20260731Direct Holland.pdf

RECEIVED
JULY 31, 2026
ANNI GLOGOVAC, IDAHO PUBLIC
COUNSEL FOR REGULATORY AFFAIRS UTILITIES COMMISSION
AVISTA CORPORATION
1411 E. MISSION AVENUE
P.O. BOX 3727
SPOKANE, WASHINGTON 99220
PHONE: [phone]
[e-mail]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE POWER COST ) CASE NO. AVU-E-26-05
ADJUSTMENT (PCA) ANNUAL RATE )
ADJUSTMENT FILING OF AVISTA ) DIRECT TESTIMONY OF
CORPORATION ) KEVIN M. HOLLAND
FOR AVISTA CORPORATION

1 I. INTRODUCTION
2 Q. Please state your name, business address, and present position with Avista
3 Corporation.
4 A. My name is Kevin M.Holland.My business address is 1411 E.Mission Avenue,
5 Spokane, Washington, and I am employed by the Company as the Director of Energy Supply.
6 Q. Would you please describe your educational background and professional
7 experience?
8 A. Yes.I am a graduate of Gonzaga University with a Bachelors Degree in Business
9 (1992) and a Masters Degree in Business Administration (1996). I have over 25 years of
10 experience in the energy industry with roles in financial analysis, real-time electric system
11 operations, wholesale trading, and long-term markets. The majority of my career has been at
12 Avista Corporation, previously holding positions in Resource Marketing, Wholesale Contracts
13 and Credit,Real Time Trading, and Energy Efficiency for Avista. I left Avista for a brief period
14 in 2007, rejoining in 2012. Prior to re joining Avista Corporation in 2012, I was a Structured
15 Transaction Originator for Shell Energy North America leading multiple team efforts to secure
16 long term relationship-based contracts with energy industry companies. In 2022, I was
17 promoted to the Director of Energy Supply at Avista Corporation where I am responsible for
18 Avista's natural gas and electric business operations including trading and marketing,resource
19 planning and acquisition, strategic initiatives, contract negotiation, renewable and emissions
20 compliance, and regional initiatives participation.
21 Q. What is the scope of your testimony in this proceeding?
22 A. My testimony gives an overview of power supply operations and provides a
23 summary of the factors contributing to the power cost deferrals during the July 1,2025 through
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Avista Corporation

I June 30, 2026 review period (Review Period).
2 Q. Are you sponsoring any workpapers and supporting documentation to be
3 introduced in this proceeding?
4 A. Yes. Detailed workpapers supporting the tables and other calculations in my
5 testimony have been provided in electronic format to the Commission, and other parties
6 coincident with this filing. The Company has also provided supporting documentation,
7 including details of all term natural gas and electricity transactions that flowed during the
8 Review Period, and daily position reports that show, among other things, forward price curves.
9 Copies of long-term power contracts that the Company entered into during the Review Period
10 have also been provided.'
11 A table of contents for my testimony is as follows:
12 Description Page
13 I. Introduction 1
14 II. Overview of Power Supply Operations 2
15 III. Overview of Power Cost Adjustment Review Period 6
16 IV. Overview of Variance Components 15
17 V. New Long-Term Contracts Entered Into During Review Period 19
18 VI. Supporting Documentation 19
19
20 II. OVERVIEW OF POWER SUPPLY OPERATIONS
21 Q. How does Avista manage its power supply resources?
22 A. Avista conducts electric planning, procurement, sales, and power resource
23 management activities to ensure an adequate supply of electricity to serve customers and other
24 load obligations, as well as to optimize its generation and transmission resources. Numerous
25 variables affect power supply positions and prices. As such, the Company employs an Energy
1 No new contracts were entered into during the Review Period,only renewals of existing contracts.
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Avista Corporation

