20150601Cox Direct.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-15-05 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 ) BRYAN A. COX )

FOR AVISTA CORPORATION
(ELECTRIC ONLY)

I. INTRODUCTION 1
Q. Please state your name, employer and business 2
address. 3
A. My name is Bryan A. Cox. 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 am a 1992 graduate of Gonzaga University with 10
a degree in Mathematics and a 2009 graduate of the 11
University of Washington’s Foster School of Business with 12
a Masters Degree in Business Administration. I joined the 13
Company in 1997 and have spent 17 years in various 14
technical and leadership positions in Information 15
Technology, Natural Gas Delivery, Strategic Planning and 16
Gas and Electric Construction Services. Over the last two 17
years I have led the West Electric Operations group which 18
delivers service to most of our Washington operations as 19
well as more recently the System Operations Department. I 20
am a member of the Capital Planning Group that manages the 21
five-year Company capital budget. 22
Cox, Di Page 1 Avista Corporation

Q. What is the scope of your testimony? 1
A. My testimony presents Avista’s transmission 2
revenues and expenses for the 2016 and 2017 two-year rate 3
period. I also discuss Avista’s Transmission and 4
Distribution capital expenditures, for the period January 5
2015 through the 2017 rate year. Company witness Ms. 6
Andrews has included these adjustments in her Pro Forma 7
adjustments, which incorporates Idaho’s share of both pro 8
forma 2016 and 2017 rate year adjustments for transmission 9
revenues, expenses and capital additions described further 10
in my testimony.1 11
A table of contents for my testimony is as follows: 12
Description Page 13
I. Introduction 1 14
II. Transmission Expenses for 2016 and 2017 3 15
III. Transmission Revenue for 2016 and 2017 11 16
IV. Transmission & Distribution Capital 17 Projects 26 18
Q. Are you sponsoring an exhibit? 19
A. Yes. Exhibit No. 9, Schedule 1, provides the 20
transmission revenue and expense adjustments for 2016 and 21
2017. 22
1 Idaho’s share of the transmission revenues are also included in the Power Cost Adjustment (PCA) authorized base. See Company witness Mr. Johnson’s Exhibit No. 6, Schedule 1, for the PCA proposed net power
supply expenses included in this case.
Cox, Di Page 2 Avista Corporation

II. TRANSMISSION EXPENSES FOR 2016 AND 2017 1
Q. Please describe the adjustments to the twelve 2
months ended December 31, 2014 test year transmission 3
expenses to arrive at transmission expenses for the 2016 4
and 2017 rate years. 5
A. Adjustments were made in this filing to 6
incorporate updated information for any changes in 7
transmission expenses from the January 2014 through 8
December 2014 test year to the 2016 rate year, and for 9
incremental changes in expenses from the 2016 rate year to 10
the 2017 rate year. Each expense item described below is 11
at a system level and is included in Exhibit No. 9, 12
Schedule 1. The changes in expenses and a description of 13
each are summarized in Table No. 1, below, and an 14
explanation of each change follows the Table. 15
Cox, Di Page 3 Avista Corporation

1
2
3
4
5
6
7
8
9
10
11
(1) Represents the change in expense above or below the December 31, 2014 12 historical test year level. 13 14 (2) Represents the change in expense above or below the December 31, 2016 15 rate year level. 16
Northwest Power Pool (NWPP) (2016: $18,000; 2017: 17
$3,000) – Avista pays its share of the NWPP operating 18
costs. The NWPP serves the electric utilities in the 19
Northwest by facilitating coordinated power system 20
operations and planning, including contingency generation 21
reserve sharing, Columbia River water coordination and 22
providing support to coordinated regional transmission 23
planning. Avista’s share of the costs for 2016 is 24
$76,000, an increase of $18,000. Avista’s share of the 25
TABLE NO. 1
Transmission Expense Adjustment
(1) 2016 Rate Year (System)
(2) 2017 Rate Year (System)
Total Change in Transmission Expense $422,000 $196,000
Cox, Di Page 4 Avista Corporation

costs for 2017 is $79,000, an incremental increase of 1
$3,000 from 2016. 2
Colstrip Transmission (2016: $7,000; 2017: $-7,000) – 3
Avista is required to pay its portion of the O&M costs 4
associated with its joint ownership share of the Colstrip 5
transmission system pursuant to the Colstrip Transmission 6
Agreement. Under this agreement, NorthWestern Energy 7
(NWE) operates and maintains the Colstrip transmission 8
system. In accordance with NWE’s proposed Colstrip 9
transmission plan provided to the Company, NWE will bill 10
Avista an estimated $303,000 for Avista’s share of the 11
Colstrip O&M expense during the 2016 rate year period. 12
This is an increase of $7,000 from the actual expense of 13
$296,000 incurred during the 2014 test year. This amount 14
is expected to return to the $296,000 expense level in 15
2017, reducing expenses by $7,000 for the 2017 rate year. 16
ColumbiaGrid Funding (2016: $62,000; 2017: $5,000) – 17
Avista became a member of the ColumbiaGrid regional 18
transmission organization in 2006. ColumbiaGrid’s purpose 19
is to enhance transmission system reliability and 20
efficiency, provide cost-effective coordinated regional 21
transmission planning, develop and facilitate the 22
implementation of solutions relating to improved use and 23
expansion of the interconnected Northwest transmission 24
Cox, Di Page 5 Avista Corporation

system, and support effective market monitoring within the 1
Northwest and the entire Western interconnection. Avista 2
supports ColumbiaGrid’s general developmental and regional 3
coordination activities under the ColumbiaGrid Fourth 4
Funding Agreement, signed July 1, 2010, and supports 5
specific functional activities under the Planning and 6
Expansion Functional Agreement. Avista’s ColumbiaGrid 7
general funding expenses for the 2014 test year were 8
$126,000, while 2016 and 2017 rate year general funding 9
expenses are expected to be $188,000 and $193,000, 10
respectively. 11
ColumbiaGrid Planning and Expansion Agreement (PEFA) 12
(2016: $68,000; 2017: $5,000) – The ColumbiaGrid Planning 13
and Expansion Functional Agreement (PEFA) was accepted by 14
the Federal Energy Regulatory Commission (FERC) on April 15
3, 2007, and Avista entered into the PEFA on April 4, 16
2007. Coordinated transmission planning activities under 17
the PEFA allow the Company to meet the coordinated 18
regional transmission planning requirements set forth in 19
FERC’s Order 890 issued in February 2007, and outlined in 20
the Company’s Open Access Transmission Tariff. 21
Actual PEFA expenses for the 2014 test year were 22
$146,000. The Company’s PEFA for 2016 and 2017 are 23
$214,000 and $219,000, respectively, and reflect 24
Cox, Di Page 6 Avista Corporation

ColumbiaGrid’s increasing staffing levels to support PEFA 1
activities and the reallocation of a portion of 2
ColumbiaGrid’s administrative expenses (previously paid 3
under the general funding agreement) to these functional 4
agreements. 5
Order 1000 Functional Agreement (2016: -$50,000; 6
2017: $25,000) – FERC Order 1000 requirements are 7
implemented under the Order 1000 Functional Agreement 8
which was executed by Avista on December 13, 2013, 9
followed by the Amended and Restated Order 1000 Functional 10
Agreement, signed on November 11, 2014 (Order 1000 11
Agreement). The contract called for a $50,000 payment late 12
in 2014 that covered two years of payments for 2015 and 13
2016. Beginning in 2017, this contract calls for an 14
annual payment of $25,000. 15
NERC Critical Infrastructure Protection (2016: 16
-$8,000) – The Company has purchased several software and 17
hardware products to assist in protecting critical 18
transmission control systems from intrusion and to meet 19
applicable NERC standards. These products provide for 20
physical security, intrusion detection, virus protection, 21
vulnerability assessment, electronic perimeter security 22
and backup/recovery of critical control systems. The 23
Cox, Di Page 7 Avista Corporation

