AVISTA CORP

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended September 30, 2026 and September 30, 2025 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income and Comprehensive Income for the interim periods are not necessarily indicative of the results expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2025 (2025 Form 10-K).

NOTE 1. SUMMARY OF SIGNIF ICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana.

AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of the subsidiary companies in the non-utility businesses, except AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment information.

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances are eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations associated with its interests in jointly owned plants.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.

Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value.

The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory liability or asset. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through the ERM in Washington, the PCA mechanism in Idaho, PGAs, and periodic general rate cases. The resulting regulatory assets associated with energy commodity derivative instruments are probable of recovery through future rates.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory liability or asset. Contracts not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract determined to be other-than-temporary.

The Company previously entered interest rate swap derivatives as risk management tools and has associated regulatory assets and liabilities. The regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt.

The Company has multiple master agreements with a variety of entities allowing for cross-commodity netting of derivative agreements with the same counterparty (e.g. power derivatives can be netted with natural gas derivatives under certain conditions). In addition, some master agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed Consolidated Balance Sheets.

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Derivative assets and liabilities, deferred compensation assets, and some equity investments are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 12 for the Company’s fair value disclosures.

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies.

Change in Accounting Estimate

In the third quarter of 2026, the Company completed a time study which supports the capitalization of certain employee compensation to Utility Property, which was previously included in other operating expenses. The Company allocated $5 million of certain employee compensation to Utility Property in the third quarter of 2026, resulting in a net income impact of $4 million (considering the impact of income taxes), which represents an increase of $0.05 earnings per diluted share. This change is treated as a change in accounting estimate and has been applied prospectively.

NOTE 2. NEW ACCO UNTING STANDARDS

ASU 2023-06 "Disclosure Improvements - Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative"

In October 2023, the FASB issued ASU 2023-06, which incorporates a variety of SEC required disclosures into the FASB Accounting Standards Codification (ASC). For entities subject to SEC's existing disclosure requirements, the effective date for each amendment will be the date on which the SEC removes the related disclosure from Regulation S-X or Regulation S-K, with early adoption permitted. If the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K by June 30, 2027, the disclosure requirements will be removed from the Codification. The requirements of the ASU will not have a material impact on the Company's financial statements.

ASU 2024-03 "Disaggregation of Income Statement Expenses"

In November 2024, the FASB issued ASU 2024-03, requiring additional footnote disclosures disaggregating certain expenses included on the income statement. The ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027, and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt in 2026.

ASU 2025-05 "Measurement of Credit Losses for Accounts Receivable and Contract Assets"

In July 2025, the FASB issued ASU 2025-05, providing a practical expedient that may be elected to assume current conditions as of the balance sheet date will remain unchanged for the remaining life of the receivable when developing an estimate of expected credit losses on accounts receivable arising from contracts with customers. The ASU is effective for annual reporting periods beginning after December 15, 2025 and interim reporting periods within those annual periods, and early adoption is permitted. The Company elected to utilize the practical expedient, effective January 1, 2026, which did not have a material impact on the financial statements.

ASU 2025-06 "Targeted Improvements to the Accounting for Internal-Use Software"

In September 2025, the FASB issued ASU 2025-06, which updates the capitalization criteria for internally developed software projects. The ASU is effective for annual reporting periods beginning after December 15, 2027 and interim reporting periods within those annual periods, and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt in 2026.

ASU 2025-10 "Accounting for Government Grants Received by Business Entities"

In December 2025, the FASB issued ASU 2025-10, which establishes authoritative accounting guidance for government grants received by a business entity. The ASU is effective for annual reporting periods beginning after December 15, 2028 and interim reporting periods within those annual periods, and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt in 2026.

ASU 2026-02 "Environmental Credits and Environmental Credit Obligations (Topic 818)"

In May 2026, the FASB issued ASU 2026-02, which establishes specific authoritative guidance for environmental credits and environmental credit obligations. The ASU is effective for annual reporting periods beginning after December 15, 2027 and interim reporting periods within those annual periods, and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt in 2026.