I Resources Risk Policy (Risk Policy) to address certain risks inherent to supplying energy and
2 managing energy supply resources. The Risk Policy establishes a process for forecasting future
3 load obligations and obligation requirements, the dispatch of supply side resources, and the
4 management of expected surplus or deficit positions.
5 Many factors cause the resource mix used to meet load obligations to differ from
6 estimates. Actual load obligations are influenced by many factors and, therefore, rarely match
7 forward estimates. Each of Avista's generating resources has inherent variability due to
8 streamflow and water storage conditions (for hydroelectric plants), mechanical limitations,
9 transmission constraints, fuel availability and delivery constraints, ambient conditions,
10 environmental and permit allowances, and other factors. Avista's Energy Resources
11 Department (Energy Resources) is responsible for fuel management, optimizing the use of
12 electric resources including wholesale power contracts, and dispatching power resources to
13 meet load obligations while providing good stewardship of electric resources.
14 The Energy Resources Department planning involves significant modeling,
15 assumptions, and forecasts to predict future situations. Balancing generation to match load
16 obligations requires ongoing management and the natural variability with load balancing
17 dictates that flexibility always be maintained. It is necessary to buy and sell energy (or
18 financially equivalent derivative transactions) in sub-hourly, hourly, daily, balance of the
19 month, monthly, and longer increments, as well as adjust dispatch plans to meet prevailing
20 conditions. As such,Avista utilizes all power and fuel transactions authorized in its Risk Policy
21 to provide reliable and affordable service to Avista's electric loads and contract obligations and
22 seeks to optimize additional opportunities associated with Avista's energy resources.
23 Q. What types of transactions are covered by the Company's Risk Policy?
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Avista Corporation

I A. The following are examples of the types of transactions permitted in the context
2 of managing Avista's energy resources and serving the Company's obligations in the short-
3 term and intermediate-term horizons:
4 • Scheduling and dispatching energy resource facilities owned or controlled by
5 Avista.
6 • Transactions with other parties for physical delivery of capacity or energy,including
7 fixed price and indexed or formula-priced transactions.
8 • Ancillary services, such as reserves, load-following, generation imbalance, and
9 others.
10 • Transportation, transmission, storage and capacity obligations, and rights.
I 1 • Bilateral forward transactions with approved counterparties.
12 • Future contracts traded on an established commodities exchange.
13 • Swap agreements as a tool for fixed price financial hedges.
14 • Transactions that allow Avista to buy or sell electricity or natural gas at Avista's
15 discretion.
16 • Exchange agreements (forward commodity agreements expected to be settled with
17 return of the commodity rather than cash, either with or without associated
18 settlement prices).
19 • Fuel (supply, delivery, storage, excess fuel disposition) related to specific electric
20 generating facilities in which Avista has ownership or contractual interest including
21 natural gas, coal,biomass (wood waste), and related emission allowances.
22 • Streamflow and water storage rights and benefits related to Avista-owned or
23 contracted hydroelectric generation stations including coordination of the related
24 river systems.
25
26 Q. How does Avista optimize its energy resources for the benefit of its
27 customers?
28 A. Avista optimizes its energy resources in several ways. Electric resource
29 optimization involves choices amongst several variables. The Company assesses these
30 variables, detailed below, to select and execute an appropriate mix for short-term and
31 intermediate-term objectives. Intra-month activity during the current month to serve loads,
32 optimize resources, and participate in the electric market is reported after-the-fact in the daily
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Avista Corporation

I position report if it is relevant to term positions. Electric optimization variables include:
2 • Scheduling and dispatching of available Avista generating units as indicated by
3 relevant plant parameters.
4 • Buying fuel to operate a generating facility or selling fuel already available to
5 decrease or eliminate generation from a unit(includes storage).
6 • Storing or using water for hydroelectric generation that maximizes expected
7 generation value and arranging for water from or for other hydroelectric plants in
8 the coordinated river system.
9 • Buying, selling, or exchanging electricity in the wholesale market from/to other
10 utilities, power marketers, or independent power producers, including displacing
11 purchases and sales available to the Avista balancing area.
12 • Buying or selling financial contracts that hedge electric purchase or sale prices and
13 open positions.
14 • Obtaining transmission rights as may be needed to deliver or receive output to or
15 from any Avista generation source or any market and selling surplus transmission
16 rights.
17 • Optimizing system and off-system resources for inclusion of emission free
18 resources.
19 • Buying and selling the natural gas basis spread based on natural gas transport
20 contract rights.
21 • Participating in organized markets such as the Western Energy Imbalance Market
22 (EIM), to optimize our system around regional diversity.
23 The most optimal combination of transaction options to best optimize the electric system
24 takes into consideration several factors including economics, load requirements, and hydro
25 conditions,to name a few. In addition to the dispatching of Company-owned or contracted for
26 resources, transactions typically are comprised of short-term, long-term market transactions,
27 and real-time/day-ahead purchase and sales transactions. These optimization activities are
28 recorded to several general ledger accounts in accordance with Generally Accepted
29 Accounting Principles (GAAP) and are typically comprised of hundreds of transactions. As
30 such, for purposes of testimony, transactions will be grouped according to unique transaction
31 types, such as Net Power Purchase (comprised of both sales and purchases), fuel expense,
32 hydro, etc. Please see Section IV. Overview of Variance Components for a full analysis.
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Avista Corporation