Company’s 2016 and 2017 rate year expense is $50,000, a 1
decrease of $8,000 from the 2014 actual test year expense. 2
OASIS Expenses (2016: $8,000) – These Open Access 3
Same-time Information System (OASIS) expenses are 4
associated with travel and training costs for transmission 5
pre-scheduling and OASIS personnel. This travel is 6
required to monitor and adhere to NERC reliability 7
standards, regional criterion development, and FERC OASIS 8
requirements. The increase in costs to $8,000 for the 9
2016 and 2017 rate years is due to the availability of the 10
necessary training in relation to the technical users’ 11
individual schedules. The absence of any travel expenses 12
in the test year was due, in large part, to Avista hosting 13
an OASIS schedulers meeting in Spokane (for which costs of 14
approximately $6,330 were attributed to another account) 15
instead of traveling to this meeting. 16
Bonneville Power Factor Charge (2016: -$56,000) – 17
Power factor charge costs are associated with the 18
Bonneville Power Administration’s (Bonneville) General 19
Transmission Rate Schedule Provisions. Avista is aware of 20
Bonneville’s Initial Proposal in its BP-16 Rate Case, 21
filed December 10, 2014, that is proposing eliminating 22
this Power Factor Charge. Accordingly, Avista has removed 23
this expense for the 2016 and 2017 rate years. 24
Cox, Di Page 8 Avista Corporation

Peak Reliability – Reliability Coordination 1
(2016: $453,000; 2017: $93,000) – The Company’s Peak 2
Reliability (Peak) fees are scheduled to increase from the 3
amount paid in the historical test year, $168,000, to 4
$621,000 in the 2016 rate year and $714,000 in the 2017 5
rate year. The large increase in 2016 is attributable to 6
the FERC requirement that the WECC reliability 7
coordination function be corporately and physically 8
separated from the remaining WECC requirements and 9
obligations. This “bifurcation” is primarily the result 10
of a transmission system outage in the Pacific Southwest 11
on September 8, 2011. A reference to the disturbance 12
including “Causes and Recommendations” may be found at 13
http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-14
nerc-report.pdf. Another reason for the large variance is 15
that Peak was not fully staffed during the test period. 16
Expenses will ramp up during 2015 to the 2016 amount. The 17
increase in 2017 of $93,000 is based upon Peak’s 18
projections of its funding requirement. 19
WECC – Administration Dues (2016: -$46,000; 2017: 20
$72,000) – WECC is the designated Regional Entity under 21
federal statute responsible for coordinating and promoting 22
Bulk Electric System reliability throughout the western 23
interconnection. WECC is responsible for monitoring and 24
Cox, Di Page 9 Avista Corporation

measuring Avista’s compliance with the standards and has 1
substantially increased its staff and other resources to 2
meet these FERC requirements. The Company’s test year 3
WECC dues and fees were $531,000. The Company’s totals 4
for dues and fees in the 2016 and 2017 rate years are 5
expected to be $485,000 and $557,000, respectively. 6
Similar to Peak, there is not a direct comparison to prior 7
years because of the aforementioned FERC mandated 8
bifurcation of the reliability coordination portion of 9
WECC’s responsibilities. 10
WECC - Loop Flow (2016: -$34,000) – Loop Flow charges 11
are spread across all transmission owners in the West to 12
compensate utilities that make system adjustments to 13
eliminate transmission system congestion throughout the 14
operating year. WECC Loop Flow charges can vary from year 15
to year since the costs incurred are dependent on 16
transmission system usage and congestion. Loop Flow 17
expenses for the 2014 test year were $34,000. These 18
expenses were rolled into the WECC annual dues beginning 19
in 2015. 20
Addy Substation ($0) – The Company pays operation and 21
maintenance fees to Bonneville associated with a 115kV 22
circuit breaker in Bonneville’s Addy Substation that 23
provides a direct interconnection for Avista’s retail 24
Cox, Di Page 10 Avista Corporation

load. In the test year the expenses were $9,000 and these 1
are anticipated to remain unchanged for the 2016 and 2017 2
rate years. 3
Hatwai Substation ($0) – The Company pays operation 4
and maintenance fees to Bonneville associated with a 230kV 5
circuit breaker owned by Avista but located in 6
Bonneville’s Hatwai Substation. In the test year the 7
expenses were $23,000 and these are expected to remain 8
unchanged for the 2016 and 2017 rate years. 9
10
III. TRANSMISSION REVENUES FOR 2016 AND 2017 11
Q. Please describe the adjustments to 2014 test 12
year transmission revenues to arrive at transmission 13
revenues for the 2016 and 2017 rate years. 14
A. Adjustments have been made in this filing to 15
incorporate updated information for transmission revenue 16
during the 2016 rate year as compared to the historical 17
test year, and to reflect incremental 2017 revenues 18
compared to 2016 levels. Each revenue item described 19
below is at a system level and is included in Exhibit No. 20
9, Schedule 1. Table No. 2 below provides a summary of 21
the changes in transmission revenues, and an explanation 22
of each change follows the Table. 23
Cox, Di Page 11 Avista Corporation

1
2
3
4
5
6
7
8
9
10
11
12
(1) Represents the change in revenue above or below the twelve months ended 13 December 31, 2014 test year level. 14 15 (2) Represents the incremental change in revenue above or below the twelve 16 months ended December 31, 2016 rate year level. 17
Borderline Wheeling – Transmission (2016: $103,000) - 18
The Company provides borderline wheeling service (wheeling 19
service over transmission facilities for service to loads 20
of other utilities within the Company’s system footprint). 21
Total revenue for the transmission portion of borderline 22
wheeling activities for the test year was $6,233,000. 23
Total revenue in the 2016 and 2017 rate years has been set 24
at $6,336,000, representing an increase of $103,000 from 25
TABLE NO. 2Transmission Revenue Adjustment
(1) 2016
Rate Year
(System)
(2) 2017
Rate Year
(System)
$333,000 $2,197,000
Cox, Di Page 12 Avista Corporation

the test year. Revenue projections from each are 1
determined as follows: 2
• Bonneville Power Administration - Network Integration 3
Transmission Service revenue is determined based upon 4
a three-year average for the 2012 to 2014 time 5
period, resulting in a figure of $6,236,000 for the 6
2016 and 2017 rate years compared to $6,126,000 for 7
the test year. The Company has in the past used a 8
five-year average for determining BPA borderline 9
wheeling revenue, but is proposing to use a three-10
year average at this time in order to be consistent 11
with the three-year average used in all other 12
instances where the Company determines transmission 13
revenues that are based upon variable customer load 14
figures (e.g. Grant County PUD and PacifiCorp Dry 15
Gulch). By changing from the five-year average to 16
the three-year average in this filing, revenue is 17
increased by $35,000, from $6,201,000 to $6,236,000. 18
• Grant County PUD – Power transfer revenue is 19
determined using a three-year average (2012-2014) 20
resulting in a figure of $28,000 for the 2016 and 21
2017 rate years compared to $29,000 for the test 22
year. 23
Cox, Di Page 13 Avista Corporation

• Consolidated Irrigation District – Point-to-Point 1
Transmission Service revenue for the 2014 test period 2
was $32,000. Under the current contract (with a term 3
from 10/1/2011 to 9/30/2016) and an expected follow-4
on contract this revenue is expected to remain 5
substantially the same during the 2016 and 2017 rate 6
years. 7
• East Greenacres Irrigation District – Point-to-Point 8
Transmission Service revenue for the 2014 test period 9
was $15,000. Under the current contract (with a term 10
from 10/1/2014 to 9/30/2019) this revenue will be 11
$11,000 for the 2016 and 2017 rate years. 12
• Spokane Tribe – Point-to-Point Transmission Service 13
revenue for the 2014 test period was $30,000. Under 14
a new contract (with a term from 1/1/2015 to 15
12/31/2019) this revenue will be $29,000 for the 2016 16
and 2017 rate years. 17
Borderline Wheeling – Low Voltage (2016: $8,000) – 18
The Company provides borderline wheeling service (wheeling 19
service over low-voltage distribution facilities for 20
service to loads of other utilities within the Company’s 21
system footprint). Total revenues for the low voltage 22
portion of borderline wheeling activities for the test 23
year was $1,072,000. Total revenue in the 2016 and 2017 24
Cox, Di Page 14 Avista Corporation

