20170609Kinney Direct.pdf

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

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-17-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) DIRECT TESTIMONY
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) SCOTT J. KINNEY
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Kinney, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, employer and business 2
address. 3
A. My name is Scott J. Kinney. I am employed as the
Director of Power Supply at Avista Corporation, located at 1411
East Mission Avenue, Spokane, Washington.
Q. Would you briefly describe your educational and 7
professional background? 8
A. Yes. I graduated from Gonzaga University in 1991
with a B.S. in Electrical Engineering and I am a licensed
Professional Engineer in the State of Washington. I joined the
Company in 1999 after spending eight years with the Bonneville
Power Administration. I have held several different positions
at Avista in the Transmission Department, beginning as a Senior
Transmission Planning Engineer. In 2002, I moved to the System
Operations Department as a Supervisor and Support Engineer. In
2004, I was appointed as the Chief Engineer, System Operations
and as the Director of Transmission Operations in June 2008. I
became the Director of Power Supply in January 2013, where my
primary responsibilities involve management and oversight of
short- and long-term planning and acquisition of power
resources.
Kinney, Di 2
Avista Corporation
Q. What is the scope of your testimony in this 1
proceeding? 2
A. My testimony provides an overview of Avista’s 3
resource planning and power supply operations. This includes
summaries of the Company’s generation resources, the current
and future load and resource position, and future resource
plans. As part of an overview of the Company’s risk management 7
policy, I will provide an overview of the Company’s hedging 8
practices. I will address hydroelectric and thermal project
upgrades, followed by an update on recent developments
regarding hydro licensing.
A table of contents for my testimony is as follows:
Description Page
I. Introduction 1
II. Resource Planning and Power Operations 3
III. Generation Capital Projects 11
IV. Hydro Relicensing 33
18
Q. Are you sponsoring any exhibits? 19
A. Yes. Exhibit No. 4, Schedule 1 includes Avista’s 20
2015 Electric Integrated Resource Plan and Appendices,
Confidential Exhibit No. 4, Schedule 2 includes Avista’s Energy 22
Resources Risk Policy, and Exhibit No. 4, Schedule 3 includes
Kinney, Di 3
Avista Corporation
the Generation and Environmental Capital Project Business
Cases.

II. RESOURCE PLANNING AND POWER OPERATIONS 4
Q. Would you please provide an overview of Avista’s 5
owned-generating resources? 6
A. Yes. Avista’s owned generating resource portfolio
includes a mix of hydroelectric generation projects, base-load
coal and base-load natural gas-fired thermal generation
facilities, waste wood-fired generation, and natural gas-fired
peaking generation. Avista-owned generation facilities have a
total capability of 1,925 MW, which includes 56% hydroelectric
and 44% thermal resources.
Table Nos. 1 and 2 summarize the present net capability of
Avista’s hydroelectric and thermal generation resources: 15
Kinney, Di 4
Avista Corporation
Table No. 1: Avista-Owned Hydroelectric Generation 1

8
Table No. 2: Avista-Owned Thermal Generation 9
10
11
12
13
14
15
16
Q. Would you please provide a brief overview of Avista’s 17
major generation contracts? 18
A. Yes. Avista’s contracted-for generation resource
portfolio consists of Mid-Columbia hydroelectric, PURPA, a
tolling agreement for a natural gas-fired combined cycle
generator, and a contract with a wind generation facility.

Project Name Fuel
Type
Start
Date
Winter
Maximum
Capacity
(MW)
Summer
Maximum
Capacity
(MW)
Nameplate
Capacity
(MW)
Colstrip 3 (15%) Coal 1984 111.0 111.0 123.5
Colstrip 4 (15%) Coal 1986 111.0 111.0 123.5
Rathdrum Gas 1995 176.0 130.0 166.5
Northeast Gas 1978 66.0 42.0 61.2
Boulder Park Gas 2002 24.6 24.6 24.6
Coyote Springs 2 Gas 2003 312.0 277.0 287.3
Kettle Falls Wood 1983 47.0 47.0 50.7
Kettle Falls CT Gas 2002 11.0 8.0 7.5
Total 858.6 750.6 844.8

Project Name River
System
Nameplate
Capacity
(MW)
Maximum
Capability
(MW)
Expected
Energy
(aMW)
Monroe Street Spokane 14.8 15.0 11.2
Post Falls Spokane 14.8 18.0 9.4
Nine Mile Spokane 36.0 32 15.7
Little Falls Spokane 32.0 35.2 22.6
Long Lake Spokane 81.6 89.0 56.0
Upper Falls Spokane 10.0 10.2 7.3
Cabinet Gorge Clark Fork 265.2 270.5 123.6
Noxon Rapids Clark Fork 518.0 610.0 195.6
Total Hydroelectric 972.4 1,079.9 441.4
1
Kinney, Di 5
Avista Corporation
The Company currently has long-term contractual rights for
resources owned and operated by the Public Utility Districts of
Chelan, Douglas and Grant counties. Table No. 3 provides the
estimated energy and capacity associated with the Mid-Columbia
hydroelectric contracts. Additional details on these contracts
are presented in Company witness Mr. Johnson’s testimony.
Table No. 3: Mid-Columbia Hydroelectric Capacity and Energy 7
Contracts 8

Table No. 4 below provides details about other resource
contracts. Avista has a long-term power purchase agreement
(PPA) in place through October 2026 entitling the Company to
dispatch, purchase fuel for, and receive the power output from,
the Lancaster natural gas-fired combined-cycle combustion
turbine project located in Rathdrum, Idaho. In 2011, the
Company executed a 30-year power purchase agreement to purchase
the output (105 MW peak) and all environmental attributes from
Counter Party –
Hydroelectric
Project
Share
(%)
Start
Date
End
Date
Estimated
On-Peak
Capability
(MW)
Annual
Energy
(aMW)
Grant PUD – Priest
Rapids
3.7 12/2001 12/2052 36 19.5
Grant PUD – Wanapum 3.7 12/2001 12/2052 39 18.7
Chelan PUD – Rocky
Reach
5.0 1/2015 12/2020 56 33.0
Chelan PUD – Rock
Island
5.0 1/2015 12/2020 25 17.0
Douglas PUD - Wells 3.3 2/1965 8/2018 24 17.4
Douglas PUD – Wells
renewal
2.0 9/2018 9/2028 14 8.1
Canadian Entitlement -3
1
Kinney, Di 6
Avista Corporation
the Palouse Wind, LLC wind generation project that began
commercial operation in December 2012. Mr. Johnson provides
details related to the remaining contract rights and
obligations in Table No. 4.
Table No. 4: Other Contractual Rights and Obligations

1

Q. Would you please provide a summary of Avista's power 13
supply operations and acquisition of new resources? 14
A. Yes. Avista uses a combination of owned and
contracted-for resources to serve its load requirements. The
Power Supply Department is responsible for dispatch decisions
related to those resources for which the Company has dispatch
rights. The Department monitors and routinely studies capacity
and energy resource needs. Short- and medium-term wholesale
transactions are used to economically balance resources with

