Reliability Work Plans ......................14
2.6.2 Project approvals by district L4
2.6.3 Reduce CPI for Worst Performing Circuits or Sub-circuits................. ..........15
2.7 Restore Service to 8Oo/o of Customers within 3 Hours ......................!7
2.8 Telephone Service and Response to Commission Complaints 17
3 CUSTOMER GUARANTEES PROGRAM STATUS... ..,..,,.........L7
...............3
Page 2 of 20
3 ROCKY MOUNTAINmfu"IDAHO
Service Qualiry Review
January - June2017
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.
L SERVICE STANDARDS PROGRAM SUMMARY1
1.1 ldaho Customer Guarantees
Note: 5ee Rules for o complete description of terms ond conditions for the Customer Guorontee Progrom.
1 On June 29, 2012, in Docket PAC-E-12-02 and Order 32583, the Commission ordered that Rocky Mountain Power had delivered upon commitments it
madeinpursuanttotheMidAmericantransactioninPAC-E-05-08andOrder29998. TheCommissionalsoorderedtheacceptanceofmodificationstothe
Service Standards Program proposed by Rocky Mountain Power, as shown on Page 4 of 15.
Page 3 of 20
Customer Guarantee 1:
Restoring Supply After an Outage
The Company will restore supply after an outage within 24 hours of
notification with certain exceptions as described in Rule 25.
Customer Guarantee 2:
Appointments
The Company will keep mutually agreed upon appointments, which
will be scheduled within a two-hour time window.
Customer Guarantee 3:
Switching on Power
The Company will switch on power within 24 hours of the customer
or applicant's request, provided no construction is required, all
government inspections are met and communicated to the
Company and required payments are made. Disconnections for
nonpayment, subterfuge or theft/diversion of service are excluded.
Customer Guarantee 4:
Estimates For New Supply
The Company will provide an estimate for new supply to the
applicant or customer within 15 working days after the initial
meeting and all necessary information is provided to the Company
Customer Guarantee 5:
Respond To Billing lnquiries
The Company will respond to most billing inquiries at the time of the
initial contact. For those that require further investigation, the
Company will investigate and respond to the Customer within 10
working days.
Customer Guarantee 5:
Resolving Meter Problems
The Company will investigate and respond to reported problems
with a meter or conduct a meter test and report results to the
customer within 10 working days.
Customer Guarantee 7:
Notification of Planned lnterruptions
The Company will provide the customer with at least two days'
notice prior to turning off power for planned interruptions
consistent will Rule 25 and relevant exemptions.
\
ROCKY MOUNTAINPol'I'ERauusorrcrA@P
IDAHO
Service Quality Review
January - June2017
L.2 ldaho Performance Standards
Note: Performonce Stondords 7, 2 & 4 ore for underlying performonce days ond exclude those clossified os Mojor
Events.
Network Performance Standard 1:
Report System Average lnterruption Duration lndex
(sArDr)
The Company will report Total, Underlying, and
Controllable SAIDI and identify annual Underlying baseline
performance targets for the reporting period. For actual
performance variations from baseline, explanations of
performance will be provided. The Company will also
report rolling twelve month performance for Controllable,
Non-Controllable and Underlying distribution events.
Network Performance Standard 2:
Report System Average lnterruption Frequency
lndex (SAlFl)
The Company will report Total, Underlying, and
Controllable SAIFI and identify annual Underlying baseline
performance targets for the reporting period. For actual
performance variations from baseline, explanations of
performance will be provided. The Company will also
report rolling twelve month performance for Controllable,
Non-Controllable and Underlying distribution events.
Network Performance Standard 3:
lmprove U nder-Performing Areas
Annually, the Company will target specific circuits or
portions of circuits to improve performance by a forecast
amount, using either its legacy worst performing circuit
program (to reduce by t0% the reliability performance
indicator (RPl) on at least one area on an annual basis
within five years after selection) or by application of its
Open Reliability Reporting Program.
