20100323Kinney Di.pdf

(1 c: (~
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNMENTAL
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
2(ì! fi LH P ")~.til:; flh;\ c.J Mî II: 05
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 AND
NATURAL GAS SERVI CE TO ELECTRI C
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-10-01)
)
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DIRECT TESTIMONY
OF
SCOTT J. KINNEY
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
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I . INTODUCTION
Q.Please state your name, employer and business
3 address.
4 A.My name is Scott J. Kinney.I am employed by
5 Avista Corporation as Director, Transmission Operations.
6 My business address is 1411 East Mission, Spokane,
7 Washington.
8 Q.Please briefly describe your education backqround
9 and professional experience.
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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
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15
Bonneville Power Administration.I have held several
different positions in the Transmission Department.I
16 started at Avista as a Senior Transmission Planning
17 Engineer.In 2002, I moved to the System Operations
18 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, Transmission Operations.
22
23
24
Q.What is the scope of your testimny?
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
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Avista Corporation
1 the capital additions testimony provided by Company witness
2 Company witness AndrewsMr.Dave DeFelice.Ms.
3 incorporates the Idaho share of the net transmission
4 expenses and the transmission and distribution capital
5 additions.
6
7
8
Are you sponsorinq any exhibits?Q.
A.Yes.I am sponsoring Exhibit 8, Schedule 1.
transmission pro formatheprovidesSchedule1,
9 adjustments.
10 TABLE OF CONTENTS
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PageSection
I Introduction 1
II Pro For. Transmission Expenses 2
III Pro For. Transmission Revenues 10
IV Transmission and Distribution Capital Projects 20
II . PRO FORM 'lSMISSION EXPENSES
Q.Please describe the pro form transmission
19 expense revisions included in this filinq.
20 were made in this filing toA.Adj ustments
21 incorporate updated information for any changes in
22 transmission expenses from the 2009 test year to the
23 October 2010 to September 2011 Pro forma period.Each
24 expense item described below is at a system level, with the
25 exception of the $71,000 Grid West adjustment which is
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Avista Corporation
i Idaho only, and is included in Exhibit 8, Schedule i.
2 Supporting workpapers for each expense item described below
3 have been provided with the Company's filing.
4 Northwest Power Pool (NWPP) - Avista pays its share of
5
6
the NWPP operating costs.The NWPP serves the electric
utilities in the Northwest by supporting regional
7 transmission planning coordination and providing
8 coordinated transmission operations, generation reserve
9 sharing and Columbia River water coordination. Actual 2009
10 transmission-related NWPP expenses were $36,000 and a
11 $4,000 adjustment was made to the pro forma period to
12 reflect planned NWPP expenses allocated to the Company.
13 Colstrip Transmission - Avista is required to pay its
14 portion of the O&M costs associated with its share of the
15 Colstrip transmission system pursuant to the joint Colstrip
16 contract.In accordance with NorthWestern Energy's (NWE)
17 proposed Colstrip transmission plan provided to the
18 Company, NWE will bill Avista $589,000 for Avista's share
19 of the Colstrip O&M expense during the pro forma period.
20 This is an increase of $98,000 from the actual expense of
21 $491,000 incurred during the 2009 test year.
22 ColumbiaGrid RTO - Avista became a member of the
23 ColumbiaGrid regional transmission organization (RTO) in
24 2006.ColumbiaGrid's purpose is to enhance transmission
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Avista Corporation
1 system reliability and efficiency, provide cost-effective
2 coordinated 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,
6 and support effective market monitoring within the
7 Northwest and the entire Western interconnection.Avista
8 supports ColumbiaGrid's general developmental and regional
9 coordination activities under a General Funding Agreement
10 and supports specific functional activities under the
11 Planning and Expansion Functional Agreement and the OASIS
12 Functional Agreement.The current General Funding
13 Agreement for ColumbiaGrid expires September 30, 2010. The
14 Company expects to execute a successor General Funding
15 Agreement in the spring of 2010 to provide for ongoing
16 funding of ColumbiaGrid general development activities
17 while shifting a portion of ColumbiaGrids administrative
costs to its other functional agreements.Accordingly,18
19
20
while ColumbiaGrid is engaging in significant new
developmental acti vi ties in coordination with other
21 regional organizations (e. g. the review of consolidated
22 balancing area operations and the development of revised
23 scheduling practices to accommodate the impacts of
24 intermittént generation) ,the Company's expected
25 ColumbiaGrid general funding expenses will decrease.
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Avista Corporation
1 Avista's ColumbiaGrid general funding expenses for the 2009
2 test year were $202,000 while pro forma period general
3 funding expenses are expected to be $192,000. This amount
4 is the Company's best estimate at this time until the
5 successor General Funding Agreement is approved in the
6 Spring of 2010.
7 ColumbiaGrid Transmission Planning - The ColumbiaGrid
8 Planning and Expansion Functional Agreement (PEFA) was
9 accepted by the Federal Energy Regulatory Commission (FERC)
