20240731Holland Direct Testimony.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY AND GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
1411 E. MISSION AVENUE
P.O. BOX 3727
SPOKANE, WASHINGTON 99220
PHONE: [phone], FAX: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE POWER COST ) CASE NO. AVU-E-24-07
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 Bachelor's Degree in
9 Business (1992)and Gonzaga University Master's Degree in Business Administration in 1996.
10 I have over 25 years of experience in the energy industry with roles in financial analysis, real
11 time electric system operations, wholesale trading and long-term markets. The majority of my
12 career has been at Avista Corporation, previously holding positions in Resource Marketing,
13 Wholesale Contracts and Credit, Real Time trading, and Energy Efficiency for Avista. I left
14 Avista for a brief period in 2007, rejoining in 2012. Prior to re joining Avista Corporation in
15 2012, I was a Structured Transaction Originator for Shell Energy North America leading
16 multiple team efforts to secure long term relationship-based contracts with energy industry
17 companies. In 2022, I was promoted to the Director of Energy Supply at Avista Corporation
18 where I am responsible for Avista's natural gas and electric business operation including trading
19 and marketing, resource planning and acquisition, strategic initiatives, contract negotiation,
20 renewable and emissions 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 2023 Idaho PCA filing in Case No.
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I AVU-E-23-08.
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 1,2023,through
5 June 30, 2024, 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 during the Review Period have
14 also been provided.
15
16 II. OVERVIEW OF POWER SUPPLY OPERATIONS
17 Q. How does Avista manage its power supply resources?
18 A. Avista Utilities conducts electric planning, procurement, sales, and power
19 resource management activities to assure an adequate supply of electricity to serve customer
20 and other load obligations, as well as to optimize its generation and transmission resources.
21 Numerous variables affect short-term power supply positions and prices.As such,the Company
22 employs an Energy Resources Risk Policy (Risk Policy) to recognize and actively manage the
23 interaction and dynamics amongst these variables by establishing processes for forecasting
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I future load and obligation requirements,resource availability, and management of the expected
2 net surplus or deficit short-term and immediate-term positions.
3 It is understood that many factors cause loads to differ from estimates. It is also
4 understood that each of Avista's generating resources has inherent variability because of
5 streamflow and water storage conditions (for hydroelectric plants), mechanical limitations,
6 transmission constraints, fuel availability and delivery constraints, ambient conditions,
7 environmental and permit allowances, among other factors. Avista's Energy Resources
8 department is responsible for fuel management, optimizing the use of electric resources
9 including wholesale power contracts,dispatching power resources to meet load obligations,and
10 providing good stewardship of electric resources.
11 Energy resource planning involves significant modeling, assumptions, and estimates to
12 forecast future situations. Actual loads are influenced by many factors and therefore rarely
13 match forward estimates. Balancing generation to match load obligations requires constant
14 attention, and its variability dictates that flexibility be always maintained. It is necessary to buy
15 and sell energy (or financially equivalent derivative transactions) in sub-hourly, hourly, daily,
16 balance of the month, monthly, and longer increments, as well as adjust dispatch plans to meet
17 prevailing conditions. As such, Avista utilizes all power and fuel transactions authorized in its
18 Risk Policy to provide reliable and affordable service to Avista's electric loads and contract
19 obligations and seeks to optimize additional opportunities associated with Avista's energy
20 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
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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:
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I • 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. The Company employs a Power Supply Hedge Requirements Report tool
24 (PSHRR). The PSHRR is an analytical tool to guide power supply hedging decisions in the
25 short-term forward period. It provides a process to systematically reduce open positions with
26 forward transactions by buying for expected shortages and selling expected surpluses. An
27 "open"position for this purpose is the forecasted monthly financial position that is not covered
28 by fixed price physical or financial transactions,i.e.,the surplus or deficit that is subject to price
29 risk. The plan provides guidance but will not be followed rigidly when management deems
30 appropriate.
