10-Q: Avista Q2 2025 Earnings: Utility Gains Offset by Investment Losses

Avista Corporation reports a decline in Q2 2025 net income due to investment losses, despite strong utility segment performance driven by rate cases and customer growth.

Summary

• Net income for the three months ended June 30, 2025, was $14 million, a decrease from $23 million in the same period of 2024.
• Net income for the six months ended June 30, 2025, was $93 million, a slight decrease from $94 million in the same period of 2024.
• Avista Utilities, the regulated segment, reported net income of $23 million for Q2 2025 (down from $24 million in Q2 2024) and $101 million for H1 2025 (up from $91 million in H1 2024).
• The 'Other non-reportable segment' (non-utility businesses) incurred a net loss of $10 million in Q2 2025 (compared to a $2 million loss in Q2 2024) and $12 million in H1 2025 (compared to a $2 million loss in H1 2024), primarily due to lower valuations of certain investments.
• Total operating revenues increased to $411 million in Q2 2025 from $402 million in Q2 2024, and to $1,028 million in H1 2025 from $1,011 million in H1 2024.
• Electric utility margin increased by $17 million in Q2 2025 and $54 million in H1 2025, driven by general rate cases and customer/load growth.
• Natural gas utility margin increased by $6 million in Q2 2025 and $15 million in H1 2025, also due to general rate cases.
• Avista Utilities' capital expenditures are projected to be approximately $525 million in 2025, $575 million in 2026, and $600 million in 2027.
• The company contributed $7 million to its pension plan in H1 2025 and expects total contributions of $10 million for the full year 2025.

Sentiment

Score: 5

Explanation: While the core regulated utility business shows positive trends due to rate case approvals and customer growth, the overall net income decline driven by significant losses in the non-regulated investment portfolio, coupled with ongoing regulatory and legal uncertainties (e.g., Colstrip tariff subject to refund, building code challenges), presents a mixed picture. The successful refinancing and strong liquidity are positive, but the drag from 'other businesses' and the inherent regulatory lag temper enthusiasm.

Positives

• Avista Utilities' net income increased for the six months ended June 30, 2025, driven by general rate cases and customer and load growth.
• Electric utility margin increased by $17 million in Q2 2025 and $54 million in H1 2025 due to general rate cases and customer growth.
• Natural gas utility margin increased by $6 million in Q2 2025 and $15 million in H1 2025 due to general rate cases.
• Successfully refinanced short-term debt into long-term debt in July 2025, including $120 million of 6.18% first mortgage bonds due 2055 for Avista Corp. and a $20 million term loan for AEL&P.
• Maintained strong liquidity with $106 million available under Avista Corp. committed line of credit, $42 million under its letter of credit facility, and $9 million under the AEL&P committed line of credit as of June 30, 2025.
• Complied with all financing agreement covenants, including debt-to-capitalization ratios (54.6% for Avista Corp. and 49.3% for AEL&P, both below their respective limits).
• Settled all claims in the Labor Day 2020 Windstorm/Babb Road Fire lawsuits for $27 million, with the company's $21 million portion offset by expected insurance proceeds received in July 2025.
• Settled all claims in the Boyds Fire lawsuits for $3 million, with the company expecting no responsibility for the settlements.
• Washington general rate cases approved increases in annual electric base revenues by $12 million (2.0%) effective January 1, 2025, and $44 million (7.5%) for Rate Year 2.
• Washington general rate cases approved increases in annual natural gas base revenues by $14 million (11.2%) effective January 1, 2025, and $4 million (2.8%) for Rate Year 2.
• Reached an all-party settlement agreement for Idaho general rate cases, which, if approved, would increase annual base electric revenues by $20 million (6.3%) effective September 2025, and $15 million (4.5%) effective September 2026.
• The Idaho settlement also proposes to increase annual base natural gas revenues by $5 million (9.2%) effective September 2025, and decrease by $0.2 million (0.4%) effective September 2026.
• Oregon general rate case approved, increasing annual base revenues by $4 million (5.0%) effective September 2025.
• The Washington Utilities and Transportation Commission (WUTC) continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.

