20170609Rosentrater Exhibit 8.pdf

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

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-17-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-17-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 8
AND NATURAL GAS CUSTOMERS IN THE )
STATE OF IDAHO ) HEATHER L. ROSENTRATER
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

Electric kwh
Schedule No. of Customers (000s) % of Total kwh
Residential Schedule 1 104,843 1,098,331 38%
General Schedules 11 & 12 21,012 357,654 12%
Large General Schedules 21 & 22 1,139 657,407 23%
Extra Large General Schedules 25 & 25P 11 729,402 25%
Pumping Schedules 30, 31 & 32 1,406 60,737 2%
Street & Area Lights Schedules 41-49 149 13,345 0%
128,560 2,916,876 100%
Natural Gas Therms
Schedule No. of Customers (000s) % of Total Therms
General Service Schedule 101 78,604 50,611 40%
Large General Service Schedules 111 & 112 1,421 21,041 17%
Interruptible Service Schedules 131 & 132 - - 0%
Transportation Service & Other 8 55,784 44%
80,033 127,436 100%
Total Electric & Gas Customers 208,593
* Average Customers and Billed Usage
Customer Usage
State of Washington - Electric & Gas
As of December 31, 2016*
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01
H. Rosentrater, Avista
Schedule 1, Page 1 of 1

2016
Amber Fowler, Rodney Pickett ,
Dave James, Ross Taylor, and
Mareval Ortiz-Camacho
Avista Corp
Electric Distribution System
2016 Asset Management Plan
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 1 of 88
Prepared by: _________________________________________________________
Amber Fowler, Asset Management Engineer
Reviewed by: _________________________________________________________
Rodney Pickett, Asset Management Engineering Manager
_________________________________________________________
Dave James, Distribution Engineering Manager
_________________________________________________________
Glenn Madden, Asset Maintenance Manager
Approved by: _________________________________________________________
Scott Waples, Director of Planning and Asset Management
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 2 of 88
Table of Contents
Purpose ......................................................................................................................................................... 7
Executive Summary ....................................................................................................................................... 7
Data Sources ............................................................................................................................................... 10
Standard Calculations ................................................................................................................................. 11
Review of OMT Data and Trends ................................................................................................................ 11
OMT Events per Year .............................................................................................................................. 11
SAIFI Trends by OMT Sub-Reasons ......................................................................................................... 17
OMT Sub-Reason Events High Limit ........................................................................................................ 19
System ......................................................................................................................................................... 25
Major Changes ........................................................................................................................................ 25
Specific Distribution Programs and Assets ................................................................................................. 25
Distribution Wood Pole Management (WPM)........................................................................................ 25
Selected KPIs and Metrics ................................................................................................................... 26
WPM Metric Performance .................................................................................................................. 30
WPM Model Performance .................................................................................................................. 32
WPM Summary ................................................................................................................................... 32
Wildlife Guards ....................................................................................................................................... 37
Selected KPIs and Metrics ................................................................................................................... 37
WILDLIFE GUARDS KPI Performance ................................................................................................... 38
WILDLIFE GUARDS Metric Performance ............................................................................................. 39
WILDLIFE GUARDS Model Performance ............................................................................................. 39
WILDLIFE GUARDS Summary .............................................................................................................. 39
URD Primary Cable .................................................................................................................................. 42
Selected KPIs and Metrics ................................................................................................................... 42
URD PRIMARY CABLE KPI Performance .............................................................................................. 43
URD PRIMARY CABLE Metric Performance ......................................................................................... 44
URD PRIMARY CABLE Model Performance ......................................................................................... 44
URD PRIMARY CABLE Summary .......................................................................................................... 44
Distribution Transformers ....................................................................................................................... 45
Selected Metrics ................................................................................................................................. 45
Metric Performance ............................................................................................................................ 46
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 3 of 88
Summary ............................................................................................................................................. 46
Area and Street Lights ............................................................................................................................. 46
Selected Metrics ................................................................................................................................. 46
Summary ............................................................................................................................................. 46
Distribution Vegetation Management (VM) ........................................................................................... 47
Selected KPIs and Metrics ................................................................................................................... 47
VM KPI Performance ........................................................................................................................... 48
VM Metric Performance ..................................................................................................................... 50
VM Model Performance...................................................................................................................... 51
VM Summary....................................................................................................................................... 51
Distribution Grid Modernization Program .............................................................................................. 52
Selected Metrics ................................................................................................................................. 52
Metric Performance ............................................................................................................................ 56
Summary ............................................................................................................................................. 57
Worst Feeders ......................................................................................................................................... 57
Feeder Tie Circuits................................................................................................................................... 59
ARD12F2-ORN12F1 Tie Circuit ............................................................................................................ 59
DAV12F2-RDN12F1 Tie Circuit ............................................................................................................ 60
Summary ............................................................................................................................................. 60
Spokane Electric Network ....................................................................................................................... 61
Equipment Types and Aging ............................................................................................................... 61
KPI and Metrics ................................................................................................................................... 61
Capital Budgets and Spending - Overview .......................................................................................... 61
New Services – Expenses .................................................................................................................... 61
Replacement of old PILC primary cable– Expenses ............................................................................ 61
Replacement of old PILC and RINC secondary cable– Expenses ......................................................... 64
Purchase of new and replacement of aging transformers and network protectors– Expenses ........ 64
Repair/refurbishment/replacement of vaults/manholes/handholes– Expenses ............................... 65
Non-routine Projects Being Carried Out on Specific CARs– Expenses ................................................ 67
Network Communications Stage 1– Expenses .................................................................................... 67
Monroe and Lincoln St Repaving– Expenses ...................................................................................... 67
Distribution Line Protection .................................................................................................................... 68
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 4 of 88
Assets Not Specifically Covered Under a Program ................................................................................. 68
Conclusion ........................................................................................................................................... 68
Distribution Vegetation Management .................................................................................................... 70
Distribution Wood Pole Management .................................................................................................... 75
Grid Modernization ................................................................................................................................. 77
Transformer Change-Out Program ......................................................................................................... 79
Business Cases ........................................................................................................................................ 80

Figure 1, OMT Annual Number of Events and AM Related Event Trends and Trend Lines ........................ 16
Figure 2, OMT Events with and without Planned Maintenance or Upgrades ............................................ 17
Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits ............................................................ 20
Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time .................................................... 21
Figure 5, 2015 OMT SAIFI Contribution by Sub-Reason ............................................................................. 22
Figure 6, 2015 OMT Sustained Outage Comparisons ................................................................................. 23
Figure 7, Customers Affected Per Event Exceeding Risk Action Levels ...................................................... 24
Figure 8, WPM OMT Event Trends .............................................................................................................. 33
Figure 9, WPM Contribution to Annual SAIFI value by Sub-Reason and Year ............................................ 34
Figure 10, Wood Pole Used by Summarized Activity .................................................................................. 35
Figure 11, Distribution Wood Pole Age Profile ........................................................................................... 36
Figure 12, Wildlife Guards Installed by Year and Expenditure Request ..................................................... 40
Figure 13, Wildlife Guards Usage by MAC for 2011-2015 .......................................................................... 41
Figure 14, URD Primary Cable OMT Events by Year ................................................................................... 44
Figure 15, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons............ 49
Figure 16, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell
Sub-Reasons ................................................................................................................................................ 50
Figure 17, OMT Sustained Outages related to Grid Modernization ................................................... 55
Figure 18, Wood Pole Management and Grid Modernization Before and After ........................................ 56
Figure 19, ARD12F2 to ORN12F1 Tie .......................................................................................................... 59
Figure 20, DAV12F2 - RDN12F1 Tie ............................................................................................................. 60
Figure 21, A faulted PILC cable ................................................................................................................... 62
Figure 22, A second faulted PILC cable ....................................................................................................... 63
Figure 23, A network transformer after a failure in the primary compartment ........................................ 65
Figure 24, Interior of a badly deteriorated old manhole in a heavily traveled street ................................ 66
Figure 25, Duct bank damage entering an old deteriorated manhole ....................................................... 66
Figure 26, Complete replacement of a badly deteriorated manhole ......................................................... 67
Table 1, OMT Events by Sub-Reason and Year ........................................................................................... 11
Table 2, OMT Outages and Partial Outages by Sub-Reason and Year ........................................................ 13
Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2009-2015 data ........................ 14
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2009-2015 data ................... 15
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 5 of 88
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage ................................................................ 18
Table 6, OMT Sub-Reasons Exceeding Annual High Limit ........................................................................... 19
Table 7, WPM KPI Goals by Year ................................................................................................................. 26
Table 8, WPM Metric Goals by Year ........................................................................................................... 29
Table 9, Wildlife KPI Goals for 2010 - 2015 ................................................................................................. 38
Table 10, Wildlife Metric Goals for 2010 - 2015 ......................................................................................... 38
Table 11, Worst Feeders for Squirrel related Events for 2015 ................................................................... 39
Table 12, URD Cable - Pri KPI Goals ............................................................................................................ 43
Table 13, URD Cable - Pri Metric Goals ....................................................................................................... 43
Table 14, TCOP Metrics ............................................................................................................................... 45
Table 15, Vegetation Management Metric Goals ....................................................................................... 48
Table 16, VM KPI Performance ................................................................................................................... 48
Table 17, Tree-Weather OMT Events Metric for Vegetation Management ............................................... 51
Table 18, VM Cost per Mile and All Vegetation Management Work Metric .............................................. 51
Table 19, Grid Modernization Program Objectives .................................................................................... 52
Table 20, Energy Savings based on Integrated Resource Plan ................................................................... 53
Table 21, OMT Sub-Reasons impacted by Grid Modernization .................................................................. 54
Table 22, Metric Performance for Grid Modernization Program ............................................................... 57
Table 23 Worst Feeder SAIFI 3 Year Average .............................................................................................. 58
Table 24 Worst Feeder Projects and Costs ................................................................................................. 58
Table 25, Assets Not Specifically Covered Under a Program ...................................................................... 68

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 6 of 88
Purpose
This report documents the asset plans for Electrical Distribution System for Avista. The plans discussed
here represent what we believe to be the best approach to managing Avista’s Distribution assets and
provides the Key Performance Indicators (KPIs) and metrics Asset Management (AM) to support the
plans and demonstrate the effectiveness of those plans implemented. The report also helps identify
areas for improvement or opportunities to improve the value we receive from our assets.
Some of the metrics provide a basis for comparing how an asset performed with a program and how it
would have performed without a program. The difference in performance provides an estimate of the
cost saving of the program. The estimated savings is only a snapshot in time and may not represent the
exact savings; it provides a relative comparison and supporting justification for AM decisions made in
the past. Other KPIs and metrics provide indications of how well an asset is performing and helps
determine when further work is required. KPIs and metrics tracking also help evaluate the accuracy of
different AM models and determine when or if a model should be revised.
Executive Summary
The primary message of this asset management plan is that the programs in place have been positively
impacting the number of outages and decreasing the cost to mitigate these failures. Continuous
improvement upon these programs is necessary to maintain reliability and efficiency. Assets are aging
faster than our current programs and plans can alleviate. However, programs are continually being
analyzed and updated to continue to improve our overall management of the distribution assets.
If available, each of the below summaries include a ranking criteria table. This table includes the
Customer IRR from the business case, the Benefit to Cost Ratio from our IRR calculation analysis and the
Risk Reduction Ratio from the supporting business case.
Current Programs:
1. Grid Modernization – includes replacing poles, transformers (Pad Mount, Overhead & Submersible),
cross arms, arresters, air switches, grounds, cutouts, riser wire, insulators, conduit and conductors in
order to address concerns related to age, capacity, high electrical resistance, strength, and
mechanical ability. The program also includes the addition of wildlife guards, smart grid devices and
switched capacitor banks, balancing feeders, removing unauthorized attachments, replacing open
wire secondary, and reconfigurations. Although this is a new program it does appear to be reducing
outages for the feeders worked on. The program has slowly shifted from “Feeder Upgrade” to this
new larger scoped Grid Modernization program. With only a few years of data since completion of
the earliest feeders, this program needs time to mature, so the full value of the program can be
realized.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 7 of 88
2. Transformer Change-Out Program – has run smoothly for the past few years with the targets and
KPIs being met regularly. This program was largely implemented to reduce the environmental
concern of Polychlorinated biphenyls (PCBs) in some Pre-81 transformers. The environmental risks
have been heavily decreased, with a focus in areas that have a greater potential to impact our
waterways. Since these are also old and inefficient transformers, our efficiency has increased.
However, this program is about to switch over to the second phase. With this switchover the
program will “piggy back” on Wood Pole Management for a complete cycle to finish removing the
non-PCB Pre-81 transformers from our system. The effectiveness and efficiency of this second
phase is yet to be determined.

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

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

5. Wood Pole Management – inspects and maintains the existing distribution wood poles on a 20 year
cycle. In addition to inspecting the poles, we inspect distribution transformers, cutouts, insulators,
wildlife guards, lightning arresters, crossarms, pole guying, and pole grounds. The inspection of
these other components on a pole drives additional action to replace bad or failed equipment along
with replacing known problematic components. Overall, WPM has been effective at maintaining the
current level of reliability to our customers, however, we will need to complete work on more
feeder miles to control the impact on future reliability.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 8 of 88
6. Area and Street Light – replaces non-decorative high pressure sodium and mercury vapor lights with
equivalent LED lights. The initial year of the program changed out 100W and 200W HPS and MV
non-decorative street lights in Washington only. The scope was changed and going forward all
wattage types of non-decorative lights for both area and street lights will be replaced in both
Washington and Idaho. The first year of the program finished on budget with more lights completed
than anticipated. The scope change and potential budget cuts may push this 5 year program out,
however, the impressive first year gives hope that with an intact budget the program may complete
closer to the 5 year cycle than not.

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

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

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

10. Protection – Avista's Electric Distribution system is configured into a trunk and lateral
system. Lateral circuits are protected via fuse-links and operate under fault conditions to isolate the
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 9 of 88
lateral in order to minimize the number of affected customers in an outage. Engineering
recommends installation of cut-outs on un-fused lateral circuits and the replacement of obsolete
fuse equipment (e.g. Chance, Durabute/V-shaped, Open Fuse Link/Grasshopper, Q-Q, Load
Break/Elephant Ear, and Porcelain Box Cutouts). As part of the program, sizing of fuses will be
reviewed to assure protection of facilities, as well as coordination with upstream/downstream
protective devices. This program began as an obsolete replacement program but has grown to
incorporate un-fused and wrong fused laterals. Cutout outages have decreased through this
program but with the added scope a new metric will need to be made. This is a targeted program to
ensure adequate protection of lateral circuits and to replace known defective equipment.

*Original scope

To date the programs developed have made a huge impact in the number of outages on the distribution
system. The cyclic programs need to continue to be analyzed and updated to maintain the improved
reliability, reduced risk and decreased O&M costs. Since the assets continue to age faster than the
current programs can mitigate, new programs or scope changes will be required going forward to
continue to provide our customers with safe and reliable service.
Data Sources
Much of the information used in this report’s metrics comes from three sources: Annual Sustained and
Momentary outage data; Outage Management Tool (OMT) events; and Oracle (financial and supply
chain database). The annual Sustained and Momentary outage data is generated by the Distribution
Dispatch Engineer each month in a spreadsheet. The Sustained and Momentary outage data for years
2001 – 2007 was modified by AM to align the reasons and sub-reasons to coincide with the current
descriptions. While the Sustained and Momentary outage data comes from OMT data and is a subset of
OMT data, this data has been scrubbed by the Distribution Dispatch Engineer to improve its accuracy.
The OMT tracks outages and customer reports of problems on the Distribution system, Substations, and
Transmission events that cause outages on the Distribution system. This data includes sustained
outages, momentary outages, and events without outages. Events that only cause a partial outage or no
outage at all do not show up in the Sustained and Momentary outage data, because the data does not
fit the definition of a sustained outage or a momentary outage. However, the OMT data is sometimes
subject to reporting an event more than once. The Distribution Dispatch Engineer reviews the data and
strives to prevent duplication by rolling events up and editing the data. However, some duplication still
occurs. OMT data is used to calculate number of outages, number of OMT events (outages, partial
outages, and non-outage events), outage duration, number of customers impacted, response times,
System Average Interruption Frequency Index (SAIFI) impacts, and System Average Interruption
Duration Index (SAIDI) impacts.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 10 of 88
Discoverer provides financial, customer information, and material usage information from our
warehouse and financial systems. Spending and material can be tracked to the ER and BI level for
capital work and the Master Activity Code (MAC) and Task for Operations and Maintenance (O&M)
work.
Standard Calculations
See reference the “2010 General Metrics Data Collection and Analysis for System Reviews” for the
details and examples of how different measures and metrics are calculated.
Review of OMT Data and Trends
Examining the data in OMT reveals a lot of information which helps Avista understand the condition of
our assets and shows some trends we can address. Below, we will examine various trends within OMT
Events per Year, SAIFI trends by OMT Sub-Reasons, and other measures.
OMT Events per Year
Table 1 shows the past seven years of data out of OMT by Sub-Reason and allows trend analysis. OMT
Events represents cost and action for Avista, so it was selected as a basis for much of our trending.
However, OMT Outage data (shown in Table 2) can have a different trend than OMT Events. Since the
SAIFI analysis already includes outage data, AM selected to trend OMT Events and SAIFI contribution.
Based on Table 1, we identified the top 10 increasing and decreasing trends in OMT Sub-Reasons. The
Top 10 increasing trends in the number of OMT events by year is shown in Table 3 and the Top 10
decreasing trends in the number of OMT events by year is shown in Table 4.

Table 1, OMT Events by Sub-Reason and Year
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
Arrester 19 32 30 36 24 32 20
Bird 218 179 332 231 270 248 227
Capacitor 4 2 0 4 4 3 0
Car Hit Pad 139 105 98 105 117 104 88
Car Hit Pole 217 298 339 355 369 378 307
Conductor - Pri 42 64 81 110 142 135 83
Conductor - Sec 286 273 310 286 331 323 299
Connector - Pri 111 101 100 79 85 85 51
Connector - Sec 429 410 408 390 336 321 283
Crossarm-rotten 23 25 28 19 18 26 23
Customer Equipment 1626 1458 1384 1434 1368 1328 1200
Cutout/Fuse 197 217 176 209 171 196 109
Dig In 164 149 123 109 103 104 96
Elbow 7 5 8 2 10 6 5
Fire 157 203 234 230 282 200 206
Forced 51 63 67 33 63 68 29
Foreign Utility 724 894 720 734 720 602 765
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 11 of 88
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
Insulator 32 49 36 32 47 34 37
Insulator Pin 28 24 30 25 23 16 19
Junctions 2 2 1 4 6 7 2
Lightning 598 163 179 635 453 297 200
Maint/Upgrade 539 1571 3334 2589 1840 1880 1566
Other 394 414 426 483 472 467 344
Pole Fire 116 102 117 113 152 134 153
Pole-rotten 44 37 35 52 34 55 43
Primary Splice 0 1 1 0 0 0 0
Protected 18 10 4 5 5 3 4
Recloser 4 11 3 2 3 11 2
Regulator 14 20 17 13 17 18 13
SEE REMARKS 821 892 543 487 463 508 518
Service 123 188 197 230 191 124 172
Snow/Ice 988 565 167 352 122 243 1882
Squirrel 700 390 395 358 215 279 272
Switch/Disconnect 9 3 0 3 6 16 8
Termination 7 7 9 12 21 19 8
Transformer - OH 158 128 156 167 132 133 84
Transformer UG 57 53 51 50 71 60 62
Tree 55 53 51 56 46 60 47
Tree Fell 390 506 392 377 298 393 340
Tree Growth 375 330 335 335 349 400 280
Underground 0 3 1 3 2 2 0
Undetermined 1145 948 861 783 765 723 728
URD Cable - Pri 136 93 95 72 93 88 64
URD Cable - Sec 212 190 248 219 208 188 153
Weather 357 895 325 314 216 166 208
Wildlife Guard 3 0 1 2 0 0 0
Wind 294 1309 256 1042 1126 3238 6465

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 12 of 88
Table 2, OMT Outages and Partial Outages by Sub-Reason and Year
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 13 of 88
OMT SUB-REASON 2009 2010 2011 2012 2013 2014 2015
URD Cable - Sec 201 175 227 202 190 173 145
Weather 273 620 178 170 137 101 122
Wildlife Guard 3 0 0 2 0 0 0
Wind 229 982 195 802 840 2345 5721

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

Table 3 shows that the largest upward trend changed this year to Wind. This change was due to the
large wind storm that impacted our service territory in November. Snow/Ice is also very high on the list
and is mostly due to the snow storm in December. Without these major events then Maintenance and
Upgrade would continue to be the largest trend upward. We have implemented many programs that
increase our outages due to maintenance but decrease the number of outages due to failures. Bird has
always been on this list but has slowly dropped to the number 10 spot with a much smaller trend
upward suggesting the increase in wildlife guard installation has had a positive impact. Car Hit Pole
remains pretty steady trending upward and will continue to be monitored. Both Primary and
Secondary Conductor are both increasing at a steady pace and may need to be reevaluated. Primary
Conductor is only addressed with our Grid Modernization and Segment Reconductor and Feeder Tie
program. Fire has consistently been on the top 10 list but is a customer issue and not an Avista issue so
this is not something Avista can mitigate. Foreign Utility is also a non Avista issue and does not need to
be addressed within this document.
Table 4 shows the Top 10 OMT Sub-Reasons with a downward trend. The largest downward trend is in
Undetermined. This Sub-Reason, as well as SEE REMARKS, have been trending downwards for a few
years and is believed to be due to an increased focus on the importance of accurate and standardized
outage data. Squirrel events continue to decline, as well. This is probably largely due to adding Wildlife
Guards (WLG) on new installs and adding them to existing transformers as part of Wood Pole
Management and Grid Modernization. The URD cable Replacement program for the first generation of
unjacketed cable has paid great dividends when compared to where it could have been without taking
action at reducing URD Cable – Pri events. Reduction in lighting strikes may simply be due to nature,
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 14 of 88
however, the Wood Pole Management (WPM), Grid Modernization and Transformer Change-out
Program (TCOP) may also be helping to mitigate this issue by adding lightning arrestors to new install
transformers. The decrease in Cutout/Fuse Sub-Reasons can likely be attributed to Wood Pole
Management, TCOP and Grid Modernization programs along with some contribution from other
programs. The remaining Sub Reasons in the table have trend downward but the changes are not
material at this point in time or are outside of Asset Management’s control.
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2009-2015 data
Top Ten Downward Trends
OMT Sub-Reason Slope Change per Year
Undetermined -61
Squirrel -60
Weather -55
Customer Equipment -37
SEE REMARKS -36
Lightning -23
Connector - Sec -11
Cutout/Fuse -9
URD Cable - Pri -8
Connector - Pri -8

The overall trends in OMT Events are shown in Figure 1 along with the trends in AM related OMT Events
(see Appendix A of the “2010 Asset Management Electrical Distribution Program Review and Metrics”
and the table titled “List of AM Related OMT Sub-Reasons” to see which OMT Sub-Reasons are
considered AM Related). Based on Figure 1, Avista sees the trend in the number of events decreasing
over the past 5 years.
AM related OMT events are actually decreasing at a rate around 4%. Since the regional growth rates are
less than 2%, the decrease is most probably due to the increase in maintenance in the system and
replacement of aged infrastructure.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 15 of 88

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

y = 623.11x -1E+06
y = -109.11x + 222428
0
2,000
4,000
6,000
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2009 2010 2011 2012 2013 2014 2015 2016
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Total Number of OMT Events by Year AM Related Total
Linear (Total Number of OMT Events by Year)Linear (AM Related Total)
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 16 of 88

Figure 2, OMT Events with and without Planned Maintenance or Upgrades
SAIFI Trends by OMT Sub-Reasons
Examining how SAIFI changes each year is shown in Table 5. SAIFI values in Table 5 represent the annual
value each event contributes to the overall SAIFI number. For example, in 2011, the average Arrester
event in OMT added 0.003380523 to the overall SAIFI number for the year. While the number of
electrical customers does typically grow each year, the main driver for changes in the average SAIFI
number per event comes from the average numbers of customers affected by the event. Continuing our
example with Arresters, in 2010 Avista had 356,777 electrical customers and the average Arrester
outage event affected 102 customers, so the average SAIFI impact per event was 0.009230266. In 2011,
our electrical customer count increased to 358,443 and the average number of customers affected by an
Arrester related outage dropped to 40, and the average SAIFI impact due to Arrester events dropped to
0.003380523. The result for SAIFI was an increase in the average impact to SAIFI in 2010 compared to
2011.
While most Sub-Reasons in OMT have fluctuating value around an average value over the past five
years, some Sub-Reasons have demonstrated a definite trend upward as shown in Figure 4. Figure 4
shows the top 10 Sub-Reasons based on the percentage change in 2015. Some of the Sub-Reasons in
Figure 4 do not have a significant impact on the SAIFI number, however, the trend for all of these Sub-
0
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2009 2010 2011 2012 2013 2014 2015 2016
Ev
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Total Outage Management Tool Events vs Year
OMT Events w/o Maint/Upgrades OMT Events w/ Maint/Upgrade
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 17 of 88
Reasons are the top increasing SAIFI trends over 5 years which could eventually move them into the top
SAIFI contributors over time.
Figure 5 and Figure 6 illustrate the makeup of the overall SAIFI value and overall OMT Sustained
Outages. Figure 5 and Figure 6 show a different result because the number of customers impacted by
each Sub-Reason is different. For example, we have very few Pole Fire caused outages, but they affect a
large number of customers. So, Pole Fire shows a significant impact to SAIFI in Figure 5 but is
insignificant on Figure 6.
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage

Average SAIFI by Sub-Reason Event
OMT Sub-Reason 2010 2011 2012 2013 2014 2015
0.009230266 0.003380523 0.015245676 0.003562297 0.009598559 0.001364179
0.026835343 0.050143556 0.015659978 0.064285794 0.021842454 0.026664936
0.002842798 0 0.006147101 8.27074E-06 0 0
0.001972404 0.00315424 0.004171572 0.004940524 0.003134 0.0051936
0.055741604 0.034563763 0.078829605 0.061689509 0.07509589 0.042359382
0.013459389 0.025213018 0.024181701 0.036457655 0.029884932 0.020986851
0.001923463 0.001952154 0.003857768 0.002491023 0.003821952 0.004026636
0.029390854 0.022841718 0.023941651 0.01912657 0.023079128 0.00541549
0.001764569 0.001927718 0.002095065 0.001612901 0.001526051 0.002468959
0.010791352 0.017452881 0.004106797 0.001059746 0.015222287 0.000560328
8.43629E-05 4.18879E-05 0 4.96037E-05 0 3.39306E-05
0.029472485 0.014918168 0.027484801 0.01707108 0.018776702 0.009920028
0.002911047 0.007751271 0.001543001 0.001766282 0.006145152 0.001637209
9.54113E-05 0.000737521 2.50685E-05 0.001158911 0.000444984 0.000469738
0.000916016 0.001765849 0.004579849 0.012299424 0.001239404 0.007950852
0.026724006 0.011341762 0.01007956 0.035479695 0.010119982 0.019996134
0.06415389 1.9551E-05 1.10385E-05 3.04099E-05 0 0.006688417
0.00947135 0.00767475 0.001619894 0.018937297 0.020106196 0.011789959
0.00609977 0.012718209 0.002646432 0.004556295 0.008017909 0.001082908
5.63488E-06 0 0.002791077 0.000475014 0.000657922 0
0.05153771 0.029986357 0.107700751 0.152792603 0.10038083 0.050646543
0.115272977 0.131045664 0.093958391 0.118799625 0.097069382 0.104791239
0.177318475 0.156583826 0.114257941 0.085502603 0.082302999 0.115450196
0.108242728 0.087722138 0.058825288 0.078650039 0.096520659 0.160560667
0.002027401 0.002475849 0.001111378 0.002186058 0.007843191 0.000477747
1.40872E-05 0.000227493 0 0 0 0
0.005438117 0.000105902 0.000523814 0.000524546 0.000303026 0.00239954
0.002520587 0.000212125 8.36386E-06 0.001310323 0.01501481 0.001838003
0.019517299 0.003012273 0.020486437 0.010292094 0.015208638 0.011244625
0.0263254 0.022946333 0.024001629 0.035782952 0.030523744 0.024167276
0.001512913 0.001254413 0.001425234 0.001116933 0.00158065 0.001204447
0.091003627 0.039682871 0.109703932 0.035007006 0.078612086 0.304018091
0.021425719 0.039013725 0.050207568 0.026293232 0.039139515 0.030862207
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 18 of 88
OMT Sub-Reason 2010 2011 2012 2013 2014 2015
Switch/Disconnect 0.004582077 0 4.14971E-05 0.020930465 0.036865454 0.008279847
Termination 0.000152009 0.000173439 0.000637191 0.003063515 0.002290441 0.001269524
Transformer - OH 0.002407314 0.017106495 0.004874802 0.004093373 0.026346897 0.008655826
Transformer UG 0.001704189 0.001165537 0.001438726 0.006231495 0.009683188 0.001587665
Tree 0.013288743 0.000938339 0.011356792 0.002750215 0.015326026 0.002845582
Tree Fell 0.092136448 0.062998204 0.067319172 0.054556299 0.057820669 0.084106127
Tree Growth 0.007012046 0.003838547 0.005569335 0.005691876 0.009617668 0.003505633
Underground 2.81744E-06 2.80426E-06 3.87453E-05 5.48895E-06 5.45993E-06 0
Undetermined 0.110134471 0.234672203 0.177748096 0.157264023 0.14781125 0.119112398
URD Cable - Pri 0.005903606 0.008770789 0.002422167 0.006080464 0.005855776 0.0069458
URD Cable - Sec 0.000953008 0.001467391 0.001544569 0.001409578 0.000980058 0.001315704
Weather 0.195547002 0.051231256 0.053674679 0.033680951 0.041372627 0.025389892
Wildlife Guard 0 0 8.35232E-06 0 0 0
Wind 0.291134088 0.089836161 0.195492335 0.209669949 0.517115518 1.128419475
OMT Sub-Reason Events High Limit
The second metric used to determine if we must examine a problem is the deviation from the
established mean discussed above for each OMT Sub-Reason. If the number of OMT events for a specific
Sub-Reason exceeds the OMT Sub-Reason Events High Limit (High Limit) AM may need to conduct an
investigation and try to explain why the annual values are exceeding the limit (see Appendix D of the
“2010 Asset Management Electrical Distribution Program Review and Metrics”). The High Limit is based
on the average of annual values for each Sub-Reason plus two standard deviations. This method is also
used to calculate the quarterly High Limit as well. The data for the average is the OMT Data for 2005
through 2009. For 2015, the following OMT Sub-Reasons exceeded their High Limit are shown in Table
6. We anticipated that Avista would exceed these limits due to natural deviations for events outside our
control and due to some cyclical nature we observe in our data. Our goal here is to help identify trends
in time to potentially address them if possible.
Table 6, OMT Sub-Reasons Exceeding Annual High Limit
OMT Sub-Reasons Exceeding their associated OMT High Limit Number of Years High Limit Exceeded
Car Hit Pole 6
Conductor – Pri 5
Wind 3

Based on Table 6, presently there are no issues requiring changes to our current plans. We will
continue to monitor Conductor – Pri, as this may call for some kind of action in the future. Car Hit Pole
is being analyzed by another group. If a program is implemented from this analysis then we should see
that issue drop off the High Limit Exceeded chart. Wind has popped up on this chart due to a couple of
fourth quarter large storms the past couple of years. We will continue to monitor all of these issues.
Figure 3 shows the quarterly trends that feed into the annual trends for the OMT High Limit. For all
OMT Sub-Reasons since 2006, only five Sub-Reasons have had more than five quarters where they
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 19 of 88
exceeded the High Limit, Car Hit Pole with 17 quarters above the limit, Conductor – Pri with 8 quarters
above the limit, Fire with 6 quarters above the limit and Service with 9 quarters above the limit. This
information is consistent with Table 6 above. We will continue to monitor Service for potential future
action, but it currently does not warrant a maintenance or replacement strategy.

Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits
y = 0.0659x + 1.3231
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Individual Sub-Reasons Exceeding Average Levels
by 2 Standard Deviations per Quarter
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 20 of 88

Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time
0%
5%
10%
15%
20%
25%
30%
Top 10 OMT Sub-Reasons in growing Unreliability
by SAIFI
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 21 of 88

Figure 5, 2015 OMT SAIFI Contribution by Sub-Reason
Wind
48%
Snow/Ice
13%
Pole Fire
7%
Undetermined
5%
Other
5%
Maint/Upgrade
4%
Tree Fell
4%
Lightning
2%
Car Hit Pole
2%
Squirrel
1%
Bird
1%
Weather
1%
SEE REMARKS
1%Conductor -Pri
1%Forced
1%
Everything
Else
5%
2015 SAIFI Contribution by OMT Sub-Reason
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 22 of 88

Figure 6, 2015 OMT Sustained Outage Comparisons
Wind
39%
Snow/Ice
11%
Maint/Upgrade
9%
Customer Equipment
7%
Foreign Utility
5%
Undetermined
4%
SEE REMARKS
3%
Other
2%
Tree Fell
2%
Car Hit Pole
2%
Conductor -Sec
2%
Connector -Sec
2%
Tree Growth
2%
Squirrel
2%
Bird
1%Weather
1%
Fire
1%
Lightning
1%
Service
1%Pole Fire
1%URD Cable -Sec
1%
Sustained Events by OMT Subreason
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 23 of 88

Figure 7, Customers Affected Per Event Exceeding Risk Action Levels
0
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350
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500
2011 2012 2013 2014 2015
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Annual RAL curves
Pole Fire Wind Wind Risk Action Level Pole Fire Risk Action Level
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 24 of 88
System
The distribution system has an equipment average life of 55 years with the replacement value of a little
over $2 billion dollars. For Avista to maintain the system at its current level, just under $37 million a
year would need to be spent on replacing aging infrastructure. The overall capital spending for the
distribution was just over $85.5 million (this includes the large storm and growth). The total capital
spending on just replacement work (with the large storm) was just over $83.5 million. Our replacement
work, without the storm, still exceed our levelized spending required to keep the system at its current
state. Avista also spent around $14 million in O&M on the distribution system.
Network
The downtown network has an equipment average life of 50 years with the replacement value of a little
over $93.7 million. For Avista to maintain the system at its current level, just under $1.9 million a year
would need to be spent on replacing aging infrastructure. The overall capital spending for the network
was $2.7 million (this includes growth). The total capital spending on just replacement work was $1.3
million. Our replacement work last year did not meet our levelized spending required to keep the
system at its current state.
Major Changes
The distribution system is a fairly constant system. Most programs are in place to maintain or improve
infrastructure for current customers or build new to support new customers. Currently there is a
program set to be completed next year that will change out the last area that Avista serves at the legacy
4kV voltage. This voltage is obsolete for serving utility distributions systems and we have very limited
spare equipment to continue service at this voltage. This is a needed upgrade to our standard
distribution class voltage and equipment that was delayed in 2014 due to resources, and was pushed
into 2015 and 2016. This is also the first year that Avista has installed LED street lights. This marks the
beginning of a complete system conversion from the more inefficient high pressure sodium and legacy
mercury vapor lighting to LED lights for both Area and Street Lighting.
Specific Distribution Programs and Assets
In the following sections, AM reviews the different programs and work done to determine an AM action
plan for particular assets. Some plans indicated the current case or no action was the best approach and
others indicated there was an appropriate action for managing an asset. If a plan was implemented,
then the available information will be reviewed to determine how the plan has impacted the system.
Distribution Wood Pole Management (WPM)
The current WPM program inspects and maintains the existing distribution wood poles on a 20 year
cycle. Avista has 7,702 overhead circuit miles. The average age of a wood pole is 28 years with a
standard deviation of 21 years. Nearly 20% of all poles are over 50 years old and we have an estimated
240,000 Distribution poles in the system. This means that about 48,000 poles are currently over 50
years old. Our inspection cycle allows us to reach approximately 12,000 poles each year. Along with
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 25 of 88
inspecting the poles, we inspect distribution transformers, cutouts, insulators, wildlife guards, lightning
arresters, crossarms, pole guying, and pole grounds. The inspection of these other components on a
pole drives additional action to replace bad or failed equipment along with replacing known problematic
components. These additional inspection items have expanded the current program beyond the original
scope, but have proven to be a cost effective way of addressing more than just wood pole issues. The
2016 budget is set to be cut for this program and many others. The goals of this program would be to
remain on the same 20 year cycle. The inspections would remain identical to the current scope,
however, the follow-up work done through the WPM program would be a subset of the items above.
WPM would no longer replace arresters, cutouts, wildlife guards or do any guying repairs, this work
would be left up to the offices to complete at within their work plan.
Selected KPIs and Metrics
AM selected the number of OMT Events by Year related to WPM work and feeder miles of follow-up
work completed verses miles of feeders inspected as KPIs to monitor WPM. These KPI relate to
reliability performance, cost performance, and customer impacts. Our goal is to maintain or reduce the
number of OMT events related to WPM. The current plan optimized the inspection cycle based on cost,
so the impacts to reliability were addressed only as they relate to costs. The goal for these KPI is to stay
below the number of events averaged over 2005 – 2009 for WPM Related OMT Events. See Table 7 for
the goal and for the actual value for 2015. The OMT Events KPI is a lagging KPI and an indication of how
well past work has impacted outages. The feeder miles of follow-up work completed verses miles of
feeders inspected KPI is a leading indicator and reflects how outages in the future will be impacted by
the work. The number of miles inspected is shown in Table 7 for the goal and actual values.
The feeder miles of follow-up work completed verses miles of feeders inspected KPI comes from the
annual Distribution WPM inspection plan and is the sum of all miles of the feeders completed in that
year. The completed number of miles for follow-up work on feeders comes from Asset Maintenance
based on their tracking of the work as it is completed. The purpose of this metric is to evaluate how
much backlog work is created each year in order to adjust future year’s budgets. Asset Management
has been working to increase the budget each year, with the goal of having no back log, by budgeting
enough to inspect and follow up on a 20 year cycle.
Table 7, WPM KPI Goals by Year
KPI
Description
WPM Goal Related
number of OMT Events
Actual WPM
Related number
of OMT Events
Projected Miles
Follow-up
Work**
Actual Miles
Follow-up Work
Completed
2009 1460 1320 500 372
2010 1460 1004 450 435
2011 1460 1004 459 333
2012 1460 1013 416 435
2013 1460 816 445 329
2014 1460 905 412 385
2015 1460 760 390 364
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 26 of 88
*Note: Beginning with 2012, the Actual Miles Follow-up Work Completed will include WPM and
Distribution Grid Modernization miles.
**To maintain a 20 year cycle the program only needs to complete 390 miles per year. The program is a
little behind the targeted average of about 380 miles per year.
Metrics provide a more detailed review of WPM. WPM metrics involve more information and
calculations than the KPIs and include: WPM contribution to the annual SAIFI number; number of
distribution wood poles inspected; material usage for WPM by Electric Distribution Minor Blanket and
Storms; number of Pole-Rotten OMT Events; Crossarms-Rotten OMT Events; and actual material use
verses model predicted material use for WPM follow-up work (see
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 27 of 88
Table 8). The WPM contribution to the annual SAIFI number metric comes from data pulled out of OMT
by Cognos and calculates the average impact to SAIFI per event by Sub-Reason.
The average impact to SAIFI per WPM event is the sum of the average impact to SAIFI for Arresters,
Cutouts/Fuses, Crossarms, Insulators, Insulator Pins, Pole Fires, Poles – Rotten, Squirrels, Transformers-
OH, and Wildlife Guards. The average impact to SAIFI for WPM events is then multiplied by the number
of event causing an outage or partial outage (this is the sum of OMT events causing an outage or partial
outage for Arresters, Cutouts/Fuses, Crossarms, Insulators, Insulator Pins, Pole Fires, Poles – Rotten,
Squirrels, Transformers-OH, and Wildlife Guards). The goal for this metric is the five year average for
2005-2009. The purpose of this metric is to ensure WPM maintains the current reliability. Although the
last two year’s SAIFI goals were exceeded it was due in part to a couple large outages. Last year a
couple of squirrel instances happened during Hot Line Holds causing a feeder lockout to occur. This year
Pole Fire caused the biggest issue. There was a single event that required an entire feeder be taken off
line to allow a cutout to be opened safely. This one occurrence impacted nearly 3000 customers.
Removing these exceptions from the SAIFI drops the overall WPM SAIFI to an acceptable level.
The number of Distribution System poles inspected metric measures the annual plan for inspecting
wood poles against how much work was actually completed. The AM plan calls for a 20 year inspection
cycle which was originally estimated to be ~12,000 poles per year. The AM plan also represents
inspecting 17.5 feeders a year. This metric ensures the WPM program meets the AM plan for
Distribution Wood Poles.
The final metric, material use verses model predicted material use, tracks the actual number of key
stock numbers (see Figure 12for assets monitored) against what the AM model predicted. Discoverer is
used to pull stock number usage out for the applicable stock numbers and then they are compared to
the AM model predictions. The purpose of this metric is to measure the performance of the model to
predict the future outcomes.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 28 of 88
Table 8, WPM Metric Goals by Year
*The SAIFI number without the exceptions is within the bounds of the projected SAIFI
Figure 8 shows the trends in OMT events for the Sub-Reasons associated with WPM and generally the
trend in OMT events is downward. The major contributors (Cutouts/Fuses, Squirrel, and Transformer –
OH) all showed a level trend or a general trend downward over the past 5 years. Pole Fire had a slight
increase this year but we had a dry hot summer which could account for some of the increase. Overall,
WPM is controlling the number of OMT events. The leading indicator, Miles Follow-up Work Completed,
shows we were falling behind in addressing issues identified during the inspection. If this backlog
continues to grow, it will begin to impact the number of OMT events into the future. Funding limitations
are preventing us from clearing out the backlog. We continue to strive to get funding for the back log.
The KPI “Actual Miles Follow-up Work Completed” provides an indication of what could happen to the
other metrics (see Table 7). Simply inspecting the poles does not improve the systems performance.
The follow-up work to the inspection needs to be completed. This metric shows follow-up work carrying
over into 2016. The driver for WPM is a 20 year inspection cycle and if allowed to fall behind, the WPM
follow-up work could become a major financial issue and reliability risk for future years
Grid Modernization, discussed later in this document, also impacts some of the same metrics as WPM
(see Table 22 for the actual comparisons). In 2012, we revised the metrics and now include the miles of
Projected
Metric
Description
Projected WPM
Contribution To The
Annual SAIFI
Number
Projected
Number of
Dist Poles
Inspected
Model Predicted
Material Use for
WPM Follow-up
Work
Projected
Number of
Pole Rotten
OMT Events
Projected
Number of
Crossarm OMT
Events
2009 0.214024996 12,600 4,792 137 32
2010 0.208489356 12,600 4,932 137 32
2011 0.211022023 12,600 5,010 137 32
2012 0.211022023 12,600 6,770 137 32
2013 0.211022023 12,600 8,592 137 32
2014 0.211022023 12,600 10,566 137 32
2015 0.211022023 12,600 12,606 137 32
Actual
Metric
Description
Actual WPM
Contribution To The
Annual SAIFI
Number
Actual
Number of
Dist Poles
Inspected
Actual Material
Use for WPM
Follow-up Work
Actual
Number of
Pole Rotten
OMT Events
Actual Number
of Crossarm
OMT Events
2009 0.1863468 13,161 7,538 44 25
2010 0.19916836 15,553 7,904 37 23
2011 0.202462739 13,324 28,011 35 28
2012 0.16613099 17,318 28,120 52 19
2013 0.15640942 14,364 15,214 34 18
2014 0.241571914* 11,879 14,901 55 26
2015 0.225273848* 8,157 12,072 43 23
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 29 of 88
completed Grid Modernization work in the Table 7 since the work is coordinated with WPM and
intended to help address the backlog in WPM.
WPM Metric Performance
The annual contribution to SAIFI showed a slight incline in 2015 but the overall trend continues to show
improvement and, if the exceptions are removed from this year’s SAIFI then it remains below the five
year average value as shown in
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 30 of 88
Table 8 and Figure 9. Overall, WPM has been effective at maintaining the current level of reliability to
our customers.
The number of Distribution poles inspected measures how well the program is performing against a 20
year inspection cycle. The goal is to inspect every feeder once every 20 years. The work to perform the
wood pole inspections is tracked based on the number of poles inspected. Using miles works, but
different feeders have different pole densities per mile and the way the contractor bills for the
inspection work makes using the number of poles inspected easier. WPM did not hit the planned
number of inspections shown in
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 31 of 88
Table 8. This is largely due to a budget cut towards the end of the year. The completed inspections are
following the AM plan for WPM very nicely. Figure 10 shows how Avista’s use of Distribution Wood
Poles changed with time. This graph supports a growing number of pole and WPM related issues.
Based on poles lasting 74 years before they will be replaced on a planned basis, Avista would need to
replace 3,200 poles per year at equilibrium. We finally reached and exceeded 3,200 poles per year in
2011 and although the replacement is not a steady number we have remained above the 3,200
threshold since then. Figure 11 shows how an increasing number of poles are reaching 74 years.
WPM Model Performance
The AM model for WPM provided a decent baseline for estimating the costs of the WPM follow-up
work, however, AM is currently reanalyzing this program and so there will be a new baseline in the near
future.
WPM Summary
The main message from the KPI and metrics for WPM is that we are moving in the right direction, but
we are falling behind and will need to complete work on more feeder miles to control the impact on
future reliability.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 32 of 88

Figure 8, WPM OMT Event Trends
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WPM OMT Events by Sub Reason and Year
2011 2012 2013 2014 2015
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 33 of 88

Figure 9, WPM Contribution to Annual SAIFI value by Sub-Reason and Year
0
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0.14
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Annual SAIFI Contribution by Sub Reason
2011 2012 2013 2014 2015
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 34 of 88

Figure 10, Wood Pole Used by Summarized Activity
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Distribution Wood Pole Replacement History
and Trend
Number of poles Used Annually Poles Replaced WPM - Dist Grid Mod
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 35 of 88

Figure 11, Distribution Wood Pole Age Profile
*Pole age data has not been updated in the past 4 years
0.0%
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1.0%
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1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020
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Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 36 of 88

Figure 12, Actual vs. Projected Usage for WPM
Wildlife Guards
Wildlife caused outages have a significant impact on electric service reliability to customers. The
improved outage tracking implemented in 2001 has consistently shown, within a percent or two either
way, that animal’s cause 19% of outages experienced by electric customers. While generally short in
duration, labor impacts to respond are significant. In 2010, Squirrels accounted for only 6% of all
sustained outages (see Table 9) which is a significant drop from 2009 value of 12%. This trend
downward has continued and the percent of squirrel caused outages is now below 3%. We will continue
to monitor this issue.
Selected KPIs and Metrics
The goal of the Wildlife Guards program is to reduce the number of Animal caused outages on the
distribution system. More specifically, the program targets reducing the number of squirrel caused
outages. The plan estimates that installing guards on the worst 60 feeders will reduce the number of
Squirrel caused outages by 50%. 2006 was selected as the starting point, because the work performed
0
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Poles Replaced
Crossarms Replaced
Steel Stubs
Lightning Arresters
Cutouts
Wildlife Guards
Actual vs. Model Projected Usage for WPM
Actual Modeled Projected
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 37 of 88
that year was not influenced by the current AM plan. The final goal was a 50% reduction from the 2006
value of 902; however, this year’s value of 272 exceeds the final goal and has for the past five years.
The second KPI used is the percentage of sustained outages caused by Squirrels. This KPI provides a
relative impact that squirrel related outages are having on the system and represents the future value of
installing Wildlife Guards on Distribution Transformers.
The only metric for Wildlife Guards is the annual avoided outage benefit from Squirrel related outages.
We estimate approximately $82 in benefit for every outage avoided starting in 2011. Using this benefit
per event, the projected avoided outage benefit by year is the difference between the projected
number of events and the actual number of events for that year multiplied by the calculated cost per
event for that year. The goals by year are shown in Table 10.

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

Table 10, Wildlife Metric Goals for 2010 - 2015
Metric
Description
Projected Avoided Outage Benefit due
to Squirrel Caused Outages
Actual Avoided Outage Benefit due to
Squirrel Caused Outages
2009 $36,000 $47,190
2010 $71,000 $157,466
2011 $22,000 $34,696
2012 $30,000 $37,935
2013 $37,000 $49,916
2014 $37,000 $46,045
2015 $37,000 $46,269
*Note: Avoided costs were revised from $390 per event to $82 for 2011 on. This change was based on a
review of costs.
WILDLIFE GUARDS KPI Performance
Installing Wildlife Guards has exceeded expectations so far and has decreased the number of OMT
events for Squirrels. The original model estimated costs were higher than actual costs because the
model assumed more guards would be needed. So, the saved money has been used to work on more
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 38 of 88
feeders than originally anticipated. This program officially ended a few years ago due to the quick pace
of the work, however, the metrics are still being watched because other programs still have an indirect
impact on the numbers. These other programs continue to add WLG into our system on a less
programmatic basis. Based on Figure 13 and Figure 14 you can see that few WLG were installed this
year with WPM continuing to install the bulk of the WLG. However, the value and original scope of the
program were realized years ago and so this is not a concern. This is the last year that this programs
metrics will be reported on but we do envision a continued value for years to come.
WILDLIFE GUARDS Metric Performance
The main purpose of the Avoided costs metric shown in Table 10 is to demonstrate the savings
associated with the work from the original model. In 2010, Avista saw savings nearly triple the
projected amount. Other work such as Electric Distribution Minor Blanket and WPM continue to install
Wildlife Guards on Distribution Transformers. However, the large increase in savings is most likely due
to the increase in the number of WLG installed in 2010.
WILDLIFE GUARDS Model Performance
The Wildlife Guard model under estimated the impact of the work performed (see Table 9), so our
performance has exceeded our expectations. This exceeds the goal of being within +/- 30% of the actual
value. However, since the program has accomplished its purpose, no further work is planned.
WILDLIFE GUARDS Summary
The Wildlife Guard program showed real cost savings over time. The program ended a few years ago
and more than exceeded expectations. We continued to report on the established metrics to help
realize a more complete value of the program. Although, we will no longer report on these metrics,
work in WPM and other efforts to install wildlife guards on Distribution Transformers may continue to
create even more value.
Table 11, Worst Feeders for Squirrel related Events for 2015
Feeder Sustained Outages Percentage of all Squirrel related Outages Running Percentage
PIN443 14 3.80% 3.80%
SLW1358 9 2.45% 6.25%
PDL1203 9 2.45% 8.70%
CFD1211 7 1.90% 10.60%
OTH501 6 1.63% 12.23%
SIP12F4 5 1.36% 13.59%
TEN1256 5 1.36% 14.95%
BLU321 5 1.36% 16.31%
CDA124 5 1.36% 17.67%
BUN426 5 1.36% 19.03%
SLW1368 5 1.36% 20.39%
SLW1348 5 1.36% 21.75%
STM633 5 1.36% 23.11%
CHW12F3 5 1.36% 24.47%

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 39 of 88

Figure 13, Wildlife Guards Installed by Year and Expenditure Request
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Distribution Minor
Blanket
Failed Electric Dist
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Sys-Dist Reliability-
Improve Worst
Fdrs
Wood Pole Mgmt Dist Grid
Modernization
TCOP Related
Distribution
Rebuilds
Wildlife Guards Issued by ER and Year
2011 2012 2013 2014 2015
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 40 of 88

Figure 14, Wildlife Guards Usage by MAC for 2011-2015
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Wildlife Guard Issued by MAC and Year
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2012
2013
2014
2015
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 41 of 88
URD Primary Cable
URD Primary Cable replacement addresses aging underground primary distribution cable. URD
installation began in 1971. Over 6,000,000 feet of URD was installed before 1982. Outage problems
exist on cable installed before 1982, cable installed after 1982 has not shown the high failure rate of the
pre-1982 cable. Programmed replacement of the problem cable has been on-going at varying levels of
funding since 1984. Emphasis is on the original vintage of URD. That cable was not jacketed with a
protective layer of insulating material, neutral conductor was bare tinned copper concentric type
construction on the outside of the cable. Insulating material was vulnerable to water intrusion.
Historically, over 200 faults of primary cable happen annually. There have been as many as 264 primary
cable faults in 2003. During 2007 there were 168 primary faults. From 1992 faults increased from 2 per
10 miles of cable to 8 per 10 miles in 2005. The number of faults per mile has stabilized between 2005 –
2007 after steadily climbing between 1992 and 2005.
Funding for URD Primary Cable replacement was significantly increased in 2007 and began the current
program. The program had an original estimate of 5 years to complete. Although the funding has not
matched the original plan, almost all of the work was accomplished over six years. The year 2012
represents the last year of major funding for the program since the number of outages has significantly
dropped and the worst feeder for URD Cable – Pri failures only had four outages. We anticipated some
low level of funding for the remaining cable sections as they fail and are currently running this program
on this smaller level.
Selected KPIs and Metrics
We selected two KPIs to track for URD Primary Cable replacement, URD Primary OMT Events and
number of feet replaced each year. The goals for each of these KPIs came from the trends observed
over the past few years and set a goal to complete the replacement of URD Primary cable in 2012. The
program continued into 2015 but with a limited budget. Table 12 shows the goals for each KPI by year.
The OMT events reflect the impact to our system of past work. The number of feet of URD Primary
Cable replaced acts as a precursor to future OMT performance. After the first generation of URD
Primary Cable has been replaced, the second generation will need to be monitored and plan may need
to be established for addressing this vintage of cable.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 42 of 88

Table 12, URD Cable - Pri KPI Goals
KPI
Description
Projected URD
Cable - Primary
OMT Events
Actual URD
Cable -
Primary OMT
Events
Projected
Number of
Feet Replaced
Actual Number of Feet
Replaced
2009 143 136 178000 213,000
2010 119 93 178000 217,883
2011 94 95 178000 225,823
2012 70 72 178000 117,247
2013 45 93 0 35,874
2014 45 88 0 35,515
2015 45 64 0 24,155

The selected metric for URD Primary Cable is the avoided costs due to cable faults. The benefits are
based on a projected number of failures without the program that are projected to be around 670
events for 2015. Currently, each event on average costs ~$2,800 due to the duration of the outage and
the number of people involved in correcting the fault. While this indicator is based on a projection, it
provides a reasonable estimate of the return on investment for the money spent to replace this vintage
of cable. Table 13 projects the anticipated avoided outage benefit by year for the estimated number of
avoided outages.
Table 13, URD Cable - Pri Metric Goals
Metric
Description
Projected Avoided Outage
Benefit due to URD Cable - Pri
Caused Outages
Actual Avoided Outage Benefit
due to URD Cable - Pri Outages
2009 $1,038,613 $1,056,113
2010 $1,228,275 $1,295,225
2011 $1,368,561 $1,352,648
2012 $1,516,159 $1,481,504
2013 $1,744,539 $1,494,738
2014 $1,898,311 $1,580,378
2015 $1,997,052 $1,720,020

URD PRIMARY CABLE KPI Performance
For 2015, the performance for URD Primary Cable did not meet expectations but performed well. Table
12 shows that URD Cable – Pri events have not met expectations for the past couple years, however, the
outages continue to have a downward trend. Figure 15 shows the downward trend in the number of
events. The second generation of URD Primary Cable is also being analyzed. If it begins failing at an
increasing rate, it would signal the next round of cable replacements. We have some faults in newer
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 43 of 88
cables and anticipate that this will be true for several years to come. If these faults begin to significantly
increase over time, we will have to begin replacement of this cable since the earliest of the second
generation cable is now approaching 30 years old.

Figure 15, URD Primary Cable OMT Events by Year
URD PRIMARY CABLE Metric Performance
The projected savings and estimated savings due to avoided outage costs for Avista has typically come in
very close as seen in Table 13. The avoided outage cost for this last few years has not performed as well
as years past but overall the current program is performing as expected.
URD PRIMARY CABLE Model Performance
This AM model is an early vintage model and given the cash flow, did not match the model; but it has
generally predicted performance reasonably well. Because of the good performance and limited
remaining time for the program, the model will be retained as is and the program allowed to expire
once all of the first generation URD Primary Cable has been replaced.
URD PRIMARY CABLE Summary
Several people have worked diligently on this program and it is now nearing completion. We anticipate
another round of URD Cable replacements in the future, but we don’t have any evidence indicating that
the company has reached the end of life on the second generation of URD Cable. The program has
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Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 44 of 88
succeeded in reducing O&M costs by avoiding long and costly outages. Since all of the work to replace
the cable comes from capital spending, the program is a great example of how capital spending can
reduce O&M. However, operations continue to find more cable than estimated remaining, so future
funding is recommended to only cover planned work on known cable.
Distribution Transformers
In 2011, Avista implemented the Transformer Change Out Program (TCOP) to replace all Distribution
Transformers containing PCB’s followed by replacing all pre-1981 transformers. The driver for the
program is to reduce the environmental risks associated with PCB’s in transformers and improve the
overall electric distribution system by eliminating higher loss transformers.
The program has two strategies associated with it. The first strategy is to eliminate all transformers
containing or potentially containing PCB’s. The initial focus was on areas near water sources. These
transformers have specific work plans for removing them from the system. The second strategy uses
the Wood Pole Management program to remove all pre-1981 transformers as part of their follow-up
work on a feeder. The first strategy work should be completed in 2016 and the Wood Pole Management
work should have all the pre-1981 transformers replaced by 2036.
Selected Metrics
Table 14 shows the metrics selected for TCOP. The number of transformers changed out represents the
reduction of future risk from PCB’s. It also provides a leading indicator of how many future transformer
failures we may experience. The energy savings represents the value of changing out the less efficient
transformers and quantifies the approximate amount of energy saved each year by replacing less
efficient transformers with more efficient ones.
Table 14, TCOP Metrics
Year
Planned
Number of
Transformers
Changed Out
Actual Number of
Transformers
Changed Out
Planned Energy
Savings from
Transformers
(MWh)
Projected Energy
Savings from
Replaced
Transformers
(MWh)*
2012 2,687 2,529 2,304 2,430
2013 2,555 2,599 2,304 2,671
2014 2,930 2,625 2,304 3,002
2015 305 2,557 299 2,547
2015 – Pad/Subm 2,030 342 1,447 603
2016 1,419 1,265
2016 – Pad/Subm 87 149
2017 948 940
2017 – Pad/Subm 259 466
2018 347 330
2018 – Pad/Subm 1,092 1,853
 Note: values in red have missed the goal
*Conservative estimate based on no load loss
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 45 of 88
Metric Performance
In 2015, we cut back the funding on the TCOP program but were still able to complete in total more
transformer’s than expected. Fewer padmount transformers were completed but many more overhead
transformers were replaced instead. Budgeting for the last few years has had an effect on the expected
program and will continue to impact the program going forward. New metrics have been developed to
account for the extended program due to the decreased budget.
Summary
The TCOP is accomplishing it objectives and reducing Avista’s and customer’s risks associated with
Distribution transformers containing PCB’s and providing energy savings.
Area and Street Lights
Asset Management converted the existing area and street light data into our Geographical Information
System (GIS) in 2012 and continued the work through 2014. This work updated and corrected the
existing information and provided a platform to convert our High Pressure Sodium (HPS) lights to Light
Emitting Diode (LED) fixtures beginning in 2015. The recent cost and reliability improvements in LED
lights have made converting 100W HPS lights to LED fixtures cost effective. The rate schedule was
approved for the state of Washington for 100W and 200W HPS street lights for 2015 and for all non-
decorative wattage of both street and area lights for Washington and Idaho in 2016.
Selected Metrics
Table 15 shows the metrics selected for the Street light change out program. The number of lights
changed out represents the reduction of maintenance costs due to the increased durability of LED lights.
It also provides a leading indicator of how many future light failures we may experience. The energy
savings represents the value of changing out the less efficient HPS lights and quantifies the approximate
amount of energy saved each year by replacing less efficient HPS lights with more efficient LED ones.
Table 15, Area and Street Light Conversion Metrics
Year
Planned
Number of
Lights
Changed Out
Number of Lights
Changed Out
Planned Energy
Savings from
Lights (W)
Actual Energy
Savings from
Lights (W)
2015 3,500 4,166 262,500 312,450
2016 4,000 300,000
2017 5,000 375,000
2018 6,500 487,500
2019 8,000 600,000
Summary
This program is not unique, years ago a systematic change out of mercury vapor lights occurred.
However, some of these lights remained well after the program ended. This program should have a
better result due to the new technology in mapping being used for lights. This program may also expand
to the remaining decorative lights in the future.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 46 of 88
Distribution Vegetation Management (VM)
Our Vegetation Management program maintains the clearance zone free of vegetation for the
distribution system clear of trees and other vegetation. This reduces outages caused by trees and to a
lesser extent squirrel caused outages. Our Distribution System runs for 7,702 circuit miles in
Washington, Idaho, and Montana. The Vegetation Management program also covers work on the
Transmission System and the High Pressure Gas Pipeline system, however the purpose here is to only
look at the Distribution System.
For the Distribution System, our analysis has shown that a pro-active maintenance program provides the
best value to our customers. While our past practices were a four and seven year cycle based on
vegetation type and had a reduced clearing diameter, our analysis has indicated a five year clearing cycle
at a normal clearing distance has advantages. Our current goal is to be on a 5 year cycle, however, we
don’t always hit our target distance (Table 18) and are closer to a 6 year cycle.
The purpose of Vegetation Management is to meet regulatory compliance, provide the best value to our
customers, and maintain current reliability. The Vegetation Management program continues herbicide
spraying and enlarged the risk tree programs to further improve vegetation management. Both of these
additions strive to improve the performance of the system by reducing vegetation related events.
Selected KPIs and Metrics
For VM, we selected one leading KPI and a lagging KPI. These KPIs were set for the old analysis and
ended last year, we linearly progressed these numbers to buffer us until we can establish new KPI goals.
The leading KPI is the number of Distribution Feeders miles managed each year. This indicates how well
the actual work matches the planned work and the model. The results of the work in VM should directly
impact the number of Tree Growth and Tree Fell events in OMT which is the lagging KPI. The number of
Tree Growth events and Tree Fell events are summed for each year and compared to the AM models
predictions if the plan is followed. The goals for each KPI by year are shown in Table 18. The AM model
for Tree Growth events and Tree Fell events shows varying KPI’s for each year due to the strict following
of the 5 year cycle based on when the feeder was last done. For a VM metric, we selected the Tree-
Weather OMT events by year. As seen in Figure 16, there is a relationship between weather events and
VM. We assume that improvements in VM results should impact the number of Tree-Weather OMT
events and set a goal shown in Table 18. The goal for Tree-Weather events is based on the AM models
average value over a 10 year period. This metric was not included as a KPI, because weather events are
very unpredictable and random in nature. Once the relationship has been better established, it may
become a KPI.
Another metric selected for monitoring is the cost per mile for VM on the distribution feeders. While no
goals have been established, this will measure how effective our AM spending gets the work done and
how much work is required to clear the lines. The costs per mile should drop in future years, because
the amount of work required to clear the feeders should decline after reaching a 5 year cycle. The total
number of miles of all planned work was modified in 2011. Beginning in 2011, the costs per mile
calculation includes all planned work and not just the miles cleared. So, the total number of miles for all
planned work was included in the metrics.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 47 of 88
Table 16, Vegetation Management Metric Goals

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

Table 17, VM KPI Performance
Note: values in red missed the goal
*Linear progression from previous metrics
Year
Projected Tree
Growth + Tree
Fell OMT
Events – 2009
Plan
Projected Tree
Growth + Tree
Fell OMT
Events – 5
Year Cycle
Actual
Number
of OMT
Events
Projected
Annual
Miles
Managed
Actual Annual
Miles Managed
w/o Risk Tree
or Spraying
Percent
Model
Error
2009 1120 556 765 1,220 790 136%
2010 620 540 836 1,560 1,304 155%
2011 790 500 727 1,560 1,747 145%
2012 1210 520 712 1,560 1,296 137%
2013 1390 630 647 1,560 1,459 103%
2014 1400 780 793 1,560 1,663 102%
2015 1730* 777* 620 1,560* 1,405 -
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 48 of 88

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

Tree Fell, 506
Tree Fell, 392 Tree Fell, 377 Tree Fell, 298
Tree Fell, 393 Tree Fell, 340
Tree Growth, 330
Tree Growth, 335 Tree Growth, 335
Tree Growth, 349
Tree Growth, 400
Tree Growth, 280
Weather, 895
Weather, 325 Weather, 314
Weather, 216
Weather, 166
Weather, 208
0
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1200
1400
1600
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2000
2010 2011 2012 2013 2014 2015
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Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 49 of 88

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

Tree Fell, 234 Tree Fell, 215 Tree Fell, 229 Tree Fell, 183 Tree Fell, 223 Tree Fell, 219
Tree Growth, 77
Tree Growth, 71 Tree Growth, 93
Tree Growth, 90
Tree Growth, 123 Tree Growth, 87
Weather, 620
Weather, 178
Weather, 170
Weather, 137
Weather, 101
Weather, 122
0
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Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 50 of 88

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

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

VM Model Performance
The AM model for Distribution VM was revised in 2010, but the recent changes to the work performed
and errors experienced justify updating the model. We anticipate completing the update in 2016.
VM Summary
Depending on how the program is evaluated, not enough miles are completed each year to achieve the
goal of a 5 year cycle. The costs per mile may be too high and/or the current funding levels are too low
and the impacts of herbicide spraying and enhanced risk tree work modify the meaning of work per
mile. Vegetation Management’s performance does show continued improvement but further analysis
will provide an opportunity to re-evaluate our current performance and update future expectations.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 51 of 88

Distribution Grid Modernization Program
Avista initiated a Grid Modernization Program designed to reduce energy losses, improve operation, and
increase the long-term reliability of its overhead and underground electric distribution system. The
program includes replacing poles, transformers (Pad Mount, OH & Submersible), cross arms, arresters,
air switches, grounds, cutouts, riser wire, insulators, conduit and conductors in order to address
concerns related to age, capacity, high electrical resistance, strength, and mechanical ability. The
program also includes the addition of wildlife guards, smart grid devices, switched capacitor banks,
balancing feeders, removing unauthorized attachments, replacing open wire secondary, and
reconfigurations.

When funded to a level that allows 5-6 feeders to be upgraded per year, the continuous program
represents a 60 year interval to upgrade all the feeders in Avista’s system and coordinates all of its
activities with Avista’s Wood Pole Management. The objectives of the Grid Modernization Program are
listed in Table 20.

Table 20, Grid Modernization Program Objectives
Objective Objective Description
Safety Focus on public and employee safety through smart design and work practices
Reliability Replace aging and failed infrastructure that has a high likelihood of creating a
need for unplanned crew call-outs
Avoided Costs Replace equipment that has high energy losses with new equipment that is more
energy efficient and improve the overall feeder performance
Operational
Ability
Replace conductor and equipment that hinders outage detection and install
automation devices that enable isolation of outages
Capital Offset Avoid future equipment O&M costs with programmatic rebuild of failing system

Selected Metrics
The metrics selected include miles of work completed, OMT sustained outages on feeders with Feeder
Upgrade work completed, and energy savings provided by completed work.
Based on Avista’s 2015 Integrated Resource Plan dated August 31st, 2015, Table 8.3, the realized and
anticipated energy savings by identified feeders is shown in Table 21.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 52 of 88

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

The miles of work planned is ultimately driven by the approved budget and generally can only be
projected for 5 years. In order to maintain a 60 year cycle, Avista would need to address an average of
137 miles per year of overhead circuit miles.
For tracking the impacts of the work on outages, we will monitor the following OMT sub-reasons shown
in Table 22. While the Grid Modernization will affect all of the sub-reasons listed in Table 22Error!
eference source not found., the sub-reasons identified as potentially avoidable represent the most
direct impact of the work. We assume that the number of OMT sustained outages will be reduced by 0.1
outages per mile of overhead work completed.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 53 of 88

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

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 54 of 88
Figure 18, OMT Sustained Outages related to Grid Modernization
0
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OMT Sustained Outages related to Grid Modernization
Grid Mod Feeder Outages System-Wide Outages
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 55 of 88
Figure 19, Wood Pole Management and Grid Modernization Before and After
Metric Performance
The results of the first four years work are shown in Table 23 the major event days from 2015 were
removed to more accurately show program value). The year 2012 marks the beginning of the program.
The number of miles actually completed missed the goal of 137 and the number of sustained outages
just fell short of its goal. Figure 19 shows the prior and post trends for WPM and Grid Mod. These
trends are broken down to be outage specific per program on a per mile of OH Conductor basis. The
graph shows a steady trend downward for both programs after work is done on a feeder. Grid Mod
work tends to trend down prior to the completion date due to the time it takes to complete the Grid
Mod work and in some cases feeders being previously completed by WPM. A feeder may take multiple
years to complete thus some portion of the benefits are gained in the couple years before completion.
The before/after portion of the graph is set so that all the work done for these programs since 2008 is
set to a zero year on the year it was completed. The program is reducing outages as seen in Figure 19
and Table 23 even though the planned miles have yet to be met. Missing this goal increases our
program cycle, the current goal is a 60 year cycle. Continuing to miss this mileage can impact the
sustained outages over time.
0
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Wood Pole Management & Grid Modification
Before and After
Average before WPM Average after WPM Average after Grid Mod Average before Grid Mod
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 56 of 88

Table 23, Metric Performance for Grid Modernization Program
Year
Planned Miles
for
Modernization
(Miles)*
Actual Miles
Completed
(Miles)**
Anticipated
Number of
Sustained
Outages
Realized
Number of
Sustained
Outages
2012 95 73.33 2340 2251
2013 137 53.83 2327 1840
2014 137 78.64 2313 1791
2015 137 85.2 2300 2342
2016 190*** 2286
2017 190*** 2272
*Note: The planned or anticipated values may be modified to match approved work plans for each year
that more accurately align with the actual work planned. Overall outages are based on the Reliability
Outage events considered
**Data from Grid Modernization Group
***Grid Mod works on both overhead and underground equipment. Future metrics and analysis will be
based on total circuit miles
Summary
The Grid Modernization Program began in earnest in 2012 and represents feeder replacement work and
upgrades founded on smart grid work. Overall the program is improving outages and improving the
health of our system. The anticipated miles completed and cycle time may need to be modified in the
future if the miles continue to miss the goal, however, the anticipated outage reduction appears to be
on target and so the mileage is not an issue at this time.
Worst Feeders
Since 2009, Avista has invested $1-2M annually to improve the reliability of its most underperforming
distribution circuits (aka – Worst Feeders). The Company operates over three hundred and fifty (350)
individual circuits throughout Northern Idaho and Eastern Washington. Many of these circuits serve
rural geographic regions and may extend for hundreds of miles. In most situations, rural circuits route
through heavily timbered national forest areas and are subject to tree, wind, and storm related outages.
Avista’s SAIFI target in 2015 was 1.17. So, on average, an Avista customer could expect one sustained,
contingency outage event in 2015. However, many rural customers experience three to five sustained
outages per year with a few circuits topping the SAIFI chart at above six (see Table 24). Avista operating
engineers are instructed to systematically review outage logs for these circuits and determine an
appropriate level of treatment. Projects vary by individual circumstance but in many cases additional
circuit reclosers are installed to reduce outage exposure and to automatically restore power to
upstream customers. In other locations, circuits in outage prone areas are converted from overhead to
underground. In other situations, circuits are effectively ‘hardened’ by shortening conductor span
lengths or by increasing phase spacing. Of particular note is the Grangeville 1273 circuit. Though its
SAIFI metric is the highest in the Company, the current average of 9.02 is a significant improvement over
the previous three year average of 21.9. A program investment of $217,686 was made on this line and
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 57 of 88
has help to improve its reliability performance. On another circuit, Roxboro 751, over 1 million dollars
was invested to convert overhead line segments to underground cable and the SAIFI statistics improved
from 5.35 to 2.67. In fact, Roxboro now ranks 35th in our feeder list and does not appear in the top
twenty ‘worst feeders’ as depicted in the graphics. In 2016, Avista plans to invest $1.5 million dollars in
ten (10) circuit projects. This includes the final phase of the Roxboro 751 project along with other multi-
year projects including Gifford Feeders 34F1 and 34F2 together with Colville 34F1 projects. Other
projects are first year efforts to improve the service reliability of rural distribution circuits. The 2016
capital plan for the worst feeder program is indicated in Table 25.

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

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

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 58 of 88
Feeder Tie Circuits
Urban distribution feeders can be connected to other feeders as a means of “back-up” to serve
customer load. By closing a “tie” switch between the two feeders, it is possible to electrically “feed” a
portion of the adjacent feeder.
Service reliability can be compromised by the contingency loss of substation equipment such as the
substation transformer, and voltage regulator. Car-hit poles can cause lengthy outages. Critical issues
with picking up an adjacent feeder include the reserve capacity of the host feeder and the end of line
service voltage.
In rural areas, feeders with back-up capability are rare because the distance between adjacent circuits
may be several miles. As with urban feeders, loss of substation equipment can cause feeder outages.
Also, losing a portion of the main feeder trunk on a rural, radial feeder due to a tree through the line
and/or via wind damage can also cause an outage that could be minimized with a “tie” feeder capability.
Feeder Tie projects increase the reliability of both of the circuits involved in the “tie”.
ARD12F2-ORN12F1 Tie Circuit
This feeder tie project will allow the Arden12F2 distribution feeder to be fed by Orin12F1. The “tie” is
being built by installing new conductor between the “gap” in the two circuits (see Figure 20). The
conductor has a cross sectional area allowing it to pick up the load of Arden12F2. In addition the voltage
drop of the “tie” conductor is small. Also, a set of voltage regulators is being installed to increase the
voltage on the Arden12F2 feeder to keep it within the required limits. If there is an outage on the
Orin12F1 feeder, the Arden12F2 will be able to pick up a portion of Orin12F1, but not the entire feeder.
This is a two year project with a cost of $850,000 covering a distance of 2 miles between the two
feeders.

Figure 20, ARD12F2 to ORN12F1 Tie
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 59 of 88
DAV12F2-RDN12F1 Tie Circuit
This circuit tie will allow Rearden12F1 to be fed from Davenport12F2 and vice versa. The “tie” is being
built by installing new conductor between the “gap” in the two circuits (see Figure 21). Also, a set of
voltage regulators is being installed to increase the voltage on the host feeder to support customer
service voltage.
This is a multiyear project with a cost of $1.8 million dollars, connecting a distance of 10 miles between
the two feeders.

