20200601Service Quality Report 2019.pdf

il:rl:1,./[rJROCKY MOUNTAIN
POWER I Di! ,.r:.r'l f;i 4..'lJ
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
June 1,2020
VIA ELECTRONIC DELIWRY
Ms. Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd.
Building 8 Suite 20lA
Boise, tD 83714
?Rc-E-os-o8, ?Ac- E tA-bL
Re: PAC-E-04-07 2019 Service Quality & Customer Guarantee Report for the period
January 1 through December 31,2019.
Dear Ms. Hanian:
Rocky Mountain Power, a division of PacifiCorp, hereby submits its Service Quality & Customer
Guarantee report covering January I through December 31,2019. This report is provided pursuant
to a merger commitment made during the PacifiCorp and ScottishPowerl merger. The Company
committed to implement a five-year Service Standards and Customer Guarantees program. The
purposes behind these programs were to improve service to customers and to emphasize to
employees that customer service is a top priority. Towards the end of the five-year merger
commitment the Company filed an application2 with the Commission requesting authorization to
extend these programs.
If there are any additional questions regarding this report please contact Ted Weston at (801) 220-
2963.
Sincerely,
c.^,.D
Vice
Enclosures
cc: Terri Carlock
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 !. - December 3L,2OL9
Report
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ROCKY MOUNTAN
POYI'ER !DAHO
Service QualiW Review
January - December 2019
TABTE OF CONTENTS
TABLE OF CONTENTS 2
EXECUTIVE SUMMARY
1 SERVICE STANDARDS PROGRAM SUMMARY
33
44
44
5s
06
E8
9s
L,L
L,2
ldaho Customer Guarantees
ldaho Performance Standards...
2 RELIABILITYPERFORMANCE
2.1 System Average lnterruption Duration lndex (SAlDl)
2.2 System Average lnterruption Frequency lndex (SAlFl)
2.3 Reliability History
2.4 Controllable, Non-Controllable and Underlying Performance Review
2.5 Cause Code Analysis
2.5.1 Underlying Cause Analysis Table..
2.5.2 Cause Category Analysis Charts
2.6 Reliability lmprovement Process
2.6.1 Reliability Work Plans
2.6.2 Project approvals by district
2.6.3 Reduce CPI for Worst Performing Circuits or Sub-circuits................
2.7 Restore Service to 80% of Customers within 3 Hours
2.8 Telephone Service and Response to Commission Complaints
rc{e
11+1
13{3
ya4
15+5
10{5
Le5
16{5
gL7
19ts
19rS
3 CUSTOMER GUARANTEES PROGRAM STATUS. ..,.........,.1919
4 APPENDIX:ReliabilityDefinitions ry)Q
Page2 ol 22
January - December 2019
EXECUTIVE SUMMARY
Rocky Mountain Power developed its Customer Service Standards and Service Quality Measures nearly 20 years
ago. The standards were developed as a way to demonstrate to customers that the Company is serious about
serving them well and willing to back its commitments with cash payments in cases where the Company falls short.
The standards also help remind employees about the importance of good customer service. The Company
developed these standards by benchmarking its performance against relevant industry reliability and customer
service standards. ln some cases, Rocky Mountain Power has expanded upon these standards. ln other cases
(largely where the industry has no established standard) Rocky Mountain Power developed its own metrics, targets
and reporting methods.
The Company distinguishes between non-controllable outages (e.g. lightning; vehicle collisions) and controllable
outages (e.g. animal interference; equipment failure) and takes cost-effective steps to minimize both. As part of
the Company's Performance Standards Program, it annually evaluates individual electrical circuits to focus on those
that have the most frequent interruptions. These are targeted for improvement, which is generally completed
within two years.
Rocky Mountain Power, for the period ending December 2019, was not only favorable to plan in network
performance metrics like average frequency and duration of customer outages, but also posted its best ever results
in each category.
However, ldaho customers did experience two major outage events in 2019. The number of ldaho customers
impacted by these events ranged trom2,2L5 to 17,319. While our restoration processes were effectively executed,
we had significant negative impacts to our customers, communities and other important stakeholders. We are
capable of doing much better.
Our goal continues to be supplying safe, reliable powerto ldaho. We are dedicated to learning from our past service
experiences and continuing to make improvements to our operations and customer service to ensure we meet
ldaho's needs.
