20160526Cox 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-16-03
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) DIRECT TESTIMONY
TO ELECTRIC CUSTOMERS IN THE ) OF
STATE OF IDAHO ) BRYAN A. COX
)

FOR AVISTA CORPORATION

(ELECTRIC)

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Avista Corporation
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 Avista
Corporation as Director, Transmission and Operations West. My
business address is 1411 East Mission, Spokane, Washington.
Q. Please briefly describe your educational background 7
and professional experience.
A. I am a 1992 graduate of Gonzaga University with a
degree in Mathematics and a 2009 graduate of the University of
Washington’s Foster School of Business with a Masters Degree in
Business Administration. I joined the Company in 1997 and have
spent 18 years in various technical and leadership positions in
Information Technology, Natural Gas Delivery, Strategic
Planning and Gas and Electric Construction Services. Over the
last two years I have led the West Electric Operations group
which delivers service to most of our Washington operations as
well as more recently the System Operations Department. I am
a member of the Capital Planning Group that manages the five
year Company capital budget.
Q. What is the scope of your testimony? 21
A. My testimony presents Avista’s transmission revenues
and expenses for the 2017 rate year. I also discuss Avista’s

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Transmission capital expenditures, for the period January 1,
2016 through the 2017 rate year.
A table of contents for my testimony is as follows:
Description Page
I. Introduction 1
II. Transmission Expenses for 2017 2
III. Transmission Revenue for 2017 9
IV. Transmission Capital Projects 22
9
Q. Are you sponsoring any exhibits? 10
A. Yes. I am sponsoring Exhibit No. 8, Schedule 1,
prepared under my direction, which provides the transmission
revenue and expense adjustment.

II. TRANSMISSION EXPENSES FOR 2017 15
Q. Please describe the adjustments to the twelve months 16
ended December 31, 2015 test year transmission expenses to 17
arrive at transmission expenses for the 2017 rate year. 18
A. Adjustments were made in this filing to incorporate
updated information for any changes in transmission expenses
from the January 2015 through December 2015 test period to the
2017 rate year. The changes in system expenses and a
description of each is summarized in Table No. 1. An
explanation of each change follows Table No. 1.

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Avista Corporation
*2017 Rate Year
Description:(System 000's)
Northwest Power Pool $6,000
Colstrip Transmission 7,000
ColumbiaGrid 60,000
ColumbiaGrid Transmission Planning 32,000
ColumbiaGrid Order 1000 Functional Agreement 25,000
NERC Critical Infrastructure Protection 5,000
OASIS Expenses 0
PEAK Reliability – Reliability Coordination 214,000
WECC – Administration Dues 12,000
WECC – Loop Flow 2,000
Addy Substation 0
Hatwai Substation 0
Total Change in Transmission Expenses $363,000
TABLE NO. 1
Transmission Expense Adjustment
*Represents the change in expense above or below the 2015 historical test year level.

Northwest Power Pool (NWPP) ($6,000): Avista pays its share of
the NWPP operating costs. The NWPP serves the electric
utilities in the Northwest by facilitating coordinated power
system operations and planning, including contingency
generation reserve sharing, Columbia River water coordination
and providing support to coordinated regional transmission
planning. Avista’s share of the costs for 2017 is $67,000, an
increase of $6,000 over the 2015 test period. The increase in
expense is primarily related to increased labor analytical
support required in the development of new standards intended
to provide consistency in operations between various states in
our region.

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Avista Corporation
Colstrip Transmission ($7,000): Avista is required to pay its
portion of the O&M costs associated with its joint ownership
share of the Colstrip transmission system pursuant to the
Colstrip Transmission Agreement. Under this agreement,
NorthWestern Energy (NWE) operates and maintains the Colstrip
transmission system. In accordance with NWE’s proposed 6
Colstrip transmission plan provided to the Company, NWE will
bill Avista an estimated $312,000 for Avista’s share of the 8
Colstrip O&M expense during the 2017 rate year. This is an
increase of $7,000 from the actual expense of $305,000 incurred
during the 2015 test period.
ColumbiaGrid ($60,000): Avista became a member of the
ColumbiaGrid regional transmission organization in 2006.
ColumbiaGrid’s purpose is to enhance transmission system 14
reliability and efficiency, provide cost-effective coordinated
regional transmission planning, develop and facilitate the
implementation of solutions relating to improved use and
expansion of the interconnected Northwest transmission system,
and support effective market monitoring within the Northwest
and the entire Western interconnection. Avista supports
ColumbiaGrid’s general developmental and regional coordination 21
activities under the ColumbiaGrid Funding Agreement and
supports specific functional activities under the Planning and

