20150601Kinney 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-15-05
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)

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 4
the Director of Power Supply at Avista Corporation, 5
located at 1411 East Mission Avenue, Spokane, Washington. 6
Q. Would you briefly describe your educational and 7
professional background? 8
A. Yes. I graduated from Gonzaga University in 9
1991 with a B.S. in Electrical Engineering and I am a 10
licensed Professional Engineer in the State of Washington. 11
I joined the Company in 1999 after spending eight years 12
with the Bonneville Power Administration. I have held 13
several different positions at Avista in the Transmission 14
Department, beginning as a Senior Transmission Planning 15
Engineer. In 2002, I moved to the System Operations 16
Department as a Supervisor and Support Engineer. In 2004, 17
I was appointed as the Chief Engineer, System Operations 18
and as the Director of Transmission Operations in June 19
2008. I became the Director of Power Supply in January 20
2013, where my primary responsibilities involve management 21
and oversight of short- and long-term planning and 22
acquisition of power resources. 23
Kinney, Di Page 1 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 4
includes summaries of the Company’s generation resources, 5
the current and future load and resource position, and 6
future resource plans. As part of an overview of the 7
Company’s risk management policy, I will provide an update 8
on the Company’s hedging practices. I will address 9
hydroelectric and thermal project upgrades, followed by an 10
update on recent developments regarding hydro licensing. 11
Company witness Ms. Andrews incorporated Idaho’s 12
share of the capital additions (2015 through 2017) 13
described in my testimony. 14
A table of contents for my testimony is as follows: 15
Description Page 16
I. Introduction 1 17
II. Resource Planning and Power Operations 3 18
III. Generation Capital Projects 13 19
IV. Hydro Relicensing 20 20
21
Q. Are you sponsoring any Exhibits? 22
A. Yes. I am sponsoring Exhibit 4, Schedules 1 23
through 3. Schedule 1 includes Avista’s 2013 Electric 24
Integrated Resource Plan and Appendices, and Schedule 2 25
Kinney, Di Page 2 Avista Corporation
provides the 2013 IRP forecast of the Company’s load and 1
resource positions from 2014 through 2033. Confidential 2
Schedule 3C includes Avista’s Energy Resources Risk 3
Policy. 4
5
II. RESOURCE PLANNING AND POWER OPERATIONS 6
Q. Would you please provide a brief overview of 7
Avista’s owned-generating resources? 8
A. Yes. Avista’s owned generating resource 9
portfolio includes hydroelectric generation projects, 10
base-load coal and base-load natural gas-fired thermal 11
generation facilities, waste wood-fired generation, and 12
natural gas-fired peaking generation. Avista-owned 13
generation facilities have a total capability of 1,851 MW, 14
which includes 58% hydroelectric and 42% thermal 15
resources. 16
Illustration Nos. 1 and 2 below summarize the present 17
net capability of Avista’s hydroelectric and thermal 18
generation resources: 19
Kinney, Di Page 3 Avista Corporation
Illustration No. 1: Avista-Owned Hydroelectric Generation 1
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9
Illustration No. 2: Avista-Owned Thermal Generation 10
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Q. Would you please provide a brief overview of 19
Avista’s major power supply contracts? 20
A. Yes. Avista’s contracted-for generation 21
resource portfolio consists of Mid-Columbia hydroelectric, 22
PURPA, a tolling agreement for a natural gas-fired 23

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 178.0 126.0 166.5
Northeast Gas 1978 68.0 42.0 61.2
Boulder Park Gas 2002 24.6 24.6 24.6
Coyote Springs 2 Gas 2003 312.0 251.0 290.0
Kettle Falls Wood 1983 47.0 47.0 50.7
Kettle Falls CT Gas 2002 11.0 8.0 7.5
Total 862.6 720.6 847.5

Project Name River System Nameplate
Capacity (MW)
Maximum
Capability (MW)
Expected
Energy (aMW)
Monroe Street Spokane 14.8 15.0 11.6
Post Falls Spokane 14.8 18.0 10.0
Nine Mile Spokane 26.0 17.5 12.5
Little Falls Spokane 32.0 35.2 22.1
Long Lake Spokane 81.6 89.0 53.4
Upper Falls Spokane 10.0 10.2 7.5
Cabinet Gorge Clark Fork 265.2 270.5 124.8
Noxon Rapids Clark Fork 518.0 610.0 198.3
Total
Hydroelectric
962.4 1,065.4 440.2

Kinney, Di Page 4 Avista Corporation
combined cycle generator, and a contract with a wind 1
generation facility. 2
The Company currently has long-term contractual 3
rights for resources owned and operated by the Public 4
Utility Districts of Chelan, Douglas and Grant counties. 5
Illustration No. 3 below provides details about the Mid-6
Columbia hydroelectric contracts. The Rocky Reach and 7
Rock Island contracts with Chelan PUD expired in December 8
