20150812AVU to Staff 49 Attachment A.pdf

2015
Rendall Farley, Beth Andrews
Asset Management
Avista Corp.

Electric Transmission System 2015 Asset Management Plan
Staff_PR_049 Attachment A Page 1 of 52

Prepared by: __________________________________________________
Rendall Farley, Asset Management Engineer

Reviewed by: __________________________________________________
Rodney Pickett, Asset Management Engineering Manager
__________________________________________________
Ken Sweigart, Transmission Engineering Manager

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

Front cover:
Steel Structures on the Burke – Pine Creek #4 115kV Line (October, 2013)
1939 Original Construction
2013 Major Rebuild

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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 ................................................................................................................................................. 19
Risk Prioritization .................................................................................................................................................. 19
Unplanned Spending ............................................................................................................................................. 23
Outages ................................................................................................................................................................. 25
Programs ............................................................................................................................................................... 29
1. Major Rebuilds ............................................................................................................................................. 29
2. Minor Rebuilds ............................................................................................................................................. 31
3. Air Switch Replacements .............................................................................................................................. 31
4. Structural Ground Inspections (Wood Pole Management) ......................................................................... 34
5. Structural Aerial Patrols ............................................................................................................................... 35
6. Vegetation Aerial Patrols and Follow-up Work ............................................................................................ 35
7. Fire Retardant Coatings ................................................................................................................................ 36
8. 230kV Foundation Grouting ......................................................................................................................... 36
9. Polymer Insulators........................................................................................................................................ 36
10. Conductor & Compression Sleeves ............................................................................................................ 37
Benchmarking ....................................................................................................................................................... 38
Data Integrity ........................................................................................................................................................ 40
Material Usage ...................................................................................................................................................... 42
Root Cause Analysis (RCA)..................................................................................................................................... 42
System Planning Projects ...................................................................................................................................... 43
Area Work Plans .................................................................................................................................................... 45
References ............................................................................................................................................................. 49
Appendix A –Transmission Probability, Consequence & Risk Index ..................................................................... 50
Appendix B – Transmission System Outage Data ................................................................................................. 52

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Figure 1: Example Transmission Asset Components and Expected Service Life .................................................. 10
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 ....................................................................... 17
Figure 5: Transmission outage causes affecting customers in 2014 .................................................................... 29
Figure 6: Air Switch Replacement Value vs. Remaining Service Life .................................................................... 32
Figure 7: 3-year Transmission Lines Replacement Capital Spending per Asset (First Quartile Consulting, 2008)
............................................................................................................................................................................... 38
Figure 8: Idaho Power Long-term Replacement Costs ......................................................................................... 39
Figure 9: Maintenance Benchmarking: Aerial Patrols (left) and Pole Inspections (right) .................................... 40

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, 2009-2014 ..................................................................................... 13
Table 7: Levelized Replacement Spending Options ............................................................................................. 16
Table 8: 2014 Transmission Spending .................................................................................................................. 17
Table 9: 2014 Planned Capital Projects (Non-Reimburseable) ............................................................................ 17
Table 10: 30-year Planned Capital and O&M Recommendations........................................................................ 18
Table 11: Probability Index Criteria and Weightings ............................................................................................ 20
Table 12: Consequence Index Criteria .................................................................................................................. 21
Table 13: Top 20 Most at Risk Circuits according to the Reliability Risk Index .................................................... 22
Table 14: Transmission Unplanned and Emergency Spending, 2006 - 2014 ....................................................... 24
Table 15: Transmission lines with the most unplanned outages in 2014 ............................................................ 26
Table 16: Transmission lines that caused the most customer hours lost in 2014 ............................................... 26
Table 17: Transmission Lines causing the most customer outages greater than 3 hours in 2014 ...................... 27
Table 18: Transmission Outage Causes, 2009-2014 ............................................................................................. 28
Table 19: Major Rebuild Projects, 2015 – 2018 ................................................................................................... 30
Table 20: Minor Rebuild and Switch Upgrade Budget, 2015 – 2018 ................................................................... 31
Table 21: Airswitch Priority List for Repairs and Replacements .......................................................................... 33
Table 22: Avista Transmission Lines Replacement Capital Spending per Asset ................................................... 38
Table 23: Transmission Asset Data Integrity ........................................................................................................ 41
Table 24: Relative Material Purchases, 10/2010 – 10/2012 ................................................................................ 42
Table 25: Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) ...................................... 43
Table 26: Corrective System Planning Projects (Palouse, Spokane and System) ................................................. 44
Table 27: Non-Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) .............................. 44
Table 28: Non-Corrective System Planning Projects (Palouse, Spokane and System) ......................................... 45
Table 29: Project Type Key ................................................................................................................................... 46

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Table 30: Area Work Plans – Major Projects ........................................................................................................ 46
Table 31: Area Work Plans – Major Projects (continued) .................................................................................... 47
Table 32: Minor Rebuilds ..................................................................................................................................... 48
Table 33: Ground Inspection Plan ........................................................................................................................ 48