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1 III. OVERVIEW OF POWER COST ADJUSTMENT
2 Q. Please provide an overview of the Power Cost Adjustment mechanism and
3 the calculation methodology.
4 A. The purpose of the Power Cost Adjustment (PCA) mechanism is to include in
5 customers' rates a true up of actual power supply expenses compared to estimated base level
6 power supply expense(authorized base level)set in a general rate case proceeding and approved
7 by the Commission.In a general rate case filing,Avista models all available Company resources
8 based on current market conditions including forward natural gas and electric prices, median
9 hydro conditions, and maintenance schedules. The model(Aurora)then dispatches the portfolio
10 of resources in the most economic manner to meet customer loads to determine power supply
11 expenses.The base level of authorized power supply expenses also includes executed long-term
12 contracts, average maintenance schedules, broker fees, and other miscellaneous expenses
13 associated with power supply expenses. Avista dispatches its resources based on current prices
14 and actual operating conditions,which result in a different power supply expense than estimated
15 in a general rate case filing. The PCA mechanism covers the difference between the actual and
16 estimated power supply expense.
17 Expenses and revenue are recorded in accordance with Generally Accepted Accounting
18 Practices (GAAP) and FERC's Uniform System of Accounts. The general ledger accounts
19 approved for inclusion in the PCA are related to primarily the four major power supply cost and
20 revenue accounts which include FERC accounts 555 (Purchased Power), 501 (Thermal Fuel),
21 547 (Fuel), and 447 (Sales for Resale). Also included in the PCA is the cost related to
22 transmission in accounts 565 (transmission expense), 456 (third-party transmission revenue),
23 natural gas sales revenue under Account 456 (revenue), and purchase for fuel expense under
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I Account 557 (expense). These accounts are included to capture the actual revenue and costs
2 related to optimizing the value of natural gas turbines and power supply's natural gas
3 transportation contracts.
4 During the PCA Review Period, the authorized base level of power supply expense
5 approved by the Commission, and in customer rates, is up to four years old in certain periods.1
6 The markets have experienced significant volatility since that time, resulting in variances
7 simply due to timing. To the extent actual expenses are different than those approved in the
8 authorized base level, they are deferred for later recovery,pending annual prudency review.
9 Q. How is the PCA deferral calculated?
10 A. The PCA deferral is the difference between authorized and actual. It is calculated
11 by subtracting authorized base net power supply expense from actual net power supply expense
12 to determine the change in net power supply expense. The total change in net expense under
13 the PCA is multiplied by Idaho's share of the Production/Transmission Ratio (PT Ratio)
14 approved in association with base net power supply expense. Changes in Idaho retail sales is
15 then multiplied by the Load Change Adjustment Rate (LCAR) and added to or subtracted from
16 the change in power supply expense to calculate the total power expense change. Ninety (90)
17 percent of the change in power expense is included in the deferral mechanism while the
18 remaining ten (10)percent is absorbed by the Company.
19 Q. What were the changes in power costs during the PCA Review Period?
20 A. During the Review Period,actual net power costs were lower than the authorized
' For July through August 2023,the authorized base level of power supply expense approved by the Commission
in Case No. AVU-E-21-01 was based on actual annual expenses for the twelve months ended December 31,
2019,with forward estimates to an effective date of September 1,2021.For September 2023 through June 2024,
the authorized base level of power supply expense approved by the Commission in Case No.AVU-E-23-01 was
based on actual annual expenses for the twelve months ended June 30, 2022, with forward estimates to an
effective date of September 1,2023.
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I (or baseline) net power costs for the Idaho jurisdiction by $7,324,002 (excluding incremental
2 O&M costs associated with EIM and interest). After taking into consideration the 90%
3 allowable deferral percent, the total PCA deferral is $6,591,601 (excluding incremental O&M
4 costs associated with EIM and interest) in the rebate direction. Company witness Ms. Schultz
5 discusses the total Idaho PCA deferral as $6,250,049 in the rebate direction,which includes the
6 $6,591,601 rebate associated with net power supply costs plus incremental O&M costs
7 associated with EIM (discussed below) at 90% of$341,552, excluding interest.
