20230731Holland 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-23-__
ADJUSTMENT (PCA) ANNUAL RATE )
ADJUSTMENT FILING OF AVISTA ) DIRECT TESTIMONY OF
CORPORATION ) KEVIN M. HOLLAND
FOR AVISTA CORPORATION
08

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Avista Corporation

I. INTRODUCTION 1
Q. Please state your name, business address, and present position with Avista 2
Corporation. 3
A. My name is Kevin M. Holland. My business address is 1411 E. Mission Avenue, 4
Spokane, Washington, and I am employed by the Company as the Director of Energy Supply. 5
Q. Would you please describe your educational background and professional 6
experience? 7
A. Yes. I am a graduate of Gonzaga University with a Bachelor’s Degree in 8
Business (1992) and Gonzaga University Master’s Degree in Business Administration in 1996. 9
I have over 25 years of experience in the energy industry with roles in financial analysis, real 10
time electric system operations, wholesale trading and long-term markets. The majority of my 11
career has been at Avista Corporation, previously holding positions in Resource Marketing, 12
Wholesale Contracts and Credit, Real Time trading, and Energy Efficiency for Avista. I left 13
Avista for a brief period in 2007, rejoining in 2012. Prior to re-joining Avista Corporation in 14
2012, I was a Structured Transaction Originator for Shell Energy North America leading 15
multiple team efforts to secure long term relationship-based contracts with energy industry 16
companies. In 2022, I was promoted to the Director of Energy Supply at Avista Corporation 17
where I am responsible for Avista’s natural gas and electric business operation including trading 18
and marketing, resource planning and acquisition, strategic initiatives, contract negotiation, 19
renewable and emissions compliance, and regional initiatives participation. 20
Q. Have you previously filed testimony in annual Power Cost Adjustment 21
proceedings? 22
A. No, I have not. Testimony related to these issues in Avista’s last Power Cost 23

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Avista Corporation

Adjustment proceeding was sponsored by Company witness Ms. Brandon, who is in my 1
organization. 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, 2022 through 5
June 30, 2023 review period (Review Period). 6
Q. Are you sponsoring any work papers and supporting documentation to be 7
introduced in this proceeding? 8
A. Yes. Detailed work papers supporting the tables and other calculations in my 9
testimony have been provided in electronic format to the Commission, and other parties 10
coincident to this filing. The Company has also provided supporting documentation, including 11
details of all term natural gas and electricity transactions that flowed during the Review Period, 12
and daily position reports that show, among other things, forward price curves. Copies of long-13
term power contracts that the Company entered during the Review Period have also been 14
provided. Finally, additional support for the Energy Imbalance Market benefit calculation as 15
agreed to in our May 18, 2023 letter to the Commission. 16
17
II. OVERVIEW OF POWER SUPPLY OPERATIONS 18
Q. How does Avista, generally, manage its power supply resources? 19
A. Avista conducts electric planning, procurement, sales and power resource 20
management activities to assure an adequate supply of electricity to serve customer and other 21
load obligations, as well as to optimize our generation and transmission resources. Numerous 22
variables affect short-term power supply positions and prices. As such, we employ an Energy 23

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Avista Corporation

Resources Risk Policy (Risk Policy) to recognize and actively manage the interaction and 1
dynamics among these variables by establishing processes for predicting future load and 2
obligation requirements, resource availability, and management of the expected net surplus or 3
deficit short-term and immediate-term positions. 4
It is understood that many factors cause loads to differ from estimates. It is also 5
understood that each of Avista’s generating resources has inherent variability because of 6
streamflow and water storage conditions (for hydroelectric plants), mechanical limitations, 7
transmission constraints, fuel availability and conditions, ambient conditions, environmental 8
and permit allowances, and other factors. 9
Energy Supply, of which I am the Director, handles fuel management including 10
transportation and transmission, optimizing the use of electric resources including wholesale 11
power contracts, obtaining, and dispatching power resources to meet load obligations and 12
providing good stewardship of electric resources. 13
Energy resource planning involves significant modeling, assumptions, and estimates. 14
Actual loads are influenced by many factors and therefore rarely match forward estimates. The 15
load and generation net surplus or deficit require constant attention, and its variability dictates 16
that flexibility be maintained at all times. It is necessary to buy and sell energy (or financially 17
equivalent derivative transactions) in hourly, daily, monthly, and longer increments, and adjust 18
dispatch plans to meet prevailing conditions. As such, we utilize all power and fuel transactions 19
authorized in our Risk Policy to provide reliable and affordable service to Avista’s electric loads 20
or obligations and seek to optimize additional opportunities associated with Avista’s energy 21
resources. 22
Q. What types of transactions will Avista enter into, as detailed and authorized 23

