20121011Kinney DI.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) DIRECT TESTIMONY
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) SCOTT J. KINNEY
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Kinney, Di 1
Avista Corporation

I. INTRODUCTION 1
Q. Please state your name, employer and business 2
address. 3
A. My name is Scott J. Kinney. I am employed by 4
Avista Corporation as Director, Transmission Operations. 5
My business address is 1411 East Mission, Spokane, 6
Washington. 7
Q. Please briefly describe your educational 8
background and professional experience. 9
A. I graduated from Gonzaga University in 1991 with 10
a B.S. in Electrical Engineering. I am a licensed 11
Professional Engineer in the State of Washington. I joined 12
the Company in 1999 after spending eight years with the 13
Bonneville Power Administration. I have held several 14
different positions in the Transmission Department. I 15
started at Avista as a Senior Transmission Planning 16
Engineer. In 2002, I moved to the System Operations 17
Department as a supervisor and support engineer. In 2004, 18
I was appointed as the Chief Engineer, System Operations. 19
In June of 2008 I was selected to my current position as 20
Director, Transmission Operations. 21
Q. What is the scope of your testimony? 22

Kinney, Di 2
Avista Corporation

A. My testimony describes Avista’s pro forma period 1
transmission revenues and expenses. I also discuss the 2
Transmission and Distribution expenditures that are part of 3
the capital additions testimony provided by Company witness 4
Mr. DeFelice, as well as projects associated with the 5
Company’s Asset Management Program. Company witness Ms. 6
Andrews incorporates the Idaho share of the net 7
transmission expenses and investment 8
Q. Are you sponsoring any Exhibits? 9
A. Yes. Exhibit 9, Schedule 1 provides the 10
transmission pro forma adjustments. 11
12
A table of contents for my testimony is as follows: 13
Section Page 14
I. Introduction 1 15
II. Pro Forma Transmission Expenses 2 16
III. Pro Forma Transmission Revenue 13 17
IV. Transmission and Distribution Capital Projects 24 18
V. Vegetation Management Program 55 19
20
II. PRO FORMA TRANSMISSION EXPENSES 21
Q. Please describe the pro forma transmission 22
expense revisions included in this filing. 23

Kinney, Di 3
Avista Corporation

A. Adjustments were made in this filing to 1
incorporate updated information for any changes in 2
transmission expenses from the July 2011 to June 2012 test 3
year to the 2013 pro forma rate period. The changes in 4
expenses and a description of each is summarized in Table 1 5
and are system costs with the exception of Grid West, which 6
is a direct Idaho cost: 7
Table 1:
Transmission Expense Adjustments

*Pro Forma
(System)
Northwest Power Pool (NWPP) $ 3,000
Colstrip Transmission $ (43,000)
ColumbiaGrid RTO $ 55,000
ColumbiaGrid Transmission Planning $ 17,000
ColumbiaGrid OASIS $ 4,000
Elect Sched & Acctg Srv (OATI) $ 8,000
NERC CIP $ 2,000
OASIS Expenses $ 9,000
BPA Power Factor Penalty $ (1,000)
WECC Total Dues - WECC Sys Secur & Admin- Net Oper Comm Sys $ 67,000
WECC - Loop Flow $ (14,000)
CNC Transmission Project $ 126,000
Transmission Line Ratings Confirmation Plan (NERC Alert) $ (189,000)
Total System Expense $ 44,000
Grid West (ID Direct) $ (35,000)

Total Expense $ 9,000
*Representing the change in expense above or below the 2011 test period level. 8
9
Northwest Power Pool (NWPP) ($3,000) – Avista pays its 10
share of the NWPP operating costs. The NWPP serves the 11
electric utilities in the Northwest by supporting regional 12

Kinney, Di 4
Avista Corporation

transmission planning coordination, providing coordinated 1
transmission operations including contingency generation 2
reserve sharing, and Columbia River water coordination. 3
Actual test period transmission related NWPP expenses were 4
$51,000 and a $3,000 adjustment is being made to the pro 5
forma period to reflect an approved 6.2% increase in the 6
NWPP expenses allocated to the Company. 7
Colstrip Transmission (-$43,000) – Avista is required 8
to pay its portion of the O&M costs associated with its 9
share of the Colstrip transmission system pursuant to the 10
joint Colstrip contract. In accordance with NorthWestern 11
Energy’s (NWE) proposed Colstrip transmission plan provided 12
to the Company, NWE will bill Avista $387,000 for Avista’s 13
share of the Colstrip O&M expense during the pro forma 14
period. This is a decrease of $43,000 from the actual 15
expense of $430,000 incurred during the test year. 16
ColumbiaGrid ($55,000) – Avista became a member of the 17
ColumbiaGrid regional organization in 2006. ColumbiaGrid’s 18
purpose is to enhance transmission system reliability and 19
efficiency, provide cost-effective coordinated regional 20
transmission planning, develop and facilitate the 21
implementation of solutions relating to improved use and 22
expansion of the interconnected Northwest transmission 23

Kinney, Di 5
Avista Corporation

system, reduce transmission system congestion, and support 1
effective market monitoring within the Northwest and the 2
entire Western interconnection. Avista supports 3
ColumbiaGrid’s general developmental and regional 4
coordination activities under a general funding agreement 5
and supports specific functional activities under the 6
Planning and Expansion Functional Agreement and the OASIS 7
Functional Agreement. The current general funding 8
agreement for ColumbiaGrid expires December 31, 2012, 9
however a follow-on contract will be developed to replace 10
the expiring contract. Avista’s ColumbiaGrid general 11
funding expenses for the test year were $132,000 while 2013 12
general funding expenses provided by ColumbiaGrid at a 13
Board meeting on August 14, 2012 are forecasted to be 14
$187,000, an increase of $55,000. 15
ColumbiaGrid Transmission Planning ($17,000) – The 16
ColumbiaGrid Planning and Expansion Functional Agreement 17
(PEFA) was accepted by the Federal Energy Regulatory 18
Commission (FERC) on April 3, 2007 and Avista entered into 19
the PEFA on April 4, 2007. Coordinated transmission 20
planning activities under the PEFA allow the Company to 21
meet the coordinated regional transmission planning 22
requirements set forth in FERC’s Order 890 issued in 23

Kinney, Di 6
Avista Corporation

February, 2007, and outlined in the Company’s Open Access 1
Transmission Tariff, Attachment K. Funding under the PEFA 2
is on a two-year cycle with provisions to adjust for 3
inflation. Actual PEFA expenses for the test year were 4
$209,000. The Company’s PEFA pro forma expenses are at the 5
maximum total payment obligation of $226,000 as provided at 6
the Board meeting on August 14, 2012. This cost reflects 7
ColumbiaGrid’s staffing levels to support the PEFA and the 8
reallocation of a portion of ColumbiaGrid’s administrative 9
expenses (previously paid under the general funding 10
agreement) to this functional agreement. 11
ColumbiaGrid Open Access Same-Time Information System 12
(OASIS) ($4,000) – Avista entered into the ColumbiaGrid 13
OASIS Functional Agreement in February 2008. This 14
agreement provides for the development of a common OASIS 15
which gives transmission customers the ability to purchase 16
transmission capacity from multiple ColumbiaGrid members 17
via a single common OASIS site instead of having to submit 18
multiple transmission service requests to each member 19
individually on each member’s respective OASIS sites. 20
Avista’s test year expenses of $30,000 reflected initial 21
developmental activities under this functional agreement. 22
Avista’s ColumbiaGrid OASIS pro forma expenses are $34,000, 23

Kinney, Di 7
Avista Corporation

reflecting operational capability of the ColumbiaGrid OASIS 1
and the reallocation of a portion of ColumbiaGrid’s 2
administrative expenses (previously paid under the general 3
funding agreement) to this functional agreement. 4
Electric Scheduling and Accounting Services ($8,000) – 5
The $8,000 increase in the pro forma period compared to 6
test year expense for electric scheduling and accounting 7
services is a result of annual increases and additional 8
services purchased from our third party vendor. These 9
services are required to assist in meeting the requirements 10
of North American Electric Reliability Corporation (NERC) 11
mandatory reliability standards. The pro forma scheduling 12
and accounting costs are $179,000 compared to test year 13
costs of $171,000. 14
NERC Critical Infrastructure Protection ($2,000) – The 15
Company has purchased several software products to assist 16
in protecting critical transmission system data from 17
intrusion and to meet applicable NERC standards. The 18
Company’s pro forma expenses increase $2,000 from the 19
actual test year expense of $31,000 due to annual 20
application maintenance cost increases. 21
OASIS Expenses ($9,000) – These OASIS expenses are 22
associated with travel and training costs for transmission 23

Kinney, Di 8
Avista Corporation

pre-scheduling and OASIS personnel. This travel is 1
required to monitor and adhere to NERC reliability 2
standards, regional criterion development, and FERC OASIS 3
requirements. The costs associated with OASIS expenses in 4
the pro forma period are $9,000 compared to $450 of actual 5
expenses in the test year. In the test year employees 6
associated with the OASIS function did not travel much nor 7
attend training due to increased workload associated with 8
several new projects and requirements. 9
Power Factor Penalty (-$1,000) – Power factor penalty 10
costs are associated with the Bonneville Power 11
Administration’s (Bonneville) General Transmission Rate 12
Schedule Provisions. Bonneville charges a power factor 13
penalty at all interconnections with Avista that exceed a 14
given threshold for reactive power flow during each month. 15
If the reactive flow from Bonneville’s transmission system 16
into Avista’s system or from Avista’s system to 17
Bonneville’s system exceeds a given threshold, then 18
Bonneville bills Avista according to its rate schedule. 19
The charge includes a 12-month rolling ratchet provision. 20
Avista currently pays Bonneville a power factor penalty at 21
several points of interconnection. Avista incurred 22
$203,000 of power factory penalty charges during the test 23

