20190610Rosentrater Direct.pdf

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DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P .O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-37 27
TELEPHONE: (509) 49s-43r6
FACSIMILE: (s09)49s-88s1
DAVID.MEYER@AVI STACORP. COM
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE
STATE OF IDAHO
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CASE NO. AVU-E-I9-04
DIRECT TESTIMONY
OF
HEATHER L. ROSENTRATER
FOR AVISTA CORPORATION
(ELECTRIC)
RECE IVED
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iSSION
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o I.INTRODUCTION
a. Please state your name, employer and business address.
A. My name is Heather Rosentrater and I am employed as the Vice President of
Energy Delivery for Avista Utilities, at l4ll East Mission Avenue, Spokane, Washington.
a. Would you briefly describe your educational background and
professional experience?
A. Yes. I received a Bachelor of Science degree in electrical engineering from
Gonzaga University, and hold a Professional Engineer (PE) credential. I joined Avista in
1996 as a student engineer, and worked initially as an electrical engineer at Avista's former
subsidiary Avista Labs startingin 1999, where I developed electrical systems for fuel cells. I
joined Avista Utilities in 2003, and have broad experience on both the electric and natural gas
side of the business, having managed departments and projects in transmission, distribution,
SCADA, asset management and supply chain, as well as business process improvement using
LEAN and Six Sigma techniques. I was named to my current position in December 2015. In
this role, I am responsible for electric and natural gas engineering, operations, and shared
services - fleet, facilities and business process improvement.
I currently serve on the board of directors for the Vanessa Behan Crisis Nursery and
Second Harvest Food Bank in Spokane, Washington. In addition, I am a member of the
GoruagaUniversity School of Engineering and Applied Science Executive Advisory Council.
a. What is the scope of your testimony?
A. I will provide an overview ofthe Company's electric energy delivery facilities,
discuss our electric reliability objectives, types of investments, and system performance, and
explain the factors driving our investment in electric distribution infrastructure. I will explain
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how our efforts to maintain the asset health and performance of our electric transmission
system, including compliance with mandatory federal standards fortransmission planning and
operations, is driving a continuing demand for new investment. Further, I will describe why
each capital investment in our operations facilities and fleet operations is needed to support
the efficient delivery of service to our customers, today and into the future. A table of the
contents for my testimony is as follows:
PageDescription
I. TNTRODUCTION I
II. OVERVIEW OF AVISTA'S ENERGY DELIVERY SERVICE 2
III. INVESTMENT PLANNING 6
IV. ELECTRIC DISTRIBUTION, TRANSMISSION, GENERAL AND OTHER
PLANT INVESTMENT 9
V. CONCLUSION 28
a. Are you sponsoring any exhibits in this proceeding?
A. Yes. I am sponsoring Exhibit No. 8, Schedule 1, is the Company's Electric
Distribution Infrastructure Plan, Schedule 2 is the Company's Electric Transmission
Infrastructure Plan and finally, Schedule 3, contains the capital business case summary
documents for each of the infrastrucfure investments described in my testimony.
II. OVERVIEW OF AVISTA'S ENERGY DELIVERY SERVICE
a. Please describe Avista Utilities' electric utility operations.
A. Avista operates a vertically-integrated electric utility in Idaho and Washington,
and local distribution natural gas utility in Idaho, Washington, and Oregon. In addition to the
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hydroelectric and thermal generating resources described by Company witness Mr. Kinney,
the Company has approximately 18,300 miles of primary and secondary electric distribution
lines. Avista has an electric transmission system of 685 miles of 230 kV lines and 1,534 miles
of 115 kV lines. A map showing the Company's electric and natural gas service area in
Washington, Idaho, and Oregon is provided by Company witness Mr. Vermillion.
As detailed in the Company's2077 Electric Integrated Resource Plan,l Avista expects
retail electric sales growth to average 0.47% annually for the next ten years in our service
territory, a decline from the 0.60/o forecast in the 2015 IRP.
a. Please describe the Company's operation centers that support electric and
natural gas customers in Idaho.
A. The Company has construction offices in Coeur d'Alene, Sandpoint, St.
Maries, Kellogg. Grangeville, and Lewiston/Clarkton. Avista's three customer contact
centers, located in Spokane, Washington, and Coeur d'Alene and Lewiston, Idaho, are
networked, allowing the full pool of regular and part-time employees in each location to
respond to customer calls from all jurisdictions.
In my testimony, I explain the need for the pro formed 2019 capital projects and
programs supporting our electric distribution system, building upon a more-detailed
discussion of our electric distribution investment needs provided in the Company's 2019
Electric Distribution Infrastructure Investment Plan, Exhibit No. 8, Schedule l.
a. Please comment on recent trends in Avista's electric system reliability.
I A copy of the Company's 2017 Electric IRP has been provided by Company witness Mr. Kinney as Exhibit
No. 5, Schedule l.
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A. In recent years, the Company has generally aimed to maintain and uphold its
current overall reliability performance. Avista's system average number of outages has been
trending toward slight improvement, and for 2018, was the lowest recorded in recent years, as
shown in Illustration No. 1, below.2 While the average duration of outages on our system was
also much lower in 2018 than in 2017,the overall trend for this measure has been increasing
slightly over the same period.3
Illustration No. I
OverallTrends for Outage Number and Duration
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2011 20t2 2013 20t4 2015 2016 2017 2018
Y?at
a. Would you describe the Company's current focus on reliability?
A. Yes. The Company has recently created a new workgroup focused on helping
Avista develop refreshed recommendations for high-level reliability objectives, an overall
plan to support meeting them, and tactical work plans to guide the investments to be made
each year.
2 This measure is the System Average Intemrption Frequency Index, or SAIFI, which is the average number of
sustained intemrptions per customer in a year.
3 This measure is the System Average Intemrption Duration Index, or SAIDI, which is the average sustained
outage time per customer for the year.
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a. Does Avista have a Service Quality Measures Program?
A. Yes. The Company's Idaho Service Quality Program (ISQ) is the result of a
Settlement Agreement in our last general rate case.a Through the course of subsequent
discussions and collaborative efforts, Avista and Staff agreed on a set of service measures and
accompanying benchmarks and reporting requirements that, taken together, provide an overall
assessment of the quality of the Company's service to its Idaho customers. Avista's ISQ
program was approved by the Commission on November l, 2018.s The associated tariff
Schedule 85 for electric service and Schedule 185 for natural gas service include the following
,/ Reporting on fwo (2) measures of electric system reliability;
./ Seven (7) individual service standards, where Avista provides customers a payment or
bill credit in the event the Company does not deliver the required service level
(Customer Service Guarantees); and
./ Five (5) individual measures of the level of customer service and satisfaction that the
Company must achieve each year. Avista's 2018 Customer Service Measures results
are depicted in Table No. 1 below.6
a Case Nos. AVU-E-I7-01 and AVU-G-I7-02
s Case Nos. AVU-E- I 8- I 0 and AVU-G- I 8-06, Order No. 341 8 I
6 Four individual customer service measures exist within each of Avista's approved tariff schedules; the fourth
benchmark differs in its requirements between electric and natural gas service, resulting in five separate measures
altogether.
