20080403Kinney Direct.pdf

DAVID J. MEYER
VICE PRESIDENT, GENERAL COUNSEL, REGULATORY &
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727TELEPHONE: [phone]FACSIMILE: [phone]
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AN CHARGES FOR ELECTRIC AN
NATURAL GAS SERVICE TO ELECTRIC
AND NATUR GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-08-01
DIRECT TESTIMONY
OF
SCOTT J. KINNEY
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
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I. INTRODUCTION
Q.Please state your nae, emloyer and business
3 address.
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A.My name is Scott J. Kinney.I am employed by
Avista Corporation as the Chief Engineer,System
Operations.My business address is 1411 East Mission,
7 Spokane, washington.
8 Q.Please briefly describe your education background
9 and professional experience.
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A.I graduated from Gonzaga University in 1991 with
a B. S . in Electrical Engineering.I am a licensed
12 Professional Engineer in the State of Washington. I joined
13 the Company in 1999 after spending eight years with the
14 Bonneville Power Administration.I have held several
15 different positions in the Transmission Department.I
16 started at Avista as a Senior Transmission Planning
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Engineer.In 2002, i moved to the System Operations
Department as a supervisor and support engineer.In 2004,
19 i was appointed to my current position of Chief Engineer,
20 System Operations.
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Q.What is the scope of your testimony?
A.My testimony describes Avista' s pro forma period
transmission revenues and expenses.I also discuss the
24 nearly completed 5-year Transmission Upgrade Project, and
25 the Transmission and Distribution expenditures that are
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1 part of the capital additions testimony provided by Company
2 witness Mr. Dave DeFelice, as well as the Company's Asset
3 Management Program expenses.Company witness Ms. Andrews
4 incorporates the Idaho share of the net transmission
5 expenses,the transmission and distribution capital
6 additions, and the Asset Management Program O&M expenses
7 proposed in this case.
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Q.Are you sponsoring any exhibits?
A.Yes.I am sponsoring Exhibit No. 10, Schedules
1-3, which were prepared under my direction.Schedule 1,
provides the transmission pro forma adjustments.Schedule
12 2, includes a map of the u230 kV Upgrade Project" at page
13 1, and the uAvista 5-Year Transmission Upgrade Project"
14 table at page 2. Schedule 3, includes the Asset Management
15 Program Model.
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II. PRO FORM TRASMISSION EXPENSES
Q.Please describe the pro form transmission
19 expense revisions included in this filing.
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A.Adjustments were made in this filing to
incorporate updated information for any changes in
22 transmission expenses from the 2007 test year to the 2009
23 Pro forma period. Each expense item described below is at a
24 system level, with the exception of the $71,000 Grid West
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1 adjustment which is Idaho only, and is included in Exhibit
2 No. 10, Schedule 1.
3 Northwest Power Pool (NWPP) - Avista pays its share
4 of the NWPP operating costs. The NWPP serves the utilities
5 in the Northwest by providing regional transmission
6 planning, coordinated transmission operations, and Columia
7 River water coordination.There is no anticipated change
8 in NWPP costs in the pro forma period compared to 2007
9 actual expense of $31,000.
10 Colstrip Transmission - Avista is required to pay its
11 portion of the O&M costs associated with the Colstrip
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transmission system pursuant to the j oint Colstrip
contract.In accordance with Northwestern Energy's (NW)
14 15 year Colstrip transmission plan provided to the Company,
15 NW will bill Avista an annual total of $631,000 (based on
16 2007 dollars with no inflation adders) for Avista's share
17 of the Colstrip O&M expense during 2009.This is an
18 increase of $172,000 over 2007 actual expense of $459,000.
19 NW expects 2008 Colstrip O&M costs to be $519,000.The
20 significant cost increase is a result of implementing
21 cathodic protection measures and the on going anchor bolt
22 replacement program.
23 ColumiaGrid (RTO Development)In 2006, Avista
24 elected to fund the ColumiaGrid RTO development effort.
25 This is a regional organization whose purpose is to enhance
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1 transmission system reliability and efficiency, provide
2 cost-effective regional transmission planning, develop and
3 facilitate the implementation of solutions relating to
4 improved use and expansion of the interconnected Northwest
5 transmission system, reduce transmission system congestion,
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and support effective market monitoring within the
Northwest and the entire Western interconnection.Under
8 the amended ColumiaGrid funding agreement signed Septemer
9 1, 2006, Avista will pay a total of $518,000, which
10 represents Avista' s share of the ColumiaGrid operating
11 costs from 2006 through Augusts 31, 2008.Prior to the
12 amended agreement, Avista paid $104,000 of these costs.
13 The remaining balance ($414,000) is being collected over
14 the remaining 20 months 0 f the agreemen t .The monthly
15 amount is $20,720. Avista anticipates that ColumiaGrid
16 operating costs will continue beyond August 2008 with
17 monthly paYments remaining at least $20,720. Therefore, the
18 ColumiaGrid cost for the pro forma period is anticipated
19 to be approximately $249,000 annually based on a monthly
20 fee of $20,720.
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ColumiaGrid Planning -An additional service being
provided by ColumiaGrid is regional planning and
23 expansion. A functional agreement was developed and filed
24 with the Federal Energy Regulatory Commission (FERC) on
25 February 2, 2007 and approved on April 3, 2007.The
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1 agreement does not have a termination date and funding is
2 on a two-year cycle with provisions to adjust for
3 inflation. Funding is based on a fixed amount, plus a
4 portion is based on Avista' s load ratio compared to the
5 other members. Avista believes the planning agreement will
6 be extended beyond the initial 2 year period that ends
7 after December 2008. The Company anticipates that costs to
8 support the ColumiaGrid planning effort will be equal to
9 at least the current monthly rate of $10,251. This equates
10 to $123,000 during the pro forma period, which is $72,000
11 over 2007 actual costs. The increase is attributed to the
12 planning agreement being started in the middle of the 2007
13 operating year.
14 Grid West (ID Direct)Included in transmission
15 expense is an annual amount of $71,000 to recover costs
16 associated with Grid West (and its forerunner, RTO west).
