20150812AVU to Staff 50 Attachment E.pdf

2013 Asset Management Distribution Program Update

Amber Fowler, Rodney Pickett, Doug Forkner, and Thomas Morrell
02-17-2013

AM plans have been created and reviewed, only a portion of the plans discussed have been
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Table of Contents
Introduction .................................................................................................................................................. 1
Purpose ......................................................................................................................................................... 1
Data Sources ................................................................................................................................................. 1
Standard Calculations ................................................................................................................................... 2
Review of OMT Data and Trends .................................................................................................................. 2
OMT Events per Year ................................................................................................................................ 2
SAIFI Trends by OMT Sub-Reasons ........................................................................................................... 8
OMT Sub-Reason Events High Limit ........................................................................................................ 10
Specific Distribution Programs and Assets ................................................................................................. 17
Distribution Wood Pole Management (WPM)........................................................................................ 17
Selected KPIs and Metrics ................................................................................................................... 17
WPM Metric Performance .................................................................................................................. 20
WPM Model Performance .................................................................................................................. 20
WPM Summary ................................................................................................................................... 21
Wildlife Guards ....................................................................................................................................... 27
Selected KPIs and Metrics ................................................................................................................... 27
WILDLIFE GUARDS KPI Performance ................................................................................................... 28
WILDLIFE GUARDS Metric Performance ............................................................................................. 28
WILDLIFE GUARDS Model Performance ............................................................................................. 29
WILDLIFE GUARDS Summary .............................................................................................................. 29
URD Primary Cable .................................................................................................................................. 32
Selected KPIs and Metrics ................................................................................................................... 32
URD PRIMARY CABLE KPI Performance .............................................................................................. 33
URD PRIMARY CABLE Metric Performance ......................................................................................... 34
URD PRIMARY CABLE Model Performance ......................................................................................... 34
URD PRIMARY CABLE Summary .......................................................................................................... 35
URD Secondary Cable.............................................................................................................................. 35
Open Wire Secondary ............................................................................................................................. 35
Distribution Cutouts ................................................................................................................................ 35
Distribution Air Switches ......................................................................................................................... 35
Distribution Mid-Line Reclosers .............................................................................................................. 35
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Distribution Mid-Line Voltage Regulators............................................................................................... 36
Primary Conductors ................................................................................................................................ 36
Primary Connections ............................................................................................................................... 37
Secondary Conductors ............................................................................................................................ 37
Secondary Connectors ............................................................................................................................ 37
Distribution Transformers ....................................................................................................................... 37
Selected Metrics ................................................................................................................................. 37
Metric Performance ............................................................................................................................ 38
Summary ............................................................................................................................................. 38
Area and Street Lights ............................................................................................................................. 38
Riser Terminations .................................................................................................................................. 38
Dead End Insulators ................................................................................................................................ 38
Distribution Capacitors ........................................................................................................................... 39
9CE12F4 Partial Feeder Rebuild .............................................................................................................. 39
Selected KPIs and Metrics ................................................................................................................... 39
Partial Feeder Rebuild KPI Performance ............................................................................................. 39
Partial Feeder Rebuild Metric Performance ....................................................................................... 39
Partial Feeder Rebuild Model Performance ....................................................................................... 41
Partial Feeder Rebuild Summary ........................................................................................................ 41
Chance Cutouts ....................................................................................................................................... 42
Selected KPIs and Metrics ................................................................................................................... 42
Chance Cutouts KPI and Metric Performance .................................................................................... 42
Chance Cutouts Model Performance .................................................................................................. 44
Chance Cutouts Summary ................................................................................................................... 44
Distribution Vegetation Management (VM) ........................................................................................... 44
Selected KPIs and Metrics ................................................................................................................... 44
VM KPI Performance ........................................................................................................................... 46
VM Metric Performance ..................................................................................................................... 48
VM Model Performance...................................................................................................................... 49
VM Summary....................................................................................................................................... 49
Distribution Grid Modernization Program .............................................................................................. 49
Selected Metrics ................................................................................................................................. 50
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Metric Performance ............................................................................................................................ 54
Summary ............................................................................................................................................. 54
Asset Management Area Work plans for Electric Distribution ...................... Error! Bookmark not defined.
Spokane Area Work Plans .......................................................................... Error! Bookmark not defined.
Conclusion ................................................................................................................................................... 54

Figure 1, OMT Annual Number of Events and AM Related Event Trends and Trend Lines .......................... 7
Figure 2, OMT Events with and without Planned Maintenance or Upgrades .............................................. 8
Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits ............................................................ 12
Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time .................................................... 13
Figure 5, 2013 OMT SAIFI Contribution by Sub-Reason ............................................................................. 14
Figure 6, 2012 OMT Sustained Outage Comparisons ................................................................................. 15
Figure 7, Customers Affected Per Event Exceeding Risk Action Levels ...................................................... 16
Figure 8, WPM OMT Event Trends .............................................................................................................. 22
Figure 9, WPM Contribution to Annual SAIFI value by Sub-Reason and Year ............................................ 23
Figure 10, Wood Pole Used by Summarized Activity .................................................................................. 24
Figure 11, Distribution Wood Pole Age Profile ........................................................................................... 25
Figure 12, WPM Model Projections vs Actual Usage for 2013 ................................................................... 26
Figure 13, Wildlife Guards Installed by Year and Expenditure Request ..................................................... 30
Figure 14, Wildlife Guards Usage by MAC for 2009-2013 .......................................................................... 31
Figure 15, URD Primary Cable OMT Events by Year ................................................................................... 34
Figure 16, All OMT Sub-Reasons except Maint/Upgrade for Feeder 9CE12F4 2002-2013 ........................ 40
Figure 17, Selected OMT Trends for AM Related Events with Upward Trends for Feeder 9CE12F4 ......... 41
Figure 18, Cutout/Fuse OMT Event Comparison between Actual, Projected without Action, and
Projected with Action ................................................................................................................................. 43
Figure 19, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons............ 47
Figure 20, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell
Sub-Reasons ................................................................................................................................................ 48
Figure 21, OMT Sustained Outages related to Grid Modernization ........................................................... 53

Table 1, OMT Events by Sub-Reason and Year ............................................................................................. 2
Table 2, OMT Outages and Partial Outages by Sub-Reason and Year .......................................................... 4
Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2007-2013 data .......................... 5
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2007-2013 data ..................... 6
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage .................................................................. 9
Table 6, OMT Sub-Reasons Exceeding Annual High Limit ........................................................................... 11
Table 7, WPM KPI Goals by Year ................................................................................................................. 18
Table 8, WPM Metric Goals by Year ........................................................................................................... 19
Table 9, Wildlife KPI Goals for 2010 - 2015 ................................................................................................. 28
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Table 10, Wildlife Metric Goals for 2010 - 2015 ......................................................................................... 28
Table 11, Worst Feeders for Squirrel related Events for 2010 - 2012 ........................................................ 29
Table 12, URD Cable - Pri KPI Goals ............................................................................................................ 33
Table 13, URD Cable - Pri Metric Goals ....................................................................................................... 33
Table 14, TCOP Metrics ............................................................................................................................... 38
Table 15, Chance Cutout Replacement KPI and Metric Goals .................................................................... 42
Table 16, Chance Cutout KPI and Metric Performance .............................................................................. 43
Table 17, Vegetation Management KPI Goals ............................................................................................ 45
Table 18, Vegetation Management Metric Goals ....................................................................................... 45
Table 19, VM KPI Performance ................................................................................................................... 46
Table 20, Tree-Weather OMT Events Metric for Vegetation Management ............................................... 49
Table 21, VM Cost per Mile and All Vegetation Management Work Metric .............................................. 49
Table 22, Grid Modernization Program Objectives .................................................................................... 50
Table 23, Energy Savings based on 2013 Integrated Resource Plan ............. Error! Bookmark not defined.
Table 24, OMT Sub-Reasons impacted by Grid Modernization .................................................................. 52
Table 25, Metric Performance for Grid Modernization Program ............................................................... 54

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Introduction
As Avista incorporates more work and Asset Management (AM) Plans each year, Asset Management is
committed to monitor how these activities impact our systems and document the value created by the
programs. Reviewing the results of AM activities and system responses provides us with the feedback
necessary to learn and improve our plans and processes. These outcomes also help drive future work
when actions don’t yield the desired results or we find there is even more value of further work. In the
end, our commitment to continuous improvement require us to examine how we have impacted our
systems and learn from what has happened to make tomorrow’s plans work better.
Purpose
This report documents the KPIs and metrics AM uses for the Distribution system and provides the results
for 2013. Some of the metrics provide a basis for comparing how an asset performed with a program
and how it would have performed without a program. The difference in performance provides an
estimate of the cost saving of the program. The estimated savings is only a snapshot in time and may
not represent the exact savings; it provides a relative comparison and supporting justification for AM
decisions made in the past. Other KPIs and metrics provide indications of how well an asset is
performing and helps determine when further work is required. KPIs and metrics tracking also help
evaluate the accuracy of different AM models and determine when or if a model should be revised.
Data Sources
Information used in this report’s metrics comes from three sources: Annual Sustained and Momentary
outage data; Outage Management Tool (OMT) events; and Discoverer. The annual Sustained and
Momentary outage data is generated by the Distribution Dispatch Engineer each month in a
spreadsheet. The Sustained and Momentary outage data for years 2001 – 2007 was modified by AM to
align the reasons and sub-reasons to coincide with the current descriptions. While the Sustained and
Momentary outage data comes from OMT data and is a subset of OMT data, this data has been
scrubbed by the Distribution Dispatch Engineer to improve its accuracy.
The OMT tracks outages and customer reports of problems on the Distribution system, Substations, and
Transmission events that cause outages on the Distribution system. This data includes sustained
outages, momentary outages, and events without outages. Events that only cause a partial outage or no
outage at all do not show up in the Sustained and Momentary outage data, because the data does not
fit the definition of a sustained outage or a momentary outage. However, the OMT data is subject to
reporting an event more than once. The Distribution Dispatch Engineer reviews the data and strives to
prevent duplication by rolling events up and editing the data. However, some duplication still occurs.
OMT data is used to calculate number of outages, number of OMT events (outages, partial outages, and
non-outage events), outage duration, number of customers impacted, response times, System Average
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Interruption Frequency Index (SAIFI) impacts, and System Average Interruption Duration Index
(SAIDI) impacts.
Discoverer provides financial, customer information, and material usage information from our
warehouse and financial systems. Spending and material can be tracked to the ER and BI level for
capital work and the MAC and Task for Operations and Maintenance (O&M) work.
Standard Calculations
See reference the “2013 General Metrics Data Collection and Analysis for System Reviews” for the
details and examples of how different measures and metrics are calculated.
Review of OMT Data and Trends
Examining the data in OMT reveals a lot of information which helps Avista understand the condition of
our assets and shows some trends we can address. Below, we will examine various trends within OMT
Events per Year, SAIFI trends by OMT Sub-Reasons, and other measures.
OMT Events per Year
Table 1 shows the past seven years of data out of OMT by Sub-Reason and allows trend analysis. OMT
Events represents cost and action for Avista, so it was selected as a basis for much of our trending.
However, OMT Outage data (shown in Table 2) can have a different trend than OMT Events. Since the
SAIFI analysis already includes outage data, AM selected to trend OMT Events and SAIFI contribution.
Based on Table 1, we identified the top 10 increasing and decreasing trends in OMT Sub-Reasons. The
Top 10 increasing trends in the number of OMT events by year is shown in Table 3 and the Top 10
decreasing trends in the number of OMT events by year is shown in Table 4.
Table 1, OMT Events by Sub-Reason and Year
OMT SUB-REASON 2007 2008 2009 2010 2011 2012 2013
Arrester 26 26 19 32 30 36 24
Bird 220 187 218 179 332 231 270
Bus Insulator

