20170609Rosentrater Direct.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 ) DIRECT TESTIMONY
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) HEATHER L. ROSENTRATER
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

Rosentrater, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, employer and business 2
address. 3
A. My name is Heather Rosentrater and I am employed as
the Vice President of Energy Delivery for Avista Utilities, at
1411 East Mission Avenue, Spokane, Washington.
Q. Would you briefly describe your educational 7
background and professional experience? 8
A. Yes. I received a Bachelor of Science degree in
electrical engineering from Gonzaga University, and hold a
Professional Engineer (PE) credential. I joined Avista in 1996,
and worked initially as an electrical engineer at Avista’s 12
former subsidiary Avista Labs, where I developed electrical
systems for fuel cells. I joined Avista Utilities in 2003, and
have broad experience on both the electric and natural gas side
of the business, having managed departments and projects in
transmission, distribution, SCADA, asset management and supply
chain, as well as business process improvement using LEAN and
Six Sigma techniques. I was named to my current position in
December 2015. In this role, I am responsible for electric and
natural gas engineering, operations, and shared services –
fleet, facilities and business process improvement.

Rosentrater, Di 2
Avista Corporation
I currently serve on the board of directors for the Vanessa
Behan Crisis Nursery and the West Valley Education Foundation
in Spokane. In addition, I am a member of the Washington State
University School of Engineering and Computer Science Executive
Council.
Q. What is the scope of your testimony? 6
A. I will provide an overview of the Company’s electric 7
and natural gas energy delivery facilities, discuss our
electric reliability objectives, types of investments, and
system performance, and explain the factors driving our
investment in electric distribution infrastructure. My
testimony will explain why our planned investments in electric
distribution are necessary to maintain the current levels of
asset health and performance of our system and will discuss the
need for each distribution capital project and program by the
“Investment Driver” classification used to categorize our 16
infrastructure investment needs. I will describe how our
planned compliance with mandatory federal standards for
transmission planning is driving a greater demand for new
investment, and why our planned investments in natural gas
distribution are necessary in the time frames they are being
completed. Finally, I will explain why each capital investment
planned for our fleet and facilities areas are necessary to

Rosentrater, Di 3
Avista Corporation
support the efficient delivery of service to our customers,
today and into the future. Overall, my testimony will
demonstrate that:
1. Avista’s recent past, current, and planned investments in
electric distribution infrastructure are necessary, and
why the failure to make these investments at this time
would impair the performance of our system and harm our
ability to deliver safe and reliable service to our
customers. As such, the Company’s investments are 9
necessary in the time frames they are being completed.

2. The investments we make to uphold the current reliability
of our electric distribution system, and to comply with
required federal standards for transmission reliability,
are thoroughly evaluated and cost-effective for our
customers.

3. The approaches used by our business units to identify,
evaluate, prioritize and recommend capital projects and
programs ensure that we are properly identifying and
funding the highest priority needs in this planning cycle.

4. Even with our current level of infrastructure investment,
the Company has identified needs for investment that are
not fully funded in this planning cycle, in an effort to
balance investment demand with the planning principles we
consider in setting our overall investment limit. 27

Rosentrater, Di 4
Avista Corporation
A table of the contents for my testimony is as follows:

Description Page
I. INTRODUCTION 1 4
II. OVERVIEW OF AVISTA’S ENERGY DELIVERY SERVICE 5 5
III. ELECTRIC DISTRIBUTION INVESTMENTS 10 6
IV. ELECTRIC TRANSMISSION INVESTMENTS 30 7
V. NATURAL GAS SYSTEM INVESTMENTS 48 8
VI. GENERAL PLANT AND FLEET INVESTMENTS 58 9
10
Q. Are you sponsoring any exhibits in this proceeding? 11
A. Yes. I am sponsoring Exhibit No. 8, Schedule 1, which
shows the number of customers and customer energy usage for
each customer class. Exhibit No. 8, Schedule 2 is the Company’s 14
Electric Distribution System 2016 Asset Management Plan.
Exhibit No. 8, Schedule 3 is the Company’s Electric Substations 16
2016 System Review performed by Asset Management. Exhibit
No. 8, Schedule 4 is the Company’s Electric Transmission System 18
2016 Asset Management Plan. Finally, Exhibit No. 8, Schedule 5
contains the capital business case summary documents for each
of the infrastructure investments described in my testimony.

Rosentrater, Di 5
Avista Corporation
II. OVERVIEW OF AVISTA’S ENERGY DELIVERY SERVICE 1
Q. Please describe Avista Utilities’ electric and 2
natural gas utility operations. 3
A. Avista Utilities operates a vertically-integrated
electric system in Washington and Idaho. In addition to the
hydroelectric and thermal generating resources described by
Company witness Mr. Kinney, the Company has approximately
18,300 miles of primary and secondary electric distribution
lines. Avista has an electric transmission system of 685 miles
of 230 kV lines and 1,534 miles of 115 kV lines.
Avista owns and maintains a total of 7,650 miles of natural
gas distribution lines, and is served off of the Williams
Northwest and Gas Transmission Northwest (GTN) pipelines. A
map showing the Company’s electric and natural gas service area 14
in Idaho, Washington, and Oregon is provided by Company witness
Mr. Morris in Exhibit No. 1, Schedule 4.
As detailed in the Company’s 2015 Electric Integrated
Resource Plan,1 Avista expects retail electric sales growth to
average 0.6% annually and customer growth is projected to
increase approximately 1% for the next twenty years in Avista’s 20

1 A copy of the Company’s 2015 Electric IRP has been provided by Mr. Kinney
as Exhibit No. 4, Schedule 1.

Rosentrater, Di 6
Avista Corporation
service territory, primarily due to increased population and
business growth.
Also, based on Avista’s 2016 Natural Gas Integrated
Resource Plan,2 the number of natural gas customers in
Idaho/Washington is projected to increase at an average annual
rate of 1.10%, with demand growing at a compound average annual
rate of 0.36% over the next twenty years.
Q. How many customers are served by Avista Utilities in 8
Idaho? 9
A. Of the Company’s 377,285 electric and 240,294 natural
gas customers (as of December 31, 2016), 128,560 and 80,033,
respectively, were Idaho customers. 12
Q. Please describe the Company’s operation centers that 13
support electric and natural gas customers in Idaho.
A. The Company has construction offices in Coeur
d’Alene, Spokane, Colville, Othello, Pullman, Clarkston, Deer
Park, and Davenport. Avista’s three customer contact centers, 17
located in Spokane, Washington, and Coeur d’Alene and Lewiston, 18
Idaho, are networked, allowing the full pool of regular and
part-time employees in each location to respond to customer
calls from all jurisdictions.

2 A copy of the Company’s 2016 Natural Gas IRP has been provided by Company
witness Ms. Morehouse at Exhibit No. 7, Schedule 1.

Rosentrater, Di 7
Avista Corporation
Q. Please describe the Company’s approach to managing 1
the reliability of its electric distribution system? 2
A. Avista is focused on maintaining a high degree of
electric reliability as an important aspect of the quality of
our service, particularly as our society becomes ever more
reliant upon electronic technologies. The Company’s objective 6
has been primarily to maintain our current level of reliability.
Q. How does the Company track its reliability 8
performance? 9
A. For many years Avista has measured, tracked and
reported the number of outages and the duration of outages that
our customers experience on average each year.3 Our annual
results for the number of electric outages and outage duration
on average are provided for the period 2004-2016 in Illustration
No. 1 on a system basis. 15

3 The number of outages on average is reported as the System Average
Interruption Frequency Index (or SAIFI), and the duration of outages on
average as the System Average Interruption Duration Index (or SAIDI).

Rosentrater, Di 8
Avista Corporation
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Average Number of Outages Average Length of Outages (minutes)
Illustration No. 1 – Duration and Frequency of Outages4 1
2

Q. What do the results in Illustration No. 1 indicate? 11
A. Although it is the norm for the number of outages and
the average length to vary each year due to factors beyond
Avista’s control, such as major weather or wind events, our 14
long-term reliability has been stable. In addition to these
primary statistics, we report on several other utility-wide
measures of reliability, the geographic areas of greatest
reliability concern on our electric system, and our plans to
improve service performance in those areas of greatest concern.

4 This illustration excludes major event days. The measuring protocol for
SAIDI and SAIFI excludes outages caused by very large outage events such as
the windstorm of November 2015. These major events are referred to a “major
event days.” Even with these major events excluded, however, we can still
experience substantial variability caused by, for example, storms that do
not qualify as major events.

Rosentrater, Di 9
Avista Corporation
These plans include investments targeted to: 1) replacing
certain sections of overhead feeders with underground lines
when cost effective; 2) relocating lines to reduce outages
caused by trees and to give our crews better access to speed up
outage repairs; 3) implementing special tree trimming and wood
pole inspection; 4) improve fuse coordination5 on the feeder
and laterals to reduce the size of an outage; and 5) dividing
individual feeders into separate segments, as well as
installing operating devices to sectionalize individual
feeders, and other means necessary and cost effective to ensure
our customers receive a reasonable level of service quality
and reliability.
Q. Please describe the overall investments the Company 13
makes to maintain and improve upon its current level of 14
reliability? 15
A. Avista has in the past referred broadly to individual
investments we make as having the purpose of “improving 17
reliability.” This reflects the fact that many investments,
especially distribution investments made to replace
deteriorated assets, are very likely to improve the reliability

5 Fuse coordination refers to the engineering scheme of ensuring we have the
properly-sized fuses for system protection at each juncture of a feeder.
Good fuse coordination helps ensure that an outage fault is restricted to
that portion of the feeder network where the damage has occurred.

Rosentrater, Di 10
Avista Corporation
of the specific infrastructure that is being rebuilt or
replaced. This is the case because the likelihood of failure of
an asset generally increases with age and deterioration over
its service life. Avista’s many infrastructure investments 4
often include at least a mention of these reliability benefits.
In the great majority of cases, however, the predominant need
for these investments is to replace assets that have reached
the end of their useful life, or to a lesser degree to solve
capacity and performance issues. This timely replacement of
deteriorated assets is crucial to our ability to uphold and
maintain our current levels of reliability performance.

III. ELECTRIC DISTRIBUTION INVESTMENTS 13
A. Avista’s Distribution Investments from 2005 - 2016 14
Q. How do the electric distribution investments made by 15
Avista over the past several years compare with those made by 16
other similar utilities? 17
A. Avista, like utilities across the country, has
responded to similar needs for increased investment in electric
transmission and distribution infrastructure on a system basis
as shown in Illustration No. 2.6

6 Results are from the data set gathered and reported by the Energy Institute
of the University of Texas, Austin. Fares, L., Robert, King, Carey W.,

Rosentrater, Di 11
Avista Corporation
Illustration No. 2 1

Organizations such as the Edison Electric Institute reported
total utility investments in electric transmission and
distribution facilities doubling between 2009 and 2014, noting
that investments in distribution infrastructure alone reached
$22.5 billion in 2014, an increase of 8% over 2013.7 The
American Society of Civil Engineers in 2011 conducted an
extensive review of then-current trends in electric utility
investments, and identified a $37 billion “investment gap” 18
between those current plans and the infrastructure investments

“Trends in Transmission, Distribution, and Administration Costs for U.S.
Investor Owned Electric Utilities,” 2016.
UTEI/2016-06-1, 2016, available at http://energy.utexas.edu/the-full-cost-
of-electricity-fce/.38 electric utilities
7 2015 Financial Review: Annual Report of the U.S. Investor-Owned Electric
Utility Industry. Edison Electric Institute.

Rosentrater, Di 12
Avista Corporation
needed by year 2020.8 Their report on electric infrastructure
was updated in 2016, noting the significant increased 2
investment that had been made by the industry compared with the
2011 forecast of planned investments, but it still identified
an $18 billion investment gap between current spending plans
and the investments that will be needed by year 2025.9 The
report noted that 54 percent of the $18 billion gap was
attributed to the needs of electric distribution systems alone.
In addition to the similarity in the overall pattern of
investment, the Company’s annual distribution investments have
been similar to those of other electric utilities measured on
a cost per customer basis. Illustration No. 3, below, shows the
annual electric distribution capital cost per customer for 38
electric utilities similar in size to Avista,10 as well as the
Company’s annual capital cost per customer. The illustration
shows the maximum and the average annual capital cost per
customer for this group. The Company’s investments in electric 17
distribution infrastructure on a system basis were depressed

8 Failure to Act. The Economic Impact of Current Investment Trends in
Electricity Infrastructure. American Society of Civil Engineers. 2011.
9 http://www.infrastructurereportcard.org/wp-content/uploads/2016/10/ASCE-
Failure-to-Act-2016-FINAL.pdf pages 16 and 17.
10 Ibid. Report of the Energy Institute of the University of Texas, Austin.
For this figure Avista selected a subset of those utilities similar in the
number of electric customers and peak loads from the more than 200 utilities
in the data set. A total of 38 utilities were selected based on the
parameters of the number of customers between 200,000 and 400,000, and peak
loads between 1,000 MW and 3,000 MW.

