AVISTA CORP
For the period ended Jun 30, 2025. Filed Aug 6, 2025.
View on SEC.govAbout this filing
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, 2025 · Filed Aug 6, 2025
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 2025-03-31; filed 2025-05-07.
0000950170-25-064737
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 2025-06-30; filed 2025-08-06.
0000950170-25-103360
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 210 previous paragraphs and 275 current paragraphs.
143 unchanged; 54 reworded; 59 added; 13 removed; 0 previous and 19 current paragraphs rearranged.
Tables are not compared: 11 previous and 15 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 (59)
Current report
Net income for the three and six months ended June 30, 2025 decreased compared to the three and six months ended June 30, 2024, primarily due to losses at our other businesses associated with lower valuations of certain investments in our portfolio. At Avista Utilities, the effects of our general rate cases have increased earnings in the first half of the year, partially offset by increased operating costs, depreciation and amortization expense and income tax expense.
Current report
In May 2025, we issued a request for proposal to add energy and capacity of up to 415 MW for winter and 425 MW for summer to meet projected resource needs. As part of this request for proposal, we submitted self-build resource bids for consideration. Initial bids were submitted by the end of June 2025, and we expect to select a list of projects to move to the detailed proposal stage during the third quarter of 2025 and begin contract negotiations with final selected projects in the fourth quarter of 2025.
Current 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.
Current report
The Company expects to file its next multi-year electric and natural gas general rate cases in the first quarter of 2026.
Current report
The settlement is designed to increase annual base electric revenues by $20 million, or 6.3 percent, effective in September 2025, and $15 million, or 4.5 percent, effective in September 2026. For natural gas, the agreement is designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026.
Current report
The settlement is based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent.
Current report
For base electric revenues, we originally requested an increase of $43 million (or 14.0 percent), effective September 1, 2025, and $18 million (or 5.0 percent), effective September 1, 2026. For base natural gas revenues, we originally requested an increase of $9 million (or 17.7 percent), effective September 1, 2025, and $1 million (or 1.7 percent), effective September 1, 2026. The lower base revenue agreed to by the parties is mainly due to a lower return on equity than we requested, as well as longer recovery periods for amortizations, a reduction in power supply expense versus filed, and a change in the law affecting the way property taxes are calculated and collected from customers.
Current report
In July 2025, the Governor of Oregon signed into law House Bill 3179 which modifies certain provisions as it relates 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 nine to 10 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 18 months of the prior rate effective date, authorizes 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.
Current report
Electric utility revenues increased as a result of the effects of general rate cases, and increased wholesale sales volumes. This was partially offset by decreased wholesale sale prices. 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 sales volumes.
Current report
Utility resource costs decreased primarily due to net amortizations and deferrals of costs under our regulatory recovery mechanisms.
Current report
Six months ended June 30, 2025 compared to the six months ended June 30, 2024
Current report
Total electric operating revenues in the graph above include intracompany sales of $1 million for both the three months ended June 30, 2025 and 2024.
Current report
Total electric revenues increased $18 million for the second quarter of 2025 as compared to the second quarter of 2024. The primary changes that occurred during the period were as follows:
Current report
Retail sales volumes increased primarily due to customer and load growth, including the effects of warmer weather. Cooling degree days in Spokane were 48 percent higher than normal during the second quarter of 2025, compared to 9 percent higher than normal in the second quarter of 2024. This was partially offset by a decrease in heating degree days, which were 23 percent below normal in the second quarter of 2025, compared to 16 percent below normal in the second quarter of 2024.
Current report
An $11 million decrease in electric decoupling revenue, due to decreased amortizations of prior year rebate balances and decreased deferrals of surcharge balances due to increased loads compared to the second quarter of 2024.
Current report
Total natural gas operating revenues in the graph above include intracompany sales of $1 million for both the three months ended June 30, 2025 and 2024.
Current report
Total natural gas revenues decreased $10 million for the second quarter of 2025 as compared to the second quarter of 2024. The primary changes that occurred during the period were as follows:
Current report
A $7 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year as a result of lower customer usage due to warmer weather.
Current report
Total electric resource costs in the graph above include intracompany resource costs of $1 million for both the three months ended June 30, 2025 and 2024.
Current report
Total electric resource costs increased $1 million for the second quarter of 2025 as compared to the second quarter of 2024. The changes that occurred during the period were as follows:
Current report
A $6 million increase in fuel for generation. This was due to increases in fuel prices and thermal generation compared to the second quarter of 2024.