Below is a summary of our 2019 performance serving the customers of ldaho.
Page3 ol 22
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ROCKY MOUNTAIN
HSHYE#.""
IDAHO
Service Quality Review
3ROCKY MOUNTAIN
POYT'ERlM8ffffircOat
IDAHO
Service Quality Review
January - December 2019
1 SERVICE STANDARDS PROGRAM SUMMARY'
1.1 ldaho Customer Guarantees
Note: See Rules for o complete description of terms ond conditions for the Customer Guorontee Progrom.
1 On June 29,2OI2, in Docket PAC-E-12-02 and Order 32583, the Commission ordered that Rocky Mountain Power had delivered upon commitments it
made in pursuant to the MidAmerican transaction in PAC-E-05-08 and Order 29998. The Commission also ordered the acceptance of modifications to the
Service Standards Program proposed by Rocky Mountain Power, as shown on Page 4 of 15.
Page 4 ol 22
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 6:
Resolving Meter Problems
The Company will investigate and respond to reported problems
with a meter or conduct a meter test and report results to the
customer within 10 working davs.
Customer Guarantee 7:
Notification of Planned lnterruptions
The Company will provide the customer with at least two days'
notice prior to turning off power for planned interruptions
consistent will Rule 25 and relevant exemptions.
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ROCKY
POIfVER
MOUNTAIN IDAHO
Service Quality Review
January - December 2019
L.2 ldaho Performance Standards
Note: Performonce Stondords 7, 2 & 4 ore for underlying performonce doys ond exclude those clossified as 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 Underlving 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 Under-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 10% 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 Reportins 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 6:
Commission Complaint Response / Resolution
The Company will a) respond to at least 95% of non-
disconnect Commission complaints within three working
days and will b) respond to at least 95% of disconnect
Commission complaints within four working hours, and will
c) resolve 95% of informal Commission complaints within
30 days.
Pagei ol 22
January - December 2019
2 RETIABITITY PERFORMANCE
ln 2019, Rocky Mountain Power achieved its planned reliability goals for the state of ldaho. ln fact, the Company
experienced its best ever underlying performance in interruption duration (SAlDl), interruption frequency (SAlFl),
and customer interruption duration (CAlDl). Almost every cause category contributed to the realized improvement,
including a 52% yearcver-year reduction in customer minutes lost related to loss of supply events. This
improvement highlights Rocky Mountain Powe/s commitment to provide safe and reliable power to its customers
in ldaho.
tn 2019, Rocky Mountain Power made significant improvements to the American Falls to Wheelon 138 kV
transmission line. Between 2OL7 and 2019, American Falls to Wheelon experienced an average of L2.7 trip and
recloses per year that were attributed to bird caused contaminated insulator flashovers. Every trip and reclose
resulted in a momentary outage for 2,855 customers served by Malad, Juniper, Snowville, and Holbrook
substations. Customers in the area were frustrated with the level of reliability the Company was providing due to
the frequent momentary interruptions they experienced. Further inspections of the line revealed items that could
be modified to prevent these contaminated insulator flashovers from occurring. The company installed bushing
covers on 105 structures in October 2019 to decrease future contaminated insulated flashovers. The bushing
covers have proven to be an effective solution at this time. A project to add breakers at Malad substation is in the
works that once installed will prevent customers from experiencing momentary outages due to trip and recloses
on the line.
The following sections illustrate the Company's reliability performance for the reporting period
Major Event General Descriptions
Two events during the reporting period met the Company's ldaho major event threshold levelz for exclusion from
underlying performance results.
April 3, 2019: Shetley, ldaho, experienced an outage when the 69 kV transmission line fed between
Sandcreek and Sugarmill Substations experienced an unknown trip event. The event should have caused a
circuit breaker momentary trip and reclose at the Sugarmill Substation, however the substation ground
relay element remained in the trip position blocking the reclosing on the circuit breaker, causing a
sustained outage event. The event affected three distribution substations, feeding a total of 11 circuits,
serving t7,3L9 customers, with outage durations ranging from t hours 4 minutes to 2 hours 27 minutes.
