20190610Kalich Direct.pdf

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DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O.BOX3727
I41I EAST MISSION AVENUE
SPOKANE, WASH INGTON 99220 -3727
TELEPHONE: (509) 49s-4316
FACSIMILE: (509) 495-885 I
[e-mail]
i0t9 JUH l0
rnIL'
TILIT
Al'i0 F
li:S CO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
TN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE
STATE OF IDAHO
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CASE NO. AVU-E-19-04
DIRECT TESTIMONY
OF
CLTNT G. KALICH
FOR AVISTA CORPORATION
(ELECTRIC)
RECEIVED
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I. INTRODUCTION
a. Please state your name, the name of your employer, and your business
address.
A. My name is Clint Kalich. I am employed by Avista Corporation at 1411
East Mission Avenue, Spokane, Washington.
a. In what capacify are you employed?
A. I am the Manager of Resource Planning & Power Supply Analyses in the
Energy Resources Department of Avista Utilities.
a. Please state your educational background and professional
experience.
A. I graduated from Central Washington University in l99l with a Bachelor
of Science Degree in Business Economics. Shortly after graduation I joined Economic
and Engineering Services, Inc. (now EES Consulting, Inc.), a northwest management-
consulting firm located in Bellevue, Washington. EES Consulting worked primarily for
municipalities, public utility districts, and cooperatives in the area of electricity, water
and wastewater utility management. My specific areas of focus were economic analyses
of new resource development, rate case proceedings involving the Bonneville Power
Administration, integrated (least-cost) resource planning, and demand-side management
program development.
In late 1995, I left EES Consulting to join Tacoma Power in Tacoma, Washington.
I provided key analytical and policy support in the areas of resource development,
procurement, and optimization, hydroelectric operations and re-licensing, unbundled
power supply rate-making, contract negotiations, and system operations. I helped
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Avista Corporation
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develop, and ultimately managed, Tacoma Power's industrial market access program
serving one-quarter of the company's retail load.
In mid-2000 I joined Avista Utilities and accepted my current position assisting
the Company in resource analysis, dispatch modeling, resource procurement, integrated
resource planning, and rate case proceedings. Much of my now 28-year utility career has
involved resource dispatch modeling of the nature described in this testimony.
a. What is the scope of your testimony in this proceeding?
A. My testimony will: 1) describe the Company's use of the AURORA
dispatch model, or "Dispatch Model;" 2) discuss our transmission revenue assumptions;
3) identify and explain the proposed normalizing and pro forma adjustments to the 2018
test period power supply revenues and expenses; and 4) detail the proposed level of
expense and Load Change Adjustment Rate (LCAR) for Power Cost Adjustment (PCA)
purposes, using the pro forma costs proposed by the Company in this filing.
A table of contents for my testimony is as follows:
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Introduction
Dispatch Model
Other Key Modeling Assumptions
Results of the Dispatch Model
Non-Dispatch Model Assumptions
Electric Transmission Assumptions
Overview of Pro Forma Power Supply Adjustment
Pro Forma Power Supply Adjustments
PCA Authorized Values
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Kalich, Di
Avista Corporation
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o O. Are you sponsoring any exhibits in this proceeding?
A. Yes. I am sponsoring exhibits marked Exhibit No. 7, Schedules I - 6.
Schedule 2C is a confidential exhibit and marked as such. Table No. I below shows the
Schedule list for Exhibit No. 7.
I - Exhibit No.Schedule
All information contained in Exhibit No. 7 was prepared by me or under my
direction.
II. THE DISPATCH MODEL
O. What testimony will you cover in this section?
A. This portion of my testimony explains the key assumptions driving the
Dispatch Model's market forecast of electricity prices. The discussion includes the
variables of natural gas, loads and resources, and hydroelectric conditions. I will describe
how the model dispatches Company resources and contractual rights to maximize
customer benefit; it tracks their values for use later in my pro forma calculations.
a. What model is the Company using to dispatch its portfolio of
resources and obligations?