Negatives

• Overall net income decreased for the three months ended June 30, 2025 ($14 million vs $23 million in 2024) and slightly for the six months ended June 30, 2025 ($93 million vs $94 million in 2024).
• The 'Other businesses' segment experienced significant net investment losses, primarily related to clean technology investments, negatively impacting overall net income ($10 million loss in Q2 2025 vs $2 million loss in Q2 2024; $12 million loss in H1 2025 vs $2 million loss in H1 2024).
• Dilution of ownership percentage in some investments due to new share issuances contributed to investment losses.
• Natural gas revenues decreased by $10 million in Q2 2025 due to decreased retail rates (Purchased Gas Adjustment) and decreased sales volumes (attributed to warmer weather).
• Electric decoupling revenue decreased by $11 million in Q2 2025 and $20 million in H1 2025 due to decreased amortizations of prior year rebate balances and current year rebate deferrals.
• Utility operating expenses increased due to higher employee salaries and benefits costs, as well as thermal generation costs.
• Income tax expense increased in H1 2025 primarily due to a decrease in tax customer credits and increased pre-tax net income.
• The WUTC did not approve the request to modify the Energy Recovery Mechanism (ERM), and actual net power supply costs are expected to exceed the level included in base rates for 2025 and 2026.
• Washington Colstrip tariff rates for 2025 ($43 million requested) were allowed to go into effect but are subject to refund, with adjudication set for October 2025.
• New Oregon law (House Bill 3179) extends the rate suspension period, prohibits residential rate increases between November 1 and March 31, and restricts new rates from taking effect within 18 months of the prior rate effective date if Return on Equity is at issue.
• Washington State Building Codes requiring all-electric space heating for most new commercial and large multifamily buildings, and electricity as the primary heat source for new residential buildings, could adversely impact the natural gas business.
• Uncertainty exists regarding the outcome of legal challenges to Washington State Building Codes and Initiative 2066.
• Potential for increased capital and operating expenses due to tariffs on imported goods and supply chain disruptions.
• Regulatory lag is inherent in utility ratemaking, causing delays between cost increases/investments and rate recovery.
• Ongoing negotiations for a new collective bargaining agreement with the International Brotherhood of Electrical Workers (IBEW), representing approximately 90% of Avista Utilities' bargaining unit employees, which expired in March 2025; a strike could disrupt operations if an agreement is not reached.
• The Orofino Fire incident (August 2023), caused by third-party damage to natural gas infrastructure, resulted in a fire that destroyed one residence and caused minor injuries; lawsuits are pending, and the company is unable to estimate potential loss.
• A complaint was filed with the Federal Energy Regulatory Commission (FERC) by Consumers for Independent Regional Transmission Planning, alleging that the local transmission planning process is not efficient or cost-effective for the interconnected grid and customers.