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Table No. 1
III. INVESTMENT PLANNING
a. Please summarize the need for ongoing investment in Avista's operations
facilities and fleet resources.
A. Adequate operating facilities are a critical ingredient to the success of all
organizations, especially those like Avista that are both asset and held-operations intensive.
Our business requires diverse facility and fleet infrastructure to support our operations,
including office and operations facilities, trucks, heavy equipment, tools, and material and
supply storage areas. Though it is easy to take for granted, this infrastructure is at the heart of
our ability to effectively and efficiently serve customers. In addition to employees associated
with heavy infrastructure, our facilities are required to support a broad range of technical and
administrative staff, including accountants, engineers, attorneys, customer service
representatives, and information technology experts. Besides the facilities themselves, our
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Percent of customers satisfied with our Contact
Center services, based on survey results At least 90%96%,/
Percent of customers satisfied with field
services, based on survey results At least 90%97%,/
Percent of calls answered live within 60
seconds by our Contact Center At least 80%81.5%,/
Average time from customer call to arrival of
field technicians in response to electric system
emergencies, per year
No more than
65 minutes 42.4 minutes ,/
Average time from customer call to arrival of
field technicians in response to natural gas
system emergencies, per year
No more than
55 minutes 4l minutes ,/
Customer Service Measures 2018
PerformanceBenchmark Achieved
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operations depend on information technology and communication systems, and a myriad other
support systems.
As would be expected for a Company that has been in business for 130 years, many of
our facilities are quite dated. A few were built in the early years of our operations, while many,
like our energy delivery infrastructure, were built during the economic expansion of the 1950s,
placing them now in the range of 60 to 70 years old. Many are inadequate for the Company's
current needs; given their age and condition, they require increasing levels of maintenance to
keep them serviceable. In order to continue to cost-effectively serve our customers and
provide adequate support for our employees going forward, buildings must be upgraded and
updated to meet our current and future operating requirements. These requirements include a
steady increase in the number of customers we serve, growing regulatory and technology
complexity in our business, and the need to care for aging infrastructure, to name a few. All
of these factors drive the need for more employees, new workspace, supporting infrastructure
and related equipment. Trucks and vehicles have increased in size and complexity to operate
more efficiently, requiring larger service space and specialized maintenance and support.
We have also reorganized our business to respond more quickly to outages and
equipment failures by locating stocks and supplies in closer proximity to crews, and storing
parts and equipment in organized and efficient spaces for quick access. Common sense and
good stewardship require caring for old buildings that need increasing levels of maintenance
to keep them going - or at times complete replacement - even if they are still minimally
functional. These investments are needed not only to keep up with current service
requirements, but they also save money for our customers over the long term. The Company
goes through systematic procedures and protocols to determine how to best manage its
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facilities. Part of this evaluation includes industry best practices as determined by national
organizations that specialize in this area, including Building Owners and Managers
Association (BOMA) and the International Facility Management Association (IFMA).
a. Please describe Avista's approach to project management for these capital
projects and program investments.
A. Proposals for individual projects and programs are initially reviewed and
evaluated within each responsible business unit, often followed by review, evaluation and
prioritization by higher-level review committees, such as Avista's Engineering Roundtable,
and the Facilities Steering Committee. In this review, projects are evaluated for completeness
of the problem statement, identification of alternatives, risks, and other elements. Finalized
proposals are submitted to the Company's Capital Planning Group for consideration of
funding. The Project Engineer or Manager identifies critical project milestones and the
resources needed to achieve them. Major equipment may be purchased in this phase, necessary
permitting carried out, and contracting processes initiated.
During execution, the Company's Project Managers establish inspection, monitoring,
safety, environmental, and invoicing protocols. They apply standard project management
practices to effectively guide the work, track and report out on status. Examples of tools that
may be used, depending upon the size and scope of a project, includes Eamed Value
Measurement, cost-loaded scheduling, and Cost Perforrnance Index (CPI) and Schedule
Performance Index (SPI) to track budget and schedule.T Project results are generally reviewed
i Cost Performance Index (CPI) is computed by Earned Value / Actual Cost. A value of above 1 means that the
project is doing well against the budget. Schedule Performance Index (SPI) represents how close actual work
is being completed compared to the schedule. SPI is computed by Eamed Value / Planned Value.
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o monthly, including budget allocations and variances, internal resource demands, customer
care results and issues, and contractor performance. These results and potential program risks
and shortfalls are reviewed monthly with the responsible Department Manager, applicable
committee, or Director.
a. Are alternatives vetted for these projects, before approvals are given?
A. Yes. Where there are altematives, those are discussed within each business
case (the project business cases that I support have been included as Exhibit No. 8, Schedule
3).
a. How is Avista's leadership informed of the program status?
A. As described above, project and program information and results are
communicated up departmental lines, through various committees, and to me via my Director-
level direct reports. Program and project results are also reported directly to Avista's Capital
Planning Group, and the Company's senior leaders, including myself, through steering
committees, various business meetings, and presentations.
IV. ELECTRIC DISTRIBUTION. TRANSMISSION. GENERAL AND OTHER
PLANT INVESTMENT
a. Can you please describe the Company's planned investment related to
distribution, transmission, general and other plant?
A. Yes. The vast majority of our planned investment is required to connect new
customers who request electric service, to replace assets that have reached the end of their
useful life, and to replace failed assets and support operations. In the following sections, I will
further explain the need for these investments, by project and program.
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A. Electric Distribution Investments
a. Please summarize the need for continuing investments in the electric
distribution system.
A. Avista, like utilities across the country, continues to respond to the sustained
need for substantial investment in electric distribution infrastructure. The pattern of our
investments bears a striking resemblance to that of the industry, which should not be a
surprise, since we are all responding to the same predominant needs: first, the need to replace
an increasing amount of infrastructure that has reached the end of its useful life (based on
asset condition), and second, responding to the need for technology investments required to
build the integrated energy services grid of the future. For additional detail around the factors
driving our need for electric distribution investment, we have organized the Company's
planned spending over the current five-year planning horizon by "Investment Driver"
categories shown below, and as previously discussed by Company witness Mr. Thies.
Respond to customer requests for new service or service enhancements;
Meet our customers' expectations for quality and reliability of service;
Meet regulatory and other mandatory obligations;
Address system performance and capacity issues;
Replace infrastructure at the end of its useful life based on asset condition, and;
Replace equipment that is damaged or fails, and support field operations.
