20250731Direct Holland.pdf

DAVID J. MEYER, ESQ.VICE PRESIDENT AND COUNSEL OF
REGULATORY AND GOVERNMENTAL AFFAIRS
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-25-07
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. Have you previously filed testimony in annual Power Cost Adjustment
22 proceedings?
23 A. Yes, I provided testimony related to our 2024 Idaho PCA filing in Case No.
Holland, Di 1
Avista Corporation

I AVU-E-24-07.
2 Q. What is the scope of your testimony in this proceeding?
3 A. My testimony gives an overview of power supply operations and provides a
4 summary of the factors contributing to the power cost deferrals during the July 1,2024,through
5 June 30, 2025, review period(Review Period).
6 Q. Are you sponsoring any workpapers and supporting documentation to be
7 introduced in this proceeding?
8 A. Yes. Detailed workpapers supporting the tables and other calculations in my
9 testimony have been provided in electronic format to the Commission, and other parties
10 coincident with this filing. The Company has also provided supporting documentation,
11 including details of all term natural gas and electricity transactions that flowed during the
12 Review Period, and daily position reports that show, among other things, forward price curves.
13 Copies of long-term power contracts that the Company entered into during the Review Period
14 have also been provided.
15
16 II. OVERVIEW OF POWER SUPPLY OPERATIONS
17 Q. How does Avista manage its power supply resources?
18 A. Avista conducts electric planning, procurement, sales, and power resource
19 management activities to ensure an adequate supply of electricity to serve customer and other
20 load obligations, as well as to optimize its generation and transmission resources. Numerous
21 variables affect short-term power supply positions and prices. As such, the Company employs
22 an Energy Resources Risk Policy(Risk Policy)to recognize and actively manage the interaction
23 and dynamics amongst these variables by establishing processes for forecasting future load and
Holland, Di 2
Avista Corporation

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

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

1 • Scheduling and dispatching of available Avista generating units as indicated by
2 relevant plant parameters.
3 • Buying fuel to operate a generating facility or selling fuel already available to
4 decrease or eliminate generation from a unit(includes storage).
5 • Storing or using water for hydroelectric generation that maximizes expected
6 generation value and arranging for water from or for other hydroelectric plants in
7 the coordinated river system.
8 • Buying, selling, or exchanging electricity in the wholesale market from/to other
9 utilities, power marketers, or independent power producers, including displacing
10 purchases and sales available to the Avista balancing area.
11 • Buying or selling financial contracts that hedge electric purchase or sale prices and
12 open positions.
13 • Obtaining transmission rights as may be needed to deliver or receive output to or
14 from any Avista generation source or any market and selling surplus transmission
15 rights.
16 • Optimizing system and off-system resources for inclusion of emission free
17 resources.
18 • Buying and selling the natural gas basis spread based on natural gas transport
19 contract rights.
20 • Participating in organized markets such as the Western Energy Imbalance Market
21 (EIM), to optimize our system around regional diversity.
22 Q. Does the Company have an active hedging program?
23 A. Yes. As part of the Risk Management Policy, Avista employs an electric
24 hedging plan to manage short-term power supply positions through price diversification and
25 layered forward transactions of natural gas and electricity. The goal is to balance financial
26 exposure to expected loads while providing reliable service at competitive costs and minimizing
27 energy supply risks. Energy Resources oversees the plan, hedging expected surpluses and
28 deficits to optimize costs. A key component of the hedging plan is the Power Supply Hedge
29 Requirements Report(PSHP),which helps guide buy/sell decisions based on forecasts of load,
30 market prices, hydroelectric and variable generation, and long-term contracts. While the tool
31 provides structured guidance, decisions may vary based on market conditions and management
32 judgment.
Holland, Di 5
Avista Corporation