I Q. Does the Company have an active hedging program?
2 A. Yes. As part of the Risk Management Policy, Avista employs an electric
3 hedging plan to manage short-term power supply positions through price diversification and
4 layered forward transactions of natural gas and electricity. The goal is to balance financial
5 exposure to expected loads while providing reliable service at competitive costs and minimizing
6 energy supply risks. Energy Resources oversees the plan, hedging expected surpluses and
7 deficits to optimize costs. A key component of the hedging plan is the Power Supply Hedge
8 Requirements report, which helps guide buy/sell decisions based on forecasts of load, market
9 prices, hydroelectric and variable generation, and long-term contracts. While the tool provides
10 structured guidance, decisions may vary based on market conditions and management
11 judgment.
12 Q. How does the Company communicate its position within the Energy
13 Resources Team?
14 A. All changes that affect the short-term electric position are reflected each
15 business day in an electric position report. The daily report depicts estimates for loads and
16 obligations, resources, and open positions for power for each month within the first twenty-
17 eight (28) to thirty-nine (39) months in the term horizon. The daily position report will also
18 show current position status related to the hedging plan. The daily position reports for the PCA
19 year have been included within the Company's confidential workpapers.
20
21 III. OVERVIEW OF POWER COST ADJUSTMENT REVIEW PERIOD
22 Q. Please provide an overview of the Power Cost Adjustment mechanism.
23 A. The Power Cost Adjustment (PCA) mechanism is designed to align customer
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Avista Corporation

I rates with the actual cost related to serve load, by reconciling the difference between actual
2 power supply expenses and the authorized power supply expense established during a general
3 rate case and reflected in customer bills. In a general rate case filing,Avista models all available
4 Company resources based on current market conditions including forward natural gas and
5 electric prices, median hydroelectric conditions, and maintenance schedules. The model
6 (Aurora) then dispatches the portfolio of resources in the most economic manner to meet
7 customer loads to determine power supply expenses. Authorized power supply expenses also
8 include executed long-term contracts, average maintenance schedules, broker fees, and other
9 miscellaneous expenses. Avista dispatches its resources based on current prices and actual
10 operating conditions, which result in a different power supply expense than forecasted in a
11 general rate case filing.
12 Specific expenses and revenue are recorded to accounts that have been approved by the
13 Commission for inclusion in the PCA. These accounts conform with Generally Accepted
14 Accounting Practices (GAAP) and the Federal Energy Regulatory Commission's (FERC)
15 Uniform System of Accounts and are primarily related to the four(4) major power supply cost
16 and revenue accounts, which include FERC accounts 555 (Purchased Power), 501 (Thermal
17 Fuel), 547 (Fuel), and 447 (Sales for Resale). Also included in the PCA are the costs related to
18 transmission in accounts 565 (transmission expense), 456 (third-party transmission revenue),
19 natural gas sales revenue under account 456 (revenue), purchase fees for fuel expense under
20 account 557 (expense), and 537 (MT invasive species). These accounts are included to capture
21 the actual revenue and costs related to optimizing the value of natural gas turbines and power
22 supply's natural gas transportation contracts.
23 Q. How is the PCA deferral calculated?
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Avista Corporation

