20160526Rosentrater Exhibit 7.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-16-03
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) EXHIBIT NO. 7
TO ELECTRIC CUSTOMERS IN THE )
STATE OF IDAHO ) HEATHER L. ROSENTRATER
)

FOR AVISTA CORPORATION

(ELECTRIC)

Electric kwh
Schedule No. of Customers (000s)% of Total kwh
Residential Sch. 1 104,621 1,124,033 37%
General Sch. 11&12 21,154 366,126 12%
Lge. General Sch. 21&22 1,157 706,267 23%
Ex. Lge. General Sch. 25 8 316,352 10%
Ex. Lge. General Sch. 25P 1 450,717 15%
Pumping Sch. 31&32 1,437 66,287 2%
Street & Area Lights 148 14,189 0%
128,526 3,043,971 100%
Customer Usage
State of Idaho - Electric
As of December 31, 2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 1, Page 1 of 1

2016
Mary Jensen, Rubal 
Gill 
Asset Management      
Avista Corp. 
02‐01‐2016 
Electric Transmission System
2016 Asset Management Plan
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 1 of 61
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 2 of 61

3 2016 Electric Transmission System Asset Management Plan 
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Table of Contents
Purpose ................................................................................................................................................................... 6 
Executive Summary ................................................................................................................................................. 6 
Assets ...................................................................................................................................................................... 9 
Key Performance Indicators (KPIs) ........................................................................................................................ 11 
Capital Replacement and Maintenance Investment ............................................................................................. 13 
Process Capability ................................................................................................................................................. 20 
Risk Prioritization .................................................................................................................................................. 20 
Unplanned Spending ............................................................................................................................................. 24 
Outages ................................................................................................................................................................. 26 
Programs ............................................................................................................................................................... 30 
1.  Major Rebuilds ............................................................................................................................................. 30 
2.  Minor Rebuilds ............................................................................................................................................. 31 
3.  Air Switch Replacements .............................................................................................................................. 32 
4.  Structural Ground Inspections (Wood Pole Management) .......................................................................... 36 
5.  Structural Aerial Patrols ............................................................................................................................... 37 
6.  Vegetation Aerial Patrols and Follow‐up Work ............................................................................................ 37 
7.  Fire Retardant Coatings ................................................................................................................................ 38 
8.  230kV Foundation Grouting ......................................................................................................................... 39 
9.  Polymer Insulators ........................................................................................................................................ 39 
10.  Conductor & Compression Sleeves ............................................................................................................ 40 
Program Ranking Criteria .................................................................................................................................. 40 
Benchmarking ....................................................................................................................................................... 41 
Data Integrity ........................................................................................................................................................ 45 
Material Usage ...................................................................................................................................................... 47 
Root Cause Analysis (RCA) .................................................................................................................................... 47 
System Planning Projects ...................................................................................................................................... 48 
Area Work Plans .................................................................................................................................................... 52 
References ............................................................................................................................................................. 56 

Figure 1:  Example Transmission Asset Components and Expected Service Life .................................................. 10 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 3 of 61

4 2016 Electric Transmission System Asset Management Plan 
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Figure 2:  Transmission and Distribution System Replacement Values, Average Service Life, and Levelized 
Replacement Spending ......................................................................................................................................... 14 
Figure 3:  Replacement Cost vs. Remaining Service Life ....................................................................................... 15 
Figure 4:  2014 Planned Capital, O&M, and Emergency Spending ....................................................................... 18 
Figure 5:  30‐year Transmission Planned Capital and Maintenance Recommendations ...................................... 19 
Figure 6:  115kV and 230kV Total Unplanned Capital Spending ........................................................................... 25 
Figure 7:  Transmission outage causes affecting customers in 2015 .................................................................... 30 
Figure 8:  Air Switch Replacement Value vs. Remaining Service Life .................................................................... 34 
Figure 9:  3‐year Transmission Lines Replacement Capital Spending per Asset  (First Quartile Consulting, 2008)
 ............................................................................................................................................................................... 42 
 Figure 10:  Idaho Power Long‐term Replacement Costs ...................................................................................... 44 
Figure 11:  Maintenance Benchmarking: Aerial Patrols (left) and Pole Inspections (right) .................................. 45 

Table 1:  Primary Assets of the Electric Transmission System – Circuits ................................................................ 9 
Table 2:  Component Assets and Quantities ........................................................................................................... 9 
Table 3:  Transmission Structures and Poles ......................................................................................................... 10 
Table 4:  115kV vs 230kV Pole Materials .............................................................................................................. 11 
Table 5:  Transmission KPIs and Unity Box Metrics ............................................................................................... 12 
Table 6:  Additional Performance Measures, 2010‐2015 ..................................................................................... 13 
Table 7:  Levelized Replacement Spending Options ............................................................................................. 16 
Table 8:  2015 Transmission Spending .................................................................................................................. 17 
Table 9:  2015 Planned Capital Projects (Non‐Reimburseable) ............................................................................ 17 
Table 10:  30‐year Planned Capital and O&M Recommendations ........................................................................ 19 
Table 11:  Probability Index Criteria and Weightings ............................................................................................ 21 
Table 12:  Consequence Index Criteria .................................................................................................................. 22 
Table 13:  Top 20 Most at Risk Circuits according to the Reliability Risk Index .................................................... 23 
Table 14:  Transmission Unplanned and Emergency Spending, 2006 ‐ 2015 ....................................................... 25 
Table 15:  Transmission lines with the most unplanned outages in 2014 ............................................................ 27 
Table 16:  Transmission lines that caused the most customer hours lost in 2015 ............................................... 27 
Table 17:  Transmission Lines causing the most customer outages greater than 3 hours in 2015 ...................... 28 
Table 18:  Transmission Outage Causes, 2009‐2015 ............................................................................................. 29 
Table 19:  Major Rebuild Projects, 2016 – 2020 ................................................................................................... 31 
Table 20:  Minor Rebuild and Switch Upgrade Budget, 2016 – 2020 ................................................................... 32 
Table 21:  Airswitch Priority List for Repairs and Replacements .......................................................................... 35 
Table 22:  Program Ranking Criteria ..................................................................................................................... 41 
Table 23:  Avista Transmission Lines Replacement Capital Spending per Asset ................................................... 43 
Table 24:  Transmission Asset Data Integrity ........................................................................................................ 46 
Table 25:  Relative Material Purchases, 10/2010 – 10/2012 ................................................................................ 47 
Table 26:  Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) ...................................... 49 
Table 27:  Corrective System Planning Projects (Palouse, Spokane and System) ................................................. 50 
Table 28:  Non‐Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) .............................. 51 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 4 of 61

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Table 29:  Non‐Corrective System Planning Projects (Palouse, Spokane and System) ......................................... 52 
Table 30:  Project Type Key ................................................................................................................................... 53 
Table 31:  Area Work Plans – Major Projects ........................................................................................................ 54 
Table 32:  Minor Rebuilds ..................................................................................................................................... 55 
Table 33:  Ground Inspection Plan ........................................................................................................................ 55 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 5 of 61

6 2016 Electric Transmission System Asset Management Plan 
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Purpose 
System asset management plans are meant to serve a general audience from the perspective of long‐term, 
balanced optimization of lifecycle costs, performance, and risk management.  The intent is to help the reader 
become rapidly familiar with the system’s physical assets, performance, risks, operational plans, and primary 
replacement and maintenance programs.  Consistent annual updates of this plan provide the continuity 
required for useful historical information and continuous improvement of asset management practices. 
For easy reference, a “Quick Facts” sheet is used to highlight key information and recommendations of this 
system‐level asset management plan.  At the individual program and project level, additional “Quick Facts” 
sheets may also be available.  For more details, please visit the Asset Management Sharepoint site at Asset 
Management Plans.  This update reflects the best available information as of December 31, 2015.   
Executive Summary 
Consistent with last year’s assessment, the primary message of this asset management plan is that the 
company must commit itself to sustainably replace the bulk of the aging transmission system over the next 
three decades.   This is essential to achieve the company’s strategic objectives of maintaining reliability levels 
while minimizing total lifecycle costs, requiring over $624 million in capital replacement investment.  As this 
represents a significant increase in capital investment as well as internal and external workloads from recent 
years, success demands strong company support and management.  In order to be most effective and 
beneficial to customers and the company, it also requires fact‐based prioritization and targeting of available 
funds to the riskiest elements of the system.  
Key performance indicators (Table 5) for the transmission system showed results lower than targeted for 2015.  
Completed ground inspections were lower than planned and aerial inspections were on‐track.  Aging 115kV 
pole replacements were 80% below target, while aging 230kV pole replacements were 37% above target.  
Customer outages were 97% higher than targeted, while emergency spending was 50% higher than targeted.  
Finally, the follow‐up repair backlog increased, ending the year with five category 4 items overdue and the 
oldest item in the backlog at 35 months.  Much of this may be due to improved identification and tracking 
methods that were recently implemented. 
Replacement budget recommendations remain relatively unchanged at $12 million for 115kV and $9 million 
for 230kV.  Planned budgets for 2016 and 2017 are relatively close to this recommendation.  Additional 
mandated, growth and reimbursable capital projects, as well as O&M work puts the total planned budget for 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 6 of 61

7 2016 Electric Transmission System Asset Management Plan 
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Transmission Engineering at approximately $25 million for 2016, and is expected to remain at this level or 
increase for many years.  This output level is nearly triple that of just a few years ago, while dedicated staff 
have only increased from five to six in the transmission engineering group.  In order to reduce operational 
risks, it is strongly recommended that management consider assigning additional dedicated staff members, as 
well as proper equipment for safe and effective fieldwork. 
Outages and unplanned spending was $2 million in 2015 , mostly as the result of a severe winter wind storm 
that raised overall unplanned spending on the 230 kV and 115kV systems by $700k.   
Notable achievements in 2015 include: 
1. Design and project management of an expanded number of mandated and system planning projects 
including LiDAR mitigation, at $16.4 million in 2015 compared to $7.5 million in 2014. 
2. Completion of minor rebuild and LiDAR mitigation on Moscow ‐ Orofino 230kV, Devil’s Gap – Stratford 
115 kV, and Noxon – Hot Springs 230 kV 
3. Total rebuild on Bronx – Cabinet 230 kV, tie line to the new Noxon reactor, and structure replacement 
projects on Benewah‐Moscow 230 kV and Devils Gap‐Lind 115 kV.   
4. Approved 2015 budget closely matching the recommended replacement budget of $12 million for 
115kV and $9 million for 230kV.   
5. Effective transition of administrative maintenance work from departing staff, as well as hiring and 
productive output of new engineering staff. 
6. Published a comprehensive set of construction standards for transmission engineering and effectively 
integrated the use of PLS‐CADD software.  Consistently using both as a baseline for continuous 
improvement, as a collaborative team effort.  
7. Confirmation of system pole data including material and location, allowing for detailed expected 
service life information on each transmission line. 
8. Began simulation studies for Lolo – Oxbow 230kV and Noxon – Pine Creek 230kV circuits. 
9. In cooperation with other utilities, continued a major project to determine best design, construction, 
inspection and maintenance of self‐weathering steel structures. 
Beyond execution of approved construction, below is a list of recommended initiatives to further improve 
the long‐term performance and stewardship of transmission assets. 
1. Provide additional dedicated staff as appropriate, to handle long‐term increased workloads in the 
Transmission Engineering group and support processes.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 7 of 61

8 2016 Electric Transmission System Asset Management Plan 
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2. Engage asset stakeholders within each major region of the transmission system in order to develop 
a comprehensive, prioritized capital project plan for the next 20 years. 
3. Continue improving the transmission construction standards to reflect best practices in design and 
construction work.  Engage line crews and regional staff. 
4. Monitor the lead time for as‐built construction updates to AFM, Plan and Profile (P&P) drawings, 
and the engineering vault files, with a target of six months.  Carry out periodic quality audits of 
construction in the field and recorded data. 
5. Develop a comprehensive inspection and planned maintenance program for steel transmission 
structures. 
6. Develop a systematic air switch risk ranking method, replacement schedule, and inspection and 
maintenance program. 
7. Complete rebuild simulation studies and business cases for Lolo – Oxbow 230kV and Noxon – Pine 
Creek 230kV circuits. 
8. Determine the risks and appropriate mitigation work resulting from structural loads of distribution 
underbuild. 
9. Complete a system‐wide simulation study to support optimal Transmission asset inspection 
intervals as well as planned and unplanned replacement budget targets, including annual minor vs. 
major rebuild budgets.  
10. Implement transmission outage software which will allow for accurate and efficient analysis of 
outages and causes on each transmission line and aerial patrol inspection software for follow up 
tracking. 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 8 of 61

9 2016 Electric Transmission System Asset Management Plan 
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Assets 
The tables and charts below provide a high‐level summary of physical assets in the transmission system, 
replacement values, and expected service lives.  Replacement values represent the cost to replace existing 
assets with equivalent new equipment in 2015 dollars, not including right‐of‐way purchases, capacity or ratings 
upgrades, mandated projects, and other work associated with growth‐related installations.   

Circuit Type Installation Cost/Mile Removal Cost/Mile Miles Total Replacement Cost
69kV Circuit $250,000 $20,000 0.4 $113,400
115 Single Circuit $400,000 $20,000 1457.1 $611,986,200
115 Underground Circuit $3,600,000 $180,000 2.8 $10,584,000
115 Double Circuit $525,000 $20,000 23.9 $13,014,600
230 Single Circuit $700,000 $20,000 604.3 $435,081,600
115‐230 Double Circuit $850,000 $20,000 55.3 $48,145,800
230 Double Circuit $900,000 $20,000 25.8 $23,736,000
2169.6 $1,142,661,600
Average Asset Lifecycle (Years)70
Annual Levelized Replacement Spending over Lifecycle $16,323,737 

Table 1:  Primary Assets of the Electric Transmission System – Circuits 

Asset Category Quantity 230kV Quantity 115kV Quantity Total Expected Service Life (years)
Structures 4990 16483 21473 65
Poles 9021 27401 36422 70
Air switches 2 188 190 40
Conductor (miles) 2055 4602 6657 100
Compression sleeves 1370 3068 4438 50
Insulators 22978 60202 83180 70  

Table 2:  Component Assets and Quantities 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 9 of 61

10 2016 Electric Transmission System Asset Management Plan 
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Figure 1:  Example Transmission Asset Components and Expected Service Life  
100 Steel Towers (galvanized steel)
50 Steel Pole/Tubular structures (galvanized or painted)
2585 Self‐Weathering Steel Structures
18817 Wood Pole Structures
4 Hybrid Concrete/Steel structures
0 Concrete Structures
0 Aluminum Structures
40 Laminated Wood Structures
21596 Total Transmission Structures
9.7 average # structures/mile
3277 # self‐weathering (cor‐ten) steel poles
50 # tubular galvanized steel poles
8 # hybrid concrete/steel poles
7602 # larch poles
366 # fir poles
25079 # cedar poles
40 # laminated wood poles
36422 Total # Poles
5660 # beyond expected service life
16% % beyond expected service life
80 # of structures with buried galvanized steel foundations
1014 # of structures with coated buried steel foundations
unknown # of structures with caisson concrete foundations
2700 # of structures with anchors  

Table 3:  Transmission Structures and Poles 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 10 of 61

11 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

pole material larch cedar steel other total
service life 55 65 150 70 69
# 115 poles 2347 21198 1506 597 25648
# 230 poles 2545 4312 1813 635 9305
total # poles 4892 25510 3319 1232 34953  

Table 4:  115kV vs 230kV Pole Materials 

Key Performance Indicators (KPIs) 
The table below shows overall KPI results for 2015, which are monitored and recorded on a monthly 
basis throughout the year.  The first four are leading indicators over which we have direct operational 
control.  The final two KPIs are lagging indicators of system performance, which should have a causal link 
to the leading indicators.  In other words, if we consistently execute well as demonstrated by the leading 
indicators, over time we should see satisfactory outcomes as manifested by the lagging indicators, and 
vice versa.  When this does not occur, deeper investigation and root‐cause analysis is justified, as 
something other than the expected causal relationship is potentially at play.    
By these measures, performance was lower than targeted for structural ground inspections.  Aerial 
patrol inspections remained on‐track overall.   System‐wide follow‐up repairs from ground and aerial 
patrol inspections were higher than planned for category 4 and 5 items.  This may be primarily due to 
improved tracking methods.  Aging infrastructure replacement was less than the levelized investment 
required to maintain system reliability over the long term for 115kV, as roughly indicated by the number 
of older poles replaced.  Reliability performance and emergency spending were higher than targeted. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 11 of 61

12 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Completed Structural Ground Inspections Projected Actual Normalized
# wood poles ground inspected 2400 2145 0.89
Completed Structural Aerial Inspections Projected Actual Normalized
% of 230kV system inspected 100 100 1.00
% of 115kV system inspected 70 70 1.00
Followup Repair Backlog Projected Actual Normalized
# worksites overdue (> 1 year after inspection year)10 8 0.80
# Category 4 or 5 items overdue (> 6 months since inspection, ground + aerial) 1 5 5.00
oldest item in backlog (# months since inspection)18 35 1.94
Aging Infrastructure Replacement Projected Actual Normalized
# 115kV wood poles  older than 60 years replaced with steel 500 98 0.20
# 230kV wood poles  older than 50 years replaced with steel 175 240 1.37
# air switches > 40 yrs old replaced 4 1 0.25
Reliability Performance Projected Actual Normalized
Extended Unplanned Outages due to Transmission (Customer‐Hrs)133,142             262,949       1.97
# of Customers with Unplanned Transmission Outages > 3 Hrs 10,182               24,927          2.45
Emergency Spending Projected Actual Normalized
230kV Emergency Spending $204,022 388,272$     1.83
115kV Emergency Spending 1,116,997$       1,792,649$  1.44
total Emergency Spending 1,321,019$       2,180,921$  1.50  
Unity Box Metrics ‐ Monthly Weighting 2015 Result
Completed Structural Ground Inspections 20.00%0.89
Completed Structural Aerial Inspections 20.00%1.00
Followup Repair Backlog 15.00%3.19
Aging Infrastructure Replacement 15.00%0.73
Reliability Performance 15.00%2.31
Emergency Spending 15.00%1.50
Sum of Weight * Value 100.00%1.54

Results
1 = Planned/On‐Track
<1 = Better than Planned
>1 = Worse than Planned  
Table 5:  Transmission KPIs and Unity Box Metrics 
It is strongly recommended that $21 million per year over a 30‐year timeframe is allocated for worn‐out 
infrastructure replacements – $12 million for 115kV, and $9 million for 230kV.  As we ramp up 
replacement construction in the years ahead, we expect to meet or exceed these goals.  We will 
continue to replace equipment primarily on the basis of recent inspection and condition assessments, 
however the age and respective service life of the system at a high‐level provides a strong leading 
indicator of long‐term system reliability.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 12 of 61

13 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Additional performance measures are tabulated below since 2010: 
Performance Measure Goal 2010 2011 2012 2013 2014 2015 Remarks
Customer‐Hours 
unplanned, extended 
outage due to 
transmission issues        113,142 255,426 64,453 82,908 238,861 200,977 262,949
# of customers of Tx 
related unplanned 
outages greater than 3 
hrs         10,182 16,478 6,644 5,409 17,135 17,609 24,927
Tx emergency repair 
costs $1,321,019 $1,442,969 $1,029,597 $1,409,972 $1,630,943 $3,040,313 $2,180,921
Avista crew safety: # 
recordable injuries 
from Transmission 
work 0 not avail not avail not avail not avail not avail not avail
Unable to 
isolate to 
Transmission
Top 10 worst 
performing 
components ‐ by 
failures NA not avail not avail not avail not avail not avail not avail
Not available 
from OMT data
Top 10 worst 
performing circuits by # 
of component failures NA not avail not avail not avail not avail not avail not avail
Not available 
from OMT data  
Table 6:  Additional Performance Measures, 2010‐2015 
Note that important performance measures currently cannot be evaluated due to inadequate data 
availability.  This includes safety incidents from transmission work, the total number of annual failures 
and respective failure modes for various transmission lines and system‐wide asset components such as 
poles, air switches, crossarms, insulators, splice connections, and so forth.  An ongoing, long‐term effort 
is necessary to make this information available and assimilate into our set of KPIs and circuit risk 
rankings.  It is also essential to taking the next steps in evaluating the benefit and value of asset 
management programs and projects for continuous improvement. 
Capital Replacement and Maintenance Investment 
Levelized replacement spending is the annual spending required to replace the asset category in a 
perfectly level form over the asset’s service life in 2015 dollars, not including inflation.  Prior to adjusting 
for uneven service life profiles, this provides a simple, rough‐cut measure to compare against actual 
replacement spending each year, i.e. the minimum needed to keep up with aging infrastructure that 
places reliability at risk.  This currently stands at $16.3 million per year for the transmission system.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 13 of 61

14 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Relative to other major areas of the transmission and distribution (T&D) system, transmission assets 
have a longer service life, and the total replacement value of $1.1 billion is on par with substation’s $0.9 
billion and about half of distribution’s $2.0 billion.  All together, levelized replacement spending is 
roughly $84 million per year in perpetuity for Avista’s T&D system (2014 dollars).  However, as shorter 
lived wood materials are replaced with steel in the decades ahead, we expect overall service life to 
increase from 70 years to over 100 years for the transmission system.  Assuming all other factors being 
equal, this in turn would reduce the minimum levelized spending to under $12 million/year, roughly 50 
years from now. 

Figure 2:  Transmission and Distribution System Replacement Values, Average Service Life, 
and Levelized Replacement Spending 

The next step is to look more closely at the replacement cost of actual installed assets compared to 
remaining service life.  This provides the basis for levelized replacement budgets given actual remaining 
service life profiles, as summarized in the following chart. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 14 of 61

15 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

0
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Remaining Service Life (years)
Transmission System Replacement Cost vs Remaining Service Life
115 kV
230 kV

Figure 3:  Replacement Cost vs. Remaining Service Life 
Note that field assets costing $234 million to replace are currently beyond expected service life, based 
on their age and statistical predictions of mean time to failure (everything to the left of 0 years in Figure 
3 above).  The oldest and greatest quantities of these assets are 115kV transmission lines.  This 
represents a significant risk to the continued reliability of the transmission system, particularly for those 
115kV circuits with more than 10 years past normal service life.   
To address this issue, several alternatives present themselves in terms of long‐term replacement 
policies, as shown in the table below.  The 30‐year replacement period is recommended at $21.1 million 
per year, split between $11.3 million for 115kV and $9.8 million for 230kV.  This policy, when coupled 
with an ongoing, annual risk assessment and targeting of funds, over the long term will effectively 
reduce risks and minimize total lifecycle costs.    
The table below presents a simple levelization that reduces the volatility and operational business risk of 
ramping up and down construction work from year‐to‐year, while responsibly maintaining system 
performance.  Again, it should be emphasized that in order to be most effective, this level of 
replacement spending must be targeted at those assets that pose the greatest overall risk, as discussed 
in the Risk Prioritization section of this report.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 15 of 61

16 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Tx Capital Assets 
Service Life (yrs)
Levelized 
Replacement Period 
(yrs) 115kV 230kV Total
Annual Levelized 
Replacement 
Spending ($)
 ‐10 or less
0 or less 10 $134,307,405 $78,477,092 $212,784,497 $21,278,450
10 or less 10 $188,044,730 $110,751,445 $298,796,176 $29,879,618
20 or less 20 $246,950,622 $264,119,590 $511,070,211 $25,553,511
30 or less 30 $339,538,157 $294,522,966 $634,061,123 $21,135,371
40 or less 40 $473,944,191 $331,318,848 $805,263,038 $20,131,576
50 or less 50 $569,441,268 $356,005,350 $925,446,618 $18,508,932
60 or less 60 $602,081,970 $379,756,364 $981,838,334 $16,363,972
70 or less 70 $617,172,136 $389,475,050 $1,006,647,186 $14,380,674
Cumulative Replacement Costs ($)

Table 7:  Levelized Replacement Spending Options 
A variety of data uncertainties result in +/‐ 5% confidence in the stated figures.   In terms of replacement 
costs, the most significant uncertainty from year to year involves the volatility of contract labor.  
Extensive work was recently completed to confirm 115kV and 230kV pole data, most importantly the 
identification of pole material and respective expected service life, which has greatly improved 
confidence levels. 
The recommended $21.1 million per year in levelized replacement spending over the next 30 years is 
higher than the $19.1 million actual replacement spending in 2015.  Significant effort is underway to 
ramp up replacement construction in 2016 and sustain it over ensuing years.  Other project categories 
include growth, mandated, and reimbursable capital projects, operations and maintenance (O&M) 
programs, and unplanned/emergency work.  These figures are tabulated below for 2015.  Spending 
associated with liability claims and the underground network are not included, due to data uncertainty.  
Please note that many construction projects involve a combination of replacement, growth, and 
mandated work, therefore these figures are rough approximations.  Historically, upwards of 90% of 
transmission construction is through contractors.   

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 16 of 61

17 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

19,074,307$             Replacement
6,301,988$               Growth/Upgrade
2,180,921$               Unplanned/Emergency
936,843$                  O&M ‐ Veg Management
327,319$                  O&M ‐ Other
25,000$                    Reimburseable work completed
28,846,378$             Total
26,640,457$             Total Planned non‐reimburseable
26,665,457$             Total Planned Capital (including reimburseable)
1,264,162$               Total Planned O&M
2,180,921$               Total Unplanned/Emergency Capital
unknown Total Unplanned O&M  
Table 8:  2015 Transmission Spending 
2015 Tx Project Spend Program/Project Description ER BI Type
5,344,333$                      Devils Gap‐Lind 115kV Transmission Rebuild Proj 2564 ST302 Replacement
5,316,486$                      Benewah‐Moscow 230kV ‐ Structure Replacement 2577 PT305 Replacement
3,426,340$                      LiDAR Mitigation Projects, Med Priority 2560 CT203, various Mandated Replacement
3,419,420$                      Xsmn Asset Management 2423 AMT81 Growth/Replacement
2,475,619$                      Benton‐Othello 115 Recond 2457 FT130 Growth/Replacement
2,053,414$                      Asset Mgmt Trans Minor Rebuilds WA 2057 AMT12 Replacement
692,288$                         Noxon 230 kV Stn Rebuild:Transmission Integration 2532 AT300 Growth/Mandated
627,195$                         Asset Mgmt Trans Minor Rebuilds ID 2057 AMT13 Replacement
529,411$                         Transmission Line Road Move 2056 56L08 Replacement
443,619$                         Asset Mgmt Transmission Switch Upgrade 2254 AMT10 Replacement
411,600$                         Chelan‐Stratford 115kV ‐ Rbld Columbia River Xing 2574 BT304 Growth/Mandated
249,540$                         Lewiston Mill Rd. 115 kV Substation Integration 1107 LT403 Growth/Mandated
198,319$                         9CE‐Sunset 115kV Transmission Line Rebuild 2557 ST503 Growth/Replacement
85,599$                            Opportunity Sub 115kV Breaker Add ‐ Tx Integration 2552 ST307 Growth/Mandated
84,903$                            Irvin 115kV Switching Stn: Transmission Integration 2446 ST102 Growth/Mandated
18,209$                            Greenacres 115 Sub New Cons:Transmission Integrate 2443 ST203 Growth/Mandated
‐$                                  Burke‐Thompson A&B 115kV Transmission Rebuld Proj 2550 CT101 Replacement
‐$                                  LiDAR Mitigation Projects, Low Priority 2579 CT304, various Growth/Mandated
‐$                                  Asset Mgmt Transmission Wood Sub Rebuild 2204 AMT08 Replacement

Table 9:  2015 Planned Capital Projects (Non‐Reimburseable)  

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 17 of 61

18 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

66%
22%
8%4%
Replacement Capital
Growth/Mandated Capital
Unplanned/Emergency
O&M

Figure 4:  2014 Planned Capital, O&M, and Emergency Spending 
This shows that approximately 92% of spending was planned, vs. 8% unplanned in 2015.  The percent of 
planned work should increase as planned replacements ramp up and unplanned/emergency spending is 
held constant or reduced.  Growth and mandated projects (e.g. LiDAR projects) of $6.3 million resulted 
in 22% of total Transmission spending in 2015.  Although the spending in this category is highly variable 
from year to year, a constant value of $3 million is assumed for the future.  A small increase of 2% per 
year is assumed for reimbursable projects such as road moves.   O&M dollars may be reduced over the 
long‐term, due to expected lower inspection costs of steel poles as they are used to replace existing 
wood poles; however, this was not accounted for as it is somewhat uncertain and represents a relatively 
insignificant sum.  Other figures represent recommendations for planned replacement and maintenance 
programs as specified in the Programs section of this report.  Optimal planned spending may vary 
considerably after making adjustments for actual condition assessments as inspections are completed, 
capturing economies of scale opportunities when rebuilding larger sections of line, and taking into 
account cost of capital considerations from year to year.  Notwithstanding these variables, the numbers 
below represent the minimum recommended investment for consistent, planned transmission work in 
the years ahead.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 18 of 61

19 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Figure 5:  30‐year Transmission Planned Capital and Maintenance Recommendations 

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O&M %0% 0% 0% 0% 0% 100% 100% 100% 100% 100%
Capital %100% 100% 100% 100% 100% 0% 0% 0% 0% 0%Total O&M Total Planned
2013 actual $8,785,633 $3,965,832 $1,136,787 $150,556 $970,036 $294,000 $94,595 $1,100,000 $200,000 $100,000 $9,906,225 $5,102,619 $1,788,595 $16,797,439
2014 
recommended $14,110,816 $2,210,000 $1,159,523 $264,000 $1,300,000 $192,000 $100,000 $1,200,000 $242,000 $100,000 $15,674,816 $3,369,523 $1,834,000 $20,878,339
2014 actual $3,638,255 $7,499,457 $150,000 $135,493 $4,103,971 $317,790 $103,154 $1,300,000 $188,111 $181,405 $7,877,719 $7,649,457 $2,090,460 $17,617,636
2015 
recommended $18,667,888 $3,000,000 $1,870,600 $392,507 $1,700,000 $216,000 $100,000 $1,200,000 $242,000 $100,000 $20,760,395 $4,870,600 $1,858,000 $27,488,995
2015 actual $15,420,668 $6,301,988 $25,000 $443,619 $3,210,020 $68,142 $135,318 $936,843 $19,322 $104,537 $19,074,307 $6,326,988 $1,264,162 $26,665,457
2016‐2020 
recommended $18,496,395 $3,000,000 $25,500 $264,000 $2,000,000 $216,000 $103,154 $1,200,000 $242,000 $100,000 $20,760,395 $3,025,500 $1,861,154 $25,647,049
2021‐2045 
recommended $18,496,395 $3,000,000 $26,010 $264,000 $2,000,000 $216,000 $103,154 $1,200,000 $242,000 $0 $20,760,395 $3,026,010 $1,761,154 $25,547,559
Capital 
Replacement 
Projects
Growth, 
Mandated & 
Reimburseable 
Capital Projects

Table 10:  30‐year Planned Capital and O&M Recommendations 
In short, in order to minimize lifecycle costs and maintain system performance, the bulk of the 
transmission system needs to be rebuilt over the next three decades, if not sooner.  This is no small 
endeavor, entailing significant financial and operational risk.  Although construction and even design 
work may be contracted out, internal workloads will in all cases rise substantially in the years ahead for 
the Transmission Engineering group and supporting departments.   A successful transition and sustained 
production of high quality design work and construction in the field – that will last well into the 22nd 
century – requires careful management and strong support across the company.    
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 19 of 61