Kinney, Di 9
Avista Corporation

year. The Company’s pro forma 2013 expenses are expected 1
to be $202,000 representing a continuation of the current 2
12 month ratchet set in June of 2012. 3
WECC – System Security Monitor and WECC Administration 4
& Net Operating Committee Fees ($67,000) – The WECC Board 5
of Directors approved a 12.5% increase in dues for 2013 at 6
their Board meeting in June of 2012. The increase is 7
primarily associated with labor and software additions to 8
support additional reliability and compliance requirements 9
for the WECC Reliability Coordinator function. WECC is 10
also responsible for monitoring and measuring Avista’s 11
compliance with the standards and, therefore, continues to 12
increase its staff and other resources to meet this FERC 13
requirement. The Company paid its 2012 WECC assessments in 14
January 2012: $205,000 for system security monitoring and 15
$328,000 for operating and support fees, for a total WECC 16
assessment of $533,000. The Company’s total pro forma 2013 17
expenses have been increased by 12.5% to $600,000 ($231,000 18
for system security and $369,000 for operating and support) 19
to reflect the WECC Board approved funding levels. 20
WECC - Loop Flow (-$14,000) – Loop Flow charges are 21
spread across all transmission owners in the West to 22
compensate utilities that make system adjustments to 23

Kinney, Di 10
Avista Corporation

eliminate transmission system congestion throughout the 1
operating year. WECC Loop Flow charges can vary from year 2
to year since the costs incurred are dependent on 3
transmission system usage and congestion. Therefore a 4
five-year average is used to determine future Loop Flow 5
costs. Based upon the average WECC Loop Flow charges 6
incurred by the Company during the five-year period from 7
2008 through 2012, pro forma Loop Flow expenses are 8
$31,000. This is $14,000 less than actual test year 9
charges of $45,000, which included payments for the 2011 10
and 2012 operating years. 11
Canada to Northern California (CNC) Transmission 12
Project ($126,000) – The CNC transmission project was 13
initially proposed by Pacific Gas and Electric Company 14
(“PG&E”). As initially proposed, the CNC transmission 15
project was an Extra High Voltage (“EHV”) transmission 16
project that, if developed, would include a 500kV 17
transmission line that would run between British Columbia, 18
Canada and Northern California. With PG&E as the primary 19
sponsor, Avista, British Columbia Transmission Corporation, 20
PacifiCorp and Transmission Agency of Northern California 21
were also original sponsors of the CNC transmission 22
project. The cost accrued by Avista for its participation 23

Kinney, Di 11
Avista Corporation

in the CNC regional transmission project was $758,000. Of 1
this amount, $537,000 is the amount Avista paid for its 2
share of the initial sponsorship of the CNC transmission 3
project pursuant to the Stage One Project Development 4
Agreement, and $221,000 consisted of the direct 5
transmission planning expenses incurred by Avista. Avista 6
is amortizing these expenses over a three-year period 7
beginning in 2012, resulting in an amortized expense of 8
$253,000 ($88,000 Idaho share) in the pro forma period. A 9
total of $127,000 (6 months) was amortized in the test 10
year1. 11
Transmission Line Ratings Confirmation Plan (NERC 12
Alert) ($-189,000) – The Transmission Line Ratings 13
Confirmation Plan was developed to address a “NERC Alert” 14
issued on October 7, 2010. The NERC issued a 15
“Recommendation to Industry addressing Consideration of 16
Actual Field Conditions in Determination of Facility 17
Ratings” based on a vegetation contact conductor-to-ground 18
fault by another Transmission Owner. The NERC Alert was 19
issued to provide the industry an opportunity to review 20
actual field conditions and compare them to design values 21

1 The amortization of the Canada to Northern California (CNC)
Transmission Line was proposed in the Company’s last general rate case
(AVU-E-11-01) that was resolved through a “black-box” settlement. The
amortization period represents the method proposed in AVU-E-11-01.

Kinney, Di 12
Avista Corporation

to ensure system reliability. Avista initiated a three 1
year program beginning in 2011 to perform Light Detection 2
and Ranging (LIDAR) surveying of all Avista 230kV 3
transmission lines and five (5) 115kV transmission lines. 4
A total of 1400 miles of transmission lines were to be 5
evaluated at a projected total system cost of $2.945 6
million. The total project cost for this effort has been 7
reduced to $2.260 million based on a reduction of miles 8
required to evaluate. The remaining pro forma costs for 9
this project are $0.323 million. The test year expenses 10
associated with this project was $0.512 million. 11
Grid West (ID Direct) (-$35,000) - Avista signed an 12
initial funding agreement in 2000, as did all other Pacific 13
Northwest investor-owned electric utilities, to provide 14
funding for the start-up phase of Grid West (then named 15
"RTO West"). Grid West had planned to repay the loans to 16
Avista and other funding utilities through surcharges to 17
customers once it became operational. With the dissolution 18
of Grid West, this repayment did not occur. As a result, 19
Avista filed an application with the Commission to defer 20
these costs. The Commission approved, on October 24, 2006, 21
in Order No. 30151, the Company’s request for an order 22
authorizing deferred accounting treatment for loan amounts 23

Kinney, Di 13
Avista Corporation

made to Grid West. In its Order the IPUC found these costs 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 $35,000 in the test year. 8
9
III. PRO FORMA TRANSMISSION REVENUES 10
Q. Please describe the pro forma transmission 11
revenue revisions included in this filing. 12
A. Adjustments have been made in this filing to 13
incorporate updated information associated with known 14
changes in transmission revenue for the 2013 pro forma 15
period as compared to the 2011/12 test year. Each revenue 16
item described below is at a system level and is included 17
in Schedule 1 of Exhibit No. 9. Please see Table 2 and 18
descriptions below for further detail on the revenue pro 19
forma amounts. 20

Kinney, Di 14
Avista Corporation

Table 2:
Transmission Revenue Adjustments

*Pro Forma
(System)
Borderline Wheeling Transmission & Low Voltage $ 40,000
Seattle/Tacoma Main Canal $ (7,000)
Seattle/Tacoma Summer Falls $ 0
OASIS, non-firm, & short-term firm (Other Wheeling) $ (2,764,000)
Pacificorp– Dry Gulch $ (4,000)
Spokane Waste to Energy Plant $ (66,000)
Grand Coulee Project $ 0
Palouse Wind $ 0
Palouse Wind O&M $ 70,000
Stimson Lumber $ 3,000
Hydro Tech Systems – Meyers Falls $ 3,000
BPA Parallel Operating Agreement Settlement $ 3,192,000
Morgan Stanley Transmission Service $ 600,000
Total Expense $ 1,067,000
*Representing the change in revenue above or below the 2011 test period level. 1
2
Borderline Wheeling Transmission and Low Voltage 3
($40,000) 4
Total borderline wheeling revenues including 5
Transmission ($7,169,000) and Low Voltage ($1,071,000) for 6
the test year were $8,240,000. Total borderline wheeling 7
revenue in the pro forma period has been set at $8,280,000 8
(Transmission, $7,209,000 and Low Voltage, $1,071,000), 9
which reflects a slight increase over the test year. In 10
the past the pro forma borderline revenue has been 11
developed using a five-year rolling average of revenues 12
from borderline wheeling service provided to Bonneville and 13
other customers since a large portion of the revenue is 14
dependent upon usage. However, with billing adjustments 15
implemented in 2009 and the new transmission rates that 16
went into effect in 2010, use of the previous five-years of 17
actual revenues would not properly reflect the new level of 18

Kinney, Di 15
Avista Corporation

revenues. Therefore, pro forma transmission revenue has 1
been set equal to the average of actual revenue from 2010, 2
2011 and 2012 through June, or set per the actual charges 3
in each specific contract. Each of the specific borderline 4
contracts is further described below. 5
Borderline Wheeling – Bonneville Power 6
Administration – ($37,000) Actual test year revenue 7
from borderline wheeling service provided to 8
Bonneville was $7,994,000. The Bonneville 9
borderline wheeling contracts are divided into 10
transmission and low voltage service. These were 11
accounted for separately beginning in October of 12
2010 as a result of the new transmission rates. The 13
new transmission rates apply to transmission 14
service, but not to low voltage service. The pro 15
forma Bonneville borderline wheeling revenue is 16
$8,031,000, which is the average of actual revenues 17
from 2010, 2011, and 2012 through June. 18
Borderline Wheeling – Grant County PUD – ($0) The 19
Company provides borderline wheeling service to two 20
Grant County PUD substations under a Power Transfer 21
Agreement executed in 1980. Charges under this 22
agreement are not impacted by the Company’s 23
transmission service rates under Avista’s Open 24
Access Transmission Tariff so a five-year average is 25
used to determine the pro forma revenue of $26,000, 26
which was the same as the test year. 27
Borderline Wheeling – East Greenacres Irrigation 28
District – ($0) The Company restructured its 29
contract to provide borderline wheeling service to 30

Kinney, Di 16
Avista Corporation

the East Greenacres Irrigation District in April, 1
2009, resulting in monthly wheeling revenue of 2
$5,000. Revenue under this agreement for the test 3
year was $60,000. Revenue for the 2013 pro forma 4
period will remain the same at $60,000. 5
Borderline Wheeling – Spokane Tribe of Indians – 6
($2,000) The Company provides borderline wheeling 7
service over both transmission and low-voltage 8
facilities to the Spokane Tribe of Indians. Total 9
transmission and low-voltage wheeling revenue under 10
this contract for the test year was $41,000. 11
Revenue associated with the transmission component 12
of this contract is adjusted annually per the 13
contract. Accordingly, 2013 pro forma period 14
revenue under this contract is set at $43,000. 15
Borderline Wheeling – Consolidated Irrigation 16
District – ($1,000) The Company provides borderline 17
wheeling service over both transmission and low-18
voltage facilities to the Consolidated Irrigation 19
District. Total transmission and low-voltage 20
wheeling revenue under this contract for the 2011 21
test year was $118,000. A new contract signed with 22
the Consolidated Irrigation District in October of 23
2011 resulted in a shift of charges between 24
transmission and low-voltage services. Per the new 25
contract, the total Consolidated Irrigation District 26
revenue for the pro forma period is $119,000. 27
28
Seattle and Tacoma Revenues Associated with the Main 29
Canal Project (-$7,000) – Effective March 1, 2008, the 30

