20230201DiLuciano Exhibit 9 Schedule 1-3.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]
[e-mail]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. AVU-E-23-01
CASE NO. AVU-G-23-01
EXHIBIT NO. 9
OF JOSHUA D. DILUCIANO
(ELECTRIC AND NATURAL GAS)
Avista Utilities Asset Management
Protocol for Managing Select Aldyl A Pipe in Avista
Utilities‟ Natural Gas System
May 2013
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 1 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 2

Protocol for Managing Select Aldyl A Pipe in Avista Utilities’
Natural Gas System

Executive Summary

Avista Utilities (Avista) protocol for managing select Aldyl A pipe proposes a twenty-
year 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
Washington, Oregon and Idaho. None of the subject pipe is “high pressure main pipe,”
but rather, consists of distribution mains at maximum operating pressures of 60 psi and
pipe diameters ranging from 1¼ to 4 inches. Further, Avista notes that while there have
been concerns with the integrity of steel pipe in other parts of the country in recent years,
the steel pipe in its system, including steel service risers, is being managed to protect its
long-term reliability and performance and is outside the scope of this program.

In recent years, Avista experienced two incidents on its natural gas system that prompted
the Washington Utilities and Transportation Commission and the Company to better
understand the potential long-term reliability of Aldyl A pipe. Results of these
investigations, which were aided by new tools developed for Avista‟s Distribution
Integrity Management Plan, corroborated reports for similar Aldyl A piping around the
country as supporting the development of a protocol for the management of this gas
facility. The following report highlights the history of DuPont‟s Aldyl A natural gas pipe
and summarizes DuPont and Federal Agency communications that are relevant to this
proposed program. The report documents the Aldyl A pipe in Avista‟s natural gas
system and describes the analysis of the types of failures observed in this pipe, and the
evaluation of its expected long-term integrity. Finally, the report describes the results of
Avista‟s work to establish the framework for the proposed protocol for the management
of Aldyl A pipe in its natural gas system.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 2 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 3

Table of Contents
I. History of DuPont Aldyl A Piping Systems .......................................................................... 5
DuPont Introduces Natural Gas Polyethylene Pipe – 1965 .................................... 5
The Phenomenon of “Low Ductile Inner Wall” ..................................................... 5
DuPont Communicates Potential Issues to Aldyl A Customers ............................. 5
1982 Letter ...................................................................................................... 5
1986 Letter ...................................................................................................... 6
DuPont Substantially Improves Aldyl A Pipe ........................................................ 6
Common Classifications of Aldyl A Pipe ............................................................... 7
II. Federal Bulletins on Brittle-Like Cracking in Plastic Pipe ................................................. 8
National Transportation Safety Board .................................................................... 8
Objectives of the Board‟s Investigation .......................................................... 8
Phenomenon of Premature Brittle-Like Cracking ........................................... 9
Board Findings on the Three Identified Safety Issues .................................... 9
Pipeline and Hazardous Materials Safety Administration .................................... 12
1999 Bulletins ................................................................................................ 12
2002 Bulletin ................................................................................................. 12
2007 Bulletin ................................................................................................. 12
III. 2009 Distribution Integrity Management Program ........................................................... 12
Objectives and Approach ...................................................................................... 12
IV. 2011 Call to Action – Transportation Secretary LaHood ................................................. 13
V. Avista’s Experience with DuPont Aldyl A Piping Systems ............................................... 14
Spokane and Odessa Incidents .............................................................................. 14
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to
Reported Soil Conditions .............................................................................. 15
Evaluation of Leak Survey Records .............................................................. 16
Pipe Replacement Projects in 2011 ............................................................... 16
Avista Distribution Integrity Management Program ............................................ 16
VI. Analyzing Modes of Failure in Avista’s Aldyl A Pipe ....................................................... 17
Towers and Caps ........................................................................................... 18
Rock Contact and Squeeze-Off ..................................................................... 19
Services Tapped from Steel Mains ................................................................ 20
Avista‟s Aldyl A Services ............................................................................. 21
Understanding the Significance of Leaks in Aldyl A Pipe ................................... 21
Frequency and Potential Consequence .......................................................... 21
The Complication of Brittle Cracking in Aldyl A Pipe ................................. 22
VII. Reliability Modeling of Avista’s Aldyl A Piping ................................................................ 22
Availability Workbench Software ........................................................................ 22
Reliability Forecasting .......................................................................................... 23
Forecasting the Reliability of Aldyl A Piping ...................................................... 23
Forecasting Results ............................................................................................... 24
Forecast Piping Failures ................................................................................ 24
Dependability of Forecasting Future Failures ............................................... 24
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 3 of 35
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Understanding the Significance of Cumulative Failure Curves .................... 25
Prudent Failure Management ........................................................................ 25
Priority Aldyl A Piping ................................................................................. 26
VIII. Formulation of a Management Program for Priority Aldyl A Pipe ................................. 26
Priority Aldyl A Piping in Avista‟s System .......................................................... 27
IX. Other Aldyl A Pipe Replacement Programs ....................................................................... 28
Aldyl A Pipe in the Pacific Northwest .................................................................. 28
Established and Emerging Programs for Aldyl A Pipe Replacement................... 28
Developments of Interest ...................................................................................... 29
X. Designing Avista’s Replacement Protocol for its Priority Aldyl A Pipe .......................... 30
Systematic Replacement Program ........................................................................ 30
Time Horizon ................................................................................................ 30
Prudent Management of Potential Risk ......................................................... 30
Prioritizing the Work ..................................................................................... 31
Twenty-Year Proposal ................................................................................... 31
Initial Optimization ....................................................................................... 32
Responsive Replacement Program ....................................................................... 33
Dr. Palermo‟s Assessment of the Proposed Protocol for Managing ..................... 33
Avista‟s Priority Aldyl A Piping........................................................................... 33
XI. Application of Avista’s Washington State Study Results to Aldyl A Pipe in the States of
Oregon and Idaho ................................................................................................................. 34
XII. Resource Requirements and Expected Cost ....................................................................... 34
Staffing .................................................................................................................. 34
Capital Costs ......................................................................................................... 35

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
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History of DuPont Aldyl A Piping Systems

Modern polyethylene pipe products are corrosion-free, lightweight, cost-effective,
highly-reliable, and can be installed quickly and efficiently. For these reasons, it has for
decades been the „standard for the industry‟ and is the predominant choice used in natural
gas distribution systems. As with any revolutionary product line, polyethylene piping
systems have undergone continuous and rigorous testing and product improvement. Such
is the case with DuPont‟s Aldyl A piping systems, as very briefly summarized below.
DuPont Introduces Natural Gas Polyethylene Pipe – 1965

Along with other manufacturers, DuPont began to use polyethylene resin to produce
plastic piping for a variety of purposes. The resin was produced from ethylene molecules
combined together in repeating patterns to form larger molecules called „polymers‟,
hence the name „polyethylene.‟ DuPont‟s product designed specifically for use in the
natural gas industry was marketed under the name “Aldyl A.” The initial resin used in
production of Aldyl A pipe, Alathon 5040, was manufactured from 1965 to 1970.
DuPont changed the resin in 1970 to improve Aldyl A‟s resistance to rupture during
pressure testing. This improved formulation, known as Alathon 5043, was the primary
resin used in DuPont‟s Aldyl A pipe from 1970 until 1984.
The Phenomenon of “Low Ductile Inner Wall”

Shortly after changing its polyethylene resin in 1970, DuPont detected a manufacturing
issue highlighted during laboratory testing of Aldyl A pipe. DuPont learned that its
manufacturing process was resulting in some of the pipe having a property described as
“low ductile inner wall.” “Ductility” is the ability of a material to withstand forces that
alter its shape without it losing strength or breaking. A „highly-ductile‟ material can be
bent, flexed, pressed or stretched without cracking or losing strength because, unlike
brittle materials, it can redistribute the forces of stress concentration. Low Ductile Inner
Wall, or as it often appears “LDIW,” results when the inner surface of the Aldyl A pipe
becomes brittle, promoting the formation of cracks and premature failure. In early 1972,
DuPont changed its manufacturing process to eliminate this phenomenon, but estimated
that 30 – 40% of the pipe it produced in 1970, 1971 and early 1972 was affected,
primarily in pipe diameters from 1¼ inches to 4 inches.
DuPont Communicates Potential Issues to Aldyl A Customers
1982 Letter

In 1982, DuPont sent a letter to its natural gas customers, noting that two of its gas utility
customers had reported a low frequency of leaks in Aldyl A pipe manufactured prior to
1973. These leaks were reported as “slits” occurring where the pipe was in “point contact
with rocks.” DuPont noted these two utilities had increased the frequency of leak surveys
where rock may have been part of the backfill around the pipe, and encouraged other
Aldyl A customers to consider the same. This letter was the genesis of what would
become a continuing focus on the pipe vintage known as “pre-1973 Aldyl A.”
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
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1986 Letter

DuPont‟s second letter to its Aldyl A pipe customers was sent in 1986, focusing again on
pre-1973 Aldyl A pipe. The letter focused on results of newly-developed (elevated
temperature) testing methods that allowed DuPont to more-accurately estimate the
longevity of this vintage pipe, in diameters of 1¼ inches and larger. Test results showed
that „Aldyl A pipe manufactured prior to 1973 had certain limitations that were not
previously-shown by then-available, state-of-the-art testing methods.‟ The limitations
were described as a reduction in pipe service life caused by: 1) “rock impingement” or
pressure from rock points directly on the pipe (as mentioned in their 1982 letter), and 2)
the use of squeeze-off practices. The term “squeeze-off” refers to the current and long-
standing construction practice of mechanically pressing in polyethylene pipe walls to
temporarily stop the flow of gas during work on a line that is in service. DuPont further
noted that average ground temperature surrounding the pipe, in the ranges of 60 to 70
degrees (F), had a major bearing on its ultimate expected service life. Finally, DuPont
recommended that operators should reinforce the pipe, using clamps that surround the
pipe at squeeze points, in order to extend the life of its Pre-1973 Aldyl A.
DuPont Substantially Improves Aldyl A Pipe

DuPont made a significant change to its Aldyl A resin formulation in 1984. The
improved resin, known as Alathon 5046-C, was marketed as “Improved Aldyl A”, and
significantly improved the performance of Aldyl A pipe in its resistance to „Slow Crack
Growth‟ and overall long-term integrity. Slow Crack Growth, or as it‟s often
abbreviated, SCG, describes the progression of a crack that begins with „crack initiation‟
or the formation of a crack in the inner wall of the pipe. The crack then progresses
through the pipe wall, usually over period of many years, until it finally breaks through
the outer surface of the pipe, resulting in failure.

Again, in 1988, DuPont announced another advance in its Aldyl A pipe resin with the
introduction of Alathon 5046-U. This change in resin formulation increased the
resistance of the pipe to slow crack growth by another order of magnitude. In addition,
because of the high „molecular efficiency‟ of this new resin, its density was also reduced,
which allowed for much greater ductility in the pipe. This product, the last of the DuPont
Aldyl A materials that Avista would install, was also marketed as Improved Aldyl A. A
summary of DuPont Aldyl A pipe produced between 1966 and 1992 is presented below
in Table 1. Information includes the year of manufacture, resin formulation, relative
resistance to slow crack growth (stress rupture testing at 80° C / 120 psig for accelerated
life testing), and summary notes.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
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Table 1. DuPont Aldyl A Pipe 1965 - 1992

Years of
Manufacture Resin
Rupture
Resistance* Notes

1965 - 1970 Alathon 5040

Initial Product Marketed as “Aldyl A”

1970 - 1972 Alathon 5043 10 hours Resin Improvement and Low Ductile Inner Wall

1970 - 1984 Alathon 5043 100 hours Resin Improvement

1984 - 1988 Alathon 5046-C 1000 hours Resin Improvement-- Sold as “Improved Aldyl A”

1988 - 1992 Alathon 5046-U 10,000 hours Resin Improvement --“Improved Aldyl A”

*Illustrates the order of magnitude difference found from accelerated life testing of resins

Common Classifications of Aldyl A Pipe

Based on the characteristics of the different vintages of Aldyl A pipe, there would emerge
over time, (from DuPont‟s 1982 letter going forward), three age-groupings recognized by
the manufacturer, natural gas industry, and regulators as relevant in the reliability
management of this pipe.

Pre-1973 Aldyl A – Pipe manufactured through 1972, from the first two resin
formulations, and including pipe having low ductile inner wall.

Pre-1984 Aldyl A – Aldyl A pipe manufactured from Alathon 5043 resin, but only that
pipe manufactured after 1972 and through 1983.

1984 and Later Aldyl A – Pipe manufactured from the improved Alathon 5046-C and
5046-U resins.

Aldyl A Service Pipe - Small-diameter (less than 1¼ inches) Aldyl A service piping is
often treated or managed differently than larger-diameter Aldyl A pipe of the same
vintage. This is because the small-diameter pipe has been assessed by industry experts as
being more resistant to brittle-like cracking than larger-diameter pipe due to its greater
flexibility. Further, small-diameter Aldyl A pipe has been confirmed as being free of the
Low Ductile Inner Wall properties present in late 1970 through early 1972 vintage
piping.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 7 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 8

Federal Bulletins on Brittle-Like Cracking in Plastic Pipe

National Transportation Safety Board

In April 1998, twelve years after DuPont‟s second letter to customers, the National
Transportation Safety Board (Board) published a comprehensive safety bulletin
describing their investigation of natural gas pipeline accidents involving polyethylene
pipe that had cracked in a “brittle-like” manner. The bulletin focused primarily on
accidents related to an early plastic pipe manufactured by Century Utility Products
(Century), produced from Union Carbide resin. In its review, findings, and in its Safety
Recommendations, however, the Board concluded that in addition to the Century pipe,
much of the polyethylene pipe produced for gas service from the 1960s through the early
1980s may be susceptible to brittle cracking and premature failure, further noting that
vulnerability of this material to premature failure could represent a serious potential
hazard to public safety.

The Board‟s bulletin represented a seminal work on the vulnerability of early plastic pipe
to brittle-like cracking because it analyzed and integrated – for the first time – reports
from the technical literature, manufacturers‟ communications, industry expert opinions,
the experience of pipeline operators and regulators‟ accident reports. Because the
bulletin provided a clear understanding of the drivers of failure in older polyethylene
pipe, we have included a fairly detailed synopsis in this report.
Objectives of the Board’s Investigation

Following the Board‟s investigation of over a dozen serious incidents, it undertook an
effort to evaluate whether the existing pipeline accident data was sufficient for assessing
the long-term performance of plastic piping. The office of Research and Special
Programs Administration of the National Transportation Safety Board compiled the
relevant accident data, but found it to be insufficient for this purpose. Lacking adequate
data for the larger assessment, the Board instead focused on estimating the likely
frequency of brittle-like cracking, focusing on published technical literature, industry
expertise, and work with several gas system operators. From this review, the Board
launched a special investigation with the objectives to address three safety issues related
to polyethylene gas service pipe:

1. Vulnerability of plastic piping to brittle-like cracking
2. Adequacy of available guidance to pipeline operators regarding installation
and protection of plastic pipe tapped to steel mains
3. Performance monitoring as a possible way to detect unacceptable performance
in piping systems

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 8 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 9

Phenomenon of Premature Brittle-Like Cracking

The Board‟s survey suggested that early plastic piping may be “susceptible to premature
brittle-like cracking under conditions of stress intensification.” The term „stress
intensification‟ refers to localized pressure on the pipe wall created by such conditions as
rock contact or significant bending of the pipe. The phenomenon of brittle-like cracking
was characterized by the failure processes described above, beginning with the initiation
of cracks on the inner wall of the pipe at the pressure or stress point, followed by slow
crack growth that progressed under normal pipeline operating pressures (much lower than
the pressure required to rupture the pipe). The process culminated with the crack
reaching the outside wall of the pipe, showing up as a very tight, slit-like opening on the
surface, running generally parallel with the length of the pipe. Premature brittle-like
cracking was believed, at the time of the Board‟s safety bulletin, to require relatively high
and localized stress on the pipe resulting from sharp or excessive bending, soil settling,
rock “impingement” (point or contact pressure on the pipe) , improperly installed fittings,
and dents or gouges to the pipe surface. The term „brittle-like cracking‟ was used to
describe this failure process because the pipe showed no signs of being bulged or
deformed where the cracks occurred.
Board Findings on the Three Identified Safety Issues
Issue 1: Vulnerability of Plastic Piping to Brittle Cracking

Long-Term Strength of Early Pipe was Overrated - In the early 1960s the industry
had very little long-term experience with plastic pipe, and consequently, developed
laboratory testing procedures to forecast the expected service life of piping. Early testing
results suggested that polyethylene pipe would exhibit a relatively constant, or „straight
line‟ gradual decline in strength over time. These tests and underlying assumptions were
subsequently incorporated as standards for the industry and in related federal
requirements.

As the industry gained experience, however, the straight-line assumptions of these early
procedures began to be challenged through the development of new testing methods,
where pipe strength was assessed under conditions of elevated temperature (such as the
testing referenced in DuPont‟s 1986 letter to customers). Results of the elevated-
temperature testing showed that the decline in strength of early plastic pipe was not
gradual or linear as had been assumed, but instead, began to accelerate or drop below the
straight line, especially after twelve years. The Board concluded that the early testing
procedures may have overrated the strength and resistance to brittle-like cracking of the
polyethylene pipe manufactured for the gas industry from the 1960s through the early
1980s.

Long-Term Ductility was Overrated - Another important assumption about early
plastic pipe, based on short-term testing, was that it would retain its ductile properties
long term. The assumption of long-term ductility had important safety ramifications
since it allowed plastic pipe systems to be designed to withstand stresses generated
primarily by internal pressure and to give less consideration to the impacts of external
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stresses such as bending. Unfortunately, the early testing methods did not properly
identify the evidence of the “ductile to brittle” transition that was occurring early in the
life of the pipe. Consequently, the tests did not distinguish pipe failures resulting from a
loss in ductility. The Board noted that this loss of ductility was also observed in the older
piping of several manufacturers, those other than Century Utility Products.

Pipeline Operators had Insufficient Notification - The Board noted that premature
brittle-like cracking was a complex phenomenon that had not been systematically
communicated to the industry, and hence, had not been fully-appreciated by pipeline
operators. The Board recognized pipe manufacturers as commonly offering technical and
safety assistance to operators, and occasionally, formal reports on their materials. But,
because the information on the potential weakness of their products was also mixed with
information publicizing its best performance characteristics, the message was not clear.
The Board also noted that the Federal Government had not provided relevant information
to gas system operators, and concluded that operators had insufficient notification that
much of their early polyethylene pipe may have been susceptible to premature brittle-like
cracking. Finally, the Board went on to recommend that the polyethylene pipe
manufacturers‟ organization, the Plastics Pipe Institute, advise its members to notify
pipeline operators if any of their materials indicate poor resistance to brittle-like failure.
Issue 2: Adequacy of Guidance for Connecting Plastic Pipe to Steel Mains

Critical Understanding of Stress on Pipe - The Board observed that the premature
transition of plastic piping from a ductile to a brittle state appeared to have little
observable adverse impact on the serviceability of plastic pipe, except where the pipe was
subjected to external stresses, such as excessive bending, earth settlement, dents or
gouges to the pipe surface, and improper installation of fittings, etc. Of those sources of
stress, a key factor identified in the Board‟s bulletin was earth settlement, but particularly
in cases where plastic piping was connected to more rigidly anchored fittings, such as
steel main pipe. Because the physical properties of plastic and steel respond differently
under the same conditions, such as to temperature change and ground settlement, the
slight movements of each type of pipe in the ground will be different. This difference in
movement can result in significant stress at the point of connection between the plastic
and steel piping.

Much of the Guidance to Operators was Insufficient or Ambiguous - In addition to
pipeline operators having insufficient guidance on the overall issue of the vulnerability of
plastic pipe to brittle cracking, as noted above, the Board also observed that much of the
available guidance to operators on how to limit stress on the pipe during installation was
inadequate or ambiguous. This was particularly the case with the stress associated with
the tapping of plastic service piping to steel mains, where the Board concluded that many
of those connections may have been installed without adequate protection from external
stress. The Board went on to identify several instances where safety requirements did not
fully incorporate safety recommendations, resulting in ambiguity for pipeline installers
and regulators. Other highlights of the Board‟s findings were the many cases where the
applicable regulations applying to pipeline installation lacked any performance
measurement criteria. Noting that the Office of Pipeline Safety considered many of its
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safety regulations to be performance-oriented requirements, the Board rebutted this in
stating that “many are no more than general statements of required actions that do not
establish any criteria against which the adequacy of the actions taken can be evaluated.”
A particular example was the regulation that “requires gas service lines to be installed so
as to minimize anticipated piping strain and external loading,” and yet it contained no
performance measurement criteria for establishing compliance. Finally, the Board went
on to note cases where the inadequacy of pipe manufacturers‟ instructions also
contributed to the lack of a clear understanding of methods to limit stress on plastic pipe
during installation.
Issue 3: Monitoring of Plastic Pipe to Determine Unacceptable Performance

The Board‟s final objective was focused on performance monitoring of pipeline systems
as the key to effectively managing the vulnerable piping types identified in the bulletin.
In this discussion, the Board focused on the accident in Waterloo, Iowa in 19941, in
highlighting the very real challenges of designing effective pipeline monitoring
programs. The Board stated that before the accident, the pipeline operator had developed
a limited capability to monitor and analyze the condition of its system. It concluded
however, that the systems the operator had developed for tracking, identifying, and
statistically treating plastic piping failures did not permit an effective analysis of system
failures and leak history, noting that their methods of handling of pipe data masked the
high failure rates of the subject Century pipe. While the operator did re-evaluate its
monitoring data after the accident, and subsequently identified the high failure rates of
Century Pipe, the Board opined that the problem could have been detected earlier (before
the accident) if the data had been properly analyzed in the first place. Finally, the Board
concluded that an effective monitoring program would have allowed the operator to
implement a pipe replacement program that might have prevented the accident.

In the second case, the Board noted that while the operator had added capabilities to its
pipe-monitoring protocols, it had still not chosen parameters needed to provide adequate
analysis of its plastic piping system failures and leak history. The bulletin went on to
note examples of the many types of additional parameters needed to enable the effective
tracking, identifying, and properly describing system failures and leak history.

The Board concluded that in light of the key findings in its bulletin, that gas system
operators may need to be advised once again of the importance of complying with
Federal requirements for piping system surveillance and analyses. Regarding the
monitoring of older piping, the Board identified the necessity to analyze factors such as
piping manufacturer, installation date, pipe diameter, operating pressure, leak history,
geographical location, modes of failure, location of failure, etc. Finally, the Board noted
that an effective monitoring program would require the evaluation of pipe material and
installation practices to provide a basis for the planned and timely replacement of piping
that indicates unacceptable performance.

1 In October, 1994, a natural gas leak and explosion at Midwest Gas Company in Waterloo, Iowa, resulted
in 6 fatalities and 7 injuries. The cause of the incident was identified as the failure of a ½ inch diameter
service pipe cracking in a brittle-like manner at a connection to a steel main.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
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Pipeline and Hazardous Materials Safety Administration
1999 Bulletins

The first two of several advisory bulletins related to the Board‟s 1998 Safety Bulletin
(above), were published by the Office of Pipeline Safety, now known as the Pipeline and
Hazardous Materials Safety Administration (Administration), in March 1999. The
bulletins, which were issued as advisories to pipeline owners and operators, provided an
abstract of the findings of the Board‟s 1998 investigation and advised that much of the
plastic pipe manufactured from the 1960s through the early 1980s may be susceptible to
brittle-like cracking. The advisories concluded with the recommendation to owners and
operators to identify all pre-1982 plastic pipe installations, analyze leak histories,
evaluate potential stresses to pipe, and to develop appropriate remedial actions, including
pipe replacement, to mitigate any risks to public safety.
2002 Bulletin

This bulletin, as with the prior advisories, reiterated to natural gas pipeline owners and
operators the susceptibility of older plastic pipe to premature brittle-like cracking. But,
for the first time, this advisory specifically named DuPont‟s pre-1973 Aldyl A pipe (low
ductile inner wall) as being susceptible to brittle cracking. The bulletin also depicted
several environmental and installation conditions that could lead to premature, brittle-like
cracking failure of the subject pipe, and described recommended practices to aid
operators in identifying and managing brittle-like cracking problems.
2007 Bulletin

This bulletin, again, served to review and recap the findings of the prior bulletins,
advising natural gas system operators to review the earlier statements. In addition, the
advisory recapped results of the ongoing effort of the American Gas Association to
identify trends in the performance of older plastic pipe. The advisory reported that the
data, at that point, could not assess failure rates of individual plastic pipe materials, but
did support what was historically known about the susceptibility of older plastic piping to
brittle-like failure, including the addition of specific materials to the list, such as Delrin
insert tap tees.
2009 Distribution Integrity Management Program

The Administration published the final rule establishing integrity management
requirements for gas distribution pipeline operators in December 2009. Though the
effective date of the rule was February 2010, operators were given until August 2011 to
write and implement their Distribution Integrity Management Plan (DIMP).
Objectives and Approach

Among other objectives, the program was intended to overcome two key weaknesses in
pipeline safety management that were identified in the National Transportation Safety
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Board‟s 1998 bulletin (above): 1) correct weaknesses in federal regulations, particularly
in the Office of Pipeline Safety, by establishing true measurement criteria for establishing
safety compliance, and 2) establish systematic protocols for pipeline data collection,
analysis, and interpretation, that helps ensure accurate integrity assessment and
appropriate remediation.

The concept of “Integrity Management” grew out of a demonstration project of the Office
of Pipeline Safety designed to test whether allowing operators the flexibility to allocate
safety resources through risk management was effective in improving pipeline safety and
reliability. Integrity management requires operators, such as natural gas distribution
companies, to write and implement Integrity Management Programs (IMPs) to assess,
evaluate, repair and validate the integrity of pipeline segments. The program contains the
following elements:
Knowledge
Identify Threats
Evaluate and Rank Risks
Identify and Implement Measures to Address Risks
Measure Performance, Monitor Results, and Evaluate Effectiveness
Periodically Evaluate and Improve Program
Report Results
The Integrity Management approach uses historical leak data and other facility
information, along with the input of subject-matter experts, to identify individual threats
to a gas system. These threats are then analyzed to predict the likelihood and
consequences of failure. Each threat is then ranked by priority, followed by the
development of a plan to reduce or remove those risks as deemed necessary.
2011 Call to Action – Transportation Secretary LaHood

Finally, in April 2011, U.S. Transportation Secretary LaHood issued a Call to Action to
all pipeline stakeholders in conjunction with the effective application of the Distribution
Integrity Management Program. The Call to Action was aimed at the more than 2.5
million miles of liquid and gas pipelines of both federal and state jurisdiction, including
transmission and distribution facilities, calling on owners and operators, the pipeline
industry, utility regulators and state and federal partners to:

Evaluate risks on pipeline systems;
Take appropriate actions to address those risks, and
Requalify subject pipeline systems as being fit for service.

The centerpiece of the Call to Action is the “Action Plan” of the Department of
Transportation and the Pipeline and Hazardous Materials Safety Administration. The
focus of the Action Plan is to accelerate the rehabilitation, repair, and replacement of
high-risk pipeline infrastructure, calling on pipeline operators and owners to take
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 13 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 14

“aggressive efforts… to review their pipelines and quickly repair and replace sections in
poor condition.” To buttress this Call to Action, Secretary LaHood has asked Congress
to increase maximum civil penalties for pipeline violations, to close regulatory loopholes,
strengthen risk-management requirements, add more inspectors, improve data reporting
and help identify potential pipeline safety risks early.
Avista’s Experience with DuPont Aldyl A Piping Systems

Avista has approximately 12,500 miles of natural gas piping in its service territories in
the States of Washington, Oregon and Idaho. Like dozens of other gas utilities, Avista
adopted plastic pipe as an excellent alternative to steel, and consequently, the broad
majority of Avista‟s pipe is polyethylene (about 8,500 miles) of various types, ages and
brands, including DuPont‟s Aldyl A.

Avista began installing DuPont Aldyl A in 1968 and discontinued its use in 1990 when
DuPont sold their production to Uponor. Of the various vintages and formulations of
Aldyl A pipe in its system, Avista has estimated quantities in the following amounts, in
diameters of ½” to 4”:

Pre-1973 Aldyl A (1965-1972 resins) 190 Miles
1973-1984 resins 960 Miles
1985-1990 resins 919 Miles

Avista noted the advisory bulletins of the Board and Administration in 1998, 1999 and
2002, but since it had no documented trends in the types of failures highlighted,
continued to manage its Aldyl A pipe according to established monitoring standards for
leak survey and sound operations practices.
Spokane and Odessa Incidents

In recent years, however, Avista experienced two natural gas incidents2 resulting in
injuries and property damage that signaled possible changes in leak patterns in its Aldyl
A piping. The first incident occurred in 2005 at a commercial site in Spokane. This
event involved the failure of 1976-vintage Aldyl A pipe caused by bending-stress
resulting from poor soil compaction around the pipe that was performed by a non-Avista
excavator in 1993. The post-incident investigation judged the resulting leak to be an
anomaly that could have been prevented with proper care by that 3rd party excavator.

The second incident, at a residence in the town of Odessa, Washington, in late 2008, was
determined to be the result of rock pressure on the 1981-vintage Aldyl A pipe that
occurred during the initial installation. Avista signed a settlement agreement with staff of
2 The Pipeline and Hazardous Materials Safety Administration defines a natural gas “incident” as a release
of gas that results in any of the following: a fatality or personal injury that requires in-patient
hospitalization; property damage of $50,000 or greater, or the loss of greater than 3 million cubic feet of
gas.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 14 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 15

the Washington Utilities and Transportation Commission as an outcome of the
investigation of this incident. Under terms of the agreement, which was subsequently
approved by the Commission, Avista increased the frequency of its residential leak
survey on pre-1984 resin (pre-1987 installed) Aldyl A natural gas mains in its
Washington jurisdiction, from once every five years to annually. In addition, whenever it
is excavating in the vicinity of Aldyl A natural gas mains in Washington, Avista will also
report on the soil conditions surrounding the pipe, and identify appropriate and
reasonable remedial measures, as necessary. Avista retained the consulting services of
Dr. Gene Palermo to help develop its approach for managing Aldyl A pipe, in relation to
the soil conditions reported.
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to Reported
Soil Conditions

Dr. Palermo is a nationally-recognized expert on the plastic pipe used in natural gas
systems, and in particular, Aldyl A piping. He has worked in the plastic pipe industry for
over 35 years, which includes 19 years with the DuPont Corporation in its Aldyl A
natural gas pipe division.

Dr. Palermo also served as the Technical Director for the Plastics Pipe Institute from
1996 through 2003 and served on the Institute‟s Hydrostatic Stress Board for over 20
years. Dr. Palermo has served on a variety of gas industry committees, has trained gas
industry practitioners and regulators, and has received numerous awards of merit for his
outstanding individual contribution to the natural gas plastic-piping industry. He is the
only person to receive both the American Society of Testing and Materials - Award of
Merit, and the American Gas Association - Platinum Award of Merit. Dr. Palermo is
president of his consulting firm, Palermo Plastics Pipe Consulting.

Dr. Palermo reviewed the content of Avista‟s agreement with the Commission to become
familiar with its requirements, specifically with regard to managing Aldyl A piping found
in soils that would currently not meet standard criteria for bedding and backfill. Dr.
Palermo‟s review and expertise provided the basis for his recommended protocol for
management of Avista‟s Aldyl A piping found in rocky soils.

1. All Aldyl A pipe manufactured prior to 1984 should be evaluated for replacement
in the following manner:
a. If the pipe has Low Ductile Inner Wall properties, Avista should
immediately begin a prioritized pipe replacement program.
b. If the pipe is installed in soil with rocks larger than ¾ inch, Avista should
immediately begin a prioritized pipe replacement program.
c. If the pipe is installed in sandy soil or in soil with rocks up to ¾ inch in
size, the pipe should remain in service and normal leak surveys per DOT
Part 192 should be followed.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 15 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 16

2. All Aldyl A pipe manufactured during or after 1984 should also be evaluated.

a. If the pipe is installed in soil with rocks larger than ¾ inch in size, Avista
should evaluate the pipe and consider replacing it if they begin to
experience rock impingement failures, and should conduct leak surveys
more frequently than required by DOT Part 192, until replacement.
b. If this pipe is installed in sandy soil or in soil with rocks up to ¾” in size,
the pipe should remain in service and normal leak surveys should be
followed.
Evaluation of Leak Survey Records

Following the Odessa incident, Avista was also asked to review five years of leak survey
records in Washington State to look for possible emerging patterns in the health of its
Aldyl A piping system. Avista organized the leak survey information and then conducted
several evaluations, which were organized under three general objectives, listed below.

1. Analyze the modes or observed types of failures in Aldyl A pipe;
2. Forecast the expected long-term integrity of Aldyl A piping;
3. Identify potential patterns in the overall health of this piping to aid in the design
of a more-focused management protocol for Aldyl A pipe.

Avista used newly-available asset-management tools to conduct these assessments,
including its recently-implemented Distribution Integrity Management Program
(Integrity Management) approach for identifying and analyzing potential threats to its
natural gas system. This approach is suited for just such an analysis, having the
capability to determine potential patterns in the overall health of a piping system that
might not have been otherwise evident through conventional data review. The analysis
of the historic leak survey data, including the observation of several new Aldyl A
material failures and leaks, did point to the development of a possible trend.
Pipe Replacement Projects in 2011

Another outcome of this heightened focus on Aldyl A leaks was Avista‟s decision to
replace several thousand feet of its Aldyl A main in 2011. In Odessa, Avista increased
the frequency of leak surveys on its gas system to once per quarter and mobilized a pipe
replacement program that removed all of the pre-1984 Aldyl A main pipe from the gas
system in the town. During that project, which was conducted from June to December
2011, nearly 32,000 feet of Aldyl A main pipe were replaced. Other Aldyl A
replacement projects in 2011 removed an additional 7,000 feet of this priority pipe.
Together, these projects had a capital cost of approximately $2.7 million.

Avista Distribution Integrity Management Program
As described briefly above, the Integrity Management approach, now required by law,
begins with the aggregation of historical leak-survey data and other facility information
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 16 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 17

relevant to Avista‟s natural gas piping system. Then, in conjunction with the input of
subject matter experts, individual threats to Avista‟s gas system are identified. These
threats are analyzed to predict the likelihood and consequences of failure associated with
each threat, based on the specific operating environment, system makeup, and history of
Avista‟s natural gas system. Each threat is then ranked relative to all others to identify,
by priority, those with the greatest hazard potential. From that priority list, measures are
developed to reduce or remove those risks as deemed necessary. These mitigating
measures are often referred to as “accelerated actions” because they may be above and
beyond the minimum requirements of applicable federal and state codes. These
accelerated actions can range from increased frequency of maintenance and leak surveys
to full replacement programs for certain gas facilities. Finally, the mitigating measures
will be reviewed to evaluate their effectiveness in reducing threats to the gas system, and
the program will then be adjusted as necessary based on those outcomes.
Integrity Management requires the use of geographically-based analytical software to
complete many of the required program elements. Like many utilities, Avista is using the
Geographic Information System (GIS) platform developed and supported by
Environmental Systems Research, Inc. (ESRI), as the geographic and analytical engine
for conducting its gas system evaluations under the Integrity Management program.
ESRI is a pioneer and world leader in developing and supporting geographic software
products for a broad range of global business sectors, including utilities. Since Avista
had already created a comprehensive GIS layer, or database, for its gas facilities, it made
sense to add analytical capabilities to this platform in complying with the Integrity
Management program requirements.
Analyzing Modes of Failure in Avista’s Aldyl A Pipe

In tackling the first objective of the assessment of its Aldyl A piping, Avista aggregated
the gas leaks resulting from Aldyl A material failures found in its gas system in
Washington State from late 2005 through March 2011. The sample included 113
material failures that were evaluated and summarized by component to offer an
understanding of the specific failure modes for Aldyl A pipe. The „modes‟ or types of
material failures categorized are shown below in Figure 1.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 17 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 18

Figure 1. Modes or types of material failures documented in a sample of 113 leaks in
Avista’s Aldyl A piping in Washington State, December 2005 through March 2011.

Towers and Caps

The largest percentage of material failures in the sample occurred in Towers and Caps,
referring to failure of the service tapping tee itself, shown below in Figure 2. In these
cases, the pressure applied to the tee as the cap was tightened onto the body during initial
installation has resulted in slow crack growth and failure of the tower body, the cap, or
the Delrin® insert many years later. Additionally, the saddle fusion point of the tower to
the main pipe is another frequent point of failure in this assembly. The unavoidable
stresses created during standard installation (using factory recommended procedures)
have led to brittle cracking in these components many years later. This phenomenon
clearly demonstrates the susceptibility of certain resins of Aldyl A piping to tend to fail
by brittle cracking due to the slow crack growth initiated during installation.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 18 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 19

Figure 2. External features and internal components of a typical Aldyl A service tee, as
fused to Aldyl A main pipe.

Rock Contact and Squeeze-Off

The second-most common material failure observed in Avista‟s Aldyl A pipe was due to
localized, brittle cracking in Aldyl A mains that resulted from rock impingement – rock
pressure directly on the pipe, or places where „squeeze-off‟ was applied over the pipe‟s
service life. These failures are very typical for certain resins of Aldyl A main pipe,
having been consistently reported by other utilities since before the time of DuPont‟s
1986 letter. As described earlier, when these external stresses (rock impingement or
squeeze-off) cause the pipe to fail, it always begins with crack initiation on the inside
surface of the pipe wall, eventually resulting in slow crack growth that propagates toward
the outer wall of the pipe, and finally, through-wall failure. These failures generally
appear as short, tight cracks in the outer wall of the pipe that run either parallel, or
slightly off-parallel with the length of the pipe. A typical failure in Aldyl A main pipe,
showing a crack through the pipe wall as it appears on both the inner and outer surfaces,
is shown below in Figure 3.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 19 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 20

Figure 3. Typical brittle-like crack through the wall of Aldyl A pipe, resulting from rock
contact directly on the pipe.

Although the duration of the stress caused by rock contact with the pipe is very different
from that associated with squeeze-off, they both result the same pattern of crack initiation
and slow crack growth leading to failure of the pipe. Other sources of external stress that
can result in brittle failure of Aldyl A pipe, as mentioned earlier in the report, include
bending of the pipe, soil settlement, dents or gouges to the pipe, and improper installation
of fittings.
Services Tapped from Steel Mains

The third most-common failure in Avista‟s sample occurred where small diameter Aldyl
A service pipe is tapped from steel main pipe. In this application, a steel service tee is
welded to the steel main pipe and the small-diameter Aldyl A service pipe is then
connected to a mechanical transition fitting on the tee, as pictured below in Figure 4.

Figure 4. Typical polyethylene service tapped from a steel main.

It is at this transition point, between the rigid steel fitting and the more-flexible Aldyl A
service pipe, that brittle-like cracking has been observed. This failure mode in older
plastic pipe is well understood, and was one of the three study objectives reported by the
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 20 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 21

National Transportation Safety Board in its 1998 bulletin, summarized earlier in this
report.
Avista’s Aldyl A Services

Avista believes its Aldyl A service piping (apart from cracking at the connection with the
tee on steel main pipe) has no greater tendency to fail than its other polyethylene service
piping , and at this point in time, should not be managed differently than other plastic
service pipe (frequency of leak survey, etc.). Consequently, Avista is not planning to
systematically replace Aldyl A service pipe as it replaces main pipe and rehabilitates
service connections at steel tees. Avista is using the Integrity Management model,
however, to track and analyze service leaks going forward to determine if the reliability
of Aldyl A service piping changes in ways that warrant a different approach.

Understanding the Significance of Leaks in Aldyl A Pipe
Frequency and Potential Consequence

Analysis of the material failures of Aldyl A pipe provides the opportunity to put these
leaks into perspective with other types of leaks on Avista‟s natural gas system. As part of
the development of the Integrity Management Plan, five years of leak data were analyzed
for Avista‟s three-state service territory. The data included nearly 17,000 individual
leaks, which were categorized according to the underlying threats to the natural gas
system as required under Integrity Management. As a point of comparison of the
significance of leak types, the data included an excess of 2,000 leaks associated with the
failure of gas system equipment, such as valves, fittings and meters. But only 153 leaks
were identified as resulting from „material failures‟ of Aldyl A piping in the three states.
Looking simply at Aldyl A leaks as part of the aggregate of all system leaks, it could be
easy to conclude that Aldyl A pipe failures pose a limited potential for hazard relative to
the threat of other system leaks. In fact, while gas equipment leaks are more likely to
occur, their potential consequence is often minimal. A thorough understanding of this
difference is one of the most important requirements and outcomes of any effective
Integrity Management Plan analysis.

Review of the leak-history data shows the vast majority of equipment leaks as occurring
typically with shut-off valves and gas meters, located either above ground or in locations
that allow free-venting of gas to the atmosphere. Consequently, these types of leaks have
a low potential to result in an incident posing harm. Through public awareness programs,
people have become familiar with the odor of venting gas and tend to quickly call Avista
to make repairs; this is especially true if the venting gas can be associated with visible gas
valves or meters. By contrast, Aldyl A failures and the associated leaks occur almost
entirely underground, out of sight, often in populated areas, and occasionally in the
proximity of buildings that are not actually connected to the natural gas system. Without
visible facilities, natural gas may have an unexpected presence in the environment that
allows people to dismiss slight gas odors. This reduced awareness allows gas from these
undetected leaks to have the significant potential to migrate into buildings before it can
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 21 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 22

be identified and reported. This is especially true in winter when the ground is saturated,
frozen or snow covered, and in areas of full pavement and concrete finishes. Of the
roughly 2,000 equipment leaks reported in the five years of data reviewed, none resulted
in gas incidents. By comparison, two of the relatively-small number of Aldyl A material
failures resulted in gas migrating into buildings undetected, and upon accidental ignition,
resulted in harmful incidents.
The Complication of Brittle Cracking in Aldyl A Pipe

The common mode of failure for Aldyl A materials, brittle-like cracking, can also present
special problems compared with leaks in other gas piping, such as corrosion in steel gas
pipe. Corrosion leaks tend to begin with the failure of a very minute area in the pipe
wall, which then begins to release a very minute amount of natural gas. These leaks then
tend to progress very slowly and in a stable and somewhat predicable way over time.
These types of leaks, while never positive, are more likely to be detected by modern gas-
detection equipment when they are at a stage where the release of gas is relatively minor.
By contrast, leaks in Aldyl A piping tend to first appear as substantial (high gas volume)
leaks that appear in a very short time period. This is due to the nature of brittle cracking,
where the crack can progress very slowly from the inner wall of the pipe toward the outer
wall without any release of gas, until the pipe finally splits open, resulting in a substantial
failure. Additionally, unlike the prevention or even suspension of corrosion problems in
steel pipe through effective protection methods, there is no way to halt undetected
progress of slow crack growth in brittle Aldyl A pipe.
Reliability Modeling of Avista’s Aldyl A Piping

Avista‟s Asset Management Group performed reliability modeling for several classes of
its natural gas pipe in order to assess the long-term performance of its Aldyl A piping,
compared with steel pipe and newer-vintage plastic pipe. Reliability analysis comes from
the discipline of „reliability engineering‟ and is a foundational asset management tool that
provides a forecast or prediction of the future performance of a piece of equipment (pipe,
in this instance). The predicted asset performance then provides the basis for the
application of other asset management tools, allowing the development of the ultimate
maintenance or replacement strategies that optimize asset cost with any number of other
factors, such as availability for service or risk avoidance.

Availability Workbench Software

Avista developed reliability forecasts for its Aldyl A and other piping using Availability
Workbench™ software. This „off the shelf software‟ was introduced by Isograph, Ltd.,
the world‟s leader in reliability analysis software. Availability Workbench was first
introduced in 1988, and is used to support asset decision making in over 7,000 sites
around the world and across a range of industries, including Aerospace, Automotive,
Chemical, Defense, Electronics, Manufacturing, Mining, Oil and Gas, Power Generation,
Railways, and Utilities. Avista‟s version of the model was released in 2009.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 22 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 23

Reliability Forecasting

Availability Workbench has four modules, one of which, the Weibull module, is used to
create reliability forecasts (curves) for an asset. Reliability curves for gas piping are
generated from input data that include pipe inventory (type, brand, footage, location, soil
conditions, etc.), current age of piping, historic and current failure information and repair
data. Avista uses predominantly its own historical data for these inputs, but when they
must be estimated, they are vetted by subject matter experts within the company. The
model integrates pipe age and failure and repair data, and then by applying a
conventional Weibull-curve mathematical model, it produces probability curves that
represent the expected failure rates over time for each failure mode, such as the brittle-
like cracking associated with Aldyl A services tapped to steel mains. The reliability
curves represent how quickly the rest of the pipe is at risk of failing, shown as the
percentage of failures expected each year over time.

Forecasting the Reliability of Aldyl A Piping

The objective of Avista‟s reliability modeling was to forecast expected failures for
elements of Avista‟s Aldyl A piping system, compared with that of steel and latest-
generation polyethylene pipe. The observed Aldyl A failure modes, discussed above,
including leak data for other types of gas pipe in Avista‟s system, provided high-quality
leak and age information for the reliability modeling. Forecasting was performed for the
following pipe „classes‟ in Avista‟s system.

a. Aldyl A Main pipe of Pre-1984 manufacture (Alathon 5040 and 5043 resins,
including low ductile inner wall pipe)
b. Aldyl A Main pipe manufactured during 1984 and after (Alathon 5046-C and
5046-U resins)
c. Aldyl A Services Tapped to Steel Main (Bending Stress Services)
d. Steel Main pipe
e. Newer Polyethylene Main pipe (1990 and later)

To perform the modeling, the data for these pipe classes must be input as discrete
elements, which are described as follows:

Main Pipe - Analyzed using 50-foot segments as discrete modeling elements.

Services Tapped from Steel Mains - Avista identified 16,000 such services in its
system, also referred to as „bending stress tees.‟ For the reliability modeling, the
individual service is the discrete element.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 23 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 24

Forecasting Results
Forecast Piping Failures

Results of the forecast modeling, for the pipe classes evaluated, are represented as
„curves‟ showing the percentage of the amount of each pipe class that is projected to fail
in each year of the forecast time period. The resulting reliability curves are shown in the
graph below in Figure 5.

Figure 5. The expected failure rates for several classes of pipe in Avista’s system, as
forecast by Availability Workbench Modeling. The “Steel” curve is obscured by the
“Newer Polyethylene” curve, both of which are essentially flat lines.

The failure curves show dramatic differences in the expected life for the pipe classes
evaluated. The difference in expected life between the Aldyl A products as a group,
compared with that of steel and newer-generation plastic pipe, is particularly evident.
Striking also, are the expected performance differences among the classes of Aldyl A
pipe evaluated, providing some clear trends useful in designing remediation strategies.
Dependability of Forecasting Future Failures

The reliability forecast is essentially a mathematical calculation of the „chance‟ of future
failure and decisions of significant risk and financial magnitude are based, at least in part,
on that result. Importantly though, the forecast has a „real numbers‟ foundation in the
actual leak data, records of material failure and repair, and the relationship of those
events with time. For Aldyl A pipe, the model is using observed endpoints in the life of
the pipe resulting from a loss in ductility and slow crack growth, for example, and
integrating that with other data to forecast future expected failures. Comparatively, the
relatively rare observed failures in steel pipe and newer-generation plastic pipe are
0%
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1984 and later Aldyl A
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Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 24 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 25

reflected in their nearly-flat cumulative failure curves. The value of using proven
reliability forecasting approaches and widely-adopted software is derived from their
ubiquitous application across reliability-critical industries, and their continuous testing,
evaluation, and support. Finally, as Avista adds new data in coming years for pipe
failures of all material classes, including Aldyl A, it serves to increase the statistical
power of the forecast results.
Understanding the Significance of Cumulative Failure Curves

Although the failure curves for the different classes of pipe differ significantly over the
long term, as mentioned, the failure rates also appear to be very close to zero for the first
40 years for Aldyl A services tapped to steel main, and for 75 years for Pre-1984 Aldyl A
main pipe. Since the weighted average age for Aldyl A pipe in Avista‟s system is 32
years, it would appear that we might have ample time before the failure rate would start
to rise substantially for Pre-1984 Aldyl A main pipe. The failure curve estimates that
when the Pre-1984 Aldyl A main pipe is 80 years old that approximately three percent of
it will fail in that single year. Given that Avista has 335 miles of this vintage pipe in
Washington, that mileage equals about 35,000 discrete elements (50-ft sections) in the
forecast model. The three percent failure, then, translates to 1,050 leaks in that 80th year.
To put that failure rate into perspective, consider that Avista documented just 113 leaks
over the past five years in Washington state, two of which resulted in injury and property
incidents, and dozens more that were categorized as hazardous leaks3, timely repaired.
Since it is expected that the number of hazardous leaks and incidents would increase
proportionally with the increase in total leaks, then it‟s easy to imagine just how
unacceptable the pipe performance would be at an annual failure rate of three percent.
Prudent Failure Management

To carry this point further, if we “zoom-in” on the curves we can gauge the significance
of the change in failure rate that is expected ten years from today. At that point the
weighted average age of Aldyl A pipe in Avista‟s system will be 42 years, and the
expected failure rate for that year is just over one-tenth of one percent (0.12%), or 42
leaks in that year. The failure rate in that year, then, will have nearly doubled over the
average annual rate for the past five years (22.6). The critical point in this analysis is the
understanding that failures in buried natural gas piping can be prudently managed only
when they are occurring at very low rates. Otherwise new leaks in the system occur too
frequently to be detected by even annual leak surveys of the entire system, resulting in an
increase in the likelihood of hazardous leaks and the potential for harmful incidents.

3 The Pipeline and Hazardous Materials Safety Administration defines a “hazardous leak” as an
unintentional release of gas that represents an existing or probable hazard to persons or property and
requires immediate repair or continuous action until the conditions are no longer hazardous.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 25 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 26

Priority Aldyl A Piping

Every pipeline operator strives to install and maintain a safe, reliable and cost-effective
system. While the goal is complete system integrity, it is impossible to avoid having any
leaks, especially on large systems such as Avista‟s with over 12,000 miles of mains and
several hundred thousand services. Regulators and the industry acknowledge this reality
through the adoption of standardized leak-survey methodologies, and recognized pipe
remediation practices.

But, while leaks are inherent on a system, there are circumstances where the expected
reliability of a particular pipe begins to rise compared with that of other piping and
industry norms. We have demonstrated that such is the case for portions of the Aldyl A
pipe in Avista‟s system, and accordingly, we have determined these classes to be at-risk
of quickly approaching a level of reliability that is unacceptable and in need of proactive
remediation. It‟s for this reason that Avista refers to these pipe classes as “Priority Aldyl
A piping.”
Formulation of a Management Program for Priority Aldyl A Pipe

The timely application of Avista‟s Distribution Integrity Management approach to its
recent and ongoing leak analysis and its reliability modeling results, including Dr.
Palermo‟s review, and the experience gained in three priority pipe-replacement projects
in 2011, has prompted Avista to formulate a protocol for systematically managing its
Aldyl A pipe. The following categories are useful classifications for Avista‟s definition
of “priority Aldyl A pipe”4:

1. Aldyl A gas services tapped to steel main pipe
2. Pre-1973 Aldyl A main pipe
3. Pre-1984 Aldyl A main pipe

Avista has determined these classes of pipe are at risk of approaching unacceptable levels
of reliability without prompt attention. Accordingly, Avista believes the decision to
formulate a management program for its priority Aldyl A pipe is both timely and prudent,
and is consistent with results of our leak investigations, Integrity Management principles
and the recent Call to Action of Secretary LaHood. The decision is also consistent with
the prior federal bulletins on this subject and with the decisions of other similarly-situated
utilities that have implemented similar pipe-replacement programs. Finally, given the
significant amounts of priority Aldyl A pipe on Avista‟s system, commencing a protocol
now provides us greater opportunity to manage this facility in a prudent and cost-
effective manner.

4 Each class noted above is subject to material failures due to concentrated stresses such as rock
impingement, bending stresses, squeeze off, and failures of service towers and caps.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 26 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 27

Priority Aldyl A Piping in Avista’s System

Main Pipe - Avista has approximately 12,500 miles of natural gas main pipe in its
service territories in the States of Washington, Oregon and Idaho. Approximately
seventeen percent of this total, or 2,000 miles, is Aldyl A pipe of all classes and sizes.
Proportions of various classes of piping in Avista‟s system, including priority Aldyl A
pipe (pre-1973 and pre-1984 mains) is shown below in Figure 6.

Figure 6. Avista’s priority Aldyl A pipe, shown as a proportion of the different pipe
classes in Avista’s natural gas system (items 2 and 3 from the list above).

Gas Services - Avista has approximately 314,000 natural gas services, of which
approximately 16,000, or five percent, are Aldyl service pipe tapped to steel main pipe,
shown below in Figure 7 as priority Aldyl A services.

Other Aldyl A
1/2" -4"
1355 Mies
Priority Aldyl A, pre-
1984 main, 1 1/4" -4"
714 Miles
Other Polyethylene
1/2"-6"
6350 Miles
Steel
1/2" -20"
4065 Miles
Miles of Pipe Materials in Avista Natural Gas System
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 27 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 28

Figure 7. Avista’s priority Aldyl A gas services (tapped from steel mains), shown as a
proportion of Avista’s total gas services.

Other Aldyl A Pipe Replacement Programs
Aldyl A Pipe in the Pacific Northwest

Through general conversation with our colleagues in western gas utilities, Avista believes
it has a substantially greater proportion of Aldyl A pipe in its system than do our
neighboring Pacific Northwest gas utilities. The proportions of Aldyl A in Avista‟s
system (or of any other brand of early polyethylene pipe), however, is not a reflection of
the unique purchasing practices of Avista, since plastic pipe quickly became the standard
of the industry and the predominant pipe installed by utilities across the county. But, the
proportions of early plastic pipe in a system do tend to track with the amount of system
growth that gas utilities experienced during the 1970s and early 1980s. For Avista, this
was a time of particularly rapid expansion of its natural gas system (from the Spokane
metro area to outlying communities in its Washington and Idaho service territories), and
consequently, the proportion of early Aldyl A pipe in our system reflects this period of
expansion.

Established and Emerging Programs for Aldyl A Pipe Replacement

Two western utilities, Southwest Gas and Pacific Gas & Electric, have significant Aldyl
A pipe management programs either well underway or anticipated, which are very briefly
summarized below.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 28 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 29

Southwest Gas – Responding to a fatality incident in the early 1990s, Southwest Gas
entered into a settlement agreement with the Corporation Commission of Arizona to
conduct additional leak monitoring and pipeline remediation. By the late 1990s,
Southwest Gas had replaced 74 miles of Aldyl HD (high density) main pipe covered by
the agreement, and had replaced another 648 miles of Aldyl A pipe based on its leak
survey monitoring results. In 2005, Southwest Gas had another injury and property
incident on their system involving Aldyl A pipe, and implemented an additional pipe
replacement program in the vicinity of the incident. Southwest Gas has also worked
closely with staff of the Public Utilities Commission of Nevada in the monitoring and
replacement of what the Commission refers to as “aging” and “high risk” natural gas
pipe, including Aldyl A pipe.

Pacific Gas & Electric - After some very high-profile natural gas incidents in 2011 that
involved Aldyl A piping, Pacific Gas & Electric has announced plans to replace all the
Pre-1973 Aldyl A pipe in its system. The utility reportedly has 7,907 miles of Aldyl A
pipe of all classes in its system, which is about 19 percent of its gas system inventory. By
comparison, Avista‟s Aldyl A pipe stock is about 16 percent of its system. Pacific Gas &
Electric‟s planned replacement of its Pre-1973 Aldyl A pipe represents a massive effort
because the utility plans to remove and replace the 1,231 miles of pipe in a proposed
timeframe reported as in the range of three years, and at a cost said to exceed $1 billion,
but that has not yet been formalized. There is some question regarding the selection of
only pre-1973 Aldyl A for replacement in PG&E‟s system, since at least one recent high-
profile incident was reported on newer vintage (still pre-1984) Aldyl A.

Developments of Interest

US Congresswoman Jackie Speier of California has been raising the awareness of
Congress and Transportation Secretary, LaHood, in two separate actions. First, in May
2011, Speier sponsored House Resolution 22 entitled the “Pipeline Safety and
Community Empowerment Act of 2011.” The legislation provided for citizens being
able to easily access pipeline maps and safety-related information from pipeline owners,
prescribed certain changes in pipeline monitoring requirements, and called for the
addition of physical safety devices to existing pipelines. The bill is currently under
consideration by the House Committees on Transportation and Infrastructure, and Energy
and Commerce.

In October 2011, Speier wrote to Secretary LaHood calling on him to direct the Pipeline
and Hazardous Materials Safety Administration to “take immediate action to address the
long-known safety risks associated with pre-1973 Aldyl-A plastic pipe manufactured by
DuPont.” She went on to advocate for the removal of this pipe from use in the U.S., and
to commend Pacific Gas & Electric for its planned removal of all of its pre-1973 Aldyl A
pipe. Citing the DuPont letters to customers, federal safety bulletins, and the Waterloo
incident, she chided Congress for not taking action, and urged the Secretary to
immediately do so.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 29 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 30

Designing Avista’s Replacement Protocol for its Priority Aldyl A
Pipe

Avista modeled two different approaches to the replacement program, one that was
systematic, based on an established timeframe and one that was responsive to problem
areas as they were identified.

Systematic Replacement Program
Time Horizon

Determining the appropriate length of time over which to replace the Priority Aldyl A
pipe involves the optimization of several factors, including: 1) the overall urgency from
a reliability and safety perspective, both present and forecast; 2) potential consequences;
3) the impact of more intensive leak survey methods to better identify priority facilities in
need of replacement and in helping reduce the potential for harmful incidents; 4) the
ability to effectively prioritize specific projects to better ensure facilities in greatest need
are addressed earliest; 5) the availability of equipment and labor resources needed to
conduct the work, and the ability to coordinate the work with Avista‟s ongoing
construction programs; 6) program efficiency, and 7) the degree of rate pressure placed
on customers, both in absolute terms and in relation to other reliability and safety
investments required across the natural gas and electric business. Ultimately, Avista
must ensure that management and removal of its Aldyl A pipe is conducted in a way that
shields our customers from imprudent risk, while at the same protecting them from the
burden of unnecessary costs.
Prudent Management of Potential Risk

Avista believes it is important to establish for our customers and other stakeholders that
while there can never be „zero risk‟ associated with the program, the potential risk can be
prudently managed. On one hand, a replacement program carried out over a very short
timeframe cannot prevent the occurrence of all leaks forecast to occur over the course of
the program. But at the other extreme, it‟s clear that setting a replacement timeline that‟s
too lengthy would likely result in safety, reliability and financial consequences for our
customers and our business that could be regarded as imprudent. Avista believes the
timeline for the replacement program should optimize the factors mentioned above in a
way that reduces the risk associated with Aldyl A pipe to the range of „prudent risks‟
associated with the myriad other electric and gas facilities and practices that are used to
serve the energy needs of utility customers. Said differently, there is no possible way to
eliminate the risks associated with energy infrastructure, but there is a range of limited
risk that‟s deemed prudent in the conduct of our business. Avista‟s treatment of its Aldyl
A pipe will be managed to comport with these sound business practices.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 30 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 31

Prioritizing the Work

As important as the replacement timeline in prudently managing the reliability of
Avista‟s Aldyl A piping, is the ability of the Asset Management and Distribution
Integrity Management staff to partner in effectively prioritizing the pipe-replacement
activities in a way that minimizes the potential for hazardous leaks. Results of the
Availability Workbench modeling provide some support in prioritization but do not take
into account factors such as soil conditions or the proximity to buildings or people.
Obviously, a leak occurring in a vacant field will have little, if any, consequence and will
likely be detected and repaired during the next leak survey. By contrast, the potential
hazard of a leak increases with its proximity to people and structures, so replacing pipe
that has a high probability of leaking and is located in populated areas is first priority.

Avista‟s Integrity Management approach provides the analytical tools that integrate key
knowledge and information needed to effectively prioritize replacement activities based
on the potential hazard. In the prioritization process, each segment of Aldyl A pipe in
Avista‟s system is assigned a relative risk ranking, based on its age, material, soil
conditions, construction methods, and its maintenance and leak history. This information
is then loaded into Avista‟s GIS database containing the gas system maps. These maps
contain a “layer” of grid squares (50 feet per side) that correspond with sections of the
Aldyl A pipe. Each square is known as a “raster” and each raster contains all of the risk-
related information that was loaded into the GIS system, as associated with the Aldyl A
pipe, at that precise geographic location.

Next, the software integrates the historic leak information for Aldyl A pipe on Avista‟s
system with the risk data associated with each of the Aldyl A pipe segments, and predicts
the geographic areas (via the risk rasters) where Aldyl A pipe failures are expected to be
greatest. In the last step, the software integrates the results for expected failures with
information for each risk raster that identifies the potential consequence of a leak on that
segment (i.e. the proximity of that raster to buildings and people, and the population
density/sensitivity of those structures). The end result is a color-coding of the rasters that
provides a visual picture of where on the gas system that both the potential likelihood of a
leak, and the potential consequence of a leak, are greatest. This approach provides Avista
with a comprehensive and objective means of identifying Aldyl A pipe that has the
highest priority for replacement.
Twenty-Year Proposal

Avista modeled various time horizons for the replacement program, up to a timeline of 30
years, and determined a replacement horizon in the range of twenty years to represent an
optimum timeframe for removing and replacing its priority Aldyl A pipe. Shortening
the timeline was found to have increasing cost impacts to customers but with little
improvement in the numbers of expected facility failures. Lengthening the timeline past
twenty years, however, was found to result in a substantial increase in the number of
material failures expected. A replacement timeline of 25 years, for example, resulted in
more than a doubling of the number of leaks expected when compared with the twenty
year horizon. Under the twenty year replacement program, the number of material
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 31 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 32

failures each year is expected to increase slightly until 2017, at which time the
cumulative effect of priority piping replaced since 2012 begins to check the failure count
and then drive it toward zero over the remaining course of the program (Figure 8).

Figure 8. Expected numbers of material failures in Avista’s priority Aldyl A piping in
two cases: Replacement Case - piping replaced over a twenty year horizon in the
manner proposed by Avista in this report, and Base Case – assumed that priority
piping was not remediated under any program.

Importantly, Avista is not saying that experiencing an increase in leaks on our system is
“acceptable” per se, in particular, after having had two harmful incidents in the past few
years. What we are saying, however, is that by using the Integrity Management model to
prioritize work activities in the manner described above, Avista believes it can manage
the forecast Aldyl A leaks in a way that significantly reduces their potential occurrence in
areas that could result in harm. Under this approach, Avista believes it can prudently
manage the replacement of priority Aldyl A pipe with the goal to avoid harmful incidents
altogether, and at a reasonable rate impact for our customers.
Initial Optimization

Importantly, Avista‟s proposal for a 20-year replacement program represents an
optimization based on the information we have available today. Any number of factors
could change as the work proceeds over the first few years that could result in a „new‟
optimum time horizon. Avista will be collecting new leak survey and other information
each year, and will continue to use its Asset Management models to further refine
expected trends and potential consequences, making program adjustments as appropriate.

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200
300
400
500
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2010 2015 2020 2025 2030 2035
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Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 32 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 33

Responsive Replacement Program

Avista also modeled a very-different pipe replacement strategy to provide a further
measure of the efficacy of the systematic replacement program. This scenario, referred to
as the Responsive Case, was essentially a reactive approach where pipe remediation and
replacement activities would be driven by leak survey results and the magnitude of leak
consequences. Under this case, it‟s expected that pipe replacement activity would
commence at a lower level than in the systematic case, but would also vary significantly
from year to year, depending on patterns of detected leaks and their consequences.
Ultimately, however, the expected activity and spending levels would far exceed both the
annual and cumulative costs of the systematic approach. This is because pipe segments
are not replaced ahead of actual material failure (as happens in the structured case) and so
the resulting work activity more-generally follows the geometrically-increasing numbers
of material failures expected over time. This scenario was easily judged as failing to
provide an appropriate measure of prudence, including system safety, reliability, cost-
efficiency, or business risk. Without a prioritized replacement protocol in place Avista
would be resigned to replacing pipe in response to serious leaks and potential incidents,
after-the-fact, rather than with foresight. Such was the case with the Aldyl A
replacements Avista completed in 2011.

From a practical standpoint, Avista believes that by managing the replacement of its
priority Aldyl A pipe in a systematic way it can prudently manage potential risks and
impacts to its customers and other stakeholders, plan for and use construction resources
most efficiently, and plan more effectively for the capital and expense requirements
necessary for the effort. This is clearly the case when compared with a responsive
approach.

Dr. Palermo’s Assessment of the Proposed Protocol for Managing Avista’s
Priority Aldyl A Piping

Following Avista‟s Integrity Management evaluations of failure trends in its Aldyl A
piping, and the development of its proposed protocol, we invited Dr. Palermo to review
the completed protocol and to judge, from his expert perspective, the overall
effectiveness and adequacy of the program. Dr. Palermo completed his review in
February 2012, and judged Avista‟s protocol to be highly responsive and appropriate to
the management needs of the priority Aldyl A pipe in Avista‟s system. In particular, he
noted his support for Avista‟s priority focus on pre-1973 Aldyl A pipe, and on the plan to
remove and replace its pre-1984 Aldyl A mains. He further noted his agreement with
Avista‟s priority for remediating Aldyl A services tapped to steel main pipe, and to the
protocol of “managing in place” existing Aldyl A service piping between the mains and
meters. Finally, Dr. Palermo agreed with the proposed twenty-year replacement time
horizon for Avista‟s priority Aldyl A pipe, noting the reliability modeling results, and the
effectiveness of Avista‟s increased leak survey and application of Integrity Management
information, tools and analysis in prioritizing pipe replacement activities. Dr. Palermo
reviewed and approved this affirmation prior to the finalization of this report.

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 33 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 34

Application of Avista’s Washington State Study Results to Aldyl A
Pipe in the States of Oregon and Idaho

Forty-six percent of Avista‟s Aldyl A main pipe is currently in service in the State of
Washington, and coincidentally, so are 46% of Avista‟s Aldyl A services tapped to steel
mains. Since Avista‟s leak survey study and subsequent modeling results are based on
Washington State data, then it follows that the expected results are most applicable to this
jurisdiction. The degree to which the reliability modeling results are applicable to
Avista‟s Aldyl A pipe in the States of Oregon and Idaho depend on factors such as the
age of the at-risk pipe and on the known similarity of conditions under which the pipe
was installed, including method (trenching or plowing), backfill material, compaction and
squeeze-off practices, soil conditions and ambient soil temperature, etc. Avista is aware
of at least some general differences among state jurisdictions, including more favorable
soil conditions in Oregon, newer pipe materials, and construction techniques potentially
more favorable to low-ductility pipe. A contributing complication, too, is the relatively
large amount of pipe of unknown age and material in services in Oregon. This territory
was acquired by Avista from a utility that did not have a consistent practice of mapping
services, and some existing maps were lost before the purchase. As a result, Avista is
conservatively managing this „unknown‟ pipe as if it was priority Aldyl A pipe, until the
time that these segments are verified by records review and possible field verification.

Most important to this discussion, however, is the fact that Avista is using its Integrity
Management model to integrate leak survey and other data to develop the priority pipe
replacement activities for each year of the program. Since comparable leak survey data
from priority Aldyl A pipe in Idaho and Oregon will be included in the prioritization
analysis, then regardless of any differences that do affect the expected reliability of the
Aldyl A pipe, that inherent reliability will be automatically integrated into the modeling,
ensuring that Avista is systematically replacing the pipe at greatest risk, regardless of the
jurisdiction. Finally, since the Medford and Grants Pass, Oregon, service territory offers
a 12-month construction season, Avista will be able to continuously mitigate priority
Aldyl A piping within that area when northern territories are effectively unable to
continue working.
Resource Requirements and Expected Cost
Staffing

Avista‟s proposed Aldyl A pipe replacement project represents a major undertaking, even
when spread over a twenty-year horizon. In addition to the scope of the effort, there‟s
added complexity in efficiently managing the project, since Avista‟s territory extends
from Bonners Ferry, Idaho to Ashland, Oregon, a distance of over 650 miles. Each year,
the deployment of equipment and inspection and construction personnel will have to be
adjusted across this service area in response to the sites identified for highest-priority
pipe replacement in any given year. Avista is planning to coordinate with contractors to
manage much of this construction, and since this project represents a long-term
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 34 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 35

construction commitment, it is expected that the pool of contractors bidding for this work
will be substantial, resulting in advantageous pricing and flexibility of field labor.

Though much of the physical construction will be accomplished through the use of
contractors, there will still be a need to increase Avista‟s internal staffing to manage the
flow of information, quality assurance, mapping, and related project documentation.
Quality assurance is a critical project element that Avista will rigorously control.
Effective remediation of Avista‟s priority Aldyl A pipe is a critically-important corporate
objective, and we must continually ensure that sound inspection, training and auditing
delivers the results we expect. Finally, the pipe replacement activities themselves will
often have disruptive effects on our customers and others. Avista will carefully
coordinate customer and community communications and notifications in an effort to
minimize the effects of any disruptions.
Capital Costs

Avista‟s analysis and planning effort is projecting capital costs just over $10 million
annually from the year 2013 – 2032. Actual costs will vary somewhat depending on the
prioritization of piping to be replaced each year, among other factors, and the calculated
amounts will also be subject to an estimated 2.3% annual inflation. Avista is planning to
spend approximately $5 million in capital on this program in 2012, allowing for effective
planning with contractors, hiring Avista staff, and developing a solid project management
foundation for years 2013 and beyond.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 1, Page 35 of 35

Avista Utilities
Study of Aldyl-A Pipe Leaks 2022 Update

Asset Management
9/15/2022

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 1 of 11
Executive Summary
Avista began a program to replace all its Aldyl-A pipe in 2011 in Washington, Oregon,
and Idaho. A regulatory mandate to replace the pipe in 20 years is in place for
Washington State (2031 deadline). While not mandated to do so, Avista enabled similar
replacement timelines for Idaho and Oregon. The purpose of this report is to provide a
regulatory update on progress made. Avista provided similar updates in 2013 and 2018.
While not limited to the following, the update’s primary intent is to show the amount of
pipe removed (to date), the pipe removal costs, and the impact to safety from the
remaining Aldyl-A pipe in the ground.
Washington and Idaho, despite rising costs, are on track to have all Aldyl-A pipe
replaced by 2031. It is likely the Oregon replacement will not be complete until 2037.
Several slowdowns have occurred in Oregon due to COVID-19 impacts, contractor
strikes, 3rd party contractor staffing issues, wildfires, and municipal permitting
turnaround times. Part of this study/update will target specifically the risk impact of
extending the Oregon program out additional years. While all risk cannot be eliminated,
the question to be answered is whether the Oregon extension adds substantial risk to
Avista’s customers living within these service territories.1

Scope
The scope is limited to Asset Management providing a review and update on Avista’s
Aldyl-A pipe replacement program. A key factor in this update is testing whether the
remaining (“in use”) pipe carries an unacceptable level of catastrophic failure risk that
justifies amending the program’s existing timeline2. Based on risk levels, can the
program be extended, in Oregon, to 2037, given the delays noted above? The update
will also provide detail on the amount of pipe that has been replaced, the amount of pipe
still in active use, and the costs associated with pipe replacement. Benefit/Cost for the
program will be discussed and it is noted the primary driver for removing the pipe is the
catastrophic risk associated with the Aldyl-A pipe and not whether the program cost
justifies itself. Consideration is being given to two failure type modes: service tees and
slow crack growth. It is recognized that other failure modes exist, but these two failure
modes are unique to the Aldyl-A pipe.3

1 Similar safety criticality test and results will be discussed for WA, ID and OR. However, OR will be
looked at separate due to the likely extended timeline (completion by 2037).
2 Refer to Key Assumptions/Constraints. Availability Work Bench (‘AWB’) software was utilized to run
Safety Criticality tests for the remaining pipe still in use.
3 Remaining failure modes, considered for the Aldyl-A pipe, would not be all that dissimilar to the
replacement pipe being installed.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 2 of 11
Regulatory Requirements
As of August 2011, the US Department of Transportation Pipeline and Hazardous
Materials Safety Administration (PHMSA) mandates gas distribution pipeline operators to
implement Integrity Management Plans, or in Avista’s case, a Distribution Integrity
Management Plan (DIMP) in which pipeline operators are required to identify and mitigate
the highest risks within their system. For Avista, aside from third party excavation
damage, the highest risks within our natural gas distribution system is Aldyl-A Main Pipe
(Manuf. 1964-1984), and the bending stress that occurs on Aldyl-A service pipe where it
is connected to steel main pipe.
More specifically, and as related to the risks identified above, in February 2012 Avista’s
Asset Management Group released findings in the “Avista’s Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report. The report
documents specific Aldyl-A pipe in Avista’s natural gas pipe system, describes the
analysis of the types of failures observed, and the evaluation of its expected long-term
integrity. The report proposed the undertaking of a 20-year program to systematically
replace select portions of Aldyl-A medium density pipe within its natural gas distribution
system in the states of Idaho, Oregon, and Washington.
Subsequently, the Gas Facility Replacement Program’s (GFRP) was formed as the
operational entity committed to structuring and implementing a systematic approach to
mitigating the Aldyl-A pipe risks as identified in aforementioned report.
On December 31, 2012, the Washington Utilities and Transportation Commission
(WUTC) issued its policy statement on Accelerated Replacement of Pipeline Facilities
with Elevated Risks which requires gas utility companies to file a plan every two years for
replacing pipe that represents an elevated risk of failure. The requirement to file a Pipe
Replacement Plan (PRP) commenced on June 1, 2013. In response to this order, Avista’s
first 2-year PRP for 2014-2015 was submitted and approved in 2013 per Docket PG-
131837, Order 01. Avista’s second two-year PRP for 2016-2017 was submitted in 2015
and approved in 2016 per WUTC Docket PG-160292, Order 01. Avista submitted a PRP
in June 2017, and 2019. In Avista’s filings, the “Avista’s Proposed Protocol for Managing
Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report serves as the pipe
replacement “Master Plan”, and two-year pipe replacement goals which includes specific
project locations, and the anticipated pipe replacement quantities.
On March 6, 2017, the Public Utility Commission of Oregon (“OPUC”) issued Order
17-084 (Docket UM 1722, Investigation into Recovery of Safety Costs by Natural Gas
Utilities), which in part required each of the natural gas distribution companies serving
customers in Oregon to file with the OPUC by September 30th each year an annual
“Safety Project Plan” (or Plan). The purpose of the Plan is to increase transparency into
the investments made by each utility that are based predominantly on the need to achieve
important safety objectives. More specifically, the Plan is intended to achieve the following
objectives:

Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 3 of 11
• Explain capital and expenses needed to mitigate safety issues identified by risk
analysis or new federal and state rules.
• Demonstrate the utility’s safety commitment and priority to its customers.
• Provide a non-technical explanation of primary safety reports each utility is
required to file with the OPUC’s pipeline safety staff; and
• Identify major regulatory changes that impact the utility’s safety investments.

The Idaho Public Utilities Commission (IPUC) has not required gas utility companies
to submit an action plan, Avista has submitted the “Avista’s Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report for review
and communicates annual pipe replacement goals which includes specific project
locations, and the anticipated pipe replacement quantities.

