20110706Kinney Di.pdf

RECEIVED
DAVID J. MEYER iûll JUL -5 Mill: 44
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P .0. 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
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-11-01
DIRECT TESTIMONY
OF
SCOTT J. KINNEY
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
1
2
I. INTRODUCTION
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 educational
9 background 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
14
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
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, 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
26 the capital additions testimony provided by Company witness
27 Mr. DeFelice, as well as projects associated with the
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Avista Corporation
1 Company's Asset Management Program (including the
2 addi tional vegetation management expenses included in the
3 Company's case). Company witness Ms. Andrews incorporates
4 the Idaho share of the net transmission expenses, the
5 transmission and distribution capital additions, and the
6 electric distribution vegetation management expenses
7 proposed in this case.
8
9
Q.Are you sponsoring any exhibits?
A.Yes.Exhibit 9,Schedule 1 provides the
10 transmission pro forma adj ustments, and Schedule 2C is the
11 Transmission Line Ratings Confirmation Plan (original dated
12 January 18, 2011 and Revision B dated April 27, 2011) that
13 was developed and filed with NERC to address the "NERC
14 Alert" issued on October 7, 2010.
15 A table of contents for my testimony follows:
16
17
18
19
Section Page
III. Pro Forma Transmission Revenue
1
2
21
I. Introduction
II. Pro Forma Transmission Expenses
20 iv. Transmission and Distribution Capital Proj ects 29
21 V. Avista's Asset Management Program 54
22
23
24
II. PRO FORM TRASMISSION EXPENSES
Q.Please describe the pro form transmission
25 expense revisions included in this filing.
26 A.Adj ustments were made in this filing to
27 incorporate updated information for any changes in
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Avista Corporation
1 transmission expenses from the January 2010 to December
2 2010 test year to the 2012 pro forma rate period.The
3 changes in expenses and a description of each is summarized
4 in Table 1:5 Table i
Transmission
Expenses
*Pro Form
CSvstem)
Northwest Power Pool (NWPP)$1,000
Colstrip O&M -500kV Line $117,000
ColumbiaGrid RTO Development $ (14,000)
ColumbiaGrid Plannina $56,000
ColumbiaGrid OASIS $42,000
Grid West (ID Direct)$ (71, 000)Electric Schedulina &Accta.Services (OATI)$4,000
NERC CIP $3,000
OASIS Expenses $1,000
BPA Power Factor Penaltv $(7,000)
WECC Svs Secur &Admin-Net Oper Comm Svs $ (21, 000)
WECC -Loop Flow $12,000
CNC Transmission Proiect $255,000TransmissionLineRatingsConfirmationPlan
(NERC Alert)$2,145,000
Total Expense $2,523,000
6
7 *Representing the change in expense above or below the 2010 test period level.
8
9
10
Northwest Power Pool (NWPP) ($1,000) - Avista pays its
share of the NWPP operating costs.The NWPP serves the
11 electric utilities in the Northwest by supporting regional
12 transmission planning coordination, providing coordinated
13
14
transmission operations including generation reserve
sharing, and Columbia River water coordination.Actual
15 2010 transmission-related NWPP expenses were $42,000 and a
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Avista Corporation
1 $1,000 increase was made for the pro forma period to
2 reflect the NWPP expenses allocated to the Company.
3 Colstrip Transmission ($117,000) - Avista is required
4 to pay its portion of the O&M costs associated with its
5 share of the Colstrip transmission system pursuant to the
6 joint Colstrip contract.In accordance with NorthWestern
7 Energy's (NWE) proposed Colstrip transmission plan provided
8 to the Company, NWE will bill Avista $560,000 for Avista's
9 share of the Colstrip O&M expense during the pro forma
10 period.This is an increase of $117,000 from the actual
11 expense of $443,000 incurred during the 2010 test year.
12 ColumbiaGrid RTO Development (-$14,000)Avista
13 became a member of the ColumbiaGrid regional transmission
14 organization (RTO) in 2006.ColumbiaGrid's purpose is to
15 enhance transmission system reliability and efficiency,
16 provide cost-effective coordinated regional transmission
17 planning, develop and facilitate the implementation of
18 solutions relating to improved use and expansion of the
19
20
interconnected Northwest transmission system,reduce
transmission system congestion,and support effective
21 market monitoring wi thin the Northwest and the entire
22 Western interconnection.Avista supports ColumbiaGrid's
23 general developmental and regional coordination acti vi ties
24 under a general funding agreement and supports specific
25 functional acti vi ties under the Planning and Expansion
26 Functional Agreement and the OASIS Functional Agreement.
27 The current general funding agreement for ColumbiaGrid
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1 expires December 31, 2012.Avista's ColumbiaGrid general
2 funding expenses for the 2010 test year were $194,000 while
3 pro forma general funding expenses are $180,000,a
4 reduction of $14,000.
5 ColumbiaGrid Transmission Planning ($56,000)The
6 ColumbiaGrid Planning and Expansion Functional Agreement
7 (PEFA) was accepted by the Federal Energy Regulatory
8 Commission (FERC) on April 3, 2007 and Avista entered into
9 the PEFA on April 4, 2007.Coordinated transmission
10 planning acti vi ties under the PEFA allows the Company to
11 meet the coordinated regional transmission planning
12 requirements set forth in FERC's Order 890 issued in
13 February 2007, and outlined in the Company's Open Access
14 Transmission Tariff, Attachment K. Funding under the PEFA
15 is on a two-year cycle with provisions to adjust for
16
17
inflation.Actual PEFA expenses for the 2010 test year
were $164,000.The Company's PEFA pro forma expenses are
18 at the maximum total payment obligation of $220,000,
19 reflecting ColumbiaGrid's final staffing levels to support
20 the PEFA and the reallocation of a portion of
21 ColumbiaGrid's administrative expenses (previously paid
22 under the general funding agreement) to this functional
23 agreement.
24 ColumbiaGrid Open Access Same-Time Information System
25 (OASIS) ($42,000) - Avista entered into the ColumbiaGrid
26 OASIS Functional Agreement in February 2008.This
27 agreement provides for the development of a common Open
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Avista Corporation
1 Access Same-time Information System (OASIS) which would
2 give transmission customers the ability to purchase
3 transmission capacity from all ColumbiaGrid members via a
4 single common OASIS site instead of having to submit
5 multiple transmission service requests to each member
6 individually on each member's respective OASIS sites.
7 Avista's 2010 test year expenses of $44,000 reflected
8 ini tial developmental acti vi ties under this functional
9 agreement. Avista's ColumbiaGrid OASIS pro forma expenses
10 are $86,000, reflecting operational capability of the
11 ColumbiaGrid OASIS and the reallocation of a portion of
12 ColumbiaGrid's administrative expenses (previously paid
13 under the general funding agreement) to this functional
14 agreement.
15 Grid West (ID Direct) (-$71,000) - Avista signed an
16 initial funding agreement in 2000, as did all other Pacific
17 Northwest investor-owned electric utili ties, to provide
18 funding for the start-up phase of Grid West (then named
19 "RTO West").Grid West had planned to repay the loans to
20 Avista and other funding utilities through surcharges to
21 customers once it became operational. With the dissolution
22 of Grid West, this repayment did not occur. As a result,
23 Avista filed an application with the Commission to defer
24 these costs. The Commission approved, on October 24, 2006,
25 in Order No. 30151, the Company's request for an order
26 authorizing deferred accounting treatment for loan amounts
27 made to Grid West. In its Order the IPUC found these costs
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Avista Corporation
1 to be "prudent and in the public interest" and required the
2 Company to begin amortization of the Idaho share of the
3 loan principal ($422,000) beginning January 2007, for five
4 years. With the completion of the amortization in December
5 2011 the Company will not incur costs associated with Grid
6 West in the pro forma period. Avista did amortize a total
7 of $71,000 in the test year.
8 Electric Scheduling and Accounting Services ($4,000) -
9 The $4,000 increase in the pro forma period compared to
10 test year expense for electric scheduling and accounting
11 services is a result of additional services provided by our
12 third party vendor.These services are required to assist
13 in meeting the requirements of the NERC mandatory
14 reliabili ty standards.The pro forma scheduling and
15 accounting costs are $175,000.
16 NERC Critical Infrastructure Protection ($3,000) - The
17 Company has purchased two software products to assist in
18 protecting critical transmission system data from intrusion
19 and to meet applicable North American Electric Reliability
20
21
Corporation (NERC)Cri tical Infrastructure Protection
standards.The Company's pro forma expenses increase
22 $3,000 from the actual 2010 test year expense of $47,000
23 due to annual software application cost increases.
24 OASIS Expenses ($1,000) - These OASIS expenses are
25 associated with travel and training costs for transmission
26 pre-scheduling and OASIS personnel.This travel is
27 required to monitor and adhere to NERC reliability
Kinney, Di 7
Avista Corporation
1 standards and FERC OAS I S requirements.The costs
2 associated with OASIS expenses in the pro forma period are
3 $1,000 more than in the 2010 test year.
4 Power Factor Penalty (-$7,000) - Power factor penalty
5 costs are associated with the Bonneville Power
6 Administration's (Bonneville) General Transmission Rate
7 Schedule Provisions.Bonneville charges a power factor
8 penal ty at all interconnections with Avista that exceed a
9 gi ven threshold for reactive power flow during each month.
10 If the reactive flow from Bonneville's transmission system
11
12
into Avista's system or from Avista's system to
Bonneville's system exceeds a given threshold,then
13 Bonneville bills Avista according to its rate schedule.
14 The charge includes a 12-month rolling ratchet provision.
15 Avista currently pays Bonneville a power factor penalty at
16 several points of interconnection.Avista incurred
17 $138,000 of power factory penalty charges during the 2010
18 test year.The Company's pro forma 2012 expenses are set
19 at $131,000 representing an average of the power factor
20 penalty charges incurred in 2009 and 2010.
21 WECC - System Security Monitor and WECC Administration
22 & Net Operating Committee Fees (-$21,000) - The Company's
23 total WECC fees have begun to level off. The past increases
24 have been driven primarily by increased compliance
25 requirements associated with mandatory national reliability
26 standards.WECC is responsible for monitoring and
27 measuring Avista' s compliance with the standards and,
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Avista Corporation
1 therefore, has substantially increased its staff and other
2 resources to meet this FERC requirement.The Company's
3 2010 test year WECC assessments were $167,000 for system
4 security monitoring and $384,000 for dues and net Operating
5 Committee fees, for a total 2010 WECC assessment of
6 $551,000.The Company paid its 2011 WECC assessments in
7 January 2011: $171,000 for system security monitoring and
8 $359,000 for dues and net Operating Committee fees, for a
9 total WECC assessment of $530,000. The Company's pro forma
10 2012 expenses have been set equal to these amounts paid in
11 January 2011.
12 WECC - Loop Flow ($12,000) - Loop Flow charges are
13 spread across all transmission owners in the West to
14 compensate utili ties that make system adj ustments to
15 eliminate transmission system congestion throughout the
16 operating year. WECC Loop Flow charges can vary from year
17 to year since the costs incurred are dependent on
18 transmission system usage and congestion.Therefore a
19 five-year average is used to determine future Loop Flow
20 costs.Based upon the WECC Loop Flow charges incurred by
21 the Company during the five-year period from 2006 through
22 2010, pro forma Loop Flow expenses are $32,000.This is
23 $12,000 more than actual 2010 test year charges of $20,000.
24 Q.Please describe Avista' s engagement in the
25 Northern Tier Transmission Group?
26
27
A.Avista is currently a Member of the ColumbiaGrid
Subregional Group.ColumbiaGrid currently coordinates
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Avista Corporation
1 regional transmission planning for its members, offers a
2 single portal access to OASIS, and performs regional
3
4
5
6
7
coordination and development of other operational
improvement efforts including evaluating Balancing
Authori ty consolidation of its members.Avista is a
signa tory to the Planning and Expansion Functional
Agreement (PEFA)and has relied on the PEFA and
8 ColumbiaGrid to meet its FERC Order 890 Attachment K
9 Requirements. Avista initially joined ColumbiaGrid to
10 leverage an independent organization's ability to direct
11 BPA (only as bound by the PEFA) to construct needed
12 facili ties and leverage ColumbiaGrid's dispute resolution
13 process and cost allocation methodologies to meet FERC's
14 Attachment K requirements.
15 Avista is geographically located at the edge of both the
16
17
ColumbiaGrid and NTTG footprints and is physically
interconnected with several NTTG members;Idaho Power,
18 NorthWestern Energy and PacifiCorp. Avista also participates
19 in several current regional study efforts to expand the
20 northwest transmission system that involve these same
21 enti ties.
