20140613Service Quality Report 2013.pdf

ROCKY MOUNTAIN
Po\'I/ER
June 13,2014
VIA OWRNIGHT DELIVERY
gr p: r-, tr l\/ | ll
?clq iuH l3 f,l't 9: 59
uT I JEfd scCli f! i;iE', o *
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Ms. Jean D. Jewell
Commission Secretary
Idatro Public Utilities Commission
472W. Washington
Boise,ID 83702
Re: Rocky Mountain Power Service Quality Report for the period
January I through December 31,2013.
Dear Ms. Jewell:
On June 10,2014 representatives of Rocky Mountain Power, a division of PacifiCorp, met with
Commission Staff and presented the above-referenced report. Attached is a final copy of the
report. If there are any additional questions regarding this report please contact me at (801) 220-
2963.
Sincerely,
Ted Weston
Manager, Idaho Regulatory Affairs
Enclosurescc: Rick Sterling
Teni Carlock
Beverly Barker
ROCKY MOUNTAIN
POWER
A DIVISION OF PAC!FICORP
IDAHO
SERVTCE aUArrTY
REVIEW
January 1r December 31, 201 3
Report
-ROCKY
MOUNfAF.IYporv=n\^fficm Service Quality Review
January - December 2013
TABLE OF CONTENTS
TABLE OF CONTENTS.......... ...........2
EXECUTTVE SUMMARY ........... ........3
1 SERVICE STANDARDS PROGMM SUMMARY.......... .................3
1.1 ldaho Customer Guarantees ............... .....................3
1.2 ldaho Performance Standards............... ...................4
1.3 Reliability Definitions ..............5
2 RELIABILITY PERFORMANCE.... ..,.,...,..,,..,7
2.1 System Average lnterruption Duration lndex (SAlDl)...... ...........9
2.2 System Average Interruption Frequency lndex (SAlFl)...... ......10
2.3 Reliability History...... ............11
2.4 Momentary Average lnterruption Event Frequency lndex (MAIFIE) ...........12
2.5 Cause Code Analysis ...........16
2.5.1 Underlying Cause Analysis Table ...................17
2.5.2 Cause Category Analysis Charts ....................18
2.6 lmprove Worst Performing Circuits or Areas by Target Amount..... ...........19
2.7 Geographic Outage History of Under-performing Areas ..........20
2.8 Restore Service to 80% of Customers within 3 Hours..... .........23
2.9 Telephone Service and Response to Commission Complaints.............. ....................23
3 CUSTOMER GUARANTEES PROGMM STATUS ,....,.,.,.,.....,,,,24
Page2 of 24
ROCKY MOUNTAINFOWER Seruice Quality Review
IDAHO
EXECUTIVE SUMMARY
January - December 2013
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. !n other cases, largely where the industry has no
established standards, Rocky Mountain Power has developed metrics, targets and reporting. While
industry standards are not focused around threshold performance levels, the Company has developed
targets or performance levels against which it evaluates its performance. These standards and
measures can be used over time, both historically and prospectively, to measure the service quality
delivered to our customers.
1 SERVICE STANDARDS PROGRAM SUMMARYI
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 thefUdiversion 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 workino 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
workino davs.
Customer Guarantee 7:
Notification of Planned lnterruptions
The Company will provide the customer with at least
two days' notice prior to turning off power for planned
interruotions.
Nofe: See Rules for a complete description of terms and conditions for the Customer Guarantee Program.
' 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.
PageS of24
ROCKY MOLT$TAIN
FOUIER Seruice Quality Review
IDAHO January - December 2013
1.2
Note:o Pertormance Standards 1, 2 & 4 are for underlying pefformance days and exclude fhose c/asslf,ed as
Major Events.
'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.
" 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 1366-20'12; they are a modification to the Company's historic CPl.
RPI excludes breaker lockout events.a Prospectively, the Company will work with Commission Staff to determine methods to report the target area performance and
cost-benefit results.
Page 4 of 24
ldaho Performance Standards
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 Underlvinq 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 Underlvino distribution events.
Network Performance Standard 3:
lmprove' Under-Performing Areas
Annually the Company will select at least one
underperforming are? based upon a reliability
performance indicatoro (RPl). Within five years after
selection the Company will reduce the RPI by an
average ol 10o/o for the areas selected in a given
year. The Company will identify the criteria used for
determining these areas and the planso 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% of customers on averaqe.
Customer Service Performance Standard 5:
Telephone Service Level
The Gompany 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
monitorinq 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 95o/o of informal
Commission comolaints within 30 davs.