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Avista Corporation
Expansion Functional Agreement and the FERC Order 1000
Functional Agreement. Avista’s ColumbiaGrid general funding 2
expenses for the 2015 test period were $82,000 while 2017 rate
year general funding expenses are planned to be $142,000. This
increase is primarily due to an increase in labor expenses due
to organizational changes and filling of previously open
positions.
ColumbiaGrid Transmission Planning ($32,000): The ColumbiaGrid
Planning and Expansion Functional Agreement (PEFA) was accepted
by the Federal Energy Regulatory Commission (FERC) on April 3,
2007, and Avista entered into the PEFA on April 4, 2007.
Coordinated transmission planning activities under the PEFA
allow the Company to meet its coordinated regional transmission
planning requirements set forth in FERC Order 890 issued in
February 2007, and as outlined in the Company’s Open Access 15
Transmission Tariff. Actual PEFA expenses for the 2015 test
period were $141,000. The Company’s PEFA expenses for 2017 are 17
$173,000, reflecting ColumbiaGrid’s staffing levels to support 18
the PEFA.
ColumbiaGrid Order 1000 Functional Agreement ($25,000): FERC
Order 1000 requirements are implemented under the Amended and
Restated Order 1000 Functional Agreement, signed on November
11, 2014 (Order 1000 Agreement). This contract called for a

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Avista Corporation
$50,000 payment late in 2014 that covered two years of payments
for 2015 and 2016. Beginning in 2017, this contract calls for
an annual payment of $25,000.
NERC Critical Infrastructure Protection ($5,000): The Company
has purchased several software and hardware products to assist
in protecting critical transmission control systems from
intrusion and to meet applicable NERC standards. These products
provide for physical security, intrusion detection, virus
protection and vulnerability assessment. The Company’s NERC 9
CIP expenses for 2017 are $75,000, an increase of $5,000 from
the 2015 test period actual expenses of $70,000.
OASIS Expenses ($0): These Open Access Same-time Information
System (OASIS) expenses are associated with travel and training
costs for transmission pre-scheduling and OASIS personnel.
This travel is required to monitor and adhere to NERC
reliability standards, regional criteria development, FERC
OASIS requirements and OASIS user group forums with software
vendor OATI. Issues regarding the software are discussed and
requests are made with the vendor for additional features that
will be needed for compliance standards mandated by NERC, NAESB
and FERC. Expenses during the 2015 test period were $15,000
and these are expected to remain unchanged for the 2017 rate
year.

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Peak Reliability – Reliability Coordination ($214,000): The
Company’s Peak Reliability (PEAK) fees are scheduled to 2
increase from the amount paid in the historical test period of
$484,000 to $698,000 in the 2017 rate year. PEAK was formed in
response to the FERC requirement that the western
interconnection reliability coordination function be
corporately and physically separated from other WECC functions.
This “bifurcation” was primarily the result of a transmission 8
system outage in the Pacific Southwest on September 8, 2011. A
reference to the disturbance including “Causes and 10
Recommendations” may be found at:
http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-
report.pdf. PEAK’s budget is approved by its independent board 13
of directors and is allocated to the members of PEAK based upon
net energy used to serve load within a member’s balancing area. 15
Detailed allocation information is available on PEAK’s website
www.peakrc.com. The increase from the historical test period
is due largely to continued growth in staff as PEAK develops
and establishes its role as the reliability coordination
function for the Western Interconnection.
WECC – Administration Dues ($12,000): WECC is the designated
Regional Entity under federal statute responsible for
coordinating and promoting Bulk Electric System reliability

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throughout the western interconnection. WECC is responsible
for monitoring and measuring Avista’s compliance with 2
reliability standards and has substantially increased its staff
and other resources to meet these FERC requirements. The
Company’s 2015 test period WECC dues and fees were $419,000.
The Company’s total for dues and fees in the 2017 rate year are
expected to be $431,000.
WECC - Loop Flow ($2,000): Loop Flow charges are spread across
all transmission owners in the West to compensate utilities
that make system adjustments to eliminate transmission system
congestion throughout the operating year. WECC Loop Flow
charges can vary from year to year since the costs incurred are
dependent on transmission system usage and congestion. Loop
Flow expenses for the 2015 test period were $41,000. Loop Flow
expenses are estimated to be $43,000 in the 2017 rate year.
Addy Substation ($0): The Company pays operation and
maintenance fees to Bonneville associated with a 115kV circuit
breaker in Bonneville’s Addy Substation that provides a direct 18
interconnection for Avista’s retail load. In the test period
the expenses were $9,000 and these are anticipated to remain
unchanged for the 2017 rate year.
Hatwai Substation ($0): The Company pays operation and
maintenance fees to Bonneville associated with a 230kV circuit

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Avista Corporation
breaker owned by Avista but located in Bonneville’s Hatwai 1
Substation. In the test period the expenses were $23,000 and
these are expected to remain unchanged for the 2017 rate year.

III. TRANSMISSION REVENUES FOR 2017 5
Q. Please describe the adjustments to 2015 test period 6
transmission revenues to arrive at transmission revenues for 7
the 2017 rate year. 8
A. Adjustments have been made in this filing to
incorporate updated information for transmission revenue during
the 2017 rate year as compared to the 2015 historical test
period. Each revenue item described below is at a system level
and is included in Exhibit No. 8, Schedule 1. Table No. 2 below
provides a summary of the changes in transmission revenues, and
an explanation of each change follows Table No. 2.