The loss of supply event affected approxim ately 64016 of the customers served within the Shelley operating
area.
a
2 A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value (Reliability Standard IEEE 1366-2012) based
on the 2.5 beta methodology. The values used for the reporting period are shown below:
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
llr-L2137120r9 82,079 15.09 7,238,872
Page 5 of 22
SAIDIDateCause
19.48Aoril 3,2019 Loss of Transmission
20.58Julv 1O 2019 Loss of Substation
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ROCKY
Po\TYER
MOUNTA!N IDAHO
Service Quality Review
Y ROCKY MOUNTAIN
POVVER IDAHO
Service Quality Review
a
January - December 2019
July 10, 2019: Montpelier, ldaho, experienced a loss of substation outage event when bushings failed on
the substation power transformer at the Montpelier Substation. The event affected three circuits fed from
the Montpelier Substation, serving 2,215 customers, with outage durations ranging from one hour 35
minutes to 21 hours 29 minutes.
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
means poorer reliability results. During the reporting period two significant event days were recorded, which
account for 10.5 SAIDI minutes; about 11.9% of the reporting period's underlying 89 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
reliability risks previously and continues on-going improvement plans.
Date Cause: General Dercriptlon Underlylng
SAIDI
Underlylng
SAIFI
% ofTotal
Under$ng
sArDr (891
l{ ofTotal
UnderlVlnt
sArFr(0.9s41
June 6,2019 Loss of Transmission Line (Wind storm
downed lines in Shelley, ldaho)6.8 0.012 8%t3%
August 8,
20L9 Pole Fire 3.8 0.015 4Yo t.6%
TOTAT 10.5 o.027 t2%2.8%
PageT ol22
x ROCKY
FTOU'ER
MOUNTAIN IDAHO
Seruice Quality Review
January - December 2019
2.L System Average lnterruption Duration lndex (SAlDll
The Company's underlying interruption duration performance for the year was favorable to plan.
ldaho 2019 SAID!
(excludes Prearranged and Customer Requested)
oo
=E
=ct
vt
180
L70
160
150
1tl()
130
120
110
100
90
80
70
60
50
40
30
20
10
0 Llt 2lt 3h 4h 5h 6h
.. . .. . Total lncluding Maior Events
-
Underlying Actual
717 &lL slr ,.0h tut tur
-,- Controllable Actual
-
Underlying Plan
Actua!
(reoortine oeriod)
Plan
(vear-end)
Total (major event included)L29
Underlying {major event excluded)89 L62
Controllable 20
Page 8 of 22
x ROCKY MOUNf,AIN
F,IWI'ER Wtrry6P
IDAHO
Service Quality Review
January - December 2019
2.2 System Average lnterruption Frequency lndex (SAlFl)
The Company's underlying interruption frequency performance results for the year are favorable to plan
ldaho 2019 SAIFI
(excludes Prearranged and Customer Requested)
1.6
1.5
1.4
1.3
1.2
1.1
6E 1.0
E o.e
tr o.8a o.7vt
o.5
o.5
o.4
0.3
o.2
0.1
0.0 tlr zlr 3lt 411 517 611 7lt
ooomr f6l3l lncluding Major Events
-
Underlying Actual
811 elt tolt tul tut
-- -'---. Controllable Actual
-
Underlying Plan
Actual
(reoortinc oeriod)
Plan
(vear-end)
Total (major event included)L.L97
Underlving (major event excluded)0.954 1.520
Controllable 0.L79
Page 9 of 22
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MOUNTAIN !DAHO
Service QualiU Review
January - December 2019
2.3 Reliability History
Depicted below is the reliability history in ldaho. The Company has been committed to improve performance,
both in underlying and in extreme weather conditions. These improvements include: 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. The graphs below illustrate how the
Company's commitment to improving reliability in ldaho has translated to system performance as measured by
SAlDl, SAlFl, and CAlDl.
ldaho Reliability History - lncluding Maior Events
ISAIDI rcAtol +sAlFt
4
3 2S
3.4
2.9
ROCKY
Pol'VER
r
Ea
ul 2 1.7
2009 2010 2077 20t2 2013 2014 2015 2016 20t7 2018 2019
600
500
400
300
200
100
aO,
.E
E
1
0 0
6cloN60Ft()q, <lH<l 66Ga to <t t\F@ 6(t(t rn:N
{i (l)(rlro (rr N.\f crr OrFI tYt @tt F.r|(OHN roN
3
0
ldaho Reliability History - Excluding Major Events
ISAIDI ICAIDI -{-SAIFI
2.1
1.5
1.0
2009 2010 2011 2012 20L3 2014 2015 2016 201,7 2018 2019
2.2
300
250
200
150
100
50
0
aco
rll
2
1
,a,EE
o<t() F.,
to lDd<t^.(OF{ (n(l o.lID F.rrr olrD6N(hrn C)dst<F'd(o(Yt (ndN@<C) \t
Page 10 of 22
January - December 2019
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.