NOTE 3. BALANCE SHEET COMPONENTS

Inventory

Inventories of materials and supplies, emission allowances, stored natural gas, and fuel stock are recorded at average cost and consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

Other Current Assets

Other current assets consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

Other Property and Investments-Net and Other Non-Current Assets

Other property and investments-net and other non-current assets consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

Other Current Liabilities

Other current liabilities consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of September 30, 2026 and December 31, 2025 (dollars in millions):

NOTE 4. REVENUE

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three and nine months ended September 30 (dollars in millions):

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and nine months ended September 30 (dollars in millions):

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and nine months ended September 30 (dollars in millions):

Unsatisfied Performance Obligations

The Company has certain capacity arrangements under which the Company has a contractual obligation to provide either electric or natural gas capacity to a customer for a fixed fee. As of September 30, 2026, the Company estimates it had unsatisfied capacity performance obligations of$16 million related to these arrangements, which will be recognized as revenue in future periods as the capacity is provided to the customers. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company has one capacity agreement under which the customer makes payments throughout the year, which resulted in deferred revenue of $2 million as of September 30, 2026. Except for the deferred revenue, these unsatisfied performance obligations are not reflected on the Condensed Consolidated Balance Sheet, as the Company has not received payment for these services.

NOTE 5. EQUITY METHOD INVESTMENTS

The Company holds a 4.71% interest in Energy Impact Partners I (EIP I), an investment fund, and records activity on a quarter lag using the equity method. In June 2026, ERock, Inc., one of the companies included in the underlying holdings of EIP I, conducted an initial public offering (IPO) and is now publicly traded on the New York Stock Exchange.

In the three months ended September 30, 2026, the Company recorded equity in earnings of $24 million for its holdings of EIP I, primarily associated with a fair market increase of ERock, Inc. through its IPO. Based on its ownership percentage of ERock, Inc., the Company estimates its portion of the fair value decrease from June 30, 2026 to September 30, 2026 to be recognized in the fourth quarter of 2026 to be $7 million. Subsequent to September 30, 2026, the underlying investment's stock price has decreased. While actual results for the first quarter of 2027 will reflect the fair market value of ERock, Inc. on December 31, 2026, the Company estimates a loss of $3 million based on their fair market value on November 3, 2026. This activity will be recognized along with any other activity reported by EIP I.

NOTE 6. DERIVATIVESAND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated commodity derivative instruments. Avista Corp. utilizes instruments that meet the definition of a derivative under U.S. GAAP, such as forwards, futures, swaps and options, to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour periods up to multiple years.

As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. Based on these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak-day event. Avista Corp. generally has more pipeline and storage capacity than is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.

The following table presents the underlying energy commodity derivative volumes as of September 30, 2026 expected to be settled in each respective year (in thousands of MWhs and mmBTUs):

As of September 30, 2026, there areno energy commodity derivative contracts outstanding with expected settlements after 2029.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2025 expected to be settled in each respective year (in thousands of MWhs and mmBTUs):

As of December 31, 2025, there wereno energy commodity derivative contracts outstanding with expected settlements after 2028.

(1)

Physical transactions represent commodity derivative transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent financial derivative instruments that are settled in cash with no physical delivery of the underlying commodity, such as futures, swaps, or options contracts.

The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be recovered through retail rates from customers.

Foreign Currency Exchange Derivatives

A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.

The following table summarizes the foreign currency exchange derivatives outstanding as of September 30, 2026 and December 31, 2025 (dollars in millions):

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of September 30, 2026 and December 31, 2025 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of energy commodity derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2026 (dollars in millions):

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2025 (dollars in millions):

Exposure to Demands for Collateral

Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. The following table presents collateral outstanding related to its energy commodity derivative instruments as of September 30, 2026 and December 31, 2025 (dollars in millions):

In the event of changes in market prices or a downgrade in Avista Corp.'s credit ratings (including maintaining an "investment grade" credit rating) or other established credit criteria, or, in some cases, if the counterparty has reasonable grounds to believe that there has been a material change in Avista Corp.'s creditworthiness, additional collateral may be required. Counterparties could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.

In periods of price volatility, the level of exposure can change significantly. In addition, these contracts contain customary events of default (including cross-defaults to indebtedness and other obligations) and termination provisions. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. See Note 9 for further discussion of these credit facilities, including the immediate reimbursement obligation associated with outstanding letters of credit.