2 1 1
Capacitor 6 4 4 2

4 4
Car Hit Pad 88 129 139 105 98 105 117
Car Hit Pole 231 202 217 298 339 355 369
Conductor - Pri 59 51 42 64 81 110 142
Conductor - Sec 231 252 286 273 310 286 331
Connector - Pri 89 99 111 101 100 79 85
Connector - Sec 340 395 429 410 408 390 336
Crossarm-rotten 46 38 23 25 28 19 18
Customer Equipment 1182 1475 1626 1458 1384 1434 1368
Cutout/Fuse 272 234 197 217 176 209 171
Dig In 132 152 164 149 123 109 103
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OMT SUB-REASON 2007 2008 2009 2010 2011 2012 2013
Elbow 5 8 7 5 8 2 10
Fire 135 182 157 203 234 230 282
Forced 52 62 51 63 67 33 63
Foreign Utility 455 856 724 894 720 734 720
Highside Breaker 1

2
Highside Fuse 2 4
Highside Swt/Disconnect

4
Insulator 25 37 32 49 36 32 47
Insulator Pin 18 17 28 24 30 25 23
Junctions 1

2 2 1 4 6
Lightning 333 335 598 163 179 635 453
Lowside OCB/Recloser 1 2 6 8 4
Lowside Swt/Disconnect

2

1
Maint/Upgrade 331 350 539 1571 3334 2589 1840
Other 409 434 394 414 426 483 472
Pole Fire 116 157 116 102 117 113 152
Pole-rotten 25 44 44 37 35 52 34
Primary Splice 3 1

1 1
Protected 10 23 18 10 4 5 5
Recloser 4 2 4 11 3 2 3
Regulator 8 13 14 20 17 13 17
Relay Misoperation 1 1 5 7

5
SEE REMARKS 747 849 821 892 543 487 463
Service 113 144 123 188 197 230 191
Snow/Ice 249 2093 988 565 167 352 122
Squirrel 801 747 700 390 395 358 215
Switch/Disconnect 1 15 9 3

3 6
Termination 9 18 7 7 9 12 21
Transformer 5 5

3

9 2
Transformer - OH 179 211 158 128 156 167 132
Transformer UG 47 46 57 53 51 50 71
Tree 92 66 55 53 51 56 46
Tree Fell 315 470 390 506 392 377 298
Tree Growth 273 443 375 330 335 335 349
Underground 5 2

3 1 3 2
Undetermined 1014 1116 1145 948 861 783 765
URD Cable - Pri 198 176 136 93 95 72 93
URD Cable - Sec 185 212 212 190 248 219 208
Weather 251 564 357 895 325 314 216
Wildlife Guard

3

1 2

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OMT SUB-REASON 2007 2008 2009 2010 2011 2012 2013
Wind 953 822 294 1309 256 1042 1126

Table 2, OMT Outages and Partial Outages by Sub-Reason and Year
OMT SUB-REASON 2007 2008 2009 2010 2011 2012 2013
Arrester 25 22 18 31 30 32 21
Bird 215 178 213 175 322 225 259
Bus Insulator 0 0 0 0 2 1 1
Capacitor 3 2 4 1 0 3 2
Car Hit Pad 46 47 41 30 31 45 36
Car Hit Pole 133 104 104 135 131 158 152
Conductor - Pri 42 26 31 49 61 70 113
Conductor - Sec 102 107 117 104 126 124 147
Connector - Pri 71 88 102 84 82 59 68
Connector - Sec 224 246 272 263 270 267 227
Crossarm-rotten 38 28 11 20 24 17 15
Customer Equipment 897 1040 1205 1121 1034 1099 1037
Cutout/Fuse 238 207 175 194 161 185 155
Dig In 99 103 104 88 75 64 62
Elbow 5 7 7 5 7 2 10
Fire 68 31 8 69 72 82 102
Forced 52 61 51 63 67 33 63
Foreign Utility 63 110 78 103 61 62 90
Highside Breaker 1 0 0 1 0 0 0
Highside Fuse 2 4 0 0 0 0 0
Highside Swt/Disconnect 0 0 0 0 0 0 0
Insulator 13 25 23 31 26 19 27
Insulator Pin 16 15 16 15 18 19 13
Junctions 1 0 0 1 0 2 2
Lightning 323 320 572 159 174 562 417
Lowside OCB/Recloser 1 2 6 8 3 0 0
Lowside Swt/Disconnect 0 0 2 0 0 0 1
Maint/Upgrade 331 342 534 1566 3331 2587 1834
Other 301 252 247 275 261 282 282
Pole Fire 108 130 101 87 93 95 128
Pole-rotten 5 7 14 11 10 9 7
Primary Splice 3 1 0 1 1 0 0
Protected 9 16 17 7 4 5 5
Recloser 4 2 3 9 1 2 3
Regulator 8 11 10 16 14 10 10
Relay Misoperation 1 1 5 7 0 0 5
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OMT SUB-REASON 2007 2008 2009 2010 2011 2012 2013
SEE REMARKS 406 318 420 443 286 255 262
Service 80 92 59 89 86 59 55
Snow/Ice 225 1176 592 347 135 291 103
Squirrel 786 725 694 380 389 351 210
Switch/Disconnect 1 6 7 3 0 1 5
Termination 9 16 7 6 8 12 18
Transformer 5 5 0 3 0 9 2
Transformer - OH 164 193 143 107 138 150 117
Transformer UG 45 38 42 44 36 42 59
Tree 71 46 42 39 36 39 35
Tree Fell 176 255 186 234 215 229 183
Tree Growth 107 101 101 77 71 93 90
Underground 5 2 0 1 1 3 2
Undetermined 914 956 1023 855 799 684 669
URD Cable - Pri 197 153 132 89 92 71 89
URD Cable - Sec 168 194 201 175 227 202 190
Weather 192 358 273 620 178 170 137
Wildlife Guard 0 0 3 0 0 2 0
Wind 737 553 229 982 195 802 840

Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2007-2013 data

The largest upward trend continues to be our increase in maintenance and upgrade outages. We have
implemented many programs that increase our outages due to maintenance but decrease the number
of outages due to failures. It appears that Planned Work has had an impact on our outages. Nearly all
of the Outage Sub-Reasons that are directly and indirectly affected by the Vegetation program, Wood
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Pole Management, and other planned work are not represented on this list. The only outage Sub-
Reason on the list that is affected by an Asset Management program is the Bird outage. This could be
due to variables outside of our control and will need to be evaluated if this behavior continues. All of
the remaining outage Sub-Reasons in Table 3 are at a level that a program is probably not needed or
outside the scope of an Asset Management Program.
Table 4 shows the Top 10 OMT Sub-Reasons with a downward trend. The largest downward trend is in
Squirrel event driven largely by the results of adding Wildlife Guards (WLG) on new installs and adding
them to existing transformers as part of Wood Pole Management and Grid Modernization. Our Cutout
Replacement programs for Chance cutouts and bad cutouts identified by Wood Pole Management have
made a great impact on the number of cutout events. The URD cable Replacement program for the first
generation of unjacketed cable has paid great dividends when compared to where it could have been
without taking action at reducing URD Cable – Pri events. The Tree events listed in Table 4 are for tree
events caused by the public and are outside of our control. The remaining Sub Reasons in the table have
trend downward but the changes are not material at this point in time.
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2007-2013 data
Top Ten Downward Trends
OMT Sub-Reason Slope Change per Year
Squirrel -99
Snow/Ice -93
Undetermined -54
SEE REMARKS -25
Weather -23
URD Cable - Pri -19
Cutout/Fuse -11
Transformer - OH -8
Dig In -8
Tree -5

The overall trends in OMT Events are shown in Figure 1 along with the trends in AM related OMT Events
(see Appendix A of the “2013 Asset Management Electrical Distribution Program Review and Metrics”
and the table titled “List of AM Related OMT Sub-Reasons” to see which OMT Sub-Reasons are
considered AM Related). Based on Figure 1, Avista sees the number of events decreasing over the past
6 years. . Figure 2 also shows that the number of OMT events representing failures is on a downward
trend over the past 6 years (see OMT Events w/o Maint/Upgrades for this trend).
AM related OMT events are actually decreasing at a rate around 5%. Since the regional growth rates are
less than 2%, the decrease is most probably due to the increase in maintenance in the system and
replacement of aged infrastructure.

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Figure 1, OMT Annual Number of Events and AM Related Event Trends and Trend Lines

