20090123Kinney Direct.pdf

C::E1\l '0
DAVID J. MEYER
VICE PRESIDENT AN CHIEF COUNSEL OF
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
Z009 23 pr112: 43
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AN
NATURAL GAS SERVICE TO ELECTRIC
AN NATURA GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-09-01
DIRECT TESTIMONY
OF
SCOTT J. KINNEY
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
1
2
I. INTRODUCTION
Q.Please state your name, emloyer and business
3 address.
4 A.My name is Scott J. Kinney.I am employed by
5 Avista Corporation as the Director of Transmission
6 Operations.My business address is 1411 East Mission,
7 Spokane, Washington.
8 Q.Please briefly describe your education background
9 and professional experience.
10
11
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
Bonneville Power Administration.I have held several14
15 different positions in the Transmission Department.I
16 started at Avista as a Senior Transmission Planning
17
18
Engineer.In 2002, I moved to the System Operations
Department as a supervisor and support engineer.In 2004,
19 i was appointed as the Chief Engineer, System Operations.
20 In June of 2008 I was selected to my current position as
21 Director of Transmission Operations.
22
23
24
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
25 Transmission and Distribution expenditures that are part of
Kinney, Di i
Avista Corporation
1 the capital additions testimony provided by Company witness
2
3
Mr. Dave DeFelice,as well as the Company's Asset
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.
8
9
10
Q.Are you sponsoring any exhibits?
A.Yes.I am sponsoring Exhibit 8, Schedules 1 and
2.Schedule 1, provides the transmission pro forma
11 adjustments and Schedule 2, includes the Asset Management
12 Program Model.
13
14
II. PRO FORM TRASMISSION EXPENSES
Q.Please describe the pro form transmission
15 expense revisions included in this filing.
16
17
A.Adjustments were made in this filing to
incorporate updated information for any changes in
18 transmission expenses from the October 2007 to Septemer
19 2008 test year to the July 2009 to June 2010 Pro forma
20 period.Each expense item described below is at a system
21 level, with the exception of the $71,000 Grid West
22 adjustment which is Idaho only, and is included in Exhibit
23 8, Schedule 1.
24 Northwest Power Pool (NWPP) - Avista pays its share
25 of the NWPP operating costs. The NWPP serves the utilities
Kinney, Di 2
Avista Corporation
1 in the Northwest by providing regional transmission
2 planning, coordinated transmission operations, and Columia
3 River water coordination.There is no anticipated change
4 in NWPP costs in the pro forma period compared to the
5 2007/2008 test year actual expense of $31,000.
6 Colstrip Transmission - Avista is required to pay its
7 portion of the O&M costs associated with the Colstrip
8
9
transmission system pursuant to the j oint Colstrip
contract.In accordance wi th Northwes tern Energy's (NWE)
10 proposed Colstrip transmission plan provided to the
11 Company, NW will bill Avista $508,000 for Avista' s share
12 of the Colstrip O&M expense during the pro forma period.
13 This is a decrease of $82,000 from the actual expense of
14 $590,000 incurred during the test year.
15 ColumiaGrid (RTO Development)In 2006, Avista
16 elected to fund the ColumiaGrid RTO development effort.
17 ColumiaGrid is a regional organization whose purpose is to
18 enhance transmission system reliability and efficiency,
19 provide cost-effective regional transmission planning,
20 develop and facilitate the implementation of solutions
21
22
relating to improved use and expansion of the
interconnected Northwest transmission system,reduce
23 transmission system congestion, and support effective
24 market monitoring within the Northwest and the entire
25 Western interconnection.Under the amended ColumiaGrid
Kinney, Di 3
Avista Corporation
1 funding agreement signed Septemer 1, 2006, Avista was
2 responsible for a total of $518,000, which represents
3 Avista' s share of the ColumiaGrid operating costs from
4 2006 through August 31, 2008.Prior to the amended
5 agreement, Avista paid $104,000 of these costs.The
6 remaining balance ($414,000) was accrued over the remaining
7 20 months of the agreement at a monthly rate of $20,720.
8 Avista signed a 2 year general funding extension in
9 Septemer 2008.Under the new agreement Avista pays its
10 share (10.03%) of the general ColumiaGrid expenses on a
11 monthly basis.Based on information provided by
12 ColumiaGrid, Avista expects to pay a monthly fee of
13 $20,000 though the 2 year extension.Therefore, the
14 ColumiaGrid cost for the pro forma period is anticipated
15 to be approximately $240,000 annually, which is $22,000
16 more than the actual costs of $218,000 paid during the test
17 period.
18
19
ColumiaGrid Planning -An additional service being
provided by ColumiaGrid is regional planning and
20 expansion. A functional agreement was developed and filed
21 with the Federal Energy Regulatory Commission (FERC) on
22 February 2, 2007 and approved on April 3, 2007.The
23 agreement does not have a termination date and funding is
24 on a two-year cycle with provisions to adjust for
25 inflation.Funding is based on a fixed amount, plus a
Kinney, Di 4
Avista Corporation
1 portion is based on Avista' s load ratio compared to the
2 other memers.ColumiaGrid provided the Company with
3 anticipated costs of $15,000 per month in the pro forma
4 period to support the ColumiaGrid planning effort going
5 forward.This equates to $180,000 during the pro forma
6 period, which is $76,000 over the test year actual costs.
7 ColumiaGrid Developmental and Staffing Reliability
8 Functional Agreement - During 2007 and 2008 ColumiaGrid
9 began an effort to evaluate opportunities to improve or
10 enhance reliability in the ColumiaGrid footprint.This
11 effort included expanding the existing regional coordinated
12 outage management process,evaluating combining
13 transmission control centers into a consolidated control
14 center, improved system modeling, and exploring new market
15
16
products.The ColumiaGrid members agreed to fund this
evaluation effort through the end of 2008.The remaining
17 work associated with this proj ect has been rolled into the
18 general funding agreement so Avista will not incur any
19 costs associated directly with this effort during the pro
20 forma period.Avista did fund $45,000 of this effort in
21 the test year.
22 ColumiaGrid Open Access Same-Time Information System
23 (OASIS)A new service currently being developed by
24 ColumiaGrid and its members is the development of a common
25 Open Access Same-Time Information System (OASIS).This
Kinney, Di 5
Avista Corporation
1 service would provide transmission customers the ability to
2 purchase transmission capacity from all ColumiaGrid
3 members from one common OASIS site instead of having to
4 purchase transmission from each memer individually.The
5 ColumiaGrid memers have signed a contract to evaluate and
6 develop this service. Avista' s portion of the development
7 cost is expected to be $100,000 during the pro forma
8 period. Avista didn' t have any costs associated with this
9 effort during the test period.
10 Grid West (ID Direct)Included in transmission
11 expense is an annual amount of $71,000 to recover costs
12 associated with Grid West (and its forerunner, RTO West).
13 Avista signed an initial funding agreement in 2000, as did
14 all other Pacific Northwest investor-owned electric
15 utilities, to provide funding for the start-up phase of
16 Grid West (then named "RTO West").Grid West had planned
17 to repay the loans to Avista and other funding utili ties
18 through surcharges to customers once it became operational.
19 with the dissolution of Grid West, this repayment did not
20 occur.As a result, Avista filed an application with the
21 Commission to defer these costs. The Commission approved,
