AVISTA CORP
For the period ended Dec 31, 2024. Filed Feb 26, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 26, 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-K
Period ended 2023-12-31; filed 2024-02-21.
0000950170-24-017421
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsBusiness SegmentsExecutive Level SummaryRegulatory MattersResults of Operations - OverallNon-GAAP Financial MeasuresResults of Operations - Avista UtilitiesResults of Operations - Alaska Electric Light and Power CompanyResults of Operations - Other BusinessesAccounting Standards to Be Adopted in 2024Critical Accounting Policies and EstimatesOverall LiquidityReview of Consolidated Cash Flow StatementCapital ResourcesUtility Capital ExpendituresNon-Regulated Investments and Capital ExpendituresPension PlanCredit RatingsDividendsCompetitionEconomic Conditions and Utility Load GrowthEnvironmental Issues and Other ContingenciesColstripEnterprise Risk ManagementCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-26.
0000950170-25-027077
Item 7. 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 BusinessesAccounting Standards to Be Adopted in 2025Critical Accounting Policies and EstimatesOverall LiquidityReview of Consolidated Cash Flow StatementCapital ResourcesUtility Capital ExpendituresNon-Regulated Investments and Capital ExpendituresPension PlanCredit RatingsDividendsCompetitionEconomic Conditions and Utility Load GrowthEnvironmental Issues and Other ContingenciesColstripEnterprise 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 416 previous paragraphs and 415 current paragraphs.
254 unchanged; 96 reworded; 64 added; 63 removed; 3 previous and 1 current paragraphs rearranged.
Tables are not compared: 21 previous and 19 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 (64)
Current report
Net income increased primarily due to the effects of general rate cases. This increase in earnings was partially offset by increases in other operating expenses, depreciation and amortization expense, taxes other than income taxes and interest expense.
Current 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.
Current report
The transition to clean energy (including the replacement of emitting facilities with non-emitting facilities, which are impacted by conditions outside of our control), and electrification, combined with expected load growth, factor into the analysis of the need for additional generation.
Current report
Our 2025 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 CT (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. See “Part I, Item 1. Business – Company Overview – Future Resource Needs” for further discussion of the IRP.
Current report
We also expect expanded transmission infrastructure will provide access to additional resources and improve reliability in our region. 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 report
Our hydroelectric generation is affected not only by precipitation levels, but also by temperatures since warmer weather causes earlier melting and runoff of snowpack, and extremely cold weather can result in the formation of ice which can decrease streamflow. 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 2024, we had a $8 million pre-tax expense under the ERM in Washington.
Current 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. Costs incurred for CCA compliance did not have a material effect on our results of operations for 2024 and 2023. See "Note 22 of the Notes to Consolidated Financial Statements" for further discussion of the CCA costs associated with our electric operations and impacts on our financial results.
Current report
The President of the United States of America has announced plans to impose tariffs on certain imported goods. The implementation of these tariffs has been paused until March 2025. We anticipate that any such tariffs would apply to natural gas and electricity imported from Canada, as well as wood waste used as fuel at the Kettle Falls GS. As we import a significant amount of natural gas from Canada, both to serve our retail natural gas customers and as fuel for electric generation, these tariffs could have a significant impact on our resource costs. In addition, we cannot predict how the broader energy markets would respond and change as a result of the tariffs. The impact of an increase in resource costs on our results of operations from the tariffs would be partially mitigated by various deferral and recovery mechanisms (ERM, PCA, and PGAs), but there could be an immediate impact on our cash flow. These tariffs could also impact the cost of other equipment and materials that are critical to our business, and could increase capital and operating expenses.
Current report
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.
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 a $77 million increase is primarily due to a $56 million decrease in power supply costs compared to those set forth in the original request, and also due to a lower approved return on equity than what was requested. The Rate Year 2 increase represents the effective increase to customers resulting from the $69 million approved in the order, partially offset by a $25 million decrease due to the expiration of a separate tariff in effect during Rate Year 1 to collect remaining Colstrip expenses by December 31, 2025 (see further discussion below).
