20090416Service Standards Report 2008.pdf

~~l~OUNTAIN R. .E- (" t: pii',.. -..,.J '-' t 'J'
2089 APR I 6 At; 9: I 7 201 South Main, Suite 2300
Salt Lake City, Utah 84111
April 15, 2009 IDAHU
UTIUT¡i:~)
nA OVERNIGHT DELIVERY
Ms. Jean D. Jewell
Commssion Secreta
Idaho Public Utilties Commission
472 W. Washington
Boise,ID 83702
P/t-E -o~-O~
Re: Rocky Mountain Power Service Quality Report for the period
Janua 1 though December 31, 2008.
Dear Ms. Jewell:
On March 23,2009, representatives of Rocky Mountain Power, a division ofPacifiCorp, 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 ths report please contat me at (801)
220-2963.
Sincerely,
1d-Wub /11
Ted Weston
Manager, Idaho Regulatory Afairs
Enclosures
cc: David Schune
Terr Carlock
Beverly Barker
Heide Caswell
.. ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
IDAHO
SERVICE QUALITY
REVIEW
.
January 1 - December 31,2008
Report
~~oo~OUTAIN
IDAHO
Service Quality Review
January - December 2008
TABLE OF CONTENTS
EXECUTIVE SUMMARy.............................................................................................................3
1 SERVICE STANDARDS PROGRAM SUMMARy.................................................................3
1.1 Idaho Customer Guarantees............................................................................................ 3
1.2 Idaho Performance Standards.......................................................................................... 4
1.3 Reliabilty Definitions........................................................................................................ 5
2 POST MERGER PERFORMANCE STANDARDS................................................................ 7
2.1 System Average Interruption Duration Index (SAlOl) ....................................................... 8
2.2 System Average Interruption Frequency Index (SAIFI) .................................................... 9
2.3 Momentary Average Interruption Frequency Index events (MAl Fie) ............................... 10
2.4 Cause Code Analysis ..................................................................................................... 14
2.5 Reduce CPI for Worst Performing Circuits by 20% ........................................................ 18
2.6 Restore Service to 80% of Customers within 3 Hours (across 3 years) ......... ................ 18
2.7 Telephone Service and Response to Commission Complaints ...................................... 19
3 'CUSTOMER GUARANTEES.............................................................................................. 19
3.1 Idaho State Customer Guarantees Summary Status...................................................... 19
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Service Quality Review
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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
industry standards (to the extent they exist) for collecting and reporting performance data. In some
cases, Rocky Mountain Power has decided to exceed these industry standards. In other cases, largely
where the industry has no established standards, Rocky Mountain Power has developed metrics, targets
and reporting. 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
Effective April 1 , 2008 through December 31, 2011.
1.1 Idaho Customer Guarantees
Customer Guarantee 1:The Company wil restore supply after an
Restoring Supply After an Outage outage within 24 hours of notification with
certain exceptions as described in Rule 25.
Customer Guarantee 2:The Company wil keep mutually agreed upon
Appointments appointments, which wil be scheduled within a
two-hour time window.
Customer Guarantee 3:The Company wil switch on power within 24
Switching on Power 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 theftdiversion of
service are excluded.
Customer Guarantee 4:The Company wil provide an estimate for new
Estimates For New Supply 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:The Company wil respond to most biling
Respond To Biling Inquiries inquiries at the time of the initial contact. For
those that require further investigation, the
Company wil investigate and respond to the
Customer within 10 workina days.
Customer Guarantee 6:The Company wil investigate and respond to
Resolving Meter Problems reported problems with a meter or conduct a
meter test and report results to the customer
within 10 workina days.
Customer Guarantee 7:The Company wil provide the customer with at
Notification of Planned Interruptions least two days notice prior to turning off power
for planned interruotions.
Note: See Rules for a complete description of terms and conditions for the Customer Guarantee Program.
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Service Quality Review
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1.2 Idaho Performance Standards
Network Performance Standard 1:The Company wil achieve SAIDI of 30.5
Improve Controllable Distribution System minutes or less by December 31, 2011.