As an example, animal-caused or equipment failure interruptions have a less random nature than lightning
caused interruptions; other causes have also been determined and are specified in Section 2.6. 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
outages3. lnordertoprovideinsightintotheresponseandhistoryforthoseoutages,thechartsbelowdistinguish
amongst the outage groupings.
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 365-Day Rolling Controllable History as Reported
stress period
-sAtDt
_sAtFl
-linear
(sAtDt]
3 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 ll ol 22
0.9
0.8
0.7
100
90
80
70
0.6
co
o.s ,i
tra
0,4
-60o
=.Egs0
6
o40
0.3
o.2
0.1
30
20
10
o
d "o" "S dit d "dl "d9 ".+ ".f ,.i" "S -,.i" "dgo go 9o go go go go go go go go go go
Y ROCKY MOUNTAIN
ng#-En"".
IDAHO
Service Quality Review
x ROCKYF(,u'ER
IrlCrLf$fAlN IDAHO
Servlce Qualtty Review
January - December 2019
ldaho il6$Day Rolllng Noncontrollable History as Reported
:m
ao
2tp
150
l(xl
3
2.5
2
aEt
E
6
6
r.s 5&
=4
fr
I
50 0.5
o 0
"tr -tr -tr /'" d / .f d r'f
"C
d -d -d
rs&.|rP.lltod
-sAtot -sJUFt -umtrF^tDlf
ldaho 365.Day Rolllng Underlylu Hlstory as kported
36
250
an
3
25
2
eot,,-
6a
1(I)
50
G
Etl
r.s &
e
I
o.5
0
lm-2009 Ln-m10 ,.n-20U ,16-2012 lrn-201i1 Jm-Z)tl ,$-2015 ,.n-2016 ,r-2017 .lm-2018 Jm-2019
rSrescprlod
-S/UU -gUF| -Uo..rFAtDl
o
PageL2ol22
Y IDAHO
Service Quality Review
January - December 2019
2.5 Cause Code Analysis
The tables below outline categories used in outage data collection. Subsequent charts and table use these
to deve for rmance.
ROCKY MOUNTAIN
HggEn"^,
Dlrect Cause
Caterorv Gtegory Mnition & Example/Direct Cause
Any problem nest that requires removal, relocation, trimming, etc.; any birds, squirrels or other animals,
whether or not remains found.
o Bird Neste Bird or Nest
o Bird Susoected. No Mortalitv
o Animal (Animals)
o Bird Mortality (Non-protected species). Bird Mortalitv {Protected soeciesl{BMTS)
Animals
Contamination or Airborne Deposit (i.e. salt, trona ash, other chemical dus! 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
r Condensation/Moisture. Contaminationr Fire/Smoke (not due to faults)
o Floodine
o Major Storm or Disaster
o Nearby Fault
o Pole Fire
Structural deterioration due to age (incl. pole rot); electrical load above limits; failure for no apparent
reason; conditions resulting in a pole/cross arm fire due to reduced insulation qualities; equipment affected
bv fault on nearbv equipment (e.9., broken conductor hits another line).
Equipment
Failure
. B/o Equipment
o Overload
. Deterioration or Rotting. Substation. Relavs
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
o Dig-in (Non-PacifiCorp Personnel)
o Other lnterfering Object
o Vandalism or Theft
o Other Utility/Contractor
o Vehicle Accident
Failure of supply from Generator or Transmission system; failure of distribution substation equipment.loss of
Supply o Failure on other line or station
e Loss of Feed from Supplier
o Loss of Generator
o LossofSubstation. Loss of Transmission Line. Svstem 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: faultv installation or construction; operational or safetv restriction.