Risks

• State and federal regulatory decisions or related judicial decisions that affect the ability to recover costs and earn a reasonable return, including disallowance or delay in recovery of capital investments, operating costs, commodity costs, ordering of refunds, and discretion over allowed return on investment.
• Loss of regulatory accounting treatment, which could require the write-off of regulatory assets and the loss of regulatory deferral and recovery mechanisms.
• Weather conditions affecting energy demand and electric generating capability, including impacts on hydroelectric resources, wind-generated power, and customer demand.
• Wildfires ignited, or allegedly ignited, by equipment or facilities could cause significant loss of life and property or result in liability for suppression costs and/or damages.
• Severe weather or natural disasters (avalanches, wind storms, wildfires, earthquakes, floods, extreme temperature events, snow and ice storms) that could disrupt energy generation, transmission, and distribution, and impact fuel, materials, equipment, supplies, and support services availability and costs.
• Political unrest and/or conflicts between foreign nation-states, which could disrupt the global, national, and local economy, increase operating and capital costs, impact energy commodity prices, affect access to energy resources, create supply chain disruptions, and increase cyber and physical security risks.
• Explosions, fires, accidents, mechanical breakdowns, or other incidents that could impair assets and disrupt operations of generation facilities, transmission, and electric and natural gas distribution systems.
• Interruptions in the delivery of natural gas by suppliers, including physical problems with pipelines.
• Blackouts or disruptions of interconnected transmission systems (the regional power grid).
• Terrorist attacks, cyberattacks, or other malicious acts that could disrupt or damage utility assets or the economy, including ransomware or vandalism affecting information technology systems.
• Pandemics disrupting business, customer demand, creditworthiness, increasing costs, causing workforce shortages, vaccine mandate losses, capital project delays, supply chain disruptions, and capital market volatility.
• Workforce issues, including changes in collective bargaining unit agreements, strikes, work stoppages, loss of key executives, and ability to recruit and retain employees.
• Changes in the availability and price of purchased power, fuel, natural gas, and transmission capacity.
• Increasing costs of insurance, more restrictive coverage terms, and the ability to obtain insurance.
• Delays or changes in construction costs, and/or the ability to obtain required permits and materials for facilities.
• Increasing health care costs and cost of health insurance provided to employees and retirees.
• Increasing operating costs, including effects of inflationary pressures.
• Third-party construction within rights of way or placement of fuel containers near equipment.
• Loss of key suppliers for materials or services or other disruptions to the supply chain.
• Adverse impacts to Alaska Electric Light and Power Company (AEL&P) from an extended outage of its hydroelectric generating resources or their inability to deliver energy due to lack of interconnectivity to other electrical grids and the availability or cost of replacement power (diesel).
• Changing river or reservoir regulation or operations at hydroelectric facilities not owned by the company.
• 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.
• Change in the use, availability, or abundancy of water resources and/or rights needed for operation of hydroelectric facilities, including impacts from climate change.
• Changes in long-term climate and weather could materially affect customer demand, streamflows for hydroelectric generation, and costs of generation, transmission, and distribution.
• Cyberattacks on operating systems used in electric generation, transmission, and distribution facilities, and natural gas distribution facilities, or on such systems of interconnected energy companies.
• Cyberattacks on administrative systems (customer billing, service, accounting, compliance) or vendor systems, resulting in business disruption, private information release, liabilities, and costs.
• Changes in technologies, potentially making current technology obsolete or introducing new cybersecurity risks and other risks inherent in new developmental technologies, including generative artificial intelligence.
• Changes in the use, perception, or regulation of generative artificial intelligence technologies, limiting utilization, increasing regulatory scrutiny, creating intellectual property uncertainty, or damaging business/reputation/financial results.
• Changes in costs that impede the ability to implement new information technology systems or to operate and maintain current production technology.
• Insufficient technology skills, leading to inability to develop, modify, or maintain information systems.
• Growth or decline of the customer base due to new uses for services or decline in existing services, including the effect of distributed generation at customer sites.
• Potential effects of negative publicity regarding business practices, which could hurt reputation and result in litigation or a decline in common stock price.
• Changes in strategic business plans, including entry into new businesses and/or exit from existing businesses.
• Wholesale and retail competition, including alternative energy sources, customer-owned power resource technologies, and alternative energy suppliers.
• Non-regulated activities may increase earnings volatility and result in investment losses.
• The risk of municipalization or other forms of service territory reduction.
• Changes in environmental laws, regulations, decisions, and policies, including regulatory responses to climate change, fish restoration efforts, and more stringent requirements related to air/water quality and waste management.
• Potential effects of initiatives, legislation, or administrative rulemaking at federal, state, or local levels, including impacts on generating resources, prohibitions on services, or restrictions on greenhouse gas emissions.
• Political pressures or regulatory practices that could constrain or place additional cost burdens on distribution systems through accelerated adoption of distributed generation or electric-powered transportation, or on energy supply sources.
• Failure to identify changes in legislation, taxation, and regulatory issues that could be detrimental or beneficial to the overall business.
• Policy and/or legislative changes in various regulated areas, including environmental regulation, healthcare regulations, and import/export regulations.
• Increasing costs due to potential tariffs applied to energy commodities and/or equipment and materials.
• Ability to obtain financing through debt and/or equity securities and access to funds held with financial institutions, affected by credit ratings, interest rates, capital market conditions, and global economic conditions.
• Changes in interest rates that affect borrowing costs, variable interest rate borrowing, and recovery of interest costs through retail rates.
• Volatility in energy commodity markets that affect the ability to effectively hedge energy commodity risks, including cash flow impacts and collateral requirements.
• Volatility in the carbon emissions allowances market that could result in increased compliance costs.
• Changes in actuarial assumptions, interest rates, and the actual return on plan assets for pension and other postretirement benefit plans, affecting future funding obligations, expense, and liabilities.
• The outcome of legal proceedings and other contingencies.
• Economic conditions in service areas, including effects on customer demand for utility services.
• National economic conditions may affect the valuation of unregulated portfolio companies.
• 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.
• Industry and geographic concentrations which could increase exposure to credit risks due to counterparties, suppliers, and customers being similarly affected by changing conditions.
• Deterioration in the creditworthiness of customers.
• Activist shareholders may result in additional costs and resources required in response to activist actions.
• Volatility and illiquidity in wholesale energy markets, including exchanges, availability of willing buyers and sellers, changes in wholesale energy prices, collateral required, and credit risk from transactions.
• Default or nonperformance on the part of parties from whom capacity or energy is purchased and/or sold.
• Potential environmental regulations or lawsuits affecting the ability to utilize or resulting in the obsolescence of power supply resources.
• Explosions, fires, accidents, pipeline ruptures, or other incidents that could limit energy supply to facilities or surrounding territory, resulting in commodity shortages and increased replacement costs.
• The fair values of equity investments fluctuate, directly affecting net income, and there is no assurance these investments will ultimately be successful. The risks faced by these businesses differ from utility operations.

