20170609Schlect 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-17-01
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 ) JEFF A. SCHLECT
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Schlect, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, employer and business 2
address. 3
A. My name is Jeff A. Schlect. I am employed by Avista
Corporation as Senior Manager, FERC Policy and Transmission
Services. My business address is 1411 East Mission, Spokane,
Washington.
Q. Please briefly describe your educational background 8
and professional experience.
A. I am a 1988 graduate of Washington State University
with a degree in Electrical Engineering. I spent five years
with Puget Sound Energy in distribution engineering and
operations positions prior to joining the Company in 1993 as a
Transmission Planning Engineer. Over the past 23 years, in
addition to stints in Customer Service and Power Supply I have
worked primarily in the Transmission Operations area with
responsibilities covering Federal Energy Regulatory Commission
(FERC) transmission policy and compliance with open access
transmission regulations, transmission contracts, transmission
and generation interconnection processes, and regional
transmission policy coordination. I have authored testimony in
Bonneville Power Administration (BPA) power and transmission
rate proceedings and provided comment before the US Senate

Schlect, Di 2
Avista Corporation
Subcommittee on Water and Power. In my current role I have
responsibility for all transmission revenue and expenses and
provide support to the Company’s transmission capital planning
process.
Q. What is the scope of your testimony? 5
A. My testimony presents Avista’s transmission revenues 6
and expenses included in the Company’s request for rate relief 7
over the Two-Year Rate Plan effective January 1, 2018 and ending
December 31, 2019.
A table of contents for my testimony is as follows:
Description Page 11
I. INTRODUCTION ....................................... 1 12
II. TRANSMISSION EXPENSES FOR TWO-YEAR RATE PLAN ....... 3 13
III. TRANSMISSION REVENUES FOR TWO-YEAR RATE PLAN ...... 11 14
IV. TRANSMISSION EXPENSES FOR ENERGY IMBALANCE MARKET
PARTICIPATION ..................................... 23 16

Q. Are you sponsoring any exhibits? 18
A. Yes. Exhibit No. 9, Schedule 1 provides the
transmission revenue and expense during the Two-Year Rate Plan
effective January 1, 2018.

Schlect, Di 3
Avista Corporation
II. TRANSMISSION EXPENSES FOR TWO-YEAR RATE PLAN 1
Q. Please describe the adjustments to the twelve-months-2
ended December 31, 2016, test year transmission expenses, to 3
arrive at transmission expenses included in this case effective 4
January 1, 2018. 5
A. Adjustments were made in this filing to incorporate
updated information for any changes in transmission expenses
from the 2016 test year to that used in this case effective
January 1, 2018. As can be seen in Exhibit No. 9, Schedule 1,
I have provided the expected changes in transmission expenses
from the 2016 test year through 2019. As noted on Exhibit No.
9, Schedule 1, the calendar 2018 Pro Forma level of transmission
expenses are used during the Two-Year Rate Plan (January 1,
2018 – December 31, 2019), as these amounts will be known by
the new rate effective date beginning January 1, 2018, and are
not expected to change materially during 2019. Company witness
Ms. Andrews pro forms this level of transmission expense within
her requested revenue requirement in this case. The changes in
expenses and a description of each is summarized in Table No.
1 below, and an explanation of each change follows the table.
Each expense item described below is at a system level and is
included in Exhibit No. 9, Schedule 1. Supporting workpapers

Schlect, Di 4
Avista Corporation
(System)(1)
NWPP 12,000$
Colstrip O&M - 500kV Line 32,000
ColumbiaGrid Funding 15,000
ColumbiaGrid PEFA 70,000
ColumbiaGrid Order 1000 Functional Agreement 25,000
NERC CIP (12,000)
OASIS 10,000
PEAK Reliability - Reliability Coordination 37,000
WECC Dues 24,000
WECC - Loop Flow 10,000
Addy BPA Substation -
Hatwai BPA Substation -
Total change in Transmission Expense 223,000$
Transmission Expense Adjustment
(1) Represents the change in expenses above or below the 2016 historical test
year level.
for each of the expense items have been included with the
Company’s filed case.
Table No. 1: 3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Northwest Power Pool (NWPP) ($12,000) – Avista pays its
share of 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 is expected to be 26
$76,000, an increase of $12,000 over the 2016 test year. This