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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, 2014.
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 for the transmission system showed a moderately worse result than targeted for
2014. Completed ground inspections were better than planned, and aerial inspections were on-track. Aging
115kV pole replacements were 51% below target, while aging 230kV pole replacements were 39% above
target. Customer outages were 50% higher than targeted, while emergency spending was 130% higher than
targeted. Finally, the follow-up repair backlog increased, ending the year with eight category 4 items overdue
and the oldest item in the backlog at 23 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 2015 and 2016 are relatively close to this recommendation. Additional

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mandated, growth and reimbursable capital projects, as well as O&M work puts the total planned budget for
Transmission Engineering at $29 million for 2015, 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 nearly doubled in 2014 to over $3 million, mostly as the result of a fire on
Lolo-Oxbow 230kV which cost $895k, and severe summer wind storms in Washington that raised overall
unplanned spending on the 115kV system by over $500k from last year.
Notable achievements in 2014 include:
1. Design and project management of an expanded number of mandated and system planning projects
including LiDAR mitigation, at $7.5 million in 2014 compared to $4.0 million in 2013.
2. Completion of technically difficult work on Burke – Pine Creek #4 115kV, and cost effective work on
Benton – Othello 115kV.
3. Approved 2015 budget closely matching the recommended replacement budget of $12 million for
115kV and $9 million for 230kV.
4. Effective transition of administrative maintenance work from departing staff, as well as hiring and
productive output of new engineering staff.
5. 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.
6. Confirmation of system pole data including material and location, allowing for detailed expected
service life information on each transmission line.
7. Development of relative probability, consequence, and risk indices for the system on a line-by line
basis. This included detailed acquisition of new power delivery and outage data on each line.
8. Completed simulation studies for Cabinet – Noxon 230kV, Benewah – Pine Creek 230kV, and Hot
Springs – Noxon #2 230kV circuits.
9. In cooperation with other utilities, initiated 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.

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1. Provide additional dedicated staff as appropriate, to handle long-term increased workloads in the
Transmission Engineering group and support processes. Provide a dedicated truck and ATV for
safe and effective fieldwork. Reduce end-to-end lead time from project initiation to project
closeout.
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.

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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.

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

Table 2: Component Assets and Quantities

Circuit Type Installation Removal Miles
Total Replacement
Cost
$1,140,319,249
Average Asset Lifecycle (Years)70
Annual Levelized Replacement Spending over Lifecycle $16,290,275
Average Replacement Cost/Mile
Asset Category 230kV 115kV Total
Expected
Service Life
(years)
Quantity

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Figure 1: Example Transmission Asset Components and Expected Service Life

Table 3: Transmission Structures and Poles

Insulators 60 years
Poles 55 years (Larch wood) 65 years (Cedar wood)150+ years (Steel)
Crossarm 45 years (Wood)150+ years (Steel)
Conductor 100+ years

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Table 4: 115kV vs 230kV Pole Materials
Key Performance Indicators (KPIs)
The table below shows overall KPI results for 2014, 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 much better than planned for structural ground inspections.
Aerial patrol inspections remained on-track overall. System-wide follow-up repairs from ground and
aerial patrol inspections were significantly worse 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, but more than
that required for 230kV, as roughly indicated by the number of older poles replaced.
Reliability performance was worse than planned and emergency spending significantly worse than the
target average of the past few years.
27%
46%
19%7%
230kV pole material
9%
83%
6%2%
115kV pole material
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

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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
Completed Structural Ground Inspections Projected Actual Normalized
# wood poles ground inspected 2,400 3,449 0.70
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 8 8.00
oldest item in backlog (# months since inspection)18 23 1.28
Aging Infrastructure Replacement Projected Actual Normalized
# 115kV wood poles older than 60 years replaced with steel 500 243 2.06
# 230kV wood poles older than 50 years replaced with steel 175 244 0.72
# air switches > 40 yrs old replaced 4 2 2.00
Reliability Performance Projected Actual Normalized
Extended Unplanned Outages due to Transmission (Customer-Hrs)133,142 200,972 1.51
# of Customers with Unplanned Transmission Outages > 3 Hrs 10,182 17,609 1.73
Emergency Spending Projected Actual Normalized
230kV Emergency Spending 204,022 965,270 4.73
115kV Emergency Spending 1,116,997 2,078,216 1.86
total Emergency Spending 1,321,019 3,043,486 2.30
Unity Box Metrics Weighting 2014 Result
Completed Structural Ground Inspections 20.00%0.70
Completed Structural Aerial Inspections 20.00%1.00
Followup Repair Backlog 15.00%4.52
Aging Infrastructure Replacement 15.00%1.45
Reliability Performance 15.00%1.66
Emergency Spending 15.00%2.30
Sum of Weight * Value 100.00%1.83
Results
1 = Planned/On-Track
<1 = Better than Planned
>1 = Worse than Planned

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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.
Additional performance measures are tabulated below since 2009:

Table 6: Additional Performance Measures, 2009-2014
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
Performance Measure Goal 2009 2010 2011 2012 2013 2014 Remarks

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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.
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.