2014, but the Company signed a one year agreement for 4 9
percent of Chelan PUD’s Rocky Reach and Rock Island 10
hydroelectric output in 2015. The Company was also 11
recently awarded a 5 percent slice of Chelan PUD’s Rocky 12
Reach and Rock Island hydro output for 2016 though 2020 13
through a competitive bidding process. Additional details 14
are provided in witness Mr. Johnson’s testimony. 15
Illustration No. 4 provides details about other contracts 16
currently in place. 17
Avista also has a long-term power purchase agreement 18
(PPA) in place through October 2026 entitling the Company 19
to dispatch, purchase fuel for, and receive the power 20
output from, the Lancaster combined-cycle combustion 21
turbine project located in Rathdrum, Idaho. In 2011, the 22
Company executed a 30-year power purchase agreement to 23
purchase the output (105 MW peak) and all environmental 24
Kinney, Di Page 5 Avista Corporation
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 28.2 16.7
Grant PUD – Wanapum 3.7 12/2001 12/2052 31.0 17.9
Chelan PUD – Rocky Reach 4.0 1/2015 12/2015 46.5 14.7
Chelan PUD – Rock Island 4.0 1/2015 12/2015 16.1 20.5
Douglas PUD - Wells 3.3 2/1965 8/2018 27.9 14.7
Canadian Entitlement1 -8.1 -4.6
2015 Total Net Contracted Capacity and Energy 141.6 79.9

attributes from the Palouse Wind, LLC wind generation 1
project that began commercial operation in December 2012. 2
The Company’s contract with the Stateline Wind facility 3
terminated in March 2014, and the contract to sell energy 4
and associated environmental attributes with the 5
Sacramento Municipal Utility District ended in December 6
2014. 7
Illustration No. 3: Mid-Columbia Hydroelectric Capacity 8 and Energy Contracts1 9 10
11
12
13
14
15
16
1 Under the Columbia River Treaty signed in 1961 and the Pacific Northwest Coordination Agreement (PNCA) signed in 1964, Canada receives return energy (Canadian Entitlement) related to storage water in upstream reservoirs for coordinated flood control and power
generation optimization.
Kinney, Di Page 6 Avista Corporation

Illustration No. 4: Other Contractual Rights and 1 Obligations Through 2015 2
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6
7
8
9
10
11
12
Q. Would you please provide a summary of Avista's 13
power supply operations and acquisition of new resources? 14
A. Yes. Avista uses a combination of owned and 15
contracted-for resources to serve its load requirements. 16
The Power Supply Department is responsible for dispatch 17
decisions related to those resources for which the Company 18
has dispatch rights. The Department monitors and 19
routinely studies capacity and energy resource needs. 20
Short- and medium-term wholesale transactions are used to 21
economically balance resources with load requirements. 22
The Integrated Resource Plan (IRP) generally guides 23
longer-term resource decisions such as the acquisition of 24
new generation resources, upgrades to existing resources, 25
Contract Type Fuel
Source
End
Date
Winter
Capacity (MW)
Summer
Capacity (MW)
Annual
Energy (aMW)
Energy America, LLC *
Sale Various 12/2019 -35 -50 -42.5
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 229.8 91.8 286.5
*Energy America contracts start July 1, 2015 and includes 42.5 aMW energy plus REC’s, 2016-2018 includes
50 aMW energy plus REC’s and 2019 includes 20 aMW energy plus REC’s.
Kinney, Di Page 7 Avista Corporation
demand-side management (DSM), and long-term contract 1
purchases. Resource acquisitions typically include a 2
Request for Proposals (RFP) and/or other market due 3
diligence processes. 4
Q. Please summarize Avista’s load and resource 5
position. 6
A. Avista’s 2013 IRP shows forecasted annual energy 7
deficits beginning in 2026, and sustained annual capacity 8
deficits beginning in 2020.2 These capacity and energy 9
load/resource positions are shown on pages 2-39 through 2-10
41 of Schedule 1. Schedule 2 shows the 2013 IRP load and 11
resource projection. Avista’s IRP projection shows an 12
annual energy deficit beginning in 2026 of about 19 aMW, 13
and increasing to a 284 aMW deficit in 2033. The 14
Company’s January capacity resource position, based on an 15
18-hour peak event (6 hours per day and over 3 days), is 16
projected to be surplus through 2019. Sustained annual 17
capacity deficiencies, based on a January peak, begin at 18
42 MW in 2020 and increase to a 551 MW deficit in 2033. 19
The Company’s August capacity resource position, based on 20
an 18-hour peak event, is projected to be surplus through 21
2023. Sustained annual capacity deficiencies, based on an 22
2 The Company has a 150 MW capacity exchange agreement with Portland General Electric that ends in December 2016 and Avista has short-term annual capacity deficits in 2015 and 2016. Sustained annual capacity
deficits begin in 2020.