Averaoe Interruotion Duration Index (SAID!)
Network Performance Standard 2:The Company wil achieve SAIFI of 0.297 or
Improve Controllable Distribution System less by December 31, 2011.
Average Interruption Frequency Index (SAIF!)
Network Performance Standard 3:The Company wil reduce by 20% the average
Improve Under Performing Circuits circuit performance indicator (CPI) for a
maximum of two under performing circuits on
an annual basis within five years after
selection.
Network Performance Standard 4:The Company wil restore power outages due
Supply Restoration to loss of supply or damage to the distribution
system on average to 80% of customers within
three hours.
Customer Service Performance Standard 5:The Company wil answer 80% of telephone
Telephone Service Level calls within 30 seconds. The Company wil
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:The Company wil: a) respond to at least 95%
Commission Complaint Response/Resolution of non-disconnect Commission complaints
within three working days, b) respond to at
least 95% of disconnect Commission
complaints within four working hours, and c)
resolve 95% of informal Commission
comolaints within 30 days.
Note:
. Performance Standards 1, 2 & 4 are for underlying performance days and exclude those classifed as
Major Events.
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~ROCKY MOUNTAINPOERA OM$N OF PAFlCQP'Service Quality Review
January - December 2008IDAHO
1.3 Reliabilty Definitions
This section wil define the various terms used when referring to interruption types, performance
metrics and the internal measures developed to meet its performance plans.
Interruption Types
Below are the definitions for interruption events. For further details, refer to IEEE P1366-20031
Standard for Reliabilty Indices.
Sustained Outage
A sustained outage is defined as an outage of equal to or greater than 5 minutes in duration.
Momentary Outage
A momentary outage is defined as an outage of less than 5 minutes in duration. Rocky Mountain
Power has historically captured this data using substation breaker fault counts.
Reliabilty Indices
SAlOl
System Average Interruption Duration Index (SAIDI) is an industry-defined term to define the average
duration summed for all sustained outages a customer experiences in a given period. It 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 SAlOl
In 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 was introduced in IEEE Standard P1366-2003. This is the
day's total customer minutes out of service divided by the static customer count for the year. It 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
System Average Interruption Frequency Index (SAIFI) is an industry-defined term that attempts to
identify the frequency of all sustained outages that the average customer experiences during a given
period. It 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.
CEMI
Customers Experiencing Multiple (Sustained and Momentary) Interruptions (CEMI) identifies
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
CPI99
CPI99 is a Circuit Performance Indicator, which uses key reliabilty metrics (such as SAIDI and SAIFI)
to identify underperforming circuits. CPI99 excludes Major Event and Loss of Supply or Transmission
outages.
1 P1366-2003 was adopted by the IEEE Commissioners on December 23,2003. The definitions and methodology
detailed therein are now industry standards.
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January - December 2008IDAHO
CPI05
CPI05 is similar to CPI99 except CPI05 includes Major Event and Loss of Supply or Transmission
outages in its results.
Performance Types & 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 IEEE P1366-2003.
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 (with some minor considerations for changes in
reporting practices) for establishing and evaluating meaningful performance trends over time.
Underlying Performance is comprised of both controllable and non-controllable distribution
interruptions.
Controllable Distribution vs. Non-Controllable Distribution
In 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. 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. (The Cause Code Analysis section 2.3 of
this report shows separate tables for Controllable Distribution and Non-Controllable Distribution,
which list the individual direct causes within each classification, as well as the Company's
performance by direct cause for the reporting period.)
Post- Transaction Commitment Target
Because of the benefits that the Company and its customers and regulators experienced from the
Service Standards Program, the Company filed and received approval to continue the program
through December 31, 2011. From a reliability perspective, the Company continues to develop goals
that wil deliver important improvements to its customers.