20 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Process Capability 
As of 2010, total planned design, project management, and construction capital and O&M work for the 
Transmission system originating from the Transmission Engineering group was less than $10 million per 
year.  At that time, Transmission Engineering had a dedicated staff of five members – one manager, 
three engineers, and one technician – equivalent to roughly $2.0 million per staff member.  In 2015, 
total planned work amounts to $26,665,457 with a dedicated staff of six members – one manager and 
five engineers – equivalent to $4.4 million per staff member.  This represents an output productivity 
increase of 120% in only a few years time.  Hidden workloads such as mandated reporting and analysis 
from regulatory bodies such as NERC are also on the rise.  In order to remedy operational risks and 
achieve management objectives, the need for additional staff, equipment, and improved support 
processes should be considered a very high priority, seriously investigated, and remedied as 
appropriate.     
Other opportunities for improved process capability include reducing overall project lead times, 
particularly from the time of internal project initiation to the beginning of construction, which has 
increased substantially.  Construction timelines and total costs may also be reduced, for example by 
completing line projects in one or two years instead of three to five.   
Continued engagement and integration with internal and contracted line crews to communicate and 
improve construction standards is also recommended as a way to improve overall process capability. 
Risk Prioritization 
According to Wikipedia, risk is defined as  “ . . . 1. The probability of something happening multiplied by 
the resulting cost or benefit if it does.  (This concept is more properly known as the 'Expectation Value' 
and is used to compare levels of risk)”     
‐ from  http://en.wikipedia.org/wiki/Risk 
In mathematical form, this is expressed as:   
Risk/Benefit   ∑(Event Probability)    *  (Event Consequence)      
The transmission system’s major circuits were ranked by this formulation.   The rankings will be used as 
a starting point for further deliberation among internal stakeholders, with the goal of allocating 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 20 of 61

21 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

resources where they will have the most significant risk reduction.  The rankings may also be used to 
justify inspection and follow‐up work earlier than normally scheduled (currently a 15‐year inspection 
cycle on each line).  At minimum, the rankings will be used to prioritize the commissioning of detailed 
studies, simulations and development of business cases for major line rebuild projects. 
The first component of risk for our transmission lines is the probability of a failure event, which we will 
refer to as the asset’s “Probability Index”.  This is a normalized relative  score from 1 (low unplanned 
event probability) to 100 (high unplanned event probability).   The factors and respective weighting for 
the Probability Index are as follows, derived from a combination of the line’s condition, track record, and 
severity of operating environment.  Each factor is scored from 1 (low) to 5 (high), based on a set of 
objective measures collaboratively developed by representatives in Asset Management, Transmission 
Design, System Planning, and System Operations groups.  In the future, improved data and analysis may 
allow for actual probability estimates rather than relative scoring methods. 
% Weight Criteria 
25 Unplanned outages/spending 
20 Remaining service life 
20 Time since last minor rebuild, # 
items identified for replacement 
20 # of miles 
15 
Severity of terrain & operating 
environment (soil conditions, 
weather intensity, vegetation, 
relative probability of 
vehicle/equip. impacts, etc) 

Table 11:  Probability Index Criteria and Weightings 
The second component of risk (event consequence), we will refer to as the asset’s “Consequence 
Index”.  It is a measure of the severity of consequences should an unplanned failure event occur.  This is 
also a normalized relative score from 1 (low severity = low event consequence) to 5 (high severity = high 
event consequence).  The factors and respective weighting for the Consequence Index are as follows, 
derived from the relative importance of the line in terms of power flow, its effect on the system should 
it become unavailable, the relative time and cost to effect repairs, and potential secondary damage 
based on safety, environmental issues and its proximity to other company and private property.  In the 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 21 of 61

22 2016 Electric Transmission System Asset Management Plan 
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future, improved data and analysis may allow consequences to be financially quantified, rather than 
relative scoring methods.  
% weight criteria 
40 power delivery 
20 potential damages 
(company/private/environmental) 
15 access 
15 system stability, voltage control and thermal 
problems
10 voltage & configuration 

Table 12:  Consequence Index Criteria 
With these indices in hand, we have the ability to prioritize lines based on comparable risk levels, which 
we refer to as the line’s “Reliability Risk Index”, where 
Reliability Risk Index = (Probability Index) * (Consequence Index) 
This is also normalized from a score of 1 (low risk) to 100 (high risk).  In order to be worthwhile, it is 
essential that the risk index is useful to making practical business decisions.  It must produce credible 
results to a wide variety of experts and decision makers, and it must be reliably reproduced each year 
without a great burden of effort.  Over time, improvement in our ability to collect and use data may 
allow us to evaluate shorter segments of lines with greater ease, providing a refined view of system risk 
at the line segment or even structure level.  This would facilitate a more detailed view of system risks 
and optimized mitigation efforts.  The development and use of aids that help visualize results (e.g. color‐
coded system maps), may also be worthwhile.    
The top 20 highest risk transmission lines are shown in the table below, and the complete list is included 
as Appendix A.  This iteration only includes transmission lines and taps that are longer than one mile.  An 
additional 37 short lines and taps not included in the risk index account for 14.3 additional miles, 
representing less than 0.7% of total Transmission system mileage. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 22 of 61

23 2016 Electric Transmission System Asset Management Plan 
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Transmission Line Name Voltage (kV) Length (miles) Replacement Value Probability Index Consequence Index Risk Index
Lolo ‐ Oxbow 230 63.41 $45,655,200 85.4 100.0 100.0
Noxon ‐ Pine Creek 230 43.51 $31,327,200 80.5 87.8 82.8
Benewah ‐ Pine Creek 230 42.77 $30,794,400 68.3 87.8 70.3
Walla Walla ‐ Wanapum 230 77.78 $56,001,600 68.4 83.7 67.1
Benewah ‐ Boulder 230 26.15 $18,828,000 67.1 72.9 57.3
Hot Springs ‐ Noxon #2 230 70.05 $50,436,000 66.0 68.8 53.2
Dry Creek ‐ Talbot 230 28.27 $20,354,400 51.4 78.3 47.1
Latah ‐ Moscow 115 51.41 $21,592,200 96.0 41.7 47.0
Devils Gap ‐ Stratford 115 86.19 $36,199,800 100.0 39.0 45.6
Post Street ‐ 3rd & Hatch 115 1.76 $3,696,000 70 100 43
Benewah ‐ Moscow 230 44.28 $31,881,600 61.1 59.3 42.5
Cabinet ‐ Rathdrum 230 52.3 $37,656,000 41.7 86.4 42.3
Bronx ‐ Cabinet 115 32.38 $13,599,600 59.4 55.2 38.4
Metro ‐ Post Street 115 0.5 $1,890,000 60 100 38
Ninth & Central ‐ Sunset 115 8.63 $3,624,600 39.0 75.6 34.7
Burke ‐ Pine Creek #3 115 23.79 $9,991,800 67.0 44.4 34.6
Shawnee ‐ Sunset 115 61.51 $25,834,200 79.0 36.3 33.4
Sunset ‐ Westside 115 10.03 $4,212,600 53.0 53.9 33.2
Hatwai ‐ Lolo 230 8.27 $5,954,400 28.9 93.2 31.6  
Table 13:  Top 20 Most at Risk Circuits according to the Reliability Risk Index 
Note that the two underground 115kV circuits, Post Street – 3rd & Hatch, and Metro – Post Street both 
have a 100 consequence rating and probability ratings of 70 and 60, respectively.  The consequence of 
unplanned outages on these lines is arguably much larger than those of any other line on the system as 
they serve the high density core of downtown Spokane.   In other words, the risks listed above may be 
understated for these two lines.   A strong recommendation for full replacement of both lines is advised 
in the near future – realistically within 5 to 10 years. 
It is important to recognize that the risk index does not yet provide an absolute priority order for 
replacement and maintenance decisions – option costs to reduce risks must first be factored in.  
Specifically, cost option analyses must be performed to determine which project options result in the 
highest reduction of risk per dollar spent.  According to best practice asset management principles, this 
analyses results in a system “Criticality Index” for each line in priority order, where each line would be 
ranked according to: 
Criticality Index = (Original Risk – Residual Risk) / (Option Cost) 
Finally, other opportunities and benefits are factored in, also known as “bundling” in asset management 
parlance, to arrive at a final priority order for replacement and maintenance projects.  These 
opportunities and benefits may come from various areas such as system planning for capacity and 
growth requirements, system operations, regulatory compliance, protection engineering and 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 23 of 61

24 2016 Electric Transmission System Asset Management Plan 
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communications, operations, and power supply.  After factoring in these priorities, a comprehensive 
replacement and maintenance plan for 20 years may be developed, sequenced according to system 
operations restrictions and with higher levels of detail for projects within the 10 year timeframe.  A good 
start in this direction may be accomplished through the concept of area mitigation plans which involve 
and integrate stakeholders within each major transmission area of the system (e.g. Big Bend, Spokane, 
Lewis‐Clark, etc). 
Ultimately, objective rankings must be useful and effective, helping the organization to arrive at the 
right business decisions with less effort.  Asset management staff will continue to facilitate and support 
this collaborative undertaking, striving for improvement and strong results.   
Unplanned Spending 
Unplanned spending represents capital replacement of those transmission assets that have 
unexpectedly failed and require prompt attention, typically by Avista crews (e.g. storm response 
events).  Despite the variability that is correlated with fluctuations in weather intensity, unplanned 
spending is an especially important lagging indicator of system performance, trends, and the 
effectiveness of asset management programs.  In addition to cost premiums incurred from overtime 
labor, unplanned work typically presents greater safety risks to the public and on‐site Avista employees, 
as well as other risks including property damage, environmental, general liability, planned work delays, 
and additional rework costs following the event.  We have set annual goals at the average of unplanned 
spending from 2009 through 2012, reflecting a desire to maintain system reliability.  This results in 
“targets” of $1.1 million for 115kV and $210k for 230kV, for a total of $1.3 million per year.  Note that in 
past years we have consistently spent a much greater amount of total unplanned dollars on the 115kV 
system, at roughly four times the proportional value of capital assets when compared to the 230kV 
system.  This is consistent with the fact that 230kV assets are felt to pose a higher potential 
consequence should they fail, and therefore we maintain them accordingly – deliberately effecting a 
lower frequency of unplanned events on the 230kV system, relative to 115kV.  While this may be the 
case, it remains that the optimal target of unplanned spending has not been quantitatively determined 
for either system.  This is a desired output from a future system model and analysis, involving the 
quantification and simulation of all significant risks and costs associated with unplanned events, 
maintenance and replacement work.  Note that zero emergency spending is actually sub‐optimal unless 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 24 of 61

25 2016 Electric Transmission System Asset Management Plan 
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there is zero tolerance for any risk – otherwise, it represents over‐investment in the design 
configuration and actual condition of physical assets. 
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Electric Transmission 115kV and 230kV Total Unplanned Capital Spending from XXX01050 
Account Information
115kV unplanned Tx capital 230kV unplanned Tx capital  
Figure 6:  115kV and 230kV Total Unplanned Capital Spending 
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
115kV - WA 115kV - WA $312,958 $609,438 $265,221 $874,996 $649,760 $585,250 $499,341 $1,123,122 $1,640,237 $1,087,223
115kV - ID 115kV - ID $406,111 $161,470 $221,343 $349,459 $626,503 $274,517 $608,163 $389,492 $437,978 $705,426
115kV - all 115kV - all $719,070 $770,908 $486,564 $1,224,455 $1,276,263 $859,767 $1,107,505 $1,512,614 $2,078,216 $1,792,649
230kV - WA 230kV - WA $215,228 $97,946 $215,416 $57,721 $73,482 $156,491 $58,976 $89,984 $13,286 $116,311
230kV - ID 230kV - ID $74,783 $32,856 $120,056 $89,364 $79,950 $12,979 $228,681 ‐$134,091 $945,631 $259,884
230kV - MT w/ Colstrip
230kV - MT
w/ Colstrip $0 $286,338 $257,879 $249,429 $368,855 $574,428 $298,059 $436,991 $249,307 $402,324
230kV - MT w/o Colstrip
230kV - MT
w/o Colstrip $0 $1,590 $59,590 $27,525 $13,275 $0 $72 $18,910 $0 $12,077
230kV - OR 230kV - OR $12,273 $0 $0 $2,475 $0 $360 $14,738 $9,435 $3,181 $0
230kV - all
230kV - all
w/o Colstrip $302,285 $132,392 $395,062 $177,085 $166,706 $169,830 $302,467 $118,329 $962,097 $388,272
115kV and 230kV (all)
115kV and
230kV (all)$1,021,354 $903,300 $881,625 $1,401,539 $1,442,969 $1,029,597 $1,409,972 $1,630,943 $3,040,313 $2,180,921 
Table 14:  Transmission Unplanned and Emergency Spending, 2006 ‐ 2015 
Total unplanned spending in 2015 was $2.18 million, significantly higher than any year recorded since 
2006 except for 2014, and well above the target of $1.3 million per year.  This was due to a major wind 
storm in November 2015, totaling $700k.     
Unfortunately, the use of 115kV blanket accounts does not allow for ready analysis of unplanned 
spending on individual 115kV circuits.  This is necessary to get a better understanding of risk and asset 
prioritization on a line‐by‐line basis.  New software is in the process of implementation by System 
Operations.  This should be complete by 2016 with annual data available for analysis starting in 2017.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 25 of 61

26 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

The figures above do not include spending on the 11% Avista ownership of the roughly 500 miles of 
500kV Colstrip transmission and substation assets. 
Outages 
Outages are a strong lagging indicator of system reliability and are highly correlated with unplanned and 
emergency spending.  It is also the principle source of emerging trends and problem root cause analysis 
that is critical to maintaining system reliability over the long term.  A full list of outage information for 
2015 on a line‐by‐line basis is provided in Appendix B.  Below are highlights of this information.   
Primary data was obtained from both the annual Reliability Reports created by Operations Management 
and the Transmission Outage Reports (TOR) created by System Operations.  The Reliability Report 
includes data on sustained outages (longer than five minutes) for Transmission related events that affect 
customers – it does not include any outages that do not affect customers. The TOR on the other hand, 
includes any transmission event (sustained or momentary), but it does not contain information about 
customer outages.  Utilizing the TOR, System Operations compiles the Transmission Adequacy Database 
System (TADS), and associated mandated NERC reports for 230kV lines, but not for 115kV lines.  It is 
important to analyze both the Reliability and TOR reports because they each contain different but 
important information regarding outages on the transmission system.  This is currently a laborious 
process, as neither the Reliability nor TOR reports consistently list transmission lines that apply to each 
event.  The Reliability Reports indicate substations and feeders associated with customer outages 
related to a transmission line outage, but not which transmission line that applies.  Breaker 
identification is provided on the TOR and must be used to cross reference other information, in some 
cases multiple sources, to identify the applicable transmission line.  New software is being implemented 
that will help identify outage events on each transmission line, greatly improving analysis capability.  
This data is expected to be available for analysis by 2017.   
Based on the TOR data, there were 477 transmission line outages recorded in 2015, 182 of which were 
planned, 165 that were trip and recloses that lasted less than a minute, and 130 unplanned outages over 
one minute.  Of these outages, only 35 caused an actual customer outage.  The Transmission lines with 
the most sustained, unplanned outage occurrences are as follows (regardless if a line outage caused a 
customer outage): 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 26 of 61

27 2016 Electric Transmission System Asset Management Plan 
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Ranking Transmission Line Name2 
#Unplanned 
Outages 
1 Lind ‐ Shawnee 115 kV 19 
2 Moscow 230 ‐ Orofino 115 kV 17 
3 Bronx ‐ Cabinet 115 kV 16 
4 Benewah ‐ Pine Creek 115 kV 15 
5 Devils Gap ‐ Stratford 115 kV 13 
6 Hot Springs ‐ Noxon #1 2230 kV 9 
7 CdA 15th St ‐ Pine Creek 115 kV 8 
8 Cabinet ‐ Rathdrum 230 kV 8 
9 Walla Walla ‐ Wanapum 230 kV 8 
10 Boulder ‐ Rathdrum 115 kV 8 

Table 15:  Transmission lines with the most unplanned outages in 2014 
Based on the Reliability Report, over 281,000 hours of unplanned customer outages were recorded in 
2015.  The transmission lines with the most unplanned customer‐hours outage are as follows: 
Ranking Transmission Line Name2 Customer Hours 
1 Devil's Gap ‐ Lind 115 kV 74696:25 
2 Addy ‐ Kettle Falls 115 kV 51848:52 
3 Beacon ‐ Ross Park 115 kV 30852:35 
4 Devils Gap ‐ Stratford 115 kV 15388:45 
5 Ninth & Central ‐ Otis Orchards 115 kV 13257:14 
6 Moscow 230 ‐ Orofino 115 kV 8838:57 
7 JAYPE‐OROFINO 115 kV 6351:55 
8 Clearwater ‐ Lolo #2 115 kV 6093:56 
9 Lolo ‐ Nez Perce 115 kV 6002:19 
10 Ninth & Central ‐ Otis Orchards 115 kV 5971:43 

Table 16:  Transmission lines that caused the most customer hours lost in 2015 

Over 27,000 customers experienced an outage that lasted longer than three hours, representing a slight 
increase from last year.  The Transmission lines with the highest number of customers experiencing 
outages greater than 3 hours are as follows: 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 27 of 61

28 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Ranking Transmission Line Name2 
# Customers 
experiencing Outages 
>3 hrs 
1 Addy ‐ Kettle Falls 115 kV 13210 
2 Devils Gap ‐ Stratford 115 kV 2944 
3 Ninth & Central ‐ Otis Orchards 115 kV 2077 
4 Grangeville ‐ Nez Perce #2 115 kV 1271 
5 JAYPE‐OROFINO 115 kV 1122 
6 Moscow 230 ‐ Orofino 115 kV 797 
7 Clearwater ‐ Lolo #2 115 kV 652 
8 Devil's Gap ‐ Lind 115 kV 563 
9 Jaype ‐ Orofino 115 kV 288 
10 Lind ‐ Washtucna 115 kV 244 

Table 17:  Transmission Lines causing the most customer outages greater than 3 hours in 2015 
Overall, the data shows that the 115 kV system is significantly less reliable than the 230 kV system in 
terms of total outages and customers directly affected. 
The causes for customer outages lasting longer than three hours increased for rotten crossarms, 
insulators, switch/disconnect, pole fires, cars hitting poles, and snow/ice events.  These types of outages 
should be monitored closely as surveys indicate that outages lasting longer than three hours are the 
most important reliability factor driving customer satisfaction.  Appropriate steps should be taken to 
prevent these outages in the future and to reduce repair time should an outage occur.  Weather related 
outages caused the most customer‐hours lost per occurrence.   
It should be noted that two lines appear on all three of the ‘worst transmission line’ lists described 
above: 
1. Moscow 230 ‐ Orofino 115 kV 
2. Devils Gap‐Stratford 115 kV 
Extending the above lists to include the worst 20 lines, four other lines would appear on all three 
indices: 
3. Ninth & Central – Otis Orchards 115 kV 
4. Devil’s Gap ‐ Lind 115 kV 
Based on this information, closer monitoring for these lines is warranted.  Moscow 230 – Orofino 115kV 
is scheduled for a minor rebuild in 2016.  Devils Gap‐Stratford 115kV is scheduled for a LiDAR/minor 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 28 of 61

29 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

rebuild in 2016 and is being considered for full rebuild.  In 2015, breakers were installed at Opportunity 
to help sectionalize Ninth & Central – Otis Orchards 115kV and by 2017 the Irvin Switching Station 
should be in service which will add an emergency tie to Opportunity to improve performance.   Devils’s 
Gap – Lind 115kV is scheduled for a major rebuild in 2017 – 2018.        
In 2015 there were 162 feeder outages, but only 58 unique transmission events that caused those 
outages.  The 2015 data was analyzed to indicate only the number of unique transmission outages for 
each subreason.   
Reason 
Sub Reason 
# Outage 
Occurances 
ANIMAL Squirrel 2 
EQUIPMENT OH Capacitor 5 
EQUIPMENT OH Crossarm‐rotten 1 
EQUIPMENT OH Regulator 1 
EQUIPMENT OH Switch/Disconnect 1 
PLANNED Maint/Upgrade 6 
POLE FIRE Pole Fire 15 
PUBLIC Car Hit Pole 1 
PUBLIC Fire 13 
TREE Weather 1 
UNDETERMINED Undetermined 1 
WEATHER Wind 11 
58

Table 18:  Transmission Outage Causes, 2009‐2015 
Pole fire related outages continue to dominate both in terms of number of occurrences and customer‐
hour outages.  At over 50,000 hours, pole fires had the highest number of customer‐hour outages.  This 
number is higher than last year (29,000 customer‐hours) and highlights the need to continue the fire 
retardant program and to replace wood poles with steel poles.      
 As can be seen from Figure 5 below,  unplanned, non‐weather and weather events dominate both the 
number of occurances and customer‐hours outages for the transmission lines. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 29 of 61

30 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Figure 7:  Transmission outage causes affecting customers in 2015 
Programs 
1.  Major Rebuilds 
Out of the $26,640,457 million in planned capital replacement projects in 2015, $15,420,668 was spent 
on major rebuilds, $3,210,020 on minor rebuilds and $443,619 on switch replacements, for a total of 
$19,074,307.  The recommended level is a minimum of $18.5 million for major rebuilds, $2.0 million for 
minor rebuilds and $264k for switch replacements, for a total of $21 million replacement spending per 
year for 30 years.  As stated previously, replacement projects do not include additional capital projects 
that are mandated, growth related, reimbursable, or otherwise do not address aging infrastructure.  
Furthermore,  the recommended spending is the minimum levelized spending over the entire 30 year 
period, which in the shorter term may need to be increased to minimize lifecycle costs – given 
inspection results, risk analysis, cost of capital, and economies of scale opportunities.  
The most significant major rebuild and reconductor projects currently planned through 2020 are listed 
below, with rough estimates of budget dollars allocated for each year.  Please note that these plans are 
subject to change and projects for 2019 and 2020 in particular are only partially complete. 
0
10
20
30
40
50
60
70
2015
# Oc
c
u
r
a
n
c
e
s
# Occurences Extended Transmission 
Outage by Cause
planned maintenance/upgrade unplanned non‐weather weather
0
50000
100000
150000
200000
250000
300000
350000
2015
Cu
s
t
o
m
e
r
‐ho
u
r
s
 Ou
t
a
g
e
s
Customer‐Hours Extended Transmission 
Outage by Cause
planned unplanned, non‐weather weather
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 30 of 61

31 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Description BI Description2 2016 2017 2018 2019 2020
West Plains Trans Reinforcement ST305 Garden Springs ‐ Sunset 450,000$        600,000$       ‐$              ‐$               ‐$              
Pine Creek ‐ Burke ‐ Thompson Falls CT101 Rebuild Transmission 25,000$          3,500,000$    ‐$              ‐$               ‐$              
9CE‐Sunset 115kV Transmission ST503 Reconductor/Rebuild 2,250,000$     ‐$               ‐$              ‐$               ‐$              
High Resistance Conductor Replacement xTxxx Reconductor/Rebuild ‐$                ‐$               ‐$              ‐$               ‐$              
Cabinet‐Noxon 230kV Rebuild AT700 CAB‐NOX Rebuild w/Reconductor ‐$                ‐$               7,500,000$   7,500,000$   ‐$              
Noxon‐Pine Creek 230kV Rebuild KT901 NOX‐PCR Rebuild w/Reconductor ‐$                ‐$               ‐$              ‐$               7,500,000$   
Lolo‐Oxbow 230kV Rebuild LT900 LOL_OXB Rebuild w/Reconductor ‐$                ‐$               ‐$              ‐$               7,500,000$   
Benewah‐Pine Creek 230 kV Rebuild CT908 BEN‐PIN Rebuild w/Reconductor ‐$                ‐$               ‐$              ‐$               ‐$              
Sys‐Rebuild Trans‐Condition AMT81 BRX‐CAB & BRX‐SCR Rebuild 3,600,000$     1,500,000$    4,500,000$   2,500,000$   2,500,000$   
Ben‐Oth SS 115 ‐ ReCond/Rebld FT130 Ben‐Oth SS 115 ‐ ReCond/Rebld 3,000,000$     1,500,000$    ‐$              ‐$               ‐$              
CDA‐Pine Creek 115kV Rebuild CT300 Rebuild Transmission 25,000$          4,000,000$    6,000,000$   5,000,000$   ‐$              
Devils Gap‐Lind 115kV Rebuild ST302 Rebuild Transmission 1,002,134$     2,900,000$    ‐$              ‐$               ‐$              
Chelan‐Stratford 115kV Rebuild BT304 Rebuild Columbia River Crossing ‐$                ‐$               ‐$              ‐$               ‐$              
Addy‐Devils Gap 115kV Reconductor ST306 Recon/Rebld near Ford Substation ‐$                25,000$         2,000,000$   ‐$               ‐$              
Recon/Rebld GDN‐SLK 115kV Line ST304 Recon/Rebld South Fairchild Tap ‐$                ‐$               ‐$              ‐$               ‐$              
Beacon‐Bell‐F&C‐Waikiki Reconfiguration ST318 Reconfiguration into Bell and Waikiki ‐$                25,000$         2,000,000$   ‐$               ‐$              
BEN‐MOS Rebuild w/o Reconductor PT305 BEN‐MOS Rebuild w/o Reconductor 8,684,000$     6,802,393$    ‐$              ‐$               ‐$               
Table 19:  Major Rebuild Projects, 2016 – 2020 
Effort will continue to be applied to prioritize replacement spending according to risk and criticality 
rankings, using detailed analysis where appropriate and engaging various stakeholders to arrive at 
optimized business decisions.  In the last several years, detailed simulation studies have repeatedly 
shown major rebuilds as the optimal rebuild option for those lines with older assets and relatively higher 
risk rankings, rather than sectional or partial rebuilds, or minor rebuild options.  Due to the infrequency 
of conductor failures, unless system planning determines a need or benefit for increased capacity, these 
studies indicate rebuilding structures and re‐using the existing conductor as optimal.  Calculated 
Customer Internal Rate of Return (CIRR) are typically at 8% or higher, with strong business risk reduction 
and final assessment scores of 90 or more, placing them in the top 25% of competing capital project 
business cases across the company.  Accordingly, similar simulation studies in the future are expected to 
generate comparable results, i.e. analysis of old, high risk lines will continue to show major rebuilds as 
the optimal rebuild decision from the standpoint of lowest lifecycle costs, including reduced business 
risk and lowest consequence costs for the customer. 
2.  Minor Rebuilds 
The information collected by aerial patrols is used in conjunction with inspection reports to prioritize 
and budget minor rebuild capital projects, where a major rebuild is not justified.  Our goal is to complete 
repairs and replacements for high‐risk issues from 0 to 6 months after identification by aerial or ground 
inspection, and for all other moderate risk issues by the end of the year following the inspection year.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 31 of 61

32 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Planned inspections and follow‐up work in the form of minor rebuilds is effective in maintaining service 
levels while minimizing near‐term capital and O&M costs.  Where warranted and on a line‐by‐line basis, 
detailed simulation modeling helps ascertain the optimal rebuild approach and support a business case 
to compete with others in the company’s capital projects selection and budgeting process.  A system‐
wide simulation model or other method is needed to help validate and/or provide adjustment 
recommendations to our inspection intervals, minor rebuild target budgets, and fact‐based policies on 
minor vs. sectional vs. full rebuild thresholds.   Current policy is to conduct detailed ground inspections 
every 15 years, following up with minor or major rebuilds as condition assessments justify.  Current 
budget plans for minor rebuilds and air switch replacements are listed below, subject to changes.  Given 
the large number of old lines due for inspection, the age profile of air switches and an expected life of 40 
years for each air switch, it is recommended to increase the minor rebuild budget to $2.0 million per 
year and air switch replacements at $264,000 per year.  