Kinney, Di 17
Avista Corporation

Company entered into long-term point-to-point transmission 1
service arrangements with the City of Seattle and the City 2
of Tacoma to transfer output from the Main Canal 3
hydroelectric project, net of local Grant County PUD load 4
service, to the Company’s transmission interconnections 5
with Grant County PUD. Service is provided during the 6
eight months of the year (March through October) in which 7
the Main Canal project operates and the agreements include 8
a three-year ratchet demand provision. Revenues under 9
these agreements totaled $288,000 during the test year. 10
Pro forma revenues are expected to be $281,000 based on a 11
reduction in the ratchet demand. 12
Seattle and Tacoma Revenues Associated with the Summer 13
Falls Project ($0) – Effective March 1, 2008, the Company 14
entered into long-term use-of-facilities arrangements with 15
the City of Seattle and the City of Tacoma to transfer 16
output from the Summer Falls hydroelectric project across 17
the Company’s Stratford Switching Station facilities to the 18
Company’s Stratford interconnection with Grant County PUD. 19
Charges under this use-of-facilities arrangement are based 20
upon the Company’s investment in its Stratford Switching 21
Station and are not impacted by the Company’s transmission 22
service rates under its Open Access Transmission Tariff. 23

Kinney, Di 18
Avista Corporation

Revenues under these two contracts totaled $74,000 in the 1
test year and will remain the same for the 2013 pro forma 2
period. 3
OASIS Non-Firm and Short-Term Firm Transmission 4
Service (-$2,764,000) – OASIS is an acronym for Open Access 5
Same-time Information System. This is the system used by 6
electric transmission providers for selling and scheduling 7
available transmission capacity to eligible customers. The 8
terms and conditions under which the Company sells its 9
transmission capacity via its OASIS are pursuant to FERC 10
regulations and Avista’s FERC Open Access Transmission 11
Tariff. The Company is calculating its pro forma 12
adjustments using a three-year average of actual OASIS Non-13
Firm and Short-Term Firm revenue. OASIS transmission 14
revenue may vary significantly depending upon a number of 15
factors, including current wholesale power market 16
conditions, forced or planned generation resource outage 17
situations in the region, current load-resource balance 18
status of regional load-serving entities and the 19
availability of parallel transmission paths for prospective 20
transmission customers. The use of a three-year average is 21
intended to strike a balance in mitigating both long-term 22
and short-term impacts to OASIS revenue. A three-year 23

Kinney, Di 19
Avista Corporation

period is intended to be long enough to mitigate the 1
impacts of non-substantial temporary operational conditions 2
(for generation and transmission) that may occur during a 3
given year and it is intended to be short-enough so as to 4
not dilute the impacts of long-term transmission and 5
generation topography changes (e.g. major transmission 6
projects which may impact the availability of the Company’s 7
transmission capacity or competing transmission paths, and 8
major generation projects which may impact the load-9
resource balance needs of prospective transmission 10
customers). However, if there are known events or factors 11
that occurred during the period that would cause the 12
average to not be representative of future expectations, 13
then adjustments may be made to the three-year average 14
methodology. In this filing, the Company is using the most 15
recent three-year average with an adjustment to 2011 16
revenues due to additional revenue received from Puget 17
Sound Energy (PSE) as a result of a planned construction 18
outage on BPA’s transmission system. The outage resulted 19
in additional one time revenue of $1.6 million. The 20
adjusted OASIS revenue for 2011 is $3.101 million. Using 21
this adjusted revenue results in pro forma revenue of 22
$2.946 million based on a three-year average from 2009 23

Kinney, Di 20
Avista Corporation

through 2011. The test year OASIS revenue was $5.710 1
million and includes the $1.6 million one-time collection 2
from PSE resulting from the BPA construction outage. 3
PacifiCorp Dry Gulch (-$4,000) – Revenue under the Dry 4
Gulch use-of-facilities agreement has been adjusted to 5
$217,000 for the pro forma period, which is a $4,000 6
decrease from the test year actual revenue of $221,000. 7
The Company is calculating its pro forma adjustments using 8
a three-year average of actual revenue. Revenue under the 9
Dry Gulch Transmission and Interconnection Agreement with 10
PacifiCorp varies depending upon PacifiCorp’s loads served 11
via the Dry Gulch Interconnection and the operating 12
conditions of PacifiCorp’s transmission system in this 13
area. The use of a three-year average is intended to 14
mitigate the impacts of potential annual variability in the 15
revenues under the contract. A three-year average is also 16
consistent with the methodology used for the Company’s 17
OASIS revenue. The contract includes a twelve-month 18
rolling ratchet demand provision and charges under this 19
agreement are not impacted by the Company’s open access 20
transmission service tariff rates. The three-year average 21
of revenue was calculated using years 2009 through 2011. 22

Kinney, Di 21
Avista Corporation

Spokane Waste-to-Energy Plant (-$66,000) – This 1
revenue has historically been associated with a long-term 2
transmission service agreement with the City of Spokane 3
that expired December 31, 2011. Upon the City of Spokane’s 4
decision to sell the output of the Spokane Waste to Energy 5
facility to Avista beginning January 1, 2012, the City of 6
Spokane no longer required transmission service to deliver 7
the output to a third-party purchaser. Under this new 8
arrangement, the City of Spokane compensates Avista for the 9
use of certain transmission facilities directly related to 10
the interconnection of the Spokane Waste to Energy project. 11
The pro forma revenue associated with this use of facility 12
charge is $28,000. The test year revenue, including six 13
month’s revenue from the expired transmission service 14
contract, was $94,000. 15
Grand Coulee Project 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 Project Hydroelectric authority under a 19
contract signed in March 2006. These services are provided 20
for a fixed annual fee. Annual charges under this contract 21
totaled $8,100 in the test year and will remain the same 22
for the 2013 pro forma period. 23

Kinney, Di 22
Avista Corporation

Palouse Wind ($0) – Palouse Wind signed a transmission 1
service contract with the Company based on its initial 2
intent to sell the output from a wind facility to an entity 3
other than Avista, commencing January, 2012. Palouse Wind 4
subsequently executed a power sales contract with Avista, 5
rendering its signed transmission service contract 6
unnecessary at this point in time. Under the terms of 7
Avista’s Open Access Transmission Tariff, Palouse Wind 8
intends to delay use of its 100 MW of reserved transmission 9
service for up to five years unless they are able to re-10
market the capacity. Accordingly, to obtain this deferral 11
Palouse Wind must pay one month’s transmission service 12
reservation fee. Test year revenue associated with this 13
deferred transmission service was $200,000 and the revenue 14
for the 2013 pro forma period is expected to remain the 15
same. 16
Palouse Wind O&M ($70,000) – Separate from any 17
transmission service, Palouse Wind signed an 18
interconnection agreement with the Company to integrate its 19
wind project into the Avista system. Avista constructed a 20
new 230kV switching station (Thornton) to integrate the 21
output from the wind facility. A portion of the cost of the 22
station was directly assigned to Palouse Wind. The 23

Kinney, Di 23
Avista Corporation

interconnection agreement includes annual maintenance 1
charges for equipment upkeep associated with those 2
facilities directly assigned to Palouse Wind. Operating 3
and Maintenance (O&M) charges under the interconnection 4
agreement have not been finalized but preliminary 5
calculations estimate the annual O&M charge to be about 6
3.5% of the overall asset costs. Based on this calculation 7
Palouse Wind will pay the Company approximately $70,000 per 8
year starting in 2013 for maintenance associated with 9
directly assigned facilities at Thornton. The Thornton 10
switching station was energized in August, 2012 so no O&M 11
revenue was collected in the test year. 12
Stimson Lumber Agreement ($3,000) – The Company has 13
identified a revenue stream associated with sole-use, or 14
directly assigned, low-voltage facilities related to the 15
integration of small generation resources. The Company 16
will receive annual use-of-facilities revenue of $9,000, or 17
approximately $790 per month, from Stimson Lumber for the 18
dedicated use of low-voltage facilities in the Company’s 19
Plummer Substation. The test year revenue was $6,000. 20
Hydro Tech Systems Agreement ($3,000) – Low-voltage 21
facilities in the Company’s Greenwood Substation are 22
dedicated for use by the Meyers Falls generation project 23

Kinney, Di 24
Avista Corporation

resulting in annual use-of-facilities revenue of $6,000, or 1
$510 per month. The pro forma revenue from this agreement 2
is $6,000 while there was $3,000 in revenue collected 3
during the test year. 4
BPA Parallel Operation Agreement ($3,192,000) – The 5
Company is negotiating a Parallel Operation Agreement with 6
the Bonneville Power Administration regarding Bonneville’s 7
use of the Avista transmission system to support the 8
integration of wind in southeastern Washington. Avista and 9
Bonneville have reached tentative agreement on an ongoing 10
settlement approach where Avista may provide Bonneville 11
with up to 133 MW of parallel capacity support in return 12
for a revenue stream roughly commensurate with Bonneville’s 13
cost to upgrade its own system to provide such capacity. 14
The expected pro forma revenue associated with this 15
agreement is $3,192,000. No such revenue was collected 16
during the test year. 17
Morgan Stanley Transmission Service ($600,000) – 18
Morgan Stanley Capital Group signed a five-year 19
transmission service agreement with the Company for 25 MW 20
of long-term firm transmission capacity. The agreement 21
starts January 1, 2013, and will result in annual revenues 22

Kinney, Di 25
Avista Corporation

of $600,000. No revenue was collected from this 1
transmission agreement during the test year. 2
3
IV. TRANSMISSION AND DISTRIBUTION CAPITAL PROJECTS 4
Q. Please describe the Company’s capital 5
transmission projects that will be completed in 2012? 6
A. Avista continuously needs to invest in its 7
transmission system to maintain reliable customer service 8
and meet mandatory reliability standards. The 2012 and 9
2013 capital transmission projects are being planned and 10
constructed to meet either compliance requirements, improve 11
system reliability, fix broken equipment, or replace aging 12
equipment that is anticipated to fail. 13
Included in the compliance requirements are the North 14
American Electric Reliability Corporation (NERC) standards, 15
which are national standards that utilities must meet to 16
ensure interconnected system reliability. Beginning June 17
2007, compliance with these standards was made mandatory 18
and failure to meet the requirements could result in 19
monetary penalties of up to $1 million per day per 20
infraction. The majority of the reliability standards 21
pertain to transmission planning, operation, and equipment 22
maintenance. The standards require utilities to plan and 23

