AVISTA CORP
For the period ended Jun 30, 2026. Filed Aug 3, 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.
Jun 30, 2026 · Filed Aug 3, 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 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 ManagementCurrent report: 10-Q
Period ended 2026-06-30; filed 2026-08-03.
0001193125-26-329083
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsBusiness SegmentsExecutive OverviewRegulatory MattersResults of Operations - OverallResults 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 187 previous paragraphs and 250 current paragraphs.
112 unchanged; 59 reworded; 58 added; 16 removed; 0 previous and 21 current paragraphs rearranged.
Tables are not compared: 14 previous and 16 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 (58)
Current report
The effects of our general rate cases also increased net income in 2026.
Current report
A number of wildfires have occurred within our service territory in 2026, impacting our operations. While the causes of some fires remain under investigation, virtually all have been attributed to human activity or lightning. Two fires ignited near our facilities but have since been fully contained. One fire damaged a small storage facility. No structures were impacted by the other fire. We do not believe either of these ignitions resulted from the improper operation or maintenance of our facilities. In response to an increased wildfire risk driven primarily by high winds and drier-than-normal conditions, we have proactively implemented enhanced system protections and public safety power shutoffs. We continue to monitor conditions closely and respond as needed to mitigate this elevated risk.
Current report
In May 2026, we entered into a non-binding memorandum of understanding (MOU) with a data center developer seeking interconnection and energy supply in our Washington service territory. The developer is seeking an initial load demand of 125 MW starting in 2029, with a pathway to expand to 500 MW by 2032.
Current report
In June 2026, we announced that we will take additional time to evaluate the processing of energy requests from data center developers, and have paused negotiations associated with the MOU. This decision followed community interest and concern surrounding the MOU. We are seeking to partner with governmental agencies on creating a clear and coordinated planning process as we consider additional stakeholder feedback associated with large load requests.
Current report
We expect to file electric and natural gas general rate cases with the IPUC in the first quarter of 2027.
Current report
In May 2026, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). AEL&P's request for an interim base rate increase of 12.5 percent (designed to increase electric revenues by $5 million), was approved and took effect in June 2026. AEL&P is seeking a permanent base rate increase of an additional 12.6 percent (designed to increase electric revenues by $5 million), which, if approved, could take effect in August 2027. This represents a combined total rate increase of 25.1 percent (designed to increase electric revenues by $10.0 million). The proposed revenue increase request is based on a 13.2 percent ROE with a common equity ratio of 58.33 percent and a ROR of 9.75 percent.
Current report
The RCA must rule on permanent rate increases within 450 days (approximately 15 months) from the date of filing.
Current report
Electric Utility revenues increased due to increases in retail rates associated with our general rate case, which were partially offset by removing the recovery of Colstrip related costs. This increase to revenues was largely offset by decreased wholesale revenues and decreases in volumes sold. The decrease in volumes sold is due to the departure of a large industrial customer in April 2026. Natural gas revenues increased due to rate increases, largely offset by decreases in wholesale revenues and decoupling revenues.
Current report
Other utility operating expenses increased due primarily to increased employee salaries and benefit costs, partially offset with decreases from removing Colstrip related expenses.
Current report
Income tax expense increased primarily due to increased pre-tax income from continuing operations (including equity method earnings) compared to the prior year.
Current report
Increased equity method earnings were primarily the result of underlying investment appreciation recognized in the second quarter of 2026, compared to losses recognized in the second quarter 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 2026.
Current report
Six months ended June 30, 2026 compared to the six months ended June 30, 2025
Current report
Other utility operating expenses increased due primarily to increased employee salaries and benefit costs, partially offset with decreases from removing Colstrip related expenses.
Current report
Income tax expense increased primarily due to increased pre-tax income from continuing operations (including equity method earnings) compared to the prior year.
Current report
Increased equity method earnings were primarily the result of underlying investment appreciation recognized in the first half of 2026, compared to losses recognized in the first half 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 2026.
Current report
Intercompany Revenues and Resource Costs
Current report
Total electric operating revenues in the graph above include intracompany sales of $1 million for both the three months ended June 30, 2026 and 2025.
Current 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.
Current 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.
Current report
Total electric revenues did not change materially for the second quarter of 2026 as compared to the second quarter of 2025. The primary fluctuations that occurred during the period were as follows:
Current report
Retail sales volumes decreased due to a 21 percent decrease in industrial electric sales volumes, partially due to the departure of a large industrial customer in April 2026. Additionally, milder weather reduced customer usage. Residential and commercial use per customer decreased 5 percent and 3 percent, respectively.
Current 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.
Current 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.
Current report
Total natural gas revenues did not change materially for the second quarter of 2026 as compared to the second quarter of 2025. The primary fluctuations that occurred during the period were as follows:
Current report
Total electric resource costs decreased $3 million for the second quarter of 2026 as compared to the second quarter of 2025. The primary changes that occurred during the period were as follows:
Current report
Total natural gas resource costs in the graph above include intracompany resource costs of $1 million for both the three months ended June 30, 2026 and 2025.