ROCKY MOI,NTANPo\'YER Service Quality Review
IDAHO January - December 2013
1.3 ReliabilityDefinitions
This section wil! define the various terms used when referring to intenuption 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 1366-2003t20125
Standard for Reliability lndices.
Susfarned 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 1366-200312012. Where no substation breaker SCADA exists, fault counts at
substation breakers are to be used.
Reliabilitv lndices
SAIDI
SAIDI (system average interruption duration index) is an industry-defined term to define the average
duration summed for all sustained outages a customer experiences in a given period. !t 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 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 year's SAIDI results.
SAIFI
SAIFI (system average interruption frequency index) is an industry-defined term that attempts to
identify the frequency of all sustained outages that the average customer experiences during a given
period. lt is calculated by summing all customer interruptions for sustained outages (those exceeding
5 minutes in duration) and dividing by all customers served within the study area.
CAIDI
CAIDI (customer average interruption duration index) is an industry standard index that is the result of
dividing the duration of the average customer's sustained outages by frequency of outages for that
average customer. While the Company did not originally specify this metric under the umbrella of the
Performance Standards Program within the context of the Service Standards Commitments, it has
since been determined to be valuable for reporting purposes. lt is derived by dividing PS1 (SAlDl) by
PS2 (SArFr).
u tEEE 1366-2003/2012 was first adopted by the IEEE Commissioners on Decemb er 23,2003. The definitions and
methodology detailed therein are now industry standards, which have since been affirmed in recent balloting activities.
Page 5 ot 24
ROCKY MOUNTAINF'ol'I'ER Service Quality Review
IDAHO
MAIFIE
January - December 2013
MAIFIE (momentary average interruption event frequency index) is an industry standard index that
quantifies the frequency of all momentary intenuption 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-specifi c reliability.
cPt99
CPl99 is an acronym for Circuit Performance lndicator, which uses key reliability metrics of the circuit
to identify underperforming circuits. !t excludes Major Event and Loss of Supply or Transmission
outages. The variables and equation for calculating CPI are:
cpl =lndex*((sAlDt*wF*NF)+(sAlFl*wF*NF)+(MAlFl*wF*NF)+(Lockouts*wF*NF))
Index: 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)) = CP! 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
cPr99.
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 two categories of performance: underlying performance and
major events. Major events represent the atypical, with extraordinary numbers and durations for
outages beyond the usual. Ordinary outages are incorporated within underlying performance. These
types of events are further defined below.
Major Events
A Major Event is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold
value, Reliability Standard I EEE 1 366-200312012.
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 that fall below the statistically derived threshold represent
"underlying" performance and are valid (with some minor considerations for changes in reporting
practices) for establishing and evaluating meaningful performance trends over time.
Page6 of24
ROCKY MOUNTAINPO/I'ER Service Quality Review
IDAHO January - December 2013
2 RELIABI LITY PERFORMANC E
Despite better than plan performance during the first half of 2013, at the end of the year, the
Company experienced underlying interruption duration (SAlDl) and interruption frequency (SAIFI)
results that were off plan. Performance results for ldaho underlying performance can be seen in
subsections 2.1 and 2.2below.
Four events during the reporting period met the Company's ldaho major event threshold levelG for an
exclusion of 347 state SAIDI minutes from underlying performance results.
Major Event General Descriptions
o On January 14, 2013, a loss of supply event occurred to a transmission line between Ricks Junction and St.
Anthony; this was due to a broken conductor, and resulted in loss of power to Rocky Mountain Power ("Company")
customers served by Moody, Canyon Creek, Newdale, St. Anthony, Ashton, Targhee, Sugar City, and Rexburg
substations.
Twenty-eight circuits experienced sustained interruptions, affecting 47% of the Company's Rexburg customers
(20% of its ldaho customers).. On April 29, 2013, strong winds caused damage to Rocky Mountain Power's facilities resulting in significant
outages to its customers in ldaho due to poles and conductor falling, airborne objects blown into facilities, pole
fires, and high winds whipping lines into other lines or vegetation. ln addition, a circuit breaker at Goshen
substation failed catastrophically, accounting for about a third of the total event customer minutes lost.