Network Performance Standard 4:
Supply Restoration
The Company will restore power outages due to loss of
supply or damage to the distribution system within three
hours to 80% of customers on average.
Customer Service Performance Standard 5:
Telephone Service Level
The Company will answer 80% of telephone calls within 30
seconds. The Company will monitor customer satisfaction
with the Company's Customer Service Associates and
quality of response received by customers through the
Company's eQuality monitoring system.
Customer Service Performance Standard 5:
Commission Complaint Response / Resolution
The Company will a) respond to at least 95% of non-
disconnect Commission complaints within three working
days and will b) respond to at least 95% of disconnect
Commission complaints within four working hours, and will
c) resolve 95% of informal Commission complaints within
30 days.
Page 4 of 20
ROCKY
POvt/ER
MOUNTAIN IDAHO
Service Quality Review
January - June2OtT
2 RELIABILITY PERFORMANCE
For the reporting period, the Company experienced underlying interruption duration (SAlDl) and interruption
frequency (SAlFl) performance in ldaho that was unfavorable to plan. Results for ldaho underlying performance
can be seen in subsections 2.1 and 2.2 below.
Major Event General Descriptions
One event during the reporting period met the Company's ldaho major event threshold level2 for exclusion from
u nderlying performance results.
March L8, 2OL7: Shelley, ldaho, experienced an outage when a potential transformer (PT) at the
Sugarmill substation failed. The failed PT damaged the operate bus causing several other circuit
breakers in the substation to be de-energized. The event affected three substations, feeding 10
circuits, serving 16,16L customers, for durations ranging from t hour 45 minutes to 2 hours 19 minutes.
a
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 days3 were recorded, which
account for 55 SAIDI minutes; about 53% of the reporting period's underlying 123 SAIDI minutes. The company
has recognized that these significant days have caused a negative impact to performance, and that they have
been generally attributable to events within the transmission system; it has recognized transmission system
reliabil risks ous and has been lans.
2 Ma.lor event threshold shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
th-72/31/2}76 76,977 74.82 7,747,067
llt-72/37/2177 78,594 16.s6 7,301,447
3 On a trial basis, the Company established a variable of 1.75 times the standard deviation of its natural log SAIDI results.
Page 5 of 20
Cause SAIDIDate
March 18,2017 Loss of Substation 23.25
Date Cause: General Description Event SAID!% of TotalsAlDl
3.7%January 6,2017 Loss of transmission Line 4.55
6.74 s.0%January t'L,20L7 Loss of transmission Line - snow storm
5.77 4.7%March 11,2017 Loss of transmission Line - BPA
12.45 t0.t%Apri!8,2017 Pole fire/Snow storm
11.35 9.2%April 18,2017 Loss of transmission Line
Wind storm s.29 4.3%May24,2Ot7
Loss of Substation 4.71 3.8o/oJuneL2,2Ot7
lune 14,20t7 Loss of transmission line due to car hit pole 4.93 4.0%
4.3%lune22,20t7 Loss of transmission Line 5.37
4.47 3.6%lune24,2OL7 Loss of transmission Line
65.02 52.5%TOTAL
Major Events
Significant Event Days
\
ROCKY
POYI'ER
MOUNTAIN IDAHO
Service Quality Review
January -June20L7
2.L System Average lnterruption Duration Index (SAlDl)
The Company's system average underlying interruption duration performance for the reporting period is
unfavorable to plan.
IDAHO SAIDI
(excludes Prearrangcd and Customer Requestedl
2(n
180
160
140
t20
100
80
@
'o
20
0
a
aot
ooasE
6aall t\t\tsNFI\t\t\t\r\t\t\dFHdHHdddddcrcloooooooocrol{r-r{NalNdNdddN
ddt
Actual
(reporting period)
Plan
(year-end)
L47Total (major event included)
L24 160Underlying (major event excluded)
24Controllable
Controlable Actual
...... TOtd lnCludng Maror Events
Underlyirg Actual
-urderlyi|u
Phn
Page 5 of 20
IDAHO
SAIDI
3 IDAHO
Service Quality Review
January - June20L7
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying system average interruption frequency performance results for the reporting period
is unfavorable to plan.