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Avista Corporation
*2017 Rate Year
Description:(System 000's)
Borderline Wheeling: Transmission, Low Voltage &
Ancillary Services $760,000
OASIS nf & stf Whl (Other Whl)(652,000)
Seattle Tacoma – Main Canal (3,000)
Seattle Tacoma – Summer Falls 0
PacificCorp Dry Gulch (15,000)
Spokane Waste to Energy 0
Columbia Basin Hydropower (formerly Grand Coulee
Project)0
First Wind (200,000)
Palouse Wind 0
Stimson Lumber 0
Hydro Tech Systems – Meyers Falls 0
BPA Parallel Operating Agreement 0
Morgan Stanley Capital Group 0
Kootenai Electric 0
Total Change in Transmission Revenues ($110,000)
Transmission Revenue Adjustment
*Represents the change in revenue above or below the 2015 historical test year level.
TABLE NO. 2

Borderline Wheeling – ($760,000)
 Borderline Wheeling Transmission ($20,000) – The Company
provides borderline wheeling service (wheeling service over
transmission and low-voltage distribution facilities for
service to loads of other utilities within the Company’s 17
transmission system footprint) to the Bonneville Power
Administration (BPA), Consolidated Irrigation District, East
Greenacres Irrigation District, Spokane Tribe of Indians and
Grant County PUD (transmission only). Total revenue for the
transmission portion of borderline wheeling activities for the
2015 test period was $6,233,000. Total revenue in the 2017

Cox, Di Page 11
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rate year has been estimated at $6,253,000, representing an
increase of $20,000 from the test period. Revenue estimates
for each transmission customer are determined as follows:
o Bonneville Power Administration – Network Integration
Transmission Service revenue is estimated based upon a
three-year average for the 2013 to 2015 time period,
resulting in a figure of $6,153,000 for the 2017 rate
year compared to $6,134,000 for the 2015 test period.
The three-year average (2013 – 2015) is consistent with
the three-year average used in all other instances where
the Company estimates transmission revenues that are
based upon variable customer load figures (e.g. Grant
County PUD and PacifiCorp Dry Gulch), and is consistent
with Case No. AVU-E-15-05.
o Grant County PUD – Power Transfer Agreement revenue is
estimated using a three-year average (2013-2015)
resulting in a figure of $28,000 for the 2017 rate year
compared to $28,000 for the 2015 test period.
o Consolidated Irrigation District – Point-to-Point
Transmission Service revenue for the 2015 test period was
$32,000. The current contract will expire on September
30, 2016 but a follow-on contract is expected to be in

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place resulting in revenue that is expected to remain
substantially unchanged during the 2017 rate year.
o East Greenacres Irrigation District – Point-to-Point
Transmission Service revenue for the 2015 test period was
$11,000. Under the current contract (with a term through
September 30, 2019) this revenue is expected to remain
unchanged for the 2017 rate year.
o Spokane Tribe – Point-to-Point Transmission Service
revenue for the 2015 test period was $28,000. Under the
current contract (with a term through December 31, 2019)
this revenue is expected to be $29,000 for the 2017 rate
year.
 Borderline Wheeling – Low Voltage ($736,000) – Total
revenues for the low voltage portion of borderline wheeling
activities for the 2015 test period was $1,079,000. Total
revenue in the 2017 rate year has been estimated to increase
$736,000 to $1,815,000. The increase is primarily due to
increased low voltage charges to BPA, effective May 1, 2016,
that are mostly attributable to modernizing substation
facilities. Revenue estimates for each transmission customer
are as follows:
o Bonneville Power Administration – Wheeling revenue over
low-voltage facilities for the 2015 test period was

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Avista Corporation
$928,000. Revenue for the 2017 rate year is expected to
be $1,664,000.
o Consolidated Irrigation District – Electric Distribution
Service revenue for the 2015 test period was $80,000.
The current contract will expire September 30, 2016 but
a follow-on contract is expected to be in place resulting
in revenue that is expected to remain substantially
unchanged during the 2017 rate year.
o East Greenacres Irrigation District – Electric
Distribution Service revenue for the 2015 test period was
$51,000. Under the current contract (with a term through
September 30, 2019) this revenue is expected to remain
unchanged for the 2017 rate year.
o Spokane Tribe – Electric Distribution Service revenue for
the 2015 test period was $20,000. Under the current
contract (with a term through December 31, 2019) this
revenue is expected to remain unchanged for the 2017 rate
year.
 Borderline Wheeling – Ancillary Services ($4,000) – The
Company provides various ancillary services in association with
long-term firm transmission service provided under its Open
Access Transmission Tariff. Ancillary services revenue for the
2015 test period was $1,618,000. Revenue in the 2017 rate year