Twenty-six substations and 42 circuits experienced sustained interruptions, affecting 41% ol the Company's
Shelley customers (160/o of its ldaho customers). Facilities replacement included one distribution pole and 6
crossarms.. On August 22, 2013, summer storms with substantial lightning caused damage to Rocky Mountain Powe/s
facilities resulting in significant outages to its customers in ldaho, especially in Rexburg. These included numerous
fuse operations, burnt cutouts, and a pole fire; however, loss of transmission on the Rigby-Saint Anthony 69kV line
about 10:30pm accounted for the majority of the event total customer minutes lost, as the transmission wire fell into
the distribution below.o ln late November 2013, Rocky Mountain Power identified a need to inspect and maintain a Goshen substation
breaker whose family's operating history had been somewhat unreliable. The reliability coordinator and the
company evaluated a variety of scenarios and determined that the maintenance would be scheduled, but if certain
parameters occurred, might result in load shedding operations to maintain the reliability and integrity of the bulk
power system. On December 4, 20'13, in the early hours of the morning, the company and the reliability
coordinator determined that conditions were moving in such a way that load shedding may be required. Then, as
temperatures continued to fall, moming loads began to build, and local wind generation resources abated, it was
determined that load shedding actions would be necessary to maintain the integrity of the bulk power
system. Those actions were invoked.
u ln 2005, the Company adopted via its Service Standard Program filing, the use of IEEE 1366-2003, wherein a statistically
based threshold for a Major Event Day is developed. At the time of the development of the Merger Commitment targets and
pre-merger baselines, it was estimated that approximately 39 SAIDI minutes and 0.4 SAIFI events were embedded in these
metrics. The charts included do not reflect the exclusion of these minutes.
PageT of24
PRIMARY CAUSE
Loss of Substation (storm
R(XKY MOUNTAF'I
Seruice Quality Review
IDAHO January - December 2013
ln 2013, sixteen significant event daysT were recorded, which account for 112 SAIDI minutes, about4To/o
of the reporting period's underlying 240 SAIDI minutes. Significant event days add substantially to year
on year cumulative performance results. Fewer counts of significant event days generally result in better
reliability, while more significant event days generally mean poorer reliability results.
DATE EVENT SAIDI
PERCENT OF
ANNUAL
sArDr(240)
PRIMARY CAUSE
oL/29/20L3 4 2%Vehicle, Equipment
o3l0i6/20L3 A 2%Loss of substation
ulo8/20L3 E 201 Loss of transmission
oi6129120L3 C 3%Substation testine
07lL6l20L3 LC 7%Loss of transmission
07/28/20L3 4 2%Loss of substation
07/29120L3 13 So/c Loss of transmission
o8l06/20L3 A 2o/c Loss of transmission
08/27/2013 4 2o/c Vehicle lnterference
0/9/ozl20L3 8 3%Loss of substation
0/9/o3120L3 3%Liehtnine
09/L3/20L3 c Zo/c Loss of transmission
09/L8/20L3 5 2%Pole Fire
o9130120L3 L2 5%Weather
L2/O8120L3 5 z%o Loss of transmission
Lzltsl20L3 LL 5Y"Loss of substation
TOTAL Lt2 4m
Significant Event General Descriptions
112912013: Lava 11 broken insulator pin burned crossarm; Shelley 13 car hit pole, wire down
31612013: Loss of Ammon substation due to 2 poles down on Goshen-Ammon 69kV; Rigby
12 due to pole flre on transmission pole with distribution underbuild
41812013: Loss of transmission due to storm with 2 poles down on Jefferson-Osgood 69kV
612912013: Emergency damage repair Winsper 21 and 22, deenergized substation for testing,
installed mobile
7116113: Lightning, loss of 230kV Antelope line and 69kV Goshen line
7128113: Squirre! in St Anthony substation
7129113: Lightning strike close to Grace substation, and 46kV wire down on Fishcreek to
Grace
816113: Poles down on Winsper tap Amps-Mudlake 69kV
8127113: Car hit pole, tore wire down on Thornton 11
912113: Lightning hit inside Grace substaton
913113: Lightning hit a pole on Sandcreek 14
9113113: Lightning burned down wires between Central Switch Rack and Fishcreek tap
9/18/13: Pole fire on Newdale 12
9/30/13: Windstorm through Rexburg and Shelley
1218113: Wires down on Winsper tap Amps-Mudlake 69kV
12115113: Two blown power fuses at Ammon substation
7 On a trial basis, the Company established a variable ot 1.75 times the standard deviation of its natural log SAIDI results.
PageB ot24
a
a
o
a
o
a
a
ROCKY MOI'TITAIN
POWERamdffi Seruice Quality Review
January - December 2013
2.1 System Average lnterruption Duration lndex (SAlDl)
The Company's underlying interruption duration performance tracked significantly better than plan,
until summer, when a barrage of lightning storms caused a record number of significant event days,
which pushed performance off plan for the remainder of the year.