Kinney, Di 26
Avista Corporation

operate their transmission systems in such a way as to 1
avoid the loss of customers or impact to neighboring 2
utility systems due to the loss of transmission facilities. 3
The transmission system must be designed so that the loss 4
of up to two facilities simultaneously will not impact the 5
interconnected transmission system. These requirements 6
drive the need for Avista to continually invest in its 7
transmission system. Avista is required to perform system 8
planning studies in both the near term (1-5 years) and long 9
term (5-10 years). If a potential violation is observed in 10
the future years, then Avista must develop a project plan 11
to ensure that the violation is fixed prior to it becoming 12
a real-time operating issue. Avista develops future 13
project plans to ensure that the design and construction of 14
the required projects are completed prior to the time they 15
are actually needed. Avista will continue to have a need 16
to develop these compliance-related projects as system load 17
grows, new generation is interconnected, and the system 18
functionality and usage changes. 19
Avista capital transmission project requirements are 20
developed through system planning studies, engineering 21
analysis, or scheduled upgrades or replacements. The 22
larger specific projects that are developed through the 23

Kinney, Di 27
Avista Corporation

system planning study process typically go through a 1
thorough internal review process that includes multiple 2
stakeholder review to ensure all system needs are 3
adequately addressed. For the smaller specific projects, 4
Avista doesn’t perform a traditional cost-benefit analysis. 5
Projects are selected to meet specific system needs or 6
equipment replacement. However, both project cost and 7
system benefits are considered in the selection of final 8
projects. 9
Q. Did the Company consider any efficiency gains or 10
offsets when evaluating the transmission projects to 11
include in the Company’s case? 12
A. Yes. The Company evaluated each project and 13
determined that some of the 2012 and 2013 capital 14
transmission projects will result in efficiency gains and 15
potential offsets or savings, and the Company has included 16
those where applicable. The primary offsets result in loss 17
savings from reconductoring heavily-loaded transmission or 18
distribution facilities. For these projects, an analysis 19
was performed to determine the savings. The assumed 20
avoided energy cost to determine the savings was $31.50 21
MWh, which is the average purchase and sale price 22
appropriate for the rate period calculation of offsets. 23

Kinney, Di 28
Avista Corporation

However, not all projects will result in loss savings or 1
other offsets. Avista has maintenance schedules for 2
certain equipment. These maintenance cycles range from 5-3
15 years depending on the equipment. Unless the 4
replacement of equipment occurs in the same year as the 5
scheduled maintenance, there will not be any savings. 6
Although one might think that the replacement of 7
equipment may reduce the failure rate of equipment and 8
reduce after-hours labor costs, newly-installed equipment 9
can get out of alignment, or require other adjustments. 10
Significant system failures also occur during large 11
weather-related events caused by wind, lightning, and snow. 12
Furthermore, each year as we replace old equipment with 13
new, the remainder of our system gets another year older, 14
which continues to generate a similar level of failures on 15
our system. At the current funding levels, the Company’s 16
Asset Management program is designed to keep failure rates 17
at current levels. 18
Q. Please describe each of the transmission projects 19
planned for in 2012. 20
A. The major capital transmission costs (system) for 21
projects to be completed in 2012 are $28.160 million and 22
are shown in Table 3 and described below. 23

Kinney, Di 29
Avista Corporation

Pro Forma
(System)
O&M
Offsets
(System)
Reliability Compliance
Spokane/CDA Relay Upgrade $900,000
SCADA Replacement $1,310,000
System Replace/Install Capacitor Bank $2,000,000
Bronx-Cabinet 115 kV Rebuild/Reconductor $2,500,000 $3,203
Power Transformers - Transmission $952,000
Total Reliability Compliance $7,662,000 $3,203
Contractual Requirements
Thornton 230 kV Switching Station $4,350,000
Colstrip Transmission $410,000
Tribal Permits $325,000
Total Contractual Requirements $5,085,000 $0
Reliability Improvements
Moscow City-N Lewiston 115 kV Reconductor $2,500,000
Burke-Thompson A&B 115 kV Reconductor $2,500,000
Millwood 115 kV Substation Rebuild $2,000,000
Noxon-Hot Springs 230 kV Line Re-Route $500,000
Total Reliability Improvements $7,500,000 $0
Reliability Replacement
Transmission Minor Rebuilds $2,370,000
Power Circuit Breakers $1,200,000
Hatwai 230 kV Breaker Replacement $614,000
Asset Management Replacement $3,479,000
Other Small Projects $250,000
Total Reliability Replacement $7,913,000 $0
Total Transmission Projects $28,160,000 $3,203
Transmission
2012 Capital - Compliance, Contractual, and Replacement Projects
TABLE 3
1 2
3
Reliability Compliance Projects ($7.662 million): 4
5
Spokane/Coeur d'Alene area relay upgrade ($0.900 6
million): This project involves the replacement of 7
older protective 115 kV system relays with new micro-8
processor relays to increase system reliability by 9

Kinney, Di 30
Avista Corporation

reducing the amount of time it takes to sense a system 1
disturbance and isolate it from the system. This is a 2
five to seven year project and is required to maintain 3
compliance with mandatory reliability standards. This 4
project is required to meet Reliability Compliance 5
under NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-6
R3, TPL-003-0a R1-R3. Positive offsets in reduced 7
maintenance costs associated with this replacement 8
effort are negatively offset by increased NERC testing 9
requirements per standard PRC-005-1. 10
11
SCADA Replacement ($1.310 million): The System Control 12
and Data Acquisition (SCADA) system is used by the 13
system operators to monitor and control the Avista 14
transmission system. An upgrade to the SCADA system 15
to a new version provided by our SCADA vendor was 16
completed in the first quarter of 2012. The previous 17
application version was no longer supported by the 18
vendor. The upgrade ensures Avista has adequate 19
control and monitoring of its Transmission facilities. 20
This portion of the project is required to meet 21
Reliability Compliance under NERC Standards: TOP-001-22
1, TOP-002-2a R5-R10, R16, TOP-005-2 R2, TOP-006-2 R1-23
R7. Several Remote Terminal Units (RTUs) located at 24
substations throughout Avista’s service territory will 25
also be replaced due to age. The RTUs are part of the 26
transmission control system. There are no offsets or 27
savings associated with this upgrade project because 28
the Company already pays the application vendor a set 29
annual maintenance fee for support. 30
31
System Replace/Install Capacitor Bank ($2.00 million): 32
This effort includes two projects. The first project 33
is the replacement of the 115 kV capacitor bank at the 34
Pine Creek 115 kV substations to support local area 35
voltages during system outages. The second project is 36
the addition of new shunt capacitors at Lind 115 kV 37
substation to support system voltages during summer 38
irrigation load conditions and system outages. These 39
projects are required to meet reliability compliance 40
with NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-41
R3, TPL-003-0a R1-R3, and provide improved service to 42
customers. The Lind project is scheduled to be 43
completed in September of 2012 and the Pine Creek 44
project is scheduled to be completed in the late fall 45
of 2012. There are no loss savings or other offsets 46

Kinney, Di 31
Avista Corporation

associated with these projects. The projects improve 1
voltage support but don’t reduce loss savings. 2
3
Bronx – Cabinet 115 kV rebuild/reconductor ($2.500 4
million): In 2010 Avista’s System Operations 5
identified a thermal constraint on the 32-mile Bronx-6
Cabinet 115kV Transmission Line. This constraint was 7
confirmed by the System Planning Group, and documented 8
in the Transmission Line Design (TLD) Design Scoping 9
Document (DSD) created on January 4, 2011, and 10
modified on January 7, 2011. The 11
reconductoring/rebuilding of this line with 795 kcmil 12
ACSS conductor will provide a present-day 143 MVA line 13
rating to match the Cabinet Switchyard Transformer, 14
and a future 200 MVA line rating to match the parallel 15
path Bonneville Power Authority (BPA) system. The 32 16
miles of line will be reconductored over a four year 17
period, which began in 2011. Phase 2 of the project 18
(addressed here) consists of the approximately 10-mile 19
stretch between Hope, ID and Clarkfork Sub. The line 20
upgrade will ensure compliance with requirements 21
associated with NERC Standards: TOP-004-2 R1-R4, TPL-22
002-0a R1-R3, TPL-003-0a R1-R3. Using 2010 actual 23
loads, since the line was operated open in over half 24
of 2011 for the first phase of the project, the new 25
conductor will reduce line losses by 1220 MWh on an 26
annual basis. This project will not be completed 27
until December so offset savings of $38,430 will be 28
observed in 2012 (based on a $31.50/MWh avoided energy 29
cost). 30
31
Power Transformers – Transmission ($0.952 million): 32
The Moscow 230kV substation is currently being 33
rebuilt. Construction started in 2011 and will 34
continue through 2013. The rebuild includes the 35
addition of a new 250 MVA 230/115 kV autotransformer. 36
This autotransformer arrived on-site in late 2011 and 37
was capitalized upon delivery per the company’s 38
accounting practices. The transformer was paid for in 39
several installments. This $952,000 was the final 40
installment (paid in 2012), which was paid after 41
receiving warranty approval from the manufacturer to 42
energize the autotransformer. This project is 43
required to meet Reliability Compliance under NERC 44
Planning and Operations Standards: TOP-004-2 R1-R4, 45
TPL-002-0a R1-R3, TPL-003-0a R1-R3. Offsets for this 46

Kinney, Di 32
Avista Corporation

project will not occur until the Moscow 230 kV 1
Substation is complete in 2013, and therefore have 2
been included in the 2013 project described later in 3
my testimony. 4
5
Contractual Requirements ($5.085 million): 6
7
Thornton 230 kV switching Station ($4.350 million): 8
The Thornton 230kV Substation Project interconnects a 9
Third Party Wind Farm Generation Project owned and 10
operated by Palouse Wind to Avista’s Benewah - Shawnee 11
230kV Transmission Line. The project includes the 12
construction of the switching station and associated 13
line work to connect the new station to Avista’s 14
existing 230 kV line. Palouse Wind will construct and 15
pay for facilities to connect its Generation 16
Collection Station to Thornton. Thornton is required 17
to maintain Avista’s 230 kV transmission service with 18
or without the wind generation, so Avista’s customers 19
are not affected by any outages as a result of the 20
interconnection. One third of the substation costs 21
(not included here) will be paid for upfront by 22
Palouse Wind as direct assigned facilities according 23
to FERC Open Access Transmission Tariff requirements. 24
There are no offsets with the construction of the new 25
substation. 26
27
Colstrip Transmission ($0.410 million): As a joint 28
owner of the Colstrip Transmission projects, Avista 29
pays its ownership share of all capital improvements. 30
Northwestern Energy either performs or contracts out 31
the capital work associated with the joint owned 32
facilities. 33
34
Tribal Permits ($0.325 million): The Company has 35
approximately 300 right-of-way permits on tribal 36
reservations that need to be renewed. The costs 37
include labor, appraisals, field work, legal review, 38
GIS information, negotiations, survey (as needed), and 39
the actual fee for the permit. 40
41
Reliability Improvements ($7.500 million): 42
43
Moscow City-North Lewiston 115 kV Transmission Rebuild 44
($2.500 million): This project includes the 45