Key Objectives/Assumptions/Constraints
Key Objective:
Utilizing a Safety Criticality test, demonstrate whether an unacceptable risk of
catastrophic failure exists on the remaining Aldyl-A pipe. Assuming a test failure,
alternative approaches would be considered, including moving up, rather than extending
timelines. Through this same test, confirm whether a timeline extension in Oregon is
appropriate given the risk parameters set around this program. In addition, provide an
update on progress made (to date) and discuss the costs involved with this program.

Key Assumptions/Constraints:
Weibull Curve
• Utilizing data from prior updates, existing leak data, and input from Subject
Matter Experts, the Weibull curve parameters were established. Existing pipe
data was incomplete for building out the model due to the fact it has yet to
complete a full life cycle. Therefore, the existing data set required certain
assumptions to be made to build out the model.
o ETA, 80 years.4
o Beta, 4.5
• Unit quantity based on size of Phase replacement. Oregon = 1,025 feet (Phase).
Washington/Idaho = 2,000 feet (Phase).6
4 Assumes 63.2% of all pipe sections will have experienced a failure within 80 years of installation.
5 Beta < 1, Infant Mortality, Beta = 1, Random Failure, Beta > 1, Long Term Failure. In line with 2018
study that used a 3.95 Beta for Rocky Soil and 4.02 for Sand.
6 A 10,000-foot stretch of pipe would equate to 5 units for WA/ID and 10 units (rounded) for OR.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 4 of 11
Failure Mode(s)/Consequences
• Failure modes utilized in this update:
o Slow crack growth
o Service Tees.
• Leak data is from 2011 (program start date) to 2021 and was provided by
Avista’s Manager, Natural Gas Pipeline Integrity.
• Effects (consequence of failure), for modeling purposes, were limited to
catastrophic failure. Failures, both catastrophic and non-catastrophic, would
require immediate replacement. However, the costs to repair a non-catastrophic
failure are immaterial to the overall results, do not impact the Safety Criticality
test, and do not provide cost justification for the overall program.
o Catastrophic Failure cost, $20,000,000.
o Catastrophic Event occurrence, 1 every 40 years.
▪ Redundancy Factor, 0.00125, based on an assumed 20
leaks/year.7
• Inspections are successful in detecting leaks but not necessarily preventing
future leaks. Therefore, the Potential Failure/Functional Failure (P-F) Interval on
leak detection = 0.8

Safety Criticality Test
• Safety Criticality Test models the likelihood of a catastrophic failure over a certain
time period.
• Test parameter, 1 failure in 40 years.9
• Lifetime model simulation, 10 years. Assumes all or most of the remaining pipe
will be replaced in the next 10 years; Oregon is likely to be complete in 15 years.
• Test simulation run for each year of the 10-year period. When the next year is
modeled, the pipe is aged 8,760 hours (1 year) and the amount of expected pipe
to be removed (prior year) is subtracted from the total.
• Oregon replacement assumed to be 15 years. Therefore, residual safety risk
exists, for Oregon, after the 10-year run period. Approximately 56 miles of pipe,
to be replaced, will remain in Oregon after 10 years.
• Safety Criticality results ≥ 1 = failure.
• Safety Criticality test run separately for Idaho & Washington and Oregon, given
the expected different timeline to completion for Oregon.
7 28 leaks were detected in 2020 (WA/ID/OR) while 18 were detected in 2021. 20 leak assumption is
conservative based on pipe replacement program which reduces mileage annually. Less pipe in the
ground assumes fewer leaks.
8 Assumes a pipe section passes a leak test but could fail as soon as the next day. Inspection does not
create safe period for risk avoidance. Test is limited to determining whether an existing leak exists.
9 For clarification, 1 or greater failures over a 40-year period would indicate a test failure.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 5 of 11
Linear Regression Assumptions
• Linear Regression analysis based on the leak data from 2011-2021.
• All slow crack growth and service tee leaks are included. Additional leaks, not
specific to Aldyl-A, are removed from consideration as those leak types would
occur with non Aldyl-A pipe.10
• Leaks per mile are determined by comparing total leaks to in use pipe remaining
(end of year).

Results/Findings
Safety Criticality threshold not exceeded: (Test Passed)
Safety Criticality Test was built in Availability Workbench (refer to Key Assumptions,
above). As already noted, the Safety Criticality Test was built around the probability of
a catastrophic event occurring in the next 10 years. Based on the replacement
schedule, the test is passed in all instances for Idaho/Washington and Oregon.
Therefore, a critical failure is highly unlikely throughout the remainder of this program
(refer to chart below).

• Safety criticality test success does not eliminate all risk. Rather, the likelihood of
a catastrophic failure is unlikely.11
10 Purpose of the study is to isolate those leaks (failures) specific to Aldyl-A.
11 Safety Criticality Test factors in number of prior leaks, age of pipe and the planned replacement
schedule.
0
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(Safety Criticality > 1 = Failure)
OR WA/ID Threshold/Limit
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 6 of 11
• Declining trend supported by pipe replacement. The pipe that is replaced is
removed from future test consideration. Example: 300 miles of in use pipe
remains. 40 miles is removed in year 1. Year 2 calculation would be based on
260 miles of in use pipe (300-40=260 miles).
• Residual risk remains for OR after 2031 because the OR portion is not expected
to be completed until 2037. WA/ID assumes all pipe is removed by 2031.

Linear Regression Analysis shows stable trend and overall risk reduction:
The Linear Regression Model (below) measures the number of hazardous and non-
hazardous leaks since 2011.12 The leak rate per mile can be determined through linear
regression. As shown, there has been a slight uptick in the number of leaks per mile
but the overall the trend is relatively flat and stable.

• Low R2 suggests randomness in the data set but is consistent with the age of the
pipe (yet to experience long-term wear out, therefore subject primarily to random
failures and infant mortality).
• Trend line is relatively flat and while ticking up, it does not suggest a near-term
material concern that supports changing the project’s timeline.
12 Linear Regression includes slow crack growth leaks and service tee problems experienced since 2011
for OR, ID and WA (combined). Hazardous and Non-hazardous leaks relate to the immediacy for a
response. A hazardous leak does not mean a catastrophic failure has occurred.
y = 0.0011x -2.0989
R² = 0.036
0
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0.04
0.06
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2010 2012 2014 2016 2018 2020 2022Le
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Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 7 of 11
Utilizing the linear regression equation (chart, above, top-right), the expected number of
leaks can be plotted against anticipated remaining pipeline in the ground at end of year.

The Projected Leaks, Linear Regression Model (above) demonstrates continued risk
reduction through pipe replacement and covers the combined service territory (WA, ID,
and OR). The modeling does not indicate a need for any material adverse changes in
the program’s timeline and supports extending Oregon an additional five years (due to
already mentioned delays in Oregon). Risk for a catastrophic failure remains but the
chances of such an event occurring are remote. In addition, the leak survey program
serves as an additional mitigant as many of the past leaks have been detected, through
the program, and remedied.

Program is on schedule to be completed in time in WA and ID. Additional time is
needed in OR (2037):
Completion in WA and ID is expected by 2031; the project remains on schedule for both
states. Oregon is expected to be completed by 2037. As noted in the Executive
Summary, delays have occurred in Oregon due to COVID-19 impacts, municipal
permitting delays, wildfire, and 3rd party contractor strikes, to name a few.
The chart below measures mileage completed (to date) and mileage planned against
budget costs. 13
13 Source: GFRP Historic Program Analysis Asset Management V.2
0
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2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032#
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Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 8 of 11

The table below shows progress in aggregate terms by listing out the amount of pipe in
the ground at the end of 2011 versus 2021. It highlights the slower progress being
made in Oregon but overall demonstrates the program is on track for completion. It
should be noted, however, budgets are tentative and subject to revision, based on14:
• Schedules and miles completed (prior year)
• Distribution Integrity Management Plan (DIMP) Analysis
• Budget Constraints
Any material changes in dollar amounts made available to the program could limit its
progress going forward.

State Pipe Remaining
(EOY 2011, Miles)
Pipe Remaining
(EOY 2021, Miles)
Percent Complete15
Washington 353 208 41%
Oregon 253 178 30%
Idaho 131 77 41%
Total 737 463 37%
Opportunity Work 385 48%
• Note. As of January 2022, an additional 78 miles of pipe replacement has been
completed, outside of the program, through opportunity work done by local
14 Budget and actual costs incorporate all planned work within the program: major main work, minor
opportunity work, STTR work, priority services, and Aldyl-A replacement (cross bore).
15 Includes ‘Good’ miles. ‘Good’ pipe is pipe that was manufactured and installed in 1985 and 1986 and
does not need to be replaced. It is found during the year through potholing and map editing. This
amount is combined with the construction completed amount to arrive at the annual total.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 9 of 11
districts, pipe verification and map editing. Therefore, the overall project is closer
to being 50% complete.

The program is getting more expensive as the cost per foot (CPF) has increased:
Replacing natural gas facilities decades after the initial installation, and after the
subsequent development of the service areas is challenging. Replacement pipe must be
installed in fully developed and occupied areas that consist of numerous below ground
facilities, paved streets, sidewalks, arterials, landscaped residential neighborhoods, and
hard-surfaced commercial developments teeming with daily traffic and other activity.
New main pipe is most often installed by either “horizontal drilling” or open trenching.
While horizontal drilling is far less invasive, both methods require cutting into existing
pavement or other hard surfaces. Care must be taken to plan and locate the existing
underground facilities to avoid damaging them, new service lines must be ditched into
landscaped yards, etc., and all these features must be restored to unblemished service
once the installation is complete.
During the first two years of the program Avista reported average per foot replacement
costs ranging from $69 to $83 per foot. These costs included pipe replacement in hard-
surfaced areas as well as areas of exposed soil, such as the shoulder of semi-rural
roadways with limited adjacent facilities and road restoration. More recently, Aldyl-A
pipe replacement project locations have been primarily located in suburban
developments in which the right-of-way is fully built-out with paved roads and sidewalks
and has required increased permitting stipulations. As a result of these conditions, pipe
replacement costs have increased. In 2021, the average cost of main pipe replacement
was $122/LF (per linear foot), with a low of $ $90/LF in Klamath Falls and a high of
$155/LF in the City of Medford.
Avista continued to report its experience with replacement construction costs, in
particular, as we experienced a trend on the part of municipalities toward more
restrictive and expensive roadway restoration and traffic control requirements. Over the
past several years these traffic control, pavement cutting, and remediation policies of
local jurisdictions have had a significant impact on the scheduling, logistics, operational
methods, extent of the area to be repaved, and the ultimate cost of pipe replacement. In
Avista’s experience, this continuing trend to enforce more restrictive moratoria on
cutting in newer arterials and streets, to require more stringent requirements for backfill
and compaction, for patching or repaving of streets cut for pipe replacement, and traffic
control requirements have had a substantial impact on installation costs.
The chart below shows the average cost per foot from 2011-2021 for all three states.
The actual pipe replacement costs are higher in Oregon. The major element of the total
cost disparity is related to road restoration requirements in Oregon jurisdictions. These
higher construction costs are a direct result of municipally driven traffic control permit
requirements (e.g. plate locks), material handling requirements that include 100%
export and import of trench backfill materials (e.g. slurry backfill), significant soil
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 10 of 11
compaction the width of pavement restoration, which averages 4 feet and can range
from 2 feet up to 8 feet for segments of a project all which are beyond Avista’s direct
control.

• CPF has increased steadily since the program’s inception.
• The program does not cost justify itself in that the actual and planned spends far
exceed the dollar costs associated with a catastrophic failure.16

Summary of program changes for Oregon
While taking into consideration the extension of Oregon’s Aldyl-A pipe replacement to
2037, there has been extensive analysis and research completed to ensure risk does
not increase. As previously stated, various slowdowns have occurred which have
impacted program timelines relating to work in Oregon. Impacts such as COVID-19,
contractor strikes, contractor staffing issues, wildfires, municipal restrictions and
municipal permitting delays have all created significant effects on operations and made
replacement efforts much more challenging. Extending Avista’s Aldyl-A replacement
work in Oregon to 2037 will allow us the opportunity to balance affordability and overall
impact to our customers. The data in this report supports that risk is continuing to be
mitigated and that extending work in Oregon will not increase the risk of catastrophic
failure.

16 Cost associated with a catastrophic failure is $20,000,000 and is based on the following risk formula to
determine its annual value: Pf * Pc * c, where Pf = Annual probability of failure, Pc = Annual
probability of consequence, and c = consequence cost ($20 million). This annual amount can then
be measured against the annual spend.
Exhibit No. 9 Case No. AVU-E-23-01 & AVU-G-23-01 J. DiLuciano, Avista
Schedule 2, Page 11 of 11
Business Case Name Page Numbe
Distribution
1 New Revenue - Growth 3
2 Elec Relocation and Replacement Program 11
3 Joint Use 18
4 Electric Storm 25
5 Meter Minor Blanket 32
6 Distribution Grid Modernization 38
7 Distribution Minor Rebuild 52
8 LED Change-Out Program 61
9 Wood Pole Management 70
10 Distribution System Enhancements 82
11 Substation - New Distribution Station Capacity Program 96
Transmission
12 Clearwater Wind Generation Interconnection 102
13 Colstrip Transmission 109
14 Generation Interconnection 116
15 Protection System Upgrade for PRC-002 133
16 Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 139
17 Spokane Valley Transmission Reinforcement Project 146
18 Transmission Construction - Compliance 153
19 Transmission NERC Low-Risk Priority Lines Mitigation 162
20 Tribal Permits & Settlements 168
21 Westside 230/115kV Station Brownfield Rebuild Project 174
22 N Lewiston Autotransformer - Failed Plant 181
23 SCADA - SOO and BuCC 189
24 Substation - Station Rebuilds Program 197
25 Transmission - Minor Rebuild 203
26 Transmission Major Rebuild - Asset Condition 209
27 Cabinet Gorge 230kV Add Bus Isolating Breakers 216
Natural Gas
28 New Revenue - Growth 3
29 Gas Above Grade Pipe Remediation Program 223
30 Gas Cathodic Protection Program 233
31 Gas Facility Replacement Program (GFRP) Aldyl A Pipe Replacement 239
32 Gas Isolated Steel Replacement Program 254
33 Gas Overbuilt Pipe Replacement Program 263
34 Gas PMC Program 268
35 Gas Replacement Street and Highway Program 276
36 Gas Transient Voltage Mitigation Program 283
Exhibit No. 9, Schedule 3
Capital Investment Business Case Justification Narratives Index
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 1 of 422
37 Gas Non-Revenue Program 290
38 Gas ERT Replacement Program 299
39 Gas Regulator Station Replacement Program 311
40 Gas Reinforcement Program 320
41 Gas Telemetry Program 327
42 Gas Operator Qualification Compliance 337
43 Jackson Prairie Natural Gas Storage Facility 343
General Plant
44 Apprentice/Craft Training 350
45 Capital Equipment Program 356
46 Fleet Services Capital Plan 367
47 Oil Storage Improvements 382
48 Structures and Improvements/Furniture 393
49 Telematics 2025 410
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 2 of 422
EXECUTIVE SUMMARY

Avista defines these investments as “customer requests for new service connections, line
extensions, transmission interconnections, or system reinforcements to serve a single
large customer.” We have often in the past referred to new service connects as “growth,”
as in growth in the number of customers, however, these investments are beyond the
control of the Company, and as such they do not reflect a plan or strategy on the part of
Avista. Responding quickly to these customer requests is a requirement of providing utility
service. Typical projects include installing electric facilities in a new housing or
commercial development, installing or replacing electric meters, or adding street or area
lights per a request from an individual customer, a city, or county agency. As would be
expected, fluctuation in the number of new customer connections is largely dependent on
local economic conditions both in the housing and business sectors. New customers are
served for electric in WA and ID and gas in WA, ID, and OR.

Both connects forecast and 12-month rolling Cost Per Service information are used to
calculate costs directly related to providing service to customers. Electric and Gas devices
are also included in this business case - Meters, Transformers, Gas Regulators, and
ERTs (Encoder Receiver Transmitter). Many of these Meters, Transformers, and ERTs
are used as replacements for Wood Pole Management, and Periodic Meter Changes, for
example. The costs are allocated based on an estimate of how many devices of each
type will be used for replacement, rather than new connects.

Growth Business Case Funds request:

The 5 yr average annual spend for this business case has been around $83M. Requests
for service are variable in number and in cost, sometimes requiring significant investment
for system reinforcements such as gas reg stations and electric distribution infrastructure.
This funds request is based on ordinary expectation as supported by forecast and input
from electric and gas operations engineers.

For 2023, there are updated impacts to Growth costs, see 2.1 for more detail.

VERSION HISTORY
Version Author Description Date Notes
Draft Julie Lee Initial draft of business case 6/26/20
Final Julie Lee Final version of business case 7/31/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 3 of 422
Draft Julie Lee Draft version of business case 7/9/2021 Exec summary,Sec 2.1,2.2
updated
Final Steve Carrozzo Business Case for 2023 to 2027 funding 10/2022

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The New Revenue – Growth Business Case is driven by tariff requirements
that mandate obligation to serve new customer load when requested within
our franchised area. Growth is also seen as a method to spread costs over
a wider customer base, keeping rate pressure lower than would otherwise be
experienced.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Customer Requested: The New Revenue – Growth Business Case serves
as support of several focus areas in Avista. We seek to serve the interests
of our customers, in a safe and responsible manner, while strengthening the
financial performance of the utility. Our growth contributes to strong
communities, ongoing value to our customers, and the device portion of the
business case keeps our system safe and reliable.
All new customers on Avista’s system are benefitted by this business case.
In addition, all customers who have their metering or regulation changed, or
who have transformers replaced, benefit from this business case.
Transmission Interconnects:
Requested Spend Amount $430M
Requested Spend Time Period 5 years
Requesting Organization/Department Energy Delivery
Business Case Owner | Sponsor David Howell | Josh DiLuciano
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Mandatory
Driver Customer Requested
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 4 of 422
• Periodically, Avista receives requests from 3rd party generation customers
seeking interconnection on our Transmission facilities. Two types of
customers seek service on our system:
o First, those who want to wheel on our Transmission system. For this
type of customer, Avista receives Transmission revenue for wheeling
service. These customers are classified as New Revenue, as the
construction costs are offset by ongoing revenues much like new retail
customers.
o The second category of generators are those that sell their output
directly to Avista under PURPA contracts. Their output is contained
in Avista’s gross margin calculation as power supply costs.
• For the first class of customer, a financial analysis shall be performed, as
justification for the construction costs to be included as New Revenue –
Growth, and the capital so constructed shall be treated as growth for
ratemaking purposes.
• PURPA customers’ facilities shall be constructed under our existing non-
revenue programs.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred

Avista is required to serve appropriate new load, complying with our
Certificate of Convenience and Necessity, and as part of our Obligation to
Serve.
The New Revenue – Growth Business Case will provide funds for connecting
new Electric and Gas customers in accordance with our filed tariffs in each
state.
Our obligation to serve, mandates that we must extend service to new
customers in our franchised service areas. We do not currently have an
alternative to serving new customers. All projects are subject to our Line
Extension Tariffs, filed with each State Utility Commission.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 5 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
We periodically review and update the line extension tariffs to ensure we are not
creating excessive rate pressure in connecting new customers.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
N/A
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
N/A

Option Capital Cost Start Complete
Serve new customer load, and purchase appropriate
devices
$79M-$98M per
year
01 2023 12 9999
No other alternatives allowed under current tariff $M MM YYYY MM YYYY

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Avista uses a rolling 12-month Cost Per New Service spreadsheet to
measure ER1000, Electric New Revenue, and ER1001, Gas New Revenue
spending. Device blankets are subject to demand for both new revenue and
non-revenue installation and replacement.
Enclosed is a spreadsheet showing projected spend through 2027 with a
breakout by Expenditure Request for the New Revenue – Growth Business
Case. Connects forecast and 12 -month rolling Cost Per Service information
are used. Electric and Gas devices are also included, such as Meters,
Transformers, Gas Regulators, and ERTs (Encoder Receiver Transmitter).
Many of the Meters, Transformers, and ERTs are used as replacements for
Transformer Change Out Program, Wood Pole Management, and Periodic
Meter Changes. These costs are allocated based on an estimate of how
many devices of each type will be used for replacement, rather than new
connects. Those splits are shown on the spending summary.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 6 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
As requests for services and lighting are received, design and the subsequent
execution processes begin immediately. Similarly, as the gas and electric
meters, devices, and transformers needs are identified by program managers
and engineers, the purchasing department will place orders.

There are no offsets to O&M.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
In some instances, providing a service may require build-up of distribution
infrastructure to support customer load. These are the Distribution System
Enhancements and Distribution Minor Rebuild.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
In some instances, there may be alternative ways to serve a customer.
Customer project coordinators and engineers determine the solution that best
serves the customer while considering subsequent customers and Avista’s
infrastructure.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Work timeline is primarily driven by the request of the customer. The transfer to
plant occurs monthly.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 7 of 422
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

This business case is about connecting customers to Avista’s facilities. The
work directly reflects our focus area for customers as well as our mission
statement.“We must hold our customer’s interests at the forefront of all our
decisions” and “We improve our customer’s lives through innovative energy
solutions.”

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
Providing service to customers upon request is mandated. As needed CPC’s
and engineers review requests to determine solutions that best meet the needs
of the customer and Avista. These extraordinary requests lend themselves to
more visibility and oversight.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
New customers. For meters, devices and transformers - program managers.

2.8.2 Identify any related Business Cases

3.1 Steering Committee or Advisory Group Information
The Energy Delivery Director Team assumes the role of advisory group for the New
Revenue – Growth Business Case, with quarterly reporting to the Board of Directors
through the Financial Planning & Analysis department. The appropriate extension
and service tariffs are designed and updated by the Avista Rates Department, in
cooperation with Construction Services, and the Financial Planning & Analysis
department. All Customer Project Coordinators are trained regularly, by Rates and
Finance, on tariff application.

3.2 Provide and discuss the governance processes and people that will
provide oversight
For the Electric and Gas New Revenue ERs: Operations managers and
directors receive monthly Cost of Service reports providing 12-month rolling
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 8 of 422
average costs for the construction areas. This allows for review of trending of
costs for decision-making regarding processes and resources.
For the Metering and Devices ERs: Monthly Capital ER and project results
reports are distributed. These provide updated variance information facilitating
oversight by the Electric Meter Shop and Gas Engineering department.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
This business case consists of many separate requests, primarily independent of
each other. Requests for services and extensions are supported by work order
documentation. Extensions over $100k are assigned a specific project number to
allow for more visible management awareness. Should the forecast for new
connects or devices or the average cost of service significantly change from budget,
the Capital Planning Group will be notified as to the new spending forecast.
The undersigned acknowledge they have reviewed the Growth Business Case and
agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: David Howell
Title:
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Electric Operations Director
11/14/2022
11/14/2022
Vice President - Energy Delivery
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 9 of 422

Template Version: 05/28/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 10 of 422
EXECUTIVE SUMMARY
The Electric Replacement and Relocations (Road Moves) program is driven by compliance that is
mandated by the “Franchise Agreement” contracts with local city and state entities, and “permits” issued by
Railroad owners. Within each agreement are provisions for relocation of utilities at the request of the right-
of-way (ROW) owner. Under a Franchise Agreement or Permit, Avista is allowed to occupy space within a
ROW owned by the respective jurisdiction in order to serve its customers. Electric relocations occur every
year during the construction season, but are unplanned, so historical trends are used to estimate the annual
cost to fully fund all the relocation projects. The annual cost of electric relocations varies slightly year to
year. Current funding needs have increased due to additional road projects driven by both additional
government funding sources, therefore fully funding the business will likely ensure all electric relocations
under franchise agreements or permits will be completed. This is mandatory work to maintain compliance
with existing franchise and operating permits with state highway districts and railroads. This impacts WA
and ID Customers.

The Electric Relocations business case is unplanned, and demand driven work, contractually obligated,
and adds high risk to the company if not completed. Funding allocation is based on historical spending
trends. The average historical spend for Electric Relocation over five years is $3.1 million. Because electric
relocations are directly correlated with the number of highway and street projects, the reason for the upward
trend in spend is due to an increase in transportation project spending. So far in 2022 our spend is nearly
$3.3m.

VERSION HISTORY
Version Author Description Date Notes
1.1 Katie Snyder 5 Year Planning Draft - 2023 06/10/2022
1.2 Katie Snyder In Year Change Request 07/19/2022
2.0 Katie Snyder Business Narrative 2023 07/25/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 11 of 422

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The Electric Distribution and Transmission Replacement and Relocations (Road Moves)
program is driven by compliance mandated by the “Franchise Agreement” contracts with local
city and state entities and “permits” issued by Railroad owners. A “Franchise Agreement”
generally refers to a non-exclusive right and authority to construct, maintain, and operate a
utility’s facility using the public streets, dedications, public utility easements, or other public ways
in the Franchise Area pursuant to a contractual agreement executed by the City and the
Franchisee. Although each Franchise Agreement or permit is a little different, they all serve a
similar purpose in providing utility access along city, county, state, and railroad right-of-way
(ROW). The agreement(s) make provisions for Avista to install electric equipment along these
ROW’s in order to provide service to Avista customers.
Within each agreement are provisions for relocation of utilities at the request of the ROW owner.
These requests are usually driven by road and or sidewalk re-design projects.
For reference, franchise 95-0990 recorded with Spokane County paragraph VI states “If
at any time, the County shall cause or require the improvement of any County road,
highway or right-of-way wherein Grantee maintains facilities subject to this
franchise by grading or regarding, planking or paving the same, changing the grade,
altering, changing, repairing or relocating the same or by constructing drainage or
sanitary sewer facilities, the grantee upon written notice from the county engineer
shall, with all convenient speed, change the location or readjust the elevation of its
system or other facilities so that the same shall not interfere with such County work
and so that such lines and facilities shall conform to such new grades or routes as
may be established.”
For example, a State Department of Transportation (DOT) is widening an intersection or
highway, which requires Avista to relocate their overhead or underground electric facility
to accommodate the new DOT design. A smaller example for instance is a local
Requested Spend Amount $6,950,000
Requested Spend Time Period 1 year
Requesting Organization/Department Electric Operations
Business Case Owner | Sponsor Katie Snyder | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 12 of 422
municipality is installing new ADA ramps on the corners of local street intersections, which
sometimes requires Avista to relocate a utility pole to accommodate the new ramp design.
The asset conditions replaced through Electric Relocations can vary since the relocations are
unplanned and therefore not coordinated with Avista’s Asset Maintenance programs. Most
assets in an Electric Relocation project are replaced because they are unsalvageable and close
to their useful life. In the case of relocating newer assets, efforts are made to re-use as much
material as possible.
Under a Franchise Agreement or Permit, Avista is allowed to occupy space within a ROW owned
by the respective jurisdiction in order to serve its customers. Electric relocations occur every
year during the construction season, but are unplanned, so historical trends are used to estimate
the annual cost to fully fund all the relocation projects. The annual cost of electric relocations
varies slightly year to year. Current funding needs have increased due to additional road projects
driven by both additional government funding sources, therefore fully funding the business will
likely ensure all electric relocations under Franchise Agreements or Permits will be completed.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Then major driver of this business case is Mandatory & Compliance. Franchise agreements,
typical state highway and Railroad permits, and WA Department of Transportation prescribe that
the utility will relocate at their expense when in conflict with entity activities. Mandatory work to
maintain compliance with existing franchise and operating permits with state highway districts
and railroads.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This program has been funded for several years and ensures compliance with our Franchise
agreements and/or railroad permits. If not funded, we would be out of compliance with our
Franchise agreements and/or railroad permits. The work would need to occur and would be
funded under another business case.
Work under Franchise Agreements or Permits are contractual, agreed upon, and if the terms of
the agreement or permit are not executed a breach of contract will likely ensue. Also, state, and
local government departments which oversee highways, roads, and city streets incorporate the
guidelines set forth in the American Association of State Highway Transportation Officials
(AASHTO) Roadside Design Guide into the design of the highways and roads. The guidelines
are based on the type of roadway and posted speed, but generally do not allow for any fixed
objects inside the traveled way or sides of the roadway (“clear zones”) for public safety. As a
result, nearly all new road projects require utilities to relocate or remove all poles inside and
outside the traveled way. The new roadside design guidelines allow for placement of new facility
in a location that improves the safety of the driving public, thus reduces risk to Avista. Avista
designers coordinate with each state or local road project to ensure the new relocations meet
the clear zone standards yet minimize cost. Most Franchise Agreements have provisions to
prohibit the ROW owner from requiring the utility to move the same facility more than once over
a span of years, usually five.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Measures to determine successful delivery on business case objectives include:
• YTD Spend
• Compliance with Franchise agreements and/or Railroad permits.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 13 of 422
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
N/A
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
N/A

2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Relocate/replace facilities in conflict with street and
highway projects where established franchise
agreements and/or permits exist.
$6,950,000
annually
Continuous Program

UNFUNDED: Avista would be out of compliance
with established franchise agreements and/or
permits if work is not completed.
$0 N/A
2.1 Describe what metrics, data, analysis, or information was considered
when preparing this capital request.
The Electric Relocations business is unplanned work, contractually obligated, and adds high
risk to the company if not completed, no alternative analysis is considered. This program is
demand driven and unplanned work. Funding allocation is based on historical spending trends.
The graph below shows the historical spend for Electric Relocation (2016 – 2020). The average
spend over the five years is $3.4 million. Because electric relocations are directly correlated with
the number of highway and street projects, the reason for the upward trend in spend is due to an
increase in transportation project spending. Significant projects currently planned for the 2022-2026
timeframe total $6M+ per year. This amount is in addition to the costs of the normal course of
business.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 14 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e., what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This funding will enable us to relocate/replace facilities in conflict with street and highway
projects where established franchise agreements and/or permits exist. The funding will ensure
we are in compliance with our existing franchise agreements and/or railroad permits.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
If funded, the outcome of this Business Case will have minimal impact on existing operations.
This funding has been in place for several years to maintain compliance with our franchise
agreements and railroad permits. If not funded, the work is required to maintain compliance with
our franchise agreements and/or railroad permits and will need to occur.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The work covered by this funding is mandatory to maintain compliance with our franchise
agreements and/or Railroad permitting. Because the Electric Relocations business is unplanned
work, contractually obligated, and adds high risk to the company if not completed, no alternative
analysis is considered. This program is demand driven and unplanned work.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
This is an ongoing project. All investments/assets are used and useful at time of install.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives, and mission statement of the organization.
This work is required to maintain compliance with our franchise agreements and/or railroad
permits. This work focuses on our Customers and performance (safety and compliance).

2.7 Include why the requested amount above is considered a prudent
investment, providing, or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The work covered by this funding is mandatory to maintain compliance with our Franchise
Agreements and/or railroad permitting.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 15 of 422
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Internal customers and stakeholders are the local area operation engineers and area
construction managers
The primary external stakeholders in the business include all state and local transportation
governments as well as customers since they live in the territory governed by these
agencies and use the transportation system.

2.8.2 Identify any related Business Cases
Control Zone Mitigation
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Electric Distribution and Transmission Relocation and Replacement Program work is
overseen by the local area operations engineers and area construction managers.

3.2 Provide and discuss the governance processes and people that will
provide oversight
The work is mostly unplanned and non-specific in nature but occurs regularly and historical
averages are used to estimate a quantity. Electric Relocations are agreed to and executed per
the jurisdictional Franchise Agreement or Permit.

The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors the incurred costs, and submits any additional
funds requests as needed. Oversight of the program is provided by the local area operation
engineers and area construction managers manage the work as it is identified throughout the
given construction season.

Work under Franchise Agreements or Permits are contractual, agreed upon, and if the terms of
the agreement or permit are not executed a breach of contract will likely ensue. Also, state, and
local government departments which oversee highways, roads, and city streets incorporate the
guidelines set forth in the American Association of State Highway Transportation Officials
(AASHTO) Roadside Design Guide into the design of the highways and roads. The guidelines
are based on the type of roadway and posted speed, but generally do not allow for any fixed
objects inside the traveled way or sides of the roadway (“clear zones”) for public safety. As a
result, nearly all new road projects require utilities to relocate or remove all poles inside and
outside the traveled way. The new roadside design guidelines allow for placement of new facility
in a location that improves the safety of the driving public, thus reduces risk to Avista. Avista
designers coordinate with each state or local road project to ensure the new relocations meet
the clear zone standards yet minimize cost. Most Franchise Agreements have provisions to
prohibit the ROW owner from requiring the utility to move the same facility more than once over
a span of years, usually five

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 16 of 422
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
For the funding: Decision making, prioritization and change requests will be documented and
monitored though the Operations Roundtable (ORT).

For the work: Each office will work with their Area Engineer and impacted jurisdiction/Railroad
in determining priority.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Replacement and Relocation and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.

Signature: Date: 07/28/2022
Print Name: Katie Snyder
Title: Asset Maintenance Business Analyst
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

7/28/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 17 of 422
EXECUTIVE SUMMARY

Joint Use is the regulated use of utility poles and other structures by 3rd party
telcommunications companies in order for them to provide their services to the
customers we have in common. Avista licenses 72 unique entities that are attached to
over 150,000 poles across Avista’s service territory and is required by federal, state and
local laws to allow non discriminatory access to those assets. Even though this
relationship is mandated by law, and is compliance driven, Avista agrees that this
practice provides a direct benefit to our customers who desire those services.

Part of this requirement includes the obligation of Avista to replace infrastructure to
taller stronger structures in order to accommodate or “make ready” those facilities for
new attachments. This make ready work falls under capital expense and Avista is
allowed to recover the actual costs from the requesting attacher. Avista is also allowed
to recover a portion of the cost of replacing & maintaining shared infrastructure via a
regulated yearly pole rental fee. Avista would face potential regulatory and or civil legal
action if timelines and obligations are not met due to a lack of funding.The outcome of
these actions could result in significant financial loss and penalties.

VERSION HISTORY
Version Author Description Date Notes
Draft Jesse Butler Initial draft of original business case 9/13/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 18 of 422

GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed? Access to
safe and reliable utility infrastructure by third parties is not only a crucial element of the
connected world in which we live but it is also mandated by regulators at the federal and state
levels. Avista therefore has a duty to repair, replace or add infrastructure to accommodate those
requests.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer. The major
drivers of this business case are the joint use and licensee’s who request new pole attachments
or who must upgrade their existing systems to meet the burgeoning and ever increasing demand
for reliable and cost efficient communication needs. This has a direct benefit to not only Avista
customers but Avista itself as we are also consumers of those same telecommunicaitons
products. As mentioned previously fair and non discriminatory access to investor owned utility
infrastructure is codified in Federal and State laws dating back to the Federal
Telecommunicaitons Act of 1934 which laid the groundwork for the current system of asset
sharing.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred. This work is needed currently and will be needed on an ongoing
basis not only for existing wired telecommunication providers but for wireless providers who are
more often than not reliant upon existing vertical utility assets to locate their equipment. These
technologies are commonly referred to as 4G, 5G and LTE. The risk of not executing to meet
these demands could result in regulatory action, resultant fines, and possible civil litigation that
could far outweigh any short term savings. Damage to Avista’s reputation and loss of customer
trust could also result whose monetary costs are incalculable.

Requested Spend Amount $6.0M
Requested Spend Time Period Year to year
Requesting Organization/Department Operations/Joint Use
Business Case Owner | Sponsor Jesse Butler | David Howell
Sponsor Organization/Department Operations/Joint Use
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 19 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. Avista’s joint use team utilizes several systems to track compliance and
adherence to Federal, State and local regulations.On physical and practical level, success is
more often realized when 2nd and 3rd parties construct their facilities, and follow up quality control
is performed. Anectodally the joint use team has been approached by Avista customers who
are very happy with their new telecommunication service that was made possible solely by the
ability of the provider to attach their cables to Avista utility poles.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem. Tracking,
invoicing and budget information is located on the joint use drive located on Avista network drive
c01m289.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Replace capital assets when requested $6.0M Ongoing Ongoing
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request. Current joint use capital business case amounts were
derived from historic spend data coupled with projected activity that is based on trends seen in
the joint use request tracking sheet. Avista receives a direct benefit of joint use related capital
work by way of receiving a new asset at a decreased cost to rate payers. Due in large part to
the dedication of fair and non discriminatory access to utility infrastructure, and the timeliness
of completing requested capital make ready work.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 20 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Given the current workload, and requests for capital asset replacement in support of joint use,
current funding levels will be fully spent by the end of the budget year. Similar funding levels will
be required on an ongoing basis with additional funding request sought as conditions warrant.
The majority of assets being replaced should not add any additional operating costs beyond
current levels such as wood pole test and treat, vegetation management etc.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented. Additional
workload resulting from increased joint use make ready could be experienced by several
workgroups including but not limited to; Distribution Operations, Maximo, Real Estate, GIS,
Asset Management, Transmission Operations.
[For example, how will the outcome of this business case impact other parts of the business?]

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative. No realistic alternatives exist nor were
discussed. The only alternative would be to cease performing this work which would result in
regulatory/legal action and customer dissatisfaction.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year. This capital work related to this business case
are ongoing and immediate. Transfers to plant occur on a monthly basis and the assets become
used and useful immediately following physical construction.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization. The investment that is
made in Avista’s physical plant to accommodate joint use telecommunications benefits the
shared customer base of Avsita and the joint use providers. It places our customer at the center
of our focus and helps Avista to provide a safe, reliable and cost effective services. It also helps
to provide a safe working environment for all workers who require access to the electric
distribution system.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 21 of 422
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project. Joint Use requested capital make ready
work is and will always be a prudent investment as the majority of assets that are being replaced
are typically near the end of their life and Avista benefits from a newer, stronger structure. Pole
replacements and new assets are typically the solution of last result and are only offered after
careful consideration and review. High dollar cost replacements such as transmission pole
receive addtitional scrutiny and review for appropriateness and cost effectiveness.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case.
Avista Electric rate payers, Distribution operations, Distribution Engineering, Electric Design.

2.8.2 Identify any related Business Cases. The Joint Use business case was carved out
of the Miscellaneous Capital Overhead Expense business case so that it could be more closely
monitored and tracked.
[Including any business cases that may have been replaced by this business case]

3.1 Steering Committee or Advisory Group Information. The advisory group for this
business case is the Operations Resource Team. It consists of the Manager of Operations
Analytics (Jeremiah Webster), Operations Analyst (Joe Wright), Facilitor of the Operations
Round Table (Katie Schneider), Manager of Distribution Engineering (Caesar Godinez),
Operations Engineers (Brian Chain and Tim Figart), Operations Director (David Howell), and
the Joint Use Manager (Jesse Butler). Meetings are held at least once per quarter and as
needed depending on necessary required changes or requests.
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 22 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight. The business case spending levels are tracked and monitored by the
Manager of Operations Analytics (Jeremiah Webster) and Operations Analyst (Joe Wright) in
Utility Accounting with monthly spend reporting to the Operations Director (David Howell).

3.3 How will decision-making, prioritization, and change requests be
documented and monitored . Desicision for funding increases will be discussed during
the Operations Resource Team meeting. If additional funding is deemed necessary then the
business case owner Jesse Butler will complete the necessary documentation which will then
be forwarded along to the Capital Planning Group for consideration. All documentation will be
kept on file in the joint use server share in a ‘budget’ folder.

The undersigned acknowledge they have reviewed the Joint Use Projects business
case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Jesse Butler Date: 9/13/22
Print Name: Jesse Butler
Title: Joint Use Manager
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Electric Operations
Role: Business Case Sponsor

9/16/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 23 of 422
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 24 of 422
EXECUTIVE SUMMARY
The Electric Storm Business Case is focused on restoring Avista’s transmission, substation, and distribution
systems (damaged plant) into serviceable condition during a weather storm event or other natural disaster
where assets are damaged. These storm events are random and often occur with short notice. This
business case is to fund a rapid response to unexpected damages and outages, so customer outages are
minimized. The business case provides funds for replacing poles, cross arms, conductor, transformers, and
all other defined retirement units damaged during weather storm events. The damage can be due to high
winds, heavy ice and snow loads, lightning strikes, flooding, or wildfires as an example. The importance of
quickly replacing damaged facilities is vital to providing reliable service to our customers. This impacts
customers in WA and ID.

The annual budget amount is determined based on the historical average rate of capital restoration work
including restoration activity related to MED’s of relativity minor restoration impact. Request excludes costs
related to very large major event days (MEDs). If not funded, the work will still occur as needed for outages
caused by weather storm events or other natural disasters and would be absorbed through other business
cases.

VERSION HISTORY
Version Author Description Date Notes
Draft Amy Jones Initial draft of Business Case refresh 2020 7/1/2020
Draft Julie Lee Revise Funds Request for 2022 5 yr plan 7/1/2021 Updated Exec Summ,Sec 2.1
Final Steve Carrozzo Updated Business Case for 2023 to 2027
funding 10/14/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 25 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The Electric Storm Business Case (BC) is focused on restoring Avista’s transmission, substation,
and distribution systems (damaged plant) into serviceable condition during a weather storm event
or other natural disasters where assets are damaged. These events are random and often occur
with short notice. This business case funds a rapid response to unexpected damages, so customer
outages are minimized. The business case provides funds for replacing poles, cross arms,
conductor, transformers, and other defined retirement units damaged during storm events. The
damage can be due to high winds, heavy ice and snow loads, lightning strikes, flooding, or wildfires.
The importance of quickly replacing damaged facilities is vital to providing reliable service to our
customers.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for the Electric Storm BC is Failed Plant and Operations. The work is a
key component to minimizing customer outage times and contributes to Avista’s reliability
indices like SAFI and CAIDI. The secondary driver for this business case is Customer
Service Quality and Reliability.

Benefits to Customers
This business case allows funding for a rapid response to unexpected damages and service
interruptions so customer outage times are minimized. The importance of quickly replacing
damaged facilities is vital to providing reliable service to our customers.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The importance of quickly replacing damaged facilities is vital to providing reliable service to our
customers. The Electric Storm BC is to fund a rapid response to unexpected damages and
Requested Spend Amount $6,000,000 annually
Requested Spend Time Period Ongoing program
Requesting Organization/Department Operations
Business Case Owner | Sponsor David Howell | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Failed Plant & Operations
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 26 of 422
outages, so customer outages are minimized. If this business case is not funded the costs to
restoring power to our customers will be absorbed by another business case. The needed work
will continue to occur.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The primary measure that will be used to determine success is outage duration including other
reliability measures such as Avista’s reliability indices like SAFI and CAIDI. These measures will
demonstrate the impact of the work charged to this business case.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
N/A
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
N/A

Option Capital Cost Start Complete
Unadjusted Average - Includes all MED
costs; subject to more volatiility in funding
needs in the year
$8,500,000
annually
Continuous Program
Adjusted Average - Excludes very large
MED costs; less volatility in funding needs in
the year
$6,000,000
annually
Continuous Program
Minimum Funding - Excludes all MED costs;
additional funding needed in the year as
MEDs occur
$5,000,000
annually
Continuous Program

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The annual budget amount is determined based on the historical average rate of capital
restoration work.
Figure 1 shows the historical costs (2016-2021) for the distribution/transmission storm business
case and YTD 2022 expenses through September. From 2016-2021, the average annual cost
for capital storm response was $8.4 million dollars, with a range of $3.6MM (2018) to $14.6MM
(2021). There were 7 MEDs in 2020 and again in 2021. The majority of the MED costs in 2021,
however, occurred in January, one $7.2MM storm. Consequently, 2020 results were excluded
and 2021 results were adjusted downward to exclude the particularly large January storm for
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 27 of 422
determining the proposed funding level. The average spend for 2016-2019/2021 was $5.9MM.
This includes some MED activity of comparatively minor restoration impact during these years.
Our proposed funding for 2023-2027 is $6M per year. Further funding for significant MED’s will
be requested as needed.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The requested capital cost amount will be spent as needed, driven by customer outages as a
result of a weather storm or natural disaster event. Historical spend is an indication of future
spend. There are no estimated impacts to O&M with this business case.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Work under this business case occurs when repair is needed to facilities that are damaged
during weather storm events or natural disasters. Depending on the severity and the duration
of the specific outages, various business functions and processes may be impacted. Impacted
areas can affect one office area or multiple Avista service territories.

$5,238,432
$6,815,294
$3,574,683
$6,309,201
$13,732,822 $14,630,591
$3,828,832
$5,873,640
$-
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,000
DX/TX Cap Storm Actuals
2020: 7 MEDs
Jan 2021
windstorm $7.2M
Net avg excl 2020
and $7.2M MED
in 2021.
Figure 1: Storm Historical Costs
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 28 of 422
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The alternative to this business case request is not funding. The costs associated with repairing
damages as a result of a weather storm event or a natural disaster would be covered through
a different business case. Damages from these events have to be repaired, regardless of
funding.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Weather storm events or natural disasters are a continuous risk. Work will occur as needed as
a result of damaged facilities related to these events. Many times, multiple events may occur
within one year in different office areas. Past data shows there has not been a year where a
storm has not happened. Since this is often emergency work, assets become used and useful
and transferred to plant immediately.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The Electric Storm business case aligns with the company’s strategic goal of Safe and
Reliable Infrastructure. The work is a key component to minimizing customer outage times
and thus contributes to Avista’s reliability indices like SAFI and CAIDI.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The importance of quickly replacing damaged facilities is vital to providing reliable service to our
customers. The Electric Storm BC is to fund a rapid response to unexpected damages caused
by weather storm events or natural disasters, so customer outage times are minimized. If this
business case is not funded, the costs to restore power to our customers will be absorbed by a
different business case, as the work will need to occur.

The YTD spend is tracked and reviewed each month during the Electric Operations Roundtable
(ORT) meetings. The ORT reviews monthly spend and manages any additional funds requests.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The Electric Storm work is overseen by the local area operations engineers and area construction
managers. In the event of larger scale storms or natural disasters, like the historical storm event in
November 2015, a formal Incident Command System (ICS) is created to manage the resources
needed to respond. Leaders will declare Emergency Operating Procedures (EOP) and
Stakeholders from every area of the company are involved on safely restoring power to our electric
customers.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 29 of 422
2.8.2 Identify any related Business Cases
N/A

3.1 Steering Committee or Advisory Group Information
The Electric Storm work is overseen by the local area operations engineers and area
construction managers. The work is unplanned and non-specific in nature but occurs regularly.
In the event of larger scale storms or natural disasters, like the historical storm event in
November 2015, a formal Incident Command System (ICS) is created to manage the resources
needed to respond. Other large events are managed through an EOP with the Director of
Operations.

3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors the incurred costs and submits any additional
funds requests as needed. Electric Storm work is overseen by the local area operations
engineers and area construction managers.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making, prioritization and change requests will be documented and monitored though
the Operations Roundtable (ORT).

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 30 of 422
The undersigned acknowledge they have reviewed the Electric Storms Business
Case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
10/17/2022
10/17/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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EXECUTIVE SUMMARY

Avista’s distribution system has numerous facilities at, or near, the end of their useful life. Over decades, many
of these were built to different construction standards using a wide variety of materials. These factors contribute
to energy losses due to inefficiencies due to age and vintage of materials and technology, increased outages that
take longer to restore and fall short of modern expectations that utilities face.

The Grid Modernization Program is a capital program that was established in 2013 to holistically evaluate and
address the improvement of Avista’s approximately 11,3000 circuit miles of overhead and underground primary
electric distribution infrastructure. The goals of the program address service reliability and cost avoidance.

Service Reliability
Increase system and service reliability through targeted replacement of aging and failed infrastructure, removal
of low reliability equipment and construction practices, relocation or reconfiguration of high risk outage locations,
and the addition of devices and equipment that improve service continuity.

Avoided Costs
Increase energy efficiency efforts through the replacement of equipment and materials that have increased
energy losses, improvement of line losses through voltage and VAR optimization, load balancing, and the
addition of devices and equipment that improve circuit efficiency.

The program was updated and approved in 2020 with a recommended solution based on an updated average
cost per mile requiring a $28.88M annual investment to achieve a 60 year cycle. $77M in funding was requested
over a 5 year duration as a ramp up to recommended funding levels. Since approval, priority and resources
have been re-allocated to mitigate wildfire risk which includes approval and execution of Grid Hardening
projects under the Wildfire Resiliency Program. The Grid Modernization program schedule was updated to
account for reduced budget allocation by extending project design and construction duration.

Upon the completion of GMP projects, Washington and Idaho customers benefit from improved system
reliability, safety, and performance. These can be measured by a reduction in outage frequencies and durations
in addition to power quality metrics. As Avista’s distribution facilities continue to age, it becomes more
important to be proactive in their replacement. Delaying the business case increases the likelihood and severity
of various risks including equipment failure, wildfire, and energy losses. A delay would also impact the cycle
time of Avista’s Wood Pole Management Program (WPM). Not approving the business case places the
responsibility of rebuilding the system on the individual offices throughout the company which are responsible
for daily maintenance and operations as well as new revenue projects. Additionally, it jeopardizes the ability to
holistically address system wide performance. Overall, not funding or delaying this business case would reduce
the efficiency that the GMP provides to the company and customers while elevating the risk of an inconsistent
application of design and construction standards.

This Business Case plan was created by the Business Case Owner and Sponsor, the Asset Maintenance
Manager and Grid Modernization Program Manager and approved by Business Case Owner and Sponsor.

VERSION HISTORY
Version Author Description Date Notes
3.0 Robb Raymond 2022 Business Case Update 9/2/2022
2.0 Heather Webster 2020 Business Case Update 7/31/2020
1.0 Laine Lambarth First Grid Mod Business Case submission 4/14/2017
0.0 Troy Dehnel Grid Modernization Charter 5/29/2013
DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 38 of 422

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The Grid Modernization Business Case (GMP) was developed to address the aging and failing infrastructure
found throughout the electric distribution system. Other issues that are addressed include sub-optimal
system performance and inaccessible facilities that drive increased routine maintenance costs. Outage
durations and frequencies and power quality problems are also evaluated for improvement through the
installation of automated devices. Safety is also a key benefit of the Program as Grid Modernization
projects bring facilities up to current NESC and Avista construction standards, fulfill the efforts of
Wildfire Resiliency, and address structures located within the control zone of roadways subject to
Washington State’s Department of Transportation Target Zero requirements.
1.2 Discuss the major drivers of the business case and the benefits to the customer
The GMP business case is driven by asset condition, performance and capacity. Customers benefit
from improvements in electric distribution infrastructure in the following ways:

Grid Reliability
Replacing aging and failed infrastructure that has high likelihood of creating customer outages. This
also increases unplanned callouts which cost more than planned work. Ultimately higher costs
associated with this are passed on to the customers.
Without programs like Grid Modernization and Wood Pole Management, there would be an average
of 40 pole failure events per year effecting an average of 80 customers for 4.8 hours per event. The
total customer impact value of these events is approximately $24,000 per event totaling $960,000 per
year. (2017 Wood Pole Management Program Review and Recommendations, Rodney Pickett).

Energy Efficiency
Replacing equipment such as old or undersized conductor and transformers that have high energy
losses with new equipment that is more energy efficient and with better performance.

Requested Spend Amount $10M
Requested Spend Time Period 5 Years
Requesting Organization/Department Asset Maintenance
Business Case Owner | Sponsor David Howell
Sponsor Organization/Department Asset Maintenance
Phase Execution
Category Program
Driver Performance & Capacity
DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 39 of 422
Operational Ability
Replacement of conductor and equipment that hinders outage detection and install automation
devices that enable isolation of outages.
a. This leads to shorter duration of outages for customers because areas that have failed can be
more quickly identified and there is a potential to reroute power automatically.
b. Installation of automated line devices on a feeder of 1,600 customers reduces an average
outage duration from 3 hours to 5 minutes for 1,200 of those customers.
c. Potential reduction in hotline holds.

Safety
Focus on public and employee safety through smart design and work practices.
a. Replacing aging and failed infrastructure puts employees and customers at risk
b. Infrastructure is brought up to current National Electric Safety Code
c. Eliminating PCB risk to the public and environment by eliminating transformers with known
PCBs.
d. Lowers risk of high severity safety (S4) events, defined below as follows
• Having potential for multiple serious injuries or loss of an individual life, major
damage to property or business, and a public health infrastructure impact up to 72
hours.
• Base case (do nothing) has the risk of 10 S4 events every 50 years with a total cost of
$52.3 million. Grid modernization brings this risk down to 2 events in 50 years with a
total cost of $10.4 million (2017 Wood Pole Management Program Review and
Recommendations, Rodney Pickett.
e. Address Washington State’s Department of Transportation (WSDOT) Target Zero
requirements, which states that utilities move all non-breakaway structures such as power
poles and pad mount transformers out of highway clear zones as defined in the 10/2005
AASHTO “A guide for Accommodating Utilities Within Highway Right-of-Way”.
Washington law requires that this task is completed by 2030. Additional control zone
justifications are included in following Washington Administrative Codes (WAC) and
Revised Codes of Washington (RCW):
• WAC 468-34-350- Control Zone Guidelines
• WAC 468-34-300- Overhead Lines Location
• RCW 47.32.130 Dangerous Objects and Structures as Nuisances
• RCW 47.44.010 Wire and Pipeline and Tram and Railway Franchises- Application-
Rules on Hearing and Notice
• RCW 47.44.020 Grant of Franchise- Condition- Hearing

Reliability improvements have been quantified that are a direct benefit to the customers in feeders
that the GMP has addressed. The analysis was performed by comparing reliability metrics in years
before and after the GMP for all feeders completed through 2018. Figures 1-4 show these reliability
metrics, and the raw data and analysis is located at:
c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Data\grid mod reliability data analysis before and after.xlsx

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 40 of 422

CEMI3 is the percentage of customers
experiencing 3 or more interruptions per year.
The data shows that customers on feeders that
have been addressed by the Grid Modernization
Program experience a 61% reduction when major
event day (MED) are not included and a 54%
reduction when MED are included.

Figure 1.2A: Average CEMI3 on feeders that have been fully
addressed by GMP. This includes all the feeders completed
through the end of 2018.
SAIFI is the Sustained Average Interruption
Frequency Index. The data shows that customers
on feeders addressed by the GMP experience a 51%
reduction (with MED) and a 64% reduction in the
duration of power interruptions.

Figure 1.2B: SAIFI before and after Grid Modernization on
feeders completed through the end of 2018.

SAIDI is the total duration of interruptions
experienced by customers (in this case, the
customers on one feeder). Customers on feeders
addressed by the GMP experience a 64%
reduction (without MED) and a 73% reduction
with MED included. This means that outages
customers experience are shorter in duration.

Figure 1.2C: SAIDI before and after GMP for feeders
completely addressed by the end of 2018

CAIDI is the Customer Average Duration Index,
which indicates the amount of time it takes to restore
service. Customers experience an 11% reduction
(without MED) and an 18% reduction with MED after
GMP.

Figure 1.2D: CAIDI before and after being addressed by the
Grid Modernization Program.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 41 of 422

1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
Delaying the work performed by the GMP would result in an increased risk of equipment failure,
continued energy losses over time, expanded system maintenance costs, and unplanned outages. There
would also be a lost opportunity to apply holistic and sustainable solutions following an in-depth
engineering analysis to locations that experience recurring unplanned outages.

1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
The previously mentioned performance metrics; SAIFI, SAIDI, CAIDI, and CEMI3 can all be used to
gauge system performance improvements after construction is completed. Voltage quality at any
individual point along the feeder can also serve as an indicator of whether a project was successful.
Across the entire program, an annual total of the feeder miles addressed serves as a measure of progress
toward addressing the entire system.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Feeder Status Report: The feeder status report details the analysis of attributes of the distribution
system in three major categories:
• Performance: Thermal utilization, efficiency, voltage regulation, reliability performance
(MAIFI, CAIDI), power factor, FDR imbalance.
• Health: Age, OH/UG ratio, pole rejection rate, reliability health (CEMI3, SAIFI).
• Criticality: Essential services, commercial account density, customer density, load density.
c01m19:\Distribution Feeder Status Report\Feeder Status Report 2019\2019FeederStatusReport.xlsm

Using the information that the Feeder Status Report provides, each feeder is prioritized by a
combined score assessing the three categories within a tool in the location below and selected to
maintain a balance between work done in Washington and Idaho.
c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Feeder Selection

Feeder analysis reports: Once selected, a distribution engineer performs a thorough analysis on
the entire circuit to determine what work is needed to make the feeder most efficient and to bring
the feeder up to current standards to improve operation, safety, and support future loads. These
reports are located at the following location: c01m19:\Feeder Upgrades - Dist Grid Mod\~Feeder Analysis\

2017 Distribution Plan: The 2017 Distribution Plan summarizes a variety of topics including the
different drivers for investing in system improvements and planned investments such as Grid
Mod, which is cited often.
Avista Utilities Electric Distribution Infrastructure Plan June 2017:
c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Data\Distribution Plan FINAL 2017.pdf

1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with
the current condition of the asset that is proposed for replacement.
The Distribution Feeder Status Report annually quantifies the performance, health, and
criticality as outlined in section 1.5.1. More specifically, Wood Pole Management commissions
DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 42 of 422
inspections on selected Grid Modernization feeders identifying deteriorating, broken, and/or
missing equipment. Individual reports can be found on the c01m19 feeder, the Feeder
Upgrades – Dist Grid Mod folder, then select the specific feeder folder in question, and finally
the ~Admin and Wood Pole Mgmt folders.

Feeder Assessment, Selection and Grid Modernization Execution

Figure 1.5 – Feeder Assessment, Selection and Execution Summary

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 43 of 422
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital
Cost Start Complete
[Recommended Solution]
Follow Scope as stated in the Business Case and extend schedule thus
reducing 5 year budget request.

Priority and resources have been re-allocated to mitigate wildfire risk
which includes approval and execution of Grid Hardening projects
under the Wildfire Resiliency Program. Revise funding request down
to $10M over 5 years to reflect change in capital prioritization.
$10M
5yrs 01 2023 Perpetual
[Alternative #1]
Follow scope as stated in the Business case and follow the budget and
timeline request stated in the 2020 BCJN as the recommended solution.

The 2020 BCJN recommended solution was based on an average cost
per mile requiring a $28.88M annual investment to achieve a 60 year
cycle.
$28.88M
Annually 01 2023 12 2072
[Alternative #2] Address issues through the different specific
company initiatives, such as WPM, TCOP, URD, Segment
Reconductor, etc.
This means that a crew would potentially go out to the same area
multiple times. This costs more for set up, travel time, flagging, etc.
which means higher rates for customers. It also means the customer
could have multiple planned outages and be impacted by multiple
street closures for crews to address needed work at separate times. The
risk reduction is also cut in half compared to the comprehensive work
completed by GMP.
$UNK 01 2023 Perpetual
2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Reference key points from external documentation, list any addendums, attachments etc.
The GMP capital request was calculated using a 60 year cycle as a goal while addressing almost 12,000
circuit-miles of electric distribution facilities. With the average spend rate of $152,000/mile over the
past thirty months, an estimate of $28.88MM is determined. The artifacts stated in section 1.51 and
summarized in Figure 1.52 where used to develop a feeder list to address and resulting design and
construction work plan.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 44 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes
or deliverables that will result from the capital spend?). Include any known or estimated reductions
to O&M as a result of this investment.

The 2023 through 2026 plan addresses approximately 30 circuit miles on the following feeders that
have been designed.
Beacon
(BEA12F2)
Moscow
(M15514)
Spokane
Industrial Park
(SIP12F4)
Orofino
(ORO1282)
Ross Park
(ROS12F4)
TBD (2027)

The capital cost of the Program is spread across numerous projects that typically span at least two
years in a process summarized in Figure 2.2.

Figure 2.2 Grid Modernization Project Workflow

Once metrics are gathered, individual feeders are evaluated to determine how they rank in
comparison to the rest of the electric distribution system.
• Once chosen, the Program Engineer analyzes the feeder for opportunities to improve its
reliability, power quality, potential for energy savings, and accessibility. That analysis is
conveyed in a report to project stakeholders outlining feeder specific opportunities for
improvement that have been agreed upon by individuals with experience in the area.
• Design follows the publishing of the report and in addition to feeder specific improvements,
a set of standard criteria are applied to the existing equipment in the field. Designs are
reviewed by subject matter experts evaluating the designs constructability and accuracy, real
estate needs, and environmental and cultural risks.
• Construction then takes place along with an audit evaluating workmanship and accuracy
relative to the design. Deviations are tracked through a design change order process.
• The project then moves towards completion as site restoration and accounting activities are
completed.

Capital Offsets
Future O&M costs are reduced by relocating, removing, converting, or refreshing sections of Avista
facilities that present an opportunity to improve the feeder’s performance as stated above. Prudency
and valuation of Grid Modernization efforts have been categorized into three areas. 1) The value
approaching feeder improvements holistically; 2) Feeder Health; 3) Feeder Performance.

Feeder Selection
•Comparison of Health,
Performance and
Ctriticality
Engineering Analysis
•Evaluation of individual
feeder needs
•Automated device
recommendations
•Feeder kickoff meeting
Design
•Incorporation of Grid
MOD standard scope and
analysis
recommendations
•Segmentation of feeder
into managable work
packates
•Formal design by
segment
Design
Review
•Feasability
•Constructability
•Real Estate,
Envirornmental, and
Cultrural review
Construction
•Permitting
•Pre-Construction meeting
•Design Construction
Audit and
Closout
•Construction monitoring
•Change Management
•Site Restoration
DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 45 of 422
Integrated Refresh Planning and Execution
When considering the prudency of this investment as part of a single program rather than spread
across multiple departments, it is worth considering the design and construction support experience
that GMP resources provide as a dedicated subject matter expert on projects. Other departments with
competing priorities might find it difficult to maintain a focus on projects of this size.

Grid Modernization, Wood Pole Management and Transformer Change Out programs were analyzed
and Customer Internal Rate of Return (CIRR) was utilized to compare different program refresh
models and integrating the three provided the highest value to the customer. Avista provided results
of such a financial analysis in response to PC-DR-221, Attachment A, which is the Company’s 2017
Wood Pole Management Program Review and Recommendations (see Exh. JD/LL-2, pages 2-94).

The lifecycle cost analyses reported were based on the output of 172 different Availability
Workbench models integrated together to provide optimized solutions for individual assets and
programs including the transformer changeout work as part of the Wood Pole Management and Grid
Modernization programs, which is identical to its application in Distribution Minor Rebuild.
Including transformer changeouts with the program reduced the total lifecycle cost to customers by
$18.3 million in direct costs and by $46.9 million in risk costs, for a combined reduction in lifecycle
costs to customers of $65.2 million, compared with the “Run-to-Fail” alternative of allowing the
transformers and attached equipment, including the cutout to fail in service and returning to the
feeder later to replace them one at a time. (see Exh. JD/LL-2, pages 52-54).

Health
Feeder health addresses how asset condition affects reliability where there are direct O&M savings
due to a reduction in the average number of equipment outage events incurred per year based on
asset condition.

Capital offset figures are estimated by feeder based on feeder analysis information provided to the
Commission in PC-DR-110 (referenced in WUTC Rebuttal 200900-901-AVA-Exh-JD-LL 1-
T_05_26_2021) Docket No. UE-200900, UG-200901, UE-200894).

The following O&M Outage sub-reason events were considered
1.       Conductor – Primary
2.       Conductor – Secondary
3.       Connector – Primary
4.       Connector - Secondary
5.       Elbow
6.       Lightning
7.       Pole Fire
8.       Regulator
9.       Snow/Ice

10.    Undetermined
11.    Weather
12.    Wildlife Guard
13.    Wind

Performance
Indirect Savings attributable to Grid Modernization is the replacement of equipment such as old
conductor and transformers that have high energy losses with new equipment that is more energy
efficient and improve the overall feeder energy performance. This creates the need for less power
generation or acquisition and equates to lower rates for customers. Estimates are derived from the
initial assessments noted in the feeder baseline reports found in PC-DR-110 Attachment A-O. The
primary reconductor savings are for trunk reconductor work only.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 46 of 422
Another important benefit of work done is the O&M savings of each automated device that is
installed. For example, using a twenty nine month long span of data between 2017 and 2019, the
devices installed by GMP has saved the company $751,465.
Automation device activation data and hard O&M costs for 2020-2022 BCJNs.xlsx

2.3 Outline any business functions and processes that may be impacted (and how) by the
business case for it to be successfully implemented.
Wood Pole Management – The GMP incorporates WPM’s scope within its projects thereby
assisting with its 20-year cycle target. Grid Modernization also relies on WPM for poles inspection
reports.

Vegetation Management – The GMP supports and relies on Vegetation Management during the
course and completion of its projects. After design and prior to construction, trimming crews address
any conflicts that a proposed design might have with existing vegetation. Upon the completion of a
project, the GMP reduces the need for future tree trimming by targeting the removal of cycle-
breaking species or the relocation and conversion of electric distribution infrastructure.

Real Estate – Locations throughout the GMP designs are reviewed by the staff within the Real Estate
department for conflicts that would arise during construction. Permitting is another consideration that
is addressed once a design has been completed. The comprehensive GMP approach that partners with
Real Estate’s analysis results in the mitigation of outstanding issues that have existed in the field,
thereby reducing a litigation risk to the company, and the establishment of sustainable alignments and
corridors for Avista facilities.

Environmental Compliance – Environmental items of concern are addressed during design and
prior to the construction of proposed GMP work. Examples include avian and wildlife protection, the
avoidance of any impact on cultural and heritage sites, and the impacts a project may have on public
lands managed by tribal, municipal, state, and federal agencies.

Segment Reconductor and FDR Tie – The GMP’s holistic approach on feeders selected after a
thorough prioritization process addresses issues that might otherwise be included on segment
reconductor and FDR tie projects. The investment of Grid Modernization funding on selected feeders
improves local office resource availability.

Distribution Minor Rebuild – GMP’s holistic approach on feeders selected after a thorough
prioritization process addresses issues that might otherwise be included on minor rebuild projects.
The investment of Grid Modernization funding on selected feeders improves local office resource
availability.

Wildfire Resiliency – The GMP incorporates efforts to reduce the risk of wildfires caused by electric
distribution lines by relocating or converting lines in addition to the scope of the Wildfire Resiliency
program.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 47 of 422
Distribution Transformer Change Out Program (TCOP) – The GMP incorporates the
replacement of PCB transformers into each of its projects fulfilling the objective of the TCOP and
reducing environmental risks and liabilities to the company and customers.

LED Change-Out Program – The GMP incorporates the replacement of outdated streetlights to
fulfill the mission of the LED Change-Out Program across its projects.

Primary URD Cable Replacement – The GMP incorporates the replacement of outdated
underground cable to fulfill the objective of Primary URD Cable Replacement across its projects.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
Replacing equipment upon failure is an alternative to the GMP business case. It would maximize the
value of an individual piece of equipment but result in numerous unplanned outages that could arise
from and be the cause of unsafe situations to employees and customers. To mitigate the increase of
unplanned outages, additional crews would be needed for trouble responses. Aside from a dedicated
resource to respond, a variety of equipment and materials would also need to be available to minimize
the impact of system failures.
GMP’s scope could be addressed through various company initiatives such as WPM, TCOP, Primary
URD Cable Replacement, Segment Reconductor and FDR Tie, etc. Given the poor condition of
selected GMP feeders, it would certainly mean that the different initiatives would visit the same
location multiple times over a short period resulting in elevated mobilization costs and disturbances
to customers and communities as crews complete their work. The additional costs of working on the
same feeder through multiple initiatives would be evident in increased rates. A possible solution to
these issues would be to attempt a large coordination effort with a single construction resource that
would receive all work packages from each initiative and attempt to carry out their construction
simultaneously.

2.5 Include a timeline of when this work will be started and completed. Describe when the
investments become used and useful to the customer.
Work across the program is intended to be completed on a 60 year cycle becoming used and useful
throughout each year as projects are constructed. Figure 2.2 above (Section 2.2) illustrates the life cycle
of individual projects that can last at least two years.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
GMP aligns with Avista’s mission: We improve our customers’ lives through innovative energy
solutions. Safely, Responsibly, and Affordably. We put those we serve at the center of everything that
we do. GMP directly improves the lives of our customers by improving system reliability and
performance by planning the work to minimize costs of long-term maintenance or unplanned work to
maintain the distribution system. The collaboration that takes place throughout the program improves
results upon the completion of each project: an efficient delivery experienced by customers and
communities and a reduced risk to Shareholders.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 48 of 422
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain how
the investment prudency will be reviewed and re-evaluated throughout the project
• By addressing necessary work on the distribution system through the work of one program, there
are reduced costs to the customer due to mobilizing crews one time, closing roads, and having
planned outages one time instead of many times.
• The GMP plans work ahead of time and invests in the feeders that will receive the highest benefit
from the scope of the program. The efficiency of this work is planned through earned value
measurements which track the cost and schedule efficiency of the work compared to plan. The
planning and tracking of the program use best project management practices.
• The work that will be performed on the program is planned through a thorough engineering
analysis and the designs go through a full design review process to ensure that any replacements
are prudent and in the best interest of the customer. This prevents work that is out of scope or
does not provide adequate benefit from being added to the plan.
• Auditing the completed work ensures that the work performed and charged for was included in
the plan or managed and tracked through the approved design change order process.
• Competitive bidding ensures that the work is awarded in a manner that reduces risks and keeps
costs lower.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Internal Customers/Stakeholders: Real Estate, Transmission Engineering, Distribution Engineering,
Environmental Compliance, Construction Services, Electric Shop, Meter Shop, Area offices, Account
Executives, Regional Business Managers, Avista line crews, WPM, Supply Chain, and Vegetation
Management.

External Customers/Stakeholders: Electric distribution customers, Municipalities, State DOT’s, US
Army Corps of Engineers, Public Land Management agencies, Joint Users, Adjacent Utilities, Native
Tribes, Community action groups, Contract line crews.

2.8.2 Identify any related Business Cases
The following Business Cases are affected by holistically performing Grid Modernization work:
Wood Pole Management Primary URD Cable
Replacement
LED Change-Out Program
Wildfire Resiliency Distribution Transformer
Change Out Program
Distribution Minor Rebuild
Segment Reconductor and
FDR Tie

Efforts in these Business cases require refreshing/extending inspection and refresh years. Effort and
thus cost requirements in these programs are reduced.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 49 of 422
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The steering committee is comprised of the Project Sponsor, Asset Maintenance Manager, Director of
Operations, Operations Engineering, and the Program Manager. This group meets as needed, usually
quarterly, for an update on the program or when key program decisions or changes in scope need to be
discussed. The members of this group are called out in the Grid Modernization Communication
Management Plan.
3.2 Provide and discuss the governance processes and people that will provide oversight
The Grid Modernization Communication plan details the individuals that receive communication,
the type of communication, and the frequency of communication. This document is managed on the
Grid Modernization TEAMS site.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Decision making is documented in Meeting Minutes and Program log in the Grid Modernization
TEAMS site.

The prioritization of feeder work is managed in the Feeder Selection management tool which is stored
in the Grid Modernization drive. The prioritization is updated every one to two years with updated data
from the Feeder Status Report. The feeders are then ranked based on equally weighted health,
performance, and reliability scores. The top feeders may undergo an engineering analysis and gather
feedback from area engineers to determine which order these feeders are selected in.

Change requests are managed through a change order process. Any proposed changes that occur during
construction to the approved designs are first evaluated, then approved, and tracked through the change
order process.

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 50 of 422

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution Grid Modernization Business Case
and agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.

Signature: Heather Webster Date:
Print Name:
Title: Asset Maintenance Manager
Role: Business Case Owner

Signature: Robb Raymond Date:
Print Name:
Title: Asset Maintenance Project Mgr.
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

DocuSign Envelope ID: 8EE31E8A-EAAD-45A5-B74E-EDD54E7CE3E6
Sep-23-2022 | 9:11 AM PDT
Sep-23-2022 | 9:13 AM PDT
Sep-23-2022 | 9:23 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 51 of 422
EXECUTIVE SUMMARY

Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system in a
reliable condition for customers and safe conditions for workers. It ensures responsiveness to unplanned
damages on distribution assets not related to weather events, as well as small customer driven rebuilds.
Throughout the entire distribution system minor rebuilds or replacements of asset units are needed to
maintain system reliability and safety. This work impacts customers in both Washington and Idaho. If not
funded, the business will impact various types of work that will need to be absorbed into other funding due
to the necessity of the work (i.e., the replacement of a car-hit pole in the alley, a broken cross-arm, a burned-
up transformer, and a myriad of other safety related projects.) Also, if not funded, the business will affect
the ability to respond to customers’ needs for modifications to their electrical service. Lastly, it is
acknowledged that if some minor rebuilds are left unrepaired it will not result in immediate catastrophic
failures to the distribution system. However, over time an adverse accumulation of unrepaired assets would
greatly put line workers and the public at risk as minor asset failures begin to deteriorate pockets of the
distribution system.

The steady increase in costs for unplanned minor rebuild work is due to multiple reasons, which includes
many assets on the distribution system being past their end-of-life cycle. The 3-year average actual spend
for minor rebuild work is $12.4m per year. This is expected to continue for the next 5 years. Minor Rebuild
spends approximately $1m per month.

VERSION HISTORY
Version Author Description Date Notes
1.0 Katie Snyder 5 Year planning update 06/10/2022
1.1 Katie Snyder In Year Change Request 07/13/2022
1.2 Katie Snyder Business Narrative Update 07/19/2022

GENERAL INFORMATION
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 52 of 422

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in a reliable condition for customers, safe conditions for workers, ensuring responsiveness to
unplanned damages on distribution assets not related to weather events, as well as small
customer driven rebuilds. Throughout the entire distribution system, minor rebuilds or
replacement of asset units need to be completed to maintain system reliability and safety.
The work includes failed asset replacements, small mandatory or compliance driven work, slight
performance and capacity improvements, or unplanned customer requests. Occasionally, larger
projects with an identified need and short timeframe for implementation are constructed under
the Distribution Minor Rebuild business case. Even though the work is unplanned, Minor Rebuild
work occurs regularly due to the nature of the utility business and numerous assets in the field
spread over a wide geographical area.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for the work is Asset Condition. This work focuses on keeping the distribution
system in reliable condition for customers, safe conditions for the workers, ensures
responsiveness to unplanned damages on distribution assets not related to weather events, as
well as small customer driven rebuilds. Throughout the entire distribution system, minor rebuilds
or replacements of asset units need to be completed to maintain system reliability and safety
which are a benefit to customers.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in a reliable condition for customers, safe conditions for workers, ensuring responsiveness to
unplanned damages on distribution assets not related to weather events, as well as small
customer driven rebuilds. Throughout the entire distribution system, minor rebuilds or
replacement of asset units need to be completed to maintain system reliability and safety.