8 Q. What was the amount associated with the incremental O&M Costs
9 associated with the Energy Imbalance Market (EIM)?
10 A. The incremental O&M expense associated with EIM for the Review Period
11 totaled $379,503, or $341,552 after sharing with the Company based on 90%/10% sharing
12 (excluding interest). By Order No. 35156 in Case No. AVU-E-21-01, dated September 1,2021,
13 the Commission approved the Settlement Stipulation, where the Parties to the case agreed that
14 effective with the expected "go live" March 1, 2022 date, the Company will begin to reflect
15 Idaho's share of incremental EIM O&M expenses through the PCA up to Idaho's share of EIM
16 benefits that also will flow through the PCA.
17 Q. Please summarize the market conditions in effect during the Review Period
18 that contributed to the variance between the actual power supply expense level and the
19 authorized power supply expense level.
20 A. The authorized level of power supply expense is intended to be a forecast of
21 anticipated expenses based on the expected market conditions, generation asset dispatch and
22 costs associated with energy supply. For Avista, July through August 2023 authorized expense
23 levels were based on twelve-months-ending December 31, 2019, and established in Case No.
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I AVU-E-21-01,while September 2023 through June 2024 authorized expense levels were based
2 on twelve-months-ending June 30, 2022, and established in Case No. AVU-E-23-01, as
3 discussed in footnote 1 above. A variance occurs when the level of actual expense differs from
4 the authorized level of power supply expense. The older the authorized base, the less likely the
5 authorized base will accurately reflect the actual market conditions that are experienced in the
6 applicable year. This leads to more opportunity for a variance between authorized and actual
7 expenses. While the authorized base is intended to capture all future assumptions of energy
8 costs,it is unable to account for the unknown variables that are affected both by Avista's owned
9 assets and external market conditions. Avista manages its overall portfolio of resources to
10 obtain the most economic combination to meet customer needs, while optimizing resources to
11 reduce costs where possible.
12 The most prominent market conditions that impacted the PCA deferral are attributed to
13 1) lower than forecasted streamflow which reduced hydroelectric generation from both Avista-
14 owned and contracted-for resources; 2) higher level of generation from Avista's natural gas-
15 fired generation sources (rebate); and 3)increased activity in both market purchases and market
16 sales. A full variance analysis is provided in Section IV of this testimony.
17 Q. Please describe the conditions that impacted hydroelectric generation
18 during the Review Period.
19 A. Hydroelectric generation for the Review Period was lower than normal due to
20 lower-than-average snowpack, resulting in a reduced level of natural river flows most of the
21 year. In addition, temperature variations impacted snowpack and runoff, further reducing the
22 potential for hydroelectric generation. The Spring of 2024 marks one of the lowest hydro levels
23 recorded with runoff from the Clark Fork River,ranking 7 1"out of 76 years.With the exception
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I of February and March, each month in the Review Period had actual hydroelectric generation
2 less than the authorized level.2 In total, Avista's combined hydroelectric generation from the
3 Clark Fork, Mid-Columbia and Spokane River system was significantly lower than average,
4 totaling an average of 435 aMW for the year compared to an authorized estimate of 532 aMW;
5 a net reduction of 97 aMW. See Figure No. I below for the Review Period monthly actual and
6 authorized hydroelectric generation along with the Mid-C prices that were available at the time
7 of those variances.
8 Figure No. 1 -Hydroelectric Generation and Power Prices (July 2023 through June 2024)
9
Hydroelectric Generation (July 2023 through June 2024)
10 800 $300
11 700
$250
600
12
$200 '2
500 g
13
400 $150
14 /
300
$100 a
15 zoo
$50
100 L L $-
16
17 Jul Aug Sept Oct Nov Dec Jan Feb Mar Apr May June
Act �Auth Price Mid-C-On-Peak
18
19 The Company utilized its non-hydro resources, including market purchases and sales,
20 to meet customers' load requirements and optimizing when market conditions were economic
21 to do so. These areas are addressed later in my testimony.