1 Energy America, LLC sale is 50 aMW through 2018 and then decreases to 20
aMW in 2019.
Contract Type Fuel
Source
End
Date
Winter
Capacity
(MW)
Summer
Capacity
(MW)
Annual
Energy
(aMW)
Energy America,
LLC1
Sale Various 12/2019 -50 -50 -50
Douglas
Settlement
Purchase Hydro 9/2018 2 2 3
WNP-3 Purchase System 6/2019 82 0 42
Lancaster Purchase Gas 10/2026 290 249 222
Palouse Wind Purchase Wind 12/2042 0 0 40
Nichols Pumping Sale System 10/2018 -6.8 -6.8 -6.8
PURPA Contracts Purchase Varies Varies 47.6 47.6 28.8
Total 364.8 241.8 279
1
Kinney, Di 7
Avista Corporation
load requirements. The Integrated Resource Plan (IRP)
generally guides longer-term resource decisions such as the
acquisition of new generation resources, upgrades to existing
resources, demand-side management (DSM), and long-term contract
purchases. Resource acquisitions typically include a Request
for Proposals (RFP) and/or other market due diligence
processes.
Q. Please summarize Avista’s load and resource position. 8
A. Avista’s 2015 IRP shows forecasted annual energy
deficits beginning in 2026, and annual capacity deficits
beginning in 2021. These capacity and energy load/resource
positions are shown on pages 6-9 through 6-12 of Exhibit No. 4,
Schedule 1 and are also provided in Avista’s 2015 IRP load and
resource projection.
The 2017 Electric IRP is currently being developed and is
scheduled to be filed with the Commission on August 31, 2017.
Besides ongoing energy efficiency programs, the new resource
needs are expected to be later than those identified in the
2015 IRP because of updates to the load forecast and the amount
of currently secured resources.
Q. How does Avista plan to meet future energy and 21
capacity needs? 22
Kinney, Di 8
Avista Corporation
A. The 2015 Preferred Resource Strategy (PRS) guides the
Company’s resource acquisitions. The current PRS is described
in the 2015 Electric IRP, which is attached as Exhibit No. 4,
Schedule 1. The Commission acknowledged the 2015 Electric IRP
in Order No. 33463 in Case No. AVU-E-15-08 on February 4, 2016.
The IRP provides details about future resource needs,
specific resource costs, resource-operating characteristics,
and the scenarios used for evaluating the mix of resources for
the PRS. The IRP represents the preferred plan at a point in
time; however, Avista continuously evaluates different resource
options to meet current and future load obligations. The
Company held the first meeting of the Technical Advisory
Committee on June 2, 2016 to begin the 2017 IRP effort and will
conclude with the sixth meeting on June 20, 2017.
Avista’s 2015 PRS includes 193 MWs of cumulative energy
efficiency, 41 MWs of upgrades to existing thermal plants, and
525 MWs of natural gas-fired plants (239 MWs of simple cycle
combustion turbines (SCCT) and 286 MWs of combined-cycle
combustion turbine (CCCT)). The timing and type of these
resources as published in the 2015 IRP is provided in Table
No. 5.
Kinney, Di 9
Avista Corporation
Table No. 5: 2015 Electric IRP Preferred Resource Strategy 1
2
3
4
5
6
7
8
9
Q. Would you please provide a high-level summary of 10
Avista’s risk management program for energy resources? 11
A. Yes. Avista Utilities uses several techniques to
manage the risks associated with serving load and managing
Company-owned and controlled resources. The Energy Resources
Risk Policy, which is attached as Confidential Exhibit No. 4,
Schedule 2, provides general guidance to manage the Company’s 16
energy risk exposure relating to electric power and natural gas
resources over the long-term (more than 41 months), the short-
term (monthly and quarterly periods up to approximately 41
months), and the immediate term (present month).
The Energy Resources Risk Policy is not a specific
procurement plan for buying or selling power or natural gas at
any particular time, but is a guideline used by management when
Resource Type By the End of
Year
ISO Conditions
(MW)

(MW)

Winter Peak
(MW)(MW)
Energy
(aMW)
Natural Gas Peaker 2020 96 102 89
Thermal Upgrades 2021-2025 38 38 35
Combined Cycle CT 2026 286 306 265
Natural Gas Peaker 2027 96 102 89
Thermal Upgrades 2033 3 3 3
Natural Gas Peaker 2034 47 47 43
Total 565 597 524

Efficiency
Improvements
Acquisition Range Winter Peak
Reduction
(MW)
Energy
(aMW)
Energy Efficiency 2016-2035 193 132
Distribution Efficiencies <1 <1
Total Efficiency 193 132
1
Kinney, Di 10
Avista Corporation
making procurement decisions for electric power and natural gas
as fuel for generation. The policy considers several factors,
including the variability associated with loads, hydroelectric
generation, planned outages, and electric power and natural gas
prices in the decision-making process.
Avista aims to develop or acquire long-term energy
resources based on the current IRP’s PRS, while taking advantage
of competitive opportunities to satisfy electric resource
supply needs in the long-term period. Electric power and
natural gas fuel transactions in the immediate term are driven
by a combination of factors that incorporate both economics and
operations, including near-term market conditions (price and
liquidity), generation economics, project license requirements,
load and generation variability, reliability considerations,
and other near-term operational factors.
For the short-term timeframe, the Company’s Energy 16
Resources Risk Policy guides its approach to hedging
financially open forward positions. A financially open forward
period position may be the result of either a short position
situation, for which the Company has not yet purchased the
fixed-price fuel to generate, or alternatively has not
purchased fixed-price electric power from the market, to meet
projected average load for the forward period. Or it may be a
Kinney, Di 11
Avista Corporation
long position, for which Avista has generation above its
expected average load needs, and has not yet made a fixed-price
sale of that surplus to the market in order to balance resources
and loads.
The Company employs an Electric Hedging Plan to guide power
supply position management in the short-term period. The Risk
Policy Electric Hedging Plan is essentially a price
diversification approach employing a layering strategy for
forward purchases and sales of either natural gas fuel for
generation or electric power in order to approach a generally
balanced financial position against expected load as forward
periods draw nearer.

III. GENERATION CAPITAL PROJECTS 14
Q. Please explain how the Company prepared its case with 15
regard to generation capital projects. 16
A. In this proceeding the Company is proposing a
Two-Year Rate Plan for 2018 and 2019. For Rate Year 1
(effective January 1, 2018), the Company included capital
project additions for 2017 on an end of period basis. For Rate
Year 2 (effective January 1, 2019), the Company included 2018
capital project additions as well as an average of monthly
averages of 2019 capital project additions. For further
Kinney, Di 12
Avista Corporation
discussion regarding the Pro Forma adjustments, please see
Company witness Ms. Schuh’s testimony. 2
Q. Company witness Mr. Morris identifies and briefly 3
explains the six “Investment Drivers” or classifications of 4
Avista’s infrastructure projects and programs. How then do 5
these “drivers” translate to the capital expenditures that are 6
occurring in the Company’s generation area? 7
A. The Company’s six Investment Drivers are briefly
described as follows:
1. Customer Requested - Respond to customer requests for new
service or service enhancements;

2. Customer Service Quality and Reliability - Meet our
customers’ expectations for quality and reliability of 14
service;