Requested Spend Amount $13,500,000
Requested Spend Time Period 1 year
Requesting Organization/Department Electric Operations
Business Case Owner | Sponsor Katie Snyder | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 53 of 422
If not funded it could impact the overall reliability of the distribution system as well as
responsiveness to customer requested service demands and system safety. Safety is of utmost
concern for linemen and the public. The minor rebuild business case provides the funding for
work such as; replacement of a car-hit pole in the alley, a broken cross-arm, a burned-up
transformer, and a myriad of other safety related projects. If not funded, this will also impact our
ability to respond to customers’ needs for modifications to their electrical service. It is
awknowledged that if some minor rebuilds are left unrepaired it will not result in immediate
catastrophic failures to the distribution system. However, over time an adverse accumulation of
unrepaired assets would greatly put line workers and the public at risk as minor asset failures
begin to deteriorate pockets of the distribution system.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Historical information and the continuance of tracking spend by categories will be useful in
determining the effectiveness of the program and meeting its original objectives.
In 2020, Distribution Minor Rebuild transitioned to an activity-based structure that divided the
business case into six budgeted general activities, which embody the major types of work
performed. This division will allow for improved clarity with reporting on spend. Below is a
categorical breakdown for the six general activities.
• Customer Requested Rebuilds – Work is initiated by an existing customer or property
owner. The costs associated with the work are typically reimbursed by the requesting
party. Examples include, but are not limited to: Customer requested reroute, overhead
to underground line conversion, or customer load increase.
• Trouble Related Rebuilds – Emergency work required to repair damaged facilities
caused by non-storm and non-fire related outages. Activities include a car hit pole, car-
hit padmount enclosure, copper theft, or unforeseen failed equipment that needs
immediate response.
• NESC / Operating Standard Violations – Activities include, but are not limited to,
NESC violations (not related to Joint Use clearances), secondary/service-related
voltage mitigation, fusing protection mitigation, aerial trespass, and undersized
equipment (transformers, regulators, etc.).
• Asset Condition– Activities include, but are not limited to, deteriorated wood poles,
leaking transformers, condition related replacement (not outage related) of line devices
and equipment.
• Facility Upgrades/Efficiency Improvements – Activities include, but are not limited
to, small scale reconductors, small scale feeder ties, installation of new switches or
sectionalizing devices, feeder balancing, installation of new regulators, reclosers, or
capacitor banks, and removal of open wire secondary.
• Facility Route / Location Modifications – Activities include, but are not limited to,
overhead to underground conversions, facility re-route, or relocation of midline devices
to facilitate future maintenance and optimize sectionalization.

Figure 1 shows a pie chart of the estimated spend by general activity. The new general activities
were implemented in January 2020.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 54 of 422

Figure 1: Estimated General Activity split by cost

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
NA

Option Capital Cost Start Complete
Fund Unplanned Work (based on historical
quantities)
$13,500,000 Continuous Program
Roll needed work into another program $13,500,000 Continuous Program
Unfunded $0 NA

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Historical spend was used to determine the requested amount. A steady increase in costs for
unplanned minor rebuild work has occurred for several reasons. Many assets on the distribution
system are past their end of life cycle and contributing to this increase. The 3-year average
actual spend for minor rebuild work is $12.4m. This is expected to continue for the next 5 years.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 55 of 422

Figure 2: Minor Rebuild Historical Spend

Figure 2 shows a steady increase from 2018 to 2020 and then remained consistent through
2021 with an average spend of $12.4m.

In 2021, 2,360 work orders were created with the average cost equaling $3,349, which
demonstrates the work is made up of thousands of small dollars, critical non-discretionary jobs.
Occasionally larger rebuild projects, such as small reconductor project, are undertaken as
Distribution Minor Blanket projects if prioritized by the Area Ops Engineers. Only 40 (1.8%) of
the 1,379 work orders created in 2021 were over $25,000. Those 40 work orders averaged
$65,452.
Figure 3 displays a breakdown of the different types of charges that occur in the Minor Rebuild.
The majority of charges are from specific work orders. Distribution Minor Rebuild work often
consists of isolated, replacement of failed asset(s) that do not lend themselves to a specific
project (i.e. trouble related work), which are charges falling under craft and non-craft
expenditures.

Figure 3: Types of Charges to Minor Rebuild (2021)

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 56 of 422

The following is a brief description of each type of charge.
• Craft Related Project Expenditures: Craft labor (servicemen, general
foremen, local rep), associated vehicle usage, trouble related work charges
• Non-Craft Related Project Expenditures: Non-craft labor, associated vehicle
usage, contribution reimbursables (credits), and material issues/returns
• Specific Work Order Charges: The work order is referenced on timesheets,
material requests, invoices, and vehicle charges/loadings.
The Non-Craft Project expenditures show a negative value due to customer contributions
being greater than charges.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in reliable condition for customers, safe conditions for the workers, provides responsiveness to
unplanned damages to distribution assets not related to weather events, as well as small
customer driven rebuilds. Throughout the entire distribution system, minor rebuilds, or
replacement of asset units need to be completed to maintain system reliability and safety. Spend
will continue as it has in previous years.
The work includes; failed asset replacements, small mandatory and compliance work, slight
performance and capacity improvements, or unplanned customer requests. Occasionally, larger
projects with an identified need and short timeframe for implementation are constructed under
the Distribution Minor Rebuild business case. Even though the work is unplanned, Minor Rebuild
work occurs regularly due to the nature of the utility business and numerous assets in the field
spread over a wide geographical area.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The Distribution Minor Rebuild business reaches across multiple departments in Engineering
and Operations. The business involves operation area engineers, local customer project
coordinators, and construction technicians who work directly with customers and perform all
the designs for the business. Once the minor projects are designed and ready for construction,
field personnel such as a Foremen, Journeyman Linemen, Line Servicemen, Meter men,
Equipment Operators execute the work.

The Distribution Minor Rebuild business provides a solution for the utility to address small
unplanned asset failures and customer driven modifications to the distribution system but
excludes fixes to the system considered to be maintenance. While the work is unplanned,
minor rebuilds to the distribution system occur on a regular basis every year and make up a
significant portion of the business within Engineering and Operations. While unplanned and
isolated minor rebuilds will always exists in the distribution system, unplanned work is
minimized to the greatest extent through other systematic infrastructure programs.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 57 of 422
By not funding this business case, work will need to be absorbed into some other business case
due to the necessity of the work (i.e. the replacement of a car-hit pole in the alley, a broken
cross-arm, a burned-up transformer, and a myriad of other safety related projects.)

Also, by not funding, the business will affect the ability to respond to customers’ needs for
modifications to their electrical service.

Lastly, it is acknowledged some minor rebuilds left unrepaired will not result in immediate
catastrophic failures to the distribution system, but over time an adverse accumulation of
unrepaired assets would greatly put line workers and the public at risk as minor asset failures
begin to deteriorate pockets of the distribution system.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The other alternative that was considered is not funding the business case however, the needed
work will continue to occur. These costs would be covered under some other business case.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This is an ongoing program.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Distribution Minor Rebuild work is one of the many components that contribute to the overall
reliability of the distribution system as well as responsiveness to customer requested service
demands and system safety. Safety is of utmost concern for linemen and the public. The minor
rebuild business funds the replacement of a car-hit pole in the alley, a broken cross-arm, a
burned-up transformer, and a myriad of other safety related projects. By not funding the
business will also affect the ability to respond to customers’ needs for modifications to their
electrical service. Lastly, it is acknowledged some minor rebuilds left unrepaired will not result
in immediate catastrophic failures to the distribution system, but over time an adverse
accumulation of unrepaired assets would greatly put line workers and the general public at risk
as minor asset failures begin to deteriorate pockets of the distribution system.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in reliable condition for customers, safe conditions for workers, provides responsiveness to
unplanned damages to distribution assets not related to weather events, as well as small
customer driven rebuilds. Throughout the entire distribution system, minor rebuilds or
replacements of asset units need to be completed to maintain system reliability and safety.

Distribution Minor Rebuild work is one of the many components that contribute to the overall
reliability of the distribution system as well as responsiveness to customer requested service
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 58 of 422
demands and system safety. Safety is of utmost concern for linemen and the general public and
the minor rebuild business case provides the funding for work such as; replacement of a car-hit
pole in the alley, a broken cross-arm, a burned-up transformer, and a myriad of other safety
related projects. In addition, if the business case is not funded, this will also affect the ability to
respond to customers’ needs for modifications to their electrical service. Lastly, it is
acknowledged some minor rebuilds left unrepaired will not result in immediate catastrophic
failures to the distribution system, but over time an adverse accumulation of unrepaired assets
would greatly put line workers and the general public at risk as minor asset failures begin to
deteriorate pockets of the distribution system.

The YTD spend is tracked and reviewed each month during the Electric Operations Roundtable
(ORT) meetings. The ORT, reviews monthly spend and manages any additional funds requests.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders that interface with the Distribution Minor Rebuild work are the local area
operations engineers, general foremen, and area construction managers.

2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
The Distribution Minor Rebuild work is managed by the local area operations engineers, general
foremen, and area construction managers.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors incurred costs and submits any additional funds
requests as needed.
The work done under Minor Rebuild, by way of projects, is overseen by Area Engineers. Area
Engineers receive a weekly report on all active work orders under the business and managed
which projects get done according to current needs and priorities. The local customer project
coordinators (CPCs), who design the projects, are required to seek Area Engineer approval for
projects above a $10,000 threshold before performing the work.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making, prioritization and change requests will be documented and monitored though
the Operations Roundtable (ORT).

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 59 of 422

The undersigned acknowledge they have reviewed the Minor Rebuild and agree
with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature: Date: 07/25/2022
Print Name: Katie Snyder
Title: Asset Maintenance Business Analyst
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
7/28/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 60 of 422
EXECUTIVE SUMMARY
Any local or state government which has jurisdiction over streets and highways has an obligation to the
general public they serve to provide acceptable illumination levels on their streets, sidewalks, and/or
highways intended for vehicle driver and pedestrian safety. Avista manages streetlights for many local and
state government entities to provide such street, sidewalk, and/or highway illumination for their streets by
installing overhead streetlights. Upon light burn-out, lights are converted to LED. This work occurs in WA
and ID.

Since this is a service our customer’s pay for, they benefit from lighting service being restored upon light
burn-out. Based on our historical burn-out rate, a spend of approximately $300,000 is needed. If this
business case is not approved, failed lighting may not get replaced, resulting in customer dissatisfaction
and increased public safety risks.

VERSION HISTORY
Version Author Description Date Notes
1.0 Katie Snyder 5 Year Planning Draft 06/10/2022 Draft
1.1 Katie Snyder Business Narrative Update 07/25/2022 Draft

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 61 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
Any local or state government which has jurisdiction over streets and highways has an obligation
to the general public they serve to provide acceptable illumination levels on their streets,
sidewalks, and/or highways intended for driver and pedestrian safety. Because they have an
overhead distribution system in most urban areas, Avista provides a convenient streetlight
service in almost every local and state government entity they serve, and manages the
streetlights to provide street, sidewalk, and/or highway illumination.
Initially, the LED Change-Out Program was on an accelerated five-year schedule (2015 – 2019)
to change-out all existing Avista owned streetlights to LED (Light Emitting Diode).
In the spring of 2018, upon Asset Management review, Avista executives, directors, and team
leaders decided to adapt the replacement strategy to replace lights as they burned out.
Background:
The desire to begin the LED Change-Out Program in 2015 stems from a delay in energy savings,
negative financial impacts, associated personal injury and property theft risks, and resource
needs. Benefits are also found in the 2013 Asset Management Street Light Plan.
• Each 100 watt and 200-watt HPS light replaced will save 65 watts and 128 watts,
respectively, per fixture. Once all the 100 watt and 200-watt HPS streetlights are
replaced, the annual energy savings will be 9,903 MWH each year.
• With respect to the financial impacts of converting to LED streetlight technology, the
customer internal rate of return is 8.46%, assuming the current cost of materials and life
expectancy of the photocells and LED streetlight fixtures.
• From a public safety perspective, the consequence of converting to LED streetlights in
lieu of replacing burned-out HPS bulbs shows a risk reduction of nearly eight times less
for potential injury, a serious fatal accident, and property theft.
• Lastly, company resource demands are reduced after the initial conversion to LED
technology. The average annual labor man-hours for current practices of changing
burned-out HPS bulbs is estimated at 5,200 man-hours and 2,600 equipment hours,
while the average man-hours required during the life of the LED fixtures are 3,200 man-
hours and 1,800 equipment hours.
Requested Spend Amount $300,000
Requested Spend Time Period 1 Year
Requesting Organization/Department Electric Operations
Business Case Owner | Sponsor Katie Snyder | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 62 of 422
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for converting overhead streetlights from High-Pressure Sodium (HPS) lights
to LED lights is Asset Condition. By focusing on Asset Condition, there will be a significant
improvement in energy savings, lighting quality for customers, and resource cost savings.
Secondly, converting streetlights to LED technology helps bring Avista in compliance with the
Washington State Initiative 937 (or the Clean Energy Initiative), which ensures that at least
fifteen percent of the electricity Washington state gets from major utilities comes from clean,
renewable sources, and that Washington utilities undertake all cost-effective energy
conservation measures. LED streetlight technology is part of the mentioned energy conservation
measure.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Any local or state government which has jurisdiction over streets and highways has an obligation
to the general public they serve to provide acceptable illumination levels on their streets,
sidewalks, and/or highways intended for driver and pedestrian safety. Due to having an
overhead distribution system in most urban areas, Avista provides a convenient streetlight
service in almost every local and state government entity they serve, and manages the
streetlights to provide street, sidewalk, and/or highway illumination.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Measures to determine success include:
• Count of Replacements per year.
• Energy savings per year.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• LED Replacement Analysis - One Pager
• 2013 Street Light Asset Management Plan - Final

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
A lifetime material usage analysis on the HPS light fixtures estimated a mean time to
failure (MTTF) for the various light fixture components. Table 1 shows the results for
each streetlight component.
Component Groups Material Usage
Quantities
Replacement
Ratio MTTF (Years)
fuse 641 1% 84
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 63 of 422
Lamp 7,930 15% 7
photocell 5,151 10% 10
starter board 1,126 2% 48
streetlight fixture 683 2% 55
Table 1: 2011 Mean Time to Failure (MTTF) for HPS Streetlights

Upon completion of all streetlights changed out to LED fixtures, energy savings can be
measured on an individual light fixture basis and then extrapolated to the entire system.
Also, once all the streetlights are converted to LED, the number of service requests for
streetlight burn-out should drop from the number of service requests prior to 2015.

Option Capital Cost Start Complete
RECOMMENDED: Base Case (current practice of
replacing burned-out HPS bulbs or replacing a
fixture if broken)
$300,000 Ongoing program
ALT #1: Optimized Case (planned replacement of
HPS bulbs and photocells)
$1.67M 1/1/2015 Ongoing -
15-year
cycle
replacement
ALT #2: LED Case (change-out all fixtures to
LED)
$2.32M 1/1/2022 5- or 10-
years cycle
bulb vs
photocell.

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Three alternative cases were initially considered in the analysis of converting the streetlight to
LED technology. Base Case replaces streetlight components only when they fail. The second
case, called the LED Case, replaces the current HPS streetlights with new LED fixtures and
implements a planned replacement at fifteen years for the fixture and photocell. At the time of
the initial analysis, a fifteen-year replacement strategy proved more cost effective over the
lifecycle than running LED lights to failure. Thirdly, the Optimized Case represents keeping the
current HPS light fixtures and performing planned replacements of the bulbs and photocells at
five-year cycles for the bulbs and ten-year cycle for the photocells.
In 2018, the replacement strategy moved from a five-year proactive program strategy to a run
to failure (or “burn-out”) strategy. A run to failure strategy is the same as the Base Case
mentioned above. By the end of 2018, nearly all Avista owned cobrahead streetlights had been
converted to LED, with the majority of the remaining HPS streetlights in Idaho; mainly Coeur d
Alene, Lewiston, Moscow, and Grangeville. However, thousands of customer area lights and
thousands of decorative streetlights remained as HPS throughout the entire service territory and
were being converted to LED on a burn-out replacement strategy. Because LED conversions of
area lights and decorative streetlights have nearly the same cost savings and energy savings
as the cobrahead streetlights, the program sponsors supported Asset Maintenance’s proposal
to expand the scope of the program to include both types of lights. Starting in 2019, all area and
decorative streetlights changed out will be charged to the LED Change Out Program.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 64 of 422

Key assumptions made in the alternative’s analysis are outlined below.
• The Base Case and the Optimized Case, because they propose using HPS fixtures,
have the same failure characteristics shown in Table 2.

Table 1, HPS Light Component Failure Characteristics
Component
Initial Population
Failure Rate (10%) by
Year___
Initial Population
Failure Rate (20%) by
Year___
Mean Time to Failure
(50% of the initial
population will have
failed by ____ Years)
100-Watt Bulb 3.4 4.4 6.7
Photocells 5.7 7.3 10.6
Starter Board 7.4 10.5 16.3

Table 2 shows the failure characteristics assumed for LED fixtures and components based on
manufacturer’s information and an assumed failure shape characteristic.

Table 2, Assumed LED Light Component Failure Curves
Component
Initial Population
Failure Rate (10%) by
Year___
Initial Population
Failure Rate (20%) by
Year___
Mean Time to Failure
(50% of the initial
population will have
failed by ____ Years)
New Style Photocell 7.9 10.2 14.9
LED Light Fixture 12.1 15.5 22.6

For each of the cases, a model was created to help compare the risks, resource needs, potential
energy savings, and financial impacts of each case. In the end, the LED Case will save customers
money over the Base Case. While the Optimized Case provides a better financial return to our
customers compared to both the Base Case and LED Case. The customers will still see savings
over the life of the LED fixtures compared to today’s practices in the Base Case and eliminate
the need for 2.3 Megawatts of generation at night.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The LED Change Out program replaces LED lights upon failure (burn-out). Funding
calculations are based on historical spend (2020 spend was approx. $411,000). We
anticipate as more bulbs are replaced due to failure, there will be less spend each year.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 65 of 422
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The impacts of the LED Change-Out Program span across many departments at Avista.
Operations is responsible for managing the work and executing the light change-outs in the field,
primarily by Avista’s servicemen and local reps. Avista’s Operations Support Group (Mobile
Dispatch) and EAM Technology are responsible for creating work orders for all change-outs and
dispatching them to the field. The Customer and Shared Services department, particularity the
Enterprise Systems – CC&B, is impacted by the project because the customer billing changes
upon converting to LED light fixtures.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Three alternative cases were initially considered in the analysis of converting the streetlight to
LED technology. Base Case replaces failed streetlight components only when they fail. The
second case, called the LED Case, replaces the current HPS streetlights with new LED fixtures
and implements a planned replacement at fifteen years for the fixture and photocell. The
analysis noted that inside the new LED Case model, a fifteen-year replacement strategy proved
more cost effective over the lifecycle than running LED lights to failure. Thirdly, the Optimized
Case represents keeping the current HPS light fixtures and performing planned replacements
of the bulbs and photocells at five-year cycles for the bulbs and ten-year cycle for the photocells

For each of the cases, a model was created to help compare the risks, resource needs, potential
energy savings, and financial impacts of each case. In the end, the LED Case will save
customers money over the Base Case. While the Optimized Case provides a better financial
return to our customers compared to both the Base Case and LED Case. The customers will
still see savings over the life of the LED fixtures compared to today’s practices in the Base Case
and eliminate the need for 2.3 Megawatts of generation at night.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This is an ongoing program that started in 2015.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The LED Change-Out Program is in alignment with the company’s strategic vision of delivering
reliable energy service and the choices that matter most to our customer’s. As part of the
program, infrastructure is replaced with longer lasting equipment. By providing more efficient
equipment and quality lighting, this results in an energy savings and an increase in driver and
pedestrian safety for our customers and communities we serve.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 66 of 422
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Any local or state government which has jurisdiction over streets and highways has an obligation
to the general public they serve to provide acceptable illumination levels on their streets,
sidewalks, and/or highways intended for driver and pedestrian safety. Due to having an
overhead distribution system in most urban areas, Avista provides a convenient streetlight
service in almost every local and state government entity they serve, and manages the
streetlights to provide street, sidewalk, and/or highway illumination.
Results of this program include; significant improvement in energy savings, lighting quality for
customers, and resource cost savings.
Secondly, converting streetlights to LED technology helps bring Avista in compliance with the
Washington State Initiative 937 (or the Clean Energy Initiative), which ensures that at least
fifteen percent of the electricity Washington state gets from major utilities comes from clean,
renewable sources, and that Washington utilities undertake all cost-effective energy
conservation measures. LED streetlight technology is part of the mentioned energy conservation
measure.
The YTD spend is tracked and reviewed each month during the Electric Operations Roundtable
(ORT) meetings. The ORT reviews monthly spend and manages any additional funds requests.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The LED Change-Out Program extends across multiple departments at Avista impacting
them directly or indirectly. Each department identified as a stakeholder will nominate an
engaged representative to act as the liaison between the program and their department.
The department stakeholder representative will also take part to promote their
department’s interests in the business. Some internal departments include; Construction
Services, Distribution Engineering, Warehouse and Investment Recovery, Supply Chain,
External Communications, Mobile Dispatch, Enterprise Asset Management, Customer
Enterprise Technology, and Regional Business Managers.
External stakeholders in the program include all state, county, and local agencies that have
a streetlight account with Avista, as well as neighborhood councils, and local law
enforcement agencies. All external stakeholders have a vested interest in the business
because the streetlights illuminate their streets and sidewalks for the purpose of public
safety.

2.8.2 Identify any related Business Cases
• Grid Modernization: With HPS lights changed out as they fail, Grid Modernization
projects are likely to find and convert more HPS lights on selected feeders. (The System
Wide DFMP says on page 34 that designers should change HPS lights when performing
work in the supply space of a pole.)

3.1 Steering Committee or Advisory Group Information
The Operations Roundtable (ORT) acts as the advisory group for the LED Change Out Program.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 67 of 422

3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors the incurred costs and submits any additional
funds requests as needed. LED Change Out Program work is overseen by the local area
operations engineers and area construction managers.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making, prioritization and change requests will be documented and monitored though
the Operations Roundtable (ORT).

The undersigned acknowledge they have reviewed the LED Street Lights and
agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 68 of 422

Signature: Date: 07/25/2022
Print Name: Katie Snyder
Title: Asset Maintenance Business Analyst
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
7/28/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 69 of 422
EXECUTIVE SUMMARY
Asset Management and Distribution Engineering provided the analysis of Avista’s distribution
assets and their condition. This analysis is used to direct the Wood Pole Management (WPM)
work that includes inspecting and maintaining Avista’s poles, hardware, and equipment on a
twenty-year cycle. This analysis is documented in the 2017 Wood Pole Management Program
Review and Recommendations, it is reiterated in the Avista Utilities Electric Distribution
Infrastructure Plan June 2017, and the 2021 Wood Pole Management (Distribution) Inspection
Cycle Analysis. Starting in 2021 the cycle was shortened to seventeen- years for the next ten-
years to help ensure poles were inspected and failed assets replaced before Grid Hardening
Programmatic work occurs. The seventeen-year cycle analysis is discussed in the Wood Pole
Management (Distribution) Inspection Cycle Analysis. Asset Maintenance manages and tracks
the work, budget, and schedule. The major drivers for the program are system reliability, improved
cost performance, and reduced customer outages. These drivers are achieved by replacing
defective poles, associated hardware, and equipment when the condition of the asset requires
replacement. The National Electric Safety Code (NESC) is adopted as Washington Law under
WAC 296-45-045. Part 013C of this code describes the application, Part 121 defines the
inspection interval, and Part 214 details documentation and correction of the pole inspection
results. We have also communicated to our insurance carrier Aegis that we are committed to
staying on cycle and completing the work in a timely manner. The service code for this program
is Electric Direct and the funding is tracked under ER2060.

WPM work encompasses Avista’s electric distribution overhead facilities in Washington, Idaho,
and Montana. In order to maintain a seventeen-year cycle for the next ten years, approximately
13,000 poles need to be inspected and follow-up work completed annually. The work plan was
developed to complete 66% of the poles in the State of Washington and 33% of the poles in the
State of Idaho each year. The average cost on a feeder basis to replace defective poles, cross
arms, equipment, and hardware is $1352/pole . To stay on a seventeen-year cycle requires
$17,576,000 per year which also benefits the Grid Hardening efforts by replacing identified
defective assets before they complete their work. The requested amount is $3,000,000 under the
funding required as that funding will be charged to the Grid Hardening Sponsored Program. Our
customers will benefit by reducing unplanned outages, replacing assets under capital funding,
and increasing safety for our line workers and the public. The risk of not approving this Business
Case means we will run our facilities in a run-to-failure mode as identified rejected assets are not
replaced in a timely manner, safety for our line hands and the public decreases, and our Operating
and Maintenance Costs increase.

VERSION HISTORY
Version Author Description Date Notes
1.0 Mark Gabert Initial draft of original
business case 7/1/2020
2.0 Mark Gabert Final Draft of original
business case 7/31/2020 Full amount approved
3.0 Mark Gabert Business Case Refresh 8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 70 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
The Wood Pole Management (WPM) program historically inspected and maintained the
distribution wood poles on a twenty-year cycle and the transmission poles on a fifteen-year
cycle. In 2021 we moved the distribution inspection cycle to seventeen years to support the
Grid Hardening work plan Avista has approximately 227,000 distribution poles and to meet
the seventeen-year cycle approximately 13,000 poles need to be inspected and
replacement work completed annually. Approximately 26 percent of the poles are older than
60 years of age which will increase over time. The Mean Time To Failure (MTTF) for wood
poles is seventy-nine years, but Distribution Engineering recommends replacement at sixty
years of age due to the time element of the next cycle and the above groundline decay
characteristics of butt-treated wood poles, more specifically pole tops where our hardware
is attached. Currently, we only replace poles that fail the inspection process and do not use
age as the criteria for replacing poles under the Wood Pole Management budget. If we used
age and pole failure as a guideline it would require a significant increase in budgeted
funding. Along with inspecting poles, WPM inspects distribution transformers, cutouts,
insulators, wildlife guards, lightning arrestors, cross arms, guying, and pole grounds. The
average asset life of this equipment is fifty-five years and requires replacement along with
the pole work. The inspections document the asset condition and indicate what assets
should be replaced. The asset condition is observed and documented during the pole
inspection process as indicated in S-622 Specification for the Inspection of Poles. Designs
and work plans are then created to replace the aging infrastructure that fails the inspection
process. The construction work to replace the assets is also part of this program.
Requested Spend Amount $14,576,000 WPM - $3,000,000 GH
Requested Spend Time Period 1 year
Requesting Organization/Department Asset Maintenance/WPM
Business Case Owner | Sponsor Mark S. Gabert - Heather Webster - David Howell
Sponsor Organization/Department M51/WPM
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 71 of 422
1.1 What is the current or potential problem that is being addressed?
This program addresses and reduces issues such as outages, safety risks, and
unplanned maintenance. This is accomplished by inspecting, documenting, and
maintaining our overhead facilities in a useful condition on a twenty-year cycle. This
keeps our poles, equipment, and hardware safe for employees and the general public
while maintaining a high level of customer satisfaction. Starting in 2020 the Grid
Hardening program impacted the twenty-year cycle. To complete Grid Hardening
efforts Wood Pole Management moved feeders in high fire risk areas to a seventeen-
year reinspection cycle. This decreased inspection cycle enables Grid Hardening to
complete its work by replacing poles with the potential for failure ahead of Grid
Hardening construction. If Wood Pole Management is underfunded it will push some
feeders past the seventeen-year cycle which may impact Grid Hardening efforts.
1.2 Discuss the major drivers of the business case and the benefits to the customer
From an Asset Condition perspective, the major drivers for the program include safety,
system reliability, improved cost performance, reduced customer outages, and
decreased fire risk. These drivers are addressed by replacing defective poles,
associated hardware, and equipment at its end of life or as required by asset condition.
This program also has a mandatory and compliance component to it because the
National Electrical Safety Code (NESC) is adopted as Washington Law under WAC
296-45-045. Part 013C of the code describes the application, Part 121 defines the
inspection interval, and Part 214A details documentation and correction of the pole
inspection results.
1.3 Identify why this work is needed now and what risks there are if not approved or
is deferred
The work is required now to keep pace with the aging assets and expected failure rate.
Figure 1 below shows the increased rate at which the poles are reaching the seventy-
nine-year end of life. If this work is not maintained, this aging infrastructure will cause
an increasing number of failures leading to increased outages and higher construction
costs as it is much more expensive to respond to an asset failure than to have it
replaced under a planned capital program.

In addition to the risks of fires, outages, and failures with the aging equipment, the
additional risks associated with this program pertain to the following:

Environmental: Risks include potential large volume transformer oil spills, difficult
hazardous waste cleanup, impact to waterways, and repeated or moderate air emission
exceedance. According to the 2017 Wood Pole Management Review and
Recommendations if the program is unfunded the potential occurrence is greater than
four spills per year. If funded the potential occurrence is less than one per fifty years.

Public Safety and Health: Risks include the potential for serious injury for crews or
the public, significant damage to equipment, property of businesses, and public health
infrastructure impact of up to forty-eight hours. If the program is unfunded, the potential
occurrence is less than one per ten years. If funded the potential occurrence is less
than one per fifty years.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 72 of 422
Figure 1-Pole Age Profile

The Outage Management Tool (OMT) is used by Asset Management to track asset
condition and show trends of failure of specific equipment that should be targeted for
replacement. This information is also used to track key program performance as shown
in Table 1 below. The number of outage-type events has been reduced by 40% from
2009 to 2021. This reduction in outage events results in significant customer benefit.
The reduction also demonstrates increased reliability and safety along with a reduction
in outages. The original goal for this KPI was to stay below the number of events
averaged over 2005-2009 for WPM Related OMT events. The goal will be re-evaluated
by Asset Management in the future.

Table 1: Event Reduction Results

WPM Goal Related
Number of OMT
Events
Actual WPM
Related Number
of OMT Events
Projected Poles
Follow-Up Work
Actual poles Follow-
Up Work
2009 1460 1320 11400 11548
2010 1460 1004 11400 12010
2011 1460 1004 11400 10461
2012 1460 1013 11400 14530
2013 1460 816 11400 10763
2014 1460 905 11400 10588
2015 1460 760 11400 12018
2016 1460 717 11400 13244
2017 1460 888 11400 12996
2018 1460 751 11400 11532
2019 1460 742 11400 10902
2020 1460 745 11400 8694
2021 1460 868 11400 11404
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 73 of 422
The type of OMT events are broken down into more detail in Figure 2. Note there are
significant improvements to some events such as squirrels being reduced on average from
nearly 750 in 2008 to 250 events today. This improvement has been realized by adding
wildlife guards to the top of the transformer bushings to prevent squirrels from touching
exposed power connections which can result in outages. Both the transformer and
cutout/fuse events have been reduced by over 50% through the replacement of aged
equipment. In 2017 the calculated cost to customers for a pole failure is $24,400 based on
an average duration of 4.8 hours for 80 customers. The combined cost impact to customers
in 2015 alone for those events was $2,265,600. Also approximately ten years ago Avista
moved to using fiberglass cross arms which is beginning to reduce the average annual
number of pole top fires. This reduction should accelerate as Grid Hardening began
replacing wood cross arms in high-risk WUI areas in the second half of 2019.

Figure 2 - OMT Events

1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed above.
Ultimately the impact of this Program can be associated with our Electric Systems
Reliability metrics. The System Average Interruption Frequency Index (SAIFI) represents
the average number of sustained interruptions per customer for the year across Avista’s
entire system . Avista reported a SAIFI score of 1.05 for the year 2015. The Asset
Management group created Table 2 below to show the impact of this Program to our overall
SAIFI score. The predicted contribution is about 0.211, which has a significant impact on
the customer, whereas the contribution to SAIFI would be 0.57. This means the customer
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 74 of 422
would experience 0.36 more outages per year without WPM. Without WPM , the
contribution to SAIDI would be 1.27 (hours).

Table 2: SAFFI Metrics

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The 2017 Wood Pole Management Program and Review, The Electric
Distribution Infrastructure Plan June 2017 and the Wood Pole Management
(Distribution) Inspection Cycle Analysis January 2021 are located on the
c01m570 drive.
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
WPM is an ongoing cyclical program that proactively replaces assets identified
for replacement during the inspection process. By replacing assets before they
fail, outages are reduced, and replacement costs are reduced through planned
work. Investing in the infrastructure increase life-cycle performance and is cost-
effective using unit-based pricing. Figure 3 below shows the significant
improvement in ”events per mile of feeder” resulting from this program on before
and after WPM work. The peak of events per mile shown in the graph is from
Projected Metric
Description
Projected WPM
Contribution to the
Annual SAIFI Number
Projected Number of
Dist Poles Inspected
Projected Number of
Pole Rotten OMT Events
Projected Number of
Crossarm OMT Events
2009 0.214024996 11,400 137 32
2010 0.208489356 11,400 137 32
2011 0.211022023 11,400 137 32
2012 0.211022023 11,400 137 32
2013 0.211022023 11,400 137 32
2014 0.211022023 11,400 137 32
2015 0.211022023 11,400 137 32
2016 0.211022023 11,400 137 32
2017 0.211022023 11,400 137 32
2018 0.211022023 11,400 137 32
2019 0.211022023 11,400 137 32
2020 0.211022023 11,400 137 32
2021 0.211022023 13,116 137 32
Actual Metric
Description
Actual WPM
Contribution to the
Annual SAIFI Number
Actual Number of Dist
Poles Inspected
Actual Number of Pole
Rotten OMT Events
Actual Number of
Crossarm OMT Events
2009 0.1863468 14,430 44 25
2010 0.19916836 14,992 37 23
2011 0.202462739 14,980 35 28
2012 0.16613099 14,406 52 19
2013 1.15640942 11,903 34 18
2014 0.241571914 11,879 55 26
2015 0.225273848 7,835 43 23
2016 0.132313511 11,636 57 23
2017 0.12662277 10,595 39 22
2018 0.128829384 16,044 25 31
2019 0.126544503 11,187 44 26
2020 0.116836918 9,627 53 15
2021 0.210971466 12,066 45 17
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 75 of 422
2011 when there were nearly .3 events per mile. The results after the program
show performance as low as .1 events per mile of feeder, a significant
improvement.
If funding were to be reduced, expected outages would increase. The team
would then need to prioritize which components would be replaced and which
would be left. This would increase the likelihood that crews would need to visit
the same pole later if a remaining component were to fail.

Figure 3
2. PROPOSAL AND RECOMMENDED SOLUTION
Based on the analysis in 2017, the current twenty-year cycle delivers the best life cycle value
for the funding level. For perspective, the industry average for inspecting and maintaining
distribution assets is ten years. In 2021 Asset Managements “Wood Pole Management
(Distribution) Inspect Cycle Analysis “ Compared the Avista utility peer group, shown below,
indicates that Avista is a more rural utility and therefore has far fewer customers per pole
(approximately 1.5 vs. 10), making it economically feasible for the peer group to inspect poles
more frequently. The ten-year cycle delivers a better rate of return but any reduction in cycle
time requires an increase in expenses to pay for the increased number of poles inspected
each year, and a corresponding increase in requirements for capital replacements. Asset
Management and Distribution Engineering monitor system reliability to determine if
adjustments in the scope of work are needed in the future. They also need to determine the
funding level required to make those adjustments so Asset Maintenance can document those
changes as a new alternative in the Business Case for funding approval by the Capital
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Number of Years After WPM Work Number of Years Before WPM Work
Completed
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 76 of 422
Planning Group. If the Capital Planning Group does not approve the new alternative it is not
incorporated until at such time funding is approved.

Option Capital Cost Start Complete
Recommended Solution]: Distribution Wood
Pole Management Program inspects all feeders
on a twenty-year cycle and replaces inspection
failed wood poles, cross arms, missing lightning
arresters as necessary, missing/stolen
grounds, bad cutouts, broken insulators,
leaking transformers, and replace guy wires not
meeting current code requirements when the
pole is replaced. This includes increasing the
pole inspections and replacement work on a
seventeen-year cycle for the next ten years on
high risk WUI feeders to meet the requirements
of the Grid Hardening program. The $3M in
additional funding will be in the Grid Hardening
budget to expedite inspections and
replacement work. Total $17.5M
$14,576,000 01/2023 annually
Alternative #1] $M MM
YYYY
MM
YYYY
[Alternative #2] $M MM
YYYY
MM
YYYY
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 77 of 422
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The metrics, data, and analysis are documented in the 2017 Wood Pole Management
Program Review and Recommendations, Electric Distribution Infrastructure Plan June
2017, and the Wood Pole Management (Distribution) Inspection Cycle Analysis
January 2021. That data, analysis, and information was considered and documented
throughout this business case.
2.2 Discuss how the requested capital cost amount will be spent in the current year
(or future years if a multi-year or ongoing initiative). Include any known or
estimated reductions to O&M as a result of this investment.

The WPM program is an ongoing process of inspecting, designing, and completing
replacement work of assets identified for replacement during the inspection process.
The feeders on the work plan are at various phases of the process throughout the year.
The goal is to complete any identified work on a feeder within eighteen months of
inspection, and we currently average about fourteen months from start to finish. This
work is incorporated into some of the office's work plans and allows the company to
efficiently utilize resources under Capital funding. By completing this work, the overall
unplanned O&M costs required to replace failed poles, equipment, or hardware such
as cross arms attached to the pole will be reduced.
Direct savings-between 2005 and 2009 the average number of OMT events related to
Wood Pole Management was 1,460 per year. Between 2009 and 2021 the average
number of OMT events has been reduced to an average of 887 events per year. This
is an average reduction of 573 OMT events per year related to WPM work. The average
OMT event takes 3.5 hours to retore at a straight time cost of $500 per hour for a total
of $1,750 per event. Based on this information we see a direct savings of $1,002,750
annually by preventing the 573 outages related to Wood Pole Management activities.
This does not include the material or any overtime costs. It is anticipated that the
average number of OMT events will continue to be reduced as feeders are completed
and there are no funding or labor resource delays.
Indirect Savings-based on the ICE calculator (Interruption Cost Estimate) Asset
Management looked at pole-rotten data for 2014-2019. Total hours per incident is 157.5
hours (average # of customers impacted (45) * the average outage time (3.5)). The ICE
cost is $116.15. Therefore, your indirect benefit per incident is $18,294. Wood Pole
Management work on average avoids 573 events per year therefore the annual indirect
benefit is $10,482,462.

2.3 Outline any business functions and processes that may be impacted (and how)
by the business case for it to be successfully implemented.
The current WPM Program has been in place since 2008 so any impacts on other
business functions have already been realized. There is however a strong need for
Asset Management to continue reviewing and analyzing the data that supports this
program.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 78 of 422
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
In Asset Management’s 2017 Wood Pole Management Review and Recommendations:
“Asset Management examined several alternatives that included a 5-year, 10-year,
20-year, and 25-year inspection cycle time as well as the impact of Grid
Modernization work on the related Wood Pole Management work. While the 5-year
cycle did provide a better Customer Internal Rate of Return of 8.85%, the 5-year
cycle Operations, and Maintenance costs exceeded our historical spending
constraint. The 20-year inspection cycle provided the best Customer Internal Rate
of return and our current practice of replacing transformers that functionally have
failed while meeting the Operating and Maintenance budget constraints.
Any delays in implementing the Wood Pole Management program strategy as
envisioned will delay the immediate benefits and take 20 years based on the
current inspection cycle to recover the long-range value of the strategy.
We recommend continuing the Wood Pole Management program on its 20-year
inspection cycle and follow-up work strategy. Any delays in the work will impact
reliability and system performance. “
Choosing the recommended solution keeps WPM and Grid Hardening on track to be
completed on time. This work has been approved and validated in previous commission
responses.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer.
WPM is an ongoing program. The work is a continuous process of inspecting Avista’s
poles on a feeder basis. Each feeder represents a project within the program. There
are several phases to completing each feeder including inspecting, designing, and
capital follow-up. As soon as any capital follow-up work is completed, the asset can
become used and useful. The transfers to plant occur on a monthly basis. In addition,
our Finance Department preps the AVA_Plan system periodically for a spend and
transfer to plant forecast update for the remainder of the year.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This business case improves safety for our customers, employees, and the general
public by responsibly mitigating safety hazards. This will also improve reliability, reduce
fire risk, and decrease the number of unplanned O&M outage responses. Our
company’s vision is supported by building reliable infrastructure and then maintaining
the assets in a safe reliable condition that improves our customers lives. The public
utility commissions and our customers hold us to the highest standard of care. When
we act prudently and follow through with our commitments, we demonstrate our
trustworthiness.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 79 of 422
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The requested amount is a prudent investment to maintain Avista’s overhead electric
system on a twenty-year cycle. This is in alignment with the NESC requirement to
inspect and maintain our facilities in a timely manner. This work reduces the company's
risk associated with owning overhead distribution electric facilities. This business case
is reviewed and updated with each requested business case refresh. The information
is also reviewed by our Rates Department and the Washington and Idaho Utility
Commission’s for rate case purposes. In addition, the information is utilized by the
Capital Budget Committee to determine funding levels based on company priority.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electric Distribution customers, Grid Hardening, Grid Modernization, Distribution
Engineering, Asset Management, Joint Use Projects, and Construction Offices. Please
note that with the sunsetting of TCOP some internal crews incorporate WPM as part of
their work plan.
2.8.2 Identify any related Business Cases
Grid Hardening Program, WSDOT Control Zone Mitigation Program, and the Grid
Modernization Program.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Asset Management and Distribution Engineering provide ongoing analysis of
distribution asset conditions. The analysis is used to direct the WPM work that includes
inspecting and maintaining Avista’s poles, hardware, and equipment on a twenty-year
cycle. The twenty-year cycle is documented in the 2017 Wood Pole Management
Review and Recommendations. The operating guidelines in the recommended solution
are documented in the DFMP-Distribution Feeder Management Plan-Design Criteria
Manual-Applicable to Wood Pole Management.
3.2 Provide and discuss the governance processes and people that will provide
oversight
The governance process is a collaborative process that includes leadership from Asset
Management, Distribution Engineering, Asset Maintenance, Distribution Engineering,
Director Of Operations, WPM Program Manager, and WPM inspectors. Status updates
on progress towards yearly goals are documented and updated on the monthly one-
pager.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
WPM is a long-standing program that is well established. There are few change orders,
but they are reviewed and approved by the inspector and program manager before
construction. Those approved changes are also documented by the inspectors during
the audit process
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 80 of 422
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Wood Pole Management Business
Case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Mark S. Gabert
Title: WPM Program Manager
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director Of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name: Heather Webster
Title: Asset Maintenance Manager
Role: Steering/Advisory Committee Review

8/31/2023
31.Aug.2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 81 of 422
EXECUTIVE SUMMARY

Avista’s electric distribution system is the largest part of the company’s infrastructure. It
consists of poles, wires, underground cable, transformers, and a variety of other
equipment. In addition, Avista’s electric distribution system has the largest footprint of
any other infrastructure within the company’s service territory. This creates a unique
challenge for the company. The distribution system is the largest contributor to a
customer’s reliability and the overall safety of the public, mostly from the sheer volume
of exposure it establishes. This business case is one of several such as, Minor
Rebuilds, Wood Pole Management, Grid Hardening, etc., that creates a direct customer
benefit by completing projects that improve the electric distribution system’s safety,
performance, and reliability. The jobs for this business case are identified by our
operations engineers for their regional areas within Washington, Idaho, and Montana
and they are prioritized against each other with input from the distribution planning
engineers.

Most of the funds provided by this business case are used to complete projects that
solve performance and capacity issues driven by system wide electric load growth.
Other projects address power quality mitigation, reliability improvements, operational
flexibility, system protection improvements, and safety enhancements. As such, the risk
in not funding this business case is the inevitable decline in the overall health and
operation of Avista’s electric distribution system, e.g., overloading conductor to the point
of failure. The ongoing nature of issues that arise within the electric distribution system
coupled with the large amount of work drives the need for this business case to be
funded on a yearly basis.

VERSION HISTORY
Version Author Description Date Notes
1.1 David James Initial draft of original business case. 04/07/2017
1.2 Cesar Godinez Updated to include voltage/transformer
mitigation work. 07/03/2019
Addition of voltage and
transformer mitigation work
identified by AMI data.
2.0 Cesar Godinez Updated narrative and business case
template. 07/01/2020
Business case refresh and
name change to “Distribution
System Enhancements” from
“Segment Reconductor and
FDR Tie.”
2.1 Cesar Godinez Minor updates. 01/04/2022
Updated “Steering Committee
or Advisory Group Information”
in section 3 “Monitor and
Control.”
3.0 Cesar Godinez Updated narrative. 08/31/2022
Business case refresh 2022;
revised Executive Summary
and incorporation of ‘offsets’
information.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 82 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM

Avista’s electric distribution system consists of three hundred and seventy (370)
discrete primary electric circuits encompassing over 19,300 miles of overhead
conductors and underground cables. The distribution grid is managed by division
or ‘operations engineers’ and centralized distribution planning.
Load Demands on the grid are dynamic with load patterns changing because of
many factors including weather, temperature, economic conditions, conservation
efforts, and seasonal variations. Avista operates a radial distribution system using
a trunk and lateral configuration (industry standard). Though many circuits are
monitored at the source substation (SCADA), downstream trunk and lateral branch
circuits loading are analyzed via computer simulation. At Avista, distribution
analysis is performed with the Synergi load flow program. AMI data is also used
to analyze service voltages and transformer loading. AMI data has shown system
issues in the form of service voltage problems and transformer overloading. Our
System Planning group is also starting to export AMI load data into Synergi to use
it in the computer simulation.
Additionally, power quality investigation and subsequent mitigation projects are
initiated by customer inquiries or analysis work. Work is also driven by reliability
and safety concerns that are identified by our engineers and/or operation
personnel. Operational flexibility can also drive the need to upgrade electric
circuits, install switching equipment, and other infrastructure as needed.
In a manner like substation rebuilds, expansions, and additions that are planned
for and scheduled years in advance, the distribution system also requires rebuilds,
expansions, and additions. The Distribution System Enhancements business case
allows for a methodical and planned out approach to needed feeder
enhancements. Secured funding for future years allows for planning large projects
in a multi-year approach, with completion of a portion of the overall project
happening over a series of years. In absence of this business case, critical issues
Requested Spend Amount $7,500,000
Requested Spend Time Period 5 years (on-going)
Requesting Organization/Department C51 / Electric Distribution Design
Business Case Owner | Sponsor Cesar Godinez | Josh DiLuciano
Sponsor Organization/Department T08 / Electrical Engineering
Phase Monitor/Control
Category Program
Driver Performance & Capacity
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 83 of 422
would be resolved in a reactionary and haphazard fashion, funded through the
Minor Blanket, and completed outside the confines of a “big picture” plan and
approach to feeder management.
Avista’s electric distribution system analysis and mitigation strategies are informed
by several internal documents and data repositories. These are listed below for
reference:

1. Distribution Planning Standard “500 Amp FDR” – internal document that defines the
performance criteria and limits for both urban FDR tie systems and rural pure radial
circuits. This document is maintained by System Planning (John Gross).
2. FDR Status Report – distribution engineering publishes an annual report indicating
peak circuit demand by season, reliability outage statistics, circuit health check, and
other logistic information.
3. Distribution Standards – distribution engineering maintains construction standards for
both overhead and underground primary circuits. It also maintains standards for all
electrical material and apparatus.
4. PI Database – operating data retrieved by either the SCADA or DMS system is stored
in the PI historian. This allows direct access by engineers and planners to help inform
both operating and design strategies. (Distribution Operations)
5. Feeder Automation Strategy – a design guide to assist the CPC/Engineer when
making decisions involving automated devices (Distribution Engineering).
6. Synergi Computer Program – the load flow program derives topology information from
Avista’s GIS system. Updates to the Synergi database are performed by Distribution
Planning.
7. SCADA Variable Limit (SVL) – Avista uses temperature compensated program to
monitor conductors, cables, and series connected major equipment (e.g. transformers,
breakers, switches, regulators, and etc.). This system is deployed on Avista’s
EMS/SCADA system. The program is SME supported by Substation Engineering.
8. AMI Data – AMI service voltage data is used to identify services that are out of
compliance with the ANSI C84.1 standard of +/- 5% of 120 volts. AMI service load data
is used to identify transformers that are overloaded according to the standards set by
distribution engineering.

A typical distribution circuit is illustrated on the next page. Like municipal water
systems, grid capacity decreases with distance away from the source substation.
This leads to system ‘constraints’ as loads are added to the system through direct
customer action or load shifting between circuits (Avista).

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 84 of 422

500A 200 A 100 A
Sub
Load Demand
Exceeds Grid
Capacity
Illustration of Distribution Grid Capacity Constraint
Avista’s Distribution System contains over 75 different wires and cables
2020 Avista Standard OH Primary Conductors
556 All-Aluminum (AAC) – 601 Amps (main trunk, urban)
336 All-Aluminum (AAC) – 442 Amps (main trunk, rural)
2/0 Aluminum Conductor, Steel Reinforced (ACSR) – 238 Amps (gen purposes, rural)
#4 Aluminum Conductor, Steel Reinforced (ACSR) – 119 Amps (lateral circuit)

Legacy Conductors
2/0-3/0 Copper – 319-369 Amps (main trunk)
#2 Copper – 197 Amps (main trunk)
#6 Copper - 110 Amps (lateral circuit)

Avista’s distribution grid contain over 1,000 miles of conductor equivalent or smaller than
#6 Copper.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 85 of 422
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Description Consequence
Reactionary
Approach
Reacting only when an issue
occurs to mitigate thermal
overloads, power quality issues,
reliability and safety issues.
Conductor will ‘sag’ down beyond
design limits and contact joint-use
telecom circuits or violate NESC
prescribed limits. In extreme
situations, conductor failure will
occur. Service quality will degrade
below acceptable levels and
customer outages will increase.
System enhancements (if they occur
at all) will be done in a “scattered”
approach and not guided by
engineered plans and solutions.
Select DSM
treatment
Target homes and businesses
with demand side management
solutions to effect peak load
demand reduction.
This option would be a viable,
however, State Commissions do not
allow DSM treatment in localized
areas.
Load Shifting FDR Tie This action is represented in the
Distribution System Enhancements
program. By extending lines to
adjacent circuits, load can be shifted
to underutilized circuits and mitigate
overloads. This action requires
capital investment.
Capacity
Increase
Reconductor overloaded
‘segments’ to increase line
capacity, mitigate identified low
voltage issues, and correct
system protection issue. Install
voltage regulators to mitigate
feeder level low voltage issues.
Replace Transformers (or install
additional transformers) to
mitigate overloaded transformers
and service voltage issues.
All electric components are
thermally limited. Reconductoring is
the most direct approach to
mitigating overloaded circuits and
low voltage issues.
System
Enhancements
Mitigate power quality issues, as
well as, reliability and safety
issues. Add operational flexibility
to the electric distribution system.
Expand distribution automation by
adding targeted “smart” devices.
Accomplishing this type of work
ensures that our electric distribution
system is operated efficiently,
reliably, and safe.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 86 of 422
Recommendation:
1. Reactionary Approach is unacceptable. Violates NESC/WAC regulations
and industry standards. It also represents an unacceptable level of risk to
public safety and infrastructure.
2. Targeted DSM is not allowed.
3. FDR Tie – represented in the program (indirect solution).
4. Segment Reconductor – represented in the program (direct solution).
5. System Enhancements – represented in the program.

Projects listed in the current 5-year “Distribution System Enhancements” program
are summarized on the Distribution Engineering SharePoint site. The following is
a summary of those projects listings as of 2022.

https://sp2016.corp.com/sites/sp/enso/dist/_layouts/15/start.aspx

Region 2022 2023 2024 2025 2026
Spokane 2,946,400 2,946,400 2,946,400 2,946,400 2,946,400
East 2,142,900 2,142,900 2,142,900 2,142,900 2,142,900
South 1,339,300 1,339,300 1,339,300 1,339,300 1,339,300
Big Bend 1,071,400 1,071,400 1,071,400 1,071,400 1,071,400
Total 7,500,000 7,500,000 7,500,000 7,500,000 7,500,000

One of the planning objectives is to levelize the resource demands and avoid
significant upswings or downturns in crew resource forecasting. Distribution
Engineering works closely with the Operating Divisions and Asset Maintenance to
develop a resource balanced work plan and maximize the effectiveness of Avista
craft resources. In addition, reductions in funding of this business case typically
result in increase spend in our Minor Blanket business case. There are also
significant capital investment offsets created by the work this business case
accomplishes. Our quantified direct saving offsets calculated for 2022 and 2023
are $1,207,740 and $929,094 respectively. Our quantified indirect savings have
been calculated to about $28,683 yearly. The detailed writeup for the calculated
offsets can be found here: Capital Investment Offsets Form - Distribution System
Enhancements.

Distribution assets are fixed resources and therefore, project alternatives are
generally dominated by supply side solutions. Operating limitations are codified in
Avista internal standards (as listed) but derived through industry and regulatory
policies including: Washington Administrative Code (WAC), National Electric
Safety Code (NESC), National Electric Code (NEC), and IEEE/ANSI standards &
manufacturer recommendations specific to equipment ratings and operating limits.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 87 of 422
3. MONITOR AND CONTROL

Steering Committee or Advisory Group Information
Distribution Area/Operations Engineers and Distribution System Planning.
Marc Lippincott, Caitlin Greeney, & Knute Rognaldson – Spokane and Deer Park
Marshall Law & Marc Lippincott – East Region (CDA, Kellogg, St. Maries,
Sandpoint)
Dan Knutson – Othello, Davenport
Tyler Dornquast – Colville
Chris Dux – South Region (Pullman, Clarkston, Grangeville)
John Gross & Damon Fisher – Distribution System Planning
Cesar Godinez – Distribution Engineering Manager

The steering committee meets monthly to review projects and construction
processes and discuss near term operating conditions. The team also meets
annually to focus attention and resources on the system planning needs for grid
capacity, service revisions, and substation capacity.

Decision Making Process

The decision model is represented by individual ‘proposals’ coupled with joint
review and acceptance by distribution engineering and distribution system
planning. The project ‘proposals’ typically consist of a Project Requirement
Diagram (PRD) that outlines the scope of the project and includes supporting
calculations and documentation. The program’s business case is modified
annually to reflect the 5-year work plan. The Capital Planning Group then reviews
all of the submitted business cases and prioritizes and allocates resources across
the organization. Distribution infrastructure is not part of the “Engineering
Roundtable” except for distribution substations and other larger distribution
projects on occasion.

The Distribution System Enhancements business case decision model is
illustrated on the next page.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 88 of 422

ApprovalAcceptanceProposal
Authorized Resources by CPG
Requested Resources by
Distribution Eng/Planning
(Area/Operations Engineer)
Problem Area Identified by
Operations Engineer (South, East,
Big Bend, and Spokane Region
Proposals to principally:
1) Reconductor line “segment”
to mitigate thermal overload
or low voltage issues
2) Construct Tie-Line
connection to shift demand
to an adjacent circuit
3) Install/replace transformers
to mitigate voltage issues or
overloaded transformers
4) Install voltage regulator,
capacitor bank, or other
equipment to mitigate
power quality issues.
5) Install recloser, protection
devices, or other switching
equipment (including
“Smart” devices) to mitigate
reliability/safety issues
and/or add operational
flexibility.
(Distribution Team)
All project proposals reviewed
by Distribution Engineering and
Planning to provide peer
review. Initially screening to
determine priority ranking and
immediacy. Business Case
Revised annually to represent 5-
year planning horizon.
Submitted to CPG
(Capital Planning)
Business Case review generally
results in partial funding of the
work plan. The Distribution
Team (OE, Mgr, Planning)
reassembles to prioritize, rank,
and schedule projects to align
with authorized budgets.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 89 of 422
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution System
Enhancements business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Cesar Godinez
Title: Distribution Engineering Manager
Role: Business Case Owner

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

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 90 of 422
EXAMPLES SHOWN FOR ILLUSTRATION:

FDR Status Report (provides baseline circuit performance and logistics
information) Warning Level (yellow highlight),

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 91 of 422
Distribution “500 Amp” Plan (System Planning)
Company standard for the operation and load service planning associated with
Avista’s electric distribution grid.

Key elements-- Urban “FRD Tie” system. Requires that reserve capacity margins
be maintained so that adjacent circuits can restore service to customers in the
event of a planned or forced outage. In summary, no urban circuit should be
loaded above its 67% capacity limit.

Excerpt from “500 Amp” Plan. Source: Distribution SharePoint (3/15/17)

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 92 of 422
Avista’s SCADA monitoring system incorporates a temperature compensated
thermal ampacity rating system known internally as SVL (Scada Variable Limit).
SVL has been in use since 1993. The following indicates a summary screen
indicating the top ten most heavily loaded (by % capacity) transmission lines,
substation power transformers, and distribution circuits. This screen is
continuously monitored by System Operators but also used by Area Engineers to
capture data during peak load conditions. It provides additional data to aid with
project planning for the distribution system enhancements program.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 93 of 422
FDR by Area. Shown only to illustrate the scale of the effort to monitor our
distribution system.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 94 of 422
Synergi Computer Modeling (Millwood 12F4 screen shot)

Computer simulation is the primary tool used to identify and develop strategies to
mitigate a thermal overload condition. Note, that Avista’s electric distribution
system has been developed over the full course of the Company’s operating
history and infrastructure installed near the turn of the century (1900) is still in-
service. Though current Avista construction standards limit the number of
overhead primary wires to four (4): #4 ASCR, 2/0 ACSR, 336 AAC, 556 AAC;
Avista maintains a fleet of seventy five (75) different primary wires and cables.
Many are no longer available commercially and we maintain ‘hand coils’ salvaged
from project work in order to effect maintenance repairs on those conductor
segments. We ceased to install overhead copper conductors in the 1950’s though
today, thousands of miles of #6A, #6CW, and other copper conductors remain in
service.

Synergi Computer System: Millwood 12F4 Circuit

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 95 of 422
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high-level summary of the
projects or programs included. Please limit to no more than 2 paragraphs. Components that should be
included:
1) NEEDS ASSESSMENT- a synopsis of the problem, the current state and recommended solution
2) COST- the cost of the recommended solution
3) DOCUMENT SUMMARY- benefit to the customer
4) RISK- of not approving the business case
5) APPROVALS- who reviewed and approved the recommended solution

<< Both the Executive Summary and Version History should fit into one page >>

New distribution substations added to the system for load growth and reliability are critical to the
long term operation of the system. As load demands, increase and customer expectations rise
regarding reliability, incremental distribution substation capacity is required. This allows for
improved operational flexibility, better system reliability, and easier routine maintenance
scheduling as equipment is more easily taken out of service because load can be transferred.

Capacity on the electric system to be able to take components out of service on a planned basis
so that maintenance or replacements can be made has reduced as load demands have
increased. Having the right amount of backup capacity in each area is critical for the continued
appropriate management of the electric system. This business case is important because through
it, customers can likely continue to receive electric service at a level that they have grown
accustom to receiving.

This Business Case includes the following Expenditure Requests:
• 2274: New Substations
• 2606: SCADA to All Substations

Service: ED – Electric Direct
Jurisdiction: Various. Each project has its own Jurisdiction.
Engineering Roundtable Request Number: Various. Each rebuild project has its own ERT
Request.
See the 5-year Funding Request for current budget requests.

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 04/14/2017 Initial Version
2.0 Update to 2020 Template 06/30/2020

DocuSign Envelope ID: 62A5EE76-6BEF-4DAD-AEA4-E17FF02145BC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 96 of 422
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what the project will do and current problem statement]
New distribution substations added to the system for load growth and reliability are critical
to the long term operation of the system. As load demands, increase and customer
expectations rise regarding reliability, incremental distribution substation capacity is
required. This allows for improved operational flexibility, better system reliability, and easier
routine maintenance scheduling as equipment is more easily taken out of service because
load can be transferred.
1.1 What is the current or potential problem that is being addressed?
As load demands, increase and customer expectations rise regarding reliability,
incremental distribution substation capacity is required.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Performance and Capacity – Increasing load on an aging electrical system. And the better
the asset condition, the fewer equipment failures and possible customer outages there are.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
This is a continuing effort to stay ahead of the curve to avoid reliability issues.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
System Planning Assessments and Studies.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
System Planning Assessments on System Planning Sharepoint site.
Requested Spend Amount $10,000,000 - $30,000,000 per year
Requested Spend Time Period On Going
Requesting Organization/Department T&D
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Program
Driver Performance & Capacity
DocuSign Envelope ID: 62A5EE76-6BEF-4DAD-AEA4-E17FF02145BC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 97 of 422
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
This program adds new distribution substations to the system in order to serve new and
growing load as well as for increased system reliability and operational flexibility. New
substations under this program will require planning and operational studies, justifications,
and approved Project Diagrams prior to funding.
Alternatives considered include:
Do Nothing: Maintain (to the best of our ability) all obsolete or end-of-life apparatus. Repair
or replace equipment on emergency basis only. Some repairs would not be possible due to
obsolescence. Considerably more, and longer, customer outages would result. Although
there is zero Capital cost connected with keeping the status quo there are some associated
O&M and other system sustainment costs.
Extension of distribution feeders from neighboring substations and increased capacity
at those substations would be required at a minimum. The negative impact is most
certainly reduced reliability and difficulty in long term maintenance and system
operation. Increased liability would result.
Solution: Anticipated load growth requires the addition of two new substations per year
over the 2017-2026 horizon
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include: - Samples of savings, benefits or risk avoidance estimates - Description of how benefits to customers are being measured - Comparison of cost ($) to benefit (value) - Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital
spend?). Include any known or estimated reductions to O&M as a result of
this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

DocuSign Envelope ID: 62A5EE76-6BEF-4DAD-AEA4-E17FF02145BC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 98 of 422
O&M will increase due to the addition of electric substation and associated transmission
and distribution lines. This will include inspections and maintenance of equipment.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Status Quo – Obsolete equipment drives up maintenance costs and outage risks. Extending
Distribution Feeders – higher risk of load issues and customer outages.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer. spend, and
transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
See graph above, Section 2.2. Transfers to plant will occur when a substation is in-service
or energized. Adhering to project timelines will save capital carrying costs.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
These projects will help Avista stay ahead of the curve of load growth and equipment age
to prevent customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
Failure to adjust to load changes and customer needs will lead to equipment failures,
customer outages and expensive emergency projects.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
DocuSign Envelope ID: 62A5EE76-6BEF-4DAD-AEA4-E17FF02145BC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 99 of 422
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part of your departmental prioritization process.]
• Glenn Madden - Manager, Substation Engineering
• Project Engineer/Project Manager (PE/PM) – Various
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
The Engineering Roundtable manages the prioritization of projects within this business
case as supported by Asset Management studies and input from company subject matter
experts. The Engineering Roundtable is comprised of representatives from the following
departments: Asset Management, Compliance, System Planning, System Operations,
Telecommunications, Transmission Contracts, Protection Engineering, Substation
Engineering, Transmission Engineering, and Substation Support.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

DocuSign Envelope ID: 62A5EE76-6BEF-4DAD-AEA4-E17FF02145BC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 100 of 422
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation – New Distribution
Station Capacity Program and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Date:
Glenn Madden
Manager, Substation Engineering
Business Case Owner

Date:
Josh DiLuciano
Director, Electrical Engineering
Business Case Sponsor

Date:
Damon Fisher
Principle Engineer
Steering/Advisory Committee Review

DocuSign Envelope ID: 62A5EE76-6BEF-4DAD-AEA4-E17FF02145BC
Jun-28-2022 | 3:49 PM PDT
Jul-05-2022 | 7:48 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 101 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY Avista is a joint owner in the 500kV Colstrip Transmission System and party to the Colstrip Project Transmission Agreement (“Agreement”). Under Federal Energy Regulatory Commission (“FERC”) rules and the Agreement, Avista must comply with all rules and procedures governing the interconnection of new generation facilities with the Colstrip Transmission System. Pursuant to the Agreement, Clearwater Energy Resources, LLC requested interconnection of a 750MW wind project at Broadview (“Clearwater Wind Project”), all required study processes were completed, and Avista executed a Large Generator Interconnection Agreement with the developer on May 22, 2019 (“LGIA”). Avista and the joint owners of the Colstrip Transmission System are obligated to fund their respective shares of all Transmission Provider Interconnection Facilities and Network Upgrades applicable to the interconnection of a Large Generator Interconnection project. Failure to fund this project will result in Avista being in breach of both the Agreement and the LGIA, and would be a violation of FERC rules governing generation interconnection. Such obligations arise from Avista’s ownership in the Colstrip Transmission System, which has benefited Avista retail native load customers over the life of the Colstrip Project. Avista’s allocation of costs for the construction of required facilities for the Clearwater Wind Project was originally estimated to be $650,600, in 2018 dollars. The original Business Case was submitted and approved, July, 2019. Overall project cost was reduced to $570,000 per the in-year adjustment request approved June 17, 2020. Applicable service code and jurisdiction are 098-ED, common system-wide, electric direct.

VERSION HISTORY
Version uthor Description Date Notes
1.0 Jeff Schlect Initial narrative drafted from pre-existing
approved case 7/30/2020 Existing Approved Case

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 102 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 2 of 6

GENERAL INFORMATION

1. BUSINESS PROBLEM
Per the Agreement, Avista is a joint owner (joint tenants in common) of the Colstrip Transmission System, which consists of approximately 250 miles of double circuit 500kV transmission facilities extending from the Colstrip Project westward to the Broadview 500kV Substation and the Townsend point of interconnection between the Colstrip Transmission System and the Bonneville Power Administration’s Eastern Intertie 500kV facilities1. Under FERC rules and the Agreement, Avista must comply with all rules and procedures governing the interconnection of new generation facilities with the Colstrip Transmission System. Pursuant to the Agreement, Clearwater Energy Resources, LLC requested interconnection of its 750MW Clearwater Wind Project to the Colstrip Transmission System at Broadview. All required study processes were completed and Avista executed a Large Generator Interconnection Agreement with the developer on May 22, 2019 (“LGIA”).

1 Avista owns a 10.2% share in the Colstrip-Broadview segment and a 12.1% share in the Broadview-
Townsend segment.
Requested Spend Amount $570,000
Requested Spend Time Period 2 years (2020-2021)
Requesting Organization/Department Energy Delivery / Transmission Services
Business Case Owner | Sponsor Jeff Schlect | Heather Rosentrater / Mike Magruder
Sponsor Organization/Department Energy Delivery / Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 103 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 3 of 6
Avista and the joint owners of the Colstrip Transmission System are obligated to fund their respective shares of all Transmission Provider Interconnection Facilities and Network Upgrades applicable to the interconnection of a Large Generator Interconnection project. NorthWestern Energy (“NWE”) performs all Transmission Operator functions under the Agreement, including construction budgeting and forecasting for Colstrip Transmission System facilities. Avista’s allocation of costs for the construction of required facilities for the Clearwater Wind Project was originally estimated to be $692,000 to be split equally between 2020 and 2021. An updated forecast received from NorthWestern Energy on June 1, 2020, outlined an overall project decrease (from $692,000 to $570,000) along with a timing adjustment between 2020 and 2021 (2020 - $110,000; 2021 - $460,000).

1.1 What is the current or potential problem that is being addressed?
Pursuant to the Agreement and its mandatory compliance requirements with FERC generation
interconnection rules, the Company must fund its applicable ownership share of constructions
costs associated with generation interconnection projects, including the Clearwater Wind
Project.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The applicable driver for the Company’s construction investment in FERC jurisdictional
generation interconnection projects Mandatory & Compliance.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Failure by the Company to provide construction funding for this project would be: (i) an act of
default under Section 25 of the Agreement, (ii) an act of default under the LGIA, and (iii) a
violation of FERC rules pursuant to which the Company could incur compliance penalties of up
to $1 million per day. The Clearwater Wind Project is currently planned for completion in 2021
but, depending upon action or inaction by the developer under the LGIA, the project and related
funding may be delayed.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Appendix B to the LGIA incorporates construction milestones for the project.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
Clearwater Wind Project #234 Feasibility Study Report (NWE)
Clearwater Wind Project #234 System Impact Study Report (NWE)
Clearwater Wind Project #234 Facilities Study Report (NWE)
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Not applicable

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 104 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 4 of 6

The Company must fund its allocated share of capital improvements under the Colstrip Transmission Agreement, the LGIA and FERC rules.

Option Capital Cost Start Complete
Fund Network Upgrades under LGIA $570,000 01 2020 12 2021
Default on agreements and violate FERC rules N/A N/A N/A

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Not applicable – Mandatory and Compliance driver
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
2020 – Design, engineering and procurement
2021 – Construction
No related O&M reductions are expected with this project
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Capital funding only; no engineering or construction labor impacts to the Company. NWE
performs all construction and administration activities as Transmission Operator under the
Agreement.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Not applicable (only alternative is to not fund as outlined under 1.3 above)
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
NWE, as the Transmission Operator under the Agreement, manages the Colstrip Transmission
System construction program. Investments become used and useful and are placed in service
following construction completion and energization.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Business Case investment upholds the Company’s Code of Conduct and is consistent with its
lasting values. Such investment complies with applicable contract obligations and FERC rules.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 105 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 5 of 6
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
Capital investment under this Business Case is mandatory – required by contract and FERC
rules. As outlined in 1.3 above, failure by the Company to provide construction funding for this
project would be: (i) an act of default under Section 25 of the Agreement, (ii) an act of default
under the LGIA, and (iii) a violation of FERC rules pursuant to which the Company could incur
compliance penalties of up to $1 million per day.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Counterparties to the Colstrip Transmission Agreement, joint owners of the Colstrip
Transmission System, and joint parties to the LGIA – NorthWestern Energy, PacifiCorp,
Portland General Electric and Puget Sound Energy
LGIA Counterparty – Clearwater Energy Resources, LLC
Bonneville Power Administration – Transmission entity interconnecting with the Colstrip
Transmission System at the point of change of ownership near Townsend, MT
2.8.2 Identify any related Business Cases
Colstrip Transmission

3.1 Steering Committee or Advisory Group Information
The Colstrip Transmission Committee, of which the Company is a member, meets periodically
to review construction funding associated with the Colstrip Transmission System, including
generation interconnection projects. The Company’s Transmission Services department
administers the LGIA.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Pursuant to Section 22 of the Agreement, the Colstrip Transmission Committee is established
to facilitate cooperation, interchange of information and efficient management of the Colstrip
Transmission System. The Colstrip Transmission Committee consists of five members, each
designated by one of the parties to the Agreement. Each committee member has the right to
vote their party’s ownership share in the Colstrip Transmission System. The Company’s
Transmission Services department participates on the Colstrip Transmission Committee and
administers the LGIA.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Such items are reviewed by the Colstrip Transmission Committee and documented by NWE
as the Transmission Operator under the Agreement.

The undersigned acknowledge they have reviewed the Clearwater Wind Generation
Interconnection Business Case and agree with the approach it presents. Significant
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 106 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 6 of 6
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Jeff Schlect
Title: Senior Manager, FERC Policy and
Transmission Services

Role: Business Case Owner

Signature: Date:
Print Name: Mike Magruder
Title: Director, Transmission Operations
and System Planning

Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 107 of 422
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 7 of 7
The undersigned acknowledge they have reviewed the Clearwater Wind Generation
Interconnection Business Case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Signature:Date:
Print Name:Jeff Schlect
Title:Senior Manager, FERC Policy and
Transmission Services
Role:Business Case Owner
Signature:Date:
Print Name:Mike Magruder
Title:Director, Transmission Operations
and System Planning
Role:Business Case Sponsor
Signature:Date:
Print Name:
Title:
Role:Steering/Advisory Committee Review
Template Version:05/28/2020
Jeff Schlect Digitally signed by Jeff Schlect
Date: 2020.07.30 17:30:45 -07'00'7/30/2020
Michael A. Magruder Digitally signed by Michael A.
Magruder
Date: 2020.07.31 12:22:28 -07'00'7/31/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 108 of 422
EXECUTIVE SUMMARY
Avista is a joint owner in the 500kV Colstrip Transmission System and party to the Colstrip Project
Transmission Agreement (“Agreement”). Avista and the joint owners are obligated to fund their respective
shares of the Colstrip Transmission System construction and maintenance budgets, as approved by the
Colstrip Transmission Committee, which consists of representatives of each of the parties to the Agreement.
The Colstrip Transmission Committee reviews and approves, on an annual basis, the capital and O&M
expense program proposed by NorthWestern Energy (“NWE”) (the designated Transmission Operator under
the Agreement). Pursuant to Section 22 of the Agreement, Avista provides annual input to, and approval for,
the Colstrip Transmission System capital and O&M expense program commensurate with its ownership
shares in the Colstrip Transmission System.1 Failure to fund Colstrip Transmission expenditures would be a
breach of the Company’s obligations under the Agreement.

In conjunction with the Company’s ownership interest in Colstrip Project Units 3 and 4, the Colstrip
Transmission System has benefited the Company’s retail native load customers since the early 1980’s. To
continue to reliably integrate the Company’s Colstrip Project resources to native load and to meet applicable
NERC transmission planning and operational reliability standards, the Colstrip Transmission System must
be maintained. Examples of recent and pending capital expenditures in the Colstrip Transmission System
include end-of-life replacement of 500kV power circuit breakers at the Colstrip 500/230kV Station and 500kV
structure relocation to mitigate erosion risk caused by high runoff in the Little Big Horn River. At such time
as the Company may no longer attain output from Colstrip Project Units 3 and 4, the Company’s ownership
in the Colstrip Transmission System may facilitate access to new resource acquisition opportunities in the
state of Montana.

Colstrip Transmission program capital expenditures have averaged $350,000 over the ten-year period from
2012-2021. Each year NWE develops a five-year capital plan for necessary capital improvements, renewals
and replacements for the Colstrip Transmission System; future program requirements are expected to remain
roughly commensurate with past expenditures. The original Business Case was submitted and approved in
April, 2017. Applicable service code and jurisdiction are 098-ED, common system-wide, electric direct.

VERSION HISTORY
Version Author Description Date Notes
2.0 Jeff Schlect Initial narrative drafted from pre-existing
approved case 7/28/2020 Existing approved case
2.1 Jeff Schlect Business Case refresh 5/26/2022 Various updates

1 Avista owns a 10.2% share in the Colstrip-Broadview segment and a 12.1% share in the Broadview-
Townsend segment.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 109 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
As part of the construction and integration of Colstrip Units 3 and 4 in the early 1980s for the benefit of
the Company’s native load retail customers, the Colstrip project participants constructed the Colstrip
Transmission System, approximately 250 miles of double circuit 500kV transmission facilities
extending from the Colstrip Project westward to the Broadview 500kV Substation and the Townsend
point of interconnection between the Colstrip Transmission System and the Bonneville Power
Administration’s Eastern Intertie 500kV facilities.

Avista owns a 15% share of Colstrip Units 3 and 4 (approximately 225MW). Reliable operation of the
Colstrip Transmission System is necessary to transfer Colstrip output to the respective systems of
each joint project owner, including Avista (other project owners are: NorthWestern Energy, PacifiCorp,
Portland General Electric and Puget Sound Energy). Avista and the other joint project owners are
party to the Colstrip Project Transmission Agreement which, among other things, obligates Avista to
fund its commensurate share of all construction and maintenance expenses for the ongoing operation,
maintenance, renewal and replacement of the jointly owned Colstrip Transmission System facilities.