22 on October 24, 2006, in Order No. 30151, the Company's
23 request for an order authorizing deferred accounting
24 treatment for loan amounts made to Grid West. In its Order
25 the IPUC found these costs to be "prudent and in the public
Kinney, Di 6
Avista Corporation
1 interest" and required the Company to begin amortization of
2 the Idaho share of the loan principal ($422,000) beginning
3 January 2007, for five years. During the pro forma period
4 Avista will amortize a total of $71,000 associated with
5 Grid West development costs.
6 Electric Scheduling and Accounting Services The
7 $55,000 decrease in the pro forma period compared to test
8 year expense for electric scheduling and accounting
9 services is a result of continued reductions in services
10 provided by third party vendors.These services are no
11 longer required because of the development of an internal
12 accounting program and the development of a regional
13 transmission interchange tool by the Western Electricity
14 Coordinating Council (WECC). These new applications replace
15 the services provided by third parties.
16 Grant County Agreement -This will be discussed in
17 more detail in conjunction with the Seattle and Tacoma
18 revenues associated with the Main Canal and Sumer Falls
19 Projects.This agreement expired in October 2007 so no
20 additional costs will be incurred in the pro forma period.
21 In the test year Avista paid Grant County $51,000 per this
22 agreemen t .
23 OASIS Expenses The Open Access Same-Time
24 Information System (OASIS) expenses are associated with
25 travel and training costs for transmission pre-scheduling
Kinney, Di 7
Avista Corporation
1 and OASIS personnel.This travel is required to moni tor
2 and adhere to the NERC reliability standards and FERC OASIS
3 requirements. The costs associated with OASIS expenses in
4 the pro forma period is $3,000 more than the test year.
5 The increase is a result of training required for a new
6 employee who replaced a retired employee in October 2008.
7 Power Factor Penalty - The power factor penalty costs
8 are associated with Bonneville Power Administration's (BPA)
9 General Transmission Rate Schedule.BPA charges a power
10 factor penalty at all interconnections with Avista that
11 exceed a given threshold for reactive power flow during the
12 month. If the reactive flow from BPA's transmission system
13 into Avista' s system or from Avista' s system to BPA's
14 system exceeds a given threshold then' BPA bills Avista
15 according to its rate schedule. The charge includes a 12
16 month rolling ratchet payment. Avista currently pays BPA a
17 power factor penalty at several interconnections.Avista
18 paid BPA a total of $178,000 during the test year and
19 anticipates paying a similar amount in the pro forma period
20 based on the ratchet clause in the rate schedule.
21 WECC - System Security Monitor & WECC Administration
22 and Net Operating Committee Systems - The total WECC fees'
23 have and will continue to increase from year to year. The
24 increase is driven primarily by compliance with mandatory
25 national reliability standards.WECC is responsible for
Kinney, Di 8
Avista Corporation
1 monitoring and measuring Avista's compliance with the
2 standards and therefore has substantially increased its
3 staff and other resources to meet this FERC requirement.
4 WECC is just beginning to develop its 2010 budget, so 2009
5 actual fees will be used for the pro forma period.The
6 WECC fees are paid in the first part of January every year.
7 WECC System Security Monitor fees in 2009 are $159,000
8 compared to test year fees of $171,000.This slight
9 decrease is the result of the completion of a significant
10 effort with regards to regional reliability coordination in
11 2008. The WECC Administrative and Net Operating fees have
12 been increased from $282,000 in 2008 to $329,000 for 2009.
13 WECC - Loop Flow -LOOp Flow charges are spread
14 across all transmission owners in the West to compensate
15 utilities that make system adjustments to eliminate
16 transmission system congestion throughout the operating
17 year.Loop Flow charges can vary from year to year since
18 charges are dependent on transmission system usage and
19 congestion.Therefore a five year average is used to
20 determine future Loop Flow costs. The Loop Flow charge in
21 the pro forma period is expected to be $26,000.This is
22 $10,000 higher than actual test year charges of $16,000.
Kinney, Di 9
Avista Corporation
1 III. PRO FORM TRASMISSION RENUS
2 Q.Please describe the pro forma transmission
3 revenue revisions included in this filing.
4 A.Adjustments were made in this filing to
5 incorporate updated information for any changes in
6 transmission revenue from the 2007/2008 test year compared
7 to the 2009/2010 Pro forma period.Each revenue item
8 described below is at a system level and is included in
9 Exhibi t 8, Schedule 1.
10 Borderline Wheeling - The Borderline Wheeling revenue
11 in the pro forma period is set at $5,354,000, which is a
12 three year average of the 2006, 2007, and 2008 actual
13 revenue levels.Actual test year revenue was $5,375,000.
14 Avista typically uses a five year average of actual annual
15 revenue to estimate future Borderline Wheeling revenue.
16 This helps levelize the revenue requirement since it is
17 based on load demand that is sensitive to temperature
18 variation from year to year.For this case Avista is only
19 using a three year average since 2006, 2007 and 2008 are
20 the only years operating under new contracts signed with
21 BPA.The new Borderline Wheeling revenue methodology is
22 based on a Load Ratio Share1, which is quite different than
1 Load Ratio Share is the ratio of a Tranmission Customer's Network Load to the Tranmission
Provider's total load calculated on a rolling twelve-month basis.
Kinney, Di i 0
Avista Corporation
1 the previous revenue calculation under the old contracts.
2 Under the new contracts, BPA, as the network customer, will
3 pay a monthly demand charge, which will be determined by
4 multiplying its Load Ratio Share times one twelfth (1/12)
5 of the Transmission Provider's annual transmission revenue
6 requirement.
7 Seattle and Tacoma Revenues and Expenses Associated
8 with the Main Canal and Sumer Falls Pro; ects - In March
9 of 2006, Seattle and Tacoma purchased interim long-term
10 firm point-to-point transmission service from Avista under
11 the Open Access Transmission Tariff to move generation from
12 their Main Canal and Sumer Falls facilities to their load.
13 These interim point-to-point transmission contracts
14 replaced expired long-term contracts. The transmission was
15 purchased from April 2006 through October 2007.Avista
16 collected $128,000 in October 2007 under these contracts
17 and in turn paid $51,000 to Grant County PUD for use of its
18 system to transfer the entire output of the Main Canal and
19 Sumer Falls proj ects. The interim contracts were meant to
20 give Seattle and Tacoma time to build new transmission
21 facilities to bypass Avista and. connect directly to BPA.
22 Pursuant to negotiations among Seattle, Tacoma, Grant
23 County PUD, Grand Coulee Project Hydroelectric Authority
24 and Avista, Seattle and Tacoma decided not to bypass
25 Avista' s transmission system. The parties agreed instead,
Kinney i Di i i
Avista Corporation
1 to a series of long term agreements with service to
2 commence March 1, 2008.Seattle and Tacoma have signed
3 similar contracts with Grant County PUD so Avista will not
4 incur any of the transmission expenses with Grant County
5 PUD that it did in 2007.Under the new Main Canal
6 agreement Avista charges Seattle and Tacoma during the
7 eight months the Main Canal project runs (March-October)
8 and only for that output not used for local load service.
9 The estimated revenue from Seattle and Tacoma for Main
10 Canal transmission usage will be $193,000, which is $38,000