I A. The PCA deferral is the difference between authorized and actual expenses
2 during the PCA period. This value is calculated by subtracting authorized net power supply
3 expense from actual net power supply expense to determine the change in net power supply
4 expense. 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 authorized power
6 supply expense. Changes in Idaho retail sales are then multiplied by the LCAR and added to or
7 subtracted from the change in power supply expense to calculate the total power expense
8 change. Ninety percent (90%) of the change in power expense is included in the deferral
9 mechanism while the remaining ten percent (10%) is absorbed by the Company.
10 The authorized level of expense for the Review Period is made up of two separate cases.
11 The July through August 2025 authorized expense levels were based on twelve (12) months
12 ending August 31, 2022, and established in Case No. AVU-E-23-01, while September 2025
13 through June 2026 authorized expense levels were based on twelve (12) months ending June
14 30, 2024, and established in Case No. AVU-E-25-07.
15 Q. What were the changes in power costs during the PCA Review Period?
16 A. During the Review Period, actual net power costs were higher than the
17 authorized net power costs for the Idaho jurisdiction by $8,925,161 (excluding incremental
18 operations and maintenance (O&M) costs associated with EIM and interest). After taking into
19 consideration the 90% allowable deferral percent, the total PCA deferral is $8,032,648 in the
20 surcharge direction. Company witness Ms. Brandon discusses the total Idaho PCA deferral as
21 $5,565,602 in the surcharge direction,which includes the$8,032,648 surcharge associated with
22 net power supply costs plus incremental O&M costs associated with EIM (discussed below) at
23 90%of$194,495. Lastly,these values were offset by$2,717,969 recorded as a rebate resulting
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Avista Corporation

I from transfer of Renewable Energy Credits (RECs).
2 Q. What was the amount associated with the incremental O&M Costs
3 associated with the Energy Imbalance Market (EIM)?
4 A. The incremental O&M expense associated with EIM for the Review Period
5 totaled $216,105 or $194,495 after sharing with the Company based on 90%/10% sharing
6 (excluding interest)2.
7 Q. Please summarize the primary contributors to the variance between actual
8 power supply expenses and authorized for the PCA Review Period.
9 A. For the PCA Review Period, the most notable market conditions that impacted
10 the PCA deferral are attributed to: 1) a downward shift in market energy pricing, which had
11 impacts throughout the portfolio but most directly to "Net Power Purchases Expense", which
12 is the sum of the Company's market purchases and market sales, 2) wind generation resources
13 excluded from the authorized base for the September 2025 through August 2026 period and, 3)
14 higher customer loads during several months of the year. A full variance analysis is provided
15 in Section IV of this testimony.
16 Q. Please describe how market purchases and sales contributed to the PCA
17 surcharge for the 2025-2026 period?
18 A. The value of market energy is a key driver for how Avista strategically optimizes
19 its resource portfolio and Net Power Purchase Expense (NPE) is significantly influenced by
20 changes in market pricing. As Avista is predominantly a net exporter of energy, a downward
2 Per Order No. 35156 in Case No. AVLJ-E-21-01, dated September 1, 2021, the Commission approved the
Settlement Stipulation, where the Parties to the case agreed that effective with the expected "go live" March 1,
2022 date,the Company will begin to reflect Idaho's share of incremental EIM O&M expenses through the PCA
up to Idaho's share of EIM benefits that also will flow through the PCA.
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Avista Corporation

I shift in market prices reduces the overall value received for the surplus energy sold. When
2 prices are higher, the value of Avista's generating portfolio increases and customers typically
3 benefit in the form of surplus market sales. Conversely, when prices are lower, it may be more
4 cost-effective to meet portions of load with market purchases rather than Company-owned or
5 contracted-for generation.
6 The Company continuously evaluates whether to sell excess generation or purchase
7 from the market, selecting the combination that minimizes total power supply costs for
8 customers. In addition to short-term market transactions, when market conditions deem
9 appropriate,day-ahead purchases not utilized to meet load requirements were sold on an hourly
10 basis, reducing overall power supply expenses.
11 For each month in the Review Period, with the exception of July, electricity market
12 prices at the Mid-Columbia (Mid-C) trading hub were lower than authorized (heavy load and
13 light load). For natural gas, the actual price for both AECO and Malin were below the
14 authorized level in all twelve months. While the decreases in prices were a key reason for the
15 decreased value of surplus sales,the Company was able to optimize any excess in its generation
16 portfolio in the most economic manner. The result was a surcharge, netting purchases with
17 surplus sales, of approximately $2.6 million(prior to sharing) on an Idaho basis.
18 Q. How were electric prices different than those assumed in the authorized
19 level of power supply expense?
20 A. As noted above, electricity prices at Mid-C market during the Review Period
21 were significantly lower than the prices forecast at the time Authorized Net Power Supply was
22 set. There are several factors that impact prices including river conditions affecting the
23 availability of hydroelectric power generation, customer demand/peak load needs, weather
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Avista Corporation