Requested Spend Amount $724,000 (2021)
Requested Spend Time Period Ongoing Annual Program
Requesting Organization/Department Energy Delivery / Transmission Services
Business Case Owner | Sponsor Jeff Schlect | Heather Rosentrater / Mike Magruder
Sponsor Organization/Department Energy Delivery / Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 110 of 422
Examples of recent expenditures in the Colstrip Transmission System are noted in Section 2.2 below.
As NERC transmission planning and operational reliability standards2 evolve, compliance with both
operational and planning standards may require replacement of, or upgrades to, Colstrip Transmission
System facilities.
1.1 What is the current or potential problem that is being addressed?
Pursuant to the Agreement, the Company must fund its applicable ownership share of capital
improvements to the jointly owned Colstrip Transmission System.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The Company’s capital investment in the Colstrip Transmission System is driven by its
contractual obligations under the Agreement (Mandatory & Compliance). Related drivers
include Asset Condition and Failed Plant & Operations.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Failure to fund its allocated share of costs under the Agreement will put the Company into default
and would eliminate the Company’s right to use the Colstrip Transmission System to integrate
its resources for service to its bundled retail native load customers.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Not applicable
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
Not applicable
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Not applicable

The Company must fund its allocated share of capital improvements under the Colstrip Transmission
Agreement.
Option Capital Cost Start Complete
2 Among its other provisions, the U.S. Energy Policy Act of 2005 provided for the establishment of mandatory
reliability standards and authorized the Federal Energy Regulatory Commission (FERC) to assess penalties of
up to $1 million per day per violation for non-compliance with these standards and other FERC regulations.
FERC has certified the North American Electric Reliability Organization (NERC) to establish and enforce these
reliability standards. The Company has a statutory obligation to plan, improve, upgrade, and operate its
transmission system, including the Colstrip Transmission System, to maintain compliance with these standards
and is required to self-certify its compliance with these standards on an annual basis.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 111 of 422
Fund capital program under the Agreement $516,000 1981 Ongoing
Do not fund – Contract default Undetermined --- ---

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Additional Information – In addition to upholding the Company’s contractual obligations and
maintaining the ability to integrate its Colstrip generation output for service to its bundled retail
native load customers, Colstrip Transmission program funding also provides the Company a
future transmission alternative for consideration under the Company’s Integrated Resource
Planning process, to integrate potential renewable resources located in Montana.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Capital amounts are used for improvements, renewals and replacements of Colstrip
Transmission System assets. Examples of recent expenditures in the Colstrip Transmission
System include:
• End-of-life replacement of 500kV equipment at the Colstrip 500/230kV Substation
• Broadview 500kV Series Capacity replacements
• Construction of optical ground wire (OPGW) communication facilities between Broadview
and Colstrip to meet dual communication path requirements under North American Electric
Reliability Corporation (NERC) standards
• Microwave communications and 500kV relay replacements
• Hardware, software and operating system upgrades to maintain compliance with applicable
operating standards
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Capital funding only; no engineering or construction labor impacts to the Company. NWE
performs all construction and construction administration activities as Transmission Operator
under the Agreement.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Not applicable (only alternative is to not fund and default on contract)
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
NWE, as the Transmission Operator under the Agreement, manages the Colstrip Transmission
System construction program. Program investments, as improvements, renewals and
replacements for the existing Colstrip Transmission System, become used and useful each year
upon being placed in-service.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 112 of 422
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Program investment upholds the Company’s Code of Conduct and is consistent with its lasting
values. Colstrip Transmission System investment maintains the Company’s ability to integrate
its Colstrip generation assets for service to bundled retail native load customers and provides
the Company with a future transmission alternative to integrate potential renewable resources
located in Montana.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
Capital investment under the program is mandatory – required by contract – pursuant to the
Agreement. The Company’s ongoing ownership in the Colstrip Transmission System may be
evaluated consistent with its assessment of potential future resource acquisitions in Montana
under the Company’s Integrated Resource Planning activities.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Avista Power Supply – Internal customer for the integration of resources designated for
service to bundled retail native load customers
Counterparties to the Colstrip Transmission Agreement and joint owners of the Colstrip
Transmission System – NorthWestern Energy, PacifiCorp, Portland General Electric and
Puget Sound Energy
Bonneville Power Administration – Transmission entity interconnecting with the Colstrip
Transmission System at the point of change of ownership near Townsend, MT
2.8.2 Identify any related Business Cases
Clearwater Wind Generation Integration

3.1 Steering Committee or Advisory Group Information
Pursuant to Section 22 of the Agreement, Avista provides annual input to, and approval for, the
Colstrip Transmission System capital and O&M expense program commensurate with its
ownership shares in the Colstrip Transmission System. The Colstrip Transmission Committee,
of which the Company is a member, meets periodically to review, and provide recommendations
for, the annual capital program administered by NWE. The Colstrip Transmission Committee
provides approval for each year’s capital program.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 113 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
Pursuant to Section 22 of the Agreement, the Colstrip Transmission Committee is established
to facilitate cooperation, interchange of information and efficient management of the Colstrip
Transmission System. The Colstrip Transmission Committee consists of five members, each
designated by one of the parties to the Agreement. Each committee member has the right to
vote their party’s ownership share in the Colstrip Transmission System. Section 22(f) of the
Agreement outlines all matters that shall be submitted to the committee by NWE for approval,
including Colstrip Transmission System construction and operating budgets.
With respect to long-term continuing ownership and participation in the Colstrip Transmission
System, the Company’s Power Supply and Transmission Services groups will, under the
Company’s Integrated Resource Planning process, analyze and assess such costs and benefits
related to the integration of potential renewable resources located in Montana.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Such items are reviewed by the Colstrip Transmission Committee and documented by NWE
as the Transmission Operator under the Agreement.
The undersigned acknowledge they have reviewed the Colstrip Transmission
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Jeff Schlect
Title: Senior Manager, FERC Policy and
Transmission Services

Role: Business Case Owner

Signature: Date:
Print Name: Mike Magruder
Title: Director, Transmission Operations
and System Planning

Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 114 of 422

Template Version: 05/28/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 115 of 422
EXECUTIVE SUMMARY The Company must provide for the interconnection of new generation resources with its Transmission System under the terms and conditions of its Open Access Transmission Tariff (“Tariff”) under the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). In compliance with federal statute, the terms and conditions of the Tariff, and FERC rules and regulations, the Company must study, design and construct the necessary facilities (“Network Upgrades”) to provide Interconnection Service to all eligible generation projects, regardless of whether such generation is intended to serve bundled retail native load customers of Avista or any third-party load. All aspects of the generation interconnection process, including application, studies, evaluation of new or upgraded facilities, construction of new or upgraded facilities, cost allocation of new or upgraded facilities, and repayment of advanced amounts are prescribed by the Tariff and FERC rules and regulations. This Business Case provides for the ongoing capital funds required to study, design and construct Network Upgrades, including repayment and capitalization of any advanced amounts, that are required to provide Interconnection Service in compliance with the Tariff and all other applicable FERC rules and regulations.

VERSION HISTORY
Version Author Description Date Notes 1.0 Jeff Schlect Initial justification narrative 3/23/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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GENERAL INFORMATION

1. BUSINESS PROBLEM
In compliance with federal statute, the terms and conditions of the Tariff, and FERC rules and regulations, the Company must design and construct new or upgraded transmission facilities to provide for the reliable interconnection of new generation projects. Upon completion of a FERC-prescribed study process, the Company must tender a standard form of Small Generator Interconnection Agreement (“SGIA”) (for projects less than or equal to 20MW in capacity) or Large Generator Interconnection Agreement (“LGIA”) (for projects greater than 20MW in capacity) to the generation project developer (“Interconnection Customer”). Consistent with the study process and FERC’s cost allocation principles, the SGIA or LGIA must specify the Network Upgrades associated with each generation project. Network Upgrades are those new or upgraded facilities that must be funded by the Company. See attached documentation providing justification and documentation of FERC rules and requirements regarding the funding of Network Upgrades associated with generation interconnection projects: Business Case Justification – Generation Interconnection Attachment A.
1.1 What is the current or potential problem that is being addressed?
Pursuant to the Company’s mandatory federal compliance requirements under the Tariff and
applicable FERC rules and regulations, the Company must fund the design and construction of
new and/or upgraded transmission facilities to provide generation interconnection service under
the Tariff.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The applicable driver for the Company’s construction investment in FERC jurisdictional
generation interconnection projects is Mandatory & Compliance.

Requested Spend Amount Determined on a yearly basis
Requested Spend Time Period Ongoing
Requesting Organization/Department Energy Delivery / Transmission Services
Business Case Owner | Sponsor Jeff Schlect | Heather Rosentrater / Mike Magruder
Sponsor Organization/Department Energy Delivery / Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 117 of 422
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Failure by the Company to provide design and construction funding for these projects would be:
(i) an act of default under the applicable Small Generator Interconnection Agreement (“SGIA”)
or Large Generator Interconnection Agreement (“LGIA”) for each project, and (ii) a violation of
the Tariff and FERC rules and regulations pursuant to which the Company could incur
compliance penalties of up to $1 million per day. Failure to provide design and construction
funding for these projects would be inconsistent with the Ethical Decision Making policy under
the Company’s Code of Conduct.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Attachment 4 to each SGIA and Appendix B to each LGIA outline the required construction
milestones for each project.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
Each generation interconnection project must be studied consistent with the generation
interconnection procedures under the Tariff. The applicable study reports must be made
available to the Interconnection Customer and any other Eligible Customer under the
Tariff who requests the study.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Not applicable

The Company must fund Network Upgrades associated with generation interconnection projects in compliance with the Tariff, the applicable SGIA or LGIA, and FERC rules and regulations.
Consistent with FERC rules and regulations regarding the funding of Network Upgrades, the Company may elect to fund all such costs up front or may require the Interconnection Customer to provide initial advanced funding for Network Upgrades, for which the Company must provide repayment (or Transmission Service credits) to the Interconnection Customer over a specified period of time not to exceed twenty years after the generating facility commences commercial operation. All repayment or Transmission Service credits must include FERC interest. While the Company must ultimately fund all Network Upgrades, the Company is able to manage its overall capital obligations, and correlating transfers to plant, under this Business Case over a period of time following the commercial operation date, to be set forth in either the SGIA, LGIA, or a separate Network Upgrades funding and repayment agreement. The Company’s election to require the Interconnection Customer to provide advanced funding of Network Upgrades is outlined in Business Case Justification – Generation Interconnection Attachment B.
Determination of repayment schedule, and resulting capital additions, will be made in consultation with the Company’s Financial Analysis, Treasury and Accounting groups. Annual amounts requested under this Business Case will reflect both committed and planned capital funding consistent with such collaborative determination.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 118 of 422
Option Capital Cost Start Complete
Fund Network Upgrades under SGIA or LGIA Determined Yearly 06 2022 Ongoing
Default on agreements and violate FERC rules N/A N/A N/A
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Not applicable – Mandatory and Compliance driver
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative) (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This is an ongoing program to accommodate the capital requirements associated with
generation interconnection projects. Requested capital amounts will cover the cost of design
and construction of required Network Upgrades for each project. Actual yearly capital amounts
will be determined by project requirements and repayment obligations of CIAC amounts initially
funded by project developers.
No related O&M reductions are expected with these projects.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Company Engineering and construction labor resources may be impacted. Project impacts and
scheduling are coordinated through the Company’s Engineering Roundtable group.
Transmission Services must coordinate with Company Financial Analysis, Treasury and
Accounting groups to determine timing of CIAC repayments to developer and resulting transfers
to capital.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
See 1.3 above
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Ongoing program year-to-year dependent upon project status and CIAC repayment
requirements.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Business Case investment upholds the Company’s Ethical Decision Making policy under the
Code of Conduct. Investment complies with applicable SGIA and LGIA contract obligations, the
Tariff, and FERC rules and regulations. Timing of repayments to Interconnection Customers
(with associated transfers to capital) provides the Company with some flexibility in the planning
of its capital funding requirements.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 119 of 422
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
Capital investment under this Business Case is mandatory – required by contract and FERC
rules and regulations. As outlined in 1.3 above, failure by the Company to provide design and
construction funding of generation interconnection Network Upgrades would be: (i) an act of
default under the applicable SGIA or LGIA for each project, and (ii) a violation of the Tariff and
FERC rules and regulations pursuant to which the Company could incur compliance penalties
of up to $1 million per day.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Customers: SGIA and LGIA Counterparties (generation project developers)
Transmission Customers (purchasers of generation output)
Avista Financial Analysis, Treasury and Accounting Groups: Coordination to determine
timing of CIAC repayments and resulting transfers to capital
2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
Not applicable
3.2 Provide and discuss the governance processes and people that will
provide oversight
Design and construction scheduling are coordinated through the Engineering Roundtable.
Capital funding is coordinated with the Financial Analysis, Treasury and Accounting groups with
final determinations made through the Capital Planning Group. The Company’s Transmission
Services group administers all SGIAs and LGIAs. The Company’s Substation Project Delivery
group provides project management services for all major generation interconnection projects.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Transmission Services coordinates with Substation Project Delivery staff to determine the need
for any adjustments to project capital. Project milestones, scope, and cost changes are
documented through administration of the applicable SGIA or LGIA with each Interconnection
Customer. All material adjustments will be managed through in-year change requests submitted
to the Capital Planning Group.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 120 of 422
The undersigned acknowledge they have reviewed the Generation Interconnection
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Date:
Jeff Schlect
Senior Manager, FERC Policy and
Transmission Services

Business Case Owner

Date:
Mike Magruder
Director
and System Planning

Business Case Sponsor

Date:

Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 121 of 422

ATTACHMENT A
BUSINESS CASE JUSTIFICATION – GENERATION INTERCONNECTION
SUPPLEMENTAL JUSTIFICATION AND BACKGROUND

A. FERC Transmission Pricing Policy for Generation Interconnections The Federal Energy Regulatory Commission (“FERC”) codified its cost allocation treatment of transmission system upgrades associated with generator interconnection in Order No. 2003, issued July 24, 2003. In its order, which also included its required form of Standard Large Generator Interconnection Agreement, FERC defined two types of facilities associated with generation interconnection that are to be owned and operated by the Transmission Provider: Transmission Provider Interconnection Facilities and Network Upgrades. Transmission Provider
Interconnection Facilities are limited to only those facilities between the point of change of
ownership with the Interconnection Customer’s facilities and the Point of Interconnection. Such facilities must be used solely by the Interconnection Customer and may not include any facilities that may be deemed Network Upgrades. Network Upgrades consist of all new or upgraded facilities that are “required at or beyond the point at which the Interconnection Facilities connect to the Transmission Provider’s Transmission System [emphasis added].” Interconnection Facilities may be directly assigned to the Interconnection Customer while Network Upgrades may not.
FERC’s affirmation of its interconnection facilities pricing policy is outlined in the introduction to
Order No. 2003:
The Commission’s interconnection cases have drawn the distinction between Interconnection Facilities and Network Upgrades. Interconnection Facilities are found between the Interconnection Customer’s Generating Facility and the Transmission Provider’s Transmission System. The Commission has developed a simple test for
distinguishing Interconnection Facilities from Network Upgrades: Network Upgrades
include only facilities at or beyond the point where the Interconnection Customer's Generating Facility interconnects to the Transmission Provider's Transmission System… Most improvements to the Transmission System, including Network Upgrades, benefit all transmission customers, but the determination of who benefits from such Network Upgrades is often made by a non-independent transmission provider, who is an interested party. In such cases, the Commission has found that it is just and reasonable for the Interconnection Customer to pay for Interconnection Facilities but not for Network Upgrades [Order No. 2003, ¶ 21].

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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Similarly, in Order No. 2003-A (issued March 5, 2004) FERC re-affirmed its cost allocation treatment (or “pricing policy”) for generation interconnections [see Order No. 2003-A, ¶ 579-590] and its legal justification therefore [see Order No. 2003-A, ¶ 591-602].
…we do not believe that the costs of Network Upgrades required to interconnect a Generating Facility to the Transmission System of a non-independent Transmission Provider are properly allocable to the Interconnection Customer through direct assignment because upgrades to the transmission grid benefit all customers… [Order No. 2003-A, ¶ 599]
Illustrative Example of FERC Transmission Pricing Policy for Generation Interconnections
Per FERC policy any facilities beyond the point of interconnection are Network Upgrades. The point of interconnection for the example generation project is its line interconnection bay at the Neilson Station. Neilson is a three bay, ring-bus configuration station, therefore the example
generation project is allocated one-third of the overall station cost (see facilities in yellow). The remaining two-thirds of the station and all upgraded facilities beyond (see facilities in red) are Network Upgrades. FERC asserts that all Network Upgrades benefit all transmission customers, including a Transmission Provider’s native load retail customers. Interconnection Customer Interconnection Facilities are the sole cost and responsibility of the generation project developer.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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B. Background Q & A Regarding FERC Compliance Requirements 1. Please explain the differences between “Network Resource” and “Energy Resource” Interconnection Service and explain why it was selected as such, and further what were the implications to Avista given the selection.
All non-PURPA generation interconnection projects must be processed pursuant to the
Company’s Open Access Transmission Tariff (“Tariff”) and applicable FERC rules and practices. The difference between Network Resource Interconnection Service (“NRIS”) and Energy Resource Interconnection Service (“ERIS”) is subtle.1 Both NRIS and ERIS must be studied such that the interconnected resource can be operated at full output. Beyond this commonality, FERC outlines the difference between NRIS and ERIS in its Order 2003 as follows:
FERC Order 2003 – Paragraphs 753-754 As proposed, Energy Resource Interconnection Service would allow the Interconnection Customer to connect its Generating Facility to the Transmission System and be eligible to deliver its output using the existing firm or non-firm capacity of the Transmission System on an "as available" basis… The Interconnection Studies to be performed for Energy Resource Interconnection Service would identify the Interconnection Facilities required as well as the Network Upgrades needed to allow the proposed Generating Facility to operate at full output [emphasis added]. In contrast, Network Resource Interconnection Service would require the Transmission Provider to undertake the Interconnection Studies and Network Upgrades needed to integrate the Generating Facility into the Transmission System in a manner comparable to that in which the Transmission Provider integrates its own generators to serve native load customers.
Additionally, with respect to NRIS: FERC Order 2003 – Paragraph 768 Network Resource Interconnection Service is intended to provide the Interconnection Customer with an interconnection of sufficient quality to allow the Generating Facility to qualify as a designated Network Resource on the Transmission Provider's system without additional Network Upgrades. This means that Network Resource Interconnection Service entitles the Generating Facility to be treated in the same manner as the Transmission Provider's own resources for purposes of assessing whether aggregate supply is sufficient to meet aggregate load within the Transmission Provider's Control Area, or other area customarily used for generation capacity planning. Thus, with Network Resource Interconnection Service, the Interconnection Customer would be eligible to obtain Network Service under the Transmission Provider's OATT… without the need for additional Network Upgrades [emphasis added].
Accordingly, any new transmission facility or upgraded transmission facility that is necessary for the resource to operate reliably at full output must be identified in the generation interconnection study process as Network Upgrades. FERC further outlines the subtle
1 FERC differentiates between NRIS and ERIS only in its Large Generator Interconnection Procedures (i.e. those
greater than 20MW).
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 124 of 422
difference between NRIS and ERIS which, on the Avista system, suggests very little difference between the two types of Interconnection Service: FERC Order 2003 – Paragraph 784 The principal difference between the study requirements for Energy Resource Interconnection Service and Network Resource Interconnection Service is that the study for Network Resource Interconnection Service identifies the Network Upgrades that are needed to allow the Generating Facility to contribute to meeting the overall capacity needs of the Control Area or planning region whereas the study for Energy Resource Interconnection Service does not. The study for Energy Resource Interconnection Service includes short circuit/fault duty, steady state (thermal and voltage) and stability analyses to identify the Network Upgrades needed to allow the output of the Generating Facility to be injected into the Transmission System using capacity on an “as available” basis. By contrast, the study for Network Resource Interconnection Service includes similar analyses but also assumes that the output of the Generating Facility may displace the output of certain other Network Resources on the Transmission System. The study then identifies the Network Upgrades that would be required to allow the Generating Facility to be counted toward system capacity needs in the same manner as the displaced resources.
To date, Avista has never received a request for only ERIS on the Avista Transmission System. 2. Who decides on the type of resource interconnection service?
As noted in (1), the Interconnection Customer requests which type of resource interconnection
service, or both, is/are to be studied. Per Article 4.1 of the FERC pro forma Large Generator
Interconnection Agreement (“LGIA”), the Interconnection Customer ultimately elects either
NRIS or ERIS (see also, FERC Order 2003 – Paragraph 786).

3. Are there any other resource interconnection service types beyond the two listed above?
No, not under FERC jurisdiction.2

4. Who decides, and at what point does the Company as a transmission provider become
obligated to provide transmission to interconnect a new generating resource?
Note: the word “transmission” in this question may refer to either “transmission service” or
“new or upgraded transmission assets.” Responses are provided based upon both meanings.

With respect to providing Transmission Service:
Technically, requests for Interconnection Service and Transmission Service are separate and
distinct. Interconnection Service does not in and of itself convey Transmission Service.
However, because NRIS requires the resource to be studied such that it can be operated as if it
were a Network Resource serving the Company’s native load customers, in many cases, with
respect to the identification of Network Upgrades, the distinction is effectively in letter only,
2 There are no ‘types’ of resource interconnection service for generation interconnections under PURPA.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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not substance. Where the distinction becomes substantive with respect to Network Upgrades
are for those instances where the new resource intends to deliver its output off-system at a
specific point of delivery. If sufficient Available Transfer Capability (“ATC”) to the requested
point of delivery is not available, additional Network Upgrades (beyond those identified in the
Generation Interconnection process), may be necessary to provide the requested Transmission
Service.

With respect to providing new or upgraded transmission assets:
The Company bears no obligation to provide new or upgraded transmission assets (Network
Upgrades or Transmission Provider Interconnection Facilities) in association with a generation
interconnection project until such time as a Large Generator Interconnection Agreement
(“LGIA”) or Small Generator Interconnection Agreement (“SGIA”) is executed. Once an
LGIA or SGIA is in place, both parties bear obligations with respect to project milestones,
construction and financing.

5. Please explain the conditions where the Company as a transmission provider is obligated to upgrade existing transmission to provide interconnection to a new generating resource. The Company is obligated to construct new transmission facilities and/or upgrade existing
transmission facilities if any such facilities are identified as Network Upgrades or
Transmission Provider Interconnection Facilities in the study process for such interconnection. All studies are performed, and Network Upgrades and Transmission Provider Interconnection Facilities identified, consistent with applicable mandatory federal reliability standards established by FERC and the North American Electric Reliability Corporation (“NERC”). The results of all such studies, and their respective Network Upgrades and Transmission Provider
Interconnection Facilities, are outlined in both summary and detailed format in the applicable
study reports associated with each generation interconnection request.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 126 of 422
Generation Interconnection Facilities Allocation Practice
Transmission Provider Interconnection Facilities vs. Network Upgrades
March 22, 2022 – Jeff Schlect and Randy Gnaedinger

Key Factors
- Comply with the Tariff and FERC Rules - Limit retail customer costs - Enable cost effective renewables

Updated Practice
In association with Avista’s work related to Project #60 where the Interconnection Customer (IC) is seeking
an interconnection at the Dry Creek 230kV Station, the Company has reviewed its NU versus TPIF
allocation practices. To comply with FERC rules and regulations as outlined in FERC Order 2003 and to
mitigate as best as possible the potential cost impacts to retail customers, Avista is updating its practice
in how the cost of generation interconnection facilities are allocated between NU and TPIF.

Past Practice
Under the generation interconnection procedures of its Open Access Transmission Tariff (Tariff), Avista
has historically sought to allocate a portion of new or upgraded interconnection station facilities to
generation project developers as direct-assigned facilities, or Transmission Provider Interconnection
Facilities (TPIF). The remainder of these station costs are designated as Network Upgrades (NU) which
must be funded by the Transmission Provider. Avista has reached mutual agreement with its ICs regarding
the allocation of facilities required for interconnection and has typically elected to self-fund the NU
portion. In instances where two breakers were required to reliably integrate the IC’s Project, Avista has
designated one breaker as NU and the other as TPIF. In instances where multiple line terminals are
established in a new interconnection station, a pro rata sharing of the overall station cost was used to
determine the allocation between NU and TPIF.

Compliance with FERC Regulations
The language of Order 2003 explicitly defines Network Upgrades to “include only facilities at or beyond
the point where the Interconnection Customer’s Generating Facility interconnects to the Transmission
Provider’s Transmission System.”1 Accordingly, it is apparent that only those facilities connecting the
Generating Facility to the Transmission System that are radial in nature can be designated as TPIF.
Specifically, for generation interconnection stations with either ring bus or double-breaker double-bus
configurations, all breaker positions are to be designated as NU. Avista’s Updated Practice is necessary
to be in compliance with FERC regulations. FERC has gone so far as to emphasize that any agreements
between an Interconnection Customer and Transmission Provider that have classified Network Upgrade
facilities as Interconnection Facilities have not been found to be just and reasonable and have been
rejected by the Commission.2

1 FERC Order 3003, paragraph 21.
2 Id.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 127 of 422
Impact Upon Retail Customers – Summary
While the Updated Practice is necessary to be in compliance with FERC rules, Avista also assessed the
Updated Practice’s impact upon retail customers using Project #60 as a case study. While the Updated
Practice may not always produce the maximum benefit to retail customers, it is clear that the Updated
Practice will in nearly all cases accrue positive benefits to retail customers and, in most cases, would
accrue greater benefits to retail customers than the Past Practice.
• Primary driver is to focus on achieving the lowest energy rates for our retail customers
• This can be achieved by either of the following:
(i) Obtaining the lowest energy cost possible (i.e. lower PPA pricing), or
(ii) Attaining wheeling revenue that offsets required transmission plant investment
• Allocating transmission upgrades as TPIF to a developer results in a higher PPA price
• A higher PPA price due to transmission upgrades being allocated as TPIF limits the potential of a
project to be sold to a third-party, thereby reducing the likelihood of Avista retail customers
benefiting from wheeling revenue
• By allocating the majority of the upgrades as Network Upgrades, Avista may exercise an additional
opportunity to have the developer front those costs, which affords capital flexibility as Avista
repays those funds over a 5-20 year period
• As Network Upgrades, the highest possible level of transmission costs are allocated to third-party
wholesale transmission customers
• Updated Practice option (b) facilitates benefits to Avista’s retail customers in five ways:
(i) lower PPA pricing
(ii) increasing the chance of an off-system wheel due to lower PPA pricing
(iii) lower initial capital investment
(iv) flexible timing for capital repayment
(v) third-party transmission customers are allocated ~20% of network upgrades

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 128 of 422
Impact Upon Retail Customers – Project #60 as a Case Study
When applying the Updated Practice to Project #60, it is apparent that this approach is in the best interest
of Avista’s retail customers. Were a third party to ultimately purchase the output of Project #60, both
practices provide a benefit to Avista’s retail customers. In the event Avista is the ultimate purchaser,
however, Past Practice would result in approximately 70% greater cost being allocated to Avista’s retail
customers. Since the cost to wheel a renewable resource off-system represents an approximately 40%-
45% adder to current long-term resource costs, it is expected that Avista would likely be the purchaser of
an on-system project such as Project #60, at least over a near term planning horizon of approximately ten
years. Additionally, considering that Avista’s retail customers are expected to most benefit when an IC
finds a non-Avista buyer and purchases transmission service from Avista, Updated Practice options (a) and
(b) would facilitate a lower PPA price, thereby making an off-system sale of a renewable resource more
likely. These considerations point to the Updated Practice as being in the best interest of Avista’s retail
customers. Of the two alternatives available for the Updated Practice, having the IC provide initial up-
front funding of the NU is expected to provide a lower long-term cost to retail customers and greater
capital funding flexibility.

Project #60 Details
- Total cost of the Dry Creek 230kV generation interconnection project is approximately $3.8 million.
- It is generally understood that any costs attributed to an IC as TPIF will be reflected in, and recovered
through, the IC’s power sales agreement with its off-taker.
- Annualized cost of capital investment to Avista retail customer is understood to be approximately 11%
- It is estimated that, for purposes of allocating the capital cost of NU transmission assets,
approximately 20% of such costs are allocated to Avista’s wholesale transmission customers through
transmission rates, while approximately 80% of such costs are allocated to Avista’s native load
customers through retail rates.
- Annual wheeling revenue for a non-PacifiCorp third-party off-taker would be approximately $3.6
million.
- Annual wheeling revenue in the event PacifiCorp is the off-taker is expected to be approximately
$330,000 3.
- Solar projects with a 20% capacity factor must spread transmission costs over 1/5 of all hours
($3.6 million) / (150 MW * 20% * 8760 hrs) = a $13.70/MWh adder for transmission service.

Past Practice – Single TPIF Breaker
This approach allocates the first breaker and metering facilities to the IC as TPIF and the second breaker
is allocated to Avista as a Network Upgrade. This option is understood to be inconsistent with FERC policy.
This allocation results in a 79%/21% split of the TPIF/NU facilities where the IC would fund $3 million in
TPIF and Avista would fund $800,000 in Network Upgrades.
- Annualized cost allocated to Avista retail customers if Avista purchases output - $400,400
- Annualized cost allocated to Avista retail customers if third party purchases output - $70,400
(offset by $3.6 million annually in wheeling revenue)
- Annualized cost allocated to Avista retail customers if PacifiCorp purchases output - $70,400
(offset by ~$330,000 annually in wheeling revenue)
3 Expected use-of-facilities (UOF) arrangement for Dry Creek 230kV facilities is presumed to, at a minimum, recover
annualized capital costs (i.e. 11% of $3 million, or $330,000).
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 129 of 422

Updated Practice – Designate Both Breakers as Network Upgrades
This approach is understood to be in compliance with FERC policy. Line termination and metering
structures would remain as TPIF. This allocation results in a 29%/61% split of TIPF/NU facilities where the
IC would fund $1,100,000 in TPIF and Avista would fund $2.7 million in Network Upgrades.

Updated Practice Option (a) – Avista Funds all Network Upgrades: Avista can elect to self-fund the
Network Upgrades. Costs will be incorporated into both Avista’s state retail and federal transmission
rates at time of next rate filing.
- Annualized cost allocated to Avista retail customers if Avista purchases output - $237,600
- Costs allocated to Avista retail customers if third party purchases output - $237,600
(offset by $3.6 million annually in wheeling revenue)
- Costs allocated to Avista retail customers if PacifiCorp purchases output - $237,600
(offset by ~$330,000 annually in wheeling revenue)

Updated Practice Option (b) – IC Provides Initial Funding – Avista Refunds over Time: Avista can elect to
have IC provide up-front funding of the Network Upgrades, resulting in no immediate impact to Avista’s
capital budget or retail rates. Only the carrying costs for the advanced funding would presumably flow
through a power sales agreement. IC-funded Network Upgrade costs must be credited or refunded back
to IC over a period of no more than 20 years (Section 11.4.1 LGIA). Once credited or refunded, these
Network Upgrade costs would be added to Avista’s asset base and included in state retail and federal
transmission rates. Long-term cost allocations under Option (b) are comparable to Option (a), except for
the following considerations:
- Deferred cost allocation to state retail and federal transmission customers
- Cost of money (i.e. FERC interest rate) is expected to be less than Avista’s carrying cost of capital,
resulting in overall lower costs allocated to both retail and transmission customers

This Updated Practice has been presented to and acknowledged by the Financial Planning and Analysis, Plant Accounting, and
Rates groups, the Assistant Treasurer, and the Senior Vice President, Energy Delivery.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 130 of 422
References

FERC Order 2003 – Paragraphs 21-22 (abridged, footnotes omitted)
Interconnection Facilities are found between the Interconnection Customer’s Generating Facility and the
Transmission Provider’s Transmission System. The Commission has developed a simple test for
distinguishing Interconnection Facilities from Network Upgrades: Network Upgrades include only facilities
at or beyond the point where the Interconnection Customer’s Generating Facility interconnects to the
Transmission Provider’s Transmission System. The Commission has made clear that Interconnection
Agreements are evaluated by the Commission according to the just and reasonable standard. Most
improvements to the Transmission System, including Network Upgrades, benefit all transmission
customers, but the determination of who benefits from such Network Upgrades is often made by a non-
independent transmission provider, who is an interested party. In such cases, the Commission has found
that it is just and reasonable for the Interconnection Customer to pay for Interconnection Facilities but
not for Network Upgrades. Agreements between the Parties to classify Interconnection Facilities as
Network Upgrades, or to otherwise directly assign the costs of Network Upgrades to the Interconnection
Customer, have not been found to be just and reasonable and have been rejected by the Commission.

Regarding pricing for a non-independent Transmission Provider, the distinction between Interconnection
Facilities and Network Upgrades is important because Interconnection Facilities will be paid for solely by
the Interconnection Customer, and while Network Upgrades will be funded initially by the Interconnection
Customer (unless the Transmission Provider elects to fund them), the Interconnection Customer would
then be entitled to a cash equivalent refund (i.e., credit) equal to the total amount paid for the Network
Upgrades, including any tax gross-up or other tax-related payments. The refund would be paid to the
Interconnection Customer on a dollar-for-dollar basis, as credits against the Interconnection Customer’s
payments for transmission services, with the full amount to be refunded, with interest within five years
of the Commercial Operation Date (emphases added).

FERC Order 2003 – Paragraph 694
The Commission recognizes that its policy of requiring refunds to be paid to an Interconnection Customer
for the cost of Network Upgrades constructed on its behalf is a controversial one. However, the
Commission instituted this policy to achieve a number of important goals. First, consistent with the
Commission’s long-held policy of prohibiting “and” pricing4 for transmission service, the crediting policy
ensures that the Interconnection Customer will not be charged twice for the use of the Transmission
System. The Commission determined that it is appropriate for the Interconnection Customer to pay
initially the full cost of Interconnection Facilities and Network Upgrades that would not be needed but for
the interconnection, but once the Generating Facility commences operation and delivery service begins,
it must receive transmission service credits for the cost of the Network Upgrades. This ensures that the
Interconnection Customer will not ultimately have to pay both incremental costs and an average
embedded cost rate for the use of the Transmission System. Second, the Commission's crediting policy
helps to ensure that the Interconnection Customer’s interconnection is treated comparably to the
4 When a Transmission Provider must construct Network Upgrades to provide new or expanded transmission service,
the Commission generally allows the Transmission Provider to charge the higher of the embedded costs of the
Transmission System with expansion costs rolled in, or incremental expansion costs, but not the sum of the two.
Hence, “and” pricing is not permitted.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 131 of 422
interconnections that a non-independent Transmission Provider completes for its own Generating
Facilities. The Transmission Provider has traditionally rolled into its transmission rates the cost of Network
Upgrades required for its own interconnections, and the Commission's crediting policy ensures that
Network Upgrades constructed for others are treated the same way. Finally, the policy is intended to
enhance competition in bulk power markets by promoting the construction of new generation,
particularly in areas where entry barriers due to unduly discriminatory transmission practices may still be
significant. The policy is therefore consistent with the Commission's long-held view that competitive
wholesale markets provide the best means by which to meet its statutory responsibility to assure
adequate and reliable supplies of electric energy at just and reasonable prices.5

Avista Tariff – LGIA 11.4 Transmission Credits.
11.4.1 Repayment of Amounts Advanced for Network Upgrades. Interconnection Customer shall be
entitled to a cash repayment, equal to the total amount paid to Transmission Provider and Affected
System Operator, if any, for the Network Upgrades, including any tax gross-up or other tax-related
payments associated with Network Upgrades, and not refunded to Interconnection Customer pursuant
to Article 5.17.8 or otherwise, to be paid to Interconnection Customer on a dollar-for-dollar basis for the
non-usage sensitive portion of transmission charges, as payments are made under Transmission Provider's
Tariff and Affected System's Tariff for transmission services with respect to the Large Generating Facility.
Any repayment shall include interest calculated in accordance with the methodology set forth in FERC’s
regulations at 18 C.F.R. § 35.19a(a)(2)(iii) from the date of any payment for Network Upgrades through
the date on which the Interconnection Customer receives a repayment of such payment pursuant to this
subparagraph. Interconnection Customer may assign such repayment rights to any person.

Notwithstanding the foregoing, Interconnection Customer, Transmission Provider, and Affected
System Operator may adopt any alternative payment schedule that is mutually agreeable so long as
Transmission Provider and Affected System Operator take one of the following actions no later than
five years from the Commercial Operation Date: (1) return to Interconnection Customer any amounts
advanced for Network Upgrades not previously repaid, or (2) declare in writing that Transmission
Provider or Affected System Operator will continue to provide payments to Interconnection
Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, or
develop an alternative schedule that is mutually agreeable and provides for the return of all amounts
advanced for Network Upgrades not previously repaid; however, full reimbursement shall not extend
beyond twenty (20) years from the Commercial Operation Date.

5 The Commission’s crediting policy has also withstood judicial review. In an opinion issued February 18, 2003, the
D.C. Circuit Court of Appeals affirmed Commission orders requiring a Transmission Provider to provide credits to
Interconnection Customers for the cost of short-circuit and stability Network Upgrades. Entergy Services, Inc. v. FERC, 319 F.3d 536 (D.C. Cir. 2003). The court stated that “[t]he Commission’s rationale for crediting network
upgrades, based on a less cramped view of what constitutes a ‘benefit,’ reflects its policy determination that a
competitive transmission system, with barriers to entry removed or reduced, is in the public interest.” Id. at 543-44.
The court concluded that “the Commission has reasonably explained that its crediting pricing policy avoids both gold
plating and less favorable price signals such that the enlarged transmission system, which it views as a public good,
can function reliably and continue to expand.” Id. at 544
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 132 of 422
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) a synopsis of
the problem, 2) the service code and jurisdiction of customers impacted, 3) the recommended solution, 4) the cost of
the solution, 5) how the solution will benefit customers identified, 6) the significance of the timeline and 7) the risks of
not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

NERC reliability standard PRC-002-2 defines the disturbance monitoring and
reporting requirements to have adequate data available to facilitate analysis of Bulk
Electric System (BES) Disturbances. The methodology of Attachment A of the NERC
standard was performed to identify the affected buses within the Avista BES. The
Protection Systems must be capable of recording electrical quantities for each BES
Elements it owns connected to the BES buses identified.
Non-compliance can carry a fine of up to a million dollars per day based on severity.
This business case is important to customers because it allows analysis of system
faults for the BES that can lead to continued stability and reliability of the electric
system.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2016-07
Cost of Solution: $12,000,000

VERSION HISTORY
Version uthor Description Date Notes
1.0 Randy Spacek Initial Version 7/11/2017 Initial Version
2.0 Glenn Madden Revised to remove DRAFT
watermark 5/28/2019
3.0 Karen Kusel /
Glenn Madden Update to 2020 Template 06/2020

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 133 of 422
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 2 of 6
GENERAL INFORMATION

1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
NERC reliability standard PRC-002-2 defines the disturbance monitoring and reporting
requirements to have adequate data available to facilitate analysis of Bulk Electric
System (BES) Disturbances. The methodology of Attachment A of the NERC standard
was performed to identify the affected buses within the Avista BES. The Protection
Systems must be capable of recording electrical quantities for each BES Elements it
owns connected to the BES buses identified.
The present Protection Systems are either electromechanical or first generation relays
not capable of meeting the NERC PRC-002-2 standard requirements of fault recording.
The scope of the project is to upgrade the existing Protection Systems on various 230
kV and 115kV terminals to Fault Recording (FR) capability per PRC- 002 requirements
at Beacon, Boulder, Rathdrum, Cabinet Gorge, North Lewiston, Lolo, Pine Creek,
Shawnee, and Westside Substations. Implementation is a phased approach with 50%
compliaint within 4 years and fully compliant within 6 years of the effective date 7/1/16.
The total number of affected terminals is 49.
Non-compliance can carry a fine of up to a million dollars per day based on severity.
1.1 What is the current or potential problem that is being addressed?
PRC-002-2 went into effect on 7/1/2016, we have six years to bring our protection system
into compliance with this updated standard.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
Mandatory & Compliance is the main driver for this project. But this will also allow more
information to be collected to facilitate analysis of BES disturbances.
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
Avista is required to comply with PRC-002 by July 1, 2022.
Requested Spend Amount $12,000,000
Requested Spend Time Period 5 Years
Requesting Organization/Department Substation Engineering
Business Case Owner | Sponsor Glenn Madden | Josh Diluciano
Sponsor Organization/Department Electrical Engineering
Phase Execution
Category Project
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 134 of 422
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 3 of 6
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
System Planning Assessments, Relay & Protection Design Reporting for PRC-002.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
NERC Reliability Standard PRC-002-2
NERC Project 200711 Disturbance Monitoring:
DL-2007-11_DM_Imp_Plan_2014Sep01_clean
PRC-002 Bus Fault Summary & Anaylsis 2016.xlsx
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
The present Protection Systems are either electromechanical or first generation relays
not capable of meeting the NERC PRC-002-2 standard requirements of fault recording.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
The Protection System upgrade of 49 terminals impacts the resources of Engineering
and GPSS over a 5 year period. The NERC standard requires compliance by specific
dates. By missing the compliance date set forth by NERC, Avista not only risks
monetary penalties based on severity but reputational damage as well.

Cost estimates per terminal from previous Protection System upgrades at a total
installed cost of $150k.

Protection System upgrades is the preffered solution. The relay replacement will not
only provide the recording capability but will improve system reliability, reduce
maintenance and support other NERC standard requirements (PRC-023, PRC-004).
In the past, Avista has attempted to put in a single digital fault recorder that complicated
the wiring and CT circuits within a station. All recorders have since been removed.

Option Capital Cost Start Complete
Upgrade Protection Systems $4.86M 02 2017 10 2022
Do Nothing $0M
Installation of a digital recorder on each BES
bus to provide the SER and FR data.

2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 135 of 422
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 4 of 6
- Samples of savings, benefits or risk avoidance estimates - Description of how benefits to customers are being measured - Comparison of cost ($) to benefit (value) - Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Since this is a compliance mandate, we also looked at other standards and relay options.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 - $3,200,000
2021 – $5,420,000
2022 – $2,480,000
2023 – $150,000
O&M costs may be reduced with this equipment replacement.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
Delay of the other projects due to resource scarcity.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Project is currently underway, construction is in progress at multiple sites and will conclude
in 2022 and closeout of project will occur in 2023. Transfers to plant are completed when
the work at each location is completed.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
Fault recording at substations enables root cause analysis, which can lead to improved
reliability. Additionally the work is mandatory from NERC.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 136 of 422
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 5 of 6
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
NERC required projects are vetted through NERC as to the viability of requiring the work to
be done and the associated benefit. The investment is likely to result in improved reliability
to the BES.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
The Engineering Roundtable process is used to identify projects requmng Transmission,
Substation, or Protection (TS&P) engineering support. The committee is responsible to
track TS&P project requests, facilitate prioritization of TS&P capital projects across
Engineering, Operations, and Planning), and to ensure projects are completed consistent
with the company's mission and corporate strategies.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 137 of 422
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 6 of 6
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Protection System Upgrades for
PRC-002 and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

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

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
1/5/2021
1/5/2021
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 138 of 422
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high-level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included:
1) NEEDS ASSESSMENT- a synopsis of the problem, the current state and recommended solution
2) COST- the cost of the recommended solution
3) DOCUMENT SUMMARY- benefit to the customer
4) RISK- of not approving the business case
5) APPROVALS- who reviewed and approved the recommended solution

<< Both the Executive Summary and Version History should fit into one page >>

Large commercial customers in the Othello area have continued to expand their businesses. The
business expansion has created demands on the electric system that are not able to be
adequately backed up with the reliability that they deserve. Meeting the increased load demands
are possible, but equipment failures could cause outages that would be time consuming and
difficult to restore quickly.

This business case would replace the Othello City substation with a new station having two
30MVA transformers. The business case also includes substantial upgrades to the transmission
system in the area to integrate the new Othello City substation with the new Saddle Mountain
substation. This business case is important to customers that they can continue to have the
reliability of the electric system that they have become accustomed to receiving. This project has
been approved and prioritices by the Engineering Roundtable Committee.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-64
Cost of Solution: $43,800,000

VERSION HISTORY
Version Author Description Date Notes
1.0 Unknown Initial Version 2017
2.0 Update to 202 Template 6/2020

DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 139 of 422
GENERAL INFORMATION

1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what the project will do and current problem statement]
This business case would replace the Othello City substation with a new station having 2-
30MVA transformers. The business case also includes substancial upgrades to the
transmission system in the area to integrate the new Othello City substation with the new
Saddle Mountain substation.
1.1 What is the current or potential problem that is being addressed?
There are performance issues in the Othello area. It is also difficult to maintain the
equipment at the Othello 115kV Substation due to load levels on all feeders.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Mandatory & Compliance are the main priority of this project due to TPL-001-4 non-
compliance at this time. There are also Performance & Capacity issues that will be
remedied with this project. Overall, this rebuild will relieve load and outage concerns for
large commercial customers.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
Due to increased load in the area, we are risking large customer outages due to equipment
failure.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
System Planning Assessments.
Requested Spend Amount $43,800,000
Requested Spend Time Period 6 Years
Requesting Organization/Department Transmission / System Planning
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory & Compliance
DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 140 of 422
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
Project Report: Saddle Mountain Study.pdf
2016 Avista System Planning Assessment Report (Page 56)
Othello City Substation Area Load Analysis
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
System Planning Assessments.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Alternative 1: Status Quo. This alternative is not recommended because it does not
mitigate the expected capacity constraints, and does not adhere to NERC Compliance
regulations.
Alternative 2: Build new 115kV Transmission Line. This alternative is not recommended
as it does not mitigate the low voltage issues in the Othello area.
Alternative 3: Close “Star” Points. This alternative is not recommended due to its high cost.
It is anticipated that $75M of reconductoring would be needed to mitigate any potential
violations comparable to the preferred alternative.
Alternative 4: Install Generation. This alternative is not recommended due to its high
financial costs, the potential for must run operation and the lead time on this project will be
well beyond the time this project is needed per NERC requirements.
Alternative 5: Build Saddle Mountain 230/115kV Substation Phase 2 Project with
associated support projects. This alternative is the most cost effective option considered
and provides enough voltage support and capacity into the area for the next 50 years. This
alternative mitigates all identified deficianencies in the Othello area documentes in the 2016
Planning Annual Assessment. This alternative is the best solution for the long term.
Phase 1: See Associated Phase 1 Business Case Narrative.
Phase 2:
1) Rebuild Othello Substation to 115kV Ring Bus with 5 positions.
2) Build new Transmission line from Saddle Mountain 115kV to Othello Substation
115kV.
This alternative is the most cost effective option considered and provides enough voltage
support and capacity into the area for the next 50 years. This alternative mitigates all
identified deficiencies in the Othello area documented in the 2016 Planning Annual
Assessment. This alternative is the best solution for the long term.

DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 141 of 422
Option Capital Cost Start Complete
Recommended Solution: Build Saddle Mountain
230/115kV Substation Phase 2 Project with
associated support projects
$11M 01 2020 12 2021
Alternative 1: Status Quo $0M
Alternative 2: Build new 115kV Transmission Line
Alternative 3: Close “Star” Points $75M
Alternative 4: Install Generation

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include: - Samples of savings, benefits or risk avoidance estimates - Description of how benefits to customers are being measured - Comparison of cost ($) to benefit (value) - Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments, previous outage information.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any
known or estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2018 $1,100,000
2019 $3,000
2020 $2,300,000
2021 $28,000,000
2022 $10,600,000 (Expected Spend)
2023 $1,950,000 (Forecast)
2023 – Closeout
O&M will be comparible to before this project.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system in the Othello
area.
DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 142 of 422
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
See Section 2.0 for alternative discussion.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer. spend, and
transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Design work was begun in 2020, construction will be completed by 2022 and closout may
continue into 2023. Transfers to plant will occur when the new station is commissioned and
energized.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
This project will alleviate concerns regarding large customer outages and will provide the
ability to maintain major substation equipment.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
The scope for the project, which is to increase transformation in the Othello area as well as
to increase reliability by creating the switching station is the least cost option. Adhering to
the scope and project objectives will be reviewed regularly by the project team including the
project engineer and the project manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Saddle Mountain 230/115kV Station (New) Integration Project Phase 1 was completed in
2020.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part of your departmental prioritization process.]
DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 143 of 422
The Engineering Roundtable initially is designated as the Steering Committee for this
project, with a more project-specific Steering Committee to be potentially identified at a later
date.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 144 of 422
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Saddle Mountain 230-115kV Station
(New) Integration Project Phase 2 and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Date:
Glenn Madden
Manager, Substation Engineering
Business Case Owner

Date:
Josh DiLuciano
Director, Electrical Engineering
Business Case Sponsor

Date:
Damon Fisher
Principle Engineer
Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: 516820B0-6EEF-4EC7-BE16-9AD269F2155B
Jun-28-2022 | 3:50 PM PDT
Jul-05-2022 | 7:43 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 145 of 422
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the
projects or programs included. Please limit to no more than 2 paragraphs. Components that should be
included: 1) a synopsis of the problem, 2) the service code and jurisdiction of customers impacted, 3) the
recommended solution, 4) the cost of the solution, 5) how the solution will benefit customers identified, 6) the
significance of the timeline and 7) the risks of not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

Local load growth, specifically at the local paper mill occurring in 2007 is a strong driver for a
transmission system expansion in the Spokane Valley area. Additionally, there are NERC TPL-
001-4 events not meeting performance requirements that are mitigated by completing the project.
The worst performance issue mitigated by the completion of the project is the NERC TPL-001-4
category P2.4 event of an internal Breaker Fault (Bus-tie Breaker) on A717 at Boulder Station.
System performance analysis indicates an inability of the System to meet the performance
requirements in Table 1 of NERC TPL-001-4 in scenarios representing 2017 Heavy Summer
Scenarios for the P2 contingency. An Operating Procedure to open Boulder A717 can be used to
mitigate the system deficiencies. Portions of the project have been completed prior to 2016.

The remaining portions of the Spokane Valley Transmission Reinforcement project are
constructing the Irvin Substation and rebuilding a portion of the Beacon – Boulder #2 115 kV
Transmission Line. All system defeciencies are mitigated and the desired operational flexibility to
serve large industrial customers is realized. This business case is important to customers
because its completion likely allows customers to continue to receive electrical service with the
reliability that they have grown accustom to receiving.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-48
Cost of Solution: $19,00,000 (includes completed projects) over $15 years

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017 Initial Version
2.0 Karen Kusel /
Glenn Madden Update to 2020 Template 06/2020

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 146 of 422
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
Completion of this project is required to mitigate a NERC TPL-001-4 system deficiency. The
transmission system in the Spokane Valley currently fails TPL-001-4(P2.4), which is an
internal Breaker Fault (Bus-tie Breaker) on A717 at the Boulder Station. In addition the
system fails the NERC TPL-001-4 P2 Contingency for the 2017 Heavy Summer Scenario.
Completion of this project is required to ensure Avista maintains compliance with NERC
regulations and Avista's planning documents.
1.1 What is the current or potential problem that is being addressed?
Being currently out of compliance of NERC TPL-001-4 and potential breaker faults which
could lead to large customer outages.
1.2 Discuss the major drivers of the business case (Customer Requested,
Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity,
Asset Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver of the business case is Mandatory & Compliance. Completion of this
project is required to ensure Avista maintains compliance with NERC regulations and
Avista's planning documents.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
There are risks to the reliability of electric service with delays to the completion of this
project.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
Future System Planning Assessments will show the BES improvements made by
completing this project.
Requested Spend Amount $6,800,000 (Remaining Projects)
Requested Spend Time Period 3 Years
Requesting Organization/Department Transmission/System Planning
Business Case Owner | Sponsor Glenn Madden | Josh Diluciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 147 of 422
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
2016 Avista System Planning Assessment.pdf
Irvin Project Final.pdf
IrvinvSubstationvProject - Rev C.pdf
SP-2009-03 Summary of Work - Irvin Project.pdf
SP-2011-07 2011 Spokane Valley Transmission Reinforcement.pdf
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Recommendation: Alternative 2, complete the Spokane Valley Transmission Reinforcement
project. Remaining project scope includes the following:
Construct the Irvin Station terminating the Beacon – Boulder #1 and #2, Irvin – IEP, and Irvin
– Opportunity 115 kV transmission lines as a breaker and a half configuration: $5 million.
Rebuild the existing Beacon – Boulder #2 115 kV Transmission Line from Beacon to Millwood
to 795 ACSS conductor: $2 million.
Alternative 1: Status Quo
This alternative is not recommended because it does not mitigate the expected capacity
constraints, and does not adhere to NERC Compliance regulations.
Alternative 2: Revert to before the CDA Reconfiguration Project
Revert the system to the condition prior to the Coeur d’Alene Reconfiguration Project creating
the Boulder-Rathdrum and Post Falls –Ramsey 115 kV transmission lines. Operational
concerns will present themselves specifically with a P2.1 planned outage followed by a forced
Pl event in the Coeur d’Alene area. (The P2.1 and Pl event combination is not a TPL-001-4
event.) Operational flexibility constrained by large industrial customers will continue to
persist.
Option Capital Cost Start Complete
Complete Project (Irvin Substation and BEA-
BLD #2 115kv Line Rebuild)
$6.8M 01 2020 12 2021
Alt 1: Status Quo $0M
Alt 3: Revert to before the CDA
Reconfiguration Project

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 148 of 422
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Load Growth, changes to compliance standards and System Planning Assessments were
considered.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital
spend?). Include any known or estimated reductions to O&M as a result of
this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 - $3.9M
2021 - $2.9M
O&M will be reduced by replacing the transmission line which will help offset the cost of
O&M of inspection and maintenance requirements of the substation and its equipment.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system in the Spokane
Valley area.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Status Quo would possibly lead to NERC fines and large customer outages. Reverting to
before the CDA Reconfiguration project would negate the benefits of having completed that
project.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer. spend, and
transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if
transfer to plant occurs monthly, quarterly or upon project completion).]
Construction at Irvin Substation will continue in the Fall of 2020 and be complete in the
Spring of 2021. The Beacon – Boulder #2 transmission rebuild will be completed in late
2021.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 149 of 422
Transfers to Plant will occur as the substation and transmission line are deemed in-service
and energized.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
This project will provide a solid foundation for customer reliability in the Spokane Valley.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
The scope for the project, which is to increase reliability in the Spokane Valley by creating
the switching station is the least cost option. Adhering to the scope and project objectives
will be reviewed regularly by the project team including the project engineer and the project
manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
• Glenn Madden - Manager, Substation Engineering
• Project Engineer/Project Manager (PE/PM)- Various
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
This project has been reviewed by the Engineering Roundtable.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and upcoming
project.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 150 of 422
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 151 of 422
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Spokane Valley Transmission
Reinforcement Project and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

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

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Glenn J Madden 1-3-2022
1/4/2022
1/4/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 152 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 9
EXECUTIVE SUMMARY
The Transmission Construction – Compliance Business Case covers the Transmission rebuild and reconductor work
necessary to maintain compliance with the NERC Reliability Standard TPL-001-4 – Transmission System Planning
Performance Requirements (“Standard”). It has 8 requirements and 57 sub-requirements related to planning and
analysis, including the requirement for robust system models to determine system stability, voltage levels and system
performance under various scenarios. This standard mandates that an annual planning assessment be conducted
and corrective actions be identified and implemented to remedy any system performance deficiencies In addition, when
Avista’s system planning studies indicate any kind of problem that could arise in the transmission system, it must be
remedied within specific timeframes. The Transmission Construction - Compliance Program provides funding to
mitigate any identified reliability issues in order to remain in compliance with NERC requirements.
The implementation of this business case will be considered successful if these projects are all completed prior to the
required compliance dates identified in the Engineering Roundtable Project List, which are copied from the Corrective
Action Plans (within the annually published Avista System Planning Assessment).
The Transmission Construction – Compliance Business Case also covers the Transmission line rebuild for lines not
meeting National Electric Safety Code (NESC) physical capacities for appropriate loading cases. These code
minimums have also been adopted into the State of Washington's Administrative Code (WAC). These lines may have
met the NESC criteria at the time of their original construction, but have been found to not be up to standards through
anaysis either as a result of requests for facility additions, or identified past additions not analyzed at the time of
installation.
The recommended solution is to build, rebuild, or reconductor transmission lines as identified in the Corrective Action
Plans to stay in compliance with NERC mandatory and enforceable Reliability Standards (most notably TPL-001-4)
and the NESC code (via WAC).
If Avista does not implement this business case, the company is at risk of violating NERC Reliability Standard
Requirements and could be subject to penalties of up to $1M per day for the duration of any such violation. Following
a “do nothing” option for this business case would likely be treated as an aggravating factor by the regulatory authority
when assessing enforcement actions. If Avista does not fully implement this business case, it also runs the risk of
being fined for not staying in compliance with the NESC code and WAC rules. There are no expected business impacts
to continuing this program in place. A spend of $2,000,000 is needed to complete the planned 2023-2027 projects .
This Program will have a Service Code of Electric Direct and a Rate Jurisdiction of Allocated North.
The Business Case contains two projects:
• Beacon-Boulder #1 115kV Rebuild (east of Irvin)
• Ninth & Central-Sunset 115kV Partial Rebuild (Upgrade to 795 ACSS)
The customer benefits from this Business Case through increased service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 5/02/2022
1.0
1.1
2.0

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 153 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 9
GENERAL INFORMATION

1. BUSINESS PROBLEM
The Transmission Construction – Compliance Business Case covers the Transmission rebuild and reconductor
work necessary to maintain compliance with the NERC Reliability Standard TPL-001-4 – Transmission System
Planning Performance Requirements (“Standard”). This standard mandates that an annual planning
assessment be conducted and corrective actions be identified and implemented to remedy any system
performance deficiencies. Corrective Action Plans must be completed within the required timeframe to meet
the system performance requirements dictated by the Standard.
The Transmission Construction – Compliance Business Case also covers the Transmission line rebuild for lines
not meeting National Electric Safety Code (NESC) physical capacities for appropriate loading cases. These
code minimums have also been adopted into the State of Washington's Administrative Code (WAC). These
lines may have met the NESC criteria at the time of their original construction, but have been found to not be up
to standards through anaysis either as a result of requests for facility additions, or identified past additions not
analyzed at the time of installation.
1.1 What is the current or potential problem that is being addressed? NERC
Reliability Standards and NESC loading capacities.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Mandatory
& Compliance: Customer benefits by having a Transmission System in compliance with Federal Code
and State Law.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
2.9 Concealment or Intentional Violation
NERC or the Regional Entity shall always consider as an aggravating factor any attempt by
a violator to conceal the violation from NERC or the Regional Entity, or any intentional
violation incurred for purposes other than a demonstrably good faith effort to avoid a
significant and greater threat to the immediate reliability of the Bulk Power System.

Requested Spend Amount $2,000,000
Requested Spend Time Period 1 year
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 154 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 9
2.10 Economic Choice to Violate
Penalties shall be sufficient to assure that entities responsible for complying with Reliability
Standards do not have incentives to make economic choices that cause or unduly risk
violations of Reliability Standards, or incidents resulting from violations of the Reliability
Standards. Economic choice includes economic gain for, or the avoidance of costs to, the
violator. NERC or the Regional Entity shall treat economic choice to violate as an aggravating
factor when determining a Penalty.
2.15 Maximum Limitations on Penalties
In the United States, the maximum Penalty amount that NERC or a Regional Entity will
assess for a violation of a Reliability Standard Requirement is $1,000,000 per day per
violation. NERC and the Regional Entities will assess Penalties amounts up to and including
this maximum amount for violations where warranted pursuant to these Sanction Guidelines.
In the case of projects addressing NESC capacity inadequacies, Avista will be cognisant of
not meeting the WAC.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
As-Built confirmation of mitigation measures.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
CAI Structure Analysis Results_BEA-BLD.xlsx
2019 Avista System Planning Assessment
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 155 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 9

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 156 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 9

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 157 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 9

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 158 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 9
2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
[Recommended Solution] $2.0M 01-2023 12-2027
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
See 1.5.2
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the various stages based on individual project.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform Spokane area jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
See 1.5.2.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Beacon-Boulder #1 115kV Rebuild (east of Irvin): 2020-2023
Ninth & Central-Sunset 115kV Partial Rebuild (Upgrade to 795 ACSS): 2022-2023

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 159 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 9
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista’s Culture of Compliance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Design solution performed within PLS-CADD, which is the industry leader in providing Transmission Line
Design computer based programs. Designs are reviewed at multiple stages to ensure prudency and
maximum Stakeholder value.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 160 of 422
2022 Transmission Construction - Compliance

Business Case Justification Narrative Template Version: 04.21.2022 Page 9 of 9
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Construction –
Compliance Business Case Justification Narrative and agree with the approach it
presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/9/2022
Josh DiLuciano
Vice President - Energy Delivery
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 161 of 422
2022 Transmission NERC Low Priority Ratings Mitigation

Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY
The Transmission NERC Low Priority Lines Mitigation Business Case covers the work to reconfigure insulator
attachments, and/or rebuild existing transmission line structures, or remove earth beneath transmission lines in order
to mitigate ratings/sag discrepancies found between "design" and "field" conditions as determined by LiDAR survey
data. This program was undertaken in response to the October 7, 2012 North American Electric Reliability Corporations
(NERC) "NERC Alert" - Recommendation to Industry, "Consideration of Actual Field Conditions in Determination of
Facility Ratings". This Capital Program covers mitigation work on Avista's "Low Priority" 230kV and 115kV transmission
lines. Mitigation brings lines in compliance with the National Electric Safety Code (NESC) minimum clearances values.
These code minimums have also been adopted into the State of Washington's Administrative Code (WAC). This
program is expected to be completed in 2024.
The recommended solution is to correct the issues found in the LiDAR studies to stay in compliance with the NESC
code and WAC. There are no expected business impacts to continuing this program in place. If Avista does not fully
implement this business case, it runs the risk of being fined for not staying in compliance with the NESC code and
WAC rules. A spend of $3,500,000 is needed to complete the mitigations by 2024. This Program will have a Service
Code of Electric Direct and a Rate Jurisdiction of Allocated North.
The customer benefits from this Business Case through increased service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 4/28/2022
1.0
1.1
2.0

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 162 of 422
2022 Transmission NERC Low Priority Ratings Mitigation

Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
The Transmission NERC Low Priority Lines Mitigation Business Case covers the work to reconfigure insulator
attachments, and/or rebuild existing transmission line structures, or remove earth beneath transmission lines in
order to mitigate ratings/sag discrepancies found between "design" and "field" conditions as determined by
LiDAR survey data. This program was undertaken in response to the October 7, 2012 North American Electric
Reliability Corporations (NERC) "NERC Alert" - Recommendation to Industry, "Consideration of Actual Field
Conditions in Determination of Facility Ratings". This Capital Program covers mitigation work on Avista's "Low
Priority" 230kV and 115kV transmission lines. Mitigation brings lines in compliance with the National Electric
Safety Code (NESC) minimum clearances values. These code minimums have also been adopted into the
State of Washington's Administrative Code (WAC).
1.1 What is the current or potential problem that is being addressed? Clearance
violations.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Mandatory
& Compliance: Customer benefits by having a Transmission System in compliance with Federal Code
and State Law.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred The North American Electric Reliability Corporations (NERC) "NERC
Alert" originally identified Low Priority Transmission Line assessments to complete by December 31, 2013.
Although a mitigation timeline did not include a penalty threat, we have been operating under a grace
period that requires us to report progress every six months. Completing the program by 2024 will show
us taking eleven years to complete the effort. Deferring completion is tempting greater scrutiny from NERC
and delays mitigation of a compliance violations recognized by Washington State Law.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. As-Built confirmation of mitigation measures.

Requested Spend Amount $3,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 163 of 422
2022 Transmission NERC Low Priority Ratings Mitigation

Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
CAN-0009_FAC-008 FAC-009.pdf
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Mitigate Violations $3.5M 01-2023 12-2024
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 164 of 422
2022 Transmission NERC Low Priority Ratings Mitigation

Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the Execution Stage with spend directed primarily at structure change-outs resulting in
greater ground clearance.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform the smaller jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Raising structure heights is by far the go to alternative. In one instance the removal of earth was used.
Earth removal can trigger permitting, which otherwise would not be necessary.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Smaller projects can take place throughout the year. Most of the large projects take place in the Fall
months and Transfer to Plant in the November time frame.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista’s Culture of Compliance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Mitigation design solution performed within PLS-CADD, which is the industry leader in providing
Transmission Line Design computer based programs. Designs are reviewed at multiple stages to ensure
prudency and maximum Stakeholder value.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 165 of 422
2022 Transmission NERC Low Priority Ratings Mitigation

Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 166 of 422
2022 Transmission NERC Low Priority Ratings Mitigation

Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Low Priority Rating Mitigation
Business Case Justification Narrative and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Josh DiLuciano
9/9/2022
Vice President - Energy Delivery
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 167 of 422
EXECUTIVE SUMMARY
This business case is driven by compliance – the legal requirement to obtain and maintain permits/leases
for Avista’s facilities located on Tribal reservations. Land ownership on Tribal reservations is complex. Much
of the land is held in trust by the federal government on behalf of either Tribes or individual Tribal members.
Permits for Avista’s transmission and distribution facilities were originally obtained pursuant to 25 CFR 169.
Business leases required for substations are obtained pursuant to 25 CFR 162. However, the federal
regulations do not typically allow for perpetual easements. Rather, permits/leases can be issued up to 50
years and then these permits need to be renewed. The majority of Avista’s permits have reached the 50
year expiration and need to be renewed. In addition, new facilities placed on Trust lands need new permits.
In order to acquire a renewed or new permit, a time-consuming federal regulatory process needs to be
followed and permission needs to be obtained from the Tribe and/or the majority of individual Tribal
landowners who have an interest in the relevant parcel of land. The permit is issued by the Bureau of Indian
Affairs after they determine all steps of the process have been achieved. Most of the land on Reservations
is divided into parcels of 80 acres or less. Therefore, a transmission or distribution line usually crosses
numerous parcels of land – each of which requires its own permit.

Avista has facilities on the following Tribal reservations: Spokane, Colville, Nez Perce, Coeur d’Alene,
Flathead, and Kalispel trust lands in Airway Heights. Avista maintains approximately 82 miles of
transmission lines on Tribal trust lands, which benefit all of Avista’s electric customers. Over the last 10
years, we have renewed permits on the Coeur d’Alene, Flathead, and Nez Perce reservations. The current
focus is renewals on the Spokane and Colville Reservations. Approximately 300 new permits are needed
on the Spokane Reservation and 130 on the Colville Reservation. Historical 4-year annual costs have
averaged just under $400k.

Failure to obtain necessary new permits and maintain existing permits would put us in immediate violation
of Federal Law. Without a valid permit, the Bureau of Indian Affairs would require us to remove our facilities
from Tribal trust lands. Avista has an obligation to serve its customers on these reservations. To ensure
Avista can serve its customers and transmit power on and across Tribal reservations, we need to complete
the process of renewing permits that have and/or are expiring.

Without capital funding the acquisition of these permits would still take place and O&M funding would be
utilized.

VERSION HISTORY
Version Author Description Date Notes
Draft Toni Pessemier Initial draft of original business case 7/8/20
1.0 Updated Approval Status Full amount approved
1.1 Budget change
2.0 Toni Pessemier Update template Version 04.21.2022 8/31/22
DocuSign Envelope ID: 866887D5-13E7-4C2F-A244-B2267DE46C36
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 168 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista has a federal regulatory requirement to obtain and maintain permits/leases for its facilities
located on Tribal reservations, specifically for the land held in trust by the Federal government
on behalf of either Tribes or individual Tribal members (“trust lands”). Permits for Avista’s
transmission and distribution facilities were originally obtained from the Bureau of Indian Affairs
pursuant to 25 CFR 169. Business leases required for substations are obtained from the BIA
pursuant to 25 CFR 162. The Federal regulations do not allow for perpetual easements. Rather,
permits/leases were issued up to 50 years. The majority of Avista’s permits on Tribal
reservations have reached the 50 year expiration and need to be renewed.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Mandatory and Compliance – Avista needs to obtain and maintain active permits for all of its
encroachments on Trust lands on Tribal reservations. Avista has facilities on the following
reservations: Spokane, Colville, Nez Perce, Coeur d’Alene, Flathead, and Kalispel trust lands
in Airway Heights. Avista maintains approximately 82 miles of transmission lines on Trust lands
and extensive distribution systems. To-date, we have renewed permits on the Nez Perce, Coeur
d’Alene and Flathead reservations. Avista’s current focus is to renew permits for facilities on the
Spokane and Colville Reservations.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista is the only electric provider on the Spokane Reservation and is the electric provider in the
Inchelium area of the Colville Reservation. Avista has an obligation to serve its customers.
Approximately 300 permits are needed on the Spokane Reservation and 130 on the Colville
Reservation. To ensure Avista can continue to serve its customers, and transmit power to serve
customers on and off the reservations, we need to continue the process of renewing permits
that have and/or are expiring. Avista does not have the ability to condemn on Tribal trust lands.
If Avista is not actively pursuing these renewals, we would be in violation of Federal law, and
the Bureau of Indian Affairs could demand that we immediately remove our facilities from Tribal
trust lands. There are examples across the United States where businesses have been required
to remove their facilities when permits have expired. Although Avista has now renewed many of
the transmission related permits for 20-50 years, it has been estimated that it would cost at least
Requested Spend Amount $400,000
Requested Spend Time Period annually
Requesting Organization/Department American Indian Relations
Business Case Owner | Sponsor Toni Pessemier | Latisha Hill
Sponsor Organization/Department / Community & Economic Vitality
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
DocuSign Envelope ID: 866887D5-13E7-4C2F-A244-B2267DE46C36
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 169 of 422
$61 million to relocate all transmission lines off of Tribal land. Because of our obligation to serve,
we need to continue obtaining the required permits for distribution facilities on the reservations.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Over the last 10 years, Avista has successfully delivered on the objectives and renewed all of
the expired permits for facilities on the Nez Perce, Coeur d’Alene and Flathead reservations so
we have a successful track record and are extensively familiar with the process and estimated
costs. However, each Tribe, reservation, and Tribal member is unique so costs can vary
depending on individual negotiations and resolutions. The renewal process on both the
Spokane and Colville reservations is underway with support from BIA and Tribal Realty offices.
While some permits may be obtained for the appraised value, other permits may require
additional effort, mediation and compensation.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
Continue the process to obtain renewed permits for Avista’s facilities located on Trust lands on Tribal
reservations which are required by law to transmit power and continue serving our customers.
Relocating transmission lines would include longer distances and the risk of obtaining satisfactory
easements on non-Tribal land. For distribution assets on Trust lands, there is no immediate viable
option, due to obligation to serve.
Option Capital Cost Start Complete
Continue to negotiate permits/leases as required 400,000 01 2023 12 2023
Relocate transmission lines off of the SpokaneTribal
land
$61,190,000 01 2023 12 2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The 400,000 is a placeholder for permitting costs which has run historically:

Costs can vary depending on the Tribe, Bureau of Indian Affairs personnel on the reservation,
and individual Tribal members when trying to reach a settlement. Additionally the federal
regulations were updated in 2017 and the costs associated with the renewal process (e,g,
individual surveys, appraisal reports, process to obtain consent from landowners) have
increased.
DocuSign Envelope ID: 866887D5-13E7-4C2F-A244-B2267DE46C36
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 170 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The costs are associated with following 25 CFR 169 and 162 regulatory processes, and
negotiating settlements with Tribe and/or individual Tribal members as needed. The objective is
to renew all of the remaining expiring permits. Avista maintains a Native American Relations
department for the express purpose of working closely with Tribes on a variety of issues. The
annual O&M expenditure for this department is approximately $300,000. The Tribal Rights of
Way Specialist devotes 90% of her time to this capital business case.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
By renewing the permits, transmission and distribution engineering will not need to evaluate
options and costs associated with relocating our facilities. Operations staff will have rights for
ingress and egress to maintain our facilities and service to customers will not be negatively
impacted.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
See 2.0
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
This work is ongoing. Transfer to plant is reviewed quarterly. When permits have been obtained,
related costs can be transferred.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Being able to serve our customers is critical and our customers trust we will do so. Obtaining
the required permits allows us to demonstrate our focus on compliance. Avista’s commitment to
Tribal relations demonstrates accomplishing this in a collaborative manner.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Costs are directly associated with compliance and adhering to federal law and regulations 25
CFR 169 and 162. When settlement discussions are necessary to obtain a permit, each situation
and scenario is evaluated for possible alternatives and related costs. In all cases to-date, the
settlement costs have been lower than alternatives such as relocating facilities.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

2.8.2 Identify any related Business Cases

DocuSign Envelope ID: 866887D5-13E7-4C2F-A244-B2267DE46C36
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 171 of 422
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
There is no specific Steering Committee for this Business Case. The Advisory Group is the
American Indian Relations department in consultation with others including the Realty
Department, Legal, District Managers, Transmission and Distribution Engineers as needed.
3.2 Provide and discuss the governance processes and people that will
provide oversight
American Indian Relations department is responsible for day to day activities. The Tribal R/W
specialist works with other Real Estate representatives and utilizes multiple systems. The VP of
Community & Economic Vitality along with the Sr. VP of Environmental & Real Estate provide
oversight with periodic engagement of the VP General Counsel and VP Chief Regulatory
Counsel as needed.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making will occur as outlined in 3.2. Change requests and documentation will be
initiated and monitored by American Indian Relations with support from Financial Planning &
Analysis.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Tribal Permits and Settlements and
agree with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Toni Pessemier
Title: American Indian Relations Advisor
Role: Business Case Owner

Signature: Date:
Print Name: Latisha Hill
Title: VP Community & Economic Vitality
Role: Business Case Sponsor

Signature: Date:
Print Name:
DocuSign Envelope ID: 866887D5-13E7-4C2F-A244-B2267DE46C36
Sep-02-2022 | 6:50 PM PDT
Sep-06-2022 | 7:14 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 172 of 422
Title:
Role: Steering/Advisory Committee Review

DocuSign Envelope ID: 866887D5-13E7-4C2F-A244-B2267DE46C36
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 173 of 422
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high-level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included:
1) NEEDS ASSESSMENT- a synopsis of the problem, the current state and recommended solution
2) COST- the cost of the recommended solution
3) DOCUMENT SUMMARY- benefit to the customer
4) RISK- of not approving the business case
5) APPROVALS- who reviewed and approved the recommended solution

<< Both the Executive Summary and Version History should fit into one page >>

The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for the P1
event of the Westside #2 230/115 kV transformer. System performance analysis indicates an
inability of the system to meet the performance requirements in Table 1 of NERC TPL-001-4 in
scenarios representing 2017 Heavy Summer for P1 events. While Avista intends to avoid
proactively shedding customer load, an operating procedure to shed non-consequential load can
be used until 2021 to mitigate system deficiencies (non-consequential load shedding is
considered acceptable through the 84 month implementation of TPL-001-4). This project is
approved and prioritized by the Engineering Roundtable Committee.
Westside Transformer Replacement is the recommended solution. Replace the existing Westside
transformers with 250 MVA rated transformers and reconstruct both the 230 kV and 115 kV buses
at the station to double bus, double breaker. All associated system deficiencies will be mitigated.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-47
Cost of Solution: $26,200,000

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017 Initial Version
2.0 Update to 2020 Template 6/2020

DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 174 of 422
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what the project will do and current problem statement]
The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for
the P1 event of the Westside #2 230/115 kV transformer. System performance analysis
indicates an inability of the system to meet the performance requirements in Table 1 of
NERC TPL-001-4 in scenarios representing 2017 Heavy Summer for P1 events. While
Avista intends to avoid proactively shedding customer load, an operating procedure to shed
non-consequential load can be used until 2021 to mitigate system deficiencies (non-
consequential load shedding is considered acceptable through the 84 month
implementation of TPL-001-4).
1.1 What is the current or potential problem that is being addressed?
System performance analysis indicates an inability of the system to meet the performance
requirements in Table 1 of NERC TPL-001-4 in scenarios representing 2017 Heavy
Summer for P1 events.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
Mandatory & Complaince - All associated system deficiencies will be mitigated with the completion
of this project.
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
While Avista intends to avoid proactively shedding customer load, an operating procedure to shed
non-consequential load can be used until 2021 to mitigate system deficiencies (non-consequential
load shedding is considered acceptable through the 84 month implementation of TPL-001-4).
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
Future System Planning Assessments which show mitigation of all prior deficiencies.
Requested Spend Amount $26,200,000
Requested Spend Time Period 15 Years
Requesting Organization/Department Transmission/System Planning
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory & Compliance
DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 175 of 422
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
System Planning Assessments.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Westside Transformer Replacement is the recommended solution. Replace the existing
Westside transformers with 250 MVA rated transformers and reconstruct both the 230
kV and 115 kV buses at the station to double bus, double breaker. All associated system
deficiencies will be mitigated.
Project scope includes the following:
Phase 1: Replace the existing Westside #1 230/115 kV transformer and construct necessary
bus work and breaker positions. $11 million, energize 2018
Phase 2: Continue bus work and breaker replacement: $8 million, energize 2019
Phase 3: Replace the existing Westside #2 230/115 kV transformer and complete bus work
to single bus configuration: $6 million, energize 2020
Phase 4: Complete bus work to double bus, double breaker on both the 230 kV and 115 kV
buses: $7 million, energize 2022. (2022 Note: Project is scheduled to complete in 2024
because of delays for getting planned outages.)