17 Avista signed an initial funding agreement in 2000, as did
18 all other Pacific Northwest investor-owned electric
19 utili ties, to provide funding for the start-up phase of
20 Grid West (then named URTO West").Grid West had planned
21 to repay the loans to Avista and other funding utilities
22 through surcharges to customers once it became operational.
23 with the dissolution of Grid West, this repaYment did not
24 occur.As a result, Avista filed an application with the
25 Commission to defer these costs. The Commission approved,
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1 on October 24, 2006, in Order No. 30151, the Company's
2 request for an order authorizing deferred accounting
3 treatment for loan amounts made to Grid West. In its Order
4 the IPUC found these costs to be uprudent and in the public
5 interest" and required the Company to begin amortization of
6 the Idaho share of the loan principal ($422,000) beginning
7 January 2007, for five years. During the pro forma period
8 Avista will amortize a total of $71,000 associated with
9 Grid West development costs.
10 Electric Scheduling and Accounting Services The
11 $52,000 decrease in the pro forma period compared to actual
12 2007 expense for electric scheduling and accounting
13 services is a result of continued reductions in services
14 provided by third party vendors.These services are no
15 longer required because of the development of an internal
16 accounting program and the development of a regional
17 transmission interchange tool by the Western Electricity
18 Coordinating Council (WECC). These new applications replace
19 the services provided by third parties.
20 Grant County Agreement - This will be discussed later
21 in conjunction with the Seattle and Tacoma revenues and
22 expenses associated with the Main Canal and Sumer Falls
23 Proj ects .
24 OASIS Expenses The Open Access Same-Time
25 Information System (OASIS) expenses are associated with
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1 travel and training costs for transmission pre-scheduling
2 and OASIS personnel.This travel is required to monitor
3 and adhere to the NERC reliability standards and FERC OASIS
4 requirements. The costs associated with OASIS expenses in
5 the pro forma period is $4,000 more than the 2007 test
6 year.
7 WECC - System Security Monitor & WECC Administration
8 and Net Operating Committee Systems - The WECC fees have
9 and will continue to increase from year to year.WECC is
10 just beginning to develop its 2009 budget so 2008 actual
11 fees will be used for the pro forma period.WECC System
12 Security Monitor fees in 2008 are $170,900 compared to 2007
13 test year fees of $98,500.Addi tionally,the WECC
14 Administrative and Net Operating fees have been increased
15 from $217,100 in 2007 to $282,000 for 2008.Both changes
16 reflect significant increases in the WECC budget to fund
17 regional reliability initiatives required to meet FERC and
18 NERC mandatory reliability standards.
19 WECC Loop Flow -Loop Flow charges are spread
20 across all transmission owners in the West to compensate
21 utilities that make system adjustments to eliminate
22 transmission system congestion throughout the operating
23 year.The 2009 pro forma charge is $26,800 which is a
24 three year average of actual fees, since charges are
25 dependent on transmission system usage and congestion, and
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1 can vary from year to year.This is $2,000 higher than
2 actual 2007 charges.
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III. PRO FORM TRASMISSION RES
Q.Please describe the pro form transmission
6 revenue revisions included in this filing.
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A.Adjustments were made in this filing to
incorporate updated information f or any changes in
9 transmission revenue from the 2007 test year to the 2009
10 Pro forma period. Each revenue item described below is at
11 a system level and is included in Exhibit No. 10, Schedule
12 i.
13 Borderline Wheeling - The Borderline Wheeling revenue
14 in the pro forma period is set at $5,218,000, which is an
15 average of the 2006 and 2007 actual revenue levels. Actual
16 2007 test year revenue was $5,203,000.Avista typically
17 uses a five year average of actual annual revenue to
18 estimate future Borderline Wheeling revenue.This helps
19 levelize the revenue requirement since it is based on load
20 demand that is sensitive to temperature variation from year
21 to year.For this case Avista is only using a two year
22 average since 2006 and 2007 are the only years operating
23 under new contracts signed with BPA.The new Borderline
24 Wheeling revenue methodology is based on a Load Ratio
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1 Share1, which is quite different than the previous revenue
2 calculation under the old contracts.Under the new
3 contracts, BPA, as the network customer, will pay a monthly
4 demand charge, which will be determined by multiplying its
5 Load Ratio Share times one twelfth (1/12 )of the
6 Transmission Provider's annual transmission revenue
7 requirement.
8 Seattle and Tacoma Revenues and Expenses Associated
9 with the Main Canal and Sumer Falls Projects - In March
10 of 2006, Seattle and Tacoma purchased interim long-term
11 firm point-to-point transmission service from Avista under
12 the OATT to move their Main Canal and Sumer Falls
generation to load.These interim point-to-point13
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transmission contracts replaced expired long-term
contracts.The transmission was purchased from April 2006
16 through October 2007. Avista collected $1,281,000 in 2007
17 under these contracts and in turn paid $512,400 (plus
18 $275,900 in losses) to Grant County PUD for use of its
19 system to transfer the entire output of the Main Canal and
20 Sumer Falls proj ects. The interim contracts were meant to
21 give Seattle and Tacoma time to build new transmission
22 facilities to bypass Avista and connect directly to BPA.
23 Pursuant to negotiations among Seattle, Tacoma, Grant
24 County PUD, Grand Coulee Project Hydroelectric Authority
i Load Ratio Shae is the ratio of a Tranmission Customer's Network Load to the Transmission
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1 and Avista, Seattle and Tacoma have decided not to bypass
2 Avista's transmission system.The parties have agreed
3 instead, to a series of long term agreements with service
4 to commence March 1, 2008.Seattle and Tacoma have signed
5 similar contracts with Grant County PUD so Avista will not
6 incur any of the transmission expenses with Grant County
7 PUD that it did in the 2007 test year. Under the new Main
8 Canal agreement Avista charges Seattle and Tacoma during
9 the eight months the Main Canal proj ect runs (March-
10 October) and only for that output not used for local load
11 service. Under the new Sumer Falls agreement, Seattle and
12 Tacoma only use a portion of Avista' s Stratford Switching
13 Station and are charged a use-of-facili ties fee based upon
14 this limited use.The estimated revenue from Seattle and
15 Tacoma for Main Canal and Sumer Falls during the pro forma
16 period is $120,000.