11 more than collected during the test year.Under the new
12 Sumer Falls agreement, Seattle and Tacoma only use a
13 portion of Avista' s Stratford Switching Station and are
14 charged a use-of-facilities fee based upon this limited
15 use.The estimated revenue from Seattle and Tacoma for
16 Sumer Falls during the pro forma period is $74,000, which
17 is $31,000 higher than actual test year revenue of $43,000.
18 The increase revenue from these two contracts in the pro
19 forma period compared to the test year is a result of
20 additional transmission usage by Seattle and Tacoma.
21 Grand Coulee Pro; ect Revenue The Grand Coulee
22 Project revenue is a result of a new contract signed in
23 March 2006 with the project owner for a fixed dollar
24 amount, replacing the previous contract which expired in
25 October 2005. The new contract results in monthly revenue
Kinney i Di 12
Avista Corporation
1 of $673 or annual revenue of $8,100 during the pro forma
2 period, which is the same as the test year.
3 OASIS Non-firm and Short-term firm Wheeling Revenue -
4 OASIS is an acronym for Open Access Same-time Information
5 System.This is the system used by utility transmission
6 departments for purchasing and scheduling available
7 transmission for other utilities and independen t
8 generators.OASIS revenues are revenues received from the
9 sale of transmission capacity to third parties,for
10 transmission above and beyond that needed by Avista to
11 serve native load.These revenues are credited back to
12 customers in a rate case, such as this one, to offset a
13 portion of the overall cost of transmission.
14 Because these revenues vary year to year depending on
15 electric energy market conditions and available
16 transmission capacity (ATC) on adjacent utility systems,
17 Avista has, in previous rate cases, used the most recent
18 five-year average as being representative of future
19 expectations unless there are known events or factors that
20 occurred during the period that would cause the average to
21 not be representative of future expectations.In 2004,
22 there were some unusual events that caused Avista' s OASIS
23 revenues ($5,475,000) to be significantly higher than the
24 other test years.
Kinney, Di 13
Avista Corporation
1 The Bonneville Power Administration (BPA) had several
2 500 kV lines out of service for rebuild proj ects, which
3 resulted in a significant increase in Avista' s transmission
4 sales in 2004. During 2004 BPA was constructing a new 500
5 kV line from Bell substation in Spokane to Grand Coulee Dam
6 in central Washington, installing fiber optic cable on
7 existing transmission lines,and ins tal ling new and
8 upgrading existing series capacitor banks on four of its
9 area 500 kV lines as part of the West of Hatwai
10 reinforcement proj ect.This construction resulted in
11 multiple prolonged transmission outages that significantly
12 reduced the BPA ATC on critical transmission paths from
13 eastern Montana.Avista owns rights and facilities in
14 these same transmission paths so Avista experienced a
15 significant increase in transmission sales and revenues
16 during the BPA outages.
17 Therefore, Avista did not include the 2004 revenue in
18 the calculation of the five-year average revenue. Avista
19 calculated the pro forma OASIS revenue based on revenue
20 from years 2003, 2005, 2006, 2007, and 2008. The resulting
21 average revenue is $3,310,000, which is $201,000 higher
22 than the test year actual revenue of $3,109,000.
23 Dry Gulch Revenue Dry Gulch revenue has been
24 adjusted to $269,000 for the pro forma period, which is an
25 $11,000 increase from the test year actual revenue of
Kinney i Di 14
Avista Corporation
1 $258,000.The current methodology used to forecast Dry
2 Gulch revenue is a five-year average of actual revenue. A
3 five-year average is used since the revenue can vary from
4 year to year.The revenue is calculated using a 12-month
5 rolling ratchet based on monthly peak demands. Load peaks
6 are very sensitive to temperatures, which vary from year to
7 year.
8 PP&L Series Cap - 1978 - PP&L Series Cap revenue was
9 reduced from $9,000 in the test year to $0 in the pro forma
10 period since the 20 year amortization of the original
11 contract expires in June 2009. In 1989 Pacificorp paid the
12 company a lump sum of $178,222 in lieu of annual payments
13 provided for under the original agreement.The lump sum
14 payment was amortized at $781 per month from August 1990
15 through June 2009.
16 Spokane Waste to Energy Plant -No adjustments to
17 Spokane Waste to Energy Plant revenue of $160,000 were made
18 for the pro forma period compared to the 2007 test year.
19 This revenue is the result of a long-term transmission
20 interconnection agreement with the City of Spokane.The
21 contract expires in February 2011.
22 Vaagen Wheeling - Vaagen Wheeling revenue was reduced
23 slightly to $112,000 for the pro forma period compared to
24 test actual revenue of $116,000. A five-year average is
25 used to determine the pro forma period revenue since
Kinney, Di 15
Avista corporation
1 revenue can fluctuate year to year depending upon
2 transmission usage.
3 Northwestern Energy (NWE)The revenue of $42,000
4 from NWE in the test year was a result of a load following
5 contract that Avista signed in 2005 with NW.Under the
6 contract Avista provides up to 15 MW of energy to NW to
7 help them match hourly fluctuations in loads and resources.
8
9
contract also included the purchase of firmThis
transmission capacity from Avista.Since the contract
10 expired in November of 2007 there isn' t transmission
11 revenue associated with the contract in the pro forma
12 period.
13
14
15
16
Forfeited Deposits - Avista was reimbursed $40,000
period to conduct generationduringthetest
interconnection planning studies.Avista is required to
based on generationimpactsdeterminesystem
17 interconnection requests to implement generation within its
18 service terri tory.Any potential customer can ask for a
19 system evaluation to be performed to determine the impacts
20 of connecting a new generator to the Avista system.The
21 potential customers must reimburse Avista for these system
22 studies.Since Avista can' t predict when these requests
23 will occur, the Company is not forecasting any collection
24 of interconnection study fees in the pro forma period.
Kinney, Di 16
Avista Corporation
1
2
iv. TRASMISSION AN DISTRIBUTION CAPITAL PROJECTS
Q.Please describe the Company's capital
3 transmission projects in 2009?
4 A.In 2007 the Company completed its 5-year (2003-
5 2007) $136.4 million transmission upgrade project that
6 significantly improved the infrastructure of the 230 kV
7 transmission system. with the completion of these projects
8 the transmission project focus has shifted to improving the
9 115 kV transmission system to meet capacity needs,
10 eliminate thermal loading issues, replace deteriorated
11 equipment, and meet mandatory national reliability standard
12 requirements.Avista will need to continue to invest in
13 its transmission system going forward to maintain reliable
14 customer service and meet the reliability standards.A
15 recent report prepared by The Brattle Group for the Edison
16 Foundation describes the future investment challenge that
17 is facing the utility industry.The report describes how
18 utilities will need to continue replacement of aging
19 equipment while construction costs continue to increase.
20 In order to integrate renewable energy alternatives and
21 incorporate intelligent grid controls utilities will be
22 required to increase capital spending on both Transmission
23 and Distribution systems.
24 The major capital transmission costs (system) for
25 projects to be completed in 2009 are approximately $15.07
Kinney, Di 17
Avista Corporation
1 million for specific transmission projects and transmission