Rosentrater, Di 13
Avista Corporation
for several years early in this period, as reflected in our
below average cost per customer. Our increasing investments
pushed our per customer cost above the national average in 2005,
however, our costs have generally converged with the group
average since 2012.
Illustration No. 3

15
Q. What conclusion do you draw from the comparison of 16
Avista’s investments in electric distribution infrastructure 17
with those of the broader utility industry since 2000?
A. The pattern of investments made by the Company during
this period bears a striking resemblance to that of the
industry, which should not be a surprise, since we are all
responding to the same investment needs: first, the need to
replace an increasing amount of infrastructure that has reached

Rosentrater, Di 14
Avista Corporation
the end of its useful life, and second, responding to the need
for reliability and technology investments required to build
the integrated energy services grid of the future.
B. Currently Planned Investments in Distribution Infrastructure 4
Q. Would you please summarize the distribution 5
investments on a system basis that are planned for years 6
2017 - 2019? 7
A. Yes. Planned investments for this period, grouped by
investment driver, are shown in Table No. 1 below on a system
basis, and the expected transfers-to-plant by “driver” is 10
provided in the following Illustration No. 4. Please see Company
witness Mr. Morris’ Exhibit No. 1, Schedule 2, consisting of an
Infrastructure Investment Plan identifying six “drivers” of 13
infrastructure development. These are:
1. Respond to customer requests for new service or service
enhancements;

2. Meet our customers’ expectations for quality and 18
reliability of service;

3. Meet regulatory and other mandatory obligations;

4. Address system performance and capacity issues;

5. Replace infrastructure at the end of its useful life
based on asset condition, and;

6. Replace equipment that is damaged or fails, and support
field operations.
30

Rosentrater, Di 15
Avista Corporation
Illustration No. 4 1

As the illustration shows, the great majority of our
planned investment is required to connect new customers who
request electric service, to replace assets that have reached
the end of their useful life, and to replace failed assets and
support operations. In the following sections, I will further
explain the need for these investments, by project and program,
and by investment driver.11

11 The figures contained within each of the Tables in my testimony reflect
“transfers-to-plant” during the respective calendar years; as such, the
amounts may differ from the amounts shown for any particular line item in
the Infrastructure Investment Plan (Exhibit No. 1, Schedule 2) or in the
associated Business Cases (Exhibit No. 8, Schedule 5), which reflect
budgeted capital spend numbers. The costs shown in Illustration No. 4 for
Customer Service Quality and Reliability are derived from the feeder
automation portion of the Grid Modernization Program, which costs are
included as part of the overall Grid Modernization investments shown in
Table No. 1 on next page.”
Performance & Capacity
$35,707,422
Asset Condition
$125,057,360
Mandatory & Compliance
$18,343,845
Customer Service Quality & Reliability
$4,241,990
Customer Requested
$115,869,920
Failed Plant & Operations
$58,215,513
Electric Distribution Infrastructure Investments by Driver
Total of Planned Transfers to Plant 2017-2021

Rosentrater, Di 16
Avista Corporation
Table No. 1 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Asset Condition: 17
Q. Please describe the Asset Condition Investment Driver 18
included and explain why these investments are necessary in the 19
time frame they are being completed. 20
A. Assets of every type degrade with age, usage and other
factors, and must be replaced or substantially rebuilt at some
point in order to ensure we continue to deliver reliable and
Business Case Name 2017 2018 2019
Asset Condition
Dist Grid Modernization $ 15,051 $ 13,929 $ 14,333
Distribution Transformer Change-Out Program 3,000 1,200 1,200
Distribution Wood Pole Management 9,000 9,500 9,500
Primary URD Cable Replacement 503 1,000 1,000
Customer Requested
New Revenue - Growth 23,775 23,249 22,668
Failed Plant and Operations
Distribution Minor Rebuild 9,105 8,900 8,900
Meter Minor Blanket 505 300 300
Mandatory and Compliance
Elec Replacement/Relocation 2,600 2,700 2,800
Environmental Compliance 350 350 350
Performance and Capacity
LED Change Out Program 2,900 2,000 2,320
Segment Reconductor and FDR Tie Program 6,587 4,900 5,001
Subtotal: Electric Distribution Capital Projects $ 73,376 $ 68,028 $ 68,371
Washington Direct Business Cases(1)
Spokane Electric Network 2,605 2,300 2,300
Franchising for WSDOT 1,594 200 200
4,199 2,500 2,500
Total Planned Electric Distribution Capital Projects $ 77,575 $ 70,528 $ 70,871
(1)Excluded from revenue requirement in this case.
Distribution Capital Projects (System) In $(000's)

Rosentrater, Di 17
Avista Corporation
cost effective service. Projects or programs in this driver are
defined as: “investments to replace assets based on established 2
asset management principles and systematic programs adopted by 3
the Company, which are designed to optimize the overall 4
lifecycle value of the investment for our customers.”12
The replacement of assets based on condition is
essentially the practice of removing them from service and
replacing them at the end of their useful life. Across the
utility industry, and likewise for Avista, the replacement of
assets based on condition often constitutes the largest type of
the infrastructure investments required each year.13 In a survey
of 433 U.S. electric utility executives, 47% listed “old 12
infrastructure” as the most challenging issue they face, with 13
the next-closest infrastructure issues reported as “Grid 14
Reliability” (17%) and Smart Grid Deployment (16%).14 As an
industry we face this investment demand today because the
sizeable infrastructure built during the period of economic
growth and expansion following World War II, and extending
generally into the 1970s, has either reached, or is nearing the
end of, its useful life and must be replaced.15 As demonstrated

12 Exhibit No. 1, Schedule 2, page 30.
13 Exhibit No. 1, Schedule 2, page 31.
14 Why Utilities are Rushing to Replace and Modernize the Aging Grid: State
of the Electric Utility 2015.
15 Exhibit No. 1, Schedule 2, page 31.

Rosentrater, Di 18
Avista Corporation
earlier in my testimony, our Company like utilities across the
nation have stepped up the level of investments needed to
accommodate the orderly replacement of these facilities. For
our electric distribution system, these investments are
required to uphold and maintain the capability of our various
feeder equipment, overhead conductor and poles, transformers,
and underground cables.
Q. What are the ongoing programs to accomplish this 8
work? 9
A. These programs include Distribution Wood Pole
Management, PCB Transformer Replacement, Underground Cable
Replacement, and Distribution Grid modernization. Collectively,
the Company relies on these primary programs for making
systematic investments in our distribution plant, which allows
us to cost-effectively maintain a safe and highly reliable
system that meets the expectations of our customers. These
programs were developed with support from the Company’s asset 17
management group, which has continued to evaluate them as needed
through the course of implementation. The most recently
completed Electric Distribution System 2016 Asset Management
Plan report has been included as Exhibit No. 8, Schedule 2.
Below are descriptions of each of these asset programs:
23

Rosentrater, Di 19
Avista Corporation
Distribution Grid Modernization – 2017: $15,051,000; 2018: 1
$13,929,000; 2019: $14,333,000 2
In order to properly select16 the most appropriate feeders for
rebuilding, Grid Modernization uses inventory information from
the Wood Pole Management Program and our Avista Facilities
Management System, to assess the potential energy efficiency
savings, avoided customer outages, and avoided expenses for
failure of equipment. This feeder criteria information is used
to rank the potential benefits for each compared with all of
the other feeders on our system. The top ranked feeders are
then balanced among Company operating districts, jurisdictions
and urban vs rural service. In the process of evaluating
feeders for potential rebuilding, our engineers evaluate
reliability results for each feeder, study the actual loadings
on each phase of the feeder under a range of seasonal conditions
and model the average and peak loadings expected after the phase
loads are balanced. They also model the capacity of the overhead
conductors, by segments on the trunk and laterals, to identify
any limitations as well as potential for energy savings. By
integrating all of this information, along with the full range
of asset age and condition data, our engineers recommend a
comprehensive set of treatments that could be applied and
identify the cumulative potential benefits.

This program represents a comprehensive approach to
infrastructure management, based on extensive data and
engineering-driven analysis and evaluation. It serves as a
platform to better integrate a portion of the capital
investments we make each year in our electric distribution
system. Through grid modernization, we know we are targeting
work on the right infrastructure at the right time, and in a
priority that allows us to maximize the customer value of every
investment made under the program. The failure to fund this
program at the planned level for this period will push even
more work into the wood pole management program and reduce the
value of both programs.

Distribution Transformer Change-Out Program - 2017: $3,000,000; 38
2018: $1,200,000; 2019: $1,200,000 39
Between 1929 and 1981, a family of synthetic organic compounds
known as Polychlorinated Biphenyls (PCBs) were commonly used in

16 The objective in selecting candidate feeders for rebuild is to achieve
the greatest overall value for customers based on improved reliability (on
that feeder), energy efficiency savings, and avoided expenses for equipment
failures.

Rosentrater, Di 20
Avista Corporation
the oil that fills electrical transformers due to their high
dielectric strength17 and resistance to fire. Studies conducted
in the 1960s and 70s revealed, however, that these compounds
are also toxic, carcinogenic and highly resistant to
biodegradation in the environment. Their production was banned
in the United States in 1979.18 As a result of this elevated
concern, Avista began to formally analyze alternatives to deal
with its distribution transformers containing PCBs.

Under the current plan all transformers with PCB concentrations
exceeding 1 ppm should be removed from our system by year 2019.
In year 2020 and beyond, the remainder of the pre-1981
transformers in our system will be targeted for removal as part
of the wood pole management and grid modernization programs. 14
15
Distribution Wood Pole Management – 2017: $9,000,000; 2018: 16
$9,500,000; 2019: $9,500,000 17
Avista has approximately 340 electric feeders with a total
circuit length of approximately 7,700 miles. This system is
composed mainly of overhead electric conductors and associated
equipment that is supported by approximately 240,000 wood poles
and attached equipment that includes crossarms, transformers,
cutouts,19 insulators and pins,20 wildlife guards, lightning
arresters, guy lines,21 and pole grounding.22 Poles, equipment
and conductors comprise over 70% of the Company’s electric 25
distribution infrastructure. In managing these assets, it is
the Company’s goal to repair or replace aging poles and 27
equipment before they actually fail, but late enough in their
expected life span to capture the full value of the initial
investment and any follow-up investments. The practical way to
accomplish this is to systematically inspect each pole in the

17 Dielectric strength refers to the ability of a material to resist carrying
an electrical current, which is a measure of its potential to insulate
against electric short circuit or fault.
18 “PCBs Questions & Answers,” United States Environmental Protection Agency,
https://www3.epa.gov/region9/pcbs/faq.html.
19 Cutouts are fuse devices that protect the feeder and equipment in the
event of a fault on the line.
20 The overhead wire or conductor that carries the electric current is
attached to insulators that prevent the conductor from faulting, and each
insulator is attached to the pole or crossarm with a wooden pin (though new
materials are frequently in use today).
21 Wire support attached at the upper part of the pole and anchored into the
ground diagonally to counteract tension on the line as needed to keep the
pole stable, upright and plumb.
22 To ensure the pole and equipment is electrically grounded to ensure any
fault goes safely to ground.

Rosentrater, Di 21
Avista Corporation
system on a regular cycle and to make the investments needed to
replace failed poles or to extend the life of weakened poles so
they don’t fail before the next inspection. The central question 3
is what time interval to use for the inspection cycle.23
Generally, more frequent inspections (shorter cycle time)
reduce the likelihood that poles and associated components will
fail sometime during the interval between inspections, but they
also cost more because the annual number of poles inspected is
greater than with a longer cycle interval. The optimum interval
time can be mathematically determined based on the
characteristics of the wood pole population, the associated
operating expenses, and the likelihood and cost of customer
service outages resulting from poles that fail between
inspections. The Company’s evaluation of the cycle interval in 14
2009 pointed to a 20-year cycle as preferable to both a shorter
10-year interval and a much longer interval.

In each 20-year cycle all of the wood poles in our system will
have been visually inspected and repaired, reinforced
(stubbed), or replaced as needed. The program has been modified
to more fully utilize the crews performing inspections, by
replacing pre-1960’s transformers, identifying inefficiently 22
sized transformers, installing grounds or guy wires where
needed, and ensuring equipment meets current safety standards.
In 2012 Avista initiated the Grid modernization Program which
is dovetailed with the Wood Pole Management Program to make
further-optimized use of crews and materials supporting wood
pole management. The failure to fund this program at the planned
levels for this period will result in more risk of customer
outages, and higher expenses and capital costs due to unplanned
maintenance and repair. This investment includes associated O&M
offsets of $68,400 (System-basis) beginning in 2017. Company
witness Ms. Andrews has included Idaho’s share of these offsets 33
within the Company’s revenue requirement request.

