AVISTA CORP
For the period ended Mar 31, 2025. Filed May 7, 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.
Mar 31, 2025 · Filed May 7, 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 2024-09-30; filed 2024-11-06.
0000950170-24-121737
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 2025-03-31; 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 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 286 previous paragraphs and 210 current paragraphs.
87 unchanged; 65 reworded; 58 added; 122 removed; 12 previous and 0 current paragraphs rearranged.
Tables are not compared: 15 previous and 11 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 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 would 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 are unable to reasonably estimate the effects of the tariffs, and have not made any adjustments to our capital or operating budget to account for increased costs resulting from tariffs.
Current 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.
Current 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.
Current report
For 2025, we expect generation at our hydro facilities to be approximately 92 percent of normal.
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 $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).
Current report
The WUTC approved an ROE of 9.8 percent, based on a common equity ratio of 48.5 percent, and an ROR of 7.32 percent.
Current report
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 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 report
The Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.
Current 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. The WUTC set the matter for adjudication in 2025, but also ordered us, WUTC Staff, and other interested parties to meet and resolve the issues. On March 6, 2025, the Commission held a prehearing conference for purposes of setting a procedural schedule. The issued schedule calls for a process that results in an Evidentiary Hearing on October 3, 2025, and a final order by the end of 2025.
Current report
In March 2025, we reached an all-party settlement agreement, which has been submitted to the OPUC for its consideration.
Current report
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 report
To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period.
Current report
See our 2024 Form 10-K for discussion of the various regulatory recovery mechanisms in each of our jurisdictions.
Current report
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 report
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 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 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:
Current report
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 report
A $9 million decrease in electric decoupling revenue, primarily due to decreased amortizations of prior year rebate balances.
Current 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.
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 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:
Current report
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 report
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 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.
Current 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:
Current 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.
Current 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:
Current report
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 report
Net income for AEL&P remained consistent at $4 million for the three months ended March 31, 2025 and 2024.
Current report
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 report
In November 2024, Washington voters approved Initiative 2066, which would prohibit state and local governments from restricting access to natural gas, prohibit the SBCC from discouraging or penalizing the use of natural gas, and prohibit the WUTC from approving any multi-year rate plan that requires or incentivizes natural gas companies to terminate or limit natural gas service. In March 2025, a Washington state court held that the Initiative violates the “single subject rule” and is invalid. That decision has been appealed and the appeal remains pending.
Current report
2025 Presidential Executive Action
Current report
Since taking office, the U.S. President's Administration has issued a multitude of Executive Orders directed towards national energy resources and development. These include, actions to:
Current report
immediately pause the disbursement of funds appropriated through the Inflation Reduction Act of 2022 or the Infrastructure and Jobs Act;
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Removed paragraphs (122)
Previous report
Extreme weather events, both in summer and winter, have recently occurred in the Pacific Northwest. These events have resulted in system load peaks that were higher than anticipated. Historically, we have had excess capacity as compared to peak load, but during some extreme events we have had to purchase short-term energy from the wholesale market to meet demand when our energy resources were not operating at full capacity or were otherwise unavailable. These weather events have highlighted the growing need for additional generating capacity both on our system and in the Pacific Northwest region. Accordingly, we are taking the increased peaks in demand into account as we consider our resource adequacy and generation requirements.
Previous report
2024 Hydroelectric Generation and Snowpack Conditions
Previous report
During 2024, our region experienced low precipitation, resulting in low snowpack levels and streamflows when compared to historical averages. This had a negative impact on our hydroelectric generation resources. Lower hydroelectric generation increased net power supply costs and resulted in us absorbing additional costs under the ERM in Washington. In the nine months ended September 30, 2024, we had a $7.8 million pre-tax expense under the ERM in Washington.