Current report
The approved rates are also designed to increase annual natural gas base revenues by $14 million (or 11.2 percent), effective January 1, 2025, and $4 million (or 2.8 percent) for Rate Year 2.
Current 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
Current report
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, discussed above, required us to establish a tracker for our Colstrip-related costs, including operating and maintenance expense, depreciation and amortization expense, and a return on rate base. In October 2024, we filed a cost recovery tariff seeking to recover the costs associated with our ownership of Colstrip in 2025. In the filing, we requested an increase in annual Colstrip tariff revenues of $19 million – from $24 million in 2024 to $43 million in 2025, effective January 1, 2025. In its review, WUTC Staff raised three concerns related to (1) whether forecasted 2025 investments are allowed in rates; (2) whether the capital investment included in the filing will be used and useful for customers prior to the end of 2025; and (3) one major capital investment that will not be in service until 2027. In December 2024, the WUTC allowed our filed tariff to go into effect, but set the rates as subject to refund. 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. A status report is due to the WUTC by March 31, 2025. If the parties cannot resolve the concerns of WUTC Staff, we believe a procedural schedule will be developed and a hearing date set.
Current report
In November 2024, we filed a general rate case with the OPUC, which is designed to increase overall revenue by $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.
Current report
AEL&P is required to file its next general rate case by August 2027.
Current report
Utility revenues increased at Avista Utilities primarily due to increased electric retail rates (due to the effects of general rate cases), and increased sales of fuel. These increases were partially offset by decreased natural gas retail sales volumes (due to warmer weather and lower usage) and rates, and decreased electric wholesale revenue due to decreased sale prices.
Current report
Utility resource costs increased at Avista Utilities primarily due to increased prices and volumes of purchased power, and an increase in net amortizations and deferrals of costs and benefits under our regulatory mechanisms. These increases were partially offset by a decrease in fuel for generation and purchased natural gas, resulting from decreased natural gas prices.
Current report
The increase in utility operating expenses was primarily due to increased thermal generation costs, legal costs and employee benefit costs (primarily related to medical). In addition, amortizations and base levels of wildfire mitigation costs and insurance costs have increased, with corresponding increases to revenue which result in no impact to earnings.
Current report
The increase in total retail MWhs sold was primarily the result of customer growth, including a large industrial customer that we began serving in August 2024.
Current report
an $11 million increase in electric decoupling revenue, resulting from current year deferrals in a surcharge position, compared to a rebate position in the prior year, as well as an increase in amortization of prior year rebate balances.
Current report
a $10 million increase in other electric revenues, primarily resulting from increased transmission and REC revenues.
Current report
Total natural gas revenues increased $35 million for 2024 as compared to 2023. The primary differences in the results for these periods were as follows:
Current report
a $19 million increase in decoupling revenues due to surcharge deferrals in the current year resulting from lower customer usage, compared to rebate deferrals in the prior year. There were also lower amortizations of prior year surcharges compared to amortizations in 2023.
Current report
a $20 million increase in other natural gas revenue due to revenues associated with the sale of CCA emissions credits, which are deferred and are amortized as they are passed through to customers through decreases in retail rates. The increase in other revenues is offset by decreased retail rates, resulting in no impact to utility margin.
Current report
Total electric resource costs increased $58 million for 2024 as compared to 2023. The primary differences in the results for these periods were as follows:
Current report
a $43 million increase in other electric resource costs, primarily related to an increase in amortization of previously deferred costs, and an increase in deferred benefits under the PCA in Idaho related to current year power supply costs. There was also an increase in the deferral of funds related to our customer assistance payment programs (low income rate assistance and demand side management).
Current report
Total natural gas resource costs increased $18 million for 2024 as compared to 2023. The primary differences in the results for these periods were as follows:
Current report
Electric utility margin increased $71 million and natural gas utility margin increased $17 million.