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Avista Corporation
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Schedule Name Brief Description
Schedule I AURORA Modeling Changes Summary
Confi dential Schedule 2C Monthly Dispatch Model Results - Generation Resources
Schedule 3 Power Supply Pro Forma - Idaho Jurisdiction
Schedule 4 Brief Description of Power Supply Adjustments
Schedule 5 Market Purchases and Sales. Plant Generation and Fuel
Cost Summary
Schedule 6 ERM Authorized Expense and Retail Sales
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A. The Company uses Energy Exemplar, Inc.'s AURORA market forecasting
model ("Dispatch Model") and its associated database for determining power supply
costs.r /2 The Dispatch Model optimizes Company-owned resource and contract dispatch
during each hour of the January 1,2020 through December 31,2020 pro forma year.
a. Please briefly describe the Dispatch Model.
A. The Dispatch Model is a fundamentals-based tool containing demand and
resource data for the entire Western Interconnect. It employs multi-area, transmission-
constrained dispatch logic to simulate wholesale power market conditions. Its dispatch
captures the dynamics, and economics, of electricity markets-both short-term (hourly,
daily, monthly) and long-term. On an hourly basis the Dispatch Model develops an
available resource stack, sorting resources from lowest to highest cost. It then compares
this resource stack with load obligations in the same hour to arrive at the least-cost
market-clearing price for the hour. Once resources are dispatched and market prices are
determined, the Dispatch Model singles out Avista resources, contracts and loads and
values them against the marketplace.
O. What experience does the Company have using AURORA?
A. The Company purchased a license to use the Dispatch Model in April
2002. AURORA has been used for numerous studies, including each of its integrated
resource plans and rate filings after 2001. The tool also is used for various resource
evaluations, market forecasting, and requests-for-proposal evaluations.
a. Who else uses AURORA?
I The Company uses AURORA version v13.2 and Aurora's base dataset U.S. - Canada2018 v3 on a
computer running the Windows 7 operating system.
2 Energy Exemplar purchased EPIS in late 2017.
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Avista Corporation
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o A. AURORA is used all across North America, Europe, Asia, and the Middle
East. In the Northwest specifically, AURORA is used by Idaho Power, the Bonneville
Power Administration, the Northwest Power and Conservation Council, Puget Sound
Energy, , Portland General Electric, PacifiCorp, Seattle City Light, Grant County PUD,
and Snohomish County PUD.
a. What benefits does the Dispatch Model offer for this type of analysis?
A. The Dispatch Model generates hourly electricity prices across the Western
Interconnect, accounting for its specific mix of resources and loads. The Dispatch Model
reflects the impact of regions outside the Northwest on Northwest market prices, limited
by known transfer (transmission) capabilities. It emulates emissions markets and, where
configured correctly with data, is able to address oversupply (i.e., negative price)
conditions. With AURORA the Company can generate price forecasts in-house instead
ofrelying on exogenous forecasts.
a. Why is a tool like the Dispatch Model important for setting rates?
A. The Company owns a number of resources, including hydroelectric plants
and natural gas-fired peaking units serving customer loads. These plants provide their
greatest value during on-peak hours and when regional loads, and prices in the
marketplace, are highest. Further, these plants should be operated only when their costs
are lower than the cost of surplus power from other participants in the marketplace. By
optimizing resource operation on an hourly basis, the Dispatch Model is able to
appropriately value the capabilities of these assets and purchase lower-cost surplus power
when it lowers rates.
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Avista Corporation
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a. How can the Commission ensure the model is appropriately reflecting
the value ofthese resources?
A. By reflecting market fundamentals, Company resources and contracts are
valued appropriately. One measure is the relationship between peak- and off-peak prices.
Because on-peak prices are higher than off-peak prices, contracts and resources with
optionality (e.g., hydro with storage) should dispatch with more power generated in the
on-peak hours. The value ofgenerating resources should be higher in on-peak periods
relative to off-peak periods.
Forward prices for the pro forma 2020 period are 51 percent higher in the on-peak
hours than off-peak hours at the time this case was prepared. The Dispatch Model
forecasts on-peak prices for the pro forma period to average 29 percent higher than off-
peak prices, which is within the range of history (see Illustration No. l).
Illustration No-l - Historical Mid- k / Off-Price Ratios,1996-20193
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Mid-C On-Peak / Off-Peak Price History
r90%
180%
t70%
t6o%
t50%
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120%
t10%
t@%(o l\ @ o) I Er C.l d) Sl |l| \D l\ @ ql () H ol (o <l Ur (o N @ otEES 8888 8888 8888 8866 8888 6d d H d (\l N a.{ 6l N N N l.\l (\,l f\,1 al a{ N f,.,| N C'l f,\l C{ N f.l
3 2016 is May through December average, 2019 is January through May 16 average.