Schlect, Di 5
Avista Corporation
estimated increase in expense is based upon the three-year
average growth rate in actual NWPP expenses.
Colstrip O&M – 500kV Line ($32,000) – Avista is required
to pay its portion of the operation and maintenance (O&M) costs
associated with its joint ownership share of the Colstrip
Transmission System pursuant to the Colstrip Project
Transmission Agreement. Under this agreement, NorthWestern
Energy (NWE) operates and maintains the Colstrip Transmission
System. In accordance with NWE’s proposed Colstrip 9
construction and maintenance plan, the Company’s expected share
of Colstrip O&M expense during the rate year is $319,000. This
is an increase of $32,000 from the actual expense of $287,000
incurred during the 2016 test year.
ColumbiaGrid Funding ($15,000) – Avista became a member of
the ColumbiaGrid regional transmission organization in 2006.
ColumbiaGrid’s purpose is to enhance transmission system 16
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

Schlect, Di 6
Avista Corporation
activities under the ColumbiaGrid Funding Agreement and
supports specific functional activities under the Planning and
Expansion Functional Agreement (PEFA) and the FERC Order 1000
Functional Agreement. Avista’s ColumbiaGrid general funding 4
expenses for the 2016 test year were $89,000. The general
funding expenses during the rate year are expected to be
$104,000.
ColumbiaGrid PEFA ($70,000) – The ColumbiaGrid PEFA1 was
accepted by 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 Transmission Tariff. Actual PEFA
expenses for the 2016 test year were $132,000. The Company’s 15
PEFA expenses during the rate year are expected to be $202,000,

1 Under the PEFA, ColumbiaGrid coordinates regional grid expansion planning
based on a single-utility concept for the combined transmission grids of
its planning parties. The goal of grid expansion planning is to determine
reasonable solutions to transmission grid issues pertaining to serving load
and complying with reliability standards. The PEFA sets forth the
responsibilities of ColumbiaGrid and each planning party to complete annual
transmission system assessments and a Biennial Transmission Expansion Plan.
While the Company is required by FERC to participate in a coordinated
regional planning process, the biennial transmission planning process under
the PEFA is enhanced by the participation of many non-FERC jurisdictional
entities, including BPA, with whom the Company has more transmission
interconnections than with any other entity.

Schlect, Di 7
Avista Corporation
reflecting ColumbiaGrid’s staffing levels and planning-related
expenses to support 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 with
ColumbiaGrid called for a $50,000 payment late in 2014 that
covered two years of payments for 2015 and 2016 (expensed in
2015). Beginning in 2017, this contract calls for an annual
payment of $25,000.
NERC Critical Infrastructure Protection (CIP) (-$12,000)
– The Company has purchased several software and hardware
products to assist in protecting critical transmission control
systems from intrusion and to meet applicable North American
Electric Reliability Corporation (NERC) standards. These
products provide for physical security, intrusion detection,
virus protection and vulnerability assessment. The Company’s 17
NERC CIP expenses are expected to be $75,000 during the rate
year, a decrease of $12,000 from the 2016 test year actual
expenses of $87,000.
OASIS ($10,000) – These Open Access Same-Time Information
System (OASIS) expenses are associated with travel and training
costs for transmission pre-scheduling and OASIS personnel.

Schlect, Di 8
Avista Corporation
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 Open Access Technology International, Inc. (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, NASB and FERC.
Expenses during the 2016 test year were $0 due to the Company
hosting a major OATI user group forum in lieu of traveling.
Accordingly, these expenses are expected to go up by $10,000
during the rate year.
Peak Reliability – Reliability Coordination ($37,000) –
The Company’s Peak Reliability (PEAK) fees are expected to 13
increase from the amount paid in the historical test year from
$678,000 to $715,000 during the rate year. The formation of
PEAK is attributable to the FERC requirement that the western
interconnection reliability coordination function be
corporately and physically separated from other Western
Electricity Coordinating Council (WECC) functions. This
“bifurcation” was primarily the result of a transmission system 20
outage in the Pacific Southwest on September 8, 2011. A
reference to the disturbance including “Causes and 22
Recommendations” may be found at:

Schlect, Di 9
Avista Corporation
http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-
report.pdf. The Company is required to obtain reliability
coordination services under NERC standards. PEAK’s budget is
approved by its independent board of directors and is allocated
to the members of PEAK based upon net energy used to serve load
within a member’s balancing area. Detailed allocation 6
information is available on PEAK’s website www.peakrc.com. The
Company’s total WECC and PEAK allocations have increased an 8
average of 13.7% over the past five years. The Company is
expecting its PEAK allocation to increase approximately 5.5%
during the rate effective period.
WECC – Dues ($24,000) – WECC is the designated Regional
Entity under federal statute responsible for coordinating and
promoting Bulk Electric System reliability throughout the
western interconnection. WECC is responsible for monitoring
and measuring Avista’s compliance with reliability standards 16
and has substantially increased its staff and other resources
to meet these FERC requirements. The Company’s 2016 test year 18
WECC dues and fees were $421,000. The Company’s total WECC and 19
PEAK allocations have increased an average of 13.7% over the
past five years. The Company’s WECC allocation is expected to
be $445,000, an increase of 5.7%, during the rate effective
period.

Schlect, Di 10
Avista Corporation
WECC - Loop Flow ($10,000) – 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 2016 test year were
$35,000. Loop Flow expenses are expected to be at $45,000
during the rate year.
Addy BPA Substation ($0) – The Company pays operation and
maintenance fees to BPA associated with a 115kV circuit breaker
in BPA’s Addy Substation that provides a direct interconnection 12
for Avista’s retail load. These expenses for the 2016 test 13
year were $9,000 and are expected to remain unchanged during
the rate year.
Hatwai BPA Substation ($0) – The Company pays operation
and maintenance fees to BPA associated with a 230kV circuit
breaker owned by Avista, but located in BPA’s Hatwai Substation. 18
These expenses for the 2016 test year were $23,000 and are
expected to remain unchanged during the rate year. 20

Schlect, Di 11
Avista Corporation
III. TRANSMISSION REVENUES FOR TWO-YEAR RATE PLAN 1
Q. Please describe the adjustments to 2016 test year 2
transmission revenues to arrive at transmission revenues 3
included in this case effective January 1, 2018. 4
A. Adjustments have been made in this filing to
incorporate updated information for transmission revenue from
the 2016 test year to that used in this case for the Two-Year
Rate Plan, effective January 1, 2018. As can be seen in Exhibit
No. 9, Schedule 1, revenues have been adjusted to 2018 Pro Forma
levels, and there are no expected changes in transmission
revenues during 2019.
Each revenue item described below is at a system level and
is included in Exhibit No. 9, Schedule 1. Ms. Andrews has pro
formed the transmission revenues within the revenue requirement
in this case, reducing transmission revenues downward by
$2,163,000 effective January 1, 2018. Table No. 2, below,
provides a detailed summary of the changes in transmission
revenues. An explanation of each change follows the table.
Supporting workpapers for each of the revenue items have been
included with the Company’s filed case.

Schlect, Di 12
Avista Corporation
(System)(1)
BPA - Transmission (68,000)$
- Low Voltage 184,000
- Ancillary Services 456,000
Consol Irrig Dist - Transmission -
- Low Voltage 4,000
- Ancillary 4,000
East Greenacres - Transmission -
- Low Voltage -
- Ancillary 1,000
Grant PUD Transmission -
Spokane Indian Tribe - Transmission -
- Low Voltage -
- Ancillary 2,000
Seattle/Tacoma Main Canal (7,000)
Seattle/Tacoma Summer Falls 62,000
OASIS nf & stf Whl (Other Whl)535,000
Pacificorp - Dry Gulch 14,000
Spokane Waste to Energy Plant -
Columbia Basin Hydropower -
First Wind Transmission (200,000)
Palouse Wind O & M -
Stimson Lumber -
BPA Parallel Capacity Support (2,268,000)
Morgan Stanley Capital Group (600,000)
Hydro Tech Systems - Meyers Falls -
Deep Creek Hydro -
Kootenai Electric Cooperative Transmission -
Kootenai Electric Cooperative Ancillary 5,000
BPA Excess Transmission Sales(2)(287,000)
(2,163,000)$
Transmission Revenue Adjustment
(1) Represents the change in revenues above or below the 2016 historical test year
level.
(2) Removes test year revenue associated with marketing unused BPA transmission
capacity to other BPA transmission customers.
Table No. 2: 1

