20160526Kinney 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-16-03
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) DIRECT TESTIMONY
TO ELECTRIC CUSTOMERS IN THE ) OF
STATE OF IDAHO ) SCOTT J. KINNEY
)

FOR AVISTA CORPORATION

(ELECTRIC)

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 update on the Company’s hedging 8
practices. I will address hydroelectric and thermal project
upgrades, followed by an update on recent developments
regarding hydro licensing.
As explained by Company witness Ms. Andrews, the Company
is basing its electric revenue increase requested in this case
on its electric Pro Forma Study including Idaho’s share of 14
generation capital projects I have described later in my
testimony.
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 25
Kinney, Di 3
Avista Corporation
Q. Are you sponsoring any exhibits? 1
A. Yes. Exhibit No. 4, Schedule 1 includes Avista’s 2
2015 Electric Integrated Resource Plan and Appendices, and
Exhibit No. 4, Confidential Schedule 2C includes Avista’s 4
Energy Resources Risk Policy.

II. RESOURCE PLANNING AND POWER OPERATIONS 7
Q. Would you please provide an overview of Avista’s 8
owned-generating resources? 9
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: 18
Kinney, Di 4
Avista Corporation
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
Table No. 1: Avista-Owned Hydroelectric Generation 1

9
Table No. 2: Avista-Owned Thermal Generation 10
11
12
13
14
15
16
17
18
Q. Would you please provide a brief overview of Avista’s 19
major generation contracts? 20
A. Yes. Avista’s contracted-for generation resource
portfolio consists of Mid-Columbia hydroelectric, PURPA, a

Project Name Fuel Type Start
Date
Winter
Maximum
Capacity
(MW)
Sumer
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

Kinney, Di 5
Avista Corporation
tolling agreement for a natural gas-fired combined cycle
generator, and a contract with a wind generation facility.
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. 4 provides details about other resource
contracts. Avista has a long-term power purchase agreement
(PPA) in place through 2026 entitling the Company to dispatch,
purchase fuel for, and receive the power output from, the
Lancaster 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 the Palouse Wind, LLC wind
generation project that began commercial operation in December
2012. 18
Kinney, Di 6
Avista Corporation
Table No. 3: Mid-Columbia Hydroelectric Capacity and Energy 1
Contracts 2
3
1 4
5
6
7
8
Table No. 4: Other Contractual Rights and Obligations

2

Q. Would you please provide a summary of Avista's power 18
supply operations and acquisition of new resources? 19

1 Under the Columbia River Treaty signed in 1961 and the Pacific Northwest
Coordination Agreement (PCNA) signed in 1964, Canada receives return energy
(Canadian Entitlement) related to storage water in upstream reservoirs for
coordinated flood control and power generation optimization.
2 Energy America, LLC sale is 50 aMW through 2018 and then decreases to
20 aMW in 2019.
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 1/2016 12/2020 56.3 35.9
Chelan PUD – Rock Island 5.0 1/2016 12/2020 25 18.4
Douglas PUD - Wells 3.3 2/1965 8/2018 24 17.4
Canadian Entitlement1 -3
2015 Total Net Contracted Capacity and Energy 180.3 106.9
1

Contract Type Fuel
Source
End
Date
Winter
Capacity
(MW)
Summer
Capacity
(MW)
Annual
Energy
(aMW)
Energy America,
LLC2
Sale Various 12/2018 -50 -50 -50
PGE Capacity
Exchange
Exchange System 12/2016 -150 -150 0
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 214.8 91.8 279
1
Kinney, Di 7
Avista Corporation
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
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. 15
A. Avista’s 2015 IRP shows forecasted annual energy
deficits beginning in 2026, and sustained annual capacity
deficits beginning in 2021.3 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 20
2015 IRP load and resource projection.

