20220729Brandon Direct.pdf

DAYID J. MEYER
VICE PRESIDENT A}.ID CHIEF COI.JNSEL FOR
REGI.'LATORY AND GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
I4I1 E. MISSION AVENI.'E
P.O.BO)(3727
SPOKAI{E, WASHINGTON 99220
PHONE: (509) 49s-4316, FAX: [phone]
BEFORE TIIE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE POWER COST
ADruSTMENT (PCA) ANNUAL RATE
ADruSTMENT FILING OF AVISTA
CORPORATION
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CASENO. AW.E-zz-'I
DIRECT TESTIMONY OF
ANNETTE M. BRANDON
FOR AVISTA CORPORATION
1 I. INTRODUCTION
2 a. Please state your namq business address, and present position with Avista
3 Corporation.
4 A. My name is Annette M. Brandon. My business address is 141I E. Mission
5 Avenue, Spokane, Washington, and I am employed by the Company as a Wholesale Marketing
6 Manager in the Energy Supply deparhnent.
7 Q. Would you please describe your educational background and professional
8 experience?
9 A. Yes. I am a2002 graduate of Eastem Washington University with a Bachelor
10 of Arts degree in Business Administration - Professional Accounting. I started with Avista in
11 January of 1999, as a Budget Analyst in the Company's Transmission Deparfinent. I spent
12 three years in the Company's Tax Department before moving to Resource Accounting for the
13 next eight years. I joined the Regulatory Affairs Departnent as a Regulatory Analyst lr,2012
14 and was promoted to Manager Regulatory Affairs in 2013. My primary responsibilities in
l5 Regulatory Affairs related to oversight of the Furchase Gas Cost (PGA) adjustment filings and
16 Energy Recovery Mechanism/Power Cost Adjustnent (ERIWPCA) frlings in Washington and
17 ldaho, was a key contact for the Company's compensation and benefits programs, and served
l8 as Revenue Requirernent Manager for Oregon's general rate case.
19 I moved to my current role of Wholesale Contracts Manager in the Energy Supply
20 Departnent in August of 2020.In this role, my responsibilities are related to the ERM and PCA
2l annual frlings and support for development of authorized power supply in general rate case
22 proceedings. I am also the primary contact for the Company's transmission contracts, and help
23 to facilitate the Request for Proposals (RFP) processes. Ir202L,I led a special project related
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Avista Corporation
1 to the development of Avista's Clean Energy Implementation Plan, which was the first to be
2 frled in the State of Washington.
3 Q. Have you previously filed testimony in annual Power Cost Adjustment
4 proceedings?
5 A. Yes. I sponsored the power supply related testimony in the 2021 anrual PCA
6 frling. In my previous role in Regulatory Affairs, I supported testimony which provided a
7 summary of accounting entries and account balances related to the Power Cost Adjustment
8 (PCA). Like last year, Company witness Ms. Schultz sponsors the accounting testimony in this
9 filing.
10 a. What is the scope of your testimony in this proceeding?
11 A. My testimony gives an overview of power supply operations and provides a
12 srunmary of the factors contributing to the power cost deferrals during the July 1,2021through
13 June 30,2022 Review Period (Review Period).
t4 a. Are you sponsoring any work papers and supporting documentation to be
15 introduced in this proceeding?
16 A. Yes. Detailed work papers supporting the tables and other calculations in my
17 testimony have been provided in electronic format to the Commission, and other parties
18 coincident to this filing. The Company has also provided supporting documentation, including
19 details of all term natural gas and electricity transactions that flowed during the Review Period,
20 and daily position reports that show, among other things, forward price curves. Copies of long-
2L term power contracts that the Company entered during the Review Period have also been
22 provided.
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Avista Corporation
I II. OVERVIEW OF POWER STJPPLY OPERATIONS
2 a. Ifow does Avista, generally, manage its power supply resources?