Kinney, Di 33
Avista Corporation

reconductor/rebuild of the 22-mile line between Moscow 1
City substation and North Lewiston due to the poor 2
condition of the existing line. The project will be 3
completed in three phases. The first phase in 2012 4
includes reconductoring the first seven miles out of 5
Moscow City towards Leon Junction. The Moscow City-6
North Lewiston 115 kV line is normally operated in a 7
radial configuration open at Moscow City to avoid the 8
line being overloaded for area outages. If the line 9
section between North Lewiston and Leon Junction is 10
lost (normal source), then the breaker is closed at 11
Moscow City to pick up load at Leon Junction. Since 12
the 7 mile line section being rebuilt is normally not 13
carrying load, there are no offsets associated with 14
this project. 15
16
Burke-Thompson A&B 115 kV Transmission Rebuild ($2.500 17
million): The Burke-Thompson falls 115 kV lines are 18
jointly owned by Avista and Northwestern Energy. 19
Avista owns and operates the 4-mile line section from 20
Burke to the Montana border on both the A&B lines. 21
These lines are part of the Montana to Northwest 22
transmission path that moves generation from Montana 23
to load centers in both Eastern and Western Washington 24
and also serves mining load and residential customers 25
in the Silver Valley area of Idaho. The current lines 26
are in poor condition and are a significant safety 27
concern. In the winter, the snow levels get high 28
enough to reduce conductor clearance so the lines have 29
to be removed from service to ensure safety. This 30
project will rebuild both the A&B lines to improve 31
reliability and eliminate the need to open the lines 32
during the winter. The projects will reuse the 33
existing conductor so there will be no loss savings or 34
offsets associated with the rebuild. 35
36
Millwood Sub Rebuild ($2.00 million): In 2012 the 37
Company will begin to rebuild the existing 115 kV 38
Millwood substation. Millwood serves local area 39
Avista customers and Inland Empire Paper Company one 40
of Avista’s largest industrial customers. The current 41
substation is old, approaching full capacity, and 42
contains a significant amount of PCBs that are an 43
environmental concern. Most of this project is 44
considered a distribution effort, but the 115 kV lines 45
that feed the substation need to be reconfigured to 46

Kinney, Di 34
Avista Corporation

support the substation rebuild effort. The costs 1
included here are associated with the 115 kV line 2
reconfigurations. The existing conductor will be 3
reused so there are no offsets associated with this 4
project. 5
6
Noxon-Hot Springs #2 230 kV reroute ($0.500 million): 7
The Noxon-Hot Springs project is being driven by 8
environmental issues that are impacting the 9
reliability of the lines. Several h-frame structures 10
are being undercut due to the meandering of Beaver 11
Creek. The Company had hoped to reroute the line by 12
moving all impacted structures away from the creek. 13
However, the property owners didn’t support the new 14
line route, so instead existing structures are being 15
replaced with hybrid poles (concrete bottoms and steel 16
tops) to eliminate the creeks impact on the poles. 17
The new poles are being buried up to 25 feet to 18
accommodate scouring. The project will reuse existing 19
conductor so there are no offsets. 20
21
22
Reliability Replacements ($7.913 million) 23
24
Transmission Minor Rebuilds ($2.370 million): These 25
projects include minor transmission rebuilds as a 26
result of age or damage caused by storms, wind, fire, 27
and the public. These projects are required to operate 28
the transmission system safely and reliably. The 29
facilities will need to be replaced when damaged in 30
order to maintain customer load service. In 2011 the 31
Company spent $2.465 million on these minor rebuild 32
projects as a result of damage caused by weather or 33
the public through vandalism or accident. No offsets 34
are expected for these projects. Power Circuit 35
Breakers ($1.200 million): The Company transfers all 36
circuit breakers to plant upon receiving them. The 37
breakers purchased in 2012 are planned for 38
installation at Moscow 230 and Lind 115 kV 39
substations. 40
41
Hatwai Breaker and switch replacement ($0.614 42
million): Avista currently owns the breaker terminal 43
at BPA’s Hatwai substation associated with the Hatwai-44
North Lewiston 230 kV line. The Breaker and switches 45

Kinney, Di 35
Avista Corporation

need to be replaced due to age. Avista has contracted 1
with BPA to replace the breaker and three air switches 2
in 2012 since BPA owns and operates the Hatwai 3
substation. 4
5
Asset Management Replacement Programs ($3.479 6
million): Avista has several different equipment 7
replacement programs to improve reliability by 8
replacing aged equipment that is beyond its useful 9
life. These programs include transmission air switch 10
upgrades, arrestor upgrades, restoration of substation 11
rock and fencing, recloser replacements, replacement 12
of obsolete circuit switchers, substation battery 13
replacement, interchange meter replacements, high 14
voltage fuse upgrades, and voltage regulator 15
replacements. All of these individual projects 16
improve system reliability and customer service. The 17
equipment is replaced when useful life has been 18
exceeded. The equipment under these replacement 19
programs are usually not maintained on a set schedule 20
so there aren’t any associated offsets. 21
22
23
Other Small Transmission Projects ($.250 million): 24
These maninly consist of reinforcement, rebuild, 25
reconductoring and re-insulating projects. 26
27
28
Q. Please describe each of the distribution projects 29
planned for in 2012. 30
A. The Company will spend approximately $65.123 31
million in Distribution projects at a system level, with 32
$16.364 million specific to Idaho in 2012. A summary of 33
the projects is shown in Table 4 and a brief description of 34
each project impacting Idaho are given below. 35

Kinney, Di 36
Avista Corporation

Pro Forma
(System)
Pro Forma
(Idaho)
O&M
Offsets
Idaho

Distribution Projects
Wood Pole Management $13,025,000 $3,576,000 $5,600
PCB Related Distribution Rebuilds $3,812,000 $2,057,000
System Dist Reliability Improve Worst
Feeders $1,950,000 $722,000
Power Transformers - Distribution $1,450,000 $492,000
Distribution - Pullman & Lewis Clark -
ID $650,000 $650,000
Distribution - Cda East & North - ID $855,000 $855,000
10 & Stewart Dx Int - ID $250,000 $250,000
Total Distribution Projects $21,992,000 $8,602,000 $5,600

Distribution Replacement Projects
Elect Distribution Minor Blanket $8,300,000 $3,235,000
Failed Electric Plant $2,200,000 $1,014,000
Distribution Line Relocation $1,900,000 $692,000
Electric Underground Replacement $1,792,000 $441,000 $25,000
Blue Creek 115 kV Rebuild - ID $1,905,000 $1,905,000
Other Small Projects $887,000 $475,000
Total Distribution Replacement Projects $16,984,000 $7,762,000 $25,000
Washington Distribution Projects
(not included in case)
System Efficiency Feeder Rebuilds $7,371,000 $0
Distribution Spokane North and West $1,910,000 $0
Millwood Sub Rebuild $1,000,000 $0
Pullman (Turner) Substation Rebuild $609,000 $0
Metro Feeder Upgrade $502,000 $0
Wood Substation Rebuild – Orin $300,000 $0
Spokane Electric Network Increase
Capacity $1,650,000 $0
Spokane Smart Circuit $5,400,000 $0
Pullman Smart Grid Demonstration Project $6,300,000 $0
Smart Grid Workforce Program $1,105,000 $0
Total Washington Distribution Projects $26,147,000 $0 $0
Total Distribution Projects $65,123,000 $16,364,000 $30,600
Distribution
2012 Capital - Distribution Projects
TABLE 4
1 2
System distribution projects (including 3
transformation) for 2012 total $21.992 million ($8.602 4

Kinney, Di 37
Avista Corporation

million Idaho Share). These projects are necessary to meet 1
capacity needs of the system, improve reliability, and 2
rebuild aging distribution substations and feeders. The 3
following projects make up the $8.602 million. 4
Wood Pole Management ($13.025 million system / $3.576 5
million Idaho): The distribution wood pole management 6
program evaluates wood pole strength of a certain 7
percentage of the wood pole population each year such 8
that the entire system is inspected every 20 years. 9
Avista has over 240,000 distribution wood poles and 10
33,000 transmission wood poles in its electric system. 11
Depending on the test results for a given pole, the 12
pole is either considered satisfactory, needing to be 13
reinforced with a steel stub, or needing to be 14
replaced. As feeders are inspected as part of the 15
wood pole management program, issues are identified 16
unrelated to the condition of the pole. This project 17
also funds the work required to resolve those issues 18
(i.e. potentially leaking transformers, transformers 19
containing more than or equal to 1 ppm polychlorinated 20
biphenyls (PCBs), failed arrestors, missing grounds, 21
damaged cutouts, and dated high resistance conductor). 22
Transformers older than 1981 have the potential to 23
have oil that contains polychlorinated biphenyls 24
(PCBs). These older transformers present increased 25
risk because of the potential to leak oil that 26
contains PCBs. Poles installed prior to World War II 27
have reached the end of their useful life. Avista’s 28
Wood Pole Management program was put into place to 29
prevent the Pole-Rotten events and Crossarm – Rotten 30
events from increasing. The company expects to 31
achieve $5,600 in savings resulting from reduced call 32
outs to fix problems during 2012. The Company spent 33
$15.961 million (system) on these efforts in 2011. 34
35
36
PCB Related Distribution Rebuilds ($3.812 million 37
system / $2.057 million Idaho): In 2011, Avista 38
initiated a systematic replacement of distribution 39
line transformers because their oil contains PCBs. In 40
addition, replacement of the "pre-1981" transformers 41
has benefits of improving the energy efficiency and 42

