AVISTA CORP
For the period ended Mar 31, 2026. Filed May 5, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 5, 2026
AVA$40.23-1.7%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-11-05.
0001193125-25-265351
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsBusiness SegmentsExecutive OverviewRegulatory MattersResults of Operations - OverallNon-GAAP Financial MeasuresResults of Operations - Avista UtilitiesResults of Operations - Alaska Electric Light and Power CompanyResults of Operations - Other BusinessesCritical Accounting Policies and EstimatesOverall LiquidityReview of Condensed Consolidated Cash Flow StatementCapital ResourcesCapital ExpendituresPension PlanEnvironmental Issues and ContingenciesEnterprise Risk ManagementFuture Resource NeedsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-05.
0001193125-26-204658
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsBusiness SegmentsExecutive OverviewRegulatory MattersResults of Operations - OverallNon-GAAP Financial MeasuresResults of Operations - Avista UtilitiesResults of Operations - Alaska Electric Light and Power CompanyResults of Operations - Other BusinessesCritical Accounting Policies and EstimatesOverall LiquidityReview of Condensed Consolidated Cash Flow StatementCapital ResourcesCapital ExpendituresPension PlanEnvironmental Issues and ContingenciesEnterprise Risk ManagementThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 297 previous paragraphs and 187 current paragraphs.
102 unchanged; 51 reworded; 34 added; 131 removed; 13 previous and 0 current paragraphs rearranged.
Tables are not compared: 16 previous and 14 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (34)
Current report
When comparing results from the first quarter of 2026 to the first quarter 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. 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 electric utility margin). 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 report
See the summary of key developments and issues that are the focus of management under the heading “Executive Overview” in the MD&A of our 2025 10-K. The following developments have occurred since that report:
Current report
Due to precipitation and warm weather, our 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 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 hydroelectric generation for the entire year will be approximately above the normal level. While our current hydro forecast shows above normal levels of generation, even if we were above or below normal, there would be no material change to our position in the ERM.
Current report
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) for Rate Year 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.
Current report
In January 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):
Current report
We requested an overall rate of return beginning 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.
Current report
Key drivers of the revenue requirement in Rate Year 1 (2027) are outlined below (dollars in millions):
Current report
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 ERM.
Current report
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.
Current report
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.
Current report
The WUTC has up to eleven months to review the general rate case filings and issue a decision. The initial settlement conference is expected to take place in May 2026, with evidentiary hearings scheduled for September 2026.
Current report
During the first quarter of 2026, we filed a request with the WUTC to recover from customers $65 million of ERM costs deferred in 2025 over a one-year period starting July 1, 2026.
Current report
Other operating expenses remained unchanged, with decreased expenses from Colstrip offset by expected increases in other expenses.
Current report
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.
Current report
Total electric operating revenues in the graph above include intracompany sales of $0 million and $1 million for the three months ended March 31, 2026 and 2025, respectively.
Current report
Total electric revenues decreased $17 million for the first quarter of 2026 as compared to the first quarter of 2025. The primary changes that occurred during the period were as follows:
Current report
Retail sales volumes decreased due to milder weather, which reduced customer usage. Residential and commercial use per customer decreased 10 percent and 6 percent, respectively. Heating degree days in Spokane were 90 percent of the historical average during the first quarter of 2026, while they were consistent with the historical average during the first quarter of 2025.
Current report
Total natural gas revenues decreased $34 million for the first quarter of 2026 as compared to the first quarter of 2025. The primary changes that occurred during the period were as follows:
Current report
Retail sales volumes decreased due to milder weather, which reduced customer usage. Residential and commercial use per customer decreased 15 percent and 14 percent, respectively. Heating degree days in Spokane were 90 percent of the historical average during the first quarter of 2026, while they were consistent with the historical average in the first quarter of 2025.
Current report
A $22 million decrease in fuel for generation due to decreased thermal generation compared to the prior year due to increased hydroelectric generation and the removal of Colstrip from our generation portfolio.
Current report
Total natural gas resource costs in the graph above include intracompany resource costs of $0 million and $1 million for the three months ended March 31, 2026 and 2025, respectively.
Current report
A $10 million decrease in natural gas purchased due to a decrease in the volumes purchased.