22 Q. What was the impact of this reduced hydroelectric generation?
z The authorized level of hydroelectric generation is based on an 80-year average water year.
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I A. In combination with colder than normal temperatures which increased demand,
2 particularly in January 2024, the value of this lost hydro generation was approximately $18.1
3 million when priced at a Mid-C proxy value. Throughout the Review Period, regional energy
4 and natural gas prices continued to be higher than anticipated, with power prices rising
5 dramatically during January 2024 when the region experienced significantly colder than normal
6 weather. In January,the average price for Mid-C pricing peaked at$249.95 per MW, making it
7 the highest monthly average price in the Review Period. Following the high prices in January,
8 Mid-C pricing returned to lower levels with prices ranging from $50 per MW down to $29 per
9 MW(see Figure No. 2 below) despite hydro generation lagging at nearly half of authorized.
10 Figure No. 2—Mid-C Power Prices (July 2023 through June 2024)
11
Power Prices(July 2023 through June 2024)
12 $300
13 $250 $250
14 $200
15 $150
� $129
16 $105
$100 98 �`
✓ � 6 75
17 $56
_ _ _
50
$50 — $37 $34 $30 $30
r _
18 —
$0
19 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
tMIDC-F-ON --*--MIDC-F-OFF —•—Auth Mid-CON Auth MID-C OFF
20
21 Q. How were natural gas prices different than those assumed in the authorized
22 level of power supply expense?
23 A. Natural gas was more economic for both serving load and for resource
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I optimization. During the Review Period,the market heat rate (the ratio of power prices relative
2 to natural gas prices) increased relative to authorized. When market heat rates rise, the value of
3 the power that the thermal fleet can generate increases more than the costs incurred to fuel the
4 plants. This resulted in higher revenue during hours when the fleet was economic. It also
5 resulted in the fleet being economic more often which caused more generation to occur than
6 under the authorized scenario. A plant is determined to be economic when the cost to fuel the
7 plant per MW of generation is below the cost of power in the market. While the cost of natural
8 gas remained higher than authorized, it remained economically beneficial to generate both for
9 customer load and to sell into energy markets. Overall, average monthly natural gas pricing
10 during the Review Period was far more stable than in the prior year with pricing. See Figure
11 No. 3 for monthly gas prices during the Review Period:
12 Figure No. 3 -Natural Gas Prices (July 2023 through June 2024)
13
Natural Gas Prices
14 $7
$5.9
$6
15 $5 $4.6
16 t $4 $3.4 $3.6
*' $3.1 S3.
v
+► $3 $2.4
17 2.1
$z $1.5 $1.3 $1.3 $1.5
18 $1
$0
19 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
tMalin-Actual fAECO-Actual
20
21 Q. How did Avista optimize its energy resources to benefit customers?
22 A. Optimization of energy resources is illustrated primarily in the level of net
23 purchase/sales. For the Review Period, Net Sales exceeded authorized by $l 04.5 million
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I (system basis), more than offsetting the result of unfavorable hydroelectric conditions. As
2 previously mentioned, the value of Avista's natural gas-generating resources was higher than
3 the fuel cost to generate that power. When Avista's total load is served by Avista resources,
4 excess energy can be sold, and the revenue is credited to sales. Conversely, when load exceeds
5 Avista resources, Avista will serve that portion of its load with market resources at the market
6 price available at that time. In addition to the generation from Company-owned or operated
7 resources, Avista engages in both short-term market transactions (purchases and sales) as well
8 as long-term structured transactions with counterparties. The Company considers several
9 factors including economics, load requirements, and hydro conditions when evaluating the
10 benefits of off-system sales.
11 Finally, Avista's real time and day ahead trading groups review several market
12 indicators to capture the time-spread associated with purchases and sales. When market
13 conditions are deemed appropriate, any day ahead purchases not utilized to meet load
14 requirements may be sold on an hourly basis to reduce overall power supply expenses. These
15 transactions,described above,contributed to the increased value of sales,entirely offsetting any
16 purchases cost.