3 The Company has a 150 MW capacity exchange agreement with Portland General
Electric that ends in December 2016 and Avista has short-term capacity
deficits in 2016. Sustained annual capacity deficits begin in 2021.
Kinney, Di 8
Avista Corporation
Q. How does Avista plan to meet future energy and 1
capacity needs? 2
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 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 Commission acknowledged the 2015
Electric IRP in Case No. AVU-E-15-08 on February 4, 2016 in
Order No. 33463. The IRP represents the preferred plan at a
point in time; however, Avista continues evaluating different
resource options to meet future load obligations. The Company
will hold a Technical Advisory Committee meeting in the middle
of 2016 to start the 2017 IRP effort.
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.
23
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 Exhibit No. 4, Confidential
Schedule 2C, 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
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 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
estimated average load for the forward period. Or it may be a
Kinney, Di 11
Avista Corporation
long position, for which the Company 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 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
regards to generation capital projects. 16
A. The Company started with the historical test period
ending December 31, 2015 and included pro forma adjustments for
planned capital investment in 2016 and 2017. For further
discussion regarding the Pro Forma adjustments and the Capital
Planning Group, please see Company witness Ms. Schuh’s 21
testimony.
Kinney, Di 12
Avista Corporation
Q. Please describe the capital planning process that the 1
Generation area goes through before generation capital projects 2
are submitted to the Capital Planning Group. 3
A. Currently, the Generation Production Substation
Support (GPSS) capital projects are proposed by the Generation
Engineering group or by the Plant Operations groups. These
projects are then included into the long range (10 year) plan
and prioritized by the Chief Generation engineer with input
from GPSS leadership including the Department Director, Plant
and Central Maintenance Managers, and Avista’s Asset Management 10
group. A Basis of Design document is then created for these
projects and a Business Case developed. As these projects come
into the 5-year planning horizon, more detail on Scope,
Schedule, and Budget are added to the plan. If the project is
still judged viable and prudent by GPSS leadership it is sent
to the Capital Planning Group for funding. After a project is
approved, and during the life of a project, steering committees
are established for executive management check-ins and
approvals of decisions as they arise throughout the project.
The Company has also historically performed specific
assessments on groups of assets. For example, in 2011 the
Company performed The Spokane River Assessment (SRA) to assess
the hydro capacity upgrade potential for all of the Spokane
Kinney, Di 13
Avista Corporation
River Project hydroelectric plants. The SRA was guided by a
Policy Team consisting of the Vice President of Energy Resources
and the department directors and managers from Power Supply,
Resource Planning, GPSS, Environmental Affairs, Substation,
Relay and Protection, Transmission Planning, and Finance. Task
groups were also formed to provide detailed oversight of
specific portions of the assessment, such as Finance,
Environmental, and Engineering. The final recommendation of
the SRA in 2012 was to rehabilitate the existing plant instead
of building a new powerhouse at Nine Mile. This recommendation
led to the formation of the Nine Mile Rehab Program (NMRP)
Business Case to address the rehabilitation of the powerhouse
and associated facilities. The NMRP Business Case is governed
by steering committees consisting of director level management
teams providing input and authorization for changes to scope,
schedule, and cost. The steering committees provide a level of
governance and oversight to support the NMRP Business Case and,
when necessary, provide recommendations to the Capital Planning
Group (CPG) for adjustments in the NMRP program level cost and
annual budget.
Q. What is driving the capital needs in the Company’s 21
generation area? 22
Kinney, Di 14
Avista Corporation
A. The main drivers for the generation-related capital
investment include updating and replacing equipment in many of
the Company’s hydro facilities that are over 100-years old in
order to reduce equipment-failure forced outages. In addition,
regular maintenance for reliability is required to keep the
generating plants operational. Furthermore, there are projects
to address plant safety and electrical capacity issues.
Finally, there are capital requirements resulting from our
settlement agreements for the implementation of Protection,
Mitigation and Enhancement (PM&E) programs related to the FERC
Licenses for the Spokane River and Clark Fork River.
Q. Would you please provide a brief description of the 12
generation-related capital projects that are included in the 13
Company’s Pro Forma Study for 2016 through 2017? 14
A. Yes. As shown in Table No. 6 below, for 2016 and
2017 the Company has included generation projects totaling, on
a system basis, $165.4 million and $75.8 million, respectively.
Details about these generation-related capital projects are
discussed below.
Kinney, Di 15
Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14