rate years has been set at $1,080,000, representing an 1
increase of $8,000 from the test year, including the 2
following components: 3
• Bonneville Power Administration – Wheeling revenue 4
over low-voltage facilities for the 2014 test period 5
was $929,000. Revenue for the 2016 and 2017 rate 6
years is expected to remain substantially the same. 7
• Consolidated Irrigation District – Electric 8
Distribution Service revenue for the 2014 test period 9
was $80,000. Under the current contract (with a term 10
from 10/1/2011 to 9/30/2016) and an expected follow-11
on contract, this revenue is expected to remain 12
substantially the same during the 2016 and 2017 rate 13
years. 14
• East Greenacres Irrigation District – Electric 15
Distribution Service revenue for the 2014 test period 16
was $45,000. Under the current contract (with a term 17
from 10/1/2014 to 9/30/2019) this revenue will be 18
$51,000 for the 2016 and 2017 rate years, an increase 19
of $6,000. 20
• Spokane Tribe – Electric Distribution Service revenue 21
for the 2014 test period was $18,000. Under a new 22
contract (with a term from 1/1/2015 to 12/31/2019) 23
Cox, Di Page 15 Avista Corporation

this revenue will be $20,000 for the 2016 and 2017 1
rate years. 2
Borderline Wheeling – Ancillary Revenues ($666,000) – 3
The Company provides various ancillary services in 4
association with long-term firm transmission service 5
provided under its Open Access Transmission Tariff. 6
Ancillary services revenue for the test year was $919,000. 7
Revenue in the 2016 and 2017 rate years has been set at 8
$1,585,000, representing an increase of $666,000 from the 9
test year. Ancillary services are necessary to support 10
the transmission of electric power from one point to 11
another given the obligations of balancing areas and 12
transmitting utilities within those balancing areas to 13
maintain reliable operation of the interconnected 14
transmission system. The revenue projection is based upon 15
an ancillary services rate of $8.94 per kW multiplied by 16
billing determinants of 2% (regulation and frequency 17
response), 1.5% (Operating Reserves – Spinning) and 1.5% 18
(Operating Reserves – Supplemental), applied to a 19
customer’s monthly peak load. The components of the 20
ancillary revenues for 2016 and 2017 are as follows: 21
• Bonneville Power Administration - Ancillary services 22
revenue is estimated based upon three-year average 23
load figures for the 2012-2014 time period, resulting 24
Cox, Di Page 16 Avista Corporation

in estimated revenues of $1,570,000 for the 2016 and 1
2017 rate years compared to $906,000 for the 2014 2
test year. Prior to October 1, 2014, when a change 3
in WECC reliability standards became effective, BPA 4
self-provided all of its operating reserve 5
obligations. This revenue increase is the result of 6
BPA now paying the Company for the operating 7
reserves. 8
• Consolidated Irrigation District – Ancillary services 9
revenue was $6,000. Under the current contract (with 10
a term from 10/1/2011 to 9/30/2016) and an expected 11
follow-on contract, this revenue is expected to 12
remain substantially the same during the 2016 and 13
2017 rate years. 14
• East Greenacres Irrigation District – Ancillary 15
services revenue is estimated based upon three-year 16
average load figures for the 2012-2014 time period, 17
resulting in estimated revenue of $4,000 for the 2016 18
and 2017 rate years compared to $4,000 for the 2014 19
test year. 20
• Spokane Tribe - Ancillary services revenue is 21
estimated based upon three-year average load figures 22
for the 2012-2014 time period, resulting in estimated 23
Cox, Di Page 17 Avista Corporation

revenue of $5,000 for the 2016 and 2017 rate years 1
compared to $3,000 for the 2014 test period. 2
Seattle and Tacoma – Main Canal Project 3
(2016: $41,000; 2017: -$3,000) Effective March 1, 2008, 4
the Company entered into long-term point-to-point 5
transmission service arrangements with the City of Seattle 6
and the City of Tacoma to transfer output from the Main 7
Canal hydroelectric project, net of local Grant County PUD 8
load service, to the Company’s transmission 9
interconnections with Grant County PUD. Service is 10
provided during the eight months of the year (March 11
through October) in which the Main Canal project operates, 12
and the agreements include a three-year ratchet demand 13
provision. Revenues under these agreements totaled 14
$320,000 during the test year. Revenues for the 2016 and 15
2017 rate years are expected to be $361,000 and $358,000 16
respectively, based on ratchet demand estimates. 17
Seattle and Tacoma – Summer Falls Project ($0) – 18
Effective March 1, 2008, the Company entered into long-19
term use-of-facilities arrangements with the City of 20
Seattle and the City of Tacoma to transfer output from the 21
Summer Falls hydroelectric project across the Company’s 22
Stratford Switching Station facilities to the Company’s 23
Stratford interconnection with Grant County PUD. Charges 24
Cox, Di Page 18 Avista Corporation

under this use-of-facilities arrangement are based upon 1
the Company’s investment in its Stratford Switching 2
Station and are not impacted by the Company’s transmission 3
service rates under its Open Access Transmission Tariff. 4
Revenues under these two contracts totaled $74,000 in the 5
test year and are expected to remain unchanged for the 6
2016 and 2017 rate years. 7
OASIS Non-Firm and Short-Term Firm Transmission 8
Service (2016: $41,000) – OASIS is an acronym for Open 9
Access Same-time Information System. This is the system 10
used by electric transmission providers for selling 11
available transmission capacity to eligible customers. 12
The terms and conditions under which the Company sells its 13
transmission capacity via its OASIS are pursuant to FERC 14
regulations and Avista’s Open Access Transmission Tariff. 15
The Company calculates its rate year adjustments using a 16
three-year average of actual OASIS Non-Firm and Short-Term 17
Firm revenue. OASIS transmission revenue may vary 18
significantly depending upon a number of factors, 19
including current wholesale power market conditions, 20
forced or planned generation resource outage situations in 21
the region, the current load-resource balance status of 22
regional load-serving entities, and the availability of 23
parallel transmission paths for prospective transmission 24
Cox, Di Page 19 Avista Corporation

customers. The use of a three-year average is intended to 1
strike a balance in mitigating both long-term and short-2
term impacts to OASIS revenue. A three-year period is 3
intended to be long enough to mitigate the impacts of non-4
substantial temporary operational conditions (for 5
generation and transmission) that may occur during a given 6
year, and it is intended to be short-enough so as to not 7
dilute the impacts of long-term transmission and 8
generation topography changes (e.g., major transmission 9
projects which may impact the availability of the 10
Company’s transmission capacity or competing transmission 11
paths, and major generation projects which may impact the 12
load-resource balance needs of prospective transmission 13
customers). However, if there are known events or factors 14
that occurred during the period that would cause the 15
average to not be representative of future expectations, 16
then adjustments may be made to the three-year average 17
methodology. In this filing, the Company is using a three 18
year average for the time period of January 2012 to 19
December 2014. The OASIS revenue for the test year was 20
$2.861 million and the three-year average results in 2016 21
and 2017 rate year revenues of $2.902 million. 22
PacifiCorp Dry Gulch (2016: -$12,000) – Revenue under 23
the Dry Gulch use-of-facilities agreement has been 24
Cox, Di Page 20 Avista Corporation

adjusted to $220,000 for the 2016 and 2017 rate years, 1
which is a $12,000 decrease from the test year actual 2
revenue of $232,000. The Company is calculating its 3
adjustment using a three-year average of actual revenue. 4
Revenue under the Dry Gulch Transmission and 5
Interconnection Agreement with PacifiCorp varies depending 6
upon PacifiCorp’s loads served via the Dry Gulch 7
Interconnection and the operating conditions of 8
PacifiCorp’s transmission system in this area. The use of 9
a three-year average is intended to mitigate the impacts 10
of potential annual variability in the revenues under the 11
contract. The contract includes a twelve-month rolling 12
ratchet demand provision and charges under this agreement 13
are not impacted by the Company’s open access transmission 14
service tariff rates. 15
Spokane Waste to Energy Plant ($0) – Spokane Waste to 16
Energy pays a use-of-facilities charge for the ongoing use 17
of its interconnection to Avista’s transmission system. 18
The 2016 and 2017 rate year revenues associated with the 19
use-of-facilities charge are $28,000 in each respective 20
year, the same as the test year. 21
Grand Coulee Project Hydroelectric Authority ($0) – 22
The Company provides operations and maintenance services 23
on the Stratford-Summer Falls 115kV Transmission Line to 24
Cox, Di Page 21 Avista Corporation