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"~ROCKY MOUNTAINPORADIVISINOIPAFIP Service Quality Review
January - December 2008IDAHO
2 POST MERGER PERFORMANCE STANDARDS
During the reporting period, the Company experienced mixed reliability results, with interruption
duration (SAIDI) over plan and interruption frequency (SAIFI) under plan. Performance results can be
seen in subsections 2.1 and 2.2 below.
During the period, six significant event days2 were recorded. In total, they account for about 55
minutes of the year's underlying performance, of which approximately 6 minutes were controllable.
The March 2 event at 17.2 SAIDI minutes nearly qualified for major event exclusion; the filing
threshold was only missed by about a minute and a half.
A snowstorm on December 13, met the Company's Idaho major event threshold leveP for filing during
the period, excluding 20.8 SAIDI minutes from total performance.
As filed in the Service Standards Program, improvements are targeted for Controllable Distribution
causes. At the same time, the Company has observed that in the area Non-Controllable Causes,
substantial impacts to state reliability can be seen in both the Interference and Loss of Supply cause
categories. The Company is analyzing this data to determine whether there are any cost-effective
improvements that can be made to influence this performance.
SAIDI
Controllable Distribution
DATE Primary Cause Total: 47
Minutes % of Total Minutes % of Total
January 22, 2008 Distribution Wire Down 5.4 3%5.4 11%
January 28, 2008 Winter Storm (Wind, Snow)7.2 4%0.2 0%
March 2, 2008 Loss of Supply 17.2 9%0 0%
May 20, 2008 Windstorm 5.8 3%0.3 1%
August 31, 2008 Windstorm 11.6 6%0.5 1%
December 3, 2008 Interfrence (Vehicle)8.0 4%0 0%
TOTAL 55.2 29%6.4 14%
2 On a trial basis, the Company established a variable of 1.75 times the stadard deviation of its natual log SAIDI results.
3 In 2005, the Company àdopted via its Service Standard Program fiing, the use of IEEE P1366-2003, wherein a
statistically-based theshold 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 SAII
events were embedded in these metrcs. The chars included do not reflect the exclusion of these minutes.
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"~ROCKY MOUNTAINPOERA DMSIO OF l'ClFlRP Service Quality Review
January - December 2008IDAHO
2.1 System Average Interruption Duration Index (SAlOl)
As noted previously, the Company experienced outage duration reliabilty over operating plan for the
reporting period. Despite exceeding operating plan SAIDI for the period, Idaho reliability has stil
improved over prior period performance. This seems to indicate that while some of the improvements
undertaken over the last two years have driven reliability higher there are stil underlying opportunities
for further improvement.
Underlying
Controllable Distribution
SAIDI Actual
193
47
SAIDI Plan
42
200
160
ø
J!120::c:~
Cl 80~(J
40
IDAHO SAlOl Comparison to Plan
(excludes Prearranged and Customer Requested)
0
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"'~ROCKY MOUNTAINPOER. """'N""''''' Service Quality ReviewIDAHO January - December 2008
2.2 System Average Interruption Frequency Index (SAIFI)
During the reporting period, the Company experienced underlying outage frequency reliabilty better
than operating plan and the prior year performance. Controllable outage frequency reliabilty was
slightly off plan.
Underlying
Controllable Distribution
SAIFI Actual
1.78
0.48
SAIFI Plan
0.41
2.0
IDAHO SAIFI Comparison to Plan
(excludes Prearranged and Custorrr Requested)
1.8
1.5
íñ
ë 1.3
~
!: 1.0
u:
:: 0.8
en
0.5
0.3
0.0
00g
~
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~~~~~~~~~~~~N M ;;iì tõ ;:õõ 0;0 N~
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"'~ROCKY MOUNTAINPORA DMlO OF I'FICP Service Quality Review
January - December 2008IDAHO
2.3 Momentary Average Interruption Frequency Index events (MAIFle)
MAl Fie reporting for the Company's Idaho performance consists of two data sets: one for SCADA-
controlled breaker operations recorded into a database and one for non-SCADA-controlled breaker
operations that are manually entered into another database. Based on SCADA operations data only,
MAIFle is calculated at an operating area level (Table A below). Based on non-SCADA operations
data, a table is compiled listing the total number of operations on each circuit for the reporting period
(Table B below.) Any circuit breaker that has an unusually high number of trip operations is
highlighted below for follow-up by local engineering staff to determine whether particular maintenance
actions should be undertaken.