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

Figure 21, DAV12F2 - RDN12F1 Tie
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 60 of 88
Spokane Electric Network
Equipment Types and Aging
Major network equipment falls into four categories: network transformers, network protectors, cable
(primary and secondary), and physical facilities – duct banks, vaults, manholes, and handholes.
Transformers and Protectors – some age, and maybe initial cost, data may be available via Maximo. A
casual search indicates 27 transformers with purchase dates between 1930 and 1950 still in service in
the network – these records are not verified. Another casual search of network protector records
indicates units dating to 1947 still in service.
Cable – we do not have specific records regarding age of cables. A fair percentage is “OLD” – comments
below.
Physical facilities – again, no specific records. Again, a fair percentage is “OLD”.
KPI and Metrics
There are no established performance metrics for the downtown network. Given that the very nature of
the network architecture is intended to prevent outages, and that OMT does not “see” network events,
we have no specific outage data other than to state that the numbers would be small in comparison
with the rest of the Avista system. Assuming the “network communications” project discussed in the
“Non-routine Projects” section below actually comes to fruition, we would be better able to identify,
track, and analyze outages should they actually occur.
Capital Budgets and Spending - Overview
CapX expenses in the downtown network fall into six general categories. Five are covered in “blanket”
projects; the sixth category is funded by specific CPRs. Details:
1. New services: Commercial, residential, Street Lights
2. Replacement of old primary cable (Paper Insulated Lead Cable, “PILC”)
3. Replacement of old secondary cable (PILC or Rubber Insulated Neutral Cable, “RINC”)
4. Purchase and replacement of aging transformers and network protectors
5. Repair/refurbishment/replacement of vaults/manholes/handholes
6. The fifth category, covered by specific CPRs, may involve projects such as:
a. Work required due to extensive city projects – e.g., the upcoming major rebuild of
Lincoln and Monroe Sts where we have extensive existing facilities which will need
major work or replacement
b. Adding a “SCADA” and communications capability to the existing network – a trial
project for Post West is budgeted.
New Services – Expenses
Generally self-explanatory. ’15 budget $200K
Replacement of old PILC primary cable– Expenses
Our 2015 budget for PILC cable replacement was $340K. The PILC primary cable in our network is
typically 30 years old or more; we do not have specific information on when much of it was installed.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 61 of 88
Our network has about 96,700 feet of primary cable, about 47,900 feet is still PILC. We have targeted for
replacing 7,500 feet of primary PILC each year. In 2015, due to personnel shortages and other more
pressing work, we only replaced 6300 feet of primary cable.
The PILC cable has been very reliable through the years of service; however, as it ages, we have
observed an increase in failures. Our goal of maximizing service in the downtown network drives the
PILC replacement effort. Figure 22 and Figure 23 are illustrations of failures that occurred with older
PILC cable.
Avista was fortunate in that we have only had one PILC cable failure in 2015 and one in 2013. This low
failure rate is in large part due to the proactive replacement of the old cable. Owing to the redundant
nature of our network, neither of these events resulted in customer outages.

Figure 22, A faulted PILC cable
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 62 of 88

Figure 23, A second faulted PILC cable
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 63 of 88
Replacement of old PILC and RINC secondary cable– Expenses
Factors driving replacement of PILC primary and PILC/RINC secondary are essentially the same. We
replaced about 4,600 feet of secondary cable in 2015.
Purchase of new and replacement of aging transformers and network protectors– Expenses
Our 2015 budget for purchasing transformers and protectors was $920K; for replacement activities
including associated cable, vault accessories, etc. was $1.1M.
We have 174 transformers in our network, each equipped with a network protector. Network
transformers and network protectors are specialized devices specifically designed and built to ensure
maximum operating reliability, and in the case of the protector, to improve and ensure safety for the
crews working on the network.
We target replacing 12 transformers per year, and generally, the protector is replaced at the same time
(there are exceptions). Replacement of a network transformer is a labor-intensive operation, and
typically involves added expenses for hiring a crane to move the old and new transformers in and out of
the vault, traffic control, and often crew overtime. We prioritize replacing very old transformers,
transformers which are found to still have PCB oil, and transformers where routine oil sampling
indicates contamination. In addition, transformers where oil sampling indicates high concentrations of
combustible gasses (typically caused by internal arcing or similar events) are replaced immediately. In
2015 we replaced one transformer due to a high concentration of combustible gasses, one due to
contaminated oil, and one ca. 1947 vintage transformer after a bulge was noted in the primary
compartment case. We also replaced three aged transformers on a more “routine” basis.
A transformer failure can be a dramatic and dangerous event. Avista has been fortunate to not
experience a violent transformer failure in recent years (a quick search indicates that the last one was in
2008.) Figure 24 illustrates the transformer which failed in 2008 due to some anomaly in the primary
compartment.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 64 of 88

Repair/refurbishment/replacement of vaults/manholes/handholes– Expenses
Our 2015 budget for this work was $500K.
Our system contains 140 vaults, 325 manholes, and 295 handholes. Many of these, particularly
manholes and handholes, date from the early 1900s and are still in service. In particular, where these
are located in a traveled street, they have often deteriorated due to stresses from traffic, weather, and
related factors. Vaults which have grated covers for circulating air for transformer cooling are often
subjected to chemicals used for deicing streets in winter, which collects in the vaults and deteriorates
the concrete.
When these facilities become deteriorated to the extent we have found in some cases, they represent
not only the possibility of interruptions to service, but becoming traffic hazards as well. In the case of
facilities in sidewalk areas, we have seen cases where cracking or buckling concrete, or deformed lids,
have the potential to be a trip hazard for pedestrians.
Mitigating the vault, manhole, and handhole deterioration has ranged from being as simple as installing
a new lid to removal and replacement of the entire facility. Figure 25 through Figure 27 illustrate various
underground facility deterioration we have recently found, and some of the remediation efforts
undertaken.
Figure 24, A network transformer after a failure in the
primary compartment
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 65 of 88
In 2015, we repaired or replaced 6 of these facilities. We have 3 more in queue pending a break in
winter weather, and we have not started our 2016 inspection cycle.

Figure 26, Duct bank damage entering an old deteriorated manhole
Figure 25, Interior of a badly
deteriorated old manhole in a
heavily traveled street
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 66 of 88

Non-routine Projects Being Carried Out on Specific CARs– Expenses
We had two open CPRs for network projects in 2015.
Network Communications Stage 1– Expenses
This project was budgeted for $122.4K
The scope of this pilot project involves adding communications capabilities to network protectors in a
subset of the Post St West sub-network. This communications capability will enable remote reading of
protector status (closed, tripped, locked open, number of protector operations), and remote
instantaneous load readings. This capability will not immediately improve system reliability, but will
pave the way for additional capability such as remote protector switching and remote indication of vault
conditions (temperature alarm, unauthorized entry, etc.) which is expected to benefit overall network
operation and maintenance. For convenience – think “smart grid” for the downtown Spokane network.
The CPR was first opened in 2014, but to date, lack of personnel resources has resulted in no charges.
This CPR remains open for 2016.
Monroe and Lincoln St Repaving– Expenses
This project was budgeted for $495K ($475K construction, $20K removal/retirement)
The City of Spokane has informed Avista of plans to extensively renovate and repave both Lincoln and
Monroe Streets from 3rd Ave north to Main St in the main downtown corridor. This project will result in
Avista needing to extensively modify, rebuild, and possibly even move network facilities in those streets.
The CPR was opened in 2015 in anticipation of ordering long-lead items, but planning delays resulted in
no expenditures in ’15. The CPR remains open for 2016.
Figure 27, Complete replacement of a badly deteriorated manhole
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 67 of 88
Distribution Line Protection
Avista's Electric Distribution system is configured into a trunk and lateral system. Lateral circuits are
protected via fuse-links and operate under fault conditions to isolate the lateral in order to minimize the
number of affected customers in an outage. Engineering recommends installation of cut-outs on un-fused
lateral circuits and the replacement of obsolete fuse equipment (e.g. Chance, Durabute/V-shaped, Open
Fuse Link/Grasshopper, Q-Q, Load Break/Elephant Ear, and Porcelain Box Cutouts). As part of the
program, sizing of fuses will be reviewed to assure protection of facilities, as well as coordination with
upstream/downstream protective devices. This is a targeted program to ensure adequate protection of
lateral circuits and to replace known defective equipment.
Assets Not Specifically Covered Under a Program
These assets do not have a planned AM program, so no specific metrics or KPIs have been identified.
The general metrics discussed above for number of OMT Events (Table 1) and the associated action
level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a plan
will be developed or if action is needed. In summary, Table 26 lists assets we continue to monitor to
determine if and when planned actions are needed.

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

Conclusion
In this report, we documented and examined the KPIs and metrics AM selected for the AM Distribution
system programs and provided the results for 2015. Some of the metrics compared how an asset
performed with a program and how it would have performed without a program. The difference in
performance provide an estimate of the cost saving and value of an AM program. While the exact
savings are impossible to calculate in most cases, it provides a relative comparison and supporting
justification or motivation for change in AM decisions made in the past. Other KPIs and metrics
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 68 of 88
provided indications of how well an asset performed and help determined if further work is required.
Some AM models clearly need more work to better predict future conditions and will be scheduled in
the future if it makes sense. This year other non-AM programs were included in this report and
submitted by the group in charge of each program. These program write-ups did not follow the same
template as the AM write-ups but were included within the document for project comparison.

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 69 of 88
Distribution Vegetation Management
2016
Washington
AIR12F1
AIR12F2
AIR12F3
CFD1210
CFD1211
CHE12F1
CHE12F2
CHE12F3
CHE12F4
CLA56
EWN241
FOR2.3
GIF34F2
INT12F1
INT12F2
L&R511
L&S12F1
L&S12F2
L&S12F3
L&S12F4
L&S12F5
LOO12F1
LOO12F2
MLN12F2
ROK451
ROX751
SE12F1
SE12F2
SE12F3
SE12F4
SE12F5
SOT522
SOT523
SPI12F1
TUR111
TUR112
TUR113
TUR115
TUR116
TUR117
TVW131
TVW132
VAL12F1
Idaho
CGC331
CKF711
DAL131
DAL132
DAL133
DAL134
GRV1271
GRV1272
GRV1273
GRV1274
KAM1291
KAM1292
KAM1293
KOO1298
KOO1299
RAT231
RAT233
SAG741
SPT4S21
SPT4S22
SPT4S23
SPT4S30
Montana
NRC352

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 70 of 88
2017
Washington
CHW12F1
CHW12F2
CHW12F3
CHW12F4
COB12F1
COB12F2
DVP12F1
DVP12F2
ECL221
ECL222
FWT12F1
FWT12F2
FWT12F3
FWT12F4
GLN12F1
GLN12F2
GRN12F1
GRN12F2
GRN12F3
L&R512
LEO611
LEO612
LF34F1
LIB12F1
LIB12F2
LIB12F3
LIB12F4
MEA12F1
MEA12F2
MLN12F1
OTH501
OTH502
OTH503
OTH505
ROS12F1
ROS12F2
ROS12F3
ROS12F4
ROS12F5
ROS12F6
Idaho
BUN422
BUN423
BUN424
BUN426
CRG1260
CRG1261
CRG1263
MIS431
NEZ1267
ODN731
ODN732
ORO1280
ORO1281
ORO1282
PIN441
PIN442
PIN443
POT321
POT322
PRA221
PRA222
PVW241
PVW243
WOR471
SWT2403
WIK1278
WIK1279

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 71 of 88
2018
Washington
3HT12F1
3HT12F2
3HT12F3
3HT12F4
3HT12F5
3HT12F6
3HT12F7
3HT12F8
9CE12F1
9CE12F2
9CE12F3
9CE12F4
ARD12F1
BKR12F1
BKR12F3
C&W12F1
C&W12F2
C&W12F3
C&W12F4
C&W12F5
C&W12F6
CLV12F1
CLV12F2
CLV12F3
CLV12F4
CLV34F1
DRY1208
DRY1209
GAR461
HAR4F1
HAR4F2
KET12F1
MIL12F1
MIL12F2
MIL12F3
MIL12F4
NW12F1
NW12F2
NW12F3
NW12F4
NW13T23
PAL311
PAL312
RDN12F1
RDN12F2
RIT731
RIT732
SPA442
SPU121
SPU122
SPU123
SPU124
SPU125
WAK12F1
WAK12F2
WAK12F3
WAK12F4
Idaho
BIG411
BIG412
BIG413
BLU321
COT2401
COT2402
HUE141
HUE142
LKV341
LKV342
LKV343
LKY551
M15511
M15512
M15513
M15514
M15515
M23621
NMO521
NMO522
OSB522
STM631
STM632
STM633

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 72 of 88
2019
Washington
ARD12F2
BKR12F2
DEP12F1
DEP12F2
DIA231
DIA232
EFM12F1
EFM12F2
H&W12F1
H&W12F2
KET12F2
LAT421
LAT422
LIN711
ORI12F1
ORI12F2
ORI12F3
SUN12F1
SUN12F2
SUN12F3
SUN12F4
SUN12F5
SUN12F6
WAS781
WIL12F1
WIL12F2
Idaho
BLA311
CDA121
CDA122
CDA123
CDA124
CDA125
JUL661
LOL1359
OGA611
OLD721
OLD722
OSB521
PF211
PF212
PRV4S40
SLW1316
SLW1348
SLW1358
SLW1368
SPL361
TEN1253
TEN1254
TEN1255
TEN1256
TEN1257

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 73 of 88
2020
Washington
BEA12F1
BEA12F2
BEA12F3
BEA12F4
BEA12F5
BEA12F6
BEA13T09
F&C12F1
F&C12F2
F&C12F3
F&C12F4
F&C12F5
F&C12F6
FOR12F1
GIF34F1
LL12F1
NE12F1
NE12F2
NE12F3
NE12F4
NE12F5
ODS12F1
OPT12F1
OPT12F2
PDL1201
PDL1202
PDL1203
PDL1204
PST12F1
RSA431
SIP12F1
SIP12F2
SIP12F3
SIP12F4
SIP12F5
SLK12F1
SLK12F2
SLK12F3
SOT521
SPI12F2
SPR761
TKO411
TKO412
VAL12F2
VAL12F3
Idaho
APW111
APW112
APW113
APW114
APW115
APW116
AVD151
AVD152
CKF712
DER651
DER652
HOL1205
HOL1206
HOL1207
IDR251
IDR252
IDR253
JPE1287
JUL662
LOL1266
N131222
N131321
PF213
SAG742
WAL542
WAL543
WAL544
WAL545
WEI1289
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 74 of 88
Distribution Wood Pole Management
2016 2017 2018 2019 2020
SOT522 BEA12F3 APW116 9CE12F1 LIN711
AIR12F3 BEA13T09 ARD12F1 9CE12F2 BLA311
APW114 COT2401 - ID ARD12F2 9CE12F3 CHW12F1
APW115 COT2402 - ID BEA12F4 BLU321 CHW12F2
CHE12F4 DVP12F2 BEA12F6 BLU322 CHW12F3
CLA56 F&C12F3 BIG411 FWT12F2 CHW12F4
L&S12F1 F&C12F4 CFD1210 - WA GIF34F2 EWN241
L&S12F2 F&C12F5 CHE12F1 INT12F1 JUL661
L&S12F3 F&C12F6 CHE12F2 INT12F2 JUL662
L&S12F4 FOR12F1 CMP12F2 LAT421 - WA KAM1291
L&S12F5 FOR2.3 FWT12F4 LAT422 - WA KAM1292
LKV341 IDR253 JPE1287 - ID LTF34F1 KAM1293
LKV342 OTH501 OPT12F1 NE12F5 LEO611
LKV343 PVW243 OPT12F2 PRV4S40 LOO12F2
LOL1359 - ID SIP12F1 OSB521 RSA431 MIS431
MLN12F1 SIP12F3 PST12F1 SPI12F2 ORI12F1
MLN12F2 SOT523 PST12F2 WAK12F1 ORI12F2
NLW1222 - ID SWT2403 - ID SLW1348 - ID WAK12F3 PIN441
SPT4S23 SPA442 - WA WAK12F4 POT321
SPT4S22 RDN12F1
RIT731
RIT732
SPL361
WEI1289
2021 2022 2023 2024 2025
CFD1210 ECL221 9CE12F4 BIG412 BKR12F1
CRG1260 ORO1282 BUN423 BKR12F3 CDA125
DVP12F1 PAL311 BUN426 CRG1261 CRG1263
FWT12F1 PAL312 CLV12F1 DER652 F&C12F2
FWT12F3 PIN443 GRV1274 H&W12F1 HAR4F2
HOL1205 POT322 M15512 H&W12F2 LEO612
HOL1206 RDN12F2 PDL1201 LIB12F3 LIB12F1
NE12F4 SPT4S21 PDL1202 ODS12F1 LIB12F4
PF213 STM631 SE12F1 ORI12F3 M15511
ROS12F3 VAL12F2 SLW1316 ORO1281 MIL12F1
SE12F3 VAL12F3 SOT521 SLK12F3 NEZ1267
SIP12F2 SUN12F1 WAL542 NLW1321
SLW1348 SUN12F3 NMO522
SLW1358 SIP12F5
WOR471 SUN12F6
TUR116
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 75 of 88

2026 2027 2028 2029 2030
AIR12F1 DAL131 CLV12F2 3HT12F4 BIG413
CFD1211 DAL132 CLV34F1 BEA12F5 BKR12F2
DRY1208 DAL134 ECL222 C&W12F1 BUN422
GRV1271 MEA12F2 GRN12F1 CDA121 BUN424
HUE141 MIL12F2 ROK451 CDA122 DRY1209
KOO1298 MIL12F4 TKO411 CDA124 GRN12F2
KOO1299 PF212 TKO412 CLV12F3 GRV1272
OGA611 PRA221 CLV12F4 GRV1273
PDL1203 PRA222 HOL1207 HUE142
PF211 TEN1253 LKY551 KET12F1
WAL543 TUR117 MEA12F1 L&R511
WIK1278 NE12F3 L&R512
WIK1279 SE12F5 LKY552
WIL12F1 TEN1257 NMO521
OSB522
PIN442
PVW241
WAL544
WAL545
2031 2032 2033 2034 2035
3HT12F1 CKF711 NW12F4 AIR12F2 BEA12F1
3HT12F2 CKF712 3HT12F5 CHE12F3 ODN731
3HT12F3 DIA231 3HT12F6 COB12F1 ODN732
CGC331 DIA232 3HT12F7 COB12F2 SPU121
M15514 EFM12F2 APW111 EFM12F1 SPU122
NRC351 HAR4F1 APW112 M15515 SPU123
ROX751 KET12F2 C&W12F2 MIL12F3 SPU124
SLW1368 LL12F1 C&W12F3 STM633 SPU125
SUN12F2 LOO12F1 C&W12F4 SUN12F4 TEN1254
TUR113 PDL1204 C&W12F5 SUN12F5 TUR111
STM632 C&W12F6 TUR115
NE12F2 VAL12F1
NW12F1
NW12F3
SPT4S30
WAK12F2
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 76 of 88
Grid Modernization

2016 Grid Modernization Plan
Feeder Design Constr State Region Area
BEA12F1 x WA West Spokane
M23621 x ID South Pullman/Mosc
MIL12F2 x x WA West Spokane
MIS431 x WA East Kellogg
ORO1280 x ID South Grangeville
PDL1201 x WA South Lewiston/Clark
RAT231 x ID East Coeur d'Alene
RAT233 x x ID East Coeur d'Alene
SPI12F1 x x WA West Colville
SPR761 x WA West Othello
TUR112 x WA South Pullman/Mosc
WAK12F2 x WA West Spokane

2017 Grid Modernization Plan
Feeder Design Constr State Region Area
2016 Carryover x x
F&C12F1 x WA West Spokane
M15514 x ID South Pullman/Mosc
MIL12F2 x WA West Spokane
MIS431 x WA East Kellogg
ORO1280 x
PDL1201 x WA South Lewiston/Clark
RAT233 x x ID East Coeur d'Alene
SPI12F1 x WA West Colville
SPR761 x x WA West Othello
TUR112 x x WA South Pullman/Mosc

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 77 of 88
2018 Grid Modernization Plan
Feeder Design Constr State Region Area
2017 Carryover x x
BEA12F2 x WA West Spokane
DEP12F2 x WA West Deer Park
F&C12F1 x x WA West Spokane
HOL1205 x WA South Lewiston/Clark
M15514 x ID South Pullman/Mosc
MIL12F2 x ID West Spokane
MIS431 x x WA East Kellogg
TEN1255 x ID South Lewiston/Clark
RAT233 x ID East Coeur d'Alene
SPI12F1 x ID West Colville
SPR761 x WA West Othello

2019 Grid Modernization Plan
Feeder Design Constr State Region Area
2018 Carryover
BEA12F2 x x WA West Spokane
F&C12F1 x WA West Spokane
HOL1205 x ID South Lewiston/Clark
M15514 x ID South Pullman/Mosc
MIL12F2 x WA West Spokane
MIS431 x x ID East Spokane
MLN12F1 x x WA West Deer Park
RAT233 x x ID East Kellogg
SPR761 x WA West Othello
TEN1255 x x ID South Lewiston/Clark
TEN1256 x WA South Lewiston/Clark
TUR112 x WA South Pullman/Mosc
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 78 of 88
Transformer Change-Out Program
TCOP Work Plan Year Program Working Count
2016 GMP 305
2016 TCOP 1027
2016 WPM 180
2017 GMP 459
2017 TCOP 480
2017 WPM 64
2017 Predicted Non Detect TCOP 204
2018 GMP 252
2018 TCOP 14
2018 WPM 138
2018 Predicted Non Detect GMP 5
2018 Predicted Non Detect TCOP 1031

Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 79 of 88
Business Cases

Distribution Wood Pole Management

Investment Name:
Requested Amount Assessments: Duration/Timeframe Indefinite Financial:
Dept.., Area: Strategic:
Owner: Business Risk:
Sponsor: Program Risk:
Category:
Mandate/Reg. Reference: Assessment Score:93
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Customer IRR =
7.42% and avoids
an average of
1,700 additional
events per year
11,172,022$ 530,943$ 5,996,350$ 15
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Status Quo: No Wood Pole
Management
Increase OMT
events by 1,700
events
8,186,361$ -$ 6,834,467$ 25
Alternative 1: Distribution
Wood Pole Management -
20 Year Inspection Cycle
describe any
incremental
changes in
operations
10,712,022$ 530,943$ 5,996,350$ 15
Alternative 2: Distribution
Wood Pole Management -
20 Year Inspection Cycle
with Guy Wire
describe any
incremental
changes in
operations
11,172,022$ 530,943$ 5,996,350$ 0
Alternative 3 Name:
Distribution Wood Pole
Management - 10 Year
Inspection Cycle with Guy
Wire Replacement
describe any
incremental
changes in
operations
17,296,437$ 961,699$ 4,920,632$ 0
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
Previous 21,393,700$ -$ 18,767,986$ 2060
2015 11,500,000$ 10,600,000$
2016 11,200,000$ 543,155$ 4,564,898$ 7,840,000$
2017 14,700,000$ 555,648$ 4,574,638$ 12,000,000$
2018 14,700,000$ 570,094$ 4,588,630$ 15,700,000$
2019 14,700,000$ 584,916$ 4,611,573$ 16,060,000$
2020 14,700,000$ 600,124$ 4,634,631$ 14,700,000$
2021+15,700,000$ 615,728$ 4,657,804$ -$
Total 118,593,700$ 3,469,665$ 27,632,174$ 95,667,986$
ER 2016 2017 2018 2019 2020 Total
2060 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total -$ -$ -$ -$ -$ -$
Asset Maintenance Life-cycle asset management
Distribution Wood Pole ManagementEstimated Total Capital Expenditure
Cox/H. Rosentrater High certainty around cost, schedule and resourcesProgram
NESC - See WPM Compliance Plan for details Annual Cost Summary - Increase/(Decrease)
Annual Cost Summary - Increase/(Decrease)
Year Program
Mandate Excerpt (if applicable):
Additional Justifications:
Any supplementary information that may be useful in
describing in more detail the nature of the Project, the
urgency, etc.
The current WPM program complies with the following part of the National Electric Safety Code: 013, 121, 212 A, 212 B, and 261 A.2
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a
10 year cycle and repairs or replaces wood poles, crossarms, missing lightning arresters,
missing grounds, bad cutouts, bad insulating pins, bad insulators, leaking transformers,
replaces guy wires not meeting current code requirements, and replaces pre-1981
transformers
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a
20 year cycle and repairs or replaces wood poles, crossarms, missing lightning arresters,
missing grounds, bad cutouts, bad insulating pins, bad insulators, leaking transformers,
replaces guy wires not meeting current code requirements on poles replaced by WPM, and
replaces pre-1981 transformers
Associated Ers (list all applicable):
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a 20 year cycle
and repairs or replaces wood poles, crossarms, missing lightning arresters, missing grounds, bad cutouts,
bad insulating pins, bad insulators, leaking transformers, and replaces pre-1981 transformers. Note: does
not cover the additional costs associated with the backlog that is related to new requirements such as
additional grounding and anchor rod replacements.
Distribution Wood Pole Management Program inspects all Electric Distribution Feeders on a 20 year cycle
and repairs or replaces wood poles, crossarms, missing lightning arresters, missing grounds, bad cutouts,
bad insulating pins, bad insulators, leaking transformers, replaces guy wires not meeting current code
requirements on poles replaced by WPM, and replaces pre-1981 transformers
Run wood poles and associated equipment to failure
Glenn Madden (Manager)Business Risk Reduction >5 and <= 10
7.42%
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 80 of 88
URD Primary Cable

Investment Name:
Requested Amount Assessments: Duration/Timeframe 2 Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Project/Program Risk:
Mandate/Reg. Reference: Assessment Score:110
Recommend Project Description: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Customer IRR =
10% and avoids
an average of
600 outages per
year
1,800,000$ -$ -$ 4
Alternatives: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Status Quo: Increase
number of
Outage towards
700 per year
-$ -$ 1,300,000$ 10
Alternative 1: Primary
URD Cable Replacement
Customer IRR =
10% and avoids an
average of 600
outages per year
1,800,000$ -$ -$ 4
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name: Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Timeline Construction Cash Flows (CWIP)
Capital Cost O&M Cost Other Costs Approved
Previous 19,852,679$ -$ -$ 19,852,679$
2012 1,800,000$ -$ -$ 1,982,000$
2013 1,000,000$ -$ -$ 1,000,000$
2014 1,000,000$ -$ -$ 750,000$
2015 1,000,000$ -$ -$ 1,000,000$
2016 1,000,000$ -$ -$ 200,000$
2017 1,000,000$ -$ -$ 500,000$
2018 1,000,000$ -$ -$ 1,000,000$
2019 -$ -$ -$ -$
2020 -$ -$ -$ 800,000$
Total 27,652,679$ -$ -$ 27,084,679$
Milestones (high level targets)
November-11 Project Started December-12 Plant In Service mm/dd/yy open
March-12 Project Plan December-12 Project Complete mm/dd/yy openJune-12 Project Design mm/dd/yy open mm/dd/yy open
March-12 Major Procurement mm/dd/yy openSeptember-12 Construction Start mm/dd/yy open
Current ER 2054
Mandate Excerpt (if applicable):
Additional Justifications:
Cost Summary - Increase/(Decrease)
MH - >= 9% & <12% CIRRLife Cycle ProgramsOperations improved beyond current levelsERM Reduction >5 and <= 10High certainty around cost, schedule and resources
Describe other options that were considered
Complete the replacement of the un-jacketed first generation of Primary URD cable
Associated Ers (list all applicable):
Cost Summary - Increase/(Decrease)
Number of Primary URD Cable faults would increase and the cost to repair the
cable would also increase. Without this work and the past 4 years of work,
the increased O&M costs would sum up to $8.8 million over the next 5 years.
Complete the replacement of the un-jacketed first generation of Primary URD
cable
Describe other options that were considered
Jason ThacksonProject
n/a
Primary URD Cable Replacement 2013$1,800,000
Asset Management & Process ImprovementYear Project
Kevin Christie
Milestones should be general. In some cases it may be as simple as project start,
project complete. Use your judgementon project progress so that progress can be
measured.
0 2 4 6 8 10 12 14
Replace Old URD Cable
Time (Months)
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 81 of 88
Transformer Change Out Program

Investment Name:
Requested Amount Assessments: Duration/Timeframe 25 Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:89
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
When
completed save
an average of
5.6 MW per
hour and
eliminate PCB
environmental
risks
5,800,000$ 105,000$ -$ 3
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a 4,500,000$ 200,000$ 900,000$ 12
Alternative 1: Transformer
Change-Out Program
When
completed save
an average of
5.6 MW per
hour and
5,800,000$ 105,000$ -$ 3
Alternative 2:200,000$ -$ -$ 0
Alternative 3 Name: -$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER 1003
Capital Cost O&M Cost Other Costs Approved 2060
2535
2012 7,000,000$ 100,000$ -$ 6,000,000$
2013 7,200,000$ 102,000$ -$ 2,924,015$
2014 5,800,000$ 105,000$ -$ 3,944,000$
2015 5,800,000$ 107,000$ -$ 3,750,000$
2016 5,800,000$ 110,000$ -$ 2,200,000$
2017 1,100,000$ 1,900,000$
2018 1,700,000$
Total 32,700,000$ 524,000$ -$ 22,418,015$
Mandate Excerpt (if applicable):
Additional Justifications:
Asset Management & Process Improvement Life Cycle Programs
Distibution Transformer Change-Out Program
7,000,000$ Year Program Medium - >= 5% & <9% CIRR
Glenn Madden (Manager) & Al Fisher (Dir)Operations require execution to perform at current levelsDon Kopczynski ERM Reduction >5 and <= 10
Program High certainty around cost, schedule and resources
n/a Annual Cost Summary - Increase/(Decrease)
The Distribution Transformer Change-Out Program has three main drivers. First, the pre-1981 distribution
transformers that are targeted for replacement average 42 years of age and are a minimum of 30 years
old. Their replacement will increase the reliability and availability of the system. Secondly, the
transformers to be replaced are inefficient compared to current standards and their replacement will result
in energy savings. Thirdly, pre-1981 transformers have the potential to have pcb containing oil. The
transformers to be removed early in the program are those that are most likely to have pcb containing oil
and their replacement will reduce the risk of pcb containing oil spills which are a safety, environmental,
and a public relations concern.
Annual Cost Summary - Increase/(Decrease)
No planned replacement program for distribution transformers. Substancially
higher risk of a pcb containing oil spill occuring.
The Distribution Transformer Change-Out Program has three main drivers.
First, the pre-1981 distribution transformers that are targeted for replacement
average 42 years of age and are a minimum of 30 years old. Their
replacement will increase the reliability and availability of the system.
Secondly, the transformers to be replaced are inefficient compared to current Distribution Engineering has proposed that any pole that the TCOP does work
on needs to have the guy replaced with the new standard guy insulator (fiber
cable).
Associated Ers (list all applicable):
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 82 of 88
Area and Street Light

Investment Name: Street Light Management
Requested Amount $475,000 Assessments: Duration/Timeframe Indefinite 2014 Financial:
Dept.., Area: Operations Strategic:
Owner: Al Fisher Business Risk:
Sponsor: Don Kopczynski Program Risk:
Category: Program
Mandate/Reg. Reference: n/a Assessment Score:89
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
7.92%475,000$ (250,000)$ (750,000)$ 8
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program:
Continue maintaining the
street lights as failures
occur
6.29%
2 - S3 event in
10 years
-$ 1,500,000$ 1,800,000$ 16
Alternative 1: 7.92%
1.5 - S3 event in
10 years
475,000$ (250,000)$ (750,000)$ 8
Alternative 2: 7.28%
1 - S3 event in
10 years
890,000$ (250,000)$ (1,175,000)$ 12
Alternative 3:7.82%
1 - S3 event in
10 years
895,000$ (250,000)$ (1,165,000)$ 12
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
Previous -$ -$ -$ -$ New ER
2013 -$ -$ -$ -$
2014 475,000$ (250,000)$ -$ -$
2015 484,500$ (500,000)$ -$ 2,400,000$
2016 494,190$ (750,000)$ -$ 1,500,000$
2017 504,074$ (1,000,000)$ -$ 1,500,000$
2018 -$ -$ -$ 1,500,000$
2019 -$ -$ -$ 1,500,000$
2020
Total 1,957,764$ (2,500,000)$ -$ 8,400,000$
ER 2013 2014 2015 2016 2017 Total
New ER -$ 475,000$ 484,500$ 494,190$ 504,074$ 1,957,764$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total -$ 475,000$ 484,500$ 494,190$ 504,074$ 1,957,764$
Associated Ers (list all applicable):
Life-cycle asset management
Moderate certainty around cost, schedule and resources
Annual Cost Summary - Increase/(Decrease)
Annual Cost Summary - Increase/(Decrease)
Mandate Excerpt (if applicable):
Additional Justifications:
Street Light Maintenance Program. This program is a 5 year planned
replacement of bulbs and 10 year planned replacement of photocells. This
alternative has the starterboards running to failure.
Street Light Maintenance Program. This program is a 5 year planned
replacement of bulbs and starterboards and a 10 year planned replacement of
photocells.
Street Light Maintenance Program. This program is a 5 year planned
replacement of bulbs and a 10 year planned replacement of photocells and
starterboards.
Business Risk Reduction >5 and <= 10
7.92%
Street Light Maintenance Program. This program is a 5 year planned replacement of bulbs and 10 year
planned replacement of photocells. This alternative has the starterboards running to failure.
The lights are currently maintained based on customer feedback and/or due to
being noticed by an Avista employee. Many street lights are out for long
periods of time which can put us at risk. We also spend a large amount of
time driving from issue to issue.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 83 of 88
Grid Modernization

Investment Name:
Requested Amount Assessments: Duration/Timeframe Indefinite Financial:
Dept.., Area: Strategic:
Owner: Business Risk:
Sponsor: Program Risk:
Category:
Mandate/Reg. Reference: Assessment Score:133
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
When completed
save an average of
1,970 MWh*
annually & Reduce
Outages
21,000,000$ -$ 198,000$ 4
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a 120,000$ -$ 1,980,000$ 25
Alternative 1: Brief name
of alternative (if
applicable)
When completed
save an average of
1,970 MWh*
annually & Reduce
Outages
21,000,000$ -$ 198,000$ 4
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name: Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
Previous 7,308,357$ -$ -$ 7,308,357$ Dist Grid Modernization 2470
2014 8,686,019$ -$ -$ 9,586,000$ Sandpoint SG 2570
2015 11,000,000$ -$ -$ 12,310,000$ Grid Mod Automation 2599
2016 12,000,000$ -$ -$ 7,000,000$
2017 13,000,000$ -$ -$ 13,000,000$
2018 15,000,000$ -$ -$ 15,000,000$
2019 18,000,000$ -$ -$ 21,000,000$
2020 21,000,000$ -$ -$ 20,800,000$
Total 105,994,376$ -$ -$ 106,004,357$
ER 2015 2016 2017 2018 2019 Total
Dist Grid Modernization -$ -$ -$ -$ -$ -$
2470 11,000,000$ 11,000,000$ 13,000,000$ 15,000,000$ 15,000,000$ 65,000,000$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Sandpoint SG -$ -$ -$ -$ -$ -$
2570 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Grid Mod Automation -$ -$ -$ -$ -$ -$
2599 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total 11,000,000$ 11,000,000$ 13,000,000$ 15,000,000$ 15,000,000$ 65,000,000$
The Dist Grid Modernization Program provides benefits to customers,
employees, and shareholders by replacing problematic poles, cross-arms, cut-
outs, transformers, conductor, etc. In addition, adding switched capacitor
banks and smart grid devices is of benefit due to increased energy efficiency
and system reliability.
Describe other options that were considered
Describe other options that were considered
Troy A. Dehnel Business Risk Reduction >15
6.4% Customer IRR
Mandate Excerpt (if applicable):
WSDOT Target Zero, an FHWA mandated initiative in MAP-21, requires that utilities move all non-breakaway
structures out of the clear zone as defined in the 10/2005 AASHTO "A Guide for Accommodating Utilities Within Highway Right-of-Way. WA State law requires that we complete this task by year 2030.
Additional Justifications:
WAC 468-34-350 - Control Zone Guidelines, WAC 468-34-
300 - Overhead Lines Location, RCW 47.32.130 Dangerous
Objects and Structures as Nuisances, RCW 47.44.010 Wire
and Pipeline and Tram and Railway Franchises - Application -
Rules on Hearing and Notice, RCW 47.44.020 Grant of
Franchise - Condition - Hearing.
Associated Ers (list all applicable):
Distribution Engineering Life-cycle asset management
Distribution Grid ModernizationSee Plan Below
Don Kopczynski High certainty around cost, schedule and resourcesProgram
Federal & State Clear Zone Mitigation Directives Annual Cost Summary - Increase/(Decrease)
The Distribution Grid Modernization Program provides value to customers and shareholders by improving Grid Reliability,
Energy Savings and Operational Ability through a systematic and managed upgrade of our aging distribution system. This
program seeks cost effective opportunities to increase service quality performance and system availability through the
identification of locations that would benefit from the addition of switched capacitor banks, regulators and smart grid
devices. The long-term plan represented by the IRR of 6.4% aims to upgrade 6 feeders per year to cover the whole
distribution system in a 60 year cycle. This coordinates well with Wood Pole Management's 20 year cycle. The average cost
to rebuild each feeder is estimated to be $3.5M.
Annual Cost Summary - Increase/(Decrease)
No systematic plan for wholistic address of conductors, reconfiguring services
for better access, or adding devices that benefit the performance of the
feeder.
Year Program
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 84 of 88
Worst Feeder

Investment Name:
Requested Amount Assessments: Duration/Timeframe on-going Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:84
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Improve the
overall system
performance of
the Company's
"top ten" worst
feeders.
2,000,000$ -$ -$ 12
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: Ten to twenty
rural FDRs
whose SAIFI
exceeds 10
-$ -$ -$ 20
50% funding annual spend
restricted to top
five worst
feeders
1,000,000$ -$ -$ 12
25% funding work plan
restricted to
enhanced
protection
500,000$ -$ -$ 0
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER 2414
Capital Cost O&M Cost Other Costs Approved
Previous 6,000,000$ 5,050,550$
2015 2,000,000$ -$ -$ 1,035,041$
2016 2,000,000$ 1,500,000$
2017 2,000,000$ 2,500,000$
2018 2,000,000$ -$ -$ 2,000,000$
2019 2,000,000$ -$ -$ 2,000,000$
Total 10,000,000$ -$ -$ 9,035,041$
Mandate Excerpt (if applicable):
Additional Justifications:
Engineering/Operations Life Cycle Programs
Underperforming Elec Ckts (Worst FDRs)$2,000,000 Year Program Medium - >= 5% & <9% CIRR
Dave James Operations require execution to perform at current levelsHowell/H Rosentrater ERM Reduction >5 and <= 10ProgramModerate certainty around cost, schedule and resources
Any supplementary information that may be useful in describing in more detail the nature of the Program, the urgency, etc.
n/a Annual Cost Summary - Increase/(Decrease)
Initiating in 2009, ER 2414- "Worst Feeders" was proposed by Asset Management to improve the service
reliability of the Company's worst-performing electric distribution circuits. Many rural feeders significantly
exceed the Company SAIFI target of 2.1. This program is coordinated through divisional Area Engineers to
identify treatment of these feeders. Work plans may include, reconstruction, hardening, vegetation
management, conversion from OH to UG, enhanced protection, and relocation.
Annual Cost Summary - Increase/(Decrease)
Rural area reliability indices expected to worsen as infrastructure ages and
deteriotes. Expect customer contacts to local media and state government
and regulatory bodies.
Funding at $1,000,000 would restrict current treatment to top five worst
feeders.
Funding at 500,000 would restrict treatment to enhanced protection only
(adding midline reclosers, additional fusing)
Associated Ers (list all applicable):
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 85 of 88
Feeder Tie Circuits

Investment Name:
Requested Amount Assessments: Duration/Timeframe on-going Financial:
Dept.., Area: Strategic:
Owner: Business Risk:
Sponsor: Program Risk:
Category:
Mandate/Reg. Reference: Assessment Score:33
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Electric Delivery
Capacity
4,000,000$ -$ -$ 4
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a -$ -$ -$ 16
Alternative 1: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 4
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name: Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
Capital Cost O&M Cost Other Costs Approved
2015 3,735,000$ -$ -$ 3,573,505$ 2514 2515 2516
2016 3,810,000$ -$ -$ 3,810,000$
2017 4,175,000$ -$ -$ 4,175,000$
2018 3,900,000$ -$ -$ 3,900,000$
2019 4,000,000$ -$ -$ 4,000,000$
2020 4,000,000$ -$ -$ 4,000,000$
2021+4,000,000$ -$ -$ -$
Total 27,620,000$ -$ -$ 23,458,505$
ER 2016 2017 2018 2019 2020 Total
2514 2,000,000$ 2,000,000$ 2,000,000$ 2,000,000$ 2,000,000$ 10,000,000$
2515 1,000,000$ 1,000,000$ 1,000,000$ 1,000,000$ 1,000,000$ 5,000,000$
2516 810,000$ 1,175,000$ 900,000$ 1,000,000$ 1,000,000$ 4,885,000$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
0 -$ -$ -$ -$ -$ -$
Total 3,810,000$ 4,175,000$ 3,900,000$ 4,000,000$ 4,000,000$ 19,885,000$
Describe other options that were considered
Describe other options that were considered
Describe other options that were considered
David Howell Business Risk Reduction - None
0.00%
Mandate Excerpt (if applicable):
Avista Distribution Planning Criteria (500 Amp)
Additional Justifications:
This program is a foundational element of the Company's
overall effort to maintain the electric delivery system.
While many of the asset managmeent program such as
WPM, TCOP, Worst Feeders, and Grid Mod are targeted
efforts to maintain reliability, this program specifically
identifies thermal, voltage, and capacity 'tie' constraints.
The program represents the collective effort of distibution
planners and area engineers to manager our ability to serve
customer load, efficiently, and securely.
Associated Ers (list all applicable):
Distribution Engineering Life-cycle asset management
Segment Reconductor & FDR Tie Program$4,000,000/year
Heather Rosentrater Low certainty around cost, schedule and resourcesProgram
n/a Annual Cost Summary - Increase/(Decrease)
The Company's Distribution Grid system includes 18,000 circuit miles of overhead and underground
primary conductors. As load and generation patterns shift, certain areas (segments) of the system become
thermally overloaded. These constrained portions of the system are identified through systematic
planning studies or from operational studyworks conducted by Area Engineers. In addition, FDR 'Tie'
switches are installed to allow load shifts between FDR circuits to balance loads and in response to either
maintenance or forced outages.
Annual Cost Summary - Increase/(Decrease)
Avista's Distribution System Planning criteria (e.g. 500 A Plan) mandates
performance levels for distribution circuits including capacity and voltage
requirements. This program is aimed at maintaining compliance with planning
criteria.
Year Program
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 86 of 88
Network

Investment Name:
Requested Amount Assessments: Duration/Timeframe n/a Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:97
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Investments
necessary to
maintain
current
operations and
to extend the
life of current
assets.
2,300,000$ 348,251$ 215,000$ 6
Alternatives: Performance Capital Cost O&M Cost Other Costs Business Risk Score
Unfunded Program: n/a -$ -$ -$ 25
Alternative 1: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 6
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name: Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER 2058 2237 2251
Capital Cost O&M Cost Other Costs Approved CapX Repl. Metro PILC Post St PILC
Previous 6,750,000$ 6,338,007$
2015 2,300,000$ 348,250$ 215,000$ 2,100,000$
2016 2,300,000$ 348,250$ 215,000$ 2,300,000$
2017 2,300,000$ 348,250$ 215,000$ 2,300,000$
2018 2,300,000$ 348,250$ 215,000$ 2,300,000$
2019 2,300,000$ 348,250$ 215,000$ 2,300,000$
2020 2,300,000$
Total 11,500,000$ 1,741,250$ 1,075,000$ 13,600,000$
CapX Specific O&M O&B
Mandate Excerpt (if applicable):
Additional Justifications:
Engineering Life Cycle Programs
Spokane Elec. Network$2,300,000 annuallyYear Program MH - >= 9% & <12% CIRR
John McClain Operations require execution to perform at current levelsCox/H Rosentrater ERM Reduction >5 and <= 10ProgramHigh certainty around cost, schedule and resources
Service to the core business district in Spokane is afforded a much higher level of service reliability than other urban or rural areas. This reflects the importance of continuous service to hospitals, law
enforcement, city government, banking, legal, commerce, and retail sectors of the local economy.
n/a Annual Cost Summary - Increase/(Decrease)
Avista owns and maintains an underground electric network that serves the core business, financial and
city government district of downtown Spokane from Division Street to Cedar and from Interstate 90 to the
Spokane River. It is operated as a networked secondary system. Most mid to large cities in the United
States operate similar electric grids. The system is configured to allow a single element forced outage
(transformer, cable segment) without impact to customers. Outages can and do occur but those
generally involve substation equipment failures or failures associated with work in progress. Like most
utilities that operate networked secondary systems, Avista uses dedicated cable crew resources
specifically trained to operate, construct, inspect and maintain these systems. All equipment and cables
are located beneath city streets and adjacent properties. Topology in the Network is unique to Avista
electric distribution and requires specialized material, equipment, tooling and training to perform
maintenance repair, planned replacement and capacity growth projects. The scope of annual capital
replacements and additions includes: 7500 feet of secondary cable, 7500 feet of primary cable, 10
refurbished manholes & vaults, 10 tranformer replacements, and 20 street light replacements.
Annual Cost Summary - Increase/(Decrease)
Unfunding Network operations assumes zero PM activities and an eventual
loss system functionality.
Describe other options that were considered
Describe other options that were considered
Describe other options that were considered
Associated Ers (list all applicable):
Various WUTC tariff schedules are associated with customer classifications in downtown Spokane. NESC/WAC govern public and worker safety.
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 87 of 88
Line Protection

Investment Name:
Requested Amount Assessments: Duration/Timeframe On-going Financial:
Dept.., Area: Strategic:
Owner: Operational:
Sponsor: Business Risk:
Category: Program Risk:
Mandate/Reg. Reference: Assessment Score:93
Recommend Program Description: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Investments
necessary to
maintain
current
operations and
to extend the
life of current
assets.
250,000$ 10,000$ 8
Alternatives: Performance Capital Cost O&M Cost Other Costs ERM Risk Score
Unfunded Program: n/a -$ -$ -$ 15
Alternative 1: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 8
Alternative 2: Brief name
of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Alternative 3 Name: Brief
name of alternative (if
applicable)
describe any
incremental
changes in
operations
-$ -$ -$ 0
Program Cash Flows
5 years of costs Current ER
Capital Cost O&M Cost Other Costs Approved 2416 System Wide
2013 250,000$ 5,000$ -$ 250,000$
2014 250,000$ 10,000$ -$ 250,000$
2015 125,000$ 10,000$ -$ 125,000$
2016 125,000$ 10,000$ -$ 125,000$
2017 125,000$ 5,000$ -$ 125,000$
2018 -$ -$ -$ 125,000$
2019 -$ -$ -$ 125,000$
2020 125,000$
Total 875,000$ 40,000$ -$ 1,250,000$
Mandate Excerpt (if applicable):
Additional Justifications:
Describe other options that were considered
Describe other options that were considered
Associated Ers (list all applicable):
This program was funded for a 2-year period in the 2009-2010 timeframe. This request allows for completion of the Chance cutout replacements but also includes the installation of devices on unfused
laterals.
Avista's Electric Distribution system is configured into a trunk and lateral system. Lateral circuits are
protected via fuse-links and operate under fault conditions to isolate the lateral minimize the number of
affected customers. Engineering recommends treatment of the following: 1. Removal and replacement of
Chance Cutouts 2. Removal and replacement of Durabute cutouts 3. Installation of cut-outs on unfused
lateral circuits. This is a targeted program to ensure adequate protection of lateral circuits and to replace
known defective equipment. The Chance fuse cutout devices are porcelain cutouts prone to mechanical
failure at a much higher failure rate than peer group devices when manually operated by line craft
personnel during various line switching scenarios. This presents a significant hazard to line personnel as
Annual Cost Summary - Increase/(Decrease)
Describe other options that were considered
Dave James Operations require execution to perform at current levelsCox/H. Rosentrater ERM Reduction >5 and <= 10ProgramModerate certainty around cost, schedule and resources
Engineering Life Cycle Programs
Distribution Line Protection875,000 5-yearsYear Program MH - >= 9% & <12% CIRR
n/a Annual Cost Summary - Increase/(Decrease)
Exhibit No. 8
Case nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 2, Page 88 of 88
Substation System Review Asset
Management

2016
David Thompson
Rodney Pickett
Rubal Gill
Februar 12, 2016
Substation System Review
Asset Management
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 1 of 31
i
Substation System Review, 2016
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 2 of 31

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 3 of 31

iii
Substation System Review, 2016

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 4 of 31

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 5 of 31

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 6 of 31
1
Substation System Review, 2016
Purpose
This report provides summary information relating to the annual review of Avista’s electric
substations operating in its Washington and Idaho service territory. The intent is to present a
comprehensive overview of the substation capital assets, performance, risks, ongoing asset
management programs, current and planned projects, and summary recommendations. Asset
Management Plans are intended to serve a general audience from the perspective of long-term,
balanced optimization of lifecycle costs, system performance, and risk management. A consistent
sequence of asset management plans will provide the continuity required for continuous
improvement of capital asset management, as well as historical information useful for rate case
submissions.
With Avista’s implementation of IBM’s Maximo as its Asset Information System in 2014, a distinct
reference point for asset data has been established. The Maximo implementation provides a
comprehensive informational and historical repository for all asset data, applications, locations,
inspection history, maintenance activity, and life cycle status. As such, the reportable data
included in this report centers around activities in 2014 and 2015 in order to leverage the reference
data within Maximo and to provide consistent and repeatable data from a single source for this
and future reports.
Avista Utilities currently operates 162 substations consisting of:
21 transmission substations
30 transmission substations with distribution
109 distribution substations
2 foreign-owned substations.
In addition, there are 14 locations associated with generation.
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 7 of 31

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

Figure 1: Substation Age Distribution

Substations are typically classified by voltage and function. The number of sites in each of these
categories is included in Figure 2. In addition to the standard population of 230kV and 115kV
substations, Avista continues to operate six substations at lower system voltages. These include
the Kooskia substation at 34kV, the St. John substation at 24kV, and four substations at 13kV
including Coeur d’Alene Shaft Mine, Sunshine Mine, and two at the Washington State University
campus in Pullman.
0
2
4
6
8
10
12
19
4
1
19
4
9
19
5
5
19
5
7
19
5
9
19
6
4
19
6
6
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6
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7
0
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7
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7
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0
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20
0
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0
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7
20
0
9
20
1
2
20
1
6
Su
b
s
t
a
t
i
o
n
s
Substation Age Distribution

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 8 of 31

3
Substation System Review, 2016

Figure 2: Substations by classification

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

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

139
17
1 1 4
Number of Substations by Voltage
115kV
230kV
34kV
24kV
13kV

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 9 of 31

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

Substation Asset Management Capital Maintenance
The Substation Asset Management Capital Maintenance program installs, replaces, or upgrades
substation apparatus based on Asset Management planning or emergency replacement
determinations. All obsolete, end-of-life, or failed apparatus, based on the Asset Management
analysis, are included under this program. Apparatus includes panel houses, high voltage
breakers, relays, metering, surge arresters, insulating rock, fence work, low voltage breakers and
reclosers, circuit switchers, SCADA systems, batteries and chargers, power transformers, high
voltage fuses, air switches, capacitor banks, autotransformer diagnostic equipment, step voltage
regulators, and instrument transformers.
Substation Capital Spares
The Substation Capital Spares program maintains Avista’s inventory of power transformers and
high voltage circuit breakers in order to manage the long lead time of the procurement cycle for
these system-critical items. These components are capitalized at receipt and placed in service in
response to both planned and emergency installations. The program expenditures may vary
significantly year to year due to the specific equipment purchased and deployed in any given year.

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 10 of 31

5
Substation System Review, 2016
Distribution Substation Rebuilds
The Distribution Substation Rebuild program supports either the complete replacement or rebuild
of existing substation infrastructure as the site nears the end of its useful life, a need to support
increased capacity requirements, or to implement modifications necessary to accommodate
equipment upgrades. Included in the program are Wood Substation rebuilds as well as upgrades
to substations to comply with current design and construction standards. Some substation
rebuilds are necessitated by external requirements, including obligation to serve, customer or load
growth, or technology improvement projects such as Smart Grid. Substation rebuilds currently
planned to be completed under this program in the next five years include Big Creek, Kamiah,
and South Lewiston (Wood Substations), 9th & Central, Ford, Sprague, Davenport, and Northwest
(Lifecycle), Deer Park, Gifford, Lee & Reynolds, Huetter, Dalton, and Southeast (Equipment
Additions), and Hallett & White (Growth).
Garden Springs Substation Integration
The Garden Spring Substation Integration project will construct a new 230kV/115kV substation at
the existing Garden Springs property that will terminate the existing Airway Heights-Sunset,
Sunset-Westside, and South Fairchild Tap 115kV transmission lines. Options being considered
to energize the 230kV bus include the possibility of a new interconnection with the BPA Bell-
Coulee #5 230kV transmission line and a new 230kV feed from the Westside Substation following
the completion of the Westside Substation Rebuild Project. Both of the newly designated Garden
Springs-Sunset 115kV transmission lines will require upgrades to 150MVA capacity conductors.
New Distribution Substations
The New Distribution Substation program provides for new distribution substations in the system
in order to serve new and growing load, increased system reliability, and operational flexibility.
New substations under this program will require planning and operational studies, justification,
and approved Project Diagrams prior to funding. Current plans for new substation projects include
Tamarack in northeast Moscow, Greenacres in the Spokane Valley, and Hillyard and Downtown
West in Spokane. Design and construction phases will be coordinated to achieve one new
substation per year depending on need and justification.
Noxon Switchyard Rebuild
The existing Noxon Rapids 230kV Switchyard requires reconstruction due to the age and
condition of the equipment within the station. The existing bus, constructed as a strain bus with
a number of recent failures, is configured as a single bus with a tie breaker separating the East
and West bus segments. This station is the interconnection point of the Noxon Rapids
Hydroelectric generation as well as a principal interconnect point between Avista and BPA. As
such, this is a crucial asset for the reliable operation of the Western Montana Hydro Complex.
Equipment outages within the station, either planned or unplanned, can cause significant
curtailments of the local generation output. Due to the key role of the station, a complete rebuild
will require coordination with Avista’s Energy Resources Department and affected utilities,
including BPA. The Noxon Switchyard Rebuild Project is a greenfield design incorporating a

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 11 of 31

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 12 of 31

7
Substation System Review, 2016
ER Project
Capital
Expenditure Status
2532 Noxon 230kV Substation Rebuild $10,162,871 Partial in 2016
2000 Substation - Capital Spares $3,267,594 Ongoing
2589 Mobile Substation - Purchase New Mobile Substations $2,539,571 2015
2443 Greenacres 115kV/13kV Substation New Construction $1,661,927 2016
2215 Substation Asset Management Capital Maintenance $915,677 Ongoing
2001 System - High Voltage Circuit Breaker Replacements $580,324 Ongoing
2278 Replace Obsolete Reclosers $530,128 Ongoing
2484 Moscow 230kV Substation Rebuild Switchyard $527,614 Complete
2275 Rock and Fence Restoration $450,226 Ongoing
2449 System - Substation Air Switches Replacements $447,733 Ongoing
1006 System - Distribution Power Transformers $394,856 Ongoing
1107 Lewiston Mill Road - 115kV substation construction $369,980 2015
2493 Replace/Upgrade Voltage Regulators $343,358 Ongoing
2446 Irvin Substation- New Construction $296,734 Ongoing
2590 Deer Park 115kV Substation - Minor Rebuild $247,956 2016
1108 Hallett & White Substation Expansion $142,621 Ongoing
2294 System - Batteries $140,538 Ongoing
2546 Blue Creek 115kV Rebuild $104,669 Complete
2592 Sprague 115kV Substation Minor Rebuild $96,304 2016
2204 Wood Substation Rebuilds $89,274 Ongoing
2571 Clearwater 115kV Substation Upgrades $85,695 Complete
2573 Little Falls 115kV Substation Rebuild $66,485 Ongoing
2341 Ninth & Central Substation - Increase Capacity and Rebuild $54,960 In progress
2569 Gifford 115kV - Rebuild Substation $28,251 Ongoing
2538 College & Walnut Substation Yard Expansion $27,473 2016
2425 System - High Voltage Fuse Upgrades $25,135 Ongoing
2112 Beacon 230kV Substation Bus Conversion $14,286 Ongoing
2505 System-Replace Current and Potential Devices $13,262 Ongoing
2531 Westside 230kV Substation Rebuild $12,598 In progress
2274 New Substations $11,088 Ongoing
2561 Lewiston Mill Road 115kV Substation $8,912 2016
2343 System - Replace/Install Substation Structures $8,702 Ongoing
2336 System - Replace Distribution Power Transformers $7,939 Ongoing
2572 Noxon Construction Substation - Minor Rebuild $2,471 Complete
2591 Davenport 115kV Substation - Minor Rebuild $2,275 Ongoing
Table 3: Substation Capital Expenditures – 2015

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 13 of 31
8
Substation System Review, 2016
Maintenance and Operations (M&O) Spending
During 2015, a total of nearly $4.7 million supported Maintenance and Operations activities
relating to existing substations. As shown in Figure 3, approximately 85.1% of the maintenance
and operation expenses were associated with planned services, while the remaining 14.9% was
in response to unplanned or reactive activities. Figure 4 shows the total substation maintenance
and operations spending by calendar month throughout 2015.
Figure 3: Substation M&O Expenditures
Figure 4: Substation M&O Expenditures by Month
$3,987,826
$696,282
Substation M&O Expenditures-2015
Planned
Unplanned
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 14 of 31
9
Substation System Review, 2016
Substation maintenance activities are tracked by both distribution and transmission tasks. As
noted earlier, many of the substation locations provide both distribution and transmission services.
For 2015, the allocation between transmission and distribution expenses, both maintenance and
operations, along with unplanned expenditures, are shown in Figure 5.
Figure 5: Substation M&O Comparison
Key Performance Indicators
Key Performance Indicators (KPIs) have been identified for tracking and review of key activities.
These KPIs continue to be refined relative to the metrics monitored. The metrics are published
on a monthly basis, providing a perspective about the implementation and use of Maximo, system
reliability, and progress towards particular key project goals as linked to substation performance.
A combination of lagging and leading indicators are tracked in order to provide both retrospective
and prospective views. It is generally expected that the proper focus on the correct leading
indicators will guide satisfactory results after a defined lag period. When this does not occur,
deeper investigation and root-cause analysis may help to identify other factors affecting the
expected causal relationship.
One of the primary goals of Asset Management is to optimally manage risk and performance
relative to capital investment and maintenance expenditures. The nexus of planned maintenance
and capital replacement activity compared to emergency repair costs, outages, lost profits and
other possible outcomes over time should be clearly identified. Additional reviews of predicted
activity versus actual outcomes for a variety of scenarios should also serve to help determine the
continuation of or adjustment to ongoing programs and projects. The availability of sufficient
reliable data to support these analytic opportunities continues to be a challenge, but is expected
to be mollified as the Maximo implementation and structured use becomes integrated into the
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 15 of 31

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

Figure 6: KPI-Reactive Work Orders

0%
10%
20%
30%
40%
50%
60%
70%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Reactive Work Orders (Completed and Active)
Projected Actual

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 16 of 31
11
Substation System Review, 2016
Figure 7: KPI-Work Order Average Age
Metrics associated with customer outages due to substation activity are shown in Figure 8
through Figure 11. In 2015, the projected outage metrics, whether time or quantity, have
typically been satisfied, demonstrating the expected reliability of service for the end customer.
Figure 8: Hours of Unplanned Outages
 ‐
 50
 100
 150
 200
 250
 300
 350
 400
 450
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Age (days) (Completed and Active)
Projected Actual
 ‐
 10,000
 20,000
 30,000
 40,000
 50,000
 60,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Substation Customer Hours due to Extended
Unplanned Outages
Projected Actual
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 17 of 31
12
Substation System Review, 2016
Figure 9: Customers Affected by Unplanned Outages
Figure 10: Customer Outage Hours
 ‐
 5,000
 10,000
 15,000
 20,000
 25,000
 30,000
 35,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Number of Customers with Uplanned
Outages (>3 hours)
Projected Actual
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Customer Outage Hours-Substation AM
Projected Actual
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 18 of 31

13
Substation System Review, 2016

Figure 11: Customer Outage Events

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

Figure 12: Equipment Removals due to PCB content

0
100
200
300
400
500
600
700
800
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Customer Outage Events-Substation AM
Projected Actual
0
20
40
60
80
100
120
140
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Equipment Removals due to PCBs
Projected Actual

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 19 of 31

14
Substation System Review, 2016

Figure 13: Power Transformer Replacements

Figure 14: Voltage Regulator Replacements

0
1
2
3
4
5
6
7
8
9
10
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Power Transformer Replacements
Projected Actual
0
20
40
60
80
100
120
140
160
180
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Voltage Regulator Replacements
Projected Actual

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 20 of 31

15
Substation System Review, 2016

Figure 15: Air Switch Replacements

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

Figure 16: Wood Substation Replacements

These final two KPIs evaluate system awareness criteria regarding level of service. The Risk
Action Curve metric in Figure 17 tracks outage event parameters, including frequency and
severity, to signal additional action if the accumulated outage activity requires further review and
analysis. The OMT High Limit in Figure 18 tracks to an acceptable limits of service statistical
metric for outage events.
0
5
10
15
20
25
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Air Switch Replacements
Projected Actual
0
1
2
3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Wood Substation Replacements
Projected Actual

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 21 of 31

16
Substation System Review, 2016

Figure 17: Substation Risk Action Curve

Figure 18: Substation OMT Limit

0
1
2
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Substation Exceeds Risk Action Curve
Projected Actual
0
1
2
3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Substation Exceeds OMT High Limit
Projected Actual

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 22 of 31

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

Programs
Substation PCB Removal
In 2010, an assessment was completed of equipment containing Polychlorinated Biphenyls
(PCBs) within the Avista substation. PCBs are typically a minor constituent of oil within substation
equipment including
 Power transformers
 Oil circuit breakers
 Voltage regulators
 Potential transformers
 Current transformers
 Station service transformers
 Capacitors
 Electromechanical relays.
Under the current process, the substation power transformers have been tested for PCBs and
units with PCB concentrations of greater than 50 ppm are slated for removal. Voltage regulators,
12
12
11
2
2 1
Outage Reason
Equipment
Planned
Company
Animal
Public
Weather

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 23 of 31

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

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

Figure 19: Voltage Regulator Age Distribution
0
20
40
60
80
100
120
140
19
6
7
19
6
8
19
6
9
19
7
0
19
7
1
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7
2
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7
3
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7
4
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7
5
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7
6
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7
7
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7
8
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7
9
19
8
0
19
8
1
19
8
2
19
8
3
19
8
4
19
8
5
19
8
6
19
8
7
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8
8
19
8
9
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0
19
9
1
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9
2
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9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
Voltage Regulator Age Distribution

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 24 of 31

19
Substation System Review, 2016

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 25 of 31

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 26 of 31

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 27 of 31

22
Substation System Review, 2016
Future Projects BI
Reference
North Lewiston 230kV--Install Reactors LS306
Kamiah - Rebuild LS208
Gifford - Add 115/13kV Station to Substations WS201
Westside - Increase Capacity; New Autotransformer SS201
Priest River – Temporary Breaker Install AMS83
Ford - Replace Transformer AMS28
Ford - Install New 12F2 Feeder Position BS202
Waikiki - Grid Modernization - Feeder 12F2 SS542
Priest River - Minor Rebuild - Distribution AMS83
Irvin--New 115kV Switching Station SS904
Hallett & White - Add Capacity SS523
Rathdrum - Grid Modernization - Feeder 231 CS502
Rathdrum - Grid Modernization - Feeder 233 CS502
Juliaetta - Replace MOAS units A-120 and A-173 AMS85
Jaype - Remove and Salvage
Colville - Replace Battery AMS10
Chester - Replace Battery AMS10
Rockford - Replace Battery AMS10
Fort Wright - Replace Battery AMS10
Beacon--Install Serveron DGA on both autotransformers XS903
Ritzville - Replace A-94 MOAS Control Box AMS85
Northwest - Add Fiber Redundancy/Upgrade XS951
Millwood - Add Radios in Yard - 2 Poles
Othello Switching Station - HVP Upgrade 42P09
Clearwater - Upgrade Metering XS801
Clearwater - Replace Battery AMS09
Oden - Replace 115kV Switches AMS85
Bronx - Replace small conductor AMS32
Garfield - Replace HV Fuses AMS80
Clearwater--Microwave Refresh

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 28 of 31

23
Substation System Review, 2016
Future Projects BI
Reference
Beacon - Add Thermal Relays - A-603/A-607 XS002
St. Maries--Install SCADA XS951
Ninth & Central - Rebuild Distribution Sub SS514
S. Lewiston 115--Rebuild station, replace transformers LS207
Ninth & Central - Move lateral line into substation SS514
Moscow City—Upgrade SCADA/Integrate System XS951
Indian Trail - Add Fiber; Upgrade Communications XS951
Northwest - Rebuild SS206
College & Walnut - Replace Breakers A-431 and A-432 AMS32
Davenport - Minor Rebuild BS400
Colville - HVP Upgrade 42P09
Kooskia 115kV--Replace Transformer AMS28
Milan - Replace A-599 MOAS AMS85
N. Moscow - Install A-369 MOAS AMS85
Warden - Replace Breakers AMS32
Warden - Install SSVT for Station Service XS905
Otis Orchards – Install SSVT for Station Service XS905
Beacon--Upgrade SCADA/Integration System XS951
Clearwater--Upgrade Relaying AMS07
St. Maries - Install 115kV Arresters AMS81
O'Gara - Install 115kV Arresters AMS81
Lee & Reynolds--Add Transformer #2 AMS28
Upriver--Replace/Upgrade Metering XS801
Dry Gulch--Replace/Upgrade Metering XS801
Cabinet - Install substation fuses/Lighting circuits AMS80
Clearwater - Replace/Upgrade SCADA XS951
Little Falls – Rebuild BS304
Tenth & Stewart--Station Upgrades/Rebuild LS202
Valley - Rebuild Substation WS402
Sunset - Rebuild Substation SS890

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 29 of 31

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

System Planning Projects
There is considerable opportunity for more collaboration between Asset Management and System
Planning on capital asset risk assessments, analyses and development of long-term asset
management plans, where overlaps and synergistic opportunities present themselves. Risk is
equivalent to the product of the probability and the consequence of a given event.
Currently, there are no substation System Planning projects that are covered by Asset
Management.

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 30 of 31

25
Substation System Review, 2016
Reference and Data Sources
Various information and data sources were used to compile the information for this report. As
referenced in the Purpose introduction, the emphasis was placed on Avista’s Maximo
implementation for all inventory and date-specific asset details. This process will provide a
tracking database for repeatable historical references, trending, and accurate data snapshots as
the system continues to be deployed and data capture processes refined.
Other sources include Availability Workbench simulations, the legacy Major Equipment Tracking
System (METS), Outage Management Tool (OMT) data, substation engineering files, substation
engineering SharePoint site, and the substation Projects and Capital Budget spreadsheets.