10 on April 3, 2007 and Avista entered into the PEFA on April
11 4, 2007.Coordinated transmission planning activities
12 under the PEFA allow the Company to meet the coordinated
13 regional transmission planning requirements set forth in
14 FERC's Order 890 issued in February 2007, and outlined in
15 the Company's Open Access Transmission Tariff, Attachment
16 K.Funding under the PEFA is on a two-year cycle with
17 provisions to adjust for inflation. Actual PEFA expenses
18 for the 2009 test year were $142,000. The Company's PEFA
19 expenses for the pro forma period are expected to reach the
20 maximum total payment obligation of $215,000, reflecting
21 ColumbiaGrid's final staffing levels to support the PEFA
22 and the allocation of a portion of ColumbiaGrids
23 administrati ve expenses to this functional agreement. This
24 amount is the Company's best estimate at this time until
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Avista Corporation
1 the successor General Funding Agreement is approved in the
2 Spring of 2010.
3 ColumbiaGrid Open Access Same-Time Information System
4 (OASIS)Avista entered into the ColumbiaGrid OASIS
5 Functional Agreement in February of 2008.This agreement
6 provides for the development of a common Open Access Same-
7 time Information System (OASIS)which would give
8 transmission customers the ability to purchase transmission
9 capacity from all ColumbiaGrid members via a single common
10 OASIS site instead of having to submi t multiple
11 transmission service requests to each member individually
12 on each member's respective OASIS sites.Avista's 2009
13 test year expenses of $35,000 reflected initial
14 developmental acti vi ties under this functional agreement.
15 Avista's ColumbiaGrid OASIS expenses for the pro forma
16 period are expected to be $80,000, reflecting operational
17 capability of the ColumbiaGrid OASIS and the allocation of
18 a portion of ColumbiaGrid's administrative expenses to this
19 functional agreement.This amount is the Company's best
20 estimate at this time until the successor General Funding
21 Agreement is approved in the Spring of 2010.
22 Grid West (ID Direct)Included in transmission
23 expense is an annual amount of $71,000 to recover costs
24 associated with Grid West (and its forerunner, RTO West).
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Avista Corporation
1 Avista signed an initial funding agreement in 2000, as did
2 all other Pacific Northwest investor-owned electric
3 utilities, to provide funding for the start-up phase of
4 Grid West (then named "RTO West").Grid West had p~anned
5 to repay the loans to Avista and other funding utili ties
6 through surcharges to customers once it became operational.
7 Wi th the dissolution of Grid West, this repayment did not
8 occur. As a result, Avista filed an application with the
9 Commission to defer these costs. The Commission approved,
10 on October 24, 2006, in Order No. 30l51, the Company's
11 request for an order authorizing deferred accounting
12 treatment for loan amounts made to Grid West. In its Order
13 the IPUC found these costs to be "prudent and in the public
14 interest" and required the Company to begin amortization of
15 the Idaho share of the loan principal ($422,000) beginning
16 January 2007, for five years. During the pro forma period
17 Avista will amortize a total of $71,000 associated with
18 Grid West development costs.
19 Electric Scheduling and Accounting Services The
20 $12,000 decrease in the pro forma period compared to test
21 year expense for electric scheduling and accounting
22 services is a result of continued reductions in services
23 provided by third party vendors.These services are no
24 longer required because of the development of an internal
25 accounting program and the development of a regional
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Avista Corporation
1 transmission interchange tool by the Western Electricity
2 Coordinating Council (WECC). These new applications replace
3 the services provided by third parties.
4 NERC Critical Infrastructure Protection - The Company
5 has purchased two software products to assist in protecting
6 critical transmission system data from intrusion and to
meet applicable North American Electric Reliability7
8 Corporation (NERC) standards.The Company expects no
9 change from the actual 2009 test year expense of $25,000.
10 OASIS Expenses - Thes"e OASIS expenses are associated
11 wi th travel and training costs for transmission pre-
12 scheduling and OASIS personnel. This travel is required to
13 monitor and adhere to NERC reliability standards and FERC
14 OASIS requirements.The costs associated with OASIS
15 expenses in the pro forma period are $5,000 more than in
16 the 2009 test year. This increase is a result of training
17 required for two new replacement transmission scheduling
18 employees and the implementation of new OASIS functions
19 required by FERC associated with network and native load
20 transmission service.
21 Power Factor Penalty - Power factor penalty costs are
22 associated with the Bonneville Power Administration's
23 (Bonneville) General Transmission Rate Schedule Provisions.
24 Bonneville charges a power factor penalty at all
25 interconnections with Avista that exceed a given threshold
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1 for reactive power flow during each month. If the reactive
2 flow from Bonneville's transmission system into Avista's
3 system or from Avista's system to Bonneville's system
4 exceeds a given threshold, then Bonneville bills Avista
5 according to its rate schedule. The charge includes a 12-
6 month rolling ratchet provision.Avista currently pays
7 Bonneville a power factor penalty at several points of
8 interconnection. Avista incurred $167,000 of power factory
9 penalty charges in 2008 and $124,000 during the 2009 test
10 year. The Company's pro forma expenses are set at $146,000
11 representing an average of the power factor penalty charges
12 incurred in 2008 and 2009.
13 WECC - System Security Monitor and WECC Administration
14 & Net Operating Committee Fees - The Company's total WECC
15 fees have increased, and are expected to continue to
16 increase, from year to year. The increase is driven
17 primarily by compliance with mandatory national reliability
18 standards.WECC is responsible for moni toring and
19 measuring Avista's compliance with the standards and
20 therefore has substantially increased its staff and other
21 resources to meet this FERC requirement.The Company's
22 2009 test year WECC assessments were $159,000 for system
23 security monitoring and $329,000 for dues and net Operating
24 Committee fees, for a total 2009 WECC assessment of
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1 $488,000.The Company paid its 2010 WECC assessments in
2 January 2010: $168,000 for system security monitoring and
3 $370,000 for dues and net Operating Committee fees, for a
4 total WECC assessment of $538,000. The Company's pro forma
5 expenses have been set equal to these amounts paid in
6 January 2010.
7 WECC - Loop Flow - Loop Flow charges are spread across
8 all transmission owners in the West to compensate utilities
9 that make system adjustments to eliminate transmission
10 system congestion throughout the operating year. WECC Loop
11 Flow charges can vary from year to year since the costs
12 incurred are dependent on transmission system usage and
13 congestion.. Therefore a five-year average is used to
14 determine future Loop Flow costs. Based upon the WECC Loop
15 Flow charges incurred by the Company during the five-year
16 period from 2005 through 2009, pro forma Loop Flow expenses
17 are expected to be $34,000.This is $6,000 less than
18 actual 2009 test year charges of $40, 000.