Kinney, Di Page 8 Avista Corporation

August peak, begin at 2 MW in 2024 and increase to a 361 1
MW deficit in 2033. 2
The Company’s updated load and resource position will 3
be included with the submission of the 2015 Electric IRP 4
in August 2015. 5
Q. How does Avista plan to meet future energy and 6
capacity needs? 7
A. The Company is currently guided by the 2013 8
Preferred Resource Strategy (PRS). The current PRS is 9
described in the 2013 Electric IRP, which is attached as 10
Schedule 1 of Exhibit No. 4. The IRP provides details 11
about future resource needs, specific resource costs, 12
resource-operating characteristics, and the scenarios used 13
for evaluating the mix of resources for the PRS. The 14
Commission acknowledged the 2013 Electric IRP in Case No. 15
AVU-E-13-07 on March 20, 2014 in Order No. 32997. The IRP 16
represents the preferred plan at a point in time; however, 17
Avista continues evaluating resource options to meet 18
future load requirements and is currently working on its 19
next IRP, which will be filed in August 2015. The Company 20
has held five of six scheduled TAC meetings and is 21
currently finalizing the PRS and completing scenario 22
analysis. 23
Kinney, Di Page 9 Avista Corporation
Avista’s 2013 PRS includes less than one MW of 1
distribution efficiencies, 221 MWs of cumulative energy 2
efficiency, 19 MWs of demand response, 6 MWs of upgrades 3
to existing thermal plants, and 569 MWs of natural gas-4
fired plants (299 MWs of simple cycle combustion turbines 5
(SCCT) and 270 MWs of combined-cycle combustion turbine 6
(CCCT)). The timing and type of these resources as 7
published in the 2013 IRP is provided in Illustration No. 8
5. The Company’s draft 2015 PRS does not deviate 9
significantly from the 2013 PRS. 10
Illustration No. 5: 2013 Electric IRP Preferred Resource 11 Strategy 12 13
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15
16
17
18
19
20
Q. Would you please provide a high-level summary of 21
Avista’s risk management program for energy resources? 22
A. Yes. Avista Utilities uses several techniques 23
to manage the risks associated with serving load and 24
managing Company-owned and controlled resources. The 25
Resource Type By the End of Year Nameplate (MW) Energy (aMW)
SCCT 2019 83 76
SCCT 2023 83 76
CCCT 2026 270 248
SCCT 2027 83 76
Rathdrum CT Upgrade 2028 6 5
SCCT 2032 50 46
Total 575 529

Efficiency Improvements By the End of Year Peak Reduction
(MW)
Energy (aMW)
Energy Efficiency 2014-2033 221 164
Demand Response 2022-2027 19 0
Distribution Efficiencies 2014-2017 <1 <1
Total Efficiency 240 164

Kinney, Di Page 10 Avista Corporation
Energy Resources Risk Policy, which is attached as 1
Confidential Schedule 3C of Exhibit No. 4, provides 2
general guidance to manage the Company’s energy risk 3
exposure relating to electric power and natural gas 4
resources over the long-term (more than 41 months), the 5
short-term (monthly and quarterly periods up to 6
approximately 41 months), and the immediate term (present 7
month). 8
The Energy Resources Risk Policy is not a specific 9
procurement plan for buying or selling power or natural 10
gas at any particular time, but is a guideline used by 11
management when making procurement decisions for electric 12
power and natural gas fuel for generation. The policy 13
considers several factors, including the variability 14
associated with loads, hydroelectric generation, planned 15
outages, and electric power and natural gas prices in the 16
decision-making process. 17
Avista aims to develop or acquire long-term energy 18
resources based on the IRP’s PRS, while taking advantage 19
of competitive opportunities to satisfy electric resource 20
supply needs in the long-term period. Electric power and 21
natural gas fuel transactions in the immediate term are 22
driven by a combination of factors that incorporate both 23
economics and operations, including near-term market 24
Kinney, Di Page 11 Avista Corporation
conditions (price and liquidity), generation economics, 1
project license requirements, load and generation 2
variability, reliability considerations, and other near-3
term operational factors. 4
For the short-term timeframe, which falls between the 5
long-term and immediate term periods, the Company’s Energy 6
Resources Risk Policy guides its approach to hedging 7
financially open forward positions. A financially open 8
forward period position may be the result of either a 9
short position situation, for which the Company has not 10
yet purchased the fixed-price fuel to generate, or 11
alternatively purchased fixed-price electric power from 12
the market, to meet projected average load for the forward 13
period. Or it may be a long position, for which the 14
Company has generation above its expected average load 15
needs, and has not yet made a fixed-price sale of that 16
surplus to the market in order to balance resources and 17
loads. 18
The Company employs an Electric Hedging Plan to guide 19
power supply position management in the short-term period. 20