January 1 - December 31, 2008
Operating Area SCADA MAIFle
MONTPELIER o
PRESTON 5.08
REXBURG 2.89
SHELLEY 2.17
January 1 through December 31, 2008
Operating Area Circuit Circuit Name OperationsID
MONTPELIER ALX11 ALEXANDER #11 0
MONTPELIER ARM11 ARIMO #11 13
MONTPELIER ARM12 ARIMO #12 7
MONTPELIER BAN11 BANCROFT #11 7
MONTPELIER BAN12 BANCROFT #12 1
MONTPELIER CHS11 CHESTERFIELD #11 25
MONTPELIER CHS12 CHESTERFIELD #12 HATCH 27
MONTPELIER COV12 COVE #12 0
MONTPELIER EGT11 EIGHT MILE #11 0
MONTPELIER GRG11 GEORGETOWN #11 6
MONTPELIER GCE11 GRACE #11 0
MONTPELIER GCE12 GRACE #12 4
MONTPELIER HRY11 HENRY#11 0
MONTPELIER HRS11 HORSLEY#11 10
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MONTPELIER IND11 INDIAN CREEK #11 5
MONTPELIER LVA11 LAVA #11 10
MONTPELIER LND11 LUND #11 10
MONTPELIER MCC11 MCCAMMON #11 8
MONTPELIER MCC12 MCCAMMON #12 0
MONTPELIER MNT11 MONTPELIER #11 0
MONTPELIER MNT13 MONTPELI ER #13 3
MONTPELIER MNT14 MONTPELIER #14 13
MONTPELIER RAY11 RAYMOND #11 7
MONTPELIER RAY12 RAYMOND #12 10
MONTPELIER STC11 ST CHARLES #11 0
PRESTON CLF11 CLIFTON #11 DAYTON & BANIDA 25
PRESTON CLF12 CLIFTON #12 32
PRESTON DWN11 DOWNEY #11 14
PRESTON DWN12 DOWNEY #12 11
PRESTON HLB11 HOLBROOK #11 4
PRESTON MLD11 MALAD #11 6
PRESTON MLD12 MALAD #12 9
PRESTON MLD13 MALAD #13 9
PRESTON PRS11 PRESTON #11 5
PRESTON PRS12 PRESTON #12 0
PRESTON PRS13 PRESTON #13 2
PRESTON TNR11 TANNER #11 MINK CREEK 12
PRESTON TNR12 TANNER #12 RIVERDALEITREASURETON 1
PRESTON WST11 WESTON#11 SOUTH - WESTON/FAIRVEW 15
PRESTON WST12 WESTON #12 NORTH TO DAYTON 13
REXBURG AND11 ANDERSON #11 WEST 6
REXBURG AND12 ANDERSON #12 EAST AND NORTH 15
REXBURG AND13 ANDERSON #13 NORTH 7
REXBURG ARC11 ARCO#11 0
REXBURG ARC12 ARCO#12 0
REXBURG ARC13 ARCO#13 0
REXBURG ASH11 ASHTON #11 26
REXBURG BLS11 BELSON #11 37
REXBURG BLS12 BELSON #12 6
REXBURG BRN21 BERENICE #21 3
REXBURG BRN22 BERENICE #22 5
REXBURG CMS11 CAMAS #11 27
REXBURG CMS12 CAMAS #12 12
REXBURG CNY21 CANYON CREEK #21 6
REXBURG CNY22 CANYON CREEK # 22 25
REXBURG DBS11 DUBOIS#11 24
REXBURG DBS12 DUBOIS #12 2
REXBURG EST11 EASTMONT #11 9
REXBURG EST12 EASTMONT #12 7
REXBURG EGN11 EGIN #11 10
REXBURG EGN12 EGIN #12 6
REXBURG HMR11 HAMER #11 71
REXBURG HMR12 HAMER #12 101
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January - December 2008
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REXBURG MNN11 MENAN #11 58