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Removed paragraphs (63)
Previous report
Avista Utilities' net income increased primarily due to increased utility margin, including benefits from our completed general rate cases, lower property taxes, and the recognition of tax customer credits which resulted in higher income tax benefit for 2023. These positive factors to net income were partially offset by increased interest expense, depreciation and amortization expense, and other operating expenses.
Previous report
The decrease in net income at our other businesses was primarily due to net investment losses recognized in 2023, compared to net investment gains recognized in 2022.
Previous report
In May and June of 2023, our region experienced historically high temperatures, causing the snowpack to melt more rapidly than expected. The quick runoff had a significant negative impact on our hydrogeneration resources, resulting in one of our worst years for hydroelectric generation. As a result, we increased thermal generation and purchased power to compensate for the decrease in available hydroelectric generation, and our ability to optimize our generation assets was limited compared to the opportunities we originally expected for the year. The decreased availability of hydroelectric generation compared to our expectations had a significant impact on the ERM in Washington, as well as our financial results.
Previous report
In November 2023, we had the largest natural gas outage in our Company’s history. Nearly 37,000 natural gas customers were impacted when a third party damaged a pipeline that transports natural gas to our system. Natural gas service was restored to every impacted customer in less than one week. We filed petitions for regulatory accounting orders with the WUTC and IPUC and received approval to defer $10.3 million of costs of the incident for recovery to be addressed in a future regulatory proceeding.
Previous report
In mid-January 2024, there were two operational issues impacting our gas distribution system, as well as the natural gas transportation system in the Pacific Northwest. These challenges, combined with very cold temperatures, resulted in high commodity prices. The first issue involved a mechanical problem with a third party transmission pipeline that delivers natural gas to our service territory. The second issue involved a mechanical problem with Jackson Prairie. These issues reduced the capacity of natural gas that could be delivered to our natural gas distribution system, as well as natural gas fuel for electric generation. We made operational decisions and contingency plans in response to the issues and we did not experience any disruptions in service to customers. We experienced higher energy commodity prices and an increased need to purchase energy, which will be accounted for under the ERM, PCA and PGAs.
Previous report
These general rate cases require a subsequent review of additions to utility plant included in rates and a refund of revenues if capital expenditures are less than the level contemplated in the rate case. The review of 2022 capital was completed in 2023, and no refunds were required.
Previous report
The proposed rates are designed to increase annual base electric revenues by $77.1 million, or 13.0 percent, effective in December 2024, and $53.7 million, or 11.7 percent, effective in December 2025.
Previous report
For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $17.3 million, or 13.6 percent, effective in December 2024, and $4.6 million, or 3.2 percent, effective in December 2025.
Previous report
The proposed electric and natural gas revenue increase requests are based on a 10.4 percent return on equity with a common equity ratio of 48.5 percent and a rate of return on rate base 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 generation from Colstrip.
Previous report
As a part of the electric rate case, we proposed certain updates to power supply costs. The updated power supply costs included as a part of the first rate year, accounts for $18.5 million of our overall electric request. For electric rate year 2, the net effect of increasing base power supply costs (primarily to make up for the loss of Colstrip from our generation portfolio), offset by reductions in customer rates through the removal of Colstrip rate base and expenses, accounts for $35.1 million of our overall $53.7 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, we are proposing moving the entire mechanism to a 95 percent customer, 5 percent company sharing of power supply cost above or below the authorized level.
Previous report
If the multi-year rate plans are approved, we would not file new general rate cases for new rate plans to be effective prior to December 2026.
Previous report
In January 2021, we filed multi-year electric and natural gas general rate cases with the IPUC. In September 2021, the IPUC approved the all party settlement agreement designed to increase annual base electric revenues by $10.6 million, or 4.3 percent, effective September 1, 2021, and $8.0 million, or 3.1 percent, effective September 1, 2022. For natural gas, the settlement agreement was designed to decrease annual base natural gas revenues by $1.6 million, or 3.7 percent, effective September 1, 2021, and increase annual base revenues by $0.9 million, or 2.2 percent, effective September 1, 2022. The parties agreed to use the tax customer credits, related to flow through of certain tax items, included in our original filing to offset overall proposed changes to rates over the two-year plan.