Kinney, Di 38
Avista Corporation

long-term reliability of the distribution system. 1
2012 represents year-two of a six year effort to 2
replace these distribution transformers. In 2012, the 3
program is expected to replace approximately 750 line 4
transformers in Idaho. The replacement work is 5
scheduled to be completed throughout the entire year. 6
Offsets associated with this project in have not been 7
included in this case2. 8
9
System Distribution Reliability Improve Worst Feeders 10
($1.950 million system / $0.722 million Idaho): Based 11
on a combination of reliability statistics, including 12
CAIDI, SAIFI, and CEMI (Customers Experiencing 13
Multiple Interruptions), feeders have been selected 14
for reliability improvement work. This work is 15
expected to improve the reliability of these electric 16
primary feeders. This is an annually recurring program 17
initiated in 2008 to address underperforming feeders 18
on the electric distribution system. This work will 19
improve the reliability of these feeders and overall 20
service to customers in these areas. The projects 21
were selected based on poor reliability performance 22
not on cost savings. The treatment of feeder 23
projects varies from conversion of overhead to 24
underground facilities, installing additional mid-line 25
protective devices, to hardening of existing 26
facilities. 27
28
29
Power Transformer Distribution ($1.450 million system / 30
$0.492 million Idaho): Transformers are transferred to 31
plant upon receiving them. These transformers are being 32
purchased to replace existing spares that will be 33
installed in 2012 as either replacements or new 34
installations. The purchased transformers will either 35
remain as system spares or placed into service as part of 36
the proposed 2013 projects. Offsets associated with this 37
project have not been included in this case2. 38
39
Distribution – Pullman & Lewis Clark ($.650 million 40
Idaho): System analysis of the distribution grid 41
indicate a number of capacity constraints and 42
locations where “switch ties” are needed to allow for 43

2 Offsets for this project have been calculated and the Company will
update these at a later date.

Kinney, Di 39
Avista Corporation

alternate service to customers in the case of planned 1
or forced outages. In many cases, main trunk feeder 2
conductor is replaced with higher capacity wire which 3
reduces overall system losses, supports uniform 4
voltage, and provides for capacity when reconfiguring 5
the system during planned or forced outages. 6
7
Distribution – CDA East & North ($.855 million Idaho): 8
System analysis of the distribution grid indicate a 9
number of capacity constraints and locations where 10
“switch ties” are needed to allow for alternate 11
service to customers in the case of planned or forced 12
outages. In many cases, main trunk feeder conductor 13
is replaced with higher capacity wire which reduces 14
overall system losses, supports uniform voltage, and 15
provides for capacity when reconfiguring the system 16
during planned or forced outages. 17
18
10th & Stewart Dx Int ($.250 million Idaho): This 19
project involves increasing 115/13 kV transformation 20
capacity at an existing substation in Lewiston, Idaho. 21
This substation serves the Lewiston “Orchards” region 22
including the newly developed commercial zone near 20th 23
Avenue. Load demand requires additional distribution 24
capacity. 25
26
The Company also will spend approximately $16.984 27
million (system) or $7.762 million (Idaho share) in 28
Distribution equipment replacements and minor rebuilds 29
associated with aging distribution equipment, underground 30
cable with poor reliability performance, replacements from 31
storm damage, or relocation of feeder sections resulting 32
from road moves. A brief description of the projects 33
included in these replacement efforts is given below. 34
35
Electric Distribution Minor Blanket Projects ($8.300 36
million system / $3.235 million Idaho): This effort 37

Kinney, Di 40
Avista Corporation

includes the replacement of poles and cross-arms on 1
distribution lines in 2012 as required, due to storm 2
damage, wind, fires, or obsolescence. The Company 3
spent $8.270 million in 2011 for these projects. No 4
offsets are expected for these projects. 5
6
Failed Electric Plant ($2.200 million system / $1.014 7
million Idaho): Replacement of distribution 8
equipment throughout the year as required due to 9
equipment failure. The Company spent $1.384 million in 10
2011. The Company must replace the equipment to 11
maintain customer load service. No offsets are 12
expected from these projects. 13
14
Distribution Line Relocation ($1.900 million system / 15
$0.692 million Idaho): The relocation of 16
distribution lines as required due to road moves 17
requested by State, County or City governments. The 18
Company spent $2.061 million (system) in 2011 on line 19
relocations associated with road moves. No offsets or 20
savings are expected for these projects. 21
22
Electric Underground Replacement ($1.792 million 23
system / $0.441 million Idaho): This effort involves 24
replacing the first generation of Underground 25
Residential District (URD) cable. This project has 26
been ongoing for the past several years and will be 27
completed in 2012. This program focuses on replacing 28
a vintage and type of cable that has reached its end 29
of life and contributes significantly to URD cable 30
failures. The Company spent $3.887 million (system) 31
in 2011. The company anticipates that it will see 32
approximately $82,000 (system) or $25,000 (in Idaho) 33
in incremental savings as a result of reduced cable 34
failures. This is being included as an offset for the 35
Electric Underground Replacement project. 36
37
Blue Creek 115kV Rebuild ($1.905 million Idaho): The 38
Blue Creek 115-13 kV Substation, just east of Coeur 39
d’Alene, needs to be rebuilt adjacent to the existing 40
substation to accommodate new equipment, including a 41
new control house, 115 kV bus and switches, and 42
upgraded SCADA indication and control. The primary 43
driver for this project is the need to replace the 44
substation transformer, which would require excessive 45

Kinney, Di 41
Avista Corporation

work in the existing station due to its design. An 1
additional feeder will also be added for distribution 2
system reliability and operational flexibility as well 3
as future load service capability. 4
5
Other Small Projects ($ 0.887 million system / $0.475 6
million Idaho): These mainly consist of capacity 7
increases and minor replacements of equipment. 8
9
Q. Please describe the Company’s capital 10
transmission projects that will be completed in 2013? 11
A. The major capital transmission costs (system) for 12
projects to be completed in 2013 are approximately $34.975 13
million and are shown in Table 5 and described below. 14

Kinney, Di 42
Avista Corporation

Pro Forma
(System)
O&M
Offsets
(System)
Reliability Compliance
Spokane/CDA Relay Upgrade $1,450,000
SCADA Replacement $450,000
System Replace/Install Capacitor Bank $1,050,000
Moscow 230 kV Substation Rebuild $8,090,000 $3,780
Bronx-Cabinet 115 kV Rebuild/Reconductor $2,500,000 $1,980
Power Transformers - Transmission $2,065,000
Irvin 115kV Switching Station $1,150,000
Opportunity 115 kV Switching Station $1,550,000
Opportunity 12F2 $400,000
Total Reliability Compliance $18,705,000 $5,760
Contractual Requirements
Lancaster 230 kV Interconnection $4,600,000
Colstrip Transmission $463,000
Tribal Permits $332,000
Total Contractual Requirements $5,395,000 $0
Reliability Improvements
Moscow City-N Lewiston 115 kV Reconductor $2,450,000
Burke-Thompson A&B 115 kV Reconductor $2,500,000 $660
Total Reliability Improvements $4,950,000 $660
Reliability Replacement
Transmission Minor Rebuilds $2,200,000
Power Circuit Breakers $1,200,000
Hatwai 230 kV Breaker Replacement $215,000
Asset Management Replacement $2,310,000
Total Reliability Replacement $5,925,000 $0
Total Transmission Projects $34,975,000 $6,420
Transmission
2013 Capital - Compliance, Contractual, and Replacement Projects
TABLE 5
1
2
Reliability Compliance Projects ($18.705 million): 3
4
Spokane/Coeur d'Alene area relay upgrade ($1.450 5
million): This project involves the replacement of 6
older protective 115 kV system relays with new micro-7
processor relays to increase system reliability by 8
reducing the amount of time it takes to sense a system 9

Kinney, Di 43
Avista Corporation

disturbance and isolate it from the system. This is a 1
five to seven year project and is required to maintain 2
compliance with mandatory reliability standards. This 3
project is required to meet Reliability Compliance 4
under NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-5
R3, TPL-003-0a R1-R3. Positive offsets in reduced 6
maintenance costs associated with this replacement 7
effort are negatively offset by increased NERC testing 8
requirements per standard PRC-005-1. 9
10
SCADA Replacement ($0.450 million): The System Control 11
and Data Acquisition (SCADA) system is used by the 12
system operators to monitor and control the Avista 13
transmission system. The SCADA system requires annual 14
enhancements to improve performance, replace computer 15
systems and networks, and integrate vendor provided 16
improvements. This portion of the project is required 17
to meet Reliability Compliance under NERC Standards: 18
TOP-001-1, TOP-002-2a R5-R10, R16, TOP-005-2 R2, TOP-19
006-2 R1-R7. Several Remote Terminal Units (RTUs) 20
located at substations throughout Avista’s service 21
territory will also be replaced due to age. The RTUs 22
are part of the transmission control system. There 23
are no offsets or savings associated with this upgrade 24
project because the Company already pays the 25
application vendor a set annual maintenance fee for 26
support. 27
28
System Replace/Install Capacitor Bank ($1.050 29
million): This effort includes the replacement of the 30
115 kV capacitor bank at the Odessa 115 kV substations 31
to support local area voltages during system outages 32
and summer irrigation load conditions. This project is 33
required to meet reliability compliance with NERC 34
Standards: TOP-004-2 R1-R4, TPL-002-0a R1-R3, TPL-003-35
0a R1-R3, and provide improved service to customers. 36
The Odessa project is scheduled to be completed by 37
June 2013. There are no loss savings or other offsets 38
associated with these projects. The project improves 39
voltage support but doesn’t reduce loss savings. 40
41
Moscow 230 kV Sub - Rebuild 230 kV Yard ($8.090 42
million): This project involves the rebuild of the 43
existing Moscow 230 kV substation. The substation 44
rebuild includes the replacement of the existing 125 45