3 A. Avista conducts electric planning, procurement, sales and power resource
4 management activities to assure an adequate supply of electricity to serve customer and other
5 load obligations, as well as to optimize our generation and transmission resources. Numerous
6 variables affect short-term power supply positions and prices. As suclr, we employ an Energy
7 Resources Risk Policy to recosuize and actively manage the interaction and dynamics among
8 these variables by establishing processes forpredicting future load and obligation requirements,
9 resource availability, and manage,rnent of the expected net surplus or deficit short-term and
10 immediate-termpositions.
11 It is understood that many factors cause loads to differ from estimates. It is also
12 understood that each of Avista's generating resources has inherent variability because of
13 streamflow and water storage conditions (for hydroelectric plants), mechanical limitations,
14 tr'ansmission constaints, fuel availability and conditions, ambient conditions, environmental
l5 and permit allowances and other factors.
16 Energy Supply, of which I am a member, is responsible for fuel management,
17 optimizing the use of electric resources including wholesale power contracts, obtaining, and
18 dispatching power resources to meet load obligations and providing good stewardship of
19 electric resources. Variability of resources is inherent because of weather, streamflow and wind
20 conditions, physical and operational limitations, and prevailing market-driven economics
2t related to power and fuel.
22 Energy resource planning involves significant modeling, assumptions, and estimates.
23 Actual loads are influenced by many factors and therefore rarely match forward esfimates. The
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Avista Corporation
load and generation net surplus or deficit require constant attention, and its variability dictates
that flexibility be maintained at all times. It is necessary to buy and sell energy (or financially
equivalent derivative tansactions) in hourly, daily, monthly and longer incrernents, and adjust
dispatch plans to meet prevailing conditions. As sucl5 we utilize all power and fuel tansactions
authorized in our Risk Policy to provide reliable and affordable service to Avista's electric loads
or obligations and seek to optimize additional opportunities associated with Avista's energy
resources.
a. What types of transactions will Avista enter into, as detailed and authorized
in the Company's Risk Policy?
A. The following are examples of the types of fransactions permitted in the context
of managing Avista's energy resources and serving the Company's obligations in the short-
term and intermediate-term time horizons:
o Scheduling and dispatching energy resource facilities owned or controlled by
Avista.
o Transactions with other parties for physical delivery of capacity or energy, including
fixed price and indexed or fonnula-priced fransactions.
o Ancillary services, such as reserves, load-following, generation imbalance and
others.
o Transportation, transmission, storage and capacity obligations and rights.
o Bilateral forward transactions with approved counterparties.
o Futures conhacts traded on an established commodities exchange.
. Swap agreements as a tool for fxed price financial hedges.
o Transactions that allow Avista to buy or sell electricity or natural gas at Avista's
discretion.
o Exchange agreernents (forward commodity agreements expected to be settled with
retum of the commodity rather than cash, either with or without associated
settlement prices).
o Fuel (supply, delivery, storage, excess fuel disposition) related to specific electric
generating facilities in which Avista has an ownership or contractual interest
including natural gas, coal, and biomass (wood waste) and related emission
allowances.
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Avista Corporation
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Steamflow and water storage rights and benefits related to Avista-owned or
contracted hydroelectric generation stations including coordination of the related
river systems.
a. How does Avista optimize its energy resources for the benefit of its
customers?
A. Avista optimizes its energy resources in a number of ways. Electric resource
optimization involves choices among several variables. We assess these variables to select and
execute an appropriate mix for short-term and intermediate-term objectives. lntra-month
activity during the prompt month to serve loads, optimize resources, and participate in the
electric market is reported after-the-fact in the daily position report. Electric optimization
variables include:
Scheduling and dispatching of available Avista generating units as indicated by
relevant plant parameters.
Buying fuel to operate a generating facility or selling fuel already available to
decrease or eliminate generation from a unit.
Storing or using water for hydroelectric generation that maximizes expected
generation value and arranging for water from or for other hydroelectric plants in
the coordinated river system.
