AVA 10-K & 10-Q changes, risk factors and insider trading

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, such as Colstrip,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.”

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, blackouts or disruptions of interconnected transmission systems (the regional power grid), unplanned outages at generating plants, 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, 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, property damage or injuries to third parties caused by our generation, transmission and distribution systems, dam failure at a company-owned hydroelectric facility, natural disasters that can disrupt energy generation, transmission and distribution, and general business operations, terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and increased costs or delay of capital projects associated with the ability of suppliers, vendors or contractors to perform, 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.

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 toof implementimplementing 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.

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 has beenis subject to, and will likely continue to be subject to, 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.

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), customers may have a choice in the future over the sources from which to receive their energyenergy, and we may not be able to compete, 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, 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, non-regulated investments in businesses outside of our core utilities operations may increase earnings volatility, 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, affordability of electric and/or gas services may be a challenge for customers resulting in increased delayed payment for utility services, 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 the risk of municipalization or other form of service territory reduction.

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 thatthose resulting from the use of natural gas by 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 futurefuture, and we are evaluating the extent to which potential changes to environmental laws and regulations may:

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 are producingproduce output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.

We rely on regular access to financial marketsmarkets, 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 impactsimpact our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.

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

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 posting 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 EIMEIM, 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 due on 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.

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 currentforward 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.

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 at the endas of 2025.January 1, 2026. See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies” for discussion regarding environmental and other issues surrounding Colstrip.

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.

Extreme weather events, both in summer and winter, have recently 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 eventsevents, 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. Accordingly, we are taking the increased peaks in demand into account as we consider our resource adequacy and generation requirements.

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 analysis of the need for additional generation.

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

2024Current Hydroelectric GenerationConditions and Outlook

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, as experienced in 2022 and 2023.rates. See “Regulatory Matters” for additional discussion of the general rate cases.

The approved rates within the orders arewere 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 a $77 million increase 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 what was 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 arewere 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 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. BasedOur onactual ournet forecastpower energy commoditysupply costs exceeded the amount reflected in 2025base retail customer rates by $78 million in 2025, and 2026, we expect actual net power supply costs to significantly exceed the level included in base rates.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.

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, discussed above, 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 three 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. TheA WUTCfinal setorder thewas matter for adjudicationissued in December 2025, butwhich alsodetermined orderedthat us,certain WUTCinvestments Staff,in Colstrip were not used or useful to our customers after December 31, 2025, and otheras interestedsuch partiesshould be prorated or disallowed. As a result, we are required to meetissue anda resolve the issues. A status report is duerefund to thecustomers WUTCof $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, 2025.2026 Ifdetailing the parties2025 cannotColstrip resolve the concerns of WUTC Staff, we believe a procedural schedule will be developedinvestments and acustomer hearing date set.refunds.

2025 General Rate CaseCases

Our business segments have not changed during the threesix months ended MarchJune 31,30, 2026. See the 2025 Form 10-K as well as “Note 1416 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income (loss) for each of our business segments and the other businesses for the three and six months ended MarchJune 3130 (dollars in millions):

Net income for the three and six months ended MarchJune 31,30, 2026 increased compared to the three and six months ended MarchJune 31,30, 2025, primarily due to increased utility margin resulting from the effects of our general rate cases and net investment gains at our other businessesbusinesses, compared to net investment losses in the firstrespective periods of 2025. See “Note 5 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding the gain recorded in the second quarter of 2025.2026, as well as expected gains and losses during the remainder of 2026.

When comparing results from the first quarterhalf of 2026 to the first quarterhalf of 2025, the transfer of our ownership of Colstrip (effective January 1, 2026) has resulted in fluctuations in multiple line items on the income statement, which ultimately net to an immaterial impact on earnings.net income. The removal of Colstrip from our generation portfolio resulted in an increase in authorized power supply cost and increases in both electric utility revenues and electric resource costs (resulting in no impact on electricnet utility marginincome). In addition, other operating costs and depreciation expense have decreased, with a corresponding decrease in electric utility revenues associated with recovery of these costs.

Current Hydroelectric Conditions and Outlook

Due to precipitation and warm weather, ourOur hydroelectric generation year-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 beis 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 hydroelectric generation for the entire year will be approximately above the normal level.normal. While our current hydrohydroelectric forecast shows above normal levels of generation,generation evenfor ifthe wefull wereyear, whether actual results are above or below normal, there would be no material change to our net income, based upon our forecast surcharge position in the 90 percent customer, 10 percent company sharing band of the ERM.

The approved rates within the orders are designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $69 million (or 11.4 percent), foreffective January 1, 2026 (Rate Year 2.2). The Rate Year 2 increase includes $54 million related to higher authorized power supply costs resulting from the removal of Colstrip from our generation portfolio. This base increase is offset by decreases in capital and operating costs removed from customer rates of $43 million, effective January 1, 2026, as we are no longer recovering Colstrip related costs.

The approved rates are 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), foreffective RateJanuary Year1, 2.2026.

The WUTC did not approve of 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. Based on our forecast energy commodity costs in 2025 and 2026, we expect actual net power supply costs to exceed the level included in base rates. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings.

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

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 3three or 4four 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.

The WUTC has up to eleven months to review the general rate case filings and issue a decision. The initialevidentiary settlement conferencehearing is expected to take place in May 2026, with evidentiary hearings scheduled for September 2026.

In 2025, we received approval from the WUTC to recover $32 million of the ERM deferred surcharge balance in Washington over a two-year period starting July 1, 2025. In 2026, we received approval from the WUTC to recover an additional $65 million of the ERM deferred surcharge balance in Washington over a two-year period starting July 1, 2026.

Three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025

The following graph shows the total change in net income for the firstsecond quarter of 2026 compared to the firstsecond quarter of 2025, as well as the factors that caused such change (dollars in millions):

Electric utility resource costs decreased primarily due to decreased purchased power costs associated with decreased wholesale prices, as well as decreased fuel for generation costs partially due to the removal of Colstrip from our generation portfolio. TheseThis decreases werewas partially offset by aincreased decreasepurchased inpower deferralsvolumes and wholesale prices, as well as increased costs under the ERM. Natural gas utility resource costs decreased due to decreases in the amortization of costs associated with the CCA and net deferrals and amortizations of costs under PGAs, as well as a decrease in volumes of natural gas purchased.

Utility depreciation and amortization decreased primarily due to our exit from Colstrip in 2026. In anticipation of the exit, we had accelerated depreciation, as we were required to recover costs from Washington customers by the end of 2025.

Three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025