Current report
The fluctuation in results is primarily related to net investment gains in the first quarter of 2026, compared to net investment losses in the first quarter of 2025.
Current report
Net cash provided by operating activities was $179 million for the three months ended March 31, 2026, compared to $184 million for the three months ended March 31, 2025. There was a decrease of $31 million associated with net decoupling deferrals and amortizations, primarily associated with decoupling surcharges recognized in the first quarter of 2026 due to milder weather and decreased customer usage. Changes in other current liabilities and accounts payable decreased operating cash flows by $37 million compared to the first quarter of 2025, primarily due to the timing of a litigation settlement accrual during the first quarter of 2025, as well as decreased payables for natural gas purchases as volumes purchased in 2026 decreased. These decreases were partially offset by the change in other current assets, which increased operating cash flows by $60 million, due to timing of prepayments and insurance proceeds receivables recorded during the first quarter of 2025.
Current report
On March 16, 2026, the U.S. President's Administration issued an Executive Order entitled “Removing Regulatory Barriers to Affordable Home Construction,” with the stated objective of increasing housing supply and affordability by reducing federal, state and local regulatory requirements that the Administration views as increasing construction costs and slowing development. Among other things, the Executive Order directs various federal agencies to incentivize state and local governments to eliminate mandatory green or energy-efficient building codes, review and potentially eliminate “unduly burdensome or costly” federal energy efficiency requirements, revise permitting rules relating to stormwater, wetlands and water pollution controls, and shorten environmental review timelines for housing projects.
Current report
On April 20, 2026, the U.S. President’s Administration issued several Executive Orders invoking authority under the Defense Production Act of 1950 (DPA) to (a) designate oil production and storage, coal and natural gas related power generation activities, electric facilities and supply chains, and large scale energy and energy-related infrastructure as critical resources under the DPA and (b) authorize the Department of Energy to use its authority under the DPA to expand and accelerate domestic capacity in each of these areas.
Current report
We are evaluating the extent to which potential changes from these Executive Orders may affect our financial results and operations.
Current report
Oregon Legislation and Regulatory Actions
Current report
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 Oregon agencies 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 (ODEQ) developing cap and reduce rules known as the CPP. The CPP originally became effective in January 2022, but was subsequently challenged and declared invalid on procedural grounds. Thereafter, the ODEQ reissued the CPP in November 2024 with updated compliance periods.
Current report
On April 16, 2026, approximately 30 parties, consisting of businesses, utilities, trade associations and unions, filed a Petition challenging the repromulgated version of the CPP. Avista Corp. is a party to the litigation, which remains pending.
Removed paragraphs (131)
Previous report
Resource Adequacy and 2025 Request for Proposal (RFP)
Previous report
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. During the third quarter, we selected a list of projects to move to the detailed proposal stage, and expect to begin contract negotiations with final selected projects by the end of 2025. See "Future Resource Needs" for further discussion of regional resource adequacy and our RFP.
Previous report
We also expect expanded transmission infrastructure will 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.
Previous report
For 2025, we expect generation at our hydro facilities to be approximately 85 percent of normal. To meet summer peak demands, we used additional thermal generation and economic market purchases to offset the decrease in available hydroelectric resources.
Previous report
The President of the United States of America has imposed tariffs on certain imported goods and has announced plans to impose tariffs on others. 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.
Previous report
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 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.
Previous report
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.
Previous report
In July 2025, the U.S. enacted a reconciliation bill commonly referred to as the One Big Beautiful Bill Act. We do not expect the bill to have a material impact on our financial results or annual effective tax rate for 2025. We continue to analyze provisions included in the bill, including the impact on various tax credits and the full expensing of domestic research and experimentation expenditures.
Previous report
We are in negotiations with software providers and system implementers and expect the ERP system to be implemented in 2028. We expect capital expenditures between $100 million to $130 million over the life of the project.
Previous report
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. Increased costs associated with tariffs as discussed above could result in additional regulatory lag. See “Regulatory Matters” for additional discussion of the general rate cases.
Previous report
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 $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).
Previous report
The Company expects to file its next multi-year electric and natural gas general rate cases in the first quarter of 2026.