ROCKY MOUNTAIN
ffi*B"*"
2.0
1.8
1.5
1.4
L.2
1.0
0.8
a 0.6cI o,o
catr 0.2etn o.o
IDAHO SAIFI
(excludes Prearranged and Customer Requested)
a a
a'
FNl\hNNFFF'\l\'\idddddd6dddHcr(r<roooo(rcroooNarNdNrt.trt.{N,\lN
Hd
Actual
(reporting period)
Plan
(year-end)
Total (ma.|or event included)1.556
Underlying (major event included)1.350 7.41_7
Controllable 0.168
Controllable Actual
o... o. Totd lncludlng l\lalor Events
Urdedyirg Actual
-
Urdedyir6 Plan
PageT of2O
IDAHO
SAIFI
V-ROCKY MOUNTAINYPOI,I,ER\ruvurrcnop
IDAHO
Service Quality Review
January - June20L7
2.3 Reliability History
Depicted below is the history of reliability in ldaho. ln 2002, 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. Recently,
the Company has recognized underperformance of portions of the transmission system and has begun preparing
improvement plans.
ldaho Reliability History - lncluding Major Events
ISAIDI TCAIDI +SAIFI
4 6m
5@
4(p
3@
2@
1m
3-O
3 2.7 2.6
2.9
a
co
tr|2
2.
\f.6
C|OT CY08 CY09 CY10 CYll CY12 CY13 CY14 CY15 CY16 June
c'tt7
oo
sE
2.O
o
1
0 o
RSlrl oHOF{m
oac{+dm
fa fnr{Nt{ r{
ra|,)N(Dc{ FJ
sr\t\ cor{fl
o<l(''nr{N
{rlmlll(oi{ cl
NE(o0nN
ONFl .{HN
6
Eo
lrl
2
4(x)
3(x)
2@
1q)
1.5 1.5
2.3
4
3
1
ldaho Reliability History - Excluding Major Events
2.6
1.4
CY07 CY08 CY09 CY10 CYl1 CY12 CY13 CY14 CY15 CY16 June
cY17
o
ts
=
o 0
Nr,l
?.1
Nq,ctC, 6lr{N
ql<totr.l N
iltm rl t\d@ !aot{ <ldN
rolf!lil o (oNln OrE.nOordd
(o+dON
Page 8 of 20
ISAIDI ICAIDI +SAIFI
3 IDAHO
Service Quality Review
January - June20L7
2,4 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 betterfuture
reliability at the lowest possible cost. At that time, certain stakeholders were concerned that the Company would
lose focus on non-controllable outages. 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,
however shows recent upticks in performance. ln order to also focus on non-controllable outages, the Company
has continued to improve its resilience to extreme weather using such programs as its visual assurance program
to evaluate facility condition. lt also has undertaken efforts to establish impacts of loss of supply events on its
customers and deliver appropriate improvements when identified. lt uses its web-based notification tool for
alerting field engineering and operational resources when devices have exceeded performance thresholds in
order to react as quickly as possible to trends in declining reliability. These notifications are conducted regardless
of whether the outage cause was controllable or not.
ldaho 365-Day Rolling Controllable )listoryas Reported
l0o
90
EO
70
1
-60o
IC-so
Ee640
0,9
0.8
o.7
0.6
E
o.s E
a
0.4
0.3
0.2
0.1
30
2o
1o
o o
.1e.20O7 Jm-2@8 ,.n-2009 ,n-2010 ,lm-2011 Jn.2ol:l J.n-2013 Jm.2Ol4 ,m-2O15 Jm.2Ol6 Je-2O17
Stress p€rlod
-SAtDt -SAtFt -tinear
(SAlDl)
Page 9 of 20
ROCKY MOUNTAIN
HSSE*."