Kinney, Di 44
Avista Corporation

MVA 230/115 kV autotransformer with a new 250 MVA 1
autotransformer to meet compliance with NERC standards 2
and ensure adequate load service. Currently the 3
existing 230/115 kV autotransformer overloads for an 4
outage of another autotransformer in the area during 5
peak load conditions. The 230 kV portion of the 6
substation will be constructed as a double breaker 7
double bus configuration to maximize reliability and 8
operational flexibility. The substation will be 9
constructed over a three-year period with energization 10
of the substation occurring in November of 2013. This 11
project is required to meet Reliability Compliance 12
under NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-13
R3, TPL-003-0a R1-R3. Loss savings calculations 14
indicate that the new transformer installation will 15
result in an offset of $3,780 in the pro forma period 16
(based on a $31.50/MWh avoided energy cost and an 17
energization date of November, 2013). 18
19
Bronx – Cabinet 115 kV rebuild/reconductor ($2.500 20
million): In 2010 Avista’s System Operations 21
identified a thermal constraint on the 32-mile Bronx-22
Cabinet 115kV Transmission Line. This constraint was 23
confirmed by the System Planning Group, and documented 24
in the Transmission Line Design (TLD) Design Scoping 25
Document (DSD) created on January 4, 2011, and 26
modified on January 7,2011. The 27
reconductoring/rebuilding of this line with 795 kcmil 28
ACSS conductor will provide a present-day 143 MVA line 29
rating to match the Cabinet Switchyard Transformer, 30
and a future 200 MVA line rating to match the parallel 31
path Bonneville Power Authority (BPA) system. The 32 32
miles of line will be reconductored over a four year 33
period, which began in 2011. Phase 3 of the project 34
(addressed here) consists of reconductoring an 8-mile 35
section of the line. The line upgrade will ensure 36
compliance with requirements associated with NERC 37
Standards: TOP-004-2 R1-R4, TPL-002-0a R1-R3, TPL-003-38
0a R1-R3. Using 2010 actual loads, since the line was 39
operated open in over half of 2011 for construction of 40
the first phase of the project, the new conductor will 41
reduce line losses by 755 MWh on an annual basis. 42
This project will not be completed until December 2013 43
so the offset savings of $1,980 will be observed in 44
2013 (based on a $31.50/MWh avoided energy cost). 45
46

Kinney, Di 45
Avista Corporation

Power Transformers – Transmission ($2.065 million): 1
The Company will be rebuilding several 230 kV 2
substations over the next 5 years. One of these 3
stations is Westside in western Spokane and involves 4
the replacement of two 230/115 kV autotransformers. 5
The autotransformer purchased in 2013 may be part of 6
the Westside project or included as a system spare. 7
The transformer will be capitalized upon delivery per 8
the Company’s accounting practices. The Westside 9
project is required to meet Reliability Compliance 10
under NERC Planning and Operations Standards: TOP-004-11
2 R1-R4, TPL-002-0a R1-R3, TPL-003-0a R1-R3. Offsets 12
for this project will not occur until the 13
autotransformer is actually placed into service. 14
15
Irvin 115 kV Switching Station ($1.150 million): A 16
new 115 kV Switching Station will be constructed in 17
the Spokane Valley to reinforce the transmission 18
system. The Irvin 115kV Switching Station is the 19
initial project in a series of projects intended to 20
improve reliability of the 115kV transmission system 21
and accompanying load service in the Spokane Valley. 22
In 2013, $1,150,000 is scheduled to be spent for the 23
construction of a new transmission line from the 24
future Irvin station site to the existing Millwood 25
Substation. Work will also be performed to relocate 26
existing structures in and around the Irvin site to 27
accommodate its integration. Since this is a new 28
transmission line, no offsets will be observed. 29
30
Opportunity 115 kV Switching Station ($1.550 million): 31
This project involves adding three 115 kV breakers to 32
the existing Opportunity substation. The project is 33
part of a group of projects to support the reliability 34
of the 115kV transmission system and accompanying load 35
service in the Spokane Valley. The completion of the 36
Opportunity switching station will allow for the 37
connection of a 115 kV line from the new Irvin 38
Substation as well as future construction of the 39
Greenacres substation in 2014. This upgrade will 40
ensure compliance with requirements associated with 41
NERC Standards: TOP-004-2 R1-R4, TPL-002-0a R1-R3, 42
TPL-003-0a R1-R3. 43
44

Kinney, Di 46
Avista Corporation

Opportunity 12F2 ($0.400 million): In order to support 1
the reliability of the Spokane Valley, a 115 kV 2
transmission line needs to be added from the new 3
Opportunity switching station to the new Irvin 115 kV 4
switching substation. This project involves the 5
under-build of a feeder on a 115 kV transmission line. 6
The 115 kV line currently operates at Distribution 7
voltage but will be reenergized at 115 kV with the 8
completion of the feeder under-build. This will 9
require the addition of a 115 kV line to the existing 10
Opportunity 12F2 feeder poles. The transmission line 11
upgrade will ensure compliance with requirements 12
associated with NERC Standards: TOP-004-2 R1-R4, TPL-13
002-0a R1-R3, TPL-003-0a R1-R3. 14
15
Contractual Requirements ($5.395 million): 16
17
Lancaster 230 kV Interconnection ($4.600 million): 18
Avista plans to interconnect to BPA’s existing 230 kV 19
Lancaster substation by looping in its Boulder-20
Rathdrum 230 kV line. The interconnection improves 21
the load service and system reliability in the Coeur 22
d’Alene and Rathdrum Prairie areas of Avista’s service 23
territory. The interconnection also reduces the 24
loading on the heavily loaded Beacon-Bell transmission 25
lines that serve the Spokane area. The interconnection 26
will provide direct transmission access to output of 27
the Lancaster natural gas combined cycle plant. BPA 28
will perform the upgrade work, including the addition 29
of 2 new breakers, required at Lancaster substation 30
for a cost of $4.1 million and Avista will perform the 31
necessary transmission line work to loop in its 32
Boulder Rathdrum line for a cost of $0.500 million. 33
34
Colstrip Transmission ($0.463 million): As a joint 35
owner of the Colstrip Transmission projects, Avista 36
pays its ownership share of all capital improvements. 37
Northwestern Energy either performs or contracts out 38
the capital work associated with the jointly owned 39
facilities. 40
41
Tribal Permits ($0.332 million): The Company has 42
approximately 300 right-of-way permits on tribal 43
reservations that need to be renewed. The $322,000 44
listed above relates to permit costs in 2013. The 45

Kinney, Di 47
Avista Corporation

costs include labor, appraisals, field work, legal 1
review, GIS information, negotiations, survey (as 2
needed), and the actual fee for the permit. 3
4
Reliability Improvements ($4.950 million): 5
6
Moscow City-North Lewiston 115 kV Transmission Rebuild 7
($2.450 million): This project includes the 8
reconductor/rebuild of the 22-mile line between Moscow 9
City substation and North Lewiston due to the poor 10
condition of the existing line. The project will be 11
completed in three phases. The first phase will be 12
completed in 2012 and the second phase in 2013. The 13
2013 effort includes reconductoring/rebuilding seven 14
miles of line, completing the line section between 15
Moscow city and Leon Junction. Phase 3 in 2015 will 16
complete the 8-mile line section between Leon Junction 17
and North Lewiston. The Moscow City-North Lewiston 18
115 kV line is normally operated in a radial 19
configuration open at Moscow City to avoid the line 20
being overloaded for area outages. If the line 21
section between North Lewiston and Leon Junction is 22
lost then the breaker is closed at Moscow City to pick 23
up load at Leon Junction. Since the line section 24
being rebuilt is normally not carrying load, there are 25
no offsets associated with this project. 26
27
Burke-Thompson A&B 115 kV Transmission Rebuild ($2.500 28
million): This project is the second phase of the 29
Burke-Thompson A&B line rebuild effort that will begin 30
in 2012. The 5-6 miles stretch on Burke-Pine Creek #4 31
115kV Line between Wallace and Burke Substation will 32
be rebuilt. These lines are part of the Montana to 33
Northwest transmission path that moves generation from 34
Montana to load centers in both Eastern and Western 35
Washington and also serves mining load and residential 36
customers in the Silver Valley area of Idaho. The 37
current lines are in poor condition. The projects 38
will result in loss savings due to the replacement of 39
the existing conductor with a larger conductor. The 40
new conductor has less resistance resulting in savings 41
of 251 MWh for an entire year. The project is 42
scheduled to be energized in December 2013. Assuming 43
an avoided cost of $31.50/MWh total 2013 Idaho savings 44
is $660. 45
46

Kinney, Di 48
Avista Corporation

Reliability Replacements ($5.925 million) 1
2
Transmission Minor Rebuilds ($2.200 million): These 3
projects include minor transmission rebuilds as a 4
result of age or damage caused by storms, wind, fire, 5
and the public. These smaller projects are required to 6
operate the transmission system safely and reliably. 7
The facilities will need to be replaced when damaged 8
in order to maintain customer load service. In 2011 9
the Company spent $2.465 million on these minor 10
rebuild projects as a result of damage caused by 11
weather or the public. 12
13
Power Circuit Breakers ($1.200 million): The Company 14
transfers all circuit breakers to plant upon receiving 15
them. The breakers purchased in 2013 are planned for 16
installation at Irvin and Odessa substations. 17
18
Hatwai Breaker and switch replacement ($0.215 19
million): Avista currently owns the relays at BPA’s 20
Hatwai substation associated with the breaker terminal 21
of Hatwai-North Lewiston 230 kV line. The relay and 22
protection system needs to be upgraded along with the 23
breaker and switches that are planned to be replaced 24
in 2012. Avista has contracted with BPA to replace 25
the relays and protection system since BPA owns and 26
operates the Hatwai substation. 27
28
Asset Management Replacement Programs ($2.310 29
million): Avista has several different equipment 30
replacement programs to improve reliability by 31
replacing aged equipment that is beyond its useful 32
life. These programs include transmission air switch 33
upgrades, arrestor upgrades, restoration of substation 34
rock and fencing, recloser replacements, replacement 35
of obsolete circuit switchers, substation battery 36
replacement, interchange meter replacements, high 37
voltage fuse upgrades, and voltage regulator 38
replacements. All of these individual projects 39
improve system reliability and customer service. The 40
equipment is replaced when useful life has been 41
exceeded. The equipment under these replacement 42
programs are usually not maintained on a set schedule 43
so there aren’t any associated offsets. 44
45

Kinney, Di 49
Avista Corporation

Q. Please describe each of the distribution projects 1
planned for in 2013. 2
A. The Company will spend approximately $52.634 3
million in Distribution projects at a system level, with 4
$21.155 million specific to Idaho in 2013. A summary of 5
the projects is shown in Table 6 and a brief description of 6
each project impacting Idaho are given below. 7
Pro Forma
(System)
Pro Forma
(Idaho)
O&M Offsets
Idaho