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Avista Corporation
has been set at $1,622,000, representing an increase of $4,000
from the test period. Ancillary services are necessary to
support the transmission of electric power from one point to
another given the obligations of balancing areas and
transmitting utilities within those balancing areas to maintain
reliable operation of the interconnected transmission system.
The revenue estimate is based upon an ancillary services rate
of $8.94 per kW multiplied by billing determinants of 2%
(regulation and frequency response), 1.5% (Operating Reserves
– Spinning) and 1.5% (Operating Reserves – Supplemental),
applied to a three-year average of a customer’s monthly peak 11
loads. Revenue estimates for each transmission customer are as
follows:
o Bonneville Power Administration – Using three-year
average load figures for the 2013-2015 time period,
ancillary services revenue is estimated to be $1,606,000
for the 2017 rate year compared to $1,602,000 for the
2015 test period.
o Consolidated Irrigation District – Using three-year
average load figures for the 2013-2015 time period,
ancillary services revenue is estimated to be $6,500 for
the 2017 rate year compared to $6,500 for the 2015 test
period.

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Avista Corporation
o East Greenacres Irrigation District – Using three-year
average load figures for the 2013-2015 time period,
ancillary services revenue is estimated to be $4,700 for
the 2017 rate year compared to $4,400 for the 2015 test
period.
o Spokane Tribe – Using three-year average load figures for
the 2015 time period, ancillary services revenue is
estimated to be $4,700 for the 2017 rate year compared
to $4,800 for the 2015 test period.
OASIS Non-Firm and Short-Term Firm Transmission Service 10
(-$652,000): OASIS is an acronym for Open Access Same-time
Information System. This is the system used by electric
transmission providers for selling available transmission
capacity to eligible customers. The terms and conditions under
which the Company sells its transmission capacity via its OASIS
are pursuant to FERC regulations and Avista’s Open Access 16
Transmission Tariff. The Company calculates its rate year
adjustments using a three-year average of actual OASIS Non-Firm
and Short-Term Firm revenue consistent with Case No. AVU-E-15-
05. OASIS transmission revenue may vary significantly
depending upon a number of factors, including current wholesale
power market conditions, forced or planned generation resource
outage situations in the region, the current load-resource

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Avista Corporation
balance status of regional load-serving entities, and the
availability of parallel transmission paths for prospective
transmission customers. The use of a three-year average is
intended to strike a balance in mitigating both long-term and
short-term impacts to OASIS revenue. A three-year period is
intended to be long enough to mitigate the impacts of non-
substantial temporary operational conditions (for generation
and transmission) that may occur during a given year, and short-
enough so as to not dilute the impacts of long-term transmission
and generation topography changes (e.g., major transmission
projects which may impact the availability of the Company’s 11
transmission capacity or competing transmission paths, and
major generation projects which may impact the load-resource
balance needs of prospective transmission customers). However,
if there are known events or factors that occurred during the
period that would cause the average to not be representative of
future expectations, then adjustments may be made to the three-
year average methodology. In this filing, the Company is using
a three year average for the time period of January 2013 to
December 2015. The OASIS revenue for the 2015 test period was
$3.479 million and the three-year average results in 2017 rate
year revenue of $2.827 million. Variation in year-to-year
revenue, even when using a three-year average, is due to a

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Avista Corporation
number of factors that include outages on surrounding
transmission systems, the duration and timing of the spring
runoff, and the level of activity in the surrounding power
markets. OASIS revenue in 2015, driven solely by short term
purchases on the Avista Transmission System, was primarily due
to a long duration outage on the BPA transmission system during
2015 and a larger than normal amount of purchases in 2015 as a
result of a good water year in the region. 8
Seattle and Tacoma – Main Canal Project ($-3,000): Effective
March 1, 2008, and continuing through October 31, 2026, the
Company entered into long-term point-to-point transmission
service arrangements with the City of Seattle and the City of
Tacoma to transfer output from the Main Canal hydroelectric
project, net of local Grant County PUD load service, to the
Company’s transmission interconnections with Grant County PUD. 15
Service is provided during the eight months of the year (March
through October) in which the Main Canal project operates, and
the agreements include a three-year ratchet demand provision.
Both contracts run to October 31, 2026. Revenues under these
agreements totaled $361,000 during the test period and are
expected to $358,000 for the 2017 rate year.
Seattle and Tacoma – Summer Falls Project ($0): Effective March
1, 2008, and continuing through October 31, 2024, the Company

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entered into long-term use-of-facilities arrangements with the
City of Seattle and the City of Tacoma to transfer output from
the Summer Falls hydroelectric project across the Company’s 3
Stratford Switching Station facilities to the Company’s 4
Stratford interconnection with Grant County PUD. Charges under
these use-of-facilities arrangements are based upon the
Company’s investment in its Stratford Switching Station and are 7
not impacted by the Company’s transmission service rates under 8
its Open Access Transmission Tariff. Revenues under these two
contracts totaled $74,000 in the 2015 test period and are
expected to remain unchanged for the 2017 rate year.
PacifiCorp Dry Gulch (-$15,000): Revenue under the Dry Gulch
use-of-facilities agreement has been adjusted to $230,000 for
the 2017 rate year, which is an $15,000 decrease from the 2015
test period actual revenue of $245,000. The Company is
calculating its adjustment using a three-year average of actual
revenue. Revenue under the Dry Gulch Transmission and
Interconnection Agreement with PacifiCorp varies depending upon
PacifiCorp’s loads served via the Dry Gulch Interconnection and 19
the operating conditions of PacifiCorp’s transmission system in 20
this area. The use of a three-year average is intended to
mitigate the impacts of potential annual variability in the
revenues under the contract. The contract includes a twelve-