The great majority of our planned investment each year is required to connect new
customers who request electric service from the Company, to meet our objectives supporting
customer service quality and reliability, and to replace assets that have reached the end of their
useful life based on asset condition.
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I Table No. 2 - Electric Distribution Capital Proiects (Svstem)
Distribution Capital Projects (System) In $(000's)
Business Case Name 2019
Disffi ution Grid Modemization
Distribution M inor Rebuild
Distribution Wood Pole Management
Electric Relocation and Replacement Progam
LED Change Otfr Program
Meter Minor Blanket
Primary Underground Residential Development Cable Replacement
SCADA - System Operations Office & Backrp Control Center
Segment Reconductor and Feeder Tie Program
Storms
Substation - Station Rebuilds
Transformer Change Out Program Related Distrbr$ion Rebuilds
Washington Direct Business Cases(')
DowntownNetwork
Total Planned Electric Distribution Capital Projects
(1) Excluded from revenue requirement in this case.
$ 10,241
9,019
10,521
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750
1,203
5,058
2,500
7,398
1,200
3,'t00
$ 55,463
Distribution Grid Modernization -$10,241,000
In order to properly select8 the most appropriate feeders for rebuilding, Grid Modernization
uses inventory information from the Wood Pole Management Program and our Avista
Facilities Management System, to assess the potential energy efficiency savings, avoided
customer outages, and avoided expenses for failure of equipment. This feeder criteria
information is used to rank the potential benefits for each compared with all of the other
feeders on our system. The top ranked feeders are then balanced among Company operating
districts, jurisdictions, and urban versus rural service. In the process of evaluating feeders for
potential rebuilding, our engineers evaluate reliability results for each feeder, study the actual
loadings on each phase of the feeder under a range of seasonal conditions and model the
average and peak loadings expected after the phase loads are balanced. They also model the
capacity of the overhead conductors, by segments on the trunk and laterals, to identifu any
limitations, as well as potential for energy savings. By integrating all ofthis information, along
with the full range of asset age and condition data, our engineers recommend a comprehensive
set of treatments that could be applied and identifu the cumulative potential benefits.
8 The objective in selecting candidate feeders for rebuild is to achieve the greatest overall value for customers
based on improved reliability (on that feeder), energy efficiency savings, and avoided expenses for equipment
failures.
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This program represents a comprehensive approach to infrastrucfure management, based on
extensive data and engineering-driven analysis and evaluation. It serves as a platform to better
integrate a portion of the capital investments we make each year in our electric distribution
system. Through grid modernization, we know we are targeting work on the right
infrastructure at the right time, and in a priority that allows us to maximizethe customer value
of every investment made under the program. The failure to fund this program at the planned
level for this period will push even more work into the wood pole management program and
reduce the value of both programs.
Distribution Minor Rebuild - $9,019,000
A major portion of the investments made under this program are driven by faults or damage
to our system that result in service outages for our customers. The vast majority of the outages
our customers experience each year occur on our overhead distribution system. In 2018, there
were 6,826 outages on the distribution grid, compared to only l7 related to substations and 56
associated with transmission lines. The majority of these outages are related to weather (e.g.
lightning, wind, rain, and snow), downed trees, animals (e.g. squirrels and birds), and
equipment failure. In addition to replacing assets that have failed, Avista's operations staff
performs a wide range of limited capital infrastructure work that does not rise to the level of
a project or program.e This work includes the need to reconfigure, replace, repair, or upgrade
distribution facilities that arise for a variety of reasons. In order to ensure the continuity of
service to our customers, the Company must promptly replace failed infrastructure. Avista
allocates funding to this program based on the evaluation of historical trends, and not through
a competitive prioritization process. If Avista did not make the required investments under
this program, we would be unable to repair and/or replace infrastructure that is damaged or
fails, and would therefore fail to provide service continuity to our customers.
Distribution Wood Pole Management - $10,521,000
Avista has approximately 340 electric feeders with a total circuit length of approximately
7,700 miles. This system is composed mainly of overhead electric conductors and associated
equipment that is supported by approximately 240,000 wood poles and attached equipment
that includes crossafins, transformers, cutouts,lo insulators and pins,ll wildlife guards,
lightning arresters, guy lines,l2 and pole grounding.l3 Poles, equipment, and conductors
comprise over 70o/o of the Company's electric distribution infrastructure. In managing these
assets, it is the Company's goal to repair or replace aging poles and equipment before they
actually fail, but late enough in their expected life span to capture the full value of the initial
investment and any follow-up investments. The practical way to accomplish this is to
e A project is a stand-alone investment activity that upgrades existing assets or installs new assets required for
operation of Avista's systems and processes. A program is a systematic or repetitive multi-year investment
designed and managed to sustain an expected desired level ofsystem or process performance.l0 Cutouts are fuse devices that protect the feeder and equipment in the event of a fault on the line.rl The overhead wire or conductor that carries the electric current is attached to insulators that prevent the
conductor from faulting, and each insulator is attached to the pole or crossarrn with a wooden pin (though new
materials are frequently in use today).
12 Wire support attached at the upper part of the pole and anchored into the ground diagonally to counteract
tension on the line as needed to keep the pole stable, upright and plumb.
13 To ensure the pole and equipment is electrically grounded to ensure any fault goes safely to ground.
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systematically inspect each pole in the system on a regular cycle and to make the investments
needed to replace failed poles or to extend the life of weakened poles so they don't fail before
the next inspection. The central question is what time interval to use for the inspection cycle.la
Generally, more frequent inspections (shorter cycle time) reduce the likelihood that poles and
associated components will fail sometime during the interval between inspections, but they
also cost more because the annual number of poles inspected is greater than with a longer
cycle interval. The optimum interval time can be mathematically determined based on the
characteristics of the wood pole population, the associated operating expenses, and the
likelihood and cost of customer service outages resulting from poles that fail between
inspections. The Company's evaluation of the cycle interval in 2009 pointed to a 20-year cycle
as preferable to both a shorter lO-year interval and a much longer interval.
In each 2}-year cycle, all of the wood poles in our system will have been visually inspected
and repaired, reinforced (stubbed), or replaced as needed. The program has been modified to
more fully utilize the crews performing inspections, by replacing pre-1960's transformers,
identifuing inefficiently sized transfonners, installing grounds or guy wires where needed, and
ensuring equipment meets current safety standards. This program also helps mitigate the risk
of wildfire on our system.
Electric Relocation and Replacement Program - $2,989,000
Each year Avista is required to respond to the projects of municipalities, counties and state-
level agencies to rebuild or realign roads, streets and highways. When these projects impact
our distribution facilities located in public rights-of-way, the Company is required to remove
and rebuild them in the clear zone of the new roadway, or to place them on a new purchased
private easement. This work must be performed at the Company's expense, and while Avista
may have some latitude to negotiate the timing of the construction, it has no choice with regard
to removing and relocating its infrastructure and paying all of the associated costs.ls If Avista
failed to make these investments, we would be in violation of our operating franchises,
municipal codes, state laws and regulations, and would be subject to litigation and financial
and other penalties.