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, 2025 and 2024.
Current report
Total natural gas resource costs decreased $16 million for the second quarter of 2025 as compared to the second quarter of 2024 due to the following:
Current report
A $10 million decrease in natural gas purchased primarily due to a decrease in volumes consistent with a decrease in retail and wholesale sales volumes.
Current report
A $6 million decrease in other costs primarily due to the decrease in amortizations of previously deferred costs under PGAs, which do not impact utility margin.
Current report
Six months ended June 30, 2025 compared to the six months ended June 30, 2024
Current report
Positive amounts are increases in decoupling revenue in the current year due to lower customer usage and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year due to higher customer usage 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 due to higher customer usage 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 due to lower customer usage and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Current report
Total electric revenues increased $15 million for the first half of 2025 as compared to the first half of 2024. The primary changes that occurred during the period were as follows:
Current report
A $8 million decrease in other electric revenues primarily resulting from decreased renewable energy credit revenues and transmission revenues.
Current report
Total natural gas operating revenues in the graph above include intracompany sales of $4 million and $5 million for the six months ended June 30, 2025 and 2024, respectively.
Showing the first 40 of 59 passages. Open the source sections for the rest.
Removed paragraphs (13)
Previous report
Net income for the three months ended March 31, 2025 increased compared to the three months ended March 31, 2024, primarily due to the effects of general rate cases. These increases in earnings from general rate cases were partially offset by expected increases in operating expenses, depreciation and amortization expense, income taxes and losses recognized at our other businesses.
Previous report
In January 2025, we filed multi-year electric and natural gas general rate cases with the IPUC. If approved, new rates would be effective in September 2025 and September 2026. The proposed rates are designed to increase annual base electric revenues by $43 million, or 14.0 percent, effective in September 2025, and $18 million, or 5.0 percent, effective in September 2026. For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $9 million, or 17.7 percent, effective September 2025, and $1 million, or 1.7 percent, effective September 2026. The proposed electric and natural gas revenue increase requests are based on an ROR of 7.68 percent, with a common equity ratio of 50 percent and an ROE of 10.4 percent. Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) and increases in operations, maintenance, and power supply costs are the main drivers of the proposed increases. The IPUC has up to nine months to review the general rate case filings and issue a decision.
Previous report
Total electric revenues decreased $4 million for the first quarter of 2025 as compared to the first quarter of 2024. The primary changes that occurred during the period were as follows:
Previous report
Total natural gas operating revenues in the graph above include intracompany sales of $3 million and $4 million for the three months ended March 31, 2025 and 2024, respectively.
Previous report
Total natural gas revenues increased $10 million for the first quarter of 2025 as compared to the first quarter of 2024. The primary changes that occurred during the period were as follows:
Previous report
Total electric resource costs in the graph above include intracompany resource costs of $3 million and $4 million for the three months ended March 31, 2025 and 2024, respectively.
Previous report
Total electric resource costs decreased $40 million for the first quarter of 2025 as compared to the first quarter of 2024. The primary changes that occurred during the period were as follows:
Previous report
Total natural gas resource costs in the graph above include intracompany resource costs of $1 million and $2 million for the three months ended March 31, 2025 and 2024, respectively.
Previous report
Total natural gas resource costs increased $2 million for the first quarter of 2025 as compared to the first quarter of 2024 primarily due to the following:
Previous report
Net income for AEL&P remained consistent at $4 million for the three months ended March 31, 2025 and 2024.
Previous report
The fluctuation in results is primarily related to higher net investment losses due to changes in fair value and recognizing our portion of equity investment losses.
Previous report
Under the terms of interest rate swap derivatives, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2024 Form 10-K for further information. As of March 31, 2025, we had interest rate swap derivatives outstanding with a notional amount totaling $10 million and we had no cash deposited as collateral and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at March 31, 2025, the amounts we would be required to post for additional collateral are immaterial.
Reworded paragraphs (54)
Previous wording
Our business segments have not changed during the three months ended March 31, 2025. See the 2024 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, 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.
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
Our 2025 electric IRP was filed with the WUTC and IPUC in December 2024. While the IRP is subject to change from time to time due to changing circumstances, assumptions and projections, given the exit of Colstrip (222 MW) from our system by December 31, 2025 and the expected retirement of the Northeast combustion turbine (65 MW) in 2030, our preferred resource strategy includes the addition of approximately 490 MW of generating capacity by 2030 and a total addition of approximately 950 MW through 2035. We believe the additional capacity would likely consist primarily of wind resources and a natural gas combustion turbine. The new capacity would likely be a combination of resources owned by the Company and resources committed under PPAs, to be determined on a case-by-case basis depending upon financial, tax and regulatory considerations.