Description BI Description2 2016 2017 2018 2019 2020
Tx Minor Rebuilds AMT12 Tx Minor Rebuild ‐ WA 775,000$ 775,000$ 800,000$ 825,000$ 850,000$ 
Tx Minor Rebuilds AMT13 Tx Minor Rebuild ‐ ID 772,262$ 780,249$ 813,420$ 848,117$ 885,022$ 
Sys‐Trans Air Sw Upgrade AMT10 Asset Man Trans Sw Upgrade 225,000$ 225,000$ 230,000$ 230,000$ 235,000$  
Table 20:  Minor Rebuild and Switch Upgrade Budget, 2016 – 2020 
See the Area Work Plans section at the end of this report for a detailed list of minor rebuild projects in 
2015. 
3.  Air Switch Replacements 
Transmission Air Switches (TAS) are used to sectionalize transmission lines during outages or when 
performing maintenance. The frequency of operation varies greatly depending on location.  Some TAS 
may not be operated for years.  
TAS may not operate properly when opened and flashover, possibly tripping the line out. This can be the 
result of a component failure (whips and vac‐rupters) or the TAS may be out of adjustment.  Most TAS 
mis‐operations could be avoided with regular inspection and maintenance, however we currently have 
no planned inspection or maintenance program.  Inspections could range from systematic visual 
inspection to infrared scanning and inspections for corona discharge.  Maintenance could consist of 
exercising switches, lubrication, blade adjustment, replacement of live parts such as contacts and whips, 
and repair of ground mats and platforms. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 32 of 61

33 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Ground grids and platforms are installed at the base of each switch to provide equal potential between 
an operator’s hands and feet in the event of a flashover of the air switch.  The typical ground grid is 
buried copper wire attached to ground rods covered with fine gravel.  Over time the ground grids may 
be damaged by machinery, cattle and erosion, or even theft.  In 2008, 80 TAS were fitted with grounding 
platforms for worker safety.  During this process a new worm gear handle was installed and 
disconnecting whips were adjusted.  Operating pivot joints of the switch mechanisms are not affected 
by this work.  Thus, the 2008 work was safety related, not switch mechanism related.  Remaining 
switches in the system requiring new platforms need to be confirmed and upgraded.  It is estimated that 
close to 100 switches require new platforms. 
With radial switching of the 115kV transmission system, many TAS are operated remotely.  In these 
instances, company personnel are not present to observe the opening of the switch and some problems 
therefore remain hidden.  A small problem could progress to the point where a major failure occurs.  A 
small amount of material is maintained in the warehouse and Beacon yard for emergency repairs, but 
many of the switches are old and parts are often difficult to locate.  
Typically three to four TAS are replaced each year.  A detailed inventory of 115kV TAS outside 
substations was completed in 2013, including determination of age where formerly 20% of the assets 
were unknown.  TAS inventory includes 180 switches of various types and configurations, as shown 
below according to remaining service life.  Based on this profile, levelized replacement should increase 
to five replacements per year, requiring an increase to $264,000 from the current $225,000 annual 
budget.  Annual budgets should be prioritized according to a rational condition assessment and 
quantitative risk assessment, rather than ad‐hoc requests from field personnel and anecdotal 
observation which is the current method. 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 33 of 61

34 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Figure 8:  Air Switch Replacement Value vs. Remaining Service Life 

Thorough investigation of industry best‐practices regarding inspection and planned maintenance of air 
switches, with follow‐up recommendations is recommended.  At minimum, a reasonable condition 
assessment program is envisioned, such as visual inspection at least every two years, possibly annual 
inspection for those more critical switches, and annual performance evaluation based on System 
Operations input.  Below is a prioritized list of switches due for repairs or replacement in the next few 
years, with those switches exhibiting operational problems listed first. 
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
0‐10 10‐20 20‐30 30‐40 40‐50 >50
Re
p
l
a
c
e
m
e
n
t
 Va
l
u
e
Age (Years)
Transmission 115 kV Air Switches 
40 Years Expected Service Life
$750,000 of
Capital 
Assets 
Beyond 
Expected 
Service Life
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 34 of 61

35 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

SW #Problems Age (yrs) LINE/SUBSTATION
A-70 Problem Switch; Scheduled 2016 84 Chelan-Stratford
A-336 Old KPF, Needs Replaced; Scheduled 2016 49 Grangeville-Nez Perce #1: Cottonwood Tap
A-355 Old KPF on a broken pole; Scheduled 2016 48 Jaype-Orofino
A-346 Wood in Switching Mech. Is bowed; Scheduled 2016 47 Grangeville-Nez Perce #2
A-376 Old KPF, Needs Replaced; Scheduled 2016 43 Grangeville-Nez Perce #2
A-298 Needs whips; Center 0 and North 0 gone, South Bent 38 115kv Boulder-Rathdrum
A-158
Doesn't work properly, drop load on both sides then use
switch, mat ground straps need repair 31 Beacon-Francis & Cedar
A-345 Pole Needs Structure # Tag 30 Grangeville-Nez Perce #2
A-442 Repaired in 2015 26 Dworshak-Orofino
A-377 Scott paper tap; Engerized to Switch; Scheduled 2016 21 Grangeville-Nez Perce #2 : Scott Paper Tap
A-176 Mat ground straps need repair 18 Bell-Northeast
A-679 Difficult to Close 15 Othello-Warden #2
A-680 Replaced in 2015 15 Othello-Warden #2
A-358 Old KPF, Needs Replaced 10 Jaype-Orofino
A-407 Broken Crossarms 4 Grangeville-Nez Perce #1
A-421 Ground Cables and Strands cut, NEEDS REPAIR 4 Ramsey-Rathdrum #1
A-184 Replaced in 2015 61 Shawnee-Sunset
A-19 59 Pine Street-Rathdrum: Oldtown Tap
A-26 59 Burke-Pine Creek # 3
A-220 57 Lolo-Nez Perce
A-221 57 Lolo-Nez Perce
A-173 Replaced in 2015 47 Moscow 230-Orofino
A-58 Replaced in 2015 46 Chelan-Stratford
A-295 Replaced in 2015 46 Benewah-Pine Creek : St Maries Tap
A-49 44 Devils Gap-Stratford
A-126 40 8th & Fancher-Latah 115 kV
A-127 40 8th & Fancher-Latah 115 kV  
Table 21:  Air Switch Priority List for Repairs and Replacements 
Finally, transmission outage cause tracking needs to be improved in order to ascertain failure trends for 
the air switch population and to justify long‐term replacement policy, e.g. improved data for line outage 
durations and affected customers that result from failed air switch operations.  In reading through notes 
on the TOR, Asset Management was able to determine that there were 122 outages from 1975 through 
2007, resulting in an average of 3.7 outages per year caused by switches.  The durations and quantified 
consequences of these outages however are unknown and difficult to model. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 35 of 61

36 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

4.  Structural Ground Inspections (Wood Pole Management) 
Avista wood transmission structures are predominately butt‐treated Western Red Cedar poles.  Most of 
the service territory is in a semi‐arid climate.  The most common failure mode for wood poles is internal 
and external decay at or near the ground line.  Transmission Wood Pole Management (WPM) measures 
this decay and determines which poles must be reinforced or replaced.  Details describing inspection 
techniques are in the company’s “Specification for Inspection and Treatment of Wood Poles, S‐622”.   
The testing program is valuable in identification of poles needing replacement or reinforcement, as well 
as identifying other structure components requiring repair or replacement.  Compared to the pre‐1987 
method of solely visual inspections for pole integrity, the testing program replaces about 15% as many 
poles.   
Wood transmission poles are on a 15‐year inspection cycle.  We are currently targeting inspection of 
2,400 wood transmission poles annually out of 36,422 wood poles installed.  At this pace, by 2019 we 
will reach the 15‐year cycle for all transmission lines.  See the Area Work Plans section of this report for 
a list of future planned inspections. 
In recent years, prioritization and scheduling of ground inspections has been based on the time since the 
last ground inspection.  Results of these inspections provide the basis for case‐by‐case analysis and the 
scope of subsequent minor and major rebuild projects on each line.  While it is important that we 
maintain a maximum 15‐year ground inspection cycle, it is recommended that future inspection 
scheduling includes consideration of the risk index, which may justify earlier inspection.  As a general 
rule, critical assets that exhibit age‐related failures should be inspected to verify condition and justify 
service extension or removal near the end of their expected service lives.  We currently have many 
115kV lines (non‐Western Electricity Coordinating Council pathways) with assets 10 or more years past 
expected service life, that have not been inspected for nearly 20 years.  This poses a significant unknown 
risk. 
If actual condition assessment warrants service extension, shorter inspection intervals are prudent when 
the time to failure characteristics worsen with age – as is the case with much of our transmission wood 
infrastructure.   Approximately 17% of the system is beyond its expected life, with a large portion of 
those assets over 15 years since the last ground inspection.  The scattered age profile on many lines that 
results over many decades from periodic minor rebuilds and one‐off replacements, makes this situation 
difficult to remedy – one must choose between the pros and cons of spotty replacements when failure 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 36 of 61

37 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

occurs on one end of the spectrum, to larger line section replacements and full rebuilds on the other. 
Regardless, for those lines that have significant sections or quantities of older assets that demonstrate 
higher relative risks, out‐of‐cycle inspection and a shorter inspection interval may be warranted (e.g. 10 
years instead of 15). 
5.  Structural Aerial Patrols 
The Avista transmission system covers a large geographical area that has all types of terrain.  
Transmission Aerial Patrols (TAP) have been utilized to provide a quick above‐ground inspection to 
identify significant problems that require immediate attention, such as lightning damage, cracked or 
sagging crossarms, fire damage, bird nests and danger trees.   
In addition, aerial patrols can identify improper uses of the transmission Right‐of‐Way (R/W), such as 
dwellings, grain bins, and other types of clearance problems that must be addressed.  Typically, the 
patrol will be performed in the spring.  Identified repairs, depending on severity, are scheduled to be 
performed within 6 months. 
TAP inspects 100% of 230kV lines and 70% of 115kV lines annually.  The remaining 30% of 115kV lines 
are located in urban areas that are frequently viewed by line personnel for potential problems.  The 
Transmission Design group schedules patrols for each service territory.  The TAP areas are: Spokane 
(includes Othello, Davenport and Colville), Coeur d’Alene (includes Kellogg and St. Maries), Pullman, and 
Lewiston/Clarkston (includes Grangeville and Orofino).  
Aerial patrols are performed by qualified personnel from Transmission Design, often accompanied by 
local office personnel.  Inspection forms have been developed that contain a weighting system to 
identify the severity of defects.  This information can then be utilized to make recommendations for 
necessary repairs.   
6.  Vegetation Aerial Patrols and Follow‐up Work 
The Transmission Vegetation Management (TVM) program maintains the transmission system clear of 
trees and other vegetation, in order to provide safe clearance from trees and reduce outages caused by 
trees, weather, snow, ice and wind.   
The entire 230kV system is annually inspected with a combination of aerial and ground patrols by the 
System Forester, who solely manages the overall program.  Select 115kV lines are also patrolled 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 37 of 61

38 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

according to criticality.  In addition, vegetation issues noted during structural aerial patrols on the 115kV 
system, as well as fielding of transmission line projects by Transmission Engineering are relayed to the 
System Forester.  Based on this information, follow‐up work plans are adjusted and executed with 
contract crews over the course of the year. 
Over the next ten years, annual budgets of $1.2 million are recommended to allow for optimal 
completion of major re‐clearing work and a transition to Integrated Vegetation Management.  It is 
expected that annual budgets will be evaluated and fine tuned to fit workloads as appropriate. 
See the Transmission Vegetation Management Program reference (Avista Utilities, 2012) for more 
details on the program.   
7.  Fire Retardant Coatings 
After several fires and a 2008 study to initiate systematic remediation, fire retardant coating has been 
applied to the base of wood transmission poles system‐wide.  At this point the entire 230kV system has 
been deemed adequately protected and the 115kV system is approximately 37% complete.  Given the 
fire event of last year, the Lolo‐Oxbow 230kV line is planned for early recoating in 2016 to reduce risk 
(coatings are expected to remain effective for 12 years, Lolo‐Oxbow was coated in 2007).  Targeted 
areas include those subject to grassland fires and in close proximity to railroads.  Protective coating is 
not applied to heavily forested areas as it is deemed inadequate in these areas to merit the cost of 
application. 
It is estimated that approximately 4,210 poles remain to be coated in the 115kV system.  Following the 
current plan to coat 179 poles in 2015 (179 115 kV poles and 535 230 kV poles repainting the Lolo – 
Oxbow line was cut from the 2015 scope of work due to budget), it is recommended to coat 1000 poles 
per year for the following five years to complete the work by 2020.  At a total labor and materials cost of 
$242/pole, this equates to $242,000/year.  Beyond this, regular maintenance and upkeep will only be 
required, at an unknown amount depending on the longevity of the coatings.  Until better information is 
obtained, $50k/year for ongoing coating maintenance is estimated.  Performance metrics could be 
considered to monitor performance of this program, possibly in terms of % of the system protected, 
maintenance spending and actual fire damage costs.  As noted in the Outages section, pole fire incidents 
have increased, reinforcing the necessity of monitoring and adjustment of this program. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 38 of 61

39 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

See Whicker (2013) for more details and history of this program, which is now administered by the 
Transmission Design group. 
8.  230kV Foundation Grouting 
The Noxon‐Pine Creek and Cabinet – Rathdrum 230kV circuits have unique steel structures where the 
interface between the steel sleeve in the foundation and above‐ground structure requires re‐grouting 
after approximately 30 years, to avoid destructive corrosion.  This work has been completed on the 
Noxon‐Pine Creek 230kV line.   Approximately $350k out of $500k of foundation grouting work on 
Cabinet – Rathdrum 230kV was completed through 2015.   Another $100k/year is planned through 
project completion in 2017. 
9.  Polymer Insulators 
Transmission Line Polymer Insulators (TPI) provide insulation at the connection points for transmission 
lines to the supporting structure.  Other types of insulators include toughened glass and older porcelain 
types.  Although no significant problems have been noted on 115kV lines, there were numerous faults 
on 230kV lines from 1998 to 2008 attributable to poly insulators causing line outages, and five 
mechanical failures that caused the line to fall. 
In 2008 a plan was initiated to replace TPIs and install corona rings on dead‐end TPI insulators on various 
230kV lines (without corona rings, TPIs are expected to fail in the 10 – 15 year timeframe, with corona 
rings the expected service life is extended to an unknown age). 
Work was completed primarily in 2009 on N. Lewiston ‐ Shawnee 230kV and Dry Creek – N. Lewiston 
230kV, and in 2011 all suspension and dead‐end TPIs on the Hatwai ‐ N. Lewiston 230kV were replaced 
with toughened glass insulators.   
This work appears to have been effective.  From 2009 to 2012, only 2 sustained outage occurrences 
involving insulators are recorded.  However, the degree to which TPIs exist on the remainder of the 
system and the prediction of current and future risk is unknown.   
For this reason, it is recommended that at least on 230kV lines, future ground inspections include 
information gathering on the insulator type, so that an analysis of risk and optimal mitigation actions 
may be made in a short time period should that become necessary. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 39 of 61

40 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Current transmission engineering standards use toughened glass insulators for 230kV, and either 
toughened glass or poly insulators for 115kV.  Due to the lighter weight of polymer insulators, they are 
generally preferred by Avista crews.  However, given the problems experienced on 230kV lines and 
anecdotal evidence of high scrap rates for TPIs on 115kV projects, their use on 115kV lines poses some 
unknown risks and a systematic monitoring program may be advisable.   
10.  Conductor & Compression Sleeves 
Credible condition and failure characteristics of conductor and compression sleeves (dead ends), and 
the location and age of thousands of compression dead ends in the system are currently unknown.  
Provided proper installation, protection, and service conditions, most conductor will last over 100 years, 
if not indefinitely.  The compression dead ends, however, are expected to last between 40 and 50 years, 
posing a more immediate reliability risk.   
Between 2008 and 2010, an effective risk mitigation program was carried out for in‐line compression 
dead ends on 230kV AAC lines, following several years of one to two failures per year.  Since then, no 
known in‐line compression dead end failures have occurred.    See Whicker (2009) for more details on 
the 230kV in‐line sleeve mitigation project.  
In 2015, Noxon‐Pine Creek 230 kV was inspected and all failed compression dead ends were replaced.  
Compression dead ends that could fail in the future were identified.  This data was gathered and sent 
back to the compression dead end manufacturer, AFL.  The manufacturer ran a failure analysis on all the 
compression dead ends that failed and determined that the ones that failed didn’t have the joint 
compound (oxide inhibitor) in the compression dead end.  Avista’s transmission department looked into 
this and determined that the specifications didn’t call for the inhibitor.  More than likely the inhibitor 
was not applied by the crew/contractor and that is why the compression dead ends failed.  The 
transmission design department has now added the inhibitor to the specifications and they will make 
sure the crew/contractor puts the inhibitor inside the compression dead end.   
Program Ranking Criteria 
Programs implemented in the Transmission Department are chosen based on ranking criteria which 
consist of the customer internal rate of return, risk reduction ratio, revised risk score, and health index.  
The health index currently is not identified for each transmission program; however, each program is 
based upon the customer internal rate of return (CIRR) and revised risk score.  The lower the revised risk 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 40 of 61

41 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

score, the higher the rank for that program.  The revised risk score is based upon the financial impact 
risks (consequential costs/revenues); legal, regulatory, and external business affairs risks; customer 
service and reliability risks; and the likelihood of each risk occurring per year.  Table 22 details current 
Transmission Department programs and their ranking criteria. 
Program Customer Internal Rate of Return Risk Reduction Factor Revised Risk Score Health Index
Transmission ‐ NERC High Priority Mitigation 5% ≤ CIRR < 9%0.011 1 N/A
Transmission ‐ NERC Medium Priority Mitigation Cirr = 9%0.003 1 N/A
Transmission ‐ NERC Low Priority Mitigation Cirr = 9%0.003 1 N/A
Transmission ‐ New Construction Cirr = 8%0.003 1 N/A
Transmission ‐ Reconductors and Rebuilds Cirr = 10%0.011 1 N/A
Transmission ‐ Asset Management Cirr = 10%0.042 12 N/A  

Table 22:  Program Ranking Criteria 

The NERC High, Medium, and Low Mitigation programs reconfigure insulator attachments, and/or 
rebuilds existing transmission line structures, or removes earth beneath transmission lines in order to 
mitigate ratings/sag discrepancies found between "design" and "field" conditions as determined by 
LiDAR survey data.  This program was undertaken in response to the October 7, 2012, North American 
Electric Reliability Corporations (NERC) "NERC Alert" ‐ Recommendation to Industry, "Consideration of 
Actual Field Conditions in Determination of Facility Ratings".  Mitigation brings lines in compliance with 
the National Electric Safety Code (NESC) minimum clearances values.  These code minimums have been 
adopted into the State of Washington's Administrative Code (WAC). 
The NERC High Priority Mitigation Capital Program (ER2560) covers mitigation work on Avista's "High 
Priority" 230kV transmission lines, including: Benewah‐Pine Creek (BI CT203), Cabinet‐Noxon (BI AT203), 
Cabinet‐Rathdrum (BI CT202), Hatwai‐North Lewiston (BI LT205), Lolo‐Oxbow (BI LT202), and Noxon‐
Pine Creek (BI AT202). 
The NERC Medium Priority Mitigation Capital Program (ER25xx) covers mitigation work on Avista's 
"Medium Priority" 230kV and 115kV transmission lines, including  North Lewiston‐Shawnee 230kV, 
Beacon‐Bell #4 230kV, Beacon‐Bell #5 230kV, Noxon‐Hot Springs #2 230kV, Beacon‐Boulder #2 115kV, 
Beacon‐Francis & Cedar 115kV, 9th & Central‐Otis 115kV, Northwest‐Westside 115kV, Dry Creek‐Talbot 
230kV, Walla Walla‐Wanapum 230kV, Benewah‐Moscow 230kV, Devils Gap‐Stratford 115kV.   
The NERC Low Priority Mitigation Capital Program (ER25xx) covers mitigation work on Avista's "Low 
Priority" 230kV and 115kV transmission lines.   
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 41 of 61

42 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

The Transmission New Construction Program supports addition of new switching stations and 
substations to the system in order to serve new and growing load as well as for increased system 
reliability and operational flexibility.  Projects include ER2578: HAT‐LOL #2 230kV and 25xx: Westside‐
Garden Springs 230kV. 
The Transmission Reconductors and Rebuilds Program reconductors and/or rebuilds existing 
transmission lines as they reach the end of their useful lives, require increased capacity, or present a risk 
management issue. Projects include: ER 2310 ‐ West Plains Transmission Reinforcement,  ER 2550 ‐ Pine 
Creek‐Burke‐Thompson, ER 2557 9CE‐Sunset Rebuild, ER 2423 ‐ System Condition Rebuild, ER 2457 
Benton‐Othello Rebuild, ER2556 CDA‐Pine Creek Rebuild, ER 2564 Devils Gap‐Lind Major Rebuild, ER 
2574 ‐ Chelan‐Stratford River Crossing Rebuild, ER 2576a Addy‐Devils Gap Reconductor, ER 2575 Garden 
Springs‐Silver Lake Rebuild, ER 2582 BEA‐BEL‐F&C‐WAI Reconfiguration, ER 2577 BEN‐M23 Rebuild, ER 
25xa ‐ Out‐Year Transmission Rebuild.  The Transmission Asset Management Program covers the follow‐
up work to the Wood Pole Inspection in ER 2057 and Air Switch Replacements in ER 2254. 
Benchmarking 
Asset replacement spending relative to other utilities is one area of particular interest.  A 2008 study 
performed by First Quartile Consulting gathered data from 17 utilities of various sizes and geographic 
service territories in the U.S. and Canada, providing the 3‐year average transmission line replacement 
capital spending per asset as shown in the figure below.   

Figure 9:  3‐year Transmission Lines Replacement Capital Spending per Asset  
(First Quartile Consulting, 2008) 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 42 of 61

43 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

This shows that out of seven companies providing data, the median was 1.93% and the mean was 2.41% 
over a three year period.  Avista’s comparable replacement spending over the last two years and the 
recommended annual replacement spending over a 30‐year period are shown in the table below. 
7,877,719$         2014 planned replacement spending
3,040,313$         2014 unplanned/emergency replacement spending
10,918,032$       2014 total replacement capital spending
1,140,319,249$ Transmission asset replacement value
0.96% 2014 replacement spending capital per asset
19,074,307$       2015 planned replacement spending
2,180,921$         2015 unplanned/emergency replacement spending
21,255,228$       2015 total replacement capital spening
1,140,319,249$ Transmission asset replacement value
1.86% 2015 replacement spending capital per asset
21,135,371$       Recommended planned annual replacement spending (30 year plan)
1,321,019$         Targeted unplanned/emergency replacement spending
22,456,390$       Targeted total replacement capital spending (30 year plan)
1,140,319,249$ Transmission asset replacement value
1.97% Recommended replacement spending capital per asset  
Table 23:  Avista Transmission Lines Replacement Capital Spending per Asset 

This shows that Avista’s capital replacement spending over the last two years is lower than the study’s 
average, close to the lowest of the seven reported utilities.  Comparably, the recommended capital 
replacement spending as part of a levelized 30‐year plan of $21.1 million (planned work) plus an 
assumed $1.3 million unplanned emergency work results in 1.97%, very near the study’s median and 
less than the average. 
Idaho Power is a very good benchmark utility for Avista in terms of size, operating environment and 
electric transmission component and system similarities.  In discussions with their staff, thorough 
transmission structure ground inspections are conducted every 10 years, with quick visual inspections 
(drive‐bys) every 2 years.  It is also clear that in general, Idaho Power spends considerably more time 
and effort on O&M maintenance activities relative to Avista, at least in areas of transmission and 
substation systems. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 43 of 61

44 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Idaho Power is also projecting a significant rise in capital replacement of aging infrastructure in the next 
several decades, as shown below.  Over just the next 10 years, this indicates a total capital spend for 
Idaho Power of $211 million for replacement of wood poles alone, or $21 million per year levelized.  This 
is similar in magnitude to the recommended replacement of aging wood infrastructure at Avista over 
the next several decades. 

Figure 10:  Idaho Power Long‐term Replacement Costs 
As stated previously, investigation of air switch maintenance practices of various utilities indicates that 
most utilities perform a much greater degree of maintenance than Avista. 
In terms of broader maintenance benchmarking, a study through a CEATI report (excerpts below) show 
that Avista is among the majority of peers conducting aerial patrols once per year, but that of all 15 
utilities responding, we have the longest ground inspection interval at 15 years, as compared to the 
most common interval of 10 years. 
This does not necessarily mean that our inspection interval needs to be shortened.  However, it does at 
least indicate where we stand relative to other utilities participating in the survey, and at minimum 
would tend to discourage extending our inspection interval any further. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 44 of 61

Figure 11:  Maintenance Benchmarking: Aerial Patrols (left) and Pole Inspections (right) 
Data Integrity 
The following table lists the various sources of information used for Asset Management purposes.  Data 
gathering from non‐electronic sources, as well as mining and cleaning of available information makes up 
a disproportionately large amount of current work for Asset Management staff, on the order of 80% of 
total work.  Long term, in order to provide the most value to Avista this needs to be reversed with 80% 
applied to analyzing data and 20% to gathering and cleaning data.  

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 45 of 61

46 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Data Integrity ‐ Electric Transmission System
Status Data Source Notes/Comments
AFM Wood species info missing for 115kV; potentially large # of stubs 
entered as pole installs, major job backlog updates pending from 1992
Line History Binder Great historical info but hasn't been updated for 15 years
Safety information Unable to isolate to Transmission work
Plan & Profile (P&P drawings)Major job backlog updates pending from 1992 to present; long term 
migration to digital (PLS‐CADD) format
WPM database
Pole information is not updated to reflect followup work or other 
projects, just at time of inspection; handnotes need to be 
consolidated and alphebetized, line naming conventions need to be 
synced up; wood species in hand notes and electronic files needs to 
be uploaded to AFM
Maximo Does not always capture component failure mode data as designed
Transmission Engineering Guidelines Partially complete, need more participation to complete
Engineering files vault Engineers need to submit as‐built updates more promptly, "archived" 
files need to be refiled in their proper line section
Discoverer Unwieldly to summarize costing across different Tx projects, difficult 
to isolate costs/activities to Tx
AWB simulations Building on progress/standards/methods
PLS‐CADD and design/construction 
standards Progress continues, published new standards in 2014
Air Switch Master Inventory 
Spreadsheet Updated inventory and detailed info complete
OMT data
Mostly reliable info but some categories are mixed with substations, 
for example PMs that really are transmission related are placed in 
subs  
Table 24:  Transmission Asset Data Integrity 
We are 100% complete processing updates to a backlog of 459 transmission jobs dated from 1992 to the 
present in our GIS/AFM database and on plan and profile (P&P) drawings.  WPM inspection records in 
handnote form have been entered electronically.  Pole material type, location and installation dates 
have been synchronized with updated AFM information.  However, this clean dataset now exists in 
spreadsheet form and needs to be uploaded to AFM.  Line history binders are in the process of being 
updated and converted to electronic files.   Engineers are following the construction as‐built recording 
process, however prompt updates continue to be problematic.  A realistic goal of 6‐months from the 
completion of construction to records updating complete and project close‐out has been established.  
Maximo implementation is in progress.  It appears that many years will be needed to obtain quality data 
that may be effectively used for asset management purposes. The new transmission construction 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 46 of 61

47 2016 Electric Transmission System Asset Management Plan 
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standards are a major accomplishment and are being used as a baseline for improvement on a regular 
basis. 
Material Usage 
According to Supply Chain staff, a definitive list of parts, quantities and funds spent on transmission 
work is currently unavailable.  The following list of materials was tabulated from a query of the Oracle 
database for those projects listed as Transmission from October 2010 to October 2012.  This should not 
be taken as complete costing information, but may be reasonably considered accurate for the relative 
use of material categories. 

Table 25:  Relative Material Purchases, 10/2010 – 10/2012 
Root Cause Analysis (RCA) 
Following the Othello storm in September 2013, a team was formed to study the causes of the event 
and develop effective solutions to prevent recurrence, as appropriate.  Representatives from 
Transmission Design, Asset Management, Distribution Engineering, Construction Services, and Spokane 
Electric participated.  In addition to technical forensics, a rigorous methodology was followed known as 
the “Apollo Root Cause Analysis methodTM ”, requiring evidence and team consensus to develop 
effective solutions.  Not only the root causes, but also the significance of the event and the more severe 
consequences that were narrowly avoided were unexpectedly discovered through the team’s 
Category Total Amount %
steel poles $1,770,582 44%
other $466,378 12%
fire retardant coating $445,514 11%
crossarms $349,709 9%
air switches $293,131 7%
conductor $259,622 6%
insulators $228,702 6%
crossbraces $96,212 2%
vibration dampers $78,916 2%
wood poles $52,927 1%
total $4,050,929 100%
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 47 of 61

48 2016 Electric Transmission System Asset Management Plan 
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deliberations.  A summary report was generated and a number of significant action items initiated to 
prevent or mitigate similar events in the future.   
Unexpected events such as the Othello storm, while undesirable, in many cases offer rare opportunities 
to learn and improve.  No single formula or approach is generically applicable to all problems.  However, 
the Apollo RCA method or close variant is applicable to many, and it is hoped that it may be used to 
greater effect in the future.  Lessons learned from this effort will inform the next RCA effort if/when it 
arises. 
System Planning Projects 
The tables below list substation and transmission projects at various stages from study through 
construction.  This list is a snapshot of current plans and is subject to frequent change.  For more details, 
see the System Planning Assessment (Avista, 2015).  The first two tables below list projects classified as 
corrective action plans in order to mitigate performance issues.  The last two tables contain projects 
that are not categorized as corrective action plans.  
Overall, customer and load growth is low at about 1%, and is expected to remain stagnant for many 
years.  Customer loads may even decrease over the next few years, due to continued conservation and 
efficiency trends such as the conversion to LED lighting.  One exception to this is in the West Plains area, 
which is forecasted to grow at a higher rate in both the residential and business sectors for several 
years.  Major system planning needs include adding transformer capacity, and improved redundancy 
around the Spokane area.  This will most likely be best accomplished by the addition of new, looped 
230kV transmission lines around Spokane. 
Clear, objective ranking and decision criteria and its consistent use in the company’s capital project 
selection and budgeting process is recommended, in order to reduce the time and effort required to 
develop, review, approve, prioritize, and execute construction projects. 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 48 of 61

49 2016 Electric Transmission System Asset Management Plan 
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Table 26:  Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston)  

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 49 of 61

50 2016 Electric Transmission System Asset Management Plan 
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Table 27:  Corrective System Planning Projects (Palouse, Spokane and System) 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 50 of 61

51 2016 Electric Transmission System Asset Management Plan 
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Table 28:  Non‐Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 51 of 61

52 2016 Electric Transmission System Asset Management Plan 
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Table 29:  Non‐Corrective System Planning Projects (Palouse, Spokane and System) 
Area Work Plans 
The following transmission projects are scheduled for work based on a variety of factors including 
changing system and operational requirements, remaining service life, asset condition, and 
performance.  This list is provided for planning and reference purposes only.  It represents current plans 
and is subject to frequent change.  See the Transmission Engineering Manager for the latest revision.  
Those items with no marks for any year represent tentative projects under consideration. 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 52 of 61

53 2016 Electric Transmission System Asset Management Plan 
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See the end of the list for the current minor rebuild and ground inspection schedule, which typically 
drives follow‐up repairs and minor rebuilds the following year (when a major rebuild is not justified 
based on condition assessment). 