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Avista Corporation

in the Company’s Risk Policy? 1
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 time horizons: 4
• Scheduling and dispatching energy resource facilities owned or controlled by 5
Avista. 6
• Management of firm natural gas transportation contracts directly assigned to electric 7
operations. 8
• Transactions with other parties for physical delivery of capacity or energy, including 9
fixed price and indexed or formula-priced transactions. 10
• Ancillary services, such as reserves, load-following, generation imbalance and 11
others. 12
• Transportation, transmission, storage and capacity obligations and rights. 13
• Bilateral forward transactions with approved counterparties. 14
• Futures contracts traded on an established commodities exchange. 15
• Swap agreements as a tool for fixed price financial hedges. 16
• Transactions that allow Avista to buy or sell electricity or natural gas at Avista’s 17
discretion. 18
• Exchange agreements (forward commodity agreements expected to be settled with 19
return of the commodity rather than cash, either with or without associated 20
settlement prices). 21
• Fuel (supply, delivery, storage, excess fuel disposition) related to specific electric 22
generating facilities in which Avista has an ownership or contractual interest 23
including natural gas, coal, and biomass (wood waste) and related emission 24
allowances. 25
• Streamflow and water storage rights and benefits related to Avista-owned or 26
contracted hydroelectric generation stations including coordination of the related 27
river systems. 28
29
Q. How does Avista optimize its energy resources for the benefit of its 30
customers? 31
A. Avista optimizes its energy resources in a number of ways to ensure that the 32
effect of energy price volatility minimally impacts customers. Electric resource optimization 33
involves choices among several variables. Avista assesses these variables in an effort to select 34

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Avista Corporation

and execute an appropriate mix to meet short-term and intermediate-term objectives. Intra-1
month activity during the prompt month to serve projected loads, optimize resources, and 2
participate in the electric market which is reported after-the-fact in the daily position report. 3
Electric optimization variables include: 4
• Scheduling and dispatching of available Avista generating units as indicated by 5
relevant plant parameters. 6
• Buying fuel to operate a generating facility or selling fuel already available to 7
decrease or eliminate generation from a unit. 8
• Storing or using water for hydroelectric generation that maximizes expected 9
generation value and arranging for water from or for other hydroelectric plants in 10
the coordinated river system. 11
• Buying, selling, or exchanging electricity in the wholesale market from/to other 12
utilities, power marketers, or independent power producers, including displacing 13
purchases and sales available to the Avista balancing area. 14
• Buying or selling financial contracts that hedge electric purchase or sale prices and 15
open positions. 16
• Obtaining transmission rights as may be needed to deliver or receive output to or 17
from any Avista generation source or any market and selling surplus transmission 18
rights. 19
• Buying and selling the natural gas basis spread based on natural gas transport 20
contract rights. 21
• Obtaining and managing transportation rights as may be needed to deliver natural 22
gas for fuel at Avista’s natural gas generating resources. 23
24
Q. Does the Company have an active hedging program? 25
A. Yes. The Company employs a Power Supply Hedge Requirements Report tool 26
(PSHRR). The PSHRR is an analytic tool to guide power supply hedging decisions in the short-27
term forward period. It provides a process to systematically reduce open positions with forward 28
transactions by buying for expected shortages and selling expected surpluses. An “open” 29
position for this purpose is the forecasted monthly financial position that is not covered by fixed 30
price physical or financial transactions, i.e., the surplus or deficit that is subject to price risk. 31
The plan provides guidance but may not be followed rigidly when management judgment or 32