22 With its geographic location and physical
23 interconnection to both ColumbiaGrid and NTTG members,
24 Avista plans to join NTTG in 2011. Avista will engage NTTG
25 to determine what level of membership makes sense. Avista
26 hopes to join NTTG as a nominal funder and participant.
27 Becoming an NTTG member will allow Avista to gain knowledge
Kinney, Di 10
Avista Corporation
1 of NTTG processes, continue to enhance relationships with
2 its interconnected utili ties, and further facilitate the
3 relationship between the two sub-regional groups.Avista
4 intends to remain a full member of ColumbiaGrid and utilize
5 ColumbiaGrid and the PEFA to meet its FERC Attachment K
6 requirements. At this time, no additional costs have been
7 included in the Company's case for its involvement in the
8 group.
9 Q.Please now describe the proposed Canada to
10 Northern California ("CNC") transmission project expense
11 included in the Company's request.
12 A.The CNC transmission proj ect was initially
13 proposed with Pacific Gas and Electric Company ("PG&E") as
14 its primary sponsor.As initially proposed, the CNC
15 transmission proj ect was an Extra High Voltage ("EHV")
16 transmission project that, if developed, would include a
17 500 kV transmission line that would run between British
18 Columbia, Canada and Northern California. With PG&E as the
19 primary sponsor, Avista, British Columbia Transmission
20 Corporation, PacifiCorp and Transmission Agency of Northern
21 California were sponsors of the CNC transmission project.
22 Q.What was the purpose of the CNC transmission
23 project?
24 A.The CNC transmission project was evaluated as a
25 regional proj ect intended to meet three primary objectives:
26
27
28
29
1.Enhance access torenewable resources in
Northwest;
significant
Canada and
incremental
the Pacific
Kinney, Di 11
Avista Corporation
1
2
3
4
5
2. Improve regional transmission reliability; and
3. Provide market participants with beneficial
opportuni ties to use the facilities.
Ini tially, the CNC transmission project offered three
6 distinct al ternati ves for satisfying these obj ecti ves,
7 which included:
8
9
10
11
12
13
14
15
16
1.
2.
An overland al ternati ve from Southeast British
Columbia to Northern California;
An overland alternative from Idaho to Northern
California; andAn undersea alternative from Western British
Columbia to Northern California.
3.
Q.Why was Avista one of the sponsors of the CNC
17 transmission project?
18
19
20
A.While there were several reasons why Avista was a
sponsor of the CNC transmission project,Avista's
sponsorship was based upon two primary obj ectives:(i) to
21 obtain access to additional resources and additional import
22 capaci ty to serve the needs of Avista' s native load
23 customers,and (ii)to maintain and enhance system
24 reliability.
25 The CNC transmission proj ect offered an opportunity
26 for Avista to access resources that would help Avista meet
27 its intermediate and long-term future renewable resource
28 needs in order to satisfy its renewable portfolio standard
29 requirements, as well as, other resources to meet future
30 native load.In the context of integrating variable
31 renewable resources, future access to regulation or shaping
32 services from BC Hydro was also a consideration.
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Avista Corporation
1 To the extent Avista intends to consider any new
2 resources, renewable or otherwise, that reside outside its
3 service terri tory to meet the future needs of the Company's
4 native load customers, the Company must maintain and
5 develop additional import capacity on its transmission
6 system to accommodate such resources. The vast majority of
7 the Company's current transmission import capability flows
8 through its interconnections with the Bonneville Power
9 Administration.The CNC transmission project not only
10 offered an opportunity to provide for future increase in
11 import capability, but provided an opportunity to diversify
12 that import capability.
13 The CNC transmission project also would serve to
14 enhance system reliability both from a regional standpoint
15 and specifically for Avista's system. The CNC transmission
16 project would provide an EHV (extra-high voltage) source on
17 the west side of Avista's service terri tory, increasing the
18 overall reliability of Avista' s transmission grid. Avista
19 currently has only three 500 kV sources supporting its
20 transmission system; the Company's Bell, Hatwai and Hot
21 Springs interconnections, which are all with the Bonneville
22 Power Administration.
23 By participating as a sponsor of the CNC transmission
24 project, Avista was able to affect certain determinations
25 regarding the project, including the choice of the overland
26 alternative from Southeast British Columbia to Northern
Kinney, Di 13
Avista Corporation
1 California, and the planned interconnection with Avista's
2 transmission system at Devils Gap.
3 Addi tionally, Avista was an affected party that needed
4 to participate in review and analysis of the project as
5 part of the Company's coordinated regional planning
6 obligations under Attachment K to its Open Access
7 Transmission Tariff.
8 Q.What is the current status of the CNC
9 transmission project?
10 A.Currently,the CNC transmission project is
11 undergoing a transformation. As originally conceived, the
12 project sponsors planned to work cooperatively to develop a
13 single transmission project from Canada to Northern
14 California.That project has completed the Western
15 Electrici ty Coordinating Council ("WECC") Regional Planning
16 and Proj ect Review process and Phase 1 Rating Study, and it
17 is now in the WECC Phase II study process. As the project
18 has evolved, however, the current sponsors BC Hydro,
19 Avista, and PG&E have recognized that each sponsor now
20 desires to focus its resources on potential transmission
21 segments that are geographically closer to its own
22 respecti ve service area.PG&E continues to be interested
23 in developing a transmission line from Northern California
24 to Eastern Oregon.Similarly, BC Hydro is interested in
25 developing a transmission line from Canada to Eastern
26 Oregon. Accordingly, the CNC transmission project is being
27 evaluated as two distinct projects; a northern project
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Avista Corporation
1 which will be a 500kV transmission line from Selkirk, BC to
2 a transmission switching station in Northeast Oregon
3 ("NEO"), and a southern proj ect that will run from NEO to
4 Northern California.To the extent that the northern
5 and/or southern projects are developed, they will be
6 developed as separate projects that will likely be
7 sponsored primarily by BC Hydro and PG&E, respectively.
8 Q.Will Avista continue to participate as a sponsor
9 of either the proposed northern or the proposed southern
10 transmission lines?
11
12
13
A.Avista has not yet made a final determination
regarding the scope of its participation,including
sponsorship, in the northern transmission line.At this
14 point in time, Avista has no plans to participate as a
15 sponsor in the southern transmission line.
16 Q.Will Avista continue to participate in the
17 development of either the proposed northern or the proposed
18 southern transmission lines?
19 A.Yes.While Avista has not yet made a final
20 determination regarding the scope of its participation, to
21 the extent that BC Hydro continues to develop the northern
22 transmission line,Avista will need to continue to
23 participate in the regional planning process as an affected
24 party under its Attachment K and as planning acti vi ties
25 relate to the Company's development of its Devils Gap
26 Interconnection.Avista does not anticipate the need to
Kinney, Di 15
Avista Corporation
1 continue participation in the southern transmission line at
2 this time.
3 Q.Have Avista's customers derived any benefit from
4 Avista's initial participation in the CNC transmission
5 project?
6 A.Yes. As explained previously in this testimony,
7 there were initially three al ternati ves for developing the
8 CNC transmission project.Through its participation as a
9 sponsor of the CNC transmission project, Avista was
10 instrumental in the selection of the first al ternati ve
11 (i. e., an overland route from Southeast British Columbia to
12 Northern California)and the establishment of a
13 transmission corridor for the project that would run
14 through Avista' s service terri tory. To the extent that the
15 northern transmission line is developed, the current plans
16 call for the use of portions of existing Avista
17 transmission corridors. This is significant because Avista
18 will be able to establish an interconnection to the
19 northern transmission line at Devils Gap, which would meet
20
21
the objectives sought by the Company, namely:(i) access
to additional resources,shaping services and import
22 capacity to meet the needs of native load customers, and
23 (ii) enhanced system reliability, as described earlier in
24 this testimony.
25 Q.Please explain the benefits of Avista' s planned
26 interconnection with the northern transmission line at
27 Devils Gap.
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Avista Corporation
1 A.Avista is planning the development of a 500/230
2 kV transmission interconnection project with the northern
3 transmission line of the CNC transmission project at Devils
4
5
Gap ("Devils Gap Interconnection").Avista has completed
the Western Electricity Coordinating Council ("WECC" )
6 Regional Planning and Project Review process and Phase 1
7 Rating Study for the Devils Gap Interconnection and is now
8 in the WECC Phase II study process for this proj ect.In
9 conj unction with the northern portion of the CNC
10 transmission project, the Devils Gap Interconnection would
11 provide benefits to Avista's native load customers
12 consistent with the Company's objectives previously
13 outlined.
14 Q.What is the cost associated with Avista's
15 participation in the CNC transmission project?
16
17
A.The cost accrued by Avista for its participation
in the CNC transmission project is $886,000.Of this
18 amount, $665,000 is the amount Avista paid for its initial
19 sponsorship of the CNC transmission project pursuant to the
20 Stage One Proj ect Development Agreement, and $221,000
21 consists of the direct transmission planning expenses
22 incurred by Avista. Avista anticipates receiving a refund
23 from the CNC Development Agreement of $121,000 with the
24 closure of the Stage One agreement in the third quarter of
25 2011.Therefore the Company's net expenditures are
26 $ 7 65, 00 0 .
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Avista Corporation
1 Q.How does Avista propose to recover the costs
2 associated with its participation in the CNC transmission
3 project?
4 A.Avista proposes to recover these expenses over a
5 three-year period, resulting in an amortized expense of
6 $255,000 ($89,000 Idaho share) in each of the next three
7 years.Ms. Andrews has reflected this amount in her
8 revenue requirement calculations.
9 Q.Please describe the Transmission Line Ratings
10 Confirmtion Plan and the amounts for which the Company is
11 requesting an increase in costs above its historical test
12 period.
13 A.The Transmission Line Ratings Confirmation Plan
14 was developed to address a "NERC Alert" issued on October
15 7 ,2010.The North American Electric Reliability
16 Corporation (NERC) issued a "Recommendation to industry
17 addressing Consideration of Actual Field Conditions in
18 Determination of Facility Ratings" based on a vegetation
19 contact conductor-to-ground fault by another Transmission
20 Owner, which stated at p. 4:
21 "NERC and the Regional Entities are concerned
22 that Transmission Owners and Generator Owners23 have, in some instances, not considered existing
24 field conditions when establishing facility25 ratings for transmission facilities, including
26 transmission conductors. Transmission Owners27 should strive to achieve a heightened awareness
28 of the actual operating conditions of their29 respecti ve transmission conductors and take30 prompt corrective action as necessary."
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Avista Corporation
1 Upon further review, the affected Transmission Owner
2 subsequently discovered significant discrepancies between
3 actual topography and the values used for design. Using a
4 Light Detection and Ranging (LIDAR)technology,the
5 Transmission Owner identified over one hundred (100)
6 previously undetected conductor-to-ground issues.These
7 discrepancies resulted in the Transmission Owner operating
8 with higher facility ratings than actual conditions. This
9 could lead to the Transmission Owner operating its system
10 to higher levels than appropriate and, therefore, impacting
11 the reliability of the interconnected transmission grid.
12 The NERC Alert was issued to provide the industry an
13 opportuni ty to review actual field conditions and compare
14 them to design values to ensure system reliability. Avista
15
16
is required to meet NERC Standard FAC-008-1 Facility
Ratings Methodology.The purpose of the standard is "To
17 ensure that facility ratings used in the reliable planning
18 and operations of the Bulk Electric System (BES) are
19
20
determined based on an established methodology or
methodologies. "Requirement Rl. 1 states that a Facility
21 Rating shall equal the most limiting applicable Equipment
22 Rating of the individual equipment that comprises that
23
24
Facility.Therefore Avista must adhere to the NERC Alert
in order to ensure compliance with FAC-008-1.If Avista
25 doesn't comply with the Alert, then the Company will lack
26 sufficient compliance evidence to provide auditors during
27 its next on-site audit.
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Avista Corporation
1 The Avista Transmission Line Ratings Confirmation Plan
2 is a three year program designed to:
3
4
5
6
7
. Provide true-up between Plan and Profile drawings
produced in the Transmission Line Design (TLD)
Group and the SCADA Variable Limit (SVL)
documents utilized by the System Operations
Group, provided to NERC under FAC-008-1.
8
9
10
. Establish a field confirmation process for
conductor sag clearances using a variety of
techniques.
11
12
13
. Provide a means to annually identify changes to
grade and other clearance impacts.