TRR = Transmission Rebuild/Reconductor Program Business Case
NT = New Transmission Program Business Case
PS = Project Specific Business Case
TAM = Transmission Asset Management Program Business Case
SDSR = Substation ‐ Distribution Station Rebuild Program Business Case
SNDS = Substation ‐ New Distribution Stations Program Business Case
SVTR = Spokane Valley Transmission Reinforcement Program Business Case
HPRM = High Priority Line Ratings Mitigation Program Business Case
MPRM = Medium Priority Line Ratings Mitigation Program Business Case
LPRM = Low Priority Line Ratings Mitigation Program Business Case
NG = New Growth  
Table 30:  Project Type Key  

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 53 of 61

54 2016 Electric Transmission System Asset Management Plan 
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Business Case Area ER Description 2016 2017 2018 2019
   TRR All Sys ‐ Rebuild Trans ‐ Condition X X
All Trans Air Switch Platform Grd Mat X
  LPRM All LP Line Ratings Mitigation Project X
  LPRM All LP Line Ratings Mitigation Project X
    PS Big Bend Harrington 115‐4kV X
  SNDS Big Bend Bruce Siding 115 Sub ‐ New X X
   TRR Big Bend Ben‐Oth SS 115 ‐ ReCond/ReBld X X
    TR Big Bend Devils Gap‐Lind 115kV Rebuild X X X X
  SDSR Big Bend Ford 115‐13kV Sub X X X
  SDSR Big Bend Little Falls 115kV Sub X X X X
    TR Big Bend Chelan‐Stratford 115kV X
  SDSR CDA Bronx 115‐21 Sub ‐ Construct X X
    TR CDA CDA‐Pine Creek 115kV Rebuild X X
    TR CDA Cabinet‐Noxon 230kV X
    TR CDA Benewah‐Pine Creek 230kV X
    PS CDA Cabinet Gorge 230kV Switchyard X
  SNDS Lewis‐Clark Wheatland 115 Sub ‐ Construct X X
    NT Lewis‐Clark Hatwai‐Lolo #2 230kV X X X
    TR Lewis‐Clark Lolo‐Oxbow 230kV X
  SNDS Palouse Bovill 115kV Substation ‐ New X X
    TR Palouse Benewah‐Moscow 230kV X X
  SDSR Spokane Sunset 115kV Sub ‐ Rebuild X X
    TR Spokane West Plains Trans Reinforcement X X
  SNDS Spokane Downtown East 115 Sub‐ New X
  SDSR Spokane 9CE 115 Sub ‐ Rebuild/Expand X X
  SNDS Spokane Greenacres 115 Sub ‐ Construct X X
  SVTR Spokane Irvin SS 115 ‐ Construct X X X X
    PS Spokane Westside 230kV Sub ‐ Rebuild X X
    PS Spokane Garden Springs 230‐115‐13 Sub X X X X
  SVTR Spokane Opportunity Sub 115‐13kV X
  SDSR Spokane Northwest 115‐13kV Sub X X
    TR Spokane Garden Springs ‐ Silver Lake 115kV X X
    TR Spokane BEA‐BEL‐F&C‐WAI 115kV X
    PS Spokane 9CE Sub ‐ New 230kV Transformation X
    NT Spokane Westside/Garden Springs 230/115 X  
Table 31:  Area Work Plans – Major Projects  

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 54 of 61

55 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

2016 Minor Rebuilds (following previous ground inspections)
Area Transmission Line kV
Spokane Beacon ‐ Boulder #2 115kV
CDA Benewah ‐ Boulder 230kV
CDA Benewah ‐ Pine Creek ‐ 115kV 115kV
CDA Benewah ‐ Pine Creek ‐ 115kV: St Maries Tap 115kV
Lewis‐Clark Dry Creek ‐ N. Lewiston ‐ 230kV 230kV
Lewis‐Clark Dry Creek ‐ Pound Lane 115kV
CDA Hot Springs ‐ Noxon #2 230kV
Lewis‐Clark Moscow 230 ‐ Orofino 115kV
Lewis‐Clark Nez Perce ‐ Orofino 115kV
Spokane Ninth & Central ‐ Sunset 115kV
Big Bend Othello Sw. Sta ‐ Warden #1 115kV
CDA Benewah ‐ Pine Creek ‐ 115kV: St Maries Tap 115kV  
Table 32:  Minor Rebuilds 

Area Transmission Line kV #Wood Poles
OTHELLO LIND ‐ WARDEN 115KV 491
CLARKSTON JAYPE ‐ OROFINO 115KV 395
CLARKSTON GRANGEVILLE ‐ NEZ PERCE (GRANGEVILLE TAP)115KV 9
CLARKSTON GRANGEVILLE ‐ NEZ PERCE #2 115KV 487
DAVENPORT CHELAN ‐ STRATFORD 115KV 1197
SPOKANE BEACON ‐ BOULDER #5 230KV 6
2585 Year 2016 Total

Table 33:  Ground Inspection Plan 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 55 of 61

56 2016 Electric Transmission System Asset Management Plan 
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References 
Avista (2015).  Transmission Vegetation Management Program.   
Avista (2015).  Avista System Planning Assessment.   
Avista (2014).  Specification for Inspection and Treatment of Wood Poles, S‐622.   
Avista (2013).  2013 Electric Integrated Resource Plan.   
Dan Whicker (2013).  Fire Guard Coating for Wood Transmission Poles.  April 16, 2013 
Dan Whicker (2009).  230kV Transmission Compression Sleeve Couplings.   
Dean Spratt (2015). Transmission Outage Report 2015. 
First Quartile Consulting (2008).  Hydro One Update of Transmission Benchmark Study.   
September 19, 2008 
Ken Sweigart (2015).  Transmission Capital Budget 5‐Year Plan.   
Rendall Farley and Valerie Petty (2013).  2012 Transmission System Review.  April 15, 2013. 
Rendall Farley and Tia Benjamin (2014).  Electric Transmission System 2014 Annual Update.   
March 31, 2014 
Reuben Arts (2015).  Reliability Data 2015. 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 56 of 61

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Appendix A –Transmission Probability, Consequence & Risk Index 
Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Lolo ‐ Oxbow 230 63.41 $45,655,200 85.4 100.0 100.0 
Noxon ‐ Pine Creek 230 43.51 $31,327,200 80.5 87.8 82.8 
Benewah ‐ Pine Creek 230 42.77 $30,794,400 68.3 87.8 70.3 
Walla Walla ‐ Wanapum 230 77.78 $56,001,600 68.4 83.7 67.1 
Benewah ‐ Boulder 230 26.15 $18,828,000 67.1 72.9 57.3 
Hot Springs ‐ Noxon #2 230 70.05 $50,436,000 66.0 68.8 53.2 
Dry Creek ‐ Talbot 230 28.27 $20,354,400 51.4 78.3 47.1 
Latah ‐ Moscow 115 51.41 $21,592,200 96.0 41.7 47.0 
Devils Gap ‐ Stratford 115 86.19 $36,199,800 100.0 39.0 45.6 
Post Street ‐ 3rd & Hatch 115 1.76 $3,696,000 70 100 43 
Benewah ‐ Moscow 230 44.28 $31,881,600 61.1 59.3 42.5 
Cabinet ‐ Rathdrum 230 52.3 $37,656,000 41.7 86.4 42.3 
Bronx ‐ Cabinet 115 32.38 $13,599,600 59.4 55.2 38.4 
Metro ‐ Post Street 115 0.5 $1,890,000 60 100 38 
Ninth & Central ‐ Sunset 115 8.63 $3,624,600 39.0 75.6 34.7 
Burke ‐ Pine Creek #3 115 23.79 $9,991,800 67.0 44.4 34.6 
Shawnee ‐ Sunset  115 61.51 $25,834,200 79.0 36.3 33.4 
Sunset ‐ Westside 115 10.03 $4,212,600 53.0 53.9 33.2 
Hatwai ‐ Lolo 230 8.27 $5,954,400 28.9 93.2 31.6 
Burke ‐ Pine Creek #4 115 23.13 $9,714,600 69.0 37.6 30.4 
Beacon ‐ Boulder #2 115 13.73 $5,766,600 38.7 66.1 29.9 
Addy ‐ Devil's Gap 115 43.31 $18,190,200 58.0 43.0 29.3 
Othello Sw. Sta ‐ Warden #2 115 16.56 $6,955,200 53.7 45.8 28.8 
Pine Street ‐ Rathdrum 115 33.24 $13,960,800 47.0 51.2 28.3 
Benton ‐ Othello Switch Station 115 26.07 $10,949,400 64.0 37.6 28.3 
CdA 15th St ‐ Pine Creek 115 29.75 $12,495,000 83.0 28.1 27.3 
Cabinet ‐ Noxon 230 18.51 $13,327,200 31.3 71.5 26.3 
Chelan ‐ Stratford 115 49.44 $20,764,800 66.6 32.2 25.1 
Moscow 230 ‐ Orofino 115 41.59 $17,467,800 84.0 25.4 25.0 
Boulder ‐ Rathdrum 115 19.07 $8,009,400 58.6 36.3 24.9 
Benewah ‐ Pine Creek 115 45.02 $18,908,400 67.0 29.5 23.2 
Jaype ‐ Orofino 115 34.64 $14,548,800 66.6 29.5 23.0 
Clearwater ‐ N. Lewiston 115 3.21 $1,348,200 30.7 63.4 22.8 
Ninth & Central ‐ Otis Orchards 115 16.31 $6,850,200 28.9 66.1 22.4 
N. Lewiston ‐ Shawnee 230 34.28 $24,681,600 33.2 56.6 22.0 
Burke ‐ Thompson Falls A 115 3.96 $1,663,200 34.4 53.9 21.7 
College & Walnut ‐ Post Street 115 0.54 $2,041,200 2.8 100 21 
Beacon ‐ Bell #4 230 6.3 $4,536,000 22.8 78.3 20.9 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 57 of 61

58 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Devil's Gap ‐ Lind 115 73.74 $30,970,800 95.1 18.6 20.8 
Dry Creek ‐ Lolo 230 11.23 $8,085,600 29.5 59.3 20.5 
Eighth & Fancher ‐ Latah 115 26.27 $11,033,400 55.6 30.8 20.1 
Coulee ‐ Westside 230 1.99 $1,432,800 27.1 62.0 19.7 
Benewah ‐ Thornton 230 32.2 $23,184,000 27.1 60.7 19.3 
Shawnee ‐ Thornton 230 27.83 $20,037,600 27.1 60.7 19.3 
Hatwai ‐ Moscow 230 18.05 $12,996,000 27.7 59.3 19.2 
Grangeville ‐ Nez Perce #2 115 37.17 $15,611,400 53.0 29.5 18.4 
Bell ‐ Northeast 115 1.53 $642,600 42.2 48.5 18.1 
Addy ‐ Kettle Falls 115 27.11 $11,386,200 27.7 55.2 17.9 
Burke ‐ Thompson Falls B 115 3.97 $1,667,400 28.3 53.9 17.9 
Bell ‐ Northeast 115 2.83 $1,188,600 31.9 34.9 17.3 
Francis & Cedar ‐ Northwest 115 2.12 $890,400 30.7 47.1 16.9 
Grangeville ‐ Nez Perce #1 115 26.9 $11,298,000 48.0 29.5 16.7 
Lolo ‐ Nez Perce 115 41.2 $17,304,000 55.7 25.4 16.6 
Lolo ‐ Pound Lane 115 10.25 $4,305,000 40.0 34.9 16.5 
Beacon ‐ Bell #5 230 6.04 $4,348,800 18.0 78.3 16.5 
Dworshak ‐ Orofino 115 3.62 $1,520,400 21.6 64.7 16.4 
Airway Heights ‐ Devils Gap 115 20.6 $8,652,000 22.8 60.7 16.2 
Beacon ‐ Ross Park 115 2.06 $865,200 20.4 67.5 16.1 
Lind ‐ Warden 115 21.71 $9,118,200 44.5 30.8 16.1 
Hatwai ‐ N. Lewiston 230 6.99 $5,032,800 18.0 75.6 15.9 
Metro ‐ Sunset 115 2.87 $1,205,400 24.6 52.5 15.1 
Devils Gap ‐ Ninemile 115 18.78 $7,887,600 28.9 44.4 15.0 
Beacon ‐ Boulder #1 115 13.07 $5,489,400 38.7 32.2 14.6 
Moscow 230‐ Terre View 115 11.94 $5,014,800 40.4 30.8 14.6 
Bronx ‐ Sand Creek 115 6.62 $2,780,400 30.7 40.3 14.5 
Beacon ‐ Ninth & Central #2 115 3.5 $1,470,000 22.8 53.9 14.4 
Beacon ‐ Bell #1 115 6.86 $2,881,200 29.5 41.7 14.4 
Lind ‐ Shawnee 115 75.81 $31,840,200 83.6 14.6 14.3 
Moscow 230 ‐ Orofino 115 21.33 $8,958,600 50.0 24.1 14.1 
College & Walnut ‐ Westside 115 8.79 $3,691,800 24.0 49.8 14.0 
Northwest ‐ Westside 115 1.95 $819,000 24.0 49.8 14.0 
Ross Park ‐ Third & Hatch 115 2.19 $919,800 19.2 60.7 13.6 
Beacon ‐ Northeast 115 5.25 $2,205,000 30.7 41.7 13.5 
Ninemile ‐ Westside 115 6.8 $2,856,000 22.8 49.8 13.3 
Nez Perce ‐ Orofino 115 17.28 $7,257,600 27.7 40.3 13.1 
Post Falls ‐ Ramsey 115 9.01 $3,784,200 28.9 36.3 12.3 
Addy ‐ Gifford 115 20.68 $8,685,600 51.9 20.0 12.2 
Ramsey ‐ Rathdrum #1 115 8.42 $3,536,400 24.0 41.7 11.7 
Beacon ‐ Boulder 230 11.95 $8,604,000 17.4 56.6 11.5 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 58 of 61

59 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Beacon ‐ Ninth & Central #1 115 3.73 $1,566,600 18.0 53.9 11.3 
Stratford ‐ Summer Falls 115 6.3 $2,646,000 18.0 53.9 11.3 
Beacon ‐ Francis & Cedar 115 11.56 $4,855,200 34.3 28.1 11.3 
Appleway ‐ Rathdrum 115 11.77 $4,943,400 20.4 47.1 11.2 
Shawnee ‐ Terre View 115 10.05 $4,221,000 30.1 30.8 10.9 
Dry Creek ‐ N. Lewiston 230 8.06 $5,803,200 13.1 70.2 10.7 
CdA 15th St ‐ Rathdrum 115 12.67 $5,321,400 19.2 47.1 10.6 
Milan Tap 115 8.22 $3,452,400 30.1 29.5 10.4 
Shawnee ‐ South Pullman 115 12.7 $5,334,000 35.0 25.4 10.4 
Beacon ‐ Rathdrum 230 25.36 $18,259,200 16.2 53.9 10.2 
Airway Heights ‐ Silver Lake 115 10.77 $4,523,400 24.0 36.3 10.2 
Boulder ‐ Lancaster 230 13.29 $9,568,800 11.3 76.9 10.2 
Libby ‐ Noxon 230 0.79 $568,800 12.5 68.8 10.1 
Moscow 230 ‐ South Pullman 115 12.07 $5,069,400 23.0 36.3 9.7 
Colbert Tap 115 3.19 $1,339,800 34.3 24.1 9.7 
Clearwater ‐ Lolo #2 115 8.56 $3,595,200 24.0 33.5 9.4 
Otis Orchards ‐ Post Falls 115 7.62 $3,200,400 24.0 30.8 8.7 
Ninth & Central ‐ Third & Hatch 115 4.34 $1,822,800 24.0 29.5 8.3 
Lind ‐ Washtucna 115 28.78 $12,087,600 30.1 22.7 8.0 
Benewah ‐ Pine Creek 115 7.06 $2,965,200 27.0 24.1 7.6 
Burke ‐ Pine Creek #3 115 4.58 $1,923,600 23.0 28.1 7.5 
Shawnee ‐ Sunset  115 7.12 $2,990,400 37.0 15.9 6.8 
Devils Gap ‐ Long Lake #2 115 1.03 $432,600 13.1 41.7 6.4 
Albeni Falls ‐ Pine Street 115 2.27 $953,400 13.1 40.3 6.2 
Francis & Cedar ‐ Ross Park 115 5.16 $2,167,200 14.3 36.3 6.1 
Clearwater ‐ Lolo #1 115 8.63 $3,624,600 24.0 20.0 5.6 
Dry Creek ‐ Pound Lane 115 3.89 $1,633,800 12.5 36.3 5.3 
Airway Heights ‐ Sunset 115 9.52 $3,998,400 18.0 25.4 5.3 
Sunset ‐ Westside 115 11.97 $5,027,400 22.0 21.3 5.2 
Latah ‐ Moscow 115 10.37 $4,355,400 17.0 25.4 5.0 
Dry Creek ‐ N. Lewiston 115 8.17 $3,431,400 13.1 30.8 4.7 
Devils Gap ‐ Little Falls #2 115 3.9 $1,638,000 24.0 15.9 4.5 
Othello Sw. Sta ‐ Warden #1 115 8.28 $3,477,600 36.1 10.5 4.4 
CdA 15th St ‐ Ramsey 115 3.17 $1,331,400 9.4 36.3 4.0 
Moscow City ‐ N. Lewiston 115 22.19 $9,319,800 16.2 21.3 4.0 
Devils Gap ‐ Little Falls #1 115 3.42 $1,436,400 19.2 14.6 3.3 
Critchfield ‐ Dry Creek 115 1.58 $663,600 13.1 20.0 3.1 
Benewah ‐ Latah 115 6.68 $2,805,600 5.9 40.3 3.0 
Lolo ‐ Pound Lane 115 2.94 $1,234,800 12.0 20.0 2.8 
Bell ‐ Westside 230 1.99 $1,432,800 2.8 72.9 2.4 
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 59 of 61

60 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Lancaster ‐ Rathdrum 230 2.93 $2,109,600 2.8 63.4 2.1 
Wilbur Tap 115 5.35 $2,247,000 14.3 11.8 2.0 
Benton ‐ Othello Switch Station 115 3.79 $1,591,800 8.0 20.0 1.9 
Dower ‐ Post Falls 115 2.16 $907,200 9.4 17.3 1.9 
Boulder ‐ Otis Orchards #1 115 3.45 $1,449,000 2.8 39.0 1.3 
Boulder ‐ Otis Orchards #2 115 2.73 $1,146,600 2.8 34.9 1.1 
Grangeville ‐ Nez Perce #1 115 6.34 $2,662,800 8.0 11.8 1.1 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 60 of 61

61 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Appendix B – Transmission System Outage Data 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 2, Page 61 of 61

Substation System Review Asset
Management

2016
David Thompson
Rodney Pickett
Rubal Gill
Februar 12, 2016
Substation System Review
Asset Management
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 1 of 31

i
Substation System Review, 2016

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 2 of 31
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 3 of 31

iii
Substation System Review, 2016

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 4 of 31

iv
Substation System Review, 2016
Table of Contents
Table of Contents ......................................................................................................................... iv 
Figures .......................................................................................................................................... v 
Tables ........................................................................................................................................... v 
Purpose ......................................................................................................................................... 1 
Equipment Portfolio ....................................................................................................................... 2 
Capital Replacement and Maintenance ........................................................................................ 4 
Substation Asset Management Capital Maintenance ................................................................ 4 
Substation Capital Spares ......................................................................................................... 4 
Distribution Substation Rebuilds ............................................................................................... 5 
Garden Springs Substation Integration ..................................................................................... 5 
New Distribution Substations .................................................................................................... 5 
Noxon Switchyard Rebuild ........................................................................................................ 5 
South Region Voltage Control ................................................................................................... 6 
Westside Substation Rebuild-Phase One ................................................................................. 6 
Capital Spending ........................................................................................................................... 6 
Maintenance and Operations (M&O) Spending ............................................................................ 8 
Key Performance Indicators .......................................................................................................... 9 
Outages ...................................................................................................................................... 17 
Programs .................................................................................................................................... 17 
Substation PCB Removal ........................................................................................................ 17 
Power Transformer Replacement ........................................................................................... 18 
Voltage Regulator Replacement ............................................................................................. 18 
Substation Air Switch Replacement ........................................................................................ 19 
Completed Substation Design and Construction Projects .......................................................... 19 
Projects in Design or Construction .............................................................................................. 20 
System Planning Projects ........................................................................................................... 24 
Reference and Data Sources ...................................................................................................... 25 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 5 of 31

v
Substation System Review, 2016
Figures
Figure 1: Substation Age Distribution .......................................................................................... 2 
Figure 2: Substations by classification ......................................................................................... 3 
Figure 3: Substation M&O Expenditures ...................................................................................... 8 
Figure 4: Substation M&O Expenditures by Month ...................................................................... 8 
Figure 5: Substation M&O Comparison ....................................................................................... 9 
Figure 6: KPI-Reactive Work Orders ......................................................................................... 10 
Figure 7: KPI-Work Order Average Age .................................................................................... 11 
Figure 8: Hours of Unplanned Outages ..................................................................................... 11 
Figure 9: Customers Affected by Unplanned Outages .............................................................. 12 
Figure 10: Customer Outage Hours ........................................................................................... 12 
Figure 11: Customer Outage Events ......................................................................................... 13 
Figure 12: Equipment Removals due to PCB content ............................................................... 13 
Figure 13: Power Transformer Replacements ........................................................................... 14 
Figure 14: Voltage Regulator Replacements ............................................................................. 14 
Figure 15: Air Switch Replacements .......................................................................................... 15 
Figure 16: Wood Substation Replacements .............................................................................. 15 
Figure 17: Substation Risk Action Curve ................................................................................... 16 
Figure 18: Substation OMT Limit ............................................................................................... 16 
Figure 19: Voltage Regulator Age Distribution ........................................................................... 18 

Tables
Table 1: Substation asset quantities ............................................................................................ 3 
Table 2: Capital Project Metrics ................................................................................................... 4 
Table 3: Substation Capital Expenditures – 2015 ........................................................................ 7 
Table 4: Substation Rebuilds completed in 2014 and 2015 ....................................................... 19 
Table 5: Completed Projects ...................................................................................................... 20 
Table 6: Work in Progress ......................................................................................................... 20 
Table 7: Active and Pending Construction ................................................................................. 21 
Table 8: Delayed Projects .......................................................................................................... 21 
Table 9: Future Projects ............................................................................................................. 24 

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 6 of 31

1
Substation System Review, 2016
Purpose
This report provides summary information relating to the annual review of Avista’s electric
substations operating in its Washington and Idaho service territory. The intent is to present a
comprehensive overview of the substation capital assets, performance, risks, ongoing asset
management programs, current and planned projects, and summary recommendations. Asset
Management Plans are intended to serve a general audience from the perspective of long-term,
balanced optimization of lifecycle costs, system performance, and risk management. A consistent
sequence of asset management plans will provide the continuity required for continuous
improvement of capital asset management, as well as historical information useful for rate case
submissions.
With Avista’s implementation of IBM’s Maximo as its Asset Information System in 2014, a distinct
reference point for asset data has been established. The Maximo implementation provides a
comprehensive informational and historical repository for all asset data, applications, locations,
inspection history, maintenance activity, and life cycle status. As such, the reportable data
included in this report centers around activities in 2014 and 2015 in order to leverage the reference
data within Maximo and to provide consistent and repeatable data from a single source for this
and future reports.
Avista Utilities currently operates 162 substations consisting of:
 21 transmission substations
 30 transmission substations with distribution
 109 distribution substations
 2 foreign-owned substations.
In addition, there are 14 locations associated with generation.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 7 of 31

2
Substation System Review, 2016
Equipment Portfolio
From a perspective of key equipment as reference, the average age of the 162 substations is just
over 31 years. Figure 1 shows the age distribution of the substation population.

Figure 1: Substation Age Distribution

Substations are typically classified by voltage and function. The number of sites in each of these
categories is included in Figure 2. In addition to the standard population of 230kV and 115kV
substations, Avista continues to operate six substations at lower system voltages. These include
the Kooskia substation at 34kV, the St. John substation at 24kV, and four substations at 13kV
including Coeur d’Alene Shaft Mine, Sunshine Mine, and two at the Washington State University
campus in Pullman.
0
2
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12
19
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b
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a
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Substation Age Distribution
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 8 of 31

3
Substation System Review, 2016

Figure 2: Substations by classification

Included in the totals above are 13 switching stations, 11 in the 115kV group and two at 230kV,
that do not incorporate voltage transformers or regulation. Standard interconnect and protection
services are provided at these locations, supporting their inclusion in the general substation
reporting.
Each substation is comprised of major assets that coordinate to serve the principal regulation,
switching, and protection activities of each site. Each asset class has unique maintenance,
lifecycle, and operational considerations. Within the greater population of substations, the
quantity of each asset is shown in Table 1.

Capital Asset Quantity
Air Switch 1,175
Disconnect Switch 1,171
Bushings 1,890
Circuit Switcher 120
High Voltage Circuit Breakers 318
Low Voltage Circuit Breakers 353
Reclosers 309
Switchgear 95
Autotransformers 17
Power Transformers 211
Voltage Regulators 1,341
Table 1: Substation asset quantities

139
17
1 1 4
Number of Substations by Voltage
115kV
230kV
34kV
24kV
13kV
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 9 of 31

4
Substation System Review, 2016
Within the current implementation of the Maximo asset database, fields that provide the
manufactured date, in-service date, and last-installed date continue to be updated and populated
with the data available from the database integration. As such, succinct reports providing age
profiles for these substation asset families are not included at this time.
Capital Replacement and Maintenance
Projects with current approved Business Case proposals are included in this Capital Replacement
and Maintenance section, including a brief description of the project’s scope and purpose. In
summary, specific project evaluation metrics are included in Table 2.
Internal Rate
of Return
Benefit/Cost
Ratio
Risk Reduction
Factor
Asset Management
Capital 5% to 9%N/A 0.027302
Capital Spares 5% to 9%N/A 0.015362
Distribution Station
Rebuilds 9% to 12%N/A 0.010633
Garden Springs 5% to 9%N/A 0.004268
New Distribution
Stations 5% to 9%N/A 0.009185
Noxon Switchyard 5% to 9%N/A 0.004268
South Region
Voltage Control 7%N/A 0.000798
Westside Rebuild 7%N/A 0.017570
Table 2: Capital Project Metrics

Substation Asset Management Capital Maintenance
The Substation Asset Management Capital Maintenance program installs, replaces, or upgrades
substation apparatus based on Asset Management planning or emergency replacement
determinations. All obsolete, end-of-life, or failed apparatus, based on the Asset Management
analysis, are included under this program. Apparatus includes panel houses, high voltage
breakers, relays, metering, surge arresters, insulating rock, fence work, low voltage breakers and
reclosers, circuit switchers, SCADA systems, batteries and chargers, power transformers, high
voltage fuses, air switches, capacitor banks, autotransformer diagnostic equipment, step voltage
regulators, and instrument transformers.
Substation Capital Spares
The Substation Capital Spares program maintains Avista’s inventory of power transformers and
high voltage circuit breakers in order to manage the long lead time of the procurement cycle for
these system-critical items. These components are capitalized at receipt and placed in service in
response to both planned and emergency installations. The program expenditures may vary
significantly year to year due to the specific equipment purchased and deployed in any given year.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 10 of 31

5
Substation System Review, 2016
Distribution Substation Rebuilds
The Distribution Substation Rebuild program supports either the complete replacement or rebuild
of existing substation infrastructure as the site nears the end of its useful life, a need to support
increased capacity requirements, or to implement modifications necessary to accommodate
equipment upgrades. Included in the program are Wood Substation rebuilds as well as upgrades
to substations to comply with current design and construction standards. Some substation
rebuilds are necessitated by external requirements, including obligation to serve, customer or load
growth, or technology improvement projects such as Smart Grid. Substation rebuilds currently
planned to be completed under this program in the next five years include Big Creek, Kamiah,
and South Lewiston (Wood Substations), 9th & Central, Ford, Sprague, Davenport, and Northwest
(Lifecycle), Deer Park, Gifford, Lee & Reynolds, Huetter, Dalton, and Southeast (Equipment
Additions), and Hallett & White (Growth).
Garden Springs Substation Integration
The Garden Spring Substation Integration project will construct a new 230kV/115kV substation at
the existing Garden Springs property that will terminate the existing Airway Heights-Sunset,
Sunset-Westside, and South Fairchild Tap 115kV transmission lines. Options being considered
to energize the 230kV bus include the possibility of a new interconnection with the BPA Bell-
Coulee #5 230kV transmission line and a new 230kV feed from the Westside Substation following
the completion of the Westside Substation Rebuild Project. Both of the newly designated Garden
Springs-Sunset 115kV transmission lines will require upgrades to 150MVA capacity conductors.
New Distribution Substations
The New Distribution Substation program provides for new distribution substations in the system
in order to serve new and growing load, increased system reliability, and operational flexibility.
New substations under this program will require planning and operational studies, justification,
and approved Project Diagrams prior to funding. Current plans for new substation projects include
Tamarack in northeast Moscow, Greenacres in the Spokane Valley, and Hillyard and Downtown
West in Spokane. Design and construction phases will be coordinated to achieve one new
substation per year depending on need and justification.
Noxon Switchyard Rebuild
The existing Noxon Rapids 230kV Switchyard requires reconstruction due to the age and
condition of the equipment within the station. The existing bus, constructed as a strain bus with
a number of recent failures, is configured as a single bus with a tie breaker separating the East
and West bus segments. This station is the interconnection point of the Noxon Rapids
Hydroelectric generation as well as a principal interconnect point between Avista and BPA. As
such, this is a crucial asset for the reliable operation of the Western Montana Hydro Complex.
Equipment outages within the station, either planned or unplanned, can cause significant
curtailments of the local generation output. Due to the key role of the station, a complete rebuild
will require coordination with Avista’s Energy Resources Department and affected utilities,
including BPA. The Noxon Switchyard Rebuild Project is a greenfield design incorporating a
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 11 of 31

6
Substation System Review, 2016
double bus-double breaker 230kV switching station as a complete replacement of the existing
Noxon Switchyard.
South Region Voltage Control
Avista's 230kV transmission system in the southern area of its service territory, generally located
around the cities of Lewiston and Clarkston, experiences excessive high voltage during periods
of low power loading. Voltage levels exceed equipment ratings over approximately 35% of the
time. Continued operation of equipment outside its specifications and ratings exposes Avista to
potentially significant legal and regulatory risks. This is in addition to increasing the probability of
large-scale outages due to equipment failure. The installation of 230kV Reactors at North
Lewiston substation will eliminate existing overvoltage conditions in Avista’s southern region,
which includes the 230kV buses at Dry Creek, Lolo, North Lewiston, Moscow, and Shawnee
substations.
Westside Substation Rebuild-Phase One
Phase One of the Westside Substation Rebuild will extend the existing Westside Substation and
the 115kV and 230kV buses and will support design and installation options in consideration of a
new 250MVA autotransformer and other substation equipment. This installation will eliminate
overload potentials for certain bus outages and tie breaker failure contingencies in the Spokane
area. Following the completion of Phase One, the second phase will replace a second
autotransformer with a new 250MVA unit. The final phase would extend the 230kV yard to a
double breaker-double bus configuration. In addition, alternatives for the 115kV configuration
would be considered to achieve either a breaker-and-and-half or a full double breaker-double bus
implementation.

Capital Spending
For 2015, the major capital expenditures associated with substation construction or equipment
activities are included in Table 3. As most capital projects extend over multiple calendar years,
the summary expenditures listed may represent only a portion of the overall project’s expenses.
In total, these projects represent $24.4 million in capital spending during 2015.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 12 of 31

7
Substation System Review, 2016
ER Project
Capital
Expenditure Status
2532 Noxon 230kV Substation Rebuild $10,162,871 Partial in 2016
2000 Substation - Capital Spares $3,267,594 Ongoing
2589 Mobile Substation - Purchase New Mobile Substations $2,539,571 2015
2443 Greenacres 115kV/13kV Substation New Construction $1,661,927 2016
2215 Substation Asset Management Capital Maintenance $915,677 Ongoing
2001 System - High Voltage Circuit Breaker Replacements $580,324 Ongoing
2278 Replace Obsolete Reclosers $530,128 Ongoing
2484 Moscow 230kV Substation Rebuild Switchyard $527,614 Complete
2275 Rock and Fence Restoration $450,226 Ongoing
2449 System - Substation Air Switches Replacements $447,733 Ongoing
1006 System - Distribution Power Transformers $394,856 Ongoing
1107 Lewiston Mill Road - 115kV substation construction $369,980 2015
2493 Replace/Upgrade Voltage Regulators $343,358 Ongoing
2446 Irvin Substation- New Construction $296,734 Ongoing
2590 Deer Park 115kV Substation - Minor Rebuild $247,956 2016
1108 Hallett & White Substation Expansion $142,621 Ongoing
2294 System - Batteries $140,538 Ongoing
2546 Blue Creek 115kV Rebuild $104,669 Complete
2592 Sprague 115kV Substation Minor Rebuild $96,304 2016
2204 Wood Substation Rebuilds $89,274 Ongoing
2571 Clearwater 115kV Substation Upgrades $85,695 Complete
2573 Little Falls 115kV Substation Rebuild $66,485 Ongoing
2341 Ninth & Central Substation - Increase Capacity and Rebuild $54,960 In progress
2569 Gifford 115kV - Rebuild Substation $28,251 Ongoing
2538 College & Walnut Substation Yard Expansion $27,473 2016
2425 System - High Voltage Fuse Upgrades $25,135 Ongoing
2112 Beacon 230kV Substation Bus Conversion $14,286 Ongoing
2505 System-Replace Current and Potential Devices $13,262 Ongoing
2531 Westside 230kV Substation Rebuild $12,598 In progress
2274 New Substations $11,088 Ongoing
2561 Lewiston Mill Road 115kV Substation $8,912 2016
2343 System - Replace/Install Substation Structures $8,702 Ongoing
2336 System - Replace Distribution Power Transformers $7,939 Ongoing
2572 Noxon Construction Substation - Minor Rebuild $2,471 Complete
2591 Davenport 115kV Substation - Minor Rebuild $2,275 Ongoing
Table 3: Substation Capital Expenditures – 2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 13 of 31

8
Substation System Review, 2016
Maintenance and Operations (M&O) Spending
During 2015, a total of nearly $4.7 million supported Maintenance and Operations activities
relating to existing substations. As shown in Figure 3, approximately 85.1% of the maintenance
and operation expenses were associated with planned services, while the remaining 14.9% was
in response to unplanned or reactive activities. Figure 4 shows the total substation maintenance
and operations spending by calendar month throughout 2015.