REXBURG MNN12 MENAN #12 33
REXBURG MNN13 MENAN #13 31
REXBURG MLL11 MILLER #11 10
REXBURG MLL12 MILLER #12 1
REXBURG MDY11 MOODY #11 10
REXBURG MDY12 MOODY #12 2
REXBURG MDY13 MOODY #13 4
REXBURG MDL11 MUDLAKE#11 65
REXBURG MDL12 MUDLAKE#12 20
REXBURG NWD11 NEWDALE #11 3
REXBURG NWD12 NEWDALE #12 0
REXBURG NWD13 NEWDALE #13 5
REXBURG REN11 RENO#11 19
REXBURG REN12 RENO#12 4
REXBURG REN13 RENO #13 7
REXBURG RXB11 REXBURG #11 4
REXBURG RXB12 REXBURG #12 2
REXBURG RXB13 REXBURG #13 1
REXBURG RXB14 REXBURG #14 2
REXBURG RXB15 REXBURG #15 5
REXBURG RXB16 REXBURG #16 0
REXBURG RGB11 RIGBY#11 0
REXBURG RGB12 RIGBY#12 5
REXBURG RGB13 RIGBY#13 7
REXBURG RGB14 RIGBY #14 14
REXBURG RIR12 RIRIE #12 4
REXBURG RBR11 ROBERTS #11 34
REXBURG RBR12 ROBERTS #12 32
REXBURG RBY11 RUBY#11 17
REXBURG STA11 ST ANTHONY #11 27
REXBURG STA12 ST ANTHONY #12 7
REXBURG STA13 ST ANTHONY #13 14
REXBURG SDN21 SANDUNE#21 9
REXBURG SDN22 SANDUNE#22 1
REXBURG SMT11 SMITH #11 12
REXBURG SMT12 SMITH #12 22
REXBURG SMT13 SMITH #13 0
REXBURG SMT14 SMITH #14 0
REXBURG SFK11 SOUTH FORK#11 IDAHO PACIFIC POTATO 0
REXBURG SFK13 SOUTH FORK #13 ANTELOPE FLATS 2
REXBURG SGR11 SUGAR CITY #11 0
REXBURG SGR12 SUGAR CITY #12 2
REXBURG SGR13 SUGAR CITY #13 6
REXBURG SGR14 SUGAR CITY #14 5
REXBURG SNN11 SUNNYDELL #11 6
REXBURG SNN12 SUNNYDELL #12 4
REXBURG TRG11 TARGHEE#11 18
REXBURG TRG12 TARGHEE#12 9
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January - December 2008
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REXBURG THR11 THORNTON #11 0
REXBURG THR12 THORNTON #12 18
REXBURG WTK11 WATKINS #11 NORTH AND EAST 7
REXBURG WBS11 WEBSTER #11 EAST AND SOUTH 48
REXBURG WBS12 weBSTER #12 NORTH .1'78
REXBURG WBS14 WEBSTER #14 27
REXBURG WNS21 WINSPER#21 6
REXBURG WNS22 WINSPER#22 39
SHELLEY AMM11 AMMON #11 2
SHELLEY AMM12 AMMON #12 2
SHELLEY CLE11 CLEMENT#11 1
SHELLEY CLE12 CLEMENT #12 12
SHELLEY GSH11 GOSHEN #11 3
SHELLEY GSH12 GOSHEN #12 2
SHELLEY GSH13 GOSHEN #13 20
SHELLEY HYS11 HAYES #11 63
SHELLEY HYS12 HAYES #12 49
SHELLEY HYS13 HAYES #13 40
SHELLEY HPS11 HOOPES #11 WEST 3
SHELLEY HPS12 HOOPES #12 NORTH 1
SHELLEY IDF11 IDAHO FALLS #11 1
SHELLEY IDF12 IDAHO FALLS #12 7
SHELLEY IDF13 IDAHO FALLS #13 2
SHELLEY IDF14 IDAHO FALLS #14 3
SHELLEY JFF21 JEFFCO #21 17
SHELLEY JFF22 JEFFCO #22 6
SHELLEY KT21 KETTLE #21 13
SHELLEY KTT22 KETTLE #22 1
SHELLEY MRR11 MERRILL #11 91.
