# EDGAR Filing Document

**Accession Number:** 0000104918
**File Stem:** 0001193125-26-067872
**Filing Date:** 2026-2
**Character Count:** 703876
**Document Hash:** acf7d6c1ab20bc80c8815c1da9378df9
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001193125-26-067872.hdr.sgml**: 20260225

**ACCESSION NUMBER**: 0001193125-26-067872

**CONFORMED SUBMISSION TYPE**: 10-K

**PUBLIC DOCUMENT COUNT**: 176

**CONFORMED PERIOD OF REPORT**: 20251231

**FILED AS OF DATE**: 20260225

**DATE AS OF CHANGE**: 20260224

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** AVISTA CORP
- **CENTRAL INDEX KEY:** 0000104918
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC & OTHER SERVICES COMBINED [4931]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 910462470
- **STATE OF INCORPORATION:** WA
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-03701
- **FILM NUMBER:** 26673689

**BUSINESS ADDRESS:**
- **STREET 1:** 1411 E MISSION AVE
- **CITY:** SPOKANE
- **STATE:** WA
- **ZIP:** 99202
- **BUSINESS PHONE:** 5094890500

**MAIL ADDRESS:**
- **STREET 1:** 1411 EAST MISSION
- **CITY:** SPOKANE
- **STATE:** WA
- **ZIP:** 99202

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** WASHINGTON WATER POWER CO
- **DATE OF NAME CHANGE:** 19920703

?xml version='1.0' encoding='ASCII'? 10-K

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

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**Form** 10-K

(Mark One)

☒ **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** 

**FOR THE FISCAL YEAR ENDED** December 31**,** 2025 **OR**

☐ **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**FOR THE TRANSITION PERIOD FROM TO**

**Commission file number** 001-03701

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AVISTA CORPORATION

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**(Exact name of Registrant as specified in its charter)**

---

| | |
|:---|:---|
| WA | 91-0462470 |
| **(State or other jurisdiction of**<br>**incorporation or organization)** | **(I.R.S. Employer<br>Identification No.)** |

---

1411 East Mission Avenue**,** Spokane**,** WA 99202-2600

**(Address of principal executive offices, including zip code)**

**Registrant's telephone number, including area code:** 509**-**489-0500

**Web site: http://www.avistacorp.com**

**Securities registered pursuant to Section 12(b) of the Act:**

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| | | |
|:---|:---|:---|
| **Title of Each Class** | **Trading Symbol(s)** | **Name of Each Exchange on Which Registered** |
| Common Stock | AVA | NYSE |

---

**Securities registered pursuant to Section 12(g) of the Act:**

**<u>Title of Class</u>**

**Preferred Stock, Cumulative, Without Par Value**

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

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| | | | |
|:---|:---|:---|:---|
| Large Accelerated Filer | ☒ | Accelerated Filer | ☐ |
| Non-accelerated Filer | ☐ | Smaller reporting company | ☐ |
| Emerging growth company | ☐ |  |  |

---

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ☐ No ☒

The aggregate market value of the Registrant's outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $3,078,099,757 based on the last reported sale price thereof on the consolidated tape on June 30, 2025.

As of January 31, 2026, 82,251,245 shares of Registrant's Common Stock, no par value (the only class of common stock), were outstanding.

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**<u>Documents Incorporated By Reference</u>**

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| | |
|:---|:---|
| **Document** | **Part of Form 10-K into Which**<br>**Document is Incorporated** |
| **Proxy Statement to be filed in connection with the annual meeting of shareholders to be held on May 14, 2026.**<br>**Prior to such filing, the Proxy Statement was filed in connection with the annual meeting of shareholders held on May 8, 2025.** | **Part III, Items 10, 11,**<br>**12, 13 and 14** |

---

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***AVISTA CORPORATION***

INDEX

---

| | | |
|:---|:---|:---|
| Item<br>No. |  | Page<br>No. |
|  | [<u>Acronyms and Terms</u>](#acronyms_terms) | iv |
|  | [<u>Forward-Looking Statements</u>](#forwardlooking_statements) | 1 |
|  | [<u>Available Information</u>](#available_information) | 6 |
|  | Part I |  |
| 1 | [<u>Business</u>](#item_1_business) | 7 |
|  | [<u>Company Overview</u>](#company_overview) | 7 |
|  | [<u>Avista Utilities</u>](#avista_utilities) | 8 |
|  | [<u>General</u>](#general) | 8 |
|  | [<u>Electric Operations</u>](#electric_operations) | 9 |
|  | [<u>Electric Requirements</u>](#electric_requirements) | 9 |
|  | [<u>Electric Resources</u>](#electric_resources) | 9 |
|  | [<u>Hydroelectric Licenses</u>](#hydroelectric_licenses) | 13 |
|  | [<u>Future Resource Needs</u>](#future_resource_needs) | 13 |
|  | [<u>Natural Gas Operations</u>](#natural_gas_operations) | 16 |
|  | [<u>Utility Regulation</u>](#utility_regulation) | 18 |
|  | [<u>Federal Laws Related to Wholesale Competition</u>](#federal_laws_related_to_wholesale_compet) | 19 |
|  | [<u>Regional Transmission Planning</u>](#regional_transmission_planning) | 19 |
|  | [<u>Regional Energy Markets</u>](#regional_energy_markets) | 20 |
|  | [<u>Reliability Standards</u>](#reliability_stards) | 20 |
|  | [<u>Vulnerability to Cyberattack</u>](#vulnerability_to_cyberattack) | 20 |
|  | [<u>Avista Utilities Operating Statistics</u>](#avista_utilities_operating_statistics) | 21 |
|  | [<u>Alaska Electric Light and Power Company</u>](#alaska_electric_light_power_company) | 23 |
|  | [<u>Alaska Electric Light and Power Company Operating Statistics</u>](#alaska_electric_light_power_company_oper) | 25 |
|  | [<u>Other Businesses</u>](#or_businesses) | 26 |
| 1A. | [<u>Risk Factors</u>](#item_1a_risk_factors) | 27 |
| 1B. | [<u>Unresolved Staff Comments</u>](#item_1b_unresolved_staff_comments) | 37 |
| 1C.  | [<u>Cybersecurity</u>](#item_1c_cybersecurity) | 37 |
| 2 | [<u>Properties</u>](#item_2_properties) | 39 |
|  | [<u>Avista Utilities</u>](#avista_utilities_1) | 39 |
|  | [<u>Alaska Electric Light and Power Company</u>](#alaska_electric_light_power_company_1) | 41 |
| 3 | [<u>Legal Proceedings</u>](#item_3_legal_proceedings) | 41 |
| 4 | [<u>Mine Safety Disclosures</u>](#item_4_mine_safety_disclosures) | 41 |
|  | Part II |  |
| 5 | [<u>Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities</u>](#item_5_market_for_registrants_common_equ) | 42 |
| 6 | [<u>Removed and Reserved</u>](#item_6_removed_and_reserved) | 42 |
| 7 | [<u>Management's Discussion and Analysis of Financial Condition and Results of Operations</u>](#item_7_managements_discussion_analysis_f) | 43 |
|  | [<u>Business Segments</u>](#business_segments) | 43 |
|  | [<u>Executive Overview</u>](#executive_level_summary) | 43 |
|  | [<u>Regulatory Matters</u>](#regulatory_matters) | 45 |
|  | [<u>Results of Operations - Overall</u>](#results_operations_overall) | 48 |

---

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***AVISTA CORPORATION***

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| | | |
|:---|:---|:---|
|  | [<u>Non-GAAP Financial Measures</u>](#nongaap_financial_measures) | 50 |
|  | [<u>Results of Operations - Avista Utilities</u>](#results_operations_avista_utilities) | 50 |
|  | [<u>Results of Operations - Alaska Electric Light and Power Company</u>](#results_operations_alaska_electric_light) | 57 |
|  | [<u>Results of Operations - Other Businesses</u>](#results_operations_or_businesses) | 57 |
|  | [<u>Accounting Standards to Be Adopted in 2026</u>](#new_accounting_standards) | 57 |
|  | [<u>Critical Accounting Policies and Estimates</u>](#critical_accounting_policies_estimates) | 57 |
|  | [<u>Liquidity and Capital Resources</u>](#liquidity_capital_resources) | 59 |
|  | [<u>Overall Liquidity</u>](#overall_liquidity) | 59 |
|  | [<u>Review of Consolidated Cash Flow Statement</u>](#review_consolidated_cash_flow_statement) | 60 |
|  | [<u>Capital Resources</u>](#capital_resources) | 61 |
|  | [<u>Utility Capital Expenditures</u>](#utility_capital_expenditures) | 63 |
|  | [<u>Non-Regulated Investments and Capital Expenditures</u>](#nonregulated_investments_capital_expendi) | 64 |
|  | [<u>Pension Plan</u>](#pension_plan) | 64 |
|  | [<u>Credit Ratings</u>](#credit_ratings) | 64 |
|  | [<u>Dividends</u>](#dividends) | 65 |
|  | [<u>Competition</u>](#competition) | 65 |
|  | [<u>Environmental Issues and Other Contingencies</u>](#environmental_issues_and_contingencies) | 66 |
|  | [<u>Colstrip</u>](#colstrip) | 71 |
|  | [<u>Enterprise Risk Management</u>](#enterprise_risk_management) | 72 |
| 7A. | [<u>Quantitative and Qualitative Disclosures about Market Risk</u>](#item_7a_quantitative_qualitative_disclos) | 78 |
| 8. | [<u>Financial Statements and Supplementary Data</u>](#item_8_financial_statements_supplementar) | 78 |
|  | [<u>Report of Independent Registered Public Accounting Firm</u>](#report_independent_registered_public_acc)<u>(PCAOB ID No.</u> 34<u>)</u> | 79 |
|  | [<u>Financial Statements</u>](#financial_statements) | 81 |
|  | [<u>Consolidated Statements of Income</u>](#consolidated_statements_income) | 81 |
|  | [<u>Consolidated Statements of Comprehensive Income</u>](#consolidated_statements_comprehensive_in) | 82 |
|  | [<u>Consolidated Balance Sheets</u>](#consolidated_balance_sheets) | 83 |
|  | [<u>Consolidated Statements of Cash Flows</u>](#consolidated_statements_cash_flows) | 84 |
|  | [<u>Consolidated Statements of Equity</u>](#consolidated_statements_equity) | 86 |
|  | [<u>Notes to Consolidated Financial Statements</u>](#notes_to_consolidated_financial_statemen) | 87 |
|  | [<u>Note 1. Summary of Significant Accounting Policies</u>](#note_1_summary_significant_accounting_po) | 87 |
|  | [<u>Note 2. New Accounting Standards</u>](#note_2_new_accounting_standards) | 93 |
|  | [<u>Note 3. Balance Sheet Components</u>](#note_3_balance_sheet_components) | 94 |
|  | [<u>Note 4. Revenue</u>](#note_4_revenue) | 95 |
|  | [<u>Note 5. Leases</u>](#note_5_leases) | 99 |
|  | [<u>Note 6. Variable Interest Entities</u>](#note_6_variable_interest_entities) | 102 |
|  | [<u>Note 7. Equity Investments</u>](#note_7_equity_investments) | 102 |
|  | [<u>Note 8. Derivatives and Risk Management</u>](#note_7_derivatives_risk_management) | 103 |
|  | [<u>Note 9. Jointly Owned Electric Facilities</u>](#note_8_jointly_owned_electric_facilities) | 106 |
|  | [<u>Note 10. Property, Plant and Equipment</u>](#note_9_property_plant_equipment) | 107 |
|  | [<u>Note 11. Asset Retirement Obligations</u>](#note_10_asset_retirement_obligations) | 107 |
|  | [<u>Note 12. Pension Plans and Other Postretirement Benefit Plans</u>](#note_11_pension_plans_or_postretirement_) | 108 |
|  | [<u>Note 13. Accounting for Income Taxes</u>](#note_12_accounting_for_income_taxes) | 113 |
|  | [<u>Note 14. Energy Purchase Contracts</u>](#note_13_energy_purchase_contracts) | 116 |

---

ii

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***AVISTA CORPORATION***

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| | | |
|:---|:---|:---|
|  | [<u>Note 15. Short-Term Borrowings</u>](#note_14_committed_lines_credit) | 117 |
|  | [<u>Note 16. Long-Term Debt</u>](#note_15_longterm_debt) | 118 |
|  | [<u>Note 17. Long-Term Debt to Affiliated Trusts</u>](#note_16_longterm_debt_to_affiliated_trus) | 119 |
|  | [<u>Note 18. Fair Value</u>](#note_17_fair_value) | 120 |
|  | [<u>Note 19. Common Stock</u>](#note_18_common_stock) | 124 |
|  | [<u>Note 20. Accumulated Other Comprehensive Loss</u>](#note_19_accumulated_or_comprehensive_los) | 124 |
|  | [<u>Note 21. Earnings per Common Share</u>](#note_20_earnings_per_common_share_attrib) | 125 |
|  | [<u>Note 22. Commitments and Contingencies</u>](#note_21_commitments_contingencies) | 125 |
|  | [<u>Note 23. Regulatory Matters</u>](#note_22_regulatory_matters) | 129 |
|  | [<u>Note 24. Information by Business Segments</u>](#note_23_information_by_business_segments) | 133 |
| 9. | [<u>Changes in and Disagreements with Accountants on Accounting and Financial Disclosure</u>](#item_9_changes_in_disagreements_with_acc) | \*135 |
| 9A. | [<u>Controls and Procedures</u>](#item_9a_controls_procedures) | 135 |
| 9B. | [<u>Other Information</u>](#item_9b_or_information) | 137 |
| 9C. | [<u>Disclosure Regarding Foreign Jurisdictions that Prevent Inspections</u>](#item_9c_foreign_jurisdictions) | 137 |
|  | Part III |  |
| 10. | [<u>Directors, Executive Officers and Corporate Governance</u>](#item_10_directors_executive_ficers_corpo) | 138 |
| 11. | [<u>Executive Compensation</u>](#item_11_executive_compensation) | 139 |
| 12. | [<u>Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters</u>](#item_12_security_ownership_certain_benef) | 139 |
| 13. | [<u>Certain Relationships and Related Transactions, and Director Independence</u>](#item_13_certain_relationships_related_tr) | 140 |
| 14. | [<u>Principal Accounting Fees and Services</u>](#item_14_principal_accounting_fees_servic) | 140 |
|  | Part IV |  |
| 15. | [<u>Exhibits, Financial Statement Schedules</u>](#item_15_exhibits_financial_statement_sch) | 141 |
|  | [<u>Exhibit Index</u>](#exhibit_index) | 142 |
|  | [<u>Signatures</u>](#signatures) | 148 |

---

\* = not an applicable item in the 2025 calendar year for Avista Corp.

iii

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***AVISTA CORPORATION***

ACRONYMS AND TERMS

(The following acronyms and terms are found in multiple locations within the document)

---

| | |
|:---|:---|
| <u>Acronym/Term</u> | <u>Meaning</u> |
| aMW | Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time |
| AEL&P | Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska |
| AERC | Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska |
| AFUDC | Allowance for Funds Used During Construction, represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period |
| ASC | Accounting Standards Codification |
| Avista Capital | Parent company to the Company's non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. |
| Avista Corp. | Avista Corporation, the Company |
| Avista Utilities | Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in Washington, Idaho, Oregon and Montana |
| BPA | Bonneville Power Administration |
| Capacity | The rate at which a particular generating source is capable of producing energy, measured in KW or MW |
| Cabinet Gorge | The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho |
| CCA | Climate Commitment Act, Washington |
| CCRs | Coal Combustion Residuals, also termed coal combustion byproducts or coal ash |
| CEIP | Clean Energy Implementation Plan, Washington |
| CETA | Clean Energy Transformation Act, Washington |
| CPP | Climate Protection Program, Oregon |
| Colstrip | The coal-fired Colstrip Generating Plant in southeastern Montana |
| Cooling degree days | The measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day is above 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures) |
| Coyote Springs 2 | The natural gas-fired combined-cycle Coyote Springs 2 Generating Plant located near Boardman, Oregon |
| CT | Combustion turbine |
| Deadband or ERM deadband | The first $4 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington |
| Ecology | The Washington State Department of Ecology |
| EIM | Energy Imbalance Market |
| Energy | The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms. |
| EPA | Environmental Protection Agency |
| ERM | The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington |
| FCA | Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho. |

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***AVISTA CORPORATION***

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| | |
|:---|:---|
| FERC | Federal Energy Regulatory Commission |
| FPA | Federal Power Act |
| GAAP | Generally Accepted Accounting Principles |
| GHG | Greenhouse gas |
| GS | Generating station |
| Heating degree days | The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day is below 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures) |
| IPUC | Idaho Public Utilities Commission |
| IRP | Integrated Resource Plan |
| Jackson Prairie | Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington |
| kV | Kilovolt (1000 volts): a measure of capacity on transmission lines |
| KW, KWh | Kilowatt (1000 watts): a measure of generating output or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced |
| Lancaster Plant | A natural gas-fired combined cycle combustion turbine plant located in Idaho |
| mmBTU | One million British Thermal Units, a thermal unit of measurement for natural gas |
| MPSC | Public Service Commission of the State of Montana |
| MW, MWh | Megawatt: 1000 KW. Megawatt-hour: 1000 KWh |
| MYRP | Multi-year rate plan |
| NERC | North American Electricity Reliability Corporation |
| NorthWestern | NorthWestern Corporation |
| Noxon Rapids | The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana |
| OPUC | The Public Utility Commission of Oregon |
| PCA | The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho |
| PGA | Purchased Gas Adjustment |
| PPA | Power Purchase Agreement |
| PUD | Public Utility District |
| RCA | The Regulatory Commission of Alaska |
| REC | Renewable energy credit |
| ROE | Return on equity |
| ROR | Rate of return on rate base |
| ROU | Right-of-use lease asset |
| SEC | U.S. Securities and Exchange Commission |
| Talen | Talen Montana, LLC, an indirect subsidiary of Talen Energy Corporation. |
| Therm | Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy) |
| WUTC | Washington Utilities and Transportation Commission |

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***AVISTA CORPORATION***

**<u>Forward-Looki</u><u>ng Statements</u>**

From time to time, we make forward-looking statements such as statements regarding projected or future:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•financial performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•cash flows;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•capital expenditures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•dividends;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•capital structure;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•other financial items;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•strategic goals and objectives;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•business environment; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•plans for operations.

These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those identified by the use of words that include "will," "may," "could," "should," "intends," "plans," "aspires," "assumes," "targets," "seeks," "anticipates," "estimates," "expects," "forecasts," "projects," "predicts," and similar expressions.

Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks, uncertainties and other factors. Most of these factors are beyond our control. Any of these factors may have a significant effect on our operations, results of operations, financial condition or cash flows, and could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

***Utility Regulatory Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return, including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, commodity costs, the ordering of refunds to customers and discretion over allowed return on investment;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the loss of regulatory accounting treatment, which could require the write-off of regulatory assets and the loss of regulatory deferral and recovery mechanisms;

***Operational Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•wildfires ignited, or allegedly ignited, by our equipment or facilities could cause significant loss of life and property or result in liability for resulting fire suppression costs and/or damages, thereby causing serious operational, reputational and financial harm;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, floods, extreme temperature events, snow and ice storms that could disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•political unrest and/or conflicts between foreign nation-states, which could disrupt the global, national and local economy, result in increases in operating and capital costs, impact energy commodity prices or our ability to access energy resources, create disruption in supply chains, disrupt, weaken or create volatility in capital markets, and

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***AVISTA CORPORATION***

increase cyber and physical security risks. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•explosions, fires, accidents, mechanical breakdowns or other incidents that could impair assets and may disrupt operations of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power or incur costs to repair our facilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•interruptions in the delivery of natural gas by our suppliers, including physical problems with pipelines themselves, can disrupt our service of natural gas to our customers and/or impair our ability to operate gas-fired electric generating facilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•explosions, fires, accidents or other incidents arising from or allegedly arising from our operations that could cause injuries to the public or property damage;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•dam failure at a company-owned hydroelectric facility;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•blackouts or disruptions of interconnected transmission systems (the regional power grid);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•terrorist attacks, cyberattacks or other malicious acts that could disrupt or cause damage to our utility assets or to the national or regional economy in general, including effects of terrorism, cyberattacks, ransomware, or vandalism that damage or disrupt information technology systems;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•pandemics, which could disrupt our business, as well as the global, national and local economy, resulting in a decline in customer demand, deterioration in the creditworthiness of our customers, increases in operating and capital costs, workforce shortages, losses or disruptions in our workforce due to vaccine mandates, delays in capital projects, disruption in supply chains, and disruption, weakness and volatility in capital markets. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•work-force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in the availability and price of purchased power, fuel and natural gas, as well as transmission capacity;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing health care costs and cost of health insurance provided to our employees and retirees;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing operating costs, including effects of inflationary pressures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuilding atop natural gas distribution lines;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the loss of key suppliers for materials or services or other disruptions to the supply chain;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•adverse impacts to our Alaska electric utility (AEL&P) that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to other electrical grids and the availability or cost of replacement power (diesel);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changing river or reservoir regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;

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***AVISTA CORPORATION***

***Climate Change Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing frequency and intensity of severe weather or natural disasters resulting from climate change that could disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities, including impacts resulting from climate change;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in the long-term climate and weather could materially affect, among other things, customer demand, the volume and timing of streamflows required for hydroelectric generation, costs of generation, transmission and distribution. Increased or new risks may arise from severe weather or natural disasters, including wildfires as well as their increased occurrence and intensity related to changes in climate;

***Cybersecurity Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•cyberattacks on the operating systems used in the operation of our electric generation, transmission and distribution facilities and our natural gas distribution facilities, and cyberattacks on such systems of other energy companies with which we are interconnected, which could damage or destroy facilities or systems or disrupt operations for extended periods of time and result in the incurrence of liabilities and costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•cyberattacks on the administrative systems used in the administration of our business, including customer billing and customer service, accounting, communications, compliance and other administrative functions, and cyberattacks on such systems of our vendors and other companies with which we do business, resulting in the disruption of business operations, the release of private information and the incurrence of liabilities and costs;

***Technology Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cybersecurity risks and other new risks inherent in the use, by either us or our counterparties, of new technologies in the developmental stage including, without limitation, generative artificial intelligence;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in the use, perception, or regulation of generative artificial intelligence technologies, which could limit our ability to utilize such technology, create risk of enhanced regulatory scrutiny, generate uncertainty around intellectual property ownership, licensing or use, or which could otherwise result in risk of damage to our business, reputation or financial results;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in costs that impede our ability to implement new information technology systems or to operate and maintain current production technology;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;

***Strategic Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•growth or decline of our customer base due to new uses for our services or decline in existing services, including, but not limited to, the effect of the trend toward distributed generation at customer sites;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and result in litigation or a decline in our common stock price;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in our strategic business plans, which could be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or may be sold back to the utility, and alternative energy suppliers and delivery arrangements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•non-regulated activities may increase earnings volatility and result in investment losses;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the risk of municipalization or other forms of service territory reduction;

***External Mandates Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in environmental laws, regulations, decisions and policies, including, but not limited to, regulatory responses to concerns regarding climate change, efforts to restore anadromous fish in areas currently blocked by dams, more stringent requirements related to air quality, water quality and waste management, present and potential environmental remediation costs and our compliance with these matters;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources, prohibitions or restrictions on new or existing services, or restrictions on greenhouse gas emissions to mitigate concerns over climate changes, including future limitations on the usage and distribution of natural gas;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•restrictions or changes in government grant programs and/or availability of other public funding used for capital projects;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt fossil fuel-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•failure to identify changes in legislation, taxation and regulatory issues that could be detrimental or beneficial to our overall business;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing costs due to potential tariffs applied to energy commodities and/or equipment and materials;

***Financial Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•our ability to obtain financing through the issuance of debt and/or equity securities and access to our funds held with financial institutions, which could be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in interest rates that affect borrowing costs, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•volatility in energy commodity markets that affects our ability to effectively hedge energy commodity risks, including cash flow impacts and requirements for collateral;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•volatility in the carbon emissions allowances market that could result in increased compliance costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which could affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the outcome of legal proceedings and other contingencies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•economic conditions in our service areas, including the economy's effects on customer demand for utility services;

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•economic conditions nationally may affect the valuation of our unregulated portfolio companies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•declining electricity demand related to customer energy efficiency, conservation measures and/or increased distributed generation and declining natural gas demand related to customer energy efficiency, conservation measures and/or increased electrification;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•industry and geographic concentrations which could increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•deterioration in the creditworthiness of our customers;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•activist shareholders may result in additional costs and resources required in response to activist actions;

***Energy Commodity Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that could affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk from such transactions, and the market value of derivative assets and liabilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•default or nonperformance on the part of parties from whom we purchase and/or sell capacity or energy;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•explosions, fires, accidents, pipeline ruptures or other incidents that could limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;

***Compliance Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in laws, regulations, decisions and policies at the federal, state or local levels, which could materially impact both our electric and gas operations and costs of operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels;

***Resource Adequacy Risk***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the ability to source and deliver adequate energy to meet customer demand in periods of high demand or unplanned events; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the potential effects of regional wholesale market strains, including during extreme weather events.

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

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***AVISTA CORPORATION***

**<u>Available I</u><u>nformation</u>**

We file annual, quarterly and current reports and proxy statements with the SEC. The SEC maintains a website that contains these documents at www.sec.gov. We make annual, quarterly and current reports and proxy statements available on our website, https://investor.avistacorp.com, as soon as practicable after electronically filing these documents with the SEC. Except for SEC filings or portions thereof specifically referred to in this report, information contained on these websites is not part of this report.

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***AVISTA CORPORATION***

**PART I**

**<u>ITEM 1. B</u><u>USINESS</u>**

**<u>COMPANY</u> <u>OVERVIEW</u>**

Avista Corp., incorporated in the territory of Washington in 1889, is primarily an electric and natural gas utility with certain other business ventures. Our corporate headquarters is in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. Through our subsidiary AEL&P, we also provide electric utility services in Juneau, Alaska.

As of December 31, 2025, we have two reportable business segments as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•**Avista Utilities** – an operating division of Avista Corp., comprising the regulated utility operations in Washington, Idaho, Oregon and Montana. 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. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and its load-serving obligation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•**AEL&P** – a regulated utility providing electric services in Juneau, Alaska that is a wholly-owned subsidiary and the primary operating subsidiary of AERC.

We have other businesses, including venture fund investments, real estate investments, as well as certain other investments made by Avista Capital, which is a direct, wholly-owned subsidiary of Avista Corp. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp.

Total Avista Corp. shareholders' equity was $2.7 billion as of December 31, 2025, which includes a $126 million investment in Avista Capital and a $129 million investment in AERC.

See "Note 24 of the Notes to Consolidated Financial Statements" for information with respect to the operating performance of each business segment (and other subsidiaries).

<u>Human Capital</u> 

On December 31, 2025, Avista Utilities employed 1,929 individuals with bargaining unit employees comprising 36 percent of our overall workforce.

Our approach to people is a critical strategy to inspire engaged and thriving employees by empowering a high-performing organization where employees are valued, respected and have opportunities to grow. Among other things, this strategy supports hiring talented people and equipping them with capabilities, tools and a culture that empowers them to pursue great ideas. Such ideas engage the imagination, stretch us all as we continue to provide exemplary and cost-effective service to our customers. Focus areas for this strategy strive to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•improve employee engagement, belonging, equity, attraction and retention while building a sense of community and purpose,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•support safety and well-being through innovative programs, best practices, tools, and technology, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•expand innovation disciplines, capabilities, and mindsets with cross-departmental interactions and external networks to build the utility of the future.

The following is an overview of some of our key human capital initiatives intended to inspire engaged and thriving employees and other stakeholders, such as our customers and business partners.

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***AVISTA CORPORATION***

*Employee Attraction, Development and Retention*

We strive to hire and retain talented people who are innovative and skilled so we can continue to provide safe, reliable and affordable service to our customers and advance the Company at the same time. We are focused on innovative recruiting and educational outreach to organizations and schools to create greater awareness of the variety of career opportunities available in our industry and in the Company. We continue to think creatively about how we connect with our communities regarding employment opportunities, with a goal of attracting talented individuals who can help advance the Company's objectives.

All of our collective bargaining agreements are with local chapters of the International Brotherhood of Electrical Workers (IBEW). In 2025, the Company successfully negotiated a 4-year agreement for our largest collective bargaining agreement. In 2026, we have one agreement expiring and currently under negotiation for a successor contract, along with negotiations for a newly-organized bargaining unit. The partnership with IBEW is key to a holistic approach to employee attraction, engagement, and retention.

Continuous learning plays a large part in fostering collaboration and innovation among our employees and is pervasive throughout the Company. Development opportunities are created to prepare our employees at all levels to continue building their skills, knowledge and experience to perform today and in the future. Keeping our workforce equipped to succeed is imperative to meet the emerging challenges that lie ahead. We develop training that is relevant, necessary and in demand for our organization. Training is delivered through instructor-led courses, self-service topics, computer-based learning modules, and field-based, hands-on workshop models covering the range of our operations. Training programs include craft apprenticeship programs, engineering development programs, leadership development, communication skills, cross-functional learning and other topics. We also provide opportunities for our employees to attend industry events and certification programs, courses or programs offered through energy-related organizations such as the Western Energy Institute, the American Gas Association and the Edison Electric Institute, as well as through our local colleges and universities.

Competitive pay and benefits, or total rewards, are a key component of our strategy to attract and retain talented employees. The Company is committed to equitable and market-competitive compensation and has well-established practices to create competitive offers, reward performance, and support employee retention. The Company regularly monitors the benefits market and manages benefit costs through a comprehensive program that supports our employees' physical, mental, and financial well-being.

In 2025, we conducted our biennial employee experience survey. The purpose of this survey is to provide employees at all levels of the organization with an opportunity to confidentially share their perspectives about their experiences working at Avista Corp., our workplace culture, and topics such as autonomy, enablement, growth opportunities, connection, leadership, safety, engagement and belonging, etc. The Company conducted many listening sessions to learn more about our employee needs and gain a better understanding of what actions might be taken to improve the employee experience.

*Workplace Safety*

Safety and well-being are an essential part of our Company's mission and a key strategy to support our employees through innovative programs, best practices, tools and technology. A variety of programs and initiatives are in place to help employees complete their work safely through heightened vigilance, hazard recognition, defensive strategies, lessons learned, human and organizational performance and other tools intended to strengthen resilience in varying and unpredictable conditions. We work with our employees to reinforce personal responsibility regarding safety and health, and to implement measures to create and maintain a safe work environment.

**<u>AVISTA U</u><u>TILITIES</u>**

**General**

At the end of 2025, Avista Utilities supplied retail electric service to approximately 429,000 customers and retail natural gas service to approximately 386,000 customers across its service territory. Avista Utilities' service territory covers 34,000 square miles with a population of 1.5 million.

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***AVISTA CORPORATION***

**Electric Operations**

**<u>General</u>** 

Avista Utilities generates, transmits and distributes electricity, serving electric customers in eastern Washington and northern Idaho and a small number of customers in Montana.

Avista Utilities generates electricity from facilities that we own and purchases capacity, energy and fuel for generation under long-term and short-term contracts to meet customer load obligations. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below.

As part of Avista Utilities' resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture 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, fuel and fuel transportation. Such transactions are part of the process of matching available resources with load obligations and hedging a portion of the related financial risks. To implement this process, we make continuing projections of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data, contract terms, and emerging trends and climate modeling results,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of snowpack and streamflows, availability of generating units, historic and forward market information, contract terms and our experience, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•carbon allowance costs and other emission fees associated with emission reduction legislation and policy.

Based on these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative contracts to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. The process of resource optimization involves scheduling and dispatching available resources as well as the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•purchasing fuel for generation,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•when economical, selling fuel and substituting wholesale electric purchases, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•other wholesale transactions to capture the value of generating resources, transmission contract rights and fuel delivery (transport) capacity contracts.

This optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments, and the terms range from intra-hour up to multiple years.

Avista Utilities' generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We acquire both long-term and short-term transmission capacity to facilitate our energy and capacity transactions. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana.

**<u>Peak Electric Re</u><u>quirements</u>**

Avista Utilities' peak electric native load requirement for 2025 was 1,837 MW, which occurred on September 2, 2025. In 2024, our peak electric native load was 1,869 MW, which occurred during the winter, and in 2023, it was 1,809 MW, which occurred during the summer.

**<u>Electric</u> <u>Resources</u>**

Avista Utilities has a diverse electric resource mix of Company-owned and contracted hydroelectric, thermal, wind and solar generation facilities, and other contracts for power purchases and exchanges. As of December 31, 2025, Avista Utilities' electric

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***AVISTA CORPORATION***

generation resource mix (including contracts for power purchases) was approximately 48 percent hydroelectric, 37 percent thermal and 15 percent other renewables. On January 1, 2026, the Company transferred its ownership in Colstrip to NorthWestern, resulting in a generation resource mix (including contracts for power purchases) of approximately 53 percent hydroelectric, 32 percent thermal and 15 percent other renewables. See "Item 2. Properties" for detailed information on Company-owned generating facilities and a detailed list of our PPAs.

**<u>Hydroelectric Resources</u>** 

Avista Utilities owns and operates Noxon Rapids and Cabinet Gorge on the Clark Fork River and six smaller hydroelectric projects on the Spokane River. Hydroelectric generation is typically our lowest cost source per MWh of electric energy and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts (including those with certain PUDs in the state of Washington and Columbia Basin Hydropower). Normal and actual annual hydroelectric generation increased in 2025 as a result of increased output received from additional capacity under one of our PPA contracts. Our estimate of normal annual hydroelectric generation for 2026 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 648.3 aMW (or 5.68 million MWhs).

See "Item 2. Properties - Avista Utilities" for the present generating capabilities of the above hydroelectric resources.

The following graph shows Avista Utilities' hydroelectric generation (in thousands of MWhs) during the year ended December 31:

![img175228948_0.jpg](img175228948_0.jpg)

(1)Normal hydroelectric generation is determined by reference to the effect of upstream dam regulation on median natural water flow. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow reflects water flow changes from upstream dams due to releasing or holding back water. The calculation of

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normal varies annually due to the timing of upstream dam regulation throughout the year, as well as changes in PUD contracts.

**<u>Thermal Resources</u>** 

Avista Utilities owns the following thermal generating resources:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the combined cycle natural gas-fired CT, known as Coyote Springs 2, located near Boardman, Oregon,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a wood waste-fired boiler generating facility known as the Kettle Falls GS in northeastern Washington,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a two-unit natural gas-fired CT generating facility in northeastern Spokane (Northeast CT),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•two small natural gas-fired generating facilities (Boulder Park GS and Kettle Falls CT).

Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under a combination of term contracts and spot market purchases, including transportation agreements with bilateral renewal rights.

The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.

The Northeast CT, Rathdrum CT, Boulder Park GS and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

We previously held a 15 percent interest in Units 3 and 4 of Colstrip, a coal-fired generating facility located in southeastern Montana. We transferred our ownership interest to NorthWestern on January 1, 2026. See "Item 7. Management's Discussion and Analysis – Colstrip" and "Note 22 of the Notes to Consolidated Financial Statements" for discussion regarding environmental and other issues surrounding Colstrip.

In addition to the resources we own listed above, we have a PPA for the output from the Lancaster Plant through December 31, 2041. The Lancaster Plant is a 270 MW natural gas-fired combined cycle combustion turbine plant located in northern Idaho, owned by an unrelated third-party. Under the terms of the PPA, we make the dispatch decisions, provide all natural gas fuel and receive all electric energy output. Therefore, we consider the Lancaster Plant to be a baseload resource. See "Note 5 of the Notes to Consolidated Financial Statements" for further discussion of this PPA.

See "Natural Gas Operations - Natural Gas Supply" for information regarding our supply of natural gas for both fuel and delivery to natural gas customers.

See "Item 2. Properties - Avista Utilities" for the present generating capabilities of the above thermal resources.

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***AVISTA CORPORATION***

The following graph shows Avista Utilities' thermal generation (in thousands of MWhs) during the year ended December 31:

![img175228948_1.jpg](img175228948_1.jpg)

**<u>Wind Resources</u>** 

We have exclusive rights to the capacity of Palouse Wind, a wind generation project developed, owned and managed by an unrelated third-party and located in Whitman County, Washington. Under the PPA, we purchase the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. We have an annual option to purchase the wind project, which we have not exercised. The purchase price is a fixed price per KW of in-service capacity with a fixed decline in the price per KW over the remaining term of the PPA.

We have exclusive rights to the capacity of Rattlesnake Flat Wind project developed, owned and managed by an unrelated third party and located in Adams County, Washington. We purchase the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement.

See "Item 2. Properties" for a detailed list of our PPAs.

**<u>Solar Resources</u>** 

We have exclusive rights to the capacity of the Lind Solar Farm, a solar generation project developed, owned and managed by an unrelated third-party and located in Lind, Washington. Under a PPA, we purchase the power and renewable attributes produced by the project at a fixed price per MWh.

See "Item 2. Properties" for a detailed list of our PPAs.

**<u>Other Purchases, Exchanges and Sales</u>** 

In addition to the resources described above, we purchase and sell power under various long-term contracts, and we enter into short-term purchases and sales. Further, pursuant to The Public Utility Regulatory Policies Act of 1978, as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the WUTC and the IPUC.

See "Avista Utilities Electric Operating Statistics – Electric Operations" below for annual quantities of purchased power, wholesale power sales and power from exchanges in 2025, 2024 and 2023. See "Electric Operations" above for additional

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information on the use of wholesale purchases and sales as part of our resource optimization process and see "Future Resource Needs" below for the magnitude of these power purchase and sales contracts in future periods.

**<u>Regional Capacity Issues</u>**

The northwest region is experiencing increased load growth, more frequent extreme weather events, and a transition to more variable energy resources. Both the region's electric and natural gas delivery systems are also reaching full utilization during peak load conditions. Purchases of capacity and energy at any time are dependent upon the availability of excess capacity in the west region at that time. Many coal-fired electric generating stations throughout the western United States are scheduled for retirement in the next several years. Depending upon a variety of factors, these retirements could have an impact upon the availability and price of purchased power in, and the dynamics of, the market in which we conduct our wholesale purchases and sales. After December 31, 2025, we are prohibited by the Clean Energy Transformation Act (CETA) from using energy produced by coal-fired plants to serve our retail customers in Washington (with some exceptions for coal generated short-term purchases), and we transferred our interest in Colstrip to NorthWestern on January 1, 2026. To the extent necessary, we will obtain energy produced by other regional resources. See "Item 7. Management's Discussion and Analysis – Environmental Matters and Contingencies – Climate Change – Washington Legislation and Regulatory Actions – Clean Energy Transformation Act" and "Colstrip."

In addition to the retirement of coal-fired generating stations, some hydroelectric and other generation plants in the region are being considered for possible closure due to environmental and other concerns. The reduction of regional generating capacity will have to be offset by the addition of new generating resources and energy storage facilities.

**<u>Hydroelectri</u><u>c Licenses</u>**

Avista Corp. is a licensee under the FPA as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project (Little Falls), our other seven hydroelectric plants are regulated by the FERC through two project licenses.

Cabinet Gorge and Noxon Rapids are under one 45-year FERC license expiring in 2046. This license embodies a settlement agreement relating to project operations and resource protection and mitigation efforts over the license term.

Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one 50-year FERC license expiring in 2059 and are referred to collectively as the Spokane River Project. The license includes numerous natural and cultural resource protection measures that are subject to ongoing regulatory interpretation. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. It is the subject of a 50-year agreement with the Spokane Tribe, expiring in 2044.

The FERC grants hydroelectric licenses, and relicenses, only after a multi-year process involving public hearings and input from multiple federal, state and local government agencies, tribes, non-governmental organizations, private landowners and other stakeholders. The FERC must find that the proposed project will be best adapted to a comprehensive plan for the waterway, taking into account the needs of power development, fish and wildlife, irrigation, flood control, water supply, recreation and other competing uses, and licenses (and relicenses) must be conditioned on appropriate protection, mitigation and enhancement measures.

Generally, upon the expiration of a license, (1) the FERC could grant a new licenses upon terms determined at that time, (2) the United States could take over the project, or the FERC could issue a new license to a new licensee, upon payment to the licensee of the lesser of the licensee's "net investment" in, or the "fair value" of, the project, plus severance damages, or (3) under the FERC's interpretation of the FPA, the FERC could order the decommissioning of the project. There is no assurance that any existing license will be renewed upon its expiration or, if renewed, that the renewal would be without significant modifications.

**<u>Future Electric Reso</u><u>urce Needs</u>**

Avista Utilities has operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies because of the factors

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***AVISTA CORPORATION***

that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,149 aMW in 2025, 1,117 aMW in 2024 and 1,115 aMW in 2023.

The following graph shows our forecasted average annual energy requirements (in aMWs) and our available resources (in MWs) for 2026 through 2029:

![img175228948_2.jpg](img175228948_2.jpg)

(1)Forecast system load does not include the addition of large load customers, which could increase system load and require additional resources, as contemplated in our 2025 Electric IRP.

(2)Estimated available energy production from Company-owned Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT resources.

(3)Other contracts for power purchases include power purchase agreements for solar and wind energy.

(4)The forecast assumes near normal hydroelectric generation.

(5)Includes the Lancaster Plant PPA. Excludes Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT, as these are considered peaking facilities and are generally not used to meet our base load requirements.

We are required to file an Integrated Resource Plan (IRP) or Washington Progress Report with the WUTC and IPUC every two years. The WUTC and IPUC review the IRP and give the public the opportunity to comment. The WUTC and IPUC do not approve or disapprove of the content in the IRP; rather, they acknowledge that the IRP was prepared in accordance with applicable standards if that is the case. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

In December 2024, we filed our 2025 Electric IRP with the WUTC and the IPUC.

Highlights of the 2025 Electric IRP include the following expectations and/or assumptions:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Due to customer growth and loss of capacity resources, the Company will need to acquire additional electricity generation to serve peak loads. Our preferred resource strategy calls for the addition of approximately 490 MW of generating capacity by 2030 and a total of approximately 950 MW to be added through 2035.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Customer energy demand is expected to grow an average of 0.9 percent per year over the next 20 years and an average of winter peak demand by 1.12 percent per year over the next 20 years.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•The 66 MW Northeast CT will be retired in 2030.

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Energy efficiency reduces future demand growth by 32 percent over 20 years.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Demand response programs reduce peak demand by up to 4 percent.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Identifies the proposed North Plains Connector transmission line as a preferred resource alternative along with other transmission upgrades in the Inland Northwest.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We are projected to exceed CETA's requirements to be greenhouse gas neutral with Washington's electric supply by 2030.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Meeting CETA's 2045 targets will require significant energy transformation including maintaining our existing hydroelectric system and acquiring new energy resources which could include using hydrogen-based fuels, wind, solar and nuclear, and will include long-term energy storage.

*2025 Request for Proposal (RFP)*

In May 2025, we issued an RFP requesting bids for up to 425 MW of capacity resources to meet modeled load growth needs and anticipated new large loads. See further information on the RFP within "Item 7. Management's Discussion and Analysis – Executive Overview".

Additional generating resources required will either be owned by us or be owned by other parties who will sell us the capacity and energy under PPAs. The decision as to ownership will be made as to each project at the appropriate time and will depend on, among other things, the type of project and the related economics, including tax and ratemaking treatment.

We are subject to the Washington State Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective energy efficiency measures. Future generation resource decisions will be affected by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.

See "Item 7. Management's Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies" for information related to existing and proposed laws and regulations that impact our resource availability.

**<u>Electric Clean Energy Goals</u>**

We have an aspirational goal to serve our customers with 100 percent clean electricity by 2045. To help achieve this goal and add to our clean electricity portfolio, we have implemented renewable energy projects, including entering into various PPAs for solar, wind and hydroelectric resources. These resources are in addition to our existing clean hydroelectric generation, biomass generation, and additional wind and solar projects.

To achieve our clean energy goals, we expect energy storage and other technologies, which are either not currently available or are not cost-effective under the lowest reasonable cost regulatory standard, will advance to allow us to meet our goals while maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from regulatory agencies. See the discussion under "Electric Resources" for more information on our existing clean electricity sources and efforts to achieve these goals. See "Item 7. Management's Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies" for further discussion on clean energy, including applicable regulations.

**<u>Wildfire Resiliency Plan</u>**

We have a wildfire resiliency plan focused on four primary areas: transmission and distribution system hardening, enhanced vegetation management, situational awareness, and operations and response.

Grid hardening involves investing in electric infrastructure to reduce spark-ignition outage events and to protect critical assets from the impact of wildfires at the distribution level, including replacing wood crossarms with fiberglass, replacing small wire, adding protective devices, undergrounding, and more. We also invest at the transmission level, replacing wood poles with steel or wrapping them with a fire-resistant protective cover in high fire risk areas. We are also developing an enhanced grid hardening program which may involve undergrounding high fire risk sections of the distribution system.

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***AVISTA CORPORATION***

Enhanced vegetation management involves risk tree inspection in non-urban areas, the addition of digital data collection, fuel reduction partnerships, and safe tree programs. We also had a third-party study the effectiveness of this program and the preferred inspection cycle.

Situational awareness is designed to help us identify and respond to risk, including the fire risk maps, a fire weather dashboard, and installation of wildfire identification cameras and localized weather stations.

Operations and response measures are focused on automating our system to allow remote control and operation of key equipment including fire safety mode automation devices as well as fire safety mode and Public Safety Power Shutoff operations during critical fire weather, as well as expedited response agreements and other partnerships and relationships with external agencies such as first responders.

In 2025, we spent $36 million in capital and $15 million in operating expenses on wildfire resiliency efforts. In 2026, we expect to spend approximately $45 million in capital and $20 million in operating expenses related to the program. The IPUC and WUTC approved deferral and recovery of certain operating expenses of the wildfire resiliency plan, and we will continue to seek recovery of costs in future rate filings.

*Wildfire Mitigation Legislation*

In April 2025, Idaho enacted the Wildfire Standard of Care Act, which became effective in July 2025. This act requires public utilities in Idaho to prepare and submit to the IPUC for approval a wildfire mitigation plan on an annual basis. Once approved, the plan establishes the utility's duty to stakeholders to mitigate wildfire risk. In September 2025, the IPUC issued an order establishing a filing schedule. We filed our initial wildfire mitigation plan in December 2025. The plan focuses on grid hardening, vegetation management, situational awareness and operations and emergency response. The IPUC has up to six months to review and approve.

Also in April 2025, Washington enacted House Bill 1522, which became effective in July 2025. This bill requires electric utilities to file a wildfire mitigation plan with the WUTC, which must be approved or rejected within 60 days of submission. We, along with other stakeholders, are currently participating in the rulemaking process related to this legislation.

See "Note 22 of the Notes to Consolidated Financial Statements" for further discussion on wildfire activity and related litigation proceedings.

**Natural Gas Operations**

**<u>General</u>** 

Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon.

Market prices for natural gas, like other commodities, can be volatile. Our natural gas procurement strategy is to provide a reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of forward fixed price purchases, index and spot market purchases, and utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and the procurement of natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years.

Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. Based on these projections, we plan and execute a series of transactions to hedge a portion of our customers' projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years. We also leave a portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets.

As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak

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***AVISTA CORPORATION***

day event. We generally have more pipeline and storage capacity than is needed during periods other than on a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource optimization activities include, but are not limited to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•wholesale market sales of surplus natural gas supplies,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•purchases and sales of natural gas to optimize use of pipeline and storage capacity, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•participation in the transportation capacity release market.

We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and deliver it to the customers' premises. These customers generally pay the same rates as other customers in the same class, without charge for the cost of the natural gas delivered.

Optimization transactions that we engage in throughout the year are included in our annual purchased gas cost adjustment filings with the various commissions and are subject to review for prudence during this process.

**<u>Natural Gas Clean Energy Goals</u>**

We have an aspirational goal for our natural gas operations to be carbon neutral by 2045. Examples of carbon emissions reduction strategies include the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•diversify or transition from conventional fossil fuel natural gas to renewable natural gas, hydrogen, and other renewable biofuels,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•reduce natural gas consumption via conservation, energy efficiency and new technologies, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•purchase carbon offsets as necessary.

See "Item 7. Management's Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies" for further discussion on clean energy, including applicable regulations.

We have several contracts for renewable natural gas to purchase an expected output of approximately 8.6 million therms annually from various projects.

**<u>Natural Gas Supply</u>** 

We purchase natural gas, for both fuel for generation and delivery to natural gas customers, in wholesale markets and are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different pipeline networks. Access to this diverse portfolio of natural gas resources allows for natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources and 75 percent from Canadian sources. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our resource mix to vary.

**<u>Natural Gas Storage</u>** 

Avista Utilities owns a one-third interest in Jackson Prairie, an underground aquifer natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 12 million therms, with a total working natural gas capacity of 256 million therms. Our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project.

We optimize our natural gas storage capacity throughout the year by executing transactions that capture favorable market price spreads. Natural gas buyers identify opportunities to purchase lower cost natural gas in the immediate term to inject into

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***AVISTA CORPORATION***

storage, and then sell the gas in a forward market to be withdrawn later. The reverse of this type of transaction also occurs. These transactions lock in incremental value for customers. Jackson Prairie is also used as a variable peaking resource, and to protect from extreme daily price volatility during cold weather or other events affecting the market.

**<u>Future Gas Resource Needs</u>** 

In March 2025, we filed our 2025 Natural Gas IRP with the WUTC, the IPUC and the OPUC. The IRP outlines a preferred resource portfolio which is designed to meet the forecast for system energy demand and comply with emissions legislation over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

Highlights of the 2025 Natural Gas IRP include the following expectations and/or assumptions:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Customer usage estimates are increasingly difficult to forecast due to the variety of rules and codes passed by Oregon, Washington, and federal administrations. The Washington building codes are assumed to remain in effect. See "Item 7. Management's Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies" for further discussion of Washington building codes, including impacts to our business.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•The IRP focuses on greenhouse gas emissions compliance program constraints of the CCA in Washington and the CPP in Oregon.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•The Oregon preferred resource strategy assumes the utilization of renewable natural gas resources and energy efficiency investments, as well as emissions reductions after 2029 and carbon capture starting in 2035 as the primary tools to meet customer energy needs and comply with the CPP program requirements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•The Washington preferred resource strategy assumes the utilization of conventional natural gas and energy efficiency, along with allowance offsets that are provided by the state or purchased by the Company and emissions reductions to meet the requirements under the CCA.

The state of Idaho currently does not have any greenhouse gas emissions reduction policies, and as such the preferred resource strategy continues to utilize natural gas from existing access to supply basins, and our existing storage.

See "Item 7. Management's Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies" for further discussion of environmental laws, including impacts to our business.

We are required to file a natural gas IRP every two years and we anticipate our next IRP to be filed in 2027.

**Utility Regulation**

**<u>General</u>** 

As a public utility, Avista Corp. is subject to regulation by state utility commissions for retail electric and natural gas rates, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the WUTC, IPUC, OPUC and MPSC. Approval of the issuance of securities is not required from the MPSC. We are subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales.

Since Avista Corp. is a "holding company" (in addition to being itself an operating utility), we are subject to the jurisdiction of the FERC under the Public Utility Holding Company Act of 2005, which imposes certain reporting and record-keeping requirements on Avista Corp. and its subsidiaries. We and our subsidiaries are required to make books and records available to the FERC and the state utility commissions. In addition, upon the request of any jurisdictional state utility commission, the FERC would have the authority to review assignment of costs of non-power goods and administrative services among us and our subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and, in this context, would continue to be able to, among other things, review transactions of an affiliated company.