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Avista Corporation
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A graphical representation ofthe differences in peak- and off-peak prices over the
pro forma period is shown below in Illustration No. 2.
Illustration No. 2 - Monthlv AURORA modeled versus forward Mid-C Prices
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Forward Mid-Columbia prices shown are the latest one month average (March
18, 2019 through April 16, 2019) of Intercontinental Exchange (lCE) quarterly prices at
the time of study preparation.
Dispatch Model and forward prices can and will be different, as forward prices
are based on market expectations whereas the data used in the Dispatch Model are
normalized for hydro, loads, and resource outages. Referring back to Illustration No. l,
the average price for the 2020 forward period is $36.93 per MWh; the Dispatch Model
price is 528.39 per MWh. This result explains that the market is expecting an upward
bias in future conditions (e.g., regional capacity deficits, low water year).
a. On a broader scale, what calculations are being performed by the
Dispatch Model?
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Avista Corporation
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A. The Dispatch Model's goal is to minimize overall system operating costs
across the Western Interconnect, including Avista's portfolio of loads and power supply
options. The Dispatch Model generates a wholesale electricity price forecast by
evaluating all Western Interconnect resources simultaneously in a least-cost equation to
meet regional loads. As the Dispatch Model progresses from hour to hour, it "operates"
those least-cost resources necessary to meet load. With respect to the Company's
portfolio, the Dispatch Model tracks the hourly output and fuel costs associated with
Avista's portfolio generation. It also calculates hourly energy quantities and values for
the Company's contractual rights and obligations. In every hour, the Company's loads
and obligations are compared to available resources to determine a net position. This net
position is balanced using the simulated wholesale electricity market. The cost of energy
purchased from or sold into the market is determined based on the electric market-
clearing price for the specified hour and the amount of energy necessary to balance loads
and resources.
a. How does the Dispatch Model determine electricity market prices,
and how are the prices used to calculate market purchases and sales?
A. The Dispatch Model calculates electricity prices for the entire Western
Interconnect, separated into various geographical areas such as the Northwest and
Northern and Southern California. The load in each area is compared to available
resources and costs, including resources available from other areas that are linked by
transmission connections, to determine the electricity price in each hour. Resource costs
include operation and maintenance, fuel, local, state and federaltax charges and credits,
and, where applicable, emissions fees.
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Avista Corporation
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Ultimately, the market price for an hour is set based on the costs of the last
resource in the dispatch stack. This resource is referred to as the "marginal resource."
Given the prominence of natural gas-fired resources on the margin, this fuel is a key
variable in determining wholesale electricity prices.
a. How does the Dispatch Model operate regional hydroelectric
projects?
A. The model begins by "peak shaving" loads using hydro resources with
storage. When peak shaving, the Dispatch Model determines the hours with the highest
loads and allocates to them as much hydroelectric energy within the constraints of the
hydro system. Remaining loads are then met with other available resources.
a. Has the Company made any modifications to the AURORA database
for this case?
A. Yes. Parting modestly from the past, Avista has for this case attempted to
rely more heavily on the default Aurora database. We do modify natural gas prices to
match the latest one month average of forward prices over the pro forma period and we
continue, as in the past, by including regional Bonneville Power Administration hydro
study datato enable modeling of the hydrologic record. We also make changes unique
to our portfolio, including gas plant heat rates and O&M costs.
a. Does the Company have a more detailed list of changes made to the
AURORA database?
A. Yes. Exhibit No. 7, Schedule I provides a list of changes made to the
AURORA database, including a short explanation of the rationale for each. These
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Avista Corporation
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changes can be audited by exploring my work papers, as well as by evaluating change set
and table data contained in the AURORA files provided with my testimony.
a. Has the Company made any methodological changes to the way it
models hydro in this case compared to prior cases?
A. No. The monthly split between on- and off-peak generation remains based
on the most recent five-year (2014-2018) average. This approach ensures customers
benefit from the capability of these resources to shape water fuel to the highest-value
hours.
a. Please compare the operating statistics from the Dispatch Model to
recent historical hydroelectric plant operations.