LED Change Out Program - $585,000
LED lighting technology emerged as a viable alternative to conventional and fluorescent
lighting around 2009, and by year 2012, over 14 million units had been installed in the U.S.
alone. It is estimated that LEDs will save U.S. consumers and businesses $20 million per year
within a decade, and reduce U.S. CO2 emissions by up to 100 million metric tons per year.
LED bulbs cut electricity use by 85% compared with incandescent bulbs, and 40o/o compared
with fluorescent lighting.r6 Avista operates approximately 35,000 street lights we have
ra The inspection cycle interval is the period of time within which every pole in the system will have been
inspected and treated as needed.
15 This requirement is based on Avista's facilities being in the public right-of-way established for this purpose.
In cases when the Company's facilities are located in private rights-of-way, while still required to be relocated,
the move is at the expense of the goveming body responsible for the roadway project.16 "PCBs Questions & Answers," United States Environmental Protection Agency,
https://www3.epa. gov/reeion9/pcbs/faq.html.
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installed for many of our communities and other jurisdictions across our service territory as
well as area lights requested and paid for by individual customers. In2013, in recognition of
the superior safety performance of LED lighting, the energy savings potential, Avista
evaluated the benefit of converting all our Schedule 042 street lights from High Pressure
Sodium (HPS) to LED fixtures. If Avista did not invest in the LED lighting program, we
would delay the safety and security benefits to customers, as well as the savings for energy
efficiency and reduced operating expenses achieved by the program.
Meter Minor Blanket - $300,000
The Company has over 370,000 electric meters in service for measuring the kWh usage for
our residential, commercial and industrial customers. Each year, in response to our customers'
requests for a meter check, the Company's detection of billing anomalies, or the identification
of failing meters through our annual meter testing program, Avista must promptly replace or
repair failed meters to ensure our customers are accurately billed. The investments for meter
replacements and repairs are included under this failed plant program.
Primary Underground Residential Development Cable Replacement - S750,000
Underground residential district cable (underground cable or URD) has been used by the
utility industry since the 1930s, though Avista did not begin installing the cable until the late
1960's. During the 1990s, it became apparent that the cable manufactured from the 1960s into
the 1980s had numerous problems. These included the lack of adequate insulation resulting in
numerous faults, the process of splicing the cable caused weaknesses and premature failure,
and excessive corrosion on the neutral strands caused voltage levels to drop unexpectedly or
the cable to entirely fall.l7
In 2009, Avista's Asset Management Group analyzed options for accelerating the replacement
schedule from 10 years to a four year program. The analysis, which was based on savings
from avoiding unplanned outages, estimated that the four-year program would save customers
approximately $7.3 million in capital installation, expenses, and failure consequences.l8 With
the majority of the known vintage cable replaced by 2013, the program was ramped down to
an annual investment of approximately one million dollars, which provides for the removal
and replacement of this vintage cable as we find it on the system (usually through responding
to an underground fault). The failure to fund this program at the planned levels for this period
will result in more customer outages, and higher expenses and capital costs due to unplanned
maintenance and repair.
SCADA - System Operations Office & Backup Control Center - S1,203,000
This program replaces and/or upgrades existing electric and natural gas control center (System
Operations Office and Backup Control Center) telecommunications and computing systems
as they reach the end of their useful lives, require increased capacity, or cannot accommodate
necessary equipment upgrades due to existing constraints. Included are hardware, software,
17 Medek, James D. P.E., "Early Underground Residential Distribution (URD) in the Midwest,", 2002,
https://www.pesicc.ors/iccwebsite/subcommittees/E/E04l2002/fall02_medek.pdO
18 Savings are based on the outages forecast to occur without the replacement program, minus the actual outages,
multiplied by the average cost ofresponding to an average cable outage.
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and operating system upgrades, as well as deployment of capabilities to meet new operational
standards and requirements. Some system upgrades are initiated by other requirements,
including NERC reliability standards, growth, and new projects (e.g. Smart Grid). Examples
of upgrades to be completed under this program are Critical Infrastructure Protection version
5 (NERC standards requirement), Gas Control Room Management (PHMSA requirement),
PEAK Reliability CoordinatorAdvanced Applications, and Technology Refresh (nefwork and
storage). The failure to make these investments in the timeframe planned will result in the
Company losing information connectivity with its transmission system and to be in violation
of NERC transmission planning standards, and subject to financial and other penalties.
Segment Reconductor and Feeder Tie Program - $51058,000
The annual investments made under this program represent 7.1% of our planned distribution
investments, and remedy the overloading of electric equipment and cable, as well as the
conductor sagle that results from overheating of the overhead wire. These instances of system
overloading result from load growth and shifts in load demand that occur over time on the
distribution system. Resolving these overloading issues involves a combination of two
strategies known as "load shifting" and "segment reconductoring." The strategy of load
shifting extends existing lines on one feeder to an adjacent feeder that has the available
capacity to carry the additional transferred load. Reconductoring involves the removal of the
wire or conductor that is too small in diameter for the current loading and replacing it with
larger conductor that can easily carry the load. Avista considers a range of options that not
only meet the current need to relieve the overloading, but that also provide for the optimization
of the overall distribution system.
Storms - $2,500,000
This ongoing program provides for the timely restoration of the Company's transmission,
substation and distribution facilities into serviceable condition during or following major
weather-related or other natural events including high winds, heavy ice and snow loads,
lightning storms, flooding, and wildfires.
Substation - Station Rebuilds - $7,398,000
This program replaces and/or rebuilds existing substations as they reach the end of their useful
lives or where installed equipment that fails or is being replaced for capacity needs cannot be
accommodated within the physical constraints of the small, older stations. Included are wood
substation rebuilds, as well as upgrading stations to current design and construction standards.
The failure to timely replace and rebuild end of life equipment in these substations will expose
the Company to the risk of more frequent and long duration outages that have a significant
impact on our customers. Examples of substation rebuilds to be completed under this program
in the next five years are Kamiah (wood substation), Ford (end of service life), 9th & Central,
Priest River, and Colville.
le When the overhead wire (conductor) on a distribution feeder is overloaded, the wire overheats and stretches,
and in doing so, sags closer to the ground than designed, which can exceed electric code requirements for safety.