The Company provides transmission service to wholesale
customers under the jurisdiction of the FERC. The components

Schlect, Di 13
Avista Corporation
of what has traditionally been known as “wheeling” service 1
include: (i) transmission service over the Company’s 2
transmission facilities that are operated at or above 115kV,
(ii) ancillary services (generation-related services that are
required to be offered in conjunction with transmission
service) and (iii) low-voltage wheeling services over
substation and distribution facilities that are operated below
115kV. With respect to ancillary services, the Company attained
FERC acceptance of revised ancillary service rates effective
September 1, 2016. Rates for Regulation Service and Operating
Reserves – Spinning increased from $8.94/kW-month to $12.83/kW-
month, while the rate for Operating Reserves – Supplemental
increased from $8.94/kW-month to $11.82/kW-month. All
ancillary service rate adjustments noted herein are due
primarily to this rate change.
Bonneville Power Administration (Transmission: -$68,000)
(Low Voltage: $184,000) (Ancillary Services: $456,000) –
Network Integration Transmission Service revenue, which is
dependent upon variable BPA load amounts each month, is
estimated based upon a three-year average for the 2014-2016
time period, resulting in a figure of $6,164,000 for the rate
year compared to $6,233,000 for the 2016 test year. The Company
attained FERC acceptance of increased substation and low

Schlect, Di 14
Avista Corporation
voltage charges effective April 1, 2016, so the 2016 test year
included three months’ time with the prior charges. Estimated 2
revenues for the rate year are $1,663,000 compared to $1,479,000
during the 2016 test year, reflecting an increase of $184,000
from the test year. Using three-year average monthly peak load
figures and the new ancillary service rates effective September
1, 2016, the Company estimates annual ancillary service revenue
of $2,244,000 during the rate year compared to $1,788,000 during
the test year, an increase of $456,000.
Consolidated Irrigation District (Transmission: $0) (Low 10
Voltage: $4,000) (Ancillary Services: $4,000) – The prior
transmission and distribution service agreements expired on
September 30, 2016 and new agreements were executed to be
effective through September 30, 2021. Point-to-Point
Transmission Service revenue for the 2016 test year was $32,000
and is expected to remain unchanged during the rate year. Low 16
voltage revenue for the 2016 test year was $81,000 while charges
under the new Electric Distribution Services Agreement will
result in revenue of $85,000 per year during the rate year.
Ancillary service revenue during the 2016 test year was $6,000
and, using three-year average peak load figures, is expected to
be $10,000 during the rate year.

Schlect, Di 15
Avista Corporation
East Greenacres Irrigation District (Transmission: $0)
(Low Voltage: $0) (Ancillary Services: $1,000) – Current
transmission and distribution service agreements will remain in
effect through September 30, 2019. Point-to-Point Transmission
Service revenue for the 2016 test year was $11,000 and is
expected to remain unchanged during the rate year. Low voltage
revenue under the current Electric Distribution Service
Agreement for the 2016 test year was $51,000 and is expected to
remain unchanged during the rate year. Ancillary service
revenue during the 2016 test year was $5,000 and, using three-
year average peak load figures, is expected to be $6,000 during
the rate year.
Grant County PUD – Transmission ($0) – Revenue under the
Power Transfer Agreement was $28,000 for the 2016 test year.
Using three-year average load figures the Company is estimating
annual revenue of $28,000 during the rate year.
Spokane Tribe of Indians (Transmission: $0) (Low Voltage:
$0) (Ancillary Services: $2,000) – Current transmission and
distribution service agreements will remain in effect through
December 31, 2019. Point-to-Point Transmission Service revenue
for the 2016 test year was $29,000 and is expected to remain
unchanged during the rate year. Low voltage revenue under the
current Electric Distribution Service Agreement for the 2016