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Figure 2, OMT Events with and without Planned Maintenance or Upgrades
SAIFI Trends by OMT Sub-Reasons
Examining how SAIFI changes each year is shown in Table 5. SAIFI values in Table 5 represent the annual
value each event contributes to the overall SAIFI number. For example, in 2010, the average Arrester
event in OMT added 0.0023076 to the overall SAIFI number for the year. While the number of electrical
customers does grow each year, the main driver for changes in the average SAIFI number per event
comes from the average numbers of customers affected by the event. Continuing our example with
Arresters, in 2009 Avista had 356,777 electrical customers and the average Arrester outage event
affected 111 customers, so the average SAIFI impact per event was 0.0023076. In 2011, our electrical
customer count increased to 358,443 and the average number of customers affected by an Arrester
related outage dropped to 40, and the average SAIFI impact due to Arrester events dropped to
0.0008451. The result for SAIFI was an increase in the average impact to SAIFI in 2010 compared to
2011.
While most Sub-Reasons in OMT have fluctuating value around an average value over the past five
years, some Sub-Reasons have demonstrated a definite trend upward as shown in Figure 4. Figure 4
shows the top 10 Sub-Reasons based on the percentage change in 2013. Some of the items in Figure 4
had small numerical changes but the percentage change was significant. The Car Hit Pole Sub-Reason is
an example of this, because the number of OMT events was less than 300 between the years 2007-2010
and the SAIFI value in 2009 was 5.6*10-2 but moved steadily to 6.2*10-2 in 2013.
Figure 5 and Figure 6 illustrate the makeup of the overall SAIFI value and overall OMT Sustained
Outages. Figure 6 and Figure 5 show a different result because the number of customers impacted by
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each Sub-Reason is different. For example, we have very few Lightning caused outages, but they affect a
large number of customers. So, Lightning shows a significant impact to SAIFI in Figure 5 but is
insignificant on Figure 6.
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage
Average SAIFI by Sub-Reason Event
OMT Sub-
Reason 2007 2008 2009 2010 2011 2012 2013
Arrester 0.01336324 0.011896617 0.008745915 0.009230266 0.003380523 0.015245676 0.003562297
Bird 0.015658058 0.016111406 0.051184585 0.026835343 0.050143556 0.015659978 0.064285794
Bus Insulator 0 0 0 0 0.009016775 0.000463618 0.00165077
Capacitor 0.000954613 0.002953837 0.002533353 0.002842798 0 0.006147101 8.27074E-06
Car Hit Pad 0.004577603 0.003859152 0.003022983 0.001972404 0.00315424 0.004171572 0.004940524
Car Hit Pole 0.082729511 0.056285174 0.05623644 0.055741604 0.034563763 0.078829605 0.061689509
Conductor - Pri 0.021600264 0.011489151 0.025289327 0.013459389 0.025213018 0.024181701 0.036457655
Conductor - Sec 0.001383003 0.001479731 0.001086872 0.001923463 0.001952154 0.003857768 0.002491023
Connector - Pri 0.019175112 0.044761723 0.036707546 0.029390854 0.022841718 0.023941651 0.01912657
Connector - Sec 0.002766032 0.002171923 0.00158371 0.001764569 0.001927718 0.002095065 0.001612901
Crossarm-rotten 0.050334458 0.0252873 0.001820303 0.010791352 0.017452881 0.004106797 0.001059746
Customer
Equipment 7.49088E-05 0.000124802 8.77548E-05 8.43629E-05 4.18879E-05 0 4.96037E-05
Cutout/Fuse 0.015844599 0.024630616 0.020002232 0.029472485 0.014918168 0.027484801 0.01707108
Dig In 0.011935045 0.017879617 0.017426241 0.002911047 0.007751271 0.001543001 0.001766282
Elbow 0.000175223 0.001148975 0.001834192 9.54113E-05 0.000737521 2.50685E-05 0.001158911
Fire 0.017648049 0.001552322 0.000963714 0.000916016 0.001765849 0.004579849 0.012299424
Forced 0.022935126 0.037704074 0.041119919 0.026724006 0.011341762 0.01007956 0.035479695
Foreign Utility 4.62462E-05 0.000104966 9.67203E-06 0.06415389 1.9551E-05 1.10385E-05 3.04099E-05
Highside Breaker 0.005624164 0 0 0.001809346 0 0 0
Highside Fuse 5.79715E-06 0.003370373 0 0 0 0 0
Highside
Swt/Disconnect 0 0 0 0 0 0 0
Insulator 0.006320321 0.005329816 0.032674813 0.00947135 0.00767475 0.001619894 0.018937297
Insulator Pin 0.015949133 0.002512396 0.00073663 0.00609977 0.012718209 0.002646432 0.004556295
Junctions 0.000127537 0 0 5.63488E-06 0 0.002791077 0.000475014
Lightning 0.128468634 0.083469701 0.093833897 0.05153771 0.029986357 0.107700751 0.152792603
Lowside
OCB/Recloser 0.002156231 0.00501564 0.032172584 0.02327413 0.013159376 0 0
Lowside
Swt/Disconnect 0 0 0.001932028 0 0 0 2.75588E-06
Maint/Upgrade 0.056121124 0.073959603 0.146879337 0.115272977 0.131045664 0.093958391 0.118799625
Other 0.139200478 0.087814989 0.158240122 0.177318475 0.156583826 0.114257941 0.085502603
Pole Fire 0.071639978 0.085131634 0.056866386 0.108242728 0.087722138 0.058825288 0.078650039
Pole-rotten 0.000430513 0.000936218 0.001111959 0.002027401 0.002475849 0.001111378 0.002186058
Staff_PR_050 Attachment E Page 14 of 73
OMT Sub-
Reason 2007 2008 2009 2010 2011 2012 2013
Primary Splice 8.94841E-05 2.81903E-06 0 1.40872E-05 0.000227493 0 0
Protected 0.009257534 0.013300204 0.006434116 0.005438117 0.000105902 0.000523814 0.000524546
Recloser 0.001297214 0.001916203 0.003492427 0.002520587 0.000212125 8.36386E-06 0.001310323
Regulator 0.005390496 0.024938242 0.011105746 0.019517299 0.003012273 0.020486437 0.010292094
Relay
Misoperation 0.008228451 0.005720398 0.01961408 0.026993562 0 0 0.008117153
SEE REMARKS 0.015994757 0.032649991 0.017553605 0.0263254 0.022946333 0.024001629 0.035782952
Service 0.000501324 0.00054765 0.000382684 0.001512913 0.001254413 0.001425234 0.001116933
Snow/Ice 0.081725352 0.264038325 0.133791974 0.091003627 0.039682871 0.109703932 0.035007006
Squirrel 0.023857822 0.08015205 0.056647666 0.021425719 0.039013725 0.050207568 0.026293232
Switch/Disconnect 5.79715E-06 0.002055625 0.0165265 0.004582077 0 4.14971E-05 0.020930465
Termination 0.000467243 0.000867328 0.000227232 0.000152009 0.000173439 0.000637191 0.003063515
Transformer 0.009703026 0.023561073 0 0.002368376 0 0.026729531 0.00246343
Transformer - OH 0.007052431 0.01118744 0.00773242 0.002407314 0.017106495 0.004874802 0.004093373
Transformer UG 0.002360207 0.002263655 0.001051355 0.001704189 0.001165537 0.001438726 0.006231495
Tree 0.013180035 0.004975592 0.005575766 0.013288743 0.000938339 0.011356792 0.002750215
Tree Fell 0.076230149 0.057889379 0.048048112 0.092136448 0.062998204 0.067319172 0.054556299
Tree Growth 0.012134005 0.010881641 0.004394705 0.007012046 0.003838547 0.005569335 0.005691876
Underground 8.34231E-05 3.4203E-05 0 2.81744E-06 2.80426E-06 3.87453E-05 5.48895E-06
Undetermined 0.168118512 0.29086705 0.286489483 0.110134471 0.234672203 0.177748096 0.157264023
URD Cable - Pri 0.017483349 0.022121806 0.009632032 0.005903606 0.008770789 0.002422167 0.006080464
URD Cable - Sec 0.000815417 0.001058763 0.000945651 0.000953008 0.001467391 0.001544569 0.001409578
Weather 0.078263003 0.115917398 0.097935383 0.195547002 0.051231256 0.053674679 0.033680951
Wildlife Guard 0 0 8.47553E-06 0 0 8.35232E-06 0
Wind 0.232776552 0.220754073 0.115850205 0.291134088 0.089836161 0.195492335 0.209669949
OMT Sub-Reason Events High Limit
The second metric used to determine if we must examine a problem is the deviation from the
established mean discussed above for each OMT Sub-Reason. If the number of OMT events for a specific
Sub-Reason exceeds the OMT Sub-Reason Events High Limit (High Limit) AM will conduct an
investigation and try to explain why the annual values are exceeding the limit (see Appendix D of the
“2013 Asset Management Electrical Distribution Program Review and Metrics”). The High Limit is based
on the average of annual values for each Sub-Reason plus two standard deviations. This method is also
used to calculate the quarterly High Limit as well. The data for the average is the OMT Data for 2006
through 2010. For 2013, the following OMT Sub-Reasons exceeded their High Limit are shown in Table
6. We anticipated that Avista would exceed these limits due to natural deviations for events outside our
control and due to some cyclical nature we observe in our data. Our goal here is to help identify trends
in time to potentially address them if possible.

Staff_PR_050 Attachment E Page 15 of 73

Table 6, OMT Sub-Reasons Exceeding Annual High Limit
OMT Sub-Reasons Exceeding their associated OMT
High Limit
Number of Years High Limit Exceeded
Bird 1
Car Hit Pole 4
Conductor - Pri 3
Elbow 1
Fire 3
Highside Breaker 1
Junctions 1
Maint/Upgrade 4
Regulator 1
Service 4
Termination 1

Based on Table 6, we currently don’t see any issues requiring changes to our current plans. Most of the
issues identified above are outside our control. We will continue to monitor Fire, Service, Car Hit Pole
and Conductor – Pri, as these may call for some kind of action in the future. Car Hit Pole is currently
being analyzed by another group. If a program is implemented from this analysis then we should see
this issue drop off the High Limit Exceeded chart. We will continue to monitor this issue.
Figure 3 shows the quarterly trends that feed into the annual trends for the OMT High Limit. For all
OMT Sub-Reasons, only three Sub-Reasons have had more than three quarters where they exceeded the
High Limit, Car Hit Pole with 9 quarters above the limit, Maint/Upgrades, and Service with 6 quarters
above the limit. This information is consistent with Table 6 above. We will continue to monitor Service
for potential future action, but it currently does not warrant a maintenance or replacement strategy.

Staff_PR_050 Attachment E Page 16 of 73

Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits
y = 0.147x + 0.0032
0
1
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3
4
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Year - Quarter
Individual Sub-Reasons Exceeding Average Levels by
2 Standard Deviations per Quarter
Staff_PR_050 Attachment E Page 17 of 73

Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time
0%
5%
10%
15%
20%
25%
Top 10 OMT Sub-Reasons in growing Unreliability by SAIFI
Staff_PR_050 Attachment E Page 18 of 73

Figure 5, 2013 OMT SAIFI Contribution by Sub-Reason
Staff_PR_050 Attachment E Page 19 of 73

Figure 6, 2012 OMT Sustained Outage Comparisons
Maint/Upgrade
16%
Customer Equipment
12%
Wind
10%
Undetermined
6%
Foreign Utility
6% Other
4%
SEE
REMARKS
4%
Lightning
4%
Car Hit Pole
3%
Tree Growth
3%
Connector - Sec
3%
Conductor - Sec
3%
Tree Fell
3%
Fire
2%
Bird
2%
Weather
2%
Squirrel
2%
URD Cable - Sec
2%
Service
2%
Cutout/Fuse
1%
Pole Fire
1%
Conductor - Pri
1% Transformer -
OH
1% Snow/Ice
1%
Car Hit Pad
1%
Everything else
6%
Sustained Events by OMT Subreason
Staff_PR_050 Attachment E Page 20 of 73

Figure 7, Customers Affected Per Event Exceeding Risk Action Levels
0
500
1000
1500
2000
2500
3000
Cu
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Annual RAL curves
Switch/Disconnect
Switch/Disconnect Risk Action Level
Staff_PR_050 Attachment E Page 21 of 73
Specific Distribution Programs and Assets
In the following sections, AM reviews the different programs and work done to determine an AM action
plan for particular assets. Some plans indicated the current case or no action was the best approach and
others indicated there was an appropriate action for managing an asset. If a plan was implemented,
then the available information will be reviewed to determine how the plan has impacted the system.
Distribution Wood Pole Management (WPM)
The current WPM program inspects and maintains the existing distribution wood poles on a 20 year
cycle. Avista has 7,793 circuit miles of Distribution lines that are predominately overhead. The average
age of a wood pole is 28 years with a standard deviation of 21 years. Nearly 20% of all poles are over 50
years old and we have an estimated 240,000 Distribution poles in the system. This means that about
48,000 poles are currently over 50 years old. Our inspection cycle allows us to reach approximately
12,000 poles each year. Along with inspecting the poles, we inspect distribution transformers, cutouts,
insulators, wildlife guards, lightning arresters, crossarms, pole guying, and pole grounds. The inspection
of these other components on a pole drives additional action to replace bad or failed equipment along
with replacing known problematic components. These additional inspection items have expanded the
current program beyond the original scope, but have proven to be a cost effective way of addressing
more than just wood pole issues.
Selected KPIs and Metrics
AM selected the number of OMT Events by Year related to WPM work and feeder miles of follow-up
work completed verses miles of feeders inspected as KPIs to monitor WPM. These KPI relate to
reliability performance, cost performance, and customer impacts. Our goal is to maintain or reduce the
number of OMT events related to WPM. The current plan optimized the inspection cycle based on cost,
so the impacts to reliability were addressed only as they relate to costs. The goal for these KPI is to stay
below the number of events averaged over 2006 – 2010 for WPM Related OMT Events. See Table 7 for
the goal and for the actual value for 2013. The Goal for the KPI is the 5 year average value using 2006-
2010. The OMT Events KPI is a lagging KPI and an indication of how well past work has impacted
outages. The feeder miles of follow-up work completed verses miles of feeders inspected KPI is a
leading indicator and reflects how outages in the future will be impacted by the work. The number of
miles inspected is shown in Table 7 for the goal and actual values.
The feeder miles of follow-up work completed verses miles of feeders inspected KPI comes from the
annual Distribution WPM inspection plan and is the sum of all miles of the feeders completed in that
year. The completed number of miles for follow-up work on feeders comes from Asset Maintenance
based on their tracking of the work as it is completed The purpose of this metric is to evaluate how
much backlog work is created each year in order to adjust future year’s budgets. Asset Management
has been working to increase the budget each year, with the goal of having no back log, by budgeting
enough to inspect and follow up on a 20 year cycle.
Staff_PR_050 Attachment E Page 22 of 73
Table 7, WPM KPI Goals by Year
KPI
Description
WPM Goal Related
number of OMT Events Related number Projected Miles
Follow-up Work
Actual Miles Follow-
up Work Completed
*Note: Beginning with 2012, the Actual Miles Follow-up Work Completed will include WPM and
Distribution Grid Modernization miles.
Metrics provide a more detailed review of WPM. WPM metrics involve more information and
calculations than the KPIs and include: WPM contribution to the annual SAIFI number; number of
distribution wood poles inspected; material usage for WPM by Electric Distribution Minor Blanket and
Storms; number of Pole-Rotten OMT Events; Crossarms-Rotten OMT Events; and actual material use
verses model predicted material use for WPM follow-up work (see Table 8). The WPM contribution to
the annual SAIFI number metric comes from data pulled out of OMT by Cognos and calculates the
average impact to SAIFI per event by Sub-Reason.
The average impact to SAIFI per WPM event is the sum of the average impact to SAIFI for Arresters,
Cutouts/Fuses, Crossarms, Insulators, Insulator Pins, Pole Fires, Poles – Rotten, Squirrels, Transformers-
OH, and Wildlife Guards. The average impact to SAIFI for WPM events is then multiplied by the number
of event causing an outage or partial outage (this is the sum of OMT events causing an outage or partial
outage for Arresters, Cutouts/Fuses, Crossarms, Insulators, Insulator Pins, Pole Fires, Poles – Rotten,
Squirrels, Transformers-OH, and Wildlife Guards). The goal for this metric is the five year average for
2005-2009. The purpose of this metric is to ensure WPM maintains the current reliability.
The number of Distribution System poles inspected metric measures the annual plan for inspecting
wood poles against how much work was actually completed. The AM plan calls for a 20 year inspection
cycle which was originally estimated to be ~12,000 poles per year. The AM plan also represents
inspecting 17.5 feeders a year. This metric ensures the WPM program meets the AM plan for
Distribution Wood Poles.
Material Usage for WPM by Electric Distribution Minor Blanket and Storms metric monitors other areas
outside of AM that may reflect trends for WPM. However, this metric is outdated and no longer useful.
New stock items are being tracked under this blanket and the 2012 and 2013 numbers are higher than
previous years because of this. The number of stock items used is tracked and compared to the average
used in 2006-2010 as a baseline. The purpose was to monitor for asset failures not indicated by OMT
data, since not all failure information is captured by OMT. Some other form of tracking may need to be
implemented in future years to monitor for asset failures not indicated by OMT data.
Staff_PR_050 Attachment E Page 23 of 73