I Q. How does the Company communicate its position within the Energy
2 Resources Team?
3 A. All changes that affect the short-term electric position are reflected each
4 business day in an electric position report. The daily report depicts estimated loads and
5 obligations, estimated resources, and estimated open positions for power for each month within
6 the first thirty (30) to forty-one (41) months in the term horizon. The daily position report will
7 also show current position status compared to the PSHP. The daily position reports for the PCA
8 year have been included within the Company's confidential workpapers.
9
10 III. OVERVIEW OF POWER COST ADJUSTMENT
11 Q. Please provide an overview of the Power Cost Adjustment mechanism
12 A. The Power Cost Adjustment (PCA) mechanism is designed to align customer
13 rates with the actual cost related to serve load, by reconciling the difference between actual
14 power supply expenses and the authorized power supply expense established during a general
15 rate case and reflected in customer bills. In a general rate case filing,Avista models all available
16 Company resources based on current market conditions including forward natural gas and
17 electric prices, median hydroelectric conditions, and maintenance schedules. The model
18 (Aurora) then dispatches the portfolio of resources in the most economic manner to meet
19 customer loads to determine power supply expenses. Authorized power supply expenses also
20 includes executed long-term contracts, average maintenance schedules, broker fees, and other
21 miscellaneous expenses. Avista dispatches its resources based on current prices and actual
22 operating conditions, which result in a different power supply expense than estimated in a
23 general rate case filing.
Holland, Di 6
Avista Corporation

I Specific expenses and revenue are recorded to accounts that have been approved by the
2 Commission for inclusion in the PCA. These accounts conform with Generally Accepted
3 Accounting Practices(GAAP)and Federal Energy Regulatory Commission's(FERC)Uniform
4 System of Accounts and are primarily related to the four (4) major power supply cost and
5 revenue accounts which include FERC accounts 555 (Purchased Power), 501 (Thermal Fuel),
6 547 (Fuel), and 447 (Sales for Resale). Also included in the PCA is the cost related to
7 transmission in accounts 565 (transmission expense), 456 (third-party transmission revenue),
8 natural gas sales revenue under account 456 (revenue), and purchase for fuel expense under
9 account 557 (expense). These accounts are included to capture the actual revenue and costs
10 related to optimizing the value of natural gas turbines and power supply's natural gas
11 transportation contracts.
12 Q. How is the PCA deferral calculated?
13 A. The PCA deferral is the difference between authorized and actual expenses
14 during the PCA period. This value is calculated by subtracting authorized net power supply
15 expense from actual net power supply expense to determine the change in net power supply
16 expense. The total change in net expense under the PCA is multiplied by Idaho's share of the
17 Production/Transmission Ratio (PT Ratio) approved in association with authorized power
18 supply expense. Changes in Idaho retail sales is then multiplied by the Load Change Adjustment
19 Rate (LCAR) and added to or subtracted from the change in power supply expense to calculate
20 the total power expense change. Ninety percent (90%) of the change in power expense is
21 included in the deferral mechanism while the remaining ten percent (10%) is absorbed by the
22 Company.
23 Q. What were the changes in power costs during the PCA Review Period?
Holland, Di 7
Avista Corporation

I A. During the Review Period,actual net power costs were lower than the authorized
2 net power costs for the Idaho jurisdiction by$5,753,074 (excluding incremental operations and
3 maintenance (O&M) costs associated with EIM and interest). After taking into consideration
4 the 90%allowable deferral percent,the total PCA deferral is$5,177,764(excluding incremental
5 O&M costs associated with EIM and interest) in the rebate direction. Company witness Ms.
6 Brandon discusses the total Idaho PCA deferral as $7,913,979 in the rebate direction, which
7 includes the $5,177,764 rebate associated with net power supply costs plus incremental O&M
8 costs associated with EIM(discussed below)at 90%of$324,712, and$2,755,522 was recorded
9 in the rebate direction resulting the transfer of Renewable Energy Credits (RECs).
10 Q. What was the amount associated with the incremental O&M Costs
11 associated with the Energy Imbalance Market (EIM)?
12 A. The incremental O&M expense associated with EIM for the Review Period
13 totaled $360,791 or $324,712 after sharing with the Company based on 90%/10% sharing
14 (excluding interest)'.
15 Q. What was the amount associated with the incremental O&M Costs
16 associated with the Energy Imbalance Market (EIM)?
17 A. The incremental O&M expense associated with EIM for the Review Period
18 totaled $360,791 or $324,712 after sharing with the Company based on 90%/10% sharing
19 (excluding interest).
1 By Order No. 35156 in Case No. AVU-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.
2 By Order No. 35156 in Case No. AVU-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,
Holland, Di 8
Avista Corporation