Previous report
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 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. An Evidentiary Hearing was held in October 2025, and a final order is expected by the end of 2025.
Previous report
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.
Previous report
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.
Previous report
Utility resource costs decreased primarily due to net amortizations and deferrals of electric resource costs under our regulatory recovery mechanisms. This includes the effects of the Washington general rate case and a lower level of authorized power supply costs resulting in increased deferrals.
Previous report
Utility operating expenses increased due to increased employee salaries and benefits costs, as well as thermal generation 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 earnings.
Previous report
Utility depreciation and amortization increased primarily due to additions to utility plant.
Previous report
Nine months ended September 30, 2025 compared to the nine months ended September 30, 2024
Previous report
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 sale prices, as well as decreased natural gas rates associated with PGA regulatory mechanism, which do not impact utility margin or net income.
Previous report
Utility operating expenses increased due to increased employee salaries and benefits costs, as well as thermal generation 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 earnings.
Previous report
Utility depreciation and amortization increased primarily due to additions to utility plant.
Previous report
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 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.
Previous report
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 updating our estimates for an existing environmental remediation liability at one of our subsidiaries, which resulted in a pre-tax expense of $3 million.
Previous report
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.
Previous report
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.
Previous report
Total electric revenues increased $13 million for the third quarter of 2025 as compared to the third quarter of 2024. The primary changes that occurred during the period were as follows:
Previous report
Retail sales volumes increased primarily due to customer growth, as well as increased customer usage. Residential use per customer increased 6 percent, and commercial use per customer increased 2 percent.
Previous report
A $13 million decrease in electric decoupling revenue, due to increased deferrals of rebate balances due to increased loads compared to the third quarter of 2024, as well as decreased amortizations of prior year rebate balances.
Previous report
A $5 million decrease in other electric revenues primarily resulting from decreased renewable energy credit revenues and transmission revenues.
Previous report
Total natural gas operating revenues in the graph above include intracompany sales of $3 million and $6 million for the three months ended September 30, 2025 and 2024, respectively.
Previous report
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.
Previous report
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.
Previous report
Total natural gas revenues decreased $5 million for the third quarter of 2025 as compared to the third quarter of 2024. The primary changes that occurred during the period were as follows:
Previous report
The decrease in sales volumes was primarily due to a 6 percent decrease in residential usage and an 8 percent decrease in commercial usage. Retail natural gas loads and changes in customer usage during the third quarter are typically not significant to the full year.
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Reworded paragraphs (51)
Previous wording
Our business segments have not changed during the nine months ended September 30, 2025. See the 2024 Form 10-K as well as “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.
Current wording
Our business segments have not changed during the three months ended March 31, 2026. See the 2025 Form 10-K as well as “Note 14 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.
Previous wording
The following table presents net income (loss) for each of our business segments and the other businesses for the three and nine months ended September 30 (dollars in millions):
Current wording
The following table presents net income (loss) for each of our business segments and the other businesses for the three months ended March 31 (dollars in millions):
Previous wording
Net income for the three and nine months ended September 30, 2025 increased compared to the three and nine months ended September 30, 2024, primarily due to the effects of our general rate cases. Partially offsetting the increase were increased operating costs, depreciation and amortization expense and income tax expense. In addition, increased investment losses associated with lower valuations of certain investments in our portfolio decreased year to date net income at our other businesses when compared to 2024.
Current wording
Net income for the three months ended March 31, 2026 increased compared to the three months ended March 31, 2025, due to increased utility margin resulting from the effects of our general rate cases and net investment gains at our other businesses compared to net investment losses in the first quarter of 2025.
Previous wording
We are planning to implement an ERP system, replacing a variety of 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 WUTC and IPUC approved these requests, and the petition with the OPUC remains pending.
Current wording
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. We expect the ERP system to be implemented in 2028, with capital expenditures of approximately $130 million.
Previous wording
In July 2025, the Governor of Oregon signed into law House Bill 3179 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 timing of our future rate case filings.
Current wording
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 OPUC 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 multi-year 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.
Previous wording
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.
Current wording
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.