3. Mandatory and Compliance - Meet regulatory and other
mandatory obligations;

4. Performance and Capacity - Address system performance and
capacity issues;

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

6. Failed Plant and Operations - Replace equipment that is
damaged or fails, and support field operations.
28
The main drivers for the generation-related capital investment
include:
Kinney, Di 13
Avista Corporation
 Updating and replacing century-old equipment in many
of the Company’s hydro facilities to reduce equipment 2
failure forced outages;
 Regular responsive maintenance for reliability to
keep generating plants operational;
 Projects to address plant safety and electrical
capacity issues;
 Capital requirements from settlement agreements for
the implementation of Protection, Mitigation and
Enhancement (PM&E) programs related to the FERC
License for the Spokane River and Clark Fork River
hydroelectric projects; and
 Efficiency upgrades and improvements to meet energy
and capacity requirements as determined through the
Integrated Resource Plan.
Q. Please describe the capital planning process that the 16
Generation area goes through before generation capital projects 17
are submitted to the Capital Planning Group. 18
A. The capital planning process in Generation Production
& Substation Support (GPSS) consists of three main phases. The
first phase is a long range or 10-year plan, the second is the
five-year prioritization activity, and the third is the five-
Kinney, Di 14
Avista Corporation
year estimating process. Descriptions of each phase of the
planning process follow.
The long range or 10-year plan uses a database tool that
exists as the central repository for projects and their
associated elements. Projects can be added to the 10-Year
Database in several ways:
 Informal project requests;
 Input from asset life cycle, condition, needs
assessment;
 Periodic report from Maximo of open corrective
maintenance work orders;
 Periodic report from Maximo of scheduled preventive
maintenance work orders;
 Annual maintenance requirements;
 Regulatory mandates;
 Project change requests, drop ins, budget changes, etc.;
 Formal project request applications; and
 Efficiency and IRP related upgrades.
The GPSS managers meet quarterly to review the 10-year
plan, confirm that it is up to date and close completed
projects. New projects are highlighted and noted. The impact
Kinney, Di 15
Avista Corporation
of each additional project is reviewed. Any disagreement in
the priority of projects is discussed until a solution is found.
The GPSS management team then participates in an annual
workshop in preparation for the budget cycle to prioritize the
projects included in the five-year horizon. The team utilizes
a formal ranking matrix to insure that the projects are
prioritized consistently.
Annually, the projects for the next year will be assigned
and any capacity or budget constraints are identified and
project schedules adjusted accordingly by the GPSS Management
Team. GPSS Management and key stakeholders meet monthly at the
Generation Coordination Meeting and specific Program or Project
Steering Committee Meetings to discuss changes and progress to
the schedule. Adjustments and consensus will take place at
these meetings.
Q. What generation-related capital projects are planned 16
to be completed in the next five years? 17
A. Table No. 6 shows the amount of projected generation
capital transfers to plant by project and by year from 2017
through 2019 on a system basis. The main investment drivers
(as discussed earlier) of capital transfers for generation
resources include asset condition, failed plant and operations,
mandatory compliance, and performance and capacity. Details
Kinney, Di 16
Avista Corporation
Business Case Name 2017 2018 2019
Asset Condition
Automation Replacement 500 450 600
Cabinet Gorge Automation Replacement 330 2,093
Cabinet Gorge Station Service Replacement 2,137
Cabinet Gorge Unit 1 Refurbishment 4
Generation DC Supplied System Upgrade 1,220 1,646 750
Kettle Falls CT Control Upgrade 669
Kettle Falls Stator Rewind 6,316
Little Falls Plant Upgrade 10,481 16,444
Long Lake Plant Upgrades 78 3,950 5,000
Nine Mile Rehab 9,526 2,213 16,210
Noxon Station Service 2,503 1,290
Peaking Generation 500 500 500
Post Falls Redevelopment 1 4,500 7,200
Purchase Certified Rebuilt Cat D10R Dozer 814
Replace Cabinet Gorge Gantry Crane 74 3,637
Failed Plant and Operations
Base Load Hydro 1,401 1,149 1,149
Base Load Thermal Plant 2,494 2,200 2,200
Regulating Hydro 6,131 3,533 3,533
Mandatory and Compliance
Colstrip Thermal Capital 9,500 4,420 10,370
Clark Fork Settlement Agreement 7,394 6,052 39,097
Hydro Safety Minor Blanket 350 50 55
Kettle Falls RO System 4,510
Spokane River License Implementation 2,007 2,786 533
Total Planned Generation Capital Projects $ 66,135 $ 59,718 $ 87,196
(System) In $(000's)
about the generation-related capital projects over the period
2017-2019 are discussed following Table No. 6, and business
cases supporting each of these projects are provided in Exhibit
No. 4, Schedule 3.
Table No. 6: Generation Capital Spending by Business Case 5
(2017 – 2019)

22
Kinney, Di 17
Avista Corporation
Q. Would you please explain the capital projects related 1
to asset conditions that are planned to be completed in the 2
next five years?
A. Yes, these capital projects include investments to
replace assets based on established asset management principles
and strategies adopted by the Company, which are designed to
optimize the overall lifecycle value of the investment for our
customers. Projects in this investment category are identified
in Table No. 6 above.
Brief descriptions of each project, the reasons for the
projects, the risks of not completing the projects, and the
timing of the decisions follow. Additional details can be found
in Exhibit No. 4, Schedule 3, Generation and Environmental
Capital Project Business Cases.
Automation Replacement - 2017: $500,000; 2018: $450,000; 2019: 15
$600,000 16
The Automation Replacement project systematically replaces the
unit and station service control equipment at our generating
facilities with a system compatible with Avista’s current 19
standards for reliability. Upgrading control systems within
our generating facilities allows us to provide reliable energy.
The Distributed Controls Systems (DCS) and Programmable Logic
Controllers (PLC) are used to control and monitor Avista’s 23
individual generating units as well as each total generating
facility. The DCS and PLC work is needed now to reduce the
higher risk of failure due to the aging equipment. The DCSs
are no longer supported and spare modules are limited. The
modules in service have a high risk of failure as they are over
20 years old. The computer drivers that are needed to
communicate to the DCSs will not fit in new computers with
Windows 10 operating systems, creating a cyber-security issue.
The software needed to view and modify the logic programs only
Kinney, Di 18
Avista Corporation
runs on Windows 95. Avista has a very limited supply of Windows
95 laptops and they also continue to fail. Replacing aging
DCSs and PLCs will reduce unexpected plant outages that require
emergency repair with like equipment. A planned approach allows
engineers and technicians to update logic programs more
effectively and replace hardware with current standards.

Avista’s hydro facilities were designed for base load
operation, but are now called on to quickly change output in
response to the variability of wind generation, to adjust to
changing customer loads, and other regulating services needed
to balance the system load requirements and assure transmission
reliability. The controls necessary to respond to these new
demands include speed controllers (governors), voltage controls
(automatic voltage regulator a.k.a. AVR), primary unit control
system (i.e. PLC), and the protective relay system. In addition
to reducing unplanned outages, these systems will allow Avista
to maximize ancillary services within its own assets on behalf
of its customers rather than having to procure them from other
providers.

Cabinet Gorge Automation Replacement - 2017: $330,000; 2018: 22
$2,093,000 23
The Cabinet Gorge Automation Replacement project replaces the
unit and station service control equipment with a system
compatible with Avista’s current standards. This plant was
designed for base load operation, but is now called on to
quickly change output in response to the variability of wind
generation, to adjust to changing customer loads, and other
regulating services needed to balance the system load
requirements and assure transmission reliability. The controls
necessary to respond to these new demands include speed
controllers (governors), voltage controls (automatic voltage
regulator a.k.a. AVR), primary unit control system (i.e. PLC),
and the protective relay system. In addition to reducing
unplanned outages, these systems will allow Avista to maximize
ancillary services on behalf of its customers rather than having
to procure such services from other providers.
39
Cabinet Gorge Station Service Replacement - 2018: $2,137,000 40
The Cabinet Gorge Station Service project includes replacement
of several components, many of them original to the plant.
Station Service is an elaborate system required to provide
electric power to the plant with multiple built-in redundancies
Kinney, Di 19
Avista Corporation
designed to protect the plant’s electrical operation. Station 1
Service components include Transformers, Power Centers, Motor
Control Centers, Load Centers, Emergency Load Centers and
various breakers. The Station Service transformers no longer
have the capacity to provide adequate plant load service and
could be subject to overload. The current Motor Control Centers
(MCC) lack monitoring and indication. Replacement of these
MCCs would create operational efficiencies by providing
visibility into Station Service performance. The cables
require evaluation due to the age of insulation and the wet
conditions they have been subject to over the years. The weight
due to the number of cables in the tray is a cause of concern
for potential failure. Due to system additions, the existing
Emergency Generator no longer meets the load critical
requirements for the plant. If no action is taken, there is a
risk of individual component failure that could force load
shedding under certain operational scenarios. If a
catastrophic failure occurred within the switchgear and/or
power cables, it could result in generator unit and/or plant
wide forced outages potentially lasting as long as eight months
because of the manufacturing lead time for some specialized
equipment. Unplanned hydro outages can result in either
purchasing higher cost replacement power from the market or
utilizing other more costly Avista generation, and may result
in FERC license violations if the plant needs to spill water. 25
26
Cabinet Gorge Unit 1 Refurbishment - 2017: $4,000 27
This is the final capital portion of a major overhaul project
completed on Cabinet Gorge Unit #1. The runner hub had
significant mechanical issues and needed to be replaced to allow
for frequent cycling associated with the integration of
intermittent renewable resources. The previous automatic
voltage regulator provided a relatively slow response due to
its hybrid design and had no limiters for generator protection.
The new system provides faster response and adds limiters. The
new machine monitoring allows for better analysis of machine
condition for this important unit. Rehabilitation of this unit
allows flexibility to operate under minimum river flow for fish
habitat.
40
Generation DC Supplied System Upgrade - 2017: $1,220,000; 2018: 41
$1,646,000; 2019: $750,000 42
The Generation DC Supplied System Upgrade is a multiyear project
to update existing plant DC systems to meet Avista's current
Generation Plant DC System Standard. This program will make
compliance with the NERC PRC-005 Reliability Standard more
Kinney, Di 20
Avista Corporation
tenable and significantly reduce plant outage times now
required for periodic testing to meet the standard. The project
changes DC System configurations to more easily comply with the
NERC requirements for inspection and testing. It addresses
battery room environmental conditions to optimize battery life.
The project replaces legacy UPS systems with an inverter system
and addresses auxiliary equipment based on its life cycle. The
Company is currently addressing Battery Bank replacement based
on the manufacturers recommended life cycle, which is based on
ideal operating conditions. For temperatures fifteen degrees
F over the normal operating temperature, the life cycle
decreases 50 percent. Component failure, utilization from
multiple extended outages and manufacturer’s quality are
problems we have experienced on these systems. The alternative
approach of replacing components as they fail and gradually
building out to Avista’s current standard may reduce program
costs, but adds significant risk of unpredictable full system
failures leading to forced plant outages. This program covers
both thermal and hydro generation assets. Each planned project
will take approximately 16 to 18 months to complete. Added
complexity, cost, and time may be needed if extensive work is
required to address the temperature and other environmental
issues with the location of each new battery system.