Unless otherwise exempted/ confirmed due to
14 construction inspection documentation or a substantial
15 design clearance buffer, the Plan calls for performing
16 LIDAR surveying of all Avista 230kV transmission lines and
17
18
the five (5) 115kV transmission lines.These lines
represent Avista's High Priori ty facilities (NERC
19 assessment reporting date of December 31, 2011 as mentioned
20 in the November 29, 2010 NERC update). It is expected this
21 process will take two years to complete, depending upon
22 availabili ty of resources and weather conditions.LIDAR
23 will allow for Avista to computer model (via TL-Pro) its
24 most important transmission lines,and also support
25 Transmission Vegetation Management efforts. The original
26 plan was submitted to NERC on January 18, 2011. A revised
27 plan was submitted on April 28, 2011 to show a modification
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Avista Corporation
1 to the overall cost estimate driven by changes in the
2 number of miles to be inspected using LIDAR. The original
3 NERC submission showed a cost of $1.8 million, and the new
4 submission increases the miles inspected using LIDAR to
5 1,400 miles at a total cost of $2.495 million. The details
6 of the original and revised plans are provided in
7 confidential Schedule 2C of Exhibit No.9.
8 No similar work was performed in 2010, so all of the
9 work represents new work. The overall cost of the two year
10 plan is $2,145,000. The Pro Forma increment for 2012 is
11 $747,300 for Idaho and is shown in Table 2.
12
13
14
Table 2: Transmission Line Ratings
Confirmtion Plan Costs
2010 Actual $0 $0
2011 Planned $350,000 $122,000
2012 Planned $2,145,000 $747,300
Pro Forma Increment $2,145,000 $747,300
15
16
17
18
III. PRO FORM TRASMISSION REVENUS
Q.Please describe the pro form transmission
19 revenue revisions included in this filing.
20 A.Adjustments have been made in this filing to
21 incorporate updated information associated with known
22 changes in transmission revenue for the 2012 pro forma
23 period as compared to the 2010 test year.Each revenue
Kinney, Di 21
Avista Corporation
1 item described below is at a system level and is included
2 in Schedule 1 of Exhibit No.9.Please see Table 3 and
3 descriptions below for further detail on the revenue pro
4 forma amounts.
56 Table 3
7
Transmission
Revenues
*Pro Forma (Sys tem)
Boarderline Wheelino Trans and Low Volt $7.000
OASIS nf & stf Whl (Other Whll $103.000
Seattle/Tacoma Main Canal ($4,000)
Seattle/Tacoma Summer Falls $0
PP&L - Drv Gulch $11,000
Spokane Waste to Enerov Plant ($160.000)
Grand Coulee Proiect $0
First Wind Enerqv Marketinq $200,000
BPA Settlement ($1, 177, 000)
Total Revenue ($1,020,000)8
9 *Represents the change in revenues above or below the 2010 test period level.
10
11 Borderline Wheeling Transmission and Low Voltage
12 ($7,000)
13
14
15
16
17
18
19
20
21
22
. Borderline Wheeling - Total borderline wheeling
revenues for the 2010 test year were $7,729,000.
Total borderline wheeling revenue in the pro
forma period has been set at $7,736,000, which
reflects a slight increase over the test year due
to transmission charge increases associated with
a specific contract with the Spokane Indian
Tribe. In the past the pro forma borderline
revenue has been developed using a five-year
rolling average of revenues from borderline
Kinney, Di 22
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
25
26
27
28
29
30
31
32
33
34
35
36
wheeling service provided to Bonneville and other
customers. However, with the new transmission
rates that went into effect in January 2010, use
of the previous five-years of actual revenues
would not properly reflect the new level of
revenues, including the transmission rate
increase. Therefore, pro forma transmission
revenue has been set equal to 2010 actual
revenue, with a slight known adjustment. Each of
the specific borderline contracts are further
described below.
. Borderline Wheeling Bonneville Power
Administration - Actual test year revenue from
borderline wheeling service provided to
Bonneville was $7,493,000. The Bonneville
borderline wheeling contracts are divided into
transmission and low voltage service. These were
accounted for separately beginning in October of
2010 as a result of the new transmission rates.
The new transmission rates apply to the
transmission services, but not to the low voltage
services. The current Bonneville Network
contracts expire on September 30, 2011. However
similar follow-on contracts are expected to be
executed with the same billing provisions under
the Avista Open Access Transmission Tariff.
Therefore, the pro forma Bonneville borderline
wheeling revenue is $ 7,493,000, which is equal to
the 2010 test year revenue.
. Borderline Wheeling Grant County PUD The
Company provides borderline wheeling service to
two Grant County PUD substations under a Power
Transfer Agreement executed in 1980. Charges
under this agreement are not impacted by the
Company's transmission service rates under
Avista's Open Access Transmission Tariff so the
Kinney, Di 23
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
25
26
27
28
29
30
31
32
33
34
35
Company is not proposing any adjustment from the
2010 test year revenue of $24,000.
. Borderline Wheeling - East Greenacres Irrigation
District - The Company restructured its contract
to provide borderline wheeling service to the
East Greenacres Irrigation District in April,
2009, resulting in monthly wheeling revenue of
$5,000. Revenue under this agreement for the
2010 test year was $60,000. Pro forma revenue
for the 2012 pro forma period is $60,000 per the
restructured contract.
. Borderline Wheeling - Spokane Tribe of Indians -
The Company provides borderline wheeling service
over both transmission and low-voltage facilities
to the Spokane Tribe of Indians. Total
transmission and low-voltage wheeling revenue
under this contract for the 2010 test year was
$35,000. Revenue associated with the
transmission component of this contract is
adj usted annually per the contract. Accordingly,
2012 pro forma period revenue under this contract
is set at $42,000.
. Borderline Wheeling Consolidated Irrigation
District The Company provides borderline
wheeling service over both transmission and low-
vol tage facilities to the Consolidated Irrigation
District. Total transmission and low-voltage
wheeling revenue under this contract for the 2010
test year was $118,000. The current contract
with the Consolidated Irrigation District expires
September 30, 2011, however a follow on contract
is expected to be signed with similar billing
requirements resulting in pro forma revenue of
$118,000.
Kinney, Di 24
Avista Corporation
1 OASIS Non-Firm and Short-Term Firm Transmission
2 Service ($103,000) - OASIS is an acronym for Open Access
3 Same-time Information System.This is the system used by
4 electric transmission providers for selling and scheduling
5 available transmission capacity to eligible customers. The
6 terms and conditions under which the Company sells its
7 transmission capacity via its OASIS are pursuant to FERC
8 regulations and Avista's FERC Open Access Transmission
9 Tariff.The Company is calculating its pro forma
10 adjustments using a three-year average of actual OASIS Non-
11 Firm and Short-Term Firm revenue.OASIS transmission
12 revenue may vary significantly depending upon a number of
13
14
factors,including current wholesale power market
condi tions,forced or planned transmission outage
15 situations in the region, forced or planned generation
16 resource outage situations in the region, current load-
17 resource balance status of regional load-serving entities
18 and the availability of parallel transmission paths for
19 prospective transmission customers.The use of a three-
20 year average is intended to strike a balance in mitigating
21 both long-term and short-term impacts to OASIS revenue. A
22 three-year period is intended to be long enough to mitigate
23 the impacts of non-substantial temporary operational
24 conditions (for generation and transmission) that may occur
25 during a given year and it is intended to be short-enough
26 so as to not dilute the impacts of long-term transmission
27 and generation topography changes (e. g. major transmission
Kinney, Di 25
Avista Corporation
1 proj ects which may impact the availability of the Company's
2 transmission capacity or competing transmission paths, and
3 maj or generation proj ects which may impact the load-
4 resource balance needs of prospecti ve transmission
5 customers). In this filing, the Company is using the most
6 recent three-year average.OASIS revenues for the 2010
7 test year were $2,887,000, and the most recent three-year
8 average of OASIS revenues from 2008 through 2010 is
9 $2,990,000.
10 Seattle and Tacoma Revenues Associated with the Main
11 Canal Project (-$4,000) - Effective March 1, 2008, the
12 Company entered into long-term point-to-point transmission
13 service arrangements with the City of Seattle and the City
14 of Tacoma to transfer output from the Main Canal
15 hydroelectric project, net of local Grant County PUD load
16 service, to the Company's transmission interconnections
17 wi th Grant County PUD.Service is provided during the
18 eight months of the year (March through October) in which
19 the Main Canal project operates and the agreements include
20 a three-year ratchet demand provision. Revenues under these
21 agreements totaled $292,000 during the 2010 test year. Pro
22 forma revenues are $288,000 based on the ratchet demand of
23 $35,960 per month set in September of 2010.
24 Seattle and Tacoma Revenues Associated with the Summer
25 Falls Project ($0) - Effective March 1, 2008, the Company
26 entered into long-term use-of-facili ties arrangements with
27 the City of Seattle and the City of Tacoma to transfer
Kinney, Di 26
Avista Corporation
1 output from the Summer Falls hydroelectric project across
2 the Company's Stratford Switching Station facilities to the
3 Company's Stratford interconnection with Grant County PUD.
4 Charges under this use-of-facili ties arrangement are based
5 upon the Company's investment in its Stratford Switching
6 Station and are not impacted by the Company's transmission
7 service rates under its Open Access Transmission Tariff.
8 Revenues under these two contracts totaled $ 74,000 in the
9 2010 test year and are expected to remain the same for the
10 2012 pro forma period.
11 PacifiCorp Dry Gulch ($11,000) - Revenue under the Dry
12 Gulch use-of-facilities agreement has been adjusted to
13 $229,000 for the pro forma period, which is an $11,000
14 increase from the 2010 test year actual revenue of
15 $218,000.The Company is calculating its pro forma
16 adjustments using a three year average of actual revenue.
17 Revenue under the Dry Gulch Transmission and
18 Interconnection Agreement with PacifiCorp varies depending
19
20
upon PacifiCorp's loads served via the Dry Gulch
Interconnection and the operating conditions of
21 PacifiCorp's transmission system in this area. The use of
22 a three-year average is intended to mitigate the impacts of
23 potential annual variability in the revenues under the
24
25
contract.A three-year average is also consistent with
that used for the Company's OASIS revenue.The contract
26 includes a twelve-month rolling ratchet demand provision
27 and charges under this agreement are not impacted by the
Kinney, Di 27
Avista Corporation
1 Company's open access transmission service tariff rates.
2 The three-year average of revenue was calculated using
3 years 2008 through 2010.
4 Spokane Waste to Energy Plant (-$160,000)This
5 revenue is the result of a long-term transmission service
6 agreement with the City of Spokane that expires December
7 31,2011.Currently it is unclear whether a follow-on
8 contract with Spokane Waste-to-Energy will be signed, and
9 the City of Spokane has not requested such a contract.
10 Therefore, the Company is assuming no revenue for this
11 contract beyond its termination date.Revenue from the
12 Spokane Waste to Energy Plant contract was $160,000 in the
13 2010 test year, and is adjusted to $0 in the pro forma
14 period.
15 Grand Coulee Proj ect Hydroelectric Authority ($0)
16 The Company provides operations and maintenance services on
17 the Stratford - Summer Falls 115kV Transmission Line to the
18 Grand Coulee Proj ect 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 2010 test year and will remain the
22 same for the 2012 pro forma period.
23 First Wind Energy ($200,000) - First Wind Energy has
24 signed a transmission service contract with the Company.
25 First Wind had originally proposed a start date of wind
26 energy production of January 1, 2012.However, due to
27 various project delays they intend to postpone the in-
Kinney, Di 28
Avista Corporation
1 service date of their proj ect by at least one year. A pro
2 forma amount of $200,000 for one month of revenue in 2012
3 is included in the rate case per the postponement terms in
4 the Company's FERC transmission tariff.
5 BPA Parallel Operation Agreement (-$1,177,000) - The
6 Company signed a Parallel Operating Agreement with the
7 Bonneville Power Administration regarding Bonneville's use
8
9
of the Avista transmission system to support the
integration of wind in south eastern Washington.The
10 agreement included a one-time settlement charge of
11 $1,177,000 received in December of 2010. The Company will
12 not receive any additional revenue from the agreement so
13 2012 pro forma period revenue has been adjusted to zero.
14
15
16
iv. TRASMISSION AN DISTRIBUTION CAITAL PROJECTS
Q.Please describe the Company's capital
17 transmission projects that will be completed in 2011 and
18 2012?
19 A.Avista continuously needs to invest in its
20 transmission system to maintain reliable customer service
21 and meet mandatory reliability standards. The 2011 and
22 2012 capital transmission projects are being constructed to
23
24
meet either compliance requirements,improve system
reliability,fix broken equipment,or replace aging
25 equipment that is anticipated to fail.