A. Over the pro forma period, the Dispatch Model generates 67 percent of
Clark Fork hydro generation during on-peak hours (based on average water). Since on-
peak hours represent only 57 percent of the year, this demonstrates a substantial shift of
hydro resources to the more expensive on-peak hours. This is identical to the five-year
historical (actual) average of on-peak hydroelectric generation at the Clark Fork through
December 2018. Similar relative performance is achieved for the Spokane and Mid-
Columbia projects.
III. OTHER KEY DISPATCH MODELING ASSUMPTIONS
a. Exhibit No. 7, Schedule 1 provides a list of assumptions made in the
Dispatch Model. Are there any Dispatch Modeling assumption you wish to highlight
here?
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Avista Corporation
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o A. Yes. Above I explained that natural gas prices greatly affect power supply
costs. Pro forma loads also are a large driver since they define how much generation we
must serve. Finally, Colstrip outage assumptions are greatly material because of the
plant's low-cost contribution to our portfolio.
a. Please describe your update to pro forma period natural gas prices.
A. Consistent with past general rate case filings, natural gas prices are based
on a one-month average of forward prices; in this case from March 15, 2019 through
April 1 5, 2019 for calendar-year 2020 monthly forward prices. Natural gas prices used
in the Dispatch Model are presented below in Table No 2.
Table No. 2 - Pro Forma Natural Gas Prices
Basin
Price
($2020/dth)Basin
Price
($2020/dth)
AECO $1.222 Stanfield $2.32s
Malin s2.405 Kingsgate $2.1 80
a. What is the Company's assumption for rate period loads?
A. Again consistent with prior general rate case proceedings, historical
Company loads are weather-adjusted. For this filing, weather normalized 2020 load is
1,040.0 average megawatts (aMW) compared to actual loads of 1034.3 (aMW). Table
No. 3 below details data included in this proceeding. Further information on the weather
normalization is within Company witness Ms. Knox's testimony.
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Avista Corporation
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o Table No. 3 - Pro Forma Loads (aMW)
Month
Actual
l-oad
Weather
Adiustment
Modeled
Load
I Actual
montnl Load
Weather
Adiustment
Modeled
t-oad
Jan-20 1,144.7 47.5 1,192.1 Jur-201 1,063.7 -49.6 I ,014. r
Feb-20 1,167 .3 - 18.8 I , 148.5 Aus-2ol 1.073.2 -20.3 1,052.9
Mar-20 I,063.8 -3.6 1.060.2 Sep-201 914.1 17.9 932.1
Apr-20 976.7 -1.0 975.8 oct-201 9$.9 3.5 947.4
May-20 921.1 24.6 945.6 Nov-201 1,062.6 6.6 1,069.2
Jur20 929.4 22.2 951.6 Dec-2ol I,155.5 38.3 I.t93.8
a. Please discuss outage assumptions for your thermal plants.
A. Consistent with prior cases, Avista uses the most recent available five-year
(2014-2018) average forced outage rate to estimate long-run perforrnance at our non-
peaking thermal plants. Maintenance outages also affect plant availability. As with
forced outages, maintenance outage rates for our non-peaking plants are based on a five-
year averuge, except for Colstrip. The Colstrip maintenance outage rate is based on the
most recent six-years. Six years are used because routine plant maintenance outages
occur once every three years. Absent including an additional year for averaging, the
assumption would not reflect the full maintenance cycle for the plant.
Peaking plants run rarely and therefore forced outage and maintenance outages
have small effects on power supply expenses. For the Rathdrum, Northeast and Kettle
Falls combustion turbines the pro forma assumes no derating for maintenance outages
and a five percent forced outage rate. Boulder Park similarly has no derating for
maintenance, but its forced outage rate is estimated at l5 percent.
a. Are there any other significant Dispatch Modeling changes from the
last rate filing?
A. No.
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Avista Corporation
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o IV. RESULTS OF THE DISPATCH MODEL
a. Please summarize the results from the Dispatch Model.
A. The Dispatch Model tracks the Company's portfolio during each hour of
the pro forma study. Generation for each resource are summarized by month. Total
market sales and purchases are also determined and summarized by month. These values
are contained in Exhibit No. 7, Confidential Schedule 2C. Resource and contract
revenues and expenses not accounted for in the Dispatch Model (e.g., contract fixed costs)
are added to the results of Exhibit No. 7, Schedule 3 to determine net power supply
expense.