Primary URD Cable Replacement - 2017: $503,000; 2018: 36
$1,000,000; 2019: $1,000,000 37
Underground residential district cable (underground cable or
URD) has been used by the utility industry since the 1930s,
though Avista did not begin installing the cable until the late
1960’s. During the 1990s it became apparent that the cable 41
manufactured from the 1960s into the 1980s had numerous
problems. These included the lack of adequate insulation

23 The inspection cycle interval is the period of time within which every
pole in the system will have been inspected and treated as needed.

Rosentrater, Di 22
Avista Corporation
resulting in numerous faults, the process of splicing the cable
caused weaknesses and premature failure, and excessive
corrosion on the neutral strands caused voltage levels to drop
unexpectedly or the cable to entirely fail.24

In 2009 Avista’s asset management group analyzed options for 6
accelerating the replacement schedule from 10 years to a four
year program. The analysis, which was based on savings from
avoiding unplanned outages, estimated that the four-year
program would save customers approximately $7.3 million in
capital installation, expenses, and failure consequences.25 With
the majority of the known vintage cable replaced by 2013, the
program was ramped down to an annual investment of approximately
one million dollars, which provides for the removal and
replacement of this vintage cable as we find it on the system
(usually through responding to an underground fault). The
failure to fund this program at the planned levels for this
period will result in more customer outages, and higher expenses
and capital costs due to unplanned maintenance and repair. 19
Q. Does the Company’s five-year investment plan fully 20
fund these programs? 21
A. No. The Company’s Distribution Grid Modernization 22
Program is optimized on a 60 year cycle, however, it has not
been funded at a level to achieve that cycle time, in order to
accommodate other priority investment needs in Avista’s 25
electric distribution system. The level of funding for this
project that the Company has included in the 2017 – 2021
timeframe provides for an 84 year cycle; longer than the
optimized cycle. The effect of the longer than 60-year cycle

24 Medek, James D. P.E., “Early Underground Residential Distribution (URD)
in the Midwest,”, 2002, https://www.pesicc.org/iccwebsite/subcommittees/E/
E04/2002/fall02_medek.pdf)
25 Savings are based on the outages forecast to occur without the replacement
program, minus the actual outages, multiplied by the average cost of
responding to an average cable outage.

Rosentrater, Di 23
Avista Corporation
interval is that the wood pole management program will have to
complete more capital work every year (work that would have
been done under grid modernization). Both the grid
modernization and wood pole management programs will operate at
a lower efficiency, and a portion of the added customer value
delivered by the grid modernization program will be lost.
Customer Requested: 7
Q. Please list and describe the infrastructure programs 8
and projects for electric distribution related to the ‘Customer 9
Requested’ investment driver? 10
A. This classification of infrastructure investments is
defined as: “customer requests for new service connections, 12
line extensions, transmission interconnections, or system 13
reinforcements to serve a customer.”26 The related capital
construction activities are typically limited to the electric
distribution system, but may extend to substations and
dedicated high voltage transmission lines. The capital
investment required to fulfill customer requests for electric
service represents 31.4% of the total distribution
infrastructure spending planned in the five-year period.
21

26 Exhibit No. 1, Schedule 2, page 18.

Rosentrater, Di 24
Avista Corporation
New Revenue – Growth - 2017: $23,775,000; 2018: $23,249,000; 1
2019: $22,668,000 2
These investments include the costs for establishing a new
service connection to a customer when requested, and which are
provided for in the line extension allowance granted under our
tariff. This work can be as simple as setting a new area light
or running a new secondary service from an existing transformer,
to the more involved instance of extending a primary
distribution line to the customer, setting the transformer,
running the service line, and setting the new meter. System
reinforcements that are required to serve a solitary or a small
group of customers, generally involve substation and feeder
upgrades that are required to meet new capacity requirements.
Because Avista is obligated to provide electric service or
service enhancements when requested, we allocate the needed
capital to this program based on the number of requests we
expect to receive each year, and not through a competitive
prioritization process. For this period, Avista expects to
connect on average about 6,000 new electric customers each year.
Avista is required by its service tariffs to make the
investments necessary to connect customers when requested. 21
Failed Plant and Operations: 22
Q. Please describe the Failed Plant and Operations 23
Investment Driver? 24
A. The Failed Plant and Operations investment driver is
defined as: “requirements to replace assets that have failed 26
and which must be replaced in order to provide continuity and 27
adequacy of service to our customers (e.g. capital repair of 28
storm-damaged facilities). Also includes investments in natural 29
gas and electric infrastructure that are performed by Avista’s 30
operations staff.”27 Avista must respond to various types of
equipment failures on our electric distribution system each

27 Exhibit No. 1, Schedule 2, page 35

Rosentrater, Di 25
Avista Corporation
year that result from natural forces such as wildfire, third-
party damage caused by others, or the unanticipated failure of
an asset. In addition to replacing failed plant, investments
under this program cover work performed through Avista’s 4
ongoing capital work performed by operations staff.
Distribution Minor Rebuild - 2017: $9,105,000; 2018: 6
$8,900,000; 2019: $8,900,000
A major portion of the investments made under this program are
driven by faults or damage to our system that result in service
outages for our customers. The vast majority of the outages our
customers experience each year occur on our overhead
distribution system. In 2016, there were 7,083 outages on the
distribution grid compared to only 53 related to substations
and 61 associated with transmission lines. The majority of these
outages are related to weather (e.g. lightning, wind, rain and
snow), downed trees, animals (e.g. squirrels and birds), and
equipment failure. In addition to replacing assets that have
failed, Avista’s operations staff performs a wide range of 18
limited capital infrastructure work that does not rise to the
level of a project or program.28 This work includes the need to
reconfigure, replace, repair, or upgrade distribution
facilities that arise for a variety of reasons. Because the
Company must promptly replace failed infrastructure in order to
ensure the continuity of service to our customers, Avista
allocates funding to this program based on the evaluation of
historical trends, and not through a competitive prioritization
process. If Avista did not make the required investments under
this program, we would be unable to repair and/or replace
infrastructure that is damaged or fails, and would therefore
fail to provide service continuity to our customers.

Meter Minor Blanket - 2017: $505,000; 2018: $300,000; 2019 32
$300,000 33
The Company has over 370,000 electric meters in service for
measuring the kWh usage for our residential, commercial and

28 A project is a stand-alone investment activity that upgrades existing
assets or installs new assets required for operation of Avista's systems
and processes. A program is a systematic or repetitive multi-year investment
designed and managed to sustain an expected desired level of system or
process performance.

Rosentrater, Di 26
Avista Corporation
industrial customers. Each year, in response to our customers’ 1
requests for a meter check, the Company’s detection of billing 2
anomalies, or the identification of failing meters through our
annual meter testing program, Avista must promptly replace or
repair failed meters to ensure our customers are accurately
billed. The investments for meter replacements and repairs are
included under this failed plant program.
Mandatory and Compliance: 8
Q. Please describe the distribution investments related 9
to the Mandatory and Compliance Investment Driver? 10
A. Avista has defined this driver as: “investments 11
required to comply with laws, rules, and contracts that are 12
external to the Company (e.g. State and Federal laws, Settlement 13
Agreements, FERC, NERC, and FCC rules, and Commission Orders, 14
and etc.).”29 15
Electric Replacement/Relocation - 2017: $2,600,000; 2018: 16
$2,700,000; 2019: $2,800,000 17
Each year Avista is required to respond to the projects of
municipalities, counties and state-level agencies to rebuild or
realign roads, streets and highways. When these projects impact
our distribution facilities located in public rights-of-way,
the Company is required to remove and rebuild them in the clear
zone of the new roadway, or to place them on a new purchased
private easement. This work must be performed at the Company’s 24
expense, and while Avista may have some latitude to negotiate
the timing of the construction, it has no choice with regard to
removing and relocating its infrastructure and paying all of
the associated costs.30 If Avista failed to make these
investments we would be in violation of our operating
franchises, municipal codes, state laws and regulations, and

29 Exhibit No. 1, Schedule 2, page 23.
30 This requirement is based on Avista’s facilities being in the public
right-of-way established for this purpose. In cases when the Company’s
facilities are located in private rights-of-way, while still required to be
relocated, the move is at the expense of the governing body responsible for
the roadway project.

Rosentrater, Di 27
Avista Corporation
would be subject to litigation and financial and other
penalties.
3
Environmental Compliance - 2017: $350,000; 2018: $350,000; 4
2019: $350,000 5
These required investments include implementation of U.S.
Forest Service Special Use Permits, waste oil disposal
including PCB transformers, and environmental compliance with
storm water management, water quality protection, property
cleanup and related issues. If Avista failed to make these
investments we would be in violation of mandated environmental
compliance regulations, and would be subject to litigation and
financial and other penalties.
Q. How are these investments prioritized within the 14
business units? 15
A. Because Avista is obligated to remove and replace its
facilities when requested, and to meet environmental standards,
the annual funding level is established based on historical
trends and any known specific projects.
Performance and Capacity: 20
Q. What planned distribution investments are grouped 21
under the Performance & Capacity Investment Driver? 22
A. When the load-carrying capacity of electric
facilities is exceeded for any extended period of time it can
stress and damage equipment, cause system instability, and lead
to equipment failures that result in customer outages. The
investments required to resolve these issues are defined as: 27
“a range of investments that address the capability of assets 28
to meet defined performance standards, typically developed by 29

Rosentrater, Di 28
Avista Corporation
the Company, or to maintain or enhance the performance level of 1
assets based on need or financial analysis.”31 2
LED Change Out Program - 2017: $2,900,000; 2018: $2,000,000; 3
2019: $2,320,000 4
LED lighting technology emerged as a viable alternative to
conventional and fluorescent lighting around 2009, and by year
2012 over 14 million units had been installed in the U.S. alone.
It is estimated that LEDs will save U.S. consumers and
businesses $20 million per year within a decade, and reduce
U.S. CO2 emissions by up to 100 million metric tons per year.
LED bulbs cut electricity use by 85% compared with incandescent
bulbs, and 40% compared with fluorescent lighting.32 Avista
operates approximately 35,000 street lights we have installed
for many of our communities and other jurisdictions across our
service territory as well as area lights requested and paid for
by individual customers. In 2013, in recognition of the superior
safety performance of LED lighting, the energy savings
potential, Avista evaluated the benefit of converting all our
Schedule 042 street lights from High Pressure Sodium (HPS) to
LED fixtures. Also, the State of Washington has established a
statewide grant program, which is administered for the state by
Avista, which provides small communities an offset to their
street lighting costs when their systems are converted to LED
lighting. If Avista did not invest in the LED lighting program,
we would delay the safety and security benefits to customers,
as well as the savings for energy efficiency and reduced
operating expenses achieved by the program. This investment
includes associated O&M offsets of $1,060,249 (System-basis)
beginning in 2017. Ms. Andrews has included Idaho’s share of 29
these offsets within the Company’s revenue requirement. 30
31
Segment Reconductor and FDR Tie Program - 2017: $6,587,000; 32
2018: $4,900,000; 2019: $5,001,000 33
The annual investments made under this program represent 7.1%
of our planned distribution investments, and remedy the
overloading of electric equipment and cable, as well as the
conductor sag33 that results from overheating of the overhead
wire. These instances of system overloading result from load

31 Exhibit No. 1, Schedule 2, page 27.
32 “PCBs Questions & Answers,” United States Environmental Protection Agency,
https://www3.epa.gov/region9/pcbs/faq.html.
33 When the overhead wire (conductor) on a distribution feeder is overloaded,
the wire overheats and stretches, and in doing so, sags closer to the ground
than designed, which can exceed electric code requirements for safety.

Rosentrater, Di 29
Avista Corporation
growth and shifts in load demand that occur over time on the
distribution system. Resolving these overloading issues
involves a combination of two strategies known as “load 3
shifting” and “segment reconductoring.” The strategy of load
shifting extends existing lines on one feeder to an adjacent
feeder that has the available capacity to carry the additional
transferred load. Reconductoring involves the removal of the
wire or conductor that is too small in diameter for the current
loading and replacing it with larger conductor that can easily
carry the load. Avista considers a range of options that not
only meet the current need to relieve the overloading, but that
also provide for the optimization of the overall distribution
system.
14
Q. In conclusion, please summarize Avista’s investment 15
plan for its electric distribution system. 16
A. Our investment plans for our electric distribution
system have been thoughtfully developed, thoroughly analyzed
and optimized, and adjusted as appropriate to ensure we deliver
cost effective value for our customers. The level of our
investments has also been conservative as we have balanced
distribution needs with our overall infrastructure demands. As
an example, we have chosen to fund our grid modernization
program at a level that does not achieve the optimized cycle
interval in an effort to manage our overall investment needs as
a part of being attentive to the price impacts to our customers.
Q. Do you believe that the Company’s investment in 27
distribution infrastructure is necessary in the time frame the 28
projects are being completed? 29
A. Yes, I do.