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a "cost of service"

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basis. Retail rates are designed to provide an opportunity to recover allowable operating expenses and earn a return of and a reasonable return on "rate base." Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred income taxes and other items and subject to possible reduction to the extent that a regulatory commission finds that part of an investment was imprudent. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and write-offs as authorized/ordered by the utility commissions. Our operating expenses and rate base are allocated or directly assigned to five regulatory jurisdictions: electric in Washington and Idaho, and natural gas in Washington, Idaho and Oregon. In general, requests for new retail rates are made based on revenues, operating expenses and net investment for a test year that ended prior to the date of the request, subject to possible adjustments, which differ among the various jurisdictions, designed to reflect the expected revenues, operating expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including, but not limited to, ongoing capital expenditures and unexpected changes in revenues and expenses following the time new retail rates are requested in the rate proceeding (known as "regulatory lag"), the denial by the commission of recovery, or timely recovery, of certain expenses or investment and the limitation by the commission of the authorized return on investment.

Our rates for wholesale electric sales and electric transmission services, as well as certain natural gas transportation services, are based on either "cost of service" principles or market-based rates as set forth by the FERC. See "Notes 1, 13 and 23 of the Notes to Consolidated Financial Statements" for additional information about regulation (including power cost deferrals, purchased gas adjustments and decoupling mechanisms), depreciation and deferred income taxes.

See "Item 7. Management's Discussion and Analysis – Regulatory Matters" for information on general rate cases.

**Federal Laws Related to Wholesale Competition**

Federal law promotes practices that foster competition in the electric wholesale energy market. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.

Public utilities operating under the FPA are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility's power merchant operations, have equal access to the public utility's transmission system. Our compliance with these standards has not had a substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.

See "Item 7. Management's Discussion and Analysis – Competition" for further information, as well as "Note 22 of the Notes to Consolidated Financial Statements" for discussion of a complaint filed with the FERC regarding transmission planning.

**Regional Transmission Planning**

Beginning with FERC Order No. 888 and continuing with subsequent rulemakings and policies, the FERC has encouraged better coordination and operational consistency aimed at capturing efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization or an independent system operator.

We meet our FERC requirements to coordinate transmission planning activities with other regional entities through NorthernGrid. Launched in 2020, NorthernGrid is an association of all major transmission providers throughout the Pacific Northwest and Intermountain West, with facilities in California, Idaho, Montana, Oregon, Utah, Washington and Wyoming. Through our participation in NorthernGrid, we meet the regional transmission planning requirements of FERC Order Nos. 890

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and 1000, and follow-on orders. NorthernGrid and its members also work with other western organizations, including WestConnect and the California Independent System Operator (CAISO), to address broader interregional planning. Neither the costs nor requirements of participating in NorthernGrid's coordinated transmission planning activities are expected to materially impact our operations or financial performance.

**Regional Energy Markets**

The CAISO operates the Western Energy Imbalance Market (EIM) in the western United States. We are participants in the Western EIM, along with all investor-owned utilities in the Pacific Northwest. The Western EIM, among other things, facilitates regional load balancing by allowing certain generating plants to receive automated dispatch signals from the CAISO in five-minute intervals.

**Reliability Standards**

Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess penalties for non-compliance with these standards and other FERC regulations.

The FERC certified the NERC as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards, including but not limited to cybersecurity measures. The FERC approves NERC Reliability Standards, including western region standards that make up the set of legally enforceable standards for the United States bulk electric system. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Failure to comply with NERC reliability standards could result in substantial financial penalties. We have a robust internal compliance program in place to manage compliance activities and mitigate the risk of potential noncompliance with these standards. We do not expect the costs associated with compliance with these standards to have a material impact on our financial results.

As both a balancing authority and transmission operator, we must operate under the oversight of a reliability coordinator per NERC reliability standards. RC West is the reliability coordinator of record for 41 balancing authorities and transmission operators in the Western Interconnection, including Avista Corp. RC West oversees grid compliance with federal and regional grid standards, and can determine measures to prevent or mitigate system emergencies in day-ahead or real-time operations.

**Vulnerability to Cyberattack**

The energy sector, including electric and natural gas utility companies, has become the subject of cyberattacks with increased frequency and we, along with other utility companies, are the target of these frequent attacks.

A successful attack on our administrative networks could compromise the security and privacy of data, including operating, financial and personal information. A successful attack on our operating networks could impair the operation of our electric and/or natural gas utility facilities, possibly resulting in our inability to provide electric and/or natural gas service for extended periods of time.

We continually reinforce and update our defensive systems and comply with the NERC's reliability standards. See "Reliability Standards," "Item 1A. Risk Factors – Cybersecurity Risk Factors" and "Item 1C. Cybersecurity" for further information.

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***AVISTA CORPORATION***

**AVISTA UTILITIES ELECTRIC OPERATING STATISTICS**

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| | | | |
|:---|:---|:---|:---|
|  | Years Ended December 31, | Years Ended December 31, | Years Ended December 31, |
|  | 2025 | 2024 | 2023 |
| **ELECTRIC OPERATIONS** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;OPERATING REVENUES (Dollars in Millions): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | $550 | $473 | $425 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 402 | 369 | 344 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 142 | 131 | 110 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Public street and highway lighting | 9 | 9 | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail | 1103 | 982 | 887 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Wholesale | 187 | 225 | 250 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Sales of fuel | 20 | 13 | (26) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other | 34 | 81 | 61 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric operating revenues | $1344 | $1301 | $1172 |
| &nbsp;&nbsp;&nbsp;&nbsp;ENERGY SALES (Thousands of MWhs): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | 4114 | 4018 | 4020 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 3216 | 3166 | 3160 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 1912 | 1785 | 1671 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Public street and highway lighting | 15 | 17 | 17 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail | 9257 | 8986 | 8868 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Wholesale | 4457 | 3740 | 3468 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric energy sales | 13714 | 12726 | 12336 |
| &nbsp;&nbsp;&nbsp;&nbsp;ENERGY RESOURCES (Thousands of MWhs): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Hydroelectric generation (from Company facilities) | 3195 | 3168 | 3024 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Thermal generation (from Company facilities) | 4815 | 4995 | 5084 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Purchased power | 6040 | 4965 | 5121 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Power exchanges | (13) | (14) | (421) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total power resources | 14037 | 13114 | 12808 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Energy losses and Company use | (323) | (388) | (472) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total energy resources (net of losses) | 13714 | 12726 | 12336 |
| &nbsp;&nbsp;&nbsp;&nbsp;NUMBER OF RETAIL CUSTOMERS (Average for Period): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | 376349 | 371076 | 366450 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 45959 | 45794 | 45341 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 1159 | 1175 | 1188 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Public street and highway lighting | 761 | 739 | 690 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric retail customers | 424228 | 418784 | 413669 |
| &nbsp;&nbsp;&nbsp;&nbsp;RESIDENTIAL SERVICE AVERAGES: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual use per customer (KWh) | 10931 | 10827 | 10971 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Revenue per KWh (in cents) | 13.37 | 11.78 | 10.58 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual revenue per customer (in dollars) | $1462 | $1276 | $1160 |
| &nbsp;&nbsp;&nbsp;&nbsp;AVERAGE HOURLY LOAD (aMW) | 1149 | 1117 | 1115 |

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***AVISTA CORPORATION***

**AVISTA UTILITIES ELECTRIC OPERATING STATISTICS**

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| | | | |
|:---|:---|:---|:---|
|  | Years Ended December 31, | Years Ended December 31, | Years Ended December 31, |
|  | 2025 | 2024 | 2023 |
| &nbsp;&nbsp;&nbsp;&nbsp;RETAIL NATIVE LOAD at time of system peak (MW): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Winter | 1832 | 1869 | 1771 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Summer | 1837 | 1831 | 1809 |
| &nbsp;&nbsp;&nbsp;&nbsp;COOLING DEGREE DAYS: (1) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Spokane, WA |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Actual | 845 | 903 | 811 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Historical average | 607 | 596 | 585 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;% of average | 139% | 152% | 139% |
| &nbsp;&nbsp;&nbsp;&nbsp;HEATING DEGREE DAYS: (2) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Spokane, WA |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Actual | 5782 | 5875 | 6012 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Historical average | 6521 | 6569 | 6557 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;% of average | 89% | 89% | 92% |

---

(1)Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day is above 65 degrees Fahrenheit (annual degree days above historical average indicate warmer than average temperatures).

(2)Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day is below 65 degrees Fahrenheit (annual degree days below historical averages indicate warmer than average temperatures).

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***AVISTA CORPORATION***

**AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS**

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| | | | |
|:---|:---|:---|:---|
|  | Years Ended December 31, | Years Ended December 31, | Years Ended December 31, |
|  | 2025 | 2024 | 2023 |
| **NATURAL GAS OPERATIONS** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;OPERATING REVENUES (Dollars in Millions): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | $291 | $317 | $326 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 137 | 163 | 164 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interruptible | 9 | 9 | 13 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 3 | 4 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail | 440 | 493 | 507 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Wholesale | 52 | 61 | 55 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transportation | 13 | 11 | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other | 79 | 41 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total natural gas operating revenues | $584 | $606 | $571 |
| &nbsp;&nbsp;&nbsp;&nbsp;THERMS DELIVERED (Thousands of Therms): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | 209200 | 217808 | 225665 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 132932 | 137972 | 138719 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interruptible | 25503 | 20682 | 20158 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 4732 | 4347 | 4914 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail | 372367 | 380809 | 389456 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Wholesale | 228646 | 271803 | 262188 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transportation | 156883 | 178236 | 165066 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interdepartmental and Company use | 389 | 391 | 413 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total therms delivered | 758285 | 831239 | 817123 |
| &nbsp;&nbsp;&nbsp;&nbsp;NUMBER OF RETAIL CUSTOMERS (Average for Period): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | 346048 | 343267 | 340655 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 37481 | 37353 | 37193 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interruptible | 51 | 52 | 50 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 184 | 185 | 187 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total natural gas retail customers | 383764 | 380857 | 378085 |
| &nbsp;&nbsp;&nbsp;&nbsp;RESIDENTIAL SERVICE AVERAGES: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual use per customer (therms) | 605 | 635 | 662 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Revenue per therm (in dollars) | $1.39 | $1.46 | $1.44 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual revenue per customer (in dollars) | $840 | $925 | $956 |
| &nbsp;&nbsp;&nbsp;&nbsp;HEATING DEGREE DAYS: (1) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Spokane, WA |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Actual | 5782 | 5875 | 6012 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Historical average | 6521 | 6569 | 6557 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;% of average | 89% | 89% | 92% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Medford, OR |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Actual | 4169 | 3963 | 4295 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Historical average | 4252 | 4282 | 4248 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;% of average | 98% | 93% | 101% |

---

(1)Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day is below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

**<u>ALASKA ELECTRIC LIGH</u><u>T AND POWER COMPANY</u>**

AEL&P is the primary operating subsidiary of AERC, and the sole utility providing electrical energy in Juneau, Alaska. Juneau is a geographically isolated community with no electric interconnections with the transmission facilities of other utilities and no pipeline access to natural gas or other fuels. Juneau's economy is primarily driven by government activities, tourism, commercial fishing, and mining, as well as activities as the commercial hub of southeast Alaska.

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***AVISTA CORPORATION***

AEL&P owns and operates electric generation, transmission and distribution facilities located in Juneau. AEL&P operates five hydroelectric generation facilities with 102.7 MW of hydroelectric generation capacity. AEL&P owns four of these generation facilities (totaling 24.5 MW of capacity) and has a PPA for the output of the Snettisham hydroelectric project (totaling 78.2 MW of capacity).

The Snettisham hydroelectric project is owned by the Alaska Industrial Development and Export Authority (AIDEA), a public corporation of the State of Alaska. AIDEA issued revenue bonds in 1998 (which were refinanced in 2015) to finance its acquisition of the project. These bonds were outstanding in the amount of $36 million as of December 31, 2025 and mature in January 2034. AEL&P has a PPA and operating and maintenance agreement with the AIDEA to operate and maintain the facility. This PPA is a take-or-pay obligation, expiring in December 2038. AIDEA's bonds are payable solely out of the revenues received under the PPA. Amounts payable by AEL&P under the PPA are equal to the required debt service on the bonds plus operating and maintenance costs.

This PPA is a finance lease and, as of December 31, 2025, the finance lease obligation was $36 million. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for a price equal to the principal amount of the bonds outstanding at that time. See "Note 5 of the Notes to Consolidated Financial Statements" for further discussion of the Snettisham finance lease obligation.

AEL&P has 107.5 MW of diesel generating capacity from four facilities to provide back-up service to firm customers when necessary.

The following graph shows AEL&P's hydroelectric generation (in thousands of MWhs) during the time periods indicated below:

![img175228948_3.jpg](img175228948_3.jpg)

(1)Normal hydroelectric generation is defined as the energy output of the plant during a year with average inflows to the reservoir.

As of December 31, 2025, AEL&P served approximately 17,600 customers. Its primary customers include city, state and federal governmental entities located in Juneau, as well as a mine located in the Juneau area. Most of AEL&P's customers are served on a firm basis while certain of its customers, including its largest customer, are served on an interruptible sales basis. AEL&P maintains separate rate tariffs for each of its customer classes, as well as seasonal rates.

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***AVISTA CORPORATION***

AEL&P's operations are subject to regulation by the RCA with respect to customer rates, standard of service, facilities, accounting and certain other matters, but not with respect to the issuance of securities.

AEL&P is subject to the jurisdiction of the FERC with respect to permits and licenses necessary to operate certain of its hydroelectric facilities. One of these licenses (for the Lake Dorothy hydroelectric project) expires in 2053 while the other (for the Salmon Creek and Annex Creek hydroelectric projects) expires in 2058. Gold Creek is not subject to a FERC license requirement. Since AEL&P has no electric interconnection with other utilities and makes no wholesale sales, it is not subject to general FERC jurisdiction, other than the reporting and other requirements of the Public Utility Holding Company Act of 2005 as an Avista Corp. subsidiary.

The Snettisham hydroelectric project is subject to regulation by the State of Alaska with respect to dam safety and certain aspects of its operations. AEL&P is subject to regulation with respect to air and water quality, land use and other environmental matters under both federal and state laws.

**AEL&P ELECTRIC OPERATING STATISTICS**

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| | | | |
|:---|:---|:---|:---|
|  | Years Ended December 31, | Years Ended December 31, | Years Ended December 31, |
|  | 2025 | 2024 | 2023 |
| **ELECTRIC OPERATIONS** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;OPERATING REVENUES (Dollars in Millions): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | $22 | $22 | $20 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial and government | 25 | 27 | 27 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail | 47 | 49 | 47 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other |  | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric operating revenues | $47 | $50 | $48 |
| &nbsp;&nbsp;&nbsp;&nbsp;ENERGY SALES (Thousands of MWhs): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | 169 | 171 | 161 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial and government | 232 | 255 | 249 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Public street and highway lighting | 1 | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric energy sales | 402 | 427 | 411 |
| &nbsp;&nbsp;&nbsp;&nbsp;NUMBER OF RETAIL CUSTOMERS (Average for Period): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | 15330 | 15236 | 15142 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial and government | 2389 | 2338 | 2327 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Public street and highway lighting | 251 | 249 | 248 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric retail customers | 17970 | 17823 | 17717 |
| &nbsp;&nbsp;&nbsp;&nbsp;RESIDENTIAL SERVICE AVERAGES: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual use per customer (KWh) | 11045 | 11192 | 10633 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Revenue per KWh (in cents) | 12.66 | 12.66 | 12.54 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual revenue per customer (in dollars) | $1398 | $1417 | $1336 |
| &nbsp;&nbsp;&nbsp;&nbsp;HEATING DEGREE DAYS: (1) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Juneau, AK |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Actual | 8118 | 8139 | 7550 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Historical average | 8336 | 8336 | 8336 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;% of average | 97% | 98% | 91% |

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(1)Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day is below 65 degrees Fahrenheit (annual heating degree days below historical average indicate warmer than average temperatures).

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***AVISTA CORPORATION***

**<u>OTHER BUS</u><u>INESSES</u>**

The following table shows our assets related to our other businesses, including intercompany amounts as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
| Entity and Asset Type | 2025 | 2024 |
| Avista Capital |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Equity investments | $148 | $157 |
| &nbsp;&nbsp;&nbsp;&nbsp;Notes receivable – third parties | 11 | 18 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other assets | 6 | 7 |
| Alaska companies (AERC and AJT Mining) | 12 | 12 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $177 | $194 |

---

Avista Capital's equity investments are primarily investments in emerging technology and biotechnology companies and venture capital funds, as well as investment in a joint venture focused on local real estate development and economic growth.

Alaska companies includes AERC and AJT Mining, which is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain real estate.

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***AVISTA CORPORATION***

**<u>ITEM 1A. R</u><u>ISK FACTORS</u>**

**<u>RISK FACTORS</u>**

The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause future results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Annual Report on Form 10-K), and elsewhere. See "Forward-Looking Statements" for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Additional risks and uncertainties not presently known to us or that we currently do not consider material could also adversely affect us. The realization of many of the risks discussed herein depends upon the prior occurrence of some event or circumstance – i.e. a "trigger". We may or may not discuss the occurrence of a trigger that has not resulted in an adverse effect on us, and the absence of such disclosure should not be construed as a representation that no such trigger has occurred.

***<u>Utility Regulatory Risk Factors</u>***

**Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.**

Avista Utilities' annual operating expenses and the costs associated with incremental investments in utility assets continue to grow at a faster rate than revenue. Our ability to recover these expenses and capital costs depends on the adequacy and timeliness of retail rate increases allowed by regulatory agencies, as well as managing costs. We expect to periodically file for rate increases with regulatory agencies to recover our expenses and capital costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators do not grant rate increases or grant substantially lower rate increases than our requests in the future or if recovery of deferred expenses is disallowed, or if regulators do not allow us to recover costs associated with assets required to be retired or divested to comply with emerging laws and regulations, it could have a negative effect on our financial condition, results of operations or cash flows. See further discussion of regulatory matters in "Item 7. Management's Discussion and Analysis – Regulatory Matters."

**In the future, we may no longer meet the criteria for continued application of regulatory accounting principles for all or a portion of our regulated operations.**

If we could no longer apply regulatory accounting principles, we could be:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•required to write off our regulatory assets, and be

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we expect to recover these amounts from customers in the future.

See further discussion at "Note 1 of the Notes to Consolidated Financial Statements – Regulatory Deferred Charges and Credits."

***<u>Operational Risk Factors</u>***

**Wildfires ignited, or allegedly ignited, by Avista Corp. equipment or facilities, could cause significant loss of life and property, thereby causing serious operational and financial harm.**

Our equipment may be the ignition source, or alleged cause of ignition, for wildfires and in the event of a fire caused by our equipment, we could potentially be held liable for resulting damages to life and property, as well as fire suppression costs. Also, wildfires could lead to extended operational outages of our equipment while we wait for the wildfire to be extinguished before restoring power, and the cost to implement rapid response or repair to such facilities could be significant. Wildfires caused by our equipment could cause significant damage to our reputation, which could erode shareholder, customer and community satisfaction. In addition, wildfires caused by our equipment could lead to increased litigation and insurance costs, loss of insurance coverage, the need to be self-insured or the need to consider non-traditional insurance coverage or other risk mitigation procedures. Wildfire risks may be exacerbated by increasing temperatures and/or decreasing precipitation due to climate change.

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***AVISTA CORPORATION***

**We are subject to various operational and event risks.**

Our operations are subject to operational and event risks that include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, floods, snow and ice storms, and heat waves due to normal weather variations as well as the impacts of climate change which could disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies, support services and general business operations,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•blackouts or disruptions of interconnected transmission systems (the regional power grid),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•unplanned outages at generating plants,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•changes in the availability and cost of purchased power, fuel and natural gas, including delivery constraints and restrictions imposed by the transition to renewable and/or non-emitting energy sources, which can disrupt service to customers,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•explosions, fires, accidents, or mechanical breakdowns that could occur while operating and maintaining our generation, transmission and distribution systems, including, but not limited to, increased risk associated with emerging renewable technologies as these technologies continue to mature,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•property damage or injuries to third parties caused by our generation, transmission and distribution systems,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•dam failure at a company-owned hydroelectric facility,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•natural disasters that can disrupt energy generation, transmission and distribution, and general business operations,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increased costs or delay of capital projects associated with the ability of suppliers, vendors or contractors to perform,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•general workforce problems, including decreased employee engagement, which may impact strategy execution and negatively affect retention, ability to attract workers, and result in challenges in collective bargaining, possible work stoppages, and strikes. Retention of employees may also be negatively impacted by early retirements, insufficient remote work opportunities, and higher pay offered by other employers. Attractions of employees to support strategies may be affected by higher pay offered from other companies, more liberal remote work opportunities offered by other employers, and other work-life balance benefits afforded by other companies.

Disasters could affect the general economy, financial and capital markets, specific industries or our ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect against liability, extra expenses and operating disruptions from the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations. If insurance or indemnification agreements are unable to adequately protect us or reimburse us for out-of-pocket costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

**Damage to facilities** could be caused by severe weather or natural disasters, such as snow, ice, wind storms, floods, wildfires, earthquakes or avalanches. The cost of implementing rapid response or repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather and are not covered by insurance.

**Physical attacks on our assets could have a negative impact on our business and our results of operations.**

Our generation, transmission and distribution assets and the systems that monitor and operate these assets are critical infrastructure for providing service to our customers. Security threats are continuing to evolve, and our industry is subject to

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***AVISTA CORPORATION***

attempts to disrupt operations. Significant destruction or interruption of these assets and systems could prevent us from fulfilling our critical business functions, including delivering energy to customers. This could result in experiencing a loss of revenues and/or additional costs to replace or restore assets and systems, and may increase costs associated with heightened security requirements.

**Lack of control over facilities under PPAs could impact power supply costs**

Generating facilities not owned by us, whose output we acquire under a PPA, could be foreclosed on by creditors of the owner, even though we are performing under the terms of the PPA. This could result in either an increase in the price to be paid by us, or the output of the facilities being diverted from us and sold to other parties.

**Adverse impacts to AEL&P could result from an extended outage of its hydroelectric generating resources or its inability to deliver energy, due to its lack of interconnectivity to other electrical grids and the cost of replacement power (diesel).**

AEL&P operates several hydroelectric power generation facilities and has diesel generating capacity to provide backup service to firm customers when necessary; however, a single hydroelectric power generation facility, the Snettisham hydroelectric project, provides approximately two-thirds of AEL&P's hydroelectric power generation. Issues that negatively affect AEL&P's ability to generate or transmit power or a decrease in the demand for the power generated by AEL&P could negatively affect our results of operations, financial condition and cash flows.

***<u>Climate Change Risk Factors</u>***

**A trend of increasing average temperatures and its effects could cause significant direct and indirect impacts on our operations and results of operations**.

Climate change may exacerbate existing risks related to weather and weather-related events. Potential direct effects of climate change include changes in the timing and magnitude of snowpack and streamflow, impacting hydroelectric generation; timing and magnitude of changes in electric and gas load; increased weather-related stress on, or damage to, energy infrastructure; increased frequency and intensity of extreme weather events that may impact energy generation and delivery.

Indirect impacts associated with climate change may include increased costs to generate electricity or secure natural gas and deliver energy to customers; impacts to the timing or amount of operating revenues; increased costs to maintain or construct energy infrastructure in adaptation to a changing climate; increased costs or inability to obtain insurance coverage; and regional impacts to the demographic makeup, economy or financial conditions of our customers. Indirect impacts also include risks associated with new and emerging laws and regulations, which could have a material adverse impact on our business and results of operations. See further discussion at "Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies."

***<u>Cybersecurity Risk Factors</u>***

**Cyberattacks, ransomware, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows.**

We rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees.

Cyberattacks, ransomware, terrorism or other malicious acts could damage, destroy or disrupt these systems for an extended period of time. The energy sector, including electric and natural gas utility companies have become the subject of cyberattacks with increased frequency. Our administrative and operating networks are targeted by hackers on a regular basis. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to the same cyber or terrorism risks as our facilities and systems and such third party systems may be interconnected to our systems both physically and technologically. Therefore, an event caused by cyberattacks, ransomware or other malicious act at an interconnected third

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***AVISTA CORPORATION***

party could impact our business and facilities similarly. Any failure, unexpected, or unauthorized use of technology systems could result in the unavailability of such systems, and could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer and/or employee information or other proprietary data that could adversely affect our reputation and competitiveness, could result in costly litigation and negatively impact our results of operations. These cyberattacks have become more common and sophisticated and, as such, we could be required to incur costs to strengthen our systems and respond to emerging concerns.

There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors.

***<u>Technology Risk Factors</u>***

**Our technology may become obsolete, development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.**

Our technology may become obsolete before the end of its useful life. In addition, custom or new technology (including generative artificial intelligence) that is heavily relied upon may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Generative artificial intelligence could also create additional regulatory scrutiny and generate uncertainty around intellectual property ownership and/or licensing or use. Technology (including artificial intelligence) is also subject to intentional misuse (by criminals, terrorists or other bad actors). Technology failures or incidents of misuse could result in significant adverse effects on our operations, results of operations, financial condition and cash flows.

**We may be adversely affected by our inability to successfully implement certain technology projects.**

There are inherent risks associated with replacing and changing systems, which could have a material adverse effect on our results of operations, financial condition and cash flows. Finally, there is the risk that we ultimately do not complete a project and will incur contract cancellation or other costs, which could be significant.

**Problems with the transition, design or implementation of our new enterprise resource planning system could interfere with our business and operations, and adversely affect our financial condition.**

We are in the process of planning for the implementation of a new cloud-based enterprise resource planning system, which will take multiple years to complete. See further information on the enterprise resource planning system within "Item 7. Management's Discussion and Analysis – Executive Overview". There are transitional risks associated with the implementation, which may include loss of data in the conversion from on-premises systems to the cloud, difficulty compiling data for external reporting requirements, costs increasing throughout the project, or other challenges in our business operations. Difficulties faced during the transition could have a material adverse effect on our business, financial condition, and results of operations.

**The expanded adoption of artificial intelligence has the potential to increase exposure to cyberattacks and negatively impact business operations.**

The adoption of artificial intelligence (AI) is driving demand for energy while also presenting opportunities and unique risks to the utility business. AI enabled tools are proving to increase efficiency and add value to daily work processes as the use and adoption continues to expand. While use cases to drive efficiencies through AI develop, cyber attackers are targeting the tools and systems used to create the efficiencies, requiring enhanced analytics and monitoring. Reliance on AI generated information and data may enhance the exposure risk over time.

AI driven solutions will be essential to compete in the marketplace, whether it be for material or energy procurement, or financial transactions, AI will accelerate data driven decision making. Therefore, AI literacy is essential. Not advancing the understanding and use of AI may compromise the operational and financial progress of the Company.

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***AVISTA CORPORATION***

***<u>Strategic Risk Factors</u>***

**Our strategic business plans, which may be affected by the foregoing, may change, including the entry into new businesses and/or the exit from existing businesses and/or the curtailment of our business development efforts where potential future business is uncertain.**

Our strategic business plans could be affected by or result in the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•disruptive innovations in the marketplace may outpace our ability to compete or manage our risk (including the transition to renewable and/or non-emitting energy resources),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•customers may have a choice in the future over the sources from which to receive their energy, and we may not be able to compete,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•reduced control over generation resources resulting from reliance on contract power from third-party owners of generation assets, which could limit our ability to balance resources with demand,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•market or other conditions that could adversely affect our operations or require changes to our business strategy and could result in reduced assets and net income,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•affordability of electric and/or gas services may be a challenge for customers resulting in increased delayed payment for utility services,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with the Company, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the risk of municipalization or other form of service territory reduction.

**Non-regulated investments in businesses outside of our core utilities operations may increase earnings volatility and can be difficult to sell due to their illiquid nature.**

The fair values of our respective equity investments fluctuate from period to period, and such changes in fair value directly affect our net income. While we make these investments after prudent analysis and with the expectation of eventual financial gains, there is no assurance these investments will ultimately be successful. A significant portion of our investment portfolio consists of equity interests in privately held companies, which are inherently illiquid due to a lack of established market. Liquidity events are largely outside of our control, and may not occur on a timely basis (or may never occur). In addition, it is likely the value of these investments will continue to fluctuate as the businesses continue to mature, causing corresponding changes in our net income. The risks faced by these businesses may differ from the risks faced by our utility operations.

***<u>External Mandates Risk Factors</u>***

External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact the Company.

**Actions or limitations to address concerns over long-term climate change, both globally and within our utilities' service areas, may affect our operations and financial performance.**

Legislative, regulatory and advocacy efforts at the local, state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric and natural gas utility industries are frequently affected by proposals to curb greenhouse gas and other air emissions. Various regulatory and legislative proposals have been made to limit or further restrict byproducts of combustion, including those resulting from the use of natural gas by

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***AVISTA CORPORATION***

our customers. In addition, there are regulatory and legislative initiatives that have been passed which are designed to limit greenhouse gas emissions and increase the use of renewable sources of energy. In addition, regulatory and legislative initiatives may restrict customers' access to natural gas and/or require or limit natural gas infrastructure in buildings. Other initiatives may seek to promote social interests expressed as energy equity, environmental justice or similar frameworks. Such legislation could direct and/or restrict the operation and raise the costs of our power generation resources and energy delivery infrastructure as well as the distribution of natural gas to our customers.

We expect continuing legislative and regulatory activity in the future, and we are evaluating the extent to which potential changes to environmental laws and regulations may:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increase the operating costs of generating plants,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increase the lead time and capital costs for the construction of new generating plants,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require modification of our existing generating plants,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require existing generating plant operations to be curtailed or shut down,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•reduce the amount of energy available from our generating plants,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•restrict the types of generating plants that can be built or contracted with,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require construction of specific types of generation plants at higher cost, including emerging generation sources still in development that operate at a higher risk of failure, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increase the cost or limit our ability to distribute natural gas to customers.

See "Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" for discussion regarding environmental issues and legislation which may affect our operations.

**We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.**

In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any issue, including the extent, if any, of insurance coverage or recovery through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See "Note 22 of the Notes to Consolidated Financial Statements" for further details of these matters.

**Import tariffs could lead to increased prices on energy commodities and/or equipment and materials that are critical to our business.**

Tariffs and other restrictions on trade with foreign countries could significantly increase the prices of energy commodities (electricity and natural gas) and equipment and materials that are critical to our business. In addition, tariffs and trade restrictions could have a similar impact on our suppliers and certain customers, which could have a negative impact on our financial condition, results of operations and cash flows.

See "Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" and "Forward-Looking Statements" for discussion of or reference to additional external mandates which could have a material adverse effect on our results of operations, financial condition and cash flows.

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***AVISTA CORPORATION***

***<u>Financial Risk Factors</u>***

**Weather (temperatures, precipitation levels, wind patterns and storms) has a significant effect on our results of operations, financial condition and cash flows. These effects could increase as climate changes occur.**

Weather impacts are described in the following subtopics:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain retail electricity and natural gas sales,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the cost of natural gas supply, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the cost of power supply.

**Certain retail electricity and natural gas** sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers' energy demand and our retail operating revenues. The revenue and earnings impact of weather fluctuations is somewhat mitigated by our decoupling mechanisms; however, we could experience liquidity constraints during the period between when decoupling revenue is earned and when it is subsequently collected from customers through retail rates.

**The cost of natural gas supply** is impacted by both supply-side factors (amount of natural gas production, level of natural gas in storage, volumes of natural gas imports and exports, regulatory restraints or costs on natural gas production and delivery) and demand-side factors (variations in weather, level of economic growth, availability and prices of other fuels). Prices tend to increase with higher demand during periods of cold weather. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in the Pacific Northwest. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we are generally allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail rates.

**The cost of power supply** can be significantly affected by weather, and therefore is subject to trends in climate change. Precipitation (consisting of snowpack, its water content and runoff pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, more costly power supply resources must be dispatched or acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in the Pacific Northwest but its contribution to supply is inconsistent.

The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. Climate change may increase the frequency and magnitude of temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and is partially deferred or shared with customers through regulatory mechanisms. However, these deferred costs require cash outflows from the time of power purchases until the costs are later recovered through retail rates.

The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation produce output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.

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***AVISTA CORPORATION***

As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.

**We rely on regular access to financial markets, but we cannot assure favorable or reasonable financing terms will be available when we need them.**

**Access to capital markets is critical to our operations and our capital structure.** We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impact our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.

We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital, including needs related to power and natural gas purchases and sales, from time-to-time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.

**We rely on credit from financial institutions for short-term borrowings.** We need adequate levels of credit with financial institutions for short-term liquidity. There is no assurance that we will have access to credit beyond the expiration dates of our committed line of credit agreements. These agreements contain customary covenants and default provisions.

Any default on the lines of credit or other financing arrangements of Avista Corp. or our "significant subsidiaries," if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.

**Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources.** If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us or result in the termination of outstanding regulatory authorizations for certain financing activities.

**Credit risk may be affected by industry concentration and geographic concentration.**

We have concentrations of suppliers and customers in the electric and natural gas industries, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•electric and natural gas utilities,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•electric generators and transmission providers,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•oil and natural gas producers and pipelines,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•financial institutions including commodity clearing exchanges and related parties, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•energy marketing and trading companies.

We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.

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***AVISTA CORPORATION***

We are a participant in the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation. The EIM collateral requirements are based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the EIM, and credit losses could be allocated among all EIM participants, including us. A significant failure of a participant in the EIM to make payments when its obligations are due could have a ripple effect on our counterparties in the power and gas markets if those counterparties experience ancillary liquidity issues, and could result in a decline in the ability of our counterparties to perform on their obligations.

**Activist shareholder actions could have a negative impact on our business and operations.**

Shareholder activism can take many forms and arise in a variety of situations. Actions by activist shareholders could include engaging in proxy solicitations, making or advancing shareholder proposals, or otherwise attempting to assert influence on our board of directors and/or management. Response to these actions could result in substantial costs, require significant attention from our board of directors and management, and divert resources from the execution of our strategy and business operations.

Shareholder activism could result in perceived uncertainties, negatively affect our business opportunities, our ability to access capital markets, and relationships with our customers and employees. These actions could have a material adverse effect on our financial condition and results of operations, and could result in significant fluctuations in the trading price of our common stock based on market perceptions or other factors.

***<u>Energy Commodity Risk Factors</u>***

**Energy commodity price changes affect our cash flows and results of operations.**

**Energy commodity prices can be volatile.** We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. A combination of factors exposes our operations to commodity price risks, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•our obligation to serve our retail customers at rates set through the regulatory process - we cannot decline to serve our customers and we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements (however, a significant portion of our energy resource costs are not fixed), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices.

Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.

**We hedge a portion of our energy commodity risk with physical and financial derivative instruments that may require the posting of collateral.** When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between forward prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.

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***AVISTA CORPORATION***

**Cash flow deferrals related to energy commodities can be significant.** We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer income statement recognition and recovery from customers for some of these differences, which are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators, who have discretion as to the extent and timing of future recovery or refund to customers.

Power and natural gas costs higher than those recovered in retail rates negatively impact cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations.

Even if our regulators ultimately allow the recovery of deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.

**Fluctuating energy commodity prices and volumes in relation to our energy risk management process can cause volatility in our cash flows and results of operations.** We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. If market prices decrease compared to the prices we have locked in with our energy commodity derivatives, this will result in a liability related to these derivatives, which can be significant. As a result of price fluctuations, we may be required to post significant amounts of cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments.

We do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows.

The hedges we enter into are reviewed for prudence by our various regulators and deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators.

**Generation plants may become obsolete.** We rely on a variety of generation and energy commodity market sources to fulfill our obligation to serve customers and meet the demands of our counterparty agreements. Some of our generation sources, such as coal, may become obsolete or be prematurely retired through regulatory action or legislation. This could result in higher commodity costs to replace the lost generation, as well as higher costs to retire the generation source before the end of its expected life. This also includes costs (including replacement of lost generation) associated with our transfer of Colstrip ownership to NorthWestern as of January 1, 2026. See "Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" for discussion regarding environmental and other issues surrounding Colstrip.

***<u>Compliance Risk Factors</u>***

**There have been numerous changes in legislation, related administrative rulemakings, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.**

We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties.

Future legislation, administrative rules or Executive Orders could have a material adverse effect on our operations, results of operations, financial condition and cash flows.

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***AVISTA CORPORATION***

***<u>Resource Adequacy Risk Factors</u>***

**Multiple factors are influencing the ability to source and deliver adequate energy to meet customer demand, which could lead to power and gas market liquidity risks.**

Local and regional factors may occur and impact our ability to meet energy needs during periods of high demand or unplanned events. Locally, some combination of factors such as unanticipated load growth, unforeseen localized climatic changes, decreases in water availability for hydro generation, and prolonged unplanned generation outages could result in being short the energy we need to meet customer demand. External to localized conditions and events, the regional wholesale market, to which we would turn to purchase energy to meet short-term shortfalls, has become strained during regional events. If the northwest region does not build sufficient new generation capacity and additional transmission and gas transport, there is a risk that we will not be able to depend on excess energy market purchases to meet customer demand during extreme weather events. These factors are increasing the risk of potential regional energy supply shortages and the ability for us to access additional energy during periods of high demand or unplanned events.

**<u>ITEM 1B. UNRESOLV</u><u>ED STAFF COMMENTS</u>**

As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the SEC.

**<u>IT</u><u>E</u><u>M 1C. CYBERSECURITY</u>**

The energy sector, including electric and natural gas utility companies, has become the subject of cyberattacks with increased frequency and we, along with other utility companies, are the target of these frequent attacks. In addition, there is a growing reliance on third party providers which are also subject to attacks and breaches. Any unexpected failure, or unauthorized access to technology systems or third parties relied upon can result in the unavailability of systems or services, which can result in a loss of operating revenues, damage to our brand and reputation, and/or an increase in operating expenses and costs to repair or replace damaged assets. To date, we have not identified any risks from cybersecurity threats that have materially affected or are reasonably likely to materially affect our results of operation or financial condition. See "Risk Factors – Cybersecurity Risk Factors" for further information regarding the risks we face from cybersecurity threats.

We consider the management of cybersecurity risk in our overall enterprise risk management process. See "Item 7. Management's Discussion and Analysis - Enterprise Risk Management" for further discussion of the process.

We mitigate cyber risk by maintaining an enterprise security program based on the National Institute of Standards and Technology Cybersecurity Framework. This program includes trainings and exercises at all levels of the Company. Our security program incorporates enterprise business continuity which facilitates a business impact analysis of core functions for development of emergency operating and disaster recovery plans and coordinates annual testing and training exercises. In addition, there are independent third party and regulatory audits of our security program.

The cybersecurity risk management program is overseen by senior leadership within our Technology and Security functions. The program is led by the Senior Vice President of Operations and Technology and the Vice President, Chief Information and Security Officer. The Senior Vice President of Operations and Technology has more than 20 years of experience in information technology leadership, including roles directing enterprise systems and cybersecurity programs at other companies. The Vice President, Chief Information and Security Officer has over 15 years of experience at the Company, having served in engineering and technology leadership roles, including as the Director of Information Technology Infrastructure and the Director of Applications. This program includes maintenance of appropriate cybersecurity measures, such as firewalls, anti-virus, patching, and other zero-trust security protocols, monitoring for intrusion and security events that may include a data breach or an attack on our operations, and working with our supply chain department to ensure contracts with third party service providers include appropriate requirements for the mitigation of cybersecurity risk that might impact our business.

Our data breach response team is comprised of designated members of the technology department, senior management and other appropriate individuals. The team is tasked with assessing, managing and responding to material cybersecurity incidents involving either our systems or the systems of third party service providers. The data breach response team includes subject matter experts within the Company, as well as outside experts who specialize in cybersecurity response. A subset of this team is

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***AVISTA CORPORATION***

also responsible for assessing the materiality of cybersecurity incidents, reporting to the Audit Committee of the Board of Directors as appropriate, and ensuring timeline reporting of cybersecurity incidents deemed material to the Company.

The Environmental, Technology and Operations Committee of the Board of Directors oversees our management of cybersecurity risks. This Committee is briefed on security policy, programs and incidents on at least a quarterly basis. The Audit Committee of the Board of Directors provides oversight of required disclosures relating to cybersecurity.

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***AVISTA CORPORATION***

**<u>ITEM 2. P</u><u>ROPERTIES</u>**

**<u>AVISTA UT</u><u>ILITIES</u>**

Substantially all of Avista Utilities' properties are subject to the lien of Avista Corp.'s mortgage indenture.

Avista Utilities' electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:

**Company-Owned Generation Properties**

---

| | |
|:---|:---|
|  | Present<br>Capability<br>(MW) (1) |
| Hydroelectric Generating Stations (River) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Washington: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Long Lake (Spokane) | 88 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Little Falls (Spokane) | 48 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Nine Mile (Spokane) | 41 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Upper Falls (Spokane) | 10 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Monroe Street (Spokane) | 15 |
| &nbsp;&nbsp;&nbsp;&nbsp;Idaho: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Cabinet Gorge (Clark Fork) (2) | 273 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Post Falls (Spokane) | 12 |
| &nbsp;&nbsp;&nbsp;&nbsp;Montana: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Noxon Rapids (Clark Fork) | 562 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Hydroelectric | 1049 |
| Thermal Generating Stations (cycle, fuel source) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Washington: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Kettle Falls GS (combined-cycle, wood waste) (3) | 53 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Kettle Falls CT (combined-cycle, natural gas) (3) | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Northeast CT (simple-cycle, natural gas) | 65 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Boulder Park GS (simple-cycle, natural gas) | 25 |
| &nbsp;&nbsp;&nbsp;&nbsp;Idaho: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Rathdrum CT (simple-cycle, natural gas) | 166 |
| &nbsp;&nbsp;&nbsp;&nbsp;Montana: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Colstrip Units 3 and 4 (simple-cycle, coal) (4) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oregon: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Coyote Springs 2 (combined-cycle, natural gas) | 322 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Thermal | 638 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total Generation Properties | 1687 |

---

(1)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions.

(2)For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights.

(3)These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency.

(4)Our 15 percent interest in Colstrip was transferred to NorthWestern on January 1, 2026. See "Item 7. Management's Discussion and Analysis of Financial Condition – Colstrip" for information related to Colstrip Units 3 and 4.

**Electric Power Purchase Agreements**

Avista Utilities enters into long-term PPAs to purchase a portion or all of the output of specific generation assets. These generating assets are owned by other parties, not the Company, and are not subject to the lien of Avista Corp.'s mortgage

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***AVISTA CORPORATION***

indenture. However, these assets are subject to the liens securing the indebtedness of the respective owners. See further discussion of certain of these PPAs in "Part 1 – Item 1. Business – Avista Utilities – Electric Operations". The following is a summary of PPAs as of December 31, 2025:

---

| | | |
|:---|:---|:---|
| Generating Source | Present<br>Capability<br>(MW) (1) | Expiration of Contract |
| Hydroelectric |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Douglas County PUD | 16 | 2028 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Grant County PUD | 76 | 2052 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Chelan County PUD (2) | 263 | 2045 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Columbia Basin Hydro (3) | 103 | 2045 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Hydroelectric | 458 |  |
| Thermal |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lancaster | 276 | 2041 |
| Wind |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Clearwater Wind | 98 | 2055 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Palouse Wind | 105 | 2042 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Rattlesnake Flat Wind | 144 | 2040 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Wind | 347 |  |
| Solar |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lind Solar | 20 | 2038 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total Power Purchase Agreements | 1100 |  |

---

(1)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions.

(2)Our contracted portion of generation asset output from Chelan County PUD changes throughout the life of the agreement. Our output is expected to increase 88 MW in 2026, decrease 88 MW in 2032, and decrease 88 MW in 2034.

(3)Our output from this contract is expected to increase to a total of 147 MW by 2030 as we receive additional capacity under this contract.

**Electric Distribution and Transmission Plant**

Avista Utilities owns and operates approximately 20,000 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 700 miles of 230 kV line and approximately 1,600 miles of 115 kV line. We also own an 11 percent interest in approximately 600 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices and other equipment.

The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, Grant County PUD, PacifiCorp, NorthWestern and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant.

These lines also provide a means to optimize resources through short-term purchases and sales of power with entities within and outside of the Pacific Northwest.

The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park GS and Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other's customers that are connected through the other's

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***AVISTA CORPORATION***

transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA's transmission system.

**Natural Gas Plant**

Avista Utilities has natural gas distribution mains of approximately 3,600 miles in Washington, 2,300 miles in Idaho and 2,400 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 15 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.

We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. See "Part 1 – Item 1. Business – Avista Utilities – Natural Gas Operations" for further discussion of Jackson Prairie.

**<u>ALASKA ELECTRIC LIGH</u><u>T AND POWER COMPANY</u>**

Substantially all of AEL&P's utility properties (except the Snettisham plant) are subject to the lien of the AEL&P mortgage indenture.

AEL&P's utility electric properties, located in Alaska include the following:

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| | |
|:---|:---|
|  | Present<br>Capability<br>(MW) (1) |
| Hydroelectric Generating Stations |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Snettisham (2) | 78 |
| &nbsp;&nbsp;&nbsp;&nbsp;Lake Dorothy | 14 |
| &nbsp;&nbsp;&nbsp;&nbsp;Salmon Creek | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Annex Creek | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gold Creek | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Hydroelectric | 103 |
| Diesel Generating Stations |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Lemon Creek | 52 |
| &nbsp;&nbsp;&nbsp;&nbsp;Auke Bay | 25 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gold Creek | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Industrial Blvd. Plant | 23 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Diesel | 107 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total Generation Properties | 210 |

---

(1)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions.

(2)AEL&P does not own this generating facility and it is not subject to the lien of the AEL&P mortgage indenture. AEL&P has a PPA under which it has the right to purchase, and the obligation to pay for, all the capacity and energy of this facility. See further information at "Part 1. Item 1. Business – Alaska Electric Light and Power Company."

In addition to the generation properties above, AEL&P owns 61 miles of transmission lines, which are primarily comprised of 69 kV line, and 184 miles of distribution lines.

**<u>ITEM 3. LEGAL</u> <u>PROCEEDINGS</u>**

See "Note 22 of Notes to Consolidated Financial Statements" for information with respect to legal proceedings.

**<u>ITEM 4. MINE SAF</u><u>ETY DISCLOSURES</u>**

Not applicable.

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***AVISTA CORPORATION***

**PART II**

**<u>ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOC</u><u>KHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES</u>**

***Avista Corp. Market Information and Dividend Policy***

Avista Corp.'s common stock is listed on the New York Stock Exchange under the ticker symbol "AVA." As of January 31, 2026, there were 5,541 registered shareholders of our common stock.

Avista Corp.'s Board of Directors considers the level of dividends on our common stock on a recurring basis, taking into account numerous factors including, without limitation:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•our results of operations, cash flows and financial condition,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the success of our business strategies, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•general economic and competitive conditions.

Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P).

The payment of dividends on common stock could be limited by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain covenants applicable to preferred stock (when outstanding) contained in the Company's Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see "Item 7. Management's Discussion and Analysis - Capital Resources" for compliance with these covenants),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the hydroelectric licensing requirements of section 10(d) of the FPA (see "Note 1 of Notes to Consolidated Financial Statements"), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (including short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

For additional information, see "Notes 1 and 19 of Notes to Consolidated Financial Statements."

For information with respect to securities authorized for issuance under equity compensation plans, see "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."

**<u>ITEM 6. [REM</u><u>OVED AND RESERVED]</u>**

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***AVISTA CORPORATION***

**<u>ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF</u> <u>FINANCIAL CONDITION AND RESULTS OF OPERATIONS</u>**

This section of this Annual Report on Form 10-K generally discusses financial statement items and comparisons between 2025 and 2024. Discussion of 2023 financial statement items and comparisons between 2024 and 2023 not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Conditions and Results of Operations" in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2024.

**<u>Business</u> <u>Segments</u>**

As of December 31, 2025, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See "Part I, Item 1. Business – Company Overview" for further discussion of our business segments.

The following table presents net income (loss) for each of our business segments and the other businesses, for the year ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Avista Utilities | $201 | $179 | $167 |
| AEL&P | 6 | 8 | 9 |
| Other non-reportable segment loss | (14) | (7) | (5) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income | $193 | $180 | $171 |

---

**<u>Executive</u> <u>Overview</u>**

***Overall Results***

Net income increased primarily due to the effects of general rate cases. This increase in earnings was partially offset by increases in other operating expenses, depreciation and amortization expense, taxes other than income taxes and interest expense. The increase in net income was also partially offset by a $9 million refund to be issued to customers for adjustments related to Colstrip investments. See "Regulatory Matters" for further details regarding the Colstrip final order. In addition, increased investment losses associated with lower valuations of certain investments in our portfolio decreased net income at our other businesses when compared to 2024.

More detailed explanations of the fluctuations are provided in the results of operations and business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this summary.

***Resource Adequacy***

Extreme weather events, both in summer and winter, have occurred in the Pacific Northwest. These events have resulted in system load peaks that were higher than anticipated. Historically, we have had excess capacity as compared to peak load, but during some extreme events, we have had to purchase short-term energy from the wholesale market to meet demand when our energy resources were not operating at full capacity or were otherwise unavailable. These weather events have highlighted the growing need for additional generating capacity both on our system and in the Pacific Northwest region.

The transition to clean energy (including the replacement of emitting facilities with non-emitting facilities, which are impacted by conditions outside of our control), and electrification, combined with expected load growth, and the transfer of our interest in Colstrip, also factor into the need for additional generation.

We also see the need for expanded transmission infrastructure to provide access to additional resources and improve reliability in our region. In November 2024, we signed a non-binding memorandum of understanding to join the North Plains Connector transmission line project that plans to construct a transmission line from Bismarck, North Dakota to Colstrip, Montana.

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***AVISTA CORPORATION***

*Current Hydroelectric Conditions and Outlook*

Due to precipitation and warm weather, our hydroelectric generation in January and February (to date) has been above normal. Due to the warm weather, the average current level of snowpack in the areas serving our hydroelectric facilities is below normal. The amount of hydroelectric generation over the rest of the year will be affected not only by current snowpack levels but also by prevailing temperatures (which affect the timing and speed of run-off) and the volume, timing and form of precipitation. On balance, we expect the amount of hydroelectric generation for the entire year will be approximately at the normal level. While our current hydro forecast shows normal levels of generation, even if we were above or below normal, there would be no material change to our position in the ERM.

***2025 Request for Proposal (RFP)***

Our 2025 electric IRP was filed with the WUTC and IPUC in December 2024, and identified needs for additional generating capacity. In May 2025, we issued a request for proposal to add energy and capacity to meet projected resource needs. We selected a list of projects and will begin contract negotiations for the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a self-build upgrade of our existing Natural Gas Combustion Turbines at Rathdrum CT to add 14 MW of capacity without increasing carbon emissions. This upgrade will occur in two stages with the first occurring in 2027 and the second in 2029,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a project for 100 MW, 4-hour Battery Energy Storage System, to be built and transferred to the Company in eastern Washington with a target date in 2028,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a PPA for approximately 200 MW of wind power from Montana that utilizes our share of the Colstrip Transmission System with a target date in 2029, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the addition of approximately 40 MW of Demand Response Programs that will recruit residential, commercial and industrial customers within our service territory, beginning in 2026.

See "Part 1 – Item 1. Business – Future Electric Resource Needs" for further discussion of regional resource adequacy.