Alternative 1 - Status Quo/Do Nothing: This alternative is not recommended because it does
not mitigate the expected capacity constraints and does not adhere to NERC transmission
planning standards.
Solution/Alternative 2 - Westside Transformer Replacement: Replace the existing Westside
transformers with 250 MVA rated transformers and reconstruct both the 230 kV and 115 kV
buses at the station to double bus, double breaker. All associated system deficiencies will be
mitigated.
Alternative 3- Garden Springs 230kV Station Integration: The Garden Springs 230 kV
Station Integration project includes the installation of new 230/115 kV transformation in the
Spokane area. The additional transformation will offload the Westside #1 and #2 230/115
transformers. In the future, the Garden Springs 230 kV Station Integration project will be
necessary in addition to the Westside Transformer Replacement project.
Alternative 4 - Replace Westside Transformers without Station Rebuild: Replacing the
existing Westside transformers to 250 MVA rated transformers will mitigate the transformer
overload system deficiencies but will create a short circuit breaker rating exceedance.
Additional P2 bus outage system deficiencies will exist.

DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 176 of 422

Option Capital Cost Start Complete
Replacement
Integration
without Station Rebuild

2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include: - Samples of savings, benefits or risk avoidance estimates - Description of how benefits to customers are being measured - Comparison of cost ($) to benefit (value) - Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 – $3,000,000
2021 - $3,500,000
2022 - $2,800,000
2023 - $2,000,000
2024 – $1,000,000
O&M costs will be comparible to what they were before this project.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 177 of 422
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Construction will continue through 2024. Transfers to Plant will be at the close of each
Phase.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
The completion of this project leads directly to a dimished threat of customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The scope for the project, which is to increase transformation capacity in the Spokane area
is the least cost option that provides the needed functionality. Adhering to the scope and
project objectives will be reviewed regularly by the project team including the project
engineer and the project manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part of your departmental prioritization process.]
• Project Engineer/Project Manager (PE/PM)- Dana Gerbing/Zachary Curry
• Engineering Roundtable Committee
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule
and costs. Also meets at time of pre-construction. Other meetings held as necessary.
This project has also been reviewed by the Engineering Roundtable.
DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 178 of 422
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 179 of 422
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Westside 230/115kV Station
Rebuild and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Date:
Glenn Madden
Manager, Substation Engineering
Business Case Owner

Date:
Josh DiLuciano
Director, Electrical Engineering
Business Case Sponsor

Date:
Damon Fisher
Principle Engineer
Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: C659F0E0-7CE3-4641-9CAA-9D0806C4E6A1
Jun-28-2022 | 3:36 PM PDT
Jul-05-2022 | 7:41 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 180 of 422
EXECUTIVE SUMMARY

The North Lewiston 230/115 kV Transformer 1 (McGraw-Edison Serial Number C-06237-5-2)
located in Lewiston, ID failed in February 2021. A replacement transformer has been ordered and
will be installed in 2022. The North Lewiston 230/115kV Transformer 1 provides the
transformation capacity needed for the system to meet performance requirements as defined by
System Planning and System Operations.

The North Lewiston 230/115 kV Transformer 1 was 40 years old when it failed. Following the
failure, an investigation was performed with testing and an internal inspection. The investigation
concluded the transformer had a failed winding. The decision to replace the 230/115 kV
Transformer 1 was made based on an evaluation of alternatives which also included rebuilding the
existing transformer and utilizing a spare transformer within Avista’s system.

Service Code: Electric Direct
Jurisdiction: Allocated North

VERSION HISTORY
Version Author Description Date Notes
Draft Karen Kusel Draft, Preliminary Dollars 04/26/2021
Draft_SK Sara Koeff Revision 06/1/2021
Draft_rev2 Keri Gross Revision 06/07/2021

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 181 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The night of 2/27/2021 there was a B to ground fault on the North Lewiston tap of the
Lolo-Pound Lane 115 kV line. The following morning, 2/28/2021, a major alarm came
in on the North Lewiston 230/115kV Transformer 1. The alarm was driven by the Online
Dissolved Gas Analysis (DGA) Monitor. The DGA showed an increase in multiple
gasses coinciding with the timing of the transmission line fault. Due to the increase in
gasses, the transformer was taken out of service to perform electrical testing on it. The
excitation current and sweep frequency response analysis (SFRA) tests had irregularities
in the test results. An internal inspection was performed, which confirmed that there was
a H2 (B phase) winding turn-to-turn fault and at least one parallel winding strand that
had broken open. The North Lewiston 230/115 kV Transformer 1 was deemed to have
a failed winding and unable to be put back into service. For complete details on the
investigation effort see “North Lewiston Auto 1 Investigation Analysis” report.

Requested Spend Amount $4,100,000
Requested Spend Time Period 2 Years
Requesting Organization/Department Substation Engineering
Business Case Owner | Sponsor Glenn Madden | Heather Rosentrater
Sponsor Organization/Department M08 / Substation Engineering
Phase Planning
Category Project
Driver Failed Plant & Operations
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 182 of 422
1.2 Discuss the major drivers of the business case
The major driver for this project is Failed Plant & Operations. The North Lewiston
230/115 kV Transformer 1 provides the transformation capacity needed for Avista’s
system to meet performance requirements as defined by System Planning and System
Operations.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The 2019-2020 Avista System Assessment, Appendix D documents the studies
performed by System Planning showing what may result on Avista’s system with the
loss of the North Lewiston 230/115kV Transformer. Studies were performed according
to NERC standard TPL-001-4 requirement R2.1.5; below is a summary from the
Assessment.
• Overload of the Lolo #1 230/115kV Transformer for outages involving the Dry Creek
230/115kV Transformer, Lolo #2 230/115kV Transformer or the Dry Creek 115kV bus.
(See below figure)
• Overload of the Dry Creek – North Lewiston 115kV Transmission Line for outages
involving the Lolo 115kV bus.
• Area low voltage for outages involving the Lolo 115kV bus.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Replacing the North Lewiston 230/115 kV Transformer 1 will return the electric system
in the Lewiston / Clarkston area to normal operating conditions.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 183 of 422
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Avista crews performed initial testing of the North Lewiston 230/115 kV
Transformer. The test results indicated performance issues and further testing was
needed. North American Substation Services (NASS) performed a Sweep
Frequency Response Analysis (SFRA). Doble Engineering analyzed the Avista
and NASS test results. An internal inspection of the transformer showed evidence
of broken winding coil and coil movement.
See the “North Lewiston Auto 1 Investigation Analysis” attachment for
inspection and testing details.
See the “2019-2020 Avista System Assessment - V2 - Appendix D” attachment
for details of system performance concerns associated with the transformer
outage.
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
The North Lewiston 230/115 kV Transformer had a H2 (B phase) winding turn-
to-turn fault and at least one parallel winding strand broke open. The transformer
was deemed to have a failed winding and unable to be put back into service.
See the “North Lewiston Auto 1 Investigation Analysis” for details on the
condition of the failed transformer.

2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
[Recommended Solution] Replace 230/115 kV
Transformer
$4.1M 02-2021 6-2022
[Alternative #1] Repair 230/115 kV Transformer Unknown 02-2021 Unknown
[Alternative #2] Relocate 230/115 kV Transformer
to NLW
N/A 02-2021 N/A
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Project cost and project completion date were priority considerations for restoring the
transmission system to meet performance requirements in the Lewiston/Clarkston area.
Replacing the failed North Lewiston 230/115 kV Transformer has the lowest project
cost and restores the transmission system with the shortest and most predictable
timeline.
See “North Lewiston Auto Transformer Failure and Replacement” for analysis of the
project options.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 184 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
2021 – Purchase new transformer, remove old transformer and associated equipment,
engineering / drafting costs. (~$ 3.35M)
2022 – Receive new transformer at North Lewiston Substation, install new transformer
and associated equipment, test and commission new transformer, engineering / drafting
costs. (~$ 0.75M)
There will be no substantial increase in O&M expenses after this transformer
replacement.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
This business case impacts work within Transmission and Distribution by postponing a
few projects about two months.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative #1: The option to repair the existing failed transformer has an unknown cost
and project completion due to the difficulty of locating a domestic facility capable of
repairing the atypical design. If a repair facility is located, there are concerns if the repair
could bring the existing transformer to current component specifications as quick as or
quicker than purchasing a new transformer. Additionally, there are cost and timeline
concerns with the round-trip transportation of the existing transformer, including
possibly to an overseas facility, due to the present worldwide pandemic restrictions and
shipping interruptions.

Alternative #2: Avista does not own a spare 230/115 kV Transformer or have sufficient
capacity in the remaining parts of the system to relocate an already in service 230/115
kV Transformer.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
February/March 2021 – Inspection, testing, and analysis of options leading to decision
to replace autotransformer
Remainder of 2021 – Order replacement transformer. Engineering to scope and design
replacement. Remove/recycle failed transformer by contractor. Site prep work is
completed before installation begins.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 185 of 422
2022 – New transformer is received onsite. Avista crews complete installation of
transformer. Testing and Commissioning is completed. Autotransformer is energized
by mid-year.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Perform:
The proposed investment is critical to serving our customers well. The North Lewiston
230/115 kV Transformer is required to safely and responsibly serve our customers.
Once it was determined to have failed, Avista performed timely and necessary analysis
to determine the most affordable path forward. Purchasing a new transformer to replace
the failed transformer provides ‘Better Energy for Life’.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Based on System Planning’s 2019-2020 System Assessment, the North Lewiston
230/115 kV Transformer is necessary to meet performance requirements. Replacing the
transformer will return the system to its normal operating condition.

2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Substation Engineering, Protection Engineering, GPSS Electric Shop, GPSS
Mechanical/Structural Shop, GPSS Relay Shop, Drafting Department, System Planning,
System Operations, Network Communications, Project Accounting, SCADA Support,
Asset Management.
2.8.2 Identify any related Business Cases
There are no related Business Cases.

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Capital Planning Group, Engineering Roundtable

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 186 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
Any major changes to the project will go to the Engineering Round Table (ERT). The
Substation Engineering Manager and System Operations will provide oversight to the
project.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Lead Substation Engineer will coordinate decisions through those who provide
oversight and document those decisions as necessary.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 187 of 422
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the North Lewiston Auto Transformer
Replacement and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Heather Rosentrater
Title: Senior VP, Energy Delivery
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Engineering Roundtable
Role: Steering/Advisory Committee Review

Glenn J Madden 1-3-2022
1/4/2022
1-4-2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 188 of 422
EXECUTIVE SUMMARY
This business case provides for replacement of existing technology, as well as for deployment
of new applications and technology as required to address expanding regulatory and business
requirements. This program (Supervisory Control and Data Acquisition - System Operations
Office and Backup Control Center) replaces and upgrades existing electric and gas control
center telecommunications and computing systems as they reach the end of their useful lives,
require increased capacity, or cannot accommodate necessary equipment upgrades due to
existing constraints. Some system upgrades may be necessitated by other requirements,
including NERC reliability standards, TSA directives, federal gas standards, system growth, and
external projects (e.g. Smart Grid). The customers who benefit are all electric and gas
residential, commercial, and industrial customers (CD.AA).
The estimated costs for the upcoming five years are $4.5M. The amount requested is based
partially upon historical spending needs, and partially on known upcoming major projects. Within
the program’s yearly authorized spend amount, specific budgetary items to be implemented are
determined based on asset condition, life-cycle management, technology enhancements, and
requests by affected stakeholders including System Operations, Distribution Operations, and
Power Supply.
There are multiple risks if this program is not adequately funded. The clearest risk would be to
public and personnel safety. The control systems supported by this business case provide real-
time visibility, situational awareness, and control of Avista’s electric and gas systems.
Degradation of these capabilities due to lack of capacity, capability, or aging systems would
present increased safety risk. Additionally there is significant compliance risk. These control
systems provide the capabilities required to achieve compliance with numerous reliability
standards and requirements. For the electrical system these include the NERC standards BAL,
COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. For the gas system these include the
PHMSA “Pipeline Safety: Control Room Management/Human Factors” rule (49 CFR Parts 192
and 195.) The expenditure of these funds is necessary to operate Avista’s electric and gas
systems in a safe, reliable, and compliant manner.
VERSION HISTORY
Version Author Description Date Notes
Draft Craig Figart Initial draft of original business case 07.1.2020
0.2 Craig N Figart Draft version of 2020 business case 07.17.2020 Updated Executive Summary
1.0 Craig N Figart Final version of 2020 business case 09.21.2020 Based on Magruder input.
2.0 Jeremiah Webster
formatting to keep the fonts consistent,
removed some of the blue help text, and
deleted the comments
12.15.2020
3.0 Craig N Figart Updated per $350k capital funding
increase for 2021 due to EMS upgrade 07.05.2021
4.0 Craig N Figart
Updated per $490k capital funding
increase for 2021 due to EMS upgrade
multi-year budgeting, firewall refresh, file
storage expansion
09.10.2021 2021-2025 total revised from
$4.35M to $4.84M.
5.0 Craig Figart Updated version for 2022 business case 08.03.2022
GENERAL INFORMATION
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 189 of 422

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
In order to effectively operate the Transmission & Distribution (T&D) Systems, sufficient
business and computing hardware and software is necessary. This business case
provides for replacement of existing technology in alignment with manufacturer product
roadmaps for application and technology lifecycles, as well as for deployment of new
applications and technology as required to address expanding regulatory and business
requirements. Technology continues to change and T&D Systems continue to incorporate
improved technology.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Asset Condition is the major driver of the business case. Other drivers are Customer
Service Quality & Reliability and Performance & Capacity. This business case is crucial in
a key aspect of Our Vision; “Delivering reliable energy service…” It is essential in providing
sufficient control center technology tools, situational awareness, and monitor/control
capabilities to achieve reliable energy service.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
There are multiple risks if this program is not adequately funded. The clearest risk would
be to public and personnel safety. The control systems supported by this business case
provide real-time visibility, situational awareness, and control of Avista’s electric and gas
systems. Degradation of these capabilities due to lack of capacity, capability, or aging
systems would present increased safety risk. Additionally there is significant compliance
risk.
These control systems provide the capabilities required to achieve compliance with
numerous reliability standards and requirements. For the electrical system these include
the NERC standards BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. For the gas
system these include the PHMSA “Pipeline Safety: Control Room Management/Human
Factors” rule (49 CFR Parts 192 and 195.)
Requested Spend Amount $4,500,000
Requested Spend Time Period 5 years
Requesting Organization/Department T&D - SCADA/EMS/DMS - System Operations
Business Case Owner | Sponsor Craig N Figart | Michael Magruder
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 190 of 422
The expenditure of these funds is necessary to operate Avista’s electric and gas systems
in a safe, reliable, and compliant manner.
In addition to the risks related to public and personnel safety, compliance risk would be
increased without this investment. Non-compliant operational capabilities and practices
would result in negative audit findings, significant financial penalties, and litigation
expenses. Obsolete equipment would remain in service until failure. Additional capacity
for growth may or may not be suitable for required expansions to meet other needs (e.g.
Regulatory, Smart Grid.)
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Not applicable
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Not applicable
2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Fully Funded “SCADA – SOO and BuCC” business
case
$1.1 M (reqst'd)
$0.9M (apprvd)
01 2022 12 2022
Do Nothing $0
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

This capital request was prepared based on typical average annual $700k costs
required to meet the needs for this business case. Additional $1M funding is included
beginning in 2027 when we plan to upgrade our main EMS system recently upgraded
in 2021.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 191 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This requested capital will be spent on such efforts as refresh of network equipment,
disk storage and backup systems, computer hardware and related software
applications and systems, database backend systems, SCADA telemetry head-end
equipment, SCADA UPS and battery backup systems, etc.. And of course, this
business case also includes costs to meet security and NERC/CIP compliance related
objectives and obligations.
One project that will reduce annual O&M by $30,000 is the Operator Training Simulator
(OTS) project that will take advantage of the Avista's existing GE SCADA system to
add OTS functionality requiring much cheaper annual licensing than the current
disparate IncSys power system training simulator.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The EMS upgrade project, like most projects in this business case, is required to be
completed in order to upgrade hardware and software that is no longer supported.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Not applicable
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
This business case is comprised of multiple individual capital projects that all close
upon completion over the course of the next five years, at which time they are
transferred to plant and become used-and-useful.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 192 of 422
There are two "revolving" projects, however, SCADA Hardware Refresh and SCADA
Expansion, that are for minor refresh and expansion items like computer desktop pcs,
monitors, etc. These projects are placed into service immediately and become used-
and-useful right as they are purchased and deployed.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
As previously mentioned, Asset Condition is the major driver of the business case.
Other drivers are Customer Service Quality & Reliability and Performance & Capacity.
This business case is crucial in a key aspect of Our Vision; “Delivering reliable energy
service…” It is essential in providing sufficient control center technology tools,
situational awareness, and monitor/control capabilities to achieve reliable energy
service.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The capital requested above is considered a prudent investment as it is required for
replacement of existing technology, as well as for deployment of new applications and
technology as required to address expanding regulatory and business requirements.
This program replaces and upgrades existing electric and gas control center
telecommunications and computing systems as they reach the end of their useful lives,
require increased capacity, or cannot accommodate necessary equipment upgrades
due to existing constraints. Some system upgrades may be necessitated by other
requirements, including NERC reliability standards, TSA directives, federal gas
standards, system growth, and external projects (e.g. Smart Grid). The customers
who benefit are all electric and gas residential, commercial, and industrial customers
(CD.AA).

Further justification of the need of this business case is listed below.
o There are numerous mandates in effect which compel these expenditures,
numerous NERC Standards, and PHMSA’s Control Room Management rule, in
particular (49 CFR Parts 192 and 195).
o There is no practical risk mitigation should we fail to meet these requirements.
o This is a continuous program. Work is started and completed throughout each
year, and in some cases, such as major upgrades, spans multiple years.
o This business case is crucial in a key aspect of Our Vision; “Delivering reliable
energy service…” It is essential in providing sufficient control center technology
tools, situational awareness, and monitor/control capabilities to achieve reliable
energy service.
o This business case is key in accomplishing the Our Focus item of “Safe &
Reliable Infrastructure.” Providing remote monitor and control capabilities to
operators is essential in achieving “optimum life-cycle performance - safely,
reliably, and at a fair price.”
o The amount requested is based partially upon historical spending needs, and
partially on known upcoming major projects.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 193 of 422

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
o Our Stakeholders include:
o Operations
▪ System Operators
▪ Power Schedulers
▪ Distribution Operators
▪ Gas Controllers
▪ Energy Accounting & Risk Management
▪ Neighboring utility control centers
▪ RC West Reliability Coordinator
o Technicians
▪ Protection/Control/Metering Technicians
▪ Telecommunication Technicians
o Engineering
▪ Protection/Integration Engineering
▪ Substation Engineering
▪ Generation Engineering
▪ Distribution System Operations
o Enterprise Technology
▪ Oracle Database Administrators
▪ Security Engineering
▪ Network Engineering
▪ Network Operations

2.8.2 Identify any related Business Cases
Not applicable
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The steering committee/advisory group for initial and ongoing vetting and department
priorization process includes the members from the entire SCADA team as needed, but
more notably the following:
- Director of System Operations and Planning
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 194 of 422
-Manager of Energy Management Systems (EMS/DMS)
-Senior System Operations Project Manager
-Sr Security Engineer
3.2 Provide and discuss the governance processes and people that will
provide oversight
Individual projects are governed by the SCADA team member assigned to the project
as project lead who is tasked with scheduling and coordinating all the work associated
with the project.
Project oversight is provided by the SCADA manager primarily, but also to the assigned
project lead.
The steering committee provides governance and oversight of this business case. The
Manager of EMS/DMS has monthly meetings scheduled within the Energy
Management Systems group to track progress of the various capital projects that
comprise the total business case.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision-making, prioritization, and change requests at the individual capital project
level are taken care of within the Energy Management Systems group under manager
supervision.
Any need for substantial change requests to capital projects that would deviate from the
original Capital Project Request (CPR) are documented and submitted to Project
Accounting as a revised CPR. Change requests and resulting decisions that lead to
significant changes in project scope are documented in the project charter
documentation and revisions to the original version and stored in SCADA's SharePoint
site.
Prioritization for each individual project within this business case is performed by the
SCADA manager as part of the on-going updates to SCADA's annual capital budget
spreadsheet. If the sum total of all SCADA capital projects is expected to exceed the
approved Business Case funding, then a Business Case Change Request must be
approved by the Steering Committee and submitted to Project Accounting.
4.APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the SCADA – SOO and BuCC Business
Case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 195 of 422
Signature: Date:
Print Name: Craig N. Figart
Title: Mgr Energy Mgmt Systems
Role: Business Case Owner
Signature: Date:
Print Name: Michael Magruder
Title: Dir Trans Ops & Sys Planning
Role: Business Case Sponsor
Signature: Date:
Print Name: Brad Calbick
Title: Sr Sys Ops Project Mgr
Role: Steering/Advisory Committee Review
Aug 22, 2022
Aug 22, 2022
Aug 22, 2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 196 of 422
EXECUTIVE SUMMARY

This section is reserved to provide a brief description of the business case and high-level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) NEEDS ASSESSMENT- a synopsis of the problem, the current state and recommended solution
2) COST- the cost of the recommended solution
3) DOCUMENT SUMMARY- benefit to the customer
4) RISK- of not approving the business case
5) APPROVALS- who reviewed and approved the recommended solution

<< Both the Executive Summary and Version History should fit into one page >>
Replacing and upgrading major substation apparatus and equipment as it approaches end of
life or becomes obsolete is necessary to maintain safe and reliable operation of Avista's
transmission and distribution systems. Rebuilding significant portions of stations may be
necessary to accommodate the replacement of failing or obsolete equipment since new standard-
use apparatus and equipment is often of higher capacity and newer technology and may need
to meet updated equipment spacing and operating standards.
Failure to replace old and obsolete equipment will increase the risk of more frequent and/or
extended duration of outages due to major equipment failure and inability to maintain major
apparatus. Substation outages may have significant consequences as they tend to impact a
large number of customers. This Business Case is important for customers because it is critical
toward Avista’s ability to continue to provide the reliable electrical service that customers have
grown accustom to receiving.
This Business Case includes the following Expenditure Requests:
• 2000: Substation – Capital Spares
• 2204: Substation Rebuilds
• 2215: Substation Asset Mgmt Capital Maintenance

Service: ED – Electric Direct
Jurisdiction: Various. Each rebuild project has its own Jurisdiction.
Engineering Roundtable Request Number: Various. Each rebuild project has its own ERT
Request.
See the 5-year Funding Request for current budget requests.

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017
2.0 Jeff Schlect maintenance and major rebuild 5/19/2017
3.0 Update to 2020 Template 6/30/2020

DocuSign Envelope ID: 85E42D5F-DEB2-43EA-951A-C3BFC9E2D146
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 197 of 422
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what the project will do and current problem statement]
Replacing and upgrading major substation apparatus and equipment as it approaches end
of life or becomes obsolete is necessary to maintain safe and reliable operation of Avista's
transmission and distribution systems. Rebuilding significant portions of stations may be
necessary to accommodate the replacement of failing or obsolete equipment since new
standard-use apparatus and equipment is often of higher capacity and newer technology
and may need to meet updated equipment spacing and operating standards. While asset
condition is the primary driver triggering the need to replace major apparatus and
equipment, additional factors that may contribute to the need to broaden the scope of a
station rebuild project include operational and maintenance requirements, updated design
and construction standards, SCADA communications, future customer load-service needs,
and other programs (e.g. Grid Modernization).
Major apparatus include high-voltage circuit breakers, lower voltage circuit breakers and
reclosers, circuit switchers, capacitor banks, power transformers and step voltage
regulators. Associated equipment includes relays, meters, surge arrestors, station rock and
fencing, panel houses, instrument transformers, high voltage fuses, air switches,
autotransformer diagnostic equipment, batteries and chargers, and panel houses.
Failure to replace old and obsolete equipment will increase the risk of more frequent and/or
extended duration of outages due to major equipment failure and inability to maintain major
apparatus. Substation outages may have significant consequences as they tend to impact
a large number of customers.
1.1 What is the current or potential problem that is being addressed?
Aging apparatus and equipment plus changes in customer needs and compliance
requirements.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
The major driver of the business case is Asset Condition. Good asset condition leads to
fewer customer outages.
Requested Spend Amount $25,000,000 - $50,000,000 per year
Requested Spend Time Period On Going
Requesting Organization/Department T&D – Substation Engineering
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Program
Driver Asset Condition
DocuSign Envelope ID: 85E42D5F-DEB2-43EA-951A-C3BFC9E2D146
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 198 of 422
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
This is an on-going program to stay ahead of the curve of asset age and condition.
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
General age of all major substation equipment.
System Planning Assessments.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
System Planning Assessments, Maximo Work Orders.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
As of July 2020, here are samples of data we use to view asset information used to
determine viable options for substation rebuilds.

2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
The recommended approach is to replace station apparatus and equipment as needed due
to asset condition and consider broader station rebuilds when the majority of assets in the
impacted area of a station have been determined to have reached their end of life.
This business case aligns with the Company's mission to deliver safe and reliable electric
service to customers by preventing the degradation of reliability and mitigating the
frequency and duration of outages due to equipment failure.
Option 1: Do nothing - Not recommended
Option 2: Maintain current funding level - Current spending on the Asset Condition risk
category is $12.85 million annually. Project prioritization will be supported by Asset
Management and substation subject matter experts for prioritization of work within this risk
category. Project and funding levels will be reviewed on an annual basis.
Option 3: Reduce current Asset Condition capital improvements. Not recommended. May
lead to a reduction in the level of reliability and or operating flexibility that can be achieved
by the transmission and distribution systems.
2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include: - Samples of savings, benefits or risk avoidance estimates - Description of how benefits to customers are being measured - Comparison of cost ($) to benefit (value) - Evidence of spend amount to anticipated return -
DocuSign Envelope ID: 85E42D5F-DEB2-43EA-951A-C3BFC9E2D146
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 199 of 422
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments and Asset Management information.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
Ongoing improvements to the BES via substation rebuilds will result in system reliability,
fewer customer outages and smaller O&M costs.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
Reduce the numbers of capital improvements or Doing Nothing causes equipment to age
and become obsolete and difficult to maintain.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Ongoing average of two rebuilds per year with multiple projects being in various stages of
design, construction and closeout.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
These projects will help Avista stay ahead of the curve of load growth and equipment age
to prevent customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
Customer outages are longer and larger when older equipment fails.
DocuSign Envelope ID: 85E42D5F-DEB2-43EA-951A-C3BFC9E2D146
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 200 of 422
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part of your departmental prioritization process.]
The Engineering Roundtable manages the prioritization of projects within this business
case as supported by Asset Management studies and input from company subject matter
experts. The Engineering Roundtable is comprised of representatives from the following
departments: Asset Management, Compliance, System Planning, System Operations,
Telecommunications, Transmission Contracts, Protection Engineering, Substation
Engineering, Transmission Engineering, and Substation Support.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

DocuSign Envelope ID: 85E42D5F-DEB2-43EA-951A-C3BFC9E2D146
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 201 of 422
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation - Station Rebuild Program
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Date:
Glenn Madden
Manager, Substation Engineering
Business Case Owner

Date:
Josh DiLuciano
Director, Electrical Engineering
Business Case Sponsor

Date:
Damon Fisher
Principle Engineer
Steering/Advisory Committee Review

DocuSign Envelope ID: 85E42D5F-DEB2-43EA-951A-C3BFC9E2D146
Jun-28-2022 | 3:47 PM PDT
Jul-05-2022 | 8:26 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 202 of 422
2022 Transmission Minor Rebuild
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY
The Transmission Minor Rebuild Business Case covers the Transmission rebuild and reconductor work necessary to
maintain compliance with the North American Electric Reliability Corporation (NERC) Reliability Standard FAC-501-
WECC-1 as applied through Avista’s Transmission Maintenance Inspection Program (TMIP) This standard mandates
that specific Transmission lines be inspected annually and assessed for corrective actions to be implemented to
remedy any system performance deficiencies. The TMIP applies the same inspection methodology to the entire Avista
system with the understanding that only a portion of the mitigation work is recognized as Mandatory and Compliance.
The remaining work undertaken within this Business Case is recognized as Failed Plant and Asset Condition.
The implementation of this business case will be considered successful if these projects are all completed on an annual
basis or the dates identified in the Engineering Roundtable Project List.
The Transmission Minor Rebuild Business Case covers the follow-up work to Wood Pole Inspections, Aerial Patrol
inspections, and Ad Hoc ground inspections and Air Switch Replacements.
During routinely scheduled inspections, issues are discovered regarding the condition of assets, including items such
as rotten poles, broken/split/rotten crossarms, broken conductor or ground/shield wire, and air switches that no longer
operate safely or reliably.
The recommended solution is to correct the issues found by these inspections either in the same year, or within 1-2
years afterwards. There are no expected business impacts to continuing this program in place. If Avista does not fully
implement this business case, it runs an increased risk of system failures, customers outages, and wildfires. This
Program will have a Service Code of Electric Direct and a Rate Jurisdiction of Allocated North. An annual spend of
$4,350,000 is needed to complete the mitigations as follows:
• ER 2057, BI AMT12 and AMT13 ($2,000,000): Wood and Steel Pole Inspections (FAC-501-WECC-1, TMIP)
• ER 2057, BI XT902 ($2,000,000): Aerial and ground inspections (FAC-501-WECC-1, TMIP, and Ad Hoc)
• ER 2254, BI AMT10 ($350,000): Planned/unplanned replacements based on failure or upgrade needs
The customer benefits from this Business Case through increased service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 4/28/2022
1.0
1.1
2.0

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 203 of 422
2022 Transmission Minor Rebuild
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6

GENERAL INFORMATION

1. BUSINESS PROBLEM
The Transmission Minor Rebuild Business Case covers the Transmission rebuild and reconductor work
necessary to maintain compliance with the North American Electric Reliability Corporation (NERC) Reliability
Standard FAC-501-WECC-1 as applied through Avista’s Transmission Maintenance Inspection Program (TMIP)
This standard mandates that specific Transmission lines be inspected annually and assessed for corrective
actions to be implemented to remedy any system performance deficiencies. The TMIP applies the same
inspection methodology to the entire Avista system with the understanding that only a portion of the mitigation
work is recognized as Mandatory and Compliance. The remaining work undertaken within this Business Case
is recognized as Failed Plant and Asset Condition.
The Business Case also covers aerial, ground and Ad Hoc patrols intended to pro-actively replace structures
and structure components as riak on near term failure. This work (BI XT902: $2.0M) in previous years was
funded through the Operations Storms blanket Business Case.
1.1 What is the current or potential problem that is being addressed? Avoidance
of failure conditions; that, if left unaddressed in the near-term (<1-2 years) will result in an increased risk
of system failures, customers outages, and wildfires.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Mandatory
& Compliance, combined with Failed Plant and Asset Condition: Customer benefits by having a
Transmission System in compliance with Federal Standards, and one where identified near-term failure
risks are proacitively addressed.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred Unlike Asset Management studies and analysis that develop long-term
facility failure models, the inspection protocols associated with this Business Case identify asset problems;
that, if left unaddressed, will lead to near-term catastrophic structural failures.

Requested Spend Amount $21,750,000
Requested Spend Time Period 5 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Multiple (see Executive Summary)
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 204 of 422
2022 Transmission Minor Rebuild
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. As-Built confirmation of mitigation measures.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Asset Maintenance Wood Pole Management annual inspection reports
Transmission Line Design annual aerial patrol reports
Ad hoc inspections and or real-time notifications from area offices
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 205 of 422
2022 Transmission Minor Rebuild
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Mitigate Deficiencies $21.75M 01-2023 12-2027
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
The benefits of this Business Case are seen in something not happening. Pro-actively addressing near-
term failures results in avoiding public safety risks including physical, electrical, and fire. A portion of this
Business Case was previously funded through an Operations Business Case.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the Execution Stage with spend directed primarily at structure and structure component
change-outs resulting in facility failure avoidance.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform the smaller jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Replacing structures and structure components is presently the only alternative considered.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Smaller projects can take place throughout the year. Most of the large projects take place in the Fall
months and Transfer to Plant in the Novemeber time frame.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 206 of 422
2022 Transmission Minor Rebuild
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista’s Culture of Compliance. This Business Case directly impacts our customer, and places
them as its focus.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Mitigation design solutions performed within PLS-CADD, which is the industry leader in providing
Transmission Line Design computer based programs. Designs are reviewed at multiple stages to ensure
prudency and maximum Stakeholder value.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 207 of 422
2022 Transmission Minor Rebuild
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Minor Rebuild
Business Case Justification Narrative and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/9/2022
Josh DiLuciano
Vice President - Energy Delivery
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 208 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 7
EXECUTIVE SUMMARY
The Transmission Major Rebuild – Asset Condition Business Case covers major rebuilds of transmission
lines due to overall asset condition. Factors such as operational issues, ease of access during outages, and
potential for communications build-out are also considered in prioritizing this work. The projects within this
program are developed through Asset Management’s general analysis of Avista’s Transmission System
facilities that provides a risk based ranking of over 100 Transmission Lines. This ranking is followed up by
line specific studies. Projects are chosen to maximize stakeholder value.
Investments made under this program rebuild existing transmission lines based on overall asset condition.
“Condition” is measured by useful life or the number of condition-related outages. Factors such as operational
issues, ease of access during outages, and need to add automation or communications equipment may be
included in the type of spending in this category. Replacing old and worn-out poles and cross-arms and other
associated transmission equipment, help guard against increasing risk for more failures and outages.
Transmission outages can have significant consequences, as they tend to impact a large number of
customers and have the potential to start fires in dry areas. In addition to reliability issues, failure to properly
invest builds a bow-wave of needed investments in the future, thus this program is crucial to maintaining
operations. When facilities reach an age when it is close to or at the end of its useful life, the Company
preventively replaces it to maintain reliability and acceptable levels of service.
The implementation of this business case will be considered successful if these projects are completed as
planned on time and on budget.
The recommended solution is to rebuild transmission lines as prioritized by the Engineering Roundtable group
to ensure that Avista sufficiently addresses its aging Transmission Line infastructure. There are no expected
business impacts to continuing this program in place. This Program will have a Service Code of Electric
Direct and a Rate Jurisdiction of Allocated North. A spend of $50,000,000 is needed to complete the projects
as follows:
• ER 2629, BI PT108 ($5,500,000): Hatwai-Moscow 230kV Transmission Line Rebuild
• ER 2596, BI LT900 ($44,500,000): Lolo-Oxbow 230kV Transmission Line Rebuild
Avista customers benefit from this Business Case through improved service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 5/02/2022
1.0
1.1
2.0

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 209 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 7

GENERAL INFORMATION

1. BUSINESS PROBLEM
The Transmission Major Rebuild – Asset Condition Business Case covers investments made to rebuild existing
transmission lines based on overall asset condition. “Condition” is measured by useful life or the number of
condition-related outages. Factors such as operational issues, ease of access during outages, and need to add
automation or communications equipment may be included in the type of spending in this category. Replacing
old and worn-out poles and cross-arms and other associated transmission equipment, help guard against
increasing risk for more failures and outages. Transmission outages can have significant consequences, as they
tend to impact a large number of customers and have the potential to start fires in dry areas. In addition to
reliability issues, failure to properly invest builds a bow-wave of needed investments in the future, thus this
program is crucial to maintaining operations. When facilities reach an age when it is close to or at the end of its
useful life, the Company preventively replaces it to maintain reliability and acceptable levels of service.
1.1 What is the current or potential problem that is being addressed?
Transmission outages can have significant consequences, as they tend to impact a large number of customers
and have the potential to start fires in dry areas. In addition to reliability issues, failure to properly invest builds
a bow-wave of needed investments in the future, thus this program is crucial to maintaining operations.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Asset Condition: Customer benefits by having a reliable Transmission System capable of supporting service
needs.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Transmission outages can have significant consequences, as they tend to impact a large number of customers
and have the potential to start fires in dry areas. In addition to reliability issues, failure to properly invest builds
a bow-wave of needed investments in the future, thus this program is crucial to maintaining operations.
Requested Spend Amount $50,000,000
Requested Spend Time Period 5 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 210 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 7
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The implementation of this business case will be considered successful if these projects are completed on time
and within budget. Typical Project Management tracking tools in regards to schedule and budget will be
employed, as well as construction inspection services.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
2016 Lolo-Oxbow 230kV Model Asset Management Plan Rev a.docx
LOL-OXB – model results.pptx
HAT-MOS TT Data Breakdown.xlsx
Palouse (Pullman-Moscow) Transmission Reinforcement Program (2016 Summary).docx
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Below are a few examples of the metric documents developed for this Business Case.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 211 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 7

The Lolo-Oxbow 230kV Line is #1 on the Asset Condition Risk Index. Given the history of outages due to fire,
the time and effort required to mobilize and rebuild in this very remote location, lost revenue during outages,
and the desire by Transmission Planning to upgrade this line to match the Idaho Power Company portion of the
line, it is recommended to pursue the Rebuild and Reconductor Option.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 212 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 7
The Hatwai-Moscow 230kV Line is further down on the Asset Condition Risk Index, but recent Test & Treat data
shows that 20%-25% of the line structures need to be replaced in the very short term. This line is the same
vintage as the Benewah-Moscow 230kV that was rebuild due to Asset Condition in 2018.
2. PROPOSAL AND RECOMMENDED SOLUTION
This is the continuation of an ongoing Program, and requires the replacement of aging infastructure to support
service levels. Please see Alternatives Evaluation within documents referenced in Section 1.6.1, and information
shown in Section 1.6.2 for details.
Option Capital Cost Start Complete
Recommended Solution $50M 01-2023 12-2027
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
The benefits of this Business Case are seen in being able to support overall Asset Management strategies.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
• ER 2629, BI PT108 ($5,500,000): The Hatwai-Moscow 230kV Transmission Line Rebuild Project is
scheduled to design and construct between 2022-2023.
• ER 2596, BI LT900 ($44,500,000): The Lolo-Oxbow 230kV Transmission Line Rebuild Project began
construction in 2020, and will complete in 2027. Used and Useful and Transferred to Plant in
Fall/Winter of each year between 2023 and 2027.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects. Design resources can be supplemented by local consulting services.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Please see documents referenced in Section 1.6.1, and information shown in Section 1.6.2.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 213 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 7
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Please see Section 2.2.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with the Focus Areas of Customers and Perform.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Design solutions performed within PLS-CADD, which is the industry leader in providing Transmission Line
Design computer based programs. Designs are reviewed at multiple stages to ensure prudency and
maximum Stakeholder value.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
3.2 Provide and discuss the governance processes and people that will
provide oversight
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 214 of 422
2022 Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 7
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Major Rebuild –
Asset Condition Business Case Justification Narrative and agree with the approach it
presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/9/2022
Josh DiLuciano
Vice President - Energy Delivery
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 215 of 422
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high-level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included:
1) NEEDS ASSESSMENT- a synopsis of the problem, the current state and recommended solution
2) COST- the cost of the recommended solution
3) DOCUMENT SUMMARY- benefit to the customer
4) RISK- of not approving the business case
5) APPROVALS- who reviewed and approved the recommended solution

<< Both the Executive Summary and Version History should fit into one page >>

The Cabinet 230kV Bus Isolating Breakers Project is comprised of installing two breakers to
isolate the 230kV bus at Cabinet from the GSUs (Generation Step-Up transformers). Several
times in the last few years an issue with a GSU has caused an entire bus outage at Cabinet Gorge
HED which has limited generation output and caused several operational issues. These new
breakers will isolate future GSU issues to just that particular equipment without affecting the whole
bus. This project has been approved and prioritized by the Engineering Roundtable group. This
project is important to customers because it will help to ensure that efficient and affordable clean
energy from hydro-generation units is utilized when available.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-71
Cost of Solution: $2,550,000

VERSION HISTORY
Version Author Description Date Notes
1.0 Initial Version 4/14/2017 Initial Version
2.0 Update to 2020 Template 6/2020

DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 216 of 422
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what the project will do and current problem statement]
Transmission Operations has identified reliability issues with the existing 230 kV circuit
breaker arrangement at Cabinet substation. This is an ongoing issue (last identified in 2011),
but recent outages and reliability history are driving a system correction. The latest redesign
in the late 90’s incorporated the Cabinet Gorge hydro facility into the 230 kV Western
Montana Hydro transmission system, but did not include 230 kV breakers to isolate the
generation from the transmission system, which resulted in one zone of protection
encapsulating both the GSU’s and the 230 kV bus. The deficiency with this design is that it
is not selective enough and drops all 230 kV lines, the 230/115 kV autotransformer and all
Cabinet Gorge generation for issues with the GSU’s. This project proposes a reliability
upgrade to Cabinet substation consisting of a new 230 kV breaker for each GSU, relocating
(2) termination towers and adding new 230 kV bus and GSU relay protection.
The primary issues with the existing arrangement are as follows:
• A GSU fault or mis-operation, which should only isolate a single GSU and two hydro
units (~130 MW), currently clears the 230 kV bus resulting in loss of four hydro units
(~260 MW), loss of both 230 kV lines, generation restrictions at Noxon, triggering a
Remedial Action Scheme (RAS) and the loss of the primary 115 kV source into the
Sandpoint area.
• During a planned outage to the Cabinet-Bronx-SandCreek 115 line, a GSU fault results
in the above mentioned issues plus the loss of all connected 115 kV load and the Cabinet
Gorge primary and backup station service. This leaves Cabinet Gorge on a single diesel
generator.
• A complete plant outage including the loss of Primary and backup station service puts
the plant at risk for over-topping the spill gates and greatly reduces reliable operations
of the plant subsystems due to the reliance on a single diesel generator. This project
does not correct this issue for a 230 bus outage, but corrects it for unplanned GSU
outages.
Requested Spend Amount $2,550,000
Requested Spend Time Period 3 years
Requesting Organization/Department Transmission Operations
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Initiation
Category Project
Driver Performance & Capacity
DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 217 of 422
• Lack of a GSU high side circuit breaker requires unit testing or energization from a single
230 kV line. This requires an outage of the remaining 230 kV line and the
autotransformer and subsequent impacts to those systems.
Seven recent Cabinet outages have resulted in NERC Event Reports. This project would
reduce the average amount of generation lost, reduce the number of Bulk Electric System
(BES) elements impacted and reduce customer load lost per event. The project also reduces
the number of events that require NERC reporting and would better isolate and identify
issues when they occur.
Cabinet unit #1 failed during a full load rejection on April 4th, 2017 due to a Sudden Pressure
Relay misoperation on GSU B. Though unit #1 may have failed under any plant wide full
load rejection, in this instance, a GSU B high side circuit breaker would have isolated the
trip to only units #3 & #4 allowing units #1 & #2 to continue operating though the event. The
estimated lost opportunity cost alone, through the end of 2017 was $2.8M.
Again, two 230 kV circuit breakers should have been installed between the Cabinet 230 kV
bus and the GSU’s for system isolation during plant construction (or during the last
substation improvements). Given they were not in the initial designs, they need to be
included to improve the reliability of these facilities going forward.
1.1 What is the current or potential problem that is being addressed?
A GSU fault causes an outage of the 230kV bus and all hydro units in the Cabinet Gorge
Hydro Electric Dam (HED).
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
Performance & Capacity – Installing breakers to isolate service to smaller portions of the
HED and switchyard to allow for safer performance of the local system.
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
After several ouages it is time to fix this issue so that future outages are avoided.
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
Ability to isolate and control smaller portions of the station will provide the ability to test and
maintain all equipment efficiently.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
Event Reports – refer to System Operations SharePoint Site (non-public information).
Summer and Winter Seasonal Operating Studies – 2205 to present (non-public
information).
DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 218 of 422
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Alternative 1 – Do Nothing / Status Quo:
This alternative is not recommended because it does not mitigate the operational issues and
loss of generation associated with a GSU transformer failure.

Alternative 2 – Install 230kV Bus Isolating Breakers:
This alternative installing two breakers to isolate the 230kV bus at Cabinet from the GSU
transformers. This will isolate future issues with the GSUs and not create an outage on the
entire 230kV bus. This is the recommended alternative.

Alternative 3 – Rebuild Cabinet Substation:
This alternative is not recommended because of physical constraints. The space is very
limited and insufficient to improve the breaker arrangement to any acceptable design without
converting to a cost prohibitive Gas Insulated Bus arrangement ($15M).

Alternative 4 – Build New Switching Station South of the River:
This alternative is not recommended because it is cost prohibitive and does not resolve the
issues identified. This option still requires installing a circuit breaker on the high side of each
GSU, but would add the additional cost of connecting from the existing yard to a new station
south of Cabinet Gorge on the 230 kV corridor ($7M). This does have additional benefits, but
requires the same initial buildout as the recommended solution.

Transmission Operations recommends correcting the initial design at Cabinet substation by
installing (2) new 230 kV breakers (one for each GSU), relocating the (2) existing termination
towers and updating 230 kV bus and GSU relay protection.
Benefits include: 1) increased reliability and reduced exposure to GSU faults and mis-
operations 2) improved Cabinet Gorge availability of primary and backup station service 3)
improved flexibility in operations between the 230 kV bus and each GSU and 4) true isolation
between generation and transmission facilities and operations.
There is no impact to equipment fault duty and this alternative does not result in any
additional equipment issues.
This alternative is the most cost effective option considered and provides the most
operational flexibility, reliability and resiliency. This alternative mitigates identified operational
issues for both Transmission Operations and Generation Operations.
Option Capital Cost Start Complete
DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 219 of 422
2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include: - Samples of savings, benefits or risk avoidance estimates - Description of how benefits to customers are being measured - Comparison of cost ($) to benefit (value) - Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Installing isolating breakers is the most cost effective option.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2021 - $1,500,000
O&M will increase due to the addition of equipment to inspect and maintain but unplanned
major outages will be reduced.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
The outcome of this business case when fully implemented will limit the generation lost due
to other outages thereby improving the generation part of the business.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Design and Construction is scheduled for 2021 and the project will closeout in 2022.
Transfers to plant will complete when breakers are commissioned and in-service.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
Since this is a hydroelectric location, this project will help to provide reliable energy from
generation to transmission line.
DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 220 of 422
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The estimated lost opportunity cost, through the end of 2017 was $2.8M for an outage due
to a GSU misoperation. This project is clearly a prudent investment when the cost of a
single outage could have paid for the project.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part of your departmental prioritization process.]
The Engineering Roundtable is designated as the Steering Committee for this project and
is responsible for prioritization of this project compared to other transmission and substation
requests.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site.

DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 221 of 422
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet 230kV Bus Isolating
Breakers and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Date:
Glenn Madden
Manager, Substation Engineering
Business Case Owner

Date:
Josh DiLuciano
Director, Electrical Engineering
Business Case Sponsor

Date:
Damon Fisher
Principle Engineer
Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: 002223C1-680A-4EEB-87F1-3EDF31310351
Jun-28-2022 | 3:51 PM PDT
Jul-05-2022 | 12:54 PM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 222 of 422
EXECUTIVE SUMMARY
Within the natural gas distribution system of all three states, there are sections of gas pipelines
that are located above grade at crossings such as bridges, small ditches, irrigation canals, etc.
These above grade crossings have a variety of construction techniques and supporting
structures which vary in age, condition, design, compliance, and overall risk. This Business
Case provides capital expenditure for remediating those sites where regular O&M maintenance
activities (e.g. replacement of pipe supports and/or pipe wrap) are no longer adequate. Facilities
needing capital remediation will be identified and prioritized by applying a risk-based scoring
methodology to all known above grade crossing locations. Each identified location will be unique
in how it is remediated and the costs will vary depending on the complexity of the project. These
projects will typically involve either installing new pipe below grade or rebuilding the existing
crossing.

It is recommended to spend $750,000 (plus 3% inflation) per year mitigating these sites. In
general, this is enough to fund one or two large directional drill projects, three to five medium
directional drill projects, or possibly between 10 and 15 small directional drill or rebuilt crossing
projects per year. This mitigation work will ensure our gas pipeline facilities continue operating
with reduced risk, resulting in a safe, compliant, and reliable system for our communities and
customers. If this program is not started, Avista will be at risk of:
• fines from the State PUC’s for being out of compliance with federal safety codes,
• pipeline failures if support structures fail,
• environmental fines if a pipeline failure results in a release of gas, and
• temporary loss of service to downstream gas customers.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial submission of original business
case 7/8/21
2.0 Mike Yang Updated for 2022, used new template 8/26/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 223 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
Within the natural gas distribution system of all three states, there are sections of gas pipelines
that are located above grade. Some of these sites are no longer compliant with current safety
codes and design practices, or the support structures are failing. Like other areas of the gas and
electric system, over the years construction practices have changed due to stricter standards
and improved construction methods. As a result, these above grade crossings have a variety of
construction techniques and supporting structures with varying degrees of risk associated with
each of them.

This Business Case addresses capital expenditures associated with remediating these sites.
Each location will be unique in how it is his corrected and the costs will vary depending on the
complexity of the project. Resolution will typically involve either installing new pipe below grade
using a horizontal directional drill (HDD) method or rebuilding the existing crossing. There are
times when the best solution will be classified as an expense (O&M), in those cases this
program will help risk rank those sites and work with the District Manager to get the work
completed under their O&M plans.

There are several issues that are typical of these sites that needs to be addressed. Each of
these cause Avista to be out of compliance with federal safety standards:
• the pipe wrap may have failed or deteriorated to the point of no longer being effective,
• the support hangers may be dislodged from their support structure (normally a bridge),
• the support hangers may be the style that do not allow a complete inspection for
atmospheric corrosion,
• the pipe may have active atmospheric corrosion,
• the support structure may be failing, and no longer able to provide adequate support for
the gas pipe, or
• the warning signs may be missing.
The Oregon PUC delivered to Avista a Notice of Probably Violation (NOPV) for a bridge
crossing in Roseburg, Oregon in their 2021 safety audit that requires action on the part Avista to
remediate. If we have this program approved and in place, this will show to the PUC in all three
states (OR, WA, and ID) that Avista recognizes the shortcomings and has a plan to address
them.

Requested Spend Amount $750,000 per year
Requested Spend Time Period > 5 years
Requesting Organization/Department Gas Engineering, B51
Business Case Owner | Sponsor Jeff Webb / Mike Yang | Jody Morehouse
Sponsor Organization/Department B51 / Gas Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 224 of 422
In 2019, Gas Engineering assessed all known above grade pipe locations in the state of Oregon
by visiting each site in person, taking pictures, evaluating the condition of the pipe, coating, and
support structures, reviewing the area for possible remediation options, and then finally using a
risk scoring matrix developed with Gas Integrity to risk rank all 162 sites. Of these sites, 34 of
them were classified as high risk, requiring remediation. The plan will be to do a similar review
of the above grade pipe in both Washington and Idaho in 2022 & 2023. That data will then be
added to the existing evaluation matrix, which will be used to determine the project list for each
year. Based on subject matter experts, it is expected that we will have far fewer sites in
Washington and Idaho to remediate then we do in Oregon.

Aboveground piping is required to be inspected once every three years for atmospheric
corrosion per CFR 192.481. To properly inspect for corrosion, the entirety of the pipe must be
available for visible assessment. Some legacy sites have pipe that is installed in a manner that
makes it impossible to do a proper inspection. This program will address this deficiency.

Gas mains in places or on structures with the potential for physical movement (i.e. bridges)
must be patrolled 4 times a year in business districts and 2 times a year outside of business
districts per CFR 192.721. The intent of these patrols is to ensure sound structures and hanging
supports. Some of the sites on the list have hanger systems that are failing due to corrosion or
concrete deterioration, resulting in improper support of gas pipes. This program will address
these deficiencies also.

If the site is remediated by installing the pipe below grade, Avista reduces the O&M expense of
the once every three-year atmospheric corrosion inspection and the quarterly bridge inspection.
Additionally, the Distribution Integrity Management Program (DIMP) will assess a lower risk
score since below grade installation have much less of a chance of being damaged by an
earthquake, flood, or vehicle incident.

1.1 What is the current or potential problem that is being addressed?
Above grade gas pipeline crossings that are not in compliance with federal safety
codes or have been deemed high risk through a risk evaluation performed by Gas
Engineering and Gas Integrity.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver is Mandatory & Compliance. This remediation is necessary to stay in
compliance with CFR 192 safety codes. Customer Service Quality & Reliability and
Asset Condition are additional drivers for remediating high risk above grade piping.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This work is necessary now because we currently have pipeline crossings that are not
in compliance, are at risk of failing, and are at risk of fines from State PUC Safety
Departments.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 225 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Success will be measured by a reduction in the number of sites in need of
remediation from the original 34 on the current risk matrix.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The assessment work conducted by Gas Engineering in 2019 is all stored on the
corporate network drive: c01d44\GASENGINEER\GAS DESIGN
DOCUMENTATION\Engineer Documentation\Heidi Plough\Oregon Above Ground
Crossings
2. PROPOSAL AND RECOMMENDED SOLUTION
It is recommended to spend $750,000 (plus 3% inflation) per year mitigating these sites. In
general, this is enough to fund one or two large directional drill projects, three to five
medium directional drill projects, or possibly between 10 and 15 small directional drill or
rebuilt crossing projects per year. This mitigation work will ensure our gas pipeline facilities
continue operating with reduced risk, resulting in a safe, compliant, and reliable system for
our communities and customers. If this program is not started, Avista will be at risk of:
o fines from the State PUC’s for being out of compliance with federal safety codes,
o pipeline failures if support structures fail,
o environmental fines if a pipeline failure results in a release of gas, and
o temporary loss of service to downstream gas customers.
Below are the top ranked project locations and their initial estimates. These projects total
$2,160k, that’s about three years’ worth of projects averaging $720k per year. Due to the
magnitude of the Rogue River Bridge site, some shifting of funds and projects will need to
happen to ensure timely completion. As we learn more about each of these sites from the
maturing of the designs and permits, the project list may change as appropriate to balance
available funds and risk mitigation.
o Hwy 99 S/Bridge – S Umpqua River – 6” IP Main – $450,000
o Riverside Dr/Bridge – Days Creek – 2” IP Main - $10,000
o 1812 Talent Ave – Canal Crossing – 6” HP Main - $90,000
o 1985 Taylor Bridge #121 – Griffin Creek – 6” IP Main - $100,000
o Washington St/Bridge – S Umpqua River – 6” IP Main - $170,000
o Rogue River Bridge – 10” HP Main - $1,250,000
o S Main Elliot St/Bridge – Canyon Creek – 2” IP Main - $75,000
o 335 Pleasant View Dr – Canal Crossing – 2” IP Main - $15,000

If the program is funded at a lower level, then the risk to the gas system and our customers
will be reduced at a slower pace. The “Do Nothing” option is not a good approach to this
Business Case since we are currently aware of existing deficiencies on our system (listed
above) and have identified parts of the system that are currently in need of remediation to
meet federal safety codes. See below for a breakdown of the risks over time associated
with doing nothing.

Option Capital Cost Start Complete
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 226 of 422
Remediate at a level of $750k/year $750,000 01 2023 TBD
Remediate at a level of $500k/year $500,000 01 2023 TBD
Do Nothing $0 MM YYYY MM YYYY

*Reference Offset Calcs spreadsheet on department drive c01d44:\GASENGINEER\GAS
DESIGN DOCUMENTATION\Budget\Business Cases Updates\ER 3009 Gas Above
Grade Pipe Remediation

2.1 Describe what metrics, data, analysis, or information was considered
when preparing this capital request.

In 2019, Gas Engineering assessed all known above grade pipe in the state of
Oregon by visiting each site in person, taking pictures, evaluating the condition of the
pipe, coating and support structures, reviewing the area for possible remediation
options, and then finally using a risk scoring matrix developed with Gas Integrity to
risk rank all 162 sites. 34 of the sites were classified as high risk, requiring
remediation.
The Oregon PUC delivered to Avista a Notice of Probably Violation (NOPV) for a
bridge crossing in Roseburg, Oregon in their 2021 safety audit that requires action on
the part Avista to remediate. If we have this program approved and in place, this will
show to the PUC in all three states (OR, WA, and ID) that Avista recognizes the
shortcomings and has a plan to address them.

See risk matrix above under Section 2 header and O&M cost offset below under section
2.2 for more metrics, data, and information.

Risk Probability Definitions:
Very High (VH)Risk event expected to occur
High (H)Risk event more likely to occur than not
Probable (P)Risk event may or may not occur
Low (L)Risk event less likely to occur than not
Very Low (VL)Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
1 2 5 10 15+
1 VL L P H VH $225,134 per day per violation (Max)
$2,251,334 Total (Max)
2 VL VL L P H $5,000 to $150,000 per site (site dependent)
3 VL VL L P H $150,000 to $3,000,000 per site (site dependent)
4 VL L P VH VH Erosion of PUC and Public trust
5 VL VL L L P Lost time, healthcare, lawsuits, etc. (varies)
Cost Estimate#
Employee & Public Safety
Risk
Risk Over Time (years)
Regulatory Fines*
Pipeline Leak
Pipeline Failure & Outage
Negative Reputation
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 227 of 422
2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
Capital spend will go directly toward bringing above grade crossings that need
remediation up to current federal safety codes. As described above, if the remediation
project will install the pipe below grade, then the once every three-year atmospheric
corrosion inspections and the quarterly bridge inspections will no longer be required,
resulting in yearly O&M reductions. Expected total cost avoidance over a 15 year
window is about $76,000 in labor and truck costs.
Installing below grade pipe also eliminates periodic future O&M work to repair pipe
coatings and bridge hangers. In addition, installing new above grade piping with
modern coatings and pipe hangers can also reduce the amount of future O&M work
since old hangers and coatings would be eliminated from the system. Expected total
cost avoidance over a 40-year window is approximately $87,500 in labor and
equipment costs.
See below for a breakdown of O&M cost avoidance associated with eliminating
inspections and maintenance. Calc spreadsheet and assumptions for this can be
found on department drive c01d44:\GASENGINEER\GAS DESIGN
DOCUMENTATION\Budget\Business Cases Updates\ER 3009 Gas Above Grade
Pipe Remediation

Cost avoidance due to eliminated O&M inspections (15 years):

Years
Sites
Eliminated
Cost / Site
Visit ($)
Visits per
year per site
Cumulative
Time Saved
over 15 yr
window (HRs)
Cumulative
O&M Cost
Savings over 15
yr window ($)
1 1.80 100.50$ 4 100.8 10,130.40$
2 1.80 100.50$ 4 93.6 9,406.80$
3 1.80 100.50$ 4 86.4 8,683.20$
4 1.80 100.50$ 4 79.2 7,959.60$
5 1.80 100.50$ 4 72.0 7,236.00$
6 1.80 100.50$ 4 64.8 6,512.40$
7 1.80 100.50$ 4 57.6 5,788.80$
8 1.80 100.50$ 4 50.4 5,065.20$
9 1.80 100.50$ 4 43.2 4,341.60$
10 1.80 100.50$ 4 36.0 3,618.00$
11 1.80 100.50$ 4 28.8 2,894.40$
12 1.80 100.50$ 4 21.6 2,170.80$
13 1.80 100.50$ 4 14.4 1,447.20$
14 1.80 100.50$ 4 7.2 723.60$
15 1.80 100.50$ 4 0.0 -$
75,978.00$
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 228 of 422

Cost avoidance due to eliminated O&M repair work (40 years):

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Instead of having each individual Operations District review, manage, and prioritize
above grade piping projects within their respective areas, this new business case will
centralize that responsibility under Gas Engineering. This includes both capital
projects covered under this new business case as well as O&M projects historically
managed under each individual district. This will ensure that above grade piping
projects (both O&M and Capital) across all three states of Avista’s territory are
consolidated together, prioritized against each other, and then funded appropriately
according to risk. Each Operation Districts will still be expected to help coordinate
and complete the work assigned to each area, which does not differ from existing
processes.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Since the identified above grade pipe in need of remediation does not currently meet
federal safety codes, the only way to address this risk is to remediate each of the
crossings. Each location is unique and will be analyzed to determine the best
Years
Sites
Eliminated
w/ BG Pipe
Sites
Remediate
d w/ AG
Pipe
Future O&M
Cost /
Maintenance
Visit ($)
O&M Time
Saved over
next 40
years (HRs)
Cumulative
O&M Cost
Savings over
next 40 years
($)
1 1.80 1.80 1,080.00$ 43 5,832.00$
2 1.80 1.80 1,080.00$ 43 5,832.00$
3 1.80 1.80 1,080.00$ 43 5,832.00$
4 1.80 1.80 1,080.00$ 43 5,832.00$
5 1.80 1.80 1,080.00$ 43 5,832.00$
6 1.80 1.80 1,080.00$ 43 5,832.00$
7 1.80 1.80 1,080.00$ 43 5,832.00$
8 1.80 1.80 1,080.00$ 43 5,832.00$
9 1.80 1.80 1,080.00$ 43 5,832.00$
10 1.80 1.80 1,080.00$ 43 5,832.00$
11 1.80 1.80 1,080.00$ 43 5,832.00$
12 1.80 1.80 1,080.00$ 43 5,832.00$
13 1.80 1.80 1,080.00$ 43 5,832.00$
14 1.80 1.80 1,080.00$ 43 5,832.00$
15 1.80 1.80 1,080.00$ 43 5,832.00$
40 year cost avoidance = 87,480.00$
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 229 of 422
remediation approach. The lower funding alternative option slows the pace of
remediation and the resultant reduction of known risk in the system. The do nothing
approach results in no risk reduction, and leads to additional risk to Avista, including:
o fines from the State PUC’s for being out of compliance with federal
safety codes,
o pipeline failures if support structures fail,
o environmental fines if a pipeline failure results in a release of gas,
and
o temporary loss of service to downstream gas customers.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
Projects will be started each year, and in most cases will be complete within a year of
beginning. Some sites may require unique permitting or specialty equipment that may
extend that project timeline beyond a year. Once construction begins, an individual
project will typically be completed (i.e. used and useful) within the same calendar
year.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Avista has a value of being Trustworthy, that means we do what’s right. The right
thing to do is take care of the pipeline facilities, make them as reliable as possible,
keep the public safe, and ensure our facilities are not out of compliance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
A funding level of $750,000 for the first several years will get this program underway.
At this level, the current staffing of Engineers is adequate to support the program
without having to contract out any of the design work. On an annual basis, this
program will be compared to other Gas Programs to ensure the company is focusing
on our highest risk areas.

Reference 5-year planning document for more detail. This can be found on
department drive c01d44:\GASENGINEER\GAS DESIGN
DOCUMENTATION\Budget\Business Cases Updates\ER 3009 Gas Above Grade
Pipe Remediation

2.8 Supplemental Information

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 230 of 422
2.8.1 Identify customers and stakeholders that interface with the business case
Gas Engineering, District Operations support individuals (CPC’s and Inspectors),
Contracts, and Drafting are the main groups impacted by this program.

2.8.2 Identify any related Business Cases
None.

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
This program will be administered by an Engineer within Gas Engineering. The
program’s spend and budget will be reviewed monthly by the Gas Engineering
Prioritization Investment Committee (EPIC). The Engineer will ensure the highest risk
projects are completed first.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The manager of Gas Engineering will provide oversight to the program.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Monthly budget changes will be documented via the existing CPG process, approved
by the Manager of Gas Engineering and the Director of Natural Gas. The monthly
Gas EPIC updates are captured via email.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Above Grade Pipe
Remediation Program and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date: 9/1/22
Print Name: Jeff Webb / Mike Yang
Title: Mgr Gas Engineering
Role: Business Case Owner

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 231 of 422
Signature: Date:
Print Name: Jody Morehouse
Title: Director of Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/1/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 232 of 422
EXECUTIVE SUMMARY
Cathodic Protection (CP) systems are used to stop corrosion on buried steel gas pipes.
CP system compliance is mandated by Federal Rules within the Department of
Transportation code 49 CFR 192, Subpart I. Some CP systems have been in service at
Avista for extended periods of time, they have exceeded their useful service life, and
are no longer functional (or are showing signs of imminent failure). These conditions
warrant a replacement of those systems. It is often difficult to predict in advance when
specific projects are required, because sudden component failures do occur. Anodes, a
key component of the CP systems, are buried and not observable, they deteriorate at
differing rates, and can become ineffective when they are physically depleted. The
estimated annual cost for this budget is based on past expenditures. Because of the
unpredictable nature of these projects, it is not always known in advance how much of
the funding will be allocated to each state.

Additional expenditures in this budget include the installation of system testing and
monitoring equipment. These new technologies allow for remote monitoring and control
of the CP systems. They alert technicians to system failures and reduce the number of
trips needed to check system status.

VERSION HISTORY
Version Author Description Date Notes
1.0 Tim Harding Initial version 4/03/2017
1.1 Jeff Webb 4/4/2017
2.0 Tim Harding Revision for 2020 Oregon GRC
filing
2/17/2020

2.1 Tim Harding Updated to the refreshed 2022
Business Case Template
8/31/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 233 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The majority of this budget is used to install new cathodic protection (CP) anode
beds. The sacrificial anodes are consumed as part of the CP process and the
service life of one of these installations is approximately 20-30 years. There are
approximately 250 anode beds installed across our service territory.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The main drivers for this business case are Mandaroty & Compliance and Asset
Condition. Properly functioning cathodic protection systems are required by
federal code. This code requires the systems to operate within specific
parameters. Those parameters can only be met when the CP systems are
regularly maintained and replaced when the anodes are depleted.
Even if CP systems were not required by code, Avista would install them. They
greatly reduce pipe corrosion and the chance of gas leaks. The cost to install,
operate, and maintain a CP system is a small fraction of the financial benefit it
provides. At a low relative cost, Avista is able to protect hundreds of millions of
dollars worth of steel pipe infrastructure from corrosion, extending its useful life for
decades.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The operations of Avista’s CP systems are largely governed by code requirements.
Not performing this work will put Avista out of compliance with state and federal
codes. This will result in system integrity risks, as well as regulatory fines.
Requested Spend Amount $715,000
Requested Spend Time Period Annually
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Tim Harding | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 234 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Avista tests and monitors the CP systems in accordance with State and Federal
code. The results of this testing indicate what CP systems are deficient and
therefore require equipment installation. A potential measurement to use to gauge
the success of the program is to track code violations.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Project information is tracked by Gas Engineering. System maintenance
records are housed in Maximo. Information is available upon request.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Anode beds get installed for two reasons. The first is to replace an existing
anode bed that has failed. The second reason is to increase the available
amount of cathodic protection current available. Additional current is required
as the pipe coating degrades over time. Anode beds have a design life of
approximately 25 years. With 250 anode beds in the system it would be
expected that approximately 10 are replaced every year. Only 7 have been
replaced in the last 5 years. This implies the anode beds are being replaced
at 1/8 the expected rate. During the last 5 years 21 new anode beds were
added to meet the increasing current requirement.
This information above should illustrate two points. First, anode beds are
being replaced at a fraction of the expected rate. This implies there will be a
time in future when failure rates will increase and more replacements will be
needed each year. The second point to note is that the steel pipe in our gas
systems, most installed in the 1950’s and 1960’s, has coating that is
continuing to degrade. More anode beds will continue to be required to meet
the growing current demand.
2. PROPOSAL AND RECOMMENDED SOLUTION
The requested level of spending is the lowest cost option to keep these systems
functioning and compliant with state and federal code. As mentioned in the above
section, equipment replacement rates are nearly an order of magnitude lower than
expected. All of these anode beds will eventually fail and more analysis should be
done to predict when that will happen. At some point in the future, failure rates will
grow rapidly. A proactive approach that replaces the oldest or poorest performing
anode beds would spread replacement costs out more evenly in the future and help
avoid a future surge in failures.
Option Capital Cost Start Complete
Recommended Solution, Replace equipment when
it fails, and add new equipment to keep the system
$715,000 January December
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 235 of 422
in compliance
Alternative Solution, Replace equipment when it
fails, and add new equipment to keep the system in
compliance. Proactively replace aging anode beds
to avoid a future rush of replacements.
$1.2M January December
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The requested amount is based on recent program spending. Expenditures
are to replace failed equipment or to add new equipment to maintain system
compliance. Since the actual spending requirement for each year cannot be
predicted, mid-year adjustments are common.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Approximately 80% of the budget will be spent on anode bed replacements.
The remaining 20% of the budget will be spent on the installation of new and
replacement test stations and monitoring equipment.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Properly operating CP systems reduce corrosion and corrosion leaks. It also
extends the life of the gas system. This has in impact on Gas Operations and
Compliance departments.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Per Federal code, CP systems are required on all buried steel gas pipes. The
only alternative is to replace all steel piping with plastic pipe. A project like this
would cost well over $1 billion.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
Anode beds are typically installed in the summer and fall. These projects will
take between one week and two months. They become used and useful
immediately at the end of the project. Special projects are undertaken some
years. These can include the installation of test stations, and remote
monitoring equipment. Those assets become used and useful when the final
installation is complete, typically in Q4.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 236 of 422
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely, and
reliably at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This budget primarily funds the installation of new and replacement anode
beds. Cathodic protection systems are required by federal code, and the
criteria under which they must be operated is specified in that code. Testing is
performed on these systems annually. Any systems deficiencies must be
addressed to remain in compliance.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Cathodic protection is a program that happens ‘behind the scenes’ and does
not involve customer interaction. Customers benefit from the improved system
safety, reliability, and longer asset service life.
Stakeholders include Gas Engineering, Gas Operations, and the Cathodic
Protection group.
2.8.2 Identify any related Business Cases
N/A
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The General Foreman of the Cathodic Protection group oversees projects done by
the group. This program will be monitored by an Engineer within Gas Engineering.
The program’s spend and budget will be reviewed monthly by the Gas Engineering
Prioritization Investment Committee (EPIC), and annual the 5-year plan is
reviewed.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed by the Cathodic Protectoin group and approved by the
General Foreman. Gas Engineering sets up project accounts and reviews
program spending on a monthly basis.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 237 of 422
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The General Foreman has the final say on project prioritization. These decisions
are based on 30 years of experience in the field of cathodic protection.
Monthly budget changes will be documented via the existing CPG process,
approved by the Manager of Gas Engineering and the Director of Natural Gas. The
monthly Gas EPIC updates are captured via email.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cathodic Protection
Program, ER 3002, and agree with the approach it presents. Significant changes
to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date: 8/31/22
Print Name: Jeff Webb / Tim Harding
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 238 of 422
EXECUTIVE SUMMARY

In February 2012, Avista’s Asset Management Group released findings in the “Avista’s Proposed Protocol
for Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report. The report documents
specific Aldyl-A pipe in Avista’s natural gas pipe system, describes the analysis of the types of failures
observed, and the evaluation of its expected long-term integrity. The report proposed the undertaking of a
20-year program to systematically replace select portions of Aldyl-A medium density pipe within its natural
gas distribution system in the states of Washington, Oregon, and Idaho. This targeted Aldyl-A pipe will
eventually reach a level of unreliability that is not acceptable due to the tendency for this material to suffer
brittle-like cracking leak failures. There is a potential harm to the public through damage to life and property
and there is a high likelihood of increasing regulatory scrutiny from increasing failures. Not approving or
deferring this body of work would further exacerbate the risks.
Avista has a regulatory mandate to complete this program and has a goal of investing in its infrastructure
to achieve optimum life-cycle performance. The Gas Facility Replacement Program (GFRP) was approved
by the Vice President of Energy Delivery and was initiated in 2012 and is planned to continue for 20 years
(until the end of 2031). It is the sole mission and charter for the GFRP to plan and execute the replacement
of 737 miles of Aldyl-A main pipe and to rebuild over 18,000 service tee transitions throughout Avista’s
service territories. The Aldyl-A main pipe replacement work includes Aldyl-A pipe that is 1-1/4” diameter
through 4” diameter and with an install date prior to January 1, 1987, or a manufactured date prior to
January 1985. The historical spending trend from 2016 through 2022 has been $20M-$23M annually and
is reflective of the program’s most recent cost experience updates. The requested budget amounts
consider Avista’s regulatory mandate to complete this program with full contractor complement and to adjust
for the mileage that was not completed in 2020 and be in alignment with Distribution Integrity Management
Program’s (DIMP) prioritization recommendations. This also meets Avista’s goal of investing in its
infrastructure to achieve optimum life-cycle performance. GFRP paid inflation of 7% in 2022. Inflation of
5% has been planned for escalating annual costs during 2023-2027.