Previous report
Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure carbon allowances to cover our carbon emissions over a certain amount each year. Costs associated with the CCA are being deferred and are included in Washington natural gas customer rates starting in April 2024. The resulting aggregate increase to customer bills was approximately 3.7 percent over a one year period, and impacts customers differently based on revenue class, income level, and meter connection date. We have proposed an additional customer bill increase to recover costs associated with the CCA of 9.1 percent to become effective in November 2024, subject to WUTC approval.
Previous report
Costs associated with the CCA related to our electric operations are deferred and included in the ERM for Washington customers. Amounts allocated to Idaho are not approved for recovery from customers. See "Note 15 of the Notes to Condensed Consolidated Financial Statements" for further discussion of the CCA costs associated with our electric operations and impacts on our financial results.
Previous report
The proposed electric and natural gas revenue increase requests were based on a 10.4 percent ROE with a common equity ratio of 48.5 percent and an ROR of 7.61 percent. Increasing power supply costs, operating and maintenance costs, and ongoing capital investments (including clean energy hydroelectric projects, continued investment in the wildfire resiliency plan, replacement of natural gas distribution pipe and technology upgrades) were the main drivers of proposed increases.
Previous report
In the second year of the proposed electric multi-year rate plan, in compliance with Washington’s CETA, we have removed from customers’ rates the costs associated with Colstrip.
Previous report
In August 2024, we filed rebuttal testimony, which updated our request as follows:
Previous report
The proposed rates are designed to increase annual base electric revenues by $42.9 million, or 7.3 percent, effective in December 2024, and $44.9 million (representing our $69.3 million requested increase partially offset by a $24.4 million reduction in customer rates resulting from a revenue reduction in a separate Colstrip tariff) or 10.9 percent, effective in December 2025.
Previous report
For the December 2025 electric increase, the effect of increasing base power supply costs (primarily to make up for the removal of Colstrip from our generation portfolio) accounts for $54.2 million of our overall $69.3 million request.
Previous report
Additionally, we are proposing changes to the ERM. Under the present construct, the ERM consists of a $4 million deadband, and then an asymmetric sharing band between $4 million and $10 million. All costs above $10 million are shared on a 90 percent customer, 10 percent company basis. As part of this rate case on rebuttal, we are proposing to have a $2 million deadband in the rebate direction, a $2.5 million deadband in the surcharge direction, and all other costs shared on a 90 percent customer, 10 percent company basis.
Previous report
We expect to file electric and natural gas general rate cases with the IPUC in the first quarter of 2025.
Previous report
In March 2023, we filed a natural gas general rate case with the OPUC. In October 2023, the OPUC approved the all-party settlement agreement filed in August 2023. The approved rates are designed to increase annual base natural gas revenues by $7.2 million, or 9.4 percent effective January 1, 2024. The OPUC approved an ROR of 7.24 percent, a common equity ratio of 50 percent, and an ROE of 9.5 percent.
Previous report
In November 2024, we filed a general rate case with the OPUC, which is designed to increase overall revenue by $7.8 million, or 9.2 percent, effective September 1, 2025. The case is based on a proposed ROR of 7.67 percent with a common equity ratio of 50 percent and an ROE of 10.4 percent. Ongoing capital infrastructure investment (including replacement and expansion of natural gas distribution pipe and technology) is the main driver of the proposed increase. The OPUC has up to ten months to review the general rate case filing and issue a decision.
Previous report
In August 2023, the RCA issued a final order related to AEL&P’s electric general rate case, which was originally filed in July 2022.
Previous report
The order reflects an 11.45 percent ROE, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. The order also results in an approved base electric revenue increase of 6.0 percent (designed to increase annual electric revenues by $2.1 million), and also makes non-refundable the interim rate increase of 4.5 percent that was approved by the RCA in August 2022 and took effect in September 2022. The final increase to rates was effective in October 2023.
Previous report
AEL&P is required to file its next general rate case by August 2027.