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Avista Corporation
month rolling ratchet demand provision and charges under this
agreement are not impacted by the Company’s open access 2
transmission service tariff rates.
Spokane Waste to Energy Plant ($0): Spokane Waste to Energy
pays a use-of-facilities charge for the ongoing use of its
interconnection to Avista’s transmission system. The 2017 rate
year revenue associated with the use-of-facilities charge is
$28,000, the same as the 2015 test period.
Columbia Basin Hydropower ($0): The Company provides operations
and maintenance services on the Stratford-Summer Falls 115kV
Transmission Line to the Columbia Basin Hydropower (formerly
the Grand Coulee Project Hydroelectric Authority) under a
contract signed in March 2006. These services are provided for
a fixed annual fee. Annual charges under this contract totaled
$8,100 in the 2015 test period and will remain the same for the
2017 rate year.
First Wind (-$200,000): First Wind signed a transmission
service contract with the Company based on its initial intent
to sell the output from a wind facility to an entity other than
Avista. Avista has since signed a power purchase agreement
with First Wind which eliminated First Wind’s need for
transmission service. First Wind has delayed its use of the
100 MW of reserved transmission service up to the maximum of

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Avista Corporation
five years. Unless First Wind develops another generation
project or is able to re-market the capacity, Avista expects
this agreement to be terminated during 2016. The 2015 test
period included a $200,000 extension of service payment. No
revenue associated with this agreement is expected during the
2017 rate year.
Palouse Wind O&M ($0): Per Avista’s interconnection agreement 7
with the Palouse Wind project, the interconnection customer
pays O&M fees associated with directly-assigned interconnection
facilities owned and operated by Avista. O&M revenue for the
2015 test year was $52,000. Revenue during the 2017 rate year
is expected to remain unchanged.
Stimson Lumber Agreement ($0): Low-voltage facilities
associated with the Company’s Plummer Substation are dedicated 14
for use by Stimson Lumber resulting in low voltage use-of-
facilities revenue of $9,000 during the 2015 test period. The
2017 rate year revenue from this agreement is also $9,000.
Hydro Tech Systems Agreement ($0): Low-voltage facilities in
the Company’s Greenwood Substation are dedicated for use by the 19
Meyers Falls generation project resulting in low voltage use-
of-facilities revenue of $6,000 during the 2015 test period.
Revenue during the 2017 rate year is expected to remain
unchanged.

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Bonneville Power Administration – Parallel Capacity Support
($0): Avista and Bonneville executed a Parallel Operation
Agreement on December 12, 2012, wherein Avista provides
Bonneville with parallel transmission capacity in support of
Bonneville’s integration of several wind resource projects.
Avista provides ongoing parallel capacity support under the
agreement at a monthly charge of $266,000. Revenue for the
2015 test period was $3,192,000. Bonneville has indicated its
intent to construct additional transmission facilities to
bypass Avista’s system and terminate this agreement. The
likelihood of this bypass, and its timing, is uncertain. The
2017 rate year reflects the same revenue of $3,192,000.
Morgan Stanley – Point-to-Point Transmission Service ($0):
Morgan Stanley Capital Group has purchased 25 MW of Long-Term
Firm Point-to-Point Transmission Service from January 1, 2013
to December 31, 2017. The 2015 test period revenues were
$600,000 and will remain unchanged for the 2017 rate year.
Kootenai Electric Cooperative Fighting Creek (KEC) ($0): KEC
has purchased 3 MW of Long-Term Firm Point-to-Point
Transmission Service from April 1, 2014 to March 31, 2019. The
2015 test period included revenues of $88,000 that will remained
unchanged for the 2017 rate year. 22

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IV. TRANSMISSION CAPITAL PROJECTS 1
Q. Please discuss the drivers for the Company’s capital 2
transmission projects that will be completed from January 1, 3
2016 through December 31, 2017. 4
A. Avista continuously needs to invest in its
transmission system in order to maintain reliable customer
service and meet mandatory compliance and reliability
standards. To accomplish this, the Company plans for and
undertakes construction projects that will replace aging
equipment that is anticipated to fail, replace broken
equipment, or make improvements that will maintain or improve
reliability for the Company’s various customers and allow the 12
Company to meet compliance requirements.
Compliance requirements are driven by the North American
Electric Reliability Corporation’s (NERC) standards. These are
national standards that utilities must meet to ensure
interconnected system reliability. Compliance with these
standards was made mandatory beginning June 2007 and failure to
meet the requirements set forth by the standards could result
in monetary penalties of up to $1 million per day per
infraction. The majority of the reliability standards pertain
to transmission planning, operations and equipment maintenance.
The standards require utilities to plan and operate their