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Avista Corporation

market conditions warrant other actions, no action, or simply a delay in taking action. 1
The PSHRR will define potential transactions to reduce the net open position for each 2
month or quarter over the available time between the current date and future delivery periods. 3
PSHRR transactions are designed to systematically reduce the net open financial position for 4
established hedge delivery periods. The PSHRR is designed to recommend forward time 5
periods for hedge transactions based on risk and/or price indicators. The model includes several 6
estimates such as price, estimated load or other obligations, variable energy resource 7
generation, hydroelectric generation, and long-term contracts. When a change in these values 8
identifies the need for a transaction, the PSHRR shows the forward time periods and the hedge 9
amount in dollars to resolve open financial position. The PSHRR is dynamic based on the best 10
information available each business day. Whenever a hedge transaction is executed (or the 11
equivalent change in net financial position forecast occurs), PSHRR recalculates the financial 12
open positions. 13
14
III. OVERVIEW OF POWER COST ADJUSTMENT 15
Q. Please provide an overview of the power cost adjustment and the 16
calculation methodology. 17
A. The purpose of the Power Cost Adjustment (PCA) mechanism is to include in 18
customers’ rates a true up of actual power supply expenses compared to estimated base level 19
power supply expense (“authorized base level”) set in a general rate case proceeding and 20
approved by the Commission. In a general rate case filing, Avista models all available 21
Company resources based on current market conditions including forward natural gas and 22
electric prices, median hydro conditions, and maintenance schedules. The model (“Aurora”) 23

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Avista Corporation

then dispatches the portfolio of resources in the most economic manner to meet customer loads 1
to determine power supply expenses. The base level of authorized power supply expenses also 2
includes executed long-term contracts, average maintenance schedules, broker fees, and other 3
miscellaneous expenses associated with power supply expenses. Avista dispatches its resources 4
based on current prices and actual operating conditions which result in a different power supply 5
expense than estimated in rate case filing. The PCA mechanism covers the difference between 6
the actual and estimated power supply expense. 7
Expenses and revenue are recorded in accordance with Generally Accepted Accounting 8
Practices (GAAP) and FERC’s Uniform System of Accounts. The general ledger accounts 9
approved for inclusion in the PCA are related to primarily the four major power supply cost and 10
revenue accounts which include FERC accounts 555 (Purchased Power), 501 (Thermal Fuel), 11
547 (Fuel), and 447 (Sales for Resale). Also included in the PCA is the cost related to 12
transmission in accounts 565 (transmission expense), 456 (third-party transmission revenue), 13
natural gas sales revenue under Account 456 (revenue), and purchase for fuel expense under 14
Account 557 (expense). These accounts are included to capture the actual revenue and costs 15
related to optimizing the value of natural gas turbines and power supply’s natural gas 16
transportation contracts. 17
For the July 2022 through June 2023 PCA evaluation period, the authorized base level 18
of expense was based on the actual annual expenses for the year ended December 31, 2019, 19
with forward estimates to an effective date of September 1, 2021. The base levels for the Review 20
Period result from the power supply revenues and expenses approved by the Commission in 21
Case No. AVU-E-21-01. To the extent actual expenses are different than those approved in the 22
authorized base level, they are deferred for later recovery, pending annual prudency review. 23

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Avista Corporation

Q. How is the deferral calculated? 1
A. The PCA deferral is calculated by subtracting authorized base net power supply 2
expense from actual net power supply expense to determine the change in net power supply 3
expense. The total change in net expense under the PCA is multiplied by Idaho’s share of the 4
Production/Transmission Ratio (PT Ratio) approved in association with base net power supply 5
expense. Change in Idaho retail sales is then multiplied by the Load Change Adjustment Rate 6
(LCAR) and added to or subtracted from the change in power supply expense to calculate the 7
total power expense change. Ninety (90) percent of the change in power expense is included in 8
the deferral mechanism while the remaining ten (10) percent is retained by the Company. 9
Q. What were the changes in power costs during the PCA Review Period? 10
A. During the Review Period, actual net power costs were higher than the 11
authorized (or baseline) net power costs for the Idaho jurisdiction by $18,300,680. After taking 12
into consideration the 90% allowable deferral percent, the total is $16,470,612 PCA deferral in 13
the surcharge direction. 14
Q. What was the amount associated with the incremental O & M Costs 15
associated with the Energy Imbalance Market (EIM)? 16
A. This expense of $879,609 was approved to be included in the PCA deferral in 17
Order No. 35606 up to the benefit of the EIM program. 1In addition, as required by Order 34606 18
in Case No. AVU-E-20-01 the Company filed a report on May 18, 2023, one year after 19
operation, detailing expenditures and informing the Commission of ongoing costs and benefits 20
of EIM. In that filing, the Company committed to filing an update on the EIM benefit 21

1 When including the impact of the incremental O&M Costs for the rate period, the total amount to be collected
from customers is $17,316,471 (16,470,608 as described in this variance – 879,609 EIM O&M = 17,262,258).