V. NON-DISPATCH MODEL ASSUMPTIONS
a. Are there changes outside of the AURORA Dispatch Model included
in this case?
A. Yes. The mark-to-market value of all forward natural gas and power
positions with contract durations falling within the pro forma period have been included,
but outside of AURORA. This case also includes the costs and benefits of our Palouse
Wind and Rattlesnake Flat wind power purchase agreements (PPAs). The Rattlesnake
Flat PPA was recently executed, and begins commercial operation in late 2020. It is
modeled in this case as entering service in December of 2020. Company witness Mr.
Kinney's direct testimony and exhibits provide support for the Rattlesnake Wind PPA
(see Kinney Direct and Exhibit No. 5, Confidential Schedules 3C - 5C).
Palouse Wind PPA, however, is an existing wind project. The 3O-year Palouse
Wind PPA was executed in 2011 by the Company and purchases all of its output (105
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MW nameplate capacity) and environmental attributes. The project began commercial
operation in December 2012. Per GRC settlements since 2012, the Company recovers
Palouse Wind PPA costs through the PCA. In this case the Company is requesting all
Palouse Wind PPA costs be included in base rates, and base power supply net costs,
beginning January 1, 2020.
a. In prior Avista GRCs did the Commission preclude the Company
from requesting that the full cost of the Palouse Wind PPA be included in base retail
rates in the future?
A. No. In prior GRCs where Avista sought recovery of the Palouse Wind
PPA, the parties agreed for settlement purposes to track Palouse Wind project through
the PCA. The Commission has not otherwise precluded Avista from seeking to
incorporate the Palouse Wind PPA into base rates, like all of its other generating
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14 a. For the past several years, with Palouse Wind tracked through the
PCA, how much has the Company's Shareholders absorbed of the annual PPA costs
(10"/"'), thus benefiting Idaho customers.
A. Through December 2019 the Company willhave absorbed approximately
$2.1 million since December 20124. This has been a direct benefit to customers of
unrecovered PPA costs absorbed by the Company through the PCA mechanism. The
Company believes it is time for recovery of this project within base rates.
a. Was Palouse Wind a prudent resource acquisition?
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a This value was calculated by taking the difference between the cost of the Palouse Wind PPA and the cost
ofwholesale energy (which would have been purchased absent the PPA in order to serve customer needs),
multiplied by l0 percent (Avista's share of the PCA sharing mechanism).
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o A. Yes. At the time the contract execution, the Palouse Wind purchase was
one of if not the lowest priced, wind resource projects in the Northwest. The purchase
price also compared favorably to the Idaho avoided cost rates at the time. The 20-year
(2013-2032) levelized cost of Palouse Wind was $63.61/MWh. By comparison, Avista's
Idaho avoided cost rate (effective 8130/2011), including the wind integration deduction,
for the same period was $67.41lMWh. The Palouse Wind contract was a cost-effective,
prudent, and long term resource acquisition. It was and remains a prudent acquisition,
whose costs should be borne by ratepayers.
a. Do Idaho customers receive benefits other than an energy resource
from Palouse Wind and other Avista renewable energy resources?
A. Yes. Avista is actively involved in the Renewable Energy Credit (REC)
market and has received significant REC sales revenue due to our mix of renewable
resources. While the state of Idaho may not have a renewable portfolio standard (RPS),
the presence of RPSs in other western states and the national Green-e REC market has
provided significant benefits to Idaho customers. Avista's Idaho customers have received
$22.8 million dollars of revenue from REC sales for the period 2007 through 201 8. This
rate case includes $423,300 of REC sales revenue for Idaho customers.
VI. ELECTRIC TRANSMISSION ASSUMPTIONS
a. Is the Company proposing any adjustments to Transmission FERC
account 456 in this case?
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Avista Corporation
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o A. No. Actuals are adjusted to the 2017 general rate case authorized level of
S15.15 million system. This is $2.77 million reduction from 2018 actual transmission
revenues of $17.92 million.
a. Why did the Company reduce 2018 actual transmission revenues for
this filing?
A. Higher 2018 transmission revenues reflect a one-off windfall due to the
Embridge natural gas pipeline failure. This unfortunate regional event created significant
short-term demand for Avista transmission, as west-side loads were served by 3'o parties
moving power plant output from the east to the west of our system to replace their natural
gas-starved plants. This event is not expected to occur again. The current authorized
transmission revenues, therefore, reflect transmission revenue expected during calendar
year 2020.