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III. PRO FORM 'lSMSSION RES
Q.Please describe the pro form transmission
22 revenue revisions included in this filinq.
23 A.Adjustments have been made in this filing to
24 incorporate updated information associated with known
25 changes in transmission revenue for the 2010/2011 pro forma
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Avista Corporation
1 period as compared to the 2009 test year.Each revenue
2 item described below is at a system level and is included
3 in Exhibit 8, Schedule 1. In particular, in December 2009
4 the Company successfully attained FERC acceptance for an
5 increase in generally applicable transmission rates under
6 Avista's Open Access Transmission Tariff, effective January
7 1, 2010.The Company was able to increase its point-to-
8 point transmission service rates by 43% (long-term firm
9 point-to-point rates increased from $16. 79/kW-year to
10 $24. OO/kW-year) and was able to increase its annual FERC
11 transmission revenue requirement applicable to network
12 transmission service (e. g. borderline wheeling service
13 provided to Bonneville) by 73%.Accordingly, adjustments
14 have been made in the pro forma period to reflect these
15 increases in transmission rates. Supporting workpapers for
16 each revenue item described below have been provided with
17 the Company's filing.
18 Borderline Wheeling Total borderline wheel.ing
19 revenues for the 2009 test year were $5,552,000.Total
20 borderline wheeling revenue in the pro forma period has
21 been set at $7,838,000, which reflects a four-year average
22 (2006 through 2009) of revenues from borderline wheeling
23 service provided to Bonneville and adjustments to reflect
24 the impact of new transmission rates on the Company's
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Avista Corporation
1 borderline wheeling contracts with Bonneville and Avista's
2 other borderline wheeling customers, which include Grant
3 County PUD, East Greenacres Irrigation District, the
4 Spokane Tribe of Indians and Consolidated Irrigation
5 District. Each of these contracts are described further
6 below.
7 a) Borderline Wheeling - Bonneville Power Administration
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Actual test year revenue from borderline wheeling
service provided to Bonneville was $5,334,000. Avista
typically uses a five-year average of actual annual
revenue to estimate future borderline wheeling revenue
from Bonneville.This helps levelize the revenue
requirement since it is based on a rolling twelve-
14 month average of Bonneville's load ratio share usage
15 of the Company's transmission system.For this case
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Avista is only using a four-year average since. 2006
through 2009 are the only years operating under new
contracts signed with Bonneville that became effective
January 1, 2006. This four-year average of borderline
wheeling service provided to Bonneville is $5,113,000.
This revenue covers borderline wheeling service to
Bonneville over both transmission and low-voltage
23 facilities. As a result of the Company's recent FERC
24 transmission rate case, the FERC transmission revenue
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Avista Corporation
1 requirement, to which Bonneville's load ratio share
2 usage of the Company's transmission system is applied,
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was increased by 73%.Accordingly, the low-voltage
revenue component of the four-year average remains the
same while the transmission revenue component of the
four-year average has been increased by 73% for the
2011 pro forma period, resulting in a revenue figure
of $7,597,000 for borderline wheeling service to
9 Bonneville.
10 b) Borderline Wheeling - Grant County PUD - The Company
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provides borderline wheeling service to two Grant
County PUD substations under a Power Transfer
Agreement executed in 1980.Charges under this
14 agreement are not impacted by the Company's
15 transmission service rates under Avista's Open Access
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Transmission Tariff so the Company is not proposing
any adjustment from the 2009 test year revenue of
$27,000.
19 c) Borderline Wheeling East Greenacres Irrigation
20 District The Company restructured its contract to
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provide borderline wheeling service to the Ea.st
Greenacres Irrigation District in April,2009,
resulting in monthly wheeling revenue of $5,000.
Revenue under this agreement for the 2009 test year
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Avista Corporation
1 was $51,000.Revenue for the pro forma period has
2 been increased to $60,000 to reflect the terms of the
3 restructured contract over the entire pro forma rate
4 period.
5 d) Borderline Wheeling - Spokane Tribe of Indians and
6 Consolidated Irrigation District The Company
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provides borderline wheeling service over both
transmission and low-voltage facilities to the Spokane
Tribe of Indians and Consolidated Irrigation District.
Total transmission and low-voltage wheeling revenue
under these contracts for the 2009 test year was
$140,000.Revenues associated with the transmission
components of these contracts have been adjusted for
the pro forma period to reflect the 43% increase in
15 the Company's long-term firm point-to-point
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transmission service rate.Accordingly, pro forma
period revenue under these two contracts is set at
$154,000.
OASIS Non-Firm and Short-Term Firm Transmission
20 Service - OASIS is an acronym for Open Access Same-time
21 Information System.This is the system used by electric
22 transmission providers for selling and scheduling available
23 transmission capacity to eligible customers. The terms and
24 conditions under which the Company sells its transmission
25 capacity via its OASIS are pursuant to FERC regulations and
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Avista Corporation
1 Avista's FERC Open Access Transmission Tariff.OASIS
2 revenues vary from year to year depending upon a variety of
3 factors, including electric energy market conditions, load
4 and resource conditions of regional electric utilities, and
5 available transmission capacity (ATC)on adjacent
6 transmission provider systems. Due to these uncertainties,
7 Avista has, in previous rate cases, used the most recent
8 five-year average as being representative of future
9 expectations for OASIS revenue unless there are known
10 events or factors for which adj ustments are appropriate.