2013 SAIDI Plan
(a (a (') ao (q (fj (q cD (',ooooooooo(\I(\I(\INNNN(\16I
(Y) ai, 0,, (', (?) (i, g) (i, ('1, e, (D (DR RE R R R R R R E E E
IDAHO SAIDI Comperlron to Phn
(excludes Prearanged and Custorner Requested)
Maior Events: OOJan l4LossofSupply(nest) !Apr29Wlnd
Aug22 LossofSupply t
Dec 4 WECC Loadshed !I
I
o o olnduding Mairr Evenb
Page 9 of 24
ROCKY MOUNTA|NFOWER Seruice Quality Review
January - December 2013
2.2 System Average lnterruption Frequency lndex (SAlFl)
During the first half of the year, the Company's underlying interruption frequency performance tracked
significantly better than plan; however, summer lightning events took performance off track, and the
year ended jus!htly better than
IDAHO SAlFlActual 2013 SAIFI Plan
Total 3.37
Underlying 2.12 2.15
Controllable 0.31
IDAHO SAIFI
(excludes Preananged and Customer Requested)
ooooooo(qooo(f,ooooooooooooNNNNNNNNNNNN
NO=A@N600N
2.5
2.0
aE 't.5
0,
{,
E 4A
th
0.5
0.0
30
2.5
oE z.o
til
1.5
r0
0.5
0.0
Maior Events: :r:i
Jan l4lossofSupply(ncst) . i
Apr 29 Wind
"uf;
-ODanline
Pt.nTffi.t
----- lndudne H ajor C Ent3
-
E:dudine Ulirr Evdb
IDAHO SAlFl Comparlron to Plen
(exclu&s Preananged and Gudorner Requeste<l)
(o o (v) (', (D (v) (r) ai, (9 (v, (ar (')R RR R R R R R R 8 R E
Page 10 ot 24
R(TKY M(X,NTAN
Service Quality Review
IDAHO January - December 2013
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. ln 2013 significant days and major events
substantially impact the yea/s performance and apparently eroded some of the improvements the
Company had previously delivered.
ldaho Reliability History - lncluding Major Events
-SAIDI
TCAIDI +SAIFI
4
3occ,
IJJ
2
1
0
600
500
o4009
.g
=300
200
100
0cy03 cy04 cY05 cY06 cY07 cY08 cY09 cy10 cy11 cy12 cy13
4
3
an
It
ul2
1
0
ldaho Reliability History - Excluding Maior Events
-SAlDl -CAlDl
+SAlFl
cY03 cY04 cY10 cY11 CY12 CY13
400
300,g3.g
200
100
0
Page11ot24
R(XKY Ilot.iTITANFilERlmdm Seruice Quality Review
IDAHO January - December2013
2.4 Momentary Average lnterruption Event Frequency lndex (MAlFlE)
The Company annual reports the occurrence of short intenuptions using two different metrics. The
first chart below displays, for the circuits with SCADA devices, the operating area weighted MAIFIE
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 conections
undertaken. Highlights of current findings for breakers with unusual levels of counter operation are
summarized here.o lndian Creek #1 1: Under investigation, however based on review with customers fed from
this circuit reportedly no more than 8 momentary events have occuned over the past
year.o Sandune#21 &#22: Rodents chewed up the breaker contro! cables, shorting them out,
which caused the breakers to roll continuously until crews arrived to isolate the problem;
problem has been permanently resolved.. Hayes #13: Recording enor on the trip counter. Reading was 297, recorded as 397.
Records are being conected.o Webster #14: This circuit had an issue that was corrected by replacing crossarms,
tightening some slack spans and re-sagging a section of wire.
January { - December 31, 20{3
Page 12 ol 24
R(TKY MOTJNTAIN
FOvt,ER Service Quality Review
IDAHO - December 2013
January I through Decomber 31,2013 (includes Major Events)
Operating Area Circuit Name Gircuit lD Operations
MONTPELIER ALEXANDER #11 ALX11
MONTPELIER ARTMO #11 ARM11
MONTPELIER ARTMO #12 ARM12 2!