Current wording
Our 2025 electric IRP was filed with the WUTC and IPUC in December 2024. While the IRP is subject to change from time to time due to changing circumstances, assumptions and projections, given the exit of Colstrip (222 MW) from our system by December 31, 2025 and the expected retirement of the Northeast combustion turbine (65 MW) in 2030, our preferred resource strategy includes the addition of approximately 490 MW of generating capacity by 2030 and a total addition of approximately 950 MW through 2035.
Previous wording
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, constructing a transmission line from Bismarck, North Dakota to Colstrip, Montana.
Current wording
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 wording
For 2025, we expect generation at our hydro facilities to be approximately 92 percent of normal.
Current wording
For 2025, we expect generation at our hydro facilities to be approximately 85 percent of normal. To meet summer peak demands, we have used additional thermal generation or economic market purchases to offset the decrease in available hydroelectric resources.
Previous wording
In March 2025, we reached an all-party settlement agreement, which has been submitted to the OPUC for its consideration.
Current wording
In June 2025, we reached an all-party settlement agreement, which has been submitted to the IPUC for its consideration. If approved, new rates would be effective in September 2025 and September 2026.
Previous wording
If approved, the settlement agreement is designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement is based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.
Current wording
In May 2025, the OPUC approved the all-party settlement agreement designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.
Previous wording
In March 2025, we filed to recover $32 million of the ERM deferred surcharge balance in Washington which, if approved by the WUTC, would be recovered over one year starting July 1, 2025.
Current 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.
Previous wording
The following graph shows the total change in net income for the first quarter of 2025 compared to the first 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 second quarter of 2025 compared to the second quarter of 2024, as well as the factors that caused such change (dollars in millions):
Previous wording
Utility revenues increased as a result of the effects of general rate cases and customer growth, partially offset by decreased wholesale revenues associated with decreased commodity prices.
Current wording
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 decreases, which do not impact utility margin or net income.
Previous wording
Utility resource costs decreased primarily due to decreased commodity prices, as well as lower authorized resource costs in our Washington GRC that went into effect in December 2024. These were partially offset by increased purchased volumes of power and natural gas, as well as increased amortizations of previously deferred costs compared to the first quarter of 2024.
Current wording
Electric utility resource costs decreased primarily due to decreased purchased power and fuel for generation, as well as increased deferrals of power supply costs and decreased amortizations of previously deferred 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.
Previous wording
Utility operating expenses increased due to increased employee salaries and benefits costs, as well as thermal generation costs. There were also increases in amortizations and base levels of wildfire mitigation and insurance costs, with corresponding increases to revenue which result in no impact to earnings.
Current wording
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 wording
Income tax expense increased primarily due to the decrease in tax customer credits, which offset a portion of 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.
Current wording
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 wording
The decrease in earnings related to other is primarily due to net investment losses recorded in the first quarter of 2025, as well as decreased interest income associated with decreased regulatory deferral balances outstanding during the period.
Current wording
The decrease in earnings related to other is primarily due to net investment losses recorded in the second quarter of 2025 and increased taxes other than income taxes compared to the first half of 2024.
Previous wording
A $40 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $27 million), and an increase in MWhs sold (increased revenues by $13 million).
Current wording
A $33 million increase in retail electric revenue due to an increase in MWhs sold (increased revenues by $17 million) and an increase in retail rates (increased revenues by $16 million).
Previous wording
A $1 million decrease in other electric revenues primarily resulting from decreased transmission revenues.
Current wording
A $7 million decrease in other electric revenues primarily resulting from decreased renewable energy credit revenues and transmission revenues.
Previous wording
A $7 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $15 million), partially offset by increased sales volumes (increased revenues $8 million).
Current wording
A $17 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $10 million) and decreased sales volumes (decreased revenues $7 million).
Previous wording
The increase in sales volumes was primarily due to a 3 percent increase in residential usage and a 4 percent increase in commercial usage resulting from colder weather.
Current wording
The decrease in sales volumes was primarily due to a 14 percent decrease in residential usage and a 10 percent decrease in commercial usage resulting from warmer weather. Heating degree days were 23 percent below normal in the second quarter of 2025, compared to 16 percent below normal in the second quarter of 2024.
Previous wording
A $2 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.