11 In this filing, the Company is using the most recent five-
12 year average and is proposing an adjustment to reflect the
13 results of the Company's recent FERC transmission rate
14 case.
15 OASIS revenues for the 2009 test year were $2,962,000
16 and the five-year average of OASIS revenues from 2005
17 through 2009 is $3,067,000.For the pro forma period the
18 Company proposes a 22% increase over the five-year average
19 to reflect the potential for recovering additional OASIS
20 revenue under the Company's new transmission rates accepted
21 by FERC which became effective January 1, 2010.
22 While the Company is able to increase its non-firm and
23 short-term firm transmission service rates by 43% as a
24 result if its FERC rate case, the Company expects to be
25 limi ted in its ability to successfully sell capacity at its
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Avista Corporation
1 maximum rates.Bonneville, the predominant transmission
2 provider in the region, operates its transmission system in
3 parallel with the Company's transmission system.
4 Bonneville's current hourly point-to-point transmission
5 service rate is $4. 33/MWh with a loss factor of 1.9%.
6 Avista's new maximum hourly point-to-point transmission
7 service rate is $5.77 /MWh with a loss factor of 3%. Where
8 Bonneville's system has available parallel capacity, the
9 Company would expect to have limited opportunity to sell
10 transmission capacity above an hourly rate of $4. 33/MWh.
11 Increasing the Company's transmission rate to match
12 Bonneville's current rate (notwithstanding the fact that
13 the Company's loss factor is 58% higher than Bonneville's
14 which would further limit the company's ability to compete
15 wi th parallel capacity on Bonneville's system) would add
16 only about one-fifth (0.33 / 1.77 = 19%) of the Company's
17 potential rate increase, resulting in an estimated increase
18 in OASIS revenue of 8%.Nevertheless, the Company is
19 estimating an increase in short-term firm and non-firm
20 OASIS revenue comparable to implementing half of the
21 potential rate increase. Accordingly, the Company proposes
22 an OASIS revenue amount of $3,741,000 for the pro forma
23 period, an amount $779,000, or 22%, greater than the most
24 recent five-year average of $2,962,000.
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Avista Corporation
1 Seattle and Tacoma Revenues Associated with the Main
2 Canal Proj ect Effective March 1, 2008, the Company
3 entered into long-term point-to-point transmission service
4 arrangements with the City of Seattle and the City of
5 Tacoma to transfer output from the Main Canal hydroelectric
6 project, net of local Grant County PUD load service, to the
7 Company's transmission interconnections with Grant County
8 PUD.Service is provided during the eight months of the
9 year (March through October) in which the Main Canal
10 project operates and the agreements include a three-year
11 ratchet demand provision. Revenues under these agreements
12 totaled $193,000 during the 2009 test year. Adjusting for
13 the increase in the Company's transmission rate as a result
14 of its FERC rate case, revenues under these agreements are
15 expected to be $276,000 during the pro forma period.
16 Seattle and Tacoma Revenues Associated with the Summer
17 Falls Project - Effective March 1, 2008, the Company
18 entered into long-term use-of-facili ties arrangements with
19 the City of Seattle and the City of Tacoma to transfer
20 output from the Summer Falls hydroelectric proj ect across
21 the Company's Stratford Switching Station facilities to the
22 Company's Stratford interconnection with Grant County PUD.
23 Charges under this use-of-facilities arrangement are based
24 upon the Company's investment in its Stratford Switching
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1 Station and are not impacted by the Company's transmission
2 service rates under its Open Access Transmission Tariff.
3 Revenues under these two contracts totaled $74,000 in the
4 2009 test year and are expected to remain the same for the
5 pro forma period.
6 PacifiCorp Dry Gulch - Revenue under the Dry Gulch
7 use-of-facilities agreement has been adjusted to $249,000
8 for the pro forma period, which is a $43,000 increase from
9 the 2009 test year actual revenue of $206,000. The current
10 methodology used to forecast Dry Gulch revenue is a five-
11 year average of actual revenue.A five-year average is
12 used since the revenue can vary from year to year depending
13 upon PacifiCorp's monthly peak demands.The contract
14 includes a twelve-month rolling ratchet demand provision
15 and charges under this agreement are not impacted by the
16 Company's open access transmission service tariff rates.
17 The five-year average of revenue was calculated using years
18 2005 through 2009.
19 Spokane Waste to Energy Plant - No adjustments to
20 Spokane Waste to Energy Plant revenue of $160,000 were made
21 for the pro forma period compared to the 2009 test year.
22 This revenue is the result of a long-term transmission
23 service agreement with the City of Spokane that expires
24 December 31, 2011.Charges under this agreement are not
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Avista Corporation
1 impacted by the Company's open access transmission service
2 tariff rates.
3 Vaagen Wheeling - The Vaagen generation plant was
4 permanently damaged by fire in November, 2009. Pursuant to
5 its terms and conditions, the Vaagen wheeling contract was
6 terminated effective December 1, 2009. Revenues under this
7 contract were $97,000 during the 2009 test year but have
8 been adjusted to zero for the pro forma period.
9 Grant County PUD - Revenues from a long-term firm
10 point-to-point transmission service agreement with Grant
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County PUD during the 2009 test year were $56,000.This
agreement expires December 31,2010.Accordingly,
13 associated revenue for the pro forma period has been
14 reduced to $42,000.