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 3, Page 31 of 31

2016
Mary Jensen, Rubal 
Gill 
Asset Management      
Avista Corp. 
02‐01‐2016 
Electric Transmission System
2016 Asset Management Plan

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 1 of 61

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 2 of 61

3 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

Figure 1:  Example Transmission Asset Components and Expected Service Life .................................................. 10 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 3 of 61

4 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

Table 1:  Primary Assets of the Electric Transmission System – Circuits ................................................................ 9 
Table 2:  Component Assets and Quantities ........................................................................................................... 9 
Table 3:  Transmission Structures and Poles ......................................................................................................... 10 
Table 4:  115kV vs 230kV Pole Materials .............................................................................................................. 11 
Table 5:  Transmission KPIs and Unity Box Metrics ............................................................................................... 12 
Table 6:  Additional Performance Measures, 2010‐2015 ..................................................................................... 13 
Table 7:  Levelized Replacement Spending Options ............................................................................................. 16 
Table 8:  2015 Transmission Spending .................................................................................................................. 17 
Table 9:  2015 Planned Capital Projects (Non‐Reimburseable) ............................................................................ 17 
Table 10:  30‐year Planned Capital and O&M Recommendations ........................................................................ 19 
Table 11:  Probability Index Criteria and Weightings ............................................................................................ 21 
Table 12:  Consequence Index Criteria .................................................................................................................. 22 
Table 13:  Top 20 Most at Risk Circuits according to the Reliability Risk Index .................................................... 23 
Table 14:  Transmission Unplanned and Emergency Spending, 2006 ‐ 2015 ....................................................... 25 
Table 15:  Transmission lines with the most unplanned outages in 2014 ............................................................ 27 
Table 16:  Transmission lines that caused the most customer hours lost in 2015 ............................................... 27 
Table 17:  Transmission Lines causing the most customer outages greater than 3 hours in 2015 ...................... 28 
Table 18:  Transmission Outage Causes, 2009‐2015 ............................................................................................. 29 
Table 19:  Major Rebuild Projects, 2016 – 2020 ................................................................................................... 31 
Table 20:  Minor Rebuild and Switch Upgrade Budget, 2016 – 2020 ................................................................... 32 
Table 21:  Airswitch Priority List for Repairs and Replacements .......................................................................... 35 
Table 22:  Program Ranking Criteria ..................................................................................................................... 41 
Table 23:  Avista Transmission Lines Replacement Capital Spending per Asset ................................................... 43 
Table 24:  Transmission Asset Data Integrity ........................................................................................................ 46 
Table 25:  Relative Material Purchases, 10/2010 – 10/2012 ................................................................................ 47 
Table 26:  Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) ...................................... 49 
Table 27:  Corrective System Planning Projects (Palouse, Spokane and System) ................................................. 50 
Table 28:  Non‐Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) .............................. 51 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 4 of 61

5 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 5 of 61

6 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Purpose 
System asset management plans are meant to serve a general audience from the perspective of long‐term, 
balanced optimization of lifecycle costs, performance, and risk management.  The intent is to help the reader 
become rapidly familiar with the system’s physical assets, performance, risks, operational plans, and primary 
replacement and maintenance programs.  Consistent annual updates of this plan provide the continuity 
required for useful historical information and continuous improvement of asset management practices. 
For easy reference, a “Quick Facts” sheet is used to highlight key information and recommendations of this 
system‐level asset management plan.  At the individual program and project level, additional “Quick Facts” 
sheets may also be available.  For more details, please visit the Asset Management Sharepoint site at Asset 
Management Plans.  This update reflects the best available information as of December 31, 2015.   
Executive Summary 
Consistent with last year’s assessment, the primary message of this asset management plan is that the 
company must commit itself to sustainably replace the bulk of the aging transmission system over the next 
three decades.   This is essential to achieve the company’s strategic objectives of maintaining reliability levels 
while minimizing total lifecycle costs, requiring over $624 million in capital replacement investment.  As this 
represents a significant increase in capital investment as well as internal and external workloads from recent 
years, success demands strong company support and management.  In order to be most effective and 
beneficial to customers and the company, it also requires fact‐based prioritization and targeting of available 
funds to the riskiest elements of the system.  
Key performance indicators (Table 5) for the transmission system showed results lower than targeted for 2015.  
Completed ground inspections were lower than planned and aerial inspections were on‐track.  Aging 115kV 
pole replacements were 80% below target, while aging 230kV pole replacements were 37% above target.  
Customer outages were 97% higher than targeted, while emergency spending was 50% higher than targeted.  
Finally, the follow‐up repair backlog increased, ending the year with five category 4 items overdue and the 
oldest item in the backlog at 35 months.  Much of this may be due to improved identification and tracking 
methods that were recently implemented. 
Replacement budget recommendations remain relatively unchanged at $12 million for 115kV and $9 million 
for 230kV.  Planned budgets for 2016 and 2017 are relatively close to this recommendation.  Additional 
mandated, growth and reimbursable capital projects, as well as O&M work puts the total planned budget for 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 6 of 61

7 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Transmission Engineering at approximately $25 million for 2016, and is expected to remain at this level or 
increase for many years.  This output level is nearly triple that of just a few years ago, while dedicated staff 
have only increased from five to six in the transmission engineering group.  In order to reduce operational 
risks, it is strongly recommended that management consider assigning additional dedicated staff members, as 
well as proper equipment for safe and effective fieldwork. 
Outages and unplanned spending was $2 million in 2015 , mostly as the result of a severe winter wind storm 
that raised overall unplanned spending on the 230 kV and 115kV systems by $700k.   
Notable achievements in 2015 include: 
1. Design and project management of an expanded number of mandated and system planning projects 
including LiDAR mitigation, at $16.4 million in 2015 compared to $7.5 million in 2014. 
2. Completion of minor rebuild and LiDAR mitigation on Moscow ‐ Orofino 230kV, Devil’s Gap – Stratford 
115 kV, and Noxon – Hot Springs 230 kV 
3. Total rebuild on Bronx – Cabinet 230 kV, tie line to the new Noxon reactor, and structure replacement 
projects on Benewah‐Moscow 230 kV and Devils Gap‐Lind 115 kV.   
4. Approved 2015 budget closely matching the recommended replacement budget of $12 million for 
115kV and $9 million for 230kV.   
5. Effective transition of administrative maintenance work from departing staff, as well as hiring and 
productive output of new engineering staff. 
6. Published a comprehensive set of construction standards for transmission engineering and effectively 
integrated the use of PLS‐CADD software.  Consistently using both as a baseline for continuous 
improvement, as a collaborative team effort.  
7. Confirmation of system pole data including material and location, allowing for detailed expected 
service life information on each transmission line. 
8. Began simulation studies for Lolo – Oxbow 230kV and Noxon – Pine Creek 230kV circuits. 
9. In cooperation with other utilities, continued a major project to determine best design, construction, 
inspection and maintenance of self‐weathering steel structures. 
Beyond execution of approved construction, below is a list of recommended initiatives to further improve 
the long‐term performance and stewardship of transmission assets. 
1. Provide additional dedicated staff as appropriate, to handle long‐term increased workloads in the 
Transmission Engineering group and support processes.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 7 of 61
8 2016 Electric Transmission System Asset Management Plan
Sharepoint ‐ Asset Management Plans 
2.Engage asset stakeholders within each major region of the transmission system in order to develop
a comprehensive, prioritized capital project plan for the next 20 years.
3.Continue improving the transmission construction standards to reflect best practices in design and
construction work.  Engage line crews and regional staff.
4.Monitor the lead time for as‐built construction updates to AFM, Plan and Profile (P&P) drawings,
and the engineering vault files, with a target of six months.  Carry out periodic quality audits of
construction in the field and recorded data.
5.Develop a comprehensive inspection and planned maintenance program for steel transmission
structures.
6.Develop a systematic air switch risk ranking method, replacement schedule, and inspection and
maintenance program.
7.Complete rebuild simulation studies and business cases for Lolo – Oxbow 230kV and Noxon – Pine
Creek 230kV circuits.
8.Determine the risks and appropriate mitigation work resulting from structural loads of distribution
underbuild.
9.Complete a system‐wide simulation study to support optimal Transmission asset inspection
intervals as well as planned and unplanned replacement budget targets, including annual minor vs.
major rebuild budgets.
10.Implement transmission outage software which will allow for accurate and efficient analysis of
outages and causes on each transmission line and aerial patrol inspection software for follow up
tracking.
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 8 of 61

9 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

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

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

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

Table 2:  Component Assets and Quantities 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 9 of 61

10 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

Table 3:  Transmission Structures and Poles 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 10 of 61

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

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

Table 4:  115kV vs 230kV Pole Materials 

Key Performance Indicators (KPIs) 
The table below shows overall KPI results for 2015, which are monitored and recorded on a monthly 
basis throughout the year.  The first four are leading indicators over which we have direct operational 
control.  The final two KPIs are lagging indicators of system performance, which should have a causal link 
to the leading indicators.  In other words, if we consistently execute well as demonstrated by the leading 
indicators, over time we should see satisfactory outcomes as manifested by the lagging indicators, and 
vice versa.  When this does not occur, deeper investigation and root‐cause analysis is justified, as 
something other than the expected causal relationship is potentially at play.    
By these measures, performance was lower than targeted for structural ground inspections.  Aerial 
patrol inspections remained on‐track overall.   System‐wide follow‐up repairs from ground and aerial 
patrol inspections were higher than planned for category 4 and 5 items.  This may be primarily due to 
improved tracking methods.  Aging infrastructure replacement was less than the levelized investment 
required to maintain system reliability over the long term for 115kV, as roughly indicated by the number 
of older poles replaced.  Reliability performance and emergency spending were higher than targeted. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 11 of 61

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

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

Results
1 = Planned/On‐Track
<1 = Better than Planned
>1 = Worse than Planned  
Table 5:  Transmission KPIs and Unity Box Metrics 
It is strongly recommended that $21 million per year over a 30‐year timeframe is allocated for worn‐out 
infrastructure replacements – $12 million for 115kV, and $9 million for 230kV.  As we ramp up 
replacement construction in the years ahead, we expect to meet or exceed these goals.  We will 
continue to replace equipment primarily on the basis of recent inspection and condition assessments, 
however the age and respective service life of the system at a high‐level provides a strong leading 
indicator of long‐term system reliability.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 12 of 61

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

Additional performance measures are tabulated below since 2010: 
Performance Measure Goal 2010 2011 2012 2013 2014 2015 Remarks
Customer‐Hours 
unplanned, extended 
outage due to 
transmission issues        113,142 255,426 64,453 82,908 238,861 200,977 262,949
# of customers of Tx 
related unplanned 
outages greater than 3 
hrs         10,182 16,478 6,644 5,409 17,135 17,609 24,927
Tx emergency repair 
costs $1,321,019 $1,442,969 $1,029,597 $1,409,972 $1,630,943 $3,040,313 $2,180,921
Avista crew safety: # 
recordable injuries 
from Transmission 
work 0 not avail not avail not avail not avail not avail not avail
Unable to 
isolate to 
Transmission
Top 10 worst 
performing 
components ‐ by 
failures NA not avail not avail not avail not avail not avail not avail
Not available 
from OMT data
Top 10 worst 
performing circuits by # 
of component failures NA not avail not avail not avail not avail not avail not avail
Not available 
from OMT data  
Table 6:  Additional Performance Measures, 2010‐2015 
Note that important performance measures currently cannot be evaluated due to inadequate data 
availability.  This includes safety incidents from transmission work, the total number of annual failures 
and respective failure modes for various transmission lines and system‐wide asset components such as 
poles, air switches, crossarms, insulators, splice connections, and so forth.  An ongoing, long‐term effort 
is necessary to make this information available and assimilate into our set of KPIs and circuit risk 
rankings.  It is also essential to taking the next steps in evaluating the benefit and value of asset 
management programs and projects for continuous improvement. 
Capital Replacement and Maintenance Investment 
Levelized replacement spending is the annual spending required to replace the asset category in a 
perfectly level form over the asset’s service life in 2015 dollars, not including inflation.  Prior to adjusting 
for uneven service life profiles, this provides a simple, rough‐cut measure to compare against actual 
replacement spending each year, i.e. the minimum needed to keep up with aging infrastructure that 
places reliability at risk.  This currently stands at $16.3 million per year for the transmission system.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 13 of 61

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

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

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

The next step is to look more closely at the replacement cost of actual installed assets compared to 
remaining service life.  This provides the basis for levelized replacement budgets given actual remaining 
service life profiles, as summarized in the following chart. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 14 of 61

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

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

Figure 3:  Replacement Cost vs. Remaining Service Life 
Note that field assets costing $234 million to replace are currently beyond expected service life, based 
on their age and statistical predictions of mean time to failure (everything to the left of 0 years in Figure 
3 above).  The oldest and greatest quantities of these assets are 115kV transmission lines.  This 
represents a significant risk to the continued reliability of the transmission system, particularly for those 
115kV circuits with more than 10 years past normal service life.   
To address this issue, several alternatives present themselves in terms of long‐term replacement 
policies, as shown in the table below.  The 30‐year replacement period is recommended at $21.1 million 
per year, split between $11.3 million for 115kV and $9.8 million for 230kV.  This policy, when coupled 
with an ongoing, annual risk assessment and targeting of funds, over the long term will effectively 
reduce risks and minimize total lifecycle costs.    
The table below presents a simple levelization that reduces the volatility and operational business risk of 
ramping up and down construction work from year‐to‐year, while responsibly maintaining system 
performance.  Again, it should be emphasized that in order to be most effective, this level of 
replacement spending must be targeted at those assets that pose the greatest overall risk, as discussed 
in the Risk Prioritization section of this report.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 15 of 61

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 16 of 61

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 17 of 61

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

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

Figure 4:  2014 Planned Capital, O&M, and Emergency Spending 
This shows that approximately 92% of spending was planned, vs. 8% unplanned in 2015.  The percent of 
planned work should increase as planned replacements ramp up and unplanned/emergency spending is 
held constant or reduced.  Growth and mandated projects (e.g. LiDAR projects) of $6.3 million resulted 
in 22% of total Transmission spending in 2015.  Although the spending in this category is highly variable 
from year to year, a constant value of $3 million is assumed for the future.  A small increase of 2% per 
year is assumed for reimbursable projects such as road moves.   O&M dollars may be reduced over the 
long‐term, due to expected lower inspection costs of steel poles as they are used to replace existing 
wood poles; however, this was not accounted for as it is somewhat uncertain and represents a relatively 
insignificant sum.  Other figures represent recommendations for planned replacement and maintenance 
programs as specified in the Programs section of this report.  Optimal planned spending may vary 
considerably after making adjustments for actual condition assessments as inspections are completed, 
capturing economies of scale opportunities when rebuilding larger sections of line, and taking into 
account cost of capital considerations from year to year.  Notwithstanding these variables, the numbers 
below represent the minimum recommended investment for consistent, planned transmission work in 
the years ahead.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 18 of 61

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

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 19 of 61

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

Process Capability 
As of 2010, total planned design, project management, and construction capital and O&M work for the 
Transmission system originating from the Transmission Engineering group was less than $10 million per 
year.  At that time, Transmission Engineering had a dedicated staff of five members – one manager, 
three engineers, and one technician – equivalent to roughly $2.0 million per staff member.  In 2015, 
total planned work amounts to $26,665,457 with a dedicated staff of six members – one manager and 
five engineers – equivalent to $4.4 million per staff member.  This represents an output productivity 
increase of 120% in only a few years time.  Hidden workloads such as mandated reporting and analysis 
from regulatory bodies such as NERC are also on the rise.  In order to remedy operational risks and 
achieve management objectives, the need for additional staff, equipment, and improved support 
processes should be considered a very high priority, seriously investigated, and remedied as 
appropriate.     
Other opportunities for improved process capability include reducing overall project lead times, 
particularly from the time of internal project initiation to the beginning of construction, which has 
increased substantially.  Construction timelines and total costs may also be reduced, for example by 
completing line projects in one or two years instead of three to five.   
Continued engagement and integration with internal and contracted line crews to communicate and 
improve construction standards is also recommended as a way to improve overall process capability. 
Risk Prioritization 
According to Wikipedia, risk is defined as  “ . . . 1. The probability of something happening multiplied by 
the resulting cost or benefit if it does.  (This concept is more properly known as the 'Expectation Value' 
and is used to compare levels of risk)”     
‐ from  http://en.wikipedia.org/wiki/Risk 
In mathematical form, this is expressed as:   
Risk/Benefit   ∑(Event Probability)    *  (Event Consequence)      
The transmission system’s major circuits were ranked by this formulation.   The rankings will be used as 
a starting point for further deliberation among internal stakeholders, with the goal of allocating 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 20 of 61

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

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

Table 11:  Probability Index Criteria and Weightings 
The second component of risk (event consequence), we will refer to as the asset’s “Consequence 
Index”.  It is a measure of the severity of consequences should an unplanned failure event occur.  This is 
also a normalized relative score from 1 (low severity = low event consequence) to 5 (high severity = high 
event consequence).  The factors and respective weighting for the Consequence Index are as follows, 
derived from the relative importance of the line in terms of power flow, its effect on the system should 
it become unavailable, the relative time and cost to effect repairs, and potential secondary damage 
based on safety, environmental issues and its proximity to other company and private property.  In the 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 21 of 61

22 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

Table 12:  Consequence Index Criteria 
With these indices in hand, we have the ability to prioritize lines based on comparable risk levels, which 
we refer to as the line’s “Reliability Risk Index”, where 
Reliability Risk Index = (Probability Index) * (Consequence Index) 
This is also normalized from a score of 1 (low risk) to 100 (high risk).  In order to be worthwhile, it is 
essential that the risk index is useful to making practical business decisions.  It must produce credible 
results to a wide variety of experts and decision makers, and it must be reliably reproduced each year 
without a great burden of effort.  Over time, improvement in our ability to collect and use data may 
allow us to evaluate shorter segments of lines with greater ease, providing a refined view of system risk 
at the line segment or even structure level.  This would facilitate a more detailed view of system risks 
and optimized mitigation efforts.  The development and use of aids that help visualize results (e.g. color‐
coded system maps), may also be worthwhile.    
The top 20 highest risk transmission lines are shown in the table below, and the complete list is included 
as Appendix A.  This iteration only includes transmission lines and taps that are longer than one mile.  An 
additional 37 short lines and taps not included in the risk index account for 14.3 additional miles, 
representing less than 0.7% of total Transmission system mileage. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 22 of 61

23 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

Transmission Line Name Voltage (kV) Length (miles) Replacement Value Probability Index Consequence Index Risk Index
Lolo ‐ Oxbow 230 63.41 $45,655,200 85.4 100.0 100.0
Noxon ‐ Pine Creek 230 43.51 $31,327,200 80.5 87.8 82.8
Benewah ‐ Pine Creek 230 42.77 $30,794,400 68.3 87.8 70.3
Walla Walla ‐ Wanapum 230 77.78 $56,001,600 68.4 83.7 67.1
Benewah ‐ Boulder 230 26.15 $18,828,000 67.1 72.9 57.3
Hot Springs ‐ Noxon #2 230 70.05 $50,436,000 66.0 68.8 53.2
Dry Creek ‐ Talbot 230 28.27 $20,354,400 51.4 78.3 47.1
Latah ‐ Moscow 115 51.41 $21,592,200 96.0 41.7 47.0
Devils Gap ‐ Stratford 115 86.19 $36,199,800 100.0 39.0 45.6
Post Street ‐ 3rd & Hatch 115 1.76 $3,696,000 70 100 43
Benewah ‐ Moscow 230 44.28 $31,881,600 61.1 59.3 42.5
Cabinet ‐ Rathdrum 230 52.3 $37,656,000 41.7 86.4 42.3
Bronx ‐ Cabinet 115 32.38 $13,599,600 59.4 55.2 38.4
Metro ‐ Post Street 115 0.5 $1,890,000 60 100 38
Ninth & Central ‐ Sunset 115 8.63 $3,624,600 39.0 75.6 34.7
Burke ‐ Pine Creek #3 115 23.79 $9,991,800 67.0 44.4 34.6
Shawnee ‐ Sunset 115 61.51 $25,834,200 79.0 36.3 33.4
Sunset ‐ Westside 115 10.03 $4,212,600 53.0 53.9 33.2
Hatwai ‐ Lolo 230 8.27 $5,954,400 28.9 93.2 31.6  
Table 13:  Top 20 Most at Risk Circuits according to the Reliability Risk Index 
Note that the two underground 115kV circuits, Post Street – 3rd & Hatch, and Metro – Post Street both 
have a 100 consequence rating and probability ratings of 70 and 60, respectively.  The consequence of 
unplanned outages on these lines is arguably much larger than those of any other line on the system as 
they serve the high density core of downtown Spokane.   In other words, the risks listed above may be 
understated for these two lines.   A strong recommendation for full replacement of both lines is advised 
in the near future – realistically within 5 to 10 years. 
It is important to recognize that the risk index does not yet provide an absolute priority order for 
replacement and maintenance decisions – option costs to reduce risks must first be factored in.  
Specifically, cost option analyses must be performed to determine which project options result in the 
highest reduction of risk per dollar spent.  According to best practice asset management principles, this 
analyses results in a system “Criticality Index” for each line in priority order, where each line would be 
ranked according to: 
Criticality Index = (Original Risk – Residual Risk) / (Option Cost) 
Finally, other opportunities and benefits are factored in, also known as “bundling” in asset management 
parlance, to arrive at a final priority order for replacement and maintenance projects.  These 
opportunities and benefits may come from various areas such as system planning for capacity and 
growth requirements, system operations, regulatory compliance, protection engineering and 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 23 of 61

24 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

communications, operations, and power supply.  After factoring in these priorities, a comprehensive 
replacement and maintenance plan for 20 years may be developed, sequenced according to system 
operations restrictions and with higher levels of detail for projects within the 10 year timeframe.  A good 
start in this direction may be accomplished through the concept of area mitigation plans which involve 
and integrate stakeholders within each major transmission area of the system (e.g. Big Bend, Spokane, 
Lewis‐Clark, etc). 
Ultimately, objective rankings must be useful and effective, helping the organization to arrive at the 
right business decisions with less effort.  Asset management staff will continue to facilitate and support 
this collaborative undertaking, striving for improvement and strong results.   
Unplanned Spending 
Unplanned spending represents capital replacement of those transmission assets that have 
unexpectedly failed and require prompt attention, typically by Avista crews (e.g. storm response 
events).  Despite the variability that is correlated with fluctuations in weather intensity, unplanned 
spending is an especially important lagging indicator of system performance, trends, and the 
effectiveness of asset management programs.  In addition to cost premiums incurred from overtime 
labor, unplanned work typically presents greater safety risks to the public and on‐site Avista employees, 
as well as other risks including property damage, environmental, general liability, planned work delays, 
and additional rework costs following the event.  We have set annual goals at the average of unplanned 
spending from 2009 through 2012, reflecting a desire to maintain system reliability.  This results in 
“targets” of $1.1 million for 115kV and $210k for 230kV, for a total of $1.3 million per year.  Note that in 
past years we have consistently spent a much greater amount of total unplanned dollars on the 115kV 
system, at roughly four times the proportional value of capital assets when compared to the 230kV 
system.  This is consistent with the fact that 230kV assets are felt to pose a higher potential 
consequence should they fail, and therefore we maintain them accordingly – deliberately effecting a 
lower frequency of unplanned events on the 230kV system, relative to 115kV.  While this may be the 
case, it remains that the optimal target of unplanned spending has not been quantitatively determined 
for either system.  This is a desired output from a future system model and analysis, involving the 
quantification and simulation of all significant risks and costs associated with unplanned events, 
maintenance and replacement work.  Note that zero emergency spending is actually sub‐optimal unless 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 24 of 61

25 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

there is zero tolerance for any risk – otherwise, it represents over‐investment in the design 
configuration and actual condition of physical assets. 
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Electric Transmission 115kV and 230kV Total Unplanned Capital Spending from XXX01050 
Account Information
115kV unplanned Tx capital 230kV unplanned Tx capital  
Figure 6:  115kV and 230kV Total Unplanned Capital Spending 
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
115kV - WA 115kV - WA $312,958 $609,438 $265,221 $874,996 $649,760 $585,250 $499,341 $1,123,122 $1,640,237 $1,087,223
115kV - ID 115kV - ID $406,111 $161,470 $221,343 $349,459 $626,503 $274,517 $608,163 $389,492 $437,978 $705,426
115kV - all 115kV - all $719,070 $770,908 $486,564 $1,224,455 $1,276,263 $859,767 $1,107,505 $1,512,614 $2,078,216 $1,792,649
230kV - WA 230kV - WA $215,228 $97,946 $215,416 $57,721 $73,482 $156,491 $58,976 $89,984 $13,286 $116,311
230kV - ID 230kV - ID $74,783 $32,856 $120,056 $89,364 $79,950 $12,979 $228,681 ‐$134,091 $945,631 $259,884
230kV - MT w/ Colstrip
230kV - MT
w/ Colstrip $0 $286,338 $257,879 $249,429 $368,855 $574,428 $298,059 $436,991 $249,307 $402,324
230kV - MT w/o Colstrip
230kV - MT
w/o Colstrip $0 $1,590 $59,590 $27,525 $13,275 $0 $72 $18,910 $0 $12,077
230kV - OR 230kV - OR $12,273 $0 $0 $2,475 $0 $360 $14,738 $9,435 $3,181 $0
230kV - all
230kV - all
w/o Colstrip $302,285 $132,392 $395,062 $177,085 $166,706 $169,830 $302,467 $118,329 $962,097 $388,272
115kV and 230kV (all)
115kV and 230kV (all)$1,021,354 $903,300 $881,625 $1,401,539 $1,442,969 $1,029,597 $1,409,972 $1,630,943 $3,040,313 $2,180,921 
Table 14:  Transmission Unplanned and Emergency Spending, 2006 ‐ 2015 
Total unplanned spending in 2015 was $2.18 million, significantly higher than any year recorded since 
2006 except for 2014, and well above the target of $1.3 million per year.  This was due to a major wind 
storm in November 2015, totaling $700k.     
Unfortunately, the use of 115kV blanket accounts does not allow for ready analysis of unplanned 
spending on individual 115kV circuits.  This is necessary to get a better understanding of risk and asset 
prioritization on a line‐by‐line basis.  New software is in the process of implementation by System 
Operations.  This should be complete by 2016 with annual data available for analysis starting in 2017.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 25 of 61

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 26 of 61

27 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 27 of 61

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

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

Table 17:  Transmission Lines causing the most customer outages greater than 3 hours in 2015 
Overall, the data shows that the 115 kV system is significantly less reliable than the 230 kV system in 
terms of total outages and customers directly affected. 
The causes for customer outages lasting longer than three hours increased for rotten crossarms, 
insulators, switch/disconnect, pole fires, cars hitting poles, and snow/ice events.  These types of outages 
should be monitored closely as surveys indicate that outages lasting longer than three hours are the 
most important reliability factor driving customer satisfaction.  Appropriate steps should be taken to 
prevent these outages in the future and to reduce repair time should an outage occur.  Weather related 
outages caused the most customer‐hours lost per occurrence.   
It should be noted that two lines appear on all three of the ‘worst transmission line’ lists described 
above: 
1. Moscow 230 ‐ Orofino 115 kV 
2. Devils Gap‐Stratford 115 kV 
Extending the above lists to include the worst 20 lines, four other lines would appear on all three 
indices: 
3. Ninth & Central – Otis Orchards 115 kV 
4. Devil’s Gap ‐ Lind 115 kV 
Based on this information, closer monitoring for these lines is warranted.  Moscow 230 – Orofino 115kV 
is scheduled for a minor rebuild in 2016.  Devils Gap‐Stratford 115kV is scheduled for a LiDAR/minor 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 28 of 61

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

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

Table 18:  Transmission Outage Causes, 2009‐2015 
Pole fire related outages continue to dominate both in terms of number of occurrences and customer‐
hour outages.  At over 50,000 hours, pole fires had the highest number of customer‐hour outages.  This 
number is higher than last year (29,000 customer‐hours) and highlights the need to continue the fire 
retardant program and to replace wood poles with steel poles.      
 As can be seen from Figure 5 below,  unplanned, non‐weather and weather events dominate both the 
number of occurances and customer‐hours outages for the transmission lines. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 29 of 61

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

Figure 7:  Transmission outage causes affecting customers in 2015 
Programs 
1.  Major Rebuilds 
Out of the $26,640,457 million in planned capital replacement projects in 2015, $15,420,668 was spent 
on major rebuilds, $3,210,020 on minor rebuilds and $443,619 on switch replacements, for a total of 
$19,074,307.  The recommended level is a minimum of $18.5 million for major rebuilds, $2.0 million for 
minor rebuilds and $264k for switch replacements, for a total of $21 million replacement spending per 
year for 30 years.  As stated previously, replacement projects do not include additional capital projects 
that are mandated, growth related, reimbursable, or otherwise do not address aging infrastructure.  
Furthermore,  the recommended spending is the minimum levelized spending over the entire 30 year 
period, which in the shorter term may need to be increased to minimize lifecycle costs – given 
inspection results, risk analysis, cost of capital, and economies of scale opportunities.  
The most significant major rebuild and reconductor projects currently planned through 2020 are listed 
below, with rough estimates of budget dollars allocated for each year.  Please note that these plans are 
subject to change and projects for 2019 and 2020 in particular are only partially complete. 
0
10
20
30
40
50
60
70
2015
# Oc
c
u
r
a
n
c
e
s
# Occurences Extended Transmission 
Outage by Cause
planned maintenance/upgrade unplanned non‐weather weather
0
50000
100000
150000
200000
250000
300000
350000
2015
Cu
s
t
o
m
e
r
‐ho
u
r
s
 Ou
t
a
g
e
s
Customer‐Hours Extended Transmission 
Outage by Cause
planned unplanned, non‐weather weather

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 30 of 61

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

Description BI Description2 2016 2017 2018 2019 2020
West Plains Trans Reinforcement ST305 Garden Springs ‐ Sunset 450,000$        600,000$       ‐$              ‐$               ‐$              
Pine Creek ‐ Burke ‐ Thompson Falls CT101 Rebuild Transmission 25,000$          3,500,000$    ‐$              ‐$               ‐$              
9CE‐Sunset 115kV Transmission ST503 Reconductor/Rebuild 2,250,000$     ‐$               ‐$              ‐$               ‐$              
High Resistance Conductor Replacement xTxxx Reconductor/Rebuild ‐$                ‐$               ‐$              ‐$               ‐$              
Cabinet‐Noxon 230kV Rebuild AT700 CAB‐NOX Rebuild w/Reconductor ‐$                ‐$               7,500,000$   7,500,000$   ‐$              
Noxon‐Pine Creek 230kV Rebuild KT901 NOX‐PCR Rebuild w/Reconductor ‐$                ‐$               ‐$              ‐$               7,500,000$   
Lolo‐Oxbow 230kV Rebuild LT900 LOL_OXB Rebuild w/Reconductor ‐$                ‐$               ‐$              ‐$               7,500,000$   
Benewah‐Pine Creek 230 kV Rebuild CT908 BEN‐PIN Rebuild w/Reconductor ‐$                ‐$               ‐$              ‐$               ‐$              
Sys‐Rebuild Trans‐Condition AMT81 BRX‐CAB & BRX‐SCR Rebuild 3,600,000$     1,500,000$    4,500,000$   2,500,000$   2,500,000$   
Ben‐Oth SS 115 ‐ ReCond/Rebld FT130 Ben‐Oth SS 115 ‐ ReCond/Rebld 3,000,000$     1,500,000$    ‐$              ‐$               ‐$              
CDA‐Pine Creek 115kV Rebuild CT300 Rebuild Transmission 25,000$          4,000,000$    6,000,000$   5,000,000$   ‐$              
Devils Gap‐Lind 115kV Rebuild ST302 Rebuild Transmission 1,002,134$     2,900,000$    ‐$              ‐$               ‐$              
Chelan‐Stratford 115kV Rebuild BT304 Rebuild Columbia River Crossing ‐$                ‐$               ‐$              ‐$               ‐$              
Addy‐Devils Gap 115kV Reconductor ST306 Recon/Rebld near Ford Substation ‐$                25,000$         2,000,000$   ‐$               ‐$              
Recon/Rebld GDN‐SLK 115kV Line ST304 Recon/Rebld South Fairchild Tap ‐$                ‐$               ‐$              ‐$               ‐$              
Beacon‐Bell‐F&C‐Waikiki Reconfiguration ST318 Reconfiguration into Bell and Waikiki ‐$                25,000$         2,000,000$   ‐$               ‐$              
BEN‐MOS Rebuild w/o Reconductor PT305 BEN‐MOS Rebuild w/o Reconductor 8,684,000$     6,802,393$    ‐$              ‐$               ‐$               
Table 19:  Major Rebuild Projects, 2016 – 2020 
Effort will continue to be applied to prioritize replacement spending according to risk and criticality 
rankings, using detailed analysis where appropriate and engaging various stakeholders to arrive at 
optimized business decisions.  In the last several years, detailed simulation studies have repeatedly 
shown major rebuilds as the optimal rebuild option for those lines with older assets and relatively higher 
risk rankings, rather than sectional or partial rebuilds, or minor rebuild options.  Due to the infrequency 
of conductor failures, unless system planning determines a need or benefit for increased capacity, these 
studies indicate rebuilding structures and re‐using the existing conductor as optimal.  Calculated 
Customer Internal Rate of Return (CIRR) are typically at 8% or higher, with strong business risk reduction 
and final assessment scores of 90 or more, placing them in the top 25% of competing capital project 
business cases across the company.  Accordingly, similar simulation studies in the future are expected to 
generate comparable results, i.e. analysis of old, high risk lines will continue to show major rebuilds as 
the optimal rebuild decision from the standpoint of lowest lifecycle costs, including reduced business 
risk and lowest consequence costs for the customer. 
2.  Minor Rebuilds 
The information collected by aerial patrols is used in conjunction with inspection reports to prioritize 
and budget minor rebuild capital projects, where a major rebuild is not justified.  Our goal is to complete 
repairs and replacements for high‐risk issues from 0 to 6 months after identification by aerial or ground 
inspection, and for all other moderate risk issues by the end of the year following the inspection year.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 31 of 61

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 32 of 61

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 33 of 61

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

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

Thorough investigation of industry best‐practices regarding inspection and planned maintenance of air 
switches, with follow‐up recommendations is recommended.  At minimum, a reasonable condition 
assessment program is envisioned, such as visual inspection at least every two years, possibly annual 
inspection for those more critical switches, and annual performance evaluation based on System 
Operations input.  Below is a prioritized list of switches due for repairs or replacement in the next few 
years, with those switches exhibiting operational problems listed first. 
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
0‐10 10‐20 20‐30 30‐40 40‐50 >50
Re
p
l
a
c
e
m
e
n
t
 Va
l
u
e
Age (Years)
Transmission 115 kV Air Switches 
40 Years Expected Service Life
$750,000 of
Capital 
Assets 
Beyond 
Expected 
Service Life

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 34 of 61

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

SW #Problems Age (yrs) LINE/SUBSTATION
A-70 Problem Switch; Scheduled 2016 84 Chelan-Stratford
A-336 Old KPF, Needs Replaced; Scheduled 2016 49 Grangeville-Nez Perce #1: Cottonwood Tap
A-355 Old KPF on a broken pole; Scheduled 2016 48 Jaype-Orofino
A-346 Wood in Switching Mech. Is bowed; Scheduled 2016 47 Grangeville-Nez Perce #2
A-376 Old KPF, Needs Replaced; Scheduled 2016 43 Grangeville-Nez Perce #2
A-298 Needs whips; Center 0 and North 0 gone, South Bent 38 115kv Boulder-Rathdrum
A-158
Doesn't work properly, drop load on both sides then use
switch, mat ground straps need repair 31 Beacon-Francis & Cedar
A-345 Pole Needs Structure # Tag 30 Grangeville-Nez Perce #2
A-442 Repaired in 2015 26 Dworshak-Orofino
A-377 Scott paper tap; Engerized to Switch; Scheduled 2016 21 Grangeville-Nez Perce #2 : Scott Paper Tap
A-176 Mat ground straps need repair 18 Bell-Northeast
A-679 Difficult to Close 15 Othello-Warden #2
A-680 Replaced in 2015 15 Othello-Warden #2
A-358 Old KPF, Needs Replaced 10 Jaype-Orofino
A-407 Broken Crossarms 4 Grangeville-Nez Perce #1
A-421 Ground Cables and Strands cut, NEEDS REPAIR 4 Ramsey-Rathdrum #1
A-184 Replaced in 2015 61 Shawnee-Sunset
A-19 59 Pine Street-Rathdrum: Oldtown Tap
A-26 59 Burke-Pine Creek # 3
A-220 57 Lolo-Nez Perce
A-221 57 Lolo-Nez Perce
A-173 Replaced in 2015 47 Moscow 230-Orofino
A-58 Replaced in 2015 46 Chelan-Stratford
A-295 Replaced in 2015 46 Benewah-Pine Creek : St Maries Tap
A-49 44 Devils Gap-Stratford
A-126 40 8th & Fancher-Latah 115 kV
A-127 40 8th & Fancher-Latah 115 kV  
Table 21:  Air Switch Priority List for Repairs and Replacements 
Finally, transmission outage cause tracking needs to be improved in order to ascertain failure trends for 
the air switch population and to justify long‐term replacement policy, e.g. improved data for line outage 
durations and affected customers that result from failed air switch operations.  In reading through notes 
on the TOR, Asset Management was able to determine that there were 122 outages from 1975 through 
2007, resulting in an average of 3.7 outages per year caused by switches.  The durations and quantified 
consequences of these outages however are unknown and difficult to model. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 35 of 61

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

4.  Structural Ground Inspections (Wood Pole Management) 
Avista wood transmission structures are predominately butt‐treated Western Red Cedar poles.  Most of 
the service territory is in a semi‐arid climate.  The most common failure mode for wood poles is internal 
and external decay at or near the ground line.  Transmission Wood Pole Management (WPM) measures 
this decay and determines which poles must be reinforced or replaced.  Details describing inspection 
techniques are in the company’s “Specification for Inspection and Treatment of Wood Poles, S‐622”.   
The testing program is valuable in identification of poles needing replacement or reinforcement, as well 
as identifying other structure components requiring repair or replacement.  Compared to the pre‐1987 
method of solely visual inspections for pole integrity, the testing program replaces about 15% as many 
poles.   
Wood transmission poles are on a 15‐year inspection cycle.  We are currently targeting inspection of 
2,400 wood transmission poles annually out of 36,422 wood poles installed.  At this pace, by 2019 we 
will reach the 15‐year cycle for all transmission lines.  See the Area Work Plans section of this report for 
a list of future planned inspections. 
In recent years, prioritization and scheduling of ground inspections has been based on the time since the 
last ground inspection.  Results of these inspections provide the basis for case‐by‐case analysis and the 
scope of subsequent minor and major rebuild projects on each line.  While it is important that we 
maintain a maximum 15‐year ground inspection cycle, it is recommended that future inspection 
scheduling includes consideration of the risk index, which may justify earlier inspection.  As a general 
rule, critical assets that exhibit age‐related failures should be inspected to verify condition and justify 
service extension or removal near the end of their expected service lives.  We currently have many 
115kV lines (non‐Western Electricity Coordinating Council pathways) with assets 10 or more years past 
expected service life, that have not been inspected for nearly 20 years.  This poses a significant unknown 
risk. 
If actual condition assessment warrants service extension, shorter inspection intervals are prudent when 
the time to failure characteristics worsen with age – as is the case with much of our transmission wood 
infrastructure.   Approximately 17% of the system is beyond its expected life, with a large portion of 
those assets over 15 years since the last ground inspection.  The scattered age profile on many lines that 
results over many decades from periodic minor rebuilds and one‐off replacements, makes this situation 
difficult to remedy – one must choose between the pros and cons of spotty replacements when failure 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 36 of 61

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

occurs on one end of the spectrum, to larger line section replacements and full rebuilds on the other. 
Regardless, for those lines that have significant sections or quantities of older assets that demonstrate 
higher relative risks, out‐of‐cycle inspection and a shorter inspection interval may be warranted (e.g. 10 
years instead of 15). 
5.  Structural Aerial Patrols 
The Avista transmission system covers a large geographical area that has all types of terrain.  
Transmission Aerial Patrols (TAP) have been utilized to provide a quick above‐ground inspection to 
identify significant problems that require immediate attention, such as lightning damage, cracked or 
sagging crossarms, fire damage, bird nests and danger trees.   
In addition, aerial patrols can identify improper uses of the transmission Right‐of‐Way (R/W), such as 
dwellings, grain bins, and other types of clearance problems that must be addressed.  Typically, the 
patrol will be performed in the spring.  Identified repairs, depending on severity, are scheduled to be 
performed within 6 months. 
TAP inspects 100% of 230kV lines and 70% of 115kV lines annually.  The remaining 30% of 115kV lines 
are located in urban areas that are frequently viewed by line personnel for potential problems.  The 
Transmission Design group schedules patrols for each service territory.  The TAP areas are: Spokane 
(includes Othello, Davenport and Colville), Coeur d’Alene (includes Kellogg and St. Maries), Pullman, and 
Lewiston/Clarkston (includes Grangeville and Orofino).  
Aerial patrols are performed by qualified personnel from Transmission Design, often accompanied by 
local office personnel.  Inspection forms have been developed that contain a weighting system to 
identify the severity of defects.  This information can then be utilized to make recommendations for 
necessary repairs.   
6.  Vegetation Aerial Patrols and Follow‐up Work 
The Transmission Vegetation Management (TVM) program maintains the transmission system clear of 
trees and other vegetation, in order to provide safe clearance from trees and reduce outages caused by 
trees, weather, snow, ice and wind.   
The entire 230kV system is annually inspected with a combination of aerial and ground patrols by the 
System Forester, who solely manages the overall program.  Select 115kV lines are also patrolled 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 37 of 61

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

according to criticality.  In addition, vegetation issues noted during structural aerial patrols on the 115kV 
system, as well as fielding of transmission line projects by Transmission Engineering are relayed to the 
System Forester.  Based on this information, follow‐up work plans are adjusted and executed with 
contract crews over the course of the year. 
Over the next ten years, annual budgets of $1.2 million are recommended to allow for optimal 
completion of major re‐clearing work and a transition to Integrated Vegetation Management.  It is 
expected that annual budgets will be evaluated and fine tuned to fit workloads as appropriate. 
See the Transmission Vegetation Management Program reference (Avista Utilities, 2012) for more 
details on the program.   
7.  Fire Retardant Coatings 
After several fires and a 2008 study to initiate systematic remediation, fire retardant coating has been 
applied to the base of wood transmission poles system‐wide.  At this point the entire 230kV system has 
been deemed adequately protected and the 115kV system is approximately 37% complete.  Given the 
fire event of last year, the Lolo‐Oxbow 230kV line is planned for early recoating in 2016 to reduce risk 
(coatings are expected to remain effective for 12 years, Lolo‐Oxbow was coated in 2007).  Targeted 
areas include those subject to grassland fires and in close proximity to railroads.  Protective coating is 
not applied to heavily forested areas as it is deemed inadequate in these areas to merit the cost of 
application. 
It is estimated that approximately 4,210 poles remain to be coated in the 115kV system.  Following the 
current plan to coat 179 poles in 2015 (179 115 kV poles and 535 230 kV poles repainting the Lolo – 
Oxbow line was cut from the 2015 scope of work due to budget), it is recommended to coat 1000 poles 
per year for the following five years to complete the work by 2020.  At a total labor and materials cost of 
$242/pole, this equates to $242,000/year.  Beyond this, regular maintenance and upkeep will only be 
required, at an unknown amount depending on the longevity of the coatings.  Until better information is 
obtained, $50k/year for ongoing coating maintenance is estimated.  Performance metrics could be 
considered to monitor performance of this program, possibly in terms of % of the system protected, 
maintenance spending and actual fire damage costs.  As noted in the Outages section, pole fire incidents 
have increased, reinforcing the necessity of monitoring and adjustment of this program. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 38 of 61

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 39 of 61

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 40 of 61

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

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

Table 22:  Program Ranking Criteria 

The NERC High, Medium, and Low Mitigation programs reconfigure insulator attachments, and/or 
rebuilds existing transmission line structures, or removes earth beneath transmission lines in order to 
mitigate ratings/sag discrepancies found between "design" and "field" conditions as determined by 
LiDAR survey data.  This program was undertaken in response to the October 7, 2012, North American 
Electric Reliability Corporations (NERC) "NERC Alert" ‐ Recommendation to Industry, "Consideration of 
Actual Field Conditions in Determination of Facility Ratings".  Mitigation brings lines in compliance with 
the National Electric Safety Code (NESC) minimum clearances values.  These code minimums have been 
adopted into the State of Washington's Administrative Code (WAC). 
The NERC High Priority Mitigation Capital Program (ER2560) covers mitigation work on Avista's "High 
Priority" 230kV transmission lines, including: Benewah‐Pine Creek (BI CT203), Cabinet‐Noxon (BI AT203), 
Cabinet‐Rathdrum (BI CT202), Hatwai‐North Lewiston (BI LT205), Lolo‐Oxbow (BI LT202), and Noxon‐
Pine Creek (BI AT202). 
The NERC Medium Priority Mitigation Capital Program (ER25xx) covers mitigation work on Avista's 
"Medium Priority" 230kV and 115kV transmission lines, including  North Lewiston‐Shawnee 230kV, 
Beacon‐Bell #4 230kV, Beacon‐Bell #5 230kV, Noxon‐Hot Springs #2 230kV, Beacon‐Boulder #2 115kV, 
Beacon‐Francis & Cedar 115kV, 9th & Central‐Otis 115kV, Northwest‐Westside 115kV, Dry Creek‐Talbot 
230kV, Walla Walla‐Wanapum 230kV, Benewah‐Moscow 230kV, Devils Gap‐Stratford 115kV.   
The NERC Low Priority Mitigation Capital Program (ER25xx) covers mitigation work on Avista's "Low 
Priority" 230kV and 115kV transmission lines.   

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 41 of 61

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

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 42 of 61

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

This shows that Avista’s capital replacement spending over the last two years is lower than the study’s 
average, close to the lowest of the seven reported utilities.  Comparably, the recommended capital 
replacement spending as part of a levelized 30‐year plan of $21.1 million (planned work) plus an 
assumed $1.3 million unplanned emergency work results in 1.97%, very near the study’s median and 
less than the average. 
Idaho Power is a very good benchmark utility for Avista in terms of size, operating environment and 
electric transmission component and system similarities.  In discussions with their staff, thorough 
transmission structure ground inspections are conducted every 10 years, with quick visual inspections 
(drive‐bys) every 2 years.  It is also clear that in general, Idaho Power spends considerably more time 
and effort on O&M maintenance activities relative to Avista, at least in areas of transmission and 
substation systems. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 43 of 61

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

Figure 10:  Idaho Power Long‐term Replacement Costs 
As stated previously, investigation of air switch maintenance practices of various utilities indicates that 
most utilities perform a much greater degree of maintenance than Avista. 
In terms of broader maintenance benchmarking, a study through a CEATI report (excerpts below) show 
that Avista is among the majority of peers conducting aerial patrols once per year, but that of all 15 
utilities responding, we have the longest ground inspection interval at 15 years, as compared to the 
most common interval of 10 years. 
This does not necessarily mean that our inspection interval needs to be shortened.  However, it does at 
least indicate where we stand relative to other utilities participating in the survey, and at minimum 
would tend to discourage extending our inspection interval any further. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 44 of 61

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 45 of 61

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Data Integrity ‐ Electric Transmission System
Status Data Source Notes/Comments
AFM Wood species info missing for 115kV; potentially large # of stubs 
entered as pole installs, major job backlog updates pending from 1992
Line History Binder Great historical info but hasn't been updated for 15 years
Safety information Unable to isolate to Transmission work
Plan & Profile (P&P drawings)Major job backlog updates pending from 1992 to present; long term 
migration to digital (PLS‐CADD) format
WPM database
Pole information is not updated to reflect followup work or other 
projects, just at time of inspection; handnotes need to be 
consolidated and alphebetized, line naming conventions need to be 
synced up; wood species in hand notes and electronic files needs to 
be uploaded to AFM
Maximo Does not always capture component failure mode data as designed
Transmission Engineering Guidelines Partially complete, need more participation to complete
Engineering files vault Engineers need to submit as‐built updates more promptly, "archived" 
files need to be refiled in their proper line section
Discoverer Unwieldly to summarize costing across different Tx projects, difficult 
to isolate costs/activities to Tx
AWB simulations Building on progress/standards/methods
PLS‐CADD and design/construction 
standards Progress continues, published new standards in 2014
Air Switch Master Inventory 
Spreadsheet Updated inventory and detailed info complete
OMT data
Mostly reliable info but some categories are mixed with substations, 
for example PMs that really are transmission related are placed in 
subs  
Table 24:  Transmission Asset Data Integrity 
We are 100% complete processing updates to a backlog of 459 transmission jobs dated from 1992 to the 
present in our GIS/AFM database and on plan and profile (P&P) drawings.  WPM inspection records in 
handnote form have been entered electronically.  Pole material type, location and installation dates 
have been synchronized with updated AFM information.  However, this clean dataset now exists in 
spreadsheet form and needs to be uploaded to AFM.  Line history binders are in the process of being 
updated and converted to electronic files.   Engineers are following the construction as‐built recording 
process, however prompt updates continue to be problematic.  A realistic goal of 6‐months from the 
completion of construction to records updating complete and project close‐out has been established.  
Maximo implementation is in progress.  It appears that many years will be needed to obtain quality data 
that may be effectively used for asset management purposes. The new transmission construction 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 46 of 61

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

Table 25:  Relative Material Purchases, 10/2010 – 10/2012 
Root Cause Analysis (RCA) 
Following the Othello storm in September 2013, a team was formed to study the causes of the event 
and develop effective solutions to prevent recurrence, as appropriate.  Representatives from 
Transmission Design, Asset Management, Distribution Engineering, Construction Services, and Spokane 
Electric participated.  In addition to technical forensics, a rigorous methodology was followed known as 
the “Apollo Root Cause Analysis methodTM ”, requiring evidence and team consensus to develop 
effective solutions.  Not only the root causes, but also the significance of the event and the more severe 
consequences that were narrowly avoided were unexpectedly discovered through the team’s 
Category Total Amount %
steel poles $1,770,582 44%
other $466,378 12%
fire retardant coating $445,514 11%
crossarms $349,709 9%
air switches $293,131 7%
conductor $259,622 6%
insulators $228,702 6%
crossbraces $96,212 2%
vibration dampers $78,916 2%
wood poles $52,927 1%
total $4,050,929 100%

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 47 of 61

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 48 of 61

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Table 26:  Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston)  

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 49 of 61

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 50 of 61

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Table 28:  Non‐Corrective System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 51 of 61

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Table 29:  Non‐Corrective System Planning Projects (Palouse, Spokane and System) 
Area Work Plans 
The following transmission projects are scheduled for work based on a variety of factors including 
changing system and operational requirements, remaining service life, asset condition, and 
performance.  This list is provided for planning and reference purposes only.  It represents current plans 
and is subject to frequent change.  See the Transmission Engineering Manager for the latest revision.  
Those items with no marks for any year represent tentative projects under consideration. 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 52 of 61

53 2016 Electric Transmission System Asset Management Plan 
Sharepoint ‐ Asset Management Plans 

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 53 of 61

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 54 of 61

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

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

Table 33:  Ground Inspection Plan 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 55 of 61

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 56 of 61

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Appendix A –Transmission Probability, Consequence & Risk Index 
Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Lolo ‐ Oxbow 230 63.41 $45,655,200 85.4 100.0 100.0 
Noxon ‐ Pine Creek 230 43.51 $31,327,200 80.5 87.8 82.8 
Benewah ‐ Pine Creek 230 42.77 $30,794,400 68.3 87.8 70.3 
Walla Walla ‐ Wanapum 230 77.78 $56,001,600 68.4 83.7 67.1 
Benewah ‐ Boulder 230 26.15 $18,828,000 67.1 72.9 57.3 
Hot Springs ‐ Noxon #2 230 70.05 $50,436,000 66.0 68.8 53.2 
Dry Creek ‐ Talbot 230 28.27 $20,354,400 51.4 78.3 47.1 
Latah ‐ Moscow 115 51.41 $21,592,200 96.0 41.7 47.0 
Devils Gap ‐ Stratford 115 86.19 $36,199,800 100.0 39.0 45.6 
Post Street ‐ 3rd & Hatch 115 1.76 $3,696,000 70 100 43 
Benewah ‐ Moscow 230 44.28 $31,881,600 61.1 59.3 42.5 
Cabinet ‐ Rathdrum 230 52.3 $37,656,000 41.7 86.4 42.3 
Bronx ‐ Cabinet 115 32.38 $13,599,600 59.4 55.2 38.4 
Metro ‐ Post Street 115 0.5 $1,890,000 60 100 38 
Ninth & Central ‐ Sunset 115 8.63 $3,624,600 39.0 75.6 34.7 
Burke ‐ Pine Creek #3 115 23.79 $9,991,800 67.0 44.4 34.6 
Shawnee ‐ Sunset  115 61.51 $25,834,200 79.0 36.3 33.4 
Sunset ‐ Westside 115 10.03 $4,212,600 53.0 53.9 33.2 
Hatwai ‐ Lolo 230 8.27 $5,954,400 28.9 93.2 31.6 
Burke ‐ Pine Creek #4 115 23.13 $9,714,600 69.0 37.6 30.4 
Beacon ‐ Boulder #2 115 13.73 $5,766,600 38.7 66.1 29.9 
Addy ‐ Devil's Gap 115 43.31 $18,190,200 58.0 43.0 29.3 
Othello Sw. Sta ‐ Warden #2 115 16.56 $6,955,200 53.7 45.8 28.8 
Pine Street ‐ Rathdrum 115 33.24 $13,960,800 47.0 51.2 28.3 
Benton ‐ Othello Switch Station 115 26.07 $10,949,400 64.0 37.6 28.3 
CdA 15th St ‐ Pine Creek 115 29.75 $12,495,000 83.0 28.1 27.3 
Cabinet ‐ Noxon 230 18.51 $13,327,200 31.3 71.5 26.3 
Chelan ‐ Stratford 115 49.44 $20,764,800 66.6 32.2 25.1 
Moscow 230 ‐ Orofino 115 41.59 $17,467,800 84.0 25.4 25.0 
Boulder ‐ Rathdrum 115 19.07 $8,009,400 58.6 36.3 24.9 
Benewah ‐ Pine Creek 115 45.02 $18,908,400 67.0 29.5 23.2 
Jaype ‐ Orofino 115 34.64 $14,548,800 66.6 29.5 23.0 
Clearwater ‐ N. Lewiston 115 3.21 $1,348,200 30.7 63.4 22.8 
Ninth & Central ‐ Otis Orchards 115 16.31 $6,850,200 28.9 66.1 22.4 
N. Lewiston ‐ Shawnee 230 34.28 $24,681,600 33.2 56.6 22.0 
Burke ‐ Thompson Falls A 115 3.96 $1,663,200 34.4 53.9 21.7 
College & Walnut ‐ Post Street 115 0.54 $2,041,200 2.8 100 21 
Beacon ‐ Bell #4 230 6.3 $4,536,000 22.8 78.3 20.9 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 57 of 61

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

Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Devil's Gap ‐ Lind 115 73.74 $30,970,800 95.1 18.6 20.8 
Dry Creek ‐ Lolo 230 11.23 $8,085,600 29.5 59.3 20.5 
Eighth & Fancher ‐ Latah 115 26.27 $11,033,400 55.6 30.8 20.1 
Coulee ‐ Westside 230 1.99 $1,432,800 27.1 62.0 19.7 
Benewah ‐ Thornton 230 32.2 $23,184,000 27.1 60.7 19.3 
Shawnee ‐ Thornton 230 27.83 $20,037,600 27.1 60.7 19.3 
Hatwai ‐ Moscow 230 18.05 $12,996,000 27.7 59.3 19.2 
Grangeville ‐ Nez Perce #2 115 37.17 $15,611,400 53.0 29.5 18.4 
Bell ‐ Northeast 115 1.53 $642,600 42.2 48.5 18.1 
Addy ‐ Kettle Falls 115 27.11 $11,386,200 27.7 55.2 17.9 
Burke ‐ Thompson Falls B 115 3.97 $1,667,400 28.3 53.9 17.9 
Bell ‐ Northeast 115 2.83 $1,188,600 31.9 34.9 17.3 
Francis & Cedar ‐ Northwest 115 2.12 $890,400 30.7 47.1 16.9 
Grangeville ‐ Nez Perce #1 115 26.9 $11,298,000 48.0 29.5 16.7 
Lolo ‐ Nez Perce 115 41.2 $17,304,000 55.7 25.4 16.6 
Lolo ‐ Pound Lane 115 10.25 $4,305,000 40.0 34.9 16.5 
Beacon ‐ Bell #5 230 6.04 $4,348,800 18.0 78.3 16.5 
Dworshak ‐ Orofino 115 3.62 $1,520,400 21.6 64.7 16.4 
Airway Heights ‐ Devils Gap 115 20.6 $8,652,000 22.8 60.7 16.2 
Beacon ‐ Ross Park 115 2.06 $865,200 20.4 67.5 16.1 
Lind ‐ Warden 115 21.71 $9,118,200 44.5 30.8 16.1 
Hatwai ‐ N. Lewiston 230 6.99 $5,032,800 18.0 75.6 15.9 
Metro ‐ Sunset 115 2.87 $1,205,400 24.6 52.5 15.1 
Devils Gap ‐ Ninemile 115 18.78 $7,887,600 28.9 44.4 15.0 
Beacon ‐ Boulder #1 115 13.07 $5,489,400 38.7 32.2 14.6 
Moscow 230‐ Terre View 115 11.94 $5,014,800 40.4 30.8 14.6 
Bronx ‐ Sand Creek 115 6.62 $2,780,400 30.7 40.3 14.5 
Beacon ‐ Ninth & Central #2 115 3.5 $1,470,000 22.8 53.9 14.4 
Beacon ‐ Bell #1 115 6.86 $2,881,200 29.5 41.7 14.4 
Lind ‐ Shawnee 115 75.81 $31,840,200 83.6 14.6 14.3 
Moscow 230 ‐ Orofino 115 21.33 $8,958,600 50.0 24.1 14.1 
College & Walnut ‐ Westside 115 8.79 $3,691,800 24.0 49.8 14.0 
Northwest ‐ Westside 115 1.95 $819,000 24.0 49.8 14.0 
Ross Park ‐ Third & Hatch 115 2.19 $919,800 19.2 60.7 13.6 
Beacon ‐ Northeast 115 5.25 $2,205,000 30.7 41.7 13.5 
Ninemile ‐ Westside 115 6.8 $2,856,000 22.8 49.8 13.3 
Nez Perce ‐ Orofino 115 17.28 $7,257,600 27.7 40.3 13.1 
Post Falls ‐ Ramsey 115 9.01 $3,784,200 28.9 36.3 12.3 
Addy ‐ Gifford 115 20.68 $8,685,600 51.9 20.0 12.2 
Ramsey ‐ Rathdrum #1 115 8.42 $3,536,400 24.0 41.7 11.7 
Beacon ‐ Boulder 230 11.95 $8,604,000 17.4 56.6 11.5 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 58 of 61

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

Transmission Line Name Voltage 
(kV) 
Length 
(miles) 
Replacement 
Value 
Probability 
Index 
Consequence 
Index 
Risk 
Index 
Beacon ‐ Ninth & Central #1 115 3.73 $1,566,600 18.0 53.9 11.3 
Stratford ‐ Summer Falls 115 6.3 $2,646,000 18.0 53.9 11.3 
Beacon ‐ Francis & Cedar 115 11.56 $4,855,200 34.3 28.1 11.3 
Appleway ‐ Rathdrum 115 11.77 $4,943,400 20.4 47.1 11.2 
Shawnee ‐ Terre View 115 10.05 $4,221,000 30.1 30.8 10.9 
Dry Creek ‐ N. Lewiston 230 8.06 $5,803,200 13.1 70.2 10.7 
CdA 15th St ‐ Rathdrum 115 12.67 $5,321,400 19.2 47.1 10.6 
Milan Tap 115 8.22 $3,452,400 30.1 29.5 10.4 
Shawnee ‐ South Pullman 115 12.7 $5,334,000 35.0 25.4 10.4 
Beacon ‐ Rathdrum 230 25.36 $18,259,200 16.2 53.9 10.2 
Airway Heights ‐ Silver Lake 115 10.77 $4,523,400 24.0 36.3 10.2 
Boulder ‐ Lancaster 230 13.29 $9,568,800 11.3 76.9 10.2 
Libby ‐ Noxon 230 0.79 $568,800 12.5 68.8 10.1 
Moscow 230 ‐ South Pullman 115 12.07 $5,069,400 23.0 36.3 9.7 
Colbert Tap 115 3.19 $1,339,800 34.3 24.1 9.7 
Clearwater ‐ Lolo #2 115 8.56 $3,595,200 24.0 33.5 9.4 
Otis Orchards ‐ Post Falls 115 7.62 $3,200,400 24.0 30.8 8.7 
Ninth & Central ‐ Third & Hatch 115 4.34 $1,822,800 24.0 29.5 8.3 
Lind ‐ Washtucna 115 28.78 $12,087,600 30.1 22.7 8.0 
Benewah ‐ Pine Creek 115 7.06 $2,965,200 27.0 24.1 7.6 
Burke ‐ Pine Creek #3 115 4.58 $1,923,600 23.0 28.1 7.5 
Shawnee ‐ Sunset  115 7.12 $2,990,400 37.0 15.9 6.8 
Devils Gap ‐ Long Lake #2 115 1.03 $432,600 13.1 41.7 6.4 
Albeni Falls ‐ Pine Street 115 2.27 $953,400 13.1 40.3 6.2 
Francis & Cedar ‐ Ross Park 115 5.16 $2,167,200 14.3 36.3 6.1 
Clearwater ‐ Lolo #1 115 8.63 $3,624,600 24.0 20.0 5.6 
Dry Creek ‐ Pound Lane 115 3.89 $1,633,800 12.5 36.3 5.3 
Airway Heights ‐ Sunset 115 9.52 $3,998,400 18.0 25.4 5.3 
Sunset ‐ Westside 115 11.97 $5,027,400 22.0 21.3 5.2 
Latah ‐ Moscow 115 10.37 $4,355,400 17.0 25.4 5.0 
Dry Creek ‐ N. Lewiston 115 8.17 $3,431,400 13.1 30.8 4.7 
Devils Gap ‐ Little Falls #2 115 3.9 $1,638,000 24.0 15.9 4.5 
Othello Sw. Sta ‐ Warden #1 115 8.28 $3,477,600 36.1 10.5 4.4 
CdA 15th St ‐ Ramsey 115 3.17 $1,331,400 9.4 36.3 4.0 
Moscow City ‐ N. Lewiston 115 22.19 $9,319,800 16.2 21.3 4.0 
Devils Gap ‐ Little Falls #1 115 3.42 $1,436,400 19.2 14.6 3.3 
Critchfield ‐ Dry Creek 115 1.58 $663,600 13.1 20.0 3.1 
Benewah ‐ Latah 115 6.68 $2,805,600 5.9 40.3 3.0 
Lolo ‐ Pound Lane 115 2.94 $1,234,800 12.0 20.0 2.8 
Bell ‐ Westside 230 1.99 $1,432,800 2.8 72.9 2.4 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 59 of 61