Previous report
The settlement was based on a 9.4 percent ROE with a common equity ratio of 50 percent and a ROR of 7.05 percent.
Previous report
In October 2021, we filed a natural gas general rate case with the OPUC. In January 2022, a partial settlement stipulation addressing cost of capital issues was filed with the OPUC in our natural gas general rate case filed in October 2021. The parties agreed to an ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.
Previous report
In March 2022, a second settlement stipulation was filed with the OPUC that addressed, and resolved, all other remaining issues, and was subsequently approved by the OPUC. The settlement is designed for an overall revenue increase of $1.6 million, effective August 22, 2022. The agreement was a “black box”, with the only component of the revenue requirement explicitly stated is the previously-agreed upon cost of capital. The parties also agreed that certain tax credits of approximately $3.0 million will be passed through to customers to mitigate the base revenue increase.
Previous report
PGAs are designed to pass through changes in natural gas costs to customers with no change in utility margin (operating revenues less resource costs) or net income.
Previous report
The following PGAs went into effect in our various jurisdictions during 2021 through 2023:
Previous report
Utility revenues increased at Avista Utilities primarily due to increased retail rates (including natural gas PGAs), increased electric wholesale sales prices and volumes, and increased electric decoupling revenues. These increases were partially offset by decreased natural gas wholesale prices, as well as financial losses from our fuel sale hedging activities that are netted with revenues.
Previous report
Utility resource costs decreased at Avista Utilities primarily due to decreased market prices for natural gas and lower fuel costs for power generation, as well as financial gains related to our hedging activities that are netted with our expenses. These decreases were partially offset by increased purchased power and increased net deferrals and amortizations under regulatory mechanisms. The change related to regulatory mechanisms represents a reduction in deferred costs as well as an increase in amortizations of previously deferred power and natural gas costs.
Previous report
The increase in utility operating expenses was primarily due to increased labor costs, insurance costs, as well as increased amortizations of previously deferred costs now included in customer rates (resulting in no impact to net income). These increases were partially offset by a decrease due to the $4.0 million write off of Dry Ash Disposal System assets in 2022.
Previous report
The decrease in other was primarily related to net investment losses recognized in 2023 compared to net investment gains recognized in 2022. See “Note 7 of the Notes to Consolidated Financial Statements” for further details of our investment gain and losses. The decrease related to net investment losses was partially offset by increased interest income, as well as decreased non-utility operating expenses and property taxes in 2023 compared to 2022.
Previous report
The decrease in total retail MWhs sold was primarily the result of decreased customer use in the winter months due to weather that was warmer than the prior year. Heating degree days in Spokane during 2023 were 8 percent below historical average, compared to 4 percent above historical average in 2022. This was partially offset by increased usage in summer months as the weather was warmer than the prior year, with Spokane cooling degree days at 39 percent above historical average compared to 33 percent above historical average in the prior year. Compared to 2022, total use per residential customer decreased 4.5 percent, and total use per commercial customer decreased 3.0 percent.
Previous report
a $44.3 million increase in electric decoupling revenue. Rebates decreased in 2023 due to lower usage by residential customers compared to the prior year, and amortizations of the prior year rebate balances in 2023 compared to amortizing a surcharge balance in 2022 increased revenues.
Previous report
Total natural gas revenues decreased $12.9 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:
Previous report
a $6.0 million decrease in decoupling revenues due to a rebate recognized in 2023 related to increased customer usage during the first quarter of 2023, compared to a surcharge recognized in 2022. In 2023 we also recognized higher amortizations of previous surcharges balances.
Previous report
Total electric resource costs decreased $34.6 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:
Previous report
a $48.1 million increase in other electric resource costs, primarily related to a decrease in the deferral of power supply costs above those authorized under the ERM and PCA mechanisms, as well as increased amortizations of surcharge balances.
Previous report
Total natural gas resource costs decreased $25.7 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:
Previous report
Electric utility margin increased $60.0 million and natural gas utility margin increased $12.8 million.