Previous report
PGAs are designed to pass through changes in natural gas costs to customers with little to no change in utility margin (operating revenues less resource costs) or net income. In Washington and Idaho, all costs under the PGAs are passed through to customers. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply to the extent not hedged. Total net deferred natural gas costs among all jurisdictions were liabilities of $9.8 million as of
Previous report
September 30, 2024 and assets of $51.4 million as of December 31, 2023. This change primarily represents the collection of previously deferred natural gas costs and a decrease in natural gas prices.
Previous report
The ERM is an accounting method used in Washington to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and sales of fuel, and the amount included in base retail rates for our customers. See the 2023 Form 10-K for a full discussion of the mechanics of the ERM and the various customer/Company sharing bands. Total net deferred power costs under the ERM were assets of $35.8 million and $37.6 million as of September 30, 2024 and December 31, 2023, respectively. These deferred power cost balances represent amounts due from customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in either the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to return the balance to customers or recover the balance from customers, as the case may be. As of September 30, 2024, $13.1 million of the $35.8 million is still being recovered through a rate surcharge to customers over a two-year period, effective July 1, 2023, as approved by the WUTC.
Previous report
The PCA mechanism in Idaho allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference (positive or negative) between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a liability of $12.5 million and an asset of $7.6 million as of September 30, 2024 and December 31, 2023, respectively.
Previous report
Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, electric and natural gas revenues from residential and certain commercial customers are adjusted so as to be based on the number of customers and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. See the 2023 Form 10-K for a discussion of the mechanisms in each jurisdiction.
Previous report
Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $8.0 million as of September 30, 2024 and regulatory liabilities of $14.9 million as of December 31, 2023. Decoupling regulatory assets represent amounts due from customers. Decoupling regulatory liabilities represent amounts due to customers.
Previous report
See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2024 and 2023 related to the decoupling mechanisms.
Previous report
Interest expense increased primarily due to increased borrowings outstanding and increased interest rates compared to 2023.
Previous report
Nine months ended September 30, 2024 compared to the nine months ended September 30, 2023
Previous report
Electric utility revenues increased as a result of the effects of general rate cases, the ERM surcharge to customers, and increased wholesale sales volumes and sales of fuel as part of our resource optimization activities. This was partially offset by decreased wholesale sale prices. Natural gas utility revenues increased primarily due to increased wholesale revenues and additional decoupling revenues associated with surcharge deferrals from lower customer use.
Previous report
Electric utility resource costs increased primarily due to increased purchased power and fuel for generation, as well as increased power supply costs deferred in prior periods that are being amortized in 2024. Natural gas utility resource costs increased due to an increase in net amortizations of previously deferred costs. The increased net amortizations was partially offset by decreased purchased natural gas costs.
Previous report
Utility operating expenses increased due to increased thermal generation costs, legal costs and employee medical expenses. In addition, net amortizations and deferrals associated with wildfire mitigation costs have increased, with corresponding increases to revenue which result in no impact to earnings.
Previous report
Interest expense increased primarily due to increased borrowings outstanding during the period and increased interest rates compared to 2023.
Previous report
Income tax was an expense for the nine months ended September 30, 2024, compared to a benefit for the nine months ended September 30, 2023. The change is primarily due to the decrease in tax customer credits offsetting the bill impact of rate increases included in our prior general rate cases. This decrease in tax customer credits was partially offset by the timing impact of spreading these fewer available credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.
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Reworded paragraphs (65)
Previous wording
Management’s Discussion and Analysis of Financial Condition and Results of Operations was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2023 Form 10-K.
Current wording
Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. Accordingly, this MD&A does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that are required to accompany financial statements for a full fiscal year and are contained in the Company's 2024 Form 10-K. Therefore, this MD&A should be read in conjunction with the Company's 2024 Form 10-K for full detail and analysis of the Company's financial condition, and results of operations, and a full discussion of trends and uncertainties that the Company faces.