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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

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replacement spending must be targeted at those assets that pose the greatest overall risk, as discussed
in the Risk Prioritization section of this report.

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
compares to $7.9 actual replacement spending in 2014. Significant effort is underway to ramp up
replacement construction in 2015 and sustain it over ensuing years. Other project categories include
growth, mandated, and reimburseable capital projects, operations and maintenance (O&M) programs,
and unplanned/emergency work. These figures are tabulated below for 2014. Spending associated with
liability claims and the underground network are not included, due to data uncertainty. Please note that
many construction projects involve a combination of replacement, growth, and mandated work,
therefore these figures are rough approximations. Historically, upwards of 90% of transmission
construction is through contractors.
Tx Capital
Assets Service
Life (yrs)
Levelized
Replacement Period
(yrs)115kV 230kV Total
Annual
Levelized
Replacement
Spending ($)
Cumulative Replacement Costs ($)

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Table 8: 2014 Transmission Spending

Table 9: 2014 Planned Capital Projects (Non-Reimburseable)

Figure 4: 2014 Planned Capital, O&M, and Emergency Spending
This shows that approximately 85% of spending was planned, vs. 15% unplanned in 2014. 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 $7.5 million
$7,877,719 Replacement
$7,499,457 Growth/Upgrade
$3,040,313 Unplanned/Emergency
$1,300,000 O&M - Veg Management
$455,000 O&M - Other
$150,000 Reimburseable work completed
$20,322,489 Total
$17,132,176 Total Planned non-reimburseable
$17,282,176 Total Planned Capital (including reimburseable)
$1,755,000 Total Planned O&M
$3,040,313 Total Unplanned/Emergency Capital
unknown Total Unplanned O&M
2014 Tx Project Spend Program/Project Description ER BI Type
$4,027,819 Asset Mgmt Trans Minor Rebuilds WA 2057 AMT12 Replacement
$2,542,534 Benton-Othello 115 Recond 2457 FT130 Growth/Upgrade
$2,239,224 Burke-Thompson A&B 115kV Transmission Rebuld 2550 CT101 Replacement$1,976,969 LiDAR Mitigation Projects, Med Priority 2560 CT203, variouGrowth/Upgrade$1,398,420 Devils Gap-Lind 115kV Transmission Rebuild Proj 2564 ST302 Replacement
$1,193,697 Benewah-Pine Creek 115kV - Low Priority Rtgs Mi2579 CT304 Growth/Upgrade
$687,777 Lewiston Mill Rd. 115 kV Substation Integration 1107 LT403 Growth/Upgrade
$392,534 Xsmn Asset Management 2423 AMT81 Growth/Upgrade
$252,634 Clearwater 115 kV Transmission Line Upgrade 2571 LT402 Growth/Upgrade
$210,211 Chelan-Stratford 115kV - Rbld Columbia River Xing2574 BT304 Growth/Upgrade
$163,495 Stratford Sub - 115kV Transm Integration 2563 BS302 Growth/Upgrade
$135,493 Asset Mgmt Transmission Switch Upgrade 2254 AMT10 Replacement
$76,152 Asset Mgmt Trans Minor Rebuilds ID 2057 AMT13 Replacement
$28,359 Greenacres 115 Sub New Cons:Transmission Integ2443 ST203 Growth/Upgrade
$26,767 Moscow 230 Sub Rebuild: Transmission Integration2484 PT002 Growth/Upgrade$11,464 Irvin 115kV Switching Stn: Transmission Integration2446 ST102 Growth/Upgrade$6,070 Benewah-Moscow 230kV - Structure Replacement2577 PT305 Growth/Upgrade
$5,480 Noxon 230 kV Stn Rebuild:Transmission Integratio2532 AT300 Growth/Upgrade
$1,467 Opportunity Sub 115kV Breaker Add - Tx Integratio2552 ST307 Growth/Upgrade
$611 Asset Mgmt Transmission Wood Sub Rebuild 2204 AMT08 Replacement
39%
38%
15%
9%

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resulted in 38% of total Transmission spending in 2014. 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.