The final metric, material use verses model predicted material use, tracks the actual number of key
stock numbers (see Figure 12 for assets monitored) against what the AM model predicted. Discoverer is
used to pull stock number usage out for the applicable stock numbers and then they are compared to
the AM model predictions. The purpose of this metric is to measure the performance of the model to
predict the future outcomes. If the difference between the model predictions and actual values
becomes more than 30%, the model should be revised.
Table 8, WPM Metric Goals by Year

Figure 8 shows the trends in OMT events for the Sub-Reasons associated with WPM and generally the
trend in OMT events is downward. The major contributors (Cutouts/Fuses, Squirrel, and Transformer –
OH) all showed a level trend or a general trend downward over the past 5 years. Three of the four
major contributors showed improvements from 2009 (Transformer - OH, Squirrel, and Cutouts) with the
Squirrel sub-reason dropping drastically in the last year. Overall, WPM is controlling the number of OMT
events. The leading indicator, Miles Follow-up Work Completed, shows we were falling behind in
addressing issues identified during the inspection. If this backlog continues to grow, it will begin to
impact the number of OMT events into the future. We plan to address the backlog by completing more
Distribution Grid Modernization work, increasing funding for the follow-up work and reducing the
number of inspections in 2015.
Metric Description
Projected WPM Contribution To The Annual SAIFI Number
Actual WPM Contribution
To The Annual SAIFI Number
Projected Number of Dist Poles Inspected
Actual Number of Dist Poles Inspected
Material Usage For WPM By Elec Dist Minor Blanket and
Usage For WPM By Elec Dist Minor Blanket and
18524
Metric
Description
Model Predicted Material Use for
WPM Follow-up Work
Material Use for WPM
Follow-up
Projected Number of
Pole Rotten OMT Events
Actual Number of
Pole Rotten OMT Events
Projected Number of
Crossarm OMT Events
Actual Number of Crossarm
OMT Events
7538
7904
28011
28120
15214

Staff_PR_050 Attachment E Page 24 of 73
The KPI “Actual Miles Follow-up Work Completed” provides an indication of what could happen to the
other metrics (see Table 7). Simply inspecting the poles does not improve the systems performance.
The follow-up work to the inspection needs to be completed. This metric shows follow-up work carrying
over into 2013. The driver for WPM is a 20 year inspection cycle and if allowed to fall behind, the WPM
follow-up work could become a major financial issue and reliability risk for future years
Grid Modernization, discussed later in this document, also impacts the same metrics as WPM. In 2012,
we revised the metrics and now include the miles of completed Grid Modernization work in the Table
7since the work is coordinated with WPM and intended to help address the backlog in WPM.
WPM Metric Performance
The annual contribution to SAIFI trend improved in 2013 even further and remains below the five year
average value as shown in Table 8 and Figure 9. Overall, WPM has been effective at maintaining the
current level of reliability to our customers.
The number of Distribution poles inspected measures how well the program is performing against a 20
year inspection cycle. The goal is to inspect every feeder once every 20 years. The work to perform the
wood pole inspections is tracked based on the number of poles inspected. Using miles works, but
different feeders have different pole densities per mile and the way the contractor bills for the
inspection work makes using the number of poles inspected easier. The results of the work exceeded
the planned number of inspections shown in Table 8. The completed inspections are following the AM
plan for WPM very nicely. Other work besides WPM has contributed significantly to the number of
poles inspected annually over the past two years. The Smart Grid project worked on a lot of poles in
2012 that were not part of WPM along with the Transformer Change Out Program.
Figure 10 shows how Avista’s use of Distribution Wood Poles changed with time. This graph supports a
growing number of pole and WPM related issues. Based on poles lasting 74 years before they will be
replaced on a planned basis, Avista would need to replace 3,200 poles per year at equilibrium. We
finally reached and exceeded 3,200 poles per year in 2012, but failed to reach 3,200 poles in 2013.
Figure 11 shows how an increasing number of poles are reaching 74 years. As shown in Table 8, we are
using more material in WPM and the Electric Distribution Minor Blankets to address our aging and
failing equipment. We expect this trend to continue for another 10 years before it stabilizes based on a
model developed in 2012.
WPM Model Performance
The AM model for WPM provided a baseline for estimating the future costs of the follow-up work, but it
under predicted the number of components for Lightning Arresters and Wildlife Guards (see Figure 12).
For our WPM, Lightning Arresters and Wildlife Guards are minor components compared to poles,
Crossarms, and Transformers, so when you ignore these two items, the model performed within the
30% margin. Currently, we don’t plan on updating the model until we have a few more years of data
since this model was completed in 2012.
Staff_PR_050 Attachment E Page 25 of 73
WPM Summary
The main message from the KPI and metrics for WPM is that we are moving in the right direction, but
we are falling behind and will need to complete work on more feeder miles to control the impact on
future reliability.

Staff_PR_050 Attachment E Page 26 of 73

Figure 8, WPM OMT Event Trends
Staff_PR_050 Attachment E Page 27 of 73

Figure 9, WPM Contribution to Annual SAIFI value by Sub-Reason and Year
Staff_PR_050 Attachment E Page 28 of 73

Figure 10, Wood Pole Used by Summarized Activity
Staff_PR_050 Attachment E Page 29 of 73

Figure 11, Distribution Wood Pole Age Profile

0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020
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Wood Pole Age Profile
Staff_PR_050 Attachment E Page 30 of 73

Figure 12, WPM Model Projections vs Actual Usage for 2013
Staff_PR_050 Attachment E Page 31 of 73
Wildlife Guards
Wildlife caused outages have a significant impact on electric service reliability to customers. The
improved outage tracking implemented in 2001 has consistently shown, within a percent or two either
way, that animal’s cause 19% of outages experienced by electric customers. While generally short in
duration, labor impacts to respond are significant. In 2010, Squirrels accounted for only 6% of all
sustained outages (see Table 9) which is a significant drop from 2009 value of 12%. This trend
downward has continued so in 2013 only 2% of sustained outages were caused by Squirrels.
Selected KPIs and Metrics
The goal of the Wildlife Guards program is to reduce the number of Animal caused outages on the
distribution system. More specifically, the program targets reducing the number of squirrel caused
outages. The plan estimates that installing guards on the worst 60 feeders will reduce the number of
Squirrel caused outages by 50%. 2006 was selected as the starting point, because the work performed
that year was not influenced by the current AM plan as seen in Figure 13. The final goal was a 50%
reduction from the 2006 value of 902; however, this year’s value of 215 already exceeds the final goal
and has for the past four years.
The second KPI is the number of Distribution Feeders completed for the Wildlife Guard Installation
program. This KPI measures how effective we were at following the plan. The annual goal for the five
year program was 12 feeders a year but was modified each of the previous years based on available
budget. WPM is also installing wildlife guards as well and is on top of the number included here. The
WPM program does address some of these worst 60 feeders, but is not driven by this program. WPM’s
role in Wildlife Guards is to install them on the remainder of the Distribution system over the next 15
years on transformers or poles they work on for other reasons. Since the number of feeders completed
has nearly reached 60 feeders, Avista will drop this KPI in the near future.
The third KPI used is the percentage of sustained outages caused by Squirrels. This KPI provides a
relative impact that squirrel related outages are having on the system and represents the future value of
installing Wildlife Guards on Distribution Transformers.
The only metric for Wildlife Guards is the annual avoided outage benefit from Squirrel related outages.
We estimate approximately $82 in benefit for every outage avoided starting in 2011. Using this benefit
per event, the projected avoided outage benefit by year is the difference between the projected
number of events and the actual number of events for that year multiplied by the calculated cost per
event for that year (approximately $83). The goals by year for the next two years are shown in Table
10.

Staff_PR_050 Attachment E Page 32 of 73
Table 9, Wildlife KPI Goals for 2010 - 2015
KPI
Description
Number of
Squirrel
Number of
Squirrel OMT
of Feeders
Completed via
of Feeders
Completed via
sustained
outages caused
2009 810 700 12 17 12.2%
2010 720 390 4 23 5.62%
2011 630 395 12 7 3.11%

Table 10, Wildlife Metric Goals for 2010 - 2015
Metric
Description
Projected Avoided Outage Benefit due
to Squirrel Caused Outages
Actual Avoided Outage Benefit due to
Squirrel Caused Outages
2009 $36,000 $47,190
*Note: Avoided costs were revised from $390 per event to $82 for 2011 and 2012 values. This change
was based on a review of costs.
WILDLIFE GUARDS KPI Performance
Installing Wildlife Guards has exceeded expectations so far and has decreased the number of OMT
events for Squirrels. The original model estimated costs were higher than actual costs because the
model assumed more guards would be needed. So, the saved money has been used to work on more
feeders than originally anticipated. Based on Figure 13 and Figure 14, Wildlife Guard installations made
a big jump driven largely by work in Moscow to install the guards on the worst feeders in Avista’s system
for squirrel related outages in 2007. This work had an immediate impact on the number of events in
2008 and 2009. In 2010, the program was funded along with WPM work to install 1017 wildlife guards.
WILDLIFE GUARDS Metric Performance
The main purpose of the Avoided costs metric shown in Table 10 is to demonstrate the savings
associated with the work from the original model. In 2010, Avista saw savings nearly triple the
projected amount. Other work such as Electric Distribution Minor Blanket and WPM continue to install
Wildlife Guards on Distribution Transformers. However, the large increase in savings is most likely due
to the increase in the number of feeders completed in 2010.
Staff_PR_050 Attachment E Page 33 of 73
WILDLIFE GUARDS Model Performance
The Wildlife Guard model over estimated the impact of the work performed (see Table 9), so our
performance has exceeded our expectations. This exceeds the goal of being within +/- 30% of the actual
value. However, since the program has accomplished its purpose, no further work is planned.
WILDLIFE GUARDS Summary
The Wildlife Guard program shows real cost savings over time. The work in WPM and other efforts to
install wildlife guards on Distribution Transformers will create even more savings into the future.
However, continuing a Wildlife Guard installation program is no longer justified. Examining Table 11
shows the current top 10 worst feeders represent 159 outages but only provides an opportunity to save
~$3,500 annually (159 outages * 80% effectiveness * $82/3 years ≈ $3,500 annually). At a cost of
~$360,000 to install Wildlife Guards on ten feeders, we estimate the time to payback the cost of
installation at 100 years. Continuing the program as a separate program no longer justifies future costs
except in localized areas which are identified as having a high concentration of squirrel caused outages.