Kettle Falls CT Control Upgrade - 2018: $669,000 25
This project will replace the Solar Combustion Turbine HMI
software and hardware, upgrade PLC controls platform, and
replace the Fire Protection system. The current controls are
outdated, with spare parts and software support no longer
available. Without this project, the system will continue to
deteriorate, increasing the risk of forced outages. In 2002,
KFGS added a second 7 MW generating unit at the facility that
can operate in simple or combined cycle modes. Operation of
this CT, the associated heat recovery steam generator (HRSG)
and fire protection is done remotely through the Solar TTX
controls system. The controls platform is legacy equipment and
the control program is no longer supported. Additionally, the
installed version of the Allen Bradley control network has not
been supported for many years. The Human Machine Interface
(HMI) control system used by operations functions on Windows
2000 software, which is no longer available or supported. The
desktop operating computer recently failed and the plant is now
operating without a spare. With this failed HMI, the HRSG
cannot be operated from the local control panel at the turbine
enclosure. If the remaining HMI fails, the CT will only be
able to be operated in the simple-cycle mode as there will not
Kinney, Di 21
Avista Corporation
be any communication with the HRSG system. The fire protection
system is no longer supported and the unit will not be operated
without the fire protection system in service due to insurance
requirements. The unit posted its third and fourth highest
forced outage rates in the past 15 years in 2013 and 2014. The
higher forced outage rate was mostly attributed to components
failing within the fire protection system. The upward failure
trend is expected to continue. With an increase in plant
operations and increasing forced outage rate, mostly attributed
to control devices failing on the fire protection system,
various options were discussed. Doing nothing will eventually
put the combustion turbine in an unreliable and unsafe mode.
The option chosen includes installation of new software and
hardware in conjunction with upgrading the fire protection
system with the newest turbine controls. Completion of this
project will increase unit reliability while maintaining safe
operations.
18
Kettle Falls Stator Rewind - 2017: $6,316,000 19
The KFGS Stator Rewind project aims to rewind the 30 plus year
old stator, which is at the end of its expected life. Field
inspections performed by GE and Avista using industry standard
megger tests have shown a decline in the winding insulation
resistance. A 2014 report prepared by the Asset Management
group demonstrated the prudency of replacing the winding before
it fails in service. Failing in service would significantly
extend the outage time and the cost to repair. Scheduled work
to rewind the stator is a proactive measure to ensure
uninterrupted and efficient operations. This project consists
of monitoring the existing machine, developing a rewind
contract, manufacturing replacement coils, disassembly, coil
removal, new coil installation, reassembly, startup, testing
and commissioning. The consequences of a stator failure include
an unscheduled outage with lost generation, loss of renewable
energy credits required for compliance with the Energy
Independence Act, long-term interruption of fuel supply,
potential collateral damage to the core and hydrogen cooling,
and poses a significant safety hazard.

Little Falls Plant Upgrade - 2017: $10,481,000; 2018: 40
$16,444,000 41
This is an ongoing multi-year project to replace the Little
Falls equipment that ranged in age from 60 to more than 100
years old. Forced outages at Little Falls because of equipment
failures have significantly increased from about 20 hours in
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Avista Corporation
2004 to several hundred hours in the past few years. This
project replaces nearly all of the older, unreliable equipment
with new equipment, including replacing two of the turbines,
all four generators, all generator breakers, three of the four
governors, all of the automatic voltage regulators, removing
all four generator exciters, replacing unit controls, changing
the switchyard configuration, replacing the unit protection
system, and replacing and modernizing the station service.
Without this focused replacement effort forced outages and
emergency repairs would continue to increase, reducing the
reliability of the plant. At some point, personnel may need to
be placed back in the plant adding to the operating costs. The
Asset Management group analyzed the age and condition of all of
the equipment in the plant. All of the equipment has been
qualified as obsolete in accordance with the obsolescence
criteria tool. There are many items in this 100-year old
facility which do not meet modern design standards, codes and
expectations. This replacement effort will allow Little Falls
to be operated reliably and efficiently. Upgrades and
replacements associated with two of the four units at Little
Falls have been completed. The replacements associated with
the remaining two units will be performed over the next two to
three years.
24
Long Lake Plant Upgrades - 2017: $78,000; 2018: $3,950,000; 25
2019: $5,000,000 26
The Long Lake Plant Upgrade is a multiyear project to replace
and improve plant equipment and systems that range from 20 to
more than 100 years old. The effort will begin with the project
design in 2018 and expected project completion in 2024. Forced
outages at the plant have increased annually from almost zero
in 2011 because of equipment failures on multiple pieces of
equipment. Specifically, a turbine failed in 2015 and there
have been problems with servicing and sourcing parts for the
failing 1990 vintage control system. This has caused O&M
spending to increase in recent years with a projected upward
trend. Prior upgrades to the project are reaching the end of
their useful life and have placed additional stress on the
plant. There are also safety issues involved with moving
station service from one generator to the other that need to be
addressed. This project will replace the existing major unit
equipment in kind including generators, field poles, governors,
exciters, and generator breakers. The generators are currently
operated at their maximum temperature which stresses the life
cycle of the already 50 plus-year-old windings. Inspections of
other components of the generator show the stator core is
Kinney, Di 23
Avista Corporation
“wavy”, which is a strong indication higher than expected losses 1
are occurring in the generator. Finally, maintenance reports
have identified that the field poles on the rotor have shifted
from their designed position over the years. The Generator
Step Up (GSU’s) transformers are over 30 years old and operating 5
at the high end of their design temperature. The GSU’s are 6
approaching the end of their useful life and need to be replaced
proactively rather than waiting for a failure. Personnel safety
is another significant driver for this. The switching procedure
for moving station service from one generator to the other
resulted in a lost time accident and a near miss incident in
the past five years. In addition, the station service
disconnects represent the greatest arc-flash potential in the
company. This project will reconfigure the system to eliminate
requiring personnel to perform this operation and avoid the
arc-flash potential area.
17
Nine Mile Rehabilitation - 2017: $9,526,000; 2018: $2,213,000; 18
2019: $16,210,000 19
The Nine Mile Redevelopment is a continuing capital project to
rehabilitate and modernize the four unit Nine Mile Hydro
Electric Dam. The existing three MW Units 1 and 2, which were
over 100 years old, were recently replaced with two new eight
MW generators/turbines. The new units added 1.4 aMW of energy
and 6.4 MW of capacity above the original configuration
generation levels. In addition to these capacity upgrades, the
Nine Mile facility has and will receive multiple other upgrades.
The additional work at the plant include upgrades to Units 3
and 4 over the next several years. The Unit 3 and 4 work
includes major unit overhaul of the Runners, Thrust Bearings,
and Switchgear; upgrades to the Control and Protection Package
including Excitation and Governors; and Rehabilitating the
Intake Gates and Trash Rack. Also the sediment bypass system
will be redesigned to improve sediment passage. At completion,
the total powerhouse production capacity will be increased,
units will experience less outages, reduced damaged from
sediment, and the failing control components will be replaced.
Spending began in 2012 and is expected to continue through 2019.
39
Noxon Station Service - 2017: $2,503,000; 2018: $1,290,000 40
All generation facilities require Station Service to provide
electric power to the plant. Station Service components include
Motor Control Centers, Load Centers, Emergency Load Centers and
various breakers. Station Service is an elaborate system with
multiple built-in redundancies designed to protect the plant’s 45
electrical operation. In the fall of 2013, studies in response
Kinney, Di 24
Avista Corporation
to an electrical overcurrent coordination issue found that a
majority of the Station Service components at Noxon Rapids
require replacement due to electrical capacity and rating
issues stemming from the added loads at the plant and the growth
of the electric system in the 50 years of service. This project
seeks to create a more reliable Station Service system with the
replacement of multiple components in order to avoid forced
outages and to modernize the electrical delivery system in the
plant. Additionally, this effort will provide remote operation
and monitoring capabilities, incorporate previously incomplete
service expansions, support future system expansion, improve
operator safety and ensure regulatory compliance. If no action
is taken, there is a risk of catastrophic switch gear failure
and generator unit forced outages for up to a year. Without
replacement forced load shedding under certain operational
scenarios could be necessary which has an impact on plant
operations. Multiple alternatives were considered for this
project including do nothing. The chosen alternative replaces
and upgrades the equipment described above.