26 Included in the compliance requirements are the North
27 American Electric Reliability Corporation (NERC) standards,
Kinney, Di 29
Avista Corporation
1 which are national standards that utili ties must meet to
2 ensure interconnected system reliability.Beginning June
3 2007 compliance with these standards was made mandatory and
4 failure to meet the requirements could result in monetary
5 penal ties of up to $1 million per day per infraction. The
6
7
8
majori ty of the reliabili ty standards pertain to
transmission planning,operation,and equipment
maintenance.The standards require utili ties to plan and
9 operate their transmission systems in such a way as to
10 avoid the loss of customers or impact to neighboring
11 utility systems due to the loss of transmission facilities.
12 The transmission system must be designed so that the loss
13 of up to two facilities simultaneously will not impact the
14 interconnected transmission system.These requirements
15 drive the need for Avista to continually invest in its
16 transmission system. Avista is required to perform system
17 planning studies in both the near term (1-5 years) and long
18 term (5-10 years). If a potential violation is observed in
19 the future years, then Avista must develop a project plan
20 to ensure that the violation is fixed prior to it becoming
21 a real-time operating issue. Avista budgets for the future
22 projects and ensures that the design and construction of
23 the required proj ects are completed prior to the time they
24 are needed. Avista will continue to have a need to develop
25 these compliance related projects as system load grows, new
26 generation is interconnected, and the system functionality
27 and usage changes.
Kinney, Di 30
Avista Corporation
1 Avista capital transmission project requirements are
2 developed through system planning studies, engineering
3 analysis, or scheduled upgrades or replacements.The
4 larger specific projects that are developed through the
5 system planning study process typically go through a
6 thorough internal review process that includes multiple
7
8
stakeholder review to ensure all system needs are
adequately addressed.For the smaller specific proj ects,
9 Avista doesn't perform a traditional cost-benefit analysis.
10 Projects are selected to meet specific system needs or
11 equipment replacement.However, both project cost and
12 system benefits are considered in the selection of the
13 final proj ects.
14 Q.Did the Company consider any efficiency gains or
15 offsets when evaluating the transmission projects to
16 include in the Company's case?
17 A.Yes. The Company evaluated each project and
18 determined that some of the 2011 and 2012 capital
19 transmission proj ects will result in efficiency gains and
20 potential offsets or savings, and the Company has included
21 those where applicable. The primary offsets result in loss
22 savings from reconductoring heavily loaded transmission
23 facilities or replacing older transformers.For these
24 proj ects, an analysis was performed to determine the
25 savings.Actual savings were calculated assuming an
26 avoided cost of $53.01 per MWh, which is the current
27 calculated average energy production cost.
Kinney, Di 31
Avista Corporation
1
2
However not all projects will result in loss savings
or other offsets.Al though one might think that the
3 replacement of equipment may reduce the failure rate of
4 equipment and reduce after-hours labor costs, there are
5 several reasons that this may not occur.Significant
6 system failures occur during large weather related events
7 caused by wind, lightning, and snow. These weather related
8 failures can impact both new and older equipment.
9 Furthermore, each year as older equipment is replaced with
10 new equipment, the remainder of the system gets another
11 year older, which continues to generate a similar level of
12 failures on our system. Until the average age of equipment
13 is significantly reduced, failure rates are expected to
14 remain the same.
15 Q.Please describe each of the transmission projects
16 included in the Company's filing for 2011.
17 A.The major capital transmission costs (system) for
18 projects to be completed in 2011 are approximately $26.959
19 million and are shown in Table 4 and described below.
Kinney, Di 32
Avista Corporation
1 TABLE 4
2 Transmission
2011 Capital -Compliance, Environmental and Replacement Projects
O&M
Pro Forma Offsets
(System)(System)
Reliabiltiv Compliance
Moscow 230 kV Sub $400,000
Spokane/CDA Relay Upqrade $1, 000, 000
SCADA Replacement $625,000
System Replace/Install Capacitor Bank $400,000
West Plains Transmission Reinforcement $2,300,000 $113,500
Bronx-Cabinet 115 kV Rebui1d/Reconductor $2,000,000 $75,400
Power Transformers - Transmission $3,250,000
Total Reliability Compliance $9,975,000 $188,900
Environmental Regulations
Beacon Storaoe Yard $1,020,000
Contractual Requirements
Colstrip Transmission $533.000
Tribal Permits $325.000
Total Contractual Requirements $858,000
Reliabil tiy Improvements
Idaho Road Substation $1,750,000 $5,300
Hatwai-N Lewistion 230kV Re-insulate $250,000
East Farms and Prarie View Uporades $265,000
Total Reliabiltiy Improvements $2,265,000 $5,300
Reliabili ty Replacement
Transmission Minor Rebuilds $2,750,000
Power Circuit Breakers $1, 600, 000
Otis Orchards 115 kV Breaker and Relay
Replacements $730,000
* Noxon Rapids B Bank GSU Replacement $5,874,000 $66,300
Asset Manaoement Replacement $1, 887,000
Total Reliabli ty Replacement $12,841 , 000 $66,300
Total Transmission Pro;ects $26,959,000 $260,500
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
2425 *Per FERC asset accounting rules, generation step-up transformers are deemed a26 transmission asset.
Kinney, Di 33
Avista Corporation
1 RELIABILITY COMPLIANCE PROJECTS ($9.975 MILLION) :
2
3 . Moscow 230 kV Sub Rebuild 230 kV Yard ($0.4
4 million) : This proj ect involves the rebuild of the
5 existing Moscow 230 kV substation. The substation
6 rebuild includes the replacement of the existing 125
7 MVA 230/115 kV autotransformer with a new 250 MVA
8 autotransformer to meet compliance with NERC standards
9 and ensure adequate load service. The existing10 230/115 kV autotransformer overloads for an outage of11 another autotransformer in the area during peak load.12 The substation will be constructed as a double breaker13 double bus configuration to maximize reliability and14 operational flexibility. The substation will be15 constructed over a three-year period with energization
16 of the 230 kV portion in 2012. Several transmission17 lines will be rerouted during 2011 to prepare for the18 new substation. The transmission line work will be19 completed and placed into service in the fall of 2011.
20 This is the portion pro formed into the Company's21 case. This proj ect is required to meet Reliability
22 Compliance under NERC Standards: TOP-004-2 R1-R4, TPL-23 002-0a R1-R3, TPL-003-0a RI-R3. Offsets for this
24 project will not occur until the Moscow 230 kV25 Substation is complete in 2012, and therefore have26 been included in the 2012 project described later in
27 my testimony.
28
29 . Spokane/Coeur d' Alene area relay upgrade ($1 million) :30 This project involves the replacement of older31 protective 115 kV system relays with new micro-32 processor relays to increase system reliability by33 reducing the amount of time it takes to sense a system34 disturbance and isolate it from the system. This is a35 fi ve to seven year proj ect and is required to maintain36 compliance with mandatory reliability standards. This37 proj ect is required to meet Reliability Compliance
38 under NERC Standards: TOP-004-2 RI-R4, TPL-002-0a R1-39 R3, TPL-003-0a Rl -R3. Posi ti ve offsets in reduced40 maintenance costs associated with this replacement
41 effort are negatively offset by increased NERC testing
42 requirements per standard PRC-005-1.
43
44 . SCADA Replacement ($0.625 million): The System Control
45 and Data Acquisition (SCADA) system is used by the46 system operators to monitor and control the Avista
47 transmission system. An upgrade to the SCADA system
48 to a new version provided by our SCADA vendor was49 started in 2010 and will be completed in 2011. The50 current application version is no longer supported by
51 the vendor. The upgrade will ensure Avista has52 adequate control and monitoring of its Transmission
53 facili ties. This portion of the proj ect is required
Kinney, Di 34
Avista Corporation
1 to meet Reliability Compliance under NERC Standards:
2 TOP-001-1, TOP-002-2a R5-RI0, R16, TOP-005-2 R2, TOP-
3 006-2 R1-R7. Several Remote Terminal Units (RTUs)
4 located at substations throughout Avista's service
5 terri tory will also be replaced due to equipment age.
6 The RTUs are part of the transmission control system.
7 There are no offsets or savings associated with this
8 upgrade proj ect because the Company already pays the
9 application vendor a set annual maintenance fee for10 support.
11
12 . System Replace/Install Capacitor Bank ($0.4 million):13 This project includes the replacement of the 115 kV14 capaci tor bank at the Pine Creek 115 kV substations to15 support local area voltages during system outages.16 The proj ect is required to meet reliability compliance
17 with NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-
18 R3, TPL-003-0a RI-R3, and provide improved service to19 customers. The project is scheduled to be completed20 by the end of 2011. There are no loss savings or21 other offsets associated with this new equipment22 installation.
23
24 . West Plains Transmission Reinforcement; Garden Springs
25 - Hallet and White 115 kV reconductor ($2.3 million):26 This work is necessary to upgrade the Garden Springs -
27 Hallet and White 115 kV. Avista's System Planning West
28 Plains Transmission Reinforcement Study (Rev. B,29 November 22, 2010) identifies the reconductoring and
30 rebuilding of the 10. 6-mile South Fairchild 115kV
31 Transmission Line between Garden Springs and Silver32 Lake Substation as needed to maximize the flexibility33 of the transmission system in this area. Phase 1 of34 the project (addressed here) consists of the six-mile35 Garden Springs to Hallet & White section. The line
36 upgrade will meet compliance requirements associated
37 wi th NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-38 R3, TPL-003-0a RI-R3. Additionally, this work will
39 increase service reliability to an essential military
40 facility (North Fairchild Air Force Base). Using 201041 actual loads, the new conductor will reduce line
42 losses by 2142 MWh on an annual basis, establishing an43 offset of $113,500 in the pro forma period (based on a
44 $53. 01/MWh avoided energy cost) .
45
46 . Bronx Cabinet 115 kV rebuild/reconductor ($2
47 million) : In 2010 Avista's System Operations48 identified a thermal constraint on the 32-mile Bronx-49 Cabinet 115kV Transmission Line. This constraint was
50 confirmed by the System Planning Groupi and documented
51 in the Transmission Line Design (TLD) Design Scoping
52 Document (DSD) created on January 4, 2011, and
53 modified on January 7, 2011. The reconductoring and
Kinney, Di 35
Avista Corporation
1 rebuilding of this line with 795 kcmil ACSS conductor
2 will provide a present-day 143 MVA line rating to
3 match the Cabinet Swi tchyard Transformer, and a future
4 200 MVA line rating to match the parallel path
5 Bonneville Power Authority (BPA) system. Phase 1 of
6 the project (addressed here) consists of the
7 approximately eight-mile section between the Cabinet
8 Swi tchyard and the Clark Fork Substation. The line
9 upgrade will meet compliance requirements associated
10 with NERC Standards: TOP-004-2 R1-R4, TPL-002-0a RI-
II R3, TPL-003-0a RI-R3. Using 2010 actual loads, the
12 new conductor will reduce line losses by 1422 MWh on13 an annual basis, establishing an offset savings of
14 $75,400 in the pro forma period (based on a $53.01/MWh15 avoided energy cost) .
16
17 . Power Transformrs - Transmission ($3.25 million): As18 previously discussed, the Moscow 230 kV substation is19 being rebuilt in 2011 and 2012. The rebuild includes20 the addition of a new 250 MVA autotransformer. This21 autotransformer will arrive on-site in 2011 and will22 be capitalized upon delivery per the Company's23 accounting practices. Offsets for this project will
24 not occur until the Moscow 230 kV Substation is25 complete in 2012, and therefore have been included in26 the 2012 project described later in my testimony.
27
28 ENVIRONMENTAL REGULATION PROJECTS ($1.020 MILLION) :
29
30 . Beacon Storage Yard ($1.02 million): The Beacon31 Storage Yard is a location where circuit breakers and32 power transformers are stored and staged for rotation33 into existing substations as replacements or for new34 construction. This site is near the Spokane River and
35 this proj ect work will provide an oil containment36 system to protect the local environment. In 2009 and
37 2010, the Company began construction of the Beacon
38 Substation Equipment Storage Yard. In 2011, the39 remainder of the yard and a building to securely house40 the mobile substations and battery trailer will be41 completed and transferred to plant. There are no42 offsets for this project because it is required to43 eliminate the potential of environmental
44 contamination.
45
46 CONTRACTUAL REQUIRED PROJECTS ($0.858 MILLION) :
47
48 . Colstrip Transmission ($0.533 million): As a joint49 owner of the Colstrip Transmission proj ects, Avista50 pays its ownership share of all capital improvements.51 Northwestern Energy either performs or contracts out52 the capital work associated with the j oint owned53 facili ties.