Rosentrater, Di 30
Avista Corporation
IV. ELECTRIC TRANSMISSION INVESTMENTS 1
Q. Please discuss the investment drivers for the 2
Company’s transmission projects. 3
A. Avista must continuously invest in its transmission
infrastructure to maintain safe and reliable service for our
customers and to meet mandatory federal reliability standards.
These investments replace equipment that has reached the end of
its useful life, meet customer requests for interconnection or
service enhancement, repair or replace infrastructure that
fails, meet our regulatory compliance requirements, ensure the
availability of critical equipment when needed, and enhance the
capacity or performance of the system to meet Company standards
or serve additional load. In the following testimony I will
provide a description of the transmission investments by
investment driver category.
Q. Please discuss the Asset Condition driver as it 16
relates to transmission investment. 17
A. Investments in transmission infrastructure related to
Asset Condition are “to replace assets based on established 19
asset management principles and strategies adopted by the 20
Company, which are designed to optimize the overall lifecycle 21
value of the investment for our customers.”34 The Company’s 22

34 Exhibit No. 1, Schedule 2, page 30.

Rosentrater, Di 31
Avista Corporation
Transmission System Asset Management Plan (Exhibit No. 8,
Schedule 4) recommends a 30-year replacement period for
transmission assets, which requires an investment of $21.1
million per year, split $11.3 million for 115 kV facilities and
$9.8 million for 230 kV facilities. Current spending on the
replacement of transmission facilities due to asset condition
is just under $10 million per year, meaning the Company is
currently on a funding level track that will require some
transmission assets to operate reliably at an age beyond 60
years.
Q. Please discuss the Customer Requested driver as it 11
relates to transmission investment. 12
A. These projects are triggered by “customer requests 13
for new service connections, line extensions, transmission 14
interconnections, or system reinforcements to serve a 15
customer.”35 In some cases the Company must construct a
distribution substation with an associated transmission line
extension in order to meet the requested new load requirements
of an industrial or large commercial customer. Other situations
may involve a requested transmission interconnection with a
neighboring utility or generation project.

35 Exhibit No. 1, Schedule 2, page 18.

Rosentrater, Di 32
Avista Corporation
Q. Please discuss the Failed Plant and Operations driver 1
as it relates to transmission investment. 2
A. Transmission investments in this category are
primarily the result of storm damage to the Company’s 4
transmission system, including damage caused by major wind
events, lightning, fire, and snow and ice.
Q. Please discuss the Mandatory and Compliance 7
Requirements driver as it relates to transmission investment. 8
A. These investments in transmission infrastructure are
primarily driven by North American Electric Reliability
Corporation (NERC) standards, which are nationwide requirements
for utilities to ensure the reliability of the interconnected
transmission grid. Compliance with these standards became
mandatory under federal law in 2007, and failure to comply may
result in monetary penalties of up to $1 million per day, per
infraction. These standards focus mainly on transmission
planning, operation, and equipment maintenance. The standards
require utilities to plan and operate their systems to avoid
customer outages and to prevent adverse impacts to neighboring
utility systems arising from the loss of transmission service.
Specifically, the transmission system must be designed so that
the simultaneous loss of up to two facilities will not impact
the interconnected transmission system. Further, the loss of

Rosentrater, Di 33
Avista Corporation
any single facility must not cause any other facility in service
to exceed its System Operating Limit (voltage or capacity
ratings) or cause the interconnected transmission grid to
operate outside specified reliability limits (voltage and
stability limits). This includes circumstances where
transmission facilities suffer an outage event, or are
purposefully removed from service for maintenance and
construction work. Finally, the transmission operator must
determine in advance whether any single outage will result in
a violation of a System Operating Limit, and to mitigate for
that occurrence in advance, prior to such contingency
occurring. This means the system must be designed to
automatically adjust to a reliable state or system operators
must take proactive action to mitigate the expected impacts of
a potential contingency. Such mitigation efforts may include
system configuration changes, generation changes, or the
controlled removal of firm load from the transmission system.
As a result, Avista must ensure that its system can be operated
reliably during a variety of operational, seasonal and other
scenarios.

36 Facilities refer to transmission lines, sections of lines and transmission
equipment in substations.

Rosentrater, Di 34
Avista Corporation
Other federal rules that could require the construction of
new transmission facilities include Avista’s compliance with 2
its Open Access Transmission Tariff, which can require the
Company to construct new facilities at the request of its
transmission system customers.
Q. Would you please describe the recent change in the 6
NERC transmission planning standards and explain the possible 7
impact on the Company’s investments in transmission and other 8
infrastructure? 9
A. Yes. In 2013, FERC mandated utility compliance with
Requirement R2 of the NERC transmission planning standard TPL-
001-4, effective January 1, 2016. This requirement underscores
FERC’s intent that disconnecting customers not directly
connected to a transmission facility that experiences a planned
or unplanned outage cannot be generally relied upon to ensure
the planned reliability of the transmission system. The
Company is now required to make transmission investments to
meet this standard or, if it is unable to do so due to
circumstances beyond its control, must initiate a broad public
stakeholder process explaining how it would rely on the option
of disconnecting customers to meet transmission reliability,
which plans would be subject to Commission review. The Company
believes that relying upon disconnecting customers to meet

Rosentrater, Di 35
Avista Corporation
reliability standards does not meet our customer service or
reliability objectives. Consequently, the Company is planning
for new transmission investments over the next several years
that will allow it to comply with the transmission planning
standard. These investments will likely trigger the need to re-
prioritize other infrastructure projects during this planning
period, resulting in the possible deferral of other priority
investment needs. 8
Q. Please discuss the Performance and Capacity driver as 9
it relates to transmission investment. 10
A. Just as with distribution facilities, transmission
investments driven by Performance and Capacity are “a range of 12
investments that address the capability of assets to meet 13
defined performance standards, typically developed by the 14
Company, or to maintain or enhance the performance level of 15
assets based on need or financial analysis.”37 When the load-
carrying capacity of electric facilities is exceeded for any
extended period of time it can stress and damage equipment, and
lead to equipment failures that result in customer outages.
Furthermore, in the case of substation and transmission
facilities, the Company must plan for sufficient capacity in
the system to accommodate a planned or forced outage to any one

37 Exhibit No. 1, Schedule 2, page 27.

Rosentrater, Di 36
Avista Corporation
system component without customers having to experience an
extensive outage. For example, to take a substation out of
service for necessary maintenance, the Company must plan for
sufficient capacity in its neighboring substations so that all
lines serving customers from the substation to be taken out of
service can be transferred to neighboring substations before
the maintenance outage occurs. Other investments, like
Supervisory Control and Data Acquisition (SCADA) systems,
enable those who operate the Company’s transmission system to 9
effectively monitor and control the system to ensure proper
system performance. 11
Q. How do Avista’s Transmission Planning, System 12
Operations and Engineering business units evaluate and 13
prioritize proposed transmission projects before they are 14
submitted to the Company’s capital planning group? 15
A. These transmission projects are initiated through
planning studies, engineering and asset management analyses,
and scheduled upgrades or replacements identified in our
operations districts. Projects developed through transmission
planning studies undergo internal review by multiple
stakeholders who help ensure all system needs and alternatives
have been identified and addressed.

Rosentrater, Di 37
Avista Corporation
In addition to this traditional review, the Company
recently implemented a new formal review process referred to as
the “Engineering Roundtable.” The objective of this process is 3
to provide added structure and increased transparency of the
review process for both internal and external stakeholders, for
development of all proposed transmission projects whether large
specific projects or smaller, program-related proposals.
Through this review all substation and transmission projects
are reviewed, evaluated, returned for additional analysis as
needed, and finally prioritized.
Representatives from ten business units participate in
this process, which include transmission planning, distribution
planning, transmission design, substation design, system
protection, distribution design, system operations, asset
management, communications engineering, and transmission
services groups. Each business unit proposing a project is
required to explain the problem that needs to be addressed, the
alternatives considered, and to provide the justification for
the approach recommended. During the review, the potential
benefits of any cross-business unit synergies that could better
optimize project benefits and scope are also identified and
evaluated.

Rosentrater, Di 38
Avista Corporation
Q. Please list the transmission infrastructure 1
investments planned by the Company and briefly describe each 2
project by investment driver. 3
A. The Company’s planned transmission investments are 4
listed on a system basis in Table No. 2, below, organized by
investment driver. These projects are briefly described
following the table.
Table No. 2 8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Business Case Name 2017 2018 2019
Asset Condition
SCADA - SOO & BUCC $ 1,270 $ 920 $ 1,013
Substation - Station Rebuilds 17,524 7,867 15,800
Transmission Minor Rebuild 5,132 1,843 1,908
Transmission Major Rebuild - Asset Condition 9,536 12,025 11,000
Customer Requested
Growth - Hallet and White 1,458 1,409
Failed Plant and Operations
Electric Storms 3,183 3,278 3,377
Mandatory and Compliance
Colstrip Transmission 325 449 391
Environmental Compliance 72 50 50
Garden Springs 230/115kV Station Integration 56 725
Noxon Switchyard Rebuild 2,504
S Region Voltage Control 5,733
Saddle Mountain 230/115kV Station Integration 1,500 14,500
Spokane Valley Transmission Reinforcement 374 7,750
Transmission - NERC Low Priority Mitigation 2,014 1,500 1,500
Transmission - NERC Medium Priority Mitigation 2,000
Transmission Construction - Compliance 15,309 13,159 13,000
Tribal Permits and Settlements 621 250 150
Westside 230/115kV Station Rebuild 5,566
Performance and Capacity
SCADA Build-Out Program 2,500 6,000
Substation - Capital Spares 4,204 5,065 4,025
Substation - New Distribution Stations 2,424 850 6,375
Total Planned Transmission Capital Projects $ 79,303 $ 60,416 $ 79,814
Transmission Capital Projects (System)
In $(000's)

Rosentrater, Di 39
Avista Corporation
Asset Condition 1
2
SCADA – SOO & BUCC - 2017: $ 1,270,000; 2018: $920,000; 2019: 3
$1,013,000 4
This program replaces and/or upgrades existing electric and
natural gas control center (System Operations Center and Backup
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 upgrades, as well as deployment of
capabilities to meet new operational standards and
requirements. Some system upgrades are initiated by other
requirements, including NERC reliability standards, growth, and
new projects (e.g. Smart Grid). Examples of upgrades to be
completed under this program are Critical Infrastructure
Protection version 5 (NERC standards requirement), Gas Control
Room Management (PHMSA requirement), PEAK Reliability
Coordinator Advanced Applications, and Technology Refresh
(network and storage). The failure to make these investments in
the timeframe planned will result in the Company losing
information connectivity with its transmission system and to be
in violation of NERC transmission planning standards, and
subject to financial and other penalties. 24

Substation – Station Rebuilds - 2017: $17,524,000; 2018: 26
$7,867,000; 2019: $15,800,000 27
This program replaces and/or rebuilds existing substations as
they reach the end of their useful lives or where installed
equipment that fails or is being replaced for capacity needs
cannot be accommodated within the physical constraints of the
small, older stations. Included are wood substation rebuilds
as well as upgrading stations to current design and construction
standards. The failure to timely replace and rebuild end of
life equipment in these substations will expose the Company to
the risk of more frequent and long duration outages that have
a significant impact on our customers. Examples of substation
rebuilds to be completed under this program in the next five
years are Kamiah (wood substation), Ford (end of service life),
9th & Central, Priest River and Colville. This investment
includes associated O&M offsets of $44,884 (System-basis)
beginning in 2017. Ms. Andrews has included Idaho’s share of 42
these offsets within the Company’s requested revenue 43
requirement.
45

Rosentrater, Di 40
Avista Corporation
Transmission Minor Rebuild - 2017: $5,132,000; 2018: 1
$1,843,000; 2019: $1,908,000 2
This project covers transmission structure (ER 2057) and air
switch (ER 2254) replacements based upon the results of the
Company’s annual Wood Pole and Aerial Patrol inspection 5
programs, and field operations. Both the Wood Pole and Aerial
Patrol inspection programs are undertaken to maintain
compliance with NERC Standard FAC-501-WECC-1. Failing to make
the necessary replacements identified by the Company’s 9
inspection programs increases the risk of transmission system
outages and the potential to ignite fires in dry areas. Air
switch replacements are made based either on condition,
capacity, or functionality issues. Prioritization of
installations and replacements are made from information
provided by System Operations, Substation Engineering or the
Company’s regional operations centers. Failing to make the
necessary replacements identified by the Company’s inspection 17
programs risks placing Avista in violation of NERC standards,
and will increase the risk of transmission system outages and
the potential to ignite fires in dry areas. 20

Transmission Major Rebuild - Asset Condition – 2017: 22
$9,536,000; 2018: $12,025,000; 2019: $11,000,000 23
Projects in this program rebuild existing transmission lines
based on overall asset condition (at the end of their useful
life). The failure to timely replace aging transmission
infrastructure on a planned basis will subject our customers to
the increased risk of service outages and increased restoration
costs as we become less able to continue providing our current
level of reliability. In addition to customer outages, the added
risk of failure also impacts the economic dispatch of our
Company’s generation resources and increases the risk of fire 32
in dry areas. Finally, the failure to properly invest builds a
“bow-wave” of needed investments to the future, which makes it
more difficult to fund these projects in addition to our
already-planned priority infrastructure needs. Projects
include: ER 2550 – Burke-Thompson A&B 115kV Transmission Line
rebuild; ER 2604 – Lind-Warden 115kV Transmission Line rebuild;
ER 2577 – Benewah-Moscow 230kV Transmission Line structure
replacement; ER 2597 – Cabinet-Noxon 230kV Transmission Line
rebuild; and ER 2596 – Lolo-Oxbow 230kV Transmission Line
rebuild.