***2026 Customer Load***

We expect a decrease in customer load from 2025 to 2026 to have a negative impact on our 2026 results. This decrease in load is associated with a large industrial customer with their own transmission rights and access to procure their own energy independently. We were notified of this customer's intent to return to procuring their power independently in the power markets effective April 2026, which is earlier than we had expected. Net income is expected to decrease $9 million compared to if we had served their load through December 2026.

***Colstrip***

In December 2025, the WUTC issued a final order for our filed tariff rider for Colstrip and on January 1, 2026, the transaction to transfer our 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern closed. See "Colstrip" section and "Note 22 of the Notes to Consolidated Financial Statements" for further details on the exit of Colstrip through an agreement with NorthWestern and "Regulatory Matters" for further details regarding the Colstrip final order.

***Tariffs on Imports***

The President of the United States of America has imposed tariffs on certain imported goods. The imposition of tariffs may impact the cost of other equipment and materials that are critical to our business, increasing capital and operating expenses, and could create supply chain disruptions. The tariffs have not had a material impact on our operations or financial performance to date. At this time, we do not expect the impact of tariffs to be material and have not made any adjustments to our capital or operating budget to account for increased costs resulting from tariffs.

We import a significant amount of natural gas from Canada, both to serve our retail natural gas customers and as fuel for electric generation. We do not expect these imports to be impacted by the current trade tariffs as they are covered by the

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***AVISTA CORPORATION***

U.S.-Mexico-Canada Agreement, but the future of trade tariffs on energy commodity imports is uncertain. The impact of an increase in resource costs on our results of operations (directly or indirectly resulting from tariffs) would be substantially mitigated by various deferral and recovery mechanisms (ERM, PCA, and PGAs), but there could be an immediate impact on our cash flow.

In February 2026, the United States Supreme Court ruled that the legal basis cited by the President for the imposition of tariffs is not valid, and that he is restricted from imposing tariffs in the absence of a clear grant of authority from the Legislature. The impact of the Court's ruling, both as to tariffs already collected and as to potential future tariffs, is uncertain at this time.

We are closely monitoring the impacts of tariffs and the potential impact they may have on our results of operations, financial condition and cash flows.

***U.S. Reconciliation Bill***

In July 2025, the One Big Beautiful Bill Act (OBBB) was signed into law, which includes significant changes to the U.S. tax code and related laws. Key provisions include modifications and extensions to certain provisions of the Tax Cuts and Jobs Act of 2017 and updates to energy-related tax incentives, including revisions to the Clean Electricity Production Credit and the investment tax credit, as well as restrictions related to support from prohibited foreign entities. OBBB also allows for the current expensing of certain specified research and experimental (Section 174) expenditures.

The OBBB did not have a material impact on our results of operations and financial condition in 2025. We continue to monitor ongoing guidance. Any future impacts will be recognized in the period in which they become known. See "Note 13 of the Notes to Consolidated Financial Statements" for further discussion of the impact of OBBB.

***Enterprise Resource Planning (ERP) Project***

We are planning to implement an ERP system, replacing certain existing technology tools currently in use. The system will be designed to accurately maintain our financial records, enhance operational functionality, and provide timely information to our management team related to business operations. Accounting petitions were filed with the WUTC, the IPUC and the OPUC related to the project. These petitions include requesting to defer the undepreciated technology assets being replaced and a 15 year depreciable life for implementation costs. The requests were materially approved by the commissions.

We entered into a contract with a software provider and are in negotiations with system implementers. We expect the ERP system to be implemented in 2028. We expect capital expenditures between $100 million to $130 million.

***Regulatory Lag***

Regulatory lag is inherent in utility ratemaking; a result of the delay between the investment in utility plant and/or the increase in costs and the receipt of an order of a public utility commission authorizing an increase in rates sufficient to recover such investment or costs. Regulatory lag can be mitigated to some extent by the incorporation of reasonably expected forward-looking information into an authorization of increased rates. However, there is no protection against unexpected inflation and increased interest rates. See "Regulatory Matters" for additional discussion of the general rate cases.

**<u>Regulator</u><u>y Matters</u>**

***General Rate Cases***

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•seek recovery of operating costs and capital investments, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•seek the opportunity to earn reasonable returns as allowed by regulators.

The assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.

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***AVISTA CORPORATION***

***<u>Avista Utilities</u>***

***Washington General Rate Cases***

*2024 General Rate Cases*

In December 2024, the WUTC issued orders related to our multi-year electric and natural gas general rate cases filed with the WUTC in January 2024.

The approved rates within the orders were designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $44 million (or 7.5 percent) for Rate Year 2. The difference in approved rates for Rate Year 1 and those included in our original request of $77 million is primarily due to a $56 million decrease in power supply costs compared to those set forth in the original request, and also due to a lower approved return on equity than requested. The Rate Year 2 increase represents the effective increase to customers resulting from the $69 million approved in the order, partially offset by a $25 million decrease due to the expiration of a separate tariff in effect during Rate Year 1 to collect remaining Colstrip expenses by December 31, 2025 (see further discussion below).

The approved rates were also designed to increase annual natural gas base revenues by $14 million (or 11.2 percent), effective January 1, 2025, and $4 million (or 2.8 percent) for Rate Year 2.

The WUTC approved an ROE of 9.8 percent, based on a common equity ratio of 48.5 percent, and an ROR of 7.32 percent.

The WUTC did not approve our request to modify the ERM under which differences between actual net power supply costs and the amount reflected in base retail customer rates are tracked. Our actual net power supply costs exceeded the amount reflected in base retail customer rates by $78 million in 2025, and we expect actual net power supply costs to significantly exceed the level included in base rates in 2026. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings. See Note 23 for further details of the ERM and other power cost deferrals and recovery mechanisms.

The Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.

*2026 General Rate Cases*

On January 16, 2026, we filed an MYRP with the WUTC. The MYRP requests base rate relief over four years designed to produce the additional base revenues shown below (dollars in millions):

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| Rate Year | Rates Effective | Electric | Electric | Natural Gas | Natural Gas |
| 1 | 2027 | $111 | 13.9% | $12 | 4.7% |
| 2 | 2028 | 43 | 4.7% | 7 | 2.4% |
| 3 | 2029 | 34 | 3.5% | 6 | 2.1% |
| 4 | 2030 | 28 | 2.8% | 3 | 1.1% |

---

We requested an overall rate of return in 2027 of 7.5 percent, with a 48.5 common equity ratio and a 10.2 percent return on equity. We requested an increase to the overall rate of return in 2029 to 7.67 percent, with a 48.5 common equity ratio and 10.5 percent return on equity.

Key drivers of the revenue requirement in rate year one (2027) are outlined below (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | Electric | Natural Gas |
| Electric resource costs | $46 | $— |
| Capital additions | 29 | 5 |
| Employee benefits | 7 | 1 |
| Insurance | 7 |  |
| Regulatory amortizations | 5 | 4 |
| Wildfire | 4 |  |
| Other | 13 | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $111 | $12 |

---

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***AVISTA CORPORATION***

In the MYRP, we propose certain changes to the calculation of authorized baseline power supply costs. These changes are designed to address the changing market dynamics which have led to significant volatility in actual power supply costs. The MYRP provides updates to our baseline power supply cost for rate years one and two; as required by Washington law, baseline power supply costs for rate years 3 and 4 will be established in later filings and as such are not included in the additional revenue requirements for those years shown above. In addition, we are proposing changes to the timing for recovery of costs deferred under the Energy Recovery Mechanism.

In addition to requesting re-approval of existing insurance, wildfire, and decoupling deferral accounts, we are proposing an additional deferral mechanism for costs associated with employee benefits.

Washington law requires utilities to file MYRPs of a minimum of two and up to four years. The law allows utilities filing a rate plan of 3 or 4 years the option to file a new rate plan for the third year and fourth year. Under this provision, we have the opportunity to address the numerous unpredictable factors that could materially affect our financial position over a longer-term rate plan. These risks include, but are not limited to, inflation, interest rate volatility, labor and benefits challenges, escalating capital costs, and other unforeseen cost drivers. See "Item 1A: Risk Factors" for a full discussion of these factors.

The WUTC has up to eleven months to review the general rate case filings and issue a decision.

*Colstrip Tariff*

In 2019, the Washington State Legislature passed the CETA, which, among other things, requires costs associated with coal-fired generation facilities to be removed from rates no later than December 31, 2025. The WUTC order approving the settlement of the 2022 general rate cases, required us to establish a tracker for our Colstrip-related costs, including operating and maintenance expense, depreciation and amortization expense, and a return on rate base. In October 2024, we filed a cost recovery tariff seeking to recover the costs associated with our ownership of Colstrip in 2025. In the filing, we requested an increase in annual Colstrip tariff revenues of $19 million – from $24 million in 2024 to $43 million in 2025, effective January 1, 2025. In its review, WUTC Staff raised concerns related to (1) whether forecasted 2025 investments are allowed in rates; (2) whether the capital investment included in the filing will be used and useful for customers prior to the end of 2025; and (3) one major capital investment that will not be in service until 2027. In December 2024, the WUTC allowed our filed tariff to go into effect, but set the rates as subject to refund. A final order was issued in December 2025, which determined that certain investments in Colstrip were not used or useful to our customers after December 31, 2025, and as such should be prorated or disallowed. As a result, we are required to issue a refund to customers of $9 million, either in a lump sum or spread over up to three months. We are required to file a compliance filing by March 31, 2026 detailing the 2025 Colstrip investments and customer refunds.

***Idaho General Rate Cases***

*2023 General Rate Cases*

In August 2023, the IPUC approved the multi-party settlement agreement designed to increase annual base electric revenues by $22 million, or 8.0 percent, effective in September 2023, and $4 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1 million, or 2.7 percent, effective in September 2023, and a negligible increase effective in September 2024.

The settlement was based on an ROE of 9.4 percent, with a common equity ratio of 50 percent, and an ROR of 7.19 percent.

*2025 General Rate Cases*

In August 2025, the IPUC approved the all-party settlement agreement designed to increase annual base electric revenues by $20 million, or 6.3 percent, effective September 2025, and $15 million, or 4.5 percent, effective September 2026. For natural gas, the agreement was designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026.

The settlement was based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent.

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***AVISTA CORPORATION***

***Oregon General Rate Cases***

*2024 General Rate Case*

In May 2025, the OPUC approved the all-party settlement agreement designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.

To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period.

*Future Oregon General Rate Cases*

In July 2025, the Governor of Oregon signed House Bill 3179 into law which modifies certain provisions of law that relate to general rate case filings and cost recovery. The law, among other things, extends the length of time for the commission to suspend rates from a proposed effective date from nine to ten months, does not allow residential rate increases of any kind between November 1 and March 31, does not allow new rates to take effect from a proceeding where the return on equity is at issue within eighteen months of the prior rate effective date, authorizes (but does not require) securitization of "capital investments" that will cause rates to "rise by more than five percent" under specific circumstances, and calls for the OPUC to establish rules requiring utilities to establish a multiyear rate plan for rate revisions where a company's return on equity is reviewed. Such rate plans must be no less than three years and no more than seven years in length. Rulemakings to institute these provisions started in September 2025 and will continue through 2026. We are analyzing the possible effects of this legislation, including how it will impact the timing of future rate case filings.

***Power Cost Deferrals, Decoupling, Earnings Sharing Mechanisms, and Purchased Gas Adjustments*** 

See "Note 23 of the Notes to Consolidated Financial Statements" for discussion of these regulatory mechanisms.

***<u>Alaska Electric Light and Power Company</u>***

*2022 General Rate Case*

In August 2023, the RCA issued a final order related to AEL&P's electric general rate case, which was originally filed in July 2022.

The order reflected an ROE of 11.45 percent, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. AEL&P is required to file its next general rate case by August 2027.

**<u>Results of Opera</u><u>tions - Overall</u>**

The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P and the other businesses) that follow this section.

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***AVISTA CORPORATION***

***2025 compared to 2024***

The following graph shows the total change in net income for 2025 to 2024, as well as the various factors that caused such change (dollars in millions):

![img175228948_4.jpg](img175228948_4.jpg)

Utility revenues increased as a result of the effects of general rate cases and customer and load growth. This was partially offset by decreased wholesale revenues associated with decreased electric sale prices, as well as decreases in natural gas rates associated with the PGA regulatory mechanism, which do not impact utility margin or net income. Additionally, the increase in electric revenue was partially offset by a refund to be issued to customers for adjustments related to Colstrip investments. See "Regulatory Matters" for further details regarding the Colstrip final order.

Electric utility resource costs decreased primarily due to decreased purchased power costs associated with decreased wholesale prices, as well as decreased amortizations of previously deferred costs. Electric utility resource costs also decreased due to the effects of the Washington general rate case and a lower level of authorized power supply costs resulting in increased deferrals of power supply costs. Natural gas utility resource costs decreased due to decreased commodity prices, as well as decreased amortization of previously deferred PGA costs. These decreases were offset by an increase in the amortization of costs associated with the CCA that are being recovered from customers.

Utility operating expenses increased due to increased employee salaries and benefits costs. In addition, net amortizations and deferrals associated with wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to net income.

Utility depreciation and amortization increased primarily due to additions to utility plant.

Income tax expense increased primarily due to the decrease in tax customer credits which offset the bill impact of rate increases included in our prior general rate cases. Income tax expense also increased due to increased pre-tax net income compared to the prior year. See "Note 13 of the Notes to Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The decrease in earnings related to other is primarily due to increased net investment losses compared to the prior year. In addition, non-utility operating expenses increased due to updated estimates for an existing environmental remediation liability at one of our subsidiaries, which resulted in a pre-tax expense of $3 million in 2025.

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***AVISTA CORPORATION***

**<u>Non-GAAP Finan</u><u>cial Measures</u>**

The following discussion for Avista Utilities includes two financial measures that are considered "non-GAAP financial measures," electric utility margin and natural gas utility margin. In the AEL&P section, we also include a discussion of electric utility margin.

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 24 of the Notes to Consolidated Financial Statements."

The presentation of electric utility margin and natural gas utility margin is intended to enhance understanding of our operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each portion of our business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.

**<u>Results of Operations</u> <u>- Avista Utilities</u>**

**<u>Resource Optimization</u>**

We engage in resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions, which is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of electric capacity and energy and fuel for electric generation, purchases and sales of natural gas to optimize use of pipeline and storage capacity, as well as derivative transactions related to capacity, energy, fuel and fuel transportation. See Item 1. "Business - Avista Utilities - Electric Operations - General" and "Business - Avista Utilities - Natural Gas Operations - General".

We typically enter into multiple transactions simultaneously to capture value. Even though these transactions are considered together when determining the net impact, they are recorded in separate items within components of utility operating revenue and resource costs and can cause fluctuations in each item. Gains and losses on derivative contracts are included in certain line items below (such as wholesale sales and purchases of power and natural gas, sales of fuel, and other fuel costs). The ERM, PCA and PGAs are based on net supply costs and consider all transactions related to resource procurement and optimization (both physical and financial).

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***AVISTA CORPORATION***

***2025 compared to 2024***

***Utility Operating Revenues***

The following graphs present Avista Utilities' electric operating revenues and MWh sales for 2025 and 2024, respectively (dollars in millions and MWhs in thousands):

![img175228948_5.gif](img175228948_5.gif)

(1)This balance includes public street and highway lighting, which is considered part of retail electric revenues, and deferrals/amortizations to customers related to federal income tax law changes.

Total electric operating revenues in the graph above include intracompany sales of $3 million and $4 million for 2025 and 2024, respectively.

![img175228948_6.gif](img175228948_6.gif)

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***AVISTA CORPORATION***

The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility electric operating revenues for the years ended December 31 (dollars in millions):

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| | | |
|:---|:---|:---|
|  | Electric Decoupling Revenues | Electric Decoupling Revenues |
|  | 2025 | 2024 |
| Current year decoupling deferrals (a) | $— | $5 |
| Amortization of prior year decoupling deferrals (b) | (1) | 18 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total electric decoupling revenue | $(1) | $23 |

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(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total electric revenues increased $43 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $122 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $90 million), and an increase in total MWhs sold (increased revenues $32 million).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•retail rates increased mainly due to the effects of our general rate cases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•retail sales volumes increased primarily due to customer growth.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $38 million decrease in wholesale electric revenues due to decreases in prices in the wholesale market (decreased revenues $68 million), partially offset by an increase in sales volumes (increased revenues $30 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $24 million decrease in electric decoupling revenue, primarily due to decreases of amortizations of prior year rebate balances compared to 2024. In addition, deferrals of surcharge balances decreased compared to 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $23 million decrease in other electric revenues, primarily resulting from a $9 million refund to be issued to customers for adjustments related to Colstrip investments, as well as decreased transmission and REC revenues.

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***AVISTA CORPORATION***

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for 2025 and 2024, respectively (dollars in millions and therms in thousands):

![img175228948_7.gif](img175228948_7.gif)

(1)This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues, and deferrals/amortizations to customers related to federal income tax law changes.

Total natural gas operating revenues in the graph above include intracompany sales of $9 million and $16 million for 2025 and 2024, respectively.

![img175228948_8.gif](img175228948_8.gif)

The following table presents the current year decoupling deferrals and the amortization of prior year decoupling balances reflected in natural gas operating revenues for the years ended December 31 (dollars in millions):

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| | | |
|:---|:---|:---|
|  | Natural Gas Decoupling Revenues | Natural Gas Decoupling Revenues |
|  | 2025 | 2024 |
| Current year decoupling deferrals (a) | $30 | $15 |
| Amortization of prior year decoupling deferrals (b) | (6) | (3) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total natural gas decoupling revenue | $24 | $12 |

---

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***AVISTA CORPORATION***

(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total natural gas revenues decreased $22 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $53 million decrease in retail natural gas revenues (including industrial, which is included in other) due to decreased retail rates (decreased revenues $43 million) and decreased sales volumes (decreased revenues $10 million). Retail rates decreased due to PGA rate decreases (which do not impact utility margin), partially offset by the effects of our general rate cases and net rate increases associated with the CCA. Residential use per customer decreased 5 percent and commercial use per customer decreased 4 percent compared to 2024 due to warmer weather in the fourth quarter.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $9 million decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues $10 million), partially offset by an increase in prices in the wholesale market (increased revenues $1 million).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $12 million increase in decoupling revenues primarily due to increased surcharge deferrals in the current year resulting from lower customer usage.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $27 million increase in other natural gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize the deferred revenues as they are passed on to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail rates, resulting in no impact to utility margin, and a provision for earnings sharing related to natural gas operations in Washington, which resulted in a refund to be issued to customers.

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***AVISTA CORPORATION***

***Utility Resource Costs***

The following graph presents Avista Utilities' electric resource costs for 2025 and 2024, respectively (dollars in millions):

![img175228948_9.gif](img175228948_9.gif)

Total electric resource costs in the graph above include intracompany resource costs of $9 million and $16 million for 2025 and 2024, respectively.

Total electric resource costs decreased $69 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $12 million decrease in power purchased due to a decrease in prices in the wholesale market (decreased costs by $51 million), partially offset by an increase in the volume of power purchases (increased costs by $39 million). Prices during the first quarter of 2024 were elevated due to extreme cold temperatures in our region that created capacity constraints.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $58 million decrease in other electric resource costs, primarily related to an increase in deferred costs, as well as a decrease in the amortization of previously deferred costs. The increase in deferred costs was primarily due to the effects of the Washington general rate case and a lower level of authorized power supply costs. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).

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***AVISTA CORPORATION***

The following graph presents Avista Utilities' natural gas resource costs for 2025 and 2024, respectively (dollars in millions):

![img175228948_10.gif](img175228948_10.gif)

Total natural gas resource costs in the graph above include intracompany resource costs of $3 million and $4 million for 2025 and 2024, respectively.

Total natural gas resource costs decreased $44 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $24 million decrease in natural gas purchased due to a decrease in the volume of purchases (decreased costs by $14 million) and a decrease in prices of natural gas in the wholesale market (decreased costs by $10 million).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•a $20 million decrease in other costs, primarily due to a decrease in amortizations of previously deferred costs under our PGAs, partially offset by increased amortization of costs associated with the CCA that were recovered from customers (resulting in no impact to utility margin) and an increase in costs related to our customer assistance payment programs (low-income rate assistance and demand side management).

***Utility Margin***

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 24 of the Notes to Consolidated Financial Statements", to the Non-GAAP financial measure utility margin for the years ended December 31 (dollars in millions):

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Electric | Electric | Natural Gas | Natural Gas | Intracompany | Intracompany | Total | Total |
|  | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 |
| Operating revenues | $1344 | $1301 | $584 | $606 | $(12) | $(20) | $1916 | $1887 |
| Resource costs | 413 | 482 | 288 | 332 | (12) | (20) | 689 | 794 |
| Utility margin | $931 | $819 | $296 | $274 | $— | $— | $1227 | $1093 |

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Electric utility margin increased $112 million and natural gas utility margin increased $22 million.

Electric utility margin increased primarily due to the effects of general rate cases, customer growth, and non-decoupled load growth, partially offset by a $9 million refund to be issued to customers for adjustments related to Colstrip investments. See "Regulatory Matters" for further details regarding the Colstrip final order. Natural gas utility margin increased primarily due to the effects of general rate cases.

In 2025 and 2024, we had a pre-tax expense under the ERM of $14 million and $8 million, respectively. The increase is due to the lower level of base net power supply costs established in the most recent Washington general rate case.

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***AVISTA CORPORATION***

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are included in the separate results for electric and natural gas presented above.

**<u>Results of Operations - Alaska E</u><u>lectric Light and Power Company</u>**

***2025 compared to 2024***

Net income for AEL&P was $6 million for 2025, compared to $8 million for 2024.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in millions):

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| | | |
|:---|:---|:---|
|  | Electric | Electric |
|  | 2025 | 2024 |
| Operating revenues | $47 | $50 |
| Resource costs | 2 | 4 |
| Utility margin | $45 | $46 |

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Utility margin decreased in 2025 primarily due to lower sales volumes. The decrease in utility margin resulted in a decrease in net income in 2025 compared to 2024. Utility margin is a non-GAAP financial measure. See "Non-GAAP Financial Measures" above.

**<u>Results of Operations</u> <u>- Other Businesses</u>**

***2025 compared to 2024***

Our other businesses had a net loss of $14 million for 2025 compared to a net loss of $7 million for 2024. The fluctuation in results is primarily related to higher net investment losses. Approximately 75 percent of investment losses in 2025 were related to investments in clean technology. That sector was negatively impacted by shifting public policy and sentiment, leading to decreased valuations of underlying holdings in these investments. Approximately 25 percent of investment losses in 2025 were due to dilution of our ownership percentage resulting from issuance of new shares.

In 2025, we updated our estimates for an existing environmental remediation liability at one of our subsidiaries, which resulted in a pre-tax expense of $3 million.

**<u>Accounting Standards to be Adopted in 2026</u>**

We are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2026. For more information on accounting standards expected to be adopted in future periods, see "Note 2 of the Notes to the Consolidated Financial Statements".

**<u>Critical Accounting Po</u><u>licies and Estimates</u>**

The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•***Regulatory accounting***, in accordance with ASC Topic 980, *Regulated Operations*, among other things, requires that costs and/or obligations that, in our judgment, are probable of recovery through rates charged to customers, but are not yet reflected in rates, not be reflected in our Consolidated Statements of Income until the period in which they are reflected in rates and matching revenues are recognized. Meanwhile, these costs and/or obligations are deferred and reflected on our Consolidated Balance Sheets as regulatory assets or liabilities. We generally receive regulatory orders before deferring costs as regulatory assets and liabilities; however, in certain instances in which

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***AVISTA CORPORATION***

we have regulatory precedent, we may not request an order before deferring the costs. If, due to changed circumstances, we no longer met the criteria to apply regulatory accounting or if we were no longer allowed to recover these costs, we would be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See "Notes 1, 4 and 23 of the Notes to Consolidated Financial Statements" for further discussion of our regulatory accounting policy and mechanisms.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•***Pension plans and other postretirement benefit plans***, discussed in further detail below.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•***Equity investments,*** specifically valuations performed to determine the fair value of certain investment holdings, require judgment in the selection of assumptions used to estimate fair value of investments for which there is not a quoted active market price. We primarily use a market approach to determine fair value of an investment, and transactions involving comparable securities may need to be adjusted to estimate our investment's fair value. See "Notes 7 and 18 of the Notes to Consolidated Financial Statements" for further discussion of our equity investments and method for determining their fair value.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•***Contingencies,*** related to unresolved regulatory, legal and tax issues as to which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. To the extent material, we also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. However, no assurance can be given as to the ultimate outcome of any contingency. See "Notes 1 and 22 of the Notes to Consolidated Financial Statements" for further discussion of our commitments and contingencies.

***Pension Plans and Other Postretirement Benefit Plans - Avista Utilities***

We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities hired prior to January 1, 2014 and regular full-time union employees that were hired prior to January 1, 2024. See "Note 12 of the Notes to Consolidated Financial Statements" for further discussion of these individual plans.

Pension cost (including the SERP) was $11 million for 2025, $7 million for 2024 and $9 million for 2023. Of our pension cost (excluding the SERP), approximately 55 percent is expensed and 45 percent is capitalized consistent with labor charges. The cost related to the SERP is expensed. Our cost for the pension plan is determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension cost is affected by among other things:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•employee demographics (including age, compensation and length of service by employees),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the amount of cash contributions to the pension plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the actual return on pension plan assets,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•expected return on pension plan assets,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•discount rate used in determining the projected benefit obligation and pension costs,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•assumed rate of increase in employee compensation,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•life expectancy of participants and other beneficiaries, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•expected method of payment (lump sum or annuity) of pension benefits.

We make estimates and assumptions as to many of these factors. In accordance with accounting standards, changes in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statements of Income, but we generally recognize the change in future years over the remaining average service period of

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***AVISTA CORPORATION***

pension plan participants. As such, our cost recorded in a period may not reflect the actual level of cash benefits provided to pension plan participants.

We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to the expected payout of pension benefits.

The expected long-term rate of return on plan assets is reset or confirmed annually based on past performance and economic forecasts for the types of investments held by our plan.

The following chart reflects the assumptions used each year for the pension discount rate (exclusive of the SERP), the expected long-term return on plan assets and the actual return on plan assets and their impacts to the pension plan associated with the change in assumption (dollars in millions):

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| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| **Discount rate (exclusive of SERP)** |  |  |  |
| Pension discount rate | 5.96% | 6.13% | 5.86% |
| Increase/(decrease) to projected benefit obligation | $11 | $(17) | $14 |
| **Return on plan assets (a)** |  |  |  |
| Expected long-term return on plan assets | 7.40% | 7.80% | 8.30% |
| Increase/(decrease) to pension costs | $2 | $3 | $(13) |
| Actual return on plan assets, net of fees | 13.20% | 7.30% | 15.00% |
| Actual gain (loss) on plan assets | $80 | $42 | $79 |

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(a)The SERP has no plan assets. The plan assets in this disclosure are for the pension plan only.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in millions):

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| | | | |
|:---|:---|:---|:---|
| Actuarial Assumption | Change in<br>Assumption | Effect on Projected<br>Benefit Obligation | Effect on<br>Pension Cost |
| Expected long-term return on plan assets | (0.5)% | $—<br> \* | $3 |
| Expected long-term return on plan assets | 0.5% | —<br> \* | (3) |
| Discount rate | (0.5)% | 33 | 3 |
| Discount rate | 0.5% | (30) | (3) |

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\* Changes in the expected return on plan assets would not affect our projected benefit obligation.

We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service.

**<u>Liquidity and Ca</u><u>pital Resources</u>**

**<u>Overall L</u><u>iquidity</u>**

Avista Corp.'s consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for Avista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows from Avista Utilities include the purchase of power, emissions allowances, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.

We design operating and capital budgets to control operating costs and to direct capital expenditures to projects that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction and improvement of utility facilities.

Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time-to-time, we need to access capital markets to fund these needs as well as fund maturing debt. See further discussion at "Capital Resources."

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***AVISTA CORPORATION***

We regularly file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns.

We have regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, when power and natural gas costs exceed the levels currently recovered from customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from customers under base rates include, but are not limited to, higher prices in wholesale markets and/or an increased need to purchase power in the wholesale markets, and a lack of regulatory approval for higher authorized net power supply costs. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•reduced snowpack and/or lower streamflows for hydroelectric generation (due to lower precipitation and/or warmer weather or extreme cold weather),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increases in demand (due to either weather or customer growth),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•unplanned outages at generating facilities, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•failure of third parties to deliver on energy or capacity contracts.

In addition to the above, we enter into derivative instruments to hedge exposure to certain risks, including fluctuations in commodity prices and foreign exchange rates (for purposes of issuing long-term debt in the future). These derivative instruments periodically require the posting of collateral (in the form of cash or letters of credit) or other credit enhancements or to reduce or terminate a portion of the contract through cash settlement, in the event of a downgrade in our credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against our cash on hand and credit facilities. See "Enterprise Risk Management – Credit Risk Liquidity Considerations" below.

Material contractual obligations that demand cash arise in the normal course of business including energy purchase contracts and contractual obligations related to generation facilities and transmission and distributions services. See "Note 14 of the Notes to Consolidated Financial Statements" for additional information related to these contractual obligations.

Additional demands for cash include payments of borrowings and interest payments (see "Notes 15-17 of the Notes to Consolidated Financial Statements"), lease obligations (see "Note 5 of the Notes to Consolidated Financial Statements"), pension and other postretirement benefit plan contributions (see "Note 12 of the Notes to Consolidated Financial Statements") and investment fund commitments (see "Note 6 of the Notes to Consolidated Financial Statements").

See discussion in "Capital Resources" below for available liquidity under our credit facilities. With our available liquidity under these agreements, we believe that we have adequate liquidity to meet our needs for the next 12 months.

**<u>Review of Consolidate</u><u>d Cash Flow Statement</u>**

***2025 compared to 2024***

**<u>Consolidated Operating Activities</u>**

Net cash provided by operating activities was $469 million for 2025 compared to $534 million for 2024. The decrease in net cash provided by operating activities primarily relates to a $158 million decrease in net power and natural gas cost deferrals and amortizations compared to 2024, primarily due to increased deferred power supply costs, as well as decreased amortizations associated with our PGAs. This decrease was partially offset by a $61 million increase associated with net amortizations and deferrals of other regulatory assets and liabilities, including increased CCA amortizations as costs were recovered from customers.

**<u>Consolidated Investing Activities</u>**

Net cash used in investing activities was $564 million for 2025, an increase compared to $539 million for 2024. During 2025, we paid $570 million for utility capital expenditures, compared to $533 million for 2024.

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***AVISTA CORPORATION***

**<u>Consolidated Financing Activities</u>**

Net cash provided by financing activities was $84 million for 2025 compared to $0 million for 2024. The increase in financing cash flows was primarily the result of a $140 million of long-term debt issuances in 2025, compared to $84 million issued in 2024, and $78 million of common stock issued in 2025 compared to $68 million in 2024. We also increased our short-term borrowings by $33 million in 2025, compared to $5 million in 2024.

**<u>Capital R</u><u>esources</u>**

***Capital Structure***

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of December 31, 2025 and 2024 (dollars in millions):

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| | | | | |
|:---|:---|:---|:---|:---|
|  | December 31, 2025 | December 31, 2025 | December 31, 2024 | December 31, 2024 |
|  | Amount | Percent<br>of total | Amount | Percent<br>of total |
| Current portion of long-term debt and leases | $9 | 0.1% | $8 | 0.1% |
| Short-term borrowings | 388 | 6.5% | 354 | 6.2% |
| Long-term debt to affiliated trusts | 52 | 0.9% | 52 | 0.9% |
| Long-term debt and leases | 2846 | 47.4% | 2711 | 47.4% |
| &nbsp;&nbsp;&nbsp;&nbsp;Total debt | 3295 | 54.9% | 3125 | 54.7% |
| Total Avista Corporation shareholders' equity | 2709 | 45.1% | 2591 | 45.3% |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $6004 | 100.0% | $5716 | 100.0% |

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Our shareholders' equity increased $118 million during 2025 primarily due to net income and the issuance of common stock, partially offset by dividends paid.

We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.

***Short-Term Borrowings***

*Avista Corp.*

Avista Corp. has a committed line of credit in the total amount of $500 million and an expiration date of June 2029, with the option to extend for an additional one-year period (subject to customary conditions). Avista Corp. also has a continuing letter of credit agreement in the aggregate amount of $50 million, and either party may terminate the agreement at any time.

The following table summarizes the balances outstanding and available liquidity as of December 31, 2025 (dollars in millions):

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| | | | | |
|:---|:---|:---|:---|:---|
|  | Aggregate Amount | Amount Outstanding | Letters of Credit Outstanding (1) | Available Liquidity |
| Line of credit expiring June 2029 | $500 | $385 | $5 | $110 |
| Letter of credit facility | 50 | N/A | 14 | 36 |
| &nbsp;&nbsp;Total | $550 | $385 | $19 | $146 |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Letters of credit are not reflected on the Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.

The Avista Corp. credit facilities 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 some cases other obligations. The committed line of credit also includes a covenant which does not permit our ratio of "consolidated total debt" to "consolidated total capitalization" to be greater than 65 percent at any time. As of December 31, 2025, we complied with this covenant with a ratio of 54.9 percent.

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***AVISTA CORPORATION***

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the year ended December 31 (dollars in millions):

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| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| **$500 million line of credit, expiring June 2029** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Maximum balance outstanding during the year | $400 | $350 |
| &nbsp;&nbsp;&nbsp;&nbsp;Average balance outstanding during the year | 298 | 270 |
| &nbsp;&nbsp;&nbsp;&nbsp;Average interest rate during the year | 5.35% | 6.26% |
| &nbsp;&nbsp;&nbsp;&nbsp;Average interest rate at end of year | 4.84% | 5.52% |

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*AEL&P*

AEL&P has a $25 million committed line of credit with an expiration date in June 2028. As of December 31, 2025, there was $3 million outstanding at an average interest rate of 5.33 percent, and $22 million of available liquidity under this line of credit.

The AEL&P credit facility contains customary covenants and default provisions including 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 obligation) to be greater than 67.5 percent at any time. As of December 31, 2025, AEL&P complied with this covenant with a ratio of 50.0 percent.

As of December 31, 2025, Avista Corp. and its subsidiaries complied with the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a "significant subsidiary" as defined in Avista Corp.'s committed line of credit.

***Long-Term Debt***

In July 2025, the Company issued and sold $120 million of 6.18 percent first mortgage bonds due in 2055 with institutional investors in the private placement market.

The net proceeds from the sale of the bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit.

In July 2025, AEL&P entered into a term loan agreement in the amount of $20 million with an interest rate of 5.49 percent and a maturity date of July 2030. AEL&P borrowed the entire $20 million available under the agreement, and used the net proceeds to repay borrowings outstanding under AEL&P's committed line of credit, as well as fund capital expenditures.

***Common Stock***

We issued common stock in 2025 for total net proceeds of $78 million. Most of the stock was issued through our sales agency agreements under which we may offer and sell new shares of our common stock from time to time through our sales agents, with the balance related to compensation plans. In 2025, 2.0 million shares were issued under these agreements and plans.

***2026 Liquidity Expectations***

During 2026, we expect to issue up to $230 million of long-term debt and up to $90 million of common stock to fund planned capital expenditures.

After considering the expected issuances of long-term debt and common stock during 2026, we expect net cash flows from operating activities, together with cash available under our credit facilities, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

***Limitations on Issuances of Preferred Stock and First Mortgage Bonds***

We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2025, we could issue $2.0 billion of preferred stock at an assumed dividend rate of 6.50 percent. We are not planning to issue preferred stock.

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***AVISTA CORPORATION***

See "Note 16 of the Notes to Consolidated Financial Statements" for discussion of first mortgage bonds issuance limits.

**<u>Utility Capita</u><u>l Expenditures</u>**

*Avista Utilities*

We make capital investments to enhance service and system reliability for customers, replace aging infrastructure and serve increased demand. Actual capital expenditures for Avista Utilities for the year ended December 31, 2025 was $553 million.

The following graph shows Avista Utilities' expected capital expenditures for 2026-2030 by category (in millions):

![img175228948_11.jpg](img175228948_11.jpg)

These estimates include expenditures for the new projects listed within "Item 7. Management's Discussion and Analysis – Executive Overview - 2025 Request for Proposal (RFP)." However, these estimates do not include potential expenditures that could result from integrating a new large load customer, incremental transmission projects like regional grid expansion, or additional generation.

*AEL&P*

The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2025 (dollars in millions):

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| | |
|:---|:---|
| **2025 Actual capital expenditures** |  |
| Capital expenditures | $17 |
| **Expected future annual capital expenditures (by year)** |  |
| 2026 | $17 |
| 2027 | 16 |
| 2028 | 11 |

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***AVISTA CORPORATION***

Avista Utilities and AEL&P's estimates of capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

**<u>Non-Regulated Investments</u>**

We make investments at our other businesses including those related to economic development projects in our service territory that demonstrate the latest energy and environmental building innovations and house several local college degree programs. In addition, we make investments in emerging technology companies, venture capital funds, and other business ventures. The following table summarizes our actual and expected investments at our other businesses as of and for the year ended December 31, 2025 (dollars in millions):

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| | |
|:---|:---|
|  | Other |
| **2025 Actual investments** |  |
| Investment expenditures | $4 |
| **Expected future annual investments (by year)** |  |
| 2026 | $7 |
| 2027 | 6 |
| 2028 | 6 |

---

These estimates of investments are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions or strategic plans.

See "Liquidity" for information regarding other material cash requirements for 2026 and thereafter.

**<u>Pensio</u><u>n Plan</u>**

We contributed $10 million to the pension plan in 2025. We expect to contribute a total of $50 million to the pension plan in the period 2026 through 2030, with an annual contribution of $10 million.

The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.

See "Note 12 of the Notes to Consolidated Financial Statements" for additional information regarding the pension plan.

**<u>Credit</u> <u>Ratings</u>**

Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See "Enterprise Risk Management – Credit Risk Liquidity Considerations" and "Note 8 of the Notes to Consolidated Financial Statements."

The following table summarizes our credit ratings as of February 24, 2026:

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| | | |
|:---|:---|:---|
|  | Standard & Poor's (1) | Moody's (2) |
| Corporate/Issuer rating | BBB | Baa2 |
| Senior Secured Debt | A- | A3 |
| Senior Unsecured Debt | BBB | Baa2 |

---

(1)Standard & Poor's lowest "investment grade" credit rating is BBB-.

(2)Moody's lowest "investment grade" credit rating is Baa3.

A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services.

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***AVISTA CORPORATION***

**<u>Divid</u><u>ends</u>**

See "Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities" for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends.

**<u>Compet</u><u>ition</u>**

Our electric and natural gas distribution utility business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a "cost of service" basis. In theory, rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity to earn a reasonable return on investment as allowed by our regulators.

In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. We have service territory agreements with certain rural electric cooperatives and public utility districts, approved in applicable jurisdictions, to set forth conditions under which one or the other utility will provide service to customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, and energy storage, may also compete for sales to existing customers. Advances in power generation, energy efficiency, energy storage and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition, possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings.

Customers may have a choice in the future over the sources from which to receive their energy. To effectively compete for our customers in the future, we continue to strive to create value through product and service offerings. We are also attempting to enhance the effectiveness and ease of our customer interactions by tailoring internal initiatives to focus on choices for customers to increase their overall satisfaction with the Company.

Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell.

In wholesale markets, competition for available electric supply is influenced by the:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•localized and system-wide demand for energy,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•type, capacity, location and availability of generation resources, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•variety and circumstances of market participants.

These wholesale markets are regulated by the FERC, which requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, enlarge or construct additional transmission capacity for the purpose of providing these services, and transparently price and offer transmission services without favor to any party, including the merchant functions of the utility.

Participants in the wholesale energy markets include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•other utilities,

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•federal power marketing agencies,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•energy marketing and trading companies,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•independent power producers,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•financial institutions, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•commodity brokers.

**<u>Environmental Issues and Contingencies</u>**

We are subject to environmental regulation by federal, state, tribal and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests or which we may need to acquire or develop are subject to environmental laws, regulations and rules relating to construction permitting, air quality and emissions, water quality, fisheries, wildlife, endangered species, avian interactions, wastewater and stormwater discharges, waste handling, natural resource protection, historic and cultural resource protection, and other similar activities. These laws and regulations require the Company to make substantial investments in compliance activities and to acquire and comply with a wide variety of environmental licenses, permits, approvals and settlement agreements. These items are enforceable by public officials and private individuals. Some of these regulations are subject to ongoing interpretation, whether administratively or judicially, and are often in the process of being modified. We conduct periodic reviews and audits of pertinent facilities and operations to enhance compliance and to respond to or anticipate emerging environmental issues. The Company's Board of Directors has established a committee to oversee environmental issues and to assess and manage environmental risk.

We monitor legislative and regulatory developments at different levels of government for environmental issues, particularly those with the potential to impact the operation of our generating plants and other assets, and our ability to provide service to natural gas customers. We continue to be subject to increasingly stringent or expanded application of environmental and related regulations from all levels of government.

Environmental laws and regulations may restrict or impact our business activities in many ways, including, but not limited to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing the operating costs of generating plants, natural gas and electric transmission and distribution facilities and other assets,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing the lead time and capital costs for the construction of new generating plants, natural gas and electric transmission and distribution facilities and other assets,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•requiring modification of existing generating plants, natural gas and electric transmission and distribution facilities,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•requiring existing generating plant, natural gas and/or operations to be curtailed or shut down,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•reducing the amount of energy available from generating plants,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•restricting the types of generating plants that can be built or contracted with,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•requiring construction of specific types of generation plants at higher cost, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•increasing costs of distributing, or limiting our ability to distribute, electricity and/or natural gas.

Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of such costs through the ratemaking process.

***Policies and Other Impacts Related to Climate Change***

Legal and policy changes responding to concerns about climate changes, and the potential impacts of such changes, could have a significant effect on our business. Direct impacts of climate changes include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year, as well as variations in temperature, and the resulting impact on the availability of hydroelectric resources at times of peak demand as

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***AVISTA CORPORATION***

well as an increased risk of wildfire and other impacts of extreme weather. Indirect impacts include, without limitation, changes in laws and regulations intended to mitigate the risk of, or alter, climate changes, including restrictions on the operation of our power generation resources and obligations or limitations imposed on the sale of natural gas. When direct or indirect impacts of climate change cause increased operational costs or capital investments, we intend to recover such costs through the ratemaking process.

***Washington Legislation and Regulatory Actions***

*Clean Energy Transformation Act*

In 2019, the Washington State Legislature passed the CETA, which effectively prohibits sales of energy produced by coal-fired generation to Washington retail customers after December 31, 2025 (with some exceptions for coal generated short-term purchases). In addition, the CETA establishes the policy of Washington State that retail sales of electricity to Washington customers must be carbon-neutral by January 1, 2030, however a utility may satisfy up to 20 percent of this requirement with specified emitting resources paired with either renewable offsets, credits and/or investments in qualifying energy transformation projects. By December 2044, 100 percent of retail sales of electricity to Washington State customers must be carbon free.

The law had direct, specific impacts on Colstrip, which were unique to the former owners of Colstrip who serve Washington customers. See "Colstrip" section and "Note 22 of the Notes to Consolidated Financial Statements" for further details on the impacts of the CETA on Colstrip and the transfer of our ownership interest in Colstrip to NorthWestern. Our hydroelectric and biomass generation facilities can be used to comply with the CETA's clean energy standards. We intend to seek recovery of costs associated with the clean energy legislation and regulations through the regulatory process.

In compliance with the CETA, we filed our first CEIP in October 2021, that was approved by the WUTC in June 2022. The CEIP's four-year compliance period of 2022-2025 proposed targets and specific actions to meet Washington State's clean energy goals and the equitable distribution of benefits and reduction of burdens to all customers. We have delivered on our commitments under the 2022-2025 CEIP.

In October 2025, the Company filed its 2025 CEIP with the WUTC in compliance with the Clean Energy Transformation Act. The CEIP proposed targets and specific actions to meet Washington State's clean energy goals and the equitable distribution of benefits and reduction of burdens to all customers.

Some highlights of the 2025 CEIP include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Updated clean energy targets: We propose increasing the amount of clean energy delivered to Washington customers from 66 percent in 2026 to 76.5 percent by 2029. The resulting projects from our 2025 RFP will contribute to reaching these targets.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Modern energy management: Between 2026 and 2029, we plan to expand demand response programs that could reduce electricity usage by up to 55 MW during peaks. The electricity reductions include projects from the RFP process described above, and may include smart thermostats, battery storage, and other tools that help customers shift or lower their energy use when demand is highest.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Energy efficiency programs: We will grow energy-saving programs to help customers use less electricity without giving up comfort or convenience.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Community engagement: The CEIP emphasizes meaningful engagement with all communities, especially named communities, which are populations disproportionately affected by environmental, financial and societal factors, among others.

*Emissions Performance Standard*

Washington applies a GHG emissions performance standard to electric generation facilities used to serve retail loads, whether the facilities are located within Washington or elsewhere. The emissions performance standard prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration to purchase energy produced by plants that have emission levels higher than 925 pounds of GHG

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***AVISTA CORPORATION***

per MWh. The Washington State Department of Commerce reviews the standard every five years. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.

*Washington Climate Commitment Act* 

The CCA, and its implementing regulations, established a cap and trade program to reduce GHG emissions and achieve the GHG limits previously established under state law. The final rules implement a cap on emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. The state issues allowances necessary to serve our Washington retail electric load; off-system wholesale sales may result in additional obligation costs. The CCA also has direct impacts on our Idaho electric operations as it applies to power that is delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is delivered to Idaho customers. Annually, the final calculated results must be certified by an independent third party and submitted to Ecology for approval. If the independent third party or Ecology disagrees with the approach or any of the calculations, it could result in a change to the number of allowances needed for compliance and could result in changes to anticipated costs for our electric operations. For Washington electric, we are allowed to defer any incremental costs associated with the CCA in accordance with our regulatory accounting order; however, in Idaho we are not allowed to recover any costs associated with CCA compliance from customers.

For our Washington natural gas operations, we have additional financial burdens associated with compliance which are being deferred and recovered from customers in accordance with our regulatory accounting order in Washington.

*Washington State Building Codes*

In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code requiring most new commercial buildings and large multifamily buildings to install all-electric space heating. An amendment to the code allows for natural gas to supplement electric heat pumps. In addition, in November 2022, the SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heat source.

Both the commercial and residential building and energy codes were the subject of legal challenges in both Washington State Superior Court (the State Action) and in the Federal District Court for the Eastern District of Washington (the Federal Action). In the Federal Action, to which the Company was a party, the plaintiffs challenged the amendments on the grounds that they were preempted by the federal Energy Policy and Conservation Act (EPCA), citing the Ninth Circuit's decision in California Restaurant Association v. Berkeley (the Berkeley Decision), which involved similar restrictions on the use of natural gas in new construction in Berkeley, California.

In May 2023, the SBCC voted to delay the effective date of the code amendments and commenced an emergency rulemaking process to evaluate additional amendments to the code in light of the Berkeley Decision. As a result of this action, in July 2023, the Federal District Court declined to issue a preliminary injunction to prevent the amendments from taking effect. The plaintiffs in the Federal Action subsequently dismissed the action, without prejudice to their ability to refile after the SBCC rulemaking process is complete.

The SBCC has since voted to approve revised residential and commercial energy regulations that continue to require new residential and commercial buildings in Washington to use electricity as the primary heat source. In light of this action, the plaintiffs in the State Action amended their complaint to challenge the new regulations. The State Action remains pending.

In May 2024, we, along with Cascade Natural Gas Corporation, Northwest Natural Gas Company, and a coalition of homebuilders, heating unit dealers and other parties, filed a lawsuit challenging the approved building codes on the grounds that they are preempted by EPCA. The lawsuit was filed in the United States District Court for the Western District of Washington. This lawsuit remains pending.

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***AVISTA CORPORATION***

In November 2024, Washington voters approved Initiative 2066, which would prohibit state and local governments from restricting access to natural gas, prohibit the SBCC from discouraging or penalizing the use of natural gas, and prohibit the WUTC from approving any multi-year rate plan that requires or incentivizes natural gas companies to terminate or limit natural gas service. In March 2025, a Washington state court held that the initiative violates the "single subject rule" and is invalid. That decision has been appealed and the appeal remains pending.

Over time, the building code changes would likely have an adverse impact on our natural gas business and natural gas customers but could also have a positive effect on our electric business. While we are in the process of studying the implications of the changes on our business, at this time we are not able to quantify the likely net effect, positive or negative, on our overall results of operations over the long term. However, the changes would clearly require that additional generating capacity be available to utilities and customers in Washington state.

***Oregon Legislation and Regulatory Actions***

*Climate Protection Plan*

In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, "Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions." The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over GHG-related matters, with the aim of reducing Oregon's overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality developing cap and reduce rules known as the CPP. The CPP, which became effective in January 2022, outlines GHG emissions reduction goals of 50 percent by 2035 and 90 percent by 2050 from the 1990 baseline. The first three-year compliance period was 2022 through 2024.

In March 2022, we, along with the utilities NW Natural and Cascade Natural Gas, filed a lawsuit requesting judicial review of the CPP. This action was subsequently consolidated with a lawsuit filed by several other parties. In December 2023, the Oregon Court of Appeals issued a decision declaring the CPP regulations invalid. The Oregon Department of Environmental Quality did not appeal the decision, but instead went back through the rulemaking process. The result of that process was a new version of the CPP that is very similar to the original. We are reviewing the new rules, and considering what legal action, if any, may be taken. To the extent the new rules impose additional compliance costs, we will seek to recover those costs through the ratemaking process.

*Emissions Performance Standard*

Oregon applies a GHG emissions performance standard to electric generation facilities, requiring that new baseload natural gas plant, non-base load natural gas plant, and non-generating facility reduce its net carbon dioxide emissions 17 percent below what the Oregon Facility Siting Council identifies as the most efficient combustion-turbine plant in the United States. The Oregon Energy Facility Siting Council issues rules periodically to update the standard, as more efficient power plants are built. The standard can be met by combination of efficiency, cogeneration, and offsets from carbon dioxide mitigation measures. We have thermal generation located in Oregon, and as such this standard applies to that facility. We intend to seek recovery of costs related to requirements through the ratemaking process.

***Clean Air Act (CAA)***

The CAA creates numerous requirements for our thermal generating plants. Kettle Falls GS, Coyote Springs and Rathdrum CT all require CAA Title V operating permits. The Boulder Park GS, Northeast CT and other operations require minor source permits or simple source registration permits. We have secured these permits and certify our compliance with Title V permits on an annual basis. These requirements can change over time as the CAA or applicable implementing regulations are amended and new permits are issued. We actively monitor legislative, regulatory and other program developments of the CAA that may impact our facilities.

