AVISTA CORP

Previous wording

Our business segments have not changed during the six months ended June 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 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.

Previous wording

The following table presents net income (loss) for each of our business segments (and the other businesses) for the three and six months ended June 30 (dollars in thousands):

Current 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):

Previous wording

Net income for the three and six months ended June 30, 2024 increased compared to the three and six months ended June 30, 2023, primarily due to the effects of general rate cases and the quarterly distribution of fewer tax customer credits to annual income taxes in 2024, as compared to 2023. These increases in earnings were partially offset by increased operating expenses and depreciation and amortization expense.

Current 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.

Previous wording

Extreme weather events, both in summer and winter, are becoming more frequent and more severe. These events have resulted in system load peaks that were higher than anticipated and, at certain times, higher than the capacity available at the time from resources owned by us or under firm contract. These unplanned capacity deficits are exacerbated by weather and other factors that reduce the availability of generating facilities, particularly hydroelectric and other renewable resources. Historically, we have been able to meet peak demand with short-term purchases of energy in the wholesale market. However, 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. In addition, the transition to clean energy (including the replacement of emitting facilities with non-emitting facilities, which are impacted by conditions outside of our control), electrification and other increasing needs for electric energy also factor into the analysis of the need for additional generation. As a result, we expect additional generating capacity will be needed earlier than reflected in our 2023 integrated resource plan. We are in the process of evaluating potential acceleration of our generation additions as compared to our most recent integrated resource plan filed in June 2023. A draft preferred resource plan will be submitted to the WUTC and IPUC in September 2024, and the final integrated resource plan will be filed in January 2025.

Current wording

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 wording

During the first half of 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 during the first half of the year and will continue to negatively impact hydroelectric generation for the remainder of the year. Expected lower hydroelectric generation increased net power supply costs and resulted in us absorbing additional costs under the ERM in Washington. In the six months ended June 30, 2024, we had a $4.7 million pre-tax expense under the ERM in Washington. We expect to absorb additional costs under the ERM in the second half of 2024.

Current wording

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 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 approximately 3.7 percent, and impacts customers differently based on revenue class, income level, and meter connection date. See "Environmental Issues and Contingencies" within our Form 10-K for 2023 for further discussion of the CCA and expected impacts on our financial results.

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 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 wording

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.

Current wording

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 wording

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.

Current wording

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 wording

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.

Current wording

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 wording

The cases are continuing through the normal regulatory process, which involves several rounds of testimony and an evidentiary hearing. These subsequent filings could potentially reflect changes in our originally-requested revenues, due to updates to power supply costs for more current market pricing, among other items. 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

The WUTC has up to eleven months to review the general rate case filings and issue a decision, which is expected in December 2024.

Previous wording

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 $1.0 million as of June 30, 2024 and assets of $51.4 million as of December 31, 2023.

Current wording

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 wording

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 $30.3 million and $37.6 million as of June 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 June 30, 2024, $17.4 million of the $30.3 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.

Current wording

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 wording

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 $2.7 million and an asset of $7.6 million as of June 30, 2024 and December 31, 2023, respectively.

Current wording

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 wording

Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $3.8 million as of June 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.

Current wording

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 wording

The following graph shows the total change in net income for the second quarter of 2024 compared to the second quarter of 2023, as well as the various factors that caused such change (dollars in millions):

Current 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):

Previous wording

Electric utility revenues increased as a result of the effects of general rate cases, and the ERM surcharge to customers partially offset by decreased wholesale sales as part of our resource optimization activities. Natural gas utility revenues increased primarily due to increased retail revenues.

Current 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.

Previous wording

Utility operating expenses increased due to increased thermal generation costs, vegetation management, legal and employee medical expenses, as well as increased amortizations of previously deferred wildfire mitigation costs now included in customer rates (resulting in no impact to net income).

Current 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.

Previous wording

Income tax was an expense in the second quarter of 2024, compared to a benefit in the second quarter of 2023. The change is 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 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.

Previous wording

The following graph shows the total change in net income for the six months ended June 30, 2024 compared to the six months ended June 30, 2023, as well as the various factors that caused such change (dollars in millions):

Current wording

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 wording

Electric utility revenues increased as a result of the effects of general rate cases, the ERM surcharge to customers, and increased wholesale sales and sales of fuel as part of our resource optimization activities. Natural gas utility revenues increased primarily due to increased wholesale revenues.