Previous wording
The following graph shows the total change in net income for the third quarter of 2025 compared to the third quarter of 2024, as well as the factors that caused such change (dollars in millions):
Current wording
The following graph shows the total change in net income for the first quarter of 2026 compared to the first quarter of 2025, as well as the factors that caused such change (dollars in millions):
Previous wording
Electric utility revenues increased primarily as a result of the effects of general rate cases and customer growth, which was partially offset by decreased wholesale revenues. Natural gas revenues decreased due to decreased rates associated with the PGAs (which do not impact utility margin or net income), as well as decreased wholesale volumes.
Current wording
Electric utility revenues decreased primarily as a result of decreased wholesale revenues associated with lower market prices, and a reduction of revenues associated with the recovery of Colstrip costs, which were partially offset by other increases in retail rates associated with our general rate cases. Natural gas revenues decreased due to decreased rates associated with the PGAs and the CCA (which do not impact utility margin or net income), as well as decreased wholesale revenues, transportation revenues and an increased provision for rate refunds associated with overearnings in Washington.
Previous wording
Electric utility resource costs decreased primarily due to decreased purchased power 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 amortizations 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.
Current wording
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. These decreases were partially offset by a decrease in deferrals 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.
Previous wording
Increases in earnings from other activity are primarily due to net investment gains, compared to net investment losses in the third quarter of 2024. This increase in earnings was partially offset by increased non-utility operating expenses associated with updating our estimates for an existing environmental remediation liability at one of our subsidiaries, which resulted in a pre-tax expense of $3 million.
Current wording
Increases in earnings from other activity are primarily due to net investment gains, compared to net investment losses in the first quarter of 2025.
Previous wording
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 financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2024 Form 10-K for further discussion of our optimization activities.
Current wording
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; this is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can include physical sales and purchases of electric capacity and energy, fuel for electric generation, natural gas to optimize use of pipeline and storage capacity, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2025 Form 10-K for further discussion of our optimization activities.
Previous wording
A $32 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $22 million) and an increase in MWhs sold (increased revenues by $10 million).
Current wording
A $5 million decrease in retail electric revenue due to a decrease in MWhs sold (decreased revenues by $21 million), partially offset by an increase in retail rates (increased revenues by $16 million).
Previous wording
Retail rates increased mainly due to the effects of our general rate cases.
Current wording
Retail rates increased mainly due to the effects of our general rate cases, including base rate increases associated with higher authorized power supply expenses resulting from removing Colstrip from our generation portfolio. These increases to base rates were partially offset by the removal of revenues related to recovery of Colstrip related costs other than power supply costs.
Previous wording
A $5 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $3 million) and a decrease in sales volumes (decreased revenues $2 million). The change in volumes was due to decreased opportunities to optimize our generation assets based on market conditions.
Current wording
A $27 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $26 million) and a decrease in sales volumes (decreased revenues $1 million).
Previous wording
A $33 million decrease in electric decoupling revenue, primarily due to decreased amortizations of prior year rebate balances, as well as current year rebate deferrals due to higher customer usage compared to surcharges deferred in 2024.
Current wording
A $14 million increase in electric decoupling revenue primarily due to current year surcharge deferrals associated with decreased customer usage compared to rebate deferrals in the first quarter of 2025.
Previous wording
Total electric operating revenues in the graph above include intracompany sales of $1 million and $0 million for the three months ended September 30, 2025 and 2024, respectively.
Current wording
Total natural gas operating revenues in the graph above include intracompany sales of $1 million and $3 million for the three months ended March 31, 2026 and 2025, respectively.
Previous wording
A $5 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $4 million) and decreased sales volumes (decreased revenues $1 million).
Current wording
A $50 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $27 million) and decreased sales volumes (decreased revenues $23 million).
Previous wording
Retail rates decreased mainly 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.
Current wording
Retail rates decreased mainly due to PGA rate decreases and rebates to Washington customers for revenues related to the sale of CCA emissions credits, neither of which impact utility margin. These decreases were partially offset by increases to base rates resulting from our general rate cases.
Previous wording
A $9 million decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues $8 million) and a decrease in prices (decreased revenues $1 million).
Current wording
An $8 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $6 million) and a decrease in volumes (decreased revenues $2 million).
Previous wording
A $6 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year.
Current wording
A $17 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year associated with lower customer usage.
Previous wording
A $27 million increase in other 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 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.