I Q. Please summarize the market conditions in effect during the Review Period
2 that contributed to the variance between the actual power supply expense level and the
3 authorized power supply expense level.
4 A. There are several variables that contribute to differences between authorized
5 power supply expense and actual power supply expenses. Market conditions including
6 hydroelectric conditions, electric prices, natural gas prices, weather, and liquidity, to name a
7 few, can play a significant role in these variances. The older the authorized base is, the less
8 probable the authorized base will accurately reflect the actual market conditions that are
9 experienced in the applicable year. This leads to more likelihood of a variance between
10 authorized and actual expenses For Avista,the PCA year expense levels were based on twelve
11 (12) months ending August 31, 2022, and established in Case No. AVU-E-23-01. While
12 authorized power supply expense is intended to capture all future assumptions of energy costs,
13 it is unable to account for the unknown variables that are affected both by Avista's owned assets
14 and external market conditions. Avista manages its overall portfolio of resources to obtain the
15 most economic combination to meet customer needs,while optimizing resources to reduce costs
16 where possible.
17 For the PCA Review Period,the most notable market conditions that impacted the PCA
18 deferral are attributed to: 1) increased activity in both market purchases and market sales which
19 was the primary contributor to the rebate balance; offset by 2) a higher level of generation from
20 Avista's natural gas-fired generation sources; and 3) lower than forecasted streamflow which
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.
Holland, Di 9
Avista Corporation

I reduced hydroelectric generation from both Avista-owned and contracted-for resources. A full
2 variance analysis is provided in Section IV of this testimony.
3 Q. Please describe how market purchases and sales contributed to the PCA
4 rebate for the 2024-2025?
5 A. The primary factor which contributed to the rebate position for the PCA year is
6 reflected in the level of wholesale sales and purchases. In periods of time when Avista's total
7 load was met by Avista resources, excess energy was sold, and the revenue was credited to
8 wholesale sales. On a monthly basis, wholesale sales alone were approximately $16.5 million
9 per month or an annual level of $199 million — approximately $141 million more than
10 embedded in authorized power supply costs. This sales revenue more than offset market
1 1 purchases of approximately $41 million, for a net favorable impact (purchases net of sales) of
12 $99 million(system)when compared to authorized wholesale purchases and sales. Conversely,
13 when load exceeded Avista resources, Avista served that portion of its load with market
14 resource purchase at the market price available at that time.
15 In addition to daily or hourly transactions, Avista also engaged in both short-term
16 market transactions (purchases and sales) as well as long-term structured transactions with
17 counterparties for this period. Finally, Avista's real time and day ahead trading groups were
18 able to capture the time-spread associated with purchases and sales. When market conditions
19 deemed appropriate, day ahead purchases not utilized to meet load requirements were sold on
20 an hourly basis, reducing overall power supply expenses. These transactions, described above,
21 contributed to the increased value of sales, entirely offsetting any purchases cost.
22 Q. How were natural gas price generation and prices different than those
23 assumed in the authorized level of power supply expense?
Holland, Di 10
Avista Corporation

I A. Natural gas generation exceeded authorized levels due to its economic
2 advantage in serving load and optimizing resources. Despite higher gas prices, market
3 conditions often made generation more cost-effective than purchasing power. Rising market
4 heat rates' boosted revenue, as the generation fleet became economically viable more
5 frequently.A plant is considered economic when its fuel cost per megawatt(MW)is lower than
6 market power prices. Overall,natural gas remained a beneficial source for customer needs,not
7 only to serve load and support reliability, but also in the form of wholesale market sales and
8 revenue.
9 Overall, average monthly natural gas pricing during the Review Period was far more
10 stable than in the prior year with pricing. See Figure No. 1 for monthly natural gas prices during
11 the Review Period.
12 Figure No. 1 -Natural Gas Prices (July 2024 through June 2025)
13
Natural Gas Prices
14 $4 $3.65
$3.41
15 $4$3 $2.90 $2.68
$2.33 $2.52
L $3 $2.22 $2.11
16 $1.95 $1.78 $1.88
$2 $1.51
+n $2 .69
171.31 $1.42
$1 250,0000
18 $1 0.35 $0.64
$0
Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
19
—*--Malin-Actual —0--AECO-Actual
20
3 Heat rate is a key measure of how efficiently a power plant converts fuel into electricity.The lower the heat rate,
the more efficient the plant—because it uses less fuel to generate the same amount of electricity. (Heat rate =
energy input(natural gas price)/electricity output(electric price)
Holland, Di 11
Avista Corporation