Kinney, Di 36
Avista Corporation
1
2 . Tribal Permits ($0.325 million): The Company has
3 approximately 300 right-of-way permits on tribal
4 reservations that need to be renewed. The costs5 include labor, appraisals, field work, legal review,
6 GIS information, negotiations, survey (as needed), and7 the actual fee for the permit.
8
9 RELIABILITY IMPROVEMENT PROJECTS ($2.265 MILLION) :
10
11 . Idaho Road Substation ($1.750 million): Year two of12 this multi-year project to integrate the local load
13 service of Idaho Road Substation will upgrade14 transmission connecti vi ty from a "tap" configuration
15 to a considerably more reliable "loop" feed by16 installing approximately four miles of transmission
17 line with 795 kcm Aluminum (125 MVA-Summer) conductor.
18 The new conductor will reduce line losses by 100 MWh19 on an annual basis, establishing an offset savings of
20 $5,300 in the proforma period (based on a $53.01/MWh21 avoided energy cost) .
22
23 . Hatwai-N Lewiston 230 kV Re-insulate ($0.250 million) :24 Re-Insulate existing 230kV polymer insulators on seven
25 (7) mile Hatwai-North Lewiston 230kV Transmission Line26 wi th a toughened glass type insulator in response to
27 documented corona induced shed cutting. Shed cutting28 has resulted in catastrophic failure of polymer
29 insulators. Toughened glass insulators are impervious
30 to this phenomenon. This project will complete in31 2011.
32
33 . East Farms and Prairie View 115 kV Upgrade ($0.26534 million): This is a transmission and distribution35 project slated for completion in 2011 to connect and36 upgrade 13.2 kV primary feeder ties between Pleasant
37 View (Idaho) and East Farms (WA) substations. This38 project is located near Post Falls, Idaho and Liberty39 Lake, WA. This project is part of an overall40 transmission and distribution effort to connect these41 primary feeders in compliance with Avista's 500A42 Distribution Feeder Plan. This project is currently43 under construction and the costs shown here are44 associated with transmission upgrades.
45
46
47 The Company will also spend approximately $12.841
48 million in transmission system equipment replacements
49 associated with storm damage or aging/obsolete equipment.
Kinney, Di 37
Avista Corporation
1 A brief description of the projects included in these
2 replacement efforts are given below.
3
4 . Transmission Minor Rebuilds ($2.750 million): These
5 projects include minor transmission rebuilds as a
6 resul t of age or damage caused by storms, wind, fire,
7 and the public. These smaller proj ects are required to
8 operate the transmission system safely and reliably.
9 The specific projects aren't known at this time but
10 the facilities will need to be replaced when damaged
11 in order to maintain customer load service. In 2010
12 the Company spent $3.053 million on these minor13 rebuild proj ects as a result of damage caused by14 weather or the public.
15
16 . Power Circuit Breakers ($1.600 million): The Company17 transfers all circuit breakers to plant upon receiving18 them. The breakers purchased in 2011 are planned for
19 installation at Moscow and Lind substations.
20
21 . Otis Orchards 115 kV Breaker and Line Relay22 Replacements ($0.730 million): This project will23 replace the 115 kV breakers and associated 115 kV line24 relays at the existing Otis Orchards substation. Four25 of the breakers are over 50 years old and have reached26 the end of their useful lives. The line relaying must27 be replaced with new microprocessor relays to provide
28 the high speed tripping required for mandatory29 reliabili ty standards. The relay replacements are part
30 of the Spokane/Coeur d' Alene area relay upgrade31 proj ect previously discussed.
32
33 . Noxon Rapids B Bank GSU Replacement ($5.874 million):
34 Replacement of the Generator Step up Transformers
35 (GSU) were needed to accommodate the additional36 capaci ty from the turbine upgrades discussed in
37 Company wi tness Lafferty's testimony. These38 transformers were 50 years old and were reaching the39 end of their useful life, without the additional
40 capacity requirements. The new GSU's are approximately41 50% more efficient than the replaced transformers.
42 The Noxon Rapids A Bank GSU proj ect was completed in
43 2010. The B Bank GSU Transformers will be replaced in44 2011 at a cost of $5.874 million. The more efficient45 transformers will provide loss savings of $66,300 in
46 the pro forma period (based on a $53. 01/MWh avoided47 energy cost) .
48
49 . Asset Management Replacement Programs ($1.887
50 million) : Avista has several different equipment51 replacement programs to improve reliability by
Kinney, Di 38
Avista Corporation
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replacing aged equipment that is beyond its useful
life. These programs include transmission air switch
upgrades, arrestor upgrades, restoration of substation
rock and fencing, recloser replacements, replacement
of obsolete circuit switchers, substation battery
replacement, interchange meter replacements, highvol tage fuse upgrades, and voltage regulatorreplacements. All of these individual projects
improve system reliability and customer service. The
equipment under these replacement programs are usually
not maintained on a set schedule. The equipment is
replaced when useful life has been exceeded.
Q. Please describe each of the Idaho distribution
projects included in the Company's filing for 2011.
A.The Company also will spend approximately $65.727
18 million in Distribution projects at a system level, with
19 $17.861 million specific to Idaho. A summary of the
20 projects is shown in Table 5 and a brief description of
21 each project is given below.
Kinney, Di 39
Avista Corporation
1 TABLE 5
2 Distribution
2011 Capital - Distribution Proiects
Pro Forma Pro Form O&M
(System)(Idaho)Offsets
Idaho Distribution Proiects
POwer Transformers - Distribution $350.000 $350.000
Appleway Sub Rebuild $4 200.000 $4 200.000
System Wood Sub Rebuild - Deary $1. 615.000 $1. 615.000 $12.200
Svstem Dist Reliabilitv Improve Worst Feeders $925 000 $925 000
East Farms and Prarie View Upqrades $360.000 $360.000
Distribution CDA East & North $675 000 $675,000
Distribution Pullman & Lewiston $350.000 $350.000
Total Idaho Distribution Proiects $8,475,000 $8,475,000 $12,200
Distribution Replacement Proiects
Elect Distribution Minor Blanket $8.000.000 $2.787.000
Wood Pole Replacement and Capital Dist Feeder
Repair $8 900 000 $3 101 000
Electric Underaround Replacement $3.500.000 $1. 219. 000 $35.000
Distribution Line Relocation $1 700 000 $592 000
Failed Electric Plant $2.000.000 $697.000
Replace Hiqh Resistance Conductor $2,491,000 $615,000
PCB Related Dist Rebuilds $2 500.000 $375.000
Total Distribution Replacement Projects $29,091,000 $9,386,000 $35,000
Washinqton Distribution Projects (Not included in this case)
Distribution Proiects in Washinaton $9 700.000 $0
Washinaton Smart Grid Proiects $18 461. 000 $0
Total Washington Distribution Proiects $28,161,000 $0
Total Distribution Proiects $65,727,000 $17,861,000 $47,200
3
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7
8
9
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12
13
14
15
16
17
18
19 Distribution Projects specific to Idaho (including
20 transformation)for 2011 total $8.475 million.These
21 proj ects are necessary to meet capacity needs of the
22 system, improve reliability, and rebuild aging distribution
23 substations and feeders.The following proj ects make up
24 the $8.475 million.
25 . Power Transformer Distribution ($0.350 million):26 Transformers are transferred to plant upon receiving27 them. These transformers are being purchased to28 replace existing spares that will be installed in 2011
29 as either replacements or new installations. The30 purchased transformers will either remain as system
Kinney, Di 40
Avista Corporation
1 spares or placed into service as part of proposed 2011
2 projects. There are no offsets associated with these
3 transformers until they are placed into service.
4
5 . Appleway Substation ($4.200 million): Appleway 115-13
6 kV Substation is a wood substation serving most of the
7 Ci ty of Coeur d'Alene. The station has reached the8 end of its useful life and additional capacity is
9 required. The new station will include 2-30 MVA10 transformers and six 13 kV feeders. The project11 started in late 2009 and will be transferred to plant
12 in 2011. Loss calculations on the new transformer
13 banks indicate that the losses are equivalent to the14 existing banks so there are no offsets associated with15 this proj ect.
16
17 . Deary Substation ($1. 615 million): Deary 115..24 kV18 Substation is a wood substation scheduled to be
19 rebuilt as a steel substation in 2010 and 2011.20 Avista plans to rebuild at least one old wood21 substation every year based on age. Loss savings22 calculations indicate that the new transformer23 installation will result in an offset of $12,200 in
24 the pro forma period (based on a $53. 01/MWh avoided25 energy cost) .
26
27 . System - Dist Reliability - Improve Worst Feeders28 ($0.925 million): Based on a combination of29 reliabili ty statistics, including CAIDI, SAIFI, and30 CEMI (Customers Experiencing Multiple Interruptions),31 feeders have been selected for reliability improvement32 work. This work is expected to improve the33 reliabili ty of these electric primary feeders. This is34 a annually recurring program initiated in 2008 to35 address underperforming feeders on the electric36 distribution system. Most of the feeder circuits are
37 rural in nature and many experience 10 to 20 sustained38 outages per year discounting maj or events. The39 treatment of feeder projects varies from conversion of40 overhead to URD facilities, installing additional mid-41 line protective devices, to hardening of existing42 facilities. In Idaho, projects stretch from43 Sandpoint, Kellogg, St. Maries, Moscow, and44 Grangeville.
45
46 . East Farms and Prairie View Feeder Upgrade ($0.36047 million): This is a transmission and distribution48 project slated for completion in 2011 to connect and49 upgrade 13.2 kV primary feeder ties between Pleasant
50 View (Idaho) and East Farms (WA) substations. This51 project is located near Post Falls, Idaho and Liberty52 Lake, WA. This project is part of an overall53 transmission and distribution effort to connect these
Kinney, Di 41
Avista Corporation
1 primary feeders in compliance with Avista' s 500A
2 Distribution Feeder Plan. The proj ect will allow load
3 to be served from either substation to improve4 reliability and load service. This project is
5 currently under construction and the cost shown here
6 are associated with distribution upgrades in Idaho.
7
8 . Distribution - Cda East & North ($0.675 million):
9 These are all Idaho distribution projects. This10 project represents (4) discrete feeder reconductor
11 projects as determined by SynerGEE modeling by12 Avista's distribution planning engineers and13 divisional area Engineers. These projects are14 characterized as "segment reconductor" projects and15 represent portions of main feeder trunk lines that are16 thermally constrained. The proj ects tend to be urban17 in nature.
18
19 . Distribution Pullman & Lewiston ($0.350 million): As20 above, this project includes the segment reconductor21 of two (2) primary feeder trunk lines in the Lewiston22 and Orofino areas. Both have been identified as23 "thermally constrained" via SynerGEE load flow24 modeling and analysis.
25
26 The Company also will spend approximately $29.091
27 million (system) in equipment replacements and minor
28 rebuilds associated with aging distribution equipment
29 discovered through inspections,feeders with poor
30 reliability performance, replacements from storm damage,
31 relocation of feeder sections resulting from road moves, or
32 safety improvements.A brief description of the projects
33 included in these replacement efforts is given below.
34
35 . Electric Distribution Minor Blanket Projects ($8.00036 million): This effort includes the replacement of37 poles and cross-arms on distribution lines in 2011 as38 required, due to storm damage, wind, fires, or
39 obsolescence. The Company spent $9.177 million in 201040 for these proj ects.
41
42 . Wood Pole Replacement Program and Capital Distribution43 Feeder Repair ($8.9 million): The distribution wood
44 pole management program evaluates wood pole strength
45 of a certain percentage of the wood pole population
Kinney, Di 42
Avista Corporation
1 each year such that the entire system is inspected
2 every 20 years. Avista has over 240,000 distribution
3 wood poles and 33,000 transmission wood poles in its
4 electric system. Depending on the test results for a5 given pole, the pole is either considered
6 satisfactory, needing to be reinforced with a steel
7 stub, or needing to be replaced. As feeders are
8 inspected as part of the wood pole management program,
9 issues are identified unrelated to the condition of10 the pole. This project also funds the work required to11 resolve those issues (i. e. potentially leaking12 transformers, transformers older than 1981, failed
13 arrestors, missing grounds, damaged cutouts, and dated14 high resistance conductor). Transformers older than15 1981 have the potential to have oil that contains16 polychlorinated biphenyls (PCBs) . These older17 transformers present increased risk because of the18 potential to leak oil that contains PCBs. Poles19 installed during the pre-World War II buildup have20 reached the end of their useful life. Avista's Wood
21 Pole Management program was put into place to prevent
22 the Pole-Rotten events and Crossarm - Rotten events
23 from increasing. So far, the Wood Pole Management
24 Program has helped keep Pole-Rotten and Crossarm-
25 Rotten events in check. Comparing 2007 to 2010 data,
26 Crossarm-Rotten Events went from 46 events to 25
27 events, however, Pole-Rotten events climbed from 2528 events to 37 events in 2008 to 2010. Thus, no net
29 offsets are anticipated from the Wood Pole Management
30 program for the 2012 rate period. The Company spent31 $7.507 million on these efforts in 2010.