\
ROCKY
POVI/ER
MOUNTAIN !DAHO
Service Quality ReviewA Dvl$ffOFrcrFrC@P
January-June2Ot7
ldaho 365-Day Rolling NonGontrollable History as Reported
300 3
2r0 2.5
200 2
J
a..t
= 15o
o-
E
,.t ,I
4
100 I
50 0.5
o 0
J.n.20O7 J.n.2008 J.n-2009 l.n-2010 Jm.20U la.2olz J.n.2013 J.n-2014 J.n.2015 J.n.2016 ,.n.2017
Sress pcriod
-9il0i -3{lFt -tinGar
lSAtOtl
ldaho 365-Day Rolling Underlying History as Reported
3(I)
250
400
:l
2.5
2
rt tto
=5d6
t(I)
Eo
r-s i\a
1
0.5
o
l. -2@7 Jrn-20O8 J.n-2009 ,.n.2010 hn-2olL J.n-2012 Jm-2013 Jm-2014 J.n-2015 l.n-2016 J.n-2017
stress p€riod _9{Dt _s/ItFt
-t_inear
(sAtDtl
0
Page 10 of 20
Y IDAHO
Service Quality Review
January -June20L7
2.5 Cause Code Analysis
The tables below outlines categories used in outage data collection. Subsequent charts and table use these
to develo rns for ance
ROCKY MOUNTAIN
HgiY.Eil"
Direct Cause
Category Category Definition & Example/Direct Cause
Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels or other animals,
whether or not remains found.
Animals
r Animal (Animals)
o Bird Mortality (Non-protected species). Bird Mortalitv (Protected speciesXBMTS)
o Bird Neste Bird or Nest
e Bird Suspected, No Mortality
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 building
fires (not including fires due to faults or lightning).
Environment
o Major Storm or Disaster
e Nearby Faultr Pole Fire
o Condensation/Moisture. Contaminationo FirelSmoke (not due to faults)
o Flooding
Structural deterioration due to age (incl. pole rot); electrical load above limits; failure for no apparent
reason; conditions resulting in a pole/cross arm fire due to reduced insulation qualities; equipment affected
by fault on nearby equipment (e.g., broken conductor hits another line).
Equipment
Failure
o B/o Equipment
o Overload
. Deterioration or Rotting
o Substation, Relays
Willful damage, interference or theft; such as gun shots, rock throwing, etc.; customer, contractor or other
utility dig-in; contact by outside utility, contractor or other third-party individual; vehicle accident, including
car, truck, tractor, aircraft, manned balloon; other interfering object such as straw, shoes, string, balloon.
lnterference
e Other Utility/Contractorr Vehicle Accident
r Dig-in (Non-PacifiCorp Personnel)
o Other lnterfering Object
o Vandalism orTheft
Failure of supply from Generator or Transmission system; failure of distribution substation equipment.Loss of
Supply r Failure on other line or station
o Loss of Feed from Supplier
o Loss of Generator
o Loss of Substation
o Loss of Transmission Line. System Protection
Accidental Contact by PacifiCorp or PacifiCorp's Contractors (including live-line work); switching error;
testing or commissioning error; relay setting error, including wrong fuse size, equipment by-passed; incorrect
circuit records or identification; faulty installation or construction; operational or safety restriction.
Operational
o Contact by PacifiCorp. Faulty lnstall. lmproper Protective Coordination
. lncorrect Records
o lnternal Contractor
o lnternal Tree Contractor
o Switching Error. Testing/Startup Errorr Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons.Other
o lnvalid Codeo Other, Known Cause
r Unknown
Transmission requested, affects distribution sub and distribution circuits; Company outage taken to make
repairs after storm damage, car hit pole, etc.; construction work, regardless if notice is given; rolling
blackouts.