Previous report
Electric utility margin increased primarily due to our general rate cases, as well as customer growth. A small portion of the increase was due to lower net power supply costs. In 2023, we had a $8.4 million pre-tax expense under the ERM, compared to a $10.9 million pre-tax expense in 2022.
Previous report
Natural gas utility margin increased primarily due to customer growth and our general rate cases.
Previous report
Our other businesses had a net loss of $4.8 million for 2023 compared to net income of $29.7 million for 2022. The decrease in net income primarily relates to decreases in the fair value of our investments in 2023, compared to net investment gains related to fair value increases in 2022. In 2022, a significant portion of the net income resulted from an increase in the fair value of our investment in a biotechnology company, which stems from an investment originally focused on the development of biofuels. See "Note 18 of the Notes to the Consolidated Financial Statements" for further discussion of our equity investment fair value.
Previous report
Net cash provided by operating activities was $447.1 million for 2023 compared to $124.2 million for 2022. The increase in net cash provided by operating activities primarily relates to a decrease in cash collateral posted for derivative investments, which was returned and increased cash flows by $129.2 million in 2023 compared to decreasing cash flows by $141.0 million in 2022. During 2023 we also had an increase to cash flows of $7.1 million resulting from net amortizations of power and natural gas cost deferrals, while the net deferral decreased cash flows by $78.4 million in 2022. Receipts of outstanding accounts receivable balances increased operating cash flows by $92.9 million compared to 2022.
Previous report
These increases in operating cash flows were partially offset by a decrease in our outstanding accounts payable balance, which decreased operating cash flows by $132.1 million compared to 2022, as well as increased inventory purchases (primarily CCA emissions allowances) resulting in a decrease to operating cash flows of $29.4 million.
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Reworded paragraphs (96)
Previous wording
This section of this Annual Report on Form 10-K generally discusses 2023 and 2022 financial statement items and year-to-year comparisons between 2023 and 2022. Discussion of 2021 financial statement items and year-to-year comparisons between 2022 and 2021 not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Conditions and Results of Operations” in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2022.
Current wording
This section of this Annual Report on Form 10-K generally discusses financial statement items and comparisons between 2024 and 2023. Discussion of 2022 financial statement items and comparisons between 2023 and 2022 not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Conditions and Results of Operations” in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2023.
Previous wording
The following table presents net income (loss) for each of our business segments and the other businesses, for the year ended December 31 (dollars in thousands):
Current wording
The following table presents net income (loss) for each of our business segments and the other businesses, for the year ended December 31 (dollars in millions):
Previous wording
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 for our natural gas operations over a certain amount each year. Costs associated with the CCA have been deferred, and will be included in natural gas customer rates starting in March 2024. The resulting aggregate increase to customer bills is expected to be approximately 3.8 percent, and will impact customers differently based on revenue class, income level, and the age of a residential customers residence. The CCA is expected to have limited financial impact on our electric operations in its initial years.
Current wording
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 3.7 percent over a one year period, and impacts customers differently based on revenue class, income level, and meter connection date. An additional customer bill increase to recover costs associated with the CCA of 9.1 percent became effective in November 2024.
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 operating expenses and interest 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. See “Regulatory Matters” for additional discussion of the general rate cases.
Previous wording
In January 2022, we filed multi-year electric and natural gas general rate cases with the WUTC. In December 2022, the WUTC issued an order approving the multi-party settlement agreement filed in June 2022. The approved rates were designed to increase annual base electric revenues by $38.0 million, or 6.9 percent, effective in December 2022, and $12.5 million, or 2.1 percent, effective in December 2023. The approved rates were also designed to increase annual base natural gas revenues by $7.5 million, or 6.5 percent, effective in December 2022, and $1.5 million, or 1.2 percent, effective in December 2023.