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Transformer Change Out Program Related Distribution Rebuilds - $1,200,000
Between 1929 and 1981, a family of synthetic organic compounds known as Polychlorinated
Biphenyls (PCBs) were commonly used in the oil that fills electrical transformers due to their
high dielectric strength20 and resistance to fire. Studies conducted in the 1960s and 70s
revealed, however, that these compounds are also toxic, carcinogenic and highly resistant to
biodegradation in the environment. Their production was banned in the United States in
1979.21As a result of this elevated concem, Avista began to formally analyze alternatives to
deal with its distribution transformers containing PCBs.
Under the current Transformer Change Out Program (TCOP) plan, all transformers with PCB
concentrations exceeding 1 ppm should be removed from our system by year 2019. The pre-
1981 distribution transformers targeted for replacement average 44 years of age; these
transformers are inefficient compared to current standards and their replacement will result in
energy savings, as well as increase reliability and availability of the system. In year 2020 and
beyond, the remainder of the pre- l98l transformers in our system will be targeted for removal
as part of the wood pole management and grid modernization programs. Combining the work
of these individual programs into one is not only more efficient, but it also enables the entire
feeder to be evaluated for beneficial changes in design, alignment, and in other ways not
possible when individual elements of the line are simply replaced in an "as-is" configuration.
B. Electric Transmission Investments
a. Would you please summarize the need for continuing investments in
electric transmission infrastructure?
A. Yes. Our nation's electric utilities have been facing times of unprecedented
challenge when it comes to the forces driving the need for new investment in our transmission
infrastructure, and Avista is no different. This growing demand for new investment continues
to challenge our ability to fund all of our high-priority needs for electric transmission, which,
themselves, are out of proportion to the investment requirements of our other infrastructure.
Drivers for new investment include:
goveming nearly every aspect of our transmission business. Priority among these are
20 Dielectric strength refers to the ability of a material to resist carrying an electrical current, which is a measure
of its potential to insulate against electric short circuit or fault.2r "PCBs Questions & Answers," United States Environmental Protection Agency,
https ://www3. epa. sov/region9/pcbs/faq.html.
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the growing requirements to meet more restrictive transmission operations and
planning standards, accompanied by the assessment of financial penalties for
noncompliance.
time high across the industry and will continue to increase year-over-year for at least
the next two decades. This need is tied to the major expansion of new electric
infrastructure built during the economic boom following the end of World War II.
Because these assets are now at or near the end of their useful lives, a substantial boost
in new investment is required, compared with previous years, just to maintain existing
systems.
interconnections for third parties to integrate new, variable energy resources,
particularly wind and solar. These interconnections require significant capital
investment to extend or reinforce our transmission system in order to provide for these
non-load-service uses of our system.
of the future. Emerging technologies are driving increasing digitization, distributed
generation, energy storage, and other technologies that require adapting and upgrading
the existing system, including new ways of engaging with our customers. Though
primarily focused at the distribution level, these changes in our energy delivery
business model are expected to impact transmission investments.
time-consuming, and expensive, due in part to increasing environmental, property
rights, and land-use requirements. Permitting can extend over several years and
typically includes conditions constraining how utilities site, design, construct and
maintain these assets.
When it comes to the impact for our customers, who must ultimately pay for these
requirements and investments, an exacerbating factor is our relatively stagnant load growth
due to relatively low increases in population and declining use-per-customer. This translates
into nearly flat revenues, which means that new capital investments must be covered by higher
customer rates. Historically, annual increases in customer loads produced new revenues that
were often sufficient to cover the costs for new investment and inflation without the need to
increase rates.
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0. Please describe the Company's process for ensuring it is making timely
investments in electric transmission to maintain compliance with mandatory federal
standards.
A. The Company's process follows several steps in determining which projects
should be recommended for funding each year to the Capital Planning Group. Projects are
initially developed through planning studies, engineering and asset management analyses, and
scheduled upgrades or replacements identified in the operations districts or in engineering
groups. These projects undergo internal review by multiple stakeholders, who help ensure all
system needs and alternatives have been identified and addressed. Projects advanced for
funding enter a formal review process referred to as the "Engineering Roundtable" (ERT).
This group carefully reviews the need for each project, the primary business driver, the
alternatives considered, and the justification for the approach recommended. During the
review, the potential benefits of any cross-business-unit synergies that could better optimize
project benefits and scope are also identified and evaluated. The result of this process is a
prioritized list of recommended projects that serves as a roadmap of investments sequenced
by year for at least a ten-year time horizon. Using this roadmap, each department can plan
ahead for the work they will be responsible to execute once the projects are approved for
funding and implementation. Once evaluated, prioritized and sequenced, these projects move
to the Capital Planning Group for final review and funding allocation. Representatives from
eleven business units participate in the ERT process.
a. Please list the transmission infrastructure investments planned by the
Company and briefly describe each project.
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A. The Company's planned transmission investments are listed on a system basis
in Table No. 3, below. These projects are briefly described following the table.
Table No. 3 - Electric Transmission Capital Proiects (Svstem)
Trans mission Capital Projects (System)
In $(000's)
Business Case Name 2019
Noxon S witchyard Rebuild
Protection System Upgrade
Rattlesnake Flat Wind Farm Project
South Regton Vohage Confrol
Spokane Valley Transmission Reffircement
Storrns
Substation - New Distribrrion Station Capacity Program
Substation - Station Rebuilds
Transmission Major Rebuild - Asset Condition
Transmission Minor Rebuild
Transmission NERC Low-Risk Priority Lines Mitigation
Tribal Permis and Settlements
Trarsmission C orstruction - C ompliance
Westside 230 I I | 5kV Station Rebuild
Total Planned Transmission Capital Projects
2,499
2,379
12,9ll
7,476
370
728
5,428
7,107
2,595
3,860
2,016
1,103
10,447
383
s 59,223
Noxon Switchyard Rebuild - $2,489,000
Today, Avista's Noxon Rapids 230kV Switching Station is subject to a potential fault current
of approximately 14,000 amps, which exceeds the 12,500 amp capability of six 230kV circuit
breakers in the station. This potential is not only an immediate safety issue, but it also exposes
the Company to a violation of NERC standards. Additionally, the existing station is at the
end of its useful life based on age and condition of the equipment in the station. The existing
bus has suffered a number of failures and is now configured as a single bus with a bus tie
breaker separating the East and West buses. The station is the point of integration for the
Noxon Rapids Hydroelectric development, as well as a principle point of interconnection
between Avista and BPA, providing a key point of integration for the Western Montana Hydro
Complex and the Company's interconnection with NorthWestern Energy in Montana. The
current bus configuration requires Avista to curtail its own hydro generation for unplanned
outages of substation equipment to complete work in the station. The reconstructed Noxon
Rapids 230kV Switching Station will have a double-breaker, double-bus configuration to
facilitate required maintenance activities without impacting local generation levels or transfer
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loads to or from Montana. The Company's Engineering Roundtable process has resulted in
the deferral of the broader station rebuild project and focused on the immediate replacement
of the over-dutied circuit breakers. This is not only an immediate safety issue, but our failure
to make the investments may result in the Company having to curtail its own hydroelectric
generation and further exposes the Company to a violation of mandatory NERC planning
standards.