Schlect, Di 16
Avista Corporation
test year was $20,000 and is expected to remain unchanged during
the rate year. Ancillary service revenue during the 2016 test
year was $5,000 and, using three-year average peak load figures,
is expected to be $7,000 during the rate year.
Seattle and Tacoma – Main Canal Project (-$7,000) –
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 11
Grant County PUD. 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. Revenues under these agreements
totaled $362,000 during the 2016 test year and are expected to
be $355,000 during the rate year.
Seattle and Tacoma – Summer Falls Project ($62,000) –
Effective March 1, 2008, and continuing through October 31,
2024, the Company 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 Stratford Switching Station facilities to 23

Schlect, Di 17
Avista Corporation
the Company’s Stratford interconnection with Grant County PUD. 1
Charges under these use-of-facilities arrangements are based
upon the Company’s investment in its Stratford Switching 3
Station and are not impacted by the Company’s transmission 4
service rates under its Open Access Transmission Tariff. The
Company attained FERC acceptance of revised use-of-facilities
rates effective August 2016. Revenues under these two contracts
totaled $118,000 in the 2016 test year and under the revised
rates will be $180,000 during the rate year.
OASIS Non-Firm and Short-Term Firm Transmission Service
($535,000) – 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. 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 balance status of regional load-

Schlect, Di 18
Avista Corporation
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 transmission capacity 11
or competing transmission paths, and major generation projects
which may impact the load-resource balance needs of prospective
transmission customers). 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. However,
volatility in OASIS revenue from year-to-year can be expected,
entirely outside the scope and purview of the Company as a
transmission provider. In this filing, the Company is using a
three-year average for the time period of January 2014 to
December 2016. The OASIS revenue for the 2016 test year was

Schlect, Di 19
Avista Corporation
$2.373 million and the three-year average calculated during the
rate year is $2.908 million.
PacifiCorp Dry Gulch ($14,000) – Revenue under the Dry
Gulch use-of-facilities agreement has been adjusted to $232,000
during the rate year, which is a $14,000 increase from the 2016
test year actual revenue of $218,000. 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
the operating conditions of PacifiCorp’s transmission system in 11
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-
month rolling ratchet demand provision and charges under this
agreement are not impacted by the Company’s open access 16
transmission service tariff rates.
Spokane Waste to Energy Plant ($0) – The City of Spokane
pays a use-of-facilities charge for the ongoing use of its
interconnection to Avista’s transmission system. Use-of-
facilities charges for the 2016 test year were $28,000 and are
expected to remain unchanged during the rate year.

Schlect, Di 20
Avista Corporation
Columbia Basin Hydropower ($0) – The Company provides
operations and maintenance services on the Stratford-Summer
Falls 115kV Transmission Line to Columbia Basin Hydropower
(formerly known as 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 2016 test year and
will remain the same during the rate year.
First Wind Transmission (-$200,000) – First Wind Energy
Marketing (FWEM) 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. FWEM
subsequently sold the output of its Palouse Wind facility to
Avista, thus voiding its need for transmission service. FWEM
extended its start date for transmission service the maximum
allowed five years and, as of February 2017 has defaulted on
the transmission service contract. The Company filed a request
with FERC in March 2017, to terminate the contract and obtained
FERC acceptance of cancellation effective May 31, 2017. The
Company received $200,000 in revenue under this agreement in

Schlect, Di 21
Avista Corporation
the 2016 test year and, following termination, will not receive
any further revenue2.
Palouse Wind O&M ($0) – Per Avista’s interconnection 3
agreement 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 2016 test year was $52,000. Revenue during the
rate year is expected to remain unchanged.
Stimson Lumber ($0) – Low-voltage facilities associated
with the Company’s Plummer Substation are dedicated for use by 10
Stimson Lumber resulting in low voltage use-of-facilities
revenue of $9,000 during the 2016 test year. Revenue during
the rate year is expected to remain unchanged.
Bonneville Power Administration – Parallel Capacity 14
Support (-$2,268,000) – Avista and BPA executed a Parallel
Operation Agreement on December 12, 2012, wherein Avista
provides BPA with parallel transmission capacity in support of
BPA’s integration of several wind resource projects. In 2014 18
BPA indicated its intent to construct additional transmission
facilities to bypass Avista’s system and terminate this