the Grand Coulee Project Hydroelectric Authority under a 1
contract signed in March 2006. These services are 2
provided at a fixed annual fee. Annual charges under this 3
contract totaled $8,100 in the test year and will remain 4
the same for the 2016 and 2017 rate years. 5
Palouse Wind (2016: $0; 2017: $2,200,000) – Palouse 6
Wind signed a transmission service contract with the 7
Company based on its initial intent to sell the output 8
from a wind facility to an entity other than Avista. 9
Avista has since signed a power purchase agreement with 10
Palouse Wind which voided its need for transmission 11
service. Palouse Wind intends to delay use of the 100 MW 12
of reserved transmission service for up to five years, 13
unless they are able to re-market the capacity. However, 14
according to Avista’s Open Access Transmission Tariff 15
(Tariff) and the contract signed with Avista, Palouse Wind 16
must pay an annual reservation fee equal to one month’s 17
service charge to extend its start date for service. The 18
test year included a $200,000 extension of service payment 19
and the 2016 rate year also includes an expected payment 20
amount of $200,000, per the terms of Avista’s Tariff. 21
After 2016, Palouse Wind may not make any further requests 22
to delay commencement of service under the terms of the 23
Tariff. Accordingly, the Company must project the 24
Cox, Di Page 22 Avista Corporation

commencement of service as of January 1, 2017, 1
notwithstanding Palouse Wind’s ability to pay for service 2
that it may not use, increasing revenues expected for the 3
2017 rate year to $2,400,000, an increase of $2,200,000. 4
Palouse Wind O&M ($0) – Per Avista’s interconnection 5
agreement with the Palouse Wind project, the 6
interconnection customer pays O&M fees associated with 7
directly-assigned interconnection facilities owned and 8
operated by Avista. O&M revenue for the test year was 9
$52,000. Revenue during the 2016 and 2017 rate years is 10
expected to remain unchanged. 11
Stimson Lumber Agreement ($0) – Low-voltage 12
facilities associated with the Company’s Plummer 13
Substation are dedicated for use by Stimson Lumber 14
resulting in annual low voltage use-of-facilities revenue 15
of $9,000. The 2016 and 2017 rate year revenues from this 16
agreement are also $9,000 per year. 17
Bonneville Power Administration – Parallel Capacity 18
Support ($0) – Avista and Bonneville executed a Parallel 19
Operation Agreement on December 12, 2012, wherein Avista 20
provides Bonneville with parallel transmission capacity in 21
support of Bonneville’s integration of several wind 22
resource projects. Avista provides ongoing parallel 23
capacity support under the agreement at a monthly charge 24
Cox, Di Page 23 Avista Corporation

of $266,000. Revenue for the test year was $3,192,000. 1
The 2016 and 2017 rate years reflect the same amount, 2
$3,192,000. 3
Morgan Stanley – Point-to-Point Transmission Service 4
($0) – Morgan Stanley Capital Group has purchased 25 MW of 5
Long-Term Firm Point-to-Point Transmission Service from 6
January 1, 2013 to December 31, 2017. The test year 7
included revenues of $600,000, and the 2016 and 2017 rate 8
years reflect the same amount, $600,000. 9
Hydro Tech Systems Agreement ($0) – Low-voltage 10
facilities in the Company’s Greenwood Substation are 11
dedicated for use by the Meyers Falls generation project 12
resulting in annual low voltage use-of-facilities revenue 13
of $6,000 during the test year. The 2016 and 2017 rate 14
year revenues from this agreement are also $6,000. 15
Kootenai Electric Cooperative Fighting Creek (KEC) 16
(2016: $15,000) – KEC has purchased 3 MW of Long-Term Firm 17
Point-to-Point Transmission Service from April 1, 2014 to 18
March 31, 2019. The test year included revenues of 19
$73,000. Revenue for the 2016 and 2017 rate years will 20
increase to $88,000. 21
BPA Excess Transmission Sales (2016: -$529,000) – In 22
December of 2013, with the completion of a new 230kV 23
interconnection with the Bonneville Power Administration 24
Cox, Di Page 24 Avista Corporation

(BPA), the Company was able to directly integrate its 1
Lancaster Generating Station into its transmission system. 2
As a result of this effort, the Company was also able to 3
terminate a 150MW Point-to-Point (PTP) transmission 4
contract with the Bonneville Power Administration. The 5
termination language of the PTP contract specified certain 6
notification periods for termination. Pursuant to its 7
terms, this contract could not be terminated until August 8
of 2014. During the nine months between completion of the 9
Lancaster interconnection project and the effective 10
termination date of the PTP contract, the Company actively 11
re-marketed its BPA PTP capacity that was considered 12
surplus to its load service requirements. This marketing 13
effort resulted in a cost offset (revenue) of 14
approximately $529,000 in 2014. The 150MW of PTP 15
transmission capacity was terminated in August of 2014. 16
This cost offset will not continue beyond the test period, 17
therefore 2016 and 2017 revenues associated with this item 18
will be $0. 19
Cox, Di Page 25 Avista Corporation

IV. TRANSMISSION AND DISTRIBUTION CAPITAL PROJECTS 1
Q. Please provide the basis for the Company’s 2
capital transmission projects that will be completed from 3
January 1, 2015 through December 31, 2017. 4
A. Avista must continuously invest in its 5
transmission system to maintain reliable customer service 6
and meet mandatory reliability standards. The capital 7
transmission projects are planned and constructed to meet 8
either compliance requirements, improve system 9
reliability, fix broken equipment, or replace aging 10
equipment that is anticipated to fail. 11
Included in the compliance requirements are the North 12
American Electric Reliability Corporation (NERC) 13
standards, which are national standards that utilities 14
must meet to ensure interconnected system reliability. 15
Beginning June 2007, compliance with these standards was 16
made mandatory and failure to meet the requirements could 17
result in monetary penalties of up to $1 million per day, 18
per infraction. The majority of the reliability standards 19
pertain to transmission planning, operation, and equipment 20
maintenance. The standards require utilities to plan and 21
operate their transmission systems in such a way as to 22
avoid the loss of customers or impact to neighboring 23
utility systems due to the loss of transmission 24
Cox, Di Page 26 Avista Corporation

facilities. The transmission system must be designed so 1
that the loss of up to two facilities simultaneously will 2
not impact the interconnected transmission system. The 3
transmission system must be operated at all times such 4
that a loss of a facility will not result in a System 5
Operating Limit exceedance. If such an exceedance occurs, 6
it must be mitigated prior to the loss of the next 7
facility. This mitigation can include system 8
configuration changes, generation changes, or removal of 9
firm load from the transmission system. These 10
requirements drive the need for Avista to continually 11
invest in its transmission system. Avista is required to 12
perform system planning studies in both the near term (1-5 13
years) and long term (5-10 years). If a potential 14
violation is observed in the future years, then Avista 15
must develop a project plan to ensure that the violation 16
is fixed prior to it becoming a real-time operating issue. 17
Avista plans for the future projects and attempts to 18
ensure that both the design and construction of the 19
required projects are completed prior to the time the 20
projects are needed. Avista will continue to have a need 21
to develop these compliance-related projects as system 22
load grows, new generation is interconnected, and the 23
system functionality and usage changes. 24
Cox, Di Page 27 Avista Corporation