I Q. How were electric prices different than those assumed in the authorized
2 level of power supply expense?
3 A. Natural gas prices, described above, are highly correlated with power prices,
4 however, there are several other factors that impact electric prices. These include river
5 conditions which impact the availability of hydroelectric power generation, customer
6 demand/peak load needs, weather conditions, transmission constraints and state and federal
7 policy mandates, to name a few. For the Review Period, temperature and weather patterns
8 continue to be reflected with load. This is particularly evident in February, when loads were
9 higher than the authorized level and power prices reflected this increase in demand. Figure No.
10 2 below illustrates the Mid-Columbia (Mid-C) power prices in actual versus the Mid-C power
11 prices approved in authorized.
Holland, Di 12
Avista Corporation

I Figure No. 2—Mid-C Power Prices (July 2024 through June 2025)
2 $120
3
$100 ,
4 i
$80 \ -
5 $ � �
L $61 ` $68
6 2 $60 �_` 55 i 0- -
7 $40 ` ~ $
35
8 _
9
$0
10 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
--o—MIDC-F-ON -MIDC-F-OFF —•—Auth Mid-CON - Auth MID-COFF
11
12 Q. Please describe the conditions that impacted hydroelectric generation
13 during the Review Period.
14 A. From July 2024 through June 2025, weather patterns - especially a cold, snowy
15 February driven by La Nina - played a pivotal role in shaping hydroelectric output across the
16 Pacific Northwest. The Spokane River system saw modest generation due to its run-of-the-river
17 design, which limited its ability to store and release water during peak flow periods. Cold
18 weather boosted flows, but operational constraints capped output. The Columbia River system
19 faced historic lows in 2024 and 2025 due to drought and heat. However,the level of generation
20 for this river system was higher than authorized due to a new contract with Chelan County PUD
21 in early 2025. The net impact was a favorable 55 average megawatt (aMW) above the
22 authorized level. The Clark Fork River system - Cabinet Gorge and Noxon Rapids dams -
23 generated power below normal for every month of the Review Period, with the exception of
Holland, Di 13
Avista Corporation

I January 2025. This was primarily related to reduced river flow brought on by low snowpack
2 and reduced precipitation. Overall hydroelectric generation remained significantly lower than
3 average, contributing to a total average of 505 aMW for the year compared to an authorized
4 estimate of 532 aMW - a net reduction of 28 aMW. On a total variance basis, hydroelectric
5 generation was less than authorized by $18.4 million. See Figure No. 3 below for the Review
6 Period monthly actual and authorized hydroelectric generation along with the Mid-C prices that
7 were available at the time of those variances.
8 Figure No.3 -Hydroelectric Generation and Power Prices (July 2024 through June 2025)
9
Hydroelectric Generation
10 July 2024 through June 2025
800 $90
11
700 $so
12 600 $70
U
72
13 500 $60
$50
14 (Daoo
300
1 $30
5 Q
200 $20
16 100 $10
17 $-
Jul Aug Sept Oct Nov Dec Jan Feb Mar Apr May June
18 Act �Auth Price Mid-C-On-Peak
19 The Company utilized its non-hydroelectric resources, including market purchases and sales,
20 to meet customers' load requirements and optimize when market conditions were economic to
21 do so. These areas are addressed later in my testimony.
22 Q. Are there any costs related to Washington's Climate Commitment Act
23 (CCA)in the PCA?
Holland, Di 14
Avista Corporation