2 Under the cancellation terms accepted by FERC, the Company will receive
proceeds totaling approximately $1,450,000. While these amounts are not
reflected in either the 2016 test year or 2018 rate period, these amounts
will be recorded as transmission revenue by June 2017 and reflected in the
Company’s Power Cost Adjustment mechanism.

Schlect, Di 22
Avista Corporation
agreement. Avista and BPA completed over two years of
negotiations and executed a revised Parallel Capacity Support
Agreement that went into effect February 1, 2017, which provides
for a reduced payment stream by BPA but with an extended minimum
term of ten years, through December 2026. Revenue for the 2016
test year was $3,192,000. Reduced annual revenue under the
revised agreement during the rate year and beyond is $924,000,
a reduction of $2,268,000 from the 2016 test year.
Morgan Stanley (-$600,000) – Morgan Stanley Capital Group
purchased 25 MW of Long-Term Firm Point-to-Point Transmission
Service from January 1, 2013 to December 31, 2017. Revenue for
the 2016 test year was $600,000 and will be reduced to $0 during
the rate year, due to the expiration of the contract.
Hydro Tech Systems ($0) – Low-voltage facilities in the
Company’s Greenwood Substation are dedicated for use by the 15
Meyers Falls generation project resulting in low voltage use-
of-facilities revenue of $6,000 during the 2016 test year.
Revenue during the rate year is expected to remain unchanged.
Kootenai Electric Cooperative – Fighting Creek 19
(Transmission: $0) (Ancillary Services: $5,000) – Kootenai
Electric Cooperative (KEC) has purchased 3 MW of Long-Term Firm
Point-to-Point Transmission Service from April 1, 2014 to March
31, 2019. Transmission revenue for the 2016 test year was

Schlect, Di 23
Avista Corporation
$72,000 and is expected to remain unchanged during the rate
year. Ancillary service revenue during the 2016 test year was
$18,000 and is expected to be $23,000 during the rate year. As
noted above the Company attained FERC acceptance of revised
ancillary service rates effective September 1, 2016. Rates for
Regulation Service and Operating Reserves – Spinning increased
from $8.94/kW-month to $12.83/kW-month, while the rate for
Operating Reserves – Supplemental increased from $8.94/kW-month
to $11.82/kW-month, this increase is due to this rate change.

IV. TRANSMISSION EXPENSES FOR POTENTIAL ENERGY 11
IMBALANCE MARKET PARTICIPATION 12
Q. Please provide detail about any transmission expense 13
associated with the Company potentially joining the CAISO 14
Western Energy Imbalance Market? 15
A. The Company is not including any transmission expense
related to participation in the California Independent System
Operator (CAISO) Western Energy Imbalance Market (EIM) in this
filing. As discussed by Company witness Mr. Kinney, the Company
is currently evaluating the costs and benefits of joining the
CAISO EIM and anticipates making a decision on when to join the
market by the end of 2017. The Company is monitoring several
operational drivers such as market liquidity and additional

Schlect, Di 24
Avista Corporation
renewable integration in our service territory that could
influence our timing to join the market.
Mr. Kinney explains that EIM integration expenses are
estimated to be $3 million, with another $12 million in capital
additions, while ongoing EIM operational expenses are expected
to be from $3 to $5 million annually. The Company expects
approximately two thirds of these costs will relate to
transmission and system operations expense, with the remaining
expense related to energy resource and technology expenses.
The Company is not requesting recovery of costs in this filing.
However, for any such expenses that may be incurred during the
Two-Year Rate Plan proposed by the Company in this case, the
Company may submit a filing for accounting or ratemaking
treatment of these costs prior to the end of the Two-Year Rate
Plan.
Q. Does this complete your pre-filed direct testimony? 16
A. Yes it does. 17