Figure 3: Substation M&O Expenditures

Figure 4: Substation M&O Expenditures by Month

$3,987,826
$696,282
Substation M&O Expenditures-2015
Planned
Unplanned
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 14 of 31

9
Substation System Review, 2016
Substation maintenance activities are tracked by both distribution and transmission tasks. As
noted earlier, many of the substation locations provide both distribution and transmission services.
For 2015, the allocation between transmission and distribution expenses, both maintenance and
operations, along with unplanned expenditures, are shown in Figure 5.

Figure 5: Substation M&O Comparison
Key Performance Indicators
Key Performance Indicators (KPIs) have been identified for tracking and review of key activities.
These KPIs continue to be refined relative to the metrics monitored. The metrics are published
on a monthly basis, providing a perspective about the implementation and use of Maximo, system
reliability, and progress towards particular key project goals as linked to substation performance.
A combination of lagging and leading indicators are tracked in order to provide both retrospective
and prospective views. It is generally expected that the proper focus on the correct leading
indicators will guide satisfactory results after a defined lag period. When this does not occur,
deeper investigation and root-cause analysis may help to identify other factors affecting the
expected causal relationship.
One of the primary goals of Asset Management is to optimally manage risk and performance
relative to capital investment and maintenance expenditures. The nexus of planned maintenance
and capital replacement activity compared to emergency repair costs, outages, lost profits and
other possible outcomes over time should be clearly identified. Additional reviews of predicted
activity versus actual outcomes for a variety of scenarios should also serve to help determine the
continuation of or adjustment to ongoing programs and projects. The availability of sufficient
reliable data to support these analytic opportunities continues to be a challenge, but is expected
to be mollified as the Maximo implementation and structured use becomes integrated into the
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 15 of 31

10
Substation System Review, 2016
formal work processes. For example, safety incidents, emergency repair and replacement work,
and other similar activities continue to be transacted in Operations under blanket accounts,
precluding the ability to extract detailed transactional data associated with specific project and
related work activities at a substation. The Asset Management group continues to suggest
opportunities and support improvements to achieve the goal of a complete corporate
implementation of Maximo.
The KPIs in Figure 6 and Figure 7 show projected and actual metrics relating to Work Orders
within Maximo. Reactive Work Orders are associated with required Corrective Maintenance tasks
that were in response to operational malfunction issues or items requiring attention following a
planned inspection. Throughout 2015, the projected target has been achieved. The Average Age
metric tracks the rolling number of days existing Work Orders have been active. This metric
continues to not meet the expected performance level, though this topic continues to be
addressed with the Operations teams.

Figure 6: KPI-Reactive Work Orders

0%
10%
20%
30%
40%
50%
60%
70%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Reactive Work Orders (Completed and Active)
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 16 of 31

11
Substation System Review, 2016

Figure 7: KPI-Work Order Average Age

Metrics associated with customer outages due to substation activity are shown in Figure 8
through Figure 11. In 2015, the projected outage metrics, whether time or quantity, have
typically been satisfied, demonstrating the expected reliability of service for the end customer.

Figure 8: Hours of Unplanned Outages

 ‐
 50
 100
 150
 200
 250
 300
 350
 400
 450
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Age (days) (Completed and Active)
Projected Actual
 ‐
 10,000
 20,000
 30,000
 40,000
 50,000
 60,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Substation Customer Hours due to Extended
Unplanned Outages
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 17 of 31

12
Substation System Review, 2016

Figure 9: Customers Affected by Unplanned Outages

Figure 10: Customer Outage Hours

 ‐
 5,000
 10,000
 15,000
 20,000
 25,000
 30,000
 35,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Number of Customers with Uplanned
Outages (>3 hours)
Projected Actual
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Customer Outage Hours-Substation AM
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 18 of 31

13
Substation System Review, 2016

Figure 11: Customer Outage Events

The metrics shown in Figure 12 through Figure 15 relate to specific substation equipment-
related programs. Figure 12 identifies the equipment replacement activities associated with the
PCB Removal program, including qualifying equipment removed from substations. Equipment
identified as a PCB-containing device continues to be prioritized for removal or replacement in
conjunction with other related activities. The remaining three graphs represent power
transformer, voltage regulator, and air switch assets.

Figure 12: Equipment Removals due to PCB content

0
100
200
300
400
500
600
700
800
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Customer Outage Events-Substation AM
Projected Actual
0
20
40
60
80
100
120
140
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Equipment Removals due to PCBs
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 19 of 31

14
Substation System Review, 2016

Figure 13: Power Transformer Replacements

Figure 14: Voltage Regulator Replacements

0
1
2
3
4
5
6
7
8
9
10
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Power Transformer Replacements
Projected Actual
0
20
40
60
80
100
120
140
160
180
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Voltage Regulator Replacements
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 20 of 31

15
Substation System Review, 2016

Figure 15: Air Switch Replacements

The Wood Substation Replacement program did not achieve a completed substation replacement
during 2015 as noted in the graph shown in Figure 16.

Figure 16: Wood Substation Replacements

These final two KPIs evaluate system awareness criteria regarding level of service. The Risk
Action Curve metric in Figure 17 tracks outage event parameters, including frequency and
severity, to signal additional action if the accumulated outage activity requires further review and
analysis. The OMT High Limit in Figure 18 tracks to an acceptable limits of service statistical
metric for outage events.
0
5
10
15
20
25
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Air Switch Replacements
Projected Actual
0
1
2
3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Wood Substation Replacements
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 21 of 31

16
Substation System Review, 2016

Figure 17: Substation Risk Action Curve

Figure 18: Substation OMT Limit

0
1
2
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Substation Exceeds Risk Action Curve
Projected Actual
0
1
2
3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Substation Exceeds OMT High Limit
Projected Actual
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 22 of 31

17
Substation System Review, 2016
Outages
During 2015, 40 outage events occurred attributable to either planned or unplanned substation
activity. For these outage events, the average duration was 2 hours 51 minutes and affected
approximately 990 customers. Durations ranged from 5 minutes to 8 hours 48 minutes and
impacted customers ranged from 1 to just over 4000. The data is derived from the annual
reliability reports provided by Operations Management.

Programs
Substation PCB Removal
In 2010, an assessment was completed of equipment containing Polychlorinated Biphenyls
(PCBs) within the Avista substation. PCBs are typically a minor constituent of oil within substation
equipment including
 Power transformers
 Oil circuit breakers
 Voltage regulators
 Potential transformers
 Current transformers
 Station service transformers
 Capacitors
 Electromechanical relays.
Under the current process, the substation power transformers have been tested for PCBs and
units with PCB concentrations of greater than 50 ppm are slated for removal. Voltage regulators,
12
12
11
2
2 1
Outage Reason
Equipment
Planned
Company
Animal
Public
Weather
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 23 of 31

18
Substation System Review, 2016
as brought in for repair, are tested and replaced if PCB concentrations of 50 ppm or greater are
identified. Other substation equipment that is found to contain oil with the 50 ppm concentration
of PCBs is evaluated on a case by case basis. The equipment may be decommissioned or
reconditioned with clean oil and returned to service.
Additional regulation at both Federal and State levels continue to be monitored for refinement of
this program.
Power Transformer Replacement
Avista’s aging population of power transformers continues to be evaluated and included as key
factors in substation upgrade projects or rebuilds. Transformer upgrades can provide significant
energy savings based on the operational efficiency of the units, as well as additional
configuration flexibility.
During 2014 and 2015, power transformer replacement projects have been completed at:
 Moscow 230 Spare (2013)
 Blue Creek #1 (2014)
 North Lewiston #1 (2014)

Voltage Regulator Replacement
Voltage regulators have been identified as significant contributors to substation reliability, and
ongoing evaluation and modeling is in progress. The age profile is shown below Figure 19. In
the conjunction with substation upgrades, older vintage voltage regulators are being replaced.
The success of this ongoing program is shown by the shift in the age profile. Presently, the
average age of installed base of voltage regulators is 15.5 years, though approximately 20% of
the units have been installed for more than 30 years.

Figure 19: Voltage Regulator Age Distribution
0
20
40
60
80
100
120
140
19
6
7
19
6
8
19
6
9
19
7
0
19
7
1
19
7
2
19
7
3
19
7
4
19
7
5
19
7
6
19
7
7
19
7
8
19
7
9
19
8
0
19
8
1
19
8
2
19
8
3
19
8
4
19
8
5
19
8
6
19
8
7
19
8
8
19
8
9
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
Voltage Regulator Age Distribution
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 24 of 31

19
Substation System Review, 2016

Substation Air Switch Replacement
The Substation Air Switch Replacement program deals with both planned and unplanned
replacements.
In the case where air switches do not operate properly, flashover and possible tripping of bus
protection devices may occur. This can be the result of a component failure at the whips or
vacrupter switch or other adjustment issues with the air switch itself. While most air switch missed
operations could be prevented with regular inspection and maintenance, the limited scope of
current maintenance procedures doesn’t extend to the level of blade adjustments or the
replacement of live parts, such as contacts and whips, or the repair of ground mats.
Many air switches are operated remotely. In these instances, Avista personnel may not be
present to observe the opening of the switch, limiting the identification of potential issues. Minor
functional issues could indicate the increasing probability of a major or catastrophic failure. Small
quantities of emergency repair materials are maintained for the legacy population, but many of
the air switches are out of production and replacement parts are difficult to procure.
Completed Substation Design and Construction Projects
The Substation Engineering group performs the scope, design, and project management
functions for all facets of substation construction, including designated equipment replacement,
rebuilds, and new site construction. The following tables describe the current status of projects
within the engineering group’s queue.
Substation Rebuilds completed in 2014 and 2015
Blue Creek – 115kV/13kV new construction
Clearwater 115kV/34kV substation upgrade
Lewiston Mill Road new construction
Moscow 230kV/115kV/24kV new construction
North Lewiston 115kV/13kV removal of equipment
Noxon Construction 230kV/13kV substation rebuild
Noxon Rapids 230kV west bus rebuild
Odessa 115kV/13kV substation upgrade
Irvin 115kV/13kV substation
Bruce Road 115kV/13kV substation
Table 4: Substation Rebuilds completed in 2014 and 2015

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 25 of 31

20
Substation System Review, 2016
Completed Projects BI
Reference
Sunset - Replace MOAS A-184 (Four Lakes Tap) AMS85
Grangeville - Replace A-337 Relay and Battery Cabinet AMS09
Ross Park - 115kV Relay Upgrade SS802
Third & Hatch - 115kV Relay Upgrade SS802
Beacon - Upgrade A-605 Line Relays SS802
Ninth & Central – Minor Upgrades SS802
Noxon - Add Line Position for Noxon Reactor Station AS202
Opportunity--Install 115kV Breakers SS204
Table 5: Completed Projects

Projects in Design or Construction
The Substation Engineering group performs the scope, design, and project management
functions for all facets of substation construction, including designated equipment replacement,
rebuilds, and new site construction. The following three tables describe the current status of
projects within the engineering group’s queue.

Construction and Field Work in Progress BI
Reference
Bronx - HVP Upgrade 42P09
Oden - HVP Upgrade 42P09
Bunker Hill - HVP Upgrade 42P09
Nine Mile Substation - Install GSU 1 GG811
Noxon 230kV Reactor Station--New Construction AS202
Greenacres--New 115kV/13kV Substation SS644
Pine Creek - Replace Auto Transformer #1 AMS28
Table 6: Work in Progress

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 26 of 31

21
Substation System Review, 2016
Engineering active and pending construction BI
Reference
Benton-Othello Transfer A-131 MOAS AMS85
Beacon - Grid Modernization - Feeder 12F1 SS406
Beacon - Replace 13kV Breaker - 12F6 AMS83
Harrington - Rebuild to 115kV/13kV Substation BS303
Mobile Battery - Add SCADA XS951
Noxon - Hot Springs #1 and #2 Line Relay Upgrades AMS07
Beacon--Replace Fence AMS82
Beacon--115kV Line Relay Upgrade A-610, A-613 SS802
Noxon - Refurbish Existing East Bus AS202
College & Walnut – Yard Expansion AMS82
Sprague - Minor Rebuild FS402
Deer Park--Metering/SCADA/Panel house SS405
Othello - Replace Feeder 501 and 502 Breakers AMS83
Othello - Replace Air Switch A-41 AMS83
Lolo - Communications DC Plant Refresh
St. John - Replace 24kV Switches AMS85
Shawnee - Communications DC Plant Refresh
St. Maries - Upgrade AC/DC Station Service AMS10
Table 7: Active and Pending Construction

Waiting prioritization or delayed BI
Reference
Replace SMP - Dry Creek XS951
Replace SMPs - Post Street XS951
Ramsey--Line Relay Upgrade A-669 CS802
Cabinet - Remove Relays and Change CT Ratios AG103
Table 8: Delayed Projects

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 27 of 31

22
Substation System Review, 2016
Future Projects BI
Reference
North Lewiston 230kV--Install Reactors LS306
Kamiah - Rebuild LS208
Gifford - Add 115/13kV Station to Substations WS201
Westside - Increase Capacity; New Autotransformer SS201
Priest River – Temporary Breaker Install AMS83
Ford - Replace Transformer AMS28
Ford - Install New 12F2 Feeder Position BS202
Waikiki - Grid Modernization - Feeder 12F2 SS542
Priest River - Minor Rebuild - Distribution AMS83
Irvin--New 115kV Switching Station SS904
Hallett & White - Add Capacity SS523
Rathdrum - Grid Modernization - Feeder 231 CS502
Rathdrum - Grid Modernization - Feeder 233 CS502
Juliaetta - Replace MOAS units A-120 and A-173 AMS85
Jaype - Remove and Salvage
Colville - Replace Battery AMS10
Chester - Replace Battery AMS10
Rockford - Replace Battery AMS10
Fort Wright - Replace Battery AMS10
Beacon--Install Serveron DGA on both autotransformers XS903
Ritzville - Replace A-94 MOAS Control Box AMS85
Northwest - Add Fiber Redundancy/Upgrade XS951
Millwood - Add Radios in Yard - 2 Poles
Othello Switching Station - HVP Upgrade 42P09
Clearwater - Upgrade Metering XS801
Clearwater - Replace Battery AMS09
Oden - Replace 115kV Switches AMS85
Bronx - Replace small conductor AMS32
Garfield - Replace HV Fuses AMS80
Clearwater--Microwave Refresh
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 28 of 31

23
Substation System Review, 2016
Future Projects BI
Reference
Beacon - Add Thermal Relays - A-603/A-607 XS002
St. Maries--Install SCADA XS951
Ninth & Central - Rebuild Distribution Sub SS514
S. Lewiston 115--Rebuild station, replace transformers LS207
Ninth & Central - Move lateral line into substation SS514
Moscow City—Upgrade SCADA/Integrate System XS951
Indian Trail - Add Fiber; Upgrade Communications XS951
Northwest - Rebuild SS206
College & Walnut - Replace Breakers A-431 and A-432 AMS32
Davenport - Minor Rebuild BS400
Colville - HVP Upgrade 42P09
Kooskia 115kV--Replace Transformer AMS28
Milan - Replace A-599 MOAS AMS85
N. Moscow - Install A-369 MOAS AMS85
Warden - Replace Breakers AMS32
Warden - Install SSVT for Station Service XS905
Otis Orchards – Install SSVT for Station Service XS905
Beacon--Upgrade SCADA/Integration System XS951
Clearwater--Upgrade Relaying AMS07
St. Maries - Install 115kV Arresters AMS81
O'Gara - Install 115kV Arresters AMS81
Lee & Reynolds--Add Transformer #2 AMS28
Upriver--Replace/Upgrade Metering XS801
Dry Gulch--Replace/Upgrade Metering XS801
Cabinet - Install substation fuses/Lighting circuits AMS80
Clearwater - Replace/Upgrade SCADA XS951
Little Falls – Rebuild BS304
Tenth & Stewart--Station Upgrades/Rebuild LS202
Valley - Rebuild Substation WS402
Sunset - Rebuild Substation SS890
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 29 of 31

24
Substation System Review, 2016
Future Projects BI
Reference
Metro - Rebuild Substation SS208
Big Creek - Rebuild Substation KS201
Coeur Shaft - Minor Rebuild TBD
Pound Lane - Rebuild Substation TBD
Chester - Rebuild Substation SS207
Othello - Rebuild Substation TBD
Silver Lake - Rebuild Substation TBD
Dalton - Rebuild Substation TBD
Huetter - Rebuild 115kV Yard CS503
Bronx - Rebuild Substation AS203
Noxon Rapids - New Substation AS202
Saddle Mt. - New Substation TBD
Tamarack - New Substation PS203
McFarlane - New Substation SS516
Bovill - New Substation TBD
Ross Park--Install Security Wall 06P98
Post Street Transformer Cooling Discharge TBD
ORO - Grid Modernization - Feeder 1280 TBD
Table 9: Future Projects

System Planning Projects
There is considerable opportunity for more collaboration between Asset Management and System
Planning on capital asset risk assessments, analyses and development of long-term asset
management plans, where overlaps and synergistic opportunities present themselves. Risk is
equivalent to the product of the probability and the consequence of a given event.
Currently, there are no substation System Planning projects that are covered by Asset
Management.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 30 of 31

25
Substation System Review, 2016
Reference and Data Sources
Various information and data sources were used to compile the information for this report. As
referenced in the Purpose introduction, the emphasis was placed on Avista’s Maximo
implementation for all inventory and date-specific asset details. This process will provide a
tracking database for repeatable historical references, trending, and accurate data snapshots as
the system continues to be deployed and data capture processes refined.
Other sources include Availability Workbench simulations, the legacy Major Equipment Tracking
System (METS), Outage Management Tool (OMT) data, substation engineering files, substation
engineering SharePoint site, and the substation Projects and Capital Budget spreadsheets.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 3, Page 31 of 31

2016
Amber Fowler, Rodney Pickett ,
Dave James, Ross Taylor, and
Mareval Ortiz-Camacho
Avista Corp

Electric Distribution System
2016 Asset Management Plan
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 1 of 88

Prepared by: _________________________________________________________
Amber Fowler, Asset Management Engineer

Reviewed by: _________________________________________________________
Rodney Pickett, Asset Management Engineering Manager
_________________________________________________________
Dave James, Distribution Engineering Manager
_________________________________________________________
Glenn Madden, Asset Maintenance Manager

Approved by: _________________________________________________________
Scott Waples, Director of Planning and Asset Management

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 2 of 88
Table of Contents
Purpose ......................................................................................................................................................... 7
Executive Summary ....................................................................................................................................... 7
Data Sources ............................................................................................................................................... 10
Standard Calculations ................................................................................................................................. 11
Review of OMT Data and Trends ................................................................................................................ 11
OMT Events per Year .............................................................................................................................. 11
SAIFI Trends by OMT Sub-Reasons ......................................................................................................... 17
OMT Sub-Reason Events High Limit ........................................................................................................ 19
System ......................................................................................................................................................... 25
Major Changes ........................................................................................................................................ 25
Specific Distribution Programs and Assets ................................................................................................. 25
Distribution Wood Pole Management (WPM)........................................................................................ 25
Selected KPIs and Metrics ................................................................................................................... 26
WPM Metric Performance .................................................................................................................. 30
WPM Model Performance .................................................................................................................. 32
WPM Summary ................................................................................................................................... 32
Wildlife Guards ....................................................................................................................................... 37
Selected KPIs and Metrics ................................................................................................................... 37
WILDLIFE GUARDS KPI Performance ................................................................................................... 38
WILDLIFE GUARDS Metric Performance ............................................................................................. 39
WILDLIFE GUARDS Model Performance ............................................................................................. 39
WILDLIFE GUARDS Summary .............................................................................................................. 39
URD Primary Cable .................................................................................................................................. 42
Selected KPIs and Metrics ................................................................................................................... 42
URD PRIMARY CABLE KPI Performance .............................................................................................. 43
URD PRIMARY CABLE Metric Performance ......................................................................................... 44
URD PRIMARY CABLE Model Performance ......................................................................................... 44
URD PRIMARY CABLE Summary .......................................................................................................... 44
Distribution Transformers ....................................................................................................................... 45
Selected Metrics ................................................................................................................................. 45
Metric Performance ............................................................................................................................ 46
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 3 of 88
Summary ............................................................................................................................................. 46
Area and Street Lights ............................................................................................................................. 46
Selected Metrics ................................................................................................................................. 46
Summary ............................................................................................................................................. 46
Distribution Vegetation Management (VM) ........................................................................................... 47
Selected KPIs and Metrics ................................................................................................................... 47
VM KPI Performance ........................................................................................................................... 48
VM Metric Performance ..................................................................................................................... 50
VM Model Performance...................................................................................................................... 51
VM Summary....................................................................................................................................... 51
Distribution Grid Modernization Program .............................................................................................. 52
Selected Metrics ................................................................................................................................. 52
Metric Performance ............................................................................................................................ 56
Summary ............................................................................................................................................. 57
Worst Feeders ......................................................................................................................................... 57
Feeder Tie Circuits................................................................................................................................... 59
ARD12F2-ORN12F1 Tie Circuit ............................................................................................................ 59
DAV12F2-RDN12F1 Tie Circuit ............................................................................................................ 60
Summary ............................................................................................................................................. 60
Spokane Electric Network ....................................................................................................................... 61
Equipment Types and Aging ............................................................................................................... 61
KPI and Metrics ................................................................................................................................... 61
Capital Budgets and Spending - Overview .......................................................................................... 61
New Services – Expenses .................................................................................................................... 61
Replacement of old PILC primary cable– Expenses ............................................................................ 61
Replacement of old PILC and RINC secondary cable– Expenses ......................................................... 64
Purchase of new and replacement of aging transformers and network protectors– Expenses ........ 64
Repair/refurbishment/replacement of vaults/manholes/handholes– Expenses ............................... 65
Non-routine Projects Being Carried Out on Specific CARs– Expenses ................................................ 67
Network Communications Stage 1– Expenses .................................................................................... 67
Monroe and Lincoln St Repaving– Expenses ...................................................................................... 67
Distribution Line Protection .................................................................................................................... 68
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 4 of 88
Assets Not Specifically Covered Under a Program ................................................................................. 68
Conclusion ........................................................................................................................................... 68
Distribution Vegetation Management .................................................................................................... 70
Distribution Wood Pole Management .................................................................................................... 75
Grid Modernization ................................................................................................................................. 77
Transformer Change-Out Program ......................................................................................................... 79
Business Cases ........................................................................................................................................ 80

Figure 1, OMT Annual Number of Events and AM Related Event Trends and Trend Lines ........................ 16
Figure 2, OMT Events with and without Planned Maintenance or Upgrades ............................................ 17
Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits ............................................................ 20
Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time .................................................... 21
Figure 5, 2015 OMT SAIFI Contribution by Sub-Reason ............................................................................. 22
Figure 6, 2015 OMT Sustained Outage Comparisons ................................................................................. 23
Figure 7, Customers Affected Per Event Exceeding Risk Action Levels ...................................................... 24
Figure 8, WPM OMT Event Trends .............................................................................................................. 33
Figure 9, WPM Contribution to Annual SAIFI value by Sub-Reason and Year ............................................ 34
Figure 10, Wood Pole Used by Summarized Activity .................................................................................. 35
Figure 11, Distribution Wood Pole Age Profile ........................................................................................... 36
Figure 12, Wildlife Guards Installed by Year and Expenditure Request ..................................................... 40
Figure 13, Wildlife Guards Usage by MAC for 2011-2015 .......................................................................... 41
Figure 14, URD Primary Cable OMT Events by Year ................................................................................... 44
Figure 15, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons............ 49
Figure 16, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell
Sub-Reasons ................................................................................................................................................ 50
Figure 17, OMT Sustained Outages related to Grid Modernization ................................................... 55
Figure 18, Wood Pole Management and Grid Modernization Before and After ........................................ 56
Figure 19, ARD12F2 to ORN12F1 Tie .......................................................................................................... 59
Figure 20, DAV12F2 - RDN12F1 Tie ............................................................................................................. 60
Figure 21, A faulted PILC cable ................................................................................................................... 62
Figure 22, A second faulted PILC cable ....................................................................................................... 63
Figure 23, A network transformer after a failure in the primary compartment ........................................ 65
Figure 24, Interior of a badly deteriorated old manhole in a heavily traveled street ................................ 66
Figure 25, Duct bank damage entering an old deteriorated manhole ....................................................... 66
Figure 26, Complete replacement of a badly deteriorated manhole ......................................................... 67
Table 1, OMT Events by Sub-Reason and Year ........................................................................................... 11
Table 2, OMT Outages and Partial Outages by Sub-Reason and Year ........................................................ 13
Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2009-2015 data ........................ 14
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2009-2015 data ................... 15
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 5 of 88
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage ................................................................ 18
Table 6, OMT Sub-Reasons Exceeding Annual High Limit ........................................................................... 19
Table 7, WPM KPI Goals by Year ................................................................................................................. 26
Table 8, WPM Metric Goals by Year ........................................................................................................... 29
Table 9, Wildlife KPI Goals for 2010 - 2015 ................................................................................................. 38
Table 10, Wildlife Metric Goals for 2010 - 2015 ......................................................................................... 38
Table 11, Worst Feeders for Squirrel related Events for 2015 ................................................................... 39
Table 12, URD Cable - Pri KPI Goals ............................................................................................................ 43
Table 13, URD Cable - Pri Metric Goals ....................................................................................................... 43
Table 14, TCOP Metrics ............................................................................................................................... 45
Table 15, Vegetation Management Metric Goals ....................................................................................... 48
Table 16, VM KPI Performance ................................................................................................................... 48
Table 17, Tree-Weather OMT Events Metric for Vegetation Management ............................................... 51
Table 18, VM Cost per Mile and All Vegetation Management Work Metric .............................................. 51
Table 19, Grid Modernization Program Objectives .................................................................................... 52
Table 20, Energy Savings based on Integrated Resource Plan ................................................................... 53
Table 21, OMT Sub-Reasons impacted by Grid Modernization .................................................................. 54
Table 22, Metric Performance for Grid Modernization Program ............................................................... 57
Table 23 Worst Feeder SAIFI 3 Year Average .............................................................................................. 58
Table 24 Worst Feeder Projects and Costs ................................................................................................. 58
Table 25, Assets Not Specifically Covered Under a Program ...................................................................... 68

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 6 of 88
Purpose
This report documents the asset plans for Electrical Distribution System for Avista. The plans discussed
here represent what we believe to be the best approach to managing Avista’s Distribution assets and
provides the Key Performance Indicators (KPIs) and metrics Asset Management (AM) to support the
plans and demonstrate the effectiveness of those plans implemented. The report also helps identify
areas for improvement or opportunities to improve the value we receive from our assets.
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.
Executive Summary
The primary message of this asset management plan is that the programs in place have been positively
impacting the number of outages and decreasing the cost to mitigate these failures. Continuous
improvement upon these programs is necessary to maintain reliability and efficiency. Assets are aging
faster than our current programs and plans can alleviate. However, programs are continually being
analyzed and updated to continue to improve our overall management of the distribution assets.
If available, each of the below summaries include a ranking criteria table. This table includes the
Customer IRR from the business case, the Benefit to Cost Ratio from our IRR calculation analysis and the
Risk Reduction Ratio from the supporting business case.
Current Programs:
1. Grid Modernization – includes replacing poles, transformers (Pad Mount, Overhead & Submersible),
cross arms, arresters, 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 and
switched capacitor banks, balancing feeders, removing unauthorized attachments, replacing open
wire secondary, and reconfigurations. Although this is a new program it does appear to be reducing
outages for the feeders worked on. The program has slowly shifted from “Feeder Upgrade” to this
new larger scoped Grid Modernization program. With only a few years of data since completion of
the earliest feeders, this program needs time to mature, so the full value of the program can be
realized.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 7 of 88
2. Transformer Change-Out Program – has run smoothly for the past few years with the targets and
KPIs being met regularly. This program was largely implemented to reduce the environmental
concern of Polychlorinated biphenyls (PCBs) in some Pre-81 transformers. The environmental risks
have been heavily decreased, with a focus in areas that have a greater potential to impact our
waterways. Since these are also old and inefficient transformers, our efficiency has increased.
However, this program is about to switch over to the second phase. With this switchover the
program will “piggy back” on Wood Pole Management for a complete cycle to finish removing the
non-PCB Pre-81 transformers from our system. The effectiveness and efficiency of this second
phase is yet to be determined.

3. URD Cable Replacement – is the programmatic replacement of the pre 1982 unjacketed
Underground Residential District (URD) cable. Originally the removal of all of the pre 1982 cable
was to be completed in 5 years; however, funding didn’t match the original target and some cable
remains in use today. To date the program has paid great dividends towards reducing URD Cable-Pri
events when compared to where it would have been without taking action. Although many feet of
this type of cable remain in use, the outages have been greatly reduced and we are seeing few
outages due to this early generation of cable.

4. Vegetation Management – maintains the distribution system clear of trees and other vegetation.
This reduces outages caused by trees and to a lesser extent outages caused by squirrels. This
program has had a big impact on reducing our number of unplanned outages. Reducing these
outages improves our reliability, reduces our risk during storms and decreases safety hazards for our
employees working on the distribution system. Tree related outages continue to decline and the
cost per mile to do this program have continually decreased due to efficiency gains, improved
processes and new methods such as per unit costing; which in turn drives up the value of this
program.

5. Wood Pole Management – inspects and maintains the existing distribution wood poles on a 20 year
cycle. In addition to 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. Overall, WPM has been effective at maintaining the
current level of reliability to our customers, however, we will need to complete work on more
feeder miles to control the impact on future reliability.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 8 of 88
6. Area and Street Light – replaces non-decorative high pressure sodium and mercury vapor lights with
equivalent LED lights. The initial year of the program changed out 100W and 200W HPS and MV
non-decorative street lights in Washington only. The scope was changed and going forward all
wattage types of non-decorative lights for both area and street lights will be replaced in both
Washington and Idaho. The first year of the program finished on budget with more lights completed
than anticipated. The scope change and potential budget cuts may push this 5 year program out,
however, the impressive first year gives hope that with an intact budget the program may complete
closer to the 5 year cycle than not.

7. Worst Feeder – This program aims to improve the reliability of its most underperforming
distribution circuits. Projects vary by individual circumstance but in many cases additional circuit
reclosers are installed to reduce outage exposure and to automatically restore power to upstream
customers or circuits in outage prone areas are converted from overhead to underground or circuits
are effectively ‘hardened’ by shortening conductor span lengths or by increasing phase spacing. This
programs goal is to selectively improve the feeders with the worst SAIFI and so far this program
seems to be producing as planned. Not all feeders drop off the list after work is done but most have
a large reduction in outages after work is done.