Peaking Generation - 2017: $500,000; 2018: $500,000; 2019: 21
$500,000 22
The Peaking Generation program focuses on the ongoing capital
maintenance expenditures required to keep Boulder Park,
Rathdrum CT, and Northeast CT operating at or above their
current performance levels. The program maximizes the ability
of these units to start and run efficiently when requested.
The reliability of these assets will decline over time,
resulting in failure to start, non-compliant emissions, or
inefficient operation without this type of program. It is
critical that these facilities start when requested to reduce
exposure to high market prices or the loss of other Company
resources. The program includes initiatives to meet FERC, NERC
and EPA mandated compliance requirements.
35
Post Falls Redevelopment - 2017: $1,000; 2018: $4,500,000; 36
2019: $7,200,000 37
The Post Falls HED has been in continual operation since 1906.
The generators, turbines, and governors (turbine speed
controller) are original equipment and are still in service.
The brick powerhouse with riveted steel superstructure remains
largely the same as when it started operation. While the plant
is still producing electricity, the generating equipment,
protective relaying, unit controls, and many other components
of the operating equipment are mechanically and functionally
failing. The turbines are estimated to be 50 percent efficient
Kinney, Di 25
Avista Corporation
contrasted to modern 90 plus percent efficient turbines. The
existing governors have had patchwork repairs due to lack of
replacement parts and while they allow for unit control, they
are ineffective in their response to system disturbances.
Generator voltage controllers, protective relays, and unit
monitoring systems all have a similar marginal functionality.
The units are exhibiting signs of failure. The age of the plant
and its original design presents some personnel safety issues
that have evolved over time. For example, the access port for
crews to access and maintain the turbine runners is too small
to allow for any type of backboard or stretcher to exit the
turbine area in the event of an injury. The castings used to
create the turbine water case do not allow the opening to be
increased without risk of permanently damaging the water case
and leaking. For this reason, crews have not been able to
access the turbines to maintain the runners for nearly a decade.
Additionally, control modifications from the late 1940’s place 17
the primary generator breakers inside the control room
presenting an unacceptable arc flash hazard to operating and
maintenance personnel. While either the operation desk or the
switchgear can be relocated to address this issue, this work
would cost several million dollars and would not address other
issues associated with the plant.

Finally, the Post Falls project has a number of critical
operational requirements that support key recreational
facilities, fishery, and other FERC license requirements. The
Post Falls dam must provide minimum flows during summer months
to support fishery habitat downstream and is also subject to
restrictions on how fast the flows through the project can
change in order to meet downstream flow requirements. The
present plant controls marginally provide the precision needed
for this control. To address water quality issues during high
river flow seasons, unit and spillway controls must follow
certain procedures to minimize Total Dissolved Gas creation in
the river system. In addition, flows through the project impact
regional recreational resources which rely on the water control
at Post Falls to maintain the water levels during the summer
months. Finally, there is a City Park and boat launch that are
located within the immediate upstream reservoir. Safety
requirements have been implemented that require all spillgates
at the project to be closed before boaters are allowed to use
the boat launch and recreate in the reservoir immediately
upstream. Flows that would normally go through the plant need
to be passed through the spillgates instead because of the
unreliability of the generating units, extended maintenance
Kinney, Di 26
Avista Corporation
outages, unit de-rates, and forced outages. This requires the
boat launch opening to be delayed or in some cases closed on an
emergency basis until flows subside or the generating unit can
be returned to service.

In an effort to determine a prudent course of action to address
the Post Falls project, a significant Assessment Study was
performed to consider a number of different options that might
address the issues described above. This assessment concluded
that the most prudent course of action was to redevelop the
site by keeping the existing powerhouse and location. A
subsequent Feasibility Study evaluated different alternatives
to redevelop the existing powerhouse. Options include partial
replacement through a full redevelopment while retaining the
existing powerhouse structure. This Feasibility Study
recommended that the project be redeveloped by shutting down
the plant, removing the old equipment, and replacing it with
new. A cross functional group considered the results of these
studies, along with significant financial analysis, to
ascertain the most attractive alternative that addressed the
issues. The final conclusion of all of this effort recommended
a full replacement of the existing units and other powerhouse
equipment and that it is more beneficial to shut down the plant
during this reconstruction. The project is expected to take
five years. This work will replace the existing six generating
units with six new variable blade turbine generator units. Work
will also include ancillary replacements and powerhouse
remediation to attain a 50-year life project. In addition, the
efficiency of the new generating equipment will result in an
improvement in output capacity and energy. This project will
result in an estimated 40 percent increase in capacity and 15
percent increase in energy and reduce future major maintenance
costs. The planned approach for this replacement project
includes completing planning and preliminary construction from
2017 through 2019. The plant will be shut down in 2020 with
project completion occurring at the end of 2021.

Purchase Certified Rebuilt Cat D10R Dozer - 2017: $814,000 38
Kettle Falls Generation Station utilizes two D10 CAT dozers to
move nearly 500,000 green tons of waste wood around the storage
area year-round. Semi-trucks move wood waste from area mills
to the plant where it is moved via a conveyor system. The
dozers move the material from underneath the conveying system
to the storage pile. If the dozers break down and material is
not moved from the conveying system, trucks back up in the yard
and possibly create issues on Highway 395. Maintaining the
Kinney, Di 27
Avista Corporation
waste wood receiving equipment at the plant is critical to the
plant operations. The Fuel Equipment Operators also use the
dozers to move wood to be burned for the plant operations. The
facility cannot operate on wood waste without the use of a
dozer. The plant may operate on natural gas at 50 percent
capacity but is then not classified as a renewable source and
the Renewable Energy Credits are lost. The generator is also
less efficient and not designed to operate on natural gas for
extended periods.