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Avista Corporation
transmission systems in such a way as to avoid customers
experiencing outages or adversely impacting neighboring utility
systems due to the loss of transmission facilities. The
transmission system must be designed so that the loss of up to
two facilities simultaneously will not impact the
interconnected transmission system. Further, the transmission
system must be operated at all times such that a loss of a
facility will not result in a System Operating Limit exceedance
(voltage, thermal or stability limit). If such an exceedance
occurs, it must be mitigated prior to the loss of the next
facility. The mitigation efforts can include system
configuration changes, generation changes or the removal of
firm load from the transmission system. The requirement to
meet the standards and avoid failing to meet the requirements
as well as not exceeding System Operation Limits drive the need
for Avista to continually invest in its transmission system.
Avista is required to perform system planning studies for both
the near term (1-5 years) and long term (5-10 years). If a
potential violation is observed in future years’ system 19
planning, then Avista must develop a project plan to ensure
that the violation is fixed prior to it becoming a real-time
operating issue. Planning for the future projects includes
attempts to ensure that the design and construction of the

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projects required to eliminate the potential violation are
completed prior to the time they are needed. Avista continues
to have a need to develop these compliance related projects as
system load grows, new generation is interconnected (including
wind and solar) and system functionality and usage changes.
Avista’s five year capital budget for the various 6
transmission projects is developed by taking into account
system planning studies, engineering analysis, scheduled or
anticipated planned transmission line outages and scheduled
upgrades or replacements while taking into consideration the
aforementioned compliance requirements. The larger, specific
projects that are developed through the system planning study
process typically go through a thorough internal review
including multiple stakeholder review to ensure all system
needs are adequately addressed. For the smaller specific
projects, Avista does not perform a traditional cost-benefit
analysis. Rather, projects are selected to meet specific system
needs or equipment replacement. However, both project cost and
system benefits are considered in the selection of the final
projects.
Q. Please describe each of the transmission projects 21
planned for the period January 1, 2016 to December 31, 2017. 22

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Business Case Name
2016
$ (000's)
2017
$ (000's)
Reliability Compliance Projects:
Transmission - NERC Low Priority Mitigation $ 1,675 $ 3,000
Transmission - NERC Medium Priority Mitigation 2,576 1,000
SCADA - System Operations and Backup Control Center 1,002 1,044
Environmental Compliance 50 50
Contractual Requirements:
Tribal Permits and Settlements 314 300
Colstrip Transmission 568 398
Reliability Improvements:
Noxon Switchyard Rebuild 11,500 6,700
Substation - Station Rebuilds 4,260 7,540
Westside Rebuild Phase One 2,525
South Region Voltage Control 5,000
SCADA Completion 1,000
Transmission - Reconductors and Rebuilds 17,559 20,830
Spokane Valley Transmission Reinforcement 1,340 7,200
Reliability Replacements:
Storms (Transmission)1,000 1,000
Substation - Capital Spares 5,200 4,565
Substation - Asset Mgmt. Capital Maintenance 4,100 4,100
Transmission - Asset Management 1,772 1,780
Total Planned Transmission Capital Projects $ 60,442 $ 60,507
TABLE NO. 3
Transmission Capital Projects (System)
A. The major capital transmission investment (on a
system basis) for projects to be completed from January 1,
2016 to December 31, 2017 total $121.0 million, as shown in
Table No. 3 and described below.

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Avista Corporation
I. Reliability Compliance Projects: 1

Transmission – NERC Low Priority Mitigation – 2016: 3
$1,675,000; 2017: $3,000,000
This program reconfigures insulator attachments, and/or
rebuilds existing transmission line structures, or removes
earth beneath transmission lines in order to mitigate
ratings/sag discrepancies found between "design" and
"field" conditions as determined by LiDAR survey data.
This program was undertaken in response to the October 7,
2010 North American Electric Reliability Corporations
(NERC) "NERC Alert" - Recommendation to Industry,
"Consideration of Actual Field Conditions in Determination
of Facility Ratings". This Capital Program covers
mitigation work on Avista's "Low Priority" 115 kV
transmission lines. Mitigation brings lines in compliance
with the National Electric Safety Code (NESC) minimum
clearances values.

Transmission - NERC Medium Priority Mitigation – 2016: 20
$2,576,000; 2017: $1,000,000
This program reconfigures insulator attachments, and/or
rebuilds existing transmission line structures, or removes
earth beneath transmission lines in order to mitigate
ratings/sag discrepancies found between "design" and
"field" conditions as determined by LiDAR survey data.
This program was undertaken in response to the October 7,
2010 North American Electric Reliability Corporations
(NERC) "NERC Alert" - Recommendation to Industry,
"Consideration of Actual Field Conditions in Determination
of Facility Ratings". This Capital Program covers
mitigation work on Avista's "Medium Priority" 230 kV and
115 kV transmission lines. Mitigation brings lines in
compliance with the National Electric Safety Code (NESC)
minimum clearances values.