I conditions, transmission constraints and state and federal policy mandates, to name a few.
2 Figure No. 1 below illustrates the Mid-C actual power prices versus the Mid-C power prices
3 approved and authorized.
4 Figure No. 1 —Mid-C Power Prices (July 2025 through June 2026)
5 Actual vs. Authorized Power Prices
$100 — —
6 $89.50
$90 $85.08 —
$80.51
7 $80 $73.35 '•571.16
$70 $66.76
8 $60 , $s7.ga',
L $as�s4 ••.�
3 $so
9 $40.71 $40.84 "$40.59 $41.97
vi $38.10 $40.41
27.99 $27.41 $29.30,.•''*•
10 $30 $24.58
$20 — $12.29 $11.78 $14.91 $12.33
11 $10
12 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
HL-Actual LL-Actual •••••• HL-Authorized LL-Authorized
13
14 A key reason for the pricing changes is due to market pricing shifting in response to
15 increased volumes of variable energy that have been flowing into western energy market.
16 Beyond regional hydro conditions, pricing dynamics have begun to include factors such as
17 CAISO solar output, regional wind regimes, and the effects of significant battery storage. The
18 result has been reduced seasonal volatility and reduced overall average market price for the
19 year. This dynamic had not yet begun to significantly materialize until after authorized was
20 established. The change in market behavior has resulted in less peaks within the actual power
21 pricing and instead creates more levelized power pricing, which reduces the optimization
22 opportunities Avista traditionally benefitted from in the past, given our position being long in
23 generation.
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Avista Corporation

I Q. Please describe the conditions that impacted hydroelectric generation
2 during the Review Period.
3 A. Hydroelectric generation during the Review Period reflected a combination of
4 above-normal precipitation, sustained warm temperatures, and varying snowpack conditions
5 across the Company's service territory. Higher-than-normal precipitation during November and
6 December 2025, particularly in the Clark Fork basin and British Columbia, increased water
7 availability entering the winter season. This was followed by several months of warmer-than-
8 normal temperatures during early 2026,which accelerated snowmelt and increased river flows.
9 As a result,hydroelectric generation exceeded expectations from December 2025 through April
10 2026.
11 Conditions varied across river basins. Snowpack in the Clark Fork basin remained near
12 normal, while snow water equivalent in the Spokane River basin was well below normal. In
13 contrast, strong snowpack conditions in British Columbia helped support water supply and
14 generation throughout the Columbia River system. Warmer temperatures accelerated the
15 depletion of lower-elevation snowpack, which reduced runoff during the late spring and early
16 summer months. As a result, hydroelectric generation fell below authorized levels from May
17 through June 2026.
18 Overall,the weather pattern primarily shifted the timing of water availability rather than
19 significantly changing total annual water supply. Earlier runoff increased winter and spring
20 generation but reduced generation opportunities later in the year. As a result, average
21 hydroelectric generation for the Review Period was 695 aMW, compared to an authorized
22 forecast of 654 aMW, an increase of 41 aMW. On a total variance basis, actual hydroelectric
23 generation costs were only $1.8 million lower than authorized for the Review Period. Figure
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Avista Corporation

I No. 2 below provides the Review Period monthly actual and authorized hydroelectric
2 generation along with the Mid-C prices that were available at the time of those variances.
3 Figure No. 2 - Hydroelectric Generation and Mid-C Prices (July 2025 -June 2026)
4
Hydroelectric Generation July 2025 through June 2026
5 1,000 $60
6 900
$800 � v
v
7 700 $40
600 a
8 500 $30 s 400
300 $20 `v
9 Q
200 $10 �
10 100
11 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
12 �Act �Auth f Price Mid-C On Peak
13 Q. How was natural gas generation and prices different than those assumed in
14 the authorized level of power supply expense?
15 A. Natural gas prices also remained lower than authorized for most of the year with
16 a more significant pricing difference occurring beginning in the winter months. During this
17 time, actual pricing at both AECO and Malin began trending lower than authorized and the
18 trend continued throughout the remainder of the PCA Review Period. See Figure No. 3 for
19 monthly natural gas prices during the Review Period.
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Avista Corporation