The following planned generation capital projects are included 16
in the Company’s Pro Forma Study. See Ms. Schuh’s Exhibit No. 17
10, Schedule 4 for business cases supporting these projects. 18
19
Colstrip Capital Additions - 2016: $12,292,000; 2017: 20
$12,432,000 21
This program includes 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. Planned capital investments
include the overhaul of Unit 4, NOx emission reduction
equipment, and replacement of gas deflection nose arches for
Units 3 & 4, among other investments. Avista votes its 15%
share of Units 3 & 4 and its approximate 10% share of common
Business Case Name
2016
$ (000's)
2017
$ (000's)
Colstrip Thermal Capital $ 12,292 $ 12,432
Cabinet Gorge Unit 1 Refurbishment 14,702
Post Falls South Channel Replacement 15,648
Nine Mile Rehab 73,193 3,814
Little Falls Plant Upgrade 23,833 11,470
Spokane River License Implementation $ 1,007 $ 17,764
Kettle Falls Stator Rewind 7,930
Peaking Generation 500 500
Cabinet Gorge Automation Replacement 2,342
Cabinet Gorge HED - Gantry Crane Replacement 3,500
Kettle Falls CT Control Upgrade 667
Kettle Falls Reverse Osmosis System 4,750
Generation DC Supplied System Upgrade 700 1,033
Coyote Springs Long Term Service Agreement 1,980 1,980
Noxon Station Service 1,477 1,172
Base Load Hydro 1,149 1,149
Regulating Hydro 5,786 3,533
Base Load Thermal Plant 2,200 2,200
Clark Fork Settlement Agreement 6,093 4,226
Hydro Safety Minor Blanket 75 80
Total Planned Generation/Production Capital Projects $ 165,387 $ 75,791
TABLE NO. 6
Generation / Production Capital Projects (System)
Kinney, Di 16
Avista Corporation
facilities to approve or disapprove of the planned expenditures
proposed by Talen Energy on behalf of all the owners.
3
Cabinet Gorge Unit 1 Refurbishment – 2016: $14,702,000 4
This is the capital portion of a major overhaul project
associated with Cabinet Gorge Unit #1. Unit No. 1 at Cabinet
Gorge is designed with variable pitch blades, which provide for
flexible operation with variable water flows (e.g., minimum
flows through the project), the remaining three units at Cabinet
Gorge are fixed-blade units. The runner hub had significant
mechanical issues and needed to be replaced to support minimum
flow for fish habitat and allow for frequent cycling associated
with the integration of intermittent renewable resources. The
present automatic voltage regulator (AVR) provides a relatively
slow response due to its hybrid design and has no limiters for
generator protection. A new AVR system will provide faster
response and add limiters. New machine monitoring will provide
better analysis of machine condition for this important unit
that supports minimum flow operation.

The initial completion date for this project was May of 2015.
This project is now estimated to be on-line in May of 2016.
The Company encountered several issues during construction of
Unit #1 causing this delay, such as issues with the supply
schedule from the manufacturer and construction quality issues
with the turbine resulting in delivery delays and additional
site work, and an unforeseen governor upgrade required to ensure
reliable operation of the new turbine.
29
Post Falls South Channel Replacement - 2016: $15,648,000 30
This project involved the maintenance of the south channel gates
to comply with FERC Dam Safety directives. The South Channel
Dam was originally constructed in 1906. A pre-construction
underwater investigation revealed that the condition of the
concrete structure was very poor and would not handle the
planned work. This resulted in an evaluation of different
design options to address the deteriorated concrete. The final
project removed most of the existing concrete structure and
replaced it with new concrete, new spillway gates, and new hoist
systems to automate gate operation.

The initial estimated completion date for this project was May
of 2015. This was based on our observation of the dam
condition, dive inspections, and estimates of the concrete
suitability for rehabilitation. Once construction started, the
Company encountered several unforeseen issues directly related
Kinney, Di 17
Avista Corporation
to working in areas that are normally submerged and part of a
100 year old structure. For example, during installation of
the coffer dam, the north bank was found to have a severe
undercut that required significant efforts to secure before any
reconstruction work could begin. Once removal of the existing
concrete began, the poor condition of the concrete required
further extraction to provide an adequate foundation for the
new concrete. This significantly impacted the scope of project,
requiring additional design, permits, and construction work.
These delays resulted in concrete work being performed later in
the year, further slowing construction as winter pouring is a
slower process. This project went into service in February of
2016.