Avista capital transmission project requirements are 1
developed through system planning studies, engineering 2
analysis, or scheduled upgrades or replacements. The 3
larger specific projects that are developed through the 4
system planning study process typically go through a 5
thorough internal review process that includes multiple 6
stakeholder reviews to ensure all system needs are 7
adequately addressed. For the smaller specific projects, 8
Avista doesn’t perform a traditional cost-benefit 9
analysis. Projects are selected to meet specific system 10
needs or equipment replacement. However, both project 11
cost and system benefits are considered in the selection 12
of the final projects. 13
Q. Did the Company consider any efficiency gains or 14
offsets when evaluating the transmission projects to 15
include in the Company’s case? 16
A. Yes. The Company evaluated each project and 17
determined that some of the 2015, 2016 and 2017 capital 18
transmission projects will result in efficiency gains and 19
potential offsets or savings, and the Company has included 20
those where applicable. The primary offsets result in 21
loss savings from reconductoring heavily-loaded 22
transmission or distribution facilities. For these 23
projects, an analysis was performed to determine the 24
Cox, Di Page 28 Avista Corporation

savings. The assumed avoided energy cost to determine the 1
savings was $44 MWh, which is the 20 year life cycle cost 2
calculated in Avista’s 2013 Integrated Resource Plan (see 3
page iii). However, not all projects will result in loss 4
savings or other offsets. Avista has maintenance 5
schedules for certain equipment. These maintenance cycles 6
range from 5-15 years depending on the equipment. Unless 7
the replacement of equipment occurs in the same year as 8
the scheduled maintenance, there will not be any savings. 9
Appropriate maintenance and replacement strategies 10
generally improve system reliability over several years on 11
the assets they target. However, several other factors 12
can impact the overall reliability, such as weather and 13
external forces, and can cause significant variation. 14
Furthermore, each year as we replace old equipment with 15
new, the remainder of our system gets another year older, 16
which continues to generate additional failures on our 17
system. 18
Q. Please describe each of the transmission 19
projects planned for the period January 1, 2015 to 20
December 31, 2017. 21
A. The major capital transmission investment (on a 22
system basis) for projects to be completed from January 1, 23
Cox, Di Page 29 Avista Corporation

2015 to December 2017 are shown in Table No. 3 and 1
described below. 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 I. Reliability Compliance Projects: 34
35 Substation – 115kV Line Relay Upgrades – 2015: 36 $1,230,000; 2016:$0; 2017:$0 37
This project involves the replacement of older 38 protective 115 kV system relays with new micro-39 processor relays to increase system reliability by 40
reducing the amount of time it takes to sense a 41 system disturbance and isolate it from the system. 42
This project is required to meet Reliability 43 Compliance under NERC Standards: TOP-004-2 R1-R4, 44
2017
System O&M Offsets System O&M Offsets System I. Reliability Compliance:
Substation - 115 kV Line Relay Upgrades 1,230$ -$ -$ -$ -$
Transmission - NERC Low Priority Mitigation 500 - 2,000 - 3,000
Transmission - NERC Medium Priority Mitigation 3,306 - 2,251 - -
SCADA - SOO & BUCC 1,061 - 1,002 - 1,044
Total Reliability Compliance 6,097 - 5,253 - 4,044
II. Contractual Requirements:
Colstrip Transmission/PNACI 491 - 497 - 516
Tribal Permits and Settlements 1,430 - 316 - 297
Clearwater Sub Upgrades 500 - 500 - - Total Contractual Requirements 2,421 - 1,313 - 813
III. Reliability Improvements:
Substation - Distribution Station Rebuilds 250 - 3,565 - 2,865
Spokane Valley Transmission Reinforcement 3,468 - 7,440 - -
Noxon Switchyard Rebuild 9,906 - 500 - 7,700
Westside Rebuild Phase One - - 1,780 - -
South Region Voltage Control - - 4,900 - -
Lewiston Mill Rd. 115 kV Substation 684 - - - -
Total Reliability Improvements 14,308 - 18,185 - 10,565
IV. Reliability Replacement:
Storms 1,000 - 890 - 883
Substation - Asset Mgmt. Capital Maintenance 1,647 - 3,300 - 3,300
Substation - Capital Spares 3,250 - 4,915 - 1,200
Transmission - Asset Management 1,813 - 1,772 - 1,780 Total Reliability Replacement: 7,710 - 10,877 - 7,163
V. Reliability Compliance and Improvements:
Environmental Compliance 434 - 350 - 350
Reconductors and Rebuilds 11,776 15 21,161 15 18,327
Total Reliability Compliance and Improvements 12,210 15 21,511 15 18,677
42,746$ 15$ 57,139$ 15$ 41,262$
TABLE NO. 3ELECTRIC TRANSMISSION (SYSTEM)
2015 2016
Cox, Di Page 30 Avista Corporation

TPL-002-0a R1-R3, and TPL-003-0a R1-R3 and will be 1 completed in 2015. 2 3 Transmission – NERC Low Priority Mitigation – 2015: 4 $500,000; 2016: $2,000,000; 2017: $3,000,000 5 This program reconfigures insulator attachments, 6 and/or rebuilds existing transmission line 7
structures, or removes earth beneath transmission 8 lines in order to mitigate ratings/sag discrepancies 9 found between "design" and "field" conditions as 10
determined by LiDAR survey data. This program was 11 undertaken in response to the October 7, 2012 North 12
American Electric Reliability Corporations (NERC) 13 "NERC Alert" - Recommendation to Industry, 14 "Consideration of Actual Field Conditions in 15 Determination of Facility Ratings". This Capital 16 Program covers mitigation work on Avista's "Low 17
Priority" 115kV transmission lines. Mitigation brings 18 lines in compliance with the National Electric Safety 19
Code (NESC) minimum clearances values. 20 21 Transmission - NERC Medium Priority Mitigation – 22 2015: $3,306,000; 2016: $2,251,000; 2017: $0 23 This program reconfigures insulator attachments, 24 and/or rebuilds existing transmission line 25 structures, or removes earth beneath transmission 26 lines in order to mitigate ratings/sag discrepancies 27
found between "design" and "field" conditions as 28 determined by LiDAR survey data. This program was 29 undertaken in response to the October 7, 2012 North 30
American Electric Reliability Corporations (NERC) 31 "NERC Alert" - Recommendation to Industry, 32
"Consideration of Actual Field Conditions in 33 Determination of Facility Ratings". This Capital 34 Program covers mitigation work on Avista's "Medium 35 Priority" 230 kV and 115 kV transmission lines. 36 Mitigation brings lines in compliance with the 37
National Electric Safety Code (NESC) minimum 38 clearances values. 39
40 SCADA–SOO&BUCC – 2015: $1,061,000; 2016: $1,002,000; 41 2017: $1,044,000 42
This program replaces and/or upgrades existing 43 electric and gas control center telecommunications 44 and computing systems as they reach the end of their 45 useful lives, require increased capacity, or cannot 46 accommodate necessary equipment upgrades due to 47
Cox, Di Page 31 Avista Corporation

existing constraints. Included are hardware, 1 software, and operating system upgrades, as well as 2
deployment of capabilities to meet new operational 3 standards and requirements. Some system upgrades may 4 be initiated by other requirements, including NERC 5 reliability standards, growth, and external projects 6 (e.g. Smart Grid). Examples of upgrades to be 7
completed under this program are Critical 8 Infrastructure Protection version 5 (NERC 9 requirement), Gas Control Room Management (PHMSA 10
requirement), WECC RC Advanced Applications, and 11 Technology Refresh (network and storage). 12 13 II. Contractual Requirements: 14
15 Colstrip Transmission – 2015: $491,000; 2016: 16 $497,000; 2017: $516,000 17
As a joint owner of the Colstrip Transmission 18 projects, Avista pays its ownership share of all 19
capital improvements. Northwestern Energy either 20 performs or contracts out the capital work associated 21 with the joint owned facilities. 22
23 Tribal Permits – 2015: $1,430,000; 2016: $316,000; 24 2017: $297,000 25 The Company has approximately 300 right-of-way 26 permits on tribal reservations that need to be 27
renewed. The costs include labor, appraisals, field 28 work, legal review, GIS information, negotiations, 29
survey (as needed), and the actual fee for the 30 permit. 31 32 Clearwater Substation Upgrade – 2015: $500,000; 2016: 33 $500,000; 2017: $0 34
This project includes a series of station upgrades to 35 improve 115 kV system reliability in the Lewiston 36 area. This part of the project will construct a new 37 115 kV line terminal in order to install a new bus 38 sectionalizing breaker. In addition, the project 39
replaces an older 115 kV oil circuit breaker and 40 installs standard 115 kV air switches in place of the 41 existing sliding link bus switches, which are 42
dangerous to operate and a reliability concern. 43
Cox, Di Page 32 Avista Corporation