The Risk Policy Electric Hedging Plan is essentially a 21
price diversification approach employing a layering 22
strategy for forward purchases and sales of either natural 23
gas fuel for generation or electric power in order to 24
Kinney, Di Page 12 Avista Corporation
approach a generally balanced position against expected 1
load as forward periods draw nearer. 2
3
III. GENERATION CAPITAL PROJECTS 4
Q. Would you please provide a brief description of 5
the generation-related capital projects planned for 2015, 6
2016 and 2017? 7
A. Yes. As shown in Table No. 1 below, the total 8
2015, 2016 and 2017 generation capital projects to be 9
completed total $122.9 million, $45.5 million, and $83.7 10
million, respectively, on a system basis. Details about 11
the generation-related capital projects totaling $252.2 12
million are discussed below. 13
Kinney, Di Page 13 Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16 Base Load Hydro: 2015: $1,974,000; 2016: $1,149,000; 2017: 17 $1,149,000 18
This program covers the capital maintenance expenditures 19
required to keep Avista’s Upper Spokane River 20 hydroelectric plants operating within 90% of their current 21 performance, assuming some degradation of performance over 22 time. The plants covered in this program include Post 23 Falls, Upper Falls, Monroe Street, and Nine Mile. The 24
program focuses on ways to maintain compliance and reduce 25 overall operations and maintenance expenses while 26 maintaining a reasonable unit availability through a 27
programmatic approach, rather than reacting to problems as 28 they develop. The historical availability for the base 29
load hydro plants has been declining over the past decade 30 due to deteriorating equipment and a need to replace some 31 equipment and systems that are as much as 100 years old. 32
Business Case Name
2015
$ (000's)
2016
$ (000's)
2017
$ (000's)
122,939$ 45,509$ 83,716$
Generation / Production Capital Projects (System)TABLE NO. 1
Kinney, Di Page 14 Avista Corporation
Clark Fork Settlement Agreement – 2015: $13,988,000; 2016: 1 $6,054,000; 2017: $22,836,000 2
These capital costs are required for the facilitation of 3 the Clark Fork Protection, Mitigation and Enhancement 4 (PM&E) measures. The implementation of programs is done 5 through the License issued to Avista Corporation for a 6 period of 45 years, effective March 1, 2001, to operate 7
and maintain the Clark Fork Project No. 2058. The License 8 includes hundreds of specific legal requirements, many of 9 which are reflected in License Articles 404-430. These 10
Articles derived from a comprehensive settlement agreement 11 between Avista and 27 other parties, including the States 12
of Idaho and Montana, various federal agencies, five 13 Native American tribes, and numerous Non Governmental 14 Organizations. Avista is required to develop, in 15 consultation with the Management Committee, a yearly work 16 plan and report, addressing all PM&E measures of the 17
License. In addition, implementation of these measures is 18 intended to address ongoing compliance with Montana and 19
Idaho Clean Water Act requirements, the Endangered Species 20 Act (fish passage), and state, federal and tribal water 21 quality standards as applicable. License articles also 22
describe our operational requirements for items such as 23 minimum flows, ramping rates and reservoir levels, as well 24
as dam safety and public safety requirements. 25 26 Generation Battery Replacement – 2015: $434,000; 2016: 27 $250,000; 2017: $250,000 28 This program is based on an asset management plan for the 29
station batteries in all generating stations. This item 30 will also have some minor fluctuations as the number and 31 size of batteries in any particular year can change. 32
33 Hydro Safety Minor Blanket – 2015: $151,000; 2016: 34 $75,000; 2017: $80,000 35 This item funds periodic capital purchases and projects to 36 ensure public safety at hydro facilities, on and off 37 water, in the context of FERC regulatory and license 38 requirements. 39
Little Falls Plant Upgrade– 2015: $14,300,000; 2016: 40 $9,000,000; 2017: $10,000,000 41
The existing Little Falls equipment ranges in age from 60 42 to more than 100 years old. Forced outages at Little 43 Falls because of equipment failures have significantly 44
increased over the past six years, from about 20 hours in 45 2004 to several hundred hours in the past three to four 46
Kinney, Di Page 15 Avista Corporation
years. This project will replace nearly all of the older, 1 unreliable equipment with new equipment. This project 2
includes replacing two of the turbines, all four 3 generators, all generator breakers, three of the four 4 governors, all of the automatic voltage regulators, 5 removing all four generator exciters, replacing the unit 6 controls, changing the switchyard configuration, replacing 7
the unit protection system, and replacing and modernizing 8 the station service. 9 10 Nine Mile Rehabilitation – 2015: $56,567,000; 2016: 11 $9,871,000; 2017: $858,000 12