17 Q. Were there any other factors which materially impacted overall power
18 supply expense for 2023-2024?
19 A. Yes. As mentioned before, in early January, the Pacific Northwest experienced
20 an extreme cold weather event that resulted in several load-serving entities, including Avista,
21 setting new peak demand records. The sustained subzero temperatures also impacted wholesale
22 natural gas costs, as well as stream flows, which reduced the availability of hydroelectric
23 generation. With a lack of regional wind, as well as other transmission intertie constraints
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I coming from California, wholesale power prices were under substantial pressures for the entire
2 Northwest. The result of these regional conditions was extremely high-power prices, with the
3 average January price approaching$250 per MWh as shown in Figure Nos. 1 and 2 above. This
4 event had a significant impact on the January variance for market purchases resulting in net
5 actual purchases of$9.1 M (system) for the month.
6 Q. Are there any costs related to Washington's Climate Commitment Act
7 (CCA) in the PCA?
8 A. No, there are not costs directly related to Washington's CCA included in the
9 PCA. That said, it is worth noting that Mid-C prices are higher than previous years likely
10 because of the embedded cost of carbon. There is no way to definitively isolate this benefit. As
11 such, Idaho customers are receiving the benefit of optimization of resources (sales)without the
12 offsetting carbon allowances cost. Avista shareholders absorbed approximately $700,000 in
13 carbon expense for the sales benefit which was included in customers rates and contributed
14 toward the rebate for the Review Period.
15
16 IV. OVERVIEW OF VARIANCE COMPONENTS
17 Q. Please provide an overview of each component of the variance analysis.
18 A. Based on timing, economic factors, and available resources, the Company
19 combined resources and market transactions to meet its current demands and capitalize on
20 market prospects, leading to costs lower than those authorized for the Review Period. The
21 impact of the transactions is reflected in various general ledger accounts and should ideally be
22 viewed collectively.However,due to the numerous transactions for each category,a direct one-
23 to-one analysis fails to capture the nuances associated with providing energy in every hour of
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1 the Review Period.3
2 For purposes of this variance analysis, workpapers provided by Avista differentiate
3 between the "cost variance" (which represents the price/quantity variance when comparing the
4 actual values to authorized as recorded to the general ledger),and"generation variance"4(which
5 represents the value each resource contributed towards meeting customer load requirements).
6 Table No. 1 below provides an overview by resource type of the variances between the
7 authorized base level expense and the actual expense recorded in the Review Period.
8 The generation variance essentially reallocates the variances to the applicable resource
9 to represent the market value the plants provided towards meeting load requirements. As such,
10 the variance is a function of both generation deviations and the estimated market price of power.
11 This calculation is not intended to be an "exact science," but rather a proxy value for Heavy
12 Load(HL)/Light Load(LL)of each component in our resource mix as compared to authorized.
13 The primary purpose is to provide an indicator as to how each component of our overall
14 resource stack adjusted up or down to meet changing load requirements.
s Please note the Company has provided workpapers supporting all impacts listed in Table No. 1.
a 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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I Table No. 1 -Actual to Authorized Variance
2 Idaho Power Cost Adjustment Variance Analysis
July 2023-June 2024
3 (in thousands)
s r i
4 Cost Generation Total Idaho Share
Variance Variance Variance @ 90%
5 1.Change in Net Power Purchases(Purchases net of Sales) $ (41,899) $ 5,426 $ (36,473) $ (32,825)
6 2.Change in Natural Gas Plant Generation $ 21,613 $ (32,340) $ (10,727) $ (9,655)
7 3.Change in Thermal Generation $ 3,289 $ 787 $ 4,076 $ 3,668
8 4.Change in Wind Generation $ 2,560 $ 1,062 $ 3,623 $ 3,260
9 5.Change in Hydro Generation $ 11,808 $ 18,089 $ 29,897 $ 26,907
10 6.Change in Retail Load $ (1,161) $ 6,976 $ 5,815 $ 5,234
11 7•Change in Net Transmission Expense(purchases net of sales) $ (4,203) $ - $ (4,203) $ (3,783)