15 Grand Coulee Proj ect Hydroelectric Authority - The
16 Company provides operations and maintenance services on the
17 Stratford ~ Summer Falls l15kV Transmission Line to the
18 Grand Coulee Project Hydroelectric authority under a
19 contract signed in March 2006. These services are provided
20 for a fixed annual fee. Annual charges under this contract
21 totaled $8,100 in the 2009 test year and will remain the
22 same for the pro forma period.
23 PP&L Series Capacitors - PP&L Series Capacitor revenue
24 under this 1978 agreement was reduced from $5,000 in the
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Avista Corporation
1 test year to zero in the pro forma period since the 20-year
2 amortization of the original contract expired in June 2009.
3 NaturEnergy Dynamic Signal The Company was
4 reimbursed during the 2009 test year for expected one-time
5 expenses related to connecting a NaturEnergy dynamic signal
6 via the WECC ICCP system to Avista's SCADA-EMS system.
7 Accordingly, the 2009 test year revenue of $10,000 has been
8 adjusted to zero for the pro forma period.
9 FERC Settlement - The Company received a settlement
10 benefit from the FERC in 2009 relating to the Western
11 energy crisis of 2000-2001. This 2009 test year revenue of
12 $115,000 has been adjusted to zero for the pro forma
13 period.
14
15 iv. TRASMISSION AN DISTRIBUTION CAITAL PROJECTS
16 Q.Please describe the Company's capital
17 transmission projects that will be completed in 2010.
18 A.Avista continuously needs to invest in its
19 transmission system to maintain reliable customer service
20 and meet mandatory reliability standards. The 2010 capital
21 transmission projects are being constructed to meet either
22 compliance requirements, improve system reliability, fix
23 broken equipment, or replace aging equipment that is
24 anticipated to fail.
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Avista Corporation
1 Included in the compliance requirements are the North
2 American Electric Reliability Corporation (NERC) standards,
3 which are national standards that utilities must meet to
4 ensure interconnected system reliability.Beginning June
5 2007 compliance with these standards was made mandatory and
6 failure to meet the requirements could result in monetary
7 penal ties of up to $1 million per day per infraction. The
majority of the reliabili ty standards pertain to8
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transmission planning,operation,and equipment
maintenance.The standards require utili ties to plan and
11 operate their transmission systems in such a way as to
12 avoid the loss of customers or impact to neighboring
13 utility systems due to the loss of transmission facilities.
14 The transmission system must be designed and operated so
15 that the loss of up to two facilities simultaneously will
16 not impact to the interconnected transmission system.
17 These requirements drive the need for Avista to continually
18 invest in its transmission system. Avista is required to
19 perform system studies in both the near term (1-5 years)
20 and long term (5-10 years). If a potential violation is
21 observed in the future years, then Avista must develop a
22 project plan to ensure that the violation is fixed prior to
23 it becoming a real i t Y .Avista budgets for the future
24 projects and ensures that the design and construction of
25 the required proj ects are completed prior to the time they
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Avista Corporation
1 are needed.Avista will always have a need to develop
2 these compliance related projects as system load grows, new
3 generation is interconnected and the system functionality
4 and usage changes.
5 Avista capital Transmission project requirements are
6 developed through system planning studies, engineering
7 analysis, or scheduled upgrades or replacements.The
8 larger specific projects that are developed through the
9 system planning study process typically go through a
10 thorough internal review process that includes multiple
11 stakeholder review to ensure all system needs are
12 adequately addressed.Smaller proj ects are selected to
13 meet specific system needs or equipment replacement.
14 However, both project cost and system benefits are
15 considered in the selection of the final projects.
16 The major capital transmission costs (system) for
17 projects to be completed in 2010 are approximately $18.888
18 million as described below.
19 The specific projects scheduled for 2010 completion
20 related to reliability compliance projects will cost
21 $13.372 million (again, on a system basis) and include:
22 Reliability Compliance Projects:
23 . Lolo 230 kV Substation ($1.450 million): This project24 involves the rebuild of the existing Lolo substation
25 to increase the capacity of the substation bus,26 breakers, and supporting equipment to match the27 upgraded capacity of the transmission lines that28 connect to the substation. The new Lolo substation29 design significantly improves reliability and
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Avista Corporation
1 operating flexibility. The Lolo Substation project
2 was constructed in phases to allow operational
3 flexibility due to system reliability concerns
4 associated with other scheduled construction in the
5 area. Phase 1 was completed in 2007 and the remainder
6 of the project ($1.45 million) was completed in
7 February 2010. The Lolo Substation project costs were
8 developed by the Engineering Department and approved
9 through the capital budget process. This project is
10 required to meet Reliability Compliance under NERC
11 Standards: TOP-004-2 R1-R4, TPL-002-0a R1-R3, and TPL-
12 003-0a R1-R3.
13
14 . Spokane/Coeur d' Alene area relay upgrade ($1. 25015 million) : This project involves the replacement of16 older protective 115 kV system relays with new micro-17 processor relays to increase system reliability by18 reducing the amount of time it takes to sense a system19 disturbance and isolate it from the system. This is a20 five year project and is required to maintain21 compliance with mandatory reliability standards. This22 proj ect is required to meet Reliability Compliance
23 under NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-
24 R3, TPL-003-0a R1-R3.
25
26 . Nez Perce 115 kV Substation Rebuild and Capacitor Bank27 ($3.575 million): This project involves the complete28 rebuild of the Nez Perce substation based upon its29 degraded condition. The project also includes the30 addi tion of a shunt capacitor bank to provide voltage31 support to the area for critical contingencies to
32 ensure compliance with NERC Standards: TOP-004-2 R1-
33 R4, TPL-002-0a R1-R3, TPL-003-0a R1-R3.
34
35 . SCADA Replacement ($0.800 million): The System Control
36 and Data Acquisition (SCADA) system is used by the37 system operators to monitor and control the Avista
38 transmission system. The SCADA system will be39 upgraded in 2010 to a new version provided by our40 SCADA vendor. The current application version is no41 longer supported by the vendor. The upgrade will42 ensure Avista has adequate control and monitoring of
43 its Transmission facilities. This portion of the44 proj ect is required to meet Reliability Compliance
45 under NERC Standards: TOP-001-1, TOP-002-2a R5-R10,
46 R16, TOP-005-2 R2, TOP-006-2 R1-R7. Several Remote47 Terminal Units (RTUs) located at substations48 throughout Avista's service territory will also be
Kinney, Di 23
Avista Corporation
1 replaced. The RTUs are part of the transmission
2 control system.