2 system equipment replacement projects.The specific
3 transmission projects scheduled for 2009 completion will
4 cost $9.18 million and include:
5 . Lolo Substation ($2.05 million): This project involves
6 the rebuild of the existing Lolo substation to
7 increase the capacity of the substation bus, breakers,
8 and supporting equipment to match the upgraded area
9 transmission lines. The new Lolo substation design10 significantly improves reliability and operating
11 flexibility. The substation rebuild is being12 constructed in three phases. phase 1 was completed in13 2007 and Phase 2 is anticipated to be completed by14 December of 2009. Approximately $0.80 million of work15 was completed in 2008 and will be transferred to plant
16 in 2009 with the additional estimated amount of $1.2517 million.
18
19 . Spokane/Coeur d i Alene area relay upgrade phase 220 ($1.25 million): This project involves the21 replacement of older protective 115 kV system relays22 with new micro-processer relays to increase system23 reliability by reducing the amount of time it takes to24 sense a system disturbance and isolate it from the25 system. This is a five year project and is required
26 to maintain compliance with mandatory reliability27 standards.
28
29 . Power Circuit Breakers ($0.54 million): The Company30 transfers all circuit breakers to plant upon receiving
31 them. In 2009 the Company will receive and replace 432 circuit breakers in its system.
33
34 . SCADA Replacement ($0.74 million): The System Control
35 and Data Acquisition (SCADA) system is used by the36 system operators to monitor and control the Avista
37 transmission system. The SCADA system will be38 upgraded in 2009 to a new version provided by our
39 SCADA vendor. Several Remote Terminal units (RTUs)40 located at substations throughout Avista' s service41 territory will also be replaced. The RTUs are part of42 the transmission control system.
43
44 . Noxon-pine Creek Fiber ($0.65 million): This project
45 is required to reinforce the optical fiber wire
Kinney, Di 18
Avista Corporation
1 supported by the Noxon-pine Creek 230 line. This line
2 routes through the mountains of north Idaho and is
3 subj ected to severe winter weather. Operational
4 history has demonstrated a need to reinforce the
5 communication circuit. This communication circuit is
6 part of the Noxon/Cabinet WECC certified RAS scheme
7 and is required to meet reliability standards.
8
9 . System Replace/install Capacitor Bank ($0.80 million) :10 This proj ect includes the construction of a 115 kV11 capaci tor bank at Airway Heights ($0.60 million) to12 support local area voltages during system outages.13 The project is required to meet reliability compliance14 and provide improved service to customers. Another15 $0.20 million will be spent to replace leaking or old16 capacitors on the Avista system.
17
18 . Benewah-Shawnee 230 kV Line Construct ($0.56 million) :19 This work is necessary to increase separation between
20 the 230 kV and 115 kV conductors on this double
21 circui t line. The lines have contacted each other22 during high winds resulting in line outages. In23 addition to line work to increase phase clearance,
24 Avista plan to install a Hathaway-traveling wave25 monitoring system to allow better accuracy of phase to26 phase contacts. The 230 kV line was constructed to27 meet reliability standard requirements.
28
29 . Mos230-Pullman 115 Reconductor ($0.59 million): The30 transmission line is being upgraded from 1/0 Copper to
31 556 kcm Aluminum (100 MVA-Sumer) to mitigate thermal
32 overloads experienced during heavy sumer load33 conditions. The line upgrade will improve load
34 service between Moscow and Shawnee.
35
36 . Burke 115 kV Protection and Metering ($0.53 million) -37 This project includes upgrading the Burke interchange38 meters as well as 115 kV line relaying for the Burke-39 pine Creek #3 and #4 lines. This proj ect is required
40 to meet reliability compliance standards. The41 estimated cost of the relay upgrade is for $400,00042 and the metering upgrade is estimated at $125,000.
43
44 . Beacon Storage Yard Oil Containment ($0.53 million):45 The Beacon Storage Yard is a location where circuit46 breakers and power transformers are staged for47 rotation into existing substations or for new48 construction. This site is near the Spokane River and
Kinney, Di 19
Avista corporation
1 this proj ect work will provide an oil containment
2 system to protect the local environment.
3
4 . The remaining transmission specific proj ects ($0.94
5 million total) being constructed in 2009 are smaller6 proj ects, including a line reconfiguration to provide
7 back up service, minor work associated with Colstrip
8 transmission, and re-insulating a 230 kV line due to
9 failing insulators. These smaller projects are10 required to operate the transmission system safely and11 reliably.
1213 The Company will also spend approximately $5.89 million in
14 transmission system equipment replacements associated with
15 storm damage or aging/obsolete equipment.A brief
16 description of the larger proj ects included in these
17 replacement efforts are given below.
18
19 . Transmission Minor Rebuilds ($1.07 million): These20 projects include minor transmission rebuilds as a21 result of damage caused by storms, wind, fire, and the22 public.
23
24 . System Rebuild Transmission Condition ($0.9325 million) : This proj ect includes transmission lines
26 that are determined to have a high probability of27 falling down or be a high reliability risk and need to28 be rebuilt during 2009. For example one specific29 project identified for a rebuild in 2009 includes30 sections of the Addy-Gifford 115 kV line.
31
32 . Interchange and Borderline Metering Upgrades ($0.6433 million): Interchange metering upgrades are required
34 for all of our interchange points with BPA and other
35 adjacent utilities. In 2009, we will complete
36 metering upgrades at westside, Warden, and Noxon
37 Substations. Borderline metering upgrades are
38 required for all loads within Avista's Balancing39 Authority. In 2009, we will complete our upgrades at
40 Mead and Noxon (230-13 kV) as well as one additional41 upgrade at either Deer Park, Priest River, Loon Lake,42 Spirit, or Wilbur.
43
Kinney, Di 20
Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
.pine Creek - Replace 115 kV Circuit Switcher & CapBank ($0.35 million): The proj ect scope andpreliminary engineering design work for this proj ect
was started in 2008 and included replacing the circuit
switcher and one 13 kV recloser due to equipment age.
After further investigation the project was expanded
to replace the other two 13 kV reclosers, the cap
bank, deteriorated station control wiring, and removal
of the small panel house including the obsolete RTU.
.Replacement Programs ($2.23 million): Avista has
several different equipment replacement programs to
improve reliability by replacing aged equipment that
is beyond its useful life. These programs include
transmission air switch upgrades, arrestor upgrades,
restoration of substation rock and fencing, recloserreplacements, replacement of obsolete circui t
switchers, substation battery replacement, porcelain
cutout replacement, high voltage fuse upgrades, and
replacement of fuses with circuit switchers. All of
these individual projects improve system reliabilityand customer service.
Q.Please discuss the national reliability
25 standards?
26 The North American Electric Reliabili tyA.
27 Corporation (NERC) has developed national reliability
28 standards for utili ties to follow to ensure interconnected
29 system reliability.When Avista started its transmission
30 upgrade projects in 2002, compliance with these standards
31 was voluntary. The Energy Policy Act of 2005 required the
32 transition of the standards from voluntary to mandatory.
33 Beginning June 2007 the standards became mandatory and non-
34 compliance may result in monetary penal ties.