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

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

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 60 of 61

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

Appendix B – Transmission System Outage Data 

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 4, Page 61 of 61
Index of Business Case Justification Narratives Page 1 of 4
Electric Distribution Capital Projects Page Number
Asset Condition
Dist Grid Modernization 5
Distribution Transformer Change-Out Program 13
Distribution Wood Pole Management 21
Primary URD Cable Replacement 29
Customer Requested
New Revenue - Growth 33
Failed Plant and Operations
Distribution Minor Rebuild 43
Meter Minor Blanket 49
Mandatory and Compliance
Elec Replacement/Relocation 55
Environmental Compliance 63
Performance and Capacity
LED Change Out Program 66
Segment Reconductor and FDR Tie Program 73
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 1 of 325
Index of Business Case Justification Narratives Page 2 of 4
Electric Transmission Capital Projects Page Number
Asset Condition
SCADA - SOO & BUCC 85
Substation - Station Rebuilds 90
Transmission Minor Rebuild 93
Transmission Major Rebuild - Asset Condition 96
Customer Requested
Growth - Hallet and White 99
Failed Plant and Operations
Electric Storms 103
Mandatory and Compliance
Colstrip Transmission 106
Environmental Compliance 110
Garden Springs 230/115kV Station Integration 113
Noxon Switchyard Rebuild 118
S Region Voltage Control 121
Saddle Mountain 230/115kV Station Integration 124
Spokane Valley Transmission Reinforcement 127
Transmission - NERC Low Priority Mitigation 130
Transmission - NERC Medium Priority Mitigation 133
Transmission Construction - Compliance 136
Tribal Permits and Settlements 140
Westside 230/115kV Station Rebuild 143
Performance and Capacity
SCADA Build-Out Program 146
Substation - Capital Spares 148
Substation - New Distribution Stations 151
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 2 of 325
Index of Business Case Justification Narratives Page 3 of 4
Natural Gas Distribution Capital Projects Page Number
Asset Condition
Gas Deteriorated Steel Pipe Replacement Program 154
Gas ERT Replacement Program 159
Gas Regulator Stn Replacement Program 164
Customer Requested
New Revenue - Growth 167
Failed Plant and Operations
Gas Non-Revenue Program 177
Mandatory and Compliance
Gas Cathodic Protection Program 182
Gas Facilities Replacement Program (Aldyl A)184
Gas HP Pipeline Remediation Program 191
Gas Isolated Steel Replacement Program 194
Gas Overbuilt Pipe Replacement Program 197
Gas PMC Program 202
Gas Replacement Street and Highway Program 205
Performance and Capacity
Gas Reinforcement Program 207
Gas Telemetry Program 211
Gas Schweitzer Mtn Rd HP Reinforcement 214
Gas Rathdrum Prairie HP Main Reinforcement Project 217
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 3 of 325
Index of Business Case Justification Narratives Page 4 of 4
General Plant Capital Projects Page Number
Asset Condition
COF Long-Term Restructuring Plan 222
Dollar Rd Service Center Addition and Remodel 236
Noxon & Clark Fork Living
Facilities 247
Structures and
Improvements/Furniture 255
Customer Service Quality and Reliability
Meter Data Management System *
Failed Plant and Operations
Capital Tools & Stores Equipment 262
Performance and Capacity
Apprentice Training 269
CNG Fleet Conversion **
COF LngTrm Restruct Ph2 272
Company Aircraft Capital 292
Ergonomic Equipment 297
New Airport Hangar 303
Other Plant Capital Projects
Asset Condition
Fleet Budget 309
Mandatory and Compliance
Jackson Prairie Storage 323
*
** The transfers to plant associated with this business case represent investment of
fifty-two thousand dollars ($52,000), on a system basis, in 2017. Given the
relatively low investment amount and near-term completion of the project (i.e., in
2017), a business case justification narrative in the new format was not completed
for this project.
For discussion of this project, please see Ms. Rosentrater's testimony (Exhibit
No. 8, page )
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 4 of 325
Distribution G rid Modernization
1 GENERAL INFORMATION
Requested Spend Amount $17,500,000
Requesting Organ ization/Department Asset Maintenance
Business Case Owner Laine Lambarth
Business Gase Sponsor Bryan Cox
Sponsor Organization/Department Asset Maintenance
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
. The program scope is defined by an analytical study done by the Program
Engineer for each feeder and by the Distribution Feeder Management Plan
which was created and is updated by consulting The Distribution
Engineering Standards Engineer and Asset Management Manager.
o Reliability, avoided costs, and capital offset of future O&M expense data is
collected and analyzed by Asset Management. This information is
normalized and entered into a selection toolwhich then ranks the feeders.
o The regional distribution engineers for the East, South, North, West and
Spokane regions are consulted regarding the feeder ranking and feeder
prioritization within their respective regions.
o The program manager then balances the prioritized feeders between the
states, rural/urban split, and regions.
o The program manager then collaborates with Electric Operations and
Contractors to coordinate the work and track the budget, scope, and
schedule.
2 BUSINESS PROBLEM
The Distribution Grid Modernization Program provides value to customers and
shareholders through the following objectives of improving:
o Grid Reliabilitv -Replacing aging and failed infrastructure that has a high
likelihood of creating customer outages and a need of an unplanned crew
call-out which costs more than planned work and would filter into higher
rates for customers.
o Without programs like Grid Modernization and Wood Pole
Management there would be an average 40 pole failure events per
year effecting an average of 80 customers for 4.8 hours per event.
Totaling a customer impact value of approximately $24,000 per
event totaling to $960,000 per year.
Page 1 of8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 5 of 325
Distribution Grid Modernization
o
a
a
Energy Efficiency - Replace equipment such as old conductor and
transformers that have high energy losses with new equipment that is more
energy efficient and improve the overall feeder energy performance. This
creates the need for less power generation or acquisition and equates to
lower rates for customers.
Operational Abilitv - Replace conductor and equipment that hinders outage
detection and install automation devices that enable isolation of outages.
o This means shorter outrages for customers because the areas that
failed can be identified faster and possibly reroute power
automatically. Currently the Grid Modernization Program in the only
company initiative installing these devices.
o The installation of automated line devices on a feeder of 1600
customers reduces an average outage duration from 3 hours to 5
minutes per event for 1200 of those customers.
Safety - Focus on public and employee safety through smart design and
work practices.
o Replacing aging and failed infrastructure that puts employees and
customers at risk of property damage and injury.
o Bringing infrastructure up to current National Electric Safety Code.
o Eliminate PCB risk to the public by eliminating transformers
containing known PCB's.
o The Grid Modernization program lowers the risk of high severity
safety (S4) events, defined below, as follows:
. 54 events are categorized as having potential for multiple
serious injuries or loss of an individual life; major damage to
property or business, and a public health infrastructure impact
up to 72 hours.
. Base Case (do nothing) has the risk of 10 34 events every 50
years with a total cost of $52.3M.
' The Grid Modernization Program brings this risk down to 2
events in 50 years with a total cost of $10.4M.
Another Safety objective of The Distribution Grid Modernization Program is
to address Washington State's Department of Transportation (WSDOT)
Target Zero requirements, which states that utilities move all non-
breakaway structures, such aS power poles and pad mount transformers,
out of highway clear zone as defined in the 1012005 AASHTO "A Guide for
Accommodating Utilities Within Highway Right-of-Way," which is attached
for reference. Washington State law requires that we complete this task by
year 2030. Currently this is the only program within Avista actively
addressing this mandate. Additional Control Zone justifications include the
Page 2 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 6 of 325
Distri b uti on G rid Modern ization
following Washington Administrative Codes (WAC) and Revised Codes of
Washington (RCW):
o WAC 468-34-350 - Control Zone Guidelines
o WAC 468-34-300 - Overhead Lines Location
o RCW 47.32.'130 Dangerous Objects and Structures as Nuisances
o RCW 47.44.010 Wire and Pipeline and Tram and Railway
Franchises - Application - Rules on Hearing and Notice
o RCW 47.44.020 Grant of Franchise - Condition - Hearing
Selected Metrics include:
o Energy savings provided by completed work
o Number of circuit miles of work completed
o Number of sustained outages (anything longer than 5 minutes)
recorded in Avista's Outage Management Tool (OMT).
Based on Avista's 2015 lntegrated Resource Plan dated August 31st,2015,
the realized and anticipated energy savings by identified feeders is shown
in Table 1.
Table I, Energy Savings bssed on Integrated Resource PIsn
a
Spokane, WA (gth &
Central)
Spokane, WA (Beacon)
Spokane, WA (Francis &
Cedar)
Spokane, WA (Beacon)
Coeur d'Alene, lD
Othello, WA
Rathdrum, lD
Moscow, lD
Wilbur, WA
Spokane, WA (Waikiki)
Rathdrum, lD
Northport, WA (Spirit)
2009
2012
2AL2
2013
20L3
20L4
20L4
20L5
2015
2016
20L9
2019
570
885
438
2I
0
4L3
L,443
175
47t
L27
6,O76
601
972
Feeder Service Area
Year
Complete
Annual Energy
Savings (MWh)
Page 3 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 7 of 325
Distri bution G rid Modernization
ln order to address Avista's entire system and every customer in a 60 year
cycle, the program would need to address an average of 190 miles per year
of Avista's 11,300 total overhead and underground circuit miles. The miles
of work planned is ultimately driven by the approved budget and generally
can only be projected for 5 years. At the current funding level and average
cost per circuit mile, represented in Table 2 below, it will take us
approximately 90 years to address the entire system and every customer.
14*
104
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4tr
d
a
E6t¿
.)
¿
aL
Õ
Table2, Grid Modernizatíon Circuít Miles Addressed und Associated Cost
Grid Modernization
:t600c'0
14t090
130000
1C4ûü0
8û000
ætw
4æç0
48
¿v
0 2013 2t74
89*
2Ð15
!2Ð171
1t0
2016
t1r17Z
98
2t71
111682
123
f CúE Per fvlile
-
Í:¡rcuìt M i¡escomptete
135770 774232
For tracking the impacts of the programs effect on sustained outages we monitor
the OMT sub-reasons identified as potentially avoidable and most directly
impacted by The Grid Modernization Program work. Through the end of 2015
there has been a reduction of 0.1 outages per mile of overhead work
completed. Table 3, below, illustrates these reduction of outages and therefore
Page 4 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 8 of 325
Distribution Grid Modernization
the reliability advantages and reasons for the program. The red line represents
the reduction of outages of these sub-reasons on the feeders that the Grid
Modernization program has completed to date. You will see the Grid
Modernization addressed feeder outages are trending down whereas the system
wide outages are trending up. lf 2015, which is when Avista experienced a large
wind storm, was excluded the system wide outages would be trending slightly
downward but the Grid Modernization addressed feeders are trending downward
at a faster rate.
Table 3, OMT SustøÍned Outages related to Grid Modernization
Sustained Outages
¡5*$
2ffi
15Sü
lStt)
500
120
10û
Ub¡[nß
fÐ
4E
6& ,i
'g
t
-E'¿.¿n u
:tl
Ðà¡
f
Ð-Ð
UrüE;
Ëo
...,::l::,"'""r;;..:..:;
7Ð
zGtT
-System
lVäeoutrye:
2ç13 2814
+ 6rid Mod Feedef outar-eg
2015
......"". Linear (sy5tem Wirle Outagesl
2úr7
.,... L¡neãr (6rid Mod Feeder üutageq
2$16
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Gapital Gost Start Complete
Do nothing - Address issues as the infrastructure
fails. This is the most risky as injury or property
damage may occur and is estimated to increase
the risk cost by S0.f U. lt is also the most costly as
usually it is done during off hours and ends up in
overtime and is estimated to increase O&M by
S2.5M. lt is also unplanned and therefore takes
longer to do. This option would also lead to higher
and longer number of customer outages.
$9,000,000 per
year
Page 5 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 9 of 325
Distri b ution G rid Modernization
[Recommended Solutionl The Distribution Grid
Modernization Program provides benefits to
customers, employees, and shareholders by
replacing problematic poles, cross-arms, cut-outs,
transformers, conductor, etc. Additionally
automated line devices are installed which
increase energy efficiency and system reliability.
20L7 request is for S17.5M as we continue to
ramp up to the full recommendation.
$21,000,000 per
year
01 2012 12 2072
[Alternative #1]Address issues through the
different specific company initiatives, such as
Wood Pole Management, Transformer Change
Out, URD, Segment Reconductor, etc. This means
that a crew would potentially go out to the same
area multiple times. This costs more for set up and
travel time, flagging, etc. which means higher rates
for customers. This also means the customer could
have multiple different planned outages and have
multiple different street closers while the crews
did specific work at multiple different times. The
risk reduction is also cut in half compared to the
comprehensive work completed by the Grid
Modernization program.
Per year MM YYYY MM YYYY
The Grid Modernization Program combines the recommendations from two Avista
system performance studies into its work activities to provide refreshed system
feeders with new automation capabilities across Avista's distribution system. The
first of these studies was performed in 2009 and had a system efficiencies team
evaluate the potential energy savings for distribution system upgrades and
analyzed the value of selective rebuild with "right sized" conductor replacements
for reducing energy losses, improve reliability, and meeting future load growth
demand. A second study was conducted in 2013 to assess the benefits of
distribution feeder automation for increased reliability, operability, and load loss
savings.
The reliability, energy losses, reductions in operations and ma¡ntenance
(O&M) costs and capital investment from the individual efficiency programs under
consideration were combined on a per feeder basis. This approach provided a
means to rank and compare optimal feeder modernizing and net resource costs to
achieve the desired benefits.
The system efficiencies team evaluated several efficiency programs to improve
both urban and rural distribution feeders. The programs consisted of the following
system enhancements:. Conductor losses;
Page 6 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 10 of 325
Distri bution G rid Modern ization
o Distribution transformer losses and PCB mitigation;. Secondary district losses;. Conservation Voltage Reduction (CVR);. lntegrated VoltA/ar Control (lWC), and;r Fault Detection lsolation and Restoration (FDIR) opportunities;
The Grid Modernization Program's charter criterion has grown to include a more
holistic approach to the way Avista addresses each project. This vital program
integrates work performed under various operational initiatives at Avista including
the Wood Pole Management Program, the Transformer Change-out Program, the
Vegetation Management Program, various budgeted maintenance programs and
the Feeder Upgrade Program.
The ancillary work of the Grid Modernization Program includes the replacement of
undersized and deteriorating conductors, replacement of failed and end-of-life
infrastructure materials including wood poles, cross arms, fuses and insulators.
lnaccessible pole re-alignment, right-away, undergrounding, joint use coordination
and clear zone compliance issues are addressed for each feeder section. This
systematic overview enables Avista to cost-effectively deliver a modernized and
robust electric distribution system that is more efficient, easier to maintain and
more reliable for our customers.
The long-term plan aims to upgrade 190 circuit miles per year to cover the whole
distribution system in a 60 year cycle. According to Avista's Asset Management
subject matter experts a 60 year cycle is optimal due to the average mean time
to failure and age profiles of our systems assets. lt also coordinates well with the
Wood Pole Management's (WPM) program 20 year cycle. The average cost for
the Grid Modernization program to rebuild a circuit mile is $110,000. ln orderto
meet the 60 year cycle $21M would be needed each year. Alternatively we could
complete the entire system in 80 years for $15.5M each year, but that means we
would not address the entire system until approximately the year 2093. This
would not be prudent at Asset Management shows a bow wave of infrastructure
reaching end of life by the year 2060. Currently the program is still ramping up to
its fully desired resource needs and therefore has only requested $17.5M for
2017. The plan is to have enough resources, design, and funding in place to be
able to construct the 190 circuit mile per year goal by 2019.
The Grid Modernization Program consists of the following fully allocated
resources: Project Manager, Associate Project Manager, Distribution Engineer,
six internal designers (customer project coordinators/CPC), and five contract
designers and has the following part time shared resources: analyst, and two in-
house and two contract field inspector/auditors. Construction labor usually
consists of a mix of in-house and contract line crews totaling around eight to
twelve five man crews. The program also interfaces with and relies on assistance
from the following departments which might require additional resources; Real
Page 7 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 11 of 325
Distri bution Grid Modernization
Estate, Environmental, Contracts, Substation Engineering, Relay Shop, Electric
Shop, SCADA, Network Systems, and Protection Engineering.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution Grid
Modernization business case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Title:
Role
Grid Modernization Project Mgr
Date
Date QAt I t-7
Tem plate Version : 021 1312017
,tll lr
Laine Lambarth
Business Case Owner
Signature
Print Nam"f Bryan CòY
Sr Dir of HR Operations
Business Case Sponsor
5 VERSION HISTORY
Vercion lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1.0 Laine Lambarth 4t14t2017 Bryan Cox 4t14t2017 lnitialversion
Page I of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 12 of 325
Distri bution Transformer Change Out Program 2017
Requested Spend Amount $3,000,000
Requesting Organ ization/Department Asset Maintenance
Business Case Owner Cody Krogh
Business Gase Sponsor Bryan Cox
Sponsor Organization/Department Asset Maintenance
Category Program
Driver Asset Condition
1 GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Transformer condition, outage information, and energy savings is collected and
analyzed by Asset Management. The environmental team tests and tracks PCB
level of each transformer by location. This information is reviewed with Asset
Maintenance to establish an effective replacement program that prioritizes work
based on environmental risk and reliability. Asset Maintenance manages the
program and collaborates with Electric Operations and contractors to coordinate
the work. Asset Maintenance tracks the work budget, scope, and schedule.
2 BUSINESS PROBLEM
The Transformer Change-Out Program (TCOP) work has three primary drivers. First, the
pre-1981 distribution transformers that are targeted for replacement average 44 years of
age. Their replacement will increase the reliability and availability of the system.
Secondly, the transformers to be replaced are inefficient compared to current standards
and their replacement will result in energy savings. Thirdly, pre-1981 transformers have
the potentialto have Polychlorinated Biphenyls (PCB) containing oil.
The TCOP Program was implemented in 2011. The Program has focused on eliminating
all transformers containing or potentially containing PCBs. The initial target was on areas
near the Spokane and Pend Oreille River watersheds and has now moved to all
transformers containing PCBs. These transformers have specificwork plans for removing
them from the system. These PCB targeted transformers are on schedule to be replaced
by 2019. The second phase of the Program is to replace all remaining pre-1981
transformers through the use of the Wood Pole Management Program. This work is
planned to be complete by 2040 based on the current funding request.
PCBs and PCB wastes are regulated by both the Washington Department of Ecology
(Ecology), through the Dangerous Waste Regulations, Chapter 173-303 WAC, and by the
U.S. Environmental Protection Agency (EPA) under 40 CFR Part 761, the Toxic
Substances Control Act (TSCA). The transformers to be removed early in the program
are those that are most likely to have PCB containing oil and their replacement will reduce
Business Case Justification Narrative Page 1 of8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 13 of 325
Dlstribution Transformer Change Out Program 2017
the risk of PCB containing oil spills which are a safety, environmental, and a public
relations concern.
There has also been an increased focus on PCBs and similar contaminants by local,
regional, and national initiatives. On April 10,2010, the EPA had issued an Advanced
Notice of Proposed Rulemaking (ANPR) on new PCB regulations. Washington State
Ecology created an "urban waters initiative" to investigate persistent and bio-accumulative
toxics; this initiative included the Spokane River watershed. The Spokane River is listed
on the Clean Water Act "impaired" list for PCB contamination. The City of Spokane began
a storm water study to find and reduce sources of PCBs in its storm water system. ln
addition, PCB cleanup is very difficult in any environment and nearly impossible in
aqueous environments. These and other efforts reflect how important it is to keep PCBs
from entering the environment. As a result, Avista is determined to aggressively remove
PCBs from its electrical distribution system in a disciplined manner.
Currently, there are 906 transformers remaining in our system that are known or predicted
to contain a PCB level greater than 1 part per million. ln addition, there are 1,098
underground transformers that have been predicted to not contain PCBs (predicted non-
detect) however, no actual tests have been conducted on these transformers. These
transformers were analyzed using Serial Number Sequencing (SNS) where transformers
with similar serial numbers were assumed to have similar PCB levels. Serial Number
Sequencing is more cost effective versus PCB testing the pre-1981 transformers in the
field. The predicted non-detect transformers do run a risk of containing some level of
PCBs. The table below reveals the replacement plans for the targeted transformers in
the immediate future.
This is the sixth year of replacing the targeted (PCB containing) distribution transformers.
When the program began in 2011, there were over 12,000 targeted transformers.
Currently, 7o/o of the 12,000 are remaining. This program has been successful in
converting targeted transformers to a retired asset. The chart below shows remaining
transformers year to date.
2017 20t820tt-2016 2019
Total L2342
Retired Lt436 Planned for
TCOP Only 815 73 18
Remaining 906
Predicted Non-Detect L098 Planned for
TCOP Only 535 568 0
Distribution Transformers Containing PCB's
Distribution Underground Transformers Predicted Non Detect
(Predicted No PCB's)
Business Case Justification Narrative Page 2 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 14 of 325
D i stri b uti o n T ran sfo rm er C h an ge Out Program 2017
Non Retired TCOP Transformers By PCB Status
As of January t,2Ot7
30,000
25,000
20,000
15,000
10,000
5,000
Total AIITCOP Contain FCB's
Trensformers
Prediæed Non-
Detêct
Actual Non-
Detect
-Model
Results OH
...'..... Linear (Transformer UG)
Another compelling reason to replace the pre-1981 transformers is due to the decreasing
reliability caused from a population of transformers that average 44 years old. The optimal
replacement age of a transformer is 44 years old. The failure of an aging transformer
results in an outage for the downstream customers. The chart below shows the positive
reduction in outages as a result of this Program. Note that overhead transformer outages
have been reduced nearly 60% between 2007 (approximately 250 outage events) and
2016 (approximately 100 outage events). There is a customer impact value of $5,600
per event according to the U.S. Department of Energy's lnterruption Cost Estimate (lCE)
Calculator. This reduction in outage events equates to about $840,000 in customer value
for 2016. !
OMT Event Trends and Projections
-Transformer-
OH
oModel Results UG
rf¡¿¡5former UG
Expon. (Transformer - OH)
tãgo
t¡¡
o
o
olt
E
Jz
400
3s0
300
250
200
150
100
50
0
2000 20LO 2060 2070
Business Case Justification Narrative
2020 2030
Year
2040 2050
Page 3 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 15 of 325
Distribution Transformer Change Out Program 2017
Another significant driver for the TCOP program is energy efficiency and cost savings. A
component of Washington State lnitiative l-937 is to undertake cost-effective energy
conservation. To fulfill this requirement, sources of efficiency were identified. Distribution
transformers are one of the identified groups of assets where efficiency can be gained by
replacing dated models with newer models that do not lose as much energy while in an
unloaded state. Upon replacement of all pre-1981 transformers, there is an expected
energy savings of 5.6 MW per hour. According to Asset Management this represents a
savings of $215 per hour and contributes to an estimated lnternal Rate of Return (lRR)
of 8.24o/o.
The key metrics of the program are to replace the targeted transformers and achieve
energy savings, which results in increased reliability. The table below reflects the results
tracked for the program.
Table 2: TCOP Metrics
Planned Number
of Transformers
Changed Out
Actual Number
of
Transformers
Changed Out
Planned Energy
Savings from
Transformers
(MWh)
Actual Energy
Savings from
Transformers
(MWh)
Year
20t2
2013
2014
20t5
20L6
20L7
20L8
*Not calculated
2,687
2,555
2,930
2,335
1,419
1.,283
3;47
2,529
2,599
2,625
2,899
2,3tO
2,3O4
2,3O4
2,304
t,746
1,265
*
.rF
2,430
2,67L
3,002
3,150
2,428
References:
"Distribution Transformer PCBs" report, February 2010
Electric Distribution System, 2016 Asset Management Plan
Business Case Justification Narrative Page 4 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 16 of 325
Distri bution Transformer Change Out Program 2017
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capltal
Cost
Start Complete
Do nothing: No planned
replacement program fordistribution transformers.
Substantially higher risk of a PCB
containing oil spill occurring.
$o N/A
Continue to replace high risk PCB
transformers, then remaining pre-
1981's.
$3,000,000 01 2017 12 2017
[Alternative #11 Planned
replacement of PCB transformers
only through programmatic work.
Cost and timing dependent on
when programs address feeders
with PCB transformers
ln order for the Distribution Transformer Change-Out Program to be successful, design
resources are needed to complete field assessments and designs. Contract construction
crews are also necessary to supplement Avista's Electric Operation resources. Pole
inspection support from the Wood Pole Management group is also required to ensure the
safety of the pole prior to any construction work.
This Program has been funded since 2011. The current approach is considered the best
solution for mitigating environmental risk and for dollar efficiency. There are alternatives
that consider different implementation schedules. One alternative is to remove overhead
PCB containing and other pre-1981 transformers through the Wood Pole Management
program. This alternatives does have some efficiencies because it involves a crew
visiting a pole one time to address multiple issues. Additional funding would be required
for Wood Pole Management to conduct this increase in scope. Another program to
address the underground transformers would also be needed. The time to replace all,
would be approximately 20 years. Underground transformers run a greater risk of leaking
and not detecting those leaks. This is motivation to replace those transformers in a
shorter time period.
Another alternative discussed was to replace the targeted transformers "as we get there".
ln other words, if work is occurring at a site where a targeted transformer is located, the
transformer would be replaced at that time. This method could be considered efficient by
the same reasons as using the Wood Pole Management approach with a crew visiting a
location one time however, this approach would take a minimum of 120 years to replace
all targeted transformers. This increases the risks of spills and/or failures.
Business Case Justification Narrative Page 5 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 17 of 325
D i stri b uti o n T ra n sfo rmer C h a n ge Out Program 2017
ln addition to the risks of outages and failures with the aging equipment, the additional
risks associated with this program pertain to the following:
Environmental: Risks include; large volume transformer oil spill, difficult
hazardous waste cleanup, moderate to low volume or level of PCBs, minimal
impact to waterways, repeated or moderate air emission exceedance. lf the
program is unfunded the potential occurrence is greater than 4 spills per year. lf
funded, the potential occurrence is less than 1 per 50 years.
Public Safety and Health: Risks include: a potential for serious injury for crews or
the public, significant damage to equipment, property or business, public health
infrastructure impact up to 48 hours. lf the program is unfunded, the potential
occurrence is less than 1 per 10 years. lf funded the potential occurrence is less
than 1 per 50 years.
The entire population of pre-1981 transformers total nearly 47,000 units. The first phase
of targeted PCB transformers (approximately 12,000) is expected to be complete by 2019.
The second phase of the program is to replace the remaining pre-1981 transformers
(Predicted Non-Detect and Actual Non-Detect). This work is expected to extend to 2040.
The chart below shows the comparison of targeted transformers by retired status (blue =
retired, orange = remaining to work)
All TCOP Transformers by PCB Status
As ofJanuary !,2017
30000
25000
20000
15000
10000
5000
0 L-'r
Contain PCB's
r Retired
The Distribution Transformer Change-Out Program aligns with Avista's strategic vision by
ensuring transformers deliver safe and reliable energy to our customers. As older
transformers are replaced for more modern equipment, the result is an increase in
reliability, efficiency and energy savings. The other impact for replacing the pre-1981
transformers containing PCB oil, demonstrate that we are diligent in protecting our
waterways and the environment as a whole, mindful of our environmental footprint and
Total AIITCOP
Transformers
Predicted Non-
Detect
r Non-Retired
Actual Non-Detect
Business Case Justification Narrative Page 6 of I
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 18 of 325
Distribution Transformer Change Out Program 2017
meet compliance requirements. As a result, Avista customers will be positively impacted
by this program with the increased efficiencies, reliability, and environmentally safe
equipment. The risk of not doing the work exposes Avista not only to environmental risks
but reliability risk as well.
The requested amount of spend is in alignment with the program plan. The chart below
shows the historic spend levels and efficiency of dollars spent versus transformers
installed.
54,064 $s,ezz 4'@8
ç3,747
S3,28s
S2,846
2011 20t2 2013 20t4 2015 20.L6
Avista stakeholders for this program include:
o Asset Maintenance department; responsible for the work.
o Environmental department; responsible for our environmental footprint in our
service territory.
o Electric Operations; performs the construction work.
o Asset Management for tracking system reliability and risk.
o Avista customers who benefit from increased system reliability and efficiencies.
. The general community within our service territory who are impacted by
environmental issues.
¡ Cost (rounded to (þ0's)
¡Transformêrs Rcphced
33,ss23,391
Business Case Justification Narrative Page 7 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 19 of 325
Distribution Transformer Change Out Program 2017
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution Transformer
Change-Out Program and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in
Sectionl .1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
U-fun/
Cody kßgh t
Mgr Asset Maintenance
Business Case Owner
Bryan Cox
Sr Dir of HR Operations
Business Case Sponsor
Date: e -W- ?þ t}
Date:- ì7*\
Template Version: 0212412017
5 VERS¡ON HISTORY
Verslon lmplemented
By
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Cody Krogh 4t14t2017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative Page 8 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 20 of 325
Wood Pole Management
I GENERAL INFORMATION
Requested Spend Amount $9,000,001
Requesting Organization/Department Asset MaintenanceMood Pole Management
Business Gase Owner Mark Gabert
Business Case Sponsor Bryan Cox
Sponsor Organization/Department M51^¡úPM
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
Asset Management and Distribution Engineering provide ongoing analysis of
distribution asset condition. This analysis is used to direct the Wood Pole
Management work that includes inspecting and maintaining Avista's poles, hardware
and equipment on a twenty year cycle. The operating guidelines are documented in
the Distribution Feeder Management Plan (DFMP). The analysis is documented in
the Electric Distribution System 2016 Asset Management Plan. Asset Maintenance
then collaborates with Electric Operations and contractors to coordinate the work.
Asset Maintenance tracks the work budget, scope, and schedule.
2 BUSINESS PROBLEM
The major drivers for the program are system reliability, improved cost performance, and
reduced customer outages. These drivers are obtained by replacing defective poles,
associated hardware, and equipment at its end of life. The National Electric Safety Code
(NESC) is adopted as Washington State Law under WAC 296-45-045. More specifically
Part 013 describes the application, Part 121 describes the inspection interval, and Part
2l2\describes documentation and correction of the pole inspection results.
The current Wood Pole Management (WPM) program inspects and maintains the existing
distribution wood poles on a twenty year cycle and the transmission poles on a fifteen
year cycle. Avista has7,702 overhead distribution circuit miles. The average age of a
wood pole is twenty-eight years with a standard deviation of twenty-one years. Nearly
20o/o of all poles are over fifty years old and we have an estimated 240,000 Distribution
poles in the system. This means approximately 48,000 poles are currently over fifty years
old. Our current inspection cycle allows us to reach approximately 12,000 poles each
year. Along with inspecting the poles, we inspect distribution transformers, cutouts,
insulators, wildlife guards, lightning arresters, crossarms, pole guying, and pole grounds.
The average asset life of this equipment is fifty-five years and requires replacement along
Business Case Justification Narrative Page 1 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 21 of 325
Wood Pole Management
with the pole work. The inspections document asset condition and indicate what work is
required to replace assets that are damaged or near failure point. The asset condition is
observed and documented during the pole inspection process as indicated in both the S-
622 Specification for the lnspection of Poles, and the Distribution Feeder Management
Plan (DFMP). Designs and work plans are then created to replace the aging
infrastructure. The construction work to replace the assets is part of this program.
The work is required now to keep pace with the aging assets and expected failure rate.
Figure 1 below shows the increased rate at which the poles are reaching the seventy-five
year end of life. lf this work is not maintained the aging infrastructure will cause an
increasing rate of failures leading to increased outages and higher construction costs.
ln addition to the risks of outages and failures with the aging equipment, the additional
risks associated with this program pertain to the following:
Environmental: Risks include; large volume transformer oil spill, difficult
hazardous waste cleanup, moderate to low volume or level of PCBs, minimal
impact to watenruays, repeated or moderate air emission exceedance. lf the
program is unfunded the potential occurrence is greater than 4 spills per year. lf
funded, the potential occurrence is less than 1 per 50 years.
Public Safety and Health: Risks include: a potentialfor serious injury for crews or
the public, significant damage to equipment, property or business, public health
infrastructure impact up to 48 hours. lf the program is unfunded, the potential
occurrence is lessthan 1 per 10years. lf funded the potential occurrence is less
than 1 per 50 years.
Business Case Justifìcation Narrative Page 2 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 22 of 325
Wood Pole Management
Fìgure I- Pole Age ProJile
Wood Pole Age Profile
3.íYo
3.OY"
O.OYo
1910 1920 1930 L94o.19sO 1960 t970 1980
Year lnstalled
1990 2000 20Lo 2020
The Outage Management Tool (OMT) is used by Asset Management to track asset
conditions and show trends of failures of specific equipment that should be targeted for
replacement. This information is also used to track key Program performance as shown
in Table 1 below. The number of outage type events has been reduced by over 40%
from 2009 through 2015. This reduction in outage events results in significant customer
benefit. This reduction also demonstrates increased reliability and safety along with a
reduction in outages. The original goal for this KPI was to stay below the number of
events averaged over 2005-2009 for WPM Related OMT Events. The goal will be re-
evaluated in the future.
Êos5CLoCLgoÀ
oc,àotoç(¡,çt
(¡,
CL
Over 75 years
2.5Y"
2.OYo
l.sYo
L.OYo
O.sYo
Business Case Justification Narrative Page 3 of I
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 23 of 325
Wood Pole Management
Tøble I: Evenf Reduclion Resuhs
WPM Goal
Related
number of
OMT
Events
Actual
WPM
Related
number
of OMT
Events
Projected
Miles
Follow'up
Work**
Actual
Miles
Follow-up
Work
Completed
KPI
Desøiption
2009
2010
20LL
20L2
20L3
20L4
2015
1460
1460
1460
1460
1460
1.460
1460
t320
1004
1004
1013
816
905
760
500
450
459
416
445
4L2
390
372
435
333
435
329
38s
964
The type of OMT events are broken down into more detail in Table 2. Note there are
significant improvements to some events such as; annual squirrel events being reduced
from nearly 750 to around 240 events. This improvement has been realized by adding
wildlife guards to the top of transformers in order to prevent squirrels from touching
exposed power connections which can result in outages. Both the transformer and
cutout\fuse events have been reduced by over 50% through the replacement of aged
equipment. Table 2 also reveals a concerning upward trend of Pole-rotten events that
indicate the impact of the aging poles. Note that the calculated cost to customers for a
pole failure is $24,400 based on an average duration of 4.8 hours for 80 customers, per
Asset Management. Other key OMT events that have been significantly reduced from
2009 to 2016 include Transformer, CutouUFuse, and Squirrel. The combined cost impact
to customers in 2015 alone for those events was $2,265,600. See Figure 2.
Business Case Justification Narrative Page 4 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 24 of 325
Wood Pole Management
Figare 2: OMT Events
800
700goÉ ooo(¡,
0c
€ soo
-à ¿oo
ã ¡oo
u
=r*o 100
WPM OMT Events by Sub Reason
¡ 2008 t 2009 I 2010 I 2011 a2O12 )2013 i20l4 ts 2015 Û2076
OMT Event Sub Reason
4,792
4,932
5,010
8,770
4"902
{0,566
tzü00
?s
23xt
{s
r0
2ð
23
.".'C .*C *"--t ".-'"
qsø
eotu
,ø1 ,(ò
..*-C ,"t-
"".r.t-
^(
-."9$ò
0¿tt0t409û
0.208489350
0.¿l|0t¿02,!
0.2t l0?2023
0.1t10?¿0ls
0.2fi022023
0.t00,l8838
0.e0¿¿tlt39
0.186,130Ð0
0.tü0t00{e
0.241571914.
0¿t527t8a8i
t$,t0r
15,553
r3J24
{7,318
laJo'l
1{,87S
8,157
1,901
B,O',,l
28,120
t5?'t4
1¡t,901
t1,0?¿
Ultimately the impact of this Program can be associated with our Electric Systems
Reliability metrics. The System Average Interruption Frequency lndex (SAlFl)
represents the average number of sustained interruptions per customer for the year.
Avista reported a SAIFI score of 1.05 for the year 2015. The Asset Management group
created Table 2 below to show the impact of this Program to our overall SAIF¡ score.
The predicted contribution is about .211 which has a significant impact on the customer,
whereas without WPM the contribution to SAIFI would be 0.57. This means the
customer would experience 0.36 more outages per year without WPM. Without WPM
and the contribution to SAIDI would be 1.27(Hours).
Tuble 2: SAIFI Metrics
32
32
3¿
32
32
32
.t37
{37
t37
{37
'r3t
137
t1,600
t2,000
raü00
{2,800
rt,000
12,000
¿4
37
35
52
3{
55
¿3
Projected WPM
Contribution To The
Annual SAIFI
Number
Projected
Number of
Dast Poles
lnspected
Model Predicted
Material Use for
WPM Follow-up
Work
Pro.iected
Number of
Pole Rotten
OMT Events
Proiected
Number of
Crossam OMT
EventsDescription
Proiected
Metric
Actual
Metric
Descript¡on
2011
?912
2013
2014
2015
2009
2009
2015
2011
2012
2013
2014
Actual WPM
Contribution To The
Annual SAIFI
Number
Actual
Number of
Dist Poles
lnspected
Actual Material
Use for WPM
Follow-up Work
Actual
Number ol
Pole Rotten
OMT Events
Actual Number
of Crossarm
OMT Events
Business Case Justification Narrative Page 5 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 25 of 325
Wood Pole Management
3 PROPOSAL AND RECOMMENDED SOLUTION
Option GapitalCost Start Complete Risk Mitigation
Do nothing $o lncreases OMT events by 1700 events
Distribution Wood Pole Management
Program inspecfs all feeders on a 20
year cycle and repairs and replaces
wood poles, crossaÍfls, missing
lightning arresters, missing/stolen
grounds, bad cutouts, bad insulators,
leaking transformers, replace guy
wires not meeting current code
requirements when the pole ,s
replaced.
$9,000,000M 012017 122017 Annuailyrtndefinite
Alternative 1: Distribution Wood Pole
Management Program inspecfs all
feeders on a 20 year cycle and repairs
and replaces wood poles, crossaíns,missing lightning arresters,
missing/stolen grounds, bad cutouts,
bad insulators, leaking transformers,
replace guy wires not meeting current
code requirements when the pole is
replaced and replaces pre-l981
transformers
$10,712,022 012021 122021 Annually/indefinite
Alternative 2: Everything in Alternative
1 except completed on a 10 year
cycle.
$17,296,437 012021 012021 Annually/lndefinite
Based on analysis the current twenty year Wood Pole Management cycle delivers the
best life cycle value for the funding level. Alternative 2 would decrease the inspection
cycle down to ten years but at nearly double the capital cost. There is also additional
O&M cost to support alternative 2. Asset Management and Distribution Engineering will
continue to monitor system reliability to determine if adjustments are required in the
future.
Distribution Wood Pole Management is an ongoing cyclical program that proactively
replaces aging assets. By replacing assets before they fail, outage risks are reduced and
replacement costs are reduced through planned work. lnvesting in the infrastructure
increases life-cycle performance, safely, reliably, and is cost effective through the use of
unit based pricing. Figure 2 below shows the significant improvement in "events per mile
of feeder" resulting from this Program. The peak of events per mile was approximately 6
years ago when there were nearly 1.5 events per mile. The results after the Program
show performance as low as .3 events per mile of feeder.
Business Case Justification Narrative Page 6 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 26 of 325
Wood Pole Management
lf funding were to be reduced, expected outages would increase. The team would need
to prioritize which components would be replaced and which would be left. This would
increase the likelihood that crews would need to revisit the same pole later if a remaining
component were to fail.
FÍgure 3: Recluction of Events per mile before ønd afterfeeclers are completed.
Wood Pole Management & Grid Modification
Before and After
rfiys¡¿gs before WPM
, "....Average after Grid Mod
nfiys¡¿gs after WPM
oflys¡¿gs before Grid Mod
1.6Lo
I
81.4o
0Jl1'2o
oal=
8o.eø
0,
'ìo.sîto
I
å0.¿tâ
o
Èo.t
EJ=o
7-6-5-4-3 -2-1012
Before and After work (Years)
34567
^t\
I \I \^.
The primary stakeholders are Asset Management, Distribution Engineering,
Environmental, Real Estate, Asset Maintenance, Electric Operations, and our electric
customers.
Business Case Justification Narrative Page 7 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 27 of 325
Wood Pole Management
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution Wood Pole
Management and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:Date:,rfrr-llW 4t6t2017
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Mark Gabert
WPM Program Manager
Business Case Owner
Bryan Cox
Sr Dir of HR Operations
Business Case Sponsor
5 VERSION HISTORY
Date:
Template Version: 0212412017
9/tz I n
[Version#
lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Mark Gabert 04t13t17 Bryan Cox 04t14t17 lnitialversion
Business Case Justification Narrative Page 8 of 8
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 28 of 325
Primary URD Cable Replacement 2017
Requested Spend Amount $1,000,000
Requesting Organization/Department Asset Maintenance
Business Gase Owner Cody Krogh
Business Gase Sponsor Bryan Cox
Sponsor Organization/Department Asset Maintenance
Category Program
Driver Asset Condition
1 GENERAL INFORMAT¡ON
1.1 Steering Committee or Advisory Group lnformation
Cable condition and outage information is collected and analyzed by Asset
Management. This information is reviewed with Asset Maintenance to establish an
effective construction plan that prioritizes work based on faults and number of
customer impacted. Asset Maintenance then collaborates with Electric Operations
to coordinate the work. Asset Maintenance tracks the work budget, scope, and
schedule.
2 BUSINESS PROBLEM
The primary driver for the Underground Residential Development (URD) Cable
Replacement Program is to improve system reliability by removing URD cable with a high
failure rate. The other driver is to reduce O&M costs related to responding to customer
outages caused by the failed cable.
This work is needed to complete the replacement of the un-jacketed first generation
underground primary distribution cable referred to as URD cable. This first generation
URD Cable was installed from 1971to 1982. There was over 6,000,000 feet of URD cable
installed during this time period. Subsequent to installation the URD cable began to
experience an increasing failure rate. From 1992 to 2005 the cable failure rates
quadrupled from 2 faults to I faults per 10 miles of cable. The faults reached a peak of
238 annual failures in 2007. lncreased capital funding to replace this URD cable from
2OO5 through 2009 helped stabilize the failure rates. Continued funding and replacement
of the cable has enabled a downward trend in failures as shown below in table 1. Cable
installed after 1982 has not shown the high failure rate'
This work is required to continue to reduce primary URD cable failures and increase
reliability. Historically there have been over 200 cable faults per year. The average cost
to respond to a fault in 2015 was about $3000 per event due to the challenging nature of
the work to locate and repair the cable underground. The estimated remaining pre-1982
cable is around 1,000,000 circuit feet.
Business Case Justification Narrative Page 1 of4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 29 of 325
Primary URD Cable Replacement 2017
The tables below demonstrate the effectiveness of this program to reduce faults and
outage expenses through the replacement of the defective cable. The trend of cable
faults and expenses decrease over time as the older cable is removed from the system.
Tablel: URD Cable Replacement Results
Projected
URD
Cable -
Primary
OMT
Events
Actual
URD
Cable -
Primary
OMT
Events
Projected
Number
of Feet
Replaced
Actual
Number
of Feet
Replaced
KPI
Description
2009
2010
20Lt
20t2
20t3
20L4
20t5
L43
119
94
70
45
45
45
136
93
95
72
93
88
64
178,000
178,000
178,000
178,000
0
0
0
213,000
2L7,883
225,823
LL7,247
35,874
35,515
24,155
Table 2 URD Cable Replacement Cost lmpact
$1,039,613
st,229,275
s1,368,561
s1,516,159
5t,744,s99
S1,899,3u
5t,997,o52
S1,os6,llg
St,zgs,zzs
$1,,9s2,648
$1,481,504
St,4gA,7gg
S1,580,378
5t,720,O2O
Reference:
Electric Distribution System, 2016 Asset Management Plan
Projected Avoided
Outage Benefit due
to URD Cable - Pri
Caused Outages
ActualAvoided
Outage Benefit due
to URD Cable - Pri
Outages
Metric
Description
2009
20LO
20LT
20L2
20L3
20r4
2015
Business Case Justification Narrative Page 2 oÍ 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 30 of 325
Primary URD Cable Replacement 2017
3 PROPOSAL AND RECOMMENDED SOLUTION
Gapital Gost Start Complete
Do nothing $o
[Recommended Solution] Continue to Replace $1M 04 2017 122037
The Primary URD Cable Replacement Program requires design resources and
construction labor to complete the field work. There is also some analytics/engineering
to identify remaining cable segment locations. Given the projected low capital spend
level, the majority of the construction labor will be performed by Avista Crews. Contract
crews are typically used to plow in the cable, bore conduit or trench and install conduit in
the trench. Avista crews then pullthe cable into the conduit and complete the installation.
The Do Nothing approach presents significant reliability risk and added O&M cost. The
historic positive results from the URD cable replacement program shown above in section
two provide strong justification for continuing the current funding plan.
Over 6,000,000 feet of URD was installed before 1982. Programmed replacement of the
problem cable has been on-going at varying funding levels. The estimated remaining
pre-1982 cable is around 1,000,000 circuit feet. At the current proposed funding rate of
$1M per year this program is planned for the next 20 years. Reduced funding would
extend this time and result in additional outages and O&M expenses.
The URD Cable Replacement Program aligns with Avista's strategic vision by increasing
reliability to the electric distribution system. Safe and Reliable infrastructure is the focus
area for this program.
The projected annual capital spend of $1M per year is reasonable based on the realized
reduction in faults from previous work and this spend level enables continued
replacement of the high failure rate cable. Repair of the cable has not shown to be cost
effective because the cable typically faults in another location.
Avista customers will be positively impacted by this program by realizing fewer outages
from the URD cable failure. This results in improved system reliability. Avista electric
operations is positively impacted through converting this work to planned work that
enables more efficient use of labor. lt also reduces O&M expenses. Asset Management
is responsible for tracking URD cable outages from Outage Management Tool (OMT) and
tracking replacement locations and cost. The Asset Maintenance group is responsible
for identifying cable segments and managing the coordination of work.
Business Case Justification Narrative Page 3 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 31 of 325
Primary URD Cable Replacement 2017
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Primary URD Cable
Replacement and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Cody
Mgr Asset Maintenance
Business Case Owner
Bryan Cox
Sr Dir of HR Operations
Business Case Sponsor
Date: 4- I lJu- Zol
9 -\7 -\1
5 VERSION HISTORY
Date
Template Version: 03107 12017
Version lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1.0 Cody Krogh 4t14t2017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 32 of 325
New Revenue - Growth
1 GENERAL INFORMAT¡ON
Requested Spend Amount $47,443,826
Requesting Organ ization/Department Energy Delivery
Business Case Owner David Howell
Business Case Sponsor Heather Rosentrater
Sponsor Organization/Department Energy Delivery
Gategory Program
Driver Customer Requested
l.l Steering Committee or Advisory Group lnformation
The Energy Delivery Director Team assumes the role of advisory group for the New
Revenue - Grovuth Business Case, with quarterly reporting to the Board of Directors
through the Financial Planning & Analysis department. The appropriate extension
and service tariffs are designed and updated by the Avista Rates Department, in
cooperation with Construction Services, and the Financial Planning & Analysis
department. All Customer Project Coordinators are trained regularly, by Rates and
Finance, on tariff application.
2 BUSINESS PROBLEM
The New Revenue - Grovuth Business Case is driven by tariff requirements
that mandate obligation to serve new customer load when requested within
our franchised area. Growth is also seen as a method to spread costs over
a wider customer base, keeping rate pressure lower than would othen¡vise be
experienced.
Avista is required to serve appropriate new load, complying with our
Certificate of Convenience and Necessity, and as part of our Obligation to
Serve.
Avista uses a rolling 12-month Cost Per New Service spreadsheet to
measure ER1000, Electric New Revenue, and ER1001, Gas New Revenue
spending. Device blankets are subject to demand for both new revenue and
non-revenue installation and replacement.
Enclosed are lnternal Rate of Return runs from the Revenue Requirements
Model for each state and service, showing the breakeven spending to
achieve our current 7.29% authorized Rate of Return. These allow us to
periodically validate the Line Extension tariffs, to ensure that we are not
creating excessive rate pressure in connecting new customers.
a
a
a
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 33 of 325
New Revenue - Growth
3 PROPOSAL AND RECOMMENDED SOLUTION
o The New Revenue - Growth Business Case will provide funds for connecting
new Electric and Gas customers in accordance with our filed tariffs in each
state
. Our obligation to serve, mandates that we must extend service to new
customers in our franchised service areas. We do not currently have an
alternative to serving new customers. All projects are subject to our Line
Extension Tariffs, filed with each State Utility Commission.
r Enclosed is a spreadsheet showing projected spend through 2021 with a
breakout by Expenditure Request for the New Revenue - Growth Business
Case. Electric and Gas devices are also included, such as Meters,
Transformers, Gas Regulators, and ERTs (Encoder Receiver Transmitter).
Many of the Meters, Transformers, and ERTs are used as replacements for
Transformer Change Out Program, Wood Pole Management, and Periodic
Meter Changes. The costs are allocated based on an estimate of how many
devices of each type will be used for replacement, rather than new connects.
Those splits are shown on the spending summary.
o The New Revenue - Growth Business Case serves as support of several
focus areas in Avista. We seek to serve the interests of our customers, in a
safe and responsible manner, while strengthening the financial performance
of the utility. Our growth contributes to strong communities, ongoing value to
our customers, and the device portion of the business case keeps our system
safe and reliable.
o The requested funds are broken down in the enclosed spreadsheet, and
value assigned to each component.
o All new customers on Avista's system are benefitted by this business case.
ln addition, all customers who have their metering or regulation changed, or
who have transformers replaced, benefit from this business case.
Optlon Gapltal Goct StaÉ Gomplete
Do nothing $0
Se¡ve new customer load, and purchase appropriate
devices
$47,443,826 01 2017 12 2099
No other alternatives allowed under current tariff.$M MM YYYY MM YYYY
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 34 of 325
New Revenue - Growth
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the New Revenue - Growth
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives
il*USignature:
Print Name
Title:
Role:
David Howell
Director, Operations
Business Case Owner
Date: A t1
Date 4 lt-z ltl
Date
Tem pf ate Version : Ogl07 12017
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Heather Rosentrater
Vice President, Operations
Business Case Sponsor
Steering/Advisory Com mittee Review
5 VERSION HISTORY
Verclon lmplemented
BV
Revlolon
Date
Approved
By
Approval
Dato
Roason
1.0 NeilThorson 03/17/17 Heather
Rosentrater
03/17/17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 35 of 325
ER
1000 Electr¡c New Revenue
ResidentialConnects
Residentia I Cost/Svc
Residential Dollars
20L6 20t7 2018 20t9 2020 202L
5,030
2,300
5,060 4,886
2,500
5,067
2,50O
5,L77
2,500
5,L77
2,5002,500
11,569,000 12,650,000 12,215,000 12,667,500 t2,942,500 12,942,500
1,000
2,219
8s0
2,500
82L
2,500
851
2,500
870
2,500
870
2,500
CommercialConnects
Commercial Cost/Svc
Commercial Dollars
ER1000 Total
1001 Gas New Revenue
Residential Connects
Residential Cost/Svc
Residential Dollars
Commercial Connects
Commercial Cost/Svc
Commercial Dollars
ER1001 Total
tOO2 Electric Meters
8R1002 Total
1003 Transformers
Growth and Other
WPM
TCOP
Fdr Rebuild
ERl003 Total
1004 Street Lights
ER1004 Total
1005 Area Lights
ERl005 Total
1009 NetworkProtectors
ERl009 Total
1050 Gas Meters
Growth
PMC
ERl050 Total
2,ztg,goo
t3,787,got
5,295
2,384
2,725,0O0
14,775,0O0
5,
2,051,,927
t4,266,927
5,479
3,095
2,127,940
14,795,440
2,t74,735
15,116,635
5,774
3,095
2,174,735
15,116,635
3,
5,744
3,095
L2,624,683 17,592,80L 16,955,3L3 L7,503,058 17,868,220 L7,775,382
656
095
68s
095
5,
3,
500
2,384
s60
3,000
540
3,000
557
3,000
s69
3,000
s66
3,000
7,192,L33 1,680,000 L,6L9,L24 L,671,,430 7,706,301 1,697,435
13,816,818 t9,272,8O1, 18,574,437 L9,174,488 t9,574,521 L9,472,8t8
550,000 550,000 550,000 500,000 500,000 500,000
550,000 550,000 550,000 500,000 500,000 500,000
3,134,000
L00,000
3,000,000
266,400
6,500,400
516,75r
L,427,68t
1,944,432
3,196,680
300,000
2,000,000
266,400
5,763,080
556,867
1,,470,512
2,027,379
3,260,674
350,000
2,000,000
266,400
5,877,OL4
536,688
L,51,4,627
2,05t,3L6
3,325,826
1,200,000
266,400
4,792,226
554,026
1,560,066
2,LLA,092
3,392,342
L,200,000
266,400
4,858,742
565,585
1,606,868
2,L72,453
3,460,189
1,200,000
266,400
4,926,589
562,646
r,655,074
2,217,720
700,000 900,000 900,000 900,000 900,000 900,000
700,000 900,000 900,000 900,000 900,000 900,000
625,000 650,000 675,000 700,000 700,000 700,000
625,000 650,000 675,000 700,000 700,000 700,000
950,000 960,000 980,000 980,000 980,000 980,000
950,000 960,000 980,000 980,000 980,000 980,000
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 36 of 325
1051 Gas Regulators
Growth
PMC
ERlO5l Total
1053 Gas ERTs
Growth
PMC
ERT Replacement
ERl053 Total
1108 Hallett & White subst
ERl009 Total
Growth Business Case Summary
Electric New Revenue
Gas New Revenue
Electric Meters
Transformers
Street Lights
Area Lights
Network Protectors
Gas Meters
Gas Regulators
Gas ERTs
Hallet & White Subst
TotalGrowth
1,900,000 950,000 950,000
1,900,000 950,000 950,000
ER1000
ER1001
ER1002
ER1003
ERr.004
ER1005
ER1009
ER1050
ER1051
ER1053
ER1108
15,116,635
L9,472,878
500,000
4,926,589
900,000
700,000
980,000
2,2L7,720
5L5,989
7,227,269
103,350
237,668
341,018
222,203
479,803
1,577,297
2,2L9,297
237,997
244,798
482,795
278,575
494,L96
400,000
L,ll.2,77t
L4,775,OO0
t9,272,80L
550,000
5,763,080
900,000
650,000
960,000
2,027,379
482,795
t,'1,L2,77t
950,000
47,443,826
229,373
252,742
481,515
2L0,655
509,022
4L2,OOO
1,13t,677
14,266,927
L8,574,437
550,000
5,877,0L4
900,000
675,000
980,000
2,05t,376
481,515
L,131,677
950,000
46,437,885
236,783
259,706
496,489
2t7,460
524,293
424,360
1,166,113
L4,795,440
L9,t74,488
500,000
4,792,226
900,000
700,000
980,000
2,Lt4,092
496,489
t,t66,713
24L,723
267,497
509,220
22L,997
540,02L
437,09t
1,199,109
15,LL6,635
!9,574,52L
500,000
4,858,742
900,000
700,000
980,000
2,L72,453
509,220
L,L99,109
240,467
275,522
515,989
220,843
556,222
450,204
t,227,269
73,787,90L
13,816,818
550,000
6,500,400
700,000
625,000
950,000
7,944,432
34L,018
2,2L9,297
1,900,000
43,334,866 45,6L8,847 46,510,681 46,557,02L
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 37 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 38 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 39 of 325
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GN REV REQ ID CAIIbTAIEd IR
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 40 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 41 of 325
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s.12%
66.6%
76.26%
a9.85%
1G.9ø
737.6%
$5.07%
2&.27%
565.ry
z@a.@%
461 p |tli2d maør
GN REV REQ M CAIIbIAIEd TR
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 42 of 325
Distribution Minor Rebuild
I GENERAL INFORMATION
Requested Spend Amount $12,300,000
Requesting Organ ization/Department Electric Operations
Business Case Owner Cody Krogh
Business Case Sponsor Bryan Cox
Sponsor Organization/Department Operations
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Distribution Minor Rebuild work is overseen by the local area operat¡ons
engineers, general foremen, and area construction managers. Often, the work
addresses failed asset replacements or customer requests that are unplanned.
Occasionally, larger projects with an identified need and short timeframe for
implementation are constructed under the Distribution Minor Rebuild business.
Minor Rebuild work occurs regularly and historical averages are used to estimate
the appropriate funding allocations.
The local area operation engineers, general foremen, and area construction
managers manage the work as it is identified throughout the given construction
season. A more formal governance is currently being developed for this business
case, which will provide a check or gate on which projects in the business become
approved for scheduling.
2 BUSINESS PROBLEM
The work done under the distribution minor rebuild is driven by keeping the
distribution system in reliable condition for customers and safe condition for the
workers, responsiveness to unplanned damaged to distribution assets not related
to weather events, as well as small customer driven rebuilds. Throughout the entire
distribution system, minor rebuilds or replacements of asset units need to be
completed to maintain system reliability and safety.
Below is a categorical breakdown which fall within the Distribution Minor Rebuild
business.
Gustomer Requested Rebuilds - Work is initiated by an existing customer or
property owner, and the costs associated with the work are typically reimbursed by
the requesting party.
Trouble Related Work - Work required to repair damaged facilities related to non-
storm related outages. A common example of trouble related work is a car hit pole.
Joint Use Requested Rebuilds - "Make-ready" work required to existing facilities
in order to accommodate joint use installations. The costs associated with the joint
use work are typically reimbursed by the requesting joint use party(s).
Business Case Justification Narrative Page 1 of6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 43 of 325
Distribution Minor Rebuild
Deteriorated Pole Replacements - Changing out isolated wood poles that fail
Avista's inspection standards that are not on schedule for a planned replacement
under Avista's Asset Maintenance programs.
General Rebuilds - Work can be initiated through a variation of sources. General
rebuild work is typically small in scope (i.e. one ortwo poles) and typically addresses
unplanned work that is identified as priority because of:
o NESC code violations (e.9., inadequate clearance)
o Failed or failing equipment (e.9., rotten cross-arms)
o lnadequately sized or classed equipment for serving an existing
customer or group of customers (such as an undersized transformer
or fuses)
o Other minor projects include minor loop feeds, installing air switches,
line regulators, line reclosers, and short reconductoring projects for
reliability improvements.
Figure I shows a pie chart of the mentioned categorical breakdown to demonstrate
the magnitude of each category. The figure gives a three year average, which has
remained h istorically constant.
Minor Rebuild Categorical Breakdown (2014 - 20L6)
s7L,444,L%Sggg,67t,7%
Sz,3oz,gzo,t,yo
s249,r93,2%
s8,3L2,497,7L%
r Customer Requested
i, General Rebuilds
r Trouble Related
r Deteriorated Pole Replacements
r Joint Use Requested
Figure I: Dislribulion Minor Rebuild Cntegorictl Breskdowtt
Business Case Justification Narrative Page 2 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 44 of 325
Distrib ution M i nor Rebuild
f n 2016, 1,115 work orders were created with the average cost equaling only $4,400,
which demonstrates the business is made of thousands of small dollar amount jobs.
Occasionally larger rebuild projects, such as small reconductor project, are
undertaken as Distribution Minor Blanket projects. A common reason is the work is
considered critÍcal and non-discretionary. Only 28 work orders were created over
$25,000, averaging $54,000 per work order in 2016.
Figure 2 displays a breakdown of the different types of charges that occur in the
Minor Rebuild. The majority of charges are from specific work orders. Distribution
Minor Rebuild work often consists of isolated, replacement of failed asset(s) that do
not lend themselves to a specific project (i.e. trouble related work), which are
charges falling under craft and non-craft expenditures.
2016 Types of Charges to Minor Rebuild
I Craft Related Project Expenditures
r Specific Work Order Charges
I Non-Craft Related Project Expenditures
Figure 2: Types of Charges to Minor Rebuild (2016)
The following is a brief description of each type of charge.
. Graft Related Project Expenditures: Craft labor (servicemen, general
foremen, local rep), associated vehicle usage, trouble related work charges
. Non-Graft Related Project Expenditures: Non-craft labor, associated vehicle
usage, contribution reimbursables (credits), and material issues/returns
. Specific Work Order Charges: The work order is referenced on timesheets,
material requests, invoices, and vehicle charges/loadings.
Distribution Minor Rebuild work is one of the many components that contribute to
the overall reliability of the distribution system as well as responsiveness to
customer requested service demands and system safety. Safety is of utmost
concern for linemen and the general public and the minor rebuild business funds
the replacement of a car-hit pole in the alley, a broken cross-arm, a burned up
transformer, or fixes a joint use code violation, and a myriad of other safety
17%
25%
58%
Business Case Justification Narrative Page 3 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 45 of 325
Distrib ution M i nor Rebu i ld
related projects. By not funding the business will also affect the ability to respond
to customers' needs for modifications to their electrical service. Lastly, it is
acknowledged some minor rebuilds left unrepaired will not result in immediate
catastrophic failures to the distribution system (i.e. a broken pole pin insulator),
but over time an adverse accumulation of unrepaired assets would greatly put
line workers and the general public at risk as minor asset failures begin to
deteriorate pockets of the distribution system.
3 PROPOSAL AND RECOMMENDED SOLUTION
Figure 3 is the historical spend required to fully fund the Minor Rebuild business
Historical Minor Rebuild Costs l2OL4 - 20161
SL4,ooo,ooo
S12,38&u5
S12,ooo,ooo 5LL,769,tzs
slo,ooo,ooo sg,00g,015
$B,ooo,ooo
$6,ooo,ooo
$4,ooo,ooo
S2,ooo,ooo
s{2,000,00o}
s-
I Trouble Related Rebuilds
I Joint Use
I General Minor Rebuilds
I Deteriorated Pole Replacement
I Customer Requested
2014
S1,478,356
S190,489
s6,389,e64
S892,854
s251,5s0
2015
Sz,4oo,L79
$261,069
58,474,276
$678,196
$(3s,7es)
2016
S2,665,215
S2sq814
$9,703,540
5782,397
5lt7,7e2l
Figure 3: Minor Rebuild Historical Spend
Figure 3 shows a steady increase in costs for unplanned minor rebuild work from
2014 to 2016. The categories of Joint Use, General Minor Rebuilds, and Trouble
Option CapitalCost Start Complete
Unfunded $o N/A
Fund Unplanned Work (based on historical
quantities)
$12,300,000 Continuous
Program
Business Case Justification Narrative Page 4 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 46 of 325
Distribution Minor Rebuild
Related Rebuilds increased annually over the three years, while Deteriorated
Pole Replacements remained steady in costs. Customer Requested Rebuilds are
typically a credit to the business because most are reimbursed in part or in full by
the customer. As shown in 2014, Customer Requested Rebuilds are not always
reimbursed back to the business.
The Distribution Minor Rebuild business reaches across multiple departments in
Engineering and Operations. The business involves operation area engineers,
local customer project coordinators, and construction technicians who work
directly with customers and perform all the designs for the business. Once the
minor projects are designed and ready for construction, field personnel such as a
Foremen, Journeyman Linemen, Line Servicemen, Meter men, Equipment
Operators execute the work.
The Distribution Minor Rebuild business provides a solution for the utility to
address small unplanned asset failures and customer driven modifications to the
distribution system, but excludes fixes to the system considered to be
maintenance. While the work is unplanned, minor rebuilds to the distribution
system occur on a regular basis every year and make up a significant portion of
the business within Engineering and Operations. While unplanned and isolated
minor rebuilds will always exists in the distribution system, unplanned work is
minimized to the greatest extent through other systematic infrastructure
programs.
The Distribution Minor Rebuild business reaches across multiple departments in
Engineering and Operations. The business involves operation area engineers,
local customer project coordinators, and construction technicians who work
directly with customers and perform all the designs for the business. Once the
minor projects are designed and ready for construction, field personnel such as a
Foremen, Journeyman Linemen, Line Servicemen, Meter men, Equipment
Operators execute the work.
The Distribution Minor Rebuild business provides a solution for the utility to
address small unplanned asset failures and customer driven modifications to the
distribution system, but excludes fixes to the system considered to be
maintenance. While the work is unplanned, minor rebuilds to the distribution
system occur on a regular basis every year and make up a significant portion of
the business within Engineering and Operations. While unplanned and isolated
minor rebuilds will always exists in the distribution system, unplanned work is
minimized to the greatest extent through other systematic infrastructure
programs.
The Distribution Minor Rebuild business aligns with the company's focus of Safe
& Reliable lnfrastructure, to invest in our infrastructure to achieve optimum life-
cycle performance - safely, reliably and at afair price.
Business Case Justification Narrative Page 5 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 47 of 325
Distribution Minor Rebuild
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution Minor Rebuild
and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
U, **.Date: 4-t¿{ -zelT
Cody xro{
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
l/
Mgr Asset Maintenance
Business Case Owner
Bryan Cox
Sr Dir of HR Operations
Business Case Sponsor
Date 4 -\'l - \-')
Tem plate Version : 0212412017
5 VERSION HISTORY
Version
#
lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Landen Grant 4t13t2017 Cody Krogh 4t1412017 lnitial version
Business Case Justification Narrative Page 6 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 48 of 325
Meter Minor Blanket
2
1 GENERAL INFORMATION
Reguesúed Spend Amount $505,000.
Req u esti n g O rg a n izatio nlDepaftm ent 208/Electric Meter Shop
Business Case Owner Dan Austin
Buslness Case Sponsor Bryan Cox
Sponsor O rg a n izati onl Depattm ent Operations
Category
Driver
"Note: 201T Request ínctudes additional one time request of 8205,000 for the A-base meter replacement project. Th¡s
work is ín support of the AMI project.
1.1 Steering Committee or Advisory Group lnformation
The determination for how the funds in this business case will be spent is a joint
decision made by the Manager and General Foreman. A meter usage forecast will
be used to guide the decision making process. The forecast will be based on the
past five years of meter installs, current install rates, and manufacturer lead times.
BUS'NESS PROBLEM
The primary driver for this business case is failed plant and operations. We regularly
experience failed plant when meters and/or metering equipment fails. Meters are a
criiical component to supplying our customers with electricity and to accurately
measure their energy consumption. Please refer to Attachment 1 for the most
recent meter failure analysis completed by Asset Management in early 2017. This
analysis shows the failure curves for both digital and mechan¡cal meters. The
analys¡s suggests that the more digital meters that are installed the higher the meter
failuie rate becomes. However, mechanical meters are no longer manufactured by
our meter vendors because they have moved to the digital market.
When meters fail at existing customer service point's immediate action must be
taken to repair or replace the meter. This is because a failed meter will not provide
accurate consumption data. Funding is necessary to replace or make needed
repairs othenryise the customer billing data will have to be estimated. Billing
estimation lowers the quality of service we provide our customers because
estimated data can be viewed by the customer as inaccurate. Additionally,
estimated billing data can put rate pressure on our customer base if usage is under
estimated. lf usage is over estimated it unfairly penalizes the customer whose bill
is being estimated.
Business Case Justification Narrative Page 1 of6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 49 of 325
Meter Minor Blanket
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capttal
Cosú
O&M Cost SÚalf Complete
Fully fund new electric
meter purchases
$505,000 $0 01 2017 12 2017
RMA meters 313,994 $278,448.72 01 2017 12 2017
Repair or Refurbish meters 313,994 $281,013.48 01 2017 12 2017
This business case will reduce the O&M required to replace failed meters. As you
can see tabulated in the above table the lowest cost option is to fully fund this
business case. The reduction in O&M is associated with the meter replacement
portion of this business case.
Historically there has been three solutions to replace failed meters:
1.) Refurbish and rePair in house
2.) Return Merchandise Authorization (RMA)
3.) Replace failed meter with new meters
3.1 REFURBISH AND REPAIR IN HOUSE
As Avista's population of digital meters grows and the mechanical meter population
shrinks the less viable this option becomes. This is because digital meters require
special equipment and training to repair, which is not available to our technicians.
Also of note is that mechanical meters are no longer manufactured by our meter
vendors because they have moved to the digital market. lt is very rare for our
technicians to remove a mechanical meter from the field as a result of failure. The
majority, if not all, of the meter failures we experience in a given year are from the
digital meter farnilies. Table 1 shows how many digital and mechanical meters we
have installed in WA and lD. This table also shows the average failure rate we
experience annually. This option was not chosen due to the equipment and
technical training required as well as the higher cost associated with the labor to
refurbish meters.
Meter Type
Qtv.
Single-Phase Mechanical 172,215
Single-Phase Digital 1 87,1 00
Poly-Phase Mechanical 5,781
Poly-Phase Digital 17,346
Total 382,442
Average failures per year 3882
Table 1: Meter Quantities bY TYPe
Business Case Justification Narrative Page 2 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 50 of 325
Meter Minor Blanket
ChargeType Cosú
Refurbish Labor $37.26
lnstall Labor $35.76
Total $73.02
Table 2: Tabulated Cost to Refurbish Meters
3.2 RETURN MERCHA TDTSE AUTHORIZATION (RMA)
Option 2 is more costly than purchasing new meters due to the manufacturer's
costs, shipping costs, and labor associated with the RMA process. Recent repair
costs were quoted from our meter vendor to be between $20 and $40 dollars per
meter. Table 3 shows the totalcostto RMA a single meter. This costwas developed
using very conservative values for each charge type and may be higher if more
expensive (Poly-phase) meter types were included. This option was not chosen
due to the high cost.
Charge Type Cosf
RMA Labor $9.31
Shipping $7.17
Repair Charges $20.00
lnstall Labor $35.76
Total $72.74
Table 3: Tabulated Cost to lnstall RMA Meters
3.3 REPLACE FAILED METERS WTH NEW METERS
The final option is to purchase meters new for meter failure replacements. This is
the lowest cost solution as shown in Table 4. There is a cost savings with new
meters because there is no labor associated with refurbishing and testing and there
is no RMA charges as compared to Options 1 and 2. This business case supports
Options 3 to purchase new meters to replace failed meters.
Charge Type Cosú
Purchase Cost $20.43
Labor $35.76
Total $56.1 9
Table 4: Tabulated Cost to lnstall New Meters
Business Case Justification Narrative Page 3 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 51 of 325
Meter Minor Blanket
Do nothing is not an option because at minimum we need functioning meters to
replace failed meters. Doing nothing would keep Avista from accurately billing our
existing customer base.
Business Case Justification Narrative Page 4 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 52 of 325
Meter Minor Blanket
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Meter Minor Blanket and
agree with the approach it presents and that it has been approved by the steering
committee or other governance body identified in Section1.1. The undersigned also
acknowledge that significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
Signature:
Print Name:
Title:
Role:
Dan n
Electric Meter Shop Manager
Business Case Owner
Date:¿/ - tq-2o17
Date -\
Date
Template Version : 03107 12017
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Bryan Cox
Sr Dir of HR Operations
Business Case Sponsor
Steering/Advisory Com mittee Review
5 VERSION HISTORY
Version lmplemented
By
Revísion
Date
Approved
By
Approval
Date
Reason
1.0 Dan Austin 4t13t2017 Bryan Cox 4t1412017 lnitialversion
Business Case Justification Narrative Page 5 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 53 of 325
Meter Minor Blanket
Attachment 1: Electric Meter Model Review
t;L,.ril
Electric Meter
Model Review.pptx
Business Case Justification Narrative Page 6 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 54 of 325
Electric Relocation and Replacement Program
I GENERAL INFORMATION
Requested Spend Amount $2,750,000
Requesting Organ ization/Department Operations
Business Gase Owner Cody Krogh
Business Gase Sponsor Bryan Cox
Sponsor Organization/Department Operations
Category Program
Driver Mandatory & Compliance
l.l Steering Committee or Advisory Group lnformation
The Electric Distribution and Transmission Relocation and Replacement Program
work is overseen by the local area operations engineers and area construction
managers. The work is mostly unplanned and non-specific in nature, but occurs
regularly and historical averages are used to estimate a quantity. The local area
operation engineers and area construction managers manage the work as it is
identified throughout the given construction season.
2 BUSINESS PROBLEM
The Electric Distribution and Transmission Road Moves/Relocation program is
driven by compliance mandated by "Franchise Agreement" contracts with local city
and state entities and "permits" issued by Railroad owners. ln general, a
"Franchise Agreement" generally refers to a non-exclusive right and authority to
construct, maintain, and operate a utility's facility using the public streets,
dedications, public utility easements, or other public ways in the Franchise Area
pursuant to a contractual agreement executed by the City and the Franchisee.
Although each Franchise Agreement or permit is a little different, they all serve a
similar purpose in providing for utility access along city, county, state and railroad
right-of-way (ROW). The agreement(s) make provisions forAvista to installelectric
equipment along these ROW's in order to provide service to Avista customers.
Within each agreement are provisions for relocation of utilities at the request of the
ROW owner. These request are usually driven by road and or sidewalk re-design
projects. For reference, franchise 95-0990 recorded with Spokane County
paragraph Vl states "lf at any time, the County shall cause or require the
improvement of any County road, highway or right-of-way wherein Grantee
maintains facilities subject to this franclz.se by grading or regarding,
planking or paving the same, changing the grade, altering, changing,
repairing or relocating the sarre or by constructing drainage or sanitary
sevyer facilities, the grantee upon written notice from the county engineer
shall, with all convenient speed, change the location or readjust the elevation
of its system or other facilities so that the same shall not intertere with such
County work and so that such lines and facilities shall conform to such new
Business Case Justification Narrative Page 1 of4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 55 of 325
Electric Relocation and Replacement Program
grades or routes as may be esfabft.shed." For example, a State Department of
Transportation (DOT) is widening an intersection or highway, which requires Avista
to relocate their overhead or underground electric facility to accommodate the new
DOT design. A smaller example for instance is a local municipality is installing new
ADA ramps on the corners of local street intersections, which sometimes requires
Avista to relocate a utility pole to accommodate the new ramp design.
The Electric Relocations are agreed to and executed per the jurisdictional
Franchise Agreement or Permit.
Work under Franchise Agreements or Permits are contractual, agreed upon, and
if the terms of the agreement or permit are not executed a breach of contract will
likely ensue. Also, state and local government departments which oversee
highways, roads, and city streets incorporate the guidelines set forth in the
American Association of State Highway Transportation Officials (AASHTO)
Roadside Design Guide into the design of the highways and roads. The guidelines
are based on the type of roadway and posted speed, but generally do not allow for
any fixed objects inside the traveled way or sides of the roadway ("clear zones")
for public safety. As a result, nearly all new road projects require utilities to relocate
or remove all poles inside and outside the traveled way. The new roadside design
guidelines allow for placement of new facility in a location that improves the safety
of the driving public, thus reduces risk to Avista. Avista designers coordinate with
each state or local road project to ensure the new relocations meet the clear zone
standards, yet minimize cost. Most Franchise Agreements have provisions to
prohibit the ROW owner from requiring the utility to move the same facility more
than once over a span of years, usually five.
The asset conditions replaced through Electric Relocations can vary since the
relocations are unplanned and therefore not coordinated with Avista's Asset
Maintenance programs. Most assets in an Electric Relocation project are replaced
because they are unsalvageable and close to their useful life. ln the case of
relocating newer assets, efforts are made to re-use as much material as possible.
Under a Franchise Agreement or Permit, Avista is allowed to occupy space within
a ROW owned by the respective jurisdiction in order to serve its customers. Electric
relocations occur every year during the construction season, but are unplanned,
so historical trends are used to estimate the annual cost to fully fund all the
relocation projects. The annual costs of electric relocations has very little variance
year to year, therefore fully funding the business will likely ensure all electric
relocations under Franchise Agreements or Permits will be completed.
Business Case Justification Narrative Page 2 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 56 of 325
Electric Relocation and Replacement Program
3 PROPOSAL AND RECOMMENDED SOLUTION
Electric Relocation projects are managed, coordinated, and executed within the
Operations department. When a transportation agency has a road project requiring
Avista to relocate its facility, a Customer Project Coordinator (CPC) is designated
full time to coordinate the project with the agency as the direct contact from Avista.
The CPC manages, coordinates, and designs the relocation of Avista's distribution
or transmission facility. He or she will meet with line foreman in the field to scope
out the project and identify any construction obstructions (i.e. equipment access).
The Real Estate group, under Environmental Affairs, often is involved in Electric
Relocation projects to obtain further easements or get permits approved.
Because the Electric Relocations business is unplanned work, contractually
obligated, and adds high risk to the company if not completed, no alternative
analysis is considered. This program is demand driven and unplanned work.
Funding allocation is based on historical spending trends. The graph below shows
the historical spend for Electric Relocation (2011 -2016). The average spend over
the six years is $2.3 million. However, rt 2014 spend is thrown out as an outlier, it
is clear the trend in electric relocations is trending upward. Because electric
relocations are directly correlated with the number of highway and street projects,
the reason for the upward trend in spend is likely an increase in transportation
project spending.
Electric Relocation Historical Spend (2011- 2016)
$3,500,000
s3,000,000
Sz,5oo,ooo
s2,000,000
S1,5oo,ooo
s1,000,000
S5oo,ooo
$-
s3,206,007
52,669,472
s2,3gg,o10
5'-,37t,o57
20tl 2012 20L3 2014 20t5 2016
The primary external stakeholders in the business include all state and local
transportation governments as well as customers since they live in the territory
governed by these agencies and use the transportation system.
S2,060,539 52,tL5,597
Option CapitalCost Start Complete
Unfunded $o
Fully Funded $2,750,000 Ongoing
_Program
Business Case Justification Narrative Page 3 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 57 of 325
Electric Relocation and Replacement Program
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Relocation and
Replacement Program and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in
Sectionl.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
(*.-furw Date: 4-t¿+- zo a+
Date L1 _lz-\7
Tem plate Version : 031 07 12017
Cody xrodn 7
Mgr Asset Maintenance
Business Case Owner
Bryan Cox
Sr Dir of HR Operations
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
BY
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Cody Krogh 4t14t2017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 58 of 325
Primary URD Cable Replacement 2017
Requested Spend Amount $1,000,000
Requesting Organization/Department Asset Maintenance
Business Case Owner Cody Krogh
Business Gase Sponsor Bryan Cox
Sponsor Organization/Department Asset Maintenance
Gategory Program
Driver Asset Condition
I GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Cable condition and outage information is collected and analyzed by Asset
Management. This information is reviewed with Asset Maintenance to establish an
effective construction plan that prioritizes work based on faults and number of
customer impacted. Asset Maintenance then collaborates with Electric Operations
to coordinate the work. Asset Maintenance tracks the work budget, scope, and
schedule.
2 BUS¡NESS PROBLEM
The primary driver for the Underground Residential Development (URD) Cable
Replacement Program is to improve system reliability by removing URD cable with a high
failure rate. The other driver is to reduce O&M costs related to responding to customer
outages caused by the failed cable.
This work is needed to complete the replacement of the un-jacketed first generation
underground primary distribution cable referred to as URD cable. This first generation
URD cable was installed from 1971to 1982. There was over 6,000,000 feet of URD cable
installed during this time period. Subsequent to installation the URD cable began to
experience an increasing failure rate. From 1992 to 2005 the cable failure rates
quadrupled from 2 faults to I faults per 10 miles of cable. The faults reached a peak of
238 annual failures in 2007. lncreased capital funding to replace this URD cable from
2OO5 through 20Og helped stabilize the failure rates. Continued funding and replacement
of the cable has enabled a downward trend in failures as shown below in table 1. Cable
installed after 1982 has not shown the high failure rate.
This work is required to continue to reduce primary URD cable failures and increase
reliability. Historically there have been over 200 cable faults per year. The average cost
to respond to a fault in 2015 was about $3000 per event due to the challenging nature of
the work to locate and repair the cable underground. The estimated remaining pre-1982
cable is around 1,000,000 circuit feet.
Business Case Justifìcation Narrative Page 1 of4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 59 of 325
Primary URD Cable Replacement 2017
The tables below demonstrate the effectiveness of this program to reduce faults and
outage expenses through the replacement of the defective cable. The trend of cable
faults and expenses decrease over time as the older cable is removed from the system.
Tablel: URD Cable Replacement Results
Projected
URD
Cable -
Primary
OMT
Events
Actual
URD
Cable -
Primary
OMT
Events
Projected
Number
of Feet
Replaced
Actual
Number
of Feet
Replaced
KPI
Description
2009
20LO
20LL
20L2
20L3
20L4
20L5
L43
119
94
70
45
45
45
Table 2: URD Cable Replacement Cost lmpact
S1,03a,613
sr,229,275
$1,368,561
S1,516,159
$L,74r,s99
S1,998,311
$t,997,o52
136
93
95
72
93
88
64
178,000
178,000
178,000
178,000
0
0
0
213,000
2I7,883
225,823
L17,247
35,874
35,515
24,155
S1,056,113
st,295,225
St,ïsz,6qg
$1,481,504
$1,494,799
$1,580,379
$t,7zo,ozo
Reference:
Electric Distribution System, 2016 Asset Management Plan
Projected Avoided
Outage Benefit due
to URD Cable - Pri
Caused Outages
ActualAvoided
Outage Benefit due
to URD Cable - Pri
Outages
Metric
Description
2009
2010
20LL
20t2
20t3
20L4
20L5
Business Case Justification Narrative Page 2 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 60 of 325
Primary URD Cable Replacement 2017
3 PROPOSAL AND RECOMMENDED SOLUTION
Gapital Cost Start Complete
Do nothing $o
[Recommended Solution] Continue to Replace $1M 04 2017 122037
The Primary URD Cable Replacement Program requires design resources and
construction labor to complete the field work. There is also some analytics/engineering
to identify remaining cable segment locations. Given the projected low capital spend
level, the majority of the construction labor will be performed by Avista Crews. Contract
crews are typically used to plow in the cable, bore conduit or trench and install conduit in
the trench. Avista crews then pullthe cable into the conduit and complete the installation.
The Do Nothing approach presents significant reliability risk and added O&M cost. The
historic positive results from the URD cable replacement program shown above in section
two provide strong justification for continuing the current funding plan.
Over 6,000,000 feet of URD was installed before 1982. Programmed replacement of the
problem cable has been on-going at varying funding levels. The estimated remaining
pre-1982 cable is around 1,000,000 circuit feet. At the current proposed funding rate of
$1M per year this program is planned for the next 20 years. Reduced funding would
extend this time and result in additional outages and O&M expenses.
The URD Cable Replacement Program aligns with Avista's strategic vision by increasing
reliability to the electric distribution system. Safe and Reliable infrastructure is the focus
area for this program.
The projected annual capital spend of $1M per year is reasonable based on the realized
reduction in faults from previous work and this spend level enables continued
replacement of the high failure rate cable. Repair of the cable has not shown to be cost
effective because the cable typically faults in another location.
Avista customers will be positively impacted by this program by realizing fewer outages
from the URD cable failure. This results in improved system reliability. Avista electric
operations is positively impacted through converting this work to planned work that
enables more efficient use of labor. lt also reduces O&M expenses. Asset Management
is responsible for tracking URD cable outages from Outage Management Tool (OMT) and
tracking replacement locations and cost. The Asset Maintenance group is responsible
for identifying cable segments and managing the coordination of work.
Business Case Justification Narrative Page 3 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 61 of 325
Primary URD Cable Replacement 2017
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Primary URD Cable
Replacement and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Sectionl.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Cody
Mgr Asset Maintenance
Date: 4- l4- ?et
? *\7 -\1
Bryan Cox
Sr Dir of HR Operations
Date:
Tem pf ate Version : 03107 l2O1 7
Business Case Sponsor
5 VERS¡ON HISTORY
Vereion lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1.0 Cody Krogh 4t1412017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 62 of 325
Envi ron mental Co m pl i an ce
I GENERAL INFORMATION
Requested Spend Amount $400,000
Requesting Organ ization/Department Environmental Compliance
Business Gase Owner Darrell Soyars
Business Case Sponsor Bruce Howard
Sponsor Organization/Department Legal
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Avista is subject to multiple Federal, State and Local environmental regulatory requirements.
Environmental Compliance is tasked with managing and maintaining compliance with the applicable
requirements from these programs, some of which require capital projects from time to time.
The Environmental Compliance group maintains a risk-based ranking of potential compliance issues
that includes our current approach, accompanied documentation and a target date for resolution. This
ranking is typically dynamic as smaller issues rise and fall or as larger issues are addressed through
various process changes, audits or projects.
2 BUSINESS PROBLEM
Regulatory programs and standards have been established to control the handling, emission,
discharge, and disposal of harmfulsubstances. These programs are implemented directly by Federal
agencies or delegated to the State or local authority. ln many cases, they are applied to sources
through permit programs which control the release of pollutants into the environment.
Two efforts currently require capital funding under this business case:
The proper handling and disposal of hazardous waste, specifically oil-filled electrical
equipment governed by Resource Conservation and Recovery Act (RCRA), Toxic
Substances Control Act (TSCA) and related State regulations. This funding covers all
activities associated with the proper handling and disposal of hazardous waste, specifically
oil-filled electrical equipment as part of the asset decommissioning process. This includes
labor and equipment from when the equipment is removed from service, transported back to
the Spokane Waste and Asset Recovery Facility where they are identified, investigated,
inventoried, sampled, sorted, stored and/or shipped to the proper waste vendor for proper
disposal. These activities are accomplished by numerous field personnel including two
hazardous waste technicians. The handling of these materials is mandated by state and
federal rules
2. Specific site mitigation required by our U.S. Forest Service Special Use Permit (SUP) which
allows right-of-way and access to our transmission and distribution assets on public land.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 63 of 325
Envi ron mental Compliance
The SUP outlined specific mitigation projects when it was renewed in 2009 for a period of 30
years'. Approximately 60% of these have been completed to date. The specific mitigation or
restoration projects were an agreed upon remedy from past impacts from our activities
related to our transmission and distribution assets. New mitigation requests do result from
on-going activities to maintain our assets. Some of these arise from security issues related
to managing public access while others are weather related or considered acts of god.
3 PROPOSAL AND RECOMMENDED SOLUTION
Hazardous Waste Disposal
Funding allows Avista to maintain compliance with Federal, State requirements. Our compliance
approach is the most cost effective method to support how construction and operational work is
currently being accomplished at Avista Corp. We have explored other methods such as utilizing
alternative support or contractors but these result in higher cost and increased liability.
Non-Funding would create significant environmental risk and potential liability which may prove
detrimental to our customers, the company, and the communities we serve. There are no
practicable alternatives to environmental compliance as stated in our Environmental Policy which
describes our commitment to protect human health and the environment: We comply with all
applicable environmental laws, regulations, and com pany procedures.
US Forest Service Special Use Permit (SUP)
Funding the SUP mitigation is essential to remaining in compliance with the conditions of the SUP.
This allows for continued permission to occupy and operate our facilities on US Forest Service Land.
Alternatives to crossing US Forest Service land were likely considered prior to the construction of
these Transmission and Distribution lines; we are not aware of a cost effective alternative that could
be employed allowing the removal of our assets and the surrender of our SUP.
Non-Funding of mitigation efforts would pose potential risk of cancellation of our SUP, which would
undermine the ability to keep and maintain these facilities on Forest Service lands. We would also
be subject to direct enforcement by the Forest Service via penalties or orders. This could cause
interruption in service and increase in rates to our customers.
Optlon Capital
Cost
Start Gomplete
Do nothing $0 N/A
Fund the Hazardous Waste Disposal $250,000 01 2017 122017
Fund the USFS SUP mitigation activities $150,000 01 2017 12 2017
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 64 of 325
Envi ro n mental Com pl i an ce
4 APPROVAL AND AUTHOR¡ZATION
The undersigned acknowledge they have reviewed the Environmental Compliance
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
G--^ ô
\"**-...-'Þr4
Date
Date
Template Version: 0212412017
t
€¡tVua..-)hÀ/Eìrrr¡ry r\C-Q-
Business Case Owner
lztti (c 7 üM*ô
D t l*e7øz- Fpv - ,4,f*attc>
Business Case Sponsor
5 VERSION HISTORY
fVerelon # lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Heide Evans 03t29t17 DarrellSoyars 04t10t17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 65 of 325
LED Change-Out Program
1 GENERAL INFORMATION
Requested Spend Amount $2,900,000
Requesting Organ ization/Department Operations
Business Gase Owner Landen Grant
Business Gase Sponsor Bryan Cox
Sponsor Organ ization/Department Operations
Gategory Project
Driver Customer Service Quality & Reliability
1.1 Steering Committee or Advisory Group lnformation
lnternal stakeholders meet together every six months to discuss program progress
and how their respective departments are impacted by the work. They guide the
program on any processes requiring modification or developing new processes to
help improve the program. lnternal stakeholders include Construction Services,
Distribution Engineering, Warehouse and lnvestment Recovery, Supply Chain,
External Communications, Mobile Dispatch, Enterprise Asset Management,
Customer Enterprise Technology, and Regional Business Managers. External
stakeholders are state and local governments who have jurisdiction over roads and
streets where Avista provides illumination. Neighborhood councils are a particular
external stakeholder which is often involved before their neighborhood is converted
to LED because the residential areas are sensitive to street lighting.
2 BUSINESS PROBLEM
Any local or state government which has jurisdiction over streets and highways has
an obligation to the general public they serve to provide acceptable illumination
levels on their streets, sidewalks, and/or highways intended for vehicle driver and
pedestrian safety. Avista manages streetlights for many local and state government
entities to provide such street, sidewalk, and/or highway illumination for their streets
by installing overhead streetlights.
The primary driver for converting overhead streetlights from High-Pressure Sodium
(HPS) lights to LED lights is the significant improvement in energy savings, lighting
quality to customers, and resource cost savings.
Secondly, converting streetlights to LED technology helps bring Avista in
compliance with the Washington State lnitiative 937 (or the Clean Energy lnitiative),
which ensured that at least fifteen percent of the electricity Washington state gets
from major utilities comes from clean, renewable sources, and that Washington
utilities undertake all cost-effective energy conservation measures. LED streetlight
technology is part of the mentioned energy conservation measure.
The desire to begin the LED Change-Out Program in2015 stems from an immediate
savings in energy, positive financial impacts, benefits associated with personal
injury and property theft, and resource cost savings.
Business Case Justification Narrative Page 1 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 66 of 325
LED Change-Out Program
. Each 100 watt and 200 watt HPS light replaced will save approximately 65
watts and 128 watts, respectively, per fixture. Once all of the 100 watt and
200 watt HPS street lights are replaced, the annual energy savings will be
9,903 MWH each year.
o With respect to the financial impacts of converting to LED streetlight
technology, the customer internal rate of return is 8.46%, assuming the
current cost of materials and life expectancy of the photocells and LED
streetlight fixtures.
o From a public safety perspective, the consequence of converting to LED
streetlights in lieu of replacing burned-out HPS bulbs shows a risk reduction
for customers of nearly eight times less for potential injury, a serious fatal
accident, and property theft.
o Lastly, company resource demands are reduced after the initial conversion
to LED technology. The Average Annual Labor Man-Hours for current
practices of changing burned-out HPS bulbs is estimated at 5,200 man-hours
and 2,600 equipment hours, while the average man-hours required during
the fifteen year life of the LED fixtures are 3,200 man-hours and 1,800
equipment hours.
ln 2011, the average cost to maintain a HPS streetlight was nearly $92 per fixture
with only about $10 of the cost being the actual material. The remaining costs were
the main constituents of the overall cost as seen in Figure 1.
Material,
$ro
Equipment,
s21
Figure l: 201 I Cosl Breakdown of a HPS Light Fìxture
Also, a lifetime material usage analysis on the HPS light fixtures estimated a Mean
Time to Failure (MTTF) for the various light fixture components. Table I shows the
results for each streetlight component.
Business Case Justification Narrative Page 2 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 67 of 325
LED Change-Out Program
Component
Groups
Material
Usage
Quantities
Replacement
Ratio
MTTF
(Years)
fuse
lamp
photocell
sta,rter board
street light fixture
641
7,930
5,151
1J26
683
1o/o
15%
10o/o
2%
2o/o
84
7
10
48
55
Túle I: 201I Meon Time To Fttìlure (MTTF) .for HPS Streetlìghts
Upon completion of all streetlights changed-out to LED fixtures, a guarantee of real
energy savings can be measured on an individual light fixture basis and then
extrapolated to the entire system. Most LED fixtures have the capability to have real-
time energy consumption measurements taken and reported back to Avista. Also,
once all the streetlights are converted to LED, the number of service requests for
streetlight burn-out should drop significantly from the number of service requests
prior to 2015.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Gapital
Cost
Start Complete
Do nothing $0 N/A
Base Case (current practice of replacing
burned-out HPS bulbs or replacing a
fixture if broken)
$1.70M Ongoing
Optimized HPS Case (planned
replacement of HPS bulbs and photocells)
$r.67M 10t2015 1212019
LED Case (change-out all fixtures to LED)$2.32M 10t2015 12t2019
Three alternative cases were considered in an analysis performed by the Asset
Management Department of converting streetlights to LED technology. The current
case or Base Case replaces failed HPS streetlight components only when they fail.
The second case, called the LED Case, replaces the current HPS streetlights with
new LED fixtures and implements a planned replacement at fifteen years for the
light fixture and photocell. The analysis noted that inside the new LED Case model,
a fifteen year replacement strategy proved more cost effective over the lifecycle than
running LED lights to failure. Thirdly, the Optimized HPS Gase represents keeping
the current HPS light fixtures and performing planned replacements of the HPS
bulbs and photocells at five year cycles for the bulbs and ten year cycle for the
photocells.
Business Case Justification Narrative Page 3 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 68 of 325
LED Change-Out Program
Key assumptions made in the alternatives analysis are outlined below.
The Base Case and the Optimized HPS Case, because they propose using HPS
fixtures, have the same failure characteristics shown in Table 2.
Table I, HPS Líght Component Failure CltaracterisÍics
Population
Failure Rate
(r0%) by
Year
Population
Failure Rate
(20%) by
Year
Mean Time to Failure
(50% of the initial
population will have
failed by _ Years)
Component
HPS 100 W Bulb
Photocells
Starter Board
3.4
5.7
7.4
4.4
7.3
10.5
6.7
10.6
16.3
Table 3 shows the failure characteristics assumed for LED fixtures and components
based on manufacturer's information and an assumed failure shape characteristic.
Table 2, Assumed LED Light Component Failure Curves
7.9
t2.t
to.2
15.5
L4.9
22.6
For all three cases, a model was created to help compare the risks including,
resource needs, potential energy savings, and financial impacts of each case. ln the
end, the LED Case will save customers money over the Base Gase. While the
Optimized HPS Case provides a better financial return to our customers compared
to both the Base Case and LED Case when considering strictly labor and material
costs, the energy savings associated with the LED Case becomes an overcoming
driver. The customers will still see savings over the life of the LED fixtures compared
to today's practices in the Base Case and eliminate the need for 2.3 Megawatts of
generation at night. ln addition, customers will realize an annual system energy
savings of 9,903 Megawatt hours.
Table 4 is a Projected Planned Capital and O&M budget for next twenty-four years,
showing the initial change-out and a subsequent planned LED change-out fifteen
years later.
Component
Population Failure
Rate (10%)by
Year
Population
Failure Rate (20%)
by Year_
Mean Time to Failure
l5o% of the initial
population will have
failed by Year _
New Style Photocell
LED Light Fixture
Business Case Justification Narrative Page 4 ol 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 69 of 325
LED Change-Out Program
Table 4, Projected Planned 24 Yeør Capital and O&M Budgetsfor Street Lights (1001{ steetlighls only)
Capital
Budget
with LED
Conversion
o&M
Budget
with LED
Conversion
o&M
Budget
without LED
Conversion
o&M
Offset with
LED
Conversion
Year
2015
2016
20L7
20L8
2019
2020
202t
2022
2023
2024
2025
2026
2027
2028
2029
2030
203L
2032
2033
2034
2035
2036
2037
2038
2039
52,3L9,249
52,323,370
s2,335,605
52,3s4,419
52,393,676
S97,159
5L4O,2t8
S225,059
529L,367
s330,003
54LL,862
s496,398
$544,068
s646,035
5704,s7L
s2,059,5L9
s2,LLg,2OO
52,144,239
s2,179,559
52,26J,9L4
5277,O74
s334,083
5444,O3t
5522,72s
s603,525
5L93,824
iLgg,24t
$203,970
52LO,732
5220,542
s228,035
s238,563
s255,240
5269,3L4
5279,462
Szgs,gzg
s312,965
5324,702
5344,4r4
S357,923
S26¿,ggg
Sz74,Lgs
5282,o99
529L,2O0
S304,680
S3x.8,617
s330,31-2
5345,078
s355,799
53lt,zEt
5732,0L2
5746,6s2
S761,585
5776,9L7
$792,353
s808,200
5824,364
S840,852
$857,669
$874,822
S892,318
$910,i.65
Sgz8,go8
s946,935
s965,874
S98s,192
s1,004,895
5L,024,993
$1,045,493
s1,066,403
5L,097,73L
s1,109,486
5t,L9r,676
S1,154,309
51,177,39s
s538,188
S548,411
5557,615
s566,085
s571,811
s580,165
S58s,goi.
S585,612
SsSg,gs¿
S595,360
s596,346
Ssgz,zoo
S603,666
5602,szt
s607,952
5720,2o9
$730,700
5742,9O5
5754,293
576L,724
5169,tL4
$779,L74
S786,598
S798,510
SSoo,osB
Business Case Justification Narrative Page 5 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 70 of 325
LED Change-Out Program
Table 4 shows the resource savings with the LED Case. The last column to the right
gives the estimated O&M savings, which is the result of installing new LED
streetlight fixtures verses installing a new HPS bulb or photocell, which is the
scenario in the Base Gase and Optimized HPS Gase. The column labeled O&M
Budget without LED Conversion shows the annual O&M costs in the Base Case.
The O&M cost in the Optimized HPS Case would be higher than the Base Gase
since it includes a programmatic change-out of all HPS bulbs.
The LED Change-Out Program achieves the objective of saving energy, reducing
resource costs, and improving nighttime light quality, which are all objectives
customers will immediately benefit from.
The LED Change-Out Program has a five year timetable, beginning in 2015, to
change-out all existing Avista owned non decorative streetlights to LED (Light
Emitting Diode), which equates to over 35,000 change-outs. The program schedule
is orientated by circuit feeder, similar to other programs. The priorities of what circuit
feeders or cities in the service territory are to be completed first is based on
efficiencies. At times, coordination with cities may impact the schedule of when an
area is changed out.
As shown in Table 4, the requested annual amount of nearly 82.32 million for five
years (2015 - 2019) is the minimum funding amount to complete the LED Change-
Out Program in the five years. lf funded below the $2.32 million for five years, the
realized O&M savings to customers would be delayed to subsequent years, and to
a lesser amount. However, if the Program is funded above the requested annual
amount of $2.32 million for five years, customers will realize the O&M savings
sooner and to a greater degree.
The impacts of the LED Change-Out Program span across multiple departments at
Avista. Operations is responsible for managing the work and executing the light
change-outs in the field, primarily by Avista's servicemen and local reps. Avista's
Operations Support Group (Mobile Dispatch) and Enterprise Asset Management
(EAM) Technology are responsible for creating work orders for all 28,000 change-
outs and dispatching them to the field. The Customer and Shared Services
department, particularity Enterprise Systems - Customer Care & Billing (CC&B), is
impacted by the project because the customer billing changes upon converting to
LED light fixtures. For the LED Gase, the implementation of converting to LED
streetlights will require only one additional Full Time Employee (FTE) over a five
year period. To remain with HPS streetlights, as in the Base Case and Optimized
HPS Gase, will require no additional or new staffing.
The entire alternative analysis report is attached for further detail.
To summarize the overarching benefits of the LED Change-Out Program and the
justification to begin the five year program sooner than later are the immediate
energy savings and resource savings. Customers will benefit with every light
changed out in the form of better lighting quality, reduced energy consumption and
reduced labor cost. To delay the program is to delay the immediate savings to
customers. The LED Change-Out Program is in alignment with the company's
strategic vision of delivering reliable energy service and the choices that matter most
to our customers. As part of the program, infrastructure is replaced with longer
Business Case Justification Narrative Page 6 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 71 of 325
LED Change-Out Program
lasting equipment. By providing more efficient equipment and quality lighting, this
results in an energy savings and safety increases for our customers.
The LED Change-Out Program extends across multiple departments at Avista
impacting them directly or indirectly. Each department identified as a stakeholder
will nominate an engaged representative to act as the liaison between the program
and their department. The department stakeholder representative will also take part
to promote their department's interests in the business'
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the LED Change-Out Program
and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature Date: 411312017
"u'.1¿-
i
¿-
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Landen Grant
Project Manager
Business Case Owner
Bryan
Sr Dir of HR Operations
Date: g,/rt I t1
Tem plate Version : 021241201 7
Business Case Sponsor
5 VERSION HISTORY
[Version#
lmplemented
By
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Landen Grant 4t1312017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative PageT of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 72 of 325
Segment Reconductor and FDR Tie
GENERAL INFORMATION
STEERING COMMITTEE OR ADVISORY GROUP INF'ORMATION
Distribution Area Engineers and Distribution System Planning.
Tim Figart - Spokane
Scott \ffeber & Marshall Law - East Region
Dan Knutson - Othello, Davenport
Marc Lippincott - Colville
Elizabeth Frederiksen - South Region
Will Stone - Distribution System Planning
David James - Distribution Eng. Mng.
BUSINESS PROBLEM
Avista's electric distribution system consists of three hundred and forty seven
(347) discrete primary electric circuits encompassing over 19,000 miles of
overhead conductors and underground cables. The distribution grid is managed
by division or'area engineers' and centralized distribution planning.
Load Demands on the srid are dvnamic with load patterns changing as a result
of many factors including weather, temperature, economic conditions,
conservation efforts, and seasonalvariations. Avista operates a radialdistribution
system using a trunk and lateral configuration (industry standard). Though many
circuits are monitored at the source substation (SCADA), downstream trunk and
lateral branch circuits loading are analyzed via computer simulation. At Avistq.
distribution analvsis is performed With the Synersee load flow prosram.
Requested Spend Amount $5,000,000 I year (on-going)
Requesting Organ izationlDepartment Distribution Engineering - C51
Business Gase Owner David James
Business Gase Sponsorc David Howell, Josh Diluciano, Heather Rosentrater
Sponsor OrganizationlDepartment Energy Delivery / Distribution Engineering
Category Program
Driver Performance & Capacity
Business Case Justification Narative Page I of12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 73 of 325
Segme nt Reconductor and FDR I,E
Avista's distribution system analysis and mitigation strategies are informed by
several internal documents and data repositories. These are listed below for
reference:
1. Dislribu$on -Planninq $ta0d?rd "509 Amo-FDR" - internal document that defines the
performance criteria and limits for both urban FDR tie systems and rural pure radial
circuits. This document is maintained by Distribution System Planning (W. Stone).
2. FpB Stqlus Report - distribution engineering publishes an annual report indicating peak
circuit demand by season, reliability outage statistics, circuit health check, and other
logistic information.
3. Distribution StandarCs - distribution engineering maintains construction standards for
both overhead and underground primary circuits. lt also maintain standards for all
electrical material and apparatus.
4. Pl Database - operating data retrieved by either the SCADA or DMS system is stored
in the Pl historian. This allows direct access by engineers and planners to help inform
both operating and design strategies. (Distribution Operations)
5. Distribution FDR Management Plan - a design guide to assist the CPG/Engineer when
making decisions related to reinforcements or reconstruction of distribution assets
(Asset Mngt).
6. FeederAutomation Strategy - a design guide to assist the CPG/Engineer when making
decisions involving automated devices (Distribution Engineering).
7. Synergee Computer Program - the load flow program derives topology information from
Avista's GIS system. Updates to the Synergee database are performed by Distribution
Planning.
8. Sgadq Ver¡âþlq l-¡fnitISYL) -Avista uses temperature compensated program to monitor
conductors, cables, and series connected majorequipment (e.9. transformers, breakers,
switches, regulators, and etc.). This system is deployed on Avista's EMS/SCADA
system. The program is SME supported by Substation Engineering.
Business Case Justification Narrative Page2 of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 74 of 325
Segment Reconductor and FDR Tie
A typical distribution circuit is illustrated below. Similar to municipalwater
systems, grid capacity decreases with distance away from the source substation.
This leads to system 'constraints' as loads are added to the system through direct
customer action or load shifting between circuits (Avista).
IA
¡A
500A.200 A 100 A
Sub
Illustration of Distribution Grid Capacity Constraint
Avìsta's Distríbation System conta¡ns over 75 different wìres and cables
Load Demand
Exceeds Grid
Capacity
2017 Avista Standard OH Primary Conductors
556 All-Aluminum (AAC) -- 557 Amps (maintrunk, urban)
336 All-Aluminum (AAC) - 405 Amps (main trunk, rurat)
2/0 Aluminum Conductor, Steel Reinforced (ACSR) -- 221Amps (gen purposes, rural)
#4 Aluminum Conductor, Steel Reinforced (ACSR) - 112 Amps (lateral circuit)
Legacy Conductors
210-310 Copper -291-336 Amps (maintrunk)
#2 Copper- 185 Amps (maintrunk)
#6 Copper - 65 Amps (lateral circuit)
Avista's distribution grid contain over 1,000 miles of conductor equivalent or smaller than
#6 Copper.
Business Case Justification Narrative Page 4 of 13
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 75 of 325
Segment Reconductor and FDR Tie
DECISION MAKING PROCESS
The decision model is represented by individual 'proposals' coupled with joint
review and acceptance by distribution engineering and distribution system
planning. The program's business case is modified annually to reflect the S-year
work plan. The Capital Planning Group then reviews all of the submitted business
cases and prioritizes and allocates resources across the organization. Distribution
infrastructure is not part of the .Engineering Roundtable" with the exception of
d i stri b ution subsfafi'ons.
The Segment Reconductor & FDR Tie decision model is illustrated below.
Authorized Resources by CPG
Requested Resources by
Distribution EngÆlanning
Proposal Acceptance Approval
( Area/Division Engineer)
Problem Area lclentifìed b¡,'
Area Engineer (South. East. and
West Region Proposals to
principally:
l) Reconductor line
"segrnerlt" to mitigate
thennal overload
I ) Constlrrct tie-Line
connection to shitì
clemand to an acl.iacent
circuit
(Distribution Teanr)
All project proposals leviewed
b¡" Distribution Enuineering and
Planning to provide peer'
review. lnitialll, scl'eening to
deternrine priority' r'anking and
inrmediac¡. Business Case
Revised arrnuall¡ to rcpresent 5-
year planning holizon.
Submitted to CPC
(Capital Planning)
Business Case review generally
results in partial fìrndirrg ol'the
work plan. fhe Distribution
Team (AI.-. Mng" Planning)
reassellbles to prioritize. rarrk.
and schedule plo.jects to align
wilh autholized budgets.
Business Case Justification Narrative Page 4 of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 76 of 325
Segment Reconductor and FDR Tie
PROPOSAL AND RECOMMENDED SOLUTION
Option Description Gonsequence
Do-Nothing No Action to mitigate
thermal overloads
Conductor will 'sag'
down beyond design
limits and contact joint-
use telecom circuits or
violate NESC prescribed
limits. ln extreme
situations, conductor
failure willoc¡ur.
Select DSM treatment Target homes and
businesses with
demand side
management solutions
to effect peak load
demand reduction.
This option would be a
viable, however, State
Commissions do not
allow DSM treatment in
localized areas.
Load Shifting FDR Tie This action is
represented in the
Segment Reconductor
program. By extending
lines to adjacent circuits,
load can be shifted to
underutilized circuits and
mitigate overloads. ïhis
action requires capital
investment.
Capacity lncrease Reconductor overloaded
'segments'to increase
line capacity
All electric components
allthermally limited.
Reconductoring is the
most direct aporoach to
mitigating overloaded
circuits.
RECOMMENDATION:
1. Po -[othins,is unaqceptablg. Violates NESCAA/AC regulations and represents
an unacceptable level of risk to public safety and infrastructure.
2. Targeted PSM is not allowed.
3. FDR Tie - represented in the program (indirect solution)
4. Seqment ßeconductor - represented in the program (direct solution)
Business Gase Justification Narrative Page 5 of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 77 of 325
Segment Reconductor and FDR Tie
Projects listed in the current 5-year "Sêgment Reconductor and FDR-Tie" program
are summarized on the Distribution Engineering SharePoint site. The following is
a summary of those projects listings as of Friday April 7, 2017.
http ://sha repoinUdepartments/enso/d ist/default. aspx
Region 2077 2018 2020 2027
West
South
Total
Qne of the planning objectives is fo levelize the resource demands and avoid
significant upswings or downturns in crew resource forecasting. Distríbution
Engíneering works closely with the Operating Divisions andAssef Maintenance to
develop a resource balanced work plan and maximize the effectiveness of Ayisfa
craft resources.
Distribution assets are fixed resources and therefore, project alternatives are
generally dominated by supply side solutions. Operating limitations are codified in
Avista internal standards (as listed) but derived through industry and regulatory
policies including: Washington Administrative Code WAC), National Electric
Safety Code (NESC), National Electric Code (NEC), and IEEE/ANSI standards &
manufacturer recommendations specific to equipment ratings and operating limits.
2019
East 1,250,000
1,250,0001,150,000
2,500,000 2,5oo,ooo 2,500,000 2,500,000
1,250,000 1,250,000 1,250,000
1,250,000 1,250,ooo
4900,000 5,o0o,o0o 5,(Xro,ooo 5,(X)O,(X)0
2,485,000
13 projects
1,315,000
9 projects
1.,375,000
I projects
5,175,000
30 projects
Business Case Justification Narrative Page 6 of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 78 of 325
Segment Reconductor and FDR Tie
APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Segment Reconductor and
FDR Tie öusiness case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in
Section1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and
representatives.
by the or their designated
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
il,/r
D¡'1. Ln fYlro
Business Case Owner
Date:
Date:(Z \l
¡fè I
Business Case Sponsor
\i3
Business Case Sponsor
Date:
Template Vercion: O3lO7 12017
Verslon lmplemented
By
Revlslon
Date
Approved
By
Approval
Date
Reason
1.1 David James Above
sionatures
04t07t17 lnitialversion
Business Case Justification Narrative PageT of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 79 of 325
Segment Reconductor and FDR Tie
EXAMPLES SHOWi\ FOR ILLUSTRATION:
FDR Status Report (provides baseline circuit performance and logistics
information) Warning Level (yellow highlight),
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Businese Case Justif¡cation Nanative Page I of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 80 of 325
Segme nt Reconductor and FDR Tie
Distribution "500 Amp" Plan (System Planning)
Company standard for the operation and load service planning associated with
Avista's electric distribution grid.
Key elements- Urban "FRD Tie" system. Requires that reserve capacity margins
be maintained so that adjacent circuits can restore service to customers in the event
of a planned orforced outage. ln summarV, no urban circuitshould be loaded above
its 67% capacity limit.
Svstem Limitq - Oogratinq & Qeshî
The fdlowirg set of proposed service limits are based on battilional company service
reliability and practices, as wellas appropr¡ete state and federal rules and regulations
These are guidelines only, specil'¡c sih¡alions willarise where these limits must be
exce€ded becaus€ of plrysical or economic problems.
1. Maximum Outage - 3 hrs.
This is an aoryoximate number heavily weþhted by the pditical influence of
'Keeping the Customer Happy"- Avista urÞn cusbmerservice record has been
quite good in the pest and should be maintained at a high level.
2. Maximum Portbn of Custøners Served to See Full Lenglh of Outage - SlCÉ
For example: Feeder ortage - 50% of customers on that feeder)
SubstalÍn outage - 50% of customers served by that substat¡on)
This again is an aúilrary number. Hourever, it is lhe worst case possibility using the
substalion connections and feeder sectimalizing practice that is being recorn-
mended as General Det¡¡gn Cdteda forthe fr¡ture. Most cases would result in a
$neller number of customers seeing full outage duralion-
Excerpt from "500 Amp" Plan. Source: Distribution SharePoint(3115117)
Business Case Justification Narrative Page 9 of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 81 of 325
Segment Reconductor and FDR Tie
Avista's SCADA monitoring system incorporates a temperature compensated
thermal, ampacity rating system known internally as SVL (Scada Variable Limit).
SVL has been in use since 1993. The following indicates a summary screen
indicating the top ten most heavily loaded (by o/o capacity) transmission lines,
substation power transformers, and distribution circuits. This screen is
continuously monitored by System Operators but also used by Area Engineers to
capture data during peak load conditions. lt provides additional data to aid with
project planning for the segment reconductor program.
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Business Case Justification Narrative Page l0 of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 82 of 325
Segment Reconductor and FDR Tie
FDR by Area. Shown only to illustrate the scale of the effort to monitor our
distribution system.
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Business Case Justif¡cation Narrative Page fi of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 83 of 325
Segme nt Reconductor and FDR Tie
Synergee Computer Modeling (Millwood 12F4 screen shot)
Computer slmulation is the primary tool used to identify and develop strategies to
mitigate a thermal overload condition. Note, that Avista's electric distribution
system has been developed over the full course of the Company's operating
history and infrastructure installed near the turn of the century (1900) is still in-
service. Though current Avista construction standards limit the number of
overhead primary wires to four @l: fia ASCR, 2/0 ACSR, 336 AAC, 556 AAC;
Avista maintains a fleet of seventy five (75) different primary wires and cables.
Many are no longer available commercially and we maintain'hand coils'salvaged
from project work in order to effect maintenance repairs on those conductor
segments. We ceased to install overhead copper conductors in the 1950's though
today, thousands of miles of #6A, #6CW, and other copper conductors remain in
service.
Synergee Gomputer System: Millwood 12F4 Circuit
Buginess Case Justification Narrative Page 12of 12
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 84 of 325
SCADA - SOO and BuCC