Rosentrater, Di 41
Avista Corporation
Customer Requested 1
2
Growth - Hallett and White Substation - 2017: $1,458,000; 2018: 3
$1,409,000 4
An existing large retail customer is expecting to double its
load over the next 7-10 years beginning in 2018. Additionally,
a wholesale network transmission customer (Inland Power &
Light) has requested an interconnection at the Hallett & White
Substation. These requests together require an increase in
substation transformer capacity and additional feeders. This
project will rebuild the Hallett & White 115/13kV Substation
with two 30MVA transformers and six feeder bays, with one feeder
dedicated to Inland Power & Light, two feeders dedicated to the
Company’s large retail customer, and the remaining feeders 14
available to provide service to the Company’s local 15
distribution system. Failure to construct this project will
result in the inability to serve the requested load of the large
retail customer, and the failure of the Company to provide the
required interconnection and low-voltage wheeling service under
FERC jurisdiction for its wholesale transmission customer.

Failed Plant and Operations Projects: 22

Electric Storms - 2017: $3,183,000; 2018: $3,278,000; 2019: 24
$3,377,000 25
This ongoing program provides for the timely restoration of the
Company’s transmission, substation and distribution facilities 27
into serviceable condition during or following major weather-
related or other natural events including high winds, heavy ice
and snow loads, lightning storms, flooding and wildfires.

Mandatory and Compliance Investments 32

Colstrip Transmission - 2017: $325,000; 2018: $449,000; 2019: 34
$391,000 35
As a joint owner of the Colstrip Transmission System, Avista
is obligated to pay its commensurate ownership share of all
capital improvements. NorthWestern Energy, the designated
Transmission Operator of the Colstrip Transmission System under
the Colstrip Transmission Agreement, implements the capital
program for purposes of maintaining reliable operation and
complying with applicable reliability standards for the jointly
owned facilities. Avista’s failure to pay its share of these
investments would place us in violation of the ownership
agreement and subject us to the legal recourse provided for in
the agreement.

Rosentrater, Di 42
Avista Corporation

Environmental Compliance - 2017: $ 72,000; 2018: $50,000; 2019: 2
$50,000 3
This project covers the implementation of required Forest
Service Special Use Permits (SUP), Waste Oil Disposal,
including polychlorinated biphenyls (PCBs), and Environmental
Compliance requirements related to storm water management,
water quality protection, property cleanup and related issues.
The failure to make these investments would place the Company
in violation of mandatory environmental compliance requirements
and the federal and tribal permits that grant us authority to
use lands for transmission facilities. 12

Garden Springs 230/115kV Substation - 2017: $56,000; 2019: 14
$725,000 15
Due to a lack of redundancy and capacity with the existing
system, the west Spokane area is unable to meet the applicable
NERC transmission planning standards. The project consists of
a new 230kV point of interconnection with BPA at a new station
to be constructed on the Coulee-Westside 230kV Line and the
Garden Springs 230/115kV Substation. The project will mitigate
the identified system deficiencies and provide additional
transformation capacity in the area. If this project, or a
less-than-optimum alternative project that allows us to meet
the standard, is not constructed in the timeframe planned, then
the Company will be in violation of NERC transmission planning
standards and will be subject to the associated penalties. In
addition to violating the planning standard, Avista will also
risk having to shed load (instantaneous disconnecting of
customers from the system) to maintain compliance with NERC
transmission operating standards in the long-range planning
horizon. The Company’s Engineering Roundtable evaluation and
prioritization process has deferred the implementation of the
230kV portion of this project, pending completion of the
Westside 230/115kV Substation rebuild project, in an effort to
balance our overall investment demands, and is considering
other possible alternatives to avoid any NERC transmission
planning standard violations.

Noxon Switchyard Rebuild - 2017: $2,504,000 40
Today, Avista’s Noxon Rapids 230kV Switching Station is subject 41
to a potential fault current of approximately 14,000 amps, which
exceeds the 12,500 amp capability of six 230kV circuit breakers
in the station. This potential is not only an immediate safety
issue, but it also exposes the Company to a violation of NERC
standards. Additionally, the existing station is at the end of

Rosentrater, Di 43
Avista Corporation
its useful life based on age and condition of the equipment in
the station. The existing bus has suffered a number of failures
and is now configured as a single bus with a bus tie breaker
separating the East and West buses. The station is the point
of integration for the Noxon Rapids Hydroelectric development
as well as a principle point of interconnection between Avista
and BPA, providing a key point of integration for the Western
Montana Hydro Complex and the Company’s interconnection with
NorthWestern Energy in Montana. The current bus configuration
requires Avista to curtail its own hydro generation for
unplanned outages of substation equipment to complete work in
the station. The reconstructed Noxon Rapids 230kV Switching
Station will have a double-breaker double-bus configuration to
facilitate required maintenance activities without impacting
local generation levels or transfer loads to or from Montana.
The Company’s Engineering Roundtable process has resulted in 16
the deferral of the broader station rebuild project and focused
on the immediate replacement of the over-dutied circuit
breakers. This is not only an immediate safety issue, but our
failure to make the investments may result in the Company having
to curtail its own hydroelectric generation and further exposes
the Company to a violation of mandatory NERC planning standards. 22
23
South Region Voltage Control - 2017: $5,733,000 24
Avista’s south region 230kV system, primarily in the Lewiston-
Clarkston area, experiences excessively high voltage, where
voltage exceeds equipment ratings over 35% of the time.
Operation of equipment outside of manufacturer’s ratings 28
introduces safety risks to Company operations and employees,
and it increases the possibility of equipment failure and
associated large scale outages. If the Company does not
implement this project in the timeframe planned, then we may be
forced to remove our 230kV lines from service (which is not
possible to do) in order to maintain compliance with NERC
transmission operating standards. This project includes the
installation of two 50MVar shunt reactors on the 230kV bus at
North Lewiston. With automatic control, overvoltages can be
reduced, if not eliminated, on the 230kV buses at Dry Creek,
Lolo, North Lewiston, Moscow and Shawnee. 39

Saddle Mountain 230/115kV Station Integration - 2018: 41
$1,500,000; 2019: $14,500,000 42
This project is the result of a joint regional transmission
planning study team under ColumbiaGrid and resolves a number of
NERC transmission planning standard violations in the Grant
County PUD transmission system that are exacerbated by the

Rosentrater, Di 44
Avista Corporation
Company’s load in the Othello area. Apart from the Grant County 1
PUD system, the Company’s Othello area load is supported by 2
only a single 115kV transmission line connection to the
Bonneville Power Administration. If Avista does not complete
this project in the timeframe planned, then the Company will be
subject to possible litigation before the FERC for failing to
timely complete a project that has been specified by the sub-
regional transmission planning process under the Company’s Open 8
Access Transmission Tariff (OATT). The 230kV portion of the
Saddle Mountain 230/115kV Substation is also required to
integrate a proposed 126 MW wind generation project in the
Othello area.

Spokane Valley Transmission Reinforcement - 2017: $374,000; 14
2018: $7,750,000 15
Portions of the Spokane Valley Transmission Reinforcement
Project already completed include construction of the
Opportunity Substation and Irvin-Millwood 115kV Transmission
Line. Currently planned projects include rebuilding the Beacon-
Boulder #2 115kV Transmission Line and construction of the Irvin
115kV Switching Station. This project must be completed to
mitigate our currently-existing failure to meet NERC
transmission planning standards, and to avoid future
transmission system reliability issues in the Spokane Valley.

Transmission – NERC Low Priority Mitigation - 2017: $2,014,000; 26
2018: $1,500,000; 2019: $1,500,000 27
This program was initiated in response to NERC’s October 7,
2010 NERC Alert Recommendation to the Industry, titled
“Consideration of Actual Field Conditions in Determination of 30
Facility Ratings.” It addresses mitigation required on 31
Avista's “Low Risk” 115kV transmission lines, and brings these 32
lines into compliance with National Electric Safety Code (NESC)
minimum clearance values. This program reconfigures insulator
attachments, rebuilds existing transmission line structures, or
removes earth from beneath transmission lines to mitigate
ratings/sag discrepancies found between facility designs and
actual field conditions. If the Company were to fail to make
these investments we would fail to meet the NERC-required
facility ratings for the safe and reliable operation of these
lines.
42
Transmission – NERC Medium Priority Mitigation - 2017: 43
$2,000,000 44
This program was initiated in response to NERC’s October 7, 45
2010 NERC Alert Recommendation to the Industry, titled

Rosentrater, Di 45
Avista Corporation
“Consideration of Actual Field Conditions in Determination of 1
Facility Ratings.” It addresses mitigation required on Avista's
“Medium Risk” 230kV and 115kV transmission lines, and brings 3
these lines into compliance with National Electric Safety Code
(NESC) minimum clearance values. This program reconfigures
insulator attachments, rebuilds existing transmission line
structures, or removes earth from beneath transmission lines to
mitigate ratings/sag discrepancies found between facility
designs and actual field conditions. If the Company were to
fail to make these investments we would fail to meet the NERC-
required facility ratings for the safe and reliable operation
of these lines.

Transmission Construction – Compliance - 2017: $15,309,000; 14
2018: $13,159,000; 2019: $13,000,000 15
This program reconductors and rebuilds existing transmission
lines to maintain compliance with NERC transmission planning
standards. Investments mitigate NERC transmission planning
standard (TPL-001-4) deficiencies that have already been
identified for both our current system and for the Near Term
transmission planning horizon (1-5 years). Failure to make
these planned investments will result in our failure to comply
with mandatory NERC standards. Projects include: ER 2557 – 9th 23
& Central-Sunset 115kV Transmission Line reconductor and
rebuild; ER 2576 – Addy-Devils Gap 115kV Transmission Line
reconductor and rebuild; ER 2457 – Benton-Othello 115kV
Transmission Line reconductor and rebuild; ER 2556 – CDA-Pine
Creek 115kV Transmission Line reconductor and rebuild; ER 2564
– Devils Gap-Lind 115kV Transmission Line reconductor and
rebuild; and ER 2310 West Plains transmission reinforcement.
Required construction on ER 2578, the Hatwai-Lolo #2 230kV
Transmission Line has been deferred by the Company’s 32
Engineering Roundtable to accommodate the other priority
investment demands.

Tribal Permits and Settlements - 2017: $621,000; 2018: 36
$250,000; 2019: $150,000 37
The Company currently owns and operates approximately 82 miles
of transmission facilities and a significantly greater amount
of distribution facilities on Tribal lands. The failure to
complete this work and to attain proper permitting or easement
rights on Tribal lands would require the Company to relocate
its facilities. This would be cost-prohibitive for its
transmission facilities and not viable for distribution
facilities considering the Company’s obligation to serve its 45
retail customers. Current renewals are being negotiated for

Rosentrater, Di 46
Avista Corporation
terms of from 30 to 50 years. Renewal costs include labor,
appraisals, field work, legal review, GIS information,
negotiations, survey (as needed), and applicable fees for
easements and permits.

Westside 230/115kV Substation Rebuild - 2017: $5,566,000 6
This project is necessary to mitigate our current noncompliance
with mandatory NERC transmission planning standards during
heavy summer loading conditions. Failure to make these planned
investments will result in our failure to comply with mandatory
NERC standards. We will continue to overload the Westside #1
230/115kV transformer during Phase I of this project, which
overloading will extend to the existing Westside Substation
115kV and 230kV buses, to allow for installation of a new 250MVA
230/115kV Autotransformer. The additional transformation
capacity is necessary to eliminate transformer overload
contingencies in the Spokane area. This project has two
additional planned phases to complete the entire rebuild of the
station. The Company’s Engineering Roundtable has deferred the
Garden Springs 230/115kV Substation integration due to the
timing of the planned completion of this project.