I Figure No. 3 -Natural Gas Prices (July 2025 through June 2026)
2 Actual vs.Authorized Natural Gas Prices
$6.00 $5.6 $5.6
........................$5.3
3 $5.00 —
s4.4,
4 $4.00 $3.8 '•.$3.9
$3.6
$3.2 $3.353 1
5 $3.00
'^ $2.24
.........................
6 $1.34 $1.20 $1.3
..$0.90 $0.96
$1.00
50.24
7 $0.00
Jul Aug Sep Oct Nov Dec )an Feb Mar Apr May Jun
8 Malin-Actual AECO-Actual ••••••Malin-Authorized ••••••AECO-Authorized
9 The Company generated less energy from its natural gas resources during the year than
10 the authorized level of expected generation.As noted above,natural gas generation is evaluated
11 as part of Avista's overall generation portfolio. When system load requirements have been met
12 and excess natural gas-fired generation is available,the Company may dispatch those resources
13 to capture the benefits of surplus market sales. During the Review Period, however, depressed
14 wholesale electricity prices reduced the economic value of excess generation,resulting in fewer
15 opportunities to optimize generation and lower natural gas output relative to authorized levels.
16 Figure No. 4 below provides an illustration of the natural gas generation during the Review
17 Period.
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Avista Corporation

I Figure No. 4 -Natural Gas Generation (July 2025 through June 20261
2 Natural Gas Generation
3 600,000
4 500,000
5 400,000
6 L
300,000
7
200,000
8
100,000
9 11,
10 Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26
■Actual ■Authorized
11
12
13 IV. OVERVIEW OF VARIANCE COMPONENTS
14 Q. Please provide an overview of each component of the variance analysis.
15 A. Based on timing, economic factors, and available resources, the Company
16 combined resources and market transactions to meet its current demands and capitalize on
17 market opportunities. The impact of the transactions is reflected in various general ledger
18 accounts and should be viewed collectively. However, due to the numerous transactions for
19 each category, a direct one-to-one analysis fails to capture the nuances associated with
20 providing energy in every hour of the Review Period.3
21 For purposes of this variance analysis, workpapers provided by Avista differentiate
22 between the "cost variance" (which represents the price/quantity variance when comparing the
s Please note the Company has provided workpapers supporting all impacts listed in Table No. 1.
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Avista Corporation

I actual values to authorized as recorded to the general ledger), and "generation variance"4
2 (which represents the value each resource contributed towards meeting customer load
3 requirements). Table No. 1 below provides an overview by resource type of the variances
4 between the authorized power supply expense and the actual expense recorded in the Review
5 Period. Please note,the variance explanations represent the total variance,prior to Idaho's 90%
6 share.
7 The generation variance essentially reallocates the variances to the applicable resource
8 to represent the market value the plants provided towards meeting load requirements. As such,
9 the variance is a function of both generation deviations and the forecasted market price of
10 power. This calculation is not intended to be an "exact science," but rather a proxy value for
I I Heavy Load (HL)/Light Load (LL) of each component in our resource mix as compared to
12 authorized. The primary purpose is to provide an indicator as to how each component of
13 Avista's overall resource stack adjusted up or down to meet changing load requirements.
14 Table No. 1 -Actual to Authorized Variance ($ in thousands)
15 Idaho
Cost Generation Total Share @
16 Variance Variance Variance 90%
1. Change in Net Power Purchases(Purchases net of Sales) $ 771 $ 1,865 $ 2,636 $ 2,372
17 2. Change in Natural Gas Plant Generation $ (3,108) $ 1,922 $ (1,186) $ (1,068)
3. Change in Thermal Generation $ 829 $ (253) $ 576 $ 519
18 4. Change in Wind Generation $ 7,583 $ (4,530) $ 3,054 $ 2,748
19 5. Change in Hydro Generation $ (281) $ (560) $ (841) $ (756)
6. Change in Retail Load $ 1,210 $ 1,556 $ 2,766 $ 2,489
20 7. Change in Net Transmission Expense(purchases net of sales) $ 1,394 $ - $ 1,394 $ 1,254
8. Other Miscellaneous Expense $ 527 $ - $ 527 $ 474
21 Total Variance to Authorized $ 8,925 $ - $ 8,925 $ 8,033
4 Workpapers provide the generation variance calculation. For ease of reference, 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