Future Outlook

The company expects to continue filing for rate adjustments to recover operating costs and capital investments and seek reasonable returns. The 2025 electric Integrated Resource Plan (IRP) outlines a preferred resource strategy to add approximately 490 MW of generating capacity by 2030 and a total of 950 MW through 2035, with a request for proposal issued for up to 415-425 MW. Expanded transmission infrastructure is also expected to provide access to additional resources and improve reliability. Hydro generation for 2025 is anticipated to be approximately 85% of normal. The 2025 Natural Gas IRP focuses on greenhouse gas emissions compliance, assuming Washington building codes remain in effect, and utilizing renewable natural gas resources, energy efficiency investments, and carbon capture in Oregon, while Idaho's strategy continues to utilize natural gas from existing access to supply basins and storage. The company does not expect the U.S. reconciliation bill to materially impact its financial results or annual effective tax rate for 2025.

Management Comments

• Net income for the three and six months ended June 30, 2025 decreased compared to the three and six months ended June 30, 2024, primarily due to losses at our other businesses associated with lower valuations of certain investments in our portfolio.
• At Avista Utilities, the effects of our general rate cases have increased earnings in the first half of the year, partially offset by increased operating costs, depreciation and amortization expense and income tax expense.
• We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings.
• 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.
• With our existing credit facilities and the expected issuances of common stock and long-term debt within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.
• 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.
• We believe any liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows.