Performance and Capacity Investments 23
24
SCADA Build-Out Program - 2018: $2,500,000; 2019: $6,000,000 25
In order to provide the Company’s System Operations group with
the necessary Supervisory Control and Data Acquisition (SCADA)
capability for reliable system operation, this project will
complete the installations of SCADA and EMS/DMS (Energy
Management System/Distribution Management System) capability to
all Avista substations. This capability will provide full
visibility of system conditions and operations, system status
indication, and operator control at each substation. The
communication infrastructure for SCADA will enable the
installation of automation on applicable distribution feeders.
Furthermore, SCADA capability to each substation will provide
real time and historical system performance data to the
Transmission System Planning, Asset Management, Operations and
Engineering groups to enable efficient, flexible and safe
design and operation the Company’s transmission and 40
distribution systems in the future. The failure to make these
investments in the timeframe planned will result in the Company
losing information connectivity with its transmission system
and risk being in violation of NERC transmission planning
standards, and subject to financial and other penalties. 45

Rosentrater, Di 47
Avista Corporation
Substation – Capital Spares - 2017: $4,204,000; 2018: 1
$5,065,000; 2019: $4,025,000 2
This program maintains our fleet of power transformers and high
voltage circuit breakers, which have very long procurement lead
times. Consequently, a sufficient inventory level needs to be
maintained to ensure the Company has required equipment for
construction projects and can quickly replace failed critical
equipment. This critical equipment is capitalized upon receipt
and placed in service for both planned and emergency
installations as required. Annual program expenditures may vary
significantly in years when a 230/115kV autotransformer is
purchased.

Substation – New Distribution Stations - 2017: $2,424,000; 14
2018: $850,000; 2019: $6,375,000 15
This program adds new distribution substations to the system in
order to serve new and growing load as well as to provide
increased system reliability and operational flexibility. New
substations under this program require planning and operational
studies, justifications, and approved project diagrams prior to
funding. Planned new projects include substation sites in the
Pullman/Moscow stateline area, as well as downtown Spokane, the
Spokane west plains area, and north Spokane. The failure to
complete these projects in this planning horizon will result in
equipment overloading and reliability issues, which are
impossible to quickly rectify once they occur.

Q. Please provide some examples of Transmission Capital 28
projects that were not approved, and the risk associated with 29
not completing or deferring these projects. 30
A. The Hatwai-Lolo #2 230kV Transmission Line
construction project, required to comply with NERC transmission
planning standards, has been deferred in order to balance the
overall demand for investment across the Company. The Company’s
engineers continue to evaluate short-range operational
solutions to mitigate transmission system deficiencies in the
southern portion of the Company’s transmission system. Until 37

Rosentrater, Di 48
Avista Corporation
this project can be completed, for certain outages the Company
will continue to have to disconnect its transmission
interconnection with Idaho Power and reconfigure major portions
of its southern system, leaving the majority of the Company’s 4
customers in this area exposed to additional outages.
6
V. NATURAL GAS SYSTEM INVESTMENTS 7
Q. What needs are driving the Company’s planned 8
investments in natural gas distribution infrastructure for the 9
period 2017 - 2019. 10
A. There are many drivers, including the removal of
capacity limitations, we have identified on our natural gas
system that could prevent us from meeting our customers’ needs 13
during periods of very cold weather. Avista is required to meet
a range of mandatory requirements that aim to ensure the
integrity of our natural gas system. It is Avista’s goal, along
with these requirements, to make sure we deliver cost-effective
energy services to our customers in a manner that protects their
health and safety, as well as that of our employees and the
general public. Finally, we face the continuous need to replace
materials and equipment that have reached the end of their
useful life, based on asset condition; to protect our system
from damage by other parties, and respond to the infrastructure

Rosentrater, Di 49
Avista Corporation
plans of municipalities and others that can require us to
relocate portions of our natural gas system. The need for our
natural gas system investments is organized by investment
driver and is briefly explained for each project and program in
the following narrative.
Q. How do the business units in Avista’s natural gas 6
operations identify the need for and prioritize requests for 7
infrastructure investment? 8
A. The need for investment is identified in a number of
ways, including but not limited to, 1) by our field personnel;
2) from needs identified through our systematic maintenance of
the system; 3) by our natural gas engineering group using the
SynerGEE® computer-based modeling tool to evaluate current and
future customer loads and our system capacity to meet them; 4)
from asset management analysis of specific issues; and 5)
through our plans to remediate threats to our system identified
by Avista’s Distribution Integrity Management Planning (DIMP)
process. The integrity management plan processes follow a
rigorous federal protocol for identifying and ranking any risks
or threats that, over time, could impair the integrity of our
natural gas system. Avista is then required to develop action
plans that reduce or eliminate these threats. Implementation of
these plans is mandatory. Our natural gas engineering group

Rosentrater, Di 50
Avista Corporation
serves as the clearing house for evaluating and prioritizing
these investment needs, including which projects are forwarded
to the Company’s Capital Planning Group. Our engineers assess
the range of needs to be met by each individual project, the
potential consequences of deferring or reducing the amount of
the proposed investment, and ranks all proposed projects across
the Company’s entire natural gas system by overall priority of 7
need, with some deference to the geographical locations of the
projects.
Q. Please list the natural gas distribution investments 10
planned for the near-term, and provide a brief description of 11
each project or program?
A. Table No. 3 below lists Avista’s planned natural gas
distribution projects by investment driver on a system basis
for the years 2017-2019. In the narrative that follows I briefly
describe each project or program, explaining why we are
implementing the project, as well as the likely consequence to
Avista of our failure to make these investments in the timeframe
proposed. 19
20

Rosentrater, Di 51
Avista Corporation
Table No. 3 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Asset Condition 38

Gas Deteriorated Steel Pipe Replacement Program - 2017: 40
$1,001,000; 2018: $1,000,000; 2019: $1,000,000 41
Existing steel natural gas piping in the Company’s distribution 42
system is aging and showing signs of deterioration, even when
properly maintained, and it presents an increased risk of
failure in the event it has been subject to corrosion. Sections
Business Case Name 2017 2018 2019
Asset Condition
Gas Deteriorated Steel Pipe Replacement Program $ 1,001 $ 1,000 $ 1,000
Gas ERT Replacement Program 240 260 280
Gas Regulator Stn Replacement Program 1,376 800 800
Customer Requested
New Revenue - Growth 23,099 22,239 22,941
Failed Plant and Operations
Gas Non-Revenue Program 6,096 6,000 6,000
Mandatory and Compliance
Gas Cathodic Protection Program 900 700 700
Gas Facilities Replacement Program (Aldyl A)21,764 20,700 21,160
Gas HP Pipeline Remediation Program 5,275 2,925 3,013
Gas Isolated Steel Replacement Program 2,050 2,000 2,000
Gas Overbuilt Pipe Replacement Program 500 500 500
Gas PMC Program 1,200 1,200 1,200
Gas Replacement Street and Highway Program 3,319 3,000 3,000
Performance and Capacity
Gas Reinforcement Program 1,000 1,000 1,000
Gas Telemetry Program 209 200 200
Gas Schweitzer Mtn Rd HP Reinforcement 1,500
Gas Rathdrum Prairie HP Main Reinforcement Project 4,426 4,000
Subtotal: Natural Gas Distribution Capital Projects $ 72,456 $ 68,024 $ 63,793
Washington and Oregon Direct Business Cases(1)
Gas N-S Corridor Greene St HP Main Project 113
Gas N Spokane Hwy 2 HP Main Reinforcement Project 342
Gas Pierce Rd La Grande HP Reinforcement 3,901
Gas Warden HP Reinforcement 6,000
Cheney HP Reinforcement 5,000
4,356 11,000
Total Planned Natural Gas Distribution Capital Projects $ 76,811 $ 68,024 $ 74,793
(1) Excluded from revenue requirement in this case.
Natural Gas Distribution Capital Projects (System) In $(000's)

Rosentrater, Di 52
Avista Corporation
of gas main with known corrosion-related issues need to be
removed to avoid failure that could impact safety and
reliability. Avista’s distribution integrity management program 3
has identified this pipe material as a threat that needs to be
removed from the Company’s natural gas distribution system. If 5
the Company fails to make the investments needed to remove this
deteriorated piping we would be exposing our customers and the
general public to elevated risk and safety concerns where pipe
is located in the vicinity of high risk facilities, in
particular, where we have leak potential and corrosion issues.
11
Gas ERT Replacement Program - 2017: $240,000; 2018: $260,000; 12
2019: $280,000 13
The majority of the Company’s natural gas meters are equipped 14
with an electronic device that records the amount of natural
gas used by the customer and wirelessly transmits that usage to
Avista for billing purposes. This device known as an Encoder
Receiver Transmitter (ERT) is battery powered, and when these
batteries fail, customers’ estimated usage must be collected
and entered into the billing system manually. Besides the
additional cost, this manual process can lead to high rates of
customer dissatisfaction because of potential error associated
with estimating the customers’ bill. Finally, because the
Company has so many of these units in service, the replacement
of batteries as they failed would quickly become unmanageable
as the entire population of batteries reach the end of their
useful life. The failure to make these planned investments would
eventually have an unsustainable impact on Avista’s natural gas 28
billing system and would result in substantially greater costs
for replacement compared with the systematic approach.

Gas Regulator Station Replacement Program - 2017: $1,376,000; 32
2018: $800,000; 2019: $800,000 33
Investments made under this program replace or upgrade Avista’s 34
natural gas regulator stations and industrial meter sets that
are at the end of their service life, or are obsolete and no
longer supported, based on the Company’s performance standards. 37
Avista’s regulator stations require federally-mandated annual
maintenance, and if the equipment at the stations is obsolete
and replacement/maintenance parts are no longer commercially
available, then proper maintenance cannot be completed. These
investments also enhance the performance of our stations,
improving natural gas system safety, reliability and
operations. The failure to timely inspect our regulators and
industrial meter sets, and to perform required maintenance and
replacements, would render them less reliable and unsafe, and

Rosentrater, Di 53
Avista Corporation
would expose the Company to regulatory and other consequences
as a result of choosing to not make such investments.

Customer Requested 4
5
New Revenue – Growth - 2017: $23,099,000; 2018: $22,239,000; 6
2019: $22,941,000 7
This annual program addresses costs to serve new loads for
natural gas service. This program includes the cost of new
meters, new natural gas piping, the cost of new regulators, the
cost of new encoder receiver transmitters (ERTs), and the
associated installation cost of these investments. Avista is
required by its service tariffs to make the investments
necessary to connect customers when requested.

Failed Plant and Operations 16
17
Gas Non-Revenue Program - 2017: $6,096,000; 2018: $6,000,000; 18
2019: $6,000,000 19
The investments made under this program are responsive to issues
identified by the Company in real time, which is why the
expected capital spend each year is estimated based on
historical trends. Typical activities include increasing the
depth of existing gas lines that are identified as not meeting
the required depth,38 performing customer-requested relocates,
making leak repairs on mains and service lines, installing meter
barricades, eliminating farm taps from the system, and
relocating facilities as required (other than street and
highway). Our failure to regularly perform these activities
would result in a greater likelihood of our shallow pipe being
damaged, which could result in increased general public,
customer, and/or employee safety risks, and prevent us from
prudently managing our natural gas system. 33

Mandatory and Compliance 35

Gas Cathodic Protection Program - 2017: $900,000; 2018: 37
$700,000; 2019: $700,000 38
Cathodic protection involves making in-ground metal structures
like steel pipelines part of a DC electrical circuit that
prevents them from corroding. Avista is required by federal and
state regulations to have effective cathodic protection systems
on all steel natural gas piping in its system. Since these

38 This situation most often occurs because soil above the line has been
removed by other activities in the time after the line was installed.

Rosentrater, Di 54
Avista Corporation
systems have a finite lifespan, and must be replaced when they
are nearing the end of their service life. Failing to timely
replace them renders the underground steel lines vulnerable to
corrosion. This failure would also expose the general public,
our customers, and our employees to increased safety risks and
would place the Company in violation of mandatory regulations.

Gas Facilities Replacement Program (Aldyl A) - 2017: 8
$21,764,000; 2018: $20,700,000; 2019: $21,160,000 9
The Company is continuing its program to systematically remove
and replace select portions of the DuPont Aldyl A medium density
polyethylene pipe in its natural gas distribution system in the
States of Idaho, Washington, and Oregon. Avista’s asset 13
management group identified this piping as prone to the
increased potential of leaking as it ages, and based on the
risks to our customers resulting from these leaks, Avista
implemented its Priority Aldyl A Pipe replacement program. In
addition to the Company’s own analysis, this piping has also 18
been identified as the highest threat to the integrity of
Avista’s natural gas system. Renamed the Gas Facilities 20
Replacement Program, this effort fulfills the Company’s 21
obligation to mitigate such threats on its natural gas system. 22

Gas High Pressure Pipeline Remediation Program - 2017: 24
$5,275,000; 2018: $2,925,000; 2019: $3,013,000 25
Current industry practice and pipeline safety codes require
natural gas distribution systems to be pressure tested, and the
documentation of this testing and the material specifications
of the pipelines to be properly maintained. Avista has
identified deficiencies in its records resulting from practices
generally prior to development of the code and current
standards. This is not uncommon in our industry. A new rule in
the Federal Pipeline Safety Code, making this testing and
documentation mandatory and subject to penalties for non-
compliance, will soon become final and effective. This program
will perform the work required to develop traceable,
verifiable, and complete pressure testing records for all
segments of our high pressure pipeline where the records do not
currently exist. Failure to make these required investments
will expose the Company to penalties for non-compliance with
this mandatory requirement.