Nine Mile Redevelopment – 2016: $73,193,360; 2017: 3,814,000 15
This capital program is necessary to rehabilitate and modernize
the four unit Nine Mile HED. The program includes projects to
replace the existing three MW Units 1 and 2, which are more
than 100 years old and worn out, with two new eight MW
generators/turbines. The new units will add 1.4 aMW of energy
beyond the original configuration. In addition to these
capacity upgrades, the Nine Mile facility has and will receive
upgrades to the following during the years listed:
 hydraulic governors (Units 1-2 in 2016 and Units 3-4 in
2019);
 static excitation system (Units 1-2 in 2016 and Units 3-4
in 2019);
 switchgear (Units 1-2 in 2016 and Units 3-4 in 2019);
 station service (interim station service completed in 2013
and permanent replacement in 2016);
 control and protection packages (Units 1-2 in 2016 and
Units 3-4 in 2019);
 ventilation upgrades (2016);
 rehabilitation of intake gates (Units 1-2 completed in
2015; Units 3-4 in 2017) and sediment bypass system (2016-
2018);
 a new warehouse completed in 2015;
 new tail race gate system completed in 2015;
 new grounding and communications completed in 2013 and
2015 respectively;
 a barge landing and crane pad completed in 2015;
Kinney, Di 18
Avista Corporation
 a cottage removed in 2013 and another remodeled in 2015;
 a new panel room completed in 2013;
 Units 3 and 4 will be overhauled and modernized (2018-
2019);
 the powerhouse will be restored (2017);
 new access gates and controls added in 2015; and
 other improvements will be made throughout the
rehabilitation and modernization of the project.
The Nine Mile rehabilitation project, specifically Units 1 and
2, have incurred some delays from the original estimated
completion date of December 2015. Limited structural support
for the tailrace gates significantly impacted plant dewatering.
Nine additional months were required to design and fabricate
additional support. This delay impacted the timing for
powerhouse demolition, concrete placement, and placement of new
equipment. Electrical completion also took nine additional
months for design, fabrication and installation based on the
need for specialized support structures for the new electric
cable tray system. The completion date for this project is now
expected in July of 2016.
21
Little Falls Powerhouse Redevelopment – 2016: $23,833,000; 22
2017: $11,470,000 23
The Little Falls equipment ranges 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 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 unit
protection system, and replacing and modernizing the station
service. Without this focused replacement effort, forced
outages and emergency repairs would have continued to increase,
reducing the reliability of the plant. At some point, personnel
would have been placed back in the plant adding to operating
costs. The Asset Management group analyzed the age and
condition of all of the equipment in the plant, all of the
equipment was 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.
Kinney, Di 19
Avista Corporation
This replacement effort will allow Little Falls to be operated
reliably and efficiently.

The Little Falls Unit 3 project encountered some delays from
the initial estimated completion date of April of 2015. The
Company encountered several issues during construction of this
project. The turbine runner was supplied out of specification
and was returned to the manufacturer. The manufacturer supplied
another turbine after six additional months of manufacturing.
The project recouped some costs by exercising liquidated
damages but could not recoup the delay in the delivery schedule.
This major delay, along with various smaller delays, caused the
project completion to be delayed until late December 2015. This
project was not placed in service until February of 2016 due to
Avista generation crews helping with the Windstorm and delays
during checkout of the new control system. 16
17
Spokane River Implementation PM&E – 2016: $1,007,000; 2017: 18
$17,764,000 19
This capital spending category covers the implementation of
Protection, Mitigation and Enhancement (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 we must meet 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 (or Protection, Mitigation and Enhancement Measures),
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,
Kinney, Di 20
Avista Corporation
public safety and monitoring requirements, which apply for the
term of the License.