3
4 . System Replace/Install Capacitor Bank ($0.750
5 million): This project includes the construction of a
6 115 kV capacitor bank at Airway Heights to support
7 local area voltages during system outages. The
8 proj ect is required to meet reliability compliance
9 with NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-
10 R3, TPL-003-0a R1-R3, and provide improved service to11 customers. The proj ect is scheduled to be completed12 by July of 2010.
13
14 . Airway Heights-Silver Lake (North Fairchild Tap) 115kV15 Transmission Line ($0.975 million): This work is16 necessary to upgrade the final 2.5 miles of the ten
17 mile long transmission line from #2/0 ACSR to 556 kcm
18 Aluminum (100 MVA-Summer) conductor. The line upgrade
19 will meet compliance requirements ~ssociated with NERC
20 Standards: TOP-004-2 R1-R4, TPL-002-0a R1-R3, TPL-003-21 Oa R1-R3. Additionally, this work will increase22 service reliability to an essential military facility23 (North Fairchild Air Force Base). Using 2009 actual24 loads, the new conductor will reduce line losses by 7125 MWh on an annual basis, establishing a yearly offset
26 savings of $7,100 (based on a $100/MWh avoided energy27 cost) ; these savings have been reflected in the
28 proposed revenue requirement.
29
30 . Mos230-Pullman 115 Reconductor ($1.300 million): Year31 two of this multi-year project continues to upgrade32 the transmission line from 1/0 copper to 556 kcm
33 Aluminum (100 MVA-Summer) conductor in order to34 mitigate thermal overloads experienced during heavy35 summer load conditions. The line upgrade will meet
36 compliance requirements associated with NERC
37 Standards: TOP-004-2 R1-R4, TPL-002-0a R1-R3, TPL-003-
38 Oa R1-R3. Using 2009 actual loads, the new conductor
39 will reduce line losses by 151 MWh on an annual basis,40 establishing a yearly offset savings of $15,100 (based
41 on a $100/MWh avoided energy cost); these savings have42 been reflected in the proposed revenue requirement.
4344 Environmental Regulation Projects:
45 . Beacon Storage Yard ($0.750 million): The Beacon46 Storage Yard is a location where circuit breakers and47 power transformers are stored and staged for rotation48 into existing substations as replacements or for new49 construction. This site is near the Spokane River and
Kinney, Di 24
Avista Corporation
1 this project work will provide an oil containment
2 system to protect the local environment. In 2009, the
3 Company constructed the bulk of the Beacon Substation
4 Equipment' Storage Yard for a total spend and transfer
5 to plant of $948k. In 2010, the remainder of the yard6 and a building to securely house the mobile
7 substations and battery trailer will be completed and8 transferred to plant.
910 Contractual Required Proj ects:
11 . Colstrip Transmission ($0.503 million): As a joint12 owner of the Colstrip Transmission projects, Avista
13' pays its ownership share of all capital improvements.14 Northwestern Energy either performs or contracts out
15 the capital work associated with the j oint owned16 facili ties.
17
18 . Tribal Permits ($0.519 million): The Company has19 approximately 300 right-of-way permits on tribal20 reservations that need to be renewed. The costs21 include labor, appraisals, field work, legal review,22 GIS information, negotiations, survey (as needed), and23 the actual fee for the permit.
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25 Reliabili ty Improvement Proj ects:
26 . Boulder-Rathdrum 115kV Transmission Line ($1.50027 million): Year two of this multi-year project to28 integrate the local load service of Idaho Road29 Substation will upgrade transmission connectivity from30 a "tap" configuration to considerably more reliable31 "loop" feed by installing approximately four miles of
32 transmission line with 795 kcm Aluminum (125 MVA-.
33 Summer) conductor. Using 2009 actual loads, the new34 conductor will reduce line losses by 100 MWh on an35 annual basis, establishing a yearly offset savings of
36 $10,000 (based on a $lOO/MWh avoided energy cost),
37 which has been incorporated into the Company's revenue
38 requirement.
39
40 The Company will also spend approximately $5.516
41 million in transmission system equipment replacements
42 associated with storm damage or aging/obsolete equipment.
43 A brief description of the larger projects included in
44 these replacement efforts are given below.
Kinney, Di 25
Avista Corporation
1 Replacement Proj ects :
2 . Transmission Minor Rebuilds ($1.250 million): These
3 projects include minor transmission rebuilds as a
4 result of age or damage caused by storms, wind, fire,
5 and the public. These smaller projects are required to
6 operate the transmission system safely and reliably.
7 Facili ties will need to be replaced when damaged in
8 order to maintain customer load service. In 2009 the
9 Company spent $2.206 million on these minor rebuild10 proj ects as a result of damage caused by weather or11 the public.
12
13 . Power Circuit Breakers ($0.485 million): The Company14 transfers all circuit breakers to plant upon receiving15 them. Breakers purchased in 2010 will be installed at
16 Otis Orchards (WA) Swi tching Station. Planned17 replacements in 2010 include a 115 kV breaker at
18 Stratford (WA) Switching Station and a 230 kV breaker
19 at Noxon Rapids Switchyard.