Current wording
A $14 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. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).
Previous wording
Electric utility margin increased $36 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $8 million primarily due to the effects of our general rate cases.
Current wording
Electric utility margin increased $17 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $6 million primarily due to the effects of our general rate cases.
Previous wording
In the first quarter of 2025, we had a $7 million pre-tax expense under the ERM in Washington, compared to a $6 million pre-tax expense for the first quarter of 2024.
Current wording
In the second quarter of 2025, we had a $1 million pre-tax expense under the ERM in Washington, compared to a $1 million pre-tax benefit for the second quarter of 2024.
Previous wording
Total electric operating revenues in the graph above include intracompany sales of $1 million and $2 million for the three months ended March 31, 2025 and 2024, respectively.
Current wording
Total electric operating revenues in the graph above include intracompany sales of $1 million and $3 million for the six months ended June 30, 2025 and 2024, respectively.
Previous wording
Retail sales volumes increased primarily due to customer and load growth. First quarter 2025 heating degree days in Spokane increased 6 percent compared to the first quarter of 2024.
Current wording
Retail sales volumes increased primarily due to customer and load growth, including the effect of warmer weather. Cooling degree days were 48 percent above normal during the first half of 2025, compared to 9 percent above normal in the first half of 2024.
Previous wording
A $34 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $28 million), and a decrease in sales volumes (decreased revenues $6 million). The change in volumes was due to decreased opportunities to optimize our generation assets based on market conditions.
Current wording
A $33 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $46 million), partially offset by an increase in sales volumes (increased revenues $13 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
Previous wording
A $9 million decrease in electric decoupling revenue, primarily due to decreased amortizations of prior year rebate balances.
Current wording
A $20 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.
Previous wording
A $5 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $8 million), partially offset by an increase in sales volumes (increased revenues $3 million). The increase in volumes was related to increased optimization opportunities.
Current wording
A $5 million decrease in wholesale natural gas revenues due to a decrease in prices.
Previous wording
A $2 million decrease in natural gas decoupling revenues due to increased amortization of prior year surcharge balances and decreased surcharge deferrals in the current year.
Current wording
A $5 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year.
Previous wording
A $24 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 as the revenues 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 $24 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.
Previous wording
A $27 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $35 million), partially offset by an increase in the volume of power purchases (increased costs $8 million). Prices during the first quarter of 2024 were elevated due to extreme cold temperatures in our region that created capacity constraints.
Current wording
An $18 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $42 million), partially offset by an increase in the volume of power purchases (increased costs $24 million). Prices during the first quarter of 2024 were elevated due to extreme cold temperatures in our region that created capacity constraints.
Previous wording
An $11 million decrease in fuel for generation. This was due to a decrease in fuel prices, as well as a decrease in thermal generation compared to the first quarter of 2024.
Current wording
A $5 million decrease in fuel for generation. This was primarily due to a decrease in fuel prices compared to the first half of 2024.
Previous wording
A $17 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $23 million), partially offset by an increase in volumes (increased costs $6 million).
Current wording
A $28 million decrease in natural gas purchased primarily due to a decrease in the price of natural gas.
Previous wording
A $19 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.
Current wording
A $13 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.
Previous wording
Our other businesses had a net loss of $3 million for the three months ended March 31, 2025 compared to $0 million for the three months ended March 31, 2024.
Current wording
Our other businesses had a net loss of $10 million for the three months ended June 30, 2025 compared to $2 million for the three months ended June 30, 2024. For the first half of 2025, net loss at our other business was $12 million compared to $2 million for the first half of 2024.
Previous wording
Our sources of overall liquidity and the requirements for liquidity have not materially changed in the three months ended March 31, 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 six months ended June 30, 2025. See the 2024 Form 10-K for further discussion.
Previous wording
As of March 31, 2025, we had $221 million of available liquidity under the Avista Corp. committed line of credit, $40 million of available liquidity under our letter of credit facility, and $12 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 June 30, 2025, we had $106 million of available liquidity under the Avista Corp. committed line of credit, $42 million of available liquidity under our letter of credit facility, and $9 million under the AEL&P committed line of credit. In July 2025, we issued long-term debt, using proceeds to repay borrowings that were outstanding as of June 30, 2025, which increased our available liquidity. 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 provided by operating activities was $184 million for the three months ended March 31, 2025, compared to $190 million for the three months ended March 31, 2024. A decrease of $41 million is associated with net power and natural gas cost deferrals and amortizations. In 2024, amortizations of previously deferred costs were higher compared to 2025. The change in other current assets also decreased operating cash flows by $42 million compared to the prior year, which is associated with increased balances for insurance proceeds receivable, prepayments, and notes receivable. These decreases were partially offset by an increase of $31 million related to the change in other regulatory asset and liability balances, including the impacts of amortization and deferral activity associated with the CCA.