***2024 EPA Regulations for Power Plants***

On April 25, 2024, the EPA released a package of final regulations addressed to electric generation facilities. These include:

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•*Greenhouse gas regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act*. This rule finalizes (a) the repeal of the Affordable Clean Energy rule; (b) guidelines for GHG emissions from existing fossil fuel-fired steam generating electric generating units; and (c) revisions to existing performance standards for new, reconstructed or heavily modified fossil fuel-fired stationary combustion turbine electric generating units. The rule is currently being challenged in the D.C. circuit, and that litigation remains pending.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•*Updated Mercury and Air Toxics Standards, pursuant to section 112 of the Clean Air Act (MATS Rule)*. The MATS Rule sets emissions limits for filterable particulate matter for coal-based generating units. The Rule reduces those limits from the standards that were originally set in 2012. The EPA has since proposed repealing the reduction in applicable limits and has granted extensions of applicable compliance deadlines for certain power plants, including Colstrip.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•*Disposal of Coal Combustion Residuals from Electric Utilities – Legacy CCR Surface Impoundments (CCR Rule)*. The CCR Rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants and CCR management units at active and inactive power plants. In January 2025, the EPA issued a revised proposed and final rule to address language inconsistencies and submittal deadlines. Likewise, in February 2026, the EPA issued a final rule providing additional time for certain compliance deadlines regarding monitoring. Along with the other owners (including the operator), we have assessed the CCR Rule and believe there will not be a material change to our asset retirement obligation for Colstrip. See Coal Ash Management/Disposal, below for further discussion of the CCR Rule as it relates to Colstrip.

These rules potentially fall within the scope of a number of Presidential executive orders that have been issued, which are discussed in more detail under "2025 Presidential Executive Action" below. In addition, a substantial number of legal challenges have been filed regarding these rules, and those lawsuits remain pending. Finally, it is likely that the decision by the EPA to revoke its 2009 Endangerment Finding, discussed below, will have an impact on the status and implementation of these rules. At the same time, we continue to analyze each of these rules to assess the impact, if any, they may have on our existing generation units. To the extent there are any additional costs associated with compliance, we will seek to recover those costs through the ratemaking process.

***EPA Endangerment Finding Revocation***

In February 2026, the EPA formally revoked its 2009 Endangerment Finding, which was a landmark determination that six key greenhouse gases, including carbon dioxide and methane, threaten the public health and welfare of current and future generations. The Endangerment Finding provided the scientific and legal foundation for federal regulation of those identified greenhouse gases, including regulation of the release of greenhouse gases from power plants and other significant emissions sources.

The action taken by the EPA to repeal the Endangerment Finding is expected to result in significant deregulation of greenhouse gas emissions, including regulation of natural gas and coal-fired power plants. It is reasonably likely that the EPA's decision will be the subject of future legal challenges, the outcome of which cannot be predicted. The precise extent of that deregulation, as well as any potential impact on the Company's operations, cannot be determined at this time.

***2025 Presidential Executive Actions***

Since taking office, the U.S. President's Administration has issued a multitude of Executive Orders directed towards national energy resources and development. These include actions to:

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•pause the disbursement of funds appropriated through the Inflation Reduction Act of 2022 or the Infrastructure and Jobs Act;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require agency review of regulations, programs and executive orders that might limit the development or use of domestic energy resources such as oil, natural gas, coal and nuclear;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•revoke the prior Administration's Executive Orders on climate policy;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require agency review of regulations, programs and executive orders that limit consumer choice for vehicles and appliances;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require review of the 2009 EPA endangerment finding for greenhouse gases under the Clean Air Act;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•direct the EPA to revise or eliminate the use of a social cost of carbon in federal decision-making;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•declare a national emergency to expedite the development of energy infrastructure;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•direct emergency action under section 202(c) of the Federal Power Act by streamlining and expediting the approval of orders allowing electric generation resources to operate at maximum capacity during times of anticipated grid failure;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•direct the United States Attorney General to identify and act against state and local laws that burden domestic energy production and may be unconstitutional, preempted by federal law, or otherwise unlawful, particularly those tied to climate change, carbon penalties or carbon cap and trade programs, and Environmental, Social and Governance policies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•restrict tax credits, tighten requirements and eliminate subsidies for wind and solar projects; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•require the incorporation of sunset provisions into regulations governing energy production.

Some of these Executive Orders are the subject of legal challenges and/or are the subject of federal court injunctions, either in whole or in part. We are assessing potential impacts, opportunities and risks that may arise from these and other executive actions that may be taken by the Administration. To the extent that any action taken by the Administration results in increased costs for our business, we will seek to recover those costs through the rate-making process.

***Other***

For other environmental issues and other contingencies see "Note 22 of the Notes to Consolidated Financial Statements."

**<u>Col</u><u>strip</u>**

Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and is owned by separate entities. Initially, we had a 15 percent ownership interest in Units 3 and 4. Due to CETA in Washington, in January 2023 we entered into an agreement with NorthWestern under which we transferred our ownership of Colstrip, effective midnight on January 1, 2026. See "Note 22 of the Notes to Consolidated Financial Statements" for further discussion of the agreement.

***Coal Ash Management/Disposal***

In 2015, the EPA issued a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash (Colstrip produces this byproduct). The CCR rule has been the subject of ongoing litigation. In August 2018, U.S. Court of Appeals for the D.C. Circuit struck down provisions of the rule. In December 2019, a proposed revision to the rule was published in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements along with existing state obligations expressed through the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling.

The AOC requires MDEQ to review Remedy and Closure plans for all parts of the Colstrip plant through an ongoing public process. The AOC also requires the Colstrip owners to provide financial assurance, primarily in the form of surety bonds, to

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secure each owner's pro rata share of various anticipated closure and remediation obligations. We are responsible for our share of two major areas: the Plant Site Area and the Effluent Holding Pond Area. Generally, the plans include the removal of boron, chloride, and sulfate from the groundwater, closure of the existing ash storage ponds, and installation of a new water treatment system to convert the facility to a dry ash storage. Our share of the posted surety bonds is $14 million. This amount is updated annually, with expected obligations decreasing over time as remediation activities are completed. The transfer of our interest in Colstrip to NorthWestern did not relieve us of these obligations.

***Colstrip Arbitration, Litigation, and Other Contingencies***

See "Note 22 of the Notes to Consolidated Financial Statements" for disputes, arbitration, litigations and other contingencies related to Colstrip. We intend to seek recovery of costs associated with Colstrip through the ratemaking process.

**<u>Enterprise Ri</u><u>sk Management</u>**

The following discussion focuses on our processes and procedures to identify and manage the principal known risks that we face. See "Item 1A: Risk Factors," "Item 1C: Cybersecurity," "Forward-Looking Statements," as well as "Environmental Issues and Contingencies."

We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance.

Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout the organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. We collect risk information across the Company, and senior management reviews the Company's major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated.

Our primary identified categories of risk exposure are:

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| | |
|:---|:---|
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Utility regulatory | • External mandates |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Operational | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Climate change | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Energy commodity |
| • Cybersecurity | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Compliance |
| • Technology | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Resource adequacy |
| • Strategic |  |

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Our primary categories of risks are described in "Item 1A. Risk Factors."

**Utility Regulatory Risk**

We have a regulatory group which seeks to mitigate regulatory risk through open communications with regulatory commissioners and staff regarding the Company's business plans and concerns. The regulatory group also considers the regulator's priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. Oversight of our regulatory strategies and policies is performed by senior management and the Board of Directors. See "Regulatory Matters" for further discussion of regulatory matters affecting the Company.

**Operational Risk**

To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from

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***AVISTA CORPORATION***

natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cybersecurity in place.

To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes a wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy below.

Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of the Board of Directors and from senior management with input from each operating department.

**Climate Change Risk**

Multiple departments work to mitigate risks related to climate change. Climate change adds uncertainty to existing risks that we have historically managed and mitigated. These efforts are reflected in electric and gas operations, investments in assets and asset reliability and resiliency across our operations.

Power Supply staff monitor items such as snowpack and broader precipitation conditions, patterns and modeled or predicted climate change. These and other assessments are incorporated into our IRP processes. Environmental Affairs, Governmental Affairs and other departments monitor policy and regulatory developments that may relate to climate change to engage these efforts constructively and prepare for compliance matters.

Our Wildfire Resiliency Plan was also developed to mitigate the increased wildfire risk associated with climate change. See "Item 1. Business - Wildfire Resiliency Plan" for further discussion of the program.

In addition, issues concerning climate-related risk and our clean energy goals are reviewed and regularly discussed by the Board of Directors. The Board's Environmental, Technology and Operations Committee regularly reviews and discusses environmental and climate related risks, and advises the full Board on critical or emerging risks and/or related policies. Likewise, the Audit Committee provides oversight of climate-related disclosures.

**Cybersecurity Risk**

See "Item 1C. - Cybersecurity" for discussion of Cybersecurity risk and processes for mitigation.

**Technology Risk**

Technology governance is led by senior management, and includes new technology strategy, risk planning and major project planning and approval. Oversight of technology risk is performed by the Board's Environmental, Technology and Operations Committee. We are dedicated to securing, maintaining and evaluating and developing our information technology systems. We evaluate our technology for obsolescence and upgrade or replace systems as necessary. The technology project management office and enterprise business performance team provide project cost, timeline and schedule oversight.

We manage Generative Artificial Intelligence (GenAI) risks through governance and policy to safeguard data and minimize operational risk. Governance and oversight is performed by a committee composed of senior management who oversee GenAI risks across cybersecurity, technology, and operational domains. This group strives to ensure alignment with our broader risk management framework, which includes approving tools, applying cross-functional risk assessments to proposed use cases, responsible use, data protection, and awareness of GenAI limitations, including risks of inaccurate or biased outputs. This committee and its members also provide updates on risk management activities and GenAI initiatives to Board Committees. Under this approach, GenAI adoption supports operational efficiency while minimizing legal, security, financial, and reputational risks.

**Strategic Risk**

Oversight of strategic risk is performed by the Board of Directors and senior management. We have a Senior Vice President, Energy Policy and Chief Strategy Officer who leads strategic initiatives, searches for and evaluates opportunities and makes recommendations to other members of senior management and the Board of Directors. We not only focus on whether opportunities are financially viable, but also consider whether these opportunities fall within our core policies and our core

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***AVISTA CORPORATION***

business strategies. We strive to mitigate reputational risk primarily through a focus on adherence to our core policies, including our Code of Conduct, maintaining an appropriate culture and tone at the top, and through communication and engagement with external stakeholders.

**External Mandates Risk**

Oversight of external mandate risk mitigation strategies is performed by the Environmental, Technology and Operations Committee of the Board of Directors and senior management. Our Environmental, Social and Governance program creates a framework that is intended to attract investment, enhancement of our brand, and promotion of sustainable long-term growth. We also have employees dedicated to actively engage and monitor federal, state and local government positions and legislative actions that may affect us or our customers.

To prevent the threat of municipalization, we work to build strong relationships with the communities we serve through, among other things:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•communicating and being involved with local business leaders and community organizations,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach, low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•tailoring internal initiatives to focus on choices for customers, to increase their overall satisfaction with the Company, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve.

**Financial Risk**

Financial risk is impacted by many factors, including regulation and rates, weather risk, access to capital markets, interest rate risk, credit risk, and foreign exchange risk. Our Treasury department monitors our daily cash position and future cash flow needs, as well as monitoring market conditions to determine the appropriate course of action for capital financing strategies. Oversight of financial risk mitigation strategies is performed by senior management and the Finance Committee of the Board of Directors.

***Regulation and Rates***

The Regulatory Affairs department is critical in mitigation of financial risk as they have regular communications with state commission regulators and staff, and they monitor and develop rate strategies. Rate strategies, such as decoupling and operating expense balancing accounts, help mitigate the impacts of revenue fluctuations due to weather, conservation or the economy.

***Weather Risk***

To partially mitigate the risk of financial under-performance due to weather-related factors, we developed decoupling rate mechanisms that were approved by the Washington, Idaho and Oregon commissions. Decoupling mechanisms are designed to break the link between a utility's revenues and consumers' energy usage and instead provide revenue based on the number of customers, thus mitigating a large portion of the risk associated with lower customer loads. See "Note 23 of the Notes to Consolidated Financial Statements" for further discussion of our decoupling mechanisms.

***Access to Capital Markets***

Our capital requirements rely to a significant degree on regular access to capital markets. We actively engage with rating agencies, banks, investors and state public utility commissions to understand and address the factors that support access to capital markets on reasonable terms. We manage our capital structure to maintain a financial risk profile that we believe will be deemed prudent. We forecast cash requirements to determine liquidity needs, including sources and variability of cash flows that may arise from spending plans or from external forces, such as changes in energy prices or interest rates. Our financial and operating forecasts consider various metrics that affect credit ratings. Our regulatory strategies include working with state public utility commissions and filing for rate changes as appropriate to meet financial performance expectations.

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***AVISTA CORPORATION***

***Interest Rate Risk***

Uncertainty about future interest rates causes risk related to a portion of existing debt, future borrowing requirements, and pension and other post-retirement benefit obligations. We manage debt interest rate risk by limiting variable rate debt to a percentage of total capitalization, monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. We may hedge a portion of our interest rate risk with derivative instruments, particularly to manage risk associated with significant concentrations of forecasted debt issuances. The Finance Committee of the Board of Directors periodically reviews and discusses interest rate risk management processes, and the steps management has undertaken to control interest rate risk. Our Risk Management Committee (RMC) also reviews the interest rate risk management plan.

The interest rate on $52 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates.

The following table shows long-term debt and related weighted-average interest rates, by expected maturity dates as of December 31, 2025 (dollars in millions):

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | Fair Value |
| Fixed rate long-term debt (1) | $— | $— | $25 | $15 | $20 | $2714 | $2774 | $2279 |
| Weighted-average interest rate |  |  | 6.37% | 5.92% | 5.49% | 4.40% | 4.43% |  |
| Variable rate long-term debt to affiliated trusts |  |  |  |  |  | $52 | $52 | $46 |
| Weighted-average interest rate |  |  |  |  |  | 4.93% | 4.93% |  |

---

(1)These balances include the fixed rate long-term debt of Avista Corp., AEL&P and AERC.

Our pension plan is exposed to interest rate risk because the value of pension obligations and other post-retirement obligations varies directly with changes in the discount rates, which are derived from end-of-year market interest rates. In addition, the value of pension investments and potential income on pension investments is partially affected by interest rates because a portion of pension investments are in fixed income securities. Oversight of pension plan investment strategies is performed by the Finance Committee of the Board of Directors, which approves investment and funding policies, objectives and strategies that seek an appropriate return for the pension plan. We manage interest rate risk associated with pension and other post-retirement benefit plans by investing a targeted amount of pension plan assets in fixed income investments that have maturities with similar profiles to future projected benefit obligations. See "Note 12 of the Notes to Consolidated Financial Statements" for further discussion of our investment policy associated with the pension plan assets.

***Credit Risk***

*Counterparty Non-Performance Risk*

We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouses and exchanges.

Counterparty non-performance risk relates to potential losses that we would incur due to non-performance of contractual obligations by counterparties to deliver energy or make financial settlements.

Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.

We seek to mitigate counterparty credit risk by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•transacting through clearinghouses and exchanges,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•entering into bilateral contracts that specify credit terms and protections against default,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•applying credit limits and duration criteria to existing and prospective counterparties,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•actively monitoring credit exposures,

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•asserting collateral rights with counterparties, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•carrying out transaction settlements timely and effectively.

The extent of transactions conducted through clearinghouses and exchanges has increased, as many market participants have shown a preference for trading through these entities and have reduced bilateral transactions. We actively monitor the collateral required by clearinghouses and exchanges to effectively manage capital requirements.

Our exposure to risks attributable to counterparties' credit profile is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk from each counterparty depends on the duration and volume of our obligations under forward contracts, unsettled transactions, interest rates and market prices, as well as other factors. There is a risk that we do not obtain sufficient additional collateral from counterparties that are unable or unwilling to provide it.

*Credit Risk Liquidity Considerations*

To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risk and demands on us for collateral. Our credit risk management process is designed to mitigate such risks through limit setting, contract protections and counterparty diversification, among other practices.

Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to enter into transactions with them for them to maintain acceptable credit exposure to us. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without unsecured credit threshold. Counterparties may seek assurances of performance in the form of letters of credit, prepayment or cash deposits.

Credit exposure can change significantly in periods of commodity price and interest rate volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

As of December 31, 2025, we had deposited as collateral cash in the amount of $12 million and letters of credit in the amount of $14 million related to energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See "Credit Ratings" for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below "investment grade" based on positions outstanding at December 31, 2025 (including contracts that meet the definition of a derivative under U.S. GAAP and those that are not accounted for as derivatives), we would potentially be required to post the following additional collateral (dollars in millions):

---

| | |
|:---|:---|
|  | December 31, 2025 |
| Additional collateral taking into account contractual thresholds (1) | $27 |
| Additional collateral without contractual thresholds | 40 |

---

(1)This amount is different from the amount disclosed in "Note 8 of the Notes to Consolidated Financial Statements" because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 8, this analysis also takes into account contractual threshold limits that are not considered in Note 8.

***Foreign Currency Risk***

A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of 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 typically settled within sixty days with U.S. dollars. We hedge a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. This risk has not had a material effect on our 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.

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***AVISTA CORPORATION***

Further information for derivatives and fair values is disclosed at "Note 8 of the Notes to Consolidated Financial Statements" and "Note 18 of the Notes to Consolidated Financial Statements."

**Energy Commodity Risk**

We mitigate energy commodity risk primarily through our energy resources risk policy, which includes oversight from the RMC and oversight from the Audit Committee and the Environmental, Technology and Operations Committee of the Board of Directors. In conjunction with the oversight committees, our management team develops hedging strategies, detailed resource procurement plans, resource optimization strategies and long-term integrated resource planning to mitigate some of the risks associated with energy commodities. The various plans and strategies are monitored daily and developed with quantitative methods.

Our energy resources risk policy includes a wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation, weather, and other factors may result in losses of earnings, cash flows and/or fair values.

We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation.

To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices.

Projected retail natural gas loads and resources are regularly reviewed by operating management and the RMC. To manage the impacts of volatile natural gas prices, we procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends into future years with the goal of reducing price volatility in natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when price spreads are favorable. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2025 that are expected to settle in each respective year (dollars in millions). As of December 31, 2025, there are no energy commodity derivative contracts outstanding with expected deliveries after 2028:

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Purchases | Purchases | Purchases | Purchases | Sales | Sales | Sales | Sales |
|  | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives |
| Year | Physical (1) | Financial (1) | Physical (1) | Financial (1) | Physical (1) | Financial (1) | Physical (1) | Financial (1) |
| 2026 | $— | $— | $(17) | $(10) | $8 | $4 | $(3) | $— |
| 2027 |  |  | (3) | (1) |  |  | (4) |  |
| 2028 |  |  |  |  |  |  | (3) |  |

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***AVISTA CORPORATION***

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2024 that were expected to settle in each respective year (dollars in millions). As of December 31, 2024, there were no energy commodity derivative contracts outstanding with expected deliveries after 2027:

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Purchases | Purchases | Purchases | Purchases | Sales | Sales | Sales | Sales |
|  | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives |
| Year | Physical (1) | Financial (1) | Physical (1) | Financial (1) | Physical (1) | Financial (1) | Physical (1) | Financial (1) |
| 2025 | $— | $— | $(23) | $(19) | $10 | $7 | $(3) | $— |
| 2026 |  |  | (9) | (3) |  |  |  |  |
| 2027 |  |  | (2) |  |  |  |  |  |

---

(1)Physical transactions represent commodity transactions in which we 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, swap derivatives, or options contracts.

The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are 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 eventually be collected through retail rates from customers.

See "Item 1. Business – Electric Operations" and "Item 1. Business – Natural Gas Operations," for additional discussion of the risks associated with Energy Commodities.

**Compliance Risk**

Compliance risk is mitigated through separate Regulatory and Environmental Compliance departments that monitor legislation, regulatory orders and actions to determine the overall potential impact and develop strategies for complying with the various rules and regulations. We also engage outside attorneys and consultants, when necessary, to help ensure compliance with laws and regulations. Oversight of compliance risk strategy is performed by senior management, including the Chief Compliance Officer, and the Environmental, Technology and Operations Committee and the Audit Committee of the Board of Directors.

See "Item 1. Business, Regulatory Issues" through "Item 1. Business, Reliability Standards" and "Environmental Issues and Contingencies" for further discussion of compliance issues that impact our Company.

**Resource Adequacy Risk**

Resource adequacy risk is managed internally through our integrated resource planning (IRP) evaluation that produces a preferred resource strategy to meet forecasted energy demand over the next twenty plus years. The IRP is conducted every two years to account for changes in assumptions such as forecasted load growth, energy market prices, climate change and other variables. If new resources are shown to be needed in the next four years, then we will initiate a competitive resource request for proposal process to procure new generating resources prior to the anticipated need. We will also hedge shorter term capacity and energy needs per our risk management policy to acquire additional generation as needed. We also participate in the Western EIM and the western resource adequacy program to reduce risk associated with near term energy and capacity needs.

External resource adequacy risk associated with regional capacity shortfalls is monitored and addressed through participation in regional coordination efforts. These efforts include participation in interregional transmission planning conducted by the western power pool, day ahead organized markets, western resource adequacy program, gas-electric coordination initiatives, joint regional transmission infrastructure projects and evaluation of joint generation projects.

**<u>ITEM 7A. QUANTITATIVE AND QUALITA</u><u>TIVE DISCLOSURES ABOUT MARKET RISK</u>**

The information required by this item is set forth in the Enterprise Risk Management section of "Item 7. Management's Discussion and Analysis" and is incorporated herein by reference.

**<u>ITEM 8. FINANCIAL STATEMEN</u><u>TS AND SUPPLEMENTARY DATA</u>**

The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page.

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***AVISTA CORPORATION***

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Avista Corporation

**Opinion on the Financial Statements**

We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in *Internal Control — Integrated Framework (2013)* issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2026, expressed an unqualified opinion on the Company's internal control over financial reporting.

**Basis for Opinion**

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

**Critical Audit Matter**

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

**Regulatory Matters - Refer to Notes 1, 22, and 23 to the financial statements**

*Critical Audit Matter Description*

The Company accounts for its regulated operations in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, Regulated Operations ("ASC 980"). The provisions of this accounting guidance require, among other things, that financial statements of a rate-regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-rate-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

The Company is subject to regulation by the Washington Utilities and Transportation Commission, the Idaho Public Utilities Commission, the Public Utility Commission of Oregon, the Public Service Commission of the State of Montana and the Regulatory Commission of Alaska (collectively, the "Commissions"), which have jurisdiction with respect to, among other things, the rates of electric and natural gas distribution companies in Washington, Idaho, Oregon, Montana, and Alaska, respectively. Accounting for the economics of rate regulation has an impact on certain financial statement line items and disclosures.

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***AVISTA CORPORATION***

The Company's rates are subject to the rate-setting processes of the Commissions and, in certain jurisdictions, annual earnings oversight. Rates are determined and approved in regulatory proceedings based on analyses of the Company's costs to provide utility service and are designed to recover the Company's prudently incurred investments in the utility business and provide a return thereon. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations under ASC 980 as described above. While the Company has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve (1) full recovery of the costs of providing utility service or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction and (3) refunds to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

*How the Critical Audit Matter Was Addressed in the Audit*

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following procedures, among others:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred and deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We read relevant regulatory orders issued by the Commissions for the Company and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on the precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, evaluating the evidence in relation to management's assertions, as applicable.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We inquired of management about property, plant, and equipment that may be abandoned. We inspected the capital-projects budget and construction-work-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of their useful life. We inspected minutes of the Board of Directors and regulatory orders and other filings with the Commissions, evaluating the evidence in relation to management's assertions, as applicable, regarding probability of an abandonment.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•We obtained an analysis from management regarding probability of recovery for regulatory assets or probability of either refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order in order to assess management's assertion that amounts are probable of recovery and/or that a future refund or reduction in rates is not probable.

/s/ Deloitte & Touche LLP

Portland, Oregon

February 24, 2026

We have served as the Company's auditor since 1933.

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***AVISTA CORPORATION***

CONSOLIDATED STATEMENTS OF INCOME

*Avista Corporation*

For the Years Ended December 31

Dollars in millions, except per share amounts

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| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Operating Revenues: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Utility revenues: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Utility revenues, exclusive of alternative revenue programs | $1940 | $1902 | $1746 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Alternative revenue programs | 23 | 35 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total utility revenues | 1963 | 1937 | 1751 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-utility revenues | 1 | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating revenues | 1964 | 1938 | 1752 |
| Operating Expenses: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Utility operating expenses: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Resource costs | 691 | 798 | 702 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other operating expenses | 504 | 442 | 414 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation and amortization | 289 | 274 | 265 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Taxes other than income taxes | 121 | 116 | 110 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-utility operating expenses | 5 | 2 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating expenses | 1610 | 1632 | 1494 |
| Income from operations | 354 | 306 | 258 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense | 152 | 147 | 141 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense to affiliated trusts | 2 | 3 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Capitalized interest | (6) | (5) | (4) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other income-net | (11) | (22) | (19) |
| Income before income taxes | 217 | 183 | 137 |
| Income tax expense (benefit) | 24 | 3 | (34) |
| Net income | $193 | $180 | $171 |
| Weighted-average common shares outstanding (thousands), basic | 80975 | 78725 | 76396 |
| Weighted-average common shares outstanding (thousands), diluted | 81051 | 78820 | 76495 |
| Earnings per common share: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Basic | $2.38 | $2.29 | $2.24 |
| &nbsp;&nbsp;&nbsp;&nbsp;Diluted | $2.38 | $2.29 | $2.24 |

---

***The Accompanying Notes are an Integral Part of These Statements.***

------

***AVISTA CORPORATION***

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

*Avista Corporation*

For the Years Ended December 31

Dollars in millions

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Net income | $193 | $180 | $171 |
| Other Comprehensive (Loss) Income: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $0, $0 and $0, respectively | (1) |  | 2 |
| Total other comprehensive (loss) income | (1) |  | 2 |
| Comprehensive income | $192 | $180 | $173 |

---

***The Accompanying Notes are an Integral Part of These Statements.***

------

***AVISTA CORPORATION***

CONSOLIDATED BALANCE SHEETS

*Avista Corporation*

As of December 31

Dollars in millions

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| **Assets:** |  |  |
| Current Assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash and cash equivalents | $19 | $30 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts and notes receivable, net | 220 | 205 |
| &nbsp;&nbsp;&nbsp;&nbsp;Inventory | 236 | 193 |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory assets | 135 | 137 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current assets | 119 | 91 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total current assets | 729 | 656 |
| Net utility property | 6319 | 5987 |
| Goodwill | 52 | 52 |
| Non-current regulatory assets | 871 | 847 |
| Other property and investments-net and other non-current assets | 388 | 399 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total assets | $8359 | $7941 |
| **Liabilities and Equity:** |  |  |
| Current Liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts payable | $163 | $125 |
| &nbsp;&nbsp;&nbsp;&nbsp;Short-term borrowings | 388 | 354 |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory liabilities | 126 | 108 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | 201 | 184 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total current liabilities | 878 | 771 |
| Long-term debt | 2754 | 2614 |
| Long-term debt to affiliated trusts | 52 | 52 |
| Pensions and other postretirement benefits | 65 | 75 |
| Deferred income taxes | 778 | 751 |
| Non-current regulatory liabilities | 818 | 834 |
| Other non-current liabilities and deferred credits | 305 | 253 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total liabilities | 5650 | 5350 |
| Commitments and Contingencies (See Notes to Consolidated Financial Statements) |  |  |
| **Equity:** |  |  |
| Common stock, no par value; 200,000 shares authorized; 82,193<br> and 80,039 shares issued and outstanding, respectively (shares in thousands) | 1805 | 1720 |
| Accumulated other comprehensive loss | (1) |  |
| Retained earnings | 905 | 871 |
| Total equity | 2709 | 2591 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total liabilities and equity | $8359 | $7941 |

---

***The Accompanying Notes are an Integral Part of These Statements.***

------

***AVISTA CORPORATION***

CONSOLIDATED STATEMENTS OF CASH FLOWS

*Avista Corporation*

For the Years Ended December 31

Dollars in millions

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| **Operating Activities:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income | $193 | $180 | $171 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-cash items included in net income: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation and amortization | 289 | 274 | 265 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Benefit from (provision for) deferred income taxes | 2 | (5) | (37) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Power and natural gas cost (deferrals) amortizations, net | (54) | 104 | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amortization of debt expense | 2 | 2 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Stock-based compensation expense | 9 | 9 | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equity-related AFUDC | (11) | (9) | (7) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Pension and other postretirement benefit expense | 15 | 12 | 14 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other regulatory assets and liabilities | 33 | (28) | (34) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other non-current assets and liabilities | 58 | 36 | 26 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Change in decoupling regulatory deferral | (24) | (35) | (3) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Realized and unrealized losses on assets and investments | 13 | 5 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | (4) | (4) | (6) |
| &nbsp;&nbsp;&nbsp;&nbsp;Contributions to defined benefit pension plan | (10) | (10) | (10) |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash received on settlement of interest rate swap agreements | 1 | 4 | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;Changes in certain current assets and liabilities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts and notes receivable | (24) | 3 | 37 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Inventory | (43) | (40) | (52) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Collateral posted for derivative instruments | 12 | 18 | 129 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Income taxes receivable | (5) | (3) | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other current assets | (23) | 16 | (26) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts payable | 25 | (8) | (66) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | 15 | 13 | 15 |
| Net cash provided by operating activities | 469 | 534 | 447 |
| **Investing Activities:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Utility property capital expenditures (excluding equity-related<br> AFUDC) | (570) | (533) | (499) |
| &nbsp;&nbsp;&nbsp;&nbsp;Issuance of notes receivable |  |  | (3) |
| &nbsp;&nbsp;&nbsp;&nbsp;Repayments from notes receivable | 6 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Equity and property investments | (4) | (10) | (13) |
| &nbsp;&nbsp;&nbsp;&nbsp;Proceeds from sale of investments |  |  | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | 4 | 4 | 2 |
| Net cash used in investing activities | $(564) | $(539) | $(510) |

---

***The Accompanying Notes are an Integral Part of These Statements.***

------

***AVISTA CORPORATION***

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

*Avista Corporation*

For the Years Ended December 31

Dollars in millions

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| **Financing Activities:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net increase (decrease) in short-term borrowings | $33 | $5 | $(114) |
| &nbsp;&nbsp;&nbsp;&nbsp;Proceeds from issuance of long-term debt | 140 | 84 | 250 |
| &nbsp;&nbsp;&nbsp;&nbsp;Maturity of long-term debt and finance leases | (4) | (3) | (17) |
| &nbsp;&nbsp;&nbsp;&nbsp;Issuance of common stock, net of issuance costs | 78 | 68 | 113 |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash dividends paid | (159) | (150) | (141) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | (4) | (4) | (6) |
| Net cash provided by financing activities | 84 |  | 85 |
| Net (decrease) increase in cash and cash equivalents | (11) | (5) | 22 |
| Cash and cash equivalents at beginning of year | 30 | 35 | 13 |
| Cash and cash equivalents at end of year | $19 | $30 | $35 |
| **Supplemental Cash Flow Information:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash paid during the year for interest | $144 | $141 | $132 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-cash financing and investing activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts payable for capital expenditures | 36 | 24 | 34 |

---

***The Accompanying Notes are an Integral Part of These Statements.***

------

***AVISTA CORPORATION***

CONSOLIDATED STATEMENTS OF EQUITY

*Avista Corporation*

For the Years Ended December 31

Dollars in millions, except per share amounts

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Common Stock, Shares (in thousands): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares outstanding at beginning of year | 80039 | 78075 | 74946 |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares issued through equity compensation plans | 148 | 147 | 118 |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares issued through Employee Investment Plan | 13 | 13 | 12 |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares issued through sales agency agreements | 1993 | 1804 | 2999 |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares outstanding at end of year | 82193 | 80039 | 78075 |
| Common Stock, Amount: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at beginning of year | $1720 | $1644 | $1525 |
| &nbsp;&nbsp;&nbsp;&nbsp;Equity compensation expense | 8 | 8 | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Issuance of common stock through equity compensation plans | 1 | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Issuance of common stock through sales agency agreements,<br> net of issuance costs | 78 | 68 | 112 |
| &nbsp;&nbsp;&nbsp;&nbsp;Payment of minimum tax withholdings for share-based<br> payment awards | (2) | (1) | (1) |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at end of year | 1805 | 1720 | 1644 |
| Accumulated Other Comprehensive (Loss) Income: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at beginning of year |  |  | (2) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other comprehensive (loss) income | (1) |  | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at end of year | (1) |  |  |
| Retained Earnings: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at beginning of year | 871 | 841 | 812 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income | 193 | 180 | 171 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dividends on common stock | (159) | (150) | (142) |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at end of year | 905 | 871 | 841 |
| Total equity | $2709 | $2591 | $2485 |
| Dividends declared per common share | $1.96 | $1.90 | $1.84 |

---

***The Accompanying Notes are an Integral Part of These Statements.***

------

***AVISTA CORPORATION***

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NOTE 1. SUMMARY OF SIGNIFICANT 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 24 for business segment information.

***Basis of Reporting***

The 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 consolidated financial statements include the Company's proportionate share of utility plant and related operations associated with its interests in jointly owned plants (see Note 9).

***Use of Estimates***

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•determining the market value of energy commodity derivative assets and liabilities,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•pension and other postretirement benefit plan obligations,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•contingent liabilities,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•obligations under the CCA,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•goodwill impairment testing,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•fair value of equity investments,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•recoverability of regulatory assets, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•unbilled revenues.

Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

***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.

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***AVISTA CORPORATION***

***Depreciation***

For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Avista Utilities | 3.52% | 3.45% | 3.52% |
| Alaska Electric Light and Power Company | 2.77% | 2.80% | 2.78% |

---

The average service lives for the following broad categories of utility plant in service are (in years):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Avista Utilities | Avista Utilities | Alaska Electric Light<br>and Power Company | Alaska Electric Light<br>and Power Company |
| Electric thermal/other production |  | 20 |  | 41 |
| Hydroelectric production |  | 80 |  | 40 |
| Electric transmission |  | 43 |  | 43 |
| Electric distribution |  | 41 |  | 38 |
| Natural gas distribution property |  | 43 | N/A | N/A |
| Other shorter-lived general plant |  | 8 |  | 19 |

---

***Allowance for Funds Used During Construction***

AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant. The debt component of AFUDC is credited against total interest expense in the Consolidated Statements of Income in the line item "capitalized interest." The equity component of AFUDC is included in the Consolidated Statements of Income in the line item "other income-net." The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base.

The WUTC and IPUC have authorized Avista Utilities to calculate AFUDC using its allowed rate of return on rate base. To the extent amounts calculated using this rate exceed the AFUDC amounts calculated using the FERC formula, Avista Utilities capitalizes the excess as a regulatory asset. The regulatory asset associated with plant in service is amortized over the average useful life of Avista Utilities' utility plant which is approximately 30 years. The regulatory asset associated with construction work in progress is not amortized until the plant is placed in service.

The effective AFUDC rate was the following for the years ended December 31:

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Avista Utilities | 7.32% | 7.03% | 7.03% |
| Alaska Electric Light and Power Company | 7.77% | 8.47% | 8.61% |

---

***Income Taxes***

Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce taxable income. Deferred income tax liabilities represent future taxable income the Company expects to recognize in future tax returns. Deferred tax assets and liabilities arise when there are temporary differences resulting from differing treatment of items for tax and accounting purposes. A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the temporary differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company's consolidated income tax returns. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the date of the enactment unless a regulatory order specifies deferral of the effect of the change in tax rates over a longer period of time. The Company establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized. Deferred income tax assets and liabilities and regulatory assets and liabilities are established for income tax benefits flowed through to customers.

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***AVISTA CORPORATION***

The Company has elected to account for transferable tax credits as a component of the income tax provision. The Company recognizes the benefit of production tax credits as a reduction of income tax expense in the period the credit is generated, which corresponds to the period the energy production occurs. The Company applies the deferral method of accounting for investment tax credits (ITCs). Under this method, ITCs are amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

The Company's largest deferred income tax item is the difference between the book and tax basis of utility plant. This item results from the temporary difference in depreciation expense. In early tax years, this item is recorded as a deferred income tax liability that will eventually reverse and become subject to income tax in later tax years.

The Company did not incur penalties on income tax positions in 2025, 2024 or 2023. The Company would recognize interest accrued related to income tax positions as interest expense or interest income and penalties incurred as other operating expense.

***Stock-Based Compensation***

The Company issues three types of stock-based compensation awards - restricted shares, market-based awards and performance-based awards. Compensation cost relating to share-based payment transactions is recognized in the Company's financial statements based on the fair value of the equity instruments issued and recorded over the requisite service period.

The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Consolidated Statements of Income of the following amounts for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Stock-based compensation expense | $8 | $8 | $7 |
| Income tax benefits | 2 | 2 | 2 |

---

Restricted share awards vest in equal thirds each year over 3 years and are payable in Avista Corp. common stock at the end of each year if the service condition is met. Restricted stock is valued at the close of market of the Company's common stock on the grant date.

Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance awards. Both types of awards vest after a period of 3 years and are payable in cash or Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that have vested and have met the market and performance conditions.

The Company accounts for both the TSR awards and CEPS awards as equity awards and compensation cost for these awards is recognized over the requisite service period, provided the requisite service period is rendered. For TSR awards, if the market condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested.

The fair value of each TSR award is estimated on the date of grant using a statistical model incorporating the probability of meeting the market targets based on historical returns relative to a peer group. CEPS awards are valued at the close of market of the Company's common stock on the grant date.

------

***AVISTA CORPORATION***

The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31:

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| **Restricted Shares** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares granted during the year | 141618 | 82433 | 76806 |
| &nbsp;&nbsp;&nbsp;&nbsp;Shares vested during the year | 96214 | 75107 | 75007 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unvested shares at end of year | 190979 | 158464 | 152140 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrecognized compensation expense at end of year<br> (in millions) | $4 | $3 | $3 |
| **TSR Awards** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;TSR shares granted during the year | 36616 | 45739 | 34912 |
| &nbsp;&nbsp;&nbsp;&nbsp;TSR shares vested during the year | 28760 | 64640 | 61456 |
| &nbsp;&nbsp;&nbsp;&nbsp;TSR shares earned based on market metrics |  | 35552 | 44863 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unvested TSR shares at end of year | 72574 | 77530 | 96915 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrecognized compensation expense at end of year<br> (in millions) | $1 | $2 | $2 |
| **CEPS Awards** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;CEPS shares granted during the year | 129056 | 137161 | 104685 |
| &nbsp;&nbsp;&nbsp;&nbsp;CEPS shares vested during the year | 86227 | 64640 | 61456 |
| &nbsp;&nbsp;&nbsp;&nbsp;CEPS shares earned based on performance metrics | 34491 | 29088 | 33801 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unvested CEPS shares at end of year | 236873 | 232486 | 161235 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrecognized compensation expense at end of year<br> (in millions) | $7 | $3 | $2 |

---

Outstanding restricted, TSR and CEPS share awards include a dividend component paid in cash. A liability for the dividends payable related to these awards is accrued as dividends are announced throughout the life of the award. As of December 31, 2025 and 2024, the Company had recognized a liability of $2 million and $3 million, respectively, related to the dividend equivalents payable on the outstanding and unvested share grants.

***Other Income - Net***

Other income - net consisted of the following items for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Interest income | $5 | $5 | $6 |
| Interest on regulatory deferrals | 7 | 9 | 9 |
| Equity-related AFUDC | 11 | 9 | 7 |
| Losses on investments | (12) | (7) | (3) |
| Other income |  | 6 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $11 | $22 | $19 |

---

***Earnings per Common Share***

Basic earnings per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted earnings per common share is calculated by dividing net income by diluted weighted-average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable under contingent stock awards. See Note 21 for earnings per common share calculations.

***Cash and Cash Equivalents***

For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents.

***Accounts Receivable and Allowance for Doubtful Accounts***

The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical

------

***AVISTA CORPORATION***

write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Allowance as of the beginning of the year | $5 | $5 | $6 |
| Additions expensed during the year | 7 | 7 | 7 |
| Net deductions | (7) | (7) | (8) |
| Allowance as of the end of the year | $5 | $5 | $5 |

---

The Company has received grants from various government agencies to assist customers with their energy bills. The Company received these grant funds and applied them to customer accounts, reducing accounts receivable balances. These grants totaled $10 million in 2024 and $2 million in 2023. There were no grants received under these programs in 2025.

***Utility Plant in Service***

The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation.

***Asset Retirement Obligations***

The Company records the fair value of a liability for an ARO in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or recognizes a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the ratemaking process. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers (see Note 11 for further discussion of the Company's AROs).

The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations. The Company records the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and includes them as a non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Regulatory liability for utility plant retirement costs | $468 | $448 |

---

***Goodwill***

Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business combination not individually identified and separately recognized. In 2025, the Company evaluated goodwill for impairment using a fair value to carrying amount comparison (Step 1). The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2025 and determined goodwill was not impaired at that time (carrying value was less than the determined fair value). No events or circumstances occurred between November 30, 2025 and December 31, 2025 that would more likely than not reduce the fair values of the reporting units below their carrying amounts. As of December 31, 2025 and December 31, 2024, the carrying amount of goodwill was $52 million. There are no accumulated impairment losses recognized to date.

***Derivative Assets and Liabilities***

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

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***AVISTA CORPORATION***

The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. 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 PGAs, the ERM in Washington, the PCA mechanism in Idaho, 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 asset or liability. 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.

For interest rate swap transactions, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no impact on the income statement. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.

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 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. Energy commodity derivative assets and liabilities, deferred compensation assets, some equity investments, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Consolidated Balance Sheets. See Note 18 for the Company's fair value disclosures.

***Regulatory Deferred Charges and Credits***

The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•rates for regulated services are established by or subject to approval by independent third-party regulators,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the regulated rates are designed to recover the cost of providing the regulated services, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.

Regulatory accounting practices require certain costs and/or obligations (such as incurred power and natural gas costs not currently reflected in rates, but expected to be recovered or refunded in the future), to be reflected as deferred charges or credits on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Consolidated Statements of Income until the period during which matching revenues are recognized. The Company also has decoupling revenue deferrals. See Note 4 for discussion on decoupling revenue deferrals.

If at some point in the future the Company determines it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:

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***AVISTA CORPORATION***

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•required to write off its regulatory assets, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future.

See Note 23 for further details of regulatory assets and liabilities.

***Unamortized Debt Expense***

Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. These costs are recorded as an offset to Long-Term Debt on the Consolidated Balance Sheets.

***Unamortized Debt Repurchase Costs***

Premiums paid or discounts received to repurchase debt are amortized over the remaining life of the original debt repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. These costs are recovered through retail rates as a component of interest expense.

***Appropriated Retained Earnings***

In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydroelectric projects. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The Company calculates the earnings in excess of the specified rate of return on an annual basis, usually during the second quarter.

The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Appropriated retained earnings | $65 | $62 |

---

***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. As of December 31, 2025, the Company has not recorded significant amounts related to unresolved contingencies. See Note 22 for further discussion of the Company's commitments and contingencies.

**NOTE 2. NEW ACCOUNTING 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 2023-09 "Income Taxes (Topic 740) - Improvements to Income Tax Disclosures"*

In December 2023, the FASB issued ASU 2023-09, requiring additional income tax disclosures. The additional disclosures include prescribed items presented in the income tax rate reconciliation, and further disaggregation of income taxes paid between federal, state and foreign taxes. The ASU became effective for fiscal years beginning after December 15, 2024, and the Company adopted with retrospective presentation. The expanded income tax disclosures have been included within Note 13.

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***AVISTA CORPORATION***

*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 as of December 31, 2025.

*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 has elected to utilize the practical expedient, effective January 1, 2026, and does not expect a material impact to 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 as of December 31, 2025.

*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 as of December 31, 2025.

**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 December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Materials and supplies | $87 | $99 |
| Emission allowances | 136 | 79 |
| Stored natural gas | 8 | 10 |
| Fuel stock | 5 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $236 | $193 |

---

***Other Current Assets***

Other current assets consisted of the following as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Prepayments | $56 | $37 |
| Income taxes receivable | 39 | 32 |
| Derivative assets net of collateral | 8 | 11 |
| Other | 16 | 11 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total | $119 | $91 |

---

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***AVISTA CORPORATION***

***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 December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Equity investments | $148 | $157 |
| Operating lease ROU assets | 64 | 66 |
| Finance lease ROU assets | 29 | 33 |
| Non-utility property | 12 | 33 |
| Notes receivable | 12 | 16 |
| Long-term prepaid license fees | 18 | 18 |
| Pension assets | 61 | 35 |
| Investment in affiliated trust | 12 | 12 |
| Deferred compensation assets | 9 | 9 |
| Other | 23 | 20 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $388 | $399 |

---

***Other Current Liabilities***

Other current liabilities consisted of the following as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Accrued taxes other than income taxes | $33 | $34 |
| Employee paid time off accruals | 34 | 32 |
| Accrued interest | 27 | 24 |
| Pensions and other postretirement benefits | 16 | 15 |
| Derivative liabilities | 18 | 14 |
| Customer deposits | 19 | 14 |
| Other | 54 | 51 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $201 | $184 |

---

***Other Non-Current Liabilities and Deferred Credits***

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

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Operating lease liabilities | $60 | $62 |
| Finance lease liabilities | 32 | 35 |
| Deferred investment tax credits | 27 | 28 |
| Climate Commitment Act obligations | 131 | 77 |
| Asset retirement obligations | 16 | 18 |
| Derivative liabilities | 10 | 12 |
| Other | 29 | 21 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $305 | $253 |

---

**NOTE 4. REVENUE**

The core principle of the revenue recognition model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

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***AVISTA CORPORATION***

**Utility Revenues**

***Revenue from Contracts with Customers***

*General*

The majority of Avista Corp.'s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately.

Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized at that time.

Revenues from contracts with customers are presented in the Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."

*Unbilled Revenue from Contracts with Customers*

The determination of the volume of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month (once per month for each individual customer). At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. The Company's estimate of unbilled revenue is based on:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the number of customers,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•tariff rates,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•meter reading dates,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•actual native load for electricity,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•actual throughput for natural gas, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•electric line losses and natural gas system losses.

Any difference between actual and estimated revenue is recorded in the following month when the meter reading and customer billing occurs.

Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Unbilled accounts receivable | $85 | $75 |

---

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***AVISTA CORPORATION***

*Non-Derivative Wholesale Contracts*

The Company has certain wholesale contracts that are not accounted for as derivatives and are considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for a specified period of time, consistent with the discussion of rate regulated sales above.

***Alternative Revenue Programs (Decoupling)***

Alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires the presentation of revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for an alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the Consolidated Statements of Income. Amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.

The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Consolidated Statements of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.

***Derivative Revenue***

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes transactions entered into and settled within the same month.

***Other Utility Revenue***

Other utility revenue, which includes rent, sales of materials, late fees and other charges, are not considered revenues from contracts with customers. This revenue is not so considered, since it is not received pursuant to contracts under which customers obtain goods or services that are an output of the Company's ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

**Other Considerations for Utility Revenues**

***Gross Versus Net Presentation***

Revenues and resource costs from Avista Utilities' settled energy contracts "booked out" (not physically delivered) are reported on a net basis as part of derivative revenues.

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are imposed on Avista Utilities as opposed to being imposed on customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes

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***AVISTA CORPORATION***

collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.

Utility-related taxes included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Utility-related taxes | $82 | $81 | $75 |

---

**Significant Judgments and Unsatisfied Performance Obligations**

The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).

The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. 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 where the customer makes payments throughout the year. As of December 31, 2025, the Company estimates it had unsatisfied capacity performance obligations of $25 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

**Disaggregation of Total Operating Revenue**

The following table disaggregates total operating revenue by segment and source for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Avista Utilities |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Revenue from contracts with customers | $1625 | $1570 | $1486 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative revenues | 221 | 249 | 199 |
| &nbsp;&nbsp;&nbsp;&nbsp;Alternative revenue programs | 23 | 34 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferrals and amortizations for rate refunds to customers | (13) | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other utility revenues | 60 | 33 | 12 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Avista Utilities | 1916 | 1887 | 1703 |
| AEL&P |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Revenue from contracts with customers | 47 | 49 | 47 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other utility revenues |  | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total AEL&P | 47 | 50 | 48 |
| Other |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other revenues | 1 | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating revenues | $1964 | $1938 | $1752 |

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***AVISTA CORPORATION***

***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 years ended December 31 (dollars in millions):

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2025 | 2025 | 2025 | 2024 | 2024 | 2024 | 2023 | 2023 | 2023 |
|  | Avista Utilities | AEL&P | Total Utility | Avista Utilities | AEL&P | Total Utility | Avista Utilities | AEL&P | Total Utility |
| **ELECTRIC OPERATIONS** |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Revenue from<br> contracts with<br> customers |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | $550 | $22 | $572 | $473 | $22 | $495 | $425 | $20 | $445 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial and<br> governmental | 402 | 25 | 427 | 369 | 27 | 396 | 344 | 27 | 371 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial | 142 |  | 142 | 131 |  | 131 | 110 |  | 110 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Public street and<br> highway lighting | 9 |  | 9 | 9 |  | 9 | 8 |  | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail<br> revenue | 1103 | 47 | 1150 | 982 | 49 | 1031 | 887 | 47 | 934 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transmission | 30 |  | 30 | 38 |  | 38 | 33 |  | 33 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other revenue from<br> contracts with<br> customers | 29 |  | 29 | 40 |  | 40 | 45 |  | 45 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total electric revenue<br> from contracts<br> with customers | $1162 | $47 | $1209 | $1060 | $49 | $1109 | $965 | $47 | $1012 |

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The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
|  | Avista Utilities | Avista Utilities | Avista Utilities |
| **NATURAL GAS OPERATIONS** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Revenue from contracts with customers |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Residential | $291 | $317 | $326 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commercial | 137 | 163 | 164 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Industrial and interruptible | 12 | 13 | 17 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total retail revenue | 440 | 493 | 507 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transportation | 13 | 11 | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other revenue from contracts with customers | 10 | 6 | 6 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total natural gas revenue from contracts with customers | $463 | $510 | $521 |

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**NOTE 5. LEASES**

The core principle of lease accounting is that an entity should recognize the ROU assets and liabilities from leases on the balance sheet and depreciate or amortize the asset and liability over the term of the lease, as well as provide disclosure to enable users of the consolidated financial statements to assess the amount, timing, and uncertainty of cash flows from leases.

***Significant Judgments and Assumptions***

The Company determines if an arrangement is a lease, as well as its classification, at its inception.

ROU assets represent the Company's right to use an underlying asset for the lease term, and lease liabilities represent the Company's obligation to make lease payments. Operating and finance lease ROU assets and lease liabilities are recognized at the commencement date of the agreement based on the present value of lease payments over the lease term. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The implicit rate is used when it is

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***AVISTA CORPORATION***

readily determinable. The operating and finance lease ROU assets also include lease payments made and exclude lease incentives, if any, that accrue to the benefit of the lessee.

Lease terms may include options to extend or terminate the lease when it is reasonably certain the Company will exercise that option. Lease expense is recognized on a straight-line basis over the lease term. The difference between lease expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability.

***Description of Leases***

*Operating Leases*

The Company's most significant operating lease is with the State of Montana associated with submerged land around the Company's hydroelectric facilities in the Clark Fork River basin, which expires in 2046. The terms of this lease are subject to adjustment - depending on the outcome of ongoing litigation between the State of Montana and NorthWestern. In addition, the State of Montana and Avista Corp. were engaged in litigation regarding lease terms, including how much money, if any, the State of Montana should return to Avista Corp.; however, that litigation was dismissed as premature pending the outcome of the ongoing litigation between the State of Montana and NorthWestern. Any reduction in future lease payments or the return to Avista Corp. of amounts previously paid will be included in the future ratemaking process.