8. Segment Reconductor and Feeder Tie – addresses specific congestion issues in the distribution
system. The purpose of the program is to reconductor portions of circuits or to install additional
‘tie’ points to enable load shifts and transfers. In most situations, this involves that poles be
replaced and that existing conductors remain in service during the majority of the work.
Transformers, customer service wires, and other equipment including crossarms, insulators, guy
wires, brackets, communication circuits, fuse holders, and other hardware must be installed new or
transferred to new poles. This program helps maintain operational flexibility and circuit reserve
capacity for our distribution system.

9. Network – Major network equipment falls into four categories: network transformers, network
protectors, cable (primary and secondary), and physical facilities – duct banks, vaults, manholes, and
handholes. There are no established performance metrics for this program. The network is
designed with redundancies to prevent outages and our current outage management tool does not
“see” network events, making it difficult to keep track of the typical metrics used in other programs.

10. Protection – Avista's Electric Distribution system is configured into a trunk and lateral
system. Lateral circuits are protected via fuse-links and operate under fault conditions to isolate the
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 9 of 88
lateral in order to minimize the number of affected customers in an outage. Engineering
recommends installation of cut-outs on un-fused lateral circuits and the replacement of obsolete
fuse equipment (e.g. Chance, Durabute/V-shaped, Open Fuse Link/Grasshopper, Q-Q, Load
Break/Elephant Ear, and Porcelain Box Cutouts). As part of the program, sizing of fuses will be
reviewed to assure protection of facilities, as well as coordination with upstream/downstream
protective devices. This program began as an obsolete replacement program but has grown to
incorporate un-fused and wrong fused laterals. Cutout outages have decreased through this
program but with the added scope a new metric will need to be made. This is a targeted program to
ensure adequate protection of lateral circuits and to replace known defective equipment.

*Original scope

To date the programs developed have made a huge impact in the number of outages on the distribution
system. The cyclic programs need to continue to be analyzed and updated to maintain the improved
reliability, reduced risk and decreased O&M costs. Since the assets continue to age faster than the
current programs can mitigate, new programs or scope changes will be required going forward to
continue to provide our customers with safe and reliable service.
Data Sources
Much of the information used in this report’s metrics comes from three sources: Annual Sustained and
Momentary outage data; Outage Management Tool (OMT) events; and Oracle (financial and supply
chain database). 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 sometimes
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 Interruption Frequency Index (SAIFI) impacts, and System Average Interruption
Duration Index (SAIDI) impacts.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 10 of 88
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 Master Activity Code (MAC) and Task for Operations and Maintenance (O&M)
work.
Standard Calculations
See reference the “2010 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 2009 2010 2011 2012 2013 2014 2015
Arrester 19 32 30 36 24 32 20
Bird 218 179 332 231 270 248 227
Capacitor 4 2 0 4 4 3 0
Car Hit Pad 139 105 98 105 117 104 88
Car Hit Pole 217 298 339 355 369 378 307
Conductor - Pri 42 64 81 110 142 135 83
Conductor - Sec 286 273 310 286 331 323 299
Connector - Pri 111 101 100 79 85 85 51
Connector - Sec 429 410 408 390 336 321 283
Crossarm-rotten 23 25 28 19 18 26 23
Customer Equipment 1626 1458 1384 1434 1368 1328 1200
Cutout/Fuse 197 217 176 209 171 196 109
Dig In 164 149 123 109 103 104 96
Elbow 7 5 8 2 10 6 5
Fire 157 203 234 230 282 200 206
Forced 51 63 67 33 63 68 29
Foreign Utility 724 894 720 734 720 602 765
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 11 of 88
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
Insulator 32 49 36 32 47 34 37
Insulator Pin 28 24 30 25 23 16 19
Junctions 2 2 1 4 6 7 2
Lightning 598 163 179 635 453 297 200
Maint/Upgrade 539 1571 3334 2589 1840 1880 1566
Other 394 414 426 483 472 467 344
Pole Fire 116 102 117 113 152 134 153
Pole-rotten 44 37 35 52 34 55 43
Primary Splice 0 1 1 0 0 0 0
Protected 18 10 4 5 5 3 4
Recloser 4 11 3 2 3 11 2
Regulator 14 20 17 13 17 18 13
SEE REMARKS 821 892 543 487 463 508 518
Service 123 188 197 230 191 124 172
Snow/Ice 988 565 167 352 122 243 1882
Squirrel 700 390 395 358 215 279 272
Switch/Disconnect 9 3 0 3 6 16 8
Termination 7 7 9 12 21 19 8
Transformer - OH 158 128 156 167 132 133 84
Transformer UG 57 53 51 50 71 60 62
Tree 55 53 51 56 46 60 47
Tree Fell 390 506 392 377 298 393 340
Tree Growth 375 330 335 335 349 400 280
Underground 0 3 1 3 2 2 0
Undetermined 1145 948 861 783 765 723 728
URD Cable - Pri 136 93 95 72 93 88 64
URD Cable - Sec 212 190 248 219 208 188 153
Weather 357 895 325 314 216 166 208
Wildlife Guard 3 0 1 2 0 0 0
Wind 294 1309 256 1042 1126 3238 6465

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 12 of 88
Table 2, OMT Outages and Partial Outages by Sub-Reason and Year
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 13 of 88
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
URD Cable - Sec 201 175 227 202 190 173 145
Weather 273 620 178 170 137 101 122
Wildlife Guard 3 0 0 2 0 0 0
Wind 229 982 195 802 840 2345 5721

Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2009-2015 data
Top Ten Upward Trends
OMT Sub-Reason Slope Change per Year
Wind 709
Maint/Upgrade 79
Snow/Ice 62
Fire 12
Conductor - Pri 9
Foreign Utility 9
Car Hit Pole 9
Conductor - Sec 8
Pole Fire 7
Bird 3

Table 3 shows that the largest upward trend changed this year to Wind. This change was due to the
large wind storm that impacted our service territory in November. Snow/Ice is also very high on the list
and is mostly due to the snow storm in December. Without these major events then Maintenance and
Upgrade would continue to be the largest trend upward. We have implemented many programs that
increase our outages due to maintenance but decrease the number of outages due to failures. Bird has
always been on this list but has slowly dropped to the number 10 spot with a much smaller trend
upward suggesting the increase in wildlife guard installation has had a positive impact. Car Hit Pole
remains pretty steady trending upward and will continue to be monitored. Both Primary and
Secondary Conductor are both increasing at a steady pace and may need to be reevaluated. Primary
Conductor is only addressed with our Grid Modernization and Segment Reconductor and Feeder Tie
program. Fire has consistently been on the top 10 list but is a customer issue and not an Avista issue so
this is not something Avista can mitigate. Foreign Utility is also a non Avista issue and does not need to
be addressed within this document.
Table 4 shows the Top 10 OMT Sub-Reasons with a downward trend. The largest downward trend is in
Undetermined. This Sub-Reason, as well as SEE REMARKS, have been trending downwards for a few
years and is believed to be due to an increased focus on the importance of accurate and standardized
outage data. Squirrel events continue to decline, as well. This is probably largely due to adding Wildlife
Guards (WLG) on new installs and adding them to existing transformers as part of Wood Pole
Management and Grid Modernization. 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. Reduction in lighting strikes may simply be due to nature,
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 14 of 88
however, the Wood Pole Management (WPM), Grid Modernization and Transformer Change-out
Program (TCOP) may also be helping to mitigate this issue by adding lightning arrestors to new install
transformers. The decrease in Cutout/Fuse Sub-Reasons can likely be attributed to Wood Pole
Management, TCOP and Grid Modernization programs along with some contribution from other
programs. The remaining Sub Reasons in the table have trend downward but the changes are not
material at this point in time or are outside of Asset Management’s control.
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2009-2015 data
Top Ten Downward Trends
OMT Sub-Reason Slope Change per Year
Undetermined -61
Squirrel -60
Weather -55
Customer Equipment -37
SEE REMARKS -36
Lightning -23
Connector - Sec -11
Cutout/Fuse -9
URD Cable - Pri -8
Connector - Pri -8

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 “2010 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 trend in the number of events decreasing
over the past 5 years.
AM related OMT events are actually decreasing at a rate around 4%. 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.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 15 of 88

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

y = 623.11x -1E+06
y = -109.11x + 222428
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
2009 2010 2011 2012 2013 2014 2015 2016
Nu
m
b
e
r

o
f

E
v
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t
s

b
y

Y
e
a
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Year
Total Number of OMT Events by Year AM Related Total
Linear (Total Number of OMT Events by Year)Linear (AM Related Total)
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 16 of 88

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 2011, the average Arrester
event in OMT added 0.003380523 to the overall SAIFI number for the year. While the number of
electrical customers does typically 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 2010 Avista had 356,777 electrical customers and the average Arrester
outage event affected 102 customers, so the average SAIFI impact per event was 0.009230266. 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
0.003380523. 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 2015. Some of the Sub-Reasons in
Figure 4 do not have a significant impact on the SAIFI number, however, the trend for all of these Sub-
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
2009 2010 2011 2012 2013 2014 2015 2016
Ev
e
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t
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Total Outage Management Tool Events vs Year
OMT Events w/o Maint/Upgrades OMT Events w/ Maint/Upgrade
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 17 of 88
Reasons are the top increasing SAIFI trends over 5 years which could eventually move them into the top
SAIFI contributors over time.
Figure 5 and Figure 6 illustrate the makeup of the overall SAIFI value and overall OMT Sustained
Outages. Figure 5 and Figure 6 show a different result because the number of customers impacted by
each Sub-Reason is different. For example, we have very few Pole Fire caused outages, but they affect a
large number of customers. So, Pole Fire 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 2010 2011 2012 2013 2014 2015
0.009230266 0.003380523 0.015245676 0.003562297 0.009598559 0.001364179
0.026835343 0.050143556 0.015659978 0.064285794 0.021842454 0.026664936
0.002842798 0 0.006147101 8.27074E-06 0 0
0.001972404 0.00315424 0.004171572 0.004940524 0.003134 0.0051936
0.055741604 0.034563763 0.078829605 0.061689509 0.07509589 0.042359382
0.013459389 0.025213018 0.024181701 0.036457655 0.029884932 0.020986851
0.001923463 0.001952154 0.003857768 0.002491023 0.003821952 0.004026636
0.029390854 0.022841718 0.023941651 0.01912657 0.023079128 0.00541549
0.001764569 0.001927718 0.002095065 0.001612901 0.001526051 0.002468959
0.010791352 0.017452881 0.004106797 0.001059746 0.015222287 0.000560328
8.43629E-05 4.18879E-05 0 4.96037E-05 0 3.39306E-05
0.029472485 0.014918168 0.027484801 0.01707108 0.018776702 0.009920028
0.002911047 0.007751271 0.001543001 0.001766282 0.006145152 0.001637209
9.54113E-05 0.000737521 2.50685E-05 0.001158911 0.000444984 0.000469738
0.000916016 0.001765849 0.004579849 0.012299424 0.001239404 0.007950852
0.026724006 0.011341762 0.01007956 0.035479695 0.010119982 0.019996134
0.06415389 1.9551E-05 1.10385E-05 3.04099E-05 0 0.006688417
0.00947135 0.00767475 0.001619894 0.018937297 0.020106196 0.011789959
0.00609977 0.012718209 0.002646432 0.004556295 0.008017909 0.001082908
5.63488E-06 0 0.002791077 0.000475014 0.000657922 0
0.05153771 0.029986357 0.107700751 0.152792603 0.10038083 0.050646543
0.115272977 0.131045664 0.093958391 0.118799625 0.097069382 0.104791239
0.177318475 0.156583826 0.114257941 0.085502603 0.082302999 0.115450196
0.108242728 0.087722138 0.058825288 0.078650039 0.096520659 0.160560667
0.002027401 0.002475849 0.001111378 0.002186058 0.007843191 0.000477747
1.40872E-05 0.000227493 0 0 0 0
0.005438117 0.000105902 0.000523814 0.000524546 0.000303026 0.00239954
0.002520587 0.000212125 8.36386E-06 0.001310323 0.01501481 0.001838003
0.019517299 0.003012273 0.020486437 0.010292094 0.015208638 0.011244625
0.0263254 0.022946333 0.024001629 0.035782952 0.030523744 0.024167276
0.001512913 0.001254413 0.001425234 0.001116933 0.00158065 0.001204447
0.091003627 0.039682871 0.109703932 0.035007006 0.078612086 0.304018091
0.021425719 0.039013725 0.050207568 0.026293232 0.039139515 0.030862207
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 18 of 88
OMT Sub-Reason 2010 2011 2012 2013 2014 2015
Switch/Disconnect 0.004582077 0 4.14971E-05 0.020930465 0.036865454 0.008279847
Termination 0.000152009 0.000173439 0.000637191 0.003063515 0.002290441 0.001269524
Transformer - OH 0.002407314 0.017106495 0.004874802 0.004093373 0.026346897 0.008655826
Transformer UG 0.001704189 0.001165537 0.001438726 0.006231495 0.009683188 0.001587665
Tree 0.013288743 0.000938339 0.011356792 0.002750215 0.015326026 0.002845582
Tree Fell 0.092136448 0.062998204 0.067319172 0.054556299 0.057820669 0.084106127
Tree Growth 0.007012046 0.003838547 0.005569335 0.005691876 0.009617668 0.003505633
Underground 2.81744E-06 2.80426E-06 3.87453E-05 5.48895E-06 5.45993E-06 0
Undetermined 0.110134471 0.234672203 0.177748096 0.157264023 0.14781125 0.119112398
URD Cable - Pri 0.005903606 0.008770789 0.002422167 0.006080464 0.005855776 0.0069458
URD Cable - Sec 0.000953008 0.001467391 0.001544569 0.001409578 0.000980058 0.001315704
Weather 0.195547002 0.051231256 0.053674679 0.033680951 0.041372627 0.025389892
Wildlife Guard 0 0 8.35232E-06 0 0 0
Wind 0.291134088 0.089836161 0.195492335 0.209669949 0.517115518 1.128419475
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 may need to conduct an
investigation and try to explain why the annual values are exceeding the limit (see Appendix D of the
“2010 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 2005
through 2009. For 2015, 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.
Table 6, OMT Sub-Reasons Exceeding Annual High Limit
OMT Sub-Reasons Exceeding their associated OMT High Limit Number of Years High Limit Exceeded
Car Hit Pole 6
Conductor – Pri 5
Wind 3

Based on Table 6, presently there are no issues requiring changes to our current plans. We will
continue to monitor Conductor – Pri, as this may call for some kind of action in the future. Car Hit Pole
is being analyzed by another group. If a program is implemented from this analysis then we should see
that issue drop off the High Limit Exceeded chart. Wind has popped up on this chart due to a couple of
fourth quarter large storms the past couple of years. We will continue to monitor all of these issues.
Figure 3 shows the quarterly trends that feed into the annual trends for the OMT High Limit. For all
OMT Sub-Reasons since 2006, only five Sub-Reasons have had more than five quarters where they
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 19 of 88
exceeded the High Limit, Car Hit Pole with 17 quarters above the limit, Conductor – Pri with 8 quarters
above the limit, Fire with 6 quarters above the limit and Service with 9 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.

Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits
y = 0.0659x + 1.3231
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Individual Sub-Reasons Exceeding Average Levels
by 2 Standard Deviations per Quarter
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 20 of 88

Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time
0%
5%
10%
15%
20%
25%
30%
Top 10 OMT Sub-Reasons in growing Unreliability
by SAIFI
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 21 of 88

Figure 5, 2015 OMT SAIFI Contribution by Sub-Reason
Wind
48%
Snow/Ice
13%
Pole Fire
7%
Undetermined
5%
Other
5%
Maint/Upgrade
4%
Tree Fell
4%
Lightning
2%
Car Hit Pole
2%
Squirrel
1%
Bird
1%
Weather
1%
SEE REMARKS
1%Conductor -Pri
1%Forced
1%
Everything
Else
5%
2015 SAIFI Contribution by OMT Sub-Reason
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 22 of 88

Figure 6, 2015 OMT Sustained Outage Comparisons
Wind
39%
Snow/Ice
11%
Maint/Upgrade
9%
Customer Equipment
7%
Foreign Utility
5%
Undetermined
4%
SEE REMARKS
3%
Other
2%
Tree Fell
2%
Car Hit Pole
2%
Conductor -Sec
2%
Connector -Sec
2%
Tree Growth
2%
Squirrel
2%
Bird
1%
Weather
1%
Fire
1%
Lightning
1%
Service
1%Pole Fire
1%URD Cable -Sec
1%
Sustained Events by OMT Subreason
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 23 of 88

Figure 7, Customers Affected Per Event Exceeding Risk Action Levels
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2011 2012 2013 2014 2015
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Pole Fire Wind Wind Risk Action Level Pole Fire Risk Action Level
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 24 of 88
System
The distribution system has an equipment average life of 55 years with the replacement value of a little
over $2 billion dollars. For Avista to maintain the system at its current level, just under $37 million a
year would need to be spent on replacing aging infrastructure. The overall capital spending for the
distribution was just over $85.5 million (this includes the large storm and growth). The total capital
spending on just replacement work (with the large storm) was just over $83.5 million. Our replacement
work, without the storm, still exceed our levelized spending required to keep the system at its current
state. Avista also spent around $14 million in O&M on the distribution system.
Network
The downtown network has an equipment average life of 50 years with the replacement value of a little
over $93.7 million. For Avista to maintain the system at its current level, just under $1.9 million a year
would need to be spent on replacing aging infrastructure. The overall capital spending for the network
was $2.7 million (this includes growth). The total capital spending on just replacement work was $1.3
million. Our replacement work last year did not meet our levelized spending required to keep the
system at its current state.
Major Changes
The distribution system is a fairly constant system. Most programs are in place to maintain or improve
infrastructure for current customers or build new to support new customers. Currently there is a
program set to be completed next year that will change out the last area that Avista serves at the legacy
4kV voltage. This voltage is obsolete for serving utility distributions systems and we have very limited
spare equipment to continue service at this voltage. This is a needed upgrade to our standard
distribution class voltage and equipment that was delayed in 2014 due to resources, and was pushed
into 2015 and 2016. This is also the first year that Avista has installed LED street lights. This marks the
beginning of a complete system conversion from the more inefficient high pressure sodium and legacy
mercury vapor lighting to LED lights for both Area and Street Lighting.
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 7,702 overhead circuit miles. 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
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 25 of 88
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. The
2016 budget is set to be cut for this program and many others. The goals of this program would be to
remain on the same 20 year cycle. The inspections would remain identical to the current scope,
however, the follow-up work done through the WPM program would be a subset of the items above.
WPM would no longer replace arresters, cutouts, wildlife guards or do any guying repairs, this work
would be left up to the offices to complete at within their work plan.
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 2005 – 2009 for WPM Related OMT Events. See Table 7 for
the goal and for the actual value for 2015. 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.
Table 7, WPM KPI Goals by Year
KPI
Description
WPM Goal Related
number of OMT Events
Actual WPM
Related number
of OMT Events
Projected Miles
Follow-up
Work**
Actual Miles
Follow-up Work
Completed
2009 1460 1320 500 372
2010 1460 1004 450 435
2011 1460 1004 459 333
2012 1460 1013 416 435
2013 1460 816 445 329
2014 1460 905 412 385
2015 1460 760 390 364
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 26 of 88
*Note: Beginning with 2012, the Actual Miles Follow-up Work Completed will include WPM and
Distribution Grid Modernization miles.
**To maintain a 20 year cycle the program only needs to complete 390 miles per year. The program is a
little behind the targeted average of about 380 miles per year.
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
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 27 of 88
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. Although the
last two year’s SAIFI goals were exceeded it was due in part to a couple large outages. Last year a
couple of squirrel instances happened during Hot Line Holds causing a feeder lockout to occur. This year
Pole Fire caused the biggest issue. There was a single event that required an entire feeder be taken off
line to allow a cutout to be opened safely. This one occurrence impacted nearly 3000 customers.
Removing these exceptions from the SAIFI drops the overall WPM SAIFI to an acceptable level.
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.
The final metric, material use verses model predicted material use, tracks the actual number of key
stock numbers (see Figure 12for 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.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 28 of 88
Table 8, WPM Metric Goals by Year
*The SAIFI number without the exceptions is within the bounds of the projected SAIFI
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. Pole Fire had a slight
increase this year but we had a dry hot summer which could account for some of the increase. 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. Funding limitations
are preventing us from clearing out the backlog. We continue to strive to get funding for the back log.
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 2016. 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 some of the same metrics as WPM
(see Table 22 for the actual comparisons). In 2012, we revised the metrics and now include the miles of
Projected
Metric
Description
Projected WPM
Contribution To The
Annual SAIFI
Number
Projected
Number of
Dist Poles
Inspected
Model Predicted
Material Use for
WPM Follow-up
Work
Projected
Number of
Pole Rotten
OMT Events
Projected
Number of
Crossarm OMT
Events
2009 0.214024996 12,600 4,792 137 32
2010 0.208489356 12,600 4,932 137 32
2011 0.211022023 12,600 5,010 137 32
2012 0.211022023 12,600 6,770 137 32
2013 0.211022023 12,600 8,592 137 32
2014 0.211022023 12,600 10,566 137 32
2015 0.211022023 12,600 12,606 137 32
Actual
Metric
Description
Actual WPM
Contribution To The
Annual SAIFI
Number
Actual
Number of
Dist Poles
Inspected
Actual Material
Use for WPM
Follow-up Work
Actual
Number of
Pole Rotten
OMT Events
Actual Number
of Crossarm
OMT Events
2009 0.1863468 13,161 7,538 44 25
2010 0.19916836 15,553 7,904 37 23
2011 0.202462739 13,324 28,011 35 28
2012 0.16613099 17,318 28,120 52 19
2013 0.15640942 14,364 15,214 34 18
2014 0.241571914* 11,879 14,901 55 26
2015 0.225273848* 8,157 12,072 43 23
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 29 of 88
completed Grid Modernization work in the Table 7 since the work is coordinated with WPM and
intended to help address the backlog in WPM.
WPM Metric Performance
The annual contribution to SAIFI showed a slight incline in 2015 but the overall trend continues to show
improvement and, if the exceptions are removed from this year’s SAIFI then it remains below the five
year average value as shown in
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 30 of 88
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. WPM did not hit the planned
number of inspections shown in
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 31 of 88
Table 8. This is largely due to a budget cut towards the end of the year. The completed inspections are
following the AM plan for WPM very nicely. 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
2011 and although the replacement is not a steady number we have remained above the 3,200
threshold since then. Figure 11 shows how an increasing number of poles are reaching 74 years.
WPM Model Performance
The AM model for WPM provided a decent baseline for estimating the costs of the WPM follow-up
work, however, AM is currently reanalyzing this program and so there will be a new baseline in the near
future.
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.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 32 of 88

Figure 8, WPM OMT Event Trends
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2011 2012 2013 2014 2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 33 of 88

Figure 9, WPM Contribution to Annual SAIFI value by Sub-Reason and Year
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Annual SAIFI Contribution by Sub Reason
2011 2012 2013 2014 2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 34 of 88

Figure 10, Wood Pole Used by Summarized Activity
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Number of poles Used Annually Poles Replaced WPM - Dist Grid Mod
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 35 of 88

Figure 11, Distribution Wood Pole Age Profile
*Pole age data has not been updated in the past 4 years
0.0%
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Over 75 years old
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 36 of 88

Figure 12, Actual vs. Projected Usage for WPM
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 and the percent of squirrel caused outages is now below 3%. We will continue
to monitor this issue.
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
0
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Steel Stubs
Lightning Arresters
Cutouts
Wildlife Guards
Actual vs. Model Projected Usage for WPM
Actual Modeled Projected
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 37 of 88
that year was not influenced by the current AM plan. The final goal was a 50% reduction from the 2006
value of 902; however, this year’s value of 272 exceeds the final goal and has for the past five years.
The second 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. The goals by year are shown in Table 10.

Table 9, Wildlife KPI Goals for 2010 - 2015
KPI
Description
Projected Number of
Squirrel OMT Events
Actual Number of
Squirrel OMT Events
Percentage of sustained outages
caused by Squirrels
2009 810 700 12.2%
2010 720 390 5.62%
2011 630 395 5.05%
2012 540 358 4.54%
2013 450 215 3.27%
2014 450 279 3.45%
2015 450 272 2.97%

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
2010 $71,000 $157,466
2011 $22,000 $34,696
2012 $30,000 $37,935
2013 $37,000 $49,916
2014 $37,000 $46,045
2015 $37,000 $46,269
*Note: Avoided costs were revised from $390 per event to $82 for 2011 on. 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
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 38 of 88
feeders than originally anticipated. This program officially ended a few years ago due to the quick pace
of the work, however, the metrics are still being watched because other programs still have an indirect
impact on the numbers. These other programs continue to add WLG into our system on a less
programmatic basis. Based on Figure 13 and Figure 14 you can see that few WLG were installed this
year with WPM continuing to install the bulk of the WLG. However, the value and original scope of the
program were realized years ago and so this is not a concern. This is the last year that this programs
metrics will be reported on but we do envision a continued value for years to come.
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 WLG installed in 2010.
WILDLIFE GUARDS Model Performance
The Wildlife Guard model under 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 showed real cost savings over time. The program ended a few years ago
and more than exceeded expectations. We continued to report on the established metrics to help
realize a more complete value of the program. Although, we will no longer report on these metrics,
work in WPM and other efforts to install wildlife guards on Distribution Transformers may continue to
create even more value.
Table 11, Worst Feeders for Squirrel related Events for 2015
Feeder Sustained Outages Percentage of all Squirrel related Outages Running Percentage
PIN443 14 3.80% 3.80%
SLW1358 9 2.45% 6.25%
PDL1203 9 2.45% 8.70%
CFD1211 7 1.90% 10.60%
OTH501 6 1.63% 12.23%
SIP12F4 5 1.36% 13.59%
TEN1256 5 1.36% 14.95%
BLU321 5 1.36% 16.31%
CDA124 5 1.36% 17.67%
BUN426 5 1.36% 19.03%
SLW1368 5 1.36% 20.39%
SLW1348 5 1.36% 21.75%
STM633 5 1.36% 23.11%
CHW12F3 5 1.36% 24.47%

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 39 of 88

Figure 13, Wildlife Guards Installed by Year and Expenditure Request
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Failed Electric Dist
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Sys-Dist Reliability-
Improve Worst
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Modernization
TCOP Related
Distribution
Rebuilds
Wildlife Guards Issued by ER and Year
2011 2012 2013 2014 2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 40 of 88

Figure 14, Wildlife Guards Usage by MAC for 2011-2015
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Wildlife Guard Issued by MAC and Year
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2013
2014
2015
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 41 of 88
URD Primary Cable
URD Primary Cable replacement addresses aging underground primary distribution cable. 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.
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. Although the funding has not
matched the original plan, 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 four outages. We anticipated some
low level of funding for the remaining cable sections as they fail and are currently running this program
on this smaller level.
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 2015 but with a limited budget. 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 may need
to be established for addressing this vintage of cable.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 42 of 88

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
2010 119 93 178000 217,883
2011 94 95 178000 225,823
2012 70 72 178000 117,247
2013 45 93 0 35,874
2014 45 88 0 35,515
2015 45 64 0 24,155

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 that are projected to be around 670
events for 2015. Currently, each event on average costs ~$2,800 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
2014 $1,898,311 $1,580,378
2015 $1,997,052 $1,720,020

URD PRIMARY CABLE KPI Performance
For 2015, the performance for URD Primary Cable did not meet expectations but performed well. Table
12 shows that URD Cable – Pri events have not met expectations for the past couple years, however, the
outages continue to have a downward trend. Figure 15 shows the downward trend in the number of
events. 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 have some faults in newer
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 43 of 88
cables and anticipate that this will 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 few years has not performed as well
as years 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.
URD PRIMARY CABLE Summary
Several people have worked diligently 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
the company has reached the end of life on the second generation of URD Cable. The program has
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Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 44 of 88
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.
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. 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.
Table 14, TCOP Metrics
Year
Planned
Number of
Transformers
Changed Out
Actual Number of
Transformers
Changed Out
Planned Energy
Savings from
Transformers
(MWh)
Projected Energy
Savings from
Replaced
Transformers
(MWh)*
2012 2,687 2,529 2,304 2,430
2013 2,555 2,599 2,304 2,671
2014 2,930 2,625 2,304 3,002
2015 305 2,557 299 2,547
2015 – Pad/Subm 2,030 342 1,447 603
2016 1,419 1,265
2016 – Pad/Subm 87 149
2017 948 940
2017 – Pad/Subm 259 466
2018 347 330
2018 – Pad/Subm 1,092 1,853
 Note: values in red have missed the goal
*Conservative estimate based on no load loss
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 45 of 88
Metric Performance
In 2015, we cut back the funding on the TCOP program but were still able to complete in total more
transformer’s than expected. Fewer padmount transformers were completed but many more overhead
transformers were replaced instead. Budgeting for the last few years has had an effect on the expected
program and will continue to impact the program going forward. New metrics have been developed to
account for the extended program due to the decreased budget.
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 continued the work through 2014. This work updated and corrected the
existing information and provided a platform to convert our High Pressure Sodium (HPS) lights to Light
Emitting Diode (LED) fixtures beginning in 2015. The recent cost and reliability improvements in LED
lights have made converting 100W HPS lights to LED fixtures cost effective. The rate schedule was
approved for the state of Washington for 100W and 200W HPS street lights for 2015 and for all non-
decorative wattage of both street and area lights for Washington and Idaho in 2016.
Selected Metrics
Table 15 shows the metrics selected for the Street light change out program. The number of lights
changed out represents the reduction of maintenance costs due to the increased durability of LED lights.
It also provides a leading indicator of how many future light failures we may experience. The energy
savings represents the value of changing out the less efficient HPS lights and quantifies the approximate
amount of energy saved each year by replacing less efficient HPS lights with more efficient LED ones.
Table 15, Area and Street Light Conversion Metrics
Year
Planned
Number of
Lights
Changed Out
Number of Lights
Changed Out
Planned Energy
Savings from
Lights (W)
Actual Energy
Savings from
Lights (W)
2015 3,500 4,166 262,500 312,450
2016 4,000 300,000
2017 5,000 375,000
2018 6,500 487,500
2019 8,000 600,000
Summary
This program is not unique, years ago a systematic change out of mercury vapor lights occurred.
However, some of these lights remained well after the program ended. This program should have a
better result due to the new technology in mapping being used for lights. This program may also expand
to the remaining decorative lights in the future.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 46 of 88
Distribution Vegetation Management (VM)
Our Vegetation Management program maintains the clearance zone free of vegetation for 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 7,702 circuit miles in
Washington, Idaho, and Montana. The Vegetation Management program also covers work on the
Transmission System and the High Pressure Gas Pipeline system, however 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. Our current goal is to be on a 5 year cycle, however, we
don’t always hit our target distance (Table 18) and are closer to a 6 year cycle.
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 VM, we selected one leading KPI and a lagging KPI. These KPIs were set for the old analysis and
ended last year, we linearly progressed these numbers to buffer us until we can establish new KPI goals.
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 18. 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 Tree-
Weather OMT events by year. As seen in Figure 16, there is a relationship 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 the feeders should decline after reaching a 5 year cycle. 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.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 47 of 88
Table 16, Vegetation Management Metric Goals

Projected
SAIFI - Tree Fall
Actual
SAIFI - Tree Fall
Projected
SAIFI - Tree Grow
Actual
SAIFI - Tree Grow
2010 1.40E-07 0.092136448 8.84E-08 0.007012046
2011 1.40E-07 0.062998204 8.84E-08 0.003838547
2012 1.40E-07 0.067319172 8.84E-08 0.005569335
2013 1.40E-07 0.054556299 8.84E-08 0.005691876
2014 1.40E-07 0.057820669 8.84E-08 0.009617668
2015 1.40E-07 0.084106127 8.84E-08 0.003505633
Note: values in red missed the goal
VM KPI Performance
Both Figure 16 and Figure 17 show the same trends for Tree Growth, Tree Fell, and Tree Weather. Table
17 shows the results for Tree Growth and Tree Fell outages and how well these align with the projected
outages. Table 17 shows the field confirmed outages due to Tree-Weather events. These are a subset
of the OMT outages and only include outages that, after being field verified, were still deemed tree
caused. For the last 5 years our average actual annual miles managed is just below the miles needed to
remain on a 5 year cycle. Last year’s missed goal was caused by budget cut late in the year and it is
likely that the slightly less than anticipated average miles is due to this and other past budget cuts. It is
important to keep the program funded at a 5 year pace to continue to achieve our anticipated Projected
Tree Growth + Tree Fell OMT Events – 5 Year Cycle.