SHELLEY MRR12 MERRILL #12 9
SHELLEY MRR13 MERRILL #13 2
SHELLEY MRR14 MERRILL #14 7
SHELLEY OSG11 OSGOOD #11 1
SHELLEY OSG12 OSGOOD #12 0
SHELLEY OSG13 OSGOOD #13 0
SHELLEY OSG14 OSGOOD #14 8
SHELLEY SND11 SANDCREEK #11 0
SHELLEY SND12 SANDCREEK #12 2
SHELLEY SND13 SANDCREEK#13 7
SHELLEY SND14 SANDCREEK #14 6
SHELLEY SND15 SANDCREEK #15 3
SHELLEY SND16 SANDCREEK#16 5
SHELLEY SHL11 SHELLEY #11 36
SHELLEY SHL12 SHELLEY #12 16
SHELLEY SHL13 SHELLEY #13 7
SHELLEY SHL14 SHELLEY #14 8
SHELLEY UCN11 UCON #11 0
SHELLEY UCN12 UCON #12 9
SHELLEY WTK12 WATKINS #12 SOUTH THEN EAST 10
Service Quality Review
January - December 2008
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~ROCKY MOUNTAINPORAOIVSION OFMCIFIP Service Quality Review
January - December 2008IDAHO
2.4 Cause Code Analysis
The charts below show customer minutes lost and sustained interruptions by cause category.
Customer minutes lost is directly related to SAIDI (the average outage duration for a customer), while
sustained interruptions depict the total number of outages by their causes. Certain types of outages
typically result in a large amount of customer minutes lost, but are infrequent, such as Loss of Supply
outages. Others tend to be more frequent, but result in few customer minutes lost. See page 10 for
Cause Category examples.
;'tlc¡~J!;¡;;C,C .d.i ..c..;,.... .........S:¡,;
,.1:Rlt=
.....,.) ...........;
J;,S,yc '..~,..¡...'..'.., ...............c.;.;..,'....;.;; ......-...... ;..c... .
Direct Cause Category Direct Cause Customers Hours Lost Customers in Incident Sustained Incidents
Animals Animals 2,150.0 1,813 387
Bird Mortality (Non-protected species)1,524.8 1,019 121
Bird Mortality (Protected species) (BMTS)229.5 147 21
Bird Nest (BMTS)1,625.5 1,007 7
Bird Suspected, No Mortality 950.7 761 57
Animals 6,480.5 4,747.0 593
Equipment Failure BIO Equipment 9,176.4 7,304 208
Deterioration or Rotting 36,911.6 18,860 864
Owrload 2,354.5 1,423 26
Equipment Failure 48,442.4 27,587.0 1,098
Operational Faulty Install 188.4 125 11
Improper Protectiw Coordination 69.2 512 5
Incorrct Records 12.2 9 9
PacifiCorp Employee - Field 4.0 3 3
Switching Errr 78.1 543 1
Operational 351.9 1,192.0 29
Trees Tree - Trimmable 335.3 207 29
*Direct Causes are not listed if no outages occured durg the period.
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~ROCKY MOUNTAINPORA DISI OFPAIF1CO""Service Quality Review
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.........i.iii. .'....NON..ONTROLLABLE DISTRIBUTION..........i ...)...........)