Gas Isolated Steel Replacement Program - 2017: $2,050,000; 43
2018: $2,000,000; 2019: $2,000,000 44
The program identifies and documents areas in our natural gas
system where we currently have steel pipe sections, including

Rosentrater, Di 55
Avista Corporation
risers that are “isolated” from steel piping in
cathodically-protected zones. The Company is required by
Federal code to remediate or replace each cathodically-isolated
riser or pipeline section once it has been identified. Avista
operates this program in each of its Idaho, Washington, and
Oregon service territories. Our failure to make these required
investments puts the Company at risk of being in violation of
cathodic protection requirements.

Gas Overbuilt Pipe Replacement Program - 2017: $500,000; 2018: 10
$500,000; 2019: $500,000 11
There are instances where our customers have constructed or
placed structures, sheds and decks, etc., directly over
sections of our natural gas distribution system. As a result of
these “overbuilds” the Company may not have adequate access to 15
operate, repair and safely maintain our system (such as
conducting the annual leak survey of our system). Avista is
required by Federal code to remediate these overbuilds. This
program is focused mainly on identifying and addressing these
issues in mobile home parks where we experience the highest
incidence rates and risks. Avista’s failure to make these 21
planned investments will expose our customers to risks
associated with our inability to access our system, and will
place the Company in violation of its mandatory federal
requirements, and potential penalties.

Gas Planned Meter Change-Out (PMC) Program - 2017: $1,200,000; 27
2018: $1,200,000; 2019: $1,200,000 28
Avista is required by Commission rules and tariffs to test a
portion of our meters each year for accuracy to ensure proper
metering performance. The costs included under this program
include labor and minor materials. Major materials (meters,
pressure regulators and encoder receiver transmitters) are
charged to the appropriate capital programs. Our failure to
make these investments would increase the likelihood that our
customers’ billing would be inaccurate and would place the 36
Company in violation of its tariffs, with the attendant
consequences of non-compliance.

Gas Replacement Street and Highway Program - 2017: $3,319,000; 40
2018: $3,000,000; 2019: $3,000,000 41
Nearly all of Avista’s distribution pipelines are located in 42
public utility easements provided for such service, which are
under the control of local jurisdictions administered through
the Company’s franchise agreements. Avista is mandated under 45
these agreements to relocate its facilities, at our cost

Rosentrater, Di 56
Avista Corporation
whenever local jurisdictional projects require such a move.
While Avista has the opportunity to discuss these requirements
and to suggest ways to avoid or minimize the cost to our
customers, we have no choice but to move our facilities if
required. Our failure to make such required investments would
put the Company in violation of its franchise agreements, could
subject us to penalties for the delay of a project, legal
action, or the revocation of our franchise to provide utility
service in that jurisdiction. 9

Performance and Capacity Investments 11

Gas Reinforcement Program - 2017: $1,000,000; 2018: $1,000,000; 13
2019: $1,000,000 14
This ongoing program supports investments for smaller projects
needed to reinforce the capacity of our natural gas distribution
system in all our jurisdictions. Our failure to make these
investments would expose our customers to the loss of their
natural gas service on a design day, and would prevent Avista
from meeting future load growth due to inadequate pressure and
capacity.

Gas Telemetry Program - 2017: $209,000; 2018: $200,000; 2019: 23
$200,000 24
Projects under this program install natural gas telemetry
throughout our natural gas system. Telemetry is the combination
of communications and sensing systems that allow Avista to
remotely monitor system pressures, volumes, and flows from
areas of special interest such as Gate Stations (supply points
into Avista’s system), gas transportation customers, regulator
stations (where operating pressure is reduced), certain large
industrial customers, and distribution systems that are served
by more than one source of natural gas. Having this detailed
“visibility” of the gas transmission and distribution systems 34
provides a more rapid response and better decision making by
the Company when any abnormal operation or emergency situation
occurs. The failure to timely make these investments would
reduce the reliability of our system for customers resulting
from low or high pressure situations, and the related safety
risks, and a higher likelihood of equipment failures that impact
our service.

Rosentrater, Di 57
Avista Corporation
Gas Schweitzer Mtn Rd High Pressure (HP) Reinforcement39 – 2018: 1
$1,500,000 2
The Sandpoint Idaho area has exceeded the capacity of the
existing gas distribution system. This area has insufficient
capacity to serve firm customers on a design day. Therefore, 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). Without this reinforcement project, Avista will
not have sufficient capacity to serve firm customer load in the
Sandpoint area on a design day scenario.

Gas Rathdrum Prairie High Pressure (HP) Main Reinforcement 18
Project – 2017: $4,426,000; 2018: $4,000,000 19
This multi-year project is composed of a two phase high pressure
distribution pipeline reinforcement that will shift gas usage
from Williams Northwest Pipeline (NWP) to Gas Transmission
Northwest (GTN). This project 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 growth in the Post Falls, ID and
Coeur d'Alene, ID areas currently served from NWP. Phase one
and phase two both consist of installing approximately three
miles of 6” high pressure distribution pipeline and two 29
Regulator Stations (pressure reduction stations) within
Avista’s system, with phase one scheduled to be constructed in 31
2017 and phase two constructed in 2018. Load growth on the 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. In addition, the 35
distribution system in the Hayden Lake, Idaho 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

39 After completion of the Company’s revenue requirement the Company
determined that the transfers to plant associated with this project should
be excluded from the revenue requirement in this Idaho rate case. The Company
will update these transfer to plant amounts during this case.

Rosentrater, Di 58
Avista Corporation
customer load in the Coeur d’Alene, ID to Kellogg, ID corridor 1
in a design day scenario.

Q. Please provide some examples of Natural Gas Plant 4
Capital projects that were not approved, and the risk associated 5
with not completing or deferring these projects. 6
A. The Overbuild Pipe Replacement Program was reduced
from $900,000 to $500,000 per year. This resulted in an
approximately 45% reduction of main and service replacement
work. The reduced funding would still allow us to address some
of the overbuilt facilities with known risk, but at a pace
slower than normal plans to address these safety concerns and
maintain compliance. The outcome 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.

VI. GENERAL PLANT AND FLEET INVESTMENTS 18
Q. Please discuss the drivers for the Company’s 19
investments grouped under the category of general plant for the 20
period 2017-2019. 21
A. The majority of these programs and projects are
investments made to maintain, improve or replace the Company’s 23
offices, service centers, material storage facilities and their
associated properties, based generally on asset condition or to

Rosentrater, Di 59
Avista Corporation
address performance and capacity needs. In addition to having
responsibility for maintaining this infrastructure, Avista’s 2
facilities management group responds to needs identified by the
business and develops responsive projects that support our
customer service center; provide ample employee work space;
provide for employee and customer safety and efficiency in the
flow of pedestrian and vehicle traffic on our central campus;
meet the needs of fleet operations; provide space for our field
service employees in electric and natural gas operations;
ensure adequate space for equipment in our warehouses and
storage yards; accommodate the safe and efficient handling of
hazardous waste and to manage environmental issues; and provide
for safe and adequate employee and customer parking.
Q. How does Avista’s facilities group evaluate 14
alternatives to meet identified needs and prioritize capital 15
projects before they are recommended to the Capital Planning 16
Group? 17
A. The facilities group completed a survey of the
structures and appurtenant facilities at each of Avista’s 19
operations service centers. Each was rated on asset condition,
based on factors including site utilities, interior condition,
plumbing and HVAC, and fire safety systems. Using this
information the facilities manager and one or more of the

Rosentrater, Di 60
Avista Corporation
group’s project managers, met with employees representing
electric and natural gas energy delivery, environmental
affairs, real estate, and finance, to review the survey results
in the context of the business needs identified by each area.
Beyond these immediate needs they factored in the needs of our
customers, the potential for future expansion, current and
expected materials storage needs (including offsite storage
yards), environmental concerns, safety and compliance
considerations, and site location. This team of employees
representing the respective areas of the business then
recommended whether each service center should be sold and
replaced, replaced on the same site, or should continue to be
maintained, repaired, remodeled, and improved with capital
upgrades as warranted. Needs were then prioritized based on the
condition factors listed above. 15
Q. Please briefly describe the infrastructure projects 16
under general plant planned for the period 2017 – 2019.
A. These individual projects and programs by year are
listed in Table No. 4, and are briefly described in my testimony
below.
21

Rosentrater, Di 61
Avista Corporation
Table No. 4 1

31
Asset Condition 32
33
COF Long-Term Restructuring Plan - 2017: $2,064,000 34
The remaining investments under this plan conclude a multiyear
effort that began in 2013 and included nine individual projects.
These projects completed in their sequence were required for
implementation of the Campus Repurposing Phase 2 plan. All of
these projects have been completed, with the exception of the
expansion of the warehouse storage yard. Without the expansion,
the Company will lack adequate and efficient space for its
materials storage needs, which today impact crews’ efficient 42
access to materials since they are stored at multiple locations
at our central office as well as offsite. 44

Business Case Name 2017 2018 2019
Asset Condition
COF Long-Term Restructuring Plan $ 2,064
Dollar Rd Service Center Addition and Remodel 321 17,710
Noxon & Clark Fork Living Facilities 1,411 1,563
Structures and Improvements/Furniture 3,294 3,600 3,600
Customer Service Quality and Reliability
Meter Data Management System 24,745
Failed Plant and Operations
Capital Tools & Stores Equipment 2,712 2,400 2,400
Performance and Capacity
Apprentice Training 60 60 60
CNG Fleet Conversion 52
COF Long-Term Restructuring Plan 2(1)13,695 10,000
Company Aircraft Capital 296 3,000
Ergonomic Equipment 616 300
Airport Hangar 1,500
Subtotal: General Plant Capital Projects 50,765 38,633 6,060
Washington Direct Business Cases(2)
New Downtown Netwk Bldg 6,559
New Deer Park Service Center 6 6,247
6,565 6,247
Total Planned General Plant Capital Projects $ 57,330 $ 44,880 $ 6,060
(1) COF = Central Office Facilities
(2) Excluded from revenue requirement in this case.
General Plant Capital Projects (System)
In $(000's)

Rosentrater, Di 62
Avista Corporation
Dollar Road Service Center Addition and Remodel40 - 2017: 1
$321,000; 2018: $17,710,000 2
This planned investment would replace the existing natural gas
operations service center at the existing site. The Dollar Road
Service Center is the main natural gas operations center serving
approximately 300,000 customers in the greater Spokane area,
performed by approximately 70 field crews and administrative
support employees. The service center also provides support
for local gas crews from the Ritzville, Colville, and Davenport
districts, which serve an additional 50,000 customers. The
existing Dollar Road Service Center is approximately 22,000
square feet and was constructed in 1956. Our business needs
have changed substantially since that time as a result of
industry advances and growth in customers. In addition to work
flow, many of the main building components, systems, and
equipment have deteriorated with age and are past their useful
service life. The Dollar Road Service Center scored the second
lowest among the Avista facilities rated for asset condition in
2012. If the Company fails to make this investment as planned,
we will continue to operate at the level of efficiency currently
limited by this facility, we spend increasing amounts of capital
and expenses for heavy maintenance, replacement of internal
systems, and repair of structures and systems that fail prior
to replacement.

Noxon & Clark Fork Living Facilities - 2017: $1,411,000; 2018: 26
$1,563,000 27
This project includes the rehabilitation of two living
facilities at Clark Fork, Idaho and Noxon, Montana, to address
deteriorating condition of the facilities and their systems,
extend the life of the facilities, and update them to a more
modern and energy efficient state. The project combines
required repair work with the facility renovation to avoid
duplicating efforts and saving costs on contractor mobilization
and re-work. The living facilities were constructed in 1983 and
1984 and have been in use for more than 30 years. They are 16-
room bunkhouses with a common space containing a kitchen, dining
hall and laundry facility. Because of the limited availability
of lodging in this rural area, Avista crews and personnel lodge
at these facilities when performing work at Noxon Rapids Dam,

40 After completion of the Company’s revenue requirement the Company
determined that the transfers to plant associated with this project should
be excluded from the revenue requirement in this rate case. The Company will
update these transfer to plant amounts during this case.