The following table presents the aggregate fair value of energy commodity derivative instruments with credit-risk-related contingent features in a liability position, and the amount of additional collateral (in cash or letters of credit) Avista Corp. could be required to post as of September 30, 2026 (dollars in millions):

NOTE 7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

The Company contributed $10 million in cash to the pension plan during the nine months ended September 30, 2026, and does not expect further contributions in 2026.

The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costsfor the three and nine months ended September 30 (dollars in millions):

Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 50 percent of all labor and benefits is capitalized to utility property and 50 percent is expensed to utility other operating expenses.

The non-service portion of costs in the table above are recorded to other expense below income from operations in the Condensed Consolidated Statements of Income and Comprehensive Income or capitalized as a regulatory asset. Approximately 50 percent of the costs are capitalized to regulatory assets and 50 percent is expensed to the income statement.

NOTE 8. INCOME TAXES

In accordance with interim reporting requirements, the Company uses an estimated annual effective tax rate for computing its provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

The following table reconciles the difference between the Company's effective tax rate and the federal statutory rate on income from continuing operations, including equity method earnings (losses), for the three and nine months ended September 30 (dollars in millions):

(1)

The Company's general rate cases included approval of base rate increases, offset by tax customer credits. As the tax customer credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs.

In 2026, the Company purchased $13 million of 2025 transferable tax credits from another taxable entity for $12 million. Of the tax credits purchased in 2026, $10 million were utilized in the Company's 2025 federal tax return, filed in September 2026, with the remaining credits carried forward for future utilization. There wereno other federal taxes paid in the first three quarters of 2026. In 2026, the Company received income tax refunds of $42 million.

NOTE 9. SHORT-TERM BORROWINGS

Lines of Credit

Avista Corp. has a committed line of credit in the total amount of $500 million, with an expiration date of June 2029. The Company may request that the lenders extend their commitments for an additional one-year period (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank that are payable only to the extent that Avista Corp. defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.’s revolving committed line of credit were as follows as of September 30, 2026 and December 31, 2025 (dollars in millions):

Letter of Credit Facility

Avista Corp. has a letter of credit agreement in the aggregate amount of $65 million, which was increased from $50 million in June 2026. Either party may terminate the agreement at any time.

Avista Corp. had$8 million and $14 million in letters of credit outstanding under this agreement as of September 30, 2026 and December 31, 2025, respectively. Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, Avista Corp. would have an immediate obligation to reimburse the bank that issued the letter of credit.

Covenants and Default Provisions

The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of September 30, 2026, the Company complied with this covenant.

AEL&P

AEL&P has a committed line of credit in the amount of $25 million that expires in June 2028. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates on borrowings under AEL&P’s revolving committed line of credit were as follows as of September 30, 2026 and December 31, 2025 (dollars in millions):

The committed line of credit agreement contains customary covenants and default provisions, including a cross default from other indebtedness (as defined). The credit agreement has a covenant which does not permit the ratio of "consolidated total debt at AEL&P" to "consolidated total capitalization at AEL&P," including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of September 30, 2026, AEL&P complied with this covenant.

NOTE 10. LONG-TERM DEBT

In May 2026, the Company issued and sold $90.0 million of 4.77 percent first mortgage bonds due in 2029 and $70.0 million of 6.10 percent first mortgage bonds due in 2056 pursuant to a bond purchase agreement with institutional investors in the private placement market. In August 2026, the Company issued and sold an additional $70.0 million of 6.10 percent first mortgage bonds due in 2056 under this bond purchase agreement.

The net proceeds from the sale of the new bonds were used to refinance existing indebtedness and pay for utility capital expenditures.

NOTE 11. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of$52 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50 million of Preferred Trust Securities. The distribution rate on the Preferred Trust Securities is three-month CME Term SOFR plus 1.137 percent.

The distribution rates were as follows during thenine months ended September 30, 2026 and the year ended December 31, 2025:

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued$2 million of Common Trust Securities to the Company. The Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In 2000, the Company purchased $10 million of these Preferred Trust Securities.

The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its condensed consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are$52 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income and Comprehensive Income represents interest expense on these debentures.