Previous wording
Our business segments have not changed during the nine months ended September 30, 2024. See the 2023 Form 10-K as well as “Note 16 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, 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.
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 thousands):
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, 2024 increased compared to the three and nine months ended September 30, 2023, primarily due to the effects of general rate cases and tax customer credits. These increases in earnings were partially offset by expected increases in operating expenses, depreciation and amortization expense, taxes other than income tax and interest expense.
Current wording
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 wording
A draft IRP, reflecting the accelerated addition of generating resources, was submitted to the WUTC and IPUC in October 2024, and we plan to file the final IRP in January 2025. While the draft 2025 IRP is, and even the final 2025 IRP will be, 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 (64.8 MW) in 2030, we see the need for the addition of approximately 490 MW of generating capacity by 2030 and a total of approximately 950 MW through 2035. We believe the additional capacity would likely consist of 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. 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.
Previous wording
We also expect expanded transmission infrastructure will provide access to additional resources and improve reliability in our region. We have 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, constructing a transmission line from Bismarck, North Dakota to Colstrip, Montana.
Previous wording
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. While we believe our recent general rate settlements are helpful, some increases in our costs will have to be addressed in future rate cases, including our 2024 Washington general rate cases. See “Regulatory Matters” for additional discussion of the general rate cases.
Current wording
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 wording
With regard to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.
Current wording
With regard to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors including, but not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.
Previous wording
On January 18, 2024, we filed multi-year electric and natural gas general rate cases with the WUTC. If approved, new rates would be effective in December 2024 and December 2025.
Current wording
In December 2024, the WUTC issued orders related to our multi-year electric and natural gas general rate cases filed with the WUTC in January 2024.
Previous wording
The proposed rates are designed to increase annual base natural gas revenues by $16.8 million, or 13.2 percent, effective December 2024, and $4.0 million, or 2.8 percent, effective December 2025.
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) for Rate Year 2.
Previous wording
In February 2023, we filed multi-year electric and natural gas general rate cases with the IPUC. In August 2023, the IPUC approved the multi-party settlement agreement designed to increase annual base electric revenues by $22.1 million, or 8.0 percent, effective in September 2023, and $4.3 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1.3 million, or 2.7 percent, effective in September 2023, and a negligible increase effective in September 2024.
Current wording
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 wording
The WUTC has up to eleven months to review the general rate case filings and issue a decision, which is expected in December 2024.
Current wording
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.
Current wording
Purchased Gas Adjustments, Power Cost Deferrals and Decoupling Mechanisms
Previous wording
The following provides an overview of changes in our Condensed Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.
Current wording
The following provides an overview of changes in our Condensed Consolidated Statements of Income and Comprehensive Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.
Previous wording
The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income.
Current wording
The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income and Comprehensive Income.
Previous wording
The following graph shows the total change in net income for the third quarter of 2024 compared to the third quarter of 2023, 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 2025 compared to the first quarter of 2024, as well as the factors that caused such change (dollars in millions):
Previous wording
Electric utility revenues increased as a result of the effects of general rate cases and customer growth, partially offset by decreased wholesale revenues as part of our resource optimization activities. Natural gas utility revenues decreased slightly primarily due to decreased wholesale revenues.
Current 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.
Previous wording
Utility resource costs decreased primarily due to decreased commodity prices. 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 third quarter of 2023.
Current 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.
Previous wording
Utility operating expenses increased due to increased thermal generation costs, legal costs and employee medical expenses. In addition, net amortizations and deferrals associated with wildfire mitigation costs have increased, 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. 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.
Previous wording
Income tax benefits decreased 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. This decrease in tax customer credits was partially offset by the timing impact of spreading these fewer available credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. 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 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.
Previous wording
The decrease in earnings related to other is primarily due to increased taxes other than income tax, as well as net investment losses recorded in the third quarter of 2024 compared to net investment gains in 2023.
Current 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.