MONTPELIER BANCROFT#11 BAN11
MONTPELIER BANCROFT#12 BAN12
MONTPELIER CHESTERFIELD #11 CHS11
MONTPELIER CHESTERFIELD #12 HATCH CHS12
MONTPELIER COVE #12 cov12
MONTPELIER EIGHT MILE #11 EGT11
MONTPELIER GEORGETOWN #11 GRG11
MONTPELIER GRACE #11 GCE11
MONTPELIER GRACE #12 GCE12
MONTPELIER HEN RY #11 HRY11
MONTPELIER HORSLEY#11 HRS11
MONTPELIER INDIAN CREEKf1l IND11 10r
MONTPELIER LAVA f11 LVA11
MONTPELIER LUND #11 LND11
MONTPELIER MCCAMMON #11 MCC11
MONTPELIER MCCAMMON f12 MCC12
MONTPELIER MONTPELIER #11 MNT11
MONTPELIER MONTPELIER #13 MNT13
MONTPELIER MONTPELIER S14 MNT14
MONTPELIER RAYMOND #11 NORTH TO GENEVA RAY11 31
MONTPELIER RAYMOND #12 SOUTH TO PEGRAM RAY12
MONTPELIER ST CHARLES #11 sTc11
PRESTON CLIFTON #11 DAYTON & BANIDA CLF11
PRESTON CLI FTON #12 CLIFTON/OXFORD/SWAN LAKE CLFL2
PRESTON DOWNEY#11 DWN11 71
PRESTON DOWNEY#12 DWN12 7(
PRESTON HOLBROOK #11 HLB11 7(
PRESTON MALAD #11 MLD11
PRESTON MALAD #12 MLD12
PRESTON PRESTON #11 PRS11
PRESTON PRESTON #12 PRS12
PRESTON PRESTON #13 PRS13
PRESTON TANNER #11 MINK CREEK TNR11
PRESTON TAN N ER #12 RIVERDALE/TREASURETON TNR12
PRESTON WESTON #12 NORTH TO DAYTON wsT12
PRESTON WESTON#11 SOUTH - WESTON/FAIRVEW wsT11
REXBURG ANDERSON #11 WEST AND11
REXBURG ANDERSON #12 EASTAND NORTH AND12 3t
REXBURG ANDERSON #13 NORTH AND13 4
REXBURG ARCO #11 ARC11
REXBURG ARCO #12 ARC12
REXBURG ARCO #13 ARC13
REXBURG ASHTON #11 ASH11
REXBURG BELSON #11 BLS11
REXBURG BETSON #12 BLS12
REXBURG BERENICE #21 BRN21
REXBURG BERENICE #22 BRN22
REXBURG CAMAS #11 cMs11 L2
REXBURG CAMAS #12 CMS12
REXBURG CANYON CREEK # 22 CNY22 1C
REXBURG CANYON CREEK #21 CNY21
Page 13 of 24
Seruice Quality Review
IDAHO December 2013
January I Orrough December 31,2013 (includes taJor Events)
Operating Area Circuit Name Gircuit lD Operations
REXBURG DUBOIS #11 DBS11
REXBURG DUBOTS #12 DBS12
REXBURG EASTMONT#11 EST11
REXBURG EASTMONT#12 EST12
REXBURG EGIN #11 EGN11
REXBURG EGIN #12 EGN12
REXBURG HAMER #11 HMR11 2e
REXBURG HAMER#12 HMR12 4
REXBURG MENAN f11 MNN11
REXBURG MENAN f12 MNN12
REXBURG MENAN #1:!MNN13
REXBURG MILLER #11 MLL11
REXBURG MILLER #12 MLL12
REXBURG MOODY#11 MDY11
REXBURG MOODY#12 MDY12
REXBURG MOODY#13 MDYilI
REXBURG MUDI.AKE #11 MDL11
REXBURG MUDIAKE #12 MDL12 C
REXBURG NEWDALE #11 NWD11
REXBURG NEWDALE #12 NWD12 4
REXBURG NEWDALE #13 NWD13 1C
REXBURG RENO #11 REN11 L7
REXBURG RENO #12 REN12
TEXBURG RENO #13 REN13 2
IEXBURG REXBURG #11 RXB11 C
IEXBURG REXBURG #12 RXB12
IEXBURG REXBURG #13 RXB13 8
REXBURG REXBURG #14 RXB14 54
REXBURG REXBURG #15 RXB15
REXBURG REXBURG #16 RXB16 6
REXBURG RIGBY #11 RGB11 A
REXBURG RIGBY #12 RGB12 5
REXBURG RIGBY#1:}RGB13 E
REXBURG RIGBYSl4 RGB14
REXBURG RtRtE #12 RIR12 c
REXBURG ROBERTS #11 RBR11
REXBURG ROEERTS #12 RBR12
REXBURG rUBY#11 RBY11
REXBURG iANDUNE#21 SDN21 56i
REXBURG ;ANDUNE#22 SDN22 ,.65(
REXBURG sMtTH #11 SMT11
REXBURG sMtTH #13 SMT13
REXBURG SMITH #14 SMT14
REXBURG SOUTH FORK #11 IDAHO PACIFIC POTATO SFK11
REXBURG SOUTH FORK #13 ANTELOPE FLATS SFK13
REXBURG STANTHONY#11 STA11
REXBURG STANTHONY#12 STA12
REXBURG STANTHONY#13 STA1:I
REXBURG SUGAR CITY#11 SGR11