III. Reliability Improvements: 1 2 Substation – Distribution Station Rebuilds – 2015: 3 $250,000; 2016: $3,565,000; 2017: $2,865,000 4
This program replaces and/or rebuilds existing 5 substations as they reach the end of their useful 6 lives, require increased capacity, or cannot 7
accommodate necessary equipment upgrades due to 8 existing physical constraints. Included are Wood 9 Substation rebuilds as well as upgrading stations to 10
current design and construction standards. Some 11 station rebuilds may be initiated by other 12
requirements, including obligation to serve, growth, 13 and external projects. Examples of Idaho substation 14 rebuilds to be completed under this program in the 15 next five years are Big Creek, South Lewiston and 16 Kamiah. 17 18 Spokane Valley Transmission Reinforcement – 2015: 19 $3,468,000; 2016: $7,440,000; 2017: $0 20 The Spokane Valley Transmission Reinforcement Project 21 includes rebuilding 4.4 miles of the Beacon - Boulder 22
#2 115 kV Transmission Line, constructing the new 23 Irvin Switching Station, rebuilding 1.75 miles of the 24
Irvin - Opportunity 115 kV Tap, installing four 115 25 kV circuit breakers at Opportunity Substation, and 26 constructing a new 2.2 mile 115 kV transmission line 27
from Irvin to Millwood/Inland Empire Paper. The 28 completion of these projects is required to mitigate 29
existing and future performance and reliability 30 issues of the Transmission System in the Spokane 31 Valley. Opportunity Substation is presently under 32
construction; the Irvin-Millwood line is under 33 construction; Irvin Substation construction will 34
break ground in 2015 and be energized in 2016; and 35 the Beacon-Boulder line will then be able to be 36 rebuilt. 37 38 Noxon Switchyard Rebuild – 2015: $9,906,000; 2016: 39 $500,000; 2017: $7,700,000 40 The existing Noxon Rapids 230 kV Switchyard requires 41 reconstruction due to the present age and condition 42
of the equipment in the station. The existing bus 43 has suffered a number of recent failures and is 44
configured as a single bus with a tiebreaker 45 separating the East and West buses. The station is 46 the interconnection point of the Noxon Rapids 47
Cox, Di Page 33 Avista Corporation

Hydroelectric development as well as a principal 1 interconnection point between Avista and BPA, and, as 2
such, is a significant asset in the reliable 3 operation of the Western Montana Hydro Complex. 4 Equipment outages within the Station (planned or 5 unplanned) can cause significant curtailments of the 6 local generation output. Due to the significance of 7
the station, a complete rebuild will require 8 coordination with Avista’s Energy Resources 9 Department and neighboring utilities, primarily BPA. 10
The Noxon Switchyard Rebuild Project is proposed to 11 be a Greenfield Double Bus Double Breaker 230 kV 12
switching station to replace the existing Noxon 13 Switchyard. 14 15 Westside Rebuild Phase I – 2015: $0; 2016: 16 $1,780,000; 2017: $0 17
Phase I of this project will extend the existing 18 Westside Substation and the 115 kV and 230 kV buses 19
to allow for a new 250 MVA Autotransformer. This 20 installation will eliminate overloads for credible 21 bus outages and tie breaker failure contingencies in 22
the Spokane area. This is the first phase of a three 23 phase project. 24
25 South Region Voltage Control – 2015: $0; 2016: 26 $4,900,000; 2017: $0 27
Avista's south region 230 kV, primarily around 28 Lewiston-Clarkston, experiences excessive high 29
voltage during light load periods. Voltages exceed 30 equipment ratings over 35% of the time. Operation of 31 equipment outside of equipment ratings imposes 32
potential legal and regulatory risks to the Company 33 on top of increasing large scale outage 34
possibilities. With automatic control, existing 35 overvoltages can be reduced, if not eliminated, on 36 the 230kV buses at Dry Creek, Lolo, and N.Lewiston, 37 as well as Moscow and Shawnee. 38 39 Lewiston Mill Rd. 115 kV Substation – 2015: $684,000; 40 2016: $0; 2017: $0 41
A new 115-13 kV substation is required to serve the 42
sawmill for the Idaho Forest Group in Lewiston near 43 Clearwater Paper Co. This new substation will have 44
one 20 MVA transformer, 115 kV Circuit Switcher, 45 panelhouse, full SCADA/Communications, and two 13 kV 46 distribution feeder bays. The transmission will tap 47
Cox, Di Page 34 Avista Corporation

the existing Clearwater-Lolo #2 line with associated 1 air switches for isolation. This substation is 2
required for Avista to serve this customer. 3 4 IV. Reliability Replacements: 5 6 Storms - 2015: $1,000,000; 2016: $890,000; 2017: 7 $883,000 8 This program will replace cross arms, poles and 9 structures as required due to storms and fires on 10
distribution and transmission lines. 11 12 Substation Asset Management Capital Maintenance –13 2015: $1,647,000; 2016: $3,300,000 ; 2017: $3,300,000 14
Avista has several different equipment replacement 15 programs to improve reliability by replacing aged 16 equipment that is beyond its useful life. These 17
programs include transmission air switch upgrades, 18 restoration of substation rock and fencing, recloser 19
replacements, replacement of obsolete circuit 20 switchers, substation battery replacement, meter 21 replacements and upgrades, relay replacements, high 22
voltage fuse upgrades, transformer replacements, 23 breaker replacements, installation of diagnostic 24
monitors, substation air switch replacements, and 25 voltage regulator replacements. All of these 26 individual projects improve system reliability and 27
customer service. 28 29 Substation – Capital Spares – 2015: $3,250,000; 2016: 30 $4,915,000; 2017: $1,200,000 31
This program maintains our fleet of Power 32
Transformers and High Voltage Circuit Breakers. This 33 fleet of critical apparatus is capitalized upon 34
receipt and placed in service for both planned and 35 emergency installations as required. The annual 36 program expenditures may vary significantly in years 37 when a 230/115 autotransformer is purchased. In 38 years without an autotransformer purchase, only minor 39
variations will occur based on planned projects as 40 well as replenishing apparatus fleet levels required 41 for adequate capital spares. Acquisition of these 42
capital items requires long lead times, so sufficient 43 levels of safety-stock must be maintained to avoid 44
service interruptions. 45 46
Cox, Di Page 35 Avista Corporation

Transmission – Asset Management – 2015: $1,813,000; 1 2016: $1,772,000; 2017: $1,780,000 2
This item includes Transmission Minor Rebuilds in ER 3 2057, and Air Switch Replacements in ER 2254. 4 Transmission Minor Rebuilds are developed using data 5 received from the prior year’s Wood Pole Inspection 6 Program. Minor rebuilds may also use data received 7
from annual Aerial Patrol Inspections. Both 8 inspection programs are undertaken to maintain 9 compliance with NERC Standard FAC-501-WECC-1. Air 10
Switch Replacements are made based either on 11 condition, capacity, or functionality issues. 12
Prioritization of installations and replacements are 13 made from information provided by Avista System 14 Operations, Operations Offices, or Substation 15 Engineering. 16 17 V. Reliability Compliance and Improvements: 18 19 Environmental Compliance – 2015: $434,000; 2016: 20 $350,000; 2017: $350,000 21
This item includes implementation of Forest Service 22
Special Use Permits, waste oil disposal, including 23 PCBs, and environmental compliance requirements 24
related to storm water management, water quality 25 protection, property cleanup and related issues. 26 27 Transmission Reconductors and Rebuilds – 2015: 28 $11,776,000; 2016: $21,161,000; 2017: $18,327,000 29
This program reconductors and/or rebuilds existing 30 transmission or distribution lines as they reach the 31 end of their useful lives, require increased 32
capacity, or present a risk management issue. 33 Projects include: ER 2310 - West Plains Transmission 34
Reinforcement (Garden Springs-Sunset Rebuild), ER 35 2550 - Pine Creek-Burke-Thompson, ER 2557 - 9CE-36 Sunset Rebuild, ER 2423-System Condition Rebuild 37 (Bronx-Cabinet Rebuild), ER 2457 -Benton-Othello 38 Rebuild, ER 2564 - Devils Gap-Lind Structure 39
Replacement, ER 2574-Chelan-Stratford River Crossing 40 Rebuild, ER 2577-BEN-M23 Structure Replacement. 41 42
O&M Offsets exist for several items included in this 43 project. To calculate the amount of savings to be 44
reflected in our rate year, reduced line losses are 45 multiplied against the avoided energy cost of $44 per 46 MWh to arrive at the total energy savings. 47
Cox, Di Page 36 Avista Corporation