35 The reliability standards include several transmission
36 The planningplanning and operating requirements.
37 standards require utilities to plan and operate their
Kinney i Di 21
Avista Corporation
1 transmission systems in such a way as to avoid the loss of
2 customers or impacting neighboring utili ties for the loss
3 of transmission facilities.The transmission system must
4 be designed and operated so that the loss of up to two
5 facilities simultaneously will have no impact to the
6 interconnected transmission system.These requirements
7 drove the need for Avista to invest in its transmission
8 system.
9 Q.Please describe the Company's distribution
10 projects in the State of Idaho that will be completed in
11 2009?
12
13
A.Distribution Projects in Idaho (including
transformation) for 2009 total $10.76 million.These
14 projects are necessary to meet capacity needs of the system
15 and rebuild aging distribution substations and feeders.
16 The following projects make up the $10.76 million.
17 . Plumer Substation Rebuild ($1. 53 million): This18 project is required to replace the existing19 deteriorated wood substation, and increase the20 transformer capacity to meet existing system capacity21 needs. These costs don' t include the cost of the22 transformer, which was transferred to plant in 2008.
23
24 . Idaho Road 115 kV Substation and Rathdrum 115-13 kV25 Sub Increase ($4.90 million) : These projects26 (including transformer costs) involve the construction
27 of the new Idaho Road 115-13 kV substation ($2.8728 million) and the addition of a second transformer and29 feeder at the Rathdrum substation ($2.03 million) to30 meet existing capacity needs in Post Falls and
31 Rathdrum Idaho. When completed these projects will32 provide improved service reliability to existing33 cus tomers .
34
Kinney, Di 22
Avista Corporation
1 . Wood Sub Rebuilds ($3.60 million) : Two wood
2 substations will be rebuilt in 2009. Deary 115-24 kV
3 Substation ($2.05 million including the transformer)
4 and Craigmont 115-13 kV Substation ($1.45 million)
5 will both be completely rebuilt in 2009. Both of
6 these substations are over 50 years old and have7 reached the end of their useful lives. In addition,
8 the Deary transformer is in need of replacement due to
9 end of life and bushing related issues, so the10 substation rebuild is in conjunction with the11 transformer replacement ($0.45 million) . An12 additional $100,000 for other system wood substations13 that require timber replacement is also included in14 this rebuild effort.
15
16 . Distribution Feeder Reconductor Projects ($0.7317 million): These projects involve the reconductor of18 sections of four feeders in Idaho. The feeders are19 required to be reconductored to eliminate thermal20 loading issues and improve service reliability to
21 existing customers during normal and outage22 conditions.
23
24 The Company also will spend approximately $25.27
25 million (system)in equipment replacements and minor
26 rebuilds associated with aging distribution equipment
27 discovered through inspec t ions,feeders with poor
28 reliability performance, replacements from storm damage, or
29 relocation of feeder sections resulting from road moves. A
30 brief description of the proj ects included in these
31 replacement efforts is given below.
32
33 . Electric Distribution Minor Blanket Proj ects ($7.9234 million): This effort includes the replacement of35 poles and cross-arms on distribution lines in 2009 as36 required, due to storm damage, wind, fires, or
37 obsolescence.
38
39 . Capital Distribution Feeder Repair Work ($4.1040 million): This work is to be done in conjunction with
Kinney i Di 23
Avista Corporation
1 the wood-pole management program. As feeders are
2 inspected as part of the wood-pole management program,
3 issues are identified unrelated to the condition of
4 the pole. This proj ect funds the work required to
5 resolve those issues (i.e. leaking transformers,
6 transformers older than 1964, failed arrestors,
7 missing grounds, damaged cutouts) .
8
9 . Wood Pole Replacement Program ($3.70 million): The
10 distribution wood-pole management program is a11 strength evaluation of a certain percentage of the12 pole population each year. Depending on the test13 results for a given pole, that pole is either14 considered satisfactory, reinforced with a steel stub,15 or replaced.
16
17 . Electric Underground Replacement ($3.16 million):
18 Replace high and low vol tage underground cable as19 required in 2009, due to cable failure or20 obsolescence.
21
22 . T&D Line Relocation ($2.30 million): Relocation of23 transmission and distribution lines as required due to24 road moves.
25
26 . Failed Electric Plant ($1.99 million): Replacement of27 distribution equipment throughout the year as required28 due to equipment failure.
29
30 . System Dist Reliability Improve Worst Feeders31 ($1.10M total, $350K in Idaho): Based on a32 combination of reliability statistics, including
33 CAIDI, SAIFI, and CEMI (Customers Experiencing34 Mul tiple Interruptions), feeders have been selected
35 for reliability improvement work. This work is36 expected to improve the reliability of these feeders.
37
38 . Open Wire Secondary ($1.0 million) - Avista has over39 60 miles of secondary districts that consist of 2 120
40 volt to ground uninsulated (open wire) conductors41 installed between poles and served by one overhead42 transformer. These service installations were43 installed in the 1950 i sand 1960 's. When there is44 contact across the 120 volt conductor and the ground45 wire due to trees or other causes, the conductor fails46 resulting in customer outages. This project replaces47 the open wire conductor with insulated conductor and48 reduces the length of some of the secondary circuits.
Kinney, Di 24
Avista Corporation
1
2
3
4
5
This effort should reduce the numer and length ofoutages and improve customer service.
V. AVISTA' S ASSET MAAGEMNT PROGRA
Q.Please provide additional background to Avista's
6 continuing investment in its transmission and distribution
7 systems?
8 A.Like most U.S. utilities, after World War II,
9 Avista' s growth required installing or updating equipment
10 to meet rising electrical demand. Substations were built or
11 modified to meet increasing loads. The transmission system
12 expanded to bring new generating plant output to population
13 centers. Distribution systems grew and voltage levels were
14 increased to meet new housing and industrial needs.
15 Avista's installed equipment is aging,and more
16 components are reaching the end of their life. Equipment
17 has become obsolete, and manufacturers no longer support
18 the aged equipment or produce replacement parts, which
19 makes it impractical to rebuild the equipment. Recognizing
20 the increasing cost of aging equipment failure, Avista
21 launched its Asset Management effort in March 2004.
22 Q.Please describe the Asset Management mission and
23 process.
24
25
A.Avista's Asset Management (AM) program manages
key electric transmission and distribution assets
26 throughout their life to provide the best value for our
Kinney, Di 25
Avista corporation
1 customers. By minimizing life cycle costs and the cost per
2 kilowatt-hour to generate and deliver energy, we're able to
3 maximize system reliability and value for our customers.
4 The Asset Management process combines technology and
5 information in a manner that integrates data from a myriad
6 of sources into a comprehensive plan that maximizes the
7 value of capital assets.The process provides a
8 replacement or maintenance program that minimizes life
9 cycle costs and maximizes system reliability.
10 Technical experts evaluate each asset and develop a
11 comprehensive Asset Management Model. Available data is
12 examined and where it is not available, expert opinion from
13 the team fills in the gaps. Exhibit 8, Schedule 2 shows the