Buying, selling or exchanging electricity in the wholesale market frorn/to other
utilities, power marketers, or independent power producers, including displacing
purchases and sales available to the Avista balancing area.
Buyng or selling financial contracts that hedge electric purchase or sale prices and
open positions.
Obtaining tansmission rights as may be needed to deliver or receive output to or
from any Avista generation source or any market and selling surplus ftansmission
rights.
Buymg and selling the natural gas basis spread based on natural gas transport
contract rights.
Does the Company have an active hedging program?
Yes. The Company employs a Power Supply Hedge Requirements Report tool
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Avista Corporation
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(PSHRR). The PSHRR is an analytic tool to gurde power supply hedging decisions in the short-
term forward period. It provides a process to systematically reduce open positions with forward
transactions by buying for expected shortages and selling expected surpluses. An "open"
position for this purpose is the forecasted monthly financial position that is not covered by fixed
price physical or furancial tansactions, i.e., the surplus or deficit that is subject to price risk.
The plan provides guidance but may not be followed rigidly when managernent judgment or
market conditions warrant other actions, no action, or simply a delay in taking action.
III. OVERYIEW OF DEFERRAL CALCT]LATIONS
a. Please provide an overview of the deferral calculation methodology.
A. Energy cost deferrals under the PCA are calculated each month by subtracting
base net power supply expense from actual net power supply expense to determine the change
in net power supply expense. The base levels for the Review Period result from the power
supply revenues and expenses approved by the Commission in Case No. AW-E-19-04 for July
2021 throughAugust 2021andCaseNo. AW-E-21-01 for September202l throughJwte}02?
of the Review Period. The methodology compares the actual and base amounts each month in
FERC accounts 555 (Purchased Power), 501 (Thermal Fuel), 547 (Fuel), and 447 (Sales for
Resale) to compute the change in power supply expense. These four FERC accounts comprise
the Company's major power supply cosUrevenue accounts. The PCA also includes changes in
Accounts 565 (transmission expense), and 456 (third-party transmission revenue).
In addition, actual expense and revenue for natural gas not burned is included as natural
gas sale revenue under Account 456 (revenue) and purchase expense under Account 557
(expense). This would include benefits and costs related to optimizing the value of natural gas
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Avista Corporation
I turbines and power supply's natural gas tansportation contracts. All expenses are recorded in
2 accordance with Generally Accepted Accounting Principles and FERC's Uniform System of
3 Accounts.
4 The total change in net expense under the PCA is multiplied by Idaho's share of the
5 Production/Transmission Ratio (PT Ratio) approved in association with base net power supply
6 expense. Change in Idaho retail sales is then multiplied by the Load Change Adjustnent Rate
7 (LCAR) and added or subtracted from the change in power supply expense to calculate the total
8 power expense change. 90 percent ofthe change in power expense is deferred and 10 percent
9 is retained by the Company.
10 a. Please explain how the load change adjustment is calculated in the PCA.
1l A. The PCA includes a load change adjustment to reflect the change in power
12 production and transmission expense recovered through base retail reve,nues, related to changes
13 in retail load. The LCAR calculation is based on the energy classified production and
14 transmission costs included in the Company's general rate case. The LCAR revenue adjusfinent
15 for July 2021 through August 2021 was $22.004{Wh and September 2021through Jwrc2022
16 was $24.89/]vIWh.
17 The monthly load change adjustnent in the PCA is computed by multiplying the retail
18 revenue adjustnent rate times the difference between actual and authorized monthly retail
19 Megawatt-hour sales. If actual Megawatt-hour sales are greater than base, the retail revenue
20 adjustment will result in a credit to the PCA deferral (reduces power supply costs). If actual
2l Megawatt-hour sales are less than base, the retail revenue adjustment will result in a debit to
22 the PCA deferral (increases power supply costs).