This capital program is necessary to rehabilitate and 13 modernize the four unit Nine Mile HED. The program 14 includes projects to replace the existing 3 MW Units 1 and 15 2, which are more than 100 years old and worn out, with 16 two new 8 MW generators/turbines. The new units will add 17
1.4 aMW of energy beyond the original configuration and 18 6.4 MW of capacity above current generation levels.3 In 19
addition to these capacity upgrades, the Nine Mile 20 facility will receive upgrades to the following: 21
• hydraulic governors; 22
• static excitation system; 23
• switchgear; 24
• station service; 25
• control and protection packages; 26
• ventilation upgrades; 27
• rehabilitation of intake gates and sediment bypass 28
system; 29
• a new warehouse will be constructed; 30
• new tail race gate system will be added; 31
• new grounding and communications will be added; 32
• a barge landing will be added; 33
• a cottage will be removed and another remodeled; 34
• a new panel room will be added; 35
• Units 3 and 4 will be overhauled and modernized; 36
• the powerhouse will be restored; 37
• new access gates and controls will be added; and 38
3 The additional output above the current generation has been included in the AURORAXMP power cost model reflecting the benefit of this
project.
Kinney, Di Page 16 Avista Corporation

• other improvements will be made. 1
2 Regulating Hydro – 2015: $5,186,000; 2016: $3,533,000; 3 2017: $3,533,000 4
This program covers the capital maintenance expenditures 5
required to keep the Long Lake, Little Falls, Noxon Rapids 6 and Cabinet Gorge plants operating at their current 7
performance levels. The program will work to improve the 8 reliability of these plants so that their value can be 9 maximized in both the energy and ancillary markets. 10 11 Spokane River Implementation PM&E – 2015: $1,266,000; 12 2016: $397,000; 2017: $17,018,000 13 This category covers the implementation of Protection, 14 Mitigation and Enhancement (PM&E) programs related to the 15
FERC License for the Spokane River. This includes items 16 enforceable by FERC, mandatory conditioning agencies, and 17
through settlement agreements. Additional details 18 concerning the PM&E measures for the Spokane River license 19 are included in the hydro relicensing section that 20
follows. 21 22 Base Load Thermal Plant – 2015: $2,200,000; 2016: 23 $2,200,000; 2017: $2,201,000 24
This program is necessary to sustain or improve the 25
existing operating costs of base load thermal generating 26 stations, including Coyote Springs 2, Colstrip, Kettle 27
Falls, and Lancaster. Capital projects include 28 replacement of items identified through asset management 29
decisions and programs necessary to maintain reliable and 30 low operating costs of these plants. As this program 31 proceeds, it is expected that forced outage rates and 32
forced deratings of these facilities will decrease to a 33 level one standard deviation less than the current 34 average, resulting in more economic benefits of the 35 project. 36 37 Peaking Generation – 2015: $501,000; 2016: $500,000; 2017: 38 $500,000 39
This program covers the capital maintenance expenditures 40 required to keep the natural gas-fired peaking units 41 (Boulder Park, Rathdrum CT, and Northeast CT) operating at 42
or above their current performance levels. The program 43 focuses on maximizing the ability of these units to start 44
and run when demanded (starting reliability). 45 46
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Kettle Falls Water Supply– 2015: $1,529,000 1
The Kettle Falls Generation Plant receives its water from 2
the City of Kettle Falls from an agreement that dates back 3 to the construction of the plant in the early 1980s. This 4 effort is to secure necessary water rights and a long term 5 water supply for the plant that is controlled by the 6 company. 7
8 Colstrip Thermal Capital – 2015: $2,497,000; 2016: 9 $10,480,000; 2017: $9,617,000 10
This program includes ongoing capital expenditures 11 associated with normal outage activities on Units 3 & 4 at 12
Colstrip. Every two out of three years, there are planned 13 outages at Colstrip with higher capital program 14 activities. For non-outage years, the program activities 15 are reduced. Avista votes its 15 percent share of Units 3 16 & 4 and its approximate 10 percent share of common 17
facilities to approve or disapprove of the budget proposed 18 by Pacific Pennsylvania Light Montana (PPLM) on behalf of 19
all the owners. 20 21 Coyote Springs 2 LTSA Capital Addition – 2016: $2,000,000; 22 2017: $730,000 23
This program covers the capital accruals required to 24
execute our Long Term Service Agreement (LTSA) with 25 General Electric for Coyote Springs Unit 2. This program 26 will have fluctuations to account for the variable 27
operating hours and operating conditions that feed into 28 the LTSA formula. 29
30 Noxon Spare Coils – 2015: $1,350,000 31
This project is to replace the spare coils that were used 32