32
33 . Electric Underground Replacement ($3.5 million): This34 effort involves replacing the first generation of35 Underground Residential District (URD) cable. This36 project which has been ongoing for the past several37 years and will be completed in 2012. This program38 focuses on replacing a vintage and type of cable that39 has reached its end of life and contributes
40 significantly to URD cable failures. The Company41 spent $4.092 million in 2010. The incremental savings
42 in Operation and Maintenance expenses seen in 2010 was
43 $35,000 due to reduced number of URD Primary Cable44 fault reductions. In 2011, we anticipate that we will
45 see the same incremental savings as 2010, which has46 been included as an offset for the Electric
47 Underground Replacement proj ect.
48
49 . Distribution Line Relocation ($1.700 million): The50 relocation of transmission and distribution lines as51 required due to road moves requested by State, County
52 or City governments. The Company spent $1.559 million
Kinney, Di 43
Avista Corporation
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2
3
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6
7
8
9
10
11
12
13
14
15
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in 2010 on line relocations associated with road
moves.
. Failed Electric Plant ($2.000 million): Replacement
of distribution equipment throughout the year as
required due to equipment failure. The Company spent
$2.665 million in 2010.
. Replace High Resistance Conductor ($2.491 million
system / $0.615 million Idaho): Avista operates
approximately 18,500 miles of primary distribution
main trunk and service lateral circuits. Nearly 1,000miles of our system has been identified as fthigh
resistance" at 10 ohms per mile or greater. These
high resistance conductors are generally small wire
copper, iron, or steel conductors and most have been
in service greater than 50 years. In 2011, Avista has
initiated an annually recurring program to
systematically replace these conductors with modern
aluminum wire. Several projects have been identified
in the Idaho service terri tory and are targeted forreplacement. High resistance wire impairs the ability
of protective devices, such as circuit reclosers and
fuses, to operate as designed resulting in a safety
issue. The high resistance wire that is being
replaced under this program is very lightly loaded so
there isn't measurable loss savings.
. PCB Related Distribution Rebuilds ($2.500 million
system / $0.375 million Idaho): Avista has begun a
systematic replacement of PCB containing distribution
line transformers. 2011 represents year one of a six
year effort to replace these "pre-l 981" distribution
transformers. The program is focused on replacing
uni ts that are located near waterways such as the
Spokane river watershed. The $375,000 slated for
Idaho represents the replacement of approximately 250transformers.
Q. Please describe each of the transmission projects
included in the Company's filing for 2012.
A.The maj or capital transmission costs (system) for
43 projects to be completed in 2012 are approximately $22.407
44 million and are shown in Table 6 and described below.
Kinney, Di 44
Avista Corporation
1
2
3
4
5
TABLE 6
Transmission
2012 Capital -Compliance,Environmental and Replacement Proiects
O&M
Pro Forma Offsets
(System)(System)
Reliabil tiv Compliance
Moscow 230 kV Sub $3,870,000 $6.400
Sookane/CDA Relav Uporade $1, 250, 000
SCADA Replacement $450,000
System Replace/Install Capacitor Bank $1, 200, 000
Irvin Inteoration. Irvin - Millwood 115 kV Line $1, 150, 000
Thornton 230 kV Substation $4,900. 000
Bronx-Cabinet 115 kV Rebuild/Reconductor $1, 500, 000 $3.900
Power Transformers - Transmission $2,665. 000
Total Reliability Compliance $16,985,000 $10,300
Contractual Requirements
Colstrio Transmission $195, 000
Tribal Permits $325, 000
Total Contractual Requirements $520,000
Reliabili tv Replacement
Transmission Minor Rebuilds $1, 500, 000
Power Circuit Breakers $1,200,000
Asset Manaqement Replacement $2,202,000
Total Reliabli ty Replacement $4,902,000
Total Transmission Projects $22,407,000 $10,300
6
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11
12
13
14
15
16
17
18
19 RELIABILITY COMPLIANCE PROJECTS ($16.985 MILLION) :
20
21 . Moscow 230 kV Sub Rebuild 230 kV Yard ($3.87022 million) : This project involves the rebuild of the23 existing Moscow 230 kV substation. The substation24 rebuild includes the replacement of the existing 125
25 MVA 230/115 kV autotransformer with a new 250 MVA
26 autotransformer to meet compliance with NERC standards27 and ensure adequate load service. The existing28 230/115 kV autotransformer overloads for an outage of29 another autotransformer in the area during peak load.30 The substation will be constructed as a double breaker31 double bus configuration to maximize reliability and32 operational flexibility. The substation will be33 constructed over a three-year period with energization34 of the 230 kV portion of the substation occurring in35 November of 2012. This is the portion pro formed into
36 the Company's case. The completion of the 115 kV37 portion of the substation will occur in 2013. This
Kinney, Di 45
Avista Corporation
1 project is required to meet Reliability Compliance
2 under NERC Standards: TOP-004-2 RI-R4, TPL-002-0a Rl-
3 R3, TPL-003-0a RI-R3. Loss savings calculations4 indicate that the new transformer installation will
5 result in an offset of $6400 in the pro forma period
6 (based on a $53. 01/MWh avoided energy cost and an
7 energization date of November, 2011).
8
9 . Spokane/Coeur d'Alene area relay upgrade ($1.25010 million) : This project involves the replacement of11 older protective 115 kV system relays with new micro-12 processor relays to increase system reliability by13 reducing the amount of time it takes to sense a system14 disturbance and isolate it from the system. This is a15 five to seven year proj ect and is required to maintain16 compliance with mandatory reliability standards. This
17 project is required to meet Reliability Compliance
18 under NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-19 R3, TPL-003-0a RI-R3. Posi ti ve offsets in reduced20 maintenance costs associated with this replacement
21 effort are negatively offset by increased NERC testing
22 requirements per standard PRC-005-1.
23
24 . SCAA Replacement ($0.450 million): The System Control
25 and Data Acquisition (SCADA) system is used by the26 system operators to monitor and control the Avista
27 transmission system. Upgrades to the SCADA system28 occur on an annual basis and include such items as29 replacing servers, increasing security, and expanding30 functionali ty. This portion of the project is
31 required to meet Reliability Compliance under NERC
32 Standards: TOP-001-1, TOP-002-2a R5-R10, R16, TOP-005-
33 2 R2, TOP-006-2 RI-R7. Several Remote Terminal Units34 (RTUs) located at substations throughout Avista's35 service terri tory will also be replaced due to age.36 The RTUs are part of the transmission control system.37 There are no offsets or savings associated with this
38 upgrade proj ect because the Company already pays the39 application vendor a set annual maintenance fee for40 support.
41
42 . System Replace/Install Capacitor Bank ($1.20043 million) : This project includes the addition of 11544 kV capacitor banks at Lind 115 kV substation and45 Odessa 115 kV substation to support local area46 voltages during system outages. The project is
47 required to meet reliability compliance with NERC
48 Standards: TOP-004-2 RI-R4, TPL-002-0a RI-R3, TPL-003-
49 Oa R1-R3, and provide improved service to customers.50 The projects are scheduled to be completed by the end51 of 2012. There are no loss savings or other offsets52 associated with this new equipment installation.
53
Kinney, Di 46
Avista Corporation
1 . Irvin Integration, Irvin Millwood 115 kV line
2 ($1.150 million): A new 115 kV Switching Station will
3 be constructed in the Spokane Valley to reinforce the
4 transmission system. The Irvin 115kV Switching5 Station is the initial project in a series of projects
6 intended to improve reliability of the 115kV
7 transmission system and accompanying load service in
8 the Spokane Valley. In 2012 $1,150,000 is scheduled
9 to be spent for the construction of a new transmission10 line from the future Irvin station site to the11 existing Millwood Substation. Work will also be12 performed to relocate existing structures in and13 around the Irvin site to accommodate its integration.
14
15 . Thornton 230 kV Substation ($4.900 million): The16 Thornton 230kV Substation Project interconnects a17 Third party Wind Farm Generation Proj ect to Avista' s
18 Benewah - Shawnee 230kV Transmission Line. The 201119 Transmission portion of this proj ect consists of20 preparing the transmission line to accept the21 Customer's shoo-fly (a temporary routing and tap22 allowing for the Substation work are to be23 electrically isolated from the transmission line while24 allowing generation from the customer's wind farm)
25 transmission line, tapping the Benewah Shawnee
26 directly to the Customer Generation Collection Station27 and beginning the construction of the 230 kV switching
28 station. 2012 work consists of installing 230kV drop29 structures for the Thornton Substation, removing the30 shoo-fly taps, and finalizing the construction of the31 230 kV switching station. The station is required to32 maintain Avista's 230 kV transmission service with or33 without the wind generation so Avista's customers are34 not affected by any outages as a result of the35 interconnection. One third of the substation costs
36 will be paid by the customer as direct assigned
37 facili ties according to FERC Open Access requirements.
38
39 . Bronx Cabinet 115 kV rebuild/reconductor ($1.5
40 million) : In 2010 Avista's System Operations41 identified a thermal constraint on the 32-mile Bronx-42 Cabinet 115kV Transmission Line. This constraint was
43 confirmed by the System Planning Group, and documented
44 in the Transmission Line Design (TLD) Design Scoping
45 Document (DSD) created on January 4, 2011, and
46 modified on January 7, 2011. The reconductoring and
47 rebuilding of this line with 795 kcmil ACSS conductor
48 will provide a present-day 143 MVA line rating to49 match the Cabinet Switchyard Transformer, and a future50 200 MVA line rating to match the parallel path
51 Bonneville Power Authority (BPA) system. Phase 1 of52 the project completed in 2011 included the rebuild and53 reconductor of the eight-mile section between the
Kinney, Di 47
Avista Corporation
1 Clark Fork Substation and Cabinet Gorge Hydro-
2 Generation Station Switchyard. Phase 2 (2012) of the3 project will look to complete an additional
4 approximate eight-mile section (specific location (s)
5 to be determined) section of line. The line upgrade
6 will meet compliance requirements associated with NERC
7 Standards: TOP-004-2 RI-R4, TPL-002-0a RI-R3, TPL-003-
8 Oa RI-R3. The new conductor will reduce line losses
9 by 889 MWh on an annual basis, establishing a system10 offset savings of $3,900 in the pro forma period
11 (based on a $53. 01/MWh avoided energy cost and12 energization of the project in December 2012).
13
14 . Power Transformers - Transmission ($2.665 million):15 The Company will be rebuilding several 230 kV16 substations over the next 5 years. One of these
17 stations is Westside in western Spokane and involves
18 the replacement of two 230/115 kV autotransformers.19 One of the autotransformer will arrive on-site in 201220 and will be capitalized upon delivery per the21 Company's accounting practices. There are no offsets
22 or savings associated with the purchase of this23 autotransformer until it is put into service.
24
25
26 CONTRACTUAL REQUIRED PROJECTS ($0.520 MILLION) :
27
28 . Colstrip Transmission ($0.195 million): As a joint29 owner of the Colstrip Transmission proj ects, Avista30 pays its ownership share of all capital improvements.31 Northwestern Energy either performs or contracts out32 the capital work associated with the joint owned33 facili ties.
34
35 . Tribal Perm ts ($0.325 million): The Company has36 approximately 300 right-of-way permits on tribal37 reservations that need to be renewed. The costs38 include labor, appraisals, field work, legal review,39 GIS information, negotiations, survey (as needed), and40 the actual fee for the permit.
41
42 The Company will also spend approximately $4.902
43 million in transmission system equipment replacements
44 associated with storm damage or aging/obsoiete equipment.
45 A brief description of the projects included in these
46 replacement efforts are given below.
47
Kinney, Di 48
Avista Corporation
1 . Transmission Minor Rebuilds ($1. 550 million): These
2 projects include minor transmission rebuilds as a
3 resul t of age or damage caused by storms, wind, fire,
4 and the public. These smaller proj ects are required to
5 operate the transmission system safely and reliably.
6 The specific projects aren't known at this time but
7 the facilities will need to be replaced when damaged
8 in order to maintain customer load service. In 2010
9 the Company spent $3.053 million on these minor10 rebuild proj ects as a result of damage caused by11 weather or the public.