Rosentrater, Di 63
Avista Corporation
Cabinet Gorge Dam, or on other Avista equipment in the area.
During inspections in 2015, extensive issues were found with
the facilities, including structural and water damage to the
siding and framing due to water penetration, inadequate and
antiquated electric heating systems, HVAC deficiencies and non-
compliant electric breaker panels and inadequate insulation.
This project would address the structural and water damage,
bring the building up to modern code, and extend the life of
the facility. The completed facilities would provide years of
additional service, increase the efficiency of energy usage,
reduce annual O&M costs to maintain the structures, and provide
a suitable environment for housing our workforce at these remote
sites. Disregarding the continuing water penetration was not an
option as this would render portions of, and eventually the
entire facility, uninhabitable over time. Maintenance and
upgrade work is ongoing at both dams and is planned for the
foreseeable future. This work is essential to maintaining the
reliability of our power generation and associated
infrastructure in the region. Without the continued
availability of the living facilities, it’s estimated that it 20
would cost more than $300,000 annually to procure lodging at
alternate sites for work at the plants, likely in Sandpoint or
Thompson Falls, about an hour drive one way from the plant.
With a centralized workforce based out of Spokane, the ability
to provide lodging near our worksites maximizes available
working hours.

Structures and Improvements/Furniture - 2017: $3,294,000; 2018: 28
$3,600,000; 2019: $3,600,000 29
This ongoing capital program funds lifecycle equipment
replacements and needed improvements at more than 40 Avista
offices and service facilities (exceeding 900,000 square feet).
These needs are compiled, evaluated and prioritized based on
need and asset condition and lifecycle standards, designed to
address: 1) Lifecycle asset replacements (examples: roofing,
asphalt, electrical, plumbing); 2) Lifecycle furniture
replacements and new furniture additions (to support growth),
and 3) Business additions or site improvements (examples:
adding a welding bay, vehicle storage canopy, expanding an
asphalt yard, and can sometimes include property purchases to
support site expansions). The replacements based on asset
condition are intended to achieve a more stable and predictable
level of capital requirements, and to avoid peak investments
caused by coincident and large-scale failures. The failure to
make these timely investments will result in reduced
efficiency, safety issues, accelerated deterioration and

Rosentrater, Di 64
Avista Corporation
failure of assets, such as roofing or HVAC systems, which can
result in major damage to the facilities, and a bow-wave of
needed investments to the future.

Customer Service Quality and Reliability 5

Meter Data Management System – 2017: $24,745,000 7
The Meter Data Management System (MDM) will store data from
meters for Avista’s Idaho, Washington, and Oregon customers
through integrations with the existing metering systems
currently collecting consumption data, including the existing
AMR system in Idaho. This system will allow consideration of
daily meter reads, and enable appointment scheduling and
optimized routing through the integration of the MDM’s Service 14
Order Management module with Oracle CC&B. The appointment
scheduling and routing optimization capabilities will allow
service order management to be centralized on one system,
providing consistent work processes and improved operational
efficiency. The MDM system will replace the custom
functionality that the Company added onto the Oracle’s Customer 20
Care and Billing (CC&B) system as an interim meter data solution
until a fully functional MDM system could be implemented, and
which was not designed to support meter data with large volumes
of data. When the Company is ready to install Advanced Metering
Infrastructure (AMI) meters in Idaho, these meter reads will
continue to be stored in MDM through similar integrations with
the new AMI metering system. If Avista failed to make this
investment, it would need to implement two or more separate
meter data systems of record in order to accommodate each
jurisdiction, which would increase cost and complexity.

Failed Plant and Operations 32

Capital Tools & Stores Equipment - 2017: $2,712,000; 2018: 34
$2,400,000; 2019: $2,400,000 35
Avista’s capital tools program provides Company employees with
proper tooling and equipment needed to safely and efficiently
construct, monitor, manage system integrity, and properly
repair and maintain our electric, gas, communications, fleet,
facilities, and generation infrastructure. If the Company fails
to provide its employees proper tools and equipment when they
are needed, we would be unable to provide our customers with
adequate, reliable and cost effective services that meet their
expectations for quality and value. These tools and equipment
also support the safety of our employees.

Rosentrater, Di 65
Avista Corporation

Performance and Capacity 2

Apprentice Training - 2017: $60,000; 2018: $60,000; 2019: 4
$60,000 5
This investment consists of on-going capital facility
improvements needed to support required training for
apprentice, pre-apprentice, and journey level craft workers,
ensuring they are prepared to safely meet the specialized
technical needs to build and properly maintain electric and
natural gas utility systems. Expenditures include expanding
existing or constructing new facilities, purchase of training
equipment, and the construction and maintenance of actual
utility infrastructure designed specifically for the training
of employees.

Compressed Natural Gas (CNG) Fleet Conversion - 2017: $52,000 17
This program supports the continuing conversion of a portion of
Avista’s fleet vehicles to run on compressed natural gas (CNG). 19
The use of natural gas by our vehicles helps Avista reduce
vehicle emissions and lower our operating costs. Operating our
natural gas-powered fleet has also allowed us to provide our
customers and others, who have been considering a natural gas
powered vehicle, with practical experience on the requirements
of owning and operating natural gas fueled vehicles.
Importantly, we also use our natural gas compression system to
fuel our truck and trailer-mounted natural gas storage tanks
that allow us to maintain natural gas service to our customers
when the distribution system has been damaged or is being
serviced by the Company.

COF Long-Term Restructuring Plan Phase 2 - 2017: $13,695,000; 32
2018: $10,000,000 33
Phase 2 of this plan is a continuation of the long-term program
to meet our ongoing and future operating needs by renovating,
improving and expanding our existing central office and
operating facilities. This phase is composed of three major
projects that include re-routing a city street adjacent to our
campus in 2017, constructing a new building for our fleet
operations in 2017 and 2018, and constructing a parking garage
in 2018. These three projects are interdependent because of
their location, timing of construction and their relationship
to the overall design of our central campus. These projects
support Avista’s objectives of 1) consolidating the footprint
of our central facilities, which today consists of several
disjointed parcels; 2) modernize and expand our aging fleet

Rosentrater, Di 66
Avista Corporation
facilities to handle today’s needs efficiently, meet compressed 1
natural gas fleet compliance, better manage environmental
concerns, and provide the space required for efficient queuing
of fleet equipment; 3) Provide adequate campus parking for
employees, which is currently short by about 400 spaces, and
consolidate parking on company-owned land, improving employee
and public safety by eliminating our parking sprawl, and 4)
separate currently shared traffic routes for our construction
vehicles and equipment and pedestrians to improve safety and
increase workflow efficiency. Avista selected this plan from
several options evaluated by the facilities group for meeting
these combined needs. The failure to implement these plans in
the timeframe proposed will result in work being terminated
mid-stream on work underway, adding significantly to future
costs to complete these projects, will require Avista to make
alternative investments to mitigate the operational and
environmental limitations of our existing fleet operations, and
fail to resolve significant issues related to our current
employee parking. 19

Company Aircraft Capital - 2017: $296,000; 2018: $3,000,000 21
This investment is to purchase the 18-year old Cessna Citation
VII aircraft that the Company has leased since 2000. In March
2018, the current lease will expire, which provides for an end-
of-term purchase option that applies prior lease payments
toward the purchase in a lump-sum amount. In addition to the
purchase price of approximately $2.5 million, the planned
investment also includes updating the avionics to comply with
new FAA mandates at a cost of approximately $500,000, and self-
funding the parts plan for the aircraft. The planned purchase
option will save approximately $1.1 million in annual expenses.
Approximately 50% of flights made each year directly support
the Company’s utility regulatory activities and the remainder
supports travel to Avista’s regional offices and other business 34
requirements. A large portion of these destinations are not
served by a commercial airline.
37
Ergonomic Equipment - 2017: $616,000; 2018: $300,000 38
It is the Company’s goal to help our employees be more engaged
with maintaining their health, wellness and work productivity.
An important step has been the introduction of ergonomic
programs, office equipment and education. This effort reduces
workplace injuries and other health impacts and helps Avista
avoid the associated health costs. This program provides
employees with ergonomic equipment and training.

Rosentrater, Di 67
Avista Corporation
Airport Hanger - 2017: $1,500,000
This project is to build an Avista-owned hangar on leased land
at Spokane International Airport. This facility will replace
the hangar we currently sublease, which will be demolished after
our sublease is withdrawn in July 2018. Avista’s facilities 5
group considered four options for securing a hangar for the
aircraft, which included building a new hangar, extending use
of the current leased hangar, relocating to another airport,
and co-use of an existing hangar. The solution to construct a
hangar on land leased from the Spokane International Airport
was selected for several reasons, including the location, site
security, cost, efficiency and cost of aircraft maintenance,
and operational safety and efficiency. The failure to make this
investment in the timeframe planned will require Avista to adopt
an alternative from among those already evaluated and
determined to be inferior. 16
Q. Are there additional infrastructure projects planned 17
for the period 2017 – 2021 that have not been previously 18
addressed in your testimony?
A. Yes. Two additional projects are listed in Table No.
5, and are briefly described in my testimony below.
Table No. 5 22
23
24
25
26
27
Asset Condition 28
29
Fleet Capital Replacement Program - 2017: $7,898,000; 2018: 30
$7,850,000; 2019: $7,850,000 31
Avista’s replacement of its service vehicles and heavy
equipment is based on the analysis of total life cycle costs,
optimized to achieve the lowest total cost of ownership. To
perform this analysis, the Company relies on the “Vehicle 35
Business Case Name 2017 2018 2019
Asset Condition
Fleet Capital Replacement Program $ 7,898 $ 7,850 $ 7,850
Mandatory and Compliance
Jackson Prairie Storage 1,718 1,562 1,483
$ 9,616 $ 9,412 $ 9,333
Other Capital Projects (System)
In $(000's)

Rosentrater, Di 68
Avista Corporation
Replacement Model” provided by Utilimarc. The model uses 1
benchmarking information, purchase and auction sales data,
combined with a range of nationwide vehicle statistics, to
produce a robust estimate of the optimum timing for replacement
of vehicles based on its residual value, the maintenance
required to keep the vehicle in service, and the cost of a
replacement. Capital project requests are created for each
vehicle and piece of equipment to be replaced and the
prioritization of projects is based on minimizing our overall
business risk and costs of ownership. This approach to replacing
assets based on condition, prior to its likely failure, has
helped the Company avoid numerous incidents of vehicles failing
while in service, resulting in extended vehicle and crew down
time, high cost for parts and labor required for emergency
repairs, and unplanned replacements. These costly incidents
would be the result if the Company were to fail to make the
investments in its service vehicles and equipment planned
during this timeframe.
19
Mandatory and Compliance 20
21
Jackson Prairie Storage - 2017: $1,718,000; 2018: $1,562,000; 22
2019: $1,483,000 23
These projects include various capital improvements that Avista
and its partners will complete at the Jackson Prairie facility.
The Company is one-third owner in the Jackson Prairie Storage
Facility and as such, is a part of the Jackson Prairie Storage
Management Committee that meets annually to discuss and approve
the capital and O&M projects needed for this facility. The
Company’s failure to make these investments in the timeframe 30
planned would place us in violation of the joint owners’ 31
agreement to make these needed investments. 32

Q. Please provide some examples of General Plant Capital 34
projects that were not approved at the requested amount, and 35
the risk associated with not completing or deferring these 36
projects. 37
A. In 2015 and 2016, capital tools and equipment
requests exceeded what was funded by approximately $800,000
each year. (see Exhibit No. 8, Schedule 5 under the Capital

Rosentrater, Di 69
Avista Corporation
Tools Business Case Justification Narrative). Capital tool
requests are prioritized by safety and compliance, replacement,
and enhanced productivity. 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. All construction, maintenance, and repair work
performed at Avista is dependent on the use of capital tools
and equipment. Without the necessary equipment, workers cannot
perform their duties safely or efficiently, and Avista
facilities and equipment could no longer be maintained. 14
The Facilities Structures and Improvements program funds
the capital maintenance, site improvement, and furniture
budgets at Avista’s offices, storage buildings, and service 17
centers. This program is intended to address the following
needs:
 Lifecycle asset replacements (examples: roofing,
asphalt, electrical, plumbing);
 Lifecycle furniture replacements and new furniture
additions (to support growth); and
 Business additions or site improvements (examples:
adding a welding bay, vehicle storage canopy, expanding

Rosentrater, Di 70
Avista Corporation
an asphalt yard, and can sometimes include property
purchases to support site expansions.)
Lifecycle asset replacements are typically funded first,
with furniture replacements and business site improvement
requests taking a lower priority. Each year, requests for
funding through this program far exceed available funds. In
2017 we funded $3.3 million of $7.4 million in requested
projects. In 2016, requests totaled $6.3 million and we funded
$3.6. In 2015, requests totaled $9.8 million, and we funded
$4.6 million.
Sites decline due to normal wear 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.
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. 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

Rosentrater, Di 71
Avista Corporation
category can help support improved processes and lead to
enhanced safety and longer lifecycles. 2
Q. Does this conclude your pre-filed direct testimony? 3
A. Yes.