Business Case Justification Narrative Page 1 of 5
1 GENERAL INFORMATION

1.1 Steering Committee or Advisory Group Information
The program’s yearly Requested Spend Amount are reviewed and authorized by the Capital
Budget Group. Within the program’s yearly authorized spend amount, specific budgetary
items to be implemented are determined based upon requests by affected stakeholders
including System Operations, Distribution Dispatch, and Power Supply, and are documented
in the Director of Transmission & Distribution System Operations’ annual goals and
priorities list. The business case owner re-prioritizes items throughout the year as necessary
to address evolving business and compliance requirements. Any mid-year increases in the
program’s requested spend amount require authorization by the Capital Budget Group.
2 BUSINESS PROBLEM
In order to effectively operate the Transmission & Distribution (T&D) Systems, sufficient
business and computing hardware and software is necessary. This business case provides
for replacement of existing technology in alignment with manufacturer product roadmaps
for application and technology lifecycles, as well as for deployment of new applications
and technology as required to address expanding regulatory and business requirements.
Technology continues to change and T&D Systems continue to incorporate improved
technology.
The primary driver for this business case is to maintain and improve our real-time T&D
System Operations, upgrading and replacing systems as they become outdated and
obsolete. Many projects within this business case replace or upgrade equipment to meet
mandatory obligations required by the Federal Energy Regulatory Commission (FERC),
North American Electric Reliability Corporation (NERC), and the US Pipeline and
Hazardous Materials Safety Administration (PHMSA). Other projects replace existing
failed or failing equipment to maintain operability. See below for information on
operational needs supported by this business case.
 Transmission Operations – Certified System Operators monitor electrical system
conditions around-the-clock. They perform switching operations, maintain system
voltage, and respond to abnormal conditions. Constant communication occurs with
neighboring systems and regional authorities to assure system reliability. Operators
respond to emergency situations such as black start restoration, load shedding,
disturbance response, and activation of the Backup Control Center.
Requested Spend Amount $1,054,000
Requesting Organization/Department T&D - SCADA/EMS/DMS - System Operations
Business Case Owner Brad Calbick
Business Case Sponsor Mike Magruder/Heather Rosentrater
Sponsor Organization/Department Energy Delivery
Category Program
Driver Asset Condition
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 85 of 325
SCADA - SOO and BuCC

Business Case Justification Narrative Page 2 of 5
 Balancing Authority – To maintain the balance between load, interchange, and
generation, automated calculations occur every four seconds which determine
Avista’s electrical power obligation based on customer load, contracted power
purchases & sales, and the system frequency at that instant. Controls are
automatically issued to generating stations to adjust generation to meet our
obligations. Control algorithms are optimized to minimize unnecessary mechanical
stress while maximizing compliance with control requirements.
 Gas Operations – Gas Controllers monitor gas system conditions around-the-clock.
They direct field crews, maintain system integrity, and respond to abnormal
conditions. Controllers respond to emergency situations.
 Critical Infrastructure Protection – Numerous protection measures are deployed to
protect critical systems from unauthorized physical and electronic access. NERC
standards have dozens of requirements regarding protection of critical infrastructure.
In-depth and lengthy audits are performed every 3 years by the regional reliability
organization, the Western Electricity Coordinating Council. Potentially significant
financial penalties result from any instances of non-compliance.
 NERC reliability standards are being continually changed. New and changed
standards are adopted which will address emergency operations, transmission
operations, critical infrastructure protection, communications, and balancing authority
operations.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Do nothing $0
Fully funded “SCADA - SOO and BuCC” business
case
$1,054,000 01/2017 12/2017

This program (Supervisory Control and Data Acquisition - System Operations Office and
Backup Control Center) replaces and upgrades existing electric and gas control center
telecommunications and computing systems as they reach the end of their useful lives,
require increased capacity, or cannot accommodate necessary equipment upgrades due to
existing constraints.
Included are hardware, software, and operating system replacement and upgrades, as well
as deployment of additional capabilities to satisfy new operational standards and
requirements.
Some system upgrades may be necessitated by other requirements, including NERC
reliability standards, federal gas standards, system growth, and external projects (e.g. Smart
Grid).
There are multiple risks if this program is not adequately funded. The clearest risk would
be to public and personnel safety. The control systems supported by this business case
provide real-time visibility, situational awareness, and control of Avista’s electric and gas
systems. Degradation of these capabilities due to lack of capacity, capability, or aging
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 86 of 325
SCADA - SOO and BuCC

Business Case Justification Narrative Page 3 of 5
systems would present increased safety risk. Additionally there is significant compliance
risk.
These control systems provide the capabilities required to achieve compliance with
numerous reliability standards and requirements. For the electrical system these include
the NERC standards BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. For the gas
system these include the PHMSA “Pipeline Safety: Control Room Management/Human
Factors” rule (49 CFR Parts 192 and 195.)
The expenditure of these funds is necessary to operate Avista’s electric and gas systems in
a safe, reliable, and compliant manner.
The “Do Nothing” option was considered. This business case addresses the need to provide
the technical capabilities and tools to remotely monitor and control our electric and gas
infrastructure. The systems which accomplish this are integral to meeting our
responsibilities to ensure public and personnel safety, monitor and respond to system
conditions, protect equipment, and protect from cyber threats. These systems need to be
periodically upgraded and expanded to continue to meet existing and new requirements.
There is really no responsible “alternative” to this business case.
In addition to the risks related to public and personnel safety, compliance risk would be
increased without this investment. Non-compliant operational capabilities and practices
would result in negative audit findings, significant financial penalties, and litigation
expenses. Obsolete equipment would remain in service until failure. Additional capacity
for growth may or may not be suitable for required expansions to meet other needs (e.g.
Regulatory, Smart Grid.)
Further justification of the need of this business case is listed below.
o There are numerous mandates in effect which compel these expenditures,
numerous NERC Standards, and PHMSA’s Control Room Management rule,
in particular (49 CFR Parts 192 and 195).
o There is no practical risk mitigation should we fail to meet these requirements.
o This is a continuous program. Work is started and completed throughout each
year, and in some cases, such as major upgrades, spans multiple years.
o This business case is crucial in a key aspect of Our Vision; “Delivering reliable
energy service…” It is essential in providing sufficient control center
technology tools, situational awareness, and monitor/control capabilities to
achieve reliable energy service.
o This business case is key in accomplishing the Our Focus item of “Safe &
Reliable Infrastructure.” Providing remote monitor and control capabilities to
operators is essential in achieving “optimum life-cycle performance - safely,
reliably, and at a fair price.”
o The amount requested is based partially upon historical spending needs, and
partially on known upcoming major projects.
o Our Customers include:
 Retail and wholesale electric customers
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 87 of 325
SCADA - SOO and BuCC

Business Case Justification Narrative Page 4 of 5
 Wholesale electric transmission customers
 Retail gas customers
o Our Stakeholders include:
o Operations
 System Operators
 Power Schedulers
 Distribution Dispatchers
 Gas Controllers
 Energy Accounting & Risk Management
 Neighboring utility control centers
 Peak Reliability Coordinator
o Technicians
 Protection/Control/Metering Technicians
 Telecommunication Technicians
o Engineering
 Protection/Integration Engineering
 Substation Engineering
 Generation Engineering
 Distribution System Operations
o Enterprise Technology
 Oracle Database Administrators
 Security Engineering
 Network Engineering
 Network Operations

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 88 of 325
SCADA - SOO and BUCC
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the "SCADA - SOO and BuCC"
business case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role
Signature:
Print Name
Title:
Role:
Brad T. Calbick, P.E
Business Case Owner
Manager of SCADA/EMS/DMS
Date 7A e 1
Date 1l*l-,t
Date
Template Version: 03107 12017
11,ù,û,Ja>1 ,"-^*¿_
Michael A. MagrudÈr, P.E
Energy Delivery
Transmission &
System Operations
Director,
Distribution
Business Case Sponsor
Steering/Advisory Com mittee Review
5 VERS¡ON HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Calbick 2017-04-10 Magruder 2017-04-14 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 89 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 90 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 91 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 92 of 325
Transmission - Minor Rebuild
I GENERAL INFORMATION
Requested Spend Amount $1,555,249
Requesting Organization/Department T&D - TLD Engineering
Business Case Owner Lamont Miles
Business Gase Sponsor David Howell/Scott Waples
Sponsor Organization/Department Electrical Engineering
Gategory Program
Driver Asset Condition
l.l Steering Committee or Advisory Group lnformation
The Transm¡ssion Design Engineering Manager manages the prioritization of
projects within this business case based on inputs from the Asset Maintenance
group and the maintenance engineer in the Transmission Design group.
2 BUSINESS PROBLEM
The Transmission Minor Rebuild Business Case covers the follow-up work to Wood
Pole lnspections and Aerial Patrol inspections in ER 2057, and Air Switch
Replacements in ER 2254.
During routinely scheduled inspections, issues are discovered regarding the
condition of assets, including items such as rotten poles, broken/spliUrotten
crossarms, broken conductor or ground/shield wire, and air switches that no longer
operate safely or reliably.
A relevant metric to this business case is the System Operator's Log, with a focus
on tracking the number of outages related to asset failures. This number would be
expected to increase over time if this program is not funded. Transmission outages
can have significant consequences as they tend to impact a large number of
customers and have the potential to start fires in dry areas.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capital
Gost
Requested
Stail
Requested
Complete
Risk ilfitigatlon
Do nothing $0 N/A
Continue lransmrcsion Minor
Rebuild Program
$1.55M 2017 N/A
(Program)
a Transmission
Outages
caused by
Assef
Failures, and
assocrafed
risk of fires
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 93 of 325
Transmíssion - Minor Rebuild
The recommended solution is to replace poles, cross-arms, and other assets
identified by inspection, and replace Transmission Air Switches located outside of
the substations that have reached their end of life.
This program has been in place for many years and there are no expected business
impacts (such as staffing, etc.) to continue the program in place.
Without replacing old and worn-out poles and cross-arms, our system will be
increasing in risk for more failures and more risk of a major fire caused by a failure.
As time moves forward, the number of failures and risk of a major fire will increase
the difference in costs between doing nothing and continuing the Transmission
Minor Rebuild program.
Transfers to plant will typically occur over a July-December monthly spread, as the
work is typically completed in summer and fall months due to access conditions and
availability of outage windows.
This business case aligns with the organization's mission to deliver reliable energy
service to customers by preventing the degradation of reliability of transmission
service to the substations that serve them.
The amount requested aligns with the amount of work typically identified on an
annual basis from pole inspections and aerial inspections. The goal of this funding
level is to ensure that the Transmission Design Engineering department doesn't fall
behind on addressing the issues as they are identified. This amount will need to
increase annually to adjust for increased material and labor costs.
lnternal stakeholders in this business case include Asset Maintenance and System
Operations.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 94 of 325
Transmissron - Minor Rebuild
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission - Minor
Rebuild and agree with the approach it presents and that it has been approved by
the steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature
Print
Title:
Role:
4\^Jt,Date: 1lt8 11
Lo,^*| Å./14;kt
Business Case Owner
r\
Date:t?
2ot7
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Business Case Sponsor
Signature: Z2Q Date /
Print Namef
Title:
Role:
e
Case
5 VERSION HISTORY
[Verslonf lmplemented
By
Revleion
Date
Approved
By
Approval
Date
Reason
1.0 Lamont Miles Above
sionatures
4/14/17 lnitialversion
Tem plate Version : 0212412017
Business Case Justifi cation Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 95 of 325
Transmission Major Rebuild - Asset Condition
I GENERAL INFORMATION
Requested Spend Amount $e,450,000
Req uestin g Organ ization/Department T&D - TLD Engineering
Business Case Owner Lamont Miles
Business Case Sponsor David Howell/Scott Waples
Sponsor Organ ization/Department Electrical Engineering
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Engineering Roundtable manages the prioritization of projects within this
business case as supported by Asset Management studies and input from company
subject matter experts. lt is comprised of representatives from the following
departments: Asset Maintenance, Asset Management, Compliance, System
Planning, System Operations, Telecommunications, Transmission Contracts,
Protection Engineering, Substation Engineering, Transmission Engineering, and
Substation Support.
2 BUSINESS PROBLEM
The Transmission Major Rebuild - Asset Condition Business Case covers major
rebuilds of transmission lines due to overall asset condition. Factors such as
operational issues, ease of access during outages, and potential for
communications build-out are also considered in prioritizing this work.
A relevant metric to this business case is the Probability, Consequence, and Risk
Summary developed by the Asset Management group, which indicates which
transmission lines are most in need of replacement due to end-of-life indicators,
This list changes on an annual basis based on the work performed under this
business case in the previous year. Another relevant metric is the System
Operator's Log with a focus on tracking the number of outages related to asset
failures.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapital
Cost
Requested
Start
Requested
Complete
Risk Mitigation
Do nothing $0 N/A
lmplement Transmission MajorRebuild Asset Condition
program at recommended
spending levels
$21 1M 2017 N/A
(Program)
Lower Operating
Risk
Transmission
Outages caused
by Asset
Failures. and
a
Business Case Justification Narrative Page 1 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 96 of 325
Transmission Major Rebuild - Asset Condition
Optlon Capital
Cost
Requested
Start
Requested
Complete
Risk Mitlgation
associated risk of
fires
lmplement Transmission MajorRebuild Asset Condition
program at current spending
levels
$9.45M 2017 N/A
(Program)
a Higher Operating
Risk
a Transmission
Outages caused
by Asset
Failures, and
associated risk of
fires
The recommended solution is to replace poles, cross-arms, and other assets where
the majority of assets have been determined to have reached their end of life.
There are no expected business impacts (such as staffing, etc.) to continue the
program in place as it was split off of an existing business case.
Without replacing old and worn-out poles and cross-arms, our system will be
increasing in risk for more failures and more risk of a major fire caused by a failure.
As time moves fonrvard, the number of failures and risk of a major fire will increase
the difference in costs between doing nothing and continuing the Transmission
Major Rebuild - Asset Condition program. Transmission outages can have
significant consequences as they tend to impact a large number of customers and
have the potential to staft fires in dry areas.
Transfers to plant will typically occur lightly over a May-June timeframe for work that
can be completed in the spring, and heavily in the October-December timeframe for
work that has to be completed in the fall. Most of the work is typically completed in
fall months due to access conditions and availability of outage windows.
This business case aligns with the organization's mission to deliver reliable energy
service to customers by preventing the degradation of reliability of transmission
service to the substations that serve them.
lnternal stakeholders in this business case include all of the departments listed in
the Steering Committee section.
Option 1: Do nothing - Not recommended
Option 2: According to Avista's Transmission System Asset Management Plan,
"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".
Option 3: Current funding level - Current spending on the Asset Condition risk
category is $9.45 million annually. Funding levels will be reviewed on an
annual basis.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 97 of 325
Transmission Major Rebuild - Asset Condition
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Major Rebuild
- Asset Condition Program and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
desig nated representatives.
Date: 'l I ISignature:
Print Name
Title:
Role:
Signature
Print Name
Title:
Role:
Signature:
Print N
Title:
Role:
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Date: 4 ìl r-l
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Tem plate Version: 0212412017
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Business Case Sponsor
2
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Business Case Sponsor
5 VERSION HISTORY
[Version#
lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1.0 Lamont Miles Above
Sionatures
4t17t17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 98 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 99 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 100 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 101 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 102 of 325
Electric Storm
I GENERAL INFORMATION
Requested Spend Amount $3,090,000
Req uesting Organization/Department Operations
Business Gase Owner Cody Krogh
Business Case Sponsor Bryan Cox
Sponsor Organization/Department Operations
Category Program
Driver Failed Plant & Operations
l.l Steering Committee or Advisory Group lnformation
The Electric Storm work is overseen by the local area operations engineers and
area construction managers. The work is unplanned and non-specific in nature, but
occurs regularly and historical averages are used to estimate an annual quantity. ln
the event of larger scale storms, like the historical storm event in Novembeî 2015,
a formal lncident Command System (lCS) is created to manage the resources
needed to respond.
2 BUSINESS PROBLEM
The electric storm business case is driven by restoring Avista's transmission,
substation, and distribution systems (damaged plant) into serviceable condition
during a weather storm event where assets are damaged. Storm events are random
and often with short notice. The business case of Storms is funding a rapid response
to unplanned damages and outages so customer outages are minimized. The
business provides funds for replacing poles, cross arms, conductor, transformers,
and all other defined retirement units damaged during storm events. The damage
can be due to high winds, heavy ice and snow loads, lightning strikes, flooding, or
wildfires. The importance of quickly replacing damaged facility is vital to providing
reliable service to our customers.
The annual budget amount is determined based on historical average experience
rate of Capital restoration work.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Unfunded $0
Fully Funded $3,090,000M Continuous Program
Figure 1 shows the historical costs (2005 - 2016) for the distribution storm
business. From 2005 to 2013, the average annual cost for distribution storms was
$2.1 million dollars, with a range of $893k (2005) to $2.7M (2013). The years of
2014 and 2015 experienced an anomaly with 2014 having two uncharacteristic
Business Case Justification Narrative Page 1 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 103 of 325
30,000,000s
Electric Storm
major wind events during the summer and November 2015 was a historic 10O-year
wind storm event. Consequently,2Ol4 and 2015 realized record spending on storm
related distribution work. The year 2016 had a distribution storm spend of nearly $4
million, but much of the work was related to clean up of the historic November 2015
storm event. The proposed funding level does not account for the storm anomalies
that occurred in 2014 and 2015.
Distribution Storm Historical Costs (2005 - 2016)
52,272,6st 52,979/7s 52,66s,146 5t,ss4,72L 57,o64,7Lo
$3,440,031 s2,733,229
s1,633,443
S25,ooo,ooo
$20,000,000
$15,ooo,ooo
s10,000,000
,000,000Ss
$-
s893,662t
S1,383,897I
2005 2005 2007 2008 2009 2010 20LL 20L2 2013 201.4 2015 20t6
Figure 1: Dx Storm Hisloricul Costs
The Electric Storm business case aligns with the company's strategic goal of Safe
and Reliable lnfrastructure. The work is a key component to minimizing customer
outage times and thus contributes to Avista's Reliability indices like SAFI and
cAtDt.
Historic ll)ll
t'car rr'ind event
'lrr'in rna,jr)r sumnlcr
rvind cvents
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 104 of 325
Electric Storm
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Storm and agree
w1h the approach it presents and that it has been approved by the steering
committee or other governance body identified in Section1.1. The undersigned also
acknowledge that significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Bryan
Cody h
Mgr Asset Maintenance
Date: 4_ t4 - ZotT
Date !-t1-\7
Template Version: 03107 12017
Sr Dir of HR Operations
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Cody Krogh 4t1412017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 105 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 106 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 107 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 108 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 109 of 325
Envi ron mental Co m pl i an ce
I GENERAL INFORMATION
Requested Spend Amount $400,000
Requesting Organ ization/Department Environmental Compliance
Business Gase Owner Darrell Soyars
Business Case Sponsor Bruce Howard
Sponsor Organization/Department Legal
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Avista is subject to multiple Federal, State and Local environmental regulatory requirements.
Environmental Compliance is tasked with managing and maintaining compliance with the applicable
requirements from these programs, some of which require capital projects from time to time.
The Environmental Compliance group maintains a risk-based ranking of potential compliance issues
that includes our current approach, accompanied documentation and a target date for resolution. This
ranking is typically dynamic as smaller issues rise and fall or as larger issues are addressed through
various process changes, audits or projects.
2 BUSINESS PROBLEM
Regulatory programs and standards have been established to control the handling, emission,
discharge, and disposal of harmfulsubstances. These programs are implemented directly by Federal
agencies or delegated to the State or local authority. ln many cases, they are applied to sources
through permit programs which control the release of pollutants into the environment.
Two efforts currently require capital funding under this business case:
The proper handling and disposal of hazardous waste, specifically oil-filled electrical
equipment governed by Resource Conservation and Recovery Act (RCRA), Toxic
Substances Control Act (TSCA) and related State regulations. This funding covers all
activities associated with the proper handling and disposal of hazardous waste, specifically
oil-filled electrical equipment as part of the asset decommissioning process. This includes
labor and equipment from when the equipment is removed from service, transported back to
the Spokane Waste and Asset Recovery Facility where they are identified, investigated,
inventoried, sampled, sorted, stored and/or shipped to the proper waste vendor for proper
disposal. These activities are accomplished by numerous field personnel including two
hazardous waste technicians. The handling of these materials is mandated by state and
federal rules
2. Specific site mitigation required by our U.S. Forest Service Special Use Permit (SUP) which
allows right-of-way and access to our transmission and distribution assets on public land.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 110 of 325
Envi ron mental Compliance
The SUP outlined specific mitigation projects when it was renewed in 2009 for a period of 30
years'. Approximately 60% of these have been completed to date. The specific mitigation or
restoration projects were an agreed upon remedy from past impacts from our activities
related to our transmission and distribution assets. New mitigation requests do result from
on-going activities to maintain our assets. Some of these arise from security issues related
to managing public access while others are weather related or considered acts of god.
3 PROPOSAL AND RECOMMENDED SOLUTION
Hazardous Waste Disposal
Funding allows Avista to maintain compliance with Federal, State requirements. Our compliance
approach is the most cost effective method to support how construction and operational work is
currently being accomplished at Avista Corp. We have explored other methods such as utilizing
alternative support or contractors but these result in higher cost and increased liability.
Non-Funding would create significant environmental risk and potential liability which may prove
detrimental to our customers, the company, and the communities we serve. There are no
practicable alternatives to environmental compliance as stated in our Environmental Policy which
describes our commitment to protect human health and the environment: We comply with all
applicable environmental laws, regulations, and com pany procedures.
US Forest Service Special Use Permit (SUP)
Funding the SUP mitigation is essential to remaining in compliance with the conditions of the SUP.
This allows for continued permission to occupy and operate our facilities on US Forest Service Land.
Alternatives to crossing US Forest Service land were likely considered prior to the construction of
these Transmission and Distribution lines; we are not aware of a cost effective alternative that could
be employed allowing the removal of our assets and the surrender of our SUP.
Non-Funding of mitigation efforts would pose potential risk of cancellation of our SUP, which would
undermine the ability to keep and maintain these facilities on Forest Service lands. We would also
be subject to direct enforcement by the Forest Service via penalties or orders. This could cause
interruption in service and increase in rates to our customers.
Optlon Capital
Cost
Start Gomplete
Do nothing $0 N/A
Fund the Hazardous Waste Disposal $250,000 01 2017 122017
Fund the USFS SUP mitigation activities $150,000 01 2017 12 2017
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 111 of 325
Envi ro n mental Com pl i an ce
4 APPROVAL AND AUTHOR¡ZATION
The undersigned acknowledge they have reviewed the Environmental Compliance
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
G--^ ô
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Date
Date
Template Version: 0212412017
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5 VERSION HISTORY
fVerelon # lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Heide Evans 03t29t17 DarrellSoyars 04t10t17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 112 of 325
Garden Springs 230/115kV Station Integration
Business Case Justification Narrative Page 1 of 5
1 GENERAL INFORMATION

1.1 Steering Committee or Advisory Group Information
Construct a new 230/115 kV substation at the existing Garden Springs property. The new
station will terminate the existing Airway Heights - Sunset, Sunset - Westside and South
Fairchild Tap 115 kV Transmission Lines. The 230 kV bus will be energized by a new
230 kV line from Westside Substation which will require the completion of the Westside
Rebuild Project and a new interconnection at Westside with the BPA Bell - Coulee #5 230
kV Transmission Line. Both of the newly designated Garden Springs - Sunset 115 kV
Transmission Lines will be required to be reconductored with 150 MVA capacity
conductor.
The Substation will be constructed in two phases. Phase 1 consists of building a 115/13kV
yard with 115kV integration, while Phase 2 includes the 230kV yard, transformation, and
230kV integration.
2 BUSINESS PROBLEM
The 2010 Spokane Area Regional Assessment identified specific transmission system
performance issues in the five and the ten-year planning horizons. Many of the issues are
caused by inadequate 230/115 kV transformation in the area. Presently there are four
substations in the Spokane Area providing 230/115 kV transformation: Beacon (500
MVA), Bell (250 MVA), Boulder (500 MVA), and Westside (250 MVA). The concept of
constructing Garden Springs Substation is to add 500 MVA of transformation capacity.
This project is required to mitigate NERC TPL-001-4 standard violations for P2 and P6
events.
Additionally, the distribution stations in this area are connected to radial transmission lines.
Manual operator action is necessary to restore service to customers following automatic
circuit breaker operation to isolate a fault. Currently the Sunset-Westside 115kV
Transmission Line includes the South Fairchild 115 kV Tap, to which the Four Lakes 115
kV Tap is connected, leaving a total exposure of 31 miles for all customers served by the
Cheney, Fairchild South, Four Lakes, Hayford and Hallett & White substations.
Avista has identified a preferred location for the new Garden Springs 230/115/13kV
Station. Selection of this property is primarily due to the convergence of 115 kV
transmission lines. The Airway Heights-Sunset and Sunset-Westside 115 kV Transmission
Lines pass through the property allowing for ease of integrating the new substation with
Requested Spend Amount $33,000,000
Requesting Organization/Department Transmission Planning
Business Case Owner Scott Waples
Business Case Sponsor Heather Rosentrater
Sponsor Organization/Department T&D
Category Project
Driver Mandatory & Compliance
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 113 of 325
Garden Springs 230/115kV Station Integration
Business Case Justification Narrative Page 2 of 5
the existing 115 kV transmission system, eliminating the need to construct additional new
115 kV transmission lines. Figure 1 provides an overhead view of the preferred property.
There are a minimum of seven (7) thermal or voltage limit violations identified to take
place within the 10-year planning horizon if this project is not constructed. Additional
supporting documentation may be found in the Garden Springs Integration Project
Feasibility Study report authored by John Gross.

 Figure 1: Garden Springs Substation Property.

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 114 of 325
Garden Springs 230/115kV Station Integration
Business Case Justification Narrative Page 3 of 5
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Alt 1: Do nothing $0
Alt 2: Option 1B - Garden Springs Integration Project
Feasibility Study (Draft Version B 2013) Phase 1
$9M 01 2018 12 2020
Alt 2: Option 1B - Garden Springs Integration Project
Feasibility Study (Draft Version B 2013) Phase 2
$24M 01 2022 12 2025
Alt 3: Airway Heights-Westside 115kV Line
Alt 4: Garden Springs 230/115kV Station with
Garden Springs-Westside 230kV Line

Alt 5: No 230kV Infrastructure – 115kV Rebuilds

Alternative 1 – Do Nothing / Status Quo:
This alternative is not recommended because it does not mitigate the expected capacity
constraints, and does not comply with applicable NERC transmission planning standards.
Operating Procedures may be used to defer some system deficiencies.
Alternative 2 – Garden Springs 230/115kV Station:
This alternative constructs a new 230 kV station at the existing Garden Springs property to
connect the existing 115 kV transmission lines passing through the property into the station.
The 230 kV station (Phase 2) would be sourced through a new 230 kV transmission line
interconnection with the Bonneville Power Administration (BPA). The 115 kV portion of the
new station (Phase 1) is a part of the West Plains Transmission Reinforcement Plan which
addresses reliability issues and provides operational flexibility. All system deficiencies
identified will be mitigated.
Alternative 3 – Airway Heights-Westside 115 kV Transmission Line:
Constructing a new 9.5-mile 115 kV transmission line from Airway Heights to Westside was
considered as an alternative. Outages at the Westside station, including the P6 outage of both
230/115 kV transformers and P7 outage of the 230 kV double circuit into Westside, continue
to cause performance issues. A new 230 kV source to the Spokane area provides a more robust
long term solution.
Alternative 4 – Garden Springs 230 kV Station with 230 kV Transmission Line to Westside:
Constructing a 7.9-mile 230 kV transmission line from Westside to the new Garden Springs
station was considered instead of the proposed Bluebird-Garden Springs 230 kV Transmission
Line interconnection with BPA. Performance issues are not fully mitigated with this
alternative. Specifically, the P7 outage of the 230 kV double circuit into Westside continues
to be an issue and right-of-way events between Westside and Garden Springs stations do not
meet performance criteria.
Alternative 5 – No New 230 kV Infrastructure – 115 kV Transmission Line Rebuilds:
Rebuilding several 115 kV transmission lines in the Spokane area instead of constructing any
new 230 kV infrastructure was considered. The alternative does not provide the necessary
redundancy but instead creates a higher dependence upon existing facilities.
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 115 of 325
Garden Springs 230/115kV Station Integration
Business Case Justification Narrative Page 4 of 5
Garden Springs
Integration Project
Feasibility Study
S P O K A N E A R E A
T R A N S M I S S I O N P L A N N I N G

P r e p a r e d b y J o h n G r o s s

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 116 of 325
Garden Springs 230/115kV Station Integration
Business Case Justification Narrative Page 5 of 5

4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Garden Springs 230/115kV
Station Integration Business Case and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the undersigned
or their designated representatives.

Signature: Date:
Print Name: Kenneth Sweigart
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Scott Waples
Title: Director, Planning and Asset Mgmt
Role: Business Case Sponsor

5 VERSION HISTORY
Version Implemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Ken Sweigart
Jeff Schlect
4/14/17 Initial version

Template Version: 03/07/2017
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 117 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 118 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 119 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 120 of 325
South Regíon Voltage Control (N. Lewiston Reactor) Project
1. GENERAL INFORMATION
Requested Spend Amount $8,000,000
Requesting Organ izationlDepartment Transmission Planning
Business Case Owner Ken Sweigart
Business Case Sponsor David Howell/Scott Waples
Sponsor OrganizationlDepartment T&D
Category Project
Driver Mandatory & Compliance
1.1 Steering Gommittee or Advisory Group lnformation
o Ken Sweigart - Manager, Substation Engineering
o Project EngineerlProject Manager (PE/PM) * Adam Newhouse
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
2. BUSINESS PROBLEM
There is an ongoing issue with high voltage on the 230 kV transmission system in the
Lewiston/Clarkston area. The high voltage problem is persistent most months of the year
(the exception is heavy slünmer loading months) and the high voltage peaks during the
ovemight hours. This high voltage condition is a result of the expansion of Avista's 230
kV transmission network. Although there are many benefits to a large networked
transmission system, one negative outcome is that long, lightly loaded transmission lines
produce large amounts of line charging current (leading reactive MVAR), which
increases system voltage. Currently, there is no practical way to correct this high voltage
issue with the existing 230 kV transmission system beyond taking lines out of service.
3. PROPOSAL AND REGOMMENDED SOLUTION
Option Capital Goet Start Complete
Alt 1: Do nothing
AIt 2: North Lewiston Reacfors $8M 2016 2019
AltgrnaÍíve 1:
This alternative is not recommended because it does not mitigate the expected capacity
constraints, and does not adhere to NERC Compliance regulations.
Alternative 2:
Install two 50 MVAR shunt reactors at the North Lewiston Station on the 230 kV bus.
The reactors allow for adequate voltage control to maintain voltage below applicable
facility ratings during normal and contingency scenarios.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 121 of 325
Eouth Region Voltage Control (N. Lewiston Reactor) Project
Solutíon:
Alternative 2: North Lewiston Reactors. Project scope includes the following:
Install two 50 MVAR shunt reactors to the existing 230 kV bus at North Lewiston
Station. The project has already been initiated including procurement of the reactors.
Business Case Justification Nanat¡ve Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 122 of 325
South Reglon Voltage Control (N. Lewiston Reactor) Project
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Soufh Region Valtage
ControlBusrness Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in
Section1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives
Signature:
Print Name:
Title:
Role:
Signatu re:
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Title:
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Title:
Role:
Bu Case Owner
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VERSION HISTORY
Venslon lmplemented
By
Revislon
Date
Approved
BY
Approval
Date
Reason
1.0 Ken Sweigaft Above
signafures
4/14/17 lnitial version
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 123 of 325
Saddle Mountain 230/11ãkV Station (New) Integration Project
Requested Spend Amount $40,000,000
Req uesting Organ ization/Department Transmission Planning
Business Gase Owner Ken Sweigart
Business Gase Sponsor David Howell/Scott Waples
Sponsor Organization/Department T&D
Gategory Project
Driver Mandatory & Compliance
1 GENERAL INFORMATION
1.1 Steering Gommittee or Advisory Group lnformation
o Ken Sweigart - Manager, Substation Engineering
o Project EngineerlProject Manager (PE/PM) - Brian Chain
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
2 BUSINESS PROBLEM
In the fall of 2013, Grant employees contacted Avista System Planning about
performance issues within Grant's system that are exacerbated by Avista's load in the
Othello area. The issue was escalated to Columbia Grid through the Regional Planning
process. It was identified through this process and Avista System Planning that the
system performance analysis indicates an inability of the System to meet the performance
requirements Pl, P2 and P6 categories in Table 1 ofNERC TPL-001-4 in current heavy
summer scenarios, and P6 categories in heavy winter scenarios. Completion of this
project is required to maintain compliance with NERC TPL-001-4.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapital Goet Ste¡t Complete
Alt 1: Status Quo
Alt 2: Build new 115kV Transmission Line
AIt 3: Close "Staf' Points $75M
AIt 4: lnstall Generation
Alt 5: Build Sadd/e Mountain 230/11úkV Suôsfafi'on
Project with associated support projects
$40M 2017 2021
Alternøtive I:
This alternative is not recommended because it does not mitigate the expected capacity
constraints, and does not adhere to NERC Compliance regulations.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 124 of 325
Saddle Nlountain 230/11úkV Station (New) Integration Project
Alternøtive,2:
This alternative is not recommended as it does not mitigate the low voltage issues in the
Othello area.
Alterryøtíve J:
This alternative is not recommended due to its high cost. It is anticipated that $75M of
reconductoring would need to be included to mitigate any potential violations comparable
to the preferred alternative.
Alternøtíve 4:.
This alternative is not recommended due to its high financial costs, the potential for must
run operation and the lead time on this project will be well beyond the time this project is
needed per NERC requirements.
Alternative 5:
This alternative is the most cost effective option considered and provides enough voltage
support and capacity into the area for the next 50 years. This altemative mitigates all
identifïed deficiencies in the Othello area documented in the2016 Planning Annual
Assessment. This alternative is the best solution for the long term.
Solution:
Alternative 5: The scope recommended consists of two phases:
PHASE I:
1) Construct a 3 -position 230 kV double bus double breaker arangement with space
for 2 future positions at the line crossing of the Walla V/alla - Wanapum 230 kV and
Benton - Othello 115 kV transmission lines.
2) Construct a 3 position 115 kV breaker and a half arrangement with space for 3 future
positions.
3) Install250 MVA Transformer
4) Rebuild entire 8.28 miles of Othello - Warden No.l 1 15 kV line with minimum 205
MVA capasity
5) Rebuild 2.88 miles of Othello - Warden No. 2 115 kV line with minimum 205 MVA
capacity
COST: $35M
IN SERVICE:12131/2020
PHASE 2:
l) Rebuild Othello City to 115 kV Ring Bus with 5 positions
2) Build new line from Saddle Mountain 115 kV to Othello City Station I l5kV
COST: $5M
IN SERVICE: l2l3ll202l
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 125 of 325
Saddle Mountain 230/115kV Station (New) lntegration Project
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Sadd/e Mountain 230/115kV
Station (New) lntegration Business Case and agree with the approach it presents
and that it has been approved by the steering committee or other governance body
identified in Section1.1. The undersigned also acknowledge that significant changes
to this will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signatu
Print Name:
Title:
Role:
Business Case Owner
Date
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Date
Approved
BY
Apprcval
Date
Reason
1.0 Ken Sweigaft Above
sr-?nafures
4/14/17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 126 of 325
Spokane Valley Tran smission Rei nforcement P roject
Requested Spend Amount $6,500,000
Req uestin g Organ ization/Department Transmission Planning
Business Gase Owner Ken Sweigart
Business Case Sponsor David Howell/Scott Waples
Sponsor Organization/Department T&D
Gategory Project
Driver Mandatory & Compliance
I GENERAL INFORMATION
1.1 Steering Gommittee or Advisory Group lnformation
o Ken Sweigart - Manager, Substation Engineering
o Project Engineer/Project Manager (PE/PM) * Various
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
2 BUSINESS PROBLEM
Completion is this project is required to mitigate a NERC TPL-001-4 system deficiency.
The transmission system in the Spokane Valley currently fails TPL-001-4(P2.4), which is
an intemal Breaker Fault (Bus-tie Breaker) on A7l7 at the Boulder Station. In addition the
system fails the NERC TPL-001-4 P2 Contingency for the 2017 Heavy Summer Scenario.
Completion of this project is required to ensure Avista maintains compliance with NERC
regulations and Avista's planning documents.
3 PROPOSAL AND REGOMMENDED SOLUTION
Option Gapital Cost Start Complete
Alt 1: Status Quo $0
Alt 2: Complete the already started Spokane Valley
Iransmrssio n Reinforcement Project
$6.sM 01 2012 12 2019
Alt 3: Reconfigure the CDA Reconfiguration Project
Alternatíve I:
This alternative is not recommended because it does not mitigate the expected capacity
constaints, and does not adhere to NERC Compliance regulations.
Alternative 2:
The remaining portions of the Spokane Valley Transmission Reinforcement project are
constructing the Irvin Station and rebuilding a portion of the Beacon - Boulder #2 ll5
kV Transmission Line. All system deficiencies are mitigated and the desired operational
flexibility to serve large industrial customers is realized.
Business Case Justification Narative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 127 of 325
Spokane Valley Trans missíon Rei nfo rcement Project
Alternatíve J:
Revert the system to the condition prior to the Coeur d'Alene Reconfiguration Project
creating the Boulder - Rathdrum and Post Falls * Ramsey I l5 kV transmission lines.
Operational concerns will present themselves specifically with a P2.l planned outage
followed by a forced Pl event in the Coeur d'Alene area. (The P2.l and Pl event
combination is not a TPL-001-4 event.) Operational flexibility constrained by large
industrial customers will continue to persist.
Solutíon:
Alternative 2, complete the Spokane Valley Transmission Reinforcement project.
Remaining project scope includes the following:
Construct the lrvin Station terminating thç Beacon - Boulder #l and #2,lwin- IEP, and
Irvin - Opportunity 115 kV Íansmission lines as a breaker and a half configuration: $4
million, energize20l9
Rebuild the existing Beacon - Boulder #2 ll5 kV Transmission Line from Beacon to
Millwood to 7 9 5 ACSS conductor: $2.5 million, energize 2019
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 128 of 325
Spokane Valley Tra ns mission Rei nforcement P roj ect
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Spokane Valley
Iransmrssion Reinforcement Project Busrness Case and agree with the approach it
presents and that it has been approved by the steering committee or other
governance body identified in Sectionl.1. The undersigned also acknowledge that
significant changes to this will be coordinated with and approved by the undersigned
or their designated re
Signature:
Print Name
Title:
Role:
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5 VERSION HISTORY
Velslon lmplemented
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Date
Apprcved
By
Approval
Date
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1.0 Ken Sweigaft Above
sl,gnafures
4/14/17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 129 of 325
T ra n s mr.ssr'on wERC L o vn-Rr.s k P ri o rity Li n es M iti g atÍ o n
I GENERAL INFORMATION
Requested Spend Amount $2,000,000
Requesting Organ ization/Department T&D - TLD Engineering
Business Gase Owner Lamont Miles
Business Case Sponsor David Howell/Scott Waples
Sponsor Organ izationlDepartment Electrical Engineering
Category Program
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
The Transmission Design Engineering Manager manages the prioritization of
projects within this business case based on inputs from the L¡DAR studies that have
been performed.
2 BUSINESS PROBLEM
The Transmission NERC Medium Priority Lines Mitigation Business Case covers
the work to reconfigure insulator attachments, and/or rebuild existing transmission
line structures, or remove earth beneath transmission lines in order to mitigate
ratings/sag discrepancies found between "design" and "field" conditions as
determined by L|DAR survey data. This program was undertaken in response to
the October 7, 2012 North American Electric Reliability Corporations (NERC)
"NERC Alert" - Recommendation to Industry, "Consideration of Actual Field
Conditions in Determination of Facility Ratings". This Capital Program covers
mitigation work on Avista's "Low Priority" 230kV and 115kV transmission lines.
Mitigation brings lines in compliance with the National Electric Safety Code (NESC)
minimum clearances values. These code minimums have also been adopted into
the State of Washington's Administrative Code WAC). This program is expected
to be completed in 2020.
The lines that were found to have clearance discrepancies were categorized High,
Medium, and Low Priority based on the following criteria:
o High: Bulk Grid 230 kV linking Avista generation to primary load
o Medium: Remaining 230 kV lines, and 11skv lines linking Avista generation
to primary load
. Low: Remaining 115 kV lines
A relevant metric to this business case can be found in the NERC Alert Mitigation
spreadsheet maintained by Avista's Reliability & Compliance Manager, which
shows the status of mitigation work completed and work outstanding.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 130 of 325
Transmissíon wERC Low-Risk Priority Lines Mitigation
3 PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to correct the issues found in the L¡DAR studies to
stay in compliance with the NESC code and WAC.
There are no expected business impacts to continuing this program in place.
lf Avista does not fully implement this business case, it runs the risk of being fined
for not staying in compliance with the NESC code and WAC rules.
Transfers to plant will typically occur lightly over a May-June timeframe for work that
can be completed in the spring, and heavily in the October-December timeframe for
work that has to be completed in the fall. Most of the work is typically completed in
fall months due to access conditions and availability of outage windows.
This business case aligns with the organization's commitment to stay in compliance
with all applicable regulations.
The amount requested is a good faith estimate of the work left to be completed on
the Low Priority transmission lines.
The internal stakeholders in this business case include System Operations and
Rel ia b i I ity/C om p I iance.
Optlon Gapital
Cost
Requested
Start
Requested
Complete
Rlek ilitigation
Do nothing $0 N/A
Continue NERC Low Priority Lines
Mitigation program
$2M 2017 2020 c Public
safety
concern;
and Avista
could be
found at
fault if an
electrical
contact
incident
occurs,
because of
these lines
being out
of
compliance
with the
NESC
code and
WAC.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 131 of 325
Transmission ,VERC Low-Risk Priority Lines Mitigation
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission NERC Low-
Risk Priority Lines Mitigation Program and agree with the approach it presents and
that it has been approved by the steering committee or other governance body
identified in Section1.1. The undersigned also acknowledge that significant changes
to this will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
sSio^
Business Case Owner
Business Case Sponsor
Date:\<l1
Date: 4,
Date 0Ã/ 7
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Date
Approved
By
Approval
Dato
Reason
1.0 Lamont Miles Above
sþnafures
4/14/17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 132 of 325
T ra n s mission IVERC M ed i u m-Risk P ri o rity Lines M iti g atio n
1 GENERAL INFORMATION
Requested Spend Amount $2,000,000
Req uesting Organ ization/Department T&D - TLD Engineering
Business Case Owner Lamont Miles
Businees Gase Sponsor David Howell/Scott Waples
Sponsor Organizatlon/Department Electrical Engineering
Gategory Program
Driver Mandatory & Compliance
l.l Steering Committee or Advisory Group lnformation
The Transm¡ss¡on Design Engineering Manager manages the prioritization of
projects within this business case based on the number and location of line
clearance discrepancies found that do not meet NESC code.
2 BUSINESS PROBLEM
The Transmission NERC Medium Priority Lines Mitigation Business Case covers
the work to reconfigure insulator attachments, and/or rebuild existing transmission
line structures, or remove earth beneath transmission lines in order to mitigate
ratings/sag discrepancies found between "design" and "field" conditions as
determined by L|DAR survey data. This program was undertaken in response to
the October 7, 20'12 North American Electric Reliability Corporations (NERC)
"NERC Alert" - Recommendation to lndustry, "Consideration of Actual Field
Conditions in Determination of Facility Ratings". This Capital Program covers
mitigation work on Avista's "Medium Priority" 230kV and 11skv transmission lines,
including Noxon-Hot Springs #2230kV and Devils Gap-Stratford 115kV. Mitigation
brings lines in compliance with the National Electric Safety Code (NESC) minimum
clearances values. These code minimums have also been adopted into the State
of Washington's Administrative Code WAC). This program is expected to be
completed in2O17.
The lines that were found to have clearance discrepancies were categorized High,
Medium, and Low Priority based on the following criteria:
. High: Bulk Grid 230 kV linking Avista generation to primary load
. Medium: Remaining 230 kV lines, and 115kV lines linking Avista generation
to primary load
. Low: Remaining 115 kV lines
A relevant metric to this business case can be found in the NERC Alert Mitigation
spreadsheet maintained by Avista's Reliability & Compliance Manager, which
shows the status of mitigation work completed and work outstanding.
Business Gase Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 133 of 325
Transmrssr'on MRC Medium-R sk Priority Lines Mitigation
3 PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to correct the issues found in the L¡DAR studies to
stay in compliance with the NESC code and WAC.
There are no expected business impacts to continuing this program in place.
lf Avista does not fully implement this business case, it runs the risk of being fined
for not staying in compliance with the NESC code and WAC rules.
Transfers to plant will typieally occur lightly over a May-June timeframe for work that
can be completed in the spring, and heavily in the October-December timeframe for
work that has to be completed in the fall. Most of the work is typically completed in
fall months due to access conditions and availability of outage windows.
This business case aligns with the organization's commitment to stay in compliance
with all applicable regulations.
The amount requested is a good faith estimate of the work left to be completed on
the Medium Priority transmission lines.
The internal stakeholders in this business case include System Operations and
Reliability/Compliance.
Optlon Gapital
Gost
Requested
Start
Requeeted
Gomplete
Rlsk Mitlgatlon
Do nothing $0 N/A
Continue NERC Medium Priority
Li n es M itig ation prog ra m
$2M 2014 2017 a Public
safety
concern;
and Avista
could be
found at
fault if an
electrical
contact
incident
occurs,
because of
fñese /rnes
being out
of
compliance
with the
NESC
code and
WAC.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 134 of 325
Transmíssion
^íERC
Medium-Rísk Priority Lines Mitlgation
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the lransmfssion NERC
Medium-Risk Priority Lines Mitigation Program and agree with the approach it
presents and that it has been approved by the steering committee or other
governance body identified in Section1.1. The undersigned also acknowledge that
significant changes to this will be coordinated with and approved by the undersigned
or their designated representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Lo,'.onl A.ÂAil"s
Business Case Owner
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[Verslon#
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Revlslon
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Approved
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4/14/17 Initialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 135 of 325
Transmrssion Construction - Compliance
I GENERAL INFORMATION
Requested Spend Amount $11,850,000
Requesting Organ ization/Department T&D - TLD Engineering
Business Case Owner Lamont Miles
Business Case Sponsor David Howell/Scott Waples
Sponsor Organization/Department Electrical Engineeri ng
Category Program
Driver Mandatory & Compliance
l.l Steering Committee or Advisory Group lnformation
The Engineering Roundtable manages the prioritization of projects within this
business case based on the annual Corrective Action Plans developed by the
System Planning group. The Engineering Roundtable is comprised of
representatives from the following departments: Asset Maintenance, Asset
Management, Compliance, System Planning, System Operations,
Telecommunications, Transmission Contracts, Protection Engineering, Substation
Engineering, Transmission Engineering, and Substation Support.
2 BUSINESS PROBLEM
The Transmission Construction Compliance Business Case covers the
Transmission rebuild and reconductor work necessary to maintain compliance withthe NERC Reliability Standard TPL-001-4 - Transmission System Planning
Performance Requirements ("Standard"). This standard mandates that an annual
planning assessment be conducted and corrective actions be identified and
implemented to remedy any system performance deficiencies. Corrective Action
Plans must be completed within the required timeframe to meet the system
performance requirements dictated by the Standard.
The implementation of this business case will be considered successful if these
projects are all completed prior to the required compliance dates identified in the
Engineering Roundtable Project List, which are copied from the Corrective Action
Plans (within the annually published Avista System Planning Assessment).
Business Case Justification Narrative Page 1 of4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 136 of 325
Transmission Construction - Compliance
3 PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to build, rebuild, or reconductor transmission lines as
identified in the Corrective Action Plans to stay in compliance with NERC mandatory
and enforceable Reliability Standards, most notably TPL-001-4.
lf Avista does not implement this business case, the company is at risk of violating
NERC Reliability Standard Requirements and could be subject to penalties of up to
$1M per day for the duration of any such violation. Following a "do nothing" option
for this business case would likely be treated as an aggravating factor by the
regulatory authority when assessing enforcement actions. Relevant sections of the
NERC Sanction Guidelines are cited below.
NERC Sanction Guideline Summaryl
2.9 Concealment or lntentional Violation
NERC orthe Regional Entity shall always consider as an aggravating
factor any attempt by a violator to conceal the violation from NERC
or the Regional Entity, or any intentional violation incurred for
purposes other than a demonstrably good faith effort to avoid a
significant and greater threat to the immediate reliability of the Bulk
Power Sysfem.
2.10 Economic Choice to Violate
Penalties shall be sufficient fo assure that entities responsible for
complying with Reliability Standards do not have incentives to make
economic choices that cause or unduly risk violations of Reliability
Standards, or incidents resulting from violations of the Reliability
Standards. Economic choice includes economic gain for, or the
avoidance of cosfs to, the violator. NERC orthe Regional Entity shall
t NERC Rules of Procedure, Appendix 4P., Sanction Guidelines of the North American Electric Reliøbility
Corporation, July l, 2014, pp 4-5.
Option Capltal
Cost
Requested
Start
Requosted
Cornplete
Rlsk Mltigatlon
Do nothing $o N/A
I mple me nt T ra n sm ission
Construction - Compliance
program
$11.85M 2017 N/A
(Program)
Potentialfines (up
to $1M/day) for
possrb/e
noncompliance with
A/ERC Reliability
Sfandards
Business Case Justification Narrative Page 2 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 137 of 325
Transmission Construction - Compliance
treat economic choice to violate as an aggravating factor when
determining a Penalty.
2.15 Maximum Limitations on Penalties
ln the United Sfafeg the maximum Penalty amount that NERC or a
Regional Entity ø// assess for a violation of a Reliability Standard
Requirement is $1,000,000 per day per violation. NERC and the
Regional Entities ø// assess Penalties amounts up to and including
this maximum amount for violations where warranted pursuant to
these Sanction Guidelines.
This business case aligns with the organization's commitment to comply with all
applicable laws and regulations. The amount requested represents the portion of the
Transmission Reconductors & Rebuilds business case that is being spent on
compliance-related projects in 2017. Annual funding will fluctuate based on the
scope identified in the Corrective Action Plans.
lnternal stakeholders in this business case include System Planning, System
Operations, and Compliance.
Business Case Justification Narrative Page 3 of4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 138 of 325
Transmission Construction - Compliance
4 APPROVAL AND AUTHOR¡ZATION
The undersigned acknowledge they have reviewed the lransmlssion Construction
and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
4lnlnSignature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature
Print Name
Title:
Role:
tYt,ct,
L"-" un| À. ¡tt"t
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Date
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Tem plate Version : 021241201 7
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Business Case Owner
Business Case Sponsor
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Business Case Sponsor
5 VERSION HISTORY
[Vereion#
lmplemented
By
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Lamont Miles Above
siqnatures
4/1 4/17 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 139 of 325
Tribal Permits & Seúúle ments
I GENERAL INFORMATION
Requested Spend Amount $ 300,000
Requesting Organization/Department 401 - Native American Relations
Business Case Owner ToniPessemier
Business Gase Sponsor Jason Thackston
Sponsor Organ ization/Department Energy Resources
Gategory Program
Driver Mandatory & Compliance
l.l Steering Committee or Advisory Group Information
There is no specific Steering Committee for this Business Case. The Advisory
Group is our Native American Relations department, who negotiates easements and
settlements with the individual Native American Tribes. Projects are dr¡ven by any
installation or rebuild of facility on Tribal lands. The Native American Relations
department meets with Tribal representatives to negotiate easements, or
modification of easements ¡n conjunction with construction projects.
2 BUSINESS PROBLEM
This business case is driven by compliance, the legal requirement to obtain
and maintain easements for our transmission and distribution lines. This is
required under Part 25 of the Code of Federal Regulations, Section 169.
Several of these cross Native American Tribal land, requiring us to maintain
easements or fees to occupy those areas. The Native American Relations
department of Avista is the interface with the Tribes, and conducts
negotiations on behalf of Avista.
Failure to maintain easements would put us in immediate violation of Federal
Law. Wewould be required, lacking an easement, to remove ourfacilityfrom
Tribal land. Many of our easements are for transmission lines, therefore this
is not a viable option.
The primary measure would be to have active easements on all Tribal
encroachments. Currently, Avista maintains 81.7 miles of transmission lines
on Tribal land.
3 PROPOSAL AND RECOMMENDED SOLUTION
a
o
a
Option Capital Gost Start Complete
Do nothing $0
Continue to negotiate easements as required $300,000 01 2017 122099
Business Case Justification Narrative Page I of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 140 of 325
Tribal Permits & Seúúle ments
Relocate all ïransmission lines off of Tribal land $61,190,000 01 2018 122023
o The only alternative to settling easements, would be to vacate those
easements and reroute all of our facility off of Tribal land. This would be an
extremely expensive alternative, as indicated above. ln fact, for Tribal
distribution assets, there is no viable option, due to obligation to serve.
o The primary risk of relocation would be the longer distances involved, and
the risk of obtaining satisfactory easements on non-Tribal land.
o This is ongoing work, as these easements are not long-lived, and are subject
to change as we change the nature of the facility covered by them.
o Through spending the approximately $300,000 annually, Avista maintains all
easements through Tribal land, and maintains good working relationships
with the Tribes.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 141 of 325
Tribal Permits & Seúúle ments
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Tribal Permits & Settlements
and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
-/"* ¿r*-Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Date I
Date '(løh
Date:
Tem plate Version : 03107 12017
a/n /
Toni Pessemier
Indian Relations Advisor
Business Case Owner
>2Ê-
Ø¡onlñackston
Sr. V.P. Energy Resources
Business Case Sponsor
Steering/Advisory Committee Review
5 VERSION HISTORY
Vorclon lmplemented
By
Revlelon
Dats
Approved
BY
Approval
Date
Reaeon
1.0 ToniPessemier 04t12t17 Jason
Thackston
04t12t17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 142 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 143 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 144 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 145 of 325
SCADA Build-Out Program
I GENERAL INFORMATION
Requested Spend Amount $7,7M per year, $115M total over 15 years
Requeeting Organ ization/Department T&D - Substation Engineering
Business Gase Owner Ken Sweigart
Business Gase Sponsor David Howell
Sponsor Organization/Department T&D
Category Program
Driver Performance & Capacity
1.1 Steering Committee or Advisory Group lnformation
o Ken Sweigart - Manager, Substation Engineering
o Project Engineer/Project Manager (PE/PM) - TBD
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
2 BUSINESS PROBLEM
Avista is committed to the Grid Modemization Initiative. This initiative, among other
things, allows for the automation of feeder devices. This enhancement reduces and/or
mitigates outages. For Grid Modernization to fully realize its potential, feeder information
must be brought into the Substation and back-hauled through SCADA & Communications,
eventually allowing for Conservation Voltage Reduction (CVR).
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Gost Start Gomplete
Do nothing
Recommended Solution $115M 01 2017 12 2032
This project will complete the installations of SCADA and EMS/DMS capability to all
Avista substations. This will provide System Operations with clear visibility, indication,
and control at every sub. In addition, Grid Modemization will have the necessary
communications infrastructure for complete inst¿llation and operation on all feeders.
System Planning, Asset Management, Operations, and Engineering will have real time and
historical datato support efficient, flexible, and safe operation and design of the system for
the future.
Alternatives considered include :
o Do Nothing: Presently only have tull SCADA with EMS/DMS capabilþ at 35
substations. Another 35 do not have any SCADA and 90 have limited SCADA
with obsolete equipment, minimal room for expansion, etc. Present priorities will
never allow us to get to all subs.
Business Case Justification Narratíve Page 1 of2
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 146 of 325
SCADA Build-Out Program
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the SCADA Build-Out Program
Busrness Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in
Sectionl .1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Business Case Owner
Date
Date r-7
Template Version: O3n7 nO17
+/ø/z"n
úìr
\
Business Case
5 VERS¡ON HISTORY
Vemion lmplemented
By
Revislon
Date
Approved
By
Approval
Date
Reaeon
1.0 Ken Sweigart Above
sl'snafures
04/14/17 lnitialversion
Business Case Justification Narrative Page2of 2
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 147 of 325
Substation – Capital Spares Program
Business Case Justification Narrative Page 1 of 3
1 GENERAL INFORMATION

1.1 Steering Committee or Advisory Group Information
 Manager, Substation Engineering - Ken Sweigart
 Project Engineer/Project Manager (PE/PM) – Scott Wilson
The assigned PE/PM holds stakeholder meetings to develop/confirm scope,
schedule and costs. Also meets at time of pre-construction. Other meetings held
as necessary.
2 BUSINESS PROBLEM
The Substation - Capital Spares program maintains Avista’s inventory of Power
Transformers and High Voltage Circuit Breakers. This inventory of critical
apparatus is capitalized upon receipt and placed in service for both planned and
emergency installations as required.
Transformers and High Voltage Circuit Breakers (capital spares) are placed into
service based on requirements and need. An available stock of transformers and
breakers are needed to support Avista’s obligation to serve under emergency
conditions and for planned replacements. This inventory is managed by
Substation Engineering.
The annual program expenditures may vary significantly in years when an
Autotransformer (230/115 kV) is purchased. In years without an Autotransformer
purchase, minor variations will occur based on planned projects as well as
replenishing apparatus inventory levels required for adequate capital spares.
Items within this business case are long lead time items and adequate apparatus
levels must be maintained to ensure reliable operations and the ability to respond
to planned worked.
Funding for this business case will change year to year based on required
inventory to support reliable operations, replacement of obsolete equipment, and
to support future substation construction needs.