Current wording
In December 2022, the WUTC issued an order approving the multi-party settlement agreement filed in June 2022. The approved rates were designed to increase annual base electric revenues by $38 million, or 6.9 percent, effective in December 2022, and $13 million, or 2.1 percent, effective in December 2023. The approved rates were also designed to increase annual base natural gas revenues by $8 million, or 6.5 percent, effective in December 2022, and $2 million, or 1.2 percent, effective in December 2023.
Previous wording
To mitigate the overall impact of the revenue increases on customers, part of the 2022 base rate increase was offset with tax customer credits. The total estimated benefits of these credits, $27.6 million for electric customers and $12.5 million for natural gas customers, are being returned over a two-year period from December 2022 to December 2024.
Current wording
To mitigate the overall impact of the revenue increases on customers, part of the 2022 base rate increase was offset with tax customer credits. The total estimated benefits of these credits, $28 million for electric customers and $13 million for natural gas customers, were returned over a two-year period from December 2022 to December 2024.
Previous wording
In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs.
Current wording
In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs through December 31, 2025. See "Colstrip Tracker" below.
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
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 January 2025, we filed multiyear 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 wording
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. The OPUC approved an ROR of 7.24 percent, a common equity ratio of 50 percent, and an ROE of 9.5 percent. New rates were effective on January 1, 2024.
Current wording
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 million, or 9.4 percent. The OPUC approved an ROR of 7.24 percent, a common equity ratio of 50 percent, and an ROE of 9.5 percent. New rates were effective on January 1, 2024.
Previous wording
The order reflects an ROE of 11.45 percent, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. The order results in an approved base electric revenue increase of 6.0 percent (designed to increase annual electric revenues by $2.1 million), and 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.
Current wording
The order reflects an ROE of 11.45 percent, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. The order results in an approved base electric revenue increase of 6.0 percent (designed to increase annual electric revenues by $2 million), and 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 wording
Interest expense increased due to higher interest rates, as well as increased borrowings outstanding during the period. Borrowings increased due to capital expenditures, higher deferred resource costs, and additional requirements for cash collateral.
Current wording
Interest expense increased due to increased borrowings outstanding during the period and increased interest rates compared to 2023.
Previous wording
Income tax benefit increased primarily due to the tax customer credits offsetting the bill impact of rate increases included in our 2021 Washington and Idaho GRCs, and the 2022 Washington GRC. Our effective tax rate for 2023 was negative 24.4 percent. See “Note 13 of the Notes to Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.
Current wording
Income tax was an expense in 2024, compared to a benefit in 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. There is a corresponding change in retail revenues related to tax customer credits such that there is minimal impact on net income. See “Note 13 of the Notes to Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.
Previous wording
The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures,” electric utility margin and natural gas utility margin. In the AEL&P section, we include a discussion of utility margin, which is also a non-GAAP financial measure.
Current wording
The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures,” electric utility margin and natural gas utility margin. In the AEL&P section, we also include a discussion of electric utility margin.
Previous wording
We engage in resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions, which is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of electric capacity and energy and fuel for electric generation, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See Item 1. "Business - Avista Utilities - Electric Operations - General".
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 Item 1. "Business - Avista Utilities - Electric Operations - General" and "Business - Avista Utilities - Natural Gas Operations - General".
Previous wording
We typically enter into multiple transactions simultaneously to capture value. Even though these transactions are considered together when determining the net impact, they are recorded in separate items within components of utility operating revenue and resource costs and can cause fluctuations in each item. This was experienced in 2023, which included gains and losses on financial derivative contracts in certain line items below (such as wholesale sales and purchases of power and natural gas, sales of fuel, and other fuel costs). The ERM, PCA and PGAs are based on net supply costs and consider all transactions related to resource procurement and optimization (both physical and financial).
Current wording
We typically enter into multiple transactions simultaneously to capture value. Even though these transactions are considered together when determining the net impact, they are recorded in separate items within components of utility operating revenue and resource costs and can cause fluctuations in each item. Gains and losses on financial derivative contracts in certain line items below (such as wholesale sales and purchases of power and natural gas, sales of fuel, and other fuel costs). The ERM, PCA and PGAs are based on net supply costs and consider all transactions related to resource procurement and optimization (both physical and financial).