SCADA –SOO&BUCC – 2016: $1,002,000; 2017: $1,044,000
This program replaces and/or upgrades existing electric
and gas control center telecommunications and computing
systems as they reach the end of their useful lives,
require increased capacity, or cannot accommodate
necessary equipment upgrades due to existing constraints.
Included are hardware, software, and operating system
upgrades, as well as deployment of capabilities to meet
new operational standards and requirements. Some system
upgrades may be initiated by other requirements, including

Cox, Di Page 27
Avista Corporation
NERC reliability standards, growth, and external projects
(e.g. Smart Grid). Examples of upgrades to be completed
under this program are Critical Infrastructure Protection
version 5 (NERC requirement), Gas Control Room Management
(PHMSA requirement), WECC RC Advanced Applications, and
Technology Refresh (network and storage). There are
multiple risks if these Business Case funds were not
expended. The clearest risk would be to public and
personnel safety. The control systems supported by this
Business Case provide real-time visibility, situational
awareness, and control of Avista’s electrical system. 11
Degradation of these capabilities due to lack of capacity,
capability, or aging systems would present increased
safety risk. Additionally there would be significant
compliance risk if these funds were not expended. These
control systems provide the capability required to achieve
compliance with numerous reliability standards and
requirements. For the electrical system these include the
NERC standards BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and
VAR. For the gas system these include the PHMSA “Pipeline 20
Safety: Control Room Management/Human Factors” rule (49 21
CFR Parts 192 and 195.) The expenditure of these funds is
necessary to operate Avista’s electric and gas systems in
a safe, reliable, and compliant manner.
25
Environmental Compliance – 2016: $50,000; 2017: $50,000 26
This item includes implementation of Forest Service
Special Use Permits, waste oil disposal, including PCBs
and environmental compliance requirements related to storm
water management, water quality protection property
cleanup and related issues.
32
II. Contractual Requirements: 33

Tribal Permits and Settlements – 2016: $314,000; 2017: 35
$300,000
The Company has approximately 300 right-of-way permits on
tribal reservations that need to be renewed. The costs
include labor, appraisals, field work, legal review, GIS
information, negotiations, survey (as needed), and the
actual fee for the permit.
42
Colstrip Transmission – 2016: $568,000; 2017: $398,000
As a joint owner of the Colstrip Transmission projects,
Avista pays its ownership share of all capital
improvements. Northwestern Energy either performs or

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Avista Corporation
contracts out the capital work associated with the joint
owned facilities.

III. Reliability Improvements: 4
5
Noxon Switchyard Rebuild – 2016: $11,500,000; 2017: 6
$6,700,000 7
The existing Noxon Rapids 230 kV Switchyard requires
reconstruction due to the present age and condition of the
equipment in the station. The existing bus is constructed
as a strain bus (which has suffered a number of recent
failures) and is configured as a single bus with a tie
breaker separating the East and West buses. The station
is the interconnection point of the Noxon Rapids
Hydroelectric development as well as a principal
interconnection point between Avista and BPA, and as such
is a significant asset in the reliable operation of the
Western Montana Hydro Complex. Equipment outages within
the Station (planned or unplanned) can cause significant
curtailments of the local generation output. Due to the
significance of the station, a complete rebuild will
require coordination with Avista’s Energy Resources 22
Department and neighboring utilities, primarily BPA. The
Noxon Switchyard Rebuild Project is proposed to be a
Greenfield Double Bus Double Breaker 230 kV switching
station to replace the existing Noxon Switchyard.
27
Substation – Distribution Station Rebuilds – 2016: 28
$4,260,000; 2017: $7,540,000 29
This program replaces and/or rebuilds existing substations
as they reach the end of their useful lives, require
increased capacity, or cannot accommodate necessary
equipment upgrades due to existing physical constraints.
Included are Wood Substation rebuilds as well as upgrading
stations to current design and construction standards.
Some station rebuilds may be initiated by other
requirements, including obligation to serve, growth, and
external projects. Examples of substation rebuilds to be
completed under this program in the next five years are
Kamiah (Wood Substation), 9th & Central, Gifford and
Southeast (Equipment Additions), Ford and Sprague (Service
Life Retirement) and Hallett & White (Growth).

Westside Rebuild Phase I – 2016: $2,525,000; 2017: $0 44
Phase I of this project will extend the existing Westside
Substation 115 kV and 230 kV buses to allow for a new 250

Cox, Di Page 29
Avista Corporation
MVA Autotransformer. This installation will eliminate
transformer overload contingencies in the Spokane area.
This is a three phase project to complete the remainder of
the station rebuild.

South Region Voltage Control – 2016: $5,000,000; 2017: $0 6
Avista’s south region 230 kV, primarily around Lewiston-
Clarkston, experiences excessive high voltage during light
load periods. Voltages exceed equipment ratings over 35%
of the time. Operation of equipment outside of equipment
ratings imposes potential legal and regulatory risks to
the Company on top of increasing large scale outage
possibilities. With automatic control, existing
overvoltages can be reduced, if not eliminated, on the 230
kV buses at Dry Creek, Lolo and North Lewiston as well as
Moscow and Shawnee.