I A. No, there are no costs directly related to Washington's CCA included in the
2 PCA. That said,it is worth noting that Mid-C prices are likely to include cost of carbon elements
3 embedded in their overall valuation. There is no way to definitively isolate this value. As such,
4 Idaho customers are receiving the benefit of optimization of resources (sales) without the
5 offsetting carbon allowances cost. Avista shareholders absorbed approximately $563,000 in
6 carbon expense for the sales benefit which was included in customers rates and contributed
7 toward the rebate for the Review Period.
8
9 IV. OVERVIEW OF VARIANCE COMPONENTS
10 Q. Please provide an overview of each component of the variance analysis.
11 A. Based on timing, economic factors, and available resources, the Company
12 combined resources and market transactions to meet its current demands and capitalize on
13 market prospects, leading to costs lower than those authorized for the Review Period. The
14 impact of the transactions is reflected in various general ledger accounts and should be viewed
15 collectively. However, due to the numerous transactions for each category, a direct one-to-one
16 analysis fails to capture the nuances associated with providing energy in every hour of the
17 Review Period.4
18 For purposes of this variance analysis, workpapers provided by Avista differentiate
19 between the "cost variance" (which represents the price/quantity variance when comparing the
20 actual values to authorized as recorded to the general ledger), and "generation variance"5
21 (which represents the value each resource contributed towards meeting customer load
4 Please note the Company has provided workpapers supporting all impacts listed in Table No. 1.
s 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.
Holland, Di 15
Avista Corporation

I requirements). Table No. 1 below provides an overview by resource type of the variances
2 between the authorized power supply expense and the actual expense recorded in the Review
3 Period.
4 The generation variance essentially reallocates the variances to the applicable resource
5 to represent the market value the plants provided towards meeting load requirements. As such,
6 the variance is a function of both generation deviations and the estimated market price of power.
7 This calculation is not intended to be an "exact science," but rather a proxy value for Heavy
8 Load(HL)/Light Load(LL) of each component in our resource mix as compared to authorized.
9 The primary purpose is to provide an indicator as to how each component of our overall
10 resource stack adjusted up or down to meet changing load requirements.
11 Table No. 1 - Actual to Authorized Variance
12 Idaho Power Cost Adjustment Variance Analysis
July 2024-June 2025
13 (in thousands)
14 Idaho
Cost Generation Total Share @
15 Variance Variance Variance 90%
1. Change in Net Power Purchases(Purchases net of Sales) $ (34,836) $ 13,717 $ (21,119) $ (19,007)
16
2. Change in Natural Gas Plant Generation $ 9,027 $ (15,111) $ (6,084) $ (5,476)
17 3. Change in Hydro Generation $ 15,517 $ 4,887 $ 20,404 $ 18,363
18 4. Change in Thermal Generation $ 3,074 $ 2,116 $ 5,190 $ 4,671
19 5. Change in Wind Generation $ 4,581 $ (3,144) $ 1,437 $ 1,293
20 6. Change in Retail Load $ (1,798) $ (2,464) $ (4,262) $ (3,836)
21 7. Change in Net Transmission Expense(purchases net of sales) $ (1,019) $ - $ (1,019) $ (917)
22 8. Other Miscellaneous Expense $ (299) $ - $ (299) $ (270)
23 Total Variance to Authorized $ (5,753)�$ - $ (5,753) $ (5,178)
Holland, Di 16
Avista Corporation