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 intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of energy (natural gas or electricity), electric capacity and fuel for electric generation, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2023 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, 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.
Previous wording
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 three months ended September 30 (dollars in thousands):
Current wording
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 three months ended March 31 (dollars in millions):
Previous wording
A $29.6 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $22.0 million), and an increase in MWhs sold (increased revenues by $7.6 million).
Current 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).
Previous wording
A $23.8 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $33.5 million), partially offset by an increase in sales volumes (increased revenues $9.7 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
Current 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.
Previous wording
A $3.3 million increase in other electric revenues primarily resulting from increased REC and transmission revenues.
Current wording
A $1 million decrease in other electric revenues primarily resulting from decreased transmission revenues.
Previous wording
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 three months ended September 30 (dollars in thousands):
Current wording
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 three months ended March 31 (dollars in millions):
Previous wording
A $2.5 million decrease in natural gas retail revenues (including industrial, which is included in other) due to decreased sales volumes (decreased revenues $11.5 million), partially offset by higher retail rates (increased revenues $9.0 million)
Current 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).
Previous wording
Retail rates increased mainly due to the effects of our general rate cases and rate increases associated with the CCA.
Current 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.
Previous wording
A $6.1 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $8.5 million), partially offset by an increase in sales volumes (increased revenues $2.4 million). The increase in volumes is related to increased optimization opportunities.
Current 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.
Previous wording
A $0.4 million increase in natural gas decoupling revenues primarily due decreased amortization of prior year surcharge balances.
Current 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.
Previous wording
A $5.2 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $14.5 million), partially offset by an increase in the volume of power purchases (increased costs $9.3 million).
Current 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.
Previous wording
A $7.6 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 third quarter of 2023.
Current 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.
Previous wording
A $6.4 million increase in other electric resource costs, primarily related to an increase in amortization of previously deferred costs, as well as an increase in the deferral of funds related to our customer assistance payment programs (low income rate assistance and demand side management).
Current 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.
Previous wording
A $6.2 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $9.7 million), partially offset by an increase in volumes (increased costs $3.5 million).
Current 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).
Previous wording
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 three months ended September 30, 2024 and 2023 (dollars in thousands):
Current wording
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, 2025 and 2024 (dollars in millions):
Previous wording
Electric utility margin increased $17.0 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $3.2 million primarily due to the effects of our general rate cases.
Current 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.
Previous wording
In the third quarter of 2024, we had a $3.2 million pre-tax expense under the ERM in Washington, compared to a $1.2 million pre-tax expense for the third quarter of 2023.
Current 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.
Previous wording
Our other businesses had a net loss of $1.4 million for the three months ended September 30, 2024 compared to net income of $0.9 million for the three months ended September 30, 2023. Net losses were $3.5 million for the first three quarters of 2024, compared to a net loss of $2.6 million in 2023.
Current 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.
Previous wording
Our sources of overall liquidity and the requirements for liquidity have not materially changed in the nine months ended September 30, 2024. See the 2023 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, 2025. See the 2024 Form 10-K for further discussion.
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Previous report — wording carried elsewhere
The following graph shows the total change in net income for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, as well as the factors that caused such change (dollars in millions):
Previous report — wording carried elsewhere
Utility depreciation and amortization increased primarily due to additions to utility plant.
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, 2024 and 2023:
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, 2024 and 2023 (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
A $76.1 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $71.8 million), and an increase in MWhs sold (increased revenues by $4.3 million).
Previous report — wording carried elsewhere
An $11.1 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $34.6 million), partially offset by an increase in sales volumes (increased revenues $23.5 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
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, 2024 and 2023 (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 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 nine months ended September 30, 2024 and 2023 (dollars in thousands):
Previous report — wording carried elsewhere
Electric utility margin increased $60.6 million primarily due to the effects of general rate cases and customer growth. Natural gas utility margin increased $13.2 million, primarily due to the effects of general rate cases.
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.