In addition to the lease with the State of Montana, the Company has other operating leases for land associated with its utility operations, as well as communication sites which support network and radio communications within its service territory. The Company's leases have remaining terms of 1 to 69 years. Most of the Company's leases include options to extend the lease term for periods of 5 to 50 years. Options are exercised at the Company's discretion.

Certain of the Company's lease agreements include rental payments which are periodically adjusted over the term of the agreement based on the consumer price index. The Company's lease agreements do not include material residual value guarantees or material restrictive covenants.

The Company has entered into a PPA agreement with Rathdrum Power, LLC for the output of the Lancaster Plant through 2041. The PPA meets the accounting definition of a lease. However, since all payments are variable in nature, based on capacity, usage, or performance of the plant, there is no lease obligation or corresponding ROU asset recorded by the Company related to this agreement. The variable lease costs related to this agreement are included in resource costs on the Consolidated Statements of Income.

Avista Corp. does not record leases with a term of 12 months or less on the Consolidated Balance Sheets. Total short-term lease costs for 2025 are immaterial.

*Finance Lease*

AEL&P has a PPA which is a finance lease for accounting purposes related to the Snettisham hydroelectric project, which expires in 2034. For ratemaking purposes, this lease is an operating lease with a constant level of annual rental expense (straight line rent expense). Because of this regulatory treatment, differences between the operating lease expense for ratemaking purposes and the expenses recognized under GAAP (interest expense and amortization of the finance lease ROU asset) are recorded as a regulatory asset and amortized during the later years of the lease when the finance lease expense is less than the operating lease expense included in base rates. The amortization of the ROU asset is included in depreciation and amortization and the interest associated with the lease liability is included in interest expense on the Consolidated Statements of Income.

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***AVISTA CORPORATION***

*Operating and Finance Lease Balances in the Financial Statements*

The components of lease expense were as follows for the year ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Operating lease cost: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fixed lease cost (Other operating expenses) | $5 | $5 | $5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Variable lease cost (Other operating expenses and Resource costs) | 31 | 31 | 25 |
| Total operating lease cost | $36 | $36 | $30 |
| Finance lease cost: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of ROU asset (Depreciation and amortization) | $4 | $4 | $4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest on lease liabilities (Interest expense) | 2 | 2 | 2 |
| Total finance lease cost | $6 | $6 | $6 |

---

Supplemental cash flow information related to leases was as follows for the year ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating cash outflows: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Operating lease payments | $5 | $5 | $5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interest on finance lease | 2 | 2 | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total operating cash outflows | $7 | $7 | $7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance cash outflows: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Principal payments on finance lease | $3 | $3 | $3 |

---

Supplemental balance sheet information related to leases was as follows for December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | December 31, | December 31, |
|  | 2025 | 2024 |
| **Operating Leases** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating lease ROU assets (Other property and investments-net<br> and other non-current assets) | $64 | $66 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | $5 | $4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other non-current liabilities and deferred credits | 60 | 62 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating lease liabilities | $65 | $66 |
| **Finance Leases** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance lease ROU assets (Other property and investments-net<br> and other non-current assets) | $29 | $33 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | $4 | $4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other non-current liabilities and deferred credits | 32 | 35 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total finance lease liabilities | $36 | $39 |
| **Weighted Average Remaining Lease Term** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating leases | 20 years | 21 years |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance leases | 8 years | 4 years |
| **Weighted Average Discount Rate** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating leases | 4.32% | 4.30% |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance leases | 3.14% | 3.46% |

---

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***AVISTA CORPORATION***

Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2025 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | Operating Leases | Finance Leases |
| 2026 | $5 | $5 |
| 2027 | 5 | 6 |
| 2028 | 5 | 6 |
| 2029 | 5 | 6 |
| 2030 | 5 | 5 |
| Thereafter | 75 | 16 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total lease payments | $100 | $44 |
| Less: imputed interest | (35) | (8) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total | $65 | $36 |

---

**NOTE 6. VARIABLE INTEREST ENTITIES**

Under GAAP, a limited partnership or similar legal entity that is the functional equivalent of a limited partnership is considered a VIE regardless of whether it otherwise qualifies as a voting interest entity unless a simple majority or lower threshold of the "unrelated" limited partners (i.e., parties other than the general partner, entities under common control with the general partner, and other parties acting on behalf of the general partner) have substantive kick-out rights (including liquidation rights) or participating rights.

The Company has investments in limited partnerships (or the functional equivalent) where Avista Corp. is a limited partner investor in an investment fund where the general partner makes all of the investment and operating decisions with regards to the partnership and fund. To remove the general partner from any of the funds, approval from greater than a simple majority of the limited partners is required. As such, the limited partners do not have substantive kick-out rights and these investments are considered VIEs. Consolidation of these VIEs by Avista Corp. is not required because the Company does not have majority ownership in any of the funds, it does not have the power to direct activities of the funds, and it does not have the power to appoint executive leadership, including the board of directors.

Avista Corp. participates in profits and losses of the investment funds based on its ownership percentage and its losses are capped at its total initial investment in the funds. Equity investments in VIEs are accounted for under the equity method (see Note 7). As of December 31, 2025, Avista Corp. has invested $83 million in these investment funds, with an additional commitment of $17 million remaining to be invested. The Company is not allowed to withdraw capital contributions from an investment fund until after that fund expiration date and all liabilities of that fund are settled. The expiration dates range from 2025 to 2036, with some investments having no termination date (as they are perpetual). As of December 31, 2025, the Company has a total carrying amount of $82 million in these VIEs, including $72 million of equity investments and $10 million of notes receivable.

**NOTE 7. EQUITY INVESTMENTS**

The Company has equity investment holdings that are accounted for under the equity method, at fair value, or using the fair value measurement alternative provided for in ASC 321, adjusting cost for impairment and observable price changes.

The following table summarizes Avista Corp.'s equity investments, which are included in "Other property and investments- net and other non-current assets" on the Consolidated Balance Sheets as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Equity method investments | $70 | $77 |
| **Investments without readily determinable fair value** |  |  |
| &nbsp;&nbsp;Non-recurring fair value | 29 | 27 |
| &nbsp;&nbsp;Recurring fair value | 49 | 53 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $148 | $157 |

---

*Equity Method Investments*

The Company has investments in limited partnerships (or the functional equivalent) where Avista Corp. is a limited partner investor in an investment fund. Holdings in these investment funds are accounted for under the equity method. Underlying

------

***AVISTA CORPORATION***

investments held by the funds are recorded at fair value by the fund, and Avista Corp. recognizes its share of the fund's profits and losses based on its ownership percentage.

The Company also has ownership in joint ventures with underlying holdings in real estate, which are accounted for under the equity method.

The Company's earnings and losses related to equity method investments are included in "Other income- net" on the Consolidated Statements of Net Income.

*Investments Without Readily Determinable Fair Value*

The Company has investments that do not qualify for equity method treatment, and for which fair value is not readily determinable. The Company has elected the measurement alternative for a majority of these investments, adjusting the recorded value on a non-recurring basis as a result of observable transactions involving the underlying asset. The observable transaction indicates an updated fair value, and the Company adjusts carrying value to fair value at this point in time. The fair value of these assets is determined using the market approach, and these assets are considered level 2 on the fair value hierarchy (see Note 18 for a description of the fair value hierarchy).

The Company has elected to record two investments at fair value on a recurring basis. These equity investments are considered Level 3 on the fair value hierarchy. See further discussion of Level 3 equity investments, including valuation methods and significant inputs, as included in Note 18.

Realized and unrealized gains or losses in equity investments are included in net income. The following table summarizes net unrealized gains (losses) related to investments without readily determinable fair value held as of the end of the respective period for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Investments recorded at non-recurring fair value | $2 | $— | $— |
| Investments recorded at recurring fair value | (4) |  | (4) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $(2) | $— | $(4) |

---

Net unrealized gains recorded related to investments recorded at non-recurring fair value result from identified observable transactions. On a cumulative basis, the Company has recognized a net gain of $17 million for fair value adjustments to investments recorded at non-recurring fair value held at December 31, 2025.

**NOTE 8. DERIVATIVES AND 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 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

------

***AVISTA CORPORATION***

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 what 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 December 31, 2025 expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Purchases | Purchases | Purchases | Purchases | Sales | Sales | Sales | Sales |
|  | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives |
| Year | Physical (1)<br>MWh | Financial (1)<br>MWh | Physical (1)<br>mmBTUs | Financial (1)<br>mmBTUs | Physical (1)<br>MWh | Financial (1)<br>MWh | Physical (1)<br>mmBTUs | Financial (1)<br>mmBTUs |
| 2026 | 6 |  | 30523 | 30535 | 373 | 328 | 2325 | 543 |
| 2027 |  |  | 14558 | 14443 |  |  | 1393 |  |
| 2028 |  |  | 4413 | 5393 |  |  | 1013 |  |

---

As of December 31, 2025, there are no energy commodity derivative contracts outstanding with expected deliveries after 2028.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2024 that were expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Purchases | Purchases | Purchases | Purchases | Sales | Sales | Sales | Sales |
|  | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives | Electric Derivatives | Electric Derivatives | Gas Derivatives | Gas Derivatives |
| Year | Physical (1)<br>MWh | Financial (1)<br>MWh | Physical (1)<br>mmBTUs | Financial (1)<br>mmBTUs | Physical (1)<br>MWh | Financial (1)<br>MWh | Physical (1)<br>mmBTUs | Financial (1)<br>mmBTUs |
| 2025 | 7 |  | 27993 | 39483 | 427 | 420 | 1897 | 1963 |
| 2026 |  |  | 17560 | 13175 |  |  |  |  |
| 2027 |  |  | 7555 | 2250 |  |  |  |  |

---

As of December 31, 2024, there were no energy commodity derivative contracts outstanding with expected deliveries after 2027.

(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

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***AVISTA CORPORATION***

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 December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Number of contracts | 26 | 22 |
| Notional amount (in United States dollars) | $6 | $2 |
| Notional amount (in Canadian dollars) | 4 | 2 |

---

***Summary of Outstanding Derivative Instruments***

The amounts recorded on the Consolidated Balance Sheets as of December 31, 2025 and December 31, 2024 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 Consolidated Balance Sheets as of December 31, 2025 (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Fair Value | Fair Value | Fair Value | Fair Value |
| Derivative and Balance Sheet Location | Gross<br>Asset | Gross<br>Liability | Collateral<br>Netting | Net Asset<br>(Liability) <br>on Balance<br>Sheet |
| Other current assets | $8 | $— | $— | $8 |
| Other current liabilities | 7 | (33) | 8 | (18) |
| Other non-current liabilities and deferred credits | 2 | (14) | 2 | (10) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total derivative instruments recorded on the<br> balance sheet | $17 | $(47) | $10 | $(20) |

---

The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheets as of December 31, 2024 (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Fair Value | Fair Value | Fair Value | Fair Value |
| Derivative and Balance Sheet Location | Gross<br>Asset | Gross<br>Liability | Collateral<br>Netting | Net Asset<br>(Liability) <br>on Balance<br>Sheet |
| **Interest rate swap derivatives** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current assets | $1 | $— | $— | $1 |
| **Energy commodity derivatives** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current assets | 10 |  |  | 10 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | 11 | (48) | 23 | (14) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other non-current liabilities and deferred credits | 2 | (16) | 1 | (13) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total derivative instruments recorded on the<br> balance sheet | $24 | $(64) | $24 | $(16) |

---

***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. In the event of changes in market prices or a downgrade in Avista Corp.'s credit ratings 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. 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. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

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***AVISTA CORPORATION***

The following table presents collateral outstanding related to its energy commodity derivative instruments as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Cash collateral posted | $12 | $24 |
| Letters of credit outstanding | 14 | 12 |

---

Certain of Avista Corp.'s derivative instruments contain provisions requiring Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.'s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.

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 Avista Corp. could be required to post as of December 31 (dollars in millions):

---

| | |
|:---|:---|
|  | 2025 |
| Liabilities with credit-risk-related contingent features | $20 |
| Additional collateral to post | 20 |

---

**NOTE 9. JOINTLY OWNED ELECTRIC FACILITIES**

The Company had a 15 percent ownership interest in Units 3 and 4 of Colstrip, and provided financing for its ownership interest in the project. Effective January 1, 2026, the Company transferred its ownership to NorthWestern. The Company has retained responsibility for remediation obligations in existence at the time the transaction closed. See further discussion of the transaction within Note 22.

Pursuant to the ownership and operating agreements among the co-owners, the Company's share of related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company's share of utility plant in service for Colstrip and accumulated depreciation (inclusive of the ARO assets and accumulated amortization) were as follows as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Utility plant in service | $401 | $401 |
| Accumulated depreciation | (382) | (355) |

---

The Company retained ownership of certain transmission assets subsequent to transferring its ownership interest in Units 3 and 4 to NorthWestern, which are included in amounts above. In addition, the Company has reclassified certain amounts to be recovered or returned to customers subsequent to the ownership transfer to regulatory assets and liabilities as of December 31, 2025.

See Note 11 for further discussion of AROs.

While the obligations and liabilities with respect to Colstrip have been shared among the co-owners on a pro-rata basis, many of the environmental liabilities are joint and several under the law, so that if any co-owner failed to pay its share of such liability, the other co-owners (or any one of them) could be required to pay the defaulting co-owner's share (or the entire liability).

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***AVISTA CORPORATION***

**NOTE 10. PROPERTY, PLANT AND EQUIPMENT**

***Net Utility Property***

Net utility property consisted of the following as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Utility plant in service | $8591 | $8180 |
| Construction work in progress | 303 | 238 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | 8894 | 8418 |
| Less: Accumulated depreciation and amortization | 2575 | 2431 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total net utility property | $6319 | $5987 |

---

***Gross Property, Plant and Equipment***

The gross balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| **Avista Utilities:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric production | $1588 | $1523 |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric transmission | 1158 | 1105 |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric distribution | 2784 | 2580 |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric construction work-in-progress (CWIP) and other | 494 | 452 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Electric total | 6024 | 5660 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas underground storage | 65 | 63 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas distribution | 1700 | 1624 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas CWIP and other | 98 | 95 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Natural gas total | 1863 | 1782 |
| &nbsp;&nbsp;&nbsp;&nbsp;Common plant (including CWIP) | 780 | 760 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total Avista Utilities | 8667 | 8202 |
| **AEL&P:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric production | 141 | 120 |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric transmission | 23 | 23 |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric distribution | 39 | 36 |
| &nbsp;&nbsp;&nbsp;&nbsp;Electric CWIP and other | 13 | 26 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Electric total | 216 | 205 |
| &nbsp;&nbsp;&nbsp;&nbsp;Common plant | 11 | 11 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total AEL&P | 227 | 216 |
| Total gross utility property | $8894 | $8418 |

---

**NOTE 11. ASSET RETIREMENT OBLIGATIONS**

The Company has recorded liabilities for future AROs to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•restore coal ash containment ponds and coal holding areas at Colstrip,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•cap a landfill at the Kettle Falls Plant, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease.

Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•removal and disposal of certain transmission and distribution assets, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.

The Company transferred its ownership interest in Colstrip to NorthWestern on January 1, 2026. The Company retained responsibility for its share of the liabilities giving rise to the Colstrip AROs existing as of the transfer date.

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***AVISTA CORPORATION***

In 2015, the EPA issued a final rule regarding CCRs. Colstrip produces this byproduct. The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of the rule. The rule includes technical requirements for CCR landfills and surface impoundments. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements and existing state obligations.

In April 2024 and January 2025, the EPA issued additional final rules building on the 2015 regulations and regulating CCR management units at active and inactive power plants. The Colstrip owners are performing analyses to determine whether any potential changes to the existing remediation efforts are required. Based on the results of these analyses to date, the Company believes there will not be a material change to the asset retirement obligation for Colstrip related to these final rules.

The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the ARO due to the uncertainty and evolving nature of the compliance strategies that will be used and the availability of data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. The Company updates its estimates as new information becomes available. The Company expects to seek recovery of costs related to complying with the CCR rule through the ratemaking process.

In addition to the above, under a 2018 Administrative Order on Consent and ongoing negotiations with the Montana Department of Ecological Quality, the owners of Colstrip are required to provide financial assurance, primarily in the form of surety bonds, to secure each owner's pro-rata share of various anticipated closure and remediation of the ash ponds and coal holding areas. The amount of financial assurance required of each owner may, like the ARO, vary substantially due to the uncertainty and evolving nature of anticipated closure and remediation activities, and as those activities are completed over time.

The following table documents the changes in the Company's asset retirement obligation during the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Asset retirement obligation at beginning of year | $18 | $18 | $16 |
| Liabilities incurred |  |  | 2 |
| Liabilities settled | (3) | (1) |  |
| Accretion expense | 1 | 1 |  |
| Asset retirement obligation at end of year | $16 | $18 | $18 |

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**NOTE 12. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS**

The pension and other postretirement benefit plans described below only relate to Avista Utilities. AEL&P participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension plan for its nonunion workers. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp.

***Avista Utilities***

The Company has a defined benefit pension plan covering the majority of regular full-time non-union employees at Avista Utilities hired prior to January 1, 2014 and regular full-time union employees that were hired prior to January 1, 2024. Employees eligible for the plan continue to accrue benefits. Individual benefits under this plan are based upon the employee's years of service, date of hire and average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 and union employees hired on or after January 1, 2024 participate in a defined contribution 401(k) plan in lieu of a defined benefit pension plan. The Company's funding policy is to contribute at least the minimum amounts required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts currently deductible for income tax purposes. The Company contributed $10 million in cash each year to the pension plan in 2025, 2024, and 2023. The Company expects to contribute $10 million in cash to the pension plan in 2026.

In 2024, the Company offered pension participants an election to leave the pension plan for an alternative defined contribution 401(k) plan. In April 2024, it was determined that due to the number of participants electing to leave the pension plan, as well as the resulting decrease in expected future service, this event resulted in a curtailment of the pension plan, and an associated

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***AVISTA CORPORATION***

gain of $1 million for the reduction in the benefit obligation. This gain was offset against the unrecognized net actuarial loss (and recorded within a regulatory asset). The curtailment triggered a remeasurement of pension plan. The remeasurement did not have a material impact on the Company's financial condition or results of operations.

The Company has a SERP providing additional pension benefits to certain executive officers and certain key employees of the Company. The SERP provides benefits to individuals whose benefits under the defined benefit pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.

The Company expects benefit payments under the pension plan and the SERP will total (dollars in millions):

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | Total 2031-<br>2035 |
| Expected benefit payments | $46 | $46 | $47 | $47 | $48 | $249 |

---

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits.

The Company provides certain health care and life insurance benefits for eligible retired employees hired prior to January 1, 2014. The Company accrues the estimated cost of postretirement benefit obligations during the years employees provide services. The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1, 2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward their medical premium.

The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee's years of service and ending salary. The liability and expense of the HRA are included as other postretirement benefits.

The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer's designated beneficiary will receive a payment equal to twice the executive officer's annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer's total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits.

The Company expects benefit payments under other postretirement benefit plans will total (dollars in millions):

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | Total 2031-<br>2035 |
| Expected benefit payments | $6 | $6 | $7 | $7 | $7 | $38 |

---

The Company expects to contribute $6 million to other postretirement benefit plans in 2026. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans.

------

***AVISTA CORPORATION***

The following tables set forth the pension and other postretirement benefit plan disclosures as of December 31, 2025 and 2024 and the components of net periodic benefit costs for the years ended December 31, 2025, 2024 and 2023 (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Pension Benefits | Pension Benefits | Other Post-<br>retirement Benefits | Other Post-<br>retirement Benefits |
|  | 2025 | 2024 | 2025 | 2024 |
| **Change in benefit obligation:** | **Change in benefit obligation:** | **Change in benefit obligation:** | **Change in benefit obligation:** | **Change in benefit obligation:** |
| Benefit obligation as of beginning of year | $600 | $585 | $117 | $122 |
| Service cost | 16 | 16 | 2 | 3 |
| Interest cost | 35 | 34 | 7 | 7 |
| Actuarial (gain)/loss (1) | 15 | 2 | (3) | (9) |
| Plan change |  |  | 1 |  |
| Benefits paid | (44) | (36) | (8) | (6) |
| Curtailments |  | (1) |  |  |
| Benefit obligation as of end of year (2) | $622 | $600 | $116 | $117 |
| **Change in plan assets:** | **Change in plan assets:** | **Change in plan assets:** | **Change in plan assets:** | **Change in plan assets:** |
| Fair value of plan assets as of beginning of year | $608 | $590 | $67 | $58 |
| Actual return on plan assets | 80 | 42 | 8 | 9 |
| Employer contributions | 10 | 10 |  |  |
| Benefits paid | (42) | (34) |  |  |
| Fair value of plan assets as of end of year (2) | $656 | $608 | $75 | $67 |
| Funded status | $34 | $8 | $(41) | $(50) |
| **Amounts recognized in the Consolidated Balance Sheets:** | **Amounts recognized in the Consolidated Balance Sheets:** | **Amounts recognized in the Consolidated Balance Sheets:** | **Amounts recognized in the Consolidated Balance Sheets:** | **Amounts recognized in the Consolidated Balance Sheets:** |
| Other non-current assets | $61 | $35 | $— | $— |
| Other current liabilities | (2) | (2) | (1) | (1) |
| Non-current liabilities | (25) | (25) | (40) | (49) |
| Net amount recognized | $34 | $8 | $(41) | $(50) |
| Accumulated pension benefit obligation (2) | $535 | $522 |  |  |
| Accumulated postretirement benefit obligation: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;For retirees |  |  | $64 | $67 |
| &nbsp;&nbsp;&nbsp;&nbsp;For fully eligible employees |  |  | $18 | $16 |
| &nbsp;&nbsp;&nbsp;&nbsp;For other participants |  |  | $34 | $34 |
| **Included in accumulated other comprehensive loss (income) (net of tax):** | **Included in accumulated other comprehensive loss (income) (net of tax):** | **Included in accumulated other comprehensive loss (income) (net of tax):** | **Included in accumulated other comprehensive loss (income) (net of tax):** | **Included in accumulated other comprehensive loss (income) (net of tax):** |
| Unrecognized prior service cost | $3 | $3 | $1 | $— |
| Unrecognized net actuarial loss (gain) | 52 | 70 | (4) | 2 |
| Total | 55 | 73 | (3) | 2 |
| Less regulatory asset | (54) | (73) | 3 | (2) |
| Accumulated other comprehensive loss for unfunded benefit<br> obligation for pensions and other postretirement benefit plans | $1 | $— | $— | $— |

---

(1)The change in the pension benefit obligation related to actuarial loss is primarily related to actual investment returns differing from our assumptions, partially offset by financial and demographic assumption changes.

(2)As of December 31, 2025, the SERP had a projected benefit obligation of $27 million and an accumulated benefit obligation of $25 million, with no plan assets.

------

***AVISTA CORPORATION***

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Pension Benefits | Pension Benefits | Other Post-<br>retirement Benefits | Other Post-<br>retirement Benefits |
|  | 2025 | 2024 | 2025 | 2024 |
| **Weighted-average assumptions as of December 31:** |  |  |  |  |
| Discount rate for benefit obligation | 5.96% | 6.13% | 6.11% | 6.09% |
| Discount rate for annual expense | 6.13% | 5.86% | 6.09% | 5.83% |
| Expected long-term return on plan assets | 7.40% | 7.80% | 6.60% | 6.70% |
| Rate of compensation increase | 5.07% | 5.19% |  |  |
| Medical cost trend pre-age 65 – initial |  |  | 7.00% | 6.50% |
| Medical cost trend pre-age 65 – ultimate |  |  | 5.00% | 5.00% |
| Ultimate medical cost trend year pre-age 65 |  |  | 2034 | 2031 |
| Medical cost trend post-age 65 – initial |  |  | 7.00% | 6.50% |
| Medical cost trend post-age 65 – ultimate |  |  | 5.00% | 5.00% |
| Ultimate medical cost trend year post-age 65 |  |  | 2034 | 2031 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | Pension Benefits | Pension Benefits | Pension Benefits | Other Post-retirement Benefits | Other Post-retirement Benefits | Other Post-retirement Benefits |
|  | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 |
| **Components of net periodic benefit cost:** |  |  |  |  |  |  |
| Service cost (1) | $16 | $16 | $14 | $2 | $3 | $2 |
| Interest cost | 35 | 34 | 33 | 7 | 7 | 7 |
| Expected return on plan assets | (44) | (45) | (44) | (4) | (4) | (3) |
| Amortization of prior service cost (credit) | 1 |  | 1 |  | (1) | (1) |
| Net loss recognition | 3 | 2 | 5 |  |  |  |
| Net periodic benefit cost | $11 | $7 | $9 | $5 | $5 | $5 |

---

(1)Total service cost in the table above is 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 45 percent of all labor and benefits is capitalized to utility property and 55 percent is expensed to utility other operating expenses.

Pension costs other than service costs are presented in the Consolidated Statements of Income in the line item "Other income-net."

***Plan Assets***

The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies.

The Company has contracted with investment consultants who are responsible for monitoring the individual investment managers. The investment managers' performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.

Pension plan assets are invested in mutual funds, and trusts and partnerships that hold marketable debt and equity securities and real estate. In seeking to obtain a return that aligns with the funded status of the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and investment ranges for each asset class of 55 percent in equity securities, 40 percent in debt securities, and 5 percent in real estate. The target investment allocation percentages are typically the midpoint of the established range.

The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, the

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***AVISTA CORPORATION***

investment manager estimates fair value based upon other inputs (including valuations of securities comparable in coupon, rating, maturity and industry).

Pension plan and other postretirement plan assets with fair values are measured using net asset value (NAV) are excluded from the fair value hierarchy and included as reconciling items in the tables below.

The plan's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days. Most of the plan's investments in closely held investments and partnership interests have redemption limitations ranging from bi-monthly to semi-annually following redemption notice requirements of 60 to 90 days.

The following table discloses by level within the fair value hierarchy (see Note 18 for a description of the fair value hierarchy) of the pension plan's assets measured and reported as of December 31, 2025 at fair value (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Level 1 | Level 2 | Level 3 | Total |
| Cash equivalents | $— | $9 | $— | $9 |
| Fixed income securities: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;U.S. government issues |  | 47 |  | 47 |
| &nbsp;&nbsp;&nbsp;&nbsp;Corporate issues |  | 227 |  | 227 |
| &nbsp;&nbsp;&nbsp;&nbsp;International issues |  | 35 |  | 35 |
| &nbsp;&nbsp;&nbsp;&nbsp;Municipal issues |  | 9 |  | 9 |
| Mutual funds: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;U.S. equity securities | 162 |  |  | 162 |
| &nbsp;&nbsp;&nbsp;&nbsp;International equity securities | 64 |  |  | 64 |
| **Plan assets measured at NAV (not subject to hierarchy<br> disclosure)** |  |  |  |  |
| Common/collective trusts: real estate |  |  |  | 24 |
| Partnership/closely held investments: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;International equity securities |  |  |  | 73 |
| &nbsp;&nbsp;&nbsp;&nbsp;Real estate |  |  |  | 6 |
| Total | $226 | $327 | $— | $656 |

---

The following table discloses by level within the fair value hierarchy (see Note 18 for a description of the fair value hierarchy) of the pension plan's assets measured and reported as of December 31, 2024 at fair value (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Level 1 | Level 2 | Level 3 | Total |
| Cash equivalents | $— | $8 | $— | $8 |
| Fixed income securities: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;U.S. government issues |  | 37 |  | 37 |
| &nbsp;&nbsp;&nbsp;&nbsp;Corporate issues |  | 213 |  | 213 |
| &nbsp;&nbsp;&nbsp;&nbsp;International issues |  | 33 |  | 33 |
| &nbsp;&nbsp;&nbsp;&nbsp;Municipal issues |  | 11 |  | 11 |
| Mutual funds: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;U.S. equity securities | 160 |  |  | 160 |
| &nbsp;&nbsp;&nbsp;&nbsp;International equity securities | 63 |  |  | 63 |
| **Plan assets measured at NAV (not subject to hierarchy<br> disclosure)** |  |  |  |  |
| Common/collective trusts: real estate |  |  |  | 24 |
| Partnership/closely held investments: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;International equity securities |  |  |  | 52 |
| &nbsp;&nbsp;&nbsp;&nbsp;Real estate |  |  |  | 7 |
| Total | $223 | $302 | $— | $608 |

---

The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. For investment securities for which market prices are not readily available, the investment manager determines fair value based upon other inputs (including

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***AVISTA CORPORATION***

valuations of securities comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2025 and 2024.

The fair value of other postretirement plan assets was determined to be $75 million as of December 31, 2025 and $67 million as of December 31, 2024. The assets consist of a balanced index mutual fund, which is a single mutual fund that includes a percentage of U.S. equity and fixed income securities and international equity and fixed income securities. This mutual fund is classified as Level 1 in the fair value hierarchy (see Note 18 for a description of the fair value hierarchy).

***401(k) Plans and Executive Deferral Plan***

Avista Utilities has a salary deferral 401(k) plan that is a defined contribution plan and covers substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The Company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.

Employer matching contributions were as follows for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Employer 401(k) matching contributions | $18 | $16 | $15 |

---

The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust.

There were deferred compensation assets included in other property and investments-net and corresponding deferred compensation liabilities included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Deferred compensation assets and liabilities | $9 | $9 |

---

**NOTE 13. ACCOUNTING FOR INCOME TAXES**

***Income Tax Expense***

Income tax expense consisted of the following for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Current income tax expense: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Federal | $20 | $5 | $1 |
| &nbsp;&nbsp;&nbsp;&nbsp;State | 2 | 3 | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total current income tax expense | 22 | 8 | 3 |
| Deferred income tax expense (benefit): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Federal | 2 | (5) | (37) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred income tax expense (benefit) | 2 | (5) | (37) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total income tax expense (benefit) | $24 | $3 | $(34) |

---

------

***AVISTA CORPORATION***

A reconciliation of federal income taxes derived from the statutory federal tax rate of 21 percent applied to income before income taxes is as follows for the years ended December 31 (dollars in millions):

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | 2025 | 2025 | 2024 | 2024 | 2023 | 2023 |
| Income from continuing operations before income tax expense (benefit) | $217 | N/A | $183 | N/A | $137 | N/A |
| U.S. federal statutory tax rate | 46 | 21.0% | 38 | 21.0% | 29 | 21.0% |
| State income taxes, net of federal income tax effect (1) | 1 | 0.5 | 2 | 0.9 | 2 | 1.5 |
| Research and development tax credits | (1) | (0.5) | (1) | (0.6) | (3) | (1.7) |
| Other adjustments: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Flow through related to deduction of meters and mixed service costs (2) | (7) | (3.2) | (23) | (12.4) | (48) | (34.9) |
| &nbsp;&nbsp;&nbsp;&nbsp;Excess deferred tax amortization | (11) | (4.9) | (11) | (6.0) | (12) | (8.9) |
| &nbsp;&nbsp;&nbsp;&nbsp;CARES Act tax benefit amortization | (2) | (0.9) | (1) | (0.6) | (1) | (0.7) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | (2) | (0.9) | (1) | (0.8) | (1) | (0.7) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total other adjustments | (22) | (9.9) | (36) | (19.8) | (62) | (45.2) |
| Effective tax rate | $24 | 11.1% | $3 | 1.5% | $(34) | (24.4)% |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)State taxes in Oregon made up greater than 50 percent of the tax effect in this category.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)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 due to flowing through the benefits related to meters and mixed service costs. Once these tax customer credits have been applied to customers and are exhausted, income tax expense will increase.

In July 2025, OBBB was signed into law, which includes significant changes to the U.S. tax code and related laws. The Company has evaluated the potential impact of OBBB on our consolidated financial statements in accordance with ASC 740 and, as of December 31, 2025, has determined the impact to the effective tax rate is not material.

***Cash Paid for Income Taxes***

Income taxes paid (net of refunds) consisted of the following for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Federal | $26 | $9 | $— |
| State | 2 | 2 | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total income taxes paid (net of refunds) | $28 | $11 | $2 |

---

State income taxes paid (net of refunds) exceeded 5 percent of total income taxes paid (net of refunds) in the following jurisdictions for the years ended December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2024 | 2023 |
| Alaska<br> \* | $1 | $1 |
| Oregon<br> \* | 1 | 1 |

---

***\****Jurisdiction below the threshold for the period presented.

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***AVISTA CORPORATION***

***Deferred Income Taxes***

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| **Deferred income tax assets:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory liabilities | $194 | $194 |
| &nbsp;&nbsp;&nbsp;&nbsp;Tax credits and net operating loss carryforwards | 29 | 36 |
| &nbsp;&nbsp;&nbsp;&nbsp;Provisions for pensions | 14 | 16 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | 56 | 49 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total gross deferred income tax assets | 293 | 295 |
| &nbsp;&nbsp;&nbsp;&nbsp;Valuation allowances for deferred tax assets | (8) | (8) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred income tax assets after valuation allowances | 285 | 287 |
| **Deferred income tax liabilities:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Utility property, plant, and equipment | 780 | 759 |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory assets | 255 | 252 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | 31 | 27 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total gross deferred income tax liabilities | 1066 | 1038 |
| &nbsp;&nbsp;&nbsp;&nbsp;Uncertain tax benefits for deferred tax liabilities | (3) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred income tax liabilities | 1063 | 1038 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net long-term deferred income tax liability | $778 | $751 |

---

The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized.

As of December 31, 2025, the Company had $22 million of state tax credit carryforwards. Of the total amount, the Company believes that it is more likely than not that it will only be able to utilize $14 million of the state tax credits. As such, the Company has recorded a valuation allowance of $8 million against the state tax credit carryforwards and reflected the net amount of $14 million as an asset as of December 31, 2025. State tax credits expire from 2026 to 2039.

***Uncertain Tax Positions***

The Company recognizes tax positions that meet the more-likely-than-not threshold as the largest amount of the tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a tax authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Unrecognized tax benefits at January 1 | $1 | $— | $— |
| &nbsp;&nbsp;Gross increases - tax positions in prior period | 2 |  |  |
| &nbsp;&nbsp;Gross increases - tax positions in current period | 1 | 1 |  |
| Unrecognized tax benefits at December 31 | $4 | $1 | $— |

---

The Company's unrecognized tax benefits include approximately $1 million related to tax positions as of December 31, 2025 and 2024 that, if recognized, would impact the annual effective tax rate.

***Status of Internal Revenue Service (IRS) and State Examinations***

The Company and its eligible subsidiaries file consolidated federal income tax returns. All tax years after 2021 are open for an IRS tax examination.

The Company files state income tax returns in certain jurisdictions, including Idaho, Oregon, Montana and Alaska. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis.

All tax years after 2021 are open for examination in Idaho, Oregon, Montana and Alaska.

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***AVISTA CORPORATION***

The Company believes open tax years for federal or state income taxes will not result in adjustments that would be significant to the consolidated financial statements.

**NOTE 14. ENERGY PURCHASE CONTRACTS**

The discussion below only relates to Avista Utilities. The sole energy purchase contract at AEL&P is a PPA for the Snettisham hydroelectric project and it is accounted for as a lease. AEL&P does not have any other significant operating agreements or contractual obligations. See Note 5 for further discussion of the Snettisham PPA.

Avista Utilities has various agreements for the purchase or exchange of electric energy (including transmission), as well as contracts for the purchase of natural gas for resale and fuel for thermal generation (including transportation). The remaining term of the contracts ranges from one month to twenty-five years.

Total fixed and variable costs for power purchased (including transmission), natural gas purchased, fuel for generation and other fuel costs (including transportation), which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Power and natural gas resources | $520 | $548 | $607 |

---

The following table details Avista Utilities' future fixed contractual commitments for power and natural gas resources (dollars in millions):

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total |
| Power resources | $335 | $268 | $249 | $234 | $230 | $2509 | $3825 |
| Natural gas resources | 106 | 77 | 142 | 48 | 43 | 156 | 572 |
| Total | $441 | $345 | $391 | $282 | $273 | $2665 | $4397 |

---

These energy purchase contracts were entered into as part of Avista Utilities' obligation to serve its retail electric and natural gas customers' energy requirements, including contracts entered into for resource optimization. These costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.

The future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts with PUDs to purchase portions of the output of certain generating facilities. Although the Company has no investment in the PUD generating facilities, the contracts obligate the Company to pay certain minimum amounts whether or not the facilities are operating. The cost of power purchased under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Consolidated Statements of Income. The contractual amounts included above consist of amounts in respect of the PUDs' existing debt service cost. The fixed minimum amounts payable by the Company under each contract with a PUD includes an amount that is the same percentage of the PUD's total debt service requirements on its revenue bonds issued to finance the related generating facility as the Company's percentage entitlement to the output of that facility. The total portion of the PUDs' future debt service requirements so allocable to the Company as of December 31, 2025 (principal and interest) was $264 million.

In addition, Avista Utilities has operating agreements, settlements and other contractual obligations related to its generating facilities and transmission and distribution services. The expenses associated with these agreements are reflected in other operating expenses in the Consolidated Statements of Income. The following table details future contractual commitments under these agreements (dollars in millions):

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total |
| Contractual obligations | $19 | $20 | $20 | $21 | $21 | $163 | $264 |

---

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***AVISTA CORPORATION***

**NOTE 15. SHORT-TERM BORROWINGS**

***Avista Corp.***

*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 the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates on borrowings (excluding letters of credit) under the Company's revolving committed line of credit were as follows as of December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Balance outstanding at end of period | $385 | $342 |
| Letters of credit balance outstanding at end of period | 5 | 5 |
| Average interest rate at end of period | 4.84% | 5.52% |

---

As of December 31, 2025 and 2024, the borrowings outstanding under Avista Corp.'s committed lines of credit were classified as short-term borrowings on the Consolidated Balance Sheets.

*Letter of Credit Facility*

Avista Corp. has a letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

The Company had $14 million and $12 million in letters of credit outstanding under this agreement as of December 31, 2025 and December 31, 2024, respectively. Letters of credit are not reflected on the Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.

*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 one case other obligations. The committed line of credit 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 December 31, 2025, 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 December 31 (dollars in millions):

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Balance outstanding at end of period | $3 | $12 |
| Average interest rate at end of period | 5.33% | 6.13% |

---

The committed line of credit agreement contains customary covenants and default provisions. 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 December 31, 2025, AEL&P complied with this covenant.

------

***AVISTA CORPORATION***

**NOTE 16. LONG-TERM DEBT**

The following details long-term debt outstanding as of December 31 (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
| Maturity<br>Year | Description | Interest<br>Rate | 2025 | 2024 |
| **Avista Corp. Secured Long-Term Debt** | **Avista Corp. Secured Long-Term Debt** |  |  |  |
| 2028 | Secured Medium-Term Notes | 6.37% | $25 | $25 |
| 2032 | Secured Pollution Control Bonds | 3.88% | 67 | 67 |
| 2034 | Secured Pollution Control Bonds | 3.88% | 17 | 17 |
| 2035 | First Mortgage Bonds | 6.25% | 150 | 150 |
| 2037 | First Mortgage Bonds | 5.70% | 150 | 150 |
| 2040 | First Mortgage Bonds | 5.55% | 35 | 35 |
| 2041 | First Mortgage Bonds | 4.45% | 85 | 85 |
| 2044 | First Mortgage Bonds | 4.11% | 60 | 60 |
| 2045 | First Mortgage Bonds | 4.37% | 100 | 100 |
| 2047 | First Mortgage Bonds | 4.23% | 80 | 80 |
| 2047 | First Mortgage Bonds | 3.91% | 90 | 90 |
| 2048 | First Mortgage Bonds | 4.35% | 375 | 375 |
| 2049 | First Mortgage Bonds | 3.43% | 180 | 180 |
| 2050 | First Mortgage Bonds | 3.07% | 165 | 165 |
| 2051 | First Mortgage Bonds | 3.54% | 175 | 175 |
| 2051 | First Mortgage Bonds | 2.90% | 140 | 140 |
| 2052 | First Mortgage Bonds | 4.00% | 400 | 400 |
| 2053 | First Mortgage Bonds | 5.66% | 250 | 250 |
| 2055 | First Mortgage Bonds (1) | 6.18% | 120 |  |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Total Avista Corp. secured long-term debt |  | 2664 | 2544 |
| **Alaska Electric Light and Power Company Secured Long-Term Debt** | **Alaska Electric Light and Power Company Secured Long-Term Debt** |  |  |  |
| 2030 | Secured Term Loan (2) | 5.49% | 20 |  |
| 2044 | First Mortgage Bonds | 4.54% | 75 | 75 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Total secured long-term debt |  | 2759 | 2619 |
| **Alaska Energy and Resources Company Unsecured Long-Term Debt** | **Alaska Energy and Resources Company Unsecured Long-Term Debt** |  |  |  |
| 2029 | Unsecured Term Loan | 5.92% | 15 | 15 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Total secured and unsecured long-term debt |  | 2774 | 2634 |
| **Other Long-Term Debt Components** | **Other Long-Term Debt Components** |  |  |  |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Unamortized debt discount |  | (1) | (1) |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Unamortized long-term debt issuance costs |  | (19) | (19) |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total long-term debt |  | $2754 | $2614 |

---

(1)In July 2025, the Company issued and sold $120 million of 6.18 percent first mortgage bonds due in 2055 with institutional investors in the private placement market. The net proceeds from the sale of the bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit.

(2)In July 2025, AEL&P entered into a term loan agreement in the amount of $20 million with an interest rate of 5.49 percent and a maturity date of July 2030. AEL&P borrowed the entire $20 million available under the agreement, and used the net proceeds to repay borrowings outstanding under AEL&P's committed line of credit, as well as fund capital expenditures. The term loan is secured under the first mortgage bonds issued to the agent bank that would become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the term loan. The term loan contains customary covenants and default provisions including a covenant which does not permit the ratio of "Consolidated Total Debt to Consolidated Total Capitalization" to be greater than 67.5 percent at any time. As of December 31, 2025, AEL&P complied with this covenant.

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***AVISTA CORPORATION***

The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 17) (dollars in millions):

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total |
| Debt maturities | $— | $— | $25 | $15 | $20 | $2766 | $2826 |

---

Substantially all of Avista Utilities' and AEL&P's owned properties are subject to the lien of their respective mortgage indentures. Under the Mortgages and Deeds of Trust (Mortgages) securing their first mortgage bonds (including secured medium-term notes), Avista Utilities and AEL&P may each issue additional first mortgage bonds under their specific mortgage in an aggregate principal amount equal to the sum of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•66-2/3 percent of the cost or fair value to the Company (whichever is lower) of property additions of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•an equal principal amount of retired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•deposit of cash.

Avista Utilities and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has "net earnings" (as defined in that entity's Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2025, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.8 billion by Avista Corp. in an aggregate principal amount of additional first mortgage bonds and $41 million by AEL&P, at an assumed interest rate of 8 percent in each case.

**NOTE 17. 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 paid were as follows during the years ended December 31:

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| Low distribution rate | 4.93% | 5.64% | 5.64% |
| High distribution rate | 5.64% | 6.51% | 6.55% |
| Distribution rate at the end of the year | 4.93% | 5.64% | 6.51% |

---

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $2 million of Common Trust Securities to the Company. These Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 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 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 Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures.

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***AVISTA CORPORATION***

**NOTE 18. FAIR VALUE**

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings as shown on the Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and finance leases), and long-term debt to affiliated trusts as shown on the 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 that include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also 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 Consolidated Balance Sheets as of December 31 (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | 2025 | 2025 | 2024 | 2024 |
|  | Carrying<br>Value | Estimated<br>Fair Value | Carrying<br>Value | Estimated<br>Fair Value |
| Long-term debt (Level 2) | $1100 | $953 | $1100 | $938 |
| Long-term debt (Level 3) | 1674 | 1326 | 1534 | 1163 |
| Snettisham finance lease obligation (Level 3) | 36 | 33 | 39 | 35 |
| Long-term debt to affiliated trusts (Level 3) | 52 | 46 | 52 | 47 |

---

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 58.88 to 108.35 percent of the principal amount, where 100.00 percent represents the carrying value recorded on the 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

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***AVISTA CORPORATION***

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 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 Consolidated Balance Sheets as of December 31, 2025 at fair value on a recurring basis (dollars in millions):

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | Level 1 | Level 2 | Level 3 | Counterparty<br>and Cash <br>Collateral <br>Netting (1) | Total |
| **December 31, 2025** |  |  |  |  |  |
| **Assets:** |  |  |  |  |  |
| Energy commodity derivatives | $— | $17 | $— | $(9) | $8 |
| Equity investments (3) |  |  | 49 |  | 49 |
| Deferred compensation assets: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Mutual Funds: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Fixed income securities (3) | 2 |  |  |  | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equity securities (3) | 7 |  |  |  | 7 |
| Total | $9 | $17 | $49 | $(9) | $66 |
| **Liabilities:** |  |  |  |  |  |
| Energy commodity derivatives (2) | $— | $37 | $10 | $(19) | $28 |
| Total | $— | $37 | $10 | $(19) | $28 |

---

The following table discloses by level within the fair value hierarchy the Company's assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2024 at fair value on a recurring basis (dollars in millions):

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | Level 1 | Level 2 | Level 3 | Counterparty<br>and Cash <br>Collateral <br>Netting (1) | Total |
| **December 31, 2024** |  |  |  |  |  |
| **Assets:** |  |  |  |  |  |
| Energy commodity derivatives | $— | $23 | $— | $(13) | $10 |
| Interest rate swap derivatives |  | 1 |  |  | 1 |
| Equity investments (3) |  |  | 53 |  | 53 |
| Deferred compensation assets: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Mutual Funds: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Fixed income securities (3) | 2 |  |  |  | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equity securities (3) | 7 |  |  |  | 7 |
| Total | $9 | $24 | $53 | $(13) | $73 |
| **Liabilities:** |  |  |  |  |  |
| Energy commodity derivatives (2) | $— | $61 | $3 | $(37) | $27 |
| Total | $— | $61 | $3 | $(37) | $27 |

---

(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 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 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 Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 8 for additional discussion of derivative netting.

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***AVISTA CORPORATION***

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 December 31, 2025 (dollars in millions, except mmBTU amounts):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Fair Value (Net) at |  |  |  |
|  | December 31, 2025 | Valuation Technique | Unobservable Input | Range |
| Natural gas exchange | $(10) | Internally derived<br>weighted average<br>cost of gas | Forward purchase prices | $1.33 - $3.25/mmBTU<br>$2.46 Weighted Average |
|  |  |  | Forward sales prices | $1.60 - $8.00/mmBTU<br>$4.66 Weighted Average |
|  |  |  | Purchase volumes | 270,000 - 310,000 mmBTUs |
|  |  |  | Sales volumes | 75,000 - 310,000 mmBTUs |

---

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 has two 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 the 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, the 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

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***AVISTA CORPORATION***

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 are relevant market transactions for the same or similar securities of the subject company or there is a reasonable possibility of a transaction occurring, those transactions are 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 which was used to estimate the fair values of the Level 3 equity investments as of December 31, 2025 (dollars in millions):

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Fair Value at |  |  |  |
|  | December 31, 2025 | Valuation Technique | Unobservable Input | Range |
| Equity investments | $49 | Market approach | Comparable enterprise values | $130-$389<br>$246 Average |
|  |  |  | Time to liquidity event | 2 years |
|  |  | Discounted cash flows | Revenue market multiples | 0.75x to 5.05x Revenue<br>3.27x Average |
|  |  |  | Market multiple exit reduction | 68% |
|  |  |  | Discount rate | 20% |
|  |  |  | Annual revenues | $12-$208 |
|  |  |  | Terminal date | 2031 |

---

There were no transfers into or out of Level 3 fair value measurements during the period. The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | Natural Gas Exchange Agreement | Equity Investments | Total |
| **2025:** |  |  |  |
| Balance as of January 1, 2025 | $(3) | $53 | $50 |
| Total gains or (losses) (realized/unrealized): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Included in regulatory assets | (5) |  | (5) |
| &nbsp;&nbsp;&nbsp;&nbsp;Recognized in net income | (2) | (4) | (6) |
| Ending balance as of December 31, 2025 | $(10) | $49 | $39 |
| **2024:** |  |  |  |
| Balance as of January 1, 2024 | $(8) | $50 | $42 |
| Total gains or (losses) (realized/unrealized): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Included in regulatory assets | 5 |  | 5 |
| Purchases and debt conversions |  | 3 | 3 |
| Ending balance as of December 31, 2024 | $(3) | $53 | $50 |
| **2023:** |  |  |  |
| Balance as of January 1, 2023 | $(18) | $54 | $36 |
| Total gains or (losses) (realized/unrealized): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Included in regulatory assets | 10 |  | 10 |
| &nbsp;&nbsp;&nbsp;&nbsp;Recognized in net income |  | (4) | (4) |
| Purchases and debt conversions |  | 3 | 3 |
| Other |  | (3) | (3) |
| Ending balance as of December 31, 2023 | $(8) | $50 | $42 |

---

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***AVISTA CORPORATION***

**NOTE 19. COMMON STOCK**

The payment of dividends on common stock could be limited by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain covenants applicable to preferred stock (when outstanding) contained in the Company's Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 40 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

The requirements of the OPUC approval of the AERC acquisition are the most restrictive. Under the OPUC restriction, the amount available for dividends at December 31, 2025 was $332 million.

See the Consolidated Statements of Equity for dividends declared in the years 2023 through 2025.

The Company has 10 million authorized shares of preferred stock. The Company did not have preferred stock outstanding as of December 31, 2025 and 2024.

***Common Stock Issuances***

The Company issued common stock for total net proceeds of $78 million in 2025. Most of these issuances were made through sales agency agreements under which the Company may offer and sell new shares of common stock from time to time through its sales agents. In 2025, 2.0 million shares were issued under these agreements.

**NOTE 20. ACCUMULATED OTHER COMPREHENSIVE LOSS**

***Accumulated Other Comprehensive Loss***

Accumulated other comprehensive loss, net of tax, was immaterial as of December 31, 2025 and December 31, 2024.

The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in millions):

---

| | | | |
|:---|:---|:---|:---|
|  | Amounts Reclassified from Accumulated Other<br>Comprehensive (Loss) Income | Amounts Reclassified from Accumulated Other<br>Comprehensive (Loss) Income | Amounts Reclassified from Accumulated Other<br>Comprehensive (Loss) Income |
| Details about Accumulated Other Comprehensive (Loss) Income Components<br>(Affected Line Item in Statements of Income) | 2025 | 2024 | 2023 |
| Amortization of defined benefit pension and postretirement benefit items |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of net prior service cost (a) | $— | $1 | $(1) |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of net loss (a) | 31 | (12) | 19 |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjustment due to effects of regulation (a) | (32) | 11 | (16) |
| Total before tax (b) | (1) |  | 2 |
| Tax expense (b) |  |  |  |
| Net of tax (b) | $(1) | $— | $2 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 12 for additional details).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)Description is also the affected line item on the Consolidated Statements of Income.

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***AVISTA CORPORATION***

**NOTE 21. EARNINGS PER COMMON SHARE**

The following table presents the computation of basic and diluted earnings per common share for the years ended December 31 (dollars in millions, except per share amounts, and shares in thousands):

---

| | | | |
|:---|:---|:---|:---|
|  | 2025 | 2024 | 2023 |
| **Numerator:** |  |  |  |
| Net income | $193 | $180 | $171 |
| **Denominator:** |  |  |  |
| Weighted-average number of common shares outstanding-basic | 80975 | 78725 | 76396 |
| Effect of dilutive securities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Performance and restricted stock awards | 76 | 95 | 100 |
| Weighted-average number of common shares outstanding-diluted | 81051 | 78820 | 76495 |
| **Earnings per common share (1):** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Basic | $2.38 | $2.29 | $2.24 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Diluted | $2.38 | $2.29 | $2.24 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Per share amounts may not recalculate due to rounding of numerator and denominator amounts within this table.