Kettle Falls Stator Rewind – 2017: $7,930,000 4
The Kettle Falls generator is 32 years old and is at the end of
its expected life. The stator can be rewound on its scheduled
basis during the spring outage of 2017 instead of running it
until it fails. This project consists of monitoring the
existing machine, developing 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,
long term interruption of fuel supply, potential collateral
damage to the core and hydrogen cooling, and poses a significant
safety hazard.
17
Peaking Generation – 2016: $500,000; 2017: $500,000 18
This program is focused on the capital maintenance expenditures
required to keep the natural gas-fired peaking units (Boulder
Park, Rathdrum CT, and Northeast CT) operating at or above their
current performance levels. The program focuses on maximizing
the ability of these units to start and run efficiently when
requested (starting reliability). The reliability of all of
these assets will decline over time, resulting in failure to
start, non-compliant emissions, or inefficient operation. 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.
31
Cabinet Gorge Hydroelectric Dam Automation Replacement – 2017: 32
$2,342,000 33
This project replaces the unit and station service control
equipment with a system compatible with Avista’s current 35
standards. The technology currently used at Cabinet Gorge is
an older vintage and is marginally supported. The existing
control system is obsolete and there are a very limited number
of spares, so some replacement parts for the system can only be
found through the secondary and salvage markets. In addition,
the current system does not provide enough inputs and outputs
to implement the standard unit control and monitoring schemes.
Therefore unit monitoring and control is inconsistent with
current industry practice. The scope of work also includes
replacement of the governors, voltage regulators, and
protective relays.
Kinney, Di 21
Avista Corporation
Replace Cabinet Gorge Gantry Crane – 2017: $3,500,000 1
The gantry crane at Cabinet Gorge is original equipment and is
now more than 60 years old. This is a critical asset needed to
service the powerhouse. The crane has experienced problems
which impacted the Cabinet Gorge Unit 1 project schedule. The
controls are antiquated and have malfunctioned. The cranes
operating integrity, and the state of the controls, make
replacing the crane with a modern and fully functioning crane
a necessity.
10
Kettle Falls CT Control Upgrade – 2017: $666,607 11
This project will replace the Solar Combustion Turbine HMI
software and hardware, upgrade PLC controls platform, and Fire
Protection system at Avista's Kettle Falls Generating Station.
The current controls are outdated, with spare parts and software
support no longer available. Failure to fund this project will
result in the system continuing to deteriorate, increasing the
risk of forced outages.
19
Kettle Falls Generating Station Reverse Osmosis System – 2016: 20
$4,750,000 21
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 and potential third party
intervention.
33
Generation DC Supplied System Upgrade – 2016: $700,000; 2017: 34
$1,033,000 35
This project will update existing plant DC systems to meet
Avista's current Generation Plant DC System Standard. This
program will make compliance with NERC PRC-005 Reliability
Standard more 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 will replace any legacy Uninterrupted
Power Supply (UPS) systems with an inverter system and address
auxiliary equipment based on its life cycle. The Company is
Kinney, Di 22
Avista Corporation
currently addressing Battery Bank replacement based on the
manufacturers recommended life cycle. This life cycle is based
on ideal operating conditions. Replacing components as they
fail adds significant risk of unpredictable full system
failures leading to forced plant outages.
6
Coyote Springs 2 LTSA Capital Addition – 2016: $1,980,000; 2017: 7
$1,980,000 8
This program covers the capital accruals required to execute
our Long Term Service Agreement (LTSA) with General Electric
for Coyote Springs Unit 2. The LTSA contract is with General
Electric to maintain the gas turbine at Coyote Springs 2 and
provide scheduled part exchanges based on unit run hours. This
program will have fluctuations to account for the variable
operating hours and operating conditions that feed into the
LTSA formula. This contract with GE provides the necessary
services, parts, and labor to maintain the Frame 7EA gas
turbine, which is the major component of the Coyote Springs
Unit 2 CCCT.
20
Noxon Station Service – 2016: $1,477,000; 2017: $1,172,000 21
An engineering study has shown that the station service
equipment at Noxon is over-rated and may not interrupt a close
in fault should one occur. In addition, as the plant load has
shifted, the simultaneous operation of all five units may be
limited if one of the station service transformers fails. This
project replaces station service equipment and cables. The
replacements include Station Service transformers A&B, 2000A
Bus Ducts from Station Service transformers to Power Centers,
Tie Bus and Power Centers, Motor Control Centers 1 through 4,
1,000 kVA Emergency Generator, Motor Control Center 4 PLC, and
the Emergency Load Center. If no action is taken, there is a
risk of catastrophic switch gear failure and generator unit
forced outage for up to a year. Additionally, forced generation
limits under certain operational scenarios could be necessary
if these replacements are not made.

Base Load Hydro – 2016: $1,149,000; 2017: $1,149,000 38
This program covers the 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 (this assumes some
degradation of performance over time.) The program will focus
on ways to maintain compliance and reduce overall O&M expenses
while maintaining a reasonable unit availability. This program
also includes FERC and NERC mandated compliance requirements.
Kinney, Di 23
Avista Corporation
These compliance projects are managed as part of the overall
Base Load Hydro program and are not separated out as individual
items. The historical availability for the base load hydro
plants has been declining over the past ten years due to
deteriorating equipment and a need to replace aging equipment
and systems. The age of these plants range from 90 to 105 years
old.
8
Regulating Hydro – 2016: $5,786,000; 2017: $3,533,000 9
This program covers the capital maintenance expenditures
required to keep the Long Lake, Little Falls, Noxon 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 very important as these facilities
age and are ramped more frequently to meet load fluctuations
associated with renewable energy integration and changing load
dynamics. Additionally, efforts will be made within this
program to improve ancillary service capabilities from these
generating assets. This includes installing blow down systems
to allow for spinning reserves, moving load following demands
to all of these plants, voltage regulating needs, and frequency
response. The program also includes some elements of hydro
license compliance related to plant operations and equipment.
27
Base Load Thermal Plant – 2016: $2,200,000; 2017: $2,200,000 28
This program is 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 that forced outage rates and
forced de-ratings of these facilities will decrease to a level
one standard deviation less than the current average. As these
plants continue to age and they 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 and exposure to
the acquisition of replacement energy and capacity from the
market. Having a mature asset management program for these
thermal facilities will help minimize plant degradation and
market exposure. The program also includes initiatives
Kinney, Di 24
Avista Corporation
associated with regulatory mandates for air emissions and
monitoring, and projects to meet NERC compliance requirements.