Planned
. Construction
o Customer Notice Given
o Energy Emergency lnterruption. lntentional to Clear Trouble
. Emergency Damage Repair. Customer Requestedr Planned Notice Exempt
o Transmission Requested
Growing or falling treesTree
o Tree-Non-preventable
o Tree-Trimmable
o Tree-Tree felled by Logger
Wind (excluding windborne material); snow, sleet or blizzard, ice, freezing fog, frost, lightning.Weather
o Extreme Cold/Heat. Freezing Fog & Frost
o Wind
o Lightning
r Rain
o Snow, Sleet, lce and Blizzard
Page 11 of 20
3 !DAHO
Service Quality Review
January -June2OL7
2.5.t 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.
Note: Direct Causes are not listed if there were no outages classified within the cause during the reporting period.
ROCKY MOUNTAIN
BSHYEfu,
customer
Minutes Lost
for lncident
Customers
in lncident
Sustained
Direct Cause
Sustained
lncident
Count
SAIDI SAIFI
ANIMALS 90,978 792 66 1.16 0.010
BI RD MORTALITY ( NON-PROTECTED SPECIES)11,809 158 22 0.15 0.002
BIRD MORTALITY (PROTECTED SPECIES) (BMTS)72,533 179 7 0.16
BIRD NEST (BMTS)437 3 )0.01 0.000
BIRD SUSPECTED, NO MORTALITY 10,665 133 L4 0.14 0.002
ANIMAI.S L26,422 1,205 LL2 1.61 0.015
728FIRE/SMOKE (NOT DUE TO FAULTS}1 1 0.00 0.000
ENVIRONMENT L28 1 1 0.00 0.000
B/O EQUIPMENT 717,580 1,100 90 1.50 0.014
1,354,550DETERIORATION OR ROTTING 7,367 442 77.23 0.094
OVERLOAD 597 u 4 0.01 0.000
POLE FIRE 555,699 3,673 16 7.07 o.o47
EqUIPMENT FAITURE 2,O24,426 12,153 552 25.81 0.155
38,564DrG-rN (NON-PACTFTCORP PERSONNEL)349 7Z 0.49 0.004
OTHER INTERFERING OBJECT 2,528 38 9 0.03 0.000
OTHER UTILITY/CONTRACTOR 7,794 6 4 o.o2 0.000
VEHICLE ACCIDENT 181,396 2,247 31 2.37 0.029
22t,643 2,UOINTERFERENCE 56 2.85 0.034
LOSS OF FEED FROM SUPPLIER a 1 r 0.00 0.000
LOSS OF SUBSTATION 681,435 7,875 20 8.67 0.100
LOSS OF TRANSMISSION LINE 3,626,548 59,474 767 46.74 0.756
4,307,991 57,300LOSS OF SUPPTY 188 54.81 0.8s5
FAULTY INSTALL 28 1 1 0.00 0.000
PACIFICORP EMPLOYEE . FIELD 87 1 7 0.00 0.000
115 2 2 0.00 0.000OPERATIONAT
OTHER, KNOWN CAUSE 40,346 300 24 0.51 0.004
UNKNOWN 527,084 4,450 221 6.t I 0.057
OTHER 567,43t 4,750 245 7,22 0.060
CONSTRUCTION 1 1,333 264 6 0.14 0.003
CUSTOMER NOTICE GIVEN 7,049,327 4,934 78 13.35 0.063
EMERGENCY DAMAGE REPAIR 261,709 3,O27 64 3.32 0.039
29,736INTENTIONAL TO CLEAR TROUBLE 435 6 0.38 0.006
PLANNED NOTICE EXEMPT I,OO2 110 2 0.11 0.001
PTANNED 1,350,508 8,770 155 t7,3L O,LL2
220,650 1,263 44 2.81 0.016TREE. NON-PREVENTABLE
266,986 3,530 9 3.40 0.045TREE. TRIMMABLE
TREES 1t87,636 4,79t 53 6.20 0.061
rcE 70,935 223 13 0.90 0.003
LIGHTNING 110,683 r,r34 40 7.47 0.014
SNOW, SLEET AND BLIZZARD 793,063 2,929 57 10.09 0.037
772,025WIND 5,254 127 9.06 0.067
WEATHER 1,686,706 9,540 2?7 2L.46 O,LzL
ldaho lncluding Prearranged 10,789,045 111,154 t,602 1t7.28 1.4L4
9,7?O,7L7 105,110ldaho Excluding Prearranged 1,522 Lzt.8t 1.350
Page 12 of 20
ldaho Cause Analysis - UnderlyingOtl0llzOLT -O6l3Ol2Ot7
IDAHO
Service Quality Review
January - June20L7
2.5.2 Cause Category Analysis Charts
The charts show each cause category's role in performance results and illustrate that certain types of outages
account for a high amount of customer minutes lost but are infrequent, while others tend to be more frequent
but account for few customer minutes lost.