Protection System Upgrade - $2,379,000
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 ofthe NERC standard was performed
to identifu 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 115 kV
terminals to Fault Recording (FR) capability per PRC-002 requirements at Beacon, Boulder,
Rathdrum, Cabinet Gorge, North Lewiston, Lolo, Pine Creek, Shawnee, and Westside.
Implementation is a phased approach with 50% compliant within 4 years and fully compliant
within 6 years of the effective date, July 1,2016. 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
Rattlesnake Flat Wind Farm Project - $12,911,000
In March, Avista signed a long term Purchase Power Agreement (PPA) for the Rattlesnake
Flat Wind project located in Adams County, Washington. Rattlesnake Flat Wind, a wind
energy facility permitted and being developed by renewable energy developer Clearway
Energy Group, will provide Avista with approximately 50 average megawatts of renewable
energy, or as much as 144 megawatts of nameplate wind capacity, under a 2}-year PPA with
deliveries beginning in 2020. The PPA provides Avista with additional renewable energy,
capacity and environmental attributes, which will offset higher priced market purchases. The
PPA aligns with Avista's 2017 Electric Integrated Resource Plan, which identifies that the
utility will consider acquiring additional resources if such resources have lower long-term cost
than electric market alternatives. The wind farm will be the largest renewable energy facility
in Adams County with the capacity to generate enough clean, renewable energy to power
about 37,600 of Avista's customers' homes. Situated on 20,000 privately owned acres near
Lind, WA, Rattlesnake Flat Wind will tie into Avista's electric system via Avista's
Lind/Washtucna transmission line.
South Region Voltage Control - $7,416,000
Avista's south region 230kV system, primarily in the Lewiston-Clarkston area, experiences
excessively high voltage, where voltage exceeds equipment ratings over 35o/o of the time.
Operation of equipment outside of manufacturer's ratings introduces safety risks to Company
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operations and employees, and it increases the possibility of equipment failure and associated
large scale outages. If the Company does not implement this project in the timeframe planned,
then we may be forced to remove our 230kV lines from service (which is not possible to do)
in order to maintain compliance with NERC transmission operating standards. This project
includes the installation of two 5OMVar shunt reactors on the 230kV bus at North Lewiston.
With automatic control, overvoltages can be reduced, if not eliminated, on the 230kV buses
at Dry Creek, Lolo, North Lewiston, Moscow, and Shawnee.
Spokane Valley Transmission Reinforcement - $370,000
Portions of the Spokane Valley Transmission Reinforcement Project already completed
include construction of the Opportunity Substation and Irvin-Millwood l l5kV Transmission
Line. Currently planned projects include rebuilding the Beacon-Boulder #2 115kV
Transmission Line and construction of the Irvin 115kV Switching Station. This project must
be completed to mitigate our currently-existing failure to meet NERC transmission planning
standards, and to avoid future transmission system reliability issues in the Spokane Valley.
This project also decreases the risk of transmission system outages and the potential to ignite
fires in dry areas.
Storms - $728,000
This ongoing program provides for the timely restoration of the Company's transmission,
substation and distribution facilities into serviceable condition during or following major
weather-related or other natural events including high winds, heavy ice and snow loads,
lightning storms, flooding, and wildfires.
Substation - New Distribution Station Capacify Program - $5,428,000
This program adds new distribution substations to the system in order to serve new and
growing load, as well as to provide increased system reliability and operational flexibility.
New substations under this program require planning and operational studies, justifications,
and approved project diagrams prior to funding. Planned new projects include substation sites
in the Pullman/Moscow stateline area, as well as downtown Spokane, the Spokane west plains
area, and north Spokane. The failure to complete these projects in this planning horizon will
result in equipment overloading and reliability issues, which are impossible to quickly rectiff
once they occur.
Substation - Station Rebuilds - $7,1070000
This program replaces and/or rebuilds existing substations as they reach the end of their useful
lives or where installed equipment that fails or is being replaced for capacity needs cannot be
accommodated within the physical constraints of the small, older stations. Included are wood
substation rebuilds, as well as upgrading stations to current design and construction standards.
The failure to timely replace and rebuild end of life equipment in these substations will expose
the Company to the risk of more frequent and long duration outages that have a significant
impact on our customers. Examples of substation rebuilds to be completed under this program
in the next five years are Kamiah (wood substation), Ford (end of service life), 9th & Central,
Priest River, and Colville. This investment includes associated O&M offsets of $44,884
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(System-basis) beginningin2017. Ms. Andrews has included Idaho's share of these offsets
within the Company's requested revenue requirement.
Transmission Major Rebuild - Asset Condition - $2,585,000
Projects in this program rebuild existing transmission lines based on overall asset condition
(at the end of their useful life). The failure to timely replace aging transmission infrastructure
on a planned basis will subject our customers to the increased risk of service outages and
increased restoration costs as we become less able to continue providing our current level of
reliability. In addition to customer outages, the added risk of failure also impacts the economic
dispatch of our Company's generation resources and increases the risk of fire in dry areas.
Finally, the failure to properly invest builds a "bow-wave" of needed investments to the fufure,
which makes it more difficult to fund these projects in addition to our already-planned priority
infrastructure needs. Projects include: ER 2550 - Burke-Thompson A&B 115kV
Transmission Line rebuild; ER 2604 - Lind-Warden 115kV Transmission Line rebuild; ER
2577 - Benewah-Moscow 230kV Transmission Line structure replacement; ER 2597 -
Cabinet-Noxon 230kV Transmission Line rebuild; and ER 2596 - Lolo-Oxbow 230kV
Transmission Line rebuild.
Transmission Minor Rebuild - $3,860,000
This project covers transmission structure (ER 2057) and air switch (EP.2254) replacements
based upon the results of the Company's annual Wood Pole and Aerial Patrol inspection
programs, and field operations. Both the Wood Pole and Aerial Patrol inspection programs
are undertaken to maintain compliance with NERC Standard FAC-501-WECC-1. Failing to
make the necessary replacements identified by the Company's inspection programs increases
the risk of transmission system outages and the potential to ignite fires in dry areas. Air switch
replacements are made based either on condition, capacity, or functionality issues.
Prioritization of installations and replacements are made from information provided by
System Operations, Substation Engineering or the Company's regional operations centers.
Failing to make the necessary replacements identified by the Company's inspection programs
risks placing Avista in violation of NERC standards, and will increase the risk of transmission
system outages and the potential to ignite fires in dry areas.