There were no shares excluded from the calculation because they were antidilutive.

**NOTE 22. 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 Avista Utilities' or AEL&P's 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 a four-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.

***Boyds Fire (State of Washington Department of Natural Resources v. Avista)***

In August 2019, the Company was served with a complaint, captioned "State of Washington Department of Natural Resources v. Avista Corporation," seeking recovery of up to $4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire (known as the "Boyds Fire") that occurred in Ferry County, Washington, in August 2018. Additional lawsuits were subsequently filed by private landowners seeking $1 million in property damages as well as potential non-economic damages, and holders of insurance subrogation claims seeking recovery of $2 million in insurance proceeds purportedly paid to their insureds.

In June 2025, the Company settled with a single plaintiff which only named the Company as a defendant for less than $0.1 million. Additionally, the Company, along with its independent vegetation management contractors Asplundh Tree Company and CN Utility Consulting, reached agreements to settle all claims included in the remaining lawsuits for $3 million. None of the settlements in these cases were the responsibility of the Company, but rather the responsibility was split between Asplundh Tree Company and CN Utility Consulting.

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***AVISTA CORPORATION***

***Labor Day 2020 Windstorm/Babb Road Fire***

In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and multiple wildfires in the region, including the Babb Road Fire, which occurred near the town of Malden, Washington.

Eleven lawsuits were filed in connection with the Babb Road Fire. CN Utility Consulting, which performs vegetation management services as an independent contractor to the Company, was also named as defendants in each of the lawsuits. The lawsuits included six subrogation actions filed by 51 insurance companies and five actions on behalf of 128 individual plaintiffs.

In April and May 2025, the Company and CN Utility Consulting reached agreements to settle all claims included in the lawsuits. The total settlement paid was $27 million, of which the Company paid $21 million and CN Utility Consulting was responsible for $6 million. An order dismissing all cases was entered by the Court in September 2025. The Company received insurance proceeds for the settlement amounts paid, resulting in no impact on net income.

***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. Except for three minor claims for damage to personal property which were resolved, the Company has not, at this time, received any claims in connection with the fire. The Company will vigorously defend itself in the event any additional claims are asserted; however, at this time, it is unable to estimate the likelihood of an adverse outcome or the amount or range of a potential loss in the event of an adverse outcome.

***Colstrip***

*Colstrip Owners Arbitration and Litigation*

Prior to January 1, 2026, Colstrip Units 3 and 4 were owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen Montana, LLC (Talen), as tenants in common under an Ownership and Operating Agreement, dated May 6, 1981, as amended (O&O Agreement), in the percentages set forth below:

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| | | |
|:---|:---|:---|
| **Co-Owner** | **Unit 3** | **Unit 4** |
| Avista | 15% | 15% |
| PacifiCorp | 10% | 10% |
| PGE | 20% | 20% |
| PSE | 25% | 25% |
| NorthWestern |  | 30% |
| Talen | 30% |  |

---

Colstrip Units 1 and 2, owned by PSE and Talen, were shut down in 2020 and are in the process of being decommissioned. The co-owners of Units 3 and 4 also own undivided interests in facilities common to both Units 3 and 4, as well as in certain facilities common to all four Colstrip units.

The Washington Clean Energy Transformation Act (CETA), among other things, imposed deadlines by which each electric utility must eliminate from its electricity rates in Washington the costs and benefits associated with coal-fired resources, such as Colstrip. The practical impact of CETA was that electricity from such resources, including Colstrip, could no longer be delivered to Washington retail customers after 2025.

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***AVISTA CORPORATION***

*Agreement Between Avista and NorthWestern*

In January 2023, the Company entered into an agreement with NorthWestern under which, subject to the terms and conditions specified in the agreement, the Company would transfer its 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There was no monetary exchange included in the transaction. The transaction closed at midnight on January 1, 2026.

Under the agreement, the Company was obligated through the close of the transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the portion allocable pro rata to the portion of useful life (through 2030) expired through the close of the transaction, and (iii) site remediation expenses except certain costs relating to post closing activities. In addition, under the agreement, the Company retained its voting rights with respect to decisions relating to remediation.

The Company retained its interest in the Colstrip transmission line between Colstrip, Montana to Townsend, Montana, which is excluded from the transaction.

*Agreement Between PSE and NorthWestern*

In July 2024, PSE entered into an agreement with NorthWestern under which, PSE will transfer its 25 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There was no monetary exchange included in the transaction. The transaction closed at midnight on January 1, 2026.

*Burnett et al. v. Talen et al.*

Multiple property owners initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, PacifiCorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs alleged the failure to contain coal dust in connection with the operation of Colstrip, and was seeking unspecified damages. In March 2025, the parties reached an agreement to settle all claims in the matter for $1 million, with the majority of that amount being paid through insurance proceeds and the remainder by entities other than the owners of Colstrip.

*Westmoreland Mine Permits*

Two lawsuits have been commenced by the Montana Environmental Information Center and others, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine, which decision was subsequently upheld by the Montana Supreme Court. In the second, the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation and Enforcement, a branch of the United States Department of the Interior, approving expansion of the mine into a new area, pending further analysis of potential environmental impact. An initial appeal of that decision to the Ninth Circuit was dismissed for lack of jurisdiction, pending further proceedings before the Department of the Interior. Avista Corp. is not a party to either of these proceedings, and is no longer impacted by the outcome of these proceedings, given its transfer of Colstrip to NorthWestern.

***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. The Company continues to vigorously defend itself in the legal proceedings; 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.

***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

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***AVISTA CORPORATION***

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.

***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.

The Company routinely assesses, based on studies, expert analysis and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company's policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred.

The Company has potential liabilities under the Endangered Species Act and similar state statutes for species of fish, plants and wildlife that have either already been added to the endangered species list, listed as "threatened" or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to these issues.

Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the Company holds additional non-hydro water rights. The States of Montana and Idaho are each conducting general adjudications of water rights in areas that include the Company's facilities in these states. Claims within the Clark Fork River basin and the Spokane River basin could adversely affect the energy production of the Company's hydroelectric facilities. The Company is and will continue to be a participant in the adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all costs related to this issue.

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***AVISTA CORPORATION***

**NOTE 23. REGULATORY MATTERS**

***Regulatory Assets and Liabilities***

The following table presents the Company's regulatory assets and liabilities as of December 31, 2025 (dollars in millions):

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  | Receiving<br>Regulatory Treatment | Receiving<br>Regulatory Treatment |  | 2025 | 2025 | 2024 | 2024 |
|  | Remaining<br>Amortization<br>Period | (1)<br>Earning<br>A Return | Not<br>Earning<br>A Return | (2)<br>Expected<br>Recovery<br>or Refund | Current | Non-<br>current | Current | Non-<br>current |
| **Regulatory Assets:** |  |  |  |  |  |  |  |  |
| Deferred income tax | (3) (16) | $— | $246 | $— | $— | $246 | $— | $246 |
| Pensions and other<br> postretirement benefit plans | (4) |  | 73 |  | 1 | 72 |  | 106 |
| Climate Commitment Act | (14) | 24 |  |  | 24 |  | 50 |  |
| Energy commodity<br> derivatives | (5) |  | 30 |  | 18 | 12 | 27 | 14 |
| Unamortized debt repurchase<br> costs | (6) | 5 |  |  |  | 5 |  | 5 |
| Settlement with<br> Coeur d'Alene Tribe | 2059 | 34 |  |  |  | 34 |  | 36 |
| Demand side management<br> programs | (3) |  | 57 |  |  | 57 |  | 38 |
| Decoupling surcharge | 2027 | 48 |  |  | 27 | 21 | 12 | 12 |
| Utility plant abandoned | (7) | 33 |  |  | 2 | 31 | 4 | 38 |
| Interest rate swaps | (8) | 165 |  |  |  | 165 |  | 172 |
| Deferred power costs | (3) | 88 |  |  | 17 | 71 | 9 | 27 |
| AFUDC above FERC<br> allowed rate | (11) | 51 |  |  |  | 51 |  | 49 |
| COVID-19 deferrals | (12) |  |  |  |  |  |  | 12 |
| Advanced meter infrastructure | (13) | 23 |  |  | 3 | 20 |  | 26 |
| Colstrip | (17) | 33 |  |  | 2 | 31 | 15 | 10 |
| Wildfire resiliency | (18) | 8 | 18 |  | 9 | 17 | 10 | 13 |
| Insurance deferrals | (18) | 9 | 7 |  | 8 | 8 | 4 | 7 |
| Other regulatory assets | (3) | 21 | 22 | 11 | 24 | 30 | 6 | 36 |
| Total regulatory assets |  | $542 | $453 | $11 | $135 | $871 | $137 | $847 |
| **Regulatory Liabilities:** |  |  |  |  |  |  |  |  |
| Deferred natural gas costs | (3) | $33 | $— | $— | $33 | $— | $25 | $— |
| Deferred power costs | (3) | 7 |  |  | 7 |  | 8 | 6 |
| Utility plant retirement costs | (9) | 468 |  |  |  | 468 |  | 448 |
| Excess deferred income taxes | (10) | 279 |  |  | 13 | 266 | 14 | 279 |
| Other income tax related liabilities | (3) (15) | 30 | 28 |  | 7 | 51 | 5 | 59 |
| Climate Commitment Act | (14) | 33 | 1 |  | 34 |  | 44 |  |
| Interest rate swaps | (8) | 22 |  | 1 |  | 23 |  | 24 |
| Decoupling rebate | 2027 | 4 |  |  | 1 | 3 | 4 |  |
| Provision for rate refund | (3) | 13 |  |  | 13 |  |  |  |
| COVID-19 deferrals | (12) |  |  |  |  |  |  | 10 |
| Other regulatory liabilities | (3) | 8 | 13 | 4 | 18 | 7 | 8 | 8 |
| Total regulatory liabilities |  | $897 | $42 | $5 | $126 | $818 | $108 | $834 |

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(1)Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return.

(2)Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence.

(3)Remaining amortization period varies depending on timing of underlying transactions.

(4)As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.

(5)The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of

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***AVISTA CORPORATION***

mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and losses result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates.

(6)Premiums paid or discounts received to repurchase debt are amortized over the remaining life of the original debt repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. These costs are recovered through retail rates as a component of interest expense.

(7)The WUTC approved recovery of AMI project costs through the 2020 general rate case settlements, including amortization of retired meters replaced through the project through 2033. The IPUC approved deferral accounting treatment for the Idaho AMI project, which will be included in a future rate case. In addition, the IPUC approved the depreciation of Colstrip through 2027, and as such the remaining depreciation after our exit of Colstrip in 2025 is included in this balance. There are additional smaller projects included in the balance the Company expects to fully recover, which have not yet been through the regulatory process.

(8)For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no impact on the income statement. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. Settled interest rate swap derivatives which have been through a general rate case proceeding are classified as earning a return in the table above, whereas all unsettled interest rate swap derivatives and settled interest rate swap derivatives which have not been included in a general rate case are classified as expected recovery.

(9)This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

(10)This balance represents amounts due back to customers and resulted from the Tax Cuts and Jobs Act signed into law in December 2017, which changed the federal income tax rate from 35 percent to 21 percent. The Company revalued all deferred income taxes as of December 31, 2017. The Company expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 29 years. The Company expects the AEL&P amounts to be returned to customers over a period of approximately 20 years.

(11)This amount is being amortized based on the underlying utility plant assets and the life of utility plant.

(12)The WUTC, IPUC and OPUC issued accounting orders allowing the Company to defer certain costs, net of benefits, related to the COVID-19 pandemic. The Company has recorded all benefits on a gross basis as a regulatory liability to customers and all additional allowed costs are a regulatory asset. The ratemaking treatment is being determined in general rate cases in each jurisdiction.

(13)This amount represents the deferral of the depreciation expense of the Company's AMI project in Washington state. Recovery of these amounts was approved by WUTC in the 2021 general rate case order, and the asset will be amortized through 2033.

(14)Regulatory assets related to the Climate Commitment Act represent costs incurred to comply with the program. Regulatory liabilities related to the Climate Commitment Act represent proceeds from the required sale of allowances, which will be returned to customers. The Company submits filings periodically to receive approval to include these items in customer rates.

(15)The portion of this balance earning a return represents the remaining tax customer credits being returned to customers. The majority of the portion not earning a return represents investment tax credits, which have a corresponding deferred tax asset within Note 13 which is also excluded from rate base.

(16)The majority of this balance represents flow-through income tax accounting differences and the related tax gross-up which have a corresponding deferred tax liability within Note 13 which is also excluded from rate base.

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***AVISTA CORPORATION***

(17)The majority of this balance relates to decommissioning and remediation costs, including asset retirement obligations, associated with Colstrip. The Company retained these obligations through the transfer of its ownership to NorthWestern.

(18)These balances are primarily balancing accounts, by which the WUTC and IPUC sets a base expense level, and any costs incurred above that base are deferred to be recovered from customers at a later date.

***Power Cost Deferrals and Recovery Mechanisms***

Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•short-term wholesale market prices and sales and purchase volumes,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the level, availability and optimization of hydroelectric generation,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•the level and availability of thermal generation (including changes in fuel prices),

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•retail loads, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•sales of surplus transmission capacity.

In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Under the ERM, the Company defers these differences (over the $4 million deadband and sharing bands) for future surcharge or rebate to customers.

The following is a summary of the ERM:

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| | | |
|:---|:---|:---|
| <u>Annual Power Supply Cost Variability</u> | Deferred for<br>Future<br>Surcharge or<br>Rebate<br>to Customers | Expense or<br>Benefit<br>to the Company |
| within +/- $0 to $4 million (deadband) | 0% | 100% |
| higher by $4 million to $10 million | 50% | 50% |
| lower by $4 million to $10 million | 75% | 25% |
| higher or lower by over $10 million | 90% | 10% |

---

Total net deferred power costs under the ERM were assets of $85 million as of December 31, 2025 and $36 million as of December 31, 2024. The deferred power cost assets represent amounts due from customers, and deferred power cost liabilities represent amounts due to customers.

Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, the Company must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. Avista Utilities makes an annual filing on, or before, April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of, and audit, the ERM deferred power cost transactions for the prior calendar year. The Company received approval to recover $32 million of the ERM deferred surcharge balance over a two-year period starting July 1, 2025.

Avista Utilities has a PCA mechanism in Idaho allowing for the modification of electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were liabilities of $5 million as of December 31, 2025 and $15 million as of December 31, 2024. Deferred power cost assets represent amounts due from customers and liabilities represent amounts due to customers.

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***AVISTA CORPORATION***

***Natural Gas Cost Deferrals and Recovery Mechanisms***

Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. In Oregon, the Company absorbs (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in base retail rates for supply that is not hedged. Total net deferred natural gas costs were a liability of $33 million as of December 31, 2025 and $25 million as of December 31, 2024. Liability balances represent amounts due to customers.

***Decoupling and Earnings Sharing Mechanisms***

Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of Avista Utilities' jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in decoupling mechanisms.

*Washington Decoupling and Earnings Sharing*

In Washington, the WUTC approved the Company's decoupling mechanisms for electric and natural gas through December 2026.

Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase on an annual basis, with remaining surcharge balance carried forward for recovery in a future period. There is no limit to the level of rebate rate adjustments. New customers added after a test period are not decoupled until included in a future test period.

The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. Through the 2022 general rate cases, the Company modified its earnings test so that if the Company earns more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, the Company will defer these excess revenues and later return them to customers.

*Idaho FCA and Earnings Sharing Mechanisms*

In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas through March 31, 2025. A pending application would extend the mechanism through August 31, 2029.

*Oregon Decoupling Mechanism*

In Oregon, the Company has a decoupling mechanism for natural gas. An earnings review is conducted on an annual basis. In the annual earnings review, if the Company earns more than 100 basis points above its allowed ROE, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. The earnings review is separate from the decoupling mechanism and was in place prior to decoupling.

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***AVISTA CORPORATION***

*Cumulative Decoupling and Earnings Sharing Mechanism Balances*

As of December 31, 2025 and December 31, 2024, the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in millions):

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| | | |
|:---|:---|:---|
|  | December 31, | December 31, |
|  | 2025 | 2024 |
| **Washington** |  |  |
| Decoupling surcharge | $31 | $18 |
| Provision for earnings sharing rebate | $(4) | $— |
| **Idaho** |  |  |
| Decoupling surcharge | $4 | $1 |
| **Oregon** |  |  |
| Decoupling surcharge | $9 | $1 |

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**NOTE 24. 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 considered one 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. Decisions by 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.

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***AVISTA CORPORATION***

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

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | Reportable Segments | Reportable Segments |  |  |  |  |
|  | Avista<br>Utilities | Alaska<br>Electric<br>Light and<br>Power<br>Company | Total Utility | Other Non-Reportable Segment Items | Eliminations<br>(1) | Total |
| **2025** |  |  |  |  |  |  |
| Operating revenues | $1916 | $47 | $1963 | $1 | $— | $1964 |
| Resource costs | 689 | 2 | 691 |  |  | 691 |
| Other operating expenses | 487 | 17 | 504 | 5 |  | 509 |
| Depreciation and amortization | 277 | 12 | 289 |  |  | 289 |
| Interest income | 13 |  | 13 | 1 | (2) | 12 |
| Interest expense (2) | 147 | 6 | 153 | 3 | (2) | 154 |
| Other segment expenses (3) | 102 | 2 | 104 | 12 |  | 116 |
| Income tax expense (benefit) | 26 | 2 | 28 | (4) |  | 24 |
| Net income (loss) | 201 | 6 | 207 | (14) |  | 193 |
| Capital expenditures (4) | 553 | 17 | 570 |  |  | 570 |
| **2024** |  |  |  |  |  |  |
| Operating revenues | $1887 | $50 | $1937 | $1 | $— | $1938 |
| Resource costs | 794 | 4 | 798 |  |  | 798 |
| Other operating expenses | 426 | 17 | 443 | 1 |  | 444 |
| Depreciation and amortization | 263 | 11 | 274 |  |  | 274 |
| Interest income | 15 |  | 15 | 1 | (2) | 14 |
| Interest expense (2) | 143 | 6 | 149 | 3 | (2) | 150 |
| Other segment expenses (3) | 95 | 1 | 96 | 7 |  | 103 |
| Income tax expense (benefit) | 2 | 3 | 5 | (2) |  | 3 |
| Net income (loss) | 179 | 8 | 187 | (7) |  | 180 |
| Capital expenditures (4) | 510 | 23 | 533 |  |  | 533 |
| **2023** |  |  |  |  |  |  |
| Operating revenues | $1703 | $48 | $1751 | $1 | $— | $1752 |
| Resource costs | 698 | 4 | 702 |  |  | 702 |
| Other operating expenses | 399 | 15 | 414 | 3 |  | 417 |
| Depreciation and amortization | 254 | 11 | 265 |  |  | 265 |
| Interest income | 15 |  | 15 | 1 | (1) | 15 |
| Interest expense (2) | 137 | 6 | 143 | 2 | (1) | 144 |
| Other segment expenses (3) | 98 |  | 98 | 4 |  | 102 |
| Income tax expense (benefit) | (35) | 3 | (32) | (2) |  | (34) |
| Net income (loss) | 167 | 9 | 176 | (5) |  | 171 |
| Capital expenditures (4) | 485 | 14 | 499 | 0 |  | 499 |
| **Total Assets:** |  |  |  |  |  |  |
| As of December 31, 2025 | $7917 | $289 | $8206 | $177 | $(24) | $8359 |
| As of December 31, 2024 | 7494 | 283 | 7777 | 194 | (30) | 7941 |
| As of December 31, 2023 | 7263 | 270 | 7533 | 191 | (22) | 7702 |

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(1)Eliminations reported as interest expense and interest income represent intercompany interest. Eliminations reported as assets represent intersegment accounts receivable.

(2)Including interest expense to affiliated trusts.

(3)Other segment items include taxes other than income tax, AFUDC equity, other miscellaneous expenses, and earnings (losses) from investments.

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

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***AVISTA CORPORATION***

**<u>Item 9. Changes in and Disagreements with Acco</u><u>untants on Accounting and Financial Disclosure</u>**

Not applicable.

**<u>Item 9A. Control</u><u>s and Procedures</u>**

***Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures***

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company's management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company's principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company's principal executive officer and principal financial officer have concluded that the Company's disclosure controls and procedures are effective at a reasonable assurance level as of December 31, 2025.

***Management's Report on Internal Control Over Financial Reporting***

The Company's management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). The Company's internal control over financial reporting is a process designed under the supervision of the Company's principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America.

The Company's internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the Company's financial statements.

Under the supervision and with the participation of the Company's management, including the Company's principal executive officer and principal financial officer, the Company conducted an assessment of the effectiveness of the Company's internal control over financial reporting based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company's internal control over financial reporting as of December 31, 2025 is effective at a reasonable assurance level.

The Company's independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the Company's internal control over financial reporting as of December 31, 2025.

***Changes in Internal Control Over Financial Reporting***

There have been no changes in the Company's internal control over financial reporting that occurred during the Company's last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

------

***AVISTA CORPORATION***

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Avista Corporation

**Opinion on Internal Control over Financial Reporting**

We have audited the internal control over financial reporting of Avista Corporation and subsidiaries (the "Company") as of December 31, 2025, based on criteria established in *Internal Control — Integrated Framework (2013)* issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in *Internal Control — Integrated Framework (2013)* issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report dated February 24, 2026, expressed an unqualified opinion on those financial statements.

**Basis for Opinion**

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

**Definition and Limitations of Internal Control over Financial Reporting**

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Portland, Oregon

February 24, 2026

------

***AVISTA CORPORATION***

**<u>Item 9B. Other</u> <u>Information</u>**

During the fiscal quarter ended December 31, 2025, none of our directors or officers informed us of the adoption or termination of a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as those terms are defined in Regulation S-K, Item 408. A copy of our insider trading policy has been included as Exhibit 19 to this report.

**<u>Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections</u>**

Not applicable.

------

***AVISTA CORPORATION***

**PART III**

**<u>Item 10. Directors, Executive Of</u><u>ficers and Corporate Governance</u>**

The information required by this Item (other than the information regarding executive officers and the Company's Code of Business Conduct and Ethics set forth below) is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:

• on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 14, 2026, from such Proxy Statement; and

• prior to such date, from the Registrant's definitive Proxy Statement, dated March 26, 2025, relating to its Annual Meeting of Shareholders held on May 8, 2025.

---

| | | |
|:---|:---|:---|
| Information about our Executive Officers | Information about our Executive Officers | Information about our Executive Officers |
| Name | Age | Business Experience |
| Heather L. Rosentrater | 48 | President, Chief Executive Officer and Director since January 2025, President and Chief Operating Officer October 2023-December 2024; Senior Vice President and Chief Operating Officer from September 2022 to October 2023; Senior Vice President, Energy Delivery and Shared Services from January 2020 to September 2022; Senior Vice President, Energy Delivery from October 2019 to December 2019; Vice President of Energy Delivery from December 2015 to October 2019; various other management and staff positions with the Company since 1996. |
| Kevin J. Christie | 58 | Senior Vice President, Chief Financial Officer, Treasurer and Regulatory Affairs Officer since May 2023; Senior Vice President, External Affairs and Chief Customer Officer from October 2019 to May 2023; Vice President, External Affairs and Chief Customer Officer January 2018 to October 2019; Vice President of Customer Solutions from February 2015 to January 2018; various other management and staff positions with the Company since 2005. |
| Bryan A. Cox | 56 | Senior Vice President, Safety and Chief People Officer since October 2023; Vice President, Safety and Chief People Officer from September 2022 to October 2023; Vice President, Safety and Human Resources from January 2020 to September 2022; Vice President, Safety and HR Shared Services from January 2018 to January 2020; various other management and staff positions with the Company since 1997. |
| Gregory C. Hesler | 48 | Senior Vice President, General Counsel, Corporate Secretary and Chief Ethics/Compliance Officer since September 2022; Vice President, General Counsel, Corporate Secretary and Chief Ethics/Compliance Officer from May 2020 to September 2022; Vice President, General Counsel and Chief Compliance Officer from January 2020 to May 2020; various other management and staff positions with the Company since 2015. |
| Wayne O. Manuel | 53 | Senior Vice President, Operations and Technology since October 2025; Vice President, Chief Information Officer and Chief Security Officer since June 2023 to September 2025; prior to employment with the Company, Senior Vice President, Chief Strategy Officer and Chief Information Officer of Valley Medical Center from 2014 to May 2023. |
| Jason R. Thackston | 56 | Senior Vice President, Growth, Energy Policy and External Relations since October 2025; Senior Vice President, Energy Policy and Chief Strategy Officer from January 2025 to September 2025; Senior Vice President, Chief Strategy and Clean Energy Officer September 2022 to December 2024; Senior Vice President of Energy Resources and Environmental Compliance Officer from May 2018 to September 2022; Senior Vice President of Energy Resources from January 2014 to May 2018; Vice President of Energy Resources from December 2012 to January 2014; Vice President of Customer Solutions – Avista Utilities from June 2012 to December 2012; Vice President of Energy Delivery from April 2011 to December 2012; Vice President of Finance from June 2009 to April 2011; various other management and staff positions with the Company since 1996. |
| Alexis G. Alexander | 43 | Vice President, Chief Information Officer and Chief Security Officer since October 2025; various other management and staff positions with the Company since 2006. |

---

------

***AVISTA CORPORATION***

---

| | | |
|:---|:---|:---|
| Joshua D. DiLuciano | 45 | Vice President, Energy Delivery since September 2022; various other management and staff positions with the Company since 2006. |
| Latisha D. Hill | 47 | Vice President, Community Affairs and Chief Customer Officer since May 2023; Vice President of Community and Economic Vitality from January 2020 to May 2023; various other management and staff positions with the Company since 2005. |
| Scott J. Kinney | 57 | Vice President, Energy Resources and Integrated Planning since January 2025; Vice President of Energy Resources from September 2022 to December 2024; various other management and staff positions with the Company since 1999. |
| Ryan L. Krasselt | 56 | Vice President, Controller and Principal Accounting Officer since October 2015; various other management and staff positions with the Company since 2001. |

---

All of the Company's executive officers, with the exception of Alexis G. Alexander, Joshua D. DiLuciano, Scott J. Kinney and Wayne O. Manuel were officers or directors of one or more of the Company's subsidiaries in 2025. The Company's executive officers are appointed annually by the Board of Directors.

The Company has adopted a Code of Conduct for directors, officers (including the principal executive officer, principal financial officer and principal accounting officer), and employees. The Code of Conduct is available on the Company's website at www.avistacorp.com and will be provided to any shareholder without charge upon written request to:

Avista Corp.

General Counsel

P.O. Box 3727 MSC-10

Spokane, Washington 99220-3727

Any changes to or waivers for executive officers and directors of the Company's Code of Conduct will be posted on the Company's website.

**<u>Item 11. Executi</u><u>ve Compensation</u>**

The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:

• on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 14, 2026, from such Proxy Statement; and

• prior to such date, from the Registrant's definitive Proxy Statement, dated March 26, 2025, relating to its Annual Meeting of Shareholders held on May 8, 2025.

**<u>Item 12. Security Ownership of Certain Beneficial Ow</u><u>ners and Management and Related Stockholder Matters</u>**

(a)Security ownership of certain beneficial owners (owning 5 percent or more of Registrant's voting securities):

Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant's voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:

• on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 14, 2026, from such Proxy Statement; and

• prior to such date, from the Registrant's definitive Proxy Statement, dated March 26, 2025, relating to its Annual Meeting of Shareholders held on May 8, 2025; reference also being made to Schedules 13G, as amended, on file with the SEC with respect to the Registrant's voting securities (the information contained in such schedules 13G, as amended, not being incorporated herein by reference).

(b)Security ownership of management:

The information required by this Item regarding the security ownership of management is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:

------

***AVISTA CORPORATION***

• on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 14, 2026, from such Proxy Statement; and

• prior to such date, from the Registrant's definitive Proxy Statement, dated March 26, 2025, relating to its Annual Meeting of Shareholders held on May 8, 2025.

(c)Changes in control:

None.

(d)Securities authorized for issuance under equity compensation plans as of December 31, 2025:

---

| | | | |
|:---|:---|:---|:---|
| Plan category | (a)<br>Number of securities to be<br>issued upon exercise of<br>outstanding options,<br>warrants and rights | (b)<br>Weighted average<br>exercise price of<br>outstanding options,<br>warrants and rights | (c)<br>Number of securities remaining<br>available for future issuance under<br>equity compensation plans<br>(excluding securities reflected in<br>column (a)) |
|  | (1) |  |  |
| Equity compensation plans approved by<br> security holders (2) | ― | $― | 153578 |

---

(1)Excludes unvested restricted shares and performance share awards granted under Avista Corp.'s Long-Term Incentive Plan. At December 31, 2025, 190,979 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 309,447 shares at target level; or 618,894 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance and market-based share awards, such shares are not included in the weighted-average price calculation.

(2)Includes the Long-Term Incentive Plan approved by shareholders in 1998 (amended in 2016) and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan.

**<u>Item 13. Certain Relationships and Related</u> <u>Transactions, and Director Independence</u>**

The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:

• on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 14, 2026, from such Proxy Statement; and

• prior to such date, from the Registrant's definitive Proxy Statement, dated March 26, 2025, relating to its Annual Meeting of Shareholders held on May 8, 2025.

**<u>Item 14. Principal Accou</u><u>nting Fees and Services</u>**

The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:

• on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 14, 2026, from such Proxy Statement; and

• prior to such date, from the Registrant's definitive Proxy Statement, dated March 26, 2025, relating to its Annual Meeting of Shareholders held on May 8, 2025.

------

***AVISTA CORPORATION***

**PART IV**

**<u>Item 15. Exhibits, Financ</u><u>ial Statement Schedules</u>**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)1. Financial Statements (Included in Part II of this report):

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income for the Years Ended December 31, 2025, 2024 and 2023

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023

Consolidated Balance Sheets as of December 31, 2025, and 2024

Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023

Consolidated Statements of Equity for the Years Ended December 31, 2025, 2024 and 2023

Notes to Consolidated Financial Statements

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)2. Financial Statement Schedules:

None

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)3. Exhibits:

Reference is made to the Exhibit Index commencing on the following page. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K pursuant to Item 15(b).

------

***AVISTA CORPORATION***

EXHIBIT INDEX

---

| | | | |
|:---|:---|:---|:---|
|  | Previously Filed (1) | Previously Filed (1) | |
| Exhibit | With<br>Registration <br>Number | As<br>Exhibit |  |
| [<u>2.1</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023000787/ava-ex2_1.htm) | (with Form 8-K filed as of January 17, 2023) | 2.1 | [<u>Colstrip Units 3 & 4 Interests Abandonment and Acquisition Agreement, dated as of January 16, 2023, among Avista Corporation and NorthWestern Corporation.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023000787/ava-ex2_1.htm) |
| [<u>3.1</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312512340791/d371580dex31.htm) | (with June 30, 2012 Form 10-Q) | 3.1 | [<u>Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312512340791/d371580dex31.htm) |
| [<u>3.2</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491816000260/ex32bylawsofavistacorpaug2.htm) | (with Form 8-K filed as of August 17, 2016) | 3.2 | [<u>Bylaws of Avista Corporation, as amended August 17, 2016.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491816000260/ex32bylawsofavistacorpaug2.htm) |
| 4.1 | 2-4077 | B-3 | Mortgage and Deed of Trust, dated as of June 1, 1939.\* |
| 4.2 | 2-9812 | 4(c) | First Supplemental Indenture, dated as of October 1, 1952.\* |
| 4.3 | 2-60728 | 2(b)-2 | Second Supplemental Indenture, dated as of May 1, 1953.\* |
| 4.4 | 2-13421 | 4(b)-3 | Third Supplemental Indenture, dated as of December 1, 1955.\* |
| 4.5 | 2-13421 | 4(b)-4 | Fourth Supplemental Indenture, dated as of March 15, 1967.\* |
| 4.6 | 2-60728 | 2(b)-5 | Fifth Supplemental Indenture, dated as of July 1, 1957.\* |
| 4.7 | 2-60728 | 2(b)-6 | Sixth Supplemental Indenture, dated as of January 1, 1958.\* |
| 4.8 | 2-60728 | 2(b)-7 | Seventh Supplemental Indenture, dated as of August 1, 1958.\* |
| 4.9 | 2-60728 | 2(b)-8 | Eighth Supplemental Indenture, dated as of January 1, 1959.\* |
| 4.10 | 2-60728 | 2(b)-9 | Ninth Supplemental Indenture, dated as of January 1, 1960.\* |
| 4.11 | 2-60728 | 2(b)-10 | Tenth Supplemental Indenture, dated as of April 1, 1964.\* |
| 4.12 | 2-60728 | 2(b)-11 | Eleventh Supplemental Indenture, dated as of March 1, 1965.\* |
| 4.13 | 2-60728 | 2(b)-12 | Twelfth Supplemental Indenture, dated as of May 1, 1966.\* |
| 4.14 | 2-60728 | 2(b)-13 | Thirteenth Supplemental Indenture, dated as of August 1, 1966.\* |
| 4.15 | 2-60728 | 2(b)-14 | Fourteenth Supplemental Indenture, dated as of April 1, 1970.\* |
| 4.16 | 2-60728 | 2(b)-15 | Fifteenth Supplemental Indenture, dated as of May 1, 1973.\* |
| 4.17 | 2-60728 | 2(b)-16 | Sixteenth Supplemental Indenture, dated as of February 1, 1975.\* |
| 4.18 | 2-60728 | 2(b)-17 | Seventeenth Supplemental Indenture, dated as of November 1, 1976.\* |
| 4.19 | 2-69080 | 2(b)-18 | Eighteenth Supplemental Indenture, dated as of June 1, 1980.\* |
| 4.20 | (with 1980 Form 10-K) | 4(a)-20 | Nineteenth Supplemental Indenture, dated as of January 1, 1981.\* |
| 4.21 | 2-79571 | 4(a)-21 | Twentieth Supplemental Indenture, dated as of August 1, 1982.\* |
| 4.22 | (with Form 8-K dated September 20, 1983) | 4(a)-22 | Twenty-First Supplemental Indenture, dated as of September 1, 1983.\* |
| 4.23 | 2-94816 | 4(a)-23 | Twenty-Second Supplemental Indenture, dated as of March 1, 1984.\* |
| 4.24 | (with 1986 Form 10-K) | 4(a)-24 | Twenty-Third Supplemental Indenture, dated as of December 1, 1986.\* |
| 4.25 | (with 1987 Form 10-K) | 4(a)-25 | Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988.\* |
| 4.26 | (with 1989 Form 10-K) | 4(a)-26 | Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989.\* |
| 4.27 | 33-51669 | 4(a)-27 | Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993.\* |

---

------

***AVISTA CORPORATION***

---

| | | | |
|:---|:---|:---|:---|
| [<u>4.28</u>](https://www.sec.gov/Archives/edgar/data/104918/0000891020-94-000019.txt) | (with 1993 Form 10-K) | 4(a)-28 | [<u>Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994.</u>](https://www.sec.gov/Archives/edgar/data/104918/0000891020-94-000019.txt) |
| [<u>4.29</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102002000255/v79977ex4-a29.txt) | (with 2001 Form 10-K) | 4(a)-29 | [<u>Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001.</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102002000255/v79977ex4-a29.txt) |
| [<u>4.30</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012002000094/ex4b.txt) | 333-82502 | 4(b) | [<u>Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012002000094/ex4b.txt) |
| [<u>4.31</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102002001154/v83511exv4wxfy.txt) | (with June 30, 2002 Form 10-Q) | 4(f) | [<u>Thirtieth Supplemental Indenture, dated as of May 1, 2002.</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102002001154/v83511exv4wxfy.txt) |
| [<u>4.32</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312503012892/dex4b.htm) | 333-39551 | 4(b) | [<u>Thirty-First Supplemental Indenture, dated as of May 1, 2003.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312503012892/dex4b.htm) |
| [<u>4.33</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003002630/v93888exv4wxfy.txt) | (with September 30, 2003 Form 10-Q) | 4(f) | [<u>Thirty-Second Supplemental Indenture, dated as of September 1, 2003.</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003002630/v93888exv4wxfy.txt) |
| [<u>4.34</u>](https://www.sec.gov/Archives/edgar/data/104918/000093041304002650/c32047_ex4a-33.txt) | 333-64652 | 4(a)33 | [<u>Thirty-Third Supplemental Indenture, dated as of May 1, 2004.</u>](https://www.sec.gov/Archives/edgar/data/104918/000093041304002650/c32047_ex4a-33.txt) |
| [<u>4.35</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w1.txt) | (with Form 8-K dated as of December 15, 2004) | 4.1 | [<u>Thirty-Fourth Supplemental Indenture, dated as of November 1, 2004.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w1.txt) |
| [<u>4.36</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w2.txt) | (with Form 8-K dated as of December 15, 2004) | 4.2 | [<u>Thirty-Fifth Supplemental Indenture, dated as of December 1, 2004.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w2.txt) |
| [<u>4.37</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w3.txt) | (with Form 8-K dated as of December 15, 2004) | 4.3 | [<u>Thirty-Sixth Supplemental Indenture, dated as of December 1, 2004.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w3.txt) |
| [<u>4.38</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w4.txt) | (with Form 8-K dated as of December 15, 2004) | 4.4 | [<u>Thirty-Seventh Supplemental Indenture, dated as of December 1, 2004.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w4.txt) |
| [<u>4.39</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102005000164/v09292exv4w1.txt) | (with Form 8-K dated as of May 12, 2005) | 4.1 | [<u>Thirty-Eighth Supplemental Indenture, dated as of May 1, 2005.</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102005000164/v09292exv4w1.txt) |
| [<u>4.40</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312505230298/dex41.htm) | (with Form 8-K dated as of November 17, 2005) | 4.1 | [<u>Thirty-Ninth Supplemental Indenture, dated as of November 1, 2005.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312505230298/dex41.htm) |
| [<u>4.41</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312506078518/dex41.htm) | (with Form 8-K dated as of April 6, 2006) | 4.1 | [<u>Fortieth Supplemental Indenture, dated as of April 1, 2006.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312506078518/dex41.htm) |
| [<u>4.42</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312506255331/dex41.htm) | (with Form 8-K dated as of December 15, 2006) | 4.1 | [<u>Forty-First Supplemental Indenture, dated as of December 1, 2006.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312506255331/dex41.htm) |
| [<u>4.43</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508077220/dex41.htm) | (with Form 8-K dated as of April 3, 2008) | 4.1 | [<u>Forty-Second Supplemental Indenture, dated as of April 1, 2008.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508077220/dex41.htm) |
| [<u>4.44</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508245816/dex41.htm) | (with Form 8-K dated as of November 26, 2008) | 4.1 | [<u>Forty-Third Supplemental Indenture, dated as of November 1, 2008.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508245816/dex41.htm) |
| [<u>4.45</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508255876/dex41.htm) | (with Form 8-K dated as of December 16, 2008) | 4.1 | [<u>Forty-Fourth Supplemental Indenture, dated as of December 1, 2008.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508255876/dex41.htm) |
| [<u>4.46</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312509001075/dex43.htm) | (with Form 8-K dated as of December 30, 2008) | 4.3 | [<u>Forty-Fifth Supplemental Indenture, dated as of December 1, 2008.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312509001075/dex43.htm) |
| [<u>4.47</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312509196475/dex41.htm) | (with Form 8-K dated as of September 15, 2009) | 4.1 | [<u>Forty-Sixth Supplemental Indenture, dated as of September 1, 2009.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312509196475/dex41.htm) |
| [<u>4.48</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312509244253/dex41.htm) | (with Form 8-K dated as of November 25, 2009) | 4.1 | [<u>Forty-Seventh Supplemental Indenture, dated as of November 1, 2009.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312509244253/dex41.htm) |
| [<u>4.49</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex45.htm) | (with Form 8-K dated as of December 15, 2010) | 4.5 | [<u>Forty-Eighth Supplemental Indenture, dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex45.htm) |
| [<u>4.50</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510286652/dex41.htm) | (with Form 8-K dated as of December 20, 2010) | 4.1 | [<u>Forty-Ninth Supplemental Indenture, dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510286652/dex41.htm) |
| [<u>4.51</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511001170/dex41.htm) | (with Form 8-K dated as of December 30, 2010) | 4.1 | [<u>Fiftieth Supplemental Indenture, dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511001170/dex41.htm) |
| [<u>4.52</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511037859/dex41.htm) | (with Form 8-K dated as of February 11, 2011) | 4.1 | [<u>Fifty-First Supplemental Indenture, dated as of February 1, 2011.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511037859/dex41.htm) |
| [<u>4.53</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511232397/dex41.htm) | (with Form 8-K dated as of August 16, 2011) | 4.1 | [<u>Fifty-Second Supplemental Indenture, dated as of August 1, 2011.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511232397/dex41.htm) |
| [<u>4.54</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511344025/d270200dex41.htm) | (with Form 8-K dated as of December 14, 2011) | 4.1 | [<u>Fifty-Third Supplemental Indenture, dated as of December 1, 2011.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511344025/d270200dex41.htm) |

---

------

***AVISTA CORPORATION***

---

| | | | |
|:---|:---|:---|:---|
| [<u>4.55</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312512490603/d448396dex41.htm) | (with Form 8-K dated as of November 30, 2012) | 4.1 | [<u>Fifty-Fourth Supplemental Indenture, dated as of November 1, 2012.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312512490603/d448396dex41.htm) |
| [<u>4.56</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491813000093/ex41fifty-fifthsupplementa.htm) | (with Form 8-K dated as of August 14, 2013) | 4.1 | [<u>Fifty-Fifth Supplemental Indenture, dated as of August 1, 2013.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491813000093/ex41fifty-fifthsupplementa.htm) |
| [<u>4.57</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491814000048/ex41fifty-sixthsupplementa.htm) | (with Form 8-K dated as of April 18, 2014) | 4.1 | [<u>Fifty-Sixth Supplemental Indenture, dated as of April 1, 2014.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491814000048/ex41fifty-sixthsupplementa.htm) |
| [<u>4.58</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491814000133/ex41fifty-seventhsupplemen.htm) | (with Form 8-K dated as of December 18, 2014) | 4.1 | [<u>Fifty-Seventh Supplemental Indenture, dated as of December 1, 2014.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491814000133/ex41fifty-seventhsupplemen.htm) |
| [<u>4.59</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491815000135/ex41fifty-eighthsupplement.htm) | (with Form 8-K dated as of December 16, 2015) | 4.1 | [<u>Fifty-Eighth Supplemental Indenture, dated as of December 1, 2015.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491815000135/ex41fifty-eighthsupplement.htm) |
| [<u>4.60</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491816000284/ex41-fiftyxninthsupplement.htm) | (with Form 8-K dated as of December 16, 2016) | 4.1 | [<u>Fifty-Ninth Supplemental Indenture, dated as of December 1, 2016.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491816000284/ex41-fiftyxninthsupplement.htm) |
| [<u>4.61</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491817000149/ex41sixtiethsupplementalin.htm) | (with Form 8-K dated as of December 14, 2017) | 4.1 | [<u>Sixtieth Supplemental Indenture, dated as of December 1, 2017.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491817000149/ex41sixtiethsupplementalin.htm) |
| [<u>4.62</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312518169655/d552671dex4a62.htm) | (with Form 8-K dated as of May 15, 2018) | 4(a)(62) | [<u>Sixty-First Supplemental Indenture, dated as of May 1, 2018</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312518169655/d552671dex4a62.htm) |
| [<u>4.63</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491819000155/ex41sixty-secondsupple.htm) | (with Form 8-K dated as of November 26, 2019) | 4.1 | [<u>Sixty-Second Supplemental Indenture, dated as of November 1, 2019</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491819000155/ex41sixty-secondsupple.htm) |
| [<u>4.64</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491820000095/avistasixty-thirdsuppl.htm) | (with Form 8-K dated as of June 4, 2020) | 4.1 | [<u>Sixty-Third Supplemental Indenture, dated as of June 1, 2020</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491820000095/avistasixty-thirdsuppl.htm) |
| [<u>4.65</u>](https://www.sec.gov/Archives/edgar/data/104918/000156459020045752/ava-ex41_6.htm) | (with Form 8-K dated as of September 30, 2020) | 4.1 | [<u>Sixty-Fourth Supplemental Indenture, dated as of September 1, 2020</u>](https://www.sec.gov/Archives/edgar/data/104918/000156459020045752/ava-ex41_6.htm) |
| [<u>4.66</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017021001952/ava-20210928ex4_1.htm) | (with Form 8-K dated as of September 30, 2021)  | 4.1 | [<u>Sixty-Fifth Supplemental Indenture, dated as of September 1, 2021</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017021001952/ava-20210928ex4_1.htm) |
| [<u>4.67</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017022003241/ava-ex4_1.htm) | (with Form 8-K dated as of March 8, 2022)  | 4.1 | [<u>Sixty-Sixth Supplemental Indenture, dated as of March 1, 2022</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017022003241/ava-ex4_1.htm) |
| [<u>4.68</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023011411/ava-ex4_1.htm) | (with Form 8-K dated as of March 29, 2023) | 4.1 | [<u>Sixty-Seventh Supplemental Indenture, dated as of March 1, 2023</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023011411/ava-ex4_1.htm) |
| [<u>4.69</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023027534/ava-ex4_1.htm) | (with Form 8-K dated as of June 8, 2023) | 4.1 | [<u>Sixty-Eighth Supplemental Indenture, dated as of June 1, 2023</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023027534/ava-ex4_1.htm) |
| [<u>4.70</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025098875/ava-ex4_1.htm) | (with Form 8-K dated as of July 23, 2025) | 4.1 | [<u>Sixty-Ninth Supplemental Indenture, dated as of July 1, 2025</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025098875/ava-ex4_1.htm) |
| [<u>4.71</u>](https://www.sec.gov/Archives/edgar/data/104918/0000950120-98-000150.txt) | 333-82165 | 4(a) | [<u>Indenture dated as of April 1, 1998 between Avista Corporation and The Bank of New York, as Successor Trustee.</u>](https://www.sec.gov/Archives/edgar/data/104918/0000950120-98-000150.txt) |
| [<u>4.72</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w5.txt) | (with Form 8-K dated as of December 15, 2004) | 4.5 | [<u>Supplemental Indenture No. 1, dated as of December 1, 2004 to the Indenture dated as of April 1, 1998 between Avista Corporation and JPMorgan Chase Bank, N.A.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095012404006356/v04150exv4w5.txt) |
| [<u>4.73</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex41.htm) | (with Form 8-K dated as of December 15, 2010) | 4.1 | [<u>Loan Agreement between City of Forsyth, Montana and Avista Corporation $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex41.htm) |
| [<u>4.74</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex4_73.htm) | (with 2024 Form 10-K) | 4.73 | [<u>Waiver of redemption right under Section 8.01 of the Loan Agreement between City of Forsyth, Montana and Avista Corporation $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex4_73.htm) |
| [<u>4.75</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex43.htm) | (with Form 8-K dated as of December 15, 2010) | 4.3 | [<u>Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A, dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex43.htm) |

---

------

***AVISTA CORPORATION***

---

| | | | |
|:---|:---|:---|:---|
| [<u>4.76</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex42.htm) | (with Form 8-K dated as of December 15, 2010) | 4.2 | [<u>Loan Agreement between City of Forsyth, Montana and Avista Corporation $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex42.htm) |
| [<u>4.77</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex4_76.htm) | (with 2024 Form 10-K) | 4.76 | [<u>Waiver of redemption right under Section 8.01 of the Loan Agreement between City of Forsyth, Montana and Avista Corporation $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex4_76.htm) |
| [<u>4.78</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex44.htm) | (with Form 8-K dated as of December 15, 2010) | 4.4 | [<u>Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B, dated as of December 1, 2010.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312510284471/dex44.htm) |
| [<u>4.79</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025064737/ava-ex4.htm) | (with March 31, 2025 Form 10-Q) | 4.1 | [<u>Description of the Registrant's Securities registered under Section 12 of the Securities Exchange Act of 1934.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025064737/ava-ex4.htm) |
| [<u>10.1</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511037859/dex101.htm) | (with Form 8-K dated as of February 11, 2011) | 10.1 | [<u>Credit Agreement, dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, The Bank of New York Mellon, Keybank National Association, and U.S. Bank National Association, as Co-Documentation Agents, Wells Fargo Bank National Association as Syndication Agent and an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511037859/dex101.htm) |
| [<u>10.2</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511344025/d270200dex101.htm) | (with Form 8-K dated as of December 14, 2011)<br>| 10.1<br>| [<u>First Amendment and Waiver Thereunder, dated as of December 14, 2011, to the Credit Agreement dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, Wells Fargo Bank National Association as an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank.</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511344025/d270200dex101.htm)<br>|
| [<u>10.3</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491814000048/ex101secondamendmenttocred.htm) | (with Form 8-K dated as of April 18, 2014) | 10.1 | [<u>Second Amendment to Credit Agreement, dated as of April 18, 2014, among Avista Corporation, Wells Fargo Bank, National Association, as an Issuing Bank, Union Bank, N.A. as Administrative Agent and an Issuing Bank, and the financial institutions identified hereof as Continuing Lenders and Exiting Lender.</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491814000048/ex101secondamendmenttocred.htm) |
| [<u>10.4</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023027534/ava-ex10_1.htm) | (with Form 8-K dated as of June 8, 2023) | 10.1 | [<u>Fifth Amendment to Credit Agreement, dated as of June 8, 2023, among Avista Corporation, the lending financial institutions, U.S. Bank National Corporation and Wells Fargo Bank National Association as issuing banks, and MUFG Bank, LTD as Administrative Agent</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023027534/ava-ex10_1.htm) |
| [<u>10.5</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023027534/ava-ex10_2.htm) | (with Form 8-K dated as of June 8, 2023) | 10.2 | [<u>Bond Delivery Agreement, dated as of June 8, 2023, between Avista Corporation and Union Bank, N.A.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023027534/ava-ex10_2.htm) |
| [<u>10.6</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv3.txt) | (with 2002 Form 10-K) | 10(b)-3 | [<u>Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv3.txt) |
| [<u>10.7</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv4.txt) | (with 2002 Form 10-K) | 10(b)-4 | [<u>Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv4.txt) |
| [<u>10.8</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv5.txt) | (with 2002 Form 10-K) | 10(b)-5 | [<u>Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv5.txt) |

---

------

***AVISTA CORPORATION***

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | [<u>(effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).</u>](https://www.sec.gov/Archives/edgar/data/104918/000089102003000804/v87987exv10wxbyv5.txt) |
| 10.9 | 2-60728 | 5(g) | Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.\* |
| 10.10 | 2-60728 | 5(g)-1 | Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.\* |
| 10.11 | 2-60728 | 5(h) | Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.\* |
| 10.12 | 2-60728 | 5(h)-1 | Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.\* |
| 10.13 | (with September 30, 1985 Form 10-Q) | 1 | Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation.\* |
| 10.14 | (with 1981 Form 10-K) | 10(s)-7 | Ownership and Operation Agreement for Colstrip Units No. 3 & 4, dated as of May 6, 1981.\* |
| [<u>10.15</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491820000036/ex1014executivedeferra.htm) | (with 2019 Form 10-K) | 10.14 | [<u>Avista Corporation Executive Deferral Plan (2020 Component). (3)(5)</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491820000036/ex1014executivedeferra.htm) |
| [<u>10.16</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491820000036/ex1015post2004serp2018.htm) | (with 2019 Form 10-K) | 10.15 | [<u>Avista Corporation Supplemental Executive Retirement Plan (Post-2004 Component, Amended in 2018). (3)(6)</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491820000036/ex1015post2004serp2018.htm) |
| 10.17 | (with 1992 Form 10-K) | 10(t)-11 | The Company's Unfunded Supplemental Executive Disability Plan. (3)\* |
| [<u>10.18</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508040207/dex1034.htm) | (with 2007 Form 10-K) | 10.34 | [<u>Income Continuation Plan of the Company. (3)</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312508040207/dex1034.htm) |
| [<u>10.19</u>](ava-ex10_19.htm) | (2) | 10.21 | [<u>Avista Corporation Long-Term Incentive Plan. (3)</u>](ava-ex10_19.htm) |
| [<u>10.20</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511047407/dex1023.htm) | (with 2010 Form 10-K) | 10.23 | [<u>Avista Corporation Performance Award Plan Summary. (3)</u>](https://www.sec.gov/Archives/edgar/data/104918/000119312511047407/dex1023.htm) |
| [<u>10.21</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023003546/ava-ex10_22.htm) | (with 2023 Form 10-K) | 10.24 | [<u>Avista Corporation Performance Award Agreement 2023. (3)</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017022001672/ava-ex10_22.htm) |
| [<u>10.22</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex10_24.htm) | (with 2024 Form 10-K) | 10.24 | [<u>Avista Corporation Performance Award Agreement 2024. (3)</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex10_24.htm) |
| [<u>10.23</u>](ava-ex10_23.htm) | (2) |  | [<u>Avista Corporation Performance Award Agreement 2025. (3)</u>](ava-ex10_23.htm) |
| [<u>10.24</u>](ava-ex10_24.htm) | (2) |  | [<u>Avista Corporation Officer Incentive Plan. (3)</u>](ava-ex10_24.htm) |
| [<u>10.25</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491819000148/ex101avistaexecutivech.htm) | (with September 30, 2019 Form 10-Q) | 10.1 | [<u>Form of Change of Control Plan between the Company and its Executive Officers. (3)(5)</u>](https://www.sec.gov/Archives/edgar/data/104918/000010491819000148/ex101avistaexecutivech.htm) |
| [<u>10.26</u>](ava-ex10_26.htm) | (2) |  | [<u>Avista Corporation Non-Employee Director Compensation.</u>](ava-ex10_26.htm) |
| [<u>10.27</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023000157/ava-ex10_1.htm) | (with Form 8-K dated January 4, 2023) | 10.1 | [<u>Continuing Letter of Credit Agreement dated as of December 29, 2022, among Avista Corporation and MUFG Bank Ltd., as Issuer.</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017023000157/ava-ex10_1.htm) |
| [<u>19</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex19.htm) | (with 2024 Form 10-K) | 19 | [<u>Insider Trading Policy</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017025027077/ava-ex19.htm) |
| [<u>21</u>](ava-ex21.htm) | (2) |  | [<u>Subsidiaries of Registrant.</u>](ava-ex21.htm) |
| [<u>23</u>](ava-ex23.htm) | (2) |  | [<u>Consent of Independent Registered Public Accounting Firm.</u>](ava-ex23.htm) |
| [<u>31.1</u>](ava-ex31_1.htm) | (2) |  | [<u>Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002).</u>](ava-ex31_1.htm) |
| [<u>31.2</u>](ava-ex31_2.htm) | (2) |  | [<u>Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002).</u>](ava-ex31_2.htm) |
| [<u>32</u>](ava-ex32.htm) | (4) |  | [<u>Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).</u>](ava-ex32.htm) |

---

------

***AVISTA CORPORATION***

---

| | | | |
|:---|:---|:---|:---|
| [<u>97</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017024017421/ava-ex97.htm) | (with 2023 Form 10-K) | 97 | [<u>Avista Corporation Dodd-Frank Recovery Policy</u>](https://www.sec.gov/Archives/edgar/data/104918/000095017024017421/ava-ex97.htm) |
| 101.INS | (2) |  | Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| 101.SCH | (2) |  | Inline XBRL Taxonomy Extension Schema with embedded linkbases Document |
| 104 | (2) |  | Cover page formatted as Inline XBRL and contained in Exhibit 101. |

---

\* Exhibit originally filed with the U.S. Securities and Exchange Commission in paper format and as such, a hyperlink is not available.