in the Spring of 2013 to repair the stator winding that 33 failed for Unit 4. This item will procure 100 spare 34
coils. These spares cover Units 1 through 4 (Unit 5 uses 35 different coils). Because Avista had spares available, 36 Unit 4 was able to return to normal service within 11 37 weeks. Without these spares, the unit would have been out 38 for nine months or more. Prices for coils supplied under 39
emergency conditions would likely carry a 30 percent cost 40 premium. This project does not include any installation, 41 only the replacement of previously held stock. 42
43 Post Falls South Channel Gate Replacement – 2015: 44 $9,309,000 45 Avista is in the process of refurbishing the south channel 46 gates to comply with FERC Dam Safety directives. The 47
Kinney, Di Page 18 Avista Corporation
project entails removing most of the existing concrete 1 structure and replacing it with a new concrete structure, 2
new spillway gates, and new hoist systems to automate gate 3 operation. 4 5 Cabinet Gorge Unit 1 Refurbishment – 2015: $11,687,000 6
This is the capital portion of a major overhaul project 7
planned for Cabinet Gorge Unit #1. The runner hub has 8 significant mechanical issues and needs to be replaced to 9 allow for frequent cycling for load following. The present 10
automatic voltage regulator provides a relatively slow 11 response due to its hybrid design and has no limiters for 12
generator protection. A new system will provide faster 13 response and add limiters. The machine monitoring is to 14 allow for better analysis of machine condition for this 15 important unit. Rehabilitation of this unit will also 16 allow flexibility around minimum flow for fish habitat. 17
18 Cabinet Gorge Automation Replacement – 2017: $2,842,000 19
This project is to replace the unit and station service 20 control equipment at Cabinet Gorge with a system 21 compatible with Avista’s current standards. The Bailey 22
Net 90 equipment that is installed currently is obsolete 23 because replacement of the system can only be done through 24
secondary and salvage markets. In addition, the current 25 system does not provide enough inputs and outputs that 26 allow implementation of standard unit control and 27
monitoring schemes. This work will replace the existing 28 panel and control systems with a new system. The scope of 29
work has expanded to include replacement governors, 30 voltage regulators, and protective relays. 31 32 Kettle Falls Stator Rewind – 2017: $7,930,000 33
The Kettle Falls generator is over 32 years old and is at 34
the end of its expected life. This project consists of 35 monitoring the existing machine, developing rewind 36 contract, manufacturing replacement coils, disassembly, 37 coil removal, new coil installation, reassembly, startup, 38 testing and commissioning. Consequences of failure 39
include an unscheduled outage with lost generation, loss 40 of renewable energy credits, long term interruption of 41 fuel supply, collateral damage to core and hydrogen 42
cooling with resulting safety hazards. 43
44 Long Lake Replace Field Windings – 2017: $4,172,000 45
Over the past 10 years, the Company has observed a 46 continuing decline in the insulation level on the 47
Kinney, Di Page 19 Avista Corporation
generators at Long Lake as measured using Megger test 1 instruments. Long Lake has experienced an increasing 2
amount of forced outages and down time due to the 3 deteriorating condition of these units. 4 5
IV. HYDRO RELICENSING 6
Q. Would you please provide an update on work being 7
done under the existing FERC operating license for the 8
Company’s Clark Fork River generation projects? 9
A. Yes. Avista received a new 45-year FERC 10
operating license for its Cabinet Gorge and Noxon Rapids 11
hydroelectric generating facilities on the Clark Fork 12
River on March 1, 2001. The Company has continued to work 13
with the 27 Clark Fork Settlement Agreement signatories to 14
meet the goals, terms, and conditions of the Protection, 15
Mitigation and Enhancement (PM&E) measures under the 16
license. The implementation program, in coordination with 17
the Management Committee which oversees the collaborative 18
effort, has resulted in the protection of approximately 19
80,000 acres of bull trout, wetlands, uplands, and 20
riparian habitat. More than 37 individual stream habitat 21
restoration projects have occurred on 23 different 22
tributaries within our project area. Avista has collected 23
data on almost 19,000 individual bull trout within the 24
project area. The upstream fish passage program, using 25
electrofishing, trapping and hook-and-line capture 26
Kinney, Di Page 20 Avista Corporation
efforts, has reestablished bull trout connectivity between 1
Lake Pend Oreille and the Clark Fork River tributaries 2
above Cabinet Gorge and Noxon Rapids Dams through the 3
upstream transport of 498 adult bull trout, with over 160 4
of these radio tagged and their movements studied. Avista 5
has worked with the U.S. Fish and Wildlife Service to 6