Industry Context

The filing highlights the ongoing challenges and opportunities in the utility sector, including the transition to clean energy (e.g., Clean Energy Transformation Act in Washington, Clean Energy Progress Program in Oregon), the impact of climate change on operations (e.g., wildfires, weather patterns affecting hydroelectric resources), and the increasing regulatory scrutiny on emissions and infrastructure development. The company's focus on integrated resource planning (IRP) and securing new generating capacity reflects the industry-wide need to ensure resource adequacy amidst evolving energy policies and demand. The legal challenges to building codes and the FERC complaint on transmission planning illustrate the complex regulatory and legal environment utilities operate within. The mention of tariffs on imports and their potential impact on costs reflects broader global economic pressures affecting various industries, including utilities.

Comparison to Industry Standards

• The company's approved Return on Equity (ROE) in Washington (9.8%), Idaho (9.6% in settlement), and Oregon (9.5%) are within the typical range for regulated utilities, which generally falls between 9% and 10.5%.
• The planned capital expenditures of $525 million in 2025, $575 million in 2026, and $600 million in 2027 for Avista Utilities reflect significant ongoing investment in infrastructure, consistent with industry trends of modernizing aging grids and integrating new energy sources.
• The company's resource strategy to add approximately 490 MW by 2030 and 950 MW by 2035, including a request for proposal for up to 415-425 MW, aligns with the broader utility industry's efforts to expand capacity to meet growing demand and replace retiring fossil fuel assets, especially given the planned exit of Colstrip (222 MW) and retirement of the Northeast combustion turbine (65 MW).
• The company's debt-to-capitalization ratios (54.6% for Avista Corp. and 49.3% for AEL&P) are within the industry's typical range for regulated utilities, which often operate with higher leverage due to stable cash flows and regulatory frameworks that allow for debt recovery. The compliance with covenants (65% and 67.5% limits) indicates sound financial management relative to its peers.

Legal Proceedings

• **Boyds Fire (State of Washington Department of Natural Resources v. Avista)**: A lawsuit seeking recovery of up to $4 million for fire suppression and investigation costs from an August 2018 wildfire. Additional lawsuits by private landowners ($1 million in property damages) and insurance subrogation claims ($2 million) were also filed. The company settled with a single plaintiff for less than $0.1 million in June 2025. The company, Asplundh Tree Company, and CN Utility Consulting reached agreements to settle all remaining claims for $3 million, with the company expecting no responsibility for these settlements.
• **Labor Day 2020 Windstorm/Babb Road Fire**: Eleven lawsuits (six subrogation actions by 51 insurance companies and five actions on behalf of 128 individual plaintiffs) were filed in connection with the September 2020 wildfire. The company and CN Utility Consulting reached agreements to settle all claims for a total of $27 million, with the company paying $21 million (offset by expected insurance proceeds received in July 2025) and CN Utility Consulting responsible for $6 million.
• **Orofino Fire**: An August 2023 fire near Orofino, Idaho, caused by third-party damage to the company's natural gas infrastructure, destroyed one residence and resulted in minor injuries. Two lawsuits have been filed seeking unspecified damages. The company is unable to estimate the likelihood of an adverse outcome or the range of potential loss.
• **Colstrip Owners Arbitration and Litigation**: The company is transferring its 15% ownership in Colstrip Units 3 and 4 to NorthWestern by December 31, 2025, with no monetary exchange. Puget Sound Energy (PSE) is also transferring its 25% ownership to NorthWestern.
• **Burnett et al. v. Talen et al.**: A legal proceeding alleging a failure to contain coal dust in connection with the operation of Colstrip. The parties reached an agreement to settle all claims for $1 million in March 2025, with the majority paid through insurance proceeds and the remainder by entities other than the Colstrip owners.
• **Westmoreland Mine Permits**: Two lawsuits challenge permits for the Westmoreland Rosebud Mine, which supplies coal to Colstrip. One permit was vacated by the Montana District Court (upheld by the Montana Supreme Court), and another decision was vacated by the Montana Federal District Court pending further environmental analysis. The company is not a party but is monitoring the proceedings.
• **Complaint of Consumers for Independent Regional Transmission Planning for All FERC-Jurisdictional Transmission Facilities at 100kV and Above**: A complaint filed with the FERC in December 2024 against FERC-jurisdictional Transmission providers (including the company), alleging that the local transmission planning process is not the most efficient or cost-effective for the interconnected grid and customers. The company intends to vigorously defend itself but is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss.