NOTE 12. FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings as shown on the Condensed Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and material finance leases) and long-term debt to affiliated trusts as shown on the Condensed Consolidated Balance Sheets may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors including the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), and the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2026 and December 31, 2025 (dollars in millions):

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of market prices of 53.80 percent to 100.33 percent of the principal amount, where 100.0 percent of the principal amount (adjusted for unamortized discount or premium) represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation fair value is determined using the Morgan Markets A Ex-Fin discount rate as published on September 30, 2026 and December 31, 2025.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 2026 and December 31, 2025 at fair value on a recurring basis (dollars in millions):

(1)

The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

(2)

The Level 3 energy commodity derivative balances are associated with a natural gas exchange agreement.

(3)

Included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 6 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. Electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets.

Level 3 Fair Value

Natural Gas Exchange Agreement

For the natural gas commodity exchange agreement, the Company uses the same Level 2 market quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions are not highly correlated with market prices and market volatility.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2026 (dollars in millions, except for per mmBTU amounts):

The valuation methods, significant inputs and resulting fair values described above were developed by the Company and are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate of fair value each reporting period.

Equity Investments

The Company hastwo equity investments measured at fair value on a recurring basis. For one investment, fair value is determined using a market approach, starting with enterprise values from recent market transaction data for comparable companies with similar equity instruments. The market transaction data was used to estimate an enterprise value of the underlying investment and that value was allocated to the various classes of equity via an option pricing model and a waterfall approach. The selection of appropriate comparable companies and the expected time to a liquidation event requires management judgment. The significant assumptions in the analysis include comparable market transactions and related enterprise values and time to liquidity event. In the event there were relevant market transactions for the same or similar securities of the subject company or there were a reasonable possibility of a transaction occurring, these transactions would be utilized as an input to the valuation with a probability weight applied to the valuation.

For the second investment, fair value is determined using an income approach utilizing a discounted cash flow model. The model is based on income statement forecasts from the underlying company to determine cash flows for the period of ownership. The model then utilizes market multiples from publicly traded comparable companies in similar industries and projects to estimate the terminal fair value. The market multiples are reduced to reflect the difference in the life cycle between the publicly traded comparable companies and the start-up nature of the investment company. The selection of appropriate comparable companies, market multiples and the reduction to those market multiples requires management judgment. The significant assumptions in the model include the discount rate representing the risk associated with the investment, market multiples and the related reduction to those multiples, revenue forecasts, and the estimated terminal date for the investment. In the event there were relevant market transactions for the same or similar securities of the subject company or there were a reasonable possibility of a transaction occurring, those transactions would be used to determine the fair value of Avista Corp.’s investment under a market approach instead of utilizing a discounted cash flow model. The market transactions are considered Level 3 inputs because they are not publicly available observable transactions.

The following table presents the quantitative information and assumptions which were used to estimate the fair values of the Level 3 equity investments as of September 30, 2026 (dollars in millions):

The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3)for the three and nine months ended September 30 (dollars in millions):

There wereno transfers into or out of Level 3 fair value measurements during the period.

NOTE 13. COMMON STOCK

The Company issued shares of common stock for total net proceeds of$0 million and$58 million during the three and nine months ended September 30, 2026. Most of these shares were issued in at-the-market transactions pursuant to the Company's sales agency agreements under which the Company may offer and sell new shares of common stock through its sales agents from time to time. Under these sales agency agreements, the Company issued 1.4 million shares during the nine months ended September 30, 2026. No shares were issued under these agreements in thethree months ended September 30, 2026.

NOTE 14. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common sharefor the three and nine months ended September 30 (dollars in millions, except per share amounts, and shares in thousands):

There wereno shares excluded from the calculation because they were antidilutive.

NOTE 15. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the outcome of any matter because litigation and other contested proceedings are subject to numerous uncertainties. For matters affecting regulated operations, the Company intends to seek, to the extent appropriate, recovery of costs through the ratemaking process.

Collective Bargaining Agreements

The Company's collective bargaining agreement with the IBEW represents 35 percent of all Avista Utilities' employees. The Company's largest represented group, representing approximately 90 percent of Avista Utilities' bargaining unit employees in Washington, Idaho and Montana, are covered under afour-year agreement which expires in 2029.