Clark Fork Settlement Agreement – 2016: $6,093,000; 2017: 4
$4,226,000
These capital costs are required for the facilitation of the
Clark Fork PM&E measures. The implementation of programs is
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
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.
27
Hydro Safety Minor Blanket – 2016: $75,000; 2017: $80,000 28
This item funds periodic capital purchases and projects to
ensure public safety at hydro facilities, on and off water, in
the context of FERC regulatory and license requirements.
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.
45
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Avista Corporation
IV. HYDRO RELICENSING 1
Q. Would you please provide an update on work being done 2
under the existing FERC operating license for the Company’s 3
Clark Fork River generation projects? 4
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
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 89,000 acres of bull trout, wetlands, uplands,
and riparian habitat. More than 41 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
Kinney, Di 26
Avista Corporation
Trout, with over 160 of these radio tagged and their movements
studied. 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 designs for a permanent
upstream adult fishway for Cabinet Gorge and discussing the
timing of, and need for, a fishway at Noxon Rapids.
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 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 3,500 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
Kinney, Di 27
Avista Corporation
ensure that these sites are appropriately protected. They are
also working to develop interpretive sites within the project.
Q. Would you please provide an update on the current 3
status of managing total dissolved gas issues at Cabinet Gorge 4
dam? 5
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
Kinney, Di 28
Avista Corporation
Supersaturation Subcommittee to determine that the Cabinet
Gorge Bypass Tunnels Project was not a viable alternative to
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 completed in 2016.
Kinney, Di 29
Avista Corporation
It is anticipated that up to five 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 new 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 both 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 FERC. The work plans pertain not only
to license requirements, but also to meeting requirements under
Clean Water Act 401 certifications by both 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, operational and related conditions
across all five hydro developments under the Protection
Mitigation and Enhancement (PM&E) measures. Six hundred and
fifty six acres of wetland mitigation properties were acquired
Kinney, Di 30
Avista Corporation
in 2011 and 2012 along Upper Hangman Creek in Idaho for the
Coeur d’Alene Tribe (Tribe) through the Coeur d’Alene 2
Reservation Trust Resources Restoration Fund that Avista
established in 2009. The Company has since developed and
implemented wetland restoration plans for 508 of the required
1,424 replacement acres of wetland and riparian habitat along
Upper Hangman Creek in cooperation with the Tribe. Avista and
the Tribe continue implementing the plans by assessing and
pursuing additional lands, primarily on the Coeur d’Alene 9
Reservation, for acquisition and wetland and riparian habitat
restoration.
The Company implemented its management plan for the 109
acre Sacheen Springs Wetland Complex located along the Little
Spokane River and will monitor its restoration efforts, as
required for the term of the license.
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 study includes assessing redband trout
spawning areas in the Spokane River downstream of the Monroe
Street Dam, (over a 10-year period) to determine if spring water
releases from the Company’s Post Falls Dam should be changed to 22
benefit the spawning areas. Another such study included one
Kinney, Di 31
Avista Corporation
specific to total dissolved gas (TDG) downstream of Long Lake
Dam. Avista modeled several different types of spillway
modifications between 2011 and 2013 and completed the design
for the desired deflector configurations in 2014. The Company
is planning to complete the spillway modification project in
2016-2017. Cost estimates to construct the TDG spillway
deflectors are approximately $11.0 million.
The Company completed the proposed dissolved oxygen (DO)
measure in the tailrace below Long Lake Dam and continues to
monitor its effectiveness in addressing low DO in the river
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.
To meet the Company’s water quality monitoring 19
requirements under the license, it partnered with the Idaho
Department of Environmental Quality to complete nutrient
monitoring in the northern portion of Coeur d’Alene Lake and in 22
the Spokane River downstream of the Lake’s natural outlet. It
Kinney, Di 32
Avista Corporation
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 Company also 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 site monitoring, looting patrol,
education and outreach, 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 Trailer Park Wave River Access in Idaho, and ten
boat-in-only campsites and a carry-in-only boat launch in
Washington.
Q. Does this conclude your pre-filed direct testimony? 19
A. Yes it does.