Table 11, Worst Feeders for Squirrel related Events for 2010 - 2012
Feeder Sustained
Outages
Momentary
Outages
Combined
Outages
of all
Squirrel
related
Running
Percentage
19 0 19 1.79% 1.79%
18 0 18 1.70% 3.49%
17 1 18 1.70% 5.18%
17 0 17 1.60% 6.79%
15 1 16 1.51% 8.29%
16 0 16 1.51% 9.80%
14 1 15 1.41% 11.22%
14 0 14 1.32% 12.54%
13 0 13 1.23% 13.76%
13 0 13 1.23% 14.99%

Staff_PR_050 Attachment E Page 34 of 73

Figure 13, Wildlife Guards Installed by Year and Expenditure Request

Staff_PR_050 Attachment E Page 35 of 73

Figure 14, Wildlife Guards Usage by MAC for 2009-2013
Staff_PR_050 Attachment E Page 36 of 73
URD Primary Cable
URD Primary Cable replacement addresses aging underground primary distribution cable, commonly
referred to as URD (Underground Residential District). URD installation began in 1971. Over 6,000,000
feet of URD was installed before 1982. Outage problems exist on cable installed before 1982, cable
installed after 1982 has not shown the high failure rate of the pre-1982 cable. Programmed
replacement of the problem cable has been on-going at varying levels of funding since 1984. Emphasis
is on the original vintage of URD. That cable was not jacketed with a protective layer of insulating
material, neutral conductor was bare tinned copper concentric type construction on the outside of the
cable. Insulating material was vulnerable to water intrusion. Based on the historical data, we estimated
that approximately 72,000 feet of the pre-1982 cable remains in service as of January, 2013.
Historically, over 200 faults of primary cable happen annually. There have been as many as 264 primary
cable faults in 2003. During 2007 there were 168 primary faults. From 1992 faults increased from 2 per
10 miles of cable to 8 per 10 miles in 2005. The number of faults per mile has stabilized between 2005 –
2007 after steadily climbing between 1992 and 2005.
Funding for URD Primary Cable replacement was significantly increased in 2007 and began the current
program. The program had an original estimate of 5 years to complete but the funding has not matched
the original plan, but almost all of the work was accomplished over six years. The year 2012 represents
the last year of major funding for the program since the number of outages has significantly dropped
and the worst feeder for URD Cable – Pri failures only had two outages. We anticipate some low level of
funding for the remaining cable sections as they fail.
Selected KPIs and Metrics
We selected two KPIs to track for URD Primary Cable replacement, URD Primary OMT Events and
number of feet replaced each year. The goals for each of these KPIs came from the trends observed
over the past few years and set a goal to complete the replacement of URD Primary cable in 2012. The
program continued into 2013 with a smaller budget of $800,000 to help complete the replacement of all
the first generation URD. Table 12 shows the goals for each KPI by year. The OMT events reflect the
impact to our system of past work. The number of feet of URD Primary Cable replaced acts as a
precursor to future OMT performance. After the first generation of URD Primary Cable has been
replaced, the second generation will need to be monitored and plan established for addressing this
vintage of cable.

Staff_PR_050 Attachment E Page 37 of 73

Table 12, URD Cable - Pri KPI Goals
KPI
Description
Projected URD
Cable - Primary
OMT Events
Actual URD
Cable -
Primary OMT
Events
Projected
Number of
Feet Replaced
Actual Number of Feet
Replaced
2009 143 136 178000 213,000
2011 94 95 178000 225,823

The selected metric for URD Primary Cable is the avoided costs due to cable faults. The benefits are
based on a projected number of failures without the program of around 600 events per year. Each
event on average costs ~$2,680 due to the duration of the outage and the number of people involved in
correcting the fault. While this indicator is based on a projection, it provides a reasonable estimate of
the return on investment for the money spent to replace this vintage of cable. Table 13 projects the
anticipated avoided outage benefit by year for the estimated number of avoided outages.
Table 13, URD Cable - Pri Metric Goals
Metric
Description
Projected Avoided Outage
Benefit due to URD Cable - Pri
Caused Outages
Actual Avoided Outage Benefit
due to URD Cable - Pri Outages
2009 $1,038,613 $1,056,113
2010 $1,228,275 $1,295,225
2011 $1,368,561 $1,352,648
2012 $1,516,159 $1,481,504
2013 $1,744,539 $1,494,738
2015 $1,997,052

URD PRIMARY CABLE KPI Performance
For 2012, the performance for URD Primary Cable met expectations and performed well. Table 12
shows that URD Cable – Pri events exceeded expectations. Figure 15 shows a declining trend in the
number of events for the previous four years. Unfortunately, 2013 saw an increase in URD Primary
related OMT events. If this trend continues more analysis will need to be done. The second generation
of URD Primary Cable is also being analyzed. If it begins failing at an increasing rate, it would signal the
next round of cable replacements. We do have some faults in newer cables and anticipate that this will
Staff_PR_050 Attachment E Page 38 of 73
be true for several years to come. If these faults begin to significantly increase over time, we will have
to begin replacement of this cable since the earliest of the second generation cable is now approaching
30 years old.

Figure 15, URD Primary Cable OMT Events by Year

URD PRIMARY CABLE Metric Performance
The projected savings and estimated savings due to avoided outage costs for Avista has typically come in
very close as seen in Table 13. The avoided outage cost for this last year did not perform as well as year
past but overall the current program is performing as expected.
URD PRIMARY CABLE Model Performance
This AM model is an early vintage model and given the cash flow, did not match the model; but it has
generally predicted performance reasonably well. Because of the good performance and limited
remaining time for the program, the model will be retained as is and the program allowed to expire
once all of the first generation URD Primary Cable has been replaced.
Staff_PR_050 Attachment E Page 39 of 73
URD PRIMARY CABLE Summary
Several people have worked hard on this program and it is now nearing completion. We anticipate
another round of URD Cable replacements in the future, but we don’t have any evidence indicating that
we have reached the end of life on the second generation of URD Cable. The program has succeeded in
reducing O&M costs by avoiding long and costly outages. Since all of the work to replace the cable
comes from capital spending, the program is a great example of how capital spending can reduce O&M.
However, operations continue to find more cable than estimated remaining, so future funding is
recommended to only cover planned work on known cable.
URD Secondary Cable
URD Secondary Cable does not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Open Wire Secondary
Open Wire Secondary does not have a planned AM program, so no specific metrics or KPIs have been
identified. While this area covers secondary conductors and connections, OMT does not provide any
direct link to Open Wire Secondary. Previous analysis indicated that this program was not financially
justified. However, future indication may drive us to re-evaluate the situation. We do anticipate that
the Distribution Grid Modernization Program will address many of the Open Wire Secondary OMT
issues. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Distribution Cutouts
Distribution Cutouts are addressed by the WPM program discussed above.
Distribution Air Switches
Distribution Air Switches do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Distribution Mid-Line Reclosers
For the Mid-Line Reclosers, no maintenance or planned replacement is recommended over the next 10
years. Feeder Reclosers are not easily accessible as they are in a substation, so any maintenance on
them is equivalent to a planned replacement. Our analysis indicates that any planned replacement
program is not cost effective for our customers. Further analysis will be performed to ensure this is the
Staff_PR_050 Attachment E Page 40 of 73
correct approach, but until more information is available, no change in our current approach is
recommended.
The Smart Grid work has replaced and installed new Mid-Line Reclosers and switches that now provide
monitoring and remote operations. We have plans to analyze these new devices to determine a
maintenance and replacement strategy specifically for Smart Grid devices.
The general metrics discussed above for number of OMT Events (Table 1) and the associated action
level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a plan
will be developed or if action is needed. In summary, this asset will be monitored to determine if and
when planned actions are needed.
Distribution Mid-Line Voltage Regulators
Avista’s distribution system includes 1,171 Voltage Regulators located in substations and out on the
distribution feeders. The age profile has a large portion of regulators around 30 years old with ~38% of
all voltage regulators being over 30 years old but only 1% greater than 40 years old. When regulators
fail, they will cause an outage 81% of the time and add 0.005 to the overall SAIFI value per event. The
average outage duration for regulator failures is 2.7 hours. On average, 30 to 40 regulators per year
come to the shops for repair, refurbishment, or replacement for a variety of reasons. Some come in
because of failures, but many are brought in because of changes and other work to be refurbished and
re-used. On older voltage regulators, we have also seen that they have higher losses. By replacing them,
Avista could save an estimated $138,000 in energy savings.
AM analyzed four cases in detail in 2010 to find the best program for managing the voltage regulators.
We examined the current case, replacing all the regulators with new regulators at a specific interval,
refurbishing/rebuilding all regulators, and finally replacing the older regulators and refurbishing the
newer regulators. The analysis identified a program that replaces the oldest regulators and refurbishing
the new ones as the best approach to manage the regulators. The replace/rebuild program provides an
8.37% IRR compared to a 5.00% IRR for the base case. The plan will replace an average of 50 Voltage
Regulators per year in the near term, with the newer Voltage Regulators being refurbished when they
reach 35 years old or come in from the field.
Due to a lack of craft resources, this program has not been implemented and remains in a monitoring
state. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine if and when the
plan will be implemented or modified.
Primary Conductors
Primary Conductors do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Staff_PR_050 Attachment E Page 41 of 73
Primary Connections
Primary Connections do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Secondary Conductors
Secondary Conductors do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Secondary Connectors
Secondary Connectors do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Distribution Transformers
In 2011, Avista implemented the Transformer Change Out Program (TCOP) to replace all Distribution
Transformers containing PCB’s followed by replacing all pre-1981 transformers. The driver for the
program is to reduce the environmental risks associated with PCB’s in transformers and improve the
overall electric distribution system by eliminating higher loss transformers.
The program has two strategies associated with it. The first strategy is to eliminate all transformers
containing or potentially containing PCB’s. The initial focus was on areas near water sources and has
now moved to all transformers containing PCB’s as the water regions are done. These transformers
have specific work plans for removing them from the system. The second strategy uses the Wood Pole
Management program to remove all pre-1981 transformers as part of their follow-up work on a feeder.
The first strategy work should be completed in 2016 and the Wood Pole Management work should have
all the pre-1981 transformers replaced by 2036.
Selected Metrics
Table 14 shows the metrics selected for TCOP. The number of transformers changed out represents the
reduction of future risk from PCB’s. It also provides a leading indicator of how many future transformer
failures we may experience. The energy savings represents the value of changing out the less efficient
transformers and quantifies the approximate amount of energy saved each year by replacing less
efficient transformers with more efficient ones.
Staff_PR_050 Attachment E Page 42 of 73
Table 14, TCOP Metrics
Year Number of
Transformers
Actual Number of
Transformers
Changed Out
Savings from
Transformers
Savings from
Transformers
2,687 2,529 2,304 2,430
2,555 2,599 2,304 2,671
2,930 2,304
305
2,030 1,447
2,335
• Note: values in red have negatively missed the goal.