Previous wording
Total electric operating revenues in the graph above include intracompany sales of $6.5 million and $11.7 million for 2023 and 2022, respectively.
Current wording
Total electric operating revenues in the graph above include intracompany sales of $4 million and $6 million for 2024 and 2023, respectively.
Previous wording
The following table presents the current year deferrals and the amortization of prior year decoupling balances reflected in utility electric operating revenues for the years ended December 31 (dollars in thousands):
Current wording
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling balances reflected in utility electric operating revenues for the years ended December 31 (dollars in millions):
Previous wording
Total electric revenues increased $25.3 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:
Current wording
Total electric revenues increased $129 million for 2024 as compared to 2023. The primary differences in the results for these periods were as follows:
Previous wording
a $17.7 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $38.0 million), partially offset by a decrease in total MWhs sold (decreased revenues $20.3 million).
Current wording
a $96 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $83 million), and an increase in total MWhs sold (increased revenues $13 million).
Previous wording
The increase in revenue per MWh was primarily due to our general rate cases, as well as the ERM surcharge to customers that started in 2023.
Current wording
The increase in revenue per MWh was primarily due to the effects of our general rate cases, as well as the ERM surcharge to customers that commenced in July 2023.
Previous wording
a $70.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $43.6 million), and an increase in sales volumes (increased revenues $26.9 million). The increase in volumes was due to resource optimization activities.
Current wording
a $25 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $41 million), partially offset by an increase in sales volumes (increased revenues $16 million). The increase in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
Previous wording
a $110.2 million decrease in sales of fuel due to thermal generation resource optimization activities, including net financial losses on derivative instruments resulting from commodity price volatility early in the year.
Current wording
a $39 million increase in revenues from sales of fuel due to thermal generation resource optimization activities, which includes net losses on derivative instruments resulting from commodity price volatility in early 2023.
Previous wording
Total natural gas operating revenues in the graph above include intracompany sales of $33.4 million and $54.8 million for 2023 and 2022, respectively.
Current wording
Total natural gas operating revenues in the graph above include intracompany sales of $16 million and $33 million for 2024 and 2023, respectively.
Previous wording
The following table presents the current year deferrals and the amortization of prior year decoupling balances reflected in natural gas operating revenues for the years ended December 31 (dollars in thousands):
Current wording
The following table presents the current year decoupling deferrals and the amortization of prior year decoupling balances reflected in natural gas operating revenues for the years ended December 31 (dollars in millions):
Previous wording
a $72.1 million increase in retail natural gas revenues (including industrial, which is included in other) due to increased retail rates (increased revenues $97.9 million), partially offset by decreased sales volumes (decreased revenues $25.8 million).
Current wording
a $14 million decrease in retail natural gas revenues (including a $4 million decrease in interruptible and industrial revenues, which are included in other) due to decreased sales volumes (decreased revenues $11 million) and decreased retail rates (decreased revenues $3 million).
Previous wording
Retail natural gas sales decreased primarily due to lower residential and commercial usage due to warmer weather. Compared to 2022, residential use per customer decreased 7.9 percent and commercial use per customer decreased 6.8 percent. Heating degree days in Spokane during 2023 were 8 percent below historical average, compared to 4 percent above historical average in 2022.
Current wording
Retail natural gas sales volumes decreased primarily due to lower residential and commercial usage due to warmer weather. Compared to 2023, residential use per customer decreased 4 percent and commercial use per customer decreased 1 percent. Heating degree days in Spokane during 2024 were 11 percent below historical average, compared to 8 percent below historical average in 2023. These decreases were partially offset by customer growth.
Previous wording
Retail rates increased due to PGA rate increases (which do not impact utility margin), as well as the effects of our general rate cases.