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Avista Corporation

calculation and the results with this PCA filing. This information is provided in my workpapers. 1
Q. Please summarize the primary components which contributed to actual 2
power supply expenses being higher than the authorized level during the Review Period? 3
A. Average load exceeded authorized (baseline) load by approximately 58 average 4
megawatts (aMW) for the year. The power market experienced significant volatility, 5
particularly in 2022, in response to high demand resulting from extremely hot (summer) or cold 6
(winter) weather, periods of lower-than-normal hydroelectric generation, and increased demand 7
for natural gas generation. Energy markets are also becoming more dynamic in response to 8
factors such as the EIM, regional climate policies, and other factors which have impacted 9
pricing since the PCA baseline became effective in September 2021. 10
Dependent upon timing, economics and resource availability, the Company utilized a 11
mix of resources and market purchases to meet the additional load demand. Meeting the 12
requirements of this additional load, particularly in times of high prices, resulted in net expenses 13
higher than authorized. The monthly shape of these variances are illustrated in Figure No. 1 14
below: 15

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Avista Corporation

Figure No. 1 – Monthly Expense Variance 1
2
3
4
5
6
7
8
9
10
11
For purposes of this variance analysis, workpapers provided by Avista differentiate 12
between the “cost variance” (which represents the price/quantity variance when comparing the 13
actual values to authorized as recorded to the general ledger), and “generation variance”2 (which 14
represents the value each resource contributed towards meeting customer load requirements). 15
The generation variance essentially reallocates the variances to the applicable resource 16
to represent the market value the plants provided towards meeting load requirements. As such, 17
the variance is a function of both generation deviations and the estimated market price of power. 18
This calculation is not intended to be an “exact science”, but rather a proxy value for Heavy 19
Load (HL)/Light Load (LL) of each component in our resource mix as compared to authorized. 20
The primary purpose is to provide an indicator as to how each component of our overall 21

2 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

resource stack adjusted up or down to meet changing load requirements. The proxy value of 1
actual HL/LL market prices, is illustrated in Figure No. 2 below: 2
Figure No. 2 - Electric Prices (July 2022 through June 2023) 3
4
5
6
7
8
9
10
11
12
13
14
Q. What were the factors which influenced actual power prices to be higher 15
than the forecast used in the authorized base? 16
A. Some of this price variance is a function of the timing difference resulting from 17
the setting of rates compared to the review period. The wholesale power market experienced 18
significant volatility since the time rates were set for a variety of reasons including (1) a 19
sustained increase in natural gas prices throughout the review period, (2) early and sustained 20
cooler than normal temperatures throughout the west in the 2022/2023 winter period, and (3) 21
lower than forecast hydro conditions in the Northwest. 22
Actual power prices were materially higher than forecast in the authorized base level in 23

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Avista Corporation

September and December due to a combination of factors, primarily resulting from higher 1
customer loads due to regional prolonged weather events, lower hydroelectric conditions, and 2
higher natural gas prices due to lower storage conditions and other supply limitations. 3
As illustrated in Figure No. 3 below, December temperatures in Spokane averaged 23.5 4
degrees Fahrenheit, well below average, as several significant, extreme cold events affected the 5
entire region. In some places across the west temperatures dropped below negative 20 degrees 6
Fahrenheit. 7
Figure No. 3 - November and December Average Temperature for Spokane 8
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12
13
14
15
16
17
18
19
20
Several Pacific Northwest utilities including Grant PUD, Douglas PUD, and Bonneville 21
Power Administration (BPA) reached all-time peak winter loads. BPA’s demand set a new high 22
for their electricity system on December 22, 2022, reaching 11,068 MW. Avista also 23

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Avista Corporation

experienced extreme weather with Avista’s peak load in this time period being second only to 1
the Heat Dome event of June 2021. The correlation between load and temperature is illustrated 2
in Figure No. 4 below: 3
Figure No. 4: Average Temperature as compared to Customer Load 4
5
6
7
8
9
10
11
12
13
14
15
16
Q. Did the electric price spike in September impact Idaho’s PCA deferral? 17
A. No, it did not. In September of 2022, the first nine days of the month started with 18
an excessive heat event, stretching from California to Utah. In Sacramento alone, temperatures 19
reached an all-time high of 116 degrees Fahrenheit, breaking the previous record set in July 20
1925 according to the national weather service. In addition, both Reno and Salt Lake City 21
experienced the hottest days ever on record. This hotter-than-normal weather system only 22
impacted the Pacific Northwest for the first two days of the month, and September finished only 23