14 steps in the process for developing an Asset Management
15 Plan. The foundation for the plan involves determining the
16 future failure rates and impacts to the environment,
17 reliability, safety, customers, costs, labor, spare parts,
18 time, and other consequences.The failure model then
19 becomes the baseline to compare all other options. Given
20 this foundation, alternatives can be examined and evaluated
21 to define the optimal asset 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 i Di 26
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 Managemnt plans been
9 implemented?
10
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 impact of $175,000.For
19 2008, we were proj ected to have 550 faults prior to
20 starting this program and now we are on track to have less
21 than 150 faults by years end. This equates to avoided cost
22 impact of $1,000,000.The increased emphasis on cable
23 replacement has stabilized the fault rate per mile of cable
24 dur ing the pas t 4 years.This marks significant progress
25 after a four-fold increase in the fault rate since 1992.
Kinney i Di 27
Avista Corporation
1
2
The Asset Management team also studied the Wood Pole
Maintenance program.After completing an optimization
3 analysis and the revenue requirement model, the data
4 indicated that distribution poles should be inspected on a
5 20-year cycle and transmission poles inspected on a 15-year
6 cycle.
7 Under the new Wood Pole maintenance program Avista
8 tested twice as many Distribution poles in 2007 as in 2006.
9 For 2008 through November, we inspected over 11,600
10 Distribution Wood Poles and over 2,500 Transmission Wood
11 Poles.Our annual goal is to inspect 12,000 Distribution
12 and 3,000 Transmission poles each year. As a result of the
13 2008 inspections, Avista reinforced 980 poles, replaced 432
14 poles, and replaced 950 cross-arms.The Operations and
15 Maintenance portion of the Avista rate request to support
16 Wood Pole maintenance work in 2010 totals $852,000
17 (system). This represents an increase of $207,000 (system)
18 above the 2007/2008 test year.
19 Q.What is the Company's request with regards to
20 Asset Management capital expenditures and O&M expenses?
21 A.Avista is not asking for any planned 2010 capital
22 Asset Management additions to be included in this case.
23 For Asset Management proj ects that require additional
24 O&M, proposed 2010 O&M expenses are $12,505,000 (system)
25 compared to 2007/2008 test year expenses of $7,896,000
Kinney, Di 28
Avista Corporation
1 (system) .This represents an increase of $4,609,000
2 (system) above the 2007/2008 test year included in this
3 rate case. As shown in Table 1 below, Asset Management O&M
4 additions have been divided into six major categories:
5 substation,Distribution,Transmission,vegetation
6 Management, Wood Pole Management and Spokane Downtown
7 Network.Cost adjustments also include adjustments for
8 inflation of 6% to bridge the time between the test year
9 and 2010.
10
Table 1:
11
12
SubstationDistribution
Transmission
Vegetation Mangement
Wood Pole Management
Network
Total Additional
Requested
Asset Management
Operations & Maintenance
Amount Above 2007/2008 Test Period(System) Pro form
$ 616,000
$ 458,000
$ 401,000
$ 2,813,000
$ 207,000
$ 114,000
$4,609,000
Q.Please describe Avista's Substation Asset
13 Management Plan.
14 A.Avista operates 157 transmission and distribution
15 substations. A significant portion of the equipment and
16 substation structures are more than 40 years old and have
17 operated beyond normal industry expectations.This older
18 equipment has reached a point in its lifecycle where
Kinney i Di 29
Avista Corporation
1 planned replacement or maintenance will add value to our
2 customers by improving reliability and safety, and avoiding
3 outage costs. Costs to support the Substation maintenance
4 work totals approximately $2,073,000 (system) in the 2010
5 pro forma period. This is an additional $616,000 compared
6 to the 2007/2008 test period.
7 The Substation plan includes:
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
.26% of Avista' s40 years old.to be eithercondition.
Power Transformers: . More than
Substation Transformers are overThese aging transformers need
maintained or replaced depending on
.Circui t Breakers: The Power Circui t Breaker Planhas been an ongoing and successful programmaintaining approximately 300 High Voltage OilCircui t 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
Switchers to protect substation transformers at
smaller Substations as well as 115 kV substation
Capacitor Banks. 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.
Kinney, Di 30
Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
. Rock and Fence: The Substation Rock and Fence plan
covers the maintenance and replacement of Rock andFence for Avista' s 166 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.
Q. Please describe Avista' s distribution Asset
21 Management Plan.
22 A.Avista's distribution system includes 324 feeders
23 and over 12,000 miles of conductors, poles, underground
24
25
cable,distribution transformers,and various other
distribution system components.Avis ta has developed
26 operations and maintenance plans for the distribution
27 system totaling approximately $569,000 for the 2010 Pro
28 forma period. This amount is $458,000 above that included
29 in the 2007/2008 test period.
30 The distribution plan includes:
31 . Animal Guards: Data shows that animals are the32 second-leading cause of outages at Avista, ranking33 second only behind weather, and accounting for 1934 percent of all outages. Outages caused by squirrels35 and birds are an increasing, on-going and36 persistent problem on the distribution system.37 Statistics indicate that 60 feeders were the38 subject of almost half of all animal-caused
Kinney, Di 31
Avista Corporation
1 outages. Four of those 60 most vulnerable feeders
2 were recently retrofitted with animal guards.
3 Animal-caused outages have decreased to almost zero
4 on all four feeders, compared to 10 or more per
5 month during warm weather in previous years. Avista
6 has included additional O&M funding to begin
7 implementing a four-year program to install animal
8 guards on the remainder of the 60 most vulnerable9 feeders.
10
11 . Underground Cable: Over 6 million feet of12 unjacketed underground cable was installed prior to13 1982; it has been subject to a replacement program14 since 1984. After 2008, there will be15 approximately 750,000 feet of pre-1982 cable still
16 left to be replaced. Though primarily a capital17 intensive program, there is some related
18 maintenance costs associated with underground19 cable.
20
21 . Exacter Testing: This is a new test using an22 inexpensive method to detect distribution equipment23 problems before they fail. The new method detects24 radio frequency failure signatures of distribution25 equipment and uses a library to identify the
26 problem. Using our Geographical Information
27 System, we can then identify the component and plan28 the replacement prior to equipment failure. This29 will add $30,000 to the 2010 budget.
30
3132 Q. Please describe changes to Avista' s vegetation
33 Management Plan.
34 A.Avista's system includes over 12,000 miles of
35 distribution circuits and over 2,200 miles of transmission
36 lines that require vegetation management.Avista's
37 vegetation management work is almost entirely contracted
38 out. The primary contractor for this work is Asplundh Tree
39 Experts.Over the past few years, Avista' s vegetation
40 management has experienced higher than anticipated rates of
41 inflation over 6% due to labor, fuel costs and equipment
Kinney, Di 32
Avista Corporation
1 costs.Our goal is to clear 1,550 miles per year, which
2 resul ts in a 5 year cycle.
3 For the transmission system, three factors require an
4 increase from the current spending on vegetation
5 management.FERC Reliability Standard FAC-003-1 has