20
21 . Pine Creek - Replace 115 kV Circuit Switcher & Cap22 Bank ($0.570 million): The project scope and
23 preliminary engineering design work for this project
24 was started in 2008 and included replacing the circuit25 switcher and one 13 kV recloser due to equipment age.26 After further investigation the project was expanded
27 to replace the other two 13 kV reclosers, the cap28 bank, deteriorated station control wiring, and removal
29 of the small panel house including the obsolete Remote30 Terminal Unit (RTU). A total of $0.57 million31 directly related to Transmission (115 kV circuit32 swi tcher, Capacitor Bank, control wiring, Remote33 Terminal Unit) will be transfered to plant in 2010.
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35 . Otis Orchards 115 kV Breaker and Line Relay36 Replacements ($0.650 million): This project will37 replace the 115 kV breakers and associated 115 kV line38 relays at the existing Otis Orchards substation. Four39 of the breakers are over 50 years old and have reached40 the end of their useful lives. The line relaying must41 be replaced with new microprocessor relays to provide
42 the high speed tripping required for mandatory
43 reliability standards. The relay replacements are
part
44 of the Spokane/Coeur d' Alene area relay upgrade45 project previously discussed.
46
47 . Replacement Programs ($2.044 million): Avista has48 several different equipment replacement programs to49 improve reliability by replacing aged equipment that
Kinney, Di 26
Avista Corporation
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is beyond its useful life. These programs include
transmission and substation air switch upgrades,
arrestor upgrades, restoration of substation rock and
fencing, recloser replacements, replacement of
obsolete circui t swi tchers, substation battery
replacement, interchange meter replacements, highvol tage fuse upgrades, replacement of fuses with
circuit switchers, and voltage regulator replacements.
All of these individual proj ects improve system
reliabili ty and customer service.
. Other Small Transmission Projects ($.517 million):
These projects include various other smaller
transmission system equipment replacement proj ects.
Q.Please describe the Company's distribution
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projects in the State of Idaho that will be completed in
2010.
A.Distribution Projects in Idaho (including
transformation) for 2010 total $8.255 million.These
22 proj ects are necessary to meet capacity needs of the
23 system, improve reliability, and rebuild aging distribution
24 The following projects make upsubstations and feeders.
25 the $8.255 million.
26 . Appleway Substation ($1.980 million) - Appleway 115-1327 kV Substation is a wood substation serving most of the28 City of Coeur d'Alene. The station has reached the29 end of its useful life and additional capacity is
30 required. The new station will include 2-30 MVA31 transformers and six 13 kV feeders. Approximately32 $416k was spent in 2009 for grading, fencing, and the33 start of foundation work. It is estimated that $1.7534 million will be staged into plant in 2010 with the35 remainder of the proj ect completed in 2011.
36
37 . Deary Substation ($1.405 million) Deary 115-24 kV38 Substation is a wood substation scheduled to be39 rebuilt as a steel substation in 2010. Engineering,
40 site grading, and fencing were completed in 2009.
Kinney, Di 27
Avista Corporation
1 Approximately $490k has been spent on this project as
2 of the end of 2009. The foundations, structures,
3 equipment, and electrical work will be completed by
4 the end of Q3 2010.
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6 . Power Transformer Distribution ($4.740 million system
7 / $1.815 million Idaho) - Transformers are transferred
8 to plant upon receiving them. These transformers are
9 being purchased to replace existing spares that will
10 be installed as ei ther replacements or new11 installations.
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13 . System - Dist Reliability - Improve Worst Feeders14 ($0.700 million): Based on a combination of15 reliabili ty statistics, including CAIDI, SAIFI, and16 CEMI (Customers Experiencing Multiple Interruptions),17 feeders have been selected for reliability improvement18 work. This work is expected to improve the
19 reliability of these feeders. The improvements at20 Clark Fork (ID) will include $250k for a new21 substation feeder bay and associated equipment.
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23 . Distribution - CdA East & North ($0.905 million)24 These are all Idaho distribution proj ects. These25 represent four discrete feeder reconductor proj ects as
26 determined by SynerGee modeling as thermally27 constrained.
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29 . Rathdrum Transformer and 233 Feeder Addition ($0.90030 million) - This project added a second 115-13 kV, 20
31 MVA Distribution Power Transformer and a new 13 kV32 feeder serving the greater Rathdrum-Post Falls area.33 The proj ect was required for system reliability and to34 allow for better system operational flexibility and
35 maintenance scheduling. The work started in 2009 and
36 was completed in February 2010..
37
38 . Pine Creek - Replace 115 kV Circuit Switcher & Cap39 Bank ($0.300 million): The project scope and40 preliminary engineering design work for this project41 was started in 2008 and included replacing the circuit42 switcher and one 13 kV recloser due to equipment age.43 After further investigation the proj ect was expanded
44 to replace the other two 13 kV reclosers, the cap45 bank, deteriorated station control wiring, and removal
46 of the small panel house including the obsolete RTU.47 Distribution costs associated with the recloser48 replacement will be $0.30 million.
49
Kinney, Di 28
Avista Corporation
1 . Potlatch (ID) Transformer Replacement ($0.250
2 million) : Transformer 1 at Potlatch Substation in
3 Potlatch, ID, must be replaced due to environmental
4 concerns. The transformer was received in 2009 and
5 transferred to plant. These costs are the associated
6 labor costs to install the new transformer.