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Avista Corporation

slightly warmer than normal. This weather pattern resulted in price spikes at many trading hubs 1
on the west coast, with Mid-C price jumping to an average of $198.36 per MW from the August 2
average of $108.16 per MW. The weather pattern was not long enough to significantly impact 3
Avista customer demand, but September finished with load above what was anticipated by 21 4
aMW. Avista was able to offset the majority of the impacts of this demand increase through 5
efficient optimization of its portfolio of resources resulting in expenses relatively close to the 6
level anticipated in authorized. 7
Q. What other conditions may have impacted overall power costs? 8
A. On the supply side, the cold temperatures in late 2022 resulted in less 9
hydroelectric generation than the median level utilized to set the authorized base level of 10
expense. The temperatures were such that all precipitation fell and remained as snow and no 11
low-level snow melted, which impacted river flow and associated hydro generation. To meet 12
demand, natural gas was needed as replacement power for this reduced hydroelectric 13
generation. However, natural gas faced supply limitations in response to the significant increase 14
in demand, reduced storage levels, and pipelines were at capacity, resulting in even further 15
upward price pressure. The impact of the combination of these supply and demand conditions 16
was significant, pushing natural gas hourly prices as high as $58.00. See Figure No. 5 for 17
monthly gas prices: 18

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Avista Corporation

Figure No. 5 - Natural Gas Prices (July 2022 through June 2023) 1
2
3
4
5
6
7
8
9
10
11
It is important to note that natural gas prices impact more than just Avista’s natural gas 12
fuel for generating resources. Natural gas prices also impact the ability to utilize transportation 13
pipelines to capture the benefit of Avista’s unique location in the Pacific Northwest for the 14
benefit of electric customers. Natural gas prices are a key input to making decisions regarding 15
generating and selling surplus energy and capacity and providing reliable system 16
support. These surplus opportunities help to reduce customers resource costs which they pay 17
for in order to ensure reliability. 18
Q. You mention hydroelectric generation was lower than median levels for 19
most of the year, would you please expand on this? 20
A. Yes. Generation from the Company-owned resources on the Clark Fork and 21
Spokane River systems, as well as contracted hydroelectric generation on the Mid-Columbia 22
were lower than the authorized level by 61 aMW. While there is no direct charge for generation 23

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Avista Corporation

at Company-owned hydroelectric plants, lack of generation results in the need to replace that 1
energy. The value of this lost generation, priced at market rates, was approximately $19.7 2
million, the highest increase as compared to authorized in this analysis. For the majority of the 3
review period, lack of precipitation and colder than normal weather, resulted in lower natural 4
river flows reducing generation. Beginning in November of 2022 until the third week of April 5
of 2023 (with the exception of January), weather was colder than normal which kept the water 6
in the mountains, reducing streamflow available for hydroelectric generation. 7
In combination with the other supply conditions described above, and increased 8
customer demand, in several months power prices were significantly higher than those 9
embedded in the authorized level. In December alone, when wholesale power prices peaked at 10
almost $275/MWh (see Figure No. 2 above), the impact of this lost generation was $14.0 11
million (system).3 Expanding this to the period of lower-than-normal temperatures November 12
– April the impact of lost generation was almost $48 million (system).4 Conversely, in late 13
April the weather abruptly changed from colder than normal to significantly warmer than 14
normal, with the last 3 days of the month 16 to 22 degrees above normal. Four days set record 15
temperatures in the first part of May in Spokane, resulting in extremely rapid snowmelt. As an 16
example, on April 14 the Clark River was 92% of normal and by June 5, 2023 the snowpack 17
was nearly gone with levels below 25%. On a generation basis, generation for the month of 18
May was higher than the anticipated median by 35 aMW. For the month of June, with snow 19
levels effectively diminished, generation was approximately 118 aMW below what was 20
anticipated in the authorized base. This lack of generation, priced at market rates, resulted in 21

3 See Company workpapers 2022-2023 sheet “Detail” column BL, row 84-86).
4 For continuity, January is included in this value. However, January was the only month not colder than normal.