Table 17, VM KPI Performance
Note: values in red missed the goal
*Linear progression from previous metrics
Year
Projected Tree
Growth + Tree
Fell OMT
Events – 2009
Plan
Projected Tree
Growth + Tree
Fell OMT
Events – 5
Year Cycle
Actual
Number
of OMT
Events
Projected
Annual
Miles
Managed
Actual Annual
Miles Managed
w/o Risk Tree
or Spraying
Percent
Model
Error
2009 1120 556 765 1,220 790 136%
2010 620 540 836 1,560 1,304 155%
2011 790 500 727 1,560 1,747 145%
2012 1210 520 712 1,560 1,296 137%
2013 1390 630 647 1,560 1,459 103%
2014 1400 780 793 1,560 1,663 102%
2015 1730* 777* 620 1,560* 1,405 -
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 48 of 88

Figure 16, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons

Tree Fell, 506
Tree Fell, 392 Tree Fell, 377 Tree Fell, 298 Tree Fell, 393 Tree Fell, 340
Tree Growth, 330
Tree Growth, 335 Tree Growth, 335
Tree Growth, 349
Tree Growth, 400
Tree Growth, 280
Weather, 895
Weather, 325 Weather, 314
Weather, 216
Weather, 166
Weather, 208
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Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 49 of 88

Figure 17, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell
Sub-Reasons
VM Metric Performance
The Tree OMT Events for 2015 continued to show improvement and were below the AM model
projections (see Table 17). However, we must update the Vegetation Management models to improve
projections and potentially update the program plan.
The cost per mile for VM in 2015 was $1,058 (see Table 19). This much lower than average. This is
partially due to the large amount of miles of distribution that was inspected after the large storm in
November of this year. We need to update the Vegetation Management model to address changes in
the program which will help understand the impact to our system.

Tree Fell, 234 Tree Fell, 215 Tree Fell, 229 Tree Fell, 183 Tree Fell, 223 Tree Fell, 219
Tree Growth, 77
Tree Growth, 71 Tree Growth, 93
Tree Growth, 90
Tree Growth, 123 Tree Growth, 87
Weather, 620
Weather, 178
Weather, 170
Weather, 137
Weather, 101
Weather, 122
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Tree Fell Tree Growth Weather
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 50 of 88

Table 18, Tree-Weather OMT Events Metric for Vegetation Management
Year
Projected
Tree-Weather
OMT Events –
2009 Plan
Projected Tree-
Weather OMT
Events – 5 Year
Cycle
Actual Field
Verified Tree
Caused
Weather
Events
Actual
Number of
Tree-Weather
OMT Events
Percent
Model
Error
2009 420 166 258 357 215%
2010 80 50 403 895 1790%
2011 220 70 159 325 464%
2012 580 70 150 314 449%
2013 800 170 121 216 127%
2014 1120 430 97 166 39%
2015 1358* 416* 84** 208 -
Note: values in red missed the goal
*Linear progression from previous metrics
**Extrapolated out to include December numbers. The field checking has not been completed for
all December tree weather events.

Table 19, VM Cost per Mile and All Vegetation Management Work Metric
Year Actual Annual Miles
Managed all work
Cost per Mile of VM
2009 N/A $6,575
2010 N/A $2,990
2011 3,455 $2,612
2012 3,364 $3,272
2013 4,014 $1,657
2014 4,721 $1,439
2015 5,565 $1,058

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 2016.
VM Summary
Depending on how the program is evaluated, not enough miles are 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.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 51 of 88

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,
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 20.

Table 20, 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
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 2015 Integrated Resource Plan dated August 31st, 2015, Table 8.3, the realized and
anticipated energy savings by identified feeders is shown in Table 21.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 52 of 88

Table 21, Energy Savings based on Integrated Resource Plan
Feeder Service Area Year Complete
Annual Energy Savings
(MWh)
9CE12F4 Spokane, WA (9th & Central) 2009 601
BEA12F1 Spokane, WA (Beacon) 2012 972
F&C12F2 Spokane, WA (Francis & Cedar) 2012 570
BEA12F5 Spokane, WA (Beacon) 2013 885
CDA121 Coeur d'Alene, ID 2013 438
OTH502 Othello, WA 2014 21
RAT231 Rathdrum, ID 2014 0
M23621 Moscow, ID 2015 413
WIL12F2 Wilbur, WA 2015 1,403
WAK12F2 Spokane, WA (Waikiki) 2016 175
RAT233 Rathdrum, ID 2019 471
SPI12F1 Northport, WA (Spirit) 2019 127
Total 6,076

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.
For tracking the impacts of the work on outages, we will monitor the following OMT sub-reasons shown
in Table 22. While the Grid Modernization will affect all of the sub-reasons listed in Table 22Error!
eference source not found., the sub-reasons identified as potentially avoidable represent the most
direct impact of the work. We assume that the number of OMT sustained outages will be reduced by 0.1
outages per mile of overhead work completed.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 53 of 88

Table 22, OMT Sub-Reasons impacted by Grid Modernization
OMT Sub-Reason GM Potentially Avoidable Wood Pole Management
Arrester x
Bird x
Capacitor x
Conductor - Pri x
Conductor - Sec x
Connector - Pri x
Connector - Sec x
Cross arm - rotten x x
Cutout/Fuse x x
Elbow x
Insulator x x
Insulator Pin x x
Lightning
Pole Fire
Pole - rotten x x
Recloser x
Regulator x
Snow/Ice x
Squirrel x
Switch/Disconnect x
Transformer - OH x x
Transformer UG x
Undetermined
Weather
Wildlife Guard x x
Wind x

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 54 of 88
Figure 18, OMT Sustained Outages related to Grid Modernization
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OMT Sustained Outages related to Grid Modernization
Grid Mod Feeder Outages System-Wide Outages
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 55 of 88
Figure 19, Wood Pole Management and Grid Modernization Before and After
Metric Performance
The results of the first four years work are shown in Table 23 the major event days from 2015 were
removed to more accurately show program value). The year 2012 marks the beginning of the program.
The number of miles actually completed missed the goal of 137 and the number of sustained outages
just fell short of its goal. Figure 19 shows the prior and post trends for WPM and Grid Mod. These
trends are broken down to be outage specific per program on a per mile of OH Conductor basis. The
graph shows a steady trend downward for both programs after work is done on a feeder. Grid Mod
work tends to trend down prior to the completion date due to the time it takes to complete the Grid
Mod work and in some cases feeders being previously completed by WPM. A feeder may take multiple
years to complete thus some portion of the benefits are gained in the couple years before completion.
The before/after portion of the graph is set so that all the work done for these programs since 2008 is
set to a zero year on the year it was completed. The program is reducing outages as seen in Figure 19
and Table 23 even though the planned miles have yet to be met. Missing this goal increases our
program cycle, the current goal is a 60 year cycle. Continuing to miss this mileage can impact the
sustained outages over time.
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Wood Pole Management & Grid Modification
Before and After
Average before WPM Average after WPM Average after Grid Mod Average before Grid Mod
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 56 of 88

Table 23, Metric Performance for Grid Modernization Program
Year
Planned Miles
for
Modernization
(Miles)*
Actual Miles
Completed
(Miles)**
Anticipated
Number of
Sustained
Outages
Realized
Number of
Sustained
Outages
2012 95 73.33 2340 2251
2013 137 53.83 2327 1840
2014 137 78.64 2313 1791
2015 137 85.2 2300 2342
2016 190*** 2286
2017 190*** 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. Overall outages are based on the Reliability
Outage events considered
**Data from Grid Modernization Group
***Grid Mod works on both overhead and underground equipment. Future metrics and analysis will be
based on total circuit miles
Summary
The Grid Modernization Program began in earnest in 2012 and represents feeder replacement work and
upgrades founded on smart grid work. Overall the program is improving outages and improving the
health of our system. The anticipated miles completed and cycle time may need to be modified in the
future if the miles continue to miss the goal, however, the anticipated outage reduction appears to be
on target and so the mileage is not an issue at this time.
Worst Feeders
Since 2009, Avista has invested $1-2M annually to improve the reliability of its most underperforming
distribution circuits (aka – Worst Feeders). The Company operates over three hundred and fifty (350)
individual circuits throughout Northern Idaho and Eastern Washington. Many of these circuits serve
rural geographic regions and may extend for hundreds of miles. In most situations, rural circuits route
through heavily timbered national forest areas and are subject to tree, wind, and storm related outages.
Avista’s SAIFI target in 2015 was 1.17. So, on average, an Avista customer could expect one sustained,
contingency outage event in 2015. However, many rural customers experience three to five sustained
outages per year with a few circuits topping the SAIFI chart at above six (see Table 24). Avista operating
engineers are instructed to systematically review outage logs for these circuits and determine an
appropriate level of treatment. Projects vary by individual circumstance but in many cases additional
circuit reclosers are installed to reduce outage exposure and to automatically restore power to
upstream customers. In other locations, circuits in outage prone areas are converted from overhead to
underground. In other situations, circuits are effectively ‘hardened’ by shortening conductor span
lengths or by increasing phase spacing. Of particular note is the Grangeville 1273 circuit. Though its
SAIFI metric is the highest in the Company, the current average of 9.02 is a significant improvement over
the previous three year average of 21.9. A program investment of $217,686 was made on this line and
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 57 of 88
has help to improve its reliability performance. On another circuit, Roxboro 751, over 1 million dollars
was invested to convert overhead line segments to underground cable and the SAIFI statistics improved
from 5.35 to 2.67. In fact, Roxboro now ranks 35th in our feeder list and does not appear in the top
twenty ‘worst feeders’ as depicted in the graphics. In 2016, Avista plans to invest $1.5 million dollars in
ten (10) circuit projects. This includes the final phase of the Roxboro 751 project along with other multi-
year projects including Gifford Feeders 34F1 and 34F2 together with Colville 34F1 projects. Other
projects are first year efforts to improve the service reliability of rural distribution circuits. The 2016
capital plan for the worst feeder program is indicated in Table 25.

Table 24, Worst Feeder SAIFI 3 Year Average
2012-2014
FDR SAIFI 3yr Avg
GRV1273 9.02
STM633 6.82
SPI12F1 6.40
ODN732 6.28
GIF34F1 5.21
GIF34F2 4.79
CHW12F4 4.48
VAL12F2 4.47
CLV34F1 4.44
RDN12F2 4.43
JPE1287 4.27
CHW12F3 4.25
CKF711 4.13
SAG741 4.11
SPR761 4.07
VAL12F1 3.54
SWT2403 3.47
CHW12F2 3.46
MIS431 3.45
RDN12F1 3.40

Table 25, Worst Feeder Projects and Costs
Project Code (SUB FDR SAIFI RANK- DESC) $ in 000’s
GIF 34F1 (5) 250
SPT4S21- Reroute heavily tree area 100
COT2404 50
RSA 431 - various locales 50
LAT 421- various 50
GIF 34F2 (6) - Twin Lake 250
JPE1787(11)-WEI1289(25) 100
CLV 34F1 (9) 250
ROX 751 OH/UG Conversion (35) 150
SPO- #6 Crapo Removal 8 miles 250

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 58 of 88
Feeder Tie Circuits
Urban distribution feeders can be connected to other feeders as a means of “back-up” to serve
customer load. By closing a “tie” switch between the two feeders, it is possible to electrically “feed” a
portion of the adjacent feeder.
Service reliability can be compromised by the contingency loss of substation equipment such as the
substation transformer, and voltage regulator. Car-hit poles can cause lengthy outages. Critical issues
with picking up an adjacent feeder include the reserve capacity of the host feeder and the end of line
service voltage.
In rural areas, feeders with back-up capability are rare because the distance between adjacent circuits
may be several miles. As with urban feeders, loss of substation equipment can cause feeder outages.
Also, losing a portion of the main feeder trunk on a rural, radial feeder due to a tree through the line
and/or via wind damage can also cause an outage that could be minimized with a “tie” feeder capability.
Feeder Tie projects increase the reliability of both of the circuits involved in the “tie”.
ARD12F2-ORN12F1 Tie Circuit
This feeder tie project will allow the Arden12F2 distribution feeder to be fed by Orin12F1. The “tie” is
being built by installing new conductor between the “gap” in the two circuits (see Figure 20). The
conductor has a cross sectional area allowing it to pick up the load of Arden12F2. In addition the voltage
drop of the “tie” conductor is small. Also, a set of voltage regulators is being installed to increase the
voltage on the Arden12F2 feeder to keep it within the required limits. If there is an outage on the
Orin12F1 feeder, the Arden12F2 will be able to pick up a portion of Orin12F1, but not the entire feeder.
This is a two year project with a cost of $850,000 covering a distance of 2 miles between the two
feeders.

Figure 20, ARD12F2 to ORN12F1 Tie
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 59 of 88
DAV12F2-RDN12F1 Tie Circuit
This circuit tie will allow Rearden12F1 to be fed from Davenport12F2 and vice versa. The “tie” is being
built by installing new conductor between the “gap” in the two circuits (see Figure 21). Also, a set of
voltage regulators is being installed to increase the voltage on the host feeder to support customer
service voltage.
This is a multiyear project with a cost of $1.8 million dollars, connecting a distance of 10 miles between
the two feeders.

At this point in time, approximately 5 miles of the tie circuit has been upgraded to 556 AAC. This new
conductor will allow either substation to carry 4 MVA in the Summer, and 6 MVA in the Winter.
When all the conductor is upgraded, the load carrying capability will be doubled and either substation
can pick up the other any time of the year.
Summary
This program is a new program and metrics have yet to be established. Metrics will be worked on this
year with the department running this program. We need to see the results from these future metrics
before we draw any conclusions from the program.

Figure 21, DAV12F2 - RDN12F1 Tie
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 60 of 88
Spokane Electric Network
Equipment Types and Aging
Major network equipment falls into four categories: network transformers, network protectors, cable
(primary and secondary), and physical facilities – duct banks, vaults, manholes, and handholes.
Transformers and Protectors – some age, and maybe initial cost, data may be available via Maximo. A
casual search indicates 27 transformers with purchase dates between 1930 and 1950 still in service in
the network – these records are not verified. Another casual search of network protector records
indicates units dating to 1947 still in service.
Cable – we do not have specific records regarding age of cables. A fair percentage is “OLD” – comments
below.
Physical facilities – again, no specific records. Again, a fair percentage is “OLD”.
KPI and Metrics
There are no established performance metrics for the downtown network. Given that the very nature of
the network architecture is intended to prevent outages, and that OMT does not “see” network events,
we have no specific outage data other than to state that the numbers would be small in comparison
with the rest of the Avista system. Assuming the “network communications” project discussed in the
“Non-routine Projects” section below actually comes to fruition, we would be better able to identify,
track, and analyze outages should they actually occur.
Capital Budgets and Spending - Overview
CapX expenses in the downtown network fall into six general categories. Five are covered in “blanket”
projects; the sixth category is funded by specific CPRs. Details:
1. New services: Commercial, residential, Street Lights
2. Replacement of old primary cable (Paper Insulated Lead Cable, “PILC”)
3. Replacement of old secondary cable (PILC or Rubber Insulated Neutral Cable, “RINC”)
4. Purchase and replacement of aging transformers and network protectors
5. Repair/refurbishment/replacement of vaults/manholes/handholes
6. The fifth category, covered by specific CPRs, may involve projects such as:
a. Work required due to extensive city projects – e.g., the upcoming major rebuild of
Lincoln and Monroe Sts where we have extensive existing facilities which will need
major work or replacement
b. Adding a “SCADA” and communications capability to the existing network – a trial
project for Post West is budgeted.
New Services – Expenses
Generally self-explanatory. ’15 budget $200K
Replacement of old PILC primary cable– Expenses
Our 2015 budget for PILC cable replacement was $340K. The PILC primary cable in our network is
typically 30 years old or more; we do not have specific information on when much of it was installed.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 61 of 88
Our network has about 96,700 feet of primary cable, about 47,900 feet is still PILC. We have targeted for
replacing 7,500 feet of primary PILC each year. In 2015, due to personnel shortages and other more
pressing work, we only replaced 6300 feet of primary cable.
The PILC cable has been very reliable through the years of service; however, as it ages, we have
observed an increase in failures. Our goal of maximizing service in the downtown network drives the
PILC replacement effort. Figure 22 and Figure 23 are illustrations of failures that occurred with older
PILC cable.
Avista was fortunate in that we have only had one PILC cable failure in 2015 and one in 2013. This low
failure rate is in large part due to the proactive replacement of the old cable. Owing to the redundant
nature of our network, neither of these events resulted in customer outages.

Figure 22, A faulted PILC cable
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 62 of 88

Figure 23, A second faulted PILC cable
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 63 of 88
Replacement of old PILC and RINC secondary cable– Expenses
Factors driving replacement of PILC primary and PILC/RINC secondary are essentially the same. We
replaced about 4,600 feet of secondary cable in 2015.
Purchase of new and replacement of aging transformers and network protectors– Expenses
Our 2015 budget for purchasing transformers and protectors was $920K; for replacement activities
including associated cable, vault accessories, etc. was $1.1M.
We have 174 transformers in our network, each equipped with a network protector. Network
transformers and network protectors are specialized devices specifically designed and built to ensure
maximum operating reliability, and in the case of the protector, to improve and ensure safety for the
crews working on the network.
We target replacing 12 transformers per year, and generally, the protector is replaced at the same time
(there are exceptions). Replacement of a network transformer is a labor-intensive operation, and
typically involves added expenses for hiring a crane to move the old and new transformers in and out of
the vault, traffic control, and often crew overtime. We prioritize replacing very old transformers,
transformers which are found to still have PCB oil, and transformers where routine oil sampling
indicates contamination. In addition, transformers where oil sampling indicates high concentrations of
combustible gasses (typically caused by internal arcing or similar events) are replaced immediately. In
2015 we replaced one transformer due to a high concentration of combustible gasses, one due to
contaminated oil, and one ca. 1947 vintage transformer after a bulge was noted in the primary
compartment case. We also replaced three aged transformers on a more “routine” basis.
A transformer failure can be a dramatic and dangerous event. Avista has been fortunate to not
experience a violent transformer failure in recent years (a quick search indicates that the last one was in
2008.) Figure 24 illustrates the transformer which failed in 2008 due to some anomaly in the primary
compartment.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 64 of 88

Repair/refurbishment/replacement of vaults/manholes/handholes– Expenses
Our 2015 budget for this work was $500K.
Our system contains 140 vaults, 325 manholes, and 295 handholes. Many of these, particularly
manholes and handholes, date from the early 1900s and are still in service. In particular, where these
are located in a traveled street, they have often deteriorated due to stresses from traffic, weather, and
related factors. Vaults which have grated covers for circulating air for transformer cooling are often
subjected to chemicals used for deicing streets in winter, which collects in the vaults and deteriorates
the concrete.
When these facilities become deteriorated to the extent we have found in some cases, they represent
not only the possibility of interruptions to service, but becoming traffic hazards as well. In the case of
facilities in sidewalk areas, we have seen cases where cracking or buckling concrete, or deformed lids,
have the potential to be a trip hazard for pedestrians.
Mitigating the vault, manhole, and handhole deterioration has ranged from being as simple as installing
a new lid to removal and replacement of the entire facility. Figure 25 through Figure 27 illustrate various
underground facility deterioration we have recently found, and some of the remediation efforts
undertaken.
Figure 24, A network transformer after a failure in the
primary compartment
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 65 of 88
In 2015, we repaired or replaced 6 of these facilities. We have 3 more in queue pending a break in
winter weather, and we have not started our 2016 inspection cycle.

Figure 26, Duct bank damage entering an old deteriorated manhole
Figure 25, Interior of a badly
deteriorated old manhole in a
heavily traveled street
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 66 of 88

Non-routine Projects Being Carried Out on Specific CARs– Expenses
We had two open CPRs for network projects in 2015.
Network Communications Stage 1– Expenses
This project was budgeted for $122.4K
The scope of this pilot project involves adding communications capabilities to network protectors in a
subset of the Post St West sub-network. This communications capability will enable remote reading of
protector status (closed, tripped, locked open, number of protector operations), and remote
instantaneous load readings. This capability will not immediately improve system reliability, but will
pave the way for additional capability such as remote protector switching and remote indication of vault
conditions (temperature alarm, unauthorized entry, etc.) which is expected to benefit overall network
operation and maintenance. For convenience – think “smart grid” for the downtown Spokane network.
The CPR was first opened in 2014, but to date, lack of personnel resources has resulted in no charges.
This CPR remains open for 2016.
Monroe and Lincoln St Repaving– Expenses
This project was budgeted for $495K ($475K construction, $20K removal/retirement)
The City of Spokane has informed Avista of plans to extensively renovate and repave both Lincoln and
Monroe Streets from 3rd Ave north to Main St in the main downtown corridor. This project will result in
Avista needing to extensively modify, rebuild, and possibly even move network facilities in those streets.
The CPR was opened in 2015 in anticipation of ordering long-lead items, but planning delays resulted in
no expenditures in ’15. The CPR remains open for 2016.
Figure 27, Complete replacement of a badly deteriorated manhole
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 67 of 88
Distribution Line Protection
Avista's Electric Distribution system is configured into a trunk and lateral system. Lateral circuits are
protected via fuse-links and operate under fault conditions to isolate the lateral in order to minimize the
number of affected customers in an outage. Engineering recommends installation of cut-outs on un-fused
lateral circuits and the replacement of obsolete fuse equipment (e.g. Chance, Durabute/V-shaped, Open
Fuse Link/Grasshopper, Q-Q, Load Break/Elephant Ear, and Porcelain Box Cutouts). As part of the
program, sizing of fuses will be reviewed to assure protection of facilities, as well as coordination with
upstream/downstream protective devices. This is a targeted program to ensure adequate protection of
lateral circuits and to replace known defective equipment.
Assets Not Specifically Covered Under a Program
These assets 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, Table 26 lists assets we continue to monitor to
determine if and when planned actions are needed.

Table 26, Assets Not Specifically Covered Under a Program
Asset Other information
Distribution Capacitors Smart Grid added switch capacitors but our initial analysis did not
indicate a strategy was justified
Distribution Cutotuts Addressed through the WPM program and Distribution Line protection
Dead End Insulators -
Distribution Mid- Line Reclosers Substation Asset Management is analyzing strategies for this asset
Distribution Mid- Line Voltage
Regulators
Substation Asset Management is analyzing strategies for this asset
Open Wire Secondary Previous analysis indicated that this program was not financially
justified. We believe Grid Mod will address many of these issues.
Primary Conductors -
Primary Connections -
Secondary Conductors -
Primary Conductors -
Riser Termination --
URD Secondary Cable Although we are monitoring this one closely we have yet to see a need
to implement a strategy

Conclusion
In this report, we documented and examined the KPIs and metrics AM selected for the AM Distribution
system programs and provided the results for 2015. 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
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 68 of 88
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. This year other non-AM programs were included in this report and
submitted by the group in charge of each program. These program write-ups did not follow the same
template as the AM write-ups but were included within the document for project comparison.

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 69 of 88
Distribution Vegetation Management
2016
Washington
AIR12F1
AIR12F2
AIR12F3
CFD1210
CFD1211
CHE12F1
CHE12F2
CHE12F3
CHE12F4
CLA56
EWN241
FOR2.3
GIF34F2
INT12F1
INT12F2
L&R511
L&S12F1
L&S12F2
L&S12F3
L&S12F4
L&S12F5
LOO12F1
LOO12F2
MLN12F2
ROK451
ROX751
SE12F1
SE12F2
SE12F3
SE12F4
SE12F5
SOT522
SOT523
SPI12F1
TUR111
TUR112
TUR113
TUR115
TUR116
TUR117
TVW131
TVW132
VAL12F1
Idaho
CGC331
CKF711
DAL131
DAL132
DAL133
DAL134
GRV1271
GRV1272
GRV1273
GRV1274
KAM1291
KAM1292
KAM1293
KOO1298
KOO1299
RAT231
RAT233
SAG741
SPT4S21
SPT4S22
SPT4S23
SPT4S30
Montana
NRC352

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 70 of 88
2017
Washington
CHW12F1
CHW12F2
CHW12F3
CHW12F4
COB12F1
COB12F2
DVP12F1
DVP12F2
ECL221
ECL222
FWT12F1
FWT12F2
FWT12F3
FWT12F4
GLN12F1
GLN12F2
GRN12F1
GRN12F2
GRN12F3
L&R512
LEO611
LEO612
LF34F1
LIB12F1
LIB12F2
LIB12F3
LIB12F4
MEA12F1
MEA12F2
MLN12F1
OTH501
OTH502
OTH503
OTH505
ROS12F1
ROS12F2
ROS12F3
ROS12F4
ROS12F5
ROS12F6
Idaho
BUN422
BUN423
BUN424
BUN426
CRG1260
CRG1261
CRG1263
MIS431
NEZ1267
ODN731
ODN732
ORO1280
ORO1281
ORO1282
PIN441
PIN442
PIN443
POT321
POT322
PRA221
PRA222
PVW241
PVW243
WOR471
SWT2403
WIK1278
WIK1279

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 71 of 88
2018
Washington
3HT12F1
3HT12F2
3HT12F3
3HT12F4
3HT12F5
3HT12F6
3HT12F7
3HT12F8
9CE12F1
9CE12F2
9CE12F3
9CE12F4
ARD12F1
BKR12F1
BKR12F3
C&W12F1
C&W12F2
C&W12F3
C&W12F4
C&W12F5
C&W12F6
CLV12F1
CLV12F2
CLV12F3
CLV12F4
CLV34F1
DRY1208
DRY1209
GAR461
HAR4F1
HAR4F2
KET12F1
MIL12F1
MIL12F2
MIL12F3
MIL12F4
NW12F1
NW12F2
NW12F3
NW12F4
NW13T23
PAL311
PAL312
RDN12F1
RDN12F2
RIT731
RIT732
SPA442
SPU121
SPU122
SPU123
SPU124
SPU125
WAK12F1
WAK12F2
WAK12F3
WAK12F4
Idaho
BIG411
BIG412
BIG413
BLU321
COT2401
COT2402
HUE141
HUE142
LKV341
LKV342
LKV343
LKY551
M15511
M15512
M15513
M15514
M15515
M23621
NMO521
NMO522
OSB522
STM631
STM632
STM633

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 72 of 88
2019
Washington
ARD12F2
BKR12F2
DEP12F1
DEP12F2
DIA231
DIA232
EFM12F1
EFM12F2
H&W12F1
H&W12F2
KET12F2
LAT421
LAT422
LIN711
ORI12F1
ORI12F2
ORI12F3
SUN12F1
SUN12F2
SUN12F3
SUN12F4
SUN12F5
SUN12F6
WAS781
WIL12F1
WIL12F2
Idaho
BLA311
CDA121
CDA122
CDA123
CDA124
CDA125
JUL661
LOL1359
OGA611
OLD721
OLD722
OSB521
PF211
PF212
PRV4S40
SLW1316
SLW1348
SLW1358
SLW1368
SPL361
TEN1253
TEN1254
TEN1255
TEN1256
TEN1257

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 73 of 88
2020
Washington
BEA12F1
BEA12F2
BEA12F3
BEA12F4
BEA12F5
BEA12F6
BEA13T09
F&C12F1
F&C12F2
F&C12F3
F&C12F4
F&C12F5
F&C12F6
FOR12F1
GIF34F1
LL12F1
NE12F1
NE12F2
NE12F3
NE12F4
NE12F5
ODS12F1
OPT12F1
OPT12F2
PDL1201
PDL1202
PDL1203
PDL1204
PST12F1
RSA431
SIP12F1
SIP12F2
SIP12F3
SIP12F4
SIP12F5
SLK12F1
SLK12F2
SLK12F3
SOT521
SPI12F2
SPR761
TKO411
TKO412
VAL12F2
VAL12F3
Idaho
APW111
APW112
APW113
APW114
APW115
APW116
AVD151
AVD152
CKF712
DER651
DER652
HOL1205
HOL1206
HOL1207
IDR251
IDR252
IDR253
JPE1287
JUL662
LOL1266
N131222
N131321
PF213
SAG742
WAL542
WAL543
WAL544
WAL545
WEI1289
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 74 of 88
Distribution Wood Pole Management
2016 2017 2018 2019 2020
SOT522 BEA12F3 APW116 9CE12F1 LIN711
AIR12F3 BEA13T09 ARD12F1 9CE12F2 BLA311
APW114 COT2401 - ID ARD12F2 9CE12F3 CHW12F1
APW115 COT2402 - ID BEA12F4 BLU321 CHW12F2
CHE12F4 DVP12F2 BEA12F6 BLU322 CHW12F3
CLA56 F&C12F3 BIG411 FWT12F2 CHW12F4
L&S12F1 F&C12F4 CFD1210 - WA GIF34F2 EWN241
L&S12F2 F&C12F5 CHE12F1 INT12F1 JUL661
L&S12F3 F&C12F6 CHE12F2 INT12F2 JUL662
L&S12F4 FOR12F1 CMP12F2 LAT421 - WA KAM1291
L&S12F5 FOR2.3 FWT12F4 LAT422 - WA KAM1292
LKV341 IDR253 JPE1287 - ID LTF34F1 KAM1293
LKV342 OTH501 OPT12F1 NE12F5 LEO611
LKV343 PVW243 OPT12F2 PRV4S40 LOO12F2
LOL1359 - ID SIP12F1 OSB521 RSA431 MIS431
MLN12F1 SIP12F3 PST12F1 SPI12F2 ORI12F1
MLN12F2 SOT523 PST12F2 WAK12F1 ORI12F2
NLW1222 - ID SWT2403 - ID SLW1348 - ID WAK12F3 PIN441
SPT4S23 SPA442 - WA WAK12F4 POT321
SPT4S22 RDN12F1
RIT731
RIT732
SPL361
WEI1289
2021 2022 2023 2024 2025
CFD1210 ECL221 9CE12F4 BIG412 BKR12F1
CRG1260 ORO1282 BUN423 BKR12F3 CDA125
DVP12F1 PAL311 BUN426 CRG1261 CRG1263
FWT12F1 PAL312 CLV12F1 DER652 F&C12F2
FWT12F3 PIN443 GRV1274 H&W12F1 HAR4F2
HOL1205 POT322 M15512 H&W12F2 LEO612
HOL1206 RDN12F2 PDL1201 LIB12F3 LIB12F1
NE12F4 SPT4S21 PDL1202 ODS12F1 LIB12F4
PF213 STM631 SE12F1 ORI12F3 M15511
ROS12F3 VAL12F2 SLW1316 ORO1281 MIL12F1
SE12F3 VAL12F3 SOT521 SLK12F3 NEZ1267
SIP12F2 SUN12F1 WAL542 NLW1321
SLW1348 SUN12F3 NMO522
SLW1358 SIP12F5
WOR471 SUN12F6
TUR116
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 75 of 88