Current wording
Net cash provided by operating activities was $224 million for the six months ended June 30, 2025, compared to $317 million for the six months ended June 30, 2024. A decrease of $81 million is associated with net power and natural gas cost deferrals and amortizations. In 2024, we recovered previously deferred costs from customers compared to returning deferred benefits in the first half of 2025. The change in other current assets also decreased operating cash flows by $44 million compared to the prior year, which is associated with increased balances for insurance proceeds receivable and prepayments. These decreases were partially offset by an increase of $44 million related to the change in other regulatory asset and liability balances, including the impacts of amortization and deferral activity associated with the CCA.
Previous wording
Net cash used in investing activities was $103 million for the three months ended March 31, 2025, compared to $118 million for the three months ended March 31, 2024. We paid $103 million for utility capital expenditures in 2025, compared to $119 million in 2024.
Current wording
Net cash used in investing activities was $248 million for the six months ended June 30, 2025, compared to $254 million for the six months ended June 30, 2024. We paid $246 million for utility capital expenditures in 2025, compared to $251 million in 2024.
Previous wording
Net cash used in financing activities was $94 million for the three months ended March 31, 2025, compared to $95 million for the three months ended March 31, 2024. We decreased our short-term borrowings by $67 million in the three months ended March 31, 2025, compared to $54 million in the three months ended March 31, 2024. In addition, we issued $16 million of common stock and paid $40 million in dividends in the three months ended March 31, 2025, compared to no issued common stock and paying $38 million in dividends in 2024.
Current wording
Net cash provided by financing activities was $3 million for the six months ended June 30, 2025, compared to $83 million used in financing activities for the six months ended June 30, 2024. We increased our short-term borrowings by $51 million in the six months ended June 30, 2025, compared to a decrease of $105 million in the six months ended June 30, 2024. We issued $84 million of long-term debt in the six months ended June 30, 2024, with no issuances of long-term debt in the first half of 2025. In addition, we issued $35 million of common stock and paid $79 million in dividends in the six months ended June 30, 2025, compared to issuing $18 million of common stock and paying $75 million in dividends in the first half of 2024.
Previous wording
Our shareholders’ equity increased $58 million during the first quarter 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 $54 million during the first half of 2025 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.
Previous wording
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $500 million and an expiration date of June 2028, with the option to extend for an additional year (subject to customary conditions).
Current wording
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $500 million with an expiration date of June 2029. We may request that the lenders extend their commitments for an additional one-year period (subject to customary conditions).
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Current report — wording carried from elsewhere
Utility operating expenses increased due to increased employee salaries and benefits costs. In addition, net amortizations and deferrals associated with wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to earnings.
Current report — wording carried from elsewhere
The decrease in earnings related to other is primarily due to net investment losses recorded in the second quarter of 2025 and increased taxes other than income taxes when compared to the second quarter of 2024.
Current report — wording carried from elsewhere
The following graph shows the total change in net income for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, as well as the factors that caused such change (dollars in millions):
Current report — wording carried from elsewhere
Utility depreciation and amortization increased primarily due to additions to utility plant.
Current report — wording carried from elsewhere
A $2 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $14 million), partially offset by a decrease in sales prices (decreased revenues $12 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
Current report — wording carried from elsewhere
A $9 million increase in power purchased due to an increase in the volume of power purchases (increased costs $16 million), partially offset by a decrease in wholesale prices (decreased costs $7 million).
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, 2025 and 2024:
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, 2025 and 2024 (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 $73 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $43 million), and an increase in MWhs sold (increased revenues by $30 million).
Current report — wording carried from elsewhere
Retail rates increased mainly due to the effects of our general rate cases.
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, 2025 and 2024 (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
A $24 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), partially offset by increased sales volumes (increased revenues $2 million). 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 report — wording carried from elsewhere
The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the six months ended June 30, 2025 and 2024 (dollars in millions):
Current report — wording carried from elsewhere
Electric utility margin increased $54 million primarily due to the effects of general rate cases and customer growth. Natural gas utility margin increased $15 million, primarily due to the effects of general rate cases.
Current report — wording carried from 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.