Current report
Total natural gas resource costs decreased $2 million for the second quarter of 2026 as compared to the second quarter of 2025 due to a $2 million decrease in natural gas purchased from a decrease in volumes, consistent with a decrease in retail and wholesale sales volumes.
Current report
Six months ended June 30, 2026 compared to the six months ended June 30, 2025
Current report
Total electric operating revenues in the graph above include intracompany sales of $1 million for both the six months ended June 30, 2026 and 2025.
Current report
Total natural gas operating revenues in the graph above include intracompany sales of $1 million and $4 million for the six months ended June 30, 2026 and 2025, respectively.
Showing the first 40 of 58 passages. Open the source sections for the rest.
Removed paragraphs (16)
Previous 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.
Previous report
Other operating expenses remained unchanged, with decreased expenses from Colstrip offset by expected increases in other expenses.
Previous report
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 report
The following discussion for Avista Utilities includes two financial measures considered “non-GAAP financial measures”: electric utility margin and natural gas utility margin.
Previous report
Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 14 of the Notes to Condensed Consolidated Financial Statements."
Previous report
The presentation of electric utility margin and natural gas utility margin is intended to enhance the understanding of operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.
Previous report
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 report
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 report
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 report
The following table reconciles Avista Utilities' operating revenues, as presented in "Note 14 of the Notes to Condensed Consolidated Financial Statements", to the Non-GAAP financial measure utility margin for the three months ended March 31, 2026 and 2025 (dollars in millions):
Previous report
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 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.
Reworded paragraphs (59)
Previous 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.
Current wording
Our business segments have not changed during the six months ended June 30, 2026. See the 2025 Form 10-K as well as “Note 16 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 months ended March 31 (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 and six months ended June 30 (dollars in millions):
Previous 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.
Current wording
Net income for the three and six months ended June 30, 2026 increased compared to the three and six months ended June 30, 2025, primarily due to net investment gains at our other businesses, compared to net investment losses in the respective 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 2026, as well as expected gains and losses during the remainder of 2026.
Previous wording
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 wording
When comparing results from the first half of 2026 to the first half 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 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 net income). In addition, other operating costs and depreciation expense have decreased, with a corresponding decrease in electric utility revenues associated with recovery of these costs.
Previous wording
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 wording
Our hydroelectric generation year-to-date has been above normal. The amount of hydroelectric generation is affected not only by 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 above normal. While our current hydroelectric forecast shows above normal levels of generation for the full year, 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.
Previous wording
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 wording
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), effective January 1, 2026 (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.
Previous wording
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) for Rate Year 2.
Current wording
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), effective January 1, 2026.
Previous wording
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.
Current wording
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. Based on our forecast energy commodity costs in 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.
Previous wording
The Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.
Current wording
The WUTC continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.
Previous wording
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 wording
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 three or four 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.
Previous wording
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 wording
The WUTC has up to eleven months to review the general rate case filings and issue a decision. The evidentiary hearing is scheduled for September 2026.
Previous 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.
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. 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.
Previous 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):
Current wording
The following graph shows the total change in net income for the second quarter of 2026 compared to the second quarter of 2025, as well as the factors that caused such change (dollars in millions):
Previous wording
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 wording
Utility depreciation and amortization decreased primarily due to our exit from Colstrip in 2026.
Previous 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.
Current wording
Electric utility revenues decreased primarily as a result of decreased wholesale revenues associated with lower market prices, a reduction of revenues associated with the recovery of Colstrip costs, and the departure of a large industrial customer in April 2026, 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 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 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.
Current wording
Electric utility resource costs decreased primarily due to 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
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.
Current wording
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 below.
Previous 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).
Current wording
A $5 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $25 million) offset by a decrease in MWhs sold (decreased revenues by $20 million).
Previous wording
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 wording
Total natural gas operating revenues in the graph above include intracompany sales of $0 million and $1 million for the three months ended June 30, 2026 and 2025.
Previous wording
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 wording
Total electric resource costs in the graph above include intracompany resource costs of $0 million and $1 million for the three months ended June 30, 2026 and 2025.
Previous wording
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 wording
A $15 million decrease in fuel for generation due to decreased thermal generation due to increased hydroelectric generation. Thermal generation decreased due to the removal of Colstrip from our generation portfolio, as well as major maintenance at the Coyote Springs 2 facility in 2026.
Previous 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).
Current wording
A $9 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
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.
Current wording
In the second quarter of 2026, we had a pre-tax expense of $6 million under the ERM in Washington compared to a pre-tax expense of $1 million in the second quarter of 2025.
Previous wording
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 wording
Total electric revenues decreased $17 million for the first half of 2026 as compared to the first half of 2025. The primary changes that occurred during the period were as follows:
Previous wording
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 wording
Retail sales volumes decreased due to a 12 percent decrease in industrial electric sales volumes, partially due to the departure of a large industrial customer in April 2026. Additionally, milder weather led to reduced customer usage. Residential and commercial use per customer decreased 8 percent and 4 percent, respectively. Heating degree days in Spokane were 87 percent of the historical average during the first half of 2026, while they were 94 percent of the historical average during the first half of 2025.