develop and test two experimental fish passage facilities. 7
Avista, in consultation with certain state and federal 8
agencies, is currently developing designs for a permanent 9
upstream adult fishway for Cabinet Gorge and Noxon Rapids. 10
In 2013, designs for the Cabinet Gorge Fishway Fish 11
Handling and Holding Facility were completed and 12
construction began in 2013. A permanent tributary trap on 13
Graves Creek (an important bull trout spawning tributary) 14
was constructed in 2012 and testing began 2013. A three-15
year evaluation process is ongoing to determine if future 16
permanent tributary traps are warranted. 17
Recreation facility improvements have been made to 18
over 28 sites along the reservoirs. Avista also owns and 19
manages over 100 miles of shoreline that includes 3,500 20
acres of property to meet FERC required natural resource 21
goals, while allowing for public use of these lands where 22
appropriate. 23
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Finally, tribal members continue to monitor known 1
cultural and historic resources located within the project 2
boundary to ensure that these sites are appropriately 3
protected and are working to develop interpretive sites 4
within the project. 5
Q. Would you please provide an update on the 6
current status of managing total dissolved gas issues at 7
Cabinet Gorge dam? 8
A. Yes. How best to deal with total dissolved gas 9
(TDG) levels occurring during spill periods at Cabinet 10
Gorge Dam was unresolved when the current Clark Fork 11
license was received. The license provided time to study 12
the actual biological impacts of dissolved gas and to 13
subsequently develop a dissolved gas mitigation plan. 14
Stakeholders, through the Management Committee, ultimately 15
concluded that dissolved gas levels should be mitigated, 16
in accordance with federal and state laws. A plan to 17
reduce dissolved gas levels was developed with all 18
stakeholders, including the Idaho Department of 19
Environmental Quality. The original plan called for the 20
modification of two existing diversion tunnels, which 21
could redirect stream flows exceeding turbine capacity 22
away from the spillway. 23
Kinney, Di Page 22 Avista Corporation
The 2006 Preliminary Design Development Report for 1
the Cabinet Gorge Bypass Tunnels Project indicated that 2
the preferred tunnel configuration did not meet the 3
performance, cost and schedule criteria established in the 4
approved Gas Supersaturation Control Plan (GSCP). This 5
led the Gas Supersaturation Subcommittee to determine that 6
the Cabinet Gorge Bypass Tunnels Project was not a viable 7
alternative to meet the GSCP. The subcommittee then 8
developed an addendum to the original GSCP to evaluate 9
alternative approaches to the Tunnel Project. 10
In September 2009, the Management Committee (MC) 11
agreed with the proposed addendum, which replaces the 12
Tunnel Project with a series of smaller TDG reduction 13
efforts, combined with mitigation efforts during the time 14
design and construction of abatement solutions take place. 15
FERC approved the GSCP addendum in February 2010 and 16
in April 2010 the Gas Supersaturation Subcommittee (a 17
subcommittee of the MC) chose five TDG abatement 18
alternatives for feasibility studies. Feasibility studies 19
and preliminary design were completed on two of the 20
alternatives in 2012. Final design, construction, and 21
testing of the spillway crest modification prototype was 22
completed in 2013. Test results indicated over all TDG 23
performance was positive, however, additional 24
Kinney, Di Page 23 Avista Corporation
modifications were required to address cavitation issues. 1
Modification of the spillway crest prototype and retesting 2
were completed in 2014. It is anticipated that up to seven 3
additional spillway crests will be modified by 2018. 4
Q. Would you please give a brief update on the 5
status of the work being done under the new Spokane River 6
Hydroelectric Project’s license? 7
A. Yes. The Company received a new 50-year license 8
for the Spokane River Project on June 18, 2009. The 9
License incorporated key agreements with the Department of 10
Interior and other key parties in both Idaho and 11
Washington. Implementation of the new license began 12
immediately, with the development of over 40 work plans 13
prepared, reviewed and approved, as required, by the Idaho 14
Department of Environmental Quality, Washington Department 15
of Ecology, the U.S. Department of Interior, and FERC. 16
The work plans pertain not only to license requirements, 17
but also to meeting requirements under Clean Water Act 401 18
certifications by both Idaho and Washington and other 19
mandatory conditions issued by the U.S. Department of 20
Interior. 21
Since 2011, Avista has implemented water quality, 22
fisheries, recreation, cultural, erosion, wetland, aquatic 23
weed management, aesthetic, operational and related 24
Kinney, Di Page 24 Avista Corporation