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Avista Corporation
I IV. SUMMARY OF DEFERRED POWER SUPPLY COSTS
2 Q. What were the changes in power costs during the PCA Review Period?
3 A. During the Review Period, actual net power costs were hieher than the
4 authorized (or baseline) net power costs for the Idaho jurisdiction by $5,453,000. After taking
5 into consideration the 90o/o allowable deferral percent, the total is $4,908,000 in the surcharge
6 direction.
7 Q. Please summarize the primary components which contributed to actual
8 power supply expenses being higher than the authorized level during the Review Period?
9 A. Average load exceeded authorized (baseline) load by approximately 33 average
l0 megawatts (aMW) for the year. Dependent upon timing, economics and resource availability,
l1 the Company utilized a mix of resources and market purchases to meet the demands of these
12 additional loads. Meeting the requirements of this additional load, particularly in times of high
13 prices (see Figure I below), resulted in net higher than authorized expense. The monthly shape
14 of these variances is provided in Table No. 1 below:
15 Table No. 1 - Monthlv Load Variance Compared to Authorized
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The variances generated by each resource component provide the basis for the variance
analysis in this testimony. Please see Table No. 2 for the primary components of the variance
analysis. Note in all variance tables below, a positive number represents unfavorable: a negative
number indicates favorable.
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Avista Corporation
ltlatlve load Variance Compaed to Authorlzed ]fister l+l lower G)
Period lul-21 Aur-21 Sep-21 Oct zfl Nov-211 Dec-21 lan-22 Feb-22 ilbr-22 Aor-22 t{av-221 !un-22
aMW 153 AI (11)tzrtl trztl s2 91 72 24 80 t+tl (16r
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Table No. 2 - Factors Impacting Power Suorlv Expense
For purposes of this variance analysis, workpapers provided by Avista differentiate
betwccn ttc "cost variance" (which rcpresents the pricc/quantity variancc wtrcn comparing thc
actual values to authorized as recorded to the general ledgcr), and "gcncration variancc'l lwhich
represents the value each resource contributed towards meeting customer load requirements).
The generation variance essentially reallocates the variances to the applicable resource
to represent the market value the plants provided towards meeting load requirements. As such,
the variance is a function ofboth generation deviations and the estimated market price ofpower.
This calculation is not intended to be an "cxact science", but rather a proxy value for Hcavy
Load (HL/Light Load (LL) of each component in our resource mix as compared to authorized.
! Workpapers provide the generation variancs calculation. For ease of referencq the formula is as follows:
Gen.Var: (actual HL MWh - authorized HL MWh) * Actual HL price + (actual LL MWh - authorized LL MWh)* Actual LL price.
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Avista Corporation
l. CtnSe in Net Powr Pudscs (hrdccs rt of Sdcs)
2. CtnS! inrtril lod
3. C10!E in lry&o Crrrdion
1. ChnlDinWindGercntkn
5. Choge h Thermot Gcncrrtion
5. ChqD itrNdrr.l Cns Plmt Crudbn
7. CtrF hNGt Tranmisskn Eryeose (pmlasr net ofraler)
E. fficr Mirccllmu Expcnse
Totrl Vrire to Arntorizrd
kVrire3 (20,400)
$ (4tol)
s 1,5t3
3 re52e
$ 2,330
$ t3,lf5
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$ (2(B)
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$ 7,002 $
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$ (6422) t
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5,123
(127e\
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(625)
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$ 5.453 3 0S 5.4538 ,L90t
Td.t Id&oShGVeire @9Wo
(ll,7r)7) 3 (10J37)
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(1155) t
1,35t I
6,724 $
(600 3
(20e) t
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The primary purposo is to provide an indicator as to how each component of our overall
resource stack adjusted up or down, ultimately met changing load requirements. Several factors
may have impacted these variances including market conditions, hydro conditions, maintenance
cycles, weather, and temperatures, among others. The proxy value of actual HLILL market
prices, is illustrated in Figure No. I below:
Fisure No. 1 - Power Prices in Review Period
Power Prices
Srao.m
Srzo.m
Sroo.oo
Seo.oo
Soo.oo
Sao.oo
s20.o0
s-Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
f[6tu3l LL Pre-Sched Prices
{-truthgrized LL Pre-Sched
{r ActualAvg HL pre-Sched prices
oaE Authorized HL Pre-Sched Prices
a. Please describe the contribution of each item shown above in Table No.2 to
the increase in net power supply expenses.