In April 2025, the Company's System Operators voted to unionize, and the National Labor Relations Board certified the IBEW Local 77 as their exclusive collective bargaining representative. We are in the process of negotiating a separate contract with the IBEW for the System Operator group, which is comprised of approximately 20 employees.

Orofino Fire

In August 2023, a fire started in windy conditions near Orofino, Idaho, burning 53 acres and seven primary residences, as well as several outbuildings. The Idaho Department of Lands investigated and has issued a report in which it concluded the fire was caused by an electrical fault igniting three separate spots which then spread uphill. The Company has a distribution line in the area near the ignition point. The Company has to date found no evidence suggesting negligence on its part. Three minor claims for damage to personal property were received in connection with the fire, which were resolved. The Company has received one additional claim in connection with the fire for suppression costs from the Idaho Department of Lands seeking $0.2 million. During the third quarter of 2026, the statute of limitations related to this matter expired.

Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. In January 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. In February 2024, the Company received a second lawsuit filed by the owners of the adjacent property, seeking damages for personal injury and emotional distress from having witnessed the incident. On motions for summary judgment, the Court dismissed the party that had originally contracted for the excavation work, as well as claims brought on behalf of the children of the property owners whose home was damaged. In July 2026, the Company entered into a settlement agreement with the remaining parties in the case for $1.3 million, which was paid in August 2026.

Complaint of Consumers for Independent Regional Transmission Planning for All FERC-Jurisdictional Transmission Facilities at 100kV and Above

In December 2024, the Company received notice of a complaint filed with the FERC by Consumers for Independent Regional Transmission Planning against all FERC-jurisdictional Transmission providers with local planning tariffs utilizing facilities at 100 kV and above, which includes the Company. The complaint alleges that the local transmission planning process allows individual transmission owners to plan FERC-jurisdictional transmission facilities without regard to whether that planning is the more efficient or cost-effective project for the interconnected grid and cost effective for customers. The Company intends to vigorously defend itself in this action; however, at this time, the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Port of Morrow Class Action Lawsuit

In February 2024, a proposed class action was filed in the U.S. District Court for the District of Oregon, Pendleton Division against the Port of Morrow and other defendants. The plaintiffs allege they have suffered adverse effects from the defendants' discharge of nitrogen-laden wastewater. Subsequently, Portland General Electric (PGE) was added as a defendant. The Company is the owner of Unit 2 of the Coyote Springs Natural Gas Plant and has contracted with PGE, the owner of Unit 1, to operate its plant. The Plants are customers of the Port of Morrow, which provides water for non-contact cooling as part of the Plants' operations. The Company and PGE dispute that the use of water from the Port of Morrow for non-contact cooling, which does not add nitrates to the water, contributes to the alleged groundwater contamination at issue in the case. Under the operating agreement between the Company and PGE, the Company would be responsible for its share of associated costs and liability relating to the Plant.

Plaintiffs are primarily seeking injunctive relief, medical monitoring, and unspecified monetary damages. The trial date is currently scheduled for September 2027, however, in September 2026, the plaintiffs filed a "Notice of Global Mediation Session" for November 2026. The Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such outcome.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes any liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the 2025 Form 10-K for additional discussion regarding other contingencies.

NOTE 16. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the information reviewed by the Company's Chief Operating Decision Maker (CODM, the Company's President and Chief Executive Officer). Such information is the basis for the analysis of segment performance and the allocation of resources. Performance is evaluated based on net income (loss) and variances of actual performance from the Company's budget and/or forecast when making decisions. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is consideredone segment. AEL&P is a separate reportable business segment since it has separate financial information and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital. Decisionsby the CODM are made in consultation with other members of management, as appropriate, and are subject to the general oversight and strategic direction of the Board of Directors.

The following table presents information for each of the Company’s business segments (dollars in millions):

(1)

Intersegment eliminations reported as interest expense represent intercompany interest.

(2)

Including interest expense to affiliated trusts.

(3)

Other segment items include taxes other than income tax, AFUDC equity, and other miscellaneous expenses.

(4)

The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.