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Avista Corporation

approximately $14 million more expense than anticipated in the authorized base level. 1
Figure No. 6 - Hydroelectric Generation and Power Prices 2
3
4
5
6
7
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9
10
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12
13
14
Q. Were there any other factors which materially impacted overall power 15
supply expense for 2023? 16
A. No, there were not. 17
Q. Are there any costs related to Washington’s Climate Commitment Act in 18
the 2023 calendar portion of the PCA? 19
A. No, there are not. 20
21
22
23

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Avista Corporation

Cost
Variance
Generation
Variance
Total
Variance
Idaho
Share @
90%
1. Change in Net Power Purchases (Purchases net of Sales)(32,029)$ 3,028$ (29,000)$ (26,100)$
2. Change in Natural Gas Plant Generation 40,552$ (19,676)$ 20,877$ 18,789$
3. Change in Thermal Generation 3,768$ (2,338)$ 1,430$ 1,287$
4. Change in Wind Generation 10,195$ (21,186)$ (10,992)$ (9,892)$
3. Change in Hydro Generation 5,758$ 19,636$ 25,394$ 22,855$
2. Change in retail load (6,385)$ 20,535$ 14,150$ 12,735$
7. Change in Net Transmission Expense (purchases net of sales)(3,654)$ -$ (3,654)$ (3,289)$
8. Other Miscellaneous Expense 96$ -$ 96$ 86$
Total Variance to Authorized 18,301$ -$ 18,301$ 16,471$
Idaho Power Cost Adjustment Variance Analysis
July 2022 - June 2023
(in thousands)
III. OVERVIEW OF VARIANCE COMPONENTS 1
Q. Please provide an overview of each component of the variance analysis. 2
Table No. 1 below provides an overview by resource type of the variances between the 3
authorized base level expense and the actual expense recorded in the review period. 4
Table No. 1 - Actual to Authorized Variance 5
6
7
8
9
10
11
12
13
14
15
16
17
18
Please note the Company has provided work papers supporting all impacts listed in 19
Table No. 1. For the following sections, please refer to the individual line items and values 20
provided in Table No. 1 above. 21
Item No. 1: Change in Net Power Purchase Expense ($29,000,000 lower than 22
authorized base). In addition to the generation from Company-owned or operated 23
resources, Avista engages in both short-term market transactions (purchases and sales) 24
as well as long-term structured transactions with counterparties. The Company 25

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Avista Corporation

considers several factors including economics, load requirements, and hydro conditions 1
when evaluating the benefits of off-system sales. For the PCA year, sales exceeded 2
purchases, netting to 44 aMW above what was estimated in setting the authorized base 3
level. Effectively, Avista was a net seller resulting higher sales of $32.0 million (before 4
sharing). On a price variance only comparison, eliminating the impact of any volume 5
variances, total net purchases were lower than anticipated by $26.1 million after sharing. 6
The primary market factors which influenced power prices were described earlier in my 7
testimony. 8
9
Item No. 2: Change in Natural Gas Generation ($20,877,000 higher than authorized 10
base). This item is primarily comprised of Avista’s Coyote Springs II (CS2) generating 11
station as well as a Power Purchase Agreement (PPA) associated with Lancaster. Also 12
included in Avista’s overall natural gas generation portfolio, categorized as “Other CT” 13
is Boulder Park, Rathdrum, Kettle Falls CT, and Northeast Combustion Turbine. For 14
the Review Period, natural gas generation was higher than anticipated in the authorized 15
base forecast by 78 aMW. Generation at Lancaster contributed the most to this 16
variance, accounting for 43 aMW of the total. On a cost basis, natural gas generation 17
was approximately $40.5 million above what was forecast in the authorized base due to 18
the increase in generation at natural gas prices which were materially higher in actuals 19
than in authorized base level in almost all months of the year. For the Review Period, 20
the average natural gas price was $9.59 per dekatherm (actual) versus $3.28 per 21
dekatherm (authorized). However, this natural gas resources were particularly valuable 22
in meeting the increase in customer loads during peak price periods. To demonstrate 23
this value, the generation variance removes the impact of the volume variance by 24
approximately $19.7 million. By removing this variance, the analysis more accurately 25
reflects the impact of only this increase in price, resulting in a total expense variance of 26
$18.8 million, after sharing. 27
28
Item No. 3: Change in Thermal Generation ($1,430,000 higher than authorized base). 29
Costs related to coal contract prices at Colstrip was the primary contributor to higher 30
expense than embedded in the authorized base level for thermal generation. The 31
contractual price is $31.41 cost per ton compared to an authorized level of $16.89 cost 32
per ton. The contract price includes a base price that is adjusted annually based on six 33
inflation adjustments for labor and benefits, diesel fuel, electricity, explosives, mining 34
machinery and equipment, and implicit price deflator. In total the impact of these 35
inflation adjustments far exceeded those anticipated when setting the authorized base. 36
As compared to authorized, actual costs exceeded the amount embedded in customers 37
rates by approximately $3.8 million. The generation variance effectively eliminates the 38
impact of the volume variance, reduced the overall difference by approximately $2.3 39
million, resulting in net costs higher than authorized by $1.3 million, after sharing. 40