12 8.Other Miscellaneous Expense $ 669 $ - $ 669 $ 602
13 Total Variance to Authorized $ (7,324) $ - $ (7,324) $ (6,592)
14 For the following sections,please refer to the individual line items and values provided in Table
15 No. 1 above.
16 Item No. 1: Chanze in Net Power Purchase Expense ($36,473,000 lower than
17 authorized base). As previously discussed,in addition to the generation from Company-
18 owned or operated resources, the Company considers several factors including
19 economics, load requirements, and hydro conditions when evaluating the benefits of
20 off-system sales. When economic to do so, the Company engages in short-term market
21 transactions(purchases and sales),as well as long-term transactions with counterparties.
22 For the PCA year,sales exceeded purchases,netting 20 aMW above what was estimated
23 in setting the authorized base level.
24
25 Item No. 2: Change in Natural Gas Generation ($10,727,000 lower than authorized
26 base). This item is primarily comprised of Avista's Coyote Springs II(CS2) generating
27 station as well as a Power Purchase Agreement (PPA) associated with Lancaster. Also
28 included in Avista's overall natural gas generation portfolio, categorized as"Other CT"
29 is Boulder Park, Rathdrum, Kettle Falls CT, and Northeast Combustion Turbine. For
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I the Review Period,natural gas generation was higher than anticipated in the authorized
2 base forecast by 141 aMW. Generation included in"Other CT"contributed over half of
3 the total with 88 aMW higher than authorized. On a cost basis, natural gas generation
4 was approximately $21.6 million higher than what was forecast in the authorized,
5 however, after netting against the generation variance, the total actual expenses were
6 $10.7 million lower than authorized for the Review Period. The generation variance
7 removes the impact of the volume variance (actual less than authorized) by
8 approximately $32.3 million, more accurately reflecting the value of these resources.
9
10 Item No. 3: Change in Thermal Generation ($4,076,000 higher than authorized base).
11 Costs related to coal contract prices at Colstrip was the primary contributor to higher
12 expense than embedded in the authorized base level for thermal generation. The
13 contractual price is $31.41 cost per ton compared to an authorized level of$16.89 cost
14 per ton. The contract price includes a base price that is adjusted annually based on six
15 inflation adjustments for labor and benefits, diesel fuel, electricity, explosives, mining
16 machinery and equipment, and implicit price deflator. In total, the impact of these
17 inflation adjustments far exceeded those anticipated when setting the authorized base.
18 As compared to authorized, actual costs exceeded the amount embedded in customers
19 rates by approximately$3.3 million(cost variance). The generation variance adds to the
20 impact of the volume variance, increasing the overall difference by approximately
21 $785,000, resulting in net costs higher than authorized by $3.7 million, after sharing.
22
23 Item No. 4: Change in Wind Net Expense ($3,623,000 higher than authorized base).
24 Included in this category is both the Palouse Wind Project and the Rattlesnake Wind
25 Project Power Purchase Agreements. For the Review Period, Palouse Wind helped to
26 meet approximately 35 aMW of customer load, and Rattlesnake Flat met 43 aMW of
27 customer load. Note that for this Review Period, nine months of expenses related to
28 both Rattlesnake and Palouse Wind were included in authorized base, resulting in less
29 of a variance for wind resources than in the prior review period.
30
31 Item No. 5: Change in Hydro Generation ($29,897,000 higher than authorized base).
32 Total hydro generation was lower than the authorized level by 97 aMW resulting in total
33 power supply expense exceeding the anticipated authorized base by $29.9 million
34 compared to authorized. Company-owned plants on the Spokane River and Clark Fork
35 River were lower than authorized by 14 aMW and 76 aMW respectively. hi addition,
36 hydro generation from the Mid-Columbia contracted hydro plants were also below
37 median levels included in the authorized base level by an additional 7 aMW. The
38 conditions which contributed to this reduced generation were discussed previously in
39 testimony.