REXBURG SUGAR CITY#12 SGR12
REXBURG SUGAR CITY#]j}SGRIj}c
REXBURG SUGAR CITY#14 SGR14
REXBURG SUNNYDELL#11 SNN11 1
REXBURG SUNNYDELL#12 SNN12 A
Page 14 of 24
ROCKY MOUNTAN
Seruice Quality Review
IDAHO December 2013
January I through Eecember 31, 2013 (includes taior Events)
Operating Area Carcuat Name Circuit !D Ooeraffons
REXBURG TARGHEE #11 TRG11
REXBURG TARGHEE #12 TRG12
REXBURG THORNTON #11 THR11 7
REXBURG THORNTON #12 THR12 25
REXBURG WATKINS #11 NORTH AND EAST WTK11 6
TEXBURG WEBSTER #11 EAST AN D SOUTH wBs11 L4
IEXBURG WEBSTER#12 NORTH wBs12 L2
IEXBURG WEBSTER #14 wBs14 L#t
IEXBURG WINSPERf2I wNs21 5
IEXBURG WINSPER #22 wNs22 6
;HELLEY AMMON #11 AMM11
;HELLEY qMMON #12 AMM12 L4
;HELLEY Cinder Butte #11 ctB11
iHELLEY CINDER BUTTE #13 ctB13 25
iHELLEY Cinder Butte #17 ctB17
;HELLEY CLEMENTS #11 CLE11
iHELLEY :LEMENTS #12 CLE12 6
;HELLEY COSHEN #11 GSH11
;HELLEY 60SHEN #13 GSHil}53
'HELLEY
HAYES f11 HYS11
iHELLEY HAYES f12 HYS12 LI
'HELLEY
HAYES #]:}HYSff}ltr
;HELLEY HOOPES f11 WEST HPS11 c
;HELLEY HOOPES #12 NORTH HPS12 c
iHELLEY IDAHO FALTS f11 IDF11
iHELLEY IDAHO FALIS #12 IDF12
iHELLEY IDAHO FALLS#13 IDF13
;HELLEY IDAHO FALI-S#14 IDF14 c
;HELLEY TEFFCO f21 IFF2L 47
;HELLEY TEFFCO*22 TFF22 18
;HELLEY KETTLE f21 KTT21 15
;HELLEY KETTLE #22 Kff22 6
iHELLEY MERRILL#11 MRR11 5
;HELLEY MERRILL#12 MRR12 1t
iHELLEY MERRILLf1:}MRR13 L7
;HELLEY MERRILLfI4 MRR14
iHELLEY cscooD #11 osG11 22
;HELLEY cscooD #12 osG12
iHELLEY cscooD #13 osG13
iHELLEY cscooD #14 osc14 5
;HELLEY SANDCREEK #11 SND11.c
'HELLEY
iANDCREEK #12 SND12 c
iHELLEY iANDCREEK #13 SND13
'HELLEY
SANDCREEK #14 SND14 27
iHELLEY SANDCREEK #15 SND15
;HELLEY SANDCREEK #15 SND16 A
'HELLEY
SHELLEY #11 SHL11 2
;HELLEY SHELLEY #12 SHL12 c
;HELLEY SHELLEY #13 SHL13 4
iHELLEY SHELLEY #14 SHL14
;HELLEY UCON #11 UCN11 6
;HELLEY ucoN #12 UCN12 L2
iHELLEY WATKINS #12 SOUTH THEN EAST WTK12 I
Page 15 of24
ROCKY MOI,JNTAINFo\'VER
^fficw Seruice Quality Review
IDAHO January - December 2013
2.5 Gause 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 building fires (not including fires due to
faults or liqhtnins).
Weather \Mnd (excluding windborne material); snow, sleet or blizzard; ice; freezing fog;
frost: liohtnino.
Equipment Failure
Structural deterioration due to age (incl. pole ro0; 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 ortheft; 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 interferino obiect such as straw. shoes. strino. balloon.
Animals and Birds Any problem nest that requires removal, relocation, trimming, etc; any birds,
squirrels or other animals, whether or not remains found.
Operational
Accidental Contact by PacifiCorp or PacifiCorp's Contractors (including live-line
work); switching error; testing or commissioning error; relay setting enor, including
wrong fuse size, equipment by-passed; incorrect circuit records or identification;
faultv installation or construction: ooerational or safetv 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 afier storm damage, car hit pole, etc.; construction
work. reoardless if notice is oiven: rollino blackouts.