6 changed the way we manage the transmission system right of
7 ways for vegetation.Vegetation line patrols have been
8 increased to an annual basis for all 200 kV and higher
9 voltages. WECC has also applied these same requirements to
10 4 other lower voltage line identified as critical to grid
11 reliability. These expanded requirements have expanded the
12 areas requiring action to include more difficult to access
13 portions of the right of way.These difficult access
14 portions have steep rocky hillsides and wet bottom draws
15 and require crews to hike in and cut the vegetation by
16 hand, often taking one to two weeks to clear one span. The
17 new regulations also require clearances to account more
18 stringently for line sag and sway necessitating clear
19 cutting timber through draws where trees have been left to
20 grow for the past 20 - 30 years. This work is very costly
21 and has added significantly to our anticipated costs.
22 The second factor is the change in access road
23 maintenance requirements included in updates of our Special
24 Use Permits with the Forest Service.This will require
25 Avista to spend more money annually to maintain roads on a
Kinney i Di 33
Avista Corporation
1 planned basis. When combined with increase requirements to
2 patrol transmission lines by FERC and WECC requirements,
3 the roads will be used more frequently and must be
4 maintained more frequently.
5 The third factor driving the costs up has been a
6 higher than anticipated inflation rate of around 6% that is
7 anticipated to continue.Per FERC requirements, Avista
8 inspects all 230kV transmission lines annually to identify
9
10
vegetation management needs.In addition to the 230kV
transmission lines,Avista also patrols the 115kV
11 transmission lines once every three years.
12 Along with increased requirements for the transmission
13 systems, the natural gas right-of-ways now require more
14 vegetation management to support leak surveys required by
15 CFR 49, Part 192.723 and Washington State WAC 480-93-188 on
16 high pressure gas pipelines. Avista has 198 miles of high
17 pressure gas pipeline and our plan is to perform vegetation
18 management on a five year cycle for an average of 40 miles
19 per year.
20
21
The Company plans to spend $8,390,000 in Operations
and Maintenance funding for support of the gas,
distribution and transmission vegetation management22
23 programs.This is an increase of $2,813,000 above the
24 2007/2008 Operations and Maintenance spending for this
25 area.
Kinney i Di 34
Avista Corporation
1 Q.Please describe Avista' s Transmission Asset
2 Management Plan.
3 A.The Avista transmission system is comprised of
4 over 2,300 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 utili ties throughout large portions of
10 Eastern Washington and Northern Idaho. Approximately 75% of
11 the transmission system components are over 35 years old.
12 A 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. Almost all Asset Management work
15 on the Transmission system is capital work, however, as
16 Asset Management completes more models in the future, some
17 O&M funding may be required to support future programs.
18 Avista is requesting $507,000 in Operations and Maintenance
19 funding for support of the transmission system under this
20 proposal to protect our current wood poles from wild fires
21 in key areas. This is an increase of $401,000 above the
22 2007/2008 Operations and Maintenance spending for this
23 area.
24 The transmission plan includes:
25
26
. Fire Retardant Coatinqs for Transmission Poles:
Random fires can have a significant impact on the
Kinney, Di 35
Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14
reliability 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. Avista proposes a four-year
program to apply fire retardant coating to critical
transmission lines in high fire areas.
Q.Please describe Avista' s Network Asset Management
15 Plan.
16 A.The Network consists of an underground
17 distribution system that feeds the core of downtown Spokane
18
19
20
the region's economic hub with a very reliable
networked distribution system.The Network includes
underground vaul ts ,manholes,handholes,substations,
21 network protectors, network transformers, and numerous
22 miles of duct banks and cables.The structural integrity
23 of these vaults, manholes and handholes is vi tal to public
24 safety because they are typically located under heavily-
25 used streets and sidewalks. Reliability is also essential,
26 because the Network serves the businesses, banks and other
27 critical services located in downtown Spokane.The
28 Operations and Maintenance portion of the Avista rate
29 request to support Network maintenance work totals
30 approximately $114,000. During the 2007/2008 test year no
31 Network asset management work was performed.
Kinney, Di 36
Avista Corporation
1
2
The Network plan includes inspecting and maintaining
an aging system:
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
. Vaults: Almost 60% of the vaults are more than 50
years old. Avista plans to add inspection of vacantvaul ts and additional maintenance acti vi ties such
as vault cleanings to prevent debris build-up and
fire hazards. When necessary an entire vault will
need to be replaced wi th a new one.
. The Manholes/Handholes: Nearly 98% of manholes are
approaching 100 years of age. Avista plans to
inspect them on a five-year cycle and perform
maintenance based on the results of the
inspections. Replacement of manholes and handholes
may also be required.
this your pre-filed directcompleteQ.Does
testimony?
A.Yes, it does.
Kinney, Di 37
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF 2099 JAN 23 PM 12: 43
REGULATORY & GOVERNNTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone] .
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-09-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHAGES FOR ELECTRIC AND )
NATURA GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 8
AN NATURA GAS CUSTOMERS IN THE )STATE OF IDAHO ) SCOTT J. KINNEY
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avista Corporation
. Energy Delivery .
Pro Forma Transmission Revenue/Expenses
($OOOs)July '09-
Oct '07-June '10
Line Sep '08 Pro Forma
No.Actual Adjusted Period
556 OTHER POWER SUPPLY EXPENSES
NWPP 31 0 31
560-71.4.935.3-.4 TRANSMISSION O&M EXPENSE
2 Colstnp O&M - 500kV Line 590 -82 508
3 ColumbiaGrid Development 218 22 240
4 ColumbiaGrid Planning 104 76 180
5 ColumbiaGrid OASIS 0 100 100
6 ColumbiaGrid DSRFA 45 -45 0
7 Grid West (ID)71 0 71
8 Total Account 560-71.4,935.3-.4 1,028 71 1,099
561 TRANSMISSION EXP-LOAD DISPATCHING
9 Elect Sched & Acctg Srv (CASSO/OATI)195 -55 140
565 TRANSMISSION BUSINESS RELATED EXPENSES
10 * Grant County Agreement 51 -51 0
566 TRANSMISSION EXP-OPRN-MISCELLANEOUS
11 OASIS Expenses 5 3 8
12 BPA Power FactorPenalty 178 0 178
13 WECC - Sys. Security Monitor 171 -12 159
14 WECC Admin & Net Oper Comm Sys 282 47 329
15 WECC - Loop Flow 16 10 26
16 Total Account 556 652 48 700
17 TOTAL EXPENSE 1,957 13 1,970
456 OTHER ELECTRIC REVENUE
18 Borderline Wheeling 5,375 -21 5,354
19 ** Seattle 64 -64 0
20 ** Tacoma 64 -64 0
21 SeattelTacoma Main Canal 155 38 193
22 Seattle/ Tacoma Summer Falls 43 31 74
23 Grand Coulee Project 8 0 8
24 OASIS nf & stf Whl (Other Whl)3,109 201 3,310
25 PP&L - Dry Gulch 258 11 269
26 *** PP&L Series Cap -1978 9 -9 0
27 Spokane Waste to Energy Plant 160 0 160
28 Vaagen Wheeling 116 -4 112
**** Northwestern Energy 42 -42 0
29 Forfeited Deposits 40 -40 0
30 Total Account 456 9,443 37 9,480
31 TOTAL REVENUE 9,443 37 9,480
32 TOTAL NET EXPENSE -7,486 -24 -7,510
* Grant County Agreement - contract ended 10/31/07
** Seattle and Tacoma - contracts ended 10/31/07
*** PP&L Series Cap - contract ended 6/30/09
**** Northwestern Energy - contract ended 11/30107 Exhibit NO.8
Case No. AVU-E-09-01
S. Kinney, Avista
Schedule 1, pg 1 of 1
As
s
e
t