Operational
. Contact by PacifiCorpr Faulty lnstallr lmproper Protective Coordination. lncorrect Records
o lnternal Contractor
o lnternal Tree Contractoro Switching Error. Testing/Startup Error
o Unsafe Situation
Cause Unknown; use comments field if there are some possible reasons.(Xher
o lnvalid Code
o 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
o Construction
o Customer Notice Given. Energy Emergency lnterruption
o lntentional to Clear Trouble
. Emergency Damage Repair
o Customer Requested
o Planned Notice Exempt
o Transmission Reouested
Growing or falling treesTree
o Tree-Non-preventableo Tree-Trimmable
r Tree-Tree felled by Logger
Wind (excluding windborne material); snow, sleet or blizzard, ice, freezing fog, frost, lightning.Weather
. Extreme Cold/Heat
e Freezing Fog & Frost
o Wind
. Lightningo Rain
o Snow. Sleet, lce and Blizzard
Page 13 ol 22
Y IDAHO
Service Quality Review
January - December 2019
2.5.L Underlying Cause Analysis Table
The table and charts below show the total customer minutes lost, customer interrupted, and the total sustained
interruptions by cause. The Underlying Cause Analysis Table includes prearranged outages (Customer Requested,
Customer Notice Given, and Planned Notice Exempt line items) with subtotals for their inclusion. The Excluding
Prearranged totals n with SAIDI and SAIFI metrics for the
Dlrect Ceu3c SAIFI
ANIMALS
BIRD MORTALITY
BIRD MORTALITY
BIRD NEST
BIRD NO MORTALITY
ANIMAIS
CONTAMINATION
ENVTRONMENT
B/O EQUIPMENT
SWITCHES
70,u8
OTHER
INIERFERENCE 7,617
TOSS OF FEED FROM SUPPLIER 195
2,954 :
IOSS OF TRANSMISSION LINE ?t,?66
2L,StSross oF suPPtY 719,206
FAULTY INSTALL 0.00 0.000
IMPROPER PROTECTIVE COORDINATION
ROCKY MOUNTAIN
POIIVER
Lq
2_!-
!
48
91
11
_8
88
rrii
7146
KNOWN CAUSE
UNKNOWN
CONSTRUCTION
INTENTIONAL TO CLEAR TROUBLE
MAINTENANCE
PI-ANNED NOTICE EXEMPT
TRANSMISSION
TREE - NON.PREVENTABLE
. _. 2,694
2,8t[0OPERANOilAL
OTHER
PI.ANNED
0.03 0.001
0.o3 0.001
1.59 0.018130,788
. __ __587,829_
718,617
8,509
9.'g!q ]
77
t7
?,2??
1,585
1.7
136
?,\{
2,987
2,678
1,459
?,7-3!1!379lry
52,727
38,891
2,838
?s8;71
t27,963
426,698
0.47 ,.
0.03- l!.srl3.64 .
1.55
0.104
3jj2s.62'
tol?7_1
?q
10.2q5
1!1
1.,77
9q3
1
4?2
44!
306 7.t6
339 8.76
9
ry7l
q9
_11
2
4
2
0.121
0.03 0.001
t6.70 0.125
0.64 0.002
4.47 0.053
7.26 0.011
0.00 0.qry
0.005
o.005
o.2t2
o.027
0.019
TREES
iii J
7S
72
87
TREE. TRIMMABLE
FREEZING FOG & FROST
lcE
!.!qI
o.03 .0.20 :
0.046
o.:000
0.002
9 _9?7
0.036
3.77 0.032
TIGHTNING
?,9r1 .19,6!:e
19qql .o,nl
309,344
2
5
116
82
_19?
307
SNOW, SLEET AND BLIZZARD
WIND
Custonrer
Minutes loet for
lnddent
Customer ln
lnddent
Sustain€d
Sustalned
lnddent
Count
SAIDI
0.96
0.95
0.46
o.o7
o.67
o.o72
0.019
o.004
0.001
0.009
3.12 0.0{4
FIRE/SMOKE (NOT DUE TO FAUTTS)
0.01
0.oo
0.01
0.000
0.000
0.000
DETERIORATION OR ROTTING
NEARBY FAULT
OVERLOAD
POLE FIRE
coNoucroR
96s
+.1?,
?99
_ry
764
I
497 5
759,611
683
0
!-,999
L!1
tw
t3
1?