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Avista Corporation

1
Item No. 4: Change in Wind Net Expense ($10,992,000 lower than authorized base). 2
Included in this category is both the Palouse Wind Project and the Rattlesnake Wind 3
Project Power Purchase Agreements that are not included in the authorized base rates 4
in Idaho. As such, the contracts are a variance when comparing actual to the base 5
authorized level. However, in regard to the value this contract brings to Avista’s overall 6
portfolio of resources, we can estimate by comparing to market rates. The formula is a 7
function of the actual hourly generation of the plant times the contract price, offset by 8
the hourly market value of the power generated, resulting in an overall favorable 9
variance. Approximately 51% of this variance is in the winter months (most especially 10
December), as is expected with the high prices in these months. For the review period, 11
Palouse Wind helped to meet approximately 34 aMW of customer load, and Rattlesnake 12
Flat met 39 aMW of customer load. The contract price for Rattlesnake Flat was lower 13
as compared to authorized market prices, offsetting a higher price for Palouse Wind. 14
15
Item No. 5: Change in Hydro Generation ($22,855,000 higher than authorized base). 16
Total hydro generation was lower than the authorized level by 61 aMW resulting in total 17
power supply expense exceeding the anticipated authorized base by $19,636,000 18
compared to authorized. Company-owned plants on the Spokane River and Clark Fork 19
River were lower than authorized by 16 aMW and 34 aMW respectively. In addition, 20
hydro generation from the Mid-Columbia contracted hydro plants were also below 21
median levels included in the authorized base level by an additional 11 aMW. The 22
conditions which contributed to this reduced generation were discussed previously in 23
testimony. This category also includes the cost related to Avista’s long term power 24
purchase for Mid-Columbia hydroelectric generation with Chelan PUD, Grant PUD, 25
and Douglas PUD. These contracts provide reliable capacity for Avista’s system in 26
addition to energy. Grant’s meaningful priority contract is adjusted annually based on 27
results of an annual “bid” process. When rates were set in September 2021, the system-28
level monthly contract expense was approximately $939,000. That monthly contract 29
increased in January 2022 to $1,459,000 and to $2,418,000 per month in 2023. The 30
result is approximately $5.8 million on an Idaho-allocated basis above what is 31
embedded in the authorized base level. 32
33
Item No. 6: Change in Retail Loads ($14,150,000 higher than authorized base). The 34
impact of the change in retail loads is the net of the deviation in actual load versus the 35
authorized level multiplied by the market price of power (netted against the retail 36
revenue adjustment). For the Review Period, Idaho retail sales were 58 aMW above the 37
authorized level. As previously discussed, Avista experienced near-peak conditions in 38
December of 2022. When priced at exceptionally high-power market prices, the cost to 39
serve this additional load, above what was included in the authorized level, is 40

Holland, Di 21
Avista Corporation

approximately $20.5 million. This higher cost is reduced by the load cost adjustment 1
as prices were higher than the authorized rate by approximately $6.4 million, netting to 2
$14.2 million ($12.7 million after sharing). Additional information regarding the LCAR 3
has been provided previously in my testimony. 4
5
Item No. 7: Change in Net Transmission Expense ($3,654,000 lower than authorized 6
base). Transmission revenue was higher than the authorized level primarily from higher 7
than normal short-term and non-firm use of Avista’s transmission system in 2022. This 8
increase was not approved at the time rates were effective in September 2021. Higher 9
revenue also resulted from Avista’s transmission rate increase which was approved by 10
FERC and became effective October 1, 2021. Avista’s point-to-point rates went up 37% 11
and its Annual Transmission Requirement (which applies to BPA Network Service) rose 12
53%. The result of this was a total variance of $3.7 million before sharing and $3.3 13
million allocated to Idaho. 14
15
Item No. 8: Change in Misc. Expense ($86,000 higher than authorized base). 16
Miscellaneous Expense consists of broker fees, California Independent System 17
Operator (CAISO) fees, and the Montana Invasive Species. The primary contributor to 18
the increase was CAISO wheeling access charge which is variable in nature. 19
20
V. NEW LONG-TERM CONTRACTS ENTERED INTO DURING REVIEW PERIOD 21
Q. Please provide a brief description of new long-term contracts that the 22
Company entered into during the Review Period. 23
A. The Company entered into a Power Purchase Agreement (PPA) for energy and 24
capacity resources from Tyr Energy’s Rathdrum based Natural Gas CCCT (aka “Lancaster”) 25
on March 31, 2023. The contracted facility is a 280 MW gas-fired, combined cycle power 26
generation facility located in Rathdrum, Idaho for which Avista was offered several options for 27
consideration including a 10-year PPA, a 15-year PPA and a facility purchase option. The 15-28
year option represented the most customer benefit and was selected. The terms of this contract 29
resulted in the acquisition of a 280 MW of firm capacity and energy. Lancaster currently 30
supplies Avista with capacity and energy and this contract extends the term from November 1, 31