Previous 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).
Current wording
A $34 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $29 million) and a decrease in sales volumes (decreased revenues $5 million).
Previous 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.
Current wording
An $18 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 half of 2025.
Previous wording
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 wording
Total natural gas revenues decreased $34 million for the first half of 2026 as compared to the first half of 2025. The primary changes that occurred during the period were as follows:
Previous 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).
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 $26 million) and decreased sales volumes (decreased revenues $24 million).
Previous 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.
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 net income. These decreases were partially offset by increases to base rates resulting from our general rate cases.
Previous wording
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 wording
Retail sales volumes decreased due to milder weather, which reduced customer usage. Residential and commercial use per customer each decreased 12 percent. Heating degree days in Spokane were 87 percent of the historical average during the first half of 2026, while they were 94 percent of the historical average in the first half of 2025.
Previous 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).
Current wording
An $11 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $8 million) and a decrease in volumes (decreased revenues $3 million).
Previous 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.
Current wording
A $16 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 $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.
Current wording
An $11 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 on net income. 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 half of 2026.
Previous 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).
Current wording
A $2 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $6 million), partially offset by an increase in the volume of power purchases (increased costs $4 million).
Previous 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:
Current wording
Total natural gas resource costs decreased $40 million for the first half of 2026 as compared to the first half of 2025 due to the following:
Previous wording
A $10 million decrease in natural gas purchased due to a decrease in the volumes purchased.
Current wording
A $12 million decrease in natural gas purchased due to a decrease in the volumes purchased.
Previous 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.
Current wording
A $28 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 on net income, as well as a decrease in net deferrals and amortizations of previously deferred costs under our PGAs.
Previous wording
For the first quarter of 2026 and 2025, net income for AEL&P was $4 million, respectively.
Current wording
Net income for AEL&P was $1 million for both the second quarter of 2026 and 2025. For the first half of 2026 and 2025, net income for AEL&P was $5 million and $4 million, respectively.
Previous 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.
Current wording
Our other businesses had net income of $12 million for the three months ended June 30, 2026 compared to a net loss of $10 million for the three months ended June 30, 2025. For the first half of 2026, net income at our other businesses was $13 million compared to a net loss of $12 million for the first half of 2025.
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Current report — wording carried from elsewhere
Alaska Electric Light and Power Company
Current report — wording carried from elsewhere
Electric utility resource costs decreased primarily due to decreased fuel for generation costs partially due to the removal of Colstrip from our generation portfolio. This was partially offset by increased purchased power volumes and wholesale prices, as well as increased costs under the ERM. Natural gas utility resource costs decreased due to decreases in volumes of natural gas purchased.
Current report — wording carried from elsewhere
The following graph shows the total change in net income for the six months ended June 30, 2026 compared to the six months ended June 30, 2025, as well as the factors that caused such change (dollars in millions):
Current report — wording carried from elsewhere
Utility depreciation and amortization decreased primarily due to our transfer of Colstrip.
Current report — wording carried from elsewhere
An $8 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $4 million) and a decrease in sales prices (decreased revenues $4 million).
Current report — wording carried from elsewhere
A $4 million increase in electric decoupling revenue primarily due to increased current year surcharge deferrals associated with decreased customer usage compared to the second quarter of 2025.
Current report — wording carried from elsewhere
A $3 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $2 million) and a decrease in volumes (decreased revenues $1 million).
Current report — wording carried from elsewhere
A $4 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 revenues, resulting in no impact on net income.
Current report — wording carried from elsewhere
A $5 million increase in power purchased due to an increase in the volume of power purchases (increased costs $3 million) and an increase in wholesale prices (increased costs $2 million).
Current report — wording carried from elsewhere
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2026 and 2025 (dollars in millions and MWhs in thousands):
Current report — wording carried from elsewhere
This balance includes public street and highway lighting, which is considered part of retail electric revenues.
Current report — wording carried from 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 six months ended June 30 (dollars in millions):
Current report — wording carried from elsewhere
A $1 million decrease in retail electric revenue due to a decrease in MWhs sold (decreased revenues by $42 million), offset by an increase in retail rates (increased revenues by $41 million).
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the six months ended June 30, 2026 and 2025 (dollars in millions and therms in thousands):
Current report — wording carried from elsewhere
This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.
Current report — wording carried from 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 six months ended June 30 (dollars in millions):
Current report — wording carried from elsewhere
The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2026 and 2025:
Current report — wording carried from elsewhere
A $22 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
Current report — wording carried from elsewhere
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).
Current report — wording carried from elsewhere
In the first half of 2026, we had a pre-tax expense of $7 million under the ERM in Washington compared to a pre-tax expense of $9 million in the first half of 2025.