Metric Performance
In 2013, we changed out more transformers than planned and exceeded our planned energy savings.
TCOP is providing the anticipated benefit.
Summary
The TCOP is accomplishing it objectives and reducing Avista’s and customer’s risks associated with
Distribution transformers containing PCB’s and providing energy savings.
Area and Street Lights
Asset Management converted the existing area and street light data into our Geographical Information
System (GIS) in 2012 and will continue the work through 2014. This work will update and correct the
existing information and provide a platform to convert our High Pressure Sodium (HPS) lights to Light
Emitting Diode (LED) fixtures in the future. The recent cost and reliability improvements in LED lights
have made converting lights to LED fixtures cost effective. We anticipate replacing the 100 watt HPS
street lights to LED fixtures starting in 2015. The rate schedule was recently approved for the state of
Washington.
Until a conversion program is implemented, no KPI’s or metrics have been established to monitor area
or street lights.
Riser Terminations
Riser Terminations do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Dead End Insulators
Dead end Insulators do not have a planned AM program outside of work identified as part of Wood Pole
Management, so no specific metrics or KPIs have been identified. The general metrics discussed above
Staff_PR_050 Attachment E Page 43 of 73
for number of OMT Events (Table 1) and the associated action level; Risk Action Curve limits; and
requests by responsible parties will determine in the future if a plan will be developed or if action is
needed. In summary, this asset will be monitored to determine if and when planned actions are
needed.
Distribution Capacitors
Distribution Capacitors do not have a planned AM program, so no specific metrics or KPIs have been
identified. Smart Grid work has added switch capacitors to our system but our initial analysis did not
indicate any maintenance or replacement strategy was justified. The general metrics discussed above
for number of OMT Events (Table 1) along with the associated action level; Risk Action Curve limits; and
requests by responsible parties will determine in the future if a plans are needed. In summary, this
asset will be monitored to determine if and when planned actions are needed.
9CE12F4 Partial Feeder Rebuild
This program was created to integrate several AM programs into a comprehensive program to address
feeder’s issues at one time and then not have to return to the feeder for several years. This program
combined WPM, re-conductoring, transformer replacement and reconfiguration, Wildlife Guards,
Vegetation Management, and other work that fit. While the project created a list of feeders along with
a priority ranking, the only work funded was on Ninth and Central Substation feeder 12F4 in Spokane.
The main drivers for the project were energy savings efficiency for the redesign portion of the work and
integrated AM work to gain labor efficiency.
In 2011, Avista implemented a Feeder Upgrade Program based on this work that will be discussed
below. We retained this program here to provide a place to document the results of the work
competed in 2009.
Selected KPIs and Metrics
Since the program was a one year project, the only metric selected is the number of OMT events
associated with the feeder. No KPI was selected since there are no further actions planned or
anticipated on this feeder. We did not develop an OMT performance metric when the model was
created, but we will monitor the OMT results to see how the work impacted the feeder’s reliability.
Avista’s crews completed the work on the feeder at the end of 2009 along with the WPM inspection and
Vegetation Management work.
Partial Feeder Rebuild KPI Performance
No KPI’s were selected nor tracked for this program.
Partial Feeder Rebuild Metric Performance
Since the work on Feeder 9CE12F4 was completed in 2009, we monitor the OMT data for the feeder to
see how reliability is impacted. Figure 16 shows the trends and shows that the work has made a
significant impact on the feeder’s performance driving the number of OMT events to their lowest levels
in recent records. Along with Figure 16, Figure 17 provides a baseline and trends on specific measures
we anticipated the work would impact. Based on the available OMT data for 2013, the work did impact
Staff_PR_050 Attachment E Page 44 of 73
performance but the real benefit took three years to realize. While weather does impact these
numbers, the impact on equipment failures is clearly improved.

Figure 16, All OMT Sub-Reasons except Maint/Upgrade for Feeder 9CE12F4 2002-2013
Staff_PR_050 Attachment E Page 45 of 73

Figure 17, Selected OMT Trends for AM Related Events with Upward Trends for Feeder 9CE12F4
Partial Feeder Rebuild Model Performance
The model did include some projections for future performance, but we have selected not to evaluate
this model. The actual work performed exceeded the scope of the model, since it included Open Wire
Secondary work. The AM model had predicted a work cost of $1.1 million excluding the following: WPM
inspection costs, Vegetation Management, and Open Wire Secondary work. The total cost of modeled
portion of the project came in at $1.1 million and an additional $1 million of work was added on top of
this. In future models, all of the work will need to factor the lessons learned into the model to improve
costs projections.
Partial Feeder Rebuild Summary
The 9CE12F4 feeder performed very well in 2013, but we anticipate 2014 and 2015 will see more
Vegetation Management issues as the feeder approaches its five year cycle for Vegetation Management
work. Based on previous work on Vegetation Management models, the first year after clearing a feeder
results in some early growth vegetation issues. When a line is cleared, some of the remaining
vegetation is weaker because it no longer has the other branches or vegetation that provided additional
support. This results in some vegetation issues the first year after clearing when the weaker structures
fail under windy or other loading conditions. Usually years 2 and3 between clearings have the lowest
number of vegetation issues and then years 4-5 see a buildup of issues as the next clearing approaches.
Staff_PR_050 Attachment E Page 46 of 73
This will be the last year we report out on this project as it will be included in the Grid Modernization
data going forward.
Chance Cutouts
This program focused on replacing a particular brand of cutout showing signs of premature failure. The
bulk of the work was completed in 2007 and 2008. However, some outlying areas did not participate as
planned with some remaining into 2012. The program and associated funding was spent on replacing
several cutouts in the system and did replace the anticipated number of cutouts. However, an initial
assumption of how many cutouts remain was too low, so the actual number in the field was higher. The
work of WPM and other types of work has effectively eliminated the remaining Chance cutouts. The
future cutout failures will come from all the non-Chance cutouts and should normalize around 150
events per year.
Selected KPIs and Metrics
The goal of the Chance Cutouts was to save money. The KPI selected is the annual projected avoided
outage benefit shown in Table 15. The estimated benefits are quite substantial and anticipated making
a large impact on cutting the number of failures. The only action that can be taken in the future is
through the WPM program, so the KPI and Metrics will be lagging indicators.
The selected metric is the number of OMT events. While normally OMT events are the KPI, it was
selected as the metric since the project was funded with Productivity money and is reported quarterly
as an estimate of the cost savings. Table 15 shows the goals for the number of OMT events under the
“Projected OMT Events w/ Action” column.
Table 15, Chance Cutout Replacement KPI and Metric Goals
Year Projected OMT Events w/o
Action
Projected OMT Events
w/ Action
Projected Annual
Avoided Outage
Benefit
380 91 $654,000
430 78 $671,000
480 106 $665,000
510 80 $640,000
550 152 $579,000
560 152 $524,000
560 152 $524,000

Chance Cutouts KPI and Metric Performance
Although, the number of outages negatively exceeded our goal the annual avoided outage benefit met
the projected benefit. The avoided outage costs were recently updated to current values which explains
how one KPI/metric can be met while the other is not. Two factors appear to be contributing to the
lower than expected results. While the Chance cutouts did remain in the system, a larger portion of the
failures came from all the other cutouts than anticipated. The model appears not to have accurately
Staff_PR_050 Attachment E Page 47 of 73
predicted the number of failures due to other types of cutouts in the early phases of the work.
However, we appear on track to achieve 150 failures a year based on WPM work and Feeder Upgrade
work addressing other issues with cutouts.

Table 16, Chance Cutout KPI and Metric Performance
Year
Projected OMT
Events w/o
Action
Projected
OMT Events
w/ Action
Actual
Number of
OMT Events
Annual
Avoided
Outage
Annual
Avoided
Outage
Model
Error
380 91 197 $654,000 $ 366,000 216%
430 78 217 $671,000 $ 438,780 278%
480 106 176 $665,000 $577,600 166%
510 80 209 $640,000 $583,338 261%
550 152 171 $579,000 $749,192 113%
560 152 $524,000
570 152 $524,000
• Note: values in red have negatively exceeded the goal.

Figure 18, Cutout/Fuse OMT Event Comparison between Actual, Projected without Action, and Projected with Action
Staff_PR_050 Attachment E Page 48 of 73
Chance Cutouts Model Performance
The model performance for Chance Cutouts provided a good indication of the trends but failed to
accurately predict the trends. The model for future cutout analysis will need to be updated and
improved to better predict future trends. The method of completing the work also caused the actual
values to deviate from the model. The differences in actual work compared to projected mainly comes
from the number of Chance Cutouts remaining in the system was more than anticipated as an
assumption. Another contributing factor comes from the worse than expected performance of other
cutouts. The model, however, for Chance Cutouts will not be changed since the bulk of the work is
complete and any remaining work is to be picked up by WPM.
Chance Cutouts Summary
In summary, the Chance Cutout replacement program has succeeded in reducing the number of failures
due to this type of cutout. While it has not created the savings originally hoped for, the program
continues to save Avista a significant amount of money each year.
Distribution Vegetation Management (VM)
Our Vegetation Management program maintains the distribution system clear of trees and other
vegetation. This reduces outages caused by trees and to a lesser extent squirrel caused outages. Our
Distribution System runs for 7,793 circuit miles in Washington, Idaho, and Montana. The Vegetation
Management program does cover work on the Transmission System and the High Pressure Gas Pipeline
system, the purpose here is to only look at the Distribution System.
For the Distribution System, our analysis has shown that a pro-active maintenance program provides the
best value to our customers. While our past practices were a four and seven year cycle based on
vegetation type and had a reduced clearing diameter, our analysis has indicated a five year clearing cycle
at a normal clearing distance has advantages.
The purpose of Vegetation Management is to meet regulatory compliance, provide the best value to our
customers, and maintain current reliability. The Vegetation Management program continues herbicide
spraying and enlarged the risk tree programs to further improve vegetation management. Both of these
additions strive to improve the performance of the system by reducing vegetation related events.
Selected KPIs and Metrics
For Vegetation Management (VM), we selected one leading KPI and a lagging KPI. The leading KPI is the
number of Distribution Feeders miles managed each year. This indicates how well the actual work
matches the planned work and the model. The results of the work in VM should directly impact the
number of Tree Growth and Tree Fell events in OMT which is the lagging KPI. The number of Tree
Growth events and Tree Fell events are summed for each year and compared to the AM models
predictions if the plan is followed. The goals for each KPI by year are shown in Table 17. The AM model
for Tree Growth events and Tree Fell events shows varying KPI’s for each year due to the strict following
of the 5 year cycle based on when the feeder was last done. For a VM metric, we selected the number of
Tree-Weather OMT events by year and SAIFI impacts. As seen in Figure 19, there is a relationship
Staff_PR_050 Attachment E Page 49 of 73
between weather events and VM. We assume that improvements in VM results should impact the
number of Tree-Weather OMT events and set a goal shown in
Table 18. The goal for Tree-Weather events is based on the AM models average value over a 10 year
period. This metric was not included as a KPI, because weather events are very unpredictable and
random in nature. Once the relationship has been better established, it may become a KPI.
Another metric selected for monitoring is the cost per mile for VM on the distribution feeders. While no
goals have been established, this will measure how effective our AM spending gets the work done and
how much work is required to clear the lines. The costs per mile should drop in future years, because
the amount of work required to clear them should drop after reaching a 5 year cycle. Inflation and other
escalators will drive costs up in the future to counter the reduced workload, but the net effect remains
undetermined. The total number of miles of all planned work was modified in 2011. Beginning in 2011,
the costs per mile calculation includes all planned work and not just the miles cleared. So, the total
number of miles for all planned work was included in the metrics.
Table 17, Vegetation Management KPI Goals
KPI
Description
Miles of Vegetation
Management Completed
OMT Events due to
Tree Fell + Tree Grow
2009 1,560 556
2010 1,560 540
2011 1,560 500
2012 1,560 520
2013 1,560 630
2014 1,560 780
2015 1,560 845