Cause Analysis - Customer Minutes tost {SAIDI}
C WEATHER 18%3 ANIMALS 1%
I ENVIRONMENTO%
r,a TREES 5%
ROCKY MOUNTAIN
HSIYHn-"
Y PLANNED3%
Y OTHER6%
r OPERATIONALO%
I EqUIPMENT
FAITURE 21%
3 INTERFERENCE 2%
s LOSS OF SUPPLY it4%
Cause Analysis - Customer lnterruptions (SAlFl)
Y OTHER4%
Y PLANNED4%
E TOSSOF sUPPLY63%d TREES 5%
I OPERATIONALO%
I. WEATHER 9%
I ANIMALS 1%
I ENVIRONMENTO%
I EQUIPMENT
FAII-URE 11%
3 INTERFERENCE 3%
Cause Analysis - Sustained lncidents
9 EQUIPMENT FAITURE 36%
I ANIMATS 7%
T ENVIRONMENTO%
Y WEATHER 15%I INTERFERENCE 4%
IJ TREES4%
v tossoFsupPLY 12%
U PTANNED6%
Y OTHER 16%
I OPERATIONATO%
Page 13 of 20
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[,
I
Y IDAHO
Service Quality Review
January -June20L7
2.6 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 proBram 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.
2.6.1 Reliability Work PIans
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.
2.6.2 Project approvals by district
The identification of projects is an ongoing process throughout the year. An approval team reviews projects
weekly and once approved, design and construction begins. Upon completion of the construction, the project is
identified for follow up review of effectiveness. One year after completion, routine assessments of performance
are prepared. This comparison is summarized for all projects for each year's plans, and actual versus forecast
results are assessed to determine whether targets were met or if additional work may be required, as would be
depicted in the table below.
ROCKY MOUNTAINFrr0\lER
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Service Quality Review
January -June20L7
2.6,3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln20L2 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 20L2,lhe 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 (orior to 12131/2011)
On a routine basis, the Company reviews circuits for performance. One measure that it uses is called circuit
performance indicator (CPl), which is a blended weighting of key reliability metrics covering a three-year period.
The higher the number, the poorer the blended performance the circuit is delivering. As part of the Company's
Performance Standards Program, it annually selects a set of Worst Performing Circuits for targeted improvement.
The improvement projects are generally completed within two years of selection. Within five years of selection,
the average performance of the selection set must improve by at least 20% against baseline performance. Those
program years which have met their target scores are removed from the listing below.
Reliabilitv Performa nce I m provement ( post 1.2/3U201 1 th roueh 1213 U2016)
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 L0% against baseline performance. Those program years which have
met their target scores are removed from the listing below.
Page 15 of 20
Plans
Meeting
Goals
(>1 year
since project
completion)
Estimated
Avoided
annual
cMt
Actual
Avoided
annual
CML
Budgeted
Cost per
annual
avoided
cMt
Actua!