17 Grand Coulee Proj ect Revenue The Grand Coulee
18 Project revenue is a result of a new contract signed in
19 March 2006 with the project owner for a fixed dollar
20 amount, replacing the previous contract which expired in
21 October 2005. The new contract results in monthly revenue
22 of $673 or annual revenue of $8,100 during the pro forma
23 period, which is the same as the test year.
Provider's tota load calculated on a rolling twelve-month basis.Kinney, Di 10
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1 OASIS Non-firm and Short-term firm Wheeling Revenue -
2 OASIS is an acronYm for Open Access Same-time Information
System.This is the system used by utility transmission3
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departments for purchasing and scheduling available
transmission for other utilities and independen t
6 generators.OASIS revenues are revenues received from the
7 sale of transmission capacity to third parties, for
8 transmission above and beyond that needed by Avista to
9 serve native load.These revenues are credi ted back to
10 customers in a rate case, such as this one, to offset a
11 portion of the overall cost of transmission.
12 Because these revenues vary year to year depending on
13 electric energy market conditions and available
14 transmission capacity (ATC) on adjacent utility systems,
15 Avista has, in previous rate cases, used the most recent
16 five-year average as being representative of future
17 expectations unless there are known events or factors that
18 occurred during the period that would cause the average to
19 not be representative of future expectations.in 2004,
20 there were some unusual events that caused Avista' s OASIS
21 revenues ($5,475,000) to be significantly higher than the
22 other test years.
23 The Bonneville Power Administration (BPA) had several
24 500 kV lines out of service for rebuild projects, which
25 resulted in a significant increase in Avista's transmission
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1 sales in 2004. During 2004 BPA was constructing a new 500
2 kV line from Bell substation in Spokane to Grand Coulee Dam
3 in central Washington, installing fiber optic cable on
4 existing transmission lines,and installing new and
5 upgrading existing series capacitor banks on four of its
6 area 500 kV lines as part of the West of Hatwai
7 reinforcement proj ect.This construction resulted in
8 multiple prolonged transmission outages that significantly
9 reduced the BPA ATC on critical transmission paths from
10 eastern Montana.Avista owns rights and facilities in
11 these same transmission paths so Avista experienced a
12 significant increase in transmission sales and revenues
13 during the BPA outages.
14 Therefore, Avista did not include the 2004 revenue in
15 the calculation of the five-year average revenue.Avista
16 calculated the 2009 pro forma OASIS revenue based on
17 revenue from years 2003, 2005, 2006, and 2007.During
18 these four years Avista' s highest OASIS revenue was $3.573
19 million in 2003 and Avista' s lowest revenue was $3.129
20 million in 2005.The resulting four-year revenue average
21 is $3,354,000, which is $18,000 higher than the 2007 actual
22 revenue of $3,336,000.
23 Dry Gulch Revenue Dry Gulch revenue has been
24 adjusted to $276,000 for the pro forma period, which is a
25 $24,000 increase from the 2007 actual revenue of $252,000.
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1 The current methodology used to forecast Dry Gulch revenue
2 is a five-year average of actual revenue.A five-year
3 average is used since the revenue can vary from year to
4 year.The revenue is calculated using a 12-month rolling
5 ratchet based on monthly peak demands. Load peaks are very
6 sensitive to temperatures, which vary from year to year.
7 PP&L Series Cap - 1978 - PP&L Series Cap revenue was
8 reduced from $9,000 in the test year to $5,000 in the pro
9 forma period since the 20 year amortization of the original
10 contract expires in June 2009. In 1989 Pacificorp paid the
11 company a lump sum of $178,222 in lieu of annual paYments
12 provided for under the original agreement.The lump sum
13 paYment was amortized at $781 per month from August 1990
14 through June 2009.
15 Spokane Waste to Energy Plant -No adjustments to
16 Spokane Waste to Energy Plant revenue of $160,000 were made
17 for the pro forma period compared to the 2007 test year.
18 This revenue is the result of a long-term transmission
19 interconnection agreement with the City of Spokane.The
20 contract expires in February 2011.
21 Vaagen Wheel ing Vaagen Wheeling revenue was
22 increased slightly to $112,000 for the pro forma period
23 compared to 2007 actual revenue of $110,000. A five-year
24 average is used to determine the pro forma period revenue
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1 since revenue can fluctuate year to year depending upon
2 transmission usage.
3 Northwestern Energy (NWE)The revenue of $231,000
4 from NWE in the 2007 test year was a result of a load
5 following contract that Avista signed in 2005 with NW.
6 Under the contract Avista provides up to 15 MW of energy to
7 NWE to help them match hourly fluctuations in loads and
8 resources.Firm transmission for this contract was
9 purchased by Avista' s Power Resources department from
10 Avista' s Transmission department and was included in the
11 contract price paid for by NWE.During the first three
12 years of the contract the transmission revenue was credited
13 to the Avista Transmission Department.Since the
14 transmission revenue from this contract is actually an
15 intra-company exchange of revenue it has been shifted to
16 revenue account 447 for the pro forma period and has been
17 included in Mr. Johnson's Power Supply information.
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iv. TRASMISSION AN DISTRIBUTION CAPITAL PROJECTS
Q.Please describe the Company's capital
21 transmission projects in 2008?
22 A.The Company has nearly completed its 5-year
23 (2003-2007) $136.4 million transmission upgrade proj ect,
24 discussed later in my testimony,that significantly
25 improved the infrastructure of the 230 kV transmission
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1 system.wi th the completion of these proj ects the
2 transmission proj ect focus is shifting to improving the 115
3 kV transmission system to meet load growth and eliminate
4 thermal loading issues.The maj or capital transmission
5 costs (system) for projects to be completed in 2008 are
6 approximately $12.1 million.The maj or proj ects scheduled
7 for 2008 completion include:
8 . Airway Heights to Silver Lake 115 kV Transmission9 ($2.0 million)
10 . Benewah Substation Transformer ($1.5 million)
11 . Extension of 115 kV underground in Spokane ($1.812 million)
13 . Spokane/Coeur d'Alene area relay upgrade phase 1 ($1.214 million)
1516 The remaining transmission projects being constructed
17 in 2008 are smaller proj ects.These projects include
18 normal system replacements due to aging facilities, minor
19 rebuilds, reliability improvements, safety requirements,
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required line relocations,and smaller construction
proj ects to address overloaded equipment.These smaller
22 proj ects are required to operate the transmission system
23 safely and reliably.