Table 18, Vegetation Management Metric Goals
Metric
Description
OMT Events due
to Tree-Weather
SAIFI -
Tree Fall
SAIFI - Tree
Grow
SAIFI - Tree
Weather
2009 166 1.40E-07 8.84E-08 1.34E-05
2010 166 1.40E-07 8.84E-08 1.34E-05
2011 166 1.40E-07 8.84E-08 1.34E-05
2012 166 1.40E-07 8.84E-08 1.34E-05
2013 166 1.40E-07 8.84E-08 1.34E-05
2014 166 1.40E-07 8.84E-08 1.34E-05
2015 166 1.40E-07 8.84E-08 1.34E-05

Staff_PR_050 Attachment E Page 50 of 73
VM KPI Performance
Both Figure 19 and Figure 20 show the same trends for Tree Growth, Tree Fell, and Tree Weather. The
number of OMT events due to Tree Growth and Tree Fell were below the 10 year average and above the
five year cycle projections. The number of miles completed in VM will cause the number of events in
the future to continue to grow and exceed projected five year cycle values. Table 19 shows the results.
The number of OMT events remains above the values for 5 year cycle plan but less than the 2009 plan.
We did clear enough miles in 2011 to exceed a five year cycle but slipped back to less than a five year
cycle in 2012 and 2013. Until we have a well entrenched five year cycle, we will continue to realize
more vegetation related events than projected by the five year cycle plan. However, we do see the
number of events improving and nearly cleared enough miles in 2013 to align with a five year cycle.
Table 19, VM KPI Performance
Year
Projected Tree
Growth + Tree
Fell OMT
Events – 2009
Plan (Current)
Projected Tree
Growth + Tree
Fell OMT
Events – 5
Year Cycle
Actual
Number
of OMT
Events
Projected
Annual
Miles
Managed
Annual
Miles
Managed
w/o Risk
Tree or
Percent
Model
Error*
2009 1120 556 1,220 790
2010
2011 790 500 1,560 1,747
2012 1210 520 1,560 1,296
2013 1390 630 1,560 1,459
2014
• Note: values in red have negatively exceeded the goal
• * This model error is for the current plan model and not the 5 year cycle model

Staff_PR_050 Attachment E Page 51 of 73

Figure 19, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons

Staff_PR_050 Attachment E Page 52 of 73

Figure 20, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons
VM Metric Performance
The Tree-Weather OMT Events for 2013 continued to show improvement and were below the AM
model projects (see Table 20). We must update the Vegetation Management models before we have
better projections.
The cost per mile for VM in 2013 was $1,657. We need to update the Vegetation Management model to
address changes in the program which will help understand the impact to our system. Table 21 shows
the current information.

Staff_PR_050 Attachment E Page 53 of 73
Table 20, Tree-Weather OMT Events Metric for Vegetation Management
Year
Projected Tree-Weather
OMT Events – 2009 Plan
(Current)
Weather OMT
Events – 5 Year
Cycle
Actual Number of
Tree-Weather OMT
Events
Percent Model
Error
420 166 357 85%
80 50 895 -
220 70 325 148%
580 70 314 54%
800 170 216 27%
1120 430
• Note: values in red have negatively exceeded the goal.

Table 21, VM Cost per Mile and All Vegetation Management Work Metric
Year Actual Annual Miles
Managed all work Cost per Mile of VM
N/A $6,575
N/A $2,990
3,455 $2,612
3,364 $3,272
4,014 $1,657

VM Model Performance
The AM model for Distribution VM was revised in 2010, but the recent changes to the work performed
and errors experienced justify updating the model. We anticipate completing the update in 2015.
VM Summary
Depending on how you evaluate the program, VM is currently not getting enough miles completed each
year to achieve the goal of a 5 year cycle. The costs per mile may be too high and/or the current funding
levels are too low and the impacts of herbicide spraying and enhanced risk tree work modify the
meaning of work per mile. Vegetation Management’s performance does show continued improvement
but further analysis will provide an opportunity to re-evaluate our current performance and update
future expectations.
Distribution Grid Modernization Program
Avista initiated a Grid Modernization Program designed to reduce energy losses, improve operation, and
increase the long-term reliability of its overhead and underground electric distribution system. The
program includes replacing poles, transformers (Pad Mount, OH & Submersible), cross arms, arresters,
Staff_PR_050 Attachment E Page 54 of 73
air switches, grounds, cutouts, riser wire, insulators, conduit and conductors in order to address
concerns related to age, capacity, high electrical resistance, strength, and mechanical ability. The
program also includes the addition of wildlife guards, smart grid devices, switched capacitor banks,
balancing feeders, removing unauthorized attachments, replacing open wire secondary, and
reconfigurations.

When funded to a level that allows 5-6 feeders to be upgraded per year, the continuous program
represents a 60 year interval to upgrade all the feeders in Avista’s system and coordinates all of its
activities with Avista’s Wood Pole Management. The objectives of the Grid Modernization Program are
listed in Table 22.

Table 22, Grid Modernization Program Objectives
Objective Objective Description
Safety Focus on public and employee safety through smart design and work practices
Reliability Replace aging and failed infrastructure that has a high likelihood of creating a need
for unplanned crew call-outs
Avoided Costs Replace equipment that has high energy losses with new equipment that is more
energy efficient and improve the overall feeder performance
Operational
Ability
Replace conductor and equipment that hinders outage detection and install
automation devices that enable isolation of outages
Capital Offset Avoid future equipment O&M costs with programmatic rebuild of failing system

Selected Metrics
Since the program originally began as a Feeder Upgrade Program and has since grown in scope to be a
Grid Modernization Program; the selected KPI’s may not be valid anymore. The metrics selected include
miles of work completed, OMT sustained outages on feeders with Feeder Upgrade work completed, and
energy savings provided by completed work.
Based on Avista’s 2013 Integrated Resource Plan dated August 31st, 2013, Table 5.3 and Table 5.4, the
realized and anticipated energy savings by identified feeders is shown in Table 23. From Table 24, we
calculated that the power saved per mile of work is 1.38 kW.

Staff_PR_050 Attachment E Page 55 of 73
Table 23, Energy Savings based on 2013 Integrated Resource Plan
Feeder Energy Savings (MWH) OH Circuit Miles
NE12F3 115 13.09062
RAT231 91 52.25448
OTH502 21 0.783542
M23621 151 28.388
DVP12F2 35 39.1079
HAR4F1 69 12.0028
BEA12F3 167 9.854272
FWT12F3 121 10.5042
TEN1255 249 12.27521
ROS12F1 267 18.93558
SPI12F1 162 91.80389
TUR112 101 24.33467
9CE12F4 601 17.04767
WIL12F2 1403 105.5954
BEA12F1 972 24.80689
F&C12F2 570 20.6956
BEA12F5 885 15.66515
TUR113 76 5.098

Total 6056 502.2438
KW per Mile 1.376471

The miles of work planned is ultimately driven by the approved budget and generally can only be
projected for 5 years. In order to maintain a 60 year cycle, Avista would need to address an average of
137 miles per year of overhead circuit miles. This would result in an average of 188 kW of power savings
each year.
For tracking the impacts of the work on outages, we will monitor the following OMT sub-reasons shown
in Table 25. While the Grid Modernization will affect all of the sub-reasons listed in Table 25, the sub-
reasons identified as potentially avoidable represent the most direct impact of the work. So we assume
that the number of OMT sustained outages will be reduced by 0.1 outages per mile of overhead work
completed. Based on the data shown in Figure 21, the average number of OMT events that could
potentially been avoided over the last 5 years is 773. Dividing 773 outages by the number of circuit
miles yields 0.1 outages avoided per mile of work. So, the annual anticipated number of OMT sustained
outages will be the average value of outages minus the number of OMT outages avoided by performing
the work.

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Table 24, OMT Sub-Reasons impacted by Grid Modernization
OMT Sub-Reason Potentially Avoidable
Arrester Yes
Capacitor Yes
Conductor - Pri Yes
Conductor - Sec Yes
Connector - Pri Yes
Connector - Sec Yes
Cross arm - rotten Yes
Cutout/Fuse Yes
Elbow Yes
Insulator Yes
Insulator Pin Yes
Lightning No
Pole Fire No
Pole - rotten Yes
Recloser Yes
Regulator Yes
Snow/Ice No
Switch/Disconnect Yes
Transformer - OH Yes
Transformer UG Yes
Undetermined No
Weather No
Wildlife Guard Yes

Staff_PR_050 Attachment E Page 57 of 73
Figure 21, OMT Sustained Outages related to Grid Modernization

0
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2000 2005 2010 2015
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b
e
r

o
f

S
u
s
t
a
i
n
e
d

O
u
t
a
g
e
s

Year
OMT Sustained Outages related to Grid
Modernization Number of Grid Modernization Related Sustained outages Average
Std Dev - Low Potentially Avoidable Outages
Staff_PR_050 Attachment E Page 58 of 73
Metric Performance
The results of the first two years work are shown in Table 25. The year 2012 marks the beginning of the
program. The number of miles actually completed missed the goal of 137 and the energy savings fell
short of its goal as well. We will continue with the program as allowed by the budgets and continue to
monitor the results for a few more years before considering any significant changes to the plan.
Table 25, Metric Performance for Grid Modernization Program
Year for
Modernization
Actual Miles
Completed
(Miles)**
Power
Savings
Power
Savings
Number of
Sustained
Number of
Sustained
95 73.33 127 150 2340 2331
137 53.83 188 150 2327 2665
137 188 2313
137 188 2300
137 188 2286
137 188 2272
*Note: The planned or anticipated values may be modified to match approved work plans for each year
that more accurately align with the actual work planned.
**Data from Grid Modernization Group
Summary
The Grid Modernization Program began in earnest in 2012 and represents feeder replacement work and
upgrades founded on smart grid work. We need to examine a few more years’ worth of data before
drawing any conclusions.
Conclusion
In this report, we documented and examined the KPIs and metrics AM selected for the Distribution
system and provided the results for 2013. Some of the metrics compared how an asset performed with
a program and how it would have performed without a program. The difference in performance provide
an estimate of the cost saving and value of an AM program. While the exact savings are impossible to
calculate in most cases, it provides a relative comparison and supporting justification or motivation for
change in AM decisions made in the past. Other KPIs and metrics provided indications of how well an
asset performed and help determined if further work is required. Some AM models clearly need more
work to better predict future conditions and will be scheduled in the future if it makes sense.