I For the following sections,please refer to the individual line items and values provided in Table
2 No. 1 above. Note these numbers represent system, prior to sharing.
3 Item No. 1: Change in Net Power Purchase Expense ($2,635,959 higher than
4 authorized base).As previously discussed,in addition to the generation from Company-
5 owned or operated resources, the Company considers several factors including
6 economics, load requirements, and hydroelectric conditions when evaluating the
7 benefits of off-system sales. When economic to do so, the Company engages in daily
8 and hourly short-term market transactions (purchases and sales), as well as long-term
9 transactions with counterparties. For the PCA year, the actual purchases and the actual
10 sales both exceeded authorized by 95 aMW and 132 aMW respectively for a combined
11 Net Power Purchases variance of actual over authorized of 37 aMW.
12
13 Item No. 2: Change in Natural Gas Generation ($1,186,205 lower than authorized
14 base). This item is primarily comprised of Avista's Coyote Springs II(CS2) generating
15 station as well as a Power Purchase Agreement (PPA) associated with Lancaster. Also
16 included in Avista's overall natural gas generation portfolio, categorized as"Other CT"
17 is Boulder Park, Rathdrum, Kettle Falls Combustion Turbine, and Northeast
18 Combustion Turbine. For the Review Period, natural gas generation was lower than
19 anticipated in the authorized base forecast by 61 aMW. On a cost basis, natural gas
20 generation was approximately $3.1 million lower than what was forecasted in the
21 authorized,however,after netting against the generation variance of$1.9 million higher
22 than authorized, the total actual expenses were $1.2 million lower than authorized for
23 the Review Period. The generation variance removes the impact of the volume variance
24 (actual less than authorized), more accurately reflecting the value of these resources.
25
26 Item No. 3: Change in Thermal Generation ($576,331 higher than authorized base).
27 Costs related to coal contract prices at Colstrip were the primary contributor to higher
28 expense than embedded in the authorized base level for thermal generation. The
29 contractual price is $31.41 cost per ton compared to an authorized level of$29.33 cost
30 per ton. The contract price includes a base price that is adjusted annually based on six
31 (6) inflation adjustments for labor and benefits, diesel fuel, electricity, explosives,
32 mining machinery and equipment, and implicit price deflator. In total, the impact of
33 these inflation adjustments exceeded those anticipated when setting the authorized base.
34 As compared to authorized, actual costs exceeded the amount embedded in customers
35 rates by $829,171 (cost variance). The generation variance partially offsets the cost
36 variance by $252,845, resulting in net costs higher than authorized by $576,331.
37
38 Item No. 4. Change in Wind Net Expense ($3,053,505 higher than authorized base).
39 Included in this category are the Palouse Wind Project, the Rattlesnake Flat Wind
40 Project, and Clearwater Wind III Power Purchase Agreements. For the Review Period,
41 generation from wind projects exceeded authorized by 64 aMW. On a cost basis, wind
42 generation was approximately$7.6 million higher than what was included in authorized
43 and after netting against the generation variance of $4.5 million, the total actual
44 expenses were $3.1 million higher than authorized for the Review Period.
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Avista Corporation