Requested Spend Amount $4,750,000 per year on-going
Requesting Organization/Department T&D – Substation Engineering
Business Case Owner Ken Sweigart
Business Case Sponsor David Howell/Scott Waples
Sponsor Organization/Department T&D
Category Program
Driver Performance & Capacity
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 148 of 325
Substation – Capital Spares Program
Business Case Justification Narrative Page 2 of 3

3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Alternative 1: Eliminate Spares Program
Alternative 2:
Retain present level of Spares Program
$4.75M
Alternatives considered include:
 Alternative 1: We will not have vital system capital spares required to
maintain our electric system in the event of failures (emergency), planned
system improvements (reliability), or obligation to serve (growth). In
addition, some of this apparatus may be required for compliance upgrades
in reliability and capacity. Lack of an adequate Capital Spares level
extends outages, and increases the premium paid to expedite and install
replacement equipment.
 Alternative 2: Maintaining the present level of Capital Spares funding, as
evaluated by Substation Engineering. This level of funding provides the
best alternative to minimize the consequences presented by outage risks
associated with major equipment failures, and best positions Avista to
efficiently perform construction. Annual funding requirements will be
established consistent with historical failures, need for future spares to
support reliable operations, and provide support for required capital
improvements to support capacity.
Solution:
Recommendation - Alternative 2.

Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 149 of 325
Suþsúation - Capital Spares Program
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation - CapitalSpares
Program Eusrness Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Sectionl ,1 . The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature
Print N
Title:
Role:
Busi ness Case Owner
Date
^lG
Þ¡-. Ç\.J*¡
Business Case Sponsor
Date:
Date:2a 7
Tem plate Version : 03107 12017
er\
fo"a 3¿f atL
Business Case ponsor
5 VERSION HISTORY
Verslon lmplemented
By
Revlslon
Date
Approved
By
Approval
Date
Reason
1.0 Ken Sweigart Above
sionatures
4/14/17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 150 of 325
Suþsúation - New Distribution StatÍon Program
I GENERAL INFORMATION
Requested Spend Amount $6,000,000 per year on-going
Requesting Organization/Department T&D - Substation Engineering
Business Gase Owner Ken Sweigart
Business Gase Sponsor David Howell
Sponsor Organization/Department T&D
Gategory Program
Driver Performance & Capaci$
1.1 Steering Committee or Advisory Group lnformation
r Ken Sweigart - Manager, Substation Engineering
o Project Engineer/Project Manager (PE/PM) - Various
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
2 BUSINESS PROBLEM
New distribution substations added to the system for load growth and reliability are critical
to the long term operation of the system. As load demands increase and customer
expectations rise regarding reliability, incremental distribution substation capacity is
required. This allows for improved operational flexibility, better system reliability, and
easier routine maintenance scheduling as equipment is more easily taken out of service
because load can be transferred.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Gapital Gost Start Gomplete
Do nothing $0
Recommended Solution $6M
This program adds new distribution substations to the system in order to serve new and
growing load as well as for increased system reliability and operational flexibility. New
substations under this program will require planning and operational studies, justifications,
and approved Project Diagrams prior to funding.
Alternatives considered include :
r Do Nothing: Maintain (to the best of our ability) all obsolete or end-of-life
apparatus. Repair or replace equipment on emergency basis only. Some repairs
would not be possible due to obsolescence. Considerably more, and longer,
customer outages would result. Although there is zero Capital cost connected with
keeping the status quo there are some associated O&M and other system
sustainment costs.
Business Case Justif¡cation Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 151 of 325
Suþsúation - New Distribution Station Capacity Program
Extension of distribution feeders from neighboring substations and increased
capacity at those substations would be required at a minimum. The negative
ímpact is most certainly reduced reliability and difficulty in long term maintenance
and system operation. Increased liability would result.
Solutíon:
Anticipated load growth requires the addition of two new substations per year over the
2Al7-2026 horizon.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 152 of 325
Subsúation - New Distribution Station Capacity Program
4 APPROVAL AND AUTHOR¡ZATION
The undersigned acknowledge they have reviewed the Substation New
Distribution Station Capacity Program Business Case and agree with the approach
it presents and that it has been approved by the steering committee or other
governance body identified in Section1.1. The undersigned also acknowledge that
significant changes to this will be coordinated with and approved by the undersigned
or their designated rep
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Case Owner
Ë\<.t..'c**J
Business Case Sponsor
Date:7
<INç
Date: 4 tt?
Tem plate Version : O3lO7 l2O1 7
I
5 VERSION HISTORY
Vorslon lmplemented
By
Revlolon
Date
Approved
By
Approval
Date
Reaeon
1.0 Ken Eweigart Above
srbnafures
4/14/17 Initial version
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 153 of 325
Gas Deteriorated Súeel Pipe Replacement Program, ER 3001
I GENERAL INFORMATION
Requested Spend Amount $1,000,000 - Annual Program Request
Req uesting Organ ization/Department 851 - Gas Engineering
Business Case Owner Jeff Webb, Seth Samsell
Business Gase Sponsor Mike Faulkenberry
Sponsor Organ ization/Department Gas Operations & Engineering
Gategory Program
Drlver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
All known deteriorated pipe segments are compiled by each of our local Gas
Operations District offices. These segments are analyzed for risk and ranked using
Avista's Distribution Integrity Management Plan (DIMP). Gas Engineering and
each Gas Operations District take this risk ranking into account when prioritizing
projects. Each Gas Operations district is allotted a portion of the overall budget
and the project for each District will typically be designed and managed locally.
There are circumstances where lower priority projects may be accelerated if it
makes sense to coordinate the timing of pipe replacement projects with other utility
or road projects. The overall program budget is managed by Gas Engineering.
2 BUSINESS PROBLEM
As a Natural Gas Operator, Avista is mandated by Federal Code to maintain and
operate an active Integrity Management Program which analyzes risk associated
with the threats of gas facilities. Multiple factors impact risk and the replacement of
facilities including, but not limited to, materialfailures, environmental impacts,
increased leak frequency, buried threaded connections, unconventional/obsolete
pipe sizes, no protective coating (bare steel) and/or problems with protective
coating on pipe. This program is intended to address these risks.
ln regards to unconventional or obsolete pipe sizes, public risk is compounded by
operational risk and the associated challenges of having to work on pipe sizes that
are not supported by today's manufacturers. Standard fittings do not fit some of
this pipe, which limits the flexibility Operation Districts have to manage
emergencies if shut down of the facilities is required and a valve is not located in a
convenient location.
Sections of existing steel piping within Avista's gas distribution system are aging
and showing signs of deterioration or are operating with an increased risk of failure
primarily due to, but not limited to, corrosion of steel material. Sections of gas main
with known corrosion related issues no longer operate reliably and/or safely.
Higher frequency of leaks on these existing facilities result in higher risk of
Business Case Justification Narrative Page 1 ofS
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 154 of 325
Gas Deteriorated Sfeel Pipe Replacement Program, ER 3001
operation and higher risk to the customers served in the areas with these aging
facilities. This risk only increases the longer these facilities continue to operate.
This program is primarily focused on addressing deteriorated pipe in Avista's
Oregon territories as this is where some of the highest known risk exists, however
there will be an occasional need to utilize this program in Avista's other service
territories as well. See lmage I below for a list of known projects within this
program.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltal Goet Start Comploto
Option 1 - Do nothing/defer project $0 N/A
Option 2 - Preferred Solution,
Strategically replace sections of high
risk steel piping
$1,000,000 January December
Option 3 - Alternative Solution,
Reduced funding option: Strategically
replace sections of high risk steel
piping
$500,000 January December
Option 1 - Do nothing/defer project
lf no money is spent proactively replacing at risk pipe, then greater efforts would
be required to reactively address each specific leak or corrosion issue as it occurs.
This presents increased risk and safety concerns for the public located in the
vicinity of high risk facilities with known leaks or leak potential as well as corrosion
issues. Operational risks and challenges will continue that are related to
unconventional/obsolete pipe sizes. Not addressing known risks within our
distribution facilities would have a negative impact on overall Operations &
Maintenance Costs and would potentially be in violation of Federal Code
requirements for maintaining an active lntegrity Management Program resulting in
State or Federal fines. lt is very difficult to anticipate what the financial impact of
this would be. These risks cannot be mitigated without the replacement of these
facilities and risk increases the longer these facilities continue to operate. This
option is not recommended.
Option 2 - Preferred Solution, Strategically replace secfions of high risk steel
piping
It is recommended as part of a programmatic approach to identify and replace
sections of existing steel piping that are showing signs of aging and deterioration
or that are operating with an increased risk of failure within the natural gas
distribution system. Completing this type of work as part of a continuing annual
program is more proactive and is anticipated to have less overall cost impact than
by addressing each specific leak or corrosion issue as it is encountered. A
programmatic approach will also allow time for better analysis and planning to help
determine if larger diameter pipes are needed for additional capacity in these
service areas to help improve system operation for all downstream customers.
Business Case Justification Narrative Page 2 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 155 of 325
Gas Deteriorated Súeel Pipe Replacement Program, ER 3001
This program aligns with Avista's organizational focus on our responsibility to
maintain a safe and reliable infrastructure for all of our customers and in each of
our services territories. The intent of this program includes, but is not limited to, the
following:o An opportunity to target areas that will improve risk, public safety and
system reliability for all of our customers as part of our Distribution lntegrity
Management Plan (DIMP)o An opportunity to systematically prioritize and replace facilities on an annual
basis reducing a portion of the risk annually and spreading the cost of
replacement out over multiple years
Option 3 - Attemative Solution, Reduced funding option: Strategically replace
secfions of high rlsk sfee/ piping
Another option is to approach the risk associated with deteriorated pipe with a
reduced funding approach. Reduced funding will result in replacement of fewer
pipe segments that are showing signs of aging and deterioration or that are
operating with an increased risk of failure within the natural gas distribution
system. The reduced funding alternative would still allow us to benefit by
addressing facilities with known risk of failure, but at a pace slower than we feel is
appropriate at this time to address these known risks. The outcome, should this
option be selected, would result in the continued operation of known high risk
facilities which leads to increased public and operational risk as previously
described in Option 1. Annual levels of spending may need to be adjusted in this
program. However, as best as Avista is able to tell at this time, what is proposed is
the correct amount to address the known risks resulting from the Distribution
lntegrity Management Plan analysis.
D¡str¡ct Site
Estimated
Cost 2017 2018 20t9 2020 202L
20L6
DIMP
Score/ft Footage
Medford
DPR-BStreet&
Pioneer
6" Replacement,
Ashland OR S 3oo,ooo x 3140 4464
Medford
DPR - Bare Steel,
Medford, OR ??
Medford
DPR - McLaughlin 8"
Replacement, Ph 3,
Medford OR S so,ooo x 4r99 418
Medford
DPR - Mclaughlin 8"
Replacement, Ph 4,
Medford OR S so,ooo X 4735 586
Medford
DPR - Mclaughlin 8"
Replacement, Ph 5,
Medford OR s 50,000 x 1815 577
Medford
DPR - Mclaughlin 8"
Replacement, Ph 6,
Medford OR S so,ooo X 4448 537
Business Case Justification Narrative Page 3 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 156 of 325
Gas Deteriorated Súeel Pipe Replacement Program, ER 3001
Medford
DPR - McLaughlin 8"
Replacement, Ph 7,
Medford OR s 2307 608X
Medford
DPR - Mclaughlin 8"
Replacement, Ph 8,
Medford OR S so,ooo X 4165 536
Medford
DPR - OR
Shakespearean 6",
Medford OR S zo,ooo X ?
Medford
DPR-SOakdaleAve
Undersized, Medford
OR s 20,000 X 191.4 1432
Medford
DPR - 16 Western
Ave Pipe
Replacement,
Medford OR S 7o,ooo x ?
Medford
DPR-W8thSt
Replacement X 2933 2006
Medford
DPR - Kenwood Ave.
(incl Bare Steel)X 3787 809
Medford
4" line between
Peach and Quince S 7o,ooo X ?
Roseburg
Channon & Madison,
Roseburg S loo,ooo X
Roseburg
NE Emerald,
Roseburg S loo,ooo X
La
Grande
DPR - Cathodic Area
#8 Replace, Ph 9, La
Grande OR S 22s,ooo x
La
Grande
DPR - Cathodic Area
#8 Replace, Ph 10, La
Grande OR s 225,000 X
La
Grande
DPR - Cathodic Area
#8 Replace, Ph 11, La
Grande OR s 22s,000 x
La
Grande
DPR - Cathodic Area
#8 Replace, Pht2,La
Grande OR S sso,ooo X
Klamath
Falls
DPR - Mills Addition,
Ph5, K Falls OR s 2s0,000 2998 20t09
Klamath
Falls
DPR - Mills Addition,
Ph6, K Falls OR S zso,ooo X 2922 24088
Klamath
Fa lls
DPR - Mills Addition,
Ph7, K Falls OR S 3oo,ooo X 3040 23908
Klamath
Falls
DPR - Mills Addition,
Ph8, K Falls OR S 3oo,ooo X 3to7 t1246
Klamath
Falls
DPR - Mills Addition,
Ph9, K Falls OR S 3oo,ooo x 332s 14832
Klamath
Falls
DPR - Presidents
Streets, Ph 3, K Falls
OR X ?
Business Case Justification Narrative
lmage I - List of known projects
Page 4 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 157 of 325
Gas Deteriorated Súeel Pipe Rep lacement Program, ER 3001
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Deteriorated Pipe
Steel Replacement Business Case and agree with the approach it presents and
that it has been approved by the steering committee or other governance body
identified in Section 1.1. The undersigned also acknowledge that significant
changes to this will be coordinated with and approved by the undersigned or their
desig nated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Date 7'rz-r 7
Date:l"l tl
Webb
Manager Gas Engineering
Mike nberry
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 02124 12017
Verslon
#
lmplementod
BY
Revlslon
Date
Approved
By
Approval
Date
Reason
1.0 Seth Samsell 04t17t17 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 158 of 325
Gas ERT Replacement Program, ER 3054
I GENERAL INFORMATION
Requested Spend Amount $200,000
Requesting Organ ization/Department Gas Engineering
Business Gase Owner Jeff Webb, David Smith
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Category Program
Driver Asset Condition
l.l Steering Committee or Advisory Group lnformation
Gas Engineering recognized that a significant negative impact to both Avista Gas
Operations and to Avista's gas customers is being caused when an Encoder
Receiver Transmitter (ERT) module experiences a battery failure while in service
on a gas meter. The Asset Management department was consulted by Gas
Engineering for assistance developing a strategic program to replace ERT
modules before their battery expires. The result of the study suggested the most
efficient method for replacing these assets that resulted in the highest customer
satisfaction and lowest cost. The asset management study is attached to this
document for reference. Gas Engineering is responsible for managing this
program.
2 BUSINESS PROBLEM
ERTs are electro-mechanical devices that allow gas meters to be read remotely.
These ERTs are powered by lithium batteries, which discharge over time and must
eventual¡y be replaced.
There are approximately 106,000 ERTs in Oregon. Figure 1 below shows the
approximate quantity of ERTs installed each year in Oregon. The large quantity of
ERT installations will result in an unmanageable quantity of battery failures in the
future if not replaced at an optimized frequency. When batteries fail, customer's
estimated usage is entered into the billing system manually. This manual process
causes a high chance of customer dissatisfaction because of potential billing errors
associated with bill estimation. Customers often express their dissatisfaction
through commission complaints.
Since the batteries are gel sealed inside the ERT to protect against weather and
the environment, it is more cost effective to replace the whole ERT, not just the
battery. Avista used to replace batteries and reseal them, but determined it was not
cost effective to do so. The average battery life for ERT modules is 15 years.
Business Case Justification Narrative Page 1 of5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 159 of 325
Gas ERT Replacement Program, ER 3054
Approximate Quantity of ERTs lnstalled Per Year in Oregon*
¡Dâtr shown ls tha qurntlty of ERTS rêcclvêd crch yâar.nd is ! closr ¡pproxlm.tlon to th! quânlW ¡nstrllcd pcr yêår
35,000
31,300
30 000
25,0m
21,956
20,000
15,000
10,000
5,236 5,516 5,509 493s5,000
I
41æ 4,t23 4104 4,'t32 41613,586
I I70
1,353 909 989lrl ¡tio1992 1999 z(X)O 2o0l 2002 2003 200rt 2005 2006 2w7 2008 2009 2010 2011 2012 2013 2014 2015
Figure 1 - Approximate Quantity of ERTs Installed per year in Oregon
3 PROPOSAL AND RECOMMENDED SOLUTION
Option 1 - Do nothing, Operate the ERT modules untiltheir battery fails.
lf the ERT is operated until the battery fails, the number of battery failures will
increase to an unsustainable level. Figure 2 below shows the number of expected
ERT battery failures in this "Run-to-Failure" model. At its peak, more than 20,000
ERTs are predicted to fail annually, each requiring a maintenance call to replace,
causing an undue burden on Operations personnel and equipment. This large
number of failed ERTs will also cause an unreasonable number of meters that
Option Gapital
Gost
Start Gomplete Risk
Mitigation
Option 1 - Do nothing, Operate the ERT
modules until their battery fails.
$405,200 N/A
Option 2 - Preferred Solution, Replace
the oldest 7,000 ERTs each year on a
15 year cycle
$180,000 01t2016 04t2031
Option 3 - Alternative Solution, Replace
7,000 ERTs based on geographic
location each year on a 15 year cycle
$126,040 01t2016 04t2031
Business Case Justification Narrative Page 2 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 160 of 325
Gas ERT Repl acement Program, ER 3054
would need to be read manually and their usage estimated. A cost analysis was
performed and is discussed below under Option 3.
Failures in a Run-to-Failure Model
øo
3
t!ILÞÉt¡¡
25,000
20,000
15,000
10,000
5,000
0
"?.+oç"?o¿?""?o"?r"?""'¿r"'¿rþ"8."?""'+o+8"ê8r"'.rc'*
Figure 2 - Quantity of ERT Battery Failures per Year in Run-to Failure Model
Option 2 - Prefened Solution, Replace the oldest 7,000 ERIs each year on a 15
year cycle.
This option involves replacing the oldest ERTs each year, regardless of their
geographic location. The benefit to this approach is that the oldest ERTs are
targeted, resulting in less battery failures and, as a result, fewer estimated
customer bills. The disadvantage to this approach is that the oldest ERTs may not
be geographically close to one another, increasing traveltime in-between ERT
locations. A cost analysis was performed and is discussed below.
Option 3 - Alternative Solution, Replace 7,000 ERïs based on geographic location
each year on a 15 year cycle.
This option involves replacing a geographic cluster of ERTs. The benefit to this
approach is that the ERTs are located close to one another, which equates to less
traveltime in-between ERT locations. The disadvantage to this approach is that
the oldest ERTs may not be replaced if they are outside of the geographic zone, so
there would be a higher quantity of ERT failures. A cost analysis was performed
and is discussed below.
Cost Analysis Com ments:
A third party contractor provided a cost estimate for both replacement Options 2
and 3, and the cost to replace the oldest ERTs was not significantly more than
replacing the geographically located ERT clusters, therefore it costs less over the
life of the program (15 years) to replace the oldest ERTs (Option 2). Figure 3
shows the cost comparison between Options 1,2 and 3. Option 2 results in a
$12,500,000 savings compared to Option 1 and a $5,000,000 savings compared to
Option 3. Option 2 provides a levelized replacement strategy and will minimize the
Business Case Justification Narrative Page 3 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 161 of 325
Gas ERT Replacement Program, ER 3054
financial impact of ERT failures as well as introduce new, levelized populations of
ERTs into the system for future preventive maintenance. Customers will also be
the least impacted by choosing option 2 because the oldest ERTs are replaced
first, reducing the amount of battery failures and the resultant number of customer
bill estimations.
-
Run lo Fallure
-
16 Y.¡r Rephæment Cyd. Bæld on ERT
Ag.
* .. 16 Yr¡r Rcpl!æment Cyolè Ba*d on ERT L@lb¡
Ëô
tI
¡Ë,F
ÀIII
.!¿Êt
s50
945
s40
9r5
Slo
s25
920
51s
g10
s5
s o 1 2 3 4 5 I 7 I 9 l0 11 12 11 14 t5 15 r7 t8 19
Yc¡t
$12.5MM
Figure 3 - Cost Comparison for Options: 1 (red), 2 (green), and 3 (yellow)
Due to the "pre-capitalization process", the cost of the ERT will go against 8R1053
(Gas ERT Minor Blanket), not this business case.
The Advanced Metering lnfrastructure (AMl) project will replace ERT modules in
Washington and ldaho, therefore the ERT Replacement Program will be focused
on Oregon only at this time. This program will continue in Oregon until either the
technology or the lifecycle of the ERT changes.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 162 of 325
Gas ERT Replacement Program, ER 3054
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas ERT Replacement
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
ú// (/il Date: 7- r Z-, ZSignature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
lWwãoo
Manager Gas Engineering
Business Case Owner
Date: ql l-l I rlttMike F
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 021241201 7
[Verclon#
lmplementod
By
Revlslon
Dato
ABproved
By
Approval
Date
Reason
1.0 Jeff Webb 4117117 Mike
Faulkenberrv
04t17t2017 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 163 of 325
Gas Reg ulator Station Replacement Program, ER 3002
Requested Spend Amount $800,000
Requesting Organ ization/Department 851 Gas Engineering
Business Case Owner Jeff Webb
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Gategory Program
Driver Asset Condition
I GENERAL INFORMATION
l.l Steering Gommittee or Advisory Group Information
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
administer the Regulator Station Replacement Program. Gas Engineering is
ultimately responsible for prioritizing the projects and reporting out financial
updates to the Capital Budget Group.
A master list of Regulator Stations (pressure reduction stations) and industrial
meter sets with reported deficiencies is maintained by Gas Engineering. Gas
Operations and the Gas Meter Shop report concerns while performing regular
maintenance and these deficiencies are collected on the master list. Annually,
subject matter experts from Gas Operations and Engineering review the master
list and risk rank the work for the following year. Stations with the highest risk
(typically due to multiple different concerns) are prioritized over stations with only
minor issues. Prioritizing this work annually with the subject matter experts
provides a consistent approach. Through this process, the highest risk projects are
selected to be funded.
2 BUSINESS PROBLEM
This annual program will replace or upgrade existing at risk Regulator Stations and
industrial meter sets that are at the end of their service life to current Avista
standards. Additionally, it will address enhancements that will improve system
operating performance, enhance safety, replace inadequate or antiquated
equipment that is no longer supported, and ensure the reliable operation of
metering and regulating equipment.
Another category of work in this program is moving regulator stations located
underground in a vault to a more traditional above ground configuration. Stations
located in vaults are difficult to maintain because of the limited working room for
tools and workers. Additionally, water in the vault can make maintenance more
difficult. Regulator Stations in a vault are also a safety concern as they are
confined spaces and can trap harmful levels of natural gas should a leak be
present.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 164 of 325
Gas Reg ulator Station Replacement Program, ER 3002
These regulator stations require annual maintenance per 49 CFR 192.739, if the
equipment at the stations is obsolete and replacemenUmaintenance parts are no
longer available, then proper maintenance cannot be completed. lncomplete
maintenance could cause Avista to be out of compliance and be exposed to fines
from the various state utility commissions.
Our customers benefit from these types of projects by having a safer, more
reliable, well maintained distribution system. Also this is a prudent way to spend
resources because many deficiencies at a stations can be remedied under just
one project.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optionl-Donothing
The do nothing option willforce Avista to operate at risk regulator stations and
industrial meter sets in an unsafe, unreliable, and sometimes non-code compliant
manner.
Option 2 - Preferred Solution, Replace at risk regulator sfafions at current funding
level
The current level of spending allows the high priority projects to be completed
every year. The list of new requests continues to grow as stations meet the end of
their service life.
Since these stations are a vital link to providing customers with reliable gas,
planned work is better than unplanned work. Unplanned work during times of high
gas use (normally the winter) can be more difficult to perform and have negative
impacts to customers if it fails to operate properly.
Option 3 - Altemative Solution, Reduced funding level option
lf this program is funded at a reduced rate, there are two possible ways to
accomplish this. One is to replace fewer regulator stations and industrial meter
sets. As explained above, there is already a backlog of high risk stations to be
replaced, so this option would take an even longer time to get through that backlog
while new stations are continually added to the list every year. Secondly, an
alternative to rebuilding the entire station would be to replace only the individual
components that are antiquated or outdated. lf this short sided course were
Optlon Caplt¿l Goet Start Gomplete
Optionl-Donothing $0
Option 2 - Preferred Solution, Replace at risk
regulator stations at current funding level
$800,000 January December
Option 3 - Alternative Solution, Replace regulator
stations at a reduced funding level option
$400,000 January December
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 165 of 325
Gas Regulator Station Replacement Program, ER 3002
chosen, the work would be less productive; and the opportunity to bring the entire
station up to current standards would be lost. This option is not recommended.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Regulator Station
Replacement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Manager of Gas Engineering
Date: Ç-l 7-t 7
Date: ü
Mike F
Director of Natural
Business Case Sponsor
5 VERSION HISTORY
Template Version : 03107 12017
vbÞ
berry
Vercton lmplemented
BY
Revlslon
Date
Approved
By
Approval
Date
Rea¡on
1.0 Jeff Webb 04t17t2017 Mike
Faulkenberrv
04t17t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 166 of 325
New Revenue - Growth
1 GENERAL INFORMAT¡ON
Requested Spend Amount $47,443,826
Requesting Organ ization/Department Energy Delivery
Business Case Owner David Howell
Business Case Sponsor Heather Rosentrater
Sponsor Organization/Department Energy Delivery
Gategory Program
Driver Customer Requested
l.l Steering Committee or Advisory Group lnformation
The Energy Delivery Director Team assumes the role of advisory group for the New
Revenue - Grovuth Business Case, with quarterly reporting to the Board of Directors
through the Financial Planning & Analysis department. The appropriate extension
and service tariffs are designed and updated by the Avista Rates Department, in
cooperation with Construction Services, and the Financial Planning & Analysis
department. All Customer Project Coordinators are trained regularly, by Rates and
Finance, on tariff application.
2 BUSINESS PROBLEM
The New Revenue - Grovuth Business Case is driven by tariff requirements
that mandate obligation to serve new customer load when requested within
our franchised area. Growth is also seen as a method to spread costs over
a wider customer base, keeping rate pressure lower than would othen¡vise be
experienced.
Avista is required to serve appropriate new load, complying with our
Certificate of Convenience and Necessity, and as part of our Obligation to
Serve.
Avista uses a rolling 12-month Cost Per New Service spreadsheet to
measure ER1000, Electric New Revenue, and ER1001, Gas New Revenue
spending. Device blankets are subject to demand for both new revenue and
non-revenue installation and replacement.
Enclosed are lnternal Rate of Return runs from the Revenue Requirements
Model for each state and service, showing the breakeven spending to
achieve our current 7.29% authorized Rate of Return. These allow us to
periodically validate the Line Extension tariffs, to ensure that we are not
creating excessive rate pressure in connecting new customers.
a
a
a
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 167 of 325
New Revenue - Growth
3 PROPOSAL AND RECOMMENDED SOLUTION
o The New Revenue - Growth Business Case will provide funds for connecting
new Electric and Gas customers in accordance with our filed tariffs in each
state
. Our obligation to serve, mandates that we must extend service to new
customers in our franchised service areas. We do not currently have an
alternative to serving new customers. All projects are subject to our Line
Extension Tariffs, filed with each State Utility Commission.
r Enclosed is a spreadsheet showing projected spend through 2021 with a
breakout by Expenditure Request for the New Revenue - Growth Business
Case. Electric and Gas devices are also included, such as Meters,
Transformers, Gas Regulators, and ERTs (Encoder Receiver Transmitter).
Many of the Meters, Transformers, and ERTs are used as replacements for
Transformer Change Out Program, Wood Pole Management, and Periodic
Meter Changes. The costs are allocated based on an estimate of how many
devices of each type will be used for replacement, rather than new connects.
Those splits are shown on the spending summary.
o The New Revenue - Growth Business Case serves as support of several
focus areas in Avista. We seek to serve the interests of our customers, in a
safe and responsible manner, while strengthening the financial performance
of the utility. Our growth contributes to strong communities, ongoing value to
our customers, and the device portion of the business case keeps our system
safe and reliable.
o The requested funds are broken down in the enclosed spreadsheet, and
value assigned to each component.
o All new customers on Avista's system are benefitted by this business case.
ln addition, all customers who have their metering or regulation changed, or
who have transformers replaced, benefit from this business case.
Optlon Gapltal Goct StaÉ Gomplete
Do nothing $0
Se¡ve new customer load, and purchase appropriate
devices
$47,443,826 01 2017 12 2099
No other alternatives allowed under current tariff.$M MM YYYY MM YYYY
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 168 of 325
New Revenue - Growth
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the New Revenue - Growth
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives
il*USignature:
Print Name
Title:
Role:
David Howell
Director, Operations
Business Case Owner
Date: A t1
Date 4 lt-z ltl
Date
Tem pf ate Version : Ogl07 12017
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Heather Rosentrater
Vice President, Operations
Business Case Sponsor
Steering/Advisory Com mittee Review
5 VERSION HISTORY
Verclon lmplemented
BV
Revlolon
Date
Approved
By
Approval
Dato
Roason
1.0 NeilThorson 03/17/17 Heather
Rosentrater
03/17/17 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 169 of 325
ER
1000 Electr¡c New Revenue
ResidentialConnects
Residentia I Cost/Svc
Residential Dollars
20L6 20t7 2018 20t9 2020 202L
5,030
2,300
5,060 4,886
2,500
5,067
2,50O
5,L77
2,500
5,L77
2,5002,500
11,569,000 12,650,000 12,215,000 12,667,500 t2,942,500 12,942,500
1,000
2,219
8s0
2,500
82L
2,500
851
2,500
870
2,500
870
2,500
CommercialConnects
Commercial Cost/Svc
Commercial Dollars
ER1000 Total
1001 Gas New Revenue
Residential Connects
Residential Cost/Svc
Residential Dollars
Commercial Connects
Commercial Cost/Svc
Commercial Dollars
ER1001 Total
tOO2 Electric Meters
8R1002 Total
1003 Transformers
Growth and Other
WPM
TCOP
Fdr Rebuild
ERl003 Total
1004 Street Lights
ER1004 Total
1005 Area Lights
ERl005 Total
1009 NetworkProtectors
ERl009 Total
1050 Gas Meters
Growth
PMC
ERl050 Total
2,ztg,goo
t3,787,got
5,295
2,384
2,725,0O0
14,775,0O0
5,
2,051,,927
t4,266,927
5,479
3,095
2,127,940
14,795,440
2,t74,735
15,116,635
5,774
3,095
2,174,735
15,116,635
3,
5,744
3,095
L2,624,683 17,592,80L 16,955,3L3 L7,503,058 17,868,220 L7,775,382
656
095
68s
095
5,
3,
500
2,384
s60
3,000
540
3,000
557
3,000
s69
3,000
s66
3,000
7,192,L33 1,680,000 L,6L9,L24 L,671,,430 7,706,301 1,697,435
13,816,818 t9,272,8O1, 18,574,437 L9,174,488 t9,574,521 L9,472,8t8
550,000 550,000 550,000 500,000 500,000 500,000
550,000 550,000 550,000 500,000 500,000 500,000
3,134,000
L00,000
3,000,000
266,400
6,500,400
516,75r
L,427,68t
1,944,432
3,196,680
300,000
2,000,000
266,400
5,763,080
556,867
1,,470,512
2,027,379
3,260,674
350,000
2,000,000
266,400
5,877,OL4
536,688
L,51,4,627
2,05t,3L6
3,325,826
1,200,000
266,400
4,792,226
554,026
1,560,066
2,LLA,092
3,392,342
L,200,000
266,400
4,858,742
565,585
1,606,868
2,L72,453
3,460,189
1,200,000
266,400
4,926,589
562,646
r,655,074
2,217,720
700,000 900,000 900,000 900,000 900,000 900,000
700,000 900,000 900,000 900,000 900,000 900,000
625,000 650,000 675,000 700,000 700,000 700,000
625,000 650,000 675,000 700,000 700,000 700,000
950,000 960,000 980,000 980,000 980,000 980,000
950,000 960,000 980,000 980,000 980,000 980,000
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 170 of 325
1051 Gas Regulators
Growth
PMC
ERlO5l Total
1053 Gas ERTs
Growth
PMC
ERT Replacement
ERl053 Total
1108 Hallett & White subst
ERl009 Total
Growth Business Case Summary
Electric New Revenue
Gas New Revenue
Electric Meters
Transformers
Street Lights
Area Lights
Network Protectors
Gas Meters
Gas Regulators
Gas ERTs
Hallet & White Subst
TotalGrowth
1,900,000 950,000 950,000
1,900,000 950,000 950,000
ER1000
ER1001
ER1002
ER1003
ERr.004
ER1005
ER1009
ER1050
ER1051
ER1053
ER1108
15,116,635
L9,472,878
500,000
4,926,589
900,000
700,000
980,000
2,2L7,720
5L5,989
7,227,269
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6,500,400
700,000
625,000
950,000
7,944,432
34L,018
2,2L9,297
1,900,000
43,334,866 45,6L8,847 46,510,681 46,557,02L
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 171 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 172 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 173 of 325
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GN REV REQ ID CAIIbTAIEd IR
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 174 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 175 of 325
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Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 176 of 325
Gas lVon-Revenue Program, ER 3005
Requested Spend Amount $6,000,000 - Annual Request
Req uesting Organization/Department 851 - Gas Engineering
Business Case Owner Jeff Webb
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Category Program
Driver Failed Plant & Operations
I GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
This work is typically initiated by customers or Avista maintenance crews and is
managed at the Local District level. Gas Engineering establishes the overall
budget based largely on historical spend patterns and reports monthly updates to
the Capital Planning Group based on feedback from the Local Districts. Gas
Engineering is responsible for projects under this ER that require substantial
design efforts such as farm tap retirements, highway or river crossings, and steel
pipelines.
2 BUSINESS PROBLEM
The work in this annual program is mostly reactionary work and is difficult to
predict aside from using historical trends. The following situations are typical
triggers for such work: shallow facilities found by excavation (the excavation may
or may not be related to gas construction), relocation of facilities as requested by
others (except for road and highway relocations), leak repairs on ma¡ns or
services, meter barricades (only in Washington State and only through the year
2020), and farm tap elimination. Each of these work types are further described
below. Customer related benefits include reduced operations and maintenance
(O&M) costs and improved safety and reliability from having facilities at the proper
depth and from reduced leak rates of new plastic pipe versus older steel.
When shallow facilities are discovered, an appropriate response to the situation is
determined by Local District Management. lf the response to the situation is capital
in nature, then the repair is funded from this program. lf the scope of the project is
large enough to warrant it, the project will be prioritized and risk ranked against
other similar type projects. These types of projects allow Avista to remain in
compliance and operate the gas facilities in a safe and reliable manner.
lf requested bv others (typically customers) to relocate facilities, Avista is bound by
tariff language to do so at the customer's expense. Under certain circumstances,
Avista may choose these opportunities to perform additional work beyond the
immediate request to improve or update the gas system. Local District
Business Case Justification Narrative Page 1 of5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 177 of 325
Gas lVon-Revenue Program, ER 3005
Management and field personnel will evaluate the circumstances and make an
appropriate decision based on a holistic view of the situation. Guidance to help
evaluate the scenario is established in the Company Gas Standards Manual. An
example might be to replace an entire existing steel service with modern plastic
material instead of just replacing a small section of the steel service that is in
conflict with a customer's home improvement project. This would eliminate the
possibility of future deficiencies with the cathodic protection system on the steel
pipes and reduce future maintenance related to that steel service. The charges for
this additionalwork are put against this program.
When leaks are found on the gas system, it is sometime advantageous to replace
a section of main or service as opposed to just repairing the leak. The Local
District looks at the long term fix when possible, not just addressing the immediate
concern but considers what is the right thing to do in these situations. This type of
betterment falls under this program.
The need for a meter barricade can come from a variety of sources: customer,
meter reader, atmospheric corrosion inspectors, or from company personnel. Each
report is vetted by the Local District to ensure the need is warranted and then the
job is scheduled for installation. lnstallation of meter barricades on existing meters
sets is capital only in Washington State and only until through the year 2020.
A sinqle service farm tap (SSFT) installed on a supply main is a common way to
provide gas service to a small number of customers. The alternative is to install
distribution main from an adjacent distribution system to serve the customer which
may be cost prohibitive at the time. Many of these farm taps are reaching the end
of their service life or need to be replaced for maintenance reasons. ln areas of
high concentrations of farm taps that have maintenance concerns, it is sometimes
advantageous to rebuild one of them as a traditional regulator station (pressure
reduction station), install distribution main to the other services from the adjacent
farm taps, and then retire the other farm taps. This reduces O&M by having fewer
stations to maintain.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapltal Gost Start Complete
Optionl-Donothing $0 N/A
Option 2 - Preferred Solution,
Complete programmatic work as
described
$6,000,000 01-2017 12-2017
Option 3 - Alternative Solution,
Reduced funding
$3,000,000 01-2017 12-2017
Business Case Justification Narrative Page 2 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 178 of 325
Gas lVon-Revenue Program, ER 3005
Optionl-Donothing
Shallow facilities - Higher likelihood of being damaged and causing a gas leak.
Reouested bv rs & leak reoair - To miss the opportunity to better the system
while already on-site doing work is shortsighted because we increase the chances
of having to be back at the site to remedy other maintenance items at a later date.
The decision to simply repair the leak or perform the customer requested work
(quickest and easiest thing to do) eliminates the chance to improve the system as
a whole, while increasing the chances of having to be back at the site later to fix
another leak or maintenance concern. lf leaks are not repaired, they must be
monitored and re-evaluated on a periodic schedule to ensure they are not
becoming a greater hazard to the public.
Meter barricades - Not installing meter protection is against Federal Rules and
presents a significant safety risk to the public, especially if the facilities are
damaged.
Farm tap elimination - lf Avista is not allowed to optimize the gas distribution
system by reducing the number of farm taps that are maintenance intensive, then
eventually more staff will be required to perform this federally mandated work.
Additionally, farm taps are normally located between the driving lane and the
property line, are low profile, and are sometimes difficult for the public to see. This
puts them at risk of vehicle damage.
Option 2 - Preferred Solution, Complete programmatic work as described
Shallow facilities - Lowering gas mains and services is not required by Federal
Rules, but it is prudent. lt reduces the chances of damage caused by excavation
over and around the gas facilities. This is critical because damage from excavation
is the highest risk to our gas facilities. Excavators are expecting gas pipes to be at
the depths they are first installed at. When they are shallow because of grade
changes that have been caused by others since installation, there is an increased
risk of damage and threat to public safety.
Requested bv others & leak repair - Betterment of the gas system when
opportunities arise is the prudent way to operate a gas distribution system.
Mobilizing crews and equipment to a site often covers the bulk of the costs for
small projects, so making the most of the time once there is the sensible way to
operate. Betterments as described in Section 2 are driven by Company Standards
and best practices.
Meter barricades - Avista is mandated by Federal Rules to protect above ground
facilities from damage. Gas meters located where vehicles are normally parked or
driven create ahazard if the meter is not properly protected.
Farm tap elimination - When there are many farm taps located in close proximity
to each other and when those stations have reason to be rebuilt, then it makes
sense to rebuild just one of them and install distribution main to the other sites to
provide a new source of gas. This allows the adjacent farm taps to be retired,
reducing O&M and improving public safety. Triggers for rebuilding a farm tap may
Business Case Justification Narrative Page 3 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 179 of 325
Gas Non-Revenue Program, ER 3005
include; replacement of inadequate or obsolete equipment that is no longer
supported, poor location of station (safety concerns), inability to perform proper
maintenance, and capacity constraints.
The customers benefit from these types of projects by having a safer, well
maintained distribution system. Also this is a prudent way to spend resources
because many deficiencies at stations can be remedied under just one project.
Additionally, the new main may be installed in front of structures without gas
service, making it easier to serve them with gas in the future should choose to
change their energy source.
Option 3 - Altemative Solution, Reduced funding
Shallow facilities - Likelihood of being damaged and causing a gas leak if fewer
facilities were lowered.
Requested bv others & leak repair - This betterment would happen at a reduced
rate, causing workload pressure on the maintenance personnel. To miss the
opportunity to better the system while already on-site doing work is shortsighted
because we increase the chances of having to be back at the site to remedy other
maintenance items at a later date. The decision to simply repair the leak or
perform the customer requested work (quickest and easiest thing to do) eliminates
the chance to improve the system as a whole, while increasing the chances of
having to be back at the site later to fix another leak or maintenance concern. lf
leaks are not repaired, they must be monitored and re-evaluated on a periodic
schedule to ensure they are not becoming a greater hazard to the public.
Meter barricades - Not installing meter protection is against Federal Rules and
presents a significant safety risk to the public, especially if the facilities are
damaged.
Farm tap elimination - This optimization would happen at a reduced rate, causing
workload pressure on the maintenance personnel.lf Avista is not allowed to
optimize the gas distribution system by reducing the number of farm taps that are
maintenance intensive, then eventually more staff may be required to perform this
federally mandated work. Additionally, farm taps are normally located between the
driving lane and the property line, are low profile, and are sometimes difficult for
the public to see. This puts them at risk of vehicle damage.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Non-Revenue Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 180 of 325
Gas Non-Revenue Program, ER 3005
Signature:
Print Name
Title:
Role:
Webb
Manager of Gas Engineering
Business Case Owner
Date: 7t 7-lz
Date: 4lrr/¡1Signature:
Print Name
Title:
Role:
Mike F nberry
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Template Version : 0212412017
[Vercion#
lmplemented
By
Revlslon
Date
Approved
By
Apprcval
Date
Reason
1.0 Jeff Webb 04t17t201
7
Mike
Faulkenberrv
04t17t2017 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 181 of 325
Gas Cathodic Protection Program, ER 3004
I GENERAL INFORMATION
Requested Spend Amount $800,000
Requesting Organ ization/Department 851 - Gas Engineering
Business Case Owner Jeff Webb, Tim Harding
Business Gase Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Gategory Mandatory
Driver Mandatory & Compliance
l.l Steering Gommittee or Advisory Group lnformation
The Cathodic Protection (CP) group monitors system performance and
recommends replacements and upgrades when corrosion control measures
become ineffective. Gas Engineering evaluates the recommendations with the CP
group and other interested parties. The pros and cons of each option are then
reviewed with the Gas Engineering Manager and a preferred alternative is
selected to proceed with a funding request. Gas Engineering is responsible for
managing this program.
2 BUSINESS PROBLEM
CP system compliance is mandated by Federal Rules within the Department of
Transportation code 49 CFR 192. Some of the CP systems have been in service
at Avista for extended periods of time and they have exceeded their useful service
life. This requires them to be replaced. lt is often difficult to predict in advance
when specific projects are required, because sudden component failures do occur.
Anodes, a key component of the CP systems, are buried and not observable,
deteriorate at differing rates, and become ineffective when they are used up.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Carlt¡l Coet Start Complete
Optionl-Donothing $o N/A
Option 2 - Preferred Solution, Replace end of life
cathodic protection systems
$800,000 01-2017 12-2017
Optionl-Donothing
CP systems have a finite lifespan and must be replaced when they are at the end
of their service life. Failing to replace these facilities will result in inadequate
external corrosion protection on Avista's steel piping systems. This would result in
non-compliance with State and Federal Rules, as well as increased risk to both
employee and public safety.
Business Case Justification Narrative Page I of 2
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 182 of 325
Gas Cathodic Protection Program, ER 3004
Option 2 - Preferred Solution, Replace end of life cathodic protection sysfems
Typical types of projects installed under this work type may include (but are not
limited to) CP deep and shallow anode wells, Remote Monitoring Units (RMU),
installation of CP rectifiers, shorted casing remediation, replacement of gas mains
to improve CP system performance.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Cathodic Protection
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Jeff Webb
Date '/- /7-/7
Date: qllltrr
Manager Gas Engineering
Business Case Owner
Mike nberry
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Tempfate Version: 03107 12017
Verclon lrnplemente
d
By
Revlslon
Date
Approvod
By
Approval
Data
Roason
1.0 Jeff Webb 04t13t2017 Mike
Faulkenberry
04t17t2017 lnitialversion
Business Case Justification Narrative Page 2 of 2
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 183 of 325
GAS FACILITY REPLACEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
I GENERAL INFORMATION
Requested Spend Amount $20, 000,000 - $22,000,000 Annually
Requesting Organ ization/Department Natural Gas / Gas Facility Replacement Program
Business Case Owner Michael B. Whitby
Business Case Sponsor Heather Rosentrater / Mike Faulkenberry
Sponsor Organization/Department Energy Delivery / Gas Delivery
Gategory Program
Driver Mandatory & Compliance
l.l Steering Committee or Advisory Group lnformation
ADVISORY GROUP:
The Gas Facility Replacement Program (GFRP) Advisory Group consists of the GFRP's
Program/Project Manager, Gas Operations Contract Construction Manager, Director of Natural Gas,
and the Manager of Gas Design & Measurement. This group meets each month to review program
wide Earned Value results, the status of the delivery of all individual projects, budget allocations and
variances, internal resource demands, customer care results and issues, contractor performance,
and to communicate potential program risks and shortfalls when necessary.
ln addition, Avista's Asset Management Group provides periodic input, and or validation of the
replacement plan and schedule.
The GFRP's annualwork load is captured in an annual "Operating Plan & Projects" document.
2 BUSINESS PROBLEM
MAJOR DRIVERS OF THE GAS FACILITY REPLACEMENT PROGRAM:
As of Augusl2Oll the US Department of Transportation Pipeline and Hazardous Materials Safety
Administration (PHMSA) mandates gas distribution pipeline operators to implement lntegrity
Management Plans, or in Avista's case, a Distribution lntegrity Management Plan (DIMP) in which
pipeline operators are required to identify and mitigate the highest risks within their system. For
Avista, aside from third party excavation damage, the highest risks within our natural gas distribution
system is Aldyl A Main Pipe (Manuf. 1964-1984), and the bending stress that occurs on Aldyl A
service pipe where it is connected to steel main pipe.
More specifically, and as related to the risks identified above, in February 2012 Avista's Asset
Management Group released findings in the "Avísta's Proposed Protocol for Managing Selecf
Aldyt A Pipe in Avista lltitity's Natural Gas Sysúem" report. The report documents specific Aldyl
A pipe in Avista's natural gas pipe system, describes the analysis of the types of failures observed,
and the evaluation of its expected long{erm integrity. The report proposed the undertaking of a
twenty-year program to systematically replace select portions of Aldyl A medium density pipe within
its natural gas distribution system in the States of Washington, Oregon, and ldaho.
Subsequently, the Gas Facility Replacement Program's (GFRP) was formed as the operationalentity
committed to structuring and implementing a systematic approach to mitigating the AldylA pipe risks
as identified in aforementioned report.
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 184 of 325
GAS FACILITY REPLACEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
AVISTA HAS A REGULATORY MANDATE TO COMPLETE THIS PROGRAM.
On Decemb er 31 ,2012 the Washington Utilities and Transportation Commission (WUTC) issued its'
policy statement on Accelerated Replacement of Pipeline Facilities with Elevated Risks which
requires gas utility companies to file a plan every two year for replacing pipe that represents an
elevated risk of failure. The requirement to file a Pipe Replacement Plan (PRP) commenced on June
1,2013.|n response to this order, Avista's first two-year PRP for 2014-2015 was submitted and
approved in 2013 per Docket PG-131837, Order 01. Avista's second two-year PRP for 2016-2017
was submitted in 2015 and approved in 2016 per WUTC Docket PG-160292, Order 01. ln Avista's
filings, the '?vlsfab Proposed Protocotfor Managing Se/ecf Aldyl A Pipe in Avista Utility's Natural
Gas Sysfem" report serves as the pipe replacement "Master Plan", and two year pipe replacement
goals which includes specific project locations, and the anticipated pipe replacement quantities.
While the ldaho Public Utilities Commission (IPUC) and the Oregon Public Utilities Commission
(OPUC) have not required gas utility companies to file pipe replacement plans, Avista has submitted
the 'Avrsfa's Proposed Protocot for Managing Se/ecf Aldyl A Pipe in Avista Utility's Natural Gas
Sysfem" report for review, and communicates annual pipe replacement goals which includes specific
project locations, and the anticipated pipe replacement quantities.
ALDYL A RISK MANAGEMENT: BASE CASE VS. REPLACEMENT GASE:
The need to conduct this program has been identified in "Avista's Proposed Protocol for Managing
Select Aldyl A Pipe in Avista Utility's Natural Gas System" report. Further, and more specifically, due
to the tendency for this material to sutfer brittle-like cracking leak failures, Aldyl A will eventually
reach a level of unreliability that is not acceptable. There is a potential harm to the public through
damage to life and property and there is a high likelihood of increasing regulatory scrutiny from
increasing failures. Not approving, or deferring this body of work would further exacerbate the risks
as identified above.
The chart below identifies the expected number of materialfailures in Avista's Priority AldylA piping
in two cases: Replacement Case - piping replaced over a 20 year time horizon, and Base Case -
assumed that priority piping was not remediated under any program.
-BaseCase -fspl¿çementCase
2015
600
500
400
300
200
100
o
2010
tJ.!o¡J
oLo,¡E
-ul!ü
o¡!
2030 203520202025
Year
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 185 of 325
GAS FACILITY REPLAGEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
As outlined in "Forecasting Results" section of "Avista's Proposed Protocol for Managing Select Aldyl
A Pipe in Avista Utility's Natural Gas System" report, Avista's forecast modeling tool "Availability
Workbench Modeling" evaluates several classes of pipe which are represented as "curves" showing
the percentage of the amount of pipe class that is projected to fail in each year of the forecasted time
period. Figure 5 of the report is shown below:
Forecast Fallure Rates for Natural Gas Plplng
=fÉl¡-aE!,
ECLxl¡¡o.go-
o!¡cD6Ë@eo,è
25o/o
20olo
1íYo
1Oólo
5o/o
Oo/o
- - Bendlng Stress Sêrv¡cas
..... Pre-lgE4Aldyl A
-.^lS4and laterAldylA
-steel- . NewerPol¡rcthylcnc
o É B g È I g ë8 8ä = ËË Ë Ë d _iË Ë BooooooÞoooo
Years
II,
I,
t
II
The GFRP's Service Tee Transition Rebuild Program is structured to mitigate the risks associated
with the "Bending Stress Seryices" category within a five-year time frame. The Aldyl A Main Pipe
Replacement Program has been structured to mitigate the "Pre-1984 Aldyl A" over a twenty year
time frame.
OBJECTIVES & MEASURES OF SUGGESS:
The objective of this investment and structured replacement program is to reduce risk by replacing
at risk pipe, and by rebuilding Service Tee Transitions. Through rigorous Project Management efforts,
the GFRP plans and tracks the performance of all projects, and utilizes Earned Value for cost
analysis and for upstream reporting. Further, the GFRP tracks and reports Planned vs. Actual
quantities by project, by year, by state jurisdiction, and also reports multi-year cumulative statistics.
REFERENCE STUDIES:
"Avista's Proposed Protocol for Managing Select Aldyl A Pipe in Avista Utility's Natural Gas System"
report has been attached.
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 186 of 325
GAS FACILITY REPLACEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
3 PROPOSAL AND RECOMMENDED SOLUTION
GAS FACILITY REPLACEMENT PROGRAM IMPACTS TO BUSINESS FUNCTIONS &
PROGESSES:
The Aldyl A Pipe Replacement effort has been proposed and planned as a systematic twenty-year
pipe replacement program. The program is expected to have a nominal impact to existing business
resources, functions and processes since the GFRP has been structured to function as a "stand
alone" program consisting of dedicated "internal" resources. The primary functions established for
these internal resource are to plan, design, oversee, manage, and administer the significant body of
projectized work as assigned to "external" contract construction resources.
Periodically, on an as-needed basis, the GFRP will call on other business units for support.
Since pipe replacement work is a capital expenditure, the impact to O&M cost has been minimal.
Occasionally GFRP projects will encounter circumstances that necessitate O&M expenditures. When
known, these O&M costs are estimated prior to construction. The GFRP tracks & monitors O&M
costs each month.
ALTERNATIVES CONSIDERED :
To establish context, Avista's goal is operate a safe & reliable, and cost effective gas distribution
system. Specifically as related to these goals, $ Xl of 'Avista's Proposed Protocol for Managing
Se/ecf Aldyl A Pipe in Avista Utility's NaturalGas Sysfem" report details the various time horizons
modeled for the Aldyl A Pipe Replacement program.
To summarize, the primary alternatives modeled are as follows;
¡ Do Nothing
Pipe Replacement Strategies:
Since the "do nothing" option was not an acceptable or prudent approach, the Company evaluated
different periods of time for removal of all Priority Aldyl A pipe, up to a program horizon of 30 years.
Avista assessed the prudence of different approaches based on the forecast of likely natural gas
leaks due to failed pipe, as well as the rate impact to customers.
o Less than 20 Year Pipe Replacement Program
r Conduct a 20 Year Pipe Replacement Program (Optimal)
. Conduct a 25+ Year Pipe Replacement Program
Based on the time horizon scenarios modeled, it was determined that the optimum timeframe for
removing priority Aldyl A pipe was the 20 years..
Optlon Gapltal Gost gtart Complete
Replace all Priority Aldyl A Pipe in Avista's
Sysúem in a Timeframe of 20 Years
= $355M 01 2012 12 2031
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 187 of 325
GAS FACILITY REPLACEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
RISKS ASSOCIATED WITH ALTERNATIVES CONSIDERED:
To summarize the primary alternatives and associated risks;
o Do Nothing:
It has been determined that this type of pipe is at risk and is approaching unacceptable levels
of reliability without prompt attention. The "Do Nothing" option exposes Avista to increased
operational risks, and worse, is a potential harm to our customers and the public through
damage to life and property, and a high likelihood of legal action against the Company and
likely regulatory fines. For this reason it was deemed "not prudent" and is not a serious
consideration.
r Less than 20 Year Pipe Replacement Program:
Avista found that a timeline less than 20 years resulted in a greater cost impact to customers
in the near term, and that it did little to reduce the forecast number of leaks expected each
year. This approach did not effectively optimize the potential risks and rate impacts.
. Conducta20 Year Pipe Replacement Program:
The report proposes and suggests that a Systematic Replacement Program conducted over
a 20 year timeline is the optimum timeframe to prudently manage this risk, based on the
forecast number of leaks and risks, and the rate impact to our customers.
. Gonduct a 25+ Year Pipe Replacement Program:
Lengthening the timeframe to 25 years resulted in more than a doubling of the number of
leaks expected when compared to a 20 year horizon. Lengthening the timeline beyond 25
years was found to result in a substantial increase in the number of material failures
expected.
As outlined above, Asset Management has identified 20 years as the optimum timeframe to prudently
manage this risk. Avista's leadership has adopted this recommendation and has funded and staffed
the program to achieve this objective. Furthermore, the three state Commissions that regulate
Avista's natural gas operations have thoroughly examined this program in several rates proceedings,
and in policy proceedings, and have deemed this approach to be prudent, cost effective, and in the
interest of our customers.
TIMELINE:
Start: 2012
End: 2031
The annual list of projects are established as unique "blanket projects" that transfer to plant each
month as they are "used & useful".
STRATEG¡C ALIGNMENT & VISION:
The GFRP's Aldyl A Pipe Replacement efforts aligns with Avista's commitment to invest in our
infrastructure to achieve optimum lifecycle performance - safely, reliably and at a fair price. The
Program eliminates risk by replacing at risk pipe, which in turn increases system reliability. ln effort
to ensure a fair price for the work, the GFRP has established "Unit Price" type contract with a multi-
year duration of 5 years. On five year intervals, the GFRP plans to test the market for "fair pricing"
by issuing a Request for Proposal (RFP) and by receiving competitive proposals for the work. The
first ever GFRP RFP yielded (7) interested contractors, (6) qualified proposals, and a two contracts;
1. Main Pipe Replacement. 2. Service Tee Transition Rebuild (STTR).
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 188 of 325
GAS FACILITY REPLACEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
BUDGET JUSTIFICATION:
As a mandated Pipe Replacement Program, the recommended 20 year replacement approach does
not include a specific cosVbenefit analysis document, however based on recent pipe replacement
cost experience, the program currently estimates the budget to be $20,000,000 - $22, 000,000
annually.
CUSTOMERS & STAKEHOLDERS:
Avista's customers and the general public expect our natural gas system to operate safely, and
reliably without inconvenience or incidents. Avista is dedicated to, and focused on maintaining a safe
and reliable system that shields the public from inconvenience and imprudent risks. The proposed
pipe replacement program has been initiated with the purpose of mitigating the known risks within
our natural gas distribution system. Given this context, the Gas Facility Replacement Program's
portfolio of projects could therefore be considered as customer-related benefit.
The GFRP's Aldyl A Pipe Replacement projects touch many internal & external stakeholders. A
comprehensive list of stakeholders can be located in the annual "GFRP Operating Plan & Projects"
booklet.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Facility Replacement Program (Aldyl
A Pipe Reptacement) and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Sectionl.1. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.
Signature Date:4t07117
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Michael B. Whitby
Program/Project Manager
Business Case Owner
Business Case Sponsor
Mike
Director NaturalGas
Date: ¿41 rì lrrrl
4 VERSION HISTORY
Ven¡ion lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
'1.0 MichaelWhitby 04/07/2017 Mike Faulkenberry 04//17/2017 lnitialversion
Tem plate Version : 03107 1201 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 189 of 325
GAS FACTLITY REPLACEMENT PROGRAM (GFRP)
ALDYL A PIPE REPLACEMENT
supplant
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 190 of 325
Gas HP Pipeline Remediation Program, ER 3057
1 GENERAL INFORMATION
Requested Spend Amount $3,000,000
Requesting Organization/Department Gas Engineering
Business Case Owner Jeff Webb, David Smith
Business Gase Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Category Program
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
The Gas Compliance department is responsible for ensuring Avista is compliant
with Federal and State Regulations governing the distribution of natural gas.
When a new regulation is brought into effect, the Gas Compliance department will
determine if Avista is meeting the requirement or not. lf the new requirement is
not being met, the Gas Compliance department will notify the appropriate work
group and work with them to determine the appropriate path forward to ensure
compliance. Gas Engineering is responsible for managing this program.
2 BUSINESS PROBLEM
Current industry Pipeline Safety code requires pipeline operators to have pressure
test documentation and material specifications for pipelines distributing natural
gas. Avista has some deficiencies in these types of records, but industry
regulators (state inspectors) historically have not placed much emphasis on this,
specifically for facilities that operate at lower stress Ievels and therefore at a lesser
risk to the public. Avista's history, very similar to that of other utilities, involves
pipeline construction during times when the pipeline safety code was not in effect
or taken to be that important. Also, Avista has acquired properties from other
companies and therefore had no control over their testing practices and record
keeping prior to the acquisition. The regulatory climate is now changing and more
scrutiny is being placed on having these records.
The Pipeline and Hazardous Materials Safety Administration (PHMSA) is actively
working on a new rule that is expected to be published in December o12017 called
"Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines". When
implemented, it will require pipeline operators to have "traceable, verifiable, and
complete" Maximum Allowable Operating Pressure (MAOP) records for its
transmission facilities. Our understanding of the Rule is that Avista will now need
to begin aggressively addressing portions of our system in order to be in
compliance. Until the Rule is published, it is not clear yet what the timeframe will
be to create a plan and mitigate all deficiencies.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 191 of 325
Gas HP Pip eline Remediation Program, ER 3057
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltal Coet Start Complets
Option 1 - Do nothing / Defer project $o
Option 2 - Preferred Solution,
Continue to remediate segments of
high pressure pipeline.
$3,000,000 2016 2022
Option 3 - Alternative Solution,
Reduced funding option: Replace
segments of high pressure pipeline.
$1,500,000 2016 2022
Option 1 - Do nothing / Defer project.
lf segments of transmission pipeline without traceable, verifiable, and complete
MAOP records are not mitigated, Avista will be non-compliant with Federal
Pipeline Safety Codes, especially when the Rule mentioned above becomes final
lf the work in this program is not completed, Avista will be going against industry
guidance and trends. Once the Federal Rules become final, penalties and fines
may be imposed for not completing this work.
Option 2 - Preferred Solution, Continue to remediate segments of high pressure
pipeline.
As stated above, the proposed Federal Rule will force action to address lack of
sufficient MAOP records. Transmission pipelines without traceable, verifiable, and
complete MAOP records will be replaced or mitigated within this program.
Reasons for this work will include, but are not limited to; incomplete construction
and pressure test documents, pipe quality deficiencies from the manufacturing
process, and risk reduction in densely populated areas. As a result of completing
this option, public and employee safety will be improved by replacing at risk pipe.
Officials and spokesmen from both PHMSA and the American Gas Association
(AGA) have stated it is not prudent for operators to wait for the Federal Rule to
become finalized before bettering their systems in this category of work. Avista
has been in the process of remediating pipelines under this program since 2015
lncidentally, many of these facilities have been in service for over 30 years.
Depending on the final language of the Rule, the annual levels of spending may
need to be adjusted in this program. However, as best as Avista is able to tell at
this time, what is proposed is the correct pace to complete this Program. The
current rate of work is reasonable with Avista's Engineering and construction
workforces.
Avista will address replacement or mitigation of its pipelines in the order of highest
operating stress and highest levels of record deficiencies. This program will be
prioritized in all three of its natural gas operating states and will analyze risks and
Business Case Justiflcation Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 192 of 325
Gas HP Pipeline Remediation Program, ER 3057
priorities regardless of jurisdiction. The projects in 2017 will likely all be in Oregon.
Replacement projects in 2018 and beyond have not yet been determined.
Option 3 - Altemative Solution, Reduced funding option: Replace segments of
high pressure pipeline.
Reduced funding will result in replacing fewer pipeline segments with insufficient
MAOP records. This will be at a pace slower than has been accomplished
historically and slower than what we feel is the ideal rate as described above. The
outcome, should this option be selected, may be pipeline segments being out of
compliance with Federal Regulations and a greater amount of backlog to work
through once the Rule is published.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas HP Pipeline
Remediation Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
clM Date:l-r z-r7
Date: L1 -?
--ryffiw"bb
Manager Gas Engineering
Business Case Owner
Director of Natural
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 02124 12017
[Vorclon#
lmplemented
By
Ravlelon
Dato
Approved
Bv
Approval
Date
Roason
1.0 Dave Smith 03t09t2017 Mike
Faulkenberry
041't7t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 193 of 325
Gas Isolated Súeel Replacement Program, ER 3007
Requested Spend Amount $2,050,000 - Annual Request
Requesting Organization/Department 851 - Gas Engineering
Business Gase Owner Jeff Webb, Jodie Lamb
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Gategory Mandatory
Driver Mandatory & Compliance
1 GENERAL INFORMATION
l.l Steering Committee or Advisory Group lnformation
Gas Construction Management is responsible for identifying the work. The work is
then dispatched to Gas Operations to complete. The overall program budget is
managed by Gas Engineering.
2 BUSINESS PROBLEM
The program objective is to identify and document isolated steel pipe sections,
including isolated risers, and to replace each riser or pipeline section within a
specified timeframe after its identification. The program started in November 2011
and is planned to be complete by November 2021. lsolated portions of pipe
including risers, service pipe and main will be replaced as required to meet the
requirements of 49 CFR 192.455 & .457 and in accordance with WUTC Docket
PG-100049. This program will be conducted in lD and OR also to assure
cathodically isolated steel is identified and replaced as needed.
Once the isolated sections of steel pipe are identified, projects are created to
replace them with new pipe. This new pipe could be either steel or plastic.
Management of the cathodic protection (CP) zone will drive the decision between
steel and plastic pipe. A Generalized Work Flow is provided in lmage 1 below.
Per the agreement, isolated steel risers are being replaced at a rate of at least
10% per year, starting in 2011, and short sections of isolated steel main are
replaced within one year of discovery. Work completed under this program results
in a safer gas distribution system.
Business Case Justiflcation Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 194 of 325
Gas Isolated Súeel Replacement Program, ER 3007
Generalized lsolated Steel ldentification/Replacement Process Flow
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Rb€r Poht
Si.ofPhrüc
Adlm Cqte 3Múlbr
llÞYear
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lmage 1 - Generalized Work Flow
3 PROPOSAL AND RECOMMENDED SOLUTION
Option GapltalGost Start Gomplete
Optionl-Donothing $ TBD
Option 2 - Preferred Solution,
Complete the program per the
agreement
$2,050,000 2011 11-2021
Optionl-Donothing
The alternative to completing this program would be to not finish the work within
the timeframe dictated by the WUTC. This would be a direct violation of the
stipulated agreement between Avista and the WUTC and likely result in financial
penalties.
Option 2 - Preferred Solution. Complete the program per agreement as described
above
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 195 of 325
Gas lsolated Súeel Replacement Program, ER 3007
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas lsolated Steel
Replacement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Business Case Owner
Date: ?-rz-r7
Date: ql n [n
bb
Manager Gas Engineering
IIMike
Director of Natural
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 0212412017
[Vemlon#
lmplemented
By
Revlslon
Dete
Approved
By
Approval
Dato
Reaaon
1.0 Jeff Webb 04t17t2017 Mike
Faulkenberry
04t17t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 196 of 325
Gas Overbuilt Pipe Replacement Program, ER 3006
Requested Spend Amount $900,000 - Annual Program Request
Req uestin g Organ ization/Department 851 - Gas Engineering
Business Gase Owner Jeff Webb, Seth Samsell
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department Gas Operations & Engineering
Category Program
Driver Mandatory & Compliance
I GENERAL INFORMATION
l.l Steering Committee or Advisory Group lnformation
All the known mobile home parks with overbuilt pipe are analyzed and risk ranked
as part of Avista's Distribution lntegrity Management Plan (DIMP). This analysis
allows Gas Engineering and each of the Gas Operations Districts to prioritize risk
associated with overbuilt pipe projects in each respective service area and
complete projects with the highest risk first. Each Operations District is allotted a
portion of the overall budget and the project priorities for each District are typically
managed locally. The overall program budget is managed by Gas Engineering.
2 BUSINESS PROBLEM
As a Natural Gas Operator we are required to operate within the minimum safety
standards described in Part 192 oÍ the Federal Code of Regulations governing the
transportation of natural gas by pipeline. Sections of existing gas piping within
Avista's gas distribution system have experienced encroachment or have been
overbuilt by customer constructed improvements (i.e. living structures, sheds,
decks, etc...) and can no longer be operated or maintained safely.
Overbuilds restrict company access to the pipe resulting in accessibility issues as
well as the inability to perform particular maintenance required by Federal Code
such as leakage survey. Leakage surveys are typically performed by walking
directly above the gas facilities while operating leak detection equipment. This
maintenance becomes impossible if access to the ground above the facility
becomes hindered. Overbuilds not originally designed to be in an overbuilt
condition are also a violation of the Federal Code for an overbuilt facility as they do
not meet code requirements for installation within a sealed conduit that can be
vented outside of the overlying structure.
Overbuilds present an increased risk to customers as well as operational risk due
to the ability of potential leaks to migrate into or become entrapped within
structures built over the gas facility resulting in hazard to life and property. Multiple
factors impact risk and the replacement of these facilities, but of primary concern
is the increased risk hazard due to leak. Overbuilds also increase Operations and
Maintenance costs as Avista is often required to return to overbuild locations
Business Case Justification Narrative Page 1 ofS
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 197 of 325
Gas Overbuilt Pipe Replacement Program, ER 3006
multiple times to attempt and complete leak survey and other maintenance tasks
that cannot be completed at the normal scheduled time due to the overbuild.
This program is primarily focused on addressing overbuilt pipe in mobile home
parks as this is where the highest risk and greatest quantity exist due to the
dynamic nature of these facilities. However overbuilds are not isolated to mobile
home parks and the need exists for this program to be utilized in all of Avista's
service territories. lmage 1 below is a list of know projects within this program.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option 1 - Do nothing/defer project
The do nothing option will continue to operate these facilities without replacement.
There is significant risk associated with not remediating these facilities and this
would be a violation of the Code of Federal Regulations subjecting Avista to
potential State and Federalfines associated with operating facilities that are out of
compliance. The financial impact of this alternative is very difficult to estimate as
penalties for non-compliance are on a case by case basis. Known risks cannot be
mitigated without replacement of these facilities or remediation of the overbuild
condition. This option is not recommended.
Option 2 - Preferred Solution, Complete programmatic replacement of overbuilt
secfions of pipe
It is recommended as part of a programmatic approach to identify and replace
sections of existing pipes that can no longer be operated safely as they have
experienced encroachment or have been overbuilt by customer constructed
improvements. Completing this type of work as part of a program will allow for the
prioritization of overbuilt facilities based upon those instances with the highest risk
to customers as well as operationally. Our Distribution Integrity Management
Program (DIMP) help prioritize the projects within each district. This methodology
is also more proactive and is anticipated to have less overall cost impact than by
addressing each specific issue as it is encountered. This program helps address
Avista's responsibility as a Natural Gas Operator in working to maintain
compliance with the Code of Federal Regulations that governs the operation of
Option Capital Cost Start Complote
Option 1 - Do nothing/defer project $0 N/A
Option 2 - Preferred Solution, Complete
programmatic replacement of overbuilt
sections of pipe.
$e00,000 01 2017 122017
Option 3 - Alternate Solution #1, Reduced
Funding Option: Complete programmatic
replacement of overbuilt sections of pipe.
$450,000 01 2017 122017
Option 4 - Alternate Solution #2, Attempt
to enforce Avista's easement rights
Unknown Unknown Unknown
Business Case Justification Narrative Page 2 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 198 of 325
Gas Overbuilt Pipe Replacement Program, ER 3006
natural gas distribution systems. lt also aligns with Avista's organizationalfocus to
operate safe and reliable infrastructure for all of our customers in each of our
service territories.
The current funding level balances available manpower with other programs
administered at the District Offices and allows crews to also work on other
compliance and risk reduction type activities. Annual levels of spending may need
to be adjusted in this program as the risks in DIMP are reassessed annually.
Option 3 - Altemative Solution #1, Reduced funding option: Complete
programmatic replacement of ovefuuilt secfions of pipe
Another option is to approach the risk associated with overbuilds with reduced
funding. Reduced funding will result in replacement of fewer sections of overbuilt
piping. The reduced funding alternative would still allow us a benefit by addressing
some of the overbuilt facilities with known risk, but at a pace slower than we feel
appropriate to address these safety concerns and maintain compliance. The
outcome, should this option be selected, would result in the continued operation of
facilities known to be out of compliance and which are currently operating with
higher risk to customers and operations personnel. Additionally, Operations &
Maintenance funds would not decrease since Avista is often required to return to
an overbuild locations multiple times to attempt and complete a leak survey or
other maintenance tasks that cannot be completed due to the overbuild. This
option would be a partial employment of both Options 1 and 2 and is not
recommended.
Option 4 - Altemative Solution #2, Enforce Avista's easement rights.
A final option to this program is to attempt to enforce Avista's "rights" and try to
force the owners, renters, or mobile home parks owners to be liable for these
fixes, however the original piping in these locations typically has weak or no
easement protection. Proving the existing customer was responsible for the cause
of the overbuild can be difficult and sometimes impossible. Avista has experienced
in the past that attempts to force customer to pay for these modifications are
difficult and often legal fees approach the cost of the work. Legal actions often
take an extensive time and resource commitment. Additionally the negative public
relations associated with such a philosophy would be very difficult to overcome.
This option is not recommended.
Business Case Justification Narrative Page 3 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 199 of 325
Gas Overbuilt Pipe Replacement Program, ER 3006
D¡str¡ct l-S¡tè tv Estimated CoF zottF zors lì zors F zozo[-zozr l-
2015 D|MP
score/ft f.
Totel s 504.000 $462.s00
CDA 900 ldaho St, space 304 s 5,000 s s.000 24r'5
Kelloss I Various Serv¡ces s 20.000 s 20.000 ?
Medford 555 Freeman Rd, Central Point OR s 4s0.00c s4s0,000 1930
Medford 301 Freeman Rd. Central PointOR s 28s.00c s28s.000 4145
Medford 1055 N sth St. Jacksonville OR s 380.00c s 200.000 s280.000 3M2
Medford Z2521able Rock, Medford OR s 32s.00c s32s,000 3485
Medford 2335 Table Rock. Medford OR s 135,00C S13s.ooo 2894
Medford 3555 S Pacific. Medford OR s 480.O0C 2021+1400
Medford 4425 W Main St, Medford OR s 1s.00c s 1s.000 777
Roseburg Drifter's Looo s 67.000 s 67.000 2958
Roseburs Main St ------MHP Winston S 7s,soo s 7s.s00 2853
Roseburg 272INE Steohens MHP. Roseburs OR S 4s,ooo S 4s,ooo 1616
LaGrande Stonewood Ph. 3, La Grande OR s 100.ooo s150.000 1936
Klamath Falls Bartlett Mobile Park, K Falls OR s 14.000 s 14.000 4764
Klamath Falls Villa West n//'HP 2247 GreensDrings s 10,000 s 10.000 1988
Klamath Falls
6800 S. 6th Street. - Wisemans Mobile
Home Park s 25.000 s 2s.000 3845
Klamath Falls
5602 Denver Ave. - Woodland Mobile
Home Park s 30.000 s 30.000 2827
lmage 1 - List of known projects within this program
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Overbuilt Pipe
Replacement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
J b
Manager Gas Engineering
Date: 7-t7-t 7
Date ql rrl rl
Business Case Owner
rlMikeberry
Director of Natural Gas
Business Case Sponsor
Business Case Justification Narrative Page 4 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 200 of 325
Gas Overbuilt Pipe Replacement Program, ER 3006
5 VERSION HISTORY
Template Vercion: 0212412017
1.0 Seth Samsell 04t17t2017 Jeff Webb 04t17t2017 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 201 of 325
Gas PMC Program, ER 3055
I GENERAL INFORMATION
Requested Spend Amount $1,200,000
Req uesting Organ ization/Department 851 - Gas Engineering
Business Case Owner Jeff Webb
Business Gase Sponsor Mike Faulkenberry
Sponsor Organization/Department B51 - Gas Engineering
Gategory Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Gas Engineering, Gas Operations, Gas Meter Shop, and Technical Services work
together to administer the Gas Planned Meter Change-out (PMC) program and
ensure compliance with the various state rules and tariffs related to gas meter
testing. Gas Engineering is ultimately responsible for the PMC plan and annual
reports that are submitted to each of the state commissions. Gas Operations and
the Gas Meter Shop remove the meters from the customer's premise and install
new ones. The Gas Meter Shop completes physical calibration tests on the meters,
and the Technical Services group then analyzes the test results at the end of the
year to determine the status of each family of gas meters.
2 BUSINESS PROBLEM
Avista is required by commission rules and tariffs in WA, lD, and OR to test meters
for accuracy and ensure proper metering performance. Execution of this program
on an annual basis ensures the continuation of reliable gas measurement and
compliance with the applicable tariffs.
The following State Rules regulate Avista's PMC Program:
Oregon:
o OAC 860-023-0015 "Testing Gas and Electric Meters"
o Tariff Rule #18
ldaho:
o IDAPA 31 .31 .01 .151 through .157 "Standards for Service"
Washington:
o WAC Chapter 480-90-333 through -348 "Gas companies - Operations"
o Tariff Rule #170
Avista's statistical sampling methodology is based on ANSI 21.9 "Sampling
Procedures and Tables for lnspection by Variables for Percent Nonconforming".
Sample sizes and acceptance criteria are defined in the ANSI standard.
Annually the test results of gas meters that have been removed from the field are
analyzed and a determination of the accuracy of each meter family is made. lf the
analytics determine a meter family (defined as a manufacturer year and
model/size) is no longer metering accurately enough to meet the tariff, then that
Business Case Justification Narrative Page 1 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 202 of 325
Gas PMC Program, ER 3055
entire meter family will be replaced. Conversely, if the analytics determine a meter
family is testing well (close to 100% accurate), the sample size (number of meters
in that family required to be tested) can be reduced. These analytics help lower
costs and also remove meters quickly that are not performing well.
This program includes only the labor and minor materials associated with the PMC
Program. Major materials (meters, pressure regulators, and Encoder Receiver
Transmitter (ERT)) will be charged to the appropriate Gas Growth Programs.
This program assures that our customers' natural gas use is measured accurately.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapltal Gost Stârt Completo
Optionl-Donothing $0
Option 2 - Preferred Solution,
Complete programmatic work as
described
$1,200,000 January December
Option 1 - Do nothing/defer project
lf this program were not completed fully and accurately, Avista would be out of
compliance with state tariffs and could be exposed to fines from the various state
utility commissions. Also, the accuracy of measurement of our customers' natural
gas usage could not be assured.
Option 2 - Preferred Solution, Complete the programmatic work at the current
funding level
Completion of this program will keep Avista in compliance with State Rules and
Tariffs and assure that our customers' natural gas use is measured accurately.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas PMC Business Case
and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Date: /-rZ-r Z
Webb
Manager Gas Engineering
Business Case Justiflcation Narrative
Business Case Owner
Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 203 of 325
Gas PMC ER 3055,
Signature:
Print Name:
Title:
Role:
Date: .-l /rr I tffrke
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 021241201 7
lken rry
[Veælon#
lmplernented
BY
Revlslon
Dale
Approved
BY
Approval
Date
Rsaoon
1.0 Jeff Webb 04t1612017 Mike
Faulkenberry
04t17t2017 lnitialVersion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 204 of 325
Gas Replacement Súreeú and Highway Program, ER 3003
Requested Spend Amount $3,000,000
Req uesting Organ ization/Department 851 - Gas Engineering
Business Case Owner Jeff Webb
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Gategory Program
Driver Mandatory & Compliance
I GENERAL INFORMATION
1.1 Steering Gommittee or Advisory Group lnformation
Gas Operations manages this category of work. The work is generated by the
various municipalities that Avista has franchise agreements in. The overall
program budget is managed by Gas Engineering.
2 BUSINESS PROBLEM
It is very difficult to forecast year-to-year what the cost in this category will be.
Virtually all of Avista's pipelines are located in public utility easements (PUEs)
which are controlled by localjurisdictionalfranchise agreements. Avista is
mandated under these agreements to relocate its facilities, when local
jurisdictional projects necessitate. Often these come without significant lead time
by the localjurisdictions. lt is often the case that meetings are called in the Spring
to notify franchisees (natural gas, electric, cable, phone etc.) that they will need to
relocate their facilities. This does not enable ideal planning and often may cause
Avista to spend unbudgeted funds and do so in a manner that is not of the utmost
efficiency.
When conflicts are identified that may require relocating gas facilities, meetings
with the appropriate entities take place in an attempt to design around the conflict.
lf relocation of gas facilities are required, then Avista must relocate the gas facility
at our cost per the applicable franchise agreement. lf the relocation project is of
significant complexity, then Gas Engineering will take over the project to design
and manage it through completion.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapltal Gost Start Gomplote
Optionl-Donothing $ TBD
Option 2 - Preferred Solution, Complete
replacements as necessary
$3,000,000 January December
Business Case Justification Narrative Page 1 of 2
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 205 of 325
Gas Replacement Street and Highway Program, ER 3003
Optionl-Donothing
The nature of this work is considered "work in request of others". lf the conflicts
are not resolved through design changes or relocation of the gas facilities, Avista
would be in conflict with franchise agreements and could be charged with delay of
a project. This would not only be a financial burden on the company, but it would
also greatly damage the working relationship between Avista and the municipality.
Option 2 - Preferred Solution, Complete the replacements as necessary
By completing the projects as requested, then Avista meets the obligations under
its franchise agreements, remains in good standing with the municipalities, and
avoids financial penalties.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Replacement Street
and Highway Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
flltt Date: ?z 7-¿ 7
Date: qìplflrl
- T&íwebb
Manager Gas Engineering
Business Case Owner
Mike
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Tem pf ate Version : 03107 12017
)
?r lkenbeff
Verclon lmplemented
By
Revlslon
Date
Approved
By
Approval
Date
Reason
1.0 Jeff Webb 04t1712017 Mike
Faulkenberry
04t17t2017 lnitialversion
Business Case Justification Narrative Page 2 of 2
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 206 of 325
Gas Reinforcement Program, ER 3000
I GENERAL INFORMATION
Requested Spend Amount $1,000,000
Requesting Organ ization/Department B51 - Gas Engineering
Business Case Owner Jeff Webb
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department B5l - Gas Engineering
Category Program
Driver Performance & Capacity
l.l Steering Committee or Advisory Group lnformation
The Gas Planning department routinely runs an analysis (load study) on Avista's
gas distribution system to identify areas of the system with insufficient capacity to
serve existing Firm customer loads on a design day (Avista defines design day as
the projected system demand for a "coldest day on record" weather event). These
deficient areas are given a priority level based on the severity of the risk
associated with insufficient system capacity. The areas with the highest priority are
selected for remediation and the project is assigned to Gas Engineering to
evaluate options to provide sufficient capacity to meet Firm gas demands on a
design day. Options are reviewed with Gas Planning, Gas Operations, and other
interested parties. The pros and cons of each option are then reviewed with the
Gas Engineering Manager and a preferred alternative is selected to proceed with a
funding request.
2 BUSINESS PROBLEM
This annual program will identify and provide for necessary capacity
reinforcements to the existing natural gas distribution system in WA, lD, and OR.
Avista has an obligation to serve existing Firm gas customers by providing
adequate capacity on design day conditions. Sufficient capacity is defined as
pressures at or above 15 pounds per square inch (psig) in the distribution system
on a design day analysis. Periodic reinforcement of the system is required to
reliably serve Firm customers due to increased demand at existing service
locations and new customers being added to the system. Execution of this
program on an annual basis will ensure the continuation of reliable gas service
that is of adequate pressure and capacity.
Typical projects completed under this Business Case may include (but are not
limited to) upsizing existing gas mains, looping existing gas mains (bringing in a
second source to an area), and installing new regulator stations (pressure
reduction stations). When a reinforcement is done by looping a system, there is a
secondary benefit of higher reliability to the area. Most of these projects will have a
unique project number assigned to them, but the lower cost projects may be
completed under the blanket project numbers set up for each district.
Business Case Justification Narrative Page 1 ol 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 207 of 325
Gas Reinforcement Program, ER 3000
Projects that are identified in this program are prioritized by a Gas Planning model,
see lmage I below for a list of high and medium priority projects. The prioritization
is based on the computer modelthat analyzes actual meter usage data from each
customer, extrapolates that data to predict a demand load at design temperature
conditions, and then analyzes each gas distribution system to determine if
reinforcements are necessary. lf system capacities are not sufficient the model
can also be used to determine the benefits of different types of reinforcement
projects by running "what if?" scenarios. Once the projects are identified, they are
risk ranked based on the number of customers affected and the temperature levels
at which the risks begin.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optionl-Donothing
Without a Reinforcement Program, Avista does not have sufficient capacity to
meet our obligation to serve existing Firm customer load on a design day scenario,
and is not able to support future customer growth.
It is important to note that if service is lost during severe cold weather, gas service
may not become available again until weather warms and customer demand
decreases. Depending on the length of the outage, this can cause severe injury up
to and including death to some customers.
Option 2 - Preferred Solution, Complete with fullfunding
lf funding continues as requested, the high priority by projects are scheduled to be
completed in 2018 and the medium priority projects by 2021. The low priority
projects will take approximately three more years to complete after that. At that
point, the backlog of projects will be completed and funding can be reduced
substantially, but not completely as reinforcements will always be needed as new
customers are added.
Option 3 - Altemative Solution, Complete with reduced funding level
lf funding is reduced, then the timeline to complete the projects and the risks of
outages extends proportionally. The more winters we keep our system below
capacity, the higher likelihood of have a cold weather event that could cause
outages.
Optlon Gapltal Cost gtert Gomplete
Optionl-Donothing $o
Option 2 - Preferred Solution, Complete with full
funding
$1,000,000 January December
Option 3 - Alternative Solution, Complete with
reduced funding level
$500,000 January December
Business Case Justification Narrative Page 2 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 208 of 325
Gas Reinforcement Program, ER 3000
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813 Proposed Frontst, and spokane Falls Blv. Mein Upgrade Spokane
16874 Proposed HP Connûdon æawæn Lo G¡ondeønd llnton (2tGustomg,|s) La Grande
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408 Proposed Loomis and Railroad (lcustomer) StJohn
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32102 Replacement ADLReplacementforGenesee (323Customers) Genesee
2306 Replacement ADL Replacement for Genesee (323 Customers) Genesee
2190 Replacement ADLReplacementforGenesee (323Customers) Genesee
3688 Replacement ADL Replacement for Genesee (323 Customers) Genesee
10893 Proposed Myrtle Creek4" Replacement(938Customers) Myrtle Creek
2557 Replacement ADL Replacement for Genesee (323 Customers) Genesee
202 New <Null> Medford
294 New Medford East 6 ps¡g System Medford
2¿10 New Medford East6psigsystem Medford
14224 Replacement Jacksonv¡lle Main Replacement Jacksonville
3853 Replacement Winston Main Replacement Winston
20412 Replacement Klamath Ma¡n Replacement Klamath Falls
610 Proposed lntersection of Lenter and Lathen Moscow
4152 Replacement.o" Main Replacement Moscow
9418 Replacement South Hill Spokane
143 Proposed Near33rd and Lincoln Spokane
224 Proposed Neer 34th and Perry Spokane
363 Proposed 9th and Eastern Spokene
80 Proposed Kahuna and Carnahan Spokane
1114 Proposed 14th and Eastern Spokane
236 Proposed 6th and Havana Spokane
85 New REGUIATORSTATION.WestMedford6psigsystem Medford
3073 Replacement Palouse 2" Ma¡n Replecemen¡ Palouse
564 Proposed 23rd St. Loop Connection Lewiston
1582 Proposed Empire Center Rd. Main Connection Post Falls
6687 Proposed HP Sdtwelaé}. Mountdn nd, þ þyet HP f,rtendon Uncøttot?etsJ Sandpoint
889 Replacement Frontst. and Spokane Falls Blv. Main Upgrade Spokane
578 Proposed Port and North St. Connection (139 customers) Clarkston
5080 Proposed Lakeshore and Sagle Rd. Development Main Extention Sagle
7072 Proposed Lakeshore and Sagle Rd. Development Main Extention Sagle
2067 Replacemant HPvilvgf'Rd,Upgmde(ncusþmeß) Rouge River
2032 Replacement HPfith$f-upgrøde2 Gold Hill
11 Proposed Douglas and Main St, Connection Roseburg
127 Proposed State Rd. Main Extension (188customers) Sutherlin
301 Proposed State Rd. Main Extens¡on (188customers) Sutherlin
409 Proposed State Rd. Main Extension (188customers) Sutherlin
152 Proposed Umpque Main Connection (188 customers) Sutherlin
155 Proposed Central Rd. Crossing(l88customers) Sutherlin
213 Proposed Mardonna and Second st. (188 customers) Sutherlln
161 Proposed Third St. Ma¡n Connection (188 customers) Sutherlin
341 Proposed Grove Rd. Main Extension (188customers) Sutherlin
349 Replacement 6th St. Main Connection (188customers) Sutherlin
49¿E Proposed Hawthorne to Central St. Main Connection (188 customers) Sutherlin
sg0'Replacement HPttthst"ltpüødef Gold Hill
1272 Replacemenl HPlÉw¡sþnwãtooæDownsúeomurymde Lewiston
428 Replacement HPNtsIHPUpüode Lewiston
21632 Replacement ADL Replacement for Endicott Rd. (384 customers) colfax
5255 Proposed HPPhaseltldøhoønd&rcokle Rethdrum
lT3lReplacement ch¡lcoRdandoldHWY95(lcustomer) Chilco,lD
19573 Proposed HPWoden Warden
16004 Proposed Aust¡n Rd and Monroe (56customers) Spokane
8113 Proposed HPPhaseltl Rathdrum
lmage 1 - Prioritized list of reinforcements
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Steel HP Medium
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Business Case Justification Narrative Page 3 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 209 of 325
Gas Reinforcement Program, ER 3000
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Reinforcement
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
f,l ü/il Date: (-t T-t 7
Date: U lì
/ ft"ff webb
Manager Gas Engineering
Business Case Owner
I
Mike
Director Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Template Version: 03107 12017
Verclon lmplemented
BY
Revlslon
Date
Approved
By
Approval
Date
Reaeon
1.0 Jeff Webb 04t17t2017 Mike
Faulkenberry
04t17t2017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 210 of 325
Gas Telemetry Program, ER 3117
Requested Spend Amount $200,000
Requesting Organ ization/Department 851 - Gas Engineering
Business Gase Owner Jeff Webb
Business Gase Sponsor Mike Faulkenberry
Sponsor Organization/Department Gas Operations & Engineering
Category Program
Driver Performance & Capacity
I GENERAL INFORMATION
l.l Steering Committee or Advisory Group lnformation
The Gas Measurement Engineer works with the Gas Telemetry Technicians, Gas
Planning, Gas Engineer¡ng, Metering Automation, Gas Operations, Gas Control
Room, Supervisory Control and Data Acquisition (SCADA), and Gas Supply
groups to determine possible projects or locations for new telemetry sites or
upgrades of existing equipment. The Gas Engineering Manager reviews the
recommendations from the Gas Measurement Engineer and approves the specific
projects within this program. A five year plan is also created by the Gas
Measurement Engineer and approved by the Gas Engineering Manager.
2 BUSINESS PROBLEM
This program will continue the installations of gas telemetry throughout Avista's
gas service territory. Gas telemetry is used to remotely monitor system pressures,
volumes, and flows from areas of special interest such as Gate Stations (supply
point into Avista's system), gas transportation customers, Regulator Stations
(pressure reductions stations), selected large industrial customers, and distribution
systems with more than one source of gas.
Further enhancing the telemetry sites will increase the visibility the Gas Control
Room and Gas Operations has of the gas system to help analyze operational
concerns and monitor cold weather performance. Alarm points can be set in the
telemetry devices to alert the Gas Control Room of any abnormal operating
condition.
Additionally, data from these telemetry sites is used to validate the system
modeling tool (load study) that Gas Planning creates every year. Since the data
collected is electronic, it can be represented graphically to quickly analyze any
anomalies.
The Gas Supply department benefits from these projects by having metering data
at Gate Stations that is independent of the interstate pipeline's metering (suppliers
of gas to Avista). This makes it easy to find calculation or metering errors at the
Gate Stations. Billing errors left unfound can create problems that lead to extra
work and manual corrections between Avista and the interstate pipelines.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 211 of 325
Gas Telemetry Program, ER 3117
The customers and general public benefit from Avista having good "visibility" to the
gas transmission and distribution system. This allows for a quicker response and
better decision making from the Gas Control Room and Gas Operations when an
abnormal or emergency situation occurs. For example, we are quickly notified
electronically of low pressure situations that if not addressed in a timely manner
could result in significant loss of gas service to our customers. lf there were no
telemetry, Avista would have to wait for customers to call in after they've lost gas
service which at that point would have a significant impact to our customers and
require substantial time and manpower to restore service.
Avista strives to replace equipment that has reached the end of its service life with
new equipment that makes use of current technology. We also review existing
installations for opportunities to improve reliability, acquire more data, or more
efficient ways of collecting the data.
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltal Gost $tart ComBlsts
Optionl-Donothing $o N/A
Option 2 - Preferred Solution, Replace/install
telemetry at the current funding level
$200,000 January December
Optíon1-Donothing
To make no further additions to Avista's telemetry system would result in less
capability to see "real time" performance of the gas system, inability to see
operational abnormalities in a timely fashion, subject our customer to increased
chances of low or high pressure situations and their related safety risks, and the
reliability of the existing system would decline due to equipment failures.
Option 2 - Preferred Solution, Replace/install telemetry at the current funding level
At the current funding level, Avista adds approximately 5 new sites and upgrades
approximately 15 sites per year. This allows the high priority sites to be addressed
as the need arises or equipment fails.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Telemetry Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 212 of 325
Gas Telemetry Program, ER 3117
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
f,/l /]//Date: 7tl-r I
Date 4lrrlrl
Á{lf vi.øø
Manager Gas Engineering
Business Case Owner
Mike
Director of Natural as
rl
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 0212412017
[Verclonf lmplemented
By
Revislon
Date
Approved
By
Approval
Dats
ReaEon
1.0 Jeff Webb 04t17t2017 Mike
Faulkenberry
04t1712017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 213 of 325
Gas Schweitzer Mtn Rd HP Reinforcement, ER 3310
Requested Spend Amount $1,500,000 (2018)
Requesting Organ ization/Department 851 - Gas Engineering
Business Gase Owner Jeff Webb
Business Gase Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Category Project
Driver Performance & Capacity
1 GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
The Gas Planning department routinely runs an analysis on Avista's gas
distribution system to identify areas of the system with insufficient capacity to
serve firm customer's loads on a design day. (Avista defines design day as the
projected system demand for a "coldest day on record" weather event). These
deficient areas are given a priority level based on the severity of the risk
associated with insufficient system capacity. The areas with the highest priority are
selected for remediation and the project is assigned to Gas Engineering to
evaluate options to provide sufficient capacity to meet firm gas demands on a
design day. Options are reviewed with Gas Planning, Gas Operations, and other
interested parties. The pros and cons of each options are then reviewed with the
Gas Engineering Manager and a preferred alternative selected to proceed with a
funding request.
2 BUSINESS PROBLEM
Based on load studies performed by Gas Planning, load growth in the Sandpoint
ldaho area has exceeded the capacity of the existing gas distribution system.
Adequate capacity is defined as system pressures at or above 15 pounds per
square inch (psig) in the distribution system and 90 psig in the high pressure
supply lines on a design day analysis. Without a reinforcement project, Avista will
not have sufficient capacity to serve firm customer load in the Sandpoint area on a
design day scenario.
It is proposed to install approximately 1.3 miles of 6" steel gas main on Schweitzer
Mtn Rd to reinforce the distribution system of Sandpoint, lD.
Need for the Project: Currently, the NE part of Sandpoint is predicted to have
capacity constraints on a design day. As part of our obligation to serve firm
customers, this reinforcement is necessary to ensure the system capacity and
resultant pressures are adequate. This project will also add an additional regulator
station to the area to increase reliability.
Business Case Justification Narrative Page 1 of3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 214 of 325
Gas Schwettzer Mtn Rd HP Reinforcement, ER 3310
3 PROPOSAL AND RECOMMENDED SOLUTION
Space heating is the most predominate use of gas for Avista's firm customers.
Should a gas outage occur during a cold weather event due to insufficient capacity
of a distribution system, there would be a high level of risk associated with the
health and safety of the individuals, and the potential damage to the buildings due
to freezing water pipes. Completion of this reinforcement project greatly reduces
this risk.
Since this area has insufficient capacity to serve firm customers on a design day, a
cold weather action plan has been developed. This plan outlines particular
activities that could be implemented such as the manual on-sight monitoring of
system pressures, a media blast to request a temporary thermostat turndown,
taking extraordinary measures to manually improve the capacity of the system by
bypassing regulator stations or manually shedding load (shutting off customers
completely), and/or preparing relight lists (to restore service to customers who
have lost gas service).
Avista has determined it is not appropriate to rely upon a cold weather action plan
for the safe and reliable operation of the natural gas distribution system. These are
stop gap measures put in place because of a known capacity deficiency until a
permanent reinforcement project can be completed. Operating in this mode
requires Avista employees to work outdoors in extremely cold situations, which
results in increased operations and maintenance expense (O&M expense) due to
overtime pay and increased safety risks to our employees performing the manual
intervention (i.e., working outdoors and driving vehicles in cold, snowy, and icy
conditions). Additionally, these activities are last-ditch efforts to maintain service,
and they do not represent a guarantee that service will be able to be maintained to
customers paying a firm gas rate.
Additional efforts will be spent in 2017 to determine alternate piping solutions and
determine the best option for construction in 2018.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Schweitzer Mtn Rd HP
Reinforcement Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Optlon Gapltal Goet $tart Gomplete
Do nothing, Cold Wx Action Plan $o
Proceed as described above $1,500,000 01 2018 122018
ITBD $??01 2018 122018
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 215 of 325
Gas Schweitzer Mtn Rd HP Reinforcement, ER 3310
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Date: 7-t 7-t 7
Date: qfrrlrr
Webb
Manager Gas Engineering
rlMike
Director of Natural Gas
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version: 03107 12017
Verclon lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1.0 Jeff Webb 04t17t2017 Mike
Faulkenberry
04t17t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 216 of 325
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
1 GENERAL ¡NFORMATION
Requested Spend Amount $10,000,000
Req uesting Organ ization/Department Gas Engineering
Business Gase Owner Jeff Webb, David Smith
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Category Project
Driver Performance & Capacity
l.l Steering Committee or Advisory Group lnformation
The Gas Planning department routinely runs an analysis (load study) on Avista's
gas distribution system to identify areas of the system with insufficient capacity to
serve existing Firm customer loads on a design day (Avista defines design day as
the projected system demand for a "coldest day on record" weather event). These
deficient areas are given a priority level based on the severity of the risk
associated with insufficient system capacity. The areas with the highest priority are
selected for remediation and the project is assigned to Gas Engineering to
evaluate options to provide sufficient capacity to meet Firm gas demands on a
design day. Options are reviewed with Gas Planning, Gas Operations, and other
interested parties. The pros and cons of each option are then reviewed with the
Gas Engineering Manager and a preferred alternative is selected to proceed with a
funding request.
2 BUSINESS PROBLEM
Based on load studies performed by the Gas Planning department, load growth on
the Williams Northwest Pipeline (NWP) Coeur d'Alene Lateral pipeline has
exceeded both Avista's contractual delivery amounts as well as the physical
capacity of the NWP Coeur d'Alene Lateral pipeline. ln addition, the distribution
system in the Hayden Lake, ldaho area will experience insufficient pressure during
periods of peak demand on a design day. Sufficient capacity is defined as
pressures at or above 15 pounds per square inch (psig) in the distribution system
on a design day analysis. Without a reinforcement project, Avista will not have
sufficient capacity to serve Firm customer load in the Coeur d'Alene, lD to Kellogg,
lD corridor on a design day scenario.
Business Case Justification Narrative Page I ofS
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 217 of 325
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltel
Coet
Start Gomplete
Optionl-Donothing $0
Option 2 - Preferred Solution, Avista to
construct approximately six miles of high
pressure distribution pipeline in two
phases to reinforce the distribution
system in the greater Post Falls and
Coeur d'Alene area.
$10,000,000 11t2015 12t2018
Option 3 - Alternative Solution,
Compensate Williams Northwest Pipeline
(NWP) for a mainline expansion of their
Coeur d'Alene Lateral pipeline.
$10,000,000 11t2015 12t2019
Optionl-Donothing
Without a reinforcement project Avista does not have sufficient capacity to serve
existing Firm customer load in the Coeur d'Alene, lD to Kellogg, lD corridor on a
design day scenario, and cannot support any future customer grov,rth. See lmage
1 below for a load study analysis showing the Hayden Lake area distribution
system with insufficient capacity. Approximately 3900 customers are at risk of
losing their gas service during a cold weather event.
It is important to note that if service is lost during severe cold weather, gas service
may not become available again until weather warms and customer demand
decreases. Depending on the length of the outage, this can cause severe injury up
to and including death to some customers.
Option 2 - Preferred Solution, Avista to construct approximately six miles of high
pressure distribution pipeline in two phases to reinforce the distribution system in
the greater Post Falls and Coeur d'Alene area.
This option capitalizes on the capacity available from the recently constructed
Chase Road Gate Station (supply point into Avista's system) located on the GTN-
TransCanada (GTN) pipeline. This option consists of a multi-year project
comprised of a two phase high pressure distribution pipeline reinforcement that will
shift gas usage from NWP to GTN, and will also allow Avista to choose a portion of
gas nominations from either NWP or GTN to take advantage of price differentials.
This additional capacity will be used to support customer grovuth in the Post Falls,
lD and Coeur d'Alene, lD area currently served from NWP. This option also
inherently increases system reliability by having two independent interstate
pipeline gas sources, which will reduce the risk of customer outages in the event
of an abnormal operating condition. Another benefit of this option is that it will be
completed approximately one year before Option 3, which will accommodate the
existing needs and support additional customer grovrrth sooner. Phase one and
phase two both consist of installing approximately three miles of 6" high pressure
distribution pipeline and two Regulator Stations (pressure reductions stations)
within Avista's system, with phase one scheduled to be constructed in 2017 and
Business Case Justification Narrative Page 2 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 218 of 325
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
phase two constructed in 2018. See lmage 2 below for a load study analysis
showing how the proposed reinforcement provides sufficient capacity to the
Hayden Lake, lD area distribution system.
Option 3 - Alternative Solution, Compensate Williams Northwest Pipeline (NWP)
for a mainline expansion of their Coeur d'Alene Lateral pipeline.
The NWP expansion would include the installation of up to 6 miles of 10" pipe
beginning at or near the WA/lD border (west of Post Falls, lD), which involves
investing significant money into the Williams NWP system instead of Avista's
infrastructure. Additionally, Avista would be required to refurbish and expand at
least four Gate Stations (NWP supply point into Avista's system) along the NWP
Coeur d'Alene Lateral to accommodate the projected load growth. This option is
estimated to take 4 years to complete, which does not provide a timely
reinforcement to the deficient Hayden Lake area, nor does it offer timely support of
continued customer growth. Another disadvantage of this option is that Avista
would not gain the ability to have two independent interstate pipeline gas sources
into one of the largest load centers in our system, which would reduce system
reliability in the event of an abnormal operating condition.
lmage 1 - Distribution System Pressures before Proposed Reinforcement
Pressure lpBl8lI o.ooI o,or-rs.æ
E u.or -¡0.æI so.or-as.oo
I as.or-æ.æ
) flt0l
By:
Business Case Justification Narrative Page 3 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 219 of 325
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
FscllltlèscolotSy:
Pressure(p3lg)E o.ooI o,or-rs.ofl rs.or -¡o.ooI ¡o.or-¡s,æI ¡s.or -eo.æI reaor
Ratlrd rr¡m
Hayderr Lake
Post Falls
Coeur d'Alene
o
o
o
o
oO
After H.P. Reinforcements &
Regu lators
lmage 2 - Distribution System Pressures after Proposed Reinforcement
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Rathdrum Prairie HP
Reinforcement Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
ú/t üil Date: L¡ -r 7-r 7
Date: c'-{lrf Iff
/té#w"oø
Manager Gas Engineering
Business Case Owner
rlMike F
Director of Natural Gas
berry
Business Case Justification Narrative
Business Case Sponsor
Page 4 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 220 of 325
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
5 VERSION HISTORY
Tempfate Vercion: 02124120'17
1.0 Dave Smith 4t17t2017 lnitialversion
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 221 of 325
Campus Repurposing Phase 1
I GENERAL INFORMATION
Requested Spend Amount $24,400,000
Requesting Organization/Department Facilities
Business Case Owner Eric BowlesA/ance Ruppert, Facilities
Business Gase Sponsor Anna Scarlett, Manager, Shared Services
Sponsor Organization/Department Shared Services
Gategory Project
Driver Performance & Capacity and Asset Condition
1.1 Steering Gommittee or Advisory Group lnformation
The Campus Repurposing Phase 1 Steering Committee is made up of a cross
section of directors that represent groups impacted by the projects, as well as
members not directly affected to add an outside view. The current group is as
follows:
o Director of Environmental Affairso Director of Shared Serviceso Director of lT and Security' . Director of Natural Gaso Director of Financial Planning and Analysiso Director of Operations
Advisors may contribute input, approvals, or information as needed, and include:
o Vice President of Energy Deliveryo Executive Officers. End Users
Each project within this business case is reviewed and approved by the Steering
Committee group, and regular updates are provided during project execution.
2 BUSINESS PROBLEM
The Campus Re-Purposing Plan, Phase 1 is a multiyear plan that address the
following issues:
. Employee space needs. lmproving safety and efficiency of campus traffic flow. Outdated warehouse / stores space and processeso Outdated Hazardous waste & materials space and processeso Outdated transformer oil recovery space and processes. Outdated investment recovery space and processes. Lack of materials storage yards, no short-term flexibility. Alignment of campus parking and number of employees based at main
campus
Business Case Justification Narrative Page 1 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 222 of 325
Campus Repu osing Phase I
The Avista corporate campus comprises 28 acres located next to the Spokane River
in heart of the Logan Neighborhood. The campus is just north of the downtown
conidor.
Avista's corporate campus footprint is currently bound to the east by the Spokane
River, and to the west and south by the Mission Park and Burlington Northern
Railroad, leaving minimal flexibility to manage company parking, employee and
materials space needs.
The Avista corporate campus was built in 1958 to consolidate and house all utility
operations that were at that time spread throughout the community. As business
needs changed over time, one-off expansion projects were initiated to reactively
address changes in business need. Employee growth and materials storage
increases through the years have created the need to locate employees and
materials at offsite locations, requiring space leases and other non-optimal solutions
to meet growing company space needs.
The decision was made in 2011 to take a holistic approach to these issues and
create a single proposed solution for the Corporate Campus that would address
current issues, and future needs. The campus repurposing planning group began
working in 2011 to find a way to address the growing employee space needs,
parking issues, campus materials storage issues, safety and traffic flow issues
Business Case Justification Narrative Page 2 oÍ '14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 223 of 325
Campus Repurposing Phase I
(Operations traffic and employee traffic mixing), as well as look into addressing the
changing business needs of our vehicle fleet and operational processes.
The result of this approach is a total campus plan that repurposes the existing
campus for the next 50 years, minimizing our reactive approach and ensuring the
best long term results for the Company and Ratepayers.
3. PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapital Goet Start Complete
Option 1 (Recommended) - Perform 9
strategically designed projects to
optimize corporate campus
workflows.
$24,400,000 Jan2O11 April2017
Option 2 - Purchase alternate sites
elsewhere for various needs.
up to -400,000,000 nla nla
Option3-Donothing $1M - $3M yearly (Capital
and O&M misc. costs -
approx.)
nla nla
OPTION 1 - PERFORM THE FOLLOWNG NINE MAJOR PROJECTS:
1. Construct new Warehouse Building & new 120 stall parking lot
2. Remodel old Warehouse space in Service Building to office
3. Construct new Waste & Asset Recovery Building
4. Build new Generation, Production, and Substation Support (GPSS) Storage
Building at Beacon Storage Yard
5. Expand outdoorWarehouse storage yard, Phase 1
6. Remodel existing canopy for new lnvestment Recovery
7. Remodel Spokane Construction office area in Service Building
8. Remodel GPSS office area in Service Building
9. Expand outdoor Warehouse storage yard, Phase 2
These nine projects are sequential and are largely dependent on each other
because of location, timing and the overall campus design. The projects will
ultimately allow us to:
o Modernize the aged warehouse space within the service building.. Expand and locate campus parking to align the available number of parking
spaces with the number of employees working onsite, improving employee
and public safety by reducing parking sprawl.. Separate operations traffic from pedestrian traffic to improve safety and
i ncrease workflow efficiencies.o Provide office space options for future Avista employee grovuth.
Descriptions of each project are discussed on the pages to follow
Business Case Justification Narrative Page 3 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 224 of 325
Campus Repu ng Phase 1
Business Case Justification Narrative Page 4 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 225 of 325
Campøs Rep urposing Phase 1
Proiect l: New e Buildinq & Parkinq Lot
The new warehouse building and parking lot expansion was completed in 2013. lts
location was determined due to its need to be adjacent to our line truck crews for
easy staging. The new building created vertical shelving efficiencies with a 3O-foot
height, whereas in its previous space in the service building, it was only 14 feet
high. The customer benefits for this facility include better response time and
reliability due to enhanced and efficient storage and material handling of all
products currently within the Avista electric and gas field infrastructure. Upon
completion, this project has provided both quantifiable and non-quantifiable
benefits in employee and delivery efficiency, storage needs and energy use.
Business Case Justification Narrative Page 5 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 226 of 325
Campus Repurposing Phase 1
Proiect 2: Service Buildinq tion into Office Soace
The Service Building Renovation was completed in 2014.lt remodeled what was
formerly the Warehouse space into administrative office space, with the ability to
seat approximately 100 employees. lt also created new restrooms, a new
mailroom/graphics space, several conference rooms, and a break area. The
customer benefits for this remodel includes lower cost and increased efficiency
due to allowing Avista administrative functions to remain consolidated on one
campus, rather than being scattered amongst multiple buildings around the
region.
Business Case Justification Narrative Page 6 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 227 of 325
Campus Repu ng Phase I
Proiect 3: Waste & Asset Recoverv Buildins
The Waste & Asset Recovery Building was completed in 2015.lt consolidated
Avista's hazardous waste / materials collection and the transformer oil recovery /
collection functions into one building. Both processes were previously performed
in buildings approx. 25 years old. These older buildings followed all state and
federally mandated environmental regulations, but the new facility will allow for a
much more efficient and streamlined process to continue meet these standards.
All waste and transformers collected by our Avista field crews are processed in
the new building. This includes Avista crews not only local to Spokane, but also
all other satellite service centers, who ship their waste and transformers back to
this new building. The customer benefits for this building includes enhanced
safety for our customers by eliminating PCB oil containing transformers, and
overall reduction of hazardous products and contaminants throughout the
customer service territory. Upon completion, this project has provided further
quantifiable and non-quantifiable benefits in employee and delivery efficiencies
and building energy usage reductions.
Business Case Justification Narrative PageT of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 228 of 325
Campus Repurposing Phase I
Proiects 4 and 5: GPSS Storaqe Buildinq and Warehouse Storaqe Yard
Expansion #l
The Avista Generation, Production and Substation Support (GPSS) storage
building was completed in 2015.It relocated an existing storage building at the
corporate campus to make way for the Warehouse Yard Expansion #1. lt was
built at our Beacon storage yard, approximately two miles east of the corporate
campus.
The Warehouse Yard Expansion #1 project was completed in 2015.lt increased
the size of our current warehouse exterior storage yard and consolidated many
materials and equipment that were previously stored in inconvenient, inefficient
"pockets" on the corporate campus. As part of the project, a new storm water
treatment swale was also installed to divert all rainwater that could be
contaminated by oils and mastics inherent in asphalt paving. The swale was
appropriately sized for additional asphalt paving for future projects. The customer
benefits for this facility include better response time and reliability due to
enhanced and efficient storage and material handling of products currently within
the Avista electric and gas field infrastructure. Further benefits include public
safety with the storm water swale preventing possible contaminants from
leeching into the Spokane River. Upon completion, this project has provided
annual estimated cost savings of approximately $19,000 in employee efficiency.
Business Case Justification Narrative Page 8 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 229 of 325
Campus Repurposing Phase I
Proiect 6: New lnvestment Recoverv Buildinq
The new lnvestment Recovery (lR) building was completed in 2016. lt created a
new home for our recycling crews that deconstruct, sort, and catalog all
applicable Avista components that field crews bring back from their daily work
orders. This includes Avista crews not only local to Spokane, but also all other
satellite service centers, who ship their recyclable materials back to this new
building. Previously, lR was housed in a building approximately 25 years old. The
customer benefits for this facility include better reliability and lower cost of service
due to enhanced and efficient material handling of recyclable products currently
within the Avista electric and gas field infrastructure. ln fact, if some products
pass inspection, they are re-stocked in the warehouse for future re-use, rather
than being diverted to a landfill. Upon completion, this project has provided
annual cost savings in employee and operational efficiencies, as well as non-
quantifiable safety benefits, below:
o Warehouse employees on forklifts will no longer need to cross N. North
Center to get materials from storage yard across the street.o Since crew trucks will no longer need to enter gate 5, drop off at lR, exit
gate 6, go back out on N. North Center, and re-enter gate 5, the potential
for costly accidents on N. North Center will reduce.o lR crews will no longer work in the main service truck travel path, reducing
the risk for a costly accident.
Business Case Justification Narrative Page 9 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 230 of 325
Campus Repurposing Phase I
Proiects 7 and 8: Spokane Gonstruction and GPSS Office Remodels
The Spokane Construction and Avista Generation, Production and Substation
Support (GPSS) office remodels were completed in 2016. A denser cubicle
arrangement created new employee workspaces, and the existing 3O+-year-old
HVAC and electrical systems were replaced with newer, more efficient
equipment. The customer benefits for this remodel include increased efficiency
due to allowing administrative functions to remain consolidated on one campus,
rather than being scattered amongst multiple buildings around the region. Upon
completion, these projects provided quantifiable and non-quantifiable benefits in
additional space and facilities energy and maintenance savings.
Business Case Justification Narrative Page 10 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 231 of 325
Campus Repu osing Phase I
Proiect 9: Warehouse Storaqe Yard Expansion #2
The Warehouse Yard Expansion #2 project is schedule to complete in the first