VII. OVERVIEW OF PRO FORMA POWER SUPPLY ADJUSTMENT
a. Please provide an overview of the pro forma power supply
adjustment.
A. The pro forma power supply adjustment determines revenues and
expenses associated with dispatch of Company resources and contract rights, as
determined by the AURORA model simulation forthe pro forma rate period under normal
weather and hydro generation conditions. Further adjustments are made to reflect
contract changes between the historical test period and the pro forma period. Table No.
4 below shows total net power supply expense during the test period and the pro forma
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period. For information purposes only, the power supply expense currently in base retail
rates, based on a calendar 2017 pro forma period, is shown.5
Table No. 4 - Net Power Supplv Expense
The net effect of my adjustments to the test year power supply expense is an
increase in2020 of S16.420 million ($152.15 - S135.73) on a system basis and a $5.683
million Idaho allocation.6 This value is provided to Company witness Ms. Andrews for
her testimony. Overall, however, the decrease in net power supply expense in 2020, as
compared to what is authorized in current base rates, is $9.080 million, or $3.143 million
Idaho share.
VIII. PRO FORMA POWER SUPPLY ADJUSTMENTS
a. Please identiS specific power supply cost items covered in your
testimony and the total adjustment being proposed.
5 For the remainder of my testimony, for purposes of the power supply adjustment I will refer to the net of
power supply revenues and expenses as power supply expense for ease ofreference.6 Assumes 2020 ProductiorVTransmission (P/T) ratio of 65.39Yo I 34.610/o for Washington / Idaho.
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Kalich, Di
Avista Corporation
Measure System
Idaho
Allocation
Power Supply Expense in Current Rates (2018 Pro Fonrn)
Actual 2018 Test Period Power Suppty Expense
Proposed 2020 Pro Fornra Power Suppty Expense
Proposed 2020 Expense versus 2018 Test Period
Proposed 2020 Expense versus Current Rates
($000s)
$ 161,230
$ r 3s,730
$ 152,150
$ 16,420
$ (9,080)
($000s)
$ 55,802
s 46.976
$ 52,659
$ 5,683
$ (3,143)
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A. Exhibit No. 7, Schedule 3 identifies non-Dispatch Model power supply
expense and revenue items. These relate to power purchases and sales, fuel expenses,
transmission expenses, and other miscellaneous power supply expenses and revenues.
a. What is the basis for the adjustments to the test period power supply
revenues and expenses?
A. The purpose of test period adjustments is normalization of power supply
expenses for expected (average) weather and hydroelectricity generation, to reflect
current forward natural gas prices, and include other known and measurable changes for
the pro forma period.
a. Please describe each adjustment.
a. Exhibit No. 7, Schedule 4 provides a brief description of each adjustment.
Detailed work papers demonstrate actual and pro forma revenues.
Long-Term Contracts
a. How are long-term power contracts included in the pro forma?
A. In the past the Company included contract power rights and obligations in
the Dispatch Model, but separately calculated pro forma revenues and expenses outside
of the model. In this filing the Dispatch Model tabulates these items.
O. Are there any new long-term power purchases or sales in the pro
forma that are not in current base rates?
A. Yes. As detailed above, the Palouse Wind and Rattlesnake Flat wind
projects are included in this case but are not in current base rates.
a. Are there any long-term power purchases or sales in current base
rates that are not in this pro forma?
Kalich, Di
Avista Corporation
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A. Yes. The WNP-3 contract expired on April 30,2019 and is not included
in this filing.7
Term Transactions
a. How are term transactions accounted for in the pro forma?
A. The Company's risk management policy, sponsored by Mr. Kinney,
executes term transactions to lessen power supply expense volatility. Our risk
management policy enables term transactions out as far as three years. We take power
and natural gas positions into the future, using both physical and financial arrangements,
in the forward markets; many of these transactions can fall within the pro forma period.
Where a portion or all of a contract for electricity falls within the pro forma period,
its costs are included in the Dispatch Model.s For physical electricity contracts falling
within the proforma period, the Dispatch Model also accounts for expected energy
deliveries by increasing (for sales) or decreasing (for purchases) our net load obligations.e
The Dispatch Model cannot value natural gas contracts. Natural gas is therefore
valued outside of the model at their delivery basin. The valuation uses the same natural
gas price as used in the Dispatch Model. The pro forma value of our natural gas purchases
may be found in my work papers.lo
Short-Term Power Purchases and Sales
a. How are short-term transactions included in the pro forma?