VERSION HISTORY
Version Author Description Date Notes
Draft Michael Whitby Initial draft of original business case 2011
1 Michael Whitby Budget Change 2015 Additional $1.8M approved
2 Michael Whitby Budget Change 2016 Additional $3M approved
3 Michael Whitby Budget Change 2017 $2M deferred to 2018
4 Michael Whitby Budget Change 2018 $1M deferred to 2019
5 Michael Whitby Budget Change 2019 $1.5M deferred to 2020
6 Karen Cash Budget Change 2020 $1,035,000 deferred to 2021
7 Karen Cash Budget Change 2020 $1,000,000 deferred to 2021
8 Karen Cash Budget Change 2020 $500,000 deferred to 2021

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 239 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
For Avista, aside from third party excavation damage, the highest risks within our natural gas
distribution system is Aldyl-A Main Pipe (Manuf. 1964-1984), and the bending stress that occurs on
Aldyl-A service pipe where it is connected to steel main pipe.
GFRP was initiated in 2012 and is planned to continue for 20 years (until the end of 2031). It is the
sole mission and charter for the GFRP to plan and execute the replacement of 737 miles of Aldyl-A
main pipe and to rebuild over 18,000 service tee transitions. The Aldyl-A main pipe replacement
work includes Aldyl-A pipe that is 1-1/4” diameter and great and with an install date prior to January
1, 1987, or a manufactured date prior to January 1985.
The GFRP’s Service Tee Transition Rebuild (STTR) Program was structured to mitigate the risks
associated with the “Bending Stress Services” category within a 5-year time frame. The STTR
Program started in 2013 and was deemed substantially complete in December 2017.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Avista has a regulatory mandate to complete this program and has a goal of investing in its
infrastructure to achieve optimum life-cycle performance.
As of August 2011, the US Department of Transportation Pipeline and Hazardous Materials Safety
Administration (PHMSA) mandates gas distribution pipeline operators to implement Integrity
Management Plans, or in Avista’s case, a Distribution Integrity Management Plan (DIMP) in which
pipeline operators are required to identify and mitigate the highest risks within their system. For
Avista, aside from third party excavation damage, the highest risks within our natural gas distribution
system is Aldyl-A Main Pipe (Manuf. 1964-1984), and the bending stress that occurs on Aldyl-A
service pipe where it is connected to steel main pipe.
More specifically, and as related to the risks identified above, in February 2012 Avista’s Asset
Management Group released findings in the “Avista’s Proposed Protocol for Managing Select Aldyl-
A Pipe in Avista Utility’s Natural Gas System” report. The report documents specific Aldyl-A pipe in
Avista’s natural gas pipe system, describes the analysis of the types of failures observed, and the
evaluation of its expected long-term integrity. The report proposed the undertaking of a 20-year
program to systematically replace select portions of Aldyl-A medium density pipe within its natural
gas distribution system in the states of Idaho, Oregon, and Washington.
Requested Spend Amount $29,000,000 - $32,000,000 Annually
Requested Spend Time Period 9 years (2023 through 2031)
Requesting Organization/Department Natural Gas / Gas Facility Replacement Program
Business Case Owner | Sponsor Karen Cash / Jody Morehouse
Sponsor Organization/Department Energy Delivery / Natural Gas
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 240 of 422
Subsequently, the Gas Facility Replacement Program’s (GFRP) was formed as the operational entity
committed to structuring and implementing a systematic approach to mitigating the Aldyl-A pipe risks
as identified in aforementioned report.
On December 31, 2012 the Washington Utilities and Transportation Commission (WUTC)
issued its policy statement on Accelerated Replacement of Pipeline Facilities with Elevated Risks
which requires gas utility companies to file a plan every two year for replacing pipe that represents
an elevated risk of failure. The requirement to file a Pipe Replacement Plan (PRP) commenced on
June 1, 2013. In response to this order, Avista’s first 2-year PRP for 2014-2015 was submitted and
approved in 2013 per Docket PG-131837, Order 01. Avista’s second two-year PRP for 2016-2017
was submitted in 2015 and approved in 2016 per WUTC Docket PG-160292, Order 01. Avista
submitted a PRP in June 2017, and 2019.In Avista’s filings, the “Avista’s Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report serves as the pipe
replacement “Master Plan”, and two year pipe replacement goals which includes specific project
locations, and the anticipated pipe replacement quantities.
On March 6, 2017 the Oregon Public Utilities Commission (“Commission”) issued Order 17-084
(Docket UM 1722, Investigation into Recovery of Safety Costs by Natural Gas Utilities), which in part
required each of the natural gas distribution companies serving customers in Oregon to file with the
Commission by September 30th each year an annual “Safety Project Plan” (or Plan).1 The purpose
of the Plan is to increase transparency into the investments made by each utility that are based
predominantly on the need to achieve important safety objectives. More specifically, the Plan is
intended to achieve the following objectives:

• Explain capital and expenses needed to mitigate safety issues identified by risk analysis or new
federal and state rules;

• Demonstrate the utility’s safety commitment and priority to its customers;

• Provide a non-technical explanation of primary safety reports each utility is required to file with
the Commission’s pipeline safety staff; and

• Identify major regulatory changes that impact the utility’s safety investments.

The Idaho Public Utilities Commission (IPUC) has not required gas utility companies to submit an
action plan, Avista has submitted the “Avista’s Proposed Protocol for Managing Select Aldyl-A Pipe
in Avista Utility’s Natural Gas System” report for review, and communicates annual pipe replacement
goals which includes specific project locations, and the anticipated pipe replacement quantities.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
To ensure Avista fulfills the regulatory mandate to complete this program.
The need to conduct this program has been identified in “Avista’s Proposed Protocol for Managing
Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report. Further, and more specifically, due
to the tendency for this material to suffer brittle-like cracking leak failures, Aldyl-A will eventually
reach a level of unreliability that is not acceptable. There is a potential harm to the public through
damage to life and property and there is a high likelihood of increasing regulatory scrutiny from
increasing failures. Not approving or deferring this body of work would further exacerbate the risks
as identified above.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 241 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The objective of this investment and structured replacement program is to reduce risk by replacing
at risk pipe and by rebuilding Service Tee Transitions. Through rigorous Project Management efforts,
the GFRP plans and tracks the performance of the projects, and utilizes Earned Value for cost
analysis and for upstream reporting. Further, the GFRP tracks and reports Planned vs. Actual
quantities by project, by year, by state jurisdiction, and also reports multi-year cumulative statistics.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
a. On December 31, 2012, the Washington Utilities and Transportation Commission
(WUTC) issued its policy statement on Accelerated Replacement of Pipeline Facilities
with Elevated Risks which requires gas utility companies to file a plan every two years
for replacing pipe that represents an elevated risk of failure. The requirement to file a
Pipe Replacement Plan (PRP) commenced on June 1, 2013.
b. February 23, 2012 – Avista Utilities Asset Management “Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utilities’ Natural Gas System”
c. April 11, 2013 - Revised Avista Utilities Asset Management “Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utilities’ Natural Gas System”
d. July 2013 – ARMS Reliability Report – Avista Study of Aldyl-A Mainline Pipe and
Bending Stress Point Leaks
e. Avista’s first 2-year PRP to the WUTC for 2014-2015 was submitted and approved in
2013 per Docket PG-131837, Order 01.
f. Avista’s second 2-year PRP to the WUTC for 2016-2017 was submitted in 2015 and
approved in 2016 per WUTC Docket PG-160292, Order 01.
g. Order of the Public Utility Commission of Oregon in Docket UM 1722, Investigation into
Recovery of Safety Costs by Natural Gas Utilities. March 6, 2017.
h. Avista’s Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility’s Natural
Gas System report serves as the pipe replacement “Master Plan”, and two year pipe
replacement goals which includes specific project locations, and the anticipated pipe
replacement quantities.
i. April 2018 – ARMS Reliability Report - Avista Study of Aldyl-A Mainline Pipe Leaks 2018
Update

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The chart below identifies the expected number of material failures in Avista’s Priority
Aldyl-A piping in two cases: Replacement Case – piping replaced over a 20-year time
horizon, and Base Case – assumed that priority piping was not remediated under any
program.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 242 of 422

As shown in the graph below and outlined in “Forecasting Results” section of “Avista’s Proposed
Protocol for Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report, Avista’s
forecast modeling tool “Availability Workbench Modeling” evaluates several classes of pipe which
are represented as “curves” showing the percentage of the amount of pipe class that is projected to
fail in each year of the forecasted time period.

2. PROPOSAL AND RECOMMENDED SOLUTION
“Avista’s Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System”
report details the various time horizons modeled for the Aldyl-A Pipe Replacement program.
The Aldyl-A Pipe Replacement effort has been proposed and planned as a systematic 20-year pipe
replacement program. The program is expected to have a nominal impact to existing business
resources, functions, and processes since the GFRP has been structured to function as a “stand alone”
program consisting of dedicated “internal” resources. The primary functions established for these
internal resources are to plan, design, oversee, manage, and administer the significant body of
projectized work as assigned to “external” contract construction resources.
Periodically, on an as-needed basis, the GFRP will call on other business units for support.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 243 of 422
Since pipe replacement work is a capital expenditure, the impact to O&M cost has been minimal.
Occasionally GFRP projects will encounter circumstances that necessitate O&M expenditures. When
known, these O&M costs are estimated prior to construction. The GFRP tracks and monitors O&M
costs monthly.
Option Capital Cost Start Complete
Replace priority high-risk Aldyl-A pipe in a 20-year
timeframe
≈ $443M January
2012
December
2031

The 2013 Avista Study of Aldyl-A Mainline Pipe Leaks was updated in 2018 based on the upon leaks
and replacements through the end of 2017. The original study developed failure distributions that
described the likelihood of leaks occurring on the Aldyl-A pipe installed by Avista for natural gas
distribution and to evaluate multiple replacement scenarios. According to the table below the
baseline scenario remains more cost effective when compared to the replacement strategies.

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

The 2013 Avista Study of Aldyl-A Mainline Pipe Leaks was updated in 2018 based on the upon leaks
and replacements through the end of 2017. The study incorporated leak reduction and risk avoidance
in the analysis.

After updating the model with leaks and replacements from 2013-2018 the expected number or leaks
for the remaining period (2018-2088) reduced from 26,792 to 12,335 due to the large amount of the
worst pipe already replaced. If the 20-year replacement program where all Aldyl-A pipe is removed
continues there is a slight reduction in the expected number of leaks, 255 in the original study and
246 in the updated model.

Safety risks and criticality were also considered as part of the study update. It is understood that each
failure event (leak) does not always result in an injury and this is incorporated as a percentage of
events that result per Avista standard modeling guidelines. The severities used are shown in table
below. The projected number of catastrophic events drop from 258 to 5 events over the next 70 years
by replacing the Aldyl-A pipe.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 244 of 422

While Avista's 20-year structured replacement program has proven to reduce the highest risk in the
early years of the program, the continuation of this structured replacement program is both necessary
and prudent to mitigating the remaining risks within the system, and to achieving Avista's goal of
operating and maintaining a safe and reliable natural gas distribution system.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

Over the duration of the 20-year program, the GFRP will conduct replacement and rebuild work in
virtually every gas district across Idaho, Oregon, and Washington, with large concentrations of Aldyl-
A pipe occurring in the metropolitan centers of Spokane, Washington, Medford, Oregon, and Coeur
d’Alene, Idaho. Based on the scope of work and schedule, the GFRP will plan and manage more
than 100 Major Capital Projects as follows:

Category Type Quantity Duration Project Count
Major Main Pipe 737 miles 20 years ~ 105
Major STTR 17,769 service tees 5 years (Completed) ~20

The 2013 study predicted a total of 26,792 leaks on Aldyl-A mainline pipe from 2018 through 2088
years without any form of a proactive replacement program. Based upon the proactive replacements
that have occurred, the number of leaks predicted over the same period has reduced to 12,335 with
246 catastrophic events if the proactive replacement were to not continue. With the current
replacement of all Aldyl-A pipe by 2035, the number of predicted leaks from 2018 to program
completion reduces slightly, moving from 255 to 246 leaks of which 4 have the potential to be
catastrophic events. The offsets to the GFRP, include but not limited to, regulatory fines, pipeline
leaks, pipeline failures and outages, negative company reputation, and elevated safety concerns.
See below for a list of the relevant pipeline safety regulations pertaining to the GFRP, as well as a
breakdown of each risk over time assuming nothing is done to remediate the Aldyl-A pipe.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 245 of 422

Risk Avoidance Over Time and the Potential Cost of the "Do Nothing" Option:

*Regulatory fines present a daily and overall maximum value per violation in accordance with 49 CFR Part
190.223. However, these values are not necessarily an accurate representation of how much Avista would
be fined for any specific violation. The actual amount is at the discretion of the enforcement agency and is
likely to be much lower due to Avista’s ongoing reputation and history of investing in programs related to
safety and non-compliance issues. However, it is a bookend reminder from which to characterize the
regulatory risk associated with chronic and/or egregious non-compliance, especially in the event of a pipeline
safety incident (i.e. failure). Therefore, Avista must continue to demonstrate an ongoing commitment to
compliance and pipeline safety to ensure favorable future outcomes with respect to regulatory penalties.
It has been determined that this type of pipe is at risk and is approaching unacceptable levels or reliability
without prompt attention. The “Do Nothing” option exposes Avista to increased operational risks, decreased
system reliability, and worse, is a potential harm to customers and the public through damage to life,
property, and the environment. There would be a high likelihood of legal action against Avista, regulatory
fines, and negative reputation. The Aldyl-A pipe will eventually reach a level of unreliability that is not
acceptable due to the tendency for this material to suffer brittle-like cracking leak failures. There is a potential
harm to the public through damage to life and property and there is a high likelihood of increasing regulatory
scrutiny from increasing failures. Not approving or deferring this body of work would further exacerbate the
risks as identified above. GFRP would not be able to address some of the highest risk/threats in the natural
gas distribution system by reducing the incident and leak rates. Per the “Avista Study of Aldyl-A Mainline
Pipe Leaks 2018 Update”, which covered the entire program in Idaho, Oregon, and Washington, based upon
the proactive replacements that have occurred, the number of leaks predicted from 2018 through 2088 has
reduced to 12,335 with 246 catastrophic events if the system-wide proactive replacement were to not
continue. With the current replacement of all Aldyl-A pipe by 2035, the number of predicted leaks from 2018
to program completion reduces slightly, moving from 255 to 246 leaks of which 4 have the potential to be
catastrophic events. Assumptions made during the study were as follows:

• Planned replacement of Aldyl-A Mainline pipe costs $357 per three feet in Washington
and Idaho and $360 per three feet in Oregon.
• Unplanned replacement of Aldyl-A Mainline pipe costs $5,071 per three-foot section.
• Consequences for a Catastrophic Event, Injury with lost time and injury without lost time
are applied per Avista standard practice.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 246 of 422
At Avista we forecast Capital Projects/Programs on five-year budget planning cycles which are
updated and adjusted annually. In order to provide the most accurate budget forecasts possible it is
necessary to draw from the program’s most current cost data which is tracked and derived from
recently completed projects. The historical spending trend from 2016 through 2021 has been $20M-
$23M annually and is reflective of the program’s most recent cost experience updates. The
requested budget amounts consider Avista’s regulatory mandate to complete this program with full
contractor complement and to adjust for the mileage that was not completed in 2020* and be in
alignment with Distribution Integrity Management Program’s (DIMP) prioritization recommendations.
This also meets Avista’s goal of investing in its infrastructure to achieve optimum life-cycle
performance. GFRP paid inflation of 7% in 2022. Inflation of 5% has been planned for escalating
annual costs during 2023-2027.
The following tables show the multi-year performance by state for main replacement from 2012 through
2021. Washington is at 93%, Oregon is 68%, and Idaho is 116% of completed main replacement. Overall
the Program has completed 102.1% (difference of 5.1 miles) of the planned main replacement.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 247 of 422

*There were several impactful events that were outside Avista’s control which led to the program
deferring $2,535,000 to 2021. Early part of 2020, the COVID-19 pandemic struck the nation and
only essential work was able to continue. The NPL union employees went on strike starting on
July 6, 2020 and the strike ended on August 26, 2020. Starting on September 8, 2020, in
Jackson County Oregon, wildfires blazed in in the Ashland – Alameda Drive area. There were
wildfires throughout Oregon (see map below). The wildfires spread due to high winds and the
smoke created poor air quality conditions. The outcome of these events in Oregon was the
completion of only 2.6 miles of the planned 15.1 miles by NPL.

0.0
10.0
20.0
30.0
40.0
50.0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
PLANNED vs COMPLETED (ALL STATES)
PLANNED MAIN COMPLETED MAIN
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 248 of 422
In order to meet maintain optimal production with current personnel levels and account for
approximately $3M a year for Minor Main/STTRs/Priority Services, and outlying municipal projects,
below is the proposed mileage by state from 2023 through 2027.

Based on the proposed mileage by state from 2023 through 2027, the estimated cost per mile by
state and by year is shown below. Variations of the Cost/Mile are due to project location. For
example, if a project requires significant Mobilization, Demobilization, crew travel expense, urban or
rural locale, etc.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Unplanned leak repairs are an O&M cost and are addressed by the local districts. Through this
program, O&M expenses are mitigated. The 2013 study predicted a total of 26,792 leaks on Aldyl-
A mainline pipe from 2018 through 2088 years without any form of a proactive replacement program.
Based upon the proactive replacements that have occurred, the number of leaks predicted over the
same period has reduced to 12,335 with 246 catastrophic events if the proactive replacement were
to not continue.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.

To establish context, Avista’s goal is operate a safe & reliable, and cost-effective gas distribution
system. Specifically, as related to these goals, § XI of “Avista’s Proposed Protocol for Managing
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 249 of 422
Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report details the various time horizons
modeled for the Aldyl-A Pipe Replacement program.
To summarize, the primary alternatives modeled are as follows:
• Do Nothing
Pipe Replacement Strategies:
Since the “do nothing” option was not an acceptable or prudent approach, the Company evaluated
different periods of time for removal of all Priority Aldyl-A pipe, up to a program horizon of 30 years.
Avista assessed the prudence of different approaches based on the forecast of likely natural gas
leaks due to failed pipe, as well as the rate impact to customers.
• Less than 20 Year Pipe Replacement Program
• Conduct a 20 Year Pipe Replacement Program (Optimal)
• Conduct a 25+ Year Pipe Replacement Program
Based on the time horizon scenarios modeled, it was determined that the optimum timeframe for
removing priority Aldyl-A pipe was the 20 years.
RISKS ASSOCIATED WITH ALTERNATIVES CONSIDERED:
To summarize the primary alternatives and associated risks;
• Do Nothing:
It has been determined that this type of pipe is at risk and is approaching unacceptable levels
of reliability without prompt attention. The “Do Nothing” option exposes Avista to increased
operational risks, and worse, is a potential harm to our customers and the public through
damage to life and property, and a high likelihood of legal action against the Company and
likely regulatory fines. For this reason it was deemed “not prudent” and is not a serious
consideration.
• Less than 20 Year Pipe Replacement Program:
Avista found that a timeline less than 20 years resulted in a greater cost impact to customers
in the near term, and that it did little to reduce the forecast number of leaks expected each
year. This approach did not effectively optimize the potential risks and rate impacts.
• Conduct a 20 Year Pipe Replacement Program:
The report proposes and suggests that a Systematic Replacement Program conducted over
a 20 year timeline is the optimum timeframe to prudently manage this risk, based on the
forecast number of leaks and risks, and the rate impact to our customers.
• Conduct a 25+ Year Pipe Replacement Program:
Lengthening the timeframe to 25 years resulted in more than a doubling of the number of
leaks expected when compared to a 20-year horizon. Lengthening the timeline beyond 25
years was found to result in a substantial increase in the number of material failures
expected.
As outlined above, Asset Management has identified 20 years as the optimum timeframe to prudently
manage this risk. Avista’s leadership has adopted this recommendation and has funded and staffed
the program to achieve this objective. Furthermore, the three state Commissions that regulate
Avista’s natural gas operations have thoroughly examined this program in several rates proceedings,
and in policy proceedings, and have deemed this approach to be prudent, cost effective, and in the
interest of our customers.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 250 of 422
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.

Start: January 2012
Expected End: December 2031
The annual list of projects in each of the three states (ID, OR, and WA) are established as unique
“blanket projects” that transfer to plant (TTP) each month as they are “used & useful”.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The Gas Facilities Replacement Program (GFRP) is responsible for Aldyl-A pipe replacement
which aligns with Avista’s mission to operate and maintain a “Safe and Reliable Infrastructure”.
Avista has a goal of investing in its infrastructure to achieve optimum life-cycle performance.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

The objective of this investment and structured replacement program is to reduce risk by
replacing at risk pipe and by rebuilding Service Tee Transitions. Through rigorous efforts, the
GFRP plans and tacks the performance of each project and utilizes Earned Value for cost
analysis and for upstream reporting. Furthermore, the GFRP tracks and report Planned vs.
Actual quantities by project, year, state jurisdiction, and also reports multi-year cumulative
statistics.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

Avista’s customers and the general public expect Avista’s natural gas system to operate safely
and reliably without incidents. Avista is dedicated to and focused on maintaining a safe and
reliable system that shields the public from imprudent risks. The proposed pipe replacement
programs have been initiated with the purpose of mitigating the known risks within the natural
gas distribution system. Given this context, the Gas Facility Replacement Program’s portfolio
of projects could therefore be considered as a customer-related benefit.

The GFRP’s Aldyl-A Pipe Replacement projects touch numerous internal and external
stakeholders. A comprehensive list of stakeholders is in the “2019 GFRP Operating Plan &
Projects” document.

2.8.2 Identify any related Business Cases

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 251 of 422
Business cases have been submitted annually and updated as necessary since 2012, the
inception of the Gas Facility Replacement Program.

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Gas Facility Replacement Program (GFRP) Advisory Group consists of the GFRP’s
Program Manager, Gas Operations Contract Construction Manager, Director of Natura Gas,
Senior Manager of Gas Operations, and the Manager of Gas Design & Measurement. This
group meets monthly to review program wide Earned Value results, that status of the delivery
of the individual projects, budget allocations and variances, internal resource demands,
customer care results and issues, contractor performance, and to communicate potential
program risks and shortfalls.

In addition, Avista’s Distribution Integrity Management Plan and Asset Management groups
provide periodic input, and/or validation of the replacement plan and schedule.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Each year an annual portfolio of projects is derived from Avista’s Distribution Integrity
Management Program (DIMP) Aldyl-A prioritization list which currently identifies unique priority
project areas (polygons) throughout the natural gas system in ID, OR, and WA. The portfolio of
projects is sized to meet jurisdictional commitments. Then individual priority projects are
planned, phased, scoped, designed, and detailed estimates are prepared. Once the individual
project estimates are finalized, the overall program-wide capital budget is refined to reflect a
more precise budget. The requested spend level has historically been determined based upon
Avista’s experience in the management of the Aldyl-A pipe facilities across Avista’s service
territories coupled with any changing costs of construction year to year.

There are circumstances where lower priority Aldyl-A projects may be accelerated if it makes
sense to coordinate the timing of pipe replacement projects with prior phasing or with other utility
and road projects. The individual projects for GFRP are typically managed by the Customer
Project Coordinators (CPC’s) while the overall program budget is managed by the GFRP
Program Manager.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Gas Facility Replacement Program (GFRP) Advisory Group consists of the GFRP’s
Program Manager, Gas Operations Contract Construction Manager, Director of Natura Gas
Senior Manager of Gas Operations, and the Manager of Gas Design & Measurement. This
group meets monthly to review program wide Earned Value results, that status of the delivery
of the individual projects, budget allocations and variances, internal resource demands,
customer care results and issues, contractor performance, and to communicate potential
program risks and shortfalls. The monthly documentation tracks the projects and is the primary
device for documenting program decision making.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 252 of 422
As projects are completed, the Distribution Integrity Management Program (DIMP) Aldyl-A
prioritization list is updated annually. As projects are completed, they are removed from the list
and new projects are added and evaluated, as necessary.
Annual spend levels and funds change requests to the Capital Planning Group are maintained
as documentation of program funding and funding changes throughout the year.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Facilities Replacement Program and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.

Signature: Date:
Print Name: Karen Cash
Title: GFRP Manager
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Natural Gas Director
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/7/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 253 of 422

EXECUTIVE SUMMARY

In accordance with a Stipulated Agreement with Washington State, Avista implemented
an “Isolated Steel Identification and Replacement Program” (Program) beginning in
2011. The goal of the Program has been to identify and remediate isolated steel within
Avista’s Washington State gas pipeline systems. As part of the overall program, Avista
has also begun to identify and remediate isolated steel within Oregon and Idaho natural
gas pipeline systems. Work completed under this program results in a safer gas
distribution system.

The annual budget through 2021 has been $1,400,000. Starting in 2022, the program
budget was reduced to $850,000, due to the program ending in Washington State.
Remediation efforts in Washington State were completed and approved by the WUTC
as outlined within the closure letter for the stipulated agreement. Failure to complete the
program on time would have been a direct violation of the stipulated agreement
between Avista and the WUTC. Avista is now focusing on isolated steel in Oregon and
Idaho to reduce the risk of continued deterioration of any isolated steel pipe in our
distribution system. The recommendation to continue the program into Oregon and
Idaho was approved and reviewed by:
.
- Jeff Webb – Manager of Natural Gas Design, Measurement and Planning
- Mike Faulkenberry – Director of Natural Gas (Retired)

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial Version 03/16/2017
1.1 Jeff Webb Revisions 04/07/2017
1.2 Jenn Massey 2020 Revisions 02/05/2020
1.3 Nick Messing Updated Business Case Template 07/10/2020
1.4 Nick Messing Updated Business Case Template 05/05/2022
1.5 Seth Samsell Updated Business Case Template 08/25/2022 Seth took over the program in
2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 254 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being address
The program objective is to identify and document isolated steel pipe sections,
including isolated risers, that may not be cathodically protected and to replace
each riser or pipeline section within a specified timeframe after its
identification.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Isolated portions of pipe including risers, service pipe and main will be
replaced as required to meet the requirements of 49 CFR 192.455 & .457 and
in accordance with WUTC Docket PG-100049, which has been satisfied.
Moving forward, this program will continue to be conducted in OR and ID to
assure cathodically isolated steel is identified and replaced as needed. Work
completed under this program results in a safer gas distribution system.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Per the original WUTC agreement, isolated steel risers are being replaced at a
rate of at least 10% per year, starting in 2011, and short sections of isolated
steel main are replaced within one year of discovery. Work as previously
described is primarily being completed in OR and ID at this time. Work
completed under this program results in a safer gas distribution system and
failure to complete the program may result in financial penalties.
Requested Spend Amount $850,000 – Annual Request
Requested Spend Time Period 10 years
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Seth Samsell | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 255 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The program will reduce the chances of corrosion on the steel piping system
thereby reducing future leaks associated with these pipes. The Isolated Steel
Replacement Program will be successful if the known isolated steel
riser/service count drops to zero in all of Avista’s service areas. This was a
Washington requirement and is a best practice for Oregon and Idaho.

As of August of 2022, Washington has 0 known isolated steel services
remaining, Oregon has 400 known isolated steel service replacement jobs
open, and Idaho has isolated steel service replacement jobs open. It is
important to note that Oregon’s numbers reflect the number of isolated steel
replacement jobs currently open. A ten year inspection began in July of 2021
to identify all isolated steel services in Oregon. Therefore, the job count in
Oregon will fluctuate as that inspection program and replacements continue.
Newly identified sites will be added to the Oregon number for remediation. The
ten year program will review approximately 90,000 services identified in
Avista’s GIS system, which have been flagged for inspection.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Proposal / Recommended Solution – Replace
isolated steel pipe sections and risers that are not
cathodically protected in all service areas as needed
$850,000
(2023-2030)
11/2011 12/2030
Alternative #1 - Complete OR only 2023 - & 90-day
only orders in ID
$800,000 06/2023 12/2023
Alternative #2 - Complete only 90-day orders in
OR/ID
$400,000 06/2023 12/2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

The capital request was based on the number of remaining jobs in each state,
the average replacement costs in each state, and by reviewing previous years’
budgets. The original stipulated agreement requirements in WA along with
best practices for Oregon and Idaho are factored in as well.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 256 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

Based upon the Recommended Solution, the Isolated Steel Pipe Program will
continue to identify and mitigate any isolated steel pipe in the gas piping
systems of WA, OR, and ID. The project’s goal is to remove all the isolated
steel pipe in our system which will eliminate the need to monitor unprotected
pipe, reduce corrosion, reduce leaks caused by corrosion, and create a safer
gas distribution system. It will also reduce the number of issues encountered
when identifying and repairing the cathodic protection system allowing
cathodic employees to focus on long term protection of the pipelines. The local
districts manage these projects with the goal of completing as much pipe
replacement work as their allocated spend level will allow. Each month, the
Program Manager and the Local Operations District Managers perform a
check-in to update current capital spending levels for the Capital Planning
Group to review. During this monthly process any additional spend requests or
funding returns are made.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
N/A
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative #1 - Complete OR only 2023 & 90-day only jobs in ID.
Complete the full amount of planned inspections and replacements in Oregon
State only along with any 90-day only jobs for Idaho. Delaying ID would
reverse Avista’s current best practice of mirroring the WUTC timeframe for
Washington. Delaying isolated steel reduction in ID may lead to an increase of
gas leaks identified within the system, due to the higher level of corrosion
associated with isolated steel pipe, and could also result in additional
compliance concerns.

Alternative #2 - Complete only 90-day jobs in OR/ID.
Complete only 90-day jobs for both Oregon and Idaho, delaying planned
inspections and replacements. This would reverse Avista’s current best
practice of mirroring the WUTC timeframe for Washington. Delaying isolated
steel reduction may lead to an increase of gas leaks identified within the
system, due to the higher level of corrosion associated with isolated steel pipe,
and could also result in additional compliance concerns.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 257 of 422
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
The Isolated Steel Replacement Program was started in 2011. Washington
inspections and replacements were completed in 2021. Oregon and Idaho are
targeted for completion by 2030. Customers will realize an immediate benefit
due to reduced corrosion and leaks resulting in a safer natural gas distribution
system. This program is set up to transfer to plant monthly as work is
completed.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus on our responsibility to
maintain a safe and reliable infrastructure for all our customers and in each of
our services territories.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The requested spend level for the Isolated Steel Pipe Replacement Program
has been based upon Avista’s agreement with Washington State and our
commitment to provide a safe natural gas piping system in all service
territories. A 10-year program is reasonable and aligns with other programs of
similar scale from other utilities. Annual levels of spending may need to be
adjusted in this program depending upon the needs of the system and
changes in labor and material costs.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The current Program impacts Avista’s ORID territories. The majority of the
customers benefiting from reduced risk are residential customers. The
Gas Programs Manager and the Isolated Steel Program Manager work
with each of the Gas Operations District Managers while also coordinating
with Gas Engineering and Cathodic Protection Techs.

2.8.2 Identify any related Business Cases
N/A

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 258 of 422
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Gas Engineering and Gas Programs (Gas Compliance) act as the Steering
Committee for the Isolated Steel Replacement Program.

Gas Programs and Gas Construction Management are responsible for
identifying the work, completing the work and monitoring the annual budget.
Gas Operations completes the work. The overall program budget is managed
by Gas Programs. Any budget modifications or requests are coordinated
through Gas Engineering.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 259 of 422

3.2 Provide and discuss the governance processes and people that will
provide oversight
The Program is currently overseen by a Program Manager along with a
Program Administrator. Monthly reporting is used to identify whether budget
targets are met and overall completion levels in each state. Software has been
created to identify time constraints based on severity of potential risk.
Annually, the Gas Engineering Prioritization Investment Committee (EPIC)
reviews the 5-year plan and ensures the budget level is appropriate given
other categories of work and risk on the gas system. The Program Manager is
a part of this process.
Locations in Avista’s system with known isolated steel pipe segments are
submitted to each of our local Gas Operations District’s. The Program
Manager and Program Administrator work with each Gas Operations District
Manager to determine a manageable level of work within the approved budget.
Each Gas Operations District is allotted a manageable portion of the budget to
complete targeted projects in their District. The individual projects for Isolated
Steel Pipe are typically managed locally while the overall program budget is
managed by the Program Manager with assistance from the Program
Administrator. Any budget modifications or requests are coordinated through
Gas Engineering.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Depending on compliance requirements higher risk projects will be completed
first. A generalized workflow for Isolated Steel Identification/Replacement is
provided in Image 1 below.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 260 of 422

Image 1 – Generalized Workflow for Isolated Steel Identification/Replacement

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 261 of 422
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Isolated Steel Replacement
Program and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/30/22
Print Name: Jeff Webb / Seth R. Samsell
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director of Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Cmt Review

8/30/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 262 of 422
EXECUTIVE SUMMARY
Overbuilt pipe refers to gas pipes that either located directly under or very close to
building structures. Except in rare case, Avista does not intentionally install gas pipes
under structures. In most cases, overbuilt pipe occurs in mobile home parks where
homes are moved over time. The close proximity of these structures makes gas system
maintenance and inspection difficult, can be against state and federal code, and can be
a potential safety hazard for the occupants.

All the known mobile home parks with overbuilt pipe in Avista’s Oregon districts were
catalogued at one time, analyzed, and risk ranked as part of the utility’s Distribution
Integrity Management Program (DIMP). In addition to these known mobile home parks,
with numerous overbuilt facilities, each local District (including those in Idaho and
Washington states) periodically finds individual locations with newly overbuilt facilities.
These projects and the risk associated with them are mitigated, over time, as part of the
Overbuilt Pipe Replacement Program. As the number of known overbuilds in the
company has decreased, the level of requested and approved funding has decreased
as well.

This program is scheduled to be complete at the end of 2024.

VERSION HISTORY
Version Author Description Date Notes
1.0 Seth Samsell Initial version 4/17/2017
2.0 Seth Samsell Revision for 2020 Oregon GRC
filing
2/12/2020

2.1 Tim Harding Updated to the refreshed 2022
Business Case Template
9/1/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 263 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Overbuild conditions usually occur when a structure is placed or constructed over
an existing gas pipe. The close proximity of these structures makes gas system
maintenance and inspection difficult, can be against state and federal code, and
can be a potential safety hazard for the occupants.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The main driver for this program is Mandatory & Compliance. Resolving overbuilt
gas pipes keeps Avista compliant with state and federal codes, and increases the
safety of customers in the immediate project areas.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Overbuilt gas pipes pose a safety risk for occupants in the area. Leaking gas can
accumulate under mobile homes and storage sheds. Relocating the gas piping is
the most straight-forward approach to resolving the issue.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The locations of known overbuilt gas pipes have been catalogued and the
completion of these projects is tracked by the DIMP Program Manager.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The DIMP study of known project locations can be obtained from the Gas
Compliance group.
Requested Spend Amount $400,000
Requested Spend Time Period Annually
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Tim Harding | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 264 of 422
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
This program replaces existing assets, however the asset condition is not
generally a factor in project prioritization. This program replaces and relocates
overbuilt gas pipes, regardless of the condition of the existing pipe.
2. PROPOSAL AND RECOMMENDED SOLUTION
The requested level of spending for this program is consistent with past years, and
that level will allow the program to be complete at the end of 2024. A reduction in
funding will extend the time required to complete all projects within the program.
Option Capital Cost Start Complete
Recommended Solution, Complete planned
projects at requested funding level
$400,000 January December
Alternative Solution, Complete planned projects at
a reduced funding level
$200,000 January December
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.
A DIMP risk analysis was performed on known overbuild projects by the Gas Compliance
group. Information on this analysis is available from the Gas Compliance group.
2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
This capital program is focused on installing new gas mains and services, and
retiring the previous overbuilt mains and services. This program does not
significantly lower O&M costs. Instead, it is addressing a safety issue.

2.3 Outline any business functions and processes that may be impacted
(and how) by the business case for it to be successfully implemented.
None
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The alternative is to leave known overbuilds in place. This is a violation of code
and standard practices. Only in rare cases is gas piping intentionally installed
under a structure. The gas pipes addressed by this program were never intended
to be built over, and therefore were not installed to comply with the special
requirements needed to make such an installation compliant with code and
Avista’s Gas Standards.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 265 of 422
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
Projects completed within this budget will be transferred to plant upon completion,
typically within the same year they are started.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely, reliably,
and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This program addresses a known safety issue. A thorough evaluation was
performed by the DIMP group to validate the need for this program. Construction
on this program will be complete at the end of 2024.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders include Gas Engineering, Compliance, Integrity, and Operations.
2.8.2 Identify any related Business Cases
N/A

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
This program budget is overseen by Gas Engineering. Construction activities are
overseen by Gas Operations. Projects are prioritized with input from the DIMP
Program Manager, the impacted Operations Managers, and Gas Engineering.
3.2 Provide and discuss the governance processes and people that will
provide oversight
DIMP risk scores are assigned to each proposed project. The highest-ranking
projects are generally completed first, but some flexibility is required to ensure that
specific operations groups are not overloaded during any given year. Gas
Engineering oversees the program budget and reports on spending monthly.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
At the beginning of each year, the prioritization process is completed and the
program budget is divided between offices. This information is formally handed off
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 266 of 422
to the operations offices at that time. Rarely will anything change for the rest of
the year. Gas Engineering reviews program spending with the operations offices
on a monthly basis to keep within the program budget. Monthly updates are
documented via email and fund requests are made using the appropriate forms
from the CPG.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Overbuild Program ER
3006 and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date: 9/1/22
Print Name: Jeff Webb / Tim Harding
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/1/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 267 of 422
EXECUTIVE SUMMARY
Avista is required by state commission rules and tariffs in WA, ID, and OR to annually
test gas meters for accuracy and ensure proper metering performance. Execution of this
program on an annual basis ensures the continuation of reliable and accurate gas
measurement for our customers and compliance with the applicable state tariffs.

The Planned Meter Change-out (PMC) Program uses a statistical sampling
methodology based on ANSI Z1.9 “Sampling Procedures and Tables for Inspection by
Variables for Percent Nonconforming”. Sample sizes and acceptance criteria are
defined in the ANSI standard. The annual test results of gas meters that have been
removed from the field are analyzed and a determination of the accuracy of each meter
family is made. If the analytics determine a meter family (defined as a manufacturer
year and model/size) is no longer metering accurately enough to meet the tariff, then
that entire meter family will be replaced. Conversely, if the analytics determine a meter
family is testing well (close to 100% accurate), the sample size (number of meters in
that family required to be tested) can be reduced. These analytics help control costs
and remove meters quickly that are not performing well.

This program includes only the labor and minor materials associated with the PMC
Program. Major materials (meters, pressure regulators, and Encoder Receiver
Transmitter (ERT)) will be charged to the appropriate Gas Growth Programs. The
annual cost for the program varies depending on the results of the previous year’s
statistical analysis. On average approximately 6,000 meters are removed for this
program resulting in an average cost of $1,500,000 ($250/meter).

Avista would not be in compliance with state commission rules and tariffs in WA, ID, and
OR if this program is not completed annually.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial Version 03/16/2017
1.1 Jeff Webb 04/07/2017
2.0 Dave Smith Revised for 2020 Oregon
GRC filing
2/17/2020
2.1 Dave Smith
Updated to the refreshed
2020 Business Case
template
6/24/2020
2.2 Dave Smith
Updated to the refreshed
2022 Business Case
template
5-5-22

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 268 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista is required by state commission rules and tariffs in WA, ID, and OR to test
meters for accuracy and ensure proper metering performance. Execution of this
program on an annual basis ensures the continuation of reliable gas measurement
and compliance with the applicable tariffs.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
This program is a mandatory requirement to be in compliance with state
commission rules and tariffs in WA, ID, and OR.
The following state rules regulate Avista’s PMC Program:
Oregon:
o OAC 860-023-0015 “Testing Gas and Electric Meters”
o Tariff Rule #18
Idaho:
o IDAPA 31.31.01.151 through .157 “Standards for Service”
Washington:
o WAC Chapter 480-90-333 through -348 “Gas companies – Operations”
o Tariff Rule #170
Our customers benefit from this program because it assures that natural gas use
is measured accurately in all jurisdictions.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista would not be in compliance with state commission rules and tariffs in WA,
ID, and OR if this program is not completed annually.
Requested Spend Amount $4,100,000 (2023)
Requested Spend Time Period Annually
Requesting Organization/Department Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Dave Smith | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 269 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The PMC Program uses a statistical sampling methodology based on ANSI Z1.9
“Sampling Procedures and Tables for Inspection by Variables for Percent
Nonconforming”. Sample sizes and acceptance criteria are defined in the ANSI
standard. The annual test results of gas meters that have been removed from the
field are analyzed and a determination of the accuracy of each meter family is
made. If the analytics determine a meter family (defined as a manufacturer year
and model/size) is no longer metering accurately enough to meet the tariff, then
that entire meter family will be replaced. Conversely, if the analytics determine a
meter family is testing well (close to 100% accurate), the sample size (number of
meters in that family required to be tested) can be reduced. These analytics help
control costs and also remove meters quickly that are not performing well.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• Gas PMC Program Standard Operating Procedure
• ANZI Z1.9 “Sampling Procedures and Tables for Inspection by Variables for
Percent Nonconforming”
• The following state rules regulate the PMC program:
Oregon:
o OAC 860-023-0015 “Testing Gas and Electric Meters”
o Tariff Rule #18
Idaho:
o IDAPA 31.31.01.151 through .157 “Standards for Service”
Washington:
o WAC Chapter 480-90-333 through -348 “Gas companies – Operations”
o Tariff Rule #170
These documents are saved on the Avista network drive c01d44 and can be made
available upon request.

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The meter accuracy testing results collected annually from the program are
documented in an Excel spreadsheet. This spreadsheet performs calculations
based on ANSI Z1.9 to determine the following year’s sampling requirements and
identify which meter families do not meet the accuracy standards and must be
removed.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 270 of 422
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to complete this mandatory programmatic work.
Completion of this program will keep Avista in compliance with state rules and
tariffs and assure that our customers’ natural gas use is measured accurately.
Partial completion of this program will result in Avista being out of compliance with
state rules and tariffs.

Option Capital Cost Start Complete
Recommended Solution, Fully complete the
programmatic work described
$4,100,000 January December
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Historical program costs are used to determine the average labor costs to remove
and test each meter. The number of meters required to be removed varies each
year depending on the previous year’s testing results. The average cost per meter
is then multiplied by the anticipated number of meters to be removed to determine
the estimated program cost for the following year.
The PMC program was paused in 2022 due to inventory limitations in the meter
manufacturing stream. There are not enough meters to support both growth and
the PMC program, so a decision was made to use the meter we do have for new
growth opportunities. The plan is to reinstate the program as soon as meter
inventories return to an acceptable level. The assumption is we will be able to
resume the program in 2023. The funds request for 2023 is higher than normal
because it includes pulling meter families that would normally have been pulled in
2022 in addion to the anticipated number for 2023.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The program is completed between January and December of each year. Gas
Engineering, Gas Operations, Gas Meter Shop, and Technical Services work
together to administer the PMC program. Gas Operations and the Gas Meter
Shop personnel remove the meters from the customer’s premise and install new
ones. If a large meter family fails, Avista may hire a contractor to assist in the
removal of the meters. The Gas Meter Shop completes physical calibration tests
on the meters and the Technical Services group then analyzes the test results at
the end of the year to determine the status of each family of gas meters. The
results of this analysis will define the meter removal and testing requirements for
the following year. Gas Engineering develops an annual report which is made
available to the state commissions upon request.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 271 of 422
Completing the annual PMC Program provides direct savings. Customers benefit
from this program because it ensures their gas meter remains accurate throughout
its service life. Meter families that have an accuracy outside of the acceptable
range will be replaced. Most customers that have a failed family meter replaced
will see a cost savings on their energy bill. See the file titled ER 3055 Cost Offset
Calcs 2022-2023.xlsx showing the calculations for the direct savings shown below.

The estimated direct savings were calculated with the following assumptions:

1. The 2022 direct savings was calculated assuming that 50% of the R275_1994
failed family meters will be replaced in 2021 and the remaining 50% in 2022.
2. The Lifetime direct savings was calculated by assuming that the failed family
meters being replaced would have remained in service for an additional 10 years.

1The direct savings for future years cannot be calculated until the program finishes
and the meter accuracy data is complied.

Quantified direct savings:
2022 2023 Lifetime
Capital: - - -
Expense: $38,000 1See
Above $153,000
Total: $38,000 1See
Above $153,000

Completing the annual PMC Program also provides indirect savings. The program
provides Avista with the data necessary to identify statistical trends in meter
accuracy. If a particular meter family shows a consistent drift in mean accuracy,
the meter family can remain in service and the customer’s bill can be adjusted
accordingly in the Meter Data Management system. This approach has allowed
Avista to adjust leave approximately 67,000 meters in service that would have
otherwise needed to be replaced. See the file titled ER 3055 Cost Offset Calcs
2022-2023.xlsx showing the calculations for the indirect savings shown below.

The estimated indirect savings were calculated with the following assumptions:

1. The average cost to replace a meter in 2022 and 2023 is estimated at $236 and
$243, respectively. This estimated cost was calculated by taking the actual
average cost to replace a meter in 2020 at $222 and then adding a 3% increase
each year to account for a cost of living adjustment.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 272 of 422
2. Per the failed family replacement timeframe defined in the PMC Program
Standard Operating Procedure, 25% of the total 67,000 meters would need to be
replaced each year starting in 2022 and ending in 2025.

Quantified indirect savings:
2022 2023 Lifetime
Capital: - - -
Expense: $3,995,000 $4,114,000 $15,984,000
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Replacing gas meters is not a new process for Avista. Existing processes and
technologies will be utilized for this program.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The only alternatives are to either partially fund this program or to not fund it at all.
If this program were not completed fully, Avista would be out of compliance with
state rules and tariffs and could be exposed to fines from the various state utility
commissions. Also, the accuracy of measurement of our customers’ natural gas
usage could not be assured. See below for breakdown of these risks:

*Regulatory fines present a daily and overall maximum value per violation in accordance with 49
CFR Part 190.223. However, these values are not necessarily an accurate representation of how
much Avista would be fined for any specific violation. The actual amount is likely to be much lower
since Avista has an ongoing reputation and history of investing in programs related to safety and
non-compliance issues. However, it is a bookend reminder from which to characterize the
regulatory risk associated with chronic and/or egregious non-compliance, especially in the event of
Risk Probability Definitions:
Very High (VH)Risk event expected to occur
High (H)Risk event more likely to occur than not
Probable (P)Risk event may or may not occur
Low (L)Risk event less likely to occur than not
Very Low (VL)Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
1 2 5 10 15+
1 H H VH VH VH $225,134 per day per violation (Max)
$2,251,334 Total (Max)
2 Not Applicable
3 Not Applicable
4 H H VH VH VH Erosion of PUC and Public trust
5 Not Applicable
#Risk
Risk Over Time (years)
Cost Estimate
Regulatory Fines*
Not Applicable
Not Applicable
Not Applicable
Pipeline Failure & Outage
Negative Reputation
Employee & Public Safety
Pipeline Leak
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 273 of 422
a pipeline safety incident (i.e. failure). Therefore, Avista must continue to demonstrate an ongoing
commitment to compliance and pipeline safety to ensure favorable future outcomes with respect to
regulatory penalties (actual penalty amount is at the discretion of the state or federal agency).

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
The program will be completed between January and December of each year.
The gas meters are purchased as a pre-capital material item under ER 1050 (Gas
Meters). The meter will become used and useful upon installation.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely, reliably,
and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This program must be completed to ensure our customer’s meters remain
accurate throughout their service life. Accuracy data is obtained and analyzed
each year to ensure the program is testing the appropriate number of meters and
removing ones that no longer meet Avista’s accuracy requirements.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
All Avista natural gas customers benefit from this program because it ensures their
gas meters remain accurate throughout their service life.
Business case stakeholders include Gas Engineering, Gas Operations, Gas Meter
Shop, Technical Services, and state commissions.
2.8.2 Identify any related Business Cases
ER 1050 Gas Meters

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Gas Engineering is ultimately responsible for the PMC plan and annual reports
that are developed and made available to each of the state commissions.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 274 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
Gas Engineering, Gas Operations, Gas Meter Shop, and Technical Services work
together to administer the PMC program and ensure compliance with the various
state rules and tariffs related to gas meter testing.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Meter accuracy testing results are compiled and analyzed in a spreadsheet. An
annual report is developed by Gas Engineering and made available to the state
commissions upon request. This report defines the program requirements for the
following year.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas PMC Program, ER 3055 and
agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature: Date: 8/30/22
Print Name: Jeff Webb / David Smith
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 275 of 422
EXECUTIVE SUMMARY
Virtually all of Avista’s pipeline systems are located in public utility easements that
are governed by local jurisdictional franchise agreements. In most cases, Avista is
mandated under these agreements to relocate its facilities when local jurisdictional
projects create a conflict.
When conflicts are identified that may require relocating gas facilities, meetings
with the appropriate entities take place in an attempt to design around the conflict.
If after meeting, relocation of gas facilities are still required, then Avista must
complete the work at our cost per the applicable franchise agreement.
It is very difficult to forecast year-to-year what the financial impacts in this category
will be in each district and state. Budgets change each year for the municipalities,
and their spending level is not directly tied to work for Avista. Some projects are
more impactful than others to the buried gas facilities.
By completing the projects as requested, then Avista meets the obligations under
its franchise agreements, remains in good standing with the municipalities, and
avoids financial penalties associated with project delays.
Gas Operations manages this category of work. The work is generated by the
various municipalities that Avista has franchise agreements in. The overall
program budget is managed by Gas Engineering.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial version 03/17/2017
1.1 Jeff Webb 04/07/2017
2.0 Jeff Webb Revised for 2020 Oregon GRC filing 2/17/2020
3.0 Jeff Webb Revised for new BC format 8/30/22

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 276 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
Virtually all of Avista’s pipelines are located in public utility easements (PUEs)
which are controlled by local jurisdictional franchise agreements. Avista is
mandated under these agreements to relocate our facilities, when local
jurisdictional projects necessitate. Often these come without significant lead time
by the local jurisdictions. It is often the case that meetings are called in the Spring
to notify franchisees (natural gas, electric, cable, phone companies etc.) that they
will need to relocate their facilities. This does not enable ideal planning and often
may cause Avista to spend unbudgeted funds and do so in a manner that is not of
the utmost efficiency.
When conflicts are identified that may require relocating gas facilities, meetings
with the appropriate entities take place in an attempt to design around the conflict.
If conflicts cannot be resolved, then relocation of gas facilities are required. Avista
must then relocate the gas facility at our cost per the applicable franchise
agreement. If the relocation project is of significant complexity, then Gas
Engineering will take over the project to design and manage it through completion,
otherwise the local districts will manage the project. The business needs and
potential solutions identified impact all gas customers in Avista’s service territory.
1.1 What is the current or potential problem that is being addressed?
Physical conflicts within a public right of way between natural gas facilities and
roadways or other utilities.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Avista is required to resolve conflicts within a public right of way, therefore this
the driver is Mandatory and Compliance.
Requested Spend Amount $3,610,000 – Annual Request
Requested Spend Time Period 10 years
Requesting Organization/Department B51 / Gas Engineering
Business Case Owner | Sponsor Jeff Webb | Jody Morehouse
Sponsor Organization/Department B51 / Gas Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 277 of 422
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The nature of this work is considered “work in request of others”. If the
conflicts are not resolved through design changes or relocation of the gas
facilities, Avista would be in conflict with franchise agreements and could be
charged with delay of a project. This would not only be a financial burden on
the company, but it would also greatly damage the working relationship
between Avista and the municipality.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Avista is required to resolve conflicts within a public right of way, therefore this
the driver is Mandatory and Compliance.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Recommended Solution – comply with franchise
agreements
$3,610,000 01-2023 12-2033
Alternative #1 – Do nothing $0 01-2023 12-2023
Alternative #2 – n/a $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Budget numbers are based off historical spends and can vary significantly from year
to year for each state. The graph below shows current 2022 spend plus the last two
years as examples.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 278 of 422

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The funding level for this program is based off of historical spend rates and
then adjusted throughout the year to account for varying levels of work by
district. It is very difficult to forecast year-to-year what the cost in this category
will be for each state as the number and size of projects differs substantially
from year to year.
There are no direct or indirect O&M saving related to this program.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Gas Operations often negotiates with the various municipalities in an attempt to
reduce our conflicts and they are responsible to complete the construction work. Gas
Engineering monitors spending and assists with complicated projects.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The numerous franchise agreements that Avista has with State, County, and City
agencies determine the circumstances related to the gas facilities being located in their
public right of ways. Should we violate those agreements by not relocating when
required to do so, we would be liable for fines related to construction delays as well as
tarnish the good working relationships we have with these entities.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 279 of 422

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Projects are typically started and completed within the same calendar year and are
placed into service the same month they become used and useful.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives, and mission statement of the organization.
Successful execution of this program ensures the integrity of Avista with the
many jurisdictions we operate in, which in turns makes us a trustworthy
partner.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The nature of this work is considered “work in request of others”. If the
conflicts are not resolved through design changes or relocation of the gas
facilities, Avista would be in conflict with franchise agreements and could be
charged with delay of a project. This would not only be a financial burden on
the company, but it would also greatly damage the working relationship
between Avista and the municipality.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
None
Risk Probability Definitions:
Very High (VH)Risk event expected to occur
High (H)Risk event more likely to occur than not
Probable (P)Risk event may or may not occur
Low (L)Risk event less likely to occur than not
Very Low (VL)Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
1 2 5 10 15+
1 H H VH VH VH Vary depeding on agency and circumstances
2 VL VL VL VL VL $5,000 to $150,000 per site (site dependent)
3 VL VL VL VL VL $150,000 to $3,000,000 per site (site dependent)
4 H VH VH VH VH Erosion of PUC and Public trust
5 VL VL VL VL VL Lost time, healthcare, lawsuits, etc. (varies)
Risk
Risk Over Time (years)
Regulatory Fines
Pipeline Leak
Pipeline Failure & Outage
Negative Reputation
Cost Estimate#
Employee & Public Safety
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 280 of 422
2.8.2 Identify any related Business Cases
None

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Gas Operations manages this category of work. The work is generated by the various
municipalities that Avista has franchise agreements in. The overall program budget is
managed by Gas Engineering
3.2 Provide and discuss the governance processes and people that will
provide oversight
The program’s spend and budget will be reviewed monthly by the Gas Engineering
Prioritization Investment Committee (EPIC). The manager of Gas Engineering will provide
oversight to the program.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Monthly budget changes will be documented via the existing CPG process, approved by the
Manager of Gas Engineering and the Director of Natural Gas. The monthly Gas EPIC
updates are captured via email.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Replace Street &
Hwy, ER 3003 business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date: 8/31/22
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director of Natural Gas
Role: Business Case Sponsor

8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 281 of 422
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 282 of 422
EXECUTIVE SUMMARY

Avista has experienced safety issues, including fires at regulator stations and damaged
equipment, due to transient voltage spikes from faults on adjacent electric transmission
systems. The purpose of this program is to identify high pressure gas piping systems
that are at risk of these conditions, identify gas systems that have high steady state
voltage, and to then install mitigative measures to reduce the risk to both these
scenarios on the pipelines. These efforts will protect the pipeline and equipment from
being damaged and reduce the touch voltage exposure to below compliance limits,
keeping our employees safe. Common approaches to this include the installation of
grounding systems, gradient mats, and solid state decouplers.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial version 12/17/2021
1.1 Tim Harding Updated to the refreshed 2022
Business Case Template
9/1/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 283 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Buried steel natural gas pipes in close proximity to electric conductors can have
high AC voltage present. The power lines induce this voltage on the pipe, either
constantly, or during fault conditions. Industry standards, including AMPP
Standard Practice SP0177 suggests that, for safety reasons, steady-state pipeline
voltages should not exceed 15 volts. Systems experiencing voltages higher than
this should be studied, and mitigation measures put in place to reduce system
voltages.
Federal code CFR 49.192.467(F) requires that pipelines located near electric
transmission systems must be protected from damage caused by faults on the
transmission system. The mitigation schemes and equipment used to address
fault voltage concerns often overlaps what is used to address steady-state voltage
hazards. Fault incidents on nearby electric systems can lead to a significant
voltage rise on the gas main – Hundreds or thousands of volts. Gas systems are
not designed to support these voltage levels, and because of this electric arcing
between components can occur. This arcing damages equipment, but also will
burn holes through gas-carrying components, leading to gas leaks and fires.
Personnel working on these gas systems during a fault event can be exposed to
fatal voltage levels.
The constant presence of AC voltage on a pipeline can lead to corrosion. AMPP
Standard Practice SP21424 addresses this issue and gives guidance on testing,
monitoring, and mitigation of this issue. AC corrosion can occur on pipelines with
less than 15 volts, so systems without shock hazard risks may still have this issue.
Because of this, AC corrosion risks must be monitored separately from the other
two risks listed above.
Requested Spend Amount $1,000,000 - 2023
Requested Spend Time Period 5-10 years
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Tim Harding | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 284 of 422
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for this business case is Mandatory & Compliance. This
program addresses safety hazards and integrity concerns on high pressure steel
gas mains. This benefits customers by reducing corrosion risks, as well as
eliminating hazardous voltage levels on above-ground gas facilities – Facilities that
sometimes are accessible to the general public.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
There are multiple gas systems with known high-voltage hazards present. Not
mitigating these systems will result in the continued prevalence of electric fault
incidents, as well as exposing employees to potentially hazardous steady-state
pipeline voltages. Mitigation methods described in this program are a proven way
to resolve these issues. This work must be done, and delaying the process puts
system integrity and workers at an increased level of risk for each year of the
delay.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Incidents where electric faults cause damage to gas facilities are noted and
investigated. The installation of mitigation equipment will reduce the prevalence of
these incidents. The occurrence of these events is fairly random in nature and
difficult to predict, but a reduction in fault damage will be noted in the long run.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
To date, two studies have been performed by consulting engineering firms on
specific gas systems that have experienced multiple incidents. These studies
have yielded reports and mitigation designs. As of September 2022, both
projects are in different stages of construction. Reports from these studies are
available from Gas Engineering.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION
The requested level of spending for this program allows the high priority projects to
be completed. These projects are addressing serious system integrity and safety
issues. A reduced level of funding will slow the installation of mitigation equipment,
and delay resolving known system integrity and safety risks.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 285 of 422
Option Capital Cost Start Complete
Recommended Solution, Replace at risk stations at
requested funding level
$1,000,000 January December
Alternative Solution, Replace at risk stations at a
reduced funding level
<$1,000,000 January December
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.
The requested program budget was based on project cost estimates to address existing
known integrity and safety risks. In the next two years extensive testing will be performed
to determine how many other systems may have high voltage concerns. Future budget
proposals will be based on the estimated project costs to mitigate those systems.

2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
The project budget is spent on the following: Consulting engineering design
services, Avista engineering designs, mitigation materials (Including anodes, wire,
grounding mats, decouplers, remote test stations, reference cells, coupons, etc.),
Avista field installation labor, contractor labor, and installation services.
The installation of mitigation equipment reduced O&M expenses. The two main
reductions in these costs are due to fewer fault damage incidents that require
emergency response, and the reduced need to follow special safety procedures
when doing construction or maintenance on the system.

2.3 Outline any business functions and processes that may be impacted
(and how) by the business case for it to be successfully implemented.
The completion of mitigation projects under this budget will have a positive impact
on Gas Operations. Because there is currently a known safety issue, additional
burdensome procedures are required when company personnel do construction
and maintenance work on these systems. After the mitigation projects are
complete, many of these additional safety procedures will no longer need to be
followed.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
As mentioned in the previous section, systems with known voltage hazards require
special safety procedures for construction and maintenance work. If these
systems are left as-is with no mitigation, these procedures would have to be
followed forever. Following these procedures is time consuming and requires
ongoing training. Workers are required to lay out grounding equipment and use
high voltage rated gloves for certain activities.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 286 of 422
Not mitigating the system will result in the continued prevalence of electric fault
incidents. During these incidents, electric arcing can occur on gas facilities. This
can lead to gas leaks and fires. Knowingly allowing dangerous incidents like this
to continue to occur is not acceptable.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
Projects that are performed under this budget can be both large and small.
Smaller projects will typically transfer to plant monthly, while larger projects that
take several months will transfer to plant upon project completion.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely, reliably,
and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This program is addressing significant system integrity and personnel safety risks.
For projects to be considered in this program, they must exhibit issues that would
put them in violation of the Codes and Standards listed in Section 1.1 of this
document. As projects are completed, these systems will become compliant with
these requirements. As more systems are addressed, fewer will require mitigation
and the program budget can be reduced.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders include Gas Engineering, Compliance, Operations, Cathodic
Protection, and Safety.

2.8.2 Identify any related Business Cases
ER 3004 – Cathodic Protection: The mitigation of high AC pipeline voltages
has ties to the field of cathodic protection. There are some overlaps between
these programs, including testing procedures and equipment. Cathodic
Protection technicians are involved with the installation and testing of AC
mitigation systems.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 287 of 422
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
AC mitigation projects are proposed by the Gas Engineering and Cathodic
Protection groups. In some cases, consulting engineers are hired to design
mitigation systems. These engineers specialize in this field, and they provide
subject matter expertise to the Company. Gas Operations is involved with project
construction. Since Gas Operations benefits from the installations of the mitigation
systems, they are included in project communications throughout the process, and
they are given some say in how the installations are performed.
3.2 Provide and discuss the governance processes and people that will
provide oversight
An engineer in the Gas Engineering group serves as the AC Mitigation Program
Manager. The Program Manager oversees projects designs, construction, and the
program budget. The Program Manager meets quarterly with representatives from
Gas Engineering, Cathodic Protection, and Gas Compliance to review current and
planned projects. Project are prioritized by the group.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
During the quarterly meeting mentioned in previous section, projects are discussed
and prioritized. Meeting minutes are taken and stored on the program’s
SharePoint site.
Monthly budget changes will be documented via the existing CPG process,
approved by the Manager of Gas Engineering and the Director of Natural Gas. The
monthly Gas EPIC updates are captured via email.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transient Voltage
Mitigation Program and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Jeff Webb / Tim Harding
Title: Mgr Gas Engineering
Role: Business Case Owner
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 288 of 422

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/1/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 289 of 422
EXECUTIVE SUMMARY
This work is typically unplanned and is initiated by customers or Avista maintenance crews
and is managed at the Local District level. Gas Engineering establishes the overall budget
based largely on historical spend patterns and reports monthly updates to the Capital
Planning Group based on feedback from the Local Districts. Gas Engineering is
responsible for projects under this ER that require substantial design efforts such as farm
tap retirements, highway or river crossings, and steel pipelines.
The work in this annual program is mostly reactionary, unplanned work and is difficult to
predict aside from using historical trends. The following situations are typical triggers for
work in thei program: shallow facilities found by excavation (the excavation may or may
not be related to gas construction), relocation of facilities as requested by others (except
for road and highway relocations), leak repairs on mains or services, and farm tap
elimination. Customer related benefits include reduced operations and maintenance
(O&M) costs and improved safety and reliability from having facilities at the proper depth
and from reduced leak rates of new plastic pipe versus older steel. The business needs
and solutions identified impact all gas customers in Avista’s service territory.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb 03/16/2017 03/17/2017 Initial version
1.1 Jeff Webb 04/05/2017
2.0 Jeff Webb 2/17/2020 2/17/2020 Revised for Oregon
2020 GRC filing
3.0 Jeff Webb Revised for new BC format 5/31/22
1.0 Jeff Webb 03/16/2017 03/17/2017 Initial version

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 290 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The work in this annual program is mostly reactionary, unplanned work and is difficult to
predict aside from using historical trends. The following situations are typical triggers for
such work: shallow facilities found by excavation (the excavation may or may not be
related to gas construction), relocation of facilities as requested by others (except for road
and highway relocations), leak repairs on mains or services, remediation of cathodic
protection (CP) issues, and farm tap elimination. Each of these work types are further
described below. Customer related benefits include reduced operations and maintenance
(O&M) costs and improved safety and reliability from having facilities at the proper depth
and from reduced leak rates of new plastic pipe versus older steel. The business needs
and potential solutions identified impact all gas customers in Avista’s service territory.

When shallow facilities are discovered, an appropriate response to the situation is
determined by Local District Management. If the response to the situation is capital in
nature, then the repair is funded from this program. If the scope of the project is large
enough to warrant it, the project will be prioritized and risk ranked against other similar
type projects. These types of projects allow Avista to remain in compliance and operate
the gas facilities in a safe and reliable manner.

If requested by others (typically customers) to relocate facilities, Avista is bound by tariff
language to do so at the customer’s expense. Under certain circumstances, Avista may
choose these opportunities to perform additional work beyond the immediate request to
improve or update the gas system. Local District Management and field personnel will
evaluate the circumstances and make an appropriate decision based on a holistic view of
the situation. Guidance to help evaluate the scenario is established in the Company Gas
Standards Manual. An example might be to replace an entire existing steel service with
modern plastic material instead of just replacing a small section of the steel service that is
in conflict with a customer’s home improvement project. This would eliminate the
possibility of future deficiencies with the cathodic protection system on the steel pipes and
reduce future maintenance related to that steel service. The charges for this additional
work are put against this program.

Requested Spend Amount $9,400,000, annually
Requested Spend Time Period 10+ years
Requesting Organization/Department B51 / Gas Engineering
Business Case Owner | Sponsor Jeff Webb | Jody Morehouse
Sponsor Organization/Department B51 / Gas Engineering
Phase Execution
Category Program
Driver Failed Plant & Operations
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 291 of 422
When leaks are found on the gas system, it is sometime advantageous to replace a
section of main or service as opposed to just repairing the leak. The Local District looks at
the long term fix when possible, not just addressing the immediate concern, and considers
what is the right thing to do in these situations. This type of betterment falls under this
program.

If a section of steel main is found to be isolated electrically from the CP system, a CP
Technician will evaluate the concern and give directions to the district to fix. If the solution
is a capital main replacement, it will fall under this program. Isolated steel services fall
under ER 3007.

A single service farm tap (SSFT) installed on a high pressure main is a common way to
provide gas service to a small number of customers. The alternative is to install
distribution main from an adjacent distribution system to serve the customer which may be
cost prohibitive at the time. Many of these farm taps are reaching the end of their service
life or need to be replaced for maintenance reasons. In areas of high concentrations of
farm taps that have maintenance concerns, it is sometimes advantageous to rebuild one
of them as a traditional regulator station (pressure reduction station), install distribution
main to the other services from the adjacent farm taps, and then retire the other farm taps.
This reduces O&M by having fewer stations to maintain.

1.2 Discuss the major drivers of the business case (Customer Requested,
Customer Service Quality & Reliability, Mandatory & Compliance, Performance
& Capacity, Asset Condition, or Failed Plant & Operations) and the benefits to
the customer
Due to the majority of this work being unplanned replacement, it is considered Failed
Plant & Operations. The percent of Customer Requested work is small compared to
the other work in this program.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
Shallow facilities – Lowering gas mains and services is not required by Federal
Rules, but it is prudent. It reduces the chances of damage caused by excavation
over and around the gas facilities. This is critical because damage from excavation is
the highest risk to our gas facilities. Excavators are expecting gas pipes to be at the
depths they are first installed at. When they are shallow because of grade changes
that have been caused by others since installation, there is an increased risk of
damage and threat to public safety.
If not approved, Avista would experience higher instances of pipe damaged and
associated gas leaks.
Requested by others & leak repair – Betterment of the gas system when
opportunities arise is the prudent way to operate a gas distribution system. Mobilizing
crews and equipment to a site often covers the bulk of the costs for small projects, so
making the most of their time once on-site is the sensible way to operate.
Betterments as described in above are driven by Company Standards and best
practices.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 292 of 422
In not approved, we would miss the opportunity to better the system while already
on-site doing work. This is shortsighted because we increase the chances of having
to be back at the site to remedy other maintenance items at a later date. The
decision to simply repair the leak or perform the customer requested work (quickest
and easiest thing to do) eliminates the chance to improve the system as a whole,
while increasing the chances of having to be back at the site later to fix another leak
or maintenance concern. If leaks are not repaired, they must be monitored and re-
evaluated on a periodic schedule to ensure they are not becoming a greater hazard
to the public.
Isolated mains (CP) – Electically isolated portions of main will be replaced as
required to meet the requirements of Federal colde 49 CFR 192.455 & 192.457. This
is a safety related requirement as a steel pipe will corrode if it does not have
sufficient CP on it.
If not approved, we will be at risk of fines for being out of compliance and our steel
piping system will not be safe for our employees and customers.
Farm tap elimination – When there are many farm taps located in close proximity to
each other and when those stations have reason to be rebuilt, then it makes sense to
rebuild just one of them and install distribution main to the other stations to provide a
new source of gas. This allows the adjacent (old) farm taps to be retired, reducing
O&M and improving public safety. Triggers for rebuilding a farm tap may include;
replacement of inadequate or obsolete equipment that is no longer supported, poor
location of station (safety concerns), inability to perform proper maintenance, and
capacity constraints.
The customers benefit from these types of projects by having a safer, well
maintained distribution system. Also this is a prudent way to spend resources
because many deficiencies at stations can be remedied under just one project.
Additionally, the new main might be installed in front of structures without gas
service, making it easier to serve them with gas in the future should they choose to
change their energy source.
If Avista is not allowed to optimize the gas distribution system by reducing the
number of farm taps that are maintenance intensive, then eventually more staff will
be required to perform this federally mandated maintenance work. Additionally, farm
taps are normally located between the driving lane and the property line, are low
profile, and are sometimes difficult for the public to see. This puts them at risk of
vehicle damage, so having fewer of them on our system helps to improve safety.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
Customer satisfaction, or lack of complaints, due to not having multiple visits to the
same address would indicate we are managing our system properly by bettering it
when we have the opportunity.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
None
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 293 of 422
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is
proposed for replacement.
None
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Recommended Solution-Fully complete the
program as described above.
$9,400,000 01 2023 12 2033
Alternative-Fund at a reduced level <$9,400,000 01 2023 12 2033
[Alternative #2]-n/a
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
This program consists of hundreds of small individual projects completed across all
three state each year. Budget levels are based on historical spend levels as the vast
majority of this work is unplanned. The spend in 2021 has been adjusted to remove
the one-time project of $2.8M and a 3% inflation factor has been applied.

2019 $ 9,430,000
2020 $ 9,138,000
2021* $ 12,275,000 $ 2,800,000
3 yr avg $ 9,347,667
*2021 had an additional $2.8M allocated that was part of
a one off specific project. The $2.8M is backed out of the
number when calculating the average.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 294 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current year
(or future years if a multi-year or ongoing initiative). (i.e. what are the expected
functions, processes or deliverables that will result from the capital spend?). Include any
known or estimated reductions to O&M as a result of this investment.
The work in this program is comprised of small projects that are typically completed
within the same month they are started. As such, the funds transfer to plant each
month throughout the year. The spending is fairly level each month as well as shown
in the graph above.
There are no direct O&M savings associatd with completion of this program.
Indirect cost savings were calculated based on two presumptions:
1) that the Avista labor spent on this budget item would likely be charged to
expense type work instead of this capital work if this work item was not available.
2) if this capital program is not funded, leaks will be repaired in a temporary
manner as opposed to a permanent repair. When leaks are repaired temporarily,
the permanent fix still needs to happen at some point in the future. So a leak
repair will actually costs more to fix in the long run if it is not permanently fixed
the first time.
All cost savings are in today’s dollars.
Quantified indirect savings:

2022 2023 Lifetime
Capital: - - *
Expense: $1,999,800 $1,999,800 *
Total: $1,999,800 $1,999,800 *

* The program is in perpetuity, as such it is not possible to calculate a lifetime benefit.

CFR 192.465 & CFR192.720 determine how a gas utility manages leaks. The other
portions of work associated with this Business Case are not mandated work. They
consist of customer requested work, mitigating shallow gas facilities, and strategically
replacing farm tap style regulators with IP main.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 295 of 422

*Regulatory fines present a daily and overall maximum value per violation in
accordance with 49 CFR Part 190.223. However, these values are not necessarily an
accurate representation of how much Avista would be fined for any specific violation.
The actual amount is at the discretion of the enforcement agency and is likely to be
much lower due to Avista’s ongoing reputation and history of investing in programs
related to safety and non-compliance issues. However, it is a bookend reminder from
which to characterize the regulatory risk associated with chronic and/or egregious
non-compliance, especially in the event of a pipeline safety incident (i.e. failure).
Therefore, Avista must continue to demonstrate an ongoing commitment to
compliance and pipeline safety to ensure favorable future outcomes with respect to
regulatory penalties.

2.3 Outline any business functions and processes that may be impacted (and how)
by the business case for it to be successfully implemented.
n/a

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Risks to not funding this program as requested are discussed above.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer.
The work in this program is comprised of small projects that are typically completed
within the same month they are started. As such, the funds transfer to plant each
month throughout the year.

Risk Probability Definitions:
Very High (VH)Risk event expected to occur
High (H)Risk event more likely to occur than not
Probable (P)Risk event may or may not occur
Low (L)Risk event less likely to occur than not
Very Low (VL)Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
1 2 5 10 15+
1 VL VL VL L L $225,134 per day per violation (Max)
$2,251,334 Total (Max)
2 VL L L P P $5,000 to $150,000 per site (site dependent)
3 VL VL VL L L $150,000 to $3,000,000 per site (site dependent)
4 VL VL VL L L Erosion of PUC and Public trust
5 VL L L P P Lost time, healthcare, lawsuits, etc. (varies)
Risk
Risk Over Time (years)
Regulatory Fines*
Pipeline Leak
Pipeline Failure & Outage
Negative Reputation
Cost Estimate#
Employee & Public Safety
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 296 of 422
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a positive customer
experience, and a safe and reliable infrastructure safely.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
This level of spending is appropriate for Avista to react to unplanned work that occurs
on a regular basis across our gas system. As already discussed, if not fully funded,
Avista could face fines and actually spend more on a project if not fixed properly the
first time at the job site.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Gas Engineering and Operations are the main stakeholders to this program.
2.8.2 Identify any related Business Cases
none
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Gas Engineering monitors the spend and reports back to the district managers on a
monthly basis.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Gas Engineering prepare the appropriate documents for the Director of Natural Gas
to represent at the CPG should changes be needed throughout the year.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Monthly updates are provided to the director of Natural Gas, these are captured via
email.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the ER 3005 Gas Non-Revenue
Program business case and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date: 8/31/22
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 297 of 422

Signature: Date:
Print Name: Jody Morehouse
Title: Director of Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 298 of 422
EXECUTIVE SUMMARY
An Encoder Receiver Transmitter (ERT) is an electro-mechanical device that allows gas
meters to be read remotely. These ERTs are powered by lithium batteries, which
discharge over time and must eventually be replaced.
Most of the gas meters in Washington, Idaho, and Oregon have ERT modules. The large
quantity of ERT installations will result in an unmanageable quantity of battery failures in
the future if the ERT is not replaced at an optimized frequency. When batteries fail, the
customer’s usage is estimated and entered into the billing system manually. This manual
process causes a high chance of customer dissatisfaction because of potential billing
errors associated with bill estimation. Customers often express their dissatisfaction
through commission complaints when this happens.
In most areas of Washington, the ERT modules were replaced in 2019 as part of the
Advanced Metering Infrastructure (AMI) project. These ERTs will not need to be replaced
for approximately 15 years unless they experience a premature battery failure. This
business case also covers instances where the ERT module is not communicating with the
AMI network as intended, causing a replacement that is compatible with the mobile meter
read routes. This will ensure reliable metering reading and billing.
In Idaho the ERTs will likely be changed out in mass when the AMI project starts in 2024,
however it is estimated that up to 30,000 40G ERT modules may have a battery failure in
2022 and 2023 due to their age. These 40G ERT modules may be replaced to avoid
battery failure and billing issues before the AMI project is implemented.
In Oregon the ERTs will not be changed out in mass because the AMI project will not be
implemented there, therefore the recommended solution is to replace the oldest 7,000
ERTs each year on a 15 year cycle. This replacement strategy was optimized by an
Avista Asset Management study. The annual cost of this replacement strategy is
$220,000 and it expected to increase approximately 5% per year to adjust for increased
wages and materials.
If this program is not funded the amount of ERT battery failures will increase to an
unsustainable level. If not replaced at the proposed rate, a peak of more than 20,000
ERTs are predicted to fail annually, each requiring an unplanned maintenance visit to
replace, causing an undue burden on Operations personnel and equipment. This large
number of failed ERTs will also cause an unreasonable number of meters that would need
to be read manually and the customer’s usage estimated resulting in estimated billing and
a negative customer experience.