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8 The Company also will spend approximately $22.872
9 million (system) in equipment replacements and minor
10 rebuilds associated with aging distribution equipment
11 discovered through inspections,feeders with poor
12 reliability performance, replacements from storm damage, or
13 relocation of feeder sections resulting from road moves. A
14 brief description of the projects included in these
15 replacement efforts is given below.
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17 . Electric Distribution Minor Blanket Projects ($7.00018 million): This effort includes the replacement of19 poles and cross-arms on distribution lines in 2010 as20 required, due to storm damage, wind, fires, or
21 obsolescence. The company spent $9.22 million in 200922 for these proj ects.
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24 . Wood Pole Replacement Program and Capital Distribution25 Feeder Repair ($6.884 million): The distribution wood-26 pole management program is a strength evaluation of a27 certain percentage of the pole population each year.28 We have over 240,000 distribution poles and 34,50029 transmission poles in our electric system. Depending30 on the test results for a given pole, that pole is31 either considered satisfactory, reinforced with a32 steel stub, or replaced. As feeders are inspected as
33 part of the wood-pole management program, issues are34 identified unrelated to the condition of the pole.35 This project also funds the work required to resolve36 those issues (i. e. leaking transformers, transformers37 older than 1964, failed arrestors, missing grounds,38 damaged cutouts). Since the pre-World War II buildup39 wood poles have reached the end of their useful life,
40 Avista's Wood Pole Management program was put into
Kinney, Di 29
Avista Corporation
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place to prevent the Pole-Rotten events and Crossarm -
Rotten events from increasing. So far, the Wood Pole
Management Program has helped keep Pole-Rotten and
Crossarm-Rotten events in check. The Company spent
$8.276 million on these efforts in 2009.
. Electric Underground Replacement ($4.000 million):
This effort involves replacing the first generation of
Underground Residential District (URD) cable, which
has been ongoing for the past several years. This
program focuses on replacing a vintage and type of
cable that has reached its end of life and contributes
significantly to URD cable failures. The Company
spent $3.69 million in 2009. The incremental savings
in Operation and Maintenance expenses seen in 2009
compared to 2008 was $120,000 due to reduced number of
URD Primary Cable fault reductions. For the pro forma
period, we anticipate that we will see the same
incremental savings as 2009, which has been included
as an offset for the Electric Underground Replacementproject.
. T&D Line Relocation ($2.348 million): The relocation
of transmission and distribution lines as required due
to road moves requested by State, County or City
governments. The Company spent $2.2 million in 2009 on
line relocations associated with road moves.
.Failed Electric
of distributionrequired due to
$3.44 million in
Plant ($2.000 million): Replacement
equipment throughout the year as
equipment failure. The Company spent
2009.
. Other Small Distribution projects ($0.640 million):These projects include various smaller distributionproj ect equipment replacements and minor rebuilds,
such as the distribution feeder reconductor project
identified as "thermally constrained" portions of the
feeder trunk lines located in Pullman and Lewis Clarkvalley.
Q.this complete your pre-filed directDoes
testimony?
A.Yes, it does.
Kinney, Di 30
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
DAVID. MEYER~AVISTACORP. COM
BEFORE .THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-10-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 8
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO ) SCOTT J. KINNEY
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avlsta Corporation
. Energy Delivery .
Pro Forma Transmission Revenue/Expenses
($OOOs)Oct 2010-
Sep 2011
Line 2009 Pro Forma
No.Actal Adjusted Period-
556 OTHER POWER SUPPLY EXPENSES
NWPP 36 4 40
560=71.4. 935.3-.4 TRANSMISSION O&M ËXPENSE
2 Colstrip O&M - 500kV Line 491 98 589
3 CoIumbiaGrid Development 202 -10 192
4 ColumbiaGrid Planning 142 73 215
5 CoIumbiaGrid OASIS 35 45 80
6 ColumbiaGrid DSRFA 2 .2 0
7 Grid West (10)71 0 71
8 Total Accunt 560-71.4,935.3-.4 943 204 1,147
561 TRNSMISSION EXP-LOAD DISPATCHING
9 Elect Sched & Acctg Srv (CASSO/OATI)172 -12 160
566 TRANSMISSION EXP-oPRN-MISCELLAEOUS
10 NERCCIP 25 0 25
11 OASIS Expenses 4 5 9
12 BPA Power Factor Penalty 124 22 146
13 WECC - Sys. Security Monitor 159 9 168
14 WECC Admin & Net Oper Comm Sys 329 41 370
15 WECC . Loop Flow 40 -6 34
16 Total Accnt 556 681 71 752
17 TOTAL EXPENSE 1,832 267 2,099
456 OTHER ELECTRIC REVENUE
18 Borderline Wheeling 5,552 2,286 7,838
19 Seatterracoma Main Canal 193 83 276
20 Seattle/ Tacoma Summer Falls 74 0 74
21 OASIS nf & stf Whl (Oter Whl)2,962 779 3,741
22 PP&L - Diy Gulch 206 43 249
23 Spokane Waste to Energy Plant 160 0 160
24 * Vaagen Wheeling 97 -97 0
25 * Grant County PUD 56 -14 42
26 Grand Coulee Project 8 0 8
27 * PP&L Series Cap -1978 5 -5 0
28 ** NaturEner Pwr Watch 10 -10 0
29 ** FERC Settement 115 -115 0
30 Total Accunt 456 9,438 2,950 12,388
31 TOTAL REVNUE 9,438 2,950 12,388
32 TOTAL NET EXPENSE -7,606 -2,683 -10,289
* Contracts ended in either 2009 or 2010.
**One time events.
Exhibit No.8
Case No. AW-E.10.Q1
S. Kinney, Avlst
SChedule 1, p. 1 of 1