Trees Growing or falling trees
Other Cause Unknown; use @mments field if there are some possible reasons.
The table and charts below show the total customer minutes lost by cause and the total sustained
interruptions by cause. The charts show each cause category's role in performance results and
illustrate that certain types of outages account for a high amount of customer minutes lost but are
infrequent, while others tend to be more frequent but account for few customer minutes lost.
The Underlying cause analysis table includes prearranged outages (Customer Requested and
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 Planned category). Following the pie charts, a table of
definitions provides descriptive examples for each direct cause category.
Page 16 ot 24
ROCKY MOUNTAN
Seruice Quality Review
IDAHO January - December 2013
2.5.1 Underlying Cause Analysis Table
fjirect Cause Category
Description Drcct Cause Customer Minutes
Lost fur lncident
Customers ln
lncident Sustained
Sustained
lncident Count
ANIMALS
qNIMALS 218,386.27 r,c6i 16/
BIRD MORTALITY (NON-PROIECTED SPECIES)35,425.8€605 u
BIRO MORTALMY EROTECIED SPECIES) (BMTS)28,993.2(41€1!
BIRD NEST (BMTS)3,786.6t 29
BIRD SUSPECTED, NO MORTALITY 89,656.0!1,2N E(
EiIVIRONMENT trIRE/SMOKE (NOT DIJE TO FAULTS)0.0c
EOUIPMENT FAILURE
B/O EOUIPMENT 748,033.83 6,435 241
DETERIORANON OR ROTNNG 2,O14,Eo4..52 11,94!79S
NEARBY FAULT 1,66E.O:21
CVERLOAD 9,/160.1:91 21
POLE FIRE 931,654.7(3,229 3!
5 I ttuu I ui<E!t, tNliutA I uKlj, uuNuuu t9K 2,718.0(12 1
REISYS, BREAKERS, SWITCHES 0.0(c
INTERFERENCE
DtG-tN (NON-PAC|F|CORP PEFaSONNEL)34,090.4t 2W 4(
)THER INTERFERING OBJECT 69,263.Ei 437
f, fi ER UTILITY/CONTRACTOR 43,392.5{767
r'ANDALISM OR THEFT 5,33.1:5€
r'EHGLE ACCIDENT 517,721.4t 3,302 n
LOSS OF SUPPLY
=AILURE ON OTHER LINE OR STATION 0.0(c
-OSS OF SUBSTATION 1,701,857.5i 't 1,991 2(.
.OSS OF TRANSMISSION LINE 4,983,367.3(56,491 18S
SYSTEM PROTECTION 268.fi 4
OPERATIONAL
;AULTY INSTALL 222.4t
MPROPEFT PROTEGTME GOQRDINATION 13,2&+.9:4
NCORRECTRECORDS 575.74
NTERML CONTRACTOR +,051.7:508
JA(.;IFIG(JT{P EMPLUYEE . FIELU 1,701.4'1 13i
OTHER )THER, KNO\A'N CAUSE 75,068.4t 741 3i
JNKNOWN /Y1,094.2(7,86S 358
PLANNED
]ONSTRUCTION 184,463.4:77(88
;onstruction - scheouled swtcilng Jrc,cv/. /2Z 51
]USIOMER NOTICE GMEN 2,o82,509.3{1 0,1 9[14S
]USTOMER REQUESTED 24,510.71 27t 19€
=MERGENCY DAMAGE REPAIR 2,031,920.81 19,732 2U
=NERGY EMERGENCY INTERRUPTION 131,797.62 3,431
NTENTIONAL TO CLEAR TROUBLE 59,730.8t 1,741 11
VIAINTENANCE 10,47E.0(1
IRANSMISSION REOUESTED 154.,227.52 I,C]i
TREES I REE - NUN.I'T(EVEN IAt'LE 658,503.24 5,10t ol
55,457.0t 73(12
WEATHER
:REEZNG FOG & FROST u,u/+ /.ol 1t
CE I
'Y.UCZ.U{
I,C'll 1
-IGHTNING 1,211 , tJt .U1 't,J/214
JNUW, I'LEE I ANU t'LIZZAI(U 146,274.9i 44t 27
A/IND 1,052,368.6t 6,s8(12C
ldaho I ncludlng Preatrenged 20,670,087.51 l7l,65t 3,5:t7
ldaho Underlylng 18,47,169.627 161,15t s,141
ldaho SAIDI SAIFI 2L 2.11
Note: Direct Causes are not listed if there were no outrages classified within the cause during the reporting period.