VERSION HISTORY
Version Author Description Date Notes
1.0 Dave Smith Initial version 3/9/2017
1.1 Dave Smith Revised per initial review 3/24/17
2.0 Dave Smith Revised for 2020 Oregon GRC
filing
2/7/20
2.1 Dave Smith Updated to the refreshed 2020
Business Case template 6/23/20
2.2 Dave Smith
Updated to the refreshed 2022
Business Case template. Edited
to include WA and ID in the
program.
5-5-22
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 299 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
An Encoder Receiver Transmitter (ERT) is an electro-mechanical device that
allows gas meters to be read remotely. These ERTs are powered by lithium
batteries, which discharge over time and must eventually be replaced. The
average battery life for ERT modules is approximately 15 years. Most of the gas
meters in Washington, Idaho, and Oregon have ERT modules. The large quantity
of ERT installations will result in an unmanageable quantity of battery failures in
the future if not replaced at an optimized frequency. When batteries fail, the
customer’s usage is estimated and entered into the billing system manually. This
manual process causes a high chance of customer dissatisfaction because of
potential billing errors associated with bill estimation. Customers often express
their dissatisfaction through commission complaints.
Battery replacement was determined to not be the best approach because in order
to replace just the battery, a technician needs to remove the module from the
meter and bring it back to the shop where the battery can be replaced in a
controlled environment. After the battery is replaced the technician needs to return
to the meter to re-install the module. This results in twice the travel time and twice
the labor time compared to replacing the entire module, negating any cost savings.
Another issue with replacing just the battery is that all of the potting gel
surrounding the battery and circuity inside the module needs to be removed in
order to access the battery, and once the gel is removed all of the electronic
components inside the ERT are now subject to moisture damage in the field,
resulting in additional failures. The manufacturer (Itron) does not recommend
replacing the battery in ERT modules for these reasons.
Requested Spend Amount $220,000
Requested Spend Time Period Annually
Requesting Organization/Department Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Dave Smith | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 300 of 422
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer

This program usess a proactive and strategic method for addressing asset
condition by replacing ERT modules before their battery fails. Replacing these
assets before they fail will avoid a manual process of estimating a customer’s
gas usage and bill resulting in higher customer satisfaction. It is also more
efficient and cost effective to proactively replace old ERTs rather than waiting
until their battery fails and having to send out a servicemen to replace a failed
ERT.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The work is needed now because many of the ERTs have reached their end-
of-life and will begin failing or are not communicating with the AMI network as
intended resulting in billing issues.
In most areas of Washington, the ERT modules were replaced in 2019 as part
of the Advanced Metering Infrastructure (AMI) project. These ERTs will not
need to be replaced for approximately 15 years unless they experience a
premature battery failure. This business case also covers instances where the
ERT module is not communicating with the AMI network as intended, causing
a replacement that is compatible with the mobile meter read routes. This will
ensure reliable metering reading and billing.
In Idaho the ERTs will likely be changed out in mass when the AMI project
starts in 2024, however it is estimated that up to 30,000 40G ERT modules
may have a battery failure in 2022 and 2023 due to their age. These 40G ERT
modules may be replaced to avoid battery failure and billing issues before the
AMI project is implemented.
The graph below shows how many ERT modules are expected to fail annually
in Oregon if they are not proactively replaced.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 301 of 422

If this program is not funded the amount of ERT battery failures will increase to
an unsustainable level. If not replaced at the proposed rate of 7,000 annually,
a peak of more than 20,000 ERTs are predicted to fail annually, each requiring
a maintenance visit to replace, causing an undue burden on Operations
personnel and equipment. This large number of failed ERTs will also cause an
unreasonable number of meters that would need to be read manually and the
customer’s usage estimated resulting in estimated billing and a negative
customer experience.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The Asset Management department was consulted by Gas Engineering for
assistance in developing a strategic program to replace ERT modules in
Oregon since the AMI program would not replace the modules there. The
result of the study suggested the most efficient method for replacing these
assets resulted in the highest customer satisfaction and the lowest cost. The
graph below summarizes the cost savings associated with a proactive and
strategic ERT replacement program over a 15 year cycle:
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 302 of 422

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The Asset Management study for the Oregon ERT Replacement
Program is saved on the Avista network drive c01d44 and can be made
available upon request.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

In Idaho the concern is the 2005-2007 vintage 40G ERTs failing before the
AMI project commences in 2024. There are approximately 30,000 of
these modules in the system. If we do not proactively replace these
modules in 2022 and 2023 there is a high likelihood that their batteries will
fail before AMI is implemented starting in 2024.

The graph below shows the quantity of ERTs installed per year in
Oregon:
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 303 of 422

If these ERTs are run to battery failure there will be an unmanageable
quantity of ERT failures each year.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution for Idaho is to replace the 30,000 +/- 40G ERTs that are
at end of life. This work will be completed in 2022 and 2023.
The recommended solution for Oregon is to continue replacing the oldest 7,000
ERTs each year on a 15 year cycle. This approach targets the oldest ERTs
resulting in less battery failures and as a result fewer estimated customer bills.

Option Capital Cost Start Complete
Recommended Solution:
ID – Replace 30,000 +/- 40G modules in 2022
and 2023.
OR – Replace the oldest 7,000 ERTs each
year on a 15 year cycle

$570,000 (ID)

$200,000 (OR)

01/2022 (ID)

01/2016 (OR)

12/2023 (ID)

04/2031 (OR)
Alternative Solution:
ID – Run 40G ERTs to failure.
OR – Replace 7,000 ERTs based on
geographic location each year on a 15 year
cycle

$5.41MM (ID)
$126,040 (OR)

N/A (ID)
01/2016 (OR)

N/A (ID)
04/2031 (OR)
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 304 of 422
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Some factors that were considered when preparing this request are the
number of ERTs in service, the average battery life of the ERT module, the
effects on the customer’s bill if the ERT fails, the cost to reactively replace the
failed module, and the cost to proactively replace the asset before failure.
Refer to the asset management study discussed in Section 1.4.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

In Idaho the replacement of approximately 30,000 2005-2007 40G ERT
modules will be replaced in 2022 and 2023. The exact timing is still being
evaluated, taking into account supply chain limitations and expected failure
rates.

At the beginning of each year the project team determines the location of the
oldest 7,000 ERTs in the Oregon. Replacement ERT modules are then
ordered. Due to the “pre-capitalization process” the cost of the ERT module
will go against ER1053 (Gas ERT Minor Blanket). This program covers the
labor and minor material cost for replacing the ERT. Work orders are created
for the replacement of each ERT. A third party contractor is utilized to
efficiently replace all 7,000 ERTs. The program is completed between
January and December each year.

If an ERT battery fails the Mobile Collector will not download the monthly
meter read. As a result a servicemen is dispatched to investigate the issue
which results in a much higher cost than if the ERT was proactively replaced
before the battery dies. This additional cost is primarily composed of
personnel labor and travel wages, vehicle costs, and the cost to produce an
estimated customer bill.
Reactive ERT Replacement Costs1, Per Unit
Avista personnel labor & travel time wages $100.36
Avista vehicle corrective call out cost $67.04
Cost to produce estimated bill when ERTs fail $12.93
Total $ 180.34
1These costs were calculated using the ERT Replacement Strategy Development study from
2012 and adjusted by adding a 2% annual inflation rate.

Washington & Idaho Proactive ERT Replacement Costs2, Per Unit
Contractor labor $54.25
Project management $0.75
Total $55.00
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 305 of 422

Oregon Proactive ERT Replacement Costs2, Per Unit
Contractor labor $25.00
Project management $0.75
Total $25.75
2These cost reflect 2022 contractor unit pricing per Avista Contract R-40780.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Replacing ERT modules is not a new process for Avista. Existing processes
and technologies will be utilized for this program.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
In 2022, an alternative solution that was considered for Washington was to
install Star Connected Grid Routers (CGR) devices in the gas only areas
where the 500G modules were not able to communicate through the AMI
mesh network. The Star CGR option would have taken much longer to
implement and would have also been much more costly than replacing the
ERT module, therefore the most timely and cost effective solution was to
replace the 500G module with a 550G module that would allow mobile reading
in the gas only areas.
An alternative solution for Oregon that was considered was to replace 7,000
ERTs based on it’s geographic location each year on a 15 year cycle
(represented by the yellow line in the graph in Section 1.4). This option
involves replacing a geographic cluster of ERTs. The benefit to this approach
is that the ERTs are located close to one another, which equates to less travel
time in-between ERT locations. The disadvantage to this approach is that the
oldest ERTs may not be replaced if they are outside of the geographic zone,
so there would be a higher quantity of ERT battery failures and customer
billing estimates. A third party contractor provided a cost estimate for both
replacement strategies and the cost to replace the oldest ERTs was not
significantly more than replacing the geographically located ERT clusters.
However the overall cost increase to replace by location was significant,
approximately $5,000,000 more over the life of the 15 year program, due to
the high number of expected unplanned replacements using this method vs
replace by age.
The run-to-failure cost to reactively replace the failed ERT modules was also
considered for Idaho and Oregon. When an ERT is run to failure the
customer’s bill is estimated and then corrected the next month after the ERT is
replaced. If this proactive replacement program is not funded there will be an
unmanageable quantity of ERTs failing each year and it is likely that the failed
ERT will not be replaced in one month’s billing cycle resulting in billing
estimates for multiple months. This will create customer dissatisfaction and
loss of trust. See below for breakdown of these risks.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 306 of 422
Assumptions:
1. Except for regulatory fines, cost estimates based on SME input.
2. Costs associated with each risk can vary significantly depending on site
conditions.

*Regulatory fines present a daily and overall maximum value per violation in accordance with
49 CFR Part 190.223. However, these values are not necessarily an accurate representation
of how much Avista would be fined for any specific violation. The actual amount is likely to be
much lower since Avista has an ongoing reputation and history of investing in programs
related to safety and non-compliance issues. However, it is a bookend reminder from which to
characterize the regulatory risk associated with chronic and/or egregious non-compliance,
especially in the event of a pipeline safety incident (i.e. failure). Therefore, Avista must
continue to demonstrate an ongoing commitment to compliance and pipeline safety to ensure
favorable future outcomes with respect to regulatory penalties (actual penalty amount is at the
discretion of the state or federal agency).
Over the life of the 15 year program in Oregon the asset management study
estimates that the cost of this run-to-failure approach would be approximately
$12,500,000 more than if a proactive and strategic replacement program was
executed. Refer to the cost analysis graph in Section 1.4 showing a
comparison between the preferred and alternative solutions.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
The Idaho program is planned to be competed by the end of 2023. The
Oregon program will be completed between January and December each year
on a 15 year cycle. The ERT modules are purchased as a pre-capital material
item under ER 1053 (Gas ERT Minor Blanket). The ERTs will become used
and useful upon installation on the meter.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 307 of 422
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely,
reliably, and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The replacement strategy described herein was optimized by Avista’s Asset
Management department to levelized the asset replacement cost, to optimize
the asset life-cycle, and to minimize the number of failed ERTs requiring
customer billing estimates. The program costs will be monitored monthly by
the program manager.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Avista gas customers benefit from the replacement of these ERT modules
because they will receive reliable and accurate billing.
Business case stakeholders including the ERT Replacement Program
manager, GIS Analyst, Sourcing Professional, Maximo Business Analyst, IT,
Service Credit Dispatch, and Oregon Gas Operations all work together to
ensure a successful program execution.

2.8.2 Identify any related Business Cases
ER 1053 Gas ERT Minor Blanket
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Asset Management department was consulted by Gas Engineering for
assistance developing a strategic program to replace ERT modules before
their battery expires. The result of the study suggested the optimized method
for replacing these assets that resulted in the highest customer satisfaction
and lowest cost.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 308 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
Using the replacement strategy recommended by Asset Management the ERT
Replacement Program manager works with GIS Technical Services to
determine the location of the oldest 7,000 ERT modules in Oregon. Each year
prior to starting work the oldest ERT locations are re-analyzed to ensure the
most accurate and up to date information. The third party contractor
performing the replacement work also provide field verification to ensure only
old ERTs are replaced.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The ERT Replacement Program is documented in a business plan and
prioritized in a spreadsheet. Each ERT replacement is documented in Maximo
with a work order.
Year to date spend and budget updates are reviewed monthly. Annually, the
Gas Engineering Prioritization Investment Committee (EPIC) reviews the 5
year plan and ensures the budget level is appropriate given other categories of
work and risk on the gas system.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas ERT Replacement Program, ER
3054 and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date: 8/31/22
Print Name: Jeff Webb / David Smith
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 309 of 422
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 310 of 422
EXECUTIVE SUMMARY
This annual program will replace or upgrade existing at-risk Gate Stations, Regulator
Stations and Industrial Meter Sets (“stations”) located throughout Avista’s gas territory in
WA, ID, and OR that are at the end of their service life and/or not up to current Avista
standards. Additionally, it will address enhancements that will improve system operating
performance, enhance safety, replace inadequate or antiquated equipment that is no
longer supported, and ensure the reliable operation of metering and regulating
equipment.
These stations require annual maintenance per 49 CFR 192.739 and if the equipment at
the station is obsolete and replacement/maintenance parts are no longer available, then
proper maintenance cannot be completed. Incomplete maintenance could cause Avista
to be out of compliance and be exposed to fines from the various state utility
commissions.
Avista’s gas customers from all jurisdictions benefit from these types of projects by
having a safer, more reliable, well maintained distribution system. Also, this is a prudent
way to spend resources because many deficiencies at a station can be remedied under
just one project.
This work is needed now because there is already a backlog of stations needing
replacement. The list of stations needing replacement continues to grow as stations
meet the end of their service life. Postponing the work will cause the list of stations
needing replacement to outpace the number of stations remediated.
Annual cost to fund this program is $1,000,000.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial version 3/17/2017 1.0
1.1 Jeff Webb 4/07/2017 1.1
2.0 Jeff Webb Revised for 2020 Oregon GRC
filing
2/17/2020 2.0
2.1 Dave Smith Updated to the refreshed 2020
Business Case template 6-24-20 2.1
2.2 Dave Smith Updated to the refreshed 2022
Business Case template 5-5-22 2.2

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 311 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Existing stations located throughout Avista’s gas territory in WA, ID, and OR have
a finite service life and will eventually no longer meet Avista’s current design
standards, may feature obsolete equipment, or may develop operational or safety
issues that need addressed in order to delivery safe and reliable gas service to
customers.
Another category of work in this program is moving regulator stations located
underground in a vault to a more traditional above ground configuration. Stations
located in vaults are difficult to maintain because of the limited working room for
tools and workers. Additionally, water in the vault can make maintenance more
difficult. Regulator Stations in a vault are also a safety concern as they are
confined spaces and can trap harmful levels of natural gas should a leak be
present.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
This program’s primary driver is asset condition. By replacing obsolete stations we
will continue to deliver safe and reliable gas service to customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This work is needed now because there is already a backlog of stations needing
replacement. The list of stations needing replacement continues to grow as
stations meet the end of their service life. Postponing the work will cause the list
of stations needing replacement to outpace the number of stations remediated.

Requested Spend Amount $1,000,000
Requested Spend Time Period Annually
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb/Dave Smith | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 312 of 422
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The success of the program can be measured by the completion of station
replacement projects. These stations are a vital link to providing gas service and
replacing obsolete stations will help Avista continue to deliver safe and reliable gas
service to customers.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
A master list of stations with reported deficiencies is maintained by Gas
Engineering.

Image 1 – Master List of Stations with Deficiencies
This list saved on the Avista network drive c01d44 and can be made available
upon request.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The master list of stations with reported deficiencies referenced in section
1.5.1 summarizes the issues at each station.
2. PROPOSAL AND RECOMMENDED SOLUTION
The requested level of spending for this program allows the high priority projects to
be completed every year. The list of new requests continues to grow as stations
meet the end of their service life. At this funding pace, the number of stations
remediated will slowly outpace the number added each year. The workforce
available to do this type of work is responsible for both maintenance of these
stations and the rebuild efforts. This level of spend complements their available time
well without requiring additional headcount.
Since these stations are a vital link to providing customers with reliable gas,
planned replacement work is preferred over unplanned work. Unplanned work
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 313 of 422
during times of high gas use (normally the winter) can be more difficult to perform
and have negative impacts to customers if it fails to operate properly.
Option Capital Cost Start Complete
Recommended Solution, Replace at risk stations at
requested funding level
$1,070,000 January December
Alternative Solution, Replace at risk stations at a
reduced funding level
$500,000 January December
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
A master list of stations with reported deficiencies is maintained by Gas
Engineering. Each year this list is evaluated by subject matter experts in Gas
Engineering and Gas Operations and the stations are prioritized by risk level.
Stations with the highest risk level are selected for completion while others are
deferred to future years. The workforce available to do this type of work is
responsible for both maintenance of these stations and the rebuild efforts. The
requested level of spend in the Recommended Solution complements their
available time well without requiring additional headcount.

Image 2 – Partial list of stations ranked by priority (only 2022-2023 are shown)

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 314 of 422

2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
prioritize and administer the work for the year. The work is generally
prioritized early in the year and then implemented throughout the spring,
summer, and fall. The work is typically comprised of several individual station
replacement projects.
Completion of this work will reduce O&M costs because stations that are at the
end of the end of their service life and/or are not up to Avista’s current
standards typically take longer to maintain. Refer to spreadsheet titled ER
3002 Cost Offset Calculations 2022-2023.xlsx showing the calculations for the
direct savings shown below.
The estimated direct savings were calculated with the following assumptions:
1. Average hourly maintenance rate is $85.00.
2. Cost of Living Adjustment rate is 3% per year.
3. Ten stations are replaced each year.
4. Rebuilding the station up to current standards saves an average of 1
hour of maintenance time per year.
5. The expected service life of a station is 40 years.
6. Avista’s average labor overhead rate between 2014 to present is 94%.
Quantified direct savings:
2022 Lifetime
Capital: - -
Expense: $1,700 $265,500
Total: $1,700 $265,500

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Gas Operations rely on station replacement projects as a vital part of their work.
The current level of spend complements their available time to do this work
without requiring additional headcount.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
There are two outcomes if this program is funded at a reduced rate. One is to
replace fewer regulator stations and industrial meter sets. There is already a
backlog of high risk stations to be replaced, so this approach would take an
even longer time to get through that backlog while new stations are continually
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 315 of 422
added to the list every year. Secondly, an alternative to rebuilding the entire
station would be to replace only the individual components that are antiquated
or outdated. If this short-sided course were chosen, the work would be less
productive and the opportunity to bring the entire station up to current
standards would be lost. This option is not recommended.
If the program were to not be funded, Avista would be forced to operate at-risk
stations in an unsafe, unreliable, and sometimes non-code compliant manner.
The risk of not doing the work includes, but is not limited to, regulatory fines,
pipeline leaks, pipeline failures and outages, negative company reputation,
and employee and public safety. O&M costs would escalate as the number of
unplanned visits to these stations would likely increase due to operating them
at or beyond their useful lives. This option is not recommended.
See below for breakdown of these risks:
Assumptions:
1. Except for regulatory fines, cost estimates based on SME input.
2. Costs associated with each risk can vary significantly depending on site
conditions.

*Regulatory fines present a daily and overall maximum value per violation in accordance with 49
CFR Part 190.223. However, these values are not necessarily an accurate representation of how
much Avista would be fined for any specific violation. The actual amount is likely to be much lower
since Avista has an ongoing reputation and history of investing in programs related to safety and
non-compliance issues. However, it is a bookend reminder from which to characterize the
regulatory risk associated with chronic and/or egregious non-compliance, especially in the event of
a pipeline safety incident (i.e. failure). Therefore, Avista must continue to demonstrate an ongoing
commitment to compliance and pipeline safety to ensure favorable future outcomes with respect to
regulatory penalties (actual penalty amount is at the discretion of the state or federal agency).
Risk Probability Definitions:
Very High (VH)Risk event expected to occur
High (H)Risk event more likely to occur than not
Probable (P)Risk event may or may not occur
Low (L)Risk event less likely to occur than not
Very Low (VL)Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
1 2 5 10 15+
1 L L L L L $225,134 per day per violation (Max)
$2,251,334 Total (Max)
2 L P P H VH $5,000 to $150,000 per site (site dependent)
3 L L P P H $150,000 to $3,000,000 per site (site dependent)
4 L L L P P Erosion of PUC and Public trust
5 L P P H H Lost time, lawsuits, healthcare , etc. (varies)
Pipeline Failure & Outage
Negative Reputation
Employee & Public Safety
Pipeline Leak
#Risk
Risk Over Time (years)
Cost Estimate
Regulatory Fines*
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 316 of 422
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
The program will be completed between January and December of each year.
The investments become used and useful to the customer at the completion of
each station rebuild project.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely,
reliably, and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The requested funding level is prudent to continue to serve safe and reliable
gas service to customers. A master list of stations with reported deficiencies is
maintained by Gas Engineering. Each year this list is evaluated by subject
matter experts in Gas Engineering and Gas Operations and the stations are
prioritized by risk level. Stations with the highest risk level are selected for
completion while others are deferred to future years. The workforce available
to do this type of work is responsible for both maintenance of these stations
and the rebuild efforts. This level of spend complements their available time
well without requiring additional headcount.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Avista gas customers in WA, ID, and OR benefit from this program as these
stations are utilized in all territories to deliver safe and reliable gas service.
Stakeholders including Gas Engineering, Gas Operations, and the Gas Meter
Shop work together to ensure a successful program execution.

2.8.2 Identify any related Business Cases
N/A.

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Gas Engineering is ultimately responsible for prioritizing the projects and reporting
out financial updates to the Capital Project Group.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 317 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
administer this program. Year to date spend and budget updates are reviewed
monthly. Annually, the Gas Engineering Prioritization Investment Committee
(EPIC) reviews the 5 year plan and ensures the budget level is appropriate given
other categories of work and risk on the gas system.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
A master list of Regulator Stations and Industrial Meter Sets with reported
deficiencies is maintained by Gas Engineering. Gas Operations and the Gas Meter
Shop report concerns while performing regular maintenance and these
deficiencies are collected on the master list. Annually, subject matter experts from
Gas Operations and Gas Engineering review the master list and risk rank the work
for the following year. Stations with the highest risk (typically due to multiple
different concerns) are prioritized over stations with only minor issues. Prioritizing
this work annually with the subject matter experts provides a consistent approach.
Through this process, the highest risk projects are selected to be funded. The
spend for each individual project that falls under this ER is monitored on a monthly
basis by the Project Engineers. Changes to the total annual spend for this ER is
monitored by the business case owner.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Regulator Station Replacement
Program, ER 3002 and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/29/22
Print Name: Jeff Webb / David Smith
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

8/29/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 318 of 422
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 319 of 422
EXECUTIVE SUMMARY

The Gas Planning department annually runs an analysis (load study) on Avista’s gas
distribution system to identify areas of the system with insufficient capacity to serve
existing Firm customer loads on a design day. These deficient areas are given a risk
ranking based on the severity and the number of customers impacted. The areas with
the highest priority are selected for remediation and the project is assigned to Gas
Engineering to evaluate options to provide sufficient capacity to meet Firm gas
demands on a design day. Options are reviewed with Gas Planning, Gas Operations,
and other interested parties. The pros and cons of each option are then reviewed with
the Gas Engineering Manager and a preferred alternative is selected to proceed with a
funding request. The business needs and potential solutions identified impact all gas
customers in Avista’s service territory. Spending per jurisdiction changes each year as
the intent is to complete the highest risk projects first, regardless of which State it is in.
The proposed annual budget is consistent with expenditures from past years. There is
currently a large backlog of projects. Significant progress has been made with
reinforcement projects in the past decade. It is anticipated that the funding for this ER
will be reduced in approximately five years, but not completely go away as
reinforcements will always be needed as new customers are added.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial version 3/17/2017
1.1 Jeff Webb 4/6/2017
2.0 Jeff Webb Revision for 2020 Oregon GRC
filing
2/17/2020

2.1 Tim Harding Updated to the refreshed 2022
Business Case Template
9/1/2022

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 320 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
This annual program will identify and provide for necessary capacity
reinforcements to the existing natural gas distribution system in WA, ID, and OR.
Avista has an obligation to serve existing Firm gas customers by providing
adequate capacity on design day weather conditions. Sufficient capacity is defined
as pressures at or above 15 pounds per square inch (psig) in the distribution
system on a design day analysis. Periodic reinforcement of the system is required
to reliably serve Firm customers due to increased demand at existing service
locations and new customers being added to the system. Execution of this
program on an annual basis will ensure the continuation of reliable gas service
that is of adequate pressure and capacity.
Typical projects completed under this Business Case may include (but are not
limited to) upsizing existing gas mains, looping existing gas mains (bringing in a
second source to an area), and installing new regulator stations (pressure
reduction stations). When a reinforcement is done by looping a system, there is a
secondary benefit of higher reliability to the area. Most of these projects will have a
unique project number assigned to them, but the smaller scope, lower cost
projects may be completed under the blanket project numbers set up for each
district.
Projects that are identified in this program are prioritized by a Gas Planning model,
see Image 1 below for a list of high and medium priority projects. The prioritization
is based on the computer model that analyzes actual meter usage data from each
customer, extrapolates that data to predict a demand load at design temperature
conditions, and then analyzes each gas distribution system to determine if
reinforcements are necessary. If system capacities are not sufficient the model
can also be used to determine the benefits of different types of reinforcement
projects by running “what if?” scenarios. Once the projects are identified, they are
risk ranked based on the number of customers affected and the temperature levels
at which the risks begin.
Requested Spend Amount $1,300,000
Requested Spend Time Period Annually
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb/Tim Harding | Jody Morehouse
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Program
Driver Performance & Capacity
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 321 of 422

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver for this business case is Performance and Capacity. Projects
also improve the reliability of the gas system by reducing the possibility of outages.
Customers benefit from this improved reliability.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
There are currently gas systems that will fail during extreme cold weather because
the system capacity cannot meet peak demand. By upgrading these systems we
reduce the chance of cold weather outages. At a minimum, outages are an
inconvenience to customers. They can, however, become a serious health and
safety concern because they tend to happen during extremely cold weather.
System outages that cause customers to be without heat during extreme cold
weather must be avoided.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
These system upgrades avoid system outages, as well as manual interventions
required to keep these systems operating during peak system demand.
Reductions in outage incidents and the reduction in field personnel intervention
can be measured.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
On an annual basis, the Gas Planning group reviews system load studies and
prioritizes future reinforcement projects. Below is an example of the list.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 322 of 422
Image 1 – Prioritized list of reinforcements

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION
The requested level of spending for this program allows some high priority projects
to be completed every year. The list of new requests continues to grow as system
deficiencies are discovered and as customer load growth increases. At a reduced
funding level, project backlogs grow longer leading to a higher chance of gas
outage incidents.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 323 of 422
Option Capital Cost Start Complete
Recommended Solution, Construct Reinforcement
projects at requested funding level
$1,300,000 January December
Alternative Solution, Construct Reinforcement
projects at a reduced funding level
$800,000 January December
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.
Gas planning uses load studies to predict system pressures during design day
weather (extreme cold) conditions. These studies determine the likelihood of system
outages, as well as how many customers are impacted. Avista has an obligation to
serve Firm customers, and because of this, gas systems must be designed to meet
these demands during all expected and planned weather conditions. The Company’s
cost to respond to a system outage can range from thousands of dollars to over one
million dollars.
2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531
Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
The entire budget is spent annually on the installation of gas mains and
regulator stations. The cost to respond to a system outage can easily exceed
the cost of funding a capital construction project that would reinforce the
system and avoid such an outage.
2.3 Outline any business functions and processes that may be impacted
(and how) by the business case for it to be successfully implemented.
The completion of reinforcement projects benefits the operations group. There
is less field intervention during cold weather events, and cold weather outages
are avoided. This reduces the chance of costly emergency responses that
require involvement from Corporate Communications, Supply Chain, Gas
Engineering, and others.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Without a Reinforcement Program, Avista does not have sufficient capacity to
meet our obligation to serve existing Firm customer load on a design day
scenario and is not able to support future customer growth.
It is important to note that if service is lost during severe cold weather, gas
service may not become available again until weather warms and customer
demand decreases. Depending on the length of the outage, this can cause
severe injury up to and including death to some customers. The process of
‘re-lighting’ after an outage and returning a gas system to service can cost
over $1M in some cases.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 324 of 422
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
Projects are constructed year-round. Smaller projects will be transferred to
plant on a monthly basis. Larger projects are transferred to plant upon project
completion.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely,
reliably, and at a fair price for our customers. Completion of this project
ensures gas service is “Always there for an always on world” and that we
Perform by providing reliable gas service to our firm customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Projects constructed within this program are specifically designed to address
severe system deficiencies. These projects are to prevent customers from
losing gas service (and heat) during extreme cold weather. They prevent
costly outage emergencies. In the future it is anticipated that, because of this
program, there will be fewer system deficiencies, and therefore a lower risk of
system outages. This should allow for a reduction in the program budget in the
future.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Customers in project areas will benefit from improved system reliability, as well
as increased system capacity.
Stakeholders include Gas Engineer, Gas Planning, and Gas Operations.
2.8.2 Identify any related Business Cases
N/A
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Using computer-based load studies, Gas Planning identifies areas of concern that
need reinforcement projects. Those projects are ranked by severity and the
highest priority projects are sent to Gas Engineering. These projects are managed
by the Gas Engineering group. Construction is completed by Gas Operations with
company or contract resources.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 325 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
The projects are managed by Gas Engineering and status updates are given to
Gas Planning several times a year to ensure that the highest priority projects are
being addressed first.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The list of projects to be constructed is assembled early in the year. If a new
project is added mid-year, Gas Planning is asked to prioritize the new project
against all un-completed projects. Late in the year the program budget is
reviewed, and projects are added or cut from the year’s schedule to keep the
program on-budget. Gas Planning prioritizes all projects being added or removed
to ensure that the highest ranked projects are constructed first.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Reinforcement
Program, ER 3000 and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Jeff Webb / Tim Harding
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

9/1/2022
9/1/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 326 of 422
EXECUTIVE SUMMARY

ER 3117 provides funding for additions, improvements, and replacements to our Gas Telemetry
system. The system provides safety related pressure monitoring including alarms at Gate
Stations, Regulator Stations, Pipelines, Odorizers, and Transport Customers. It also provides
significant data including consumption for gas procurement and billing, engineering analysis,
and system operations. It is important to our customers for safe and reliable operation of our gas
system and regulatory compliance for pressure monitoring.

Telemetry equipment includes flow computers, electronic volume correctors, and electronic
pressure monitors at new or upgraded regulator and gate stations. Also, system pressure
monitoring at ends of pipelines and multi-fed systems (required by Federal Code).

Some existing in-service equipment is obsolete and failing so replacements are required to
maintain functionality. Risks if not upgraded include reduced reliability and increased
maintenance costs to reactively repair sites. Regulatory compliance could be reduced and over
or under pressure events may not be detected early enough for corrective action which could lead
to a loss of gas service to customers or an overpressure event. Additionally, manual meter reads
and/or bill estimates could be required for some billing sites.

A portion of the budget estimates are based on a five-year plan (four years to go) to upgrade
most instruments with dial up modems by conversion to cellular communication through
instrument replacement. By stretching the replacement out to five years, there is a compromise
and some risk as addressed in the narrative below if the head end dial-up modem bank were to
completely fail in the next 4 years. The remainder of the annual budget request provides for
modest upgrades and additional system monitoring. Gas Engineering is responsible for
prioritizing and approving specific projects within this program.

VERSION HISTORY
Version Author Description Date Notes
1.1 Dave Moeller Business Case update for 2023 7-15-22

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 327 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Some existing Gas Telemetry equipment is obsolete, and failures are
increasing so it needs to be replaced. This includes the dial-up telephone
landline modem bank head end of the Gas Telemetry System. In order to
upgrade this obsolete communication form, it’s necessary to replace the field
instruments with IP based (mostly cellular) communication. Once all the dial up
field devices have been replaced, the head end modem bank can be retired.
Additional system monitoring is required for situational awareness, safety,
compliance, new Gas Transportation Customers, and system improvements
such as new or rebuilt gate and regulator stations.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
ER 3117 provides capital funding for additions, improvements, and
replacements for our Gas Telemetry system. The system provides pressure
monitoring including safety related alarms and history for pressure,
temperature, gas volumes, and gas flow rates at Gate Stations, Reg Stations,
pipelines, odorizers, and for Transport Customers where applicable.
Equipment includes flow computers, electronic volume correctors, and
electronic pressure monitors at new or upgraded regulator and gate stations.
Also, system pressure monitoring at ends of pipelines and on multi-fed
systems.
The system provides data to SCADA for Gas Control, to Nucleus for Gas
Procurement, and to the PI data base for use by all departments including Gas
Engineering, and Operations (Pressure Controlmen). It is important for safe
and reliable operation of our gas system, regulatory compliance with pressure
Requested Spend Amount $295,000, 304,000, 313,000, 322,000, 200,000
Requested Spend Time Period 2023 - 2027
Requesting Organization/Department Gas Engineering
Business Case Owner | Sponsor Jeff Webb / Dave Moeller | Jody Morehouse
Sponsor Organization/Department B51 / Gas Engineering
Phase Execution
Category Program
Driver Performance & Capacity
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 328 of 422
monitoring, operational monitoring, and billing data at gate stations and
Transport Customers.
For many of the Transport Customers, when replacing the instrument, we are
also improving safety by buying instruments with a second pressure
transducer. The dual pressure monitors allow for monitoring both the metering
and delivery pressure and can provide early warning to the Gas Control Room
of an abnormal event that could negatively impact the customer.
Continued investment in our Gas Telemetry System is a benefit to our
customers to continue to safely and efficiently operate and maintain our gas
transmission and distribution systems as well as provide accurate and timely
billing data.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
The requested funding is needed now to prevent extensive equipment failures
and the associated reduced situational awareness, timeliness of billing data.

A portion of the budget estimates are based on a five-year plan (four years to
go) to upgrade most instruments with dial up modems by conversion to cellular
communication through instrument replacement. By stretching the
replacement out to five years, there is a compromise and some risk as
addressed in the narrative and below if the head end dial-up modem bank
were to completely fail in the next 4 years. The remainder of the annual budget
request provides for modest upgrades and additional system monitoring

In addition to field devices, the obsolete dial up modem bank in the head end
of our system located in the SCADA area that communicates with field
instruments is experiencing individual modem failures more frequently and
could have a complete catastrophic failure any time. It is already operating
with reduced capacity causing longer times to poll all instruments. Landline
(POTS) dial up modems are obsolete, and parts are no longer available. At the
Transport Customer end, many have switched to IP based phone systems
which do not work well with dial up modems in the field, this creates extra work
for our technicians. The electric side of Avista has upgraded to all IP with no
remaining dial up modems
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 329 of 422
Significant failure of the POTS modem bank would seriously impair our ability
to communicate with approximately 76, or 1/3 of our ~230 instruments.
Communications needs to be upgraded to IP based with cellular being the best
option. Replacing POTS with IP communication also allows for the transfer of
all gas telemetry data to our Backup Control Center (BUCC) in CdA, Idaho.
The POTS modem bank is not replicated at the BUCC. Failure of the head end
communications (modem bank) would involve loss of visibility to critical system
operating conditions and less timely data for Gas Procurement. Without this
communication network in place, we’d need to rely on transport customers to
call in daily readings (not the 4-5x/day and the early timing we normally get
from our automated system).

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Our experience is that upgrading and replacing obsolete and failing
instruments at this funding pace has been, and is, very effective and prudent.
Internal customers such as Gas Control, Gas Procurement, Billing, Gas
Engineering, and Gas Operations all provide feedback on system
performance.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
N/A
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Some existing in-service field equipment is obsolete and failing so replacements
are required to maintain functionality. Risks if not upgraded include reduced
reliability and increased maintenance costs to reactively repair sites. Regulatory
compliance could be reduced and over or under pressure events may not be
detected early enough for corrective action which could lead to loss of gas
service to customers or an overpressure event. Additionally, manual meter reads
and/or bill estimates could be required for some billing sites.

Approximately 76 of the field devices that communicate with the obsolete dial
up modem bank in the head end of our system located in the SCADA area need
to be upgraded to IP based (cellular) communications. That modem bank is
experiencing individual modem failures more frequently and could have a
complete catastrophic failure any time. It is already operating with reduced
capacity causing longer times to poll all instruments. Landline (POTS) dial up
modems are obsolete, and parts are no longer available. At the Transport
Customer end, many have switched to IP based phone systems which do not
work well with dial up modems in the field which creates extra work for our
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 330 of 422
technicians. The electric side of Avista has upgraded to all IP with no remaining
dial up modems.

Significant failure of the POTS modem bank would seriously impair our ability
to communicate with approximately 76, or 1/3 of our ~230 instruments.
Communications needs to be upgraded to IP based with cellular being the best
option. Replacing POTS with IP communication also allows for the transfer of
all gas telemetry data to our Backup Control Center (BUCC) in CdA, Idaho.
The POTS modem bank is not replicated at the BUCC. Failure of the head end
communications (modem bank) would involve loss of visibility to critical
system operating conditions and less timely data for Gas Procurement. Without
this communication network in place, we’d need to rely on transport customers
to call in daily readings (not the 4-5x/day and the early timing we normally get
from our automated system).

2. PROPOSAL AND RECOMMENDED SOLUTION
ER 3117 provides capital funding for additions, improvements, and replacements for our
Gas Telemetry system. The system provides pressure monitoring including safety related
alarms and history for pressure, temperature, and gas volumes and gas flow rates at Gate
Stations, Reg Stations, pipelines, odorizers, and for Transport Customers where applicable.
76 dial-up instruments to be replaced with new with IP (cellular) comms x $7500 =
$570,000 total over four years or $142,500 annually for 19 sites/year for three more years.
The sites with dial up modems often have AC power so these sites will take less labor to
upgrade than a new site installation but similar costs for the materials for the basic
instrument. Unit cost averaged across all 3 states is estimated at $7500 each.
3 sites/year upgraded to flow computers for a total of $50,000.
5 new pressure monitors/year for a total of $65,000.
5 other instruments to be replaced that are already on IP (cellular) annually as they become
obsolete or fail for a total of $37,500.
Estimated Annual Totals $295,000 for year 1 with a 3% adder for inflation. Year 5 is less
at $200,000, assuming that the instruments with dial up modems have all been replaced.
By state: WA 43%, OR 26%, ID 31%

Option Capital Cost Start Complete
ER 3117 funding as described by year on page 2 $1.434M 1-1-23 12-31-27

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 331 of 422
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.

Typically estimates for desired work each year have been $400,000, however due to
budget constraints and other work we have been limited to $200,000 for several years.
This is catching up with us. We are experiencing more frequent failures with obsolete
instrumentation and communication devices causing unplanned replacements of those
items. This has caused the system to age beyond our ability to replace components.
Proactively planned replacements are more efficient than the run to failure mode we
are currently operating in.
In recent past, we’ve done capital work outside of ER 3117. For example, in 2019 all
obsolete cellular 3G modems were replaced with 4G/LTE modems for approximately
$200,000. In 2020-21 we added 25 new pressure monitoring instruments as part of the
Dithaizine Mitigation Project. Prior years also included capital work that was done as
part of the construction of a major gate stations, this type of work has slowed so most
of our technician’s time will be focused on ER 3117 capital projects and O&M
moving forward.
O&M has increased as the instrument base has grown so now less than half of the
Telemetry Technician’s time is available for capital projects.
The requested annual amount starting at $295,000 is a compromise based on projected
manpower availability and equipment purchases.

2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e., what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.

76 dial-up instruments to be replaced with new with IP (cellular) comms x $7500 =
$570,000 total over four years or $142,500 annually for 19 sites/year for three more
years.
The sites with dial up modems often have AC power so these sites will take less labor
to upgrade than a new site installation but similar costs for the materials for the basic
instrument. Unit cost averaged across all 3 states is estimated at $7500 each.
3 sites/year upgraded to flow computers for a total of $50,000.
5 new pressure monitors/year for a total of $65,000.
5 other instruments to be replaced that are already on IP (cellular) annually as they
become obsolete or fail for a total of $37,500.
Estimated Annual Totals $295,000 for year 1 with a 3% adder for inflation. Year 5 is
less at $200,000, assuming that the instruments with dial up modems have all been
replaced.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 332 of 422
By state: WA 43%, OR 26%, ID 31%

2.3 Outline any business functions and processes that may be impacted
(and how) by the business case for it to be successfully implemented.
Support from IT is required for provisioning cellular modems and adding or canceling
telephone land lines.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
When individual instruments including communications fail; periodic site visits are
required to verify proper operation including pressures and injection type odorizer
functions, Gas Control has to call the Interstate Pipelines to get info from their
SCADA systems, and Gas Scheduling has to request Gas Transportation Customers to
provide manual daily readings for procuring gas and billing. This all costs additional
time and money and reduces situational awareness, safety, and compliance.
Additional information about a backup plan if a catastrophic failure of the dial up
modem bank occurs before this work is completed:
Prioritize manual reads generally daily and dependent on weather and site type and
availability of Interstate Pipelines’ pressure and volume data. This on-site monitoring
for gate and reg stations requires manpower to be re-distributed from their normal
work and additional mileage so costs would increase, and other work may be deferred.
Ask Gas Transportation customers and Interstate Pipeline’s to provide daily reads via
email for daily consumption. Note that the majority of our most important / largest
Transport Customers and Gate Stations instruments are already communicating via
cellular modems.
Ask Gas Control to frequently contact the interstate pipelines’ Gas Control to monitor
pressures and alarms on their systems that affect Avista such as delivery pressure to
Avista.
Request an emergency job authorization to provide for expedited procurement and
installation of new field equipment with IP communication (cellular modems) and OT
hours.
Note that our gas transmission and distribution system functions autonomously and is
mechanically independent of any monitoring provided via telemetry. We do not
control any gas facilities via telemetry or SCADA.
Note that timing of a potential failure, winter peak vs. warmer temps and regional gas
supply, may have a significant impact on our Gas Supply Group and daily gas
nominations which would need to be estimated until data via telemetry returns.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 333 of 422
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
A portion of the budget estimates are based on a five-year plan (four years to go) to
upgrade most instruments with dial up modems by conversion to cellular
communication through instrument replacement. By stretching the replacement out to
five years, there is a compromise and some risk as addressed in the narrative and
below if the head end dial-up modem bank were to completely fail in the next 4 years.
The remainder of the annual budget request provides for modest upgrades and
additional system monitoring.
Instruments are placed into service as they are installed, typically monthly.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Gas Telemetry supports Avista’s goals of safe, reliable, cost effective, and efficient
delivery of natural gas to our customers.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Typically estimates for desired work each year have been $400,000, however due to
budget constraints and other work we have been limited to $200,000 for several years.
This is catching up with us. We are experiencing more frequent failures with obsolete
instrumentation and communication devices causing unplanned replacements of those
items. This has caused the system to age beyond our ability to replace components.
Proactively planned replacements are more efficient than the run to failure mode we
are currently operating in.
In recent past, we’ve done capital work outside of ER 3117. For example, in 2019 all
obsolete cellular 3G modems were replaced with 4G/LTE modems for approximately
$200,000. In 2020-21 we added 25 new pressure monitoring instruments as part of the
Dithaizine Mitigation Project. Prior years also included capital work that was done as
part of the construction of a major gate stations, this type of work has slowed so most
of our technician’s time will be focused on ER 3117 capital projects and O&M
moving forward.
O&M has increased as the instrument base has grown so now less than half of the
Telemetry Technician’s time is available for capital projects.
The requested annual amount of $295,000 is a compromise based on projected
manpower availability and equipment purchases.

2.8 Supplemental Information

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 334 of 422
2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders and customers of the data provided by Gas Telemetry include Gas
Control, Gas Operations, Gas Engineering, Gas Supply, Billing, Account
Executives
2.8.2 Identify any related Business Cases
N/A

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Gas Engineering in consultation with other groups such as Gas Operations, Gas Control,
Gas Supply, and Billing develops the planning, implementation, and performance of the
system.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Gas Engineering in consultation with other groups such as gas operations, gas control,
gas supply, and billing develops the planning, implementation, and performance of the
telemetry system.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Gas Engineering is responsible for identifying and prioritizing the work, getting
approval via the Capital Project Request (CPR) procedure, and initiating changes via
the Gas Management of Change (GMOC) process where applicable such as any
instrumentation sending data to SCADA for use by Gas Control.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the ER 3117 – Gas Telemetry Business
Case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date: 8/30/22
Print Name: Jeff Webb / Dave Moeller
Title: Manager Gas Engineering
Role: Business Case Owner

Signature: Date: 8/31/2022
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 335 of 422
Print Name: Jody Morehouse
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 336 of 422
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY
As an operator of gas infrastructure, Avista Utilities is required by regulation to minimize the impact of safety
and integrity of the pipeline facilities due to human error that may result from an individual’s lack of knowledge,
skills, or abilities during the performance of certain activities, or covered tasks. Craft Training and Gas
Operations are responsible for ensuring a qualified and competent workforce. This is partially accomplished
by evaluating and qualifying internal and contract employees on Operator Qualification tasks specific to
Avista’s natural gas infrastructure.

This business case will provide the tooling, vehicles, and equipment necessary to enable internal Avista
Evaluators to evaluate Avista “non-peer” employees and contract personnel under the PHMSA regulations
for Operator Qualification. Further, the tooling, vehicles and equipment may be used by Avista’s Evaluators
to maintain proficiency in the tasks required by the program and to design, construct and implement new
testing tools, techniques and technologies. Not providing these resources would result in the Evaluators
being unable to perform their duties, possibly resulting in regulatory penalties and incidents that impact
Avista’s customers and the public. This project will support Avista’s gas operations in Idaho, Washington
and Oregon. The total cost of the recommended solution to support these activities is $185,000 over a 5-
year period or $37,000 annually.

VERSION HISTORY
Version Author Description Date Notes
Draft Joe Brown Executive Summary Only 7/6/2020 Business Case 2020 Refresher
1.0 Joe Brown Final version for 2020 capital update 7/29/2020 Full amount approved
1.1 Joe Brown Reviewed for Approval 7/13/2021 No Changes Required

GENERAL INFORMATION

Requested Spend Amount $185,000
Requested Spend Time Period 5 years
Requesting Organization/Department Craft Training and Operator Qualification [I02]
Business Case Owner | Sponsor Joe Brown | Jeremy Gall
Sponsor Organization/Department Human Resources
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 337 of 422
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 2 of 6
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Growth and high attrition rates in the Natural Gas industry has led to a workforce shortage of trained and
competent personnel. Employing this workforce has resulted in several safety and quality control issues on
Avista’s natural gas infrastructure.
Currently, Avista Utilities evaluates internal personnel by utilizing loaned employees from Gas Operations to
evaluate other peer employees. The utilization of peer craft employees to conduct evaluations is not recognized
as a best practice in the natural gas industry.
Further, Avista’s Gas Contractors train and evaluate themselves on Avista’s covered tasks. These activities are
conducted independent of Avista’s oversight. Evaluation of contract employees by contract employees, with no
utility oversight, is not recognized as a best practice in the natural gas industry.
Recent safety and quality incidents in the field and questionable evaluation practices has demonstrated the need
for direct evaluation by internal, “non-peer”, Avista evaluators for Operator Qualification. This unbiased evaluation
practice will determine the knowledge, skill and ability of personnel and ensure the integrity of qualifications.
The following regulations outline the requirements of Operator Qualification that must be met by Avista as an
Operator of a natural gas utility. These requirements apply to both internal and contract employees.
1. Background. 49 C.F.R. §§ 192.803 through 192.809 prescribe the requirements associated with qualifications
for gas pipeline company personnel to perform "covered tasks." 49 C.F.R. § 192.801 contains a definition of
"covered task." In WAC 480-93-999, the commission adopts 49 C.F.R. §§ 192.801 through 192.809. However,
in this section, the commission includes "new construction" in the definition of "covered task."
2. Accordingly, for the purpose of this chapter, the commission defines a covered task that will be subject to the
requirements of 49 C.F.R. §§ 192.803 through 192.809 as an activity, identified by the gas pipeline company,
that:
a. Is performed on a gas pipeline;
b. Is an operations, maintenance, or new construction task;
c. Is performed as a requirement of Part 192 C.F.R.; and
d. Affects the operation or integrity of the gas pipeline.
3. In all other respects, the requirements of 49 C.F.R. §§ 192.801 through 192.809 apply to this chapter.
4. The equipment and facilities used by a gas pipeline company for training and qualification of employees must
be similar to the equipment and facilities on which the employee will perform the covered task.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary business driver for this business case is Mandatory & Compliance and the secondary drive is
Customer Service Quality. Avista must have and execute an OQ Program in order to maintain compliance with
laws, rules and regulations. Secondarily, the safety and quality of Avista’s gas delivery business is greatly
impacted by the testing program carried out through the implementation of the OQ program.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista’s OQ Program is in its implementation stage and must be funded. Deferring or canceling this funding
altogether exposes the company to regulatory risk and possible fines.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 338 of 422
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 3 of 6
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The implementation of this new evaluation process for the OQ Program began on June 1, 2020. Monitoring,
metrics and reporting will be developed based on this implementation stage. Currently, Avista has more than
350 active contractors that go through testing and evaluation. Lagging safety and quality metrics may be used
in the future to assess the success of this change in program execution.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
No studies have been conducted to date. This business case supports an industry “best practice”
where non-peer employees with evaluate personnel on OQ tasks.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
NOT APPLICABLE

The proposed solution is to obtain the resources needed for OQ Program evaluation
This is the least cost alternative from a capital perspective when considering the risks associated with outsourcing
the OQ evaluations to a third party, or fully funding all tools and equipment.

Option Capital Cost Start Complete
1. OQ Evaluator Tools and Material – Partial $185,000 01 2021 12 2025
2. OQ Evaluator Tools and Material – Full $460,000 01 2021 12 2025
3. Outsource OQ Evaluator Program $0 01 2021 NA
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
For the recommended solution (Option 1) [OQ Evaluator Tools and Material – Partial], this amount is based
on the estimate of tools and equipment that will need to be purchased and utilized annually in order to
support the program. The tools and equipment in this solution will be shared among the Spokane and
Oregon locations and there will not be significant duplicate. This will slightly increase O&M expense due
to travel and sharing of equipment among evaluators.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This is a compliance program and there are no O&M offsets associated with the project.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The greatest impact of this business case is on Gas Operations and Avista’s Gas Customer. Gas
Operations contracted resources will be tested through this program which may result in safer, higher
quality work products. Avista’s Gas Customer may receive safer, better service in the areas where Avista
utilizes contract personnel for gas work.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 339 of 422
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 4 of 6
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
For the recommended solution (Option 1) [OQ Evaluator Tools and Material – Partial], this amount is based
on the estimate of tools and equipment that will need to be purchased and utilized annually in order to
support the program. The tools and equipment in this solution will be shared among the Spokane and
Oregon locations and there will not be significant duplicate. This will slightly increase O&M expense due
to travel and sharing of equipment among evaluators.

For Option 2, it is estimated that Avista may need to spend $92,000 annually in order to purchase each
evaluator their own tools and equipment utilized for skill evaluations. This would include upgrading existing
equipment and replacing all outdated equipment. This includes many of the tools and materials utilized
by contractors, such as leak survey and locating, that are extremely capital intensive. We believe the
prudent decision is to share this equipment among the evaluation areas and reduce the overall capital
spend.

Finally, for Option 3, OQ skill evaluations could be outsourced to a 3rd Party contract resource. This
outsourced testing model has been adopted by some peer companies. This option is estimated to cost
more than $600,000 in O&M alone, not to mention the risk this option would pose from an employee morale
and labor relations perspective. Further, this option does not drive a culture of safety, compliance and
quality that we hope to achieve by executing on Option 1.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Equipment and tools will be purchased on an annual basis and will become ‘used-and-useful’ during the
year as the evaluators implement the resources in the field.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This investment aligns with two of Avista’s key Focus Areas of ‘Our Customers.’ and ‘Perform.’.
When it comes to Avista’s customers, this program promotes transparency in the safety, quality and
integrity of Avista’s work product delivered to each customer. The safety and integrity of the gas system
depends on a highly skilled workforce, and this program helps ensure these skills meet or exceed Avista’s
standards. Regarding performance, this program helps ensure customers are served with safe and
reliable infrastructure.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Avista must comply with laws, rules and regulations as well as provide customers with safe, reliable gas
resources. This program helps ensure the safety and quality of Avista’s gas system. As stated previously,
this program was implemented on June 1, 2020 and monitoring, metrics and reporting will be developed
as part of the ongoing program as it is executed.
2.8 Supplemental Information

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 340 of 422
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 5 of 6
2.8.1 Identify customers and stakeholders that interface with the business case
Key internal stakeholders include Craft Training, Gas Operations, and Compliance. Key external
stakeholders include Avista’s Customers and 3rd Party Contractors.
2.8.2 Identify any related Business Cases
NA
3.1 Steering Committee or Advisory Group Information
See the governance process below
3.2 Provide and discuss the governance processes and people that will
provide oversight
As a practical matter, the OQ Evaluators [3] will plan their needs for tools, materials and equipment with the
Manager or Craft Training &OQ. The team will prioritize their needs and manage the funds accordingly.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Manager or Craft Training & OQ will be responsible for prioritization, change requests, documentation and
monitoring of this project.

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 341 of 422
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 6 of 6

The undersigned acknowledge they have reviewed the Gas Operator Qualification
Compliance Business Case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Joe Brown
Title: Mgr Craft Training & OQ
Role: Business Case Owner

Signature: Date:
Print Name: Jeremy Gall
Title: Sr. Mgr Safety & Craft Training
Role: Business Case Sponsor

Signature: NA Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
7/13/2021
7/19/2021
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 342 of 422
EXECUTIVE SUMMARY
Avista co-owns a natural gas storage reservoir, Jackson Prairie (JP) Underground Natural
Gas Storage Facility (JP). The JP natural gas storage facility is a critical component of
Avista’s overall natural gas supply strategy. Avista does not own any natural gas wells
or supply facilities. The Company purchases all gas supply on behalf of its customers
from multiple market trading hubs including AECO, Sumas, and Rocky Mountains. Avista
has also secured adequate gas pipelilne transport rights to ensure that all purchased gas
can be reliably moved to serve customer load. In order to reduce the exposure to market
prices, Avista also owns a third of the overall storage capacity at the JP gas storage
facility in southwest Washington. Having gas storage allows Avista to inject gas when
prices are lower and then withdraw gas duing the winter peak use months when market
prices are historically higher in order to keep customer rates affordable. All three owners
share equally in the annual expense costs to operate the facility and the capital
investments to improve operations, meet regulatory requirements and reduce future risks.

The three owners have contracted with PSE to operate the JP storage facility. The plant
operations management creates an annual and five year capital budget plan to ensure
the storage facility is operated safely, reliably, and meets all federal and state regulatory
requirements. Each owner has a representative that meets at least quarterly with the
operating staff to review current operating performance, discuss current project spend
and approve annual and five year budget plans. The Director of Energy Supply
represents Avista on the Owners Committee and approves all annual and five year
budgets after consulting with the Gas Supply department. The Manger of Gas Design is
Avista’s alternate representative on the Owners Committee and is also consulted on all
budget decisions.

Without the JP gas storage facility, Avista customers would be completely exposed to
market conditions that can be extremely volital at times. The ability to inject gas into
storage during lower priced time periods and withdrawal gas during high prices or peak
load periods allows Avista to reduce customers’ exposure and risks to real-time market
prices and improve reliable service to customers. Avista’s one third share of JP allows
the utility to meet 100 percent of its customers’ peak winter demand with the facility’s
stored reserves.

VERSION HISTORY
Version Author Description Date Notes
1.0 Scott Kinney Annual Business Case Update 08/23/2022

DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 343 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
This request is for the ongoing funding for the capital costs associated with the
JP operations.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The drivers for funding JP are Perfromance and Capacity. JP provides solutions
for the following gas supply needs:
 Stored gas supply that enables Avista to reliably serve customers during
peak load demand.
 Risk mitigation for shielding customers from extreme daily gas price volatility
during cold weather or other events affecting the natural gas commodity
market.
 A mechanism for purchasing gas at lower prices during off-peak periods for
use during high cost periods.
All commodity price benefits resulting from the utilization of JP are passed along
to the customer through the annual PGA filings.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
JP is a functioning natural gas storage project that has critical ongoing capital
funding requirements for ensuring continuous safe and reliable operation of the
facility. Not funding JP at the requested levels increases a number of risks for
plant operations including, but not limited to, non-compliance with Pipeline and
Hazardous Materials Safety Administration’s underground storage safety
mandates, deliverability during peak demand periods, reduced physical plant
Requested Spend Amount $11,606,000 (Avista’s 1/3 cost obligation)
Requested Spend Time Period 5 Years
Requesting Organization/Department Natural Gas Energy Resources
Business Case Owner | Sponsor TBD | Scott Kinney
Sponsor Organization/Department Energy Resourses
Phase Execution
Category Program
Driver Performance & Capacity
DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 344 of 422
security, reduced efficiency of plant output, or increased likelihood of component
failure resulting in unplanned outages.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The storage project is continually managed and monitored for optimal storage
volume, injection and withdrawal performance, and other key operational
metrics. An operations report is submitted to the JP Management Committee
on a monthly basis. Additionally, the report provides a current and projected
budget status.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
The JP natural gas storage facility is a critical component of Avista’s overall natural
gas supply strategy to ensure reliable and affordable delivery of gas to meet customer
needs. Avista does not own any natural gas wells or supply facilities. The Company
purchases all gas supply on behalf of its customers from multiple market trading hubs
including AECO, Sumas, and Rocky Mountains. Having gas storage allows Avista to
inject gas when prices are lower and then withdraw gas duing the winter peak use
months when market prices are historically higher in order to keep customer rates
affordable.
Option Capital Cost Start Complete
Ongoing annual funding for JP capital budget 2,370,000 01 2023 12 2023
2,421,000 01 2024 12 2024
2,410,000 01 2025 12 2025
2,410,000 01 2026 12 2026
1,995,000 01 2027 12 2027
5 Year Total $11,606,000 01 2023 12 2027
Rely on spot market for all gas purchases $Unknonw - High
risk and depends
on daily market
price
01 2023 12 2027

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The budget and associated annual projects are prepared and developed by the
JP facility operations team and provided to the Owners Management Committee
DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 345 of 422
for review and approval. Projects are informed by a number of supporting
documents, including:
 Engineering studies and ongoing operational monitoring data
 Risk gap analyses and risk mitigation plan
 Actual operational performance results
 Safety compliance and other regulatory mandates and requirements
 Contractual obligations
 Asset maintenance and replacement schedules
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative).
The capital dollars will be spent throughout the year according to the capital
budget scheduling plan prepared by the JP operations team and approved by
the Owners Management Committee. An updated budget status is provided
monthly to track the spending. No O&M reductions are estimated as a result of
this investment but the operation of JP helps provide reliable gas service to
customers and reduces market exposure risk.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
JP is one third owned by Avista but operated by Puget Sound Energy. No
impacts to other Avista business functions or processes are anticipated by this
business case.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
No cost effective alternatives exist for replacing JP. Because JP is a unique
solution that provides benefits/solutions for an array of supply needs, it would
likely require multiple business solutions to replace the resource functionality
provided by JP, none of which could fully duplicate the benefits of JP nor be cost
competitive with JP.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
The annual capital spending for JP includes multiple capital improvement
investments, which become used and useful at the end of each budget year.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
JP is a critical integrated supply resource for our natural gas business. JP helps
enable the delivery of natural gas energy safely, responsibly, and affordably to
our customers. Without JP customers would be exposed to market price
volatility risk and the need to acquire more pipeline transport capacity to the
different gas supply regions.
DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 346 of 422
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The requested capital budget amount is prudent and has been reviewed and
approved by the JP Management Committee (described below). The capital
budget amount will provide for and ensure the continuous operational
performance contractually mandated by the JP owners, and licensed by FERC.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Internal stakeholders include the Director of Energy Supply, Gas Supply and
Gas Engineering. External stakeholders who directly interface with the business
case include the two other ownership partners; PSE and Williams-NWP.
Additionally, the Pacific Northwest (PNW) natural gas market and pipeline
operation are directly affected by JP operations. JP provides critical supply
delivery funcationality to the PNW pipeline grid, especially during peak demand
times.
2.8.2 Identify any related Business Cases
This business case replaces the 2022 Jackson Prairie Joint Project Business
Case
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
A JP Owners Management Committee meets at least quarterly to review and
approve the capital budget status for the current year as well as to review and
approve any ongoing or future expenses. A business representative from each
of the 3 ownership partners has final approval authority on the Committee. The
decisions are documented in the minutes of the meeting. Occasionally, a
decision is made through email correspondence and is retained by the JP
general manager. A monthly report is provided to the owners that includes the
budget statue. The Director of Energy Supply is the Management Committee
representative for Avista and the Manger of Gas Supply is the alternate
representative.
Avista’s Risk Management Committee (RMC) oversees corporate decisions that
affect joint energy resource projects including the Jackson Prairie Storage
Project.
DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 347 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Director of Energy Supply is responsible for management of the JP contract
including Avista’s ownership, operating rights, and budget. The Director of
Energy Supply works with the Manager of Gas Supply to manage Avista’s
operational rights to fill and withdraw gas from the storage facility as governed
by Avista’s Risk Management Policy and the Risk Management Committee.
The Manager of Gas Design and Planning also participates in the Owners
Management Committee to provide input and feedback on proposed projects.
Resource Accounting reviews and manages the monthly invoices received from
the JP operator and prepares them for approval by the Director of Energy
Supply.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Director of Energy Supply reviews the monthly budget updates provided by
the JP operator. The operator manages project spend to stay within owner
approved budgets. However if any changes or adjustments to project spend are
required the Director of Energy Supply will communicate change requests with
the Capital Planning Group for discussion and approval.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Jackson Prairie Natural Gas Storage
Facility business case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: (TBD)
Title: Director Energy Supply
Role: Business Case Owner

Signature: Date: 8/23/22
Print Name: Scott Kinney
Title: VP Energy Resources
Role: Business Case Sponsor

Signature: Date:
Print Name:
DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 348 of 422
Title:
Role: Steering/Advisory Committee Review

DocuSign Envelope ID: CBD7050C-0912-4A46-B510-A37DA131038C
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 349 of 422
Apprentice Craft Training
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY
Avista manages 11 Federally regulated apprenticeships that require instructional aides, facilities and
equipment deemed necessary to provide quality instruction. [Regulated by 29 CFR 29 & 30] The Joint
Apprenticeship Training Committee (JATC) administers these apprenticeships supported by the Craft
Training Department. These funds are used to purchase tools, materials, equipment and make minor facility
improvements for training apprentices and journey workers in all crafts. These tools and materials provide
for related instruction that is closely correlated with the practical experience and training received on the job.
The trained and competent workforce produced through the various apprenticeship’s benefits customers in
all Avista service territories. These apprenticeship programs further benefit Avista’s customers by providing
a safe, proficient and skilled workforce.

Support of apprenticeship at Avista through this capital program aligns strategically to Avista’s Mission and
Focus Areas. In order to deliver innovative energy solutions safely, responsibly, and affordably, Avista must
have a field workforce of highly proficient professionals. This professionalism is achieved through
apprenticeship. Without this funding, Avista will not have the ability to train in-house. This leaves Avista’s
customers without critical craft positions needed for energy delivery. Further, there is a potential that
regulating bodies may de-certify Avista’s Apprentice program, leaving Avista without the ability to train in-
house and require significant expense to meet labor demands and maintain required skillsets. This project
will train apprentices in all Avista states and service territories, the rate jurisdiction is Common Direct –
Allocated All. The total capital expense to support this ongoing project is $375,000 over 5 years or
$75,000/year.

VERSION HISTORY
Version Author Description Date Notes
1.0 Joe Brown Updated for Approval 8/25/2022 Full amt approved; updated

Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 350 of 422
Apprentice Craft Training
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
This capital program provides for tools, materials and equipment for training apprentices and journey
workers across eleven skilled crafts or trades. This training consists of hands-on skills development
that builds competency in a safe learning environment that may not always be available or controllable
in the field. A well trained and competent workforce ensures reliable delivery of energy to Avista’s
customers and maintains a safe environment for employees, customers and the general public in all
Avista Utilities service territories. Being unable to provide these needed tools, materials and equipment
leaves apprentices and journeyman without the resources needed for their related instruction.

As stated previously, support of apprenticeship at Avista through this capital program aligns
strategically to Avista’s Mission and Focus Areas. In order to deliver innovative energy solutions safely,
responsibly, and affordably, Avista must have a field workforce of highly proficient professional. In
addition to creating a safe and skilled workforce, this training helps Avista to deliver timely training on
new and emerging technologies as well as meet several federal and state mandated regulations
including:
• Department of Labor, Standards of Apprenticeship – Title 29 CFR 29.5 (b)(4) and (b)(9) –
Apprentice on the job training and related instruction
• Department of Labor, Occupational Safety and Health Standards – Title 29 CFR 1910.269 (a)(2)
– Electric Power Generation, Transmission, and Distribution training
• Department of Transportation, Transportation of Natural Gas and Gas by Pipeline: Minimum
Federal Safety Standards - Title 49 CFR 192.805 (h) – Qualification of Pipeline Personnel,
Qualification Program training
• State of Washington – WAC 480-93-013 (4) – Covered Tasks: Equipment and facilities used by
pipeline company for training and qualification of employees
Requested Spend Amount $375,000
Requested Spend Time Period 5 Years
Requesting Organization/Department Craft Training [I02]
Business Case Owner | Sponsor Joe Brown | Jeremy Gall
Sponsor Organization/Department Human Resources
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 351 of 422
Apprentice Craft Training
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver of this business case is Mandatory & Compliance with the secondary drivers being
Customer Service Quality & Reliability and Performance & Capacity. Avista must meet comply with
the laws, rules and regulations associated with apprenticeship. Further, customer service and asset
performance will benefit from a highly skilled workforce.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista will not have the ability to train in-house if this program is not funded. This leaves Avista’s
customers without critical craft positions needed for energy delivery. Further, there is a potential that
regulating bodies may de-certify Avista’s Apprentice program, leaving Avista without the ability to train
in-house and require significant expense to meet labor demands and maintain required skillsets
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Ensure all apprentices receive training and support from instructors/journeyman in accordance with
regulatory requirements and meet the minimum of 144-hours of related instruction.
Training Progam Metrics 2021 2020 2019
Apprentices — All Crafts:
Total number of apprentices trained 69 80 74
Number of active programs 11 11 11
Hours of training on the job 140,033 132,838 153,920
Hours of classroom training 9,735 9,235 10,967
Journeyman Training:
Electric/Generation 6,757 3,192 8,764
Gas refresher - hours 2,228 2,882 3,380

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The cost to outsource hands-on-training and field simulations would be approximately $473,000 a year
for facility rental alone. This is based on current training programs that have averaged over 530 hours
per year at the training center. The overall annual costs including travel, lodging, meals and
registration are estimated to more than triple this rental cost and be classified as operations and
maintenance costs. It is estimated this total cost would be approximately $2.4M in O&M expense over
5-years. Again, this would result in a negative impact to Avista’s customers; do not attach]
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 352 of 422
Apprentice Craft Training
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement. [NA]
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution (Option 1) is to provide resources needed [tools, materials, facility] to
ensure related instruction of craft personnel

Option Capital Cost Start Complete
1. On-Going Capital Improvement Program $375,000 01 2023 01 2027
2. Outsource All Training $2.4M 01 2023 01 2027

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The cost to outsource hands-on-training and field simulations would be approximately $473,000 a year
for facility rental alone. This is based on current training programs that have averaged over 530 hours
per year at the training center. The overall annual costs including travel, lodging, meals and registration
are estimated to more than triple this rental cost and be classified as O&M costs.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Under this program, projects could include items such as improving facilities or expanding existing
facilities, purchase of equipment needed, or build out of realistic utility field infrastructure used to train
employees. Examples include new or expanded shops, truck canopy, classrooms, backhoes and other
equipment, build out of “SmartCity”- commercial and residential building replicas, and distribution,
transmission, smart grid, metering, gas and substation infrastructure.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The greatest impact will be seen by Avista’s Operations and Avista’s Customers. Operations will have
employees with the knowledge and skills to do their jobs professionally, and customers will be served
by these competent professionals.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The primary alternative for this program is to outsource all training. If this is done, at great expense,
there will be significant impact on operating budgets, company culture, and possibly labor relations.
These impacts may result in poor customer service and reduced reliability.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 353 of 422
Apprentice Craft Training
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
The projects associated with this business case will be planned on an annual basis and be used and
useful during the calendar year in which they are implemented.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Support of apprenticeship at Avista through this capital program aligns strategically to Avista’s Mission
and Focus Areas. In order to deliver innovative energy solutions safely, responsibly, and affordably,
Avista must have a field workforce of highly proficient professionals. This professionalism is achieved
through apprenticeship. This is an investment in Our People. Providing Avista’s employees with the
tools, equipment and materials they need to train in a safe, simulated environment is essential: This is
an investment in the people of Avista and allows these apprentices to deliver value to customers and
the communities they serve.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Apprentices are the future workforce of Avista service Avista’s customers. Ensuring that they have
the facilities, equipment, tools and materials they need to become successful journeyman is an
investment in the future. Taking care now to invest in the future workforce will benefit Avista’s
customers and operations.
This project will be evaluated annually in the Craft Training Department and ensure projects of the
highest need area addressed.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The key stakeholders associated with this business case are primarily internal Avista employees and
departments.
2.8.2 Identify any related Business Cases
NA

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
As part of the Craft Training annual planning process, the list of projects for apprenticeships will
be established, vetted and managed within the department. The manager of Craft Training & OQ
will be accountable for the business case and annual funding.
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 354 of 422
Apprentice Craft Training
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6
3.2 Provide and discuss the governance processes and people that will
provide oversight
Oversight will be provided by the Manager of Craft Training & OQ, and through periodic meetings with
the Sr. Manager of Safety & Craft Training.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The manager of Craft Training & OQ will be accountable for making decisions on the business case
in coordination with the Sr. Manager of Safety & Craft Training.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Apprentice Craft Training Business
Case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Joe Brown
Manager, Craft Training
8/25/2022
8/29/2022
Director, Safety & Craft Training
Jeremy Gall
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 355 of 422
EXECUTIVE SUMMARY

The Capital Equipment Program (ER7005/7006) funds the essential tools required
for Avista employees to perform work efficiently and safely. This equipment is
necessary to construct, monitor, ensure system integrity, and properly repair and
maintain the Avista systems (electric, gas, communications, fleet, facilities, and
generation). This equipment needs to be fully functional and available for planned
work as well as emergency outage repairs on our facilities and equipment. Capital
tools are utilized in all service territories, and by all Crafts. Capital tools are
required to execute and support work across all business units, and it is
recommended to continue to fund these tools at an annual level of $2.5M.

Capital tools benefit customers by reducing labor cost due to improved efficiency
and improving quality of the work by advanced performance of the tools.
Customers will also benefit from improved system reliability and reduced outage
duration enabled by diagnostic tools. It is critical that capital tools are consistently
and adequately funded year over year to maintain performance and ensure tool
availability. The risk of not funding capital tools is reduced work performance,
increased safety risk, reduced work quality, and increased outage time for
customers.

VERSION HISTORY
Version Author Description Date Notes
Draft Cody Krogh Initial draft of original business case 2/11/2020
1.0 Cody Krogh Updated plan to new outline 7/13/2020
2.0 Gary Shrope Yearly Update 5/20/2022

GENERAL INFORMATION
Requested Spend Amount $2,500,000.00
Requested Spend Time Period 5 years
Requesting Organization/Department Supply Chain
Business Case Owner | Sponsor Cody Krogh | Alicia Gibbs
Sponsor Organization/Department H51 Supply Chain
Phase Monitor/Control
Category Program
Driver Asset Condition
DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Each year, the Capital Equipment Program has more requests for tools and
equipment The funding deficit prevents the purchase of all submitted requests.
In addition, there is a trend of decreased funding for the capital tools. Over this
same time period, the tool complement has been expanding by replacing
manual tools with battery assist devices to increase safety and productivity.
These additional tools will require more funding, over time, to support
replacement costs, as well as ensure all areas of the company can take
advantage of this technology.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The Capital Equipment Program (ER7005/7006) funds the essential tools
required for Avista employees to perform work efficiently and safely. This
equipment is necessary to construct, monitor, ensure system integrity, and
properly repair and maintain the Avista systems (electric, gas, communications,
fleet, facilities, and generation). Much of the capital equipment used in the utility
industry is very specialized and may not be readily available due to long lead
times. This equipment needs to be fully functional and available for planned
work as well as emergency outage repairs on our facilities and equipment.
Equipment failures contribute to injuries, slowdowns in work performance, and
increased customer restoration time.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This work is needed to ensure that our workers have safe and reliable tools to
complete their tasks, and also to ensure that if there are any tools that are
broken, they can be replaced in a timely matter to keep projects/tasks on
schedule. If this work is not approved/deferred the risks include breakage of
equipment that is critical to daily operations/projects leading to longer lead times
for repairs or project completion. Also, our employees need safe tools to ensure
there are no injuries on the job. By having these updated through this program,
we can increase our productivity by having tools that will allow us to complete
our work efficiently on time and increase the safety of our employees.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The Capital Equipment Committee (CEC) ensures that the investment
successfully addresses all capital equipment requests to ensure each is
warranted. The CEC also ensures that each request is prioritized based upon
importance of need and equal allocation of funds for capital equipment requests.
DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Attachment 1: Email from Tony Klutz describing the benefits of the Capital Equipment
Program
Attachment 2: Scoring Criteria & Weighting
Attachment 3: Capital Equipment Committee Board Charter
Attachment 4: Capital Committee Notes
Attachment 5: Business Case Model / Offset Costs
NOTE: All files are stored in the “N-Drive” under “Capital Budget”, then
“Business Case Folder”.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The safety project for ergonomic related battery assist tools was widely implemented in
2016 with the addition of 44 battery assist tools. This was followed by 2017 with 75 tools,
2019 with 58 tools. This equipment has a 5-year warranty, so future failures for 5-year-
old equipment will not be covered by the warranty. Replacements for these out of
warranty tools will need to be budgeted for within the ER7006 budget each year, as per
all additional “new” capital equipment.
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital
Cost
Start Complete
[Recommended Solution] Option 1 $2.5 M 01/2018 NA
[Alternative #1] (based on priority) Varies 01/2018 NA
[Alternative #2] Rent 4% of total equipment & purchase the rest $2.3 M 01/2018 12/2020
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Each year, the Capital Tool Program has more requests for tools and equipment than
can be funded as shown below in Figure 1. The requests are prioritized, and tool
selection is completed as described in Section 2.2. The funding deficit prevents the
purchase of all submitted requests. In addition, there is a trend of decreased funding
for the capital tools. Over this same time period, the tool complement has been
expanding by replacing manual tools with battery assist devices to increase safety and
productivity. These additional tools will require more funding, over time, to support
replacement costs.

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 358 of 422

Figure 1
The distribution of Capital Equipment funds by the Business Unit is shown below in
Figure 2 (see below). The allocation is based on overall tool ranking and priority rather
than a set allotment by department. As a result, there is variation year over year (as noted
in the graph) ensuring that the most critical tools are funded.

Figure 2

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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The 2019 capital tool breakdown by investment driver is represented below in Figure 3.
The highest percent of spend (62%) was for tools related to Safety and Compliance. This
category is also the highest-ranking investment driver. Spend in this area is related to
changing industry compliance standards and tools identified to improve safety or
ergonomics (improved body posture, reduced exertion of force, and reduction in
frequency).

Figure 3

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

An updated process was created in 2019 and is being fully implemented in 2020. The process
begins by requesting Business Unit Managers to upload their tool needs into a SharePoint site.
As part of the tool submittal the Manager must complete several ranking criteria used to support
the business need for the tool. These criteria are Priority, Current State, Investment Driver,
Strategic Alignment, Stakeholder, and Demand Type. The Managers’ requests are then routed to
the respective Business Unit Directors for approval. For a detailed breakdown of the criteria see
reference document “Scoring Criteria & Weighting” in section 1.5.1.