7 The WNP-3 contract was power purchased from BPA that was priced at the O&M expense of four
surrogate nuclear plants, and was originated from the settlement agreement for the never completed nuclear
plant that the then Washington Water Power had agreed to buy a small portion of.
8 Financial contracts include only costs in the Dispatch Model. Physical contracts include both costs and
delivered energy.
e Net loads include retail load plus any obligations (up or dou,n) to reflect contracts with 3'd parties resulting
from these term transactions.
10 See Kalich workpapers, Tab 11 of spreadsheet "Exhibit No. 7 - Schedules 1-6.xlsx."
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Kalich, Di
Avista Corporation
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o A. Short-term electric power prices, purchases and sales are an output of the
AURORA model. The Dispatch Model calculates both the volumes and costs of short-
term purchases and sales that balance the system's generation and long-term purchases
with retail load and other obligations.
Thermal Fuel Expense
O. How are thermal fuel expenses determined in the pro forma?
A. The Company incurs thermal fuel expenses for its Colstrip (coal), Kettle
Falls (wood-waste), and its gas-fired power plants Coyote Springs 2, Lancaster,
Rathdrum, Noftheast, Boulder Park, and Kettle Falls CT. Unit coal costs are based on
long-term coal supply and transportation agreements for Colstrip. Unit wood waste fuel
costs are based on multiple shorter-term contracts with fuel suppliers and our existing
inventory. Plant-level fuel cost are the product of unit fuel cost and the generation level
determined by the Dispatch Model. Exhibit No. 7, Schedule 5 details generation and fuel
consumption and costs for the Company's thermal plants.
Transmission Expenses
a. What changes in transmission expense are in the pro forma compared
to the test-year and the expense in current base rates?
A. We no longer include costs associated with transmission of our WNP-3
contract with BPA. The contract expires in June 2019. While power deliveries ended in
April 2019, the transmission contract went for an additional two months.
Natural Gas Transportation
a. Please explain how natural gas transportation contracts are included
in the pro forma.
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Avista Corporation
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o A. Natural gas transportation contract costs are included based on 2018 actual
expense. Benefits are less certain because the value ofthese contracts is dependent on
the basis spread between Canadian and U.S. delivery points. To estimate the value, the
pro forma contains the five-year (2014-2018) average of our actual experience optimizing
these contracts, or $1 1.25 million system.
Summary
a. Please summarize your proposed pro forma power supply expense
that is provided to Company witness Ms. Andrews for the Company's electric Pro
Forma study.
A. The net effect of my adjustments to the test year power supply expense is
an increase in2020 of $16.4 million ($152.15 - $135.73) on a system basis and a S5.683
million Idaho allocation. Overall, however, the decrease in net power supply expense in
2020, as compared to what is authorized in current base rates, is $3.143 million (ldaho
share).
IX. PCA AUTHORIZED VALUES
a. What is Avista's proposed authorized power supply expense and
revenue for the PCA?
A. The proposed authorized level of annual system net power supply expense
and revenues is $136.7 million for the pro forma. This is the sum of FERC Accounts 555
(Purchased Power), 501 (Thermal Fuel), 547 (Fuel), less Account 447 (Sale for Resale).
It also includes transmission expense and transmission revenue. The proposed level of
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Kalich, Di
Avista Corporation
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o net Renewable Energy Credits (REC) and natural gas liquids revenue is also included in
the total authorized net expense.
a. What is the level of retail sales and the proposed Load Change
Adjustment Rate for the PCA?
A. The proposed authorized level of retail sales to be used in the PCA is 2018
weather adjusted Idaho retail sales. The proposed Load Change Adjustment Rate is
$23.41lMWh for the pro forma period, which is the energy related portion of the average
production and transmission cost.
The proposed authorized PCA power supply expense and revenue, transmission
expense and revenue, REC revenues, Load Change Adjustment Rate and retail sales are
shown in Exhibit No. 7, Schedule 6.
a. Does this conclude your pre-filed direct testimony?
A. Yes, it does.
Kalich, Di
Avista Corporation
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