52
L49
327
8
4
4
!?6
80
635
q0l
1
4
1?_
7_
6
I
79,tog
78,328
3l_,6s1j1!l
55,066
996,101
92
1E91 -7,943 |
EqUIPMENT FAILURE 2,026,975 820
0.019
0.093
0.oo 0.000
0.01 0.000
9.2s 0.061
0.000
o.tl?
3.29
72.14
0.01
2t,70
DrG-lN (NON-PAC| FTCORP PERSONNET)
OTHER I t{TERFERING OBJECT
TOSS OF SUBSTATION
VEHICLE ACCIDENT
0.013
0.002
0.001
0.29!'
q-8e
!;3
0.12
8.56
9.77
Q,?1
4.78
16.30
21.31
0.078
0.002
0.093
0.036
0.260
CUSTOMER NOTICE GIVEN
CUSTOMER REQUESTED
EMERGENCY DAMAGE REPAIR
o.Gr7
8.776.474 89.164 2,40L 106.93 1.086
7,3t4,380 89.11 0.954ldaho Excluding
WEAI}IER
78,326
10.42
Page L4 of 22
x R(XKY MOUNTAIN
HSIYES*
!DAHO
Service Qualfi Review
, January - December 2019
2.5.2 Cause Category Analysis Charts
The charts show each cause catetory'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.
Crucr Amlyrls - Curtomar Mlnutcr l.cr [SAlDll
I I}{IERFEE'rcE1tSI WEAI}ER
r or{mmr
T EQUPI$E}IT
FNLLNE 28'6
r Puilr@tr
r rn€Es6t5
I AtffliAlsSSI OPERAIIOIIATOi
C $nfl8dtftEfiToX
r LNOF$rP?tY24ga
Crusr An lylb - Custorn:r lntcrruptlonc (SrUfll
r wEATtffil{tr
r SIHER r IHIENFENETCE 1I}'6
I ?ITII{EDI,*
I UXiliOFS| PPLYrl9r
r rRE3Str
r E{\Ilfio0{MErfr0r6
r Eqr,P$Err
FA,|,URE 18It
r AlilMAUi5r
@cRATtO{rtAt0r
Crusc Anelysis - Surtrincd lnddrntr
I EqIM,EI'IT FAIU.NE 377
r otHEnlSra
a AtrtMAts1916I ]I'IIERFERETrcE
I TRCSS'96
I II'IEfiFERS{CE
I PLAill{tr) 50i
r losioFsr.rPPtY
r Of,urA-nONa/qL
r EI!,V!ROXMEIIT(}96
Page75o122
V-ROCKY MOUNTAINYpowen\^orco*nmw
IDAHO
Service Quality Review
January - December 2019
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 2015 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 shifted the Company's reliability program from a circuit or area-based view reliant on blended
reliability metrics (using circuit SAlDl, SAIFI and MAIFI) to a more strategic and targeted approach based upon
recent trends in performance of the local area, as measured by customer minutes interrupted (from which SAIDI
is derived). The decision to fund one performance improvement project versus another is based on cost
effectiveness as measured by the cost per avoided annual customer minute interrupted. However, the cost
effectiveness measure will not limit funding of improvement projects in areas of low customer density where
cost effectiveness per customer may not be as high as projects in more densely populated areas.
2.6.1 Reliability Work Plans
The Company has worked to improve reliability through Reliability Work Plans. To assist in identification of
problem areas, Area lmprovement Teams (AlT) meetings and Frequent lnterrupters Requiring Evaluation (FIRE)
reports have been established. On a daily basis the Company systems alert operations and engineering team
members regarding outages experienced at interrupting devices (circuit breakers, line reclosers and fuses).
When repetition occurs, it is an indicator that system improvements may be needed. On a routine basis, local
operations and engineering team members review the performance of the network using geospatial and tabular
tools to look for opportunities to improve reliability. As system improvement projects are identified, cost
estimates of reliability improvement and costs to deliver that improvement are prepared. lf the project's cost
effectiveness metrics are favorable, i.e. low cost and/or high avoidance of future customer minutes interrupted,
the project is approved for funding and the forecast customer minutes interrupted are recorded for subsequent
comparison. This process allows individual distrlcts 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 yea/s plans, and actual versus forecast
results are assessed to determine whether targets were met or if additional work may be required, as would be
depicted in the table below.