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
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
2013 actual 2014 recommended 2014 actual 2015 recommended 2015 budget 2016-2020 recommended 2021-2045 recommended
30-year Transmission Planned Capital
and Maintenance Recommendations (2015 dollars)
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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 budget $18,111,134 $5,524,000 $1,870,600 $220,000 $1,514,000 $216,000 $100,000 $1,200,000 $200,000 $100,000 $19,845,134 $7,394,600 $1,816,000 $29,055,734
2016-2020 recommended $18,496,395 $3,000,000 $1,908,012 $264,000 $2,000,000 $216,000 $103,154 $1,200,000 $242,000 $100,000 $20,760,395 $4,908,012 $1,861,154 $27,529,561
2021-2045 recommended $18,496,395 $3,000,000 $1,946,172 $264,000 $2,000,000 $216,000 $103,154 $1,200,000 $242,000 $0 $20,760,395 $4,946,172 $1,761,154 $27,467,721
Capital
Replacement
Projects
Growth,
Mandated &
Reimburseable
Capital Projects

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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.
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 $29,055,734 with a dedicated staff of six members – one manager and
five engineers – equivalent to $4.8 million per staff member. This represents an output productivity
increase of 242% 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.
A strong case can be made for example, for a dedicated field truck and ATV for the group, to avoid the
use of personal vehicles on customer property and in dangerous, remote conditions that are routinely
visited on-site. This will help ensure safer operations in the field and effective use of valuable
engineering staff time.
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

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In mathematical form, this is expressed as:
Risk/Benefit = ∑𝑛𝑖=1 (Event Probability) 𝑖 * (Event Consequence) 𝑖
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
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
20 # of miles
15
environment (soil conditions,
weather intensity, vegetation,
relative probability of
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,

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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
future, improved data and analysis may allow consequences to be financially quantified, rather than
relative scoring methods.
% weight criteria
40 power delivery
20
15 access
15
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.

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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
communications, operations, and power supply. After factoring in these priorities, a comprehensive
2014 Transmission Probability, Consequence, and Risk Index Summary
Transmission Line Name
Voltage
(kV)
Length
(miles)Replacement Value
Probability
Index
Consequence
Index Risk Index Recent and Planned Work Description

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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

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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.

Table 14: Transmission Unplanned and Emergency Spending, 2006 - 2014
Total unplanned spending increased in 2014 to $3.04 million, significantly higher than in any year
recorded since 2006, and well above the target of $1.3 million per year. This was due to major fire
damage on Lolo-Oxbow 230kV, totaling $895k, and major storm responses in Washington on the 115kV
system.
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.
Electric Transmission 115kV and 230kV Total Unplanned Capital Spending
from XXX01050 account info
2006 2007 2008 2009 2010 2011 2012 2013 2014
115kV - WA $312,958 $609,438 $265,221 $874,996 $649,760 $585,250 $499,341 $1,123,122 $1,640,237
115kV - ID $406,111 $161,470 $221,343 $349,459 $626,503 $274,517 $608,163 $389,492 $437,978
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
230kV - WA $215,228 $97,946 $215,416 $57,721 $73,482 $156,491 $58,976 $89,984 $13,286
230kV - ID $74,783 $32,856 $120,056 $89,364 $79,950 $12,979 $228,681 -$134,091 $945,631
230kV - MT w/ Colstrip $0 $286,338 $257,879 $249,429 $368,855 $574,428 $298,059 $436,991 $0
230kV - MT w/o Colstrip $0 $1,590 $59,590 $27,525 $13,275 $0 $72 $18,910 $0
230kV - OR $12,273 $0 $0 $2,475 $0 $360 $14,738 $9,435 $3,181230kV - all w/o Colstrip $302,285 $132,392 $395,062 $177,085 $166,706 $169,830 $302,467 $118,329 $962,097
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

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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
2014 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 492 transmission line outages recorded in 2014, 180 of which were
planned, 159 that were trip and recloses that lasted less than a minute, and 153 unplanned outages over
one minute. Of these outages, only 51 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):

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Line Name # Outages
1. Devils Gap-Stratford 115 kV 22
2. Coulee-Westside 230 kV 12
3. Devils Gap-Lind 115 kV 12
4. Benewah-Pine Creek 115 kV 10
5. Burke-Thompson Falls A 115 kV 10
6. Latah-Moscow 230 115 kV 10
7. Moscow 230-Orofino 115 kV 9
8. Sunset-Westside 115 kV 9
9. Lind-Shawnee 115 kV 8
10. Shawnee-Sunset 115 kV 8
Table 15: Transmission lines with the most unplanned outages in 2014
Based on the Reliability Report, over 200,000 hours of unplanned customer outages were recorded in
2014. The transmission lines with the most unplanned customer-hours outage are as follows:
Line Name Customer Hours
1. Mead Tap 115 kV 33823
2. Addy-Devils Gap 115 kV 33448
3. Bronx-Cabinet 115 kV 28352
4. Colbert Tap 115 kV 16192
5. Shawnee-Terre View 115 kV 13487
6. Benton-Othello Sw Sta 115 kV 10965
7. Benewah-Pine Creek 115 kV 10267
8. Devils Gap-Stratford 115 kV 7553
9. Post Falls-Ramsey 115 kV 6401
10. Devils Gap-Lind 115 kV 3155
Table 16: Transmission lines that caused the most customer hours lost in 2014
Over 17,000 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:
Line Name # Customers experiencing Outages >3 hrs
1. Colbert Tap 115 kV 4093
2. Addy-Devils Gap 115 kV 3206
3. Benton-Othello Sw Sta 115 kV 2556
4. Mead Tap 115 kV 2324