Current wording
Retail rates decreased 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 $77.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $74.1 million) and a decrease in volumes (decreased revenues $3.8 million). The decrease in prices includes the impact of losses on financial derivative instruments associated with our hedging activities, which nets with our wholesale revenues. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
Current wording
a $6 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $4 million) and an increase in volumes (increased revenues $2 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
Previous wording
Total electric resource costs in the graph above include intracompany resource costs of $33.4 million and $54.8 million for 2023 and 2022, respectively.
Current wording
Total electric resource costs in the graph above include intracompany resource costs of $16 million and $33 million for 2024 and 2023, respectively.
Previous wording
a $26.5 million increase in power purchased due to an increase in wholesale prices (increased costs by $25.6 million), and an increase in the volume of power purchases (increased costs by $0.9 million).
Current wording
a $27 million increase in power purchased due to an increase in wholesale prices (increased costs by $15 million), and an increase in the volume of power purchases (increased costs by $12 million). In mid-January 2024, our service territory experienced much colder than normal weather, requiring purchases at a time when wholesale prices were substantially elevated due to capacity constraints in our region.
Previous wording
a $52.0 million decrease in fuel for generation primarily due to decreased natural gas prices. This was partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation during the year.
Current wording
a $9 million decrease in fuel for generation primarily due to decreased natural gas prices and decreased thermal generation.
Previous wording
a $57.2 million decrease in other fuel costs, including gains on financial derivative instruments associated with our hedging activities. This represents fuel and the related derivative instruments that were purchased for generation but later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
Current wording
a $3 million decrease in other fuel costs, including gains on financial derivative instruments associated with our hedging activities. This represents fuel and the related derivative instruments that were purchased for generation but later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
Previous wording
Total natural gas resource costs in the graph above include intracompany resource costs of $6.5 million and $11.7 million for 2023 and 2022, respectively.
Current wording
Total natural gas resource costs in the graph above include intracompany resource costs of $4 million and $6 million for 2024 and 2023, respectively.
Previous wording
a $63.5 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs by $47.0 million) and a decrease in total therms purchased (decreased costs $16.5 million).
Current wording
a $98 million decrease in natural gas purchased due to a decrease in the price of natural gas.
Previous wording
a $37.8 million increase in other costs, primarily due to the amortization of previously deferred costs.
Current wording
a $116 million increase in other costs, primarily due to a decrease in deferred costs during the period, largely a result of lower natural gas prices, as well as the amortization of costs associated with the CCA that were recovered from customers, resulting in no impact to utility margin.
Previous wording
The following table reconciles Avista Utilities' operating revenues, as presented in “Note 24 of the Notes to Consolidated Financial Statements” to the Non-GAAP financial measure utility margin for the years ended December 31 (dollars in thousands):
Current wording
The following table reconciles Avista Utilities' operating revenues, as presented in “Note 24 of the Notes to Consolidated Financial Statements”, to the Non-GAAP financial measure utility margin for the years ended December 31 (dollars in millions):
Previous wording
Net income for AEL&P was $8.9 million for the year ended December 31, 2023, compared to $7.5 million for 2022.
Current wording
Net income for AEL&P was $8 million for 2024, compared to $9 million for 2023.
Previous wording
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in thousands):
Current wording
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in millions):
Previous wording
AEL&P net income increased, primarily due to higher sales volumes and rate increases.
Current wording
Utility margin increased for 2024 primarily due to higher sales volumes and rate increases. The increase in utility margin was offset by increased operating expenses, resulting in a decrease to net income in 2024 compared to 2023. Utility margin is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" above.
Showing the first 40 of 96 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
For our Washington natural gas operations, we have additional financial burdens associated with compliance which are being deferred and recovered from customers in accordance with our regulatory accounting order in Washington (see "Executive Overview" for discussion of the CCA).
Rearranged previous paragraphs (3)
Previous report — wording carried elsewhere
See "Environmental Issues and Contingencies" for further discussion of the CCA.
Previous report — wording carried elsewhere
The WUTC has up to eleven months to review the general rate case filings and issue a decision.
Previous report — wording carried elsewhere
Utility margin increased for 2023 primarily due to higher sales volumes and rate increases.