Transmission - NERC Low-Risk Priority Lines Mitigation - $2,016,000
This program was initiated in response to NERC's October 7, 2010 NERC Alert
Recommendation to the Industry, titled "Consideration of Actual Field Conditions in
Determination of Facility Ratings." It addresses mitigation required on Avista's "Low Risk"
I 15kV transmission lines, and brings these lines into compliance with National Electric Safety
Code (NESC) minimum clearance values. This program reconfigures insulator attachments,
rebuilds existing transmission line structures, or removes earth from beneath transmission
lines to mitigate ratings/sag discrepancies found between facility designs and actual field
conditions. If the Company were to fail to make these investments, we would fail to meet the
NERC-required facility ratings for the safe and reliable operation of these lines.
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Tribal Permits and Settlements - $1,103,000
The Company currently owns and operates approximately 82 miles of transmission facilities
and a significantly greater amount of distribution facilities on Tribal lands. The failure to
complete this work and to attain proper permitting or easement rights on Tribal lands would
require the Company to relocate its facilities. This would be cost-prohibitive for its
transmission facilities and not viable for distribution facilities, considering the Company's
obligation to serve its retail customers. Current renewals are being negotiated for terms of 30
to 50 years. Renewal costs include labor, appraisals, field work, legal review, GIS
information, negotiations, survey (as needed), and applicable fees for easements and permits.
Transmission Construction - Compliance - $1004471000
This program reconductors and rebuilds existing transmission lines to maintain compliance
with NERC transmission planning standards. Investments mitigate NERC transmission
planning standard (TPL-001-4) deficiencies that have already been identified for both our
current system and for the Near Term transmission planning horizon (l-5 years). Failure to
make these planned investments will result in our failure to comply with mandatory NERC
standards. Projects include: ER 2557 - gth & Central-Sunset 115kV Transmission Line
reconductor and rebuild; ER 2576 - Addy-Devils Gap l l5kV Transmission Line reconductor
and rebuild;EP.2457 - Benton-Othello 115kV Transmission Line reconductor and rebuild;
ER 2556 - CDA-Pine Creek 115kV Transmission Line reconductor and rebuild; ER 2564 -
Devils Gap-Lind ll5kv Transmission Line reconductor and rebuild; and ER 2310 West
Plains transmission reinforcement. Required construction on ER 2578, the Hatwai-Lolo #2
230kV Transmission Line, has been defened by the Company's Engineering Roundtable to
accommodate the other priority investment demands.
Westside 230/115kV Station Rebuild - $383,000
This project is necessary to mitigate our current noncompliance with mandatory NERC
transmission planning standards during heavy summer loading conditions. Failure to make
these planned investments will result in our failure to comply with mandatory NERC
standards. We will continue to overload the Westside#12301115kV transformer during Phase
I of this project, which overloading will extend to the existing Westside Substation 115kV
and 230kV buses, to allow for installation of a new 250MVA 2301115kY Autotransformer.
The additional transformation capacity is necessary to eliminate transformer overload
contingencies in the Spokane area. This project has two additional planned phases to complete
the entire rebuild of the station. The Company's Engineering Roundtable has deferred the
Garden Springs 230/l l5kV Substation integration due to the timing of the planned completion
ofthis project.
C. General and Other Capital Investments
Table Nos. 4 and 5 below list the projects and dollars in 2019 for general and other
projects in my area of responsibility. Business cases supporting each of these projects are
o
provided in Exhibit No. 8, Schedule 3
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Table No. 4 - Gtueralllall Capital Proiects (Svstem)
General Plant Capital Projects (System)
In $(000's)
Business Case Name 2019
Facilities Srucnnes & Improvenrent Office Furnihne
Stores, Tools Lab & Shop Equiprrrent
Central Office Facilities Long Term Restucturing PIan Phase 2
New Airport Hanger
Noxon and Clark Fork Living Faculty Remodel
Ross Park Building Renovation(2)
Apprentice Craft Training
Subtotal: General Plant Capital Projects
Washington Direct Business Cases(')
Deer Park Service Center
Washington State DOT Higlrway Franchise Consolidation
Dollar Road Service Center Addition and Remodel
Total Washington Direct Business Cases
Total Planned General Plant Capital Pmjects
(1) Excluded from revenue requirement in this case.
(2) Inadvertently inchrded in revemre requirenrent in this case. Will be
removed duing next rpdate to tarsfers-to-plant.
$ 1,932
2,065
16,052
83
1,266
200
54
21,653
6,166
2,065
6,053
14,284
$ 35,937
Facilities Structures & Improvement, Office Furniture - $119321000
This ongoing capital program funds lifecycle equipment replacements and needed
improvements at more than 40 Avista offices and service facilities (exceeding 900,000 square
feet). These needs are compiled, evaluated and prioritized based on need and asset condition
and lifecycle standards, designed to address: l) Lifecycle asset replacements (examples:
roofing, asphalt, electrical, plumbing; 2) lifecycle furniture replacements and new furniture
additions (to support growth); and 3) business additions or site improvements (examples:
adding a welding bay, vehicle storage canopy, expanding an asphalt yard, and can sometimes
include property purchases to support site expansions). The replacements based on asset
condition are intended to achieve a more stable and predictable level of capital requirements,
and to avoid peak investments caused by coincident and large-scale failures. The failure to
make these timely investments will result in reduced efficiency, safety issues, accelerated
deterioration and failure of assets, such as roofing or HVAC systems, which can result in
major damage to the facilities, and a bow-wave of needed investments to the future.
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Stores, Tools Lab & Shop Equipment - $2,065,000
Avista's capital tools program provides Company employees with proper tooling and
equipment needed to safely and efficiently construct, monitor, manage system integrity, and
properly repair and maintain our electric, natural gas, communications, fleet, facilities, and
generation infrastructure. If the Company fails to provide its employees proper tools and
equipment when they are needed, we would be unable to provide our customers with adequate,
reliable and cost effective services that meet their expectations for quality and value. These
tools and equipment also support the safety of our employees .
Central Office Facility Long Term Restructuring Plan Phase 2 - $16,052,000
Phase 2 ofthis plan is a continuation of the long-term program to meet our ongoing and future
operating needs by renovating, improving and expanding our existing central office and
operating facilities. This phase is composed of three major projects that include: re-routing a
city street adjacent to our campus in20l7, constructing a new building for our fleet operations
in 2017 and 2018, and constructing a parking garage in 2018. These three projects are
interdependent because of their location, timing of construction and their relationship to the
overall design of our central campus. These projects support Avista's objectives of 1)
consolidating the footprint of our central facilities, which today consists of several disjointed
parcels; 2) modernize and expand our aging fleet facilities to handle today's needs efficiently,
meet compressed natural gas fleet compliance, beffer manage environmental concerns, and
provide the space required for efficient queuing of fleet equipment; 3) provide adequate
campus parking for employees, which is currently short by about 400 spaces, and consolidate
parking on company-owned land, improving employee and public safety by eliminating our
parking sprawl, and; 4) separate currently shared traffic routes for our construction vehicles
and equipment and pedestrians to improve safety and increase workflow efficiency. Avista
selected this plan from several options evaluated by the facilities group for meeting these
combined needs. The failure to implement these plans in the timeframe proposed will result
in work being terminated mid-stream on work underway, adding significantly to future costs
to complete these projects, will require Avista to make alternative investments to mitigate the
operational and environmental limitations of our existing fleet operations, and fail to resolve
significant issues related to our current employee parking.