Normally one dozer operates while the other is in standby until
the 250 hour service is needed. Typically, the dozer operates
10-12 hours each day with each machine operating 2,000 hours
per year. Major overhauls require shipment over 80 miles to
the nearest service center in Spokane. This work is planned
and scheduled around the annual maintenance outage to reduce
the risk to plant availability due to the loss of the standby
dozer. Data over the past 20 years show the engine on the D10R
has never reached 9,000 hours of operation between failures and
the transmission has never reached 10,000 hours of operation
between failures. The CAT D10R dozer has over 36,000 operating
hours on the machine chassis. Major components have been
rebuilt and are planned on a time based maintenance schedule.
Minor components in the auxiliary systems are run until failure.
Discussions with the equipment manufacturer service
representative identified three options to consider: major
rebuild of critical components, a complete certified rebuild,
and purchase of new equipment. The fourth, doing nothing, was
not viable as the motor had failed and the transmission will
fail at some point. The recommendation is to complete a
Certified Rebuild of the CAT D10R dozer. The rebuild will be
completed during the scheduled annual maintenance outage and
will be finished two weeks prior to the plant startup. The
Certified Rebuild on our existing D10R will reset the time based
maintenance of the major and minor equipment. Reliability on
the D10R will increase with the complete rebuild and new brakes
and steering will improve safe operation.
38
Replace Cabinet Gorge Gantry Crane - 2017: $74,000; 2018: 39
$3,637,000 40
The Cabinet Gorge Gantry Crane project involves the replacement
of the original 60 plus year old gantry crane. Previous work
prolonged the crane’s usefulness, but the crane is currently 43
unable to perform dependably. The gantry crane is the only
means of moving the large machinery at Cabinet Gorge in and out
of the plant. Its inability to function reliably impacts the
Kinney, Di 28
Avista Corporation
work at the plant and presents a safety risk to personnel if
the crane fails to control the load. There is also a risk of
not being able to accomplish emergency repairs to any of the
four generating units. The gantry crane is a bottle neck
preventing annual maintenance work and capital improvements.
Problems with the crane impacted the Cabinet Gorge Unit 1
project (2014-2016) causing delays from two days to three weeks
throughout the project. This project will deliver a state-of-
the-art crane capable of safely and reliably meeting plant
needs. Alternatives ranging from total replacement to
refurbishment were considered. Construction will take over
four months, following dismantling of the existing crane and a
year-long lead time to manufacture a new crane. We anticipate
construction will be completed and the project placed in service
by December 31, 2018.
Q. Would you please provide details about the capital 16
projects related to failed plant and operations, as shown in 17
Table No. 6 above?
A. Yes, the generation capital related to failed plant
and operations covers requirements to replace assets that have
failed and which must be replaced in order to provide continuity
and adequacy of service to our customers, such as capital repair
of storm-damaged facilities. This investment driver also
includes investments in electric infrastructure that is
performed by Avista’s operational staff, and which is typically
budgeted under the category of blankets. The projects for this
investment driver include Base Load Hydro, Base Load Thermal
Plant, and Regulating Hydro. Additional details can be found
in Exhibit No. 4, Schedule 3 Generation and Environmental
Capital Project Business Cases.
Kinney, Di 29
Avista Corporation
Base Load Hydro - 2017: $1,401,000; 2018: $1,149,000; 2019: 1
$1,149,000 2
The Base Load Hydro program covers the ongoing capital
maintenance expenditures required to keep the Upper Spokane
River Plants (Post Falls, Upper Falls, Monroe Street, and Nine
Mile) operating within 90 percent of their current performance,
as well as meeting FERC and NERC mandated compliance
requirements. The historical availability for the base load
hydro plants has been declining over the past decade due to
deteriorating equipment and a need to replace aging equipment
and systems. These plants range from 90 to 105 years old. The
program focuses on ways to maintain compliance and reduce
overall O&M expenses while maintaining a reasonable level of
unit availability. Projects completed under this program
include replacement of failed equipment and small capital
upgrades to plant facilities. Most of these projects are short
in duration, and many are reactionary to plant operations
issues.

Base Load Thermal Plant - 2017: $2,494,000; 2018: $2,200,000; 20
2019: $2,200,000 21
The Base Load Thermal Plant program is an ongoing program
necessary to sustain or improve the operation of base load
thermal generating plants, including Coyote Springs 2,
Colstrip, Kettle Falls, and Lancaster. Capital projects
include replacement of items identified through asset
management decisions and programs necessary to maintain
reliable operations of these plants. As this asset maintenance
program matures, it is expected to decrease forced outage rates
and forced de-ratings of these facilities by one standard
deviation less than the current average. As these plants
continue to age and are called upon to ramp more frequently to
meet variations associated with renewable energy integration,
their operating performance begins to degrade over time
resulting in increased forced outage rates, which increases
exposure to the acquisition of replacement energy and capacity
from the market. Having a mature asset management program for
these thermal facilities helps minimize plant degradation and
market exposure. The program also includes initiatives
associated with regulatory mandates for air emissions and
monitoring, and projects to meet NERC compliance requirements.

Regulating Hydro - 2017: $6,131,000; 2018: $3,533,000; 2019: 43
$3,533,000 44
The Regulating Hydro program covers the capital maintenance
expenditures required to keep the Long Lake, Little Falls, Noxon
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Avista Corporation
Rapids and Cabinet Gorge plants operating at their current
performance levels. The program works to improve plant
operating reliability so unit output can be optimized to serve
load obligations or sold to bilateral counterparties. Work is
prioritized according to equipment needs. Sustaining this
asset management program is crucial as these facilities age and
are ramped more frequently to meet load fluctuations associated
with renewable energy integration and changing load dynamics.
Additionally, efforts in this program improve ancillary service
capabilities from these generating assets. This includes
installing blow down systems to allow for units to be on
responsive stand by and the ability to provide spinning
reserves, move load following demands to all of these plants,
voltage regulating needs, and frequency response. The program
also includes some elements of hydro license compliance as
related to plant operations and equipment.
Q. Would you please provide details about the mandatory 17
and compliance capital projects, as shown in Table No. 6 above? 18
A. Yes, the mandatory and compliance capital investment
driver typically includes projects done for compliance with
laws, rules, and contract requirements that are external to the
Company (e.g. State and Federal laws, Settlement Agreements,
FERC, NERC, and FCC rules, and Commission Orders, etc.).
Generation capital projects in this investment driver category
include Colstrip Thermal Capital, Clark Fork Settlement
Agreement, Kettle Falls Reverse Osmosis System, Environmental
Compliance, Hydro Safety Minor Blanket and the Spokane River
License Implementation. Brief descriptions of each project,
the reasons for the projects, the risks of not completing the
projects, and the timing of the decisions follow. Additional
Kinney, Di 31
Avista Corporation
details can be found in Exhibit No. 4, Schedule 3 Generation
and Environmental Capital Project Business Cases.
Colstrip Thermal Capital - 2017: $9,500,000; 2018: 4,420,000; 3
2019: $10,370,000 4
The Colstrip capital additions include Avista’s pro rata share 5
of ongoing capital expenditures associated with normal outage
activities on Units 3 & 4 at Colstrip. Every two out of three
years, there are planned outages at Colstrip with higher capital
program activities. For non-outage years, the program
activities are reduced. Avista votes its 15 percent share of
Units 3 & 4 and its approximate 10 percent share of common
facilities to approve or disapprove of the planned expenditures
proposed by the plant operator on behalf of all the owners.
Avista does not operate the facility nor does it prepare the
annual capital budget plan. The current operator (Talen)
provides the annual business plan and capital budgets to the
owner group every September. The entire body of capital work
performed in a calendar year at Colstrip includes a variety of
projects that the operator characterizes under the following
categories: Environmental Must Do, Sustenance, Regulatory, and
Reliability Must Do. Avista reviews these individual projects.
Some projects are reclassified to O&M if the work does not
conform to our own capitalization policy. Avista does not have
a “line item veto” capability for individual projects, but can 24
present concerns during the annual September owners’ meeting. 25
Ultimately, the business plan is approved in accordance with
the Ownership and Operation Agreement for Units 3 & 4 that all
six companies with ownership interests are party to.