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I This category also includes the cost related to Avista's long term power purchase for
2 Mid-Columbia hydroelectric generation with Chelan PUD, Grant PUD, and Douglas
3 PUD. These contracts provide reliable capacity for Avista's system in addition to
4 energy. Grant's meaningful priority contract is adjusted annually based on results of an
5 annual"bid"process.When rates were set in September 2021,the system-level monthly
6 contract expense was approximately $939,000. That monthly contract has increased
7 over the Review Period with a monthly cost of$2,827,408 in 2023 and increasing to
8 $2,880,764 in 2024.The result is approximately$7.2 million on an Idaho-allocated basis
9 above what is embedded in the authorized base level.
10
11 Item No. 6: Change in Retail Loads ($5.815.000 higher than authorized base). The
12 impact of the change in retail loads is the net of the deviation in actual load versus the
13 authorized level multiplied by the market price of power (netted against the retail
14 revenue adjustment). For the Review Period, Idaho retail sales were 12 aMW above the
15 authorized level. As previously discussed, Avista experienced near-peak conditions in
16 January of 2024 which is the primary contributor to this variance.
17
18 Item No. 7. Change in Net Transmission Expense ($4.203,000 lower than authorized
19 base). Transmission revenue was higher than the authorized level primarily from higher
20 than normal short-term and non-firm use of Avista's transmission system in the Review
21 Period.
22
23 Item No. 8: Change in Misc. Expense ($669.000 higher than authorized base).
24 Miscellaneous Expense consists of broker fees, California Independent System
25 Operator (CAISO) fees, and the Montana Invasive Species. The primary contributor to
26 the increase was CAISO wheeling access charges, which are variable in nature.
27
28 V. NEW LONG-TERM CONTRACTS ENTERED INTO DURING REVIEW PERIOD
29 Q. Please provide a brief description of new long-term contracts that the
30 Company entered into during the Review Period.
31 A. Avista did not enter any new PPA contracts during the Review Period.However,
32 there were three PURPA contracts that were renewed during the Review Period U of I Solar,
33 Stimson Lumber, and Clearwater Paper. These contracts were approved by the Commission in
34 Order No. 36139, Order Nos. 36019/36078, and Order Nos. 36046/36157, respectively. One
Holland, Di 18
Avista Corporation

I contract, Jim Ford (Ford Hydro LLC) is currently awaiting final order.
2
3 VI. SUPPORTING DOCUMENTATION
4 Q. Please provide a brief overview of the documentation provided by the
5 Company in this filing.
6 A. The Company maintains a number of documents that record relevant factors
7 considered at the time of a transaction. The following is a list of documents that are maintained
8 and that have been provided in electronic format with this filing:
9 • Natural Gas/Electric Transaction Records: These documents record the key details
10 of the price, terms, and conditions of a transaction. As part of Avista's workpapers
11 accompanying this filing, the Company has provided a confidential worksheet
12 showing each natural gas and electric term (balance of the month or longer)
13 transaction during the Review Period, including all key transaction details such as
14 trade date, delivery period,price,volume, and counterparty. Additional information
15 can be provided, upon request, for any of these transactions.
16
17 • Position Reports: These daily reports for each trading day in the Review Period
18 provide a summary of transactions and plant generation and the Company's net
19 average system position in future periods. The Daily Position Reports also contain
20 forward electric and natural gas prices.
21
22 • Variance Analysis: This analysis provides the detailed calculation of the differences
23 between actual and authorized for the Review Period for each subsection described
24 above. Please note, this analysis excludes incremental O&M costs associated with
25 EIM and interest.
26
27 • Contracts: Avista did not enter into any new contracts during the Review Period.
28
29 Q. Does that conclude your pre-filed direct testimony?
30 A. Yes.
Holland, Di 19
Avista Corporation