half of 2017.lt will increase the size of our current warehouse exterior storage
yard and consolidate many materials and equipment that were previously stored
in inconvenient, inefficient "pockets" on the corporate campus. The customer
benefits for this facility include better response time and reliability due to
enhanced and efficient storage and material handling of products currently within
the Avista electric and gas field infrastructure. Upon completion, this project is
expected to provide quantifiable and non-quantifiable benefits in employee
efficiency warehouse storage.
OPTION 2 - PURCHASE ALTERNATE SITES ELSEWHERE FOR VARIOUS NEEDS
Due to the issues outlined in the "Business Problem," another possible option
would be to move some functions currently taking place at the corporate campus
and relocating them elsewhere, thus freeing up space. However, this would be
disadvantageous and create several possible risks.
Any new site purchased should be large enough to create another campus, so
that Avista facilities can be secured and maintained at one site. This would
require a lot possibly around 10 - 20 acres in size. As such, an available lot that
size would probably need to be procured outside of Spokane city limits, and
possibly in undeveloped county land. The capital costs to purchase a lot and
address basic infrastructure needs (paved street access, water, sewer, electric,
Business Case Justification Narrative Page11o114
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 232 of 325
Campus Repurp osing Phase 1
gas, etc.) could run into several million dollars. Any new facilities on the new site
would come at an additional cost, which could vary based on design. For the
projects mentioned in Option 1, it can be assumed that approximately the same
$25 million cost could be expected at the new site.
However, there would be strong internal resistance to this "alternate site" model
due to the fact that inefficiencies of work crews, deliveries, material handling,
drop-off's, etc. would be conducted at two different sites, with travel times for
crews unknown. In addition, there are definitive efficiencies with field crews being
adjacent to their administrative support employees. ln this option, all
administrative support employees would remain at the corporate campus.
However, to solve this, another option is if the ENTIRE corporate campus (field &
administrative functions) were to move to a new site. This would require a site of
at least 30-35 acres, and would require rebuilding ALL buildings and facilities that
are currently at the corporate campus. The cost estimate for this option, at a very
high level, would approach $400 million.
oPTtoN 3 -NOTHING
lf none of the projects outlined in Option 1 were started, then all of the issues outlined in
the "Business Needs" section would still need to be addressed over time. At a very high
level, the list below brainstorms possible ideas to accommodate the issues.
o Employee space needs. Renting office space, purchasing off-site offices?. Risks: Decreased adjacency efficiencies, rental or purchase market
costs, new maintenance at a new facility.
o lmproving safety and efficiency of campus traffic flowr Build new roads, pathways, fence and gate systems, and controlled
access points throughout the campus that would help separate these
trqffic patterns?. Risks: lncrease in accidents - vehicular, pedestrian, or other.
o Outdated warehouse / stores space and processes
o Outdated Hazardous waste & materials space and processes
o Outdated transformer oil recovery space and processes
o Outdated investment recovery space and processes
' For allfour above: no building changes, keep their spaces as-is. Year-
by-year increase in capital and maintenance costs to keep their spaces
as functional as possible.. Risks: Catastrophic failure of any one of these structures would require a
spike in capital or maintenance costs in any given year'
o Lack of materials storage yards, no short-term flexibility.. Materials would continue to be scattered around the corporate campus.
Eventually materials may need to be shipped and stored off-site at a
rented or purchased site.. Risks: Forklift traffic accidents crossing public streets. Material needed in
an outage may be off-site. Decreased efficiency due to off-site travel.
Business Case Justification Narrative Page 12 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 233 of 325
Campus Repu osing Phase 1
o Alignment of campus parking and number of employees based at main campus. Rental of office space or purchase of off-site offices would hopefully
include additional parking.. Purchase additional land off-site and develop into a parking lot. May
need to look at an "employee shuttle" situation at a one-off parking lot
since it may be too far away from the corporate campus.. Risks: Supply will continue to not meet demand. Employees may not use
parking options, may continue to park in adjacent residential
neighborhood. Additional maintenance costs of additional asphalt
parking lots.
Business Case Justiflcation Narrative Page 13 of l4
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 234 of 325
Campus Repurposing Phase I
APPROVAL AN D AUTHORIZATION
The undersigned acknowledge they have reviewed the Campus Repurposing
Phase 2 plan and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Section1.1. The
undersigned also that significant changes to this will be coordinated
with and approved unders or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Eric Bowles
Business Case Owner
Manager, Facilities
Date sltl,t
Date
Date: ¿1_?¿r_ 11
-l*- Su*1,*V, lrt
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory Com mittee Review
VERSION HISTORY
Tem pf ate Version : 021241201 7
Verelon lmplemented
By
Revlslon
Date
Approved
tsy
Approval
Date
Reason
1 Vance Ruppert 4t18t2017 Heather
Rosentrater
04t25t17 New template
Business Case Justification Narrative Page M of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 235 of 325
New Dollar Road Service Center
I GENERAL INFORMATION
Requested Spend Amount $24,000,000
Requesting Organ ization/Department Facilities
Business Gase Owner Eric Bowles / Vance Ruppert, Facilities
Business Case Sponsor Anna Scarlett, Manager, Shared Services
Sponsor Organization/Department Shared Services
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Steering Committee is made up of a cross section of directors that represent
groups impacted by the projects, as well as a couple members not directly affected
to add an outside view. The current group is as follows:
o Directorof EnvironmentalAffairso Director of Shared Serviceso Director of lT and Securityo Director of Natural Gaso Director of Financial Planning and Analysiso Director of Operations
The Advisory Group that assisted in shaping the "Business Problem and the
"Proposal and Recommended Solution" consisted of the following stakeholders:
. Gas Operations: Mike Faulkenberry, Tim Mair, Craig Buchanan, Seth Shaffer,
Jeff Webb, Fred Valentine. Previous stakeholders included David Howell and
John Schwendener.. Warehouse: Laurie Heagle, Gary Knight, Mike Cavallaro.o Fleet Maintenance: Greg Loew.o Facilities: Eric Bowles, Anna Scarlett, Vance Ruppert. Previous stakeholders
included Laura Vickers and Mike Broemeling.
Other advisors may contribute input, approvals, or information as needed, and
include:
. Vice President of Energy Deliveryo Executive Officers. End Users
Business Case Justification Narrative Page 1 of 1l
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 236 of 325
New Dollar Road Service Center
2 BUSINESS PROBLEM
The Dollar Road Service Center serves as the main gas operations facility for
approximately 300,000 customers within the greater Spokane area. Approximately
70 Avista field crew and administrative support employees are based out of the
site. This facility also supports our local gas crews in the Ritzville, Colville, and
Davenport regions to help serve an additional approximately 50,000 customers.
The existing Dollar Road Service Center was constructed in 1956, at a size of
approximately 22,000 square feet. Over the decades, previous capital projects
included asphalting exterior yards for gas pipe lay down and material and
equipment storage, as well as purchasing adjacent properties to increase our
storage acreage. ln the early 2010's, a vehicle storage and fleet maintenance
building was constructed to support the gas operations functions.
This narrative is meant to address the 22,000 square foot main building that has
been in service for nearly 70 years. Due to its long history, many of the main
building components, systems, and equipment have deteriorated over time.
ln 2011, Facilities prepared a survey of several of our existing sites that created an
Asset Condition score. The Dollar Road Service Center scored the second lowest
in terms of Asset Condition (see attached survey results).
As part of the survey, the following images were captured to represent current
conditions:
Business Case Justification Narrative Page 2 of 11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 237 of 325
New Dollar Road Sen¡rce Center
3 PROPOSAL AND RECOMMENDED SOLUTION
Option GapitalCost Start Gomplete
Option I (Recommended) -
Demolish existing building and
build new Service Center on
existing property.
$24,000,000 01t2016 12t2018
Option2-Purchasenew
property/site and build new Service
Genter.
$37,000,000 (approx.)01t2016 12t2018
Option 3 - Do nothing, keep using
existing building.
$21K capital yearly. $169K
O&M yearly. (Both values are
approximate averages from
the last 5 years)
N/A N/A
The three above options were produced with input from the Advisory Group listed
above in Section 1, ltem 1.1. Please note, individual stakeholders from the
Advisory Group may not have been involved in producing allthree options.
Option I - Demolish existinq buildins and build new Seruice Center on existins
propertv
The recommended design solution is shown below. The existing building to be
demolished is at the lower left of the image, shown underneath the new proposed
parking lot. The vehicle storage and fleet maintenance building was constructed in
2011 and 2013 and is shown in white in the upper middle portion of the image.
This option is proposed to begin construction in 2017 and end in late 2018.
Business Case Justification Narrative Page3of11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 238 of 325
New Dollar Road Sen¡ice Center
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Business Case Justification Narrative Page4of11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 239 of 325
New Dollar Road Seruice Center
The benefits this proposed design will provide include the following items 1 through
7.
1. Estimated Cost Savings. The chart below summarizes estimated yearly cost
savings going fonryard.
s250,000
$233,889 YEARLY
OPTION 1. - ESTIMATED YEARLY COST SAVINGS
s200,ooo
s150,000
s100,000
s50,000
rTIME SAVINGS T COF SPACE SAVINGS T BUILDING MAINTENANCE SAVINGS
o Time savings from increased efficiency and production capabilities of
Avista employees leading to direct cost savings, is estimated at
approximately $1 50,000 annually.o Space savings for potential office space and parking uses will occur
once the project is completed due to the relocation of approximately 10
gas meter shop employees from the main campus, and the capacity for
relocating up to 30 more as needed, resulting in decreased pressure
on the limited employee and parking space at the main campus.o Building maintenance savings refers to the reduction in building, site,
electrical, plumbing, or HVAC systems that will need repair and or
maintenance once a new building is completed. The direct cost
savings are conservatively estimated to be ($20,000) yearly going
fonrard.2. Non-quantifiable improvements in safety of Avista employees, including but not
limited to:
o Service truck backing accidents.o Air quality for welding and work that produces possible harmful vapors
or particles.o Providing clearly articulated paths of service vehicle traffic on site.o Separating employee parking from service yard traffic and parking.o Providing necessary clearances for employees that work with interior
shelving and forklifts, build natural gas controlgates, and pick
materials such as 60 foot sticks of gas pipe in the storage yard.o Providing gantry, trolley, and jib cranes as needed to prevent lost time
accidents resulting from manual lifting and moving of equipment and
materials.o Providing canopies or covers for main forklift and pedestrian pathways
So
Business Case Justification Narrative Page5of11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 240 of 325
New Dollar Road Seryrce Center
to prevent snow and ice slips, trips, and falls.
3. Non-Quantifiable Equipment Savings
o Potential increased longevity of service vehicles/trucks due to being
covered and/or in heated parking.
4. Create temporary office space for current Dollar Road employees during
construction that will be become permanent after the project is completed. The
space will be available for use by any other Avista group, which in turn will free
up parking and usable square footage at the main campus.
5. Please see Appendix 1 at the end of this Business Case Justification Narrative
for further advantages for the Gas Operations, Gas Meter Shop and Warehouse
business units.
6. Customer benefits are outlíned throughout the items above, but some
clarifications and items to consider also include:
o Faster response time of field crews due to increased efficiencies.o lncreased reliability of gas operations.o lncreased customer safety, especially during a safety event such as a
broken gas line.o Accommodating future customers within the Spokane area. Between
the 2000 and 2010 census Spokane population grew approximately
6%.o Ability to accommodate and assist customers outside the greater
Spokane area, but within our overall service territory.
Option 2 - Purchase new prope¡tv/site and build new Seruice Center
Facilities explored relocating the gas operations to an alternate sites, with the
intent to build a facility similar to Option 1 above. In addition, the new site would
have to build a new Fleet Maintenance Building and Vehicle Storage Building to
replace their uses currently on the existing site. The estimated cost of this option
would be $7 million for an alternate site, $24 million for the Option 1 facility above,
and $6 million to replace the Fleet Maintenance and Vehicle Storage Buildings
(total $37 million).
During the search for an alternate site, it was determined with David Howell and
Tim Mair that based on service territory and travel, the new site must be roughly in
the same centralized position of Spokane that it is now, which ruled out any lots on
the north side or South Hill of Spokane, west towards the Airport, or east towards
the Valley. We did find a lot of suitable size near Playfair Commerce Park, however
it was a build-to-suit lease option only, not a purchase option. The central location
desired resulted in no lots on the market (at that time) large enough for the Gas
Operations team. lt was thus decided to stay and expand upon the current site by
purchasing residential properties to the east and re-zone them into Ll Light
Industrial Zoning.
Business Case Justification Narrative Page6of11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 241 of 325
New Dollar Road Servrce Center
Option 3 - Do nothins. keep usins existins buildins
Tlre third option will see ongoing yearly average costs at about $190,000 per year
($21,000 in capital and $169,000 in O&M costs). lt should be noted that the O&M
costs should expect to grow uniformly over time as the building must be
maintained to remain in usable condition. Using a conservative uniform increase
rate of 5% yearly it could be expected that within 10 years the O&M yearly costs
would at least approach $265,000. At the same time, over that 10 years a total of
approximately $2.1 million would be spent on O&M maintenance costs.
In regards to future capital costs, it should be expected that it will rise at a uniform
increase rate of 10o/o leatly as building, site, and building systems are
systematically replaced due to age or condition. Using this figure it could be
expected that within 10 years the capital yearly costs would at least approach
$33,000. At the same time, over that 10 years a total of approximately $270,000
would be spent on capital costs. However, catastrophic failures of the building,
site, or any of its systems would require an immediate, and potentially costly,
replacement from capital budget.resources. lt could create a spike in any given
year of the capital cost spending:due to the failure.
OPTION 3 - FUTURE YEARLY COSTS
S350,ooo
S3oo,ooo
S25o,ooo
s2o0,ooo
s1s0,000
s100,000
ss0,000
So 5678
Year Number
r CAPITAL YEARLY COSTS
321 4
r O&M YEARLY COSTS
910
Business Case Justification Narrative PageT of 11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 242 of 325
New Dollar Road Sen¡ice Center
4 APPROVAL AND AUTHORIZATION hrrlo- lr( S¡u¡¡* C,ø-t</
Theundersignedacknowledgetheyhavereviewedtheffiing
P{tasd plan and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in
Section1.1. The undersigned also acknowledge that significant changes to this will
be coordinated
representatives
with a roved the undersigned or their designated
t1Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Eric Bowles
Business Case Owner
Manager, Facilities
Date
Date
Date: Ll-Zf -\1
S*'*U-a
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory Com mittee Review
5 VERSION HISTORY
Tem plate Version : 03107 12017
Verclon lmplemented
By
Revislon
Date
Approved
By
Approval
Date
Reason
1 Eric Bowles 04t25117 Heather
Rosentrater
04t25117 New template
Business Case Justification Narrative Page 8 of 11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 243 of 325
New Dollar Road Seruice Center
Appendix I
1. Gas Operations additional efficiencies obtained and iustifications for Option 1.
as per Tim Mair:
Heated Truck Parkinq Stalls:
o Protects the trucks from winter weather - shortens the time that it takes to get ready for
use.o lncreases the life span of tools that are no longer in the elements.. Dry's tools, equipment, and the trucks out for the next day's work.o Eliminates the need for engine power cord connections, and snow removal of trucks.. Mini warehouse will be in this area for loading trucks.
Pressure Gontrol-men work area:
o At this time the area is over crowded with not enough area to work and walk.. lmproves the overall safety of employees working in the area.o Large diameter pipe is being moved around by employees without full use of cranes.
The new cranes will enable the employees to do the work with a crane.. The new area will be better ventilated for clearing the area out when welding.
Govered Crane / Pipe Gleaninq Area:
Preparation of pipe needs to be outside for health and safety reason.
Cleaning of this pipe outside will help keep the PC area inside clean and avoid trip
hazards.
Crane will be used to transport large diameter pipe into PC area for final prep and build
of Regulator Stations.
The crane and covered area will improve the overall safety for this area and the
employees.
a
a
a
a
a
Weldinq Trainins Room:
o This room will have 3 training weld stations that are enclosed out of the weathero We have only 2 stations now that are outside on the dock.o lmproves safety, out of weather, and better training environment.
Tool Grib Area:
. lmproved storage racks - safer to work around, more organizedo More open area for the tools to be repaired.o Locked area for storing of high cost items.
Gas Serviceman Area:
Area is used to build meter sets and house out of stores parts for field work.
Test equipment required in this area which is required to meet compliance regulationsa
Business Case Justification Narrative Page9ofl1
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 244 of 325
New Dollar Road Seryrce Center
Main Office Area:
o Two conference rooms will facilitate the meeting requests for five different departments
working out of the service center.. Foreman's work area is consistent with other service centers. lt will allow the foreman to
complete paper work, check emails, follow up on training, and complete time sheets
online.o Cubicle space for field workers - this area will be used for computer based, training,
checking emails, and field paper work.o Existing office space for 26 employees new space for 31 employees allow for some
growth.o Large classroom - used for Quarterly, safety, training meetings and for emergencies.
. Break Room will be used for early AM crew meetings'
Covered Spoils Area:
Sand, cold mix, and gravelthat is left uncovered creates problems with dust, freezing of
materials, additional weight for loading and hauling. This adds cost and time to the work
that has to be done with this material.
a
2. Gas Meter Shop additionat efficiencies obtained and iustifications for Option 1.
as per Fred Valentine:
The bullets points below help show how things will be improved (compared to
current state) when the Dollar Road Service Center gets completed. To
summarize:
1 - Materialwill be managed and distributed by one group. Currently, two different groups
are doing this work.
2 - Materialwill be consolidated under one roof. Currently, there are at least 6 locations
meters and regulators are being stored.
3 - lnventory will be easier to record when all material is in one warehouse.
4 - Shop size increase will allow more functional space.
S - Work benches will be in each specific room and not in pedestrian areas as per current
layout.
6 - Noise and debris will be confined to the specific room and not throughout the entire
area, or adjoining neighbors.
7 - Material and equipment specific to each room will have a "destination" rather than a
random placement for future attention.
I - Shelves can be placed more appropriately to increase spacing for safer movement
and use of units.
g. Warehouse additional efficiencies obtained and iustifications for Option 1. as
per Laurie Heagle:
o lncreased number of stores inventory items from 670 in 2011 to 1200 in 2016. A
79% increase.. Changes in gas standards and increased emphasis on gas growth continue to
increáse both the number of new items and the quantity of material needed
to serve the company's needs. (Dollar Road is the distribution center for all of
Washington and ldaho and some of Oregon.)
Business Case Justification Narrative Page 10 of 1 1
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 245 of 325
New Dollar Road Seryrce Center
a Pallets of materials must be routinely placed in the aisles as there is not enough
space to stage, put away or store materials on shelves/racking. This makes the
storekeepers job to pull materials more challenging and time consuming.
With the added number of items it is challenging to place frequently needed
materials in locations to provide efficient and ergonomic access.
The warehouse is not currently secured resulting in unexpected material
shortages.
a
a
Business Case Justification Narrative Page 11 of 11
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 246 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 247 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 248 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 249 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 250 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 251 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 252 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 253 of 325
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 254 of 325
Faci I ities Sfru ctu res and I m provement
1 GENERAL INFORMATION
Requested Spend Amount $3,000,000
Requesting Organ ization/Department Facilities
Business Case Owner Eric Bowles, Facilities Manager
Business Gase Sponsor Anna Scarlett, Shared Services Manager
Sponsor Organization/Department Shared Services
Gategory Program
Driver Asset Condition
l.l Steering Gommittee or Advisory Group lnformation
ER7001 Facilities Structures and lmprovements is a 5-year program created to
address the capital lifecycle asset replacements and business/site improvements at
all of Avista's regional sites and offices. Asset lifecycle replacements are compiled
by Facilities and are based on an asset condition report and industry recognized
lifecycles. Site improvement projects are approved based on productivity and/or
business need.
ln 2011, Facilities prepared a survey of several of our existing sites that created an
Asset Condition score. This survey is the basis for prioritizing asset lifecycle
replacements and site improvement projects (See attached for survey results).
A new site assessment survey is currently underway with an independent
contractor and should be completed in 2017. This will be the basis for the asset
replacement program over the next 10 years.
Total combined requests have been considerably higher each year than funding,
and valid projects are often times backlogged.
Funding backlog
Once the project list is assembled, it is vetted for approval by a stakeholder group
at the next level of management familiar with the individual requests, (usually at
ER 7001 l7OO3 Request vs Funding
Srz
Sro
Se
$o
s4
Sz
So
âcg
=
I
2015 20L720L6
r requested r Funded
Business Case Justification Narrative Page 1 ol7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 255 of 325
Facil ities Sfru ctu res and I m provement
the Director level). In the past this has most often been:
o Director of Facilities,
o Directors of East and West Operations,
o Directors of Generation, Transmission, and Gas (when applicable)
2 BUSINESS PROBLEM
Many of the service centers in Avista's territory were built in the 1950s and 60s and
are starting to show signs of severe aging. Most of our building systems are also
past their recommended life based on recognized industry standards defined by
Building Owners and Managers Association (BOMA), and lnternational Facility
Management Association (IFMA) and are requiring renovation or replacement.
Many of the original campus layouts and buildings at our Service centers are no
longer optimal today due to changes in our vehicle sizes, materials storage, and
operations flow. These changes have required the need for project funding to
address changing business and site requirements as well.
ER7001/ER7003 2Ot7 fu nding breakdown
r ER7001 Asset Lifecycle Replacements
r ER7001 Site lmprovement/Business Need Projects
r ER7003 Furniture Replacements
Average funding splits based on project priorities
This program is be responsible for the capital maintenance, site improvement, and
furniture budgets at over 40 Avista offices, storage buildings, and service centers
(over 900,000 total square feet) Companywide. This program is intended to
systematically address the following needs:
o Lifecycle asset replacements (examples: roofing, asphalt, electrical,
plumbing)
o Lifecycle furniture replacements and new furniture additions (to support
growth)
o Business additions or site improvements (examples: adding a welding bay,
vehicle storage canopy, expanding an asphalt yard. Can sometimes include
property purchases to support site expansions.)
Business Case Justification Narrative Page 2 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 256 of 325
Facilities Súru ctures and Improvement
This program would encompass capital projects in all construction disciplines
(roofing, asphalt, electrical, plumbing, HVAC, landscaping, expansions, remodels,
energy efficiency projects).
3 PROPOSAL AND RECOMMENDED SOLUTION
Option 1 - Fund Program at Current Level (Recommendedl
This will allow us to address capital asset replacements and business needs. Safety,
compliance, and productivity requests are rated highest and given priority first. Many of
these replacements can create safety risk if not addressed (sidewalks, structural
repairs). Not systematically addressing maintenance needs could ultimately result in
complete replacement of the buildings at some point.
This Structures and lmprovements program will be made up of 3 main parts:
1. Capital Asset Replacements ER 7001
This portion of the Structures and lmprovements Program is based on the results of the
Facilities Condition Assessment Survey. This survey will take into account the condition
and lifecycle of each Facilities asset. Assets will be graded and those requiring
replacement within the next 10 years will be estimated and scheduled for replacement
at an appropriate year during the 10 year time frame of the survey. Buildings as a whole
will be assigned a Facilities Condition lndex (FCl) as part of the survey to help compare
future capital needs and drive the decision of continued capital expenditures vs.
possible replacement.
Optlon Gapftal
Cost
Start Complete Rlsk Mitlgatlon
Option I (Recommended) - Fund at
existing levels.
$3M 01 I 2017 01t2022 Many of the issues on the
list can quickly become
safety issues if not
addressed, exposing the
company to risk.
Option 2 - Partially Fund Program $1M
Capital
and $1M
o&M
01 I 2018 01t2022 Capital investments can be
limited with a corresponding
increase in O&M dollars. As
building systems continue
to decline O&M burden will
increase.
Option3-Donothing $0 Sites will continue to decline due to normal wear and
tear. Certain systems (ex: roofing) failing can cause
major damage to other areas of the building. Safety
issues due to walkways and structural issues not being
addressed.
Business Case Justification Narrative Page 3 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 257 of 325
Faci I ities Sfru ctu res an d I m provement
Examples (asphalt and structural issues):
2. Furniture Replacement or Additions ER 7003
This portion of the program is for furniture replacements based on industry standard
lifecycles, condition, and availability of parts. The program is also meant to support new
furniture additions required on approved building projects.
Examples
,rsQ¿uji., - . *;'
Business Case Justiflcation Narrative Page 4 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 258 of 325
Facilities Súru ctu res and lmprovement
3. Business Additions or Site lmprovements ER 7001
This portion of the program is intended to support site improvement requests and
productivity or business-related needs. Project requests are made by Operations site
managers in June the year before. The list is then vetted for validity and business need
by director-level management. Approved projects are then prioritized vs. capital asset
replacement priorities, and assigned per available capital funding. Projects that are tied
to compliance, safety, or productivity will be given funding preference.
Example (security fencing and gate, weld shop crane):
A robust operations and maintenance program will be required to help further extend
the lifecycle of our Facilities assets and help to lessen capital replacement needs.
Conversely, limited O&M maintenance programs will result in shorter than standard
asset lifecycles, and ultimately increased Capital spending.
As the condition of our Facilities improve, capital asset replacements should lessen in
future years of the program. This is again dependent on sufficient O&M maintenance
budgets and workforce.
The majority of projects in the Facilities Structures and lmprovements program begin
work in the 2nd or 3'd quarter of each year, and will usually transfer to plant before the
end of the year. Some of the larger projects, or projects with extensive design, can carry
over to the following year.
Option 2 - Partiallv Fund Prosram based on prioritv
This option would decrease the capital program and increase existing O&M budgets to
prolong structures' lifecycles beyond rated life, and reduce capital needs. This option is
not the preferred approach over the long-term. Capital investments can be limited with a
corresponding increase in O&M dollars. As building systems continue to decline O&M
burden will increase.
Business site improvement requests are intended to address changing business needs.
These projects are usually linked to an enhanced productivity outcome. Having the
ability to incorporate structures and equipment that fall within the improvement and
business needs category can help support improved processes and lead to enhanced
Business Case Justification Narrative Page 5 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 259 of 325
Facilities Súru ctu res and lmprovement
safety and longer lifecycles. When the budget needs to be reduced, reductions are first
made to requests in this category.
Replacement is intended to replace aging units to achieve more predictable capital
requirements and avoid replacement peaks caused by large-scale failures. Cutting into
these requests over an extended period could lead to reduced efficiency and have
safety impacts.
Option 3- Do nothins
This option is not recommended. Sites will continue to decline due to normalwear and
tear. The failure of certain systems, such as roofing or HVAC, can cause major damage
to other areas of the building. Walkways and structural issues not being addressed
could have safety impacts to employees, visitors and customers.
Business Case Justification Narrative Page 6 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 260 of 325
Facilities Súru ctures and Improvement
4 APPROVAL AND AUTHORIZATION 6oíe;*s 9ru¿,*. f h¡'uo-'*
The undersigned acknowledge they have reviewed the Æ{e€d{Cqãr plan and
agree with the approach it presents and that it has been approved by the steering
committee or other governance body identified in Section1.1. The undersigned
also acknowledg
approved by the
e nificant anges to this will be coordinated with and
ned or desig nated representatives
Date: S t1
Eric Bowles
Facilities Manager
Business Case Owner
Date:V, lt-t
Anna S
Manager, Shared Services
Business Case Sponsor
Date: q-Z g '(1
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory mem ber
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
5 VERSION HISTORY
Tem plate Version : 021241201 7
Vercion lmplemented
BV
Revlsion
Date
Approved
BY
Apprcval
Date
Reason
1 Eric Bowles 04t25t17 Heather
Rosentrater
04t25t17 New template
Business Case Justification Narrative PageT o17
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 261 of 325
Capital Tools & Súores
Requested Spend Amount $2,400,000
Req uesting Organ ization/Department Supply Chain
Business Case Owner Glenn Madden, Manager, Supply Chain
Business Gase Sponsor Anna Scarlett, Manager, Shared Services
Sponsor Organ ization/Department Shared Services
Gategory Program
Driver Asset Condition
I GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Budgeting for Avista's Capital Tool Program is projected for five years based on
historical spends and prioritized against other company budget needs by Avista's
capital Planning Group (cPG). Midway through every year, business units
analyze their need for tools and equipment to be purchased during the next fiscal
year. Each year the Capital Tool Program has more requests for tools and
equipment than can be funded (see Figure 1). The requests are prioritized by
Safety and Compliance, Replacement, or Enhanced Productivity categories. Cuts
to the requests are made by the business units to bring the projected cost of the
list of equipment and tools into line with the budgeted amount. Review of the
request is performed by Avista's CPG who may modify the funding level for the
program in concert with other business budget needs. Additional cuts by the
business units to the Tools and Equipment budget may be needed to meet the
revised budget.
Total Request vs Approved Budget (in millions)
2.27 2.5t
1.7?t.42
20t5
I Total Request
20t6
I Approved Budget
Figure I
Business Case Justification Narrative Page I of7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 262 of 325
Capital Ïools & Súores
Purchasing and oversight of this program is by the Supply Chain Department. The
approval process follows the management chain of Supply Chain Manager,
Manager of Shared Services, Vice-President of Energy Delivery, and President of
Avista Utilities. The Capital Tools Program does not have a steering committee but
does have stakeholders who are the managers and directors of all departments.
2 BUSINESS PROBLEM
Avista's Capital Tool Program provides all departments the proper tooling and
equipment to perform work safely and efficiently. This equipment is necessary to
safely construct, monitor, ensure system integrity, and properly repair and
maintain the Avista systems (electric, gas, communications, fleet, facilities, and
generation). Tool and equipment purchases are prioritized based on three
categories:
1. Safety and Compliance
2. Replacements
3. Enhanced Productivity (see Figure 2)
2OL4-2OL6 Tools and Equipment Purchased
Safety and
Compliance,
t32,27o/o
Enhanced
Productivity,
283,57%
Replacement,
8O, t6o/o
Figure 2
The highest priority tool and equipment purchases help ensure that Avista meets
all safety and compliance requirements. Changes to safety standards and new
compliance mandates may require purchasing new tools. Examples of tools and
equipment purchased for safety and compliance reasons are:
Business Case Justification Narrative Page2of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 263 of 325
Capital Tools & Súores
Ergonomic tooling such as battery cutters/presses/pole grounding staplers,
vibration reduction pole tamps
Manhole extrication devices, rescue mannequins and Automatic External
Defibrillators (AEDs)
Grounding equipment - such as mechanical grounding jumpers, equipotential
grounding mats, and voltage indicators needed to support Avista's new
Electro Potential Zone (EPZ) grounding program
Groundhound site safety device - measures variances in ground voltage,
alarming workers of hazardous ground potential rises preventing shock
hazards
The next highest priority tool and equipment purchases are to replace existing
tools that have reached their end of life. Avista employees must be able to rely on
this equipment while performing hazardous duties, and must be confident that the
equipment will perform safely and efficiently. Failed equipment can lead to
hazardous conditions for the operators, potentially causing injury or death.
Much of the capital equipment used in the utility industry is very specialized and
may not be readily available due to long lead times. This equipment needs to be
fully functional and available, for planned work as well as emergency outage
repairs on our facilities and equipment. Equipment failures cause slowdowns in
work performance. Examples of tools and equipment purchased for replacement
reasons are:
. Replacement of telecommunications equipment when the current platform is
no longer supported. Aged gas boring moles that can no longer be rebuilto Underground locating equipment when replacement parts are no longer
available for repairs
The third and last category for prioritizing tool and equipment purchases is
enhanced productivity. Capitaltooling and equipment is used to perform new
construction work or repair work for unplanned failures. Often this work can take
less time or be completed with better results by using tools.
This category also includes material handling and storage equipment for company
storerooms (forklift, storage cabinets, racking, etc.) Equipment for storerooms
increases warehouse response and efficiency to crews in providing the needed
material or tool in a timely manner.
Examples of tools and equipment purchased for enhanced productivity are:o Purchase of new underground locators, which serve as a cable locator and
fault finder - previously these were separate pieces of equipmento Plasma metal cutting table so Generation can machine their own parts onsiteo IKE field data collection device used to efficiently design, capture mapping
information, and field audit overhead assetso Fiber optic fusion splicing trailer to allow technicians to splice in all
climates/conditions
a
a
a
Business Case Justification Narrative Page 3 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 264 of 325
Capital Tools & Súores
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapltal
Goet
Requeoted
Start
Roquostod
Gompleto
Rlek
Mltlgation
Option I (Recommended):
Fund program at current levels
$2.4M 1/2018 Low Risk
Option 2: Partially fund (based on
priority)
Varies 1/2018 Medium Risk
Option 3: Rent 4o/o oI total equipment
and purchase the rest
$2.3M 1/2018 12/2020 High Risk
Option 4: Do nothing $0 N/A 12J2020 Extremely
High Risk
Option I - Fund Program at Current Level (Recommendedl
It is recommended that this program be funded annually at its current level to
ensure Avista has the proper capital equipment necessary to safely and efficiently
perform all required work. Due to the specialized nature of utility equipment, it is
most efficient for Avista to equip employees with the necessary tools and
equipment to safely perform timely emergency repairs, while using the same tools
and equipment to perform ongoing scheduled work and maintenance.
Furthermore, this specialized equipment is often only available directly from the
manufacturer, and is not typically available as a rental.
By funding this program, Avista ensures that employees have the proper
equipment to safely and efficiently perform their work, while providing safe, reliable
service to customers.
Option 2 - Partiallv Fund Program based on prioritv
This option is not the preferred approach over the long-term, however it is
exercised when necessary. Each year when the requests for tools and equipment
are submitted, cuts to Capital Tool program are made by the business units to
bring the projected cost of the list of equipment and tools into line with the
budgeted amount. Further modification of the funding level for the program is
performed in concert with other business budget needs.
When the budget needs to be reduced, reductions are first made to requests in the
category of enhanced productivity, then replacement. Replacement is intended to
replace aging units to achieve more predictable capital requirements and avoid
replacement peaks caused by large-scale failures. Cutting into these requests
over an extended period could lead to reduced efficiency and have safety impacts.
Having the ability to test and incorporate equipment that falls within the enhanced
productivity category can help support improved processes and lead to enhanced
safety and longer equipment lifecycles.
Business Case Justification Narrative Page 4 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 265 of 325
Capital Tools & Súores
Option 3 - Rent Equipment
Renting a percentage of the capital equipment was considered as a possible
alternative. Of the 430 items purchased Írom 2012 to 2014, 233 can be rented,
although 216 out of the 233 items are needed on hand at all times for emergency
locates and repairs. This leaves 17 possible items, or 4o/o of the total equipment,
which qualifies as potential rental equipment (see Figure 3).
lf equipment is rented, there is no guarantee of availability. Rental companies rent
equipment on a first-come, first-serve basis, making equipment scheduling for
specific time sensitive jobs very difficult. Safety and compliance regulations are
also affected when correct equipment is not available for rent.
Equipment failure is often a concern with rental equipment, as it is uncertain what
condition rental equipment is in, or how it has previously been maintained. This
can lead to safety issues for equipment operators when failures occur, as well as
lost production time.
Depending on the timeline of the rental equipment, it would not be cost effective to
rent long-term as the rental costs would exceed the base price of new equipment.
An average rental price for a basic cable locator is $450/month, which equates to
$5,400/year. The 2017 purchase price of this item is $3,700.
2OL2-20t4 Renta I Possibility
Not Needed for
Emergencies,
L7,4Yo
Figure 3
Training on rental equipment would also be required, if different than standardized
Avista equipment. For example, Avista gas employees are only trained/qualified
on specific equipment that has been standardized by Avista, which may or may
not be what can be rented for specific jobs. This can contribute to added time
Can not be
Rented, L97,
46%
Needed for
Emergencies,
2L6,50Yo
Business Case Justification Narrative Page 5 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 266 of 325
Capital Tools & Súores
necessary to qualify employees on the operation of the equipment, and safe
operating procedures.
Due to the Department of Transportation (DOT) compliance, Avista is also
required to maintain maintenance and calibration records for all gas equipment,
along with operations guides for all on site equipment. Avista would be out of
compliance using various rental equipment as rental companies are not required
to provide this documentation for their equipment to their customers.
Option 4- Do Nothins
All construction, maintenance, and repair work performed at Avista is dependent
on the use of capital tools and equipment. lf proper tools and equipment are not
available, work would cease. Without the necessary equipment, workers cannot
perform their duties safely or efficiently, and Avista facilities and equipment could
no longer be maintained.
Business Case Justification Narrative Page 6 of 7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 267 of 325
Capital Ïools & Súores
I APPROVAL AND AUTHORIZATION Ca¿,.¿J làots Ê fio.o5
The undersigned acknowledge they have revieu¡sfl tþelr4*Feltfiãreär plan and
agree with the approach it presents and that it has been approved by the steering
committee or other governance body identified in Sectionl.1. The undersigned
also acknowledge that significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Glenn n
Date
Date:7,7
Date:\-zrt-t
Manager, Supply Chain
Business Case Owner
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory member
2 VERSION HISTORY
Tem plate Version : 0212412017
Verslon lmplemented
By
Revleion
Dato
Approved
By
Approval
Date
Reason
1 Gary Shrope 4-7-2017 Heather
Rosentrater
04/25/17 New template
Business Case Justification Narrative PageT of7
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 268 of 325
Ap p re nti ce/C raft T rai n i n g
I GENERAL INFORMATION
Requested Spend Amount $300,000 over 5 years ($60,000 annual)
Req uesting Organ ization/Department H uman Resources/Craft Train ing
Business Gase Owner Eric Rosentrater
Business Gase Sponsor George Brown
Sponsor Organization/Department Human Resources
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
The Joint Apprenticeship Training Committee (JATC) is the group identified by
Avista to oversee the administration of the company's apprenticeship programs.
The JATC will, as outlined in the Avista Standards of Apprenticeship, secure the
instructional aides and equipment it deems necessary to provide quality instruction.
To the extent possible, related instruction will be closely correlated with the practical
experience and training received on the job.
2 BUSINESS PROBLEM
The capital allowance allotted to the Training Department through the Apprentice
Training Business Case provides for tools, materials and equipment for training
apprentices and journey workers across eleven skilled crafts or trades. This training
consists of hands-on skills development that builds competency in a safe learning
environment that may not always be available or controllable in the field. A well
trained and competent workforce ensures reliable delivery of energy to Avista's
customers and maintains a safe environment for employees, customers and the
general public in all of Avista Utilities service territories.
In addition to creating a safe and skilled workforce, this training helps Avista to
deliver timely training on new and emerging technologies as well as meet several
federal and state mandated regulations including:. Department of Labor, Standards of Apprenticeship - Title 29 CFR 29.5 (bX4)
and (b)(9) - Apprentice on the job training and related instruction. Department of Labor, Occupational Safety and Health Standards - Title 29
CFR 1910.269 (a)(2) Electric Power Generation, Transmission, and
Distribution training. Department of Transportation, Transportation of Natural Gas and Gas by
Pipeline: Minimum Federal Safety Standards - Title 49 CFR 192.805 (h) -
Qualification of Pipeline Personnel, Qualification Program training. State of Washington - WAC 480-93-013 (4) - Covered Tasks: Equipment and
facilities used by pipeline company for training and qualification of employees
Business Case Justification Narrative Page 1 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 269 of 325
A p p renti celC raft T rai n i ng
3 PROPOSAL AND RECOMMENDED SOLUTION
Capital expenditures under this program could include items such as building new
facilities or expanding existing facilities, purchase of equipment needed, or build out
of realistic utility field infrastructure used to train employees. Examples include: new
or expanded shops, truck canopy, classrooms, backhoes and other equipment, build
out of "Safe City"- commercial and residential building replicas, and distribution,
transmission, smart grid, metering, gas and substation infrastructure.
Without the ability to provide specific hands-on operational training in-house, the
company takes on several risks which include the inability to successfully fill critical
craft positions with the necessary knowledge, skills and abilities specific to Avista's
operations. This would have a direct and significant negative impact on system
reliability, customer response times, as well as employee and public safety.
Regulating bodies may also de-certify our apprentice program due to not meeting
mandatory requirements for adequate training. As a result, the inability to train in-
house would require extensive travel to fulfill our training obligations.
The cost to outsource hands-on-training and field simulations would be
approximately $473,000 a year for facility rental alone. This is based on current
training programs that have averaged over 530 hours per year at the training center.
The overall annual costs including travel, lodging, meals and registration are
estimated to more than triple this rental cost and be classified as operations and
maintenance costs. Again this would result in a negative impact to Avista's
customers.
Option Gapital Gost Start Complete
Do nothing $0
On-going Capital lmprovements $300,000 01 2015 122019
Conduct Training Externally (No Training Facility)$1,400,000 0&M Annual Annual
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 270 of 325
Ap p re nti celC raft T ra i n i n g
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Apprentice/Craft Training
and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role
Signature:
Print Name
Title:
Role
ÇøL-:
Eric Rosentrater
Safety, Training, and Labor Relations
Manager
Business Case Owner
George Brown
Director of HR, Shared Services, Benefits,
Craft Training, Occupational Health and
Safety & Union Labor Relations
Business Case Sponsor
Date
Tem plate Version: 03107 12017
Date I
//, r, -
5 VERSION HISTORY
Veroion lmplemented
By
Rovision
Date
Approved
8y
Apprcval
Date
Reason
1.0 Jeremy Gall 04t04t2017 George Brown 04t14t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 271 of 325
Campus Repurposing Phase 2
I GENERAL INFORMATION
Requested Spend Amount $28,000,000
Requesting Organization/Department Facilities
Business Gase Owner Vance Ruppert i Eric Bowles, Facilities
Business Case Sponsor Anna Scarlett, Manager, Shared Services
Sponsor Organization/Department Shared Services
Gategory Project
Driver Performance & Capacity
1.1 Steering Gommittee or Advisory Group Information
The Campus Repurposing Phase 2 Steering Committee is made up of a cross
section of directors that represent groups impacted by the projects, as well as a
couple members not directly affected to add an outside view. The current group is as
follows:
o Director of Environmental Affairso Director of Shared Serviceso Director of lT and Security. Director of Natural Gaso Director of Financial Planning and Analysiso Director of Operations
Advisors may contribute input; approvals, or information as needed, and include:
o Vice President of Energy Deliveryo Executive Officerso End Users
Each project within this business case is reviewed and approved by the Steering
Committee group, and regular updates are provided during project execution.
2 BUSINESS PROBLEM
The Campus Re-Purposing Plan is a multiyear plan (Phase 1 and Phase 2) that
address the following issues:
. Employee space needs. lmproving safety and efficiency of campus traffic flowo Outdated fleet maintenance space and processeso Lack of materials storage yards, no short-term flexibility
Business Case Justification Narrative Page 1 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 272 of 325
Campus Repurposing Phase 2
Alignment of campus parking and number of employees based at main
campus
The Avista corporate campus comprises 28 acres located next to the Spokane River
in heart of the Logan Neighborhood. The campus in just north of the downtown
Spokane corridor. Avista also owns eight additional acres of property directly
adjacent to the campus at the north end. This parcel is separated from the main
campus by North Genter Street (a main city arterial).
Avista's corporate campus footprínt is currently bound to the east by the Spokane
River, and to the west and south by the Mission Park and Burlington Northern
Railroad, leaving minimal flexibility to manage company parking, employee and
materials space needs.
The Avista corporate campus was built in 1958 to consolidate and house all utility
operations that were at that time spread throughout the community. As business
needs changed over time, one-off expansion projects were to reactively address
changes in business need. Employee growth and materials storage increases
through the years have created the need to locate employees and materials at
offsite locations, requiring space leases and other non-optimal solutions to meet
growing company space needs.
Business Case Justification Narrative Page 2 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 273 of 325
Campus Repu ng Phase 2
Strategic property purchases to the North of the campus have been ongoing since
1988 as they become available to help address the issue and grow the campus to
give us future flexibility. The final properties between Avista and the neighboring
Riverview Retirement Community were purchased in 2014, now allowing us to
develop them for company use.
The decision was made in 2011 to take a holistic approach to these issues and
create a single proposed solution for the Corporate Campus that would address
current issues, and future needs. The campus repurposing planning group began
working in 2011 to find a way to address the growing employee space needs,
parking issues, campus materials storage issues, safety and traffic flow issues
(Operations traffic and employee traffic mixing), as well as look into addressing the
changing business needs of our vehicle fleet and operational processes.
The result of this approach is a total campus plan that repurposes the existing
campus for the next 50 years, minimizing our reactive approach and ensuring the
best long term results for the Company and Ratepayers.
3. PROPOSAL AND RECOMMENDED SOLUTION
Campus Repurposing Phase 2 includes three major projects:
1. North Genter Re-Route
2. Construct New Fleet Building
3. Construct Parking Garage
These three projects are connected and largely dependent on each other because of
location, timing and the overall campus design. The projects will ultimately allow us
to:o Expand and consolidate the campus footprint while establishing a formal
boundary between the Avista campus and the Riverview campus.o Modernize the aged Fleet Building and address Fleet queuing needs.. Expand and locate campus parking to align the available number of parking
spaces with the number of employees working onsite, improving employee
and public safety by reducing parking sprawl.. Separate operations traffic from pedestrian traffic to improve safety and
i ncrease workflow efficiencies.
Business Case Justification Narrative Page 3 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 274 of 325
Campus Repurposing Phase 2
7.72 ^<t6Pr6i cilb.n.Ur ¡ilpint fùrn
[!:: ia I n'"t-
Í6!rcmnt Resh
Proiect 1: North Center Street Re-Route
Avista-owned properties separated from campus by North Genter Street
North Center Street currently divides us from the eight acres of property owned to
the north on Ross Court. Re-routing North Center Street will allow us to
consolidate our campus to include these properties. As North Center Street is a
major city arterial that connects lndiana Street to Upriver Drive, a considerable
amount of traffic uses the street daily. This traffic creates an ongoing safety risk to
employees moving back and forth between the properties. lt also creates
challenges with securing the lots during business hours (gates, entrances, etc.).
Beginning in 2013, Avista began discussion with Riverview to plan the future
development of each of our campuses. Riverview management expressed
concern with future development on our adjacent properties due to the proximity of
these properties to their resident housing. With no formal separation between our
campuses, they were concerned with the height of proposed buildings as well as
idling dieseltrucks next to their resident properties.
Several options were considered (see options listed below). After many
discussions, there was interest on both sides to explore rerouting North Center
Street to the north in order to: 1) consolidate our properties into our secured
campus; and 2) give Riverview a formal separation between our campuses.
Business Case Justification Narrative Page 4 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 275 of 325
Campus Repurposing Phase 2
Ross CouÉ Property Optlons
(¡e-routo of North Center Street)
Gapltal
Cost
9fârt Complete RIsk Mitigatlon
Option 1 (Recommended):
North Center rerouted around our
Ross Court properties, adding eight
acres to the Campus
$6M 2016 2017 Riverview prefers this
option due to formal
separation.
Option 2: no reroute (minimum
development required to make
Ross Court property usable).
North Center Street remains in place
creating a separated campus to the
North, accessed by crossing North
Center. Fencing, gates, and lot
development still req uired.
$3,000,000 2016 2017 Risk involved in
transporting materials
across a major City
Arterial. Strong
opposition from
Riverview on any
development other than
basic storage.
Option 3: no reroute, with tunnel or
bridge connection to Ross Court
North Center Street would remain and
a tunnel or bridge would be created to
safely access Ross Court and create
a single secured Campus.
$8,000,000 2016 2017 Higher maintenance
costs for bridge or
tunnel. Strong
opposition from
Riverview on any
development other than
basic storage
Option 4: Do nothing $0 Basic storage use only with no development.
Property does require basic Civiland site
work to be usable though.
Option 7 hecommended): Reroute North Center Sfreef to consolidafe Ross Court
properties with the main campus.
The re-route of North Center Street would allow us to create a new operations entrance
to our campus, separating operations traffic from pedestrian traffic and resulting in
operations workflow efficiencies and improved safety of the company and employees.
Business Case Justification Narrative Page 5 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 276 of 325
Campus Repurposrng Phase 2
Recommended Option
Positive Benefits Neqatives
Allows the creation of a new Operations entrance lssues with Citv permittino?
Riverview's preferred option due to formal separation. No
opposition to future developments options
Closure of North Crescent Street to
access aoartments behind Riverview
Single con nected/secured Campus
Better Operations traffic flow from entry, drop off, and
oarkino
Create a formal separation between Avista and Riverview
Better separation of employee and Operations traffic would
dramatically lessen safety risk to the company
Business Case Justification Narrative Page 6 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 277 of 325
Campus Repurposing Phase 2
Options 2 and 3: No reroute. leave North Center Street in place and secure as
separate campus.
A minimum of Option 2 or 3 would be required to make the Ross Court properties
usable; however, these options would not allow separate operations entrance to be
added.
Optionsl and 2
Positive Benefits Negatives
Lower cost options
(Option I lower cost, Option 2 similar cost)
Development options we are considering would be
strongly opposed by Riverview due to direct
adjacency of our operations to their resident
properties
Slightly larger usable area vs Option 1 Two separate campuses requiring constant traffic
across North Center Street creates safety risk
(Alternative 2 only).
Alternative 2 would create a single Campus
access
Alternative 2 would require higher O&M cost for
tunnel or bridge
Quicker project execution These 2 alternatives will not allow for a new
Operations entrance
Business Case Justification Narrative PageT oÍ20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 278 of 325
Campus Repurposing Phase 2
Proiect 2: Gonstruct New Fleet Ooerations Facilitv
Avista's existing fleet operations building is located in the heart of the main campus and
was originally built in 1958 to centralize all Avista fleet maintenance operations.
Vehicle and Building Size
The original fleet building was built to house smaller half-ton pick-ups and has been
expanded twice through the years to accommodate the increased size of the new
service trucks, once in 1978 and again in 1999. The size of vehicles in today's fleet
have continue to increase since 1999 and some of the current fleet is difficult to service
in the existing building. The current building is much smaller than City of Spokane and
Waste Management facilities, which utilize similar-sized vehicles. Many of our larger
trucks cannot be worked on in the existing space without leaving the doors open.
Existing Fleet Building Location
Business Case Justification Narrative Page I of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 279 of 325
Campus Rep osing Phase 2
CNG
Avista has added vehicles fueled by compressed natural gas (CNG) to our fleet over the
past four years. The existing fleet building is not CNG rated and all CNG-fueled vehicles
must be taken offsite for repairs. To make the building CNG compliant would require the
addition of a new emergency exhaust system. The estimated cost to make the building
CNG compliant is around $1.3 Million
Environmental
The hydraulic lift system installed in the existing building did not include secondary
containment when originally installed, and testing has indicated possible leakage of
hydraulic oil in the soil under the building. Relocation of the building will allow us to
completely encase all new hydraulic systems and mitigate any current or potential
leakage.
Safety
The existing fleet staging and queuing area is also in the heart of the campus and is
directly adjacent to multiple parking canopies and surface parking areas. This staging
area is small and requires multiple trips in and out of the area for day-to-day operations.
A main employee walkway also goes through this major traffic area and brings
considerable safety risk to the company as some of the pedestrian traffic can be hidden
by the parking canopies. Moving the fleet building to the north will allow for increased
queuing area and lessen the employee and operations traffic risk considerably.
Building Gonditions
ln addition to compliance, environmental and safety issues, the existing building has a
number of conditions that affect operations and employee safety and health, including
the issues below (see attachment Corp Fleet Building /ssues for complete list).
r Current facilities have bays less than 14' wide. Current trucks are 103" wide at the
mirrors, leaving limited space for maneuvering and working on vehicles.o We cannot lift rear tandem axle trucks with in ground lifts. We utilize wheel lifts which
add 38" to the width of the vehicle. This leaves less than 2' for the technician to
move himself and his tools into position. Tandem axle trucks make up 35% of the
Avista Fleet. This effects productivity.. Roof leaks at multiple points.
Options and Alternatives
Fleet Operatlons Optlons Capital
Gost
Start Gomplete Rlsk Mitlgatlon
Option 1 (Recommended): Build a
new CNG-compliant Fleet
Operations building at the north
end of the property and address the
existing issues.
o This options would allow us to use
the existing fleet footprint for the
Parkino Garaqe and move all
$10,000,000 2017 2018 Major safety risk
mitigated with
employee and Ops
traffic mixing.
Business Case Justification Narrative Page 9 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 280 of 325
Campus Repurposrng Phase 2
Operations traffic to the North end
of the Campus.
Option 2: Address the major issues
in the existing building separately.
. Replace Hydraulic systems,
replace the constantly leaking roof,
and installa CNG compliant
exhausting system.
o lncrease the building in the future
if needed.
$4,000,000 2017 2018 . Location not optimal
in regards to safety
and risk
o Environmentaland
compliance issues
o Continued rising of
maintenance costs
due to age of the
building and
systems
Option 3: Do nothing $0 Still need to address the future impact of
larger fleet vehicle sizes, aging hydraulic
systems, non-compliant CNG space, and most
importantly the safety risk due to the constant
traffic and employee mixing.
Option 1 (recommendedl: Construct a new fleet operations facilitv at the north
end of the campus.
Constructing a new fleet operations center operations building strategically located at
the north end of the campus would achieve a number of objectives:
o Enable us to increase the size of bays to accommodate larger fleet vehicleso Address CNG compliance requirements and environmental issues related to the
aging current facilityo Increase efficiency and safety of pedestrians and operations traffic on campuso Increase efficiency of fleet operations
A pre-design BPI process was undertaken in early 2016 to look at efficiencies that
would be created by a new building and new processes. lt was discovered that the poor
layout of the existing building resulted in numerous extra steps taken each day resulting
in wasted time and resources. The new building was designed using industry best
practices, and observed employee workflow.
Business Case Justification Narrative Page 10 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 281 of 325
Campus Repurposing Phase 2
BPI Spaghetti workflow diagram
See attached buttet points for a comprehensive /isf of rssues that a new building would
address.
Recommended Option: New Fleet Building on Ross Gourt
Business Case Justification Narrative Page 11 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 282 of 325
Camp us Rep urposing Phase 2
Option 2: Address individual issues with existins buildins
Remodeling the existing building to accommodate fleet vehicles that no longer fit the
current facility is not possible within the current footprint's size. ln addition, this option
does not address environmental, compliance or safety concerns described above. To
make the building CNG compliant would require the addition of a new emergency
exhaust system. Íhe estimated cost to make the building CNG compliant is around $1 .3
Million
Option 3: Do Nothins:
Doing nothing is not a viable option. New hydraulic lifts would be required soon, and basic
space, environmental and compliance issues would still need to be addressed. We would
need to reevaluate how to continue servicing CNG vehicles.
Business Case Justification Narrative Page 12 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 283 of 325
Campus Repu g Phase 2
Proiect 3: Parking Garage
As of June 2016, Avista has a headcount of approximately 1,280, including company
and contracted employees, reporting to the main campus facility. The number of parking
spaces available for employees is approximately 728 (not including visitor and disabled
parking). Assuming not all employees are on the property at any one time, a minimum
of 400 additional parking spaces are required each day to address the current existing
need as well as additional spaces for future flexibility. Avista leases parking space along
Perry Street from Burlington Northern Railroad (BNR), in an open-ended lease that can
be cancelled by BNR with 30 days written notice. Employees walk across railroad tracks
to get to and from the buildings and these parking areas. Additionally, loss of this lease
would result in the loss of almost 200 parking spaces.
Aligning campus parking with employee count has been addressed through the years
by relocating materials storage yards from the campus footprint and adding surface
parking lots (see below).
Mission Campus Parking Space Count 2008 538
2009 +57Added Spaces South Mission Lot
2009 +55Added Spaces Transformer Storage Lot
2012 +124Expanded North Pole Yard
2012 +49Added North Ross Court
823Total Current Parking Spaces
(includinq Disabilitv and Visitor Parkins)
728Total Parking Spaces Available
(excludinq Disability and Visitor Parking)
Estimated Employees/Contractors Assigned to Mission
Campus as of June 2016*
1282
Estimated Employee/Contractors e not at Mission Campus
on any one day (15Yo)
-129
425**Shortage of Parking Spaces to Meet Current Need for
Employees/ Contractors Assigned to Mission Gampus**
Year ParkingAction Taken
cesS
Business Case Justification Narrative Page 13 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 284 of 325
Campus Repu osing Phase 2
Using valuable campus real estate for parking lots has required us to take our
operations vehicles and materials storage offsite to our Beacon substation property
more than a mile away, increasing crew time and resources to access materials and
vehicles each day.
This daily deficit in parking is currently absorbed in gravel lots on Ross Court and along
the railroad tracks on Burlington Northern Railroad land. This parking is not in
compliance with City of Spokane parking code, and we could be required to cease at
any time. Additional parking overflow beyond these locations usually takes place in the
immediate neighborhoods around Avista, and has resulted in frustrated calls, threats,
and visits from our residential neighbors.
The proposed parking garage is intended as a long-term solution to the employee and
visitor parking deficiency and related safety concerns.
Safety
With our current parking conditions, employees and visitors face a number of ongoing
safety risks:
Business Case Justification Narrative Page 14 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 285 of 325
a
a
a
a
Campus Repurposing Phase 2
The main building and service center, where the majority of regular and contract
employees are located, is separated from parking areas by railroad tracks, busy
arterials (Mission and Perry Streets), and operations areas, forcing pedestrians
to cross these areas throughout the day.
Operations traffic peaks in the mornings and afternoons, when employees are
often walking to or from their vehicles.
Parking areas are open and must be maintained throughout year to keep lots
safe and clear of seasonal conditions. Even with ongoing maintenance, lost work
days due to slipping and falls on the main campus (both inside and outside) is
estimated at 11,000 days since 1997.|n the first quarter of 2017, Avista
experienced a record number of slips, trips and falls related to icy conditions.
While we have full-time security on campus with cameras and patrol staff, there
is no security off campus to protect employees, visitors and their vehicles.
Parking lmpact 2016
Options and Alternatives
We analyzed three primary options for adding up to 500 parking spaces to fully solve
the parking issue and give protection against the loss of the BNR leased space:
. Option 1 (recommended) - Construct a parking garage in the location of the
original fleet building. The garage would be a four-story structure with five levels
of parking.
Business Case Justification Narrative Page 15 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 286 of 325
Campus Repurposing Phase 2
Option 2 - Convert property at the north end of campus (Ross Court) into
parking lots.
Option 3 - Purchase properties to the east of campus, across Perry Street, and
develop parking lots.
Roes Gsurt Property Options
{re-routs of North Center Street)
Gapltal
Gost
9tart Completo Risk Mitigation
Option I (Recommended): Build
Parking Garage
Build a 4-story 500-space parking
garage in the location of the
existing Fleet Building.
$12,000,000 2018 2018 o Coverage in the event
of the loss of BNR
leased space.
. Employees would not
need to park in the
neighborhood.
Option 2: Convert Ross Gourt
property into parking to
address current deficit
Pave the remaining four acres of
undeveloped Ross Court property
and make a parking lot. Would
need to include drainage swales,
parking island vegetation, and
sidewalks to be comply with city
code.
$3,000,000 2017 2018 . Not highest and best
use of existing property.
Will only net -175.
spaces.
o Would impact Fleet
construction project as
this space is earmarked
for the new building.
. Risk of impact from
losing BNR lease still
possible.
Option 3: Purchase properties
to the east of Avista to build 500
parking spaces (10 acres
required)
Purchase 10 acres of property
along Perry to the east and
develop to create 500 parking
spaces.
$16.2M 2016 2017 ¡ Risk of not getting all
properties.
o Highest maintenance
costs (snow removal,
crack seal, seal coat,
1S-year average
asphalt replacement)
Option 4: Do nothing $o a
a
a
Risk of City of Spokane compliance issues
with using Ross Park in its current form.
This can be called out at any time.
Negative perception from local neighbors
due to parking overflow in front of their
houses.
Loss of BNR lease would be catastrophic to
employee parking with no immediate
resolution.
Option I (recommendedt: Build a 4 storu Parkins Garase
This option will minimize the physical footprint required (only 0.71 acres). Constructing it
in the location of the original Fleet Building will locate parking density next to employee
workspace density, maximiz¡ng safety and operations efficiency.
a
a
Business Case Justification Narrative Page 16 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 287 of 325
Campus Repurposing Phase 2
Option I (Recommended): Buildins a four-etory parking garage with five levels of parkins
Positive Benefits Negatives
Locates parkinq densitv near emÞlovee densitv Customer perceotion of structure
Willdrastically reduce slips, trips and falls experienced by
employees walking through 20 acres of existing parking lots
each day, reducinq risk and L&l claims to the Company.
Possible environmental issues under
existinq fleet footprint
Majority of parking would now be secured within the Campus.
Will dramatically reduce the risk to the company from
emolovee and Operations traffic mixinq in the north lot areas.
Lowest O&M maintenance costs, and longest life vs. asphalt
lot.
Lowest snow removal cost vs.10 acres of traditional blacktop.
Could allow us to repurpose campus real estate back to
materials storaoe.
Parking Garage Footprint
Option 2: Convert Ross Court property into parking to address current deficit
Converting property on the north side of Campus (Ross Court), would only address part
of the current park¡ng deficit, with a net of approx. 175 spaces. This solution doesn't
address a potential BNR lease loss and would impact plans for the new fleet facility.
Option 2=Pave existing Ross Gourt properties to be used for parking
Positive Benefits Negatives
Lower cost vs. recommended Not highest and best use of purchased properties on Ross
Court. High cost vs strategic value (when including property
purchases). No option for a new Fleet Building.
Quickest Solution Solution would only address the current parking deficit, (only
net approx. 175 spaces) Doesn't address BNR lease loss.
Business Case Justification Narrative Page17 o120
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 288 of 325
Campus Repurposing Phase 2
Option 3: Purchase properties to the east of Avista to build 500 parkins spaces
Traditional parking lot construction for 500 spaces would require 10 acres of land to
accommodate 208 drainage swales, vegetation for heat island mitigation, and other
items required by the City of Spokane. The only available option for adding additional
land to the campus would be the properties to the east, on the other side of Perry
Street. These would be difficult and costly to acquire, and add additional challenges of
expanding the campus into a residential area separated by a major arterial.
500 spots using surface parking construction
Option 4: Do Nothins
This option would not solve the parking deficiency or the problems it has created:
o Operations vehicles and materials storage offsite at Beacon substation property. Non-compliantparkingo Neighborhood impacts
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10.5 Â(res
pra¡¡ <lil, to ailbla aô¡p9rñ1. Îlrn
off ihc Àllorurañcd rooi to ç_tnø
Option 3: Purchase l0 acres to the east and build 500 spaces
Positive Benefits Negatives
Would net the full 500 spaces Highest cost option
High risk of not getting all properties required to build. Risk of
street vacations not beino approved.
lncreased risk of injury with 500 employees crossing Perry
Street dailv.
Highest cost maintenance option, (snow removal, crack seal,
sealcoat, complete asphalt replacement every 15-20 years).
Business Case Justification Narrative Page 18 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 289 of 325
Campus Repu ing Phase 2
Do Nothins
Positive Benefits Neqatives
Lowest Cost Does not address the current parkinq deficit
Still out of compliance with current City of Spokane parking
code
Frustration from neighbors due to employees parking in front of
their houses.
At risk if BNR lease is ever lost.
Ongoing Parking (O&M) Cost
S3oo
Szso
s2oo
s1s0
$i.oo
Sso
So
Alternate 1 Alternate 2
Ongoing O&M costs include snow removal, crack seal, seal coat, and asphalt renewalat 15 years.
Parking Garage useful life based on 45 years.
See attached PowerPoint Presentations for high level explanations
Ec(!
o-c!-
I
Preferred
Business Case Justification Narrative Page 19 of20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 290 of 325
Campus Repu ng Phase 2
APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Campus Repurposing
Phase 2 plan and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Section1.l. The
undersigned also that significant changes to this will be coordinated
with and approved ndersig or their designated representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Eric Bowles
Business Case Owner
Manager, Facilities
Date:sf, lrt
Date L1-Zg_t-7
-A* S2"*O"U-Date çl ,l (t
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory Com mittee Review
VERSION HISTORY
Tem plate Version : 02124 1201 7
Vercion lmplemented
By
Revleion
Date
Approved
By
Approval
Dato
Reason
1 Eric Bowles 04t24117 Heather Rosentrater 04t25t17 New template
Business Case Justification Narrative Page 20 of 20
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 291 of 325
Company Aircraft Capital
Requested Spend Amount $3,000,000
Req uesting Organ ization/Department Travel& Flight
Business Gase Owner David Robinson, Chief Pilot
Business Case Sponsor Anna Scarlett, Manager of Shared Services
Sponsor Organization/Department Shared Services
Gategory Project
Driver Performance & Capacity
1 GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Steering Committee:
o Manager of Shared Serviceso Chief Piloto Captaino Director of Finance. Legal Counsel
Advisors may contribute input, approvals, or information as needed, and include
o Vice President of Energy Deliveryo Financial Planning and Analysiso Executive travelers
2 BUSINESS PROBLEM
Avista currently operates a 1999 Cessna Citation Vll aircraft in support of all
company business units and subsidiaries. Approximately 50% of legs flown are in
direct support of utility regulatory activities with the remainder in support of regional
Avista offices and various business undertakings. A large portion of these
destinations are not served by an airline.
Avista has leased the company aircraft from PNC Aviation Finance since February
2000. ln March 2018, the current 3-year lease of the company aircraft expires. The
lease contains an end-of-term purchase option that applies lease payments made
towards the purchase in a lump-sum amount.
The current lease requires 360 days' notice of intent to purchase or return the
aircraft. Avista was granted a 30-day extension by PNC to this requirement. This
extension expires on or about April 5, 2017.
The current lease requires Avista to carry an engine and auxiliary maintenance
service plan, which expires at the end of 2018 and will cover major overhauls of
both engines. One engine received this overhaul in March 2017 and the other
engine is expected to be due for overhaul in the next two years. Avista also carries
a separate ProParts parts plan, which we can terminate without penalty with 30
days notice.
Business Case Justification Narrative Page I ofS
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 292 of 325
Company Aircraft Capital
Usage Number of
Trips
Houn¡Top 3 Destinations
2014 216 234 1 .Olympia 2.Medford 3.Seattle
2015 222 253 1 .Olympia 2.Boise 3.Seattle
2016 215 226 1 .Olympia 2.Salem 3.Medford
Avista will be required to upgrade the avionics to comply with Federal Aviation
Administration (FAA) ADSB-OuI mandate before January 1,2020.
3 PROPOSAL AND RECOMMENDED SOLUTION
A work group was convened in 2016 to complete a cost and revenue analysis of
four option. Data and conclusions were updated March 2017 (see attachments).
The cost of the current lease is approximately $1.2 million per year.
Option I (Recommended) - Purchase current aircraft:
This includes purchasing the aircraft at a cost of approximately $2.5 million,
modifying the avionics to comply with the FAA ADSB-OuI mandate at a cost of
approximately $500k, and self-funding the parts plan. This option would save $1.1
million O&M annually by eliminating the lease payments, assuming we self-fund
the parts plan beginning in 2018 and discontinue the engine and auxiliary MSPs at
the end of 2018.
Timeline
o JanuarV 2018: Avionics upgrade to comply with FAA mandate.
o March/April 2018: Complete aircraft purchase.
Option Capital
Cost
Start Gomplete Risk
llllitigation
1. Recommended:
Purchase/Upg rade Current
Aircraft
$3M 01t2018 04t2018
2. New 3 -year lease $0 03t2018 03t2021
3. Alternate transportation $0 03t2018 $1.5-2.2M
Return
Payment
costs
4. Purchase new aircraft $1 5M 01t2018 12t2018 $1.5-2.2M
Return
Payment
costs
Business Case Justification Narrative Page 2 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 293 of 325
Company Aircraft Capital
Option 2 - New 3 year lease:
Renegotiation of the lease is not provided as an end of term option, but
presumably a lease could be negotiated such that it supersedes or othenruise
cancels the existing lease.
lf we renew the existing lease for a term of three years, the cost would be $1.79
million O&M in years 1 thru 3. The cost analysis assumes Avista would purchase
the aircraft at the end of the lease term and operate it seven additional years. The
same condition regarding parts and engine programs as in Option 1 apply.
Option 3 - Return aircraft and use alternate transportation:
Avista could end the current lease and, rather than extend or exercise the
purchase option, we could choose to return the aircraft at the end of the lease. The
cost of ending the current lease and returning or selling the aircraft would be
between $1.5 million and $2.2 million as detailed below:
. Exercising this option would require Avista to pay an "aircraft return payment"
of $2,185,008 (per Schedule No. 2-A to lease supplement.)o Avista may attempt to sell the aircraft and reduce the aircraft return payment
by any proceeds in excess of the "maximum lessee amount" of $1,659,984.o At an estimated market value $2.3 million, Avista could reduce the aircraft
return payment by approximately $640,000, to a net cost to Avista of
$1,545,000, less selling costs.
Should Avista exercise the option to return the aircraft, travelwould be through
one of the alternatives below:
4.1 Aírline
Most legs flown are to destinations that don't have regular airline service. This
would require flying to the nearest airline airport and driving, sometimes a
considerable d istance.
4.2 Charter
There are currently no charter aircraft available in the Spokane area. Aircraft
would need to come from outside the area (Seattle). These empty legs are usually
charged at the full rate to the customer. Charter is also not usually available on
short notice. Cost per flight hour is approximately the same as ownership.
4.3 Fractional
Fractional ownership is owning a part (usually %) of an aircraft. Shares are usually
sold in 50 hour blocks. At Avista's current usage rates would require 4 shares or
full ownership. Cost per share information is hard to come by. Fractional operators
want you to show serious interest before they will talk specific dollar amounts. The
assumption is that for similar aircraft flying Avista's typical missions, the cost per
flight hour would be approximately the same as sole ownership of an aircraft.
Aircraft are controlled by the managing company and would have to come from
outside the area.
Business Case Justification Narrative Page 3 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 294 of 325
Company Aircraft Capital
Option 4 - Purchase new aircraft:
Avista could elect to return the existing aircraft (subject to return costs described
above) and purchase a new aircraft with comparable capabilities. The plane
considered has added fuel efficiency and a longer range (Gulfstream 150) would
cost $15M capital in 2018. O&M costs would be approximately $0.63M in year 1
and would increase as items come off warranty. A new aircraft would have a
minimum life of 20 years. This option has the highest revenue requirement over
time.
Existlno Lease
Lease Payments
Operat¡ng costs
Total $2.21
Rencw Lea¡e
$ ln Millions
Purchasc Exist. Plano
$1.26
0.95
Annual Budgot
Year 1
Caoital
$0
o&M
$1.79
1.79
1.79
0.59
0.6
o.71
0.63
0.64
0.46
o.ø7
RevReo
$1.91
1.90
1.88
0.62
0.63
0.74
0.65
0.67
0.79
0.70
CaÞ¡tål
$2.75
o&M
$0.s3
0.54
0.66
0.57
0.59
,..o.7
0.62
0.63
0.75
0.67
RevReq
$1.1s
1.12
1.20
1.07
1.05
1.14
1.02
1.00
1.'t1
1.00
Cap¡tal
$11.00
o&M
$0.53
0.55
0.66
0.58
0.59
0.7
0.62
0.63
0.75
0.66
RevReq
$2.30
2.19
2.19
2.OO
1.94
1.98
1.82
1.77
1.85
1.72
2
3
4
5
6
7
I
9
10
Present Value 9.66 7.91 22.8
See attachments; Corporate Aircraft Analysis 2016 and Aircraft Analysis-March 2017 for
supporting documentation.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 295 of 325
Company Aircraft Capital
4 APPROVAL AND AUTHORIZATION h¡cr"-(f C^çìt*r
TheundersignedacknowledgetheyhavereviewedtheA,iffiarplanand
agree with the approach it presents and that it has been approved by the steering
committee or other governance body identified in Section1.1. The undersigned
also acknowledge that significant changes to this will be coordinated with and
approved by the undersigned or designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
David binson
Date: {-Z- t7
Date:ç/, 1t
Date 4-2tr-r-7
Chief Pilot
Business Case Owner
LS
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory mem ber
5 VERSION HISTORY
Tem pf ate Version : 0212412017
Verclon lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1 David
Robinson
04t25t17 Heather
Rosentrater
04t25t17 New Template
Business Case Justification Narrative Page 5 of 5
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 296 of 325
Ergonomic Equipment
1 GENERAL INFORMATION
Requested Spend Amount $900,000 over 3 years
Requesting Organization/Department Facilities
Business Case Owner Lindsay Miller, Facilities Project Manager
Business Case Sponsor Anna Scarlett, Shared Services Manager
Sponsor Organization/Department Shared Services
Category Project
Driver Performance & Capacity
l.l Steering Committee or Advisory Group lnformation
A stakeholder group was formed in 2015 to evaluate this program. Stakeholders
were George Brown, Eric Bowles, Mark Gustafson and Mike McAllister. They
rev¡ewed mater¡als and made recommendations to leadership regarding the
direction moving forward. They approved submission of the business case for the
initial roll out of equipment. This initial roll out will cover the cost of new ergonomic
equipment. Beginning in 2018, the subsequent equipment will be funded out of
the furniture business case.
Steering Committee
o Eric Bowles, Facilities Managero Lindsay Miller, Project Manager. Oona Timmons, Nursing Services Supervisor
Advísors may contribute input, approvals, or information as needed, and include:
. Vice President of Energy Deliveryo End Users
2 BUSINESS PROBLEM
Research from the Texas A&M Health Science Center School of Public Health
indicates that standing desks as ergonomic interventions can improve physical
health among employees and may also positively impact their work productivity.
More from the study:
htto://www.tandfonli e. com/d oi I absl 1 0 . 1 080 121 577 323.20 1 6. 1 183534?tokenDomai
n=eprints&tokenAccess=km4nB42SSqEGEqwTBwjz&forwardService=showFullTex
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83534&iou rnalCode= uehf20
90% of Avista's ergonomic requests have been for siVstand workstations. Avista
previously had an ergonomic program that required employees to complete a
symptom survey and demonstrate need when making a request for ergonomic
additions to work stations. We only provided ergonomic equipment once it had
been proven through an ergonomic evaluation that the employee was in need of
intervention, often after an employee had already begun experiencing issues.
Business Case Justification Narrative Page 1 of6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 297 of 325
Ergonomic Equipment
Employees have sought services at our clinic and outside to help reduce
symptoms associated with a variety of injuries exacerbated by their work station.
Treatments include surgery, physical therapy and massage therapy.
Avista is self-insured, and healthcare costs are directly impacted by employee
health and wellness. Between 2011 and 2014 we saw an average of 4.5
recordable injuries each year, under our self-insured workers compensation
program, that were specifically related to an ergonomic issue. The average cost of
those claims was $4,066 per claim. Each claim, from start to finish, takes an
average of 8 hours of labor for Oona Timmons, Nursing Services Supervisor, and
one hour of labor for Melanie Steele to complete. Total cost per claim, in labor, is
$599.40.
3 PROPOSAL AND RECOMMENDED SOLUTION
Estirnated Total Costs, lncluding lnjury Claims,
Ergo Evaluations, Treatments and Services
$soo,ooo
s400,000
s3oo,ooo
s200,000
s100,000
s-
2021,
Option I (Recommended) - lmplement a proactive ergonomic program
2016 20L7
tr Recommended
2018 2019 2020
llAlternative 2 LlAlternative 3
Option Capital
Gost
Start Complete Risk
Mitigation
1. Recommended: Proactive
Ergonomic Program (as-requested)
Costs for new Ergonomic equipment
$900,000 0712016 12 2018
2. Use a less expensive product list and
respond to ergonomic issues once
they arise.
Costs for new Ergonomic equipment
$600,000 0712016 12t2018
3. Return to previous process of
responding to requests with
ergonomic evaluations (as-needed)
$0 N/A
Business Case Justification Narrative Page 2 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 298 of 325
Ergonomic Equipment
This option proposes to implement an ongoing program where all employees
requesting ergonomic equipment will receive it, with no requirement of an
ergonomic assessment or other proof of need. A proactive program has the
following benefits:
lncreased employee engagement in ergonomic programs and education, by
encouraging employees to take responsibility for maintaining their health and
wellness at their workplace.
Decreased time and cost of ergonomic equipment deployment by removing
evaluations and approvals and standardizing equipment and installation.
Prevention of workplace injuries and health impacts and reduction of the costs to
the company and our customers, as well as to employees, associated with these.
CosUresources:
The newest option to be funded out of this project is the Vari-Desk, which costs
under $400 and takes up to an hour of facilities labor and about 30 minutes of lT
labor to install. Included in the program are ergonomic chairs, monitor arms and
ergonomic lT hardware. The overall costs of the program are higher up front, but
the program is expected to reduce long-term costs of health and wellness
programs and services.
Other program benefits:
. Participants of the program receive tools including the Ergonomic Reference
Guide. Employees can use this document as a starting off point for their
ergonomic self-assessment. The guide identifies various areas of
ergonomics that employees can pinpoint and implement on their own and
can also help them recognize areas where our other tools may help.o When employees receive new equipment they are provided with the Nerø
Workstatíon Handoul which provides tips and tricks to make better use of
their new equipment.o Avista provides a location for resources on our Intranet that employees can
access. This includes videos on how to adjust our standard chairs and
additional documentation and case studies regarding ergonomics.o Education is ongoing included in a TED talk series we provide once a month
as a "lunch and learn".. After ergonomic deployment, employees receive a follow up survey at the 3
month, 6 month and 1 year mark. This is to ensure they are still using the
equipment and that the equipment is working for them. This survey also
includes reminders and tips and tricks to help keep employees engaged.
a
a
Business Case Justification Narrative Page 3 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 299 of 325
Ergonomic Equipment
s350,000
s300,000
s2s0,000
s200,000
s1s0,000
s100,000
Sso,ooo
s-
Option L: Recommended
2016 2017 2018 2079 2020
-Ergonomic
Equipment
-Est¡mated
Health and Welness Spend for Ergonomic Needs
202r
Option 2 - Less expensive equipment
The team researched less expensive products, including chairs and siU stand
stations. This option was not preferred for the following reasons:
o The siU stand products do not have the same weight capacity that the Vari-
Desk does.. The equipment options were less expensive but also less durable. Units
would require more frequent replacement over time.o The less expensive seating options have fewer functions that provide
ergonomic relief and would not provide the benefit to employees that the
more robust equipment does.
Option 2
s3so,o00
s3oo,ooo
s2so,ooo
s2oo,ooo
s1so,o00
s100,000
Sso,ooo
s-2016 2077 2018 2019 2020
-f
¡gs¡ernic Equipment
-Estimated
Health and Welness Spend for Ergonomic Needs
202L
Option 3 - Respond to requests with ergonomic evaluations (as-needed)
Business Case Justification Narrative Page 4 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 300 of 325
Ergonomic Equipment
From 2013-2015, new ergonomic requests required an ergonomic evaluation to
determine the need for a siUstand station. Each evaluation cost $150 and was
charged back to the employees department. We required the manager to approve
all recommended ergonomic evaluations prior to proceeding with the evaluation.
Between 2013 and 2015, we spent $11,250 on Ergonomic Evaluations. Once it
was determined that a siUstand is necessarV, we would then deploy the equipment.
Prior to 2015, we used either a motorized station or an elevated standing desk.
The motorized station cost approximately $600 plus labor to install on the front end
and, in the event of a move, another 5-6 hours for turn around. An elevated
standing desk, which is just raising the original desk, had minimal costs from a
material standpoint but much greater costs in labor. Labor for this install included
roughly 5 hours with original set up then, if an employee had to be moved, it would
take another 5 hours to set up and 2-3 hours to turn to other station back to the
standard design.
We moved away from this approach to our proactive program (Option 1) approach
because of the following considerations:' o Installations took longer and cost more under the previous program.
. Employees were forced through an evaluation and approval process, and
often received ergonomic equipment only after they began experiencing
issues.
Option 3
s3s0,000
s300,000
s2so,ooo
s2oo,ooo
s1s0,000
s100,000
$so,ooo
s-2016 2017 2078 2019 2020
-Ergonom¡c
Equ¡pment
-Estimated
Health and Welness Spend for Ergonomic Needs
2027
Business Case Justification Narrative Page 5 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 301 of 325
Ergonomic Equipment
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Ergonomic Equipment plan
and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Date I
Date: Li-Lî.N
Template Version: 03101 12017
'l/01
Lindsay Mi
Facilities Project Manager
S-"--e.fr-ç/,1,',Date
Anna Scarlett
Shared Services Manager
Business Case Sponsor
lI.,* h
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory Com m ittee Review
5 VERSION HISTORY
Vetgion lmplemented
BY
Revielon
Date
Approved
EV
Approval
Dats
Reason
1 Lindsay Miller 04/25n7 Heather
Rosentrater
04/25/17 New template
Business Case Justification Narrative Page 6 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 302 of 325
Airport Hangar
Requested Spend Amount $1,500,000
Req uesting Organ ization/Department Facilities
Business Gase Owner Eric Bowles, Facilities Manager
Business Case Sponsor Anna Scarlett, Manager of Shared Services
Sponsor Organ ization/Department Shared Services
Category Project
Driver Performance & Capacity
1 GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Steering Committee:
o Facilities Manager. Manager of Shared Serviceso Chief Piloto Captaino Project Manager, Facilitieso Real Estate Manager
Advisors may contribute input, approvals, or information as needed, and include:
o Vice President of Energy Deliveryo Executive Officers
2 BUSINESS PROBLEM
Avista currently subleases a hangar owned by Spokane lnternationalAirport and
leased by the airport to Merlin Enterprises, for secure storage and maintenance of
our company aircraft and for daily operations by the flight crew. Avista will lose the
sublease on the hangar after July 31,2018, at which time Merlin's lease will end.
At that time, airport management plans to demolish the existing hangar as part of
a plan to reclaim the existing property and relocate private hangars tô a different
part of the airport. At that time, Avista will need to secure a new hangar for the
aircraft.
Business Case Justification Narrative Page 1 of6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 303 of 325
Airport Hangar
3 PROPOSAL AND RECOMMENDED SOLUTION.
Four options were considered for securing a hangar for the aircraft, including
building a new hangar, extending use of the current hangar, relocating to another
airport, and co-use of an existing hangar.
Option 1 (Recommended): Build a new Avista-owned hangar on land leased
directly from Spokane lnternational Airport.
This solution is recommended for the following reasons:
o Spokane lnternationalAirport is convenient to headquarters.
o The airport is currently offering a good selection of plots, with good
approaches and footprints that would allow easier separation of the public
entrance from the secured part of the airport.
o We could secure a long-term lease with the airport and lock in lease
payments. Current discussions include a lease term of up to 50 years.
o Construction in 2018 would allow us to take advantage of lower interest
rates and construction costs than what we would likely get in 2019 or 2020.
r Leasing directly from the airport will allow us to de-ice and fuel the aircraft
ourselves or through a contractor we select, rather than having to use the
airport's services exclusively, saving costs and increasing efficiency.
o Constructing the hangar would allow us to design a structure with the future
in mind. The current aircraft has an expected life of up to 20 years, and a
new aircraft would change the required size of height and width of the
hangar. A new hangar would include the following elements (see
schematics):
o Ample plane storage and room for maintenance and maneuveringo Minimal parts storageo Restroomso Offices for flight staffo Secure parking with Avista accesso Separate unsecured and secured areas for travelers
Optlon Gapltal Goet Start Complete Rlsk
ftllitlsatloÍr
1. Recommended: Build a new Hangar
at Spokane lnternational Airport.
$1,s00,000 01 2018 122018
2. Extension of the existing sublease $o I 2018 10 2019
3. Co-Lease an existing structure with
another plane.
$o N/A
4. Find a location at another Airport.N/A N/A
Business Case Justification Narrative Page 2 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 304 of 325
Airport Hangar
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Business Case Justification Narrative Page 3 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 305 of 325
Airport Hangar
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Option 2 - Direct lease from Spokane airport
We ¡ooked into pursuing an extension of the existing sublease, and confirmed that
we can convert our sublease into a direct lease with the airport and stay in the
existing hangar temporarily. However, because of airport management's plans for
vacating theland the current hangar is on, we would be able to do this for a
maximgm of 6-12 months, and we would need to be in negotiations with the airport
on a long term solution.
Option 3 - Share existing hangar
There is currently one hangar at the Spokane lnternational Airport large enough
and with owners who would consider co-leasing with Avista. Avista would not have
ownership of this building, which presents several challenges:
. Sharing space with co-lessor(s) would require additional security measures
to protect our aircraft and ensure the security of our network (located in the
office of the flight crew). These measures could require additional
construction of secured entrances and areas and/or hiring security
personnel, and would need to be coordinated with and approved of by any
co-lessors, at Avista's cost.
o There is also a concern about damage to the airplane. The plane would be
stored in tight quarters alongside another aircraft, and damage is more
likely to occur as planes are maneuvered in and out of the hangar'
Business Case Justification Narrative Page 4 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 306 of 325
Airport Hangar
Maintaining the aircraft and keeping it secure from co-lessor's employees
and/or mechanics would present a security logistical challenges as well.
. Currently we do not have to coordinate departures or arrivals with another
entity. Co-leasing would require us to share flight information and
coordinate our departures and arrivals with our co-lessor.
o Additional future co-occupants could be brought in and affect Avista's use
of the hangar.
Option 4 - Store at another airport
A. Felts Field was looked into as an option to move the plane but the runway is
not long enough. A 7,000-ft runway minimum is required to safely land and
takeoff with our current aircraft.
B. The Coeur d'Alene airport was researched as a solution. There are no
options to lease an existing hangar available; however there is the
possibility of building a hangar at that location. The cost of building a
hangar at the Coeur d'Alene Airport would be the same or comparable as
building a hangar at the Spokane lnternational Airport, but would increase
overall travel time and cost for employees having to drive to Coeur d'Alene
for flights.
Business Case Justification Narrative Page 5 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 307 of 325
Airport Hangar
4 APPROVAL AND AUTHOR¡ZATION
The undersigned acknowledge they have reviewed the Airport Hangar plan and
agree with the approach it presents and that it has been approved by the steering
committee or other gove rnance body identified in Section1.1. The undersigned
also acknowledge that ificant changes to this will be coordinated with and
approved by the or their ignated representatives
Date:sSignature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
ric Bowles
Facilities Manager
Business Case Owner
S.¿n-oate:sf¡/,t
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
h Date: ¿( - >î-n
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory mem ber
5 VERSION HISTORY
Tem plate Version : 0212412017
Vercion lmplemented
By
Revision
Date
Approved
BY
Approval
Data
Reason
1 Eric Bowles 04125117 Heather Rosentrater 04t25117 New template
Business Gase Justification Narrative Page 6 of 6
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 308 of 325
Fleet Seryrces Capital PIan
I GENERAL INFORMATION
Requested Spend Amount $7,700,000
Requesting Organ ization/Department Fleet
Business Case Owner Greg Loew, Manager, Fleet Services
Business Case Sponsor Anna Scarlett, Manager, Shared Services
Sponsor Organ ization/Department Shared Services
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Fleet capital replacement program is based on the Vehicle Replacement
Model that is a product of our Utilimarc benchmarking subscription. The model
uses benchmark data, purchase and auction data, combined with nationwide
vehicle information that Utilimarc uses to build an accurate and robust model. The
Fleet Specialist for Capital then takes the results of the model to validate, verify
usage and work with operations managers to ensure that the identified unit meet
their business needs. Capital projects requests are created for each discrete
project (vehicle/equipment) that is approved by the Fleet Manager with notifications
to the Manager of Shared Services and the Vice President of Operations.
2 BUSINESS PROBLEM
Fleet equipment as it ages experiences a growth in cost related to its operation.
Those costs are driven by the requirement of more parts and more labor required
to keep that unit up and running. As your fleet's average age increases you will see
a steady but accelerating trajectory of costs servicing hours required. lt can be
described as more complex repairs requiring more hours and parts to fix. Those
increasing costs are not just the burden of Fleet; the users will see the impact in
lost productivity/downtime. ln a 2011 analysis of Avista's class 46 vehicles and a
subsequent analysis done in 2016 saw a 52o/o reduction in the labor hours required.
per truck by bringing the classes average age from 9.5 years to the industry
average of 5.5 years.
2010 201 1 2012 2013 2014 201 5
AVA Avg
Age
8.03 7.81 7.59 6.81 6.55 6.23
lndustry
Avg Age
6.11 6.27 6.27 6.56 6.53 6.38
Avg Op
Cost / Unit
$10,924 $11,558 911,534 $10,845 $9,739 $9,285
Business Case Justification Narrative Page 1 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 309 of 325
Fleet Seryices Capital PIan
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Gapltal Cost Start Gomplete
Option 1 (Recommended): Fully fund
replacement program
$7,700,000
Option 2: Paftially fund program $3,700,000
Option 3: No funding 0
Ootion I lRecommended) - Fu lv Fund Reolacement Proqram
The Fleet asset model is optimized for the lowest total cost of ownership. Our life cycle
model seeks the goal of balancing risk and limited investment dollars. The model allows
Fleet to provide users with a reliable and safe tool that is ready for work at any given
moment. The fully funded option allows our capital purchasing model of equipment to
continue replacing aging equipment in a predictive manner that keeps technician
staffing levels constant to the predictive number of repair work orders generated. The
program does not include additions to the existing fleet. The analysis of the data by
Utilimarc shows that this fully funded model over time will yield the lowest cost per
vehicle.
The recent large outages from the summer of 2014 and November 2015 show the
strength of our fleet. During those thousands of hours of combined operation we only
had two minor breakdowns that we were able to quickly repair and return to service
before the start of the operator's next shift.
The customer benefits from this in two distinct ways. One, that crews are quicker to
respond to issues because they operate reliable equipment that can be ready for duty.
Two, that costs for customers remain steady from a fleet cost perspective because we
have a constant investment in the equipment along with a progressive maintenance that
has a monthly average over 95% of vehicles ready for duty. By pursing the
recommended investment path we avoid rising maintenance costs, outside of economic
inflationary trends, and increasing down time due to mounting demand repair work
orders. Additionally, this investments allows us to purchase equipment that has modern
emissions controls or alternative energy sources allowing us reduce carbon emissions
from our fleet vehicles.
Option 2 - Partiallv Fund Replacement Prosram
The partially funded, option 2 continues to replace vehicles but at reduced amount when
compared to the recommended option. The combined ownership and maintenance
costs to appear to be nominally less in costs over the time of the model. However what
you see is a rapidly aging fleet in the last two thirds of the model which have increasing
work order counts for repairs and significant impacts to reliability/uptime not shown in
the total fleet costs.
Business Case Justification Narrative Page 2 ot 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 310 of 325
Fleet Sen¡ices Capital PIan
Option 3 - Do Not Fund Replacement Program
Option 3 is a plan designed to replace a unit only at failure. This model has rapidly
increasing costs due to significant repairs required. This model will require increasing
numbers of repair work orders to be assigned to outside vendors since company
technicians will be able to handle only incrementally more work than today. This outside
work has a higher price per hour and higher parts costs due to vendor markups. This
model will lead to increasing down time of equipment as it ages. The repairs will
become more costly and consume more technician time. lncreasingly, even with the
best preventative maintenance plan, there will be unplanned failures in the field downing
a crew while the issue is addressed. This model was practiced at Avista for over 20
years and led to clusters of vehicles failing at approximately the same time and creating
capital constraint issues.
Vehicle Replacement Analvsis
The following information demonstrates the effect of three different replacement
strategies on Avista's Fleet performance. Three projections were built using Utilimarc
Vehicle Replacement Model (VRM) to show the effect of different levels of capital
commitment on fleet maintenance cost, ownership cost, average age, and demand
repairs. ln the Full Budget (Option 1) scenario, vehicles are replaced in line with each
vehicle's calculated, optimal, lifecycles with an annual capital cost starting at
approximately $8,000,000. The Half Budget (Option 2) scenario cuts the annual
replacement budget in half to start at approximately $3,700,000. The No Budget (Option
3) scenario restricts the annual capital cost to $0.
Summary
The table below shows the effects of each budget on annual vehicle ownership and
maintenance cost for Avista's fleet. The full projections are provided on the pages to
follow.
AnnualVehicle Ownership and Maintenance Cost
FullBudget
Half Budget
No Budget
2016
$9,588,817
$9,439,904
$9,350,935
2020
$9,735,956
$9,274,112
$9,145,384
2025
$10,604,849
$1 0,1 97,1 51
$10,854,088
2030
$11,700,794
$1 1,658,431
$13,913,603
Avista's fleet is currently ahead of its ideal lifecycle. This is shown by the increase in
average age we see under even the Full Budget scenario. Because of this, the No
Budget scenario is marginally cheaper in the first few years of the projection (<2%).
However, by the 1Sth year, the No Budget scenario is 19% higher than the two
alternative scenarios. Avista would also see average age increase from 9.0 years to
over 20 years under this worst-case scenario.
The Full Budget scenario is marginally more expensive then the Half Budget scenario in
these projections, but will begin to outperform the Half Budget scenario beyond the 15th
year. While their total costs are comparable, the Full and Half Budget scenarios differ in
how money is being spent. Under the Full Budget scenario, capital investment is larger
each year, but maintenance costs are significantly lower. The Full Budget scenario also
offers younger units for the crews to operate (average age of 9.22 in the 15th year) vs
Business Case Justifìcation Narrative Page 3 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 311 of 325
Fleet Seryices Capital Plan
14.74 in 1sth year) and fewer demand repairs (7 ,082 work order in the 1Sth year).
Conversely, The Half Budget scenario sees a smaller capital investment each year, but
the unit for the crews to operate will be older (average age of 14.74 in year 15) and will
see more demand repair (9,671 work orders in the 1Sth year).
Vehicle condition, availability and downtime should also be considered in these
scenarios. ln order to maximize safety, reliability and responsiveness for customer
needs, including emergency outage restoration, vehicles should be equitable in terms of
standards and in optimal working condition.
Assumptions
a
a
lnflation: All capital, ownership and maintenance costs are increase annually be
2o/o to account for inflation.
Consistent Replacement: The replacement model is programed to replace a
consistent number of unit each year to achieve more predictable capital
requirements and avoid replacement bubbles. When many vehicles are
concentrated in relatively few vintages, these "bubbles" can cause sudden
increases in parts and labor cost, vehicle downtime, and technician requirements.
Replacing a constant number of unit each year avoids this problem, but
consequently the model will occasionally replace a unit before it reaches in
lifecycle or let a unit run beyond its lifecycle.
Maintenance: Maintenance cost includes the cost of all parts and labor needed to
maintain the asset over the course of its lifetime. Note that maintenance cost does
not include the cost of fuel or any administrative or corporate overheads. While
there will be some fuel efficiencies associated with running younger vehicles, the
unpredictable nature of the price fuel make it difficult to quantify the savings
associated with these efficiencies.
Maintenance Savings: The replacement model maintains a constant cost per
wrench-turning hour of technician labor. This means that when maintenance cost
increase or decrease, the model adjusts staffing levels to meet the increased or
decreased demand for labor. This should be considered alongside historic
overtime and contract labor practices when interpreting these results.
a
o
Business Case Justification Narrative Page 4 of M
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 312 of 325
Fleet Sen¡ices Capital Plan
Gost Tables
FullBudget
Annual Maintenance (Parts, Labor,
Vendor) Gost
Annual Ownership Cost
AnnualGapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
3.7M Budget
Annual Maintenance (Parts, Labor,
Vendor) Cost
Annual Ownership Gost
Annual Gapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
No Replacement
Annuàl Maintenance (Parts, Labor,
Vendor) Gost
Annual Ownership Gost
AnnualGapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
2016
$4,742,786
$6,559,724
$8,010,456
112
8.47
134
6,609
2017
$4,856,108
$6,390,102
$7,625,997
106
8.38
110
6,637
2018
$4,976,095
$6,363,332
$8,550,766
106
8.36
74
6,660
2019
$5,129,998
$6,262,211
$7,983,602
103
8.42
57
6,711
2020
$5,303,926
$6,210,697
$8,457,832
104
8.51
41
6,768
2016
$4,945,378
$6,130,531
$3,719,912
50
9.11
186
6,899
2017
$5,262,213
$5,589,192
$2,905,936
44
9.59
203
7,191
2018
$5,553,296
$5,260,460
$4,096,366
50
10.01
202
7,434
2019
$5,876,138
$4,914,123
$3,574,700
46
10.47
238
7,694
2020
$6,1 94,1 99
$4,665,065
$3,664,350
47
10.92
247
7,942
20'16
95,236,220
$5,735,049
$-
2017
$5,756,008
$4,936,895
$-
2018
$6,296,020
$4,259,317
$-
$6,859,429
$3,682,958
$-
$7,436,489
$3,191,696
$-
2019 2020
9.77
281
7,276
10.76
322
7,828
11.74
403
8,380
12.71
457
8,932
13.69
572
9,485
Business Case Justification Narrative Page 5 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 313 of 325
Fleet Seryices Capital Plan
FullBudget
Annual Maintenance (Parts, Labor,
Vendor) Gost
Annual Ownership Cost
AnnualCapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
3.7M Budget
Annual Maintenance (Parts, Labor,
Vendor) Gost
Annual Ownership Cost
AnnualGapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
No Replacement
Annuai Mainténance (Parts, Labor,
Vendor) Gost
Annual Ownership Cost
AnnualGapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
2021
$5,469,634
$6,231,649
$8,744,956
103
8.62
34
6,834
2022
$5,626,095
$6,252,235
$8,763,990
111
8.65
40
6,880
2023
$5,806,710
$6,244,883
$8,633,034
101
8.77
41
6,945
2024
$5,936,489
$6,383,525
$9,629,551
106
8.83
38
6,956
2025
$6,088,050
$6,422,122
$8,990,833
103
8.93
32
6,990
2021
$6,505,655
$4,509,902
$4,301,788
49
11.35
307
8,1 69
2022
$6,847,961
$4,243,790
$3,281,927
45
11.80
330
8,404
2023
$7,168,380
$4,133,092
$3,841,499
46
12.23
366
8,618
$4,613,173
50
12.60
400
8,790
$4,025,692
46
13.01
418
8,985
2024 2025
$7,465,391 $7,801,053
$4,111,033 $4,009,498
2021
$8,036,849
$2,772,141
$-
2022
$8,660,759
$2,413,132
$-
2023
$9,299,771
$2,105,273
$-
2024
$9,958,388
$1,840,887
$-
2025
$10,638,865
$1,613,357
$-
14.66
620
10,037
15.63
681
10,588
16.59
734
11,140
17.55
769
11,691
18.50
793
12,242
Business Case Justifìcation Narrative Page 6 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 314 of 325
Fleet Sen¡ices Capital Plan
FullBudget
Annual Maintenance (Parts, Labor,
Vendor) Gost
Annual Ownership Cost
AnnualGapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
3.7M Budget
Annual Maintenance (Parts, Labor,
Vendor) Cost
Annual Ownership Cost
AnnualCapital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
No Replacement
Annual Maintenance (Parts, Labor,
Vendor) Cost
AnnualOwnership Cost
Annual Capital Budget
Units Replaced Annually
Average Age
Units Out of Lifecycle
Annual Demand Repair Work Orders
2026
$6,226,667
$6,549,886
$9,764,701
112
8.93
23
6,995
2026
$8,099,925
$3,998,122
$4,534,552
50
13.34
422
9,1 36
2027
96,411,144
$6,593,568
$9,296,048
r06
8.95
20
7,048
2028
$6,535,809
$6,783,330
$10,423,336
106
9.02
16
7,045
2029
$6,698,371
$6,851,754
$9,731,966
103
9.13
17
7,074
2030
$6,853,080
$6,967,321
$10,310,050
't04
9.22
19
7,092
2027
$8,432,876
$3,899,631
$3,542,320
44
13.75
443
9,314
2028
$8,704,428
$3,982,001
$4,993,447
50
14.06
459
9,419
2029
$9,019,315
$3,957,415
$4,357,539
46
14.41
477
9,555
2030
$9,318,223
$3,994,430
$4,466,822
47
14.74
497
9,671
2026
$11,342,717
$1,417,138
$-
2027
$12,068,385
$1,247,603
$-
2028
$12,823,413
$1,100,859
$-
2029
$13,603,405
$973,611
$-
2030
$14,412,019
$863,098
$-
19.46
828
12,793
20.41
860
13,343
21.36
889
13,894
22.31
921
14,444
23.25
940
14,994
Business Case Justification Narrative PageT o1 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 315 of 325
Fleet Services Capital PIan
Methodology
Annualized Total Cost
For each class, Utilimarc's Vehicle Replacement Module (VRM) determines what
lifecycle achieves the lowest cost to own and maintain an average asset over its
lifetime. This done by calculating the annualized totalcosf for each potential lifecycle.
Annualized cost total is the sum of all ownership and maintenance cost a unit obtains
over the coursè of its life, divided by the number of years the unit is in service.
Minimizing annualized total cost guarantees the lowest total cost over the life of the
asset. As an example, the table below shows the annualized cost for the possible
lifecycles of a light duty pickup truck.
1
2
3
4
5
o
Replacement Age
I
I
10
11
12
13
14
Annualized Total Gost
$5,964
$5,759
$5,598
$5,476
$5,390
5 337
$5,316
$5,345
$5,397
$5,472
$5,567
$5,682
$5,816
Deviation
3.1o/o
1.5o/o
1.60/o
3.0o/o
Consider the following three replacement scenarios over a 14-year financial period:
Scenario 1: A fleet manager plans to replace this vehicle every year. The annualized
cost of this replacement strategy is $7,811. Over the 14-year period, this replacement
strategy will cost fleet 14 x $5,946 = $83,244.
Scenario 2: A fleet manager plans to replace this vehicle every seven years. The
annualized cost of this replacement strategy is $5,810. Over the 14-year period, this
replacement strategy will cost fleet 14 x $5,313 = $74,382.
Scenario 3: A fleet manager plans to replace this vehicle every fourteen years. The
annualized cost of this replacement strategy is $6,913. Over the 14-year period, this
strategy will cost fleet 14 x $5,81 $ = $81,424
Business Case Justification Narrative Page I of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 316 of 325
Fleet Serurces Capital Plan
The table below summarizes the calculations in the previous example
Chosen
Replacement
Age
1
Financial Period
(Years)
14
Annualized
Cost
$5,946
Total Gost for Financial
Period
$83,244Scenario I
Scenario 2 7 14 $5,382 $74,382
Scenario 3 14 14 $5,816 981,424
This example illustrates that by minimizing annualized total cost achieves the lowest
total cost of ownership over the life of the vehicle. Utilimarc recommends replacing units
within 1.0% of the true lowest cost of ownership. This generally provides a three-year
range for replacement, which allows for flexibility when planning replacement without
dramatically affecting overall cost.
Business Case Justification Narrative Page 9 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 317 of 325
Fleet Seryices Capital Plan
Modelinq Ownership Cost
The Vehicle Replacement Model uses an exponential decay model to project the
ownership cost of an asset over its lifetime. Each asset is assumed to lose 18% of its
current book value every year as a cost of depreciation. This decay rate of 18% is
established based on historical auction information from companies across the industry.
Annualized Ownership Cost is calculated by taking the cumulative sum of each year of
depreciation for the asset and dividing by the number of years the asset is in service.
Continuing the example from the previous section, the graph below shows the
annualized ownership cost for a light pickup truck for each potential lifecycle.
Light Pickup Annualized Cost by Lifecycle
-Ownerships7,oo0
S6,ooo
s5,ooo
S+,ooo
S3,ooo
$z,ooo
Sr,ooo
(I,(lJ
(l.,ô-
øoUoöo(o
o
So t23456 789
Lifecycle (Years)
10 LL 12 13 L4 1-5
Business Case Justification Narrative Page 10 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 318 of 325
Fleet Services Capital Plan
Modelinq Maintenance Cost
The Vehicle Replacement Model uses a linear regression model to project the
maintenance cost of an asset over its lifetime. These class specific models are built
using historical, maintenance cost per mile data taken from the Utilimarc data. ln the
graph below, the red dots represent the average historical maintenance cost per mile for
a light pickup truck of each age. The red, dashed line represents the linear regression
model used to estimate the maintenance cost of an average pickup. The linear
regression model helps predict the increase cost of maintenance associated with
running older vehicles.
Light Pick Maintenance Cost Per Mile
So.60
o -O-i
-ttO
-to'-'-
---tt o a-o
g
oô-
P
o(J
OJ()c(EcoPc'õ
q.,
bo(E
OJ
aSo.so
$0.¿o
So.3o
So.2o
oo o 2-¡
t'ttt'O
aOOSo.1o R2 = 0.8657
s0.00 123456789 10
Age
tt t2 13 L4 15 16 77 18 L9
Business Case Justification Narrative Page 11 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 319 of 325
Fleet Seryrces Capital PIan
Annualized Maintenance Cosú is calculated by taking the cumulative sum of each year
of maintenance cost for the asset and dividing by the number of years the asset is in
service. The graph below shows the annualized maintenance cost for light pickup
trucks, based on the linear regression model and a calculated average annual mileage.
Light Pickup Annualized Cost by Lifecycle
-[\¡l¿i¡ls¡¿¡çg
(!o
o
CL
P
o(J
(lJ
oo(I'
o
S7,ooo
s6,0oo
Ss,ooo
s4,0oo
Sg,ooo
s2,0oo
s1,ooo
So 723456 789
Lifecycle (Years)
10 t! 12 13 74 15
Business Case Justification Narrative Page 12 of M
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 320 of 325
Fleet Sen¡ices Capital Plan
Modelino Annualized Total Cost
Annualized total cost is calculated by taking the sum of annualized maintenance and
ownership cost. The graph below shows the annualized total cost for a light duty pickup
truck. The target lifecycle is indicated by a green shaded zone. This is a visual
representation of the table from pg. 7 and demonstrates how the model identifies each
lifecycle.
Light Pickup Annualized Cost by Lifecycle
-Qvy¡s¡sþlp -
Maintenance mTotal ra,Eãþiiecvc le
S7,ooo
S6,ooo
rlJI ss,ooo
(lJï S¿,ooo
o! ss,ooo
bo(!b Sz,ooo
s1,000
So
L23456
--
¿-t'-
10789
(Years)
It L2 1.3 14 15
Business Case Justification Narrative Page 13 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 321 of 325
Fleet Senzices Capital Plan
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Fleet Services plan and
agree with the approach it presents and that it has been approved by the steering
committee or other governance body identified in Section1.1. The undersigned
also acknowledge that significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Date l-7
Date
Date 4-zr-q
Loew
Manager, Fleet Services
J*Sr--O'ffi--V,/,r
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Ll, h-
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory Com mittee Review
5 VERSION HISTORY
Tem pf ate Version : 03107 1201 7
Verelon lmplemented
By
Revislon
Date
Approved
By
Approval
Date
Reason
1 Greg Loew 04/25/17 Heather
Rosentrater
04/25/17 New template
Business Case Justification Narrative Page 14 of 14
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 322 of 325
Jackson Prairie Joint Proiect
1 GENERAL INFORMAT¡ON
Requested Spend Amount $ 1,626,667
Requesting Organ ization/Department Gas Supply
Business Gase Owner Jody Morehouse
Business Case Sponsor Jason Thackston
Sponsor Organ ization/Department Gas Supply
Gategory Project
Driver Performance & Capacity
1.1 Steering Committee or Advisory Group lnformation
The Risk Management Committee (RMC) oversees decisions to enter into a joint
projects such að Jackson Prairie Storage Project (JP). The RMC is comprised of
the following:
. Scott Morris, Chairman, President & Chief Executive Officer, Chair of Risk
Management Committee
¡ Dennis Vermillion, Senior Vice President Avista Corporation - President
Avista Utilities
o Mark Thies, Senior Vice President & Chief Financial Officer
. Marian Durkin, SeniorVice President, General Counsel, Corporate Secretary
& Chief Compliance Officer
. Jason Thackston, Senior Vice President Avista Corporation - Vice President
of Energy Resources Avista Utilities
o David Meyer, Vice President & Chief Counsel for Regulatory &
Governmental Affairs
o Ryan Krasselt, Vice President, Controller & Principal Accounting Officer
o Patrice Gorton, Director of Finance, Assistant Treasurer
. Tracy Van Orden (non-voting), Director of lnternal Audit
Additionally, the JP Management Committee meets quarterly to review and approve
the capital budget status for the current year as well as for vetting of any ongoing or
future expenseé. A business owner representative from each of the 3 partners has
final authority on the Committee. Currently, these representatives are
o Lynn Dahlberg of Williams NWP
. Ron Roberts of Puget Sound Energy
. Jody Morehouse of Avista'
2 BUSINESS PROBLEM
Avista must provide solutions for the following gas supply needs:
Business Case Justification Narrative Page I of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 323 of 325
Jackson Prairie Joint Proiect
o
A flexible, diverse portfolio with components that enable Avista to serve
customers during peak load demand'
Risk mitigation methods for shielding customers from extreme daily gas price
volatility during cold weather or other events affecting the natural gas
commodity market.
A mechanism or methodology for purchasing gas at lower prices during off-
peak periods for use during high cost periods.
3 PROPOSAL AND RECOMMENDED SOLUTION
No viable singular caPital Project options exist for replacing JP Storage at this time.
Because JP Storage Provides benefits/solutions for an array of business problems,
it's likely that in its absence,a combination of solutions would be packaged together
For meeting peak load requirements, an option is purchasing additional
leased pipeline transport on GTN at an estimated cost of $9,900,000 per year
for 90,000 dth/day at $0.30/dth. This expense would flow through the PGA.
Another solution that has been assessed in past Gas lRPs to meet peaking
needs and/or transport needs is to build an LNG storage facility. The capital
cost estimates have been in the multi-million dollar range and have proven
to be cost prohibitive. The timeline to design and build an LNG facility would
be 4 or more years.
Replacing the optimization benefit JP provides to customers with other
options would be difficult if not impossible. Over the 2016 - 2017 gas
procurement year, the storage optimization saved gas customers an
estimated $20,000,000. This benefit currently flows through the PGA.
Without storage, the flexibility is lost to purchase gas during seasonal periods
of lower gas prices (typically summer), to use or sell back into the market
when maikets are higher (typically winter). The estimated savings for this
seasonal buying approach varies, but has been as high as $10,000,000 over
a gas procurement year.
To replace JP storage capacity with leased capacity would be estimated at
more than $34,000,000/year plus additional pipeline transport. This is based
on storage capacity lease estimates of approximately $4/dth for equivalent
a
a
a
o
a
o
Option Capital Cost Start Gomplete
Do nothing - this is not an oPtion
Package together various solutions to fulfill Gas
Supply obligations
None - See
below for
expenses that
would flow
through the PGA
Continue with ownership in JP and fund necessary
annual capital expenditures
$ 1,626,667 01/01/2017 12/31/2017
Build LNG Storage Cost prohibitive
Business Case Justification Narrative Page 2 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 324 of 325
Jackson Prairie Joint Proiect
working gas capacity
The recommended solution is to continue to fund 1/3 of the capital budget for
Jackson Prairie (JP) Underground Storage Facility. Avista owns this facility as a 1/3
partner with Puget Sound Energy and Williams' Northwest Pipeline. Puget Sound
Energy is the managing partner for the facility which is located in Chehalis, WA. The
requested capital represents Avista's 1/3 share of the capital needed to maintain the
existing facility and maintain equal ownership status.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Jackson Prairie Storage
Project and agree with the approach it presents and that it has been approved by
the steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
J rehouse
Date:
Date
Template Version: 03107 12017
y'"/ s 'zot 7
Director Gas Supply
Business Case Owner
)Y
ffion Thackston
SVP & VP Energy Resources
@
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
1.0 Jody
Morehouse
04t13t2017 Jason
Thackston
04t1412017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 8
Case Nos. AVU-E-17-01 and AVU-G-17-01 H. Rosentrater, Avista
Schedule 5, Page 325 of 325