24 Q.Please describe the Company's distribution
25 projects in the State of Idaho that will be completed in
26 2008?
27 A.Distribution Projects in Idaho (including
28 transformation) for 2008 total $10.9 million, of which $3.5
29 million are for proj ects necessary to meet capacity needs
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1 of the system. Included in the $3.5 million is the
2 transformation upgrade and substation rebuild at Plumer
3 planned to be completed in 2008 at $2 million.New
4 feeders, feeder reconductoring, substation transformers in
5 plant and road construction requirements make up the
6 remainder of the $3.5 million.The remaining anticipated
7 distribution plant expenditures in the State of Idaho for
8 2008 over and above the $3.5 million are for minor blankets
9 and various small-scale proj ects.
10 Q.Please describe the Company's 5-year transmission
11 upgrade project?
12 A.The Company has nearly completed its 5-year
13 transmission upgrade effort that began in 2003 at a total
14 system cost of $136.4 million ($134.9 million has been
15 completed and placed in service as of December 31, 2007).
16 This multi-year transmission upgrade project added over 100
17 circuit miles of new 230 kV transmission line to Avista' s
18 system, and increased the capacity of an additional 50
19 miles of transmission line.The upgrade proj ect included
20 constructing two new 230 kV substations as well as
21 reconstructing three existing transmission substations.
22 Six additional 230 kV substations were upgraded to meet
23 capacity requirements, replace protective relaying systems,
24 and meet regional and national reliability standards.In
25 total, Avista performed work on eleven of its thirteen 230
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1 kV substations. Avista also upgraded its telecommunication
2 system by installing fiber and digital microwave systems.
3 This created redundant communication paths, required by
4 national reliabili ty standards and improved system
5 monitoring, control, and protection.Exhibit No. 10,
6 Schedule 2 page 1, includes a map showing the location of
7 the 230 kV upgrade projects.Page 2 shows the individual
8 project costs by year totaling the $136.4 million total
9 project cost. Included in Table No. 1 below is the listing
10 of completed proj ects and their system costs through
11 December 31, 2007.
12 Table No. 1- Transmission Project Costs
13 5-Year Transmission upgrade Projects completed through14 Decemer 31, 2007
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Transmission Projects Cost: System
Pine Creek Substation $4,745
Beacon-Rathdrum 230 kV $19,991
Dry Creek Substation $14,454
Beacon-Bell #4 230 kV $1,431
Beacon-Bell #5 230 kV $3,657
Spokane Valley Reinforcement $23,623
WoH Telecom $8,184
WoH Telecom Line Upgrades $966
Clark Fork RAS $1,071
Palouse Reinforcement (1)$54,658
Lolo Substation(1)$2,139
Total $134,919
PI Additional costs of approximately $1.5 for Palouse Reinforcement ($800k)
and Lolo Substation ($700k) are planned for 2008 and included in the
Company's Pro Forma Caoital Additions 2008 adiustment lPF7)
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1 Q.Please describe the major components of the
2 transmission upgrade project included in this filing?
3 As shown in the table above (see also ExhibitA.
4 No. 10, Schedule 2, page 2), the Company has completed
5 several major transmission projects during the 5-year
6 reinforcement effort, which include the pine Creek 230 kV
7 Substation, Beacon-Rathdrum 230 kV Project, the Beacon-Bell
8 #4 and #5 230 kV line upgrades, the Dry Creek Substation
9 Project, the Spokane Valley Reinforcement Project, the West
10 of Hatwai (WoH) Telecom Projects including the Clark Fork
11 Remedial Action Scheme, Palouse Reinforcement Proj ect, the
12 Lolo Substation Rebuild Proj ect at a total system
13 investment of $136.4 million.
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.pine Creek Substation: Avista rebuilt this 230 kV
substation located in Pinehurst, ID. The 500 MVA
substation was re-energized in November 2003.
Modernizing the 50-year old substation, by upgrading
circui t breakers and other equipment relieved
transmission congestion between Noxon Rapids Dam and
delivery points in the Silver Valley, Spokane and
southward into the Palouse area.
.Beacon-Rathdru 230 kV: Avista reconstructed 25 miles
of double circuit 230 kV transmission line between
Rathdrum, ID and Spokane, WA. This project includedreconstructing the Rathdrum 230 kV substation inIdaho. By adding a 23 OkV circui t and using larger
conductor, the capacity of the old transmission linewas raised from 300 to 2000 MW. This relieved a
significant transmission bottleneck between North
Idaho and Eastern Washington. Conversely, Rathdrum
substation was reconstructed to enable the higher
transfer limits. A second 230 kV bus was added to
Rathdrum, making the station fully redundant. Without
this addition, 230kV main bus outages at Rathdrum
would result in 200-350 MW of load loss to customers
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throughou t North Idaho and Eas tern Washington. This
project was completed in June of 2004.
.Dry Creek Substation: Avista constructed a new 230 kVsubstation near Clarkston, WA that enabled existing
transmission lines to form a 35-mile transmissionUring" around the Lewiston, ID and Clarkston, WA. The
transmission loop improved reliability by reducing
congestion during heavy load periods and peak energy
flows. The 230 kV Dry Creek switchyard was completed
in December of 2004 and a 200 MVAR capacitor bank
installed in June of 2005 to support area voltage.Avista also added a 250 MVA, 230 kV to 115 kv
autotransformer in November of 2006, to improve load
service and system reliability. The Hatwai-Lolo and
Hatwai-North Lewiston 230 kV lines were also both
upgraded as part of this project to eliminate thermal
loading issues experienced during peak loadconditions.
.Beacon-Bell 230 kV: Avista increased the capacity of
two (2) parallel 230 kV transmission lines in north
Spokane that originate from Avista' s Beacon Substation
and interconnect with Bonneville Power Administration
(BPA) at its Bell Substation. upgrading the capacity
of each line from 400 to 800 MVA mitigated overloads
between Avista and BPA and improved load service to
the entire Avista system. One of the transmission
lines was reconductored and placed into service in
Decemer 2005 and the other line upgraded in April
2007.