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5. Shawnee-Terre View 115 kV 2270
6. Bronx-Cabinet 115 kV 1585
7. Devils Gap-Stratford 115 kV 1150
8. Cabinet-Rathdrum 230 kV 402
9. Hot Springs-Noxon #1 230 kV 21
10. Benewah-Pine Creek 115 kV 2
Table 17: Transmission Lines causing the most customer outages greater than 3 hours in 2014
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. Benewah-Pine Creek 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. Benton-Othello Sw Sta 115 kV
4. Bronx-Cabinet 115 kV
5. Cabinet-Rathdrum 230 kV
6. Addy-Devils Gap 115 kV
Based on this information, closer monitoring for these lines is warranted. Benton-Othello 115kV is in
the process of a major rebuild/reconductor that will be completed in 2017. Bronx-Cabinet 115kV is in
the middle of a 5-year rebuild scheduled to be completed in 2017. Devils Gap-Stratford 115kV is
scheduled for a minor rebuild in 2016 and should be considered for full rebuild. A rebuild/reconductor
is planned for 2017-2018 on Addy - Devils Gap 115kV. A thorough rebuild analysis was completed for

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Benewah-Pine Creek 230kV lines, recommending a $27 million full rebuild of structures, no reconductor
in 2018-2020. Cabinet – Rathdrum 230kV is a steel line in excellent condition, however trees that fell on
the line on two separate occasions in December caused over 12 hours of outage time on the line with
over 3 hours outage to 402 customers.
The outage causes for the last six years are summarized in the table below. In 2014 there were 172
feeder outages, but only 51 unique transmission events that caused those outages. Data for 2009
through 2013 previously analyzed indicated individual feeder outages stemming from a transmission
outage (in many cases the same transmission outage caused more than one feeder outage), while the
2014 data was analyzed to indicate only the number of unique transmission outages for each subreason.
For this reason the available data from 2009 to 2013 is not directly comparable to what is presented for
2014 at the current time.

Table 18: Transmission Outage Causes, 2009-2014
Weather related outages continue to dominate both in terms of number of occurrences and customer-
hour outages. At over 60,000 hours, wind had the highest number of customer-hour outages. This
Reason Subreason 2014
Animal Bird
Animal Animal - Other
Animal Squirrel
Company Company - Other 2
Equipment OH Conductor - Pri 1
Equipment OH Connector - Pri
Equipment OH Crossarm - Rotten 1
Equipment OH Insulator 1
Equipment OH Cutout/Fuse
Equipment OH Switch/Disconnect 4
Equipment Sub Highside Breaker 1
Equipment Sub Relay Misoperation
Equipment Sub Transformer 2
Equipment Equipment - Other 2
Miscellaneous See Remarks
Planned Planned - Forced Outage 1
Planned Planned - Maint/Upgrade 5
Pole Fire Pole Fire 1
Public Car Hit Pole 1
Public Public - Tree
Public Public - Other 3
Tree Fell Tree Fell
Undetermined Undetermined 12
Weather Weather - Lightning 3
Weather Weather - Snow/Ice 8
Weather Weather - Tree
Weather Weather - Wind 3
Grand Total 51

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number is slightly higher than last year (55,000 customer-hours) and is mostly due to two back-to-back
storms that hit in late July and early August. These wind storms not only caused the most customer
outages for the year, but also caused widespread damage to the system, particularly in northern
Spokane and Sandpoint where the storms hit the hardest.
The nine largest outage events for the year include three due to weather, one due to pole fires, three
due to equipment failures, one because a car hit a pole, and one resulting from planned maintenance &
upgrades. The pole fire event caused 29,000 hours in customer outages, but it was the only pole fire
incident of the year to affect customers. The Milan Tap, Colbert Tap, and Mead Tap which tap off of
BPA’s Addy-Bell #1 115 KV line, all sustained long outages due to this single pole fire incident. Another
notable outage due to pole fires occurred on the Lolo-Oxbow 230 KV line. While this occurrence did not
leave any customers without power, it did burn about 20 poles, resulting in a line outage lasting 24 days.
Despite these two incidents, the lack of other pole fires in 2014 is a positive indicator of the system-wide
fire protective coating program.

Figure 5: Transmission outage causes affecting customers in 2014
Programs
1. Major Rebuilds
Out of the $15,527,176 million in planned capital replacement projects in 2014, $3,637,644 was spent
on major rebuilds, $4,103,971 on minor rebuilds and $135,493 on switch replacements, for a total of
$7,877,108. 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

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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 2017 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 2018 and 2019 in particular are only partially complete.

Table 19: Major Rebuild Projects, 2015 – 2018
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
Description BI Description 2015 2016 2017 2018 2019
Pine Creek-Burke-Thompson Falls CT101 Rebuild Transmission $0 $0 $3,500,000 $0 $0
9CE-Sunset 115kV Transmission ST503 Reconductor/Rebuild $25,000 $900,000 $0 $0 $0
Garden Springs - Silver Lake 115kV ST304

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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.
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.