Clark Fork Settlement Agreement - 2017: $7,934,000; 2018: 30
$6,052,000; 2019: $39,097,000 31
The Clark Fork Protection, Mitigation and Enhancement (PM&E)
measures include funding for the implementation of programs
done through the License issued to Avista Corporation for a
period of 45 years, effective March 1, 2001, to operate and
maintain the Clark Fork Project No. 2058. The License includes
hundreds of specific legal requirements, many of which are
reflected in License Articles 404-430. These Articles derived
from a comprehensive settlement agreement between Avista and 27
other parties, including the States of Idaho and Montana,
various federal agencies, five Native American tribes, and
numerous Non-Governmental Organizations. Avista is required to
develop, in consultation with the Management Committee, a
yearly work plan and report, addressing all PM&E measures of
Kinney, Di 32
Avista Corporation
the License. In addition, implementation of these measures is
intended to address ongoing compliance with Montana and Idaho
Clean Water Act requirements, the Endangered Species Act (fish
passage), and state, federal and tribal water quality standards
as applicable. License articles also describe our operational
requirements for items such as minimum flows, ramping rates and
reservoir levels, as well as dam safety and public safety
requirements. More details are discussed in the hydro
relicensing section of this testimony.
10
Hydro Safety Minor Blanket - 2017: $350,000; 2018: $50,000; 11
2019: $55,000 12
The Hydro Generation Minor Blanket funds periodic capital
purchases and projects to ensure public safety at hydro
facilities both on and off water, for FERC regulatory and
license requirements. The types of projects include barriers
and other safety items like lights, signs and sirens. Section
10(c) of the Federal Power Act authorizes the FERC to establish
regulations requiring owners of hydro projects under its
jurisdiction to operate and properly maintain such projects for
the protection of life, health and property. Title 18, Part
12, Section 42 of the Code of Federal Regulations states that,
"To the satisfaction of, and within a time specified by the
Regional Engineer an applicant, or licensee must install,
operate and maintain any signs, lights, sirens, barriers or
other safety devices that may reasonably be necessary”. Hydro
Public Safety measures includes projects as described in the
FERC publication "Guidelines for Public Safety at Hydropower
Projects" and as documented in Avista's Hydro Public Safety
Plans for each of its hydro facilities.