Staff_PR_050 Attachment E Page 59 of 73
Distribution Vegetation Management
2013 Washington RIT732

WAK12F1

NW13T23

DRY1208

DRY1209

GAR461

HAR4F1

HAR4F2

KET12F1

SPU125

SPU124

SPU123

SPU122

MIL12F1

SPA442

CLV34F1

RIT731

RDN12F2

RDN12F1

PAL312

MIL12F2

MIL12F3

MIL12F4

PAL311

NW12F1

NW12F2

NW12F3

NW12F4

SPU121

WAK12F3

3HT12F2

3HT12F3

3HT12F4

3HT12F5

3HT12F6

3HT12F7

3HT12F8

9CE12F1

9CE12F2

9CE12F3

9CE12F4

ARD12F1

WAK12F4

CLV12F4

C&W12F3

CLV12F3

CLV12F2

CLV12F1

C&W12F6

C&W12F5

3HT12F1

C&W12F4

BKR12F1

C&W12F2

C&W12F1

WAK12F2

BKR12F3
Idaho

STM631

OSB522

STM633

STM632

BLU321

BIG411

M23621

BIG413

NMO522

COT2401

COT2402

HUE141

HUE142

LKV341

LKV342

M15515

BIG412

LKV343

NMO521

M15514

M15513

M15512

M15511

LKY551

Staff_PR_050 Attachment E Page 60 of 73
2014 Washington LAT421

WAS781

SUN12F1

LIN711

ORI12F1

ORI12F2

ORI12F3

LAT422

SUN12F2

SUN12F3

SUN12F4

SUN12F6

WIL12F1

WIL12F2

KET12F2

EFM12F2

SUN12F5

DIA232

DEP12F1

DEP12F2

DIA231

EFM12F1

BKR12F2

H&W12F2

H&W12F1

ARD12F2
Idaho

CDA121

TEN1256

JUL661

TEN1257

TEN1254

TEN1253

CDA122

CDA123

CDA124

CDA125

TEN1255

OSB521

SPL361

BLA311

LOL1359

OLD721

OLD722

OGA611

PF211

PF212

PRV4S40

SLW1316

SLW1348

SLW1358

SLW1368

Staff_PR_050 Attachment E Page 61 of 73
2015 Washington BEA12F1

BEA12F3

F&C12F1

BEA12F2

LL12F1

NE12F2

NE12F3

NE12F4

BEA12F4

ODS12F1

HOL1205

OPT12F1

OPT12F2

NE12F5

F&C12F2

BEA12F5

BEA12F6

BEA13T09

HOL1206

GIF34F1

FOR12F1

F&C12F6

F&C12F5

F&C12F4

F&C12F3

PDL1201

SPI12F2

HOL1207

SOT521

NE12F1

VAL12F3

VAL12F2

TKO412

SLK12F3

SPR761

PDL1202

SLK12F2

SLK12F1

SIP12F5

PDL1204

SIP12F3

SIP12F2

SIP12F1

RSA431

PDL1203

PST12F1

SIP12F4

TKO411
Idaho

DER651

APW111

APW112

APW113

APW114

APW115

AVD152

CKF712

AVD151

APW116

WAL544

DER652

WAL545

N131222

WAL543

WAL542

SAG742

PF213

N131321

LOL1266

JUL662

JPE1287

IDR253

IDR252

WEI1289

IDR251

Staff_PR_050 Attachment E Page 62 of 73
2016 Washington L&S12F3

SE12F2

SE12F1

ROX751

ROK451

MLN12F2

LOO12F2

LOO12F1

L&S12F4

L&S12F1

L&S12F2

SE12F3

L&S12F5

SE12F4

SE12F5

SOT522

SOT523

SPI12F1

L&R511

TUR115

TUR111

TUR116

TUR117

TVW131

TVW132

VAL12F1

TUR112

CHE12F2

TUR113

AIR12F1

AIR12F2

AIR12F3

CFD1210

CFD1211

CHE12F1

CHE12F3

CHE12F4

CLA56

EWN241

FOR2.3

GIF34F2

INT12F2

INT12F1
Idaho

SPT4S21

KOO1298

CGC331

RAT231

KAM1292

KAM1291

KAM1293

KOO1299

SPT4S30

SPT4S22

DAL131

RAT233

SAG741

DAL134

SPT4S23

DAL132

GRV1274

GRV1271

CKF711

GRV1272

GRV1273

DAL133
Montana

NRC352

Staff_PR_050 Attachment E Page 63 of 73
2017 Washington LIB12F4

LIB12F2

LIB12F3

LIB12F1

LF34F1

LEO612

LEO611

MEA12F1

GRN12F3

L&R512

MEA12F2

MLN12F1

OTH501

OTH502

OTH503

OTH505

ROS12F1

ROS12F2

ROS12F3

ROS12F4

ROS12F6

GRN12F2

DVP12F1

ROS12F5

COB12F1

CHW12F1

CHW12F2

ECL221

CHW12F4

GRN12F1

COB12F2

DVP12F2

GLN12F2

CHW12F3

ECL222

FWT12F1

GLN12F1

FWT12F4

FWT12F3

FWT12F2
Idaho

PRA222

PVW241

PRA221

BUN426

PIN441

BUN424

BUN423

BUN422

WOR471

SWT2403

WIK1278

WIK1279

PVW243

POT322

POT321

PIN442

ORO1282

ORO1281

ORO1280

ODN732

ODN731

NEZ1267

MIS431

CRG1260

CRG1261

CRG1263

PIN443

Staff_PR_050 Attachment E Page 64 of 73
Distribution Wood Pole Management
WA
2013
Office Feeder
SPO 3HT 12F1 4.56 237
SPO 3HT 12F3 3.22 167
SPO 3HT 12F5 7.67 399
SPO 3HT 12F6 3.2 166
SPO 3HT 12F7 4.67 243
SPO 3HT 12F8 1.07 56
PCB TR's
SPO C&W 12F2 7.4 444
SPO C&W 12F3 7.16 430
SPO C&W 12F4 5.65 339
SPO C&W 12F5 8.94 536
SPO C&W 12F6 12.9 774
SPO NW 12F1 16.29 977
SPO NW 12F2 11.8 708
SPO NW 12F3 13.52 811
SPO NW13T23 0.94 56
COL SPI12F1 90.32 1626
COL GIF 34F1-SEC.3 58 1034
OTH WAS 781 34.68 506

9,510

ID

PCB TR's
CDA APW112 13.09 759
CDA LKV341 0.8 44
CDA LKV342 2.6 59
CDA LKV343 9.14 188
PAL M23621 28.33 659
SDPT SAG741 52.21 1,566

3,275

Staff_PR_050 Attachment E Page 65 of 73
2014
WA Office Feeder OHM Est.# Poles
SPO NW12F3 13.52 811
SPO WAK12F2 13.21 766
SPO NW12F4 14.45 874
COL GIF 34F1-SEC 4 58 1,034
SPO AIR12F3 7.6 228
SPO L&S12F1 3.25 195
SPO L&S12F2 18.62 1,117
SPO L&S12F3 3.22 193
PAL GAR461 46.81 1,239
SPO L&S12F4 6.24 374
SPO L&S12F5 5.48 329

7,160
ID Office Feeder
CDA APW113 8.04 466
CDA APW111 11.67 537
CDA RAT233 58 1,830
LEW LOL1266 31.07 932
LEW LOL1359 27.43 823
SDPT SAG741 52.17 1,566
SDPT SAG742 29.4 882

7,036

Staff_PR_050 Attachment E Page 66 of 73

2015
WA Office Feeder OHM Est.# Poles
OTH SOT522 36.1 738
DPK MLN12F1 44.3 1,329
DPK MLN12F2 38.67 1,154
DPK CLA56 2 40
OTH SPR761 55.79 918
PAL TUR112 37.73 1,321
SPO NE12F1 12.5 749
SPO NE12F2 3.8 225

6,474
ID Office Feeder Est.# Poles
LEW N131222 19.21 672
CDA IDR252 10.34 414
LEW LOL1359 27.43 823
LEW ORO1280 9.51 396
CDA APW115 1.48 68
CDA APW114 1.9 108
SDPT SDPT4S23 20.88 835
3,316

Staff_PR_050 Attachment E Page 67 of 73
2016 WA Office Feeder Est.# Poles
SPO NE12F4 18.1 861
SPO H&W12F2 66.86 2,006
SPO H&W12F1 0.24 7
SPO CHE12F1 16.3 650
SPO CHE12F2 13.3 531
SPO CHE12F4 17.5 699
PAL ROK451 21.6 757
SPO SE12F3 7.8 374
OTH OTH501 9.4 330
OTH OTH503 0.3 6
OTH OTH505 0.7 26
SPO F&C12F3 9.6 411

6,658
ID
Office Feeder Est.# Poles
CDA APW116 7.37 353
CDA IDR251 7.1 285
SDPT SPT4S22 11.2 449
SDPT SPT4S30 17.3 694
PAL JUL661 15.0 335
PAL JUL662 25.9 510
LEW JPE1287 19.6 490
KEL PIN441 19.3 545
CDA PVW243 1.8 81
3,742

Staff_PR_050 Attachment E Page 68 of 73

2017
WA Office Feeder OHM Est.# Poles
SPO F&C12F4 20.4 875
SPO F&C12F6 12.8 552
SPO F&C12F1 21.5 924
COL CHW12F1 0.5 13
COL CHW12F4 61.9 2,228
SPO LIB12F2 38.6 1,352
SPO LIB12F4 2.1 74
PAL TUR116 27.1 948

6,966
ID
Office Feeder OHM Est.# Poles

Staff_PR_050 Attachment E Page 69 of 73

2018
WA Office Feeder OHM Est.# Poles
SPO GLN12F1 22.1 884
SPO 9CE12F1 12.6 518
SPO 9CE12F2 16.5 674
SPO 9CE12F3 9.8 403
SPO BEA12F2 21.2 955
SPO BEA12F4 6.8 304
SPO BEA12F6 10.5 474
SPO BEA13T09 1.2 52
DAV FOR12F1 70.9 1,488
DAV FOR2.3 0.2 5
PAL LEO612 21.6 832
SPO ROS12F2 6.6 404

6,993
ID
Office Feeder OHM Est.# Poles

Staff_PR_050 Attachment E Page 70 of 73

2019
WA Office Feeder OHM Est.# Poles
SPO ROS12F1 18.44 1,125
SPO ROS12F3 11.3 698
SPO ROS12F4 5.6 341
SPO ROS12F5 12.6 769
SPO ROS12F6 14.5 883
SPO FWT12F2 12.0 721
SPO FWT12F4 15.0 900
SPO INT12F1 1.4 49
SPO INT12F2 24.9 871
SPO WAK12F1 15.6 933
SPO WAK12F3 7.0 422
SPO WAK12F4 13.3 798
SPO OPT12F1 7.0 418
SPO OPT12F2 2.4 146

9,074
ID
Office Feeder OHM Est.# Poles

Staff_PR_050 Attachment E Page 71 of 73
Grid Modernization

2015 Grid Modernization Plan Feeder Design Constr State Region Area
BEA12F1 x WA West Spokane
M23621 x x ID South Pullman/Mosc
MIL12F2 x WA West Spokane
ORO1280 x ID South Grangeville
OTH502 x WA West Othello
RAT231 x ID East Coeur d'Alene
RAT233 x ID East Coeur d'Alene
SPI12F1 x x WA West Colville
SPR761 x WA West Othello
TUR112 x WA South Pullman/Mosc
WAK12F2 x WA West Spokane
WIL12F2 x WA West Davenport
ER 2570 Sandpoint Grid Mod x x ID East Sandpoint

2016 Grid Modernization Plan Feeder Design Constr State Region Area
2015 Carryover x x
MIL12F2 x x WA West Spokane
ORO1280 x x ID South Grangeville
PDL1201 x WA South Lewiston/Clark
RAT233 x x ID East Coeur d'Alene
SPI12F1 x WA West Colville
SPR761 x WA West Othello
TUR112 x WA South Pullman/Mosc

2017 Grid Modernization Plan Feeder Design Constr State Region Area
2016 Carryover x x
F&C12F1 x WA West Spokane
M15514 x ID South Pullman/Mosc
MIL12F2 x WA West Spokane
PDL1201 x WA South Lewiston/Clark
RAT233 x ID East Coeur d'Alene
SPI12F1 x WA West Colville
SPR761 x x WA West Othello
TUR112 x WA South Pullman/Mosc

Staff_PR_050 Attachment E Page 72 of 73
Transformer Change-Out Program

Row Labels Count of STENCIL
Grand Total 31,894

Staff_PR_050 Attachment E Page 73 of 73