M
o
d
e
l

a
n
d
St
r
u
c
t
u
r
e
As
s
e
t

F
a
i
l
u
r
e
Mo
d
e
l
i
n
g
As
s
e
t

M
a
n
a
g
e
m
e
n
t

P
l
a
n

M
o
d
e
l
Id
e
n
t
i
f
y

a
n
d
Ev
a
l
u
a
t
e
Ma
i
n
t
e
n
a
n
c
e
Ac
t
i
o
n
s
Va
l
i
d
a
t
e

t
h
e

F
a
i
l
u
r
e
Mo
d
e
l
Pr
e
p
a
r
e

A
s
s
e
t
Ma
n
a
g
e
m
e
n
t

P
l
a
n
Im
p
l
e
m
e
n
t

A
s
s
e
t
Ma
n
a
g
e
m
e
n
t

P
l
a
n
Id
e
n
t
i
f
y

a
l
l

f
u
n
c
t
i
o
n
s

o
f
th
e

c
o
m
p
o
n
e
n
t
Id
e
n
t
i
f
y

w
h
a
t
co
m
p
o
n
e
n
t

l
e
v
e
l

t
o
ev
a
l
u
a
t
e
Id
e
n
t
i
f
y

a
l
l

f
u
n
c
t
i
o
n
a
l
fa
i
l
u
r
e
s
De
t
e
r
m
i
n
e

t
h
e

m
a
i
n
fu
n
c
t
i
o
n
s

a
n
d
fu
n
c
t
i
o
n
a
l

f
a
i
l
u
r
e
s

t
o
an
a
l
y
z
e
De
t
e
r
m
i
n
e

t
h
e

r
o
o
t
ca
u
s
e
s

o
f

f
a
i
l
u
r
e
De
t
e
r
m
i
n
e

t
h
e

F
a
i
l
u
r
e
da
t
a

a
n
d

c
u
r
v
e

f
o
r

e
a
c
h
fa
i
l
u
r
e

m
o
d
e
De
t
e
r
m
i
n
e

t
h
e
Co
r
r
e
c
t
i
v
e

a
c
t
i
o
n

t
o
ea
c
h

f
a
i
l
u
r
e
De
t
e
r
m
i
n
e

t
h
e

R
i
s
k
s
as
s
o
c
i
a
t
e
d

w
i
t
h

t
h
e
fa
i
l
u
r
e

a
n
d

C
o
r
r
e
c
t
i
v
e
Ac
t
i
o
n
s
Co
m
p
a
r
e

m
o
d
e
l
pr
e
d
i
c
t
i
o
n
s

f
o
r

f
a
i
l
u
r
e
s
to

p
r
e
v
i
o
u
s

o
r

c
u
r
r
e
n
t
fa
i
l
u
r
e

r
a
t
e
s

t
o

e
n
s
u
r
e
th
e

m
o
d
e
l

a
p
p
r
o
x
i
m
a
t
e
s
cu
r
r
e
n
t

c
o
n
d
i
t
i
o
n
s
Va
l
i
d
a
t
e

t
h
e

r
e
s
o
u
r
c
e
s
an
d

c
o
s
t
s

a
r
e

i
n

l
i
n
e
wi
t
h

e
x
p
e
c
t
a
t
i
o
n
s
Is

t
h
e

f
a
i
l
u
r
e

e
v
i
d
e
n
t
?
Ca
n

t
h
e

f
a
i
l
u
r
e

b
e
to
l
e
r
a
t
e
d
?
Se
l
e
c
t

B
e
s
t

O
p
t
i
o
n
s
Is

t
h
e

r
i
s
k

a
c
c
e
p
t
a
b
l
e
?
Va
l
i
d
a
t
e

M
o
d
e
l
Pr
e
s
e
n
t
a
t
i
o
n

o
f
Al
t
e
r
n
a
t
i
v
e
s
I
B
u
d
O
m

I
Tr
a
n
s
l
a
t
e

M
o
d
e
l

I
n
t
o
Pl
a
n
Pr
o
g
r
a
m
/
P
r
o
j
e
c
t

O
w
n
e
r
.
Im
p
l
e
m
e
n
t
s

P
l
a
n
As
s
e
t

M
a
n
a
g
e
m
e
n
t
.
Su
p
p
o
r
t
s

P
l
a
n
Ex
h
i
b
i
t

N
o
.
8
Ca
s
e

N
o
.

A

V
U
-
E
-
0
9
-
0

1
S.

K
i
n
n
e
y
,

A
v
i
s
t
a
Sc
h
e
d
u
l
e

2
,

p
g

1