Direct Cause Category Direct Cause Customers Hours Lost Customers in Incident Sustained Incidents
Environment Fire/Smoke (not due to faults)6.2 3 2
Flooding 5.3 1 1
Environment 11.5 4.0 3
Equipment Failure Nearby Fault 329.0 43 4
Pole Fire 14,913.0 5,943 49
Fault or Pole Fire 15,242.0 5,986.0 53
Interfrence Dig-in (Non-PacifiCorp Personnel)1,550.0 576 58
Other Interfring Object 520.9 479 15
Other Utility/Contractor 2,030.9 2,352 20
Vandalism or Theft 100.4 40 5
Vehicle Accident 22,234.8 10,382 117
Interfrence 26,437.0 13,829.0 215
Loss of Supply Failure on other line or station 0.0 0 1
Loss of Substation 819.5 626 8
Loss of Transmission Line 40,150.5 13,557 89
System Protection 0.0 0 3
Loss of Supply 40,970.0 14,183.0 101
Operational Unsafe Situation 252.7 694 2
Other Other, Known Cause 167.3 142 29
Unknown 13,493.3 13,319 695
Other 13,660.5 13,461.0 724
Planned Construction 553.4 810 25
Customer Notice Gii.n 7,484.0 2,574 102
Customer Requested 4.3 6 2
Emergency Damage Repair 17,n1.9 15,324 275
Energy Emergency Interrption 2,242.5 4,144 10
Intentional to Clear Trouble 1,283.8 1,722 33
Transmission Requested 1,818.6 660 4
Planned 31,158.6 25,240.0 451
Tres Tre - Non-prei.ntable 11,060.4 4,615 88
Weather Freeing Fog & Frost 494.6 401 3
Ice 39.9 22 11
Lightning 5,298.0 1,908 119
Snow, Sleet and. Blizzard 5,272.7 1,601 68
Wind 29,567.6 12,719 288
Weather 40,672.8 16,651.0 489
*Direct Causes are not listed if no outages occured during the period.
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"'~ROCKY MOUNTAINPOWER"'OIVlIOHOF PAIFll'P
IDAHO
Service Quality Review
January - December 2008
Idaho Customer Hours Lost CY2008
(Contrllable Distibution)
Idaho Customer Hours Lost CY2008
(Non-Contrllable Distibution)Tres
1%
Operational
1%
Idaho Customers Sustained CY2008
(Contrllable Distbution)
Tres
1%
Operaional
4%
Idaho Incidents Sustained CY2008
(Controllable Distibution)
Tre
2%
Operaional
2%
Animals
12%
Equipment
Failure
86%
Animals
14%
Equipment
Failur
81%
Animals
34%
Equipment
Failur
62%
Page 16 of 19
Weather
23%
FauK or Pole Fire
8%
Tre - Non-
preientable
6%
Interfrence
15%
Loss of Supply
23%
Emironment
0%
Unsaf Situation
0%
Othe
8%
Idaho Customers Sustained CY2008
(Non-Contrllable Distbution)
Tree - Non-
preientable
5%
Loss ofSupp
15%
Weather
18%
Fault or Pole Fire
6%
Interfce
15%
Emironment
0%
Planned
26%
Unsaf Situation
1%
Other
14%
Idaho Incidents Sustained CY2008
(Non-Cntrllable Distibution)
Tree - Non-
preientable
4%
Weather
23%
Interfrence
10%
Loss of Supply
5%
Emiroment
0%nsaf Situation
0%
Planned
21%Other
35%
"~ROCKY MOUNTAINPOWERA DlVSION OF PAFlII'Service Quality Review
January - December 2008IDAHO
y /..
hi:IIi:ØÎ ....1'1 Descriptipri and Examplesc-
..CY. .............
Contamination or Airborne Deposit (i.e. salt, trona, ash, other chemical dust,
Environment sawdust, etc.); corrosive environment; flooding due to nvers, broken water main,
etc.; fire/smoke related to forest, brush or building fires (not including fires. due to
faults or lightning).
Weather Wind (excluding windborne material); snow, sleet or blizzard; ice; freezing fog;
frost; lightning.