Current wording
A $7 million increase in other 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 as discussed above, resulting in no impact to utility margin. This increase was partially offset by a decrease in transportation revenue, as well as a provision for rate refunds associated with overearnings in Washington recorded in the first quarter of 2026.
Previous wording
Total natural gas resource costs in the graph above include intracompany resource costs of $1 million and $0 million for the three months ended September 30, 2025 and 2024, respectively.
Current wording
Total electric resource costs in the graph above include intracompany resource costs of $1 million and $3 million for the three months ended March 31, 2026 and 2025, respectively.
Previous wording
Total electric resource costs decreased $19 million for the third quarter of 2025 as compared to the third quarter of 2024. The changes that occurred during the period were as follows:
Current wording
Total electric resource costs decreased $14 million for the first quarter of 2026 as compared to the first quarter of 2025. The changes that occurred during the period were as follows:
Previous wording
A $3 million increase in power purchased due to an increase in the volume of power purchases (increased costs $5 million), partially offset by a decrease in wholesale prices (decreased costs $2 million).
Current wording
A $7 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $8 million), partially offset by an increase in the volume of power purchases (increased costs $1 million).
Previous wording
A $28 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).
Current wording
A $13 million increase in other electric resource costs primarily related to a decrease in deferred costs under the ERM. The decrease in deferred costs was due to an increase in authorized power supply costs primarily due to the removal of Colstrip from our generation portfolio. There were also increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).
Previous wording
Total natural gas resource costs decreased $9 million for the third quarter of 2025 as compared to the third quarter of 2024 due to the following:
Current wording
Total natural gas resource costs decreased $39 million for the first quarter of 2026 as compared to the first quarter of 2025 due to the following:
Previous wording
A $12 million increase in other costs primarily related to the amortization of costs associated with the CCA that were recovered from customers, resulting in no impact to utility margin. This was partially offset by a decrease in amortizations of previously deferred costs under our PGAs.
Current wording
A $29 million decrease in other costs primarily related to a decrease in the amortization of costs associated with the CCA that were recovered from customers, resulting in no impact to utility margin, as well as a decrease in net deferrals and amortizations of previously deferred costs under our PGAs.
Previous wording
Electric utility margin increased $32 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $4 million primarily due to the effects of our general rate cases.
Current wording
Electric utility margin decreased $3 million primarily due to the removal of revenues related to the recovery of Colstrip capital and operating costs, partially offset by other effects of our general rate cases. Natural gas utility margin increased $5 million primarily due to the effects of general rate cases.
Previous wording
In the first three quarters of 2025 we had a pre-tax expense of $13 million under the ERM in Washington, compared to a pre-tax expense of $8 million in the first three quarters of 2024.
Current wording
In the first quarter of 2026 we had a pre-tax expense of $1 million under the ERM in Washington compared to a pre-tax expense of $7 million in the first quarter of 2025.
Previous wording
For the first three quarters of 2025, net income for AEL&P was $4 million compared to $5 million for the first three quarters of 2024.
Current wording
For the first quarter of 2026 and 2025, net income for AEL&P was $4 million, respectively.
Previous wording
Our other businesses had a net loss of $1 million for the three months ended September 30, 2025 compared to $2 million for the three months ended September 30, 2024. For the first three quarters of 2025, net loss at our other business was $13 million compared to $3 million for the first three quarters of 2024.
Current wording
Our other businesses had net income of $1 million for the three months ended March 31, 2026 compared to a net loss of $3 million for the three months ended March 31, 2025.
Previous wording
Our sources of overall liquidity and the requirements for liquidity have not materially changed in the nine months ended September 30, 2025. See the 2024 Form 10-K for further discussion.
Current wording
Our sources of overall liquidity and the requirements for liquidity have not materially changed in the three months ended March 31, 2026. See the 2025 Form 10-K for further discussion.
Previous wording
As of September 30, 2025, we had $210 million of available liquidity under the Avista Corp. committed line of credit, $43 million of available liquidity under our letter of credit facility, and $23 million under the AEL&P committed line of credit. 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.
Current wording
As of March 31, 2026, we had $110 million of available liquidity under the Avista Corp. committed line of credit, $46 million of available liquidity under our letter of credit facility, and $25 million under the AEL&P committed line of credit. 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.