Cost per
annual
avoided
CML
Plans Not
Meeting
Goals
(not
included in
metrics)
Plans
waiting for
information
2 21,,478 20,444 S3.6s S2.01 2 1Lava5s 1.3s
0 0 5Montpelier5Ss.ze
Preston 13 st.76 5 324,299 L,028,833 s1.63 S0.53 0 8
Rexburg 9 S3.86 3 226,364 547,996 s2.06 so.2s 1 5
Shelley 10 s 1.os 3 124,005 418,900 s1.4s s0.29 1 6
13 696,146 2,0L6,t73 S1.80 S0.48 4 25
Approval Metrics Effectiveness Metrics ln
Progress
District Project
count
Budgeted
CosVCML
TOTAL 42 s1.99
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Service Quality Review
January -June20L7
(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
IN PROGRESS 225 237Clifton 11 (Figure 3C)
Dubois 12 (Figure 4C)IN PROGRESS 195 158
TARGET SCORE = 189 2LO 198
PROGRAM YEAR 16
Lava 11 (Figure 1C)COMPLETE L27 40
Preston 11 (Figure 2C)COMPLETE 36 59
82TARGET SCORE = 73 50
YEAR 15
PROGRAM YEAR 12
Grace 12 COMPLETED 124 704
Preston 13 COMPLETED t02 108
TARGET SCORE = 90 113 105
Page L6 of 20
lDAHO WORST PERFORMING
crRcutTs STATUS BASELINE PERFORMANCE
0613012016
Region Performance lndicator 2012 (RPt12) Method
Circuit Performance Indicator 2005 {CPl05) Method
UROCKY MOUNTAINx(POWER
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IDAHO
Service Quality Review
2,7 Restore Service to 8O% of Customers within 3 Hoursa
2.8 Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
customerguaran fees
January - June2OLT
January to June 2017
FebruaryJanuary March April May June
9L/o83%89%75o/o 90%96%
PS5-Answer calls within 30 seconds 80%820/,
PS6a) Respond to commission complaints within 3 days 95%L00%
PSSb) Respond to commission complaints regarding service disconnects
within 4 hours 95%700%
PS6c) Resolve commission complaints within 30 days 9s%700%
ldaho
cG1
cG2
CG3
CC'4
CG5
cG6
CG7
EvEnt3
m17
Fdifra !t sEcs..P.ld EYrnt3
2016
Fduroa fi Succe3r P.ld
Restodng Srpply
Appoinfnents
Srid-rg m Power
Esfindes
Respond to Elillng lnqiies
Respmd to ]tleGr Prcblems
i,tot'hcatirn d Phmed lnEnLptions
t0
$0
$0
$0
t0
$0
I750
r06:20
4y
21
165
219
9t
tt,934
0
0
0
0
0
0
15
.lm.r
'tm!f,
lmrr
lUrr
1m*
lUrr
99.70t4
tt5,816
t12u
111
217
trt
3,8911
1m%
99.75t5
l(xrl6
tfi!%
1m*
tm*
t0015
0
1
0
0
0
0
0
r0
s50
g)
t{)
t0
t0
t0
't12,317 15 99.90% t760 60.7{8 1 99.990/6 350
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.
CG7 performance was the result of a single outage which was planned for a pole replacement project, but due to incorrect
modeling, customers were not notified consistent with the guarantee requirement.
a ln some cases a substation residing in one state may have a circuit which feeds customers within another state. ln this case restorations
times are allocated to the state in which the feeding substation resides, opposed the customer's physical location.
PageLT of20
RESTORATIONS WITHIN 3 HOURS
Reporting Period Cumulative = 90%
COMMlTMENT GOAt PERFORMANCE
V-.ROCKY MOUNTAINYTPOVI/ER
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Service Quality Review
January -June20L7
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 Types
Below are the definitions for interruption events. For further details, refer to IEEE 1366-20O3l2OL2s Standard for
Reliability lndices.
Sustained Outdge
A sustained outage is defined as an outage greater than 5 minutes in duration.
Momentory Outage Event
A momentary outage event is defined as an outage 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 t365-20O312012. Where no substation breaker SCADA
exists, fault counts at substation breakers are to be used.
Reliability lndices
SAIDI
SAIDI (system average interruption duration index) is an industry-defined term to define the average duration
summed for all sustained outages a customer experiences in a given period. lt is calculated by summing all
customer minutes lost for sustained outages (those exceeding 5 minutes) and dividing by all customers served
within the study area. When not explicitly stated otherwise, this value can be assumed to be for a one-year
period.