I For the following sections,please refer to the individual line items and values provided in Table
2 No. 1 above. Note the following numbers represent system expense.
3 Item No. 1: Change in Net Power Purchase Expense ($21,119,000 lower 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, sales exceeded purchases, netting
10 124 aMW above what was estimated in setting the authorized base level.
11
12 Item No. 2: Change in Natural Gas Generation ($6,084,000 lower than authorized
13 base). This item is primarily comprised of Avista's Coyote Springs II(CS2) generating
14 station as well as a Power Purchase Agreement (PPA) associated with Lancaster. Also
15 included in Avista's overall natural gas generation portfolio, categorized as"Other CT"
16 is Boulder Park, Rathdrum, Kettle Falls CT, and Northeast Combustion Turbine. For
17 the Review Period,natural gas generation was higher than anticipated in the authorized
18 base forecast by 113 aMW. On a cost basis, natural gas generation was approximately
19 $9.0 million higbgr than what was forecasted in the authorized, however, after netting
20 against the generation variance of$15.1 million, the total actual expenses were $6.1
21 million lower than authorized for the Review Period. The generation variance removes
22 the impact of the volume variance (actual less than authorized), more accurately
23 reflecting the value of these resources.
24
25 Item No. 3: Change in Hydro Generation ($20,404,000 higher than authorized base).
26 Total hydroelectric generation was lower than the authorized level by 28 aMW resulting
27 in total power supply expense exceeding the anticipated authorized base by $20.4
28 million compared to authorized. Company-owned plants on the Spokane River and
29 Clark Fork River were lower than authorized by 17 aMW and 66 aMW, respectively.
30 Hydroelectric generation from the Mid-Columbia contracted hydroelectric plants were
31 higher than the authorized base level by 55 aMW which help to offset the variances
32 from the Clark Fork and Spokane Hydro. The conditions which contributed to this
33 reduced generation were discussed previously in testimony. This category also includes
34 the cost related to Avista's long term power purchase for Mid-Columbia hydroelectric
35 generation with Chelan PUD, Grant PUD, Douglas PUD. These contracts provide
36 reliable capacity for Avista's system in addition to energy.
37
38 Item No. 4: Change in Thermal Generation($5,190,000 higher than authorized base).
39 Costs related to coal contract prices at Colstrip was the primary contributor to higher
40 expense than embedded in the authorized base level for thermal generation. The
41 contractual price is $31.41cost per ton compared to an authorized level of$16.89 cost
42 per ton. The contract price includes a base price that is adjusted annually based on six
43 (6) inflation adjustments for labor and benefits, diesel fuel, electricity, explosives,
44 mining machinery and equipment, and implicit price deflator. In total, the impact of
Holland, Di 17
Avista Corporation

I these inflation adjustments far exceeded those anticipated when setting the authorized
2 base. As compared to authorized, actual costs exceeded the amount embedded in
3 customers rates by approximately$3.1 million(cost variance). The generation variance
4 adds to the impact of the volume variance, increasing the overall difference by
5 approximately$2.1 million resulting in net costs higher than authorized by$5.2 million,
6 before sharing.
7
8 Item No. S. Change in Wind Net Expense ($1,437,000 higher than authorized base).
9 Included in this category are the Palouse Wind Project, the Rattlesnake Flat Wind
10 Project, and Clearwater Wind III Power Purchase Agreements. For the Review Period,
I I Palouse Wind helped to meet approximately 38 aMW of customer load, Rattlesnake
12 Flat met approximately 53 aMW and Clearwater Wind III met approximately 41 aMW
13 of customer load. Note that for this Review Period, both Rattlesnake Flat and Palouse
14 Wind were included in authorized base,resulting in less of a variance for wind resources
15 than in the prior review period, however Clearwater Wind III costs were not included
16 in authorized base.
17
18 Item No. 6: Change in Retail Loads ($4,262,000 lower than authorized base). The
19 impact of the change in retail loads is the net of the deviation in actual load versus the
20 authorized level multiplied by the market price of power (netted against the retail
21 revenue adjustment). For the Review Period, Idaho retail sales were 29 aMW above the
22 authorized level.
23
24 Item No. 7. Change in Net Transmission Expense($1,019,000 lower than authorized
25 base). Transmission revenue was higher than the authorized level primarily from higher
26 than normal short-term and non-firm use of Avista's transmission system in the Review
27 Period.
28
29 Item No. 8: Change in Misc. Expense ($299,000 lower than authorized base).
30 Miscellaneous Expense consists of broker fees, California Independent System
31 Operator(CAISO) fees, and Montana Invasive Species expenses.
32
33 V. NEW LONG-TERM CONTRACTS ENTERED INTO DURING REVIEW PERIOD
34 Q. Please provide a brief description of new long-term contracts that the
35 Company entered into during the Review Period.
36 A. Avista did not enter any new PPA contracts during the Review Period.However,
37 there was one Public Utility Regulatory Policies Act of 1978 (PURPA) contract that was
38 renewed during the Review Period: Jim Ford (Ford Hydro LLC) was renewed with a starting
39 date of July 1, 2024 and was approved in Case No. AVU-E-24-06 Order No. 36310 on August
Holland, Di 18
Avista Corporation