Previous wording
Net cash used in investing activities was $373 million for the nine months ended September 30, 2025, compared to $410 million for the nine months ended September 30, 2024. We paid $379 million for utility capital expenditures in 2025, compared to $405 million in 2024.
Current wording
Net cash used in investing activities was $148 million for the three months ended March 31, 2026, compared to $103 million for the three months ended March 31, 2025. We paid $150 million for utility capital expenditures in 2026, compared to $103 million in 2025.
Previous wording
Net cash provided by financing activities was $7 million for the nine months ended September 30, 2025, compared to $60 million used in financing activities for the nine months ended September 30, 2024. We issued $140 million of long-term debt in the nine months ended September 30, 2025, compared to $84 million of long-term debt issued in the nine months ended September 30, 2024. In addition, we issued $45 million of common stock and paid $119 million in dividends in the nine months ended September 30, 2025, compared to issuing $36 million of common stock and paying $112 million in dividends in the nine months ended September 30, 2024.
Current wording
Net cash used in financing activities was $32 million for the three months ended March 31, 2026, compared to $94 million for the three months ended March 31, 2025. In the first quarter of 2026, we repaid $3 million in short term borrowings, compared to $67 million in the first quarter of 2025. We issued $14 million of common stock and paid $41 million in dividends in the three months ended March 31, 2026, compared to issuing $16 million of common stock and paying $40 million in dividends in the three months ended March 31, 2025.
Previous wording
Our shareholders’ equity increased $54 million during the first three quarters of 2025 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.
Current wording
Our shareholders’ equity increased $67 million during the first quarter of 2026 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.
Previous wording
The Avista Corp. credit facilities contain customary covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of September 30, 2025, we complied with this covenant with a ratio of 54.7 percent.
Current wording
The Avista Corp. credit facilities contain customary covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of March 31, 2026, we complied with this covenant with a ratio of 54.3 percent.
Previous wording
Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the nine months ended September 30 (dollars in millions):
Current wording
Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the three months ended March 31 (dollars in millions):
Previous wording
AEL&P has a $25 million committed line of credit that expires in June 2028. As of September 30, 2025, there was $2 million outstanding under this committed line of credit, and $23 million of available liquidity.
Current wording
AEL&P has a $25 million committed line of credit that expires in June 2028. As of March 31, 2026, there was no balance outstanding under this committed line of credit, and $25 million of available liquidity.
Previous wording
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 September 30, 2025, AEL&P complied with this covenant with a ratio of 50.3 percent.
Current wording
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 March 31, 2026, AEL&P complied with this covenant with a ratio of 48.7 percent.
Showing the first 40 of 51 pairs. Open the source sections for the rest.
Rearranged previous paragraphs (13)
Previous report — wording carried elsewhere
The following graph shows the total change in net income for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, as well as the factors that caused such change (dollars in millions):
Previous report — wording carried elsewhere
A $4 million decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues $6 million), partially offset by an increase in prices (increased revenues $2 million).
Previous report — wording carried elsewhere
The following table presents Avista Utilities' average number of electric and natural gas retail customers for the nine months ended September 30, 2025 and 2024:
Previous report — wording carried elsewhere
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30, 2025 and 2024 (dollars in millions and MWhs in thousands):
Previous report — wording carried elsewhere
This balance includes public street and highway lighting, which is considered part of retail electric revenues.
Previous report — wording carried elsewhere
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 nine months ended September 30 (dollars in millions):
Previous report — wording carried elsewhere
Retail rates increased mainly due to the effects of our general rate cases.
Previous report — wording carried elsewhere
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the nine months ended September 30, 2025 and 2024 (dollars in millions and therms in thousands):
Previous report — wording carried elsewhere
This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.
Previous report — wording carried elsewhere
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility natural gas operating revenues for the nine months ended September 30 (dollars in millions):
Previous report — wording carried elsewhere
A $45 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).
Previous report — wording carried elsewhere
The following table reconciles Avista Utilities' operating revenues, as presented in "Note 15 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the nine months ended September 30, 2025 and 2024 (dollars in millions):
Previous report — wording carried elsewhere
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 condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.