Page 16 of 22
Effectfueness Metrics ln Progress
Esdmated
Avoided
annual
cMt
Actual
Avolded
annual
cMr
Budgeted
Cost per
annual
avoided
CML
Actual
Cost per
annual
avolded
cMr
Plans Not
Meetint
Goals (not
induded in
metricsl
Plans
waltlngfor
lnformaUo
n
Plans
Meetint
Goals (>1
year slnce
proiect
completlonl
Mon$elhr s2.77 L 18,150 54,999 5s.ra So.oo 0 23
Preston 3 s1.03 2 27,555 63,693 s1.40 S5.zs 0 1
Rexburg 5 Ss.so 1 7,893 13,155 s6.s5 s4.3e 1 3
Shelley 9 St.qt 6 t78,742 564,26L so.e8 So.oo 0 3
6%,1o7 $r.ss $r.re 1 9Tot l 20 $l.ee 10 xngn
January - December 2019
*Metrics cover RWP's approved between tlLl20l7 and t2/3t/20L9.
2.6.3 Reduce CPI for Worst Performing Circuits or Sub-circuits
ln 2OL2 the Company modified its previous program with regards to selecting areas for improvement. Delivery
of tools allowed more targeted improvement areas. As a result, the Service Standard Program was modified to
reflect this change. Prior to 2012, the Company selected circuits as its most granular improvement focus; since
then, groupings of service transformers are selected, however, if warranted entire distribution or transmission
circuits could be selected. Since 2012, the Company has transitioned and further refined its approach to support
cost/benefit valuation for reliability improvements, which are a cornerstone of ORR, as discussed above.
Circuit Performance lmprovement (prior to 12131/20111
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. fu 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 wilhin two years of selection. Within five years of selection,
the average performance of the selection set must improve by at least2Oo/o against baseline performance. Those
program years which have met their target scores are removed from the listing below.
Reliabilitv Performance lmorovement (oost 1213U20U throueh 12131/20161
On a routine basis, the Company reviews areas for performance. Utilizing a measure called reliability
performance indicator (RPl), which is a blended weighting of underlying reliability metrics covering a three-year
period, calculated at the service transformer, excluding loss of supply outages. The higher the number, the
poorer the blended performance the area has received. As part of the Company's Performance Standards
Program, it annually selects Underperforming Areas for targeted improvement. The improvement projects are
generally completed within two years of selection. Within five years of selection, the average performance of
the selection set must improve by at least 10% against baseline performance. Those program years which have
met their target scores are removed from the listing below.
PageLT of22
xffiHlvrouNrArN IDAHO
Service QualiW Review
\
ROCKY MOUNTAIN
F,Iol,YER IDAHO
Service Quality Review
(lmprovement targets for circuits in Program Years 1-11 and 13-15 have been met and filed in prior reports.)
January - December 2019
PROGRAM YEAR 17 (RPl) Method
Clifton 11 (Figure 3C)IN PROGRESS 225 78
Dubois 12 (Figure 4C)COMPLETE 195 L20
TARGETSCORE = 189 Goal Met 2to 98
Page 18 of 22
xROCKY MOUNTAIN
FTol'VER
IDAHO
Service Qualfi Review
2.7 Restore Seruice to 80% of Customers within 3 Hours
2.8 Telephone Service and Response to Commission Complaints
3 CUSTOMER GUARANTEES PROGRAM STATUS
custometguarantees
January - December 2019
January b Dec€mber 2019
January February March April May June
97%96%85%99%96%98%
DecemberJulyAugustSeptemberOctoberNovember
89%82%95%94%95%94%
85%PS5-Answer calls within 30 seconds 8gY"
PS6a) Respond to commission complaints within 3 days 95%too,%
t@%PSSb) Respond to commission complaints regarding service disconnects
within 4 hours 95%
9s%tO0YoPSSc) Resolve commission complaints within 30 days
cGl
cG2
cG3cel
cG5
cG6
cG7
Evrtt
,01c
F.allr.. ta slrc.r.Pdd Ett{nt
201t
F{ur. f SrE r P.ld
Restomo Supply
Appoilmeftb
Swftcnhgdl Porer
EstmaEs
Respond lo BmrE lngwies
Respom to Mcter Hoolems
Noffication d Plilmed lnterrudoos
78.694
1,18:I
361
CE
68
r3r
10265
0
0
0
t
0
0
0
r00.00*
tm.una
lm.m%
99_76%
rm.o65
r00.m*
im.m.r
t0
30
30
350
30
$l
t0
90.0a5
8S2
3!r3
286
ilf3
ttls
12.188
.lm-flDr
99.8914
1oo-txlta
99.65*
1m-00t5
1m-firr
99.98!t
EO
350
t0
t5{l
t0
s0
tlm
9r,687 r 00.90% 360 tt2-302 a 00.9e% 3200
ldaho
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 protram.