A. Several factors contributed to a surcharge for the annual PCA filing, primarily
driven by the increase in load described above for $3.8 million, natural gas plant generation of
$6.1 million, and hydro generation of $6.4 million (all Idaho share). These surcharges were
primarily offset by favorable net power purchases expense of $10.5 million. The remaining
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Avista Corporation
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components (comprised of wind and thermal generation, transmission, and other) combine to
account for the remaining $0.9 million of the total variance of surcharge of $4.9 million.
Provided below is a summary of the factors that, added together, resulted in an increase in
power supply expenses for the Review Period (the "Item" number references back to Table No.
2). Please note that the Company is providing work papers supporting all impacts listed in
Table No. 2 and described in more detail above.
Item No. I: Chanee in Net Power Purchase Exoense ($10.537.000 rebate directiont.
ln addition to the generation from Company-owned or operated resources, Avista
engages in both short-term market transactions (purchases and sales) as well as long-
term structured transactions with counterparties. The Company considers several factors
including economics, load requirements, and hydro conditions when evaluating the
benefits of off-system sales. For the year, sales exceeded purchases for a total net
purchase variance of 88 aMW. After assigning the cost and generation variance to each
surplus or deficit resource, the value associated with the Net Power Purchase category
was favorable by $10.5 million (Idaho share), as shown in Table No. 3 below:
Table No. 3 - Net Power Purchase Variance
Net Purchase Variance Favorable Gl / (+l Unfavonble
aMW Cost Gen Total lD Share S
Purchases 67 S a,osz S (12.434)S (4,347)S (3,912)
Sales (1s5)s (28,488)5 21,L27 s (7,361)(6,6241
Net (88)s (2o,4oo)S 9,699 s (11,708)s (10,537)
For all months within the Review Period, with the exception of July 2021, Avista was
able to sell at a higher price than included in authorized. On an annual basis, sales prices
exceeded authorized by approximately $12.00 per aMW, whereas purchases were very
close to authorized level with a variance of only $0.43 per aMW. Effectively, when
Avista was a net seller, power prices deviated from the authorized prices to a greater
degree than prices deviated from the authorized level when Avista was a net purchaser.
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Avista Corporation
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Item No. 2: Chanse in Retail Loads (53.780.000 surcharpe direciiont The impact of
the change in retail loads is the net of the deviation in actual load versus the authorized
level multiplied by the market price of power (netted against the retail revenue
adjustment). For the Review Period, Idaho retail sales were 34 aMW above the
authorized level. The biggest variance as compared to authorized was in July 2021 at
1 34 aMW in response to record high heat. In July 2021 , peakload conditions, combined
with high prices averaging $127.00 per aMW (heavy loao, resulted in an unfavorable
variance inretail loads of approximately $5.2 millionofthe $7.0 annual variance.2 This
unfavorable variance was offset by the load change adjustrnent as prices were higher
than the authorized rate. Additional information regarding the LCAR has been provided
previously in my testimony.
Item No. 3: Chanee in Hvdro Generation ($6,423,000 surcharse directionl. Total
hydro generation was lower than the authorized level by 6 aMW. Hydro generation at
Company-owned plants on the Spokane River and Clark Fork River were lower than
authorized by 4 aMW and 6 aMW respectively. Offsetting this was a favorable 4 aMW
variance due to higher than authorized generation from the Mid-Columbia contracted
hydro plants. Record high temperatures, combined with lower-than-normal
precipitation, resulted in an early seasonal runoffin 202l.Unfavorable hydro conditions
contributed to reduced generation n 2021, particularly for the July through October
time period. Reduced hydro generation, coupled with high prices resulted in a variance
of $2.4 million (of the total $6.4 million) for July alone. The remainder of the Review
Period included periods of both favorable hydro generation and unfavorable hydro
generation, driven by a variety of factors such as weather, economics, and market
conditions.