.Spokane Valley Reinforcement: Avista added two 250
MVA 230 kV to 115 kV transformers in two stages at the
new Boulder Substation in the Spokane Valley. The
first transformer was placed into commercial operationin December of 2005. The second transformer and
corresponding substation work was energized in June of2007. The Boulder station was constructed to serve
customer load growth in the Spokane Valley, Post
Falls, and Coeur d'Alene. The added capacity atBoulder also relieved congestion at Avista' s largesttransmission substation, Beacon. Shifting load from
Beacon to Boulder improved service adequacy and
overall reliability.
.West of Hatwai (WoH) Telecom and Clark Fork Remedial
Action Scheme (RAS): The ability to communicate with,
moni tor, and control transmission equipment is an
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important factor in providing reliable service to
customers. The WoH Telecom initiative was comprisedof several individual proj ects . Several of thesefiber proj ects required the upgrade of existing
transmission lines in order to support the fiber. The
Noxon-pine Creek fiber project, the Benewah-Boulder
fiber proj ect and the Benewah-Pine Creek Digital
Microwave proj ect completed a telecommunication ring
from Spokane to Noxon Rapids Dam. The ring provides
for redundant communication paths, where the loss of
one side of the ring will not eliminate the ability to
control equipment. The ring is also required to
implement the Clark Fork Remedial Action Scheme (RAS)
that drops generation at Noxon Rapids and Cabinet
Gorge Dams following the loss of critical transmission
circui ts to ensure system reliability. Another
component of the Clark Fork RAS included the addition
of fiber from the Cabinet generation units to the 230
kV Cabinet Substation. The Hatwai-North Lewiston
fiber project completed a fiber ring around the
Lewiston/Clarkston load service area. The Benewah-
Boulder fiber project was placed into service in 2005.
The Hatwai-North Lewiston and Clark Fork fiber
projects were completed and commissioned in 2006. The
Noxon-pine Creek fiber project was commissioned in
Septemer of 2007.
.Palouse Reinforcement: This proj ect involved the
construction of 60 miles of new 230 kV transmission
line between the Benewah and Shawnee substations and
the rebuild of Benewah substation to a more reliableconfiguration. The proj ect was required to relieve
congestion on the existing Benewah-Moscow 230 kV line
by providing a second 230 kV transmission line between
Avista's Northern and Southern. load service areas and
to provide an alternate 230 kV source of power to theShawnee Substation. This project significantly
improves system reliability. The transmission line
portion of the proj ect was completed in three phases
over a two year construction period. All but one
small portion of the proj ect was energized and placed
into service before December 2007. The 200 MVAR
capacitor bank is currently being constructed and will
placed into service by June, 2008.
.LOlo Substation: This project involves the rebuild of
the existing Lolo substation to increase the capacity
of the substation bus, breakers, and supportingequipment to match the upgraded area transmission
lines. The new Lolo substation design significantlyKinney, Di 20
Avista Corporation
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improves reliability and operating flexibility. The
substation rebuild was constructed in two phases.
Phase 1 was completed in 2007 and Phase 2 is
anticipated to be completed by September of 2008.
Q. Did the construction of these new facilities
increase third party transmission revenue received by the
Company from third party transmission users who move power
across Avista' s system?
A.No. These projects were built to improve system
12 reliability, improve area load service, and meet national
13 reliabili ty standards that are now mandatory. In the WoH
14 agreement signed with BPA, Avista preserved its existing
15 transfer capability (600 MW) across the WoH cut-plane and
16 BPA gained the additional transfer capacity that was
17 created.
18 As previously discussed in Section III of my testimony
19 Avista receives third party transmission wheeling revenue
20 from transmission sales made through its OASIS.A
21 comparison of revenue for years 2003 through 2007 show
22 Avista averages $3.354 million per year with a high of
23 $3.573 million in 2003 and a low of 3.129 million in 2005
24 excluding year 2004 ($5.475 million), which was an anomaly
25 due to scheduled BPA transmission outages as previously
26 discussed.This data shows that Avista has not seen a
27 significant increase in transmission revenue after the
28 completion of the upgrade proj ects.The upgrade proj ects
Kinney, Di 21
Avista Corporation
1 reinforced the transmission system internal to Avista¡
2 however,the projects did not create additional
3 transmission capacity to our adjacent utilities.
4 Q.Please discuss the national reliability
5 standards?
6 A.The North American Electric Reliability
7 Corporation (NERC) has developed national reliability
8 standards for utilities to follow to ensure interconnected
9 system reliability.When Avista started its transmission
10 upgrade projects in 2002, compliance with these standards
11 was voluntary. The Energy Policy Act of 2005 required the
12 transi tion of the standards from voluntary to mandatory.
13 Beginning June 2007 the standards became mandatory and non-
14 compliance may result in monetary penalties.
15 The reliability standards include several transmission
16 planning and operating requirements.The planning
17 standards require utilities to plan and operate their
18 transmission systems in such a way as to avoid the loss of
19 customers or impacting neighboring utili ties for the loss
20 of transmission facilities.The transmission system must
21 be designed and operated so that the loss of up to two
22 facili ties simultaneously will have no impact to the
23 interconnected transmission system.These requirements
24 drove the need for Avista to invest in its transmission
25 system.
Kinney, Di 22
Avista Corporation
1
2
V.AVISTA'S ASSET MAAGEM PROGRA
Q.Please provide additional background to Avista' s
3 continuing investment in its transmission and distribution
4 systems?
5 A.Like most U. S. utili ties, after World War II,
6 Avista' s growth required installing or updating equipment
7 to meet rising electrical demand. Substations were built or
8 modified to meet increasing loads. The transmission system
9 expanded to bring new generating plant output to population
10 centers. Distribution systems grew and voltage levels were
11 increased to meet new housing and industrial needs.
12 Avista's installed equipment is aging, and more
13 components are reaching the end of their life. Equipment
14 has become obsolete, and manufacturers no longer support
15 the aged equipment or produce replacement parts, which
16 makes it impractical to rebuild the equipment. Recognizing
17 the increasing cost of aging equipment failure, Avista
18 launched its Asset Management effort in March 2004.