Benton-Othello 115 will experience an incremental 1 reduction in line losses of 225 MWh in both 2015 and 2
2016 – 450 MWh total. After applying the avoided 3 energy cost per MWh of $44, this equates to $19,800 4 ($6,990 Idaho) of total offsets on a system basis. 5 6 Bronx-Cabinet will experience incremental reductions 7
in line losses of 755 MWh in both 2015 and 2016 8 (1,510 total). This equates to total offsets of 9 $66,440 on a system level ($23,450 Idaho Electric). 10
Q. Please describe each of the distribution 11
projects planned for January 1, 2015 through 12
December 31, 2017. 13
A. Distribution specific projects in Idaho are 14
necessary to meet capacity needs of the system, improve 15
reliability, and rebuild aging distribution substations 16
and feeders. The major capital distribution costs for 17
projects to be completed from January 1, 2015 to December 18
31, 2017 are shown in Table No. 4 and described below. 19
Cox, Di Page 37 Avista Corporation

1
2
3
4
5
6
7
8
9
10
11
12
I. Distribution Projects: 13
Distribution Grid Modernization – Idaho - 2015: 14 $10,114,000; 2016: $6,300,000; 2017: $10,300,000 15 In 2012, Avista began a program to upgrade 16
distribution feeders to reduce energy losses, improve 17 operation of the feeders and increase long-term 18 reliability. The program will replace poles, 19
transformers, conductors and other equipment on rural 20 and urban feeders. As part of the work, elements of 21
Avista’s Smart Grid will be installed as appropriate 22 on these feeders. Electric circuits are selected 23 based on a selection criteria including: 1) age of 24 asset, 2) opportunity for line loss savings, 3) 25 outage/reliability metrics, 4) opportunity for 26
automation to increase efficiency and reliability and 27 5) workforce resource availability. Once selected, 28 circuits are analyzed by engineering staff to 29
determine the scope of work including structure 30 replacement, line reroutes, conversion from overhead 31
to underground, automation scheme, transformer & 32 equipment replacement, and reconductor segments. 33 This program along with other asset management 34
System ID
ID Savings/(Costs)System ID
ID Savings/(Costs)System ID
I. Distribution Projects:
Total Distribution Projects 43,090 17,051 - 36,409 13,345 (34) 40,826 17,740
II. Distribution Replacement Projects
Total Distribution Replacement Projects 25,367 8,047 165 23,959 8,819 (193) 21,440 7,724
Total Distribution Idaho Distribution 68,457$ 25,098$ 165$ 60,368$ 22,165$ (227)$ 62,266$ 25,464$
TABLE NO. 4Electric Distribution
2015 2016 2017
Cox, Di Page 38 Avista Corporation

programs, uses the Distribution Feeder Management 1 Plan to provide direction and guidance to designers 2
and construction personnel. 3 4 Distribution Wood Pole Management – Idaho - 2015: 5 $3,011,000; 2016: $3,011,000; 2017: $3,289,000 6
The distribution wood pole management program 7
evaluates wood pole strength of 5% of the wood pole 8 population each year such that the entire system is 9 inspected every 20 years. Avista has approximately 10
237,000 distribution wood poles and 33,000 11 transmission wood poles in its electric system. 12
Depending on the test results for a given pole, the 13 pole is either considered satisfactory, needing to be 14 reinforced with a steel stub, or needing to be 15 replaced. In addition to pole condition and 16 strength, inspection crews inspect crossarms, 17
insulators, transformers, guy wires, ground and 18 bonding wires, and primary and secondary conductors. 19
This project also funds the work required to resolve 20 those issues (i.e., potentially leaking transformers, 21 transformers containing more than or equal to 1 ppm 22
polychlorinated biphenyls (PCBs), failed arresters 23 and other visible issues). Transformers older than 24
1981 have the potential to have oil that contains 25 polychlorinated biphenyls (PCBs). These older 26 transformers present increased risk because of the 27
potential to leak oil that contains PCBs. Pre-81 28 transformers are replaced if the pole is replaced. 29
In 2017 WPM will begin to replace all pre-81 30 transformers regardless of whether the pole needs to 31 be replaced. Poles installed during the pre-World 32
War II buildup have reached the end of their useful 33 lives. Avista’s Wood Pole Management program was put 34
into place to prevent the Pole-Rotten events and 35 Crossarm – Rotten events from increasing. The 36 Company estimates the cost of an event associated 37 with a bad wood pole based on crew response and labor 38 is approximately $600. For 2016 we anticipate a 39
reduction of 110 events. We estimate that the O&M 40 offset for 2016 due to Wood Pole Management work is 41 $66,000. This translates to an Idaho offset of 42
$23,000. 43
Cox, Di Page 39 Avista Corporation

Meter Minor Blanket – Idaho – 2015: $1,121,000; 2016: 1 $1,121,000; 2017: $971,000 2
The existing power line carrier system for reading 3 meters has failed and is not repairable. This 4 project will replace the existing TURTLE meters with 5 TWACs meters and replace substation equipment with 6 TWACs equipment. 7 8 Segment Reconductor and Feeder Tie program – Idaho - 9 2015: $1,017,000; 2016: $1,562,000; 2017: $1,141,000 10
This project improves the capacity and reliability of 11 the Company’s distribution grid through targeted 12
reconductoring/rebuild projects. In Idaho, there are 13 thirteen (13) projects. These projects are 14 identified, prioritized, and coordinated through the 15 combined effort of Avista’s central system planning 16 function together with the assistance of regional 17
operating engineer analysis and study. This is an 18 on-going effort to identify and mitigate the capacity 19
constrained portions of Avista’s 18,000 mile 20 distribution grid. In addition to circuit capacity 21 projects, Avista constructs several new feeder tie 22
points annually in order to effect seasonal and or 23 permanent load shifts from either heavily loaded 24
circuits or to relieve substation transformer 25 loading. 26 27 Substation Asset Management Capital Maintenance – 28 Idaho - 2015: $935,000; 2016: $530,000; 2017: 29 $541,000 30 Avista has several different equipment replacement 31 programs to improve reliability by replacing aged 32
equipment that is beyond its useful life. These 33 programs include transmission air switch upgrades, 34
restoration of substation rock and fencing, recloser 35 replacements, replacement of obsolete circuit 36 switchers, substation battery replacement, meter 37 replacements and upgrades, relay replacements, high 38 voltage fuse upgrades, transformer replacements, 39
breaker replacements, installation of diagnostic 40 monitors, substation air switch replacements, and 41 voltage regulator replacements. All of these 42
individual projects improve system reliability and 43 customer service. The equipment is replaced when its 44
useful life has been exceeded. The System-Install 45 Autotransformer Diagnostic Monitor program is one of 46 the projects included in Substation Asset Management 47
Cox, Di Page 40 Avista Corporation