Kettle Falls Reverse Osmosis System – 2017: $4,510,000 32
The Kettle Falls Generating Station needs a long-term solution
to achieve environmental permit compliance, improve the well
water supply chemistry, and replace an aging demineralization
system. Currently, several short-term solutions have been
employed with increasing and unsustainable operation costs,
which includes the use of chemicals at a cost of $40,000 per
month and risk associated with a deionization system. This
project will design and install a new water treatment system at
Kettle Falls. If this project is not completed, it could result
in plant discharge permit violations. 42
Kinney, Di 33
Avista Corporation
Spokane River License Implementation - 2017: $2,007,000; 2018: 1
$2,786,000; 2019: $533,000 2
This capital spending category covers the ongoing
implementation of PM&E programs related to the FERC License for
the Spokane River including Post Falls, Upper Falls, Monroe
Street, Nine Mile and Long Lake. This includes items
enforceable by FERC, mandatory conditioning agencies, and
through settlement agreements. Additional details concerning
the PM&E measures for the Spokane River license are included in
the hydro relicensing section later in this testimony. This
License defines how Avista shall operate the Spokane River
Project and includes several hundred requirements that must be
met to retain this License. Overall, the License is issued
pursuant to the Federal Power Act. It embodies requirements of
a wide range of other laws, including the Clean Water Act, the
Endangered Species Act, and the National Historic Preservation
Act, among others. These requirements are also expressed
through specific license articles relating to fish, terrestrial
resources, water quality, recreation, education, cultural, and
aesthetic resources at the Project. In addition, the License
incorporates requirements specific to a 50-year settlement
agreement between Avista, the Department of Interior and the
Coeur d'Alene Tribe, which includes specific funding
requirements over the term of the License. Avista entered into
additional two-party settlement agreements with local and state
agencies, and the Spokane Tribe; these agreements also include
funding commitments. The License references our requirements
for land management, dam safety, public safety and monitoring
requirements, which apply for the term of the License. 29
30
IV. HYDRO RELICENSING 31
Q. Would you please provide an update on work being done 32
under the existing FERC operating license for the Company’s 33
Clark Fork River generation projects? 34
A. Yes. Avista received a new 45-year FERC operating
license for its Cabinet Gorge and Noxon Rapids hydroelectric
generating facilities on the Clark Fork River on March 1, 2001.
The Company has continued to work with the 27 Clark Fork
Kinney, Di 34
Avista Corporation
Settlement Agreement signatories to meet the goals, terms, and
conditions of the Protection, Mitigation and Enhancement (PM&E)
measures under the license. The implementation program, in
coordination with the Management Committee, which oversees the
collaborative effort, has resulted in the protection of
approximately 89,500 acres of bull trout, wetlands, uplands,
and riparian habitat. More than 44 individual stream habitat
restoration projects have occurred on 24 different tributaries
within our project area. Avista has collected data on over
25,000 individual Bull Trout within the project area.
The upstream fish passage program, using electrofishing,
trapping and hook-and-line capture efforts, has reestablished
Bull Trout connectivity between Lake Pend Oreille and the Clark
Fork River tributaries upstream of Cabinet Gorge and Noxon
Rapids Dams through the upstream transport of 538 adult Bull
Trout, with over 160 of these radio tagged and their movements
studied. Beginning in 2015, Avista has also annually
implemented experimental upstream transport of 40 to 50 radio
tagged adult Westslope Cutthroat Trout from below Cabinet Gorge
Dam to Cabinet Gorge Reservoir. Avista has worked with the
U.S. Fish and Wildlife Service to develop and test two
experimental fish passage facilities. Avista, in consultation
with key state and federal agencies, is currently developing
Kinney, Di 35
Avista Corporation
designs for a permanent upstream adult fishway for Cabinet Gorge
Dam and discussing the timing of, and need for, a fishway at
Noxon Rapids Dam.
In 2015, the Cabinet Gorge Fishway Fish Handling and
Holding Facility was completed. A permanent tributary trap on
Graves Creek (an important bull trout spawning tributary) was
constructed in 2012 and testing began in 2013. The permanent
trap is being iteratively optimized and evaluated to determine
if additional permanent tributary traps are warranted.
Concurrently, the physical attributes at a site on the East
Fork Bull River are being evaluated to determine if this would
be a feasible location for a future permanent trap.
Recreation facility improvements have been made to over 28
sites along the reservoirs. Avista also owns and manages over
100 miles of shoreline that includes 3,700 acres of property to
meet FERC required natural resource goals, while allowing for
public use of these lands where appropriate.
Finally, tribal members continue to monitor known cultural
and historic resources located within the project boundary to
ensure that these sites are appropriately protected. They are
also working to develop interpretive sites within the project.
Kinney, Di 36
Avista Corporation
Q. Would you please provide an update on the current 1
status of managing total dissolved gas issues at Cabinet Gorge 2
dam? 3
A. Yes. How best to deal with total dissolved gas (TDG)
levels occurring during spill periods at Cabinet Gorge Dam was
unresolved when the current Clark Fork license was received.
The license provided time to study the actual biological impacts
of dissolved gas and to subsequently develop a dissolved gas
mitigation plan. Stakeholders, through the Management
Committee, ultimately concluded that dissolved gas levels
should be mitigated, in accordance with federal and state laws.
A plan to reduce dissolved gas levels was developed with all
stakeholders, including the Idaho Department of Environmental
Quality. The original plan called for the modification of two
existing diversion tunnels, which could redirect stream flows
exceeding turbine capacity away from the spillway.
The 2006 Preliminary Design Development Report for the
Cabinet Gorge Bypass Tunnels Project indicated that the
preferred tunnel configuration did not meet the performance,
cost and schedule criteria established in the approved Gas
Supersaturation Control Plan (GSCP). This led the Gas
Supersaturation Subcommittee to determine that the Cabinet
Gorge Bypass Tunnels Project was not a viable alternative to
Kinney, Di 37
Avista Corporation
meet the GSCP. The subcommittee then developed an addendum to
the original GSCP to evaluate alternative approaches to the
Tunnel Project.
In September 2009, the Management Committee (MC) agreed
with the proposed addendum, which replaces the Tunnel Project
with a series of smaller TDG reduction efforts, combined with
mitigation efforts during the time design and construction of
abatement solutions take place.
FERC approved the GSCP addendum in February 2010, and in
April 2010 the Gas Supersaturation Subcommittee (a subcommittee
of the MC) chose five TDG abatement alternatives for feasibility
studies. Feasibility studies and preliminary design were
completed on two of the alternatives in 2012. Final design,
construction, and testing of the spillway crest modification
prototype was completed in 2013. Test results indicated over
all TDG performance was positive, however, additional
modifications were required to address cavitation issues.
Modification of the spillway crest prototype and retesting were
completed in 2014. Based on this design, construction of two
additional spillway crest modifications were initiated in 2015
and completed in 2016. The test results from these two spillway
crests were also favorable and modification of two more spillway
crests is planned for 2017. Pending results from these
Kinney, Di 38
Avista Corporation
additional modifications, it is anticipated that up to three
additional spillway crests will be modified by 2018.
Q. Would you please give a brief update on the status of 3
the work being done under the Spokane River Hydroelectric 4
Project’s license? 5
A. Yes. The Company received a new 50-year license for
the Spokane River Project on June 18, 2009. The License
incorporated key agreements with the U.S. Department of
Interior (Interior) and other key parties in Idaho and
Washington. Implementation of the new license began
immediately, with the development of over 40 work plans
prepared, reviewed and approved, as required, by the Idaho
Department of Environmental Quality, Washington Department of
Ecology, Interior, and the FERC. The work plans pertain not
only to license requirements, but also to meeting requirements
under Clean Water Act 401 certifications by Idaho and Washington
and other mandatory conditions issued by Interior.
Since 2011, Avista has implemented wetland, water quality,
fisheries, cultural, recreation, erosion, aquatic weed
management, aesthetic, bald eagle, operational and related
conditions across all five hydro developments under the
Protection Mitigation and Enhancement (PM&E) measures.
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Avista Corporation
Avista worked with the Coeur d’Alene Tribe (Tribe) to 1
purchase 656 acres of wetland mitigation properties in 2011 and
2012 along Upper Hangman Creek. These properties were purchased
utilizing the Coeur d’Alene Reservation Trust Resources 4
Restoration Fund that Avista established in 2009. Avista, in
cooperation with the Tribe, has developed and implemented
wetland restoration plans for 508 of the required 1,424
replacement acres of wetland and riparian habitat along Upper
Hangman Creek. Avista and the Tribe continue implementing the
wetland plan by assessing and pursuing additional lands,
primarily on the Coeur d’Alene Reservation, for acquisition and 11
wetland and riparian habitat restoration.
In Idaho, Avista partnered with the Idaho Department of
Fish and Game (IDFG) to complete a wetland restoration project
on the 124 acre Shadowy St. Joe Wetland Complex. Avista and
IDFG continue to evaluate additional wetland protection and/or
restoration projects in Idaho. Avista purchased the 109 acre
Sacheen Springs Wetland Complex located along the Little
Spokane River in Washington. The Company developed a management
plan for the wetland complex, which will be protected in
perpetuity under a conservation easement.
Avista also implements aquatic weed management plans in
Coeur d’Alene Lake in Idaho, and Nine Mile Reservoir and Lake 23
Kinney, Di 40
Avista Corporation
Spokane in Washington. The primary components of these plans
include monitoring, managing, and educational outreach efforts
to assist in reducing or controlling invasive and problematic
weeds within the Project area.
Avista will continue to develop and implement local,
state, and federally required work plans related to fisheries
and water quality to fulfill License conditions. One on-going
fishery study includes assessing redband trout spawning areas
in the Spokane River between Monroe Street Dam and the Nine
Mile Reservoir, (over a 10-year period) to determine if spring
water releases from the Company’s Post Falls Dam should be 11
changed to benefit the spawning areas.
The Company completed the Long Lake Dam Spillway
Modification Project, following the model and design phases, to
reduce total dissolved gas (TDG) in the river downstream of the
dam. The cost to construct the spillway deflectors was
approximately $12.0 million. Avista will establish a spillgate
protocol to determine the most effective operational scenario
to reduce TDG and will monitor TDG downstream of the dam in
2017 and 2018 to determine the effectiveness in reducing TDG.
Avista completed the proposed dissolved oxygen (DO)
improvement measure in the Long Lake Dam tailrace and continues
to monitor its effectiveness in addressing low DO in the river
Kinney, Di 41
Avista Corporation
below the dam. The monitoring efforts will be ongoing in
nature, as the Company has to balance improved DO conditions
with increases in TDG, which can be detrimental to downstream
fish. Avista is also continuing to evaluate potential measures
to improve DO in Lake Spokane, the reservoir created by the
Long Lake Dam. Cost estimates to address DO in Lake Spokane
are between $2.5 and $8.0 million. These estimates will be
refined as the evaluations and studies are completed. The
Company conducted a pilot test to remove carp, which cause water
quality problems associated with DO throughout their life
cycle, from the lake in early 2017. The pilot project was
successful, allowing the Company to move forward with a more
extensive carp removal effort in the Spring of 2017. Avista is
also working closely with the Washington Department of Fish and
Wildlife and the Washington Department of Ecology on a multi-
year habitat assessment for salmonoids for Lake Spokane.
Avista partnered with the Idaho Department of
Environmental Quality to complete nutrient monitoring in the
northern portion of Coeur d’Alene Lake and in the Spokane River 19
downstream of the Lake’s outlet to meet the water quality
monitoring requirements under the license. It also partnered
with the Tribe to complete nutrient monitoring in the southern
portion of Coeur d’Alene Lake and the lower St. Joe River. The 23
Kinney, Di 42
Avista Corporation
Company further conducted nutrient monitoring in Lake Spokane
as part of its Lake Spokane Dissolved Oxygen Water Quality
Attainment Plan.
Avista and the Tribe continue to implement the Cultural
Resource Management Plan on the Reservation, whereas Avista
implements Historic Property Management Plans (off the
Reservation) on Project lands in both Idaho and Washington.
The primary measures include education and outreach, site
monitoring, looting patrol, curation of materials collected,
and reporting.
The Company continues to work with the various local,
state, and federal agencies to manage the required recreation
projects in Idaho and Washington. Last year, the Company
completed the Post Falls South Channel Overlook and ADA access
project, when it restored the area that was disturbed for the
Post Falls South Channel Dam Gate Replacement Project in Idaho,
and started the planning process for the Lake Spokane Campground
expansion project, a cooperative effort with the Washington
State Parks and Recreation Commission and the Washington
Department of Natural Resources. Avista also constructed a new
trailhead and trail to the Spokane River during the restoration
effort for the Long Lake Dam Spillway Modification Project.
Kinney, Di 43
Avista Corporation
Q. Does this conclude your pre-filed direct testimony? 1
A. Yes it does. 2