SCADA Completion – 2016: $0; 2017: $1,000,000 18
This project will complete the installations of SCADA and
EMS/DMS capability to all Avista substations. This will
provide System Operations with clear visibility,
indication and control at every substation. In addition,
Grid Modernization will have the necessary communication
infrastructure for complete installation and operation on
all distribution feeders. System Planning, Asset
Management, Operations and Engineering will have real time
and historical data to support efficient, flexible and
safe operation and design of the system for the future.

Transmission Reconductors and Rebuilds – 2016: 30
$17,559,000; 2017: $20,830,000 31
This program reconductors and/or rebuilds existing
transmission lines as they reach the end of their useful
lives, require increased capacity, or present a risk
management issue. Projects include: ER 2423 – System
Transmission: Rebuild Condition; ER 2457 – Benton Othello
115 kV Recondition; ER 2550 – Burke-Thompson A&B 115kV
Transmission Rebuild Proj; ER 2556 – CDA-Pine Creek 115kV
Transmission Line: Rebuild; ER 2557 – 9CE-Sunset 115kV
Transmission Line: Rebuild; ER 2564 – Devils Gap-Lind
115kV Transmission Rebuild Proj; ER 2577 – Benewah-Moscow
230kV – Structure Replacement; ER 2576 – Addy-Devils Gap
115kV – Rec/Rbld 266 & 397 Cond; ER 2582 – Beacon-Bell-
Francis&Cdr-Waikiki 115kV – Reconfig; ER 2597 – Cabinet-
Noxon 230kV Transm Line Rebuild Project.
46

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Avista Corporation
Spokane Valley Transmission Reinforcement – 2016: 1
$1,340,000; 2017: $7,200,000 2
The Spokane Valley Transmission Reinforcement Project
includes rebuilding 4.4 miles of the Beacon - Boulder #2
115 kV Transmission Line, constructing the new Irvin
Switching Station, rebuilding 1.75 miles of the Irvin -
Opportunity 115 kV Tap, installing four 115 kV circuit
breakers at Opportunity Substation, and constructing a new
2.2 mile 115 kV transmission line from Irvin to
Millwood/Inland Empire Paper. The completion of these
projects is required to mitigate existing and future
performance and reliability issues of the Transmission
System in the Spokane Valley. Opportunity Substation was
completed and energized in 2015; the Irvin-Millwood line
was completed in 2014; Irvin Substation construction will
break ground in 2016 and is expected to be energized in
2017; and the Beacon-Boulder line will then be able to be
rebuilt.

IV. Reliability Replacements: 20

Storms - 2016: $1,000,000; 2017: $1,000,000 22
This program will replace cross arms, poles and structures
as required due to storms, and fires on distribution and
transmission lines.

Substation – Capital Spares – 2016: $5,200,000; 2017: 27
$4,565,000
This program maintains our fleet of Power Transformers and
High Voltage Circuit Breakers. This fleet of critical
apparatus is capitalized upon receipt and placed in
service for both planned and emergency installations as
required. The annual program expenditures may vary
significantly in years when a 230/115 autotransformer is
purchased. In years without an autotransformer purchase,
only minor variations will occur based on planned projects
as well as replenishing apparatus fleet levels required
for adequate capital spares. These are long lead time
items so sufficient levels need to be maintained. 39

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Avista Corporation
Substation Asset Management Capital Maintenance – 2016 : 1
$4,100,000; 2017: $4,100,000
Avista has several different equipment replacement
programs to improve reliability by replacing aged
equipment that is beyond its useful life. These programs
include transmission air switch upgrades, restoration of
substation rock and fencing, recloser replacements,
replacement of obsolete circuit switchers, substation
battery replacement, meter replacements and upgrades,
relay replacements, high voltage fuse upgrades,
transformer replacements, breaker replacements,
installation of diagnostic monitors, substation air switch
replacements, and voltage regulator replacements. All of
these individual projects improve system reliability and
customer service. The equipment is replaced when it is
approaching the end of its useful life.
17
Transmission – Asset Management – 2016: $1,772,000; 2017: 18
$1,780,000 19
This item includes Transmission Minor Rebuilds in ER 2057,
and Air Switch Replacements in ER 2254. Transmission Minor
Rebuilds are developed using data received from the prior
year’s Wood Pole Inspection Program. Minor Rebuilds may
also use data received from annual Aerial Patrol
Inspections. Both inspection programs are undertaken to
maintain compliance with NERC Standard FAC-501-WECC-1.
Air Switch Replacements are made based either on
condition, capacity, or functionality issues.
Prioritization of installations and replacements are made
from information provided by Avista System Operations,
Operations Offices, or Substation Engineering.

Q. Does this complete your pre-filed direct testimony? 33
A. Yes it does. 34