Table 20: Minor Rebuild and Switch Upgrade Budget, 2015 – 2018
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
Description BI Description 2015 2016 2017 2018 2019
Transmission Minor Rebuilds AMT12 Xsmn Minor Rebuild - WA $750,000 $775,000 $775,000 $800,000 $825,000
Transmission Minor Rebuilds AMT13 Xsmn Minor Rebuild - ID $739,455 $772,262 $780,249 $813,420 $848,117
Sys - Trans Air Switch Upgrade AMT10 Asset Man Trans Switch Upgrade $220,000 $225,000 $225,000 $230,000 $230,000
sum $1,709,455 $1,772,262 $1,780,249 $1,843,420 $1,903,117

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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.
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 $220,000 annual
budget and recent spending in 2013 - 2014 of $151,556 and $135,493, respectively. 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.

Figure 6: Air Switch Replacement Value vs. Remaining Service Life

Re
p
l
a
c
e
m
e
n
t

V
a
l
u
e
Age (Years)
Transmission 115 kV Air Switches
40 Years Expected Service Life
$750,000 ofCapital Assets
Beyond
Expected
Service Life

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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.

Table 21: Airswitch 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
SW #Problems Age (yrs)LINE/SUBSTATION
A-70 Problem Switch 84 Chelan-Stratford
A-336 Old KPF, Needs Replaced 49 Grangeville-Nez Perce #1: Cottonwood Tap
A-355 Old KPF on a broken pole 48 Jaype-Orofino
A-346 Wood in Switching Mech. Is bowed 47 Grangeville-Nez Perce #2
A-376 Old KPF, Needs Replaced 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 Broken Whip 26 Dworshak-Orofino
A-377 Scott paper tap; Engerized to Switch 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 Motor Operator is too slow - it arcs 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 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 47 Moscow 230-Orofino
A-58 46 Chelan-Stratford
A-295 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

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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.
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
2400 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 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
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).

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5. Structural Aerial Patrols
The Avista transmission system covers a large geographical area that has all types of terrain. Some parts
of the system are so remote and difficult to access that they only get inspected from the ground when
company personnel are in the area due to a failure or a major reconstruction project. 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
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.

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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 34% complete. Given the
fire event of last year, the Lolo-Oxbow 230kV line is planned for early recoating in 2015 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 4,390 poles remain to be coated in the 115kV system. Following the
current plan to coat 714 poles in 2015 (179 115 kV poles and 535 230 kV poles repainting the Lolo –
Oxbow line), it 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 dramatically decreased, however
monitoring and adjustment of this program remains a necessity.
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 $250k out of $500k of foundation grouting work on
Cabinet – Rathdrum 230kV was completed through 2014. Another $83k/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.

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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 occurances
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.
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, and the location
and age of thousands of compression sleeves 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 sleeves, 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
sleeves on 230kV AAC lines, following several years of one to two failures per year. Since then, no
known in-line compression sleeve failures have occurred. However, at some point we should expect
failures to resurface. Until that time, an effort to determine sleeve locations and confirmation of
reliable reporting of conductor and sleeve failures system-wide is advisable. Proactive reinforcement of
sleeves may also be justified, pending more detailed study. See Whicker (2009) for more details on the
230kV in-line sleeve mitigation project.
In December of 2014, two separate incidents of dead-end compression sleeve failures occurred on the
Noxon – Pine Creek 230kV line. Preliminary analysis indicates these failures were probably the result of
poor installation workmanship, where the internal inhibitor material was removed to allow for easier
installation. The lack of inhibitor thus fails to seal the sleeve, allowing water to intrude and corrode the
conductor, leading to early failure of steel and aluminum strands. A thorough investigation and is in
progress to determine appropriate remedial actions.

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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 7: 3-year Transmission Lines Replacement Capital Spending per Asset
(First Quartile Consulting, 2008)
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.

Table 22: Avista Transmission Lines Replacement Capital Spending per Asset
This shows that Avista’s capital replacement spending over the last two years is significantly lower than
the study’s average, close to the lowest of the seven reported utilities. Comparably, the recommended
0.87%2013 replacement spending capital per asset
$7,877,719 2014 planned replacement spending
2014 unplanned/emergency replacement spending
$7,877,719 2014 total replacement capital spending
$1,140,319,249 Transmission asset replacement value
0.69%2014 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

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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.
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 8: 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.

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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.

Figure 9: 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.
Avista
Avista

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Table 23: 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
Status Data Source Notes/Comments

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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 24: 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
deliberations. A summary report was generated and a number of significant action items initiated to
prevent or mitigate similar events in the future.
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%

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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, 2014). 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.

Table 25: Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston)

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Table 26: Corrective System Planning Projects (Palouse, Spokane and System)

Table 27: Non-Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston)

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Table 28: 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.
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).