Related Party Transactions

• The company has long-term debt to affiliated trusts, specifically Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $52 million issued to Avista Capital II, an affiliated business trust. The company owns 100% 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 issued by Avista Capital II.

Stakeholder Impact

• **Shareholders**: Experienced decreased net income and earnings per share due to investment losses in non-regulated businesses. Common stock issuances, while supporting capital needs, also dilute existing shares. Dividends declared per common share increased.
• **Customers**: Face approved rate increases in Washington, Idaho (pending settlement approval), and Oregon to allow for cost recovery and capital investments. Tax customer credits are being accelerated in Oregon to mitigate the overall impact of revenue increases. Decoupling mechanisms and other regulatory recovery mechanisms are in place to manage commodity cost fluctuations and stabilize rates. Potential for increased costs due to tariffs on imported goods and potential adverse impacts on natural gas customers from new Washington building codes.
• **Employees**: Utility operating expenses increased due to higher employee salaries and benefits costs. Ongoing collective bargaining agreement negotiations with the IBEW, representing a significant portion of the workforce, carry a risk of disruption if not resolved. System Operators recently unionized.
• **Creditors**: The company maintained strong credit ratings and complied with all debt covenants, indicating financial stability. Successful refinancing of short-term debt into long-term debt enhances the capital structure.
• **Suppliers**: Potential for increased costs and supply chain disruptions due to tariffs on imported goods, which could affect the availability and cost of materials and equipment.

Next Steps

• Continue to file for rate adjustments to recover operating costs and capital investments and seek reasonable returns.
• Select a list of projects for the detailed proposal stage for the 415-425 MW energy/capacity Request for Proposal (RFP) during the third quarter of 2025.
• Begin contract negotiations with final selected projects for the energy/capacity RFP in the fourth quarter of 2025.
• Participate in the Evidentiary Hearing on October 3, 2025, for the Washington Colstrip tariff adjudication, with a final order expected by the end of 2025.
• Expect to file the next multi-year electric and natural gas general rate cases in Washington in the first quarter of 2026.
• Prepare to negotiate a separate contract with the IBEW for the System Operator group in Fall 2025.
• Continue to analyze the U.S. reconciliation bill for impacts on various tax credits and the full expensing of domestic research and experimentation expenditures.
• Monitor the progress of lawsuits challenging Westmoreland Mine permits and assess the impact, if any, on Westmoreland's ability to meet its contractual coal supply obligations.
• Continue to analyze EPA regulations for power plants and assess their impact on existing generating units, seeking cost recovery through the ratemaking process.
• Assess potential impacts, opportunities, and risks that may arise from Presidential Executive Actions on national energy resources and development.
• Study the implications of the Washington State Building Code changes on the natural gas and electric businesses.

Key Dates

Recommendation

The core regulated utility business demonstrates stability and growth, supported by favorable rate case outcomes and customer expansion. However, the significant losses from the non-regulated 'other businesses' segment are a notable drag on overall profitability and introduce unwelcome earnings volatility. While the company is actively managing its capital structure and liquidity, the mixed financial performance and ongoing regulatory and legal uncertainties, particularly regarding environmental mandates and the Colstrip asset, suggest a 'hold' position. Investors should monitor the performance of the non-regulated portfolio and the resolution of regulatory proceedings.

Keywords

Utility, Electric Utility, Natural Gas Utility, SEC Filing, 10-Q, Earnings Report, Avista, AVA, Energy, Regulation, Capital Expenditures, Risk Management, Corporate Governance, Climate Change, Renewable Energy, Infrastructure, Washington, Idaho, Oregon, Alaska