19 Q.Please describe the Asset Management mission and
20 process.
21
22
A.Avista's Asset Management (AM) program manages
key electric transmission and distribution assets
23 throughout their life to provide the best value for our
24 customers. By minimizing life cycle costs and the cost per
Kinney, Di 23
Avista Corporation
1 kilowatt-hour to generate. and deliver energy, we're able to
2 maximize system reliability and value for our customers.
3 The Asset Management process combines technology and
4 information in a manner that integrates data from a myriad
5 of sources into a comprehensive plan that maximizes the
6 value of capital assets.The process provides a
7 replacement or maintenance program that minimizes life
8 cycle costs and maximizes system reliability.
9 Technical experts evaluate each asset and develop a
10 comprehensive Asset Management Model. Available data is
11 examined and where it is not available, expert opinion from
12 the team fills in the gaps. Exhibit No. 10, Schedule 3
13 shows the steps in the process for developing an Asset
14 Management Plan.The foundation for the plan involves
15 determining the future failure rates and impacts to the
16 environment, reliability, safety, customers, costs, labor,
17 spare parts, time, and other consequences.The failure
18 model then becomes the baseline to compare all other
19 options.Given this foundation,alternatives can be
20 examined and evaluated to define the optimal asset
21 management plan.
22 Q.How has Avista implemented and facilitated the
23 Asset Management process?
24 A.Avista has assigned two full-time engineers to
25 the formal Asset Management program. These individuals are
Kinney, Di 24
Avista Corporation
1 responsible for gathering information, prioritizing work
2 and executing efforts to best meet the Asset Management
3 mission.The engineers utilize a statistical Reliability
4 Centered Maintenance (RCM) software package to analyze
5 data.This software allows detailed analysis of the
6 impacts of increased or decreased reliability based on
7 system configuration and component reliability.
8 Q.Have any Avista Asset Management plans been
9 implemented?
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11
A.Yes, several programs have been successfully
implemented.Two of the successful programs underway are
12 Underground Cable Replacement and Wood Pole Management.
13 The Underground Cable Replacement program has
14 successfully reduced the numer of primary underground
15 distribution cable faults from 250 in 2004 to approximately
16 180 events in 2007.The replacement program eliminated
17 approximately 5,600 hours of outage time for our customers
18 and resulted in avoided costs/savings of $175,000.The
19 increased emphasis on cable replacement has stabilized the
20 faul t rate per mile of cable during the past 3 years. This
21 marks significant progress after a four-fold increase in
22 the fault rate since 1992.
23 The Asset Management team also studied the Wood Pole
24 Maintenance program.After completing an optimization
25 analysis and revenue resource requirement model, the data
Kinney, Di 25
Avista Corporation
1 indicated that distribution poles should be inspected on a
2 20-year cycle and transmission poles inspected on a 15-year
3 cycle.
4 Under the new Wood Pole maintenance program Avista
5 tested twice as many Distribution poles in 2007 as in 2006.
6 Increased wood pole inspections identified nearly 200
7 rotten cross-arms that were replaced and also identified
8 addi tional poles that require replacement.The Operations
9 and Maintenance portion of the Avista rate request to
10 support Wood Pole maintenance work in 2009 totals $776,000
11 (system). This represents an increase of $493,000 (system)
12 above the 2007 test year.
13 Q.What is the Company's request with regards to
14 Asset Management capital expenditures and O&M expenses?
15
16
A.Asset Management capital projects for 2008 are
included in our existing capital project funding
17 requirement discussed by Company witness Mr. DeFelice.
18 Avista is not asking for any planned 2009 capital Asset
19 Management additions to be included in this case.
20 For Asset Management proj ects that require additional
21 O&M, proposed 2009 O&M expenses are $3,941,000 (system)
22 compared to 2007 test year expenses of $1,690,000 (system).
23 This represents an increase of $2,251,000 (system) above
24 the 2007 test year included in this rate case. As shown in
25 Table No. 2 below, Asset Management O&M additions have been
Kinney, Di 26
Avista Corporation
1 divided into four major categories:Substation,
2 Distribution, Transmission and Spokane Downtown Network.
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Table No.2:
Substation
Distribution
Transmission
Network
total Additional Requested
Asset Management
Operations & Maintenance
Amount Above 2007 Test Period
(System) Pro forma
453,000
491,000
1,221,000
86,000
2,251,000
$
$
$
$
$
9
10 Q.Please describe Avista's Substation Asset
11 Management Plan.
12 A.Avista operates 157 transmission and distribution
13 substations. A significant portion of the equipment and
14 substation structures are more than 40 years old and have
15 operated beyond normal industry expectations.This older
16 equipment has reached a point in its lifecycle where
17 planned replacement or maintenance will add value to our
18 customers by improving reliability and safety, and avoiding
19 outage costs. Costs to support the Substation maintenance
20 work totals approximately $1,896,000 (system) in the 2009
21 pro forma period. This is an additional $453,000 compared
22 to the 2007 test period.
23 The Substation plan includes:
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.Power Transformers: More than
Substation Transformers are overThese aging transformers need
maintained or replaced depending on
26% of Avista' s40 years old.to be eithercondition.
Kinney, Di 27
Avista Corporation
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. Circuit Breakers: The Power Circuit Breaker Planhas been an ongoing and successful programmaintaining approximately 300 High Voltage Oil
Circuit Breakers prior to establishing an Asset
Management Program. However, Avista has not yet
reached the target of a 10 year Circuit Breaker
maintenance cycle and is currently at a 15 year
cycle. The requested increased funding will allow
more Circuit Breaker maintenance each year.
. Circuit Switchers: Avista uses 120 Circuit
Swi tchers to protect substation transformers at
smaller Substations. Avista' s analysis indicates
periodic maintenance based on the age of the
Circuit Switcher should extend the life of thesedevices by 25% based on a graduated cycle plan
determined by age. It is anticipated that the
program will result in approximately $180,000 of
avoided outage related costs to our customers.