2026 2027 2028 2029 2030
AIR12F1 DAL131 CLV12F2 3HT12F4 BIG413
CFD1211 DAL132 CLV34F1 BEA12F5 BKR12F2
DRY1208 DAL134 ECL222 C&W12F1 BUN422
GRV1271 MEA12F2 GRN12F1 CDA121 BUN424
HUE141 MIL12F2 ROK451 CDA122 DRY1209
KOO1298 MIL12F4 TKO411 CDA124 GRN12F2
KOO1299 PF212 TKO412 CLV12F3 GRV1272
OGA611 PRA221 CLV12F4 GRV1273
PDL1203 PRA222 HOL1207 HUE142
PF211 TEN1253 LKY551 KET12F1
WAL543 TUR117 MEA12F1 L&R511
WIK1278 NE12F3 L&R512
WIK1279 SE12F5 LKY552
WIL12F1 TEN1257 NMO521
OSB522
PIN442
PVW241
WAL544
WAL545
2031 2032 2033 2034 2035
3HT12F1 CKF711 NW12F4 AIR12F2 BEA12F1
3HT12F2 CKF712 3HT12F5 CHE12F3 ODN731
3HT12F3 DIA231 3HT12F6 COB12F1 ODN732
CGC331 DIA232 3HT12F7 COB12F2 SPU121
M15514 EFM12F2 APW111 EFM12F1 SPU122
NRC351 HAR4F1 APW112 M15515 SPU123
ROX751 KET12F2 C&W12F2 MIL12F3 SPU124
SLW1368 LL12F1 C&W12F3 STM633 SPU125
SUN12F2 LOO12F1 C&W12F4 SUN12F4 TEN1254
TUR113 PDL1204 C&W12F5 SUN12F5 TUR111
STM632 C&W12F6 TUR115
NE12F2 VAL12F1
NW12F1
NW12F3
SPT4S30
WAK12F2
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 76 of 88
Grid Modernization

2016 Grid Modernization Plan
Feeder Design Constr State Region Area
BEA12F1 x WA West Spokane
M23621 x ID South Pullman/Mosc
MIL12F2 x x WA West Spokane
MIS431 x WA East Kellogg
ORO1280 x ID South Grangeville
PDL1201 x WA South Lewiston/Clark
RAT231 x ID East Coeur d'Alene
RAT233 x 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

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
MIS431 x WA East Kellogg
ORO1280 x
PDL1201 x WA South Lewiston/Clark
RAT233 x x ID East Coeur d'Alene
SPI12F1 x WA West Colville
SPR761 x x WA West Othello
TUR112 x x WA South Pullman/Mosc

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 77 of 88
2018 Grid Modernization Plan
Feeder Design Constr State Region Area
2017 Carryover x x
BEA12F2 x WA West Spokane
DEP12F2 x WA West Deer Park
F&C12F1 x x WA West Spokane
HOL1205 x WA South Lewiston/Clark
M15514 x ID South Pullman/Mosc
MIL12F2 x ID West Spokane
MIS431 x x WA East Kellogg
TEN1255 x ID South Lewiston/Clark
RAT233 x ID East Coeur d'Alene
SPI12F1 x ID West Colville
SPR761 x WA West Othello

2019 Grid Modernization Plan
Feeder Design Constr State Region Area
2018 Carryover
BEA12F2 x x WA West Spokane
F&C12F1 x WA West Spokane
HOL1205 x ID South Lewiston/Clark
M15514 x ID South Pullman/Mosc
MIL12F2 x WA West Spokane
MIS431 x x ID East Spokane
MLN12F1 x x WA West Deer Park
RAT233 x x ID East Kellogg
SPR761 x WA West Othello
TEN1255 x x ID South Lewiston/Clark
TEN1256 x WA South Lewiston/Clark
TUR112 x WA South Pullman/Mosc
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 78 of 88
Transformer Change-Out Program
TCOP Work Plan Year Program Working Count
2016 GMP 305
2016 TCOP 1027
2016 WPM 180
2017 GMP 459
2017 TCOP 480
2017 WPM 64
2017 Predicted Non Detect TCOP 204
2018 GMP 252
2018 TCOP 14
2018 WPM 138
2018 Predicted Non Detect GMP 5
2018 Predicted Non Detect TCOP 1031

Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 79 of 88
Business Cases

Distribution Wood Pole Management

Investment Name:
Requested Amount Assessments:
Duration/Timeframe Indefinite Financial:
Dept.., Area: Strategic:
Owner: Business Risk:
Sponsor: Program Risk:
Category:
Mandate/Reg. Reference: Assessment Score:93
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Customer IRR =
7.42% and avoids
an average of
1,700 additional
events per year
11,172,022$ 530,943$ 5,996,350$ 15
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Status Quo: No Wood Pole
Management
Increase OMT
events by 1,700
events
8,186,361$ -$ 6,834,467$ 25
Alternative 1: Distribution
Wood Pole Management -
20 Year Inspection Cycle
describe any
incremental
changes in
operations
10,712,022$ 530,943$ 5,996,350$ 15
Alternative 2: Distribution
Wood Pole Management -
20 Year Inspection Cycle
with Guy Wire
describe any
incremental
changes in
operations
11,172,022$ 530,943$ 5,996,350$ 0
Alternative 3 Name :
Distribution Wood Pole
Management - 10 Year
Inspection Cycle with Guy
Wire Replacement
describe any
incremental
changes in
operations
17,296,437$ 961,699$ 4,920,632$ 0
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
Previous 21,393,700$ -$ 18,767,986$ 2060
2015 11,500,000$ 10,600,000$
2016 11,200,000$ 543,155$ 4,564,898$ 7,840,000$
2017 14,700,000$ 555,648$ 4,574,638$ 12,000,000$
2018 14,700,000$ 570,094$ 4,588,630$ 15,700,000$
2019 14,700,000$ 584,916$ 4,611,573$ 16,060,000$
2020 14,700,000$ 600,124$ 4,634,631$ 14,700,000$
2021+15,700,000$ 615,728$ 4,657,804$ -$
Total 118,593,700$ 3,469,665$ 27,632,174$ 95,667,986$
ER 2016 2017 2018 2019 2020 Total
2060 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total -$ -$ -$ -$ -$ -$
Asset Maintenance Life-cycle asset management
Distribution Wood Pole Management
Estimated Total Capital Expenditure
Cox/H. Rosentrater High certainty around cost, schedule and resources
Program
NESC - See WPM Compliance Plan for details Annual Cost Summary - Increase/(Decrease)
Annual Cost Summary - Increase/(Decrease)
Year Program
Mandate Excerpt (if applicable):
Additional Justifications:
Any supplementary information that may be useful in
describing in more detail the nature of the Project, the
urgency, etc.
The current WPM program complies with the following
part of the National Electric Safety Code: 013, 121, 212
A, 212 B, and 261 A.2
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a
10 year cycle and repairs or replaces wood poles, crossarms, missing lightning arresters,
missing grounds, bad cutouts, bad insulating pins, bad insulators, leaking transformers,
replaces guy wires not meeting current code requirements, and replaces pre-1981
transformers
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a
20 year cycle and repairs or replaces wood poles, crossarms, missing lightning arresters,
missing grounds, bad cutouts, bad insulating pins, bad insulators, leaking transformers,
replaces guy wires not meeting current code requirements on poles replaced by WPM, and
replaces pre-1981 transformers
Associated Ers (list all applicable):
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a 20 year cycle
and repairs or replaces wood poles, crossarms, missing lightning arresters, missing grounds, bad cutouts,
bad insulating pins, bad insulators, leaking transformers, and replaces pre-1981 transformers. Note: does
not cover the additional costs associated with the backlog that is related to new requirements such as
additional grounding and anchor rod replacements.
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a 20 year cycle
and repairs or replaces wood poles, crossarms, missing lightning arresters, missing grounds, bad cutouts,
bad insulating pins, bad insulators, leaking transformers, replaces guy wires not meeting current code
requirements on poles replaced by WPM, and replaces pre-1981 transformers
Run wood poles and associated equipment to failure
Glenn Madden (Manager)Business Risk Reduction >5 and <= 10
7.42%
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 80 of 88
URD Primary Cable

Investment Name:
Requested Amount Assessments:
Duration/Timeframe 2 Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Project/Program Risk:
Mandate/Reg. Reference: Assessment Score:110
Recommend Project Description: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Customer IRR =
10% and avoids
an average of
600 outages per
year
1,800,000$ -$ -$ 4
Alternatives: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Status Quo: Increase
number of
Outage towards
700 per year
-$ -$ 1,300,000$ 10
Alternative 1: Primary
URD Cable Replacement
Customer IRR =
10% and avoids an
average of 600
outages per year
1,800,000$ -$ -$ 4
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name : Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Timeline Construction Cash Flows (CWIP)
Capital Cost O&M Cost Other Costs Approved
Previous 19,852,679$ -$ -$ 19,852,679$
2012 1,800,000$ -$ -$ 1,982,000$
2013 1,000,000$ -$ -$ 1,000,000$
2014 1,000,000$ -$ -$ 750,000$
2015 1,000,000$ -$ -$ 1,000,000$
2016 1,000,000$ -$ -$ 200,000$
2017 1,000,000$ -$ -$ 500,000$
2018 1,000,000$ -$ -$ 1,000,000$
2019 -$ -$ -$ -$
2020 -$ -$ -$ 800,000$
Total 27,652,679$ -$ -$ 27,084,679$
Milestones (high level targets)
November-11 Project Started December-12 Plant In Service mm/dd/yy open
March-12 Project Plan December-12 Project Complete mm/dd/yy open
June-12 Project Design mm/dd/yy open mm/dd/yy open
March-12 Major Procurement mm/dd/yy open
September-12 Construction Start mm/dd/yy open
Current ER 2054
Mandate Excerpt (if applicable):
Additional Justifications:
Cost Summary - Increase/(Decrease)
MH - >= 9% & <12% CIRR
Life Cycle Programs
Operations improved beyond current levels
ERM Reduction >5 and <= 10
High certainty around cost, schedule and resources
Describe other options that were considered
Complete the replacement of the un-jacketed first generation of Primary URD cable
Associated Ers (list all applicable):
Cost Summary - Increase/(Decrease)
Number of Primary URD Cable faults would increase and the cost to repair the
cable would also increase. Without this work and the past 4 years of work,
the increased O&M costs would sum up to $8.8 million over the next 5 years.
Complete the replacement of the un-jacketed first generation of Primary URD
cable
Describe other options that were considered
Jason Thackson
Project
n/a
Primary URD Cable Replacement 2013
$1,800,000
Asset Management & Process Improvement
Year Project
Kevin Christie
Milestones should be general. In some cases it may be as simple as project start,
project complete. Use your judgementon project progress so that progress can be
measured.
0 2 4 6 8 10 12 14
Replace Old URD Cable
Time (Months)
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 81 of 88
Transformer Change Out Program

Investment Name:
Requested Amount Assessments:
Duration/Timeframe 25 Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:89
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
When
completed save
an average of
5.6 MW per
hour and
eliminate PCB
environmental
risks
5,800,000$ 105,000$ -$ 3
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a 4,500,000$ 200,000$ 900,000$ 12
Alternative 1: Transformer
Change-Out Program
When
completed save
an average of
5.6 MW per
hour and
5,800,000$ 105,000$ -$ 3
Alternative 2:200,000$ -$ -$ 0
Alternative 3 Name : -$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER 1003
Capital Cost O&M Cost Other Costs Approved 2060
2535
2012 7,000,000$ 100,000$ -$ 6,000,000$
2013 7,200,000$ 102,000$ -$ 2,924,015$
2014 5,800,000$ 105,000$ -$ 3,944,000$
2015 5,800,000$ 107,000$ -$ 3,750,000$
2016 5,800,000$ 110,000$ -$ 2,200,000$
2017 1,100,000$ 1,900,000$
2018 1,700,000$
Total 32,700,000$ 524,000$ -$ 22,418,015$
Mandate Excerpt (if applicable):
Additional Justifications:
Asset Management & Process Improvement Life Cycle Programs
Distibution Transformer Change-Out Program
7,000,000$
Year Program Medium - >= 5% & <9% CIRR
Glenn Madden (Manager) & Al Fisher (Dir)Operations require execution to perform at current levels
Don Kopczynski ERM Reduction >5 and <= 10
Program High certainty around cost, schedule and resources
n/a Annual Cost Summary - Increase/(Decrease)
The Distribution Transformer Change-Out Program has three main drivers. First, the pre-1981 distribution
transformers that are targeted for replacement average 42 years of age and are a minimum of 30 years
old. Their replacement will increase the reliability and availability of the system. Secondly, the
transformers to be replaced are inefficient compared to current standards and their replacement will result
in energy savings. Thirdly, pre-1981 transformers have the potential to have pcb containing oil. The
transformers to be removed early in the program are those that are most likely to have pcb containing oil
and their replacement will reduce the risk of pcb containing oil spills which are a safety, environmental,
and a public relations concern.
Annual Cost Summary - Increase/(Decrease)
No planned replacement program for distribution transformers. Substancially
higher risk of a pcb containing oil spill occuring.
The Distribution Transformer Change-Out Program has three main drivers.
First, the pre-1981 distribution transformers that are targeted for replacement
average 42 years of age and are a minimum of 30 years old. Their
replacement will increase the reliability and availability of the system.
Secondly, the transformers to be replaced are inefficient compared to current Distribution Engineering has proposed that any pole that the TCOP does work
on needs to have the guy replaced with the new standard guy insulator (fiber
cable).
Associated Ers (list all applicable):
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 82 of 88
Area and Street Light

Investment Name: Street Light Management
Requested Amount $475,000 Assessments:
Duration/Timeframe Indefinite 2014 Financial:
Dept.., Area: Operations Strategic:
Owner: Al Fisher Business Risk:
Sponsor: Don Kopczynski Program Risk:
Category: Program
Mandate/Reg. Reference: n/a Assessment Score:89
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
7.92%475,000$ (250,000)$ (750,000)$ 8
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program:
Continue maintaining the
street lights as failures
occur
6.29%
2 - S3 event in
10 years
-$ 1,500,000$ 1,800,000$ 16
Alternative 1: 7.92%
1.5 - S3 event in
10 years
475,000$ (250,000)$ (750,000)$ 8
Alternative 2: 7.28%
1 - S3 event in
10 years
890,000$ (250,000)$ (1,175,000)$ 12
Alternative 3:7.82%
1 - S3 event in
10 years
895,000$ (250,000)$ (1,165,000)$ 12
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
Previous -$ -$ -$ -$ New ER
2013 -$ -$ -$ -$
2014 475,000$ (250,000)$ -$ -$
2015 484,500$ (500,000)$ -$ 2,400,000$
2016 494,190$ (750,000)$ -$ 1,500,000$
2017 504,074$ (1,000,000)$ -$ 1,500,000$
2018 -$ -$ -$ 1,500,000$
2019 -$ -$ -$ 1,500,000$
2020
Total 1,957,764$ (2,500,000)$ -$ 8,400,000$
ER 2013 2014 2015 2016 2017 Total
New ER -$ 475,000$ 484,500$ 494,190$ 504,074$ 1,957,764$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total -$ 475,000$ 484,500$ 494,190$ 504,074$ 1,957,764$
Associated Ers (list all applicable):
Life-cycle asset management
Moderate certainty around cost, schedule and resources
Annual Cost Summary - Increase/(Decrease)
Annual Cost Summary - Increase/(Decrease)
Mandate Excerpt (if applicable):
Additional Justifications:
Street Light Maintenance Program. This program is a 5 year planned
replacement of bulbs and 10 year planned replacement of photocells. This
alternative has the starterboards running to failure.
Street Light Maintenance Program. This program is a 5 year planned
replacement of bulbs and starterboards and a 10 year planned replacement of
photocells.
Street Light Maintenance Program. This program is a 5 year planned
replacement of bulbs and a 10 year planned replacement of photocells and
starterboards.
Business Risk Reduction >5 and <= 10
7.92%
Street Light Maintenance Program. This program is a 5 year planned replacement of bulbs and 10 year
planned replacement of photocells. This alternative has the starterboards running to failure.
The lights are currently maintained based on customer feedback and/or due to
being noticed by an Avista employee. Many street lights are out for long
periods of time which can put us at risk. We also spend a large amount of
time driving from issue to issue.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 83 of 88
Grid Modernization

Investment Name:
Requested Amount Assessments:
Duration/Timeframe Indefinite Financial:
Dept.., Area: Strategic:
Owner: Business Risk:
Sponsor: Program Risk:
Category:
Mandate/Reg. Reference: Assessment Score:133
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
When completed
save an average of
1,970 MWh*
annually & Reduce
Outages
21,000,000$ -$ 198,000$ 4
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a 120,000$ -$ 1,980,000$ 25
Alternative 1: Brief name
of alternative (if
applicable)
When completed
save an average of
1,970 MWh*
annually & Reduce
Outages
21,000,000$ -$ 198,000$ 4
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name : Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
Previous 7,308,357$ -$ -$ 7,308,357$ Dist Grid Modernization 2470
2014 8,686,019$ -$ -$ 9,586,000$ Sandpoint SG 2570
2015 11,000,000$ -$ -$ 12,310,000$ Grid Mod Automation 2599
2016 12,000,000$ -$ -$ 7,000,000$
2017 13,000,000$ -$ -$ 13,000,000$
2018 15,000,000$ -$ -$ 15,000,000$
2019 18,000,000$ -$ -$ 21,000,000$
2020 21,000,000$ -$ -$ 20,800,000$
Total 105,994,376$ -$ -$ 106,004,357$
ER 2015 2016 2017 2018 2019 Total
Dist Grid Modernization -$ -$ -$ -$ -$ -$
2470 11,000,000$ 11,000,000$ 13,000,000$ 15,000,000$ 15,000,000$ 65,000,000$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Sandpoint SG -$ -$ -$ -$ -$ -$
2570 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Grid Mod Automation -$ -$ -$ -$ -$ -$
2599 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total 11,000,000$ 11,000,000$ 13,000,000$ 15,000,000$ 15,000,000$ 65,000,000$
The Dist Grid Modernization Program provides benefits to customers,
employees, and shareholders by replacing problematic poles, cross-arms, cut-
outs, transformers, conductor, etc. In addition, adding switched capacitor
banks and smart grid devices is of benefit due to increased energy efficiency
and system reliability.
Describe other options that were considered
Describe other options that were considered
Troy A. Dehnel Business Risk Reduction >15
6.4% Customer IRR
Mandate Excerpt (if applicable):
WSDOT Target Zero, an FHWA mandated initiative in
MAP-21, requires that utilities move all non-breakaway
structures out of the clear zone as defined in the 10/2005
AASHTO "A Guide for Accommodating Utilities Within
Highway Right-of-Way. WA State law requires that we
complete this task by year 2030.
Additional Justifications:
WAC 468-34-350 - Control Zone Guidelines, WAC 468-34-
300 - Overhead Lines Location, RCW 47.32.130 Dangerous
Objects and Structures as Nuisances, RCW 47.44.010 Wire
and Pipeline and Tram and Railway Franchises - Application -
Rules on Hearing and Notice, RCW 47.44.020 Grant of
Franchise - Condition - Hearing.
Associated Ers (list all applicable):
Distribution Engineering Life-cycle asset management
Distribution Grid Modernization
See Plan Below
Don Kopczynski High certainty around cost, schedule and resources
Program
Federal & State Clear Zone Mitigation Directives Annual Cost Summary - Increase/(Decrease)
The Distribution Grid Modernization Program provides value to customers and shareholders by improving Grid Reliability,
Energy Savings and Operational Ability through a systematic and managed upgrade of our aging distribution system. This
program seeks cost effective opportunities to increase service quality performance and system availability through the
identification of locations that would benefit from the addition of switched capacitor banks, regulators and smart grid
devices. The long-term plan represented by the IRR of 6.4% aims to upgrade 6 feeders per year to cover the whole
distribution system in a 60 year cycle. This coordinates well with Wood Pole Management's 20 year cycle. The average cost
to rebuild each feeder is estimated to be $3.5M.
Annual Cost Summary - Increase/(Decrease)
No systematic plan for wholistic address of conductors, reconfiguring services
for better access, or adding devices that benefit the performance of the
feeder.
Year Program
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 84 of 88
Worst Feeder

Investment Name:
Requested Amount Assessments:
Duration/Timeframe on-going Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:84
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Improve the
overall system
performance of
the Company's
"top ten" worst
feeders.
2,000,000$ -$ -$ 12
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: Ten to twenty
rural FDRs
whose SAIFI
exceeds 10
-$ -$ -$ 20
50% funding annual spend
restricted to top
five worst
feeders
1,000,000$ -$ -$ 12
25% funding work plan
restricted to
enhanced
protection
500,000$ -$ -$ 0
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER 2414
Capital Cost O&M Cost Other Costs Approved
Previous 6,000,000$ 5,050,550$
2015 2,000,000$ -$ -$ 1,035,041$
2016 2,000,000$ 1,500,000$
2017 2,000,000$ 2,500,000$
2018 2,000,000$ -$ -$ 2,000,000$
2019 2,000,000$ -$ -$ 2,000,000$
Total 10,000,000$ -$ -$ 9,035,041$
Mandate Excerpt (if applicable):
Additional Justifications:
Engineering/Operations Life Cycle Programs
Underperforming Elec Ckts (Worst FDRs)
$2,000,000
Year Program Medium - >= 5% & <9% CIRR
Dave James Operations require execution to perform at current levels
Howell/H Rosentrater ERM Reduction >5 and <= 10
Program Moderate certainty around cost, schedule and resources
Any supplementary information that may be useful in describing in more detail the nature of the Program, the urgency, etc.
n/a Annual Cost Summary - Increase/(Decrease)
Initiating in 2009, ER 2414- "Worst Feeders" was proposed by Asset Management to improve the service
reliability of the Company's worst-performing electric distribution circuits. Many rural feeders significantly
exceed the Company SAIFI target of 2.1. This program is coordinated through divisional Area Engineers to
identify treatment of these feeders. Work plans may include, reconstruction, hardening, vegetation
management, conversion from OH to UG, enhanced protection, and relocation.
Annual Cost Summary - Increase/(Decrease)
Rural area reliability indices expected to worsen as infrastructure ages and
deteriotes. Expect customer contacts to local media and state government
and regulatory bodies.
Funding at $1,000,000 would restrict current treatment to top five worst
feeders.
Funding at 500,000 would restrict treatment to enhanced protection only
(adding midline reclosers, additional fusing)
Associated Ers (list all applicable):
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 85 of 88
Feeder Tie Circuits

Investment Name:
Requested Amount Assessments:
Duration/Timeframe on-going Financial:
Dept.., Area: Strategic:
Owner: Business Risk:
Sponsor: Program Risk:
Category:
Mandate/Reg. Reference: Assessment Score:33
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Electric Delivery
Capacity
4,000,000$ -$ -$ 4
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a -$ -$ -$ 16
Alternative 1: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 4
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name : Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
2015 3,735,000$ -$ -$ 3,573,505$ 2514 2515 2516
2016 3,810,000$ -$ -$ 3,810,000$
2017 4,175,000$ -$ -$ 4,175,000$
2018 3,900,000$ -$ -$ 3,900,000$
2019 4,000,000$ -$ -$ 4,000,000$
2020 4,000,000$ -$ -$ 4,000,000$
2021+4,000,000$ -$ -$ -$
Total 27,620,000$ -$ -$ 23,458,505$
ER 2016 2017 2018 2019 2020 Total
2514 2,000,000$ 2,000,000$ 2,000,000$ 2,000,000$ 2,000,000$ 10,000,000$
2515 1,000,000$ 1,000,000$ 1,000,000$ 1,000,000$ 1,000,000$ 5,000,000$
2516 810,000$ 1,175,000$ 900,000$ 1,000,000$ 1,000,000$ 4,885,000$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total 3,810,000$ 4,175,000$ 3,900,000$ 4,000,000$ 4,000,000$ 19,885,000$
Describe other options that were considered
Describe other options that were considered
Describe other options that were considered
David Howell Business Risk Reduction - None
0.00%
Mandate Excerpt (if applicable):
Avista Distribution Planning Criteria (500 Amp)
Additional Justifications:
This program is a foundational element of the Company's
overall effort to maintain the electric delivery system.
While many of the asset managmeent program such as
WPM, TCOP, Worst Feeders, and Grid Mod are targeted
efforts to maintain reliability, this program specifically
identifies thermal, voltage, and capacity 'tie' constraints.
The program represents the collective effort of distibution
planners and area engineers to manager our ability to serve
customer load, efficiently, and securely.
Associated Ers (list all applicable):
Distribution Engineering Life-cycle asset management
Segment Reconductor & FDR Tie Program
$4,000,000/year
Heather Rosentrater Low certainty around cost, schedule and resources
Program
n/a Annual Cost Summary - Increase/(Decrease)
The Company's Distribution Grid system includes 18,000 circuit miles of overhead and underground
primary conductors. As load and generation patterns shift, certain areas (segments) of the system become
thermally overloaded. These constrained portions of the system are identified through systematic
planning studies or from operational studyworks conducted by Area Engineers. In addition, FDR 'Tie'
switches are installed to allow load shifts between FDR circuits to balance loads and in response to either
maintenance or forced outages.
Annual Cost Summary - Increase/(Decrease)
Avista's Distribution System Planning criteria (e.g. 500 A Plan) mandates
performance levels for distribution circuits including capacity and voltage
requirements. This program is aimed at maintaining compliance with planning
criteria.
Year Program
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 86 of 88
Network

Investment Name:
Requested Amount Assessments:
Duration/Timeframe n/a Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:97
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Investments
necessary to
maintain
current
operations and
to extend the
life of current
assets.
2,300,000$ 348,251$ 215,000$ 6
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a -$ -$ -$ 25
Alternative 1: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 6
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name : Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER 2058 2237 2251
Capital Cost O&M Cost Other Costs Approved CapX Repl. Metro PILC Post St PILC
Previous 6,750,000$ 6,338,007$
2015 2,300,000$ 348,250$ 215,000$ 2,100,000$
2016 2,300,000$ 348,250$ 215,000$ 2,300,000$
2017 2,300,000$ 348,250$ 215,000$ 2,300,000$
2018 2,300,000$ 348,250$ 215,000$ 2,300,000$
2019 2,300,000$ 348,250$ 215,000$ 2,300,000$
2020 2,300,000$
Total 11,500,000$ 1,741,250$ 1,075,000$ 13,600,000$
CapX Specific O&M O&B
Mandate Excerpt (if applicable):
Additional Justifications:
Engineering Life Cycle Programs
Spokane Elec. Network
$2,300,000 annually
Year Program MH - >= 9% & <12% CIRR
John McClain Operations require execution to perform at current levels
Cox/H Rosentrater ERM Reduction >5 and <= 10
Program High certainty around cost, schedule and resources
Service to the core business district in Spokane is afforded a much higher level of service reliability than other urban or rural areas. This reflects the importance of continuous service to hospitals, law
enforcement, city government, banking, legal, commerce, and retail sectors of the local economy.
n/a Annual Cost Summary - Increase/(Decrease)
Avista owns and maintains an underground electric network that serves the core business, financial and
city government district of downtown Spokane from Division Street to Cedar and from Interstate 90 to the
Spokane River. It is operated as a networked secondary system. Most mid to large cities in the United
States operate similar electric grids. The system is configured to allow a single element forced outage
(transformer, cable segment) without impact to customers. Outages can and do occur but those
generally involve substation equipment failures or failures associated with work in progress. Like most
utilities that operate networked secondary systems, Avista uses dedicated cable crew resources
specifically trained to operate, construct, inspect and maintain these systems. All equipment and cables
are located beneath city streets and adjacent properties. Topology in the Network is unique to Avista
electric distribution and requires specialized material, equipment, tooling and training to perform
maintenance repair, planned replacement and capacity growth projects. The scope of annual capital
replacements and additions includes: 7500 feet of secondary cable, 7500 feet of primary cable, 10
refurbished manholes & vaults, 10 tranformer replacements, and 20 street light replacements.
Annual Cost Summary - Increase/(Decrease)
Unfunding Network operations assumes zero PM activities and an eventual
loss system functionality.
Describe other options that were considered
Describe other options that were considered
Describe other options that were considered
Associated Ers (list all applicable):
Various WUTC tariff schedules are associated with customer classifications in downtown Spokane. NESC/WAC govern public and worker safety.
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 87 of 88
Line Protection

Investment Name:
Requested Amount Assessments:
Duration/Timeframe On-going Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:93
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Investments
necessary to
maintain
current
operations and
to extend the
life of current
assets.
250,000$ 10,000$ 8
Alternatives: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Unfunded Program: n/a -$ -$ -$ 15
Alternative 1: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 8
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name : Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER
Capital Cost O&M Cost Other Costs Approved 2416 System Wide
2013 250,000$ 5,000$ -$ 250,000$
2014 250,000$ 10,000$ -$ 250,000$
2015 125,000$ 10,000$ -$ 125,000$
2016 125,000$ 10,000$ -$ 125,000$
2017 125,000$ 5,000$ -$ 125,000$
2018 -$ -$ -$ 125,000$
2019 -$ -$ -$ 125,000$
2020 125,000$
Total 875,000$ 40,000$ -$ 1,250,000$
Mandate Excerpt (if applicable):
Additional Justifications:
Describe other options that were considered
Describe other options that were considered
Associated Ers (list all applicable):
This program was funded for a 2-year period in the 2009-2010 timeframe. This request allows for completion of the Chance cutout replacements but also includes the installation of devices on unfused
laterals.
Avista's Electric Distribution system is configured into a trunk and lateral system. Lateral circuits are
protected via fuse-links and operate under fault conditions to isolate the lateral minimize the number of
affected customers. Engineering recommends treatment of the following: 1. Removal and replacement of
Chance Cutouts 2. Removal and replacement of Durabute cutouts 3. Installation of cut-outs on unfused
lateral circuits. This is a targeted program to ensure adequate protection of lateral circuits and to replace
known defective equipment. The Chance fuse cutout devices are porcelain cutouts prone to mechanical
failure at a much higher failure rate than peer group devices when manually operated by line craft
personnel during various line switching scenarios. This presents a significant hazard to line personnel as
Annual Cost Summary - Increase/(Decrease)
Describe other options that were considered
Dave James Operations require execution to perform at current levels
Cox/H. Rosentrater ERM Reduction >5 and <= 10
Program Moderate certainty around cost, schedule and resources
Engineering Life Cycle Programs
Distribution Line Protection
875,000 5-years
Year Program MH - >= 9% & <12% CIRR
n/a Annual Cost Summary - Increase/(Decrease)
Exhibit No. 7
Case No. AVU-E-16-03
H. Rosentrater, Avista
Schedule 4, Page 88 of 88