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Table 29: Project Type Key

Table 30: Area Work Plans – Major Projects

EFA = Reimburseable or Growth
HPRM = High Priority Line Ratings Mitigation Program Business Case
IAA = Other
LPRM = Low Priority Line Ratings Mitigation Program Business Case
MPRM = Medium Priority Line Ratings Mitigation Program Business Case
NG = New Growth
NT = New Transmission Program Business Case
PS = Project Specific 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
TAM = Transmission Asset Management Program Business Case
TRR = Transmission Rebuild/Reconductor Program Business Case
Business
Case Area ER Description 2015 2016 2017 2018 2019
MPRM Big Bend Devils Gap-Stratford Line Mitigation X
PS Big Bend Harrington 115-4kV - Integration X
LPRM Big Bend Othello-Warden #1/#2 Line Mitigation X
SDSR Big Bend Little Falls 115kV Sub - Integration X X X
NT Big Bend Coulee - Westside 230 - Construct - acquire Right-of-Way
SDSR Big Bend Ford 115-13kV Sub - Integration X X
TRR Big Bend Devils Gap-Lind 115kV Rebuild X X
TRR Big Bend Ben-Oth SS 115 - ReCond/ReBld X X
TRR Big Bend Addy-Devils Gap 115kV - Reconductor/Rebuild near Ford Sub X X
TRR Big Bend Chelan-Stratford 115kV - Rebuild Columbia River Crossing
SNDS Big Bend Bruce Siding 115 Sub - New - Tap to Sub
SNDS Big Bend 49 Deg North 115-21 Feeder - Integration
MPRM CDA Noxon-Hot Springs #2 Line Mitigation X
PS CDA Noxon 230kV SS - Rebuild - Integration X X X X X
SDSR CDA Bronx 115-21 Sub - Construct - Integration
NT CDA Carlin Bay 115-13 Sub - New - Integration
PS CDA Cabinet Gorge 230kV Switchyard - Integration
TRR CDA BRX-CAB & BRX-SCR Rebuild X X X X X
TRR CDA Pine Creek-Burke-Thompson Falls - Rebuild X
TRR CDA CDA-Pine Creek 115kV Rebuild X X X
TRR CDA Cabinet-Noxon 230kV - Reconductor/Rebuild X X
TRR CDA Benewah-Pine Creek 230kV - Reconductor/Rebuild
BLKT CDA Government Way Road Widening (CDA) - Reimbursable X
BLKT CDA 15th Street Road Widening (CDA) - Reimbursable

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Table 31: Area Work Plans – Major Projects (continued)

Business
Case Area ER Description 2015 2016 2017 2018 2019
LPRM Lewis-Clark Moscow-Orofino (Julietta-Orofino) 115 Mitigation X
SNDS Lewis-Clark Wheatland 115 Sub - Construct - Tap to Sub
SDSR Lewis-Clark Grangeville 115-13-34.5kV - Integration
NT Lewis-Clark Hatwai-Lolo #2 230kV - New Transmission X X X
TRR Lewis-Clark Lolo-Oxbow 230kV - Reconductor/Rebuild
NT Lewis-Clark Hatwai- Lolo 230 Casino X
SNDS Palouse Tamarack 115 Sub - Construct - Integration X X
SDSR Palouse N. Moscow Add Transformer - Integration X X
SDSR Palouse N. Moscow Add Transformer - Upgrade X
SNDS Palouse Bovill 115kV Substation - New - Integration
TRR Palouse Benewah-Moscow 230kV - Reconductor/Rebuild X X X
SVTR Spokane Irvin SS 115 - Construct - Integration X X
SDSR Spokane 9CE 115 Sub - Rebuild/Expand X
SVTR Spokane Opportunity Sub 115-13kV - Integration X
SNDS Spokane Greenacres 115 Sub - Construct - Integration X
TRR Spokane Garden Springs - Sunset - West Plains Trans Reinforcement X X
SVTR Spokane BEA-BLD #2 115 - Upgrd 140MVA X X
Spokane Hawthorne 115 Sub - Construct - Integration
SDSR Spokane Beacon 230 - 2 X 2 -Integration
SDSR Spokane Sunset 115kV Sub - Rebuild - Integration X X
SNDS Spokane Downtown East 115 Sub- New - Tap to Sub
SNDS Spokane Downtown West 115 Sub- New - Tap to Sub X X
SNDS Spokane Hillyard 115-13 Sub - Construct - Integration
PS Spokane Westside 230kV Sub - Rebuild - Integration
PS Spokane Garden Springs 230-115-13 Sub - Integration X X X
SDSR Spokane Northwest 115-13kV Sub - Integration X X
SDSR Spokane Chester 115-13kV Sub - Integration X X
SDSR Spokane Metro 115-13kV Sub - Integration X X
TRR Spokane BEA-BEL-F&C-WAI 115kV - Reconfiguration X X
PS Spokane Beacon 230kV Sub - 115kV Rebuild - Integration
PS Spokane 9CE Sub - New 230kV Transformation - New Transmission & Integration
NT Spokane Westside/Garden Springs 230/115 - New Transmission
TRR Spokane Garden Springs - Silver Lake 115kV - Recon/Rebld H&W to S Fairchild Tap X X
TRR Spokane 9CE-Sunset 115kV Transmission - Reconductor/Rebuild X X
BLKT Spokane MLK New Road Relocation - Reimbursable X
TAM All Sys - Trans Air Switch Upgrade X X X X X
TAM All Trans Air Switch Platform Grd Mat
SDSR All Sys - Wood Sub Rebuilds X X X X X
LPRM All LP Line Ratings Mitigation Project X X
MPRM All MP Line Ratings Mitigation Project X
TRR All High Resistance Conductor Replace X
TAM All Transmission Minor Rebuilds - WA X X X X X
TAM All Transmission Minor Rebuilds - ID X X X X X