(1)Incorporated herein by reference.

(2)Filed herewith.

(3)Management contracts or compensatory plans filed as exhibits to this Form 10-K pursuant to Item 15(b).

(4)Furnished herewith.

(5)Applies to Alexis G. Alexander, Kevin J. Christie, Bryan A. Cox, Josh D. DiLuciano, Gregory C. Hesler, Latisha D. Hill, Scott J. Kinney, Ryan L. Krasselt, Wayne O. Manuel, Heather L. Rosentrater, and Jason R. Thackston.

(6)Applies to Alexis G. Alexander, Kevin J. Christie, Bryan A. Cox, Josh D. DiLuciano, Latisha D. Hill, Scott J. Kinney, Ryan L. Krasselt, Heather L. Rosentrater, and Jason R. Thackston.

------

***AVISTA CORPORATION***

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

---

| | | |
|:---|:---|:---|
|  |  | AVISTA CORPORATION |
| February 24, 2026 | By | /s/ Heather L. Rosentrater |
| Date |  | Heather L. Rosentrater |
|  |  | President and Chief Executive Officer |

---

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

---

| | | |
|:---|:---|:---|
| <u>Signature</u> | <u>Title</u> | <u>Date</u> |
| /s/ Heather L. Rosentrater | Principal Executive Officer and Director | February 24, 2026 |
| Heather L. Rosentrater |  |  |
| President and Chief Executive Officer |  |  |
| /s/ Kevin J. Christie | Principal Financial Officer | February 24, 2026 |
| Kevin J. Christie |  |  |
| Senior Vice President, Chief Financial Officer |  |  |
| Treasurer, and Regulatory Affairs Officer |  |  |
| /s/ Ryan L. Krasselt | Principal Accounting Officer | February 24, 2026 |
| Ryan L. Krasselt |  |  |
| Vice President and Controller |  |  |
| /s/ Scott L. Morris | Director | February 24, 2026 |
| Scott L. Morris |  |  |
| Chairman of the Board |  |  |
| /s/ Julie A. Bentz | Director | February 24, 2026 |
| Julie A. Bentz | Director |  |
| /s/ Donald C. Burke | Director | February 24, 2026 |
| Donald C. Burke |  |  |
| /s/ Kevin B. Jacobsen | Director | February 24, 2026 |
| Kevin B. Jacobsen |  |  |
| /s/ Rebecca A. Klein | Director | February 24, 2026 |
| Rebecca A. Klein |  |  |
| /s/ Sena M. Kwawu | Director | February 24, 2026 |
| Sena M. Kwawu | Director |  |
| /s/ Scott H. Maw | Director | February 24, 2026 |
| Scott H. Maw |  |  |
| /s/ Jeffry L. Philipps | Director | February 24, 2026 |
| Jeffry L. Philipps |  |  |
| /s/ Heidi B. Stanley | Director | February 24, 2026 |
| Heidi B. Stanley |  |  |
| /s/ Janet D. Widmann | Director | February 24, 2026 |
| Janet D. Widmann |  |  |

---

------

## Exhibit 10.19

**Exhibit 10.19**

![img108928359_0.jpg](img108928359_0.jpg)

**Long-Term Incentive Plan**

**Avista Corporation**

**Adopted by the Shareholders**

**on May 14, 1998**

**Amended and Restated** 

**February 21, 2025**

------

**AVISTA CORPORATION** 

**LONG-TERM INCENTIVE PLAN** 

**SECTION 1. PURPOSE** 

The purpose of the Avista Corporation Long-Term Incentive Plan (the "Plan") is to enhance the long-term shareholder value of Avista Corporation, a Washington corporation (the "Company"), by offering opportunities to employees, directors and officers of the Company and its Subsidiaries (as defined in Section 2) to participate in the Company's growth and success, and to encourage them to remain in the service of the Company and its Subsidiaries and to acquire and maintain stock ownership in the Company.

The Plan was initially adopted by the Company's shareholders on May 14, 1998 and was subsequently amended and restated on May 12, 2000, January 1, 2005, November 9, 2006 May 13, 2010, January 19, 2016, and February 21, 2025.

Changes made pursuant to this amendment and restatement of the Plan shall apply to Awards (as defined below) granted on or after February 21, 2025, and Awards granted prior to February 21, 2025, shall continue to be governed by the applicable Award agreements and the terms of the Plan without giving effect to changes made pursuant to this amendment and restatement of the Plan.

**SECTION 2. DEFINITIONS** 

For purposes of the Plan, the following terms are defined as set forth below:

*2.1 Award* 

"Award" means an award or grant made to a Participant pursuant to the Plan, including, without limitation, awards or grants of Options, Stock Appreciation Rights, Stock Awards, Performance Awards, Other Stock-Based Awards or any combination of the foregoing (including any Dividend Equivalent Rights granted in connection with such Awards).

*2.2 Board* 

"Board" means the Board of Directors of the Company.

*2.3 Cause* 

"Cause" means (a) the willful and continued failure of the Holder to perform substantially the Holder's duties with the Company or one of its Subsidiaries (other than any such failure resulting from incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Holder by the Board or the Chief Executive Officer of the Company which specifically identifies the manner in which the Board or the Chief Executive Officer believes that the Holder has not substantially performed the Holder's duties; or (b) the willful engaging by the Holder in illegal conduct or gross misconduct which is materially and demonstrably injurious to the Company.

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For purposes of this provision, no act or failure to act, on the part of the Holder, shall be considered "willful" unless it is done, or omitted to be done, by the Holder in bad faith or without reasonable belief that the Holder's action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the Chief Executive Officer or a senior officer of the Company or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Holder in good faith and in the best interests of the Company.

*2.4 Change of Control* 

"Change of Control" means any of the following events:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) the then outstanding shares of Common Stock of the Company (the "Outstanding Company Common Stock") or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (iv) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this Section 2.4;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) A change in the Board so that individuals who constitute the Board (the "Incumbent Board") as of the date of adoption of the Plan cease for any reason to constitute at least a majority of the Board after such date; provided, however, that any individual becoming a director subsequent to such date whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a "Business Combination"), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities

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immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of Common Stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of Common Stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the Board of Directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) A complete liquidation or dissolution of the Company.

Notwithstanding the foregoing, if a Change of Control constitutes a payment event with respect to any Award (or portion of any Award) that provides for the deferral of compensation that is required to comply with (and is not otherwise exempt from) Section 409A of the Code, to the extent required to avoid the imposition of additional taxes under Section 409A of the Code, the transaction or event described in subsections (a), (b), (c) or (d) with respect to such Award (or portion thereof) shall only constitute a Change of Control for purposes of the payment timing of such Award if such transaction also constitutes a "change in control event" as defined in Treasury Regulation Section 1.409A-3(i)(5).

*2.5 Code* 

"Code" means the Internal Revenue Code of 1986, as amended.

*2.6 Common Stock* 

"Common Stock" means the common stock, no par value, of the Company.

*2.7 Disability* 

"Disability" means "disability" as that term is defined for purposes of the Company's Long-Term Disability Plan or other similar successor plan applicable to salaried employees. Notwithstanding the foregoing, if a Disability constitutes a payment event with respect to any Award (or portion of any Award) that provides for the deferral of compensation that is required to comply with (and is not otherwise exempt from) Section 409A of the Code, to the extent required to avoid the

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imposition of additional taxes under Section 409A of the Code, the "disability" described in the immediately preceding sentence with respect to such Award (or portion thereof) shall only constitute a Disability for purposes of the payment timing of such Award if such disability also constitutes a "disability" as defined in Treasury Regulation Section 1.409A-3(i)(4).

*2.8 Dividend Equivalent Right* 

"Dividend Equivalent Right" means an Award granted under Section 13.

*2.9 Early Retirement* 

"Early Retirement" means early retirement as that term is defined by the Plan Administrator from time to time for purposes of the Plan.

*2.10 Exchange Act* 

"Exchange Act" means the Securities Exchange Act of 1934, as amended.

*2.11 Fair Market Value* 

The "Fair Market Value" shall be the closing price per share for the applicable date for the Common Stock on the New York Stock Exchange as such price is officially quoted in the composite tape of transactions on such exchange for a single trading day. If there is no such reported price for the Common Stock for the date in question, then such price on the last preceding date for which such price exists shall be determinative of Fair Market Value.

*2.12 Good Reason* 

"Good Reason" means a voluntary termination of employment by a Participant following the initial existence of any one of the following conditions arising without the consent of the Participant:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)a material diminution by the Company of the Participant's authority, duties, or responsibilities, excluding for this purpose isolated and inadvertent actions not taken in bad faith and remedied by the Company promptly after the Company receives notice from the Participant; provided, however, that a change in title or reporting relationship alone shall not constitute Good Reason;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)a material diminution in Participant's annual base salary or annual bonus opportunity;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)a material change in the geographic location at which Participant must perform the services (which, for purposes of this Plan, means relocation of the offices of the Company at which Participant is principally employed to a location more than 50 miles from the location of such offices immediately prior to such change);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d)a material diminution in the budget over which Participant retains authority; or

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e)any action or inaction that constitutes a material breach by the Company of this Plan with respect to Participant.

Good Reason shall exist only if (i) Participant provides notice to the Company of the existence of a condition described in (a) through (e) above within 90 days of the initial existence of the condition, (ii) upon the notice of which the Company shall be provided a period of 30 days during which it may remedy the condition, and (iii) if the Company does not timely remedy such condition, Participant terminates employment after the end of such remedial period and in all events no later than 90 days following the end of such remedial period.

*2.13 Grant Date* 

"Grant Date" means the date the Plan Administrator adopted the granting resolution or a later date designated in a resolution of the Plan Administrator as the date an Award is to be granted.

*2.14 Holder* 

"Holder" means:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) a Participant who holds an outstanding Award;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) for a Participant who has died while holding an outstanding Award, the personal representative of the Participant's estate, the person(s) to whom the Participant's rights under the Award have passed by will or by the applicable laws of descent and distribution, or the beneficiary designated in accordance with Section 14; or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) the person(s) to whom an Award has been transferred in accordance with Section 14.

*2.15 Incentive Stock Option* 

"Incentive Stock Option" means an Option to purchase Common Stock granted under Section 7 with the intention that such Option qualify as an "incentive stock option" as that term is defined in Section 422 of the Code.

*2.16 Nonqualified Stock Option* 

"Nonqualified Stock Option" means an Option to purchase Common Stock granted under Section 7 other than an Incentive Stock Option.

*2.17 Option* 

"Option" means the right to purchase Common Stock granted under Section 7.

*2.18 Other Stock-Based Award* 

"Other Stock-Based Award" means an Award granted under Section 12.

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*2.19 Participant* 

"Participant" means an employee, officer or director of or an individual consultant or independent contractor to the Company or a Subsidiary, in any case who holds an outstanding Award, or, as the context may require, any of the foregoing individuals who has been designated by the Plan Administrator as eligible to participate in the Plan.

*2.20 Performance Award* 

"Performance Award" means an Award granted under Section 11, the payout of which is subject to achievement through a performance period of performance goals prescribed by the Plan Administrator.

*2.21 Plan Administrator* 

"Plan Administrator" means the Board or any committee or committees designated by the Board or any person or persons to whom the Board has delegated authority to administer the Plan under Section 3.1.

*2.22 Restricted Stock* 

"Restricted Stock" means shares of Common Stock granted under Section 10, the rights of ownership of which are subject to restrictions prescribed by the Plan Administrator.

*2.23 Retirement* 

"Retirement" means retirement as of the individual's normal retirement date under the Company's retirement plan for salaried employees or other similar successor plan applicable to salaried employees.

*2.24 Securities Act* 

"Securities Act" means the Securities Act of 1933, as amended.

*2.25 Stock Appreciation Right* 

"Stock Appreciation Right" means an Award granted under Section 9.

*2.26 Stock Award* 

"Stock Award" means an Award granted under Section 10.

*2.27 Subsidiary* 

"Subsidiary," except as provided in Section 8.3 in connection with Incentive Stock Options, means any entity that is directly or indirectly controlled by the Company or in which the Company has a

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significant ownership interest, as determined by the Plan Administrator, and any entity that may become a direct or indirect parent of the Company.

*2.28 Successor Corporation* 

"Successor Corporation" has the meaning set forth under Section 15.2.

**SECTION 3. ADMINISTRATION** 

*3.1 Plan Administrator* 

The Plan shall be administered by the Board or a committee or committees (which term includes subcommittees) appointed by, and consisting of two or more members of the Board. If and so long as the Common Stock is registered under Section 12(b) or 12(g) of the Exchange Act, the Board shall consider in selecting the Plan Administrator and the membership of any committee acting as Plan Administrator, with respect to any persons subject or likely to become subject to Section 16 of the Exchange Act, the provisions regarding (a) "nonemployee directors" as contemplated by Rule 16b-3 under the Exchange Act; and (b) "independent directors" as contemplated by Section 303A.02 of the New York Stock Exchange Listed Company Manual. The Board may delegate the responsibility for administering the Plan with respect to designated classes of eligible Participants to different committees consisting of two or more members of the Board, subject to such limitations as the Board or the Plan Administrator deems appropriate. Committee members shall serve for such term as the Board may determine, subject to removal by the Board at any time. To the extent consistent with applicable law, the Board may authorize one or more senior executive officers of the Company to grant Awards to designated classes of eligible employees within the limits prescribed by the Board.

*3.2 Administration and Interpretation by the Plan Administrator* 

Except for the terms and conditions explicitly set forth in the Plan, the Plan Administrator shall have exclusive authority, in its discretion, to determine all matters relating to Awards under the Plan or necessary or advisable in the administration of the Plan, including to (a) select individuals to be granted Awards, (b) determine the type of Awards to be granted, (c) determine the number of shares of Common Stock subject to an Award, (d) determine all terms, conditions, restrictions and limitations, if any, of an Award and the terms of any instrument that evidences the Award, (e) construe and interpret the Plan and Award agreements, (f) correct any defect, supply any omission and reconcile any inconsistency in the Plan or any Award agreement, (g) adopt, revise or rescind rules and regulations of general application for the Plan's administration, and (h) exercise discretion to make any and all other determinations and to take such actions that it determines to be necessary or advisable for the administration of the Plan. The Plan Administrator's interpretation of the Plan and Award agreements and the Plan's rules and regulations, and all actions taken and determinations made by the Plan Administrator pursuant to the Plan, shall be conclusive and binding on all parties involved or affected. Subject to applicable law and any applicable listing rules, the Plan Administrator may delegate administrative duties to such of the Company's officers as it so determines.

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**SECTION 4. STOCK SUBJECT TO THE PLAN** 

*4.1 Authorized Number of Shares* 

Subject to adjustment from time to time as provided in Section 15.1, a maximum of 7,715,000 shares of Common Stock (which represents the sum of: (i) 6,135,000 shares that were previously authorized; and (ii) 1,580,000 shares newly authorized by shareholders with this restatement shall be available for issuance under the Plan. Shares issued under the Plan shall be drawn from authorized and unissued shares or shares now held or subsequently acquired by the Company or may be purchased on the open market.

*4.2 Limitations* 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) Subject to adjustment from time to time as provided in Section 15.1, to the extent consistent with Section 424 of the Code, not more than an aggregate of 80,000 shares may be issued under Incentive Stock Options.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) Subject to adjustment from time to time as provided in Section 15.1, shares of common stock made subject to Awards under the Plan to any non-employee director who is a Participant may not exceed $750,000 in value at the time of issuance in any given calendar year.

*4.3 Reuse of Shares* 

Any shares of Common Stock that have been made subject to an Award that cease to be subject to the Award (other than by reason of exercise or payment of the Award to the extent it is exercised for or settled in shares or by reason of holding back shares to cover taxes on the Holder associated with exercise or payment of the Award) shall again be available for issuance in connection with future grants of Awards under the Plan. Shares that are subject to tandem Awards shall be counted only once.

**SECTION 5. ELIGIBILITY** 

Except as otherwise set forth herein, Awards may be granted under the Plan to those officers, directors and employees of and individual consultants and independent contractors to the Company and its Subsidiaries as the Plan Administrator from time to time selects.

**SECTION 6. AWARDS** 

*6.1 Form and Grant of Awards* 

The Plan Administrator shall have the authority, in its sole discretion, to determine the type or types of Awards to be made under the Plan. Such Awards may include, but are not limited to, Incentive Stock Options, Nonqualified Stock Options, Stock Appreciation Rights, Stock Awards, Performance Awards, Other Stock-Based Awards and Dividend Equivalent Rights. Awards may be granted singly, in combination or in tandem so that the settlement or payment of one automatically reduces or cancels the other. Awards may also be made in combination or in tandem

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with, as alternatives to, or as the payment form for, grants or rights under any other compensation or benefit plan of the Company or of a Subsidiary.

*6.2 Acquired Company Awards* 

Notwithstanding anything in the Plan to the contrary, the Plan Administrator may grant Awards under the Plan in substitution for awards issued under other plans, or assume under the Plan awards issued under other plans, if the other plans are or were plans of other acquired entities ("Acquired Entities") (or the parent of the Acquired Entity) and the new Award is substituted, or the old award is assumed, by reason of a merger, consolidation, acquisition of property or of stock, reorganization or liquidation (the "Acquisition Transaction"); provided, however, any substitution of a new Option pursuant to a corporate transaction for an outstanding option or the assumption of an outstanding option shall meet the requirements of Treasury Regulation section 1.424-1. The preceding sentence shall apply to "incentive stock options" as that term is defined in Section 422 of the Code and nonqualified stock options. In the event that a written agreement pursuant to which the Acquisition Transaction is completed is approved by the Board and said agreement sets forth the terms and conditions of the substitution for or assumption of outstanding awards of the Acquired Entity, said terms and conditions shall be deemed to be the action of the Plan Administrator without any further action by the Plan Administrator, except as may be required for compliance with Rule 16b-3 under the Exchange Act, and the persons holding such Awards shall be deemed to be Participants and Holders.

*6.3 No Repricing* 

Other than in connection with a change in the Company's capitalization as described in Section 15.1 of the Plan, the exercise price of an Option or Stock Appreciation Right may not be reduced without shareholder approval. In addition, other than in connection with a change in the Company's capitalization as described in Section 15.1 of the Plan or in accordance with Section 15.2 of the plan, the exchange of Option or Stock Appreciation Rights, prior to exercise, for cash or other awards may not be made without shareholder approval.

*6.4 Recoupment of Awards* 

Awards granted under the Plan shall be subject to any and all policies, guidelines, codes of conduct, or other agreement or arrangement adopted by the Board or Compensation Committee thereof with respect to the recoupment, recovery or clawback of compensation (collectively, the "Recoupment Policy") and/or to any provisions set forth in the applicable Award agreement under which the Company may recover from current and former Participants or Holders any amounts paid or shares of Common Stock transferred in connection with an Award and any proceeds therefrom under such circumstances as the Plan Administrator determines appropriate. The Plan Administrator may apply the Recoupment Policy to Awards granted before the policy is adopted to the extent required by applicable law or rule of any securities exchange or market on which shares of Common Stock are listed or admitted for trading, as determined by the Plan Administrator in its sole discretion.

**SECTION 7. AWARDS OF OPTIONS** 

*7.1 Grant of Options* 

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The Plan Administrator is authorized under the Plan, in its sole discretion, to issue Options as Incentive Stock Options or as Nonqualified Stock Options, which shall be appropriately designated.

*7.2 Option Exercise Price* 

The exercise price for shares purchased under an Option shall be as determined by the Plan Administrator, but shall not be less than 100% of the Fair Market Value of the Common Stock on the Grant Date.

*7.3 Term of Options* 

The term of each Option shall be as established by the Plan Administrator or, if not so established, shall be 10 years from the Grant Date.

*7.4 Exercise of Options* 

The Plan Administrator shall establish and set forth in each instrument that evidences an Option the time at which or the installments in which the Option shall vest and become exercisable, which provisions may be waived or modified by the Plan Administrator at any time. If not so established in the instrument evidencing the Option, the Option will vest and become exercisable according to the following schedule, which may be waived or modified by the Plan Administrator at any time:

---

| | |
|:---|:---|
| **Period of Participant's Continuous Employment or**<br>**Service With the Company or Its**<br>**Subsidiaries From the Option Grant Date** | &nbsp;&nbsp;**Percent of Total**<br>**Option That Is Vested**<br>**and Exercisable** |
| &nbsp;&nbsp;&nbsp;After 1 year | &nbsp;&nbsp;25% |
| &nbsp;&nbsp;&nbsp;After 2 years | &nbsp;&nbsp;50% |
| &nbsp;&nbsp;&nbsp;After 3 years | &nbsp;&nbsp;75% |
| &nbsp;&nbsp;&nbsp;After 4 years | &nbsp;&nbsp;100% |

---

Notwithstanding the provisions of Section 7.4 above or of Section 7.6, any unvested portion of the Option shall vest and become exercisable in full immediately upon termination of employment for reasons of Disability or death.

To the extent that the right to purchase shares has accrued thereunder, an Option may be exercised from time to time by written notice to the Company, in accordance with procedures established by the Plan Administrator, setting forth the number of shares with respect to which the Option is being exercised and accompanied by payment in full as described in Section 7.5. The Plan Administrator may determine at any time that an Option may not be exercised as to less than 100 shares at any one time (or the lesser number of remaining shares covered by the Option).

*7.5 Payment of Exercise Price* 

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The exercise price for shares purchased under an Option shall be paid in full to the Company by delivery of consideration equal to the product of the Option exercise price and the number of shares purchased. Such consideration must be paid in cash or by check, or, unless the Plan Administrator in its sole discretion determines otherwise, either at the time the Option is granted or at any time before it is exercised, a combination of cash and/or check (if any) and one or both of the following alternative forms:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) tendering (either actually or, if and so long as the Common Stock is registered under Section 12(b) or 12(g) of the Exchange Act, by attestation) Common Stock already owned by the Holder for at least six months (or any shorter period necessary to avoid a charge to the Company's earnings for financial reporting purposes) having a Fair Market Value on the day prior to the exercise date equal to the aggregate Option exercise price; or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) if and so long as the Common Stock is registered under Section 12(b) or 12(g) of the Exchange Act, and to the extent not prohibited by applicable law, including Section 402 of the Sarbanes-Oxley Act of 2002, as amended, delivery of a properly executed exercise notice, together with irrevocable instructions, to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) a brokerage firm designated by the Company to deliver promptly to the Company the aggregate amount of sale or loan proceeds to pay the Option exercise price and any withholding tax obligations that may arise in connection with the exercise and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(ii) the Company to deliver the certificates for such purchased shares directly to such brokerage firm, all in accordance with the regulations of the Federal Reserve Board.

In addition, the price for shares purchased under an Option may be paid, either singly or in combination with one or more of the alternative forms of payment authorized by this Section 7.5 by such other consideration as the Plan Administrator may permit.

*7.6 Post-Termination Exercises* 

The Plan Administrator shall establish and set forth in each instrument that evidences an Option whether the Option will continue to be exercisable, and the terms and conditions of such exercise, if a Participant ceases to be employed by, or to provide services to, the Company or its Subsidiaries, which provisions may be waived or modified by the Plan Administrator at any time. If not so established in the instrument evidencing the Option, the Option will be exercisable according to the following terms and conditions, which may be waived or modified by the Plan Administrator at any time.

In case of termination of the Participant's employment or services other than by reason of death or Cause, the Option shall be exercisable, to the extent of the number of shares purchasable by the Participant at the date of such termination, only

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) within one year if the termination of the Participant's employment or services is coincident with Retirement, Early Retirement in connection with a Company program offering early retirement or Disability; or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) within three months after the date the Participant ceases employment with or services to the Company or a Subsidiary if termination of the Participant's employment or services is for any reason other than Retirement, Early Retirement in connection with a Company program offering early retirement or Disability, but in no event later than the remaining term of the Option. Any Option exercisable at the time of the Participant's death may be exercised, to the extent of the number of shares purchasable by the Participant at the date of the Participant's death, by the personal representative of the Participant's estate, the person(s) to whom the Participant's rights under the Award have passed by will or the applicable laws of descent and distribution or the beneficiary designated pursuant to Section 14 at any time or from time to time within one year after the date of death, but in no event later than the remaining term of the Option. Any portion of an Option that is not exercisable on the date of termination of the Participant's employment or services shall terminate on such date, unless the Plan Administrator determines otherwise. In case of termination of the Participant's employment or services for Cause, the Option shall automatically terminate upon first notification to the Participant of such termination, unless the Plan Administrator determines otherwise. If a Participant's employment or services with the Company are suspended pending an investigation of whether the Participant shall be terminated for Cause, all the Participant's rights under any Option likewise shall be suspended during the period of investigation, provided the the maximum term of the Option shall not be extended beyond its original end date.

A transfer of employment or services between or among the Company and its Subsidiaries shall not be considered a termination of employment or services for purposes of this Section 7.6. The effect of a Company-approved leave of absence on the terms and conditions of an Option shall be determined by the Plan Administrator, in its sole discretion.

**SECTION 8. INCENTIVE STOCK OPTION LIMITATIONS** 

To the extent required by Section 422 of the Code, Incentive Stock Options shall be subject to the following additional terms and conditions:

*8.1 Dollar Limitation* 

To the extent the aggregate Fair Market Value (determined as of the Grant Date) of Common Stock with respect to which Incentive Stock Options are exercisable for the first time during any calendar year (under the Plan and all other stock option plans of the Company) exceeds $100,000, such portion in excess of $100,000 shall be treated as a Nonqualified Stock Option. In the event the Participant holds two or more such Options that become exercisable for the first time in the same calendar year, such limitation shall be applied on the basis of the order in which such Options are granted.

*8.2 10% Shareholders* 

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If a Participant owns more than 10% of the total voting power of all classes of the Company's stock, then the exercise price per share of an Incentive Stock Option shall not be less than 110% of the Fair Market Value of the Common Stock on the Grant Date and the Option term shall not exceed five years. The determination of 10% ownership shall be made in accordance with Section 422 of the Code.

*8.3 Eligible Employees* 

Only employees of the Company or of one of its parent corporations or subsidiary corporations may be granted Incentive Stock Options. For purposes of this Section 8.3, "parent corporation" and "subsidiary corporation" shall have the meanings attributed to those terms for purposes of Section 422 of the Code.

*8.4 Term* 

The term of an Incentive Stock Option shall not exceed 10 years.

*8.5 Exercisability* 

To qualify for Incentive Stock Option tax treatment, an Option designated as an Incentive Stock Option must be exercised within three months after termination of employment for reasons other than death, except that, in the case of termination of employment due to total disability, such Option must be exercised within one year after such termination. Employment shall not be deemed to continue beyond the first 3 months of a leave of absence unless the Participant's reemployment rights are provided by statute or contract. For purposes of this Section 8.5, "total disability" shall mean a mental or physical impairment of the Participant that is expected to result in death or that has lasted or is expected to last for a continuous period of 12 months or more and that causes the Participant to be unable, in the opinion of the Company and two independent physicians, to perform his or her duties for the Company and to be engaged in any substantial gainful activity. Total disability shall be deemed to have occurred on the first day after the Company and the two independent physicians have furnished their opinion of total disability to the Plan Administrator.

*8.6 Taxation of Incentive Stock Options* 

In order to obtain certain tax benefits afforded to Incentive Stock Options under Section 422 of the Code, the Participant must hold the shares issued upon the exercise of an Incentive Stock Option for two years after the Grant Date of the Incentive Stock Option and one year from the date of exercise. A Participant may be subject to the alternative minimum tax at the time of exercise of an Incentive Stock Option. The Plan Administrator may require a Participant to give the Company prompt notice of any disposition of shares acquired by the exercise of an Incentive Stock Option prior to the expiration of such holding periods.

**SECTION 9. STOCK APPRECIATION RIGHTS** 

*9.1 Grant of Stock Appreciation Rights* 

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To the extent permitted by Section 6.1, the Plan Administrator may grant a Stock Appreciation Right separately or in tandem with a related Option.

*9.2 Tandem Stock Appreciation Rights* 

A Stock Appreciation Right granted in tandem with a related Option will give the Holder the right to surrender to the Company all or a portion of the related Option and to receive an appreciation distribution (in shares of Common Stock or cash or any combination of shares and cash, as the Plan Administrator, in its sole discretion, shall determine at any time) in an amount equal to the excess of the Fair Market Value for the date the Stock Appreciation Right is exercised over the exercise price per share of the right, which shall be the same as the exercise price of the related Option. A tandem Stock Appreciation Right will have the same other terms and provisions as the related Option. Upon and to the extent a tandem Stock Appreciation Right is exercised, the related Option will terminate.

*9.3 Stand-Alone Stock Appreciation Rights* 

A Stock Appreciation Right granted separately and not in tandem with an Option will give the Holder the right to receive an appreciation distribution (in shares of Common Stock or cash or any combination of shares and cash, as the Plan Administrator, in its sole discretion, shall determine at any time) in an amount equal to the excess of the Fair Market Value for the date the Stock Appreciation Right is exercised over the exercise price per share of the right.

A stand-alone Stock Appreciation Right will have such terms as the Plan Administrator may determine, except that the exercise price per share of the right must be at least equal to 100% of the Fair Market Value on the Grant Date and the term of the right, if not otherwise established by the Plan Administrator, shall be 10 years from the Grant Date.

*9.4 Exercise of Stock Appreciation Rights* 

Unless otherwise provided by the Plan Administrator in the instrument that evidences the Stock Appreciation Right, the provisions of Section 7.6 relating to the termination of a Participant's employment or services shall apply equally, to the extent applicable, to the Holder of a Stock Appreciation Right.

**SECTION 10. STOCK AWARDS** 

*10.1 Grant of Stock Awards* 

To the extent permitted by Section 6.1, the Plan Administrator is authorized to make Awards of Common Stock to Participants on such terms and conditions and subject to such restrictions, if any (which may be based on continuous service with the Company or the achievement of performance goals related to earnings, earnings per share, profits, profit growth, profit-related return ratios, cost management, dividend payout ratios, economic value added, cash flow or total shareholder return, where such goals may be stated in absolute terms or relative to comparison companies), as the Plan Administrator shall determine, in its sole discretion, which terms, conditions and restrictions shall

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be set forth in the instrument evidencing the Award. The terms, conditions and restrictions that the Plan Administrator shall have the power to determine shall include, without limitation, the manner in which shares subject to Stock Awards are held during the periods they are subject to restrictions and the circumstances under which forfeiture of Restricted Stock shall occur by reason of termination of the Participant's services.

*10.2 Issuance of Shares* 

Upon the satisfaction of any terms, conditions and restrictions prescribed in respect to a Stock Award, or upon the Participant's release from any terms, conditions and restrictions of a Stock Award, as determined by the Plan Administrator, the Company shall release, as soon as practicable, to the Holder or, in the case of the Holder's death, to the personal representative of the Holder's estate or as the appropriate court directs, the appropriate number of shares of Common Stock.

*10.3 Waiver of Restrictions* 

Notwithstanding any other provisions of the Plan, the Plan Administrator may, in its sole discretion, waive the forfeiture period and any other terms, conditions or restrictions on any Restricted Stock under such circumstances and subject to such terms and conditions as the Plan Administrator shall deem appropriate.

**SECTION 11. PERFORMANCE AWARDS** 

*11.1 Plan Administrator Authority* 

Performance Awards may be denominated in cash, shares of Common Stock or any combination thereof. To the extent permitted by Section 6.1, the Plan Administrator is authorized to grant Performance Awards and shall determine the nature, length and starting date of the performance period for each Performance Award and the performance objectives to be used in valuing Performance Awards and determining the extent to which such Performance Awards have been earned. Performance objectives and other terms may vary from Participant to Participant and between groups of Participants. Performance objectives may be based on, among other criteria, earnings, earnings per share, profits, profit growth, profit-related return ratios, cost management, dividend payout ratios, economic value added, cash flow or total shareholder return, where such goals may be stated in absolute terms relative to comparison companies or otherwise, as the Plan Administrator shall determine, in its sole discretion. Performance periods may overlap and Participants may participate simultaneously with respect to Performance Awards that are subject to different performance periods and different performance factors and criteria.

The Plan Administrator shall determine for each Performance Award the range of dollar values or number of shares of Common Stock (which may, but need not, be shares of Restricted Stock pursuant to Section 10), or a combination thereof, to be received by the Participant at the end of the performance period if and to the extent that the relevant measures of performance for such Performance Awards are met. The earned portion of a Performance Award may be paid currently or on a deferred basis with such interest or earnings equivalent as may be determined by the Plan Administrator. Payment shall be made in the form of cash, whole shares of Common Stock (which

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may, but need not, be shares of Restricted Stock pursuant to Section 10), Options or any combination thereof, either in a single payment or in annual installments, all as the Plan Administrator shall determine.

*11.2 Adjustment of Awards* 

The Plan Administrator may adjust the performance goals and measurements applicable to Performance Awards to take into account changes in law and accounting and tax rules and to make such adjustments as the Plan Administrator deems necessary or appropriate to reflect the inclusion or exclusion of the impact of extraordinary or unusual items, events or circumstances. The Plan Administrator also may adjust the performance goals and measurements applicable to Performance Awards and thereby reduce the amount to be received by any Participant pursuant to such Awards if and to the extent that the Plan Administrator deems it appropriate.

*11.3 Payout Upon Termination* 

The Plan Administrator shall establish and set forth in each instrument that evidences a Performance Award whether the Award will be payable, and the terms and conditions of such payment, if a Participant ceases to be employed by, or to provide services to, the Company or its Subsidiaries, which provisions may be waived or modified by the Plan Administrator at any time. If not so established in the instrument evidencing the Performance Award, the Award will be payable according to the following terms and conditions, which may be waived or modified by the Plan Administrator at any time. If during a performance period a Participant's employment or services with the Company terminate by reason of the Participant's Retirement, Early Retirement at the Company's request, Disability or death, such Participant shall be entitled to a payment with respect to each outstanding Performance Award at the end of the applicable performance period (a) based, to the extent relevant under the terms of the Award, on the Participant's performance for the portion of such performance period ending on the date of termination and (b) prorated for the portion of the performance period during which the Participant was employed by the Company, all as determined by the Plan Administrator. The Plan Administrator may provide for an earlier payment in settlement of such Performance Award discounted at a reasonable interest rate and otherwise in such amount and under such terms and conditions as the Plan Administrator deems appropriate.

Except as otherwise provided in Section 15 or in the instrument evidencing the Performance Award, if during a performance period a Participant's employment or services with the Company terminate other than by reason of the Participant's Retirement, Early Retirement at the Company's request, Disability or death, then such Participant shall not be entitled to any payment with respect to the Performance Awards relating to such performance period, unless the Plan Administrator shall otherwise determine. The provisions of Section 7.6 regarding leaves of absence and termination for Cause shall apply to Performance Awards.

**SECTION 12. OTHER STOCK-BASED AWARDS** 

To the extent permitted by Section 6.1, the Plan Administrator may grant other Awards under the Plan pursuant to which shares of Common Stock (which may, but need not, be shares of Restricted Stock pursuant to Section 10) are or may in the future be acquired, or Awards denominated in

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stock units, including ones valued using measures other than market value. Such Other Stock-Based Awards may be granted alone or in addition to or in tandem with any Award of any type granted under the Plan and must be consistent with the Plan's purpose.

**SECTION 13. DIVIDEND EQUIVALENT RIGHTS** 

To the extent permitted by Section 6.1, any Awards under the Plan may, in the Plan Administrator's discretion, earn Dividend Equivalent Rights. In respect of any Award that is outstanding on the dividend record date for Common Stock, the Participant may be credited with an amount equal to the cash or stock dividends or other distributions that would have been paid on the shares of Common Stock covered by such Award had such covered shares been issued and outstanding on such dividend record date. The Plan Administrator shall establish such rules and procedures governing the crediting of Dividend Equivalent Rights, including the timing, form of payment and payment contingencies of such Dividend Equivalent Rights, as it deems are appropriate or necessary.

**SECTION 14. ASSIGNABILITY** 

No Award granted under the Plan may be assigned or transferred by the Holder other than by will or by the applicable laws of descent and distribution, and, during the Holder's lifetime, such Awards may be exercised only by the Holder or a permitted assignee or transferee of the Holder (as provided below). Notwithstanding the foregoing, and to the extent permitted by Section 422 of the Code, the Plan Administrator, in its sole discretion, may permit such assignment, transfer and exercisability and may permit a Holder of such Awards to designate a beneficiary who may exercise the Award or receive compensation under the Award after the Holder's death; provided, however, that any Award so assigned or transferred shall be subject to all the same terms and conditions contained in the instrument evidencing the Award.

**SECTION 15. ADJUSTMENTS** 

*15.1 Adjustment of Shares* 

In the event that, at any time or from time to time, a stock dividend, stock split, spin-off, combination or exchange of shares, recapitalization, merger, consolidation, distribution to shareholders other than a normal cash dividend or other change in the Company's corporate or capital structure results in (a) the outstanding shares, or any securities exchanged therefor or received in their place, being exchanged for a different number or class of securities of the Company or of any other corporation or (b) new, different or additional securities of the Company or of any other corporation being received by the holders of shares of Common Stock of the Company, then the Plan Administrator shall make proportional adjustments in (i) the maximum number and kind of securities subject to the Plan as set forth in Section 4.1, (ii) the maximum number and kind of securities that may be made subject to Stock Awards and to Awards to any individual Participant as set forth in Section 4.2, and (iii) the number and kind of securities that are subject to any outstanding Award and the per share price of such securities, without any change in the aggregate price to be paid therefor; provided, however, any substitution of a new Option pursuant to a corporate transaction for an outstanding Option or the assumption of an outstanding Option shall meet the requirements of Treasury Regulation §1.424-1. The preceding sentence shall

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apply to "incentive stock options" as that term is defined in Section 422 of the Code and nonqualified stock options. The determination by the Plan Administrator as to the terms of any of the foregoing adjustments shall be conclusive and binding.

*15.2 Change of Control* 

Except as otherwise provided in the instrument that evidences the Award, in the event of any Change of Control, each Award that is at the time outstanding shall automatically accelerate so that each such Award shall, immediately prior to the specified effective date for the Change of Control, become 100% vested and exercisable; provided, however, that with respect to Performance Awards, the performance objectives with respect thereto shall be deemed to be met at the target level or determined based on actual performance through the date of the Change of Control as if the performance period ended on such date, whichever is higher. Such Award shall not so accelerate, however, if and to the extent that such Award is, in connection with the Change of Control, either to be assumed by the successor corporation or parent thereof (the "Successor Corporation") or to be replaced with a comparable award for the purchase of shares of the capital stock of the Successor Corporation. The determination of Award comparability in the immediately preceding sentence shall be made by the Plan Administrator, and its determination shall be conclusive and binding. All such Awards shall terminate and cease to remain outstanding immediately following the consummation of the Change of Control, except to the extent assumed by the Successor Corporation. In the event an Option or Stock Appreciation Right is cancelled pursuant to this Section 15.2 in exchange for a payment based on the amount by which the Fair Market Value of Common Stock exceeds the exercise price for such Option or Stock Appreciation Right, any Option or Stock Appreciation Right with an exercise price equal to or greater than the Fair Market Value of Common Stock may be cancelled for no consideration. Any Awards that are assumed or replaced in the Change of Control and do not otherwise accelerate at that time shall be accelerated in the event that the Participant's employment or services should subsequently terminate within 24 months following such Change of Control, unless such employment or services are terminated by the Successor Corporation for Cause or by the Participant voluntarily without Good Reason.

*15.3 Further Adjustment of Awards* 

Subject to Sections 15.2 and 17.3, and subject to the limitations set forth in Section 11, the Plan Administrator shall have the discretion, exercisable at any time before a sale, merger, consolidation, reorganization, liquidation or other corporate transaction, as defined by the Plan Administrator, to take such further action as it determines to be necessary or advisable, and fair and equitable to Participants, with respect to Awards. Such authorized action may include (but shall not be limited to) establishing, amending or waiving the type, terms, conditions or duration of, or restrictions on, Awards so as to provide for earlier, later, extended or additional time for exercise, payment or settlement or lifting restrictions, differing methods for calculating payments or settlements, alternate forms and amounts of payments and settlements and other modifications, and the Plan Administrator may take such actions with respect to all Participants, to certain categories of Participants or only to individual Participants; provided that any cancellation or termination of Options or Stock Appreciation Rights with an exercise price that is less than the Fair Market Value of a share of Common Stock on the date of such cancellation or termination may be made without payment of any consideration therefor. The Plan Administrator may take

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such action before or after granting Awards to which the action relates and before or after any public announcement with respect to such sale, merger, consolidation, reorganization, liquidation or Change of Control that is the reason for such action.

*15.4 Limitations* 

The grant of Awards will in no way affect the Company's right to adjust, reclassify, reorganize or otherwise change its capital or business structure or to merge, consolidate, dissolve, liquidate or sell or transfer all or any part of its business or assets.

**SECTION 16. WITHHOLDING** 

The Company may require the Holder to pay to the Company the amount of any withholding taxes that the Company is required to withhold with respect to the grant, exercise, payment or settlement of any Award. Subject to the Plan and applicable law and unless the Plan Administrator determines otherwise, the Holder may satisfy withholding obligations, in whole or in part, by paying cash, by electing to have the Company withhold shares of Common Stock (up to the employer's minimum required tax withholding rate) or by transferring shares of Common Stock to the Company (already owned by the Participant for the period necessary to avoid a charge to the Company's earnings for financial reporting purposes), in such amounts as are equivalent to the Fair Market Value of the withholding obligation. The Company shall have the right to withhold from any Award or any shares of Common Stock issuable pursuant to an Award or from any cash amounts otherwise due or to become due from the Company to the Participant an amount equal to such taxes.

**SECTION 17. AMENDMENT AND TERMINATION OF PLAN** 

*17.1 Amendment of Plan* 

The Plan may be amended only by the Board as it shall deem advisable; provided, however, to the extent required for compliance with Section 422 of the Code or any other applicable law, rule or regulation, shareholder approval will be required for any amendment that will (a) increase the total number of shares as to which Options may be granted or that may be used in payment of Stock Appreciation Rights, Performance Awards, Other Stock-Based Awards or Dividend Equivalent Rights under the Plan or that may be issued as Stock Awards, (b) modify the class of persons eligible to receive Options, (c) result in a "material revision" of the Plan as contemplated by Section 303A.08 of the New York Stock Exchange Listed Company Manual, or (d) otherwise require shareholder approval under any applicable law, rule or regulation.

*17.2 Termination of Plan* 

The Board may suspend or terminate the Plan at any time. The Plan will have no fixed expiration date; provided, however, that no Incentive Stock Options may be granted more than 10 years after the earlier of the Plan's adoption by the Board and approval by the shareholders. In accordance with Treasury Regulations sections 1.422-2(b)(iii) and 1.422-2(c), the amendment and restatement of the Plan effective February 21, 2025, constitutes a new plan for purposes of the Incentive Stock Option rules. As a result, Incentive Stock Options may be granted within ten years from the earlier

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of the date the amended and restated plan is adopted by the Board or the date such plan is approved by shareholders.

*17.3 Consent of Holder* 

The amendment or termination of the Plan shall not, without the consent of the Holder of any Award under the Plan, impair or diminish any rights or obligations under any Award theretofore granted under the Plan. Any change or adjustment to an outstanding Incentive Stock Option shall not, without the consent of the Holder, be made in a manner so as to constitute a "modification" that would cause such Incentive Stock Option to fail to continue to qualify as an Incentive Stock Option.

*17.4 Correction of Errors*

Notwithstanding anything in this Plan or an Award agreement to the contrary, the Plan Administrator may amend an Award, to take effective retroactively or otherwise, as deemed necessary or advisable for the purpose of correcting errors occurring in connection with the grant or documentation of an Award, including rescinding an Award erroneously granted, including, but not limited to, an Award erroneously granted to an individual who is not eligible to receive on an Award on the date of grant of the Award. By accepting an Award under the Plan, each Participant agrees to any amendment made pursuant to this Section 17.4 to any Award made under the Plan without further consideration or action.

**SECTION 18. GENERAL** 

*18.1 Award Agreements* 

Awards granted under the Plan shall be evidenced by a written agreement that shall contain such terms, conditions, limitations and restrictions as the Plan Administrator shall deem advisable and that are not inconsistent with the Plan. In the event that the Company establishes, for itself or using the services of a third party, an automated system for the documentation, granting or exercise of Awards, such as a system using an internet website or interactive voice response, then the paperless documentation, granting or exercise of Awards by a Participant may be permitted through the use of such an automated system.

*18.2 No Employment Rights; No Right to Award*

Nothing contained in the Plan or any Award agreement shall confer upon any individual any right with respect to the continuation of employment by or provision of services to the Company or any Subsidiary or interfere in any way with the right of the Company or applicable Subsidiary, subject to the terms of any separate agreement to the contrary, at any time to terminate such employment or service or to increase or decrease the compensation or benefits of such individual. No individual shall have any claim or right to receive an Award hereunder. The Plan Administrator's granting of an Award to a Participant at any time shall neither require the Plan Administrator to grant any other Award to such Participant or other individual at any time nor preclude the Plan Administrator from making subsequent grants to such Participant or any other individual.

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*18.3 Registration* 

The Company may issue certificates for shares with such legends and subject to such restrictions on transfer and stop-transfer instructions as counsel for the Company deems necessary or desirable for compliance by the Company with federal and state securities laws.

Inability of the Company to obtain, from any regulatory body having jurisdiction, the authority deemed by the Company's counsel to be necessary for the lawful issuance and sale of any shares hereunder or the unavailability of an exemption from registration for the issuance and sale of any shares hereunder shall relieve the Company of any liability in respect of the nonissuance or sale of such shares as to which such requisite authority shall not have been obtained.

*18.4 No Rights as a Shareholder* 

No Award shall entitle the Holder to any cash dividend (except to the extent provided in an Award of Restricted Stock or of Dividend Equivalent Rights), voting or other right of a shareholder unless and until the date of issuance under the Plan of the shares that are the subject of such Award, free of all applicable restrictions except as otherwise required with respect to a transfer of Restricted Stock.

*18.4 Section 409A of the Code*

The Plan and Award agreements as well as payments and benefits thereunder are intended to be exempt from, or to the extent subject thereto, to comply with Section 409A of the Code, and, accordingly, to the maximum extent permitted, the Plan and Award agreements shall be interpreted in accordance therewith. Notwithstanding anything contained herein to the contrary, if payments or benefits under the Plan are payable upon a termination of employment or other service (or words of similar import), a Participant shall not be considered to have experienced such a termination for purposes of the Plan and no payment or benefit shall be due to such Participant under the Plan or any Award until such Participant is considered to have experienced a "separation from service" from the Company within the meaning of Section 409A of the Code. Any payments or benefits described in the Plan that are due within the "short term deferral period" as defined in Section 409A of the Code shall not be treated as deferred compensation unless applicable law requires otherwise. Notwithstanding anything to the contrary in the Plan, to the extent that any Awards are payable upon a separation from service and the Participant is a "specified employee" as defined in Section 409A of the Code, the settlement and payment of such Awards shall instead be made (without interest) on the Company's first regular payroll date that is at least six (6) months following such separation from service (or death, if earlier). Each amount to be paid or benefit to be provided under this Plan shall be construed as a separate identified payment for purposes of Section 409A of the Code.