1 30, 2024.
2
3 VI. OTHER
4 Q. Please describe how the Company met the requirements related to the
5 Chelan PUD/Columbia basin hydroelectric contracts, as well as Boulder Park tracking of
6 CCA allowances.
7 A. As a result of the Settlement approved through Order No. 35909 in Case No.
8 AVU-E-23-01,the Settling Parties stipulated that the cost of Columbia Basin Hydro(CBH)and
9 the newly acquired 5% slice of Chelan Hydro (via Chelan County PUD) would be included in
10 the PCA using the "lesser of market or contract. The Settling Parties agreed to only include
1 1 the new Chelan County PUD and Columbia Basin Hydro contacts at the market rate. Should
12 the contract value exceed the contract value, the "lesser of value would be absorbed by the
13 Company. However, particularly in relation to the Chelan Hydro contract, complexities arose
14 given that contract is a fixed price contract, rather than a price per megawatt. As a result of the
15 meetings between the Company and Staff, an agreed upon methodology was adopted and
16 provided to other interested parties for comments. As no comments were received, the
17 Company will continue to utilize the methodology as agreed.
18 Regarding Boulder Park, the Company was ordered to track the cost impact of lost
19 revenue stemming from making dispatch decisions that utilized carbon allowance price.During
20 the Review Period, carbon allowance prices were not included in dispatch decisions, resulting
21 in no lost revenue.
22 Q. Was a re-evaluation of the methodology performed by Avista and IPUC
23 Staff?
Holland, Di 19
Avista Corporation

I A. Yes. Avista and Staff evaluated several approaches and ultimately agreed to a
2 monthly cumulative approach. This approach allows for the difference between the daily Mid-
3 C market index costs and the actual daily contract costs to be recorded within the adjustment
4 but also incorporates flexibility so that, within the month, the daily fluctuations in market and
5 contract price could be netted so that days in which the contract is lower can be applied against
6 days where Mid-C index is lower. Avista feels that this is a fair and reasonable approach that
7 preserves the intention of the Settlement stipulation.
8 Q. Has this methodology been utilized within the PCA period, and what was
9 the result?
10 A. Yes, Avista began this adjustment in July of 2024 and has recorded an
11 adjustment within the Company's PCA journal DJ480 in each month. For Chelan, the total
12 adjustments for the PCA year were $1,895,201 (ID Share) removed from the PCA. For CBH,
13 the total adjustments were $989,691 (ID Share). For CBH, the Summer Falls resource required
14 that incremental transmission service be acquired to deliver energy to Avista's system. These
15 additional costs began in March 2025 and were included in the monthly"lesser of'calculation.
16 Workpapers have been provided to illustrate the costs for these contracts included in the PCA.
17
18 VII. SUPPORTING DOCUMENTATION
19 Q. Please provide a brief overview of the documentation provided by the
20 Company in this filing.
21 A. The Company maintains a number of documents that record relevant factors
22 considered at the time of a transaction. The following is a list of documents that are maintained
23 and that have been provided in electronic format with this filing:
Holland, Di 20
Avista Corporation

I • Natural Gas/Electric Transaction Records: These documents record the key details
2 of the price, terms, and conditions of a transaction. As part of Avista's workpapers
3 accompanying this filing, the Company has provided a confidential worksheet
4 showing each natural gas and electric term (balance of the month or longer)
5 transaction during the Review Period, including all key transaction details such as
6 trade date, delivery period,price,volume, and counterparty. Additional information
7 can be provided,upon request, for any of these transactions.
8
9 • Position Reports: These daily reports for each trading day in the Review Period
10 provide a summary of transactions and plant generation and the Company's net
11 average system position in future periods. The Daily Position Reports also contain
12 forward electric and natural gas prices.
13
14 • Variance Analysis: This analysis provides the detailed calculation of the differences
15 between actual and authorized for the Review Period for each subsection described
16 above. Please note, this analysis excludes incremental O&M costs associated with
17 EIM and interest.
18
19 • Contracts: Avista did not enter into any new contracts during the Review Period.
20
21 Q. Does that conclude your pre-filed direct testimony?
22 A. Yes.
Holland, Di 21
Avista Corporation