Item No. 4: Chanee in Wind Net Exoense (51.229.000 rebate directioil. Included in
this category is both the Palouse Wind Project and the Rattlesnake Wind Project, which
became operational in December 2020. Because these power purchase agreements are
2 Total annual variance is comprised of $7.0 million generation variance less $2.8 million load change adjustment,
for a net annual variance of $4.2 million (prior to sharing).
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not included in base rates in ldaho, the increase in net expense in the PCA is a function
of the actual hourly generation of the plant times the contract price, offset by the hourly
market value of the power generated, resulting in an overall favorable variance. For the
Review Period, Palouse Wind provided 40 aMW, and Rattlesnake Flat provided 49
aMW toward serving load. Rattlesnake Flat also had a favorable price variance as
compared to authorized, which offsets the higher contact price associated with Palouse
Wind.
Item No. 5: Chanse in Thermal Generatian ($1.232,000 surcharge directionl. The
change in the value of thermal generating units at Colstrip and Kettle Falls is a function
of the change in generation multiplied by the market price of power, netted against the
change in fuel expense. Colstrip generation was approximately 5 aMW above
authorized, and Kettle Falls generated 4 aIvIW below the authorized level. The value of
Kettle Falls was $ I 0l ,000 lower than the authorized level, and the value of Colstrip was
$1,332,000 higher than the authorized level, for a total surcharge of $1,232,000.
However, the new coal contract that went into effect early 2020 resulted in a higher fuel
cost for Colstrip of $29.81 per aMW vs. the authorized level for $17.37 per aMW. This
offset the value of the additional generation.
Item No. 6: Chanse in Natural Gas Generation ($6.057.000 surcharse directiont.
This item is primarily comprised of Avista's Coyote Springs II (CS2) generating station
as well as a Power Purchase Agreement (PPA) associated with Lancaster. Also included
in Avista's overall natural gas generation portfolio, categorized as "Other CT", is
Boulder Park, Rathdrum, Kettle Falls CT, and Northeast Combustion Turbine. For the
Review Period, natural gas generation contributed an additional23 aMW above what
was embedded in authorized. Lancaster contributed the most to this variarrrce, at 26
aMW above authorized. Coyote Springs 23 and Other CT contributed a favorable 8
aMW and an unfavorable 5 aMW, respectively, above authorized. The net value of this
3 Coyote Springs 2 was down from March - Jvre 2021for a transformer replacement project, which replaced
the three-phase transformer that suffered a failure in 201 8 to three single phase transformers This project was
outside of the Review Period and was addressed in the 2021 PCA filing.
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Avista Corporation
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increased generation was approximately $6.1 million (Idaho share). The value of this
additional generation was offset by approximately $11.8 million (Idaho share) in
unfavorable fuel expense due to natural gas prices, which were materially higher than
authorized as illustrated in Figure No. 2 below. For the Review Period, the average
natural gas price was $3.20 per dekatherm (actual) versus $2.58 per dekatherm
(authorized).
Fieure No. 2 - Natural Gas Prices in Reyiew Period
Natural Gas Prices (per Dth)
s10.00
se.00
Se.m
Sz.m
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Sa.m
SE.M
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S-
Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
rf trutherized Malin -!r trutherized AECO f [s1rJ3l AECO .-aF.Actual Malin
It is worth noting, however, that the increase in natural gas prices likely contributed to
the favorable variance in ltem No. 1 Net Purchases, as electric prices were pulled higher
and in periods of time when Avista was long generation, this value was captured by
selling into the market at prices well above purchases.