Page 17 ot24
-ROCKY
lrllot.trrlTAlN\ffi* S"-i"" Ou"litv n"rl
January - December 2013
2.5.2 Gause Gategory Analysis Gharts
ldaho 2Ol3 Cause Analysls - SAIDI
I weathar
13!t6
I Anlmals I Envlronment2txo*
v Tnecs
496
I EqulpmCnt
F.llurr
1896
r tnterfrrencc
?16
r Planncd
2416
E othcr
496 r Loss of Supply
32%r OpeEtlon.l
tdaho 2OLil Cause Analysls - SAIFI
E Weethcr
,,296
I Anlmeb I Envtronmcnt2x oge
ia Trcca
396
I Equlpment
Fallurc
t3%t lntcrfarcnce
316
r Planncd22*
E Othcr
596 r [o$ of Supply
8t 6I Opar.tlon.l
ldaho 2013 Cause Analysls - lncldents
E We.thcr
tt96
I Anlmalstw
E TNGC3
316
r Envlronmanto*
r Planncd
2216
r Equlpmcnt
Fallurc
3216
E Other
1116
r Opcr.tlon.lt6 rf Supply
6%
I lntarfer€ncc
4%
Page 18 ot24
ROCKY MOITVTAh|
POWER Service Quality Review
IDAHO January - December 2013
2.6 Improve Worst Performing Circuits or Areas by Target Amount
ln 2012 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 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.
Circuit Performance Improvement (prior to 1213112011)
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 20o/o against baseline performance.
Rel iability Perform ance I m provement (post 12131 1201 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.
Gircuit Performance lndicator 2Oo5 (CPt05) Method
PROGRAM YEAR 12
Grace 12 124 COMPLETED 186
Preston 13 102 COMPLETED 56
TARGET SCORE = 90 113 121
Region Performance lndicator 2012 (RPl12) Method
PROGRAM YEAR 13
Mudlake 12 248 COMPLETED 130
Goshen 13 100 COMPLETED 106
TARGET SCORE = 157 174 GOAL MET 118
PROGRAM YEAR 14
Berenice 21 (Fiqure |D-1A-C)290 COMPLETED 275
Malad 13 (Fisure lD-2A-C)122 IN PROGRESS 111
TARGET SCORE = 185 206 193
(lmprovement targets for circuits in Program Years 1 through 11 have been met and filed in prior reports.)
Page 19 of 24
VROCKY MOI'NTAINXH9[E.E- Service Qualiw Review
IDAHO January - December 2013
2.7 Geographic Outage History of Under-performing Areas
a.a456r[5!iraiattaEtortatr50,54iro
ab!a.aa5aItrt!tlrttrE50rorrt
tao
0
Figure ID-IA: Berenice 21 Controllable View
Figure 1B: Berenice 21 Non-Controllable View
Page20 ot24
ROCKY MOUNTAIN
POVVER Service Quality Review
January - December 2013
Figure lC: Berenice 21 Underlying View excluding Loss of Supply
daa
o
Figure 24: Malad 13 Controllable View
Page21 of 24
,ROCKY MOUNTAIN
FolTYER
Figure 38: Malad 13 Non-Controllable View
Figure 2C: Malad 13 Underlying View excluding Loss of Supply
Service Qual
January - December 2013
-
o-ic lnal t lnra
-*E*
!-
Page22 of 24
xffiouNrAN Service Quality Review
January - December 2013
2.8 Restore Seruice to 80% of Customers within 3 Hours
2.9 Telephone Service and Response to Commission Complaints
January 1 - December 31 ,2013 = 86%
PS5-Answer calls within 30 seconds
PSGa) Respond to commission complaints within 3 days
PSOb) Respond to commission complaints regarding
service disconnects within 4 hours
PS6c) Resolve commission complaints within 30 days
Page23 ot 24
ROCKY MOUNTANPOWERAreOffi Service Quality Review
IDAHO3 CUSTOMER GUARANTEES PROGRAM
custom erguaranfees
January - December 20'13
STATUS
Januaryto December2013
ldaho
cGl
CG2
cG3
cG4
cG5
cG6
cG7
Major Events are excluded from the Customer Guarantees program.
2013
B,Ents F.llures 96success Pald
160,491 0
812 0
816 0
248 1
496 1
183 0
8,005 6
10o/o $0
'100o/o $0
'100o/o $0
99.6% $50
99.8% $50
100o/o $0
99.97o $300
to Billing lnquiries
to ttbter Problems
0 100% $0
1 99.9% $s0
0 100% $0
0 100% $0't 99.8% $50
0 't00% $0
3 99.9% $150
108,7S6
882
956
250
502
146
5,384
116.916 5 99.9% $250
Page24 ot24