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Table 32: Minor Rebuilds

Table 33: Ground Inspection Plan

Big Bend Addy Devils Gap 115 kV
Big Bend Devils Gap-Stratford 115 kV
Big Bend Othello-Warden #1 115 kV
Big Bend Othello-Warden #2 115 kV
CDA Burke-Pine Creek #3 115 kV
CDA Cabinet-Noxon 230 kV
CDA Hot Springs-Noxon #2 230 kV
CDA St Maries Tap 115 kV
CDA/Spokane Benewah-Boulder 230 kV
Lewis-Clark Dry Creek-Lolo 230 kV
Lewis-Clark Dry Creek-Pound Lane 115 kV
Lewis-Clark Jaype-Orofino 115 kV
Lewis-Clark Moscow-Orofino 115 kV
Palouse Moscow-South Pullman 115 kV
Spokane Beacon-Ross Park 115 kV
Lewis-Clark Lolo-Oxbow 230 kV 657
Lewis-Clark Dry Creek-N Lewiston 230 kV 13
Big Bend Devils Gap-Stratford*115 kV 582
Big Bend Addy-Gifford 115 kV 271
Palouse Latah-Moscow 115 kV 706
Spokane Boulder-Rathdrum 115 kV 241
Spokane Beacon-Boulder #2 115 kV 146
2616 Year 2015 Total
*Odessa to Stratford only
Spokane Boulder- Otis Orchards #1 115 kV 55
Spokane Post Falls-Ramsey 115 kV 161
Lewis-Clark Jaype-Orofino 115 kV 540
Big Bend Chelan-Stratford 115 kV 1197
Lewis-Clark Clearwater-North Lewiston 115 kV 50
Palouse Shawnee-South Pullman 115 kV 191
Spokane Francis & Cedar-Ross Park 115 kV 85
Spokane Airway Heights-Sunset 115 kV 129
Spokane College & Walnut-Post Street 115 kV 3
2411 Year 2016 Total
Spokane College & Walnut-Westside 115 kV 135
Spokane Francis & Cedar-Northwest 115 kV 52
Spokane Nineth & Central-Sunset 115 kV 184
Spokane Beacon-Bell #1 115 kV 158
Big Bend Lind-Warden 115 kV 498
Big Bend Lind-Washtucna 115 kV 362
CDA Bronx-Cabinet 115 kV 319
Lewis-Clark Lolo-Nez Perce 115 kV 692
2400 Year 2017 Total
Spokane Metro-Sunset 115 kV 53
Spokane Beacon-Ninth & Central 115 kV 70
Lewis-Clark Lolo-Pound Lane 115 kV 242
Spokane Boulder-Otis Orchards #2 115 kV 55
Lewis-Clark Hatwai-Lolo 230 kV 146
Palouse Moscow-Terre View 115 kV TBD
Palouse Shawnee-Terre View 115 kV TBD
Big Bend Devils Gap-Stratford*115 kV 621
TBD TBD 115 kV TBD
TBD Year 2018 Total
*partial inspection Odessa to Stratford only

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References
Avista (2015). Transmission Vegetation Management Program.
Avista (2014). 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 2014.
First Quartile Consulting (2008). Hydro One Update of Transmission Benchmark Study.
September 19, 2008
Ken Sweigart (2014). 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 2014.

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Appendix A –Transmission Probability, Consequence & Risk Index

Transmission Line Name
Voltage
(kV)Tap Name
Length
(miles)Replacement Value
Probability
Index
Consequence
Index Risk Index Recent and Planned Work Description

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Transmission Line Name
Voltage
(kV)Tap Name
Length
(miles)Replacement Value
Probability
Index
Consequence
Index Risk Index

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Appendix B – Transmission System Outage Data

Transmission Line Name
Voltage
(kV)
# Line
Outages
#Planned
Outages
#Unplanned
Outages Transmission Line Name
Voltage
(kV)
# Line
Outages
#Planned
Outages
#Unplanned
Outages

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