Pagel9 of22
\
IDAHO
Service Quality Review
January - December 2019
4 APPENDIX: Reliability Definitions
This section will define the various terms used when referring to interruption types, performance metrics and
the internal measures developed to meet its performance plans.
lnterruption Tvpes
Below are the definitions for interruption events. For further details, refer to IEEE 1355-2003120L24 Standard for
Reliability lndices.
Sustoined Outoge
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 L366-2003/2012. 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 othenrise, 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 specifo this metric under the umbrella of the Performance Standards
1 IEEE 1366-2003/2012 was first adopted by the IEEE Commissioners on December 23,2m3. The definitions and methodology detailed therein are now
industry standards, which have since been affirmed in recent balloting activities.
Page2O ol 22
ROCKY MOUNTAIN
PotA'ER
\
IDAHO
Service Quality Review
January - December 2019
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).
MAlFle
MAlFle (momentary average interruption event frequency index) is an industry standard index that quantifies
the frequency of all momentary interruption events that the average customer experiences during a given time-
frame. lt is calculated by counting all momentary interruptions which occur within a 5 minute time period, as
long as the interruption event did not result in a device experiencing a sustained interruption.
CEMI
CEMI is an acronym for Customers Experiencing Multiple (Sustained and Momentary) lnterruptions. This index
depicts repetition of outages across the period being reported and can be an indicator of recent portions of the
system that have experienced reliability challenges. This metric is used to evaluate customer-specific reliability.
ORR
ORR is an acronym for Open Reliability Reporting, which shifts the Company's reliability program from a circuit
based metric (RPllto a targeted approach reviewing performance in a localarea, measured by customer minutes
lost. Project funding is based on cost effectiveness as measured by the cost per avoided annual customer minute
interrupted.
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'i 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*2.4391+(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 CPt05 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.
ROCKY MOUNTAIN
HSYE#*,
Page 2L ol 22
\
IDAHO
Service Quality Review
January - December 2019
Performance Tvpes & Commitments
Rocky Mountain Power recognizes several categories of performance; major events and underlying performance.
Underlying performance days may be significant event days. Outages recorded during any day may be classified
as "controllable" events.
Major Events
A Major Event (ME) is defined as a 24-hour period where SAIDI exceeds a statistically derived threshold value
(Reliability Standard IEEE 1366-2012) based on the 2.5 beta methodology. The values used for the reporting
period and the prospective period are shown below.
Effective Date Customer Count ME Threshold SAIDI ME Customer Minutes Lost
Llt-12l3tl29t9 82,079 15.09 1,238,872
Signiftcont 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 ol t.75 beta (or 1.75 times the natural log standard deviation beyond the natural Iog
daily average for the day's SAIDI) that generally these days' events are generally associated with weather events
and serve as an indicator of a day which accrues substantial reliability metrics, adding to the cumulative reliability
results for the period. As a result, the Company individually identifies these days so that year-on-year
comparisons are informed by the quantity and their combined impact to the reporting period results.
Underlying Events
Within the industry, there has been a great need to develop methodologies to evaluate year-on-year
performance. This has led to the development of methods for segregating outlier days, via the approaches
described above. Those days which fall below the statistically derived threshold represent "underlying"
performance, and are valid. lf any changes have occurred in outage reporting processes, those impacts need to
be considered when making comparisons. Underlying events include all sustained interruptions, whether of a
controllable or non-controllable cause, exclusive of major events, prearranged (which can include short notice
emergency prearranged outages), customer requested interruptions and forced outages mandated by public
authority typically regarding safety in an emergency situation.
controllable Distribution (cD) Events
ln 2(X)8, 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 MOUNTAINPWi/ER
Page 22 ol 22