. Reclosers: The Recloser/Medium Voltage Circuit
Breaker plan covers about 415 substation and 145
Line Reclosers/Medium Voltage Circuit Breakers. Our
current maintenance practice strives to sustain theSubstation Reclosers/Medium Voltage Circuit
Breakers on a 10-year cycle and to refurbish any
failed or replaced ones to use as spares for future
needs.
. Rock and Fence: The Substation Rock and Fence plan
covers the maintenance and replacement of Rock andFence for Avista' s 157 substations. Avistaanticipates an average of 4 Substations will
require repairs to the fence or rock ground cover
in order to ensure safety by preventing publicaccess and maintain the required insulating
properties of the Substation Rock. O&M funding is
increased by a relatively small amount for minor
repairs to Rock and Fence above current levels.
. Relays: The Relay plan covers the maintenance and
replacement of over 6000 separate relay hardwaredevices that provide protection for Avista' s
generation, transmission and distribution systems.
Regulatory requirements for relay testing and
record keeping have increased in recent years as
part of new mandatory reliability standards.
Kinney, Di 28
Avista Corporation
1 Q.Please describe Avista' s distribution Asset
2 Management Plan.
3 A.Avista's distribution system includes 324 feeders
4 and over 12,000 miles of conductors, poles, underground
5
6
cable,distribution transformers,and various other
distribution system components.Avista has developed
7 operations and maintenance plans for the distribution
8 system totaling approximately $648,000 for the 2009 Pro
9 forma period. This amount is $491,000 above that included
10 in the 2007 test period.
11 The distribution plan includes:
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. Animal Guards: Data shows that animals are the
second-leading cause of outages at Avista, ranking
second only behind weather, and accounting for 19
percent of all outages. Outages caused by squirrels
and birds are an increasing, on-going and
persistent problem on the distribution system.
Statistics indicate that 60 feeders were the
subj ect of almost half of all animal-caused
outages. Four of those 60 most vulnerable feeders
were recently retrofitted with animal guards.
Animal-caused outages have decreased to almost zero
on all four feeders, compared to 10 or more per
month during warm weather in previous years. Avista
has included additional O&M funding to begin
implementing a four-year program to install animal
guards on the remainder of the 60 most vulnerablefeeders.
. Underground Cable: Over 6 million feet of
unjacketed underground cable was installed prior to
1982 i it has been subject to a replacement programsince 1984. After 2008, there will be
approximately 750,000 feet of pre-1982 cable still
left to be replaced. Though primarily a capital
intensive program, there is some related
maintenance costs associated with undergroundcable.
Kinney, Di 29
Avista Corporation
1 Q.Please describe Avista's Transmission Asset
2 Management Plan.
3 A.The Avista transmission system is comprised of
4 over 2500 miles of lines crossing an extreme variety of
5 terrain. The 976 miles of 230kV transmission system is
6 critical to serving Avista' s customers and to the stability
7 of transmission resources throughout the region. The 115kV
8 system, comprised of 1675 miles, serves Avista customers
9 and neighboring utilities throughout large portions of
10 Eastern Washington and Northern Idaho. Approximately 75% of
11 the transmission system components are over 35 years old. A
12 more rigorous inventory of the 115kV system is underway.
13 Preliminary results of this survey show over 20% of the
14 115kV system is pre-1930. Avista is requesting $1,289,000
15 in Operations and Maintenance funding for support of the
16 transmission system under this proposal. This is an
17 increase of $1,221,000 above the 2007 Operations and
18 Maintenance spending for this area.
19 The transmission plan includes:
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. Compression Sleeve Couplings: The majority of the
230kV system was installed in the late 1950s and
early 1960s. A critical component of the conductor
system is ucompression sleeve couplings" that join
together sections of conductor. These couplings are
beginning to fail. Technology now exists to test
the integrity of the couplings far more reliably
than with visual inspections. Avista plans to
implement a planned inspection and replacement
program and anticipates replacing or repairing 15%
of the total population.
Kinney, Di 30
Avista Corporation
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47 Plan.
. Fire Retardant Coatinqs for Transmission Poles:
Random fires can have a significant impact on the
reliabili ty of Avista' s transmission system. During
the past five years, Avista has lost at least 60
wooden poles to brush fires. Protective coatings
are now available that can protect wood poles for20 minutes, or more, from close contact with
flames. The coating is especially effective against
brush fires. A neighboring utility has used the
coating and reported 80% survival rate of wood
poles in situations where 20% survival would havebeen more typical. Avis ta proposes a four-year
program to apply fire retardant coating to critical
transmission lines in high fire areas.
. Painting of Steel Transmission Structures: The
Avista transmission system was primarily built with
wood pole structures prior to the 1990s. However,
some critical structures were constructed of
painted steel and installed in the early 1970s.
These structures need more protective paint to
prevent corrosion. These older steel poles are
different from new steel poles that do not require
protective paint because they were designed and
built to have a rustic look to improve aesthetics.
The first priority is to repaint an important 230kV
line known as the Westside Tap located in the
northwest part of Spokane. The structures are
showing rust over a larger portion of their surface
area. It is imperative that these structures be
maintained to prevent further corrosion and loss ofstructural integrity.
. Steel Tower Base Plate Grout: An important
component for structural integrity of steel
transmission towers is the interface between thetower and the foundation. Most large steel
transmission structures utilize a base plate that
requires grout between the steel structure and the
foundation to provide solid surface area for
transfer of loads to the foundation. The grout can
deteriorate from freeze-thaw cycles and requires
periodic maintenance. Avista plans to inspect and
repair the grout.
Q. Please describe Avista's Network Asset Management
Kinney, Di 31
Avista Corporation
1 A.The Network consists of an underground
2 distribution system that feeds the core of downtown Spokane
3 the region's economic hub with a very reliable
4 networked distribution system.The Network includes
5 underground vaul ts,manholes,handholes,substations,
6 network protectors, network trans formers, and numerous
7 miles of duct banks and cables.The structural integri ty
8 of these vaults, manholes and handholes is vital to public
9 safety because they are typically located under heavily-
10 used streets and sidewalks. Reliability is also essential,
11 because the Network serves the businesses, banks and other
12 critical services located in downtown Spokane.The
13 Operations and Maintenance portion of the Avista rate
14 request to support Network maintenance work totals
15 approximately $108,000. This represents an increase of
16 $86,000 between the 2009 pro forma period maintenance
17 expenses and the 2007 test year.