Holland, Di 22
Avista Corporation

2026 through December 31, 2041. The Lancaster executed PPA will help meet Avista’s energy 1
and capacity needs as defined in the Company’s 2021 IRP. The continuation of the Lancaster 2
agreement provides years of affordable and reliable energy that will benefit Avista’s system 3
and its customers. 4
Avista also executed a final Power Purchase Agreement (PPA) for NextEra’s phase 3 5
of their Clearwater Wind Project (Clearwater) on January 20, 2023. Clearwater is located 6
approximately 80 miles north of Colstrip Montana, connecting via a gen-tie line constructed by 7
NextEra to the Colstrip Transmission System (CTS) which is also the interconnection point to 8
the Northwestern Energy system (NWE). The terms of this contract resulted in the acquisition 9
of a 100 MW of name plate capacity. The contract will supply Avista with renewable energy 10
from Clearwater, from January 1, 2026 through December 31, 2055. In exchange for a reduced 11
rate, Avista agreed to an early Commercial Operation Date (COD), where Avista will accept 12
delivery of test energy as early as September 1, 2024, with an estimated COD of December 1, 13
2024. 14
A new contract with Columbia Basin Hydro Power executed in December 2022 15
provides new hydro capacity and energy for Avista. As a product of irrigation operations, the 16
generation profile meets Avista’s increasing summer load requirements. While only the Russell 17
D. Smith, E.B.C. 4.6, Summer Falls Development and P.E.C 66.0 Development projects 18
contribute during the pro forma period, the list below contains all projects. 19
• March 1, 2023, for the Russell D. Smith (P.E.C. 22.7) Development – 6.1 MW 20
• May 1, 2023, for the E.B.C. 4.6 Development – 2.2 MW 21
• January 1, 2025, for the Summer Falls Development – 92 MW 22
• March 1, 2025, for the P.E.C. 66.0 Development – 2.4 MW 23
• October 1, 2025, for the Quincy Chute Development – 9.4 MW 24
• January 1, 2027, for the Main Canal Development – 26 MW 25
• September 1, 2030, for the P.E.C. Headworks Development – 6 MW 26

Holland, Di 23
Avista Corporation

1
The Columbia Basin Hydro (CBH) contract was evaluated as part of Avista’ 2022 2
Request for Proposals (RFP) process. While this contract was not initiated as part of the RFP 3
process, it was evaluated alongside the bids received and was ranked in the top 3. 4
The Company also renewed two small PURPA contracts. The Jim Ford PURPA 5
Contract, effective July 1, 2022, provides for approximately 1.5 MW capacity for an extension 6
of two years with an expiration of June 30, 2024. This contract was approved by Order No. 7
34589, amended on August 8, 2022. The second contract was with John Day Creek Hydro with 8
an effective date of October 31, 2022 for 0.90 MW capacity with an expiration date of October 9
30, 2041, approved by Order No. 35451. 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
• Position Reports: These daily reports for each trading day in the Review Period 25

Holland, Di 24
Avista Corporation

provide a summary of transactions and plant generation and the Company’s net 1
average system position in future periods. The Daily Position Reports also contain 2
forward electric and natural gas prices. 3
• Variance Analysis: This analysis provides the detailed calculation of the differences 4
between actual and authorized for the Review Period for each subsection described 5
above. 6
• Contracts: Please see section above for provided contracts. 7
• Energy Imbalance Market Additional support on benefit calculation, above what 8
was sent in May 2023. 9
Q. Does that conclude your pre-filed direct testimony? 10
A. Yes. 11