1
2 Note that since the PCA Review Period covers two different periods of authorized base,
3 there are more nuanced variances within the wind generation resource category. First,
4 Palouse Wind was removed in the September 2025 through June 2026 Authorized Base,
5 however, two months' worth of expense were included in authorized for July 2025 and
6 August 2025. Similarly, both Rattlesnake and Clearwater were included in the
7 September 2025 through June 2026 Authorized Base,but not included in July 2025 and
8 August 2025.
9
10 Item No. 5: Change in Hydro Generation ($840,539 lower than authorized base).
11 The Hydroelectric Generation category includes the cost related to Avista's owned
12 hydro operations,long term power purchase for Mid-Columbia hydroelectric generation
13 with Chelan PUD, Grant PUD, Douglas PUD and Columbia Basin Hydro (CBHP).
14 These contracts provide reliable capacity for Avista's system in addition to energy.
15
16 Overall,total hydroelectric generation was higher than the authorized level by 41 aMW
17 during the PCA period. Company-owned plants on the Spokane River were lower than
18 authorized by 14 aMW and plants on the Clark Fork River were higher than authorized
19 by 24 aMW, netting 10 aMW over authorized. Hydroelectric generation from the Mid-
20 Columbia contracted hydroelectric plants were higher than the authorized base level by
21 38 aMW. CBHP also had a small variance of 7 aMW under authorized which
22 contributed to the actual generation being 41 aMW above authorized.
23
24 Actual expenses related to Mid-C Hydro were higher than authorized by $679,169
25 which was offset by CBHP which had expenses lower than authorized by $959,787,
26 netting $280,618 of variance. The generation variance added an additional $559,921 to
27 that total with actual expenses lower than authorized. In total, power supply expense
28 lower than anticipated authorized base by$840,539.
29
30 Item No. 6: Change in Retail Loads ($2,766,022 higher than authorized base). The
31 impact of the change in retail loads is the net of the deviation in actual load (MWh)
32 versus the authorized level (MWh) multiplied by the market price of power (netted
33 against the LCAR). For the Review Period, Idaho retail sales were 5 aMW below the
34 authorized level.
35
36 Item No. 7. Change in Net Transmission Expense($1,393,516 higher than authorized
37 base).Net transmission expense is comprised of transmission revenue and transmission
38 expense. For the PCA period,Net Transmission Expense was higher than the authorized
39 level primarily from lower than normal short-term and non-firm use of Avista's
40 transmission system in the Review Period(i.e., less revenue from third party use of our
41 transmission system).
42
43 Item No. 8: Change in Misc. Expense ($526,570 higher than authorized base).
44 Miscellaneous Expense consists of broker fees, California Independent System
45 Operator(CAISO) fees, and Montana Invasive Species expenses.
46
Holland, Di 18
Avista Corporation

I V. NEW LONG-TERM CONTRACTS ENTERED INTO DURING REVIEW PERIOD
2 Q. Please provide a brief description of new long-term contracts that the
3 Company entered into during the Review Period.
4 A. Avista did not enter any new PPA contracts during the Review Period.However,
5 there was two Public Utility Regulatory Policies Act of 1978 ("PURPA") contracts that were
6 renewed during the Review Period: Jim Ford (Ford Hydro, LLC) was renewed with a contract
7 start date of July 1, 2026, which was approved in Final Order No. 37073 in Case No. AVU-E-
8 26-03 and University of Idaho's Solar project, which was approved by the Commission on
9 February 20, 2026 in Case No. AVU-E-25-16, Order No. 36942.
10
11 VI. SUPPORTING DOCUMENTATION
12 Q. Please provide a brief overview of the documentation provided by the
13 Company in this filing.
14 A. The Company maintains a number of documents that record relevant factors
15 considered at the time of a transaction. The following is a list of documents that are maintained
16 and that have been provided in electronic format with this filing:
17 • Natural Gas/Electric Transaction Records: These documents record the key details
18 of the price, terms, and conditions of a transaction. As part of Avista's workpapers
19 accompanying this filing, the Company has provided a confidential worksheet
20 showing each natural gas and electric term (balance of the month or longer)
21 transaction during the Review Period, including all key transaction details such as
22 trade date, delivery period,price,volume, and counterparty. Additional information
23 can be provided,upon request, for any of these transactions.
24
25 • Position Reports: These daily reports for each trading day in the Review Period
26 provide a summary of transactions and plant generation and the Company's net
27 average system position in future periods. The Daily Position Reports also contain
28 forward electric and natural gas prices.
29
30 • Variance Analysis: This analysis provides the detailed calculation of the differences
Holland, Di 19
Avista Corporation

I between actual and authorized for the Review Period for each subsection described
2 above. Please note, this analysis excludes incremental O&M costs associated with
3 EIM and interest.
4
5 • Contracts: Avista did not enter into any new contracts during the Review Period,
6 however renewal contracts have been included in this filing.
7
8 Q. Does that conclude your pre-filed direct testimony?
9 A. Yes.
Holland, Di 20
Avista Corporation