Distribution Projects
Wood Pole Management $12,016,000 $3,883,000 $5,600
System Efficiency Feeder Rebuilds $8,001,000 $3,163,000 $4,980
PCB Related Distribution Rebuilds $2,925,000 $899,000 $0
Power Transformers - Distribution $2,100,000 $1,750,000Distribution - Cda East & North -
ID $500,000 $500,000Distribution - Pullman & Lewis
Clark $500,000 $500,000
System Wood Substation Rebuild $3,705,000 $3,705,000
N. Moscow Increase Capacity - ID $1,680,000 $1,680,000
Total Distribution Projects $31,427,000 $16,080,000 $10,580

Distribution Replacement Projects
Elect Distribution Minor Blanket $8,300,000 $3,235,000
Failed Electric Plant $2,250,000 $1,037,000
Distribution Line Relocation $2,200,000 $803,000Total Distribution Replacement
Projects $12,750,000 $5,075,000 $0
Washington Distribution Projects
(not included in case)
Feeder Automation Upgrades $2,501,000 $0
Distribution Spokane North and West $500,000 $0
Millwood Sub Rebuild $3,000,000 $0
Metro Feeder Upgrade $498,000 $0 Spokane Electric Network Increase
Capacity $1,763,000 $0Pullman Smart Grid Demonstration
Project $195,000 $0
Smart Grid Workforce Program $0 $0Total Washington Distribution
Projects $8,457,000 $0 $0
Total Distribution Projects $52,634,000 $21,155,000 $10,580
Distribution
2013 Capital - Distribution Projects
TABLE 6
8

Kinney, Di 50
Avista Corporation

Distribution projects related to Idaho (including 1
transformers) for 2013 total $21.155 million. These 2
projects are necessary to meet capacity needs of the 3
system, improve reliability, and rebuild aging distribution 4
substations and feeders. The following projects make up 5
the $21.155 million. 6
Wood Pole Management ($12.016 million system / $3.883 7
million Idaho): The distribution wood pole management 8
program evaluates wood pole strength of a certain 9
percentage of the wood pole population each year such 10
that the entire system is inspected every 20 years. 11
Avista has over 240,000 distribution wood poles and 12
33,000 transmission wood poles in its electric system. 13
Depending on the test results for a given pole, the 14
pole is either considered satisfactory, needing to be 15
reinforced with a steel stub, or needing to be 16
replaced. As feeders are inspected as part of the 17
wood pole management program, issues are identified 18
unrelated to the condition of the pole. This project 19
also funds the work required to resolve those issues 20
(i.e. potentially leaking transformers, transformers 21
older than 1981, failed arrestors, missing grounds, 22
damaged cutouts, and dated high resistance conductor). 23
Transformers older than 1981 have the potential to 24
have oil that contains polychlorinated biphenyls 25
(PCBs). These older transformers present increased 26
risk because of the potential to leak oil that 27
contains PCBs. Poles installed prior to World War II 28
have reached the end of their useful life. Avista’s 29
Wood Pole Management program was put into place to 30
prevent the Pole-Rotten events and Crossarm – Rotten 31
events from increasing. The Company expects to 32
achieve $5,600 in savings resulting from reduced call 33
outs to fix problems during 2013. The Company spent a 34
total $15.961 million (system) on these efforts in 35
2011. 36
37
System Efficiency Feeder Rebuild ($8.001 million 38
system / $3.163 Idaho): Beginning in 2012, Avista 39
began a program to rebuild distribution feeders to 40

Kinney, Di 51
Avista Corporation

reduce energy losses, improve operation of the feeders 1
and increase long-term reliability. The program will 2
replace poles, transformers, conductor and other 3
equipment on a rural feeder and two urban feeders in 4
2012. The work associated with this effort will be 5
completed between June and December of 2013. The 6
energy savings from reduced losses calculated using an 7
average of three months of savings is 400 MWh. This 8
equates to an offset of $12,600 system and $4,410 in 9
Idaho using an avoided cost of $31.50/MWh. 10
11
PCB Related Distribution Rebuilds ($2.925 million 12
system / $0.899 million Idaho): In 2011, Avista 13
initiated a systematic replacement of distribution 14
line transformers because their oil contains PCBs. In 15
addition, replacement of the "pre-1981" transformers 16
has benefits of improving the energy efficiency and 17
long-term reliability of the distribution system. 18
2013 represents year-three of a six year effort to 19
replace these distribution transformers. In 2013, the 20
program is expected to replace approximately 610 line 21
transformers in Idaho. The replacement work is 22
scheduled to be completed throughout the entire year. 23
There are no energy savings from reduced losses in 24
included in this case3. 25
26
27
Power Transformer Distribution ($2.100 million system 28
/ $1.750 million Idaho): Transformers are transferred 29
to plant upon receiving them. These transformers are 30
being purchased to replace existing spares that will 31
be installed in 2013 as either replacements or new 32
installations. The purchased transformers will either 33
remain as system spares or placed into service as part 34
of proposed 2014 projects. There are no offsets 35
associated with these transformers until they are 36
placed into service. 37
38
Distribution-CDA East & North ($ 0.500 million Idaho): 39
System analysis of the distribution grid indicate a 40
number of capacity constraints and locations where 41
“switch ties” are needed to allow for alternate 42
service to customers in the case of planned or forced 43

3 Offsets for this project have been calculated and the Company will
update these at a later date.

Kinney, Di 52
Avista Corporation

outages. In many cases, main trunk feeder conductor 1
is replaced with higher capacity wire which reduces 2
overall system losses, supports uniform voltage, and 3
provides for capacity when reconfiguring the system 4
during planned or forced outages. 5
6
Distribution – Pullman & Lewis Clark ($0.500 million 7
Idaho): System analysis of the distribution grid 8
indicate a number of capacity constraints and 9
locations where “switch ties” are needed to allow for 10
alternate service to customers in the case of planned 11
or forced outages. In many cases, main trunk feeder 12
conductor is replaced with higher capacity wire which 13
reduces overall system losses, supports uniform 14
voltage, and provides for capacity when reconfiguring 15
the system during planned or forced outages. 16
17
System Wood Substation Rebuild ($ 3.705 million 18
Idaho): The Big Creek 115-13 kV Substation near 19
Kellogg, ID, will be rebuilt with steel structures and 20
new equipment. The station was originally constructed 21
in 1956 and needs to be rebuilt to today’s design and 22
construction standards. In addition, the new station 23
will have only one transformer rather than the two 24
transformers it has today. 25
26
The North Lewiston 115-13 kV Substation will be 27
constructed to today’s design and construction 28
standards inside the existing North Lewiston 230-115 29
kV Substation. The new station will be constructed 30
while the existing 115-13 kV wood sub remains in 31
service. The distribution feeders will be transferred 32
to the new sub and the old sub will then be retired 33
and salvaged. The primary driver for this project is 34
the need to replace the substation transformer and the 35
age of the wood substation, which was constructed in 36
1958. 37
38
N. Moscow Increase Capacity ($1.680 million Idaho): The 39
North Moscow 115 kV Substation will have a second 40
transformer and new feeder added to the existing 41
substation to meet increasing demand in the Moscow 42
area, including the University of Idaho. This will 43
require extension of the 115 kV bus, a new control 44
house, a new 13 kV distribution structure, a 13 kV bus 45

Kinney, Di 53
Avista Corporation

tie, and upgraded SCADA indication and control. The 1
upgraded station will have greater operational 2
reliability and flexibility and will have 3
accommodations for future 13 kV distribution feeders. 4
5
6
The Company also will spend approximately $12.750 7
million (system) or $5.075 million (Idaho share) in 8
Distribution equipment replacements and minor rebuilds 9
associated with aging distribution equipment, underground 10
cable with poor reliability performance, replacements from 11
storm damage, or relocation of feeder sections resulting 12
from road moves. A brief description of the projects 13
included in these replacement efforts is given below. 14
15
Electric Distribution Minor Blanket Projects ($8.300 16
million system / $3.235 million Idaho): This effort 17
includes the replacement of poles and cross-arms on 18
distribution lines in 2013 as required, due to storm 19
damage, wind, fires, or obsolescence. The Company 20
spent $8.270 million in 2011 for these projects. No 21
offsets are expected. 22
23
Failed Electric Plant ($2.250 million system / $1.037 24
million Idaho): Replacement of distribution equipment 25
throughout the year as required due to equipment 26
failure. The Company spent $1.384 million in 2011. No 27
offsets or savings are expected for these projects. 28
The Company must replace the equipment to maintain 29
customer load service. 30
31
Distribution Line Relocation ($2.200 million system / 32
$ 0.803 million Idaho): The relocation of distribution 33
lines as required due to road moves requested by 34
State, County or City governments. The Company spent 35
$2.061 million (system) in 2011 on line relocations 36

Kinney, Di 54
Avista Corporation

associated with road moves. No offsets or savings are 1
expected these projects. 2
3
V. Vegetation Management Program 4
5
Q. Please provide an update on the Company’s 6
vegetation management program? 7
A. “Avista’s Vegetation Management Program” is still 8
striving towards an average frequency of 4 years. Work 9
performed as part of Avista’s Performance Excellence 10
Initiative suggested changes to the Company’s contracting 11
practices to increase efficiencies, allowing more work to 12
be performed on an annual basis. For 2012, a new contract 13
with provisions to transition from “time and material 14
pricing” at the beginning of the year to a unit price 15
structure by the end of the year was established. Avista 16
will be measuring the results to quantify potential value 17
and opportunities that would allow us to approach a four-18
year cycle within our current annual spending level for 19
distribution feeders of $4.1 million. Accordingly, the 20
Company has not made an adjustment for Vegetation 21
Management. 22
While the number of “Tree Fell” events in our Outage 23
Management Tool (OMT) shows a small trend upwards 24
(Illustration 1), the number of “Tree Growth” events has 25

Kinney, Di 55
Avista Corporation

declined over the past 4 years, except for a slight 1
increase in 2011. The real improvement from Vegetation 2
Management shows up in the number of outages (Illustration 3
2). The number of outages or partial outages due to “Tree 4
Fell” and “Tree Growth” events has generally decreased. 5
Illustration 1 – Number of OMT Events 6
7
Illustration 2 – Number of Outages 8
9

Kinney, Di 56
Avista Corporation

Q. Does this complete your pre-filed direct 1
testimony? 2
A. Yes it does. 3