conditions across all five hydro developments under the 1
Protection Mitigation and Enhancement (PM&E) measures. 2
The majority of the PM&E measures are on-going in nature, 3
however, a number are one-time improvements, such as the 4
Upper Falls aesthetic spill project located in downtown 5
Spokane. Six hundred and fifty six acres of wetland 6
mitigation properties were acquired in 2011 and 2012 on 7
Upper Hangman Creek in Idaho for the Coeur d’Alene Tribe 8
through the Coeur d’Alene Reservation Trust Resources 9
Restoration Fund that Avista established in 2009. The 10
Company developed wetland restoration plans for 11
approximately 500 of the required 1,368 replacement acres 12
of wetland and riparian habitat and is waiting for 13
approval by the U.S. Department of Interior, Bureau of 14
Indian Affairs to continue implementing the plans. The 15
U.S. Department of Interior, Bureau of Indian Affairs and 16
FERC approved revisions, requested by the Coeur d’Alene 17
Tribe, to the Coeur d’Alene Reservation Erosion Control 18
Implementation Plan. The revisions allow Avista and the 19
Tribe to acquire, restore, manage, and monitor 56 acres of 20
land consistent with the requirements of the Wetland and 21
Riparian Habitat Plan, mentioned above, in lieu of 22
implementing shoreline stabilization along 63,130 feet of 23
the Lower St. Joe River. The new total for all replacement 24
Kinney, Di Page 25 Avista Corporation
lands is now 1,424 acres. In 2014, the Company monitored 1
the vegetation on the recently completed 124-acre wetland 2
mitigation project along the St. Joe River and will be 3
responsible for maintaining approximately half of it, 4
which lies on Avista’s property, for the License term. 5
Avista continued work with the various local, state, 6
and federal agencies to complete more of the required 7
recreation projects in Idaho, such as trail and 8
interpretive sign improvements in Post Falls, and public 9
recreation improvements along the St. Maries River. In 10
Washington, the Company completed the ten boat-in-only 11
campsites on Lake Spokane, and a new carry-in-only boat 12
launch at Nine Mile Falls. The Company developed and is 13
implementing the management plan for the recently 14
purchased 109 acre Sacheen Springs Wetland Complex located 15
along the Little Spokane River. In 2015, Avista will 16
continue to develop and implement local, state, and 17
federally required work plans to fulfill License 18
conditions. 19
A number of the approved work plans required the 20
Company to conduct extensive studies to determine 21
appropriate measures to mitigate resource impacts. The 22
more significant studies and mitigation measures include 23
those for total dissolved gas (TDG) downstream of Long 24
Kinney, Di Page 26 Avista Corporation
Lake Dam. Avista modeled several different types of 1
spillway modifications between 2011 and 2013 and completed 2
the design for the desired deflector configurations in 3
2014. Following the design, Avista requested a one-year 4
setback in the construction schedule to allow completing 5
of the construction process in 2016-2017 instead of 2015-6
2016. The new schedule will allow the Company to complete 7
work on the dam’s spillway gate seals and the rigorous 8
permitting processes prior to constructing the new 9
deflectors. The Company completed the proposed dissolved 10
oxygen (DO) measure in the tailrace below Long Lake Dam 11
and is continuing to monitor its effectiveness in 12
addressing low DO in the river below the dam. Avista is 13
also continuing to evaluate potential measures to improve 14
DO in Lake Spokane, the reservoir created by the Long Lake 15
Dam. Cost estimates to construct the TDG spillway 16
deflectors range between $8.0 and $10.0 million, and 17
between $2.5 and $8.0 million to address DO in Lake 18
Spokane. These estimates will be refined as the 19
evaluations and studies are completed. 20
Q. Please explain the costs incurred by the Company 21
to study the total dissolved gas downstream of Long Lake 22
Dam, and the Company’s proposal for recovering these 23
costs. 24
Kinney, Di Page 27 Avista Corporation
A. Through December 31, 2012, the Company had 1
incurred $1.340 million of system costs related to meeting 2
certain regulatory requirements to improve the dissolved 3
oxygen levels in Lake Spokane, as described above. 4
Idaho’s share of these costs was approximately $473,000. 5
As described by Ms. Andrews, through this general rate 6
case filing, the Company is seeking a prudence finding 7
related to these costs, and amortization of the TDG costs 8
for Lake Spokane over a two-year period beginning in 20164. 9
Q. Does this conclude your pre-filed direct 10
testimony? 11
A. Yes it does. 12
4 As explained by Ms. Andrews, the Company was authorized in Case No. AVU-E-13-06 (see Order No. 32917) to defer these costs in FERC Account 182.3 without a carrying charge, with a prudency review to occur in
the Company’s next general rate case or other proceeding.
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