18 The Network plan includes inspecting and maintaining
19 an aging system:
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. Vaults: Almost 60% of the vaults are more than 50
years old. Avista plans to add inspection of vacant
vaults and additional maintenance activities such
as vault cleanings to prevent debris build-up and
fire hazards. When necessary an entire vault will
need to be replaced wi th a new one.
. The Manholes/Handholes: Nearly 98% of manholes are
approaching 100 years of age. Avista plans to
inspect them on a five-year cycle and perform
maintenance based on the results of the
Kinney, Di 32
Avista Corporation
1
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5
inspections. Replacement of manholes and handholes
may also be required.
Q. Has Avista completed all of its Asset Management
6 Plans?
7 A.No. While Avista has developed multiple Asset
8 Management Plans,some of the plans have not been
9 implemented. Much of the work to date involved development
10 of the processes, skills, and expertise needed to develop
11 the plans. As additional data is gathered and analyzed, the
12 plans will continue to be refined to maximize system
13 reliability and cost effectiveness.
14 Q.Does this complete your pre-filed direct
15 testimony?
16 A.Yes, it does.
Kinney, Di 33
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT, GENERA COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
6"flmi lI
DO ., ""
REGULAT R' f,&¡1 -.: tfii: 05
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-08-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AN CHARGES FOR ELECTRIC AN )
NATURA GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 10
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO ) SCOTT J. KINNEY
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avista Corporation
. Energy Delivery .
Pro Forma Transmission Revenue/Expenses
($OOOs)
2009
Line 2007 Pro Forma
No.Actual Period Adjusted
556 OTHER POWER SUPPLY EXPENSES
NWPP 31 31 0
560-71.4,935.3-.4 TRANSMISSION O&M EXPENSE
2 Colstrip O&M - 500kV Line 459 631 172
3 Columbia Grid Development 249 249 0
4 Columbia Grid Planning 51 123 72
5 Grid West (10)71 71 0
6 Total Account 560-71.4,935.3-.4 830 1,074 244
561 TRANSMISSION EXP-LOAD DISPATCHING
7 Elect Sched & Accg Srv (CASSO/OATI)212 160 -52
566 TRANSMISSION EXP-OPRN-MISCELLANEOUS
8 OASIS Expenses 2 6 4
9 WECC - Sys. Security Monitor 98 171 73
10 WECC Admin & Net Oper Comm Sys 217 282 65
11 WECC - Loop Flow 25 27 2
12 Total Account 556 342 486 144
13 TOTAL EXPENSE 1,415 1,751 336
456 OTHER ELECTRIC REVENUE
14 Borderline Wheeling 5,203 5,218 15
15 * Seattle 641 0 -641
16 * Tacoma 641 0 -641
17 SeattlelTacoma Main Canal 0 46 46
18 Seattle/ Tacoma Summer Falls 0 74 74
19 Grand Coulee Project 8 8 0
20 OASIS nf & stf Whl (Other Whl)3,336 3,354 18
21 PP&L - Dry Gulch 252 276 24
22 ** PP&L Series Cap -1978 9 5 -4
23 Spokane Waste to Energy Plant 160 160 0
24 Vaagen Wheeling 110 112 2
25 *** Northwestern Energy 231 0 -231
26 Total Account 456 10,591 9,253 -1,338
27 TOTAL REVENUE 10,591 9,253 -1,338
28 TOTAL NET EXPENSE -9,176 -7,502 1,674
* Seattle and Tacoma - contracts ended 10/31/07
** PP&L Series Cap - contract ended 6/30/09
*** Northwestern Energy - contract ended 11/30/07
Exhibit NO.1 0
Case No. AVU-E-08-1
S. Kinney, Avista
Schedule 1, pg 1
230 kV Upgrade Project
Project Milestones & Forecasted Cost
::----
=:
March 2008
Avist 23 kV""",
Be-Rathdmm 23 l2 MI. $20.0M
25 mile Beaon-Rathdrm line, Mar 200
Ratdrm Sub, Recnstrct to DBIDB, Apr 200
Fully Commioned .June 200
Wesde i
Bea-Bel 23 (160 MID. $5.1M
Bell #4 Upgre to 800 MW, De 2005
Bell #5 Upgre to 800 MW, Apr 2007
Fuly Commssioned April 2007
Rathdmm
Spo val Reinformet (S MW) S2
Boulder Substaon, West 115 kV Bus, Jun 2005
Boulder Substation, Eat 115 kV Bus, Se 205
230 and 115 kV Trasmission lines, Oc 2005
23011 i 5 Autotrsforer #2, Jun 20
Fully Commioned July 200
Pi Sution $47M
Recnstrct 230 kV Substaon
Fully Comioned Noyember 20Benewah
Paou 23 Upg (1N MI. SSAM
Benewah 230 kV DBIDB Substaon, Noy 20
8 mile Colfax-Shawnee 230 kV line, Nov 20
26 mile Rosalia-Colfax 230 kV li, Aug 200
26 mie Benewah-Rosaia 230 kV line, Nov 200
Benewah 200 MVar Caactor Ban June 2008
Fully Commoned .June 2008
Shawn
N.Leiston
Dry Crek
Transmission Line
. - New or Upgraded
Mos 23 Dr Crek (20 MW I 20 MY)' $14M
Dr Crek 230 kV DBIDB Substaon, De 200
Hatai-Lolo Upgr to 800 MW, May 205
Dr Crek 230 kV Capacto Ban Jun 2005
Hatai-N. Lewiston Upgre to 710 MW, Mar 20
230115 Autotrsformer, Aug 200
Fully Commioned Octber 200
Lo 23 kV Rebu $2.9 M
Phas i Rebuild - De. 200
Phas 2 Rebuild - Se. 200
Fuly Commioned Septmber 208
Ot 23 kV Upg Prjec Ço
Reme Acton Sceme (R) SI.lMDita Communcation $8.2
Ass Communcation Prjec $UM
Tota Prjec Upges ------ $1364M Exibit No. 10
Ca No. AVU-E-08-1
S. Kiey, Avista
Schedule 2, pg. i
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