Item No. 7: Chanse in Net Transmission Exoense ($625.000 rebate direction). Net
transmission expense was above the authorized level primarily due to higherthird-party
transmission revenues. Third-party transmission revenues, a result from increased
purchases or sales from other regional entities utilizing our ffansmission system,
contributed approximately $1.6 million to this variance. Fluctuations in short-term
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Avista Corporation
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transmission sales are partially a function of other utilities' load/resource balance and
whether they are sellers or buyers. Transmission expense was higher than the authorized
level by approximately $0.9 million primarily due to the 2022 BPA General Rate Case
which was effective October 2021.
Item No. 8: Chanse in Mise Exoense (8188,000 rebate directiont Miscellaneous
Expense consists ofbroker fees, California Independent System Operator (CAISO) fees,
and the Montana Invasive Species. The primary contributor to the variation in this
expense was a reduction in the Montana lnvasive Species expense.
V. NEW LONG,TERM CONTRACTS ENTERED INTO DURING REYIEW PERIOD
O. Please provide a brief description of new long-term contracts that the
Company entered into during the Review Period.
A. The Company entered into one long-term power purchase contract during the
Review Period with Chelan County PUD No. I . This is a 20-year contract for the output of the
Rocky Reach Project. The Company closed out its 2020 RFP with a second contact with
Chelan for an additional 5% (88 MW/5 1 aMW) with delivery starting on Janua{v 1. 2026.4 This
contract increases to l0%o on January 1,2031, when an existing Chelan PUD contract expires
on December 31, 2030, and continues until 2045. As this contract is not effective until January
I,2026, it is not included in the Review Period.
The Company also completed two Public Utility Regulatory Policies Act (PURPA)
renewals with the City of Spokane for its Waste-to-Energy facility, and Upriver Dam.
Together, these contracts contribute an additional 43 .7 MW beginning January l, 2023 through
a As noted in my testimony in Case No. AVU-E-21-09 (the 2021 Avista PCA), Avista entered into a l0-year
contract with Chelan County PUD No. I for the output from the PLID's Rock Island and Rocky Reach hydropower
projects from2024 through 2033.
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Avista Corporation
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December 31,2037. These facilities are located within Washington State and therefore follow
Washington's PURPA requirements. However, they are system resources and flow through
Idaho's actual and authorized power supply expense.
Finally, two PURPA contracts for the University of Idaho were completed in the Review
Period. The first is for the Steam Turbine for 825 kilowatts ftW) effective February 16,2022
for 20 years. This PURPA was approved by this Commission in Order No. 35462 on July 13,
2022. The second one is fortheir Solar facility for 132.32 kW with an effective date of February
16,2022 for 20 years. This PURPA was approved by this Commission in Order No. 35440 on
Jwrc 22,2022.
YI. SUPPORTING DOCTIMENTATION
a. Please provide a brief overview of the documentation provided by the
Company in this filing.
A. The Company maintains a number of documents that record relevant factors
considered at the time of a transaction. The following is a list of documents that are maintained
and that have been provided in electonic format with this filing:
o Natural GaslElectric Transaction Records: These documents record the key details
of the price, tenns, and conditions of a tansaction. As part of Avista's workpapers
accompanying this filing, the Company has provided a confidential worksheet
showing each natural gas and electric term (balance of the month or longer)
transaction during the Review Period, including all key transaction details such as
trade date, delivery period, price, volume and counter-party. Additional information
can be provided, upon request, for any ofthese transactions.
o Position Reports: These daily reports for each trading day in the Review Period
provide a summary of transactions and plant generation and the Company's net
average system position in future periods. The Daily Position Reports also contain
Brandon, Di 16
Avista Corporation
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forward electic and natural gas prices.
o Variance Anallrsis: This analysis provides the dstail€d calculatim of the ditrerencw
betlve€Nr actual and authorized for the Review Period for each subsection desoribd
above.
Q. Does thot conclude yom pre.filed direct tesfimouy?
A. Yes.
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Avista Corporation