12
13 . Power Circuit Breakers ($1.200 million): The Company14 transfers all circuit breakers to plant upon receiving15 them. The breakers purchased in 2012 are planned for16 installation at Odessa 115 kV substation as part of17 the new capacitor bank installation and the new Irvin18 115 kV switching station in Spokane planned for19 energization in 2013 or 2014.
20
21 . Asset Management Replacement Programs ($2.202
22 million) : Avista has several different equipment23 replacement programs to improve reliability by24 replacing aged equipment that is beyond its useful
25 life. These programs include transmission air switch26 upgrades, arrestor upgrades, restoration of substation27 rock and fencing, recloser replacements, replacement28 of obsolete circuit switchers, substation battery29 replacement, interchange meter replacements, high30 vol tage fuse upgrades, and voltage regulator31 replacements. All of these individual projects32 improve system reliability and customer service. The
33 equipment under these replacement programs are usually34 not maintained on a set schedule. The equipment is35 replaced when useful life has been exceeded.
36
37 Q.Please describe each of the Idaho distribution
38 projects included in the Company's filing for 2012.
39 A.The Company also will spend approximately $58.003
40 million in Distribution proj ects at a system level, with
41 $16.630 million specific to Idaho. A summary of the
42 proj ects is shown in Table 7 and a brief description of
43 each proj ect is given below.
44
Kinney, Di 49
Avista Corporation
1
2
3
TABLE 7
Distribution
2012 Capital - Distribution Proiects
Pro Form Pro Forma O&M
(System)(Idaho)Offsets
Idaho Distribution Proiects
Power Transformers - Distribution $350 000 $350,000
System Wood Sub Rebuild - Bia Creek $1. 515 000 $1. 515 000 $6 600
System Dist Reliabilitv Imnrove Worst Feeders $1 075 000 $1.075 000
Distribution CDA East & North $1. 325 000 $1. 325 000
Distribution Pullman & Lewiston $600 000 $600 000
10th & Stewart Dist Int $250 000 $250 000
Blue Creek 115 kV Substation Rebuild $1 500 000 $1.500 000TotalIdaho Distribution Proiects $6,615,000 $6,615,000 $6,600
Distribution Replacement Proiects
Elect Distribution Minor Blanket $8 000 000 $2.787 000
Wood Pole Replacement and Capital Dist Feeder
Repair $9.468.000 $3 299 000
Electric Underaround Renlacement $3.675.000 $1. 280 000 $35,000
Distribution Line Relocation $1.700.000 $592 000
Failed Electric Plant $2.100.000 $732.000
Replace Hiah Resistance Conductor $3.017.000 $905.000
PCB Related Dist Rebuilds $2.820.000 $420.000
Total Distribution Replacement Proiects $30,780,000 $10,015,000 $35,000
Washinqton Distribution Proiects (Not included in this case)
Distribution Proiects in Washinaton $12.204.000 $0
Washinaton Smart Grid Proiects $8.404.000 $0
Total Washington Distribution Proiects $20,608,000 $0
Total Distribution Proiects $58,003,000 $16,630,000 $41,600
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18 Distribution Projects specific to Idaho (including
19 for 2012 total $6.615 million.Thesetransformation)
20 proj ects are necessary to meet capacity needs of the
21 system, improve reliability, and rebuild aging distribution
22 substations and feeders.The following proj ects make up
23 the $ 6.615 million.
24 . Power Transformer Distribution ($0.350 million):25 Transformers are transferred to plant upon receiving26 them. These transformers are being purchased to27 replace existing spares that will be installed in 2012
28 as either replacements or new installations. The29 purchased transformers will either remain as system
Kinney, Di 50
Avista Corporation
1 spares or placed into service as part of proposed 2012
2 projects. There are no offsets associated with these
3 transformers until they are placed into service.
4
5 . System Wood Substation Rebuild - Big Creek 115 kV
6 ($1.515 million): The Big Creek 115 kV Substation near7 Kellogg, ID, will be rebuilt with steel structures and
8 new equipment. The station was originally constructed
9 in 1956 and needs to be rebuilt to today's design and10 construction standards. Loss savings calculations11 indicate that the new transformer installation will12 result in an offset of $6,600 in the pro forma period
13 (based on a $53. 01/MWh avoided energy cost and an14 energization date of October, 2012).
15
16 . System - Dist Reliability Improve Worst Feeders17 ($1.075 million): Based on a combination of
18 reliability statistics, including CAIDI, SAIFI, and19 CEMI (Customers Experiencing Multiple Interruptions),20 feeders have been selected for reliability improvement21 work. This work is expected to improve the22 reliabili ty of these electric primary feeders. This is23 an annually recurring program initiated in 2008 to24 address underperforming feeders on the electric25 distribution system. Most of the feeder circuits are
26 rural in nature and many experience 10 to 20 sustained27 outages per year discounting maj or events. The28 treatment of feeder projects varies from conversion of29 overhead to URD facilities, installing additional mid-30 line protective devices, to hardening of existing31 facilities. In Idaho, projects stretch from32 Sandpoint, Kellogg, St. Maries, Moscow, and33 Grangeville.
34
35 . Distribution - CdA East & North ($1.325 million): This36 program represents several distribution capacity
37 upgrade proj ects as determined by SynerGEE modeling by38 Avista's distribution planning engineers and39 divisional area Engineers. These projects are40 characterized as "segment reconductor" proj ects and41 represent portions of main feeder trunk lines that are42 thermally constrained. The proj ects tend to be urban43 in nature.
44
45 . Distribution Pullman & Lewiston ($0.600 million): As46 above, this project includes the segment reconductor
47 of primary feeder trunk lines in Lewiston, Idaho.48 Both have been identified as "thermally constrained"
49 via SynerGEE load flow modeling and analysis.
50
51 . 10th & Stewart Distribution Integration ($0.250
52 million): Load growth in the Lewiston "Orchards"53 requires a substation capacity increase from a 20MVA
Kinney, Di 51
Avista Corporation
1 to 30MVA 115/13.2 kV unit. An associated third
2 distribution feeder will be added to the substation.
3 This $250,000 dollar project represents the cost to
4 reconfigure the distribution system beyond the
5 substation boundary fence line.
6
7 . Blue Creek 115 kV Substation Rebuild ($1.500 million) :
8 The Blue Creek 115 kV Substation just east of Coeur
9 d' Alene needs to be rebuilt adj acent to the existing
10 substation to accommodate new equipment, including a11 new panelhouse, as a result of the need to replace the12 substation transformer. An additional feeder will13 also be added for distribution system reliability and14 operational flexibility as well as future load service15 capabili ty.
16
17 The Company also will spend approximately $30.780
18 million (system) in equipment replacements and minor
19 rebuilds associated with aging distribution equipment
20 discovered through inspections,feeders with poor
21 reliability performance, replacements from storm damage,
22 relocation of feeder sections resulting from road moves, or
23 safety improvements.A brief description of the projects
24 included in these replacement efforts is given below.
25
26 . Electric Distribution Minor Blanket Projects ($8.00027 million): This effort includes the replacement of
28 poles and cross-arms on distribution lines in 2011 as29 required, due to storm damage, wind, fires, or
30 obsolescence. The Company spent $9.177 million in 201031 for these proj ects.
32
33 . Wood Pole Replacement Program and Capital Distribution34 Feeder Repair ($9.468 million): The distribution wood
35 pole management program evaluates wood pole strength
36 of a certain percentage of the wood pole population37 each year such that the entire system is inspected38 every 20 years. Avista has over 240,000 distribution39 wood poles and 33,000 transmission wood poles in its40 electric system. Depending on the test results for a41 gi ven pole, the pole is ei ther considered42 satisfactory, needing to be reinforced with a steel43 stub, or needing to be replaced. As feeders are
44 inspected as part of the wood pole management program,
Kinney, Di 52
Avista Corporation
1 issues are identified unrelated to the condition of
2 the pole. This proj ect also funds the work required to3 resolve those issues (i. e. potentially leaking
4 transformers, transformers older than 1981, failed
5 arrestors, missing grounds, damaged cutouts, and dated
6 high resistance conductor). Transformers older than
7 1981 have the potential to have oil that contains
8 polychlorinated biphenyls (PCBs) . These older
9 transformers present increased risk because of the10 potential to leak oil that contains PCBs. Poles11 installed during the pre-World War II buildup have12 reached the end of their useful life. Avista' s Wood
13 Pole Management program was put into place to prevent
14 the Pole-Rotten events and Crossarm - Rotten events
15 from increasing. So far, the Wood Pole Management
16 Program has helped keep Pole-Rotten and Crossarm-
17 Rotten events in check. Comparing 2007 to 2010 data,
18 Crossarm-Rotten Events went from 46 events to 25
19 events, however, Pole-Rotten events climbed from 2520 events to 37 events in 2008 to 2010. Thus, no net
21 offsets are anticipated from the Wood Pole Management
22 program for the 2012 rate period. The Company spent23 $7.507 million on these efforts in 2010.
24
25 . Electric Underground Replacement ($3.675 million):26 This effort involves replacing the first generation of27 Underground Residential District (URD) cable. This28 project, which has been ongoing for the past several29 years, will be completed in 2012. This program30 focuses on replacing a vintage and type of cable that31 has reached its end of life and contributes
32 significantly to URD cable failures. The Company33 spent $4.092 million in 2010. The incremental savings
34 in Operation and Maintenance expenses seen in 2010 was
35 $35,000 due to reduced number ofURD Primary Cable36 fault reductions. In 2012, we anticipate that we will
37 see the same incremental savings as 2010, which has38 been included as an offset for the Electric
39 Underground Replacement proj ect.
40
41 . Distribution Line Relocation ($1.700 million): The42 relocation of transmission and distribution lines as43 required due to road moves requested by State, County
44 or City governments. The Company spent $1.559 million
45 in 2010 on line relocations associated with road46 moves.
47
48 . Failed Electric Plant ($2.100 million): Replacement
49 of distribution equipment throughout the year as
50 required due to equipment failure. The Company spent51 $2.665 million in 2010.
52
Kinney, Di 53
Avista Corporation
1 . Replace High Resistance Conductor ($3.017 million
2 system / $0.905 million Idaho): Avista operates
3 approximately 18,500 miles of primary distribution
4 main trunk and service lateral circuits. Nearly 1,000
5 miles of our system has been identified as 'high
6 resistance" at 10 ohms per mile or greater. These
7 high resistance conductors are generally small wire
8 copper, iron, or steel conductors and most have been
9 in service greater than 50 years. 2012 represents
10 year-2 of an annually recurring program to11 systematically replace these conductors with modern12 aluminum wire. Several projects have been identified13 in the Idaho service terri tory and are targeted for14 replacement. High resistance wire impairs the ability15 of protective devices, such as circuit reclosers and16 fuses, to operate as designed resulting in a safety
17 issue. The high resistance wire that is being18 replaced under this program is very lightly loaded so19 there isn't measurable loss savings.
20
21 . PCB Related Distribution Rebuilds ($2.820 million22 system / $0.420 million Idaho): In 2011, Avista
23 ini tiated a systematic replacement of PCB containing24 distribution line transformers. 2012 represents year-25 two of a six year effort to replace these "pre-1 981"26 distribution transformers. In 2012, the program is27 expected to replace approximately 280 line28 transformers in Idaho.
29
30
31 V. AVISTA'S ASSET MAAGEMNT PROGRA
32 Q.Please describe the Company's overall Asset
33 Management Program plan.
34
35
A.Entering the 21st Century Avista, like most
utilities faced an aging infrastructure,needed to
36 transition the electric distribution and transmission
37 system into a new era. Planning to replace aging physical
38 assets in the most cost effective and beneficial manner for
39 customers has become a priority. Asset Management involves
40 determining what equipment should be integrated into a
41 comprehensive program, what are the optimum maintenance
Kinney, Di 54
Avista Corporation
1 intervals for each asset, and when is the right time to
2 replace these assets to reduce lifecycle costs.
3 Avista's Asset Management program has made an impact
4 for our customers. The wildlife guard installation program
5 on Distribution Transformers has cut the number of squirrel
6 related events from a high of 902 in 2006 to 390 in 2010.
7 Underground Residential Primary Cable faults were reduced
8 from a high of 211 to 93.Combined, the number of Asset
9 Management related events in our Outage Management Tool
10 (OMT) has come down from a high of 3,742 events in 2008 to
11 3,191 in 2010. While there is still room for improvement,
12 Asset Management has made a difference and is saving money
13 by avoiding or reducing the number of future failures.
14 Asset Management uses a process which combines
15 technology and information into an integrated analysis from
16 a myriad of sources and creates a comprehensive plan for
17 Avista's physical plant.Asset Management strives to
18 maximize the lifecycle value of the Company's assets for
19 its customers.By minimizing life cycle costs, Avista is
20 able to maximize system reliability and value for our
21 customers.Using the analytical models, Avista enhances
22 the decision process to better ensure future success.