New Airport Hanger - $83,000
This project is to build an Avista-owned hangar on leased land at Spokane International
Airport. This facility will replace the hangar we currently sublease, which will be demolished
after our sublease is withdrawn in July 2018. Avista's facilities group considered four options
for securing a hangar for the aircraft, which included building a new hangar, extending use of
the current leased hangar, relocating to another airport, and co-use ofan existing hangar. The
solution to construct a hangar on land leased from the Spokane International Airport was
selected for several reasons, including the location, site securitlz, cost, efficiency and cost of
aircraft maintenance, and operational safety and efficiency. The failure to make this
investment in the timeframe planned will require Avista to adopt an alternative from among
those already evaluated and determined to be inferior.
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Avista Corporation
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Noxon and Clark Fork Living Facility Remodel - $1,266,000
This project includes the rehabilitation of two living facilities at Clark Fork, Idaho and Noxon,
Montana, to address deteriorating condition of the facilities and their systems, extend the life
of the facilities, and update them to a more modern and energy efficient state. The project
combines required repair work with the facility renovation to avoid duplicating efforts and
saving costs on contractor mobilization and re-work. The living facilities were constructed in
1983 and 1984 and have been in use for more than 30 years. They are 16-room bunkhouses
with a common space containing a kitchen, dining hall, and laundry facility. There is limited
availability of lodging in this rural area. Avista crews and personnel lodge at these facilities
when performing work at Noxon Rapids Dam, Cabinet Gorge Dam, or on other Avista
equipment in the area. During inspections in 2015, extensive issues were found with the
facilities, including structural and water damage to the siding and framing due to water
penetration, inadequate and antiquated electric heating systems, HVAC deficiencies and non-
compliant electric breaker panels and inadequate insulation. This project would address the
structural and water damage, bring the building up to modern code, and extend the life of the
facility. The completed facilities would provide years of additional service, increase the
efficiency of energy usage, reduce annual O&M costs to maintain the structures, and provide
a suitable environment for housing our workforce at these remote sites. Disregarding the
continuing water penetration was not an option, as this would render portions of, and
eventually the entire facility, uninhabitable over time. Maintenance and upgrade work is
ongoing at both dams and is planned for the foreseeable future. This work is essential to
maintaining the reliability of our power generation and associated infrastructure in the region.
Without the continued availability of the living facilities, it's estimated that it would cost more
than $300,000 annually to procure lodging at alternate sites for work at the plants, likely in
Sandpoint or Thompson Falls, about an hour drive one way from the plant. With a centralized
workforce based out of Spokane, the ability to provide lodging near our worksites maximizes
available working hours.
Ross Park Building Renovation - $200,000
Company inadvertently included this project and it will be updated/removed when the
Company updates the transfers-to-plant in third quarter 2019.
Apprentice Craft Training - $54,000
This investment consists of on-going capital facility improvements needed to support required
training for apprentice, pre-apprentice, and journey level craft workers, ensuring they are
prepared to safely meet the specialized technical needs to build and properly maintain electric
and natural gas utility systems. Expenditures include expanding existing or constructing new
facilities, purchase of training equipment, and the construction and maintenance of actual
utility infrastructure designed specifically for the training of employees.
Rosentrater, Di 26
Avista Corporation
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Table No. 5 - Other Capital Proiects (System)
Other Capital Projects (System)
In $(000's)
Business Case Name 2019
Fleet Capital Replacement Program
Strategic
Total Planned Other Capital Projects
$ 8,582
4,730
$ 13,312
Fleet Capital Replacement Program - $8,582,000
Avista's replacement of its service vehicles and heavy equipment is based on the analysis of
total life cycle costs, optimized to achieve the lowest total cost of ownership. To perform this
analysis, the Company relies on the "Vehicle Replacement Model" provided by Utilimarc.
The model uses benchmarking information, purchase and auction sales data, combined with a
range of nationwide vehicle statistics, to produce a robust estimate of the optimum timing for
replacement of vehicles based on its residual value, the maintenance required to keep the
vehicle in service, and the cost of a replacement. Capital project requests are created for each
vehicle and piece of equipment to be replaced and the prioritization of projects is based on
minimizing our overall business risk and costs of ownership. This approach to replacing assets
based on condition, prior to its likely failure, has helped the Company avoid numerous
incidents of vehicles failing while in service, resulting in extended vehicle and crew down
time, high cost for parts and labor required for emergency repairs, and unplanned
replacements. These costly incidents would be the result if the Company were to fail to make
the investments in its service vehicles and equipment planned during this timeframe.
Strategic - $4,730,000
The strategic program is available for a limited amount of flexible funding beyond annual
capital guidance. The types of projects included under this business case meet the Company's
specific strategic plan. An example of the type of projects22 that have been included under this
business case include the Clean Energy Fund 2 battery storage project. The limit for Strategic
projects is currently $5 million granted per year. For a multi-year project request, the total cost
is counted against the limit in the year of request, as opposed to annual dollar values. Projects
may need greater flexibility and quicker response than the normal capital planning cycle, and
may not fit within the investment drivers. For instance, an agency such as the Department of
Energy may issue a grant request. The company may prepare and file a proposal for projects
such as for smart grid or battery demonstration.
22 The number above, $4,730,000, represents a system total for the strategic overall business case. There are several sub-
business cases within the strategic business case, including some directly assigned business cases (i.e.; Electric Vehicle Pilot
Program in Washington). Business cases that are directly assigned to Washington have not been provided in this filing and
have not been included in the Company's revenue requirement request.
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Avista Corporation
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V. CONCLUSION
a. Is the plant investment presented in your testimony necessary to provide
safe, reliable service to customers?
A. Yes. The investments in Avista's energy delivery infrastructure and office and
operations facilities included in this case, represent a prudent balance of maintaining the
integrity of our electric system, meeting compliance requirements for reliability and safety,
providing the capacity to meet current and future service needs, while being sensitive to the
rate impacts to customers resulting from these investments. Overall, these investments provide
Avista the ability to continue to provide safe, reliable, and cost-effective service to our
customers.
a. Does this conclude your pre-filed direct testimony?
A. Yes.
Rosentrater, Di 28
Avista Corporation
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