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*18.5 No Guarantee of Tax Consequences*

None of the Company, its Subsidiaries, the Board, the Plan Administrator or any officer, employee, agent, affilaite or representative of any of the foregoing makes any commitment or guarantee with respect to the Plan or any Award granted hereunder that any particular tax treatment will (or will not) apply with respect to any Participant (or any party claiming through or on behalf of any Participant), including any tax consequences under Section 409A of the Code, or assumes any liability or responsibility with respect thereto.

*18.5 Compliance With Laws and Regulations* 

Notwithstanding anything in the Plan to the contrary, the Board, in its sole discretion, may bifurcate the Plan so as to restrict, limit or condition the use of any provision of the Plan to Participants who are officers or directors subject to Section 16 of the Exchange Act without so restricting, limiting or conditioning the Plan with respect to other Participants. Additionally, in interpreting and applying the provisions of the Plan, any Option granted as an Incentive Stock Option pursuant to the Plan shall, to the extent permitted by law, be construed as an "incentive stock option" within the meaning of Section 422 of the Code.

*18.6 Unfunded Plan* 

The Plan is intended to constitute an "unfunded" plan. Nothing contained herein shall require the Company to segregate any monies or other property, or shares of Common Stock, or to create any trusts, or to make any special deposits for any immediate or deferred amounts payable to any Participant, and no Participant shall have any rights that are greater than those of a general unsecured creditor of the Company.

*18.7 Severability* 

If any provision of the Plan or any Award is determined to be invalid, illegal or unenforceable in any jurisdiction, or as to any person, or would disqualify the Plan or any Award under any law deemed applicable by the Plan Administrator, such provision shall be construed or deemed amended to conform to applicable laws, or, if it cannot be so construed or deemed amended without, in the Plan Administrator's determination, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, person or Award, and the remainder of the Plan and any such Award shall remain in full force and effect.

*18.8 Captions.*

The captions of this Plan are not part of the provisions hereof and shall have no force or effect.

**SECTION 19. EFFECTIVE DATE** 

The Plan's effective date is the date on which it is adopted by the Board, so long as it is approved by the Company's shareholders at any time within 12 months of such adoption.

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## Exhibit 10.23

**Exhibit 10.23**

![img132016384_0.jpg](img132016384_0.jpg)

**RRRAVISTA CORPORATION**

**PERFORMANCE AWARD AGREEMENT**

This Performance Award Agreement (the "Agreement") is made by and between Avista Corporation, a Washington Corporation (the "Company") and **PARTICIPANT NAME** (the "Participant") as designated by the Avista Corporation Compensation and Organization Committee (the "Plan Administrator").

WHEREAS, Performance Awards are defined and granted under the February 21, 2025 amended and restated Avista Corporation Long-Term Incentive Plan (the "Plan"). The terms and conditions of the Performance Awards are set forth below and in the Plan, which is incorporated into this Agreement by reference. All current and future grants will be made subject to the terms of this Agreement.

NOW, THEREFORE, in consideration of the premises contained herein and in the Plan, it is agreed as follows:

1. **Terms of Performance Awards**. The terms of the Performance Awards are set forth as follows:**.**

The "Performance Cycle" is the period notated in the annual performance award metrics and goals (the "Performance Metrics"), as approved each year by Avista's Board of Directors.

2. **Conditions to Award**. Pursuant to this Award, the number of Performance Awards earned will depend upon the Company's performance against specific performance metrics. The performance metrics are (i) Relative Total Shareholder Return and (ii) Cumulative Earnings Per Share ("CEPS"). The total number of shares of Stock that will be issued in the settlement of this Award, based upon the Company's satisfaction of the metrics, will be determined by multiplying the Target Number of units allocated for each metric by the applicable Payout Factor in accordance with the provisions of the Performance Metrics.

3. **Settlement of Performance Awards**. The Company shall deliver to the Participant one share of Common Stock (or cash equal to the Fair Market Value of one share of Common Stock) for each Performance Award earned by the Participant, as determined in accordance with the provisions of the approved Performance Metrics. The earned Performance Award payable to the Participant shall be paid in shares of Common Stock or in cash (based on the Fair Market Value of the Common Stock as of the date the Plan Administrator certifies the attainment of the performance goals), or in a combination of the two, as determined by the Plan Administrator in its sole discretion, except that cash may be distributed in lieu of any fractional share of Common Stock.

All Performance Awards and any Dividend Equivalents (as described in Section 5 below) earned by a Participant under this Agreement are subject to the Recoupment Policy adopted by the Company's Board of Directors as amended from time to time ("Recoupment Policy"). If a Participant becomes subject to the Recoupment Policy any Performance Award and associated Dividend Equivalent may be forfeited in whole or in part and all or part of any distribution payable to a Participant or his or her beneficiary under this Agreement may be recovered by the Company pursuant to the Recoupment Policy.

4. **Time of Payment**. Except as otherwise provided in this Agreement, payment of Performance Awards earned will be delivered as soon as feasible after the end of the Performance Cycle and after the Plan Administrator certifies the attainment of the performance goals.

5. **Dividend Equivalent Rights**. Any Performance Awards may, in the Plan Administrator's discretion, earn Dividend Equivalent Rights. In respect of any Performance Award that is outstanding on the dividend record date for Common Stock, the Participant may be credited with an amount equal to the cash distributions that would have been paid on the shares of Common Stock covered by such Award had such covered shares been issued and outstanding on such dividend record date. Dividend Equivalent Rights are to be paid in cash based on the total number of Performance Awards earned at the end of the Performance Cycle and delivered as soon as feasible after the Performance Cycle and after the Plan Administrator certifies the attainment of the performance goals.

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Dividend Equivalent Rights are subject to all applicable taxes, which are the responsibility of the Participant. The Dividend Equivalent Rights in respect of any Performance Awards that are not earned as of the end of a Performance Cycle, shall be forfeited as of the end of the Performance Cycle.

6. **Termination of Employment during Performance Cycle**. Except as otherwise provided in section 7, this section 6 shall apply if the Participant's employment terminates during a Performance Cycle. If the Participant's employment with the Company and/or Subsidiaries terminates during the Performance Cycle because of Retirement, Disability, or Death, the Participant shall be entitled to a prorated value of the Performance Award earned in accordance with the Performance Metrics , determined at the end of the Performance Cycle, and based on the ratio of the number of whole months the Participant was employed during the Performance Cycle to the total number of months in the Performance Cycle (36). If a Participant's employment or services with the Company and/or Subsidiaries terminate on or as of the last day of a Performance Cycle, such Participant will be deemed to have terminated after the end of such Performance Cycle. If the Participant's employment with the Company and/or Subsidiaries terminates during the Performance Cycle for any reason other than Retirement, Disability, or Death, the Performance Award granted under this Agreement will be forfeited on the Date of Termination (as defined in section 9(b)); provided, however, that in such circumstances, the Plan Administrator, in its sole discretion, may determine that the Participant will be entitled to receive a prorated or other portion of the Performance Award. In case of termination for Cause, the Performance Award granted shall automatically terminate upon first notification to the Participant of such termination, unless the Plan Administrator determines otherwise. If a Participant's employment with the Company is suspended pending an investigation of whether the Participant shall be terminated for Cause, all the Participant's rights under any Award likewise shall be suspended during the period of investigation. The effect of a Company-approved leave of absence on the terms and conditions of an Award shall be determined by the Plan Administrator, in its sole discretion.

7. **Change in Control**. If a Change in Control occurs during the Performance Cycle, and the Participant's Date of Termination (as defined in section 9(b)) does not occur before the Change in Control date, the Participant shall be entitled to a prorated value of the Performance Award that would have been earned by the Participant in accordance with the Performance Metrics , determined as of the date of the Change in Control, prorated based on the ratio of the number of whole months the Participant is employed during the Performance Cycle through the date of the Change in Control, to the total number of months in the Performance Cycle; provided, however, that a Payout Factor of at least 100% as set forth in the Performance Metrics for the Performance Cycle shall be deemed to have been achieved as of the date of the Change in Control. Notwithstanding the provisions of sections 3 (with the exception of the application of the Recoupment Policy), 4, and 5, the value of the Performance Award, and any Dividend Equivalent Right, earned in accordance with the foregoing provisions of this section shall be delivered to the Participant in a lump sum cash payment as soon as feasible after the occurrence of a Change in Control, with the value of a Performance Award equal to the Fair Market Value of a share of Common Stock determined under the provision of section 3 as of the date of the Change in Control. Distributions to the Participant under sections 3 and 5 shall not be affected by payments under this section, except that the number of Performance Awards and Dividend Equivalent Rights earned by and payable to the Participant shall be reduced by the number of Performance Awards and Dividend Equivalent Rights with respect to which payment was made to the Participant under this section.

8. **Taxes**. The Participant is liable for any and all taxes, including withholding taxes, arising out of the grant, vesting, payment or settlement of any Performance Awards and Dividend Equivalent Rights. The Company shall have the right to require the Participant to remit to the Company, or to withhold awarded shares of Common Stock, or from any Dividend Equivalent Rights or other amounts due to the Participant, as compensation or otherwise, an amount sufficient to satisfy all federal, state and local withholding tax requirements.

9. **Definitions**. For purposes of this Agreement, the terms used in this Agreement shall be subject to the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)<u>Change in Control</u>. The term "Change in Control" is defined in section 2.4 of the amended and restated Avista Corp. Long Term Incentive Plan.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)<u>Date of Termination</u>. The Participant's "Date of Termination" shall be the first day occurring on or after the Grant Date on which the Participant is not employed by the Company or any Subsidiary, regardless of the reason for the termination of employment; provided that a termination of employment shall not be deemed to occur by reason of a transfer of the Participant between the Company and a Subsidiary or between two Subsidiaries; and further provided that the

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Participant's employment shall not be considered terminated while the Participant is on a leave of absence from the Company or a Subsidiary approved by the Participant's employer. If, as a result of a sale or other transaction, the Participant's employer ceases to be a Subsidiary (and the Participant's employer is or becomes an entity that is separate from the Company), and the Participant is not, at the end of the 30-day period following the transaction, employed by the Company or an entity that is then a Subsidiary, then the occurrence of such transaction shall be treated as the Participant's Date of Termination caused by the Participant being discharged by the employer.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)<u>Disability</u>. ''Disability'' means ''disability'' as that term is defined for purposes of the Company's Long Term Disability Plan or other similar successor plan applicable to employees.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d)<u>Retirement</u>. "Retirement" of the Participant shall mean retirement as of the individual's retirement date under the Retirement Plan for Employees of Avista Corporation or other similar successor plan applicable to employees.

10. **Assignability**. No Performance Award or Dividend Equivalent Right granted or awarded under the Plan may be assigned or transferred by the Participant other than by will or by the applicable laws of descent and distribution, and, during the Participant's lifetime, settlements of such Awards may be payable only to the Participant or a permitted assignee or transferee of the Participant (as provided below). Notwithstanding the foregoing, the Plan Administrator, in its sole discretion, may permit such assignment or transfer and may permit a Participant of such Performance Awards or Dividend Equivalent Rights to designate a beneficiary who may receive compensation settlement under the Performance Award after the Participant's death; provided, however, that any amount so assigned or transferred shall be subject to all the same terms and conditions contained in this Agreement.

11. **General**.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.1 **Award Agreements**. Performance Awards granted under the Plan shall be evidenced by a written agreement that shall contain such terms, conditions, limitations and restrictions as the Plan Administrator shall deem advisable and that are not inconsistent with the Plan.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.2 **Continued Employment or Services; Rights in Awards**. Nothing contained in this Agreement, the Plan, or any action of the Plan Administrator taken under the Plan or this Agreement shall be construed as giving any Participant or employee of the Company any right to be retained in the employ of the Company or any Subsidiary or to limit the Company's or any Subsidiary's right to terminate the employment or services of the Participant.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.3 **Registration**. At the present time, the Company has an effective registration statement with respect to the shares. The Company intends to maintain this registration but has no obligation to do so. In the event that such registration ceases to be effective, the Participant will not receive a Performance Award settlement or payment unless exemptions from registration under federal and state securities laws are available; such exemptions from registration are very limited and might be unavailable. **By accepting the Agreement, the Participant hereby acknowledges that he/she has read the section of the Plan and this Agreement entitled Registration.**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.4 **No Rights as a Shareholder**. No Award under this Agreement shall entitle the Participant to any dividends (except to the extent provided in an award of Dividend Equivalent Rights), voting or any other right of a shareholder unless and until the date of issuance under the Plan of the shares that are the subject of such Performance Award, are free of all applicable restrictions.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.5 **Compliance with Laws and Regulations**. Notwithstanding anything in the Plan to the contrary, the Board of Directors, in its sole discretion, may bifurcate the Plan so as to restrict, limit or condition the use of any provision of the Plan to Participants who are officers or directors subject to Section 16 of the Exchange Act without so restricting, limiting or conditioning the Plan with respect to other Participants.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.6 **Severability**. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity and enforceability of any other provision of this Agreement. If any provision of the Agreement is determined to be invalid, illegal or unenforceable in any jurisdiction, or as to any person, or would disqualify any Performance Award under any law deemed applicable by the Plan Administrator, such provision shall be construed or deemed

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amended by the Plan Administrator to conform to applicable laws, or, if the Plan Administrator determines that the provision cannot be so construed or deemed amended without materially altering the intent of the Plan or the Performance Award, such provision shall be stricken as to such jurisdiction, person or Performance Award, and the remainder of the Agreement and any such Performance Award shall remain in full force and effect.

12. **Administration**. The authority to manage and control the operation and administration of this Agreement shall be vested in the Plan Administrator, and the Plan Administrator shall have all powers with respect to this Agreement as it has with respect to the Plan. Any interpretation of the Agreement by the Plan Administrator and any decision made by it with respect to the Agreement are final and binding.

13. **Construction**. This Agreement is subject to and shall be construed in accordance with the Plan, the terms of which are explicitly made applicable hereto. Unless otherwise defined herein, capitalized terms in this Agreement shall have the same definitions as set forth in the Plan. In the event of any conflict between the provisions hereof and those of the Plan, the provisions of the Plan shall govern.

14. **Amendment**. This Agreement may be amended by written agreement of the Participant and the Company, without the consent of any other person.

15. **Governing Law**. The validity, construction, interpretation and enforceability of this Agreement shall be determined and governed by the laws of the State of Washington without giving effect to the principles of conflicts of laws. For the purpose of litigating any dispute that arises under this Agreement, the parties hereby consent to exclusive jurisdiction in Washington State and agree that such litigation shall be conducted in the courts of Spokane County, Washington or the federal courts of the United States for the eastern district of Washington.

16. **Successors**. The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise to all or substantially all of the business and/or assets of the Company) to agree in writing to assume the Company's obligations under this Agreement and to perform such obligations in the same manner and to the same extent that the Company is required to perform them. As used in this Agreement, "Company" shall mean the Company and any successor to its business and/or assets that assumes and agrees to perform the Company's obligations under the Agreement by operation of law or otherwise.

IN WITNESS WHEREOF, the Participant has executed this Agreement, and the Company has caused these presents to be executed in its name and on its behalf,

AVISTA CORPORATION

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| | |
|:---|:---|
| By: | /s/ Heather Rosentrater |
|  | Heather Rosentrater |
|  | Chief Executive Officer |

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ACCEPTANCE AND ACKNOWLEDGMENT

I, a resident of the state of ___________________________________, accept the Performance Award described in this Agreement and in the Plan, and acknowledge that I have received a copy of this Agreement and the Plan. I have read and understand the Plan, and I hereby make the representations, warranties and acknowledgments, and undertake the indemnity and other obligations, therein specified.

Dated: ________________

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| |
|:---|
| Signature of Employee |
| Printed Name |

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# AVISTA CORPORATION

# PERFORMANCE AWARD AGREEMENT - PERFORMANCE METRICS
**Performance Award Plan**

**Relative Total Shareholder Return Metric and Goals**

**2025 - 2027 Performance Cycle**

The following graph and table represent the relationship between the Company's relative three-year Total Shareholder Return ("TSR") commencing January 1, 2025 and ending December 31, 2027 and the target award opportunity. The number of shares delivered at the end of the three-year Performance Cycle can range from zero to 200% of the target number of units allocated under this metric. The actual issuance of shares depends on Avista's three-year TSR performance compared to the returns of the peer companies reported in the S&P 400 Utilities Index and how we rank among them. To receive 100% of the Award allocated under this metric, Avista must perform at the **50th** percentile among the companies in the S&P 400 Utilities Index. To receive 200% of the Award, Avista must rank at the **75**<sup>th</sup>percentile. If Avista ranks below the **25**<sup>th</sup> percentile, no stock awards or cash Dividend Equivalent Rights will be earned. Dividend Equivalent Rights are calculated and paid out in cash when and to the extent the Performance Awards are issued. The following graph demonstrates the relationship between TSR ranking and various payout factors. Performance Awards are interpolated on a straight line for performance results between the figures shown. The final performance cycle result is certified by our third-party compensation consultant.

![img132016384_1.jpg](img132016384_1.jpg)

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| | | |
|:---|:---|:---|
|  | **TSR Percentile Ranking** | **Payout (% of Target)** |
| **Maximum** | 75th | 200% |
| **Target** | 50th | 100% |
| **Threshold** | 25th | 50% |
|  | <25th | 0% |

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TSR is calculated using S&P's Research Insight software and reflects share price appreciation plus the impact of dividend distributions and the reinvestment of such dividends. TSR is calculated daily based on stock price changes and dividend payments, and then accumulated over the measurement period. Dividends are calculated using ex-date dividends per share. Beginning and ending share prices for the performance period reflect the average of closing share prices on the last 20 trading days ending on December 31<sup>st</sup> for both Avista and the peers.

The peer companies reported in the S&P 400 Utilities Index to be used in the ranking will be captured at the performance award grant date and will remain unchanged throughout the performance cycle. If S&P drops a company out of the index and/or adds another, the new company will not be included in the ranking and the

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dropped company will remain included in the ranking, as long as it remains a publicly traded company. If a company becomes no longer publicly traded, it will be removed from the comparison group.

**Settlement Formula Example:**

Assuming that 1,000 Performance Award units were allocated under this metric at the beginning of the three-year Performance Cycle and Avista's TSR ranked at the 75<sup>th</sup> percentile after the three-year Performance Cycle, the Participant would receive 200% of 1,000 or 2,000 shares of Avista common stock plus cash dividend equivalents.

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| | | | | |
|:---|:---|:---|:---|:---|
| Payout Factor (% of Target) |  | Target Number of <br>Performance Awards Granted |  | Final Number of Common <br>Stocks Issued |
| 200% | X | 1000 | = | 2,000 shares plus cash dividends |

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**Percentile Ranking Methodology:**

The percentile rank is calculated using the PERCENTRANK function in MS Excel, initially excluding Avista from the list. The results are rounded to the nearest whole percentile after Avista has been ranked.

The calculation can be replicated by arranging the TSR data from highest to lowest for all peers except Avista. A percentile ranking is calculated for each data point assuming 100.0th percentile for the highest data point, 0.0 percentile for the lowest data point, and the corresponding percentile for every other data point with an equal difference in percentile ranking for each data point. The TSR for Avista is calculated by determining Avista's rank in the list and interpolating between the percentile rankings for the companies immediately above and below based on the differences in TSR. An example, based on sample data is as follows:

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| | | |
|:---|:---|:---|
| Company Ranking | TSR | Percentile Rank |
| 1 | 63.6% | 100.0% |
| 2 | 62.8% | 92.8% |
| 11 (ABC Corp) | 32.0% | 28.5% |
| 12(XYZ Corp) | 10.0% | 21.4% |
| 14 | 4.4% | 7.1% |
| 15 | -11.6% | 0.0% |

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If a company's TSR is 29.1%, the resulting percentile ranking would be 27.6%, calculated as follows: 27.6% = 21.4% + [(29.1% - 10.0%) / (32.0% - 10.0%) \* (28.5% - 21.4%)]

**Total Shareholder Return (TSR) Methodology:**

For purposes of this Agreement, a methodology for calculating a total return to shareholder with dividend reinvestment was established. Returns are calculated daily based on stock price changes and dividend payments and then accumulated over the Performance Cycle. Below are additional assumptions used in Avista's calculation for TSR.

**General Assumptions:**

The starting share price for the Performance Cycle is determined by averaging the closing stock price on the last 20 trading days ending on December 31<sup>st</sup> prior to the first day of Performance Cycle. The ending share price is determined by averaging the closing stock price on the last 20 trading days ending on December 31<sup>st</sup> at the end of the Performance Cycle.

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**Performance Award Plan**

**Cumulative Earnings Per Share Metric and Goals**

**2025-2027 Performance Period**

The following graph and table represent the relationship between the Company's Cumulative Earnings Per Share ("CEPS") commencing January 1, 2025 and ending December 31, 2027 and the target award opportunity. The number of shares delivered at the end of the three-year Performance Cycle can range from zero to 200% of the target number of units allocated under this metric. The actual issuance of shares depends on Avista's CEPS over the three-year Performance Cycle. To receive 100% of the Performance Award allocated under this metric, Avista must achieve CEPS **$7.99** over the three-year cycle. To receive 200% of the Award, Avista must achieve CEPS of **$8.30.** If Avista's CEPS is less than **$7.68**, no stock awards or cash Dividend Equivalent Rights will be earned. Dividend Equivalent Rights are calculated and paid out in cash when and to the extent the Performance Awards are issued. The following graph demonstrates the relationship between CEPS and various payout factors. Performance Awards are interpolated on a straight line for performance results between the figures shown.

![img132016384_2.jpg](img132016384_2.jpg)

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| | | |
|:---|:---|:---|
|  | **3-Year CEPS** | **Payout Factor** |
| **Maximum** | $8.30 | 200% |
| **Target** | $7.99 | 100% |
| **Threshold** | $7.68 | 50% |
|  | <$7.68 | 0% |

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Performance is tracked over a three-year Performance Cycle thereby focusing on sustainability.

Cumulative EPS (CEPS) is fully diluted earnings per share for Avista Utilities and Alaska Electric Light and Power Company excluding the impact of the Energy Recovery Mechanism in Washington. CEPS may be adjusted to remove the effects of such items as regulatory charges, income tax legislative changes and/or items of a non-routine or items of an extraordinary nature as determined by the Plan Administrator.

**Settlement Formula Example:**

Assuming that 1,000 Performance Award units were allocated under this metric at the beginning of the Performance Cycle and Avista's cumulative EPS was $**8.07** over three years, the Participant would receive 125% of 1,000 or 1,250 shares of Avista common stock plus dividend equivalents in cash.

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| | | | | |
|:---|:---|:---|:---|:---|
| Payout Factor (% of Target) |  | Target Number of <br>Performance Awards Granted |  | Number of Common <br>Stocks Issued |
| 125% | X | 1000 | = | 1,250 shares plus cash dividends |

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## Exhibit 10.24

**Exhibit 10.24**

![img132939905_0.jpg](img132939905_0.jpg)

**2025 SENIOR LEADER** 

**ANNUAL CASH INCENTIVE PLAN**

# PLAN PROVISIONS
**Approved by Board**

**Purpose:** The Senior Leader Annual Cash Incentive Plan (Plan) is designed to align the interests of our senior leaders with both shareholder and customer interests to achieve overall positive financial and operational performance for the Company. The Plan is an important element of the overall compensation of our senior leaders which provides compensation that is competitive with compensation paid to comparable leaders of companies within the energy/utility industry and ensures the Company can attract and retain quality employees in key positions to lead the Company.

**Plan Year:** January 1, 2025 – December 31, 2025

*Note: If Dec 31 falls on a non-working day, the previous business working day (M-F) will be considered the last day of the plan year.*

**Eligibility:**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•All executive officers ("officers") hired prior to October 1<sup>st</sup> and actively employed on the last day of the plan year, are eligible to participate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•All Directors and Senior Legal Counsel employees ("non-officers") currently participating in the company's Long-Term Incentive (LTI) plan are eligible to participate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· Past-officer part-time advisors employed during the plan year are also eligible to participate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· Subsidiary officers are not eligible to participate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· Other details available in section *Exceptions to Eligibility and Circumstances for Proration*

**Performance Measurements:** The Plan focuses on shareholders and customers by creating value through sound financial performance and controlling costs through driving efficiencies while paying close attention to our customers' voices regarding the products and services we provide. The Plan incorporates Utility Earnings Per Share (Utility EPS) and Operating & Maintenance Cost per Customer (O&M CPC) as financial performance measurements. There are also four non-financial measurements: Customer Satisfaction Rating (Customer Satisfaction), Reliability Index (Reliability), Dispatched Gas Emergency Response Time (Response Time), and Strategy Scorecard (Strategy Scorecard). These performance goals help increase shareholder value, gain financial strength, support long-term strategy, and maintain safe and reliable cost-effective service levels essential for our customers and for the long-term success of the Company. With the exception of the Utility EPS and Strategy Scorecard, performance metrics are identical to those used in the Company's annual cash incentive plan for non-senior leader employees. The Compensation Committee believes that having similar metrics for both the senior leader plan and the non-senior leader plan encourages employees at all levels of the organization to focus on common objectives.

*Utility EPS -* This metric reflects the financial strength and alignment of interests

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between officers and shareholders. Utility EPS includes Avista Utilities and Alaska Electric Light & Power (AEL&P),and excludes other.

*O&M CPC* - The O&M CPC is a measure that focuses on controlling costs and driving efficiencies to keep our costs reasonable for our customers. The metric is based on targeted O&M expense and number of customers. These components are combined to create the O&M CPC metric.

*Strategy Scorecard –* This is a measure that supports Avista's Strategic Plan and ensures alignment with the organization's strategic goals to drive performance in these areas. The metric is based on achieving a set of activity-based milestones.

*Customer Satisfaction* - This measure is derived from a <u>Voice of the Customer</u> survey, which is conducted each quarter by an independent agency. The rating measures the customer's overall satisfaction with the service they received during a recent contact with the Company's contact center and/or service center.

*Reliability* - This measure tracks how quickly the Company restores outages, how frequently customers are affected by outages and what percent of customers experience more than three sustained outages per year. The Company combined three common industry indices to balance our focus.

*Response Time* - This measure tracks how quickly the Company responds to dispatched natural gas emergency calls. The primary objective is customer and public safety while consistently treating customers the same throughout our service territory.

**Award Opportunity:** The Plan has six independent metrics, each having their own goal to achieve. Each piece or component makes up a portion of the employee's total incentive award opportunity as represented in the graph. Specific metric weightings differ for officers and non-officers and are shown in Figure 1 and in the Incentive Targets table below:

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![img132939905_1.jpg](img132939905_1.jpg)

*Figure 1*

*Non-financial metrics:* Three of the four non-financial pieces of the award (customer satisfaction, reliability, and response time) are all-or-nothing goals. If the Company meets or exceeds the target goal for any one of the metrics, employees receive 100% of the incentive award percentage related to the metric. If the Company fails to meet the target, employees will receive no award related to the metric. For example, if the Company achieves Customer Satisfaction with a 90% or better rating, employees will receive 8% of their total incentive award opportunity. If the Company achieves 88% which is below the target, employees will receive no award related to the metric. This works the same for Reliability and Response Time. The maximum amount an employee could receive related to the non-financial metrics is 8% for customer satisfaction, 8% reliability, and 4% response time. The fourth non-financial metric, Strategy Scorecard, is on a sliding scale; if three out of the five milestones are completed, employees will receive threshold or 70% of total for that metric. For employees to receive 100% of their award related to this metric, the company must achieve target, or four out of five milestones*.* For employees to earn a maximum of 130%, five out of five milestones must be achieved. The Strategy Scorecard makes up 10% of the total Senior Leader award.

Financial metrics: The Utility EPS and O&M CPC metrics work a little differently due to the various performance levels that can be met. Depending on the Company's level of performance under each metric, employees may earn more or less than 100% of the award percentage related to each financial metric. Increasing levels of performance are established between threshold and maximum by using a sliding scale. For employees to receive at least 50% of their award percentage related to the metric, the Company must achieve or surpass the minimum or threshold level of performance. The better the Company performs, the more employees may earn. For employees to receive 100% of their award percentage related to a financial metric, the Company must achieve the level of performance selected for target. If the Company performs above target level, employees may earn up to a maximum of 175% (rounded up) for Utility EPS, and

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147.5% for officers / 164% for non-officers for O&M CPC. Performance below threshold results in no award payment for the related metric.

For ease of communication and display purposes performance levels may be rounded using the accounting rules such as to the nearest whole number or up to two decimals. To calculate actual payments and to ensure no overpayments occur the performance levels within the sliding scale actually extend out six (6) decimal places (ex. 166.666666%) for Utility EPS and four (4) decimals (ex. 149.9430%) for Cost per Customer. See Calculation of Awards section for more details on how payments are calculated.

**Establish Targets:** The Compensation and Organization Committee of the Board (Committee) in conjunction with management reviews and reestablishes the targets for each measurement on an annual basis. The computations for this Plan are described below:

*Utility EPS:* To determine the Utility EPS goal for the Plan, the Committee, in conjunction with the Finance Committee of the Board and management, consider and set the EPS target range. The earnings guidance for the Utility EPS **excludes** the earnings impact associated with changes in the Energy Recovery Mechanism (ERM). The target in the Plan is Diluted Earnings per Share and includes executive incentive payout/accrual-pro-forma and net of taxes. Occasionally, adjustments to actual results may be deemed necessary. Since the portion of the incentive related to EPS indirectly benefits the customer, it is charged below the line. The Company's original 2025 guidance for Utility EPS is shown below in the incentive targets table.

*O&M CPC:* For this measurement, the Company uses the total budget for O&M expense (numerator) and customer count (denominator).

*Numerator:* The numerator of the formula is derived from the Company's total budget for O&M expense. Certain items are excluded from the total O&M budget such as Pacesetters and certain accounting adjustments. For each performance level, the Company estimates the potential payout for the incentive which includes payroll taxes and subtracts the result from the total O&M budget. The estimation is based on budgeted labor costs, employee job levels and the corresponding individual target award opportunities.

To establish the performance levels between threshold and target, the Company assumes a 1:1 ratio between O&M spend and threshold to target. Cost sharing occurs once we exceed target at 100%. Performance levels between target and maximum assumes a 2:1 ratio between O&M spend and target to maximum.

*Denominator:* The target uses a net customer count of 805,233. This number is based upon the count at the beginning of the performance year and will not change in the calculation for the entire plan year.

*Strategy Scorecard:* The purpose of this metric is to align senior leaders with Avista's strategic goals. In this plan, outlined objectives and key results (OKRs) will ensure alignment with the organization's strategic goals and drive performance in these areas. The target is set at achieving four out of the five specific milestones, or 80%

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achievement, to meet this metric. The measurable action is listed in the yearly plan document.

*Customer Satisfaction:* For this measure, the Company uses the ratings from question three of the <u>Voice of the Customer</u> survey which measures the customer's *Overall Satisfaction* with the service they received in a recent contact through the Avista contact center and/or service center. The *Overall Satisfaction* question from surveys such as this is widely used in the industry for external reporting purposes. Rather than using the standard "satisfied" rating, which is typically used in the industry, the Company uses the average of the combined "*satisfied"* and "*very satisfied"* ratings. By combining these two ratings the target is more difficult to achieve and more emphasis is placed on serving the customer. In this Plan, the target is set at **90%**very satisfied/satisfied for the customer's Overall Satisfaction rating.

*Reliability:* This index combines *Customer Average Interruption Duration Index (CAIDI), System Average Interruption Frequency Index (SAIFI) and Customer Experiencing Multiple Interruptions (CEMI*<sup>3</sup>*)*. CEMI<sup>3</sup> measures the percentage of customers that experience more than three sustained outages in the year. The Company chose this level of outages over others because industry data received from JD Power's customer service surveys indicate that customers are more apt to be dissatisfied after three outages. Providing safe and reliable energy to our customers is the backbone of our business, therefore, it makes good sense to focus on service levels for our customers. By focusing on these measurements, it enables the Company to direct our resources appropriately and efficiently to contain costs and plan for future infrastructure upgrades that will benefit the customer.

To determine the target for the Reliability portion of the Plan, the Company sets a separate target for each metric, weighs them equally and combines them into one metric (see the formula below). In this Plan the target is set at **1.00**.

*Index = <u>CAIDI Target / CAIDI Actual</u> + <u>SAIFI Target / SAIFI Actual</u> + <u>CEMI</u>*<sup>3</sup>*<u>Target / CEMI</u>*<sup>3</sup>*<u>Actual</u>* 

*3 3 3*

The formula used to set the target for each metric is described below:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Customer Average Interruption Duration Index (CAIDI): *outage duration multiplied by the number of customers affected for all sustained outages (> 5 minutes), divided by the number of customers which had sustained outages*. Per industry practice Major Event Days (MEDs) are excluded from this metric. In this Plan the Company uses a 5-year average with a standard deviation of 0.72 (76% probability) to set the target which is 2 hours and 32 minutes restoration time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•System Average Interruption Frequency Index (SAIFI): *the number of customers which had sustained outages (> 5 minutes), divided by the number of customers served.* Per industry practice MEDs are excluded from this metric. In this Plan the Company uses a 5-year average and a standard deviation of 0.72 (76% probability) to set the target which is 1.07 outages per customer.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Customers Experiencing Multiple Sustained Interruptions more than 3 (CEMI<sup>3</sup>): *the total number of customers that experience more than 3 sustained outages per year, divided by total number of customers served.* To be consistent with the other two indices, MEDs are excluded from this

------

metric. In this Plan the Company uses a 5-year average with a standard deviation of 0.72 (76% probability) to set the target at 6.32% of our customers.

*Response Time:* This metric measures how quickly the Company responds to natural gas system emergency calls. The Company tracks the average response time between the receipt of the emergency call to the time our crew or service worker arrives on-site, assesses the situation, and *reports back* to dispatch. The Company wants crews and/or the service worker to respond within the targeted response time goal. To be consistent with other service metrics, response times in excess of 24 hours are excluded from the metric. A "natural gas system emergency" is defined as an event when there is a natural gas explosion or fire, fire in the vicinity of natural gas facilities, police or fire are standing by, leads identified in the field as "Grade 1", high or low gas pressure problems identified by alarms or customer calls, natural gas system emergency alarms, carbon monoxide calls, natural gas odor calls, runaway furnace calls, or delayed ignition calls. In this Plan the Company aligns the response time with the Service Reliability Target negotiated with the Washington Utility Commission and set the target goal to respond within an average of, and not to exceed, **55 minutes**.

**Incentive Targets for 2025:**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Utility Earnings Per Share** | **O&M Cost per Customer** | **Customer Satisfaction Rating** | **Reliability Index** | **Average Response Time Minutes** | **Strategy Scorecard** |
| Officers % of Total Opportunity | 50% | 20% | 8% | 8% | 4% | 10% |
| Non-Officers\* % of Total Opportunity | 20% | 50% | 8% | 8% | 4% | 10% |
| Threshold <br>EPS 50% <br>O&M CPC 50%<br>Strategy 70% | $2.61 | $508.97 |  |  |  | 3/5 milestones achieved |
| **Target 100%** | **$2.74** | **$502.24** | **90%** | **1.00** | **<55 Min** | **4/5 milestones achieved** |
| Maximum 175% | $2.84 |  |  |  |  |  |
| Maximum <br>Officer 147.5%<br>Non-Officer - 164% |  | $488.78 |  |  |  |  |
| Maximum 130% |  |  |  |  |  | 5/5 milestones achieved |

---

\*Director and senior legal counsel roles

Values are rounded for display or communication purposes only

**Individual Target Award Opportunities:** During the February Board meeting, the Committee and the Chief Executive Officer (CEO) jointly review and approve the individual target award opportunities for the participants of the Plan. Each eligible employee has an incentive target award opportunity expressed as

------

a percentage of their base salary. Target opportunities range from 20% to 100% of base salary and are assigned based on position. Actual award payments are calculated based on the employee's target award opportunity in effect as of the last day of the plan year and year-end regular earnings unless otherwise noted in the Plan document (see provisions under *Exceptions to Eligibility and Circumstances for Proration* section).

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Individual Target Award Opportunity**<br>**% of Base Pay by Position Type** | **Individual Target Award Opportunity**<br>**% of Base Pay by Position Type** | **Individual Target Award Opportunity**<br>**% of Base Pay by Position Type** | **Individual Target Award Opportunity**<br>**% of Base Pay by Position Type** | **Individual Target Award Opportunity**<br>**% of Base Pay by Position Type** | **Individual Target Award Opportunity**<br>**% of Base Pay by Position Type** |
| CEO | EVP | Senior VP | VP | Past Officer PT Advisor | Director & Senior Legal Counsel |
| 100% | 65% | 60% | 40% | 40% | 20% |

---

**Distribution of Awards:** If earned, incentive award payments will be distributed as soon as feasible usually in March after the filing of the Company's Form 10-K with the SEC, and Compensation Committee of the Board certifies and approves the achievement of the performance goals.

**Calculation of Awards:** In most instances actual amounts will be calculated using the participant's regular year-end earnings (as defined in the provisions section of the Plan), individual target award opportunity and employment status in effect as of the last working day of the Plan year. See the section *Exceptions to Eligibility and Circumstances for Proration* for definitions and exceptions.

For purposes of calculating the actual payments and ensure no overpayments or underpayments occur, the final performance results will be extended out six decimal places (ex. 166.666666%) for Utility EPS and four decimals (ex. 149.9323%) for Cost per Customer and rounded based on accounting rules. The following table shows how an overpayment can occur if the final performance level is rounded to two decimals and used to calculate the final payment.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | <br>**Metric** | **Target Opportunity** | **Metric Allocation** | **Maximum Results** | **Maximum % Allowed** | <br>**Maximum Dollar Value** |
| Maximum | Net Income | $152248.39 | 60% | 166.666666% | 100.000000% | $152248.39 |
| Over Payment | Net Income | $152248.39 | 60% | 166.670000% | **100.002000%** | **$152251.43** |

---

Since the non-financial metrics have only two performance levels, 0% or 100%, rounding the final results is not an issue.

Once the total incentive amount is calculated, all cash payments will be rounded to the nearest penny based on accounting rules.

**Communication**: When communicating the results of the financial metrics and the payout, the Company will round results to the nearest 100<sup>th</sup> percent based on accounting rules. For example, if the O&M CPC result is 148.6468%, the Company will communicate the results using 148.65%.

When communicating the results of the non-financial metrics, the Company will round results to the nearest whole number or, in the case of reliability, out two decimal points based on accounting rules. For example, customer satisfaction would be rounded to 93% from 92.8% and reliability would be 1.23 from 1.232.

------

**Recoupment Policy**: All incentive awards earned by officers under this Plan are subject to the Recoupment Policies adopted by the Company's Board of Directors as amended from time to time ("Recoupment Policies"). If a participant becomes subject to the Recoupment Policies any award may be forfeited in whole or in part and all or part of any distribution payable to a participant or his or her beneficiary under this Plan may be recovered by the Company pursuant to the Recoupment Policies.

**Administration of Plan:** The Committee is responsible for administering the Plan and may delegate specific administrative tasks to corporate staff, as appropriate. The Committee has the authority to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Terminate, amend, or modify this Plan in whole or in part for any reason at any time without prior notice to participants

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Modify or adjust financial targets due to extraordinary occurrences and/or significant reorganizations

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Grant discretionary awards up to 15% of the individual officer target award opportunity

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•May pay incentive amounts in excess of 100% (up to 150%) of an individual's target opportunity in the form of non-cash equivalents

Participation in this Plan should in no way be construed as a contract or promise of employment and/or compensation.

**Exceptions to Eligibility and Circumstances for Proration:**

**Pay Periods:** There are 26 pay periods and pay dates during the Plan year. A pay period (pp) is made up of two pay weeks. Each pay week typically starts 12:00am Monday and ends 11:59pm Sunday. Employees are paid on the pay date on the following Friday, after the end of the pay period. The first pay period of the year consists of the date range 12/16/2024 – 12/29/2024 which is paid on pay date 1/3/2025. Changes effective during this pay period will count towards the 2025 plan since the earnings and pay date are part of 2025. Changes effective during the dates 12/15/2025 – 12/28/2025 are *not included* in the 2025 Plan because the earnings and pay date are part of 2026.

**Pay Period Schedule for 2025:**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Pay Period** | **Date Range** | **Pay Date** | **Pay Period** | **Date Range** | **Pay Date** |
| 1 | 12/16/24 - 12/29/24 | 1/3/2025 | 14 | 6/16 - 6/29 | 7/4 |
| 2 | 12/30 - 1/12 | 1/17 | 15 | 6/30 - 7/13 | 7/18 |
| 3 | 1/13 - 1/26 | 1/31 | 16 | 7/14 - 7/27 | 8/1 |
| 4 | 1/27 - 2/09 | 2/14 | 17 | 7/28 - 8/10 | 8/15 |
| 5 | 2/10 - 2/23 | 2/28 | 18 | 8/11 - 8/24 | 8/29 |
| 6 | 2/24 - 3/09 | 3/14 | 19 | 8/25 - 9/07 | 9/12 |
| 7 | 3/10 - 3/23 | 3/28 | 20 | 9/08 - 9/21 | 9/26 |
| 8 | 3/24 - 4/06 | 4/11 | 21 | 9/22 - 10/05 | 10/10 |
| 9 | 4/07 - 4/20 | 4/25 | 22 | 10/06 - 10/19 | 10/24 |
| 10 | 4/21 - 5/04 | 5/9 | 23 | 10/20 - 11/02 | 11/7 |
| 11 | 5/05 - 5/18 | 5/23 | 24 | 11/03 - 11/16 | 11/21 |
| 12 | 5/19 - 6/01 | 6/6 | 25 | 11/17 - 11/30 | 12/5 |
| 13 | 6/02 - 6/15 | 6/20 | 26 | 12/01 - 12/14 | 12/19 |

---

**Proration:** Prorating an employee's award is based on the number of pay dates associated with a change. Each change of status (COS) has an effective date. The date determines which pay period and pay date is to be counted as part of the proration.

Use the **Pay Period Schedule** above to count the pay dates. Using the effective date from the COS, search through the date ranges to find the pay period and pay date associated with it. Count the pay

------

dates to the end of the Plan year or to the next COS effective date whichever comes first. The employee receives 1 pay period credit for each pay date counted.

**Regular Earnings:** Regular earnings will be used in calculating the final awards. The earnings to be used and their associated codes are as follows:

---

| | |
|:---|:---|
| **Earnings Type** | **Earnings Codes** |
| **Regular** | 01, 01R, 02, 32, 32B, 58 |
| **1.5x Overtime** | 04, 04R, 21, 23, 71, 76, 78, 83 |
| **Light Duty** | 29 |
| **Swing Shift** | 31 |
| **Alternative/dual** | 20 |
| **Relief Pay** | 08 |
| **Retro Pay** | 70, 70A, 70B |
| **One Leave/PTO/Paid Leave** | 10, 14, 14B, 15, 16, 16PFM, 16 PLO, 34B, 34C, 34D, 61, 73 |
| **Short-term Disability 100% & 60%** | 18, 80 |
| **Workers Compensation** | 19, 19A, 85, 85C, 86, 87, 88 |
| **Holiday** | 25, 25P, 26, 63E, 63F, 75 |
| **Jury Duty** | 35 |
| **Military Pay** | 36, 36C |

---

**New Hires:** Employees hired on or after October 1<sup>st</sup> will not be eligible for an award under this Plan. Employees hired prior to October 1<sup>st</sup> will have their awards calculated based on the provisions detailed above.

**Leave of Absence:** Eligible employees on approved unpaid leave of absence must have at least 6 full pay periods of active service during the Plan year to receive an award. Awards will be calculated based on the provisions detailed above. *Short-term disability leave does not affect an eligible employee's award and is excluded from this provision.*

**Resignation/Termination:** Any eligible employee who resigns or is terminated for reasons other than retirement, disability, or death prior to the last day of the plan year will not be eligible to receive an award under this Plan. Eligible employees who terminate after the Plan year may receive an award at the time of distribution unless reason for termination is due to poor performance or for cause, see section on Discipline or Poor Performance below.

**Death, Long-term Disability & Retirement:** In the case of death, total disability (as defined under the Company's Long-term Disability Plan) or retirement as a participant in Avista's pension or 401(k) plan (employees must be age 55 and have 15 years of service to qualify), an eligible employee or estate must have at least 6 pay periods of active service within the Plan year to be eligible to receive an award. Awards will be calculated based on the provisions detailed above.

**Discipline or Poor Performance:** Employees who receive a **fails to meet** performance rating for the Plan year or a **Last Chance Agreement** under the Company's formal discipline program and effective as of the last working day of the plan year are not eligible to receive an award under this Plan. Any employee who is terminated for poor performance or for cause by the Company **after** the last day of the plan year and up to the time of distribution, will not be eligible to receive an award under this Plan.

------

**Transfers from Subsidiaries to Corp/Utilities:** Eligible employees who transfer from a subsidiary will be treated as a new hire to the Company and all Plan criteria apply as is. Prorated awards are at the discretion of the Committee and CEO.

**Senior Leader Promotions**: If an officer or senior leader is promoted to a new position type (e.g. VP to SVP or director to VP), the officer's individual award opportunity will be prorated based upon earnings before and after date of promotion, using our **Proration** methodology noted above.

**Other Company Short-term Incentive Plans:** Employees can only participate under one formal incentive plan at a time. If the employee becomes eligible for a different plan during the year, their earnings will be prorated between the appropriate plan before and after the promotion. For example, if an employee participates in the employee plan, and is promoted to a senior leader on June 1<sup>st</sup>, their earnings and incentive opportunity will be calculated based upon the employee plan through pay period 12. The remainder of their earnings in periods 13-26 will be calculated based upon the senior leader plan and incentive opportunity of that plan, using the **Proration** methodology noted above. Similarly, if a senior leader demotes to a position covered by the Employee plan during the year, their earnings will be prorated between the appropriate plans before and after the transfer following the above methodology.

------

## Exhibit 10.26

**Exhibit 10.26**

**Avista Corporation**

**Non-Employee Director Compensation - 2025**

The Board regularly reviews director compensation with the assistance of Meridian Compensation Partners (the same consultant used for executive compensation) to determine whether it is appropriate and competitive in light of market circumstances and prevailing best practices for corporate governance for the energy/utility industry. The Board targets overall director compensation to the median of the same peer group used to review executive compensation. As a result of this review process, the annual retainer for directors was increased from $235,000 to $250,000 effective September 1, 2025. The elements of director compensation reflect the Board's view that compensation to the independent directors should consist of an appropriate mix of cash and stock. The cash portion of the retainer is paid quarterly, and the stock portion is paid annually (as soon as practicable following the Annual Meeting). Employee directors are not compensated for their Board service.

**Elements of Director Compensation** 

---

| | | |
|:---|:---|:---|
| **Pay Element** | &nbsp;&nbsp;**Compensation** | &nbsp;&nbsp;**Compensation** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Annual Retainer (cash and stock) | Board Members:<br>(Directors receive an annual retainer of $250,000, with $145,000 automatically paid in stock. Directors have the option of taking the balance in cash, stock or a combination of both cash and stock.) | &nbsp;&nbsp;**$250000** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Committee Chair Retainers (Cash) | Audit Committee: | &nbsp;&nbsp;**$25000**  |
|  | Compensation Committee: | &nbsp;&nbsp;**$20000**  |
|  | Environmental Committee: | &nbsp;&nbsp;**$15000**  |
|  | Finance Committee: | &nbsp;&nbsp;**$15000**  |
|  | Governance Committee: | &nbsp;&nbsp;**$15000**  |
|  | Vice Chair: | &nbsp;&nbsp;**$30000**  |
|  | Non-Executive Chairman: | &nbsp;&nbsp;**$110000**  |

---

Each director is entitled to reimbursement of reasonable out-of-pocket expenses incurred in connection with meetings of the Board or its committees and related activities, including third party director education courses and materials. These expenses include travel to and from the meetings, as well as any expenses they incur while attending the meetings. The Company does not provide perquisites or other personal benefits to its Board members.

**Director Stock Ownership Policy** 

The Company has a minimum stock ownership expectation for all Board members. Outside directors are expected to achieve a minimum investment of five times the minimum stock portion of their retainer and retain at least that level of investment while a Board member.

The ownership expectation illustrates the Board's philosophy of the importance of stock ownership for directors to further strengthen the commonality of interest between the Board and shareholders. The Governance Committee annually reviews director holdings to determine whether they meet ownership expectations.

There were no annual stock option grants or non-stock incentive plan compensation payments to directors for services in 2025 and none are currently contemplated under the current compensation structure. The Company also does not provide a retirement plan or deferred compensation plan to its directors.

------

## Ex-21

**Exhibit 21**

AVISTA CORPORATION

**SUBSIDIARIES OF REGISTRANT**

---

| | |
|:---|:---|
| Subsidiary | State or Country<br>of Incorporation |
| Avista Capital, Inc. | Washington |
| Avista Development, Inc. | Washington |
| Avista Edge, Inc. | Washington |
| Avista Northwest Resources, LLC | Washington |
| Pentzer Corporation | Washington |
| Pentzer Venture Holding II, Inc. | Washington |
| Avista Capital II | Delaware |
| Alaska Energy and Resources Company | Alaska |
| Alaska Electric Light and Power Company | Alaska |
| AJT Mining Properties, Inc. | Alaska |
| Snettisham Electric Company | Alaska |
| Salix, Inc. | Washington |

---

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## Ex-23

**Exhibit 23**

**CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM** 

We consent to the incorporation by reference in Registration Statement Nos. 333-33790, 333-179042 and 333-208986 on Form S-8 and in Registration Statement No. 333-287023 on Form S-3 of our reports dated February 24, 2026, relating to the financial statements of Avista Corporation, and the effectiveness of Avista Corporation's internal control over financial reporting, appearing in this Annual Report on Form 10-K of Avista Corporation for the year ended December 31, 2025.

/s/ DELOITTE & TOUCHE LLP

Portland, Oregon

February 24, 2026

------

## Exhibit 31.1

**Exhibit 31.1**

**<u>CERTIFICATION</u>**

I, Heather L. Rosentrater, certify that:

1. I have reviewed this report on Form 10-K of Avista Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | | |
|:---|:---|:---|
| Date: | February 24, 2026 | /s/ Heather L. Rosentrater |
|  |  | Heather L. Rosentrater |
|  |  | President and Chief Executive Officer |
|  |  | (Principal Executive Officer) |

---

------

## Exhibit 31.2

**Exhibit 31.2**

**<u>CERTIFICATION</u>**

I, Kevin J. Christie, certify that:

1. I have reviewed this report on Form 10-K of Avista Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | | |
|:---|:---|:---|
| Date: | February 24, 2026 | /s/ Kevin J. Christie |
|  |  | Kevin J. Christie |
|  |  | Senior Vice President, Chief Financial Officer |
|  |  | Treasurer and Regulatory Affairs Officer |
|  |  | (Principal Financial Officer) |

---

------

## Ex-32

**Exhibit 32**

**AVISTA CORPORATION**

__________________________________________________________________________________________

**CERTIFICATION OF CORPORATE OFFICERS**

(Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the

Sarbanes-Oxley Act of 2002)

__________________________________________________________________________________________

Each of the undersigned, Heather L. Rosentrater, President and Chief Executive Officer of Avista Corporation (the "Company"), and Kevin J. Christie, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company's Annual Report on Form 10-K for the year ended December 31, 2025 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2026

---

| |
|:---|
| /s/ Heather L. Rosentrater |
| Heather L. Rosentrater |
| President and Chief Executive Officer |
| /s/ Kevin J. Christie |
| Kevin J. Christie |
| Senior Vice President, Chief Financial Officer |
| Treasurer and Regulatory Affairs Officer |

---

------