Capital Maintenance. This program includes 1 additional incremental costs in 2016 of $162,000, of 2
which $57,000 is Idaho’s share. This amount is the 3 net of additional potential O&M costs of $170,300 4 less the positional annual O&M savings of $8,217. 5 These additional O&M Costs have been included in the 6 Company’s O&M Offset adjustment. 7 8 Substation – Capital Spares – Idaho - 2015: $115,000; 9 2016: $115,000; 2017: $76,000 10
This program maintains our fleet of Power 11 Transformers and High Voltage Circuit Breakers. This 12
fleet of critical apparatus is capitalized upon 13 receipt and placed in service for both planned and 14 emergency installations as required. The annual 15 program expenditures may vary significantly in years 16 when an Autotransformer (230/115 kV) is purchased. 17
In years without an Autotransformer purchase, only 18 minor variations will occur based on planned projects 19
as well as replenishing apparatus fleet levels 20 required for adequate capital spares. Acquisition of 21 these capital items requires long lead times, so 22
sufficient levels of safety-stock must be maintained 23 to avoid service interruptions. 24
25 Substation – New Distribution Stations – Idaho - 26 2015: $0; 2016: $9,000; 2017: $723,000 27
This program adds new distribution substations to the 28 system in order to serve new and growing load as well 29
as for increased system reliability and operational 30 flexibility. New substations under this program will 31 require planning and operational studies, 32
justifications, and approved project diagrams prior 33 to funding. Planned new substation projects include 34
Tamarack (NE Moscow), Greenacres and Irvin (Spokane 35 Valley), and Lewiston Mill Road. 36 37 Worst Feeders – Idaho - 2015: $739,000; 2016: 38 $698,000; 2017: $698,000 39
In 2009 Avista initiated a program to target the 40 reinforcement of the most underperforming electric 41 circuits. This program is coordinated with regional 42
engineers and focus treatment on those feeders (FDRs) 43 whose sustained outage statistics (SAIFI) and 44
customer experiencing multiple interruption (CEMI) 45 are at the top of the ‘worst performing FDR list’. 46 Most of these circuits are rural in nature and many 47
Cox, Di Page 41 Avista Corporation

involve dozens of miles of tree/forest exposed line 1 routes. In 2015, the circuits served from Gifford, 2
Colville, and Roxboro will be targeted for 3 reliability projects. Project scope often involves 4 the installation of midline breaker devices and may 5 involve circuit hardening, conversion from overhead 6 to underground, or circuit rerouting. 7 8 II. Distribution Replacement Projects 9 10 Distribution Line Protection – Idaho - 2015; $44,000; 11 2016: $44,000; 2017: $44,000 12
Avista's Electric Distribution system is configured 13 into a trunk and lateral system. Lateral circuits 14 are protected via fuse-links and operate under fault 15 conditions to isolate the lateral in order to 16 minimize the number of affected customers in an 17
outage. Engineering recommends treatment of the 18 removal and replacement of Chance Cutouts, the 19
removal and replacement of Durabute cutouts and the 20 installation of cut-outs on un-fused lateral 21 circuits. This is a targeted program to ensure 22
adequate protection of lateral circuits and to 23 replace known defective equipment. 24 25 Distribution Minor Rebuild – Idaho - 2015: 26 $2,601,000; 2016: $2,601,000; 2017: $2,601,000 27
This program is for distribution minor rebuilds as 28 requested by the customer or initiated by Avista. 29
Examples of construction work includes replacing 30 meters, services, transformers, primary overhead or 31 underground lines, or devices. This also includes 32
addressing trouble related jobs (i.e. replacing burnt 33 or damaged poles). 34 35 Distribution Transformer Change Out Program – Idaho - 36 2015: $1,282,000; 2016: $1,282,000; 2017: $300,000 37 The Distribution Transformer Change-Out Program has 38 three main drivers. First, the pre-1981 distribution 39
transformers that are targeted for replacement 40 average 42 years of age and are a minimum of 30 years 41 old. Their replacement will increase the reliability 42
and availability of the system. Secondly, the 43 transformers to be replaced are inefficient compared 44
to current standards. Thirdly, pre-1981 transformers 45 have the potential to have oil containing PCBs. The 46 transformers to be removed early in the programs are 47
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those that are most likely to have PCBs in the oil 1 and their replacement will reduce the risk of oil 2
spills containing PCBs. 3 4 Environmental Compliance – Idaho - 2015: $41,000; 5 2016: $41,000; 2017: $0 6
This item includes implementation of Forest Service 7
Special Use Permits, waste oil disposal, including 8 PCBs, and environmental compliance requirements 9 related to storm water management, water quality 10
protection, property cleanup and related issues. 11 12 Electric Replacement/Relocation – Idaho - 2015: 13 $1,479,000; 2016: $1,479,000; 2017: $1,479,000 14
This annual program will replace sections of existing 15 infrastructure that require replacement due to 16 relocation or improvement of streets or highways. 17
Requirements may come from our franchise agreements, 18 permits, or the Idaho Transportation Department. 19
Avista installs many of its facilities in public 20 right-of-way under established franchise agreements. 21 Avista is required under the franchise agreements, in 22
most cases, to relocate its facilities when they are 23 in conflict with road or highway improvements. 24 25 Primary URD Cable Replacement – Idaho - 2015: 26 $800,000; 2016: $0; 2017: $0 27
This program involves replacing the first generation 28 of Underground Residential District (URD) cable. 29
This project has been ongoing for the past several 30 years and focuses on replacing a vintage and type of 31 cable that has reached its end of life and 32
contributes significantly to URD cable failures. The 33 Company estimates the cost of each underground outage 34
to be $3,850. With the downward trend in underground 35 outages, it is projected that 45 outages will occur 36 in 2015, as compared to 72 in 2012. A five year plan 37 to inspect and maintain our padmount equipment will 38 add $800,000 per year to O&M spending for the first 39
five years. Idaho’s allocation of these additional 40 O&M costs is $282,000 in 2016. These additional 41 costs have been included in the Company’s O&M Offset 42
adjustment. 43
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Reconductors and Rebuilds – Idaho - 2015: $1,009,000; 1 2016: $872,000; 2017: $872,000 2
This program reconductors and/or rebuilds existing 3 transmission or distribution lines as they reach the 4 end of their useful lives, require increased 5 capacity, or present a risk management issue. 6 Projects include: ER 2310 - West Plains Transmission 7
Reinforcement, ER 2550 - Pine Creek-Burke-Thompson, 8 ER 2557 - 9CE-Sunset Rebuild, ER 2423 - System 9 Condition Rebuild, ER 2457 - Benton-Othello Rebuild, 10
ER2556 - CDA-Pine Creek Rebuild, ER 2564 - Devils 11 Gap-Lind Major Rebuild, ER 2574 - Chelan-Stratford 12
River Crossing Rebuild, ER 2576 - Addy-Devils Gap 13 Reconductor, ER 2575 - Garden Springs-Silver Lake 14 Rebuild, ER 2582 - BEA-BEL-F&C-WAI Reconfiguration, 15 and ER 2577 - BEN-M23 Rebuild. 16 17 Storms – Idaho - 2015: $539,000; 2016: $512,000; 18 2017: $539,000 19
Weather events associated with wind, lightning, rain, 20 and snow create a number of outage situations. This 21 program addresses these outage situations. Estimated 22
capital spend is based on historical averages. 23 24 Substation – Distribution Station Rebuilds – Idaho -25 2015: $119,000; 2016: $1,797,000; 2017: $1,697,000 26
This program replaces and/or rebuilds existing 27
substations as they reach the end of their useful 28 lives, require increased capacity, or cannot 29
accommodate necessary equipment upgrades due to 30 existing physical constraints. Included are Wood 31 Substation rebuilds as well as upgrading stations to 32
current design and construction standards. Some 33 station rebuilds may be initiated by other 34
requirements, including obligation to serve, growth, 35 and external projects. Examples of Idaho substation 36 rebuilds to be completed under this program in the 37 next five years are Big Creek, South Lewiston and 38 Kamiah. 39 40 Street Light Management – Idaho - 2015: $133,000; 41 2016: $191,000; 2017: $191,000 42
This program is a five year planned replacement of 43 fixtures and 10 year planned replacement of 44
photocells. We anticipate there will be O&M savings 45 in 2015 of $468,000 ($165,000 ID) and an additional 46 offset in 2016 of $254,000 ($90,000 ID), resulting in 47
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a total offset of $722,000 ($255,000 ID). The 1 offsets result from the conversion to 100 Watt street 2
lights from High Pressure Sodium. The savings come 3 from eliminating the labor, equipment, material, and 4 overhead costs associated with repairing older 5 lights. 6
Q. Does this complete your pre-filed direct 7
testimony? 8
A. Yes it does. 9
Cox, Di Page 45 Avista Corporation