23 The foundation for the plan involves determining the
24 future failure rates and impacts to the environment,
25 reliabili ty, safety, customers, costs, labor, spare parts,
26 and time.This failure rate model then becomes the
Kinney, Di 55
Avista Corporation
1 baseline to compare all other options, to assure the most
2 efficient use of Company resources.
3 Based on the work of Asset Management, Avista's
4 Vegetation Management program results in a pro forma
5 adjustment to program costs planned for 2012 that are above
6 that included in the Company's test period.
7 Q.Please describe the vegetation management portion
8 of the Asset Management Program and the amounts for which
9 the Company is requesting an increase in costs above its
10 historical test period.
11
12
A.Vegetation Management is a key component of
Avista's Asset Management Plan.Avista's Vegetation
13 Management (VM) program maintains the distribution and
14 transmission systems clear of trees and other vegetation.
15 In addition, the VM program provides safety clearances for
16 the public from trees and reduces customer outages caused
17 by trees, weather, and, to a lesser extent, squirrel caused
18 outages.Avista's electric distribution system includes
19 7,800 distribution overhead circuit miles of which 5,200
20 are in Washington and 2,600 are in Idaho. The Transmission
21 System includes 1,675 circuit miles of 115 kV Transmission
22 Lines and 984 circuit miles of 230 kV Transmission Lines
23
24
25
26
mainly in Washington and Idaho.The Gas System High
Pressure Lines include 291 miles.This is a significant
amount of miles,and each mile requires vegetation
management.Avista's VM program is almost entirely
Kinney, Di 56
Avista Corporation
1 contracted out, with the primary contractor for this work
2 being Asplundh Tree Experts.
3 As shown in Table 8 below,Idaho's electric
4 distribution vegetation management level of expenditure
5 necessary in 2012 is $3.237 million, which is approximately
6 $1.3 million above that included in the 2010 test period
7 ($1.874 million).The $1.284 million of incremental pro
8 forma spend compared to 2010 actual spend (less offsetting
9 savings included as described below of $80,000) has been
10 included in the Company's electric revenue requirement
11 request filed in this case as discussed further by Ms.
12 Andrews.
1314 Table 8: Distribution Pro Form
15 Increment for Vegetation Management
Pro Forma Increment
$1,873,707
$3,237,477
-$80,000
$1,283,770
2010 Actual
2012 Planned
2012 Offset
16
17 Q.What is the cause for the incremental increase in
18 costs in distribution vegetation management over that
19 included in the Company's 2010 test period?
20 A.Avista strives to improve its Asset Management
21 programs as better information is available or conditions
22 change. Over the last few years the Company has continued
23 to evaluate its processes and plans and determined it can
Kinney, Di 57
Avista Corporation
1 further optimize its Vegetation Management program.The
2 most recent analysis performed on the Company's vegetation
3 management work plan determined an optimized clearing cycle
4 more customized to each feeder will provide more value to
5 our customers. The Optimized Cycle has an average clearing
6 cycle time of four years, but the actual cycle times will
7 vary depending upon the circuits needs.This equates to
8 clearing 1,950 miles per year in order to minimize future
9 increases in costs,reduce future failure rates and
10 optimize system reliability.
11 As the Company has analyzed the plan over time, outage
12 data collected by the Company's Outage Management Tool
13 (OMT) 1 has shown an increase in events on circuit miles
14 where trees are trimmed less frequently.As shown in
15 Illustration 1 below, Avista continues to see an increase
16 in the number of vegetation related events.The general
17 OMT trends in Tree Growth (i. e. trees growing into the
18 power lines and causing an outage or other problems with
19 the power line), Tree Fell (i. e. trees falling from outside
20 and inside the easement into a distribution power line) and
21 Tree Weather (i. e. tree related outages or events where the
22 root cause is related to the weather) events remain a
23 concern for VM with a trend upwards.While weather
24 condi tions change each year and contribute to the number of
i The data behind the failure rates used in the program models come
from information gathered during past years' work and failures.
Information was gathered for the number of trees removed, trees
trimmed, and brush removed along with the failure documented in the
Outage Management Tool (OMT) and were used to create the failure
curves used by the models.
Kinney, Di 58
Avista Corporation
1 events each year, the overall trend continues upward even
2 with a few good years of weather in 2009 and 2010.3 Illustration 1
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
--- Tree Fell Events ...... Tree Growth Events -Tree Weather Events
1600
1400
1200II..c
! 1000
$io 800Õ..
,l 600
E::Z 400
. ..."",,~---,.--,------:",., .......
200
o
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Year
partial outages associated with Tree Fell, Tree Growth, and
However, a trend in the number of actual outages and
20 Tree Weather shows promise and improvement as shown in
21 Illustration 2 below. While the number of events continues
22 upwards for Tree Fell (see Illustration 1), the actual
23 number of outages is trending downwards and Tree Growth
24 outages remain relatively flat (see Illustration 2). This
25 suggests the current program is having a positive impact,
27
26 but not enough to stop all of the rising trends.
Kinney, Di 59
Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Illustration 2
- - Tree Fell Outages - Tree Weather Outages...... Tree Growth Outages
1600
11
fo 1400ni..::o
.!!
1:niQ.
"0Cni
11
CItIni..::o-o..
CI.c
E::Z
1200
1000
800
600
400
- -200 - - - --
....................................................................... ........ .
o
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Year
Delaying work increases the amount of work required
and the associated cost.This is clearly shown in the
19 exponential curve illustrated in Illustration 3 below. The
20 probability that a line segment will require work begins to
21 trend upwards when you exceed four years since the last
22 vegetation work.
Kinney, Di 60
Avista Corporation
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Illustration 3
100.00%
..
l;~
i 80.00%
crii
1iII 60.00%~
J:
II.s......
i 40.00%
0
ol
20.00%
Probabilty a Feeder Segment wil require Vegetation Management
Work
120.00%
0.00%
o 6 10 12 14 164
Years since Last Vegetation Manaiement
19 Company's current case and the Optimized Case (average of a
Illustration 4 below shows cost projections of the
21
20 four-year clearing cycle) .
Kinney, Di 61
Avista Corporation
0 T"C\(t -.i.(0 ..00 0)T"T"T"T"..T"T"......0 0 0 0 0 0 0 0 0 0C\C\C\C\C\C\C\C\C\C\
Year
To further support the rational for the optimized
cycle time (four-year cycle) ,Table 9 below shows the
2
3
4
5
6
7
8
ti 1600i:
~~1400
Inc:0 1200~(I...1000~ri-800In0(J
~600
;¡.!400=
E=(J 200
0
Illustration 4
I ...... No Action Case -CurrntCase -_ 5YearCsII8 . '"....." OptimiZed Case I
..'......
..
......
.
.....
.
..'
......'...;-..'.'.'.'
.'-.'.'.'--.'..'.'~ 9f.....,...9f..."..".'. ....."" 9f.....""... .......................". .....
17 estimated average number of OMT events over the next 10
9
10
11
12
13
14
15
16
18
19
and the Optimizedyears for the Company's current case
Based on the information shown inCase (four year cycle).
20 Table 9, we anticipate preventing over 1,500 events each
21 year once all feeders are on an optimized cycle.
22
Kinney, Di 62
Avista Corporation
1
2
3
4
5
6
7
8
9
10
Table 9
6 Year Average OMT 420 309 440 1,169Events
Projected 10 Year 330 789 774 1,893Avera e. Current Case
Projected 10 Year
Average. Optimized 53 225 62 340
Case
Difference between
Current Case and 277 564 712 1,553
o timized Case
11 In response to a revised look at risks, Avista is also
12 expanding the Risk Tree inspections to include more trees
14
13 such as those with split tops, which have a higher risk of
failing than a normal tree.This additional work is
15 estimated to add over $100,000 in Idaho to the current work
16 and is included in the increased expense for the overall
17 Vegetation Management program.
18 As can be seen from the illustrations and discussions
19 above, for the distribution system, our analysis shows that
20 an optimized clearing cycle has definite advantages and
21 savings over the longer current and previous line clearing
22 cycles, and that a pro-active maintenance program is
23 necessary to provide the best value and level of
25
24 reliability to our customers.
What offsetting the CompanyQ.factors does
26 anticipate as a result of Avista's vegetation managemnt
27 plan?
Kinney, Di 63
Avista Corporation
1 A.Under the current plan, an approximate five-year
2 trim cycle is anticipated to reduce OMT events each year
3 once all feeders are on a cycle, providing estimated
4 savings of approximately $1.5 million annually.Annual
5 savings cannot be realized until after the specific feeders
6 have been trimmed for a given year, and the savings would
7 not be seen until the following year.In 2011, since the
8 Company is on an approximate five-year trim cycle, the
9 annual savings anticipated in 2012 (after the first year
10 cycle is completed) is estimated at $234,400 ($80,000 Idaho
11 share) .The Company has included this offset (reducing
12 operating and maintenance expense) against the 2012 planned
13 vegetation management expense pro formed into this case.
14 Ms. Andrews includes the pro forma vegetation management
15 adjustment (including this offset) in her adjustments.
16 For future years, after moving to a four year trim
17 cycle in 2012 as proposed in this case, anticipated savings
18 increases to approximately $342,000 ($119,200 Idaho share)
19 in 2013.
20 Q.Does this complete your pre-filed direct
21 testimony?
22 A.Yes it does.
Kinney, Di 64
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: ( 509 ) 495 - 4 316
FACSIMILE: [phone]
DAVID. MEYERØAVI STACORP . COM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC AN
NATURA GAS SERVICE TO ELECTRIC
AND NATURA GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-11-01
EXHIBIT NO. 9
SCOTT J. KINNEY
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avista Corporation
- Energy Delivery -
Pro Forma Transmission Revenue/Expenses
($OOOs)
2012
Line 2010 Pro Forma
No.Actual Adjusted Period
556 OTHER POWER SUPPLY EXPENSES
NWPP 42 43
560-71.4,935.3-.4 TRANSMISSION O&M EXPENSE
2 Colstrip O&M - 500kV Line 443 117 560
3 ColumbiaGrid Development 194 -14 180
4 ColumbiaGrid Planning 164 56 220
5 Columbia Grid OASIS 44 42 86
6 Canada to N.Cal (CNC) Project 0 255 255
7 Transmission Line Ratings Confirmation Plan 0 2,145 2,145
8 · Grid West (10)71 -71 0
9 Total Account 560-71.4, 935.3-.4 916 2,530 3,46
561 TRANSMISSION EXP-LOAD DISPATCHING
10 Elect Sched & Acctg Srv (OATI)171 4 175
566 TRANSMISSION EXP-OPRN-MISCELLANEOUS
11 NERC CIP 47 3 50
12 OASIS Expenses 8 1 9
13 BPA Power Factor Penalty 138 -7 131
14 WECC - Sys. Security Monitor 167 4 171
15 WECC Admin & Net Oper Comm Sys 384 -25 359
16 WECC - Loop Flow 20 12 32
17 Total Account 556 764 -12 752
18 TOTAL EXPENSE 1,893 2,523 4,416
456 OTHER ELECTRIC REVENUE
19 Borderline Wheeling Transmission 7,365 -706 6,659
Borderline Wheeling Low Voltage 364 713 1,077
20 SeattlelTacoma Main Canal 292 -4 288
21 Seattlel Tacoma Summer Falls 74 0 74
22 OASIS nf & stf Whl (Other Whl)2,887 103 2,990
23 PP&L - Dry Gulch 218 11 229
24 Spokane Waste to Energy Plant 160 -160 0
25 Grand Coulee Project 8 0 8
26 First Wind Energy Marketing 0 200 200
27 .. BPA Settlement 1,177 -1,177 0
28 Total Account 456 12,545 -1,020 11,525
29 TOTAL REVENUE 12,545 -1,020 11,525
30 TOTAL NET EXPENSE -10,652 3,543 -7,109
· Grid West/RTO Deposit Amortization for Idaho ends December 2011.
One time event.
Exhibit NO.9
Case Nos. AVU-E-11-01 and AVU-G-11-01
S, Kinney, Avista
Schedule 1, Page 1 of 1
r
CONFIDENTIAL
Transmission Line Ratings Confirmation Plan
Pages i through 32
THESE PAGES ALLEGEDLY CONTAIN TRAE SECRETS OR
CONFIDENTIAL MATERIALS AN AR SEPARTELY FILED.
Exhibi t No. 9
Case No. AVU-E-11-01
S. Kinney, Avista
Schedule 2, p. 1 of 32