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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The final list from each Business Unit is then reviewed by the CEC to ensure funding is distributed
fairly and impartially across the company. The equipment request list is ranked per the scoring
criteria ensuring all equipment is funded in order of ranking. This is required to prioritize spending
as the total equipment requests exceed the allocated budget. Decision records and meeting notes
are maintained on the SharePoint site once the CEC finalizes the list and purchasing is ready for
execution.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
One of the business functions that will be impacted are those areas using outdated
equipment/tools. We need to replace existing tools that have failed or reached the end of their life
or have been deemed unsafe due to current safety or regulatory issues. Avista employees must
be able to rely on this equipment while performing hazardous duties, and must be confident that
the equipment will perform safely and efficiently. Failed equipment not in compliance with current
safety standards can lead to hazardous conditions for the operators, potentially causing injury or
death. Another important priority for tool and equipment purchases is enhanced productivity.
Capital equipment is used to perform new construction work or repair work for unplanned failures.
Often this work can take less time or be completed quickly with better results by using improved
tools. These processes need to be implemented to not only improve safety, but also the
productivity of employees. These benefits do impact other parts of the business as work will be
completed efficiently and safely, reducing delays and injuries. There are also benefits to our
external customers in regard to restoration time and reliability.

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.

Option 1 – Fund Program at Current Level (Recommended)
It is recommended that this Program be funded, annually, at its current level to ensure Avista has
the proper capital equipment necessary to safely and efficiently perform all required work. This
funding level is to cover inflation of current pricing, support replacement equipment as
complement has increase in time, and support increases in technology leading to higher
equipment costs. Due to the specialized nature of utility equipment, it is most efficient for Avista
to equip employees with the necessary tools and equipment to safely perform timely emergency
repairs, while using the same tools and equipment to perform ongoing scheduled work and
maintenance. Furthermore, this specialized equipment is often only available directly from the
manufacturer, and is not typically available as a rental.

By funding this Program, Avista ensures that employees have the proper equipment to safely and
efficiently perform their work, while providing safe, reliable service to customers.

Option 1 will provide an approximate annual savings of $15M over Option 3 below, as shown in
Attachment 5: Business Case Model / Offset Costs.

Option 2 – Partially Fund Program based on priority
This option is not the preferred approach over the long-term; however, it is exercised when
necessary. Each year, when the requests for tools and equipment are submitted, cuts to the
Capital Equipment Program are made by the business units to bring the projected cost of the list
of equipment and tools into line with the budgeted amount. Further modification of the funding
level for the Program is performed in concert with other business budget needs.

When the program 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 leads to reduced
efficiency and have safety impacts. This has caused excessive rollovers each year, which build
up extensively when they are not able to be purchased within the current budget cycle. This leads
to a buildup in capital equipment requests that cannot be adequately funded.

Having the ability to test and incorporate equipment that falls within the enhanced productivity
category helps support improved processes and leads to enhanced safety and longer equipment
lifecycles.

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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Option 3 – Rent Equipment
Renting a percentage of the capital equipment was considered as a possible alternative. Of the
430 items purchased from 2012 to 2014, 233 can be rented, although 216 out of the 233 items
are needed, on hand, at all times for emergency locates and repairs. This leaves 17 possible
items, or 4% of the total equipment, which qualifies as potential rental equipment (see Figure 3).

If equipment is rented, there is no guarantee of availability. Rental companies rent equipment on
a first-come, first-served basis, making equipment scheduling for specific time sensitive jobs very
difficult. Safety and compliance regulations are also affected when correct equipment is not
available for rent.

Equipment failure is often a concern with rental equipment, as it is uncertain what condition rental
equipment is in, or how it has previously been maintained. This can lead to safety issues for
equipment operators when failures occur, as well as lost production time.

Depending on the timeline of the rental equipment, it would not be cost effective to rent long-term
as the rental costs would exceed the base price of new equipment. An average rental price for a
basic cable locator is $450/month, which equates to $5,400/year. The 2017 purchase price of this
item is $3,700.

Training on rental equipment would also be required, if different than standardized Avista
equipment. For example, Avista gas employees are only trained/qualified on specific equipment
that has been standardized by Avista, which may or may not be what can be rented for specific
jobs. This can contribute to added time necessary to qualify employees on the operation of the
equipment, and safe operating procedures.

Due to the Department of Transportation (DOT) compliance, Avista is also required to maintain
maintenance and calibration records for all gas equipment, along with operations guides for all
on-site equipment. Avista would be out of compliance using various rental equipment as rental
companies are not required to provide this documentation for their equipment to their customers.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
An updated process was created in 2019 and is being fully implemented in 2020. The program is
projected for five (5) years to account for equipment/tool life cycle and replacements. The planning
and execution of the program is managed by the Supply Chain Department. Tools are received
and delivered to internal customers and immediately become used and useful, this program has
been ongoing for decades. The average tool lead-time is 12-14 weeks.

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Capital equipment benefits customers by reducing labor cost due to improved efficiency and
improving quality of the work by advanced performance of the tools. Customer will also benefit
from improved system reliability and reduced outage duration enabled by diagnostic tools. It is
critical that capital equipment is consistently funded year over year to maintain performance and
ensure equipment/tool availability. The risk of not funding capital equipment is reduced work
performance, increased safety risk, and reduced work quality.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The funding is managed through a well-defined process with oversight from the CEC the final list
from each Business Unit is then reviewed by the CEC to ensure funding is distributed fairly and
impartially across the company. This is required to prioritize spending because the total tool
requests exceed the allocated budget. Decision records and meeting notes are maintained on
the SharePoint site. The Capital Equipment Steering Committee submits the revised list to the
CPG for final approval and execution.

2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Internal customers would be employees such as line workers and other employees who will be
using the capital tools to perform their jobs. They are also the stakeholders as some equipment
will need to be replaced in order for the employees to effectively and safely complete their jobs.
Our external customers also benefit from this program as they will reap the benefits of our
workers' increased reliability and decreased down time. With more reliability and less down time
we are able to fix/repair any issues the customers may have much faster and keep our external
customers satisfied with our quick service and reduced downtime.

2.8.2 Identify any related Business Cases
All business cases need the proper tools in order to best utilize the labor for the completion of
work benefiting our employees and customers. Examples of business cases that utilize these
tools are: Wood Pole Management, Grid Modernization, Aldyl-A pipe replacement, and Wildfire
Resiliency.

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Capital Equipment Steering Committee
The final requested tool list from each Business Unit is then reviewed by the Capital Equipment
Committee (CEC) to ensure funding is distributed fairly and impartially across the company. The
tool list is ranked from the scoring criteria to make certain the tools are funded in order of ranking.
Ranking is required because the total tool requests exceed the allocated budget. Purchasing
begins executing purchases starting with the highest priority scoring.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance process is documented in the Capital Equipment Committee Board Charter (See
attachments in section 15.1). In summary it is guided by the following scoring criteria:
Priority, Current State, Investment Driver, Strategic Alignment, Stakeholder, Demand Type and
Age of request. Each of these scoring criteria are weighted to help place the requests in order of
high to low importance.

Those who provide oversight will be those who make up the Capital Equipment Committee Board
(these members are nominated annually by Directors). These members will help to ensure that
the funding for capital equipment is distributed fairly and impartially based on the needs of Avista.

The following are those members that make up the board composition:
Tool Keeper (Gas): Voting Member
Tool Keeper (Elec): Voting Member
Safety & Health Coordinator: Voting Member
Electric Operations Manager: Voting Member
Gas Operations Manager: Voting Member
Generation & Production Manager: Voting Member
Capital Planning Group Member: Voting Member
Supply Chain Manager: (Non) Voting Member
Capital Equipment Sourcing Professional: (Non) Voting Member

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
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3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Capital Equipment Committee works to ensure that the funding for capital
equipment is fairly distributed, all decision-making, prioritization and change
request records along with meeting notes will and are maintained on the
SharePoint site as “Capital Committee Notes”. All participants in the process
(Directors, managers, requesters) have access to the approvals and addition
for their area via the SharePoint site. The members of the CPG are also the
Directors approving the requests for their areas prior to the Cap Equipment
Committee’s approval session.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Business Case Name> and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Cody Krogh
Title: Supply Chain Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alicia Gibbs
Title: Director Shared Services
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

DocuSign Envelope ID: 795802D8-5A11-4099-8BB5-81C606487332
Jun-10-2022 | 7:25 AM PDT
Jun-13-2022 | 8:04 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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EXECUTIVE SUMMARY
A 2018 Avista brand study found that 65% customers are most likely to see and identify Avista with our trucks. Our vehicles and associated gear are an essential part of our ability to address customer needs and perform work required to be an effective an efficient electric and gas utility. The Fleet Vehicle Refresh Capital Plan is the annual and ongoing plan to replace a portion of Avista’s fleet in order to ensure the highest level or reliability and the lowest total cost of ownership. The annual cost of vehicles is split into two types, direct operating and indirect costs. Direct costs include fuel and maintenance, while indirect costs include common ownership expense. Avista’s replacement model is based on a proven fleet management concept that there are predictable increasing maintenance costs and decreasing ownership costs as a vehicle ages. The point at which those two lines intersect gives Avista a window of opportunity in which we will achieve the lowest total cost of ownership cost for a given unit. Replacing the unit at that time allows us to ensure a high level of reliability (96% availability currently) at the same time ensuring we have a steady and predictable level of work for the technicians in our garages. Maintaining a high reliability percentage is essential when we experience an EOP event. Over the last several years we have experienced multiple large EOP events. The fleet experienced very few breakdowns even though our units were being used around the clock in some of the most serve conditions. This strategy also gives us the advantage of liquidating units while they still have reasonable amount of after market value. These funds help supplement our planned spend, minimizing the need for additional funds request when market prices fluctuate. To develop this model Avista has worked with Utilimarc, a utility focused data analytics company who
benchmarks and proven record working with utility fleets in the US. The model inputs the initial price, actual
maintenance & repair costs, depreciation expense and salvage value to establish each class of vehicle’s
replacement cycle. The recommended solution will replace 60-90 units per year with an average spend of
$6,600,000 per year for a total five year cost of $33,300,000. The investment in Avista’s fleet, over the past
decade, means that we have a highly reliable fleet that meets the service level expectations of our internal
customers. Our equipment must be able to function in the most extreme situations. Our trucks can be in 120+
degree heat in the bottom of Hells Canyon or 0 degree snow storms in Sandpoint. Trucks that are running
allow crews to work an outage and reenergize/repressurize the system. By spending a level amount of capital
every year, we are able to maintain a constant average fleet age which produces a known quantity of work
in our shop and it prevents us from having a bubble of trucks that create budget issues in later years. The
investment made has meant that we are a highly reliable and highly functional tool for our crews. We have
maximized our value while minimizing our total cost. By failing to fund this program we create a growing cost
of repair expense and a decreasing level of reliability/availability. The Fleet Vehicle Capital Refresh Program
was reviewed with the Facilities & Fleet Steering Committee in May of 2022.
VERSION HISTORY
Version Author Description Date Notes
Draft Greg Loew Initial draft of original business case 5/26/2022 1.0 Greg Loew Updated Approval Status 9/1/2022

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
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GENERAL INFORMATION
Requested Spend Amount $38,805,600
Requested Spend Time Period 5 years
Requesting Organization/Department Fleet K51
Business Case Owner | Sponsor Greg Loew | Alicia Gibbs
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
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1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Trucks and equipment do not age well. Fleet vehicles experience a duty cycle that most
vehicle owners would not imagine for their personal car or truck. Avista’s fleet of
vehicles operate in environments that are often at the extreme of whatever scale you
are looking at, extreme heat, cold, or the dustiest of environments. These vehicles also
experience employees constantly entering, and exiting, while the engines experience
high idle time or high loads. These factors all contribute to the wear and tear our
vehicles and can create substantial demand for repair workorders. This kind of duty
cycle over the life of a truck will add up to an increasing amount of repair work and a
lower reliability factor as a vehicle ages. By building a replacement program we
optimize our vehicle life so that we extract the right amount of useful value from our
vehicles before they experience a rapidly growing amount of repair expenses. The
program we have built affords us the ability to plan our labor and maximize our internal
mechanic resources while having a fleet of vehicles that are available for any job;
planned or unplanned operational response.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The Fleet Equipment Capital Refresh Program is driven by Asset Condition. This
program benefits both our internal and external customers.
External customers: Our customers benefit from our Fleet Replacement Program by
having a small and predictable annual portion of their bill tied to the acquisition and
operation of our fleet. Additionally, new vehicles have the cleanest burning engines and
advanced safety features that protect the environment and drivers on the road. A highly
reliable fleet ensures that our customers will not experience a delay in getting their
energy restored because our crews cannot get there.
Internal customers: Our drivers have the safest most reliable trucks as a result of the
investment in our fleet. Our fleet of trucks are ready for work over 96% of the time. In
the field our trucks experience fewer breakdowns per 100 hours of operations and are
in the 1st quartile when compared to peer utility fleets. Our fleet of vehicles includes
advanced safety features, modern efficient engines and operational tools that make
many tasks more efficient. We work very hard with input from or customers to make
sure we are producing units that give them what they need to serve our external
customers safely, efficiently, and reliably.

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
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1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The investment in vehicles for our Avista’s fleet is not an option. Our crews do not get
to their jobsites, near or far, in any way but in an Avista owned piece of equipment.
Vehicles will break down and reach their end of life. It can be prolonged by making
expensive and time-consuming repairs. The availability of the company’s fleet and its
field reliability will suffer if there is not an invest of capital. Additionally, the company
will see a steady rising cost in maintenance both in labor and material dollars. The
deferral of investment will also cause bubbles of increased capital needs in out years
as the team tries to shore failed assets and work to bring the average fleet age in line
with industry best practices. If we do not invest our dollars into the capital replacement
plan, we will end up spending those dollars on costly repairs. Repair costs are much
more, are unpredictable and make it much more difficult to forecast. In the worst case
we would see at 12,000 hour gap between labor available and the labor required to
complete necessary repairs experience by the replacement deferral in the coming
decade. That difference would likely be met with vendor labor which carries a premium
over internal labor. In 2032 that would add an additional $660,000 per year to the
clearing account which would be born through significant equipment cost burdens.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Our annual industry benchmarking and year of year analysis of numbers show that we
are performing within the industry 50th percentile band. The number of work orders per
year and maintenance cost per year have remained steady.
DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
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1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Supplemental information is available from Utilimarc.com
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Fully funded (no adds to complement funded) $38.8M 01 2023 12 2027
Partial funding $19.4M 01 2023 12 2027
Lease $M 01 2023 12 2027
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Avistas Vehicle Replacement Model (VRM) uses fleet data to develop company
specific replacement criteria for each vehicle class in fleet. This analysis is unique to
the behavior and characteristics of the Avista fleet. The inputs for the Utilimarc VRM
include:
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• Company specific trending parts and labor cost for each vehicle class
• Company specific purchase price for each vehicle class
• Company specific annual usage patterns (mileage) for each vehicle class
• Company specific loaded productive labor rate and mechanic productivity
• Vehicles are identified as candidates for replacement when over their
recommended replacement age or replacement life to date mileage, whichever
occurs first.
A vehicle is identified as a candidate for replacement when it reaches its replacement
range for age or lifetime mileage. Replacing within these ranges ensures operating within
1% of the lowest total ownership cost of the vehicle over its lifetime. A standard regression
model is used in this analysis.

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 372 of 422

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 373 of 422

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 374 of 422

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 375 of 422
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The capital in this case will be spent evenly over the 5 year period. The investment of
capital in this case will provide a consistent replacement plan which enables a
predictable parts and labor cost, vehicle downtime and technician requirements.
Annual labor savings by maintaining the capital plan and having a predictable labor requirement
2023 2024 2025 2026

Our 2021 analysis showed that demand repair work orders would increase over time when not
controlling the total overall average age of fleet. A percentage of demand repair orders has some
impact on the users of the trucks. On average for this exercise we assume each work order has
a 2 minute impact on the crew.
2021 2022 2023 2024 2025
Annual Demand Repair Work
Orders
order = 2mins
*2022 hourly 4 person line crew labor rate of $360/hr

Quantified indirect savings:

Allocation:
O&M—$462,025
Capital—$67,021
*assumption $82.89 loaded mechanic rate plus annual 3% increase
**parts demand not included in analysis
***Life-time assumes 1% growth between 2025 and 2026
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 376 of 422

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Avista’s fleet of vehicles is used by nearly every department. By not investing in new
assets we increase the potential for equipment failure and unforeseen downtime for our
crews and employees in the field. Our industry is amid many changes driven by internal
as well as external factors. By not having a replacement plan we limit ourselves on
being able to keep up with current standards, as well as new safety requirement. The
impact would most be felt when a large EOP or mutual aid event occurs.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The first alternative is to invest approximately 25% less in capital that what our optimum
scenario is. By investing at this level, we would be able to continue to address the
highest cost per mile vehicle classes (five of which account for 55% of the total annual
operating spend) and those vehicles that are critical response units. We will still face
increasing costs, downtime and constrained technician hours but the amount is
mitigated by the focus on those high cost classes. Additionally, we risk the potential
that additional funding is apportioned in one or two of the out years to get “caught up.”
This creates bubbles of work for the team purchasing vehicles but also in the parts and
maintenance costs.

The second scenario would be to fund the program at 50% of what the recommended
spend is from our data analytics. This route would create even larger bubbles that will
need to be addressed by future capital spending that could exceed the recommended
spend by as much as 50%. One of our biggest challenges we will face in this scenario
would be the effect it has on our shop workload. As previously stated we this scenario
will have a 12,000 hour or a 33% increase in the amount of labor available to what is
required to repair all demand driven repairs and maintenance. With a predictable
number of units coming in we can better plan our teams schedule. This also allows us
to maintain a level staffing needs year over year.

The third scenario is leasing option. Multiple utility fleets lease their vehicles. This on
the surface has the potential to free up capital for other uses. The risk in this option is
that you are trading a capital cost for an operating cost. The depreciation that had been
realized on the P&L statement is now an O&M cost that must be absorbed. Those costs
include a leasing company’s return on equity. This would require huge change
management with help from the operations management team, as our vehicles are
highly customized to ensure they can do their work in the most efficient and expedient
manner.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
The Fleet Vehicle Refresh is a capital plan. Each vehicle or piece of equipment
purchased get a jurisdiction code specific project number and a FERC specific task
code. We begin purchasing the next years equipment during the summer of the prior
DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 377 of 422
year. Right now, we are taking delivery of equipment that had purchase orders cut last
August. Our most expensive mounted hydraulic equipment has a 350 to 450 day lead
time. We transfer each individual unit to plant when in becomes used and useful, which
is approximately 30 days after receipt and invoicing.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program enables to Our People to serve Our Customers. When the power is out
or gas is not flowing due to an unexpected incident our fleet of trucks gets the people
and equipment to where it needs to be and then runs until the issue is resolved.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The following figure represents the totals of maintenance costs and work orders
generated per year. As can be seen on the first and last line we maintain a steady cost
and work load year over year. We benchmark and review our results on an annual
basis.

Utilimarc Lifecycle Replacement Projections
Value 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Annual Capital $5,556,379 $5,794,138 $6,765,327 $8,550,317 $8,038,595 $9,425,595 $9,470,600 $10,096,500 $9,378,313 $8,847,861Units Replaced 69 71 76 88 86 89 90 91 82 85
Annual Maintenance $8,057,038 $8,330,557 $8,531,107 $8,624,560 $8,757,253 $8,818,198 $8,916,771 $8,928,386 $9,015,413 $9,200,408
Annual Ownership $5,333,819 $5,350,745 $5,506,508 $5,908,989 $6,174,116 $6,614,670 $6,989,863 $7,406,765 $7,650,302 $7,792,466Total$13,390,860 $13,681,300 $14,037,610 $14,533,550 $14,931,370 $15,432,870 $15,906,630 $16,335,150 $16,665,720 $16,992,870
Out of Life 227 223 251 265 251 234 264 243 253 250Avg Age 11.63 11.45 11.34 11.10 10.93 10.72 10.51 10.29 10.18 10.03
Labor Hours 41,456 42,023 42,191 41,817 41,628 41,095 40,740 39,993 39,591 39,611
Half Utilimarc Lifecycle Replacement Projections
Value 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Annual Capital $2,536,587 $2,816,819 $3,741,889 $3,859,175 $3,546,683 $3,981,964 $4,467,021 $4,556,362 $4,647,489 $4,740,439
Units Replaced 31 36 40 41 39 40 42 42 42 42
Annual Maintenance $8,137,428 $8,602,623 $9,036,137 $9,483,095 $9,949,424 $10,410,080 $10,862,510 $11,319,940 $11,772,930 $12,223,390Annual Ownership $4,853,715 $4,496,113 $4,341,073 $4,230,449 $4,090,467 $4,043,929 $4,084,629 $4,135,452 $4,196,157 $4,264,716
Total $12,991,140 $13,098,740 $13,377,210 $13,713,540 $14,039,890 $14,454,010 $14,947,140 $15,455,390 $15,969,090 $16,488,110
Out of Life 265 296 360 421 454 486 564 592 642 686
Avg Age 12.43 12.73 13.07 13.42 13.81 14.18 14.50 14.82 15.12 15.41
Labor Hours 41,870 43,395 44,689 45,979 47,295 48,514 49,630 50,706 51,701 52,626
Avista Budget Replacement Projections
Value 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Annual Capital $5,180,552 $6,147,232 $6,143,363 $6,189,603 $6,176,617 $6,206,909 $6,212,876 $6,052,722 $6,171,291 $6,203,925
Units Replaced 59 72 72 61 61 54 57 52 50 51Annual Maintenance $7,907,314 $8,209,488 $8,555,177 $8,804,992 $9,117,942 $9,451,825 $9,770,447 $10,154,520 $10,537,160 $10,947,320
Annual Ownership $5,252,313 $5,318,170 $5,381,230 $5,425,657 $5,480,650 $5,529,131 $5,572,587 $5,588,461 $5,622,189 $5,651,153
Total $13,159,630 $13,527,660 $13,936,410 $14,230,650 $14,598,590 $14,980,960 $15,343,030 $15,742,980 $16,159,350 $16,598,470Out of Life 237 232 264 305 316 334 397 415 457 498
Avg Age 12.01 11.78 11.74 11.92 12.07 12.34 12.57 12.84 13.13 13.43Labor Hours 40,686 41,412 42,310 42,692 43,342 44,048 44,640 45,485 46,274 47,132
DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 378 of 422
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Internal Customers:
Distribution Electric Ops Generation Engineering
Gas Distribution Ops Gas Metering Communication
Sub-station Support Electric and Gas Metering IT
Project Management CPC Relay Shop
MS Shop Cathodic Veg Management

Stakeholder include:
Plant Accounting Rates
Engineering Operators

2.8.2 Identify any related Business Cases
None at this time

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The fleet capital plan is driven by statistical analysis that is based on our financial and
operating outcomes. The analysis is reviewed by the Fleet Manager, Fleet Specialist
and our Fleet Analyst.
DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 379 of 422
3.2 Provide and discuss the governance processes and people that will
provide oversight
Each individual vehicle purchase is approved in two parts: 1) The Fleet Manager
approves the CPR request and then the director is notified. 2) The requisition process
is approved based on value from the Fleet Manager all the way to the CEO if the value
is great enough.
Department and district managers are involved in the order process by confirming
which vehicles to be replaced and helping to ensure any requests that specific
operators or crews may have. Managers, operators/drivers sign off on a VLC form
which is maintained for every class and build of vehicle.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Annually, Fleet Spec Committees for our major operating groups come together to
review the specifications of their specific core operating vehicles. This helps ensure
that vehicles come from the manufacturer ready to work. We track our revisions/change
orders on an ECO form and record the dollars in our tracking program by using a
change order specific task code. Fleet’s goal is to not exceed more than 1% of our total
budget in change orders. In 2019 we were less than .8% of our total spend for change
orders.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Business Case Name> and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Date:

Business Case Owner

Date:

Business Case Sponsor

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Alicia Gibbs
Alicia Gibbs
Sep-08-2022 | 1:14 PM PDT
Sep-09-2022 | 8:44 AM PDT
Greg Loew
Fleet Manager
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 380 of 422
Signature: Date:

Steering/Advisory Committee Review

DocuSign Envelope ID: 9BC3AD60-4505-4E46-8035-9C33820F1084
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 381 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 1 of 11
EXECUTIVE SUMMARY
In the 1990s, an underground vault was built at the Mission Campus to house several
tanks intended to hold new oil, used but viable oil, and scrap oil, all related to substation
maintenance and electrical distribution operations. This system connected the electric
shop and the scrap oil recovery areas through a series of manifolds and pumps to
segregate the new and used oils. Several incidents, including one holiday weekend
overfill incident in 2010, brought to light the disadvantage of using an underground
system, as problems could go undetected. This risk was further highlighted during a 2019
pipeline spill and subsequent investigation/excavation and cleanup.

In 2014, two new above-ground scrap oil storage tanks were built as part of the Waste &
Asset Recovery (WAR) Building. This allowed for the two scrap tanks in the underground
vault to be decommissioned, but the remaining four underground tanks, and associated
underground piping, remain in use. This system still poses risks of undetected leaks. In
addition, access to the underground system becomes more problematic as we redevelop
the campus. The vault space itself limits use of the area. Finally, the vault has been
subject to intrusion by water, and maintenance costs to ensure the vault provides proper
containment are increasing.

The recommended solution will build two additional new oil tanks by the WAR Building,
with several smaller “day” containers for the Electric Shop, allowing the underground vault
to be permanently removed, eliminating environmental risk.

The recommended solution is estimated to cost $1.5 million (as of May 2022). There will
be two rate jurisdictions for this project. For the actual oil tanks and dispensing equipment,
since they will only be used for Substation Support, the costs will be filed under Electric
Only – WA & ID. All other associated site improvements, since they could be used by any
business unit at the Mission Campus, will be filed with the rate jurisdiction of Common
Direct – Allocated All. The major customer benefit would be the reduction in future O&M
maintenance, and costs of clean up of environmental events. Customers will also benefit
with an enhanced oil storage process that will provide Avista employees with reduced
overall environmental risk, time efficiencies and generally faster response times within
substation maintenance. It is recommended to proceed with this business case as soon
as possible to avoid any additional environmental risk and inefficiencies utilizing the
existing system. The Facilities Capital Steering Committee approved submission of this
Business Case.

DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 382 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 2 of 11
VERSION HISTORY
Version uthor Description Date Notes
0.0 Vance Ruppert Initial draft to be approved by
Sponsors 7/6/2020
1.0 Vance Ruppert Final Draft, Sponsor edits
incorporated 7/10/2020
1.1 Vance Ruppert BCJN update Capital Plannin 7/9/2021
2.0 Lindsa Miller Executive Summar Update 5/24/2022
2.1 Conor Crai en BCJN update 08/31/2022

GENERAL INFORMATION
Requested Spend Amount $1,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department Shared Services (Facilities)
Business Case Owner | Sponsor BC Owner: Eric Bowles
Sponsors: Bruce Howard, Alexis Alexander, and Alicia
Gibbs
Sponsor Organization/Department Environmental / GPSS / Shared Services
Phase Initiation
Category Project
Driver Asset Condition
DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 383 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 3 of 11
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
In the 1990s, an underground vault was built at the Mission Campus which housed several
tanks that were intended to hold new oil, used but viable oil, and scrap transformer oil, all
related to substation maintenance and electrical distribution operations. Over time, there
have been several incidents of an environmental regulatory nature that began to question
the ongoing practicality of retaining this asset.
A. The prime event occurred in September 2019, when an Electric Shop Electrician
discovered a pipe rupture into the containment vault after operating the system for
approximately 30 minutes. The pipe connects the vault and the Electric Shop (a
substation maintenance shop) within the Service Building (one of several standalone
buildings on the Mission Campus). The leak released an estimated two hundred gallons
of oil, and required excavation to a depth of 15 feet deep and approximately 31 cubic
yards of soil. The system is currently curtailed to direct pumping operations from the
containment building, which is cumbersome to Avista personnel. On June 17, 2020
Avista received a letter from the Washington Department of Ecology’s Toxic Cleanup
Program stating that “no further action” is required in the cleanup effort.
B. Another incident occurred in 2010, when an oil transfer occurred on a Friday with electric
shop personnel and a contractor. The wrong tank was selected to fill, the oil overflowed
out of the tank and oil was allowed to float on the floor for over three days as it was a
holiday weekend. It is unknown if the oil significantly penetrated the concrete floor, but
some concrete may have been contaminated. Designation and disposal will occur under
this business case.
C. O&M dewatering - The roof to the underground vault is an asphalted lid that doubles as
a drive path for Avista vehicles. However, water seeps down into the vault through
cracks and porous surfaces. This problem has accelerated through the years and
requires a hazardous waste technician to pump out the water, and screen it for oil/PCB
contamination before disposing of it. This occurs 5-10 times per year.
D. The oil storage vault is a “stranded asset” as multiple stakeholders claim use of the
resource, without a single stakeholder that “owns” the asset for O&M checks or
maintenance. O&M checks are currently performed by Hazardous Waste Technicians
and Security contractors to ensure that oil isn’t present in the containment on a weekly
basis.
1.2 Discuss the major drivers of the business case and the benefits to the
customer
The major driver for this Business Case is “Asset Condition,” due to its containment failures
and environmental risks as outlined in Section 1.1. The major customer benefit would be
the offset of any future O&M maintenance or clean up of environmental events. Customers
will also benefit with an enhanced oil storage process that will provide Avista employees
with time efficiencies and generally faster response times within substation maintenance.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
With the past failures as outlined above, it is Avista’s belief that a major environmental event
with the underground vault is a matter of when, not if. Avista cannot predict when that event
DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 384 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 4 of 11
would occur, be it months or years. However, in general, the longer this Business Case is
not implemented, the greater the chance the risk could occur without the problem being
fixed.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
At this time, the only measure that can be used is to design an oil storage system that takes
lessons learned from the underground vault and uses them to mitigate risks. Some
measures include a system that will:
1) be easily viewable by multiple employees on a daily basis to check for leaks
2) not use any underground tanks or piping
3) use oil containment best practices such as: active electronic monitoring, modern pumping
equipment, reinforced single or double-walled tanks, weathertight roofing, purpose-built
concrete containment with impermeable coating.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
2010 CH2M Hill Assessment of Underground Storage Tanks for Avista. Available
on request (Facilities / Vance Ruppert).
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
Pictures of the underground pipe oil leak as described in Section 1.1 (A) above
are available on request (Facilities / Conor Craigen).
Pictures of the oil tank overflow as described in Section 1.1 (B) above are
available on request (Facilities /Conor Craigen).
Pictures of the annual water roof leaks as described in Section 1.1 (C) above are
available on request (Facilities /Conor Craigen).
Option Capital Cost Start Complete
Recommended Option: Build new above ground
tanks, demolish underground vault and tanks
$1.5M
(see note 1
below)
07/2022 11/2023
Alternate #1: Build a new GPSS Maintenance Shop
at Mission or off-site, with a new tank(s)
arrangement.
$15M - $25M (?) 2022 (?) 2024 (?)
Notes:
1) See Appendix A for further cost estimate breakdowns of the Recommended Option’s
$1.5M Capital Cost as shown in the table above.
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The main intent of this project is to avoid significant environmental risks as described in
Section 1.1 Any risks that actually occur carry with it significant O&M costs as well. For
instance, the underground pipe oil leak as described in Section 1.1(A) had a remediation
cost of approximately $100,000.
DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 385 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 5 of 11
If (and when) a major environmental risk were to occur with the underground vault, such
as a burst oil tank and vault containment failure, a remediation cost of the soil below the
vault would probably start at $200,000, and would potentially reach multiples of that
amount if the contamination reached groundwater. Avista would be subject to
environmental enforcement, penalties, and significant reputational harm.

Avista Facilities employee time to contend with the other issues in Section 1.1 can range
from a few hours to several days. A conservative estimation of an average Avista
Facilities maintenance employee labor rates, which includes hour rates, overhead, and
benefits, is at least $60 an hour. If an average estimate of each event requires 2
employees for 4 hours, 1 time a month, then yearly O&M savings could be assumed to
be $5,760.

In addition, the Avista senior hazardous waste technician ($75 per hour) spends at least
two and a half hours per event (with 5-10 events every year) to dewater the vault as
described in Section 1.1 (C). The 10 event estimate would calculate to a yearly O&M
savings of approximately $1,875, plus disposal costs of approximately $1000. Should
cross contamination of water occur, costs would increase by orders of magnitude.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). Include any
known or estimated reductions to O&M as a result of this investment.
The requested capital cost amount of $1.5M will be used for tank procurement and
construction.
The project will provide the following new equipment and processes:
Two new 10,000 gallon tanks, one for new oil, and one for used but viable oil. They shall
be installed near the existing tanks at the Waste & Asset Recovery Building (WAR Bldg).
The tanks shall be above ground, surrounded by a concrete spill containment. They will
also require a covered roof/canopy, and may also require metal siding to prevent
snow/rain accumulation in the containment.
A smaller racked oil storage containers will be purchased for the Electric Shop for day use.
The new oil tank will be filled as needed by our oil supply vendor. The used but viable oil
tank will be filled by our Electric Shop (ES), a department within Avista’s Generation
Production Substation Support (GPSS) business unit.
A 500 gallon portable storage tote to be filled with new oil from the tank mentioned above.
It will be filled as required by the ES, but it is expected to be no more than 2-3 times a
year.
A 300 gallon portable storage tote to be filled with used but viable oiland to transport scrap
oil to the tank mentioned above. It will be used as required by the ES, but it is expected to
be no more than 2-3 times a year.
A storage area (concrete slab or asphalted) will be provided for 20 empty 55 gallon drum
barrels for new or used oil as required by the ES.
A second storage area (concrete slab or asphalted), with a covered roof/canopy, will be
provided for 12 full 55 gallon drum barrels for new oil as required by the ES. It may also
require metal siding to prevent snow/rain accumulation in the storage area.
The ES will forklift the totes to and from the WAR Building. Due to the storm water
containment systems and oil water separators that have been installed on the Mission
DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 386 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 6 of 11
Campus over the past decades, the risk of any major oil spill events from forklift traffic is
extremely low.
The new oil tank will also provide oil to an approx. 3000 gallon Isuzu tanker truck or an
8000 gallon tanker trailer Avista owns and stores at our Beacon Substation. Both pieces
of equipment will be used as needed for large substation equipment work at both the
Mission Campus ES, and in the field / at any particular substation.
Demolish the existing underground vault. Remove only 6 feet or so top-down, with existing
slab and footings to remain. Holes will be bored in to the abandoned slab, and the
remaining area filled in with structural fill. The removed underground vault will be replaced
with a new asphalt parking lot, approximately the same footprint, for GPSS use.
Siding and slider doors will be added to the (2) existing tanks at the WAR Bldg. due to
snow/rain/ice accumulation inside its concrete containment the past few years.
In addition to the O&M savings for Avista employees as described in Section 2.1, it can
be conservatively estimated that this new process will save at least 30 minutes for two ES
employees at least once a week. The yearly O&M savings, using a $75 ES employee rate,
can be assumed to be $3,900.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

Current processes, metrics, & data:
1) Currently, the underground vault has four tanks that can be used by the Electric Shop
(ES). There are (2) 10,000 gallon tanks to hold oil, and (2) 5000 gallon tanks subdivided
into (4) 2500 gallon compartments that hold new or used but viable oil. The (2) 5000
gallon tanks can be used as queuing tanks from either of the 10,000 gallon tanks.
2) The 5000 gallon tanks were previously accessed by the ES through direct underground
plumbing coming from the vault directly into the ES. The controls for switching between
all the tanks, and also the (4) 2500 gallon subdivided tanks, are in the vault.
3) Inside of the ES, 55 gallon drums/totes (usually around four total) were being filled using
the direct plumbed line. This practice recently ended however, due to the discovery of
the leak in the underground piping as described in Section 1.1 (A). Now that the
underground plumbing is no longer usable, if the totes need refilling, they will be
forklifted over to the external, above-ground, hose hook up located at the vault.
4) Once the full totes are placed back in the ES, the oil is manually pumped into “smaller”
pieces of equipment, as needed. Since the smaller equipment doesn’t usually require
much oil, the totes only need to be refilled maybe twice, or three times a year.
5) However, the ES will sometimes require thousands of gallons at one time to work on
larger equipment such as power transformers or oil circuit breakers, on a scheduled or
emergency basis. Instead of using the totes, the ES has a separate process.
a. Use the large tanker trailer or the smaller Isuzu tanker truck stored at Beacon
Substation.
b. More often than not, the ES will work on large equipment in the field / at the
substation. They will fill the Isuzu or our tanker trailer at our vault at Mission
Campus. After filling, they will then drive to the substation to dispense.
6) Lastly, whenever the ES needs a refill of either 10,000 gallon tank in the underground
vault, they will usually have to “shuffle” some oil between the 10,000 gallon tanks and
the 5000 gallon tanks in order to receive the full approx. 8000 gallons of oil for any
tanker truck delivery from our vendor.

DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 387 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 7 of 11
All of the above current processes will be replaced by the new processes as described
above in Section 2.2.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
There was some discussion to build a new GPSS Shops Maintenance Building either at the
Mission Campus, or at another off-site location. There is significant risk that the scope of
such a building could fluctuate and produce a project requiring anywhere from $15M - $25M.
At this time, this is not a reasonable solution to the main problem – the environmental issues
with the underground vault and tanks.
Doing nothing was also considered, but given the difficulties numerous departments such
as Facilities, Environmental, and GPSS have endured the past few decades, as well as the
risk of a major future environmental event, the do nothing option is also not reasonable.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This business case is considered a project, as it is not intended to be an ongoing project
beyond 2023. The major milestones and timeline of the project is estimated to be the
following:
Complete Design Drawings: Completed
Bidding / permits complete, General Contractor (GC) selection: 2 months
GC procure tanks and long lead items: 6 months
GC complete new tanks: 4 months
GC complete demolition of underground vault: 2 months
The project is expected to complete and become used and useful in early-to-mid Q4 of
2023, with all of its $1.5M transferring to plant in 2024, around the same timeframe.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The major reason to perform this project is to align with Avista’s strategic vision of
environmental stewardship. This Business Case clearly identifies the environmental
regulatory issues that could occur at some point if no action is taken.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The environmental regulatory issues and O&M maintenance described in the business case
earlier makes a strong case that this investment makes sense, as to avoid significant
operational and environmental risks. As the project progresses, the scope and budget will
be re-baselined as required, with the expectation of meeting scope, schedule, and budget
targets.
2.8 Supplemental Information

DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 388 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 8 of 11
2.8.1 Identify customers and stakeholders that interface with the business case
Major customers/stakeholders:
Environmental Department
Generation Production / Substation Support Department
Facilities
Minor customers/stakeholders:
Electric Operations, Fleet Maintenance, Warehouse/Stores
2.8.2 Identify any related Business Cases
Not applicable.
3.1 Steering Committee or Advisory Group Information
A. The Steering Committee (SteerCo) (as of August 2022) shall consist of the following:
Alicia Gibbs, Jody Morehouse, Alexis Alexander, David Howell, Jim Corder, Adam
Munson, Mike Magruder, and Bruce Howard.

B. The Advisory Group that assisted in shaping this Business Case consisted of the
following stakeholders:
Environmental Department (Bruce Howard, Darrell Soyars, Bryce Robbert)
Generation Production / Substation Support Department ( Alexis Alexander, Brad
McNamara)
Facilities (Dan Johnson, Eric Bowles, Robert Johnson, Dave Schlicht, Nick Lasko, Conor
Craigen)
3.2 Provide and discuss the governance processes and people that will
provide oversight
The project shall use certain Project Management Professional (PMP) guidelines and
procedures during the course of this project.
A Project Execution Plan, consisting of the documents below, will be drafted and approved
by the SteerCo described in Section 3.1 (A).
 Project Charter, Change Management Plan, Communication Management Plan,
Cost Management Plan, Procurement Management Plan, Project Team
Management Plan, Risk Management Plan and Risk Register, Schedule
Management Plan, Scope Management Plan, and Project Execution Approval
Form.
Each month, the project manager will provide the following information either at the
scheduled SteerCo meeting, or via email.
 Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at Complete, Year
Variance at Complete, Approved Lifetime Budget, Accrued Lifetime to Date, Lifetime
Project Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required
by the Project Execution Plan. The project manager reserves the right to present items not
outlined in the Project Execution Plan if he/she determines its importance is relevant to
SteerCo input.
DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 389 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 9 of 11
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The final decisions regarding these items, especially certain change requests as required
by the Project Execution Plan, will be presented to, and voted upon by the SteerCo. The
decisions will be documented in a monthly meeting minutes of the SteerCo for
documentation and oversight.
It will be the Project Manager’s role to monitor the scope, budget, and schedule and present
the results to the SteerCo, regardless of they are within tolerances, or not.

DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 390 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 10 of 11

The undersigned acknowledge they have reviewed the Oil Storage Improvements Business
Case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Eric Bowles
Title: Corp Facilities Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alicia Gibbs
Title: Director of Shared Services
Role: Business Case Sponsor

Template Version: 05/28/2020

DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Aug-31-2022 | 2:55 PM PDT
Aug-31-2022 | 6:14 PM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 391 of 422
Oil Storage Improvements
Business Case Justification Narrative Page 11 of 11
Appendix A – Cost Estimate Breakdown
Presented and approved by Facilities Steering Committee to request additional funds
through the Capital Planning Group on June 10, 2021.

YEARLY 2022
Category Planned
Spend Scope 
Avista Resources 104,280$                       
 Group 1 ‐ 12 hr/month
Group 2 ‐ 20 hr/month
Group 3 ‐ 48 hr/month 
Benefits 95% of Wages 94,895$                          Matches hours shown above
‐$                               
Contract Project Support 1,145,628$                    
$1.02M + tax for general contractor
$21K for special inspections
$13K for consultant construction administration
‐$                               
Avista Supplied Equipment and Materials ‐$                               
Material Overheads 8% of Mo Total ‐$                               
AFUDC 48,620$                          estimated
Other Expenses ‐$                               
Capt OH ‐ Functional and A&G 3.25% of Mo Total 45,286$                          3.25% of all charges
Contingency 6% of Planned 86,323$                          If needed for any items as described above
1,525,031
1,500,000$              Budget
(25,031)$                    Variance
DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 392 of 422
EXECUTIVE SUMMARY
This program is be responsible for the capital maintenance, site improvement, and
furniture budgets at over 40 Avista offices, storage buildings, and service centers (over
900,000 total square feet) companywide. This program is intended to systematically
address: lifecycle asset replacements (examples: roofing, asphalt, electrical, plumbing),
lifecycle furniture replacements and new furniture additions (to support growth) and
business additions or site improvements.

Facilities apportions approximately 50% to Asset Condition work that is identified using
Paragon Asset Condition software (Terracon), 30% is set aside for Manager Requested
projects, and 20% is kept aside for unexpected capital needs and furniture
replacements. There is currently a $12.6M Asset Condition backlog identified using
Paragon Asset Condition software. A funding of $4.4M takes into account 7% Inflation in
2023 and 3% Inflation in remaining years. This also includes a $250K one time
purchase (2023) for an Asset Management System/ work orders ect. and $100K yearly
for outdoor spaces.

This program supports Avista’s entire Service Territory and all service codes and
jurisdictions. Performing adequate Asset Management allows the Company to preserve
and fully utilize its properties while reducing expensive repairs in the long term. It also
ensures a safe environment for people and equipment. Damaged or poorly maintained
facilities can create very real safety risks and associated liability for employees,
customers, and contractors.

The Facilities Capital Steering Committee approved submission of this Business Case.
VERSION HISTORY
Version Author Description Date Notes
1.0 Lindsay Miller Initial Version 07/10/2018 Initial Version
2.0 Lindsay Miller Executive Summary Only 07/07/2020 Revised Template
3.0 Lindsay Miller Yearly Update 07/30/2021 Updated Graphs
4.0 Lindsay Miller Executive Summary Only 05/24/2022

DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 393 of 422
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Many of the service centers in Avista’s territory were built in the 1950s and 60s and
are starting to show signs of severe aging. Almost half of Avista’s Assets were built
before 1980. Most of our building systems are also past their recommended life
based on recognized industry standards defined by Building Owners and
Managers Association (BOMA), and International Facility Management Association
(IFMA) and are requiring renovation or replacement. Many of the original campus
layouts and buildings at our Service centers are no longer optimal today due to
changes in our vehicle sizes, materials storage, and operations flow. These
changes have required the need for project funding to address changing business
and site requirements as well.

Location Address City State
Airport Hangar 2019 Spokane WA
2015 2180 N Havana St WA
Clark Fork Bunkhouse 1959 806 Main St. Clark Fork ID
Coeur d’Alene Service Center 1994 1735 N. 15th Street Coeur d’Alene ID
Colville Service Center 2010 176 Degrief Road Colville WA
1996 Davenport WA
Deer Park Service Center 2018 Airport Drive Deer Park WA
Requested Spend Amount $4,400,000 + 15% year over year
Requested Spend Time Period Yearly
Requesting Organization/Department Facilities
Business Case Owner | Sponsor Eric Bowles | Alicia Gibbs
Sponsor Organization/Department Shared Services
Phase Planning
Category Program
Driver Asset Condition
DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 394 of 422
Dollar Road Fleet Shop 2015 2,406 N. Dollar Road Spokane WA
Dollar Road Service Center 2019 2406 N. Dollar Road Spokane WA
Dollar Road Truck Storage 2014 2406 N. Dollar Road Spokane Wa
Dollar Road Wash Bay 2018 2406 N. Dollar Road Spokane Wa
Downtown Network Center 2016 1717 W. 4th Ave Spokane WA
Downtown Project Center 2016 1717 W. 4th Ave Spokane WA
Elk City Facility 2017 Hwy 14 Elk City ID
Goldendale 2015 912 E. Broadway Goldendale WA
Grangeville Facility 1933 201 E. Main Street Grangeville ID
Grangeville Pole Yard 2016 Grangeville ID
Grants Pass Service Center 1960 618 SE J Street Grants Pass OR
Jack Stewart North Line
Trailer 1985 8308 N. Regal Spokane WA
Jack Stewart Office Modular 2012 8307 N. Regal Spokane WA
1993 8309 N. Regal Spokane WA
Jack Stewart Training Center 1999 8307 N. Regal Spokane WA
2012 121 Hill Street Kellogg ID
Kellogg Materials Storage 1980 122 Hill Street Kellogg ID
Kellogg Service Center 1960 120 Hill Street Kellogg ID
1976 1151 Hwy 395 N Kettle Falls WA
2012 2826 Dakota Ct. Klamath Falls OR
Lewiston Call Center 1976 803 Main Street Lewiston ID
1959 1412 E. Mission Ave. Spokane WA
1959 1411 E. Mission Ave. Spokane WA
2011 1411 E. Mission Ave. Spokane WA
Main Campus Mini Line Dock 1970 1411 E. Mission Ave. Spokane WA
2017 1411 E. Mission Ave. Spokane WA
1996 1412 E. Mission Ave. Spokane WA
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Schedule 3, Page 395 of 422
Main Campus Parking
Garage 2019 1411 E. Mission Ave. Spokane WA
Main Campus Ross Park
Building 1903 1411 E. Mission Ave. Spokane WA
1959 1411 E. Mission Ave. Spokane WA
1959 1411 E. Mission Ave. Spokane WA
2014 1411 E. Mission Ave. Spokane WA
1994 581 Business Park Drive Medford OR
Medford Service Center 1994 580 Business Park Drive Medford OR
Orofino Service Center 1970 1051 Michigan Ave Orofino ID
th
Pierce Facility 1985 104 Moscrip Dr. Pierce ID
1903 337 N. Post Street Spokane WA
Pullman Mechanic Shop 2012 5704 SR 270 Pullman WA
Pullman Shed 1959 5704 SR 270 Pullman WA
Ritzville Facility 1955 401 E First Ritzville WA
Sandpoint Covered Storage 1985 103 N. Lincoln Sandpoint ID
Sandpoint Storage Bays 1957 101 N. Lincoln Sandpoint ID
Spokane Valley Call Center 1979 14523 E. Trent Ave. WA
2011 St. Maries ID

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Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
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Funding backlog
There is currently an identified backlog of $8.2M in Asset Condition work needed
across the system of assets Facilities manages. In 2017 Terricon identified $6M in
work on their initial assessment. This list is growing every year as our buildings
age and new items are identified that need replacement. At the current funding
level this backlog of capital work will continue to grow. The backlog is growing
faster than our current funding model can accommodate.

$-
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
2017 2018 2019 2020
ER 7001/ 7003 Requested vs Funding
Requested Funding Asset Condition Backlog
ER 7001/ 7033 Funding Breakdown
Manager Requested Asset Condition
Furniture (7003)Drop In/ Safety
Project Center Asphalt- Asset Condition
DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 397 of 422
Capital Lifecycle Asset Replacements ER 7001
This portion of the Structures and Improvements Program is based on the results
of the Facilities Condition Assessment Survey. This survey will take into account
the condition and lifecycle of each Facilities asset. Assets will be graded and those
requiring replacement within the next 10 years will be estimated and scheduled for
replacement at an appropriate year during the 10 year time frame of the survey.
Buildings as a whole will be assigned a Facilities Condition Index (FCI) as part of
the survey to help compare future capital needs and drive the decision of
continued capital expenditures vs. possible replacement.

Examples (asphalt and structural issues):

Furniture Replacement or Additions ER 7003
This portion of the program is for furniture replacements based on industry
standard lifecycles, condition, and availability of parts. The program is also meant
to support new furniture additions required on approved building projects.

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Examples:

Business Additions or Site Improvements ER 7001
This portion of the program is intended to support site improvement requests and
productivity or business-related needs. Project requests are made by Operations
site managers in June the year before. The list is then vetted for validity and
business need by director-level management. Approved projects are then
prioritized vs. capital asset replacement priorities, and assigned per available
capital funding. Projects that are tied to compliance, safety, or productivity will be
given funding preference.

Example (security fencing and gate, weld shop crane):

A robust operations and maintenance program will be required to help further
extend the lifecycle of our Facilities assets and help to lessen capital replacement
needs. Conversely, limited O&M maintenance programs will result in shorter than
standard asset lifecycles, and ultimately increased Capital spending.
As the condition of our Facilities improve, capital asset replacements should
lessen in future years of the program. This is again dependent on sufficient O&M
maintenance budgets and workforce.
DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
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Schedule 3, Page 399 of 422
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or Failed Plant & Operations) and the benefits to
the customer
The major driver of this business case is Asset Condition. Facilities apportions
approximately 50% to Asset Condition work that is identified using Paragon
Asset Condition software (Terracon), 30% is set aside for Manager Requested
projects, and 20% is kept aside for unexpected capital needs and furniture
replacements.
Customers benefit from this project by Facilities providing a safe, usable
buildings through which our Operations teams provide electricity and gas to our
customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
As previously stated there is an identified backlog of Asset Condition work of
$8.2M. This list is growing every year as our buildings age and new items are
identified that need replacement. Deferring this work will cause a large bow
wave of Capital investment in future years. Providing a level investment over
the next 10 years will allow us to prevent equipment failures and the need for a
large one time capital investment.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
At this time, the only measure that can be used is to design solutions that
provides room for growth, expands technology requirements, and adheres to
safety and security best practices. Some of these solutions would include items
such as:
1) Materials/ Storage: Provide spaces that meet the needs of the Stores team
and Operations
2) Environmental/ Compliance: Ensure that the building and site meets with
Avistas environmental standards
3) Employee/ Customer Impacts: Room for employee or operations growth
4) Operational Efficiency: Ensure that operational needs of employees are
being met
5) Asset Condition: Provide systems and materials that meet with Avista
standards

DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
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1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem
The Asset Condition Study and Asset Condition Report for all of Avista’s
Assets is used to help determine the best options to resolve the various
Asset Condition needs.
1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is
proposed for replacement.
The Asset Condition Study and Asset Condition Report for all of Avista’s
Assets is used to help determine the best projects to fund in any given
year. Projects are prioritized by the Paragon Asset Condition program
using metrics such as risk, impact and ROI. This prioritized list is then
used to create the Asset Condition project list for the coming year.

Recommended Solution – Fund Program at full amount
This will allow us to address capital asset replacements and business needs.
Safety, compliance, and productivity requests are rated highest and given priority
first. Many of these replacements can create safety risk if not addressed (sidewalks,
structural repairs). Not systematically addressing maintenance needs could
ultimately result in complete replacement of the buildings at some point.

Option Capital Cost Start Complete
$4.4M
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

There is currently an identified backlog and requirements of $8.2M in Asset
Condition work needed across the system of assets Facilities manages. In
2017 Terricon identified $6M in work on their initial assessment. This list is
growing every year as our buildings age and new items are identified that need
replacement. At the current funding level this backlog of capital work will
continue to grow. The backlog is growing faster than our current funding model
can accommodate. It is the goal of this program to maintain a level backlog
that projects are selected from using Terracon’s risk assessment and the
impact the item has on the Company’s ability to perform its work, making the
highest priority projects readily apparent.
Even funding this program at the $4M level we will never be able to completely
reduce the backlog. Providing more than the $4.4M requested would require
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Schedule 3, Page 401 of 422
additional Project Management personnel and possibly FTE’s. Facilities can
accommodate this request within their current staffing model. It is the goal of
this program to maintain a level backlog that projects are selected from using
Terracon’s risk and the impact the item has on the Company’s ability to
perform its work, making the highest priority projects readily apparent.

Base known projects over the next 5 years- including backlog:

10-year Forecast- Fully Funded:

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2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital
spend?). Include any known or estimated reductions to O&M as a result of
this investment.

Average funding splits based on project priorities
This program is be responsible for the capital maintenance, site improvement,
and furniture budgets at over 40 Avista offices, storage buildings, and service
centers (over 1.1M total square feet) Companywide. This program is intended
to systematically address the following needs:
• Lifecycle asset replacements (examples: roofing, asphalt, electrical,
plumbing)
• Lifecycle furniture replacements and new furniture additions (to support
growth)
• Business additions or site improvements (examples: adding a welding
bay, vehicle storage canopy, expanding an asphalt yard. Can
sometimes include property purchases to support site expansions.)
This program would encompass capital projects in all construction disciplines
(roofing, asphalt, electrical, plumbing, HVAC, landscaping, expansions,
remodels, energy efficiency projects). Facilities apportions approximately 50%
to Asset Condition work that is identified using Paragon Asset Condition
software (Terracon), 30% is set aside for Manager Requested projects, and 20%
is kept aside for unexpected capital needs and furniture replacements.
DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
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Schedule 3, Page 403 of 422
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

This Business Case will impact the employees that work out of the offices and
locations where projects are completed. Other teams that may be impacted are:
ET, ET Security, Radio Relay, Environmental and Stores/ Warehouse.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative #1 – Partially Fund Program based on priority
This option would decrease the capital program and increase existing O&M
budgets to prolong structures’ lifecycles beyond rated life, and reduce capital
needs. This option is not the preferred approach over the long-term. Capital
investments can be limited with a corresponding increase in O&M dollars. As
building systems continue to decline O&M burden will increase.

The estimated replacement value of Avista’s assets when the Terricon survey
was taken in 2017 was approximately $242 million, with estimated maintenance
and replacement requirements based on the Terracon report of $8,800,640 per year, which equals 3.64% of the current replacement value of the assets. The
graph above clearly demonstrates that the amount spent by Avista (the green
bars) typically does not reach the minimum level of O&M expenditures (the blue
bars) standard in the building industry for basic sustenance of facilities. This
level of underfunding would need to be addressed if the choice is made to
underfund this program.
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
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improvement and business needs category can help support improved processes
and lead to enhanced safety and longer lifecycles. When the budget needs to be
reduced, reductions are first made to requests in this category.
Replacement is intended to replace aging units to achieve more predictable
capital requirements and avoid replacement peaks caused by large-scale
failures. Cutting into these requests over an extended period could lead to
reduced efficiency and have safety impacts.
Funding this business case at less then $4M will require a reallocation of the
dollars reducing the funding for Manager Requested Projects.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
The majority of projects in the Facilities Structures and Improvements program
begin work in the 2nd or 3rd quarter of each year, and will usually transfer to plant
before the end of the year. Some of the larger projects, or projects with extensive
design, can carry over to the following year.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The major reason to perform this project is to align with Avista’s strategic vision
of customer performance and reliability. Being able to provide service to our
customers safely and efficiently is a cornerstone of Avista and the current
Pullman Operations office does not allow employees to meet those goals.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

Hopefully the business problems described earlier makes a strong case that this
investment makes sense, as to avoid significant operational, reliability, and
performance risks. As the project progresses, the scope and budget will be re-
baselined as required. And hopefully the project can come in possibly under
budget and ahead of schedule. Full oversight of the scope and budget will be
provided to the Facilities Steering Committee (see Section 3.1 (A)) for their
review and evaluation as described in Section 3.2 and 3.3.

DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 405 of 422
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business
case
This Business Case will interface with the employees that work in the facilities
where project work is completed. They will be a partner in the design and
execution of these projects. Other teams that may be impacted are: ET, ET
Security, Radio Relay, Environmental and Stores/ Warehouse as well as Gas
and Electric Operations.

2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
ER7001 Facilities Structures and Improvements is a 5-year program created to
address the capital lifecycle asset replacements and business/site
improvements at all of Avista’s regional sites and offices. Asset lifecycle
replacements are compiled by Facilities and are based on an asset condition
report and industry recognized lifecycles. Site improvement projects are
approved based on productivity and/or business need.

Asset Lifecycle Replacement Projects
In 2017 and 2022 Avista hired Terracon Consultants to perform a condition
assessment on 76 Avista-owned facilities and 35 real estate sites at 34 different
locations, comprising approximately 1,186,000 square feet. These facilities
were constructed between 1903 and 2019. Terracon estimated the value of this
infrastructure at approximately $365 Million.
The Terracon study was highly detailed and in depth. They examined every
characteristic of each facility from a variety of perspectives. External structures
from asphalt in the parking lot to roof condition, fences, curbs, work, and storage
areas were examined to ascertain and score condition and to identify issues
and note concerns. Internal aspects such as walls, carpets, and furniture
condition were evaluated.
They surveyed building systems including plumbing, heating and cooling,
electrical, lighting, air quality, drainage, and security. They also looked at safety
aspects from both the customer and employee perspective. Then each item in
the facility was rated based upon its condition and assigned a budget category
of O&M Preventative Maintenance, O&M Deficiency Repairs, Capital
Replacement, and Capital Renewal/In-Kind Replacement. Terracon’s list is
sorted by relative risk and the impact the item has on the Company’s ability to
perform its work, making the highest priority projects readily apparent. Of the
363 “at risk” items Terracon identified, nearly 60% had a risk rating higher than
DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 406 of 422
5 (on a 1 to 10 scale) and 20% were identified as having an actual impact on
operations. This rating is what is used to identify the highest risk replacements
needed and the project list is created using this information.

Site Improvement Projects
These types of requested facilities projects undergo a multi-level internal review
process. It begins with the related manager who either identifies the capital need
themselves or is notified of an issue that needs to be resolved by an employee.
If the manager believes the project is in the best interests of his group and the
Company, the proposal is submitted to that manager’s director. If the director
also sees the value of the request, it is submitted to a group known as the
Facilities Capital Request Board.
This Board meets every fall to review the requested projects for the upcoming
year. Managers from each major business area send a representative (the
employee chosen usually changes every year). In addition, there is a
requirement of at least one person from Operations, Environmental Affairs,
Materials Management, and Facilities. This broad mixture of perspectives is
designed to provide a neutral and “outside” perspective while having access to
the expertise and experience of the directly related and impacted business
entities.
By the time the Board receives the list of requests, it has already been vetted
twice within its related department. The requests are prioritized based on the
Capital Request form that was filled out and approved. At the Board level, each
request is reviewed for required criteria such as risk, safety, environmental
impact, and compliance. Thus this process is designed to ensure that multiple
stakeholder participation provides a thorough and robust analysis of all facility
needs and alternatives across the Company.

3.2 Provide and discuss the governance processes and people that will
provide oversight
Facilities Capital Steering Committee
Once the project list is assembled, the finalized list of projects is approved by
the Capital Facilities Steering Committee. This Committee of Directors is
responsible for approving the submission of Business Cases to the Capital
Planning Group and approval of projects and any changes within this program.
In the past this has most often been:
• Director of Shared Services
• Director of Environmental Affairs
• Director of Financial Planning and Analysis
• Director of Generation, Production, Substation Support
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• Director of IT and Security
• Director of Natural Gas

The project shall use certain Project Management Professional (PMP)
guidelines and procedures during the course of this project.
A Project Execution Plan, consisting of the documents below, will be drafted and
approved by the SteerCo described in Section 3.1 (A).
• Project Charter, Change Management Plan, Communication
Management Plan, Cost Management Plan, Procurement Management
Plan, Project Team Management Plan, Risk Management Plan and Risk
Register, Schedule Management Plan, Scope Management Plan, and
Project Execution Approval Form.
Each month, the project manager will provide the following information either at
the scheduled SteerCo meeting, or via email.
• Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at
Complete, Year Variance at Complete, Approved Lifetime Budget,
Accrued Life to Date, Lifetime Project Estimate at Complete, and Lifetime
Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items
as required by the Project Execution Plan. The project manager reserves the
right to present items not outlined in the Project Execution Plan if he/she
determines its importance is relevant to SteerCo input.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The final decisions regarding these items, especially certain change requests
as required by the Project Execution Plan, will be presented to, and voted upon
by the SteerCo. The decisions will be documented in a monthly meeting minutes
of the SteerCo for documentation and oversight.
It will be the Project Manager’s role to monitor the scope, budget, and schedule
and present the results to the SteerCo, regardless of they are within tolerances,
or not.

DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 408 of 422
The undersigned acknowledge they have reviewed the ER 7001/ 7003 Structures
and Improvements and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.

Date:

Business Case Owner

Date:

Business Case Sponsor

Date:

Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: 14712CEF-F956-4240-A458-84108ABF6EBC
Corporate Facilities Manager
Eric Bowles
Aug-31-2022 | 11:43 AM PDT
Alicia Gibbs
Sep-01-2022 | 7:15 AM PDT
Alicia Gibbs
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 409 of 422
EXECUTIVE SUMMARY
Fleet operations across the US and within the utility industry are implementing telematics
solutions to solve complex business problems. The Advisory Group has identified five
ways that vehicles on the road impact Avista. The first represents the first generation of
telematics and is focused on utility owned trucks. The next four have the potential to
positively or negatively impact our business but they are vehicles not owned by the Avista.
It could be the contractor working for Avista in a contractor owned truck, a contractor in
their personal vehicle, Avista’s employee’s doing business on behalf of the utility in their
personal vehicle and crews responding to mutual aid in our service territory. Telematics
has been implemented on the Avista’s fleet since 2012. The first generation of telematics
was implemented to streamline and track the inspections of trucks and mounted
equipment. The digitization of inspections has been very successful and has improved
the tracking of federally required inspections and the administration of those records as
required by the same authorities.
In February 2022 our current provider has notified us that the 3G network that nearly 500
devices connect to would sunset. This network shut down forces us to invest capital in an
upgrade. Additionally, customer requirements and our strategy to put the customer at the
center of every decision necessitate the need for us to leverage vehicle location data on
a modern and timely platform. Finally, best in class utilities are using telematics to provide
both coaching to drivers and collecting leading indicators on decisions a fleet of drivers
are making. The Advisory Group’s recommendation is to replace Zonar telematics with a
modern cloud platform system. Both platforms address latency issues and integrate more
info sources than ever before. The final estimated cost for this is upgrade $2,387,500
spread over three years. An upgraded system will integrate location data with the CX
platform to give our customers accurate response info, safer roads for all and lower overall
costs by streamlining our operations with data. We began this investment in 2021 with
the 2022 shutdown of the AT&T 3G network. In doing nothing we will lose our ability to
complete a critical compliance function by being unable to complete our daily vehicle
inspections. Additionally, we fail to meet our customers where they expect us to be in
today’s digitally connected economy.
VERSION HISTORY
Version Author Description Date Notes Draft Greg Loew Initial draft of original business case 6/19/2019 1.0 Greg Loew Updated business case 7/21/2020 2.0 Greg Loew Updated business case 9/1/2022 Includes change to program

DocuSign Envelope ID: BDF05058-842B-4637-B226-3006525C1ADB
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GENERAL INFORMATION
Requested Spend Amount $2,185,250
Requested Spend Time Period 4 years.
Requesting Organization/Department Fleet K51
Business Case Owner | Sponsor Greg Loew | Alicia Gibbs
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
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1. BUSINESS PROBLEM
Advances in technology, customer requirements and safety are driving the need to
invest capital in our connected vehicle systems. Implementing the next generation of
telematics in vehicles on the road operating on behalf of Avista have the opportunity
to delight our customers, reduce our liability exposure and improve operational safety.
Technological Changes: Telematics works by connecting the vehicle to the cellular
data network. Currently, most telematics connectivity use third generation networks
(3G) provided by the major carriers. In February 2022 this network will no longer be
supported and many carriers are already preventing new 3G devices on their
networks. To ensure current functionality we will need to equip our vehicles to connect
to the fourth and fifth generation networks (LTE and 5G respectively). We also know
that connected worker solutions are proliferating across our workforce. This has driven
numerous data connections inside and outside of the vehicle. Telematics technology
has advanced to allow the consolidation of connections. Leading telematics providers
have embraced a platform perspective. They have acknowledged that original
equipment manufacturers are controlling some of the data flow from the vehicle or like
Caterpillar it is just build in to the equipment computer. This migration to a platform is
beneficial for Avista as we advance solutions for the fully digitized worker of the coming
decade.
Customer Requirements: Our customers are being influenced by Amazon and Google
and other leading customer experience companies. They expect timely and relevant
communications from everyone they do business with. The utility is not exempt from
these expectations. Next generation telematics is an enabling technology for a fully
integrated and digital field work process. The connected vehicle and worker,
integrated with the mobile work management system and customer experience
platform will provide greater visibility about where our field personnel are and when
they will arrive. The information will be available to employees and to customers,
improving our ability to provide firm estimates of when we will be there to complete the
work. The platform will also improve emergency response times through improved
routing and real time location services. Finally, providing more crew location
information to our dispatchers will allowing us to dispatch the crew closet to the work
saving valuable time and resources.
Safety: The impact of telematics on the overall safety to a fleet of vehicles is under
estimated. Telematics allows the capture of data around all facets of the drive cycle.
More importantly, telematics is to several leading indicator safety metrics. Next
generation telematics integrations will allow us to see items as specific as seat belt
usage, the engagement of reverse or how close we backed up to an object. Telematics
also has the ability to coach drivers in real time and or provide them a summary of
their performance on a pre-determined interval. Finally, the next generation systems
will provide metrics on the co-location of supervisors to the crews which has been
proven to be a major predictor in crew safety performance
Additionally, as the Advisory Group has engaged internal stakeholders we have
created a required functionality list. Based on current published Zonar capabilities the
following issues with Zonar were identified:

Issue Impact on Capability
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Dynamic Reporting Provides inconsistent data points
Server based system 5-8 minute lag in actual unit status
Only support Android operating system Avista has standardized on iOS
No vehicle as a hotspot capability Multiple connections and expense
Driver coaching Requires dedicated tablet
Workflow management No integrations or partnerships
Behavior metrics No metrics outside of speed to posted
Auxiliary system data capture No 3rd party device integration
Point designed solution No platform capabilities at this time
No manufacture API integration
device

Telematics 2025 will initially provide a platform for compliance. We can and will continue to
measure inspections completions and other safety related functions. We will use this
platform to capture, track and communicate this information to users and leaders. A
feedback loop to the driver on their driving performance will be a key feature of this initiative.
Over time the advanced telemetry data from this system will help us shrink the gap between
actual behaviors and expected behaviors.
The Driver Safety team that was stood up in 2017 identified a dozen key actions to improve
our vehicle incident rate. These recommendations where based on the analysis of multiple
best in class companies and the programs/practices they had in place to achieve such
results. Every program we looked at had some sort of driver performance feedback
mechanism.
1.1 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Asset Condition
Telematics 2025 is also an enabling platform for Customer Experience
advancements and Business Intelligence. We could measure improvements in
customer satisfaction, reduced maintenance costs, and lower overall cost per
customer being driven by fleet related activities.
1.2 Identify why this work is needed now and what risks there are if not
approved or is deferred
The 3G network that Zonar currently operates on will cease operations in February of
2022. Our DOT/FMCSA compliance with CFR49 and the inspections required before and
after operation are digitally managed. Not doing anything will force our commercial vehicle
operators to complete inspections by pen and paper and creates a document
management challenge because we must keep them for 12 months before disposing of
them. Failure to do so opens the company to additional liability.
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1.3 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.

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Schedule 3, Page 414 of 422

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Schedule 3, Page 415 of 422

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Schedule 3, Page 416 of 422

1.4 Supplemental Information
1.4.1 Please reference and summarize any studies that support the problem
See the Driver Safety Team report out February 2018 by Greg Loew and Tony
Klutz
1.4.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The current network for Zonar will ceased operation in 2022. As noted in section
1.1 several functions were noted as missing for future anticipated business
processes.

2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Full telematics program implementation $2,185,250M 01 2021 12 2026
Partial funding telematics program $1,208,250 01 2021 12 2026

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2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Telematics 2025 will be implemented over a six year period beginning in 2021 in order
to meet 3G obsolescence. In year one our commercial fleet will be functional and on
Problem Statement Identify a telematics solution that provides safety and compliance data on vehicles doing work
on behalf of Avista and enables or supports solutions connected to the digital worker of the future.
Required
Functionality Details Alternatives
Priorit
y
Focus
Area
Electronic Inspections The completion and documentation of DOT required inspections plus pre-flight inspections Paper ComplianceRegulatory Mileage
Reporting Multiple federal and state agencies require exact mileage to be reported per state N/A ComplianceDiagnostic Alerting and
Reporting The ability for the truck to push diagnostic trouble codes to Fleet N/A Fleet
AssetWorks Integration Pushing mileage to database to act as system of record eliminating the need for the vehicle ledgerN/A Fleet
iOS Compatible Must work on iOS devices N/A ITDriver Behavior Scoring
and Coaching Feed back mechanism to help drivers know how they are driving In cab or daily summary Safety
4G and 5G capable 3G network is at end of life N/A IT
Customer facing info Customer know who the worker is that will be serving them and visibility into when they will be thN/A Customer Service
Utilization Reporting and mechanisms for understanding under utilized equipment N/A Fleet
Idle Reduction Knowing what it productive idle and non-productive idle N/A FleetECM data/Vehicle
Performance Real-time performance data to build dynamic maintenance response
Maintain current system
of time base FleetIntegration for
Distribution Dispatch Showing vehicle assets to distribution dispatchers to improve dispatch capabilities N/A IT
Work Flow Management Match personnel and resources to work requiring completion (work management) (maybe a tie to N/A Operations
Driver Identification Knowing who is driving every single truck every time it moves
Assumptions based on
inspection Safety
Behavior Metrics Data analysis info to understand trends and habits N/A Safety
Accident Reconstruction Capability to record some amount of data that can be analyzed after minor crashes Uses air bag computer after major crashes SafetyIntegration of mulitple
telemetry data systems Trailers and other AVA assets can use different location systems.Put everything one syste FleetAuxiliary System Data
Capture Capability to capture data from other systems installed on the truck (back up sensors, seatbelt usa N/A SafetyGPS location for non motorized units Find the lost trailer N/A Fleet
Vehicle Hotspot Vehicle based data connection point
Current system with
rugged laptops IT
Smart Phone App App that could be installed on contractors phone to know where they are at in our system (think gas survey)N/A IT
Productivity Expedited routing N/A Operations
Co-Location Where are supervisors (GFs, managers) in relations to crews N/A SafetyMobile Device Use
Reporting
Utilizing mobile device app integrated with telematics to know if the phone is used while vehicle
is in motion
App deployed with MDM
solution Safety
Satellite Connectivity For use in remote wilderness areas N/A Safety
Vehicle Pooling Dynamic assignment of available vehicle to worker requiring vehicle
One vehicle for each
worker Fleet
Driver Cameras Forward and rear facing in cab cameras Forward facing camera only Safety
Telematics Capabilities
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the new systems. In years two and three we will bring our light duty vehicles fully on to
the platform plus trailers and complete integrations to systems like Assetworks, Intelex
and Oracle.
On an ongoing basis the operational costs for telematics flow to the Fleet Clearing
Account. From there a portion of the costs go to capital and some to O&M depending
on the class of vehicle. Vehicle rates for light duty trucks and trailers will see a small
impact from this technology.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Telematics 2025 will continue to be used by Fleet and Distribution Ops. The CX project
will use the data stream from this system as described in section 1.1. Vehicle
electrification efforts have the potential to tap into the platform.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Upgrade existing system. Preserve current functionality with technology that
does not meet current or future business needs across the enterprise.
Partial install on only the on-road portion of our fleet (excludes trailers)
Partial install of new system on commercial motor vehicles only. Preserves
current functionality does not integrate or capture almost a third of all Avista
owned vehicles. Many safety and operational benefits would not be met.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
$808K Q1-2023
and TTP EOFY
22 work

Q2-2023
Product
installs
Q3-2023
Vehicle installs
districts or orgs
completed
Q4-2023
Project
remaining TTP
$400K Q1-2024
SOW
Q2-2024
Development
Q3-2024
Development
Q4-2024
Development
$200K Q1-2025
Implementation
Q2-2025 TTP
2024 work
Q3-2025 Q4-2025
$200K Q1-2026
SOW
Q2-2026
Integrations,
final TTP
Q3-2026 Q4-2026

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Schedule 3, Page 419 of 422
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Enhancing the telematics in the fleet vehicles directly aligns with the four focus areas;
customers, people, perform and invent.
Customers are better served by providing a platform that enables notifications and
awareness of crew arrival times. Avista Employees are better served through
interactive coaching and feedback on their driving behavior. Performance is better
served through the enhanced integrations that are enabled and the information that can
be shared across multiple systems. Invention is served by recognizing that the
expectations of customer service has changed, and that technology is required, not
only in our back office but in the front-line vehicles that serve as the initial touchpoint
for many customer interactions.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The majority of Telematics 2025 scope is the replacement of a system that will no longer
operate after February 2025. As outlined in section 1.1 our next generation telematics
will enable additional functions and help streamline analog processes. Project
management and business case owner will continue to review the scope of the project
for material changes.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholder Name Department
Andrea Pike Customer Service
Reuben Arts Distribution Dispatch
Amy Parsons Finance
Paul Good Gas Ops
Alexis Alexander GPSS
Mike Littrel Enterprise Technology
Jon Thompson Enterprise Technology

2.8.2 Identify any related Business Cases

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Schedule 3, Page 420 of 422
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
This project reports in with the executive advisory committee comprised of:

3.2 Provide and discuss the governance processes and people that will
provide oversight
Specific project updates will be provided and key decisions will be confirmed by the
group from the program owner.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The project manager and the business case owner will be responsible for monitoring
and recording priority changes and material change requests.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Business Case Name> and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Date:

Business Case Owner

Heather Rosentrater Jason Thackston Jim Kensok
Alicia Gibbs Jeremy Gall Kermit Olson
Jim Corder Liz Fredrickson
DocuSign Envelope ID: BDF05058-842B-4637-B226-3006525C1ADB
Fleet Manager
Greg Loew
Sep-09-2022 | 8:42 AM PDT
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 421 of 422
Signature: Date:

Business Case Sponsor

Date:

Steering/Advisory Committee Review

DocuSign Envelope ID: BDF05058-842B-4637-B226-3006525C1ADB
Sep-08-2022 | 1:16 PM PDT
Alicia Gibbs
Alicia Gibbs
Exhibit No. 9 Case Nos. AVU-E-23-01/AVU-G-23-01 J. DiLuciano, Avista
Schedule 3, Page 422 of 422