Structural deterioration due to age (inc!. pole rot); electrical load above limits;
Equipment Failure 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).
Wilful damage, interference or theft; such as gun shots, rock throwing, etc;
Interference customer, contractor or other utility dig-in; contact by outside utility, contractor or
other third-part individual; vehicle accident, including car, truck, tractor, aircraft,
manned balloon; other interfenng object such as straw, shoes, string, balloon.
Animals and Birds Any problem nest that requires removal, relocation, trimming, etc; any birds,
squirrels or other animals, whether or not remains found.
.
Accidental Contact by PacifiCorp or PacifiCorp's Contractors (including live-line
Operational 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 restnction.
Loss of Supply Failure of supply from Generator or Transmission system; failure of distribution
substation equipment.
Transmission requested, affects distribution sub and distribution circuits; Company
Planned outage taken to make repairs after storm damage, car hit pole, etc.; construction
work, regardless if notice is given; rollng blackouts.
Trees Growing or fallng trees
Other Cause Unknown; use comments field if there are some possible reasons.
Page 17 of 19
~~~~o~OUNTAIN
IDAHO
Service Quality Review
January - December 2008
2.5 Reduce CPI for Worst Performing Circuits by 20%
On a routine basis, the Company reviews circuits for performance. One measure that it uses is called
circuit performance indicator (CPI), 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 target improvement. The improvements are to be completed within two
years of selection. Within five years of selection, the average performance of the selection set must
improve by at least 20% (comparing current performance against baseline performance).
Circuit Penormance Indicator 2005 (CPI05)
PROGRAM YEAR 9
478 COMPLETE
297 COMPLETE
351 COMPLETE
272 COMPLETE
451 COMPLETE
370
PROGRAM YEAR 7
201 COMPLETE
265 COMPLETE
367 COMPLETE
1 COMPLETE
COMPLETE
MET
Anderson 13 North
Camas 11
Kettle 21
Shelle 14
Winsper22
GET SCORE = 296
Goshen 12
Grace 12
Performance
12/31/2008
360
2991
186
55
2.6 Restore Service to 80% of Customers within 3 Hours (across 3 years)
3-Year Program to Date = 85%
January 1 - December 31, 2008 = 85%
January February I March II April I May June85% 96% 99% 93% 95%
July
90%
August
77%
September October
87% 84%
ecember
68%
Page 18 of 19
"~ROCKY MOUNTAINPOERA DIIO OF PAFlCOfP Service Quality Review
January - December 2008IDAHO
2.7 Telephone Service and Response to Commission Complaints
l,tgMMI~M.ENT "GOAL
i
PERFORMANCE
PS5-Answer calls within 30 seconds 80%85%
Respond to commission complaints within 3 da 95%100%,"",wj
PS6b)Respond to commission complaints regarding 100%service disconnects within 4 hours 95%
PS6c)Resolve commission complaints within 30 days 95%100%
3 CUSTOMER GUARANTEES
3.1 Idaho State Customer Guarantees Summary Status
customerguarantees January to December 2008
Idaho
CG1
CG2
CG3
CG4
CG5
CG6
CG7
2008 2007
Description Event Failures 0/ Success Paid Evnt Failures 0/ Success Paid
Restoring Suppiy 121,101 0 100%$0 117,683 0 100%$0
Appointments 1,173 1 99.9%$50 1,405 3 99.8%$150
Switching on Power 1,367 1 99.9%$50 1,496 2 99.9%$100
Estimates 414 0 100.0%$0 499 0 100%$0
Respond to Billng Inquiries 789 2 99.7%$100 809 0 100%$0
Respond to llter Problems 219 1 99.5%$50 140 0 100%$0
Notifcation of Planned Interruptions 2,574 3 99.9%$150 2,479 2 99.9%$100
127,637 8 99.9%$400 124,511 7 99.9%$350
Effective April 1, 2005, a modified customer guarantee program was implemented. The new program streamlines
and simplifies the guarantees.
Major Events are excluded from the Customer Guarantees program.
Page 19 of 19