Current wording

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 wording

Utility operating expenses increased due to increased thermal generation costs, vegetation management, legal and employee medical expenses, as well as increased amortizations of previously deferred wildfire mitigation costs now included in customer rates (resulting in no impact to net income).

Current 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.

Previous wording

Income tax was an expense in the first half of 2024, compared to a benefit in the first half of 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.

Current wording

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.

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 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 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.

Previous wording

Total electric revenues increased $6.3 million for the second quarter of 2024 as compared to the second quarter of 2023. The primary changes that occurred during the period were as follows:

Current wording

Total electric revenues increased $7.7 million for the third quarter of 2024 as compared to the third quarter of 2023. The primary changes that occurred during the period were as follows:

Previous wording

A $12.7 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $23.1 million), partially offset by a decrease in MWhs sold (decreased revenues by $10.4 million).

Current 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).

Previous wording

A $12.7 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $13.5 million), partially offset by a decrease in sales prices (decreased revenues $0.8 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.

Current 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.

Previous wording

A $5.2 million increase in other electric revenues primarily from increased REC revenue, as well as increased transmission revenue.

Current wording

A $3.3 million increase in other electric revenues primarily resulting from increased REC and transmission revenues.

Previous wording

A $9.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to increased sales volumes (increased revenues $4.3 million), and higher retail rates (increased revenues $5.0 million). The increase in sales volumes was primarily due to increased residential and commercial usage, resulting from slightly higher heating degree days in the beginning of the second quarter. Compared to the second quarter of 2023, residential use per customer increased 4 percent, and commercial firm use per customer increased 7 percent primarily due to colder weather. Retail rates increased mainly due to the effects of our general rate cases and rate increases associated with the CCA.

Current wording

A $2.0 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $2.9 million), partially offset by decreased sales volumes (decreased revenues $0.9 million). The decrease in sales volumes was primarily due to a 7 percent decrease in residential usage, resulting from warmer weather. Retail rates increased mainly due to the effects of our general rate cases and rate increases associated with the CCA.

Previous wording

A $2.3 million decrease in wholesale natural gas revenues, due to decreased optimization opportunities.

Current 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.

Previous wording

A $3.4 million increase in other gas revenues primarily due to amortizations of previously deferred CCA revenues, which began April 1, 2024.

Current wording

A $2.3 million increase in other gas revenues primarily due to amortizations of previously deferred CCA revenues, which began April 1, 2024.

Previous wording

A $1.2 million decrease in power purchased due to a decrease in the volume of power purchases (decreased costs $7.7 million), partially offset by an increase in wholesale prices (increased costs $6.5 million).

Current 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).

Previous wording

A $10.0 million decrease in fuel for generation. This was due to a decrease in fuel prices, as well as a decrease in thermal generation during the second quarter, resulting from a decrease in retail and wholesale sales volumes.

Current 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.

Previous wording

A $3.6 million decrease in other fuel costs. These costs represent fuel and the related derivative instruments purchased for generation which were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

Current wording

A $3.0 million decrease in other fuel costs. These costs represent fuel and the related derivative instruments purchased for generation which were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

Previous wording

A $26.5 million increase in other electric resource costs related to an increase in amortization of previously deferred costs, as well as an increase in deferrals related to current year power supply costs.

Current 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).

Previous wording

Total natural gas resource costs increased $6.9 million for the second quarter of 2024 as compared to the second quarter of 2023 primarily due to a decrease in deferred costs during the period, as well as an increase in amortization of previously deferred costs.

Current wording

A $2.1 million increase in other primarily related to an increase in deferred PGA rebates during the period, as well as an increase in amortization of previously deferred costs. The increase in PGA rebates was due to a decrease in the price of natural gas.

Previous wording

Electric utility margin increased $15.6 million and natural gas utility margin increased $3.5 million, primarily due to the effects of our general rate cases.

Current 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.

Previous wording

In the second quarter of 2024, we had a $1.3 million pre-tax benefit under the ERM in Washington, compared to a $1.0 million pre-tax benefit for the second quarter of 2023.

Current 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.

Previous wording

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2024 and 2023:

Current wording

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 wording

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2024 and 2023 (dollars in millions and MWhs in thousands):

Current wording

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 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 six months ended June 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 nine months ended September 30 (dollars in thousands):