Doily SAIDI
ln order to evaluate trends during a year and to establish Major Event Thresholds, a daily SAIDI value is often
used as a measure. This concept is contained IEEE Standard L366-20L2. This is the day's total customer minutes
outofservicedividedbythestaticcustomercountfortheyear. ltisthetotalaverageoutagedurationcustomers
experienced for that given day. When these daily values are accumulated through the year, it yields the yea/s
SAIDI results.
SAIFI
SAIFI (system average interruption frequency index) is an industry-defined term that attempts to identify the
frequency of all sustained outages that the average customer experiences during a given period. lt is calculated
by summing all customer interruptions for sustained outages (those exceeding 5 minutes in duration) and
dividing by all customers served within the study area.
CAIDI
CAIDI (customer average interruption duration index) is an industry standard index that is the result of dividing
the duration of the average custome/s sustained outages by frequency of outages for that average customer.
While the Company did not originally specify this metric under the umbrella of the Performance Standards
s IEEE 1366-2003/2012 was first adopted by the IEEE Commissioners on December 23,2003. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
Page 18 of 20
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Service Quality Review
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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).
MAIFIE
MAlFle (momentary average interruption event frequency index) is an industry standard index that quantifies
the frequency of all momentary interruption events that the average customer experiences during a given time-
frame. lt is calculated by counting all momentary interruptions which occur within a 5 minute time period, as
long as the interruption event did not result in a device experiencing a sustained interruption.
CEMI
CEMI is an acronym for Customers Experiencing Multiple (Sustained and Momentary) lnterruptions. This index
depicts repetition of outages across the period being reported and can be an indicator of recent portions of the
system that have experienced reliability challenges. This metric is used to evaluate customer-specific reliability.
cPt99
CPl99 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to identify
underperforming circuits. lt excludes Major Event and Loss of Supply or Transmission outages. The variables and
equation for calculating CPI are:
CPI=lndex*((SAlDl*WF*NF)+(SAlFl*WF'*NF)+(MAlFl *WF*NF)+(Lockouts*WF*NF))
lndex: 10.645
SAIDI: Weighting Factor 0.30, Normalizing Factor 0.029
SAIFI: Weighting Factor 0.30, Normalizing Factor 2.439
MAIFI: Weighting Factor 0.20, Normalizing Factor 0.70
Lockouts: Weighting Factor 0.20, Normalizing Factor 2.00
Therefore,10.645*((3-yearSAlDl*0.30*0.029)+(3-yearSAlFl*0.30*2.439)+(3-yearMAlFl*0.20*0.70)
+ (3-year breaker lockouts * 0.20 * 2.00)) = CPI Score
cPt05
CPl05 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit to identify
underperforming circuits, Unlike CPl99 it includes Major Event and Loss of Supply or Transmission outages. The
calculation of CPl05 uses the same weighting and normalizing factors as CPl99.
RPI
RPI is an acronym for Reliability Performance lndicator, which measures reliability performance on a specific
segment of a circuit to identify underperforming circuit segments rather than measuring performance of the
whole circuit.
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 L366-20L2) 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 LostLIL-12137/20L6 76,97L L4.82 7,L41.,067
tlt-Lzl3tl2oL7 78,594 15.56 !,301.,447
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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 t.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 caLrse, 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 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 Anolysls section of this report contains two
tables for Controllable Distribution and Non-controllable Distribution, which list the Company's performance by
direct cause under each classification.) At the time that the Company established the determination of
controllable and non-controllable distribution it undertook significant root cause analysis of each cause type and
its proper categorization (either controllable or non-controllable). Thus, when outages are completed and
evaluated, and if the outage cause designation is improperly identified as non-controllable, then it would result
in correction to the outage's cause to preserve the association between controllable and non-controllable based
on the outage cause code. The company distinguishes the performance delivered using this differentiation for
comparing year to date performance against underlying and total performance metrics.
Page 20 of 20
ROCKY MOUNTAINPOI,I'ER
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